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181-136
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, July 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1B-11 KUPARUK RIV UNIT 1B-11 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/22/2025 1B-11 50-029-20657-00-00 181-136-0 W SPT 5975 1811360 1800 1578 1579 1579 1576 605 2000 1965 1960 REQVAR P Guy Cook 6/13/2025 MIT-OA to 1800 psi per AIO 2C.044. Testing completed with a Little Red Services pump truck and calibrated gauges. OOA = 30 psi. throughout the test. 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-11 Inspection Date: Tubing OA Packer Depth 1100 1420 1405 1400IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC250612102126 BBL Pumped:1.7 BBL Returned:1.7 Tuesday, July 22, 2025 Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, July 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1B-11 KUPARUK RIV UNIT 1B-11 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/22/2025 1B-11 50-029-20657-00-00 181-136-0 W SPT 5975 1811360 3900 1575 1578 1577 1572 653 1150 1133 1124 REQVAR P Guy Cook 6/13/2025 MIT-IA to maximum anticipated injection pressure per AIO 2C.044. Testing completed with a Little Red Services pump truck and calibrated gauges. OOA = 30 psi. throughout the test. 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-11 Inspection Date: Tubing OA Packer Depth 1090 4190 4085 4070IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC250612102036 BBL Pumped:2.6 BBL Returned:2.4 Tuesday, July 22, 2025 Page 1 of 1 Originated: Delivered to:8-Jul-25Halliburton Alaska Oil and Gas Conservation Comm.Wireline & Perforating Attn.: Natural Resource TechnicianAttn: Fanny Haroun 333 West 7th Avenue, Suite 1006900 Arctic Blvd. Anchorage, Alaska 99501Anchorage, Alaska 99518Office: 907-275-2605FRS_ANC@halliburton.comThe technical data listed below is being submitted herewith. Please address any problems orconcerns to the attention of the sender aboveWELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPEDATA TYPE LOGGING DATE PRINTS # DIGITAL # E SET#1 1B-04 50-029-20595-00 910151309 Kuparuk River Plug Setting Record Field- Final 30-Jun-25 0 12 1B-05 50-029-20237-00 910106098 Kuparuk River Multi Finger Caliper Field & Processed 19-Jun-25 0 13 1B-05 50-029-20237-00 910106098 Kuparuk River Plug Setting Record Field- Final 21-Jun-25 0 14 1B-11 50-029-20657-00 910151309 Kuparuk River Multi Finger Caliper Field & Processed 1-Jul-25 0 15 1B-11 50-029-20657-00 910149873 Kuparuk River Plug Setting Record Field- Final 1-Jul-25 0 16 1B-15A 50-029-22465-01 910106169 Kuparuk River Plug Setting Record Field- Final 20-Jun-25 0 17 1D-101 50-029-22988-00 910151308 Kuparuk River Packer Setting Record Field- Final 6-Jul-25 0 18 1H-103 50-029-23593-00 910082841 Kuparuk River Multi Finger Caliper Field & Processed 21-Jun-25 0 19 1L-24 50-029-22170-00 910151023 Kuparuk River Packer Setting Record Field- Final 28-Jun-25 0 110 2A-16 50-103-20042-00 910150862 Kuparuk River Plug Setting Record Field- Final 27-Jun-25 0 1PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF:Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518FRS_ANC@halliburton.comDate:Signed:Transmittal Date:181-065177-001181-136204-256200-183218-003191-066185-147T40642T40643T40643T40644T40644T40645T40646T40647T40648T406497/9/202541B-1150-029-20657-00910151309Kuparuk RiverMulti Finger CaliperField & Processed1-Jul-250151B-1150-029-20657-00910149873Kuparuk RiverPlug Setting RecordField- Final1-Jul-2501Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.07.09 09:29:07 -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-11 KUPARUK RIV UNIT 1B-11 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/26/2023 1B-11 50-029-20657-00-00 181-136-0 G SPT 5975 1811360 1800 2804 2804 2804 2804 760 1990 1960 1960 REQVAR P Brian Bixby 6/3/2023 MIT-OA as per AIO 2C.044 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-11 Inspection Date: Tubing OA Packer Depth 601 886 878 880IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB230607072210 BBL Pumped:1.8 BBL Returned:1.4 Wednesday, July 26, 2023 Page 1 of 1 9 9 9 9 9 9 999 9 9 9 9 9 MIT-OA James B. Regg Digitally signed by James B. Regg Date: 2023.07.26 14:35:59 -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-11 KUPARUK RIV UNIT 1B-11 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/26/2023 1B-11 50-029-20657-00-00 181-136-0 G SPT 5975 1811360 3900 2804 2804 2804 2804 475 475 474 471 REQVAR P Brian Bixby 6/3/2023 MIT-IA as per AIO 2C.044 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-11 Inspection Date: Tubing OA Packer Depth 600 4195 4100 4090IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB230607071812 BBL Pumped:3.2 BBL Returned:3.2 Wednesday, July 26, 2023 Page 1 of 1 9 9 9 9 9 9 9 9 9 99 9 9 9 MIT-IA James B. Regg Digitally signed by James B. Regg Date: 2023.07.26 14:33:49 -08'00' C:\Users\kmjunke\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\99RGP1KB\2022-09-21_22501_KRU_1B-11_CaliperSurvey_LogData_Transmittal.docx DELIVERABLE DISCRIPTION Ticket # Field Well # API # Log Description Log Date 22501 KRU 1B-11 50-029-20657-00 Caliper Survey Log 21-Sep-22 DELIVERED TO Company & Address DIGITAL FILE # of Copies LOG PRINTS # of Prints CD’s # of Copies 1 AOGCC Attn: Natural Resources Technician 333 W. 7th Ave., Suite 100 Anchorage, Ak. 99501-3539 Delivered By: CPAI Sharefile ______________________________ ______________________________________ Date received Signature PLEASE RETURN COPY VIA EMAIL TO: DIANE.WILLIAMS@READCASEDHOLE.COM READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503 PHONE: (907)245-8951 E-MAIL : READ-Anchorage@readcasedhole.com WEBSITE : WWW.READCASEDHOLE.COM PTD:181-136 T37040 Kayla Junke Digitally signed by Kayla Junke Date: 2022.09.28 08:38:47 -08'00' MEMORANDUM TO: Jim Regg P.I. Supervisor FROM: Jeff Jones Petroleum Inspector -71,6�7-0z"; Well Name KUPARUK RIV UNIT 1B-11 IInsp Num: mitJJ210701110849 Rel Insp Num: NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, July 12, 2021 SUBJECT: Mechanical Integrity Tests ConocoPhillips Alaska, Inc. IB -11 KUPARUKRIV UNIT IB -11 Src: Inspector Reviewed By- P.I. Supry IJ12— Comm API Well Number 50-029-20657-00-00 Inspector Name: Jeff Jones Permit Number: 181-136-0 Inspection Date: 6/29/2021 ' Monday, July 12, 2021 Page I of 1 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1B-11 Type jnj W 'TVD 5975 Tubing 2340 2340 - 2340 - 2340 - PTD L 1811360T "i yp e Test SPT Test psi 3900 - I j,4 820 4200 - 4120- 4090 - BBL Pumped 3 - BBL Returned: 3 OA 550 1160 1070 1060 - Interval REQVAR P/F P Notes: AIO 2C.044; MIT1A to max. anticipated injection pressure. Monday, July 12, 2021 Page I of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, July l2, 2021 TO. Jun ReggSUBJECT: Mechanical Integrity Tests P.I. Supervisor E /� 7�«,i c'ft` Z ( ConocoPhillips Alaska, Inc. 1B-11 FROM: Jeff Jones KUPARUKRIV UNIT 1B-11 Petroleum Inspector Src: Inspector Reviewed By: P. 1. Sopry �jrlp— NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 1B-11 API Well Number 50-029-20657-00-00 Inspector Name: Jeff Jones Permit Number: 181-136-0 Inspection Date: 6/29/2021 ' Insp Num' mitJJ210701110253 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1B-11 Type Inj W- TVD 5975 Tubing 2350 2340, 2340 2340 - PTD 1811360 Type Test SPT- Test psi 1800 IA 750 1160 1150 - 1140 , BBL Pumped: 2.4 BBL Returned: 1.9 OA 480 2000: 1960 - 1960 - Interval� REQVAR P/F P Notes: AIO 2C.044; MIT -OA to 1800 PSI. Monday, July 12, 2021 Page I of 1 Originated:Delivered to:6-Apr-21 Halliburton Alaska Oil and Gas Conservation Comm. Wireline & Perforating Attn.: Natural Resource Technician Attn: Fanny Haroun 333 West 7th Avenue, Suite 100 6900 Arctic Blvd.Anchorage, Alaska 99501 Anchorage, Alaska 99518 Office: 907-275-2605 FRS_ANC@halliburton.com The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of the sender above WELL NAME API #SERVICE ORDER #FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS #DIGITAL # 1 1A-23 50-029-22131-00 906975765 Kuparuk River Multi Finger Caliper Field & Processed 12-Feb-21 0 1 2 1B-11 50-029-20657-00 907041775 Kuparuk River Multi Finger Caliper Field & Processed 20-Mar-21 0 1 3 1D-101 50-029-22986-00 n/a West Sak Packer Setting Record Field- Final 14-Mar-21 0 1 4 1D-130 50-029-22815-00 907025874 West Sak Packer Setting Record Field- Final 13-Mar-21 0 1 5 1F-19 50-029-22660-00 906994361 Kuparuk River Packer Setting Record Field- Final 24-Feb-21 0 1 6 1G-02 50-029-20813-00 906996811 Kuparuk River Multi Finger Caliper Field & Processed 24-Feb-21 0 1 7 1L-11 50-029-22034-00 906914692 Kuparuk River Leak Detect Log Field- Final 15-Jan-21 0 1 8 1Q-10 50-029-21215-00 907035266 Kuparuk River Packer Setting Record Field- Final 18-Mar-21 0 1 9 2H-09 50-103-20050-00 907042522 Kuparuk River Packer Setting Record Field- Final 19-Mar-21 0 1 10 3H-21 50-103-20094-00 907045708 Kuparuk River Packer Setting Record Field- Final 22-Mar-21 0 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com Date:Signed: Transmittal Date: Received by the AOGCC 04/07/2021 04/07/2021 PTD: 1811360 E-Set: 34902 https://readcasedhole-my.sharepoint.com/personal/diane_williams_readcasedhole_com/Documents/D Drive/Achives/MasterTemplateFiles/Templates/Distribution/TransmittalSheets/ConocoPhillips_Transmit.docx Well Log Transmittal To: AOGCC Natural Resources Technician 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 RE : Cased Hole/Open Hole/Mechanical Logs and /or Tubing Inspection(Caliper / MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of : READ Cased Hole, Inc. Attn: Diane Williams 4141 B Street Suite 308 Anchorage, AK 99503 Diane.Williams@readcasedhole.com 1) Caliper Report 23-Mar-20 1B-11 1 Reort / CD 50-029-20657-00 2) Signed : Date : ___________________ Print Name: __________________________________ ______________________________________ READ CASED HOLE, INC, 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503 PHONE: (907)245-8951 E-MAIL : READ-ANCHORAGE@READCASEDHOLE.COM WEBSITE : WWW.READCASEDHOLE.COM Abby Bell 04/22/2020 Abby Bell Received by the AOGCC on 04/22/2020 PTD: 1811360 E-Set: 32774 MEMORANDUM TO: Jim Regg X141 -7151Ic P.I. Supervisor ( 41 t FROM: Lou Laubenstein Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, June 26, 2019 SUBJECT: Mechanical Integrity Tests ConocoPhillips Alaska, Inc. IB -11 KUPARUK RIV UNIT IB -I I Src: Inspector Reviewed By: y�: P.I. Supry � Comm Well Name KUPARUK RIV UNIT IB -11 API Well Number 50-029-20657-00-00 Inspector Name: Lou Laubenstein Permit Number: 181-136-0 Inspection Date: 6/10/2019 " IOSp Num: mitLOL190611082548 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well IB -11 - Type Inj W TVD 5975 Tubing � 2314 'i 2314 2295 PTD — 1811360 '.Type Test SPT Test psi 3900 [,4 —2295 50 4200 - 4110 4090 - BBL Pumped: L 3.8 - BBL Returned: 3.7 OA 533 — 1010 - 995 980 Interval I_ _ _ REQVAR JP/F P Notes: MIT -IA to maximum anticipatedinjection pressure per AIO 2C.044 OOA 12/12/12/12 Wednesday, June 26, 2019 Page I of I MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim ReggI1310 DATE: Wednesday, June 26, 2019 P.I. Supervisor l � SUBJECT: Mechanical Integrity Tests ConocoPhillips Alaska, Inc. 1B-11 FROM: Lou Laubenstein KUPARUK RIV UNIT IB-11 Petroleum Inspector Ste: Inspector Reviewed By: P.I. Supry Z(— — NON-CONFIDENTIAL Comm I Well Name KUPARUK RIV UNIT 113-11 IInsp Num: mi[LOL190611083819 Rel Insp Num: API Well Number 50-029-20657-00-00 Inspector Name: Lou Laubenstein Permit Number: 181-136-0 Inspection Date: 6/10/2019 � Packer Depth Well IB -11 'I -Npc Inj TVD s, -s PTD, 1811360 - Type Test MN Test psi 1800 BBL Pumped: 22 BBL Returned: 2--2 - Interval REQVAR P/F P Notes: MIT -OA to 1800 psi AIO 2C.044 OOA 12/12/12/12 Pretest Initial 15 Min 30 Min 45 Min 60 Min Tubing 2296 2296 2336 IA W- 995 1012 ..1041 - OA 562 2000 1980 - 1980 Wednesday, June 26, 2019 Page I of I VS -11. PROACTIVE DIAgNGSTIC SERVICES, INC, WELL LOG TRANSMITTAL To: AOGCC Natural Resources Technician 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907) 793-1225 1811'!6 30488 RE: Cased Hole/Open Hole/Mechanical Logs and /or Tubing Inspection(Caliper / MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letterto the attention of : 1) Caliper Report 2) Signed : Print Name: ProActive Diagnostic Services, Inc, RECEIVE® Attn: Diane Williams RECEIVED 130 West International Airport Road Suite C MAR 2 2 2019 Anchorage, AK 99518 A®C� Ddsanchoraae(&memorvlog com C 17 -Mar -19 1 B-11 CD 50-029-20657-00 PROACTIVE DIAGNOSTIC SERVICES, INC„ 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-8952 E-MAIL: PDSANCHORAGEi Company: Log Date: Log No.: Run No.: Pipe Description: Pipe Use: Pipe Description: ConocoPhillips Alaska, Inc. March 17, 2019 20057 3 3.5 inch 9.2 Ib. L-80 Tubing 4.5 inch 12.6 Ib, J-55 181136 30488 Memory Multi -Finger Caliper Log Results Summary Well: Field: State: API No. Top Log Interval: Bottom Log Interval: Top Log Interval: Bottom Lop Interval: Inspection Type : Corrosive & Mechanical Damage Inspection COMMENTS: 1B-11 Kuparuk Alaska 50-029-20657-00 Su rface 8,858 Ft. (MD) 8,848 Ft. (MD) 10,281 Ft. (MD) This caliper data is tied into the top of the Camco DS No Go Nipple at 9,132 feet (Drillees Depth) While logging out ofhole, the operator noticed the mechanical depth counter was slipping, resulting in inaccurate depth recordings. The inaccurate depth rile was replaced with a new depth file based on time and depth logged as noted by the engineer. This log was run to assess the condition of the tubing with respect to internal corrosive and mechanical damage. The caliper recordings indicate the 3.5 inch tubing appears to be in good condition, with no significant wall penetrations, areas of cross-sectional wall loss or I.D. restrictions recorded. The caliper recordings indicate the 4.5 inch tubing logged appears to be in mostly fair to poor condition with multiple holes recorded intermittently throughout. Wall penetrations ranging from 40% to 100% wall thickness are recorded in 32 of the 49 joints logged. Recorded damage appears as general corrosion, line corrosion and isolated pitting. Cross-sectional wall loss between 15% and 28% metal volume is recorded in 8 of the 49 joints logged. Intermittent deposits are recorded throughout much of the tubing logged, restricting the I.D. to 2.94 inches in pup joint 2.7 (10,276 ft). A graph illustrating minimum recorded diameters on a joint -by -joint basis across the tubing logged is included in this report. The caliper recordings indicate a slight bend at -9,829 feet. This is the third time a PDS caliper has been run in this well and the second time the 3.5 inch and 4.5 inch tubing have been logged. A comparison of the current and previous log (March 5, 2018) of the 3.5 inch tubing indicates little if any changes in maximum recorded wall penetrations or ID restrictions during the time between logs. A comparison of the current and previous log of the 4.5 inch tubing indicates little, if any increase in wall penetrations and a slight increase in minimum recorded diameters during the time between logs. Graphs illustrating the difference in maximum recorded wall penetrations on a joint by joint basis and minimum recorded diameters on a joint by joint basis are included in this report. 3.5 INCH TUBING - MAXIMUM RECORDED WALL PENETRATIONS: No significant wall penetrations (> 15%) are recorded. 3.5 INCH TUBING - MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: No significant areas of cross-sectional wall loss (> 4%) are recorded. ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) 431-7100 or (888) 565-9085 Fax: (281) 431-7125 E-mail: PDSAnalvsis(a)memorvloa com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2314 3.5 INCH TUBING - MAXIMUM RECORDED ID RESTRICTIONS: No significant I.D. restrictions are recorded. 4.5 INCH TUBING - MAXIMUM RECORDED WALL PENETRATIONS: Multiple Holes 100 18 9,833 Ft. (MD) Hole 100 6 9,573 Ft. (MD) Possible Hole 100 7 9,208 Ft. (MD) Corrosion 86 23 9,724 Ft. (MD) Line of Pits 81 38 10,169 Ft. (MD) 4.5 INCH TUBING - MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: Corrosion 28 5 9,134 Ft. (MD) Corrosion 21 3.1 9,049 Ft. (MD) Corrosion 20 4 9,111 Ft. (MD) Perforation Interval 20 27 9,833 Ft. (MD) Hole 19 6 9,186 Ft. (MD) 4.5 INCH TUBING - MAXIMUM RECORDED ID RESTRICTIONS: No significant I.D. restrictions are recorded. M. Domec C. Waldrop E. Zemba ProActive Diagnostic Ser✓ices, Inc / P.O. Pox 1369, Stafford, TX 77-197 Phone: (281) 4.31-7100 or (888) 565-9085 Fax: (281) 431-7125 E-mail: PDSAnalvsis(aa memorvloo com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2-14 .a -�_._. __ _'. _ . _ ��.. _ �..e. 1 �a - -. ::� -_ -- 6 �'- = �- I f s f Correlation of Recorded Damage to Borehole Profile 'Pipe 1 3.5 in (12.9'-8,848.5') Well: 1B-11 Pipe 2 4.5 in (8,848.5'- 10,281.1') Field: Kuparuk Company: ConocoPhillips Alaska, Inc; Country: USA Survey Date: March 17, 2019 ■ Approx. Tool Deviation ■ Approx. Borehole Profile 13 50 1,590 100 3,205 150 4,771 D �c L 3 z 200 C 6,320 � "o a v o 250 7,855 GLM 1 GLM 2 8,877 41 10,259 0 50 100 Damage P rofile (% wall) / Tool Deviation (degrees) Bottom of Survey = 41 ■ Perforations Maximum Recorded Penetration ji Comparison To Previous Well: 1 B-11 Survey Date: March 17, 2019 Field: Kuparuk Previous Date: March 5, 2018 Company: Conoco Phillips Alaska, Inc. Tool Type: UW MFC 24 No. 10020078 Country: USA Tubing: 3.5" 9.2 Ib L-80 Overlay Difference Maximum Recorded Penetration (mils) Difference in Maximum Penetration (mils) 0 50 100 150 200 250 -50 .25 0 25 50 1 10 17 4-7 2727 37 _ 47 _ 57 67 6 _ 77 77 87 87 97 107 107 117 117 $ 127 w 127 Z 137 z `c 147 9 147 'ii 157 157 167 167 177 177 187 187 197 207 217 2 227 227- 237 237 247 247- 257 2 267 26 anri_ 277 277 -48 -24 0 24 48 March 17, 2019 March 5, 2018 Approximate Corrosion Rate (mpy) Tosion RateLmpy] I Top 10 Its. Overal_ J Avedaedian 0 _ M --99 L 7_ Pipe Nom.OD Weight Grade & Thread Nom.ID Top Depth Bottom Depth 3.5 in. 9.2 ppf L-80 2.992 in 13 ft 8 848 ft Damage Configuration (body) 10 8 6 4 2 0 Isolated General Line Other Hole/ Pitting Corrosion Corrosion Damage Pos. Hole 0 0 1 0 0 Damage Profile (%wall) Penetration body Metal loss body 0 50 100 GLM 1 (2:00) Bottom of Survey = 279.2 PDS Report Overview (PS Body Region Analysis Well: 1B-11 Survev Date: March 17, 2019 Field: Kuparuk Tool Type: UW MFC 24 No. 10020078 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 inches Country: USA No. of Fingers: 24 Pipe 3.5 in. 9.2 ppf L-80 Analyst: Waldrop Pipe Nom.OD Weight Grade & Thread Nom.ID Top Depth Bottom Depth 3.5 in. 9.2 ppf L-80 2.992 in 13 ft 8 848 ft Damage Configuration (body) 10 8 6 4 2 0 Isolated General Line Other Hole/ Pitting Corrosion Corrosion Damage Pos. Hole 0 0 1 0 0 Damage Profile (%wall) Penetration body Metal loss body 0 50 100 GLM 1 (2:00) Bottom of Survey = 279.2 cp�,s Well: 1 B-11 Field: Kuparuk Company: ConocoPhillips Alaska, Inc. PDS Report Joint Tabulation Sheet Survey Date: March 17, 2019 Analyst: Waldrop Pipe Description 3.5 in. 9.2 ppf L-80 Tubing Nom. ID Body Wall Top Depth Bottom Depth 2.992 in. 0.254 in. 13 ft 8,848 ft. Joint Jt. Depth No. (Ft.) Pen. Upset (in.) Pen. Body (in.) Pen. % Metal Loss % in. Damage Profile LD. Comments (% wall) (in.) 0 50 100 3 0 .0 2 2.9 1.7 45 0 .02 2 .96 Pu 12 2 47 0 0.02 9 2 2.96 7 0 0.02 7 3.95 4 110 .02 9 2 2.95 5 142 0 0.02 7 2 2.95 6 174 0 0.02 8 4 7 206 0 0. 7 2 4 8 238 0 0.02 7 1 2.96 270 0 2 7V 10 301 0 0.02 8 11 334 0 .0 9 12 366 0 0.0 7 13 398 0 0.02 9 Deposits. 14 430 0. 2 7 15 46 0.02 7 15.1 494 0 0.02 8 15.2 504 0 0 O DSNIPP F 1 .3 6 0 0.02 7 16516 0 0.01 6 2 2.94 17 548 0 0.0 9 2.94 18 1 5790 0.02 G 1 1 1 2.95 19 1 610 0 0.02 7 1 2.94 201 0.03 1 2 2.94 1 672 0 0.01 5 1 1 1 .95 22 703 0 0.02 7 2 2.94 3 734 0 0.01 5 1 2.95 24 1 766 0 0.01 5 1 2.94 25 1 797 0 0.01 5 2 2. 4 6 8260 0.01 6 1 2.93 27 858 1 0 1 0.02 6 1 2.94 28 890 0 6 2 2.94 29 21 0 7 1 .94 30 953 0 r002 7 2 2.94 31 4 0 6 1 2.94 32 101 0 6 2 2.95 33 1048 0 0.01 4 1 2.94 34 1 9 0 0.01 4 1 2.95 5 1111 0 I 0.01 6 2 2.96 36 1143 0 0.02 8 1 2.96 37 1174 0.01 4 1 2.97 38 1 06 0 0.02 1 2.97 39 1238 0 0.02 9 2 2.94 40 127000. 8 2 2 41 1302 0 0.01 6 1 2.94 4 1334 02 8 1 2.4 4 66 0.0 10 4 2. 4 44 1398 0 0.01 4 1 2.94 45 1429 0 1 0.02 6 1 2.96 46 1461 0 1 0.02 G 2 2. 7 Penetration Body Metal Loss Body Page 1 ji� Well: Field: Company: 1 B-11 Kuparuk ConocoPhillips Alaska, Inc. PDS Report Joint Tabulation Sheet Survey Date: March 17, 2019 Analyst: Waldrop Pipe Description 3.5 in. 9.2 ppf L-80 Tubing Nom. ID 2.992 in. Body Wall Top Depth Bottom Depth 0.254 in. 13 ft. 8,848 ft. Joint )t. Depth No. (Ft.) Pen. Upset (in.) Pen. Body (in.) Pen. % Metal Loss °o Min. I.D. (in.) Damage Profile Comments (% wall) 0 50 100 47 1 30 102 7 2 2.95 48 1525 0 0.02 6 2 2.97 49 1558 0 0.01 6 1 2.95 50 1590 0 0. 1 5 1 2.95 51 1621 0 0.01 6 2 2. 5 52 1653 0 17774 1 2.97 53 16 0 0.02 ( 2. Lt. osi 4 1718 0 0.01 4 2 2.96 55 1750 0 0.02 8 4 2.94 56 1783 0 .01 4 2 2. 5 57 1814 0 0.01 4 1 2.96 58 1846 0 0.02 7 1 2. 7 59 1878 0. 2 7 3 2.97 60 1910 0 0.01 6 2 2.95 61 1943 0 .01 4 2 2. 7 1 75 0 001 4 1 2.96 63 2007 0 0.01 4 2 2.96 64 2040 0 1 4 1 2.9 5 2 72 0 0. 2 7 3 2.94 66 2104 0 0.01 5 2 2.96 67 1 6 0 0.01 6 2 .92 It, De osits. 68 21 0 0.01 5 1 2.96 69 2200 0 0.01 Fi 1 2.96 7 22 0 0.01 6 1 1 2.97 71 226 0 0.n1 6 1 2. 72 2294 0 0.02 8 2 2.97 7 2327 0 0.01 6 2.94 74 2359 0 0.01 6 1 2.96 75 23 7-01 4 1 2.96 7 2424 0 0.01 6 1 2.96 77 2457 0 0.01 4 1 2.97 78 2489 0 0.01 6 .97 7 2522 0 0.02 7 1 2.96 802554 0 0.02 6 2 2.97 1 2 7 1 0 0.02 6 1 2.97 2 1 2620 1 0 1 0.02 6 1 6 83 2652 0 0.01 4 1 2.97 4 2685 0 0. 6 2 .97 2717 0 0.01 6 2.97 86 2750 00.02 7 3 2.96 87 27 0. 2 8 2 .94 88 281 9 0 0.02 7 1 .96 89 2848 0 0.02 8 3 2.95 90 2881 0 6 1 .95 91 2913 0 0.02 8 2 2.96 92 2944 0 0.02 3 2. 4 93 2977 0 6 3 2.9 94 3010 0 0.02 7 3 2.94 95 3042 0 0.03 10 2 2. Lt. Deposits. 96 7 .0 C 2 2.9 'Penetration Body Metal Loss Body Page 2 (Ii 5 Well: Field: Company: 1B-1 I Kuparuk ConocoPhillips Alaska, Inc. PDS Report Joint Tabulation Sheet Survey Date: March 1 7, 2019 Analyst: Waldrop Pipe Descripfion 3.5 in. 9.2 ppf L-80 Tubing Nom. ID 2.992 in. Body Wall Top Depth Bottom Depth 0.254 in. 13 ft 8,848 ft. joint jt. Depth Pen. No. (Ft.) Upset (in.) Pen. Body (in.) Pen. % Metal Loss % Min. 1. D. (in.) Damage Profile Comments (% wall) 0 50 100 97 3108 0 0.02 7 2 2.97 8 3140 0 0.01 5 1 2.94 99 3173 0 0.02 7 2 2.97 100 3205 0 0.01 4 2 2.97 101 3238 0 0.02 6 1 2.97 102 3271 0 0.02 9 2 22 .96 10 04 0 002 7 1 .9 1 4 3 6 0 0.01 4 1 2.97 105 365 0 0.01 5 1 2.97 1 3 6 0 0.01 6 1 2.94 107 3426 0 0.01 4 2 2.95 1 8 457 ( 0. f 7 2 2.9- 10 34 0 0.02 V 1 2.96 110 3519 0 0.02 9 4 2.97 1 1 3 n 0. 2 9 1 2.95 112 3581 0 0.01 4 1 2.97 113 3612 0 0.02 6 4 2.95 114 364 0 0.01 6 297 11 3674 0 0,02 7 2 2. 6 116 3705 0 0.01 5 1 2.97 117 3736 0 1 0.01 61 12.97 118 3767 0 n.02 7 1 2. 7 119 3798 0 0.02 7 1 2.97 120 3829 0 0.02 6 1 2 7 11 361 1 1 2.7 122 3891 0 0.01 6 2 2.96 123 3922 .01 124 3953 0 0.02 7 1 2.97 125 3985 0 .01 6 2.97 126 4016 0 01 127 4048 0 0.02 7 3 2.97 128 407 0 .02 2. 6 129 41 1 0 .0 9 3 2. 4 130 4142 0 0.02 7 2 2.96 1 4174 q 0.01 G 1 2.97 132 4206 0 .01 5 1 2. 7 133 4237 0 0.02 6 1 2.95 1 4 426 0 0.01 6 7 135 4300 0 0.0 7 2 2.95 136 4332 0 0.01 6 1 2.95 1 7 4364 0 0.01 C 1 2.92 e osi 138 4395 0 0,01 5 1 3 Lt. osits. 139 4427 0 0.01 6 1 2.94 14 4459 0 0.03 2 2.94 141 4490 0 0.01 5 2 2.97 14 4521 0 0.02 7 2 .93 143 4552 0 0.02 7 3 .96 144 45830 0.02 8 2 2.94 145 4614 jttM 1 10 1 3 2.94 146 4646 1 0 1 0.01 1 6 .92 1 Lt. Dermits. Penetration Body Metal Loss Body Page 3 i i -'s Well: Field: Company: iB-11 Kuparuk ConocoPhillips Alaska, Inc. PDS Report Joint Tabulation Sheet Survey Date: March 17, 2019 Analyst: Waldrop Pipe Description 3.5 in. 9.2 ppf L-80 Tubing Nom. ID 2.992 in. Body Wall Top Depth Bottom Depth 0.254 in. 13 ft 8,848 ft. Joint It. Depth No. (Ft.) Pen. Upset (in.) Pen. Body (in.) Pen. % Metal Loss % Min. 1. D. (in.) Damage Profile Comments (% wall) 0 50 100 147 4677 0 Q,02 7 3 2.94 148 4708 0 1 5 2 2.94 149 4739 0 0.02 7 2 2.94 150 4771 0 0.02 8 3 2.96 151 4802 0 0.01 6 2 2.96 152 4833 0 0.02 7 2 2.95 1 4 5O 0.02 6 96 154 4896 0 0.01 6 2 2. 6 155 4927 0 0.02 6 2 2.93 Lt De osits. 15 4 5 0 0.01 5 1 2. 7 157 4987 0 0.02 7 1 2.94 7 8 1 0 0.01 G 4 .97 159 5051 0 0.02 C 2 2. 160 5082 0 0.0 5 1 2.96 161 5111 0 0.02 7 . 7 162 5143 0 0.01 1 2.97 163 5174 0 0.02 7 1 2.96 164 5206 0 1 0.01 5 1 2. 165 5238 0 1 0.03 11 2 .94 166 5269 0 1 0.02 6 2 2.97 167 .5299 0 1 0.027 4 2.97 168 5331 1 0 1 0.01 6 2 2.97 169 1 5362 0 0.01 4 1 2.96 170 5394 0 0. 1 6 1 2.94 1 1 426 0 0.02 8 3 .96 172 5456 0 0.01 4 1 2.97 173 5487 0. 1 6 1 .96 174 5517 0 0.01 5 1 2.97 175 5548 0 1 6 1 2.9 176 579 0.01 5 2 ,97 177 5609 0 0.02 7 1 2.97 178 5638 0 0. 6 1 2.96 179 668 0 0.02 7 2.97 1805698 0 0.02 7 3 2.95 781 729fi 0. 6 1 2.97 182 5760 0 0.0 7 2 .96 183 5791 0 0.01 6 2 2.94 0 184 5822 0 0 1 4 1 .97 185 5853 0 0.01 5 .96 186 5884 0 0.02 7 1 2.97 187 5915 0 0. 1 6 1 2.94 188 1 5946 o 0.01 6 2 .96 189 5977 0 0.02 8 2 2.94 190 6008 0 0. 6 2 2.94 191 6039 0 0.01 6 1 2.96 1 607 0 .02 2 2. 7 1 3 6101 0 .O7 5 1 2.95 194 6132 0 0.02 7 1 2.96 5 67 0 0.02 8 1 2. 7 196 6195 .02 7 3 2. Penetration Body Metal Loss Body Page 4 Well: Field: Company: 1 B-11 Kuparuk ConocoPhillips Alaska, Inc. PDS Report Joint Tabulation Sheet Suney Date: March 1 7, 2019 Analyst: Waldrop Pipe Description 3.5 in. 9.2 ppf L-80 Tubing Nom. ID 2.992 in. Body Wall Top Depth Bottom Depth 0.254 in. 13 ft 8,848 ft. Joint Jr. Depth Pen. No. (Ft.) Upset (in.) Pen. Body (in.) Pen. % Metal Loss % Min. I.D. (in.) Damage Profile Comments (% wall) 0 50 100 1 7 6226 0 0.01 1 6 19 6 58 0 0.01 5 2 2.96 199 6289 0 0.02 G 2 2.97 2 6 20 0 0.02 9 2. 201 352 0 .01 4 Z 2.97 202 6384 0 0.02 8 2 2.94 03 415 0 6 2 2.9 20 6447 0.01 5 1 2.96 205 6478 0 0.01 5 2 2.96 06 651 0-02 8. 2 6 207 6542 0 0.01 4 2 2.97 208 74 0 .02 6 2 2.94 9 6606 0 0.02 7 2 6 210 6638 0 0.01 62 2.94 211 667 0 1 6 1 2.94 212 6703 0 0.01 5 1 6 213 L 6735 0 0.01 6 2 1 2.96 14 1 6768 0 0.01 6 2 2.97 215 1 6800 0 1 0.02 7 2.96 216 6833 0 0.02 7 1 2 2.97 17 6865 0 0.02 3 2.94 218 6898 0 0.02 8 4 2C)6 219 6931 0 0.02 7 2 2.93 2 6963 0.02 6 2 7 221 6 5 0 0.02 9 3 2.94 222 7026 0 0.02 6 1 2.95 22 7055 0 0.02 8 2 2.96 224 7084 0 0.03 10 2 2.96 225 71 14 0.02 8 2 6 2 7143 0 .02 8 2. 4 227 7172 0 0.02 8 1 2.96 228 7201 0 1 0.02 6 2 2.96 229 7228 0 0.02 6 2 2.96 1 230 7257 0 0.02 7 2 2.96 231 7287 0.02 7 2.96 232 7316 0 0.02 7 1 2. 97 1 233 7345 0 0.03 10 2 2.93 Lt. Deposits. 4 7375 0 0.02 9 3 2.94 235 7403 0 0.02 8 3 2.93 Lt. De its. 236 7432 0 0.02 9 1 4 1 2.94 237 7462 0 0.03 10 1 4 1 2.92 Lt. Deposits, 238 7492 0 1 0.02 9 1 2 2.9 239 7522 0 0.02 6 3 2.96 240 7552 0 0.02 8 3 6 241 7582 0 0.01 4 2 2.97 242 761 0 6.02 7 2 2.94 24 764 0 0.03 1 1 2.95 244 .7672 0 0.02 8 1 2.96 245 77 0 2 9 1 2.95 24 7732 Q 0.02 9 3 t. Deposits. Penetration Body Metal Loss Body Page 5 (R -S PDS Report Joint Tabulation Sheet Well: 1B-1 I Survey Date: March 1 7, 2019 Field: Kuparuk Analyst: Waldrop Company: ConocoPhillips Alaska, Inc. Pipe Descriplon 3.5 in. 9.2 ppf L-80 Tubing Nom. ID Body Wall Top Depth Bottom Depth 2.992 in. 0.254 in. 13 ft 8,848 ft. Joint No. Jt. Depth (Ft.) Pen, Upset (in.) Pen. Body (in.) Pen. Metal Loss % Min. Damage Profile I.D. Comments (%wall) (in.) 0 50 100 247 7763 0 0.02 6 2 2.96 248 7794 0 0.02 9 1 2 1 2.96 249 7824 0 0.02 7 1 2 1 2.97 250 7855 0 0.02 6 1 2 1 2.96 251 7886 0 0.02 7 3 1 2.94 252 7919 0 0.02 7 1 2.95 253 7953 0 0.02 7 3 2.94 254 7985 0 0.01 5 1 2.95 255 8017 0 0.01 6 2 2.96 256 8046 0 0.01 6 2 2.96 257 8078 0 0.01 6 1 2.95 258 8111 0 0.01 6 2 2.93 Lt. Deposits. 259 8142 0 0.01 5 2 2.93 Lt. Deposits. 260 8174 0 0.02 8 2 2.93 Lt. Deposits. 261 8204 0 0.01 6 2 2.96 262 1 8235 0 0.02 1 7 1 2 2.96 263 8267 0 0.01 1 4 1 2 2.96 264 8298 0 0.01 4 1 1 195 65 8329 0 0.01 4 1 1 2.95 266 8361 0 0.02 6 2 2.96 267 8392 0 0.01 2 8 8423 0 0.01 6 1 2.96 269 8456 0 0.02 7 2 2.96 270 488 0 0.02 3 294 271 8521 0 0.02 8 2 2.96 272 8555 0 Q03 10 2 2.94 7 8588 0 0.02 7 2.95 274 8620 0 0.04 15 4 2.95 Shallow Line of Pits. 275 8652 0 0.02 1 .9 7 4 ) 0.02 6 2.95 277 8716 0 0.02 7 2 2.94 78 8747 0 0.02 7 1 2.96 278.1 878 0 0.01 6 3 2.94 Pun 278.2 8789 0 0 0 0 2.85 GLM 1 LATCH Cgs 2:00 78.3 8799 0 0.02 2 2. Pu 279 8809 0 0.02 9 2 2.95 279.1 8841 0 0.02 7 2 2.96 Pu 79. 847 1 0 2.90 3.5" X 4.5" CROSS-OVER Penetration Body Metal Loss Body Page 6 Maximum Recorded Penetration Comparison To Previous Well: 1B-11 Survey Date: March 17, 2019 Field: Kuparuk Previous Date: March 5, 2018 Company: Conoco Phillips Alaska, Inc. Tool Type: UW MFC 24 No. 10020078 Country: USA Tubing: 4.5" 12.6 lb J-55 Overlay Maximum Recorded Penetration (mils) Difference in Maximum Penetration (mils) 0 50 100 150 200 250 -200 -100 0 100 200 GLM INj3 a E E e z Z c � 161 21 N 26 'o ^31 36 06 0 March 17, 2019 0 March S, 2010 -194 .97 0 97 194 Perforations Approximate Corrosion Rate (mpy) Difference 128 ' Corrosion RaCeEmpyZi TOP U Its. _Overall j �i��er@ge____36 -8 �— Mertan I 34 � -1 J 11 16 26 31 ' Corrosion RaCeEmpyZi TOP U Its. _Overall j �i��er@ge____36 -8 �— Mertan I 34 � -1 J Minimum Measured Diameters , Comparison To Previous Well: iB-11 Survey Date: March 17, 2019 Field: Kuparuk Previous Date: March 5, 2018 Company: ConocoPhillips Alaska, Inc Tubing: 4.5"12.61b J-55 Country: USA Tubing I.D.: 3.958 inches Overlay 1j p 1 Minimum Measured Diameters (in.) 1.75 2 2.5 Gc 3 3.5 - 0.1 848 2 926 2.3 010 2.8 041 4 093 ,199 r C E e11 343 'o y O 16 493 21 ,644 26 ,799 31 951 36 103 41 259 0 March 17, 2019 0 March 5, 2018 1j p 1 R-_ C G G Gc - Difference Difference in Minimum Diameters (in.) -0.5 10 J•S. PDS Report Overview Body Region Analysis Well: 18-11 Survey Date: March 17, 2019 Field: Kuparuk Tool Type: UW MFC 24 No. 10020078 Company: Conoco Phillips Alaska, Inc. Tool Size: 1.69 inches Country: USA No. of Fingers: 24 Pipe 4.5 in. 12.6 ppf J-55 Analyst: Waldrop Pipe Nom.OD Weight Grade & Thread Nom.ID Top Depth Bottom Depth L 45m 12.6 ppf J-55 3.958 in 8 848 ft 10 281 ft 30 20 0 Penetration (%wall) 0 to 20 to 40 to over 20% 40% 85% 85% Number of joints analyzed (total = 49) 7 5 29 3 ji3"s Well: Field: Company: 1B-1 I Kuparuk ConocoPhillips Alaska, Inc. PDS Report Joint Tabulation Sheet Survey Date: March 1 7, 2019 Analyst: Waldrop Pipe Description 4.5 in. 12.6 pot J-55 Tubing Nom. ID Body Wall Top Depth Bottom Depth 3.958in. 0.271 in. 8,848 ft. 10,281 ft. Joint No. It. Depth Pen. (Ft.) Upset (in.) Pen, Body (in.) Pen. % Metal Loss % Min. I.D. (in.) Comments 0 Damage Profile I% wall) 50 100 0.148 0 0 0 3.85 Pun Lt. Denoqits. 0.2 8852 0 0 1 0 0 .78 BAK R SEAL ASSEMBLY 0.3 8869 0 0 0 0 3.83 BAKER SEAL BORE EXTENSION 1 8877 0 603 10 1 3.85 Lt. Deoosits. 1.1 8917 0 0.0 6 1 3. Pu .2 8926 0 0 0 0 3.74 GLM 2 LATCH @ 6:00 .3 8935 0.01 4 1 3. Pu 2 8943 0 0.04 6 2 3.85 Shallow Pi tin . Lt. Deposits. .1 12.2 8982 0 0.04 15 3 3.88 Pu Shallow Line of Pits. Lt. Deposits. 8992t0.080. 0 0 3.77 KER S AL ASS Y .3 9010 0 0 3.85 FH HYDROSTATI PACKER .4 01 3 45 143. Pu Corr ion. De sits. 5 1 34 11 3.90 P Corrosion, 2.6 9025 48 18 3.95 Pu Corrosion. 2.7 9032 0 0 2.60 HESX NIPP E 2.8 041 33 11 3.94 PUD Corrosion. 2.9 9046 1 0 0 0 0 4.06 BAKER OVERSHOT 3.1 9Q48 1 0.17 0.18 65 21 3.81 Pup Corrosion. Lt D sits. 3.2 9068 1 0 0 0 3.96 BAKER PBR 3.3 9085 0 0 0 0 3.70 BAKER FHL RETRIEVABLE PACKER 4 2Q93 0.14 0.13 49 20 3.84 CQrrosion. Lt. Deposits. 4.1 9132 1 0 0 0 3.72 CAMCO DB NO GO NIPPLE 5 9133 0.14 0.19 71 28 3.83 Corrosion. Lt. Deposits. ONE 5.1 9162 0 n 0 0 .89 I I N MAN REL TCH 8:00) 9170 0.14 0.38 100 19 3.76 Hole! Lt. De o i s. 7 9199 0.09 0.23 86 13 3.77 Possible Hole! Lt De osits. MEN 7.1 924 0 0 3.54 IN ION MA DREL 4 (LATCH : 0 8 9253 43 8 3.76 Corrosion. Lt. Deposits 9 9283 A0.070.16 41 4 3.76 I fated Pittin Lt. De its. 10 931 56 9 5 Corr sjon. Lt. Deposits. 11 9343 58 13 3.77 Corrosion. Lt. De osits12 2 53 0 3.75 CQrrQsion. Lt. Deposits. 13 14 9402 9433 0.09 0.07 0.19 0.14 68 53 17 10 181 1 3.79 1 C rr sion. Lt. Denosits. Isolated Pitting. Lt. De osits. 15 4 0 .17 63 5 3.72 1 in f Pits. . De osits. 16 9493 0.11 0.13 46 7 3.74 Corrosion. Lt. Deposits. 17 9524 0.16 0.16 61 7 3.76 Corrosion. Lt. De osits. 18 2555 0.08 0.43 100 = 3.77 kAidtin1p Hnlacl Lt. De 19 9584 0.04 0.14 51 1 3.72 Corrosion. Deoosjts. 20 1 9614 0.06 8 3.73 Corrosion. Lt. Deposits. 21 644 0.04 7 3.71 rrosion. Deposits. 2 967 0 . 7 3.64 C rr sion. De sits. 23 9706 0.06 9 3.73 Corrosion. Lt. Deposits 24 737 0 $0,4410 9 3.78 orr sion. Lt. Deposits. 25 9768 0.05 6 3.68 Isolated Pitting, De osits. 26 99 3.67 solated Pi i e sits. 2 8 9 0.0 0 ...8 Perforations Deposits. 28 9858 0.09 . 6 3.77 Perforations Lt. De osits. 29 890 ().09 0.19 68 7.8 Perforations . Deposits 30 921 0. 6 0.14 .53 3.7 Isolated Pitting. LLDeposits. 'Penetration Perforations Metal Loss Perforations Page 1 Penetration Body Metal Loss Body ii -S Well: 1B-11 Field: Kuparuk Company: ConocoPhillips Alaska, Inc. PDS Report Joint Tabulation Survey Date: March 17, 2019 Analyst: Waldrop Sheet Pipe Description 4.5 in. 12.6 ppf J-55 Tubing Nom. ID Body Wall Top Depth Bottom Depth 3.958 in. 0.271 in. 8,848 ft. 10,281 ft. Joint Jt. Depth No. (Ft.) Pen. Upset (in.) Pen. Body (in.) Pen. °o Metal Loss % Min, I.D. (in.) Comiments Damage Profile (%wall) 0 50 100 31 1 0 0.1 69 6 72 Isol d Pittin . e o i 2 9982 0.10 .11 42 6 3. orrosion. t. Deo its. 33 10013 0.06 0.12 43 3 3.77 Isolated Pittin Lt. De 4 1 0 U4 75 3 J2 Perfor i ns De si35 10071 0 0.13 49 7 3,71 Perforations De osits. 36 10103 0 0.08 28 7 3.86 Isolated Pittin Lt. De 37 101 35 0 0.0 30 4 3.7 ine of Pi . De o i 38 10165 0.05 0.21 77 7 3.84 e of Pits. t. e osit39 101 95 0 0.12 44 5 3.85 Line of Pits. Lt. De osit4 10227 U 0.05 18 3 .83 hallow Pi t.De 41 10259 0 014 51 7 294 Line -fPits: Heav De Penetration Perforations Metal Loss Perforations Page 2 Penetration Body Metal Loss Body jits, Field: Company: Country: 1 B-1 1 Kuparuk ConocoPhillips Alaska. Inc. USA PDS Report Cross Sections Survey Date: March 17, 2019 Tool Type: UW MFC 24 No, 10020078 Tool Size: 1.69 No. of Fingers: 24 Cross Section for Joint 18 at depth 9,573.641 ft. Tool speed = 51 Nominal ID = 3.958 Nominal OD = 4.5 Remaining wall area = 92% Tool deviation = 59° Finger = 5 Penetration = 0.425 in. Multiple Holes 0.43 in. = 100% Wall Penetration HIGH SIDE= UP ji: �-a IB -11 Field: Kuparuk Company: ConocoPhillips Alaska, Inc. Country: USA Tubing: 4.5 in. 12.6 ppf J-55 PDS Report Cross Sections Survey Date: March 17, 2019 Tool Type: UW MFC 24 No. 10020078 Tool Size: 1.69 No. of Fingers: 24 Cross Section for Joint 6 at depth 9,194.761 ft. Tool speed = 51 Nominal ID = 3.958 Nominal OD = 4.5 Remaining wall area = 84% Tool deviation = 60° Finger =l2 Penetration = 0.381 in. Hole 0.38 in. = 100% Wall Penetration HIGH SIDE = UP is� Well: 113-11 Field: Kuparuk Company: ConocoPhillips Alaska, Inc. Country: USA Tubing: _ 4.5 in. 12.6 ppf I-55 PDS Report Cross Sections Survey Date: March 17, 2019 Tool Type: UW MFC 24 No. 10020078 Tool Size: 1.69 No. of Fingers 24 Cross Section for Joint 5 at depth 9,133.951 ft. Tool speed = 51 Nominal ID = 3.958 Nominal OD = 4.5 Remaining wall area = 72% Tool deviation = 49° Finger = 15 Penetration= 0.188 in. Corrosion 28% Cross -Sectional Wall Loss HIGH SIDE =UP iiS� PDS Report Cross Sections Well: 1 B-11 Survey Date: March 17, 2019 Field: Kuparuk Tool Type: UW MFC 24 No. 10020078 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Cross Section for Joint 3.1 at depth 9,049.150 ft. Tool speed = 51 Nominal ID = 3.958 Nominal OD = 4.5 Remaining wall area = 79% Tool deviation = 56° Finger = 17 Penetration = 0.110 in. Corrosion 21% Cross -Sectional Wall Loss HIGH SIDE = UP jPDS Report Cross Sections Well: 1 B-11 Survey Date: March 17, 2019 Field: Kuparuk Tool Type: UW MFC 24 No. 10020078 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Cross Section for Joint 41 at depth 10,276.298 ft. Tool speed = 50 Nominal ID = 3.958 Nominal OD = 4.5 Remaining wall area = 99% Tool deviation = 65° Minimum I.D. = 2.940 in. Heavy Deposits Minimum 1. D. =2.94 in. HIGH SIDE = UP PDS Report Cross Sections Well: 1 B-11 Survey Date: March 17, 2019 Field: Kuparuk Tool Type: UW MFC 24 No. 10020078 Company: Conoco Phillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 4.5 in. 12.6 ppf J-55 Analyst: Waldrop Cross Section for Joint 2.4 at depth 9,016.581 ft. Tool speed = 51 Nominal ID = 3.958 Nominal OD = 4.5 Remaining wall area = 92% Tool deviation = 560 Minimum I.D. = 3.643 in. Deposits Minimum I.D. = 3.64 in. HIGH SIDE = UP y,AdEhh, KUP INJ 1B-11 rnnnenPkrll4ne Well Attributes -- Tz Anole s htn r- l n ��'•��� ""•T" .449318, If C. vJclmarcgpuuwl 5 0 0 2920 6 510 0 Ham rvame wm14[,e s{au. na(<{ rnDlnrcR{ A.<.em (ttrca) KUPARUF RIVER UNIT INJ 64.58 10.60000 10,7210 Ment 59GV', NIPPLE R9"Ong a pnnoiell[n na OFp .Gr01n1 LaskWO: R 25201] 2J.fiO "a..le... Dale 1209982 +en vro¢leiu ]. e4, Last Tag X.q,.rcneneur .rme9 ........... ... .N+NG=R, Ni.n- Mn..'Orn - 1 and TO, RKR l .pM1 (XKB) ntl-01 10..4.45.0 R T'lI .sl Metl mm4axj By Last Rev Reason MnalalianEntl Ree R -on: A., DV, nab Pnllxl] 231 CAJ PInq. H SxI A -Y lnjrK,lion Vnlvx NI700YR 'MWBy 'xmbaxj ..._.. .. _......... .....__._ _._...... __....... Casing S`trl.g6 Cneine 0cvcrimion DOD.) IDfin) 20 {893$29680.0 ivn lflKBl SN DCRfh PRKO] 11... Gr:Hv O1.5DH40 ivvThrt:WNDUCTOR WELDER C.[Ing Deeupt,"nn SI IFACE Do li nj ID(inl 1334, 12.415 TopIRKB) 6x Dy+h IflKBI O)... ILen (1... Gra[ ]ABRPLR42.0 ]2.00 .All Top Th." BTC.(In, 3rWDIDI,-01...-1 I.(In) Tep [rzrc.]SelepinlnXelpl-. Valun n.,MO.. TapTnreea PROD Te back 2017 WO 958 SAW 26395.6 40.00L-80 TDDans Wedge 563.II,m, D.e[np[i[n OO POST M1]WO OD Dnj N(inp 45/0 8.1 Top I KB es D[pih IS. il__ YRILen I1... 6rxla ]MBATSR g200I TII Tap ThmaGPR PIT,........crpllan HIWLe SL'EF IX,iI.IrDXvn.eLIBSEYI: ap lnl IA(In, TeP"Re, n'NnXnfa 01... WI en lL..LINER J 6276 9264.4 et 1069E0 23 426.00 Ill56BU1T - TopThnea - Liner Details - .re.n TopinKel T[pCwlflIDal TOP 111119 mm De.NammeHO n] 9.2604 6. 0 5]3]SLEEVE BAf:ER SEI TING SL EEVEm 6.151 G, 2BN.h 1 8/A)K3 5/.;AN NIYW F HAKFHSI-AI NIVWF N.1hY RG. Tlebuk::l'1100:11 9.2698 62 .1 SJ34 HANGER BAl1EMdOHYDHANGER 6151 TM'0 ITS SS 1,Y17Y h/.!1 %U BIISY{INIi HAKLH GHUSS.1..USIHING flY01 TubingStrings EJR=M. E; iCd 2A1<x� Tubing 0[ecnpibn 1.01NCi-=17] IU BVin9 Mc.,, ]t< 10 (i n) ';.942 TOK PIKE) 2U!J ..ftIPI (X.. 8.611 Sct RPIh ITW)(...WIOM) v. UC5.1 EST Grq[ DO Tap C-Iwuun TunaneWape :F3 ISOmpletion Details nav fT n; ;p.Y TIP IWO, TeP(RnR] 1X -el T"m I I"I ram De: N -B., AIn) 20.9 20.8 0.11 HANGER rM4 .1 4,81312"-4 fZ IBTTUBING NGER 4.000 9LH 21p 0.11 ME HIIII A--X1-PARI. IIY%:H L'J'.9:1tl.1-RII%AND{-OVEN 2.9Y1 4➢GTOR A➢'16.2K 508.4 508.4 454 NIPPLE CAMG 2.876" DS LAND NG NIPPLE 2.875 WJ ReMr,BrtunnB);a¢:9n SEiL iS5Y:3,BYB{ aB2B.] S;D/3.tl b/.hS XC LrII ging '3V2"'D.S LBq ISH 141'4 V2"' 12 .53, LSU, ISH 5U!%-0VLH 2. U50 I,ITI., XO I'S"I p ITI)4501 bS292 h,U/4.4 S/.b LUV'AIOH OHH 22 L0.¢1ol San 3.8SU 8,828.8 4974.7 111 SEALASSY Baka11 W47 Heal MIS,ri bly 3.880 uW111 M'II'v, ., T.O, DmIn I INFR-Innx, fal.ing .102017 rinp M. IDQnI ] 42]9 Tap (hN8) Jft ft Sel O.p[M1 (h.. RAWLO int pvpfM1lMy(_WY(Ipllp fi.OR3.3 28.001-30 Grale TIp CInn[n on TY,P Gomplstion Details tocnrDR BHiu gEAL A6: v,de?BE rnp{ry81 TeP lnxel IrzKef TOP IncI Ih INm De. Nlminfll IDHnJ 913f3 5,9761 7.5656E Baker.1BBDl¢ EM P51011 WIa10.7510 150 8,974,5 &062.8 9.59 LOCATOR 666 RLgcalpr Bub�2Xxpace pul BACK Ff.CkER .5.¢453 8978. 6,0539 57.59 SEA AGSY ESKIr19047'Seal AseemblT 3.870 N FpER C<: NIFPLER36CER$92<: bl ng pe.[Itptlan 91r1n41&3 1pllnl 8.3 3.675 f.'errlpleaOn Qetdis compTU 111 YVi on TaPlrD.9 gel -KIT 9087 S.t cePln jKnI W1fIWr1) Glwle 8.976.2 9,OU87 6.06]2 iopc011neRlan CV[n2 roT n..I.0 TI nne TIpI )" PI 1 (h%B) a979A W3.] Tlp lrel I°I mm ae. cam 5. PBR BAKER RBRE 1904] Neminal 111151 95 eBR 0¢8.41 9,0 94 60 1.5 5]50 Pp1:KCR FIIlMOROS A CPACKCR 3900 PB02a 2v6i.1 90240 6.0793 67.61 NIPPLE HESRNIPPLE 3.813 9,030. 60810 5]8:5 OVCR8I IRT BAKEC RSIIOTIRWALLOW]1,TOPMOIl0lnal WhlnO A BA IJ 1-19.1]2: ANH/' INdGCTibN 9miz TILE, es[O'K. TUBINGOn01na1 Strinp Me... lb(Inl 412 4958 Tap (1cK9I Se1-1 (0._ $et D.p{n(TM) I._ Wt( ICM) Grazle 9.037.1 10,3155 5700.2 12.60 J 55 ......nec+lOn BUXIe9e INJECTIDIJ 5,F4d9 Completion Details TOPID)TIP nal TOp IXNB I'] ltam baa CO.- 9,065.1 0,101.3 5'70 POR BARER PBR Nlminal m(Inl 3.920 9.051.1 6,11'15PACK R BA E 'FHL'RET ENABLE PACKE 3320 9,13240 B, 137.0 9.� NIPPLE CAMCO OB NO GO NIPPLE 3.750 103 .2 6764.3 1.]6 %OREDEGING CROBSOVE .1(35' 3.500 10.303.8 0,754.0 01 ]6 LOCATOR BAKER LOCATOR 2992 PPI Fvvnv . PI z 10304.3 6764.9 917] ALASSY BAKER" ALASSEhISLY 2 92 .11" ' 10307.2 6,7 6.2 1.80 30C SCAL UR %TCNSION 2,992 T4pIn93eecHptlan Nrinp Ma... I D Xn) Tap {RKBI Sel BEgll ({L.SN DEprM1 CV%(...YM(I.X) GrAYe TaPCO" 0"'05 TUBING OII9Qna1 3112 2392 10,30].1 103855 6.7926 0.307-55 BuNcss APERF: 19 OR 010{00']-- _ Campletlan Detalls - inp KigVU1 T10301., , ) tU;3O/.l 6/5fl'1 reP Incl 19 1411Do-. tl1 YU PACKER Com HANGH}tl-1'PACKLH ul'LDD .4000 L'KA➢Cn 19.1959 sE•i lss.lu]9u ,I 103006 075 A 61.&3 BBE BAKER DEAL BORE E N310N 4,000 fAL'aFR +B]te^ eaR7o 10. 51. 67]8.3 fi238 NIPPLE DAMUO'D'NP E 2.750 im.a .. .99.9 10.304.5 6792.2 02,74 SOS BAKER BULL NOSE SHEAR TOOL 2,992 197177 Other In Hole (Wlrellne,. retrievable plugs, valves, pumps, ilsh, etc.) ... jTV01 TOP ncI 19.]eaE TOP IXKB) (BKB) SOBA 5084 V pea 1 4 INJCC 10 Cpm Run Orta 10 (In) 2.075Al IRleneoe Vely. T' -1T 3'1]1a11b RPERF1040L].19a15:- VAI VF (3S3V) ROI .103]. 19119- 9,0.0 5,0]9.3 1 5'G'I NIPPL RF911CFH 3.81"s�LOCKON2.31"BNIPRCDUCCNi3'S) {"Sd 2011 2.8'10 WMWll OIIIOF FNmY ON BOTTOM Cfi 9,C5:.Y19,09I +Qi l ConocoPhillips Alaska.Ivu 1B-11 + ,(, t 5 cx]n Fld ..:. ........ ......7,. _....... Per(orafions&Sbfs iOp lgNBl 6tm IgKB] ro 9 (11K6) Rlm no IgKB] 1 gene aTe 195)eh Type E. 9, 300 9;92 .0 6.514.1 fi,5G2.t C-S,C-3, IB -11 1rz4H982 40 APERF CUMUVC OR 255-400 10,066.0 10.f OG.O 68360 6.6511.3 C -i, NITS, IB 11 'I'Ii1N UYO 4.0 APEHF 296 A,-. J.S1 Odell. PCIIInaIW lOblllyl 6"a Ndee 0, L0 10,415.1] 6,]99. 6.8ofi. Miuv ch,1B. 4;20'1962 40 RPERr 4" HYPERJET II 11 hlOeLE 556.3 IruECrlUry \'0.VE 19Siy. 1T3 104310 104 .A G.813.3 6,P39.5 Mlklvc cn, lB- 11 420'IOR 4.0 RPER 4"HVPTRJETF Mandrel ln"M P9Ue To hfal.Jll"✓Jo )L: TV0 V.11ye M^4e Lfllen Port31ze TR(I qyX 91.6 CAMCO 9 CAS LIFT OMY BK 0.00 00 u'I]ROtBY6.8 TB CPIACO KBh16 t GBS LIFT OMY W BK1., CApdLU 445b 1112 INJ CV p/p! OU 192y11Ytll 89019].6 CANICO 4.5.:1.5 1112 INJ CV 0.]03 0.0 12pD'1992 5'.00 ^Pfl Lli-: 9nL6 • IVOt2e: 6xmeral 52f0}y EpX 6Atp MIIOIAHUX 2'52003 NOTE: VIO 8'9rzD10 NOTE.Vic Schemaf le Ala6kESO.a11c9.OREV WCATUP.: 91M2 ,,3;0 13 12 NOTE: VJAN REO JELL OAt00A .aon Wenpl9Xacy: Ra'.9a 6_AL 99:Y: 8.030.6 3 L20] NOTE: Leaknl&3Rr auRaLew9in af912'tluR tR inativerhml B cultlmlR 201]HWO Y f.BE:0;1I10 1 Fo Fyni;;yiluYiiu`.Bdu0.9 9.511!' J `15 i u.l A44Y.fi.9]n5 PBF.', 9Y%6.0 cA, KER "O54- O54 11, HIPPLE: 9,9_40 WCie� O-. e.G9o.B R,51 NIPPI ,RITR w.ECTMm,nnm IPLEZTIOP30.2345 v,912i AP -RF: uCALAYV: 10303.] 'J 9072 _ 39F'.'J.30)3 3aF.'2,]OV.6 HILPIF IX:ti31 PP@G'J3p1 h1i1,315 p� FPGA F.'J.391.010.169.e�� LIFICl..:MA- i.E96.0� • 1 81136 WELL LOG TRANSMITTAL 29185 S ,, PROACTIVE DIACINOSTIC SERVICES, INC. To: AOGCC Makana Bender 333 West 7th Avenue Suite 100 SCANNEV Anchorage, Alaska 99501 (907) 793-1225 RE : Cased Hole/Open Hole/Mechanical Logs and/or Tubing Inspection(Caliper/MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of: ProActive Diagnostic Services, Inc. RECEIVEDAttn: Ryan C. Rupe 130 West International Airport Road Suite C MAR . 9 2618 Anchorage, AK 99518 Fax: (907) 245-8952 AOGCC 1) Caliper Report 05-Mar-18 1B-11 1 Report I CD 50-029-20657-00 2) ip Date 4 Signed : ��oh Print Name: N VCA PROACTIVE DIAGNOSTIC SERVICES, INC., 130W.INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAx: (907)245-8952 E-MAIL: PDSANCHORAGEt5 MEMORYLOG.COM WEBSITE:WWW.MEMORYLOG.COM DAAchivesNastenemplateFiles\Templates\Distribution\TransmittalSheets\Conoconillips_Transmit.docx Wallace, Chris D (DOA) From: NSK Well Integrity Supv CPF1 and 2 <n1617@conocophillips.com> Sent: Monday,April 16, 2018 5:13 PM To: Wallace, Chris D (DOA) Cc: Senden, R.Tyler Subject: RE: KRU 1B-11 (PTD 181-130 Report of suspect OA pressure increase update 4-16-18 Attachments: 1B-11 90 day TIO 4-16-18.JPG Chris, 1B-11 was returned to gas injection on March 18th and is nearing the end of its 30-day monitor period. There has not been a return of the unexplained OA repressurization. However neither has the OA achieved stabilization. The OA is particularly sensitive to thermal fluctuations and unfortunately the gas injection temperature has oscillated greatly over the last month due to CPF plant issues. We will extend the monitor out an additional 30 days on gas injection and proceed with the plan that was laid out in last month's letter(see below). Let us know if you disagree. Attached is an updated 90 day TIO plot. Kelly Lyons/Jan Byrne Well Integrity Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907)659-7224 From: NSK Well Integrity Supv CPF1 and 2 Sent:Saturday, March 17,2018 8:29 AM To: 'Wallace,Chris D (DOA)'<chris.wallace@alaska.gov> Cc:Senden, R.Tyler<R.Tyler.Senden@conocophillips.com> Subject: RE: KRU 1B-11(PTD 181-136) Report of suspect OA pressure increase update 3-17-18 Chris, 1B-11 was secured and the PM wellhead maintenance work was completed. During the secure process, an MITT did pass(see attached 10-426)and the OA was circulated out with fresh fluid via the GLM which was installed during the 2017 RWO. CPAI intends to return the well to gas injection for a 30-day monitor. If the OA resumes its unexplained repressurization, an acoustic LDL will be run in hopes that the point of communication can be determined so that a path forward can be established in returning the well to MI/gas injection on a permanent basis. Follow-up communication will be provided at the conclusion of the diagnostics. Please let us know if you disagree with our plans. Kelly Lyons/Jan Byrne Well Integrity Supervisor SCANNED - ConocoPhillips Alaska, Inc. Desk Phone(907)659-7224 From: NSK Well Integri e PF1 and 2 Sent:Tuesday,January 30,2018 6:26 • To:Wallace, Chris D(DOA)<chris.wallace@alaska.gov> Cc:Senden, R.Tyler<R.Tyler.Senden@conocophillips.com> Subject: RE: KRU 1B-11(PTD 181-136) Report of suspect OA pressure increase update 1 • • Wallace, Chris D (DOA) From: NSK Well Integrity Supv CPF1 and 2 <n1617@conocophillips.com> Sent: Saturday, March 17, 2018 8:29 AM To: Wallace, Chris D (DOA) Cc: Senden, R.Tyler Subject: RE: KRU 1B-11 (PTD 181-136) Report of suspect OA pressure increase update 3-17-18 Attachments: MIT KRU 1B-11 diagnostic MITT 3-6-18.xlsx Chris, 1B-11 was secured and the PM wellhead maintenance work was completed. During the secure process, an MITT did pass(see attached 10-426)and the OA was circulated out with fresh fluid via the GLM which was installed during the 2017 RWO. CPAI intends to return the well to gas injection for a 30-day monitor. If the OA resumes its unexplained repressurization,an acoustic LDL will be run in hopes that the point of communication can be determined so that a path forward can be established in returning the well to MI/gas injection on a permanent basis. Follow-up communication will be provided at the conclusion of the diagnostics. Please let us know if you disagree with our plans. Kelly Lyons/Jan Byrne Well Integrity Supervisor ConocoPhillips Alaska, Inc. S M4(48 Desk Phone (907)659-7224 From: NSK Well Integrity Supv CPF1 and 2 Sent:Tuesday,January 30, 2018 6:26 PM To:Wallace, Chris D(DOA)<chris.wallace@alaska.gov> Cc:Senden, R.Tyler<R.Tyler.Senden@conocophillips.com> Subject: RE: KRU 1B-11 (PTD 181-136) Report of suspect OA pressure increase update 1-30-18 Chris, Passing MITIA, MITOA and IC packoff tests were performed on January 12,2018 on 1B-11. The IA pressure was bled down below the OA. However the OA continued to repressurize while the well was on gas injection. There is a section of this completion where direct TxOA communication is possible. Therefore a gas-only TxOA communication leak began to be suspected. The well was WAG'ed to water injection on January 26,2018. The OA continued to climb. But over the last several days, extended OA bleeding has occurred and the OA pressure has begun to stabilize out. The 30 day monitor period is being reset to begin when we WAG'ed the well to water injection. Incidentally,the well is due for preventative maintenance wellhead work which will require the well to be secured with a downhole tubing plug. At the conclusion of the monitor,the well will be secured and the PM work completed. At that time an MITT will be performed that will test the section of pipe that would allow the TxOA communication. Prior to returning the well to injection, a follow-up email will be provided at the conclusion of the wellhead work,once a path forward is established. Please let us know if you disagree with the plan. Attached is a 2 week SCADA snapshot highlighting the recent OA bleeds. Kelly Lyons/Jan Byrne Well Integrity Supervisor ConocoPhillips Alaska, Inc. Desk Phone(907) 659-7224 1 • • 181136 29 1 8 5 Memory Multi-Finger Caliper _.. Log Results Summary Company: ConocoPhillips Alaska, Inc. Well: 1B-11 Log Date: March 5, 2018 Field: Kuparuk Log No.: 14306 State: Alaska Run No.: 2 API No. 50-029-20657-00 Pipe Description: 3.5 inch 9.2 lb. L-80 Top Log Interval: Surface Pipe Use: Tubing Bottom Log Interval: 8,841 Ft.(MD) Pipe Description: 4.5 inch 12.6 lb. J-55 Top Log Interval: 8,841 Ft. (MD) Pi•e Use Tubing Bottom Lo• Interval: 10,283 Ft. MD Inspection Type : Corrosive & Mechanical Damage Inspection COMMENTS : This caliper data is tied into the top of Injection Profile 4 at 9,245 feet(Driller's Depth). This log was run to assess the condition of the tubing with respect to internal corrosive and mechanical damage. The caliper recordings indicate the 3.5 inch tubing appears to be in good condition, with no significant wall penetrations, areas of cross-sectional wall loss or I.D. restrictions recorded. The caliper recordings indicate the 4.5 inch tubing logged appears to be in mostly fair to poor condition with multiple holes recorded intermittently throughout. Wall penetrations ranging from 40%to 100%wall thickness are recorded in 28 of the 49 joints logged. Recorded damage appears as isolated pitting, a line of pits, line corrosion, and general corrosion. Cross-sectional wall loss between 15% and 23% metal volume is recorded in 4 of the 49 joints logged. Deposits are recorded throughout the tubing logged, restricting the I.D. to 3.25 inches at 10,281 feet. A 3-D log plot of the caliper recordings across the tubing logged and a graph illustrating the minimum recorded diameters on a joint-by-joint basis are included in this report. The caliper recordings indicate a slight bend at—9,843 feet. This is the second time a PDS caliper has been run in this well and the first time this tubing has been logged. 3.5 INCH TUBING - MAXIMUM RECORDED WALL PENETRATIONS : No significant wall penetrations (> 15%) are recorded. 3.5 INCH TUBING - MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS : No significant areas of cross-sectional wall loss (> 7%)are recorded. 3.5 INCH TUBING - MAXIMUM RECORDED ID RESTRICTIONS : No significant I.D. restrictions are recorded. SGAN°Ii ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) 431-7100 or (888) 565-9085 Fax: (281) 431-7125 E-mail: PDSAnalysis@memorylog.com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2314 • 4.5 INCH TUBING ,-- MAXIMUM RECORDED WALL PENETRATIONS : Description Percent,^'.,'i Penetration Joint Multiple Holes 100 27 9,847 Ft. (MD) Multiple Holes 100 6 9,196 Ft. (MD) Hole 100 10 9,326 Ft. (MD) Hole 100 18 9,577 Ft. (MD) Possible Hole 94 21 9,678 Ft. (MD) 4.5 INCH TUBING .. MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: Description Percent "'All Lor Multiple Holes 23 27 9,137 Ft. (MD) Multiple Holes 20 6 9,196 Ft. (MD) Hole 16 10 8,841 Ft. (MD) Hole 15 10 9,599 Ft. (MD) No other significant areas of cross-sectional wall loss (> 14%)are recorded throughout the tubing logged. 4.5 INCH TUBING MAXIMUM RECORDED ID RESTRICTIONS : Description '.Minimum Recorded Diameter Deposits 3.25 inches 41 10,281 Ft. (MD) Deposits 3.54 inches 8 9,257 Ft. (MD) Deposits 3.54 inches 33 10,052 Ft. (MD) Deposits 3.68 inches 1.3 8,928 Ft. (MD) Deposits 3.69 inches 30 9,964 Ft. (MD) C. Goerdt C.Waldrop S. Ferguson ineer(s) Analyst(s) Witness(es) ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) 431-7100 or (888) 565-9085 Fax: (281) 431-7125 E-mail: PDSAnalysis@memorylog.com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2314 0 • CPS PDS Multifinger Caliper 3D Log Plot Company : ConocoPhillips Alaska, Inc. Field : Kuparuk Well : 1B-11 Date : March 5, 2018 Description : Detail of Caliper Recordings Across 4.5 inch Tubing Logged. Comments Depth Maximum Penetration Nominal I.D. 3-D Log Image Map I1ft:300ft 0 % 10013.5 inches 4.5 0° 0° 90° 180° 270° 0° Maximum I.D. 3.5 inches 4.5 Minimum I.D. I I 3.5 inches 4.5 _ I - Pup Joint • ; 8850 Seal Assembly re Seal Bore Extension , 8875 ' = w Joint 1 "' 8900 l4.- Ita Pup Joint GLM 2 �i�. .,—a 8925 Pup Joint 25 8950 3 Joint 2 c 1 8975 1 t - f Seal Assembly 0 0 9000 • Packer — Pup Joint AM Pup Jointa ti •.,_... _., w _ Pup Joint 9025 , , _ ..... .,...... Pup Joint ill m:,.. ,.... X Nipple Pup Joint Overshot 9050 mu i 1 -,0 Pup Joint /111t ___ W. PBR 9075 11111 Packer r 9100 .1 Joint 4 .. • L . , 9125 • r . , / ask No Go Nipple ----_ _ ...1=PP• F.k._. _•• II Joint 5 E.-.._ 23%Wall Loss 9150 F. — IF ... .._ a Injection - Mandrel 3 _________ _ • ler 9175 '. Joint 6 111 _ ill Multiple Holes _ • 20%Wall Loss 111" - _ It 9200 . ...._ if 1 IS S • Joint 7 9225 Fil- P •-- I r--•••: 1.- Injection ave Mandrel 4 9250 II ali T _,,...,_...i. ainall sr i,.. r• .4111, -,„- ,-_- Joint 8 9275 .,, 7 - MI .1i ,..., ---1111 •••••1 .4111 - 9300 - Ammo --,■1 - _ -_-_. Joint 9 ..... 9325 _., Joint 10 Hole _3 _ ....._ J , _ l 9350 ------. 1. - r- - ii Joint 11 il --i7: 9375 rp-- __..... - - —a 4 t _ --... -.1 t _ Joint 12 NI 9400 • ir-- _ Pr'- -7-4-11 11:1111 Joint 13 9425 1 • ... Ir , ....., • • 9450 MOME4inni. - 1 Joint 14 1 --'1°1111 111111111111111111111 1111111E111111111111 i 11111111-34111111111111-3411111111111E-3� 11 i: , , 9475 _....-mi1111E!C3■■■■ -i 1111■FitI■1111■ = a Joint 15 r I ■■11M611■■■■ Possible Hole 21111 ■■CC1ii■■■■ . 9500 11111111E111111111111 gi 1111■ 0CAE■■■ — ■■■ . ,1111■■ norm.41111M11 Joint 16 ;'�1 OMELiLli■■■ 9525 . .,,._ - .1 ■■ia.1N�i■■■ ''. '° .__ ■■■roll■■■■ ... ,..„. „. _, ._.. ,_ ...,._. - � ■■■EU■i■■ ■_ ■11■E:1�1■1111■ Joint 17 9550 ■■■E: ,ii■■■ 1, 1 �� ■■■■t v:�■■■■ _-,:' ■■EEN7EN■■ - :;. 9575 :lam ■■■I_11-11111■■ Joint 18 1111■11t11[1:112■■ - Hole ?1■■■■■■1111■11� 1111.■■ - _J1i■ ■■■S: ■■■■ ■■■FJ_M■■11 9600 -�� ■■11 ■■■11 ■■■f VIII= - - MIK IE4■■■■ - . Joint 191 ■■E..�11a■■■■ - - ,.. 11111111E11111111111111 111111111P-1111111111111111 1■■■■ 9625 -3rA ■■ - N ilii■■ ' 4. , 1111111115J111111 111111-1111111•11 Joint 20 ■■■11'1E ■■■■ 9650 1111==��■■■■ - i�� ■■_e 111111■ ■■■i-Ai■■■■ _. ...p -1 111111111111111111111 Joint 21 - ■■■E:i,/■1111■ _ Mb. • • Possible Hole 9675 . ,. .. .... .,, _.........d -.111-:. 1 ..... -.- & -- _ .. . ... .., __ 9700 E- 1 1 ------.7 Joint 22 2 . .., 1._ ... - vIE Ilr:111 1 . ' 9725 - ---,J. Joint 23 F.•=4 1 ... , . . ...., , .. _ .. , . .• ... ..., -...1. _...... ,. ,_„,,.. 9750 -...„ _ 1....I-,-:. -A ___ ., Joint 24 '-j 1 .. 9775 -111 t 4 _...,. -4I41 ..- ,. .:. 1 4 .,._ Joint 25 9800 -I ____ r_..... 411 N- --,-- I......1 9825 — -11 1 - - --- Joint 26 •— =:4111 It" ik- _.-..... _E._ . ---7-N 4 , — 9850 -L :..,,,. I _ 1 , , . ;PAO Mil 1 . Joint 27 IBI P Multiple Holes r- Kt — ... , 6.;-_-_-• r I, Illow Mr 9875 om.H. -1= -ill 7Fli ___ —, -41 ili —.I 7.— ir .- -.... Joint 28 - - - ---1 1 _ --;1- .7=. ---1 FS z= 0 • 9900 Joint 29 Et - _ 9925 - c.- EJB a i Joint 30 9950 _-a .4 rir 9975 ICmil t Joint 31 i � L I_rn 10000 -' � - or Joint 32 All CI 10025 ,;,, Joint 33 -� 10050 ,y - lf Joint 34 10075- - 10100 - 3 - Joint 35 -� �� _- -•- i IIINIMMI ., J� F a+ t+a __ 4: S • 10125 -. •1! 1 .. -sfr-----. , - ..... Joint 36 -I It- 10150 -- - Joint 37 1 ... .,. aa ..., La! •'„, — ......., . It ....., 10175 ....., 11 Joint 38 2 1 „0 10200 -i--• 1 -- - — --= Joint 39 10225 ;; 1 _...-_ , _ ... ,., • , ..1 -. •••• --•.. 111 • .. .,.,.., : 10250 1 Pil Joint 40 _ r 11. Jar 1 ,gi... 10275 _ Joint 41 7. • • Minimum I.D. I I 3.5 inches 4.5 Maximum I.D. I. 1 3.5 inches 4.5 Comments Depth Maximum Penetration Nominal I.D. 3-D Log Image Map I 1ft:300ftI i 411111111111111MIL_____' 0 % 1003.5 inches 4.5 0° 0° 90° 180° 270° 0° 1 • Correlation of Recorded Damage to Borehole Profile Pipe 1 3.5 in (-5.7'-8,840.6') Well: 1B-11 II Pipe 2 4.5 in (8,840.6'- 10,282.6') Field: Kuparuk Company: ConocoPhillips Alaska,Inc. Country: USA Survey Date: March 5,2018 . Approx.Tool Deviation ■ Approx.Borehole Profile 1 -6 50 1,566 100 3,138 150 4,715 0 LL Z 200 6,283 t fl ILI250 7,869 GLM1 GLM 2 1 8,869 'NJ 4 41 10,2 73 0 50 100 Damage Profile(%wall)/Tool Deviation (degrees) Bottom of Survey=41 • Perforations 41, PDS Report Overview Body Region Analysis Well: 1 3-1 1 Survey Date: March 5,2018 Field: Kuparuk Tool Type: UW MFC 24 No.218527 Company: ConocoPhillips Alaska,Inc. Tool Size: 1.69 inches Country: USA No. of Fingers: 24 Pipe 3.5 in. 9.2 ppf L-80 Analyst: C.Waldrop Pipe Nom.OD Weight Grade&Thread Nom.ID Top Depth Bottom Depth 3.5 in. 9.2 ppf L-80 2.992 in. -6 ft. 8,850 ft. Penetration(%wall) Damage Profile(%wall) 300on Penetration body Metal loss body 0 50 100 1 250 200 150 - — 47 100 50 0 0 to 20 to 40 to over 20% 40% 85% 85% 97 Number of joints analyzed(total=285) 285 0 0 0 • Damage Configuration(body) 147 10 8 6 197 4 2 - 247 0 Isolated General Line Other Hole/ - S 4110 PDS Report Joint Tabulation Sheet Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.2 ppf L-80 Tubing 2.992 in. 0.254 in. -6 ft. 8,850 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 1 -6 0 0.02 7 2 2.98 1.1 27 0 0.02 6 2 2.98 Pup 2 29 0 0.02 9 1 2.99 3 59 0 0.02 7 3 2.98 4 92 0 0.03 12 2 2.97 5 123 0 0.02 8 2 2.97 6 156 0 0.02 7 2 2.97 7 189 0 0.02 9 3 2.98 8 220 0 0.02 8 2 2.96 9 252 0 0.02 7 2 2.97 10 283 0 0.02 7 2 2.97 11 314 0 0.03 10 2 2.96 12 346 0 0.02 7 2 2.97 13 378 0 0.02 9 2 2.95 14 409 0 0.02 . 6 2 2.98 15 441 0 0.02 6 2 2.97 15.1 473 0 0.02 6 1 2.98 PUD 15.2 482 0 0 0 0 2.88 CAMCO DS LANDING NIPPLE 15.3 484 0 0.02 6 1 2.97 Pup 16 494 0 0.02 7 3 2.97 17 525 0 0.02 8 3 2.95 18 557 0 0.02 9 2 2.96 19 588 0 0.02 7 1 2.97 20 620 0 0.02 7 2 2.95 21 651 0 0.02 8 2 2.98 22 683 0 0.02 8 2 2.95 23 714 0 0.02 7 1 2.98 24 746 0 0.02 8 2 2.97 25 778 0 0.02 8 2 2.96 26 807 0 0.02 7 1 2.96 27 839 0 0.02 7 1 2.97 28 870 0 0.01 5 2 2.98 29 901 0 0.02 7 1 2.97 30 933 0 0.02 9 2 2.95 31 965 0 0,01 6 1 2.96 32 997 0 0.02 7 1 2.97 33 1028 0 0.02 6 1 2.98 34 1060 0 0.02 6 2 2.97 35 1091 0 0.02 7 2 2.96 36 1123 0 0.02 7 2 2.97 37 1154 0 0.02 7 2 2.97 38 1186 0 0.02 7 1 2.97 39 1218 0 0.02 8 2 2.94 40 1249 0 0.02 9 2 2,95 41 1281 0 0.02 7 1 2.96 42 1312 0 0.02 6 1 2.96 43 1344 0 0.02 9 3 2.96 44 1376 0 0,01 5 1 2.97 45 140 7 0 0.01 5 1 2.98 46 143 9 0 0.01 5 2 2.98 IPenetration Body Metal Loss Body Page 1 • • S PDS Report Joint Tabulation Sheet Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.2 ppf L-80 Tubing 2.992 in. 0.254 in. -6 ft. 8,850 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 47 1470 0 0.02 7 3 2.95 48 1502 0 0,02 7 2 2.98 49 1534 0 0.02 9 1 2.97 50 1566 0 0.02 7 1 2.97 51 1597 0 0.02 7 2 2,97 52 1628 0 0.02 7 1 2.96 53 1660 0 0.02 7 2 2.96 54 1692 0 0.01 . 5 2 2.97 55 1723 0 0.02 7 4 2.97 56 1755 0 0.02 7 3 2.97 57 1786 0 , 0.02 6 1 2.97 58 1818 0 _0.02 6 1 2.98 59 1849 0 0,02 7 3 2.97 60 1881 0 0.01 5 2 2.96 61 1913 0 0.04 15 2 2.97 Shallow Pitting. 62 1944 0 0.01 5 2 2.97 63 1976 0 0.02 6 1 2.96 64 2008 0 0.02 6 1 2.97 65 2039 0 0.02 6 3 2.95 66 2071 0 0.01 6 2 2.96 67 2102 0 0.02 7 2 2.94 68 2134 0 0.01 5 1 2.97 69 2165 0 0.01 5 1 2.96 70 2194 0 0,01 5 1 2.98 71 222 6 0 0.01 5 1 2.96 72 2257 0 0.02 7 2 2.96 73 2289 0 0.02 7 2 2.94 74 2321 0 0.01 4 1 2.95 75 2353 0 0.01 5 1 2.96 76 2384 0 0.01 4 1 2.96 77 2416 0 0.01 5 1 2.97 78 2447 0 0.02 6 2 2.97 79 2479 0 0.02 6 1 2.96 80 2511 0 0.01 5 2 2.96 81 2542 0 0.01 5 1 2.96 82 2574 0 0.01 5 1 2.95 83 2605 0 0.01 5 1 2.96 , 84 263 7 0 0.01 5 2 2.96 85 266 9 0 0.02 6 1 2.96 86 2700 0 0.02 6 2 2.95 87 2732 0 0.02 7 2 2.93 88 2763 0 0.02 7 1 2.95 89 2795 0 0.02 7 2 2.93 90 2826 0 0.02 6 1 2.96 91 285 7 0 0.02 7 1 2.96 92 288 7 0 0.02 7 3 2.93 93 2918 0 0.01 6 2 2.96 94 2950 0 0.02 6 2 2.94 95 2982 0 0.02 6 2 2.93 Lt. Deposits. 96 3013 0 0.02 9 2 2.94 IPenetration Body Metal Loss Body Page 2 • • PO PDS Report Joint Tabulation Sheet Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.2 ppf L-80 Tubing 2.992 in. 0.254 in. -6 ft. 8,850 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 97 3044 0 0.01 6 2 2.96 98 3075 0 0.02 6 1 2.96 99 3107 0 0.01 5 2.96 100 3138 0 0.01 5 2.96 101 3170 0 0.01 5 2.96 102 3 02 0 0.02 7 2.9 103 BM 0 0.01 5 1 2.96 104 • 0 0.01 6 1 2.96 105 3294 0 0.01 5 1 2.96 106 3326 0 0.02 6 1 2.95 107 3357 0 0.01 5 2 2.95 108 3389 0 0,02 6 2 2.97 109 3420 0 0.01 5 1 2.96 110 3452 0 0.02 6 3 2.96 111 348 0 0.02 9 1 2.95 112 3515 0 0.01 5 1 2.96 113 3547 0 0.02 6 3 2.94 114 3578 0 0.02 6 2 2.96 115 3609 0 0.01 5 1 2.96 116 3641 0 0.02 6 1 2.96 117 3673 0 0.01 5 1 2.96 118 3704 0 0.02 7 1 2.96 119 3736 0 0.02 6 1 2.96 120 3767 0 0.01 5 1 2.96 121 3799 0 0.01 6 1 2.95 122 3830 0 0.01 5 2 2.96 123 3862 0 0.01 5 1 2.96 124 3893 0 0.01 5 1 2.97 125 3925 0 0.01 5 1 2.96 126 3957 0 0.02 6 2 2.96 127 3988 0 0.02 7 2 2.95 128 4020 0 0.02 7 2 2.94 129 4051 0 0.03 11 2 2.93 Lt. Deposits. 130 4083 0 0.02 6 1 2.96 131 4115 0 0.01 6 1 2.96 13 4146 0 0.01 5 1 2.95 133 4178 0 0.01 5 1 2.96 134 4209 0 0.01 5 1 2.95 135 42,1 0 0.02 8 1 2.96 136 4272 0 0.01 6 1 2.96 137 4 04 0 Irrall 4 EREMOI 138 MEM 0 0.01 6 1 2.95 139 4367 0 0.02 9 6 2.96 1,0 4 9• 0 0i1 ME 2 2.93 141 4430 0 0.01 5 2 2.95 142 4462 0 0.02 7 2 2.93 Lt. De•osits. 143 44.4 0 1.02 7 2 2.9 144 4525 MI 0.01 5 2 2.•4 145 4557 0 0.02 7 2 2.93 Lt. Deposits. 146 4588 0 0.02 6 2 2.91 Lt. Deposits. IPenetration Body Metal Loss Body Page 3 • • IIII €111 OIL PDS Report Joint Tabulation Sheet Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.2 ppf L-80 Tubing 2.992 in. 0.254 in. -6 ft. 8,850 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 147 4620 0 0.02 6 3 2.94 148 4652 0 0.02 6 2 2.95 149 4683 0 0.02 6 2 2.93 i 150 4715 0 0.02 6 2 2.95 C 151 474 7 0 0.02 7 2 2.96 152 4778 0 0.02 6 2 2.95 153 4810 0 0.02 7 1 2.96 1 154 4841 0 0.02 6 2 2.95 i I 155 4872 0 0.02 6 1 2.93 Lt. Deposits. 156 4904 0 0.01 5 1 2.96 157 493 3 0 0.02 6 1 2.95 1 158 4965 0 0.02 6 3 2.95 159 4996 0 0.02 8 2 2.94 160 502 8 0 0.01 5 1 2.94 1 161 505 7 0 0.01 6 2 2.95 1 162 5089 0 0.02 6 1 2.96 B 163 5120 0 0.01 5 1 2.95 1 164 5152 0 0.01 5 1 2.95 165 5184 0 0.01 5 , 1 2.93 1 166 5215 0 0.01 6 2 2.95 M 167 5244 0 0.02 6 2 2.96 0 168 5276 0 0.01 5 2 2.95 1 169 5308 0 0.01 5 1 2.95 1 170 5339 , 0 0.01 6 1 2.95 1 171 5371 0 0.02 8 3 2.96 r 172 5402 0 0.01 4 1 2.96 173 543 3 0 0.01 6 1 2.96 1 174 5465 0 0.02 6 2 2.96 1 175 549 7 0 0.02 8 6 2.96 r 176 5528 0 0.01 6 1 2.95 177 5560 0 0.02 6 1 2.95 i 178 5589 0 0.02 6 1 2.94 1 179 5620 0 0.01 5 1 2.96 180 5652 0 0.02 6 3 2.94 i 181 5683 0 0.02 6 2 2.96 182 5715 0 0.02 6 2 2.95 1 183 5747 0 0.02 7 1 2.94 a 184 5778 0 0.01 5 1 2.95 i 185 5810 0 0.01 5 2 2.95 186 5841 0 0.01 5 1 2.93 1 187 5873 0 0.02 6 1 2.95 i 188 5904 0 0.01 5 2 2.94 1 189 5936 0 0.02 6 2 2.92 Lt. Deposits. 190 5967 0 0.01 6 2 2.92 Lt. Deposits. 1 191 5999 0 0.01 5 1 2.95 1 192 6030 0 0.02 6 2 2.96 1 193 6062 0 0.02 6 1 2.93 i 194 6094 0 0.02 6 1 2.95 II 195 612 5 0 0.02 7 2 2.95 2 196 615 6 0 0.02 6 2 2.94 i IPenetration Body Metal Loss Body Page 4 • • PDS Report Joint Tabulation Sheet Well: 113-11 Survey Date: March 5,2018 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.2 ppf L-80 Tubing 2.992 in. 0.254 in. -6 ft. 8,850 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 197 6188 0 0.02 6 1 2.95 198 6219 0 0.02 9 6 2.95 199 6251 0 0.02 7 2 2.95 200 6283 0 0.01 6 2 2.95 201 6314 0 0.01 5 1 2.95 202 6346 0 0.02 7 2 2.94 203 6377 0 0.02 , 6 2 2.95 204 6409 0 0.02 . 7 2 2.95 205 6441 0 0.02 8 2 2.94 206 6472 0 0.02 6 1 2,95 207 6504 0 0.02 7 3 2.95 208 653 5 0 0.03 11 7 2.93 209 6567 0 0.02 6 2 2.94 210 6598 0 0.02 7 2 2.93 Lt. Deposits. 211 6630 0 0.02 7 1 2.93 Lt. Deposits. 212 6661 0 0.01 5 1 2.95 213 6693 0 0.01 5 1 2.95 214 6725 0 0.02 6 2 2.96 215 6770 0 0,02 7 2 2.95 216 6802 0.04 0.02 9 5 2.95 217 683 3 0 0.02 8 2 2.93 Lt. Deposits. 218 6865 0 0.02 7 2 2.95 219 689 7 0 0.02 6 2 2.95 220 6929 0 0.02 6 2 2.95 221 6960 0 0.02 7 4 2.94 222 6992 0 0.01 5 2 2.94 223 7023 0 0.02 6 2 2.94 224 7055 0 0.01 6 1 2.96 225 7086 0 0.02 7 1 2.94 226 7118 0 0.02 9 2 2.93 Lt. Deposits. 227 7150 0 0.02 7 2 2,94 228 7181 0 0.01 5 2 2.95 229 7209 0 0.01 5 2 2.95 230 7241 0 0.02 6 2 2.95 231 7272 0 0.01 6 1 2.94 232 7304 0 0.01 6 2 2.95 233 7336 0 0.02 8 2 2.92 Lt. Deposits. 234 7367 0 0.02 8 2 2.91 Lt. Deposits. 235 7396 0 0.02 9 2 2.93 Lt. Deposits. 236 7428 0 0.02 6 2 2.93 Lt. Deposits. 237 7460 0 0.02 7 4 2.94 238 7491 0 0.01 5 1 2.94 239 7523 0 0.02 6 2 2.95 240 7554 0 0.02 7 2 2.94 241 7586 0 0.02 8 1 2.95 242 761 7 0 0.02 7 3 2.92 Lt. Deposits. 243 7648 0 0.02 7 1 2.94 244 7680 0 0.02 7 1 2.94 245 7712 0 0.02 8 1 2.93 246 7743 0 0.03 11 2 2,93 Lt. Deposits. IPenetration Body Metal Loss Body Page 5 410 • ilb PDS Report Joint Tabulation Sheet Well: 18-11 Survey Date: March 5,2018 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.2 ppf L-80 Tubing 2.992 in. 0.254 in. -6 ft. 8,850 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 247 7775 0 _ 0.01 5 2 2.94 248 7805 0 0.02 7 2 2.94 249 783 7 0 0.01 5 2 2.95 250 7869 , 0 0.02 6 1 2.95 251 7900 0 0.02 8 6 2.95 252 7931 0 0.02 7 1 2.94 253 7963 0 0,02 7 2 2.92 Lt. Deposits. 254 7995 0 0.02 7 1 2.93 255 802 7 0 0.02 6 2 2.94 256 8056 0 0.02 7 2 2.94 257 8087 0 0.01 5 2 2.94 258 8119 0 0.02 8 2 2.91 Lt. Deposits. 259 8151 0 0.01 6 2 2.92 Lt. Deposits. 260 8183 0 0,02 7 2 2.92 Lt. Deposits. 261 8212 0 0.02 6 2 2.93 262 8243 0 0.02 7 4 2.94 263 8275 0 0.02 6 1 2.95 264 8307 0 0.02 6 1 2.94 265 8339 0 0.02 6 1 2.93 Lt. Deposits. 266 8371 0 0.01 5 2 .2.95 267 8402 0 0,01 5 1 2.94 268 8432 0 0.01 5 1 2.94 269 8463 0 0.02 6 1 2.93 270 8495 0 0.02 9 3 2.92 Lt. Deposits. 271 8526 0 0.02 7 3 2.93 Lt. Deposits. 272 8558 0 0.02 7 2 2.92 Lt. Deposits. 273 8590 0 0,02 6 1 2.93 Lt. Deposits. 274 8618 0 0.03 10 2 2.93 275 8650 0 0.02 6 1 2.94 276 8681 0 0.01 5 2 2.95 277 8713 0 0.02 6 2 2.93 Lt. Deposits. 278 8744 0 0.02 6 1 2.93 Lt. Deposits. 278.1 8775 0 0.02 6 4 2.93 Pup 278.2 8785 0 0 0 0 2.87 GLM 1 (LATCH 0) 2:00) 278.3 8792 0 0.02 6 2 2.95 Pup 279 8802 0 0.02 7 2 2.94 279.1 8834 0 0.01 6 1 2.95 Pup 279.2 8839 0 0 0 0 2.88 3.5"X 4.5"CROSS-OVER IPenetration Body Metal loss Body Page 6 • • Minimum Diameter Profile Well: 18-11 Survey Date: March 5,2018 Field: Kuparuk Tool Type: UW MFC 24 No.218527 Company: ConocoPhillips Alaska,Inc. Tool Size: 1.69 inches Country: USA Tubing I.D.: 3.958 inches Minimum Measured Diameters(in.) 1.75 2 2.5 3 3.5 0.1 - 8,841 1.2 — 8,918 23 19,009 2.8 9,038 4 in 9,092 7 1E_ 9,201 i -- E — C Z 11 _ 9,349 O. C — « CI 16 -- 9,502 E 21 __ 9,656 26 -- 9,813 1 C- 31 -- 9,966 36 10,118 41 r. 10,273 • • PDS Report Overview IRS. Body Region Analysis Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Tool Type: UW MFC 24 No.218527 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 inches Country: USA No. of Fingers: 24 Pipe 4.5 in. 12.6 ppf J-55 Analyst: C.Waldrop Pipe Nom.OD Weight Grade&Thread Nom.ID Top Depth Bottom Depth 4.5 in. 12.6 ppf J-55 3.958 in. 8,841 ft. 10,283 ft. Penetration(%wall) Damage Profile(%wall) 40 Now Penetration body Imo Metal loss body 0 50 100 0,1 mo NomI 30 NNW -,1111 1 GLM 2 (6:00) • mom 2.3 �m MINIIIMMIIIIIIIII 20 —_ - MI IM 10 4 MON inn INJ 3 (8:30) 0 INJ 4(5:00) ,s_� 0 to 20 to 40 to over 20% 40% 85% 85% 11 Number of joints analyzed(total=49) ,••••••••• 4 7 30 6 Damage Configuration(body) IMO Ali Mt .a 30 21 20 .. ANA 31 MIMI 10 IIINIFIN M 0 • Isolated General Line Other Hole/ a i Pitting Corrosion Corrosion Damage Pos.Hole no 41 j Number of joints damaged(total=43) 3 25 9 0 6 Bottom of Survey=41 = Perforations III III CUPS PDS Report Joint Tabulation Sheet Well: 18-11 Survey Date: March 5,2018 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 4.5 in. 12.6 ppf J-55 Tubing 3.958 in. 0.271 in. 8,841 ft. 10,283 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 0.1 8841 0.05 0.06 21 16 3.85 Pup Isolated Pitting. Lt.Deposits. 0.2 8845 0 0 0 0 3.82 Baker 190-47 Seal Assembly ' 0.3 8861 0 0 0 0 3.87 Baker Seal Bore Extension 1 886 9 0 0.03 10 1 3.90 1.1 8909 0 0,01 5 1 3.90 Pup 1.2 8918 0 0 0 0 3.83 GLM 2(Latch @ 6:00) 1.3 8925 0 0.03 12 3 3.68 Pup Deposits. ■ 2 893 6 0 0.04 14 2 3.90 I 2.1 8976 0 0 0 0 3.85 Baker 190-47 Seal Assembly 2.2 9005 0 0 0 0 3.95 FH Hydrostatic Packer 2.3 9009 0.07 0.09 35 10 3.87 Pup Corrosion.Lt Deposits. mg 2.4 9015 0.07 0.09 31 8 3.96 Pup Corrosion. III 2.5 9021 0.07 0.10 38 10 3.98 Pup Corrosion. I. 2.6 9030 0.06 0.07 27 7 3.91 Pup Corrosion. �' 2.7 9037 0 0 0 0 2.21 HES X Nipple 2.8 9038 0.09 0.08 30 7 3.96 Pup Line Corrosion. III 9042 0 0 0 0 3.97 Baker Overshot 3.1 9048 0.18 0.18 65 11 3.88 Pup Corrosion.Lt Deposits. '" 3.2 9065 0 0 0 0 3.97 Baker PBR 3.3 9080 0 0 0 0 3.79 Baker FHL Retrievable Packer 4 9092 0.09 0,13 48 13 3,94 Corrosion. sill 9132 0 0 0 0 3.73 Camco DB No Go Nipple 5 9133 0.14 0.20 73 23 3.81 Corrosion.Lt. Deposits. 5.1 9163 0 0 0 0 3.66 Infection Mandrel 3 (Latch @ 830) iii 6 9171 0.13 0.35 100 20 3.77 Multiple Holes! Lt. Deposits. 7 9201 0.13 0.18 68 14 3,84 Corrosion.Lt. Deposits. 7.1 9245 0 0 0 0 3.54 Iniection Mandrel 4 (Latch @ 5:00) dill 8 9253 0.07 0.12 44 8 3.54 Corrosion.Deposits. tum 9 9287 0.14 0.14 52 11 3.77 Isolated Pitting. Lt.Deposits. lomm 10 9320 0.12 0.35 100 7 3.81 Hole!Lt. Deposits. tum 11 9349 0.06 . 0.17 61 11 3,81 Corrosion.Lt. Deposits. -min 12 9379 0.08 0.12 44 9 3.84 Corrosion.Lt. Deposits. gum 13 9410 0.09 0.22 80 10 3.84 Corrosion.Lt. Deposits. -sm 14 9441 0.08 0.11 42 9 3.83 Corrosion.Lt. Deposits. amen 15 9472 0,05 0,24 , 89 4 3.76 Possible Hole!Lt. Deposits. mum 16 9502 0.06 0.12 46 7 3.78 Corrosion.Lt. Deposits. NE 17 9534 0.05 0.22 80 8 3.83 Corrosion.Lt. Deposits, ice" 18 9566 0 0.29 100 11 3.84 Hole!Lt. Deposits. ■' 19 9595 0.09 . 0.13 48 15 3.77 Corrosion.Lt. Deposits. •tim" 20 9626 0.05 0.11 41 8 3.70 Corrosion.Deposits. r: AI 21 9656 0.08 0.26 94 8 3.80 Possible Hole!Lt Deposits. i� 22 9687 0.10 0.15 54 7 3.76 Corrosion.Lt. Deposits. 11.` 23 9719 0.11 01 54 7 3.71 Corrosion.De.osit . IN 24 9749 0.04 0.13 46 8 3.79 Corrosion.Lt. Deposits. ow 25 9781 0 0.1 43 5 .76 Line of Pits Lt.De..sits. um 26 9813 0.09 0.14 50 5 3.77 Slight Bend. Corrosion. Lt.Deposits. am 27 9843 0.07 0.36 100 13 3.88 Multiple Holes! Lt. Deposits. ■'" 28 9873 0.05 0.12 45 5 3.77 Line of Pits. Lt.Deposits. mom 29 9905 0.07 0.15 56 7 3.81 Isolated Pitting. Lt.Deposits. mom 30 9937 0.07 0.14 52 8 3.69 Corrosion.Deposits. Penetration Body Metal Loss Body Page 1 i i PDS Report Joint Tabulation Sheet Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 4.5 in. 12.6 ppf J-55 Tubing 3.958 in. 0.271 in. 8,841 ft. 10,283 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 31 9966 0.04 0.15 56 7 3.78 Corrosion.Lt. Deposits. 32 9997 0.05 0.12 44 6 3.85 Corrosion.Lt. Deposits. '"U 33 10028 0.08 0.20 73 4 3.61 Corrosion,Deposits. MIMI" 34 10058 0.05 0.23 86 13 3.62 Perforations Deposits. ■ om 35 10086 0.06 0.13 48 6 , 3.81 Perforations Lt.Deposits. riven 36 10118 0 0.14 52 5 3.86 Line Corrosion. Lt.Deposits. num 37 10149 0 0.11 41 4 3.82 Line of Pits. Lt.Deposits. 11=1111 38 10179 0.09 0.22 82 7 3.80 Line of Pits. Lt.Deposits. mum. 39 10209 0.05 0.14 50 7 3.88 Line of Pits. Lt.Deposits. erre 40 10241 0 0.08 31 4 3.84 Line of Pits. Lt.Deposits. .ter•, 41 10273 0 0.15 56 5 3.24 Line Corrosion. Heavy Deposits. I Penetration Perforations Body Metal Loss Perforations 'Penetration Metal Loss Body Page 2 • • PDS Report Cross Sections Well: 1 B-1 1 Survey Date: March 5,2018 Field: Kuparuk Tool Type: UW MFC 24 No.218527 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 4.5 in. 12.6 ppf J-55 Analyst: C.Waldrop Cross Section for Joint 27 at depth 9,846.541 ft. Tool speed=49 Nominal ID=3.958 .5, Nominal OD=4.5 Remaining wall area=87% Tool deviation=56° Z . \ i' Ns Finger=5 Penetration=0.359 in. Multiple Holes 0.36 in.= 100%Wall Penetration HIGH SIDE= UP • • PDS Report Cross Sections Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Tool Type: UW MFC 24 No.218527 Company: ConocoPhillips Alaska,Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 4.5 in. 12.6 ppf J-55 Analyst: C.Waldrop Cross Section for Joint 6 at depth 9,196.321 ft. Tool speed=50 Nominal ID=3.958 Nominal OD=4.5 Remaining wall area=80% Tool deviation=55° 1 Finger= 10 Penetration=0.352 in. Multiple Holes 0.35 in.= 100%Wall Penetration HIGH SIDE=UP • • 11-414S,, PDS Report Cross Sections Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Tool Type: UW MFC 24 No.218527 Company: ConocoPhillips Alaska,Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubin:: 4.5 in. 12.6 ..f J-55 Anal st: C.Waldro. Cross Section for Joint 5 at depth 9,137.431 ft. Tool speed=50 Nominal ID=3.958 Nominal OD=4.5 / Remaining wall area=77% Tool deviation=56° , ..... / \ / 1 \ il \ / —v `` Finger= 11 Penetration=0.153 in. Corrosion 23%Cross-Sectional Wall Loss HIGH SIDE=UP • • PDS Report Cross Sections IPS. Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Tool Type: UW MFC 24 No.218527 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 4.5 in. 12.6 ppf J-55 Analyst: C.Waldrop Cross Section for Joint 6 at depth 9,196.311 ft. Tool speed= 50 Nominal ID=3.958 Nominal OD=4.5 Remaining wall area=80% Tool deviation=55° 1 I Finger= 10 Penetration=0.352 in. Multiple Holes 20%Cross-Sectional Wall Loss HIGH SIDE=UP • • PDS Report Cross Sections Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Tool Type: UW MFC 24 No.218527 Company: ConocoPhillips Alaska,Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 4.5 in. 12.6 ppf J-55 Analyst: C.Waldrop Cross Section for Joint 41 at depth 10,281.291 ft. Tool speed=37 Nominal ID=3.958 Nominal OD=4.5 � Remaining wall area=96% >' Tool deviation=64° I 1 / Minimum I.D.=3.245 in. Heavy Deposits Minimum I.D.=3.25 in. HIGH SIDE=UP • 110 PDS Report Cross Sections Well: 1B-11 Survey Date: March 5,2018 Field: Kuparuk Tool Type: UW MFC 24 No.218527 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 4.5 in. 12.6 ppf J-55 Analyst: C.Waldrop Cross Section for Joint 8 at depth 9,256.591 Tool speed= 51 Nominal ID=3.958 Nominal OD=4.5 Remaining wall area= 100% Tool deviation=54° 1 �\ i N Minimum I.D.=3.542 in. Deposits Minimum I.D.=3.54 in. HIGH SIDE=UP r.' KUP INJ 1B-11 Conocoi hi lipst ,Well Attributes 0 Max Angle&MD TD Alaska,Inc. Wellbore AP W WI Field Name Wellbore Status ncl(°) MD(RKB) Act Bim MKS) cortOcoPlvMps 500292065700 KUPARUK RIVER UNIT INJ 64.58 10,600.00 10,723.0 °°° Comment H2S(ppm) Date Annotation End Date KBGrd(ft) Rig Release Date 18-11.1/3/2018 3.1898 PM SSSV:NIPPLE Last WO: 2/9/2017 27.50 1/20/1982 Vertical schematic(actual) Annotation Depth(RKB) End Date Annotation Last Mod By End Date HANGER:20.9-g)_,. > • Last Tag:RKB 1/14/2017 Rev Reason:TAG,PULL&SET INJ VLV pproven 1/3/2018 Casing Strings • Casing Description OD(In) ID On) Top(ftKe) Set Depth(91(13) Set Depth(TVD)...WtlLen(1...Grade Top Thread •^ - CONDUCTOR 20 18.936 29.6 80.0 80.0 91,50 H.40 WELDED ........_..........................................._.._..................... '.......................Casing Description OD(in) ID(In) Top MKS) Set Depth(RKB) Set Depth(TVD)...WBLen(I...Grade Top Thread ---------------•----------• ...- .-.•SURFACE 133/8 12.415 29.6 2614.6 2,242.0 72.00 N-80 BTC ir Casing Description OD(In) ID(in) Top(RKB) Set Depth(888(8) Set Depth(TVD)...WttLen(I...Grade Top Thread PROD Tie back 2017 WO 95/8 8.835 28.3 706.9 705.6 40.00 L-80 Tenaris Wedge 563 Casing Description OD(In) ID(in) Top(RKB) Set Depth(88KB) Set Depth(TVD)...Wt1Len(1...Grade Top Thread I PROD POST 2017 WO 95/8 8.681 704.8 9,572.4 6,375.9 47.00 L-80 BTC CONDUCTOR;29.8-80.0' Casing Description OD(In) ID(in) Top(68(8) Set Depth(RKB) Set Depth(TVD)... WULen(1...Grade Top Thread LINER 7 6.276 9,260.4 10.698.0 6,930.3 26.00 K-55 BUTT Liner Details Nominal ID I Top(RKB) Top(TVD)(RKB) Top Incl(°) Item Des Com (In) 9,260.4 6,206.0 57.37 SLEEVE BAKER SETTING SLEEVE 6,151 NIPPLE:508.4 $F 9,266.5 6,209.3 57.35 NIPPLE BAKER SEAL NIPPLE 6.151 VALVE:506.0 9,269.8 6,211.1 57.34 HANGER BAKER MC HYD HANGER 6.151 • 9.282.1 6.217.7 57.31 XO BUSHING BAKER CROSS-OVER BUSHING 6.151 Tubing Strings PROD Tie beck 2017 w0;28.3- Tubing Description String Ma...ID(In) Top(RKB) Set Depth(ft..Set Depth MT)).-WI(Iblrt) Grade Top Connection Toes TUBING-2017 WO 3 1/2 2.942 20.9 8,848.0 5,985.1 9.20 L-80 Tenaris Wedge 563 SURFACE;29.8-2.614.13--,18 4. Completion Details Nominal ID Top(ttKB) Top(TVD)(RKB) Top Incl(°), Item Des Com (In) 20.9 20.8 0.11 HANGER FMC-TC-1 EMS 131/2"x41/2"IBT TUBING HANGER 4.000 GAS UFT',82723 21.6 21.6 0.11 XO Reducing 4 1/2"x IBT-M PIN UP X 3 1/2"9.38,1-80,TSH 563 X 2.992 OVER 508.4 508.4 1.54 NIPPLE CAMCO 2.875"DS LANDING NIPPLE 2.875 II 8,826.7 5,973.6 57.55 XO Enlarging "3 1/2"9.3,L80,1'SH 563 X 4 1/2-12.66,180,TSH 563 2.950 LOCATOR,8,028.2 X-OVER` XO Reducing(Tubing)',8.829.81 8,828.2 5,974.4 57.55 LOCATOR GBH 22 Locator Sub 3.880 SEAL ASSY:8.828 8 SBE;8,631 3 ' a!1 8,828.6 5,974.7 57.55 SEAL ASSY Baker 190-47 Seal Assembly 3.880 XO Reducing(Tubings:8.850.8 Tubing Description String Ma...ID(In) Top(88KB) Set Depth(It...Set Depth(TVD)1...Wt 118W) Diode Top Connection -- LINER-Inner Casing 7 6.276 26.0 8,994.0 6,063.3 26.00 L-80 TXP WO2017 GAS UFT 8.9073 t•I Completion Details Nominal ID Top(RKB) Top(TVD)(ttKB) Top Incl(°) Item Des Corn (1721 8,831.3 5,976.1 57.56 1726E Baker Seal Bore Extension with 4.75"ID 4.750 8,974.5 6,052.8 57.59 LOCATOR GBH 22 Locator Sub*2 ft space out 3.800 LOCATOR';8974.5, SEAL ASSY.8.976 5 8,976.5 6,053.9 57.59 SEAL ASSY Baker 190-47 Seal Assembly 3.870 PBR',8.978.2, 1. I Tubing Deeonption String Me...ID(In) Top(RKB) Set Depth(R..Set Depth(TVD)(...Wt(lblrt) Grade Top Connection TUBING W/O-2003 I 8.31 3.8751 8,976.21 9,038.7 6,087.21 PACKER,9.009.4 •- Completion Details i Nominal 10 NIPPLE:9,024.0- i To RKB To TVD RKB T 1006 Item Des Com NIPPLE REDUCER;9026.0 p( ) p( )( ) (°) (In) 8,976.2 6,053.7 57.59 PBR BAKER PBR SIZE 190-47 3.875 OVERSHOT:9,030.9 9,009.4 6,071.5 07.59-PACKER FH HYDROSTATIC PACKER 3.990 ry „,1 9,024.0 6,079.3 57,61 NIPPLE HESXNIPPLE 3.813 PBR:9.065.1 9,030.8 6,083.0 57.63 OVERSHOT BAKER 8'OVERSHOT(SWALLOW 7'),Top of original - 4.625 tubing 7037' PACKER:9084.1 - - Tubing Description String Ma...ID(in) Top(RKB) Sel Depth(ft..Set Depth(TVD)(...WI(1b/ft) Grade Top Connection TUBING Original 4 1/2 3.958 9,037.1 10.315.6 6,760.2 12.60 J-55 Buttress NIPPLE.9,132,0 Completion Details r Nominal ID INJECTION,9,161.2 * To (RKB) Top(TVD)(ftK8) Top Incl(°) Rem Des Com (in) pa 9,065.1 6,101.3 57.70 PBR BAKER PBR 3.920 INJECTION:9.244.9 • 9,084.1 6,111.5 57.73 PACKER BAKER'PHL'RETRIEVABLE PACKER 3.920 9,132.0 6,137.0 57,69 NIPPLE CAMCO DB NO GO NIPPLE 3.750 10,303.2 6,754.3 61.76 XO CROSSOVER 4.5x3.5" 3.500 'i; 'F' •REDUCING 10,303.8 6,754.6 61.76 LOCATOR BAKER LOCATOR 2.992 10,304.3 6,754.9 61.77 SEAL ASSY BAKER SEAL ASSEMBLY 2.992 10,307.2 6,756.2 61.80 SBE SEAL BORE EXTENSION 2.992 PROD POST 2017 WO;704,9- Tubing Description (String Ma...IID(In) ,Top(RKB) ,Set D173118(50:5.1 Set Depth Fra1...IWt(Ib/Ill Grade ,Top Connection 8.572.4 TUBING Original 3M13/2110 12 2.992 10.307.1 6,792.6 9.30 J-55 Buttress APERF;9,830.0-9.920.0 Completion Details Nominal ID APERF;10,066.0-10.106.0 Top(11110) Top(TVD)(RKB) Top!milt) Item Des Com (In) 10.307.1 6,756.2 61.80 PACKER BAKER'FB-1'PACKER 4.000 10,309.6 6,757.4 61.83 SBE BAKER SEAL BORE EXTENSION 4.000 LOCATOR;10,303.9- 10,354.3 6,778.3 62.38 NIPPLE -CAMCO'D'NIPPLE 2.750 SEAL ASSY;10,304.3, PACKER,10.307.20, Lil . 10,384.5 6,792.2 62.74 SOS BAKER BULL NOSE SHEAR TOOL 2.992 SSE,10.307.2 .. n VS SBE:10309.6 Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) Top(TVD) Top Incl NIPPLE:10354.3 Top(SKS) (868) (°) Des Com Run Date ID(In) a 508.0' 508.0 1.52 VALVE -3 1/2"A-1 INJ VALVE 0E86 001,48"OAL,1" 12/25/2017 1.000 sos:10.384.3 BEAN)ON 2.875'CS LOCK RPERF:10,401.0-10,A15.0 9,024.0 6,079.3 57.61 NIPPLE 3.81"X-LOCK ON 2.31`DS NIP REDUCER(3'-5') 1/22/2017 2.310 REDUCER W/BWLL GUIDE ENTRY ON BOTTOM RPERF;10,431.0-10,489.0 . 4 LINER;9,200410,696.0 4 KUP INJ • 1B-11 ConocoPhillipsoi, Alaska,Inc ,rsmciweatpe ••• ii 10-11,17320183,18:12 PM i Vertical schematic iactueS .........HANGER;209— II:,.:•-s.... IfPerforations&slots Steel .,..: ..,.. . ,._..� Dens .... ....... ..,.... _..... Top(TVD) Btm(TVD) (shoteH _ Top(ftKB) 810,(1168) MKS) (1168) Zone Date t) Type Com fl 9,830.0 9,920.0 6,514.1 6,562.1 C-4,C-3,1B- 4/24/1982 4.0 APERF I 11 10,066.0 10,106.0 6,638.0 6,658.3 C-1,UNIT E, 11/16/1990 4.0 APERF 25/8 Jumbo Jet:180 1B-11 deg.Perforated tubing! Can't Isolate MA-CONDUCTOR,29.6-800• 10,401.0 10,415.0 6,799.7 6,806.1 Miluveach,1B 4/20/1982 4.0 RPERF 4'HYPERJET II -11 10,431.0 10,489.0 6,813.3 6,839.5 MIluveach,16 4/20/1982 4.0 RPERF 4"HYPERJET II -11 NIPPLE;508 Mandrel Inserts VALVE',508.0 } St atl _. on Top(TVD) Valve Latch Pon 8100 TRO Run N Top(ttK8) (KKB) Make Model OD(In) Sery Type Type (In) (psi) Run Date Com 1 8,772.6 5,944.6 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 2/14/2017 2 8,907.3 6,016.8 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 2/15/2017 PROD Tie Cock 2017 WO.283- 708.9 3 9,161.2 6,152.7 CAMCO 4.5x3.5 11/2 INJ CV 0.703 0.0 12/23/1982'8:00 4 9,244.9 6,197.6 CAMCO 4.5x3.5 11/2 (NJ CV 0.703 0.0 12/23/1992 5:00 SURFACE',29.6-2,614.6—.. / .. Notes:General&Safety End Date Annotation II 2/5/2003 NOTE:WO GAS LIFT,0.7726 8/9/2010 NOTE:View Schematic w/Alaska Schematic9.0REV 111 lir3/13/2012 NOTE:WAIVERED WELL OA x OOA 0121/20(7 ROTC:Leak In 13-3/8"surface casing at-712'due to Inadvertent cut during 2017 RWO LOCATOR;8,826.2 1M XO Reducing(Tubing);8.829.8 1 SEAL ASSY;8.828.6 r F. OBE;8,831,3 ' XO Reducing(Tubing):8,850 6 ,!,. GAS LIFT;8.907.3 LOCATOR;8,974.51 SEAL ASSY:6,978 5 PER.8.978.2, a PACKER.9.009.4 _ NIPPLE;9,024.0— a!a NIPPLE REDUCER;8.0240 a OVERSHOT;9,030.8 jljXj I PRR'90651 s 3' PACKER.9,084.1 -" NIPPLE;9,1320 M - P mil INJECTION,0161.2 K- il INJECTION,9,244.9 1" I PROD POST 2017 WO,704 9- 9,572.4 APERF:9,830 0-9,920 0.-APER F, 0APERF,10,066.0-10,106.0 LOCATOR'10303.9 j SEAL ASSY;10,304 3-. 1 1 PACKER;10307.2� SBE;10,307 2, SBE 10,309 6 , a I NIPPLE;10,354.3 111 SOS.10.304.5 if RPERF;10.401.0-10,415.0 ` RPERF;10,431 0-10,489.0 1 p • LINER,9,260.4-10.698.0 • • Wallace, Chris D (DOA) From: NSK Well Integrity Supv CPF1 and 2 <n1617@conocophillips.com> Sent: Tuesday,January 30, 2018 6:26 PM To: Wallace, Chris D (DOA) Cc: Senden, R.Tyler Subject: RE: KRU 1B-11 (PTD 181-136) Report of suspect OA pressure increase update 1-30-18 Attachments: 1B-11 SCADA 2 week snapshot 1-30-18.JPG Chris, Passing MITIA, MITOA and IC packoff tests were performed on January 12,2018 on 1B-11. The IA pressure was bled down below the OA. However the OA continued to repressurize while the well was on gas injection. There is a section of this completion where direct TxOA communication is possible. Therefore a gas-only TxOA communication leak began to be suspected. The well was WAG'ed to water injection on January 26,2018. The OA continued to climb. But over the last several days,extended OA bleeding has occurred and the OA pressure has begun to stabilize out. The 30 day monitor period is being reset to begin when we WAG'ed the well to water injection. Incidentally,the well is due for preventative maintenance wellhead work which will require the well to be secured with a downhole tubing plug. At the conclusion of the monitor,the well will be secured and the PM work completed. At that time an MITT will be performed that will test the section of pipe that would allow the TxOA communication. Prior to returning the well to injection, a follow-up email will be provided at the conclusion of the wellhead work,once a path forward is established. Please let us know if you disagree with the plan. Attached is a 2 week SCADA snapshot highlighting the recent OA bleeds. Kelly Lyons/Jan Byrne Well Integrity Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907)659-7224 SCANf From: NSK Well Integrity Supv CPF1 and 2 S- t:Thursday,January 11, 2018 4:55 PM To: . .ce,Chris D (DOA)<chris.wallace@alaska.gov> Cc:Senden, ,. ler<R.Tyler.Senden@conocophillips.com>; NSK Well Integrity Supv CPF1 and 2 <n1617@conocop'• •.s.com> Subject: KRU 1B-11(PTD -136) Report of suspect OA pressure increase Chris, KRU WAG injector 1B-11(PTD 181-136)was reporte• • Operations for exhibiting an unexplained OA pressure increase. The OA pressure was bleed down to^'700 psi an. • aerations intends to bleed the IA pressure to^'800 psi to maintain the OA pressure below the 1000 psi DNE throughout the :ht. The plan is for DHD to perform initial diagnostics in the morning to include; MIT-IA, MIT-OA, pack off, and dra, down tests. If the well passes diagnostic testing it will be put on a 30 day monitor period. If an MIT fails the well will hut in and freeze protected until a plan forward has been determined. Attached is a wellbore schematic and 90 day TIO tr- •. Please let us know if you disagree or have any questions with this plan. Regards, 1 • • Wallace, Chris D (DOA) From: NSK Well Integrity Supv CPF1 and 2 <n1617@conocophillips.com> Sent: Thursday,January 11, 2018 4:55 PM To: Wallace, Chris D (DOA) Cc: Senden, R.Tyler; NSK Well Integrity Supv CPF1 and 2 Subject: KRU 1B-11 (PTD 181-136) Report of suspect OA pressure increase Attachments: 1 B-01.pdf; 1B-11 90 day TIO trend 1-11-18.JPG Chris, KRU WAG injector 1B-11(PTD 181-136) was reported by Operations for exhibiting an unexplained OA pressure increase. The OA pressure was bleed down to—700 psi and Operations intends to bleed the IA pressure to—800 psi to maintain the OA pressure below the 1000 psi DNE throughout the night. The plan is for DHD to perform initial diagnostics in the morning to include; MIT-IA, MIT-OA, pack off, and draw down tests. If the well passes diagnostic testing it will be put on a 30 day monitor period. If an MIT fails the well will'be shut in and freeze protected until a plan forward has been determined. Attached is a wellbore schematic and 90 day TIO trend. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne/Kelly Lyons Well Integrity Supervisor ConocoPhillips Alaska, Inc. Office phone: (907)659-7224 01/4WELLS TEAM SCA�ti�� • • ConocoPhillips RECEIVED Alaska P.O. BOX 100360 OCT 19 2017 ANCHORAGE,ALASKA 99510-0360 AOGCC October 15, 2017 Commissioner Hollis French Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 SCANNED DEC 4n17, Commissioner Hollis French: 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 if needed 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 attached spread sheet presents the well name,top of cement depth prior to filling and volumes used on each conductor. Please call Roger Mouser or Roger Winter at 907-659-7506, if you have any questions. Sincerely, Roger Mouser ConocoPhillips Well Integrity Field Supervisor • • • ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations(10-404) Kuparuk Field Date 10/7/2016 1B-11,1E-32, 1G-01 &1R-16 Corrosion Initial top Vol.of cement Final top of Cement top off Corrosion inhibitor/ Well Name API# PTD# of cement pumped cement date inhibitor sealant date ft bbls ft gal , 1B-11 50029206570000 181-136-0 12" NA 12" NA 3.4 10/14/2017 1 E-32 50029227880000 197-132-0 7' 0.5 8" 7/16/2017 2 9/20/2017 1G-01 50029208050000 182-130-0 14'7" 2.50 13" 7/16/2017 3.4 9/20/2017 1R-16 50029213880000 185-153-0 22" 0.25 7.5" 7/17/2017 4.2 9/10/2017 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg Wen- 5/�l/ DATE: Wednesday,May 03,2017 P.I.Supervisor I l 1 SUBJECT:Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC FROM: Lou Laubenstein lB-II Petroleum Inspector KUPARUK RIV UNIT 1B-11 Src: Inspector Reviewed By:le NON-CONFIDENTIAL P.I.Supry ,'jyi�'� — Comm Well Name KUPARUK RIV UNIT 1B-11 API Well Number 50-029-20657-00-00 Inspector Name: Lou Laubenstein Insp Num: mitLOL170423071813 Permit Number: 181-136-0 Inspection Date: 4/22/2017 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1 is-11 Type Inj G 'ITVD 5975 ' Tubing 2960 I 2977 - 2976 2983 PTD 1811360 - Type Test SPT (Test psi 3850 IA 350 4130 - 4110 - 4105 - BBL Pumped_ 3.9 -BBL Returned: 3.7 OA 46 328 - 328 ' 329- Interval REQVAR P/F P ✓ -- Notes: MITIA to MAIP per AIO 2C.044 SCANNED AUG 2 4 2017, Wednesday,May 03,2017 Page 1 of 1 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Re DATE: Wednesday,May 03,2017 P.I.Supervisor l SI 11 t C7 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC IB-11 FROM: Lou Laubenstein KUPARUK RIV UNIT IB-I1 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry.:3771— NON-CONFIDENTIAL :37'NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 1B-11 API Well Number 50-029-20657-00-00 Inspector Name: Lou Laubenstein Permit Number: 181-136-0 Inspection Date: 4/22/2017 Insp Num: mitLOL170423072115 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1B-11 —Type Inj G- TVD 5975 ' Tubing 2988 2988 2986 . 2980 • PTD 1811360 " Type Test SPT Test psi Iso0 - IA 384 855 - 872 - 885• BBL Pumped_ 3.2 ' JBBL Returned: 2.6 " OA 75 2010 ' 1985 - 1985 Interval REQVAR P/F P Notes: MITOA to 1800 per AIO 2C.044 SCANNED AUG 2 4 zor Wednesday,May 03,2017 Page 1 of 1 STATE OF ALASKA KA OIL AND GAS CONSERVATION COM SION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon E Plug Perforations Fracture Stimulate E Pull Tubing F Operations Shutdown Performed. Suspend r Perforate E Other Stimulate Alter CasingChange g Approved Program Plug for Redrill E Perforate New Pool r Repair Well F Re-enter Susp Well E Other: Replace Well Head 17 2.Operator Name: 4.Well Class Before Work: 5.Permit to Drill Number: ConocoPhillips Alaska, Inc. Development E Exploratory 181-136 3.Address: 6.API Number: P.O. Box 100360,Anchorage,Alaska 99510 Stratigraphic Service F 50-029-20657-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 25648 KRU 1B-11 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kuparuk River Field/Kuparuk River Oil Pool 11.Present Well Condition Summary: Total Depth measured 10723 feet Plugs(measured) None true vertical 6941 feet Junk(measured) None Effective Depth measured 10006 feet Packer(measured) 9009,9084, 10307 true vertical 6607 feet (true vertical) 6071,6111,6756 Casing Length Size MD TVD Burst Collapse CONDUCTOR 50 20 80 80 SURFACE 2585 13 3/8 2615 2242 PROD TIE BACK. 679 9 5/8 707 706 PROD POST 201 8867 9 5/8 9572 6376 LINER 1438 7 10698 6930 RECEIVED LINER-Inner Casing 8968 7 8994 6063 MAR 1 4 2017 Perforation depth: Measured depth: 9830-9920, 10066-10106, 10401-10415, 10431-10489 True Vertical Depth: 6514-6562,6638-6658,6798-6806,6813-6839 AOGC Tubing(size,grade,MD,and ND) 3 1/2 x 4 1/2, L-80/J-55, 10385 MD/6793 TVD Packers&SSSV(type,MD,and ND) PACKER=FH HYDROSTATIC PACKER @ 9009 MD and 6071 ND PACKER=BAKER FHL PACKER @ 9084 MD and 6111 ND PACKER=BAKER FB-1 PACKER @ 10307 MD and 6756 ND SSSV: NONE 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A DIED SPP. Ji. 22017 Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation - - 6350 410 1840 Subsequent to operation - 5500 590 1685 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations Pr.. Exploratory fl Development E Service F Stratigraphic 1-- Copies Copies of Logs and Surveys Run EJ, 16.Well Status after work: Oil r Gas E WDSPL fl Printed and Electronic Fracture Stimulation Data n GSTOR I- WINJ E WAG PGINJ E SUSP E SPLUG r 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: 317-018 Contact Daniel Kanea 265-6048 Email Daniel.Kanea,conocophillips.com Printed Name Daniel Kane Title Sr. Wells Engineer Signature Phone:265-6048 Date 1 S MDQ. 20(ri. Form 10-404 Revised 5/2015 VTC 31 R Df � iPia l7 Submit Original Only ,'/ /7 OS ,:., • 0 Operations Summary (with Timelog Depths) 1 B-11 Con000PhiIhpss Rig: DOYON 142 Job: RECOMPLETION Time Log Start Depth Start Time End Time Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB) 1/27/2017 1/28/2017 6.00 MIRU MOVE MOB P Pull all modules off 1C-172.Stage on 18:00 00:00 1C-pad,being moving to 1B-11 @ 23:00 hrs. 1/28/2017 1/28/2017 2.00 MIRU MOVE MOB P Continue to move rig from 1C-1B 00:00 02:00 pad. 1/28/2017 1/28/2017 10.00 MIRU MOVE RURD P Spot sub over well/set modules and 02:00 12:00 install inner connects/stairs. 1/28/2017 1/28/2017 2.00 MIRU WELCTL RURD P Take on KWF to pits. 580 BBLS sea 12:00 14:00 water. 1/28/2017 1/28/2017 1.00 MIRU WELCTL MPSP P Pick up lubricator to pull BPV. Tubing, 14:00 15:00 OA,OOA=0 PSI. IA at 50 PSI. RD lubricator 1/28/2017 1/28/2017 0.50 MIRU WELCTL SFTY P RWO meeting with crews. 15:00 15:30 1/28/2017 1/28/2017 1.50 MIRU WELCTL RURD P Continue to rig up kill lines. PT flow 15:30 17:00 back lines to tanks. 350 low/2,500 PSI high. 1/28/2017 1/28/2017 1.50 MIRU WELCTL KLWL P Reverse 45 BBLS of sea water to flow 17:00 18:30 back tanks to recover diesel at 3 BPM, IA 280 PSI,FCP=417. Pump 200 BBLS seawater down tubing taking returns to flow back tanks @ 5BPM. IA 540 PSI, FCP 737 PSI. Slow pumps to 2 BPM and pump additional 20 BBLS @ 106 PSI. Total BBLS pumped=265. 1/28/2017 1/28/2017 1.25 MIRU WELCTL OWFF P Monitor well for flow,Allow well to vent 18:30 19:45 to tanks while monitoring then SI looking for build up. None noted. 1/28/2017 1/28/2017 1.25 MIRU WHDBOP MPSP P Install IS-A BPV test from below to 19:45 21:00 1,000PSI. Bleed down and rig down all lines. Same time installing 9 5/8" rams in upper BOP. 1/28/2017 1/29/2017 3.00 MIRU WHDBOP NUND P ND production tree and prepare to 21:00 00:00 instal BOP. FMC working on upper LDS,with simops of mu 2 ea.2' spacer spools along with install of 5 3/4"blanking plug. 10 turns to left. Remove and lay down tree from BOP deck. 1/29/2017 1/29/2017 4.00 MIRU WHDBOP NUND P R/U BOPE stack,Riser,choke and kill 00:00 04:00 lines 1/29/2017 1/29/2017 2.00 MIRU WHDBOP RURD P R/U to test 9 5/8"test joint,R/U dart 04:00 06:00 valve and flood stack to test assembly. Re-tighten flange below BOPE stack. 1/29/2017 1/29/2017 2.50 MIRU WHDBOP BOPE P Begin BOPE test 250/3500 psi 06:00 08:30 Witness waived by Lou Grimaldi. 9 5/8"Test Annular,UPR pipe rams, kill line valve,TIW&dart valve.Choke Valves 1,2,5,7,8,9,10,11,12,14,14. Pull 9 5/8"TJ 1/29/2017 1/29/2017 2.00 MIRU WHDBOP BOPE T C/O BX 160 api ring on flange below 08:30 10:30 BOPE 1/29/2017 1/29/2017 1.50 MIRU WHDBOP BOPE P Test with 5"TJ 10:30 12:00 LPR,Annular,CV 3,4,6,HCR choke Draw down test 2616 psi,200 psi recovery in 9 secs,full recovery in 53 secs. Page 1/8 Report Printed: 2/28/2017 • Operations Summary (with Timelog Depths) 1B-11 C om;Philiips Rig: DOYON 142 Job: RECOMPLETION Time Log Start Depth Start Time End Time Our(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB) 1/29/2017 1/29/2017 2.50 MIRU WHDBOP BOPE P Install 3.5"TJ-Test LPR,annular, 12:00 14:30 HCR choke, Upper IBOP,manual choke,Lower IBOP.Remove TJ and test Blind rams.Test complete. 1/29/2017 1/29/2017 1.00 MIRU WHDBOP RURD P R/D testing equipment,B/D topdrive, 14:30 15:30 choke manifold and remove blanking plug.Clean up rig floor. 1/29/2017 1/29/2017 1.00 MIRU WHDBOP OTHR P Clean rig floor and working area. Prep 15:30 16:30 tools for POOH. 1/29/2017 1/29/2017 0.50 MIRU WHDBOP MPSP P PULL IS-A BPV. 16:30 17:00 1/29/2017 1/29/2017 0.50 COMPZN RPCOMP BHAH P Pick up,make up Baker fishing 17:00 17:30 assembly to spear tubing hanger and pull to surface. 3 1/4"shoulder type Spear with grapple and two joints of 5" DP for strait pull. 1/29/2017 1/29/2017 0.50 COMPZN RPCOMP PULL P Engage spear at 36'. set dwn 10K, 8,955.0 8,925.0 17:30 18:00 BOLDS&Pull hanger to rig floor. UP WT= 133K. 1/29/2017 1/29/2017 2.50 COMPZN RPCOMP CIRC P Rig up to pump down tubing the rig up 8,925.0 8,925.0 18:00 20:30 to reverse 250 BBL total. Rig circulation system down and prep to POOH. 1/29/2017 1/30/2017 3.50 COMPZN RPCOMP PULL P POOH with 4 1/2"12.6#production 8,925.0 5,906.0 20:30 00:00 string. from 8,955. UP WT 122K DWN 85K. 1/30/2017 1/30/2017 1.75 COMPZN RPCOMP PULL P Continue to POOH with 4 1/2" 5,906.0 5,200.0 00:00 01:45 completion 1/30/2017 1/30/2017 0.50 COMPZN RPCOMP RGRP T Power outage.Bring Gens back on 5,200.0 5,200.0 01:45 02:15 line.Service rig&Gens. 1/30/2017 1/30/2017 4.75 COMPZ1 RPCOMP PULL P Continue to POOH with 4 1/2" 5,200.0 0.0 02:15 07:00 completion.Cut joint below GLM= 14.82' 1/30/2017 1/30/2017 2.00 COMPZN RPCOMP RURD P Finish loading shed with DP,LD 0.0 0.0 07:00 09:00 tubing tongs,clean up rig floor,C/O safety valve,R/U floor handling equipment for 5"DP. 1/30/2017 1/30/2017 2.50 COMPZN RPCOMP BHAH P M/U Fishing BHA with 8-1/4"overshot, 0.0 351.0 09:00 11:30 Rat pac,accelator,jars and 9 joints of HWDP. Test Rat Pac tool in hole-2 bpm @ 1500 psi. 1/30/2017 1/30/2017 0.50 COMPZN RPCOMP PULD P Single in hole with 5"DP Shallow test 351.0 446.0 11:30 12:00 rattler tool at 446'MD. Continue to RIH with 5"DP. 1/30/2017 1/30/2017 10.75 COMPZN RPCOMP PULD P RIH picking pu singles of 5"SP.to fish 446.0 8,941.0 12:00 22:45 at 8,941'MD UP WT=222K DWN WT 153K. Kelly up to gain parameters with pumps on at 2 BPM 85 GPM 1,228PS1 UP WT 220K, DWN WT 218K, RPM 20 with rotating WT of 184K up, rotating torque- 10.5K. 1/30/2017 1/30/2017 0.50 COMPZN RPCOMP FISH P Wash down from 8,941'MD to engage 8,962.0 8,962.0 22:45 23:15 fish. TOF at 8,962'MD. PUH maintaining 15K over up wt to ease out of seal bore. PUH to top of stand 91 for effect. 1/30/2017 1/30/2017 0.25 COMPZN RPCOMP CIRC P Drop 2 5/8"dart to open circ sub sheat 8,940.0 8,940.0 23:15 23:30 out and prep for circ. Page 2/8 Report Printed: 2/28/2017 X • • at IIII Operations Summary (with Timelog Depths) 1B-11 C c P��ilrps Rig: DOYON 142 Job: RECOMPLETION Time Log Start Depth Start Time End Time Our(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB)- End Depth(ftKB) 1/30/2017 1/31/2017 0.50 COMPZN RPCOMP CIRC P Circulate BU from 8,872'MD @ 10 8,940.0 8,940.0 23:30 00:00 BPM. 420 GPM @ 580 PSI. 1/31/2017 1/31/2017 0.50 COMPZN RPCOMP CIRC P Finish circulating prior to POOH. 8,940.0 8,940.0 00:00 00:30 1/31/2017 1/31/2017 5.00 COMPZN RPCOMP TRIP P POOH with chemical cut stub and seal 8,940.0 351.0 00:30 05:30 asym. 218K up WT. 1/31/2017 1/31/2017 1.50 COMPZN RPCOMP BHAH P Laid down Fish and BHA.Cleared 351.0 0.0 05:30 07:00 Fishing tools from floor. 1/31/2017 1/31/2017 3.00 PROD1 WELLPR MPSP P Made up Baker G Plug and RIH to 0.0 1,200.0 07:00 10:00 1200'.Set Plug and confirmed set. 1/31/2017 1/31/2017 0.50 PROD1 WELLPR MPSP P Pulled to 1130'and tested plug 2,000 1,200.0 1,130.0 10:00 10:30 psi for 10 Min.Good test. 1/31/2017 1/31/2017 1.00 PROD1 WELLPR CIRC P Pulled up to 1064'and dumped 50'of 1,130.0 1,064.0 10:30 11:30 Sand on top of Plug. 1/31/2017 1/31/2017 0.25 PROD1 WELLPR MPSP P Tagged Sand @ 1,160'. 1,064.0 1,160.0 11:30 11:45 1/31/2017 1/31/2017 0.75 PROD1 WELLPR TRIP P POOH from 1,060'to Surface. 1,160.0 0.0 11:45 12:30 1/31/2017 1/31/2017 0.25 PROD1 WELLPR BHAH P Laid down Running Tool. 0.0 0.0 12:30 12:45 1/31/2017 1/31/2017 0.75 PROD1 WELLPR PRTS P Closed Blind Rams and tested 3,000 0.0 0.0 12:45 13:30 psi for 10 Min.Good test. 1/31/2017 1/31/2017 0.50 PROD1 CSGRCY BHAH P Made up Baker Multi String Casing 0.0 0.0 13:30 14:00 Cutter. 1/31/2017 1/31/2017 0.75 PROD1 CSGRCY TRIP P RIH to 705'. 0.0 705.0 14:00 14:45 1/31/2017 1/31/2017 2.00 PROD1 CSGRCY CPBO P Located coupling at 699'and 740'.Cut 705.0 712.0 14:45 16:45 casing @ 712'. 1/31/2017 1/31/2017 0.25 PROD1 CSGRCY OWFF P OWFF no flow 712.0 712.0 16:45 17:00 1/31/2017 1/31/2017 1.00 PROD1 CSGRCY CIRC P Circulated out Artic Pack @ 3 BPM 712.0 712.0 17:00 18:00 127 psi. 1/31/2017 1/31/2017 0.75 PROD1 CSGRCY TRIP P POOH from 712'to Surface. 712.0 0.0 18:00 18:45 1/31/2017 1/31/2017 0.25 PROD1 CSGRCY BHAH P Laid down Casing Cutter. 0.0 0.0 18:45 19:00 1/31/2017 2/1/2017 5.00 PROD1 CSGRCY NUND P Nippled down and set back BOP. 0.0 0.0 19:00 00:00 Attempted to pull Tubinghead.Tight. 2/1/2017 2/1/2017 1.50 PROD1 CSGRCY NUND P BOLDS-Pull up on tubing spool, 0.0 0.0 00:00 01:30 remove from BOPE stack. 2/1/2017 2/1/2017 3.00 PROD1 CSGRCY PULL P R/U 9 5/8"grapple,run thru stack, 0.0 0.0 01:30 04:30 enage casing,P/U break over 83K, pull up and remove emergency slips. Set 9 5/8"back down on itself. Release spear and pull casing pack off. 2/1/2017 2/1/2017 3.50 PROD1 CSGRCY NUND P N/U spacer spool and BOPE 0.0 0.0 04:30 08:00 2/1/2017 2/1/2017 4.00 PROD1 CSGRCY PULL P P/U BOT 9 5/8"spear,latch into 0.0 712.0 08:00 12:00 casing and begin pulling 9 5/8"casing from 712'.Connections taking from 30,000#-50,000#to break connections. 2/1/2017 2/1/2017 1.50 PROD1 CSGRCY PULL P Casing patch at surface. Have to re 712.0 0.0 12:00 13:30 configure and stick oin the mousehole to cut casing.full joint plus patch plus pup. 2/1/2017 2/1/2017 1.00 PROD1 CSGRCY BHAH P Removed Spear from Top Joint and 0.0 0.0 13:30 14:30 cleared Rig Floor. Page 3/8 Report Printed: 2/28/2017 Operations Summary (with Timelog Depths) 0 1B-11 ConocoPP illips Rig: DOYON 142 Job: RECOMPLETION Time Log Start Depth Start Time End Time Our(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB) 2/1/2017 2/1/2017 2.00 PROD1 CSGRCY NUND P Nippled down BOP. 0.0 0.0 14:30 16:30 2/1/2017 2/1/2017 4.00 PROD1 CSGRCY PULL P Remove Bolts and back out 0.0 0.0 16:30 20:30 lockdowns from Casing Spool. Made up Potato Masher.Attempted to pull Spool with out success. Puled in stages with Blocks to 60K over while pulling Max with Bridge Crane for a combined pull Estimated 95 to 100K over. No success. 2/1/2017 2/2/2017 3.50 PROD1 CSGRCY CUTP P Prep and Cut 13 3/8"casing 5"below 0.0 0.0 20:30 00:00 the wellhead. 1st cut was not low enough.Recut casing 7"below the wellhead. 2/2/2017 2/2/2017 1.25 PROD1 CSGRCY CUTP P Continue cutting 13 3/8"casing with 0.0 00:00 01:15 MS casing cutter. 2/2/2017 2/2/2017 0.75 PROD1 CSGRCY BHAH P Layed down single and Casing cutter. 01:15 02:00 2/2/2017 2/2/2017 3.00 PROD1 CSGRCY CUTP P Installed Potato Masher for lifting and 02:00 05:00 Welder cut 20"Conductor. Removed Wellhead. 2/2/2017 2/2/2017 4.50 PROD1 CSGRCY NUND P Cleaned out cellar and annulus 05:00 09:30 between casing.Prepped for Landing Ring installation. 2/2/2017 2/2/2017 8.50 PROD1 CSGRCY NUND P Made final cut on 20"conductor and 09:30 18:00 installed Landing ring on 20".Set C-21 slips on 13 3/8"Stub. 2/2/2017 2/3/2017 6.00 PROD1 CSGRCY NUND P Prepped 13 3/8"Casing Stub and 18:00 00:00 Welded on SOW Transition Nipple. 2/3/2017 2/3/2017 12.00 PROD1 CSGRCY NUND P Cooling down Welds on Wellhead to 00:00 12:00 prevent Stress Cracking.CO Service Loop while waiting. 2/3/2017 2/3/2017 4.00 PROD1 CSGRCY NUND P Cooling down Welds on Wellhead to 12:00 16:00 prevent Stress Cracking.CO Service Loop while waiting. 2/3/2017 2/3/2017 6.50 PROD1 CSGRCY NUND P PJSM-test welds with N2 to 1000 psi, 16:00 22:30 N/U Speed head.Checkled with Pad Operator and DSO lead on valve alignement.Test metal to metal seal to 1000 psi. Nipple up BOPE. 2/3/2017 2/4/2017 1.50 PROD1 CSGRCY BOPE P Picked up and set Test Plug. 22:30 00:00 Removed Test Jt and filled Stack with water.Closed Blind Rams.Tested all Breaks to 250/3500 psi on the chart. Good test. 2/4/2017 2/4/2017 2.25 PROD1 CSGRCY PRTS T Pull test plug,R/U and attempt to test 00:00 02:15 13 3/8"casing.take pressure up to 550 psi,pressure bled off pumping 1 & 2 bpm.Test all surface lines and valves-good test.re-test 13 3/8"-did not pass.Blow down lines,install wear ring 2/4/2017 2/4/2017 2.00 PROD1 CSGRCY BHAH P P/U 9 5/8"dress off assembly.BHA 500.0 02:15 04:15 #6. 2/4/2017 2/4/2017 1.50 PROD1 CSGRCY MILL P Tag stump @ 712'Dress off stump as 500.0 712.0 04:15 05:45 per BOT rep.Work down 6ft over casing and 3"dress off the top of the casing. 6 BPM,65 psi, 1-8 K TQ,P/U 78K, S/O 86K. Page 4/8 Report Printed: 2/28/2017 • • 0 Operations Summary (with Timelog Depths) 1B-11 ConocoPhii ips Rig: DOYON 142 Job: RECOMPLETION Time Log Start Depth Start Time End Time Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB) 2/4/2017 2/4/2017 2.00 PROD1 CSGRCY BHAH P TOOH and lay down BHA assembly- 712.0 0.0 05:45 07:45 inspect mills look good. 2/4/2017 2/4/2017 5.00 PROD1 CSGRCY WAIT T Wait on Test packer to arrive from 0.0 0.0 07:45 12:45 Halliburtion that had to redress tool- unexpected test.Redress cutter in case of additional run.Prep rig floor for next run. 2/4/2017 2/4/2017 2.50 PROD1 CSGRCY PRTS T P/U Halliburtoin RTTS test packer- 0.0 706.0 12:45 15:15 TIH COE @ 706'Test above to 1800 psi-good test.Could not test below packer-leaking off @ 1.5 bpm @ 300 psi. 2/4/2017 2/4/2017 1.25 PROD1 CSGRCY BHAH T TOOH and lay down test packer. 706.0 0.0 15:15 16:30 2/4/2017 2/4/2017 0.25 PROD1 CASING SFTY P PJSM-P/U and running 9 5/8"casing 0.0 0.0 16:30 16:45 2/4/2017 2/4/2017 2.25 PROD1 CASING PUTB P Ran 9 5/8"40#L-80 Hyd 563 Casing 0.0 698.0 16:45 19:00 with Baker casing patch to 698'. 2/4/2017 2/4/2017 0.75 PROD1 CASING HOSO P Make up XO and 1 Jt of 5"DP with 698.0 712.0 19:00 19:45 Topdrive UW 74K DW 68K.Engaged Stump @ 712'.Slacked off and engaged Casing Patch.Tested with 100K over pull. 2/4/2017 2/4/2017 0.75 PROD1 CASING PRTS P Tested 9 5/8"Tieback to 3000 psi for 712.0 712.0 19:45 20:30 10 Min on the chart.Good Test. 2/4/2017 2/4/2017 1.75 PROD1 CASING CUTP P Stretch casing with 65K overpull. 712.0 0.0 20:30 22:15 Broke Flange and set C-21 Casing slips with 65K on slips. 2/4/2017 2/5/2017 1.75 PROD1 CASING CUTP P Rigged up WACHS Saw and Cut 0.0 0.0 22:15 00:00 Casing. 2/5/2017 2/5/2017 0.50 PROD1 CASING CUTP P Laid down Cut Jt. 0.0 00:00 00:30 2/5/2017 2/5/2017 0.75 PROD1 CASING WWSP P Made up Packoff running tool and 00:30 01:15 Packoff on a Jt of HWDP.Set Packoff and ran in Lock Down Screws.Laid down running tool and stood back HWDP. 2/5/2017 2/5/2017 1.00 PROD1 CASING NUND P Nipple up BOP. 01:15 02:15 2/5/2017 2/5/2017 0.75 PROD1 CASING PRTS P RU pump and tested Void to 2,450 psi 02:15 03:00 for 10 Min. 2/5/2017 2/5/2017 0.50 PROD1 CASING PRTS T 'Attempted to test 9 5/8 by 13 3/8" 03:00 03:30 Annulus.Broke down @ 340 psi. Pumped in 3 Bbls. 2/5/2017 2/5/2017 2.00 PROD1 CASING BHAH P Picked up and Made up Reverse 0.0 318.0 03:30 05:30 Baskit BHA to 318'. 2/5/2017 2/5/2017 0.50 PROD1 CASING TRIP P RIH from 318'to 1,076'. 318.0 1,076.0 05:30 06:00 2/5/2017 2/5/2017 0.50 PROD1 CASING WASH P Washed down from 1,076'to 1,160' 1,076.0 1,160.0 06:00 06:30 8BPM 1675 psi.40 RPM Tq 1K.Top of sand was 1148'. 2/5/2017 2/5/2017 0.50 PROD1 CSGRCY CIRC P CBU 8 BPM 1660 psi. 1,160.0 1,160.0 06:30 07:00 2/5/2017 2/5/2017 0.50 PROD1 CASING TRIP P POOH from 1160'to 318'. 1,160.0 318.0 07:00 07:30 2/5/2017 2/5/2017 0.75 PROD1 CASING BHAH P Racked back HWDP and laid down 318.0 0.0 07:30 08:15 BHA. 2/5/2017 2/5/2017 1.00 PROD1 CASING TRIP P Made up Retriving head and RIH to 0.0 1,148.0 08:15 09:15 1,148' Page 5/8 Report Printed: 2/28/2017 • • Operations Summary (with Timelog Depths) '' 2 1B-11 C o oPhinip$ Rig: DOYON 142 Job: RECOMPLETION Time Log Start Depth Start Time End Time :Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftK6)` End Depth(ftKE) 2/5/2017 2/5/2017 0.25 PROD1 CASING WASH P Washed down to G Plug @ 1190'and 1,148.0 1,190.0 09:15 09:30 tagged with 5K. SIMOPS-pumped 80 bbls of deisel down the OA 9 5/8"X 13 3/8"-saw a pressure increase after 40 bbls away from 500 psi to 600 psi.reduce pump rate from 1.3 bpm to.9 bpm.* 2/5/2017 2/5/2017 0.50 PROD1 CASING CIRC P Pumped Hi Vis and Circulated out at 1,190.0 1,190.0 09:30 10:00 10 BPM 145 psi. 2/5/2017 2/5/2017 0.25 PROD1 CASING OWFF P Unseated G Plug and OWFF.Static. 1,190.0 1,190.0 10:00 10:15 2/5/2017 2/5/2017 0.75 PROD1 CASING TRIP P POOH from 1190'to Surface. 1,190.0 0.0 10:15 11:00 2/5/2017 2/5/2017 0.50 PROD1 CASING BHAH P Laid down G Plug and retriving head. 0.0 0.0 11:00 11:30 2/5/2017 2/5/2017 2.00 PROD1 CASING BHAH P Made up Casing Scrapper BHA. 0.0 526.0 11:30 13:30 2/5/2017 2/5/2017 5.25 PROD1 CASING TRIP P RIH with Casing Scrapper BHA from 526.0 8,955.0 13:30 18:45 526'to 8,955'. 2/5/2017 2/5/2017 0.25 PROD1 CASING WASH P Washed down to the top of PBR 8,955.0 9,012.0 18:45 19:00 8,991'and rotated mule shoe into PBR and washed to 9,012'.8 BPM 418 psi. 2/5/2017 2/5/2017 1.25 PROD1 CASING CIRC P Pumped Hi Vis and circulated out at 9,012.0 9,006.0 19:00 20:15 12 BPM 855 psi. 2/5/2017 2/5/2017 0.50 PROD1 CASING PRTS P Tested 9 5/8"casing 2500 psi for 10 9,006.0 8,953.0 20:15 20:45 Min on Chart. 2/5/2017 2/5/2017 0.25 PROD1 CASING OWFF P OWFF Static. 8,953.0 8,953.0 20:45 21:00 2/5/2017 2/6/2017 3.00 PROD1 CASING PULD P POOH laying down 5"DP from 8,953' 8,953.0 6,114.0 21:00 00:00 to 6,114'. 2/6/2017 2/6/2017 5.25 PROD1 CASING PULD P POOH laying down 5"DP from 6,114' 6,114.0 526.0 00:00 05:15 to 526'. 2/6/2017 2/6/2017 2.25 PROD1 CASING BHAH P Laid down BHA. 526.0 0.0 05:15 07:30 2/6/2017 2/6/2017 0.50 PROD1 CASING BHAH P Cleared Rig Floor. 07:30 08:00 2/6/2017 2/6/2017 0.50 PROD1 CASING BOPE P Drained Stack and pulled Wear 08:00 08:30 Bushing.Set Test Plug. 2/6/2017 2/6/2017 1.25 PROD1 CASING BOPE P Changed upper Rams to 7". 08:30 09:45 2/6/2017 2/6/2017 1.25 PROD1 CASING BOPE P Made up 7"Test Jt and tested Annular 09:45 11:00 and Upper Rams to 250/3500 5 Min on chart.Laid down Test Jt and Test Plug. 2/6/2017 2/6/2017 3.50 PROD1 CASING RURD P Arranged Casing in Pipeshed and 11:00 14:30 rigged up to run 7"Tieback Casing. 2/6/2017 2/6/2017 0.75 PROD1 CASING PUTB P Picked up Seals and 4 1/2"Lower 0.0 164.0 14:30 15:15 casing with XO to 7"TXP. 2/6/2017 2/7/2017 8.75 PROD1 CASING PUTB P Ran 7"26#L-80 TXP casing from 164' 164.0 5,609.0 15:15 00:00 to 5,609' 2/7/2017 2/7/2017 5.00 PROD1 CASING PUTB P Ran 7"26#L-80 TXP casing from 5,609.0 8,986.0 00:00 05:00 5,609'to 8,986' 2/7/2017 2/7/2017 1.25 PROD1 CASING HOSO P Stabbed in with seals and located on 8,986.0 9,007.0 05:00 06:15 PBR.No go out @ 9,007'.PU 2'out and marked Pipe. Page 6/8 Report Printed: 2/28/2017 Operations Summary (with Timelog Depths) 1B-1 l Coe,ocoPhitlms Rig: DOYON 142 Job: RECOMPLETION Time Log Start Depth Start Time - End Time Dur(hr) Phase - Op Code Activity Code Time P-T-X Operation.. (ftKB) End Depth(ftKB) 2/7/2017 2/7/2017 0.75 PROD1 CASING PRTS P Rig up and pressure test 7"casing to 9,007.0 9,007.0 06:15 07:00 2500 psi for 10 charted minutes--Good Test. Rig down crossovers and lay down joint of 5"drillpipe. Blow down top drive 2/7/2017 2/7/2017 1.25 PROD1 CASING RURD P Rig up 2 ea 10'7"pups and XO 9,007.0 9,007.0 07:00 08:15 2/7/2017 2/7/2017 1.75 PROD1 CASING CRIH P Displace well with 9.8 ppg corrosion 9,007.0 9,007.0 08:15 10:00 inhibitted brine at 4.5 bpm,30 psi 2/7/2017 2/7/2017 0.50 PROD1 CASING OWFF P Observe well for flow--dead 9,007.0 9,007.0 10:00 10:30 2/7/2017 2/7/2017 0.50 PROD1 CASING HOSO P Sting into SBE. Pick up 2'and 9,007.0 0.0 10:30 11:00 pressure test seals to 1000 psi to verify seals engaged in PBR 2/7/2017 2/7/2017 0.25 PROD1 CASING RURD P Rig down crossovers and rig up false 0.0 0.0 11:00 11:15 table and bowl 2/7/2017 2/7/2017 1.75 PROD1 CASING BHAH P Make up Baker running tool and 0.0 98.0 11:15 13:00 Model G RBP on one stand of drillpipe 2/7/2017 2/7/2017 1.00 PROD1 CASING MPSP P Set G Plug and tested 1000 psi for 10 98.0 0.0 13:00 14:00 Min. Laid down running tool. 2/7/2017 2/7/2017 0.50 PROD1 CASING OWFF P OWFF No Flow.Offline RD GBR. 14:00 14:30 2/7/2017 2/7/2017 0.50 PROD1 CASING RURD P Finish Rig sown GBR.and clear Rig 14:30 15:00 Floor. 2/7/2017 2/7/2017 1.00 PROD1 CASING NUND P Split Stack to set Casing Slips. 15:00 16:00 2/7/2017 2/7/2017 1.75 PROD1 CASING WWSP P Installed C-29 Slips with Packoff and 16:00 17:45 ran in Lockdown Screws. 2/7/2017 2/7/2017 1.50 PROD1 CASING CUTP P Rigged up WACHS Saw and cut 7" 17:45 19:15 casing.Laid down cutoff. 2/7/2017 2/7/2017 2.75 PROD1 CASING NUND P Pulled and Laid down upper Riser.Put 19:15 22:00 Stack on Rack. 2/7/2017 2/7/2017 1.00 PROD1 CASING CUTP P Dressed 7"cut.Simops changed top 22:00 23:00 rams to VBR. 2/7/2017 2/8/2017 1.00 PROD1 CASING NUND P Nippled up Tubing Head. 23:00 00:00 2/8/2017 2/8/2017 0.50 PROD1 CASING PRTS P Tested Void to 4250 psi for 10 Min. 00:00 00:30 2/8/2017 2/8/2017 1.50 PROD1 CASING NUND P Nippled up Choke and Kill Line. 00:30 02:00 Installed Riser. 2/8/2017 2/8/2017 1.25 PROD1 CASING BOPE P Set Test Plug with 3 1/2"Test Jt and 02:00 03:15 tested all breaks,Upper VBR rams, and Annular 250/3500 psi on chart. Laid down Test Plug and Jt. 2/8/2017 2/8/2017 1.25 PROD1 CASING MPSP P Made up Retriving tool and Retrived G 0.0 98.0 03:15 04:30 Plug @ 98'. 2/8/2017 2/8/2017 0.50 PROD1 CASING MPSP P Laid down G Plug and 3 Jts 4"DP. 98.0 0.0 04:30 05:00 2/8/2017 2/8/2017 1.00 COMPZN RPCOMP RURD P Rigged up to run Upper Completion. 05:00 06:00 2/8/2017 2/8/2017 10.75 COMPZN RPCOMP RCST P Made up and ran 3 1/2"9.3#L80 TSH 0.0 8,824.0 06:00 16:45 563 Tubing and Jewelery per Detail from surface to 8,824'. 2/8/2017 2/8/2017 0.75 COMPZN RPCOMP HOSO P Made up Circulating Head.Pumping 2 8,824.0 8,860.0 16:45 17:30 BPM @ 65 PSI. Noted Presure increase at 8,840'turned off pump, opened bleder and Located in PBR. Seals @ 8,860'set down 10K. Page 7/8 Report Printed: 2/28/2017 `' Operations Summary (with Timelog Depths) O. 1B-11 ComcoPhithps Rig: DOYON 142 Job: RECOMPLETION Time Log Start Depth Start Tame/'. End Time Our(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB) 2/8/2017 2/8/2017 0.75 COMPZN RPCOMP HOSO P Spaced out wit 1.92'Pup for 2.48'ut of 8,860.0 8,825.0 17:30 18:15 PBR. 2/8/2017 2/8/2017 1.00 COMPZN RPCOMP THGR P Made up Tubing Hanger and 8,825.0 8,825.0 18:15 19:15 Circulating lines. 2/8/2017 2/8/2017 2.00 COMPZN RPCOMP CRIH P Pumped 233 Bbls Of Inhibited 9.8 8,825.0 8,825.0 19:15 21:15 PPG Brine @ 3 to 3.5 BPM 215 psi. Followed by 69 Bbls of uninhibited 9.8 PPG brine. 2/8/2017 2/8/2017 0.75 COMPZN RPCOMP HOSO P Landed out Tubing and ran in Lock 8,825.0 8,857.5 21:15 22:00 Down Screws. 2/8/2017 2/8/2017 0.50 COMPZN RPCOMP PRTS P Tested Tubing 3500 psi for 15 Min on 8,857.5 8,857.5 22:00 22:30 chart.Bled Tubing to 2,000 psi. 2/8/2017 2/8/2017 0.75 COMPZN RPCOMP PRTS P Tested OA to 3000 psi for 30 Min on 8,857.5 8,857.5 22:30 23:15 chart. 2/8/2017 2/9/2017 0.75 COMPZN RPCOMP PRTS P Tested IA to 3000 psi for 30 Min on 8,857.5 0.0 23:15 00:00 chart. 2/9/2017 2/9/2017 0.50 COMPZN RPCOMP CIRC P Sheared out SOV in Tubing with 1730 00:00 00:30 psi. 2/9/2017 2/9/2017 0.50 COMPZN RPCOMP RURD P Rigged down circulating lines and 00:30 01:00 clear Rig Floor. 2/9/2017 2/9/2017 0.50 COMPZN RPCOMP MPSP P RU and set BPV.Tested form below 01:00 01:30 1000 psi for 10 Min on chart. 2/9/2017 2/9/2017 2.00 COMPZN RPCOMP NUND P Nipple down BOPE. 01:30 03:30 2/9/2017 2/9/2017 2.50 COMPZN RPCOMP WWSP P Cleaned Flange and Nippled up Tree 03:30 06:00 Adapter and Tree. 2/9/2017 2/9/2017 0.50 COMPZN RPCOMP PRTS P Tested Void 250/5000#for 10 Min. 06:00 06:30 2/9/2017 2/9/2017 1.25 COMPZN RPCOMP PRTS P Filled Tree with Diesel and tested 06:30 07:45 250/5000 psi on chart. Drained Tree. 2/9/2017 2/9/2017 0.50 COMPZN RPCOMP MPSP P Pulled BPV/TWC. 07:45 08:15 2/9/2017 2/9/2017 1.75 COMPZN RPCOMP CIRC P RU and Sheared SOV in OA with 08:15 10:00 3000 psi. 2/9/2017 2/9/2017 2.00 COMPZN RPCOMP FRZP P RU LRS and Pumped 75 Bbls 10:00 12:00 Isotherm @ 2 BPM FCP 1650 psi.RD LRS from OA. 2/9/2017 2/9/2017 1.75 COMPZN RPCOMP FRZP P RU LRS to IA and pumped 76 Bbls of 12:00 13:45 Diesel into IA at 2 BPM 1250 psi FCP. Tied Tubing and IA together and U Tubed. 2/9/2017 2/9/2017 1.25 COMPZN RPCOMP FRZP P LRS Cleared lines and Sucked back 13:45 15:00 excess Diesel.RD LRS. 2/9/2017 2/9/2017 0.75 COMPZN RPCOMP MPSP P Set BPV. 15:00 15:45 2/9/2017 2/9/2017 2.25 COMPZN RPCOMP RURD P Secured Well and Dressed out Tree 15:45 18:00 Release Doyon 142 @ 18:00 hrs on 2- 9-17 Page 8/8 Report Printed: 2/28/2017 KUP 1 B-11 ConocoPhillips0.1- Well Attribu ' Max Angl D TD AI;1SkUl..inc. Wellbore APIIUWI Field Name Wellbore Status ncl l') MD(ftKB) Act Btm(ftKB) CorfocoVhillips 500292065700 KUPARUK RIVER UNIT INJ 64.58 10,600.00 10,723.0 ... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) "Rig Release Date 18-11,3/13/2017 122051 PM SSSV:NIPPLE Last WO. 2/9/2017 27.50 1/20/1982 Vertical schematic.(actual) Annotation Depth)ftKB) End Date Annotation Last Mod By End Date HANGER;20.9-_p I I,g Last Tag:SLM 10,006.0 7/27/2016 Rev Reason:RECOMPLETION,GLV C/O, pproven 3/10/2017 V PULLED PLUG&SET CS LOC w/A1 Inj VLV Casing Strings Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... WtlLen(I...Grade Top Thread CONDUCTOR 20 18.936 29.6 80.0 80.0 91.50 H-40 WELDED " Casing Description OD(in) ID(in) Top)ftKB) Set Depth(ftKB) Set Depth(ND)...WtlLen)I...Grade Top Thread ' " ' - SURFACE 13 3/8 12.415 29.6 2,614.6 2,242.0 72.00 N-80 BTC l Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...WtlLen(I...Grade Top Thread lll.��� PROD Tie back 2017 WO 9 5/8 8.835 28.3 706.9 705.6 40.00 L-80 Tenaris Wedge 563 fCasing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...WtlLen(I...Grade 'Top Thread wil PROD POST 2017 WO 9 5/8 8.681 704.8 9,572.4 6,375.9 47.00 L-80 BTC -A-A-t CONDUCTOR;29.6-80.0 Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread LINER 7 6.276 9,260.4 10,698.0 6,930.3 26.00 K-55 BUTT • Liner Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (in) VALVE;506.0 9,260.4 6,206.0 57.37 SLEEVE BAKER SETTING SLEEVE 6.151 NIPPLE;508.4 9,266.5 6,209.3 57.35 NIPPLE BAKER SEAL NIPPLE 6.151 9,269.8 6,211.1 57.34 HANGER BAKER MC HYD HANGER 6.151 9,282.1 6,217.7 57.31 XO BUSHING BAKER CROSS-OVER BUSHING 6.151 Tubing Strings PROD T back 2017 WO;28.3- Tubing Description String Ma...ID(in) Top)ftKB) (Set Depth(ft..{Set Depth(ND)(...Wt(Ib/ft) Grade Top Connection 706.9 00 TUBING-2017 WO 31/2 2.942 20.9 8,848.0 5,985.1 9.20 L-80 ITevaris Wedge J563 1 Completion Details 1 SURFACE;29.6-2,614.6 111 Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (In) 20.9 20.8 0.11 HANGER FMC-TC-1 EMS 131/2"x 4 1/2"IBT TUBING HANGER 4.000 AM 21.6 21.6 0.11 XO Reducing 4 1/2"x IBT-M PIN UP X 3 1/2"9.3#,L-80,TSH 563 X 2.992 GAS LIFT;8,772.8 OVER illE MI 508.4 508.4 1.54 NIPPLE CAMCO 2.875"DS LANDING NIPPLE 2.875 IN 8,826.7 5,973.6 57.55 XO Enlarging '31/2""9.3,L80,TSH 563 X 41/2""12.68,L80,TSH 563 2.950 LOCATOR;8,828.2 a® X-OVER" XO Reducing(Tubing);8,8298, = 8,828.2 5,974.4 57.55 LOCATOR GBH 22 Locator Sub 3.880 SEAL ASSY;8,828.6, 8,828.6 5,974.7 57.55 SEAL ASSY Baker 190-47 Seal Assembly3.880 SBE;8,831.3 Tubing Description (String Ma...IID fin) ITop(ftKB) Set Depth Set Depth(ND)(...IWt(Iblft) !Grade !Top Connection XO Reducing(Tubing);8,850.8 ��, LINER-Inner Casing7 6.276 26.0 8,994 0 6,063.3 26.00 L-80 TXP o WO 2017 GAS LIFT;8,907.3 Completion Details Nominal ID Top(11KB) Top)TVD)(10B)•Top Incl(°) Item Des Corn (in) 8,831.3 5,976.1 57.56 SBE Baker Seal Bore Extension with 4.75"ID 4.750 8,974.5 6,052.8 57.59 LOCATOR GBH 22 Locator Sub+2 ft space out 3.800 LOCATOR;8,974.5 SEAL ASSY;8,976.5 8,976.5 6,053.9 57.59 SEAL ASSY Baker 190-47'Seal Assembly 3.870 PBR;8,978.2 L' TubingDescription Strin Ma...ID(in) To ftKB Set Depth ft..Set Depth ND 9 p) ) p ( p (TVD)(...1W1(Ib/ft) Grade Top Connection TUBING W/O-2003 8.3 3.875 8,976.2 9,038.71 6,087.21 I ' PACKER;9,009.4 "-11 Completion Details if NIPPLE;9,024.0-. ID NIPPLE REDUCER;9,024.0 f Top(ftKB) Top(TVD)(ftKB) Top Incl(°) Item Des Com (in) #: 8,976.2 6,053.7 57.59 PBR -BAKER PBR SIZE 190-47 3.875 11 OVERSHOT;9,0308-1 =i 9,009.4 6,071.5 57.59 PACKER FH HYDROSTATIC PACKER 3.990 • 9,024.0 6,079.3 57.61 NIPPLE HES X NIPPLE 3.813 PBR;9,085.1 ijl 9,030.8 6,083.0 57.63 OVERSHOT BAKER 8"OVERSHOT(SWALLOW 7'),Top of original 4.625 PACKER;9,084.1 tubing 7037' Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(ND)(...1W1(IMO 'Grade Top Connection TUBING Original 41/2 3.958 9,037.1 10,315.61 6,760.21 12.60IJ- 55 'Buttress NIPPLE;9,1320 - Completion Details INJECTION;9161.2 Nominal ID "t Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (in) INJECTION;9,244.9 if 9,065.1 6,101.3 57.70 PBR BAKER PBR 3.920 9,084.1 6,111.5 57.73 PACKER BAKER'FHL'RETRIEVABLE PACKER 3.920 I I 9,132.0 6,137.0 57.69 NIPPLE CAMCO DB NO GO NIPPLE 3.750 'r y,'r 10,3032 6,754.3 61.76 XO CROSSOVER 4.5x3.5" 3.500 REDUCING 10,303.8 6,754.6 61.76 LOCATOR BAKER LOCATOR 2.992 • 10,304.3 6,754.9 61.77 SEAL ASSY BAKER SEAL ASSEMBLY 2.992 10,307.2 6,756.2 61.80 SBE SEAL BORE EXTENSION 2.992 2 PROD POST 2017 WO;704.9- 9,572.4 04.&9,520.4 Tubing Description 'String Ma...IID(in) 'Top)ftKB) Set Depth(tt..JSet Depth(ND)(...IWt(11d/ft) !Grade 'Top Connection APERF;e,e30.09,920.0TUBING Original 31/2 2.992 10,307.1 10,385.51 67926 9.30 J-55 Buttress , Completion Details APERF;10,088.0-10,108.0 Top(ftKB) Top(ND)(ftKB) Top Mel k) Item Des Corn No(in)I ID 10,307.1 6,756.2 61.80 PACKER BAKER'FB-1'PACKER 4.000 IF 10,309.6 6,757.4 61.83 SBE BAKER SEAL BORE EXTENSION 4.000 LOCATOR;10,303.9- SEAL ASSY;10,304.3, 10,354.3 6,778.3 62.38 NIPPLE CAMCO'D'NIPPLE 2.750 PACKER;10,307.2N SBE;10,307.2` , - 10,384.5 6,792.2 62.74 SOS BAKER BULL NOSE SHEAR TOOL 2.992 mx SBE;10,308.8 Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) NIPPLE;10,354.3- ` Top(ND) Top Incl Top(ftKB) (ftKB) (°) Des Corn Run Date ID(In) 'ff4'p SOS;10,384.5 506.0 506.0 1.44 VALVE Al INJECTION VALVE ON 2.875"CS LOCK 2/23/2017 1.000 (1"BEAN) RPERF;10,401.0-10,415.0 9,024.0 6,079.3 57.61 NIPPLE 3.81"X-LOCK ON 2.31"DS NIP REDUCER(3'-5") 1/22/2017 - 2.310 REDUCER W/BWLL GUIDE ENTRY ON BOTTOM RPERF;10,431.610,489.0 I l LINER;9,260.4-10,6980----. KUP 0 1B-11 Conor Phillips 4'6 ''"' Alaska Ing_ conocoPhdlips 18-11 3/13/2017.122352 PM I >..Vedr I s hema'c Ste) HANGER',20.9- 4 Perforations&Slots Shot . • Dens Top(ND) Btm(TVD) (shoal Top(ftKB) Btm(ftKB) (ftKB) (RKB) Zone Date ft) Type Com Ili, 9,830.0 9,920.0 6,514.1 6,562.1 C-4,C-3,1B- 4/24/1982 11 4.0 APERF 10,066.0 10,106.0 6,638.0 6,658.3 C-1,UNIT B, 11/16/1990 4.0 APERF 25/8 Jumbo Jet;180 1B-11 deg.Perforated tubing! Can't Isolate -Ns.+CONDUCTOR;29.6-80.0- 10,401.0 10,415.0 6,799.7 6,806.1 Miluveach,1B 4/20/1982 4.0 RPERF 4"HYPERJET II -11 ; ::: 10,431.0 10,489.0 6,813.3 6,839.5 Miluveach,1B 4/20/1982 4.0 RPERF 4"HYPERJET II I11 VALVE;506.0 Mandrel Inserts St NIPPLE;508.4 ati on Top(TVD) Valve Latch Port Size TRO Run .o Top(SKB) (RKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com Ii 8,772.6 5,944.6 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 2/14/2017 2 8,907.3 6,016.8 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 2/15/2017 PROD Tie back 2017 WO,28.3- 3 9,161.2 6,152.7 CAMCO 4.5x3.5 11/2 INJ CV 0.703 0.0 12/23/1982 8:00 706.9 P 4 9,244.9 6,197.6 CAMCO 4.5x3.5 11/2 INJ CV 0.703 0.0 12/23/1992 5:00 SURFACE;29.8-2,814.6 J Il Notes:General&Safety End Date Annotation 2/5/2003 NOTE:WO GAS LIFT;8,772.6 8/9/2010 'NOTE:View Schematic w/Alaska Schematic9.OREV ID 3/13/2012 NOTE WAIVERED WELL OA x OOA a LOCATOR;8,828.2 Villa XO Reducing(Tubing);8,829.8 SEAL ASSY,8,828 6-, Z. SBE;8,831.3 ;211' INIIMIIII XO Reducing(Tubing),8,850.6 mr GAS LIFT,8,907.3 g LOCATOR,8,974.5 • SEAL ASSY,8,9765 PBR;8,976.2 ._. I I PACKER;9,009.4 lli NIPPLE,9,024.0 ` NIPPLE REDUCER;9,024.0 II OVERSHOT,9,030.8 r [ PER,9,065.1 PACKER,9,084.1 - -- NIPPLE;9,132.0 INJECTION;9,161.2 Lw.w -.. INJECTION;9,244.9 •. -'1 ,1" PROD POST 2017 WO;704.9- 9,572.4 APERF,9,830.0-9,920.0 APERF;10,086.0-10,106.0 a LOCATOR,10,303.9- SEAL ASSY,10,304.3` f_ 1 PACKER;10,307.2 F SBE;10,307.2` - i MI SBE;10,309.6 - - NIPPLE;10,354.3 SOS,10,384.5 k a. RPERF;10,401.0-10,415.0 RPERF,10,431.0-10,489.0 1 1 I 1 LINER',9,260.4-10,698.0 • PTO /8/- /34 Loepp, Victoria T (DOA) From: Kane, Danny <Danny.Kane@conocophillips.com> Sent: Sunday, February 05, 2017 2:05 PM To: Loepp,Victoria T(DOA) Subject: RE:CPAI KRU 1B-11 (PTD 181-136/Sundry 317-018) - Request to Change Approved Program Attachments: KRU 1B-11 - Proposed RWO with Inner Casing - FINAL 20170204.pdf Importance: High Follow Up Flag: Follow up Flag Status: Flagged Victoria, I wanted to confirm before we started doing the 7"casing work(tomorrow)that the AOGCC approves of this proposed Scope Change? Regards, • Danny Danny Kane Senior Wells Engineer ConocoPhillips-ATO 1509 Office: +1907 265-6048 Mobile:+1907 227-6037 SCANNED MAY j 2017, danny.kane@conocophillips.com From: Kane, Danny Sent:Sunday, February 05,2017 12:21 AM To: 'Loepp,Victoria T(DOA)'<victoria.loepp@alaska.gov> Subject: RE:CPAI KRU 1B-11 (PTD 181-136/Sundry 317-018)- Request to Change Approved Program Victoria, Please see the attached proposed KRU 1B-11 RWO Schematic w/7" Inner Casing String. Regards, • Danny Danny Kane Senior Wells Engineer ConocoPhillips-ATO 1509 Office: +1907 265-6048 Mobile:+1907 227-6037 danny.kane@conocophillips.com 1 FMC ALP Big Bore • KRU 1 B-11 13-/."x 4-1/2"Tbg Hgr ConocoPhillips Kuparuk B-&C-Sand Injector Proposed 2017 RWO w/Added Inner Casing String for 13-%"x 20"91.5#H-40 WLD,109'MD 9-%"Annulus Leak [in '500'MD,3-1/2"Camco 2.875"DS'Nipple For A-1 Infection Valve 9-%"40#L-80 TSH563 R3 Casing a 5 Bowen Packer-Type Casing Patch Swallow Leak in 13-/e"x 9-/e"Annulus Deeper--r ,. 9-5/."47#L-80 BTC Casing Stub at 712'MD than 706'MD found during RWO 4'/2"Tubing Hanger,XO to 3'/2"Tbg Below 3-1/2"9.3#L-80 TSH563 R2 Tubing 13'/."72#N-80 BTC,2614'MD--OP---L i___ Drilling Mud/Spacer Cement Arctic Pack Diesel Kill Weight Fluid 8793'MD,Camco 3'/2"x 1"KBMG,SOV Unknown/Form Fluid SOV Pinned 2000 psig/A T Shear ♦ 8853'MD,Baker 190-47 Sealbore Extension .0----t—4-1/2"12.6#L-80 TSH563 R2 Tubing al 4 8919'MD,4'/¢"Camco 1-1/2"MMG,SO\ SOV Pinned 2000 psig IA4 T Shear ms.,— -.0—+--8976'MD,Baker 190-47 PBR AAI .41.1--9009'MD,Baker 9-%"x 4-1/2"FH Packer ` I -" Pinned for 50 klbs Shear Release l' �—9024'MD,4'/:"HES 3.813"'X'Nipple 11 3.813"x 2.313"RN&CA-2 Plug Installed Pre-RW"O `� 4 9030'MD,4'/:"Tubing Poor-Boy Overshot f--, 9065'MD,Baker PBR a1.- /► Lk } -4-+—9084'MD,Baker 9-'/."x 4'A"FHL Packer 6 � p -4----9132'MD,4-1/2"Camco 3.75"'DB'Nipple I I O 9161'MD,Camco 4-1/2"Injection -4 9030II f—i--9244'MD,Camco 4-1/2"Injection Mandrel -4--9260'MD,Baker 9-1/2"x 7"Setting Sleeve 9269'MD,Baker MC Hydraulic Hanger/Packer 9-8/."47#L-80 BTC,9572'MD---`� �.. Kuparuk C-Sand Perforations C-4&C-3,1982—9830'-9920'MD C-1,1990—10066'—10106'MD I ri !ii ,_ I 10307'MD,Baker 7"x 3-1/2"FB-1 Packer I •a 4 10354'MD,3-1/2"Camco 2.75"'D'Nipple Kuparuk B-Sand Perforations 10384'MD,Baker Shear-Out Sub B,1982—10401'-10415'MD B,1982—10431'-10489'MD 7"26#K-55 BTC,10698'MD--o►d— I Dare, 04fab-2017 I Drawn By: Danny Kane • • From: Loepp,Victoria T(DOA) [mailto:victoria.loepp@alaska.gov] Sent:Saturday, February 04, 2017 10:35 PM To: Kane, Danny<Danny.Kane@conocophillips.com> Subject: [EXTERNAL]Re: CPAI KRU 1B-11 (PTD 181-136/Sundry 317-018)-Request to Change Approved Program Danny, This proposal will meet approval. Please send proposed schematic. Thanx, Victoria Sent from my iPhone On Feb 4,2017,at 7:22 PM, Kane, Danny<Danny.Kane@conocophillips.com>wrote: Victoria, To follow-up,does the AOGCC approve of the following repair of KRU 1B-11? After running the 9-%"tie-back casing string,we propose adding a 7"casing string from surface to the existing production packer before running the new Upper Completion within the 7"casing. The 7"x3-W" annulus will become the IA,the 9-%"x 7"annulus will become the OA,and the leaking 13-%"x 9-%" annulus will become the OOA. To recap the Current Operations/Problem: • After installing the 13-%"wellhead,the rig N/U the BOPE stack,shut-in the blind rams& attempted to pressure-test the 13-%"casing. This test failed with a LLR of 1 bpm at 200 psig. o This tested the 13-%"casing to OA shoe,9-%"casing from bridge plug to OA shoe,the OA shoe itself,and the 9-%" bridge plug. o A test packer has confirmed the leak in our 13-3/8"casing deeper than 706' MD,the deepest we could set our test packer. ConocoPhillips proposes the following scope to complete the RWO objectives as per Sundry 317-018. • M/U & run 9-%"40# L-80 TSH563 casing tie-back w/Bowen Packer Type Casing Patch. Circulate clean fluids around, engage patch, & land in slips at surface. Pressure-test 9-%" casing to 3,000 psig for 10 minutes. • N/D BOPE stack. Cut 9-%" casing as needed above the SLIPLOC Casing Head, and install emergency slips&pack-off. • N/U BOPE stack, install Lower Test Plug,&shell-test BOPE. • TIH & Wash-out sand above RBP. TIH w/ retrieval tool for 9-%" RBP, retrieve RBP, TOH, & LID same. • M/U &TIH w/new 7" 26#L-80 TXPM Casing String. Tag the top of the PBR,spot a C.I. brine pill, fully-locate,&space-out 2'from fully-located. o 7" Casing will be run from surface to just above FH packer at 9,009' MD where it will XO to a Seal Assembly dressed for the PBR. • Land 7"casing in slips at surface. Pressure-test 7"casing to 3,000 psig for 10 minutes. N/D BOPE stack,cut 7" casing as needed above the Lower Casing Head,and install emergency slips& pack- off. 2 • • N/D BOPE stack. Cut 7" casing as needed above the Lower Casing Head, and install emergency slips&pack-off. Install Upper Casing Head. • N/U BOPE stack, install Lower Test Plug,&shell-test BOPE. • M/U&TIH w/new 3-1/2"9.3#L-80 TSH563 Injector Upper Completion. • Tag the top of the SBE,spot a C.I. brine pill,fully-locate,&space-out 2'from fully-located, mark- pipe at surface, & lay-down two joints. Space-out with tubing pups, M/U tubing hanger, & M/U landing joint. • Displace IA to C.I.seawater,stab seals, land hanger, &RILDS. • Pressure-test tubing to 3,500 psig, bleed to & while holding 2,000 psig on the tubing, pressure- test IA to 3,000 psig. Rapidly dump the tubing pressure to shear the SOV. Bleed the IA,then the tubing. Perform DDT on each the tubing&the IA. • Back-out landing joint, install 3"Type 'HP' BPV, & pressure-test to 1,000 psig in the direction of flow. • N/D BOPE, N/U new 3-'h" vertical tree, make-up the Sealing HP Plug-Off tool to the BPV, & pressure-test tree to 250/5,000 psig. Pull the Sealing HP Plug-Off tool&3"Type'HP' BPV. • Freeze-protect well through SOV. Set 3"Type'H' BPV. • RDMO Doyon 142. Regards, • Danny Danny Kane Senior Wells Engineer ConocoPhillips-ATO 1509 Office: +1907 265-6048 Mobile:+1907 227-6037 danny.kane@conocophillips.com From: Kane, Danny Sent:Saturday, February 04, 2017 9:14 AM To:Victoria Loepp(AOGCC)<victoria.loepp@alaska.gov> Subject:CPAI KRU 1B-11(PTD 181-136/Sundry 317-018) REVISED Importance: High Victoria, Can you let me know if the AOGCC would approve of the following repair for KRU 1B-11? The proposed RWO repair of KRU 1B-11(Sundry#317-018)consisted of the following objectives& scope: • Objectives: o Replace corroded 4-%" Upper Completion o Restore OA integrity to enable MWAG injection- 13-%"mandrel casing hanger thread leak. • Completed Scope: o Pull 4-1A" Upper Completion o Installed bridge plug in 9-%"casing beneath planned cut. 3 • • o Cut&Pull 9-%" Production Casing to 712' MD o Cut-Off Existing Wellhead o Installed New Wellhead • Current Operations/Problem o After installing the 13-%"wellhead,the rig N/U the BOPE stack,shut-in the blind rams &attempted to pressure-test the 13-%"casing. This test failed with a LLR of 1 bpm at 200 psig. • This tested the 13-%"casing to OA shoe,9-%"casing from bridge plug to OA shoe,the OA shoe itself,and the 9-%" bridge plug. • We are currently waiting on a test packer to determine the leak location(from surface to 712'MD,or deeper than 712'MD). • This was the planned remaining Scope o Run 9-%"Tieback Casing o Pull bridge plug in 9-%"casing. o Run New 4-%2" Gas-Tight Upper Completion Depending on where the 13-34" leak is found and how big it is,we may not have a viable means of fixing the leak with available equipment on the North Slope. Would the AOGCC allow MWAG injection on KRU 1B-11 with a known surface casing leak but good production casing and Upper Completion? I will call shortly to discuss this. Regards, • Danny Danny Kane Senior Wells Engineer ConocoPhillips-ATO 1509 Office: +1907 265-6048 Mobile:+1907 227-6037 danny.kane@conocophillips.com 4 • • Loepp, Victoria T (DOA) From: Kane, Danny <Danny.Kane@conocophillips.com> Sent: Saturday, February 04, 2017 9:14 AM To: Loepp,Victoria T(DOA) Subject: CPAI KRU 1B-11 (PTD 181-136/Sundry 317-018) REVISED Importance: High Follow Up Flag: Follow up Flag Status: Flagged Victoria, Can you let me know if the AOGCC would approve of the following repair for KRU 1B-11? The proposed RWO repair of KRU 1B-11 (Sundry#317-018)consisted of the following objectives&scope: • Objectives: o Replace corroded 4-1A" Upper Completion o Restore OA integrity to enable MWAG injection- 13-%"mandrel casing hanger thread leak. • Completed Scope: o Pull 4-h" Upper Completion o Installed bridge plug in 9-%"casing beneath planned cut. o Cut& Pull 9-%8" Production Casing to 712' MD o Cut-Off Existing Wellhead o Installed New Wellhead • Current Operations/Problem o After installing the 13-%"wellhead,the rig N/U the BOPE stack,shut-in the blind rams&attempted to pressure-test the 13-rb"casing. This test failed with a LLR of 1 bpm at 200 psig. ■ This tested the 13-%"casing to OA shoe,9-%8"casing from bridge plug to OA shoe,the OA shoe itself,and the 9-%" bridge plug. • We are currently waiting on a test packer to determine the leak location(from surface to 712' MD,or deeper than 712'MD). • This was the planned remaining Scope o Run 9-%"Tieback Casing o Pull bridge plug in 9-%"casing. o Run New 4-36"Gas-Tight Upper Completion Depending on where the 13-36" leak is found and how big it is,we may not have a viable means of fixing the leak with available equipment on the North Slope. Would the AOGCC allow MWAG injection on KRU 1B-11 with a known surface casing leak but good production casing and Upper Completion? I will call shortly to discuss this. Regards, • Danny Danny Kane Senior Wells Engineer • • ConocoPhillips-ATO 1509 Office: +1907 265-6048 Mobile:+1907 227-6037 danny.kane@conocophillips.com 2 • • Loepp, Victoria T (DOA) From: Kane, Danny <Danny.Kane@conocophillips.com> Sent: Saturday, February 04,2017 9:09 AM To: Loepp,Victoria T(DOA) Subject: RE:CPAI KRU 1B-11 (PTD 181-136/Sundry 317-018) Follow Up Flag: Follow up Flag Status: Flagged Victoria, This was sent accidentally before it was finished. I will be sending the final email soon. Danny Kane Senior Wells Engineer ConocoPhillips-ATO 1509 Office: +1907 265-6048 Mobile:+1907 227-6037 danny.kane@conocophillips.com From: Kane, Danny Sent:Saturday, February 04,2017 9:08 AM To:Victoria Loepp(AOGCC)<victoria.loepp@alaska.gov> Subject:CPAI KRU 1B-11(PTD 181-136/Sundry 317-018) Victoria, Can you let me know if the AOGCC would approve of the following repair for KRU 1B-11? The proposed RWO repair of KRU 1B-11 (Sundry#317-018)consisted of the following objectives&scope: • Objectives: o Replace corroded 4-1r4" Upper Completion o Restore OA integrity to enable MWAG injection- 13-%8" mandrel casing hanger thread leak. • Completed Scope: o Pull 4-%" Upper Completion o Installed bridge plug in 9-%" casing beneath planned cut. o Cut&Pull 9-%" Production Casing to 712' MD o Cut-Off Existing Wellhead o Installed New Wellhead • Current Operations/Problem o After installing the 13-34"wellhead,the rig N/U the BOPE stack,shut-in the blind rams&attempted to pressure-test the 13-%"casing. This test failed with a LLR of 1 bpm at 200 psig. • This tested the 13-%"casing to OA shoe,9-3/4"casing from bridge plug to OA shoe,the OA shoe itself,and the 9-3/4" bridge plug. • We are currently waiting on a test packer to determine the leak location(from surface to 712' MD,or deeper than 712' MD). • This was the planned remaining Scope o Run 9-%"Tieback Casing o Pull bridge plug in 9-3"casing. 3 • • o Run New 4-W'Gas-Tight Upper Completion Danny Kane Senior Wells Engineer ConocoPhillips-ATO 1509 Office: +1907 265-6048 Mobile:+1907 227-6037 danny.kane@conocophillips.com 4 • • Loepp, Victoria T (DOA) From: Kane, Danny <Danny.Kane@conocophillips.com> Sent: Saturday, February 04,2017 9:08 AM To: Loepp,Victoria T(DOA) Subject: CPAI KRU 1B-11 (PTD 181-136/Sundry 317-018) Follow Up Flag: Follow up Flag Status: Flagged Victoria, Can you let me know if the AOGCC would approve of the following repair for KRU 1B-11? The proposed RWO repair of KRU 1B-11 (Sundry#317-018)consisted of the following objectives&scope: • Objectives: o Replace corroded 4-%" Upper Completion o Restore OA integrity to enable MWAG injection- 13-%"mandrel casing hanger thread leak. • Completed Scope: o Pull 4-34" Upper Completion o Installed bridge plug in 9-%8"casing beneath planned cut. o Cut&Pull 9-%8" Production Casing to 712' MD o Cut-Off Existing Wellhead o Installed New Wellhead • Current Operations/Problem o After installing the 13-%"wellhead,the rig N/U the BOPE stack,shut-in the blind rams&attempted to pressure-test the 13-%"casing. This test failed with a LLR of 1 bpm at 200 psig. • This tested the 13-%"casing to OA shoe,9-%8"casing from bridge plug to OA shoe,the OA shoe itself,and the 9-%" bridge plug. • We are currently waiting on a test packer to determine the leak location(from surface to 712' MD,or deeper than 712' MD). • This was the planned remaining Scope o Run 9-%"Tieback Casing o Pull bridge plug in 9-%"casing. o Run New 4-1/4"Gas-Tight Upper Completion Danny Kane Senior Wells Engineer ConocoPhillips-ATO 1509 Office: +1907 265-6048 Mobile:+1907 227-6037 danny.kane@conocophillips.com 5 • S Loepp, Victoria T (DOA) From: Thompson,Jacob <Jacob.Thompson@BP.com> Sent: Wednesday, February 01, 2017 3:36 PM To: Loepp,Victoria T(DOA) Subject: RE: L-200A(PTD216-125 revised)Change Request Follow Up Flag: Follow up Flag Status: Flagged Thank you. I will forward this to the rig site and they add the change to the approved PTD. Jacob Thompson BP Alaska Rotary Drilling Engineer Cell:(907)854-4377 Office:(907)564-5579 From: Loepp, Victoria T(DOA) [mailto:victoria.loepp@alaska.gov] Sent: Wednesday, February 01, 2017 3:34 PM To:Thompson,Jacob Subject: RE: L-200A(PTD216-125 revised) Change Request Jacob, Approval is granted to test the surface casing to 2000 psig as written below. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil&Gas Conservation Commission 333 W.7th Ave Anchorage,AK 99501 Work: (907)793-1247 Victoria.Loepp aa..alaska.gov CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Victoria Loepp at(907)793-1247 or Victorialoem@alaska.gov From:Thompson,Jacob Finailto:Jacob.Thompson@BP.coml Sent:Wednesday, February 01,2017 3:27 PM To: Loepp,Victoria T(DOA)<victoria.loepp(a@alaska.gov> Cc:Lastufka,Joseph N<Joseph.Lastufka@bp.com>;Allen, Kenneth W<Kenneth.Allen@bp.com> Subject: RE: L-200A(PTD216-125 revised)Change Request 1 • • Victoria, Per the below request and approval the planned L-200A surface casing pressure test value was reduced to 2,400 psi. BP is requesting that the surface casing pressure test be again reduced to 2,000 psi.As stated in the PTD L-200A has a MASP of 1,840 psi.The below pressure test value of 2,400 psi was chosen by placing a—150 psi safety factor on top of the highest pore pressure seen in the Schrader Bluff formation. L-200A has three offset injectors L-211, L-212,and L-218 that have down hole pressure gauges.The pressure gauges in these wells give us high confidence in the most likely pore pressure and subsequent MASP of 1,840 psi. In order to not exert unnecessary stress on the existing surface casing we are requesting that the 10-3/4"surface casing test pressure be reduced to 2,000 psi.This is above MASP, meets all AOGCC requirement,and will reduce the chances of damaging the surface casing. Please advise if you approve this change. Attached is a schematic of the current condition of the well. Please feel free to call me if you have any questions, Thanks, Jacob Thompson BP Alaska Rotary Drilling Engineer Cell:(907)854-4377 Office:(907)564-5579 From: Loepp, Victoria T(DOA) rmailto:victoria.loeoo@alaska.gov] Sent: Friday, January 27, 2017 2:25 PM To: Thompson,Jacob Subject: RE: L-200A(PTD216-125 revised) Change Request Jacob, Approval is granted as written. Please include this email with the approved PTD. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil&Gas Conservation Commission 333 W.7th Ave Anchorage,AK 99501 Work: (907)793-1247 Victoria.loepo alaska.00v 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 Victoria Loepp at(907)793-1247 or Victoria.Loeoo@alaska.gov From:Thompson,Jacob f mailto:Jacob.Thompson@ BP.coml Sent: Friday,January 27,2017 2:09 PM To:Loepp,Victoria T(DOA)<victoria.loepp@alaska.gov> Subject: L-200A(PTD216-125 revised)Change Request 2 • • Victoria, On step 12 of the proposed drilling rig operations section of the L-200A original sundry and PTD the 10-3/4"surface casing was to be pressure tested to 3,500 psi.3,500 psi is our standard test pressure for producers in the Greater Prudhoe Bay Field to cover all well types.As stated in the PTD L-200A is accessing reserves in the Schrader Bluff formation where a MASP of 1,840 psi is expected. In order to not exert unnecessary stress on the existing surface casing we are requesting that the 10-3/4"surface casing test pressure be reduced to 2,400 psi.This is well above MASP and meets all AOGCC requirement,and will reduce the chances of damaging the surface casing. Please advise if you approve this change. Thank you and have a great weekend, Jacob Thompson BP Alaska Rotary Drilling Engineer Cell:(907)854-4377 Office:(907)564-5579 3 n - i L I I W �1 gn ~ > 0 to p Uj co n d U > E 060 v � � tl W ro `- C Y ° c (0 co + O o N V2 'Jo o ili m c HIII O T Q 0 _ W r r r r r r N L L 0 o CO Q y O C C C C C C E ++ 10 N J 10 10 ca f0 f0 co (o WT coN IA O cO ro Y ,.. C N Z N Q N N N M U (o \ 4-' U C: O N O C i �- a-• U .1'' c0 O F- 00 N -0 N U 0 0 0 0 0 0 Ca) 0 L U.' J J J J J J _ c `- () 0 W W W W W W � N c Y.F- LL LL LL LL LL LL Q -0 > t C < J J J J J -JC 4'' 4- o C; a Z Z Z Z Z Z v L N 0 v O G' 0 LL LL LL LL LL LL K .... 4-, > C CD (moo 4-4 > N N U v O ` z '^ O' oD U > R O C O ro ,-- co 0 o s Y Z a G O c c a 0 0 z _ Q v a c a U F- J e! iC 2 LL V id. W LL L.L. LL U w � C Q N £ t \ abTi 853 z — � aaaJt �n 1 re y wU W r.: Fri p a a Q� - co 66 '\ iN 9 g 0 --. Oof as Lu 19 03 EW Ud J J J J J J To* CG a Z CO W U C *! 4 o Z Z iec w w w w w w I Ce ca ce CL re Ce W > > > > > > z Y Y Y Y Y Y o Q Q Q Q Q Q 2 ti O ® LL a a a a a a .� a > > > > > ` C L Y Y Y Y Y Y coO LU _ LIJ _ X o U . el NY 0 Tr Tr 0 0 0 0 E N ♦ , s O O O O O O D1 �- v C. 0 0 0 0 0 ro WO 0 Y Y LL FL LL LL LLLL U 0 0 0 0 — m C 0 0 0 0 0 0 Q c Q. W ®. E " O m CC N 0 0 0 0 0 0 IV Q a v v 00) r uri N 4+ •-• a 0 a a C) (0 N I� 0 0 0 0 0 M N N N N N N N VI • r 0' M M M O C 0 a p O O N O N N f0 0 O 01 0 0 0 OU - Co a. C 4C N if) N M N N a0. dl o U ionGl OCD • 0_ rl=Oa u, �c QQh o3 co CC V E E ii .a ~ DJ Dj 4"4 Q t0 N a co 4— 4., E w Y �.. z b ,}, z N o •• E a,+ -, v E H J v) to X Y Fn di E co v Q N W M M N N r. v1 z O y �e�-f1 ^ 3. fC .c w E E m CD OW 67. 3.-14..1 a Q Fy a a H 0 yoFTg • • �.a\�����y��s� THE STATE Alaska Oil and Gas - ofConservation Commission LAsKA 333 West Seventh Avenue 4'1 - ;••% GOVERNOR BILL WALKER Anchorage,e, Alaska 99501-3572 W-jr.�rF Main: 907.279.1433 of ge'A Fax: 907.276.7542 .S www.aogcc.alaska.gov Daniel Kane Sr. Wells Engineer MARGO, ConocoPhillips Alaska, Inc. SCANNED P.O. Box 100360 Anchorage,AK 99510 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 1B-11 Permit to Drill Number: 181-136 Sundry Number: 317-018 Dear Mr. Kane: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 4/_.,i /eL, Cathy . Foerster Chair DATED this�day of January,2017. RDDNIS Li - 3 Ng • STATE OF ALASKA • RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION JAN 1 3 2017 APPLICATION FOR SUNDRY APPROVALS Dcr5 lc/9 20 AAC 25.280 4ánQhuU 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well U ! tdown Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing Q Change Approved Program❑ Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing Q Other: Cl-pl4 zv4[t'.( 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: ConocoPhillips Alaska,Inc. Exploratory ❑ Development ❑ 181-136 • 3.Address: Stratigraphic ❑ Service ❑ • 6.API Number: P.O.Box 100360,Anchorage,Alaska 99510 50-029-20657-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? n/a Will planned perforations require a spacing exception? Yes ❑ No❑✓ / KRU 1B-11 • 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL025648 \ Kuparuk River Field/Kuparuk River Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Zt/4 if Plugs(MD): Junk(MD): 10723' . 6941' . 10006' , 6607' • O • none none Casing Length Size MD TVD Burst Collapse Structural Conductor 50' 20" 80' 80' Surface 2580' 13.375" 2613' 2241' Intermediate Production 9539' 9.625" 9571' 6375' Liner 1413' 7" 10696' 6930' Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9830'-9920' . 6514'-6562' 4.5"x 3.5" L-80 10386' 10066'-10106' • 6638'-6658' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): SSSV: CAMCO DB-6 NIPPLE; SET A-1 INJ VALVE MD=499 TVD=499 • PACKER-FH HYDROSTATIC PACKER MD=9009 TVD=6072 • 12.Attachments: Proposal Summary ❑ Wellbore schematic ❑ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑ Service 2 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 1/18/2017 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑✓ ' GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Daniel Kane @ 265-6048 Email Daniel.Kane@conocophillips.com Printed Name Daniel Kane 265-6048 Title Sr.Wells Engineer Phone Signature Date l2—5AN 2Q5 -3- COMMISSION COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: `I — O` s Plug Integrity ❑ BOP Test Er Mechanical Integrity Testkr" Location Clearance ❑ t (2tp 1 4 Other: £30P ,f,.-54--1.-6, 3 57 Cp s !\ /}nvivl a r p r e' Vc /±e—r- 5� ZSR c7 ����� Post Initial Injection MIT Req'd? Yes No ❑ RBDMSF-B - LI! 17 Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: ]0 L1 0 L— Approved 0 I APPROVED BY Approved by: id MMisTHE COMMISSION Date:/ —1 JitJi ,va1ici 3u rnlr Four].12 Form 10-403 Re ed 11/2015 '' for 12 months from the date of approval. Attachments in Duplicate VL //7 -lr� • • ConocoPhillips Alaska P.O. BOX 100360 RECEIVED ANCHORAGE,ALASKA 99510-0360 January 12th,2017 JAN 1 3 2017 Cathy Foerster AOGCO State of Alaska Alaska Oil&Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage,Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits an Application for Sundry Approval to workover Kuparuk MWAG Injector/CFW Disposal well KRU 1B-11 (PTD# 181-136). Well 1B-11 was spudded in 1981 and completed in 1982 as a Lower Kuparuk Lean-Gas Injection well. A RWO was performed in 1982 shortly after the well was initially brought online and a leak developed in the 9-%" production casing;the RWO repaired the leak and replaced the entire completion with a selective single completion along with adding Kuparuk C-sand perforations. Lean gas injection ceased in 1989 and the well was converted to a water-only injector in 1991. In 1993,the well was converted to allow disposal of Contaminated Fresh Water from CPF1 camp. In 2001,TxIA communication was discovered,a waiver was put in place to continue water-injection(including CFW), and the well was worked over in 2003 to pull&replace the Upper Completion. In 2004,the well was converted to an MWAG injector. In 2011,OA x OOA communication was discovered as the result of a surface casing thread leak at the mandrel hanger. AIO 2B.060 was approved to allow water-only injection(including CFW)with an OA x OOA leak. After failing to successfully plan a feasible non-rig weld repair of the surface casing thread leak,the well was placed on the RWO list in 2017 to pull &replace the Upper Completion and to replace the entire wellhead to bring the well back on MWAG. This Sundry is intended to document the proposed work on KRU 1B-11 because of the intent to repair the well,pull tubing, &alter the casing(required to remove replace the wellhead), as well as to request approval to workover this well. If you have any questions or require any further information, please call me at 265-6048 or email me at danny.kane@conocophil lip s.com. Sincerely, Danny Kane Wells Engineer CPAI Drilling and Wells • • KRU 1B-11 Proposed Rig Workover ConocoPhillips P&R Tubing and Wellhead Replacement Original PTD M181-136 Alaska CURRENT STATUS: KRU 1B-11 a selective single completion Kuparuk B- &C-sand injector,is currently online injecting both produced water and intermittently contaminated fresh water(CFW,alternating with KRU 1B-09). While currently testing good,the existing 4-1'"tubing has severe corrosion with significant wall loss in addition to a 13-%"surface casing thread leak at the mandrel hanger. A rig work-over is being proposed to proactively pull &replace the 4-%" Upper Completion to avoid losing a CFW well as well as to cut-off&replace the wellhead to restore surface casing integrity to enable miscible injectant water alternating gas(MWAG) injection. Please see below for a history of the well&annuli integrity diagnostics: - 1982—KRU 1B-11(originally named 1B-11G1)was drilled targeting the Lower Kuparuk sands for lean-gas injection to dispose of excess gas produced from the 40-well Kuparuk River Phase I development(produced gas>allowable flared volume&no pipeline to transport produced gas). The well was completed as a single completion injector after the Lower Kuparuk sands were perforated from 10,401'-10,489' MD. Spudded 15-Dec-1981&rig released 20-Jan-1982. o In February 1982,after a failed clean-out run for excessive fill produced into well,an attempt was made to inject into the partially-covered perforations. While injecting at 25 MMCFD for several hours at 3700 psig WHP,a leak developed in the 9-%"casing and in the well was immediately shut-in&secured. o RWO#1(AOGCC approved 30-Mar-1982)performed to repair 9-%"production casing leak, provide isolation of Lower Kuparuk sands,&re-perforate/acidize Lower Kuparuk sands,& install a new selective single completion. • 9-3/4"casing leak<473' MD caused by high injection rates into partially-covered perforations increasing surface pressure that failed the wellhead pack-offs& increased pressure within the 4-%"x 9-34"annulus. 9-%"casing ultimately cut at 589' MD&repaired w/new casing&'JOY'overshot casing patch. • Added C-4/C-3 perforations from 9,830'-9,920' MD. - 1983—Approval given to inject into both Kuparuk C-sands& Lower Kuparuk. - 1989—Stopped injecting lean gas into well. - 1990—Perforated through both tubing&casing across the C-1 interval (10,066'to 10,106' MD)in preparation to converting well to water-only injector. - 1991—Started water-only injection(Sundry#90-622). - 1993—Surface piping modified to allow for CPF1 camp contaminated fresh water(CFW)disposal into 1B-09 and 1B-11. 1B-11 was primary CFW disposal well as part of water injection stream. - 2001—TxIA communication discovered&confirmed. o AOGCC approved continued CFW disposal with TxIA while diagnosing leak. o Tubing leaks found at 5,459'&5,489' MD. CMIT-TxIA passes. o AOGCC approved leaving well on CFW injection until rig work-over(Sundry#301-241). - 2002—RWO delayed&AOGCC approves 6-month CFW injection extension (Sundry#302-249). - 2003—RWO#2(Sundry#302-090)performed to pull&replace the 4-34"Upper Completion. o RWO repaired TxIA,&well placed back on CFW injection. - 2004—Started WAG injection. - 2010—First indications of OA x OOA communication while performing surface casing diagnostics. - 2011—OA x OOA communication confirmed as surface casing mandrel hanger thread leak. o Visible thread leak as 05:00 position where surface casing screws into mandrel hanger. o Requested&received AIO 26.060 to continue water-only injection w/surface casing leak. - 2014—Tree swapped out in response to Miscible Injectant gas release on KRU 1B-09. - 2015—Internal decision made to pursue weld repair of surface casing mandrel hanger thread leak. - 2017—Weld repair planning tests failed. Internal decision made to perform RWO to pull&replace severely corroded tubing and replace wellhead to allow MWAG injection again. Page 1 of 4 • • ✓ KRU 1B-11 Proposed Rig Workover ConocoPhillips P&R Tubing and Wellhead Replacement Alaska Original PTD #:181-136 SCOPE OF WORK: The objectives for the proposed KRU 1B-11 RWO are to restore degraded upper completion tubing integrity with new tubing&gas-tight connections as well as to repair the surface casing thread leak by replacing the wellhead. The scope of the proposed RWO will be to pull the existing 4-1/2" Upper Completion to a pre-rig tubing cut,fish the tubing stub/seal assembly,cut&pull the 9-%" production casing to provide access to the 13-%"surface casing, cut the existing wellhead off,install a new wellhead, run new 9-%"production casing,&run a new gas-tight 3%:" Upper Completion. This will allow the well to be brought back online as a Kuparuk A-&C-sand selective single completion MWAG injector and CFW disposal well. Well Type: Kuparuk A-&C-sand Selective Single Completion Injector MPSP: 2,486 psig using MPSP=(PP-(0.1*ND)),or dry gas gradient to surface. 2,486 psig=(3,144 psig—(0.1 psig/ft*6,587'TVD)) Reservoir Pressure/TVD: Kuparuk C-Sand Mid-Perfs—3,144 psig/6,587'ND(9.2 ppg EMW) Using last recorded shut-in bottom-hole pressure. Wellhead Type: FMC Gen II (5M) BOP Configuration: Annular/Pipe Rams/Blind Rams/Mud Cross/Pipe Rams BOP Test Pressure 250/3,000 psig(2,500 psig high for Annular) Integrity Results: MIT-T Passed 2003 **Tubing test during RWO** MIT-IA Passed 07-Jul-2015 **New MIT-IA as part of pre-rig** MIT-OA Failed 22-Apr-2004 Last passing MIT-OA 17-Jan-2003 Earliest Start Date: 18-Jan-2017 Production Engineers: Dana Glessner Workover Engineer: Danny Kane (907)265-6048 danny.kane@conocophillips.com SUMMARY OF COMPLETED&PROPOSED RWO PROCEDURE: Proposed Pre-Rig Work: 1. Function-test all T, I.C.,&O.C. LDS. Test tubing, I.C.,&O.C. pack-offs(T-POT/T-PPPOT/IC-POT/IC-PPPOT/ OC-POT/OC-PPPOT). 2. Pull A-1 Injection Valve from 4-1/2"Camco 3.813"DB-6 Landing Nipple at 498' MD. 3. Obtain 30-min SBHP with gradient stop. a. NOTE:This SBHP will be used to adjust the BOPE test pressure to>500 psig over the updated MPSP. 4. Set nipple reducer&plug/prong in the 4-W' HES 3.813"X Landing Nipple at 9,024' MD. a. If no compatible nipple reducer can be installed,set inflatable/collapsible plug. 5. Pressure-test tubing to 2,500 psig to test plug integrity. Pressure-test IA to 2,500 psig to test IA integrity. a. NOTE: If either test fails,a CMIT-TxIA to 2,500 psig will be performed. 6. Install catcher on top of plug. 7. Pull the DV from the Camco 4-1/2"x 1-Y2" MMG GLM (#1)at 8,925' MD. 8. Pull catcher sub from on top of plug. 9. Swap the well above the packer/plug to seawater&2,000'TVD diesel freeze-protect cap. 10. Bleed TxIA&perform CDDT-TxIA to confirm packer/plug integrity in the direction of flow. 11. Fire a minimum 10'string shot across proposed tubing cut at 8,955' MD. 12. Chemical cut 4-1/2" 12.6#L-80 NS-CT tubing at 8,955' MD. 13. Set 4"Type'IS-A' BPV. Start bleeding OA&OOA with bleed trailer. Page 2 of 4 • • ✓ KRU 1B-11 Proposed Rig Workover ConocoPhillips P&R Tubing and Wellhead Replacement Alaska Original PTD#:181-136 Completed Rig Workover Procedure: 1. MIRU Doyon 142. 2. Pull 4"Type'IS-A' BPV. 3. Rock the diesel out of the tubing by reverse circulating seawater (over-displace diesel by 150%). Line-up to pump seawater the long-way to displace the diesel from the IA(over-displace diesel by 150%). Shut-in the T& IA,obtain initial SITP&SICP,&perform 10-minute CDDT-TxIA to verify the packer/plug have integrity. 4. Install 4"Type'IS-A' BPV. Pressure-test BPV in the direction of flow to 1,000 psig. 5. ND 4-1/16'vertical tree. Install blanking plug. NU BOPE&test to 250/3,000 psig(annular to 2,500 psig). 6. Pull the blanking plug&4"Type'IS-A' BPV,screw in the landing joint, BOLDS,&unseat tubing hanger. 7. P/U on the 4-1/2"tubing&pull the tubing hanger to the rig floor. Monitor the well for 5 minutes &start TOH laying down the 4-1/2" Upper Completion to the pre-rig tubing cut at 8,955' MD. 8. M/U&TIH while picking-up drill pipe with the 4-1/2"tubing stub fishing assembly. Engage the 4-1/2"tubing stub at 8,955' MD,pull/jar free,&TOH w/fish. L/D BHA&fish. 9. M/U RBP dressed for 9-%"47#casing,TIH, &set at—700' MD. Close the pipe rams& pressure-up against the 9-%" RBP to 1,000 psig to confirm RBP integrity. TOH & L/D running tool. Dump 50'sand on RBP. 10. N/U Dutch Riser, R/U E-Line,&Chemical Cut 9-%"47#L-80 BTC production casing at' 633' MD(middle of next full joint beneath existing JOY casing patch). R/D E-Line&N/D Dutch Riser. 11. M/U &spear 9-3/4"production casing, P/U,close pipe rams,&circulate Arctic Pack out of the OA to kill tanks. 12. TOH &L/D 9-%" production casing to casing cut at^'633' MD(including JOY casing patch set in 1982). 13. M/U RBP dressed for 13-%"72#production casing,TIH, &set at—500' MD. TIH &L/D running tool. 14. M/U test packer dressed for 13-%"72#production casing,TIH, &set at—50' MD. Pressure-test beneath test packer against 13-%" RBP to 1,000 psig to confirm RBP integrity. Release&L/D test packer. 15. Dump 50'sand on top of 13-%" RBP. ✓ 16. N/D BOPE stack. N/D existing FMC Gen II wellhead. Cut-off surface casing mandrel hanger & conductor as needed. N/U new slip-on weld landing ring,weld as per procedure,and N/U FMC Gen V Slip-Lock casing head &BOPE stack. Pressure-test casing head& 13-%"pack-offs. Shell-test BOPE stack to 250/3000 psig. 17. Wash-out sand above RBP. TIH w/retrieval tool for 13-%" RBP, retrieve RBP,TOH,&L/D same. 18. Run new 9-%" 40# L-80 TSH563 w/ Casing Overshot Patch, locate casing stub, latch-on, & pick-up to verify casing stub engagement. a. NOTE: If casing overshot patch is not available,will back-off partial joint of casing&run triple-connect. 19. Pressure-test 9-%"casing to 3,000 psig to verify casing overshot integrity. 20. Pick-up&land 9-3/4"casing in tension within the emergency slips. N/D BOPE. 21. Cut-off-excess 9-%"casing,install pack-off assembly,and N/U FMC Gen V tubing head&BOPE stack. Pressure- test tubing head&9-%" pack-offs. Shell-test BOPE stack to 250/3000 psig. 22. Wash-out sand above RBP. TIH w/retrieval tool for 9-%" RBP, retrieve RBP,TOH,&L/D same. 23. M/U&TIH w/new 3%:"9.3#L-80 TSH563 Injector Upper Completion. 24. Tag the top of the PBR,spot a C.I.brine pill,fully-locate,&space-out 2'from fully-located,mark-pipe at surface, &lay-down two joints. Space-out with tubing pups, M/U tubing hanger, &M/U landing joint. 25. Displace IA to C.I.seawater,stab seals, land hanger,&RILDS. 26. Pressure-test tubing to 3,500 psig,bleed to&while holding 2,000 psig on the tubing, pressure-test IA to 3,000 psig. Rapidly dump the tubing pressure to shear the SOV. Bleed the IA,then the tubing. Perform DDT on each the tubing&the IA. 27. Back-out landing joint, install 3"Type'HP' BPV,&pressure-test to 1,000 psig in the direction of flow. Page 3 of 4 • • ✓ KRU 1B-11 Proposed Rig Workover ConocoPhiflips P&R Tubing and Wellhead Replacement Alaska Original PTD#:181-136 28. N/D BOPE, N/U new 3%8"vertical tree, make-up the Sealing HP Plug-Off tool to the BPV, &pressure-test tree to 250/5,000 psig. Pull the Sealing HP Plug-Off tool&3"Type'HP' BPV. 29. Freeze-protect well through SOV. Set 3"Type'H' BPV. 30. RDMO Doyon 142. Proposed Post-Rig Well Work 1. Pull BPV. 2. RU Slickline. a. Set a catcher sub above the tubing tail plug. b. Swap the sheared SOV for a DV. c. Pull catcher sub&tubing tail plug. d. Set A-1 injection valve. e. RDMO Slickline. 3. Reset well houses&flow lines. 4. Turn well over to Operations via Handover form. Page 4 of 4 KUP INJ • 1 B-11 • ConocoPhiltips ; Well Attributes Max Angle&MD TD r Alaska Ina Wellbore API/UWI Field Name Wellbore Status ncl(°) MD OMB) Act Btm(ftKB) ,-_ ,..mil9r., 500292065700 KUPARUK RIVER UNIT INJ 64.58 10,600.00 10,723.0 ••• Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) -Rig Release Date 1B-11,1/11/2017 23149 PM SSSV:WRDP Last WO: 2/5/2003 31.99 1/20/1982 Vesical schematic(actuaD Annotation Depth(MB) End Date Annotation Last Mod By End Date - - - .. .. ...-......._.... . Last Tag:SLM 10,006.0 7/27/2016 Rev Reason:SET DB LOCK&INJ VALVE pproven 8/4/2016 HANGER;22.8 7�11Mr Casing Strings Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread CONDUCTOR 20 18.936 29.6 80.0 80.0 91.50 H-40 WELDED ". .. .'"' I •IIBICasing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread URFACE 133/8 12.415 29.6 2,614.6 2,242.0 72.00 N-80 BTC Casing Description 'OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread PRODUCTION 95/8 8.681 28.3 9,572.4 6,375.9 47.00 L-80 BTC .-A-,-,CONDUCTOR;29.680.0 Casing Description OD(in) ID(in) Top(kKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread LINER 7 6276 9,260.4 10,698.0 6,930.3 26.00 K-55 BUTT Liner Details la Nominal ID Top(kKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (in) NIPPLE498.6 VALVE;496.0 4 9,260.4 6,206.0 57.37 SLEEVE BAKER SETTING SLEEVE 6.151 9,266.5 6,209.3 57.35 NIPPLE BAKER SEAL NIPPLE 6.151 9,269.8 6,211.1 57.34 HANGER BAKER MC HYD HANGER 6.151 9,282.1 6,217.7 57.31 XO BUSHING BAKER CROSS-OVER BUSHING 6.151' • Tubing Strings Tubing Description Ma...ID(in) Top(ftKB( Set Depth(ft..Set Depth(ND)I...Wt(Ib/ft( Grade Top Connection SURFACE;29.6-2,614.6- TUBING !String 41/21 3.9581 22.91 9,038.71 6 ,08721 12.601 L-80 I NSCT Completion Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (in) 22.9 22.9 0.12 HANGER FMC TUBING HANGER 3.958 GAS LIFT;K925 498.6 498.6 1.17 NIPPLE CAMCO DB-6 NIPPLE;SET Al- INJ VALVE 3.813 8,976.2 6,053.7 57.59 PBR BAKER PBR SIZE 190-47 3.875 11 9,009.4 6,071.5 57.59 PACKER FH HYDROSTATIC PACKER 3.990 9,024.0 6,079.3 57.61 NIPPLE HES X NIPPLE 3.813 PBR;8,976.2 T-•-t. 9,030.8 6,083.0 57.63 OVERSHOT BAKER 8"OVERSHOT(SWALLOW 7),Top of original 4.625 tubing 7037' PACKER;9,009.4 -'"'' TubingDescription String Ma...ID in) Top(ftKB) Set Depth(ft..Set Depth ND p 9 ( p (TVD)(...Wt(Ib/ft) Grade Top Connection ..• TUBING Original 4 1/2 3.958 9,037.1 10,315.6 6,760.2 12.60 J-55 Buttress NIPPLE;9,024.0 Completion Details ■ Top(ftKB) To ND ftKB Top Incl(°I Item Des Com Nominal ID PI 1( ) (in) OVERSHOT;9,030.801 9,065.1 6,101.3 57.70 PBR BAKER PBR 3.920 11/ 9,084.2 6,111.5 57.74 PACKER BAKER'FHL'RETRIEVABLE PACKER 3.920 9,132.0 6,137.1 57.69 NIPPLE CAMCO DB NO GO NIPPLE 3.750 PBR;9,065.1 III 10,303.2 6,754.3 61.76 XO CROSSOVER 4.5x3.5" 3.500 REDUCING PACKER;9.0842 a-" 10,303.9 6,754.7 61.76 LOCATOR BAKER LOCATOR 2.992la. 10,304.4 6,754.9 61.77 SEAL ASSY BAKER SEAL ASSEMBLY 2.992 NIPPLE;9,132.0 = 10,307.2 6,756.2 61.80 SBE SEAL BORE EXTENSION 2.992 Tubing Description String Ma...ID(in) Top(ftKB) -Set Depth(ft..Set Depth(ND)(...Wt(lb/ft) Grade Top Connection INJECTION;9,161.211 TUBING Original1 31/21 2.9921 10,307.2 10,385.51 6,792.71 9.301 J-55 Buttress Completion Details INJECTION;9,244.9 Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (in) 10,307.2 6,756.2 61.80 PACKER BAKER'FB-1'PACKER 4.000 • • 10,309.7 6,757.4 61.83'SBE BAKER SEAL BORE EXTENSION 4.000 10,354.3 6,778.3 62.38 NIPPLE CAMCO'D'NIPPLE 2.750 10,384.5 6,792.2 62.75 SOS BAKER BULL NOSE SHEAR TOOL 2.992 Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) Top(TVD) Top Incl Top(ftKB( (ftKB) (°I Des Com Run Date ID(in) 498.0 498.0 1.17 VALVE 3.81"DB LOCK 8 4.5"A-1 INJ.VLV.W/1.25"BEAN 7/27/2016 1.250 (SERIAL#HYS-258)OAL=34" PRODUCTION;28.3-9.572.4-' Perforations&Slots Shot APERF;9,830.0-9,920.0 Dens Top(ND) Btm(ND) (shotsft Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Com 9,830.0 9,920.0 6,514.1 6,562.1 C-4,C-3,1B- 4/24/1982 4.0 APERF ' APERF;10,066.0-10,106.0 11 10,066.0 10,106.0 6,638.0 6,658.3 C-1,UNIT B, 11/16/19W 4.0 APERF 2 5/8 Jumbo Jet;180 • 1B-11 deg.Perforated tubing) Can't Isolate 10,401.0 10,415.0 6,799.7 6,806.1'Miluveach,1B 4/20/1982 4.0 RPERF 4"HYPERJET II LOCATOR;10,303.9 -11 SEAL ASSY;10,304.4 - 10,431.0 10,489.0 6,813.3 6,839.5 Miluveach,1B 4/20/1982 4.0 RPERF 4"HYPERJET II PACKER;10,307.2 -11 SBE;10,307.2- SBE;10,309.7 ,C.. Mandrel Inserts Iff St ati NIPPLE;10.354.3 -.Fon Top(ND) Valve Latch Port Size TRO Run N, Top(ftKB) (ftKB) Make Model OD(in) Sery _ Type Type (in) (psi) Run Date Com 1 8,925.0 6,026.3 CAMCO MMG 1 1/2 GAS LIFT DMY RK-Ext 0.000 0.0 6/7/2014 6:30 sop;10.384.5 Pkg 2 9,161.2 6,152.7 CAMCO 4.5x3.5 11/2 INJ CV 0.703 0.0 12/23/1982 8:00 RPERF;10,401.0-10,415.0 - - 3 9,244.9 6,197.6 CAMCO 4.5x3.5 1 1/2 INJ CV 0.703 0.0'12/23/1992 5:00 RPERF;10,431.410.489.0 - Notes:General&Safety End Date Annotation 8/9/2010 NOTE:View Schematic w/Alaska Schematic9.0REV 3/13/2012 NOTE:WAIVERED WELL OA x OOA 1/14/2014 NOTE:Mandrel Orientation:#1)5:00,#2)11:30,#3)1:00 LINER;9,260.4-10,698.0 . . C r crio• 1'4 m p�p _ .0 > J D WA"W c, a) m r� ( o Z O Q 3 N + _N a) Q O O Q • Y Cro O O Op L. H T � a Ys E - o p 0. C O LO •.O -o I.:., p c0 4-, CO EM O_ < ' l.9 to 0 CO cO co CO VO O v E t m a o > N _c o c c C. J Q M 7 M '? ? E L'' co G w Ln rn o r 'o O- > v) ZI %.. Q N N M M N - c C N > a) N Z g€ Ov E Ov >. ~< U > t I .� IIII • 0 00 0 0 0 c'o v t 6 }a} W W W W W W 40 O ccv 0 0 F LL LL LL Lc. LL LL 'v) N E 'O h ' 41 C N C0 :... H Q Q Q Q Q Q O. „ c0 c �O cs) O < Z Z Z Z Z Z O N 0 4' U C N LL LL LL LL LL LL L F. U 00 a CO u J--, O _ "" E v c o 0 Lit , Q v O CO i 0 c o Q C v U oO F M a a ) 0r 0d H > > C 'i c, .O U «r. u E H <v t u > Zi W G) O J N 3 o Wti3 it • O cc p y MI 0 , co 0 a 0 2 03 p N Qtx U - RS M 0W N .Z M = _. N sa._,_..,.. c0 t0 n w., p. > 8 zaco 3,3 a) in ch 2 2Lu I13.-1111 W W W W W D 2.4 > > > > > 1;k‘ a) cu z Y Y Y Y Y E E Q Q Q Q Q 'j a) u LT_ a s a a a o o '0 Y Y Y Y Y Uinn T O. O 1:4.4 X N 0 cV V o o cO CO CO l- a; U N. 0 0 0 0 0 NOM � 0" 0 0 0 0 0 0 m 0 0 0 0 0 0CO O ° cio, c.) c) c.) rn E 0 f O — 00No0OWN w 0 0 0 0 0 0 13c LU < < X c6 co IU S 0 0 0 0 0 0 U) S 0 0 0 0 o cO �^ r in cc co v C u) 0 CO CO N v Op E 4 0 CO 0 0 r- N n _'. O N CO CO 0 0 0 N G. N N N N N N U N _ C) O) O C) M M O o o N N N O O d N al 0 0 0 0 — %/�� _ C LI )On in in in u) u) �, 3 y L CL2 re co C G OU C r alal E 'a - u E N > U 02 w 6. cc w ` C �� U d a l V M M O — g Z N E v H 2 Vt ? n w CO W c p Y p E z ` a _= d Q N w N 0 N 4) ra r .•-1 . ^ w Cra @ 8vmd` � I- a aQ /au fe_1( P'rh 16( 134 ,„0 Regg, James B (DOA) From: CPF1 Prod Engr <n1269@conocophillips.com> Sent: Monday, July 11, 2016 5:12 PM (q),, To: Regg,James B (DOA) Cc: NSK Fieldwide Operations Supt; CPF1&2 Ops Supt; CPF1 Ops Supv; CPF1 DS Lead Techs; CPF1 Prod Engr; CPF1 DS Operators; NSK Prod Engr Specialist; NSK Problem Well Supv; CPF1 Control Room; NSK West Sak Prod Engr; Targac, Gary Subject: RE: Update for LPP/SSV defeat on WI wells for CPAI CPF-1 Facility Shutdown Jim, We have completed the CPF1 facility shut down and are in the process of bringing wells online. The low pressure pilot (LPP) on our CFW injector 1B-11 (PTD#181-136(was returned to service today, 7/11/16, with a pilot setting of 700 psig. The well is currently stable at a wellhead pressure of 2000 psi and rate at 9650 BWPD. The well has been removed from the "Facility Defeated Safety Device Log". This notification is in accordance with "Administrative Approval No. CO 406B.001". Please let me know if you have any questions. . Regards, Mitch Autrey / Courtney Gallo CPF1 Production Engineer ConocoPhillips Alaska Office: (907) 659 7493 Voicepage: (907) 659 7000 #765 SCANNED NOV 2 22016 N1269Cconocophillips.cor From: NSK West Sak Prod Engr Sent:Sunday,June 26, 2016 10:01 AM To: Regg,James B (DOA)<jim.regg@alaska.gov> Cc: NSK Fieldwide Operations Supt<n2072@conocophillips.com>; CPF1&2 Ops Sup 2073@conocophillips.com>; CPF1 Ops Supv<n2067@conocophillips.com>; CPF1 DS Lead Techs<n1140 • co•.co•hilli.s.com>; CPF1 Prod Engr <n1269@conocophillips.com>; NSK Prod Engr Specialist<n1139 • conoco. i.s.com>; NSK Problem Well Supv <n1617@conocophillips.com>; CPF1 DS Operators<n1275 • conoco• ' i•s.com>; CPF1 Control Room <n1114@conocophillips.com>; Targac, Gary<Gar .Tar:ac • conocfo illi.s.com> Subject: Update for LPP/SSV defeat on WI wells for CPAI CPF- 'acility Shutdown Jim, The CPF1 facility is shut in, and all water injector ave been shut in and secured as of this morning. The water header pressure has been bled down through CPF-1 -, .ter injection system.All LPP's will be placed in service when the CPF-1 facility is brought online. For the duration of the shutdown, o CFW injector 1B-11 (PTD#181-136)will remain online with the low pressure pilot (LPP) defeated due to pressure flu, uations while doing plant maintenance.The LPP and surface safety valves (SSV) have 1 • 0 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday,November 18,2015 TO: Jim Regg ' i i i 1 g 1(s P.I.Supervisor ICI SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1B-11 FROM: Jeff Jones KUPARUK RIV UNIT 1B-11 Petroleum Inspector Src: Inspector NON-CONFIDENTIAL Well Name KUPARUK RIV UNIT 1B-11 API Well Number 50-029-20657-00-00 Inspector Name: Jeff Jones Permit Number: 181-136-0 Inspection Date: 7/7/2015 Insp Num: mitJJ150903093851 Rel Insp Num: mitop000005528 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 18-11 'Type Inj W TVD 6112 Tubing; 1695 1691 • 1694 1698 PTD; 1811360 Type Test SPT Test psi 3000 - IA 340 3400 3340 3340 Interval Required by Variance 'P/F Pass / OA 65 163 162 161 - Notes: MITIA to 1.2 max anticipated injection pressure per AIO 2B.060. ,— Wednesday,November 18,2015 Page 1 of 1 24 2000 WELL LOG TRANSMITTAL To: Alaska Oil and Gas Conservation Comm. August 12, 2015 Attn.: Makana Bender DATA LOGGED 333 West 7th Avenue, Suite 100 01/1/201s °'. K. BENDER Anchorage, Alaska 99501 RECEWED RE: Multi Finger Caliper(MFC) : 1B-11 SFS' 01. 261J Run Date: 7/21/2015 A 0 a The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Chris Gullett, Halliburton Wireline &Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com 1B-11 Digital Data(LAS), Digital Log file, Casing Inspection Report, 3D Viewer 1 CD Rom 50-029-20657-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline&Perforating Attn: Chris Gullett 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3527 Fax: 907-273-3535 FRS_ANC@halliburton.com Date: Signed: iDvialzozek., eLteat MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: Wednesday,July 08,2015 Jim Regg P.I.Supervisor 11 I5 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC IB-11 FROM: John Crisp KUPARUK RIV UNIT 1B-11 Petroleum Inspector Src: Inspector Reviewed Bp P.I.Supry NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 1B-11 API Well Number 50-029-20657-00-00 Inspector Name: John Crisp Permit Number: 181-136-0 Inspection Date: 7/3/2015 Insp Num: mitJCrl50707110030 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min IB-ll Type Inj TVD Tubing W I Well 6071 2220 • 2225 2260 PTD 1811360 - Type Test SAM Test psi! 1518 IA 3400 . 3440 - 3450 - Interval TREQVAR P/F ' / OA ! 16 16 17 _i Notes: No pumping on annulus Watched for thermal pressure build or stabilization AIO 2B 060 Test result determined to be inconclusive per J Regg ,/ SCANNEC „ f; ;ji`. Wednesday,July 08,2015 Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: Wednesday,July 08,2015 P.I.Supervisor )Selq SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1B-11 FROM: John Crisp KUPARUK RIV UNIT 1B-11 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry JPC— NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT IB-11 API Well Number 50-029-20657-00-00 Inspector Name: John Crisp Permit Number: 181-136-0 Inspection Date: 7/3/2015 Insp Num: mitJCr150707105614 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well IB-11Type Inj W TVD 6071 Tubing' 2245 T 2250. 2250 ' 2255 2255 2230 • PTD Type Test SPT Test SI 1518 IA 3100 3400 3340 3300 ' 3260 3300 - 1 11 6 yP p Interval REQVAR P/F I T OA 15 15 15 15 11 15 15 Notes: .5 bbls pumped for test AIO 2B.060.Test result determined to be inconclusive per J.Regg ✓ z- SCMNHED �r i i.;, Wednesday,July 08,2015 Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg I DATE: Wednesday,July 08,2015 P.1.Supervisor k ? �`�( 15 SUBJECT: Mechanical Integrity Tests l CONOCOPHILLIPS ALASKA INC 1B-I1 FROM: John Crisp KUPARUK RIV UNIT 1B-I1 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry T-Q_-,_ NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 1B-11 API Well Number 50-029-20657-00-00 Inspector Name: John Crisp Permit Number: 181-136-0 Inspection Date: 7/3/2015 Insp Num: mitJCr150707105328 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well'] 1B-11 - Type Inj rW 'TVD 6071 Tubing 2210 - 2250 - 1 2260 - 2240 - 2245 - i PTD 1 1811360 - Type Test SPT(Test psi] 1518 " ! IA 160 3400 = 3280 - ; 3190 = 3100 .— Interval REQvAR P/F I OA I 12 18 1 17 16 1 15 Notes: 6 9 bbls pumped for test AIO 2B 060 Test result determined to be inconclusive per J Regg. Iit Qs,- i r„� SCONEC 0 r, i, Wednesday,July 08,2015 Page 1 of 1 1 Ima ect Well History File Cover e XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file, J S L- / ~ ~ Well History File Identifier Organizing RESCAN Color items: [] Grayscale items: Poor Quality Originals: [] Other: NOTES: /~ Two-Sided DIGITAL DATA [] Diskettes, No. m Other. No/Type OVERSIZED (Scannable) [] Maps: Other items scannable by large scanner OVERSIZED (Non-Scannable) [] Logs of various kinds [] Other BY: BEVERLY ROBIN VINCENT SHERY~VINDY Project Proofing .. BY: ~ROB'IN VINCENT SHERYL MARIA WINDY Scanning Preparation x 30 = '/~- = OTA'PAGES BY: OBINVINCENT SHERYL MARIA WINDY Production Scanning PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: YES NO Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: YES NO DUE TO ~ALI~. ~yS~ABE ~ ~OLO~ I~ES) ReScanned findividuat page [,~pecial afTe~tion] sca,nmg completed) RESCANNED BY: BEVERLY ROBIN VINCENT SHERYL MARIA WINDY DATE: IS~ General Notes or Comments about this file: Quality Checked (dona) 12110/02Rev3NOTScanned.wpd • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, July 26, 2011 TO: Jim Regg c?I P.I. Supervisor f 7 1c) `/ SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1B - 11 FROM: Lou Grimaldi KUPARUK RIV UNIT 1B - 11 Petroleum Inspector Src: Inspector Reviewed By: P.I. SuprvV-- NON - CONFIDENTIAL Comm Well Name: KUPARUK RIV UNIT 1B -11 API Well Number: 50- 029 - 20657 -00 -00 Inspector Name: Lou Grimaldi Insp Num: mitLG110726100813 Permit Number: 181 -136 -0 Inspection Date: 7/5/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well r 1B -11 ' [Type Inj. W TVD 6071 IA 1379 3000 2986 2985 - P.T.D 1811360' TypeTest i SPT Test psi 3000 OA 90 270 270 270 Interval OTHER p/r' P - Tubing 1945 1922 1906 1911 Notes: Test required for AA application. gas /MI ( ?) in annulus. Bled IA until good fluid to surface (1380 -> 785 psi). Pressured up annulus to 3000 psi in two stages due to running out of test fluid. 6.1 Bbl's pumped, 5.0 returned. Fairly stable test. , Tuesday, July 26, 2011 Page 1 of 1 • • m7-721 n --3 SEAN PARNELL, GOVERNOR t ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL AIO2B.060 Mr. Martin Walters Problem Well Supervisor ConocoPhillips Alaska, Inc. 1 Box 100360 A I � j '- 1 Anchorage, AK 99510 -0360 RE: KRU 1B -11 (PTD 1811360) Request for Administrative Approval Dear Mr. Walters: In accordance with Rule 9 of Area Injection Order (AIO) 02B.000, the Alaska Oil and Gas Conservation Commission (AOGCC or Commission) hereby GRANTS ConocoPhillips Alaska Inc. (CPAI)'s request for administrative approval to continue water injection in the subject well. In March 2011, CPAI reported Kuparuk River Unit (KRU) 1B -11 was exhibiting communication between the surface casing and conductor via a thread leak. Since that report, the well's tubing, inner annulus (IA) and wellhead seals have passed all positive pressure tests. A diagnostic MIT -IA was successfully accomplished on March 27, 2011. The Commission finds, based upon reported results of CPAI's diagnostic procedures and wellhead pressure trend plots, that KRU 1B -11 exhibits at least two competent barriers to the release of well pressure. Accordingly, the Commission finds the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. CPAI intends to pursue repair options and will make appropriate application if a viable option is available. AOGCC's administrative approval to continue water injection in KRU 1B -11 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli; 3. CPAI shall perform an MIT -IA every 2 years to 1.2 times the maximum anticipated injection pressure; 4. IA pressure not to exceed 2000 psi; • • AIO 2B.060 July 6, 2011 Page 2 of 2 5. Outer Annulus pressure to be maintained as low as reasonably practicable; 6. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection, and MIT anniversary date remains Jul 06, 2009. An MIT -IA according 8. The MI ann y July g to Condition 3, above, should be conducted prior to July 06, 2011. OIL q„ DONE at Anchorage, Alaska and dated July 6, 2011. �Y o -4 1 •I Al �. Daniel T.. -amount, Jr. ari orman Cathy r. I ��' Chair, Commissioner "o : oner Co issioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • R P C INV ID ConocoPhillips "1a Alaska P.O. BOX 100360 Alaska Gil & cieg C • C ii,fnIIS310t➢ ANCHORAGE, ALASKA 99510 -0360 '.ncferap0 May 25, 2011 Commissioner Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Seamount: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 2B, Rule 9, to apply for Administrative Approval allowing well 1B -11 (PTD 181 -136) to be online in water only injection service with a known OA X Conductor communication. ConocoPhillips intends to pursue repairs should MI injection be desired in the future. If a successful repair is achieved we will request the well be returned to normal status and resume the ability to inject MI. If you need additional information, please contact myself or Brent Rogers at 659 -7224, or Perry Klein / MJ Loveland at 659 -7043. Sincerely, / i/ Martin Walters Problem Wells Supervisor ConocoPhillips Alaska Inc. Attachments • • RECEVED ConocoPhillips Alaska, Inc. 11 t. Kuparuk Well 1B -11 (PTD# 181 -136) ��� # Coo �or1�. d)ission Technical Justification for Administrative Relief Request flctTri Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 2B, Rule 9, to continue water only injection with a known OA X Sealed Conductor leak for Kuparuk injection well 1B-11. Well History and Status Kuparuk River Unit well 1B -11 (PTD# 181 -136) was drilled and completed as a service well in December of 1981 through January of 1982. ConocoPhillips reported to your office on 03/28/11 that WAG and non - hazardous fluid injector 1B -11 was suspected of having a surface casing to sealed conductor leak. Subsequent test have confirmed the suspicion. Diagnostics performed on 4/19/11 indicated a thread connection leak and was visually confirmed between the OC -PO and surface casing. The well was WAGd on 02/27/11 and has been injecting produced water only since that date. The following relevant tests have been completed: Date Test Result Comment 06/24/09 MITIA Passed Witnessed by Jeff Jones 03/26/11 OC POT Passed 03/27/11 MITIA Passed 04/13/11 MITOA Failed 4/13 -19/11 SC Leak Leak determined to be at collar below casing Diagnostics head ConocoPhillips requests that the well remain online should it be needed as an alternate point of non - hazardous fluid injection. ConocoPhillips also requests Administrative Approval which will allow the well to be on water only injection with a known surface casing leak. The well has been added to the monthly report and will be evaluated for repair. Should the repair be feasible and successful the well will proposed to return to "Normal" status. Well Integrity Supervisor 5/25/2011 . • • Barrier and Hazard Evaluation Tubing: The 4 -1/2 ", 12.6 ppf, L -80 tubing has integrity to the packer @ 9009' MD (6072' TVD) based upon a passing MITIA to 2500 psi. Production casing: The 9 5/8 ", 47 ppf, L -80 production casing with an internal yield pressure rating of 6870 psi has integrity to the Packer @ 9009' MD (6072' TVD) based upon a passing MITIA to 2500 psi. Surface casing: The 13 -3/8 ", 72 ppf, N -80 surface casing set at 2615' MD(2242' TVD) with an internal yield pressure rating of 5380 psi does not have integrity based upon a failing MITOA and resulting liquid leak rate and depth determination. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Second barrier: The production casing is the secondary barrier should the tubing or packer fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Any deviations from approved MAOP annular pressures require investigation and corrective action, up to and including a shut -in of the well. T /IO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water injection only (no gas or MI allowed). 2. Perform a passing MITIA every 2 years as per AOGCC criteria (0.25 x tvd @ packer, 1500 psi minimum). 3. IA pressure not to exceed 2000 psi (29% internal yield). 4. OA pressure will be maintained as low as reasonably possible. 5. Submit monthly reports of daily tubing & IA pressures, injection volumes, and any pressure bleeds on any annuli. 6. Shut -in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Workover and /or repair the well prior to gas injection consideration with appropriate AOGCC notification 8. Workover and /or repair the well prior to gas injection consideration with appropriate AOGCC notification Well Integrity Supervisor 5/25/2011 2 As • KUP 1B-11 ConocoPhillips it Well Attributes Max Angle & MD TD Alaska kiC Wellbore API/UWI Field Name Well Status Incl (°) MD (RKB) Act Btm (RKB) ua„xw g 500292065700 KUPARUK RIVER UNIT INJ 64.58 10,600.00 10,723.0 Comment H2S (ppm) Date Annotation End Date KB (R) Rig Release Date • "•" Well Conan - 1B 116/11(M109:52:19AM SSSV: WRDP Last WO: 2/5 /2003 31.99 1/20/1982 Schematic • Actual Annotation Depth (RKB) End Date Annotation Last Mod By End Date Last Tag: 10.083.0 6/5/2006 Rev Reason: FORMAT UPDATE TO 9.OREV Imosbor 8/11/2010 HANGER. 23 "� N. �"" Casing Strings me" Casing Description String 0.., String ID ... Top (RKB) Set Depth (1... Set Depth (TVD) ... String Wt... String ... String Top Thrd ' CON DUCTOR 20 18.936 29.6 80.0 80.0 91.50 H-40 WELDED • Casin D escription String 0... String ID ... Top (RKB) Set Depth (1... Set Depth (TVD)... String Wt... String ... String Top Thrd 1 I SURFACE 133/8 12.415 29.6 2,614.6 2,241.9 72.00 N - 80 BTC Casing Descript 5trinp 0... String 1D ... Top (RKB) Set Depth (1... Set Depth (TVD) ... String Wt... String ... String Top Thrd PRODUCTIO 95/8 8.525 28.3 9,572.4 6,375.8 47.00 L -80 BTC Casing Description String 0 ... String ID ... Top (RKB) Set Depth (1 Set Depth (ND) ... String Wt String . String Top Thrd CONDUCTOR, LINER 7 6.151 9,260.4 10,698.0 6,930 26.00 K -55 BUTT 30 -80 Liner Details Top Depth (ND) Top Intl Nomi... Top (RKB) (RKB) ( °) Rem Description Comment ID (in) VALVE. 498 9,260.4 6,206.0 57.37 SLEEVE BAKER SETTING SLEEVE 6.151 NIPPLE, 499 t 9,266.5 6,209.3 57.35 NIPPLE BAKER SEAL NIPPLE 6.151 IIIII 9269.8 6,211.1 57.34 HANGER BAKER MC HYD HANGER 6.151 9,282.1 6,217.7 57.31 XO BUSHING BAKER CROSS -OVER BUSHING 6.151 Tubing Strings SURFACE, __J L Tubing Description String 0... String ID ... Top (RKB) Set Depth (1... Set Depth (TVD) ... String Wt... String ... String Top Thrd TUBING I 41/2 I 3.500 I 22.9 I 9,038.7 I 6,087.2 I 12.60 L - 80 NSCT 30 -2,815 Completion Details Top Depth (� (ND) Top Inc! Nomi... ( Top (RKB) MB) (°) Kern Description Comment ID (In) GAS LIFT. 1 22.9 22.9 0.12 HANGER FMC HANGER 3.500 8,925 - 498.6 498.6 1.17 NIPPLE CAMCO DBE NIPPLE 3.813 NIB 8,976.2 6,053.7 57.52 PBR BAKER PBR SIZE 190-47 1875 _ 9,009.4 6,071.5 57.59 PACKER FH HYDROSTATIC PACKER 3.990 PBR, 8,976 9,024.0 6,079.3 57.61 NIPPLE HES X NIPPLE 3.813 .- 9,030.8 6,083.0 57.63 OVERSHOT BAKER 8" OVERSHOT (SWALLOW 7), Top of original tubing 7037 4.625 PACKER, 9,009 ^P Tubing Description String 0... String ID ... Top (RKB) Set Depth (1... Set Depth (ND) ... String Wt... String ... String Top Thrd INN TUBING Original 4 1/2 3.958 9,037.1 10,315.6 6,760.4 12.60 J -55 Buttress NIPPLE, 9,024 Completion Details Top Depth (ND) Top Inc! Nomi... OVERSHOT. Top (RKB) (RKB) ( °) kern Description Comment ID (in) 9,031 E 9,065.1 6,101.3 57.70 PBR BAKER PBR 3.920 9,084.2 6,111.5 57.74 PACKER BAKER'FHL' RETRIEVABLE PACKER 3.920 P912. 9,065 9,132.0 6,1372 57.69 NIPPLE CAMCO DB NO GO NIPPLE 3.750 10,303.2 6,754.5 62.48 XO CROSSOVER 4.5x3.5" 3.500 PACKER, 9,084 fei,77:.' _ REDUCING 10,303.9 6,754.9 62.48 LOCATOR BAKER LOCATOR 2.992 ® 10,304.4 6,755.1 62.49 SEAL ASSY BAKER SEAL ASSEMBLY 2.992 NIPPLE, 9,132 `.7....,.' 10,307.2 6,756.4 62.50 SBE SEAL BORE EXTENSION 2.992 Tubing Description String 0... String ID ... Top (RKB) S et Depth (1... Set Depth (TVD) ... String Wt... String ... String Top Thrd INJEC9,161 TUBING Original I 31/2 2.992 I 10,307,2 I 10,385.5 I 6,792.7 I 9.30 I J -55 Buttress [ Completion Details INJECTION, Top Depth 9.245 r (ND) Top Incl Nomi... Top (RKB) (RKB) ( °) Item Description Comment ID (in) 10,307.2 6,756.4 62.50 PACKER BAKER'FB -1' PACKER 4.000 10,309.7 6,757.6 62.51 SBE BAKER SEAL BORE EXTENSION 4.000 10,354.3 6,778.3 62.72 NIPPLE CAMCO 'D' NIPPLE 2.750 10,384.5 6,792.2 62.86 SOS BAKER BULL NOSE SHEAR TOOL 2.992 I Other In Hole ireline retrievable plugs, valves, pumps, fish, etc.) 1 I Top Depth (ND) Top Incl Top (RKB) (RKB) ( °) Description Comment Run Date ID (in) 498 498.0 1.17 VALVE 3.812' A -1 INJECTION VALVE W /.650" ORIFICE set 12/28/2006 1.375 PRODUCTION, i , 12/28/2006 28 -9,572 i APERF, 9,830 -9,920 i ir! erYQn$ & Slots Shot APERF, Top (ND) Btm (TVD) Dens 10,066- 10.106 T op (RKB) Btm (RKB) (RKB) (RKB) Zone Date Oh-. Type Comment INF 9,830 9,920 6,514.1 6,561.5 C -4, C -3, 18-11 4/24/1982 4.0 APERF Illi 10,066 10,106 6,638.0 6,657.9 C-1, UNIT B, 11/16/1990 4.0 APERF 25/8 Jumbo Jet; 180 deg. Perforated 1 - 18-11 tubing! Can't Isolate LOCATOR, ;. 10,401 10,415 6,799.7 6,806.1 4/20/1982 4.0 RPERF 4" HYPERJET II SEAL ASSY, 10,431 10,489 6,813.3 6,839.5 4/20/1982 4.0 RPERF 4" HYPERJET II PACKER. 0,307 68E, 10.3 Notes: General & Safety SBE, 10,310 10 ill End Date Annotaion 8/9/2010 ( NOTE: View Schematic w/ Alaska Schematic9.OREV a NIPPLE, 10,354 � III 508, 10.385 0 RPERF, 10.401 - 10.415 RPERF, 10,431 - 10.489 Mandrel Details Top Depth Top Port (ND) Inc! OD Valve Latch Size TRO Run Stn Top (RKB) (RKB) (*) Make Model (in) Sery Type Type On) (Psi) Run Date Corn... 1 8,925.0 6,026.1 57.42 CAMCO MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 3/4/2003 LINER, 2 9,161.2 6,152.7 57.61 CAMCO 4.5x3.5 - 1 1/2 INJ CV 0.703 0.0 12/23/1982 4 eze0- 10,e98 N " 70, 10,723 3 9,244.9 6,197.7 57.40 CAMCO 4.5x3.5 1 1/2 INJ CV 0.703 0.0 12/23/1992 Well Name 1B-11 Notes: Administrative Approval Application Start Date 2/1/2011 Days 120 End Date 6/1/2011 Annular Communication Surveillance 3500 WHP 180 _ IAP ip\.. OAP — 160 3000 WHT — 140 2500 — 120 • 2000 — 10% . Cr) y N Q. — 80 V 1500 — 60 1000 \1 1--"i\---—/\r—j — 40 500 — 20 0 • 0 Feb -11 Mar -11 Apr -11 May -11 14000 - • �DGI 12000 MGI 10000 - -PWI 0 5 e00o SWI m c1 6000 . �BLPD f 4000 ■Nr.1.1.'MVO"NOIrlig 11.1..1..M.M1 2000 Feb -11 Mar -11 Apr -11 May -11 Date • • Page 1 of 1 Maunder, Thomas E (DOA) From: NSK Problem Well Supv [n1617 @conocophillips.com] Sent: Sunday, April 03, 2011 2:50 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA) Cc: NSK Problem Well Supv; NSK Well Integrity Proj Subject: CPAI Monthly Injector Report - March 2011 Attachments: CPAI Failed MITIA Monthly Data 03- 11.xIs Jim/Tom /Guy, Attached for your records is the ConocoPhillips March 2011 monthly injector report. Wells added to the report: IT -0 is SC feaf ` C 75 \ \ 3B -10 - TxIA communication on 3G-16 - OAxAtmosphere communication - SC leak Wells removed from the report: 2A -06 - P &A Please contact me at your convenience if you have questions or comments. Martin Martin Walters / Brent Rogers Problem Wells Supervisor ConocoPhillips Alaska Inc. Office 907 -659 -7224 Cell 907 - 943 -1720 / 1999 Pager 907 - 659 -7000 #909 APR 1 9 ZOO G 4/17/2011 • • ConocoPhillips Well 1B-11 Injection Data • Tbg Psi IA Psi O OA Psi I 4000 3500 3000 • Vser ~ •.h • • • Ale .2' 2500 cn a 2000 - • i� •• ., .* • 1500 imilladiew EN NI 1000 • YYW 500 •'"• • • 0 r, ,► .NI-w-. YW 12/10 01/1 02/11 03/11 04/11 Date PTD# 181 -178 OAxOOA Communication 03/26/11 - OC POT passed 03/27/11 - MITIA passed • • ConocoPhillips Well 1B-11 Injection Data \ ♦ Water Injection O Gas Injection I 4000 3500 41/04) 3000 OA 0 0 0 :10'.> <> O" a) 2500 fit. -_.. O gC0 O to a S a 2000 1500 • • • y 1000 500 0 0 2000 4000 6000 8000 10000 12000 14000 Injection Rate, bwpd or mscfpd Date of Water Gas Injected Tubing IA Pressure OA Pressure Injected Pressure Injection (bwpd) (mscfpd) (psi) (psi) (psi) ' 662 (1 2r2,11 (1 li 30- Mar -11 4555 0 2009 550 0 29- Mar -11 4565 0 1959 550 0 28 -Mar - I 1 3665 0 1617 550 r. 27- Mar -11 2772 0 1293 900 0 26- Mar -11 2599 0 1326 1000 200 25- Mar -11 3445 0 1746 1200 250 24- Mar -11 4289 0 2012 1200 300 23- Mar -11 4069 0 1960 1550 300 22- Mar -11 4231 0 1994 1600 500 21- Mar -11 4324 0 1993 1400 300 20- Mar -11 4353 0 1987 1400 300 19- Mar -11 4315 0 1982 1200 300 18- Mar -11 4319 0 1925 1200 300 17- Mar -11 4653 0 1920 1200 300 16- Mar -11 4683 0 1948 1450 40 15- Mar -11 4951 0 1945 1450 40 14- Mar -11 5150 0 1954 1550 80 13- Mar -11 4216 0 1823 1550 80 12- Mar -11 3293 0 1593 1350 75 11- Mar -11 3811 0 1862 1500 75 10- Mar -11 4169 0 1863 1450 75 9- Mar -11 4190 0 1965 1350 75 8- Mar -11 4279 0 1964 1300 75 7- Mar -11 4248 0 1953 1250 75 6- Mar -11 4273 0 1949 1250 75 5- Mar -11 4248 0 1936 1600 100 • Page 1 of/ Maunder, Thomas E (DOA) From: NSK Well Integrity Proj [N1878 @conocophillips.com] Sent: Wednesday, March 30, 2011 5:26 AM To: Maunder, Thomas E (DOA) Subject: RE: 3G -16 (PTD 1901040) Report of SC Leak Tom, No, 1B-11 is one of approx 120 older wells that was constructed with a sealed conductor. On this style well, there are no open flutes, no FMC type dust ring, or Tank Co top. The well has internal packoffs sealing the conductor casing from the OA. In these wells we have found that there is no surface casing corrosion at surface since water and oxygen has not been able to leak into the OOA void. With the little diagnostics info that we have now, 1 B -11 appears to be the first of its kind regarding the sealed conductors and suspected failure mode. Perry From: Maunder, Thomas E (DOA) [mailto:tom.maunder©alaska.gov] Sent: Tuesday, March 29, 2011 2:45 PM To: NSK Well Integrity Proj Subject: RE: 3G -16 (PTD 1901040) Report of SC Leak Thanks Perry. Was 1 B - 11 one of those done, but still failed ?? From: NSK Well Integrity Proj [ mailto :N1878 @conocophillips.com] Sent: Tuesday, March 29, 2011 2:35 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: NSK Problem Well Supv Subject: RE: 3G -16 (PTD 1901040) Report of SC Leak Tom, There are additional wells where the surface casing has failed post placement of corrosion inhibitor in the OOA. As the number of total wells with sealant increases, 1225 treated YTD and roughly 1345 total wells, there are 120 wells remaining without sealant. We have observed a noticeable drop in the frequency of SC failures since instituting the sealant program as indicated by the graph below. year 2005 2006 2007 2008 2009 2010 2011YTD # wells treated 2 77 267 296 314 206 63 Sincerely, Perry Klein Well Integrity Projects 907 - 659 -7034 4/18/2011 Page 1 of 1 • Maunder, Thomas E (DOA) From: NSK Problem Well Supv [n1617 @conocophillips.com] Sent: Monday, March 28, 2011 4:43 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA) Cc: NSK Problem Well Supv; NSK Well Integrity Proj; NSK Env Coord Spills Waste Land & Other; CPF1 DS Lead Techs; CPF1 Prod Engr Subject: 1B -11 (PTD# 181 -136) Report Of Suspected Surface Casing Leak Attachments: 1 B -11 Wellbore Schematic.pdf; 1 B -11 TIO Plot.pdf; MIT KRU 1 B -11 03- 27- 11.xls Jim/Tom /Guy, Kuparuk WAG and non - hazardous fluid injector 1B -11 (PTD# 181 -136) is suspected of having a surface casing to sealed conductor leak based upon annular pressure and bleed performance. We have completed an outer casing packoff test and have confirmed surface casing packoff integrity. We have also performed a passing MITIA to establish that there are two barriers with integrity. The well is currently injecting produced water only and will be added to the monthly injector report. ConocoPhillips requests that the well remain online should it be needed as an alternate point of non - hazardous fluid injection until it can be repaired or administrative approval can be obtained for continued water only and non - hazardous fluid injection. Attached are the wellbore schematic, TIO plot, and MIT form. Please contact me at your convenience if you have questions or comments. Martin Martin Walters / Brent Rogers Problem Wells Supervisor ConocoPhillips Alaska Inc. Office 907 - 659 -7224 CeII 907 - 943 -1720 / 1999 Pager 907 - 659 -7000 #909 4/18/2011 Well Name 1B-11 Notes: Report To AOGCC Start Date 12/1/2010 Days 120 End Date 3/31/2011 Annular Communication Surveillance 3500 WHP 180 IAP OAP Al - 160 3000 WHT �� 1 S/ r eIlliii■■■ ,..• - 140 2500 1 J 120 • 2000 y - 10� ' N a3) a? d Ts 1500 80 - 60 1000 ( 1 J \ - 40 - 20 500 0 0 Dec -10 Jan -11 Feb-11 Mar -11 a000 • DGI 12000. -M GI i0000- ■PWI 0 m 8000 . - SWI d 8 000 •BIPD ▪ 4000 1 flOtal■lift.%■% 2000 0 Dec -10 Jan -11 Feb -11 Mar -11 Date 1 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.regq(cilalaska.clov: doa .aocicc.prudhoe.bav(a)alaska.gov phoebe.brooks(a)alaska.aovi tom.maunder(o�alaska.gov OPERATOR: ConocoPhillips Alaska, Inc FIELD / UNIT 1 PAD: Kuparuk / KRU / 1B DATE: 03/27/11 OPERATOR REP: Ives / Mouser - AES AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 11 Type Inj. W TVD 6,072' Tubing 1,150 1,335 1,335 1,335 Interval 0 P.T.D. 1811360 Type test P Test psi 1518 Casing 950 2,500 2,460 2,456 P/F P Notes: Diagnostic MITIA OA 160 140 130 127 Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey T = Test during Workover W = Water D = Differential Temperature Test 0 = Other (describe in notes) Form 10 -426 (Revised 06/2010) MIT KRU 1B - 11 03 27 11.xls . ~ MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: Monday, July 06, 2009 Jim Regg P.L Supervisor ~~7~Z/~~ SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1 B-1 I FROM: Jeff lones xuPaituic iuv vrnT is-i 1 Petroleum Inspector Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv~~ Comm Well Name: KUPARUK RIV LTNIT 1B-11 Insp Num: miUJ090706094656 Rel Insp Num: API Well Number: 50-029-20657-00-00 Permit Number: 181-136-0 ~ Inspector Name: JeffJones Inspection Date: 6/24/2009 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 1B'1~ Type Inj. W TVD 6on IA i22o zsoo 2~6o Z~so P.T.D 1811360 TypeTest SPT Test psi lsi~.~s pA so so so as Interval antTST p~ r i Tubing zo9o zo9o zioo 2iio Notes: 53 BBLS diesel pumped. 1 well inspected; no exceptio~s noted. . . p~ ~i;ti 5i 4; ~ . ~e °~ ~~{~ ~. a 5:; D :+W'~+s ~ ._ .~ ~ ~ G 'J ~J Monday, July 06, 2009 Page 1 of 1 July SVS testing ~ Maunder, ThQm~~ E (D4Aj from; Maunder, Thomas E (DOA) 5ent: Tuesday, July 07, 2QQ9 9:50 AM To; 'PIS1~ Prod Engr SpecialisY Cc: ~leekenst~in, RQbert J (~QA) 3ubjsct: Revised 1 B-9 9, 4Q4 Darrell, Please senc} in the hard copy of the 404. Thanks, Tom Maunder, PE AC?GCC -----priginal Message----- From: Maunder, Thomas E (DOA) Sent: Monday, July 06, 2009 12c38 PNI To: Fleckenstein~ Robert J (DOA) Subjeet: RE: Revised 1B-11, 404 Page 1 of 2 ~ ~3Y~ ~`. , ~,~~,'~4r~~`~~~: ~.,Ur... ~ ~~ ?._OG~ Bob, I took a look at the file and it appears that the packer at 9009 although shown on the completion arawing was never listed on the 404. That packer is the shallow packer whose tvd depth should be used in the MIT calculation, Looking at the directional survey, I estimate that 9009 tnd = 6070 tvd, Looking at the latest MIT in the file I see ~071 was used. `I' om -----0riginal Me;ssage----- From; Fleckenstein, Robert J (DOA) Sent; Monday, July 06, 2009 9;13 AM To: Maunder, Thomas E (DOA) Subject; FW: ~tevised 1B-11, A04 Tom, I don't know why he sent this to me, I may have a5ked him a questio~ on PKRTVD on this well, but I do not remember exactly. I would think he needs to send in a revised 404, I will let you tell him what he needs to send us. Thanks, BobF Robert J. Fleckenstein Statistical Technician II Alaska Oil and Gas Conservation Commission Office; 907-793-1242 Fax: 907-276-7542 *Please note new email address bob.fleckenstein@alaska.gov -----0riginal Message----- 7/13/2Q(l3 July SVS testing • ~ From: NSK Prod Enqr Specialist [ t.a~ ~ Lu .~i~ ~,:t;~~ ~~v~;~s y~i~ ,~ v~~;:l _ __ __ _ _ _ Sent; Saturday, July 04, 2009 4:33 PM To: Fleekenstein, Robert J (DOA) Subject: Revised 1B-11, 404 Bob- Added hydrostatic packer at 9Q09'.,., Do you need a hard copy? Darrell Page 2 of 2 7/1 ~/~~~~ i~~~C~ 1/ CV ~ ~ STATEOFALASKA JI~L O $ ZOO~ ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIOI~ska Dii & Cas Cans. Commissior~ 1. Operations Performed: Abandon ~ Suspend ^ Operation Shutdown ~ Perforate ~ VarianCe nnular Disp. ~ Alter Casing ~ Repair Well ^ Piug Perforations ~ Stimulate ^ Time Extension ^ Other Q Change Approved Program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ Revised wrrt Inj. to WAG 2. Operator Name: 4. Current Well Status: 5. Permit to Drill Number: COnOCOPhIIGps Alaska, IC1C. Development ^ Exploratory ^ 181-136 / ` 3. Address: Stratigraphic ^ Service ~^ 6. API Number: P. O. Box 100360 50-029-20657-00 ~ 7. KB Elevation (ft): 9. Well Name and Number: RKB 98' ` 1 B-11 • 8. Property Designation: 10. Field/Pool(s): ADL0025648 / ALK 466 Kuparuk River Unit / Kuparuk Oil Pool 11. Present Well Condition Summary: Total Depth measured 10723' • feet true vertical 6941' • feet Plugs (measured) Effective Depth measured 9033 feet Junk (measured) true vertical 6228 feet Casing Length Size MD ND ~urst Collapse Structural CONDUCTOR 80' 20" 80' $0' ~~~~~~~ ~~t~ '' SURFACE 2516' 13-3/8" 2614' 2242' PRODUCTION 9474' 9-5/8" 9572' 6376' ~ d ~~1c.t-~~ . LINER 1438' 7" 10698' 6930' ~~ -, + o~~,~~ ~jA~~~ ~~~r ~ ~~~' ~~ . Perforation depth: Measured depth: 9830-9920;10066-10106;10401-10415;10431-10489 true vertical depth: 6514-6562;6638-6658;6800-6806;6813-6839 c~ l '~'~`~--~ Tubing (size, grade, and measured depth) 3-1/2" , J-55, 10384' MD. ~ Packers & SSSV (type & measured depth) pkr= FH Hydrostatic, BAKER'FHL' RETR. ; BAKER'FB-1' pkr= 9009', 9082' ; 10307' SSSV= NIP SSSV= 499' 12. Stimulation or cement squeeze summary: ~~ -~~35~ Intervals treated (measured) N/A Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casin Pressure Tubin Pressure Prior to well operation 3729 60 1946 Subsequent to operation 5540 60 3028 14. Attachments 15. Well Class after proposed work: Copies of Logs and Surveys run _ Exploratory ^ Development ^ Service ~~ Daily Report of Well Operations _X 16. Well Status after proposed work: Oil^ Gas^ WAG ~^ - GINJ^ WINJ ^ WDSPL^ 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. Facempt: Contact B. Christensen/ D. Humphrey Printed Name Darrell R. Hum hrey Title Production Engineering Specialist Signature ~: Q C Phone 659-7535 Date ~, tJ ~~ a,~.~g~Jl -i ~~~ ~~. .~IU~ ~ 4 ~~~9 ~'`~ ~1 /~ Y _ /~ ~7' ~'a ~.~ Form 10-404 Revised 2/2003 • O K I ~., I R~~~ ~d~~~..~SUBMIT IN DU~~~~~ VilV 1. Operations Peñormed: Abandon ,~ ~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSlùN REPORT OF SUNDRY WELL OPERATIONS ø:lAJ-S- ~ ()JAG, 0 Suspend 0 Operation Shutdown 0 Perforate d Variance 0 Annular Disp. 0 0 RepairWell 0 Plug Peñorations 0 Stimulate 0 Time Éxtension < 0 Other 0 < 0 PullTubiog 0 Perforate New Pool 0 Re-enter Suspended Well 0 4. Current Well Status: 5. Permit to Drill Number: Development 0 Explorato;,. 0 181-136/ Stratigraphic 0 SeJVÌGe 0 6. API Number: 50-029-20657 -00 Alter Cásing Change Approved Program 2. Operator Name: ConocoPhillips Alaska, Inc. 3. Address: P. O. Box 100360 7. KB Elevation (ft): RKB 98' 9. Well Name and Number: 1B-11 8. Property Designation: Kuparuk River Unit 11. Present Well Condition Summary: 10. Aeld/Pool(s): Kuparuk Oil Pool Total Depth Effective Depth Casing Structural CONDUCTOR SURFACE PRODUCTION LINER Perforation depth: measured 10723' feet true vertical 6941' feet measured 9033 feet true vertical 6228 feet Length Size MD 80' 20" 80' 2516' 13-3/8" 2614' 9474' 9-5/8" 9572' 1438' 7" 10698' Plugs (measured) Junk (measured) TVD Burst Collapse 80' 2242' 6376' 6930' Measured depth: 9830-9920;10066-10106;10401-10415;10431-10489 RECEIVED APR 2 6 2004 true vertical depth: 6514-6562;6638-6658;6800-6806;6813-6839 Tubing (size, grade, and measured depth) 3-1/2' ,J-55, 10384' MD. Alaska Oil & Gas Cons. t;ummission Anchorage Packers & SSSV (type & measured depth) pkr= BAKER 'FHL' RETR.; BAKER 'FB-1' pkr= 9082'; 10307' SSSV= NIP SSSV= 499' 12. Stimulation or cement squeeze summary: Intervals treated (measured) N/A 13. Treatment descriptions including volumes used and final pressure: Prior to well operation Subsequent to operation 14. Attachments Copies of Logs and Surveys run - Daily Report of Well Operations_X 5540 15. Well Class after proposed work: Exploratory 0 Development 0 Service 0 16. Well Status after proposed work: Oilo GasD WAGQ] GINJD WINJ 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. I Sund;,. Number or N/A if C.O. Exempt: Contact James Rodgers @ 659-7226 Printed Nam~17 ~rt D C ris!ens Title Production Engineering Technician J I Signature ~~ Phone 659-7535 Date 1/12/67 _BFL. ~ftle- ORTt91NA L SUBMIT IN DUPLICATE Representative Daily Average Production or Injection Data Oìl-Bbl Gas.McI Water-Bbl 3729 CasinQ Pressure 60 60 Tubing Pressure 1946 3028 WDSPLD Form 10-404 Revised 2/2003 . 18-11 V "-" DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 04/12104 Cominenced WAG EOR Injection ;$,,:1, f'#~. .&L ~.. ,ôÝ.IJ.l,¡&,JI.< JAMtm9o -~ .. GConocoPhillips Alaska, Inc. 1B-11 KRU 1B-11 PUP (9025-9031, OD:4 PBR (9o63-c..~ OD:45.'.C) PKR (9082-9:.53 0D:8 (9130-9131. OD:5 (9830-~'~,2;,) Fe.'f (10066-101.:,5~ (10401-10415) Perf ¢ 0431-10489) APl:1500292065700 SSSV Type:IWRDP Annular Fluid:I Reference Log:I Last Tag:110055 WLM Last Tag Date:13~4~2003 ICasino String - ALL STRINGS Description CONDUCTOR SURFACE PRODUCTION LINER Tubing String - Pre-Workover Size I Top 4.5OO 3.5OO I 1O319 Well Type:I INJ Orig 11/20/1982 Completion:I Last w/o:12/5/2oo3 Ref Lo9 Date:I TD:i 10723 ftKB Max Hole Angle:165 deg (~ 10600 Size 20.000 13.375 T~p 0 9.625 0 7.000 9260 2614 I 9572 10698 TVD 8O 2242 6376 6930 215/2003 Bottom TVD 10319 6762 10106 6658 10384 6792 Angle (~ TS:158 deg @ 9828 Angle @ TD:I65 deg @ 10723 I Rev Reason:lTag, GLV, Pull IRHC, set Inj VIv Last Update:J3/5/2003 i w, I Grade Thread 91.50 I H-40 72.00 I N-80 47.00 I L-80 26.00I K-55 Thread Perforated Tubing Wt IGrade 12.60 I J-55 12.60 I J-55 9.30 I J-55 : Wt Grade 12.60 I J-55 Tubing:string -TUBING : 4.500 0 9030 6083 Interval TVD Iz°ne IstatusI Ft ISPFIOate I TYPe I Comment 9830-9920 6514-6562 IO-4,O-3 I Open 1901 4 I / I 10066-10106 6638-6658 I C-I,UN~T I Open 14o I 4 111/16/199ol IPERF 125/8Jumbo Jet; 180deg. I S I I I I / I Perforated tubing! Can't I I I I I / IIs°late 10401-104156800-6806I I Open 1141 4 I / I 10431-104896813-6839I I Open 1581 4 I / I :Gas: Eift ~Mandrel~:Nal,ves:: ;:: ::::;: :::,: :; : stI MO I TVD I Man I Man I V Mfr I V Type I V OD I Latch I .crt I TRO I Date I VIv Mfr Type Run Injection. Mandrels/Valves , · ...... · stI MD I TVDI Man I Man I V Mfr IV Type IV OD I Latchl Port I TRO I Date I Vlv I I IM'EI Pel I I I I [ l"un °mnt 2 9161 6153 Camco 4.5X 1.5 CV 1.5 0.703 0 2/23/198 Open 3 I 92451 61981Camco I 4.5Xl.5 I I cv I 1.5 I I 0.703 I 0 p2/23/198;~ open ~qu P;i etc;~:;JEWEER¥:::' :::: : :: ::.. : ::: ::: :::;:: ::;: :: .:::: Type Description ID VALVE 3.812" A-1 INJECTION VALVE WI1.375" ORIFICE SET 31412003 1.375 DepthI TVD , 499 1499 499 I 499 8976 16054 9009 16o71 9024 16079 9025 16080 9031 16083 NIP PBR PACKER NIP PUP OVERSHOT CAMCO 'DB-6' NIPPLE BAKER PBR SIZE 190-47 'FH' HYDROSTATIC PACKER HES 'X' NIPPLE BAKER 8" OVERSHOT (SWALLOW 7'), TOP OF ORIGINAL TUBING STUB 9032 3.813 '3.875 3.990 3.813 3.875 4.625 Description I D PBR Baker 3.920 PKR Baker 'FHL' RETR. 3.920 NIP 3.750 Camco 'DB' Nipple NO GO PKR Baker 'FB-I' NIP Nipple NO GO SOS Baker 'I-FL 4.000 2.750 2.992 : 2.992 i'"'"oat~ ""1 Note 2/5/2003 IWORKOVER-JEWELRY ABOVE OVERSHOT NEW MAY 0 8 2003 Alaska Oil & Gas Ce.._t fA_ . Anchorage MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission i?X_Ct~ TO: Randy Rueddch Commissioner ,d~,~\ THRU: Tom Maunder Petroleum Engineer DATE: April 29, 2003 FROM: Lou Grimaldi Petroleum Inspector NON- CONFIDENTIAL SUBJECT: Mechanical Integrity Tests Conoco\Phillips I-B pad 1B-11, PTD #181-1360 KRU Kuparuk River Field Packer Depth Pretest Initial 15 Min. 30 Min. P.T.D.I 1811360 TypetestI P ITestpsil 1518 I Casingl 5 I 22001 21401 21301 P/F I P I Notes: Initial test. I Type INJ. Fluid Codes F = FRESH WATER INJ. G = GAS I NJ. 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 Test's Details Interval I= Initial Test 4= Four Year Cycle V= Required by Variance W= Test during Workover O= Other (describe in notes) I arrived lB pad with the test crew and started rigging up. The MIT test was begun shortly thereafter. The test went well with the above results showing good IA integrity. M.I.T.'s performed' One Attachments: Number of Failures: None Total Time during tests: 1.5 hours cc: Jerry Detlefs MIT report form 5/12/00 L.G. 2003-0429_M IT_KRU_I B- 1 l_lg.xls 5/7/2003 ~Re: Eu, paruk 1 B-11 i' ,, Subject: Re: Kuparuk 1B-11 ' , Date: Tue, 29 Apr 2003 16:10:50 -0800 From: Lou Grimaldi <lou_grimaldi@admin.state.ak.us> Organization: aogcc To: Tom Maunder <tom_maunder@admin.state.ak.us> Hi Tom, I have a schematic and will fax it right now. Do you want me to mention this in my report? Lou Tom Maunder wrote: > Lou, > I checked the well file. The sundry was issued 3/11/02. It appears > that the original completion was a dual packer with one down in the > liner and the upper one in the casing at about 9000'. They seem to have > set a new packer at the same general depth. I cannot tell from the > reports how much of the old completion was pulled. There is mention of > a cut, but I can't tell if that was fished. They may have employed a > "stacker packer" arrangement. I have put a call in to Randy Thomas to > get a revised well drawing. > Did they have a well drawing there foryou?? > Catch you later. > Tom 4/30/2003 9:01 AM iC, OniOCOPhillips Alaska,/nc, ¢ PUP (9025-9031, 0D:4.530) PBR (906~64. 0D:4.500) PKR (9082-9083, 0D:8.469) FlIP (9130-9131, 0D:5;450) (9830-9920) Perf (10066-10106) Perf (10401-10415) (10431-10489) KRU 1B-11 APl:1500292065700 SSSV Type1 WRDP Annular Fluid:I Reference Log:I Last Tag:~ 10055 WLM Last Tag Date:13/4/2003 Icasi~$~i~'~!ALLiSTRINGS · . Description ISize I TM CONDUCTOR I20.000 I 0 SURFACE I 13.375I 0 PRODUCTION I 9.625 I 0 LINER I 7.000 I 9260 Well Type:I INJ Orig 11/20/1982 Completion:I Last W/O: 12/5/2003 I Ref Log Date:I TD:110723 ftKB Max Hole Angle:165 deg (~ 10600 Tubin~ 'string - Pre-Workover 21512003' 4. 500 9031 10319 4.500 10066 10106 3.500 10319 10384 ';:TUBING" '.:' *' ' !". ': '."." ' Size Bottom I 4.500 0 9030 Interval TVD 9830-9920 6514-6562 10066-10106 6638-6658 10401- 6800-6806 Angle (~ TS:158 deg @ 9828 Angle @ TD:I6~ deg @ 10723 I Rev Reason:lTag, GLV, Pull I RHC, set Inj VIv Last Update:13/~/2003 Boffom 'rVD 80 80 2614 2242 9572 6376 1O698 693O 72.00 47.00 26.00 10431 10489 6813-6839 J Gr.ade 1' Thread H-40 ~ N-80 I L-.'8 0 I K-55 I TVD I Wt IGrade I Thread 6762 I12'60 I J-55 I 6658 I12'6° I J-55 I Perf°rated Tubing 6792 19.30 I J-55 I .... . ' . . . TVO I Wt I'ora;:l'eI Tiiread 6o83 I 12.60 I J-55 I Comment Vlv Cmnt 2 5/8 Jumbo Jet; 180 deg. Perforated tubingl Can't Isolate VIv Cmnt Description VALVE 3.812" A-1 INJECTION VALVE WI1.375" ORIFICE SET 3/4/2003 ID t.375 NIP CAMCO 'DB-6' NIPPLE 3,813 PBR BAKER PBR SIZE 190-47 3.875 PACKER 'FH' HYDROSTATIC PACKER 3.990 NIP HES 'X' NIPPLE 3.813 PUP 3.875 OVERSHOT BAKER 8" OVERSHOT (SWALLOW 7'), TOP OF ORIGINAL TUBING STUB 9032 4.625 Description I D PBR Baker 3.920 PKR Baker 'FHL' RETR. 3.920 3.750 NIP Camco 'DB' Nipple NO GO PKR Baker 'FB-I' 4.000 NIP Camco 'D' Nipple NO GO 2.750 SOS Baker 2.992 TrL :General Notes IDate INote 2/5/2003 I WORKOVER - JEWELRY ABOVE OVERSHOT NEW PUP ~ 0D:4.500} 0D:4.500) OD:IL409J NIP (9130-9131, 00:5,450} ¢00~t0106} ConocoPhillips Alaska, Inc. lB-11 ' KRU 1B-11 APl: 500292065700 sSSv 'ry;~: WRDP Annular Fluid: J W ell T~:I INJ ,,Completion:J Last W/O: 12~oo3 I. ost Tn 110055WLM I ..... T1~',l':~_~'7..23 ItKB 3/4/2003 I Max..H_ ale ^n.qle.:{ 65 dc'~l ~ 10600 ALL'STRINGS." · ..... · ..... ' ........ ,.. 6?62 6658 6792 Ang~. @ Tb:J~'a~ ~ ~0723 Rev Reas~':JTag, GLV. LRHC, set InJ Vlv Last U~ele',I 3/~003 Thread CONDUCTOR SURFACE PRODUCTION LINI~R :.' Pra~Workover 215/2003 Size Bottom 4.;;00 9031 10319 4.500 10066 10106 3.500 103t.4 10384 I Thread Perforated Tubt~ siz. =ottom J we ..... I wt I~,~de'"""I Thread 4,500 0 9030, 6683 ! t2.60 I J-55 I Interval TVD gH30-9920 6514-6562 -10106 6638-6658 10401-I041 6800-6806 10431-10489 .~13-6839 Gas Lift~MandrelsNalves ::': .... Comment 2 ~8 Jumbo Jet; 100 dog, Pe~lorated tubingt Can'l Isolale action Mandrels/Valves." :.' ..... ' ' .',,, . ..... VIv Cmnt Vlv Cmnt General Notes Note · JEWELRY .......... ' , , Description 3.812" A-1 INJECTION vALvE W/1.375" ORIFICE SET 3/4/2003 ._1 ._375 CAMCO 'DB-6' NIPPLE 3,813 ;3,875 iSAKER PaR SIZE 100-47 'FH' HYDt~OSTATI_C PACKER HES 'X' NIPPLE §" OVERSHOT (SWALLOW 7% TOP OF ORIGINAl. TUBING STUB !9032 - P. re-Workover,.2/5/2003 .. ' , ,. ,.. Descdptlon Baker Bakur'FHL' RETR. Cameo 'OB' N(p=plo NO GO Baker'FB.l' NO GO Baker 3.990 3,813 3,~75 ._ 4.828 .., 3.9~o 3,~20 3,750 4.000 .... 2.750 2.9~2,, 2,992 . , WORKOVER - JEWELRY ABOVE OVERSHOT NEW (10401-I0415) (10431-104891 TOO'd dc~S :~0 ConocoPhillips Randy Thomas Kuparuk Drilling Team Leader Drilling & Wells P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-6830 March 3, 2003 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Report of Sundry Well Operations (APD # 181-136/302-090) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent workover work on the Kuparuk well 1B-11. If you have any questions regarding this matter, please contact me at 265-6830. Sincerely, R. Thomas Kuparuk Drilling Team Leader CPAI Drilling RT/skad 0 4 2003 Alaska Oi[& G~s Cons. Cor~lmissio~ ,C.~? ~ ~ /~, ~ Anchorage STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_ Stimulate _ Plugging _ Pull tubing _XX Alter casing _ Repair well _ 2. Name of Operator ConocoPhillips Alaska, Inc. 3. Address P, O, Box 100360 Anchora~le, AK 99510-0360 5. Type of Well: Development __ Exploratory __ Stratigraphic _ Service XX 4. Location of well at surface 494' FNL, 1141' FEL, Sec. 9, T11N, R10E, UM At top of productive interval (asp's 549298, 5969647) At effective depth At total depth 630' FNL, 788' FEL, Sec. 3, T11N, R10E, UM (asp's 554883, 5974828) 12. Present well condition summary Total depth: measured true vertical 10723 6941 feet Plugs (measured) feet Perforate _ Other _ 6. Datum elevation (DF or KB feet) RKB 27 feet 7. Unit or Property name Kuparuk Unit 8. Well number 1B-11 9. Permit number / approval number 181-136 / 302-090 10. APl number 50-029-20657 11. Field / Pool Kuparuk Oil Pool Effective depth: measured true vertical Casing Length Size CONDUCTOR 80' 20" SURFACE 2587' 13-3/8" PRODUCTION 9545' 9-5/8" LINER 1438' 7" LINER 9260 6652 feet Junk (measured) feet Cemented Measured Depth 432 sx AS II 80' 1600 sx Fondu, 400 sx AS II 2614' 1250 sx Class G 9572' 675 sx Class G 10698' True ve~icalDepth 80' 2242' 6376' 6930' Perforation depth: measured 9830'- 9920', 10066' - 10106', 10401'- 10415', 10431' - 10489' true vertical 6514' - 6562', 6638' - 6658', 6800' - 6806', 6813' - 6839' R CEJV D 'ubing (size, grade, and measured depth) Packers & SSSV (type & measured depth) 4.5", 12.6#, J-55 @ 9030' FH Hydrostatic packer @ 9009' CAMCO 'DB-6' @ 499' MD. HAR 0 4 2003 Al~Lska 0ii & Gas Cons. Commi~mo~ Anchorage 13. Stimulation or cement squeeze summary Intervals treated (measured) N/A Treatment description including volumes used and final pressure 14,¸ OiI-Bbl Prior to well operation N/A Subsequent to operation N/A Representative Daily Averaqe Production or Iniection Data Gas-Mcf Water-Bbl N/A 4400 N/A Shut-In Casing Pressure Tubing Pressure - 1800 - N/A 15. Attachments Copies of Logs and Surveys run _ Daily Report of Well Operations __X Oil __ Gas __ Suspended _ Service _XWater Injector XX 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~~ Title: Well_S Team Leader Rand~v Thomas SCANNED N1AR d 7 2003 3 n , 4S BFL Form 10-404 Rev 06/15/88 · Questions? Call Shane Cloninger 265-6829 Date ~5//'~,~'O ~ Prepared b~/ Sharon AIIsup-Drake 263-4612 ~. 2003 ~ SUBMIT IN DUPLICATE Legal Well Name: 1B-11 Common Well Name: 1B-11 Spud Date: 12/15/1981 Event Name: WORKOVER/RECOMP Start: 1/24/2003 End: Contractor Name: n1334@ppco.com Rig Release: Group: Rig Name: Doyon 141 Rig Number: 1/27/2003 12:00 - 22:00 10.00 MOVE MOVE MOVE Prep rig-move camp & rig from 2G-17 To 1B-11. 11.2 miles 22:00 - 00:00 2.00 MOVE OTHR MOVE Standby to move rig over occupied well. SWS working on well 1B-11. 1/28/2003 00:00 - 02:30 2.50 MOVE OTHR MOVE Continue stanby to move over well. (APC installing bpv & rigging down scaffoling.) 02:30 - 06:30 4.00 MOVE RURD MOVE Lay matting boards-move sub over well & spot complexes-pipeshed & rockwasher. (Accept rig @ 0400 hrs. 1/28/03 Due to wait time.) 06:30 - 08:00 1,50 MOVE RURD MOVE Connect service lines between complexes & pipe shed. 08:00 - 11:00 3.00 CMPLTI~ OTHR DECOMP Rig up lubricator & pull bpv. (problem getting bpv out due to ice) 11:00 - 12:30 1.50 CMPLTN SFTY DECOMP Pre workover meeting & biohazard meeting w/crews & service hands. 12:30 - 20:30 8.00 CMPLTN SLIN DECOMP Rig up hawco slickline unit-lubricator & bop assy. test to 1200#-rih-latch fish & work same loose-fish contains of sws chemical cutter-poh-safety meeting on laying down chemical cutter-lay down same, 20:30 - 22:00 1.50 CMPLTN OTHR DECOMP Change out top drive grabbers-guide & saver sub to 4 1/2" IF. 22:00 - 00:00 2.00 CMPLTN OTHR DECOMP Berm & hardline 400 bbl. tank-rig up to displace diesel & seawater out of well w/ 10,5# mud. 1/29/2003 00:00 - 01:00 1.00 CMPLTN OTHR CMPLTN Rigging up 400 bbL tank & hard line for displacing well. 01:00 - 07:30 6.50 CMPLTN ClRC CMPLTN Displace well w/10,5# mud-recovered 400 bbl. diesel & 220 bbls. seawater-pump @ 8 BPM to overcome holes in tbg. Pump out gas. 07:30 - 08:30 1.00 CMPLTN OBSV CMPLTN Monitor well for flow, 08:30 - 09:00 0.50 CMPLTN OTHR CMPLTN Set BPV. 09:00 - 10:30 1.50 CMPLTN NUND CMPLTN Nipple down tree & adapter flange. 10:30 - 13:30 3.00 CMPLTN NUND CMPLTN Nipple up 13 5/8" 5k bope. 13:30 - 15:00 1.50 CMPLTN NUND CMPLTN Change bottom rams to 4.5", 15:00 - 23:30 8.50 CMPLTN SEQT CMPLTN Rig up & test bope 250-3500k. Blanking plug seal leaking-pull test jt.-install new seal-test hope.Tested all components except bottom rams (unable to close with blanking plug in tubing hanger). Tested floor safety valve, IBOP, upper & lower Top drive IBOPs to 250/5000 psi. Witnessing of test waived by AOGCC Rep. Jeff Jones. 23:30 - 00:00 0.50 CMPLTN OTHR CMPLTN Service rig. 1/30/2003 00:00 - 01:00 1.00 CMPLTN WRKOVR Cut & slip 65' drlg. line. 01:00 - 02:30 1.50 CMPLTN OTHR ;CMPLTN Rig up lubricator & pull BPV. 02:30 - 03:00 0.50 CMPLTN PULL CMPLTN Make up spear & attempt latch up. 03:00 - 04:00 1.00 CMPLTN PULL CMPLTN BOLDS & unhook control line. 04:00 - 05:00 1.00 CMPLTN PULL i CMPLTN Wrong grapples in spear-change out grapples & latch tbg. 05:00 - 06:30 1.50 CMPLTN PULL CMPLTN Pull tbg. hanger to floor-pump dry job-Lay down fishing tools & hanger, 06:30 - 17:30 11.00 CMPLTN PULL CMPLTN Rig up control line spool & lay down 290 jts. 4.5" 12.6~ IJ4S tbg. 1 cut off piece 1 pup & 1 glm. Rig down tools & clear floor. 17:30 - 20:00 2.50 CMPLTN OTHR CMPLTN Change out bottom rams to 5"-pick up test jt.-full body test 250-5k Lay down test jt. & run wear ring. 20:00 - 00:00 4.00 CMPLTN TRIP CMPLTN Make up baker retriev-o-matic packer & 9 5/8" scraper & rih picking up 5" dp. 1/31/2003 00:00 - 00:30 0.50 CMPLTN CIRC WRKOVR Circ. dp capacity @ 2500', 00:30 - 03:00 2.50 CMPLTN DEQT WRKOVR Attempt to test 9 5/8" csg. @ 2495'-packer failed after several attempts. 03:00 - 04:30 1,50 CMPLTN PULL WRKOVR POH-inspect & lay down packer & scraper-tight hole @ 575'-10k over string wt. (same area as csg. patch) 04:30 - 06:00 1.50 CMPLTN PULD WRKOVR Picking up 5" dp & stand in derrick while waiting on boot baskets. 06:00 - 13:30 7.50 CMPLTN PULD WRKOVR Make up reverse basket & 2 boot baskets w/9 5/8" csg. scraper & rih to 8988' picking up 5" dp. 13:30 - 15:30 2.00 CMPLTN CIRC WRKOVR ;Circ. bottoms up-cycle pumps & utilize boot baskets & reverse basket. 15:30- 16:00 0.50 CMPLTN ClRC WRKOVR ;Tag up on tbg. cut off @ 9032 DPM. 16:00 - 21:30 5,50 CMPLTN PULL WRKOVR Monitor well-pump dry job & poh w/scraper & fishing baskets. 21:30 - 22:30 1.00 CMPLTN OTHR WRKOVR Lay down boot baskets & reverse basket-clean out same-recovered 1 --~ ss band & large cup full of metal shavings. Lay down csg, scraper, Legal Well Name: 1B-11 Common Well Name: 1B-11 Spud Date: 1~15/1981 Event Name: WORKOVER/RECOMP Sta~: 1/24/2003 End: Contractor Name: n1334~ppco.com Rig Release: Group: Rig Name: Doyon 141 Rig Number: 1/31/2003 22:30 - 00:00 1.50 CMPLTN TRIP WRKOVR Make up baker test packer & rih to 3016'. ~1/2003 00:00-00:30 0.50 CMPLTN DEQT WRKOVR Testcsg. 3500~5 mins. ~ 3016'. (2.7bbls. to3500~) 00:30 - 02:00 1.50 CMPLTN TRIP WRKOVR RIH to 6058'. Test csg. 3500~ 5 mins. (4.4 bbls. to 3500~) 02:00 - 03:00 1.00 CMPLTN TRIP WRKOVR RIH to 9032'. 03:00 - 03:30 0.50 CMPLTN DEQT WRKOVR Test csg. ~ 9016' 3500~ 30 mins. (6.2 bbls. to 3500~) no bleed off in 30 mins. 03:30 - 05:30 2.00 CMPLTN CIRC WRKOVR CBU ~ile preparing to lay down dp. 05:30 - 12:00 6.50 CMPLTN PULD WRKOVR Obse~e well-pump d~ job & lay do~ 5" dp & packer. 12:00 - 13:30 1.50 CMPLTN SEQT WRKOVR ~Pull wear ring-change boEom rams to 4.5"-test door seals 250-3500~. 13:30- 14:00 0.50 CMPLT~ OTHR WRKOVR i Rig up csg. tools to run completion. 14:00 - 15:00 1.00 CMPLT~ OTHR WRKOVR Se~ice rig-top d~ve & lay down machine-Clear flor. 15:00 - 16:00 1.00 CMPLTN S~ WRKOVR Fully simulated h2s-rig evacuation d~ll & debriefing. 16:00- 00:00 8.00 CMPLTN RUNT WRKOVR Run 4.5" completion. ~2003 00:00 - 02:00 2.00 CMPLTN RUNT WRKOVR Finish running completion to 9032'. 02:00 - 03:30 1.50 CMPLT~ PCKR WRKOVR Drop ball & set packer ~ 9009'-Shear seal assy. out of PBR. 03:30 - 06:00 2.50 CMPLT~ SOHO WRKOVR Space out-land hange>rilds. 06:00 - 07:00 1.00 CMPLT~ OTHR WRKOVR Lay down landing it. & set BPV. 07:00 -09:00 2.00 CMPLT~ NUND WRKOVR Nipple down bope. 09:00 - 09:30 0.50' CMPLT~ NUND WRKOVR A~empt to nipple up adapter flange-would not go-hanger set 1' to high-lds,s were screwed in on packing. 09:30- 12:00 2.50 CMPLT~ NUND WRKOVR Nipple up bope. 12:00 - 12:30 0.50 CMPLT~ OTHR WRKOVR Pick up landing jt.-bolds-pull hanger out of spool. 12:30- 13:00 0.50 CMPLT~ SEQT WRKOVR ~Test ~pstack2000~Smins. 13:00 - 15:00 2.00 CMPLT~ OTHR WRKOVR Pull hanger to floo>remove crushed control line plugs-install e~emal flush plugs-redress hanger & land same in tbg. s~ol. Hanger set 1" high-visual verification thru tbg. spool gland. 15:00 - 18:00 3.00 CMPLT~ OTHR WRKOVR Meet w/team leaders-expidite t~ls to I~ation. 18:00 - 19:00 1.00 CMPLT~ OTHR WRKOVR Lay down landing jt.-~g up lubricator & pull BPV. 19:00 - 20:00 1.00 CMPLTK PULD WRKOVR Pick up landing jt.-pull & lay down hange>stand back 1 stand 4.5" tbg. 20:00 - 22:30 2.501 CMPLTK PCKR WRKOVR Make up storm packer & set ~ 43'-test packer to 1000~ 5 mins. 22:30 - 00:00 1.50 CMPLTK NUND WRKOVR Nipple down bope-prepare to cut 9 5/8" stump inside tbg. sp~l. ~3/2003 00:00 - 00:30 0.50; CMPLTK OTHR WRKOVR Cut 5" off 9 5/8" csg. stub in well head spool. 00:30 - 02:00 1.50 CMPLTK NUND WRKOVR Nipple up bope & screw into storm packer-body test bope 1000~ 5 mins. 02:00 - 04:00 2.00 CMPLTK OTHR WRKOVR Lay down storm packer-make up 4.5" tbg. & hangeMand same in tbg. spool. ~:00 - 05:30 1.50 CMPLTK OTHR WRKOVR RILDS-lay down landing jt. & set BPV. 05:30 - 06:30 1.00 CMPLTK NUND WRKOVR Nipple down hope. 06:30- 08:00 1.50 CMPLTK NUND WRKOVR Nipple up adapter flange & tree. 08:00 - 09:30 1.50 CMPLTK SEQT WRKOVR Pull BPV-install test plug & test tree & flange 5000~ 5 mins. 09:30 - 10:30 1.00 CMPLTK DEQT WRKOVR Rig up & test tbg. 3500~ 30 mins. cha~ same-bleed tbg. to 1200~. 10:30-11:30 1.00 CMPLTK DEQT WRKOVR Test 4.5" X 9 5/8" annulus to 3000~ 30 mins. cha~same. 11:30 - 17:00 5.50 CMPLTK CIRC WRKOVR Bleed tbg. & shear rp valve in glm-reveme cim. displacing well to seawater 8.6~ thru choke-overdisplace by 250 bbls. to clean hole. SITP 415~ SICP 450~. 17:00 - 20:30 3.50 CMPLTK~ FRZP WRKOVR PJSM-freeze protect well w/150 bbls. diesel down 9 5/8" annulus. 'U' tube diesel. (final SITP 1200~ Final SICP 1200~.) 20:30 - 00:00 3.50 CMPLTK OTHR WRKOVR Rig up lubricator & install BPV-secure well-clean displacement lines & rig down. Clean mud tanks. (Release rig from 1B-11 ~ 2400 0~03/2003.) Date Comment 1 B-11 Event History 01/17/03 01/18/03 01/20/03 01/21/03 01/22/03 TAGGED FILL IN TBG @ 9918' WLM. OBTAINED SBHP @ 9915' WLM. IN PROGRESS. [TAG, PRESSURE DATA] DRIFTED TBG (3.79") TO DB NIPPLE @ 9130' RKB. UNABLE TO PULL DV @ 8987' RKB. SUSPEND JOB DUE TO DETERIORATING WEATHER CONDITIONS. PULLED DV @ 8987' RKB. LOADED IA & TBG W/SW & 2500' DIESEL CAP SET 3.75"DB LOCK W/PLUG BODY @ 9130' RKB. JOB IN PROGRESS. SET 3.75 DBPX PLUG @ 9130' EKD, PX PPG PULLED @ 9130' RKB, DI3PX PLUG PULLED @ 9130' RED, HUNG UP UNDER FLAPPER, CUTTER BAR DROPPED, ALL WIRE RECOVERED. 27' 5" TL FISH. [OPEN- CLOSE A SAND, MIT, FISH] BRUSH & FLUSH, BROACH TBG TO 2126' RED. SET 75 @ 2126' RKB, ATTEMPT RELOCK OUT TRDP @ 2126' RED. 75 STILL @ 2126' RED. IN PROGRESS. [SSSV WORK, FISH] 01/23/03 01/24/03 01/26/03 01/27/03 01/28/03 FMC PACKOFF TEST PASSED PRE RIG WORKOVER. TESTED 9-5/8" PACKOFF @ 3000 PSI FOR 50 MINUTES (PASSED). TESTED TUBING PACKOFF @ 5000 PSI (PASSED). PULLED Z5 L.O.T @ 2126' RKB, FLAPPER APPEARS LOCKED OUT. RECOVERED COMPLETE TOOL STRING & 3.75" DBPX PLUG. DRIFTED TBG 3.74".TO 9130' RKB. NOTE: TBG TIGHT 9037' TO 9061' RKB. IN PROGRESS. [FISH, SSSV WORK] SET 3.75" DBPX PLUG @ 9130' RKB, CMIT FAILED. SET HOLE FINDER ABOVE PLUG @ 9130', BELOW & ABOVE GLM @ 8987', BELOW & ABOVE TBG LEAKS @ 5489 & 5459' ELM (SEE WSR 05/17/01), ALL FAILED. SET H.F. @ 4000', TBG TEST GOOD FOR ONE MINUTE, THEN FAILED. IN PROGRESS. PERFORMED LEAK DETECT LOG TO DETERMINE CASING LEAK AND CHECK INTEGRITY OF THE PACKER. LOG BASELINE PASS FROM SURFACE TO TUBING PLUG AT 120 FPM. LOG UP ANOMALY PASS FROM TUBING PLUG TO 200'. DETECTED LITTLE FLOW BELOW THE PACKER BEHIND THE TUBING. CHC JOB POSTPONED. PULLED DBPX ASS'Y @ 9130' RKB. CONFER W/E-LINE, RIG AND CWG REPS. ROUND UP EQUIPMENT FOR RIG JOB, FISHING E-LINE TOOLS. IN PROGRESS. [FISH] RAN 12' STRING SHOT PRIOR RUNNING CHC. SHOOT INTERVEL 9029' - 9041'. RAN 3-5/8" CHC TO CUT TUBING @ 9039'. TOOL STUCK AFTER FIRING. PUMPING DIESEL DOWN TUBING DID NOT HELP TO UNSTICK THE TOOL. WEAKPOINT BROKEN. 30.5' FISH LEFT IN HOLE. RECOVERED COMPLETE FISH FROM 9027' ELM. [FISH] SCANNED ? 2003 Page 1 of I 2/11/2003 PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August 5, 2002 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7a Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Maunder: Enclosed please find a 10-403 Sundry Notice variance request for Phillips Alaska, Inc., well lB-11. The variance request is for approval for an extension to continue gray water injection with a failed MIT. Also attached is a discussion and action plan. Please call Pete Nezaticky or me at 907-659-7224 if you have any questions. Sincerely, Jerry Dethlefs Phillips Problem Well Supervisor Attachments ORIGINAL RECEIVED AUG O 7 2002 Anchorage 1. Type of request: APPLICATION FOR SUNDRY APPROVALS Abandon_ Suspend_ Operational shutdown _ Re-enter suspended well _ Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Change approved program _ Pull tubing _ Variance _X Perforate _ Other_ 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 5. Type of Well: Development _ Exploratory _ Stratigraphic __ Service~X 4. Location of well at surface 494' FNL, 1141' FEL, Sec. 9, T11N, R10E, UM At top of productive interval At effective depth At total depth 630' FNL, 788' FEL, Sec. 3, T11N, R10E, UM (asp's 549298, 5969647) (asp's 554883, 5974828) 12. Present well condition summary Total depth: measured 10723 feet Plugs (measured) true vertical 6941 feet Effective depth: measured 10094 feet Junk (measured) true vertical 6652 feet Casing Length Size Cemented CONDUCTOR 80' 20" 432 sx AS II SURFACE 2516' 13-3/8" 16oo sx Fondu, 400 sx AS II PRODUCTION 9474' 9-5/8" 1250 sx Class G LINER 1438' 7" 675 sx Class G LINER 6. Datum elevation (DF or KB feet) RKB 98 feet 7. Unit or Property name Kuparuk Unit 8. Well number 1B-11 9. Permit number / approval number 181-136 10. APl number 50-029-20657 . 11. Field / Pool Kuparuk Oil Pool Measured Depth True vertical Depth 80' 80' 2614' 2242' 9572' 6376' 10698' 6930' Perforation depth: measured true vertical g830'-9920',10066'-10106',10401'-10415',10431'-10489' 6514'-6562',6638'-6658',6800'-6806',6813'-6839' R, ECS VE? Tubing (size, grade, and measured depth Packers & SSSV (type & measured depth) 4-1/2", 12.6#, J-55 Tbg @ 10319' MD; 3-1/2", 9.3#, J-55 Tbg @ 10384' MD. i~;Li(~ I.~ T 2002 BAKER 'FEE' RETR. @ 9082' MD; BAKER 'FB-I' @ 10307' MD; Alaska 0JJ CAMCO WRDP-1; SET ON 11/21/90 @ 2126' MD. BOP sketch'~_ 13. Attachments Description summary of proposal __X 14. Estimated date for commencing operation I 16. If proposal was verbally approved I Oil __ Name of approver Date approved Service 17. I hereby certify that the foregoing is true and correct to the~best of my knowledge. Signed ~~ ~' ~) '~~ Title: Problem Well Supervisor Jer~De~tSlefs ~'-- ""~ FOR COMMISSION USE ONLY Detailed operations program 15. Status of well classification as: Gas __ Water Injector Conditions of approval: Notify Commission so representative may witness Suspended_ [ Appr°val n°~'~:~ Z .-. ~ ~ Plug integrity _ BOP Test __ Location clearance _ Subsequent form required 10-. Mechanical Integrity Test _ Approved by order of the Commission ~-~-,_'ii~ Oechsli TayIo~ Commissioner Date Form 10-403 Rev 06/15/88 · ORiGiNAL SUBMIT IN TRIPLICATE UNDERGROUND INJECTION CONTROL PR(OGRAM ALASKA OIL AND GAS CONSERVATION COMMISSION Authorization to Inject with an Integrity Loss Sundry application 7~Q)~)-~c~C5. for well ¥~").~x.) \ ~'<~- \ ~., PTD ~c~,-~(,ois approved to allow the well to remain in injection service. This approval is subject to the following conditions: Confirmed T x IA communication, rate not quantifiable. Water Injection ONLY 4 Daily Pressure (tubing and all annuli) and Rate Monitoring with a monthly report of this information to the Commission. Annual MITIA/LLRT 4 year CMIT T x IA Confirmed T x IA communication, > 10 gpm. Water Injection ONLY Daily Pressure (tubing and all armuli) and Rate Monitoring with a monthly report of this information to the Commission. 2 year CMIT T x IA Production Casing Leak Water Injection ONLY Daily Pressure (tubing and all annuli) and Rate Monitoring with a 2 monthly report of this information to the Commission. Annual MITT Annual CMIT IA x OA IA x OA Communication Water Injection ONLY Daily Pressure (tubing and all annuli) and Rate Monitoring with a 1 monthly report of this information to the Commission. Annual MITT Annual CMIT IA x OA Alarm w/injection shutdown on OA. Set point minimum 1000 psi < minimum burst strength of outside casing. This approval is specific for the identified integrity loss. Should pressure/rate monitoring indicate a change in the well conditions, the following applies: Type 4 changes to Type 3, notify Commission on next business day and secure permission to continue operations. If well already has Type 4 or 3 integrity loss and monitoring indicates Type 2 or 1 may have developed, secure well immediately and notify the Commission on the next business day. By Order of the Commission Phillips Alaska, Inc. Kuparuk Well 1B-Il SUNDRY NOTICE 10-403 VARIANCE REQUEST 08/05/02 The purpose of this Sundry Notice variance request is for approval to continue gray water injection with a failed MIT. DS lB-11 is the Kuparuk Camp gray water injection well that failed a MIT on 03/02/01. The AOGCC approved continued injection into the well on Sundry #301-24 l~on 8/17/01, which will expire on 08/16/02. The intent is to continue injection until a workover, currently scheduled for October 2002. Due to possible unforeseen changes in the rig schedule the extension is requested for a 6-month period. The following Action Plan is proposed to support the variance request for continued injection: ACTION PLAN / 1. Well will be used for KOC gray water injection (water flood);' 2. Extend approval for injection for up to 6-months until a workover is performed. Extension will be effective through 02/16/03; ~ 3. Shut-in the well should annular pressures or injection rates and pressures indicate further / problems. NSK Problem Well Supervisor 12/11/00 PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 C. R. Mallary Phone (907) 265-6434 Fax: (907) 265-6224 March 5, 2002 Ms. Cammy Oechsli Taylor Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501 Subject: lB-11 Application for Sundry Approval (APD 181-136) Dear Commissioner: Phillips Alaska, Inc. hereby files this Application for Sundry Approval to workover the Kuparuk well lB-11. If you have any questions regarding this matter, please contact Skip Coyner at 265-6074. Sincerely, /q/~ C. R. Mallary U Drilling Engineering Supervisor PAI Drilling CRM/skad Alaska Oil & Gas Cons. Commission Anchorage STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon_ Suspend_ Operational shutdown _ Re-enter suspended well _ Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Change approved program _ Pull tubing _X Variance _ Perforate _ Other _ 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchora~le, AK 99510-0360 4. Location of well at surface 494' FNL, 1141' FEL, Sec. 9, T11N, R10E, UM At top of productive interval At effective depth At total depth 630' FNL, 788' FEL, Sec. 3, T11N, R10E, UM 5. Type of Well: Development __ Exploratory __ Stratigraphic __ Service X (asp's 549298, 5969647) (asp's 554883, 5974828) 6. Datum elevation (DF or KB feet) RKB 98 feet 7. Unit or Property name Kuparuk Unit 8. Well number 1B-11 9. Permit number/.,.approval number 181-136' 10. APl number 50-029-20657 11. Field / Pool Kuparuk Oil Pool 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length CONDUCTOR 80' SURFACE 2516' PRODUCTION 9474' LINER 1438' LINER 10723 feet Plugs (measured) 6941 feet ~ 10094 feet Junk (measured) 6652 feet Size Cemented 20" 432 sx AS II 13-3/8" 1600 sx Fondu, 400 sx AS II 9-5/8" 1250 sx Class G 7" 675 sx Class G Measured Depth 80' 2614' 9572' 10698' True ve~icalDepth 80' 2242' 6376' 6930' Perforation depth: measured 9830' - 9920', 10066' - 10106', 10401' - 10415', 10431' - 10489' true vertical l'ubing (size, grade, and measured depth Packers & SSSV (type & measured depth) 6514'-6562', 6638'-6658', 6800'-6806', 6813'-6839' 4-1/2", 12.6#, J-55 Tbg @ 10319' MD; 3-1/2", 9.3#, J-55 Tbg @ 10384' MD. BAKER 'FHL' RETR. @ 9082' MD; BAKER 'FB-I' @ 10307' MD; CAMCO WRDP-1; SET ON 11/21/90 @ 2126' MD. 13. Attachments Description summary of proposal __X Detailed operations program __ BOP sketch __ Schematic __X 15. Status of well classification as: 14. Estimated date for commencing operation April 1, 2002 16. If proposal was verbally approved Name of approver Date approved Oil _ Gas _ Service _ X' Water Injector Suspended_ 17. I hereby certify that the foregoing is.J~ue and correct to the best of my knowledge. Signed ~--~' E~('~'~{~/,~~': Title: Drilling Engineering Supervisor Conditions of approval: Notify Commission so representative may witness '-~.~<30 ~,,.~(~'~> ~-~'¥- Plug integrity _ BOP Test _~ Location clearance __ Mechanical Integrity Test ~ Subsequent form required 10- L-~(~ Questions? Call Skip Coyner 265-607z~ Date Prepared b,v Sharon AIIsup-Drake 263.4612 Approval no.,~C~ Approved by order of the Commission Original Signed By C~.,.,,,y Oecl',sli Commissioner Date ORIGINAL Form 10-403 Rev 06/15/88 · SUBMIT IN TRIPLICATE lB- 11 Workover Spud Date: 2nd Qtr, 2002 Geometry: 20" to 80' 13-3/8" to 2614' 9-5/8" to 9572' 7" Lnr: 9260' - 10698' 4-1/2" to 10319' 3-1/2" to 10384' Baker, FHL PKR at 9082' Baker, PBR at 9063' Baker, FB-1 PKR at 10307 with Iocator seal assembly CMIT passed to 3400 psi on 5/10/2001 Status: Originally drilled and completed in 1982. This well was converted to a Kuparuk A & C injector and it currently serves the grey water disposal well. The well is currently completed with a straddle packer hook up: A tubing leak has developed above the upper packer (5400' - 5500'). The object of this workover is to restore mechanical integrity by replacing the tubing above the upper packer only. A CMIT was done in May 2001. The 9-5/8" casing, the upper packer and the tail pipe plug below all held 3400 psi. Wellhead is an FMC, 5000# Gen II with a 13-5/8" (5M) Tubing Head. The tubing hanger is 4-1/2" The tree is a 4-1/16" (5M)carbon tree. Project Scope: · Pull 4-1/2", J-55, IJ-4S (corroded) tubing and PBR seal nipple · Run new 4-1/2" tubing and new PBR seal nipple. Pre-rig Work: . 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. Flush the tubing (bullhead) with > 150 bbl of seawater. Set a plug in the "DB" nipple below the FHL packer at + 9130' MD. Dump bail "Sluggits" on the plug. Test.the "DB" plug and casing (CMIT) to 3000 psi. Retrieve the dummy GLV from the mandrel at 8987' MD. Circulate the well with seawater through the GLM at 8987' MD. Freeze protect the tubing and IA to + 2200, MD with diesel. Make sure the tubing hanger LDS's can be turned' (backed out). Remove flow riser and gas lift riser. Set BPV in tubing. Remove the well house and scaffolding as required. Ri.q Work: 1. RU Nordic 3. Circulate out the freeze protect fluid. Set a BPV. 2. ND tree. NU BOP's. Test to 250/3500 psi. 3. Lay down the old tubing, SSSV and control line. 4. Make a clean out run with a 3-1/2" stinger and casing scraper. 5. Circulate the casing clean. 6. LDDP 7. Pick up the new completion: I Baker, I 4-1/2", I 4-1/2", I 4-1/2", + 6000' 4-1/2", I 4-1/2", I 4-1/2", I 4-1/2", + 790' 4-1/2", I 4-1/2", I 4-1/2", I 4-1/2", + 2180' 4-1/2", 12' PBR seal nipple 12.6#, L-80, BTC-M pup joint + 10' HES "X" nipple (ID = 3.813") 12.6#, L-80, BTC-M pup joint + 10' 12.6#, L-80, BTC-M tubing 12.6#, L-80, BTC-M pup joint + 10' Camco MMG GLM with an RP shear valve (2500 psi) 12.6#, L-80, BTC-M pup joint + 10' 12.6#, L-80, BTC-M tubing 12.6#, L-80, BTC-M pup joint + 10' HES "X" nipple (ID = 3.813") 12.6#, L-80, BTC-M pup joint + 10' 12.6#, L-80, BTC-M tubing 8. Space out. Displace the IA with seawater and corrosion inhibitor. 9. Sting into the PBR and land the tubing hanger. RILDS. 10. Test the tubing to 3000 psi. 11. Test the IA to 3000 psi. 12. Freeze protect with diesel. 13. Set a BPV. ND BOP's. NU Tree. 14. Test the tree to 4000 psi using a TWC. 15. Replace the BPV. 16. RD Nordic 3. Post-rig Work: o 2. 3. 4. 5. Pull the BPV. RU Slickline. Replace the RP shear valve with a DGLV. Retrieve the CA2 plug from the Camco "D" nipple below the FHL packer. Re-connect flow lines, etc. Re-set the well house. lB - 11 (Current Schematic) SSSV at 2126' MD (1951' TVD) 13-3/8" Casing at 2614' MD (2242' TVD) ,47#, L-80 Casing at 9572' MD (6376' TVD) 4-1/2", 12.6g, J-55, IJ4STubing (Drift = 3.833") GLM w/DGLV at 8987' MD PKR at 9082' MD (6110' TVD) w/PBR Camco "DB" Nipple at 9130' MD (6136' TVD) Liner Perfs: 9830'- 9920' MD 6514' - 6562' TVD Tubing Perfs: 10066' - 10106' MD 6638' - 6658' TVD "FB-I" PKR at 10307' MD (6756' TVD) Liner Perfs: 10401'- 10489' MD 6800' - 6839' TVD 7", 26g, K-55 Liner 10698' MD (6930' TVD) lB - 11 (Proposed Schematic) "X" nipple at + 2200' MD (2.813" ID) 13-3/8" Casing at 2614' MD (2242' TVD) ,47#, L-80 Casing at 9572' MD (6376' TVD) 4-1/2", 12.6g, -80, BTC-M Tubing (Drift = 3.833") GLM w/DGLV at + 8980' MD i --HES "X" niPple at + 9010' MD (2.813" ID) PKR at 9082' MD w/new PBR seal nipple Camco "DB" Nipple at 9130' MD (6136' TVD) Liner Perfs: 9830' - 9920' MD 6514' - 6562' TVD Tubing Perfs: 10066'- 10106' MD 6638' - 6658' TVD "FB-I" PKR at 10307' MD (6756' TVD) Liner Perfs: 10401'- 10489' MD 6800' - 6839' TVD 7", 26g, K-55 Liner 10698' MD (6930' TVD) PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August 13, 2001 Mr. Tom Maunder Alaska Oil & Gas Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 Dear Mr. Maunder: Enclosed please find a 10-403 Sundry Notice variance request for Phillips Alaska, Inc., well lB-11. The variance request is for approval to continue gray water injection with a failed MIT. Also attached is a discussion and action plan and a well schematic. Please call Jerry Dethlefs or me at 907-659-7224 if you have any questions. Sincerely, Peter Nezaticky Phillips Problem Well Supervisor Attachments APPLICATION FOR SUNDRY APPROVALS 1. Type of request Abandon_ Suspend_ Operational shutdown _ Re-enter suspended well _ Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Change approved program _ Pull tubing _ Variance _X Perforate _ Other _ 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 4. Location of well at surface 494' FNL, 1141' FEL, Sec. 9, T11N, R10E, UM At top of productive interval At effective depth At total depth 630' FNL, 788' FEL, Sec. 3, T11N, R10E, UM 5. Type of Well: Development Exploratory _ Stratigraphic __ Service__X (asp's 549298, 5969647) (asp's 554883, 5974828) 6. Datum elevation (DF or KB feet) RKB 98 feet 7. Unit or Property name Kuparuk Unit 8. Well number 1B-11 9. Permit number / approval number 181-136 10. APl number 50-029-20657 11. Field / Pool Kuparuk Oil Pool 12. Present well condition summar Total depth: measured true vertical Effective depth: measured true vertical Casing Length CONDUCTOR 80' SURFACE 2516' PRODUCTION 9474' LINER 1438' LINER 10723 feet Plugs (measured) 6941 feet 10094 feet Junk (measured) 6652 feet Size Cemented 20" 432 sx AS II 13-3/8" 16oo sx Fondu, 400 sx AS II 9-5/8" 1250 sx Class G 7" 675 sx Class G Measured Depth 80' 2614' 9572' 10698' True vertical Depth 80' 2242' 6376' 6930' Perforation depth: measured 9830'-9920',10066'-10106',10401'-10415',10431'-10489' true vertical 6514' o 6562', 6638' - 6658', 6800' - 6806', 6813' - 6839' Tubing (size, grade, and measured depth 4-1/2", 12.6#, J-55 Tbg @ 10319' MD; 3-1/2", 9.3#, J-55 Tbg @ 10384' MD. Packers & SSSV (type & measured depth) BAKER 'FHL' RETR. @ 9082' MD; BAKER 'FB-I' @ 10307' MD; CAMCO WRDP-1; SET ON 11/21/90 @ 2126' MD. RECEIVED 1 5 2.001 Alaska Oil & Gas Cons. Commission Anchorage 13. Attachments Description summary of proposal __X Detailed operations program __ BOP sketch __ 14. Estimated date for commencing operation 15. Status of well classification as: 16. If proposal was verbally approved Name of approver Date approved Oil __ Gas __ Suspended __ Service Water Injector 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~-----~~PeterNezaticky ~,. ~~ ~ Title: Wells Engineer FOR COMMISSION USE ONLY Questions? Call Peter Nezaticky 659-7224 Date 08/13/01 Prepared by Sharon A//sup-Drake 263-4612 Conditions of approval: Notify Commission so representative may witness ~ Approval no_. Plug integrity __ BOP Test _ Location clearance _ . I I ... Mechanical Integrity Test _ Subseqgent form required 10- 'I~,~1~.~.~,~,~ ~a~-\~ {b~{~,[ ORIGINAL SIGNED BY comn~issioner Date Approved by order of the Commission J.M. H~usser Form 10-403 Rev 06/15/88 · ORIGINAL SUBMIT IN TRIPLI CATE Phillips Alaska, Inc. Kuparuk Well 1B-Il SUNDRY NOTICE 10-403 VARIANCE REQUEST 08/13/01 The purpose of this Sundry Notice variance request is for approval to continue gray water injection with a failed MIT. DS lB-11 is the Kuparuk Camp gray water injection well that failed a MIT on 03/02/01. The following diagnostics and actions were taken: · 03/30/01: Established a liquid leak rate of 0.25 bpm while pumping down the IA. The AOGCC was notified at that time of the failure and an action plan for diagnostics was approved. · 05/05/01' Well shut in. · 05/09/01: Set a TTP and passed a combination T x IA MIT (CMIT-T x IA). Initial test pressure was 3450 psi with a loss of 50 psi in 30 min. · 05/17/01: Leak detect log identified leaks in the tubing at 5459 ft and 5489 ft. · 06/15/01: Caliper survey indicated the tubing below the leaks was in poor to fair condition with pitting documented. The diagnostic tests identified 2 leaks in the tubing and the condition of the lower portion of the tubing is in fair to poor condition with pitting. The casing and packer have integrity with no evidence of leaks. The following Action Plan is proposed to support the variance request for continued injection: ACTION PLAN 1. Well will be used for KOC gray water injection. 2. Well is scheduled for rig workover (tubing replacement) at the end of the 1st Quarter of 2002. 3. Shut-in the well should annular pressures or injection rates and pressures indicate further problems. NSK Problem Well Supervisor i 12/11/00 ARCO Alaska, Inc. '~r GKA 1 B-11 ~ = APl: 500292065700 Well Type: INJ Angle {~ TS: 58 deg ~ 9828 WRDP ~l~iiil~ SSSVType: Camco WRDP Odg Completion: 1120/82 Angle ~TD: 65de~ ~ 10723 (2126-2127, Annular Fluid: Last W/O: Rev Reason: Corrections by ImO Reference Lo~: Ref Log Date: Last Update: 415199 0D:3.813) i Last Tag: 10094 TD: 10723 ftKB ? Last Tag Date: 12/6/96 Max Hole Ancjle: 65 deg (~ 10600 casin~l ~tin~], CONDUCT~ Size I Top I Bottom I TVD I Wt I Grade I Thread Size I Top I Bottom I TVD I Wt IGrade I Thread :~ill 13.375 ] o I 2614 I 2242 I 72.00 PBR Size I Top IBott°m I TVD Iwt IGrade I Thread 9,825 I 0 I 9572 I 6376 I 47.00 I L-80 I (9063-9064, C~i~:~iSt~ih.g ~::.Ei~ : ~ ~ : 0D:4.$00) Si=e I Top IBott°m I TVO Iwt IGrade I Thread il 7~000 I 9260 I 1o698 I 893o I 28.00 I K-55 I PKR Size I Top I Bottom TVD I v~ IGrade I Thread B 4.5oo I 0 I 1o319 8782 I 12.80 I d-55 I ~__~_ 3~500 I 1o319 I 103~4 6792 I 9~30 ! J-55 I (9O82-9O83, OD:8.469) :/. ::.:~., ~ ~ .~ ::.. ~... :' Interval TVD Zone Status Feet SPF Date Type Comment :: : 983o- 9920 6514- 6562 c-4,c-3 Open 90 4 10066- 10106 6638- 6658 C-I,UNIT Open 40 4 1/16/9CIPERF 2 5/8 Jumbo Jet; 180 deg. Perforated .o o Ilili! (9130-9131, 10401 - 10415 6800 - 6806 Open 14 4 10431 - 10489 6813- 6839 Open 58 4 Stn MD TVD Man Man V Mfr VType V OD Latch Port TRO Date Vlv M fr Type Run .~om m e n' In~.~on 1 89876060Camco ~ D~ 1.5R~ ~.000 01/20~2 MandrelNalve ~i'i :~ ,, ,,, ,, ,,, ~, , ,,..,.,. , , , 2(9161-9162, .,m .... .... ..... Stn MD TVD Man Man V Mfr V Type V OD Latch Port TKO Date VIv 0D:7.031) Mfr Type Run ;om men' ::~:~ :.::::::: 2 9161 6153 Camco 4.5 X 1.5 CV 1.5 3.703 0 12123182 Open :i:i::::: 3 9245 6198 Camco 4.5Xl.5 CV 1.5 3.703 0 12/23/82 Open . ~:: ~ ~,:~:~ :: : ,,:, ~, , ;;;; ~ ~ ;; ;;;; ;;;; ;;;; ~:: ;:;;::.:::~::;: : · :::::::::.:.:: MandrelNalvelnjecti°n ] o,o, h lTVO, TypeI Description I ID ~ 66381 Perforate IPerforated Tubing; Can't Isolate. I 3.875 3 (9245-9246, i~i I Tubin~l o~..~.0~) ................................................................ ! I i: Depth TVD Type Description ID Perf :i: :ii:ii ::: ::::~::::.=: 2126 1951 SSSV Camco 'TRDP-1A' locked out 3.813 (0~30-9920) :~ 2126 1951 WRD. Camco WRD.-1; Set on 11121190 2.250 ~i i ::i~I~ 9063 6100 PBR Baker 3.920 ::~: :~: 9082 6110 PKR Baker 'FHL' RE'IR. 3.920 !i:.iii!~::~!ii 9130 6136 NO GO Camco 'DB' Nipple 3.750 ~ ~: ~ ~. ::i~i 10307 6756 PKR Baker 'FB-I' 4.000 ??~::i~iiiiii 10354 6778 NO GO Camco 'D' Nipple 2.750 ~: i. ili 10383 6791 SHEAR Baker 2.992 !::' :!::::iii ::: :' ::'=' ..... OUT :. :: i:=': .... i TU~,N~ , i::i 0O319'1O384, 0D:3.500, :.:: ID:2.992) : :ii!,: Perf (1O4O1-1O415) Per[ (10431-1O489) REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed Operation Shutdown__ Pull tubing .. Alter casing Stimulate __ Plugging Perforate ,~ Repair well ....... Other X 2. Name of Operator ARCO Alaska. In(;, 3. Address P. O. Box 100360, Anchorage, AK 99510 5. Type of Well: Development Exploratory Stratigraphic Service 4. Location of well at surface 495' FNL, 1142' FEL, Sec. 9, T11N, R10E, UM At top of productive interval 1114' FNL, 1484' FEL, Sec. 3, T11N, R10E, UM At effective depth 685' FNL, 881' FEL, Sec. 3, T11N, R10E, UM At total depth 631' FNL, 8.03' FEL~ Sec. 3, T11N, R10E, UM 12. Present well condition summary Total Depth: measured 1 0723' true vertical 6942' feet Plugs (measured) feet 6. Datum elevation (DF or KB) RKB ~' 7. Unit or Property name Kuparuk River Unit feet 8. Well number 1B-11 9. Permit number/approval number ~1-136 10. APl number $0-029-20657 11. Field/Pool Kuparuk River Oil Pool Effective depth: measured 1 0 61 9' feet Junk (measured) true vertical 6 8 9 7' feet None Casing Length Size Cemented Measured depth True vertical depth Structural Conductor 8 0' 2 0" 432 SX AS II 8 0' 8 0' Surface 261 5' 13 3/8" 1600 Sx Fondue & 261 5' 2242' Intermediate 400 Sx AS II Production 9 5 7 2' 9 5/8" 1250 Sx Class G 9 5 72' 6 3 7 6' Liner 9560-10698 7" 675 SX CLASS G 1 0 6 9 8' 6 9 31' Perforation depth: measured 9830'-9920', 10401'-10415', 10431'-10489' true vertical 6515'-6563', 6800'-6807', 6814'-6840' Tubing (size, grade, and measured depth) DEC 1 1 1990 4 1/2" J-55, TT @ 10384' Packers and SSSV (type and measured depth) Baker packers FHL @ 9082' and FB-1 @ 10307', Camco WRDP @ 2126Alaska 01[ & Gas Cons. 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure 14. Reuresentative Daily Averaae Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation - 0 - - 0 - - 0 - 7 0 0 2 855 Subsequent to operation ., - 0 - - 0 - 6 0 0 0 2 7 5 2 3 5 0 16. Status of well classification as: Water Injector X Oil _ Gas Suspended 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations X Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Si~ned .~, ~' ~ Form 10-404 Rev 09/12/90 SUBMIT IN DUPLICATE KRU 1B-11 Water injection into 1B-11 began September 10, 1990 with an initial rate of 1666 bbl of produced water per day REEEIVED DEC 1 1 1990 Alaska 0il & Gas Cons. CommiSsio~ Anchorage ARCO Alaska, Inc. ~ · ~.ubs!dta~/of Atlantic Richfield Company i W~LL IPBDT $~-/I /~.z'! /o, ~/~' CONTRACTOR /~:~'IARKS " / .. WELL SERVICE REPORT I FIELD - DISTRICT-STATE /~'/'~,~4/~' ~VZ~ /Z~/E_/_~ !DAYS I Ii IOPERATION AT REPORT TIME/ / , , Anchorage CHECK THIS BLOCK IF SUMMARY CONTINUED ON / I ~/; BACK .,po. ~a *F -- ~0 'FI miles . knots , (r' STATE OF ALASKA ( ALAbr~ OIL AND GAS CONSERVATION COMMISo, ON APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Suspend _ Operation Shutdown /4' Alter casing _ Repair well Change approved program __X_ _ Plugging _ Pull tubing _ _ Re-enter suspended well _ Time extension Stimulate Variance Perforate 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 495' FNL, 1142' FEL, Sec. 9, T11N, R10E, UM At top of productive interval 1114' FNL, 1484' FEL, Sec. 3, T11N, R10E, UM At effective depth 685' FNL, 881' FEL, Sec. 3, T11N, R10E, UM At total depth 631' FNL, 803' FEL, Sec. 3, T11N, R10E, UM 12. Present well condition summary Total Depth: measured 10723' feet true vertical 6 94 2' feet Effective depth: measured 1 0 61 9' feet true vertical 6 8 9 7' feet Plugs (measured) Junk (measured) None 6. Datum elevation (DF or KB) RKB 98' 7. Unit or Property name Kuparuk River Unit feet 8. Well number 1B-11 9. Permit number 81-136 10. APl number 5o-029-20657 11. Field/Pool Kuparuk River Field Kuparuk River Oil Pool Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length Size 80' 20" 261 5' 13 3/8" Cemented 9572' 9 5/8" 9560-10698 7" measured 9830'-9920',10401'-10415', true vertical 6515'-6563', Tubing (size, grade, and measured depth 4 1/2" J-55, TT @ 10384' Measured depth True vertical depth 432 Sx AS II 8 0' 8 0' 1600 Sx Fondue & 2 61 5' 2 2 4 3' 400 Sx AS II 1250 Sx Class G 9572' 6376' 675 sx Class G 1 0698 6931 10431'-10489', 6800'-6807', 6814'-6840' RECEIVED AUG 1 o 19 JO Packers and SSSV (type and measured depth) Baker packers FHL @ 9082' and FB-1 @ 10307', Camco WRDP @ 2126' 13. Attachments Description summary of proposal _ Detailed operation program _ Propose converting well from oil producer to water injector. 14. Estimated date for commencing operation Status of well classification as: . August 15, 1990 oil _ . Gas _ 16. If proposal was verbally approved 15. Name of approver Date approved Service _Water Iniector 17. I here~ ce~ify that the foregoing is true and correct tothe best of my knowledge. Signed . Title FOR COMMISSION USE ®NLY Conditions of approval: Notify Commission so representative may witness Plug integrity __ BOP Test Location clearance Mechanical Integrity Test ~;~ Subsequent form require / ORIGINAL SIGNED BY I n~,~NIE C. SMITH Approved by the order Commission BOP sketch Suspended Date JApproy~al No.. ~x_o,.o~,ct CoPY Commissioner Date O /~ ~' Form 10-403 Rev 5/03/89 SUBMIT IN TRIPLICATE ARCO Alaska, Inc. Post Office 1~':' 360 Anchorage,,~' .;ka 99510 Telephone 907 ."77 5637 RETURN TO: ARCO ALASKA, INC. A_mTN: Records Cler~ ATO-1115B ~. P.O. Box 100360 Anchorage, AK 99510 Transmitted herewith are the following items. Please acknowledge receipt and return one signed copy of this transmittal. o.. CAMCO- ,BHP REP. ORT~/PBU ,,,/1G- ~ lB-3. ~G-2 iA -6 / ~/1C-9 ~B-1! w~E-3 / /2B-4 / 12102, 03~84 12/10,11/84 11/26/84 / 12/08/84 12/12,13/84 10/21,22/84 10/12,14/84 10/10,12/84 10115184 10119/84 10/19/84 TORQUE 'TURN PBU &. TEMP SURVEYS · ? ~-4 12/12, 13/84 Gauge (/64009 1 ~ iE-2 10/15/84 /cat Receipt Acknowledged: DIS TRIBUTION J~ ~ .N 80 '~g""'" RECEIVED B. Currier Drilling W. Pasher State of AK BPAE Geology' G. Phillips Sohio Chevron Mobil Phillips Oil Union D&M NSK Cps. J. Rathmell Well Files ARCO Alaska Inc Is i~ subsldlaty of Atlar, t!cRichtieldComl;;any ARCO Alaska, inc. Post Officr -ox 360 Anchorage, ,laska 99510 Telephone 907 277 5637 Date: 1/07/85 Transmittal No: 4942 RETI/RN TO: ARCO ALASKA, INC. ATTN: Records Cler~ ATO-1115B . 0~ Box 100360 orage, AK 99510 · /~ransmitted herewith are the following items. Please acknowledge receipt and return one signed copy of this transmittal. · -CAMCO .BHP REP. ORT.~/~.~.U : . .. ~T.ORQUE-'TURN PBU &. TEMP SURVEYS 1F-7 /'12/02, 03/84 1F-4 ....... 12/12, 13/84 Gauge #6400! 1G-4 ,L.~ 12/10,11/84 'lB-3 .... ~ 11/26/84 1G-2/ 12/08/84 1E-8. 12/12,13/84 lA-6 ~ 10/21,22/84 1C-9/'10'/12,14/84 ,. 1E-3 ? 2B-4 ,12/84 10/15/84 10/19/84 2B-3 ,' 10/19/84 1E-2 .... 10/15/84 /cat Receipt Acknowledged: B. Currier DISTRIBUTION Date: ..... Alaska Oil & G~s Cons. CommJssJoll /\nchorage W. Pasher State of AK BPAE Geology: G. Phillips Sohio Chevron Mobil Phillips Oil Union D&M NSK Ops. J. Rathmell Well Files ARCO Alaska. Inc. is · subsidiary of AtlantlcRichfleldCcm~any ARCO Alaska, Inc. ', ..;.':c':,~ 9;~7 277 5~37 Return To: · . · ARCO ALASKA, Inc. ATTN: Records Clerk ATO-1115B P.O. Box 100360 Anchorage, AK 99510 Date: 10/08/84 Transmittal No: 4759 PAGE 1 of 2 ~/Tr ' ansmitted herewith are the following items. Please acknowledge receipt and return one signed copy of this transmittal. P~U~VEYS/PRESSU~ ANALYSZS ~-~IA-2 5/11,12/84 Torque Turn (Pressure & Temp Surveys) .......................... ~iA.---6.._ 7/00/84 Camco ~%~,.~ ~' c i~/ /1B-11..~? 7/10,12/84 ~_712_~.__ ...................... >-iAii0 5/i0/84 /lC-1 12/17/83 zlC-6 8/04/84 /_IG-IO- ' 12/21/83 12/23/83 8/11/84 5/21/~ / !G=3_ 6/26/84 ~o;~,~ s/Bo/s4 ~!q-6'. 8/11/84 ~G~~ 6/28/84 /~-4 12/27/83 .- . ~ tY-5 12/14/83 ~ 1Y-7 12/15/83 / ~;1 7/03/84 /%~/1 4/10/84 Csmco Otis Otis Otis Camco Camco Otis Camco Static Torque~ Turn (Pressure & Temp Surveys) Camco Static HP Static C~mco Camco Camco Camm Otis Otis Otis Otis Otis Camco Re ceip 7 ~actnowledg e d: B. Adams · F.G. Baker P. Baxter BPAE Chevron Date: DISTRIBUTION D&M Drilling Geology Mobil NSK Operations W.V. Pasher G. Phillips Phillips Oil J.J. Rathmell R & D C. R. Smith Sohio Union Well Files , .. ;'i',Cr,,.:. 277 $~57 Date: 10/08/84 Transmittal No: PAGE 2 of 2 Return To: · . . ARCO ALASKA, Inc. ATTN: Records Clerk ATO-1115B P.O. Box 100360 Anchorage, AK 99510 smitted herewith are the followiug items. and return one signed copy of this transmittal. 4759 Please acknowledge receipt '~2~_~91~' 5/28/84 11/09/83' 2C-2 11/09/83 2C-6 11/08/83 2C-7 11/08/83 . 2~ .C- ~ 4/18/83 -~'~ 4/24/83 (2C~ 4/22/83 '~~ 4/30/83 ~3 4/28/84 4/29/84 _5-~ 5/04/84 5/06/84' 2X-5 8/12/84 5108.184 · ,..,, 3C-6 5719184 3C-6 5/17/84 .. Otis Lynes 'Lynes Lynes Lynes Camco Camco Camco Otis C_~n~_o Camco Dresser Otis Otis Camco DrESser Dresser PBU Flow Survey (Gradient). Static Gradient Mini Drawdown & BUild~ Survey .' / /cat Receipt Acknowledged: Date: DISTRIBUTION B. Adams F.G. Baker P. Baxter BP;£ D & M Drilling Geology Mobil W.~. Pasher G. Phillips Phillips Oil J.J. Rathmell C. R. Smith Sohio Union Chevron NSK Operations R&D Well Files MEMORA OUM State of Alaska ALASKA OIL AND GAS CONSERVATION COMMISSION TO: File DATE: August 27, 1984 FILE NO: A. Se. 5 TELEPHONE NO: FROM: Petroleum Engineer SUBJECT: Well History, Kuparuk River Unit Well No. 1B-11GI. The well was completed as a gas injector on January 31, 1982. On February 24 and 25, 1982, an attempt was made to clean out the well bore which had perforations from 10,401' to 10,415' and 10,431' to 10,489' in the "A" sands (lower Kuparuk). The attempt was unsuc- cessful. An attempt was made to inject gas following the attempted clean-out. For several hours, an injection rate of approximately 25 MMCFPD was maintained. The injection was halted when an increase in pressure was noticed in the 13 3/8" x 9 5/8" annulus. On April 1, 1982, a workover rig co~enced repairs. Tests confirmed that the 9 578" casing leaks were a~ove 473'. New casing was run from surface to 589' and was tested to 3,000 psi. The erforated interval from 10,401' to 10,415' and from 10,431' to 0,489' was reperforated and acidized ~ith 66 3/4 BBLs ~cid. The well flowed 3 to 5 MMCFPD of dry gas at a stabilized pressure of 2,000 psi after the acid job. The well was then perforated from 9,830' to 9,920' before the rig was released on April 29, 1982. On May 2, 1982, gas injection into the "A" sand commenced. A total of 329 MMCFG was injected from Mmy 2 to May 29, 1982. Injection rates varied from 16 MMCFGPD at the beginning of this period to about 5 MMCFGPD on the 29th. Wellhead pressure was about 3975 psi during this period. From May 29, 1982 to June 26, 1982, gas was injected into both the "A" and "C" sands. Average injection rate during the month of June, 1982 was 13.25 ~MCFPD. From June 27, 1982 to December 23, 1982, gas was injected into the "A" sand only. A total of 609.6 }.~CFG was injected at an average rate of about 3.4 MMCFGPD. Wellhead pressure during this period generally ranged between 3,700 and 3,800 psi. On December 24, 1982, a dummy gas lift valve at 9,245' was replaced with a circulati~_g valve. Since that date, gas has been injected into both the "A" and "C" sands. Gas injection rates have varied from 8 to 17 MMCFPD with wellhead pressures generally between 3,700 and 3,800 psi. ( STATE Of ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION SUNDRY NOTICES AND REPORTS ON WELLS DRILLING WELL I--I COMPLETED WE LL ;[~ 7 Permit No 81-136 8 APl Number 50- 029-20657 9. Unit or Lease Name 2. Name of Operator ARCO Alaska, Inc. 3. Address P. 0. Box 100360, Anchorage, AK 99510 4. Location of Well Surface: ~95' FNL, 11~2~ FEL, Sec. 9, T11N, RIOE, UN Kuparuk 256~8 10. Well Number 1B-11GI 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. 93' RKB 12. Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data 11. Field and Pool Kuparuk River Field Kuparuk River 0ii Pool NOTICE OF INTENTION TO: (Submit in Triplicate) Perforate [] Alter Casing [~ Perforations Stimulate [] Abandon [] Stimulation Repair Welt [] Change Plans [] Repairs Made Pull Tubing [] Other [] Pulling Tubing SUBSEQUENT REPORT OF · (Submit in Duplicate) [] Altering Casing [] Abandonment Other (Note: Report multiple completions on Form 10.407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-17Oh Accepted rig ~ 1900 hrs, 0~/01/82. Bled pressure from tree. Pulled BPV. RIH w/bridge plug & set ~ 9325'. Tstd tbg to 2800 psi - ok. Bled pressure off tbg & observed we]] - we]] dead. Closed SSSV & set BPV. ND tree. NU BOPE & tstd to 5000 psi - ok. Pulled tbg & LD. RIH w/RTTS to isolate a leak in the 9-5/8" csg. Set tools (~ 98', 160', 222', 28~', 3~,6', ~08', ~70' & pressured 9-5/8" x 3-1/2" ann to 1500 psi - no pressure on 13-3/8" ann. Pressure tst, d @ ~70' down 9-5/8" csg to pkr & 'G0' plug in tbg tail to 1500 psi - no leak found. Re]eased RTTS. Closed pipe rams on 3-1/2" & pressure tstd entire 9-5/8" system - no leaks seen. P011 & LD RTTS too]s. RIH w/3-1/2' DP to 9100'. Circ 9-5/8" csg; monitored wail tamp., 9-5/8" ann & 13-3/8" ann.' Closed top' pipe rams & tstd 9-5/8" csg to 1500 psi & tstd 13-3/8" to 1000 psi - ok. RIH w/RTTS & set Opened by-pass & circ. Pulled up to ~73'o Confirmed that leaks were above ~73~. Pressured be]ow ~+73' to 3000 psi for I hr (final press = 2960 psi). 13-3/8" x 9-5/8" ann was open w/no returns. Bled pressure. PON & LD RTTS. Ran CCL to 1200'. RIH w/9-5/8' mechanical cutter to 600'. Disp 9-5/8" csg to diesel thru cutter'. Pulled up to ~80' & cut 9-5/8" csg. P0H & LD 9-5/8" csg. RIH to 500' & backed off 9-5/8" csg. POOH w/fish (20' pup, 2 jts of 9-5/8" csg w/a co]Jar on btm). LD csg & spear assy. NU 11-3/M~ x 10-7/8" skirted screw-in guide to 9-5/8" csg. RIH w/15 its 9-5/8" csg. Tagged 9-5/8" stub & pulled up 1-2'. Pumped 50 bb]s Arctic Pack down 13-3/8" ann @ 3-4 BPH, 150 psi, taking returns thru the 9-5/8" csg. Tagged 9-5/8" stub & screwed onto w/wiggins. (max torque 15,000 it-lbs) Tstd 13-3/8" ann to 1000 psi - ok. Tstd 9-5/8" csg to 1500 psi ok. ND BOPE @ csg head. Set: slip-type hgr around 9-5/8" csg. We]der made cut-off, cleaned 9-5/8" csg down 3-~', isolated we]]bore, made final cut-off & beveled 5" above csg head. Installed packoff & tstd t,o 5000 ps - ok. Tstd 9-5/8" csg to 3000 psi - ok. RIH to 9100'; circ. down to top of PBR. Sting into PBR & (see attached sheets) 14. I hereby c/ect'~hat the foregoing is.tr.~je and correct tO the best of my knowledge· Signed ( Title Area Drilling Engineer The space b~w ~~/~s,o~ use Conditio~ of Appr~f any: By Order of Approved by COMMISSIONER the Commission Date Form 10-403 Rev. 7-1-80 GRUT/SN33 Submit "Intentions" in Triplicate and "Subsequent Reports" i n Du placate 16-11(;I Sundry Notice rotate out of pkr w/K-anchor. POH w/PBR & K-anchor. RIH w/3-1/8" gun/CCL, perf tailpipe w/2' gun & 4 spf. RIH & tagged 9-5/8" SAB pkr @ 9206'. Milled on pkr. POH & stuck pipe ~ 8772'. Worked pipe & circ - freed pipe. POH & LD pkr, plucker, BHA & tailpipe. RIH w/JB & CCL. Circ. hole clean. RIH & set EZ drill bridge plug @ 10,200'. Perf'd 10,060' - 10,064' w/4 spf. RIH w/EZ Drill retainer & set @ 10,038'. Pumped & squeezed 210 sx Class "G" cmt. Tstd 13-3/8" x 9-5/8" packoff - ok. Ran CCL/GR to 3000'. POH. Ran CCL/4-arm caliper to 3000'. Possible problem w/collar @ 5?4'. POH. Stabbed in w/spear to 9-5/8" csg & pulled out 1 jr. NU BOPE. Circ. 9-5/8" x 13-3/8" ann to clean out Arctic Pack. POH w/9-5/8" csg. RIH w/RTTS & set @ 586'. Pressured up on 9-5/8" csg - RTTS not holding. POH & LD RTTS. RIH w/second RTTS - unable to get it to go into 9-5/8" csg. POM. RIH w/tapered mill, tagged stub & rotated. POH & LD mill. RIH w/RTT? & set @ 585'. Tstd 9-5/8" csg to 3000 psi - ok. POH & LD RTTS. RIH & dressed top of 9-5/8" csg stub to 567'. Circ. 13-3/8" csg. POH. Ran 15 its .of 9-5/8", 47.0#/ft, L-80 csg to 550'(~). Pumped 40 bbls Arctic Pack down 13-3/8" csg taking returns thru 9-5/8" csg. Attempted to activate "Joy" patch on 9-5/8" stub @ 573'. Released patch. Unable to lower back over stub to original position. POH & LD 15 its 9-5/8" csg. RIH w/cutter & attempted to cut 9-5/8" csg stub @ 583'. RIH w/spear & pulled on 9-5/8" csg - no cutoff seen. RIH w/cutter again & attempted to cut csg @ 588'. RIH w/spear, engaged & pulled on 9-5/8" csg. No cutoff Observed. POH & LD spear. RIH w/cutter & cut 9-5/8" csg @ 589'. RIH w/spear & POH w/fish (15.6' 9-5/8" csg) Dressed top of 9-5/8" csg stub @ 589'. PU to 587'. Pumped 35 bbls diesel followed by 90 bbls Arctic Pack. Ran 16 its 9-5/8", 47.0#/ft~ L-80 csg w/"Joy" patch on btm. Sting over 9-5/8" csg stub ~ 589'. Worked over packoff assy & slips. Engaged patch. Tstd 9-5/8" csg to 3000 psi - ok. Tstd 13-3/8" x 9-5/8" ann to 1000 psi - ok. ND BOPE. Cut & dress 9-5/8" csg. Set packoff. NU BOPE & tstd packoff to 5000 psi - ok. .Tstd BOPE - ok. Circ out Arctic Pack. RIH & tagged top of Cmt @ 10,028'. Tstd 9-5/8" csg & 7" lnr to 1500 psi - ok. Drld 8' cmt & tagged cmt retainer @ 10~036'. Drld cmt retainer & cmt to 10,055'. Tstd 9-5/8" csg & 7" lnr to 1500 psi - ok. Drld cmt. Tagged CIBP ~ 10,210'. Tstd 9-5/8" csg & 7" lnr to 1500 psi - ok. Drld CIBP. RIH & tagged btm @ 10,616' (no fill), Ran CBL/CCL f/10,607' - 10,000'. Ran CBL/GR/CCL f/10~400' - 9240' (under static condition) & f/10~300' - 10,000' (under dynamic condition). Reperf'd the following intervals w/4 spf: 10~474' - 10,489' 10,459' - 10,474' 10,444' - 10,459' 10,431' - 10,444' 10,401' - 10,415' RIH & set tailpipe @ 10,525' & RTTS @ 10,375'. Spotted 10 bbls H_O @ 10,525' followed by 80 bbls diesel. Pulled up 150' & set RTTS @ 10~220' w/tailpipe @ 10s375'. SqueezeZd acid into perfs (10,401' - 10,~84'): w/12% HC1 - MSR-IOOs O.S~ A-200~ 0.2% W-35, 0.2~ L-53 & 0.1% J-238. Total of 66-3/4 bbls acid into parrs. Observed well. Shut well in. Installed gas line heater, bulk separator, flareline system & related flow test equipment. Opened well to on-site choke manifold for flow & flare gas cap (initial SIDPP = 2550 psi). Flowed well. Pressure stabilized ~ 2000 psi w/flow rate of 3-5 MMCFPD (dry gas). Continued flowing well to on-site choke manifold & bulk separator unit. Flared gas to flare pit. FDPP ranged f/750 psi to 75 psi. Well stopped flowing (dead). Shut in well for pressure build-up (final SIDPP = 2SO0 psi). Opened well to on-site prod. facility to bleed off gas head {SIDPP = 2500 psi). Pressure stabilized ~ 1000 psi. Shut in well ~ rig choke manifold. Set RTTS pkr - bullheaded 78 bbls of 10.~ ppg brine w/2800 stks ~ 30 SPM w/initial press = 500 psi, final press = 1~00 psi. Unseat RTTS pkr. ~served well - no flow. POH & LD RTTS pkr & 5 its 3-1/2" 1B-11GI Sundry Notice tailpipe. RIH w/FB-1 pkr & set~ on wireline, @ 10,300'. Sting into pkr & tstd to 2000 psi - ok. RIH & perf'd the following intervals w/4 spf, 90e phasing: 9920' - 9900' 9900' - 9880' 9880' - 9860' 9860' - 9840' 9840' - 9830' Ran 4-1/2" completion assy. Tstd hanger to 3000 psi - ok. RIH & set dummy in GLH @ 8987'. Dropped ball & set pkr. Tstd tbg to 3000 psi - ok. RIH & attempted to latch standing valve. POH @ 5400' & parted line. Recovered fish (5000'±). Pulled standing valve. Set BPV. NO BOPE. NU tree & tstd to 5000 psi - ok. Pulled BPV. Pulled dummy f/GLH ~ 8987'. Disp well w/diesel. Set dummy in GLM @ 8987'. POH. Closed SSSV. Set BPV. Secured well & released rig @ 0700 hfs, 04/29/82. GRU7/SN33:tw RECEIVED AUG 2 4 Alaska Oil & Gas Cons, commission ,Anchorage ALAS~ r ST. ATE Of ALASKA (~" ..... .,. ,. A'N'D GAS CONSERVATION~,~...MISSION SUNDRY NOTICES AND REPORTS ON WELLS 7. Permit No. 8, APl Number 50- 029-20657 2. Name of Operator ARCO Alaska, Inc. 3, Address P. 0. Box 100360, Anchorage, AK 99510 4. Location of Well Surface: 495' FNL, 1142' FEL, Sec. 9, T11N, R10E, UM 9. Unit or Lease Name Kupa ruk 25648 10. Well Number 1B-11GI 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. 93' RKB I ADL 25648 ALK 466 12. Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data 11. Field and Pool Kuparuk River Field Kuparuk River 0il Pool NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] Perforations [] Altering Casing Stimulate [] Abandon [] Stimulation [] Abandonment Repair Well [] Change Plans [] Repairs Made '[] Other Pull Tubing [] Other [] Pulling Tubing [] (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). Accepted rig ~ 1900 hrs, 04/01/82. Bled pressure from tree. Pulled BPV. RIH w/bridge plug & set ~ 9325', Tstd tbg to 2800 psi - ok. Bled pressure off tbg & observed well - well dead. Closed SSSV,& set BPV. ND tree. NU BOPE & tstd to 5000 psi - ok. Pulled tbg & Lb. RIH w/RTTS to isolate a leak in the 9-5/8" csg. Set tools ~ 98', 160', 222', 284', 346', 408', 470' & pressured 9-5/8" x 3-1/2" ann to 1500 psi - no pressure on 13-3/8" ann. Pressure tstd ~ 470' down 9-5/8" csg to pkr & "GO" plug in tbg tail to 1500 psi - no leak found. Released RTTS. Closed pipe rams on 3-1/2" & pressure tstd entire 9-5/8" system - no leaks seen. POE & LD RTTS tools. RIH w/3-1/2" DP to 9100'. Circ 9-5/8" csg; monitored well temp., 9-5/8" ann & 13-3/8" ann Closed top pipe rams & tstd 9-5/8" csg to 1500 psi & tstd 13-3/8" to 1000 psi - ok. RIH w/RTTS & set ~ '750' Opened by-pass & circ. Pulled up to 473'. Confirmed that leaks were above 473'. Pressured below 473' to 3000 psi for 1 hr (final press = 2960 psi). 13-3/8" x 9-5/8" ann was open w/no returns. Bled pressure. POi & LD RTTS. .Ran CCL to 1200'. RIH w/9-5/8" mechanical cutter to 600'. Disp 9-5/8" csg to diesel thru cutter Pulled up to 480' & cut 9-5/8" csg. POH & LD 9-5/8" csg. RIH to 500' & backed off 9-5/8" csg. POOH w/fish (20' pup, 2 jts of 9-5/8" csg w/a '~ollar on btm). LD csg & spear assy. MU 11-3/4" x 10-7/8" skirted screw-i guide to 9-5/8" csg. RIH w/15 jts 9-5/8" esg. Tagged 9-5/8" stub & Pulled up 1-2'. PumPed 50 bbls Arctic Pack down 13-3/8" ann ~ 3-4 BPM, 150 Psi, .taking returns thru the 9-5/8" csg. Tagged 9-5/8" stub & SCrewed onto w/wiggins. (max torque 15,000 ft-lbs) Tstd 13-3/8" ann to 1000 psi - ok. Tstd 9-5/8" csg to 1500 Psi - ok. ND BOPE ~ csg head. Set slip-type hgr around 9-5/8" csg. Welder made cut-off, cleaned 9-5/8" csg down 3-4', isolated wellbore, made final cut-off & beveled 5" above csg head. Installed packoff & tstd to 5000 ps - ok. Tstd 9-5/8" csg to 3000 psi - ok. RIH to 9100'; circ. down to top of PBR. Sting into PBR & (see attached sheets) 14. I hereby c/co.that the foregoing is.tr.~e and correct to the best of my knowledge. Signed Title Area Dri 11 ing Engi neet ssion use Conditio~ of Appr~t~'if any: Date By Order of Approved by. COMMISSIONER the Commission Date Form 10-403 Rev. 7-1-80 GRU7/SN33 Submit "I ntentions" 'in Triplicate and "Subsequent Reports" in Duplicate 1B-11GI Sundry Notice rotate out of pkr w/K-anchor. POH w/PBR & K-anchor. RIH w/3-1/8" gun/CCL, perf tailpipe w/2' gun & 4 spf. RIH & tagged 9-5/8" SAB pkr @ 9206'. Milled on pkr. POH & stuck pipe @ 8772'. Worked pipe & circ - freed pipe. POH & LD pkr, plucker, BHA & tailpipe. RIH w/JB & CCL. Circ. hole clean. RIH & set EZ drill bridge plug ~ 10,200'. Perf'd 10,060' - 10,064' w/4 spf. RIH w/EZ Drill retainer & set ~ 10,038'. Pumped & squeezed 210 sx Class "G" cmt. Tstd 13-3/8" x 9-5/8" packoff - ok. Ran CCL/GR to 3000'. POH. Ran CCL/4-arm caliper to 3000'. Possible problem w/collar @ 574'. POH. Stabbed in w/spear to 9-5/8" csg & pulled out 1 jr. NU BOPE. Circ. 9-5/8" x 13-3/8" ann to clean out Arctic Pack. POH w/9-5/8" csg. RIH w/RTTS & set ~ 586'. Pressured up on 9-5/8" csg - RTTS not holding. POH & LD RTTS. RIH w/second RTTS - unable to get it to go into 9-5/8" csg. POH. RIH w/tapered mill, tagged stub & rotated. POH & LD mill. RIH w/RTTS & set @ 585'. Tstd 9-5/8" csg to 3000 psi - ok. POH & LD RTTS. RIH & dressed top of 9-5/8" csg stub to 587'. Circ. 13-3/8" csg. POH. Ran 15 jts of 9-5/8", 47.0#/ft, L-80 csg to 550'(~). Pumped 40 bbls Arctic Pack down 13-3/8" csg taking returns thru 9-5/8" csg. Attempted to activate "Joy" patch on 9-5/8" stub ~ 573'. Released patch. Unable to lower back over stub to original position. POH & LD 15 jts 9-5/8" esg. RIH w/cutter & attempted to cut 9-5/8" csg stub ~ 583'. RIH w/spear & pulled on 9-5/8" csg - no cutoff seen. RIH w/cutter again & attempted to cut csg ~ 588'. RIH w/spear, engaged & pulled on 9-5/8" csg. No cutoff observed. POH & LD spear. RIH w/cutter & cut 9-5/8" csg ~ 589'. RIH w/spear & POH w/fish (15.6' 9-5/8" csg). Dressed top of 9-5/8" csg stub ~ 589'. PU to 587'. Pumped 35 bbls diesel followed by 90 bbls Arctic Pack. Ran 16 jts 9-5/8,', 47.0#/ft, L-80 csg w/"Joy" patch on btm. Sting over 9-5/8" csg stub ~ 589'. Worked over packoff assy & slips. Engaged patch. Tstd 9-5/8" csg to 3000 psi - ok. Tstd 13-3/8" x 9-5/8" ann to 1000 psi - ok. ND BOPE. Cut & dress 9-5/8" csg. Set packoff. NU BOPE & tstd packoff to 5000 psi - ok. Tstd BOPE - ok. Circ out Arctic Pack. RIH & tagged top of cmt ~ 10,028'. Tstd 9-5/8" csg & 7" lnr to 1500 psi - ok. Drld 8' cmt & tagged cmt retainer ~ 10,036'. Drld cmt retainer & cmt to 10,055'. Tstd 9-5/8" csg & 7" lnr to 1500 psi - ok. Drld cmt. Tagged CIBP @ 10,210'. Tstd 9-5/8" csg & 7" lnr to 1500 psi - ok. Drld CIBP. RIH & tagged btm ~ 10,616' (no fill). Ran CBL/CCL f/10,607' - 10,000'. Ran CBL/GR/CCL f/lO,400' - 9240' (under static condition) &'f/lO,300' - 10,000' (under dynamic condition). Reperf'd the following intervals w/4 spf: 10,474' - 10,489' 10,459' - 10,474' 10,444' - 10,459' 10,431' - 10,444' 10,401' - 10,415' RIH & set tailpipe ~ 10,525' & RTTS @ 10,375'. Spotted,lO bbls H_O ~ 10,525' followed by 80 bbls diesel. Pulled up 150' & set RTTS ~ 10,220' w/tailPipe @ 10,375 . Squeezed acid into perfs (10,401' - 10,484'): w/12% HC1 - MSR-IO0, 0.5% A-200, 0.2% W-35, 0.2% L-53 & 0.1% J-238. Total of 66-3/4 bbls acid into perfs. Observed well. Shut well in. Installed gas line heater, bulk separator, flareline system & related flow test equipment. Opened well to on-site choke manifold for flow & flare gas cap (initial SIDPP = 2550 psi). Flowed well. Pressure stabilized ~ 2000 psi w/flow rate of 3-5 MMCFPD (dry gas). Continued flowing well to on-site choke manifold & bulk separator unit. Flared gas to flare.pit. FDPP ranged f/750 psi to 75 psi. Well stopped flowing (dead). Shut in well for pressure build-up (final SIDPP = 2500 psi). Opened well to on-site prod. facility to bleed off gas head (SIDPP = 2500 psi). Pressure stabilized ~ 1000 psi. Shut in well @ rig choke manifold. Set RTTS pkr - bullheaded 78 bbls of 10.4 ppg brine w/2800 stks ~ 30 SPM w/initial press = 500 psi, final press = 1400 psi. Unseat RTTS pkr. Observed well - no flow. POH & LD RTTS pkr & 5 jts 3-1/2" RECEIVED JUNO 8 JII4 Alaska Oil & Gas Cons. Commission Anchorage 1B-11GI Sundry Noti ce tailpipe. RIH w/FB-1 pkr & set, on wireline, ~ 10,300'. Sting into pkr & tstd to 2000 psi - ok. RIH & perf'd the following intervals w/4 spf, 90° phasing: 9920' - 9900' 9900' - 9880' 9880' - 9860' 9860' - 9840' 9840' - 9830' Ran 4-1/2" completion assy. Tstd hanger to 3000 psi - ok. RIH & set dummy in GLM ~ 8987'. Dropped ball & set pkr. Tstd tbg to 3000 psi - ok. RIH & attempted to latch standing valve. POH ~ 5400' & parted line. Recovered fish (5000'±). Pulled standing valve. Set BPV. ND BOPE. NU tree & tstd to 5000 psi - ok. Pulled BPV. Pulled dummy f/GLM @ 8987'. Disp well w/diesel. Set dummy in GLM ~ 8987'. POH. Closed SSSV. Set BPV. Secured well & released rig ~ 0700 hfs, 04/29/82. GRU7/SN33:tw RECEIVED JUN 0 8 Alaska Oil & Gas Cons. Commission Anchorage Alaska, Inc. ~ ARCO Post Office B~,, 360 Anchorage, Alaska 99510 Telephone 907 277 5637 May 5, 1983 Chat Chatterton State of Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Chat: Attached are several subsequent Sundry Notices covering some of our recent activities at Kuparuk. If you have any questions, please call me at 263-4527. Charles K. House Kuparuk Operations Coordinator CKH/kjc Attachment I ECEIVED. MAy 0 5 1983 Alaska Oil & Gas Cons. C°rnn~issiort Anchorage ARCO Alaska, Inc, is a Subsidiary of AtlanticRichfieldCompany STATE OF ALASKA C~'M ALASKA OIL AND GAS CONSERVATION MISSION SUNDRY NOTICES AND REPORTS ON WELLS DRILLING WELL [] COMPLETED WELL [] OTHER [] 2. Name of Operator ARCO ALASKA, INC. 3. Address P. O. BOX 360, ANCHORAGE, ALASKA 99510 4. Location of Well SURFACE LOCATION' 495' FNL, 1142' FEL, SEC. 9, Tl lN, R10E, UM BOTTOM HOLE LOCATION' SEC. 3, T11N, R10E, UM 5. Elevation in feet (indicate KB, DF, etc.) g8 ' (KB) 12. 754' FNL, 807' FEL 7. Permit No. 81-136 8. APl Number 50-029-20656 9. Unit or Lease Name KUPARUK RIVER UNIT 10. Well Number 1B-11GI 11. Field and Pool KUPARUK RIVER FIELD 6. Lease Designation and Serial No. KUPARUK R I VER O I L ADL 25648 POOL Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data Perforate Stimulate Repair Well Pull Tubing NOTICE 'OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) [] Alter Casing [] Perforations [] Altering Casing [] Abandon [] Stimulation [] Abandonment [] Change Plans [] Repairs Made [] Other [] Other [] Pulling Tubing [] (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, includ ng estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). On December 23 and 24, 1982 the gas lift dummy opposite the Upper Kuparuk sands at 9245' was pulled and replaced with a circulating valve. Gas injection is now going into the upper as well as the lower sands in this well. 14. I hereby certify that the foregoing is true and correct to the best of my knowledge. SigneO Title OPERAT IONS The space be~ow for Commission use Conditions of Approval, if any: COORDINATOR By Order of Approved by COMMISSIONER the Commission Date Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate ARCO Alaska, Inc; ~ Post Office & 360 Anchorage, Alaska 99510 Telephone 907 277 5637 Landon B. Kelly Kuparuk Operations Manager December 17, 1982 · Chat Chatterton State of Alaska Oil and Gas Conservation Commission' 3001 'Porcupine Drive Anchorage, Alaska 99504 Dear Chat: Attached are notices of our intent to stimulate Kuparuk well 1C-9 and 1C-10 with acid through coiled tubing. As you know, these wells were recently drilled to be used as additional gas injection wells. During our planned cleanup period for the wells, we have identified reservoir damage that we feel can be removed through acid stimula- tion. Removal of the damage is necessary to ensure maximum gas injection capacity for the wells. Also attached is a notice of our intent to pull a dummy gas lift valve in well 1B-tl 'to allow gas injection into the upper Kuparuk sands in this well. This will increase the well's injection capacity. Please have your secretary call me at 263-4528 when the notices are approved so that I Can send a courier over to pick them up. Kuparuk Operations Coordinator RLS/b Attachment's xc: H. C. Vickers E. A. Simonsen L. M. Sellers ARCO Alaska. Inc. Is a Subsidiary of AtlanlicRichfieldCompany STATE OF ALASKA ALASKA O(" ,AND GAS CONSERVATION CO(' AISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] COMPLETED,~VELL IX] 2. Name of Operator '~ ~r~C~' 3. Addre~ ~~) 0 P-. O. BOX ~60, ANCHORAGE, ALASKA 99~ /~ - 4. L o~tion of W¢I . , ~ . ~u~ '~ ' SURFACE LOCATION: 495' FNL, ll~z' FEL, ~;¢~2/~ SEC. 9, T11N, 10E, %% BOTTOM HOLE LOCATION' 754' FNL, 807' FEL SEC. 3, T11N, ~R10E~ UM 5. Elevation in feet (indicate KB, DF, etc.) ~ 6. Lease Designation and Serial No. 98' (KB) ~ ' ADL 25648 12. Check Appropriate Box To indicate Nature of Notice, Report, or Other Data OTHER [] 7. Permit No. 81-136 8. APl Number ~o-029-20656 9. Unit or Lease Name KUPARUK RIVER UHIT 10. Well Number 1B-11GI 11. Field and Pool KUPA'RUK RIVER FIELD KUPARUK RIVER'OIL POOL NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] Perforations [] Altering 'Casing Stimulate [] Abandon [] Stimulation [] Abandonment Repair Well [] Change Plans [] Repairs Made [] Other Puli Tubing [] Other E~ Pulling Tubing [] E] [] [] (Note: Report multiple completions on Form 10-407 with a submitted Fo~m 10-407 for each completion'.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). ARCO Alaska, Inc. proposes to pull the dummy gas lift valve at 9245' in -Kuparuk River Unit well 1B-11 to allow gas injection into the Upper Kuparuk sands. Gas injection has been limited to the lower sands in this well. ..... .unti !. ng.w..~.. "--T~--h-~---~-~'~-~ ......... E'~-~-~'k ...... ~ands are. b'eing OPened to increase this wells injection capacity, All wireline BOPs will be pressure tested to 4500 psig. Expected start date' 12/20/82 14 I hereby certify that the foregoing is true and correc~ to the best of my knowledge. _.The space ~b~¢ovv for Commis.sio, use ConditionsVaf Approval, if any: KUPARUK Title_ OPERATIONS COORDINATOR Approved Copy Date Returned Form '10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate ARCO Alaska, Inc. F Post Office III 360 Anchorage, A,'~aska 99510 Telephone 907 277 5637 November 22-, 1982 C. V. Chatterton Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Chatterton: Please find attached the well completion reports for the following producing/injecting wells: 1B-9GI 1H-3 1B-10GI 1H--4 1B-11GI 1H-6 1E-11 1H-7 1E-14 1H-8 1E-15 Very truly yours, Dayton Area Operations Engineer slz Attachment cc: L. M. Sellers 'E. A. Simonsen R. L. Stramp H. C. Vickers AN0-332 w/attachments AFA-311 w/attachments AST-308 w/attachments AFA-326 w/o attachments RECEIVED, DEC 0 !982 ~'~r STATE OF ALASKA ALASKA O AND GAS CONSERVATION COl 'ISSION WELL COMPLETION OR RECOMPLETION EPORT AND LOG - 1. Status of Well Classification of Service Well OILI-'IX GAS [] SUSPENDED[] ABANDONED [] - SERVICE [] 2. Name of Operator 7. Permit Number ARCO Aiaska, Inc. 81-136 3. Address 8. APl Number P.0.Box 360, Anchorage, AK 99510 50- 029-20657 4. Location of well at surface 4~5' FNL, 1142' FEL, Sec 9, T11N, R10E, UM 9. Unit or Lease Name Kuparuk River Unit . At Top Producing lnterval 1114' FNL, 1484' FEL, Sec 3, T11N, R10E, UM '10. WellNumber 1B-11GI At Total Depth 6311 FNL, 803' FEL, Sec 3, T11N, R10E, UH 11. Field and Pool Kuparuk River Field 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation'and Serial No. 98'RKBI ADL 25648 ALK 466 Kuparuk River 0il P°ol 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 15. Water Depth, if offshore 116. No. of Completions .12/15/81 1/10/82 1/20/82 N/A feetMSLI 1 17. TotaI Depth(MD+TVD) 18.Plug Back Depth (MD+TVD) ,9. DirectionalSurvey i 20. Depth where SSSV set I 21. Thickness of Permafro~t 10723' 6942' 10619' 6897' YES DX NO [] 2126' feetMD . 1900' (approx) 22. Type Electric or Other Logs Run DIL/FDC/CNL/GR/Cal, CBL/VDL/GR/CCL 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD .CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 94t~ H-40 Surf 80' 30" 432 sx AS II 13 3/8" 72~ N-80 Surf 2615' 17 1/2' 1600EX Fondu & 400 sx AS II 9 5/8 47~ L-BO Surf 9572' 12 1/4 1250 sx Class G Ce~ent 7" 26# K-55 9260' 10698' 8 1/2" 675 sx Class G Ceml,nt - , 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. i TUBING RECORD , interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 10469-10489' , 4 1/2" 10384 10307 . 10449-10469' 10431-10449' w/4 SPF, ~ 90° Phasing 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 10401-10415' . ..~. .. ~DEPTH INTERVAL (MD) AMOUNT& KINDOF MATERIAL USED ~ 9830-9920 N/A , , , . · · , 27. PRoDUcTION TEST -, Date First Production t' Method of Operation (Flowing, gas lif..t, etc.) N/A (Ir~jection)J Comple!,ed as gas, injector ' ' Date of Test Hours Tested PRODUCTION FOR OI L-BBL GAS-MCF WATER-BBL CHOICE SIZE I GAS-OIL RATIO · 1./3.1/8:~_ ,5 TEST PERIOD I~ Trace . __ .. . ~;3 64/64I -- Flow Tubing Casing Pressure CALCULATED , OIL-BBL GAS-MCR WATER-BBL - O'I'L GRAVITY-APl (~orr) · Press. 24-HOUR RATE I~ ' 31-32 . ,. 28. CDR E DATA ~ - Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or wate r. Submit core chips. N/A ." DEC 0 J982 · Form 10-407 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. :30. GEOLOGIC MARKERS FORMATION TESTS . NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. _ Top Kuparuk N/A River Form. 9770' 6482 ' Base Kupa=uk River Form. 10615 ' 6895 ' ¢ · ,, 31. LIST OF ATTACHMENTS N/A , , , · ;321 I hereby certify that the foregoing is true and correct to the best of my knowledge '" Origi.al Sig.ed Area Ops. Engr. !N0V 9:3 1982 Signed · / By J, S, DAYTON. Title Date .... .., INSTRUCTIONS General: This form is designed for submitting a complete and correct well coml~letion 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, observati .on,_injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measureme'nts 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 multip, le 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. ' '"'~"'~'~'-ltem 28: If no cores taken,' indicate "none". TO: KUPARUK ENGINEERING D. W. Bose/Lorie L. Johnson Transmitted herewith are the following: PLEASE NOTE: BL - BLUELINE, S - SEPIA, F - FI~, T - TAPE RECEIPT ACKNOWLEDGED: '- PLEASE RETURN RECEIPT TO: RECEIVED AUG - 6 ~982 DAq~.~ka Oil & Gas Cons. 6ommlssion r~nc'no¢~ge ARCo ALASKA, INC. ATTN: ~ LORIE L. JOHNSON - AFA/311 P. O. BOX 360 ANCHORAGE , AK 99510 KUPARUK ENGINEERING TO: TRANSMITTAL # ~'~ D. W. Bose/Lorie L. Johnson Transmitted herewith are the following: · ~ , ~ JUN2~i982 CEI T ACKNOWLED DAT~'~ ..... Co~is~O~ ~ PLEAS~ RETURN RECEIPT TO: '' ARCO ALASKA, INC. ATTN: LORIE L. JOHNSON - AFA/311 P. O. BOX 360 ANCHO~GE, AK 99510 KUPARUK ENGINEERING TO: D. W. Bose/Ann Simonsen DATE: ~/S-~ ~ WELL NAME: Transmitted 'herewith are the following: PLEASE NOTE: BL - BLUELINE, S - SEPIA, F - FILM,~ TAPE ANCHORAGE,.~.AK '99510 · ; . . /~RC0 Alaska, Inc. Post Office Box 36,0 Anchorage, Alaska 99510 Telephone 907 277 5637 May 11', 1982 Mr. C. V. Chatterton Commissioner StaLe of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive. Anchorage, AK 99501 SUBJECT: As-Built Conductor Location Plats Dear Hr. Chatterton.: Enclosed are as-built conducLor'plats for the following wells: 1B-gGI West Sak 18 Wesk Sak 20 These items were listed as mzssing data on the attachment to .your April 19, 1982, letter to Mark Major. If you have any questions, call'me at 263-4960. Sincerely, P. A. Van Dusen District Drilling Engineer PAV :JG/hrl Enclosures GRU5/A12 MAy 1 I982 bi]CO A!g.~.k,I Irt,' i? a ~ ~ si f a v r,! AHanl~rRichf-;IdComp~ny _ MON. 7-A GYRO MARKER 5969648.06 55 08 37. O9 ~00 ' 150' SEWAGE LAGOON DENOTES WELL + SITE 80' '200' "8" 7+ . 120' 120' ~2o' 4+ 120' 120' 1+ GYRO MARKER 5969647. 04 548348.2,7 RESERVE PIT g GIW 1,.-~ C~. ~6o' GIW 2+ 160' GIW 3+ ~ B-%.~7o' ?.2O .'~ ........ I~_;:..~:._~.1.,-'~.. ATLANTIC RICHFIELD CO. DRILL SITE "B" 6YRO MARKER LOCATION 'I ' PREPARED BY ' BOMHOFF & ASSOCIATES, INC, ANCHORAGE A LAS KA D ATE: I 0/25/80 DRAWN BY: R.R,K. SCALE: !% 200' CHECKED BY: 7"'~/,,~"' FAC,.: d.d. Pa:-:elek/Ann Simonsen DATE- z/_ ~._~ 2__ WELL ~,,,,':~- ~. ,¢~ C~oF_.O Tra::smi~ted herev:ith are ti~e following' .. .... PL:.~ I~OTE' BL BLUEL!~=, S - SEPIA, F - FiLi.i, T - TAPE ARCO AI.,~SKA, I''~' .ATI':i' A;~?i SIMO~iSE~I P.O. BOX 360 .... ~"'~:~'~ ..... cc:l 0 - AFA/311 A!:.".s!-:a 0}1 & G.~ Cons. .Anchor~,go ARCO Alaska, Inc.'~ Post Office Bo% ,~60 Anchorage, Alaska 99510 Telephone 907 277 5637 April 15, 1982 C. V. Chatterton State of Alaska Oil & Gas Conservation Comm. 3001 Porcupine Drive Anchorage, AK 99504 Dear Mr. Chatterton: Enclosed is the subsequent report for Kuparuk Well 1B-11GI which covers the attempted cleanout and gas injection. Sincerely Simonsen slz Attachments ARCO Alaska, Inc. is a subsidiary of AtlanticRichfieldCompar~y STATE OF ALASKA ALASKA LANDGAS CONSERVATION C ;MISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] 2. Name of Operator ARCO Alaska, Inc. 3. Address P.0.Box 360, Anehorage~ 4. Location of Well S.L. 495'FNL, 1142'FEL, B.H.L. 754'FNL, 807'FEL, 5. Elevation in feet (indicate KB, DF, etc.) KB:98 ' COMPLETED WELL ~IA Ii, .cEIVED AK 99 510 ~P~ 2 982 ~aska Oil & Gas Cons. Comn~i, l"m. ch. grage Sec ~, Tl lN~ RIOE~ u~ Sec 3, T11N, RIOE, UH 6. Lease Designation and Serial No. ADL 25648 OTHER [] 7. Permit No. 81-136 8. APl Number 5o- 029-20656 9. Unit or Lease Name ?s~,_.V. p ar u k 25648 10. Well Number 1B-11GI 11. Field and Pool Kuparuk River FieId Kuparuk River 0il Poo~ 12. Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] Perforations [] Altering Casing [] Stimulate [] Abandon [] Stimulation [] Abandonment [] Repair Well [] Change Plans [] Repairs Made [] Other X [] Pull Tubing [] Other [] Pulling Tubing [] C1 eanout (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). ARCO Alaska, Inc. attempted to cleanout drilling fluids in cased hole across 'the Lower Kuparuk Sands from February 24, through February 25, 1982. The work was done using a coiled tubing unit which circulated nitrogen and diesel. The BOP assembly was tested to 4000 psi. All circulated and flowed fluids were diverted to tankage on location and later injected into a disposal well. eanout was not successful.~ An attempt was made to inject gas ing the cleanout. Fo~ several hours, an injection ~ate of approximately 25 MMCFD at a tubing pmessu~e of 3700 psi was maintained. The injection was halted when an increase in p~essu~e was noticed in the 13 3/8"-9 5/8" annulus. The 13 3/8"-9 5/8" annulus and the 9 5/8"-4 1/2" annulus were then bled down. The 9 5/8"-4 1/2" annulu,'~~''' was filled with 10.4 PPG b~ine and operations suspended. A wo~kove~ w~11 be performed to ~epai~ the 9 5/8" casing leak and '~ / cleen out the wellbo~e ~ .... ~..~.~ ~,~- ~___~~ ~ ~~ The cl follow · / ~ /' ~'~.~/~//d~///_~///~r///,~//~--///~/ S r. 0 p e r a t i 0 n s Signed v/~/~.,_~ Title The space below for Commission use Engineer Date 4.15.82 Conditions of Approval, if any: ~...A)pp roved by By Order of COMMISSIONER the Commission Date Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate STATE OF ALASKA ALASK iL AND GAS CONSERVATION C ,v, MISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] 2. Name of Operator ARCO Alaska, Inc. 3. Address P.0.Box 360, Anchorage, AK 4. Location of Well S · L . 49 5 ' FNL, I 142 ' FEL, B.H.L. 754'FNL, 807'FEL, 5. Elevation in feet (indicate KB, DF, etc.) KB=98' 12. Sec Sec Kuparuk River I 6. Lease Designation and Serial No. K u p a r u k R i v e r ADL 25648 COMPLETED WELL~ OTHER ¢4('/:-,, '""~ ^ ~- - ~0~.. ~ 9. Unitor Lease Name T11N, R10E, UH 16.~Number TllN, R10E, UH 1B-116Z 11. Field and Pool F~etd 0~1 ~oo Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] Perforations [] Altering Casing [] Stimulate [] Abandon [] Stimulation [] Abandonment [] Repair Well [] Change Plans [] Repairs Made [] Other X [] Pull Tubing [] Other [] Pulling Tubing [] Cteanout (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). ARCO Alaska, Inc. attempted to cleanout drilling fluids in cased hole across the Lower Kuparuk Sands from February 24, through February 25, 1982. The work was done using a coiled tubing unit which circulated nitrogen and diesel. The BOP assembly was tested to 4000 psi. All circulated and flowed fluids were diverted to tankage on location and later injected into a disposal well. The cleanout was not successful. An attempt was made to inject gas following the cleanout. For several hours, an injection rate of approximately 25 MMCFD at a tubing pressure of 3700 psi was maintained. The inject[on was hatted when an increase in pressure was noticed tn the 13 3/8"-9 5/8" annulus. The 13 3/8"-9 5/8" annulus and the 9 5/8"-4 1/2" annulus were then bled., down. The 9 5/8"-4 1/2" annulus was filled with 10.4 PPG brine and operations suspended. A workover will be performed to repair the 9 5/8" easing ieak and clean out the wellbore. 14. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sr. Operat ions Signed Oriqinal Signed-H. C. Vickers Title The space below for Commission use Engineer Date. 4= !5:82 Conditions of Approval, if any: By Order of ^A~oproved by COMMISSIONER the Commission Date Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate ALASKA .L AND GAS CONSERVATION C ,MISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] COMPLETED WELL [] OTHER [] 2. Name of Operator 7. Permit No. ARCO Alaska, ]:nc. 81-136 3. Address 8. APl Number P. 0. Box 360, Anchorage, AK 99501 50-029-20657 4. Location of Well SFL: 495' FNL, 1142' Target: 1320' FNL, 1320' TD: 893' FNL, 831' 5. Elevation in feet (indicate KB, DF, etc.) 93' RKB FEL, Sec. 9, T11N, RiOE, UM FEL, Sec. 3, T11N, RiOE, UM FEL, Sec. 3, T11N, RIOE, UM 12. I6. Lease Designation and Serial No. ADL 25648 ALK 466 9. Unit or Lease Name Kuparuk 25648 10. Well Number 1B-11-GI 11. Field and Pool Kuparuk River Field Kuparuk River Oil Pool Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: (Submit in Triplicate) Perforate [] Alter Casing [] Perforations Stimulate [] Abandon [] Stimulation Repair Well [~ Change Plans [] Repairs Made Pull Tubing [] Other [] Pulling Tubing (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) SUBSEQUENT REPORT OF: (Submit in Duplicate) [] Altering Casing [] Abandonment [] Other 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). ARCO Alaska, ]:nc., proposes to repair leak(s) in the 9-5/8" casing and squeeze cement to isolate zones in this well. After killing the well, a plug will be set in the tailpipe. The 4-1/2" tubing will be pulled and the 9-5/8" casing will be repaired as necessary. The tailpipe will be perforated and the packer milled and retrieved.. Fill will be cleaned out ~f?om across the existing perfs at 10401'-10489' and a retainer set at_+10380' The well r)~ill be~, in the middle Kuparuk Sand at .+10080' and cement squeezed ~o isolate /the lower and upper sands. The retainers will be drilled out and a CBL will be run to' evaluate the squeeze. The well will be resqueezed if necessary and the upper sand perfor- ated for gas injection. Perforated intervals will be reported on the "Subsequent" Sundry Notice. The well will be recompleted with a selective single completion with two packers and gas lift mandrels as applicable for displacement and perforation access purposes. A 13-5/8" 5000 psi RSRRA BOP stack will be used on well work performed by the workover rig. The BOP equipment will be pressure tested each week and operationally tested each trip.' A ~non-freezing fluid will be left in all uncemented annuli within the permafrost interval. Necessary provisions for subsurface safety equipment will be run in b~ee%~~~ string. A 5000 psi WP wireline lubricator, tested to working pressure, will wire- line wo~k.~..~a~ applicable. _./~/ ~/~,~ ~ ,"Estimated start- April 3, 1982 'S~b.~¢q~_~ i~'~__~ 1)~e(~ ~.1 Al~aka0ii&GasC0ns. C0mmksi0~ ~- _ ~ ~c~.-.-~ Anchorage 14. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~~ Title Area Dri 11 ing Engineer The space below for Commission use Conditions of Approval, if any: ~lease notify so that a representative of the Ccmmission can be present to wi~3_e_s_s t~ting ~nd casing repair work. ,,/ - Remme~ .... Form 10-403 SubmTC~:~n'~enduh~'''' . Rev. 7-1aO I1¥ LOlIItI[ ~ ~1111! and "S.bse, uent Reports" i, ~,p~ioate \ J. J. Pawelek/Ann S~m, or T,.~ .... ~-~-H ho"o'.'ith are the following_ ... PLEASE I;OTE' BL -- BLUELZ::E, o. S - SEPIA, F - FILM, T - TAPE F--] COMM - / I'--coM~T- I 4ENG --F-STAT 7.'7~__i _ Jl. STATT'J'Eq aONFER: I . E .r',ET:.'2:: I.~EC :?T TO.: DATE: RECEIVED ARCO Alaska, Inc._[, Post Office 1~6.,,. 360 Anchorage, Alaska 99510 Telephone 907 277 5637 March 22, 1982 Mr. C. V. Chatterton State of Alaska Alaska Oil & Gas Conservation Commi s s i on 3001 Porcupine Drive Anchorage, AK 99501 SUBJECT: Revised Well Completion Report, Kuparuk 1B-11GI Dear Sir' Enclosed are a revised well completion report and two copies of the approved gyroscopic survey. The original completion report, dated February 23, 1982, indicated that certain items would be submitted at a later date. These items are now included in this well comple- tion report for well 1B-11GI. Sincerely, P. A. Van Dusen District Drilling Engineer PAV'JG/hrl Enclosures GRU2/B23 RECEIVED MAR 2 · , ~laska 0il & Gas Oons. Commission ^n~hora~o ARCO Alaska, Inc, is a Subsidiaq/of AtlanticRichfieldCompany · ALASKA , :~'AND GAS CONSERVATION C ,vllSSION WELL COMPLETION OR RECOMPLETION R_EPORT AN_n LOt_. -1. Status of Well Classification of Service Well OIL~ GAS [] SUSPENDED [-I. ABANDONED [] SERVICE~: 2. Name of Operator 7. Permit Number ARCO Alaska, Inc. 81-136 3. Address 8· APl Number P. O. Box 360, Anchorage, AK 99510 50-029-20657 4. Location of well at surface 9. Unit or Lease Name 495' FNL, 1142' FEL, Sec. 9, T11N, RIOE, UM Kuparuk 25648 At Top Producing Interval 10. Well Number 1083' FNL, 1444' FEL, Sec. 3, T11N, RiOE, UM 1B-11GI At Total Depth 11. Field and Pool 631' FNL, 803' FEL, Sec. 3, T11N, RiOE, UM Kuparuk River Field ~5' ElevationRKB in feet ~!(indicate~', ~T;, KB, DF, etc.),I 6.ADLLease25648Designation andALKser~a~466No. Kup ar u k 0i 1 Po01 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., SuMp. or Aband. 15. Water Depth, if offshore 16· No. of Completions 12-15-81 01-10-82 01-20-82 N/A feet MSL 1 17. Total Depth (M D+TVD) 18. Plug Back Depth (MD+TVD) 19. Directional Survey 20. Depth where SSSV set 21.. Thickness of Permafrost 10723'MD,6942'TVD 10619'MD,6897'TVD YES~] NO[-] 2121' feetMD 1900' (approx) 22. Type Electric or Other Logs Run · r DIL/FDC/CNL/GR/Cal , CBL/VDL/GR/CCL 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD ,.CASING SIZE WT. PER FT. GRADE TO,P BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 94# H-40 Surf 8~3' .~n" ~,32~x AS I! 13-3/8" 72# N-80 Surf 2615' 17-1/2" 1600sx Fondu & 4[lllsx AS · 9"5/8" 47# L-80 'SUrf 9572,' ]2.1/4", ]_2.~Osx Cla~s G cmt. 7" 26# K-55 9260' 10698' 8-1/2" 675sx Class G cmt 24. Perforations open to Production (MD+TVD of Top and Bottom and .· 25. TUBING RECORD . · interval, size and number) .. SIZE ' DEPTH SET (MD) PACKER SET (MD) ~-!/2" 9331, 92.03, - 10469'-10489' - 10449' -10469' ' 10'431'.10449' W/4 spf @ 90° phasing 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC, '. ' . · . ..~ , DEPTH INTERVAL (MD) AMOUNT& KIND OF MATERIAL USED . 10401'-10415' N/A , ., 27. PRODUCTION :TEs~ ...... · Date First~F'~ .'~-'.~ ~ I ' ' ., Product on .Method of Operation (Ftow, Jng, gas lift, ~etc.) wix.' 'j" ' . .... Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RA'~IO '; - , TEST PERIOD:~., , Flow,Tubing Casing Pressure CA,LCU, LATED ,.~ ·OIL-BBL GAS-McF WATER-BBL OIL GRAVITY-APl icorr) Press., , 24-HOUR RATE ~ ' '~ " 28. CORE DATA '" -- Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water· Submit core chips. N/A ., · · ._ Form 10-407 Rev. 7-1-80 · CONTINUED ON REVERSE SIDE Submit in duplicate 29. j : .30. . GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTI~ GOR, and time of each phase. Top of Kuparuk 9830' 6515' Base of Kuparuk 10246' 6728, · . .. . . . .. . · ,' 31' LIST OF Arl-ACHMENTS .Gyroscopic Survey (2 copies) , · 32. · I hereby certify that the foregoing is true and ·correct to the best of my. knowledge Signed 'Title'Sr. Dr19 ' ~Engr. Da~e ' " ' · ' .-/ r- //-- "k- - · ' · ,/, !/ · INSTRUCTIONS General: This fOrm is designed for submitting a complete and correct well completion reporl~ and log on all types of lands and leases in Alaska. ' :':,'I 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 measur'ement~ given i'n' other, spaces on this form.and in any attachments. "' Item 16 and 24' If this well is completed for separate productiOn Yr.om 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 per,tinent to such interval. ' ' Item 21·: 'Indicate whether from ground level (G L) 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 I'n- jection., Gas Injection, Shut-in, Other-explain. ' .. - l,.lO~ ..... ,-,iH ~LOPE E~:GI~'~E~RIi~G TRAilSHITTAL # ~C~ PaweleK/ann Simonsen DATE ..~- I- $ Z~ WELL "~'"-' · i',/m'lE. 7ransmigted here;.;ith are the follov;ing' pLc~C_,: , .--. _, ..... :,0 = BLUEL!HE, SEPIA, ~R/'~-'' F - FILH, T - TAPE RECETpT ACr.,,..,';Lr' L'~L~ xl nrTi,n,! ~- · PLE/..E? :.,:,,.:;;,, I'~E~E~?T TO' ARCO ALAS~tA, INC. -- 'I '"' A t T;,: A,',~ S I,'~u~, P.O. BO:': 360 . ~C~;C.~,~G~', ,~r, 0 A:' "=~' ~ ," 9951 RECEIVED MAR 0 ~ 1982 - AFA/31 1 Alaslm Oil & 6as Cons, C~missi¢~ J. J. Pawelek/Ann Simonsen Tra '- ' ' · :.-.mlsted ~=,'o'.,ith are th~ follo'.,:lng ... PLEASE IiOT~ BLUEL!NE,.. '~- SEPIA, F- FILH, · T - TAPE DATE' - AFA/311 RECEIVED, RAAI~ ,,,,~r~ 0 ~ i982 ^laaka Oil & ~chorage ARCO Alaska, Inc. Post Office B, ,60 Anchorage. Alo.,,,a 99510 Telephone 907 277 5637 February 22', 1982 Mr. C. V. ChattertOn State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Subject- State Reports Dear Sir' Enclosed please find Well Completion Reports 'for the following drill sites- 11-6, 12-4A, 13-19, 14-9A, 14-26, 15-15, lA-12, lA-13, anc~l~GI~ Also included are Monthly Reports for January on drill sites' 13-20, 13-23, 14-30, 15-1, and lA-14. Sincere ly, P. A'. VanDusen District Drilling F. ngineer Enclosures PAV/GLA' sins ARCO Alaska; Inc. is a Subsidi;,ry of AtlanticRichfi'eldCompany · . . ~ % STATE OF ALASKA "' ALASKA(..,~L AND GAS CONSERVATION I?~ISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL [~ GAS [] SUSPENDED [] ABANDONED [] SERVICE [] 2. Name of Operator 7. Permit Number ARCO Alaska, Inc. 81-136 3. Address 8. APl Number P. O. Box 360, Anchorage, Alaska 99510 so- 029-20657 · 4. Location of well at surface 9. Unit or Lease Name 495' FNL, 1142' FY.L, Sec. 9, TllN, R10E, UM Kuparuk 25648 At Top Producing Interval 10. Well Number To Be Submitted. 1B-11GI At Total Depth W/~ gy~ $~V~'f 11. Field and Pool To Be Submitted. Kuparuk River Field 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. Kuparuk Oil Pool 93' RKB ADL 25648 ALK 466 12. Date Spudded 13. DateT.D. Reached 14. Date Comp., Susp. orAband. 115. Water. Depth, ifoffshore 116. No. of Completions 12/15/81 01/10/82 01/20/82 feet MSL 1 !7. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) 19. Directional Survey [ 20. Depth Where SSSV set 21. Thickness of Permafrost 10723' '~ 10619' YES~] NO1-]I 2121 feetMD 1900' (Approx.),. 22. Type Electric or Other Logs Run DIL/FDC/CNL/GR/Cal, CBL/VDL/GR/CCL 23. CASING, LINER AND CEMENTING RECORD .. SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED · 20" 94# H-40 Surf. 80' 30" 432 sx A,S, II z,, 1600sx Fondu & 400.;x A,S, II 13.3/8" 72# N-80 Surf. 2615' 17a 9-5/8 '" 47# L-80 Surf. 9572' ,,',-12'~,' . 1250sx ClaSs. "G" alt ~" 675sx Class "G" c~zt 7" 26# K-55 9260' 10698' 8~ · 24. Perforations open to. Product on (MD+[FVDofToPand:Bottom,and . 25. TUBING RECORD , interv~l, size and number) .. SIZE. DEPTH SET (MD) PACKER SET (MD) 4~" 93~]' 920-~' 10469" - 10489 ' : ,,.~ , 10449' - 10469' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 10431] ~- 10449 , W/4 spf @ 90© phasing' DEPTH INTERVAL (MD) AMOUNT,& KIND OF MATERIAL USED 10401' - 10415' ' - N/A · : N T" 27. PRODUCTIO TLS ' I Date Firsf Production .... M.ethod o.f. Operation (FI0wing.,.gas.!:ift, e~.c..,) ~ ~ , N/A' N/A' · ,,:~:~,:.,, · . Date of Test Hours Tested PRODUCTION FOR OIL-DEL GAS-MCF WATER-BIlL CHOKE SIZE [GAS-OILRATIO' . . : TEST'PERIOD ~ .'-. ' · . . ...... '.[ . Flow,Tdb'i'ng: :Casing. Pressu.re CALCULATED'.~ 01L-BBL . GAs-McF . "WATER-'BEE OIL GRAVITY-APl (c0rr) :' "" . 28. COP E DATA -Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. : . .....: ';: , ,.: '' : .).., . . . ,... , ~. ' :' · .N/A , · · , /L..'?~?! ;of,.2i,': .. Form 10-407 Submi~ in d~plicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. 30. '-' GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravitY, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. TO BF. SUBM I~ TED. · .. ,]. · · '! 31. LIST OF ATTACHMENTS ' ' ' . . ,.. 32. I hereby certif.y that the. foregoing is true.and correct, to the best of my knowledge " · ·.. .. SeniOr "' . ' Signed · Title Drilling '~z~-g'±:P-ee~ate .. / .K'Y/ . .' ".'. . ' -' ' INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on 'i ~.- 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. . · ~ltem 16 and 24: If this well is completed for separate production from more than one interval (multiple .~ completion), so state' i.n item"!6, and initem 24 show the producing intervals for~only the interVal reported .~. ~.:... :. in item 27. Submit a separate form for.,, each additi°nal interval to be Separately' produced, show.lng the · ~. data pertinent.to.such interval .' . Item 21' Indicate whether from ground level"(GL) or~ot.her elevation (DF, .KB,, etc.). - Item 23: Attached supplemental records for this well should show the details of any multiple stage cement. ~.ing and the location of the cementing tool. 'Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water jection, Gas Injection, Shut-in, Other-explain. - "' . - - ' .'~" ' · ;;~?', . ,,. ,.. . , . ~.. .... , , · .: , : .. , ... , Drilling History NU hydril and diverter. Spudded well @ 0930 hrs, 12/15/81. Drld 17½" hole to 2630'. Ran 66 jts 13-3/8" 72~ N-80 BTC casing w/shoe @ 2615'. Cemented 13-3/8" casing w/1600sx Fondu and 400sx A.S. II. ND hydrii and diverter. Instld 13-3/8" pack off and tested to 2000 psi - ok. NU BOPE and tested to 3000 psi - ok. Tested casing to 2000 psi - ok. Drilled FC and cement. Tstd casing to 2000 psi - bled to 1000 psi. Drilled FS and 10' new fom. Tested form to 13.4 ppg EMW - no leak-off. Drilled 122" hole to 9592'. Dropped 20' of 3/8" chain down hole. RIH w/11-3/4" inside spear - tag fish and POOH. DIL/FDC/CNL/GR/Cal from 2614' - 8192'. Ran 237 jts 9-5/8" 47# L-80 csg w/F.S. @ 9572'. Cmtd 9-5/8" casing w/1250 sx Class "G', cmt lead slurry followed by 500sx Class '%" cmt tail slurry. Arctic Packed 9-5/8" x 13-3/8" annulus w/ 300 bbl H2.O, 300sx A.S. II and 129 bbl Arctic Pack. Drld FC & cmt. Tstd csg to 1500 psi - ok. Drld FS and 10' new form. Tstd form to 12.5 ppg EMW - ok. Drld 8~" hole to 9917' - D.P. stuck. While working stuck pipe, D.P. parted. RIH,screw into fish and work same. Ran free-point tool - parted off in kelly. Fished free-point tool. Jar on D.P. - pipe came free. Drld 8~" hole to 10723'. Ran DIL/FDC/CNL/GR/Cal. Ran 36 jts 7" 26# K-55__lin~fr/9260' - 10698'. Cmtd 7" liner w/675 sx Class '%" cmt. Drld ~c~ment to 10619. PBTD. Tstd liner ~iap to 2000 psi - ok. Displaced wel~l to NaC1/NaBr brine. Ran CBL/VDL/GR/CCL ,~' and Gyro. RIH and perf w/4 spf @ 90v phasing through the following intervals' ,~cj:F~'v 10469'- 10489', 10449' - 10469', 10431' - 10449', and, 10401' - 10415. [~ ~.~:~ Ran 4~ completion assembly w/tail @ 9331 and pkr @ 9203'. Tstd ~bg hanger and pack off to ..5000 psi - ok. Dropped ball and set packer. Tstd tbg 2800 psi & shear out sub @ 2500 psi. Bled ~bg to zero psi and press annulus to 1500 psi - ok. ND BOPE. NU tree and tstd to 3000 psi - ok. Displace tbg w/ diesel. Closed SSSV @ 2121'. Instld tree cap. Secured well and released rig '@ 0600 hrs, 01/20/82. FE[ 2, 4 Oil & Gas Cons. Co~iSsio~ Anchorage . : r~!aska Oil 8, 6as Cons. Cornmiss/o~ ' ' -' , ~ ~, ~ Anchorage ' . - : ' '. ' ~ ~1, ~ . , , .................. .. , . · ~>PI:,RI'~Y ,:,LIN WELL ~UR~EY~NG. OO~F~NY::: .... ........ :: ~ . F:'~OE; '1 ..... I~"'~ ~ ~ ~.~j~ ~ ~~.. ~' ~'..~¥~..~:.~::.::.:',: ~;::~'.~`:.:`~.~..::~.:?..:::~:(:~:~:?D~TB::~:.::~.L~VEY:~::d~qL~Y. a c;c aLa 'K ;; ' .... ..... ...... "'"': .... ' .... 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':!(:(-::.. .::'- . ._. -:( ' - Job NO, 'Boss-16958 :'5'." ..................... ...... '] ':..:--::-5'7':.'~::~..;':'''-- :"~-'.-_'=5"' ('Well?- ~1 B-Il G1 (SECg"~-I'~N'R~"0E) - - - '.._ -..-L:.-. " - -' VuparUk Field - .-' .... ' . ._ '._. i'.." ....... : '::-- North'Slope, Ala s'~a" -':J -!:: -::2:-:'-? --:: '.:::-:~'.'-'" ~::::J:(i:-.'.i:(~i..", .: :?'~'-. (' .ii ..... · '-~-..--:_ · - -. .---.-'.:." '.::-- ._ Survey..Date-.- January_.16 1Q82 "" ........ '- ..... ' ' ..... '" - .... -i ...... Operat'°r: John':'Samec :--.: :.:' ~:-'- ' --:" ---':- ..... :-'- ' ' - · : ......":-. --:.i':.:;~i' :':~::~-'.":,.-' .' .. ' ..... :-~"- ' - ' .... -' ' .......... -'.:.'-~ ..... .-.-:-:..:-: .:~...---.-.:-~---. : _ '" 'Scale.~'~ 1" = lO00'.-:'?:.:~'::-(:ii:..-.:.:.-:-.:.'-:.' .... ':'.'"-:_: : ':':':i:::J: ..... . ................... . :_:...>".-.. :__.-~_... - .':: "': "b::-:...' : ~::.'--">:'-'T~UE N0~TH '. ' : :'-'" ' ' "'''>':'-. .7:-:.. ':..':il ..11:'- -:r:'::-.~2Zii':-L:::::.::~.'_. ..... '~. ::.: ...... : .~":':'~-.~...... ~.:' -Sooa. oo -- _ ...... ..... . .... .................. ................... HOR!ZONTF L PROJECTION :' .: '. ::.--i .'.'.:. 'U: ~. '.. :L .-'_'-L.:.'- ... ' .'::'- ARCO Alaska,- _ .--. our.:B.oss .:.?yros Job No Boss-16958 . -- .:'::--:Well: --~I.B-11::_Gi (SEC9 Tll~ R!0E) ... .--Kupar~k ..F~eld ........... - -': ............ 1982 :-: · --- - ............. : .... Survey Date: Januaz~¢ 16, -'-' .... -'::""':';: ...... ' ..... .~::~'"- .... '"':._.... ....... -' ........... .. .:-. .... - _ - Operator_ .. ::'- John. :'SameC.-~ -::..-..'::-.:.:-::_.'~":_~: ~ -- ' ' : ........--- .-. , _ . - .- '_ .......... . . - ". ' . '" :'- - - Scale- 1" = 150o' u..uu ...... . _ _ _ .... .. ... 1500.0~ .... .. ........................................ ~-~.~.'.. ~r. Bob H~nos ~CO ~laska, Inc. P. O. Box 360 ~chorage, Alaska 99510 March 10, 1982 Re: Our Boss Gyroscopic Survey Job No. Boss-16958 W~ll: ~1 B-11 GI (SEC9 TllN R10E) Kuparuk Field North Slope, Alaska Survey Date: January 16, 1982 Operator: John Samec Dear Nr. Hines: Please find enclosed the "Original" and one (1) copy of our Boss Gyroscopic Multishot Directional Survey on the above well. Thank you for giving us this opportunity to be of service. Sincerely, NL SPERRY-SUN, INC. Kirk Afflerbacb. Di. strict Supervisor KA/pr Enclosures cc: Dave Rees - BP Alaska Exploration Company Steve Lambert Union Oil Company Donald James - Sohio Petroleum Company ,, . ~:>Fli:,RRY-,;,i.,,IN WEI..,,L ~:'.,[IR~/E¥II~,IO'I~IF~-I~ ........ ~ ................................ ~:;~; ":' : ]' :'~ '.~; '~" i .~'~ '." ;'"' ... : .'! .: ' ~~l. - _ANC;HOR~E'E' ALA~KA - : '" ': "": :' ~': :'~'~::':'':'''': .... : ...... ': ''':~:: : :'' ARUJ'"~ ...... AI_A'.::,KA, INb. " 'i'"' ' ' " : "::~ ' ~" .... ' '~ 'MARCH ~, 1 AL~;I.::~ , .~ KELLY BLISHIN~3 ELEU. = MERT~C:~L S~CT~ON C~LL. UI_~'I'~D ~bN~ ~U'~m ;": ~8.87"'DEc~itEE~; : ..... .......... :''' ...... · ~- ...... , ......... ~.L,._,2 ...... TRI IE ....... ::jLIB=SE~ ................. COURSE~-'--_.OLIRoE DOG--EEG .... TOTAE ' . MEA;:,L KED VERTICAL VERTIC:AL INCLINATION DIRECTION SEVERITY RECTANGULAR COORDINATES; VER'I- DFPTH DEPTH DEPTH DEG MIN [ EL~EEo DE~]/100 NORTH/SOLITH ER.m, F/WEz, T SEC r .... . ." ., . .. : - . .: -. .. .. .... ' : · : ...'.: ;. 2: . . ? .... i:...., : .'..:::::':::~:i '...i. . 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FEE.T..~: AT~NURTH~:~47~ZIEi3~:~;~:~:~L4:i~:~r~,:[N~?:EA:~:~.~:A~:~::/~Di~J~¢}7~`:' - . · .::: · . · . ... · .:.:.:...... : .: .:: ..:.... ......-:.;.......:.... :.:........ : ....... : :.:.:.::.:.:.;..~:.....:..:.....:.:^:..:.....:.....:.:.~:.,:. ;~.:.:.:..:.;.:...:.:.:...::..........:.:.:.~-.;.. -.-.:.,.:.:.g.:...;....: :.; .. . .. .. .......:... .:.....:.:. :.,...;.: .... . .. :. THE C.'ALCLILATIOIq FRuuEDLRE..-. ARE DA~=;ED ON THE IL'RE F;F THREE !IDIIdEI',,ISIONAL;r:RADILIS OF C. LIRVATLIRE I ~ ''~ :I:NTEJ:q:'OLfiTFD VfiLt..E.'z, FOF¢ EVEN 1000 FEET TRLIE SLIE~-SEF~ TO"FAL -Ac, L RED VER'T I CF~L VERI'I CA~L R 1:: U TAN ...~ UI.. AI.'~ L. UL RI~ZNA leo HD-TVD VERTICAL i NLRTH/,::,OL FH E~,:..,]/NE.o F DIFFEI'.,ENCE ..:..::~.:,... COi..,,REGTION ::.'... :,. ~F'TH ............. : ........ DEP'FH ............. )IEF'TH ........'~ '" " ! ............. ~ ......' .......... ': , . . ' .... . 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' "'"'"'~HE CALCLIL~TION PRLL'EE.JRE'~']'' ~l ' '" USE ~ L.TNE~R INTERPOLAT.TFJN BETNEEN , ' " ......................... "I'I--IE"I'"/E~RE:'~;T"" 20-'FOO'F''T'lB "'(FROM-- R~DIUS'''OF--F.:LIRV~TURE--) ..... POINTS ................ · · ::.. ": ...... · .}': '. ,:'; i :~ ,: :!~':-'". !i:." : :i.:. ii.:~F:i.': ':'i~::':i:i:~'...' :i::'.'::i:~?:::::!:.:i:::'!??:'L!.i!~..'..~':':'.i:)::.. ~:'.:'.~ · ' - ; - ' · ' ': ~" ' ' ' ' ~ ' ' I :: . ~' ': ':F :: '~' ' ',' i I .,.:! ! ,'~",~:~,]~l',,Ii.' I..,,,:'~t;:"i',.~,;!!-~,~ ;'.~: il;!~! ':,:l::;ti?:,i,'{',:.: , I!:.'::,.,i;I i,I '-;: ' !~ ~ ' . ................... .. . · . ;.'. ~ n~l,::HC,~'nO~ :nLn~;Kn~: :.':~.. ~.... ARCO ~L~E;~C~, INC, . : :..~:;::."':":.'-::". :. ;-.'.~.~:.:::;~}~:;~?:?:$.~;:;:-.. '::.:~.~'.'?.;'}:'~'.~?:~;':- F"$tGE'"I~ KL F'RRLII< ................... '--'._' ALASt:~A MARCH 9, 1'~c"~' · c,~ dOB NUMBER BOSS- ~ "9='"' .................................... ~:,ELLY EI. IoHINL~ ELEV. = '?"J:.O0 F']'. :. , -. .... . 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'- '- ":' '.':.'.';".:'T.F.~: LF.::.~:,UP~RLI~:':??.~c:~.::~::<..--.~:~.~-:.?':.. : 10600 ~,::,,;,,-, 7;/._, 74 ~;080 40 N ~='-'~ 1061 '~ 68S~6. ;~9 6r~c)::: :::9 5(]9e~ ~ 9 N P~-~ . ................... · .~.] o;/ E PBTD ~ 0 F.~.:, 69 ~ Z "= ( o ~ ,~ - · ~, "; ' · _,4 ' .......... , .... :, 5']"4~ 80"-'N .............. 56] · ,54 .................. #,t E~-- .t ,t ,: T R A T .T'G R A F' F.I'~'C-S'EI M M A R Y Z.'IEI:?ZVED I../S~NC~ Z.'I~L DEF:"i"I-IS A~ND SF'I-SRI:~¥ ~.,LN :,LII.,~V[.-.¥ DATA ........ ....... IF_ASuR.r.-.O OEF"rH '.: ": ...... i .... ..... R ZF'. TO, , ' . E,I<IB ' - '' Edd~ ..' SLII~-SEA~"'.' '~.~'~.'~..:'".: VERTZC:AL"~::~;.?~"~:'0~ICi"iN'.-. 4'PSFNL ~:I.,:i.:Z'I::'EL) · .................................................................................................................................... ' .................... ' ..... = ............. ~':~" ::' ':" .......... ' ...... ~~EC?O~:-I"i'I N "R Z OE ............... 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Z UN ~'::-:::::.~.'~ ;.:; ::~..:.:~:~: :~.:~.:..:..;:.:;.'. :~:~;::'~::-~-':..:::.::~::;::;~?,;~¢~ ;~::;;;-~z?~.~:;~;~:~z~;j;,? ::::~;¢?,~?.~ ~;¢%;::~.. ~ ;i;?:~;~;~;: ¢~?~:;::~'~?~??::~.:~ ?;~:?~::?'~: :;...:..':; ~ 1 ~ ~' " ~ ~' '" "';:" ' ~ ' ~ '" ::::::::::::::::::::::::::: '~ ';':'"':; ~ :,,.x,:.:.;. ,t.:..,:,::~::.:, :::::;.:...:,:., ,:;~'.~ · :,, ,..: :..-.: ,... '. ~';'). h COMF'UTER FRO .,R~I I ': '".SPERRY .',.. _NI THREE, - [~ ~MEN.,Z~.~IxI~ L::-' ~ I ]LI ..... .... II ~ .... ...... Eli., RV~,ll RE, .~:~:,~:,:,,:~,..:~:~::~,~:~.~:;.~ .:~::{;~.¢~,~{~:;:~:;~:~,:~:~;.~ ~....~ :.~ ~:,.::~ ,:::, :.::.:. ~..- · :. --D~ T~'-C~ b CLIL'~ T'Z ON :~ND'-'Z N TERF'O b~ T ~' c,N~B ~'R'~D Z'i~IS:zOF-c Ei~V'~TIZli~E;3::::''~::' ::~::~:::'::"-:¢::;'" .:~;:~.:~:~;:::::.:.~.:~::~.:~::::;:.:.~.::::.~.:~:~;~z~?~j~?~;?~;~:~.~:~;~:~;~¢~.~:~:~¢~::~:~:~:~:r ~:'~:~':';¢:~;~:~:~ :~ ~' ~: ........................ ...... ~ .... ~ ...... ~'~'s-"'~'-;'7-~ ....... ~-7"~.77'-~.¥~ ...... : .... ~ .... · .... · ......... .: ......... -: ...:.. D'~%E~OFT'TSUR~EY:;;~'~NiZI~R ~::~:.:~::.;:~:::~..::.::~..~..::..:-:: ..... :. : · '": ..... .-' .............. ..... . , . T~.UE NO~TH -- ARCO Alaska, Inc. Our Boss Gyroscopic Job No. Boss-16958 Survey . . Well'~ ~1B-!I GI Wuparuk Field. North Slope, Alaska . Survey Date: January 16,-1982 Operator: ,7ohn'Samec Scale 1" = 1000' .. (SEC9 Tl lN R10E) -500C. 01:3 ,'~ 10723. '' . .:- . . -4000. O0 ._. . · ~.::_ - . . . ~;:..: .- "'fL ' ' .........'.~' ""- -300C. O0 ..' '~' '/':':-i:::~'' '.:'--".'.'--!/.-.-'--'.': .':_'..'-.-T:..- ...... :"i~O"'~:2:!i -: '."'-:.:.~:'.:..-:'::;{.i:x-.'.:..t.::i.S%-:?i:.' ::.::-~.i':??!-'?::_::~.i:-.-:~'~;.~:::!~.}!...:-::...i:::~???:--..~::: 4 · '.. -'-'." '::'' ....... .'. '". :'.-':.:'.:'.:~:-. '. ":. / '-'.--:;'.'-'....'.. -'..: :i:d.i':i.-?A' :i' v..:....' ~:.'::': :!:.':i'i' ::: .:.'.": ..'..u'.Z:-:::T'-.!::':::'ii.:'i::'.:,:. :r-'irt::'..:.-:i. :: '2.~-i:-:.~'i':~i:-:'-'(:'. :':T:'2:"-C-':-> ~ ' -':::':::': ' "' "i"-'"' "'-"":" .... :i[~~~'[9~'~'~LL~-~) "'--' ,--' .... :'::-.:.(::¥:::':k?.:.:.'-:::':--::'".-':i:-!_~'~'::!.:"..'-':.:,::'-'.':'. .'-:'.::"- ...... -'-..--1000.00 ' -':.'-; .."--- t'200.00 2000.'00 3000.00 :::':":dOOO:O0 -:'"5000.-00 .. --.'.- --. ' ' ': ........ ' 5...."-.. /".'.. _ ; .... .... . .... ..... . . HOR T ZONT,.qL_ .._ 21' · . . · · T..' ................. :.._-.W'..' ... ~.500.00 -' - . ... . _ . _ . . ~OUU.'UU .-" ---: - .~-- . .. ' ' '-: . 2: .'.-'-'. ..... .' . '~ .-' T.'.~ ' -- ' ' '2'- ~--"- -'-'-- ''' '"~"'~' ' .-_-.'. .......... : 'z~,,z,z' _.-, s-sT.-- ..'zz"z.-.. .. ". .... ' ': '..'.'~:.. ~ ..'.-.'. i.. - :' .( - .. _ . · - ARCO-.Alaska,-.Inc. -.- '-' : ._ Our Boss.Gyroscopic Survey '~ Job No. Boss-16958 ... Well: ~1B-11GI (SEC9 TllN RiOE) : KuparUk F~eld - - . North Slope, Alaska Survey Date:-January 16, 1982 Operator: John Samec - . ..- _... Scale: 1" = 1500' Suggested form to be inserted in each "Active" well folder to c~.eck for timely compliance with our regulations. Operator, Wel~ Name and Number Reports and Materials to be received by: ~1-/~-£~ Date Required Date Received Remarks Ccmpletion Report Yes Well History Yes Samples _ ~ua ~,~ ........ /V~-" p/ '- ~K COre Chips Core Description Registered Su~e:l~/'Y ' ~~ ' , _~ .... ' .... , ' e.~ Inclination Su~ey · ~. . Drill St~ Test Re~s ~0' ~~'" Pr~u~ion T~t Re~rts y.~ ,, ,, ~s ~, ~es .... ' , , , , .. NORTH '~LOPE E~GINEERIi;G ~' TRAilS:.!ITTAL # ,~,~Z 7 TO' ~ (.~.~_ ~ FROM' J. J. Pawelek/Ann Simonsen DATE' ~-/~ -~-~-~ WELL IIAME' ///-Y-Z/ Cz' Transmitted herewith are the following' PLca':::=,_.-,..,,._ HOTE' BL - BLUEL!~,,E, S - SEPIA, F - FILM, ~ TAPE RECEIPT ACK~OWLEDGED' PLEASE RETURN REC£1?T TO' ARCO ALAS!iA, INC. ATTH: AN[; SIMONSE~! - AFA/311 P.O. BOX 360 '" '-"" '- '"'" 9c, 510 A;, C,~'~O,,,,-,O~, ,~r-, ~ ARCO Alaska, Inc. Post Office Box 360 Anchorage, Alaska 99510 Telephone 907 277 5637 February 9, 1981 Mr. Chat Chatterton State of Alaska 0il & Gas Conservati. on Comm. 3001 Porcupine Drive Anchorage, Alaska 99504 Dear Mr. Chatterton: Attached piease find Sundry~p_t__i.S~_~s of Intention for Kuparuk Wells 1A-7 and/'l"'B-11 ~I2. Due to the immediate action proposed for these wells, these Notices were discussed today with~Jack Trimble of your office, who extended verbal approval. SincereIy, T. WeIIman bl Attachment RECEIVED FEB 0 91982 Alaska 0il & Gas Cons. Commission Anchorage ARCO Alaska, Inc, is e subsidiary of AtlanticRichfieldCompany STATE OF ALASKA [ ALASKA IL AND GAS CONSERVATION COMMISSION SUNDRY NOTICES AND REPORTS ON WELLS DRILLING WELL [] COMPLETED WELL OTHER [] 2. Name of Operator ARCO Alaska, Inc. 3. Address P.0.Box 360, Anchorage, 4. Location of Well Surface Locat£on: Bottomhole Location: Elevation in feet (indicate KB, DF, etc.) KB : 98' AK 99510 495' FNL, 1142' FEL Sec. 9, T11N, RIOE, UM 754' FNL, 807' FEL Sec. 3, T11N~ RIOE, UM 6. Lease Designation and Serial No. ADL 25648 7. Permit No. 81-136 8. APl Number 50- 029-20656 9. Unit or Lease Name Kuparuk 25648 10. Well Number 1B-1 1 GT 12. 11. Field and Pool Kuparuk River Kuparuk River Field 0i 1 Pool Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: (submit in Triplicate) Perforate [] Alter Casing [] Perforations Stimulate ~] Abandon [] Stimulation Repair Well [] Change Plans [] Repairs Made Pull Tubing [] Other C 1 e a n out X[] Pulling Tubing SUBSEQUENT REPORT OF: (Submit in Duplicate) [] Altering Casing [] Abandonment [] Other (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). ARCO Alaska, Inc. proposes to cleanout drilling fluids in cased hole which cover the Lower Kuparuk Sands. The work will be done using a coiled tubing unit with BOP assembly tested to 4000 psi. The well will 'be acidized after cleanout if an acceptable gas injection rate is not achieved. All circulated and flowed fluids will be diverted to tankage on location. Expected start date is February 11, 1982. Subsequent Work Repo~t¢cl o. 14. I hereby certify that the foregoing is true and correct to the best of my' knowledge. The space below for Commission use Sr. Op.er.ations Engineer Title FEB 0 9 Oil & Gas Cons. Commissi Date Conditions of Approval, if any: Approveo by ORIG!.NAt' SIGNED' BY LOPINIE C. SMITIi Approved c..~y Returned BV Order of COMMISSIONER the Comm~s~u~ Form 10-403 Rev. 7-1 ~80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate ARCO Alaska. Inc. ~, Post Office B~ ;0 Anchorage, Alaska 99510 Telephone 907 277 5637 January. 25, 1982 Mr. Lonnie Smith State of Alaska Alaska Oil and Gas Conservation Commis sion 3001 Porcupine Drive Anchorage, Alaska 99501 Subject' Dea~, -Si.r i DS 11-5 DS 14-12 DS 11-6 DS 14- 26 DS 12-7A .DS 15-14 DS 12-8B DS 15-15 DS 13-10 DS lA-12 DS 13-19 DS B-11GI DS B-8 Enclosed please find the Well Completion Reports for the following drill sites' 11-5, 12-7A, 12-8B, 13-10, 14-12, 15-14, as well as an up-dated Completion Report for DS B-8. Also included are the Monthly Drilling Reports for drill sites' 11-6, 13-19, 14-26, 15-15, lA-12 and B-11GI. Sincerely, P. A. VanDusen District Drilling Engineer Enclosures PAV/GA: ss ARCO Alaska, Inc is a Subsidiary of AtlanticRichfieldCompany -' A( STATE OF ALASKA AL'ASK L AND GAS CONSERVATION C ~ .,MISSION MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS 1. Drilling well ~_. Workover operation [] 2. Name of operator 7. Permit No. ARCO Alaska, Inc. 81-136 3. Address 8. APl Number P. O. Box 360, Anchorage, Alaska 99510 so- 029-20657 4. Location of Well at surface 495' FNL, 1142' FEL, Sec 9, TllN, R10E, UM 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. 93 RKB I ADL 25648 ALK 466 9. Unit or Lease Name Kuparuk 25648 10. Well No. 1 B - llGI 11. Field and Pool Kuparuk River Field Kuparuk Oil Pool December 81 For the Month of. ,19__ 12. Depth at end of month, footage drilled, fishing jobs, directional drilling problems, spud date, remarks Spudded well @ 0930 hrs. 12/15/81. Ran and cemented 13-3/8" casing to 2615'. 122". holt to 9592'. ~.Dropped 2~O;....r~i_n..~.~gwn hole - tagged @ 2782 and POOH. Drilled See Attached Drilling History. 13. Casing or liner run and quantities of cement, results of pressure tests 20" conductor @ 80'. Cmtd. w/432sx A.S. II. 13-3/8" 72# N-80' casing @ 2615" Cmtd. w/1600sx Fondu and 400sx A.S. II. See Attached Drilling History. 14. Coring resume and brief desc~ription N/A 15. Logs run and depth where run DIL/FDC/CNL/GR/Cal fr/2614' - 8192'. 1 6. DST data, perforating data, shows of H2S, miscellaneous data N/A 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. . .... SIGNED '"'~/ '~ TITLE Senior Drilling Engineer DATE ~--?- 7~ -~-~---' NOTE--Report on this form is required for each/calendar month, regardless of the status of operations, and must be filed in duplicate with the Alaska Oil and Gas Conservation Commission by the 15~hof the succeeding month, unless otherwise directed. Form 10-404 Submit in duplicate Rev. 7-1-80 Drilling History NU hydril and diverter. Spudded well @ 0930 hrs, 12/15/81. Drld 17½" hole to 2630'. Ran 66 jts 13-3/8" 72# N-80 BTC casing w/shoe @ 2615'. Cemented 13-3/8" casing w/1600sx Fondu and 400sx A.S. II. ND hydril and diverter. Instld 13-3/8" pack off and tested to 2000 psi - ok. NU BOPE and tested to 3000 psi - ok. Tested casing to 2000 psi - ok. Drilled FC and cement. Tstd casing to 2000 psi - bled to I000 psi. Drilled FS and 10' new form. Tested form to 13.4 ppg EMW - no leak-off. Drilled 122" hole to 9592'. Dropped 20' of 3/8" chain down hole. RIH w/11-3/4" inside spear - tag fish and POOH. Ran DIL/FDC/CNL/GR/Cal from 2614' - 8192', as of 12/31/81. ALASKA OIL AND GAS CONSERVATION COMMISSION ~oyle H. Hamilton Chairman Thru: Lonnie C. Smith~ Commissioner Ben LeNorman Petroleum Inspector December 22, 1981 Witness BOPE Test on ARCO ' s 1B-11GI Sec. 9, TI/R, R10E, UM Kupa~ruk River_ und_efined WednesdaY,~ December 16 - I departed my home at 5~40 a.m. for a 6:10 'a.m. ShOwUp and 7~10 a.m. departure via Wien flight #15 for Deadhorse arriving at 8~40 a.m. Weather: -14'F, clear, light wind. Thursday,. December 17 - Tests on Sohio's R-17 were completed, the subject.'" 6f ' a ~se~'~e report. ~riday.~..~cember ~1.~8 - Standing by on ARCO's 1B-i1GI. Saturday,. ~.De~cem.be.~r..!9 - Tests on ARCO's 1B-11GI began at 11=15 a.m. and were completed at 1~30 p.m. BOPE inspection report is attached. I departed Deadhorse via Alaska Airlines flight #56 at 6~15 p.m. arriving in Anchorage at 7z45 p.m. and at my home at 8:15 p.m. Tuesday, December 22 - John Nydegger, ARCO drilling foreman, ~a~S'ed th~'-6ve~h~'~led the accumulator pump after finding a valve stuck closed. Also, some N2 remains entrained in the flu id. In summary, I witnessed successful BOPE tests on ARCO's Kuparuk 1B-11GI. 4/81 ~ TATE OF ALASI< ALASKA OIL &~. ~S (ID~SERVATI~ t: CC~gIISSION B.O.P.E. Inspection Report Representative ~JO,u~J Location: Sec ~ T//~R/O~-M c/~ Pril linq Contractor /~.z~..~ g~-~2~ Rig ,~/~/ Permit /~/~sing Set @, .~ ~/~ Represe ntat ive/..-'9 ~ ~/ ft. Location, Genera] Wel 1 Sign Ceneral Housekeeping ~D/~ Reserve pit BOPE Stack Test Pressure ACCUMULATOR SYSTEM __Full Charge Pressure 3/~o psig __ Pressure After Closure /.2~-O psig Pump incr. clos. pres. 200 psig.. / Full Charge Pressure Attained: Controls: biaster R~_te O~.~i Blinds switd% cover ,~_~ Kelly and Floor Safety Valves - Annular Preventer Pipe Rams Blind Rams Choke Line Valves Upper Kelly, Lower Kelly. Ball Type__ Ins ide BOP Test Pressure Test Pressure Test Pressure Test Pressure H.C.R. Valve Kill Line Valves Check Valve ..... Test Results: Failures .... 7 Choke Manifold. No. Valves No. flanges Adj ustab le Chokea Hydrauically operated choke Test Timel ~ hrs Repair or Replacement of failed equipment to be made within,,.. Inspector/Ccmmission office notified. Test Pressure days and rain ~-sec. rain ~ ~ sec. Distribution prig. - AO&(t2C cc - Operator cc - Supervisor Inspector ARCO Alaska, Inc. ( Post Office Bi>,, 360 Anchorage, Alaska 99510 Telephone 907 277 5637 December 17, 1981 Mr. Hoyle Hamilton State of Alaska Alaska Oil & Gas Conservat ion Commis s ion 3001 Porcupine Anchorage, Alaska 99510 Dear Sir: Attached is a sundry notice for an upcoming change in Casing Procedure on Kuparuk 1B-11-GI. Se~n~or~'Dr~er CC:ss Attachment 0£C? 1 1981 4laska Oil & Gas Cons '~c~or,~ c°~o ARCO Alaska, Inc. is a subsidiary of AtlanticRichfieldCompany g, STATE OF ALASKA 'O~ ALASKA L AND GAS CONSERVATION C ~MISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL rX] COMPLETED WELL [] OTHER [] 2. Name of Operator 7. Permit No. ARCO Alaska, Inc. 81-136 3. Address P.0. Box 360, Anchorage, Alaska 99510 4. Location of Well Surface: 495'FNL, l142'FEL, Sec. 9, TllN, RIOE, UM Top of Prod. Interval: 1320'FNL, 1220'FEL, Sec. 3, TllN, RIOE, UM Total Depth: 893'FNL, 831'FEL, Sec. 3, TllN, RIOE, UM 5. Elevation in feet (indicate KB, DF, etc.) 93'RKB 6. Lease Designation and Serial No. ADL 25648 ALK 466 8. APl Number s0-029-20657 9. Unit or Lease Name Kuparuk 25648 10. Well Number 1 B-11 GI 11. Field and Pool Kuparuk River Field Kuparuk River Pool 12. Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] Perforations [] Altering Casing [] Stimulate [] Abandon [] Stimulation [] Abandonment [] Repair Well [] Change Plans [~ Repairs Made [] Other [] Pull Tubing [] Other [] Pulling Tubing [] (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). A 7" 26# K-55 BTC liner to be run from lO,560'MD to 9400'MD. 9-5/8" 47# L-80 BTC casing will be set at 9600'MD. Estimated date 9-5/8" casing to be set 12/25/81. RECEIVED DEC2 1 198! Alaska Oil & Gas Cons. Commission Anchorage 14. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed The space below for Co Conditions of Approval, if any: Approved by~ Title SR. Dril Iing Engineer Approved Cop,/ Returned By Order of COMMISSIONER the Commission Date Date __~_~_ __~_//~#/ Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate September 17, 1981 Mr. P. A. VanDusen District Drilling Engineer ARCO Alaska, Inc. P. O. Box 360 Anchorage, Alaska 99510 Rez Kuparuk 25648, I B-11 GI ARCO Alaska, Inc. Permit No. 81-136 Sur. Lou. z 495tFNL, 1142~FEL, Sec 9, T11N, Bottomhole Lou.~ 893tFNL, 831~FEL, Sec 3, T11N,-R10E, Dear Mr. VanDusen~ ~nclosed is the approved application for .permit to drill the above referenced we11. Well samples and a mud log are not required. A directional survey is required.. If available, a. tape containing the d/gitized log information shall be submitted.- on all logs for copying except experimental logs, velocity surveys and dipmeter s~rveys. Many rivers in Alaska and their drainage systems have been classified as important for the spawning or migration of anadromous fish. Operations in the~e areas are subject to AS 16'.50.870 and the regulations promulgated thereunder (Title 5, Alaska Administrative Code). Prior to commencing operations you may be contacted by the Habitat Coordinator's office, Department of~ Fish and Game. Pollution of any waters of the State is prohibited by AS 46, Chapter 3, Arti=le 7 and the regulations-promulgated thereunder (Title 18, Alaska Admini.strative Code, Chapter 70) and by the Federal Water Pollution Control Act, as amended. Prior to Mr. P. A. VanDusen Kuparuk 25648, i B-11 GI -2- September 17, 1981 commencing operations you may be contacted by.a representative of the Department of Environmental Conservation. To aid us in scheduling field work, we WOuld appreciate your notifying this office within 48 hours after the well is spudded, we would also like to 'be notified so that a repre- sentative of the Commission may be present to witness testing of blowout preventer equipment before surface casing shoe is drilled. In the event of suspension or abandonment, please give this office adequate advance notification so that we may have a witness present. Very truly yours, Hoyl H. ~amilton Chairman of BY ORDER OF THE COMMISSION .Alaska Oil & Gas Conservation Commission Enclosure c.c~ Department of Fish & Game, Habitat Section w/o encl. Department. of Environmenta! Conservation w/o/encl. ARCO Alaska, Inc.( Post Office BI[ 360 Anchorage, Alaska 99510 Telephone 907 277 5637 August 10, 1981 Mr. Hoyl e Hamil ton State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Hamil ton: ARCO Alaska, Inc. proposes to drill a development well, Kuparuk 1 B-11 GI, commencing on approximately Novemberl6, 1981. Attached please find: 1. A "Permit to Drill" application form. e A plat showing a) surface and target locations, b) ver- tical directional planning. e A plat showing the proposed wellbore in relation to other wells within 200' and other Wells on B pad & B pad extension. e A determination of maximum pressure to which BOPE could be subjected. Be Diagrams and operational procedures for the 20" 2000 psi diverter stack and 13-5/8" 5000 psi RSRRA stack. Please feel free to contact us at .263-4270 if we can be of any assistance. Sincerely, ~/~ P. A. VanDusen District Drilling Engineer PAV/ELP:sp Attachments ARCO Alaska, Inc. is a subsidiary of AtlanticRichfieldCompany ALASKA ,LAND GAS CONSERVATION C ,MISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work. DRILL ~X lb. Type of well EXPLORATORY [] SERVICE C~ STRATIGRAPHIC [] REDRILL [] DEVELOPMENT OIL [] SINGLE ZONE [~] DEEPEN Fl DEVELOPMENT GAS [] MULTIPLE ZONE [] 2. Name of operator ARCO Alaska, Inc. 3. Address P.O. Box 360, Anchorage,. Alaska 99510 ~,,.. 4. Location of well at surface ' ~ (,, ~,,/V~ ~ Unit or lease name 495'FNL, l142'FEL, Sec 9, TllN, R10E, UN ' 'Kuparuk 25648 At top of proposed producing interval t~) ,~ , 10. Well number 1320'FNL,At total depth 1320'FEL, Sec 3, TllN, R10E, UN 4la, Ira 0i1~ .~aa O, ~- ]`,08] 1 B-11 GI 893'FNL, 831' FEL,' Sec 3, TllN, R10E, UM~lac/~0.,ra~,,~. ~°aT~-'.Kuparukrag'/,. ~ ~' F~e~d and poo~River Field 5. Elevation in feet (indicate KB, DF etc.) 6. Lease designation and serial no. ' ~s~'4~uparuk River 0i 1 Pool 62'GL/ 66'Pad/ 93' RKB ADL 25648 ALK 466 12. Bond information (see ~20 AAC 25.025) Type Statewide 0il & Gas Surety and/or number Fed .Ins Co #8088-26-27 Amount $500,000 13. Distance and direction fro~l~est town 14. Distance to nearest property or lease line 15. Distance to nearest drilling or completed 30 miles NW Deadhorse miles 1320' at Target, 831' at TI)et well 160' / B-I feet 16. Proposed depth (MD & TVD) 17. Number of acres in lease 18. Approximate spud date 10560'MD = 6964'TVD feet 2560 11-16-81 19. If deviated (see 20 AAC 25.050) '120. Anticipated pressures _2~] psig@ 40OF Surface lem ... KICK OFF POINT 500 feet. MAXIMUM HOLE ANGLE 54 o (see 20 AAC 25.035 (c) (2) '~R(I psig@. 6483Jt. , (TVD) 21 ..... Proposed Casing, Liner and Cementing Program SIZE CASING AND LINER SETTING DEPTH QUANTITY OF CEMENT r Hole Casing Weight Grade Coupling Length MD TOP TVD MD BOTTOM TVD (include stage data) 72" Corrugi~ted CE:llar Surf I , 5' 15' BackfillP_d 30" 20" 9] 5# H-40 Welded 80' Surf ~ ' ' · ~ 80 I 80' 400 sx AS II 17~"' 13-3/8 72# L-80 BTC 3~,00', Surf ~ ,3400' I 2700' 2300 sx Fondu~ 300sx 12~" 9-5/8 47# L-80 BTC ~10560'i Surf ~ 10560'; 6964' 800sx Ext G + 300sx G I I I 22. Describe proposed program: I ARCO Alaska, Inc. proposes to drill a Kuparuk River Field Gas Injection Well to 10560' MD : 6964' TVD. A 20" 2000 psi annulur diverter will be installed on the 20" .conductor while drilling the surface hole. A 13.-5/8" 5000 psi RSRRA BOP stack will be ins'tailed on the 13-3/8" surface string & tested upon installation and weekly to 3000 psi. The well will be completed w/4½" tbg and pkr. Non-freezing fluids will be left in uncemented annuli thru the permafrost interval. Selected intervals will be perforated within the Kuparuk formation for injection,and reported on subsequent report. A downhole safety valve will be installed with the completion string and shut and tested upon conclusion of job. 23. I hereby certify that t~~he best of my knowledge SIGNED_ TITLE District Drilling Eng. DATE ~- The space below for Commission use CONDITIONS OF APPROVAL Samples required Mud log required Directional Survey required APl number []YES [~O []YES ]~]-N O [~¥ES []NO Permit number Approval date ~/~q (o 09/17/81 I SEE COVER LETTER FOR OTHER REQUIREMENTS APPROVED BY.~ ,COMMISSIONER DATE Segten~ 17, 1981 ~r/, by order of the Commission ~rm I (~1~1 ,,,' S I Rev. 7-1-80 Submi~ in triplicate B4 _ ~'oz' L v v v V v V /% 43 ANTICIPATED PRESSURES Expected reservoir pressure in the Kuparuk interval has been determined to be 3295 psia : 3280 psig from RFT & pressure buildup date. This pressure @ 6390' SS = 6483' TVD will be balanced by 9.8 ppg mud wt. Normal drilling practice calls for a 10.4 ppg wt prior to penetration and during drilling of the Upper Kuparuk and remaining intervals. This will result in a 202 psi overbalance. It is anticipated the surface BOPE equipment could be subjected to a max- imum of 2621 psig during drilling operations. Derivation assumes a gas kick at reservoir temperature and pressure (165OF, 3295 psia), gas migration to the surface w/o expansion, and cooling to 40°F summer cellar temperature. This is well below the 5000 psig BOPE working pressure and less than the 3000 psig weekly 'test pressure. Pi = pressure initial (reservoir) Ti = temperature initial (.reservoir) Vi : vo!ume initial (.reservoir) Pf = pressure final (surface) Tf = temperature final (surface) Vf: volume final (surface) PiVi = P -~i Tf Since Vi = Vf ie no expansion. Pi: Pf Then Pf: PiTf.: (3295 psia)(40 + 460) Ti Tf Ti (165oF + 460) Pf = 2636 psia = 262! psig. · · Surface Diverter System 20" Bradenhead. 20" 2000 psi drilling spool w/10" side outlets. 10" ball valves, hydraulically actuated, w/lO" lines to reserve pit. Valves to open automati- cally upon closure of annular preventer. 20" 2000 psi annular preventer. 20" bell nipple. Maintenance & Operation 1. Upon initial installation close annular preventer and verify that ball valves have opened properly. 2. Close annular preventer and blow air through diverter lines every 12 hours. 3. Close annular preventer in the event that gas or fluid flow to surface is detected. If necessary, manually over- ride and close ball valve to upwind diverter line. Do not shut in well under anS circumstances. 18ECEIVED SEP 1 4 1981 'Al dm 0ii & Gas Cons. Co~nrnis~,~r~ Anchorage (J-5/8" 5000 PSI RSRRA BOP STACK BLIND RRHS~ ) C____ P I PE R.qMS l F- {- ) ILLI SPOOL 6 PIPE 'RRHS 5 TBG HD 3; CSG ND I z 1. 20" slip on 2000# WP Bradenhead. 2. 20¼" x 13-5/8" 5000# WP casing head. 3. 13-5/8" x 13-5/8" 5000# WP tubing head. 4. 13-5/8" x 13-5/8" 5000# flange by Graylok Hub adapter spool. 13-5/8" 5000 psi pipe rams. 6. 13-5/8" 5000 psi drilling spool w/choke and kill lines. 7. 13-5/8" 5000 psi pipe rams. 8. 13-5/8" 5000 psi blind rams. 9. 13-5/8",, 5000 psi annular. ACC~IULATOR CAPACITY TEST 1. CHECK AND FILL ACCUHULATOR RESERVOIR TO PROPER LEVEL WITH HYDRAULIC FLUID. 2. ASSURE THAT ACCUHULATOR PRESSURE IS 3000 PSI WITH 1500 PSI DO'~I;;STREAH OF THE REGULATOR. 3. OBSERVE TIHE THEN CLOSE ALL UNITS SIHULTA~;E- OUSLY AND RECORD THE TIHE AND PRESSU2E REHAIN- IDIG AFTER ALL UNITS ARE CLOSED WITH CHARGING PUHP OFF. 4. RECORD ON IADC REPORT. THE ACCEPTABLE LO'.;ER LIHIT IS 45 SECO~DS CLOSID~G TIIIE AND 1200 PSI RE.HAI NI~;G PRESSURE. 13-5/8" BOP STACK TEST 1. FILL BOP STACK AND MANIFOLD WITH ARCTIC DIESEL. 2. CHECK THAT ALL HOLD DOWN SCRE'~'S ARE FULLY RE- TRACTED. PREDETER/.IINE DEPTH THAT TEST PLUG WILL SEAT A~;D SEAT IN WELLHEAD. RUN IN LOCK DO~N SCREWS IN HEAD. 3. CLOSE ANIiULAR PREVENTER AND CHOKES AND BYPASS VALVES ON HADiIFOLD. 4. TEST ALL CO:,IPO;JENTS TO 250 PSI AND HOLD FOR lO HINUTES. 5. INCREASE PRESSURE TO 1800 PSI AND HOLD FOR lO MINUTES. BLEED TO ZERO PSI. 6. OPEN ANNULAR PREVENTER AND CLOSE TOP SET OF PIPE R~,IS. 7. INCREASE PRESSURE TO 3000 PSI AND HOLD FOR 10 MINUTES. 8. CLOSE VALVES DIRECTLY UPSTREAM OF CHOKES. BLEED DOWNSTREAH PRESSURE TO ZERO PSI TO TEST VALVES. TEST REHAINING UNTESTED HANIFOLD VALVES, IF ANY, WITH 3000 PSI UPSTREA'.I OF VALVE AND ZERO PSI DOWNSTREAM. BLEED SYSTEM TO ZERO PSI. 9. OPEN TOP SET OF PIPE RAHS AND CLOSE BOTTO:.! SET OF PIPE .RAMS. 10. INCREASE PRESSURE TO 3000 PSI AND HOLD FOR l0 MI~;UTES. BLEED TO ZERO PSI. 11. OPEN BOTTOH SET OF PIPE RA>IS. BACK OFF RUN- NING JOI~IT ADID PULL OUT OF HOLE. CLOSE BLIND C EI VEo RJ~ISBLEEDANDTo TESTzERO TOpsi.3000 PSI FOR 10 ,.,I;,UTES. 12. OPE:~ BLI~D RAHS A~IO RECOVER TEST PLUG. MAKE SURE HANIFOLD A~;D LI:~ES ARE FULL OF ARCTIC DIESEL AND ALL VALVES ARE SET IN DRILLI~;G SEP 1 4 1981 POSITION. Oil TEST STANDPIPE VALVES TO 3000 PSI ~5J25__ & GaS milS. COm~','-11~: TEST KELLY COCKS A;IO INSIDE BOP16 3000 PSI ~CDOl'ag8 '",~$,tOF~ WITH KOO;',EY PUNP. ].5. RECORD TEST [?IFO,~.tATION ON BLO',~OUT PREVENTER I'EST FOPJ',! SIGN AND SEND TO DRILLI:';G SUPEP,- VISOR. 16o PERFORI! C~':PLETE BOPE TEST O:;CE A WEEK FUNCTIO~ALLY OPERATE BOPE DAILY. LIST FOR NEW WELL PER,MITS ITEM APPROVE DATE thru 8) Company Lease & Well No. 1. Is the permit fee attached ........................................ o 3. 4. 5. 6. 7. 8. (3) Admin ~P'~- ~ '~/¥'~ / 9. (9/thru 11) 10. 12. 13. 14. 15. 16. 17. 18. 19. 20. (4) Casg ~ (12 thru 20) Is well to located in a defined pool ............................ Is well located proper distance from property line ................. Is well located proper distance from other wells ................... Is suffi'cient undedicated acreage available in this pool ........... Is well to be deviated and is well bore plat included ...... ........ Is operator the only affected party ................ --- ---...----'.. Can permit be approved before ten-day wait ......................... YES NO ? · .... ·( · Does operator have a bond in force ................... Is a conservation order needed .......... 1[.].1..1..1..].~1.[]111.[. Is administrative approval needed ................................... Is conductor string provided ........................................ Is enough cement used to circulate on conductor and surface ......... Will cement tie in surface and intermediate or production strings ...~ Will cement cover all known productive horizons ......... .... Will surface casing protect fresh water zones ...1...1.1111.1. .1... Will all casing give adequate safety in collapse, tension and burst. Is this well to be kicked off from an existing wellbore ....... ' ....... ~Is old wellbore abandonment procedure included on 10-403 ..' .......... Is adequate well bore separation proposed ........................... REMARKS (5) BOPE-~ ~Jl~/~¢ (21 thru 24) (6) Add: 21. 22. 23. 24. 25. Is a diverter system required ....................................... ~ · Are necessary diagrams of diverter and BOP equipment attached ....... ~ Does BOPE have sufficient pressure rating - Test to ~C~OO psig ..~__ Does the choke manifold comply w/AP1 RP-53 (Feb.78).. ................. Additional requirements ............................................. ~ -- Additional Remarks: £Z Engin_.e/ering: Geology: LCS ~BEW d~ HWK ~ JAL rev: 03/10/81 INITIAL ' GEO. UNIT ON/OFF POOL CLASS STATUS AREA NO. · SHORE Well Histo.ry 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. LEASE NO. BEGAN INJECTION TYPE ALASKA INDIVIDUAL WELL INJECTION VOLUMES FOR i982 INJECTION PROJECTS - - MONTH JAN FEB MAR ' APR MAY JUN JUL AUG SEPT ********* KUPARUK RIVER, KUPARUK RIVER /i1111111 ARCO ALASKA INC KUPARUK RIV UNIT 1B-gGI UNITOlll60. OIL 06/82 WTR GAS KUPARUK R. IV UNIT 1B-IOGI UNIT011160 OIL 02/82 WTR GAS KUPARUK RIV UNIT UNIT011160 OIL 02/82 WTR GAS 22,400 UNIT011160 OIL 13/82 WTR GAS KUPARUK RIV uNIT 1C-IOGI UNIT011160 OIL 12/82 WTR GAS KUPARUK RIV UNIT WSW-1 UNIT011160 OIL 04/82 WTR GAS APl 029-20655-00 YEAR .OCT NOV DEC TOTAL CUM. APl 029-20656-00 178,690 059,102 356,460 380,651 482,741 261,815 226,352'7;945,811 7,945,811 421,476 161,450 251,990 207,477 140,090 434,341 370,310 367,630 562,440 760~540 787,420' 8,465,164 8,465,164 1B-11GI APl 029-20657-00 '339,090 384,2~?_/119f967 107,540 94,4'10 118,8'"0 87,610 ~31,810 1,405,927' 1,405,927 · . APl 029-20865-00 APl 02~-20537-00 18,024 14,292 5,550 5,550 5,550 12,643 15,259 -22,348 27,175 13,731 2,895 825 127,192 127,192 OPERATOR ARCO ALASKA INC TOTALS OIL POOL TOTALS WATER 18,024 12,643 22,348 13,731. 825 14,292 15,259 27,175' 2,895 GAS 443,876' 1,251,990 1,703,040 1,834,310 2,164,021 2,151,132 1,16.1,450' 1,546,567 1,613,410 1,842,691 2,109,965 KUPARUK RIVER, KuPARUK RIVER OIL 127,192 127,192 17,822,452 17,822,.452 WATER 18,024 12,643 22,348 13,731 .825 14,292 15,259 27,175 2,895 GAS 443,876 1,251,990 1,703,040 1,834,310 2,164,021 2,151,.132 1,1'61,450 1,546,567 1,613,410 1,842,691 2,109,965 OPERATOR ARCO ALASKA INC TOTALS OIL FIELD TOTALS WATER GAS KUPARUK RIVER OIL 127,192 127,192' 17,822,452 17,822,452 WATER GAS .. 18,024 12,643 22,348 13,731 825 127,192 14,292 15,259 27,175 2,895 127,192 443,876 1,251,990 1,703,040 . 1,834,310 2,164,021 2,151,132 17,822,452 1,161,450 1,546,567 !,613,410 1.842,691 2,109,965 1.7,822..452 18,024 12,643 22,348 13,731 825 127,192 14,292 15,259 27,175 2,895 127,192 443.876~ 1,251,990 ;,703,040 834,310 -2,164,021 2,151,132 17,822,452 .16~11111111~ ~1 5~ ~1,~1~' ~I!!!1[ 1,~691 ~11~' 2~!~.., 96 .~.~... ALASKA INDIVIDUAL WELL PRODUCTION FOR 1983 +. ................ + .......................................... LEASE NO. I OIL PRODUCTION I COMP.DATE + ................. + YEAR STATUS PRODUCT JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC TOTAL ######### KUPARUK RIVER, KUPARUK RIVER ......... SOHIO ALASKA PETROLEUM CO E UGNU I APl 029-20052-00 ADL-25635 OIL 05/05/70 WTR SUSP GAS CUM. 5942 2079 ......... SOHIO ALASKA PETROLEUM OPERATOR OIL TOTALS 5,942 WATER OS.HO.GAS 2,079 POOL KUPARUK RIVER, KUPARUK RIVER ~ TOTALS OIL 2,839,044 2,966,754 3,239,690 3,303,882 3,310,866 3,828,915 73,379,737 3,190,218 3,017,413 3,394,427 3,671,323 3,426,820 3,686,930 39,876,282 WATER 6,549 18,223 48,507 57,968 104,766 92,638 753,717 2,004 8,846 39,076 q9,670 91,688 85,334 605,269 CS. HD.GAS 3,461,032 3,460,325 3,308,263 3,229,950 3,808,989 4,436,250 67,996,562 ~m 3,6Ol,542 3,943,817 3~6o3,567 3,559,314 3,855,527 4,122,345 44,390,921 · i II ALASKA INDIVIDUAL WELL PRODUCTION FOR 1983 LEASE NO, IINJECTION PROJECTI COMP.DATE + ................. + STATUS PRODUCT JAN FEB MAR APR MAY JUN. JUL AUG SEP YEAR OCT NOV DEC TOTAL CUM. ###*##*** KUPARUK RIVER, KUPARUK RIVER ......... ARCO ALASKA INC KUPARUK RIV UNIT WSW-1 APl 029-20537-00 UNIT011160 OIL 02/05/81 WTR 2004 6549 8846 18223 39076 48507 49670 57968 91688 104766 85334 92638 605269 732461 WTRSP GAS - KUPARUK RIV UNIT lA-7 APl 029-20658-00 UNITO11160 OIL 10/17/81 WTR 23983 119638 122012 112904 131700 117872 127379 136758 141573 148248 1182067 1182067 OAS KUPARUK RIV UNIT 1A-9 APl 029-20669-00 UNIT011160 0 L 11/04/81 WTR 847 93392 90006 98076 95029 101272 104892 99022 97304 94515 95639 969994 969994 GAS KUPARUK RIV UNIT 1A-11 APl 029-20685-00 UNIT011160 0 L 12/22/81 WTR 29503 55968 55269 52040 50080 49874 ~5958 45430 44846 44831 473799 473799 OAS KUPARUK RIV UNIT 1A-12 APl 029-20688-00 UNITOlll60 O L 01/06/82 WTR 24638 125953 145906 164653 143414 140097 154336 150403 148140 153470 151709 156562 1659281 1659281 OAS KUPARUK RIV UNIT 1A-13 APl 029-20700-00 UNITOlll60 O L 01/25/82 WTR 113213 143202 180247 167939 171582 183179 184720 76804 73834 92100 95628 1482448 1482448 OAS KUPARUK RIV UNIT 1A-14 APl 029-20706-00 UNIT011160 O L 02/11/82 WTR 14554 55648 55503 58156 52697 53338 60538 53540 54945 56319 54566 569804 569804 GAS KUPARUK RIV UNIT lA-15 APl 029-20711-00 UNITO11160 O L 02/28/82 WTR 57453 337386 138085 128023 129550 137320 132794 162727 180960 178662 194639 1557599 1557599 OAS KUPARUK RIV UNIT 1A-16RD APl 029-20713-01 UNIT011160 0 L 03/21/82 WTR 10571 94844 102777 104667 107102 108979 1123'86 157093 189371 192489 185790 1366069 1366069 OAS KUPARUK RIV UNIT 1B-9GI APl 029-20655-00 UNIT011160 0 L 11/10/81 WTR 1CINJ CAS 1014855 602525 1338310 1344463 783130 533062 39477 268920 362341 216316 422991 25722 6952.112 14897923 KUPARUK RIV UNIT 18-10Gl APl 029-20656-00 UNIT011160 0 L 12/13/81 WTR 1GINJ GAS 274770 255660 14150 165940 5830 103390 704590 361930 735700 800810 720210 388280 4531260 12996424 KUPARUK RIV UNIT 18-11GI APl 029-20657-00 UNIT011160 O L O1/20/82 HTR 1GINJ OAS 458880 502560 600050 502650 485140 466950 526500 470200 547490 587940 571640 553310 6273310 7679237 -14- Memory Multi-Finger Caliper Log Results Surnrnaw Company: PHILLIPS ALASKA Well: 1B-11 Log Date: June 15, 2001 Field: Kuparuk Log No.: 4358 State: Alaska Run No.: I APl No.: 50-029-20657-00 Pipe Desc.: 4.5" 12.6 lb J-55 Top Log Intvh 2,124 Ft. (MD) Pipe Use: Tubing Bot. Log Intvl: 9,872 Ft. (MD) Inspection Type: Corrosive Damage Inspection COMMENTS: This survey was run to assess the condition of the tubing with respect to corrosive damages. The caliper recordings indicate that the tubing ranges from good to poor condition with respect to corrosive damage. A Probable Hole, measuring 94% wall penetration is recorded in the deepest joint logged @ 9,843'. A cross- sectional drawing of the tubing at this location is included in this report. Penetrations ranging from 10% to 68% are recorded throughout the interval logged. A majodty of the damage recorded appears as Isolated Pitting, with no significant cross-sectional wall loss associated. Areas of General Corrosion and Lines of Corrosion are also recorded in several joints. The distribution of maximum penetrations recorded throughout the logged interval is illustrated in the Body Region Overview page of this report. Deposits are recorded throughout the interval logged. The deposits appear to be relatively light throughout most of the interval logged, but increase significantly in thickness and sevedty below the 'DB' Nipple @ 9,130'. These deposits appear to be the cause for the caliper tool "sitting down" @ 9,872', while attempting to get down to the bottom of the 4.5" tubing @ 10,319'. A cross-sectional drawing illustrating the extent of ID restriction due to these deposits @ 9,196' is included in this report. The caliper tool 'hung-up' in the Sub-surface Safety Valve @ 2,126' while logging out of the hole. In order to prevent damage to the caliper arms, the tool was allowed to close before working the tool through the SSSV. Therefore the top of the logged interval ends @ 2,124', just below the SSSV. The number of full length joints above the SSSV has been estimated at 70, and the actual joint numbering presented in this report may be in error. MAXIMUM RECORDED WALL PENETRATIONS: PROBABLE HOLE (94%) Jt. 318 @ 9,843' MD Isolated Pit (68%) Jt. 216 @ 6,582' MD Isolated Pit (61%) Jt. 95 @ 2,873' MD Isolated Pit (58%) Jt. 71 @ 2,140' MD Isolated Pit (57%) Jt. 199 @ 6,082' MD MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: No areas of significant cross-sectional wall-loss (in excess of 5%) were recorded throughout the interval logged. MAXIMUM RECORDED ID RESTRICTIONS: Deposits 3.39" Min. ID Jt. 297 @ 9,196' MD Deposits 3.46" Min. ID Jt. 308 @ 9,558' MD Deposits 3.48" Min. ID Jt. 318' @ 9,854' MD Deposits 3.49" Min. ID Jt. 312 @ 9,679' MD Deposits 3.50" Min. ID Jt. 298 @ 9,196' MD Field Engineer' S. Adcock Analyst: J. Burton Witness: T. Johns ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) or (888) 565-9085 Fax: (281) 565-1369 E-mail: PDS@memorylog.com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2314 Wei: Fe)d: Kq)arsk Rivl Unii PDS Catiper Overview Body Region Anatysis Survey DMe: lc, re J S ~00[ l i)ol ]',p ~:MFC24 No004 ! ooi Size: A ~a~vsed: J Burlo 1 F Damage P~-()flie (% wallt (Ti 50 I (}0 PDS CALIPER JOINT TABULATION Si iE~ Pipe fabuiadoss page 1 PDS CALIPER /OINT TABUI_ATION SHEP: Pi filliPS ALASKA 4 penehation body Jtne 15 200! 30 ( ...... [: fi PD$ CALIPER IOINT TABULATION X,r~mi al Ii): }gsa} ~s SA (h v, ail] 10 S0 / 00 PDS CAUPER lOIN. TABL)LATION SHE~ PDS CAi~iPER )OINT TABULA]'ION St tE~/ PDS CALIPER IOINT TABULATION PDS CALIPER JOINT TALLY SHEET Pipe: 4.5 ins 12.6 ppf J-55 Wall thickness. Body: 0.271ins Upset = 0.271ins Nominal ID: 3.958 ins Joint Depth Length Measured Type No. ID feet feet inches 71 2123.80 27.90 nominal 72 2151.70 29.56 nominal 73 2181.26 28.99 nominal 74 2210.25 28.41 nominal 75 2238.66 31.21 nominal 76 2269.87 29.62 nominal 77 2299.49 30.25 nominal 78 2329.74 29.22 nominal 79 2358.96 30.58 nominal 80 2389.54 30.30 nominal 81 2419.84 31.97 nominal 82 2451.81 30.10 no mina] 83 2481.91 31.28 nominal 84 2513.19 31.40 nominal 85 2544.59 29.95 nominal 86 2574.54 28.91 nominal 87 2603.45 28.94 nominal 88 2632.39 32.23 nominal 89 2664.62 33.37 nominal 90 2697.99 30.30 nominal 91 2728.29 31.53 nominal 92 2 759.82 30.73 nonainat 93 2790.55 28.54 nominal 94 2819.09 32.79 nominal 95 2851.88 34.92 nominal 96 2886.80 32.33 nominal 97 2919.13 29.27 nominal 98 2948.40 29.40 nominal 99 2977.80 30.20 nominal 100 3008.00 31.06 nominal 101 3039.06 31.55 nominal 102 3070.61 29.73 nominal 103 3100.34 31.63 nominal 104 3131.97 31.82 nominal 105 3163.79 30.56 nom ina] 106 3194.35 31.43 nominal 107 3225.78 29.97 nominal -- 108 3255.75 28.29 nominal 109 3284.04 30.96 nominal 110 3315.00 29.30 nominal 111 3344.30 31.09 nominal 112 3375.39 31.37 nominal 113 3406.76 32.65 nominal 114 3439.41 31.74 nominal 115 3471.15 31.39 nominal 116 3502.54 29.97 nominal 11 7 3532.51 29.35 nominal 118 3561.86 31.58 nominal 119 3593.44 31.68 nominal 120 3625.12 31.96 nominal Well: 1B-11 Fie]d: Kuparuk River Unit Company: PHILLIPS ALASKA Country: USA Date: June 15, 2001 Joint Depth Length Measured Type · No. ID feet feet inches 121 3657.08 29.49 nominal 122 3686.57 31.22 nominal 123 3717.79 33.93 nominal 124 3751.72 31.98 nominal 125 3783.70 30.99 nominal 126 3814.69 29.71 nominal 127 3844.40 30.91 nominal 128 3875.31 31.23 nominal 129 3906.54 31.36 nominal 130 3937.90 30.00 nominal 131 3967.90 27.69 nominal 132 3995.59 27.51 nominal 133 4023.10 29.94 nominal 134 4053.04 32.58 nominal 135 4085.62 30.03 nominal 136 4115.65 31.34 nominal 137 4146.99 29.25 nominal 138 4176.24 29.24 nominal 139 4205.48 32.02 nominal 140 4237.50 31.79 nominal 141 4269.29 32.95 nominal 142 4302.24 32.15 nominal 143 4334.39 29.53 nominal 144 4363.92 30.99 nominal 145 4394.91 30.92 nominal 146 4425.83 31.22 nominal 147 4457.05 31.81 nominal 148 4488.86 29.52 nominal 149 4518.38 30.46 nominal 150 4548.84 31.83 nominal 151 4580.67 32.63 nominal 152 4613.30 29.43 nominal 153 4642.73 33,20 nominal 154 46 75.93 31,31 nominal 155 4707.24 30.62 nominal 156 4737.86 31.33 nominal 157 4769.19 31.10 nominal -- 158 4800.29 32.57 nominal 159 4832.86 30.45 nominal 160 4863.31 29.58 nominal 161 4892.89 31.57 nominal 162 4924.46 28.80 nominal 163 4953.26 30.02 nominal 164 4983.28 31.04 nominal 165 5014.32 30.13 nominal 166 5044.45 2 7.34 nominal 167 50.71.79 31.20 nominal 168 5102:99 31.27 nominal 169 5134.26 29.65 nominal 170 5163.91 30.46 nominal Joint Tally page 1 PDS CALIPER JOINT TALLY SHEET Pipe: 4.5 ins 12.6 ppf J-55 Wall thickness. Body: 0.271ins Upset = 0.271ins Nominal ID: 3.958 ins Joint Depth Length Measured fype No. ID feet feet inches 171 5194.37 30.11 nominal 172 5224.48 31.70 nominal 173 5256.18 29.75 nominal 174 5285.93 32.57 nominal 175 5318.50 31.19 nominal 176 5349.69 31.48 nominal 177 5381.1 7 30.15 nominal 178 5411.32 30.89 nominal 179 5442.21 29.28 nominal 180 5471.49 30.10 nominal 181 5501.59 31.94 nominal 182 5533.53 29.46 nominal 183 5562.99 32.86 nominal 184 5595.85 30.77 nominal 185 5626.62 30.68 nominal 186 5657.30 33.08 nominal 187 5690.38 32.09 nominal 188 5722.47 31.46 nominal 189 5753.93 30.88 nominal 190 5784.81 29.33 nominal 191 5814.14 30.83 nominal 192 5844.97 29.07 nominal '193 5874.04 29.41 nominal 194 5903.45 30.34 nominal 195 5933.79 31.03 nominal 196 5964.82 30.59 nominal 197 5995.41 31.26 nominal 198 6026.:67 31.08 nominal 199 6057.75 29.03 nominal 200 6086.78 30.11 nominal 201 6116.89 27.36 nominal 202 6144.25 30.25 nominal 203 6174.50 33.19 nominal 204 6207.69 31.64 nominal 205 6239.33 31.89 nominal 206 6271.22 27.59 nominal 207 6298.81 31.35 nominal 208 6330.16 31.35 nominal 209 6361.51 31.87 nominal 210 6393.38 29.46 nominal 211 6422.84 31.03 nominal 212 6453.87 32.00 nominal 213 6485.87 29.18 nominal 214 6515.05 29.58 nominal 215 6544.63 31.87 nominal 216 6576.50 29.38 nominal 217 6605.88 30.49 nominal 218 6636.37 28.81 nominal 219 6665.18 31.13 nominal 220 6696.31 30.14 nominal Well: 1B-11 Field: Kuparuk River Unit Company: PHILLIPS ALASKA Country: USA Date: June 15, 2001 Joint Depth Length Measured Type No. ID feet feet inches 221 6726.45 31.50 nominal 222 6757.95 29.47 nominal 223 6787.42 30.48 nominal 224 6817.90 31.33 nominal 225 6849.23 31.58 nominal 226 6880.81 31.97 nominal 227 6912.78 28.48 nominal 228 6941.26 32.04 nominal 229 6973.30 31.80 nominal 230 7005.10 29.09 nominal 231 7034.19 32.10 nominal 232 7066.29 31.82 nominal 233 7098.11 33.04 nominal 234 7131.15 32.10 nominal 235 7163.25 30.21 nominal 236 7193.46 30.57 nominal 23 7 7224.03 30.49 nominal 238 7254.52 31.08 nominal 239 7285.60 28.73 nominal 240 7314.33 30.09 nominal 241 7344.42 29.76 nominal 242 7374.18 31.58 nominal 243 7405.76 30.33 nominal 244 7436.09 31.77 nominal 245 7467.86 27.84 nominal 246 7495.70 32.47 nominal 247 7528.17 31.94 nominal 248 7560.11 30.52 nominal 249 7590.63 29.27 nominal 250 7619.90 29.80 nominal 251 7649.70 30.87 nominal 252 7680.57 29.82 nominal 253 7710.39 31.04 no mina] 254 7741.43 30.15 nominal 255 7771.58 31.59 nominal 256 7803.17 31.05 nominal 257 7834.22 30.51 nominal 258 7864.73 30.70 nominal 259 7895.43 30.16 nominal 260 7925.59 31_40 nominal 261 7956.99 32.46 nominal 262 7989.45 30.69 nominal 263 8020.14 30.34 nominal 264 8050.48 31.23 nominal 265 8081.71 30.33 nominal 266 8112.04 29.81 nominal 267 8147.85 30.52 nominal 268 8172.37 30.68 nominal 269 8203.05 30.86 nominal 270 8233.91 31.24 nominal Joint Tally page 2 PDS CALIPER JOINT TALLY SHEET Pipe: 4.5 ins 12.6 ppf J-55 Wall thickness. Body: 0.271ins Upset = 0.271ins Nominal ID: 3.958 ins Joint Depth Length Measured Type No. ID feet feet inches 271 8265.15 32.47 nominal 272 8297.62 30.50 nominal 273 8328.12 31.59 nominal 274 8359.71 28.91 nominal 275 8388.62 26.26 nominal 276 8414.88 28.92 nominal 277 8443.80 36.18 nominal 278 8479.98 35.14 nominal 279 8515.12 31.75 nominal 280 8546.87 31.23 nominal 281 8578.10 30.52 nominal 282 8608.62 29.62 nominal 283 8638.24 29.63 nominal 284 8667.87 32.64 nominal 285 8700.51 28.37 nominal 286 8728.88 28.22 nominal 287 8757.10 30.52 nominal 288 8787.62 29.45 nominal 289 8817.07 29.81 nominal 290 8846.88 29.98 nominal 291 8876.86 33.00 nominal 292 8909.86 37.60 nominal 293 8947.46 34.96 nominal 293.1 8982.42 8.88 nominal Pup 293.2 8991.30 8.86 nominal Giml 293.3 9000.16 7.64 nominal Pup 294 9007.80 35.66 nominal -- 294.1 9043.46 23.59 nominal Pup 294.2 9067.05 15.97 nominal PKR 294.3 9083.02 9.22 nominal Pup 295 9092.24 31.75 nominal 295.1 9123.99 5.33 nominal Pup 295.2 9129.32 1.94 nominal DB-Nip 296 9131.26 26.34 nominal 296.1 9157.60 7.56 nominal Giro2 296.2 9165.16 4.79 nominal Pup 297 9169.95 29.27 nominal 298 9199.22 30.15 nominal 298.1 9229.37 8.70 nominal Pup 298_2 9238_07 8.34 nominal Glm3 298.3 9246.41 7.80 nominal Pup 299 9254.21 30.16 nominal 300 9284.3 7 36.90 nominal 301 9321.27 33.53 nominal 302 9354.80 27.85 nominal 303 9382.65 30.34 nominal 304 9412.99 28.73 nominal 305 9441.72 28.56 nominal 306 9470.28 28.93 nominal 307 9499.21 29.98 nominal Well: 1 B-11 Field: Kuparuk River Unit Company: PHILLIPS ALASKA Country: USA Date: June 15, 2001 Joint Depth Length Measured --ype [ No. ID feet feet inches 308 9529.19 29.97 nominal ] 309 9559.16 31.22 nominal 310 9590.38 28.92 nominal 311 9619.30 29.10 nominal 312 9648.40 30.86 nominal 313 9679.26 34.25 nominal 314 9713.51 29.09 nominal 315 9742.60 36.37 nominal 316 9778.97 30.15 nominal 31 7 9809.12 24.64 nominal 318 9833.76 28.95 nominal 318.1 9862.71 unknown nominal END Joint Tally page 3 LVP OIO,HO1 VERIFICATION LISTING ** REEL HEADER SERVICM NAME EEL NAME tREEL ID ONTINUATION # PREVIOUS REEL COMMENTS IREEL COMMENTS ** TAPE HEADER SERVICE NAME ISERVIC DATE 182/05/ ? ORIGIN ,lo?o TAPE NAME ~6~ CONTINUATION # PREVIOUS TAPE ** FILE HEADER ** FILE NAME :SERVIC,O0! SERVICE NAME ~ VERSION # ~ DATE ~ ~AXINU~ LENGTH ~ 1024 FILE TYPE I PREVIOUS FILE ~ ** INFORMATION RECORDS ** NNEM CONTENTS CN RANGI TOWNI 5ECTI COUNI STAT~ CTRY~ MNEM ATLANTIC RICHFIELD CO. IB-1tGI KUPARUK RANGE TOWNSHIP SECTION N. SLOPE ALASKA USA CONTENTS PRESI NEDIT4F LVP 0iO,H0! VERIFICATION LISTING OR D F~ELD = KU A~UK COUNTY = NORTH SLOPE BOTTO~ bOG INTERVAL = 10288 FT, - ~~ ~-'~: {:" TOP LO~ INTERVA~ = 9558 FT- ~ ~:~.~~. ~ -. TYPE HOLE FLUID = POLYMER R:MC ~ MEAS, TBUP. = .go ~ 56 RM ~ BHT ~ .65 ~ THB DXD GR AND THE CNLFDC GR WERB DIGX:~:: ............ ..... .~ . .... ..:: ...... .__ _ WELL NAM~ = IB-'XIG~ ZELD = KUPARUK :"' :..:::. :.::;:;:; <: .:.::..:' :::_ ;: · - OUNTY · NORTH ~LOP~ O~NSHXP = . IL RU~ ~1, LOGGBD TOP LOG INTERVAL = 2606 FT: ...... CASING-~OGGER = I3-38 IN,~: ~.'..2614.::: <'::.. :": ::' : :. TYPE HO~E ~UXD = LO~ SO~I~D.~S ~::' :.~'::~:.::~.~.~.~{' :~..~:~:::<:.::.~?~:::.~?: 2:.~:~:~:::::?~..g~.~>:::g.:~<::~.:F~:~:~'::?~ ~:~:~::~:~'~F:'~::~.L:< :~: ~:~:~:'.:::: __-:: - - LVP 010,H01 VERIFICATION LISTING DENSITY VISCOSZTY LUID LOSS RM P ~EAS, R~F ~ MESS, RMC P ~EAS, TEMP, TEMP, TEMP, MATRIX SANDSTONE ********************************************** DATA FORMAT RECORD ~TRY BLOCKS 4 t ' ......... ::~ ..... "::~ :'66:~:'-''~:~'':::::::::::::::::::::::::::::: :~:I:-;::'* ,.~;:: .:.::~::. :::~:~-::..:.:,~:::~:.::. :.:..::_ :. 4 ~::./:: :::: · :< =================================== .t~?. :,:::: :.:~:~-.~:~ :?~:~:::L~. :::~:~0.::~ ~.:~:~ ._:;.: .: ':::,~';. ,:..;::,::~::.<:::~'~:::~:.::'..?~:'~:::: ..~::::::::~ :~.:. ~. 4 ' ":' *':, :::~"6 :":'"~'?';Tt'~:<?~'<: ":':: '::::::: ::':'::' ::' "~::'":::::":': ..... . ;::~.:~:, ::::,:... ::: ,:~. :',.::? :-,,:_ ..~'-.'::. ' DATU~ SPeCIfICATION BLOCKS . ~NE~ SERV~ Sr~VT~ U~T A~I ID ORDER ~ LO~ TY~E~CL:A. SS:::': .... ~....:::::~.CO:D~::.~-:.~:,~:. ....... ================================ FT 0 0:' :":~:-0 ':~' :':'0: .............. '~:"":~:0~::'::~::':::':~':::::':'4::~:::''':''<:''?:~ :: :::::: :::::::: :: ::: :::: ....... - ........... D ~ ~ 0 H ~ ~ D ~ ~ G A P ~ ? :-3"~' .:.~ 2 ~'..:~. 0.~:: ~'~:: ~:~:~;:~..~:;*::~.:..::~.:.~:..::~.::~:.:~.`~.`~:~:.`~:;:.~:;.:~.~::~:::: ::~:: ~.~::: :.~_ ~:~;:: ~/.~'::~:?:.:6~.~:~<:..:~.~.=:~::.: .:::.: :-..,: FD N PU 4 2 68 FDN G/C3 42 FDH ~API 42 :~1 ...... ~'~3':2~:~':' ?";0:~':~'~ ::: ~ ':O:~`~ ............ ~ ~/C3 FDN 4.2 .: 42 ....... :::::::::i:::::::::::::::::O::<:::?:::O::::::::: ;::~.:~:.: :~:;.::'~:~,::~::6.'~:~.:~.:~:::': :; ~.. :~::~::~': ?: '..:::: ~DN 42 :'~' ;'.; ':~.:::':;"-'::':;;~:-'::::<:~::~ ::::}- :~;...:.:~:~.~:~.~:~::~:~`:`~z~:~:::::::::::::::::::::::::::::::::::: ;:~::::: ';::'" ':' :~. h: .~?~;':::~:::::.x~:h.:~:5:~.:.' ".'~:"-:~:ii:.::.::L~:.:.:':.~:~::: ?' ?_ ~:;. DATA ** ~:~ ~':~/~: ~ ~:~:::/~:'~;:'" :~: :"~>: :' ::: ~::¥ <'/:: : ;- :~:>?:?~:.:.~. ?.< :.:::':: ~?:~:~::~::/:~:~::~..~;::?:.'~:??: :: :::::::::::::::::::::::::::::::::::::::: DEPT SFLU SP ~R NPNI DRHO .NRA? NCNL ?CNL LVP OIO,H01 VERIFICATION GR 9 ,2500 CALl NCNb 3028,0000 DEPT 10~00,0000 5000 CALl NCNb 2776,0000 FCNb DEP? 10200 0000 SFbU SP -28:7696 ~R GR 93,2500 CAb! NCNL 2614,0000 rCNL DEPT 10100,0000 SFLU SP -50 0938 OR NCNb 3440,00 DEP? 9900.0000 8FLU D~? 0800,0000 NCNb ~400'0000 DEPT 9700,0000 SFLU SP -60,4688 GR 65,0625 CAb! NCNb 2830,0000 ?CNb SP ~ 8750 CALl NCNb ! ,0000 DEPT 9500,0000 SrbU 8P -999,2500 GE GE -9'99,2500 CAb! ,,oo.oooo SP '999,2500 GE '999,2500 CALl L!STING . ¸3 999 - _8 1320 9;::I250 4 '7'. t:_ 855 :; 5000 6 10,5'00-0- 83:0 ; 50 O0 1 .~ ~' ;07 1289 .00.007:: :~: 65 ~::0:~62~5.~:: ~ ::. ::: 54{, 0000.::.. -999. . "999 ;:250::0:~:::'~ -999, · ~: ?:. bVP 010,H0t VERIFICATION LXS?ING NCNL =999.2500 DEPT 9300.0000 ~ -999.2~00 -999.2500 NC~L -999,~500 DEPT ~200.0000 SP 999.2500 GR -999,2500 NCNb -999.2500 D~PT 9100.0000 SP '999,2500 OR -999.2500 NCNb -999,2500 DEPT go00,0000 SP =999,2500 =999,258o ~Nb -999.25 0 DEPT ~900.0000 SP 9g'9,2500 ~R -999,2500 ~CNL -999.2500 oEP? 8800 oooo sP i999!25oo GR 999 2500 NCNL -9'99 2500 DEPT 8?00.0000 SP -999 2500 ~R -999!2500 NCNb '999 2500 EPT 8600,0000 P -999,2500 GR '999.2500 NCNb -999,2500 DEPT 8500,0000 SP '999,2500 GR -999.2500 NCNb -99g,2500 DEPT 8400 0000 SP -999!2500 OR -999 2500 NCNb -999,2500 DEPT 8300,0000 SP -999.2500 FCNL SFLU CALX FCNb SFLU OR CALl SFLU GR CALX rCNL SFLU GR CAb rCN~ CAb! FCNb $FLU GR CALI FCNL SFLU rCNb SFLU CALl FCNL SFLU CALl FCNb 8FLU OR 8FLU -999,2500..:.:~ :::::.. :,: -_.: 500=:::?~ .': · 999 ;:25 O0 DR'HO : .... '~RAT ;":-":' ~:99 ';25 O0> ..... ' -999 '2500 ,.;././~' :999,:2500:. ~.::::.: ..:.: ;...- :00:.. ::,:::.~ : 999 ;2':500-': ': NPffI: ........ ~'~:. ~:9 ~:<'~: R'HO-B"-":';' ~:': :~9:99:~:2'5:'00:~ ........ ':~-'"' : '-': ': ~- .g99.:2500:-::..DRHO.::::.:::.:':-~ O0::-N :::::::::::::::::::::: :::::::::::::::::::::::::: :<':: ' 99 9 .:: 2'50 :0~::': ="N:PH~:.::::.<~. ':.::::: .::::~:~5:~:~:::: ;:.:::.::.:::-.:: ::-: - 999 ;2500 ..... PR.'O .... '~ ?~ggg~O:O=::: ::~:~9:2500~'''-'~':-':':''':: ::: "gg~ · 2500'<::::.:':::::::::::: .~:~.::::.<~.~.?:~:~::.:_..:~::~ .:::~::::::.. ::,:: :~: · ./ ::.:' ~.~'< -.::.;;... :.:.. ~f:::::<L'~:.:':?::.::- :::2.': ' :'-.~'.: ~.:: --:. :::::.:: :.;.::::..:-:~..:..:;.::.::~::::.:.::::~ -<::::.':'..::::: : .",: : :. : , 7 - ~ '25 ~ O- -~' -~:P~I:''~' ~:' ~'~:":-~'99:~';~500':':'~'::'' ~.OB'';: ':: ::-~999~500'"::: '"' ........ -'" .... ;'2500-: :,...:~.._._:.. ....... ,. ,..~.~.... ............. :.. : :999 ;2500:::< :::::::::::::::::::::::::::::::::::::: 999 ~ 2:5 0':0:.: :::.N:P~L:: .~..::,:-.~.~ :~:5:0:0:::: :;:: :: .... ~::~:..:::,,..9::~'2.5~0:~.:,::::.:~.:::. :::.:._: ~.: :::: -. - 999 ;2 500': ::: ~R:HO' :" :< ~ ::: ';~:~':::2~00::''': ': ::': ~RAT" ':~: :::' - ':~:~9:9:9:~:2'B':~'0 :-:: ":" :'" -:' ..... ~:': -999: =99-9 - 999 "99-9 "999 -99.9~ 999,~2:5,,00::::DRHO::<< ::: =25=======:====:= · :::-.,::: :::::::' ::;:;":::::-_:::-: .... - . 999-,25.00~ ;::' <...::: ..... :-: :: ::;,::: ..... ======:==?== === - 999 ~::;2500:. ::-NPH[::.~::'- ~:.:::.,:--:: ::::;.;R~B:: ::: :: . :<::: :: ..~: : :.:::::: ..... 99'9 ;':J~'oo: :: -'::':::'-: ..... ~::9':~:: ...... :'::::: ::::: ': .... '::-- - ; ::. '~- ::; -.,::,.:7::::: :.:Y :-C: X?: :,::s :/,: :: :: ~:':_.: :;, ~:::...:.¢k:.::.~:: .. : :;:.h :.:L.:'.:::::::::; ;::- :> ~.:/: : :::- :~ ': :~ LVP 010,HO1 VERIFICATION LISTING GR =999,2500 CAb! NCNb -999,2500 FCNL SP -ggg'.~500 G~R ,-ggg :2.500 CAb! CNL -g99."2500 FCNL DEPT 8~,00.0000 SFLU P -42.275500 GR ~R 'gg9, O0 CAb! NCNb '999.2500 FCNL DE:PT 8000,0000 SFbU SP '32.5938 GR GR gg9 2500 CAb! ~CNL -' ' 999.2500 FCNL DEPT 7900.0000 sFLu sp -38,~562 GR G~ -ggo.2500 CALI NCNb -999.2500 FCNb DEPT ~.~0,0000 SFLU SP .1250 GR GP 99g,2500 CALl ~CNb -gg9.2500 rCNL DEPT 7700.0000 8FLU (~P -36 1250 GR .-gg9'2500 CALI NCNb g99.2500 FCNL DEPT 7~00,0000 SFLU SP 33'0000 DR GR -gg9,250 NCNL -gg9,250~ CALl DEPT 7500,0000 SFLU SP -38,~875 GR R '999. 500 CALl ~CNL '999,2500 FCNb DE:PT 7.400, SFLU OR -999,25000 CAbI NCNb -999.250 FCNL O~PT 7200,0000 8rbU : g 99 * 2500 .- g g g, 2500 . gg ' "999 ' .-~ . ~ 43 ~'0000 "gg9'~ 2500 -:~ ~.~:~ ~.:..69:::. ,~: · ~ ~..t~' :~ : 999-;:2~ 00::' ........... :99:9~2~0 ~' ~,i9 '"'-' ::::' LVP 010.H01 VERIFICATION LISTING SD -45.$563 GR GR -999.2500 CALI WCNL -999'2500 FCNL DEPT 7100,0000 SFLU (~ -52.9062 GR DEPT 7000,0000 &FLU SP -58.1562 GR -999,2500 CAL~ NCNL -999.2500 DEPT ~900.0000 SFLU G~ ,3750 NCNb -999.2500 FCNb DEPT 6gO0.O000 SFbU SP -49,2187 GE GE -g99,2500 CAb! NCNb -999.2500 FCNL D'£PT ~700.0000 SFLU SP -47,9437 GR GR 999.2500 CAb! NCNb -999.2500 ~CNL EPT 6600,0000 SFLU P .=51.2500 GR GR 999,2500 CAb! NCNb -999.2S00 FCNL 6500.0000 8FbU '56 906 CALl .,oo.oooo 8P . 54";500 GR 999,2500 CAbI NCNb -999.2500 FCNL DEPT 6100 NCNb -999 0000 8FbU CAb! 2500 FCNb DEPT 6200,0000 SFI.,U NCNb , FCNL '999 '2500 99; 29 O'O ..... -999,250 -999 99-,2500: = .999 :::::::::::::::::::::::::::::::::::::::::::::::::::::::::: 9 :: -:_ · :. -,~ .: ~ ..'-~ bVP 010.H01 VERIFICATION 6100.0000 SFbU -46,4688 GR -999,2500 CAL! -ggg,2500 Fcr',/b DI~PT DEPT SP GR ~CNL DEPT NCNb DEPT SP GR NCNb DEPT NCNb DEPT SP NCNb DEPT SP GR NCNb DEPT SP CNL DEPT 5P GR NCNb 5900 0000 SFLU '44,2813 GR -q99,2500 CAb! -999,2500 FCNb 5800 0000 SFbU -46:6250 GR 3,9180 CkbI 72,0625 FCNb 5700,0000 SFLU ,3125 CAb! 2116.0000 FCNb 5600i~0~00 8FLU -55 50 GR 91 5000 CAb! 2304,0000 FCNL 500,0000 SFLU 5-58{,5000 GR .9395 CAb! 2204.0000 FCNb 5400.0000 SFLU -72.1250 GR 81,4375 CALl 1964.0000 FCNL 5300.0000 SrLU 2047,0000 FCNb 5200,0000 SFbU -66;2500 OR 87,0000 ALI 2026,0000 ~CNb 53.00,0000 8FLU 64.18 CALI 2380,0000 rCNb - 9 9 9,2500~ ..: ~/.'" ::?~'~ .:< :".~ ~'~: 00'00- 999 ' 2500' , 25'00 -999, 2500 ; 5625 ....BPH'[ :::':' <~:~'< 0~36:': :::~ ~' 18,2:03.1. 92 ;62:50-- ..... '-: -' ':::::'::: ...... '::' :::" ..... 104,3125:'- ::: NP~..:_~: 18 , 8125 .....DRH'O ...... '"'~':: ::':':'iU~::':':::"~:AT 504.0000: 941.0820: ~':$.::~'::'/::~'::X~D<.::,:.::-.:.:~:':::::'::-'::,:':::~:i~2,:~A:: ;"50 O0 'NP~I: ::': ':::~:::'::39~50'~:0~'':'- 576 ;0000- : .... ..... -': -:'::'- ............ ::":::'"::':':: .......... e. ~4-22 84, 9:37.5: 16; ..... 566,0000 :,~ ::::~ ~ {:~:: :~::;..8 8- -8 8{:: $ :~:::i S6:::'::~ 5~ 000:0. ,.'36 33.'---::~::: X~:b~ 64 ~:1:875 14 ;:3'3:59: ~¥P 010,~01 YERIFIC~TION LISTING NCNL 2 ~PT 4900 NCNb 2212 DEPT 4800 SP -'70 MO~'NL 2116 DEPT 4700 NCNB 2282 DEPT 4600, sp =6~. NCNb 18 , DEPT 4500. NCNb 1894. PT 4400, '91, GE 52, NCNB 1850. DEPT 4300. 8P '74, O~ 71' NCNb 1822, DEPT 4200 8P -79! OR 64 NCNb 1910. DEPT 4100 8P -65 GR 59 NCNb 1994 DEPT 4000 8P -65i GR 70 . rCNb ,0000 8FLU ,0000 FCNb ,00 .06~ GRSFLU rCNb ,0000 SFLU . .0000 FCNb oooo SFbU 1562 GE 0000 CALI 0000 rCNb 0000 SFLU 6563 0R · 0625 CAb! 0000 rCNb 000 562~ ~RSFbU O0 rC.b 0000 srbu 56~5 OR 68 5 0000 FCNL 0000 SFbU 5000 GR 68 rCNb 0000 0000 FCNb 0000 srbu 6875 0625 CAb! 588,5000:: < .... ::::=::: ::. ..... :- .... .:: :: 14 ;::6'~g4:: :':::'::::':::~: : :::::::::?:::: ::: ::: "Y': : ': -- ?:3:: "'-:: ::::::%::: · .:<:: :: ~.~:.~' :F::. :.:-.~: .::.:::::'~V::Z. ':': Y .~..s-~<,-.:.:.:+'? ":: ::' '..2 ::- :- -:: ::L.:::: .:.::::,,:: *:3: :::::::::::: :::::::::::::::::%.::: <<: ..: ::.- :-: :< - ? - _ <3: ::.., ::.::':..-,::F:-:::: ::::::: ::-::::..<:: -: : - 404 ~:'~::~:~'0::-':: ::"':' ============================= : :::<:.::::: :::" : : : ...::::-:-:_:3: :.::~ ::::::::::::::::::::::::::::::::::: ?::~<:..:~: :::::::::::::::::::::::::::::::::::::::::::::::::: .::::,::::::::: .:':: ::::: ; j:: LVP NCNL D£PT 8P NCNb DEPT NCNb DEPT 8P NCNb SP NCNb D~PT SP OR NCNb DEPT SP NCNL DEPT SP NCNb DEI:)T SP GR NCNb DE:PT 8P NCNb DEPT SP OR NCNb OlO,HO1 VERIFICATION ~146.0000 rCNL 3900.0000 SFLU , CALl 190),0000 FCNL 3800 00 2372 FCNL 3700,0000 SFLU '53,81~5 OR 84.81 5 CALI 1777,0000 FCNL 3600,0000 SrbU '65,4375 GR 2 .000 FCNb 3500 0000 8FLU 2260.0000 FCNb 3400,0000 ~RFbU -51.7813 0625 CALl 3300.0000 SFLU '50,7813 GR 61.8437 CAbI 2298,0000 rCNb . lioooo 3750 OR 57 6875 CAbI 2140.0000 rCNb 3100.0000 8FLU -59,5000 GR 66,1250 CA~I 2414,0000 FCN5 3000,0000 SFbU -60.8437 GR 65,0625 CALl 2224,0000 rCNL DEPT 2900,0000 SFbU SP -72.6875 GR LISTING 16 ;3125: ; 616,9000: ': I76 ;:'i~i9-:- .pR'~:~ 20, Sm ;'156"2 ~P~':"::':~' ':~'~':4'Y;~0~:~5': ...... -: ..... '~::::~::~;"0~0 ,5.39~? ~::: ::..:'. ~:~:. :.~:~ .?~ ::~:: 029~'~:?. ::::::::::::::::::::::::::::::::::::: ::::~:~: :~: 547 ~5000:: 6 l: ,::~:8:~'.3 ~:~:--::'.::N:P i.5.':;~:8~.~9 :- 559 ~00 ~:0:: ~:::::~ :::?.~.~ ./:j: ~?::::~?:;~;::~... lO 7:8:::~:.:::.:~ : ~:.:::~: ~ ~.~:.:~ ::;':;::.~ ~:~: 59'~ ;5'000::~:::~':-~':-:::'~-':::'~ ~'~'~"~:'"'~::::::':~: .......... ~:::'~'::~:::~:":~: .......... :: "::~::'~ ........ ~:~:~:::?::~:' ........ ::::::::::::::::::::::::: .......... 66 ~:~:1~3 54~,0:000~:~:::: :~.:~:~:~?.?:~:~ ::~::~:: :~:~.~..":?:~:? ?~:?::~:~.::..:~':? :.:':::?::~?:~:.:~?:?:.:~?:~:~{~:~:~?~:~::"?.:.:?-::;~:":;::~ ':~:'~ ,:.; ~ :::. :~:`..:.~:::..::~?:~.:::::::~::..~::~..~.:.::.:~:~..:~??.~:`~:~;:.:~:?:~:..?:.::~:~::.:::~:~ :~. ~:~::'::~ ::::. ?~.?: :~:~:-?::::~:~:~:: bVP OIO,H01 NCNb 63,6563 CALI 2398.0000 FCNL DEP? 2800 8P OR 73 NCNb 2248 9375 CALI 15,~.1328:~ ,0000 ~Nb 5'33~ ,0000 .0000 S r L U 14 8750 CALI 1 . rCNL sooo ,0000 rCNb 349-2500 DEPT 2700 8P -77 GR 59 NCNb 2306 DEPT 2600 SP -29 GR 40 NCNb 1433 DEPT 2592 Sp -27 GR 41 NCNb 1549 *~ FIL~ TRAILER *~ FILE NAME lSERVIC,O01 SERVICE NAME t VERSION # l DATE MAXIMUM LENGTH I 1024 NEXT FILE NAME I ERVICE NAME lSERVIC ATE 182/05/ 7 ORIGIN 11070 TAPE NAME 162702 ONTINUATION # I01 EXT TAPE NAME I COMMENTS ~TAPE COMMENTS ERVICE NAME :SLAVIC ATE m8~/05/ 7 ORIGIN ~ REEL NAME IREEL ID CONTINUATION # lO1 N~XT REEL NAME { COMMENTS {RE~L COMMENTS
