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Home My WebLink About203-051Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/19/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240319 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 12/5/2023 AK E-LINE Plug/Cement/Cutter GP ST 18742 37 (AN 37) 50733203940000 187109 11/12/2023 AK E-LINE PERF IRU 241-01 50283201840000 221076 2/25/2024 AK E-LINE Perf/GPT KU 13-06A 50133207160000 223112 2/9/2024 AK E-LINE GPT MPU CFP-02 50029212580000 184242 3/13/2024 READ CaliperSurvey NCIU A-18 50883201890000 223033 12/13/2023 AK E-LINE GPT/Plug/Perf PBU L-122 50029231470000 203051 3/2/2024 AK E-LINE LowerPatchPacker PBU L4-14 50029219730000 189098 11/22/2023 AK E-LINE PERF SRU 241-33B 50133206960000 221053 3/4/2024 AK E-LINE GPT/Cmnt/CIBP/Perf Please include current contact information if different from above. T38648 T38649 T38650 T38651 T38652 T38653 T38654 T38655 T38656 PBU L-122 50029231470000 203051 3/2/2024 AK E-LINE LowerPatchPacker Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 11:50:20 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/15/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240315 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 12/6/2023 AK E-LINE Cement-JetCut BCU 13 50133205250000 203138 2/11/2024 AK E-LINE CIBP-Perf BCU 19RD 50133205790100 219188 2/20/2024 AK E-LINE Perf-CIBP BRU 232-26 50283200770000 184138 11/26/2023 AK E-LINE GPT-PLUG-PERF BRU 244-27 50283201850000 222038 2/27/2024 AK E-LINE GPT-Perf GP ST 18742 37 (AN- 37) 50733203940000 187109 11/22/2023 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 11/3/2023 AK E-LINE GPT-PERF KBU 42-6 50133205460000 204209 2/16/2024 AK E-LINE Patch PBU L-122 50029231470000 203051 12/7/2023 AK E-LINE Patch NCIU A-12B 50883200320200 223053 12/6/2023 AK E-LINE Perf-GPT NCIU A-17 50883201880000 223031 12/10/2023 AK E-LINE Perf-GPT NCIU B-02 50883200900100 197210 3/9/2024 AK E-LINE GPT-Perf SRU 241-33B 50133206960000 221053 3/6/2024 AK E-LINE GPT-Cmnt-CIBP- Perf Please include current contact information if different from above. T38630 T38630 T38631 T38632 T38633 T38634 T38635 T38636 T38637 T38638 T38639 T38640 T38641 PBU L-122 50029231470000 203051 12/7/2023 AK E-LINE Patch Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.18 08:49:06 -08'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UN BORE L-122 JBR 03/31/2022 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:2 During test #4 the manual choke valve failed to hold dp and the HCR choke was closed while troubleshooting and it failed to hold dp as well. Both valves were serviced and passed the retest. The upper and lower pipe slips both failed on the high. After lots of troubleshooting the pipe slips were pulled and redressed and retested for a fail. Both failed as they did before they were redressed. The combination test joint was pulled and cleaned and inspected then reinstalled. The pipe slips were tested off chart and failed again in the same manner. The test joint was pulled again and it was found that there were both oring and non- oring connections used allowing for the test fluid to bypass the pipe slips during testing through the test joint. A new test joint was assembled for just the 2" and the pipe slips passed. The test joint was then pulled again and assembled for the 2 3/8" pipe slips and reinstalled and testing continued. The accumulator recovery times were tested and the results were as follows: Annular- 6 seconds, UPR 2"- 2.5 seconds, LPR 2"- 2.7 seconds, 2 3/8" PR- 2.5 seconds, Blinds (simulated with the annular) 4 seconds, HCR Kill- 1 second, HCR Choke- 1 second. The precharge on all 16 bottles were checked as well. All bottles were pressured up to 1000 psi if they were under 1000 psi The bottles were found to have the precharge pressures as follows before Test Results TEST DATA Rig Rep:J. Medina/W. WilliamsOperator:Hilcorp North Slope, LLC Operator Rep:M. Igtanloc/T. Kavanagh Contractor/Rig No.:Nabors CDR2AC PTD#:2030510 DATE:3/6/2022 Type Operation:WRKOV Annular: 250/2500Type Test:INIT Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopGDC220305063113 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 18.5 MASP: 2944 Sundry No: 321-524 Location Gen.:P Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Drl. Rig P Hazard Sec.P Misc NA Upper Kelly 0 NA Lower Kelly 0 NA Ball Type 2 P Inside BOP 0 NA FSV Misc 0 NA 12 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 1 2"P Annular Preventer 1 7 1/16" 5000 P #1 Rams 1 Blind Shear P #2 Rams 1 2" Pipe Slips P #3 Rams 1 2 3/8" Pipe Sli P #4 Rams 1 2" Pipe Slips P #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 1/16" 5000 P HCR Valves 2 2 1/16" 5000 FP Kill Line Valves 1 2 1/16" 5000 FP Check Valve 0 NA BOP Misc 2 2" 5000 P System Pressure P3000 Pressure After Closure P2250 200 PSI Attained P18 Full Pressure Attained P51.5 Blind Switch Covers:P Nitgn. Bottles (avg):P10 @ 1952 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 1 P 9 9 99 9 9 9 9 9 9 9 FP FP BOPE Test – Nabors CDR2AC (3/6/2022) PBU L-122 (PTD 2030510) AOGCC Inspection Rpt # bopgdc220305063113 Inspector G. Cook Remarks During test #4 the manual choke valve failed to hold dp and the HCR choke was closed while troubleshooting and it failed to hold dp as well. Both valves were serviced and passed the retest. The upper and lower pipe slips both failed on the high. After lots of troubleshooting the pipe slips were pulled and redressed and retested for a fail. Both failed as they did before they were redressed. The combination test joint was pulled and cleaned and inspected then reinstalled. The pipe slips were tested off chart and failed again in the same manner. The test joint was pulled again and it was found that there were both oring and non-oring connections used allowing for the test fluid to bypass the pipe slips during testing through the test joint. A new test joint was assembled for just the 2" and the pipe slips passed. The test joint was then pulled again and assembled for the 2 3/8" pipe slips and reinstalled and testing continued. The accumulator recovery times were tested and the results were as follows: Annular- 6 seconds, UPR 2"- 2.5 seconds, LPR 2"- 2.7 seconds, 2 3/8" PR- 2.5 seconds, Blinds (simulated with the annular) 4 seconds, HCR Kill- 1 second, HCR Choke- 1 second. The precharge on all 16 bottles were checked as well. All bottles were pressured up to 1000 psi if they were under 1000 psi. The bottles were found to have the precharge pressures as follows before being pressured up to 1000 psi: 1. 700 psi., 2. 900 psi., 3. 900 psi., 4. 800 psi., 5. 1000 psi., 6. 1000 psi., 7. 1000 psi., 8. 1000 psi., 9. 900 psi., 10. 800 psi., 11. 900 psi., 12. 900 psi., 13. 950 psi., 14. 1000 psi., 15. 1000 psi., 16. 1000 psi. 9 MEU manual choke valve failed HCR choke failed serviced and passed g The testjj j joint was then pulled again and assembled for the 2 3/8" pipe slips and reinstalled and testing y The combination test joint was pulled and cleaned and inspected theny reinstalled. accumulator recovery times g Annular-6 seconds, UPR 2"- 2.5 seconds, y LPR 2"- 2.7 seconds,2 3/8" PR- 2.5 seconds, Blinds (simulated with the annular) 4 seconds, HCR Kill- 1 second, HCR Choke- 1 second. 2SHUDWLRQV $EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 3XOO7XELQJ 2SHUDWLRQVVKXWGRZQ 3HUIRUPHG 6XVSHQG 3HUIRUDWH 2WKHU6WLPXODWH $OWHU&DVLQJ &KDQJH$SSURYHG3URJUDP 3OXJIRU5HGULOO 3HUIRUDWH1HZ3RRO 5HSDLU:HOO 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VSDFHRXW8QGHSOR\%+$0LOOLV*R1RJR5HDPHULV*R1R*R/'ZLQGRZPLOO38EXLOG%+$'HSOR\%+$EXLOG%+$ $3, :HOO1DPH )LHOG &RXQW\6WDWH 3%:// 3UXGKRH%D\:HVW +LOFRUS(QHUJ\&RPSDQ\&RPSRVLWH5HSRUW $ODVND From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Sundry 321-524 PTD203-051 Pre rig L-122L1 Date:Tuesday, February 22, 2022 9:05:15 AM Attachments:Sundry_321-524_100521.pdf image005.png From: Rixse, Melvin G (OGC) Sent: Tuesday, February 22, 2022 9:03 AM To: Brodie Wages <David.Wages@hilcorp.com> Subject: Sundry 321-524 PTD203-051 Pre rig L-122L1 Brodie, Hilcorp is approved to perform service coil work on Sundry 321-524 with CDR2. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Brodie Wages <David.Wages@hilcorp.com> Sent: Tuesday, February 22, 2022 5:44 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] PTD 221-083 Pre rig L-122L1 or are you referring to: PTD 203-051, Sundry 321-524 Yessir, We are still uncertain as to when service coil will show up and is just about infeasible to perform the FCO prior to CTD showing up. Especially with all the activity we have on L pad and the other opportunities available to service coil once it gets here. David “Brodie” Wages Ops Engineer C: 713.380.9836 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Sunday, February 20, 2022 5:42 PM To: Brodie Wages <David.Wages@hilcorp.com> Subject: [EXTERNAL] PTD 221-083 Pre rig L-122L1 or are you referring to: PTD 203-051, Sundry 321- 524 Brodie, Is this the work you are referencing: PTD203-051, Sundry 321-524 ? Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Brodie Wages <David.Wages@hilcorp.com> Sent: Friday, February 18, 2022 4:52 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] PTD 221-083 Pre rig L-122L1 Due to service coil out of service still, we would like to perform the fill cleanout, whipstock setting and the window milling on the coil drilling rig. David “Brodie” Wages Ops Engineer C: 713.380.9836 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, February 18, 2022 2:09 PM To: Brodie Wages <David.Wages@hilcorp.com> Subject: [EXTERNAL] PTD 221-083 Pre rig L-122L1 Brodie, Are you talking about the window milling? It is already an approved contingency. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,422'None Casing Collapse Conductor 470 Surface 4,790 Production 4,990 / 10,530 Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: December 15, 2021 3-1/2", 9.2# 3-1/2" Baker SABL-3 Packer Authorized Title: Drilling Manager Authorized Name: Monty Myers 25' - 9,410' Perforation Depth MD (ft): 9,050' - 9,217' 9,385' Perforation Depth TVD (ft): Tubing Size: 25' - 6,850'5-1/2" x 3-1/2" 20" 7-5/8" 81' 3,430' MD 1,490 6,890 29' - 110' 28' - 2,605' 29' - 110' 28' - 3,458' Prudhoe Bay Field, Borealis Oil Pool PBU L-122 PRESENT WELL CONDITION SUMMARY L-80 TVD Burst 8,795' 7,000 / 10,160 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 028239 203-051 3800 Centerpoint Drive, Suite 1400, Acnhorage, AK 99503 50-029-23147-00-00 Hilcorp North Slope, LLC COMMISSION USE ONLY Tubing Grade: Tubing MD (ft): 6,493' - 6,659' 8,621' / 6,078' Trevor Hyatt trevor.hyatt@hilcorp.com 777-8396 6,862' 9,210' 6,652' 2,944 None Length Size Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Set Whipstock for Lateral 10.01.2021 By Meredith Guhl at 11:13 am, Oct 01, 2021 321-524 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.10.01 06:53:30 -08'00' Monty M Myers 10-407 (L-122 L1) DLB 10/01/2021 DSR-10/5/21MGR01OCT2021 Mill window & X BOPE test to 3500 psi for service coil window milling operations. 24 hour notice to AOGCC. dts 10/5/2021 JLC 10/5/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.05 17:26:32 -08'00' RBDMS HEW 10/7/2021 To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: September 30, 2021 Re: PBU L-122 Sundry Request Sundry approval is requested to set a flow through whipstock and mill a window in L-122 pre- rig as part of the drilling and completion of the proposed L-122L1 CTD lateral. Proposed plan for L-122L1 Producer: Prior to drilling activities, a 3-1/2" Flow Through Whipstock will be set pre-rig with E-line in the 3-1/2" casing. The parent perforations will remain open. Service Coil will mill a single string window in the 3-1/2” casing (if scheduling needs arise, the rig will mill the window). See the L-116A PTD request for complete drilling details - A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 rig. The rig will move in, test BOPE and kill the well. The well will kick off drilling in the Kuparuk C, build through C and land in Kuparuk B. The well will build back up and drill the lateral in Kuparuk C to TD. The proposed sidetrack will be completed with a 2-3/8” L-80 solid liner with frac sleeves. Frac to be conducted post rig, see future L-122L1 Frac Sundry request for details. This completion will NOT abandon the parent Kuparuk perfs. Pre-Rig Work - (Estimated to start in December 2021): 1. Slickline: Dummy WS drift, dummy all mandrels, run caliper, set/pull TTP a. Drift past whipstock setting location b. Run caliper across whipstock setting location c. Dummy all 3-1/2” GLMs d. Set TTP at 8,644’md and perform MITs. Pull TTP after MIT-T and MIT-IA are complete. 2. Fullbore: MIT-IA to 4,000 psi and MIT-T to 4,500 psi 3. E-line: Set 3-1/2” flow through whipstock a. Top of whipstock set at 9,055’ MD (top of window - pinch point) b. Oriented 85° ROHS 4. Service Coil: Mill Window a. Mill 2.74” window with straight motor plus 10’ of rat hole b. Single string window exit out of 3-1/2” casing 5. Valve Shop: Pre-CTD Tree Work as necessary Rig Work: x Reference PBU L-122L1 PTD request submitted in concert with this request for full details. x General work scope of Rig work: 1. MIRU and Test BOPE - MASP with gas (0.10 psi/ft) to surface is 2,944 psi 2. Mill Window (only if not done pre-rig) 3. Drill Build and Lateral 4. Run Liner 5. Freeze Protect and RDMO 6. Set temporary LTP and frac post rig (see future L-122L1 Frac Sundry request) Future PTD Flow Through Whipstock w MIRU Service Coil Window Milling Surface Kit. 24 hour notice for AOGCC to wit- ness BOPE test to 3500 psi. pg This completion will NOT abandon the parent Kuparuk perfs. End of Sundry 321-524 The sundry and permit to drill will be posted in the Operations Cabin of the unit during the window milling operation. Window Milling Fluids Program: x A min EMW of 8.4 ppg KCL. KCl will be used as the primary working fluid and viscous gel sweeps will be used as necessary to keep the hole clean. x The well will be freeze protected with a non-freezable fluid (typically a 60/40 methanol/water mixture) prior to service coil’s departure. x Additionally, all BHA’s will be lubricated and there is no plan to “open hole” a BHA. Disposal: x All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4 or Pad 3. x Fluids >1% hydrocarbons or flammables must go to Pad 3. x Fluids >15% solids by volume must go to GNI. Hole Size: x The window and 10’ of formation will be milled/drilled with a 3.74” OD mill. Well Control: x BOP diagram is attached. x AOGCC will be given at least 24-hour notice prior to performing a BOPE function pressure test so that a representative of the commission can witness the test. x Pipe rams, blind rams, CT pack off, and choke manifold will be pressure tested to 250 psi and at least 3,500 psi. x BOPE test results will be recorded in our daily reporting system (Alaska Wells Group Reporting System) and will provide the results to the commission in an approved format within five days of test completion. x BOPE tests will be performed upon arrival (prior to first entry into the well) and at 7 days intervals thereafter. x 10 AAC 25.036 c.4.C requires that a BOPE assembly must include “a firewall to shield accumulators and primary controls”. A variance is requested based on the result of the joint hazop with the AOGCC. For our operation, the primary controls for the BOPE are located in the Operations Cabin of the Coiled Tubing Unit, and the accumulators are located on the backside of the Operations Cabin (opposite side from the well). These are approximately 70' from the well. Hazards: x PBU L-pad is an H2S pad. o The highest recorded H2S well on the pad was from L-110 (1,110 ppm) in 2021. o Last recorded H2S on L-122 was 40 ppm in 2021 Reservoir Pressure: x The maximum reservoir pressure is expected to be 3,604 psi at 6,600’ TVD (10.5 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,944 psi. x Reservoir pressure will be controlled with a closed circulating system and choke for backpressure to maintain overbalance to the formation. Trevor Hyatt CC: Well File Drilling Engineer Joseph Lastufka 907-223-3087 Coiled Tubing BOPs Well Slimhole Date Quick Test Sub to Otis -1.1 ft Top of 7" Otis 0.0 ft Distances from top of riser Excluding quick-test sub Top of Annular 6.0 ft Top of Annular Element 6.7 ft Bottom Annular 8.0 ft CL Blind/Shears 9.3 ft CL 2" Pipe/Slips 10.1 ft B1 B2 B3 B4 Choke Line Kill Line CL 2-3/8" Pipe/Slips 12.6 ft CL 2" Pipe/Slips 13.4 ft CL of Top Swab 16.0 ft Swab Test Pump Hose T1 T2 Swab 1 CL of Flow Cross 17.4 ft Master CL of Master 18.8 ft LDS IA OA LDS Ground Level CDR2-AC 4 Ram BOP Schematic 21-Nov-17 CDR2 Rig's Drip Pan 7-1/16" 5k Flange X 7" Otis Box Hydril 7 1/16" Annular 2" Pipe/Slips 7-1/16" 5k Mud Cross 2" Pipe/Slips Blind/Shear 7-1/16" 5 Mud Cross 2-3/8" Pipe/Slips e e Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~ 03 - 0 S 1 Well History File Identifier Organizing (done) 0wo-sided 1111111111111111111 o Rescan Needed 11111111111 II 111111 RESCAN DIGITAL DATA t,ø15iskettes, No. 1 o Other, No/Type: OVERSIZED (Scannable) o Maps: o Other Items Scannable by a Large Scanner o Color Items: o Greyscale Items: o Poor Quality Originals: OVERSIZED (Non-Scannable) o Other: o Logs of various kinds: NOTES: BY: ~ Date (p Ir loft; o Other:: 151 me III 11111111111 111I1 ~ {PI Project Proofing BY: ~ 151 Scanning Preparation BY: +J = TOTAL PAGES (Count does not include cover sheet) 151 Date: Production Scanning 1111111111111111111 Stage 1 Page Count from Scanned File: (P.:).. (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ¿ YES Qwiã) Date: & / 7/0 fp If NO in stage 1, page(s) discrepancies were found: YES NO 151 VV1f NO BY: Stage 1 BY: Maria Date: 151 1111111111111111111 Scanning is complete at this point unless rescanning is required. ReScanned III 1111111111111111 BY: Maria Date: 151 Comments about this file: Quality Checked 1/1 "111111I" 1111I 10/6/2005 Well History File Cover Page.doc t � D STATE OF ALASKA AKA OIL AND GAS CONSERVATION COMM1DON A U G 1 2 2013 REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Repair Well U Plug Perforations U Perforate U Other U Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: BP Exploration(Alaska),Inc Development el Exploratory ❑ 203-051-0 , 3.Address: P.O.Box 196612 StratigraphiC Service ❑ 6.API Number: Anchorage,AK 99519-6612 50-029-23147-00-00 • 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0028239 BRLS L-122 ., 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): To Be Submitted PRUDHOE BAY,BOREALIS OIL , 11.Present Well Condition Summary: Total Depth measured 9422 feet Plugs measured None feet true vertical 6862.04 feet Junk measured None feet Effective Depth measured 9311 feet Packer measured 8621 feet true vertical 6751.82 feet true vertical 6077.75 feet Casing Length Size MD ND Burst Collapse Structural None None None None None None Conductor 80 20"91.5#H-40 29-109 29-109 1490 470 Surface See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Intermediate None None None None None None Production 8771 5-1/2"15.5#L-80 25-8796 25-6243.86 7000 4990 Liner 614 3-1/2"9.3#L-80 8796-9410 6243.86-6850.12 10160 10530 Perforation depth Measured depth 9050-9062 feet 9062-9070 feet 9070-9082 feet 9094-9105 feet 9187-9217 feet True Vertical depth 6492.84-6504.75 feet 6504.75-6512.69 feet 6512.69-6524.59 feet 6536.5-6547.41 feet 6628.77-6658.53 feet Tubing(size,grade,measured and true vertical depth) See Attachment See Attachment See Attachment Packers and SSSV(type,measured and true vertical depth) 3-1/2"Baker SABL-3 Packer 8621 6077.75 Packer None None None SSSV 12.Stimulation or cement squeeze summary: Intervals treated(measured): Treatment descriptions including volumes used and final pressure: SCANNED NOV 0 8 2013 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 156 85 126 1060 338 Subsequent to operation: 93 600 153 1378 266 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development 0 Service❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil U • Gas ❑ WDSPLU GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUCO 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 Nita Summerhays Email Nita.SummerhaVS( BP.com Printed Name Nita Summerhays / Title Petrotechnical Data Technician _i �wr�orl►.%IIIi ��/l%�� Phone 564-4035 Date 8/12/2013 Ignat I iii' �f ■ Vii riBLMb AUG 2 0 2 i(/7///3 _ Form 10-404 Revised 10/2012 Submit Original Only • • Daily Report of Well Operations ADL0028239 ACTIVITYDATE r • . 'cIve 01 v= .. s o. •.)ec lye: • •• -e Rih w/SLB PT/GR/CCL/2.5" JSN. Tagged top of fill at 9058' ctm. Cleaned down to 9266' ctm. Chased out at 80% to 2000' and the gas diminished as well as returns. Let the well unload at surface. MU SLB PT/CCL and a 2"gun-6 SPF-60 Deg Phasing PJ HMX. Rih to TD at 9213' CTM 9229' corrected ELMD. Pulled Correlation log from TD to 8850' ctm. +16' depth shift to SLB Perforation log dated 26-July-2003. CCL to top shot= + 1/2" 9.2'. Pulled into shooting depth of 9177.8' CCL depth +9.2'to top shot. Launch 1/2 9 p P P Ball. Perforated interval 9187' -9217' ELMD. Freeze Protected wellbore to 2500'with 50/50 Methanol. At surface 7/19/2013 «<Job cont'd on 07-20-13 WSR>>> ASRC Test Unit 1 Inlet well L-T22 Outlet well L-02 CT-I-CO Assist***Cont from WSR 7/18/13*** 7/19/2013 STBY for CTU, Assist CTU ***Cont to WSR 7/20/13*** CTU #9 1.15"Active Coil (CV Tbbls) Job Objective: I-CO/Add pert **Cont'd from 07- 19-13 WSR** Lay down fired perf gun, 1/2" Ball recovered. Rig Coil unit down and turn over to ASRC for 8 hour test 7/20/2013 **Job Complete** ASRC Test Unit 1 Inlet well L-122 Outlet well L-02 CT I-CO Assist***Cont from WSR 7/19/13*** 7/20/2013 Assist CTU ***Cont to WSR 7/21/13*** ASRC Test Unit 1 Inlet well L-122 Outlet well L-02 CT1-CO Assiit***Cont trom WSR 7/20/13*** 7/21/2013 8 hr piggy test, rig down, Move unit***Job Complete*** FLUIDS PUMPED BBLS 280 1% SLICK KCL 45 POWERVIS 145 1% SLICK KCL WITH SAFELUBE 470 TOTAL Casing / Tubing Attachment ADL0028239 Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 20"91.5# H-40 29 - 109 29 - 109 1490 470 LINER 614 3-1/2" 9.3# L-80 8796 - 9410 6243.86 - 6850.12 10160 10530 PRODUCTION 8771 5-1/2" 15.5# L-80 25 - 8796 25 - 6243.86 7000 4990 SURFACE 3345 7-5/8"29.7#S-95 28 - 3373 28 - 2557.85 8180 5120 SURFACE 85 7-5/8"29.7# L-80 3373 - 3458 2557.85 - 2604.5 6890 4790 TUBING 8440 3-1/2" 9.2# L-80 23 - 8463 23 - 5933.17 10160 10530 TUBING 158 3-1/2" 9.2# 13Cr80 8463 - 8621 5933.17 - 6077.75 10160 10530 • TUBING 54 3-1/2"9.2# L-80 8621 - 8675 6077.75 - 6128.57 10160 10530 TUBING 126 3-1/2" 9.2# L-80 8670 - 8796 6123.85 - 6243.86 10160 10530 • I TREE= 3-1/8"5M CM/ • SAS NOTES: ***3-112"CHROME TBG 11VEi..L}fAD- 11'FMC SECTION FROM 8463'-8621 ONLY'r"ACTUATOR= BAKER_C L-122 PITIAL KB.El 7T BF.BEV= 50' _O =______ v30p_ 'Max AngIe= 58°4 4352' _ 1022' j-{TAM PORT OOt IAR Datum MD= 8994' Datum TVD= 6600'SS I nor $3-112-HT'S x NP,D=2.813" I 7-518"CSG,29.7#,S-95,ID=6.875" H 3373' IX X 7-5/8"CSG,29.7#,L-80,D=6.875' -I 3458' I-—A ■ GAS LFT MANDRELS ST MD 1VD DEV TYPE VLV LATCH PORT DATE 7 3536 2648 57 KBG2-9 DOME NT 16 07/05/11 6 4870 3395 56 KBG2-9 DMY NT 0 06101/06 Minimum ID =2.750"@ 8644' 5 6004 4107 44 KBG2-9 DOME NT 16 07/05/11 3-112" HES X NIPPLE 4 6936 4795 43 KBG2-9 DMY NT 0 05/06/06 3 7910 5495 44 KBG2-9 DOME INT 16 07/05/11 2 8509 5974 25 KBG2-9 SO NT 22 07/05/11 '°''1 8695 6148 19 KBG2-9 OPB4 POCKET - 10/03/05 3-1/2"TBG,92#,L-80 BT M .0087 bpf,D=2.992" H 8463' I "ORIGINAL GLM FROM 2003 COMPLETION BELOW PACKER 8666' H 3-1/2"HES X NP,D=2.813" I 3-1(718G.9.2#,13CR-80 VAMTOP H 8621' g, 8621' H3-1/2"BKR KBH-22S ANCHOR SEAL ASSY,N3=2.94" .0087 bpf,I)=2.992" _ ►_ 8621' H s_112"X 3-1/7 BKR SABL-3 P101,D=2.780" 1 I 8644' H3-1/2'FES X NP,D=2.750' I I3-1/2'TBG,9.2#,L-80 TCI,.0087 bpf,D=2.992' H 8665' I I 8670' HTBG STUB(05/04106 DIMS) I 8675' H5-1/2"X 3-1/2"UNIQUE OVERSHOT I 1 m 8752' -i 3-1/2"BKR GA)SL KING SLV,D=2813' I 3-1/2"TBG,9.2#,L-80,.0087 bpf,D=2.992' H 8766' 8776' -I BKR LOC SEAL ASSY,D=3.00" I L5-1/2"CSG,15.5#,L-80,0=4.950" H 8776 8776' TOP OF BKR PBR,0=4.00' I L ' -X 3.12"XO,D=2.95" H 8796' I— I 8795' U BIM OF 3-1/7 BKR SBR,D=3.00' I I 8878' H3-1/2"FES X f'1 D=2.813' 1 PERFORATION SUMMARY REF LOG: DENSITY/NEUTRON ON 0526103 I 8899' H 3-1/2"HES X NP,D=2.81X ANGLE AT TOP FE RE: 70'.9050' Note:Refer to Production DB for historical perf data I 8540' HPUPJTVII'RA TAG! SIZE SPF NTR VAL Opn/Sgz SHOT SQZ I 2-1/2 6 9050-9062 0 12/04/03 2-1/7' 6 9050-9070 0 07/26/03 2-1/2" 6 9062-9082 0 12/04/03 I 2-1/2" 6 9094-9105 0 12/04/03 2" 6 9187-9217 0 07/19/13 I 9181' HPUPJTWI RA TAG I I PBTD -I 9311' I 9210'C f i -I CTU CLEANED OUT(08/13/11) ►4tl4t144411 11404 1 3.1/2"LNR,9.2#,L-80,.0087 bpf,t)=2.997 H 9410' 41.1.1.1 DATE REV BY COMI+B'TTS BATE REV BY COMMENTS BOREALIS UNIT 05/31/03 DAV/KK ORIGINAL COMPLETION 07/29/11 RCT/PJC GLV GO(07/05/11) WELL L-122 05/06/06 NOES MO 08/14/11 SJVV/PJC FCO(08/13/11) PERMIT Pb: 1030510 0227/07 THJTLH GLV GO(02/18/07) 12/03/12 DOK/JMD TREE CORRECTION(12/01/12) API 2-b: 50-029-23147-00 02/16/08 KSB/TT_H GLV GO 08/05/13 JRPTJMD ADFERFS(07/19/13) SEC 34,T12N,R11E,2536'FSL&1449'FVVL 03/09/11 JNIJ PJC F LD CORRECTION 06/13/11 VVINR/PJC GLV GO(06/06/11) BP Exploration(Alaska) STATE OF ALASKA ALASKA OAND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Stimulate 0 Other ❑ Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator BP Exploration (Alaska), Inc. 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 Exploratory p - 203 -0510 3. Address: P.O. Box 196612 Stratigraphic❑ Service p 6. API Number: Anchorage, AK 99519 -6612 — 50- 029 - 23147 -00 -00 8. Property Designation (Lease Number) : 9. Well Name and Number: ADLO- 028239 ° L -122 10. Field /Pool(s): PRUDHOE BAY FIELD / BOREALIS OIL POOL 11. Present Well Condition Summary: Total Depth measured 9422 feet Plugs (measured) None feet true vertical 6862.04 feet Junk (measured) None feet Effective Depth measured 9311 feet Packer (measured) 8621 feet true vertical 6751.82 feet (true vertical) 6078 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 20" 91.5# H-40 29 - 109 29 - 109 1490 470 Surface 3345' 7 -5/8" 29.7# S -95 28 - 3373 28 - 2558 8180 5120 Surface 85' 7 -5/8" 29.7# L -80 3373 - 3458 2558 - 2605 6890 4790 Production 8771' 5 -1/2" 15.5# L -80 25 - 8796 25 - 6244 7000 4990 Liner 614' 3 -1/2" 9.3# L -80 8796 - 9410 6244 - 6850 10160 10530 Liner Perforation depth: Measured depth: SEE ATTACHED - ,g � - _ True Vertical depth: _ `�ii$I JUL 1 3 2011 _ Tubing: (size, grade, measured and true vertical depth) 3 -1/2" 9.2# L -80 23 - 8463 23 - 5933 3 -1/2" 9.2# 13CR80 8463 - 8621 5933 - 6078 3 -1/2" 9.2# L -80 8621 - 8795 6078 - 6243 Packers and SSSV (type, measured and true vertical depth) 3 -1/2" Baker SABL -3 Packer 8621 6078 R 12. Stimulation or cement squeeze summary: t )0\ ' Intervals treated (measured): f � _' 1 psi. f,;lattfi• g titUUUUSSion Treatment descriptions including volumes used and final pressure: >:�,: tip F 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing pressure Prior to well operation: 267 96 250 337 Subsequent to operation: 263 95 246 348 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development 0 ' Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ,. 0 Gas ❑ WDSPL ❑ GSTOR ❑ WINJ ❑ WAGE' GINJ ❑ 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: NA Contact Joe Lastufka Printed Na' a J. - Last i a i Title Petrotechnical Data Technologist Signa ure Ilitil't. Phone 564 -4091 Date 7/5/2011 r Form 10-404 Revised 10/2010 bmit Original Only CM JUG. 0 7 2111 �` rr• �� Su ,P3 i L -122 203 -051 ' PERF ATTACHMENT Sw Name Operation Date Perf Operation Code Meas Depth Top Meas Depth Base Tvd Depth Top Tvd Depth Base L -122 7/26/03 PER 9,050. 9,070. 6,492.84 6,512.69 L -122 12/4/03 APF 9,050. 9,062. 6,492.84 6,504.75 L -122 12/4/03 APF 9,062. 9,082. 6,504.75 6,524.59 L -122 12/4/03 APF 9,094. 9,105. 6,536.5 6,547.41 L -122 12/21/06 FIL 9,158. 9,311. 6,599.99 6,751.82 L -122 12/22/06 FCO 9,115. 9,158. 6,557.33 6,599.99 AB ABANDONED PER PERF APF ADD PERF RPF REPERF BPP BRIDGE PLUG PULLED SL SLOTTED LINER BPS BRIDGE PLUG SET SPR SAND PLUG REMOVED FCO FILL CLEAN OUT SPS SAND PLUG SET ill 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 OPEN HOLE III • • • L -122 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY 6/10/2011 1 * * *SLB Frac Crew * ** Job Scope: Fracture C Sands « <InterAct Publishing »> Rig I up frac equipment, LRS and Stinger tree saver. Pump break down /step down test and data frac. Datafrac analysis showed frac gradient = 0.66, leak -off coef = 0.0055, Pc = 1426 psi, Tc = 5.9 min, eff = 0.36. Pump frac at 20 bpm using 40# delayed XL gel: Pad stage of 175 Bbls, 1 PPA Flat stage w/ 10 gpt of L065 (Scale Inhibitor) for a 'total of 308 gals, ramp 1 PPA - 6 PPA in 125 bbls, pump flat 6 PPA for 125 Bbls, flat 17 PPA for 130 Bbls, flat 8 PPA for 150 Bbls, flat 9 PPA for 160 Bbls, flat 10 PPA for 1 198 Bbls. Flush volumes of 15 Bbls 40# XL gel, 17 bbls linear gel, and 42 bbls diesel placing freeze protect at 4000'. Pumped at total of 209,685 Ibs of 16/20 Carbolite propant, of which 208,272 Ibs were placed behind pipe and 1413 Ibs in liner. i ._..... ___..._.... _ . __.. i Propant top —295' above top perf. ** *Job Complete * ** FLUIDS PUMPED BBLS 42 DIESEL 241 15# LINEAR 1261 40# DELAYED XL 17 40# XL 1561 TOTAL TREE = 3 -1/8" 5M CIW WEL = 11" FMC • SAFETY FS: ***3-1/2" CHROME TBG (SECTION ACTUATOR = NA L - 1 2 2 FROM 8463' - 8621 ONLY') * ** KB. ELEV = 77' BF, ELEV = 50' ' KOP = _ = 300' Max Angie 58° @ 4352' 1022' H TAM PORT COLLAR 1 Datum MD = 8994' Datum TVD = 6600' SS I I 2207' H 3-1/2" HES X NIP, ID = 2.813" I I7 -5/8" CSG, 29.7 #, S -95, ID = 6.875" 1 - 1 3373' 17-5/8" CSG, 29.7 #, L -80, ID = 6.875" H 3458' I A l GAS LIFT MANDRELS -I ST MD TVD DEV TYPE VLV LATCH PORT DATE 7 3536 2648 57 KBG2 -9 DOME NT 16 06/13/11 6 4870 3395 56 KBG2 -9 DMY NT 0 06/01/06 Minimum ID = 2.750" @ 8644' 5 6004 4107 44 KBG2 -9 SO NT 20 06/13/11 3 -1/2" HES X NIPPLE 4 6936 4795 43 KBG2 -9 DMY NT 0 05/06/06 3 7910 5495 44 KBG2 -9 DMY NT 0 06/06/11 2 8509 5974 25 K8G2 -9 DMY NT 0 06/06/11 * *1 8695 6148 19 KBG2 -9 OPEN POCKET 10/03/05 13-1/2" TBG, 9.2 #, L -80 IBT -M, .0087 bpf, ID = 2.992" H 8463' 1 is * *ORIGINAL GLM FROM 2003 COMPLETION BELOW PACKER 8566' 1 HES X NIP, ID = 2.813" I 3-1/2" TBG, 9.2 #, 13CR -$0 VAM TOP, — 8621' 1 x ;, 8621' 1 - - 1/2" BKR KBH -228 ANCHOR SEAL ASSY, ID = 2.94" I 0087 bpf, ID = 2.992" C.4 8621' I--I5 - 1/2" X 3 -1/2" BKR SABL -3 PKR, ID = 2.780" I I I 8644' H 3-1/2" HES X NIP, ID = 2.750" I 13-1/2" TBG, 9.2 #, L -80 TCII, .0087 bpf, ID = 2.992" H 8665' I r ( 8670' H TBG STUB (05/04/06 DIMS) I I 8675' H 5 -1/2" X 3 -1/2" UNIQUE OVERSHOT 1 En EH 8752' —13-1/2" BKR CMD SLIDING SLV, ID = 2.813" I I3 -1/2" TBG, 9.2 #, L -80, .0087 bpf, ID = 2.992" 1-1 8766' 8776' H BKR LOC SEAL ASSY, ID = 3.00" I I5 -1/2" CSG, 15.5 #, L -80, ID = 4.950" H 8776' ' v 8776' H TOP OF BKR PBR, ID = 4,00" I 15-1/2" X 3 -1/2" XO, ID = 2.95" H 8796' I ' I 8795' I — I BTM OF 3 -1/2" BKR SBR, ID = 3.00" I I 8878' H3 -1 /2" HES X NIP, ID = 2.813" I PERFORATION SUMMARY I 8899' H 3 -1/2" HES X NIP, ID = 2.813" I REF LOG: DENSITY /NEUTRON ON 05/26/03 ANGLE AT TOP PERF: 7 @ 9050' Note: Refer to Production DB for historical perf data 1 8940' I-I PUP JT W/ RA TAG I SIZE SPF INTERVAL Opn /Sqz DATE 2 -1/2" 6 9050 - 9062 0 12/04/03 1 2 -1/2" 6 9050 - 9070 0 07/26/03 2 -1/2" 6 9062 - 9082 0 12/04/03 2-1/2" 6 9094 - 9105 0 12/04/03 1 9115' CTM I- J CTUCLEANEDOUT(12 /22/06) I 1 9181' H PUP JT W/ RA TAG 1 I PBTD I 9311' I 40. I3 -1/2" LNR, 9.2 #, L -80, .0087 bpf, ID = 2.992" H 9410' I DATE REV BY COMMENTS DATE REV BY COMMENTS BOREALIS UNIT 05/31/03 DAV /KK ORIGINAL COMPLETION 06/14/11 ALH/ PJC GLV C/0 (06/07/11) WELL: L -122 05/06/06 N9ES RWO 06/15/11 JLJ/ PJC GLV C/0 (06/13/11) PERMIT No: 2030510 02/27/07 TEL/TLH GLV C/O (02/18/07) API No: 50- 029 - 23147 -00 02/16/08 KSB/TLH GLV C/0 SEC 34, T12N, R11 E, 2536' NSL & 3831' WEL 03/09/11 JNL/ PJC FIELD CORRECTION 06/13/11 WWR/PJC GLV C/0 (06/06/11) BP Exploration (Alaska) ~ BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 ~a f h °~+ f ~~`~~~~."~~~ y`'E.' ~,~ .t. ~ ~c~~J ~ 4~w^lwL' . ->., August 14, 2009 ~ bp ~~~~~~~~ Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of GPB L-Pad Dear Mr. Maunder, o c T o~ zoos ~las~C~ ~ii ~ Gas Cons. Commi~~ion Anchorage ~,43 - O~ ~ ~. - I a.a- Enclosed please find multiple copies of a spreadsheet with a list of wells from GPB L- Pad that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Anna Dube, at 659-5102. Sincerely, Torin Roschinger BPXA, Well Integrity Coordinator ~ ~ BP Ezploration (Alaska ) Inc. SurNace Casing by Conductor Mnulus Cement, Corrosion inhihitor, Sealant Top-off Report of Sundry Operations (70~04) Date L pad 8/13/2009 Well Name PTD # API # Inftial to of cement Vol. of cement um ed Final top of cement Cement top off date Conosion inhibftor Corrosion inhibftod sealant date ft bbis ft na al L-01 2010720 50029230110000 NA 6 NA 612 6/25/2009 L-02A 2041490 50029230480100 NA 1.4 NA 14.5 6/27/2009 L-03 2051030 50029232690000 NA 2.8 NA 24.7 6/25/2009 L-04 2061200 50029233190000 NA 1.7 NA 15.3 6/25/2009 L-100 1980550 50029228580100 NA 6.2 NA 57.8 6/29/2009 L-101 1980320 50029228650000 NA 3.3 NA 30.6 6/29/2009 L-102 2020360 50029230710000 37' NA Need To Job? NA L-103 2021390 50029231010000 NA 1.6 NA 102 6/26/2009 L-104 2012380 50029230600000 NA 3.5 NA 47.6 5/6/2009 L-105 2020580 50029230750000 NA 1.75 NA 24.65 5/6/2009 L-t06 2012230 50029230550000 NA 2.75 NA 28.05 5/6/2009 1-107 2011510 50029230360000 NA 4.8 NA 57.8 5/6/2009 L-108 2021090 50029230900000 NA 1.2 NA 13.8 6/25/2009 L-109 2012010 50029230460000 NA 2.9 NA 32.3 6/27/2009 L-110 2011230 50029230280000 NA 27 NA 3162 6/29/2009 L-t i 1 2020300 50029230690000 NA 4.7 NA 54.4 6/29/2009 L-112 2022290 50029231290000 NA 5.5 NA 51 6/27/2009 ~-114A 2051120 50029230320100 NA 2.5 NA 25.5 6/29/2009 L-115 2011400 50029230350000 NA 0.5 NA 3.4 6/27/2009 L-116 2011160 50029230250000 NA 5 NA 54.4 6/28/2009 L-117 2011670 50029230390100 NA 2.9 NA 28.9 6/27/2009 L-118 2011870 50029230430000 NA 1.4 NA 15.3 6/27/2009 L-119 2020640 50029230770000 NA 2.25 NA 28.9 5/6/2009 L-120 2020060 50029230640000 NA 0.75 NA 6.8 5/5/2009 L-121A 2030390 50029231380100 NA 2.2 NA 25.5 6/27/2009 L-122 2030510 50029231470000 NA 2 NA 20.4 6/27/2009 L-123 2051940 50029232900000 NA 2 NA 18.7 6/27/2009 L-124 2050430 50029232550000 M1tA 1.8 NA 17 6/27/2009 L-200 2040010 50029231910000 NA 1.8 NA 13.5 6/26/2009 L-201 2040460 50029232020000 NA t.75 NA 15.3 5/6/2009 L-202 2041960 50029232290000 NA 2 NA 17 6/26/2009 L-204 2060920 50029233140000 NA 1.5 NA 5.95 5/6/2009 L-205 2080530 50029233880000 NA 1 NA 12.75 1/10/2009 L-210 2031990 50029231870000 NA 325 NA 31.4 5/5/2009 L-211 2040290 50029231970000 NA 1.8 NA 17 6/27/2009 L-212 2050300 50029232520000 NA 1.8 NA 17 6/26/2009 L-273 2060530 50029233080000 NA 2 NA 17 6/25/2009 L-214A 2060270 50029232580100 NA 025 NA 10.2 5/6/2009 L-215 2051270 50029232740000 NA 1.5 NA 30.6 5/6/2009 L-216 2040650 50029232060000 NA 1.3 NA 11.9 6/26/2009 L-217 2060750 50029233120000 late bbckin conductor NA NA L-218 2051190 50029232720000 NA 1.7 NA 15.3 6/27/2009 L-219 2071480 50029233760000 surface NA NA L-220 2080470 50029233870000 NA 2 NA 20.4 6/28/2009 L-221 2080310 50029233850000 NA 1.7 NA 16.2 6/25/2009 L-250 2051520 50029232810000 NA 3.4 NA 34 6/26/2009 L-50 2051360 50029232770000 NA 1.8 NA 20.4 6/27/2009 L-51 2060590 50029233090000 NA 1.8 NA 17 6/27/2009 OPERABLE: L-122 (PTD #2030 0} Tubing Integrity has been restored Page 1 of l Regg, James B (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com) ~~/ 3)~~'w Sent: Friday, February 15, 2008 12:43 PM / I To: NSU, ADW Well Integrity Engineer; Regg, James B (DOA); Maunder, Thomas E (DOA); GPB, Area Mgr West (GC2/WRD); GPB, GC2 OTL; GPB, GC2 Wellpad Lead; GPB, Well Pad LV; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor; Oakley, Ray (PRA) Cc: Roschinger, Torin T. Subject: OPERABLE: L-122 (PTD #2030510) Tubing Integrity has been restored All, Well L-122 (PTD #2030510) passed a MITIA on 02/15/07 after dummying off the gas lift valves proving integrity has been restored. The well has been reclasst- I~`eTas Operable and may be brought on line when convenient for operations. Please ~ be prepared for the IA pressure to increase due to thermal expansion as the lA is liquid packed. ~;~~ ~i~R `~ 200 From: NSU, ADW Well Integrity Engineer Sent: Friday, February 08, 2008 9:21 AM To: 'Regg, James B (DOA)'; 'Maunder, Thomas E (DOA)'; GPB, Area Mgr West (GC2/WRD); GPB, GC2 OTL; GPB; GC2-Wellpad Lead; GPB, Well Pad LV; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor Cc: NSU, ADW Welt Integrity Engineer; Roschinger, Torin T. Subject: L-122 (PTD #2030510) Under Evaluation for sustained casing pressure - TxIA communication All, Well L-122 (PTD #2030510) has been found to have sustained casing pressure on the IA. The wellhead pressures were 2020/2050/0 psi on 02/03/08. A subsequent TIFL failed on 02/08/08. The well has been classified as Under Evaluation and may be produced under a 28-day clock. The plan forward for this well is as follows: 1. D: TIFL -FAILED 2. S: Set DGLVs 3. F: MIT-IA to 3000 psi, LLR if fails A wellbore schematic and TIO plot have been included for reference. « File: L-122.pdf » « File: L-122.ZIP » Please call with any questions or concerns. Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 3/i312008 • • ~~- ~, .-~. ~~ - ~" .~ .., p,+A , :,:f ~. w` -~ ' • ~ o3io~~zoos DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs_Inserts\Microfilm_Marker.doc RE: L-122 (PTD #2030510) Und~valuation for sustained casing pressure - TxIA communicati... Page 1 of 1 Re , James B DOA • gg From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] Sent: Friday, February 08, 2008 9:23 AM To: NSU, ADW Well Integrity Engineer; Regg, James B (DOA}; Maunder, Thomas E (DOA); GPB, Area Mgr West (GC2/WRD); GPB, GC2 OTL; GPB, GC2 Wellpad Lead; GPB, Well Pad LV; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor Cc: Roschinger, Torin T. Subject: RE: L-122 (PTD #2030510) Under Evaluation for sustained casing pressure - TxIA communication Correction to subject line. The body of the email is correct as the Well is L-122 not L-22. ,~~ I(,~~ ~~~~ Thanks, Andrea Hughes ~~~~~ FEB ~ Q 200 From: NSU, ADW Well Integrity Engineer Sent: Friday, February 08, 2008 9:21 AM To: 'Regg, James B (DOA)'; 'Maunder, Thomas E (DOA)'; GP6, Area Mgr West (GC2/WRD); GPB, GC2 OTL; GPB, GC2 Wellpad Lead; GPB, Well Pad LV; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor Cc: NSU, ADW Well Integrity Engineer; Roschinger, Torin T. Subject: L-22 (PTD #2030510) Under Evaluation for sustained casing pressure - TxIA communication All, Well L-122 (PTD #2030510) has been found to have sustained casing pressure on the IA. The wellhead pressures were 2020/2050/0 psi on 02/03/08. A subsequent TIFL failed on 02/08/08. The well has been classified as Under Evaluation and may be produced under a 28-day clock. The plan forward for this welt is as follows: 1. D: TIFL -FAILED 2. S: Set DGLVs 3. F: MIT-IA to 3000 psi, LLR if fails A wellbore schematic and TIO plot have been included for reference. « File: L-122.pdf» « File: L-122.ZIP » Please call with any questions or concerns. Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 2/I 1/2008 ~,aoo - ~ ..~.._-~___.__.._v .~ L-'122 TI4 Plo# __ ~ ~ ~,aoa ~ 2,000 1,000 0 12P8~00~ 12J1812oa~ 12~28l200~ 1 P8~o08 1 rl 8008 1 ~28~008 2!8l2aa8 2l18~008 2rzsraoo 5 6 ~ 8 ~ 10 11 12 13 14 15 16 1l 18 ~ Tbg 221200$ 2J1 X2008 1 X3112008 1 ~30~2008 1 ~9~008 1128 2008 1 E27~008 1 ~26~2008 1 ~4~2008 1 C22l2008 1 (21(2008 1 E20~008 i 11900$ 1 ~1 ~~i 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 20 1,950. 1,950 1,950. 1,980 1,: IA 2~~1008 211 X008 1 X31 ~00$11~30~2008 1 ~Z9~008 1!28{2008 1 {272008 1 ~8r2008 1 124 200$ 1 E22l2008 1 X211"100$ 1 l20~2008 1 M 9 2008 1 11 7~2~ n nnn n nnn ^~ nnn 7 nnn n nnn n nnn n nnn n nnn ^r nnn n nnn a nnn anon a nnn n . # Tbg i~ -~ o~ ao~ OOOA• TREE = 3-1 i8" 5h;1 CI4~J +fJELLHEAD= 11" FMC ACTUATOR= NA KB. ELEV = 77' BF. ELEV. ~0 K{7P _ . 30(7' tvlax Angle = 58" cv, 4352' 17aturn It1D = .~ ~-.~.~aww, _._ Datum TV D - 8994' ...m ~ __ ... 66CQ' SS 7-518" CSG, 29.7#, 5-95; iD = 6.875" I`~ 3373° 7-5?8" CSG, 29.7#, L-80, ID = 6.875" ~--~ 3458' +~ 1gq1°l lr~tll'I I,.I C1l ~® =p1.'jy{9)~# ~~' J°i'aGfe HES NA~P~E ~3-1l2" TBG, 9.2#, L-80113T-fi~#; .OQ87 bpf, ID= 2.992" ~-f 8463' ~ 3-112'° TBG, 9.2#, 93CR84 VA TOP. ID = 2.992" ~ j 3-1?2" TBG, 9.2#, L-80 TCII; .Ob87 i7pf, lD = 2.992" ~--{ $665' 3-1,`2" TBG, 9.2#, L-8{l, .C087 bpf, ID = 2.992" 5-1?2°' CSG, 15.5#, l~ 8b. ID = 4.95C" 5-1?2" X 3-1?2°' CSG XE), #D = 2.95" 8766' $796' PERFC?RAT(QN SU~AIv3ARY REF LOG: DENS[TYINEUTRON t3N 05(26;C3 A NGLE A T TC7P PERP 7 @ 8050' Nate: Refer to Praduatian DB fcr histarical parf data SIZE SPF INTERVAL C7pn?Sqz tIATE 2-1/2" 6 9050 - 9062 £3 12?04/03 2-112" 6 9C5b - 9{}7b €:} 07?26?03 2-1?2" fi 9C62 - 9(182 J 12lb4?03 2-112" fi 9C94 - 9105 f 3 12104?03 PBTD 9311° 3-1 (2" CSG, £3.2;#, L-BCS. ID = 2.992" 941 Q' L-122 N®TES: ***3-112°° CfiROE rBG (5ECrlON $463` - $621 t)NLIt )*"* 1 U22' --i TAM PORT COLLAR 2207' 3-112" HES X NIP, Ifs = 2.813„ GAS LIFT MANDRELS ST (~4D TVD DEV TY~ VLV LATCH PORT DATE 7 3536 26%+8 57 KBG2-9 DOME INT 16 02118?07 6 4870 3395 56 KBG2-9 L~livll' IN7 C 06i'01r`06 5 6004 4107 44 KBG2-9 DO~AE INT 16 02,18/07 d 6936 4795 4'3 KBG2-9 '7Pv11' lNT 0 05x'06/06 3 7910 5495 44 KBG2-9 DOME INT 16 02118x'07 2 8509 5974 25 KBG2-9 SQ INT 22 02!18107 **1 8695 6148 19 KBG2-9 OPEN POCKET C 10,`03,-05 ""C}RIGlNAI GLiN FRUM 2043 C{)NIP€-EI'!(3N EELOYV PACKER ~$$' 3-112" HES X NIP, ID = 2.813" 8621' 3-112" BKR KBH-22S ANCHOR SEAL ASSY, iD = 2.94" 8621' S-112" X 3-1 i2" BKR SABL-3 I'ICR, ID = 2.780" 8 --~3-1,'"2" HES X NIP, ID = 2.750" $670' TBG STUB (05?04;06 DIMS} $675' S-1 r2'° X 3-112" UNIG2UE OV ERSHUT 8752° -- j 3-1?2" BKR CMD SLIDING SLV, ID = 2.813„ $776° BKR L(~C SEAL ASSY, ID = 3.00" 8776° TOP OF BKR PBR, ID = 4.00°' 8795' Bl"M OF 3-1?2" BKR 513R, tD = 3.0C" 8$78° 3-1 %2" HES X NIP, ID = 2.813" $899° - 3-1?2" FIES X NIP, ID = 2.813" 8940` I~JP ,7T W? RA ?AG 9115' CTM -~CTUCLF~4NEDOlIT(12/22.!06 91$1' ~ PUPJTVV,' RA TAG DATE REV E3Y COMI~IFJ~•JT:S DATE REV BY COMfv#ENTS 45131f43 DAV?KK ORIGINAL COMPLETION 02?b4?b7 Il•1GS?TLH GLV C'O & X LJCK PULL.F_D 45146!46 N9ES 12WO 0212CI07 JC~rU'PAG CTU CLEANC3UT CORRECTION 05/20?06 K`v'~IAITLH DRLG DRAFT (:{3RRECTItJNS 02127107 TELr7LH GLV~C/C} (02118/07} 061C4.-C6 DAt,1,'PAG GLV G`CJ,()6i'01i06} _ -°---° -- 06i16i06 RCT?PJC GLV C?O 12/16/06 DAV.?PJC MIN ID & X N1P CORRECTIONS PRUDHOE BAY UNIT WEZI_: L-122 PERP~tIT Na: 2030510 APE Na: 5C-029-23147-Ob SEC 34, Ti'LN, R11 E, 2536' NSL & 3831' UIEI l3P Exploration {Alaska) Scblumberger RECENEO AUG 1 Û 2006 commiss\Cn 0\1 & Gas CO\'lS· A\aS\(a Anchoroge 08/09/06 NO. 3916 Schlumberger.DCS 2525 Gambell St, Suite 400 Anchorage, AK 99503·2838 ATTN: Seth Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Borealis Orion Well Job# Log Description Oate SL Color CD L·122 40009065 OH EDIT OF MWD/LWD OS/26/03 6 1 L·211 40010216 OH EDIT OF MWD/LWD 03/08/04 2 1 L·211 PBI 40010216 OH EDIT OF MWD/LWD 03/03/04 2 1 . PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COpy EACH TO: SP Exploration (Alaska) Inc. Petrotechnical Data Center LR2·1 900 E Senson Slvd. Anchorage AK 99508-4254 SCANNED §\UG :1 /~ ?OCB Schlumberger·DCS 2525 Gambell St. Suite 400 Anchorege. AK 99503·2838 A TTN: Seth Date Delivered: Received by: . 9:53 --os- ( :d /~'ô /'7 t/L !flbf ð6 _ STATE OF ALASKA _ ALAS~JL AND GAS CONSERVATION ~MISSJON REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: o Abandon ~ Repair Well o Plug Perforations o Stimulate o Other o Alter Casing ~ Pull Tubing o Perforate New Pool o Waiver o Re-Enter Suspended Well o Change Approved Program o Operation Shutdown o Perforate o Time Extension 2. Operator Name: 4. Well Class Before Work: 5. I-'ermit 10 urilJ Number: BP Exploration (Alaska) Inc. ~ Development 0 Exploratory 203-051 3. Address: o Stratigraphic o Service 6. API Number: P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-23147-00-00 7. KB Elevation (ft): 77' 9. Well Name and Number: PBU L-122 8. Property Designation: 10. Field / Pool(s): ADL 028239 Prudhoe Bay Field / Borealis Pool 11. Present well condition summary Total depth: measured 9422 feet true vertical 6862 feet Plugs (measured) None Effective depth: measured 9311 feet Junk (measured) None true vertical 6752 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 34" x 20" 110' 110' 1490 470 Surface 3430' 7-5/8" 3458' 2605' 8180 5120 Intermediate 8771' 5-1/2" 8796' 6244' 7000 4990 Production Liner 614' 3-1/2" 8796' - 9410' 6244' - 6850' 10160 10530 Perforation Depth MD (ft): 9050' - 9105' Perforation Depth TVD (ft): 6493' - 6547' Tubing Size (size, grade, and measured depth): 3-1/2",9.2# L-80 8795' Packers and SSSV (type and measured depth): 5-1/2" x 3-1/2" 'SABL' packer 8621' 12. Stimulation or cement squeeze summary: "'CANNE-'; "CD') Q Intervals treated (measured): !j <,' t. '),LI I,' ',y Treatment description including volumes used and final pressure: RBDMS 8Ft MAY] 6 7.006 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casino Pressure Tubina Pressure Prior to well operation: Subsequent to operation: 14. Attachments: o Copies of Logs and Surveys run 15. Well Class after proposed work: ~ Daily Report of Well Operations o Exploratory ~ Development o Service ~ Well Schematic Diagram 16. Well Status after proposed work: ~Oil o Gas o WAG OGINJ OWINJ o WDSPL 17. I hereby certify that the toregolng IS true and correct to the test ot my Knowledge. I Sundry Number or N/A if C.O. Exempt Contact Ken Allen, 564-4366 N/A Printed Name Terrie Hubble Title Technical Assistant ~^fI; IJ ¡{,ßM.ç Phone Date OSjIO/Ck:Þ Prepared By Name/Number: Signature 564-4628 Terrie Hubble, 564-4628 . . Form 10-404 RevIsed 04/2006 üt{\G r~AL Submit Onglnal Only ,TREE = 3-1/8" 5M CIW WElLHEAD = 11" FMC ACTUA TOR = NA KB. ElEV = 77' SF. ElEV = 50' KOP = 300' Max Angle = 58° @ 4352' Datum MD = 8994' Datum 1VD = 6600' SS e DRLG L-122 .AÆTYNOTE5: -I 1022' --fTAMPORTCOLLAR I 2207' -13-1/2" HES X NIP, 10 = 2.813" 17-518" CSG, 29.7#, L-80, ID = 6.875" , GAS LIFT MANDRELS ST MD lVD DEV TYPE VLV LATCH PORT DATE Minimum ID = 2.75" @ 8644' 6 3536 2648 56 KBG2-9 DMY INT 0 05106/06 3-1/2" HES 'BPX' X Nipple 5 4870 3395 56 KBG2-9 DCK INT 05106/06 4 6004 4107 44 KBG2-9 DMY INT 0 05/06/06 3 6936 4795 43 KBG2-9 DMY INT 0 05106/06 2 7910 5495 44 KBG2-9 DMY INT 0 05/06/06 1 8508 5975 25 KBG2-9 DMY INT 0 05/06/06 8695 6148 19 KBG2-9 INT 10/03/05 13-1/2" TBG, 9.2#, L-BO, IBT-M, 10 = 2.992" 13-112" TBG, 9.2#, 13Cr, VamTop, 10 = 2.992" H 8621' 5-1/2" CSG, 15.5#, L-80, ID = 4.950" I 15-1/2" X 3-1/2" CSG XO, ID = 2.95" PERFORATION SUMMARY REF LOG: DENSITY/NEUTRON ON OS/26/03 ANGLE AT TOP PERF: 7 @ 9050' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 2-1/2" 6 9050 - 9062 0 12/04/03 2-1/2" 6 9050 - 9070 0 07/26/03 2-1/2" 6 9062 - 9082 0 12/04/03 2-1/2" 6 9094 - 9105 0 12/04103 PBTD H 9311' 13-1/2" CSG, 9.2#, L-80, 10 = 2.992" I DATE 05/31/03 07/26/03 12/04/03 02/05/04 04/22/05 07/18/05 REV BY COMMENTS DAV/KK ORIGINAL COMPLETION BJMlKK IPERF KLClTLP ADPERFS GJBITLP GL V C/O RWLITLH GL V C/O RWLlTLH GL V C/O DATE 10/03/05 10/17/05 12/11/05 05/06/06 -13-112" HES X NIP, 10 = 2.813" I 8621' 1-15-1/2" X3-1/2" SABL PKR, 10 = 2.78" 8644' 1-13-112" HES BPXNIP, 10 = 2.75" I 8670' 8675' --TOP OF 3-1/2" L-80 10=2.992" TBG STUB (05/4/0(,) -I UNIQUE OVERSHOT I --13-1/2" BKR CMD SLIDING SLV, ID = 2.813" I--TOP OF BKR PBR, 10 = 4.00" I -3-1/2" BKR SEAL ASSY, ID = 3.00" -13-1/2" HES X NIP, ID = 2.813" H3-1/2" HES X NIP, ID = 2.813" I 8940' -l PUP JT WI RA TAG I 9181' --fPUPJTW/RATAG REV BY COMMENTS DA V ITLH GL V C/O KSB/PJC GL V C/O DA V /TLH PX TIP SET 9ES RWO Com pletion PRUDHOE BA Y UNIT WElL: L-122 PERMIT No: ~030510 API No: 50-029-23147-00 SEC 34, T12N, R11 E, 2536' NSL & 3831' WEl BP Exploration (Alaska) e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L-122 WORKOVER NABORS ALASKA DRILLING I NABORS 9ES Start: 4/29/2006 Rig Release: 5/6/2006 Rig Number: Spud Date: 5/20/2003 End: 5/6/2006 Bridle up and lower skate chute. Remove pins from derrick. Function kick overs. Lower derrick Move pits away from substructure and position out of the way. Pull sub off well L-213i on spot onto L-122. Lever rig and berm up around cellar area. Move pits into postion next to sub and level same. Raise derrick and pin in place. Raise and pin skate chute. Bridle down and pin blocks to Topdrive. Connect interconnect between sub and pits and take on brine in pits. Rig accepted @ 1000. Install kelly hose, clear rig floor, prep. cellar area for circulation operations. Berm flow line area outside. Ready cellar, complete pre-spud check list. Lubricate out BPV with DSM. 0 PSI on IA and 80 PSI on OA RU and pressure test circulating system to 3,500. Line up and pump down annulus taking returns up the tubing via open pocket in GLM at 8695. Initial pressure at 1 BPM @ 2400 PSI. Unable to circulate at rates greater than 1 BPM do to high pressures. Circulate app. 90 bbls and still getting some diesel and dirty water. Shut down and allow diesel to migrate to top of brine inside tubing. Pump app. 5 more bbls. with minor amounts of diesel in returns. Switch over and pump down the tubing. While pumping down the tubing taking returns back the annulus, the restriction was blown out of system and the rate was increased to 4 bbls. per minute at 850. Take dirty returns directly into cutting tank thru choke and out of flare line. Some gas seen in returns while clearing annulus. Shut down for diesel/gas to migrate up. Circulate additional 30 minutes to insure well is dead. DECOMP Observe well and monitor for signs of gas. OK DECOMP Blow down lines. Install 2 way check and test from below. DECOMP N/D tree and secure in cellar. Confirm threads in hanger to be TC-II and in good working order. Install XO into hanger and count and record number of turns required to make up connection. (8 1/4 turns) DECOMP N/U BOP system. DECOMP Continue to NU BOPE. DECOMP RU and test BOPE to 250 psi / 4,000 psi. Test annuluar to 250 psi /3,500 psi. No failures. Witness of the test was waived by John Crisp of the AOGCC. Witness of the test was conducted by Brian Tiedemann with NAD and James Franks with BP. RD testing equipment. RU DSM lubricator and pull TWC. RD DSM lubricator. Hold PJSM with SLB Slickline. Bring Slickline tools to the floor and start to RU to run slickline. RD slickline equipment. Wait on FMC hand to arrive on location. Install TWC and test from below to 1,000 psi. Change out the upper set of rams to 7". Test door seals to 3,500 psi - good. RU DSM lubricator and pull TWC. PJSM. RU Slickline equipment.. Run #1: RIH with 2.7" OD JDC to pull prong from PX plug. Started to take weight at 1,800'. At 2,000' decide to POH to 4/29/2006 00:00 - 01 :30 1.50 MOB P PRE 01 :30 - 06:00 4.50 MOB P PRE 06:00 - 07:30 1.50 MOB P PRE 07:30 - 09:30 2.00 RIGU P PRE 09:30 - 10:00 0.50 RIGU P PRE 10:00 - 13:00 3,00 RIGU P PRE 13:00 - 13:30 0.50 WHSUR P DECOMP 13:30 - 14:30 1.00 KILL P DECOMP 14:30 - 19:30 5.00 KILL P DECOMP 19:30 - 20:00 20:00 - 21 :00 21 :00 - 22:30 0.50 KILL P 1.00 KILL P 1.50 WHSUR P 4/30/2006 22:30 - 00:00 00:00 - 01 :00 01 :00 - 07:00 1.50 BOPSU P 1.00 BOPSU P 6.00 BOPSU P 07:00 - 08:30 1.50 WHSUR P DECOMP 08:30 - 10:30 2.00 FISH P DECOMP 10:30 - 11 :00 0.50 WHSUR N WAIT DECOMP 11 :00 - 11 :30 0.50 WHSUR P DECOMP 11 :30 - 13:00 1.50 BOPSU P DECOMP 13:00 - 13:30 0.50 WHSUR P DECOMP 13:30 - 15:30 2.00 FISH P DECOMP 15:30 - 16:00 0.50 FISH P DECOMP Printed: 5/812006 11:56:16 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L -122 WORKOVER NABORS ALASKA DRILLING I NABORS 9ES Start: 4/29/2006 Rig Release: 5/6/2006 Rig Number: Spud Date: 5/20/2003 End: 5/6/2006 4/30/2006 15:30 - 16:00 0.50 FISH P DECOMP changeout centralizer to 2.5" OD. 16:00 - 18:00 2.00 FISH P DECOMP Run #2: RIH with 2.5" OD JDC to pull prong from PX plug. Took weight at 8,689' SLM. Attempt to work past - no good. POH. Found the JDC pin had sheared on the tool indicating a possible latch up on the PX prong. 18:00 - 21:00 3.00 FISH P DECOMP Run #3: RIH with 2.5" OD JUC to pull prong from PX plug. Took weight at 2,075'. Pump the tools down to 8,706'. 5 bpm, 1,750 psi. Shut down the pumps, adjust the slickline load cell and attempt to work past - no good. POH. Not marks on the tool. 21 :00 - 00:00 3.00 FISH P DECOMP Run #4: RIH with 2.75" Lead Impression Block to 8701'. POH. Definite indication of Frac Sand fill in the tubing. Prepare to run Bailer 5/1/2006 00:00 - 01 :30 1.50 FISH P DECOMP Bailer Run #1: RIH with 2.25" pump bailer to 8,696'. POH. Recovered -1 gallon of trac sand. 01 :30 - 03:30 2.00 FISH P DECOMP Bailer Run #2: RIH with 2.25" pump bailer to 8,680'. POH. Recovered -1.5 gallons of frac sand. 03:30 - 05:30 2.00 FISH P DECOMP Bailer Run #3: RIH with 2.25" pump bailer to 8,686' - pump tools down - 1 bpm, 1,500 psi initially. After -35 bbl pumped, pressure dropped and the rate was increased to 5 bpm, 1400 psi until tagging up. POH. Recovered -1.5 gallons of sand. 05:30 - 07:00 1.50 FISH P DECOMP Bailer Run #4: RIH with a drive down bailer to 8,692'. POH. Recovered -1 gallon of frac sand. 07:00 - 09:00 2.00 FISH P DECOMP Bailer Run #5: RIH with a pump bailer to 8,696'. POH. Recovered -0.75 gallons of frac sand. 09:00 - 10:30 1.50 FISH P DECOMP Bailer Run #6: RIH with a pump bailer to 8,698'. POH. Recovered 0 gallons of frac sand. 10:30 - 12:00 1.50 FISH P DECOMP Bailer Run #7: RIH with 2.25" pump bailer to 8,685'. POH. Recovered -1 gallon of frac sand. 12:00 - 15:45 3.75 FISH P DECOMP Circulate and annular volume - 220 gpm, 1,690 psi. Pump a 10 bbl, 280 FV, viscous pill at 220 gpm, 1,690 psi - recovered -35 to 50 gallons of frac sand. Pump another 10 bbl, 280 FV, viscous pill at 220 gpm, 2,500 psi - recovered very little frac sand. Circulate and spot a 10 bbl, 280 FV, viscous pill in the 5.5" x 3.5" annulus at the GLM to keep sand from entering the tubing. 15:45 - 16:30 0.75 FISH P DECOMP Bailer Run #8: RIH with 2.25" pump bailer to 8,692'. POH. Recovered -0.5 gallons of frac sand. 16:30 - 18:00 1.50 FISH P DECOMP Bailer Run #9: RIH with 2.25" pump bailer to 8,700'. POH. Recovered -0.75 gallons of frac sand. 18:00 - 19:30 1.50 FISH P DECOMP Bailer Run #10: RIH with 2.25" pump bailer to 8,704'. POH. Recovered -0.75 gallons of frac sand. 19:30 - 21 :00 1.50 FISH P DECOMP Bailer Run #11: RIH with 2.25" pump bailer to 8,713'. POH. Recovered -0.5 gallons of frac sand. 21 :00 - 22:30 1.50 FISH P DECOMP Bailer Run #12: RIH with 2.25" pump bailer to 8,717'. POH. Recovered -0.5 gallons of frac sand. 22:30 - 00:00 1.50 FISH P DECOMP Bailer Run #13: RIH with 2.25" pump bailer to 8,717'. POH. 5/212006 00:00 - 00:15 0.25 FISH P DECOMP Continue POH w/ Bailer Run #13 - recovered - 0.5 gallons of frac sand. 00:15 - 01:30 1.25 FISH P DECOMP Bailer Run #14: RIH with 2.25" pump bailer to 8,717'. POH. Recovered - 0.5 gallons of frac sand. 01 :30 - 02:30 1.00 FISH P DECOMP Slip and cut slickline. 02:30 - 03:30 1.00 FISH P DECOMP Bailer Run #15: RIH with 2.25" pump bailer to 8719'. POH. Printed: 5/812006 11 :56: 16 AM e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L-122 WORKOVER NABORS ALASKA DRILLING I NABORS 9ES Start: 4/29/2006 Rig Release: 5/6/2006 Rig Number: Spud Date: 5/20/2003 End: 5/6/2006 5/212006 02:30 - 03:30 1.00 FISH P DECOMP Recovered - 0.5 gallons of frac sand. 03:30 - 04:30 1.00 FISH P DECOMP Bailer Run #16: RIH with 2.25" pump bailer to 8,721 '. POH. Recovered - 0.5 gallons of frac sand. 04:30 - 06:00 1.50 FISH P DECOMP Bailer Run #17: RIH with 2.25" pump bailer to 8,723'. POH. Recovered - 0.75 gallons of frac sand. 06:00 - 07:00 1.00 FISH P DECOMP Bailer Run #18: RIH with 2.25" pump bailer to 8,723'. POH. Recovered - 0.75 gallons of frac sand. 07:00 - 08:30 1.50 FISH P DECOMP Bailer Run #19: RIH with 2.25" pump bailer to 8,725'. POH. Recovered - 0.25 gallons of frac sand. 08:30 - 10:00 1.50 FISH P DECOMP Bailer Run #20: RIH with 2.25" pump bailer to 8,726'. POH. Recovered - 0.75 gallons of frac sand. 10:00 - 11 :00 1.00 FISH P DECOMP Bailer Run #21: RIH with 2.25" pump bailer to 8,727'. POH. Recovered - 0.75 gallons of frac sand. 11 :00 - 12:00 1.00 FISH P DECOMP Bailer Run #22: RIH with 2.25" pump bailer to 8,728'. POH. Recovered - 0.5 gallons of frac sand. 12:00 - 13:00 1.00 FISH P DECOMP Bailer Run #23: RIH with 2.25" pump bailer to 8,730'. POH. Recovered - 0.5 gallons offrac sand. 13:00 - 14:30 1.50 FISH P DECOMP Bailer Run #24: RIH with 2.25" pump bailer to 8,732'. POH. Recovered - 1.25 gallons of frac sand. 14:30 - 16:00 1.50 FISH P DECOMP Bailer Run #25: RIH with 2.25" pump bailer to 8,733'. POH. Recovered - 1.5 gallons of frac sand. 16:00 - 17:30 1.50 FISH P DECOMP Bailer Run #26: RIH with 2.25" pump bailer to 8,733'. POH. Recovered - 1.5 gallons of frac sand. 17:30 - 19:00 1.50 FISH P DECOMP Bailer Run #27: RIH with 2.25" pump bailer to 8,735'. POH. Recovered - 1.25 gallons of frac sand. 19:00 - 21 :00 2.00 FISH P DECOMP Bailer Run #28: RIH with 2.25" pump bailer to 8,738'. POH. Recovered - 0.25 gallons of frac sand. Saw some marks on the bottom of the bailer indicating top of the prong. 21 :00 - 23:00 2.00 FISH P DECOMP Re-calibrate the Slicklline depth counter. RIH with 2.5" JU tool to pull the prong. Tag up and latch onto the prong at 8,747' SLM - unable to get prong to release. Shear pin and released the JU tool from the prong. POH. 23:00 - 00:00 1.00 FISH P DECOMP Change over and RIH with a 2.5" JD tool. Tag up and latch up at 8,747' SLM. With the well shut in, jar up and pull prong free - no increase in pressure seen on the tubing or on the annulus. POH with the prong. 5/3/2006 00:00 - 01 :00 1.00 FISH P DECOMP Bailer Run #29: RIH with 2.25" pump bailer to 8,750'. POH. Recovered - 0.75 gallons of frac sand and some sludge. The serrated edge on the bottom of the bailer were flattened indicating top of the PX plug. 01 :00 - 02:00 1.00 FISH P DECOMP Bailer Run #30: RIH with 2.25" snorkel bailer to 8,750' to clean out the latching profile. POH. Recovered -0.25 gallons of frac sand and sludge. 02:00 - 03:30 1.50 FISH P DECOMP RIH with 3.5" GS tool to retrieve PX plug. Latch into the plug and POH. SITP and SICP - 260 psi 03:30 - 06:00 2.50 KILL P DECOMP Attempt to bleed off pressure - 10 bbls. Shut in and observe pressure - SITP and SICP - 260 psi. Circulate surface to surface through the choke holding -300 psi on the backside with 9.2 ppg brine to clear the influx - not acting like gas - 2 bpm, 2300 psi Once a bottoms up was seen, we started to get a lot of crude back in the returns. Complete pumping a surface to surface without seeing a decrease in the crude contaminated brine. SITP and SICP - 350 psi. Printed: 5/812006 11 :56: 16 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L -122 L -122 WORKOVER NABORS ALASKA DRILLING I NABORS 9ES Start: 4/29/2006 Rig Release: 5/6/2006 Rig Number: Spud Date: 5/20/2003 End: 5/6/2006 5/3/2006 06:00 - 08:30 2.50 KILL P DECOMP Weight up the surface system to 9.9 ppg with NaCI while waiting on 10.2 ppg brine to arrive. Close the blinds and the Slickline BOPE. Disconnect the luricator to verify that the PX plug was retrieved - verified. Reconnect the Slickline lubricator and open the BOPE and blinds. 0645 - Notified AOGCC via pager that we had to circulate through the choke. 08:30 - 09:30 1.00 KILL P DECOMP Attempt to bullhead 9.9 ppg fluid down the tubing and the annulus. Pressure up on both sides to 4,200 psi. Let bleed down to 3,000 psi. Repressure up to 3,800 psi several times - pumped 11 bbls away - locked up. Bleed off the tubing and the annulus pressure. 09:30 - 10:30 1.00 KILL P DECOMP Circulate 9.9 ppg brine from surface to surface - 5 bpm, 1,680 psi - ICP, 1,700 FCP. Shut in the well, SITP and SICP - 190 psi 10:30 - 14:30 4.00 KILL P DECOMP Take on 290 bbls of 10.2 NaCl/NaBr brine. Weight up to 10.7 with NaBr. 14:30 - 16:00 1.50 KILL P DECOMP Displace the well over to 10.7 ppg brine - 5 bpm, 1,750 psi. Reduce rate to 3 bpm, 650 psi - Casing pressure reading 10-20 psi. Shut down and monitor the well - stable. 16:00 - 17:30 1.50 KILL P DECOMP RD Slickline tools - lubricator, BOPE and pump in sub. 17:30 - 19:30 2.00 WHSUR P DECOMP Install TWC and attempt test from below to 1,000 psi - failed. RU and pull TWC with DSM lubricator - found outer rubber seal damaged. Install new TWC with DSM lubricator and test from below to 1,000 psi - good. 19:30 - 20:30 1.00 BOPSU P DECOMP Changeout the upper rams from 7" to 3-1/2" x 6" variables. RU and test rams to 250 psi / 4,000 psi - good. RD testing equipment 20:30 - 21 :30 1.00 WHSUR P DECOMP RU and pull TWC with DSM lubricator. RD DSM lubricator. 21 :30 - 23:00 1.50 PULL P DECOMP RU the landing joint. Back out the lock down screws and make several attempts to pull the tubing out of the SBR, working the up weight to 195k max - unsuccessful. Run in the lock down screws and torque to 450 psi. RD landing joint. 23:00 - 23:30 0.50 WHSUR P DECOMP Dry rod install the TWC. Test from below to 1,000 psi - good. 23:30 - 00:00 0.50 BOPSU P DECOMP Changeout the upper rams from 3-1/2" x 6" variables to 7". 5/4/2006 00:00 - 00:30 0.50 BOPSU P DECOMP Continue changeout the upper rams from 3-1/2" x 6" variables to 7". Test doors to 3,500 psi - good. 00:30 - 01 :45 1.25 WHSUR P DECOMP Spot SLB E-line and bring BOPE, lubricator and sheaves to the rig floor. 01 :45 - 03:00 1.25 WHSUR P DECOMP RU and pull TWC with DSM lubricator. RD DSM. 03:00 - 11 :00 8.00 PULL P DECOMP PJSM. RU and RIH with 2-5/8" chemical cutter on SLB E-line. Spot and cut original 3-1/2" tubing in the middle of the first full joint above the lowest GLM - 8,670'. POH. RD SLB E-line equipment. 11 :00 - 12:30 1.50 PULL P DECOMP RU to pull tubing to verify cut. Back out the lock down screws. PU and verify that the tubing is cut - PU - 105k, SO - 70k. Re-Iand the tubing. Clear and clean the floor. 12:30 - 13:00 0.50 WHSUR P DECOMP Drain the BOP stack and install a TWC. Test from below to 1,000 psi - good. 13:00 - 14:00 1.00 BOPSU P DECOMP Change the upper rams from 7" to 3-1/2" x 6" variables and test to 250 psi I 4,000 psi - good. 14:00 - 15:00 1.00 WHSUR P DECOMP RU DSM lubricator and pull TWC. RD DSM lubricator. 15:00 - 15:30 0.50 PULL P DECOMP MU landing joint and pull hanger to the rig floor, PU - 102k. Circulate a bottoms up at 5 bpm, 1,290 psi. Shut in and Printed: 5/8/2006 11:56:16AM e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L-122 WORKOVER NABORS ALASKA DRILLING I NABORS 9ES Start: 4/29/2006 Rig Release: 5/6/2006 Rig Number: Spud Date: 5/20/2003 End: 5/6/2006 monitor the well - stable. MW in and out - 10.7 ppg. RU to pull the original 3-1/2" completion. LD 3-1/2" completion to 5,000'. Continue to LD 3-1/2" completion from 5,000'. Recovered 272 joints of 3-1/2" 9.2# L-80 IBT-m tubing, 5 GLM's, an 'X' nipple, and 15.39' cut joint. Function the blind-shear rams. Clear and clean the rig floor. RU and pressure test the lower pipe rams to 250 psi / 4,000 psi. RD testing equipment. MU landing joint to the tubing hanger, make a dummy run and mark on landing joint. PU and RIH with 3-1/2" overshot completion. All connectionss below the packer have been Bakerloc'd and torqued to 2,300 ftlbs. All chrome Vam Top connections were torqued to 2,900 ftlbs utilizing Jet Lube Seal Guard thread lubricant. AIIIBT-m connections torqued to 2,400 ftlbs utilizing Best-o-life 2000 NM thread lubricant. RUNCMP Changeout bails from short to long. RUNCMP Continue to PU and RIH with the 3-1/2" completion. PU 7 more joints and then screwed a TIW and a head pin onto joint #278 to circulate down while the overshot went over the tubing stub @ 8,670'. Circulated down at 2 bpm, 500 psi. Saw no pressure increase as we swallowed the stub. Took weight on the shear pins in the over shot and sheared them with -1 Ok SO. Continued to RIH and tag the nogo 4' later. PU to the up weight +2' to get spaceout. RUNCMP LD joints 278, 277 and 276. PU 20' spaceout PU and then PU #276 and RIH. Make up tubing hanger, drain the stack, Land tubing on the hanger and RILDS. Unique Machine Overshot -5' over the tubing stub. 5/4/2006 15:00 - 15:30 0.50 PULL P DECOMP 15:30 - 16:00 0.50 PULL P DECOMP 16:00 - 00:00 8.00 PULL P DECOMP 5/5/2006 00:00 - 06:30 6.50 PULL P DECOMP 06:30 - 07:30 1.00 PULL DECOMP 07:30 - 08:30 1.00 BOPSU DECOMP 08:30 - 09:00 0.50 RUNCMP 09:00 - 23:00 14.00 RUNCMP 5/6/2006 23:00 - 00:00 00:00 - 01 :00 1.00 RUNCO 1.00 RUNCO 01 :00 - 02:00 1.00 RUNCO PU - 116k, SO - 66k Unique Machine Overshot (9.2' total interior length - 5' over stub) - 8674.70 HES 3.5" x 2.750" "X" Nipple w/Hi Press X Lock & RHC-m plug - 8644.29 SABL Hydraulic Set Prod Packer - 8621.27 KBH-22S Anchor Tubing Seal - 8620.52 3.5 x 2.813" HES "X" nipple - 8566.14 3.5"x1" Camco GLM # 1 KBG-2-9CR w/dummy, integral latch - 8508.92 3.5"x1" Camco GLM # 2 KBG-2-9CR w/dummy, integral latch - 7910.32 3.5"x1" Camco GLM # 3 KBG-2-9CR w/dummy, integral latch - 6936.38 3.5"x1" Camco GLM # 4 KBG-2-9CR w/dummy, integral latch - 6004.38 3.5"x1" Camco GLM # 5 KBG-2-9CR w/DCK shear, integral latch - 4870.39 3.5"x1" Camco GLM # 6 KBG-2-9CR w/dummy, integral latch - 3536.24 3.5" x 2.813 HES "X" Nipple - 2207.27 Printed: 5/8/2006 11:56:16 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L-122 WORKOVER NABORS ALASKA DRILLING I NABORS 9ES Start 4/29/2006 Rig Release: 5/6/2006 Rig Number: Spud Date: 5/20/2003 End: 5/6/2006 20:00 - 21 :00 1.00 WHSUR P RU and reverse circulate 179 bbls of clean 10.7 ppg brine, 45 bbls of 10.7 ppg brine wlcorrosion inhibitor and 58 bbls of clean 10.7 ppg brine - 3 bpm, 1,000 psi. RD circulation lines. RUNCMP Drop the 1-5/16" ball and rod and allow to seat in the RHC-m plug at 8,644'. Attempt to pressure up on the tubing- unsuccesful. Pump at a higher rate to attempt to land the ball and rod and repressure up on the tubing - unsuccessful. Wait a little longer and try again - appears ball is on seat. Pressure up to 4,500 psi - chart and hold for 30 minutes - good. Bleed off the tubing pressure to 2,500 psi. Pressure up on the annulus to 3,500 psi - chart and hold for 30 minutes - good. Bleed off the annulus pressure and then the tubing pressure to zero. Pressure up to 2,500 psi on the annulus and observe the shear of the DCK-3 valve in the GLM at 4,870'. Install TWC and test from below to 1,000 psi - good. ND the BOP stack and remove the mouse hole. NU the tree and adapter flange. Test to 5,000 psi - good. Wait on DSM to pull the TWC. Changeout the bails and the quill, service the top drive, crown and draw works while waiting. RU DSM lubricator and pull TWC. RU LRHOS. Freeze protect the tubing and the annulus to 2,750' MD - 2,200' TVD with 60 bbls of diesel. U-tube the diesel from the annulus to the tubing, OA - 400 psi, Tbg - 200 psi. Remove remaining fluid from the pits while waiting for the diesel to u-tube. RUNCMP Install BPV with DSM lubricator and test from below to 1,000 psi - good. RD LRHOS and DSM lubricator. Install VR plugs in the IA. Secure the cellar area. Release the rig to S-121 at 2100 hours. 04:30 - 07:30 07:30 - 07:30 24.00 WHSUR P RUNCMP 07:30 - 09:00 1.50 BOPSU P RUNCMP 09:00 - 10:30 1.50 WHSUR P RUNCMP 10:30 - 15:00 4.50 WHSUR N WAIT RUNCMP 15:00 - 16:00 1.00 WHSUR P RUNCMP 16:00 - 20:00 4.00 WHSUR P RUNCMP Plinled: 5/812006 11:56:16AM . '\1_ \.J..... V L..: U . STATE OF ALASKA A JAN 1 8 2006 ALA_Oil AND GAS CONSERVATION COMM~N REPORT OF SUNDRY WELL OPERATIONSAJaska Oil & Gas Cons. Commission 1. Operations Abandon D Repair Well D Plug Perforations 0 Stimulate D Other onchoraøe Performed: Alter Casing D Pull Tubing D Perforate New Pool D Waiver D Time Extension D Change Approved Program D Operat. Shutdown D Perforate D Re-enter Suspended Well D 2. Operator BP Exploration (Alaska), Inc. 4. Current Well Class: 5. Permit to Drill Number: Name: Development ¡;a Exploratory 0 203-0510 3. Address: P.O. Box 196612 Stratigraphic 0 Service 0 6. API Number: Anchorage, AK 99519-6612 50-029-23147-00-00 7. KB Elevation (ft): 9. Well Name and Number: 77 KB L-122 8. Property Designation: 10. Field/Pool(s): ADL-028239 Prudhoe Bay Field/ Borealis Oil Pool 11. Present Well Condition Summary: Total Depth measured 9422 feet Plugs (measured) 8752 TT true vertical 6862.04 feet Junk (measured) None Effective Depth measured 9311 feet true vertical 6751.82 feet Casing Length Size MD TVD Burst Collapse Conductor 80 20" 91.5# H-40 29 - 109 29 - 109 1490 470 Surface 3430 7-5/8" 29.7# S-95/L-80 28 - 3458 28 - 2604.5 8180/6890 5120/4790 Production 8771 5-1/2" 15.5# L-80 25 - 8796 25 - 6243.86 7000 4990 Production 614 3-1/2" 9.2# L-80 8796 - 9410 6243.86 - 6850.12 10160 10530 Perforation depth: Measured depth: 9050 - 9105 ~'e^NN"~~t CEP 2 c. 2nm) '" ,.' . ,t;,c/ V '. .J <:J __.v.... True Vertical depth: 6492.84 - 6547.41 Tubing: (size, grade, and measured depth) 3-1/2" 9.2# L-80 23 - 8795 Packers and SSSV (type and measured depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: RBDMS BFL JAN 2 0 2006 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure I Tubing pressure Prior to well operation: SHUT-IN Subsequent to operation: SHUT-IN 14. Attachments: 15. Well Class after oroposed work: Copies of Logs and Surveys Run Exploratory 0 Developm ent Pi Service Daily Report of Well Operations X 16. Well Status after proposed work: Oil P Gas 0 WAG 0 GINJ 0 WINJ 0 WDSPl 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. I~Undry Number or N/A if C.O. Exempt: N/A Contact Sharmaine Vestal Printed Name Sharmaine Vestal / Title Data Mgmt Engr Signatur~~' ~ Phone 564-4424 Date 1/17/2006 .' Form 10-404 Revised 04/2004 U K f lj II\! A L Submit Original Only ... ~~"'I' ,.....-. . . L-122 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY ACTIVITYDATE 12/11/2005 ***WELL S/I ON ARRIVAL *** RIH W/ 2.5" CENT & S. BAILER. SAT DOWN @ 8855' SLM. S. BAILER HAD WHAT APPEARS TO BE SAND. LRS PUMPED 1 BBL. OF CRUDE. RIH W/ 2.5" CENT & S. BAILER. SAT DOWN @ 8861' SLM. S. BAILER CONTAINED MORE OF THE SAME MATERIAL. RUNNING CALIPER. ***JOB CONTINUED ON 12-12-05*** 12/11/2005 T/I/O=1050/1070/0 Assist slickline with caliper. Rigged up to tree cap & pumped 1 bbls diesel to move sand bridge down hole, SWS to set TTP. Tubing pressured up to 2000 psi, Bled back to 1000 psi RDMO. FWHP's=1000/1180/0 12/12/2005 T/I/O=1000/1000/0 Assist Slickline. CMIT TxlA PASSED @ 2400 psi. (Shut In)(Well Secure) TxlA pressured up w/ 2.5 bbls Diesel Pumped. TBG lost 20 psi and IA lost 20 psi in 15 min. w/ total TBG loss of 20 psi and IA loss of 20 psi in 30 min. Final WHP's=760/780/0 12/12/2005 ***JOB CONTINUED FROM 12-11-05*** CALIPER TUBING FROM 8861' SLM TO SURFACE. SET 3-1/2' PX PLUG BODY IN SLIDING SLV @ 8730' SLM. SET PRONG @ 8730 (1.75" FN & BODY, 96" LENGTH). CMIT TO 2400 PSI PASSED. PLUG LEFT IN HOLE ***WELL LEFT S/I*** FLUIDS PUMPED BBLS 1 I ::::L 1 ~~. ~ v...9- DATA SUBMITTAL COMPLIANCE REPORT 8/1/2005 Permit to Drill 2030510 Well Name/No. PRUDHOE BAY UN BORE L-122 Operator BP EXPLORATION (ALASKA) INC -rct¿ ;{,D fVk; ~Q~ API No. 50-029-23147-00-00 MD 9422 __ TVD 6862/ Completion Date 7/26/2003.r' Completion Status 1-01L Current Status 1-01L UIC N REQUIRED INFORMATION Mud Log No Samples No D;",ct;O",!~ DATA INFORMATION Types Electric or Other Logs Run: MWD, GR, RES, NEW, DEN, PWD Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name ~ D Asc Directional Survey Well Cores/Samples Information: (data taken from Logs Portion of Master Well Data Main!) Log Log Run Interval OH/ Scale Media No Start Stop CH Received Comments final 0 9422 Open 6/16/2003 Sample Interval Set Start Stop Sent Received Number Comments . Name ADDITIONAL INFORMATION Well Cored? Y~ Chips Received? ~ ~ Daily History Received? ~ 6)/N Formation Tops Analysis Received? ~ . Comments: Compliance Reviewed By: Date: ..... It STATE OF ALASKA . ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Stimulate 00 OtherO Abandon 0 Repair Well 0 PluQ PerforationsD Alter CasingO Pull TubingO Perforate New Pool 0 WaiverO Time Extension 0 Change Approved Program 0 Operation Shutdown 0 Perforate 0 Re-enter Suspended Well 0 2. Operator BP Exploration (Alaska), Inc. 4. Current Well Class: 5. Permit to Drill Number: Name: Development Œ1 Exploratory 0 ^^^Ar~^ 3. Address: P.O. Box 196612 6. API Number Anchorage, Ak 99519-6612 Stratigraphic D Service 0 50-029-23147-00-00 7. KB Elevation (ft): 9. Well Name and Number: 77.00 L-122 8. Property Designation: 10. Field/Pool(s): ADL-0028239 Prudhoe Bay Field I Borealis Oil Pool 11. Present Well Condition Summary: Total Depth measured 9422 feet true vertical 6862.0 feet Plugs (measured) None Effective Depth measured 9311 feet Junk (measured) None true vertical 6751.8 feet Casing Length Size MD TVD Bu rst Collapse Conductor 80 20" 91.5# H-40 29 - 109 29.0 - 109.0 1490 470 Production 8771 5-1/2" 15.5# L-80 25 - 8796 25.0 - 6243.9 7000 4990 Production 614 3-1/2" 9,3# L-80 8796 - 9410 6243.9 - 6850.1 10160 10530 Surface 85 7-5/8" 29.7# L-80 28 - 113 28.0 - 113.0 6890 4790 Surface 6772 7-5/8" 29.7# 5-95 113 - 6885 113.0 - 4757.2 8180 5120 Perforation depth: RECEIVED Measured depth: 9050 - 9070, 9070 - 9082, 9094 - 9105 True vertical depth: 6492.84 - 6512.69,6512.69 - 6524.59,6536,5 - 6547.41 SEP 2 1 2004 Tubing ( size, grade, and measured depth): 3-1/2" 9.3# L-80 @ 23 - A/alks Oil & Gas C 879 . on$, Gømmj~~¡øl1 Packers & SSSV (type & measured depth): None AnChorage .. 12. Stimulation or cement squeeze summary: Intervals treated (measured): 9050 - 9105 Treatment descriptions including volumes used and final pressure: 207.5 K Lbs Carbo lite using YF-130LG System @ 6929 psig 13 Representative Dailv Averaae Production or Iniection Data Oil-Bbl Gas-Met Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 280 0.2 76 1400 327 Subsequent to operation: 2213 1.2 1241 500 340 14. Attachments: 15. Well Class after proposed work: ExploratoryD DevelopmentŒ ServiceD Copies of Logs and Surveys run _ 16. Well Status after proposed work: Daily Report of Well Operations. ! OilŒJ GasD WAG 0 GINJD WINJD WDSPLD Prepared by Garry Catron (907) 564-4657. 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ISUndry Number or NIA if C.O. Exempt: Contact Garry Catron 303-379 Printed Name Garry Catron Title Production Technical Assistant Signature J1r~AÁÁÁ C~ Phone 564-4657 Date 9/20104 . v Form 10-404 Revised 4/2004 ORIG'~~¡~L ~ . ' It . L-122 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY 01/31/04 FRAC'D C SANDS PERFS 9050'-9105' WI 209K# CARBOLlTE USING YF-130LG SYSTEM. PLACED 207.5K# BEHIND PIPE, UNDER FLUSH BY 5 BBLS, LEFT 1458# IN CSG, EST. TOS= 9170' MD. MAX TREAT = 7560 PSI, AVG TREAT =6900 PSI. LOAD TO RECOVER- 1255 BBLS. WELL LEFT SHUT IN. ALL ELEMENTS AND CUPS ON ISOLATION TOOL RECOVERED. FLUIDS PUMPED BBLS 1790 Fresh Water 150 Diesel 1940 TOTAL Page 1 " .. STATE OF ALASKA . ALAS~IL AND GAS CONSERVATION CO SSION REPORT OF SUNDRY WELL OPERATIONS ~. 1. Operations Performed: Abandon 0 Alter Casing D Change Approved Program D 2. Operator SuspendD RepairWellD Pull TubingD Operation Shutdown D Plug PerforationsD Perforate New Pool 0 4. Current Well Class: Perforate ŒI WaiverO OtherD Stimulate D Time ExtensionD Re-enter Suspended Well 0 5. Permit to Drill Number: 203-0510 Name: BP Exploration (Alaska), Inc. 3. Address: P.O. Box 196612 Anchorage, Ak 99519-6612 7. KB Elevation (ft): Development 00 ExploratoryD 77.00 8. Property Designation: ADL-0028239 11. Present Well Condition Summary: Stratigraphic 0 ServiceD 9. Well Name and Number: L-122 10. Field/Pool(s): Prudhoe Bay Field I Borealis Oil Pool 6. API Number 50-029-23147-00-00 Total Depth measured 9422 feet true vertical 6862.0 feet Effective Depth measured 9311 feet true vertical 6751.8 feet Plugs (measured) None Junk (measured) None Casing Length Size MD TVD Burst Collapse Conductor 80 20" 91.5# H-40 29 109 29.0 109.0 1490 470 Production 8771 5-112" 15.5# L-80 25 - 8796 25.0 - 6243.9 7000 4990 Production 614 3-112" 9.3# L-80 8796 - 9410 6243.9 - 6850.1 10160 10530 Surface 85 7-5/8" 29.7# L-80 28 113 28.0 113.0 6890 4790 Surface 6772 7-5/8" 29.7# S-95 113 - 6885 113.0 - 4757.2 8180 5120 Perforation depth: Measured depth: 9050 - 9070,9070 - 9082,9094 - 9105 True vertical depth: 6492.84 - 6512.69, 6512.69 - 6524.59, 6536.5 - 6547.41 Tubing ( size, grade, and measured depth): 3-1/2" 9.3# L-80 @ 23 8795 .1 Fi Packers & SSSV (type & measured depth): None 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13 Prior to well operation: Subsequent to operation: Oil-Bbl 439 275 Representative Dailv Averaqe Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure 1.6 0 0 0.15 74 100 Tubing Pressure 360 327 14. Attachments: 15. Well Class after proposed work: ExploratoryD Development ŒI ServiceD Copies of Logs and Surveys run _ 16. Well Status after proposed work: Operational Shutdown D Oil 00 GasD WAG D GINJD WINJD WDSPLD Prepared by Garry Catron (907) 564-4657. SUndry Number or NIA if C.O. Exempt: 303-358 Title Production Technical Assistant Daily Report of Well Operations. ! 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Garry Catron Printed Name G.~Iry Catron Signature J..,l1, C~4 Phone 564-4657 Date 3/11/04 Form 10-404 Revised 12/2003 OR\G\NAL RBDMs Bfa.. MAR It) 1M . . L-122 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY 12/01/03 DRIFT TO 9245' (SLM) 2.5 DUMMY GUN. TARGET 9105' MD. WELL TURNED OVER TO DSO, LEFT SHUT IN. 12/04/03 Perforate 9050'-9082' 6 SPF, 9094'-9105' 6 SPF FLUIDS PUMPED BBLS No Fluids Pumped o ITOTAL Page 1 ,. . "'FETY NOTES: TREE = 3-118" 5M CWV WELU£AO= 11" FMC À-CWA ï'ÕR = NA L-122 KB. RBI >;;~ '>-»77' IfF. ELBI = 50' KOP= 300' Max Angle = 58" @ 4352' = ~ 1022' HTAMPORTCOLLAR I Datum fII1) = 8994' Datum 'lVO = 6600' SS -- 2730' H3-1/Z' f-ESX NIP, 10=2.813" I 7-5I8"CSG, 29.7#, 5-95, 10= 6.875" H 3373' ~ 17-518" CSG, 29.7#, L-80, 10 = 6.875" H 3458' r--a GAS LIFT IIt\ð.NORB..S ¡Minimum ID = 2.813" @2730' I ST fII1) TVO OBI TYPE VLV LATCH FQRr DATE 3-1/2" HES X NIPPLE L 6 3441 2596 57 KBG2-9 OOfvE INT 16 02105/04 5 4704 3303 55 KBG2-9 OMY INT 02105/04 4 6132 4200 42 KBG2-9 OOfvE INT 16 02105/04 3 7367 5107 45 KBG2-9 OOfvE INT 16 02105/04 2 8203 5718 38 KBG2-9 OOfvE INT 16 02105/04 1 8695 6147 19 KBG2-9 S/O INT 24 02105/04 PERFORATION SUMIlt\ð.RY REF LOG: DENSITY/NB.JlRON ON 05126/03 ANGLEATTOP ÆRF: 7@ 9050' IIbte: Refer to A'oduction DB for hislorical perf data SIZE SPF INTER\! AL Opn/Sqz DA lE 2-1/2" 6 9050 - 9062 0 12/04103 2-1/2" 6 9050 - 9070 0 07/26/03 2-1/2" 6 9062 - 9082 0 12/04103 2-1/2" 6 9094-9105 0 12/04103 I I --- 8752' H3-1/Z' BKR 0v10SLlOING SLV, 10= 2.813" I 13-1/2" TBG, 9.2#, L-80, .0087 bpf, 10 = 2.99Z' H 1 5-1/2" CSG, 15.5#, L-80, 10 = 4.950" H 15-112" X3-1/2"CSG XO, 10 =2.95" H 8766' 8776' ~ q ---i - -----1 8776' 8776' 8795' 8878' HBKRLOCSEALASSY, 10= 3.00" I HTOPOFBKRPBR, D=4.00" 1 ~BTMOF3-112" BKRSBR, D =3.00" H3-1/Z' HES X NIP, 10 = 2.813" 1 H3-1/Z' HES X NIP, 10= 2.813" I 8796' 8899' 8940' HpLP Jf W/ RA TAG I 9181' HpLPJfW/ RA TAG 1 PBm H 9311' ~ 13-1/Z' CSG, 9.2#, L-80, 10 = 2.992" H 9410' DAlE 05131/03 06/02/03 07/26/03 12/04103 01/20/04 02/05104 REV BY COMfvENTS DAV/KK ORIGINAL COMPLETION f'v1H/KK GLV CiO BJ MIKK IPERF KLC/1LP AIYERFS OAV/1LH GLV CiO GJBIlLP GLV CiO DATE REV BY COMfvENTS PRUDHOE BAY LNIT WELL: L-122 PERfv1T lib: 2030510 API lib: 50-029-23147-00 SEe 34, T12N, R11E, 2536' NSL & 3831' WB.. BP Exploration (Alaska) - WC¡Æ- fl.' l1/z.o03 I/rzf )L/ /7 ß 7fftZ1J 7 .. STATE OF ALASKA . ALAS~IL AND GAS CONSERVATION CO SSION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 1. Type of Request: D Abandon Suspend D Alter CasinQ 0 Repair Well 0 Change Approved Program 0 Pull Tubing 0 2. Operator Name: BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, Ak 99519-6612 7. KB Elevation (ft): 3. Address: 77.00 KB 8. Property Designation: ADL-0028239 11. Total Depth MD (ft): 9422 Casing Conductor Production Production Surface Surface Perforation Depth MD (ft): 9050 9070 9070 9082 9094 9105 Packers and SSSV Type: 110 20" 91.5# H-40 8771 5-1/2" 15.5# L-80 614 3-1/2" 9.3# L-80 85 7-5/8" 29.7# L-80 6772 7-5/8" 29.7# S-95 Perforation Depth TVD (ft): 6493 6512.7 6513 6524.6 6537 6547.4 None 12. Attachments: Description Summary of Proposal ŒI Detailed Operations Program ŒI BOP Sketch D 14. Estimated Date for Commencing Operation: 16. Verbal Approval: Commission Representative: December 25, 2003 /' Date: Operation Shutdown D PluQ Perforations D Perforate New Pool D PerforateD VarianceD StimulateŒ / Time ExtensionD Re-enter Suspended Well 0 4. Current Well Class: Development Œ] Exploratory D 5. Permit to Drill Number: 203-0510 / Annular Disposal D OtherO StratigraphicD Service D 9. Well Name and Number: / 6. API Number / 50-029-23147-00-00 Plugs (md): None Burst top bottom top bottom 28 138 28.0 138.0 1490 25 8796 25.0 6243.9 7000 8796 9410 6243.9 6850.1 10160 28 113 28.0 113.0 6890 113 6885 113.0 4757.2 8180 Tubing Size: Tubing Grade: Tubing MD (ft): 3.5 " 9.3 # L-80 23 Packers and SSSV MD (ft): None 13. Well Class after proposed work: ExploratoryD Development ŒI L-122 10. Field/Pool(s): Prudhoe Bay Field / Borealis Oil Pool PRESENT WELL CONDITION SUMMARY I Total Depth TVD (ft): I Effective Depth MD (ft): Effective Depth TVD (ft): 6862.0 9311 6674.8 Length Size MD TVD 15. Well Status after proposed work: Oil [!] GasD PluggedD WAG D GINJD WINJD Junk (md): None Collapse 470 4990 10530 4790 5120 8795 ServiceD Abandoned 0 WDSPL D...-:=:).. Perpared by Gãr(f Ca~ ,,64-4657. ~ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name Signature Bruce Smith Á. ~ 'J /~ Contact Bruce Smith Title Petroleum Engineer Phone 564-5093 Commission Use Onlv 12/15/03 I Sundry Number: 303-37/, Location Clearance clì E eEl VE D DEC 1 7 Z003 61:a~ka Oil & Gas Cons. comm~'s 'oi0n BY ORDERlW P?'-' THE COMMISSION Dati:nchorage r v'. r7J () 5 Plug Integrity 0 Conditions of approval: Notify Commission so that a representative may witness Mechanciallntegrity Test D Other: Subsequent Form Required: Approved by: BOP TestD I 0 - '/-0 t.{. VI ¡gina\ S\gnod By Sarah Palin Form 10-403 Revised 2/2003 ORIGI~L~L RBDMS BFt OEC 1 8 "3 SUBMIT IN DUPLICATE bp .".- .1. ~ ~~. ~..- ~....-. --.~ ~~-- ·II'·~§\" ". To: . . Doug Cismoski /John Smart GPB Well Ops Team Leaders Date: December 8, 2003 Revised 12-10-03 From: Bruce Smith Michael Coker GPB Satellites Engineer GPB Wells Engineer Subject: L-122 Frac Completion (Revised 12-10-03) AFE: BRD5M4125 Est. Cost: $500M lOR: 2000 BOPD Revision: In regards to pumping only diesel for all HOT IA applications, no dead crude"""" Attached is the completion program to fracture stimulate the C sand in L-122. The procedures require 1600 Bbls of fresh water for diagnostics and fracturing with 235 Mlbs of 16/20 / Carbo Lite proppant. See pump schedules for details. Fluid and proppant volumes should be adequate to address contingencies. The procedure includes the following major steps: Step 1 2 3 4 5 6 7 Category o o S o C S T Last test: Max Deviation: Perf deviation: Min.ID: Last TD tag: Last Downhole Ops: Latest H2S value: BHT & BHP: Latest H2S: Reference Log: Cc: Well File Bruce Smith lOR 2000 2000 2000 2000 2000 2000 2000 Pri 1.00 1.00 1.00 1.00 1.00 1.00 1.00 / Description HOT IA and tubing for POP Liquid pack, freeze protect & MITIA. Pull and dummy GLVs. Set SPMG. DataFrac and Frac Kuparuk C-Sand. Shut In "" Over-balanced reverse FCO. Pull SPMG and DGL Vs and set LGL Vs POP & Frac flowback. HOT tubing, SIMULTANEOUSLY POP ./ 547 BOPD, 761 BWPD, 2385 MCFPD on 9/24/03. 58° @ 4352' MD. 7° @ 9050' MD. 2.813": 3-1/2' HES X NIPPLE @ 2730'MD. 9285' CaRR, pre SBHPS on 09/25/03. CT Hydrate/lceplug CO, drift to 4000' CTM and FP on 10/05/03 No Record in Database 158°F. Pr @ 9236' MD (6600' TVDSS) = -3150 PSI 10 ppm 2003 / SWS Density/Neutron on OS/26/03 Contacts Bruce Smith Steve Deckert Michael Coker Office Home Cell 564-5093 345-2948 440-8008 564-4128 338-1476 240-8046 564-5850 258-7586 223-0582 ec: Mike Coker Brad Musgrove Petredat Gary Elmore . . 1) Prepare well for C-Sand Fracture Treatment: a) HOT IA and tubing for POP i) Pump 175bbls warm diesel (MeOH spear) into lA, taking returns to flowline. ii) POP well, flow 24-48 hrs. Well test and NOC sample. b) Slickline work: (1) Freeze protect IA and Tbg with Seawater and diesel to 3000'. (2) Pull OGL V from GLM #1. (3) Set SPMG in GLM #1. (a) Program gauge with 5 days of high daytime capture rate (to witness the daytime frac job) and low nightime capture rate (to witness other activities). Period Time Sample Number of Frequency Samples Five Days 7 AM - 10 PM 3 seconds 18000 Five Nights 10 PM - 7 AM 1 minute 540 With 250,000 lines of data capacity, the gauge should be able to monitor 13 days for the frac job execution. (4) Dummy-off other GLMs, in preparation for frac jobs. c) Shut-in pending frac. d) Other work: i) MITIA to 4000 psi. 2) Fracture Stimulate Kuparuk C-Sand: Detailed pump schedule is available on the attendant Excel frac schedule spreadsheet. The generalized procedure for is as follows: a) Load frac tanks with - 100°F fresh water; -1600 bbls of working volume required. Load sand silos with 235M# of 16-20 Carbolite. b) RU the tree-saver/isolation tool for 3112" 9.2 #/ft tubing (tubing tally shows no 4-1/2" pups below hanger). PT backside to 4000 psi. Maintain 3500 psi on the inner annulus throughout treatment (set inner annulus pop-off at 4000 psi). Pressure test treating lines to 9500 psi. Set pressure relief valve to 8000 psi, and set pump trips to 7500 psi. This I well is expected to treat at ±4500 psi and require 2200 HHP. The maximum expected surface treating pressure is calculated to be ±6000 psi, not including any near wellbore friction losses. It is recommended that 4 pumps be on location (3 required + 1 on-line backup). c) Breaker Tests will be performed on fluids prior to frac. The breaker schedule will be designed to ensure fluid stability at end of pump time with complete break within four hours of shutdown. A minimum of 100 cp @ 100 sec-1 is required at shutdown. d) Perform on-site pre-job QA/QC tests and complete BP form. e) Begin pumping data frac, initial rate will be 10 bpm while displacing wellbore fluid, after spotting data frac fluid a few barrels above top perf increase injection rate to 20 bpm and displace data frac. Shutdown for ISIP and monitor for closure time, calculate efficiency and adjust frac schedule as necessary (pad size, fluid loss additive, etc). Additional Cc: Well File Bruce Smith ec; Mike Coker Brad Musgrove Petredat Gary Elmore . . diagnostic tests may be performed after data frac analysis (i.e. scour, step down). Consult with design engineer before proceeding with frac. f) Begin pumping frac pad, initial rate will be 10 bpm while displacing wellbore fluid, after spotting pad a few barrels above top perf increase injection rate to 20 bpm. Pump the proppant schedule as detailed in the attached pump schedule. Under Flush with 74 Bbls, 54 Bbls of linear fluid and 20 bbls of diesel for freeze protection. i) Underflushing by 5 Bbls helps prevent overflushing of perfs and losing conductivity at near wellbore. g) Shut-in for ISIP, monitor for 15 minutes. h) Bleed off excess annulus pressure. Rig down service company. 3) Post Fracture a) Perform CTU fill cleanout to 50' above top perf. (-9000' MD): i) Perform an overbalanced pressure fill clean-out to prevent hydrocarbons from flowing into wellbore and CT, reverse circulate gel and sand to clean tubing and mandrels and help facilitate Slickline work. Use filtered seawater to clean-out. If gel sweeps are required to clean-out, have lab verify that breaker loading is adequate to break polymer & mix water at 150° F. Last 50' of fill will be flowed back with formation and GL assist to portable separator (ASRC). ii) Freeze protect to 3000' with neat 60/40 MEOH. b) Slickline to install gas lift design to lift from bottom. c) Shut-in pending frac flowback. 4) Frac Flowback a. As soon as possible flowback through portable flow-back separator: i. For analog Kuparuk frac flowback, see L-110 & L-107 well files. ii. Kuparuk wells tend to hydrate-off, HOT IA with 175 bbls of warm diesel followed by 20 bbls of neat MEOH. Kick off well simultaneouslv with POP well. iii. Expect FWHTs of 50 - 60°F and watercuts of 100% to begin with. Treat gas lift with methanol to prevent freezing. Attempt to quantify returned proppant flushed to tank. iv. Unload the well with 0.5 MMSCFGPD. v. Set choke at 500 BPD and TGLR of 1000 SCFSTB (500 MSCFGPD total). If after 8 hours, solids are <0.1 %, then open choke to 1000 BPD and increase gas lift until TGLR is 1000 STCFSTB (1000 MSCFGPD). vi. Repeat until choke is full open. Increase gas lift until TFLR is 1000 SCFSTB. vii. Conduct final 4 hour well test. viii. Do not surge well to flowback proppant. Surging could cause formation failure and sand production. ix. Continue producing to the flowback separator until the gel load has been recovered or watercut <10% and the solids production <0.1 %. Cc: Well File Bruce Smith ec: Mike Coker Brad Musgrove Petredat Gary Elmore . b. Service tree. Cc: Well File Bruce Smith . ec: Mike Coker Brad Musgrove Petredat Gary Elmore · TREE = 3-1/8" 5M CIW J~~~~~: 11" ~; KB. ELEV = 77' '~~A__A_'_'_'~~A~~__~A BF. ELEV = 50' KOP = 300' Max Angle = 58° @ 4352' Datum MD = 899<4' DatumTYb= 6000'SS 17-5/8" CSG, 29.7#, S-95, I[)= 6.875" H L-122 -'FETYNOTES: /' = =l 1022' H TA M PORT COLLAR I --I 2730' H3-1/2" I-ESX NIP, ID=2.813" I 3373' r- 17-5/8" CSG, 29.7#, L-80, I[)= 6.875" H 3458' ~ GAS LlFr Mð.NDRB.S IMinimum ID = 2.813" @ 2730' I ---1: ST I\.otJ TVD DBI TYPE VLV LATCH FDRr DATE 6 3441 2596 57 KBG2-9 DOIVE BTM 16 06102/03 3-1/2" H ES X NIP PLE 5 4704 3303 55 KBG2-9 DM'( BTM 0 05129/03 4 6132 4200 42 KBG2-9 DOIVE BTM 16 06102/03 3 7367 5107 45 KBG2-9 DOIVE BTM 16 06102/03 2 8203 5718 38 KBG2-9 DOIVE BTM 16 06102/03 1 8695 6147 19 KBG2-9 SO BTM 24 06102/03 PERFORATION SUfIITv1ARY REF LOG: DENSITY /NEUlROO ON OS/26/03 At\GLE AT TOP PERF: 7 @ 9050' Note: Refer to Production DB for histori::al perf data SIZE SA" INTERVAL Opn/Sqz )ð.1E 2-112" 6 9050 - 9062 0 12/04103 2-112" 6 9050 - 9070 0 07/26/03 2-112" 6 9062 - 9082 0 12/04103 2-112" 6 9094 - 9105 0 12/04103 ~ ---t 8752' H3-1/2" BKR CMDSLlDIt\G SLV, ID= 2.813" I - 13-1/2" TBG, 9.2#, L-80, .0087 bpf, ID= 2.992" H 5-1/2" CSG, 15.5#, L-80, ID = 4.950" H 8766' 8776' j! qi: ~ ~ ~ } ---i - ----t 15-112" X 3-1/2" CSG XO, ID =2.95" H 8796' PBlD H 9311' 13-1/2" CSG, 9.2#, L-80, ID = 2.992" H 9410' )ð. 1E 05131/03 06/02/03 07/26/03 12/04103 REV BY COMIVENTS DAVI1<K ORIGINAL COMPLETION MH/KK GLV C/O BJ MiKK IPERF KLC/lLP AIFERFS DATE REV BY COMIVENTS 8776' 8776' 8795' 8878' HBKR LOCSE=AL ASSY, ID= 3.00" I H TOP OF BKR PBR, D = 4.00" I UBTMOF3-112" BKRSBR, D = 3.00" H3-1/2" HES X NIP, ID= 2.813" 1 H3-1/2" HES X NIP, ID= 2.813" 1 8899' 8940' HpLP JT W/ RA TAG 1 9181' H PLP JT W/ RA TA G 1 PRUDI-OE BAY \..NIT WELL: L-122 PERMT f'.b: 2030510 API f'.b: 50-029-23147-00 SEC34, T12N, R11E, 2536' NSL & 3831' WB. BP Exploration (Alaska) '!IV (1 A IZ-fS ¡ 2..00'5 . STATE OF ALASKA . f}VS ¡2.{,) 3 ALAS~IL AND GAS CONSERVATION COrJlllrSSION StJ I ljllJ APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 1. Type of Request: D D D Abandon Suspend Operation Shutdown Alter Casinç 0 Repair Well 0 Pluç Perforations 0 Chanqe Approved Proqram D Pull Tubinq D Perforate New Pool 0 2. Operator Name: BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, Ak 99519-6612 7. KB Elevation (ft): 77.00 KB 8. Property Designation: ADL-0028239 3. Address: 11. Total Depth MD (ft): 9422 Casing Conductor Production Production Surface Surface Perforation Depth MD (ft): 9050 - 9070 Packers and SSSV Type: 110 20" 91.5# H-40 8771 5-1/2" 15.5# L-80 614 3-1/2" 9.3# L-80 85 7-5/8" 29.7# L-80 6772 7-5/8" 29.7# S-95 I Perforation Depth TVD (ft): 6493 - 6512.7 None 12. Attachments: Description Summary of Proposal D Detailed Operations Program Œ] BOP ~etch D f 14. Estimated Date for Decem~. 9.03 Î? . Commencing Operation: /. 16. Verbal Approval: a e: Commission Representative: Perforate IX] StimulateD VarianceD Time ExtensionD Annular Disposal D OtherD 4. Current Well Class: Re-enter Suspended WellD 5. Permit to Drill Numþer: 203-0510 /' Development I!I Exploratory D top bottom top bottom 28 138 28.0 138.0 25 . 8796 25.0 6243.9 8796 - 9410 6243.9 6850.1 28 113 28.0 113.0 113 6885 113.0 4757.2 I Tubing Size: I Tubing Grade: 3.5 " 9.3 # L-80 Packers and SSSV MD (ft): 6. API Number / 50-029-23147-00-00 Plugs (md): None Burst 1490 7000 10160 6890 8180 ITubing MD (ft): 23 None 13. Well Class after proposed work: Exploratory D. Development Œ] 15. Well Status after proposed work: Oil ~ GasD PluggedD WAG D GINJD WINJD Printed Name 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact StratigraphicD Service D 9. Well Name and Number: L-122 / 10. Field/Pool(s): Prudhoe Bay Field I Borealis Oil Pool PRESENT WELL CONDITION SUMMARY I Total Depth TVD (ft): IEffeCtiVe Depth MD (1Effective Depth TVD (ft): 6862.0 9311 6674.8 Length Size MD TVD Signature rs:::smit~ ~ Junk (md): None Collapse 470 4990 10530 4790 5120 8795 ServiceD Abandoned D WDSPLD Perpared by Garry Catron 564-4657. Bruce Smith Title Petroleum Engineer Phone 564-5093 Commission Use Only Plug Integrity D Conditions of approval: Notify Commission so that a representative may witness BOP TestD Mechanciallntegrity Test 0 Other: Subsequent Form Required: 10..40'-/- Original Signed By Saræh P~lin Approved by: ABDUSBFL OEt 1 0 2ß03 Form 10-403 Revised 2/2003 11/26/03 Sundry Number: ..303- 3SY Location Clearance D RECEIVED DEC - ~1/~ BY ORDER OF '. I THE COMMI~lm/a mtJ.\\ Gas C s.· , . s~n />. f)u¡c..~ t 41 Z f Anchorage !fJ-ed lu.J 4iW'" ~ kh- Yk. '~kJ . lLJ '; WIt ~ "- \'\Vf~." t a+' ~ $~ ~. ()D'ht~J,~' SUBMIT IN DUPLICATE . bp ... ,\,t.,,,. ..~ ~..- ~...- ~.. t!l.i\'" ". . . To: Doug Cismoski/John Smart GPB Well Ops Team Leaders Date: November 25,2003 From: Bruce W. Smith GPB Borealis Development Engineer Subject: L-122 Re-Perfs (Kuparuk C Sands) AFE: 5M4125 Completion Priority: Est. Cost: $560 M lOR: New Well Prepare the subject well for tie-in, well prep work, pressure test, re-perforate for Frac and hot oil prior to placing on production. Please contact Bruce W. Smith (Cell 440-8008, W:564-5093, H:345-2948, ) with any questions. 1. E Re-perforate 43' (Bottom shot @ 9105') / 2. 0 HOT well to POP 3. S Dummy Off GL V 4. P FRAC, (separate program will follow) 5. S Set full GL Design 6. C Cleanout Tubing as required Post Frac 7. 0 HOT well and Flow back into ASRC Last test: Max Deviation: Perf deviation: Min. ID: Last TD tag: Latest H2S value: Wellbore Fluids: BHT & BHP: Reference Log: Note: New completion, never tested. 58° @ 4352' MD 7° @ 9050' MD 2.813" X Nipples @ 2730' MD 9311 MD Drillers 10 ppm. 2003 Freeze protected tubing & IA to 2500' with diesel. 160°F & 3140 psia @ 6600' TVDSS (8/11/03) Schlumberger PEX Density Neutron 5/26/03 Simops on going Construction, drilling and early production. cc: w/a: Well File Steve Deckert Bruce W. Smith NS Wells Tech Aide Gil Beuhler a-122 Re- Perfs - Kuparuk C sa. E-Line: 1. Perf Kuparuk C4 & C3 from 9105-9094' (11') and 9082-9050' (32'),43 ft gross, 256 shots (well was originally shot with deep penetrating guns for the SWTT.) 2-1/2" Hollow steel carrier. 2506 Powerflow (Big Hole Charges), 6 SPF, i. 60° phasing, oriented +/-10 deg off bottom ii. EHD 0.66" & TTP 4.8". iii. Frac proppant 16-20 (0.0394"). Perf / Propp ant ratio = 16.75 big hole charge . Perf with existing fluid in wellbore. . Record Prior and after each gun fired, WHPIWHTIIAP/OAP, number of shots fired. Any indication of low order detonation HOT:. 2. RU HOT oil unit, Open wing and well to test header, pump 10 bbls neat MEOH, followed by 120 bbls of heated (HOT) diesel, tailed in with 10 bbls neat MEOH, simultaneously POP well, flow 24-48 hours, obtain well test with WPS, obtain NOC fluid sample off the fluid leg of the WPS. (Needed prior to FRAC) Slickline: 3. SI well, freeze protect IA and tubing, 4. Dummy off gas lift valves for FRAC FRAC 5. Wait on frac program, separate program. Slickline 6. RU Slickline, Drift to TD, set full Normal Borealis Gas lift design. :CTU: 7. RU CTU for tubing cleanout as required after FRAC, cleanout tubing to at least 9115 MD. HOT/ASRC:. 8. RU HOT oil unit, Open wing and well to ASRC Mobile Separator, pump 10 bbls neat MEOH, followed by 120 bbls of heated (HOT) diesel, tailed in with 10 bbls neat MEOH, simultaneously POP well, once well has cleaned up obtain a well test using the ASRC unit, piggy back into the WPS. . Q ëo e ~ 0 '5 U Measured Depth Log cr.J <ri Q) .£ z L[) '(;;' Composite FIELD PRINT U '" ::=- ro "" "- ,ñ OJ) m <:: co Scales 1 :600 and 1 :240 ~ L[) Q) ::ç" II 0 ~ >- Z <:: Total depth: 9422 ft <:: KB. NIA - Top Drive ft 0 ëo 0 .51 '-; (f) tD ¡r.¡ 1õ Spud date: 20-May-03 > G.L. 50.0 ft 0.. w cD 5 0 Q) m .!!2 ro - <:: Runs: 3 To 3 iIi D.F. 77.0 ft ª ~ 0 a. 0 c;; '" '" " .- 0 Q) ro w 1õ Permanent datum: Mean Sea Level Elev.: Oft ..0 0 L[) '" u co * ~ CL 0 I z IIJ IIJ-.J Log measured from: Drill Floor 77.0 ft above Perm. datum ¿ >, Depth reference: Driller's Pipe Tally ~ <:: .51 co 'i:i '" a. API serial no. 12536' NSL, 3831' V\lEL I Longitude Latitude E ~ ¡;, ãi u ãi 0 ë: ü: 0 3: 50-029-23147-00 SEC. 34, T12N, R11E, UM W 149.32544303 N 70.35056758 ~ -.J Ü I Depth logged: 3450 ft To 9368 ft I Mag decl: 25.53 deg. I Other services: ~ Date logged: 23-May-03 To 26-May-03 Mag dip: 80.79 deg. D&I, Res, AP\J\Æ) ~ Bore hole record Casing record ('..1 Hole size from to Size Density from to ('..1 g A7" in 1nA ft ,AhA ft ?nin '11" Ihm/ft nft 11n ft ..-I h 7" in ,AhA ft gA?? ft 7 h?" in ?'1 7 Ihml(1 nft ,A"A ft . Type Spud LSND 'vIud record frnm 108 ft 3468 ft to 3468 ft 9422 ft Borehole devia ion record Max from 57.45 deg 108 ft 57.60 deg 3468 ft MIn ° deg. 6.78 deg. In 3468 ft 9422 ft Surface equipment Unit PUO Depth system DES-CA Software record IDEAL Wls SPM L \J\Æ) M\J\Æ) ID8_0c_07 HSPM8_0c_13 VG.1c VG.1c I _~ ",,"':~'" 1" l¡ h ..'¡ :_,"i.. Î ~ . ~ , . ìiV~ .. I f /'_~/\ \. i/v . ~ ì.' _ \., ,\-i~,J.,... "t\- f.tl \\. ~ \ ,~- ~J\ ..: ; \;, . ,to!'\ ~;'\ ~ ~~~ ).1 w" J '..,:_- \ \J'" ..- -- ~ I I, I i-'¡' ; 4: ..; \ ,// / ./ 11, ""r."/r"j"",'\~1\nM¡' ,¡;;~~.~" !"t"h" ,. o . 0; ;; @ '" "':¡oWW '" ¡¡ "' _\;, Þ,'\ii!ÞW - ",." U\~ "\'".J~FI' '" ""\1\"1 '.'" ~1¡"'I,..Miib ,II", 'I'" if """I' 'I"',;"" '"'q''' "'. \ " jf\ ,I ¡ r¡ .~ \, ,'1 I"\} \.\ "'" J \.: \.. \ I t· ~ ;\ ; ,- r 11.'IIII'I117B¡ ~lllt'T¡"Ii'IIAI'\"'''li'''''I-'-nl _.' _," "'I , . " I ,~ ~ ~ " i \, i "'I~;';:' :{I\,\ , .':... ,(./ '" \/,', .J , t',", .' 'v.... . '. , '.' r II A f\'l\ ·v\ h {" , , I . h' I, 1 I ,./", 'J/ J \"\",, .' \¡ vV' V " ; '1" \;.J ," 1!IIIIIIIr.il'¡¡~ ~tlUI i 11I1r\na! II~II'! 1 \'1 ~I , I r" '- 1 ~~:\ ".'J.f\~y,\j\~:< .... . . ''''''f.",,} .~ I '-,\ l , " ) \ ( J \ 1'.... 0.,,\) ~v~' V . ~ - ~- ~ - - - - - - - - - - - - - - - - - -. - ,.. - -..... -'-.'-.- .. -......"'".. ~- · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · J CHEMICAL STING Performed for EXPLORATION (ALASKA), INC. Kuparuk Upper Zone API No 50-029-23147-00 · · · · · · · · · · · · · · - · · · · · · · · · · · · - · · · · · · · - · · · · · · · · Determination of Residual Oil Saturation Before and After a Low Salinity Water Injection Borealis Unit, Well L-122 Kuparuk Upper Zone C API No 50-029-23147-00 REPORT SUMMARY Two single well chemical tracer (SWCT) tests have been completed at the L-122 well in the Borealis Unit. The purpose of these tests, performed by Chemical Tracers Inc., was to measure residual oil saturation before and after low salinity water injection in the Kuparuk Upper Zone C. The results of the first SWCT test, Test I, show that prior to low salinity water injection, the residual oil saturation (SOR) in the test zone is 0.21 ± 0.02. This saturation measurement represents the pore space in a 20-foot thick section of the Kuparuk Upper Zone C, from the well bore to a radial position of about 12.8 feet. After this initial residual saturation measurement, the zone was treated with 900 bbls of low salinity water followed by 2,018 bbls of produced water. A second SWCT test, Test 2, was then to be conducted to measure SOR(LoSAL) (SOR after Low Salinity Water injection) in the same pore space as the initial SWCT test investigated. The results of SWCT Test 2 show that the SOR(LoSAL) is 0.13 ± 0.02. A summary of the SWCT Tests I and 2 is shown below: Test Description Test Size Depth of Sub-zones SOR Measured (bbls) Investigation Recognized Test I, SOR ISO 12.8 feet I SOR = 0.21 ±o.02 Test 2, SOR(LoSAL) 150 13.9 feet I SOR(LoSAU = 0.13 ±o.02 The reported SOR and SOR(LoSAL) measurements represent fluid-injection weighted average oil saturation for the sub-zones penetrated by the tracer fluids during these tests. The SWCT test results show ideal behavior of the chemical tracers used for both of these reported tests. The interpretation and field operational details for these SWCT tests are discussed in the following report. The field data recorded during 'the tests are presented and compared with best-fit model results CharI s . Carlisle Cherrncal Tracers, Inc. Determination of Residual Oil Saturation Before and After a Low Salinity Water Injection INTRODUCTION A detailed explanation of the Single Well Chemical Tracer (SWCT) test method is offered in Appendix A. The one-spot pilot program carried out at the L- I 22 utilized the SWCT test as an in-situ non-destructive oil saturation-measuring tool before and after a small low salinity water injection. This report summarizes the initial oil saturation measurement, Test 1, the low salinity water/produce water push injection, and the post-low salinity water injection oil saturation measurement, Test 2. Both Test 1 and Test 2 were completed on September 25,2003. This report section describes the above-mentioned work. TESTING PROGRAM AND FIELD RESULTS The test well, L-122, was completed in May 31, 2003. The 7" production casing was perforated once: 9,050' to 9,070'. The Kuparuk Upper Zone C sand penetrated by this perforation is 20' thick and has an average porosity of 16%. Reservoir temperature is 150 degrees Fahrenheit. The well is produced through 3-1/2" production tubing via gas lift. The well produced about 10 days from July 26, 2003 until the reported SWCT testing was carried out. During this production period, the test zone produced an average of 650 BOPD. During August and September 2003, Chemical Tracers, Inc. conducted two residual oil saturation tests. 2 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · I · · · · · - · · · · · · · · · · · · , · · · · · · · · · · · · · · Table 1: Testing Program Schedule Activity Date Started Date Completed August 19,2003 August 25,2003 August. 25, 2003 Sept. 6, 2003 Sept 6, 2003 Sept. 7, 2003 Sept. 7, 2003 Sept. 10, 2003 Sept. 11, 2003 Sept. 25, 2003 Water-Flood SOR Test I LoSAL Water Injection Produced Water-flood SOR(LoSAL) Test 2 The SOR Test (Test 1) Since the well produced 100% oil, it was necessary to inject a small volume of water into the test zone to reduce the oil saturation to residual. This volume of water was 3,895 bbls (195 bbls/ft.). The injection rate for this water-flood water was from 800 BWPD to 900 BWPD. Because the injection water was not filtered, (produced water manifold on L-Pad) it was necessary to back produce the well occasionally, to maintain clean perforations during injection. Initially, 1,870 bbIs of water was injected at 800 BWPD and a wellhead pressure, WHP, of 1,850 psi (maximum WHP was 1900 psi). After a 210 bbls production period, injection was resumed at 800 BWPD at a WHP of 1,850 psi, for 2,025 additional bbls. The well was then produced for 305 bbls and the SWCT test injection immediately followed. The total gross water-flood injection was 3,895 bbls water. The total injection water back produced for clean up was 515 bbls. Following water injection, the SWCT Test 1, to measure SOR was carried out. This test comprised a total injection of 640 bbls. The injection rate was from 800 to 530 BWPD and the maximum WHP encountered was 1,700 psi. The first 150 bbls of water carried 1O,000-ppm ethyl acetate (EtAc), 5,500-ppm normal propyl alcohol (NPA), and 7,000-ppm iso-propyl 3 alcohol (IPA). These 150 bbls were followed by 490 bbls of water containing 8,500-ppm IPA., The well was then freeze protected with 32 bbls of arctic dieseL The total injection of 640 bbls plus freeze protect fluids placed about 600 bbls of water into the test zone (150 bbls with ester plus 450 bbls of push). The well was then shut-in for 9.7 days for the reaction period. Following the reaction period, the well was produced for two days, 960 bbls. Samples of the produced fluid, water, were taken every 5 to 15 bbls and immediately analyzed for tracer content via gas chromatography. The field-measured tracer profiles are shown in Figures 1-4, plotted as tracer concentrations vs. produced bbls. The primary tracer, ethyl acetate (EtAc), is plotted in Figure 1; with product tracer, ethyl alcohol (EtOH). The cover tracer, NP A, is plotted in Figure 2; and the material balance tracer, Iso-Propyl Alcohol (IP A), is shown in Figure 3;and the cover tracer, NP A, and EtAc are shown together in Figure 4. Low Salinity Water Injection The low salinity water injection was carried out after the first residual oil saturation test was completed. Prince Creek low salinity water was hauled to location from Milne Point via vacuum truck and injected using a First Energy hot oil truck. This injection comprised of 900 bbls of low salinity water heated to 150 degree Fahrenheit injected at 900 BWPD. Produced water, from the L-Pad waterflood header, was then injected from 650 to 900 BWPD until 2,018 bbls were injected, The well was then produced for four hours to clean accumulated solids from the perforations (203 bbls) and the SWCT test two injection immediately followed. SOR(LoSAL) Test (Test 2) The post-low salinity water SWCT test was then carried out to measure SOR(LoSAL). This SOR(LoSAL) test comprised a total injection of 640 bbls. The injection rate was from 650 to 800 BWPD and the maximum WHP encountered was 1,900 psi. The first 150 bbls of water carried 4 · · .. · · · · · · · · · · · · · · '. · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · - · · · · · · · · · · · · · · · · · · .. - .- · · · · · · · 1O,500-ppm ethyl acetate (EtAc), 6,800-ppm normal propyl alcohol (NPA), and 4,200-ppm iso- propyl alcohol (IPA). These 150 bbls were followed by 490 bbls of water containing 4,000-ppm IPA. The well was then freeze-protected with 35 bbls of artic diesel. The total injection of 640 bbls plus freeze-protect fluid placed about 600 bbls of water into the test zone (150 bbls with ester plus 450 bbls of push water). The well was then shut-in for 11.5 days for the reaction period. Following the reaction period, the well was produced for 1.3 days, 1,175 bbls. Samples of the produced fluid, water, were taken every 10 to 20 bbls and immediately analyzed on site for tracer content via gas chromatography. Figures 10-18 show the field-measured tracer profiles for this Test 2. The profiles for EtAc and EtOH are shown in Figure 10. There is clearly less separation between the two profiles than in the previous test, indicating that some oil was displaced by the low salinity water process. The value of SOR(LoSAL) will be quantified below in the test interpretation section. A detailed daily journal of field activities is recorded in Appendix C. 5 Quantity · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · Table 2: Fluid Injection for L-122 Single Well Pilot Produced Water Injection Volume Injected (bbls) 3,895 o through 3,895 LoSAL Water Injection Volume Injected (bbls) 900 3,895 through 4,795 Produced Water Push Volume Injected (bbls) 2,018 4,795 through 6.813 Test 2 Ester Bank Volume Injected (bbls) 150 6,813 through 6,913 Test 2 Push Volume Injected (bbls) 450 6,913 through 7,413 6 · · · · · · · · · II · · · · tþ - · · · · · · · · · - · · 4Þc · · · · · · · · · · · · · · This sequence of fluid injection is also shown in the following illustration. WeIl Bore, 79 bbls Depth (ft) SWCT Test 2 Push, 450 bbls 17.6 SWCT Test 2 Ester Bank. 150 bbls 13.9 Produced Water Push. 2018 bbls 36.0 LoSAL Water In¡ection, 900 bbls 41.9 Produced Water Iniection, 3895 bbls 61.3 Note: The depth notation in the illustration above refers to the radial depth of penetration for the given aliquot of water considering a 20-foot zone with a 20% porosity and !esidual oil saturation of 0.13. No dispersion is considered here and the picture is offered as a simplistic illustration of the fluid injection sequence. 7 INTERPRETATION OF SWCT TEST DATA Ideal SWCT Tests The theory of the ideal SWCT1 test assumes that the tracer carrying fluid is injected along streamlines that extend radially from the well bore into the test formation, which is assumed to be a single homogeneous layer. When the well is shut in for the reaction period, the tracer is supposed to remain fixed while the reaction proceeds to form the product alcohol. During production, the tracer carrying fluid then returns radially along the same streamlines to the well. When these conditions are met, an ideal SWCT test is generated. Non-Ideal SWCT Tests In most cases, the tracer profiles obtained in the field display some non-ideal symptoms. There are four common reasons why a real test may depart from ideal behavior; each has its own characteristic symptoms. (1) Fluid drift - general movement of the mobile phase in the test formation, usually caused by production from or injection into nearby wells in the same reservoir. The streamlines around the test well are not the same during injection and production. Furthermore, the tracers continue to move during the shut in period. Tracer profiles tend to arrive too early, and have strange shapes; separation is observed between the partitioning ester and the cover tracer, even though they were injected in the same fluid. (2) Flow irreversibility in layered test zones - individual layers may accept a different fraction of the injected fluid than they return to the well bore during production. Partial plugging of perforations during injection, if the injected fluid contains suspended solids, can cause this. The most obvious symptoms are early arrival of all tracers and late arrival, in the fOlm of extended tails on the tracer profiles. 8 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · I · · · · tþ · · · · · · · ~ · · · · · · · · · · · · · · · · (3) Cross-flow between layers - in layered test zones, small pressure differences between individual layers can cause fluid with tracers to flow from one layer to another through the well bore during shut in. The same pressure differences will cause flow irreversibility as in (2) above. The symptoms are the same in the tracer profiles. (4) Complex Pore system effects - non-equilibrium flow conditions in most carbonate reservoirs usually cause distorted profile shapes in the individual tracer production profiles. Ester profiles arrive earlier than expected and have extended tailing. Material balance tracers arrive diluted and have extended tailing. Capacitance is reflected in each chemical profile shape and position. These effects can be extensive in some cases depending on lithology and distribution of pore space. The complex pore system effects are usually limited to carbonate reservoirs. The reported test is ideal in nature. Appendix B contains a detailed explanation of the simulation process and the available simulators. Matching The SOR Test Profiles CFSIM was first used with an ideal single layer model to simulate the L-O I SOR test results. Dispersion constant, hydrolysis reaction rate, and finally SOR were varied for the single layer to , obtain the best fit of simulated profiles to field profiles. The results are shown for EtAc and EtOH in Figure 5, NPA (cover) in Figure 6 and IPA (material balance) in Figure 7. Sor used for the single layer model is 0.21. It is obvious from Figures 5, 6 and 7 that the ideal simulation model fits the tracers reasonably well. 9 CFSIM Best-Fit I-Layer Model, SOR Test Considering the ideal shape and conformance of each of the Test 1 production profiles the single layer ideal model was used to interpret the Test 1 results. Figures 5 through 9 show the field measure data with the best fit, ideal model results. Sor for Test I is 0.2 I ±.02. Matching The SOR(LoSAL) Test Profiles The best-fit single-layer, ideal, model also fit each of the SOR(LoSAL) Test 2 production profiles. Figures 14 through 18 show Test 2 field measured data with the ideal simulation results. SOR(LoSAL) for Test 2 is 0.13 ±.02. 10 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · I I · · · · · · · · · I · · · · - · · · · · · · · · · · 41 · · · · · · · · · · · · · · · · Table 3: Best Fit 1 -Layer Model Parameters Test 1 Number of Sub-zones Fraction of total volume entering zone 1 during 1.0 1.0 ester injection phase Fraction of total volume entering zone 1 during 1.0 1.0 push injection phase Fraction of total volume produced from zone 1 1.0 1.0 during production phase Ethyl Acetate Partition 4.0 4.0 Coefficient Oil Saturation in Zone 1 0.21 0.13 Reaction rate 0.0136 0.0089 constant (days-I) Test 2 GENERAL CHARACTERISTICS OF THE SWCT TESTS AT L-122 Hydrolysis Reaction Rate The fraction of ester reacted depends on hydrolysis reaction rate, which varies with reservoir temperature, ester distribution coefficient, and SOR. The total conversion of the ester is listed on the next page. 11 Table 4: Ester Hydrolysis Converted to Alcohol Ethyl Acetate/ SOR Test 1 9.7days 2.8 % Ethyl Acetate/ SOR(LoSAL) Test 2 11.5 days 2.3 % Investigation Depth Radial depth of investigation of each chemical tracer used is shown in Table 5: Table 5: Investigation Depth l{ª<Ii~IDèpJbQfi..yeSJìga'tiop Tracér SôRTest SÖ~(LøSAL)····Test Ethyl Acetate (reactive) 8 .4 feet 8 .8 feet Ethyl Alcohol (product) 8 .4 feet 8 .8 feet N-Propyl Alcohol (cover) I 1 .2feet 1 2.2 feet Iso-Propyl Alcohol (Mat. Bal .) 1 1 .2 feet 1 2 .2 feet The portion of Kuparuk reservoir tested was about 17 feet in diameter and 20 feet tall. The pore space tested for low salinity water injection response was about 135 bbls. Dispersion The dispersion used to match the L-122 tests was 0.9 feet (cell size). This translates to a 0.45 dispersivity. 12 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · " · · · · ø · · · · · · · · · · · · · - - · · · - e; · · · · · · · · INTERPRETATION SUMMARY The following summarizes the observations made during interpretation: . SOR was determined with good precision from the production profiles. · Both SWCT Tests 1 and 2 are quite ideal in nature. The value obtained for SOR or SOR(LoSAL) was not affected by the choice of simulation model. Sensitivity to SOR and SOR(LoSAL) is very good, plus or minus two saturation units or better. CONCLUSIONS The two reported Single Well Chemical Tracer Tests 1 and 2 for residual oil saturation, SOR and SOR(LoSAL) respectively carried out at the Borealis, L-122 show excellent profile definition and excellent sensitivity to oil saturation. Both tests quantitatively determined oil saturation within the reservoir pore volume penetrated by the tracer carrying fluid (about 350 bbls of pore space investigated). The primary objective of this series of SWCT tests was to evaluate the perfonnance of a small low salinity water flood carried out at well L-122. The results show that the initial oil saturation is 0.21 and the post-low salinity water-flood oil saturation is 0.13, a 38% reduction of pore space oil content. 13 References I. Deans, H. A., S. Majoros, "The Single Well Chemical Tracer Method for Measuring Residual Oil Saturation", Final Report. Report No. DOE/BC/20006-18. (October 1980). 2. Deans, H.A., Carlisle, c.T., "Single Well Tracer Test in Complex Pore Systems," SPE/DOE Fifth Symposium on Enhanced Oil Recovery. Paper 14886. (April 1986). 3. Deans, H. A., "A mathematical model for dispersion in the direction of flow in porous media," Soc. Pet. Eng. J. (March 1963) 49-52; Trans., AIME, Vol. 228. 14 · · · · · · · '. · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · ~ I 1 for Sor . . . . .. . Â . Â . .. I. . . . . . . . . .., . Â .. . . Â . . . . . Â Â Â .. ÂÂ Â Â 200 300 400 500 600 700 800 900 1000 Figure 2 NPA Cover Tracer L-122 SWCT Test 1 for Sor Field Measured Data ~ --".----.--.--.,.- --- .-- --~------_._-_.'--------'"--'-------"---'-~----"-'------'-'-~-'-'--.--'--'--'-----"-'--'-"----------'-------'---'--..-- '---.--..-.----.,.-...--...-.--.....-....--- ._-,-_._-,-_..- ---...- -..---'-------'-"-- The cover tracer, normal propyl alcohol (NPA), field data are shown here. NPA tracer was placed in the first 150 1500 bbls of the SWCT test injection water. The same 150 bbls also carried the Ethyl Acetate into the reservoir. The purpose of the NPA tracer is to serve as a cover or reflector of the Ethyl Acetate shape and position in case the Ethyl Acetate is distored because of solution stripping or excessive hydrolysis reaction. [ 1200 Q. <l a.. z c 900 0 .. CO ~ - c G) 600 (.) C 0 (,) 300 . . . . '\ NPA . . . . . . . . .. . . . . ... .. .. o o - --·--··------.'-··--·------·,--·~----r-'---'--- -···---1-----·------···---,---·----------·------,---- --.---"-'--.------'-----r-.-.-~_. --..-----------..-----nT- 100 200 300 400 500 600 Barrels Produced 700 800 900 1000 ............................................ .,... ...... .~.-.~--...._.... ............................... 1 0000 I I I 9000 8000 E 7000 0. 0. <i 6000 a.. C 0 5000 ~ C'Ø ~ ... C 4000 Q) () C 0 3000 U 2000 1000 0 0 . . . tit . . . . . Figure 3 IPA Material Balance Tracer L-122 Sor SWCT Test 1 Field Data .... . .. . .. . . .. . . . . . . The material balance tracer iso-propyl alcohol (IPA) field data are shown here. IPA tracer was placed in all of the SWCT test injection water to distinguish the SWCT fluids from formation fluids. . . . .. .. .. -., . ... . . 100 200 900 1000 . 300 400 500 Barrels Produced 600 700 800 1 1600 1500 1400 1300 1200 III III III I III 100 III E III Q. III III III E Q. 1000 III Q. III Q. 900 III 11I11I III I 800 III III III III III III 700 11I111I11I 600 III III III. 500 III III III III 400 III 300 400 200 III 100 0 100 200 300 400 500 600 700 800 900 1000 - ............................................ 1 . o 100 200 300 400 500 600 700 800 900 000 Figure 6 NPA Tracer L-122 Sor SWCT Test 1 Field Measured Data With Ideal Simulation Results NPA Field data for the material balance tracer, n- propyl alcohol, are shown here with simulation results from the Ideal model. The simulation results are shown as a solid line. 1500 ¡ &. 1200 Q, <i 0- Z s:: 900 o ;; ~ - s:: B 600 s:: o o o o 300 · . 100 200 300 400 500 600 Barrels Produced 700 800 900 1000 ............................................ u ~.,_._._._._.~__.~____._.~._......._._~"._._.._.J_._._...... .......... e.. Figure 7 IPA Material Balance Tracer L-122 Sor SWCT Test 1 Field Measured Data With Ideal Simulation Results ¡Ideal Simulation Model .--.- ..~ ~ e"",-.. ~ ., .'~. .~~. ~ .~"'''. .. . ..., ~~~ ... ~, . . 8000 7000 , 6000 E a. a. 5000 <i Il. ~ ~ 4000 n:I ... - ~ Q) g 3000 o () . . . Field Measured IPA . . 2000 1000 o . o 200 300 100 The field data for the material balance tracer, iso-propyl alcohol (IPA), are shown here with simulation results from the Ideal model. The simulation results are shown as a solid line. IPA tracer was placed in all of the SWCT test injection water. . 400 500 600 Barrels Produced 700 800 900 1000 - 200 1 50 or 200 300 400 500 600 700 800 900 1000 ............................................ 1 o 100 200 300 400 500 600 700 800 900 000 . 100 200 . . . ... . .. . ... . . . . . . . . . .. . . . . . . . 300 400 500 600 700 900 1000 ............................................ ............................................ Figure 11 NPA Cover Tracer L-122 SWCT Test 2 for Sor(LoSAL) Field Measured Data 700 600 The cover tracer, normal propyl alcohol (NPA), field data are shown here. NPA tracer was placed in the first 150 bbls of the SWCT test injection water. The same 150 bbls also carried the Ethyl Acetate into the reservoir. The purpose of the NPA tracer is to serve as a cover or reflector of the Ethyl Acetate shape and position in case the Ethyl Acetate is distored because of solution stripping or excessive hydrolysis reaction. 500 E . Q. Q. .. . . < . . . Q. 400 . . . .. . . z .. . c . 0 . = CG .= 300 . . c Q) . . . u c . . . . 0 (.) . 200 .. . . . . . . 100 . . . . 0 . , 0 100 200 300 400 500 600 700 800 900 1000 Barrels Produced Figure 12 IPA Material Balance Tracer L-122 Sor SWCT Test 2 for Sor(LoSAL) Field Data 5000 4000 The material balance tracer iso-propyl alcohol (IPA) field data are shown here. IPA tracer was placed in all of the SWCT test injection water to distinguish the SWCT fluids from formation fluids. E . Q. . . Q. . . <( 3000 2: c . 0 . . ;: . e . - c . .. G) 2000 (,) . c . 0 . 0 . . .. . . . . 1000 . . . . . . . . . . . . . 0 - - - 0 100 200 300 400 500 600 700 800 900 1000 Barrels Produced ............................................ 700 1400 600 1200 500 400 300 200 00 o . . . . .. . . . .... . ,. . .. . .. ... , . . . ., . I. . . . . . .. I . . . . . . . .. III . . ,. . . . . . . . 00 200 300 400 500 600 700 800 900 . . 400 . . 200 000 000 800 600 . Acetate reactíve ìn same posìtìon all . . . . . . Ã o 200 400 600 800 1000 1200 ........... ................................ .-.---........~.-.~.-.-.~..'......__.~.._~.,._._.... .. ....... ... Figure 15 NPA Tracer L-122 Sor SWCT Test 2 for Sor(LoSAL) Field Measured Data With Ideal Simulation Results 600 . . . . Field data for the material balance tracer, n-propyl alcohol, are shown here with simulation results from the Ideal model. The simulation results are shown as a solid line. . . 500 . E Q. Q. 400 <i. 0.. Z c o 300 ;:; I! .... c CD (.) 200 C o o . . . . 100 o o 100 200 300 400 500 600 Barrels Produced 700 800 900 1000 Figure 16 IPA Material Balance Tracer L-122 Sor SWCT Test 2 for Sor(LoSAL) Field Measured Data With Ideal Simulation Results 5000 Ideal Simulation Model The field data for the material balance tracer, iso-propyl alcohol (IPA), are shown here with simulation results from the Ideal model. The simulation results are shown as a solid line. IPA tracer was placed in all of the SWCT test injection water. 4000 E 0. 0. <i 3000 e: c o :,¡::; ft ... - ¡ 2000 u c o o . . /" . . . .. . .. Field Measured IPA 1000 . . . . . . o o 100 200 300 400 500 600 Barrels Produced 700 800 900 1000 ............................................ ..... ....... - - ............ ............. ..;. ................................ SWCT 5 = 0.13 or 200 300 400 500 800 600 900 700 1000 Test 2 900 000 ............................. ........... . · · · · · · · · ~ · · · · · - · · · · · · · - · · · 41 ., · · · · · ~, ~ · · · · · · · · APPENDICES APPENDIX A SWCT TEST METHOD AND INTERPRET A TION APPENDIX B SWCT TEST SIMULATION MODELS APPENDIX C FIELD OPERATIONS APPENDIX D FIELD JOURNAL APPENDIX E TABULAR FIELD DATA 15 16 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · APPENDIX A SWCT TEST METHOD AND INTERPRETATION The Single Well Chemical Tracer (SWCT) test is a method for measuring fluid saturations in oil producing reservoirs. Chemical Tracers, Inc performs the test as a contract service. The SWCT test is carried out on a watered out formation interval by injecting, and then· ,=>8~ ~ ~o~ o~o~ 0 C;:8~o OO~ c? ~o~ 00.% 0_00 %~oo ~ g oO.,pg oo~o g pO.,p ~8~o~o~ ~o~o ~o~ c:,0~0C;0;? 000 %Qoo.%o 00." 0°0000° 000 00 000 ~a.0 '" 0. ~ QO 0D~ OJ:) 0 o..o~ 8':::::> '<::;. <:J0'0 0c:>0'0 ~ 08c:::>° o0e:::> O'~ DC::> =oå % 0=000 ""2:oå % ° åoóo 00""00 åoó Watered Out Test Zone, 10 to 100 ft. ~8~ ~ ~oð> o~o~ 0 C:8~o 00£=> c? C;;09 ooo%o_oo%~oo~goo.,pgoo~ogpo.,p "'2R~o~o:::>_ ~o:::>_o _0..09 _0..09°0..09 producing back from the same well, a volume of reserVOIr fluid labeled with appropriate chemical tracers. In the case of a single well residual oil (SOR) test, as reported here, a volume of water containing a suitable ester (ethyl acetate in this case) is injected into the target zone of the test well. A larger volume of. water that does not contain ester is then injected to push the ester- carrying water until it reaches a position five to fifteen feet into the reservoir (5 to 15 feet radius from the well bore). · · · - · · · · · · - · · · · · - - · · · .. · · · · · - .. · · · · · · · · · · · · · · · The total volume injected is typically labeled with a suitable non-reactive, non- 8"0<0=.0"0°=.0"0008=°0°=°0°= <00° t.::) o~ 0'0 ~ 0 "V <:7 0 <7 C7 <7 0 C7 q 0 ~OD 0.0 oo~o 0 pO..p t =8"0°=.0'0 Water 0.0=°0.0= '=>0,=:>"=:>0">.:::) 0°0°0 .00.00£0.0,0.0 Containing .00.00.000 ~Q.0 'V Cl 0.0. <7 0ù~ 8'0""=.0'00 1% Ester (D) 0.0=°=.0= 'C::>0'C:::>~O,=> 0000 0.0 0.0 0.0 .0 .0 a a .00 a .00 a DO ODD 100 0001 10 001 ,DO ODD....... OOOOOO, Formation ,000000. 18888881 Water ~8~~~°6>°~o~ 0 ~8~oOO¿?<7c;,0~ DOq~D~OD~~OD~goO..pg.oO~.ogpo..p "2R~o~D~_ ~D~_O _c::.os¡> _c::.os¡>°c~oÇ> Displaced Injected Water partitioning (material balance) tracer, iso-propyl alcohol (IPA). During a shut-in period of one to ten days, a portion of the ester reacts with the reservoir water and forms ethyl alcohol (product tracer). The ethyl alcohol is virtually insoluble in the residual oiL The shut in period is designed to allow a measurable amount of ethyl alcohol to form. Typical ester to alcohol conversion is from 10% to 50%. 0c:>°OOc:> 0:0 goåo:p O<:::,>ooOc:::> °oågåoOo ..0 0 0û~ o C::> 0' ~ 0 C::> 00°0 <7 åooo o 0 .0O ° .0.0.0 '0.0.0.' ..0.0.01 ,0.0.0., ,.0.0.0, Formation ,0.0.0., I~~~~~~. Water ~8~ ~ ~o,& o~o~ 0 ':85>0 OO~ C7 c;o~ .0 OD.'g, D~OO 'g,~Oo ~ g o0..2g oO~o g p0..2 "2R~o~o~_ ~o~_o _C::0Ç> C:0Ç>°OOÇ> Displaced After the shut-in period, the well is back-produced. The produced fluid is periodically 17 sampled at the wellhead and immediately analyzed for content of the un-reacted ethyl acetate tracer, the ethyl alcohol tracer, and the material balance tracer, IP A. At the beginning of the production step, the un-reacted ethyl acetate and the product ethyl alcohol tracers are superimposed, located about 5 to 15 feet from the test well bore. Partitioning Sample Analysis of the un-reacted ethyl acetate tracer between the immobile residual oil phase and the mobile water phase delays production of the ester by an increment of volume directly related to the residual oil saturation. The product alcohol tracer, however, is not delayed, and flows back to the well at very near the same speed as the water. Since the ethyl alcohol does not spend time in the stationary oil phase, it is produced earlier than the ethyl acetate tracer, resulting in a separation between the product alcohol and un-reacted ester tracers. This chromatographic separation is observed in profiles of tracer concentrations vs. produced volume, as shown below. The amount of separation between the two tracers is used to calculate residual oil saturation. SWCT test results from high SOR cases show a large separation between the product alcohol and ester. Test results from low SOR cases show a small separation between the product alcohol tracer and ester. 18 · · · '. ~, · · · · · · · · · · · · · · · · · · · · · · · e· · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · tþ. - · · · · · · - · · · ,. · t · · - · · · · · · · · · · · Alcohol S Product g; Tracer Injected A. ""''''II> ~. \ 0<1) 'bOo ¡ Ester : \ l \ Tracer å 'i e 'ò ~ 8 °0 X. \\ \ 'I><¡, \. ðq, · <!>q, III.." "q, ~e~ ~~~0 "........ oo"'~ ¡..~ ~ .... '" ~ s: o -.;: œ ¡.. .... s: ~ C,) s: o U Volume Produced, Barrels E 0- 0- Õ -= o <:J ~ C .~ .... œ ¡.. .... s: ~ <:J C o U In actual practice, a second non-reactive alcohol tracer, such as normal propyl alcohol (NPA), is added to the volume of water that carries the ester into the reservoir. This second material balance or cover tracer uniquely identifies the ester-water bank and allows for interpretation of the test in the event that all of the ester reacts, or that some of the ester is stripped away by gas breaking out of the produced water or by gas-lift gas. SWCT tests are non-destructive; after the production step, the formation is returned to its original condition. The test procedure can be repeated on a given completion as many times as needed without altering the fluid content of the pore space investigated. This non-destructive feature allows oil saturation measurements before and after an EOR injection from a single well. This test-inject-test strategy was employed on the 81X-33S well to evaluate the performance of an alkaline-polymer (AP) process. The oil-water partitioning coefficient (K-value) of the ester, an important variable in test interpretation, is measured in the laboratory prior to the test. The K measurement is performed at reservoir conditions, using samples of reservoir oil and test water. In ideal cases, the SOR results can be calculated directly from field measured tracer concentration vs. produced volume profiles, by using the measured K-value and the degree of separation between the secondary tracer and the ester peaks. A more rigorous interpretation is 19 20 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · made through mathematical modeling. Simulated SWCT production profiles are compared to field SWCT production profiles. A best-fit value of SOR is obtained from the simulation model. Simulation allows the interpreter to compensate for complications such as ester reaction during the flow period and K-value concentration dependencies, and to address possible flow irregularities encountered during the test. A more rigorous explanation is offered below. This version is based on the theory presented in "DETERMINATION OF RESIDUAL OIL SATURATION", Interstate Compact Commission, 1978, (pp 156-176). The basic mathematical premise used to calculate Sor from SWCT test results follows. Residual oil determination is identical theory with oil serving as the mobile phase and water as the stationary phase. The following explanation serves as a general explanation of Sor measurement. Let: Vi = velocity of tracer i moving through the pore space of the reservoir occupied by water. Vw = velocity of water in pore space. V 0 = velocity of oil in pore space. Pi = probability of tracer i being in water phase. I-Pi = probability of tracer i being in oil phase. Ki = partition coefficient for tracer i = Ci (oiI)/Ci(water). Ka = partition coefficient for ester tracer. Kb = partition coefficient for ester hydrolysis product alcohol. Ci (oil) = concentration of tracer i in oil phase at equilibrium. Ci (water) = concentration of tracer i in brine phase at equilibrium. ni (oil) = number of i molecules in oil phase at equilibrium. ni (water) = number of i molecules in water phase at equilibrium. Sor = residual oil saturation. Sw = water saturation = I-Sor. · · · · · · · · · · · · · · - · · · · · · · · · · · · .. ~ - · · · ~. - · · · · · · · · During the injection and production steps of a SWCT test, the tracer í moves at the following rate: Vi = Pi Vw + (1-Pi)Vo (1) Since V 0 = 0 for a reservoir at residual oil saturation equation (1) may be restated as Vi = Pi Vw (2) The number of i molecules in the oil and water phase at a given point in time is related to the fraction of the pore space occupied by each phase and the concentration of tracer i in each phase, l.e I-Pi = ni (oil) Pi ni (water) (3) = Ci (oil) Sor = Ki Sor Ci (water)Sw I-Sor For simplicity let Ki (Sor)/(1-Sor) = ß where ß is the tracer retardation factor. This term is an expression of the relative velocities of the partitioning and non-partitioning tracers. Combining equation (2) and (3) the result is Vi = Vw/(1+ß) (4) In an SWCT test, this velocity is measured indirectly by measuring the volume required to produce tracer i from the reservoir. Since Vi ß ex: 1/ Qi (5) where Qi = volume required to produce tracer i. During the production step of an SWCT test, the ester (tracer a) and hydrolysis product (tracer b) are being produced from a common point about 15' into the reservoir to the well-bore and surface. The volume required to produce each of these tracers is carefully monitored. Ka and Kb are measured in the laboratory and found to be: Ka> 0 (generally 2.0 to 8.0) 21 22 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · Kb=O. For ethyl alcohol Kb == 0, and ßb = 0, so equation (4) becomes Vb = Vw/(l +ßb) = Vw (6) and considering equation (5) Vb oc: I/Qb (7) The volume required tQ produce ethyl acetate is Qa and Va = Vw/(l +ßa) = Vb/(l +ßa) and from equation (5) and (7) VbNa = Qa/ Qb = l+ßa In summary, ßa = (Ka)Sor/( I-Sor) and Sor = ßa /(ßa +Ka · · · · · · · · tt · · · · · - It · · · · · · · · · · tit II - - · · · tit tþ. · · · · · · · · APPENDIX B SWCT TEST SIMULATION MODELS The program CFSIM mathematically simulates fluid flow during a Single Well Chemical Tracer test with a finite cell model. The model assumes radial flow in the test zone. Dispersion operates on the tracer fluids as they move through a system of mixing cells. Each cell is sized to accommodate the interval being modeled. Tests using one reactive tracer, and one product tracer can be modeled in a single nm and the K-values are changed with variations in concentration of the tracers. This program allows parameters such as interval size, dispersion, and Sor to be operated independently in as many individual sub-zones (layers) as needed. SSIM also allows fluid produced from one zone to be injected into other zones during the shut in period of the test. This feature simulates cross-flow through the wellbore caused by subtle pressure differences in a layered reservoir. The program 2D5TRAMS is also a finite difference model. This model assumes radial flow in the test zone. The 2D5TRAMS program is capable of simulating cases with drift due to production or injection elsewhere. Dispersion, both radial and angular is proportioned to the magnitude of local fluid velocity. Tests using up to three tracers - a material balance tracer and two esters with or without product alcohol - can be modeled simultaneously and the K-values are changed with variations in concentration of the tracers. This program has a multi-layer feature that allows simulation of cases with heterogeneous reservoirs. Fractions of fluid injected into or produced from each layer may be specified for as many layers as necessary for the test. For each layer, parameters such as interval size, dispersion, Sor and drift are operated independently from other layers. Simulation Models Available Exxon Production Research Company and the U.S. Department of Energy provided the original models for simulating SWCT results to Chemical Tracers, Inc. These computer programs are DRIFTSIM and TRACRL respectively. The DRIFTSIM model is capable of simulating SWCT test results where fluid drift is present. TRACRL was extended by Chemical Tracers, Inc., to accommodate a wider range of non-ideal flow features. The modified model is called CFSIM (cross-flow layered sandstone simulator). CTI also developed a dual porosity simulator to interpret SWCT tests in carbonate formations. Details of these programs are given in Appendix A. Generating the Best-fit Simulator Model for SWCT a Field Test Interpreting a SWCT test requires matching a single simulation model to the material balance tracer (IP A), the cover tracer (NP A), and the ester tracer (EtF) profiles. The product alcohol tracer (EtOH) profile is then matched with the same simulation model by adjusting SOR. The flow pattern of a particular test is delineated when the same model successfully matches all the-tracer profiles. Since the apparent reason for the non-ideal symptoms seen in the reported tests is layering, CFSIM was used to obtain the simulation results shown in this report. The usual 23 24 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · procedure is to start the simulation process with a single-layer (ideal) model, then add layers to improve the match between field profiles and simulated profiles. After each run, the simulation results were compared to the field measured production profile data for the tracer being modeled. Following each comparison, adjustments were made in the model input parameters; and the process was repeated until the best-fit model was attained. Input Parameters for CFSIM Known parameters are: well bore volume, well bore radius, perforated interval thickness and porosity. Known chemical and test timing parameters are: rate and total volume of fluid injected; rate and volume of fluid produced; injected concentration for each tracer chemical; shut-in time; and partition coefficient for each tracer. Unknown (adjustable) parameters are: nµmber of layers, fraction of fluid injected, fraction of fluid produced for each layer; SOR, dispersion constant, and hydrolysis reaction rate for each layer. The best-fit model for the IPA and NPA tracers is essentially independent of SOR' After these two tracer profiles are well matched, the final step is to compare the position of the ethyl alcohol field data with the best-fit model ethyl alcohol results for various SOR cases. The best-fit SOR is then selected. · · · · · · · · · -- · · · -. - · · · · · · · · · · · · · - · · · · · .. · APPENDIX C FIELD OPERATIONS This series of L-122 SWCT tests were carried out in the Prudhoe Bay field WOA, Drill Pad L. During the test a small portable laboratory building was positioned near the test well, L- 122, throughout testing. The' water used for injection came from a one inch temporary line about 50 feet long that was built off of the L- I 15i injection line. A choke was added below the L-115i Casasco value to control flow. Also a small meter run containing a chemical addition point, static mixer and Halliburton turbine flow meter was installed to add/mix the chemical tracers and measure water injection rates and pressure. Pure chemical was pumped during injection into the chemical addition point by means of small high-pressure injection pumps. Samples of the injection fluid were taken each 30 minutes during the injection and analyzed for tracer content on location to assure quality control. During production, the well was produced through the L-pad test separator. Samples were taken at the wellhead and immediately analyzed on site. For each sample taken, an accurate measurement of the total produced volume, bbls, was also recorded by noting the volume produced as indicated on the Net Oil Computer monitoring the L-Pad Separator. When combined, the volume data and tracer analysis of each sample was plotted in production profile form for interpretation and presentation in this report. 25 APPENDIX D Field Journal L-Ol and L-122 SWCT Test Series Water Injection-Sor, LoW Salinity Water Injection-Sor (LoSal) Measurement August 10,2003 Sunday: Charlie Carlisle, CTC, and Lonnie Schultz travel to Anchorage from Laramie, WY. Arrive PM. Accommodations at Puffin Inn August II, 2003 Monday: CTC arranged for meetings with Bruce Smith, Frank Paskvan, Danielle Ohms on Tuesday. Visited stores in Anchorage for N. Slope field gear. August 12, 2003 Tuesday: LS attended NSTC schooL CTC met with above to complete planning for L-pad tracer work. August 13, 2003 Wednesday: CTC and LC traveled to slope on 8:30 charter. Met with Jerry Middendorf, Randy Selman. Acquired pick up, ID badges, and room at BOC. Arranged for well site lab building with Tool Services, Jim, 4636. Located CTI equipment and SWCT test chemicals at BOC warehouse. All looked good. August 14,2003 Thursday: CTC attended toolbox meeting with production grouplpad operators. Arranged for electrical connection to portable lab to be made. Lab delivered to L pad late PM. Met with L-pad operator, Tim Okonek, PM and discussed of SWCT testing plan. August 15, 2003 Friday: Electrical generator delivered to L-pad PM and John Trojan made necessary connections. cn equipment delivered to L-pad PM. Cleaned lab building and started unloading CTI analytical equipment. cn equipment in good condition after shipping related damage. August 16, 2003 Saturday: Met with Brad, Well Support and Stan Coleman Well Support WOA to make necessary connections from L-l l5i to L-122 and from L-109i to L-01 welL Meter run, static mixer, check valve, sampling valves, etc installed in small one inch spool in Well Support shop near GC-1. Assembly completed late PM. Arranged for hydrogen and helium cylinder to be delivered to L-pad next day. Coleville supply, 659-3198 was he source of the He and H2. August 17,2003 Sunday: Hydrogen and Helium delivered to L-pad AM. Well Support group, Stan Coleman et al arrived AM and installed temporary injection lines. Pressure test failed because of pipe thread leaks. Well Support group returned to their shop with each spool to dress and reassemble each threaded part that leaked. Returned PM and pressure tested. Test failed at 1,000 psi with several thread leaks. Each spool was taken back to Well Support shop to re-make each thread with BakerLok. Left spools overnight under mild heat to cure BakerLok. August 18, 2003 Monday: Installed each meter run/injection line and pressure tested to 3,000 psi. Good shape. Closed casing valve on L-O I at 12:00 noon. Casing pressure dropped from 1,100 to 650 psi in about 45 minutes. Started produced water injection into L-01 at 12:50 PM. Rate was 1,500 bid. Well went on vacuum after about 20 bbls and pressured up to 1,250 psi after 138 bbls. Stabilized injection after 220 bbls at 1,500 psi WHP at 1,500 bid water injection. Continued produced water injection throughout night. Total injected by midnight was: L-O I, 694 bbls 26 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · 4Þ tit · · · · · .. · · · · · · · · · · - e: · · · · · ~ · · · · · · · · · August 19,2003 Tuesday: Continued injecting into L-OI at 1,500 bId. Shut in L-122 at 8:30 and started injecting produced water at 10:35. Well accepted injection fluids with no noticeable problems. Initial tubing pressure, shut in, was 400 psi. Injection rate was intended to be 800 bId with a max WHP during injection to be 1,371 psi. Well started pressuring after 40 bbls injected at a rate of 500 bId. Increased rate to 800 after 42.7 bbls and well pressured to 1,450 after 58 bbls. Slowed injection rate to 540 and WHP continued to increase to 1,500 psi. Called Bruce Smith in Anchorage and discussed parting pressure. He said that the recorded breakdown pressure for the Borealiswas 2,200 psi. Continued to inject with an elevated maximum WHP, 1,700 psi. Rate was maintained at 450 bId and WHP stabilized after 150 bbls were injected at 1,620 psi. Well-bore volume for L-122 is 78.7 bbls. Well bore volume for L-OI is 147.4 bbls. Total produced water injected by midnight was: L-OI 2184 bbls L-I22 270 bbls Johnny Brown, JB, and Ray Carlisle, RC, arrive in Anchorage. Accommodations at Puffin Inn. August 20, 2003 Wednesday: JB and RC arrive on the Slope via the 1:50 charter. Continued water injection on both the L-OI and L- 122 wells. L-122 injection rate slowed to 350 BPD as WHP increased to 1650. After discussing parting pressure, maximum WHP was increased to 1900 psi from 1700, this allowed L-122 injection rate to increase to 800 BPD.L-OI injection rate was 1480 BPD at a WHP of 1700 psi. Total produced water injected by midnight was: L-OI 3634 bbls L-122 716 bbls August 21, 2003 Thursday: Injection continues on both wells. L-O I after discussing parting pressure was increased from 1800 to 1900 psi. L-O I injection choke was opened all the way rate increased to 1600 bpd and WHP increased 1800 psi L-122 rate steady at 800 bpd. Total produced water injected by midnight was: L-Ol 5158 bbls L-1221589 August 22, 2003 Friday: L-122 from 8:30 am to 3:00 pm 210 bbls of fluid was back produced; in order to clean up the perfs, improve injection, and remove any oil left in the well bore. At 3:00 pm injection resumed on L-I22 at a rate of 800 bpd, well pressured back up and WHP was back to 1800 by midnight. Injection continued on L-O I with the choke all the way open. By midnight the total produced water injected was: L-Ol 6781 bbls L-122 2174 bbls August 23, 2003 Saturday: Injection continued on both wells. Total injection of produced water by midnight was: L-Ol 8328 bbls L-122 2973 bbls August 24, 2003 Sunday: Injection continued on both wells. Total injection of produced water by midnight was:OI 9830 bbls L-122 3717 bbls August 25, 2005 Monday: Injection of produced water was completed on L-122 at 8: 15 am total volume injected 3895 bbls. Then 305 bbls was back produced from L-122 in order to clean perfs and remove any remaining oil from well bore. Finished back producing L-122 at 12:30pm and started injecting tracer test by 1:00 pm. Tracer test design was to inject 150 bbls of 10,000 ppm ethyl acetate, 5,000 ppm n-propyl alcohol, and 2,500 ppm isopropyl alcohoL Followed by 450 bbls of 2,500 ppm isopropyl alcohoL Due to a decreased manifold pressure the injection rate fell from 800 BPD to 550 BPD this caused the IPA concentration to rise to 8500 ppm. The first 150 bbls was injected by 6:00 pm, the remainder of the test will continue through the night and finish sometime on the 26th. Injection continued on L-OI until I: 10 pm, total water injected 10450 bbls. L-OI was then back produced until 5:30 am August 26th; total fluid back produced 419 bbls. 27 28 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · August 26, 2003 Tuesday: Finished tracer push injection on L-122 by 3:40 pm, well will be shut in for 10 days to allow for reaction. Freeze protect called and arranged to come out the 27th at 9:00 am. Injection resumed on L-OI by 8:30 am. Surface safety valve shut at 4:00 pm, total water injected by then 10,914. Injection resumed at 7:40 pm. Total volume injected by midnight on L-O I 11,254 bbls. August 27, 2003 Wednesday: LS left the slope. Injection continued on L-OI manifold pressure decreased significantly rate dropped from 1,550 BPD to 1,100 BPD. Total volume injected by midnight was 12,781 bbls. August 28, 2003 Thursday: Injection continued on L-OI, manifold pressure started picking up by 6pm. Injection rate at midnight was back up to 1550 bpd and total volume injected was 13,995 bbls August 29, 2003 Friday: Produced water injection continues on L-OI, WHP holding steady at 1,750 psi with a rate of 1550 BPD. Total volume injected by eleven pm was 15,445 bbls. August 30, 2003 Saturday: Lanelle Carlisle, LC, arrives in Anchorage, accommodations at Barrett Inn. Injection on L-OI proceeds. Total volume injected by midnight was 16,915 bbls. August 31, 2003 Sunday: LC arrives on the slope. RC left the slope. Injection continues on L-Ol. Average rate, 1,450 bid. Total injected by midnight was 18,498 bbls. Sept. I, 2003 Monday: Kory Kumer, KK, arrives in Anchorage, accommodations at Barrett Inn. Continued L-OI injection. Arranged to put L-O I in test separator about midnight to back produce for clean-up. Total injected by start of back production was 19,967 bbls. Sept. 2, 2003 Tuesday: KK attended NSTC school. Start L-OI production for clean-up. Started at 12:21 AM. Produced 431 bbls by II :00 AM. Found best arrangement for continuous lift was a full open production choke and 3.5 MMSCFD gas lift rate. Actual gas lift rate was about 2 MMSCFD because the gas-lift gas manifold supply pressure was low at 1,560 psi. Continuous rate was 2, 100 BWPD. Started SWCT Test I injection at L-OI at 13:00 at 1,500 bid. Injected 200 bbls carrying ethyl acetate (EtAc), methyl acetate (MeAc), normal propyl alcohol (NPA), and iso- propyl alcohol (IPA), continued with 1,090 bbls total with last 890 bbls tagged with IPAonly. Total injected by midnight was 690 bbls. L-122 shut-in for soak period. Sept. 3, 2003 Wednesday: KK arrives on the slope via charter. Completed L-OI SWCT Test I at 06:33 with 1090.2 bbls injected. Freeze protect arranged for on Tuesday, scheduled for later in day. L-122 shut-in for soak period (10 days). L-OI shut-in for soak period (3 days). Sept. 4, 2003 Thursday:L-122 and L-O I shut-in for soak period. L-122 scheduled for POP on Friday AM. Sept. 5, 2003 Friday: L-I 22 POP at 8:46 am to produce tracer test. Methanol pump used for gas lift to prevent hydrate formation. Methanol pumped set at a 3% (30,000 ppm) concentration. Total production by midnight 738 bbls. Sept. 6, 2003 Saturday: L-122 tracer production stopped at 12:45 pm, 965 bbls produced. Well shut in at 12:45 and HBR started injecting low salinity water at a rate of 800 bpd. LOI POP at 2: Wpm in order to produce tracer test. Total barrels produced by midnight for L-OI was 567 bbls. · · · · · · · · · it · · · - - - · · · · · · · · · · t .' · · · · · - ~: · · · · · · · · Sept. 7, 2003 Sunday: HBR continued to inject low salinity water in L-122. At 9:45 pm HBR finished low salinity water injection and started to rig up on L-OI, total barrels oflow salinity water injected into L-I22 were 900 bbls. Produced water injection started at 10:00 pm on L-I22, 63 total barrels of produced water injected by midnight at a rate of 800 BPD. Continued to produce L-O 1 for tracer test, total barrels produced by midnight was 1481 bbls. Sept 8, 2003 Monday: Dan Dycus, DD, arrives in Anchorage, accommodations at the Barrett Inn. L-OI production finished at 6:40 am, total barrels produced 1685 bbls. HBR started to inject low salinity water there after at a rate of 2000 bpd. Produce water injection continued on .L-122. Sept 9, 2003 Tuesday: DD attends NSTC school in Anchorage. HBR finished low salinity water injection at 10:00 pm, total barrels injected 2,900. Produced water injection started at II :30 pm on L-Ol at a rate of 2000 BPD. Produced water injection continued on L-122, total barrels injected by midnight 1500 bbls. Sept 10,2003 Wednesday: DD arrives on the slope via charter. Produced water injection finished on L-122 at 19:50 total volume injected 2018 bbls. Well POP at 21 :00. Finished back production at 00:00 September 11, total volume produced was 203 bbls at an average rate of 1600 BPD. Injection line was blown out to with gas to prevent freezing. Discovered that 2" Halliburton valve on injection line was leaking. L-Ol produced water injection continued, by midnight 1700 bbls injected at a rate of 2000 BPD. September II, 2003 Thursday: L-122 well shut in until leaking 2" Halliburton valve was repaired. Began injecting second tracer test (after low salinity water) at 21:30 at a rate of 800 BPD. Tracer test design was to inject ISO bbls of 10,000 ppm ethyl acetate, 6,000 ppm n-propyl alcohol, and 4,000 ppm isopropyl alcohoL Followed by 450 bbls of 4,000 ppm isopropyl alcohoL The first 150 bbls was injected by 03:30 pm. The remainder of the test will continue through the day and finish sometime on the 12th L-O 1 produced water injection continued. L-O I surface safety valve closed due to the pad beginning closed in, injection was stopped from 8:30 to 14:45. Valve was opened and injection continued at a rate of 2,000 BPD, total injection by midnight was 3,148 bbls. September 12, 2003 Friday: L-122 SWCT test 2 injection completed at 19: 10. Total injection was 640 bbls. Freeze protect carried out immediately, 35 bbls dieseL Completed freeze protect at 19:45. Shut in for 12 day soak. L-Ol continued produced water injection. Total injected by midnight was 4,900 bbls. September 13,2003 Saturday: L-122 shut in. L-OI continued produced water injection at 1,900 BWPD. Completed 5,603 bbl injection at 9:50. Started back production for clean-up at 10:30. Produced 316 bbls by 14:00. Started SWCT test 2 injection at 19:30. Injection planned for was 200 bbls carrying ester pushed by 1000 bbls produced water with IPA only. Total injected by midnight was 195 bbls. September 14, 2003 Sunday: L-I22 shut in. L-OI completed SWCT test 2 at 15:00,1,090 bbls. Freeze protect carried out at 15:30,60 bbls dieseL Shut in well at 16:30. September 15,2003 Monday: L-I22 shut in. L-OI shut in. September 16, 2003 Tuesday: L-I22 shut in. L-O I shut in. Analyzed selected production samples from L-OI and L-122 test production to improve data quality where needed. KK left for home, PM. September 17, 2003 Wednesday: L-I22 shut in. L-OI shut in. Continued sample re-runs. 29 30 · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · September 18, 2003 Thursday: L-I22 shut in. L-OI shut in. September 19,2003 Friday: L-122 shut in. L-OI shut in. Charlie Carlisle, CC arrived back on Slope, PM. Arranged to produce L-02 into test header next day, Saturday. September 20, 2003 Saturday: L-I22 shut in. Started production of test 2 at L-O!. Started at 13:00. Total produced by midnight was 602 bbls. September 21, 2003 Sunday: L-122 shut in. L-OI continued production oftest 2. Total produced by midnight was 1,675 bbls. September 22, 2003 Monday: L-122 shut in. L-O I completed test 2 at 7 :30. Placed L-Ol into production header and continued production. September 23, 2003 Tuesday: L-122 shut in. L-O I producing water into production header. September 24, 2003 Wednesday: Started production of SWCT test 2 at L-I22 at 8 :30. Total produced by midnight was 719 bbls. L-O I continued production until 13:00. Shut in to run shut-off/pressure recording tool for build-up test. Set timer to shut off production and start recording data at 08:00 on Thursday. September 25, 2003 Thursday: Completed L-122 test 2 production at 15:37. Total produced 1,175 bbls. Continued production via production header until 20:00 when well was shut down to run pressure recorder/shut -off tool for build-up test. Ran drift to bottom successfully. Second slick-line run to set tool encountered ice at 1,200 feet. Unable to run tool. L- 01, shut off tool appeared to stop production at 8:00 AM (well head started cooling). September 26, 2003 Friday: L-122 sent for hot-oil unit to thaw tubing. Plan to freeze protect after thaw and wait until after pad shut- down scheduled for Sat. Sun. before producing more. CTI rigged down L-pad tracer lab, injection equipment and chemical drums. September 27, 2003 Saturday: L-122 Hot oil truck arrived and did not have enough fluid to thaw the tubing. Well shut-in for L-Pad shut down. Rigged down Hot Oil unit. Rigged up BP methanol pump so methanol can be added to gas lift gas when L- 122 is returned to production. cn Lab cleared and equipment boxed for shipment. cn equipment taken to BOC warehouse for shipment to Laramie. Cleared off remaining containments, etc related to SWCT testing and secured site. September 28, 2003 Sunday: CTC, LC and JB traveled to Anchorage, PM. Wrapping up last details of report. September 29,2003 Monday: Completed Report PM. Delivered to Kinko's in Anchorage to bind copies. September 30, 2003 Tuesday: CTC met with Frank Paskvan, Bruce Smith, Pat McGuire, Gil Buhler, Jim Young, and Doug Pollock, AM. Reviewed test results from L-Ol and L-122. Delivered report copies to BP at 9:30 PM. CTC, LC, JB departed Anchorage at II :45 PM. October 1,2003 Wednesday: CTC, LC, and JB arrived home, AM. October 4, 2003 Saturday: cn equipment arrived in Laramie, · · · · · · · · - JJiii2 .. · · · · - - · · - .. · · · · · · · · · - · · · 4Þ, .. · · · · · · · · APPENDIX E TABULAR FIELD DATA The field analytical data recorded during the reported L-122 SWCT SOR Test I is presented in tabular form here. These data are plotted in the Figures of this report and recorded here to accommodate data entry to other media. BBLS. EtOH IPA o 40 49 58 67 75 81 85 89 97 102 108 44 121 130 137 38 143 149 49 155 161 49 167 173 180 53 186 192 198 59 204 69 215 222 86 228 97 234 240 101 246 252 258 121 264 270 276 282 136 288 294 300 133 306 312 137 2455 3699 4789 5126 5639 6576 6527 6882 6913 7044 6663 6710 6708 6716 NPA EtAc 315 455 310 391 327 319 272 299 250 o 265 293 277 229 247 271 249 272 244 266 364 420 472 433 444 560 595 31 · · · 88lS. EtOH IPA NPA EtAc · 324 137 6476 562 660 · 330 · 336 6277 756 343 151 · 352 0 6272 611 867 · 358 0 366 130 6048 851 · 372 0 5231 765 988 · 380 131 · 390 0 5653 1037 401 119 5901 853 921 · 411 0 5836 1204 · 420 108 5616 931 1063 430 93 5278 1167 · 444 81 5374 978 1142 · 457 74 5028 1341 · 471 71 4841 1045 1312 488 59 4968 1432 · 499 46 4738 1250 · 517 38 4572 1162 1354 553 33 4601 1402 · 584 33 4029 1433 · 595 1134 · 615 28 1475 637 20 1061 1310 · 652 18 3110 1145 · 673 15 2941 1233 688 13 2533 1006 1226 · 710 12 2444 1171 · 721 15 2317 1097 · 738 11 2134 1126 754 9 2005 891 1076 · 769 1869 980 · 770 7 1865 901 788 1799 899 · 805 5 1640 880 · 807 7 1754 857 · 808 1421 993 815 10 1136 638 · 823 4 1309 732 705 · 834 1388 933 843 1481 843 · 859 1083 570 · · · · · · · 32 · · · · · · · · · · · · · It · · · · · · · · · · · tt · · - · I .. · · · · 4Þ · · · · · - · · · The field analytical data recorded during the reported L-122 SWCT SOR(LoSAL) Test 2 is presented in tabular form here. BBLS. EtOH IPA NPA EtAc 62 88 5202 83 77 88 10 5185 100 111 5 2472 126 135 7 2130 10 142 170 17 3422 87 191 196 26 3301 66 245 212 36 96 289 227 241 41 139 312 258 273 47 3220 179 288 52 3341 187 570 305 49 3225 199 534 319 53 248 334 54 305 355 55 2676 264 370 381 388 56 2524 377 403 418 53 385 860 433 51 2451 445 448 2148 432 464 50 2123 395 900 479 496 48 2279 426 512 1956 446 837 533 37 1783 468 548 39 1896 436 563 36 1646 398 584 37 1555 386 812 599 29 1503 422 610 1566 394 829 625 33 1461 394 645 1513 388 829 660 22 1427 422 672 1231 401 786 686 23 1029 351 747 33 · · · BBLS. EtOH IPA NPA EtAc · 704 1100 . 299 · 719 883 340 643 747 18 961 273 627 · 773 982 267 629 · 798 19 821 251 820 14 812 245 547 · 846 714 253 506 · 873 7 679 209 · 895 27 735 172 514 919 667 188 405 · 957 597 143 425 · 987 46 527 123 434 · 1023 37 19 397 287 1055 23 644 · · · · · · · · · · · · · · .. · · · · · · · · · · · · · 34 · · · . TREE = 3-1/8" 5M CIW W8...LI-EAD =.' 11" FMC AcrðAToR = -NA KB. ELEV = 77' A_'~_AA_A~_M BF. ELEV = 50' KOP = 300' Max Angle = 5a'> @ 4352' Datum MD = 8994' Datum TVD;' 6600; SS 17-5/8" CSG, 29.7#, S-95, ID= 6.875" H L-122 = :i --- 3373' - 17-5/8" CSG, 29.7#, L-BO, I[)= 6.875" H 3458' ~ 1022' 2730' . SAFETY NOTES: H TA M PORT COLLAR I H3-1/2" I-ESX I\IP, ID=2.813" 1 GAS LIFT MANDR8...S IMinimum ID = 2.813" @ 2730' I ST M) TVD DBI TYPE VLV LATCH FORT DATE L 6 3441 2596 57 KBG2-9 DOM: BTM 16 06¡Q2/03 3-1/2" H ES X NIP PLE 5 4704 3303 55 KBG2-9 DMY BTM 0 OS/29/03 4 6132 4200 42 KBG2-9 DOM: BTM 16 06ÆJ2/03 3 7367 5107 45 KBG2-9 DOM: BTM 16 06¡Q2/03 2 8203 5718 38 KBG2-9 DOM: BTM 16 06¡Q2/03 1 8695 6147 19 KBG2-9 SO BTM 24 06¡Q2/03 ~ -----i 8752' H3-1/2" BKR CMDSLDING SLY, ID =2.813" 1 - 13-1/2" TBG, 9.2#, L-80, .0087 bpf, ID = 2.992" H 8766' 5-1/2" CSG, 15.5#, L-80, ID = 4.950" H 8776' j q 15-1/2" X 3-1/2" CSG XO, ID = 2.95" H 8796' PERFORATION SUMMARY REF LOG: DENSITY/NBJ1RON ON 05126/03 ANGLEA TTOP ÆRF: 7 @ 9050' t\bte: Refer to A"oduction DB for his1Drical perf data SIZ E SPF INfERIf AL OpnlSqz DATE 2-1/2" 6 9050-9070 0 07/26/03 ---I - ---I c PBlD H 9311' ~ 13-1/2" CSG, 9.2#, L-80, ID= 2.992" H 9410' DATE 05/31/03 06/02/03 07/26/03 REV BY COMM:NfS DAV/KK ORIGINAL COMPLETION Mf-IIKK GL V C/O BJM'KK IÆRF DATE RBI BY CO Mv1ENTS 8776' 8776' 8795' 8878' 8899' 8940' 9181' HBKRLOC SEAL ASSY, ID= 3.00" HTOP OF BKRPBR, ID= 4.00" I U BTM OF 3-1/2" BKR SBR, ID = 3.00" H3-1/2" HEB X NIp, ID= 2.813"1 H3-1/2" I-ES X NIP, ID = 2.813" I HpUPJTW/RA TAG I HpUPJTW/ RA TAG I ffiUDHOE BA Y Uf\IT W8...L: L-122 ÆRfI!IIT No: 2030510 API No: 50-029-23147-00 SEe 34, T12N, R11 E, 2536' NSL & 3831' WEL BP Exploration (Alaska) ! iii ,.~ . '. .. STATE OF ALASKA I ALAS~IL AND GAS CONSERVATION COM I SSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: 1m Oil 0 Gas 0 Plugged 0 Abandoned 0 Suspended 0 WAG 20AAC 25.105 20AAC 25.110 CASING, LINER AND CEMENTING RECORD SETTIN.GÐEPTI-f BÖttÖM 110' 3458' 8796' 9410' o GINJ 0 WINJ 0 WDSPL No. of Completions 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 2536' NSL, 3831' WEL, SEC. 34, T12N, R11E, UM Top of Productive Horizon: 287' NSL, 3094' WEL, SEC. 28, T12N, R11 E, UM Total Depth: 331' NSL, 3106' WEL, SEC. 28, T12N, R11E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: )(- 583084 y- 5978256 Zone- ASP4 TPI: )(- 578502 y- 5981238 Zone- ASP4 Total Depth: x- 578489 Y- 5981281 Zone- ASP4 18. Directional Survey 1m Yes 0 No 21. Logs Run: MWD, GR, RES, NEU, DEN, PWD 22. 34" x 20" 7-5/8" 5-1/2" 3-1/2" 91.5# 29.7# 15.5# 9.2# H-40 S-95 L-80 L-80 Surface 28' 25' 8796' 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): 2-1/2" Gun Diameter, 6spf MD TVD MD TVD 9050' - 9070' 6493' - 6513' 26. Date First Production: July 30,2003 Date of Test Hours Tested 7/30/2003 4 Flow Tubing Casing Pressure Press. 345 One Other 5. Date Comp., Susp., or Aband. 7/26/2003 6. Date Spudded 5/20/2003 7. Date T.D. Reached 5/26/2003 8. Elevation in feet (indicate KB, DF, etc.) KBE = 77' 9. Plug Back Depth (MD+ TVD) 9311 + 6752 Ft 10. Total Depth (MD+TVD) 9422 + 6862 Ft 11. Depth where SSSV set (Nipple) 2730' MD 19. Water depth, if offshore NIA MSL 42" 1 b. Well Class: 1m Development 0 Exploratory o Stratigraphic 0 Service 12. Permit Number 203-051 13. API Number 50- 029-23147-00-00 14. Well Number PBU L-122 15. Field and Pool Prudhoe Bay Field 1 Borealis Pool 16. Lease Designation and Serial No. ADL 028239 17. Land Use Permit: 20. Thickness of Permafrost 1900' (Approx.) 9-7/8" 6-3/4" 6-3/4" 260 sx Arctic Set (Approx.) 412 sx Permafrost 'L', 197 sx Class 'G' 152 sx Class 'G', 160 sx Class 'G' (5-1/2" x 3-112" Cement Job) SIZE 3-1/2",9.2#, L-80 DEPTH SET (MD) 8795' PACKER SET (MD) NIA DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Freeze Protect with 156 Bbls of Diesel PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc.): Flowing OIL-BsL GAs-McF WATER-BsL 671 317 13 PRODUCTION FOR TEST PERIOD + CALCULATED + 24-HoUR RATE OIL-BsL 4026 27. GAs-McF 1902 WATER-BsL 78 CHOKE SIZE I GAS-OIL RATIO 176 472 OIL GRAVITY-API (CORR) 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 nOn~, state "none". ~~ëiJi¡?Jt¿::¡;;XI'T-' None ~ ~ !rTE IL~~1 . _ V~FIED . . (' . " , . Form 10-407 Revised 2/2003 OJ 01 \- ! ) \ \ ). ¡~ ,- CONTINUED ON REVERSE SIDE ~Í<Õ! rwl2ü r~(.;)!U~:i'A!Þ! iC2Jtr"1b AUG 1 ~p , 2t!. .. GEOLOGIC MARKE8 29. _FORMATION TESTS Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". NAME MD TVD Ugnu 3811' Ugnu M 5718' Schrader Bluff N 6094' Schrader Bluff 0 6298' Base Schrader I Top Colville 6779' CM2 7180' CM1 8104' HRZ 8628' Kalubik 8857' Kuparuk D 9014' Kuparuk C 9050' Kuparuk B 9197' Kuparuk A 9339' 2802' None 3906' 4172' 4322' 4678' 4973' 5640' 6084' 6303' 6457' 6492' 6638' 6779' 30. List of Attachments: Summary of Daily Drilling Reports, Surveys 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Terrie Hubble ~Jl.; J . ~ Title Technical Assistant Date 08.. { ~"'D3 PBU L-122 203-051 Prepared By NamelNumber: Terrie Hubb/e, 564-4628 Well Number Drilling Engineer: Neil Magee, 564-5119 Permit No. I Approval No. INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. ITEM 4b: TPI (Top of Producing Interval). ITEM 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. ITEM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). ITEM 20: True vertical thickness. ITEM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). ITEM 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). ITEM 27: If no cores taken, indicate "None". ITEM 29: List all test information. If none, state "None". Form 10-407 Revised 2/2003 Legal Name: L-122 Common Name: L-122 5/23/2003 LOT 3.76 (ppg) 865 (psi 550 (psi 9.70 (ppg) 2,610.0 (ft) 3,458.0 (ft) e e Printed: 6/2/2003 8:10:53 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L-122 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: Rig Release: Rig Number: 5/19/2003 5/29/2003 Spud Date: 5/20/2003 End: 5/29/2003 5/19/2003 09:00 - 12:00 3.00 MOB P PRE Prep rig floor and cellar for move. Bridle up. RD pipe chute 12:00 - 14:00 2.00 MOB P PRE Layover derrick. Move sub off of V-202, down L-Pad access road and onto the pad. 14:00 - 15:00 1.00 MOB P PRE Lay mats and pit liner. Arrange diverter spool and riser around cellar. 15:00 - 16:00 1.00 MOB P PRE Position sub over L-122, raise derrick. Spot and RU pits. RIG ACCEPTED @ 16:00 16:00 - 23:30 7.50 BOPSURP PRE NU diverter spool and riser. Take on water for spud mud 23:30 - 00:00 0.50 BOPSURP SURF PU DP from pipe shed, MU stands and stand back in derrick. 5/20/2003 00:00 - 03:30 3.50 BOPSURP SURF Continue PU DP from pipe shed, MU stands and stand back in derrick. 03:30 - 04:00 0.50 BOPSURP SURF Function test diverter and knife valve 04:00 - 04:30 0.50 BOPSUR P SURF Pre-spud meeting 04:30 - 05:30 1.00 DIVRTR P SURF Diverter drill & Rig evacuation drill 05:30 - 08:00 2.50 DRILL P SURF MU BHA #1. RU SWS sheave in derrick for GyroData surveys 08:00 - 10:30 2.50 DRILL P SURF Drill from 110' to 359'. SPUD WELL @ 08:00 10:30 - 11 :00 0.50 DRILL P SURF POH with 2 stands of HWDP. MU jar stand. Wash to bottom. 11 :00 - 00:00 13.00 DRILL P SURF Directional drill from 359' to 1440'. Take GryoData surveys every 100' to 1100' MD. 76 klbs up, 71 klbs down, 74 klbs rotate. 650 gpm at 2200 psi. Lost communication with MWD, cycled pumps unable to regain transmission. AST last 24 hrs = 7.48 hrs. ART last 24 hrs = 2.04 hrs. Total drilling time = 9.52 hrs. 5/21/2003 00:00 - 00:30 0.50 DRILL P SURF Ciculate and condition hole to POH and change out MWD and pick up new MX-C1 bit. Monitor well - static. 00:30 - 01 :30 1.00 DRILL P SURF POH. Pulled 15-20 klbs over from 1040' to 1000' 01 :30 - 02:30 1.00 DRILL P SURF PU new MWD and bit. Orient MWD. Shallow test MWD - OK. 02:30 - 03:30 1.00 DRILL P SURF RIH with BHA #2. Wipe through tight spot from 1000' to 1040' 03:30 - 13:30 10.00 DRILL P SURF Directional drill from 1440' to 3468'. Build angle to -57 degrees. 650 gpm @ 3400 psi. 105 klbs up, 66 klbs down, 78 klbs rotate. TD surface hole section in first shale below the top of the SV1 sand. AST last 24 hrs. = 2.2 hrs. ART last 24 hrs. = 3.7 hrs. Total drilling time for 9-7/8" section = 15.42 hrs. 13:30 - 14:30 1.00 DRILL P SURF Circulate and condition hole. Monitor well - static. Blow down top drive. 14:30 - 16:00 1.50 DRILL P SURF POH on short trip to 800'. Work through tight spots at 2600' and 1200' 16:00 - 20:00 4.00 DRILL P SURF RIH to TD. hit obstruction at 1000', push and work through. Wash through intermintent tight spots all the way to TD. 20:00 - 21 :00 1.00 DRILL P SURF Circulate and condition hole for POH. 630 gpm at 3050 psi. 21 :00 - 00:00 3.00 DRILL P SURF POH to run 7-5/8" csg. Wipe through tight spots at 2500',2200' and 1400' - no problems on second pass through. 5/22/2003 00:00 - 01 :30 1.50 DRILL P SURF Stand back HWDP. LD BHA #2 01 :30 - 02:00 0.50 DRILL P SURF Clean and clear rig floor 02:00 - 04:00 2.00 CASE P SURF RU fill up tool and csg. equipment. Drain and flush stack. MU Printed: 6/212003 8: 11 :01 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L-122 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: Rig Release: Rig Number: 5/19/2003 5/29/2003 Spud Date: 5/20/2003 End: 5/29/2003 5/22/2003 02:00 - 04:00 2.00 CASE P SURF landing joint and make dummy run. 04:00 - 04:15 0.25 CASE P SURF PJSM with Nabors Csg., PES and all rig personnel on running 7-5/8" csg. 04: 15 - 05:00 0.75 CASE P SURF MU and BakerLok float equipment. Check floats - OK. 05:00 - 10:30 5.50 CASE P SURF Run 7-5/8"29.7# BTC-M casing to 3458'.110 klbs up, 70 klbs down. 10:30 - 11 :00 0.50 CEMT P SURF Land Csg. RD fill up tool, RU cement head 11:00-12:15 1.25 CEMT P SURF Stage pumps to 8 bpm, 610 psi to circulate and condition mud for cement job. Reciprocate csg 10' while circulating. 12:15 - 12:30 0.25 CEMT P SURF PJSM with HOWCO, PES and rig personnel on surface casing cement job. 12:30 - 12:45 0.25 CEMT P SURF RU HOWCO cementers. Pump 10 bbl water pre-flush and pressure test lines to 3500 psi - OK. 12:45 - 14:00 1.25 CEMT P SURF Pump remaining 10 bbl water flush followed by 75 bbls of 10.2 ppg alpha spacer at 6 bpm, 280 psi. Drop bottom plug. Mix and pump 314 bbls (425 sxs) 10.7 ppg PermaFrost L lead cement at 6 bpm, 300 psi. Follow with 43 bbls (210 sxs) 15.8 ppg Premium Class G tail cement at 5 bpm, 300 psi. 14:00 - 15:00 1.00 CEMT P SURF Drop top plug and kick out with 10 bbls water from HOWCO. Switch to rig pumps and displace with 146 bbls mud. Bump plugs on calculated strokes, pressure up to 1500 psi, FCP 1000 psi. Bleed off pressure and check floats - OK. Casing landed after lead cement came around the shoe. 100 bbls good cement returns. CIP 14:30 15:00 - 16:30 1.50 CEMT P SURF RD cement head. LD landing joint. Flush flow lines and diverter. 16:30 - 17:30 1.00 CASE P SURF RD casing equipment and clear rig floor 17:30 - 20:30 3.00 DIVRTR P SURF ND diverter and position in cellar 20:30 - 22:00 1.50 WHSUR P SURF Move wellhead equipment into cellar. NU same. Test metal to metal seal to 1000 psi - OK. 22:00 - 00:00 2.00 BOPSURP SURF NU BOPE 5/23/2003 00:00 - 00:30 0.50 BOPSUR P SURF RU BOP test equipment 00:30 - 03:30 3.00 BOPSURP SURF Test BOPE 250 psi low and 4000 psi high. Test the Hydril 250 psi low and 3500 psi high. Witness of BOP test waived by Chuck Sheve AOGCC. 03:30 - 04:00 0.50 BOPSUR P SURF RD BOP test equipment. Install wear bushing 04:00 - 09:30 5.50 DRILL P PROD1 PU 120 single joints of DP, MU stands and stand back 09:30 - 09:45 0.25 DRILL P PROD1 PJSM SWS and rig personnel - Picking up BHA and loading nuclear sources. 09:45 - 13:00 3.25 DRILL P PROD1 PU BHA #3. Orient and shallow test MWD. 13:00 - 15:00 2.00 DRILL P PROD1 RIH to 3195'. At 1021' test TAM port collar to 1000 psi - OK. 15:00 - 15:30 0.50 CASE P SURF Test 7-5/8" csg to 3500 psi - OK 15:30 - 16:00 0.50 DRILL P PROD1 Wash down and tag float collar at 3373'. 16:00 - 19:00 3.00 DRILL P PROD1 Drill cement from 3373' to float shoe, tagged at 3458'. Drill rat hole to 3468' and 20' of new hole to 3488'. WOB 5-10 klbs, 50 rpm, 275 gpm @ 1600 psi. 19:00 - 20:00 1.00 DRILL P PROD1 Displace well to new 9.7 ppg LSND mud, Rotate and reciprocate during diplsacement. 20:00 - 20:30 0.50 DRILL P PROD1 Pull bit back inside 7-5/8" casing and perform LOT. EMW calculated at 13.76 ppg 20:30 - 21 :00 0.50 DRILL P PROD1 Circulate at drilling rate to establish baseline ECD. 21 :00 - 00:00 3.00 DRILL P PROD1 Directional drill from 3488' to 3941'.82 klbs up, 70 klbs down, 75 klbs rotate. WOB 8-10 klbs and 80 rpm. 325 gpm @ 1850 Printed: 6/2/2003 8: 11 :01 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L-122 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: Rig Release: Rig Number: 5/19/2003 5/29/2003 Spud Date: 5/20/2003 End: 5/29/2003 5/23/2003 21 :00 - 00:00 3.00 DRILL P PROD1 psi. Back ream every stand at drilling rate, reducing flow rate to 250 gpm on down stroke. At 3847' took a 20 bblloss while circulating a sweep around to reduce ECD's, ECD spiked at 1.3 ppg over calculated. Regained full returns and contined drilling ahead circulating as needed to reduce ECD's. AST last 24 hrs. = 0.15 hrs. ART last 24 hrs. = 1.35 hrs. Total drilling time = 1.5 hrs. 5/24/2003 00:00 - 06:00 6.00 DRILL P PROD1 Directional drill from 3941' to 4593'.90 klbs up, 71 klbs down, 80 klbs rotate. WOB 8-12 klbs, 80 rpm. Torque 3,800 Ibs. 325 gpm @ 2350 psi. slide to maintain angle -56 degrees. Back ream every stand at drilling rate, reducing flow rate to 250 gpm on down stroke. Circulate hi-vis sweep every 300', or as need to reduce ECD's. Circulate as needed to maintain ECD's within 1.2 ppg of calculated. 5 bblloss at 4499'. Total losses 25 bbls 06:00 - 07:30 1.50 DRILL P PROD1 Circulate and condition hole. 325 gpm at 2210 psi.. Pump lo-hi vis sweep to clean hole. 07:30 - 10:00 2.50 DRILL P PROD1 Back ream to shoe to clean hole and reduce ECD's 10:00 - 10:30 0.50 DRILL P PROD1 Circulate and condition at shoe. Pump lo-hi vis sweep. 10:30 - 11 :30 1.00 DRILL P PROD1 RIH to 4499'. Wash and ream to bottom at 4593' 11 :30 - 00:00 12.50 DRILL P PROD1 Directional drill from 4593' to 6088'.114 klbs up, 82 klbs down, 95 klbs rotate. WOB 8-15 klbs, 80 rpm. Torque 4400 Ibs. 330 gpm @ 2700 psi. slide as needed to maintain angle at -56 degrees to 5200' then drop inclination to 42 degrees and hold. Back ream every stand at drilling flow rate and 100 rpm, reducing flow rate to 250 gpm on down stroke. Circulate hi-vis sweep every 200', or as need to reduce ECD's. Circulate as needed to maintain ECD's within 1.2 ppg of calculated. As the string reamer came out of the Ugnu form. the ECD's dropped to 0.4-0.7 over calculated, able to increase ROP. AST last 24 hrs. = 2.86 hrs. ART last 24 hrs. = 4.37 hrs. Total drilling time = 8.73 hrs Total losses 25 bbls 5/25/2003 00:00 - 00:00 24.00 DRILL P PROD1 Directional drill from 6088' to 8328'. 156 klbs up, 94 klbs down, 116 klbs rotate. WOB 8-15 klbs, 80 rpm. Torque 7-10 klbs. 325 gpm @ 3200 psi. Back ream every stand at drilling flow rate and 100 rpm, reducing flow rate to 250 gpm on down stroke. Circulate hi-vis sweep every 500', or as need to reduce ECD's. Circulate as needed to maintain ECD's within 1.5 ppg of calculated. weight up mud to 9.9 ppg at 8300',200' above HRZ. AST last 24 hrs. = 1.95 hrs. ART last 24 hrs. = 11.16 hrs. Total drilling time = 21.84 hrs. 5/26/2003 00:00 - 14:30 14.50 DRILL P PROD1 Directional drill from 8328' to 9422'. 180 klbs up, 108 klbs down, 136 klbs rotate. WOB 8-15 klbs, 100 rpm. Torque Printed: 6/2/2003 8:11:01 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L-122 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: Rig Release: Rig Number: 5/19/2003 5/29/2003 Spud Date: 5/20/2003 End: 5/29/2003 5/26/2003 00:00 - 14:30 14.50 DRILL P PROD1 7.5-8.8 klbs. 325 gpm @ 3650 psi. 30' back ream on every stand at drilling flow rate and 100 rpm, reducing flow rate to 250 gpm on down stroke. Circulate hi-vis sweep every 500', or as need to reduce ECD's. Calculated ECD = 11.13, Actual ECD=11.85 AST last 24 hrs. = 4.3 hrs. ART last 24 hrs. = 5.21 hrs. Total drilling time = 31.35 hrs. 14:30 - 16:30 2.00 DRILL P PROD1 Circulate and condition. Pump hi-vis sweeps to reduce ECD's. Calculated ECD = 11.13. Actual ECD prior to short trip 11.53. 16:30 - 16:45 0.25 DRILL P PROD1 Monitor well - static. 16:45 - 19:15 2.50 DRILL P PROD1 POH 10 stands, pump dry job. Continue POH to csg shoe at 3458'. No hole problems on POH. 19:15-19:30 0.25 DRILL P PROD1 Monitor well - static 19:30 - 21 :00 1.50 DRILL P PROD1 Cut and slip 85' of drilling line. Service top drive and crown. 21 :00 - 23:00 2.00 DRILL P PROD1 RIH to 6650' at 1 to 1-1/2 minutes per stand. Fill pipe and break circulation every 10 stands. Monitor DP displacement 23:00 - 23:30 0.50 DRILL P PROD1 Stage pumps to drilling rate. CBU at 100 rpm 23:30 - 00:00 0.50 DRILL P PROD1 Continue RIH. 1 to 1-1/2 minutes per stand. fill pipe and break circulation every 10 stands. Monitor DP displacement. 5/27/2003 00:00 - 01 :00 1.00 DRILL P PROD1 Continue RIH to TD @ 9422' 01 :00 - 02:30 1.50 DRILL P PROD1 Circulate and condition. Circulate hi-vis sweep around. 325 gpm @ 3150 psi. Calculated ECD 11.13 actual ECD prior to POH 11.34 02:30 - 02:45 0.25 DRILL P PROD1 Monitor well - static 02:45 - 04:30 1.75 DRILL P PROD1 Stand 10 stands back in derrick to put bit above HRZ. Pump dry job. Continue POH, laying down 54 joints to the base of the Schrader at 6779'.210 klbs up, 104 klbs down 04:30 - 06:00 1.50 DRILL P PROD1 Break circulation and spot 150 bbl 30#/bbl G-Seal pill from the base of the Schrader to the csg shoe 3458'. 06:00 - 12:00 6.00 DRILL P PROD1 Continue POH, laying down DP 12:00 - 15:00 3.00 DRILL P PROD1 Lay down HWDP. Layout BHA and remove source. Lay down all excess vendors equipment. 15:00 - 15:30 0.50 CASE P PROD1 Remove wear ring and dummy run landing joinUhanger. 15:30 - 17:00 1.50 CASE P PROD1 Change bails. RIU to run 5 1/2 x 3 1/2 tapered longstring. 17:00 - 18:30 1.50 CASE P PROD1 P/U 3 1/2 , 9.2 # L-80 casing and float equipment. Check floats. 18:30 - 00:00 5.50 CASE P PROD1 RIU 200 Ton 5 1/2 elevators and "Franks" fill up tool. RIH with 5 1/2 15.5# L-80 casing to 2608. Fill each joint with Franks tool and circulate down every 15 joints for 10 minutes. Running speed while up inside casing @ 1 minute per joint. 5/28/2003 00:00 - 01 :00 1.00 CASE P PROD1 RIH with 3 1/2 x 51/2 tapered long string from 2,608 to 3,458. 01 :00 - 01 :30 0.50 CASE P PROD1 Circulate 1.5 times bottoms up at 5 BPM @ 560 PSI., with no losses. Up wt. 76K Dwn. wt. 63K. 01 :30 - 05:30 4.00 CASE P PROD1 Continue TIH with 3 1/2 x 51/2 tapered long string to 5,700 @ 1 minute per jt., fill every joint and break circulation for 15 minutes every 15 run. No adverse hole conditons. 05:30 - 06:30 1.00 CASE P PROD1 CBU at 2 BPM @ 550 PSI. Up wt.==1 06 Dwn wt.==71 K. Lost a total of 11 bbls. while running in from shoe to 5,700. 06:30 - 12:30 6.00 CASE P PROD1 Continue in hole with 3 1/2 x 51/2 tapered string, from 5,700 to 8,500. 12:30 - 13:30 1.00 CASE P PROD1 Stage pumps up to 3 BPM @ 780 PSI. CBU. (Additional rate Printed: 61212003 8: 11 :01 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L-122 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: Rig Release: Rig Number: 5/19/2003 5/29/2003 Spud Date: 5/20/2003 End: 5/29/2003 5/28/2003 12:30 - 13:30 1.00 CASE P PROD1 caused losses to occur.) 13:30 - 15:30 2.00 CASE P PROD1 RIH to 9,383. P/U landing joint and hanger and wash to shoe setting depth of 9,410. RID "Franks" tool and P/U cement head. Up==190K Dwn==86K 15:30 - 18:30 3.00 CASE P PROD1 Stage pumps up to 5 BPM @ 1050 PSI and circulate and conditon for cement job. 18:30 - 20:30 2.00 CEMT P PROD1 Pump 5 bbls. water and pressure test lines to 3,500. Pump 25 bbls. of 10.9 ppg. alpha spacer, 64 bbls.(154 sks.) 12.5 ppg. lead followed by 33 bbls.(160 sks.) tail @ 15.8 ppg.. Swap to rig pumps and kick out double plug assembly with seawater. Displace cement @ 6 BPM for first 170 bbls. then 4 BPM for next 35 bbls. Pump final 1 0 bbls. at 2 bpm and bump plug at calculated displacement. Pressure up to 2250 and hold bump pressure for 5 minutes. Check floats. Note: Lost 30 bbls. of mud during cement job. Reciprocated string with 10 ft. strokes until 12 bbls. away from bumping plug. Good lift seen as cement rounded shoe and up annulus. CIP @ 20:30 hrs. 20:30 - 21 :30 1.00 CEMT P PROD1 RID casing running equipment. Back out and layout landing joint. Clear floor of all vendors excess equipment. 21 :30 - 22:30 1.00 CEMT P PROD1 Install and pressure test packoff to 5,000 for 5 minutes. 22:30 - 23:30 1.00 RUNCOMP COMP Dummy run landing joint and tubing hanger. 23:30 - 00:00 0.50 RUNCOMP COMP PJSM. P/U Baker "Seal Assembly" and coat seals with lubricants. 5/29/2003 00:00 - 07:00 7.00 RUNCOMP COMP RIH with 3 1/2" IBT-Mod, 9.2 #, L-80 completion to 6,055. 07:00 - 08:00 1.00 RUNCOMP COMP RlU and pressure test casing to 3,500 PSI. 08:00 - 12:00 4.00 RUNCOMP COMP RIH with 3 1/2" IBT-Mod, 9.2 #, L-80 completion to 8,792. Perform LOT on OA while running in hole. Test MW==9.9 TVD==2604 Leak off pressure==500 EMW==13.5 Inject 85 bbls. at 3 bpm at 700 PSI. 12:00 - 13:30 1.50 RUNCOMP COMP Make up circ. pin and cement hose to tubing string and sting into Baker seal receptical while pumping slowly. Confirm sting in with pressure increase. Stop pumps and bottom out seal assembly into receptical. Space out to allow app. 1.5 ft. from being fully inserted. M/U hanger and confirm space-out. 13:30 - 15:00 1.50 RUNCOMP COMP Reverse circulate in inhibitor treated seawater at 4 BPM @ 770 psi. 15:00 - 15:30 0.50 RUNCOMP COMP Land tubing and run in and torque LDS to specs. per FMC. 15:30 - 17:00 1.50 RUNCOMP COMP Test tubing and annulus to 4,000 for 30 minutes each. Bleed pressures to zero. Pressure up to 2,700 on annulus and shear open DCK in bottom stationed GLM. Establish circulation both ways. 17:00 -17:30 0.50 RUNCOMP COMP Install 2-way check and pressure from below to 2,800 psi. 17:30 - 19:00 1.50 RIGD P COMP NID 5,000K stack and set on stand. 19:00 - 20:30 1.50 RIGD P COMP N/U adapter flange and tree. Test to 5,000 psi. 20:30 - 21 :30 1.00 WHSUR P COMP Pump down OA with 57 bbls. heated diesel and freeze protect. (2.5 BPM @ 900 PSI.) Initial breakdown at 550 PSI. 21 :30 - 22:30 1.00 WHSUR P COMP Pressure test lines to 3,000 and pump 99 bbls. 70 degree Printed: 61212003 8:11 :01 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-122 L-122 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 5/19/2003 Rig Release: 5/29/2003 Rig Number: Spud Date: 5/20/2003 End: 5/29/2003 5/29/2003 21 :30 - 22:30 1.00 WHSUR P COMP diesel down IA @ 3.5 BPM with 2,800 PSI. Connect IA to tubing and allow to U-tube to balance point. Install BPV and test from below to 1,000. RID and blow down completion manifold and layout all excess vendors equipment. Remove secondary annulus valve and secure tree. 22:30 - 00:00 1.50 WHSUR P COMP Release rig from L-122 @ 00:00 Hrs. Printed: 6/2/2003 8: 11 :01 AM e e Well: Field: API: Permit: L -1 22 Prudhoe Bay Unit 50-029-23147-00 203-051 Accept: Spud: Release: 05/19/03 OS/20/03 OS/29/03 Nabors 9ES POST RIG WORK 06/01/03 DRIFT WI 2.75 TS WI 2.60 BG TO 9258 WLM. SET X CATCHER SUB @ 8860' WLM. PULL VALVES @ STA# 1,2,3,4,6. ATTEMPT TO SET STA # 6@3425 WLM 06/02103 SET STA'S # 6,4,3,2,1. PULLED X CATCHER SUB @ 8860' WLM. 07/26/03 DRIFT W/2.5 D-GUN, TAG TD @ 9278 WLM. (PERF TARGET 9050-9070). RIH WITH PERF ASSEMBLY, PERFORATED 9050' - 9070',6 SPF POWERJET. CORRELATE TO SCHLUMBERGER VISION DENSITY NEUTRON LOG. RAN JEWELRY LOG FROM 9270' TO 8650', TAGGED AT 9296'. 07/30/03 HOT POP FOR WELL TEST {SANDERS} HHP T1I10=64010/180 FINAL WHP TIII0=540/800/240. 07/31/03 TIO= 351/8001190. IA FL @ 8495' (200' ABOVE STA # 1,75 BBLS). (FOR GLE). GLR 1 MIL. SCHLOMBERGER Survey report Client... ................: BP Exploration (Alaska) Inc. Field. . . . . . . . . . . . . . . . . . . .: Borealis Well. . . . . . . . . . . . . . . . . . . . .: L-122 API number............ ...: 50-029-23147-00 Engineer.................: St. Amour RIG: . . . . . . . . . . . . . . . . . . . . .: Nabors 9ES STATE:. ............ ......: Alaska ----- Survey calculation methods------------- Method for positions.....: Minimum curvature Method for DLS... ........: Mason & Taylor ----- Depth reference ----------------------- Permanent datum.. ...... ..: Mean Sea Level Depth reference..........: Drill Floor GL above permanent.......: 50.00 ft KB above permanent.......: N/A OF above permanent.......: 77.00 ft ----- Vertical section origin---------------- Latitude (+N/S-).........: 0.00 ft Departure (+E/W-)........: 0.00 ft ----- Platform reference point--------------- Latitude (+N/S-).........: -999.25 ft Departure (+E/W-).. ......: -999.25 ft Azimuth from rotary table to target: 303.63 degrees 26-May-2003 15:42:49 Spud date. . . . . . . . . . . . . . . . : Last survey date.........: Total accepted surveys...: MD of first survey.. .....: MD of last survey........: Page 1 of 5 20-May-2003 26-May-03 102 0.00 ft 9422.00 ft e ----- Geomagnetic data ---------------------- Magnetic model...........: BGGM version 2002 Magnetic date..... .......: 19-May-2003 Magnetic field strength..: 1150.29 HCNT Magnetic dec (+E/W-).. ...: 25.54 degrees Magnetic dip.............: 80.79 degrees ----- MWD survey Reference Reference G.......... ....: Reference H......... .....: Reference Dip.... ..... ...: Tolerance of G...... .....: Tolerance of H...........: Tolerance of Dip....... ..: Criteria --------- 1002.68 mGal 1150.29 HCNT 80.79 degrees (+/-) 2.50 mGal (+/-) 6.00 HCNT (+/-) 0.45 degrees e ----- Corrections --------------------------- Magnetic dec (+E/W-) .....: 25.53 degrees Grid convergence (+E/W-).: 0.00 degrees Total az corr (+E/W-)....: 25.53 degrees (Total az corr = magnetic dec - grid conv) Survey Correction Type ...: I=Sag Corrected Inclination M=Schlumberger Magnetic Correction S=Shell Magnetic Correction F=Failed Axis Correction R=Magnetic Resonance Tool Correction I=MWD Infield Reference Corrected SCHLUMBERGER Survey Report 26-May-2003 15:42:49 Page 2 of 5 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Carr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TIP None 2 100.00 0.02 46.14 100.00 100.00 -0.00 0.01 0.01 0.02 46.14 0.02 GYRO None 3 200.00 0.14 296.46 100.00 200.00 0.11 0.08 -0.08 0.12 313.04 0.15 GYRO None 4 300.00 0.24 226.51 100.00 300.00 0.28 -0.01 -0.35 0.35 268.16 0.23 GYRO None 5 400.00 1. 42 280.82 100.00 399.99 1. 47 0.08 -1.71 1. 72 272.58 1. 29 GYRO None 6 500.00 2.74 289.17 100.00 499.92 4.93 1. 09 -5.19 5.30 281. 91 1. 35 GYRO None e 7 600.00 4.91 293.10 100.00 599.69 11.45 3.56 -11.38 11. 93 287.36 2.18 GYRO None 8 700.00 6.65 293.00 100.00 699.18 21.35 7.50 -20.65 21. 97 289.96 1. 74 GYRO None 9 800.00 9.26 294.22 100.00 798.21 34.98 13.06 -33.32 35.79 291.41 2.62 GYRO None 10 900.00 12.49 294.42 100.00 896.40 53.60 20.84 -50.51 54.64 292.42 3.23 GYRO None 11 1000.00 16.57 294.11 100.00 993.18 78.34 31.14 -73.38 79.71 292.99 4.08 GYRO None 12 1100.00 21.43 294.43 100.00 1087.70 110.46 44.53 -103.05 112.25 293.37 4.86 GYRO None 13 1221. 05 27.56 293.91 121.05 1197.81 159.94 65.04 -148.82 162.42 293.61 5.07 MWD I None - 14 1314.94 30.71 292 .15 93.89 1279.81 204.85 82.89 -190.90 208.12 293.47 3.48 MWD I None - 15 1408.14 33.38 289.48 93.20 1358.80 253.05 100.42 -237.12 257.51 292.95 3.24 MWD I None 16 1497.53 38.60 285.61 89.39 1431.12 303.45 116.13 -287.20 309.79 292.02 6.37 MWD I None - 17 1593.85 40.14 286.40 96.32 1505.58 361. 68 132.98 -345.93 370.61 291.03 1. 68 MWD I None - 18 1686.62 43.57 285.32 92.77 1574.67 420.61 149.88 -405.46 432.28 290.29 3.78 MWD I None - 19 1780.69 44.75 285.59 94.07 1642.15 482.87 167.34 -468.63 497.61 289.65 1. 27 MWD I None - 20 1875.04 48.56 284.72 94.35 1706.90 547.93 185.26 -534.85 566.03 289.11 4.09 MWD I None 21 1967.94 50.34 287.46 92.90 1767.30 615.23 204.84 -602.65 636.51 288.77 2.95 MWD I None e - 22 2062.10 52.25 287.95 94.16 1826.18 685.89 227.19 -672.65 709.98 288.66 2.07 MWD I None - 23 2155.67 54.14 287.54 93.57 1882.23 757.95 250.02 -744.00 784.88 288.58 2.05 MWD I None - 24 2248.35 56.95 285.53 92.68 1934.66 830.97 271. 75 -817.25 861.25 288.39 3.52 MWD I None - 25 2342.24 57.45 285.93 93.89 1985.52 906.07 293.14 -893.22 940.09 288.17 0.64 MWD I None - 26 2436.18 56.72 285.46 93.94 2036.57 981.10 314.48 -969.14 1018.88 287.98 0.88 MWD I None - 27 2528.36 56.23 285.51 92.18 2087.48 1054.12 334.99 -1043.19 1095.66 287.80 0.53 MWD I None - 28 2621.45 55.99 286.07 93.09 2139.39 1127.68 356.02 -1117.55 1172.89 287.67 0.56 MWD I None - 29 2713.80 55.49 285.81 92.35 2191.38 1200.40 376.98 -1190.94 1249.18 287.56 0.59 MWD I None - 30 2807.37 55.70 287.25 93.57 2244.25 1274.18 398.95 -1264.95 1326.37 287.50 1. 29 MWD I None SCHLUMBERGER Survey Report 26-May-2003 15:42:49 Page 3 of 5 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 31 2900.78 55.97 287.21 93.41 2296.71 1348.33 421.84 -1338.77 1403.66 287.49 0.29 MWD I None - 32 2994.11 55.77 287.66 93.33 2349.07 1422.52 444.99 -1412.48 1480.91 287.49 0.45 MWD I None 33 3087.39 55.74 287.56 93.28 2401. 56 1496.63 468.32 -1485.97 1558.02 287.49 0.09 MWD I None - 34 3179.76 57.30 290.25 92.37 2452.52 1571.14 493.29 -1558.84 1635.03 287.56 2.96 MWD I None 35 3273.46 56.91 290.75 93.70 2503.41 1647.76 520.84 -1632.53 1713.61 287.69 0.61 MWD I None 36 3368.12 56.79 290.18 94.66 2555.18 1724.93 548.55 -1706.78 1792.77 287.82 0.52 MWD I None e - 37 3406.58 56.74 290.45 38.46 2576.25 1756.23 559.72 -1736.95 1824.91 287.86 0.60 MWD I None - 38 3514.59 56.54 290.50 108.01 2635.65 1844.08 591.28 -1821.47 1915.03 287.98 0.19 MWD I None - 39 3607.32 57.50 290.80 92.73 2686.13 1919.88 618.71 -1894.26 1992.74 288.09 1. 07 MWD I None - 40 3701. 54 54.58 293.18 94.22 2738.76 1996.39 647.94 -1966.71 2070.70 288.23 3.74 MWD I None 41 3794.52 54.65 293.44 92.98 2792.60 2070.97 677.94 -2036.33 2146.21 288.41 0.24 MWD I None 42 3887.08 55.23 294.31 92.56 2845.77 2145.64 708.60 -2105.61 2221.65 288.60 0.99 MWD I None - 43 3979.69 56.02 291. 96 92.61 2898.06 2220.79 738.62 -2175.89 2297.84 288.75 2.26 MWD I None - 44 4073.27 56.27 293.57 93.58 2950.20 2297.10 768.70 -2247.55 2375.37 288.88 1. 45 MWD I None - 45 4165.70 56.80 293.17 92.43 3001.17 2372.98 799.28 -2318.33 2452.24 289.02 0.68 MWD I None 46 4258.91 57.25 293.26 93.21 3051. 90 2449.88 830.10 -2390.19 2530.24 289.15 0.49 MWD I None 47 4351.71 57.60 293.69 92.80 3101. 86 2526.86 861. 26 -2461.92 2608.22 289.28 0.54 MWD I None - 48 4445.61 55.68 293.12 93.90 3153.50 2604.04 892.41 -2533.89 2686.45 289.40 2.11 MWD I None - 49 4539.17 55.46 293.86 93.56 3206.39 2680.00 923.17 -2604.67 2763.43 289.52 0.69 MWD I None - 50 4632.76 55.14 292.46 93.59 3259.67 2755.66 953.43 -2675.41 2840.22 289.61 1. 28 MWD I None 51 4726.31 54.94 291.95 93.55 3313.28 2830.81 982.41 -2746.39 2916.81 289.68 0.50 MWD I None e - 52 4820.85 55.67 291.76 94.54 3367.09 2906.91 1011.34 -2818.53 2994.48 289.74 0.79 MWD I None - 53 4913.35 56.24 292.17 92.50 3418.88 2981. 97 1040.01 -2889.61 3071.07 289.79 0.72 MWD I None 54 5007.19 55.54 292.78 93.84 3471.50 3058.20 1069.71 -2961. 41 3148.68 289.86 0.92 MWD I None - 55 5100.47 55.53 292.70 93.28 3524.29 3133.72 1099.44 -3032.34 3225.50 289.93 0.07 MWD I None 56 5193.72 55 . 5"2 294.66 93.25 3577.08 3209.43 113 0 . 3'1 -3102.73 3302.20 290.02 1. 73 MWD I None - 57 5286.55 54.51 298.26 92.83 3630.31 3284.87 1164.18 -3170.81 3377 . 77 290.16 3.36 MWD I None - 58 5381. 07 53.18 301. 68 94.52 3686.09 3361.01 1202.27 -3236.91 3452.98 290.38 3.24 MWD I None - 59 5474.94 50.60 305.28 93.87 3744.03 3434.84 1242.97 -3298.51 3524.94 290.65 4.08 MWD I None - 60 5567.19 47.88 307.84 92.25 3804.26 3504.61 1284.55 -3354.65 3592.18 290.95 3.62 MWD I None SCHLUMBERGER Survey Report 26-May-2003 15:42:49 Page 4 of 5 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 61 5660.87 47.19 311.73 93.68 3867.52 3573.29 1328.75 -3407.74 3657.63 291.30 3.15 MWD I None - 62 5755.65 47.30 316.51 94.78 3931.88 3641.68 1377.17 -3457.67 3721. 84 291.72 3.70 MWD I None - 63 5849.30 46.37 319.64 93.65 3995.95 3707.82 1427.97 -3503.31 3783.16 292.18 2.63 MWD I None - 64 5942.15 43.61 323.20 92.85 4061.62 3770.31 1479.24 -3544.27 3840.57 292. 65 4.02 MWD I None - 65 6033.74 43.91 325.00 91. 59 4127.78 3829.65 1530.55 -3581.41 3894.75 293.14 1. 40 MWD I None 66 6127.07 42.03 326.28 93.33 4196.07 3888.63 1583.05 -3617.32 3948.55 293.64 2.22 MWD I None e - 67 6221.50 42.64 325.77 94.43 4265.87 3947.43 1635.79 -3652.86 4002.39 294.12 0.74 MWD I None - 68 6315.73 43.25 325.37 94.23 4334.85 4006.98 1688.74 -3689.15 4057.30 294.60 0.71 MWD I None - 69 6407.69 41.94 326.53 91. 96 4402.54 4064.55 1740.30 -3724.01 4110.58 295.05 1. 66 MWD I None - 70 6503.04 42.03 325.95 95.35 4473.42 4123.43 1793.33 -3759.45 4165.27 295.50 0.42 MWD I None 71 6595.70 42.17 325.97 92.66 4542.17 4180.90 1844.80 -3794.23 4218.94 295.93 0.15 MWD I None - 72 6688.40 42.00 325.77 92.70 4610.97 4238.40 1896.23 -3829.09 4272.89 296.35 0.23 MWD I None - 73 6781. 45 41. 99 324.52 93.05 4680.13 4296.32 1947.32 -3864.67 4327.55 296.74 0.90 MWD I None - 74 6873.92 41.87 324.62 92.47 4748.92 4354.03 1997.67 -3900.49 4382.29 297.12 0.15 MWD I None - 75 6966.08 43.44 326.69 92.16 4816.70 4411.90 2049.23 -3935.70 4437.23 297.51 2.28 MWD I None 76 7058.47 43.12 327.00 92.39 4883.96 4470.11 2102.25 -3970.34 4492.56 297.90 0.42 MWD I None - 77 7153.24 43.14 326.27 94.77 4953.12 4529.75 2156.37 -4005.97 4549.47 298.29 0.53 MWD I None - 78 7246.28 44.05 327.37 93.04 5020.51 4588.72 2210.06 -4041. 08 4605.94 298.67 1. 27 MWD I None - 79 7339.98 44.48 327.01 93.70 5087.61 4648.67 2265.03 -4076.51 4663.51 299.06 0.53 MWD I None - 80 7432.22 44.58 326.85 92.24 5153.36 4708.08 2319.24 -4111.81 4720.79 299.42 0.16 MWD I None 81 7525.70 44.42 327.48 93.48 5220.04 4768.15 2374.29 -4147.34 4778.88 299.79 0.50 MWD I None e - 82 7619.00 44.18 326.94 93.30 5286.81 4827.87 2429.07 -4182.63 4836.81 300.15 0.48 MWD I None - 83 7712.92 44.60 329.18 93.92 5353.93 4887.68 2484.82 -4217.38 4894.95 300.51 1. 73 MWD I None - 84 7806.80 44.13 328.97 93.88 5421.05 4946.95 2541. 13 -4251.11 4952.70 300.87 0.52 MWD I None - 85 7899.98 44.33 329.17 93.18 5487.81 5005.65 2596.88 -4284.52 5010.08 301. 22 0.26 MWD I None 86 7993.14 41. 04 329.87 93.16 5556.29 5062.47 2651. 30 -4316.56 5065.77 301.56 3.57 MWD I None 87 - 8085.78 40.31 328.67 92.64 5626.55 5116.90 2703.20 -4347.41 5119.30 301.87 1.15 MWD I None 88 - 8178.57 38.11 328.05 92.79 5698.44 5170.17 2753.14 -4378.17 5171.86 302.16 2.41 MWD I None - 89 8273.13 36.17 327 . 63 94.56 5773.82 5222.23 2801. 47 -4408.55 5223.37 302.43 2.07 MWD I None 90 8367.91 - 34.03 328.56 94.78 5851. 36 5271.84 2847.73 -4437.37 5272.55 302.69 2.33 MWD I None SCHLUMBERGER Survey Report 26-May-2003 15:42:49 Page 5 of 5 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 91 8461.72 27.26 323.79 93.81 5932.03 5315.87 2887.51 -4463.78 5316.30 302.90 7.66 MWD I None - 92 8552.48 23.08 324.13 90.76 6014.15 5352.06 2918.71 -4486.50 5352.34 303.05 4.61 MWD I None - 93 8646.79 19.69 328.89 94.31 6101.96 5383.75 2947.30 -4505.54 5383.91 303.19 4.04 MWD I None - 94 8739.99 17.72 329.87 93.20 6190.24 5410.68 2973.02 -4520.78 5410.75 303.33 2.14 MWD I None - 95 8832.29 14.73 333.73 92.30 6278.85 5433.44 2995.69 -4533.02 5433.46 303.46 3.44 MWD I None - 96 8926.38 10.72 337.80 94.09 6370.62 5451.03 3014.53 -4541. 63 5451. 04 303.57 4.36 MWD I None e - 97 9019.08 7.24 341.03 92.70 6462.17 5462.81 3028.04 -4546.79 5462.81 303.66 3.79 MWD I None - 98 9113.37 7.16 343.27 94.29 6555.71 5472.06 3039.29 -4550.41 5472.07 303.74 0.31 MWD I None - 99 9205.70 7.16 344.34 92.33 6647.32 5480.85 3050.34 -4553.62 5480.88 303.82 0.14 MWD I None 100 9299.91 7.00 345.41 94.21 6740.81 5489.58 3061.55 -4556.65 5489.64 303.90 0.22 MWD I None 101 9368.60 6.78 346.47 68.69 6809.01 5495.67 3069.54 -4558.65 5495.76 303.95 0.37 MWD I None - Projected to TD: 102 9422.00 6.78 346.47 53.40 6862.04 5500.30 3075.67 -4560.13 5500.41 304.00 0.00 Proj. None [(c)2003 IDEAL ID8_0C_07] e bp L-122 Schlumberuer Survey Report - Geodetic Report Date: 26-May-03 Survey I DLS Computation Method: Minimum Curvature I Lubinski Client: BP Exploration Alaska Vertical Section Azimuth: 303.630° Field: Prudhoe Bay Unit - WOA (Drill Pads) Vertical Section Origin: N 0.000 ft, E 0.000 f1 Structure I Slot: L-Pad 1 L-122 TVD Reference Datum: KB Well: L-122 TVD Reference Elevation: 77.000 ft relative to MSL Borehole: L-122 Sea Bed I Ground Level Elevation: 44.100 ft relative to MSL UWI/API#: 500292314700 Magnetic Declination: +25.527° Survey Name I Date: L-122 1 May 26,2003 Total Field Strength: 57514.425 nT e Tort I AHD I DDII ERD ratio: 169.809° 15771.82 ft 16.1291 0.841 Magnetic Dip: 80.787° Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feel Declination Date: June 02, 2003 Location Lat/Long: N 70.35056758, W 149.32544302 Magnetic Declination Model: BGGM 2002 Location Grid NlE YIX: N 5978256.080 ftUS, E 583083.680 ftUS North Reference: True North Grid Convergence Angle: +0.63527929° Total Corr Mag North .> True North: +25.527° Grid Scale Factor: 0.99990784 Local Coordinates Referenced To: Well Head Grid Coordinates Geographic Coordinates Station ID MD Incl Azim TVD VSec NI-S I E/·W DLS Northing I Easting Latitude I Longitude (It) (') (0) (It) (It) (It) (It) ('/1001t) (ltUS) (ltUS) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 597B256.08 583083.68 N 70.35056758 W 149.32544303 100.00 0.02 46.14 100.00 0.00 0.01 0.01 0.02 5978256.09 583083.69 N 70.35056761 W 149.32544293 200.00 0.14 296.46 200.00 0.11 0.08 -0.08 0.15 5978256.16 583083.59 N 70.35056779 W 149.32544371 300.00 0.24 226.51 300.00 0.28 -0.01 -0.35 0.23 5978256.07 583083.33 N 70.35056755 W 149.32544583 400.00 1.42 280.82 399.99 1.47 0.08 -1.71 1.29 5978256.14 583081.96 N 70.35056779 W 149.32545695 500.00 2.74 289.17 499.92 4.93 1.09 -5.19 1.35 5978257.12 583078.48 N 70.35057057 W 149.32548516 600.00 4.91 293.1 0 599.69 11 .45 3.56 -11.38 2.18 5978259.51 583072.26 N 70.35057730 W 149.32553545 700.00 6.65 293.00 699.18 21.35 7.50 -20.65 1.74 5978263.35 583062.95 N 70.35058807 W 149.32561068 e 800.00 9.26 294.22 798.21 34.98 13.06 -33.32 2.62 5978268.77 583050.22 N 70.35060327 W 149.32571353 900.00 12.49 294.42 896.40 53.60 20.84 -50.51 3.23 5978276.35 583032.95 N 70.35062450 W 149.32585306 1000.00 16.57 294.11 993.18 78.34 31.14 -73.38 4.08 5978286.40 583009.97 N 70.35065264 W 149.32603873 1100.00 21.43 294.43 1087.70 110.46 44,53 -103.05 4.86 5978299.46 582980.16 N 70.35068922 W 149.32627956 1221.05 27.56 293.91 1197.81 159.94 65.04 -148.82 5.07 5978319.46 582934.16 N 70.35074526 W 149.32665120 1314.94 30.71 292.15 1279.81 204.85 82.89 -190.90 3.48 5978336.84 582891.89 N 70.35079401 W 149.32699275 1408.14 33.38 289.48 1358.81 253.05 100.42 -237.12 3.24 5978353.85 582845.48 N 70.35084189 W 149.32736801 1497.53 38.60 285.61 1431.12 303.45 116.13 -287.20 6.37 5978369.01 582795.24 N 70.35088482 W 149.32777457 1593.85 40.14 286.40 1505.58 361.68 132.98 -345.93 1.68 5978385.21 582736.33 N 70.35093085 W 149.32825132 1686.62 43.57 285.32 1574.67 420.61 149.88 -405.46 3.78 5978401.44 582676.62 N 70.35097700 W 149.32873467 Schlumberger Private Page 1 of 4 6/12/2003-3:55 PM L-122 ASP Final Survey.xls Grid Coordinates Geographic Coordinates Station ID MD Incl Azim TVD VSec NI·S E/·W DLS Northing I Easting Latitude I Longitude (ft) (') (') (ft) (ft) (ft) (ft) ('/100ft) (ftUS) (ftUS) 1780.69 44.75 285.59 1642.15 482.87 167.34 -468.63 1.27 5978418.20 582613.27 N 70.35102470 W 149.32924746 1875.04 48.56 284.72 1706.90 547.93 185.26 -534.85 4.09 5978435.38 582546.86 N 70.35107364 W 149.32978505 1967.94 50.34 287.46 1767.30 615.23 204.84 -602.65 2.95 5978454.21 582478.85 N 70.35112712 W 149.33033550 2062.10 52.25 287.95 1826.18 685.89 227.19 -672.65 2.07 5978475.78 582408.62 N 70.35118816 W 149.33090375 2155.67 54.14 287.54 1882.23 757.95 250.02 -744.00 2.05 5978497.82 582337.03 N 70.35125051 W 149.33148303 2248.35 56.95 285.53 1934.66 830.97 271.75 -817.25 3.52 5978518.72 582263.54 N 70.35130984 W 149.33207775 2342.24 57.45 285.93 1985.52 906.07 293.14 -893.22 0.64 5978539.27 582187.35 N 70.35136827 W 149.33269447 2436.18 56.72 285.46 2036.57 981.10 314.48 -969.14 0.88 5978559.76 582111.21 N 70.35142653 W 149.33331083 2528.36 56.23 285.51 2087.48 1054.12 334.99 -1043.19 0.53 5978579.46 582036.94 N 70.35148255 W 149.33391207 e 2621.45 55.99 286.07 2139.39 1127.68 356.02 -1117.55 0.56 5978599.66 581962.36 N 70.35153996 W 149.33451577 2713.80 55.49 285.81 2191.38 1200.40 376.98 -1190.94 0.59 5978619.80 581888.74 N 70.35159720 W 149.33511162 2807.37 55.70 287.25 2244.25 1274.18 398.95 -1264.95 1.29 5978640.94 581814.51 N 70.35165717 W 149.33571247 2900.78 55.97 287.21 2296.71 1348.33 421.84 -1338.77 0.29 5978663.01 581740.44 N 70.35171968 W 149.33631181 2994.11 55.77 287.66 2349.07 1422.52 444.99 -1412.48 0.45 5978685.34 581666.49 N 70.35178288 W 149.33691023 3087.39 55.74 287.56 2401.56 1496.63 468.32 -1485.97 0.09 5978707.85 581592.75 N 70.35184657 W 149.33750694 3179.76 57.30 290.25 2452.52 1571.14 493.29 -1558.84 2.96 5978732.01 581519.61 N 70.35191476 W 149.33809858 3273.46 56.91 290.75 2503.41 1647.76 520.84 -1632.53 0.61 5978758.74 581445.63 N 70.35198998 W 149.33869692 3368.12 56.79 290.18 2555.18 1724.93 548.55 -1706.78 0.52 5978785.62 581371.08 N 70.35206564 W 149.33929978 3406.58 56.74 290.45 2576.26 1756.23 559.72 ·1736.95 0.60 5978796.46 581340.79 N 70.35209613 W 149.33954473 3514.59 56.54 290.50 2635.65 1844.08 591.28 -1821.47 0.19 5978827.07 581255.94 N 70.35218229 W 149.34023093 3607.32 57.50 290.80 2686.13 1919.88 618.71 -1894.26 1.07 5978853.69 581182.86 N 70.35225718 W 149.34082193 3701.54 54.58 293.18 2738.76 1996.39 647.94 -1966.71 3.74 5978882.12 581110.09 N 70.35233698 W 149.34141025 3794.52 54.65 293.44 2792.60 2070.97 677.94 -2036.33 0.24 5978911.34 581040.15 N 70.35241888 W 149.34197552 3887.08 55.23 294.31 2845.77 2145.64 708.60 -2105.61 0.99 5978941.23 580970.54 N 70.35250261 W 149.34253806 e 3979.69 56.02 291.96 2898.06 2220.79 738.62 -2175.89 2.26 5978970.47 580899.94 N 70.35258457 W 149.34310875 4073.27 56.27 293.57 2950.20 2297.10 768.70 -2247.55 1.45 5978999.74 580827.96 N 70.35266666 W 149.34369058 4165.70 56.80 293.17 3001 .17 2372.98 799.28 -2318.33 0.68 5979029.53 580756.85 N 70.35275016 W 149.34426532 4258.91 57.25 293.26 3051.90 2449.88 830.10 -2390.19 0.49 5979059.56 580684.66 N 70.35283430 W 149.34484885 4351.71 57.60 293.69 3101.86 2526.86 861.26 -2461.92 0.54 5979089.91 580612.59 N 70.35291934 W 149.34543129 4445.61 55.68 293.12 3153.50 2604.04 892.41 -2533.89 2.11 5979120.26 580540.29 N 70.35300439 W 149.34601570 4539.17 55.46 293.86 3206.39 2680.00 923.17 -2604.67 0.69 5979150.23 580469.19 N 70.35308835 W 149.34659040 4632.76 55.14 292.46 3259.68 2755.66 953.43 -2675.41 1.28 5979179.70 580398.12 N 70.35317096 W 149.34716483 4726.31 54.94 291.95 3313.28 2830.81 982.41 -2746.39 0.50 5979207.89 580326.83 N 70.35325005 W 149.34774123 4820.85 55.67 291.76 3367.09 2906.91 1011.34 -2818.53 0.79 5979236.02 580254.37 N 70.35332902 W 149.34832705 4913.35 56.24 292.17 3418.88 2981.97 1040.01 -2889.61 0.72 5979263.89 580182,99 N 70.35340727 W 149.34890426 Schlumberger Private L-122 ASP Final Survey.xls Page 2 of 4 6/12/2003-3:55 PM Grid Coordinates Geographic Coordinates Station ID MD Incl Azim TVD VSec N/·S E/·W DLS Northing I Easting Latitude I Longitude (ft) (') (') (ft) (ft) (ft) (ft) ('/100ft) (ftUS) (ftUS) 5007.19 55.54 292.78 3471.50 3058.20 1069.71 -2961.41 0.92 5979292.79 580110.87 N 70.35348833 W 149.34948726 5100.47 55.53 292.70 3524.29 3133.72 1099.44 -3032.34 0.07 5979321.73 580039.63 N 70.35356947 W 149.35006325 5193.72 55.52 294.66 3577.08 3209.43 1130.31 -3102.73 1.73 5979351.82 579968.90 N 70.35365373 W 149.35063490 5286.55 54.51 298.26 3630.31 3284.87 1164.18 -3170.81 3.36 5979384.92 579900.46 N 70.35374617 W 149.35118774 5381.07 53.18 301 .68 3686.09 3361.01 1202.27 -3236.91 3.24 5979422.28 579833.94 N 70.35385017 W 149.35172460 5474.94 50.60 305.28 3744.03 3434.84 1242.97 -3298.51 4.08 5979462.29 579771.90 N 70.35396127 W 149.35222493 5567.19 47.88 307.84 3804.26 3504.60 1284.55 -3354.65 3.62 5979503.24 579715.32 N 70.35407481 W 149.35268083 5660.87 47.19 311.73 3867.52 3573.29 1328.75 -3407.74 3.15 5979546.84 579661.74 N 70.35419548 W 149.35311208 5755.65 47.30 316.51 3931.88 3641.68 1377.17 -3457.67 3.70 5979594.71 579611.28 N 70.35432771 W 149.35351767 e 5849.30 46.37 319.64 3995.95 3707.82 1427.97 -3503.31 2.63 5979644.99 579565.09 N 70.35446643 W 149.35388843 5942.15 43.61 323.20 4061.62 3770.31 1479.24 -3544.27 4.02 5979695.79 579523.57 N 70.35460643 W 149.35422118 6033.74 43.91 325.00 4127.78 3829.65 1530.55 -3581.41 1.40 5979746.68 579485.86 N 70.35474656 W 149.35452294 6127.07 42.03 326.28 4196.07 3888.63 1583.05 -3617.32 2.22 5979798.78 579449.38 N 70.35488994 W 149.35481473 6221.50 42.64 325.77 4265.87 3947.43 1635.79 -3652.86 0.74 5979851.12 579413.26 N 70.35503397 W 149.35510352 6315.73 43.25 325.37 4334.85 4006.98 1688.74 -3689.15 0.71 5979903.66 579376.38 N 70.35517858 W 149.35539846 6407.69 41.94 326.53 4402.54 4064.55 1740.30 -3724.01 1.66 5979954.82 579340.96 N 70.35531939 W 149.35568168 6503.04 42.03 325.95 4473.42 4123.43 1793.33 -3759.45 0.42 5980007.45 579304.93 N 70.35546420 W 149.35596971 6595.70 42.17 325.97 4542.17 4180.90 1844.80 -3794.23 0.15 5980058.53 579269.59 N 70.35560479 W 149.35625228 6688.40 42.00 325.77 4610.97 4238.40 1896.23 -3829.09 0.23 5980109.57 579234.17 N 70.35574524 W 149.35653555 6781 .45 41.99 324.52 4680.12 4296.32 1947.32 -3864.66 0.90 5980160.25 579198.03 N 70.35588475 W 149.35682467 6873.92 41.87 324.62 4748.92 4354.03 1997.67 -3900.49 0.15 5980210.19 579161.65 N 70.35602225 W 149.35711575 6966.08 43.44 326.69 4816.70 4411.90 2049.23 -3935.70 2.28 5980261.36 579125.88 N 70.35616306 W 149.35740189 7058.47 43.12 327.00 4883.96 4470.11 2102.26 -3970.34 0.42 5980313.99 579090.65 N 70.35630787 W 149.35768341 7153.24 43.14 326.27 4953.12 4529.75 2156.37 -4005.97 0.53 5980367.70 579054.43 N 70.35645565 W 149.35797299 e 7246.28 44.05 327.37 5020.51 4588.72 2210.06 -4041.07 1.27 5980421.00 579018.73 N 70.35660229 W 149.35825829 7339.98 44.48 327.01 5087.61 4648.67 2265.03 -4076.51 0.53 5980475.56 578982.69 N 70.35675240 W 149.35854631 7432.22 44.58 326.85 5153.36 4708.08 2319.24 -4111.81 0.16 5980529.37 578946.80 N 70.35690044 W 149.35883318 7525.70 44.42 327.48 5220.04 4768.15 2374.29 -4147.34 0.50 5980584.02 578910.67 N 70.35705078 W 149.35912193 7619.00 44.18 326.94 5286.81 4827.87 2429.07 -4182.63 0.48 5980638.40 578874.78 N 70.35720038 W 149.35940874 7712.92 44.60 329.18 5353.93 4887.68 2484.82 -4217.37 1.73 5980693.75 578839.41 N 70.35735263 W 149.35969118 7806.80 44.13 328.97 5421.05 4946.95 2541 .13 -4251.11 0.52 5980749.68 578805.06 N 70.35750641 W 149.35996539 7899.98 44.33 329.17 5487.81 5005.65 2596.88 -4284.52 0.26 5980805.06 578771.04 N 70.35765868 W 149.36023694 7993.14 41.04 329.87 5556.29 5062.47 2651.30 -4316.56 3.57 5980859.11 578738.40 N 70.35780729 W 149.36049741 8085.78 40.31 328.67 5626.55 5116.89 2703.20 -4347.41 1.15 5980910.66 578706.98 N 70.35794903 W 149.36074816 8178.57 38.11 328.05 5698.44 5170.17 2753.14 -4378.17 2.41 5980960.25 578675.67 N 70.35808541 W 149.36099822 Schlumberger Private L-122 ASP Final Survey.xls Page 3 of 4 6/12/2003-3:55 PM Grid Coordinates Geographic Coordinates Station ID MD Inel Azim TVD VSee N/·S EI-W DLS Northing I Easting Latitude I Longitude (ft) (') (') (ft) (It) (ft) (ft) ('/1000) (ftUS) (ftUS) 8273.13 36.17 327.63 5773.82 5222.23 2801.47 -4408.55 2.07 5981008.24 578644.75 N 70.35821740 W 149.36124520 8367.91 34.03 328.56 5851.36 5271 .84 2847.73 -4437.36 2.33 5981054.17 578615.44 N 70.35834372 W 149.36147940 8461.72 27.26 323.79 5932.03 5315.87 2887.51 -4463.78 7.66 5981093.65 578588.58 N 70.35845236 W 149.36169414 8552.48 23.08 324.13 6014.15 5352.06 2918.71 -4486.50 4.61 5981124.60 578565.52 N 70.35853756 W 149.36187874 8646.79 19.69 328.89 6101.96 5383.75 2947.30 -4505.54 4.04 5981152.98 578546.16 N 70.35861564 W 149.36203357 8739.99 17.72 329.87 6190.24 5410.68 2973.02 -4520.78 2.14 5981178.51 578530.65 N 70.35868586 W 149.36215741 8832.29 14.73 333.73 6278.85 5433.44 2995.69 -4533.02 3.44 5981201.05 578518.15 N 70.35874779 W 149.36225699 8926.38 10.72 337.80 6370.62 5451.03 3014.53 -4541.63 4.36 5981219.79 578509.34 N 70.35879924 W 149.36232696 9019.08 7.24 341.03 6462.17 5462.81 3028.04 -4546.79 3.79 5981233.24 578504.03 N 70.35883614 W 149.36236892 e 9113.37 7.16 343.27 6555.71 5472.05 3039.29 -4550.41 0.31 5981244.45 578500.28 N 70.35886686 W 149.36239840 9205.70 7,16 344.34 6647.32 5480.85 3050.34 -4553.62 0.14 5981255.46 578496.95 N 70.35889704 W 149.36242452 9299.91 7.00 345.41 6740.82 5489.58 3061.55 -4556.65 0.22 5981266.63 578493.80 N 70.35892766 W 149.36244919 9368.60 6.78 346.47 6809.01 5495.67 3069.54 -4558.65 0.37 5981274.60 578491.71 N 70.35894949 W 149.36246549 9422.00 6.78 346.47 6862.04 5500.30 3075.67 -4560.13 0.00 5981280.71 578490.16 N 70.35896623 W 149.36247750 e L-122 ASP Final Survey.xls Schlumberger Private Page 4 of 4 6/12/2003-3:55 PM Customer Well No Installation/Rig Data Surveys Received By: . . MWD/LWD Log Product Delivery BP Exploration (Alaska) Inc. L-122 Nabors 9ES 4,-,~ ¿' oL(j,3-D.:.:J ! RECEIVED JUN 1 6 2003 Ataaka OK & Gas Cons. ~ Anchorage ~ù Y'? ßv,1-- LWD Log Delivery V1.1 , Dec '97 Dispatched To: Lisa Weepie Date Dispatche 18-May-03 Dispatched By: Nate Rose No Of Prints No of Floppies 2 Please sign and return to: Anadrill LWD Division 3940 Arctic Blvd, Suite 300 Anchorage, Alaska 99503 nrose1 @slb.com Fax: 907-561-8417 Customer Well No Installation/Rig Data Surveys Received By: . . MWDILWD Log Product Delivery BP Exploration (Alaska) Inc. L-122 Nabors 9ES &-£!ò ~DS J RECEIVED JUN 1 6 2003 Alaska Oil & Gas Cons. Commieeior Andlorage £~Q YJ. bjLr- LWD Log Delivery V1.1, Dec '97 Dispatched To: Lisa Weepie Date Dispatche 18-May-03 Dispatched By: Nate Rose No Of Prints No of Floppies 2 Please sign and return to: James H. Johnson BP Exploration (Alaska) Inc. Petrotechnical Data Center (LR2-1) 900 E. Benson Blvd. Anchorage, Alaska 99508 Fax: 907-564-4005 e-mail address:johnsojh@bp.com ·. ~~~~E (ill} ~~~~~~.~ ¡tI,Jt.SIi& OIL AlQ) GAS CONSERVATION COMMISSION Bill Isaacson Senior Drilling Engineer BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, Alaska 99519-6612 . FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Prudhoe Bay Unit L-122 BP Exploration (Alaska) Inc. Pennit No: 203-051 Surface Location: 2536' NSL, 3831' WEL, SEC. 34, T12N, RIlE, UM Bottomhole Location: 333' NSL, 2940' WEL, SEC. 28, T12N, RIlE, UM Dear Mr. Isaacson: Enclosed is the approved application for pennit to drill the above referenced development well. This pennit to drill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit 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 tenns and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, k":J ~ Randy Ruedrich Commissioner BY ORDER ~~JHE COMMISSION DATED this day of~, 2003 ..-q A:p-r \ L cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. 1a. Type of work II Drill 0 Redrill ORe-Entry 0 Deepen 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface x;: 583084. Y;: 5978256 2536' NSL, 3831' WEL, SEC. 34, T12N, R11 E, UM At top of productive interval x;: 578680. Y;: 5981210 258' NSL, 2916' WEL, SEC. 28, T12N, R11E, UM At total depth x;: 578655. Y;: 5981285 333' NSL, 2940' WEL, SEC. 28, T12N, R11E, UM 12. Distance to nearest property line \13. Distance to nearest well / ADL 047449, 2339' MD No Close Approach 16. To be completed for deviated wells Kick Off Depth 300' MD Maximum Hole Angle 18. caSing~;~gram Specifications Hole Casina Weiç:¡ht Grade CouDlinQ 42" 34" x 20" 91.5# H-40 Weld 9-7/8" 7-5/8" 29.7# S-95 BTC 6-3/4" 5-1/2" 15.5# L-80 BTC-M 6-3/4" 3-1/2" 9.2# L-80 IBT-M .. STATE OF ALASKA I ALASKML AND GAS CONSERVATION COM ··SION PERMIT TO DRILL 20 AAC 25.005 11 b. Type of well 0 Exploratory 0 Stratigraphic Test II Development Oil o Service 0 Development Gas 0 Single Zone 0 Multiple Zone 5. Datum Elevation (DF or KB) 10. Field and Pool Plan RKB = 76.4' Prudhoe Bay Field / Borealis 6. Property Designation Pool (Undefined) ADL 028239 7. Unit or Property Name _ Prudhoe Bay Unit 8. Well Number . L-122 / 9. Approximate spud date 04112/03 Amount $200,000.00 14. Number of acres in property 15. Proposed depth (MD and rvD) 2560 9439' MD / 6997' rvD 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} 54 0 Maximum surface 2755 "'PSig, At total depth (TVD) 6655' / 3420 psig Setting Depth Top Bottom MD rvD MD rvD Surface Surface 110' 110' Surface Surface 3490' 2677' Surface Surface 8681' 6250' 8681' 6250' 9439' 6997' N(} 1\- ~/l1 {z.cc: ~ 11. Type Bond (See 20 AAC 25.025) Number 2S10030263O-277 Lenath 80' 3490' 8681' 758' Quantity of Cement (include staae data) 260 sx Arctic Set (Approx.) 421 sx Permafrost 'L', 200 sx 'G' 146 sx Class 'G', 208 sx Class 'G' (5-1/2" x 3-1/2" Cement) ,/' /' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Structural Conductor Surface Intermediate Production Liner Length Size Cemented MD rvD RECEIVED Perforation depth: measured MAR 26 2003 20. Attachments .ðJaß801j & Gas CoOS. Commìssion II Filing Fee 0 Property Plat 0 BOP Sketch 0 Diverter Sketch II ~~~!ram II Drilling Fluid Program 0 Time vs Depth Plot 0 Refraction Analysis 0 Seabed Report 1120 AAC 25.050 Requirements Contact Engineer NamelNumber: Neil Magee, 564-5119 Prepared By NamelNumber: Terrie Hubble, 564-4628 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Billlsaacson J. _ 1. A...... Title Senior Drilling Engineer true vertical Date M <.~z. (. ,l. 00 3 Permit Number 203 -O.S/ Conditions of Approval: I API Number 50- O.2/.:t- 23/"/'7 Samples Required 0 Yes 181 No Hydrogen Sulfide Measures 0 Yes ..181 No Required Working Pressure for BOPE 0 2K 0 3K Other: T.e-st-Bo PE k t.fO~rJ pro ¿ . ~ ~OLJ I~Ncxnrissioner 12-01-'; -) I (\ 161 f\L OAPt9VªJ D,t~ ::> I See cover letter (J ~ V...2) for other requirements Mud Log Required 0 Yes .BI No Directional Survey Required '5 Yes 0 No o 4K 05K 010K 015K 0 3.5K psi for CTU Approved By Form 10-401 Rev. by order of the commission Date ¿Jt'/0y03 Submit In Triplicate . . IWell Name: IL-122 Drill and Complete Plan Summary I Type of Well (service 1 producer 1 injector): 1 Producer Surface Location: As-Built Target Location: Top Kuparuk Bottom Hole Location: x = 583,083.68' Y = 5,978,256.08' 2535' FSL, 3831' FEL,Sec. 34, T12N, R11E X = 578,680' Y = 5,981,210' 258' FSL,2916' FEL, Sec. 28,T12N, R11E X = 578,655.05' Y = 5,981,284.94' 333' FSL,2940' FEL, Sec. 28, T12N, R11E I AFE Number: I BRD5M??? I I Estimated Start Date: 14/12/2003 1 I MD: 19439' I TVD: 16997' I / /' / I Rig: I Nabors 9ES / I Operating days to complete: 111.8 I BF/MS: 127.5' 1 I RKB: 176.4' I Well Design (conventional, slim hole, etc.): 1 Microbore (Iongstring) I Objective: 1 Kuparuk Formation Mud Program: 9-7/8" Surface Hole (0-3490'): Initial below Permafrost interval TD Densitv Viscosity (ppg) (seconds) 8.5 - 9.2 250-300 9.0 - 9.5 . 200 9.5 max /' 150-200 Upper Interval Top of HRZ 4-7 10.1 / 3-7 L-122 Drilling Program (AOGCC) Fresh Water Surface Hole Mud Yield Point (lb/1 OOft~) 50 - 70 30 - 45 20 - 35 27 -32 1 0-15 6 3,4" Intermediate 1 Production Hole (3490' - 9439'): Interval Density Tau 0 YP PV (ppg) 9.7 17 -25 1 0-15 Tau 0 API FL PH (mls/30min) >20 15-20 8.5 - 9.5 >15 <8 8.5- 9.5 >15 <8 8.5- 9.5 Fresh Water LSND pH API HTHP Filtrate Filtrate 8.5-9.5 6-10 8.5-9.5 4-6 <10 by HRZ Page 1 . . Hydraulics: Surface Hole: 9 7/8" Interval Pump Drill AV Pump PSI ECD Motor Jet Nozzles TFA GPM Pipe (fpm) ppg-emw ("/32) (in2) 0-1800' 550 4" 17.5# 130 1600 10.2 N/A 18,18,18,16 .942 1812'-3491 ' 600 4" 17.5# 150 2600 10.4 N/A 18,18,18,16 .942 Production Hole: 6 %" Interval Pump Drill Pipe AV Pump PSI ECD Motor Jet Nozzles TFA GPM (fpm) ppg-emw ("/32) (in2) 3491'-9439' 330 4" 17.5# 210 1700 - 2500 11.1 N/A 5X12 .552 Hole Cleaning Criteria: Interval Interval ROP Drill Pump Mud Hole Cleaning Condition Pipe GPM Weight Rotation 110'-3490' Surface Superior hole cleaning practices at to SV-3 connections will greatly enhance cuttings transport particularly in sliding mode 210 60 500 9.5 Acceptable 250 60 600 9.5 Acceptable 300 60 700 9.5 Acceptable 250 90 500 9.5 Acceptable 315 90 600 9.5 Acceptable 300 90 700 9.5 Acceptable 2797' -6650' To Base ROP's greater than 400'/hr must be Schrader accompanied by a GPM of 330 and fully reamed connections to maintain minimum hole cleaning requirements 250 80 330 9.7 Marginal 250 100 330 9.7 Acceptable 300 80 330 9.7 Marginal/Poor 300 100 330 9.7 Marginal/Manageable 400 80 330 9.7 Very Poor 400 100 330 9.7 Poor 6650'-TD Base ROP's greater than 200'/hr must be Schrader accompanied by maximum pump rates toTD and fully reamed connections to maintain minimum hole cleaning requirements 150 80 330 10.1 Acceptable 200 80 330 10.1 Marginal L-122 Drilling Program (AOGCC) Page 2 Di rectional: Ver. Anadrill P3 Slot NG KOP: 300' Maximum Hole Angle: Close Approach Wells: Survey Program: Logging Program: Surface Production Hole Formation Markers: Formation Tops SV6 SV5 SV4 Base Permafrost SV3 SV2 SV1 UG4A UG3 UG1 Ma WS2 (Na sands) WS1 (Oa sands) Obf Base CM2 (Colville) CM1 THRZ BHRZ (Kalubik) K-1 TKUP Kuparuk C LCU Kuparuk B Kuparuk A TMLV (Miluveach) TD Criteria L-122 Drilling Program (AOGCC) . . 54 degree~ at 2160' MD All Wells Pass Major Risk Criteria /' L-02 - 19' Ctr-Ctr at 600' MD NWE1-02 19' Ctr-Ctr at 850' MD L-115 - 31' Ctr-Ctr at 300' MD Standard MWD surveys (IFR+MSA Correction) Drilling: MWD I GR Open Hole: Cased Hole: None Drilling: MWD I GR IRES I NEU I DEN I PWD Open Hole: Cased Hole: TVDss 895' 1545' 1680' 1690' 1975' 2130' 2430' 2760' 3079' 3475' 3875' 4095' 4225' 4600' 4833' 5545' 6010' 6170' 6230' 6330' 6355' 6505' 6655' 6725' Estimated Pore Pressure Not Hydrocarbon Bearing, 8.5 ppg Not Hydrocarbon Bearing, 8.5 ppg Not Hydrocarbon Bearing, 8.5 ppq Hydrocarbon Bearing, 9.1 ppg Possibly Hydrocarbon Bearing, 9.8 ppg \ o· \ 150' below Miluveach top Page 3 . . CasinglTubing Program: Hole Csgl WtlFt Grade co~ Length Top Btm Size Tbg O.D. / MDfTVD MDfTVD bkb 42" Insulated 91.5# H-40 WLD 80' GL 110/110 34"x20" 9-7/8" 7 5/8" 29.7# S-95 £~ 3490' GL 3490'/2677' 6-3/4" 5-1/2" 15.5# L-80 8681' GL 8681 '/6250' 6-3/4" 3-1/2" 9.2# L-80 758' 8681 '/6250' 9439'/6997' Tubing 3-1/2" 9.2# L-80 -Mod 8681' GL 8681 '/6250' Note: Composite S-95 with top two joints L-80 Integrity Testing: Test Point Depth Surface Casing Shoe 20' min from su rface shoe Test Type LOT EMW 13.2 ppg (minimum for a 25bbl kick tolerance) Cement Calculations: The following surface cement calculations are based upon a single stage job The production cement calculation assumes cement will be required to cover 500' above the top of the Schrader Ma sands with 1000 psi ultimate compressive strength and covering the entire Kuparuk interval with 2000 psi/24 hours compressive strength cement. Casing Size 17-5/8" Surface I Basis: Lead: Based on 1812' of annulus in the permafrost @ 250% excess and 210' of open hole from top of tail slurry to base permafrost @ 30% excess. Lead TOC: To surface Tail: Based on 750' MD open hole volume + 30% excess + 80' shoe track volume. Tail TOG: At -2022' MD I Total Cement Volume: Lead 312 bbl I 1750fe I 2 ks of Halliburton Permafrost L at 10.7 ppg and 4.1 sk. 41 bbl / 230 fe 0 sks of Halliburton Premium 'G' at 15.8 ppg and 1. cf/sk. Tail Casing Size 5-1/2"X3-1/2" Production I Longstring Basis: Lead: Based on TOC 500' MD above the top of the Schrader Bluff Ma formation + 30% excess and base of cement 500' MD above top of Kuparuk formation. 517 If' Tail: Based on TOC 500' MD above top of Kuparuk formation + 30% excess + 90' shoe track volume. ~ I Total Cement Volume: Lead 61 bbl I 342ft;:! / ~ ks of Halliburton Premium 'G' + 15 Ibs/sk Microlite~ ppg and 2.36 cf/sk. Tail 43 bbl / 241 fe 0 sks of Halliburton Premium 'G' (.3Ibs/sk Supe L) at 15.8 ppg and 1.16 cf/sk. L-122 Drilling Program (AOGCC) Page 4 . . Well Control: Surface hole will be drilled with diverter. The intermediate and production hole, well control equipment consisting of 5000 psi working pressure pipe rams(2), blind/shear rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Based upon the planned casing test for future frac job considerations, the BOP equipment will be tested to 4000 psi ../' Diverter, BOPE and drilling fluid system schematics on file with the AOGCC. Production Interval- · Maximum anticipated BHP: . Maximum surface pressure: 9.8 ppg EMW, 3420 psi @ 6655'TVDss +77' RKB 2755 psi @ surface ,/ (based on 3420 psi at KUPA and a full column of gas @ 0.10 psi/ft) · Planned BOP test pressure: . Planned completion fluid: 4000 psi (for future frac stimulation treatments) ~ 8.6 ppg filtered seawater / 6.8 ppg Diesel Disposal: · No annular injection in this well. · Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at DS-04. · Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to DS- 04 for disposal. Haul all Class I wastes to Pad 3 for disposal. H2S: · H2S has not been recorded on L-Pad wells. As a precaution Standard Operating Procedures for H2S should be followed at all times. L-122 Drilling Program (AOGCC) Page 5 . . DRILL AND COMPLETE PROCEDURE SUMMARY Pre-Rig Work: The 20" insulated conductor was installed September 2002. 1. Weld a FMC landing on the conductor. 2. If necessary, level the pad and prepare location for rig move. 3. L -115 well house may have to be removed for the rig move. Rig Operations: 1. MIRU Nabors 9ES on Slot NG. / 2. Nipple up diverter spool and riser. PU 4" DP as required and stand back in derrick. Test diverter line. 3. MU 9 7/8" drilling assembly with MWD/LWD (see page 3) and directionally drill surface hole to approximately 100' TVD below anticipated SV1 sands (see Anadrill directional plan). An intermediate bit trip to surface will be performed prior to exiting the Permafrost. 4. Run and cement the 7-5/8", 29.7# L-80/S-95 surface casing back to surface. (The top two joints will be L-80 with the remainder S-95.) A Tam port collar will be run as a contingency if surface drilling is problematic. 5. ND diverter spool and NU casing I tubing head. NU BOPE and test to 4000 psi. /" 6. MU 6-3/4" drilling assembly with drill mill and MWD/LWD (see page 4) and RIH to float collar. Test the 7-5/8" casing to 3500 psi for 30 minutes. / 7. Drill out shoe joints and displace well to 9.7 ppg LSND drilling fluid. Drill new formation to 20' below 7- 5/8" shoe and perform Leak Off Test. /' 8. Drill to ±200' above the HRZ, ensure mud is in good condition at 10.1 ppg. Hold the 'Pre-Reservoir' meeting highlighting kick tolerance and detection. Drill ahead to -130' of rat hole into the Miluveach formation. 9. Condition hole for running longstring and POOH. 10. Run and cement the tapered production casing as required from TD to 500' above the Schrader Ma ".-. sands. Displace the casing with filtered seawater during cementing operations and freeze protect the 5 W' x 7-5/8" annulus as required. 11. Run the 3-1/2",9.2#, L-80 gas lift completion assembly. Circulate around corrosion inhibitor. Sting seal /. assembly into tieback receptacle and test to 4000 psi for 30 minutes both the tubing and annulus. Release tubing pressure and shear RP valve. 12. Install TWC and test from below to 1000 psi. Nipple down the BOPE. Nipple up and test the tree to 5000 psi. Remove TWC. 13. RU hot oil truck and freeze protect the well by reverse circulating in a sufficient volume of diesel to reach the lower GLM. / 14. Rig down and move off. / L-122 Drilling Program (AOGCC) Page 6 . . L-122 Drilling Program Summary Job 1: MIRU Hazards and Contingencies / ~ L-Pad is not designated as an H2S site. As a precaution however Standard Operating Procedures for H2S precautions should be followed at all times. þ.- The closest surface locations will be L-115 and L-02. Both will be -30' wellhead to wellhead. If the well house is removed from L-02 for the move-in, the well will require a surface shut-in. þ.- Check landing ring height on L-122, the BOP nipple up may need review. Reference RPs .:. "Drilling! Work over Close Proximity Surface and Subsurface Wells Procedure" Job 2: DrillinCl Surface Hole Hazards and Contingencies ~ No faults are expected to be penetrated by L-122 in the surface interval. , Drilling Close Approach: The nearest wells are NWE1-02, L-02 and L-115. L-02 and NWE1-02 /' have 19' center to center distances of 600' and 850' respectively. L-115 has a 31' center to center distance until 300'. ~ A limited amount of gas hydrates have been observed on the surface holes drilled on L-Pad from ~ the base of permafrost to TD in the SV1 sand. Hydrates will be treated at surface with appropriate mud products and adjustment of drilling parameters. Refer to MI mud recommendation þ.- Associated with the hydrates, is the danger of deeper gravel beds below the Permafrost that will tend to slough in when aerated gas cut hydrate mud is being circulated out. Maintain adequate viscosity. Reference RPs .:. "Prudhoe Bay Directional Guidelines" .:. "Well Control Operations Station Bill" L-122 Drilling Program (AOGCC) Page 7 . . Job 3: Install Surface Casinq Hazards and Contingencies ~ It is critical that cement is circulated to surface for well integrity. Plan 250% excess cement / through the permafrost zone and 30% excess below the permafrost. A 7-5/8" port collar will be utilized if operational problems are encountered while drilling the surface hole. If use it should be positioned at ±1 OOO'MD to allow a secondary circulation should cement to surface not be achieved. ~ "Annular Pumping Away" criteria for future permitting approval for annular injection. 1. Pipe reciprocation during cement displacement 2. Cement - Top of tail >500' TVD above shoe using 30% excess. 3. Casing Shoe Set approximately 100'TVD below SV-1 sand. ~ Ensure casing detail highlights the S-95 top two joints of surface casing will be L-80 and the remainder will be S-95. Reference RPs .:. "Casing and Liner Running Procedure" .:. "Surface Casing and Cementing Guidelines" .:. "Halliburton Cement Program" .:. "Surface Casing Port Collar Procedure" Job 7: Drillinq Production Hole Hazards and Contingencies ~ KICK TOLERANCE: The reservoir pressure of the Kuparuk has been estimated to be 9.8 ppg due to production in the area. Assuming gauge hole, a fracture gra~ient- 3.2 ppg at the surface casing shoe, 10.1 ppg mud in the hole the kick tolerance i b s. An accurate LOT will be required as well as heightened awareness for kick dete . . Contact Drilling Manager if LOT is less than 13.2 ppg. >- Four faults are expected to be penetrated by L-122 in the production hole. The first in the Schrader N sands at 4252' TVD. This fault is very small, less than 50' of throw and is not expected to be an issue for lost circulation. The second fault in the Schrader 0 sands at -5052' TVD has 40' of throw and is not expected to be an issue for lost circulation. The third fault at 6025' TVD in the Colville has a throw estimated at -125' and is considered a risk for loss circulation. The fourth fault is just into the Milveach at 6877' TVD, has 50' of throw and is not expected to be penetrated. It is feasible that losses may be encountered when running the production casing string if adequate precautions are not taken including running speed, staging in and optimal mud properties. >- L-Pad development wells have kick tolerances in the 35-50 bbl range. A heightened awareness of kick detection, pre-job planning and trip tank calibration will be essential while drilling/tripping the intermediate/production intervals. ~ There are no "Close Approach" issues with the production hole interval of L-122. ~ During the drilling of the Kuparuk reservoir do not add LCM (including Walnut sweeps, Barofibre) other than Baracarb for losses <50 BPH without prior discussions with the Drilling Engineer/Asset Production Engineer. Significant mud losses, >50 BPH may include the use of Barofibre to arrest losses. See LCM Decision Chart in the Mud Program. L-122 Drilling Program (AOGCC) Page 8 . . Reference RPs .:. Standard Operating Procedure for Leak-off and Formation Integrity Tests .:. Prudhoe Bay Directional Guidelines .:. Lubricants for Torque and Drag Management. .:. "Shale Drilling- Kingak & HRZ" ~~"'Mm«...w<=~"'_ Job 9: Case & Cement Production Hole Hazards and Contingencies ~ The 5-1/2" casing will be cemented to 500' above the top of the Schrader Bluff Ma sands with a single stage-two slurry cement. Due to the small annular spacing, a two stage job is not an option. Getting casing to bottom while maintaining returns is a critical operation. ~ Considerable losses during the running and cementing of the production casing has occurred on L and L-Pad. A casing running program will be jointly issued by the ODE and Drilling Supervisor detailing circulating points and running speed. In addition, a LCM pill composed of "Steel Seal" will be placed across the Schrader and Ugnu to help arrest mud dehydration. ~ Ensure the upper production cement has reached at least a 70BC thickening value prior to freeze protecting. After freeze protecting the 7-5/8" x 5-1/2"" casing outer annulus with dead crude to 2200' MD, 2092'TVD, the hydrostatic pressure will be 7.7 ppg vs 8.5 ppg EMW of the formation pressure immediately below the shoe. Ensure a double-barrier at the surface on the annulus exists until the cement has set up for at least 12 hours. Trapped annulus pressure may be present after pumping the dead crude as the hydrostatic pressure of the mud and crude could be 110 psi underbalance to the open hole. ~ Ensure a minimum hydrostatic equivalent of 10.1 ppg on the Kuparuk formation during pumping of cement pre flushes/chemical washes. Loss of hole integrity and packing off has resulted from a reduction in hydrostatic pressure while pumping spacers and flushes. ~ The well will be under-balanced after displacing the cement with sea-water. Verify that the floats are holding before continuing operations and hold pressure on the well if they are not holding. ~ The X- Nipples, with 1.0. of 2.813" is the tightest tolerance for the Weatherford Dual- Plug system, (tapered cement plugs to be used in the 5 112" X 3 W' tapered casing string.) Caliper and confirm the 1.0. of all X-Nipples prior to make-up to ensure conformity with proposed design. The By-Pass plug head has been milled down to an 0.0. of 2.5". Caliper to confirm, prior to use. Note: Based on wiper plug failures, drop the top and bottom plug together prior to displacement of cement. Reference RPs .:. "Intermediate Casing and Cementing Guidelines" .:. "Halliburton Cement Program" Attached. .:. "Freeze Protecting an Outer Annulus" L-122 Drilling Program (AOGCC) Page 9 . . Job 12: Run Completion Hazards and Contingencies ~ Watch hole fill closely and verify proper safety valves are on the rig floor while running this completion. The well will be under-balanced if there is a casing integrity problem. ~ Shear valves have been failing at lower than the 2500 psi differential pressure. When testing annulus maintain no more than a 1500 psi differential: 2500 psi tubing pressure, 4000 psi annulus pressure. Avoid cycling pressure (pumping up and bleeding off) prior to activating shear valve as this is thought to cause shearing at lower pressures. Reference RPs .:. "Completion Design and Running" .:. "Freeze Protection of Inner Annulus" __ AM ·X.__ Job 13: ND/NUlRelease RiQ Hazards and Contingencies ~ No hazards specific to this well have been identified for this phase of the well construction. Reference RPs .:. Standard practices apply. .:. Freeze Protection of Inner Annulus. ~-=--v ,-- .==~.........._.......~~ L-122 Drilling Program (AOGCC) Page 10 TREE = 3-1/8" 5M CIIN WELLHEAD = 11" FMC w__,_·~__·_·u__mA__V__________~W"_,·_·___~^~~~.·.·~_·mm_w__mn_m~~~"N ACTUA TOR = NA ~mm.~,'.',W,'~"""'''W NmmN"N_'_~m_'_'_'mm""" KB. ELEV = 82.0' =~=~wmmm=mm==mN,','m~~mWAW.'."mm' BF. ELEV = 56.43' ~.',_'m'.~~.m_m.m~·m~mm" KOP = 300 ~~~"~~='mN_v_'_W_w_'_'mmmmNu_vNN_W_~,,'~~_'m ~~~~~I:~~ 54° @ , Datum MD = _'_v'____,____,_____,_A___.___.,_._,____'_'.'._.?_'u.______._..__ Datum TVD = . 17-5/8" casing 29.7 Iblft S-95/L-80 10= 6.875" -j 3490' 13-1/2" TBG, 9.2#, L-80, TC-II, .0087 bpf, ID = 2.992" 1- 5-1/2" CSG, 15.5#, L-80, BTC, 10 = 4.950" 1- 15-1/2" X 3-112" CSG XO, ID = 3.000" 1- ÆRFORA TION SUMMARY REF LOG: ANGLE AT TOP PERF: Note: Refer to A"oduction DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE None PBTD 1- 13-1/2" CSG, 9.2#, L-80, .0087 bpf, 10 = 2.992" -j OA TE REV BY COMMENTS 03/25/03 nm A"oposed Completion (P3) L-122 / J ~ - ----t 2200' - . .FETY NOTES: -j7-5/8" TAM Collar, ID = 6.875"1 -j3-1/2" HES 'X' NIP, 10 = 2.813" I ST MO TVD l-~ 2 1 GAS LIFT MANDRELS OEV TYÆ VLV LATCH PORT KBG2-9 DV BTM 3.5x1 KBG2-9 DV BTM 3.5x1 KBG2-9 DV BTM 3.5x1 KBG2-9 DCK-2 BTM 3.5x1 DATE .l.L r- ~ 9439' ~ OA TE REV BY COMMENTS -j3-1/2" BKR CMD SLIDING SLY, 10 = 2.813" 1 -j BKR LOG SEAL ASSY, ID = 3.00" 1 -j TOP OF BKR PBR, ID = 4.00" 1 I~ BTM OF 3-1/2" BKR SEAL ASSY, 10 = 3.00" 1-13-1/2" HES X NIP, ID = 2.813" I -j3-1/2" HES X NIP, 10 = 2.813" I lîPUPJTW I RA TAG 1 jt I above TKUPB lîPUPJTW I RA TAG 2jt I above TKUPA PRUOHOE BAY UNIT WELL: L-122 PERMIT No: API No: SEC 34, T12N, R11 E, 2535' FSL & 3831' FEL BP Exploration (Alaska) . . L-122 Well Summary of Drillina Hazards POST THIS NOTICE IN THE DOGHOUSE Surface Hole Section: . Gas hydrates may be encountered near the base of the Permafrost at 1900'MD and near the TD hole section as well. · Gravel beds below the Permafrost will tend to slough in when aerated (hydrate cut) mud is being circulated out. Ensure adequate mud viscosity is maintained to avoid stuck pipe situations. Production Hole Section: · A majority of the L-Pad development wells will have "kick tolerances" in the 35-50 bbl. A heightened awareness of kick detection, pre-job planning and trip tank calibration will be essential while drilling/tripping the intermediate/production intervals. · The production section will be drilled with a recommended mud weight of 10.1 ppg to ensure shale stability in the HRZ shale and to cover the Kuparuk 9.8 pore pressure. · Tight hole, hole packing-off, and lost returns have been encountered in previous wells on this pad. Pipe sticking tendency is possible if the HRZ shale gives problems. Back reaming at connections and good hole cleaning practices will contribute to favorable hole conditions. . L-122 will cross three faults: NO.1 at 4252' TVD Schrader N sand NO.2 at 5052' TVD Schrader 0 sand No.3 at 6025' TVD Colville- Risk of Lost Circulation Lost circulation is considered to be a moderate risk in fault No.3. Consult the Lost Circulation Decision Tree regarding LCM treatments and procedures. HYDROGEN SULFIDE - H2S /' · This drill-site not designated as an H2S drill site. Recent wells test do not indicate the presence of H2S. As a precaution, Standard Operating Procedures for H2S precautions should be followed at all times. CONSULT THE L-PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION Version 1.0 Rigsite Hazards and Contingencies L-122 Proposed Well Profile - Geodetic Report Schlumberuer Report Date: March 21, 2003 Survey / DLS Computation Method: Minimum Curvature / Lubinski Client: BP Exploration Alaska Vertical Section Azimuth: 305.000° Field: Prudhoe Bay Unit - WOA (Drill Pads) studY Vertical Section Origin: N 0.000 ft, E 0.000 ft Structure / Slot: mt",eas1blllty TVD Reference Datum: KB Well: TVD Reference Elevation: 77. 0 ft relative to MSL Borehole: Sea Bed / Ground Level Elevation: 44.100 ft relative to MSL UWI/API#: 50029 Magnetic Declination: 25.576° Survey Name / Date: L-122 (P3) / March 21, 2003 Total Field Strength: 57512.339 nT . Tort I AHD / DDI/ ERD ratio: 129.629° /5669.58 ft /5.996/ 0.81C Magnetic Dip: 80.785° Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feel Declination Date: April 15, 2003 Location Lat/Long: N 70.35056758, W 149.32544303 Magnetic Declination Model: BGGM 2002 Location Grid N/E Y/X: N 5978256.080 ftUS, E 583083.680 ftUS North Reference: True North Grid Convergence Angle: -+Ü.63527929° Total Corr Mag North·) True North: +25.576° Grid Scale Factor: 0.99990784 Local Coordinates Referenced To: Well Head Grid Coordinates Geographic Coordinates Station ID MD Incl Azim TVD VSec N/-S E/-W I DLS Northing I Easting Latitude I Longitude (ft) (0) (0) (ft) (ft) (ft) (ft) (0/100ft) (ftUS) (ftUS) KBE 0.00 0.00 292.21 0.00 0.00 0.00 0.00 0.00 5978256.08 583083.68 N 70.35056758 W 149.32544303 KOP Bid 1.5/100 300.00 0.00 292.21 300.00 0.00 0.00 0.00 0.00 5978256.08 583083.68 N 70.35056758 W 149.32544303 Crv 3/100 400.00 1.50 292.21 399.99 1.28 0.49 -1.21 1.50 5978256.56 583082.46 N 70.35056891 W 149.32545285 500.00 4.50 292.21 499.84 6.38 2.47 -6.06 3.00 5978258.48 583077.59 N 70.35057432 W 149.32549222 600.00 7.50 292.21 599.28 16.57 6.42 -15.73 3.00 5978262.32 583067.88 N 70.35058511 W 149.32557073 700.00 10.50 292.21 698.04 31.83 12.34 -30.21 3.00 5978268.08 583053.34 N 70.35060129 W 149.32568827 800.00 13.50 292.21 795.84 52.10 20.20 -49.46 V-. 3.00 5978275.73 583034.00 N 70.35062276 W 149.32584455 900.00 16.50 292.21 892.42 77.34 29.98 -73.42 3.00 5978285.24 583009.94 N 70.35064948 W 149.32603906 . 1000.00 19.50 292.21 987.52 1 07.47 41.67 -102.02 3.00 5978296.61 582981.21 N 70.35068141 W 149.32627123 1100.00 22.50 292.21 1080.87 142.41 55.21 -135.19 3.00 5978309.78 582947.90 N 70.35071840 W 149.32654051 1200.00 25.50 292.21 1172.21 182.07 70.59 -172.84 3.00 5978324.74 582910.08 N 70.35076042 W 149.32684616 1300.00 28.50 292.21 1261.30 226.34 87.75 -214.87 3.00 5978341 .43 582867.87 N 70.35080729 W 149.32718737 1400.00 31.50 292.21 1347.89 275.10 106.65 -261.15 3.00 5978359.82 582821.39 N 70.35085892 W 149.32756308 1500.00 34.50 292.21 1431.75 328.20 127.24 -311.57 3.00 5978379.85 582770.75 N 70.35091517 W 149.32797241 1600.00 37.50 292.21 1512.64 385.52 149.46 -365.98 3.00 5978401.46 582716.10 N 70.35097586 W 149.32841413 1700.00 40.50 292.21 1590.35 446.88 173.25 -424.23 3.00 5978424.60 582657.60 N 70.35104085 W 149.32888702 1800.00 43.50 292.21 1664.65 512.13 198.55 -486.17 3.00 5978449.21 582595.38 N 70.35110995 W 149.32938988 1900.00 46.50 292.21 1735.36 581.08 225.28 -551.62 3.00 5978475.21 582529.65 N 70.35118296 W 149.32992123 Schlumberger Private L-122 (P3) report.xls Page 1 of 3 3/21/2003-1:33 PM Grid Coordinates Geographic Coordinates Station ID MD Incl Azim I TVD VSec N/·S E/·W DLS Northing I Easting Latitude I Longitude (ft) (0) (0) (ft) (ft) (ft) (ft) (0/100ft) (ftUS) (ftUS) 2000.00 49.50 292.21 1802.26 653.54 253.38 -620.41 3.00 5978502.54 582460.56 N 70.35125972 W 149.33047971 2100.00 52.50 292.21 1865.19 729.32 282.75 -692.35 3.00 5978531.11 582388.30 N 70.35133994 W 149.33106376 End Bid 2160.50 54.32 292.21 1901.25 776.69 301.12 -737.32 3.00 5978548.98 582343.14 N 70.35139011 W 149.33142886 9-5/8" Csg pt 3490.37 54.32 292.21 2677.00 1830.08 709.51 -1737.31 0.00 5978946.22 581338.77 N 70.35250534 W 149.33954791 Crv 3/100 5497.21 54.32 292.21 3847.65 3419.70 1325.80 -3246.34 0.00 5979545.68 579823.15 N 70.35418762 W 149.35180159 5500.00 54.27 292.30 3849.28 3421.91 1326.66 -3248.44 3.00 5979546.52 579821.04 N 70.35418997 W 149.35181865 5600.00 52.85 295.59 3908.68 3500.84 1359.28 -3321.96 3.00 5979578.32 579747.17 N 70.35427899 W 149.35241571 5700.00 51.52 298.99 3970.00 3579.10 1395.48 -3392.15 3.00 5979613.74 579676.59 N 70.35437780 W 149.35298575 . 5800.00 50.30 302.52 4033.06 3656.48 1435.14 -3458.84 3.00 5979652.65 579609.47 N 70.35448607 W 149.35352739 5900.00 49.18 306.17 4097.70 3732.76 1478.16 -3521.84 3.00 5979694.97 579546.00 N 70.35460351 W 149.35403909 6000.00 48.18 309.94 4163.74 3807.73 1524.43 -3580.97 3.00 5979740.57 579486.37 N 70.35472984 W 149.35451938 Target 6019.85 48.00 310.70 4177.00 3822.44 1533.98 -3592.23 3.00 5979750.00 579475.00 N 70.35475592 W 149.35461085 6100.00 46.86 313.57 4231.23 3881.00 1573.56 -3636.00 3.00 5979789.08 579430.80 N 70.35486399 W 149.35496640 6200.00 45.53 317.30 4300.46 3951.95 1624.95 -3686.64 3.00 5979839.91 579379.60 N 70.35500431 W 149.35537779 6300.00 44.34 321.20 4371.26 4020.39 1678.42 -3732.75 3.00 5979892.86 579332.90 N 70.35515033 W 149.35575241 6400.00 43.28 325.26 4443.44 4086.12 1733.84 -3774.19 3.00 5979947.81 579290.86 N 70.35530167 W 149.35608913 6500.00 42.37 329.46 4516.79 4148.97 1791.05 -3810.85 3.00 5980004.60 579253.57 N 70.35545791 W 149.35638704 End Crv 6548.94 41.99 331.57 4553.06 4178.62 1819.65 -3827.03 3.00 5980033.02 579237.07 N 70.35553602 W 149.35651854 Crv 3/100 7625.10 41.99 331.57 5352.95 4822.49 2452.77 -4169.73 0.00 5980662.24 578887.41 N 70.35726515 W 149.35930412 7700.00 40.16 333.55 5409.42 4866.12 2496.43 -4192.42 3.00 5980705.64 578864.24 N 70.35738439 W 149.35948858 7800.00 37.77 336.44 5487.18 4920.58 2553.38 -4219.02 3.00 5980762.29 578837.01 N 70.35753993 W 149.35970485 Target 7849.98 36.60 338.00 5527.00 4946.13 2581.23 -4230.72 3.00 5980790.00 578825.00 N 70.35761600 W 149.35979999 7900.00 35.18 338.83 5567.52 4970.61 2608.49 -4241.51 3.00 5980817.14 578813.91 N 70.35769045 W 149.35988774 8000.00 32.36 340.69 5650.64 5016.29 2660.63 -4260.77 3.00 5980869.06 578794.08 N 70.35783286 W 149.36004439 . End Crv 8071.96 30.36 342.22 5712.09 5046.42 2696.12 -4272.69 3.00 5980904.41 578781.76 N 70.35792980 W 149.36014136 Drp 3/100 8319.99 30.36 342.22 5926.11 5146.24 2815.48 -4310.98 0.00 5981023.33 578742.16 N 70.35825582 W 149.36045287 8400.00 27.96 342.22 5995.98 5177.28 2852.60 -4322.88 3.00 5981060.31 578729.85 N 70.35835721 W 149.36054968 8500.00 24.96 342.22 6085.49 5212.75 2895.01 -4336.49 3.00 5981102.56 578715.77 N 70.35847305 W 149.36066041 8600.00 21.96 342.22 6177.22 5244.45 2932.91 -4348.64 3.00 5981140.32 578703.20 N 70.35857657 W 149.36075926 8700.00 18.96 342.22 6270.90 5272.27 2966.19 -4359.31 3.00 5981173.48 578692.16 N 70.35866747 W 149.36084607 8800.00 15.96 342.22 6366.29 5296.16 2994.75 -4368.47 3.00 5981201.93 578682.69 N 70.35874548 W 149.36092060 Target! Drp 2.5/100 8831.87 15.00 342.22 6397.00 5302.93 3002.85 -4371.07 3.00 5981210.00 578680.00 N 70.35876760 W 149.36094175 8900.00 13.32 342.22 6463.06 5316.20 3018.71 -4376.16 2.47 5981225.80 578674.73 N 70.35881092 W 149.36098316 9000.00 10.84 342.22 6560.84 5332.87 3038.64 -4382.55 2.47 5981245.66 578668.12 N 70.35886536 W 149.36103515 9100.00 8.37 342.22 6659.43 5346.16 3054.54 -4387.64 2.47 5981261.50 578662.86 N 70.35890879 W 149.36107657 Schlumberger Private L-122 (P3) report.xls Page 2 of 3 3/21/2003-1 :33 PM Grid Coordinates Geographic Coordinates Station ID MD Incl Azim TVD VSec N/-S I E/·W DLS Northing I Easting Latitude I Longitude (ft) (0) (0) (ft) (ft) (ft) (ft) (0/100ft) (ftUS) (ftUS) 9200.00 5.90 342.22 6758.64 5356.05 3066.37 -4391.44 2.47 5981273.29 578658.93 N 70.35894110 W 149.36110748 9300.00 3.43 342.22 6858.30 5362.53 3074.11 -4393.92 2.47 5981281.00 578656.36 N 70.35896224 W 149.36112766 9400.00 0.96 342.22 6958.22 5365.58 3077. 76 -4395.09 2.47 5981284.64 578655.15 N 70.35897221 W 149.36113718 TD I 7" Csg pt 9438.78 0.00 342.22 6997.00 5365.84 3078.07 -4395.19 2.47 5981284.94 578655.05 N 70.35897306 W 149.36113799 LeQal Description: Surface: 2535 FSL 3831 FEL S34 T12N R11E UM Target: 4068 FSL 2140 FEL S33 T12N R11E UM Target: 5115 FSL 2777 FEL S33 T12N R11 E UM Target: 257 FSL 2916 FEL S28 T12N R11E UM BHL: 332 FSL 2940 FEL S28 T12N R11E UM NorthinQ ey) rftUSl 5978256.08 5979750.00 5980790.00 5981210.00 5981284.94 EastinQ eX) rftUSl 583083.68 579475.00 578825.00 578680.00 578655.05 . . L-122 (P3) report. xis Schlumberger Private Page 3 of 3 3/21/2003-1 :33 PM · VERTICAL SECTION VIEW Client: Well: Field: BP Exploration Alaska L-122 (P3) Prudhoe Bay Unit - WOA L-pad 305.00 deg March 21, 2003 Schlumberger Structure: Section At: Date: o Hold Angle 54.32° - - CD- .æ~ g~ o CD N > II .8 I:: ro ~~ ........0 L:~ ã.~ CD........ om -~ ~.;...: :e CD CDe::: > ã; ~w .... I- 2000 4000 6000 Target 7850 MO 5527 TVD 36.600 338.000 az 4946 departure End Cry 8072 MO 5712 TVD 30.36° 342.22° az Drp3/100 8320 MD 5926 TVO 30.36° 342.22° az 5146 departure 8000 -2000 o 2000 4000 6000 Vertical Section Departure at 305.00 deg from (0.0, 0.0). (1 in = 2000 feet) PLAN VIEW BP Exploration Alaska L-122 (P3) Prudhoe Bay Unit - WOA L-pad 1 in = 1000 ft 21-Mar-2003 Client: Well: Field: Structure: Scale: Date: Schlumberuer 1000 -2000 I -1000 I o , -3000 I -5000 I -4000 I - 4000 4000 . True North Mag Dee ( E 25.58° TD/7" Csg Pt 9439 MD 6997 TVD 0.00· 342.22· az 3078 N 4395 W Drp31100 8320 MD 5926 TVD 30.36° 342.22° az 2815 N 4311 W - 3000 3000 ^ ^ ^ ::r: I- 0::: o Z 15.00· 3003 N W End Cry . 8072 MD ¡ 5712 TVD 30.36· 3<}2.22° az 2696 N 4þ73 W ~ :0- ~. ~" \1 / j 0 Target 6ö20·MD4177TVD' 48.00' 310.70· az 1S34N 3592W - 2000 2000 - -1000 1000- . ::r: l- => o CJ) V V V I !-¡Olcj,.(. I <?''hútA 1.<9<,,> m....... .................;:<:..t~. Crv3/100 400 MD 400 TVO 1.50· 292.21" az ON 1W ¡ ~ ~;PMB~~.;O~;D ...... ~ "O.Óöö·· 292:2io"äZ" ON 0 E 0- ........m-O . .........¡.......m" I i ¡ ¡ 1000 ; i I -2000 I -5000 I -1000 EAST »> I -4000 I -3000 «< WEST -1000 -1000 o · BP Exploration Alaska. Anticollision Report NO GLOBAL SCAN: Using user defined selection & scan criteria Interpolation Method: MD Interval: 50.00 ft Depth Range: 28.50 to 9438.78 ft Maximum Radius: 3000.00 ft Reference: Error Model: Scan Method: Error Surface: Principal Plan & PLANNED PROGRAM ISCWSA Ellipse Trav Cylinder North Ellipse + Casing Survey Program for Definitive Wellpath Date: 8/23/2002 Validated: No Planned From To Survey ft ft 28.50 700.00 Planned: Plan #3 V1 700.00 9438.78 Planned: Plan #3 V1 Version: 3 Toolcode Tool Name GYD-GC-SS MWD+IFR+MS Gyrodata gyro single shots MWD + IFR + Multi Station Casing Points 3490.37 2677.00 9438.78 6997.00 9.625 7.000 12.250 8.750 95/8" 7" Summary EX NWE#1 NWE1-01A NWE1-01A V4 300.03 300.05 204.40 5.27 199.14 Pass: Major Risk EX NWE#1 NWE1-01 NWE1-01 V3 299.98 300.00 204.39 5.26 199.13 Pass: Major Risk EX NWE#1 NWE1-02 NWE1-02 V2 852.54 850.00 20.83 14.60 6.23 Pass: Major Risk PB L Pad L-01 L-01 V14 300.00 300.00 222.73 4.94 217.78 Pass: Major Risk PB L Pad L-01 L-01 L 1 V2 Plan: Plan # 300.00 300.00 222.73 4.94 217.78 Pass: Major Risk PB L Pad L-02 L-02 V1 595.32 600.00 19.36 9.72 9.73 Pass: Major Risk PB L Pad L-02 L-02PB1 V21 Plan: L-02 595.32 600.00 19.36 9.83 9.62 Pass: Major Risk PB L Pad L-102 L-102 V2 248.00 250.00 346.08 4.08 342.00 Pass: Major Risk PB L Pad L-102 L-102PB1 V10 248.00 250.00 346.08 4.17 341.91 Pass: Major Risk PB L Pad L-102 L-102PB2 V2 248.00 250.00 346.08 4.17 341.91 Pass: Major Risk PB L Pad L-103 L-103 V23 346.43 350.00 220.92 5.81 215.11 Pass: Major Risk PB L Pad L-104 L-104 V7 344.21 350.00 318.92 5.88 313.04 Pass: Major Risk PB L Pad L-105 L-105 V4 298.19 300.00 286.35 5.44 280.91 Pass: Major Risk PB L Pad L-106 L-106 V14 478.23 500.00 293.56 7.75 285.85 Pass: Major Risk PB L Pad L-107 L-107 V14 199.68 200.00 232.25 4.41 227.84 Pass: Major Risk PB L Pad L-108 L-108 V18 436.40 450.00 268.72 7.96 260.76 Pass: Major Risk PB L Pad L-109 L-109 V12 300.00 300.00 189.18 6.27 182.91 Pass: Major Risk PB L Pad L-110 L-110V11 299.89 300.00 182.24 5.52 176.72 Pass: Major Risk PB L Pad L-111 L-111 V24 300.78 300.00 203.04 5.38 197.65 Pass: Major Risk PB L Pad L-112 L-112V8 647.40 650.00 44.63 12.27 32.43 Pass: Major Risk PB L Pad L-114 L-114 V14 496.03 500.00 187.82 7.69 180.17 Pass: Major Risk PB L Pad L-115 L-115 V7 299.99 300.00 31.06 5.27 25.79 Pass: Major Risk PB L Pad L-116 L-116 V10 397.12 400.00 187.00 6.01 181.00 Pass: Major Risk PB L Pad L-117 L-117V11 398.96 400.00 45.77 6.26 39.51 Pass: Major Risk PB L Pad L-119 L-119V9 345.54 350.00 266.97 5.79 261.18 Pass: Major Risk PB L Pad L-120 L-120 V8 297.88 300.00 297.25 5.16 292.09 Pass: Major Risk PB L Pad L-121 L-121 V13 200.59 200.00 182.63 3.67 178.96 Pass: Major Risk PB L Pad L-121 L-121A V3 200.59 200.00 182.63 3.67 178.96 Pass: Major Risk PB L Pad Plan L-118 Plan L-118 V7 Plan: PI 349.37 350.00 60.45 6.45 54.00 Pass: Major Risk DATE INVOICE I CREDIT MEMO DESCRIPTION GROSS I DATE . 3/1212003 VENDOR DISCOUNT CHECK NO. ~ I 055032 I P055032 . NET 3/12/2003 INV# CK030603E ,/ PERMIT TO DRILL H 1---1 A~ RECEIVED MAR 2 6 200~ A _8 Oit & Gas ConS. Con mieeion Anc:htnge 'HE ATTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. TOTAL ~ BP EXPLORATION, (ALASKA) INC. PRUDHOE BAY UNIT PO BOX 196612 ANCHORAGE:, AK99519-6612 NATIONAL CITY BANK Ashland, Ohio 56-389 412 No. P 055032 CONSOLIDATED COMMERCIAL ACCOUNT PAY: rei)' ",,... ".1111,..... "f.'I....i··'l ,'·'·.'./'I" Iat¡·:",:"-.'f:','" ':, It'· ....".-... .., .., If ;_,_:~u,,, H~f!t,'~I"'1 ·...m,,- "'J> B. TO THE ORDER OF: ALASKA OIL & GAS CONSERVATION COMMISSION 333 W 7TH AVENUE SUITE 100 ANCHORAGE,AK 99501~3539 DATE AMOUNT Match 12,2003 II *******$100.00******i NOT VALlI1M:I!iD..~~~ ~~Y'ì.: ...." ;.".7'.. .. .. "'" L:;, ~':' ,':" '."'<::'''~t:;;;·'f;'':'i;'::¡::;'' , ;':':.ÞJ;2::;~~f~%:~ 1110 5 SO :I 2 III I: 0 ... ~ 20 :I 8 g 5 I: 0 ~ 2 78 g b III . . TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERlP ARAGRAPHS TO BE INCLUDED INTRANSNOTTALLETTER WELL NAME PTD# CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) "CLUE" The permit is for a new well bore segment of existing well_, Permit No, API No. Production should continue to· be reported as a function of the original API number stated above. HOLE In accordance with 20 AAC 25.005(t), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 70/80) from records, data and logs acquired for well (name on permit). PILOT (PH) SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. WELL PERMIT CHECKLIST COMPANY ß j/ Y WELL NAME/.ð'CI ¿ -/2-2- PROGRAM: Exp _ Dev ~ Redrll_ Re-Enter _ Serv _ Wellbore seg_ ::~~N~S~:~ION ~1:p~~~f~attached. . . I.N~T.~~~~ . ~~~J. . ~~~~~. rÇ N GEOLAREA ~7CJ UNIT# //bJô ON/OFFSHORE~ 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . Y N 3. Unique well name and number. . . . . . . . . . . . . . . . . Y N 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . Y N 5. Well located proper distance from drilling unit boundary. Y N 6. Well located proper distance from other wells.. . . . . . . . . Y N 7. Sufficient acreage available in drilling unit.. . . . . . . . . . . Y N /ii1J ~ L ~ I:L 8. If deviated, is wellbore plat included.. . . . . . . . . . . . . . ~ N ~~....7 9. Operator only affected party.. . . . . . . . . . . . . . . . . . Y N 10. Operator has appropriate bond in force. . . . . . . . . . . . . Y N 11. Permit can be issued without conservation order. . . . . . . . Y N 12. Permit can be issued without administrative approval.. . . . . N 13. Well located w/in area & strata authorized by injection order#_ ~ y A/I .,4. 14. All wells w/in ~ mile area of review identified. . . . . . . . .. h ~ ~ 15. Conductor string provided. . . . . . . . . .. . . . . . . . . ~ N ~'II X Z¡;;I( @ /fO'. 16. Surface casing protects all known USDWs. . . . . . . . . . . N 17. CMT vol adequate to circulate on conductor & surf csg. . . . . . . N 18. CMT vol adequate to tie-in long string to surf csg. . . . . . . . ~~ 19. CMT will cover all known productive horizons. . . . . . . . . . 20. Casing designs adequate for C, T. B & permafrost. . . . . . . t 21. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . œ N rJÞ,.. 0 r<,. q ~S . 22. If a re-drill, has a 10-403 for abandonment been approved. . . AI / ' 23. Adequate wellbore separation proposed.. , . . . . . . . . . . N 24. If diverter required, does it meet regulations. . . . . . . . . . N 1 25. Drilling fluid program schematic & equip list adequate. . . . . N (1;1 fA4.. ¡It!¡ ki to. t P P q . 26. BOPEs. do they meet regulation. . . . . . . . . . . . . . . . N 27. BOPE press rating appropriate; test to 400 Ð psig. N M ç, P r;fc.. 27$<:; P S ¡' . . 28. Choke manifold complies w/API RP-53 (May 84). . . . . . . . N \JJGA- ~l11lsB 29. Work will occur without operation shutdown. . . . . . . . . . . N 30. Is presence ofH2S gas probable.. . . . . . . . . . . . . . . . Y £V 31. Mechanical condition of wells within AOR verified. . . . . . . . -¥--N'"'¡\I/Æ- . WN '1 f ,A/,4. ~~ ' APPR DATE (Service Well Only) (Service Well Only) ENGINEERING APPR DATE (Service Well Only) GEOLOGY APPR DATE ~~ (Exploratory Only) . . ,.."",,..>t.....'" 32. Permit can be issued w/o hydrogen sulfide measures. . . . . 33. Data presented on potential overpressure zones. . . . . . . . 34. Seismic analysis of shallow gas zones. . . . . . . . . . . . . 35. Seabed condition survey (if off-shore). . . . . ., ...... 36. Contact namelphone for weekly progress reports. ...... . GEOLOGY: PETROLEUM ENGINEERING: RESERVOIR ENGINEERING UIC ENGINEER COMMISSIONER: Comments/lnstructions: R~ TM JH JR SP P0?y' RR...J;:. ~ o~ SFD WA /' MW DS Off;> pi- Rev: 2/25/03 - \weIU>ermiCchecklist