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197-112
Originated: Delivered to:2-Sep-25Alaska Oil & Gas Conservation Commiss02Sep25-NR ! "# $$%$ !&$$'($)*%+ ($)*%,- .WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGEDCD4-24 50-103-20602-00-00 209-097 Colville River WL RBP FINAL FIELD 3-Aug-251E-36 50-029-22927-00-00 198-213 Kuparuk River WL WFL FINAL FIELD 5-Aug-252F-18 50-029-22720-00-00 196-178 Kuparuk River WL SCMT FINAL FIELD 6-Aug-251E-36 50-029-22927-00-00 198-213 Kuparuk River WL RST FINAL FIELD 7-Aug-251C-121 50-029-23015-00-00 201-080 Kuparuk River WL IPROF FINAL FIELD 8-Aug-252V-16 50-029-21296-00-00 185-033 Kuparuk River WL PPROF FINAL FIELD 9-Aug-252X-01 50-029-20963-00-00 183-084 Kuparuk River WL HEX-PLUG FINAL FIELD 10-Aug-251R-22A 50-029-22206-01-00 199-049 Kuparuk River WL PPROF FINAL FIELD 11-Aug-251C-121 50-029-23015-00-00 201-080 Kuparuk River WL IPROF FINAL FIELD 13-Aug-251B-08A 50-029-20635-01-00 197-112 Kuparuk River WL IPROF FINAL FIELD 22-Aug-25Transmittal Receipt//////////////////////////////// 0///////////////////////////////// + ! 1 Please return via courier or sign/scan and email a copy to Schlumberger. " 2"3 +45 %TRANSMITTAL DATETRANSMITTAL #1 67 8 " ! - +" 8 # !(3 . 8 ) "3 8 # !9 3 : 8" +8 6 8 8 " 8 # !;" " 3 - 3 " 3 ""+ 3 + < +3!% T40840T40841T40842T40841T40843T40844T40845T40846T40843T408471B-08A50-029-20635-01-00197-112Kuparuk RiverWLIPROFFINAL FIELD22-Aug-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.09.03 08:58:49 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, July 24, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1B-08A KUPARUK RIV UNIT 1B-08A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/24/2025 1B-08A 50-029-20635-01-00 197-112-0 W SPT 4826 1971120 1500 1236 1231 1231 1231 100 100 100 100 4YRTST P Josh Hunt 6/18/2025 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 1B-08A Inspection Date: Tubing OA Packer Depth 680 2410 2350 2340IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH250620082252 BBL Pumped:1.4 BBL Returned:1.2 Thursday, July 24, 2025 Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, June 12, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Austin McLeod P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1B-08A KUPARUK RIV UNIT 1B-08A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 06/12/2024 1B-08A 50-029-20635-01-00 197-112-0 G SPT 4826 1971120 1500 2601 2596 2620 2633 6 5 6 6 INITAL P Austin McLeod 4/28/2024 Initial. Post RWO. Pad across the road from plant (slight tubing swing) 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 1B-08A Inspection Date: Tubing OA Packer Depth 520 2020 1980 1980IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSAM240429111937 BBL Pumped:1 BBL Returned:0.9 Wednesday, June 12, 2024 Page 1 of 1 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Tuesday, March 26, 2024 10:12 AM To:Al Hansen Cc:Regg, James B (OGC) Subject:RE: Nordic 3 BOPE test 2-28-24 Attachments:Nordic 3 02-28-24 Revised.xlsx Al, I revised report to add A to well name KRU 1B‐08A based on PTD #1971120. Please update your copy. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Al Hansen <al.hansen@nordic‐calista.com> Sent: Thursday, February 29, 2024 11:17 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: Nordic 3 BOPE test 2‐28‐24 Jake Henry Nordic Calista Dog House 670‐6144 907‐414‐0962 Cell This information is intended only for the use of the individual (s) or entity (ies) named above and may contain confidential or privileged information. Any unauthorized disclosure, copying, distribution or the taking of any action in reliance on the contents of this transmitted information is strictly prohibited. If you are not the intended recipient or have received this transmission in error, please immediately delete it and any attachments from your system and send me an email confirming that you have not disclosed, copied, or distributed this message and that you have deleted this message and any attachments from your system. 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. KRU 1B-08APTD 1971120 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:3 DATE:2/28/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #1971120 Sundry #323-615 Operation:Drilling:Workover:xxx Explor.: Test:Initial:Weekly:xxx Bi-Weekly:Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2545 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 1 P Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 1 P BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 13 5/8"P Pit Level Indicators P P #1 Rams 1 2 7/8" X 5 1/2"P Flow Indicator P P #2 Rams 1 CSO Rams P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 3 1/8"P Time/Pressure Test Result HCR Valves 2 3 1/8"P System Pressure (psi)2920 P Kill Line Valves 1 3 1/8"P Pressure After Closure (psi)1650 P Check Valve 0 NA 200 psi Attained (sec)24 P BOP Misc 2 2 1/16" 5000 P Full Pressure Attained (sec)116 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):4@1920 P No. Valves 12 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 1 P Annular Preventer 13 P #1 Rams 5 P Coiled Tubing Only:#2 Rams 4 P Inside Reel valves 0 NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:7.0 HCR Choke 1 P Repair or replacement of equipment will be made within 3 days. HCR Kill 1 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 2/26/24/06:48 Waived By Test Start Date/Time:2/27/2024 18:30 (date)(time)Witness Test Finish Date/Time:2/28/2024 1:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Adam Earl Nordic Test BOPE with 4 1/2" test joint Henry/Twedt CPAI Newell/Barr KRU 1B-08A Test Pressure (psi): gmanager.rig3@nordic-calista.com ic3.Companyman@conocophillips Form 10-424 (Revised 08/2022)2024-0228_BOP_Nordic3_KRU_1B-08A J. Regg; 4/1/2024 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Friday, March 22, 2024 1:23 PM To:Regg, James B (OGC) Subject:FW: Nordic 3 BOP test 2-20-24 Attachments:Nordic 3 02-19-24.xlsx Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Jake Henry <jake.henry@nordic‐calista.com> Sent: Thursday, March 21, 2024 12:58 PM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: RE: Nordic 3 BOP test 2‐20‐24 My apologies again, I believe I corrected the mistakes. From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Thursday, March 21, 2024 12:02 PM To: Jake Henry <jake.henry@nordic‐calista.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: FW: Nordic 3 BOP test 2‐20‐24 CAUTION: This email originated from outside of the organization. DO NOT CLICK LINKS OR OPEN ATTACHMENTS unless you recognize the sender and know the content is safe. Jake, The finish date includes 2/19/24, however the report date is 2/20/24; please advise. The Well Name should reflect KRU 1B‐08A for PTD #1971120. Please resubmit with these corrections. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission You don't often get email from jake.henry@nordic‐calista.com. Learn why this is important KRU 1B-08APTD 1971120 J. Regg 4/1/2024 2 Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Jake Henry <jake.henry@nordic‐calista.com> Sent: Friday, February 23, 2024 8:39 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: Nordic 3 BOP test 2‐20‐24 BOP test for 2‐20‐24 Jake Henry Nordic Calista Dog House 670‐6144 907‐414‐0962 Cell This information is intended only for the use of the individual (s) or entity (ies) named above and may contain confidential or privileged information. Any unauthorized disclosure, copying, distribution or the taking of any action in reliance on the contents of this transmitted information is strictly prohibited. If you are not the intended recipient or have received this transmission in error, please immediately delete it and any attachments from your system and send me an email confirming that you have not disclosed, copied, or distributed this message and that you have deleted this message and any attachments from your system. Some people who received this message don't often get email from jake.henry@nordic-calista.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:3 DATE:2/19/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #1971120 Sundry #323-615 Operation:Drilling:Workover:xxx Explor.: Test:Initial:Weekly:xxx Bi-Weekly:Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2545 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 1 P Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 2 P BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 13 5/8"P Pit Level Indicators P P #1 Rams 1 2 7/8" X 5 1/2"P Flow Indicator P P #2 Rams 1 CSO Rams P Meth Gas Detector P P #3 Rams 1 7" Fixed P H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 3 1/8"P Time/Pressure Test Result HCR Valves 2 3 1/8"P System Pressure (psi)2950 P Kill Line Valves 1 3 1/8"P Pressure After Closure (psi)1550 P Check Valve 0 NA 200 psi Attained (sec)24 P BOP Misc 2 2 1/16" 5000 P Full Pressure Attained (sec)125 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):4@1950 P No. Valves 12 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 1 P Annular Preventer 17 P #1 Rams 4 P Coiled Tubing Only:#2 Rams 4 P Inside Reel valves 0 NA #3 Rams 4 P #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:5.5hrs HCR Choke 1 P Repair or replacement of equipment will be made within 3 days. HCR Kill 1 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 2/18/24/17:04 Waived By Test Start Date/Time:2/18/2024 23:00 (date)(time)Witness Test Finish Date/Time:2/19/2024 4:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Sully Sullivan Nordic Test BOPE with 3.5, 4.5, and 7" test joints Henry/Bezold CPAI Wiese/Newell KRU 1B-08A Test Pressure (psi): gmanager.rig3@nordic-calista.com ic3.Companyman@conocophillips Form 10-424 (Revised 08/2022)2024-0219_BOP_Nordic3_KRU_1B-08A J. Regg; 4/1/29024 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Pull/Replace Tubing Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9710'feet None feet true vertical 6659' feet None feet Effective Depth measured 9341'feet 5941', 6110'feet true vertical 6491'feet 4703', 4837'feet Perforation depth Measured depth True Vertical depth Tubing (size, grade, measured and true vertical depth)4-1/2" 4-1/2" L-80 L-80 6076' 6135' 4810' 4858' Packers and SSSV (type, measured and true vertical depth)5941' 6110' 4703' 4837' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work:Kuparuk Oil Pool 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: 2379'2274' Burst Collapse Tie-Back Liner A 8435' 1723' Casing 6086' 1734' 8465' 1754' 9710'6659' 2351' 80'Conductor Surface Production 16" 10-3/4" 51' measured TVD 7" 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 197-112 50-029-20635-01-00 P.O. Box 100360 Anchorage, AK 99510 3. Address: ConocoPhillips Alaska, Inc. N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025649, ADL0025648 Kuparuk River Field/ Kuparuk Oil Pool KRU 1B-08A Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) Gas-Mcf MDSize 80' N/A 323-615 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Packer: SLB BluePack Packer: Baker FAB 47-40 SSSV: None James Ohlinger james.j.ohlinger@conocophillips.com (907) 265-1102CTD Engineer 9270-9402' 6459-6519' 3589'4-1/2" Fra O s 6. A PG , C Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 11:46 am, Mar 27, 2024 Digitally signed by James J. Ohlinger DN: C=US, OU=ConocoPhillips, O=Wells - Coiled Tubing Drlling, CN=James J. Ohlinger, E= James.J.Ohlinger@cop.com Reason: I am the author of this document Location: Date: 2024.03.27 09:46:11-08'00' Foxit PDF Editor Version: 13.0.0 James J. Ohlinger DSR-4/12/24 RBDMS JSB 040224 Page 1/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/11/2024 18:00 2/11/2024 21:45 3.75 MIRU, MOVE RURD P R/D hard line to kill tanks, clean up in cellar area, check moving system, put test JTS for next well in pipe shed, move highline trailer, smoke and mud man shacks, spot rig mats for pulling off well, move cuttings box 0.0 0.0 2/11/2024 21:45 2/11/2024 22:15 0.50 MIRU, MOVE MOB P Jack up rig and pull off 1H-103 and off matting boards 0.0 0.0 2/11/2024 22:15 2/12/2024 00:00 1.75 MIRU, MOVE RURD P Pick up matting boards and herculite, clean around well area and rig foot print for sight inspection and handover 0.0 0.0 2/12/2024 00:00 2/12/2024 01:00 1.00 MIRU, MOVE MOB P Continue to pick up and clean up around 1H-103 for site inspection, move equipment from behind well 0.0 0.0 2/12/2024 01:00 2/12/2024 04:00 3.00 MIRU, MOVE MOB P Move rig from 1H pad to 1B pad 0.0 0.0 2/12/2024 04:00 2/12/2024 09:30 5.50 MIRU, MOVE MOB P Lay herculite around well, level out area next to 1B-17 for rig mat due to scaffolding for soft sided well house in the way, remove 1/2" gauge cluster off OA valve and plug to spot rig over well. Slide portable well house structure out of the way to spot rig over well. Set rig mats, Spot sub over the well. 0.0 0.0 2/12/2024 09:30 2/12/2024 13:00 3.50 MIRU, MOVE RURD P Berm cellar. Spot auxiliary equipment around rig. R/U hard line to tiger tank. Take initial pressures T/IA/OA = 0/65/50. Rig accepted @ 13:00 Hrs 0.0 0.0 2/12/2024 13:00 2/12/2024 18:00 5.00 MIRU, WELCTL RURD P Take on seawater in pits. R/U circ manifold in cellar. Build 40 Bbls deep clean pill. 0.0 0.0 2/12/2024 18:00 2/12/2024 18:30 0.50 MIRU, WELCTL PRTS P PT circ manifold T/ 2500 PSI. 0.0 0.0 2/12/2024 18:30 2/12/2024 19:00 0.50 MIRU, WELCTL SFTY P Crew change out. PJSM on killing well. 0.0 0.0 2/12/2024 19:00 2/12/2024 21:00 2.00 MIRU, WELCTL KLWL P Bleed gas off of IA F/ 50 T/ 20. Bleed gas off TBG F/ 20 T/ 0. Pump 32 Bbls heated soap pill down TBG @ 4 BPM, ICP=580, FCP=520. Total of 300 Bbls pumped, 284 Bbls returned. 0.0 0.0 2/12/2024 21:00 2/12/2024 21:30 0.50 MIRU, WELCTL OWFF P OWFF. Slight flow seen out of IA. No flow from TBG. 0.0 0.0 2/12/2024 21:30 2/12/2024 22:00 0.50 MIRU, WELCTL KLWL P Pump additional 30 Bbls down TBG @ 4 BPM, 560 PSI. 0.0 0.0 2/12/2024 22:00 2/12/2024 23:00 1.00 MIRU, WELCTL OWFF P OWFF TBG side static, IA slight flow Montior well 30 min after static Bleed OA F/80 PSI T/10 PSI 0.0 0.0 2/12/2024 23:00 2/13/2024 00:00 1.00 MIRU, WELCTL MPSP T Set BPV Unable set BPV, double check SSSV, double check records to see what size BPV hanger takes Suck out tree notice there is already a H -BPV in hanger 0.0 0.0 2/13/2024 00:00 2/13/2024 01:15 1.25 MIRU, WELCTL MPSP T Pull 4" H-BPV Note: OA = 60 PSI, bleed down to 20 PSI, bleed off gas,leave OA open to vent for 7" casing grow 0.0 0.0 2/13/2024 01:15 2/13/2024 02:00 0.75 MIRU, WELCTL MPSP P Set 4" HP-BPV Test T/1000 PSI F/10 Min B/D R/D lines 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 2/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/13/2024 02:00 2/13/2024 03:15 1.25 MIRU, WHDBOP NUND P N/D tree and TBG head adaptor Inspect hanger threads, make up 4 1/2" EUE 7 turns by hand, install test dart Function LDS Obtain RKB's ULDS = 26.02', MLDS = 27.95', G/L = 30.10' 0.0 0.0 2/13/2024 03:15 2/13/2024 04:15 1.00 MIRU, WHDBOP NUND P N/U 7 1/6" x 11" 5K DSA Pull flow riser of top of BOP and secure out of the way 0.0 0.0 2/13/2024 04:15 2/13/2024 11:15 7.00 MIRU, WHDBOP NUND P N/U 11" 5K x 13 5/8" spool, N/U BOP, install flow riser back on top of BOP Tighten all bolts on stack and kill/choke lines, hook up lines to trip tanks, tighten up and center stack, install riser, air up boots 0.0 0.0 2/13/2024 11:15 2/13/2024 13:00 1.75 MIRU, WHDBOP RURD P R/U to test BOP, fill lines and stack with water, purge air from system grease choke valves Obtain good shell test 0.0 0.0 2/13/2024 13:00 2/13/2024 21:30 8.50 MIRU, WHDBOP BOPE P Test BOPE at 250/3000 PSI for 5 Min each, Test annular with 3 1/2" and 7" test joints, UVBR's with 3 ½” and 4 1/2” test joints, Test lower rams W/7” test joint. Test blinds rams. Choke valves #1 to #13, upper/lower top drive IBOP. Test 3 1/2" IF FOSV and dart valve. Test 3 ½” and 4 1/2" EUE FOSV. Test 2" rig floor Demco kill valve MM #13. Test manual/HCR kill valves & manual/HCR choke valves. Test two ea 2 1/6" gate auxiliary valves below LPR. Test hydraulic and manual choke valves to 1500 PSI and demonstrate bleed off. Perform accumulator test. Initial pressure = 2950 PSI, After closure = 1600 PSI. 200 PSI attained = 24 sec. Full recovery attained = 128 sec. UVBR's = 4 sec, LVBR’s = 4 sec. Annular = 14 sec. Simulated blinds = 4 sec. HCR choke & kill =1 sec each. 4 back up nitrogen bottles average = 2100 PSI. Test gas detectors, PVT and flow show. Witness waived by AOGCC rep Brain Bixby 0.0 0.0 2/13/2024 21:30 2/13/2024 23:00 1.50 MIRU, WHDBOP RURD P RD testing equipment. Drain stack. Blowdown lines. Install wear ring (6 3/8" ID). Prep rig floor to pull 4 1/2" Tubing. 0.0 0.0 2/13/2024 23:00 2/13/2024 23:30 0.50 MIRU, WHDBOP MPSP P Pull test dart and 4" HP BPV. 0.0 0.0 2/13/2024 23:30 2/14/2024 00:00 0.50 COMPZN, RPCOMP PULL P M/U 3 1/2" EUE Landing Joint w/ XO to 4 1/2" EUE Pin. Screw into hanger neck threads. Set 10K down. BOLDS. Pull hanger to rig floor. Unseated hanger @ 105K. Pulled to rig floor dragging 125- 145K. 6,070.0 6,044.0 2/14/2024 00:00 2/14/2024 00:30 0.50 COMPZN, RPCOMP CIRC P Circ BU. 5 BPM @ 360 psi. 120 bbls. SD Pumps. 6,044.0 6,044.0 2/14/2024 00:30 2/14/2024 01:00 0.50 COMPZN, RPCOMP RURD P L/D Landing Joint, Hanger, and Hanger Pup. Blowdown TD. Prep rig floor to pull 4 1/2" Tubing. 6,044.0 6,044.0 2/14/2024 01:00 2/14/2024 01:30 0.50 COMPZN, RPCOMP OWFF P OWFF for 30-min. Suck out cuttings tank, slop tank, and pit #1. 6,044.0 6,044.0 2/14/2024 01:30 2/14/2024 07:30 6.00 COMPZN, RPCOMP PULL P Pull 4 1/2" Completions from cut @ 6,070' to 3000' 6,044.0 3,000.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 3/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/14/2024 07:30 2/14/2024 08:00 0.50 COMPZN, RPCOMP SVRG P Service rig, change out foot throttle on DW 3,000.0 3,000.0 2/14/2024 08:00 2/14/2024 11:30 3.50 COMPZN, RPCOMP PULL P Pull 4 1/2" Completions from 3000' to surface. Cut Joint = 15.05'. Clean cut. No flare. 3,000.0 0.0 2/14/2024 11:30 2/14/2024 12:45 1.25 COMPZN, RPCOMP RURD P Clean and clear rig floor. Prep rig floor for E-line CBL.*** Install wear ring ID 6.185"*** 0.0 0.0 2/14/2024 12:45 2/14/2024 16:45 4.00 COMPZN, RPCOMP ELNE P PJSM, R/U Yellow Jacket E-line. RIH and log CBL from 3,000' to surface. Sent field print log to Town for review. Est. TOC @ 1,920'. R/D E-line 12:45- PJSM 13:15- Start picking up e-line tools and sheaves 14:30 - Start running in hole with CBL 15:10- Log up from 3038' to surface 16:00 - Rig down E-line 0.0 0.0 2/14/2024 16:45 2/14/2024 18:30 1.75 COMPZN, RPCOMP BHAH P PU/MU BHA #1 (RBP Drift). Crew C/O. 0.0 6.0 2/14/2024 18:30 2/15/2024 00:00 5.50 COMPZN, RPCOMP PULD P TIH picking up singles and drift for RBP to 2,018'. Worked through tight spot @ 257'. Cont. to build stands to clear ODS pipe shed to midnight depth of 5,050'. PUW = 115K. SOW = 75K. 6.0 5,050.0 2/15/2024 00:00 2/15/2024 01:30 1.50 COMPZN, RPCOMP PULD P Cont. TIH on singles building stands to depth of 5,944'. PUW = 106K. SOW = 72K. 5,050.0 5,944.0 2/15/2024 01:30 2/15/2024 04:30 3.00 COMPZN, RPCOMP TRIP P TOOH racking stands in derrick to 250'. 5,944.0 250.0 2/15/2024 04:30 2/15/2024 05:30 1.00 COMPZN, RPCOMP MILL P Obtain Parameters. PUW = 30K, SOW = 30K. Work 6 1/8" string mill across tight spot @ 257'. 250.0 250.0 2/15/2024 05:30 2/15/2024 06:00 0.50 COMPZN, RPCOMP TRIP P Cont. TOOH to surface, standing back DP. 250.0 6.0 2/15/2024 06:00 2/15/2024 06:15 0.25 COMPZN, RPCOMP BHAH P L/D BHA #1 (RBP drift). 6.0 0.0 2/15/2024 06:15 2/15/2024 06:30 0.25 COMPZN, RPCOMP BHAH P Pick up BHA #2 (7" RBP). 0.0 17.0 2/15/2024 06:30 2/15/2024 09:00 2.50 COMPZN, RPCOMP TRIP P TIH with RBP to 2018' COE'. Pu Wt 72K So Wt 56K 2013.37' top of plug 2021.41' bottom of plug 17.0 2,021.0 2/15/2024 09:00 2/15/2024 09:30 0.50 COMPZN, RPCOMP MPSP P Set RBP (COE) mid-joint @ 2,018' (208' below TOC). Release from RBP. Set lower slips set down 20K // Set upper slips pull 20K over 2,021.0 2,021.0 2/15/2024 09:30 2/15/2024 09:45 0.25 COMPZN, RPCOMP TRIP P PUH approx. 100' above RBP. 2,021.0 1,900.0 2/15/2024 09:45 2/15/2024 12:45 3.00 COMPZN, RPCOMP PRTS P Close UPR. PT RBP to 1,000 psi. Chart for 30-min. Unable to obtain good test, bleed pressure off circulate B/U re- test good test break down test equipment 1,900.0 1,900.0 2/15/2024 12:45 2/15/2024 23:30 10.75 COMPZN, RPCOMP OTHR P RU circ hose and sand hopper. Dump 1500# (25 - 60# bags) of all-purpose sand on top of RBP. 1,900.0 1,900.0 2/15/2024 23:30 2/16/2024 00:00 0.50 COMPZN, RPCOMP WAIT P Wait 1-hour for sand to settle. 1,900.0 1,900.0 2/16/2024 00:00 2/16/2024 00:30 0.50 COMPZN, RPCOMP WAIT P Wait 1-hr for sand to settle. 1,900.0 1,900.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 4/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/16/2024 00:30 2/16/2024 01:00 0.50 COMPZN, RPCOMP TRIP P M/U stand #21. PUW = 74K, SOW = 55K. TIH and tag top of sand @ 1,948'. Set 2k down. (70' of sand on top of RBP). 1,900.0 1,948.0 2/16/2024 01:00 2/16/2024 01:30 0.50 COMPZN, RPCOMP CIRC P PUH 1 stand. Circ 60 bbls (STS) to confirm DP is clear of sand and load well with warm fluid prior to wellhead work. 1,948.0 1,858.0 2/16/2024 01:30 2/16/2024 03:00 1.50 COMPZN, RPCOMP TRIP P TOOH w/ BHA #2. 1,858.0 9.0 2/16/2024 03:00 2/16/2024 03:15 0.25 COMPZN, RPCOMP BHAH P L/D BHA #2 (RBP setting tool + XO + 5' pup) 9.0 0.0 2/16/2024 03:15 2/16/2024 03:45 0.50 COMPZN, RPCOMP OWFF P OWFF. Ensure OA = 0 psi. 0.0 0.0 2/16/2024 03:45 2/16/2024 04:45 1.00 COMPZN, RPCOMP RURD P Drain Stack. Pull wear ring. Pull riser. 0.0 0.0 2/16/2024 04:45 2/16/2024 06:45 2.00 COMPZN, RPCOMP NUND P ND BOPE. ND DSA and Tubing Head 0.0 0.0 2/16/2024 06:45 2/16/2024 13:30 6.75 COMPZN, RPCOMP OTHR P Cameron perform WH work removing LDS // Ground down LDS found second LDS seazed, work on removing LDS and repairing threads for gland nut 0.0 0.0 2/16/2024 13:30 2/16/2024 17:00 3.50 COMPZN, RPCOMP CUTP P Install flange for grow operations, Hydrotight grow casing // Total growth 22-3/4"" estimated pressure on casing 324K // Rig down Hyrotight equipment 0.0 0.0 2/16/2024 17:00 2/16/2024 22:30 5.50 COMPZN, RPCOMP NUND P NU BOPE. Found slight ring groove scarring on 11" 3 x 11" 5 DSA. Call for new in case it leaks. Install riser and air boots. 0.0 0.0 2/16/2024 22:30 2/16/2024 23:30 1.00 COMPZN, RPCOMP PRTS P Close Blind rams. Line up to test BOP break to 1,000 psi against RBP @ 2,018'. Charted. 0.0 0.0 2/16/2024 23:30 2/17/2024 00:00 0.50 COMPZN, RPCOMP BHAH P MU 7" MSC BHA# 3 0.0 4.7 2/17/2024 00:00 2/17/2024 01:30 1.50 COMPZN, RPCOMP TRIP P TIH w/ MSC to 1,755'. Bring pumps on at x BPM and xxx psi. Slowly TIH and locate collar @ 1,731' TIH to cut depth 1,749'. 4.7 1,755.0 2/17/2024 01:30 2/17/2024 06:00 4.50 COMPZN, RPCOMP SLPC P Hang blocks. Slip and Cut Drill Line. Crew C/O. PJSM. Grease Drawworks. 1,758.0 1,758.0 2/17/2024 06:00 2/17/2024 08:00 2.00 COMPZN, RPCOMP CPBO P Establish parameters. PUW = 63K. SOW = 60K. Rotating Weight = 60K. RPM = 75. Free Torque = 6700K. Stop rotation. Bring pumps on at 6 BPM and 1245 psi. Locate collars @ 1,693', 1,732'. TIH to cut depth 1,749'. Cut 7" casing. Pump rate 6 BPM at 1250 psi. Avg Torque = 8100K. Rot 75 RPM. After 7 minutes cutting stand pipe pressure dropped to 1250 psi. OA pressure did not increase due to no packoffs. Torque dropped to 7100K. 1,758.0 1,758.0 2/17/2024 08:00 2/17/2024 08:06 0.10 COMPZN, RPCOMP TRIP P SD Pumps. PUH 1 stand w/ cutter. 1,758.0 1,700.0 2/17/2024 08:06 2/17/2024 09:06 1.00 COMPZN, RPCOMP CIRC P Line up to circulate down DP taking returns from 3 1/2" x 7" Annulus. Circulate 8.6# SW until returns clean up. Kick dirty fluid outside to cuttings tank. No Pack-off in casing head so unable to circ out OA. 1,700.0 1,700.0 2/17/2024 09:06 2/17/2024 10:30 1.40 COMPZN, RPCOMP OWFF P OWFF for 30-min. Let OA/IA balance 1,700.0 1,700.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 5/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/17/2024 10:30 2/17/2024 12:30 2.00 COMPZN, RPCOMP TRIP P TOOH w/ BHA #3 (MSC). 1,700.0 6.0 2/17/2024 12:30 2/17/2024 12:45 0.25 COMPZN, RPCOMP BHAH P L/D BHA #3. 6.0 0.0 2/17/2024 12:45 2/17/2024 13:30 0.75 COMPZN, RPCOMP BHAH P MU BHA #4 (7" Spear w/ pack-off). Suck out fluid from stack for engaging fish // Engage 7" casing below hanger at surface. PU 81K. 7" casing free. PU to close 7" LPR for circulating. 0.0 1,749.0 2/17/2024 13:30 2/17/2024 21:15 7.75 COMPZN, RPCOMP DISP P LRS pressure test lines to 3,500psi. Start pumping @ 16:00. Pump hot diesel @ 2bbls/min followed with 290 hot water (140 deg) . Dirty Vac plugged up with Arctic Pack. Sent to 1B WIF to thin out with diesel. Displace OA with diesel and hot water to flush out arctic pack. R/D LRS. Swap over to rig pumps. Pump 30 bbl hi-vis pill and circ. out with 8.6# seawater. At 19:30, open top tank full. Swapped to cuttings tank to finish circulation. Noticed fluid leaking from top of tank. Tank was overfilled > 360 bbl during circulation. Called Security, D&W Safety, and ACS. Initial spill volume estimated to be >1 bbl < 10 bbl (mixture of Class II diesel and fresh water). 1,749.0 1,749.0 2/17/2024 21:15 2/17/2024 21:30 0.25 COMPZN, RPCOMP OWFF P OWFF. No Flow. 1,749.0 1,749.0 2/17/2024 21:30 2/17/2024 22:00 0.50 COMPZN, RPCOMP PULL P Pull 7" hanger to floor. 80K PUW. L/D BHA #4 (7" Spear) and mandrel hanger w/ pup. M/U Floor valve to 7" stump. 1,721.0 1,721.0 2/17/2024 22:00 2/17/2024 23:00 1.00 COMPZN, RPCOMP SFTY P Gather up crew for Safety Standown. Discuss spill and action items to mitigate going forward. Re-focus on upcoming tasks. 1,721.0 1,721.0 2/17/2024 23:00 2/18/2024 00:00 1.00 COMPZN, RPCOMP RURD P RU GBR 7" casing handing equipment and Power Tongs. Finish sucking out Open Top. DTH here to support cleanup and haul Open Top to Wash bay. Clean up Arctic Pack from pit system. Moved open top. Less spill coverage than expected under tank. ACS to come out in the morning to estimate spill volume. 1,721.0 1,721.0 2/18/2024 00:00 2/18/2024 01:15 1.25 COMPZN, RPCOMP RURD P Finish cleaning pits. Clean Open Top before hauling to Wash Bay. 1,721.0 1,721.0 2/18/2024 01:15 2/18/2024 01:30 0.25 COMPZN, RPCOMP SFTY P PJSM before pulling 7" casing string. 1,721.0 1,721.0 2/18/2024 01:30 2/18/2024 02:00 0.50 COMPZN, RPCOMP PULL P Pull 7" casing from cut depth of 1,749' to 1,668'. Joint #6 corkscrewed. See pictures. 1,721.0 1,668.0 2/18/2024 02:00 2/18/2024 03:30 1.50 COMPZN, RPCOMP PULL T GBR Power Tongs Backup Ram broke. R/D broken tongs. Load new tongs to rig floor. 1,668.0 1,668.0 2/18/2024 03:30 2/18/2024 06:00 2.50 COMPZN, RPCOMP PULL P Pull 7" casing from 1,668' to surface. Cut Jt. 19.99' See Pictures 1,668.0 0.0 2/18/2024 06:00 2/18/2024 08:00 2.00 COMPZN, RPCOMP RURD P R/D GBR equipment. Clean and Clear rig floor. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 6/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/18/2024 08:00 2/18/2024 11:00 3.00 COMPZN, RPCOMP CLEN P Pick up stack flushing tool, flush stack from arctic pack circulation // arctic pack plugged up pump in cellar // Blow down lines and stack 0.0 0.0 2/18/2024 11:00 2/18/2024 12:00 1.00 COMPZN, RPCOMP MPSP P Set 11" Test Plug. RILDS on plug, flood lines 0.0 0.0 2/18/2024 12:00 2/18/2024 13:00 1.00 COMPZN, RPCOMP BOPE P Test BOP break to 3,000 psi. Good test rig down test equipment 0.0 0.0 2/18/2024 13:00 2/18/2024 14:30 1.50 COMPZN, RPCOMP CLEN P Clean up floor and move out handling tools 0.0 0.0 2/18/2024 14:30 2/18/2024 18:00 3.50 COMPZN, RPCOMP BHAH P Pick up BHA# 5 Tandem string mill drift BHA // Bring up BHA, too cold for cart bring up BHA over several trips // Make up BHA. Crew C/O. 0.0 130.0 2/18/2024 18:00 2/18/2024 18:30 0.50 COMPZN, RPCOMP TRIP P TIH to ~250' to dress of tight spot. Did not see anything. Continue trip to just above 7" stub. 130.0 1,709.0 2/18/2024 18:30 2/18/2024 19:15 0.75 COMPZN, RPCOMP WASH P Kelly Up. Pump online @ 5 BPM and 231 psi. Wash down to 7" stump @ 1,750.6'. 1,709.0 1,750.0 2/18/2024 19:15 2/18/2024 21:15 2.00 COMPZN, RPCOMP MILL P Obtain Parameters. PUW = 67K, SOW = 69k, RPM = 60, Free Torque = 4.8K, Pump Rate = 5 BPM @ 231 psi. TIH and start dressing off stump @ 1,750.6'. Set 4K down. Torque 5K. PUH. Increase to 80 RPM. Free Torque = 5.9K. Cont. dress off stump to 1,751'. 1,750.0 1,751.0 2/18/2024 21:15 2/18/2024 21:45 0.50 COMPZN, RPCOMP CIRC P After dressing off 7" stub. Pump 30 bbl hi-vis pill. Circulate hi-vis pill out w/ 8.6# SW until returns are clean. Pump Rate = 6 BPM @ 375 psi. 1,751.0 1,751.0 2/18/2024 21:45 2/18/2024 22:00 0.25 COMPZN, RPCOMP OWFF P OWFF. 1,751.0 1,751.0 2/18/2024 22:00 2/18/2024 23:00 1.00 COMPZN, RPCOMP TRIP P TOOH w/ BHA #5 (8 1/2" Tandem String Mills + 8 3/8" Pilot Mill). 1,751.0 130.0 2/18/2024 23:00 2/19/2024 00:00 1.00 COMPZN, RPCOMP BHAH P L/D BHA #5. 130.0 0.0 2/19/2024 00:00 2/19/2024 00:30 0.50 COMPZN, RPCOMP BHAH P Cont. L/D BHA #5. 131.0 0.0 2/19/2024 00:30 2/19/2024 01:00 0.50 COMPZN, RPCOMP BHAH P MU BHA #6 (Burn shoe). 0.0 131.0 2/19/2024 01:00 2/19/2024 03:00 2.00 COMPZN, RPCOMP TRIP P TIH w/ BHA #6 to just above 7" stub. 131.0 1,704.0 2/19/2024 03:00 2/19/2024 03:15 0.25 COMPZN, RPCOMP MILL P Kelly up. Pumps on @ 3 BPM and 90 psi. Wash down to 7" stub. See stub @ 1750.5' PUH. Obtain Parameters. 3 BPM @ 90 psi. Rotary = 10 RPM. Free Torque = 2K. TIH and wash around backside of 7" stub to 1,754'. Set 2K down. SPP = 107 psi. Repeat swallow to confirm clear. Good. 1,704.0 1,754.0 2/19/2024 03:15 2/19/2024 03:45 0.50 COMPZN, RPCOMP CIRC P Pump 30 bbl hi-vis pill. Circ BU. 1,748.0 1,748.0 2/19/2024 03:45 2/19/2024 04:00 0.25 COMPZN, RPCOMP OWFF P OWFF 1,748.0 1,748.0 2/19/2024 04:00 2/19/2024 06:30 2.50 COMPZN, RPCOMP TRIP P TOOH w/ BHA #6 1,748.0 150.0 2/19/2024 06:30 2/19/2024 08:30 2.00 COMPZN, RPCOMP BHAH P L/D BHA #6 150.0 0.0 2/19/2024 08:30 2/19/2024 12:30 4.00 COMPZN, RPCOMP RURD P Clean and clear rig floor get all bha off rig for running 7". Drain Stack. Set 11" Test Plug. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 7/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/19/2024 12:30 2/19/2024 15:30 3.00 COMPZN, RPCOMP RURD P RU testing equipment. Prep rig for BOP test. Load 3 1/2", 4 1/2", and 7" Test Joints. 0.0 0.0 2/19/2024 15:30 2/19/2024 21:30 6.00 COMPZN, RPCOMP RGRP T Unable to get shell test due to leaking HCR kill , replace HCR Kill. 0.0 0.0 2/19/2024 21:30 2/20/2024 00:00 2.50 COMPZN, RPCOMP BOPE P Perform shell test. HCR kill leaking around flange Perform shell test. Passed. Perform weekly BOP test to 250/3000 psi. 0.0 0.0 2/20/2024 00:00 2/20/2024 04:30 4.50 COMPZN, RPCOMP BOPE P Complete weekly BOP test to 250/3000 psi on each component for 5-min. (witness waived by Sean Sullivan). Tested annular w/ 3 1/2" and 7" test joints. Tested UPR w/ 3 1/2" and 4 1/2" test joints. Tested LPR w/ 7" test joint. Test #1: Blinds, MM kill valve, CMV's 4,11,12, 3 1/2" IF Dart, Hyd TD IBOP, and Test spool valve #1. Test #2: Blinds, Kill HCR, CMV's 3,7,9,10, 3 1/2" TIW, TD Manual IBOP, Test spool valve #2. Test #3: Blinds, kill manual, CMV's 2,5,8. RU test hose to test spool. PU 3 1/2" Test Joint. Test #4: UPR, kill manual, CMV's 1,2,5,6, 3 1/2" FOSV. Test #5: Annular, CMV 13. Close manual choke and kill valves. Perform accumulator test. Initial pressure = 2,950 PSI, After closure = 1550 PSI. 200 PSI attained = 24 sec. Full recovery attained = 125 sec. UVBR's = 4 sec, LVBR’s = 4 sec. Annular = 17 sec. Simulated blinds = 4 sec. HCR choke & kill =1 sec each. 4 back up nitrogen bottles average = 1950 PSI. Test gas detectors, PVT and flow show. Pull 3 1/2" test joint. PU 4 1/2" test joint. Test #6: UPR, Kill manual, 4 1/2" FOSV. Pull 4 1/2" test joint. PU 7" test joint. Test #7: LPR's, manual kill, manual choke. Test #8: Annular 3 1/2" TIW. Test #9: Annular, manual kill, choke valve, superchoke. Pressure up to 2,000 psi. Bleed down to 1,000 psi slowly through manual choke. Bleed down slowly to 0 psi through super choke. Witness waived by AOGCC rep Sean Sullivan. 0.0 0.0 2/20/2024 04:30 2/20/2024 07:00 2.50 COMPZN, RPCOMP RURD P R/D testing equipment. Blowdown lines. PT hardline to tanks. 0.0 2/20/2024 07:00 2/20/2024 07:30 0.50 COMPZN, RPCOMP MPSP P Drain Stack. Pull Test Plug. 0.0 2/20/2024 07:30 2/20/2024 11:30 4.00 COMPZN, RPCOMP RURD P Blowdown outside lines and cementer line. R/U GBR equipment w/ Torque Turn. Kickout test joints. RU contingency test spool hardline. MU TIW valve with 7" HYD563 x 3 1/2" IF XO's. 0.0 0.0 2/20/2024 11:30 2/20/2024 16:00 4.50 COMPZN, RPCOMP PUTB P PJSM. Verify 7” Tieback Tally and run order. Run 7” Tieback as per tally to just above the 7" stub. 1 Hydroform centralizer every other joint, 21 total. 0.0 1,745.0 2/20/2024 16:00 2/20/2024 17:30 1.50 COMPZN, RPCOMP HOSO P Space out w/ 2', 10', and 20' pup joints prior to latching 7" stub. MU last full joint and 5' pup to leave cement head approx. 4' off rig floor after latched. 1,745.0 1,745.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 8/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/20/2024 17:30 2/20/2024 17:45 0.25 COMPZN, RPCOMP WASH P Kelly up. With pumps at 1 BPM slowly wash down over 7" stump. Unable to swallow. PUH. Bring rotary on @ 6 RPM. Wash down over 7" stub to 1,754'. Swallow 7" stub and fully locate a1,754'. Set 30K down to confirm swallowed. PU 50K tension (125K on the hook). Good. 1,745.0 1,754.0 2/20/2024 17:45 2/20/2024 19:00 1.25 COMPZN, RPCOMP RURD P R/D 10' pup. R/U testing equipment to 7" casing. Crew change. R/D GBR touque turn 1,754.0 1,754.0 2/20/2024 19:00 2/20/2024 19:30 0.50 COMPZN, RPCOMP PRTS P Pressure test 7" casing. 2500 PSI / 30 min 1,754.0 1,754.0 2/20/2024 19:30 2/20/2024 20:30 1.00 COMPZN, RPCOMP RURD P PJSM, R/D tst equipment. M/U top drive to 7" casing. Pull to neutral weight. Pressure up to 3300 PSI. Observe cement valve shift open. Able to circulate. 1,754.0 1,754.0 2/20/2024 20:30 2/20/2024 21:00 0.50 COMPZN, RPCOMP CIRC P Circulate STS ~160 BBls 8.6 PPG seawater 4 BPM @ 66 PSI 1,754.0 1,754.0 2/20/2024 21:00 2/20/2024 23:15 2.25 COMPZN, RPCOMP RURD P PJSM, R/U to nipple down stack Loosen riser and lift stack 1,754.0 1,754.0 2/20/2024 23:15 2/21/2024 00:00 0.75 COMPZN, RPCOMP WAIT P Phase three called, Set stack back down. Suspend well work 1,754.0 1,754.0 2/21/2024 00:00 2/21/2024 06:00 6.00 COMPZN, RPCOMP T Stand by for Phase 3 weather 1,754.0 1,754.0 2/21/2024 06:00 2/21/2024 12:00 6.00 COMPZN, RPCOMP T Stand by for Phase 3 weather 1,754.0 1,754.0 2/21/2024 12:00 2/21/2024 16:00 4.00 COMPZN, RPCOMP T Stand by for Phase 3 weather 1,754.0 1,754.0 2/21/2024 16:00 2/21/2024 20:30 4.50 COMPZN, RPCOMP NUND P ND BOP. Pull 7" in tension, 50K. Set 7" Slips. NU BOP. 1,754.0 1,754.0 2/21/2024 20:30 2/21/2024 22:00 1.50 COMPZN, RPCOMP RURD P Blow down hard lines, cement line, test spool line. MIRU cementers, M/U cement head on 7" tubing 1,754.0 1,754.0 2/21/2024 22:00 2/21/2024 23:30 1.50 COMPZN, RPCOMP RURD P PJSM with cementers, Load rinsate n trip tank and puill pit. Pull residuale fluid out of uttings box, PT cementers to 4000PSI. 1,754.0 1,754.0 2/21/2024 23:30 2/22/2024 00:00 0.50 COMPZN, RPCOMP CIRC P Cirulate 100 BBls 140° resh water. CEMENT WET @ 23:30, 4 BPM @ 390 PSI 1,754.0 1,754.0 2/22/2024 00:00 2/22/2024 00:15 0.25 COMPZN, RPCOMP CIRC P Continue pumping 140° water 1,754.0 1,754.0 2/22/2024 00:15 2/22/2024 01:00 0.75 COMPZN, RPCOMP CMNT P Start 15.3 PPG cement down 7" tubing, 3.5 BPM, 435 PSI 1,754.0 1,754.0 2/22/2024 01:00 2/22/2024 01:15 0.25 COMPZN, RPCOMP DISP P Pumped 150 BBLs ement. Drop dart. Cementers online with 20 BBl fresh water spacer. 4 BPM @ 602 PSI. 12.3PPG cement at cellar. 1,754.0 1,754.0 2/22/2024 01:15 2/22/2024 01:45 0.50 COMPZN, RPCOMP DISP P 20 BBl fresh water spacer away. Take over displacing seawater with rig pump. Blow down cement lines. At 40 BBls displaced getting 15.3 PPG in cellar samples. Continuous samples @ 15.3 PPG. Dart landed @ 66.7BBls. Full returns through out job. Estimate 65 BBls cement back . 1,754.0 1,754.0 2/22/2024 01:45 2/22/2024 02:45 1.00 COMPZN, RPCOMP RURD P Rig up to blow all lies down from cellar 1,754.0 1,754.0 2/22/2024 02:45 2/22/2024 05:15 2.50 COMPZN, RPCOMP RURD P Fllush rig lines and BOPE with contam pill. Inspect BOPE, Open up LPRs. to clear cement. Clean out trip tank 1,754.0 1,754.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 9/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/22/2024 05:15 2/22/2024 08:30 3.25 COMPZN, RPCOMP WOC P WOC until 08:30 (100 psi C.S.). Load and process 4 1/2" Tubing on ODS. 1,754.0 1,754.0 2/22/2024 08:30 2/22/2024 16:00 7.50 COMPZN, RPCOMP NUND P ND BOP stack. Cut 7" casing. L/D cut joint = 14' long. Break out 5' pup. Kick out 7" cut joint and pup. Kick out GBR 7" Power Tongs. Stand back BOP's above stump. Clean out wellhead. Install 7" pack-offs. 1,754.0 1,754.0 2/22/2024 16:00 2/22/2024 17:00 1.00 COMPZN, RPCOMP NUND P Attempt to install 7" pack-offs. Unsuccessful. Pack Off is over size 1,754.0 1,754.0 2/22/2024 17:00 2/22/2024 21:30 4.50 COMPZN, RPCOMP NUND T Send pack off to machine shop to turn down. continue to process 4 1/2" completion. Load 4 1/2" jewelry. Load 7"test plug 1,754.0 1,754.0 2/22/2024 21:30 2/23/2024 00:00 2.50 COMPZN, RPCOMP NUND P Set 7" packoff, Set dow 15K to get packoff into profile. Run in LDS. Nipple up tubing head 1,754.0 1,754.0 2/23/2024 00:00 2/23/2024 01:30 1.50 COMPZN, RPCOMP NUND P NU new tubing head. Test pack-offs to 3,000 psi/10 min. Nipple up secondary IA valve w/companion flange. 0.0 0.0 2/23/2024 01:30 2/23/2024 09:30 8.00 COMPZN, RPCOMP NUND P Nipple up 11 X 7 1/16 DSA. nipple down flow riser. NU BOP stack. RU trip tank hose. 0.0 0.0 2/23/2024 09:30 2/23/2024 11:00 1.50 COMPZN, RPCOMP PRTS P Set Test Plug. PT BOP break at new Tubing Head to 3,000 psi for 15-min. Troubleshoot leak 0.0 0.0 2/23/2024 11:00 2/23/2024 12:30 1.50 COMPZN, RPCOMP PRTS T Trouble shoot bell nipple tighten flange, 0.0 0.0 2/23/2024 12:30 2/23/2024 13:30 1.00 COMPZN, RPCOMP PRTS P Bleed air from system. Test BOP flange break. Chart 300 PSI for 5-min. 0.0 0.0 2/23/2024 13:30 2/23/2024 14:30 1.00 COMPZN, RPCOMP RURD P RD testing equipment. Drain Stack. Pull Test Plug. Set Wear Ring. Load YJ tools milling tools and drill collars. 0.0 0.0 2/23/2024 14:30 2/23/2024 16:30 2.00 COMPZN, RPCOMP BHAH P PJSM. MU BHA #7 (cement mill). TIH w/ BHA #7. Picking up drill colars. 0.0 305.4 2/23/2024 16:30 2/23/2024 18:00 1.50 COMPZN, RPCOMP TRIP P TIH w/ BHA #7. on 3 1/2DP. to 1694, PUW=63K, SOW=57K 305.4 1,694.0 2/23/2024 18:00 2/23/2024 21:18 3.30 COMPZN, RPCOMP MILL P KU, Wash down to 1700', Start stacking 5K down. Kick on rotary, 60 RPM. 4.5K free torque. 5 BPM @220 PSI. 1,694.0 1,739.0 2/23/2024 21:18 2/24/2024 00:00 2.70 COMPZN, RPCOMP MILL P Continue milling, See some rubber across shaker. Call cement valve at 1739. Try different weights and RPM. Unable to make any footage 1,739.0 1,739.0 2/24/2024 00:00 2/24/2024 01:00 1.00 COMPZN, RPCOMP MILL P Continue milling on cement valve. 60 RPM. 4.5K free torque. 5 BPM @220 PSI. Unable to make footage. 1,739.0 1,739.0 2/24/2024 01:00 2/24/2024 02:30 1.50 COMPZN, RPCOMP TRIP P Trip out to inspect BHA, PUW= 63K, Blow down top drivr. Continue out 1,739.0 305.0 2/24/2024 02:30 2/24/2024 03:12 0.70 COMPZN, RPCOMP BHAH P Lay down collars, Lay down BHA #7. , Clean boot baskets inspect mill. No smoking gun. 305.0 0.0 2/24/2024 03:12 2/24/2024 04:00 0.80 COMPZN, RPCOMP BHAH P M/U BHA #8, 6.125 5 bladed junk mill, Boot baskets X2, bumper sub, jars, and drill collars. Run in one stand. Hose down rig floor. Poor footing 0.0 305.0 2/24/2024 04:00 2/24/2024 05:00 1.00 COMPZN, RPCOMP TRIP P Trip in hole 305.0 1,690.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 10/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/24/2024 05:00 2/24/2024 09:00 4.00 COMPZN, RPCOMP MILL P 1,690', KU. Bring pumps online. 5 BPM @ 175 PSI, PUW=67K, SOW=67K. 50 RPM @ 5.2K FT. Mill from 1,739' through cementer. Saw milling break @ 1,742'. Cont. to mill/wash down to 1,754'. SD to troubleshoot Pumps. Swap to Pump #1. Cont milling cement to 1,886'. Signifciant cement cuttings to surface. SD to clear riser and thaw chute to cutting tank. Cont. to mill cement to top of sand @ 1,948'. 1,690.0 1,754.0 2/24/2024 09:00 2/24/2024 14:00 5.00 COMPZN, RPCOMP MILL P Cont milling cement to 1,886'. Signifciant cement cuttings to surface. SD to clear riser and thaw chute to cutting tank. Cont. milling cement to top of sand @ 1,950'. 1,754.0 1,950.0 2/24/2024 14:00 2/24/2024 14:30 0.50 COMPZN, RPCOMP OWFF P OWFF for 30-min. Pass. 1,950.0 1,950.0 2/24/2024 14:30 2/24/2024 17:00 2.50 COMPZN, RPCOMP TRIP P TOOH w/ BHA #8. At 1,768', drawworks throttle pin sheared. Repaired. Cont. TOOH w/ BHA #8. 1,950.0 305.0 2/24/2024 17:00 2/24/2024 20:30 3.50 COMPZN, RPCOMP BHAH P L/D DC's, BHA #8.. Clean rig floor 305.0 0.0 2/24/2024 20:30 2/24/2024 21:00 0.50 COMPZN, RPCOMP PRTS P PT 7" casing, ES cementer, and casing patch (Post Mill-Out) to 3,000 psi for 10- min. 0.0 0.0 2/24/2024 21:00 2/24/2024 21:30 0.50 COMPZN, RPCOMP BHAH P P/U BHA #9 RFJB w/boot backets 0.0 37.6 2/24/2024 21:30 2/25/2024 00:00 2.50 COMPZN, RPCOMP TRIP P Trip in hole BHA #9 37.6 1,796.0 2/25/2024 00:00 2/25/2024 02:00 2.00 COMPZN, RPCOMP OTHR P Wash F/1798 to 1,957', 5.5 BPM @ 1355 PSI, Recip 1,796.0 1,957.0 2/25/2024 02:00 2/25/2024 03:30 1.50 COMPZN, RPCOMP TRIP P TOOH, PUW=72K 1,957.0 35.0 2/25/2024 03:30 2/25/2024 04:00 0.50 COMPZN, RPCOMP BHAH P At surface, Break down RCJB, Large rubber chunks, Steel half moon pieces. Clean rig floor 35.0 0.0 2/25/2024 04:00 2/25/2024 04:30 0.50 COMPZN, RPCOMP BHAH P M/U BHA #10, RCJB 0.0 35.0 2/25/2024 04:30 2/25/2024 05:30 1.00 COMPZN, RPCOMP TRIP P Trip in hole, BHA #10 (RCJB) 35.0 1,889.0 2/25/2024 05:30 2/25/2024 07:30 2.00 COMPZN, RPCOMP WASH P Kelly up. Obtain parameters. PUW = 70K. SOW = 67K. Pump Rate = 8 BPM @ 1300 psi. Wash sand down to 1,983'. Crew C/O. Cont. washing sand down to 1,983'. 1,889.0 1,983.0 2/25/2024 07:30 2/25/2024 07:45 0.25 COMPZN, RPCOMP OWFF P OWFF. 1,983.0 1,983.0 2/25/2024 07:45 2/25/2024 09:15 1.50 COMPZN, RPCOMP TRIP P TOOH w/ BHA #10 (RCJB). 1,983.0 35.0 2/25/2024 09:15 2/25/2024 12:00 2.75 COMPZN, RPCOMP BHAH P L/D BHA #10. Recovered metal debris and chunks in junk basket. 35.0 0.0 2/25/2024 12:00 2/25/2024 13:00 1.00 COMPZN, RPCOMP SVRG P Service Drawworks. 0.0 0.0 2/25/2024 13:00 2/25/2024 16:00 3.00 COMPZN, RPCOMP WAIT T Found Brake Band Rollers were worn. Machined and adjusted to allow proper brake functionality. 0.0 0.0 2/25/2024 16:00 2/25/2024 16:30 0.50 COMPZN, RPCOMP BHAH P MU BHA #11 (RCJB Run #3) 0.0 35.0 2/25/2024 16:30 2/25/2024 17:30 1.00 COMPZN, RPCOMP TRIP P TIH w/ BHA #11 35.0 1,972.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 11/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/25/2024 17:30 2/25/2024 19:30 2.00 COMPZN, RPCOMP WASH P Kelly up. Obtain parameters. PUW = 70K. SOW = 70K. Pump Rate = 8 BPM @ 1384 psi. Clean debris off top of sand and RBP down to 2013', Circ BU'. 1,972.0 2,013.0 2/25/2024 19:30 2/25/2024 21:00 1.50 COMPZN, RPCOMP TRIP P PUH, Blow down top drive, Trip out, PUW=70K 2,013.0 30.0 2/25/2024 21:00 2/25/2024 21:30 0.50 COMPZN, RPCOMP BHAH P At surface, Break down RFJB. Clean 30.0 0.0 2/25/2024 21:30 2/25/2024 22:00 0.50 COMPZN, RPCOMP BHAH P M/U BHA #12 0.0 17.7 2/25/2024 22:00 2/26/2024 00:00 2.00 COMPZN, RPCOMP TRIP P Trip in well, BHA #12, Spinners drive roller bearing failure on trip in. Continue in with chain tongs 17.7 1,986.0 2/26/2024 00:00 2/26/2024 01:12 1.20 COMPZN, RPCOMP DISP P Displacing well to clear brine. Have latch on plug 1,986.0 2,013.0 2/26/2024 01:12 2/26/2024 01:30 0.30 COMPZN, RPCOMP CIRC P Equalize plug, Circ BU 2,013.0 2,013.0 2/26/2024 01:30 2/26/2024 03:30 2.00 COMPZN, RPCOMP TRIP P S/D pump. RIH past plug set depth to 2049. Kelly down. Blow down top drive. Trip out of hole, PUW=70K 2,013.0 2,049.0 2/26/2024 03:30 2/26/2024 04:00 0.50 COMPZN, RPCOMP BHAH P At BHA, Lay down BHA #12. Recover shallow RBP 2,049.0 0.0 2/26/2024 04:00 2/26/2024 11:00 7.00 COMPZN, RPCOMP SLKL P Slick line on location - MIRU. RIH to catcher @ 6,372'. Latch catcher. POOH. L/D 3.79" OD catcher. Full of scale/debris. MU new 3.70" OD x 36" long bait sub/catcher. RIH and leave 3.70" OD catcher on top of RBP @ 6,372'. R/D Slickline. 0.0 0.0 2/26/2024 11:00 2/26/2024 16:00 5.00 COMPZN, RPCOMP RURD P Clean and clear rig floor. R/D Slickline tools from rig floor. MU new Spinners. Function Test. Load GBR tongs, elevators, and basket. Load 3 extra joint of Drill Pipe to reach stub. 0.0 0.0 2/26/2024 16:00 2/26/2024 17:30 1.50 COMPZN, RPCOMP BHAH P MU BHA #12 (4 1/2" dress off shoe). 0.0 54.0 2/26/2024 17:30 2/26/2024 23:00 5.50 COMPZN, RPCOMP TRIP P Crew C/O. TIH to 4 1/2" tubing stub @ 6,070'. Saw tight spot @ approx. 1,734'. Plan to work string mill across tight spot during TOOH. Cont. TIH to just above tubing stub @ 5,993'. 54.0 6,052.0 2/26/2024 23:00 2/27/2024 00:00 1.00 COMPZN, RPCOMP MILL P TIH w/ last three joint of DP. Screw in TD. Obtain parameters. PUW = 117K. SOW = 95k. Pump Rate = 8 BPM @ 2,040 psi. TIH and find top of stub @ 6,067'. Set 8K down. Repeat setdown. PUH. RPM = 20. Free Torque = 4.7K. TBIH to wash backside of stub. See pressure indicator @ 6,067'. 200 psi bump. Swallow stub to 6,074' (7' swallow). PUH. SD rotation. TIH. Fully locate @ 6,074'. Mark Pipe at floor. 6,052.0 6,074.0 2/27/2024 00:00 2/27/2024 00:30 0.50 COMPZN, RPCOMP CIRC P Pump 30 bbl hi-vis pill. Circ. STS. 6.5 BPM FCP 2000PSI 6,074.0 6,074.0 2/27/2024 00:30 2/27/2024 12:00 11.50 COMPZN, RPCOMP PULD P PJSM to POOH laying down DP. PUW=120K, Perform Kick while tripping @ 2:40 6,074.0 54.4 2/27/2024 12:00 2/27/2024 12:30 0.50 COMPZN, RPCOMP BHAH P Lay down BHA #12 and inspect 54.4 0.0 2/27/2024 12:30 2/27/2024 16:00 3.50 COMPZN, RPCOMP RURD P Clean and clear floor. Rig up to jet stack, Flush stack, Blow down top drive. Drain stack 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 12/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/27/2024 16:00 2/27/2024 17:00 1.00 COMPZN, RPCOMP MPSP P Pull wear ring. Set test plug. 0.0 0.0 2/27/2024 17:00 2/27/2024 18:30 1.50 COMPZN, RPCOMP RURD P R/U testing equipment. Fill BOPE w/ fresh water. 0.0 0.0 2/27/2024 18:30 2/28/2024 00:00 5.50 COMPZN, RPCOMP BOPE P Weekly BOPE test, Tested BOPE at 250/3000 PSI for 5 Min each, Tested annular, UVBR's w/ 4 1/2" test joints. Test blinds rams. Choke valves #1 to #13, upper and lower top drive well control valves. Test 3 1/2" IF FOSV and IBOP. Test 4 ½” EUE FOSV. Test 2" rig floor Demco kill valve MM #13. Test manual and HCR kill valves. Test two ea 2 1/6" gate auxiliary valves below LPR. Test hydraulic and manual choke valves to 1500 PSI and demonstrate bleed off. Test gas detector. Witness waived by AOGCC rep Adam Earl. 0.0 0.0 2/28/2024 00:00 2/28/2024 01:30 1.50 COMPZN, RPCOMP BOPE P Perform weekly BOPE test 250/3000 PSI. Test manual and HCR choke valves. Perform accumulator test. Initial pressure=2920 PSI, after closure=1650 PSI, 200 PSI attained =24 sec, full recovery attained =116 sec. UVBR's= 5 sec, Annular= 13 sec. Simulated blinds= 5 sec. HCR choke & kill= 1 sec each. 4 back up nitrogen bottles average =1920 PSI. PVT and flow show. Witness waived by AOGCC rep Adam Earl. 0.0 0.0 2/28/2024 01:30 2/28/2024 02:45 1.25 COMPZN, RPCOMP RURD P B/D, R/D testing equipment. Drain stack. 0.0 0.0 2/28/2024 02:45 2/28/2024 03:15 0.50 COMPZN, RPCOMP MPSP P Pull test plug. 0.0 0.0 2/28/2024 03:15 2/28/2024 05:00 1.75 COMPZN, RPCOMP RURD P R/U GBR tubing equipment. Verify joint count and jewelry running order. 0.0 0.0 2/28/2024 05:00 2/28/2024 05:30 0.50 COMPZN, RPCOMP SFTY P PJSM w/ GBR, SLB & rig crew on running 4 1/2" Hyd 563 completion. 0.0 0.0 2/28/2024 05:30 2/28/2024 10:00 4.50 COMPZN, RPCOMP PUTB P Run 4 1/2", 13.6#, L-80, Hyd 563 completion per Talley T/ 1449' 4 1/2" Hyd 563 torque turned T/ 3800 Ft/lbs. Best O life Arctic grade dope used. 0.0 1,449.0 2/28/2024 10:00 2/28/2024 10:30 0.50 COMPZN, RPCOMP SVRG P Service top drive. Inspect for leaks. C/O JIC link tilt ram fitting 1,449.0 1,449.0 2/28/2024 10:30 2/28/2024 23:00 12.50 COMPZN, RPCOMP PUTB P Continue in well with 4 1/2" completion to 1814. PUW=55K. RIW=57K. Trip @ 10 FPM past ES Cementer and casing patch. Watching for drag on Es cementer and casing patch 1720 to 1949'. where cement was drilled. 1 to 2K drag around overshot through ES cementer. 2-3K on packer through ES cementer. Back to normal below where top of sand was @ 2013. Cont RIH T/ 5496' saw 2-3K drag. PUW=93K, SOW=75K. K/U circ @ 3 BPM, 135 PSI work past tight spot @ 5496,. Cont RIH T/ 6045'. PUW=99K, SOW=82K. 1,449.0 6,045.0 2/28/2024 23:00 2/28/2024 23:45 0.75 COMPZN, RPCOMP PUTB P Pump @ 3 BPM, 140 PSI. RIH F/ 6045', pressure spike T/ 200 PSI @ 6071'. Shear pins pop @ 6073'. Fully locate @ 6077'. 6,045.0 6,077.0 2/28/2024 23:45 2/29/2024 00:00 0.25 COMPZN, RPCOMP HOSO P L/D joint #145. 6,077.0 6,003.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Page 13/13 1B-08 Report Printed: 3/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/29/2024 00:00 2/29/2024 00:30 0.50 COMPZN, RPCOMP HOSO P L/D joint # 144, M/U 1.84' space out pup. M/U joint #144 T/ 6043'. 6,003.0 6,043.0 2/29/2024 00:30 2/29/2024 01:45 1.25 COMPZN, RPCOMP PULD P P/U landing joint. M/U T/ hanger. M/U T/ sting w/ circ hose on top. 6,043.0 6,043.0 2/29/2024 01:45 2/29/2024 02:45 1.00 COMPZN, RPCOMP CRIH P Reverse 90 Bbls CI seawater chased by 30 Bbls of neat seawater down IA @ 2 BPM, 110 PSI. 6,043.0 6,043.0 2/29/2024 02:45 2/29/2024 03:30 0.75 COMPZN, RPCOMP RURD P B/D circ equipment. Suck out stack 6,043.0 6,043.0 2/29/2024 03:30 2/29/2024 04:00 0.50 COMPZN, RPCOMP PUTB P RIH land hanger. RILDS. End of mule shoe depth @ 6075.63' ORKB 6,043.0 6,075.0 2/29/2024 04:00 2/29/2024 06:00 2.00 COMPZN, RPCOMP RURD P Drop ball & rod. R/U testing equipment. 6,075.0 6,075.0 2/29/2024 06:00 2/29/2024 07:30 1.50 COMPZN, RPCOMP RURD P Crew change, PJSM. Add dump valve to manifold for SOV shear 6,075.0 6,075.0 2/29/2024 07:30 2/29/2024 10:30 3.00 COMPZN, RPCOMP PRTS P Go to set packer per SLB rep. Pressure up on tubing to 1000 PSI. Hesitate 1 minute. Pressure up in 500 PSI increments with one minute in between to 3500 PSI. Hold PT 30 min on chart. Good test. Bleed tubing down to 2000 PSI. Pressure up IA to 3000 PSI. Hold and chart for 30 minutes. Good test. Dump Tubing. Observe SOV shift open 6,075.0 6,075.0 2/29/2024 10:30 2/29/2024 11:00 0.50 COMPZN, RPCOMP CIRC P Break circulation down IA returns out of tubing. 2 BBl/Min @ 670 PSI 6,075.0 6,075.0 2/29/2024 11:00 2/29/2024 11:30 0.50 COMPZN, RPCOMP RURD P R/D tubing side of pressure testing equipment 6,075.0 6,075.0 2/29/2024 11:30 2/29/2024 12:00 0.50 COMPZN, RPCOMP RURD P Lay down landing joint, Set BPV 6,075.0 0.0 2/29/2024 12:00 2/29/2024 12:30 0.50 COMPZN, RPCOMP SEQP P Test BPV 1000 PSI below for 10 minutes 0.0 0.0 2/29/2024 12:30 2/29/2024 13:00 0.50 COMPZN, WHDBOP RURD P Blow down and rig down remaining test equipment 0.0 0.0 2/29/2024 13:00 2/29/2024 13:30 0.50 COMPZN, WHDBOP OTHR P Start emptying pits. Off load 4 1/2 tubular's and GBR tongs from pipe shed 0.0 0.0 2/29/2024 13:30 2/29/2024 15:30 2.00 COMPZN, WHDBOP NUND P Prep BOP for removal. Bleed off air boot. Break DSA X Tubing. Clean cement out of flow box. Nipple down flow nipple 0.0 0.0 2/29/2024 15:30 2/29/2024 17:00 1.50 COMPZN, WHDBOP NUND P Lift stack, Set down on stump. Pull DSA 0.0 0.0 2/29/2024 17:00 2/29/2024 20:00 3.00 COMPZN, WHDBOP NUND P Install tree test dart. N/U adaptor spool & tree. 0.0 0.0 2/29/2024 20:00 2/29/2024 20:30 0.50 COMPZN, WHDBOP PRTS P PT hanger void T/ 5000 PSI for 15 Min. 0.0 0.0 2/29/2024 20:30 2/29/2024 23:00 2.50 COMPZN, WHDBOP RURD P R/U freeze protect & tree testing manifold. 0.0 0.0 2/29/2024 23:00 2/29/2024 23:30 0.50 COMPZN, WHDBOP SFTY P PJSM w/ LRS & rig crew on testing tree & freeze protect. 0.0 0.0 2/29/2024 23:30 3/1/2024 00:00 0.50 COMPZN, WHDBOP PRTS P PT tree T/ 5000 PSI for 5 Min. 0.0 0.0 3/1/2024 00:00 3/1/2024 00:30 0.50 DEMOB, MOVE MPSP P Pull test dart BPV. 0.0 0.0 3/1/2024 00:30 3/1/2024 02:00 1.50 DEMOB, MOVE FRZP P LRS pump 70 Bbls diesel freeze protect down IA @ 2 BPM. ICP=900. FCP=1250. U-tube well for 1 Hr. 0.0 0.0 3/1/2024 02:00 3/1/2024 04:30 2.50 DEMOB, MOVE RURD P B/D, R/D circ manifold. Secure tree & cellar. Take final pressures T/IA/OA = x/x/x. 0.0 0.0 3/1/2024 04:30 3/1/2024 06:00 1.50 DEMOB, MOVE DMOB P Remove auxilary equipment away from rig. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 3/1/2024 Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB (stalled out) 9,341.0 1B-08A 3/13/2024 rogerba Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Pulled SOV, set DMY, Pulled B&R, RHC, Catcher, and RBP. Update tag 1B-08A 3/13/2024 rogerba Notes: General & Safety Annotation End Date Last Mod By NOTE: WAIVERED WELL, IA x OA COMMUNICATION, WATER INJECTION ONLY 8/15/2015 hipshkf NOTE: NEW LATERALS 1B-08AL1, 1B-08AL1-01 7/26/2007 WV5.3 Conversio n NOTE: WELL SIDETRACKED 8/3/1997 WV5.3 Conversio n NOTE: A Sand not perf'd 8/3/1997 WV5.3 Conversio n NOTE: ORIGINAL WELL COMPLETION - MONOBORE INJECTOR 9/21/1981 WV5.3 Conversio n Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 80.0 80.0 65.00 H-40 WELDED SURFACE 10 3/4 9.95 27.7 2,379.0 2,274.2 45.50 K-55 BUTT 7" Tieback 7 6.28 29.5 1,754.0 1,734.4 26.00 L-80 HYD563 PRODUCTION 7 6.28 29.5 8,464.7 6,085.6 26.00 K-55 BUTT WINDOW L1 5 4.00 9,236.0 9,256.0 6,452.5 9.20 LINER A 4 1/2 3.96 6,120.8 9,710.0 6,659.4 12.60 L-80 NSCT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 25.3 Set Depth … 6,075.6 String Max No… 4 1/2 Set Depth … 4,809.8 Tubing Description Tubing – Completion Upper Wt (lb/ft) 12.60 Grade L-80 Top Connection HYD563 ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 25.3 25.3 0.13 Hanger 7.100 Cameron CXS 7 1/16" x 4 1/2" VAM FJL Tubing Hanger, 4" H Profile Camero n CXS 3.795 5,872.9 4,648.3 38.00 Mandrel – GAS LIFT 5.987 4 1/2" x 1" KBG-2 GLM. HYD563 SLB KBG-2 3.860 5,941.4 4,702.5 37.48 Packer 5.873 SLB BluePack Packer 4 1/2" x 7", VAMTOP SLB Bluepac k 3.875 6,005.8 4,753.7 36.92 Nipple - DB 5.207 Camco 3.75" DS-nipple, HYD563, 9CR Camco DB- Nipple 3.750 6,068.5 4,804.0 36.47 Overshot 6.050 Baker Poorboy Overshot (1.5' from fully located) Baker PB Oversho t 4.590 Top (ftKB) 6,069.8 Set Depth … 6,134.9 String Max No… 4 1/2 Set Depth … 4,857.6 Tubing Description Tubing - Production Wt (lb/ft) 12.75 Grade L-80 Top Connection EUE8rdMOD ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 6,092.5 4,823.4 36.30 LOCATOR 5.500 BAKER LOCATOR SUB 3.937 6,095.5 4,825.8 36.28 PBR 4.750 BAKER 80-47 PBR 3.880 6,109.0 4,836.7 36.14 NIPPLE 5.500 BAKER KBH-22 ANCHOR SEAL NIPPLE 3.937 6,109.7 4,837.3 36.13 PACKER 5.875 BAKER FAB 47-40 PERMANENT PACKER 3.937 6,112.9 4,839.8 36.10 BLAST JOINT 5.250 3.937 6,122.6 4,847.6 36.00 LOCATOR 5.250 BAKER GBH-22 LOCATOR 3.875 6,123.6 4,848.5 35.98 SEALS 4.750 BAKER SEAL ASSEMBLY w/10' STROKE 3.875 6,133.9 4,856.8 35.87 TTL 4.500 3.958 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 29.5 29.4 0.15 EMERGENCY SLIPS 11" x 7" Emergency Slips 2/21/2024 7.000 9,019.0 6,343.6 62.49 CTD Liner 1B-08AL1 CTD Liner 7/3/2007 1.920 9,236.0 6,443.3 62.57 WHIPSTOCK FLOW-THRU WHIPSTOCK 7/1/2007 3.750 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 5,872.9 4,648.3 38.00 1 INJ DMY BK 1 0.0 3/6/2024 SLB KBG-2 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 1,738.7 1,720.2 20.78 Collar - Stage 8.270 7" ES Cementer (SN#: 101899235) Halliburto n HES Cementer 6.171 6,120.8 4,846.2 36.01 PBR 5.875 BAKER 80-47 PBR w/SEAL BORE 4.750 9,173.3 6,414.5 62.69 NIPPLE 5.000 CAMCO 'DB' LANDING NIPPLE 3.750 1B-08A, 3/19/2024 1:51:40 PM Vertical schematic (actual) LINER AL1 TOP; 9,019.3- 10,480.0 LINER A; 6,120.8-9,710.0 CTD Liner; 9,019.0 APERF; 9,392.0-9,402.0 RPERF; 9,392.0-9,402.0 RPERF; 9,360.0-9,380.0 IPERF; 9,360.0-9,380.0 IPERF; 9,340.0-9,350.0 RPERF; 9,340.0-9,350.0 APERF; 9,326.0-9,327.0 APERF; 9,322.0-9,323.0 APERF; 9,318.0-9,319.0 APERF; 9,314.0-9,315.0 APERF; 9,310.0-9,311.0 APERF; 9,306.0-9,307.0 RPERF; 9,270.0-9,310.0 WINDOW L1; 9,236.0-9,256.0 WHIPSTOCK; 9,236.0 PRODUCTION; 1,749.0-8,464.7 CATCHER; 6,369.0 PACKER; 6,109.7 Nipple - DB; 6,005.8 Packer; 5,941.4 Mandrel – GAS LIFT; 5,872.9 SURFACE; 27.7-2,379.0 7" Tieback; 29.4-1,754.0 Production String 1 Cement; 29.5 ftKB CONDUCTOR; 29.0-80.0 EMERGENCY SLIPS; 29.5 Hanger; 25.3 KUP INJ KB-Grd (ft) 31.48 RR Date 10/13/198 1 Other Elev… 1B-08A ... TD Act Btm (ftKB) 9,710.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292063501 Wellbore Status INJ Max Angle & MD Incl (°) 64.06 MD (ftKB) 7,148.16 WELLNAME WELLBORE1B-08A Annotation Last WO: End Date 3/1/2024 H2S (ppm) DateComment SSSV: NIPPLE Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 9,270.0 9,310.0 6,459.0 6,477.3 C-4, 1B-08A 12/7/1997 4.0 RPERF 2 1/8" EnerJet DP;180° ph 9,306.0 9,307.0 6,475.5 6,475.9 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0° ph 9,310.0 9,311.0 6,477.3 6,477.8 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0° ph 9,314.0 9,315.0 6,479.1 6,479.6 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0° ph 9,318.0 9,319.0 6,480.9 6,481.4 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0° ph 9,322.0 9,323.0 6,482.8 6,483.2 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0° ph 9,326.0 9,327.0 6,484.6 6,485.0 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0° ph 9,340.0 9,350.0 6,491.0 6,495.5 C-3, 1B-08A 8/31/1997 6.0 RPERF 2 7/8" HSD DP; 60° ph 9,340.0 9,350.0 6,491.0 6,495.5 C-4, 1B-08A 8/12/1997 6.0 IPERF 2 1/2" HSD DP; 60° ph 9,360.0 9,380.0 6,500.1 6,509.1 C-3, 1B-08A 8/31/1997 6.0 RPERF 2 7/8" HSD DP; 60° ph 9,360.0 9,380.0 6,500.1 6,509.1 C-3, 1B-08A 8/12/1997 6.0 IPERF 2 1/2" HSD DP; 60° ph 9,392.0 9,402.0 6,514.6 6,519.1 C-3, 1B-08A 8/31/1997 6.0 RPERF 2 7/8" HSD DP; 60° ph 9,392.0 9,402.0 6,514.6 6,519.1 C-3, 1B-08A 8/12/1997 6.0 APERF 2 1/2" HSD DP; 60° ph 1B-08A, 3/19/2024 1:51:41 PM Vertical schematic (actual) LINER AL1 TOP; 9,019.3- 10,480.0 LINER A; 6,120.8-9,710.0 CTD Liner; 9,019.0 APERF; 9,392.0-9,402.0 RPERF; 9,392.0-9,402.0 RPERF; 9,360.0-9,380.0 IPERF; 9,360.0-9,380.0 IPERF; 9,340.0-9,350.0 RPERF; 9,340.0-9,350.0 APERF; 9,326.0-9,327.0 APERF; 9,322.0-9,323.0 APERF; 9,318.0-9,319.0 APERF; 9,314.0-9,315.0 APERF; 9,310.0-9,311.0 APERF; 9,306.0-9,307.0 RPERF; 9,270.0-9,310.0 WINDOW L1; 9,236.0-9,256.0 WHIPSTOCK; 9,236.0 PRODUCTION; 1,749.0-8,464.7 CATCHER; 6,369.0 PACKER; 6,109.7 Nipple - DB; 6,005.8 Packer; 5,941.4 Mandrel – GAS LIFT; 5,872.9 SURFACE; 27.7-2,379.0 7" Tieback; 29.4-1,754.0 Production String 1 Cement; 29.5 ftKB CONDUCTOR; 29.0-80.0 EMERGENCY SLIPS; 29.5 Hanger; 25.3 KUP INJ 1B-08A ... WELLNAME WELLBORE1B-08A 1B-08A Completion COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Conductor 80 16 Surface 2379 10-3/4 Production 8465 7 26 K-55 Liner 9710 4-1/2 Tubing 6110 4-1/2 COMPLETION 4-1/2", 12.6#, L-80 Hyd563 Tubing to surface 7" Tieback ~ 1754' RKB 4-1/2" KBG-2 gas lift mandrel ~5873' RKB 4-1/2" x 7" Bluepack Max Packer @ 5941' RKB Nipple @ 6006' RKB (3.813" min ID) 4-1/2" Poorboy Overshot ~6069' RKB Baker 80-47 PBR 6096' RKB (3.88" ID) Baker KBH-22 Anchor-Seal Nipple Baker FAB Permanent Packer @ 6110' RKB (4" ID) Blast Joint ~10' length Baker GBH 22 Locator w/ 10' seals 4-1/4" Liner COMPLETION Baker 80-47 PBR 6121' RKB Baker 5"x7" CMC Hanger CTD COMPLETION BTT KB LTP ~9019' MD 2-7/8" Pup CMU Sliding Sleeve w/ 2.313" X-profile 2-7/8" Pup BTT Seal Assembly BTT Liner Deployment Sleeve w/4" GS Profile Surface Casing ~2379' RKB Production Casing 8465' Conductor TOWS ~9236'MD IA OA Tubing Cut ~6070' MD Packer ~6110'MD CTD KB Packer ~9019' MD OOA 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:Al Hansen To:Regg, James B (OGC); Brooks, Phoebe L (OGC); DOA AOGCC Prudhoe Bay Cc:Company Man, Nordic 3; Nordic Calista Rig 3 Tool Subject:KUP 1B-08 2-13-24 AOGCC Date:Thursday, February 15, 2024 10:36:08 AM Attachments:KUP 1B-8 2-13-24 AOGCC.xlsx Some people who received this message don't often get email from al.hansen@nordic-calista.com. Learn why this is important Al Hansen Rig Manager Rig 3 907-440-6928 Cell This information is intended only for the use of the individual (s) or entity (ies) named above and may contain confidential or privileged information. Any unauthorized disclosure, copying, distribution or the taking of any action in reliance on the contents of this transmitted information is strictly prohibited. If you are not the intended recipient or have received this transmission in error, please immediately delete it and any attachments from your system and send me an email confirming that you have not disclosed, copied, or distributed this message and that you have deleted this message and any attachments from your system. .58%$ 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSub m it to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:3 DATE: 2/13/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #11971120 Sundry #323-615 Operation: Drilling: Workover: xxx Explor.: Test: Initial: xxx Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2545 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1P Permit On Location P Hazard Sec.P Lower Kelly 1P Standing Order Posted P Misc.NA Ball Type 1P Test Fluid Water Inside BOP 1P FSV Misc 2P BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 13 5/8"P Pit Level Indicators PP #1 Rams 1 2 7/8" X 5 1/2"P Flow Indicator PP #2 Rams 1 CSO Rams P Meth Gas Detector PP #3 Rams 0 7" Fixed P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 1 3 1/8"P Time/Pressure Test Result HCR Valves 2 3 1/8"P System Pressure (psi)2950 P Kill Line Valves 1 3 1/8"P Pressure After Closure (psi)1600 P Check Valve 0NA200 psi Attained (sec)24 P BOP Misc 2 2 1/16" 5000 P Full Pressure Attained (sec)128 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4@2100 P No. Valves 12 P ACC Misc 0NA Manual Chokes 1P Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result CH Misc 1P Annular Preventer 14 P #1 Rams 4 P Coiled Tubing Only:#2 Rams 4 P Inside Reel valves 0NA #3 Rams 4 P #4 Rams NA Test Results #5 Rams NA #6 Rams NA Number of Failures:0 Test Time:8.5 HCR Choke 1 P Repair or replacement of equipment will be made within days. HCR Kill 1 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 2-12-24 / 04:39 Waived By Test Start Date/Time:2/13/2024 13:00 (date) (time)Witness Test Finish Date/Time:2/13/2024 21:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Brian Bixby Nordic Test with 3 1/2",4 1/2" & 7" Test Joints.Annular Tested with With 3 1/2" & 7" to 3000psi Hansen/Bezold CPAI Erdman/Wiese KRU 1B-08A Test Pressure (psi): gmanager.rig3@nordic-calista.co c3.Companyman@conocophillips Form 10-424 (Revised 08/2022) 2024-0213_BOP_Nordic3_KRU_1B-08A 9 9 9 999 9 9 9 9 9 -5HJJ 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: Pull/Replace Tubing 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? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9710'None Casing Collapse Structural Conductor Surface Intermediate Production Liner A 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 AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng (907) 265-1102 Staff CTD Engineer KRU 1B-08A 6659' 9358' 6499' 2545 None N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: james.j.ohlinger@conocophillips.com AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 6110' MD and 4837' TVD N/A James Ohlinger STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025649 197-112 P.O. Box 100360, Anchorage, AK 99510 50-029-20635-01-00 Kuparuk River Field Kuparuk River Oil Pool ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Kuparuk River Oil Pool TVD Burst 6135' MD 80' 2274' 80' 2379' 6086'8465' 16" 10-3/4" 51' 2351' 9270-9402' 8435' 4-1/2" 6459-6519' 7" Perforation Depth TVD (ft): 11/27/2023 9710'3589' 4-1/2" 6659' Packer: Baker FAB 47-40 Perm Packer SSSV: None Perforation Depth MD (ft): L-80 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:59 am, Nov 15, 2023 Digitally signed by James J. Ohlinger DN: C=US, OU=ConocoPhillips, O=Wells - Coiled Tubing Drlling, CN=James J. Ohlinger, E=James.J.Ohlinger@ cop.com Reason: I am the author of this document Location: Date: 2023.11.14 09:56:37-09'00' Foxit PDF Editor Version: 13.0.0 James J. Ohlinger 323-615 ADL0025648, X VTL 11/16/2023 10-404 SFD BOP test to 3000 psig Annular preventer test to 2500 psig X DSR-11/15/23 X SFD 11/16/2023*&:JLC 11/16/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.11.16 15:29:19 -09'00'11/16/23 RBDMS JSB 111723 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 November 13, 2023 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: James J Ohlinger Staff CTD/RWO Engineer CPAI Drilling and Wells ConocoPhillips Alaska, Inc. hereby submits an Application for Sundry Approval to work over KUP Injector 1B-08 (PTD# 197-112). Well 1B-08 was drilled and completed in 1981, then the well was sidetracked in 1997. In 2007 the CTD laterals were added. It is currently waivered for continued water injection only with known IAxOA communication. If you have any questions or require any further information, please contact me at +1-907-229-3338. The 4-1/2" tubing will be cut above the packer, and removed. The 7" casing will be repaired to re-establish the required barriers for WAG injection. Then the 4-1/2" tubing will be replaced via a poor-boy overshot and stack packer completion. 1B-08A RWO Procedure Kuparuk Injector PTD #197-112 Page 1 of 4 Remaining Pre-Rig Work 1. T-PPPOT and T-POT tests 2. SBHP 3. Set 2.313" X Lock in the CMU ~9045’ MD 4. Open CMU sliding sleeve. 5. Perform CDDT-TxIA to confirm barriers in place and isolating 6. Cut the tubing at ~6070’ RKB in the middle of the 31’ pup between the PBR and CMU sliding sleeve 7. Prepare well within 48 hrs of rig arrival. Rig Work MIRU 1. MIRU Nabors 7ES on 1B-08. 2. Record shut-in pressures on the T & IA. If there is pressure, bleed off IA and/or tubing pressure and complete 30-minute NFT. Verify well is dead. Circulate KWF as needed. 3. Set BPV and confirm as barrier if needed, ND Tree, NU BOPE and test to 250/3,000 psi. Test annular 250/2,500 psi. Retrieve Tubing 4. Pull BPV, MU landing joint and BOLDS. 5. Pull 4-1/2” tubing down to the tubing cut (~6070’ RKB). Cleanout Run 6. Perform a Cleanout run if necessary, based on tubing condition and dress off 4.5” tubing stub if necessary. 7” Surface Casing Subsidence Repair 7. RU E-line: Run caliper & RCBL and log from ~6050’ MD back to surface. Confirm top of cement behind 7” casing; Estimated TOC ~ 4350’ MD (SLB CET Log 10/09/81) 8. Set RBP below TOC, pressure test and perform 30 min NFT, dump 50’ of sand on top of RBP. The tubing will be plugged off with a plug in the top of the CTD liner. 9. RIH with multistring cutter on DP, cut 7” casing above the TOC, POOH and stand back DP 10. Circulate out the Arctic Pack from the OA 11. ND BOPEs, ND tubing head using Hydratight, NU BOP to the casing head a. Can not retest the BOPE at this point. Retest flange break once casing is recovered 12. Spear the 7” casing. POOH and lay down the 7” casing 13. RIH w/ tandem string mills to gauge the 10-3/4” casing for the ES cementer & Sealing Overshot 14. RU casing crew and RIH w/ new 7” casing, ES Cementer, and Sealing Overshot, PT casing to 2500 psi 15. RU cementer and cement 7” x 10-3/4” annulus to surface 16. ND BOPE, pull 7” casing in tension and land in the slips. Cut excess 7” casing with Wachs cutter. 17. NU new tubing head and BOP stock. PT BOPs 18. RIH w/ 6-1/8” bit/mill to TOC, mill through cement. POOH standing back drillpipe. 19. Pressure test the casing to 2500 psi, chart for 30 minutes 20. RIH w/ wash string assembly and circulate out sand on top of RBP. POOH standing back drillpipe. 21. Pull RBP 1B-08A RWO Procedure Kuparuk Injector PTD #197-112 Page 2 of 4 Install 4-½” Tubing Injection String 22. MU 4 ½” completion with poorboy overshot, packer, nipples, and GLMs. RIH to tubing stub 23. Once on depth, circulate CI brine, space out as needed, land hanger, RILDS, drop B&R, and set packer. 24. Pressure test tubing to 3,000 psig for 5 minutes. 25. Pressure test inner annulus to 2,500 psig for 30 minutes on chart. ND BOP, NU Tree 26. Confirm pressure tests, then shear out SOV with pressure differential. 27. Install BPV. 28. ND BOPE. NU tree. 29. Pull BPV, freeze protect well, and set BPV if necessary. 30. RDMO. Post-Rig Work 31. Pull BPV 32. Pull plugs General Well info: Wellhead type/pressure rating: McEvoy Gen I, 5M psi top flange Production Engineer: Dmitry Shchekotov Reservoir Development Engineer: Cody Keith Estimated Start Date: 11/27/23 Workover Engineer: James Ohlinger (265-1102/ James.J.Ohlinger@conocophillips.com) Current Operations: Waivered for continued water injection only with known IAxOA communication. Well Type: Injector Scope of Work: Pull the existing 4-1/2” completion down to the pre-rig tubing cut. Install a new 7” casing to regain all the OA needed for WAG injection. New 4-1/2” tubing will be run from the tubing cut up, with a poor-boy overshot and stack packer. BOP configuration: Annular / Pipe Rams / Blind Rams / Pipe Ram Following subject to change/be updated with pre-rig work: MIT results: MIT-IA Passed 6/6/23 ~ 3300 psi MIT-OA Passed 6/6/23 ~2000 psi IC POT & PPPOT PASSED – 8/30/23 TBG POT & PPPOT PASSED – 01/30/2014 MPSP: 2545 psi using 0.1 psi/ft gradient Static BHP: 3175 psi / 6300’ TVD measured on 8/23/23 1B-08A RWO Procedure Kuparuk Injector PTD #197-112 Page 3 of 4 1B-08A RWO Procedure Kuparuk Injector PTD #197-112 Page 4 of 4 1B-08A Completion COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Conductor 80 16 Surface 2379 10-3/4 Production 8465 7 26 K-55 Liner 9710 4-1/2 Tubing 6110 4-1/2 COMPLETION 4-1/2", 12.6#, L-80 Hyd563 Tubing to surface 4-1/2" xxxx gas lift mandrel ~xxxx RKB w/ SOV 3-1/2" x 7" Packer 4-1/2" x 3-1/2" XO Nipple @ xxxx' RKB (x" min ID) 4-1/2" Poorboy Overshot Baker 80-47 PBR 6096' RKB (3.88" ID) Baker KBH-22 Anchor-Seal Nipple Baker FAB Permanent Packer @ 6110' RKB (4" ID) Blast Joint ~10' length Baker GBH 22 Locator w/ 10' seals 4-1/4" Liner COMPLETION Baker 80-47 PBR 6121' RKB Baker 5"x7" CMC Hanger CTD COMPLETION BTT KB LTP ~9019' MD 2-7/8" Pup CMU Sliding Sleeve w/ 2.313" X-profile 2-7/8" Pup Surface Casing ~2379' RKB Production Casing 8465' Conductor TOWS ~9236'MD IA OA Tubing Cut ~6070' MD Packer ~6110'MD CTD KB Packer ~9019' MD OOA Last Tag Annotation Depth (ftKB)End Date Wellbore Last Mod By Last Tag: RKB 9,358.0 5/31/2017 1B-08A pproven Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Update CTD Liner 1/24/2020 1B-08A fergusp Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.06 Top (ftKB) 29.0 Set Depth (ftKB) 80.0 Set Depth (TVD)… 80.0 Wt/Len (l… 65.00 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 27.7 Set Depth (ftKB) 2,379.0 Set Depth (TVD)… 2,274.2 Wt/Len (l… 45.50 Grade K-55 Top Thread BUTT Casing Description PRODUCTION OD (in) 7 ID (in) 6.28 Top (ftKB) 29.5 Set Depth (ftKB) 8,464.7 Set Depth (TVD)… 6,085.6 Wt/Len (l… 26.00 Grade K-55 Top Thread BUTT Casing Description WINDOW L1 OD (in) 5 ID (in) 4.00 Top (ftKB) 9,236.0 Set Depth (ftKB) 9,256.0 Set Depth (TVD)… 6,452.5 Wt/Len (l… 9.20 Grade Top Thread Casing Description LINER A OD (in) 4 1/2 ID (in) 3.96 Top (ftKB) 6,120.8 Set Depth (ftKB) 9,710.0 Set Depth (TVD)… 6,659.4 Wt/Len (l… 12.60 Grade L-80 Top Thread NSCT Liner Details Top (ftKB)Top (TVD) (ftKB)Top Incl (°)Item Des Com Nominal ID (in) 6,120.8 4,846.2 36.01 PBR BAKER 80-47 PBR w/SEAL BORE 4.750 6,131.5 4,854.9 35.90 HANGER BAKER MCM LINER HANGER 4.250 9,173.3 6,414.5 62.69 NIPPLE CAMCO 'DB' LANDING NIPPLE 3.750 Tubing Strings Tubing Description TUBING String Ma… 4 1/2 ID (in) 3.96 Top (ftKB) 25.3 Set Depth (ft… 6,134.9 Set Depth (TVD) (… 4,857.6 Wt (lb/ft) 12.75 Grade L-80 Top Connection EUE8rdMOD Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 25.325.30.13 HANGER CAMERON GEN 4 TUBING HANGER 4.500 517.1 517.1 0.59 NIPPLE CAMCO 'DB' NIPPLE w/NO GO PROFILE 3.813 6,048.9 4,788.3 36.61 SLEEVE-C BAKER CMU SLIDING SLEEVE w/OTIS SELECTIVE PROFILE (CLOSED 7/26/2007) 3.813 6,092.5 4,823.4 36.30 LOCATOR BAKER LOCATOR SUB 3.937 6,095.5 4,825.8 36.28 PBR BAKER 80-47 PBR 3.880 6,109.0 4,836.7 36.14 NIPPLE BAKER KBH-22 ANCHOR SEAL NIPPLE 3.937 6,109.7 4,837.336.13 PACKER BAKER FAB 47-40 PERMANENT PACKER 3.937 6,112.9 4,839.836.10 BLAST JOINT 3.937 6,122.5 4,847.636.00 LOCATOR BAKER GBH-22 LOCATOR 3.875 6,123.6 4,848.5 35.98 SEALS BAKER SEAL ASSEMBLY w/10' STROKE 3.875 6,133.9 4,856.8 35.87 TTL 3.958 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Des Com Run Date ID (in) 517.0 517.00.59 VALVE 3 1/2" A-1 INJ VALVE (HKS-236, .682" BEAN) ON 3.812" DB LOCK 5/31/2017 0.682 9,019.06,343.662.49CTD Liner 1B-08AL1 CTD Liner 7/3/2007 1.920 9,236.06,443.362.57 WHIPSTOCKFLOW-THRU WHIPSTOCK7/1/2007 3.750 Perforations & Slots Top (ftKB)Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB)Linked Zone Date Shot Dens (shots/ft )Type Com 9,270.0 9,310.0 6,459.0 6,477.3 C-4, 1B-08A 12/7/1997 4.0 RPERF 2 1/8" EnerJet DP;180 deg. ph 9,306.0 9,307.0 6,475.5 6,475.9 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0 deg. ph 9,310.0 9,311.0 6,477.3 6,477.8 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0 deg. ph 9,314.0 9,315.0 6,479.1 6,479.6 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0 deg. ph 9,318.0 9,319.0 6,480.9 6,481.4 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0 deg. ph 9,322.0 9,323.0 6,482.8 6,483.2 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0 deg. ph 9,326.0 9,327.0 6,484.6 6,485.0 C-4, 1B-08A 9/28/1997 1.0 APERF 2 1/8" EnerJet DP; 0 deg. ph 9,340.0 9,350.0 6,491.0 6,495.5 C-3, 1B-08A 8/31/1997 6.0 RPERF 2 7/8" HSD DP; 60 deg. ph 9,340.0 9,350.0 6,491.0 6,495.5 C-4, 1B-08A 8/12/1997 6.0 IPERF 2 1/2" HSD DP; 60 deg. ph 9,360.0 9,380.0 6,500.1 6,509.1 C-3, 1B-08A 8/31/1997 6.0 RPERF 2 7/8" HSD DP; 60 deg. ph 9,360.09,380.06,500.16,509.1C-3, 1B-08A 8/12/1997 6.0 IPERF 2 1/2" HSD DP; 60 deg. phase 9,392.09,402.06,514.66,519.1C-3, 1B-08A 8/12/1997 6.0 APERF 2 1/2" HSD DP; 60 deg. phase 9,392.09,402.06,514.66,519.1C-3, 1B-08A 8/31/1997 6.0 RPERF 2 7/8" HSD DP; 60 deg. ph Notes: General & Safety End Date Annotation 8/15/2015NOTE: WAIVERED WELL, IA x OA COMMUNICATION, WATER INJECTION ONLY 7/16/2009 NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0REV 7/26/2007 NOTE: NEW LATERALS 1B-08AL1, 1B-08AL1-01 1B-08A, 1/24/2020 2:08:53 PM Vertical schematic (actual) LINER AL1 TOP; 9,019.3- 10,480.0 LINER A; 6,120.8-9,710.0 CTD Liner; 9,019.0 APERF; 9,392.0-9,402.0 RPERF; 9,392.0-9,402.0 IPERF; 9,360.0-9,380.0 RPERF; 9,360.0-9,380.0 RPERF; 9,340.0-9,350.0 IPERF; 9,340.0-9,350.0 APERF; 9,326.0-9,327.0 APERF; 9,322.0-9,323.0 APERF; 9,318.0-9,319.0 APERF; 9,314.0-9,315.0 APERF; 9,310.0-9,311.0 APERF; 9,306.0-9,307.0 RPERF; 9,270.0-9,310.0 WINDOW L1; 9,236.0-9,256.0 WHIPSTOCK; 9,236.0 PRODUCTION; 29.5-8,464.7 SEALS; 6,123.6 LOCATOR; 6,122.5 PACKER; 6,109.7 NIPPLE; 6,109.0 PBR; 6,095.5 LOCATOR; 6,092.5 SLEEVE-C; 6,048.9 SURFACE; 27.7-2,379.0 NIPPLE; 517.1 VALVE; 517.0 CONDUCTOR; 29.0-80.0 HANGER; 25.3 KUP INJ KB-Grd (ft) 31.48 Rig Release Date 10/13/1981 1B-08A ... TD Act Btm (ftKB) 9,710.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292063501 Wellbore Status INJ Max Angle & MD Incl (°) 64.06 MD (ftKB) 7,148.16 WELLNAME WELLBORE Annotation Last WO: End Date 6/27/2007 H2S (ppm)DateComment SSSV: NIPPLE MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, July 26, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1B-08A KUPARUK RIV UNIT 1B-08A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/26/2023 1B-08A 50-029-20635-01-00 197-112-0 W SPT 4826 1971120 1800 2293 2296 2282 2285 730 2000 1920 1900 REQVAR P Brian Bixby 6/6/2023 MIT-OA as per AIO 2C.027 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 1B-08A Inspection Date: Tubing OA Packer Depth 950 970 960 960IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB230607095034 BBL Pumped:1 BBL Returned:1 Wednesday, July 26, 2023 Page 1 of 1 9 9 9 9 9 9 9 9 9 99 9 9 9 MIT-OA James B. Regg Digitally signed by James B. Regg Date: 2023.07.26 16:06:02 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, July 26, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1B-08A KUPARUK RIV UNIT 1B-08A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/26/2023 1B-08A 50-029-20635-01-00 197-112-0 W SPT 4826 1971120 3000 2266 2259 2263 2259 760 925 940 940 REQVAR P Brian Bixby 6/6/2023 MIT-IA as per AIO 2C.027 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 1B-08A Inspection Date: Tubing OA Packer Depth 900 3300 3220 3210IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB230607094816 BBL Pumped:2 BBL Returned:2 Wednesday, July 26, 2023 Page 1 of 1 9 9 9 9 9 9 9 9 9 9 9 9 9 9MIT-IA a James B. Regg Digitally signed by James B. Regg Date: 2023.07.26 16:03:49 -08'00' MEMORANDUM TO: Jim Regg �- l/ it,/,zeZ� P.I. Supervisor ' C 6 l FROM: Jeff Jones Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, July 9, 2021 SUBJECT: Mechanical Integrity Tests ConocoPhillips Alaska, Inc. 1B -08A KUPARUKRIV UNIT 1B -08A Src: Inspector Reviewed By: P.I. Supry Comm Well Name KUPARUK RIV UNIT 1B -08A API Well Number 50-029-20635-01-00 Inspector Name: Jeff Jones Permit Number: 197-112-0 Inspection Date: 6/30/2021 Insp Num: mitJJ210701114105 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1B -08A Type Inj � -TVD 4826 Tubing 2350 2350 2360' 2360 — PTD 1971120 Type Test sPT''Test psi 1800 IA 550 630 620_ 620 . �- -- - BBL Pumped: 1 - BBL Returned: j o.9 OA 500 2000 , 1920 - 1890. - - - - Interval REQVAR P/FP Notes: AIO 2C.027; MIT -OA to 1800 PSI. 1 well inspected, no exceptions noted. Friday, July 9, 2021 Page 1 of I MEMORANDUM TO: Jim Regg P.I. Supervisor �� W /(, ze Z-( FROM: Jeff Jones Petroleum Inspector Well Name KUPARUK RIV UNIT IB -08A Insp Num: mitJJ210701124811 Rel Insp Num: NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, July 9, 2021 SUBJECT: Mechanical Integrity Tests ConocoPhillips Alaska, Inc. 1B -08A KUPARUK RIV UNIT IB -08A Src: Inspector Reviewed By: p P.I. Supry— Comm API Well Number 50-029-20635-01-00 Inspector Name: Jeff Jones Permit Number: 197-112-0 Inspection Date: 6/30/2021 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well IB -08A Type Inj LW TVD 4826 - Tubing 2360 2360 2350 - 350 - PTD� — t 1971120 Type Test SPT est psi 3000 IA 520 3300 - 3200 - 3180 BBL Pumped_ 2 iBBL Returned: 1.9 - OA 270 470 — 470 _ 475 Interval REQVAR P/F P J Notes: AIO 2C.027; MIT -IA to max. anticipated injection pressure. Friday, July 9, 2021 Page 1 of 1 MEMORANDUM TO: Jim Regg p� P.I. Supervisor —y `1 7/,; FROM: Lou Laubenstein Petroleum Inspector Well Name KUPARUK RIV UNIT IB -08A IInsp Num: mitLOLI90611081900 Rel Insp Num: State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, June 26, 2019 SUBJECT: Mechanical Integrity Tests ConocoPhillips Alaska, Inc. IB -08A KUPARUK RIV UNIT IB -08A Src: Inspector Reviewed By: P.I. Suprv'R = Comm API Well Number 50-029-20635-01-00 Inspector Name: Lou Laubenstein Permit Number: 197-112-0 Inspection Date: 6/10/2019 Packer Depth Well 1B -08A i—Type Inj w - TVD 482e Tut g PTD 1971120 Type Test s" J' Test psi 3000 IA -- _� BBL Pumped: 2.1 BBL Returned: 2.1 CIA Interval REQVAR P/F P Notes: MIT -IA to maximum anticipated injection pressure per AIO 2C.027 Pretest Initial 15 Min 30 Min A5 Min 60 Min '4a- 2437'437 2.I_^ 500 3310 - 3220 - 3'00 - 710 880 - 880 F80 Wednesday, June 26, 2019 Page I of I MEMORANDUM State of Alaska Initial Alaska Oil and Gas Conservation Commission TO: Jim Re gg 'IAC Z�SI DATE: Wednesday, June 26, 2019 i y P.I. Supervisor "�� SUBJECT: Mechanical Integrity Tests 1800 ConmaPhillips Alaska, Inc. 680 _ IB-O8A FROM: Lou Laubenstein KUPARUK RIV UNIT IB -08A Petroleum Inspector 1940' 191_0 Well Name KUPARUK RIV UNIT IB -08A Insp Num: mitLOL190611082330 Rel lnsp Num: Sire: Inspector Reviewed By: P.I. Supry NON -CONFIDENTIAL Comm API Well Number 50-029-20635-01-00 Inspector Name: Lou Laubenstein Permit Number: 197-112-0 Inspection Date: 6/10/2019 Packer Well IB -08A Type Inj w � TVD PTD 1971120 Type Test sl'T Test psi BBL Pumped: BBL Returned: Interval —REQVAR P/F Notes: MIT -OA to 1800 psi per 20.027 Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min 4826 - Tubing 'IiS - 2438- 2438 _1438 " 1800 IA h00 - 680 _ 700 0.8 OA 720 - 2000- 1940' 191_0 Wednesday, June 26, 2019 Page I of I • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg kr--) DATE: Wednesday,May 03,2017 P.I.Supervisor Sill I J t 7 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1B-08A FROM: Lou Laubenstein KUPARUK RIV UNIT 1B-08A Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 1B-08A API Well Number 50-029-20635-01-00 Inspector Name: Lou Laubenstein Permit Number: 197-112-0 Inspection Date: 4/22/2017 Insp Num: mitLOL170423071221 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1B-08A - Type Inj W- TVD 4826 - Tubing 1 2288 • 2290 • 2287. 2297 - PTD 1971120 " Type Test SPT Test psi 1800 - IA 600 675 _ 680 680 , BBL Pumped: 1 - BBL Returned: I - OA 675 I 1990 , 1910 - 1890, Interval REQVAR P/F P ✓ Notes: MITOA test pressure 1800 psi per 2C.027 SCANNED AUG 2 4 2017 Wednesday,May 03,2017 Page 1 of 1 • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday,May 03,2017 TO: Jim Rp Supervisor 5 I It J t i SUBJECT: Mechanical Integrity Tests P.I.P •,�C(� CONOCOPHILLIPS ALASKA INC IB-08A FROM: Lou Laubenstein KUPARUK RIV UNIT 1B-08A Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 1B-08A API Well Number 50-029-20635-01-00 Inspector Name: Lou Laubenstein Permit Number: 197-112-0 Inspection Date: 4/22/2017 Insp Num: mitLOL170423070813 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1B-08A - Type Inj I W TVD 4826 - Tubing 2290 2291- 2289- 2290- PTD 1971120 - Type Test SPT Test psi 3000 - IA 710 3310 - 3210 - 3200 • BBL Pumped: 1.7 BBL Returned: 1.8 - OA 690 860 - 859 - 857 - Interval REQVAR P/F P Notes: MITIA to MAIP per AIO 2C.027 ✓ SCANNED AUG 2 4 2017 Wednesday,May 03,2017 Page 1 of 1 Wallace, Chris D (DOA) From: NSK Problem Well Supv <n1617@conocophillips.com> Sent: Tuesday, July 14, 2015 5:09 PM To: Wallace, Chris D (DOA) Cc: Senden, R. Tyler Subject: Report of multiple OA bleeds KRU injector 1B-08A (PTD 197-112) 7-14-15 Attachments: 1B-08A schematic.pdf; 1B-08A 90 day TIO 7-14-15.JPG Chris, KRU injector 1B-08A(PTD 197-112) has had the OA bled multiple times over the past several months, with the latest bleed occurring yesterday. The pressure increase currently is believed to be thermally induced. The well has been on MI/gas injection since 5-14-15 and there have been erratic thermal swings with the gas injection, causing the OA to swing as well. This message is to inform you that CPAI intends to monitor the well under heightened scrutiny for 30 days to confirm this theory. CPAI is planning to WAG the well to water injection in the near future. Since water injection temperature is much more stable, we hopefully will be able to eliminate the thermal swings and thus confirm definitively that there is no annular communication present. If communication becomes suspected during the monitor, we will begin the normal round of initial DHD diagnostics to include MITs and packoff testing. A follow-up email will be sent at the conclusion of the monitor period. Please let us know if you disagree. Attached are the schematic and 90 day TIO plot. SCANNED JUL 1 5 2015 1 Well Name 1B-08A Notes: Start Date 4/15/2015 Days 90 End Date 7/14/2015 4000 - 15 WHP Annular • •mmunication Su eill 3500 — OAP 11114 — 14 _ ‘WIT V ' — 13 3000 — 12 2500 — 11 2000 10 73' 1500 — Bd 0. \The/ �_ V� t [ — 80 1000 —•J — 70 500 tb\) )rji — 60 0 50 Apr-15 Apr-15 Apr-15 May-15 May-15 May-15 Jun-15 Jun-15 Jun-1S Jul-1S Jul-15 Jul-15 mxt 111 .41.11.01001.11.111.10411.11.00111 �r-15 Apr-15 Apr-15 May-15 May-15 May-15 Jun-15 Jun-15 Jun-15 Jul-15 Jul-15 Jul-15 Date Let me know if you have any questions Brent Rogers/Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc Desk Phone(907)659-7224 Pager(907)659-7000 pgr 909 2 Pages NOT Scanned in this Well History File XHVZE This page identifies those items that were not scanned during the initial scanning Project. They are available in the original file and viewable by direct inspection. / ~ 7-//~ File Number of Well History File PAGES TO DELETE Complete RESCAN Color items - Pages: Grayscale, halftones, pictures, graphs, charts - Pages: ~C~ Poor Quality Original'- Pages: [] Other- Pages: DIGITAL DATA [] Diskettes, No. [] Other, No/Type 'OVERSIZED [] Logs of vadous kinds Other COMMENTS: Scanned by: sevedy M~red-Daretha Date: ~--~/~ is/,~L~ [3 TO RE-SCAN Notes: Re-Scanned by: Bevedy Mildred Damtha Nathan Lowell Date: /si • • 'iv • • ConocoPh.i l l i ps Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510 -0360 `UL 8201; • June 27, 2011 . ice .. U " i �... a. ,. - a " Commissioner Dan Seamount Alaska Oil and Gas Commission 333 West 7 Avenue, Suite 100 ? �; ;:} 3 Grin . ; 3taa,31ssion Anchorage, AK 99501 1 \ r2- dict Commissioner Dan Seamount: 1 00 Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor. These voids were filled with cement and corrosion inhibitor, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10 -404, Report of Sundry Operations. The cement was pumped on 3/21, 5/9, 5/23 and 5/24, 2011. The corrosion inhibitor /sealant was pumped 6/18, 6/19, 6/20 and 6/21, 2011. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call MJ Loveland or Martin Walters at 907 - 659 -7043, if you have any questions. Sincerely, MJ L veland ConocoPhillips Well Integrity Projects Supervisor • • ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top -off Report of Sundry Operations (10 -404) Kuparuk Field Date 06/27/2011 1A,1B,1E,1L,1Q,1Y PAD Corrosion Initial top of Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name API # PTD # cement pumped cement date inhibitor sealant date ft bbls ft _ gal 1A -03 50029206150000 1810880 r 16" N/A 23" WA 1.7 6/20/2011 1A -04A 50029206210100 2001940 18" N/A 23" _ N/A 2.5 6/20/2011 1A -16RD 50029207130100 1820310 SF N/A 22" N/A 5 6/18/2011 1B -03 50029205880000 1810560 SF N/A 23" N/A 5 6/21/2011 1B -04 50029205950000 1810650 18" N/A 18" N/A 2.5 6/21 /2011 1B -05 50029202370000 1770010 31" 6.40 2'9" 5/24/2011 6 6/21 /2011 1B-07 B -07 50029206160000 1810890 72" 1.00 22" 5/9/2011 2.5 6/21/2011 1B-08A 50029206350100 _ 1971120 18'8" N/A 29" WA 4.5 6/21/2011 1B-09 50029206550000 1811340 SF N/A 23" N/A 5 6/20/2011 1B -10 50029206560000 1811350 SF N/A 23" N/A 6 6/21/2011 1B-12 50029223650000 1930610 13'4" 2.00 24" 5/9/2011 6 6/21/2011 1B -101 50029231730000 2031330 3" N/A 22" N/A 1.7 6/21/2011 1B-102 50029231670000 2031220 _ 11'2" 0.60 36" 5/9/2011 1.7 6/21/2011 1E-05 50029204790000 1800580 _ 19" N/A 19" _ N/A 1.7 6/19/2011 1E-22 50029208840000 1822140 _ 14" _ 1.75 17" 3/21 /2011 1.7 6/19/2011 1E-23 50029208580000 1821840 58' 10.75 2'5" 5/23/2011 3.4 6/19/2011 1E-30 50029208140000 1821390 15'5" , 1.75 I 16" 3/21/2011 2.5 6/19/2011 1E -105 50029232430000 2050060 20" N/A 20" N/A 6 6/19/2011 1L -16 50029212020000 1841810 _ 14'9" 2.00 35" 5/23/2011 6 6/20/2011 1L -18 50029221450000 1910350 SF N/A 18" N/A 2.5 6/19/2011 1Q-24 50029225840000 1951210 7'8" 1.00 12" 5/9/2011 5 6/18/2011 1Y-02 50029209410000 1830590 40'10" 5.00 41" 5/9/2011 8.5 6/18/2011 I MEMORANDUM ~ ~ To: Jim Regg ~ l~ 7~Z~~Z~9 P.I. Supervisor FROM: Jeff Jones Petroleum Inspector • State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday, July 23, 2009 SUBJECT: Mechanical Integrity Tests coNOCOr~,Lirs ni.asxn ~rrc ~ s-osa KUPARLJK RIV iINIT 1B-08A Src: Inspector NON-CONFIDENTIAL Well Name: KUPARUK RN iINIT 1B-08A API Well Number: 50-029-20635-01-00 Inspector Name: Jeff Jones Insp Num: miUJ090706094150 Permit Number: 197-112-0 ~ Inspection Date 6/24/2009 Rel Insp Num: MITOP000002665 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. We~l 1B-08A Type Inj. W T~ 4826 ,i` jA 280 i 2620 2540 2540 P.T.Di 1971120 TypeTest SPT Test psi ~~~ Ot~ ~ 50 i 50 ~ 50 50 -~ Interval Four Yeaz Cycle P~~' Pass TUblrig I 1860 I 1896 I 1854 ( - 1861 - Notes• 4.2 BBLS diesel pumped. 1 well inspected, 2 exceptions noted: the casaco fitting on the injection line is leaking and the solenoid valve on the ~ SVS panel is leaking hydraulic oil. Mr. Colee will address these items. M. ~~. -Fes ~ ~~essz~,~ t ~~ps~' i ~1~(t!('. ; i 1 3~1 _ t ~~~ Thursday, July 23, 2009 Page 1 of 1 ~~~i~~~~ Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Well Job # ~~~,~ JUN ~ ~. 20fl~ Log Description 05/30/08 NO.4732 Company: Alaska Oii & Gas Cons Comm Attn: Christine Mahnke~n 333 West 7th Ave, SuitE~ 100 Anchorage, AK 99501 Field: Kuparuk Date BL Color CD i F-04 11964615 INJECTION PROFILE („+ ,~ ( 05/26/08 1 1 3F-10 11964609 PRODUCTION PROFILE - . ~ ~ jj 05/23/08 1 1 1J-101 11970685 GLS [ C 05/23/08 1 1 iJ-166 11970681 GLS ~ / 05/20/08 1 1 2N-306 11964608 INJECTION PROFILE / ~U (-- 05/22/08 1 1 3K-13 11970688 INJECTION PROFILE - ~ 05/26/08 1 1 B-OSA 11970686 INJECTION PROFILE e - ~( / 05/24/08 1 1 1Y-11 11964613 INJECTION PROFILE Itj - / /(8~L} 05/25/08 1 1 3K-19 11964616 INJECTION PROFILE U"' ci 05/27/08 1 1 • Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. MEC~iANICAL INTEGRITY REPORT °~ ~; SPUD DATE : ~r~ ~~~ `~ RIG RELEASE : ~~, ~~' ~- i ~-rr ~. OPER ~ FIELD '"~'~. c:,~ WELL NUMBER WELL DATA TD : ~ ~ ~ ~ MD ~ TVD ; PBTD :_rIDTVD Casing: ~ ~,~ ~, Shoe: €33S MD TVD; DV: MD -TVD Liner : ~,~ ~~,6 Le Shoe :~ ~$ MD TVD f TOP : ~MD TVD Tubing: ~=a~' Packer ~~~~ MD TVD; Set at ~~~~" . Hole Size ~~, ~. ~-~ and ; Perfs ~~~ to ~'~~~ MECHANICAL INTEGRITY - PART ~1 `~'`'~~~~`' °~~~ ~' ~ ~~~~ Annulus Press Test: IP ; 15 min = 30 min Comments: i MECHANICAL INTEGRITY - PART ~2 Cement Bond Log (Yes or No); In AOGCC File P ~._ CBL Evaluation, zone above perfs '~~- ~~~-~.~~; .c~¢ ,f,~ t' ~ F k ( / {.°~trL^( dua..~ ~o r.i-°'F `c.e`°-z C-~SS~: w-""--' ~~,.t*T? .,. ~S Production Log: Type ; Evaluation CONCLUSIONS: Part ~1: Part #2: <~`t~ ~' ~s~~-~~,~_~ ti.- , ~s s € Cement Volumes: Amt, Liner Csg ~ ~ ~..j DV Cmt vol to cover perfs Theoretical TOC ~' rev. 05/20/87 C.028 ~ ~(~ ~ a~,~~- Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Well Job # NO.4482 ~~ '~ Company: Alaska Oit & Gas Cons Comm ,~ Attn: Christine Mahnken y ,'4~1.1~f ~~~ ~ ~ ~~~~ 333 West 7th Ave, Suite 100 ~`~~ Anchorage, AK 99501 Field: Kuparuk Log Description Date BL Color CD 11 /07/07 3J-10 11850465 SBHP SURVEY j ~ 10131/07 1 1B-08A 11839682 INJECTION PROFILE Z, - 10131/07 1 1 D-01 11846458 LDL - 11101107 1 2A-15 11846459 PRODUCTION PROFILE 5 - 'L (o _ 11/02/07 1 1E-02 11850470 PRODUCTION PROFILE '$ °(~5 11/04/07 1 2N-310 11745242 SCMT _ 11/04/07 1 1E-119 10687772 OH LDWG EDIT ~ Y 04/08/04 1 1 E-119 10687772 CMR ~pL - 04/08/04 1 1E-119 10687772 MDT 04/08/04 1 • • Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. -- MEMORANDUM • TO: Jim Regg -7 P.I. Supervisor ~~( ~ ~2~1~~ FROM: John Crisp Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commis DATE: Thursday, September 27, 2007 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1 B-08A KUPARUK RIV UNIT IB-OSA Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv ~~? Comm Well Name: KUPARUK RN UNIT IB-08A API Well Number: 50-029-20635-01-00 Inspector Name: John Crisp Insp Num: mitJCr070925134713 Permit Number: 197-112-0 Inspection Date: 9/25/2007 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well '~ IB-osA Type Inj. ~'~ ~ TVD ~ as3s ~~ IA ~I ll9o 2soo ~ I z45o I zaao 'I P.T. 19?1120 TypeTeSt SPT ~I TCSt pSl I 1500 •~QA I 430 i 430 ' 430 430 ~' Interval ~T~- P/F P '' Tubing ~ ~ I?so I?so ~ 1?so 1 1?so _ Notes: 1 bbl pumped for test. ~~L~ii`Ct7~~ 14~~ S. ~ L.~~~ Thursday, September 27, 2007 Page 1 of I . . WELL LOG TRANSMITTAL ProActive Diagnostic Services, Inc. To: AOGCC Howard Okland 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907) 659-5102 RE: Cased Hole/Open Hole/Mechanical Logs and/or Tubing Inspection(Caliper / MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by retuming a signed copy of this transmittal letter to the attention of : ProActive Diagnostic Services. Inc. Attn: Robert A. Richey 130 West Intemational Airport Road Suite C Anchorage. AK 99518 Fax: (907) 245-8952 1) 2) 3) 4) 5) U I c.- I 0, 1- - II d- ¢ I 5"0'-/3 1 Report / EDE 18 - 08A Caliper Report 15-ApF'-07 SCANNED APR 2 0 2007 6) 7) RECEIVED Print Name: Œ_U J_0rì6t)v¡a_ MO{;¡IA {¿-e.l~ Date : '~Ofl & Gas Coos. Commission Aìl~ APR 1 9 Z007 Signed: PROAcTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-8952 E-MAIL: PDSANCHORAGE@MEMORYLOG.COM WEBSITE: WWW.MEMORYLOG.COM D:\Master _Copy- 00_ PDSANC-2OxxIZ _ Word\Dis1ribution\Transmittal_ SheetslTr.u1smit_ Original.doc I I I I I I I I I I I I I I I I I I I . . Memory Multi-Finger Caliper Log Results Summary Company: Log Date: Log No. : Run No.: Pipe1 Desc.: Pipe1 Use: ConocoPhilJips Alaska, Inc. April 15, 2007 7153 1 4.5" 12.6 lb. L-80 Tubing & Liner Well: Field: State: API No.: Top Log Intvl1.: Bot. Log Intvl1.: 1 B-08A Kuparuk Alaska 50-029-20635-01 Suñace 9,310 Ft. (MD) Inspection Type: COMMENTS: Co"osive & Mechanical Damage Inspection This caliper data is tied into "DB" Nipple @ 9,173' (Drillers Depth). This log was run to assess the condition of the 4.5" tubing and liner with respect to internal corrosive and mechanical damage. The recordings indicate the 4.5" tubing and liner is in good to fair condition with respect to corrosive damage (excluding the perfs.), with a recorded maximum wall penetration of 40% in joint 252 at 7,959'. Penetrations ranging 20% to 40% are recorded in 174 of the 306 joints logged. The damage appears in the forms of lines of corrosion, isolated pitting, and general corrosion. A 32% cross-sectional wall loss is recorded in the perforation interval in joints 295 (9,284') and 294 (9,268'). Deposits are recorded in joints 295 and 296, with a recorded minimum 10 of3.71" at 9,307'. Cross-sectional drawings of the most significant events recorded are included in this report. The distribution of maximum recorded penetrations is illustrated in the Body Region Analysis Page of this report. A graph illustrating the correlation of recorded damage to borehole profile is included in this report. MAXIMUM RECORDED WALL PENETRATIONS: Perforations ( 65%) Jt. 295 @ 9,296 Ft. (MD) Perforations ( 59%) Jt. 294 @ 9,268 Ft. (MD) Line Corrosion ( 40%) Jt. 252 @ 7,959 Ft. (MD) Line Corrosion ( 39%) Jt. 203 @ 6,453 Ft. (MD) Line Corrosion ( 37%) Jt. 198 @ 6,305 Ft. (MD) MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: Perforations ( 32%) Jt. 294 @ 9,268 Ft. (MD) Perforations ( 32%) Jt. 295 @ 9,284 Ft. (MD) No other areas of significant cross-sectional wall loss (>10%) are recorded. MAXIMUM RECORDED ID RESTRICTIONS: Deposits Minimum 10 = 3.71" Jt. 296 @ 9,307 Ft. (MD) No other significant 1.0. restrictions are recorded. I Field Engineer: Wm. McCrossan Analyst: M. Tahtouh Witness: T. Senden I ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 REC EIVED Phone: (281) or (888) 565-9085 Fax: (281) 565-1369 E-mail: PDS@memoryìog.com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2314 APR 1 9 Z007 U:LC- 10,7--//;} tJ: lS-ó43 Alaska Oil & Gas Cons. COß'IØIIs8ion Anchorage I I I 1 ß..OBA Kuparuk Wen: Field: Company: Country: Alaska, Inc. USA I Tubing: Nom.OD 4.5 ins Weight 12.6 f Grade & Thread L-80 I Penetration and Metallo!>!> (% I metal loss I 250 200 150 100 50 0 o to 1% 1 to 10% 10 10 20 to 40 to over 20% 40% 85% 85% I I I o o I Damage 250 200 I 150 100 I 50 o I Isolated pìttìng general line ring corrosion corrosion corrosion o I I I I I Survey Date: Tool Type: Tool Size: No. of Fingers: Anal st: Nom.ID 3.958 ins 15,2007 MFC UW 40 No. 210357 2.75 40 M. Tahtouh Nom. Upset 4.5 ins Upper len. 6.0 ins Lower len. 6.0 ins Damage Profile (% metal loss 50 100 193 291 Bottom of Survey = 296 Analysis Overview page 2 I Correlation of Recorded Damage to Borehole Profile I Pipe 1 4.5 in (-1.1' - 9304.5') Well: Field: Company: Country: Survey Date: 1ß..08A Kuparuk ConocoPhíllips Alaska, Inc. USA April 15, 2007 I I I Approx. Tool Deviation Approx. Borehole Profile I 3 25 783 50 1568 75 2354 100 3141 125 3928 150 4711 ID 175 5497 -D .,.; E LL.. :::J ¡: Z ..... 200 6352 c ,) 225 7121 250 7888 275 8651 296 9304 0 50 100 Damage Profile (% wall) / Tool Deviation (degrees) I I I I I I I I I I I Bottom of Survey = 296 I I I REPORT JOINT LATION S I Pipe: Body Wall: Upset Wall: Nominal I.D.: 4.5 in 12.6 ppf 1.-80 0.271 in 0.271 in 3.958 in Well: field: Company: Country: Survey Date: 1 B-08A Kuparuk ConocoPhillips Alaska, Ine. USA April 15, 2007 I I I Joint Jt. Depth Pen Pen. Pen. ¡'·vletal Min. i> -0' Profile No. LD. Comments (%wall) ) (ins.) (ins.) 0 50 100 .1 -1 () 0.01 4 mit PUP 1 3 ( 0.03 1 3.88 Shallow oittin2. 1.1 36 ! 0.01 . 1'1)1' 2 47 ! 0.02 3 76 () 16 0.03 11 3.91 Pittino in unset 4 111 () ){) 0.02 1 3.89 Pittinll in uoset. 5 142 ( ~1 I 3.89 6 174 ! I 3.88 7 20'S ( 0.031) ¡ 3.86 Shallow niHin"'. Ii 8 237 ( 0.ü3 () I 3.89 Ii 9 268 ! 0.02 ) 3.88 10 300 ! 0.02 ~3.89 Ii 11 331 ! 0.02 3.89 12 363 () 0.03 I 3.88 ~ () 0.02 7 1 3.87 Lt. Denosí ts. Ii 14 ~ () 0.02 6 I 3.86 II 0 0.03 In I 3.86 . nittin"'. Ii 15.1 489 0 0.02 l' I 3.89 PUP Iii 15.2 495 () 0 ! () 3.81 DB NIPPLE 16 501 0 0.ü3 HJ ¡ 3.87 Iii 17 533 () 0.02 I 3.87 18 564 !í 0.ü2 7 I 3.88 I 19 596 !í 0.03 10 I 3.87 Iii 20 627 0 0.03 1 ;; 3.85 II 21 657 0 0.04 I 3.86 Shallow nittin"'. Iii ! 22 689 (LOB 0.04 I 3.88 Shallow oíttinq. Iii 23 720 ! 0.03 , 3.87 Iii 24 752 ( 0.04 ! 3.87 Shallow oittirn!:. 25 783 ( 0.02 ) 3.85 26 812 ( 0.03 II I I 3.87 Shallow oittímt Ii 27 844 ! 0.02 ) 3.87 !II 28 875 0 0.03 10 ) 3.85 II 29 907 0 0.03 10 I 3.8H III 30 938 0 0.02 l' ) 3.87 31 970 0 O'W I 3.87 32 1001 0 0.03 I 3.87 33 1033 0 0.0 (, I 3.89 34 1064 0 0.02 7 I 3.86 35 1095 !í 0.02 (, 1 3.88 36 1127 0 0.03 1 ¡ 3.88 Lt. Deoosits. II 37 1159 ( 0.04 I 188 Shallow nittin"'. II 38 1190 0 0.02 ) 3.87 39 1221 () 0.02 ) 3.90 40 1253 0 0.02 I 3.87 41 1284 !í 0.04 S 1 3.87 Shallow oittinll. 42 1316 !í 0.04 16 I 3.88 Shallow oittím.. 43 1347 () 0.04 1 I 3.87:=1 Shallow nittín<>. 44 1379 0 0.03 I 2 3.87 ' nittinq. 45 1410 () 0.04 ! ¡ 3.87 Shallow nitÛrm. 46 1442 () 0.01 t; ! 3.87 I Lt. Deoosits. I I I I I I I I I I I I Body Metal Loss Body Page 1 I I PDS REPORT JOINT EET I I I Pipe: BodyWali: Upset Wall: NominaII.D.: 4.5 in 12.6 ppf L-80 0.271 in 0.271 in 3.958 in Well: Field: Company: Country: Survey Date: 1B..Q8A Kuparuk ConocoPhíllips Alaska, Inc. USA April 15,2007 I Joint Jt. Depth Pen Pen. Pen. Me:al Min. Damag e Profile No. iPse;: Body I.D. Comments ('Yo wali) (Ins.) (Ins.) 0 50 100 47 1473 n om :) I 3.85 Shallow nittinq. Lt. Denosits. 48 1505 n O.fn 1 1 3.87 49 1536 n 0.02 1 3.87 50 1568 n 0.02 I 3.87 51 1599 n 0.03 1 3.87 Shaliow oitlin"'. 11 52 1631 n 0.03 I 3.88 !f!!J 53 1662 () 0.03 I 3.87 Shallow oittin". 11 54 1694 0 0.03 1 3.87 11 55 1725 n 0.04 13 3.87 Shallow nittin<>. 11 56 1757 ) 0.03 1 3.86 Iì 57 1788 n 0.03 3.87 II 58 1818 n 0.03 3.86 59 1850 0 0.02 3.85 60 1881 n 0.03 I ~ 61 1913 n 0.03 I Shaliow nittin<>. 62 1944 n 0.03 'I ;; 3.85 Shallow nittinº. 6'{ 1976 n 0.02 ¡: 3.86 64 2007 n 0.03 ) 3.85 65 2039 () 0.02 ¡ 3.85 66 2070 n 0.02 1 3.88 67 2101 ) 0.02 3 3.87 68 2133 () 0.03 q 1 3.86 I 69 2165 {) 0.04 14 1 3.86 Shallow corrosion. 70 2196 {) 0.02 ß 3 3.86 71 2228 n 0.04 l' I 3.87 Shallow nittirw. 72 2259 n 0.04 I" I 3.87 Shallow oittinq. 73 2291 n 0.03 í 3.85 Shallow oittinll. 74 2322 0 0.03 : 3.88 75 2354 0 0.03 ) 3.86 Line of shallow nits. 76 2385 0 0.04 3 3.86 Line of shallow nits. 77 2417 0 0.03 C : 3.86 78 2449 () 0.04 :4 :2 3.86 Line of shaliow nits. 79 2480 0 0.03 1 ) 3.86 Line of shallow oits. 80 2512 0 0.03 1 I 3.85 Line of shallow nits. 81 2543 II Œ I 1 3.86 Line of shallow oits. 82 2575 0 )1 ) 3.86 Line of nits 83 2606 () 0.04 II ) 3.86 Line of shallow nits. 84 2638 0 0.04 1 ;: 3.86 Line of shallow oits. Lt. Deoosits. 85 2669 0 0.05 } 3.86 Line of shallow nits. 86 2701 J 0.04 3.85 Line of shallow nits. 87 2732 () 0.04 3.85 Line of shallow nits. 88 2764 0 0.05 3.85 Line of shallow nits. 89 2795 () 0.04 3.84 Line of shallow nits. 90 2827 0 0.05 I 3.86 Line of shallow oits. 91 2858 I 0.04 3.85 Line of shallow nits. U. Deoosits. 92 2890 ( 0.05 1 3.85 Line of shallow nits. 93 2921 ( 0.05 2C 3.85 Line corrosion. Lt. Denosits. 94 2953 ( 0.04 1 3.86 Line shallow corrosion. 95 2984 0.05 (' 3.85 line shallow corrosion. 96 3016 () 0.04 II 3.86 Line shallow corrosion. U. Denosits. I I I I I I I I I I I I I Body Metal Loss Body Page 2 I I I PDS REPORT INT LATION 5 I I Wall: Upset Wall: Nominal 1.0.: 4.5 in 12.6 ppf l-80 0.271 in 0.271 in 3.958 in Well: Field: Company: Country: Survey Date: 1B-08A Kuparuk ConocoPhillips Alaska, loe. USA April 15, 2007 I Joint Jt. Depth Pen Pen. F'en. Melal Min. n~~~:;= P rofile No. Body !.D. Comments wal I) (Ins.) (Ins.) (Ins.) 0 50 100 97 3047 :J 0.05 21 3.85 line shallow corrosion. 98 307R 0 0.05 II 3.85 Line shallow corrosion. 99 '1110 ~ ) 0.05 3.85 Line shallow corrosion. 100 3141 I ~~ 3.84 Line corrosion. 101 3173 I 3.83 line corrosion. 102 3204 0, II, O. 3.85 Line corrosion. 103 3236 0.05 3.84 Line shallow corrosion. 104 3267 I 0.05 3.84 Line shallow corrosion. 105 3299 ¡ 0.05 51 3.85 Line corrosion. 106 3330 ( 0.06 3.84 line corrosion. 107 3361 n 0.06 ¡ 4 3.85 Line corrosion. 108 3393 0 0.06 4 3.83 Line corrosion. 109 3424 0 m 5 3.82 Line shallow corrosion. Lt. Denosi ts. 110 3456 n 0.0 4 3.85 Line shallow corrosion. U.Denosíts. 111 3487 [) 4 3.85 Line shallow corrosion. 112 3519 [) 0.06 4 3.85 Line corrosion. 113 3550 ¡) 0.08 H 4 3.85 Corrosion. 114 3582 :) 0.05 3.85 Corrosion. 115 3613 0 0.07 3.85 Isolated oittim!. 116 3644 0 0.06 '1 3.84 Corrosion. 117 3676 007 0.07 7 F 3.85 Corrosion. 118 3707 ( 0.07 S 4 3.85 Corrosion. 119 3739 0.08~ 4 3.85 Corrosion. It. Denosits. 120 3770 0.06 10 3.84 Line corrosion. U. Denosits. 121 3802 0.06 T '1.81 line mrrosion. It. Denosits. 122 3833 0 0.04 If 3.84 Line shallow corrosion. 123 3865 0 0.05 3.83 Line shallow corrosion. It. Denosits. 124 3896 0 0.07 3.84 line corrosion. U.Deoosits. 125 3928 o 17 fì 06 3.83 Line corrosion. 126 3959 1 0.05 3.82 Line shallow corrosion. Lt. Deoosits. 127 3990 ( 0.05 3.84 Line shallow corrosion. 128 4022 ( 0.06 ') 3.84 Line corrosion. U. Denosits. 129 4053 ¡ 0.08 ! 3.85 Line corrosion. 130 4085 006 0.06 3.84 Line corrosion. 131 4116 0 0.06 3.85 Line corrosion. 132 4147 C 0.06 3.84 Line corrosion. 133 4179 C 0.09 7 3.84 Line corrosion. / 134 4211 C 0.09 4 3.82 Line corrosion. U. Denosits. 135 4242 n( H, 0.06 I) 3.83 Line corrosion. 136 4273 tI§j07 >4 3.81 line corrosion. 137 4304 C 06 1 '184 line corrosion. 138 4335 o 06 3.84 Line corrosion. 139 4366 [) 0.07 If 3.84 line corrosion. 140 4397 0 0.06 3.84 Line corrosion. 141 4429 ( 0.07 3.83 line corrosion. U. Dennsi ts. 142 4460 ( 0.05 ( 3.83 line corrosion. 141 4492 I 0.07 3 3~ Line corrosion. 144 4523 ( 0.08 ·,(1 4 3. line corrosion. 145 4554 I 0.07 27 ,"Í 3.84 Line corrosion. 146 4585 0 0.07 7S :¡ 3.83 I line corrosion. I I I I I I I I I I I I Body Metal Loss Body I Page 3 I I I JOINT TABULATION SH I I Pipe: Body Wall: Upset Wall: NominaILD.: 4.5 in 12.6 ppf 1.-80 0.271 in 0.271 in 3.958 in Well: Field: Company: Country: Survey Date: 1 B·OM Kuparuk Alaska, Ine. USA April 15, 2007 I Joint Jt. Depth Pe Pen. PerL Metal Min. .,~~ .~.~ P rofile No. '1 Body !.D. Comments wall) (Ins.) (Ins.) 0 50 100 4617 0 06 ~"~on 148 4648 0 06 3.83 rrosion. 149 4680 0 06 mrroslon. 150 4711 0 07 Line corrosion. 151 4743 24 4 3.82 Line mrrosion. 152 4774 4 3.82 Line mrrosion. 153 4806 4 3.82 Line mrrosÎon. 154 4837 0 0.07 3.84 Line mrrosion. 155 4869 0 0.07 ~ Line mrrosion. 156 4900 0 0.06 Line corrosion. U. Denosits. 157 4930 0 0.07 158 4963 í 0.07 3.82 Line mrrosion. 15911'" 0.07 26 6 3.81 Line corrosion. 160 í 0.07 26 3.80 Line corrosion. Lt. Dennsits. 161 ~ =;=t23 3.82 Line corrosion. 162 3.83 Line corrosion. 163 0 3.83 Line mrrosion. 164 ( 0.07 3.81 Line mrrosion. 165 5183 0.07 3.83 Line mrrosion. 166 5215 0.07 3.82 Line corrosion. 167 5246 0.06 I 21 4 3.80 Line mrrosion. U. Denosi ts. 168 5277 0.07 2' 3.79 Line mrrosion. 169 5309 i=il07 f 3.80 Line corrosion. 170 5340 .06 l 3.81 Line mrrosion. 171 5372 U 0.08 3.80 Lin'" corrosion. I.t Dennsits. 172 5403 U 0.06 3.81 Line mrrosion. 173 5434 0 0.08 3.82 Line corrosion. 174 5466 0 0.07 3.81 Line corrosion. 175 5497 0 0.06 4 3.82 Line corrosion. 176 5528 D 0.06 2¿ 4 3.83 Line corrosion. 177 5560 D 0.06 3.81 I ¡op mrrosion. 178 5592 D 0.07 3.81 Line corrosion. U. Dennsits. 179 5623 [) 0.08 3.81 Line mrrosion. 180 5653 0 ~ ¿ 3.81 Line corrosion. Lt. Denosits. 181 5684 0 3.81 Line corrosion. L t. Denosi ts. 182 5715 0 0.07 ill 3.82 Line mrrosion. 183 5747 () 0.10 3.80 Line mrrosÎon. 184 5778 0 0.07 2 3.80 Line mrrosion. It. DenosÎts. 185 5810 OOS 0.07 3.80 Line corrosion. 186 5841 0 0.07 3.ß1 Line corrosion. 187 5873 0 0.07 3.81 Line mrrosÎon. 188 5904 0 0.06 3.80 Line mrrosion. 189 5936 n 0.08 . i.ß1 Line corrosion. 190 i 5967 0 0.08 i 3.79 I ine corrosion. 191 5998 0 0.08 tt¡4 3.80 Line corrosion. 191.1 6029 0.06 3.80 PUP Line corrosion. 191.2 6035 0 í N/A SLIDING SLEEVE 191.3 6038 0.05 3.74 PUP Shallow nittinQ. U. Denosits. 192 6041 0.06 3.78 Line corrosion. It Denn5Íts. 192.1 6072 ( 0.06 3.81 PUP Line corrosion. U. Denosits. I I I I I I I I I I I I Body Metal loss Body I 4 I I I PDS REPORT JOINT TABU EET I I Pipe: Body Wall: Upset Wall: NominaII.D.: 4.5 in 12.6 ppf 1.-80 0.271 in 0.271 in 3.958 in Well: Field: Company: Country: Survey Date: 1B..(J8A Kuparuk ConocoPhi!lìps Alaska, Ine. USA April 1 5, 2007 I I Joint Jt Depth I'en Pen. Pen. Metal Min. Damage Pr ofile No. (Ft.) \;;)5';1 Body 1.0. Comment.,> (%wall) (Ins.) (Ins.) 0 50 100 192.2 6079 n 0 n (I N/A PBR ASSEMBLY I Corrosion. \ 192.3 6092 0 0 0 0 N/A PACKER 192.4 6100 +++ 0.05 19 'j 3.73 PUP Shallow nittìna. Lt. Denosits. 192.5 6110 0.06 3.74 PUP Isolated nittina. Lt. Denosits. 192.6 6122 0 0 I N/A SEAL ASSEMBLY (Corrosion.S 192.7 6134 0.04 3.91 PUP Shallow corrosion. 193 6139 0.10 3.90 Line corrosion. Lt. Deoosits. 1st It. of liner. 194 6169 0 I') 0.09 3.90 Line corrosion. Lt. Deoosits. 195 6200 0.09 IS ¡j 3.89 Line corrosion. 196 6230 0.07 2'1 ··1 3.91 Line corrosion. 197 6261 0 0.09 34 ¡j 3.89 Line corrosion. 198 6291 0 0.10 4 3.89 Line corrosion. U. Denosits. 199 6321 0 0.07 3.89 Line ,.orrosion. 200 6352 0 0.09 3.87 Line corrosion. Em= 6383 n 0.09 3.90 Line corrosion. U. Denosits. 02 6413 n 0.07 3.85 Line corrosion. Isolated nittinQ. Lt. Deoosits. 6444 n 0.11 3.86 Line corrosion. 204 6475 n 0.08 3.88 Line corrosion. Isolated nittina. 205 6505 () 0.07 25 r¡ 3.84 Line corrosion. Slioht mash lower bod\!. Lt. De 206 6536 () 0.09 3.87 Line corrosion. 207 6567 0 0.09 3.88 Line corrosion. 208 6598 0 0.07 3.88 Line corrosion. Lt. Denosits. 209 6629 0 0.09 3.87 Line corrosion. 210 6660 0 0.08 3.90 Line corrosion. 211 6691 0 0.07 3.91 Line oJrrosion. 212 6723 0 0.07 2 3.86 Line corrosion. Lt. Dennsits. 213 6753 (1 0.09 3.89 Line corrosion. 214 6784 0 0.09 3.86 Line corrosion. Lt. Dennsits. 215 6815 () 0.08 3.89 Line corrosion. 216 6847 0 0.07 3.86 Line corrosion. 217 6877 0 0.0 3.89 Line corrosion. Lt Dennsits. 218 6909 0 0.0 3.90 Line corrosion. 219 6940 0 0.08 3.89 Line corrosion. U. Denosits. 220 6970 0 0.06 23 4 3.88 Line corrosion. 221 7001 0 0.07 3.87 Line corrosion. 222 7031 0 0.07 3.88 Line corrosion. 223 7062 o o·s 0.06 3.85 Line corrosÎon. U. Denosi 15. 224 7092 0.05 0.07 3.85 Line corrosion. 225 7121 0 0.06 3.89 Line corrosion. 226 7153 { 0.09 12 ..j 3.88 Line corrosion. 227 7184 íI i 12 0.09 {2 4 3.89 Line mrrosion. 228 7214 {Ii h) 0.07 27 4 3.90 Line corrosion. 229 7245 ( 0.09 II 4 3.88 Line corrosion. 230 7276 il 0.10 \5 4 3.89 Line corrosion. 231 7306 {I 0.08 3.89 Line corrosion. 232 7336 0 0.09 3.90 Line corrosÎon. 233 7367 0 0.07 3.91 Line corrosion. 234 7397 {I 0.09 3.85 Line corrosion. 235 7428 íI 0.06 A \ 3.88 Line corrosion. 236 7458 {I 0.09 n 4 3.89 Line corrosion. I I I I I I I I I I I I Body Metal loss Body Page 5 I I I REPORT JOINT I I Pipe: Body Wall: Upset Wall: Nominal I.D.: 4.5in 12.6ppf L·80 0.271 in 0.271 in 3.958 in Well: Field: Company: Country: Survey Date: 1B"()8A Kuparuk ConocoPhimps Alaska, tne. USA April 15, 2007 I I Joint Jt. Depth I'en ~~~~ Pen. ,'vlelal Min. Damage Profile No. ID. Comments (%wall) (ins) (Ins.) (Ins.) 0 50 100 237 7490 ) 0.09 35 tl Line corrosion. Isolated oitting, U. Denosi ts. 238 7520 ) 0.08 30 3.89 Corrosion. 239 7550 ) 0.09 32 3.91 Line corrosion. 240 7582 ) 0.09 4 3.89 Line corrosion. 241 7612 0 0.09 4 3.90 Line corrosion. 242 ~ 0.06 0.07 3,90 Line corrosion. 243 () 0.07 3ifioono"on. Lt. Deoosits. Hi 0.08 3.82 e corrosion. U. Deoosits. 0.1') 0.09 3. corrosion. 7765 0.08 ¿ . 3.88 Line corrosion. 7796 ( 0.06 14 4 3.87 Line corrosion. 248 7827 ( 0.06 23 3.87 Line corrosion. 249 7858 0.05 0.07 )') 3.85 Corrosion. U. Denosits. 250 7888 D 0.08 3 3.84 Line corrosion. It. Denosits. 251 7919 () ±fIT= 1 3.87 Line shallow corrosion. ~9 ( .4 3.88 Line corrosion. 2 78 ( 0.09 "I 3.89 Line corrosion. Lt. Deoosits. 2 8009 I), )6 0.08 m= 3.83 Line corrosion. 255 8038 0.07 24 mli'~ oono>'on. 256 8068 0 0.08 2B 4 3. Line corrosion. 257 8099 0 0.08 3'5 Line corrosion. 258 8130 0 0.07 Line corrosion. 259 8161 () 0.05 3.89 Line corrosion. 260 8191 0.06 0.06 3.88 line corrosion. 261 8222 () 0.07 3.83 Line corrosion. 262 8252 0 .~ 3.86 Line shallow corrosion. 263 8283 0 3.57 Line corrosion. It. Denosits. 264 5313 0 3.89 Une corrosion. Lt. Denosits. 265 5343 0 3.89 Line corrosion. Lt. Denosits. 266 8374 0.07 3.59 Line corrosion. 267 8405 0.06 3.88 Line corrosion. U. Deoosits. 268 8435 0.09 31 3.87 Line corrosion. Isolated oitting. 269 8466 0.06 2 ( 3.85 Line corrosion. 270 8497 C 0.06 2 r¡ 3.87 Line corrosion. ;~; tmt= 0.09 3' I) 3.87 Line corrosion. U 0.07 2 3 3.90 Line corrosion. 273 8589 U I 14 4 3.90 Line corrosion. 274 8620 0 4 3.88 Line corrosion. 275 8651 4 3.88 Line corrosion. Lt. Deoosits. 276 86111 n., IS ¡ 3.88 Line shallow corrosion. 277 8712 0.05 I) 3.85 Line shallow corrosion. 278 8743 ( 0.05 3 3.88 Line corrosion. 279 8774 ( 0.06 3.86 Line orrosion. 280 8803 0 0.06 3.86 Line corrosion. U. Deoosits. 281 8835 0 0.06 3.88 Line corrosion. 282 8865 0.06 3.88 Line corrosion. 283 8897 0.05 . I 3.87 Line shallow corrosion. 284 8928 0.07 3.90 Line corrosion. 285 8960 0.05 17 4 3.87 Shallow oittimz. 286 8991 0 0.07 26 3 3.90 Line corrosion. I I I I I I I I I I I I I:>age 6 I I I PDS JOINT TABU ON SH Pipe: 4.5 in 12.6 ppf L-80 Well: 1ß..08A Body Wall: 0.2 71 in Field: Kuparuk Upset Wall: 0.271 in Company: ConocoPhillips Inc. NominaII.D.: 3.958 in Country: USA Survey Date: April 1 5, 2007 I I I I Joint No. I I I I I I I I I I I I I I Min. 1.0. (Ins.) 3.88 3.87 3.87 3.89 3.86 3.75 .85 3.84 3.80 3.83 3.83 3.71 Damage Profile wall) o 50 100 Comments Body Metal Loss Body Page 7 .. .. .. .. .. .. .. Well: Field: Company: Country: Tubin : 1 B-OBA Kuparuk ConocoPhillips Alaska, Ine USA 4.5 ins 12.6 f L-80 .. .. .. .. .. .. .. .. s s Date: Type: Tool Size: No. of Fingers: Anal st: April 15, 2007 MFC UW 40 No. 210357 :U5 40 M. Tahtouh Tool = 43 Nominal 10 = 3.958 Nominal 00 = 4500 Remaining wall area = 68 % Tool deviation = 30 0 24 it 24 Penetration = 0.16 ins Erosion in Perforations 32% Cross-Sectional Wall Loss HIGH SIDE = UP Cross Sections page 1 .. s .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. S rt ro ns Well: 1ß-08A Survey Date: 15, 2007 Field: Kuparuk Tool Type: MFC UW 40 No. 210357 Company: Alaska, Inc. Tool Size: ;1.75 Country: USA No. of Fingers: 40 Tubin : 4.5 Îns 12.6 f L·80 Anal st: M. Tahtouh 3 ft Tool = 43 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area'" 97 % Tool deviation = 32 0 Finger 27 Penetration 0.108 ins Une Corrosion 0.11 ins = 40% Wall Penetration HIGH SIDE = UP Cross Sections page 2 .. .. .. .. .. .. .. .. .. .. .. .. Well: Field: Company: Country: Tubin : 1B-08A Kuparuk ConocoPhillips Alaska, Inc. USA 4.5 ins 12.6 f L-80 for Joint 203 Tool speed = 43 Nominal 10 = 3.958 Nominal 00 = 4.500 Remaining wall area = 98 % Tool deviation = 140 .. .. .. .. .. .. .. P S Report Cro S ons Survey Date: Tool Type: Tool Size: No, of Fingers: Anal st: April 15, 2007 MFC UW 40 No. 210357 2.75 40 M. Tahtouh 3.443 ft Finger 38 Penetration 0,107 ins Line Corrosion 0,11 ins 39% Wall Penetration HIGH SIDE UP Cross Sections page 3 .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. S Repo s Well: 1S-08A Field: Company: Alaska, Inc. Country: USA Tubin : 4.5 ins 12.6 f L-80 Survey Date: Tool Tool Size: No. of Fingers: Anal st: 15, 2007 MfC UW 40 No. 210357 2.75 40 M. Tahtouh ft Tool 43 NominallD 3.958 Nominal OD = 4.500 Remaining wall area = 99 % Tool deviation 31 0 Finger 16 Projection = -0.248 ins Deposits Minimum ID 3.71 ins HIGH SIDE UP Cross Sections page 4 .. .. .. I KRU 1 B-OSA I I lllMlilA API: 500292063501 Well Tvpe: INJ AnQle (â) TS: 63 deQ (â) 9260 SSSV Type: NIPPLE Orig 8/3/1997 Angle @ TO: 63 deg @ 9710 VALVE ComDletion: (517-518, Annular Fluid: Last W/O: 813/1997 Rev Reason: Adjust INJ VLV 00:3.810) orifice size NIP (517-518, Reference Ref Log Date: Last Update: 7/S/2006 00:4.500) LOQ: Last Taa: 9479' RKB TD: 971 ° ftK8 LastTag 6/28/2006 Max Hole 64 deg @ 7148 SLEEVE-C Date: AnQle: (6049-6050, .. IUl 00:4.500) Descriotion Size TOD Bottom ND Wt Grade Thresd WBING (0--6135, ~I 10,750 0 2343 2246 45.50 K-55 00:4.500, PRODUCTION 7.000 0 8465 6086 26.00 K-55 10:3.953) CONDUCTOR 16.000 0 80 80 65.00 H-40 LINER 4,500 6120 9708 6658 12.60 L-80 PBR .iMtNCi //···'.'.·/·.·..'...···.·.·.1 (6095-6096, Size TOD I Bottom I TVD I Wt I Grade Thread 00:4.500) 4.500 0 I 6135 I 4858 I 12.75 I L-80 EUE 8RD MOD , RODUCTION (0-8465, 00:7.000, intarval ND Zone StaW$ 1 Ft SPF Date Comment Wt:26.00) 9270 - 9306 6459 - 6475 C-4 Open 36 4 2f7/199 RPERF 21/8" EnerJet DP;180 deo. phasing ANCHOR 9306 - 9306 6475 - 6475 C-4 Open 0 5 2m199¡ RPERF 2 1/8" Ener Jet DP; 180 (6109-6110, - - - - -- 00:4.500) - - cleQ. phasinQ PKR 9306 - 9310 6475 - 6477 C-4 Open 4 4 2m199 RPERF 2 118" Ener Jet DP; 180 (6110-6111, OD:6.156) dea. ohasino 9310 - 9310 6477 - 6477 C-4 Open 0 1 :3/28/1991 APERF 21/8" EnerJet DP; 0 deQ.ph 9314 - 9314 6479 - 6479 C-3 Open 0 1 ~/28/1991 APERF 2 1/8" Ener Jet DP; 0 SEAL deQ,ph (6123-6124, 00:4.500) 9318 - 9318 6481 - 6481 C-3 Open 0 1 ~/28/199 1 APERF 21/8" EnerJet DP; 0 LINER deg.ph (6120-9708. OD:4.5OO, 9322 - 9322 6483 6483 C-3 Open 0 1 ~/28/1 991 APERF 21/8" EnerJet DP; 0 Wt:12.60) cleo. ph TIt 9326 - 9326 6485 - 6485 C-3 Open 0 1 ~/28/199 ¡ APERF 2118" EnerJet DP; 0 (6135-6136, deQ.ph 00:4.500) 9340 - 9350 6491 - 6495 C-3 Open 10 12 ~/31 1199'" RPERF 27/S" HSD DP; 60 deg. ~Ph 9360 - 9380 6500 6509 C-2 Open 20 12 131/199 2 718" HSD DP; 60 deg. NIP Iph (9173-9174, 9392 - 9402 6514 - 6519 C-2 Open 10 12 ~/31/199 PERF 2 7/8" HSD DP; 60 deg. 00:3.828) Inh .r DescriDtioo ID .- ~ 517 517 NIP Cameo 'DB' 3.813 Perf 517 517 VALVE SET 3.81 INJ VALVE it HRS-51 ON 6-29-06 0.623 (9270-9310) - - - 6049 4788 SLEEVE-C Baker 'CMU' Sliding wI Otis Selective Profile, Run on WO 8/3/97 3.813 "- = 6095 4825 PBR Baker 3.880 ~ 6109 4837 ANCHOR Baker 'KBH-22' 3.937 Perf == == 6110 4838 PKR Baker 'F AB-1 ' 3.937 (9306-9306) 6123 4848 SEAL Baker 'GBH-22' SEAL ASSY. 3,937 - ~- 6135 4858 TTL 3.958 - --" ~ NIP Cameo 'DB' in Liner 3.750 - - Nota Perf ._"- - 121/198 ORIGINAL WELL COMPLETION (9318-9318) 8/3/1997 WELL SIDETRACKED - - Monobore Injector - - A Sand not perfd Perf .-- - (9340-9350) -- - -- --. Perf .:= = (9360-9380) - - - .""- Perf = = (9392-9402) - - .- -- -. I I I I I I I I I I I I I I I I ) STATE OF ALASKA ) RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION MAR 17 2005 REPORT OF SUNDRY WELL OPERATlql~, Oil & GanGa Co 111' 'un 1. Operations Pl;lrformed: Abandon 0 "Repair Well ,0 ,Plug P~rf9rationsD 'Stimulate D, : . OthXncllor~ W~to~~ , Alter Casing D, ' , , Plill,Tubing D' . Pe~oraie Ne~ Pool' D ,', ',Waiyer 0 ,::' ,Time, Extension ~, " , Change Approved Program D Operat.sh4tdownD" Perforate,. 0 ' Re":ent~r Susperided Well' D 2. Operator Name: ,'4:'Current Well Status:' 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. 'beve~oP!TIent' '0 Exploratory, D" 197-112 3. Address: Strati~raphic tJ " 'Service,: 0 6. API Number: P. O. Box 100360 50-029-20635-01 7. KB Elevation (ft): 9. Well Name and Number: RKB 93' 1 B-08A 8. Property Designation: Kuparuk River Unit 11. Present Well Condition Summary: 10. Field/Pool(s): Kuparuk River Field 1 Kuparuk Oil Pool Total Depth Effective Depth Casing Structural CONDUCTOR SURFACE PRODUCTION LINER Perforation depth: measured 9710' feet true vertical 6659' feet measured 9611 feet true vertical 6614 feet Length Size MD 80' 16" 80' 2250' 10-3/4" 2343' 8372' 7" 8465' 3588' 4-1/2" 9708' Plugs (measured) Junk (measured) Burst Collapse TVD 80' 2246' 6086' 6659' Measured depth: 9270' - 9402' true vertical depth: 6459' - 6519' . (' Oor SCANNE.[\¡ Mt\R 2; 1.1 ¿ J Tubing (size, grade, and measured depth) 4-1/2" , L-80, 6135' MD. Packers & SSSV (type & measured depth) pkr= BAKER 'FAB-1' pkr= 6110' SSSV= NIP SSSV= 517' 1~.,$~imlJlåti()n9 'ceÏ11~~tsgÙe~z~suIjIÏTiåry: .,' , . .. .. .... ... . .. . ..... ..... . . ,". . . .. . .. ........ . ... .'. . Intervàlstreated(ltiea~lJred) .. . .. . . . . . . . . . . .. . Tr¢atrnentdeSpripti()nsinÓILJ~ingvolurnesusedandfinal·pÏ"eSSlJra:. . 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Met Water-Bbl 3873 CasinQ Pressure 600 600 TubinQ Pressure 2406 3687 Prior to well operation Subsequent to operation 14. Attachments Copies of Logs and Surveys run _ 6064 15. Well Class after proposed work: Exploratory ·.·.0 Development D Service 0 16. Well Status after proposed work: oilD GasD WAG0 GINJO WINJ D 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: Daily Report of Well Operations _X WDSPLD Contact Robert Christensen @ 659-7535 p~inted Name /) ~ob~h~eØEm () Signature ~(~~ Title Production Engineering Technician r- Phone 659-7535 Date 3/IL(¡'ð~ o R \ G \ N A :mDMS BFL MAR 1 7 1OO§mit Onginal Only Form 10-404 Revised 04/2004 ') 1B-08A ) DESCRIPTION OF WORK COMPLETED SUMMARY I ,',I Date '. , Event Summary 2I10/200slCommenced WAG EOR Injection MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Cammy O Taylor~ Chairman DATE: June 16, 2002 THRU: Tom Maunder~" P.I. Supervisor FROM: Chuck Scheve Petroleum Inspector NON- CONFIDENTIAL SUBJECT: Mechanical Integrity Tests Phillips 1 B Pad KRU Kuparuk Packer Depth Pretest Initial 15 Min. 30 Min. WellI 1B-02 I Typelnj. I F I T,V.D. I 6109 I Tubingl 1450 I 1450 I 1450 J 1450 I lntervall 4 P.T.D.I 181-133 TYpe testl P I TestpsiI 1527 I CasingI 150 11980 ,I 1930 I 1920 I P/F I P Notes: WellI 1B-01 P.T.D.I 181-065 Notes: P.T.D.I 177-001 I Notes: Well! 1B-07 ,P.T.D.I 181-089 Notes: Well] 1B-08 P.T.D.I 197-112 Notes: WellI 1B-09 P.T.D.I 181-134 Notes: P.T.D.I 193-061 Notes: TyPe testI P I TestpsiI 1545 IcasingI 550 I 20501 20501 20501 P/F I P I Typelnj.I F I T.V.D. I~ I Tubing 12500 I 2500 I 2500 12500 I lntervall 4 TYpe testI P I TestpsiI 1585 I Casing l 250 120001 195011925I P/F I P I Typelnj.I F J T.V.D. I 6227 I Tubing I 2350 J 2350 I 2350 I 2350 I lntervall 4' Type testI P I Testpsil 1557 I CaSingI 1o001195011920119201 P/F I _P I Type,nj.I F I T.V.D. 14837 I TUbing12500 12500 [2500 12500 I,nte~va, I 4 Type testIP I TeStpsil 1209 ICasingI 0 I 2O50 / 2000 I 2000 I P/F I P I Typelnj.I F I T.V.D. I 6109 J Tubing I 2500 I 2500 I 2500 I 2500 I lntervall 4 ; Type testI P I TeStpsiI 1527 ICasingI 550 I 2025 '1 20001 20001 P/F I -P! Type lnj.I F I T.V.D. I 6094 I Tubingl 1950 I 1950 I 1950 I 1950 J lntervalI 4"' Type testI P I Testpsil 1524 IcasingI 0 I 21001 2°5°1 2°5°1 P/F I -P Type INJ. Fluid Codes F = FRESH WATER INJ. G = GAS INJ. S = SALT WATER INJ. N = NOT INJECTING Type Test M= Annulus Monitoring P= Standard Pressure Test R= Internal Radioactive Tracer Survey A= Temperature Anomaly Survey D= Differential Temperature Test Interval I= Initial Test 4= Four Year Cycle V= Required by Variance W= Test during Workover O= Other (describe in notes) Test's Details I traveled to Phillips 1B Pad in the Kuparuk River Field and witnessed the routine 4 year MITs on the above 7 wells. The pretest tubing and casing pressures on all wells was observed and found to be stable. The standard annulus pressure tests were then performed with all 7 wells demonstrating good mechanical integrity. t~,l.T.'s performed: 7 Number of Failures: 0 Total Time during tests: 4 Hours Attachments: cc.; MIT report form 5/12/00 L.G. MIT KRU lB Pad 6-16-02 CS.xls 6/20/2002 SCANNED JUL 1 0 2002 THE MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED ON OR BEFORE JANUARY 03,2001 M p i ATE E W IA L U N U !:: I~ T H IS M A R K E R C:LO~ILM.DOC AOGCC Geological Materials Inventory PERMIT 9 7-112 ARCO Log Data Sent Recieved 8118 ~3P~Y GR 9/24/97 9/26/97 CBL 5900-9604 , [/ /Obv~c~ ~ ) 9/22/97 9/29/97 MWD SRVY X~s'~RRy 6299-9710 9/10/97 9/17/97 NGP-MD ~-'b~6-9710 9/26/97 9/26/97 Box NGP-TVD ~22-6659 9/26/97 9/26/97 gt0~7 Completion Date Daily well ops ~/0~---~ Are dry ditch samples required? yes /.~--'~'ff5~ And receivedg.---~-'~---'~ yes Was the well cored? Are tests required? Well is in compliance Comments yes --~ n-'-"-O~ Analysis description yes ....... no Received? .~ye's no / Initial Tuesday, August 31, 1999 Page 1 of 1 STATE OF ALASKA AL~,,_., ~A OIL AND GAS CONSERVATION COMMIbo,ON REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Operation Shutdown Stimulate Plugging Pull tubing Alter casing Repair well Perforate X Other 2. Name of Operator ARCO Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510 5. Type of Well: Development Exploratory Stratigraphic Service 4. Location of well at surface 501' FNL, 141' FEL, Sec. 9, T11N, R10E, UM At top of productive interval 1415' FNL, 230' FWL, Sec. 11, Tll At effective depth 1365' FNL, 550' FWL, Sec. 11, Tll At total depth 1362' FNL, 638' FWL, Sec. 11, Tll N, R10E, UM N, R10E, UM N, R10E, UM 12. Present well condition summary Total Depth: measured true vertical Effective depth: measured true vertical 971 0 feet 6659 feet 9611 feet 6 61 4 feet 6. Datum elevation (DF or KB) RKB 32 feet 7. Unit or Property name Kuparuk River Unit 8. Well number 1 B-08A 9. Permit number/approval number 97-112 10. APl number 50-029-20635-01 11. Field/Pool Kuparuk River Field/Oil Pool Plugs (measured) None Junk (measured) None Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length Size Cemented Measured depth True vertical depth 80' 2315' 6110' 3590' measured 1 6" 200 Sx P F C 1 1 2' 1 1 2' 1 0-3/4" 1000 Sx Fondu & 2343' 2246' 250 Sx AS II 7" 923 Sx Class G 61 35' 4857' 4.5" 496 Sx Class G 9708 6658' 9270-9310',9314',9318',9322',9326','9340'-9350',9360'-9380',9392'-9402' true vertical 6458'-6477',6479',6480',6482',6484',6491'-6495',6499'-6509',6514'-6518' Tubing (size, grade, and measured depth) 4.5",12.75#/ft., L-80 @ 6135' Packers and SSSV (type and measured depth) Packer: Baker FAB @ 6110'; SSSV: None, nipple @ 517' 13. Stimulation or cement squeeze summary Perforate "C" sand on 12/07/97. Intervals treated (measured) 9270-9310' Treatment description including volumes used and final pressure Perforate using 2-1/8" EJ guns w/ DP charges at 4 spf, 180° phasing, fp was 1700 psi. 14. Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 0 0 11 0 2574 Subsequent to operation 0 0 346 0 2614 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations X 16. Status of well classification as: Oil Gas Suspended Service X 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ),.~_,,~,.,., Title Wells Superintendent Form /- Date /.~,.¢~-- ..~ SUBMIT IN DUPLICATE Alaska 0il & r,~, Cons. 60mmissior~ ARCO Alaska, Inc. '---' KUPARUK RIVER UNIT ~' ,~, WELL SERVICE REPORT '~' KI(B-08A(W4-6)) WELL JOB SCO'PE JOB NUMBER 1B-08A PERFORATE, PERF SUPPORT 1203970514.1 DATE DAILY WORK UNIT NUMBER 12/07/97 PERFORATE, PERF SUPPORT DAY OPERATION COMPLETE ] SUCCESSFUL KEY PERSON SUPERVISOR 1 (~) Yes O NoI ® Yes O No SWS-DECKERT rl~_...~. FIELD AFC# CC# DAILY COST ACCUM COST ESTIMATE AK8949 230DS10BG $11,474 $13,077 Initial Tbq Press Final Tb_q Press Initial Inner Ann Final Inner Ann ] Initial Outeir"Ar~ J Fir~al Outer Ann 1700 PSI 1700 PSI 0 PSI 0 PSII 10 FSI 0 PSI DAILY SUMMARY PERFORATED F/9270 - 9310' ELM W/2-1/8" EJ DP @ 2 SPF 180 DEG PHASED ( 4 SPF TOTAL ) TIME 18:45 21:45 00:30 03:15 06:00 08:00 09:00 LOG ENTRY MIRU SWS (DECKERT & CREW) & LRS. TGSM & JOB OVERVIEW. PUMP 15 BBLS DIESEL @ 3000 PSI TO ENSURE PROPER FREEZE PROTECT. MU GUN ASSEMBLY#1 O/VT/ROLLER STEM/20' 2-1/8" EJ/CCL/HD) TL-38'. RIH TO 9310' ELM W/O PUMPING. TIE IN TO 8/31/97 SWS PERF RECORD. LOG INTO POSITION & PERFORATE F/ 9290 - 9310' ELM W/2-1/8" EJ DP @ 2 SPF. SAW MINIMAL SURFACE INDICATION. LOG UP & POOH. AT SURFACE.-ALL SHOTS FIRED RELEASE LRS. MU GUN ASSEMBLY#2 (SAME AS ABOVE ORIENTED 18(~ DEG). PT& RIH. TIE IN & PERFOF~.ATE W9290 9310' ELM W/SAME GUNS AS BEFORE ORIENTED 1~(:' 0-'.'.-. ;~..... ¢~-' ~' '~.":~ 'AL F/9290 - 9310' ELM. LOG UP & POOH. AT SURFACE. ALL SHOTS FIRED. MU GUN ASSEMBLY #3 (SAME AS ABOVE). PT & RIH. TIE IN & PERFORATE F/ 9270 - 9290' ELM W/2-1/8" EJ DP @ 2 SPF. LOG UP & POOH. AT SURFACE. ALL SHOTS FIRED. MU GUN ASSEMBLY #4 (SAME AS ABOVE ORIENTED 180 DEG). PT & RIH. TIE IN & PERFORATE F/9270-9290' ELM W/SAME GUNS AS BEFORE ORIENTED 180 DEG - 4 SPF TOTAL 9270 - 9290' ELM. LOG UP & POOH. AT SURFACE. ALL SHOTS FIRED. BEGIN RD. RD COMPLETE. TURN WELL OVER TO PRODUCTION F/INJECTION. SERVICE COMPANY - SERVICE DAILY COST ACCUM TOTAL $0.00 $21.00 APO $250.00 $775.00 HALLIBURTON $0.00 $1,057.65 LITTLE RED $1,320.00 $1,320.00 SCHLUMBERGER $9,904.00 $9,904.00 TOTAL FIELD ESTIMATE $11,474.00 $13,077.65 STATE OF ALASKA AL~,.., ~ OIL AND GAS CONSERVATION COMMIS,~,ON REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Operation Shutdown Stimulate Plugging Pull tubing Alter casing Repair well Perforate X ~t/'7-,~¢ ~'" Other 2. Name of Operator ARCO Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510 5. Type of Well: Development __ Exploratory _ Stratigraphic _ Service X 4. Location of well at surface 501' FNL, 141' FEL, Sec. 9, T11N, R10E, UM At top of productive interval 1415' FNL, 230' FWL, Sec. 11, Tll At effective depth 1365' FNL, 550' FWL, Sec. 11, Tll At total depth 1362' FNL, 638' FWL, Sec. 11, Tll N, R10E, UM N, R10E, UM N, R10E, UM 12. Present well condition summary Total Depth: measured true vertical Effective depth: measured true vertical 971 0 feet 6659 feet 9 61 1 feet 6 61 4 feet 6. Datum elevation (DF or KB) RKB 32 7. Unit or Property name Kuparuk River Unit 8. Well number 1 B-08A 9. Permit number/approval number 97-112 10. APl number 50-029-20635-01 11. Field/Pool Kuparuk River Field/Oil Pool Plugs (measured) None Junk (measured) None feet L Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length Size Cemented Measured depth True vertical depth 80' 2315' 6110' 3590' measured 1 6" 200 Sx PFC 1 0-3/4" 1000 Sx Fondu & 250 Sx AS II 7" 923 Sx Class G 4.5" 496 Sx Class G 9306',931 0',931 4',931 8',9322',9326',9340 true vertical 6475',6477',6479',6480',6482',6484',6491 112' 112' 2343' 2246' 613 970 '-93 '-64 5' 4857' 8 6658' 50',9360'-9380',9392'-9402' 95',6499'-6509',6514'-6518' Tubing (size, grade, and measured depth) 4.5",12.75#/ft., L-80 @ 6135' Packers and SSSV (type and measured depth) Packer: Baker FAB @ 6110'; SSSV: None, nipple @ 517' 13. Stimulation or cement squeeze summary Perforate "C" sand on 9/28/97. Intervals treated (measured) 9306',9310',9314',9318',9322',9326' Treatment description including volumes used and final pressure Perforate using 2-1/8" EJ guns w/ DP charges at 1 spf, 60° phasing, fp was 1250 psi. 14. Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 0 0 15 0 2578 Subsequent to operation 0 0 500 0 2611 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations 16. Status of well classification as: Oil Gas Suspended Service 17. I hereby~rtify that the foregoing is true and correct to the best of my knowledge. Signed ~---.;~.,~ Title Wells Superintendent / ,,.'5 ;--,, '.,,':~ 'Alask *" "'" ' Date SUBMIT IN DUPLICATE ARCO Alaska, Inc. KUPARUK RIVER UNIT '' WELL SERVICE REPORT ~' . KI(B-08A(W4-6)) WELL JOB SCOPE JOB NUMBER 1B-08A PERFORATE, PERF SUPPORT 0918972113.7 ,. DATE DAILY WORK UNIT NUMBER 09/28/97 PERFORATE W/2 1/8" EJ DP 8337 DAY OPERATION COMPLETE I SUCCESSFUL KEY PERSON SUPERVISOR 1 (~) Yes O NoI ® Yes (~ No SWS-BAILEY BLACK FIELD A FC~ CC# DALLY COST A OCUM COST ~i~Final ESTIMATE AK8949 230DSl 0BG $7,1 37 $7,1 37 Initial Tb.q Press Final Tbq Press Initial Inner Ann Final Inner Ann I Initial Outer A Outer Ann 1250 PSI 1250 PSI 125 PSI 250 PSll 10 PSII 10 PSI DAILY SUMMARY IPERFORATED 9306, 9310', 9314', 9318', 9322' & 9326' ELM (ONE SHOT A FOOT) W/2-1/8" EJ DP 20' OF 2 1/8" EJ DP @ 0 DEG PHASING / ORIENTATION. TIME LOG ENTRY 07:30 MIRU SWS (BAILEY & CREW) & APC. MU GUN ASSEMBLY (1-11/16" SWS SLINE ROLLERS / 2-1/8" EJ DP / CCL) TL-34'. TGSM & JOB OVERVIEW. PT BOPE TO 3500 PSI. 10:30 13:00 14:00 RIH W/GUN ASSEMBLY TO 9440' ELM. TIE IN W/8/11/97 SWS CBTF__JGR/CCL. PERFORATE 1 SHOT PER FOOT @ 9306',10',14',18',22' & 26' W/2-1/8" EJ DP, 0 DEG PHASED / ORIENTED. SAW POSITIVE SURFACE INDICATION. LOG UP & POOH. AT SURFACE. BEGIN RD. ALL GUNS FIRED. FINISH RD. TURN OVER TO PRODUCTION F/INJECTION. MOVE TO 1B-15. SERVICE COMPANY - SERVICE DAILY COST ACCUM TOTAL APC $250.00 $250.00 SCHLUMBERGER $6,887.00 $6,887.00 TOTAL FIELD' ESTIMATE $7,1 37.00 $7,1 37.00 STATE OF ALASKA AL,,,.,,<A OIL AND GAS CONSERVATION COMMIb,.,~ON REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Operation Shutdown__ Pull tubing Alter casing Stimulate Plugging Perforate X Repair well Other__ 2. Name of Operator ARCO Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510 5. Type of Well: Development __ Exploratory _ Stratigraphic _ Service X 4. Location of well at surface 501' FNL, 141' FEL, Sec. 9, T11N, R10E, UM At top of productive interval 1415' FNL, 230' FWL, Sec. 11, T11N, R10E, UM At effective depth 1365' FNL, 550' FWL, Sec. 11, T11N, R10E, UM At total depth 1362' FNL, 638' FWL, Sec. 11, T11N, R10E, UM 12. Present well condition summary Total Depth' measured true vertical Effective depth: measured true vertical 9 71 0 feet 6659 feet 961 I feet 6 61 4 feet 6. Datum elevation (DF or KB) RKB 32 7. Unit or Property name Kuparuk River Unit 8. Well number 1 B-08A 9. Permit number/approval number 97-112 10. APl number 5o-029-20635-01 1 1. Field/Pool Kuparuk River Field/Oil Pool Plugs (measured) None Junk (measured) None feet Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length Size 80' 16" 231 5' 1 0-3/4" 6110' 7" 3590' 4.5" measured 9340'-9350',9360'-93 true vertical 6491'-6495',6499'-65 Cemented Tubing Pressure 200 Sx PFC 1000 Sx Fondu & 250 Sx AS II 923 Sx Class G 496 Sx Class G 80',9392'-9402' 09',6514'-6518' Measured depth True vertical depth 112' 112' 2343' 2246' 6135' 4857' 9708 6658' Tubing (size, grade, and measured depth) 4.5",12.75#/ft., L-80 @ 6135' Packers and SSSV (type and measured depth) Packer: Baker FAB @ 6110'; SSSV: None, nipple @ 517' 13. Stimulation or cement squeeze summary Perforate "C" sand on 8/31/97. Intervals treated (measured) 9340'-9350',9360'-9380',9392'-9402' Treatment description including volumes used and final pressure Perforate using 2-7/8" HSD guns w/ DP charges at 6 spf, 60° phasing, fp was 1250 psi. 14. Representative Daily Average Production or Iniection Data OiI-Bbl Gas-Mcf Water~Bbl Casing Pressure Prior to well operation 0 0 0 0 0 Subsequent to operation 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations X 0 0 982 0 2572 16. Status of well classification as: Oil Gas Suspended Service X 17. I he/~ certify that the foregoing is true and correct to the best of my knowledge. (/ Signed V,~/'X,,¢" j Title Wells Superintendent..,. ~. r%Date /-~/...,~ .~:~ Form /0~'~~67~8 ~ ~ ~'< ~ (~ F ~ V X [¢UBMIT IN DUPLICATE _' , Ar, choraf~e ARCO Alaska, Inc. .... KUPARUK RIVER UNIT "~' A WELL SERVICE REPORT KI(B-0eA(W4-6)) WELL JOB SCC~PE JOB NUMBER 1B-08A PERFORATE, PERF SUPPORT 0825970654.2 DATE DAILY WORK UNIT NUMBER 08/31/97 PEFORATE 2 7/8" HSD GUNS SWS 8293 DAY OPERATION COMPLETE SUCCESSFUL KEY PERSON SUPERVISOR 3 (~) Yes O No (~) Yes O No SWS-ELMORE BLACK FIELD AFC_~ CCC DAILY COST ACCUM COST e~gi~~e~~ ESTIMATE AK8949 230DS10BG $17,348 $32,163 . Initial Tb_q Press Final Tbq Press Initial Inner Ann Final Inner Ann I Initial Out r Ann 1250 PSI 1250 PSI 270 PSI 270 PSII 0 PSI DAILY SUMMARY PERFORATED 9392'-9402', 9360'-9380', 9340'-9350' WITH 2- 7/8" HSD DP 6 SPF & 60 DEG PHASED. TIME LOG ENTRY 12:30 MIRU SWS 8293 ELMORE. TGSM. PT 3000#. 14:30 RIH GUN #1 W/SWIVEL, CCL,P/LINE ROLLER, 10' X 2 7/8" GUN, P/LINE ROLLER. CCL TO TOP SHOT= 5.2' CCL TO BO-rTOM=18.7' TOTAL STRING LENGTH=22.7' HEAD OD=I 3/8", SWIVEL/CCL OD=1.68", PETROLINE ROLLER OD=2.5", GUN OD=2.875" 15:00 15:30 16:45 17:15 17:45 19:15 20:15 20:30 21:15 22:00 TIE,.. I_N~.(_~/_~12/__97 sws PERF RECORD & 8111/97 SWS CBTE/GR/CCL), TO SHORT JOINT AND D NIPPLE @ 9178' t:_,; AND ~'~!4,COT GUN #1 AT 9392'-9402'. 10' X 6 SPF. GUN SPECS: ,?,4J U..:, ~:!!')~: ,L';Z£P PENETRATING CHARGE. 10'X 6 ~sPF. POOH. RIH GUN #2 W/SWIVEL, CCL, P/LINE ROLLER, 20'X 2 7/8" GUN, P/LINE ROLLER. CCL TO TOP SHOT= 5.2' CCL TO BO'1-I'OM=28.3' TOTAL STRING LENGTH=33.1' HEAD OD=I 3/8", SWIVEL/CCL OD=1.68", PETROLINE ROLLER OD=2.5", GUN OD=2.875" TIE IN TO SHORT JOINT & D NIPPLE. LU AND SHOOT GUN #2 AT 9360'-9380'. 20' GUN. GUN SPECS: 34J UJ RDX ,DEEP PENETRATING CHARGE. 20' X 6 SPF. POOH. RIH GUN #3 W/SWIVEL, CCL,P/LINE ROLLER, 10' X 2 7/8" GUN, P/LINE ROLLER. CCL TO TOP SHOT= 5.2' CCL TO BO'I-I'OM=18.7' TOTAL STRING LENGTH=22.7' HEAD OD=I 3/8", SWlVEL/CCL OD=1.68", PETROLINE ROLLER OD=2.5", GUN OD=2.875" TIE IN TO FLAG ON LINE, LU PAST SHORT JT. LU AND SHOOT GUN #3 AT 9340'-9350'. 10' X 6 SPF. GUN SPECS: 34J UJ RDX ,DEEP PENETRATING CHARGE. 10' X 6 SPF. POOH. AT SURFACE. BD LUBRICATOR. RELEASE RADIO SILENCE. LEAVE WELL SI. RDMO & TURN OVER TO PRODUCTION F/AM HPBD. SERVICE COMPANY - SERVICE DAILY COST ACCUM TOTAL APC $300.00 $6,300.00 DIESEL $0.00 $476.00 DOWELL $0.00 $6,018.00 GELLED DIESEL $0.00 $840.00 HALLI BURTON $0.00 $1,482.00 SCHLUMBERG ER $17,048.00 $17,048.00 TOTAL FIELD ESTIMATE $17,348.00 $32,1 64.00 STATE OF ALASKA AIJ-,,.,KA OIL AND GAS CONSERVATION COMMIbo~ON REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Operation Shutdown__ Pull tubing Alter casing Stimulate Plugging Perforate X Repair well Other__ 8f f' 4 2. Name of Operator ARCO Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510 5. Type of Well: Development __ Exploratory _ Stratigraphic _ Service X 4. Location of well at surface 501' FNL, 141' FEL, Sec. 9, T11N, R10E, UM At top of productive interval 1415' FNL, 230' FWL, Sec. 11, T11N, R10E, UM At effective depth 1365' FNL, 550' FWL, Sec. 11, T11N, R10E, UM At total depth 1362' FNL, 638' FWL, Sec. 11, T11N, R10E, UM 12. Present well condition summary Total Depth: measured true vertical 971 0 feet 6659 feet 6. Datum elevation (DF or KB) RKB 32 7. Unit or Property name Kuparuk River Unit 8. Well number 1 B-08A 9. Permit number/approval number 97-112 10. APl number 50-029-20635-01 11. Field/Pool feet Plugs (measured) Kuparuk River Field/Oil Pool None Effective depth: measured 9 61 1 true vertical 6614 feet feet Junk (measured) None 13. 14. Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length Size Cemented Measured depth True vertical depth 80' 2315' 6110' 359O' measured 1 6" 200 SX PFC 1 1 2' 1 0 - 3 / 4" 1000 Sx Fondu & 23 4 3' 250 Sx AS II 7" 923 Sx Class G 61 35' 4.5" 496 Sx Class G 9 7 0 8 112' 2246' 4857 6658 9340'-9350',9360'-9380',9392'-9402' true vertical 6491 '-6495',6499'-6509',6514'-6518' Tubing (size, grade, and measured depth) 4.5",12.75#/ft., L-80 @ 6135' Packers and SSSV (type and measured depth) Packer: Baker FAB @ 6110'; SSSV: None, nipple @ 517' Stimulation or cement squeeze summary Perforate "C" sand on 8/12/97. Intervals treated (measured) 9340'-9350',9360'-9380',9392'-9402' Treatment description including volumes used and final pressure Perforate using 2-1/2" HSD guns w/ DP charges at 6 spf, 60° phasing, fp was 1250 psi. Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure O IGINAL Tubing Pressure Prior to well operation 0 0 0 0 0 Subsequent to operation 0 0 982 0 2572 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations X 16. Status of well classification as: Oil Gas Suspended Service X 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~_., ~/~~~~.?~ ~, For~,~-~04r Title Wells Superintendent Date /'-'/.~"~fC~ ::2 i-.: !'" !i.i~ ~ ? / 17 '; SuBMIf IN DUPLICATE ARCO Alaska, Inc. KUPARUK RIVER UNIT WELL SERVICE REPORT '~ K1 (B-08A(W4-6)) WELL JOB SCOPE JOB NUMBER 1B-08A PERFORATE, PERF SUPPORT 0809971733.3 DATE DAILY WORK UNIT NUMBER 08/12/97 PERFORATE 2 1/2" HSD CARRIER GUNS 8337 DAY OPERATION COMPLETE I SUCCESSFUL KEY PERSON SUPERVISOR 2 (~D Yes 0 NoI (~) Yes ~ No SWS-BAILEY BLAC~-.., FIELD AFC# CC# DAILY COST ACCUM COST ,.~gn~d ~,? ~,~, ESTIMATE AK8949 230DS10BG $1 3,306 $24,361 Initial Tbcl Press Final Tb_q Press Initial Inner Ann Final Inner Ann I Initial Outer Ann I I l~inal Outer Ann 0 PSI 0 PSI 0 PSI 0 PSlII0 PSI 0 PSI DAILY SUMMARY PERFORATE F/9340- 9350', 9360- 9380' & 9392' - 9402' ELM W/2.5" HSD DP @ 60 DEG PHASING & 6 SPF J TIME LOG ENTRY 14:00 MIRU SWS #8337 W/BAILEY-FREY-WOOTEN 17:00 PFF TO 3500 PSI 17:15 18:00 20:45 21:30 22:30 RIH W/2EA 10'2 1/2" HSD CARRIER GUNS LOADED AT 6 SPF, 60 DEGREE PHASING, DEP PENETRATING CHARGES. RAN A CCL-L ABOVE A 2 1/2" PETROLINE ROLLER, THE SWITCHED GUN, THEN ANOTHER 2 1/2" INLINE PETROLINE ROLLER TIE-IN TO SWS CBT DA'.rE~) 8/'i i/9'.:. LCG INTO POSITION AT 9375.5' TO SHOOT FROM 9392 9.'i0;:'. !-'. f.:';"~ ,G'JN WITH EXCELENT INDICATIONS AT SURFACE. LOG INTO POSITION AT 9335.5' TO SHOOT FROM 9340' TO 9350' HAD GOOD SURFACE INDICATIONS. LOG INTO POSITION AT 9354' TO SHOOT FROM 9360' TO 9380'. SHOT WITH GOOD INDICATIONS AT THE SURFACE. POOH. AT SURFACE. START RIG DOWN. FINISH RIG DOWN. LEAVE LOCATION. SERVICE COMPANY - SERVICE DAILY COST ACCUM TOTAL $o.oo $4.00 · APC $500.00 $1,000.00 HALLIBURTON $0.00 $423.00 LI-I-I-LE RED $0.00 $2,615.00 · SCHLUMBERGER $12,806.00 $20,319.00 TOTAL FIELD. ESTIMATE $13,306.00 $24,361.00 /~RCO Alaska, Inc. ~-- KUPARUK RIVER UNIT __ WELL SERVICE REPORT KI(B-08A(W4-6)) WELL JOB SCO'PE JOB NUMBER 1B-08A PERFORATE, PERF SUPPORT 0809971733.3 DATE DAILY WORK UNIT NUMBER 08/1 1/97 RUN CEMENT BOND TOOL AND PERFRATE 8337 DAY OPERATION COMPLETE I SUCCESSFUL KEY PERSON SUPERVISOR 1 O Yes ('~ NoI O Yes (~) No SWS-BAILEY SCHUROSKY FIELD AFC# CC_,~ DAILY COST ACCUM COST Signed¥/~ ~ / //,,/,, ESTIMATE AK8949 230DS10BG $1 0,01 3 $1 1,055 Initial Tb_q Press Final Tbq Press Initial Inner Ann Final Inner Ann I Initial Outer Ann-( ] Final OutC'r~nn 0PSI 0PSI 0PSI 0PSII 10PSI "' 0PSI DAILY SUMMARY I RUN CEMENT BOND LOG AND PERFORATE W/2 1/8" EJ III TIME LOG ENTRY 14:00 MIRU SWS #8337 W/BAILEY-FREY-WOOTEN. HOLD SPOT SAFETY MEETING. 15:30 RIH W/CBTE-SGTL-TCCB-CALY 16:15 TIE-IN TO SPERRY SUN ROP/NGR DATED 27-JUL-97. 18:00 LOG UP FROM TD AT 9610' TO 6000' AT 2000 FPH. 19:50 21:30 22:00 00:15 01:30 02:00 FINISH LOGGING CBT. POOH. AT SURFACE R/D CBT. SWITHC TO 223ZT CAS, LF AND PF."F!$SdRE CONTROL EQUIPMENT. ARM 2 1/8" EJ III. P/T TO 2500 PSI. RIH W/MPD-H , CCL-L, AND 2 10' 2 1/8" EJ III GUNS (SWITCHED) AT 3750' STARTED HAVING TROUBLE GE'I-I'ING DOWN. WORKED WITH TOOLS FOR ABOUT 45 MINUTES BEFORE GIVE UP AND PULLING OUT OF THE HOLE. AT 2050' WHILE PULLING OUT OF THE HOLE, THE CABLE JUMPED SHEAVE AND PARTED LINE AT THE UPPER SHEAVE. THE CABLE STAYED IN THE FLOW TUBES AND AROUND THE UPPER SHEAVE. CLOSED THE BOPS AND REMOVED THE RISER WITH THE WELL UNPERFORATED, THE PRESSURE WAS ZERO. TIED A SQUARE KNOT IN THE CABLE AND RECOVERED THE WIRELINE AND THE GUN. AT SURFACE. DISARM GUN AND START R/D. FINISH R/D. LEAVE LOCATION. SERVICE COMPANY - SERVICE DAILY COST ACCUM TOTAL $o.oo $4.oo APC $500.00 $500.00 HALLIBURTON $0.00 $423.00 LI'I-I'LE RED $2,000.00 $2,615.00 SCHLUMBERGER $7,513.00 $7,513.00 TOTAL FIELD ESTIMATE $1 0,01 3.00 $11,055.00 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 Status of Well Classification of Service Well RECEIV OIL [] GAS r~ SUSPENDED [] ABANDONED ~---]SERVICE [~ WATER INJECTOR 2 Name of Operator 7 Permit Number DEC -- Z 11~! ARCO Alaska, Inc 97-112 3 Address 8 APl Number 0il & Gas Cons. P.O. Box 100360, Anchorage, AK 99510-0360 50-029-20635-01 j~aSk~ 4 Location of well at surface 9 Unit or Lease Name ~i-I(;h0i'ag¢-, 501' FNL, 141' FEL, Sec. 09, T11N, R10E, UM At Top Producing Interval At Total Depth . 1362' FNL, 638' FWL, Sec. 11, T11N, R10E, UM 5 Elevation in feet (indicate KB, DF, etc.) I 6 Lease Designation and Sedal No. Nordic Rig RKB 32', Pad 61' I ADL 25649 ALK 467 12 Date Spudded 13 Date T.D. Reached 14 Date Comp., S. usp. 21 -Jul-97 26-Ju1-97 12-Aug-97-.-'~ 17 Total Depth (MD+TVD) 18 Plug Back Depth (MD+TVD) Directional Survey 9710' MD & 6659' TVD 9611' MD & 6614' TVD YES 22 Type Electdc or Other Logs Run CCUCBUGR 23 CASING SIZE WT 16" 65# 10.75" 45.5# CASING, LINER AND CEMENTING RECORD Kuparuk River Unit 10 Well Number 1 B-08A 1 Field and Pool KUPARUK RIVER 15 WaterNADepth, if offshorefeet MSL 16 NO.lOf Completions Depth where SSSV set I 21 Thickness of permafrost NA feet MDI 1465' APPROX ORIGINAl.. 7' 26.0# 4.5" 12.6# GRADE H-40 K-55 K-55 L-80 SETTING DEPTH MD TOP BTM SURF. 112' SURF. 2343' SURF. 6339' 6120' 9708' 24 Perforations open to Production (MD+TVD of Top and Bottom and interval, size and number) 9340'-9350', 9360'-9380', 9392'- 9402' MD 6491 '-6495', 6499'-6509', 6514'-6518' TVD 6 spf 9306', 9310', 9314', 9318', 9322', 9326' MD 6475', 6477', 6479'. 6480', 6482', 6484' TVD 1 spf I HOLE SIZE CEMENT RECORD 24' 13.75' 200 sx Permafrost 1000 sx Fondue & 250 sx AS II 923 sx Class G 496 sx C ass G 8.75' 6.125' 25 SIZE 4,5' TUBING RECORD 6D1E31~,TH S ET (MD) ~iAlC0,KER SET (MD) 26 ACID, FRACTURE, CEMENT SQUEEZE, ETC DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Stage #1 HPBD, pumped 590 bbls, used 2001 # of #16/2£ Stage #2 HPBD, pumped 1130 bbls. ED 27 PRODUCTION TEST 'Date First Production Method of OperatiOnwATER(FIowing,iNJECTORgas lift, etc.) PRODUCTION FOtOIL-BBL GAS-MCF TEST PERIOI: J CALCULATED /OIL-BBL GAS-MCF 24-HOUR RATE: J J CORE DATA Date of Test Hours Tested Press. Flow Tubing Casing Pressure 28 i WATER-BBI CHOKE SIZE J GAS-OIL RATIO I WATER-BBI OIL GRAVITY-APl (corr) Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. N/A Submit in duplicate Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE 9. 30. GEOLOGIC MARKERS FORMATIC NAME Include interval tested, pressure M EAS DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Top Kuparuk C 6360' 5041' Base Kuparuk C 6472' 5129' TESTS data, all fluids recovered and gravity, ORIGINAL 31. LIST OF ATTACHMENTS Summary of Daily Drilling Reports, Surveys 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Title ~, .,,~ ¢..'T.. L L~4 L~ I~r,l (.,. DATE Prepared by Name/Number Sharon AIIsup-Drake/263-4612 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 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- lng and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 Date: 8/7/97 ARCO ALASKA INC. WELL SUMMARY REPORT Page ' 1 WELL:iB-08A WELL ID: AK8949 TYPE: STATE:ALASKA AREA/CNTY: NORTH SLOPE EAST FIELD: KUPARUK RIVER UNIT SPUD: START COMP: RIG-NORDIC BLOCK' FINAL: WI: 0% SECURITY:0 API NUMBER: 50-029-20635-01 07/16/97 (D1) TD: 7694' (7694) SUPV: DLW DAILY: $ 07/17/97 (D2) TD: 7380' ( 0) SUPV: DLW DAILY: $ 07/18/97 (D3) TD: 6549' ( 0) SUPV: DLW DAILY:$ 07/19/97 (D4) TD: 6389' ( 0) SUPV:DLW DAILY:$ 07/20/97 (D5) TD: 6389' ( 0) SUPV:DLW DAILY:$ 07/21/97 (D6) TD: 6628' (239) SUPV:DLW DAILY:$ 07/22/97 (D7) TD: 7245' (617) SUPV'RLM DAILY'$ MW: 9.6 VISC: 42 PV/YP: 9/ 5 APIWL: 7.5 TESTING BOPS Turn key rig move pad to pad from 3K to lB. Accept rig @ 1330 hrs. 7/16/97. Pump water ahead of mud down tubing and take returns to production flowline. Well dead. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 9.5 VISC: 40 PV/YP: 8/ 5 APIWL: 8.0 RUNNING GAUGE RING JUNK BASKET Test BOPE 250/3500 psi, test annular 250/3000 psi. Pump cement. Pull 3.5" tubing. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 9.5 VISC: 95 PV/YP: 15/50 APIWL: 6.5 CUTTING 7" SECTION @ 6343' RIH w/6.125" gauge ring junk basket to 6700'. Recovered large piece of rubber and one piece of cast aluminum. RIH Baker 7" bridge plug, set @ 6540' Test 7" casing to 3500 psi, OK. RIH to 6549' 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 9.6 VISC: 82 PV/YP: 13/55 APIWL: 6.1 POOH W/7" SECTION MILL Circulate and condition mud for milling fluid. Spot section mill knives @ 6339', start cut out. Cut 7" section to 6389' total of 50' Close section mill knives. POOH. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 9.5 VISC' 56 PV/YP' 11/33 APIWL: 7.7 RIH W/BHA %1 TO STSE POOH w/7" section mill BHA. Recovered iron f/flowline. Pump cement slurry. Down squeeze cement. Estimate top of cement @ 6200' 0 CUM:$ 0 ETD'$ 0 EFC'$ 0 MW: 9.5 VISC: 50 PV/YP: 12/27 APIWL: 7.9 DRILLING AHEAD W/6.125" @ 6800 Tag cement @ 6214'. Clean out cement from 6214' to 6344' Sidetrack section from 6344' to 6406' FIT test, EMW = 13.0 ppg. Drill ahead w/6.5" for direction and angle from 6406' to 6628' 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 9.5 VISC: 45 PV/YP: 14/14 APIWL: 6.0 DRILLING AHEAD W/6.125" @ 7665 Directional drill and survey with MWD from 6628' to 7425' 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 Date: 8/7/97 ARCO ALASKA INC. WELL SUMMARY REPORT Page: 2 07/23/97 (DS) TD: 8377' (1132) SUPV:RLM DAILY:$ 07/24/97 (D9) TD: 8960' (583) SUPV:RLM DAILY:$ 07/25/97 (D10) TD: 9174' ( 214} SUPV:RLM DAILY:$ 07/26/97 (Dll) TD: 9710' (536) SUPV:RLM DAILY:$ 07/27/97 (D12) TD: 9710' ( 0} SUPV:RLM DAILY:$ 07/28/97 (D13) TD: 9710' ( 0) SUPV:RLM DAILY: $ 07/29/97 (D14) TD: 9710' ( 0} S UP V: RLM DAILY:$ MW: 11.3 VISC: 46 PV/YP: 25/18 APIWL: 3.6 DRILLING AHEAD W/6.125" @ 8536 Directional drill and survey with MWD from 7425' to 8218' Minor packing off problems while picking up off bottom for connections. CBU. Short trip from 8277' to 7238' . Washed bottom 30' no fill. Had increased cuttings returns from wiper trip. Directional drill and survey with MWD from 8218' to 8377'. Minor packing off problems while picking up off bottom for connections. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 11.4 VISC: 49 PV/YP: 30/28 APIWL: 3.6 CHANGE OUT MUD MOTOR Directional drill and survey with MWD from 8377' to 8960'. Minor packing off problems while picking up off bottom for connections. Had increased cuttings recovery with hi vis sweep. POOH. Tight at 8121' Could not work past 8100' Hole packing off. Circulated and reamed 8121' to 161' 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 11.5 rISC: 50 PV/YP: 26/25 APIWL: 3.2 DRILLING AT 9431' Test all rams, hydril, lines and valves to 300/3500 psi. RIH to 8910' Did not see any tight hole. Wash and ream from 8910' to 8960'. Directional drill and survey with MWD from 8960' to 9174'. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 11.5 VISC: 50 PV/YP: 24/26 APIWL: 3.6 RUNNING 4.5" LINER Directional drill and survey with MWD from 9174' to 9710' . Wipe hole to window at 6339' 0 CUM:$ 0 ETD:~ 0 EFC'$ 0 MW: 11.5 VISC: 49 PV/YP: 23/21 APIWL: 3.0 CIRCULATE AT 6220' Run 4.5" liner, to 9070' hit bridge, work liner to 9192'. Rig up to circulate, hole packed off. Work and pump liner to 9111' Could not get below 9111' 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 11.5 VISC: 46 PV/YP: 20/22 APIWL: 3.5 RIH TO CLEAN OUT Pulled through tight spot at 9060' and packed off. Could not regain circ. Liner stuck. Work stuck pipe. Pipe came loose and regained circ. Debris from centralizers partially pack off hole and 56 bbls were pumped away. Observe well, flowing probably giving back fluid. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 11.5 VISC: 53 PV/YP: 23/27 APIWL: 4.2 POOH Hit bridge at 8205'. Ream from 8180' to 8252'. Hit bridge at 8969' Ream from 9050' to 9208'. Wash and ream from 9612' to 9710'. Circ. and condition mud. Wipe hole to window at 6339'. 0 CUM:$ 0 ETD:$ 0 EFC'$ RECE4VED Date: 8/7/97 ARCO ALASKA INC. WELL SUMMARY REPORT Page: 3 07/30/97 (D15) TD: 9710' ( 0) SUPV: RLM DAILY: $ 07/31/97 (D16} TD: 9611' ( 0) S UP V: RLM DAILY: $ 08/01/97 (D17) TD: 9611' ( 0) S UP V: RLM DAILY: $ 08/02/97 (D18) TD: 9611' ( 0) S UP V: RLM DAILY: $ 08/03/97 (D19) TD: 9611' ( 0) SUPV: RLM DAILY:$ MW: 11.5 VISC: 49 PV/YP: 18/21 APIWL: 4.0 POOH Held prejob safety meeting. Run 4.5" liner. Circulate and condition mud prior to cement job. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 11.5 VISC: 48 PV/YP: 17/18 APIWL: 5.3 RIH WITH PACKER Cement 4.5" liner. Shut down rig for quarterly safety assessment. Circulated out thick cement contaminated mud. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 11.5 VISC: 48 PV/¥P: 16/17 APIWL: 5.2 LOAD PIPE SHED Set packer with top at 6105'_ POOH laying down drill pipe. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 0.0 VISC: 0 PV/YP: 0/ 0 APIWL: 0.0 ND/NU Load pipe shed with 4.5" tubing. Run 4.5" completion. Test tubing to 3500 psi for 30 min, OK. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 MW: 0.0 VISC: 0 PV/YP: 0/ 0 APIWL: 0.0 RIG MAINTENANCE Freeze protect well to 2000' with diesel. ND BOPE and NU tree. Test tree and packoff to 250/5000 psi. Release rig 8/3/97. 0 CUM:$ 0 ETD:$ 0 EFC:$ 0 End of WellSummary for Well:AK8949 KUPARUK RIVE~ UNIT WELL SERVICE REPORT KI (1B-08A(W4-6)) WEIZ. JOB SCOPE JOB NUMBER 1B-08A PERFORATE, PERF SUPPORT 0809971733.3 DATE DALLY WORK UNIT N~MBER 08/11/97 RUN CEMENT BOND TOOL AND PERFRATE 8337 DAY OPERATION COMPLETE I SUCCF-SSi<L I KEYPF-XSON SUPERVISOR 1 NO NO SWS-BAILEY SCHUROSKY Initial Tbg Press [FinalTbgPress ]InitiallnnerAnn [ Final Inner Ann [ Initial Outer Ann [ Final Outer Ann 0 PSI 0 PSI 0 PSI 0 PSI 0 PSI 0 PSI DAILY SUMMARY RUN CEMENT BOND LOG AND PERFORATE W/21/8" EJ III TIME LOG ENTRY 14:00 MIRU SWS #8337 W/BAILEY-FREY-WOOTEN. HOLD SPOT SAFETY MEETING. 15:3 0 RIH W/CBTE-SGTL-TCCB-CALY 16:15 TIE-IN TO SPERRY SUN ROP/NGR DATED 27-JUL-97. 18:00 LOG UP FROM TD AT 9610' TO 6000' AT 2000 FPH. 19:50 FINISH LOGGING CBT. POOH. 20:20 21:30 22:00 AT SURFACE R/D CBT. SWlTHC TO 223ZT CABLE AND PRESSURE CONVI'ROL EQUIPMENT. ARM 2 1/8" EJ III. P/T TO 2500 PSI. RIH W/MPD-H , CC'L-L, AND 2 10' 2 1/8" EJ III GUNS {SWITCHED/ AT 3750' STARTED HAVING TROUBLE GETHNG DOWN.'. WORKED WITH TOOLS FOR ABOUT 45 MINUTES BEFORE GIVE UP AND PULLING OUT OF THE HOLE. 00:15 AT 2050' WHILE PULLING OUT OF THE HOLE, THE CABLE JUMPED SHEAVE AND PARTED LINE AT THE UPPER SHEAVE. THE CABLE STAYED hN THE FLOW TUBES AND AROUND THE UPPER SHEAVE. CLOSED THE BOPS AND REMOVED THE RISER W1TH THE WELL UNPERFORATED, THE PRESSURE WAS ZERO. TIED A SQUARE KNOT IN THE CABLE AND RECOVERED THE WIRELhNE AND'ITIE GU~. 01:30 ATSURFACE. DISARM GUN AND STARTR/D. 02:00 FINISH R/D. LEAVE LOCATION. KUPARUK RIVER UNIT WELL SERVICE REPORT KI(1B-08A(W4-6)) WELL 1B-O8A JOB SCOPE PERFORATE, PERF SUPPORT DATE DAILY WORK 08/12/97 PERFORATE 2 1/2" HSD CARRIER GUNS DAY OPERATION COMPLETE I SUCCESSFUL 2 YES [ YES Initial Tbg PressIFinal Tbg Press [ Initial Inner Ann 0 PSI[ 0 PSI[ 0 PSI DALLY SUMMARY JOB NUMBER 0809971733.3 UNIT N~MBER 8337 KEY PERSON SUPERVISOR SWS-BAILEY BLACK Final lnner Ann IlnitialOuterAnn [ Final Outer Ann 0 PSI 0 PSI 0 PSI PERFORATE F! 9340 - 9350', 9360 - 9380' & 9392' - 9402' ELM W/2.5" HSD DP @ 60 DEG PHASING & 6 SPF TIME LOG ENTRY 14:00 MIRU SWS #8337 W/BAILEY-FREY-WOOTEN 17:00 P/T TO 3500 PSI 17:15 RIH W/2EA 10' 2 1/2" HSD CARRIER GUNS LOADED AT 6 SPF, 60 DEGREE PHASING, DEP PENETRATING CHARGES. RAN A CCL-L ABOVE A 2 1/2" PETROLINE ROLLER, THE SWITCHED GUN, THEN ANOTHER 2 1/2" INLINE PETROLINE ROLLER 18:00 TIE-IN TO SWS CBT DATED 8/11/97. LOG INTO POSITION AT 9375.5' TO SHOOT FROM 9392' TO 9402'. SHOT GUN WITH EXCELENrl' INDICATIONS AT SURFACE. LOG IN~I'O POSITION AT 9335.5' TO SHOOT FROM 9340' TO 9350' HAD GOOD SURFACE INDICATIONS. 20:45 LOG INTO POSITION AT 9354' TO SHOOT FROM 9360' TO 9380'. SHOT WITH GOOD INDICATIONS AT THE SURFACE. POOH. 21:30 ATSURFACE. STARTRIG DOWN. 22:30 FINISH RIG DOWN. LEAVE LOCATION. KUPARUK RIVER UNIT WELL SERVICE REPORT KI(1B-08A(W4-6)) WELL JOB SCOPE JOB NUMBER 1B-08A PERFORATE, PERF SUPPORT 0825970654.2 DATE DAILY WORK UNIT NUMBER 08/31/97 PEFORATE 2 7/8" HSD GUNS SWS 8293 DAY OPERATION COMPLETE I SUCCESSFULI IKEYPERSON I SUPERVISOR 3 YES YES SWS-ELMORE BLACK Initial Tbg Press [ Final Tbg Press [ Initial Inner Ann Final Inner Ann Initial Outer Ann Final Outer Ann 1250 PSI 1250 PSI [ 270 PSI 270 PSI 0 PSI 0 PSI DAILY SUMMARY PERFORATED 9392'-9402', 9360'-9380', 9340'-9350' WITH 2- 7/8" HSD DP 6 SPF & 60 DEG PHASED. I TIME LOG ENTRY 12:30 MIRU SWS 8293 ELMORE. TGSM. PT 300Og. 14:3 0 RIH GUN #1 W/SWIVEL, CCL,P/LINE ROLLER, 10' X 2 7/8" GUN, P/LINE ROLLER.CCL TO TOP SHOT= 5.2' CCL TO BOTTOM=I 8.7' TOTAL STRING LENGTH=22.7'HEAD OD=I 3/8", SWIVEL/CCL OD=1.68", PETROLINE ROLLER OD=-2.5", GUN OD=2.875" 15:00 15:30 16:45 17:15 17:45 19:15 20:15 20:30 21:15 22:00 TIE IN (8112197 SWS PERF RECORD & 8/11/97 SWS CBTE/GR/CCL) TO SHORT JOINq' AND D NIPPLE @ 9178' LU AND SHOOT GUN #1 AT 9392'-9402'. 10' X 6 SPF. GUN SPECS: 34J UJ RDX ,DEEP PENETRATING CHARGE. 10' X 6 SPF. POOH. RIH GUN #2 W/SWIVEL, CCL,P/LINE ROLLER, 20' X 2 7/8" GUN, P/LINdE ROLLER.CCL TO TOP SHOT= 5.2' CCL TO BOTTOM=28.3' TOTAL STRING LENGTH=33. I'HEAD OD=I 3/8", SWIVEL/CCL OD=1.68", PETROLINE ROLLER OI)=-2.5", GUN OD=2.875" TIE IN TO SHORT JOINW & D NIPPLE. LU AND SHOOT GUN #2 AT 9360'-9380'. 20' GUN. GUN SPECS: 34J UJ RDX ,DEEP PENETRATING CHARGE. 20' X 6 SPF. POOH. RIH GUN #3 W/SWIVEL, CCL,P/LINE ROLLER, 10' X 2 7/8" GUN, P/LhNE ROLLER.CCL TO TOP SHOT= 5.2' CCL TO BOTTOM=18.7' TOTAL STRING LENGTH=22.7'HEAD OD=I 3/8", SWIVEL/CCL OD=-1.68", PETROLINE ROLLER OD=-2.5", GUN OD=2.875" TIE IN TO FLAG ON LINE, LU PAST SHORT JT. LU AND SHOOT GUN #3 AT 9340'-9350'. 10' X 6 SPF. GUN SPECS: 34J UJ RDX ,DEEP PENETRATING-CtfARGE. 10' X 6 SPF. POOH. AT SURFACE. BD LUBRICATOR. RELEASE RADIO SILENCE. LEAVE WELL SI. RI)MO & TURN OVER TO PRODUCTION F/AM HPBD. ARCO Alaska, Inc. A KUPARUK RIVER UNIT WELL SERVICE REPORT KI(1B-08A(W4-6)) WEIL l B-08A DATE O9/28/97 DAY 1 I)AII,Y JOB SCOPE JOB NUMBER PERFORATE, PERF SUPPORT 0918972113.7 DAILY WORK UNIT NUMBER PERFORATE W/2 1/8" EJ DP 8337 OPERATION COMPLETE I SUCCESSFUL I KEYPERSON SUPERVISOR YES YES SWS-BAILEY BLACK lnitialTbgPress [FinalTbgPress IanitialInnerAnn IFinallnnerAnn ] Initial Outer Ann Final Outer Ann 1250 PSI 1250 PSI, 125 PSI 250 PSI 10 PSI 10 PSI SUMMARY PERFORATED 9306, 9310', 9314', 9318', 9322' & 9326' ELM (ONE SHOT A FOOT) W/2-1/8" EJ DP 20' OF 2 1/8" EJ DP @ 0 DEG PItASING / ORIENTATION. TIME 07:30 10:30 13:00 14:00 LOG ENTRY MIRU SWS (BAILEY & CREW) & APC. MU GUN ASSEMBLY (1-11/16" SWS SLINE ROLLERS / 2-1/8" EJ DP / CCL) TL-34'. TGSM & JOB OVERVIEW. PT BOPE TO 3500 PSI. RIH W/GUN ASSEMBLY TO 9440' ELM. TIE IN W/8/11/97 SWS CBTE/GR/CCL. PERFORATE 1 SHOT PER FOOT@ 9306',10',14',18',22' & 26' W/2-1/8" EJ DP, 0 DEG PHASED /ORIENTED. SAW POSITIVE SURFACE INDICATION. LOG UP & POOH. AT SURFACE. BEGIN liD. ALI. GUNS FIRED. FINISH RD. TURN OVER TO PRODUCTION F1 INJECTION. MOVE 3'0 1 B- 15. ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 November 26, 1997 Mr. David J. Johnston Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Subject: 1B-08A (Permit No. 97-112) Well Completion Report Dear Mr. Commissioner: Enclosed is the well completion report for the completion on KRU 1B-08A. If there are any questions, please call 263-4622. Sincerely, W. S. Isaacson Drilling Engineer Kuparuk Development WSl/skad ORIGtNAL SPE i-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE ARCO ALASKA INC KRU / ZB-0aA 500292063501 NORTH SLOPE BOROUGH COMPUTATION DATE: 9/ 6/97 DATE OF SURVEY: 072797 MWD SURVEY JOB NI/MBER: AK-MW-70215 KELLY BUSHING ELEV. = 93.00 FT. OPERATOR: ARCO ALASKA INC TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH COURS INCLN DG MN COURSE' DLS TOTAL DIRECTION RECTANGULAR COORDINATES DEGREES DG/100 NORTH/SOUTH EAST/WEST VERT. SECT. 6299.00 4991.29 4898.29 34 42 6344.00 5028.33 4935.33 34 31 6479.66 5134.81 5041.81 42 14 6571.64 5197.94 5104.94 50 59 6667.65 5253.22 5160.22 58 39 S 72.50 E. .00 853.76S 3111.62E S 71.70 E 1.09 861.62S 3135.94E S 86.17 E 8.70 876.78S 3218.22E N 89.27 E 10.17 878.40S 3284.95E S 89.74 E 8.02 878.11S 3363.36E 3109.22 3133.52 3215.76 3282.49 3360.90 6764.43 5301.80 5208.80 6860.55 5347.18 5254.18 6955.33 5391.01 5298.01 7052.11 5436.59 5343.59 7148.17 5480.58 5387.58 61 62 62 61 64 4 33 21 26 3 S 89.31 E 2.54 878.81S 3447.04E S 89.71 E 1.58 879.53S 3531.76E N 89.35 E .90 879.26S 3615.80E N 88.80 E 1.07 877.89S 3701.15E S 87.53 E 4.36 878.87S 3786.52E 3444.57 3529.29 3613.33 3698.69 3784.05 7243.93 5522.55 5429.55 7338.18 5564.19 5471.19 7434.18 5607.69 5514.69 7527.74 5650.81 5557.81 7625.17 5695.07 5602.07 7719.00 5737.78 5644.78 7814.54 5782.28 568.9.28 7909.58 5826.05 5733.05 8004.9-8 5869.75 5776.75 8100.32 5914.64 5821.64 63 58 63 35 62 30 62 36 63 20 62 30 61 58 63 11 62 16 61 32 N 89.28 E 3.00 880.18S 3872.57E N 87.94 E 1.34 878.138 3957.09E N 86.55 E 1.71 874.02S 4042.56E N 87.63 E 1.03 869.81S 4125.48E N 89.55 E 1.91 867.688 4212.24E N 89.84 E .95 867.23S 4295.78E N 89.32 E .73 866.62S 4380.32E S 88.98 E 2.04 866.87S 4464.66E S 88.82 E .97 868.50S 4549.45E S 88.78 E .78 870.26S 4633.54E 3870.10 3954.63 4040.10 4123.04 4209.80 4293.34 4377.88 4462.23 4547.00 4631.09 8194.26 5958.46 5865.46 8290.07 6002.69 5909.69 8384.00 6047.10 5954.10 8480.55 6092.39 5999.39 8576.08 6136.54 6043.54 8671.23 6180.80 6087.80 8766.37 6225.21 6132.21 8862.36 6270.14 6177.14 8955.80 6313.76 6220.76 9052.33 6358.44 6265.44 9147.37 6402.06 6309.06 9244.48 6446.69 6353.69 9340.1.7 6490.50 6397.50. 9437.18 6534.39 6441.39 9531.20 6577.03 6484.03 62 50 62 9 61 24 62 37 62 19 S 89.18 E 1.44 871.74S 4716.61E S 89.48 E .77 872.73S 4801.59E S 89.69 E .82. 873.33S 4884.36E S 88.78 E 1.51 874.47S 4969.61E S 89.05 E .41 876.08S 5054.31E 62 14 S 88.12 E .87 62 5 S 89.32 E 1.13 62 5 S 89.24 E .08 62 15 N 88.04 E 2.58 62 36 N 88.07 E .37 62 44 N 87.54 E .51 62 32 N 87.66 E' .23 62 57 N 87.59 E ·.42 63 15 N 87.87 E ".40 62 48 N 87.54 E ..56 878.16S 880.04S 881.10S. 880.24S 877.338 · 874.10S 870.49S 866.96S 863.54S 860.18S 4714.16 4799.14 4881.90 4967.14 5051.84 5475.56w. 5473.09 5559.94E 5557.47 5646.11E ..5643.66 5731. lie ': '--.5728 . 66 5817.55E . i'5815 . 12 5901.28E 5898 . 85 · ORIGINAL SPt Y-SI/N DRILLING SERVICES ANCHORAGE ALASKA PAGE 2 ARCO ALASKA INC KRU / 1B-08A 500292063501 NORTH SLOPE BOROUGH COMPUTATION DATE: 9/ 6/97 DATE OF SURVEY: 072797 MWD SURVEY JOB NUMBER: AK-MW-70215 KELLY BUSHING ELEV. = 93.00 FT. OPERATOR: ARCO ALASKA INC TRUE SUB-SEA COl/RS COURSE- DLS TOTAL MEASD VERTICAL VERTICAL INCLN DIRECTION RECTANGULAR COORDINATES VERT. DEPTH DEPTH DEPTH DG MN DEGREES DG/100 NORTH/SOUTH EAST/WEST SECT. 9626.24 6620.50 6527.50 62 45 N 88.11 E .54 9653.73 6633.08 6540.08 62 44 N 88.18 E .24 9710.00 6658.86 6565.86 62 44 N 88.18 E .00 856.97S 5985.74E 5983.32 856.18S 6010.16E 6007.75 854.59S 6060.16E 6057.75 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE-DIMENSION MINIMUM CURVATURE METHOD. HORIZONTAL DISPLACEMENT = 6120.12 FEET AT SOUTH 81 DEG. 58 MIN. EAST AT MD = 9710 VERTICAL SECTION RELATIVE TO WELL HEAD VERTICAL SECTION COMPUTED ALONG 89.84 DEG. TIE-IN SURVEY AT 6,299.00' MD WINDOW POINT AT 6,344.00' MD PROJECTED SURVEY AT 9,710.00' MD S]~ tY-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE ARCO ALASKA INC KRU / lB- 0 SA 500292063501 NORTH SLOPE BOROUGH COMPUTATION DATE: 9/ 6/97 DATE OF SURVEY: 072797 JOB NUMBER: AK-MW-70215 KELLY BUSHING ELEV. = 93.00 FT. OPERATOR: ARCO ALASKA INC INTERPOLATED VALUES FOR EVEN .1000 FEET OF MEASURED DEPTH TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST MD-TVD VERTICAL DIFFERENCE CORRECTION 6299.00 4991.29 4898.29 853.76 S 3111.62 E 1307.71 7299.00 5546.76 5453.76 879.39 S 3922.02 E 1752.24 444.53 8299.00 6006.86 5913.86 872.80 S 4809.49 E 2292.14 539.90 9299.00 6471.78 6378.78 868.50 S 5694.47 E 2827.22 535.08 9710.00 6658.86 6565.86 854.59 S 6060.16 E 3051.14 223.92 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE-DIMENSION MINIMUM CURVATURE METHOD. SP~ .Y-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE ARCO ALASKA INC KRU / lB- 0 SA 500292063501 NORTH SLOPE BOROUGH COMPUTATION DATE: 9 / 6 / 97 DATE OF SURVEY: 072797 JOB NUMBER: AK-MW-70215 KELLY BUSHING ELEV. = 93.00 FT. OPERATOR: ARCO ALASKA INC INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST MD-TVD VERTICAL DIFFERENCE CORRECTION 6299.00 4991.29 4898.29 853.76 S 3111.62 E 1307.71 6301.11 4993.00 4900.00 854.02 S 3112.84 E 1308.11 .40 6424.66 5093.00 5000.00 872.77 S 3182.75 E 1331.66 23.55 6563.92 5193.00 5100.00 878.44 S 3279.02 E 1370.92 39.26 6746.24 5293.00 5200.00 878.61 S 3431.12 E 1453.24 82.32 6959.63 5393.00 5300.00 879.22 S 3619.60 E 1566.63 113.38 7176.54 5493.00 5400.00 879.74 S 3812.01 E 1683.54 116.91 7402.34 5593.00 5500.00 875.72 S 4014.37 E 1809.34 125.81 7620.55 5693.00 5600.00 867.71 S 4208.11 E 1927.55 118.21 7837.34 5793.00 5700.00 866.38 S 4400.44 E 2044.34 116.79 8054.84 5893.00 5800.00 869.41 S 4593.55 E 2161.84 117.50 8269.32 5993.00 5900.00 872.57 S 4783.25 E 2276.32 114.48 8481.87 6093.00 6000.00 874.50 S 4970.78 E 2388.87 112.55 8697.43 6193.00 6100.00 878.92 S 5161.68 E 2504.43 115.56 8911.23 6293.00 6200.00 881.42 S 5350.63 E 2618.23 113.80 9127.58 6393.00 6300.00 874.85 S 5542.36 E 2734.58 116.35 9345.67 6493.00 6400.00 866.76 S 5736.00 E 2852.67 118.08 9566.15 6593.00 6500.00 858.85 S 5932.33 E 2973.15 120.48 9710.00 6658.86 6565.86 854.59 S 6060.16 E 3051.14 78.00 THE CALCULATION PROCEDURES USE A LINEAR INTERPOLATION BETWEEN THE NEAREST 20 FOOT MD (FROM MINIMUM CURVATURE) POINTS 9/22/97 ... GeoQuest 500 w. International Airport Road Anchorage, AK 99518-1199 ATTN: Sherrie NO. 11366 Company: Alaska Oil & Gas Cons Comm Attn: Lori Taylor 3001 Porcupine Drive Anchorage, AK 99501 Field: Kuparuk (Reservoir Analysis Logs) Well Job # Log Description Date BL RF Sepia Floppy Disk 1B-8A ~-/- /Io~. CEMENT BOND LOG 970811 I 1 1Q-08A (~7 - ~) ~ '~ STATIC BO'I-rOM HOLE SURVEY 970729 I 1 1R-34 ~z~- /(~. GAS LIFTSURVEY 970810 I I ... 3 F-..1.2 ~ ~- ~"7 ~) [ ~, ~ ~ INJECTION PROFILE 97061 9 I 1 31-02 '~- ~o ~ [.&~ ~ INJECTION PROFILE .... 970818 I 1 31-06 ~ ~ --- O'~'~ {),,~ ¢._., INJECTION PROFILE 970708 I 1 !3K-23 ~- ocl'''] CEMENT EVALUATION LOG W/GR 970629 I 1 3K-23 ~ CEMENT BOND LOG W/GR 970629 I 1 '3K-26 ~ - ©"7'"l STATIC BHPLOG 970723 I 1 !3M-17 ~'7 -C)~ GAS LIFT SURVEY 970707 I 1 3 M-23 C~ '~ -. I ~-J GAS LIFT SURVEY 970704 I 1 3N-03 ~{o- Oi(.~ (.,k.I C.~, INJECTION PROFILE 970703 I 1 3N-7 ~ ~ '- O~, PRODUCTION PROFILE 970702 I 1 :3N-7 ~ DEFT LOG 970702 I I Please sign and return one copy of this transmittal to Sherrie at the above address. Thank you. RECEIVED SEP 2 9 1997 Alaska Oil & Gas C<)~s. Commission Anchorage C! I::! I I--LI N G S E I:l~J I C ~:: S WELL LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Comm. Atm.: Loft Taylor 3001 Porcupine Dr. Anchorage, Alaska 99501 MWD Formation Evaluation Logs 1B-08A, September 24, 1997 AK-MW-70215 The technical data listed below is being submitted herewitk Please address any problems or concemS to the attention of.' Jan Galvi~ Sperry-Sun Drilling Services, 5631 Silverado Way, #G, Anchorage, AK 99518 1 LDWG formatted Disc with verification listing. APl#: 50-029-20635-01 5631 Silverado Way, Suite G · Anchorage, Alaska 99518 · (9.07) 563-3256 ° Fax (907) 563-7252 A Dresser Industries, Inc. Company September 10, 1997 ARCO Alaska, Inc. AOGCC, Lori Taylor 700 G Street Anchorage, AK 99501 Re: MWD Survey 1B-08A Dear Sir/Madam, Enclosed is two hard copy of the above mentioned file(s). Well 1B-08A MWD survey Tie-In point at 6,299.00', Window point at 6,344.00' and a Projected survey at 9,710.00'. Please call me at 563-3256 if you have any questions or concerns. Regards, William T. Allen Survey Manager Attachments. · ~'Idr~0rage 5631 Silverado Way, Suite G · Anchorage, Alaska 99518 · (9.07) 563-3256 · Fax (907) 563-7252 A Dresser Industries, Inc, Company TONY KNOWLE$, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 June 13. 1997 Mikc Zanghi Drill Site Dcvclop. Supv. ARCO Alaska. Inc. PO Box 100360 ,Anchorage, AK 99510-0360 ae~ Kuparuk River Unit 1B-08A ARCO Alaska. Inc. Pcrmit No. 97-112 Sur. Loc.: 501 'FNL. 141'FEL.SEC 09. 'Fl 1N.RIOE. UM Btmhole Loc: 1386'FNL.636'FWL.SEC Il.T1 IN.RIOE. UM Dcar Mr. Zanghi: Encloscd is thc approvcd application for pcnnit to rcdrill thc above rcfcrcnccd ,~vcll. Thc permit to rcdrill docs not cxcmpt you from obtaining additional pcrmits rcquircd by law from other governmental agcncics, and docs not authorize conducting drilling opcrations until all other rcquircd permitting dctcrminations arc madc. Thc blowout prcvcntion cquipmcnt {BOPE) must bc tcstcd in accordancc with 20 AAC 25.035: and the mcchanical intcgrity (MI) of thc injcction ,wells must bc dcmonstratcd under 20 AAC 25.412 and 20 25.030(g)(3). Sufficient notice (approximatcly 24 hours) of thc MI tcst before opcration, and of thc BOPE tcst pcrformcd bcforc drilling bclow thc surfacc casing shoc. must be given so that a rcprcscntativc of thc Commission may xvitncss thc tcsts. Noticc mavbc given bv contacting thc Commission pctrolcum ficld inspcctor on thc North Slopc pager at 659-3607. i · . · ~ Chairman %~, BY ORDER OF THE COMMISSION dll"encl{~sures l)epartmcnt o1' Fish & (}amc. l lahital Section w, o cncl. l)cpartmcnt o1' l';nvimmm~cnt C(mscrvatitm w, o cnct. STATE OF ALASKA ALAS¥~A OIL AND GAS CONSERVATION ~MISSI~,~ PERMIT TO DRILL 20 AAC 25.005 la. Type of Work Drill [~ Redrill X lb Type of Well Explore. tory" [] Stratlbraphlc Test [] Development OII [] Re-Entry r'~ Deepen r~ Service X Development Gas ~-1 Single Zone X Multiple Zone r~ 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool ARCO Alaska, Inc. RKB 93', Pad 61' feet Kuparuk River Field 3. Address 6. Property Designation Kuparuk River Oil Pool P. O. Box 100360, Anchora~le, AK 99510-0360 ADL 25649, ALK 467 4. Location of well at surface 7. Unit or property Name 11. Type Bond (see 2o AAC 25.025) 501' FNL, 141' FEL, Sec. 9, T11N, R10E, UM Kuparuk River Unit Statewide At top of productive interval 8. Well number Number · 1387' FNL, 231' FWL, Sec. 11, T11N, R10E, UM 1B-08A #U-630610 At total depth 9. Approximate spud date Amount 1386' FNL, 636' FWL, Sec. 11, T11N, R10E, UM 6/20/97 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) property line 1 B-1 7 9706' MD 231' @ Top Intvl feet 13' @ surface feet 2560 6661' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035(e)(2)) Kickoff depth 6344' feet Maximum hole angle 62.25° Maximum surface 3040 '~ psig At total depth (TVD) 3750 '" psig 18. Casing program Settln~ Deplh size Specifications Top Bottom Quantity of cement Hole Casi~ Wei~lht Grade Couplincj Len~h IV~ TVD Iv~ TVD linclude sta~le data) 6-1/8" 4-1/2' 12.6# L-80 NSCT 3567' 6139' 4860' 9706' 6661' 488 sxs Class G 19. To be completed for Reddll, Re-entry, and Deepen Operations. --- ~ -- Present well condition summary Total depth: measured 8508 feet Plugs (measured) true vertical 6913 feetdUN -9 Effective depth: measured 8320 feet Junk (measured) ~a~ka 0il & Gas Cons. C0mmissi0rl true vertica 6752 feet Arrch0rage Casing Length Size Cemented Measured depth True Vertical depth Structural Conductor 80' 1 6 ' 200 Sx PF 112' 112' Surface 2312' 1 0-3/4' 1000 sx Fondue, 250 sx AS II 2343' 2246' Intermediate Production 8538' 7 ' 923 sx Class G 8465' 6876' Liner Perforation depth: measured 7872'-7966', 8126'-8134', 8148'-8172', 8175'-8184'MDORIGINAL true vertical 6359'-6443', 6583'-6590', 6602'-6623', 6626'-6634' TVD 20. Attachments Filing fee X Property plat r~ BOPSketch X Diverter Sketch E] Drilling program X Drilling fluid program X Time vs depth plot r-~ Refraction analysis E] Seabed report D 20 AAC 25.050 requirements X 21. Signed I hereby certifY thThe I°reg°ing is true and c°rrect t° the best °f mY kn°wledge: ~//~ ,, ~/1~(~ ~,~ Title Drill Site Develop. Supv. (contact William Isaacson at 263-4622 with ~lU(~stions.) ¢ ' ' [.~' / ~ Commission Use Only Permit Number '1' APl r~j~a~:)er I ApProval date / , -.~ C~ ,-., I See cover letter for ?'7-'//.z.- 1 50- o ~.. ?- ~ ~ 4; z 5'- ~ / I ("'~-t 5"/) !other requirements Conditions of approval Samples required E] Yes J~ No Mud logrequired r~ Y~s [~ No Hydrogen sa,ida measures .~ Yes E] No Directional survey required .~ Yes [-] No Required working pressure for BOPE E] 2M r~ 3M [~ 5M ~ 10M ~] 15M Other:Original Signed By[~ David W. Johnstonby order of Approved by Commissioner the commission Date REDRILL PLAN SUMMARY Well 1B-08A Type of well (producer/injector): Surface Location- Top Producing Interval: Bottom Hole Location: MD: TVD: Rig: Estimated Start Date: Operation Days to Complete: Injector 501' FNL, 141' FEL, SEC 9, T11N, R10E, UM 1387' FNL, 231' FWL, SEC 11, T11N, R10E, UM 1386' FNL, 636' FWL, SEC 11, T11N, R10E, UM 9706' 6661' Nordic Rig 2 6-2O-97 15 Drill Fluids Program: Density PV YP Viscosity Initial Gel 10 Minute Gel APl Filtrate pH % Solids Milling Section in 7" casin~] 9.5 >25 30-35 85-95 20-30 30-40 8.5-9.5 Kick off to weight up 9.5-9.7 5-15 5-8 30.40 2-4 4-8 8-10 9.5-10 4-7% Weight up to TD 11.5 10-18 8-12 35-50 2-4 4-8 4-5 through Kuparuk 9.5-10 <12% Drilling Fluid System: Swaco Geolograph Adjustable Linear Shaker Brandt SMC-10 Mud Cleaner Triflow 600 vacuum Degasser, Poor Boy Degasser Pit Volume Totalizer (Visual and Audio Alarm) Trip Tank Fluid Flow Sensor Fluid Agitators and Jetting Guns Notes: Drilling fluid practices will be in accordance with the appropriate regulations stated in 20 AAC 25.033. Page 1 Casing/Tubing Hole size 6-1/8" Program: Csg/Tbg 4-1/2", 12.6#, L-80, NSCT Tubing 4-1/2", 12.75#, L-80, EUE Length Too (MD/TVD) Btm (MD/TVD 3567' 6139'/4860' 9706'/6661' 6113' 26'/26' 6139'/4860' Cement Calculations: Casina to be cemented: -- 4-1/2" in 6-1/8" open hole Volume = 488 sxs of class G Blend @ 1.19 cu ft/sx Based on: Shoe volume, open hole volume + 66%, & 200' liner lap. Well Control: Well control equipment consisting of 5000 psi working pressure pipe rams, blind rams, and annular preventer will be installed. Maximum anticipated surface pressure is estimated at 3,040 psi and is calculated using a gas column to surface. The expected leak-off at the section cut in the 7" casing is estimated at 14.0 ppg EMW. With an expected formation pressure in the Kuparuk of 3750 psi and a gas gradient of 0.11 psi/ft, this shows that formation breakdown would not occur before a surface pressure of 3,040 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3500 psi. See attached BOPE schematic. Drilling Hazards: Lost Circulation: Overpressured Intervals: Other Hazards: Directional: KOP: Max hole angle: Close approach: The suspect lost circulation zones throughout the Kuparuk field are the K- 10 and the K-5 intervals. The sidetrack 1B-08A, will kick off out of the 7" casing below both the K-5 and K-10. The casing around the kick-off window will be squeezed with cement prior to ddlling out, which should isolate both the intervals from sidetrack operations. If the cement squeeze is unsuccessful at achieving isolation, it is believed that both intervals should be able to handle the expected mud weights to be used for this sidetrack. Recent infill ddlling data shows that wells in the area of 1B-08A were drilled to TD through the K-5 and K-10 intervals with mud weights as high as 11.7 ppg and no loses. The kick-off point in 1B-08A is below any zones which would be of pressure concern prior to weighting up for the KupanJk interval. None RECEIVED 6344' MD / 5029' TVD Alaska 0ii & Gas Cons. c0mmissi011 Amh0rage 62.25° (in sidetrack portion) 61.5° (in odginal well at 3800' MD) No Hazards Page 2 Logging Program: Open Hole Logs: GR/Resistivity Cased Hole Logs: GR/CET/CCL Notes: All drill solids generated from the 1B-08A sidetrack will be hauled to CC-2A in Prudhoe Bay for gdnd and inject. If the Kuparuk River bridge outage will not allow trucking of these solids to Prudhoe, they will be stored and later processed or disposed of in a permitted solids disposal area. Incidental fluids developed from ddlling operations will be hauled to the nearest permitted disposal well or to Parker 245 to be disposed by annular pumping into the permitted annulus Parker is connected to at that time. The permitted well will be within the Kuparuk River Unit. Page 3 KRU 1B-08A GENERAL SIDETRACK PROCEDURE PRE-RIG WORK: . RU slickline unit. RIH and set isolating blanking plug in 'D' nipple profile at 8054' MD. Pull dummy valve from C Sand mandrel at 8019' MD and circ valve from mandrel at 7747' MD, leaving an open pocket in each. Set 3-1/2" cement retainer in first joint of tubing immediately below top production packer. . RU CTU. RIH with stinger for 3-1/2" cement retainer. Sting into retainer and pump cement squeeze below retainer and into C Sand perfs with enough cement volume to fill the 7" casing and 3-1/2" tubing down to blanking plug in 'D' landing nipple. Unsting from retainer and circulate the well clean. 3. RU slickline unit. RIH and pull dummy valve from bottom GLM at 7649' MD, leaving an open pocket. WORKOVER RIG WORK: 1. MIRU Nordic Rig 2. Lay hard-line to tree. 2. Verify well is dead. Load pits w/water. Circulate well to water. Set BPV. 3. ND tree. NU and test BOPE. 4. Screw in landing joint. POOH laying down all tubing and jewelry. 5. RU E-line unit. Run gauge ring through bddge plug setting depth. RIH and set permanent bridge plug at 6540' MD-RKB. 6. Pressure test wellbore to 3000 psi to ensure isolation from perforations and wellbore integrity above bridge plug. 7. PU DP and RIH with section mill to top of bddge plug. Circulate well to milling fluid. Spot an 18 ppg balanced mud pill from PBTD to the base of proposed section. 8. Pull up to proposed section top at 6340' and cut a 50' section in the 7" casing from 6340' - 6390'. POOH w/mill. . RIH w/open ended DP. Wash down through section and circulate any metal shavings from well. Mix and pump balanced cement kick-off plug f/100' below base of section to 200' above top of section. POOH. 10. RIH w/6-1/8" bit, mud motor, MWD/LWD, and steerable ddlling assembly. Dress off cement to top of section. Kick-off well and directionally ddll to total depth as per directional plan. Short tdp to section in casing. POOH. 11. Run 4-1/2" liner to TD w/200' of ovedap to top of milled section. 12. Cement liner. Set liner hanger. POOH w/DP. 13. RIH w/liner tie-back seals and liner top production packer on DP. Sting into polished bore receptacle at top of liner and set production packer. POOH laying down DP. Page 4 14. RIH with 4-1/2" completion assembly. Latch into top of production packer, shear PBR, and space out. Displace well to sea water at max rate. Freeze protect well with diesel and land tubing. Test tubing, liner, and annulus. 15. ND BOPE. NU and test tree. RDMO Nordic. 16. Clean out well to PBTD w/coiled tubing. Run Cement Evaluation tool & perforate through tubing. Lower Limit: 13 days Expected Case: 15 days Upper Limit: 20 days No problems milling section, drilling new hole, or running completion. Difficulties encountered milling section, or ddlling new hole. WSI 6/6/97 Page 5 Created by jones For: Date plotted : 6-Jun-97 Plot Reference is 8A Ve¢$ion Coordinctcs ore in f~et reference 4800 ARCO ALASKA, Inc. Field : Kuporuk River UnH Locolion : North Slope, Alaska k,ee,? 2800 ~ooo ~oo ~44oo ~6oo ~8oo ~ooo ~oo ~oo ~oo ~oo ~ooo ~oo ~oo ~oo ~oo ~ooo ~oo I I I I I t I I I I I t I I I I I I I I I I I I ~ I I I I I I I I I Nc~ i I 400 600 u3 o t- 13- 80O ..q. 1 000I V 1200 5000 5200 5400 (D C- 5600 5800 __ 0 ,_ '~ 6000 (D 6200 I 64oo V 6600 680O 70O0 KOP - Sidetrack Pt 38.82 46.81 BLS: 9.00 deg per 100 ft 55.05 EOC Base HRZ K-1 TARGET - T/ Unit C4 1B-8A (T/C4) Rvsd 5-Jun-97 __ WELL PROFILE DATA ..... Point ..... MD Inc Dir TVD North East V. Sect Beg/lO0 KOP 63444.00 34.52 108.35 5028.88 -861.50 3135.55 3133,12 0,00 End of Build/Turn 6685.88 62.25 89.84 5254.78 -892.32 3384.79 3582.27 9.00 Target 1B-SA (T/C4) Rv 92448,26 62.25 89.844 6448.00 -885.93 5652.56 56¢9.87 0.00 End of Hold 9505.95 62.25 89.84 6568.00 -885.28 5880.45 5877.92 0.00 T.O. & End of Hold 9705.95 62.25 89.84 6661.13 -884.78 6057.42 6O5430 o.oo Top Kup Sands Base C3 Top Unit B Top C1 TO - Casing Pt 3000 3200 34-00 3600 3800 4000 4200 444400 4600 4800 5000 5200 54400 5600 5800 6000 6200 Vertical Section (feet) -> Azimuth 89.84 with reference 0.00 N, 0.00 E from slot #SA 1B-08A Proposed Co,,,pletion 4-1/2" landing nipple profile RKB = 93' Pad Level = 61' ** All Depths are reference Nordic 2 RKB 10-3/4" 45.5#, J-55 set at 2342' MD 4-1/2", 12.75~, L-80 EUE 8rd Mod tubing to Sudace 4-1/2" Sliding Sleeve 7" x 4-1/2" permanent production packer with PBR at +/-6125' MD 4-1/2" liner top at +/-6140' MD Liner Top: - Baker 5-1/2" setting sleeve (4.997" ID). - Baker 10' Seal Bore Extension (4.75" seal bore, 5.875" OD). - Baker 5" x 7" 18# L-80 'CMC' mechanical liner hanger (4.276" ID) w/4-1/2" NSCT pin on bottom. Section in 7" 6339' - 6389' MD Bridge Plug at +/- 6539' MD Abandoned C Sand Perfs RECEIVED Ju -9 1991 AJaska 0il & Gas Cons, Commission A~chorage 4-1/2" landing nipple profile set +/- 100' MD above top of the C Sand. Abandoned A Sand Perfs 7", 26#, J-55 set at 8464' MD 4-1/2" L-80 NSCT liner @ +/-9706' MD WSI 6/6/97 7-1/16" 5000 PSI BOP STACK ACCUMULATOR CAPACITY TEST PIPE RAM ~= I I BLIND RAM~=' 1. CHECK AND FILL ACCUMULATOR RESERVOIR TO PROPER LEVEL WITH HYDRAULIC FLUID. 2. ASSURE THAT ACCUMULATOR PRESSURE IS 3000 PSI WITH 1500 PSI DOWNSTREAM OF THE REGULATOR. 3. OBSERVETIME, THEN CLOSE ALL UNITS SIMULTANEOUSLY AND RECORD THE TIME AND PRESSURE REMAINING AFTER ALL UNITS ARE CLOSED WITH CHARGING PUMP OFF. 4. RECORD ON THE IADC REPORT. THE ACCEPTABLE LOWER LIMIT IS 45 SECONDS CLOSING TIME AND 1200 PSI REMAINING PRESSURE. BOP STACK TEST J MUD CROSS 4 3 PIPE RAM ~ 2 1. FILL BOP STACK AND MANIFOLD WITH WATER 2. CHECK THAT ALL HOLD-DOWN SCREWS ARE FULLY RETRACTED. PREDETERMINE DEPTH THAT TEST PLUG WILL SEAT AND SEAT IN WELLHEAD. RUN IN LOCK-DOWN SCREWS IN HEAD. 3. CLOSE ANNULAR PREVENTER AND CHOKES AND BYPASS VALVES ON THE MANIFOLD. ALL OTHERS OPEN. 4. TEST ALL COMPONENTS TO 250 PSi AND HOLD FOR 5 MINUTES. INCREASE PRESSURE TO 3500 PSI AND HOLD FOR 5 MINUTES. BLEED TO ZERO PSI. 5. OPEN ANNULAR PREVENTOR AND INSIDE MANUAL KILL AND CHOKE LINE VALVES. CLOSE TOP PIPE RAMS, HCR VALVE ON CHOKE LINE, AND OUTSIDE MANUAL VALVE ON KILL LINE. 6. TEST TO 250 PSI AND 3500 PSI AS IN STEP 4. 7. CONTINUE TESTING AL VALVES, LINES, AND CHOKES WITH A 250 PSI LOW AND 3500 PSI HIGH. TEST AS IN STEP 4. DO NOT PRESSURE TEST ANY CHOKE THAT IS NOT A FULL CLOSING POSITIVE SEAL CHOKE. 8. OPEN TOP PIPE RAMS AND CLOSE Bo'FrOM PIPE RAMS. TEST BOTTOM RAMS TO 250 PSI AND 3500 PSI. 9. OPEN PIPE RAMS. BACKOFF RUNNING JT AND PULL OUT OF HOLE. 10. CLOSE BLIND RAMS AND TEST TO 3500 PSI FOR 5 MINUTES. BLEED TO ZERO PSI. 11. OPEN BLIND RAMS AND RECOVER TEST PLUG. MAKE SURE MANIFOLD AND LINES ARE FULL OF ARCTIC DIESEL AND ALL VALVES ARE SET IN THE DRILLING POSITION. 12. TEST STANDPIPE VALVES TO 3500 PSI. 13. TEST KELLY COCKS AND INSIDE BOP TO 3500 PSI WITH KOOMEY PUMP. 14. RECORD TEST INFORMATION ON BLOWOUT PREVENTER TEST FORM. SIGN AND SEND TO DRILLING SUPERVISOR. 15. PERFORM COMPLETE BOPE TEST ONCE A WEEK AND FUNCTIONALLY OPERATE BOPE DAILY. 1.11" - 3000 PSI CASING HEAD 2.11" - 3000 PSI x 7-1/16" 5000 PSI TUBING HEAD 3.7-1/16"- 5000PSI SINGLE GATE W/PIPE RAMS 4.7-1/16"- 5000 PSI DRLG SPOOL W/CHOKE & KILL LINES 5.7-1/16" - 5000 PSI SINGLE GATE W/ BLIND RAMS 6.7-1/16" - 5000 PSI SINGLE GATE W/PIPE RAMS 7.7-1/16" - 5000 PSI ANNULAR PREVENTER NORDIC RIG LEVEL z Ltl Z 7Y-0" ' 25'-0' n': STAIRS - =o I rosco r-8oo ,,,~- o ~ TRIPLEX MUD I~" -~L PUMP _: EMSCO F-800 TRIPLEX MUD PUMP STAIRS - icebox. ~CONSOU~ -- 28'-6' 12'-4.' J 8'-6' - ~ 36'-0' I 5Y-O' NORDIC RIG 92 LEVEL 2 NORDIC RIC~ 4t2 LEVEL 3 I UN~ / l SPOOL I iAIR HEATER MUD TANK 750 BBLS SPIRAL ~'NR~ WATER TANK /GLYCOL TANK HTDRAUUC - 15'-6" CHOKE: MANIFOLD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISS~. APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon ~ Suspend -- Alter casing _ Repair well Change approved program_ Operation Shutdown_ Re-enter suspended well _ Plugging ~X Time extension Stimulate Pull tubing_ Variance _ Perforate _ Other Plugback for X Redrill 2. Name of Operator ARCO Alaska, Inc, 3. Address P. O. Box 100360, Anchorage, AK 99510 5. Type of Well: Development _ Exploratory _ Stratigraphic _ Service ~X 4. Location of well at surface 501' FNL, 141' FEL, Sec. 9, T11N, R10E, UM At top of productive interval 1700' FNL, 1627' FEL, Sec 10, T11N, R10E, UM At effective depth 1865' FNL, 1488' FEL, Sec. 10, T11N, R10E, UM At total depth 1946' FNL, 1435' FEL, Sec. 10, T11N, R10E, UM 12. Present well condition summary Total Depth: measured (approx) true vertical 8508' 6913' feet Plugs (measured) feet 6. Datum elevation (DF or KB) RKB 94', Pad Elev, 61' 7. Unit or Property name Kuparuk River Unit feet 8. Well number 1B-08 9. Permit number 88-113 10. APl number 50-029-20635 11. Field/Pool Kupurak River Field/ Kuparuk River Oil Pool Effective depth: measured (approx) true vertical 8320' 6752' feet Junk (measured) feet Casing Length Structural Conductor 8 0' Surface 2 31 2' Intermediate Production 8 5 38' Liner Perforation depth: measured 7872'-7966', true vertical 6359'-6443', Size 16" 1 0- 3/4" 7" 8126'-8134', 6583'-6590', Tubing (size, grade, and measured depth) 3-1/2", J-55, @ 8062' MD Packers and SSSV (type and measured depth) Cemented Measured depth True vertical depth 200 Sx PF 1000 sx Fondue & 250 sx AS II 923 sx Class G 8148'-8172', 6602'-6623', 112' 112° 2343' 2246' 8465' 6876' ~"-~ (', ..a : ~ :-' :i'". 8175'-8184' :.i -- 'cid~ 7~ 6626'-6634 ~: Baker'HB' @ 7712', Baker'FBol' @ 8040', Camco 'TRDP-1AE' SSSV @ 1830' 13. Attachments Description summary of proposal X Contact William Isaacson at 263-4622 with any questions. 14. Estimated date for commencing operation dune t0, 1997 16. If proposal was verbally approved Name of approver Date approved Detailed operation program__ 15. Status of well classification as: Oil Gas Service BOP sketch Suspended _ 17. I hereby certifylhat the Si~lne ' · foregoing is true and correc.t to. the best of my knowledge. [ ~',"~--'~"//-' Title Drill-Site Development Supv Date FOR COMMISSION USE ONLY Conditions of approval: Notj. fy Commission so representative may witness Plug integrity..~ BOP TestLZ~Location clearance __ Mechanical Integrity Test _ Subsequent form require IAppEov~ No. Approved by the order of the Commission Form 10-403 Rev 06/15/88 Commissioner Date SUBMIT IN TRIPLICATE WELL PERMIT CHECKLISToo Y INIT CLASS ./~--~¢/~ PROGRAM= exp[] dev [] redr~ serv~wellbore seg[] ann disp para req[] G~.OL ~,~U~A ~V?~--~ UNIT# .,///L"---_-- ._,~"~ ON/OFF S~O~ ~.~,) ADMINISTRATION 1. Permit fee attached .................. 2. Lease number appropriate ............... 3. Unique well name and number .............. 4. Well located in a defined pool ............. 5. Well located proper distance from drlg unit boundary. . 6. Well located proper distance from other wells ..... 7. Sufficient acreage available in drilling unit ..... 8. If deviated, is wellbore plat included ........ 9. Operator only affected party .............. 10. Operator has appropriate bond in force ......... 11. Permit can be issued without conservation order .... 12. Permit can be issued without administrative approval. . 13. Can permit be approved before 15-day wait ....... ENGINEERING 14. Conductor string provided ............... 15. Surface casing protects all known USDWs ......... 16. CMT vol adequate to circulate on conductor & surf csg. 17. CMT vol adequate to tie-in long string to surf csg . . 18. CMT will cover all known productive horizons ...... 19. Casing designs adequate for C, T, B & permafrost .... 20. Adequate tankage or reserve pit ............ 21. If a re-drill, has a 10-403 for abndnmnt been approved. 22. Adequate wellbore separation proposed .......... 23. If diverter required, is it adequate .......... 24. Drilling fluid program schematic & equip list adequate 25. BOPEs adequate ............ _~... · .... 26. BOPE press rating adequate; test to ~~ psig. 27. Choke manifold complies w/API RP-53 (May 84) ...... 28. Work will occur without operation shutdown ....... 29. Is presence of H2S gas probable ............ REMARKS N N GEOLOGY APPR 9ATE; 30. Permit can be issued w/o hydrogen sulfide measures .... Y 31. Data presented on potential overpressure zones ..... Y/N 32. Seismic analysis of shallow gas zones ......... ./~ N 33. Seabed condition survey (if off-shore) ....... ~/. Y N - ' ' 34. Contact name/phone for weekly progress reports . . /. . Y N [exploratory only] · GEOLOGY: ENGINEERING: COMMISS ION: Connments/Instructions: HOWfdlf- A:\FORMS\cheklist rev 01/97 Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. Sperry-Sun Drilling Services LIS Scan Utility Tue Sep 16 15:30:56 1997 Reel Header Service ns/ne ............. LISTPE Date ..................... 97/09/16 Origin ................... STS Reel Name ................ UNKNOWN Continuation Number ...... 01 Previous Reel Name ....... UNKNOWN Comments ................. STS LIS Writing Library. Technical Services Tape Header Service name ............. LISTPE Date ..................... 97/09/16 Origin ................... STS Tape Name ................ UNKNOWN Continuation Number ...... 01 Previous Tape Name ....... UNKNOWN Comments ................. STS LIS Writing Library. Technical Services Scientific Scientific Physical EOF Comment Record TAPE HEADER KUPARUK RIVER UNIT MWD/MAD LOGS WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: JOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: MWD RUN AK-MW-7 0215 SHAYNE LAITI DON WESTEN ELEVATION (FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: Date 01- 03- O I 1B-08A 500292063501 ARCO A~ASKA, INC. SPERRY-SUN DRILLING SERVICES 16-SEP-97 MWD RUN 2 AK-MW-70215 SHAYNE LAITI BOBBY MORRIS 9 llN 10E 501 141 93 .00 91.50 30.80 .R, ECEIVED SEP 2 6 199i~ Alask~ Oil & Gas Con~. C, om.~s~o~ Anchorage WELL CASING RECORD 1ST STRING 2ND STRING 3RD STRING PRODUCTION STRING REMARKS: OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 16.000 80.0 10.750 2343.0 7.000 6339.0 6.125 9710.0 1. ALL DEPTHS ARE MEASURED DEPTHS (MD) UNLESS OTHERWISE NOTED. 2. ALL GAMMA RAY DATA (SGRD) IS DOWNHOLE RECORDED. 3. MWD RUNS 1 AND 2 ARE DIRECTIONAL WITH SCINTILLATION TYPE GAMMA RAY (NGP) . 4. DEPTH SHIFTING/CORRECTION OF MWD DATA IS WAIVED AS PER THE PHONE CONVERSATION BETWEEN ALI TURKER OF SPERRY-SUN DRILLING SERVICES AND DENISE PETRASH OF ARCO ALASKA, INC. ON 04 SEPTEMBER, 1997. 5. THIS WELL REACHED A TOTAL DEPTH (TD) OF 9710'MD, 6659'TVD. SROP = SMOOTHED RATE OF PENETRATION WHILE DRILLING. SGRD = SMOOTHED GAMMA RAY. $ File Header Service name ............. STSLIB.001 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 97/09/16 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.000 Comment Record FILE HEADER FILE NUMBER: 1 EDITED MERGED MWD · Depth shifted and clipped curves; all bit ru~s merged. DEPTH INCREMENT: .5000 - FILE SUMMARY PBU TOOL CODE START DEPTH STOP DEPTH GR 6153.0 9647.0 ROP 6216.0 9709.5 $ BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) BASELINE DEPTH $ MERGED DATA SOURCE PBU TOOL CODE MWD MWD $ REMARKS: EQUIVALENT UNSHIFTED DEPTH MERGED MAIN PASS. BIT RUN NO MERGE TOP MERGE BASE 1 6216.0 8960.0 2 8960.0 9710.0 $ # Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet Data Reference Point .............. Undefined Frame Spacing ..................... 60 .lin Max frames per record ............. Undefined Absent value ...................... -999.25 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 GR MWD AAPI 4 1 68 4 2 ROP MWD FT/H 4 1 68 8 3 First Name Min Max Mean Nsam Reading DEPT 6153 9709.5 7931.25 7114 6153 GR 36.82 560.86 138.248 6989 6153 ROP 2.37 652.39 89.6099 6988 6216 Last Reading 9709.5 9647 9709.5 First Reading For Entire File .......... 6153 Last Reading For Entire File ........... 9709.5 File Trailer Service name ............. STSLIB.001 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 97/09/16 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.002 Physical EOF File Header Service name ............. STSLIB.002 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 97/09/16 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.001 Comment Record FILE HEADER FILE NUMBER: 2 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: i DEPTH INCREMENT: .5000 FILE VENDOR TOOL CODE START DEPTH GR 6153.0 ROP 6216.0 $ LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT) TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: STOP DEPTH 8898.5 8959.5 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE NGP NATURAL GAMMA PROBE $ BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER' S CASING DEPTH (FT) : BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): . RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: $ Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet 24-JUL-97 MSC 1.32 / ISC 5.06 2.042 / 5.74 MEMORY 8960.0 6216.0 8960.0 34~3 64.2 TOOL NUMBER NGP SPC 243 6.130 6.1 LSND-HT 11.40 49.0 9.1 400 3.6 .000 .000 .000 .000 20.0 .6 Data Reference Point .............. Undefined Frame Spacing ..................... 60 .lin Max frames per record ............. Undefined Absent value ...................... -999.25 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 GR MWD 1 AAPI 4 1 68 4 2 ROP MWD 1 FT/H 4 1 68 8 3 First Name Min Max Mean Nsam Reading DEPT 6153 8959.5 7556.25 5614 6153 GR 36.99 560.86 151.358 5492 6153 ROP 2.37 652.39 93.6373 5488 6216 First Reading For Entire File .......... 6153 Last Reading For Entire File ........... 8959.5 Last Reading 8959.5 8898.5 8959.5 File Trailer Service name ............. STSLIB.002 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 97/09/16 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.003 Physical EOF File Header Service name ............. STSLIB.003 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 97/09/16 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.002 Comment Record FILE HEADER FILE NUMBER: 3 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 2 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 8899.5 9647.0 ROP 8961.5 9709.5 $ LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWN-HOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT) : TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM) : HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE NGP NATURAL GAMMA PROBE $ BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHFIM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: $ Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet Data Reference Point .............. Undefined Frame Spacing ..................... 60 .lin Max frames per record ............. Undefined Absent value ...................... -999.25 Depth Units ....................... Datum Specification Block sub-type...0 2 6 -JUL- 9 7 MSC 1.32 / ISC 5.06 2.042 / 5.74 MEMORY 9710.0 8960.0 9710.0 62.2 63.2 TOOL NUMBER NGP SPC 239 6.130 6.1 LSND-HT 11.50 50.0 9.1 600 3.2 .000 .000 .000 .000 22.8 .6 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 GR MWD 2 AAPI 4 1 68 4 2 ROP MWD 2 FT/H 4 1 68 8 3 First Name Min Max Mean Nsam Reading DEPT 8899.5 9709.5 9304.5 1621 8899.5 GR 36.82 186.88 90.1354 1496 8899.5 ROP 9.11 405.44 74.5836 1497 8961.5 Last Reading 9709.5 9647 9709.5 First Reading For Entire File .......... 8899.5 Last Reading For Entire File ........... 9709.5 File Trailer Service name ............. STSLIB.003 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 97/09/16 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.004 Physical EOF Tape Trailer Service ns_me ............. LISTPE Date ..................... 97/09/16 Origin ................... STS Tape Name ................ UNKNOWN Continuation Number ...... 01 Next Tape Name ........... UNKNOWN Comments ................. STS LIS Writing Library. Technical Services Reel Trailer Service name ............. LISTPE Date ..................... 97/09/16 Origin ................... STS Reel Name ................ UNKNOWN Continuation Number ...... 01 Next Reel Name ........... UNKNOWN Comments ................. STS LIS Writing Library. Technical Services Scientific scientific Physical EOF Physical EOF End Of LIS File
