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Home My WebLink About215-050CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: KRU 2G-14A (PTD # 215-050) Possible IAxOA Communication Date:Tuesday, January 7, 2025 4:02:16 PM Attachments:AnnComm Surveillance TIO for 2G-14A.pdf From: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent: Tuesday, December 17, 2024 7:33 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Livingston, Erica J <Erica.J.Livingston@conocophillips.com> Subject: RE: KRU 2G-14A (PTD # 215-050) Possible IAxOA Communication Hi Chris, CPAI has concluded the monitoring of KRU 2G-14A (PTD #215-050) and confirmed the IA and OA have integrity. The TIO plots, bleed log and schematic are attached. Thank you, Jaime From: Well Integrity Specialist CPF2 Sent: Friday, November 15, 2024 10:29 AM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Livingston, Erica J <Erica.J.Livingston@conocophillips.com> Subject: KRU 2G-14A (PTD # 215-050) Possible IAxOA Communication Hi Chris, On review of our monthly waivered wells report, KRU 2G-14A (PTD #215-050) was identified as having possible IAxOA communication. 2G-14A is an injector with TxIA on gas injection that is waivered for water only injection. The IA was charged with lift gas and the well will be monitored to confirm any annular communication. The TIO plots, bleed logs, and schematic are attached. Please let me know if you have any questions or disagree with the plan. Warmest regards, Jaime Bronga Well Integrity – CPF2 – ConocoPhillips Alaska Cell: 907-229-8282 2G-14A 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING 2G-14 2024-11-11 371 1298 927 IA Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: SLM 8,296.0 2G-14A 5/20/2015 smsmith Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Replaced SPG w/ DMY 2G-14A 12/16/2023 fergusp Notes: General & Safety Annotation End Date Last Mod By NOTE: WAIVERED WAG INJ WITH TXIA ON GAS 5/12/2019 freebd Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread WINDOW 7 8,457.0 8,462.0 6,088.2 LINER 2 3/8 1.99 8,839.7 9,940.0 4.60 L-80 STL Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 32.0 Set Depth … 8,373.9 Set Depth … 6,024.4 String Max No… 3 1/2 Tubing Description TUBING Wt (lb/ft) 9.30 Grade J-55 Top Connection EUE8rd ID (in) 2.99 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 32.0 32.0 0.00 HANGER 8.000 McEVOY TUBING HANGER 3.500 2,054.8 1,920.4 40.30 SAFETY VLV 5.937 BAKER FVL (LOCKED OUT 6/18/2001) 2.810 2,104.2 1,957.6 42.13 GAS LIFT 5.312 MMH FMHO 2.937 4,420.3 3,427.6 51.30 GAS LIFT 5.312 MMH FMHO 2.937 6,165.8 4,552.8 48.33 GAS LIFT 5.312 MMH FMHO 2.937 7,473.1 5,413.0 49.98 GAS LIFT 5.312 MMH FMHO 2.937 8,289.2 5,963.5 44.53 GAS LIFT 5.312 MMH FMHO 2.937 8,330.9 5,993.3 44.14 PBR 5.000 BAKER PBR 2.810 8,344.6 6,003.2 44.01 PACKER 5.968 BAKER FHL PACKER 3.000 8,361.6 6,015.5 43.84 NIPPLE 4.000 CAMCO 'D' NIPPLE (Milled out 5/13/2015) 2.800 8,373.2 6,023.8 43.74 SOS 4.000 BAKER SHEAR OUT SUB 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 8,363.0 6,016.5 43.83 CTD Liner Top 2G-14AL1 2 3/8" CTD Liner 5/21/2015 1.990 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 2,104.2 1,957.6 42.13 1 GAS LIFT DMY BK 1 7/12/2015 5:30 0.000 4,420.3 3,427.6 51.30 2 GAS LIFT DMY BK 1 0.0 7/12/2015 2:00 0.000 6,165.8 4,552.8 48.33 3 GAS LIFT DMY BK 1 0.0 6/20/2001 9:30 0.000 7,473.1 5,413.0 49.98 4 GAS LIFT DMY BK 1 0.0 6/20/2001 4:30 0.000 8,289.2 5,963.5 44.53 5 GAS LIFT DMY BTM 1 0.0 12/16/2023 8:00 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 8,839.7 6,130.2 89.32 BILLET 2.625 BAKER ALUMINUM LINER TOP BILLET Baker 1.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 8,864.3 9,939.6 6,130.5 6,175.2 A-4, 2G-14A 5/29/2015 SLOTS Slotted Liner 2G-14A, 12/17/2023 9:09:11 AM Vertical schematic (actual) LINER; 8,839.7-9,940.0 SLOTS; 8,864.3-9,939.6 CTD Liner Top; 8,363.0 L1 LINER; 8,362.4-9,940.0 SLOTS; 8,377.5-9,939.6 WINDOW; 8,457.0-8,462.0 PRODUCTION; 33.0-8,724.0 RPERF; 8,452.0-8,458.0 APERF; 8,357.0-8,359.0 PACKER; 8,344.6 Cement Plug; 8,296.0 ftKB GAS LIFT; 8,289.2 GAS LIFT; 7,473.1 GAS LIFT; 6,165.8 GAS LIFT; 4,420.3 SURFACE; 34.0-3,327.0 GAS LIFT; 2,104.2 SAFETY VLV; 2,054.8 CONDUCTOR; 38.0-110.0 KUP INJ KB-Grd (ft) 40.98 RR Date 10/10/198 4 Other Elev… 2G-14A ... TD Act Btm (ftKB) 9,940.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292116101 Wellbore Status INJ Max Angle & MD Incl (°) 95.69 MD (ftKB) 9,700.59 WELLNAME WELLBORE2G-14A Annotation Last WO: End DateH2S (ppm) DateComment SSSV: LOCKED OUT CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: KRU 2G-14A (PTD # 215-050) Possible IAxOA Communication Date:Monday, November 18, 2024 11:09:45 AM Attachments:AnnComm Surveillance TIO for 2G-14A.pdf From: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent: Friday, November 15, 2024 10:29 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Livingston, Erica J <Erica.J.Livingston@conocophillips.com> Subject: KRU 2G-14A (PTD # 215-050) Possible IAxOA Communication Hi Chris, On review of our monthly waivered wells report, KRU 2G-14A (PTD #215-050) was identified as having possible IAxOA communication. 2G-14A is an injector with TxIA on gas injection that is waivered for water only injection. The IA was charged with lift gas and the well will be monitored to confirm any annular communication. The TIO plots, bleed logs, and schematic are attached. Please let me know if you have any questions or disagree with the plan. Warmest regards, Jaime Bronga Well Integrity – CPF2 – ConocoPhillips Alaska Cell: 907-229-8282 2250 2000 1750 w 1500 a 1250 N v 1000 a` 750 500 250 2000 v c 500 Pressure Summary For 2G-14A h 0 M 0 M H Q h 0 MM 0 M N M m 0 a h 0 M 0 m N M m H M 0 mr off . N N N N o 0 0. r r. N N N a o o.. r r N N N m o 0 m m m m m m m m m m m m m m m m a m m m m m m m m m�� 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 i�.« N N N N N N N N N N N N N N N N N N N N N N N N N N N N NNV N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 4 m 0 0 0 0 0 0 0 0 0 0 0 m o N N N N N N N N N N N N N N N ry ry N N N N N N N N N N N NNV N Date E H — IA PRESSURE — CA PRESSURE — TUBING PRESSURE (PSI) — TEMPERATURE(DEGF) — DRY GAS (MSCFD) — MI GAS (MSCFD) — PRODUCED WATER(BPD) — SEAWATER (BPD) 2G-14A 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING 2G-14 2024-11-11 371 1298 927 IA KUP INJ WELLNAME 2G-14A WELLBORE 2G-14A GNmaliii llips Alaska. Inc. go corvoucroX: ae SAFETY MTV', GAS LIFT, SDRFACE:3<0 GAS LIFT, GAS LIFT GAS LIFT, GAS LIFT APERF,%M GB,3S90- CTD Dner Lopl Well Attributes I Max Angle & MD ITO Field Name WNlbore APWWI I.E.I. 5rslua Icl (•) KUPARUK RIVER UNIT 50029211 d101 INJ 5.69 MB InKBI 9,J00.59 AciBM(XKBI 9,940.0 Camirenl X351ppm) Date IT AnmlNian Ldst WO: End Dade KBGN IXI 40.98 RR Date 10I101198 OIa.r lan, Annoation Depth (ftKB) WWIWm End Date Lap Mad By Last Tag: ELM 8,296.0 2G-14A 5/20I2015 mansen Last Rev Reason Annotation WeIIWm End Date Last Moat By Rev Reason: Replaced SPG w/OMV I 2G-14A I 1211 W2023 lergusp Notes: General & Safety Annotation Ena ope Lut MM ay NOTE: WAIVERED WAG INJ WITH TRIA ON GAS 5I12Q019 free. Casing Strings C¢g Des OD lint ID lint Top IfiKB) SITCepth semepth (fiK8) ITVDI IIMBI W en 9E1tl Grade I Top TMead WINDOW 'I I 8,45J.0 1 8,462.0 6088.2 LINER 23,81 1.991 8,839./1 9940.01 14.60 1 L-90 ETL Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top lftKBI Set,-'h...SHOepth- Slring Max N"...TuMmd Deacripion WIIIbRI Grade Top Connection ID lint 32.0 8,3J3.9 6,024.4 3112 TUBING 9.30 J-55 1 EUE8mI 12.99 Completion Details: excludes tubing, pup, space out, thread, RKB... Top MR.) Top ITVDI (flXB) Top Intl (•I hem Des OD Nan" (in) Com Meke Model Nominal ID (in) 32.0 32.0 0.00 HANGER 8.000 McEVOY TUBING HANGER 3.500 2,054.8 1.920.4 40.30 SAFETYVLV 5.937 BAKER FVL(LOCKED OUT 6/182001) 2.81D 2,104.2 1.957.6 42.13 GAS LIFT 5.312 MMH FMHO 2.937 4.420.3 3,427.6 51.30 GAS LIFT 5.312 MMH FMHO 2.937 61165.8 4,552.8 48.33 GAS LIFT 5.312 MMH FMHO 2.937 7,473.1 5,413.0 49.98 GAS LIFT 5.312 MMH FMHO 2.937 8,289.2 5,963.5 44.53 GAS LIFT 5.312 MMH FMHO 2.937 81330.9 5,993.3 44.14 PER 5.000 BAKER PER 2.810 8,344.6 6,003.2 44.01 PACKER 5.968 BAKER FHL PACKER 3.000 8,361.6 6.015.5 43.B4 NIPPLE I 4.000 CAMOO'DNIPPLE(MIIletlout 5113/2015) 2.800 8,3J3.2 6,023.8 1 43.14 SOS 1 4U00 I BAKER SHEAR OUT SUB 3.000 Other In Hole (Wlrellne retrievable plugs, valves, pumps, fish, etc.) Top lrvD) Top LIKE) (ftKB) ropincir) Bea I C"m I Make I Model I N Run Bate IB L.) 8,363.0 6DI65 43.83 CTO Liner Top 2G-14AL1 2318" CID Liner I 5121I2015 I TaMU Mandrel Inserts : excludes pulled Inserts Top IBKB) Top I. (MET st pi Top on Inc.l°) No Sery Type GD (in) TRO Run Pe) Run Ope Com Make McdN Pod aim (in) 2,1042 1,957.6 42.13 1 GAS LIFT 711MO15 530 0.000 4,420.3 3,427.6 51.30 2 GAS LIFT JDMYK 711MO15 200 O.00D 6165.8 4,552.8 48.33 3 GAS LIFT Ij 612D2001 930 0.000 7,473.1 5,413.0 49.98 4 GAS LIFT 612D4001 430 0.000 8289.2 5963.5 44.53 5 GAS LIFT lV16/2023 800 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, Float, sub, shoe... Top (Win Top (ND) llh(B) Topincl I°) hem Des GD Nominal Pn) Com Make MotlM Nominal ID (in) 8,839.7 6,130.2 B9.32 BILLET 1 2.625 BAKE BILLET HALLIMINLMLINER TOP Baker 1.000 Perforations & Slots Top (ftKB) Bt. (Al(M(B) ToplrvD) etm MIDIDen. MKB) Ilnke42one DaM shin plwta/ft) Type Can 8.864.3 9.9346 8.130.5 8.95.2 A<, 2G-14A 5/29I2015 I SLOTS I Sbnetl Liner MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, June 12, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 2G-14A KUPARUK RIV UNIT 2G-14A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 06/12/2024 2G-14A 50-029-21161-01-00 215-050-0 W SPT 6003 2150500 3000 2160 2160 2160 2160 20 20 20 20 REQVAR P Adam Earl 5/1/2024 Tested as per AIO 2C.068 to MAIP 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 2G-14A Inspection Date: Tubing OA Packer Depth 620 3310 3230 3230IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE240501201335 BBL Pumped:2.6 BBL Returned:2.5 Wednesday, June 12, 2024 Page 1 of 1            MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, June 13, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 2G-14A KUPARUK RIV UNIT 2G-14A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 06/13/2022 2G-14A 50-029-21161-01-00 215-050-0 W SPT 6003 2150500 3000 2060 2060 2060 2060 200 440 440 440 REQVAR P Adam Earl 5/4/2022 MIT IA to max ant. Inj. Psi. per 2C.068 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 2G-14A Inspection Date: Tubing OA Packer Depth 970 3290 3220 3220IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE220509132901 BBL Pumped:2.2 BBL Returned:2.2 Monday, June 13, 2022 Page 1 of 1 9 9 9 9 9 9 9 9 99 9 9MIT IA 2C.068 James B. Regg Digitally signed by James B. Regg Date: 2022.06.13 14:25:22 -08'00' Wallace, Chris D (CED) From: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent: Thursday, May 6, 2021 10:48 AM To: Wallace, Chris D (CED) Cc: Earhart, Will C; Well Integrity Specialist CPF2 Subject: Kuparuk injector 2G -14A (PTD# 215-050) Monitor period completion. Attachments: 2G-14 90 day TIO.pdf Chris- Kuparuk injector 2G -14A (PTD #215-050) has completed the extended monitor period for unexplainable IA pressure fluctuations. The IA passed a diagnostic MIT -IA to 3000 psi and IC POTs. The IA DDT initially failed however there was a temperature fluctuation that occurred simultaneously in which was determined to be the cause of failure. After injection rates and the temperature stabilized the IA has shown no further unexpected pressure anomalies. CPAI intends to return the well to normal injection status under 2C.068 and will report any further pressure anomalies as required. Please let me know if you have any question or disagree with the plan. Attached is the current 90 day TIO plot. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 WELLS TEAM Canoco'Mffips From: V017%W.ILity Specialist CPF2 <n2549@conocophillips.com> Sent: Monday, Apr i 213:08 PM To: Wallace, Chris D (DOA) is.waIlace @alaska.gov> Cc: Earhart, Will C <William.C.Ear @conocophillips.com>; Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: Kuparuk injector 2G -14A (PTD# 2130) Monitor period update Chris- Kuparuk injector 2G-14 (PTD#215-050) is nearing the en the 30 day monitor period for unexplainable IA pressure fluctuations. During the monitor period, there were unforeseen ' cumstances which created the need to WAG the well to produced water and then back to seawater. Due to having multip ariables, (injection rates & temperature), the monitor period produced inconclusive results. CPAI intends to extend the nitor period by an addition 30 days to continue to monitor under stable conditions barring any further facility issues. ached is a current copy of the 90 day TIO plot. Please let me know if you have any questions or disagree with the plan. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 WELLS TEAM CorwA Nips Wallace, Chris D (GED) From: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent: Monday, April 5, 2021 3:08 PM To: Wallace, Chris D (CED) Cc: Earhart, Will C; Well Integrity Specialist CPF2 Subject: Kuparuk injector 2G -14A (PTD# 215-050) Monitor period update Attachments: 2G-14 90 day TIO.xlsm Chris- Kuparuk injector 2G-14 (PTD#215-050) is nearing the end of the 30 day monitor period for unexplainable IA pressure fluctuations. During the monitor period, there were unforeseen circumstances which created the need to WAG the well to produced water and then back to seawater. Due to having multiple variables, (injection rates & temperature), the monitor period produced inconclusive results. CPAI intends to extend the monitor period by an addition 30 days to continue to monitor under stable conditions barring any further facility issues. Attached is a current copy of the 90 day TIO plot. Please let me know if you have any questions or disagree with the plan. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 WELLS TEAM Can 6mnips From: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent: Wednesday, March 3, 20212:21 PM To: Wallace, Chris D (DOA) <chris.wallace@alaska.gov> Cc: Well Integrity Specialist CPF2 <n2549@conocophillips.com>; Earhart, Will C <William.C.Earhart@conocophillips.com>; 5enden, R. Tyler <R.Tyler.Senden@conocophillips.com> Subject: Kuparuk injector 2G -14A (PTD# 215-050) Report of unexplainable IA pressure fluctuation. Chris- Kuparuk injector 2G -14A (PTD# 215-050) has shown unexplainable IA pressure fluctuations recently. The well currently operates under AIO 2C.068 Water injection only due to TxIA communication while on gas injection. CPAI intends to leave the well on injection and conduct the initial series of diagnostics to investigate the cause of the pressure changes. Depending on the results of the diagnostics the proper notifications for continued injection or repair will be submitted at that time. If the initial diagnostics prove integrity, the well will be put onto a 30 day monitor period for additional observations. Attached are the current 90 day TIO plot and well bore schematic. Please let me know if you have any questions or disagree with the plan. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 WELLS TEAM Coiwoo�'hl�ips Wallace, Chris D (CED) From: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent: Wednesday, March 3, 2021 2:21 PM To: Wallace, Chris D (CED) Cc: Well Integrity Specialist CPF2; Earhart, Will C; Senden, R. Tyler Subject: Kuparuk injector 2G -14A (PTD# 215-050) Report of unexplainable IA pressure fluctuation. Attachments: 2G-14 90 Day TIO.pdf; 2G-14A.pdf Chris- Kuparuk injector 2G -14A (PTD# 215-050) has shown unexplainable IA pressure fluctuations recently. The well currently operates under AIO 2C.068 Water injection only due to TxIA communication while on gas injection. CPAI intends to leave the well on injection and conduct the initial series of diagnostics to investigate the cause of the pressure changes. Depending on the results of the diagnostics the proper notifications for continued injection or repair will be submitted at that time. If the initial diagnostics prove integrity, the well will be put onto a 30 day monitor period for additional observations. Attached are the current 90 day TIO plot and well bore schematic. Please let me know if you have any questions or disagree with the plan. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 WELLS TEAM quips MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission To: Jim Regg DATE: Monday, August 3, 2020 / P.I. Supervisor 7,2z(l `Il Zt I SUBJECT: Mechanical Integrity Tests ConocoPhillips Alaska, Inc. 2G -14A FROM: Matt Herrera KUPARUK RIV UNIT 2G -14A Petroleum Inspector Sre: Inspector Reviewed By: P.I. Supry y5z— NON -CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 2G -14A API Well Number 50-029-21161-01-00 Inspector Name: Matt Herrera Permit Number: 215-050-0 Inspection Date: 7/30/2020 Insp Num: mitMFH2O0730130905 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 2G -14A Type Inj w' TVD 6003 - Tubing 1530 1530 , 1530 - 1530 PTD 2150500 Type 'fest SPT Test psi 3000 IA 900 3320 3260 - 3250 ' BBL Pumped: 2.7 BBL Returned: 2.6 OA 420 670 - 670 _ 670' Interval REQVAR P/F P Notes: MITIA performed to MAIP Per AIO 2C.068 ✓ Monday, August 3, 2020 Page 1 of 1 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Remove tubing patch Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 8750 feet NA feet true vertical 6297 feet NA feet Effective Depth measured 8362 feet 8345 feet true vertical 6016 feet 6003 feet Perforation depth Measured depth 8378' - 8532'feet True Vertical depth 6027' - 6139'feet Tubing (size, grade, measured and true vertical depth)3.5 J-55 8374 6024 Packers and SSSV (type, measured and true vertical depth)Baker FHL packer Baker FVL (locked out) 8345 MD 6003 TVD 2054 MD 1920 TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name:Jan Byrne/ Dusty Freeborn Authorized Title:Well Integrity Compliance Specialist Contact Email:N1617@conocophillips.com Contact Phone:907-659-7224 8724 WINJ WAG Water-Bbl MD 110 3327 9940 TVD Tubing PressureOil-Bbl measured true vertical Packer 7 2 3/8 Plugs Junk P.O. Box 100360, Anchorage, Alaska 995103. Address: 4. Well Class Before Work: Representative Daily Average Production or Injection Data KRU 2G-14A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-050 50-029-21161-01-00 ADL0025667 measured 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-167 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) Gas-Mcf Authorized Signature with date: Authorized Name: Jan Byrne Casing Pressure Liner 1100 5. Permit to Drill Number: Kurparuk River / Kuparuk River Oil measured 8761 Conductor Surface Intermediate Production Casing Structural 16 9 5/8 Length 72 3293 110 2760 6278 6175 Burst ConocoPhillips Alaska, Inc. 2. Operator Name Senior Engineer:Senior Res. Engineer: Collapse t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations Digitally signed by jan.byrne@conocophillips.com DN: CN=jan.byrne@conocophillips.com Reason: I am the author of this document Location: Kuparuk, F-wing, F-217 Date: 2020-05-14 08:04:36 Foxit PhantomPDF Version: 9.7.0 jan.byrne@conocophillip s.com By Samantha Carlisle at 8:41 am, May 14, 2020 DSR-5/14/2020 SFD 5/21/2020 9940 SFD 5/21/2020VTL 5/26/20 6175 RBDMS HEW 5/15/2020 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 14 May 2020 Commissioner Jessie Chmielowski Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Chmielowski, Enclosed please find the 10-404 Report for Sundry 320-167 Well Operations for ConocoPhillips Alaska, Inc. well KRU 2G-14A (PTD 215-050) for pulling a retrievable tubing patch. The well is planned to be returned to water injection only under AIO2C.068. Please contact Dusty Freeborn or myself at 659-7224 if you have any questions. Sincerely, Jan Byrne Well Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Digitally signed by jan.byrne@conocophillips.com DN: CN=jan.byrne@conocophillips.com Reason: I am the author of this document Location: Kuparuk, F-wing, F-217 Date: 2020-05-14 08:01:36 Foxit PhantomPDF Version: 9.7.0 jan.byrne@co nocophillips.c om Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag: SLM 8,296.0 5/20/2015 2G-14A smsmith Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Pulled Patch & Replaced DV 5/13/2020 2G-14A zembaej Casing Strings Casing Description WINDOW OD (in) 7 ID (in) Top (ftKB) 8,457.0 Set Depth (ftKB) 8,462.0 Set Depth (TVD) … 6,088.2 Wt/Len (l…Grade Top Thread Casing Description LINER OD (in) 2 3/8 ID (in) 1.99 Top (ftKB) 8,839.7 Set Depth (ftKB) 9,940.0 Set Depth (TVD) … Wt/Len (l… 4.60 Grade L-80 Top Thread STL Liner Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 8,839.7 6,130.2 89.32 BILLET BAKER ALUMINUM LINER TOP BILLET 1.000 Tubing Strings Tubing Description TUBING String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 32.0 Set Depth (ft… 8,373.9 Set Depth (TVD) (… 6,024.4 Wt (lb/ft) 9.30 Grade J-55 Top Connection EUE8rd Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 32.0 32.0 0.00 HANGER McEVOY TUBING HANGER 3.500 2,054.8 1,920.4 40.30 SAFETY VLV BAKER FVL (LOCKED OUT 6/18/2001) 2.810 8,330.9 5,993.3 44.14 PBR BAKER PBR 2.810 8,344.6 6,003.2 44.01 PACKER BAKER FHL PACKER 3.000 8,361.6 6,015.5 43.84 NIPPLE CAMCO 'D' NIPPLE (Milled out 5/13/2015) 2.800 8,373.2 6,023.8 43.74 SOS BAKER SHEAR OUT SUB 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) SN 8,363.0 6,016.5 43.83 CTD Liner Top 2G-14AL1 2 3/8" CTD Liner 5/21/2015 1.990 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com 8,864.3 9,939.6 6,130.5 6,175.2 A-4, 2G-14A 5/29/2015 SLOTS Slotted Liner Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 2,104.2 1,957.6 MMH FMHO 1 GAS LIFT DMY BK 0.000 7/12/2015 5:30 2 4,420.3 3,427.6 MMH FMHO 1 GAS LIFT DMY BK 0.000 0.0 7/12/2015 2:00 3 6,165.8 4,552.8 MMH FMHO 1 GAS LIFT DMY BK 0.000 0.0 6/20/2001 9:30 4 7,473.1 5,413.0 MMH FMHO 1 GAS LIFT DMY BK 0.000 0.0 6/20/2001 4:30 5 8,289.2 5,963.5 MMH FMHO 1 GAS LIFT DMY BTM 0.000 0.0 5/13/2020 8:00 Notes: General & Safety End Date Annotation 5/12/2019 NOTE: WAIVERED WAG INJ WITH TXIA ON GAS 2G-14A, 5/14/2020 4:36:33 AM Vertical schematic (actual) LINER; 8,839.7-9,940.0 SLOTS; 8,864.3-9,939.6 CTD Liner Top; 8,363.0 L1 LINER; 8,362.4-9,940.0 SLOTS; 8,377.5-9,939.6 WINDOW; 8,457.0-8,462.0 PRODUCTION; 33.0-8,724.0 RPERF; 8,452.0-8,458.0 SOS; 8,373.2 NIPPLE; 8,361.6 APERF; 8,357.0-8,359.0 PACKER; 8,344.6 PBR; 8,330.9 Cement Plug; 8,296.0 ftKB GAS LIFT; 8,289.2 GAS LIFT; 7,473.1 GAS LIFT; 6,165.8 GAS LIFT; 4,420.3 SURFACE; 34.0-3,327.0 GAS LIFT; 2,104.2 SAFETY VLV; 2,054.8 CONDUCTOR; 38.0-110.0 HANGER; 32.0 KUP INJ KB-Grd (ft) 40.98 Rig Release Date 10/10/1984 2G-14A ... TD Act Btm (ftKB) 9,940.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292116101 Wellbore Status INJ Max Angle & MD Incl (°) 95.69 MD (ftKB) 9,700.59 WELLNAME WELLBORE2G-14A Annotation Last WO: End DateH2S (ppm) DateComment SSSV: LOCKED OUT Wallace, Chris D (CED) From: Well Integrity Compliance Specialist CPF1 & 2 <n1617@conocophillips.com> Sent: Wednesday, April 15, 2020 8:07 AM To: Wallace, Chris D (CED) Cc: CPA Wells Supt Subject: KRU 2G -14A (PTD 215-050) Update 4/15/2020 Chris - I wanted to give you an update on the status of KRU injector 2G -14A (PTD #215-050/A10 2C.068). Due to the inability to regain TxIA integrity with the tubing patch over the suspected gas leaks, CPAI intends to pull the patch and return the well to operate as a water injector only under A10 2C.068. A 10-403 has been submitted to pull the patch attempt and return the well to water injection only, as requested by Victoria. If the well displays TxIA communication while on water injection the well will be reported as normal protocol requires. Please let me know if you have any questions or disagree with this plan. Dusty Freeborn/Jan Byrne Wells Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 WELLS TEAM From: Well Integrity Compliance Specialist CPF1 & 2 Sent: Sunday, April 5, 2020 4:32 PM To:'Wallace, Chris D (CED)' <chris.waIlace @alaska.gov> Cc: CPA Wells Supt <n1030@conocophillips.com> Subject: RE: KRU 2G -14A (PTD 215-050) Update 4/5/2020 Chris, KRU WAG injector 2G -14A (PTD 215-050) (AIO 2C.068): The well is on a 60 day gas injection monitor period which began February 25th, 2020 and is now exhibited signs of TxIA communication. The plan is to shut in and freeze protect the well as soon as possible. The proper paperwork for continued injection or corrective action will be submitted once the path forward has been determined. A wellbore schematic and 90 day TIO trend are attached. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne / Dusty Freeborn Well Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Cell phone: (808) 345-6886 Office phone: (907) 659-7224 From: Well Integrity Compliance Specialist CPF1 & 2 Sent: Tuesday, January 21, 2020 10:21 AM To: 'ch ris.waIlace @alaska.gov' <chris.waIlace @alaska.gov> Cc: CPA Wells Supt <n1030@conocophillips.com> Subject: RE: KRU 2G -14A (PTD 215-050) Update 1/21/20 Chris, KRU WAG injector 2G -14A (PTD 215-050) (AIO 2C.068): After the last correspondence the IA and OA pressures were bled, subsequent which one of the CPF2 water injection pumps failed and all the seawater injectors were swapped to producer water, of which 2G-14 is one. The IA and OA pressures rose in response to the thermal increase, but after the pump was repaired and seawater was returned to 2G-14 the IA and OA pressures appear to have stabilized. CPAI intends to extend the monitor period on water injection for an additional 30 days to confirm stabilization. If the IA and OA pressures remain stable the well will be placed on a 60 day gas injection monitor to determine if the patch installed over the SSSV repaired the previous gas leak. The proper paperwork for continued injection or corrective action will be submitted upon conclusion of the monitors. A 90 day TIO trend and wellbore schematic is attached. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne / Dusty Freeborn Well Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 4 IWELLS TEAM ca.,oc;mgips From: Well Integrity Compliance Specialist CPF1 & 2 Sent: Monday, December 23, 2019 5:01 PM To: chris.wallace@alaska.gov Cc: CPA Wells Supt <n1030@conocophillips.com>; Well Integrity Compliance Specialist CPF1 & 2 <n1617@conocophillips.com> Subject: RE: KRU 2G -14A (PTD 215-050) Report of suspect OA pressure increase Chris- KRU WAG injector 2G -14A (PTD 215-050) (AIO 2C.068) is nearing the end of the 30 day monitor period for the suspect OA pressure increase. The OA has continued to show pressure increase however the IA has shown a very similar upward pressure trend. Due to the inability to determine if the OA pressure is influenced thermally or the pressure increase is due to an unknown source, CPAI intends to extend the monitor period for an additional 30 days to allow for pressure stabilization and/or manipulation of the IA and OA pressures to identify the cause of the OA pressure increase. Please let me know if you have any questions or disagree with the plan. Attached is a copy of the most recent 90 TIO trend. Dusty Freeborn/Jan Byrne Wells Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 WELLS TEAM Conoc, Phiuips From: Well Integrity Compliance Specialist CPF1 & 2 Sent: Wednesday, July 31, 2019 7:42 AM To:'chris.wallace@alaska.gov' <chris.wallace@alaska.gov> Cc: CPA Wells Supt <n1030@conocophillips.com> Subject: KRU 2G -14A (PTD 215-050) Report of suspect OA pressure increase Chris, KRU WAG injector 2G -14A (PTD 215-050) (AIO 2C.068) has been shut in since January 19, 2019. The well is exhibiting suspect OA pressure increase. DHD will mobilize to perform initial diagnostics. If diagnostic tests pass and the well is brought online it will be placed on a 30 day monitor period. The proper paperwork for continued injection or corrective action will be submitted once the path forward has been determined. A wellbore schematic and TIO trend are attached. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne / Dusty Freeborn Well Integrity & Compliance Specialist, CPF1 & 2 ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 WELLS TEAM Caooclwmips Wallace, Chris D (CED) From: Well Integrity Compliance Specialist CPF1 & 2 <n1617@conocophillips.com> Sent: Sunday, April 5, 2020 4:32 PM To: Wallace, Chris D (CED) Cc: CPA Wells Supt Subject: RE: KRU 2G -14A (PTD 215-050) Update 4/5/2020 Attachments: 2G-14 90 day TIO trend 4-5-2020.pdf, 2G-14A.pdf Chris, KRU WAG injector 2G -14A (PTD 215-050) (AIO 2C.068): The well is on a 60 day gas injection monitor period which began February 25th, 2020 and is now exhibited signs of TxIA communication. The plan is to shut in and freeze protect the well as soon as possible. The proper paperwork for continued injection or corrective action will be submitted once the path forward has been determined. A wellbore schematic and 90 day TIO trend are attached. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne / Dusty Freeborn Well Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Cell phone: (808) 345-6886 Office phone: (907) 659-7224 From: Well Integrity Compliance Specialist CPF1 & 2 Sent: Tuesday, January 21, 2020 10:21 AM To: 'ch ris.wa I lace @a laska.gov' <chris.waIlace @alaska.gov> Cc: CPA Wells Supt <n1030@conocophillips.com> Subject: RE: KRU 2G -14A (PTD 215-050) Update 1/21/20 Chris, KRU WAG injector 2G -14A (PTD 215-050) (AIO 2C.068): After the last correspondence the IA and OA pressures were bled, subsequent which one of the CPF2 water injection pumps failed and all the seawater injectors were swapped to producer water, of which 2G-14 is one. The IA and OA pressures rose in response to the thermal increase, but after the pump was repaired and seawater was returned to 2G-14 the IA and OA pressures appear to have stabilized. CPAI intends to extend the monitor period on water injection for an additional 30 days to confirm stabilization. If the IA and OA pressures remain stable the well will be placed on a 60 day gas injection monitor to determine if the patch installed over the SSSV repaired the previous gas leak. The proper paperwork for continued injection or corrective action will be submitted upon conclusion of the monitors. A 90 day TIO trend and wellbore schematic is attached. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne / Dusty Freeborn Well Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 APA WELLS TEAM conocc>halips From: Well Integrity Compliance Specialist CPF1 & 2 Sent: Monday, December 23, 2019 5:01 PM To: chris.wallace@alaska.gov Cc: CPA Wells Supt <n1030@conocophillips.com>; Well Integrity Compliance Specialist CPF1 & 2 <n1617@conocophillips.com> Subject: RE: KRU 2G -14A (PTD 215-050) Report of suspect OA pressure increase Chris- KRU WAG injector 2G -14A (PTD 215-050) (AIO 2C.068) is nearing the end of the 30 day monitor period for the suspect OA pressure increase. The OA has continued to show pressure increase however the IA has shown a very similar upward pressure trend. Due to the inability to determine if the OA pressure is influenced thermally or the pressure increase is due to an unknown source, CPAI intends to extend the monitor period for an additional 30 days to allow for pressure stabilization and/or manipulation of the IA and OA pressures to identify the cause of the OA pressure increase. Please let me know if you have any questions or disagree with the plan. Attached is a copy of the most recent 90 TIO trend. Dusty Freeborn/Jan Byrne Wells Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 WELLS TEAM Conoco` wlips From: Well Integrity Compliance Specialist CPF1 & 2 Sent: Wednesday, July 31, 2019 7:42 AM To: 'chris.waIlace @alaska.gov' <chris.waIlace@alaska.gov> Cc: CPA Wells Supt <n1030@conocophillips.com> Subject: KRU 2G -14A (PTD 215-050) Report of suspect OA pressure increase Chris, KRU WAG injector 2G -14A (PTD 215-050) (AIO 2C.068) has been shut in since January 19, 2019. The well is exhibiting suspect OA pressure increase. DHD will mobilize to perform initial diagnostics. If diagnostic tests pass and the well is brought online it will be placed on a 30 day monitor period. The proper paperwork for continued injection or corrective action will be submitted once the path forward has been determined. A wellbore schematic and TIO trend are attached. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne / Dusty Freeborn Well Integrity & Compliance Specialist, CPF1 & 2 ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 WELLS TEAM 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): Casing Collapse Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: Perforation Depth MD (ft): TVD BurstMDLength Size Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): approval: Notify Commission so that a representative may witness Sundry Number: BOP TestMechanical Integrity Test Location Clearance ection MIT Req'd? Yes No ption Required? Yes No Subsequent Form Required: COMMISSION USE ONLY Contact Name: Contact Email: Contact Phone: Date: e: certify that the foregoing is true and the procedure approved herein will not rom without prior written approval. gnature: me: Date for 15. Well Status after proposed work: Operations: OILWINJ W DSPL Suspended proval: Date: GASWAGGSTOR SPLUG Representative:GINJ Op Shutdown Abandoned nts: Proposal Summary Wellbore schematic13. Well Class after proposed work: ations Program BOP SketchExploratory Stratigraphic Development Service quest: Abandon Plug Perforations Fracture Stimulate Repair We Operations shutdown pair Well Suspend Perforate Other Stimulate Pull Tub Change Approved Program ll Tubing Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___er Casing ________________ __ ame: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development Stratigraphic Service 6. API Number: g:8. Well Name and Number: ation or Conservation Order governs well spacing in this pool? perforations require a spacing exception? Yes No esignation (Lease Number): 10. Field/Pool(s): D (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD):Junk (MD): g Collapse SSSV Type: Packers and SSSV MD (ft) and TVD (ft): pth MD (ft): TVD BurstMDLengthSize Perforation Depth TVD (ft):Tubing Size: PRESENT WELL CONDITION SUMMARY Tubing Grade: Tubing MD (ft): Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. ConocoPhillips Alaska, Inc P.O. Box 100360, Anchorage Alaska 99510 184-130 50029211610000 N/A KRU 2G-14A ADL0025667 Kuparuk River/Kuparuk River oil 8750 6297 8362 6016 2721 N/A N/A Conductor 72 16 110 110 Surface 3293 9 5/8 3327 2760 Production 8761 7 8724 6278 L1 Liner 1577 2 3/8 9940 6175 Liner 1100 2 3/8 9940 6175 940,8864-9937,8357-8359, 84555,6131-6175,6012-6014, 60 3 1/2 J-55 8379 Baker FHL Packer & Baker FVL (Locked out)8345 MD 6003 TVD & 2054 MD 1920 TVD 4/20/20 N/A N/A Dusty Freeborn Well Integrity & Compliance Specialist Dusty Freeborn Digitally signed by Dusty Freeborn Date: 2020.04.14 20:20:52 -08'00'4/14/20 Dusty Freeborn/Jan Byrne N1617@conocophillips.com 907-830-9777 ✔Remove tubing patc ✔ ✔ ✔ By Samantha Carlisle at 8:02 am, Apr 15, 2020 320-167 50-029-21161-01-00 DSR-4/15/2020 X 215-050 DLB DLB DLB 04/15/2020 X 10-404X VTL 4/15/20Comm. 4/16/2020 dts 4/15/2020 JLC 4/16/2020 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 14 April 2020 Commissioner Jessie Chmielowski Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Chmielowski, Enclosed please find the 10-403 Application for Sundry Approval for ConocoPhillips Alaska, Inc. well KRU 2G-14A (PTD 215-050) to pull retrievable tubing patch that was used as an attempt to repair a gas only leak and return the well to water injection only under AIO2C.068. Please contact Jan Byrne or myself at 659-7224 if you have any questions. Sincerely, Dusty Freeborn Well Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Dusty Freeborn Digitally signed by Dusty Freeborn Date: 2020.04.14 20:19:59 -08'00' KRU 2G-14 (PTD #215-050) Description Summary of Proposal Well Work Justification & Objectives (and date required if appropriate): 2G-14 was in a diagnostic 60 day monitor period to verify integrity of a patch attempt over the known gas leaks in the tubing. During the monitor period the IA continued to build in pressure indicating that TxIA communication while on gas injection still existed. The well needs to return to normal well conditions and return to a water injector only under AIO 2C.068. Risk/Job Concerns: -Broken SSSV; has been locked out -SSSV control line may be parted -Tubing patch currently installed is V0 rated. -IA FL last shot at ~2750' and gas needs to be circulated out. -Camco D nipple at 8362' has been milled out and is unaccessible. -DO NOT PERFORM WORK UNTIL 10-403 HAS BEEN APPROVED Steps: S-line 1. Have jumper line hooked from IA to available flow line. 2. Pull upper P2P (V0 rated), spacer pipe and anchor latch from 2046' (OAL= 27'). 3. Pull lower P2P (V0 rated) from 2072'. 4. Set baited holdfinder assembly with catcher on liner top at 8363'. (Alternative plugs/catcher assemblies are acceptable due to the only use is a fluids platform). Perform tubing pressure test to confirm set. Proceed to step 4 if pressure test passes. 5. Pull dummy valve from station #5. 6. Pump 225 bbls of 1% CRW SW followed by 70 bbls diesel down the tubing taking returns off the IA. U- tube to equalize freeze protect. 7. Set dummy valve into station #5. 8. Perform MIT-IA to 3000 psi. Record initial, 15 min and 30 min TIO pressures. A. If MIT-IA passes, bleed IA pressure to starting pressure and proceed to step #9. B. If MIT-IA fails trouble shoot failure mechanism. 9. Pull catcher and plug assembly and turn well over to operations. Notify WICS prior to BOI. SW MIT-IA required Last Tag Annotation Depth (ftKB) End Date Last Mod By Wellbore Last Tag:smsmith 2G-14AL1 Last Rev Reason Annotation End Date Last Mod By Wellbore Rev Reason: Set patch over SSSV 11/18/2019 famaj 2G-14A Notes: General & Safety End Date 5/21/2015 Annotation NOTE: WELL SIDETRACKED, ADDED LATERAL AL1 (OFF MAIN WELLBORE) Wellbore 2G-14AL1 End Date 5/12/2019 Annotation NOTE: WAIVERED WAG INJ WITH TXIA ON GAS Wellbore 2G-14A Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread Wellbore CONDUCTOR 16 15.06 38.0 110.0 110.0 62.50 H-40 WELDED 2G-14 SURFACE 9 5/8 8.92 34.0 3,327.0 2,760.0 36.00 L-80 BUTT 2G-14 WINDOW 7 8,457.0 8,462.0 6,088.2 2G-14A PRODUCTION 7 6.28 32.9 8,724.0 6,278.3 26.00 J-55 BUTT 2G-14 L1 LINER 2 3/8 1.99 8,362.5 9,940.0 4.60 L-80 STL 2G-14AL1 LINER 2 3/8 1.99 8,839.7 9,940.0 4.60 L-80 STL 2G-14A Tubing Strings Des String Max Nominal OD (in)ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt (lb/ft) Grade Top Thread Wellbore TUBING 3 1/2 2.99 32.0 8,373.9 6,024.4 9.30 J-55 EUE8rd 2G-14A Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) Wellbore 32.0 32.0 0.00 HANGER McEVOY TUBING HANGER 3.500 2G-14A 2,054.8 1,920.4 40.30 SAFETY VLV BAKER FVL (LOCKED OUT 6/18/2001) 2.810 2G-14A 8,330.9 5,993.3 44.14 PBR BAKER PBR 2.810 2G-14A 8,344.6 6,003.2 44.01 PACKER BAKER FHL PACKER 3.000 2G-14A 8,361.6 6,015.5 43.84 NIPPLE CAMCO 'D' NIPPLE (Milled out 5/13/2015) 2.800 2G-14A 8,373.2 6,023.8 43.74 SOS BAKER SHEAR OUT SUB 3.000 2G-14A Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) Wellbore 2,046.0 1,913.7 39.98 Patch 2.72" P2P (VO rated ALPPHP35004) w/ Spacer pipe and Anchor latch (CPAL35061). OAL 27' Max OD 2.72" 11/18/2019 1.625 2G-14 2,050.0 1,916.7 40.13 Spacer Pipe 2 1/16" P-110 Spacer Pipe. 11/18/2019 1.670 2G-14 2,072.0 1,933.4 40.94 Patch 2.72" P2P (VO rated ALPPHP35003). OAL4' Max OD 2.72" 11/18/2019 1.625 2G-14 8,455.0 6,083.1 43.45 WHIPSTOCK - MONOBORE Baker 3.5'' XL Monobore Whipstock with OH Anchor 5/26/2015 2G-14 Liner Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) Wellbore 34.0 34.0 0.01 HANGER 9.625 2G-14 38.0 38.0 0.01 CONDUCTOR 15.062 2G-14 8,362.5 6,016.1 43.84 DEPLOY BAKER SHORTY DEPLOYMENT SLEEVE 1.000 2G-14AL1 8,457.0 6,084.6 43.70 Window 2G-14A 8,488.3 6,107.4 43.43 PROD CSG 6.276 2G-14 8,839.7 6,130.2 89.32 BILLET BAKER ALUMINUM LINER TOP BILLET 1.000 2G-14A Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com Wellbore 8,377.5 9,939.6 6,026.9 6,154.7 A-5, 2G-14AL1 5/31/2015 SLOTS Slotted Liner 2G-14AL1 8,864.3 9,939.6 6,130.5 6,175.2 A-4, 2G-14A 5/29/2015 SLOTS Slotted Liner 2G-14A 8,357.0 8,359.0 6,012.1 6,013.6 A-4, 2G-14 4/20/2015 3.0 APERF 2" HSC 120 deg, bh charges 2G-14 8,452.0 8,458.0 6,081.0 6,085.3 A-5, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,458.0 8,459.0 6,085.3 6,086.1 A-5, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,458.0 8,459.0 6,085.3 6,086.1 A-5, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,459.0 8,460.0 6,086.1 6,086.8 A-5, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,459.0 8,466.0 6,086.1 6,091.1 A-5, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,465.0 8,466.0 6,090.4 6,091.1 A-5, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,466.0 8,467.0 6,091.1 6,091.9 A-5, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,467.0 8,468.0 6,091.9 6,092.6 A-5, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,467.0 8,470.0 6,091.9 6,094.0 A-5, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,490.0 8,495.0 6,108.6 6,112.2 A-4, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,495.0 8,498.0 6,112.2 6,114.4 A-4, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,495.0 8,496.0 6,112.2 6,112.9 A-4, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,498.0 8,499.0 6,114.4 6,115.1 A-4, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,498.0 8,499.0 6,114.4 6,115.1 A-4, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 Comment SSSV: LOCKED OUT 2G-14, 11/21/2019 10:57:36 AM Vertical schematic (actual) PRODUCTION; 33.0- 8,724.0 RPERF; 8,530.0-8,532.0 RPERF; 8,526.0-8,530.0 RPERF; 8,516.0-8,526.0 RPERF; 8,515.0-8,516.0 RPERF; 8,511.0-8,516.0 RPERF; 8,508.0-8,511.0 RPERF; 8,503.0-8,508.0 RPERF; 8,502.0-8,503.0 RPERF; 8,499.0-8,503.0 RPERF; 8,499.0 RPERF; 8,498.0-8,499.0 RPERF; 8,498.0-8,499.0 RPERF; 8,495.0-8,498.0 RPERF; 8,495.0-8,496.0 RPERF; 8,490.0-8,495.0 RPERF; 8,467.0-8,470.0 RPERF; 8,467.0-8,468.0 RPERF; 8,466.0-8,467.0 RPERF; 8,465.0-8,466.0 RPERF; 8,459.0-8,466.0 WHIPSTOCK - MONOBORE; 8,455.0 RPERF; 8,459.0-8,460.0 RPERF; 8,458.0-8,459.0 RPERF; 8,458.0-8,459.0 L1 LINER; 8,362.4- 9,940.0 RPERF; 8,452.0-8,458.0 SLOTS; 8,377.5-9,939.6 SOS; 8,373.2 NIPPLE; 8,361.6 APERF; 8,357.0-8,359.0 PACKER; 8,344.6 PBR; 8,330.9 Cement Plug; 8,296.0 ftKB GAS LIFT; 8,289.2 GAS LIFT; 7,473.1 GAS LIFT; 6,165.8 GAS LIFT; 4,420.3 SURFACE; 34.0-3,327.0 GAS LIFT; 2,104.2 Patch; 2,072.0 SAFETY VLV; 2,054.8 Spacer Pipe; 2,050.0 Patch; 2,046.0 CONDUCTOR; 38.0- 110.0 HANGER; 32.0 KUP INJ KB-Grd (ft) 40.98 Rig Release Date 10/10/1984 Annotation Last WO: End DateH2S (ppm) Date... TD Act Btm (ftKB) 8,750.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292116100 Wellbore Status INJ Max Angle & MD Incl (°) 53.97 MD (ftKB) 4,200.00 Legal Wellname 2G-14 Common Wellname2G-14A AK All Wellbores Schem Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com Wellbore 8,499.0 8,499.0 6,115.1 6,115.1 A-4, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,499.0 8,503.0 6,115.1 6,118.0 A-4, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,502.0 8,503.0 6,117.3 6,118.0 A-4, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,503.0 8,508.0 6,118.0 6,121.6 A-4, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,508.0 8,511.0 6,121.6 6,123.8 A-4, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,511.0 8,516.0 6,123.8 6,127.4 A-4, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,515.0 8,516.0 6,126.7 6,127.4 A-4, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,516.0 8,526.0 6,127.4 6,134.7 A-4, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,526.0 8,530.0 6,134.7 6,137.6 A-4, 2G-14 9/29/1985 5.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 8,530.0 8,532.0 6,137.6 6,139.1 A-4, 2G-14 9/29/1985 4.0 RPERF 2 1/8" BarKone II; 0 deg pH 2G-14 Mandrel Inserts St ati on No /S Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com Wellbore 1 2,104.2 1,957.6 MMH FMHO 1 GAS LIFT DMY BK 0.000 7/12/2015 5:30 2G-14A 2 4,420.3 3,427.6 MMH FMHO 1 GAS LIFT DMY BK 0.000 0.0 7/12/2015 2:00 2G-14A 3 6,165.8 4,552.8 MMH FMHO 1 GAS LIFT DMY BK 0.000 0.0 6/20/2001 9:30 2G-14A 4 7,473.1 5,413.0 MMH FMHO 1 GAS LIFT DMY BK 0.000 0.0 6/20/2001 4:30 2G-14A 5 8,289.2 5,963.5 MMH FMHO 1 GAS LIFT DMY BTM 0.000 0.0 11/17/2019 8:00 2G-14A 2G-14, 11/21/2019 10:57:37 AM Vertical schematic (actual) PRODUCTION; 33.0- 8,724.0 RPERF; 8,530.0-8,532.0 RPERF; 8,526.0-8,530.0 RPERF; 8,516.0-8,526.0 RPERF; 8,515.0-8,516.0 RPERF; 8,511.0-8,516.0 RPERF; 8,508.0-8,511.0 RPERF; 8,503.0-8,508.0 RPERF; 8,502.0-8,503.0 RPERF; 8,499.0-8,503.0 RPERF; 8,499.0 RPERF; 8,498.0-8,499.0 RPERF; 8,498.0-8,499.0 RPERF; 8,495.0-8,498.0 RPERF; 8,495.0-8,496.0 RPERF; 8,490.0-8,495.0 RPERF; 8,467.0-8,470.0 RPERF; 8,467.0-8,468.0 RPERF; 8,466.0-8,467.0 RPERF; 8,465.0-8,466.0 RPERF; 8,459.0-8,466.0 WHIPSTOCK - MONOBORE; 8,455.0 RPERF; 8,459.0-8,460.0 RPERF; 8,458.0-8,459.0 RPERF; 8,458.0-8,459.0 L1 LINER; 8,362.4- 9,940.0 RPERF; 8,452.0-8,458.0 SLOTS; 8,377.5-9,939.6 SOS; 8,373.2 NIPPLE; 8,361.6 APERF; 8,357.0-8,359.0 PACKER; 8,344.6 PBR; 8,330.9 Cement Plug; 8,296.0 ftKB GAS LIFT; 8,289.2 GAS LIFT; 7,473.1 GAS LIFT; 6,165.8 GAS LIFT; 4,420.3 SURFACE; 34.0-3,327.0 GAS LIFT; 2,104.2 Patch; 2,072.0 SAFETY VLV; 2,054.8 Spacer Pipe; 2,050.0 Patch; 2,046.0 CONDUCTOR; 38.0- 110.0 HANGER; 32.0 KUP INJ ... Legal Wellname 2G-14 Common Wellname2G-14A AK All Wellbores Schem Annular Communication Surveillance 15 Well Name:22G-14 Start Date:15-Jan-2020 14 Days:90 End Date:14-Apr-2020 50 70 90 110 130 150 170 0 500 1000 1500 2000 2500 3000 3500 4000 15-Jan-2018-Jan-2021-Jan-2024-Jan-2027-Jan-2030-Jan-202-Feb-205-Feb-208-Feb-2011-Feb-2014-Feb-2017-Feb-2020-Feb-2023-Feb-2026-Feb-2029-Feb-203-Mar-206-Mar-209-Mar-2012-Mar-2015-Mar-2018-Mar-2021-Mar-2024-Mar-2027-Mar-2030-Mar-202-Apr-205-Apr-208-Apr-2011-Apr-2014-Apr-20Temperature (degF)Pressure (PSI)Pressure Summary WHP IAP OAP WHT 0 2000 4000 6000 8000 10000 12000 15-Jan-2018-Jan-2021-Jan-2024-Jan-2027-Jan-2030-Jan-202-Feb-205-Feb-208-Feb-2011-Feb-2014-Feb-2017-Feb-2020-Feb-2023-Feb-2026-Feb-2029-Feb-203-Mar-206-Mar-209-Mar-2012-Mar-2015-Mar-2018-Mar-2021-Mar-2024-Mar-2027-Mar-2030-Mar-202-Apr-205-Apr-208-Apr-2011-Apr-20Injection Rate (BPD or MSCFD)Injection Rate Summary DGI MGI PWI SWI BLPD Wallace, Chris D (CED) From: Well Integrity Compliance Specialist CPF1 & 2 <n1617@conocophillips.com> Sent: Tuesday, January 21, 2020 10:21 AM To: Wallace, Chris D (CED) Cc: CPA Wells Supt Subject: RE: KRU 2G -14A (PTD 215-050) Update 1/21/20 Attachments: 2G-14 90 day TIO trend 1.21.20.pdf; 2G-14A.pdf Chris, KRU WAG injector 2G -14A (PTD 215-050) (AIO 2C.068): After the last correspondence the IA and OA pressures were bled, subsequent which one of the CPF2 water injection pumps failed and all the seawater injectors were swapped to producer water, of which 2G-14 is one. The IA and OA pressures rose in response to the thermal increase, but after the pump was repaired and seawater was returned to 2G-14 the IA and OA pressures appear to have stabilized. CPAI intends to extend the monitor period on water injection for an additional 30 days to confirm stabilization. If the IA and OA pressures remain stable the well will be placed on a 60 day gas injection monitor to determine if the patch installed over the SSSV repaired the previous gas leak. The proper paperwork for continued injection or corrective action will be submitted upon conclusion of the monitors. A 90 day TIO trend and wellbore schematic is attached. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne / Dusty Freeborn Well Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 AWELLS TEAM C000c8mvilips From: WM4,Lntegrity Compliance Specialist CPF1 & 2 Sent: Monday, ecember 23, 2019 5:01 PM To: chris.wallace@ ka.gov Cc: CPA Wells Supt <nlconocophillips.com>; Well Integrity Compliance Specialist CPF1 & 2 <n1617Cc@conocoohillios.com Subject: RE: KRU 2G -14A (PTD 21,50) Report of suspect OA pressure increase Chris- KRU WAG injector 2G -14A (PTD 215-050) (AID 68) is nearing the end of the 30 day monitor period for the suspect OA pressure increase. The OA has continued to sho ressure increase however the IA has shown a very similar upward pressure trend. Due to the inability to determine if the O ressure is influenced thermally or the pressure increase is due to an unknown source, CPAI intends to extend the monito eriod for an additional 30 days to allow for pressure stabilization and/or manipulation of the IA and OA pressures to ide 'fy the cause of the OA pressure increase. Please let me know if you have any questions or disagree with the plan. Attac is a copy of the most recent 90 TIO trend. Dusty Freeborn/Jan Byrne Wells Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Wallace, Chris D (CED) From: Well Integrity Compliance Specialist CPF1 & 2 <n1617@conocophillips.com> Sent: Monday, December 23, 2019 5:01 PM To: Wallace, Chris D (CED) Cc: CPA Wells Supt; Well Integrity Compliance Specialist CPF1 & 2 Subject: RE: KRU 2G -14A (PTD 215-050) Report of suspect OA pressure increase Attachments: 2G-14 90 Day TIO plot.JPG Chris- KRU WAG injector 2G -14A (PTD 215-050) (AID 2C.068) is nearing the end of the 30 day monitor period for the suspect OA pressure increase. The OA has continued to show pressure increase however the IA has shown a very similar upward pressure trend. Due to the inability to determine if the OA pressure is influenced thermally or the pressure increase is due to an unknown source, CPAI intends to extend the monitor period for an additional 30 days to allow for pressure stabilization and/or manipulation of the IA and OA pressures to identify the cause of the OA pressure increase. Please let me know if you have any questions or disagree with the plan. Attached is a copy of the most recent 90 TIO trend. Dusty Freeborn/Jan Byrne Wells Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 WELLS TEAM Cc-ocol+tY�ps From: Well Integrity Compliance Specialist CPF1 & 2 Sent: Wednesday, July 31, 2019 7:42 AM To:'chris.wallace@alaska.gov' <chris.wallace@alaska.gov> Cc: CPA Wells Supt <n1030@conocophillips.com> Subject: KRU 2G -14A (PTD 215-050) Report of suspect OA pressure increase Chris, KRU WAG injector 2G -14A (PTD 215-050) (AID 2C.068) has been shut in since January 19, 2019. The well is exhibiting suspect OA pressure increase. DHD will mobilize to perform initial diagnostics. If diagnostic tests pass and the well is brought online it will be placed on a 30 day monitor period. The proper paperwork for continued injection or corrective action will be submitted once the path forward has been determined. A wellbore schematic and TIO trend are attached. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne / Dusty Freeborn Well Integrity & Compliance Specialist, CPF1 & 2 ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Begg 7 J DATE: Tuesday, December 10, 2019 P.I. Supervisor �) �� l2l /ul ! SUBJECT: Mechanical Integrity Tests ConocoPhillips Alaska, Inc. 2G -14A FROM: Adam Earl KUPARUK RIV UNIT 2G -14A Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry NON -CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 2G -14A API Well Number 50-029-21161-0I-00 Inspector Name: Adam Earl Permit Number: 215-050-0 Inspection Date: 12/7/2019. Insp Num: mitAGE191207202538 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 2G -14A Type Inj TVD 6003 Tubing ass 4zo 1420 . azo PTD 2150500 Type Test SPT Test psi 3000 IA 165 3310 3180 " 3150 BBL Pumped: 3.7 'BBL Returned: 3.7 OA sso - 730 no os " Interval IOTHER - P/F P Notes: Tested as per sundry # 319468 post patch/ per AIG 2C.068 to max anticipated inj. Pressure. Tuesday, December 10, 2019 Page I of I STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS W _kms°arw V 4:,r i..7 DEC - 5 2019 nnr il"r i. uperanons Abandon❑ Plug Perforations Fracture Stimulate ❑ Pull Tubing ❑ 'perahons s u own ❑ Performed: Suspend❑ Perforate❑ Other Stimulate El Alter Casing El Change Approved Program E] Plug for Redrill❑ 'erforate New Pool❑ Repair Well ❑ Re-enter Susp Well ❑ Other: PATCH TUBIN42 2. Operator ConocoPhillips Alaska, Inc. 4. Well Class Before Work: 5. Permit to Drill Number: Name: Developmen❑ Exploratol-] Stratigraphi❑ Service 215-050-0 3. Address: P. O. Box 100360, Anchorage, Alaska 6. API Number: 99510 50-029-21161-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL 25667 KRL) 2G -14A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): I N/A Ku aruk River Field / Ku aruk River Oil Pool 11. Present Well Condition Summary: Total Depth measured 9,940 feet Plugs measured None feet true vertical 6,175 feet Junk measured None feet Effective Depth measured 9,940 feet Packer measured 8,345 feet true vertical 6,175 feet true vertical 6,003 feet Casing Length Size MD TVD Burst Collapse CONDUCTOR 72 feet 16 110' MD 110' TVD SURFACE 3,293 feet 9 5/8 " 3,327' MD 2760' TVD PRODUCTION 8,422 feet 7 " 8,724' MD 6278' TVD LINER 1,100 feet 2 3/8 " 9,940' MD 6175' TVD Perforation depth: Measured depth: 8864-9939 feet True Vertical depth: 6130-6175 feet Tubing (size, grade, measured and true vertical depth) 3.5 " J-55 8,373' MD 6,024' TVD Packers and SSSV (type, measured and true vertical depth) PACKER - BAKER FHL PACKER 8,345' MD 6,003' TVD SSSV -BAKER FVL 2,055' MD 1,920' TVD 12. Stimulation or cement squeeze summary: 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 Casing Pressure Tubing Pressure Prior to well operation: 0 0 2316 100 1390 Subsequent to operation: 0 0 2300 100 1390 14. Attachments (required per 20 AAC 25.070, 25.071, s 25.293) 15. Well Class after work: Daily Report of Well Operations ❑ Exploratory ❑ Development❑ Services Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ❑ Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG [71 GINJ❑ SUSP❑ SPLU(0 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319.468 Contact Name: Steve Drake Authorized Name: Steve Drake Authorized Title: Sr. Wells Engineer Contact Email: Steve.G,Drake@cop.com Authorized Signature: - Date: ) Z � C Contact Phone: (907) 263-4062 V Form 10-404 Revised 4/2017 VTG 17 -IM -117 RBDMS45L- DLL D 5 2019 Submit Original Only KUP INJ WELLNAME 2G -114A WELLBORE 2G-14 Well Attributes Max Angle & MD TD Conoeoi'hillips F ,e Name WeIIMn APUUW W I16ore5dtua MDn aj TD (XXBj Alaska, Inc. n161nn w.I .� Ad 14. nrmrmte 113113 AM Lasa Tag VWmlunemaho'ereaq Arrington Depapilk.) I End Data Welltare (asI MOE 9y ............................................................ Last Tag: SOT'8,296.0 lioPowiii 2G-14 Iehallf Last Rev Reason LANCE., 3z.O Anticipation End Data Wellbore Lane MW By Has R eason; WELL SIDETRACKED WELLBORE ADDE TERALALIO MAIN 52312015 2G-14 hehoo Casing Strings N CONDUCTOKWP. 1ih0 casme Desnnpnon CONDUCTOR 10D(in) to(in) TOP(PKED 16 15.06 380 SetDepth lnKe) 110.0 sat oepm lrvOL.. wtlLen p._G,a]. TOPTbreatl 110.0 62.50 940 WELDED Casing DesctlptlonOB(in) SURFACE 9518 ,D(N) TOPIXKBI 8.92 34.0 Setre,g,i 3,3270 sal Depm a-)...-al.n 2,]600 36.00 111.... Tap TbreeE L-80 BUTT PMcb12,Wa° Casing Oen.opron PRODUCTION --van ] S(up 6.26 32.9 Joel UePtb Que) 8,724.0 set Depth (N°)... WIIL.n 6,2]8.3 26.00 I1...GMde Top Thnxd J-55 BUTT sparer Pp: Z.. I Other In Note (Wireline retrievable plugs, valves, pumps, fish, etc.) S9FEn V.. 2.WA9 Top nVO) Top mm Top(MB) ("B) r) Dea cam Run Data ID (in) 2,046.0 1,913.7 39.98 Patch 2.72"P ratedA PH 5 4 wl SpacerPipe antl 1111 1.625 vmb 2orz.p Anchor lsiCh(CPAL35061). DAL 27 Max DD2]2" 9 2,094.0 1,9167 40.13 SpacerPipe 21116"P-110 Spacer Pipe. 11/1 1.6]0 EAS LFT; z,nw z 9 2,0]2.0 1,9334 40.94 Patch Z/ "P P(VO rated ALPPHP35003). UAL'Max 00 1 1.625 272" 9 8,455.0 6,083.1 43.45 WHI TOC - Baker 3.5" KL Monobore Whipstock with OH Anchor 52612015 MONOBORE SURFACE;bN,32]0� Perforations 8 Slots GAS LIFT; 40.43 an., GASLIR', Shoe regain) BUIRIKB) TOPITVD) (XKB) Bonata)(s NNSB) Llnkelion. Bele Den n. ) Typa COM 8,3570 6359.0 6,012.1 6,013.6 A4,2G-14 4202015 30 RPERF THTCUUdeg,b ors LIFT: 747s charges 8,452.0 8,458.0 6,081.0 6,085.3 A-5, 2G-14 912911985 4.0 RPERF 2118" BarKone II; 0 deg PH cAa LFTl B3al.z 8,458.0 8,4590 6,085.3 6.086.1 A -62G-14 912911985 5.0 RPERF 2118"BarKone ll;Odeg PH 8,4580 8,459.0 6085.3 6,p8fi.i Ad, 2G-14 929/1985 4.0 RPERF 21/8" BarKone ll; O deg pH career Put; e,znaD nKe 8,459.0 8,460.0 6,086.1 6,08fi.8 A-623-14 929/1985 5.0 RPERF 218"BarKone ll;Odeg PH 8,459.0 8,466 0 6,088.1 6,091.1 AS, 231 929,1985 4.0 RPERF 2118" BarKone II; 0 tleg PH P°R;°,.0 8,465.0 8,4660 5,090.4 6,091.1 A5, 2G-14 9/29/1985 5.1) RPERF 2118" BaMone 11; 0 deg PH PACKER; e,644.a 8,466.0 8,46].0 6091.1 6,091.9 A-5, 928/1985 4.0 RPERF 21/8' BarKone 11; 0 deg pH 6467.0 8,468.0 6,091.9 6,MS A-5, 2G-1492911985 5.0 RPERF118" BarKone 11; 0 tleg pH APER'; 11157 ad 8,467.0 8,470.0 6091.9 6,094.0 775 2G-14 912911985 4.0 RPERF 2118" BarKone 11; 0 deg pH 8,490.0 8,495.0 6,1086 6112.2 A4,2G-14 929/1985 4.0 RPERF 2118" Ba1KD0e 11; 0 deg pH NIPPLE eae�e 8,4950 8,498.0 61122 6114.41742314 929/1985 4.0 RPERF 2118"BarKonell;OtlegpH 8,485.0 8,496.0 6,112.2 8,112.9 A-0, 2G-14 912911985 5.0 RPERF 2118" BarKone II; 0 deg pH sos: ava2 8,498.0 8,499.0 6,114.4 6,115.1 74, 2G-14 729 19B5 5.0 RPERF 2118" WME ll;Otlep pH 8,498.0 8,4 0 6114.4 8,115.1 A42G-14 929/1985 4.0 RPERF 2118"BarKone ll;Otleg pH 8,499,0 8,499.0 6115.1 6,115.1 A4,2G-14 MW1985 50 RPERF 218' BarKone ll; 0 deg PH ....'anse,gas_ 8.499.0 8,5030 6,115.1 6,1180 A4,23-14 912911985 4.0 RPERF 2118"BarKone ll;Otleg pH 8,502.0 8,5030 6,117.3 6118.0 A4, 2G-14 92911985 5.0 RPERF 21/8" BarK.Ne 11; 0 deg PH 8,503.0 8,5080 8,118.0 6,121.6 A4,2G14 9/2911985 4.0 RPERF 21/8" BarKone 11; 0 deg pH 8,508.0 8,511.0 6,121.6 6,123.8 A4,2G-14 912911985 5.0 RPERF 2118" BarKone 11; 0 deg pH RPERF,&452"46SO Lt LINER: aeR.48.&D.0 RPERF::.....6515.0 RPERf,a,45a....°3 6,511.0 8,516.0 6,123.8 6,12].4 A4,2G-14 92911985 4.0 RPERF 2118"BaMone ll;Otleg pH 8,516.0 6,126] 8,12)4 A4, 2G-14 92911985 5.0 RPERF 2118"BaMonell;OtlegpH RPERF eoe,awo8,51fi0 WHIPSTOCK-MONOBORE, 652fi0 6,12].4 6,134] 774 2G 929/1985 40 RPERF 8V8"BarKonell;OtlegpH a4xa FPERr:E,NR ,4Ba0� 6526.0 6530.0 6134 ] 61376 7472G 4 929,1985 5.0 RPERF 2118" BarKone II', 0 tleg pH RPERr; grESc $4W U 6530.0 65320 613].6 6,139.1 A4, 2G-14 912911985 4.0 RPERF 2118"BarKone ll;Otleg pH Cement Squeezes RPERF; a 48608g4910 Top Top IXKB) BMIXKB) IXKB) IND) RinIIND) INNBI Oes Sbtl Oale Co. gpsRF; 8.4ame..1- gPERF:a48]69.4]il.D� 8,2DU 96.0 6124.0 69684 Cement Plug 511]/2015 15 bb1s 165 ppg RPERr;8,49D.08,495.0� RPERF;0,49a0a496,0� RPERF', RKFP8.499,0 RPERF; Aa...490 RPERF,449a0$48a0� RPERF,8.489.0 RPERF;9,49R08...0� RPER1;RgCLC8.W31- RPERF;.EW.D UES. RPERF: &7.4.08$11 D� RPERP; a,5nl "Ar8°- RP.1;a.515PBa180� RPERF'.Sse8.0$E26.0� RPERr;a52a0$aoud. RPERP,a,530.c_exAc0. PROOUCPON', 90,7240 t� KUP INJ WELLNAME 2G -14A WELLBORE 2G -14A Conoc3 tlnl�i$ ++1""+ ° Well Attributes Max Angle & MD TD i Flep Nema IWellnore Apl/UWI IWellbon Sdtus I11G IFol MOnnKBI Act Btin MK91 Al85kd.IF1C. IISI IPLRIIK RIVERI INIT Snn'J(1211fi1D1 IN.I d °fin[ —dn 1-1 E4-1-1511 W-14A.linNAall31:13AM Last Tag VeiEnlxMreec(xNep Arbitration Dap1h IN(BI Encomia 1 WNlbore ta@MaEBy Last Tag:SLM 8,296D dSs'Q15 2G -14A smamith ................. ............ """""" Last Rev Reason Annotepon Entl Ogle WeIIWre bet Mctl By NANOEe, no Rev Reason: Set patch over SSSV 11/1&2019 2G -14A iamdj Casing Strings Casing Description WINDOW Do (11 101in1 Tap lXMel set ] 8,45].0 8G62D Depth sat Depdb lot 11'ruL¢n(L. 6,088.2 cmtle Toprndead cououcroR:39.w+a.° casing oesnnpinn LINER ..pm m(in) Top (RNB) last 2318 1.99 8,839.7 9,940.0 eptn (nitB) Set Depth lrvoL.. wULan (1... 4.50 Gmae L-80 rop lTrcaa STL Liner Details Top (In.)TopINO)IXKB) Top Incl pIkml Dee Cold Nomina110 Peprc 2Ma.o 8,839) 6,130.2 8932BILLET BAKER ALUMINUM LINER TOP BILLET 1.000 Tubing Strings - SpawrFido 2.— sAFErvnv; 20:4.° Tuning Description stung Ma... IDlial mpin8dl sal Depth ln. set oegn lNol 6-w111mr11 TUBING 312 299 32.0 8,3]3.9 6,0244 9.30 J-55 Dmae Top conneauon EUEBrd Completion Details rmp¢,m2° a Top OVDI Top mnl Tap IXNB) (ryHB) rl 1lem Des Com Nominal to (in) 32.0 32.0 0.00 HANGER MCEVOV TUBINGHANGER 3.500 2,054.8 1,9204 40.30 SAFETY VLV BAKER FVL(LOCKED OUT 6/18/2001) 2.810 IDSLFT;q+D9.2 8,3309 5,9933 44.14 PRE BAKER PER 2810 8,344.6 6,003.2 44.01 PACKER BAKER FHL PACKER 3.000 8,3616 6,015.5 43.84 NIPPLE CAMCO D' NIPPLE(Milled Out 5/13/2015) 2.800 8,3]32 Q023.8 43.74 SGS BAKER SHEAR OUT SUB 3000 V.SFACE, 31.0339.°— Perforations & Slots sesa dAS LIFT: a.GA9 iopntl(B) OUn MIKE)MH9) TOPOVD) atm IND) OIXB) Llnk¢a gene Dab Den IsM1abM I Type Cam 8,864.3 9,939.8 6,130.5 8,1]5.2 A-0, 2G -14A 8292015 ISLUTS ISIOUP1 Liner GAGUIT.1tril Mandrel Inserts at tll GASLIFT;]p]3.1 N Top INDt Valve Labn P.O.-IT-.. TOPMB) Real Make Mosel Do (in) Sery Type Type (in) (pail n Run Date Coal 1 2,104.2 1,957.6 MMI FMHO 1 JGAS LIFT JDMY BK 0000 L1Z2015 5:30 cos un;0,2A92 2 4,420.3 3,42].6 MMH FMHO 1 GAS LIFT DMV BK 0.000 11.0 ]112/2015 2:00 3 6,165.8 4,552.8 MMH FMHO 1 GAS LIFT DMV BK 0.000 0.0 612012001 9:30 cemem vl�a; S,2d5.OnKe 4 ],4]3.1 5,413.0 MMH FMHO 1 GA6 LIFT DMY BK 0.000 00 6/202001 4:30 5 82892 5,963.5 ONFMHO 1 GAS LIFT DMV BTM 0.000 00 11/172019 8:00 PeR: e.33o.s Notes: General & Safety PACKER a,aM.fi Entl Odle Annateuan 81122019 NOTE: WgIVERED WAG INJ WITH TXIq ON GAS PPERF: S3sTMLWGX� NIPPLE, 8 a 6 SOS', %.2 RPERF, 84520-8,459.0 PRODUc ION, 33.08.72a.0 WNDOW;845/.OS482.0 lg.ss3TF.5b.9ag.0— Lt LINER. 3 3fi269,at°.° �I I� 3 SLOTS', 8ag9,35,9399------ LINER:o.S3a.t.gang 2G -14A PATCH TUBING DTTM JOBTYP SUMMARYOPS START 11/17/19 ANNCOMM BRUSHED & FLUSHED TBG F/ 1940' TO 2140' RKB. SET CATCHER ON LINER TOP @ 8362' RKB. PULLED DV @ 8289' RKB. PULLED CATCHER. BULLHEAD 150 BBLS CISW & 72 BBLS DSL DOWN IA TO FORMATION. DRIFTED TO 2140' RKB W/ 2.72" x 19.6' DMY PATCH. DEPLOY CATCHER & SET DV @ 8289' RKB. PULLED CATCHER. IN PROGRESS. 11/18/19 ANNCOMM SET 2.72" P2P (VO RATED, 4ALPPHP35003) MID-ELEM @ 2072' RKB. CORRELATED TO TBG DETAIL 11-2-84. SET 2.72" P2P (VO RATED, #ALPPHP35004), SPACER PIPE, ANCHOR LATCH (#CPAL35061, 26.98' OAL) MID-ELEM @ 2046' RKB. LRS MITIA (pass) @ 3000 psi. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Hanna Sylte Wells Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2G -14A Permit to Drill Number: 215-050 Sundry Number: 319-468 Dear Ms. Sylte: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Enclosed is the approved application for the 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, wiece Chair [� DATED this " day of October, 2019. ABDMSL�OCT 17 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.2An 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate 11 Repair Well 0 Operations shutdowro Suspend ❑ Perforate O Other Stimulate ❑ Pull Tubing ❑ Change Approved Progran❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Patch Tubing ❑ 2. Operator Name: 4, Current Well Class: 5. Permit to Drill Number: CODOCOPhill S Alaska Inc. Exploratory ❑ Development ❑ Stratigraphic ❑ Service ❑' 1 215-050 3. Address: 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 51302d21161ll 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? NA Will planned perforations require a spacing exception? Yes ❑ No 0 1 KRU 213-14A 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 25667 z I KuparukR,vev� Kaipai MveV Oil 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9940' 6175' 9940' 6175' 3800 Casing Length Size MD TVD Burst Collapse Structural Conductor 72' 16" 110' Surface 3298' 9.625" 3327' Intermediate 8686' 7" 8724' Production Liner 1100' 2.375" 9940' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8864'- 9939' 6130' - 6175' 3.5" J65 8373.9' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker FHL Packer / Baker FVL Safety Valve 8345' MD, 6003' TVD / 2054' MD, 1920' TVD 12. Attachments: Proposal Summary 0 Wellbore schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Sfratigraphic❑ Development[] Service ❑� 14. Estimated Date for 10/18/2019 15. Well Status after proposed work: Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG 0 GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Hanna Sylte Hanna Sylte Contact Name: Authorized Title: Wells Engineer Contact Email hanna.sylte@conocophillips.com p,, Contact Phone: 907-265-6342 Authorized Signature: t�V.'W� � `t I ,4/v—P+�.. Date: \ 1 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: L4 Lill Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test LK Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes 17 No❑ RBEIMSOCT 172019 Spacing Exception Required? Yes ❑ No 3K Subsequent Form Required: APPROVED BYQ I Approved by: , I ' 1 COMMISSIONER THE COMMISSION Date: 1 "' /V//5/i y lei X� Fo,m os Revise a/z r Approved applicat n' v iJ f r 2 s o the date of approval. ftt submit Form and ✓✓✓ o sRi & �NA� pp ^ _ Attachments in Form and f WTQ en�la r.� ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 11, 2019 Commissioner Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7�h Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski, Enclosed please find the 10-403 Application for Sundry Approval for ConocoPhillips Alaska, Inc. well 2G -14A (PTD 215-050). This request is for approval to set a tubing patch to restore tubing integrity for gas injection. If you need additional information, please contact me at 907-265-6342 or 713-449-2197. Regards, Hanna Sylte Wells Engineer 2G -14A DESCRIPTION SUMMARY OF PROPOSAL 2G -14A has an identified tubing leaks around the SSSV between 2056' and 2066' MD. This proposal is to install a patch over the SSSV to return the well to gas injection. 1. Brush and flush patch setting area from 2000' to 2100'. 2. Set CSV in landing nipple at 8361' and pull DV from GLM at 8289' 3. Circ well out with corrosion inhibitied SW and diesel. U-tube well to equalize diesel FP. 4. Re -set DV in GLM at 8289' and pull CSV from 8361'. 5. Install 26' patch across identified leakes near SSSV. 6. Perform MIT -T to ensure patch is holding. 7. Perform SW MITIA. 8. Submit 10-404. KUP INJ WELLNAME 2G -14A WELLBORE 213-14A COnocoF'hillips " ' Well Attributes I Max Angle & MD TD WeII�-APINWI Wellbore Blalus cl l') MB I%1(al gcIBM IXXBI AIeSKe.IrIC.IHUPARIIKRIVFP IINIT I5009miiesm linii II"c ea 2G -14A, 1 01112 01 9 11:51:30 AM Last Tag D (R K Venical schematic (actual) gnnobtion Beptn (MKBt Entl Gale Wellbore feet Mod By Last Tag:SLM 8,296.0 512012015 2G -14A larnsinith Last Rev Reason Annotation Entl Date Wellbore Last Mod By B Rev Reason: DETERMINE THE LINER TOP ID BI&2019 2G -1M )hansen8 . Casing Strings .. ..._ __. ...._..__. _... cealnq Daacripron oG tm) mtinl Top tflKBl 80 Depth t%Ket WINDOW 1 8,45).0 8,462.0 Bet De trVDl t... wvLen 6,088.2 p._Gratla ropconnecnan "' Casing Cascrlptbn ODlln IG (in) Top tXKBI Set GeptM1 (XNBt LINER 2318 1.99 8,8301 9,940.0 Sel-we (ND)(...Wta_aa 4.60 p...Gretle Top Connection L-80 STL ==a•m Liner Details - Top TaKBt Top TVD1 DdKm Topincl(°) Item Des Com Nom mauG tin) �y.se 1W �' ,...,..,.a, 8,83911 6,13021 89.32 JBILITET BAKER ALUMINUM LINER TOP BILLET -1.000 Tubing Strings wwrvv caro ...199 Top (flKBt Set Depth ifl... Set GeptM1 tNOt tI... WItIWX) TUBINGescrlptlon 3tring1/2 Me TUBING 3112 2.99 320 8,3)39 8,0244 9.30 Gmtle T'PCon ne.son J-55 EUEBM Completion Details '•'.^. _ pop ITVDI Top IXKBI IttKel ropincl(') Ilam Dec Co. I rvommal to lip 32.0 32.0 000 HANGER MLEVOVTUBING HANGER 3.500 2,054.8 1,9204 40.30 SAFETVVLV BAKER FVL(LOCKED OUT Ni 812001) 2810 8,330.9 5,993.3 44.14 TBR BAKER PER 2.810 vrw8,344.6 6,003.2 44.01 PACKER BAKER FHL PACKER 3000 8,3616 5,015.5 4384 NIPPLE CAMCO'DNIPPLC (MMel Cut 511312015) 2.800 8,3132 6,023.8 4314 SOS BAKER SHEAR OUT SUB 3.000 —CAMP...— •..•= Perforations&Slots i e'1°'""•."• u. •4emr Top (XHBt Blm tttKBl roINS) (XKBI Blm(NG) (ttKB) Linketl Zone Dale seat Gene tsnoKM) type Com 8,864.3 9,939.6 I b,13U.51 6,115.2 A4,2114A 51292015 SLOTS I SSISV Liner >var„m Mandrel Inserts at ai —UPPE._ LOWE...— — -P five) varve Pdch Pmt Sltt TRO Rnn N Top(XKBI (ttKB) M.a. Model OD tip Sa, Type Type pp toxin Ron Dano Com 1 21042 1,957.6 ?TMH FMHO 1GAS LIFT DMV BK 0.000 I1112/2015 5:30 2 4,4202 3,421.6 MMH FMHO 1 GASLIFT FM —y.1 0000 0.0 Al2I2015 2:00 3 6,165.8 4,552.8 MMH FMHO 1 GAS LIFT DMV BK 0.000 0.0 82012001 9:30 4 1413.1 5,413.0 MMH ?MHO 1 GAS LIFT DMV BK 0.000 I 0.0 612112001 4:30 - S 8,289.2 5,963.5 MH ?MHO 1 GAS LIFT DMV BTM1 0.000 1 0.0 2/1212019 11100 „_ >m Notes: General & Safety rna Ilam Annomtmn "'•'®' 5212015 NOTE: WELL SIDETRACKED, ADDED LATERAL ALI(OFF MAIN WELLBORE) 51124019 NOTE WAIVERED WAG INJ WITH TXIA ON GAS —B-2IN... D -11N..... — A -61N_ — A5-2 5... — —A-51N... lsliw A4 IN... --so- -A-4 IN... — —A-5 IN_ _ B-1 IN... A-6 IN... _ — —A.6 IN_ —II - —A-51N... KUP INJ WELLNAME 213-14A WELLBORE 2G-14AL1 Ct11' ocoF" Tillips Well Attributes Maz Angle & MO TO Alaka.IDC KUPARUKRIVER UNIT 5002921161fi01 Ne ibore wawa n3 �41� 8,6)3.00 �t Fin 9,940.0 tflKB� Comment SSTV: LOCKED OUT H35lppmt D.R pnnatatlon EnE Oah KB�GM IN Last W0: 40.98 Alp geleaae Oah 1011011994 2G-14AL1, 10/112G1911:51:11 AM Last Tag D (ft K Vertical schematic (actual) Annotation DepXi MKB) I End Due Wellbore Laat Mod By Last Tag: 2G-14811 smsmilh Last Rev Reason 8 Annotation End Date Wellbore teat Mod By Rev Reason: WAIVERED WAG INJ WITH TAA 5/122019 2G-14AL1 freebtl . .. ...... _ ... _ Casing Strings - caamg DeacnpXon Dopn) LI LINER 238 mtint Top tnKet sat D-iAh MK sat DeplX lrvot �... WtlLen O... G2ae 1.99 8,362.5 9,940.11 4fi0 L-80 Top connmXon TTL Liner Oetalls - ........"....'.'......". """'"•,." �• �'�-Y"w..m'r Top mim) Top ILL)(Ma rop mol fl nem oes om NominallD In, 8,362.5 Q016.1 43.84 DEPLOY DAKER THORTY DEPLOYMENT SLEEVE 1.1100 Perforations &Slots _ "''p rop lttKB� at_MKBt ToplrvDl MKB� eon RVDt MKe� Llnketl Zone Dah Shot Dens (shotslX) Type cam 8,3)).5 9,939.6 8,026.9 6,154) A-5, 2G-14AL1 5/312015 SLOTS Slofled Liner -� Notes: General &-Safety Entl Dah Annotation5212015 NOTE: WELL SIDETRACKED, ADDED LATERAL AU(OFF MAINWELLGORE) ,a.,.......m wli u19 NOTE: WAIVERED FOR WAG INJ WITH TXIA —CAMP... UPPE. —LOWE_ — —8-2 IN B-1 IN.. —A-61N.." - -A5-2 S... — —A-5 IN... —A-4 W, —A -41N... —A4 IN... — — B-1 IN, —A-61 —A -51N... N.-- - A-5 IN. � .u..... Wallace, Chris D (CED) From: Well Integrity Compliance Specialist CPF1 & 2 <n1617@conocophillips.com> Sent: Wednesday, July 31, 2019 7:42 AM To: Wallace, Chris D (CED) Cc: CPA Wells Supt Subject: KRU 2G -14A (PTD 215-050) Report of suspect OA pressure increase Attachments: 2G-14 90 clay i1O trend 7.31.19.pdf, 2G-14A.pdf Chris, KRU WAG injector 2G -14A (PTD 215-050) (AIO 2C.068) has been shut in since January 19, 2019. The well is exhibiting suspect OA pressure increase. DHD will mobilize to perform initial diagnostics. If diagnostic tests pass and the well is brought online it will be placed on a 30 day monitor period. The proper paperwork for continued injection or corrective action will be submitted once the path forward has been determined. A wellbore schematic and TIO trend are attached. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne / Dusty Freeborn Well Integrity & Compliance Specialist, CPF1 & 2 ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 WELLS TEAM Originated: Schlumberger PTS- PRINT CENTER 6411 A Street Anchorage, AK 99518 (907) 273-1700 main (907)273-4760fax Delivered to: -�,j, AOGCC �. ATTN: Natural Resources Technician II Alaska Oil & Gas Conservation Commision 333 W, 7th Ave, Suite 100 +y Anchorage, AK 99501 TRANSMITTALDATE TRANSMITTAL# 21 5050 Name Signature Please return via courier or sign/scan and email a copy A Transmittal Receipt signature confirms that a package (box envelope, etc.) has been received and the contents of the V I package have been verified to match the media noted above. The Date specific content of the CDs and/or hardcopy prints may or may not have been verified for correctness or quality level at this !r and CPAI. point. SLB Auditor J Schlumberger -Private .•. SERVICE ORDER FIELD NAME DESCRIPTION DELIVERABLE DESCRIPTION DATA DATELOGGED Prints CD's 1A-25 30-11 3K-23 50.029-22116.00 50-029.21676-00 50-029-22771-00 EBNL-00028 EBNL-00029 EBNL-00030 KUPARUK RIVER KUPARUK RIVER KUPARUK RIVER WL WL -WL1 PPROF LDL LDL FINAL FIELD FINAL FIELD FINAL FIELD 21 -Jun -19 22 -Jun -19 23 -Jun -19 1 1 2V-02 1Y-14 1H-109 1H-113 1 H-117 3H -14B 50.029-21037-00 50-029-20910-00 50-029.23595.00 50-029-23588-00 50-029.23602-00 50.103-20092.02 EBNL-00034 EBNL-00035 EBNL-00036 EBNL-00037 EBNL-00038 EOSH-00062 KUPARUK RIVER KUPARUK RIVER KUPARUK RIVER KUPARUK RIVER KUPARUK RIVER KUPARUK RIVER WL WL WL WL WL WLLDL (PROF IPROF IPROF IPROF (PROF FINAL FIELD FINAL FIELD FINAL FIELD FINAL FIELD FINAL FIELD FINAL FIELD 27-Jun•19 28 -Jun -19 29 -Jun -19 30 -Jun -19 1 -Jul -19 3Ju1-19 1 1 1 1 1 1 2G -14A 16-06 16-09 3G-03 1R -22A 50-029-21161-01 50-029-20603-00 50.029-20655-00 50-103-20245-00 50-029.22206-01 EOSH-00064 EOSH-00065 EOSH-00066 EOSH-00067 EOSH-00048 KUPARUK RIVER KUPARUK RIVER KUPARUK RIVER KUPARUK RIVER KUPARUK RIVER WL WL WL WL WL LDL PPROF IPROF PPROF LDL FINAL FIELD FINAL FIELD FINAL FIELD FINAL FIELD FINAL FIELD 5-Jui-19 6 -Jul -19 7 -Jul -19 8 -Jul -19 8 -Jul -19 1 1 1 1 1 14 Name Signature Please return via courier or sign/scan and email a copy A Transmittal Receipt signature confirms that a package (box envelope, etc.) has been received and the contents of the V I package have been verified to match the media noted above. The Date specific content of the CDs and/or hardcopy prints may or may not have been verified for correctness or quality level at this !r and CPAI. point. SLB Auditor J Schlumberger -Private • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg 2 S(2Sjl a DATE: Wednesday,May 11,2016 P.I.Supervisor SUBJECT:Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2G-14A FROM: Lou Grimaldi KUPARUK RIV UNIT 2G-14A Petroleum Inspector Src: Inspector Reviewed By: P.I.Suprvy NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 2G-14A API Well Number 50-029-21161-01-00 Inspector Name: Lou Grimaldi Permit Number: 215-050-0 Inspection Date: 5/10/2016 Insp Num: mitLG160510104700 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 2G-14A Type Inj W'TVD 6003 - Tubing 2350 - 2350 - 2350 • 2340 PTD 2150500 Type Test SPT Test psi 1501 - IA 1300 3000 - 2940 - 2940 - Interval 4YRTST P/F P v' OA 200 - 210 210 210 - Notes: Pumped 1.6 bbl's diesel, 1.9 bbl's returned.All required paperwork available on location.Good test.._ SCANNED SEP.2 120 6 Wednesday,May 11,2016 Page 1 of 1 • ! MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday,August 06,2015 TO: Jim Regg (5`i P.I.Supervisor r . e 7 is SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2G-14A FROM: Chuck Scheve KUPARUK RIV UNIT 2G-14A Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 2G-14A API Well Number 50-029-21161-01-00 Inspector Name: Chuck Scheve Permit Number: 215-050-0 Inspection Date: 8/1/2015 Insp Num: mitCS150802182622 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well! 2G-14A - Type Inj W TVD 6003 • Tubing 1850 1850 1850 - 1850- PTD 2150500 - Type Test SPT,Test psi 1501 IA 1160 - 2490 - 2440 - 2430 - Interval INITAL PAF P ,)' OA 760 900 - 900 - 900 - Notes: Initial test post conversion,producer to injector Thursday,August 06,2015 Page 1 of 1 Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. a15_ 0 50 Well History File Identifier Organizing(done) ❑ Two-sided ❑ Rescan Needed RESCAN: OVERSIZED: NOTES: of r Items: ❑ Maps: vvil Grayscale Items: ogs: E Poor Quality Originals: ❑ Other: ❑ Other: / BY: al, Date: Cl/ l Jr ,. /s/ Or Project Proofing BY: Date: viP'5s' /s/ 1 Scanning Preparation I x 30 = 30 +sZ I = TOTAL PAGES I (Count does not include cover sheet) BY: ACM Date: /s/ Production Scanning Stage 1 Page Count from Scanned File: A-a (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: 7- YES NO BY: aft Date: G `5 !S /s/ ylJ ` I Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Stage 2 Additional Well Reports: YES NO TOTAL PAGES: Digital version appended by: Meredith Michal Date: /s/ Final Page Count: Stage 1 + Stage 2: TOTAL PAGES: Scanning is complete at this point unless rescanning is required. ReScanned BY: Maria Date: /s/ Comments about this file: Quality Checked 7/8/2014 Well History File Cover Page_20140708.doc O 0 ' • O '. Q • Y N O N § ' °' "� 0 O Q E E UIII) rn• UI Ui . -.-- %- . N } c Q y J • 0f 0 O a a J m 2 - o NU N M Z U Q Q a m rn �_ m vrn m ml o o J O D } 0O 0 a) J J O J J C @ C J J 0) O ) Z i'_ c07 f0 c6 LL To W U 0oLL v7 h D > N N COC C C C U) a) co C C �p O a) N co F m = W LL 2 it LE Q YO d LL LL (n �' Z z E -,..7 0 0 0 0 0 > I . 0 0 0 0 F. co ; a) (0 N CO H N co co N�Ln �1 N Ln F F Q 0) io 0 Q < Ft LL h Q Q Q Q Q Q Q Q Q Q Q C (a V V O V V a V - -1 a V V Z o 2 .- .- ,_ Y _ co 0 N 0 'N N N W N N N N N N N N N N N I < C w l .. < .CO 0 > 0 O C a) a) N d @ a) ) a) N m a) a) CO a) N a a Z > E N LE It,_ LL D 0 LL LL IL IL LE LL LE it LE I1 LL it o E U Q N d c.)-0 U Y U U c.) 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O co c 2 0 U co C o O co c o �, P--4 0- E ® w N 0 07 U (� m o _I a `J\ } Q ENI Q o o ato O _ 7-6 Ci N c E �_ CON m c CS H Z 1 CO N CO fa 1 > M c I a) E ▪ in5 0 F- E CO as co o o c 0as a C C O Q c mihil Y c a - o E a O CC o _ Z▪ O • Cl)O Co o 2 o E co CoU Z d N @ in D C o LO N 11 C IN 11 2 o It) c 0 I—1E G c I 5. Ow o CO H co coo c > o w v in co co W E n O I 0 N N N d W t "O C N m E •- a) E O m c01 Co .. c I I I re o rn co m Z Q o o 2 Q o 0 0 v E v O a -0 0 a 0 0 E a C7 0 m 0 0 o d LI- o o aa' 0 o a� m o E Q a 2 .J W 3 Z 0 a 0 0 0 c G 0 0 . t: 1 5050 21 5051 26166 BAKER PRINT DISTRIBUTION LIST HUGHES Please sign and return one copy of this transmittal form to: COMPANY ConocoPhillips Baker Hughes INTEQ DATA LOGGED (mandatory) 795 East 94th Avenue 3 /3t/2015 WELL NAME 2G-14A; 14AL1 Anchorage,Alaska 99515 K.BENDER (mandatory) FIELD Kuparuk River Unit to acknowledge receipt of this data. (mandatory) COUNTY North Slope Borough LOG TYPE LWD-Coil (mandatory) (mandatory) STATE Alaska BH DISTRICT Alaska (mandatory) (mandatory) LOG DATE: May 31,2015 TODAYS DATE: 21-Aug-15 (mandatory) DISTRIBUTION LIST AUTHORIZED BY: Patrick Rider EMAIL: 3trick.rider(a�bakerhughes.co (mandatory) HAS CLIENT BEEN INVOICED FOR ADDITIONAL PRINTS? No COMPANY FIELD FINAL CD Final CD ADDRESS(FEDEXWILL NOT DELIVER TO P.O.BOX) LOGS LOGS (digital/image) Surveys (Final Surveys) PERSON ATTENTION #OF PRINTS #01-I'KIN I S #OF COPIES #OF COPIES#OF COPIES 4 4 4 4 4 4 4 1 ConocoPhillips Alaska Inc. Attn:Ricky Elgaricio ATO 3-344 700 G Street Anchorage,AK 99510 2 BP Exploration(Alaska)Inc. 1 1 kfij05.) \.9.) Petrotechnical Data Center,LR2-1 900 E.Benson Blvd. Anchorage,Alaska 99508 Attn:Dodie StinsonC (1.9j J • 3 Chevron/KRU Rep 1 �� 1 \\ 4N C- 41 Attn:Glenn Frederick , \ A4\41) P.O.Box 196247 ,) ` J ✓✓✓ Anchorage,AK 99519 �, 4 State of Alaska -AOGCC ' \--- JCZ 1 1 I 2 1 Attn:Makana Bender 333 W.7th Ave,Suite 100 Anchorage,Alaska 99501 5 DNR-Division of Oil&Gas *** 1 I 1 Attn:Sean Clifton 550 West 7th Avenue,Suite 802 Anchorage,Alaska 99501 "confidential"on all material deliver to DNR TOTALS FOR THIS PAGE: 0 3 4 4 4 0 TOTALS FOR ALL PAGES: 0 3 4 4 4 0 k• vi I) STATE OF ALASKA JUL 01 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LC la.Well Status: Oil ❑ Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended lb.Well Class: 20AAC 25.105 20AAC 25.11U Development ❑ Exploratory ❑ GINJ ❑ WINJ ❑ WAGE• WDSPL❑ No.of Completions: Service ❑✓ • Stratigraphic Test ❑ 2.Operator Name: 6. Date Comp sp.,oan') 14. Permit to Drill Number/ Sundry: ConocoPhillips Alaska, Inc. \ Aband.:: 15• 215-050 3.Address: 7. Date Spudded: 15.API Number: P.O. Box 100360 Anchorage,AK 99510 •5/27/2015 50-029-21161-01 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 243'FNL,88'FEL,Sec.6,T1ON, R9E, UM • •5/28/2015 KRU 2G-14A • Top of Productive Interval: 9. KB(ft above MSL): 140' • 17. Field/Pool(s): 877'FSL,912'FWL, Sec.6,T1ON, R9E,UM GL(ft above MSL): 102' , Kuparuk River Field/Kuparuk River Oil Poo • Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 100'FNL,468'FWL,Sec. 7,T1ON, R9E, UM 8296'MD/5968'TVD ' ADL 25667 . 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 508610 y- 5943345 Zone- 4 • •9940'MD/6175'TVD - ALK 2588 TPI: x- 504595 y- 5939182 Zone- 4 - 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 504152 y- 5938205 Zone- 4 2055'MD/1920'TVD 3410'MD/2814'TVD 5. Directional or Inclination Survey: Yes • ❑✓(attached) No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 not applicable (ft MSL) •8456'MD/6084'TVD 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first.Types of logs to be listed include,but are not limited to:mud log,spontaneous potential, gamma ray,caliper, resistivity, porosity, magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary GR/Res 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED I 16" 62.5# H-40 38' 110' 38' 110' 24" 202 sx Cold Set II 9.625" 36# L-80 34' 3327' 34' 2760' 12.25" 1060 sx Permafrost E,370 sx PF C 7" 26# J-55 33' 8724' 33' 6278' 8.5" 335 sx Class G,250 sx PF C 2.375" 4.6# L-80 8840' 9940' 6130' 6175' 3" slotted liner 24.Open to production or injection? Yes ❑ No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom;Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 3.5" 8374' 8345'MD/6003'TVD slotted liner from 8840'-9940'MD 6130'-6175'TVD : fir,iw 2 ,d ;, ,. 1 . • .- ' 15....° 26.ACID, FRACTURE, CEMENT SQUEEZE,ETC. 3 ,i, Was hydraulic fracturing used during completion? Yes❑ No ❑ < Per 20 AAC 25.283(i)(2)attach electronic and printed information DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 8296-8724 15 bbls 16.5 ppg Class G 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): waiting on facility hook-up Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: Test Period -0.- Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 24-Hour Rate ► Form 10-407 Revised 5/2015 1/TL 9/z//.1- CONTINI$E�D ON ArE�2 RB M�"1nAUG 2 7 2015 Submit ORIGINIAL oni 28 CORE DATA Conventional Con., , Yes ❑ No Q Sidewall Cores. ❑ No If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips, photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. NONE 29 GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No Q Permafrost-Top surface surface If yes, list intervals and formations tested, briefly summarizing test results Permafrost-Base 3410' 2814' Attach separate pages to this form,if needed,and submit detailed test information, including reports,per 20 AAC 25 071. Kuparuk A5 8456' 6084 Top Kuparuk A4 8483' 6104' Top Kuparuk A6 9206' 6145' Top Kuparuk A5 9247' 6152' NONE Top Kuparuk A4 9372' 6173' Formation at total depth: Kuparuk A4 • 31. List of Attachments: Summary of Daily Operations,schematic,final directional survey Information to be attached includes,but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report, production or well test results, per 20 AAC 25 070 32. I hereby certify that the foregoing is true a or t the best of my knowledge. Contact. Jason Burke @ 265-6097 Email: Jason.Burke@cop corn Printed Name: Dan Venhaus Title. CTD Engineering Supervisor Signature: Phone: 263-4372 Date: lv—Z9-/S INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC,no matter when the analyses are conducted Item 1 a Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI(Top of Producing Interval). Item 9. The Kelly Bushing and Ground Level elevations in feet above mean sea level Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15 The API number reported to AOGCC must be 14 digits(ex.50-029-20123-00-00) Item 20• Report measured depth and true vertical thickness of permafrost.Provide MD and TVD for the top and base of permafrost in Box 29. Item 22. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first. Item 23. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool Item 24. If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26.(Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval) Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Pursuant to 20 AAC 25 071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results, including,but not limited to:porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30 Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form.well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including, but not limited to:core analysis,paleontological report, production or well test results. Form 10-407 Revised 5/2015 Submit ORIGINAL Only I, KUP INJ 2G-14A Co occ i hi lips Well Attributes Max Angle&MD TD A R3kc (t-IC Wellbore APIIUWI Field Name Wellbore Status ncl(1 MD OMB) Act Btm IttKB) [orromn.WMx , 500292116101 KUPARUK RIVER UNIT INJ 95.69 9,700.59 9,940.0 ... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date 2G-14A 6/23/20151'.07'.49 PM 40.98 10/10/1984 Vertical schematic(actual) Annotation Depth(kKB) End Date Annotation Last Mod By End Date it r Casing Strings Casing Description OD(in) ID(in) Top((MB) Set Depth(ftKB) Set Depth(TVD),,, Wt/Len(I...Grade Top Thread Liner,A Lateral 2 3/8 1.992 8,839.7 9,940.0 4.60 L-80 STL HANGER;320 . .i �1, ` L -A.A./CONDUCTOR;38.0-110.0• II I SAFETY VLV',2.054.8 1 a( I II GAS LIFT,2.104.2 I SURFACE;34.0-3,327.0-• • GAS LIFT,4.420.3 GAS LIFT,6,165.8 _ 1). 7 GAS LIFT;7,473.1 y GAS LIFT.8,289.2 f 3 'Y +—i 7 4 PBR;8,330.9 PACKER;8,344 6 1 — APERF,8.357.0.8,359.0 �. f NIPPLE;8,361 6 '� il SOS;8,3732 "} S� . fir bM RPERF.8,4520-8,458.0�_• E,,,' PRODUCTION;330-8,724.0 ••• LI ner AL1 Lateral.8,362.4- 9.940.0 Liner,A Lateral;8,839.7-9,940.0 in 03 L c 1-1 a H CO °0 zI 0 m I 2 in 0 1 0 1 0 E 0 ao 73 in 2 I v 0 v in 00 . 2m iLi ._ O v M I V O N V OC) I d?- N o 0 O N co t 2 w m� �c00 0'" i 5 1 C o a 0- 0,a . 0 co Q c i NN H : ,_N id 1:-_ aZo 1 P N CO '� M - M 01 (n W CO i o1 m C a O co N N 1 2 g© • .g I >^ W a N 2Q. @ I N a U . N I LL M N p a N N O N I U O- O.0.0 61 I NOD• 4t E -J _ E_ C I NN co co sN Q w n of U ii �U� w I i (V (V N ♦ V i (V M co I I I 1 ii _____:,,,,,,--,/,' U.) !! 0 i N _ d 0 � J � H ,r / ' U jjr, 111111 N ., a N N I o m Q0 o N o t =� m2 U, o bm .n0 _ N Ui La `jo 4tN co a0 �co03 to:i _ M © I,- 44© -�epi a- E(V N LO rn I,-ro LO N °D N UY U OND Q.4.03 L,...- L t L N O) O) 2G 'RE AND POST RIG WELL WORK SUMP 'Y PRE RIG WELL WORK DATE SUMMARY 2/24/2015 (PRE-CTD): MITIA(PASSED TO 3000 PSI), MITOA(PASSED TO 1800 PSI), T POT (PASSED), T PPPOT(PASSED), IC POT(PASSED), IC PPPOT(PASSED), FT LDS (ALL FUNCTIONED PROPERLY). 2/25/2015 (PRE-CTD) : TREE VALVE DDT: SV, MV, SSV(PASSED), TREE VALVE PT: SV, MV (PASSED), SSV(FAILED). 3/23/2015 MEASURED BHP @ 8500' RKB: 3843 PSI. COMPLETE. 4/20/2015 PERFORMED A TUBING PUNCH FROM 8357-8359 WITH A 2"2' 120 PHASE, 3 SPF, BH HSC. LRS PERFORMED SW INJECTIVITY TEST DOWN TUBING 0.43 BPM AT 1180 PSI, 0.5 BPM AT 1190 PSI, 1 BPM AT 1250 PSI, 1.25 BPM AT 1350 PSI, 1.5 BPM AT 1450 PSI. 4/21/2015 PUMP 150BBLS SW FOR INJECTIVITY TEST FOLLWED BY 3OBBLS DSL FOR FP (JOB COMPLETE) 5/5/2015 MEASURE BHP @ 8500' RKB (3748 PSI). JOB COMPLETE 5/13/2015 Mill Nipple. Late start due to rig move and wait on hardline to be rigged up. RIH to D Nipple @ 8,362' and painted EOP flag. Milled nipple out with 2.80"tapered mill. Mill gauged 2.80". Will have to jet w/Schmoo-B-Gone in morning. Well freeze protected. Job in progress. 5/14/2015 Pump 25 bbls 16.5 ppg cement and squeeze into A-Sand Perfs. Unsuccessful attempt to to hold requested squeeze pressure (2,200 psi). Contaminate down to 8,400' and wash mandrels and jewerly while POOH. Restart in morning. 5/15/2015 Tag TOC @ 8,526' RKB corrected. Perform FCO to clean any residual contaminated cement from 8,300'down to tag. After initail gel pill returned to surface with slug of cement fluids were clean remaider of FCO.Reciprocated pipe at very slow speeds numerous times through cement area down to TOC. Well freeze protected and ready for cement in morning. Job in progress. 5/16/2015 Second attempt at cement plug unsuccessful. Pushed cement away and washed up 7"casing and tubing jewerly while POOH. Will return in morning and pump cement with Syntec fiber. Job in progress. 5/17/2015 Pump 15 bbls 16.5 ppg cement with middle 8 bbls containing 1 ppb CemNet fiber. Obtained squeeze pressure while squeezing 7.5 bbls behind 7"casing. Washed down to just above target depth of 8,352' RKB corrected. POOH washing tubing jewerly while maintaining overbalance on well. Well freeze protected and ready for Slickline in 72 hrs. 5/19/2015 (PRE CTD) TREE VALVE TEST, JOB POSTPONED DUE TO VALVES LEAKING BY. 5/20/2015 TAGGED CMT WITH 2" BAILER @ 8296' SLM, EST. 8336' RKB. COMPLETE. 5/20/2015 (PRE-CTD): TREE VALVE PPT: MV(PASSED), SSV(PASSED), SV(PASSED). TREE VALVE DDT: MV(PASSED), SSV(PASSED), SV(PASSED). ConocoPhillips Time Log & Summary We//view Web Reporting Report Well Name: 2G-14 Rig Name: NABORS CDR2-AC Job Type: DRILLING SIDETRACK Rig Accept: 5/22/2015 10:00:00 AM Rig Release: 6/1/2015 12:00:00 AM Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 05/21/2015 24hrSummary Mob to 2G Pad 15:00 18:00 3.00 0 0 MIRU MOVE MOB P MOB to 2G 18:00 00:00 6.00 0 0 MIRU MOVE MOB P Crew change-Continue to 2G pad- hold @ 2A for additional matting21:00 to 23:30 35/22/2015 MIRU,to 2G-14,tested BOPE 00:00 01:00 1.00 0 0 MIRU MOVE MOB P Continue to 2G-14,Arrive on location @ 1:00AM 01:00 02:00 1.00 0 0 MIRU MOVE MOB P Check status on 2G-14, Remove Jeeps, Pull tree cap flange 02:00 06:30 4.50 0 0 MIRU MOVE MOB P Spot sub and pits. Soft pad conditions need cat to move fore and aft 06:30 10:00 3.50 0 0 MIRU MOVE MOB P Rig modules spotted, MIRU 10:00 12:00 2.00 0 0 MIRU WHDBO NUND P Rig Accept @ 10:00, Nipple up stack 12:00 22:45 10.75 0 0 MIRU WHDBO BOPE P Start full BOPE Test,Test witness waived by John Crisp,AOGCC. BOP test pressure low 250/high 4300 psi /Annular 2500 psi 22:45 00:00 1.25 0 0 MIRU WHDBO BOPE P Fluid pack coil,test inner reel valve and pac off.swab valves. 05/23/2015 Completed BOP test, MU, RIH with 0.9°and D331. Mill cement pilot hole. 00:00 00:45 0.75 0 0 MIRU WHDBO CTOP T Replace blind rams, IA 700,OA 0 00:45 01:45 1.00 0 0 MIRU WHDBO BOPE T Retest Lower blind rams, 01:45 02:30 0.75 0 0 MIRU WHDBO CTOP P Test PDL's and kill tank line 02:30 04:00 1.50 0 0 MIRU WHDBO MPSP P PJSM, Load, MU,and PT FMC lubricator. Pull TWC 04:00 06:30 2.50 0 62 PROD1 RPEQP1 PULD P PJSM, PU BHA#1 pilot hole milling assembly,deploy, hole dead. Deploy """"Note: coil wall thickness 0.179" good. 06:30 08:54 2.40 62 8,270 PROD1 RPEQP1TRIP P RIH, swap hole to milling fluid(9.34 ppg),flud @ the bit 09:25. 08:54 09:06 0.20 8,270 8,325 PROD1 RPEQPI DLOG P Log GR tie in, did not get correlation 09:06 10:00 0.90 8,325 8,230 PROD1 RPEQP1 CIRC P Circulate well to 9.3 PPG milling fluid while analyzing logs 10:00 10:54 0.90 8,230 8,325 PROD1 RPEQP1DLOG P log GR tie in tagged @ 8325, PUW=30K,-1'correction Page 1 of 9 Time Logs Date From To Dur S. Death E. Depth Phase Code Subcode T Comment 10:54 13:24 2.50 8,325 8,362 PROD1 RPEQPI MILL P Motored down to 8361. did get samples of green cement. Stalled @ 8361,Assumed milled out D nipple. Stall 4 times to get started 13:24 14:00 0.60 8,362 8,380 PROD1 RPEQP1MILL P 8362 past D nipple Mill down to 8380 and stalled at 7"contact. Found hard cement @ 8365, 2K WOB @ 25FPH 14:00 14:30 0.50 8,380 8,380 PROD1 RPEQP1WPRT P Wipe up hole to 8200', PUW=32K 14:30 16:36 2.10 8,380 8,430 PROD1 RPEQP1MILL P 8380', Mill pilot hole, 1.42 BPM @ 3295 PSI FS, ROP=25 FPM @ 2.1K DHWOB 16:36 17:06 0.50 8,430 8,430 PROD1 RPEQP1WPRT P Wiper trip to 8200, PUW=28K 17:06 19:36 2.50 8,430 8,485 PROD1 RPEQPI MILL P 8430', Mill, 1.43 BPM @ 3360 PSI FS, BHP=3700 19:36 19:51 0.25 8,485 8,280 PROD1 RPEQPI DLOG P 8280ft,tie into the K1 zero ft correction. 19:51 20:06 0.25 8,280 8,485 PROD1 RPEQP1MILL P Dry run through cement pilot hole down to 8396', 1k weight bobble at 8380' looks to be where we contacted the 7 inch. PUH, back ream from 8685'at 1 fph up to 8370' 20:06 22:06 2.00 8,485 8,370 PROD1 RPEQP1MILL P 8396, PUH, back ream from 8685'to 8370'@ 1 fph,to clean up transition area. Dry run to bottom seeing 300 lbs or motor work. Looks good 22:06 23:36 1.50 8,370 62 PROD1 RPEQP1TRIP P POOH 23:36 00:00 0.40 62 62 PROD1 RPEQP SFTY P PJSM, simops, Check well for flow 05/24/2015 LD milling BHA#1, MU milling BHA#2 with bi-center bit, RIH milled TOC 8336' to 8512', POOH, LD milling BHA#2, RIH milled from 8485'-8512', POOH, early due to stalling motor. RU HAL caliper, RIH,stacked out on master valve,discussed plan forward., 00:00 00:30 0.50 62 0 PROD1 RPEQPI PULD P LD milling BHA 00:30 01:00 0.50 0 63 PROD1 RPEQPI PULD P MU second milling BHA with 0.6° ako motor and used Reed-Hycalog bi-center bit, 2.7x3.0 01:00 02:30 1.50 63 8,285 PROD1 RPEQPITRIP P RIH,with BHA#2 02:30 02:45 0.25 8,285 8,285 PROD1 RPEQP1 DLOG P 8285',tie into the K1 marker correctiono of minus 1.0' 02:45 03:00 0.25 8,285 8,485 PROD1 RPEQP1TRIP P Continue in hole through cement pilot hole pumping min rate. 03:00 05:30 2.50 8,485 8,513 PROD1 RPEQP1MILL P 8485',OBD cement pilot hole 20° ROHS down to 8505', turned tool face down to 180°from 8505'to 8520', 1.4 bpm at 3126 psi, IA 7,OA 0 ****Note: 3 stalled getting started, total of 12 stalls,with level 2-3 severity lateral vibration. Max ROP 34fphwithastall 05:30 07:42 2.20 8,513 76 PROD1 RPEQP1TRIP P POOH, check well for flow, looks good and dead, Painting EOP flag 8200'for tie in on next trip. Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07:42 08:18 0.60 76 76 PROD1 RPEQP1OWFF P At surface, PJSM to lay down BHA #2, perform no flow test 08:18 09:24 1.10 76 0 PROD1 RPEQP1PULD P Lay down BHA#2, Pilot hole bi center test 09:24 10:24 1.00 0 0 PROD1 RPEQP1 CIRC P Make up nozzle and jet stack,during stack jetting swabs are closed with tangos open WHP climbed to 630 PSI. Opened up to tiger tank and bled off WHP. Shut back in and pressure began to rise 10:24 10:36 0.20 0 5 PROD1 RPEQP1PULD P Pop off well to double check torque on nozzle,stab on injector 10:36 13:00 2.40 5 8,274 PROD1 RPEQP1 TRIP P RIH with Nozzle to kill well 13:00 14:30 1.50 8,274 14 PROD1 RPEQP1TRIP P Trip out pumping 12PPG completion fluid 14:30 15:06 0.60 14 0 PROD1 RPEQP1 OWFF P At surface, PJSM,30 Min no flow, LD BHA#3 15:06 15:18 0.20 0 0 PROD1 RPEQP1PULD P LD BHA#3 Nozzle 15:18 15:36 0.30 0 0 PROD1 RPEQP1PULD P PJSM, P/U HES Caliper, Suspend job and shut master for welding project in pitts 15:36 16:06 0.50 0 25 PROD1 RPEQP1PULD P PJSM, M/U coil to caliper stab on well with master shut.Stabbed on for master opening 16:06 16:12 0.10 25 33 PROD1 RPEQP1 TRIP P Trip in hole,tag up on master valve, command given to open, confirmation not received. Lost communication with tool 16:12 17:00 0.80 33 0 PROD1 RPEQPI PULD T PUH and unstab, Caliper parted at knuckle joint.Vac stack out and see caliper at swab valve level 17:00 18:30 1.50 0 0 PROD1 RPEQP1 FISH T Group huddle to indentify time line and operational errors, Formulate plan forward. Make notifications 18:30 21:00 2.50 0 0 PROD1 RPEQP1 FISH T PJSM, nipple down BOP stack from upper swab to check for tool, tool seemed to be bound up in lower combi cavity, Change of scope, PJSM, remove BOP lower 2"ram doors, Cut centrilizer with sawsaw, hook up steel cable to fish from rig floor, pull to surface. inspection showed that all was returned except one 1/4"keeper from end of bow spring. 21:00 23:00 2.00 0 0 PROD1 RPEQPI FISH T PJSM, nipple up stack, inspect and install lower combi's, install doors, fluid pac stack and surface lines for testing Combi rams 23:00 00:00 1.00 0 0 PROD1 RPEQP1 BOPE T Test lower 2"combi's 250 psi low/ 4300 psi high 05/25/2015 RIH, caliper cement pilot hole,crossover broke leaving caliper in hole, RU SL- fish caliper, RU SL attemp dummy WS down to 8355', RD SL, RU and RIH w/coil and dummy WS,tie into the K1 00:00 00:45 0.75 0 0 PROD1 RPEQP1PULD T Finish testing lower 2-3/8"combi's, RD testing equipment. Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 00:45 01:45 1.00 0 0 PROD1 RPEQPI PULD T PJSM,with Haliburton e-line. for making up caliper to calibrate.Then make up tools to BHI upper quick. 01:45 02:00 0.25 0 26 PROD1 RPEQPIPULD T MU caliper tools in hole, stab INJH ****Note: 10 hrs downtime for Nabors damaged caliper 02:00 05:06 3.10 26 8,228 PROD1 RPEQP1TRIP P RIH with caliper at 60 fpm 05:06 05:30 0.40 8,228 8,226 PROD1 RPEQPI DLOG P Tie into flag for-1.4', Log GR tie in with HAL GR log for-1'correction 05:30 05:42 0.20 8,226 8,502 PROD1 RPEQPI TRIP P RIH to log cement pilot hole 05:42 05:54 0.20 8,502 8,250 PROD1 RPEQP DLOG P Caliper cement pilot hole,8502 to 8250 05:54 06:00 0.10 8,250 8,502 PROD1 RPEQPI TRIP P Close fingers, RIH to make second pass 06:00 06:12 0.20 8,502 8,246 PROD1 RPEQPI DLOG P Make second caliper pass 8502 to 8246, Close fingers 06:12 07:36 1.40 8,246 31 PROD1 RPEQP-1TRIP P POOH 07:36 08:06 0.50 31 31 PROD1 RPEQPI OWFF P At surface,30 Min flow check, PJSM to lay down caliper 08:06 08:30 0.40 31 0 PROD1 RPEQP1PULD P Break off injector, caliper tool not on. Camera adapter failed 08:30 11:30 3.00 0 0 PROD1 RPEQPI WAIT T Make notifications, Plan forward to rig up slick line to fish caliper 11:30 12:00 0.50 0 0 PROD1 RPEQPI SFTY T PJSM with HAL S/L Rig up to fish caliper 12:00 15:00 3.00 0 0 PROD1 RPEQP1PULD T Rig up slick line 15:00 17:06 2.10 0 0 PROD1 RPEQPI TRIP T RIH with slick line 17:06 17:36 0.50 0 0 PROD1 RPEQP1PULD T At surface with fish, LD tools 17:36 18:21 0.75 0 0 PROD1 RPEQP1PULD P MU Dummy WS on Haliburton slick line, 18:21 20:21 2.00 0 0 PROD1 RPEQPITRIP P RIH, set down at 8355' SLMD, jarred down 2 times, PU 1k heavy, POOH 20:21 21:21 1.00 0 0 PROD1 RPEQP1PULD P RD slickline 21:21 21:36 0.25 0 0 PROD1 RPEQPI SFTY P PJSM for MU dummy WS to coil. 21:36 22:21 0.75 0 71 PROD1 RPEQP1PULD P MU, BHI tools and dummy WS. 22:21 23:51 1.50 71 8,295 PROD1 RPEQP-1TRIP P RIH,with coil 23:51 00:00 0.15 8,295 8,295 PROD1 RPEQP1DLOG P 8295',tie into the K1 marker no correction of 0.0 ft 35/26/2015 LD BHA#6, P/U BHA#7,set whipstock @ 8,455'. POOH for milling assembly. LD BHA#7, P/U BHA#8. Mill exit window @ 8,457'to 8,463', mill rathole to 8,478', back ream window,window clean. Start OOH, in progress. 00:00 00:45 0.75 8,295 8,485 PROD1 RPEQPITRIP P Continue RIH with dummy down to 8485', 00:45 02:03 1.30 8,485 71 PROD1 RPEQP1TRIP P POOH 02:03 02:33 0.50 71 0 PROD1 RPEQP1PULD P PJSM, check well for flow, LD dummy WS 02:33 03:18 0.75 0 74 PROD1 RPEQPI PULD P MU BOT WS setting tools P"ge 4 o 9 I Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 03:18 05:30 2.20 74 8,295 PROD1 RPEQP1TRIP P RIH with Open hole anchored WS EDC Open 05:30 05:36 0.10 8,295 8,305 PROD1 RPEQP1DLOG P Log tie in for-1, PUW=31 K, Shut EDC 05:36 06:00 0.40 8,305 8,465 PROD1 RPEQPI TRIP P Continue in with whipstock, Slight stacking 1200-1500LBS DHWOB, Get to setting depth, Orient to 5° LOHS, See tool shift @ 3800, Set down 2K after set,TOWS=8455 ' 06:00 07:36 1.60 8,465 74 PROD1 RPEQP1TRIP P Trip out after setting whipstock 07:36 08:06 0.50 74 74 PROD1 RPEQPI OWFF P On surface, 30 min flow check, PJSM lay down BHA#7 08:06 09:00 0.90 74 0 PROD1 RPEQPI PULD P Break off injector and reconfig BHA 09:00 09:18 0.30 0 73 PROD1 WHPST PULD P Make up injector to BHA#8 with .6° motor,2.80"DSM and 2.79"string reamer 09:18 10:54 1.60 73 8,295 PROD1 WHPST TRIP P RIH EDC open 10:54 11:00 0.10 8,295 8,322 PROD1 WHPST DLOG P Log K1 for no correction 11:00 12:12 1.20 8,322 8,318 PROD1 WHPST CIRC P Roll well to 9.3PPG used milling fluid, close EDC 12:12 12:48 0.60 8,318 8,457 PROD1 WHPST TRIP P RIH and dry tag TOWS @ 8457, 12:48 13:48 1.00 8,457 8,457 PROD1 WHPST WPST P Start milling window following revised procedure, 1.41 BPM @ 3270 PSI FS, BHP=3685. Did not stall contacting whipstock @ 10 FPH call pinch point©8456.9' 13:48 14:48 1.00 8,457 8,458 PROD1 WHPST WPST P Made one foot, Increase Diff pressure and WOB per procedure, Good metal on ditch magnets 14:48 18:39 3.85 8,458 8,462 PROD1 WHPST WPST P Continue as per well plan @ 1 fph, good metal in return, mill off casing, not much WOB. 18:39 22:27 3.80 8,462 8,478 PROD1 WHPST WPST P Mill @ 2-3 fph, dress BOW with string mill,good pressure and WOB, continue milling @ 6 fph to rathole TD. 22:27 23:27 1.00 8,478 8,478 PROD1 WHPST REAM P Make several back reaming passes @ 5L, 35L, and 25R. Dry drift window,window clean. 23:27 00:00 0.55 8,478 8,300 PROD1 WHPST TRIP P Start OOH, saw small overpull @ 8,415'. RBIH with no issue, continue OOH. 35/27/2015 Trouble getting high bend motor through tree, able to free BHA. RIH w/nozzle to 8,440', POOH laying KWF. LD BHA#9, MU BHA#10,displace fluid to used mud system,drill build section from 8,477'to EOB @ 8,556',displace back to KWF. POOH, LD BHA#10, PU BHA#11. RIH w/drilling assembly,displace fluid to new mud system. Start drilling A lateral from 8,556'to 8,640',drilling in progress. 00:00 01:00 1.00 8,300 77 PROD1 WHPST TRIP P Continue OOH with BHA#8 01:00 02:30 1.50 77 0 PROD1 WHPST PULD P PJSM. PUD BHA#8 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 02:30 04:30 2.00 0 76 PROD1 DRILL PULD T PJSM. PD BHA#9, made several attempts get 2.3 AKO motor through tree, all the normal tricks, unable to move BHA, can not close master. Call town, prep to bullhead KWF annulus. 04:30 05:30 1.00 76 0 PROD1 DRILL PULD T Got tool free. Pull into PDL, Bleed off and inspect 05:30 07:30 2.00 15 8,440 PROD1 DRILL TRIP T Tool look good, M/U BHA#9 Nozzle trip in to displace to 12.0PPG completion fluid 07:30 09:12 1.70 8,440 14 PROD1 DRILL TRIP T POOH on 12 PPG Fluid 09:12 09:48 0.60 14 14 PROD1 DRILL OWFF T At surface, 30 Min flow check, PJSM to P/U Build section BHA in PDL 09:48 10:42 0.90 14 63 PROD1 DRILL PULD P Unstab injector and break off nozzle. Run BHA#10 in well. Inspect motor/ AKO setting,All good, M/U to coil and surface test. 10:42 12:54 2.20 63 8,285 PROD1 DRILL TRIP P Trip in hole with BHA#10,2.3°AKO and RR Hughes bi center 12:54 13:00 0.10 8,285 8,314 PROD1 DRILL DLOG P Log K1 for-1.5'correction 13:00 13:36 0.60 8,314 8,422 PROD1 DRILL CIRC P Trip to 8420 and circulate well to 9.3PPG used floP ro 13:36 13:54 0.30 8,422 8,477 PROD1 DRILL TRIP P Close EDC and trip in to drill, Clean pass through window 13:54 14:54 1.00 8,477 8,557 PROD1 DRILL DRLG P 8477', Drill ahead, 1.41 BPM @ 3300 PSI FS, BHP=3705 14:54 17:12 2.30 8,557 73 PROD1 DRILL TRIP P Call EOB, PUW=31K, PUH to 8315 open EDC and swap well to 12PPG fluid 17:12 17:42 0.50 73 73 PROD1 DRILL OWFF P At surface,start 30 Min no flo check 17:42 19:27 1.75 73 73 PROD1 DRILL PULD P PJSM. LD BHA#10, motor AKO 2.3. PJSM. PU/MU BHA#11. 19:27 22:27 3.00 73 8,557 PROD1 DRILL TRIP P RIH w/lateral drilling assembly,while displace well over to new mud system 9.3 ppg Pow Vis. No correction at K1 marker, log RA tag @ 8,464',continue in hole. 22:27 23:36 1.15 8,557 8,640 PROD1 DRILL DRLG P BOBD: 1.42 bpm @ 3,150 psi, BHP=3,610 psi, CTW=8.5K, WOB=2.3K, ROP=80. 23:36 00:00 0.40 8,640 8,470 PROD1 DRILL DLOG P Trip for Mad pass, Mad pass @ 6 fpm. Start back in hole. 05/28/2015 Complete mad pass, continue drilling A lateral from 8,640'to TD @ 9,940'.Wiper trip to swab at max rate. RBIH for corrected TD @ 9,940'. Start OOH laying in beaded liner pill. 00:00 00:09 0.15 8,470 8,640 PROD1 DRILL DLOG P Complete mad pass, RBIH. 00:09 02:24 2.25 8,640 8,890 PROD1 DRILL DRLG P BOBD: 1.52 bpm @ 3,480 psi, BHP=3,740 psi, CTW=8.2K, WOB=1.6K, ROP=120. 02:24 02:39 0.25 8,890 8,890 PROD1 DRILL WPRT P Wiper to window, PUW=27K, RBIH. 02:39 05:36 2.95 8,890 9,140 PROD1 DRILL DRLG P BOBD: 1.45 bpm @ 3,420 psi, BHP=3,710 psi, CTW=7.2K, WOB=2.4K, ROP=115. Found fault @ 9,125',slowed progress. Page 6 of 9 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 05:36 06:12 0.60 9,140 9,140 PROD1 DRILL WPRT P Wiper trip to 8480, PUW=29K 06:12 12:54 6.70 9,140 9,440 PROD1 DRILL DRLG P 9140', Drill, 1.4 BPM @ 3025 PSI FS, BHP=3710 12:54 13:54 1.00 9,440 9,440 PROD1 DRILL WPRT P 9440 Wiper to window with tie in, PUW=29K,Tie in to RA marker for +2'correction. 13:54 17:00 3.10 9,440 9,740 PROD1 DRILL DRLG P 9440', Drill ahead, 1.45BPM @ 3060 PSI FS, BHP=3830 17:00 17:54 0.90 9,740 9,740 PROD1 DRILL WPRT P 9740 Wiper trip to 8940. PUW=30K 17:54 19:48 1.90 9,740 9,940 PROD1 DRILL DRLG P BOBD: 1.43 BPM @ 3,320 PSI, BHP=3,785 PSI, CTW=7.5K, WOB=2.8K, ROP=105. Called TD @ 9,940'. Pump 10 bbl to/hi vis sweeps. 19:48 21:48 2.00 9,940 76 PROD1 DRILL WPRT P Chase sweeps to swab at max rate, tag up, reset depth. 21:48 23:51 2.05 76 9,440 PROD1 DRILL DLOG P RBIH for corrected TD, tie-in to K1 for -1'correction, continue in hole,tag TD @ 9,440'.• 23:51 00:00 0.15 9,440 9,420 PROD1 DRILL CIRC P POOH laying in beaded liner pill. X5/29/2015 POOH laying in completion fluid. LD BHA#11. MU A liner assemby. RIH w/BHA#12, release from liner @ 9,940',TOL @ 8,439'. POOH. LD BHA#12. Function test BOP. MU BHA#13. RIH w/drilling assembly,dry tag billet @ 8,439'. Kick-off billet,drill ahead AL1 lateral,drilling in progress. 00:00 02:15 2.25 9,420 83 PROD1 DRILL CIRC P Continue OOH, laying in beaded liner pill/completion fluid. Paint EOP flags @ 8,600'and 7,200'. 02:15 02:45 0.50 83 83 PROD1 DRILL OWFF P Monitor well for flow. 02:45 03:45 1.00 0 0 PROD1 DRILL PULD P PJSM. LD BHA#11. Prep rig floor to run liner. 03:45 06:15 2.50 0 1,185 COMPZ CASING PUTB P PJSM. PU/MU A lateral liner assembly: Bull nose, 36 jts slotted, two solid pups, anchored billet. MU BHA#13. 06:15 07:51 1.60 1,185 8,366 COMPZ CASING RUNL P RIH w/BHA#12 Liner assembly 07:51 07:57 0.10 8,366 8,363 COMPZ CASING DLOG P Tie into upper pipe flag @ 7200 EOP for-3" 07:57 08:51 0.90 8,363 9,940 COMPZ CASING RUNL P Weight check 30K, Close EDC, Trip in hole. Clean pass through window and trip to bottom @ 9940 08:51 08:57 0.10 9,940 9,475 COMPZ CASING RUNL P Tag up @ 9940, PUW=32.5K,set back down oriented to 150R, Pumps on see tool shift @ 4100PSI 08:57 10:33 1.60 9,475 71 COMPZ CASING TRIP P PUH to 9475 take liner length out of counters,8374',Trip out 10:33 11:09 0.60 71 71 COMPZ CASING OWFF P At surface, 30 min flow check 11:09 11:39 0.50 71 0 COMPZ CASING PULD P Break off injector, Lay down liner running tools 11:39 12:09 0.50 0 0 PROD2 DRILL BOPE P Vac out stack and perform BOPE function test Pag'37af9 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 12:09 13:15 1.10 0 72 PROD2 DRILL PULD P M/U BHA#13, Drill by AL1 lateral with.8°AKO motor and RR Bi Center. Change out pack offs. Change out floats in UQC,service floats in lower FVS. Stab on injector and surface test 13:15 14:45 1.50 72 8,305 PROD2 DRILL TRIP P RIH, EDC open 14:45 15:45 1.00 8,305 8,320 PROD2 DRILL DLOG P Log K1 for-1'correction 15:45 16:09 0.40 8,320 8,350 PROD2 STK CIRC P RIH to 8350 and displace 12.0 to 9.3 PPG fluid 16:09 16:15 0.10 8,350 8,839 PROD2 STK TRIP P Trip in and dry tag liner top billet @8839 16:15 17:09 0.90 8,839 8,840 PROD2 STK KOST P Mill off liner top billet, 1.53 BPM @ 3200 PSI FS, BHP=3745,TF=180° 17:09 17:48 0.65 8,840 8,842 PROD2 STK KOST P Milled 1'speed up to 2 FPH, WOB=1.35,Aluminum in samples 17:48 22:03 4.25 8,842 9,090 PROD2 DRILL DRLG P Drill ahead: 1.54 BPM @ 3,545 PSI, BHP=3,790 PSI, CTW=9K, WOB=1.8K, ROP=35. PUH for dry drift, clean both directions. Continue drilling, start pumping new mud system, new mud around @ 9,027'. 22:03 22:48 0.75 9,090 9,090 PROD2 DRILL WPRT P Wiper to window, PUW=29K, RBIH. 22:48 00:00 1.20 9,090 9,139 PROD2 DRILL DRLG P Drill ahead: 1.51 BPM @ 3,480 PSI, BHP=3,830 PSI, CTW=7.8K, WOB=1.65K, ROP=35. 05/30/2015 Drill ahead AL1 lateral from 9,139'to called TD @ 9,940'. Pumped sweeps, chase to swab. RBIH for corrected TD @ 9,940'. POOH laying in liner pill/completion fluid. LD BHA#13. Prep rig floor for liner run. 00:00 03:45 3.75 9,139 9,340 PROD2 DRILL DRLG P Drill ahead: 1.51 BPM @ 3,560 PSI, BHP=3,840 PSI, CTW=7.5K, WOB=1.95K, ROP=50. 03:45 04:30 0.75 9,340 9,340 PROD2 DRILL WPRT P Wiper to window, PUW=29K, RBIH. 04:30 07:54 3.40 9,340 9,640 PROD2 DRILL DRLG P Drill ahead: 1.50 BPM @ 3,650 PSI, BHP=3,825 PSI, CTW=8.5K, WOB=1.45K, ROP=75. 07:54 08:54 1.00 9,640 9,640 PROD2 DRILL WPRT P 9640,Wiper trip to window with tie in for+1.5'correction, PUW=30K, Clean trip up and down 08:54 13:12 4.30 9,640 9,877 PROD2 DRILL DRLG P 9640', Drill, 1.5 BPM @ 3385PS1 FS, BHP=3875 13:12 13:18 0.10 9,877 9,877 PROD2 DRILL WPRT P BHA Wiper, PUW=29K 13:18 14:12 0.90 9,877 9,940 PROD2 DRILL DRLG P 9877', Drill 1.5 BPM @ 3358 PSI FS, BHP=3885 14:12 16:30 2.30 9,940 72 PROD2 DRILL WPRT P 9940', Call TD'Pump 10 X 10 sweeps, Chase to swab, PUW=29K 16:30 18:27 1.95 72 72 PROD2 DRILL WPRT P Tag up and reset counters. 18:27 19:51 1.40 72 9,940 PROD2 DRILL DLOG P RBIH, tie-in to K1, no correction.Tag corrected TD @ 9,940'. 19:51 22:39 2.80 9,940 72 PROD2 DRILL CIRC P Pump beads, POOH laying in liner pill/completion fluids. Paint EOP flags©8,200'&6,700', continue OOH. 22:39 23:09 0.50 72 72 PROD2 DRILL OWFF P Monitor well for flow, no flow. Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 23:09 00:00 0.85 72 0 PROD2 DRILL PULD P PJSM. LD BHA#13. Prep floor for liner run. 05/31/2015 Run AL1 liner assembly to 9,940', release from liner,TOL @ 8,362'. Circulate well to seawater,freeze protect with diesel from 2,500'. PUD BHA#14, Set BPV. Inhibit/Flush/blow down coil. Cut 2,500'of coil. ND BOP stack. 00:00 00:45 0.75 0 0 COMPZ CASING PUTB P Finish rig floor prep. PJSM. 00:45 04:48 4.05 0 1,622 COMPZ CASING PUTB P MU AL1 liner assembly: bull nose, 51 jts slotted, 3 solid pups,shorty deployment sleeve. MU BHA#14. 04:48 06:06 1.30 1,622 8,324 COMPZ CASING RUNL P RIH w/AL1 liner assembly,tie-in for 06:06 06:12 0.10 8,324 8,321 COMPZ CASING DLOG P Tie into flag for-.3, PUW=30K, DHWOB=-5K 06:12 06:54 0.70 8,321 9,940 COMPZ CASING RUNL P Continue in with AL-1 Liner,Tag bottom @ 9940, PUW=30K, DHWOB=-1.5K Pumps on 1.3 BPM @ 4100 PSI, PUH, PUW=27K, DHWOB=3.4K 06:54 07:30 0.60 9,940 8,350 COMPZ CASING DISP P PUH to 9928, Subtract liner length, 8350, Start seawater down coil 07:30 10:06 2.60 8,350 8,350 COMPZ CASING FRZP P Trip out, Lay in Diesel from 2500' 10:06 11:30 1.40 8,350 0 COMPZ CASING PULD P PJSM.Tag up and space out, PUD BHA#14 11:30 13:12 1.70 0 0 DEMOB WHDBO MPSP P PJSM, Set BPV 13:12 15:00 1.80 0 0 DEMOB WHDBO RURD P Pump flush, inhibitor, amd flush through CT 15:00 16:00 1.00 0 0 DEMOB WHDBO RURD P PJSM, R/U and blow down coil string. Bleed off 16:00 22:30 6.50 0 0 DEMOB WHDBO CTOP P PJSM, R/U to trim 2500'CT and discard, prep floor for move. 22:30 00:00 1.50 0 0 DEMOB WHDBO NUND P PJSM. Start ND BOP stack/cellar., RIG Release Midnight Page 9 of 9 2G-14 PRE AND POST RIG WELL WORK SUMMARY DATE SUMMARY POST RIG WELL WORK 6/5/2015 (STANDBY FOR VALVE CREW TO PULL BPV) MAKE SEVERAL MAGNET RUNS TO LINER TOP @ 8362' RKB; MEASURED BHP @ 8362' RKB (3634 PSI) IN PROGRESS. 6/6/2015 SET CATCHER ON LINER TOP © 8362' RKB; PULLED DV'S © 4420' &2104' RKB; SET OV© 4420' RKB & GLV @ 2104' RKB (GOOD IA DDT); PULLED CATCHER @ 8362' RKB. JOB COMPLETE. . . U) lii vs z W; ` gzN 1 C 7.0 i 0 CO 0 aw WCe a H ,, a. 0 z > •— -�. — CD MINN 2 .— Cl) t E 2 o c > )1,C1" 0 O a , O viN 1/4.1 � � � N � � aiC �. �. 0 YY OA2 CO 0 0 . , III Mb .4. N = o 11/411110 r-i ai °. .c co Iftbdo i CA 0 SZ ' 6 10 E — u"-- ..., 'CS 0 'o co c 6 . r-- •:r lo = -a u) T w u-) ¢ .- U- 0.. 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(O (ISO 8288 n 83 m 00D 00) N OC o n. .. 0 a) > : ai CO of CO CD CO of of of 01 0) 0f 0) of 01 of o) CO 0) 0) 0) 10 E O d O 0, o9C O a. 'Co o to 215050 215051 5 88 25 890 BAKER PRINT DISTRIBUTION LIST NES Please sign and return one copy of this transmittal form to: COMPANY ConocoPhillips Baker Hughes INTEQ RECEIVED (mandatory) 795 East 94th Avenue DATA LOGGED WELL NAME 2G-14A 2G-14AL1 Anchorage,Alaska 99515 ., K.BENDER UN 0 5 2015 (ma a ory FIELD Kuparuk River Unit to acknowledge receipt of this data. AOGCC (mandatory) COUNTY North Slope Borough LOG TYPE LWD-Coil (mandatory) (mandatory) STATE Alaska BH DISTRICT Alaska (mandatory) (mandatory) LOG DATE: May 29,2015 TODAYS DATE: 4-Jun-16 (mandatory) DISTRIBUTION LIST AUTHORIZED BY: Paula Lacey EMAIL: paula.lacevCa�bakerhuahes.com (mandatory) HAS CLIENT BEEN INVOICED FOR ADDITIONAL PRINTS? No COMPANY CD FIELD FINAL (digit FiFinal Finnalal ADDRESS(FEDEX WILL NOT DELIVER TO P.O.BOX) LOGS LOGS Survey/Logs Surveys PERSON ATTENTION #OF PRINTS #OF PRINTS #OF COPIES #OF PRINTS 4 4 4 4 4 4 4 1 ConocoPhillips Alaska Inc. 1 1 I Karen Hipsher/Lynn Hallford NSK 69 700 G Street Anchorage,AK 99510 2 BP Exploration(Alaska)Inc. 1 1 I Petrotechnical Data Center,LR2-1 900 E.Benson Blvd. Anchorage,Alaska 99508 Attn:Analisa Steger 3 Chevron/KRU Rep 1 1 Attn:Glenn Frederick P.O.Box 196247 Anchorage,AK 99519 4 1 State of Alaska -AOGCC I 1 1 _I Attn:Makana Bender 333 W.7th Ave,Suite 100 Anchorage,Alaska 99501 5 DNR-Division of Oil&Gas *** 1 Attn:James Hyun 550 West 7th Avenue,Suite 802 Anchorage,Alaska 99501 ***Stamp"confidential"on all material deliver to DNR TOTALS FOR THIS PAGE: 0 4 5 0 0 0 TOTALS FOR ALL PAGES: 0 4 5 0 0 0 5051 i z1 5050 158781587. Letter of Transmittal Esau lECEIVED BAKER Date: June 2, 2015 DATA LOGGED 6 /%5/2015 JUN 03 2015 HUGHES K BENDER AOGCC To: From: Makana Bender Yosha Ragbirsingh/Michael Soper AOGCC Baker Hughes 1NTEQ 333 West 7th Ave, Suite 100 795 East 94th Avenue Anchorage, Alaska 99501 Anchorage, Alaska 99515 Please find enclosed the directional survey data for the following well(s): 12G-14A • (2) Total prints Enclosed for each well(s): 1 hardcopy print of directional survey reports (NAD27) 1 compact disk containing electronic survey files Note: Please feel free to send us an email in place of return mail. Michael Soper, Baker Hughes, Project Engineer Michael.Soper@BakerHughes.com Yosha Ragbirsingh, Baker Hughes, Survey Manager Yosha.Ragbirsingh@BakerHughes.com ___— _____ CD N Ln N. CD CO Ln LC) r y C U H 0 au Ili ^ L. = > S0 `W0 0 O sz W Q cc N Z • C i ca 0 a co 0 w WIX a I— >, 0cn z w •Q a �, - •....._ _ a) m s = � .r ._ Ou 0 G)0. 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Q N co M V V V V N 1O 1O 6 6 6 r r r r 6 6 6 O) m 0 (0 V p C >, 2 7 D) 0) O) O) Oi Oi cc Oi Oi 0) O) O) O) 0) 0) 0i Oi 0) 0i W Oi U) I U E o :; m m m Ua in D N ,li PV OF Ty., e,\�\�j/,:s THE STATE Alaska Oil and Gas ti�,,"?�� O Conservation Commission -_- ____ _. fALAS :A ,• it-___' 333 West Seventh Avenue • Anchorage, OF � 01 GOVERNOR BILL WALKER Alaska 99501-3572 Main: 907.279.1433 ALAS* Fax• 907.276.7542 www.aogcc.alaska.gov D. Venhaus CTD Supervising Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2G-14A ConocoPhillips Alaska, Inc. Permit No: 215-050 Surface Location: 243' FNL, 88' FEL, SEC. 6, T1ON, R9E, UM Bottomhole Location: 94' FNL, 441' FWL, SEC. 7, T1ON, R9E, UM Dear Mr. Venhaus: Enclosed is the approved application for permit to redrill the above referenced service well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P oerster Chair DATED this 23 day of March, 2015. RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAR 12 2015 PERMIT TO DRILL AOGCC 20 AAC 25.005 1a Type of Work' 1 b Proposed Well Class Development-Oil ❑ Service-Winj ❑ Single Zone ❑✓ . 1c.Specify if well is proposed for. Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone❑ Coalbed Gas ❑ Gas Hydrates❑ Redrill ❑i ` Reentry E Exploratory ❑ Service-WAG ❑✓ •Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name 5. Bond' . U Blanket U Single Well 11.Well Name and Number: ConocoPhillips Alaska, Inc. • Bond No. 59-52-180 • KRU 2G-14A 3.Address: 6 Proposed Depth 12. Field/Pool(s): P.O. Box 100360 Anchorage,AK 99510-0360 MD.9941'• TVD: 6176' ` 4a. Location of Well(Governmental Section) 7 Property Designation(Lease Number) Kuparuk River Field Surface.243'FNL,88'FEL,Sec 6,T1ON, R9E, UM 1 ADL 25667 • Kupruk River Pool , Top of Productive Horizon 8 Land Use Permit 13.Approximate Spud Date 577'FSL,838'FWL,Sec.6,T1ON, R9E, UM 2588 5/7/2015 Total Depth: 9 Acres in Property. 14.Distance to 94'FNL,441'FWL,Sec. 7,T1ON, R9E, UM 2501 • Nearest Property: 11122 4b Location of Well(State Base Plane Coordinates-NAD 27) 10 KB Elevation above MSL: ' 140 feet 15 Distance to Nearest Well Open Surface:x- 508610 y- 5943345 Zone- 4 GL Elevation above MSL' 102 feet to Same Pool. 2K-07,1930 16 Deviated wells Kickoff depth • 8455 ft. 17 Maximum Anticipated Pressures in psig(see 20 AAC 25 035) Maximum Hole Angle • 98° deg Downhole.4349 psig • Surface. 3820 psig . 18.Casing Program Specifications Top - Setting Depth -Bottom Cement Quantity,c f or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7# L-80 ST-L 790' 9150' 6149' 9940' 6176' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft). Total Depth TVD(ft) Plugs(measured) Effective Depth MD(ft): Effective Depth TVD(ft): Junk(measured) 8750 6297 none 8645 6220 none Casing Length Size Cement Volume MD ND Conductor/Structural 72' 16" 202 sx CS II 110' 110' Surface 3293' 9.625" 1060 PF E,370 sx PF C 3327' 27.60' Intermediate Production 8691' 8724' 335 sx CI G, 175 sx PF C 8724' 6278' Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 8452-8470, 8490-8532 6081-6094, 6109-6139 20 Attachments: Property PIM ❑ BOP Sketch❑ Drilling Program ❑✓ Time v.Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Program Q 20 MC 25.050 requirements Q 21 Verbal Approval Commission Representative: Date ' ,—\\_S 22. I hereby certify that the foregoing is true and correct Contact Gary Eller @ 263-4172 Email J.Gary.Eller@cop m Printed Name D. Venhaus Title CTD Supervising Engineer Signature `�,a,-;,_' Phone 263-4372 Date 3—/ ' IS 9 Commission Use Only Permit to Drill API Number. Number: Permit Appro I See cover letter Number: a IS — as J 50- 0029— a//6/_0/ oo Date 3� 16- for other requirements Conditions of approval: If box is checked,well may not be used to explore for,test,or produce c-oalbedathane,gas hydrates,or gas contained in shales: Other: ac p fsei- to 43 Oa p5 i Samples req'd: Yes ❑ No Mud log req'd• Yes❑ No 21'p- / -21J/a ✓ 3 i CVCn 1-C 1' 'Z5 r H2S measures: Yes L No ❑ Directional svy req'd: Yes Zf No❑ a 2 2 5 Sr¢G wi fntSS�� AA 7 7—Z.9/acing exceptipn req'd: Yes ❑ No Inclination-only svy req'd: Yes No Er ag:iYc QFtr�S1-mob) ii3ro/ /eVccf/b-1-, , D APPROVED BY THE 2 Approved by. se = I EIS COMMISSION Date: 3/ J Form 10-401 (Rlsed 10/2012) e i v li r /( i s from the date of approval(20 AAC 25.005(g)) a 3/0„//5 I/�c� ConocoPhilli s RECEIVED Alaska MAR 12 2015 P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 AOGCC March 10, 2015 Commissioner-State of Alaska Alaska Oil &Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill a dual-lateral out of the Kuparuk Well 2G-14 using the coiled tubing drilling rig, Nabors CDR2-AC. CTD operations are scheduled to begin in May 2015. The objective will be to drill laterals KRU 2G-14A and 2G-14AL1 targeting the Kuparuk A-sand. A separate sundry application is attached to plug the KRU 2G-14 (184-130) perfs to allow these laterals to be drilled. As detailed in the attachments, ConocoPhillips requests a variance from the requirements of 20 AAC 25.112(c)(1)to plug the A-sand perfs in 2G-14. Attached to this application are the following documents: — 10-401 Applications for 2G-14A&2G-14AL1 — Detailed Summary of Operations — Directional Plans for 2G-14A&2G-14AL1 — Proposed CTD Schematic — 10-403 Sundry Application to Abandon KRU 2G-14 (184-130) — Operations Summary in support of the 10-403 sundry application If you have any questions or require additional information please contact me at 907-263-4172. Sincerely, Gary Elle ConocoPhillips ska P Coiled Tubing Drilling Engineer Kuparuk CTD Laterals NABOAKAsKA 2G-14A& AL1 ° 01." Application for Permit to Drill Document 2fit 1. Well Name and Classification 2 (Requirements of 20 AAC 25.005(f)and 20 AAC 25.005(b)) 2 2. Location Summary 2 (Requirements of 20 AAC 25.005(c)(2)) 2 3. Blowout Prevention Equipment Information 2 (Requirements of 20 AAC 25.005(c)(3)) 2 4. Drilling Hazards Information and Reservoir Pressure 2 (Requirements of 20 AAC 25.005(c)(4)) 2 5. Procedure for Conducting Formation Integrity tests 2 (Requirements of 20 AAC 25.005(c)(5)) 2 6. Casing and Cementing Program 3 (Requirements of 20 AAC 25.005(c)(6)) 3 7. Diverter System Information 3 (Requirements of 20 AAC 25.005(c)(7)) 3 8. Drilling Fluids Program 3 (Requirements of 20 AAC 25.005(c)(8)) 3 9. Abnormally Pressured Formation Information 4 (Requirements of 20 AAC 25.005(c)(9)) 4 10. Seismic Analysis 4 (Requirements of 20 AAC 25.005(c)(10)) 4 11. Seabed Condition Analysis 4 (Requirements of 20 AAC 25.005(c)(11)) 4 12. Evidence of Bonding 4 (Requirements of 20 AAC 25.005(c)(12)) 4 13. Proposed Drilling Program 4 (Requirements of 20 AAC 25.005(c)(13)) 4 Summary of Operations 4 Pressure Deployment of BHA 5 Liner Running 6 14. Disposal of Drilling Mud and Cuttings 6 (Requirements of 20 AAC 25.005(c)(14)) 6 15. Directional Plans for Intentionally Deviated Wells 6 (Requirements of 20 AAC 25.050(b)) 6 16. Quarter Mile Injection Review (for injection wells only) 7 (Requirements of 20 AAC 25.402) 7 17. Attachments 7 Attachment 1: Directional Plans for 2G-14A&2G-14AL1 7 Attachment 2: Current Well Schematic for 2G-14 7 Attachment 3: Proposed Well Schematic for 2G-14 CTD Laterals 7 Page 1 of 7 March 12, 2015 PTD Application: 2G-14A & 2G-14AL1 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) The proposed laterals described in this document are 2G-14A & 2G-14AL1. All laterals will be classified as "Service- WAG"wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the A sand package in the Kuparuk reservoir. See the attached 10-401 forms for surface and subsurface coordinates of the 2G-14A& 2G-14AL1 laterals. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR2-AC. BOP equipment is as required per 20 AAC 25.036, for thru-tubing drilling operations. - Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and 4300 psi. Using the maximum formation pressure in the area of 14.0 ppg EMW in well 2G-15 (4349 psi at 5995' TVD, 7/10/2012), the maximum potential surface pressure in 2G-14, assuming a gas gradient of 0.1 psi/ft, would be 38.20 psi. See the "Drilling Hazards Information and Reservoir Pressure" section for more details. - The annular preventer will be tested to 250 psi and 2500 psi. 4. Drilling Hazards Information and Reservoir Pressure (Requirements of 20 AAC 25.005(c)(4)) Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005(c)(4)(a)) Well 2G-14 has been shut in almost a year, which has allowed the formation pressure to drop to 12.4 ppg EMW as of 3/5/15 (3935 psi at 6116' TVD). The maximum down hole pressure in the vicinity is at well 2G-15 to the northeast, which measured 14.0 ppg EMW in July 2012 (4349 psi at 5995' TVD). The 2G-14 laterals will be drilled away from 2G-15, so it is believed that there is no way we can encounter formation pressure in the magnitude of 2G-15. The highest pressure that we expect to encounter is in 2G-14 itself. The most recent pressure measurement in 2G-14 indicated a formation pressure of 3910 psi at 6116' TVD or 12.3 ppg EMW (3/10/15) but w expect formation pressure to decline to approximately 12.0 ppg EMW by the time we spud. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) No specific gas zones will be drilled but 2G-14 has had gas injection as recently as 2009. There is a distinct potential that free gas could be associated with any formation influx. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) A major objective in drilling the 2G-14 laterals is to cross a large DTS fault south of 2G-14 into an area of lower pressure, believed to be in the range of 8.0 ppg EMW. The major drilling risk in 2G-14 then is lost circulation from these lower pressure intervals. We have mitigated that risk by reducing the differential pressure between fault blocks by keeping 2G-14 shut-in for almost a year. We hope that the formation pressure in 2G-14 will have declined to 12.0 ppg EMW by the time we spud in May 2015. Another risk in 2G-14 is hole stability through the A6 shale and A5 basal shales. We expect to encounter these intervals in the build section and after crossing the DTS fault south of 2G-14. We will use MPD techniques to target a constant formation pressure while drilling and completing all laterals. There is a risk of differential sticking since we're drilling into areas of reduced formation pressure. There are some backup window exit locations available in 2G-14 if needed. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) N/A for this thru-tubing drilling operation. Page 2 of 7 March 12, 2015 PTD Application: 2G-14A & 2G-14AL1 According to 20 AAC 25.030(f), thru-tubing drilling operations need not perform additional formation integrity tests. 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Lateral Liner Top Liner Btm Liner Top Liner Btm Liner Details Name MD MD TVDSS TVDSS 2%", 4.7#, L-80, ST-L slotted liner; with 2G-14A 9150' 9940' 6010' 6036' aluminum billet 2G-14AL2 8368' 9940' 5880' 6016' 2%", 4.7#, L-80, ST-L slotted liner with deployment sleeve Existing Casing/Liner Information Category OD Weight Grade Connection Top Btm Top Btm Burst Collapse (ppf) MD MD TVD TVD psi psi Conductor 16" 62.50 H-40 Welded 0' 110' 0' 110' 1640 630 Surface 9%" 36.0 J-55 BTC 0' 3327' 0' 2759' 3520 2020 Casing 7" 26 J-55 BTC 0' 8727' 0' 6278' 4980 4320 Tubing 3W 9.3 J-55 EUE 8rd 0' 8374' 0' 6024' 6990 7400 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) N/A for this thru-tubing drilling operation. Nabors CDR2-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a diverter system is not required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System Diagram of Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System - Window milling operations: Chloride-based Flo-Pro mud (10.0 ppg) - Drilling operations: Chloride-based Flo-Pro mud (10.0 ppg). This mud weight will not hydrostatically overbalance reservoir pressure. However, overbalanced conditions will be maintained using MPD practices described below. - Completion operations: 2G-14 does not contain a subsurface safety valve (SSSV). The well will be loaded with 12.2 ppg (or greater) completion fluid in order to provide formation over-balance while running completions. � - Emergency Kill Weight fluid: Two wellbore volumes of 12.9 ppg kill weight fluid will be stored at drillsite 1B in the Kuparuk field, and is accessible for trucking to the rig during CTD operations. Managed Pressure Drilling Practice / Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole formation throughout the coiled tubing drilling (CTD) process. Maintaining a constant BHP Page 3 of 7 March 12, 2015 PTD Application: 2G-14A & 2G-14AL1 promotes wellbore stability, particularly in shale sections, while at the same time providing an overbalance on the reservoir. Because of the expected 12.0 ppg EMW formation pressure in 2G-14, it is our plan to hold 12.2 ppg EMW at the window to maintain overbalance and promote shale stability. The constant BHP target will be adjusted to maintain overbalanced conditions if increased reservoir pressure is encountered during drilling. The constant BHP target will be maintained utilizing the surface choke. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Pressure at the 2G-14A Window(8455' MD, 6083' TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A-sand Formation Pressure (12.0 ppg) 3796 psi 3796 psi Mud Hydrostatic(10.0 ppg) 3163 psi 3163 psi Annular friction (i.e. ECD, 0.060 psi/ft) 507 psi 0 psi Mud + ECD Combined 3670 psi 3163 psi (no choke pressure) (underbalanced (underbalanced —130 psi) —630 psi) Target BHP at Window(12.2 ppg) 3859 psi 3859 psi Choke Pressure Required to Maintain Target BHP 190 psi 700 psi 9. Abnormally Pressured Formation Information (Requirements of 20 AA C 25.005(c)(9)) N/A-Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005(c)(10)) N/A-Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A-Application is not for an exploratory or stratigraphic test well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well 2G-14 is a Kuparuk A-sand injection (service)well equipped with 31/2"tubing and 7"production casing. Two laterals from well 2G-14 will be drilled,both to the south to support A sand production from 2K-07, 2K-15, and 2K-26. Operations will target the A4 and A5 sand intervals. Prior to CTD operations,the existing A-sand perfs in will be squeezed with cement to provide a means to kick out of the 7"casing. ConocoPhillips has submitted at 10-403 sundry application for a variance Page 4 of 7 March 12, 2015 PTD Application: 2G-14A & 2G-14AL1 from the requirements of 20 AAC 25.112(c)(1)to plug the A-sand perfs in this manner. Immediately prior to cementing the A-sand perfs,the D-nipple at 8362' MD will be milled out to a 2.80" ID and the tubing tail will be perforated. Both of these operations are needed to prepare the well for CTD operations. After plugging off the existing A-sand perfs with cement pre-rig,the Nabors CDR2-AC drilling rig will drill a pilot hole to 8475' and set a whipstock in the 2.80"pilot hole at the planned kickoff point at 8455' MD Both laterals will be completed with 23/8" slotted liner from TD with the final liner top located inside the 3'/2"tubing tail. Pre-CTD Work 1. E-line: Shoot 2' of holes in the 31/4"tubing tail at 8357' MD. 2. Coil: Mill out Camco D-nipple at 8362' MD to 2.80" 3. Coil: Cement squeeze the A-sand perfs bringing cement up into the tubing tail. 4. Slickline: Drift tubing,tag top of cement and pressure test. 5. Prep site for Nabors CDR2-AC, including setting BPV Rig Work 1. MIRU Nabors CDR2-AC rig using 2"coil tubing. NU 7-1/16"BOPE,test. 2. 2G-14A Sidetrack(A4 sand - south) / a. Drill 2.80"high-side pilot hole through cement to 8475' MD b. Caliper pilot hole c. Set whipstock at 8455' MD d. Mill 2.80"window at 8455' MD e. Drill 3"bi-center lateral to TD of 9940' MD f. Run 2%" slotted liner with an aluminum billet from TD up to 9150' MD 3. 2G-14AL1 Lateral(A5 sand -south) a. Kick off of the aluminum billet at 9150' MD b. Drill 3" bi-center lateral to TD of 9940' MD c. Run 2%" slotted liner from TD up to 8368' MD, inside the 31/4"tubing tail 4. Freeze protect. Set BPV,ND BOPE. RDMO Nabors CRD2-AC. Post-Rig Work 1. Pull BPV 2. Obtain static BHP. 3. Backflow well to clean up CTD laterals 4. Conduct MIT-IA 5. Return to injection Pressure Deployment of BHA The planned bottomhole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. Because of this, MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slickline lubricator. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slickline. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate Page 5 of 7 March 12, 2015 PTD Application: 2G-14A & 2G-14AL1 reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. - The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment, the steps listed above are observed, only in reverse. Liner Running - The 2G-14 CTD laterals will be displaced to an overbalancing fluid (12.2 ppg NaBr) prior to running liner. See the "Drilling Fluids" section for more details. - While running 2%" slotted liner, a joint of 2%" non-slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2%" rams will provide secondary well control while running 2%" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1R-18 or 1B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) - The Applicant is the only affected owner. - Please see Attachment 1: Directional Plan - Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. - MWD directional, resistivity, and gamma ray will be run over the entire openhole section. - Distance to Nearest Property Line and nearest well in the same pool. Sidetrack Directional Distance to Distance to Name Plan Unit Boundary Nearest Well Nearest Well 2G-14A 06 11,122' 1930' 2K-07 (existing) 1830' 2K-15L1 (proposed) 2G-14AL1 03 11,122' 1930' 2K-07 (existing) 1830' 2K-15L1 (proposed) Page 6 of 7 March 12, 2015 PTD Application: 2G-14A & 2G-14AL1 16. Quarter Mile Injection Review (for injection wells only) (Requirements of 20 AAC 25.402) There are no wells within 1/4-mile of either 2G-14A or 2G-14AL1 that penetrate the same strata. 2G-14(mother bore) Injector • Completed with 7", 26#, K-55 casing in October 1982. It was cemented with 335 sacks of Class"G" cement. • 2G-14 is classified as a "Normal Well" in the ConocoPhillips AnnCom database. It passed a non- AOGCC witnessed MIT-IA to 3000 psi on 2/24/15. The last state-witnessed MIT-IA was 5/1/12. • Current A-sand perforations as follows. These perfs will be squeezed as part of the pre-CTD prep. • A5: 8452'-8472' MD • A4: 8490'-8532' MD • The CTD sidetrack will exit within the current perforated interval at 8455' MD • The packer is located at 8345' MD, placing it well within the 200' of the window as required by 20 AAC 25.412(b). • The cement bond log of 10/22/1984 shows good quality cement as per the original injection order. The proposed kick-off point for the CTD sidetrack is in the A-sand perfs and should not compromise existing conformance. 2G-14A& AL1 CTD Injectors • The window for the 2G-14A CTD lateral will be milled at 8455' MD which is within the existing perforated interval for 2G-14. The window exit here will not compromise the cement integrity of 2G-14 in any way. 17. Attachments Attachment 1: Directional Plans for 2G-14A & 2G-14AL 1 Attachment 2: Current Well Schematic for 2G-14 Attachment 3: Proposed Well Schematic for 2G-14 CTD Laterals Page 7 of 7 March 12, 2015 2G-14 Proposed CTD Sidetrack Modified by JGE 3-12-15 3-1/2"Baker FVL SSSV @ 2055'MD(locked out) (ID=2.813") 3-1/2"9.3#J-55 EUE 8rd Tubing to surface 16"62#H-40 shoe @ 110' MD 9-5/8""36#L-80 shoe @ 3327'MD —mole 1_ 3-1/2"Camco MMH gas lift mandrel @ 2104',4420',6165',7473',8289' Baker 3-1/2"PBR @ 8331 MD(2.81"ID) Baker FHL packer @ 8345'MD(3.0"ID) ***Will pert tubing tail at 8357'MD 3-1/2"Camco D landing nipple @ 8362'MD(2.75"min ID,No-Go) ""Will be milled out to 2.80"ID 3-1/2"tubing tail @ 8373'MD KOP @ 8455'MD Cement pilot hole drilled to-8475'MD 2G-14AL1,Proposed TD=9,940'MD A-sand perfs(sqz'd) 2-3/8"liner with top at 8368'MD 8452'-8470'MD 2G-14A,Proposed TD=9,940'MD 2-3/8"liner with billet at 9150'MD 7"26#J-55 shoe @ N fto_ N„Tio w2 ga. h }tt tl�+ ' F 1{ I::rd, Y I�, t:' , ffiimfi0 t. » o - �o ■Bani+-h.-la-I-4+1 ZEoo8E � ..., ,,, ... : ,_ , .;.tImommels7:-F-ti---NtY;� 7s m 5 s �c •yam f E F. 3 r c, �.'i8r i. .ari�i r { l:I . . -1-1, .. it ../ as! _nnsiiiii._*i;_ �' { 1�g S��c� _ --- - 1$ i.-+ matimf-+ 1,-.� it __r o 1 '.~r -1- t i1 4 Tt MEM.,.fitEllin +4,-El i„ t:. \ Htl MEI ,t- 8lir ..' t: 7ZEE +,4 F Nth �� 11 r - 47 �. 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LI t{I{ _ o N _..___ . ,,,_7,_ 1 1:i.44H-it 1 ,,1. 8 0 - sPINENIM `` 8 = 8 0 8 8 8 8 8 " 8' �... o _ . o 8 $ 8 o� O o�0 N N N N N ; N O b Hf W vi-' 4 Y Y o N a , ' 1 / �p �O �6 (uijjsn OOZ)(+) oN/(-)4anos N ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2G Pad 2G-14 2G-14A Plan: 2G-14A wp06 Standard Planning Report 10 March, 2015 BAKER HUGHES r ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 2G-14 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2G-14 @ 140.00usft(2G-14) Site: Kuparuk 2G Pad North Reference: True Well: 2G-14 Survey Calculation Method: Minimum Curvature Wellbore: 2G-14A Design: 2G-14A_wp06 Project Kuparuk River Unit,North Slope Alaska,United States Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk 2G Pad Site Position: Northing: 5,944,015.12 usft Latitude: 70°15'29.733 N From: Map Easting: 508,649.96 usft Longitude: 149°55'48.314 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.07° Well 2G-14 Well Position +N/-S 0.00 usft Northing: 5,943,345.15 usft Latitude: 70°15'23.144 N +E/-W 0.00 usft Easting: 508,609.90 usft Longitude: 149°55'49.502 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 2G-14A Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2014 7/1/2015 18.68 80.85 57,545 Design 2G-14A_wp06 Audit Notes: Version: Phase: PLAN Tie On Depth: 8,400.00 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 0.00 0.00 0.00 221.20 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +El-W Rate Rate Rate TFO (usft) (°) (°) (usft) (usft) (usft) 0100ft) (°/100ft) (°/100ft) (0) Target 8,400.00 43.48 223.47 5,903.23 -3,845.81 -3,758.43 0.00 0.00 0.00 0.00 8,455.00 43.45 223.25 5,943.15 -3,873.32 -3,784.41 0.28 -0.05 -0.40 -101.29 8,476.00 46.39 223.25 5,958.02 -3,884.12 -3,794.57 14.00 14.00 0.00 0.00 8,590.69 98.00 223.25 5,991.91 -3,960.99 -3,866.88 45.00 45.00 0.00 0.00 8,680.69 89.54 220.18 5,986.00 -4,027.97 -3,926.57 10.00 -9.41 -3.41 200.00 8,980.00 89.60 190.25 5,988.32 -4,295.68 -4,052.64 10.00 0.02 -10.00 270.00 9,080.00 79.94 192.87 5,997.43 -4,393.12 -4,072.56 10.00 -9.66 2.62 165.00 9,200.00 80.16 205.05 6,018.23 -4,504.68 -4,110.88 10.00 0.19 10.15 90.00 9,310.00 80.35 216.21 6,036.91 -4,597.81 -4,166.03 10.00 0.17 10.15 90.00 9,419.16 91.10 214.32 6,045.04 -4,686.56 -4,228.77 10.00 9.85 -1.73 350.00 9,599.16 91.05 196.32 6,041.64 -4,848.57 -4,305.43 10.00 -0.03 -10.00 270.00 9,940.87 90.87 230.50 6,035.76 -5,129.57 -4,490.78 10.00 -0.05 10.00 90.00 3/10/2015 12:38:58PM Page 2 COMPASS 5000.1 Build 61 • ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 2G-14 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2G-14 @ 140.00usft(2G-14) Site: Kuparuk 2G Pad North Reference: True Well: 2G-14 Survey Calculation Method: Minimum Curvature Wellbore: 2G-14A Design: 2G-14A_wp06 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (o) (e). (usft) (usft) (usft) (usft) (.1100ft) (') (usft) (usft) 8,400.00 43.48 223.47 5,903.23 -3,845.81 -3,758.43 5,369.29 0.00 0.00 5,939,495.43 504,856.24 TIP 8,455.00 43.45 223.25 5,943.15 -3,873.32 -3,784.41 5,407.10 0.28 -101.29 5,939,467.89 504,830.30 KOP 8,476.00 46.39 223.25 5,958.02 -3,884.12 -3,794.57 5,421.92 14.00 0.00 5,939,457.08 504,820.15 End 14 dls,Start 45 dls 8,500.00 57.19 223.25 5,972.84 -3,897.84 -3,807.47 5,440.74 45.00 0.00 5,939,443.35 504,807.27 8,590.69 98.00 223.25 5,991.91 -3,960.99 -3,866.88 5,527.39 45.00 0.00 5,939,380.13 504,747.93 End 45 dls,Start 10 dls 8,600.00 97.12 222.93 5,990.69 -3,967.74 -3,873.19 5,536.62 10.00 -160.00 5,939,373.39 504,741.64 8,680.69 89.54 220.18 5,986.00 -4,027.97 -3,926.57 5,617.10 10.00 -160.04 5,939,313.10 504,688.33 5 8,700.00 89.54 218.25 5,986.16 -4,042.93 -3,938.78 5,636.40 10.00 -90.00 5,939,298.13 504,676.14 8,800.00 89.55 208.25 5,986.96 -4,126.45 -3,993.54 5,735.31 10.00 -89.98 5,939,214.55 504,621.48 8,900.00 89.57 198.25 5,987.74 -4,218.21 -4,032.97 5,830.32 10.00 -89.90 5,939,122.76 504,582.16 8,980.00 89.60 190.25 5,988.32 -4,295.68 -4,052.64 5,901.57 10.00 -89.83 5,939,045.27 504,562.57 6 9,000.00 87.67 190.77 5,988.80 -4,315.34 -4,056.29 5,918.76 10.00 165.00 5,939,025.61 504,558.95 9,080.00 79.94 192.87 5,997.43 -4,393.12 -4,072.56 5,988.00 10.00 164.99 5,938,947.82 504,542.78 7 9,100.00 79.95 194.90 6,000.92 -4,412.24 -4,077.28 6,005.50 10.00 90.00 5,938,928.69 504,538.07 9,200.00 80.16 205.05 6,018.23 -4,504.68 -4,110.88 6,097.19 10.00 89.65 5,938,836.22 504,504.58 8 9,300.00 80.31 215.20 6,035.23 -4,589.81 -4,160.27 6,193.77 10.00 90.00 5,938,751.05 504,455.29 9,310.00 80.35 216.21 6,036.91 -4,597.81 -4,166.03 6,203.58 10.00 88.28 5,938,743.04 504,449.55 9 9,400.00 89.21 214.65 6,045.09 -4,670.77 -4,217.92 6,292.66 10.00 -10.00 5,938,670.03 504,397.74 9,419.16 91.10 214.32 6,045.04 -4,686.56 -4,228.77 6,311.69 10.00 -9.86 5,938,654.22 504,386.91 10 9,500.00 91.09 206.24 6,043.49 -4,756.30 -4,269.50 6,390.99 10.00 -90.00 5,938,584.45 504,346.27 9,599.16 91.05 196.32 6,041.64 -4,848.57 -4,305.43 6,484.08 10.00 -90.15 5,938,492.14 504,310.44 11 9,600.00 91.05 196.40 6,041.62 -4,849.38 -4,305.67 6,484.84 10.00 90.00 5,938,491.34 504,310.21 9,700.00 91.03 206.41 6,039.81 -4,942.34 -4,342.11 6,578.80 10.00 90.00 5,938,398.34 504,273.87 9,800.00 90.98 216.41 6,038.05 -5,027.57 -4,394.15 6,677.20 10.00 90.18 5,938,313.06 504,221.94 9,900.00 90.91 226.41 6,036.40 -5,102.47 -4,460.20 6,777.06 10.00 90.36 5,938,238.10 504,155.98 9,940.87 90.87 230.50 6,035.76 -5,129.57 -4,490.78 6,817.59 10.00 90.52 5,938,210.97 504,125.44 Planned TD at 9940.87 3/10/2015 12:38:58PM Page 3 COMPASS 5000.1 Build 61 ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 2G-14 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2G-14 @ 140.00usft(2G-14) Site: Kuparuk 2G Pad North Reference: True Well: 2G-14 Survey Calculation Method: Minimum Curvature Wellbore: 2G-14A Design: 2G-14A_wp06 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +NI-S +EI-W Northing Easting -Shape (1 (1 (usft) (usft) (usft) (usft) (usft) Latitude Longitude 2G-14A_T03 0.00 0.00 6,027.00 -6,101.181,136,011.37 5,938,543.00 1,644,514.00 70°0'27.213 N 140°49'50.744 W -plan misses target center by 1139772.04usft at 8400.00usft MD(5903.23 TVD,-3845.81 N,-3758.43 E) -Point 2G-14A_Fault1 0.00 0.00 0.00 -5,849.251,136,091.67 5,938,795.00 1,644,594.00 70°0'29.542 N 140°49'47.388 W -plan misses target center by 1139867.15usft at 8400.00usft MD(5903.23 TVD,-3845.81 N,-3758.43 E) -Rectangle(sides W470.00 1-11.00 D0.00) 2G-14A_T01 0.00 0.00 5,993.00 -5,498.441,136,292.09 5,939,146.00 1,644,794.00 70°0'32.656 N 140°49'40.201 W -plan misses target center by 1140051.72usft at 8400.00usft MD(5903.23 TVD,-3845.81 N,-3758.43 E) -Point 2G-14A_T02 0.00 0.00 5,988.00 -5,848.251,136,092.67 5,938,796.00 1,644,595.00 70°0'29.550 N 140°49'47.356 W -plan misses target center by 1139852.86usft at 8400.00usft MD(5903.23 TVD,-3845.81 N,-3758.43 E) -Point 2G-14A_T04 0.00 0.00 6,036.00 -6,682.831,135,654.67 5,937,961.00 1,644,158.00 70°0'22.086 N 140°50'3.351 W -plan misses target center by I139416.64usft at 8400.00usft MD(5903.23 TVD,-3845.81 N,-3758.43 E) -Point 2G-14 CTD Polygon 0.00 0.00 0.00 -5,342.191,136,084.25 5,939,302.00 1,644,586.00 70°0'34.477 N 140°49'45.432 W -plan misses target center by 1139858.95usft at 8400.00usft MD(5903.23 TVD,-3845.81 N,-3758.43 E) -Polygon Point 1 0.00 0.00 0.00 5,939,302.00 1,644,586.00 Point2 0.00 -1,299.40 -666.49 5,938,001.97 1,643,921.06 Point 3 0.00 -1,533.83 -300.71 5,937,767.98 1,644,287.07 Point4 0.00 -164.48 427.86 5,939,138.03 1,645,014.00 Point 5 0.00 0.00 0.00 5,939,302.00 1,644,586.00 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 9,940.87 6,035.76 2 3/8" 2.375 3.000 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 8,400.00 5,903.23 -3,845.81 -3,758.43 TIP 8,455.00 5,943.15 -3,873.32 -3,784.41 KOP 8,476.00 5,958.02 -3,884.12 -3,794.57 End 14 dls,Start 45 dls 8,590.69 5,991.91 -3,960.99 -3,866.88 End 45 dls,Start 10 dls 8,680.69 5,986.00 -4,027.97 -3,926.57 5 8,980.00 5,988.32 -4,295.68 -4,052.64 6 9,080.00 5,997.43 -4,393.12 -4,072.56 7 9,200.00 6,018.23 -4,504.68 -4,110.88 8 9,310.00 6,036.91 -4,597.81 -4,166.03 9 9,419.16 6,045.04 -4,686.56 -4,228.77 10 9,599.16 6,041.64 -4,848.57 -4,305.43 11 9,940.87 6,035.76 -5,129.57 -4,490.78 Planned TD at 9940.87 3/10/2015 12:38:58PM Page 4 COMPASS 5000.1 Build 61 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2G Pad 2G-14 2G-14A 2G-14A_wp06 Travelling Cylinder Report 10 March, 2015 r1 BAKER HUGHES Baker Hughes INTEQ r�� ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips(Alaska)Inc.-Kup2 Local Co-ordinate Reference: Well 2G-14 Project: Kuparuk River Unit TVD Reference: 2G-14 @ 140.00usft(2G-14) Reference Site: Kuparuk 2G Pad MD Reference: 2G-14 @ 140.00usft(2G-14) Site Error: 0.00usft North Reference: True Reference Well: 2G-14 Survey Calculation Method: Minimum Curvature Well Error: 0.00usft Output errors are at 1.00 sigma Reference Wellbore 2G-14A Database: OAKEDMP2 Reference Design: 2G-14A_wp06 Offset TVD Reference: Offset Datum Reference 20-14A_wp06 Filter type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Interpolation Method: MD Interval 25.O0usft Error Model: ISCWSA Depth Range: 8,400.00 to 9,940.87usft Scan Method: Tray.Cylinder North Results Limited by: Maximum center-center distance of 1,180.09usft Error Surface: Elliptical Conic Survey Tool Program Date 3/10/2015 From To (usft) (usft) Survey(Wellbore) Tool Name Description 200.00 8,400.00 2G-14(2G-14) GCT-MS Schlumberger GCT multishot 8,400.00 9,940.86 2G-14A_wp06(2G-14A) MWD MWD-Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") ( ) 9,940.87 6,175.76 23/8" 2-3/8 3 Summary Reference Offset Centre to No-Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well-Wellbore-Design (usft) (usft) (usft) (usft) Kuparuk 2G Pad 2G-13-2G-13A-2G-13A Out of range 2G-13-2G-13AL1-2G-13AL1 Out of range 2G-14-2G-14-2G-14 8,474.98 8,475.00 0.49 2.90 -2.24 FAIL-Major Risk 2G-14-2G-14AL1-2G-14AL1_wp03 9,174.97 9,175.00 0.84 0.46 0.50 Pass-Minor 1/10 CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 3/10/2015 11:46:43AM Page 2 of 5 COMPASS 5000.1 Build 65 • C O r 10. o en en 17? 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Development /Service Exploratory Stratigraphic Test Non-Conventional FIELD: 2POOL: LA3c�✓`c C � ,U JJ Check Box for Appropriate Letter/ Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing well Permit (If last two digits No. , API No. 50- - - - in API number are Production should continue to be reported as a function of the original between 60-69) API number stated above. In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name Pilot Hole ( PH) and API number (50- - - - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce / inject is contingent upon issuance of a Spacing Exception conservation order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are Well Lo in also required for this well: gg g Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 4/2014 El n N 0) d N N 0 E c 3 , To m a m , o o -o 0 . o. W t: , Qo' : a): w a EO 2. 0: o o_ : 2 d U: rn ma) co, o �, 3 • m ' o ar c �: o m c j 3. w : u. I— 0 U •;. O: �: N, I. p, u-, a)akii YcTr�� n N p' , ma da — a y, c •o a; ; Qm — m c m E 3coon � w a O) Y O Z. ' N G? D c To to 7, N. O. — d, c: o : ami c as 3 •6 y 0 3: 3 3 m Z, , m D _ C tq U) ._ a)' � , E. E, �' Y o a) m ac C. o, .N 0 o m, N, 3, , 3 N o (0 �: Y C: a: •3, �� 3' U), U): N: : C' O' M • O �.ca cva 3. O U' �' ~� a). 0 c ' n' U: 0 o': Y 3' o cm) c0 a m' 4 a��i �' �: Z O, N: �: M O. 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