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216-026
Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Tuesday, June 12, 2018 1:53 PM To: Phillips, Ron L; 'Starck, Kai' Cc: Loepp, Victoria T (DOA); Davies, Stephen F (DOA) Subject: 216-026 KRU 2K-25 L1-02 and 216-079 KRU 1L-24A L1-01: Permits Expired Hello Ron and Kai, On February 17, 2018, the permit for KRU 2K-25 L1-02 expired under Regulation 20 AAC 25.005 (g). On June 9, 2018, the permit for KRU 1L-24A L1-01 expired under Regulation 20 AAC 25.005 (g). The PTDs will be marked expired in the AOGCC database. If you have any questions, please contact me. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.aov. ,STD a d (,- 0 z�. Loepp, Victoria T (DOA) From: Phillips, Ron L <Ron.L.Phillips@conocophillips.com> Sent: Monday, March 28, 2016 9:42 AM To: Loepp, Victoria T (DOA) Cc: Eller, J Gary Subject: 2K-25 laterals drilled Attachments: 2K-25 updated proposed CTD Schematic.pdf, 2K-25 final CTD schematic.pdf Follow Up Flag: Follow up Flag Status: Flagged Good morning Victoria, The well 2K-25 was planned for 3 laterals and after drilling 2 laterals the reservoir pressure was slowly creeping up to 13.2 ppg, which is getting too high for the Formate completion fluid we use. The decision was made to rig down and move off after running the liner for the second lateral. The third lateral 2K-25L1-02 (PTD 216-026) was not drilled or completed. The plan is to produce this well until pressures come down to a manageable level, than come back and drill the third lateral. Attached is the proposed schematic and the final schematic. Please let me know if you have any questions. Thanks, Ron L. Phillips Senior CTD Engineer ConocoPhillips Alaska Phone 265-6312 Cell 317-5092 2K-25 Final CTD Schematic 16", 82.5#, H-40 at 115' MD a5/8", 36#, J55 t 4082' MD _ IL31,V' 9.3# L-80 EUE 8rd-Mod tubing to surface 3'R Camco gas lift mandrel @ 3315', 5299', 6718', 7474' RKB 3Yz" X-nipple @ 7535' RKB (2.813" min ID) 3'W' 9.3# L-80 Mule Shoe @ 7620' RKB Baker ZXP packer @ 7571' RKB Baker Flexloc k liner hanger at 759Y RKB Baker SBE @ 7600' RKB 411." scab liner cemented in place. '• Three KO joints 9825', 9867' & 9909' PDC for CTD exits " No centralizers on these 3 kickout joints. All other 4'/x" _ _ C-sand perfs (sgz'a) 9778'-9792' MD A -sand perfs (sqz'd) 9860'-9880' MD 9912'-9948' MD -sand reperf post-RWO 9860' - 9880' 9918' - 9938' MD �21K-251-1-01, TD=13,485' MD, PBTD=13,270' MD 2%" slotted liner with top at 9,915' MD K-25L1, TD = 13,375 MD, PBTD = 13,33T MD 7", 26#, J-55 at 2i4" slotted liner with billet at 10,230' MD 10,230' MD 2K-25 Updated Proposed CTD Schematic 18", 62.5#, H0 at 115' MD 9-5/8', 36#, J55 at 4082' MD C-sand perfs (sqz d) 9778'-9792' MD A -sand perfs (sgz'd) 9860'-9880' MD 9912'-9948' MD sand reperf post-RWO 9860' - 9880' 9918' - 9938' 2K-25L1-02, Planned TD = 11,809 MD 2%" slotted liner with top at 9,864' MD 7", 28#, J-55 at 10,230' MD 9.3# L-80 EUE 8rd-Mod tubing to surface Carrico gas lift mandrel @ 3316, 5299', 6718', 7474' RKB a @ 7535' RKB min ID) 9.3# L-80 Mule Shoe @ 7620' RKB er ZXP packer @ 7571' RKB Baker Flexloc k liner hanger at 7590' RKB er SBE @ 76W RKB %" scab liner cemented in place. •" Three KO joints 9820' - 9946' RKB (9825', 9867' & 9909' 'DC) for CTD exits " E-line not needed to log in place, but instead use existing jewelry to correlate depth " No centralizers on these 3 kickout joints. All other 41/5" joints are centralized. " " Landing collar @ 10065' MD " Proposed CTD KOP @ 9,869' MD Proposed CTD KOP @ 9,929 MD 2K-25L1-01, Planned TD = 13,400' MD 2%" slotted liner with top at 9,916 MD K-25L1, Planned TD = 13,400 MD I/V slotted liner with billet at 10,127 MD pTD -2/4- —bZC Loepp, Victoria T (DOA) From: Phillips, Ron L <Ron.L.Phillips@conocophillips.com> Sent: Thursday, March 17, 2016 4:19 PM To: Loepp, Victoria T (DOA) Cc: Eller, J Gary Subject: 2K-25L1-02 change to KOP Attachments: 1L-13 original proposed CTD Schematic.pdf, 1L-13 updated proposed CTD Schematic.pdf Follow Up Flag: Follow up Flag Status: Flagged Good afternoon Victoria, The plan was for Nabors CDR2-AC to drill 3 laterals out of 2K-25 out of one window at 9920' MD. The first lateral would kick off the whipstock at 9920' MD and drill to a TD of 13,400' MD and the second lateral would kick off billet at 10,122' MD and drill to a TD of 13,400' MD. This has not changed, but the third lateral 2K-25L1-02 (PTD 216-026) will not kick off a billet as planned at 10,020'MD because there is no good sand for a junction. If we leave a junction in an unstable shale we predict we will lose the lateral, therefore we plan to bring the slotted liner back up into the casing 5' above the top of whipstock at 9915' MD. Then we plan to set a second whipstock at 9869' MD and mill another window to drill our third lateral 2K-25L1-02. We are only moving the kick off point by 151'. Attached is the original proposed schematic and the updated version. Please let me know if you have any questions. Thanks, Ron L. Phillips Senior CTD Engineer ConocoPhillips Alaska Phone 265-6312 Cell 317-5092 2K-25 Updated Proposed CTD Schematic 9-5/8", 36#, J-55 at 4082' MD C-sand perfs (sq- 9778'-9792' MD A -sand penis (sgz'd) 9860'-9880' MD 9912'-9948' MD sand reperf post-RWO saso' - 986a 9918' - 9938' 2K-25L1-02, Planned TD = 11,800' MD 2%" slotted liner with top at 9,864' MD 10,230' MD 9.3# L-80 ELIE 8rd-Mod tubing to surface ' Camoo gas lift mandrel @ 3316, 5299', 6719, 7474' RKB ' X-nipple @ 7535' RKB (2.813" min ID) 9.3# L-80 Mule Shoe @ 7620' RKB er ZXP packer @ 7571' RKB Baker Flexlock liner hanger at 759U RKB or SBE @ 76W RKB %" scab liner cemented in place. "" Three KO joints 9820' - 9946' RKB (98251, 9867' & 9909' 'DC) for CTD exits E-line not needed to log in place, but instead use existing jewelry to correlate depth " No centralizers on these 3 kickoutjoints. All other 41/2" joints are centralized.'• " Landing collar @ 10065, MD " Proposed CTD KOP Q 9,869' MD Proposed CTD KOP @ 9,920' MD 2K-251-1-01, Planned TD = 13,409 MD 31V slotted liner with top at 9,915' MD 2K-25L1, Planned TD = 13,400 MD 2%" slotted liner with billet at 10,122' MD 2K-25 Original Proposed CTD Schematic r5/8", 36#, J55 at 4082' MD C-sand perfs (sqz'd) 9778'-9792' MD A -sand perfs (sqz'd) 9860'-9880' MD 9912'-9948' MD sand reperf post-RWO 9860' - 9880' 9918' - 9936 2K-25L1-02, Planned TD=11,800' MD 2%" slotted liner with top at 991V MD To. 26#, J-55 at 10,230' MD 9.3# L-80 EUE 8rd-Mod tubing to surface Camco gas lift mandrel @ 3315', 5299', 6718', 7474' RKB ' X-nipple @ 75W RKB (2.813" min ID) 9.3# L-80 Mule Shoe @ 7620' RKB er ZXP packer @ 7571' RKB Baker Flexlock liner hanger at 7599 RKB er SBE @ 76W RKB %" scab liner cemented in place. '" Three KO joints 9820' - 9946' RKB (9825', 9867' & 9909' 'DC) for CTD exits E-line not needed to log in place, but instead use existing jewelry to correlate depth " No centralizers on these 3 kickout joints. All other 4'/2" joints are centralized. `" " Landing collar @ 10065' MD " Proposed CTD KOP 9929 MD K-251-1-01, Planned TD=13,400' MD 31." slotted liner with billet at 10,020' MD K-25L1, Planned TD=13,400 MD %" slotted liner with billet at 10,122' MD THE STATE °fALASKA GOVERNOR BILL WALKER D. Venhaus CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2K-25L 1-02 ConocoPhillips Alaska, Inc. Permit to Drill Number: 216-026 Surface Location: 369' FNL, 95' FEL, SEC. 11, T10N, R8E, UM Bottomhole Location: 4815' FNL, 1086' FEL, SEC. 12, TION, R8E, UM Dear Mr. Venhaus: Enclosed is the approved application for permit to re -drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 190-012, API No. 50-103- 20124-00-00. Production should continue to be reported as a function of the original API number stated above. 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 . Foerster Chair DATED this / 7 � day of February, 2016. RECEIVED STATE OF ALASKA A. :A OIL AND GAS CONSERVATION COMN FEB 0 8 2016 PERMIT TO DRILL ON 7C-ASED 20 AAC 25.005 1 a. Typeof, W 1b. Proposed Well Class- Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill ❑ ''' ' 11❑✓ Stratigraphic Test ❑ Development - Oil Q Service - Winj ❑ Single Zone ❑✓ ' Coalbed Gas ❑ Gas Hydrates ❑ Redril ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name and Number: ConocoPhillips Alaska Inc, Bond No. 59-52-130 KRU 2K-25L1-02 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 11,800' TVD: 6,285' Kuparuk River Field i_ Kuparuk Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number):�) Surface: 369' FNL, 95' FEL, Sec. 11, T1ON, R8E, UM ADL 25605 Z S�ab Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 961' FNL, 1058' FEL, Sec. 13, T10N, R8E, UM 2679 2/20/2016 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4815' FNL, 1086' FEL, Sec. 12, T10N, R8E, UM 25 791' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 154, 15. Distance to Nearest Well Open Surface: x- 498310 y- 5,937,935 Zone- 4 GL Elevation above MSL (ft): 118 to Same Pool: 2K-24, 2505' 16. Deviated wells: Kickoff depth: 10,020' feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 1010 degrees Downhole: 4806 psig - Surface: 4170 psig , 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling I Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7* L-80 ST-L 1,885' 9,915' 6,319' 11,800, 6,285' 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): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 10,264 6539' none 10,230 6518 none Casing Length Size Cement Volume MD TVD Conductor/Structural 80' 16" 191 sx AS II 115' 115' Surface 4,047' 9-5/8" 1300 sx AS III & 450 sx Class G 4,082' 2,919' Production 10,197' 7" 300 sx G 10,224' 6,514' Scab liner 2,562' 4-1/2" 309 sx Class G 10,133' 6,45T Perforation Depth MD (ft): Planned pre -rig Perforation Depth TVD (ft): Planned pre -rig 9918'-9938', 9860'-9880' 6321'-6333', 6285'-6297' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Program ❑✓ Time v. Depth Plot ❑ Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date -J/,� O ZI 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not R. Phillips @265-6312 Contact be deviated from without prior written approval. Email ron.l.phillips(o)cop.com Printed Name D.Venhaus fj� j Gars v .;7i;�Y� Title CTD Engineering Supervisor Signature Phone 263-4372 Date Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: 50- — 0� — 6 _-00 Date: dl 1� requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: [� Other: 30P fitSf tc' +f6C7 pS1 S Samples req'd: Yes ❑ Nog Mud log req'd: Yes ❑ No [2' fj vz n v/ ei ✓ rG (/tvz 4 C ✓ fl$ Z 50 rU h 52S HZS measures: Yes [f No ❑ Directional svy req'd: Yes [2'No ❑ Spacing exception req'd: Yes ❑ No [Z Inclination -only svy req'd: Yes ❑ Noy Post initial injection MIT req'd: Yes ❑ No ❑ by: APPROVED BY Approved COMMISSIONER THE COMMISSION Date:Z•'l7 / v7-1_ a//.` /l a lim ;11101A, i " Submit Form and Form 10-401 (Revised 11/2015) 0TRT r/ fqp 2+ months from the date of approval (20 AAC 25.005(g)) Attachments in Duplicate ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, AL ASKA 99510-0360 February 5, 2016 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: RECEIVED FEB 0 8 2016 ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill a tri-lateral out of the KRU 2K-25 (190-012) using the coiled tubing drilling rig, Nabors CDR2-AC. The work is scheduled to begin February 20, 2016. The CTD objective will be to drill three laterals (2K-251-1, 2K-251-1-01 & 2K-25L1-02), targeting the Kuparuk A -sand intervals. Note the current A and C sand perforations were cemented behind a 4-1/2" scab liner during the RWO in January 2016 and the A sand perforations will be re -perforated to monitor the bottom hole pressure prior to CTD moving over this well to re -drill. Attached to this application are the following documents: — Permit to Drill Application Forms (10-401) for 2K-251-1, 2K-25L1-01 & 2K-251-1-02 — Detailed Summary of Operations — Directional Plans for 2K-251-1, 2K-251-1-01 & 2K-25L1-02 — Current wellbore schematic — Proposed wellbore schematic If you have any questions or require additional information please contact me at 907-265-6312. Sincerely, Ron Phillips Coiled Tubing Drilling Engineer Kuparuk CTD Laterals NABORr ASKA 2K-251-1, 2K-251-1-01 & 2K-251-1-02 CIJ9 Application for Permit to Drill Document 2RC 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(o 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............................................................................................................. 5 (Requirements of 20 AAC 25.005(c)(13)).. 5 Summaryof Operations...................................................................................................................................................5 LinerRunning...................................................................................................................................................................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....................................................................... 7 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 7 16. Attachments.................................................................................................................................... 7 Attachment 1: Directional Plans for 2K-25 laterals..........................................................................................................7 Attachment 2: Current Well Schematic for 2K-25............................................................................................................7 Attachment 3: Proposed Well Schematic for 2K-25 laterals............................................................................................7 Page 1 of 7 February 5, 2016 P`fD Application: 2K-_SL1, 2K-251_1-01 & 2K-25L1-02 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 2K-25L1, 2K-25L1-01 & 2K-25L1-02. All laterals will be classified as "Development -Oil' 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 attached 10-401 form for surface and subsurface coordinates of the 2K-25L1, 2K-25L1-01 & 2K-25L1-02. 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 to 4,400 psi. Using the maximum formation pressure in the area of 4,806 psi in 2K-24 (i.e. 14.5 ppg EMW), the maximum potential surface pressure in 2K-25, assuming a gas gradient of 0.1 psi/ft, would be 4,170 psi. See the "Drilling Hazards Information and Reservoir Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2,500 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)) The formation pressure in KRU 2K-25 was measured to be 4483 psi (14.2 ppg EMW) on 4/09/2011. Wells 2K- 23 and 2K-24 are shut-in and we are monitoring the pressure decline, targeting below 12.0 ppg EMW. From this we expect the formation pressure to be 12.0 ppg EMW while drilling. The maximum downhole pressure in the 2K-25 vicinity is to the west in the 2K-24 injector at 4,806 psi (14.5 ppg EMW) from Nov 2015. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) None of the offset injection wells to 2K-15 have ever injected gas, so there is a low probability of encountering free gas while drilling the 2K-15 laterals. Nevertheless, if significant gas is detected in the returns the contaminated mud can be diverted to a storage tank away from the rig. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) The major expected risk of hole problems in the 2K-25 laterals will be shale instability across faults. Managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossing. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 2K-25 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity test is not required. Page 2 of 7 February 5, 2016 PTD Application: 2K-_jL1, 2K-251_1-01 & 2K-25L1-02 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 2K-25L1 10,122' 13,400' 6,193' 6,240` 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 21K-251_1-01 10,020' 13,400' 6,206' 6,201' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 2K-25L1-02 9,915' 11,800' 6,165' 6,131' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top Existing Casing/Liner Information Category OD Weight (ppf) Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.5 H-40 Welded 0' 115' 0' 115' 1,640 670 Surface 9-5/8" 36 J-55 BTC 0' 4,082' 0' 2,918' 3,520 2,020 Production 7" 26.0 J-55 BTC 0' 10,224' 0' 6,514' 4,980 4,320 Tubing 3-1/2" 9.3 L-80 EUE 0 7,620' 0 4,909' 10,160 10,540 Scab liner 4-1/2" 11.6 L-80 BTC 7,571' 10,133' 4,881' 6,457' 7,780 6,350 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) 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 A diagram of the Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System — Window milling operations: Chloride -based FloVis mud (9.3 ppg) — Drilling operations: Chloride -based FloVis mud (9.3 ppg). While this mud weight will not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. — Completion operations: The well will be loaded with 12.2 ppg NaBr completion fluid in order to provide formation over -balance and well bore stability while running completions. Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000 psi rated coiled tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". In the 2K-25 laterals we will target a constant BHP of 12.2 ppg EMW at the window. The constant BHP target will be adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if increased reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed for improved borehole stability. 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. Page 3 of 7 February 5, 2016 PTD Application: 2K--iL1, 2K-251-1-01 & 2K-251-1-02 Pressure at the 2K-25 Window (9,920' MD, 6322' TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A -sand Formation Pressure (12 ppg) 3945 psi 3945 psi Mud Hydrostatic 9.3 pp) 3057 psi 3057 psi Annular friction (i.e. ECD, 0.080 psi/ft) 794 psi 0 psi Mud + ECD Combined (no choke pressure) 3851 psi (underbalanced -94 psi) 3189 psi (underbalanced - 888psi) Target BHP at Window 12.2 4011 psi 4011 psi Choke Pressure Required to Maintain Tar et BHP 160 psi 953 psi 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 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 for a land based 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. Page 4 of 7 February 5, 2016 PTD Application: 2K-_jL1, 2K-251_1-01 & 2K-25L1-02 13. Proposed Drilling Program (Requirements of 20 AA 25.005(c)(13)) Summary of Operations Background Well 2K-25 was originally drilled and completed in 1990 as an `A' and `C' sand, gas lifted producer in Kuparuk. In 2002, the well was converted to injection. In 2010, communication between the tubing and IA was reported and the well was suspended in 2011. A rig work -over was performed, cementing a 4-1/2" scab liner from 7,571' to 10,133' and replacing the existing tubing and packers with new 3 %2" tubing completion. Three laterals will be drilled two to the south and one to the north of the parent well with the laterals targeting the Kuparuk A4 and A5 sands. A thru-tubing whip -stock will be set pre -rig inside the 4'/2" scab liner at the planned kick off point of 9,920' MD. The 2K-25L1 lateral will exit through the 4'h" liner and 7" casing at 9,920'MD and TD at 13,400' MD, targeting the Kuparuk A4 sands to the south. It will be completed with 2%" slotted liner from TD up to 10,122' MD with an aluminum billet for kicking off the 2K-25L1-01 lateral. The 2K-25L1-01 will also drill south to a TD of 13,400' MD, but invert to target the A5 sands. It will be completed with 2%" slotted liner from TD up to 10,020' MD with an aluminum billet for kicking off the 2K-25L 1-02 lateral. The 2K-25L1-02 will drill north to a TD of 11,800' MD targeting the A4 and A5 sands. It will be completed with 2%" slotted liner from TD up to 9,915' MD with the liner top just inside the 4-1/2" liner 5' above the top of whipstock. Pre-CTD Work 1. Pull the BPV, re -perforate the Kuparuk A -sands and drift for a whipstock. 2. Set a whipstock, perform a SBHP test and set a BPV. 3. Prep site for Nabors CDR2-AC. Ria Work 1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 2K-25L1 Lateral (A4 sand south) a. Mill 2.80" window at 9,920' MD. b. Drill 3" bi-center lateral to TD of 13,400' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 10,122' MD. 3. 2K-25L1-01 Lateral (A5 sand south) a. Kick off of the aluminum billet at 10,122' MD. b. Drill 3" bi-center lateral to TD of 13,400' MD. c. Run 2%" slotted liner from TD up to 10,020' MD. 4. 2K-25L1-02 Lateral (A4/5 sands north) a. Kick off of the aluminum billet at 10,020' MD. b. Drill 3" bi-center lateral to TD of 11,800' MD. c. Run 2%" slotted liner from TD up to—9,915' MD, just above the whipstock 5. Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV. 2. Install GLV's . 3. Return to production. Page 5 of 7 February 5, 2016 PTD Application: 2K-_jL1, 2K-251-1-01 & 2K-25L1-02 Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. 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 slick -line lubricator can be used. 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 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 2K-25 laterals will be displaced to an overbalancing fluid (12.2 ppg NaBr) prior to running liner. See "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 23/" rams will provide secondary well control while running 23/" 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 1 B 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). Page 6 of 7 February 5, 2016 PTD Application: 2K--6L1, 2K-251-1-01 & 2K-251-1-02 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 (measured to KPA boundary at closest point) Lateral Name Distance 2K-251-1 1,015' 2K-25L1-01 1015' 2K-2511-1-02 791' - Distance to Nearest Well within Pool Lateral Name Distance Well 2K-25L1 2,529' 2K-24 2K-25L1-01 2,588' 2K-24 2K-251-1-02 2,505' 2K-24 16. Attachments Attachment 1: Directional Plans for 2K-25 laterals Attachment 2: Current Well Schematic for 2K-25 Attachment 3. Proposed Well Schematic for 2K-25 laterals Page 7 of 7 February 5, 2016 ConocoPhiflips NADConversion Kuparuk River Unit Kuparuk 2K Pad 2K-25 2K-25L1-02 Plan: 2K-25L1-02_wp03 Standard Planning Report 05 February, 2016 WE a I BAKER NUGHES �.- ConocoPhillips MAP.. ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska ANC Prod Company: NADConversion Project: Kuparuk River Unit Site: Kuparuk 2K Pad Well: 2K-25 Welibore: 2K-25 L1-02_wp03 Design: Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2K-25 Mean Sea Level 2K-25 @ 154.00usft (2K-25) True Minimum Curvature 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 2K Pad Site Position: Northing: 5,938,600.18 usft Latitude: 70° 14' 36.519 N From: Map Easting: 498,310.17usft Longitude: 150° 0' 49.133 W Position Uncertainty: - 0.00 usft Slot Radius: 0" Grid Convergence: 0.01 ° Well 2K-25 I Well Position +N/-S 0.00 usft Northing: 5,937,935.20 usft Latitude: 70° 14' 29.979 N +E/-W 0.00 usft Easting: 498,310.13 usft Longitude: 150° 0' 49.130 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 2K-251-1-02 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2015 4/1/2016 18.35 80.89 57,486 Design 2K-25L1-02_wp03 Audit Notes: Version: Phase: PLAN Tie On Depth: 10,020.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (I 0.00 0.00 0.00 0.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (°) (I (usft) (usft) (usft) ('1100usft) (°/100usft) (°/100usft) (°) Target 10,020+00 87.01 151.15 6,205.69-5,871.21 4,320.91 0.00 0.00 0.00 0.00 10,090.00 92.03 123.59 6,206.29-5,922.20 4,367.85 40.00 7.17 -39.37 280.00 10,290.00 98.23 43.41 6,184.84-5,902+24 4,549.65 40.00 3.10 -40.09 278.00 10,390.00 95.65 3.18 6,172.24-5,812.95 4,587.99 40.00 -2.57 -40.23 269.00 10,525.00 95.58 353.68 6,159.00-5,678.81 4,584.31 7.00 -0.06 -7.03 270.00 10,650.00 101.15 346.86 6,140.81-5,557.03 4,563+49 7.00 4.46 -5A6 310.00 10,775.00 96.06 339.66 6,122.09-5,438.80 4,527.88 7.00 -4.07 -5.76 235.00 10,975.00 91.15 352.81 6,109.46-5,245.41 4,480.57 7.00 -2.45 6.57 110.00 11,125.00 91.13 342.30 6,106.46-5,099.16 4,448.29 7.00 -0.01 -7.00 270.00 11,225.00 89.91 349.20 6,105.55-5,002.30 4,423.70 7.00 -1.22 6.89 100.00 11,350.00 86.93 340.97 6,109.00-4,881.68 4,391.57 7.00 -2.39 -6.58 250.00 11,550.00 85.81 354.95 6,121.72-4,686.97 4,350.02 7.00 -0.56 6.99 95.00 11,700.00 88.05 344.68 6,129.77-4,539.75 4,323.55 7.00 1.49 -6.85 282.00 11,800.00 90.45 338.10 6,131.07-4,445.05 4,291.66 7.00 2.40 -6.58 290.00 2/5/2016 10:45:58AM Page 2 COMPASS 5000.1 Build 74 - ConocoPhillips Hal Conoc4Phiiii(s Planning Report BAKER HUGHES Database: EDMAlaska ANC Prod Company: NADConversion Project: Kuparuk River Unit Site: Kuparuk 2K Pad Well: 2K-25 W e l l b o re: 2 K-25 L 1-02_wp 03 Design: Planned Survey Measured TVD Below Depth Inclination Azimuth System (usft) (°) (°) (usft) 10,020.00 87.01 151.15 6,205,69 TIP/KOP 10,090.00 92.03 123.59 6,206.29 2 10,100.00 92.58 119.63 6,205.89 10,200.00 97.01 79.72 6,197.18 10,290.00 98.23 43.41 6,184.84 3 10,300.00 98.14 39.37 10,390.00 95.65 3.18 End 40 dis, Start 7 dis 10,400.00 95.65 2.48 10,500.00 95.60 355.44 10,525.00 95.58 353.68 6 10,600.00 98.94 349.61 10,650.00 101.15 346.86 6 10,700.00 99.13 343.96 10,775.00 96.06 339.66 7 10,800.00 95.46 341.32 10,900.00 93.01 347.89 10,975.00 91.15 352.81 8 11,000.00 91.15 351.06 11,100.00 91.14 344.05 11,125.00 91.13 342.30 9 11,200.00 90.22 347.47 11,225.00 89.91 349.20 10 11,300.00 88.12 344.26 11,350.00 86.93 340.97 11 11,400.00 86.63 344.46 11,500.00 86.07 351.45 11,550.00 85.81 354.95 12 11,600.00 86.55 351.52 11,700.00 88.05 344.68 13 11,800.00 90.45 338.10 Planned TD at 11800.00 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2K-25 Mean Sea Level 2K-25 @ 154,00usft (2K-25) True Minimum Curvature Vertical Dogleg Toolface Map Map +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (usft) (usft) (°/100usft) (°) (usft) (usft) -5,871_21 4,320.91 -5,871.21 0 00 0.00 5,932,063.61 502,629.29 -5,922.20 4,367.85 -5,922.20 4000 -80.00 5,932,012.62 502,676.22 -5,927.43 4,376.36 -5,927.43 40.00 -82.00 5,932,007.38 502,684.72 -5,943.95 4,472.55 -5,943.95 40.00 -82.16 5,931,990.85 502,780.90 -5,902.24 4,549.65 -5,902.24 40.00 -85.64 5,932,032.53 502,858.00 6.183.42 -5,894.81 4,556.19 -5,894.81 40.00 -91.00 5,932,039.96 502,864.55 6,172.24 -5,812.95 4,587.99 -5,812.95 40.00 -91.58 5,932,121.80 502,896.35 6,171.26 -5,803.01 4,588.48 -5,803.01 7.00 -90.00 5,932,131.74 502,896.85 6,161.44 -5,703.57 4,586.67 -5,703.57 7.00 -90.07 5,932,231.17 502,895.06 6,159.00 -5,678.81 4,584.31 -5,678.81 7.00 -90.76 5,932,255.94 502,892.71 6,149.53 -5,605.22 4,573.52 -5,605.22 7.00 -50.00 5,932,329.52 502,881.94 6.140.81 -5,557.03 4,563.49 -5,557.03 7.00 -50.51 5,932,377.71 502,871.92 6,132.00 -5,509.40 4,551.09 -5,509.40 7.00 -125.00 5,932,425.33 502,859.53 6,122.09 -5,438.80 4,527.88 -5,438.80 7.00 -125.51 5,932,495.92 502,836.34 6,119.58 -5,415.36 4,519.58 -5,415.36 7.00 110.00 5,932,519.37 502,828.04 6,112.19 -5,319.27 4,493.12 -5,319.27 7.00 110.17 5,932,615.46 502,801.61 6.109.46 -5,245.41 4,480.57 -5,245.41 7.00 110.65 5,932,689.31 502,789.07 6,108.96 -5,220.66 4,477.06 -5,220.66 7.00 -90.00 5,932,714.06 502,785.57 6,106.96 -5,123.09 4,455.53 -5,123.09 7.00 -90.04 5.932,811.62 502,764.06 6,106.46 -5,099.16 4,448.29 -5,099.16 7.00 -90.18 5,932,835.55 502,756.84 6,105.58 -5,026.79 4,428.75 -5,026.79 7.00 100.00 5,932,907.92 502,737.31 6,105.55 -5,002.30 4,423.70 -5,002.30 7.00 100.06 5,932,932.40 502,732.26 6,106.84 -4,929.34 4,406.49 -4,929.34 7.00 -110.00 5,933,005.36 502,715.07 6,109.00 -4,881.68 4,391.57 -4,881.68 7.00 -109.92 5,933,053.02 502,700.16 6,111.81 -4,834.02 4,376.73 -4,834.02 7.00 95.00 5,933,100.68 502,685.34 6,118.18 -4,736.48 4,355.92 -4,736.48 7.00 94.80 5,933,198.21 502,664.55 6.121.72 -4,686.97 4,350.02 -4,686.97 7.00 94.36 5,933,247.73 502,658.66 6,125.05 -4,637.43 4,344.14 -4,637.43 7.00 -78.00 5,933,297.26 502,652.80 6,129.77 -4,539.75 4,323.55 -4,539.75 7.00 -77.77 5,933,394.93 502,632.23 6,131.07-4,445.05 4,291.66-4,445.05 7.00 -70.00 5,933,489.63 502,600.36 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 11,800.00 6,131.07 2 3/8" 2-3/8 3 2/5/2016 10:45:58AM Page 3 COMPASS 5000.1 Build 74 Vr, ConocoPhillips Hal ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska ANC Prod Local Co-ordinate Reference: Well 2K-25 Company: NADConversion TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2K-25 @ 154.00usft (2K-25) Site: Kuparuk 2K Pad North Reference: True Well: 2K-25 Survey Calculation Method: Minimum Curvature We II bo re: 2K-25 L1-02_wp03 Design: Plan Annotations Measured Vertical Local Coordinates Depth Depth +NI-S +EI-W (usft) (usft) (usft) (usft) Comment 10,020.00 6,205.69 -5,871.21 4,320.91 TIP/KOP 10,090.00 6,206.29 -5,922.20 4,367.85 2 10,290.00 6,184.84 -5,902.24 4,549.65 3 10,390.00 6,172.24 -5,812.95 4,587.99 End 40 dls, Start 7 dls 10,525.00 6,159.00 -5,678.81 4,584.31 5 10,650.00 6,140.81 -5,557.03 4,563.49 6 10,775.00 6,122.09 -5,438.80 4,527.88 7 10,975.00 6,109.46 -5,245.41 4,480.57 8 11,125.00 6,106.46 -5,099.16 4,448.29 9 11,225.00 6,105.55 -5,002.30 4,423.70 10 11,350.00 6,109.00 -4,881.68 4,391.57 11 11,550.00 6,121.72 -4,686.97 4,350.02 12 11,700.00 6,129.77 -4,539.75 4,323.55 13 11,800.00 6,131.07 -4,445.05 4,291.66 Planned TD at 11800.00 2/5/2016 10:45:58AM Page 4 COMPASS 5000.1 Build 74 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2K Pad 2K-25 2K-25L1-02 w p03 Travelling Cylinder Report 05 February, 2016 BAKER HUGHES Baker Hughes INTEQ rigs ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 2K Pad Site Error: 0 00 usft Reference Well: 2K-25 Well Error: 0,00 usft Reference Welibore 21K-251-1-02 Reference Design: 2K-25L1-02_wp03 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 2K-25 2K-25 @ 154.00usft (2K-25) 2K-25 @ 154.00usft (2K-25) True Minimum Curvature 1.00 sigma OAKEDMP2 Offset Datum teference 2K-25L1-02_wp03 alter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference nterpolation Method: MD Interval 25.00usft Error Model: ISCWSA )epth Range: 10,020.00 to 11,800.00usft Scan Method: Tray. Cylinder North tesults Limited by: Maximum center -center distance of 1,364.60 usft Error Surface: Elliptical Conic Survey Tool Program Date 1/4/2016 From To (usft) (usft) Survey (Welibore) Tool Name Description 200.00 9,900.00 2K-25 (2K-25) Copy of GYD-CT-CMS Gyrodata cont.casing m/s 9,900.00 10,020.00 2K-25L1_wp04(2K-251-1) MWD MWD- Standard 10,020.00 11,800.00 2K-25L1-02_wp03 MWD MWD- Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 11,800.00 6,285.07 2 3/8" 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 2K Pad 2K-22 - 2K-22AL1 - 2K-22AL1 Out of range 2K-23 - 2K-23 - 2K-23 Out of range 2K-24 - 2K-24 - 2K-24 Out of range 2K-25 - 2K-25 - 2K-25 10,031.56 10,050.00 44.17 5.64 39.36 Pass - Major Risk 2K-25 - 2K-251-1 - 2K-25L1_wp04 10,025.00 10,025.00 0.11 0.41 -0.18 FAIL - Minor 1/10 2K-25 - 2K-2511-01 - 10,025.00 10,025.00 0.11 0.41 -0.18 FAIL - Minor 1/10 2K-251-1-01 w 02 Offset Design Kuparuk 2K Pad - 2K-25 - 2K-25 - 2K-25 offset site Error: 0.00 usft Survey Program: 200-Copy of GYD-CT-CMS Rule Assigned: Major Risk Offset Well Error: 0.00 usft Reference Offset Semi Major Axis Measured Vertical Measured Vertical Reference Offset Toolface+ Offset Wellbore Centre Casing- Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/S +E/-W Hole Size Centre Distance Deviation (usft) (usft) (usft) (usft) (usft) (usft) (°) (usft) (usft) (") (usft) (usft) (usft) 10,031.56 6,360.21 10,050.00 6,404.34 0.12 Us -34,57 -5,880.18 4,325.21 2-11/16 44.17 5.64 39.36 Pass - Major Risk, CC, ES, SF 10,049.48 6,360.69 10,075.00 6,420.21 0.12 1.00 -44.66 -5,897.53 4,333.70 2-11/16 59.69 6.48 54A7 Pass - Major Risk 10,065.67 6,360.78 10,100.00 6,436.06 0,12 1A4 -54sl -5,915,06 4,341_85 2-11/16 76.02 7.27 70.35 Pass - Major Risk 10,080.00 6,360.58 10,125.00 6,451,86 0.13 1.29 -64.25 -5,932.75 4,349,76 2-11/16 93.27 7.93 87.12 Pass - Major Risk 10,092,53 6,360.20 10,150,00 6,467.59 0.13 1.43 -72.72 -5,950.56 4,357.54 2-11/16 111A2 8,48 104.83 Pass - Major Risk 10,103.62 6,359,72 10,175.00 6,483.31 0.14 1.57 -80.25 -5,968.38 4,365.30 2-11/16 130,43 8.96 123.42 Pass - Major Risk 10,113.25 6,359,21 10,200,00 6,499.03 0.15 1,72 -86.82 -5,986.20 4,373,06 2-11/16 150,20 9.36 142,83 Pass - Major Risk 10,120.00 6,358.80 10,225.00 6,514,75 0,15 1,86 -91.85 -6,004.03 4,380,82 2-11/16 170.64 9,67 162,96 Pass - Major Risk 10,130.00 6,358.12 10,250.00 6,530,47 0.16 2.01 -98,00 -6,021.85 4,388.58 2-11/16 191.63 9,95 183.66 Pass - Major Risk 10,132.61 6,357.93 10,264,00 6,539,27 0.16 2.09 -100.06 -6,031.83 4,392.93 2-11/16 203.61 10.08 195.50 Pass - Major Risk 10,813.00 6,272,38 9,550,00 6,092.75 0.63 0.00 -84,49 -5,546,42 4,122.58 2-11/16 455.21 13,14 444.36 Pass - Major Risk 10,825.42 6,271.30 9,525.00 6,077,03 0,64 0.00 -82.35 -5,531.24 4,110.44 2-11/16 467.38 13,30 456.41 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 2/5/2016 3:59:54PM Page 2 COMPASS 5000.1 Build 74 a e o o w� v o n pX o N O � � o A Y o x Y - v N •- v O r v N V CD 0 x cU� .- T�l � N f F FO N e ^ O Z> Z. o m mCo�c' b 00 v V y o GJ O h O N N N N Q+ � O � C p b V1 - h O V NO O O N J U Y N N N y p (n N J M O 0 I M '^ O F O Lu p n O ' Ob Ob Ob ON O. 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Type of Work: Drill ❑ Lateral ❑✓ 1 b. Proposed Well ClassExploratory - Gas ❑ Stratigraphic Test ❑ Development - Oil ❑✓ Service - WAG ❑ Service - Disp ❑ Service - Winj ❑ Single Zone ❑Q 1 c. Specify if well is g oposed for: Coalbed Gas ❑ as Hydrates ❑ Redril ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name,/and Number: ConocoPhillips Alaska Inc Bond No. 59-52-18D VfRU 2K-25AL2 3. Address: 6. Proposed Depth: ol(s): 12. Field/7Kuparuk P.O. Box 100360 Anchorage, AK 99510-0360 MD: 11,800' TVD: 6,285' River Field Kuparuk Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 369' FNL, 95' FEL, Sec. 11, T10N, R8E, UM ADL 25605 Top of Productive Horizon: 8. Land Use Permit: 1 . Approximate Spud Date: 961' FNL, 1058' FEL, Sec. 13, T1 ON, R8E, UM 2679 2/20/2016 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4815' FNL, 1086' FEL, Sec. 12, T1 ON, R8E, UM 2560 791' 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 498310 y- 5,937,935 Zone- 4 10. KB Elevation above MSL (ft): 154' GL Elevation above MSL (ft): 1 (8 15. Distance to Nearest Well Open to Same Pool: 2K-24, 2505' 16. Deviated wells: Kickoff depth: 10,020' feet 17. Maximum Potential Pressures in psig,("see 20 AAC 25.035) Maximum Hole Angle: 101, degrees Downhole: 4806 psig S rface: 4170 psig 18. Casing Program: Specifications Top - Setting Depth - Bo om 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 1,885' 9,915' 6,319' 1 U 6,285' slotted liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill perations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Dep MD (ft): Effect. Depth TVD (ft): Junk (measured): 10,264 6539' none 10 30 6518 none Casing Length Size e t Volume MD TVD Conductor/Structural 80' 16" 191 sx A 115' 115' Surface 4,047' 9-5/8" 1300 s II & 450 sx Class G 4,082' 2,919' Production 10,197' 7" 300 10,224' 6,514' Scab liner 2,562' 4-1/2" 30 lass G 1 10,133' 6,457' Perforation Depth MD (ft): Planned pre -rig ration Depth TVD (ft): Planned pre -rig 9918'-9938', 9860'-9880' 6321'-6333', 6285'-6297' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Dri g Program ❑✓ Time v. Depth Plot ❑ Shallow Hazard Analysis❑ Diverter Sketch ❑ eabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure appr ed herein will not R. Phillips @265-6312 be deviated from without prior written approval. Contact Email ron.l.phillips(aDcop.com Printed Name D.Venhaus Title CTD Engineering Supervisor Signatu A&" E i) Phone 263-4372 Date Z Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: 50- Date: requirements. Conditions of approval : If box is checke , well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: ❑ Other: Samples req'd: Yes ❑ No ❑ Mud log req'd: Yes ❑ No ❑ H2S measures: Yes ❑ No ❑ Directional svy req'd: Yes ❑ No ❑ Spacing exception req'd: Yes ❑ No ❑ Inclination -only svy req'd: Yes ❑ No ❑ Post initial injection MIT req'd: Yes ❑ No ❑ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: n n f6h[ NAPLov-1 Submit Form and Form 10-401 (Revised 11/2015) This permit is valid for 2 (20 AAC 25.005(g)) Attachments in Duplicate ConocoPp hilli s Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 2, 2016 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 tri-lateral out of the KRU 2K-25 (190-012) using the coiled tubing drilling rig, Nabors CDR2-AC. The work is scheduled to begin February 20, 2016. The CTD objective will be to drill three laterals (2K-25A, 2K-25AL1 & 2K-25AL2), targeting the Kuparuk A -sand intervals. Note the current A and C sand perforations were cemented behind a 4-1/2" scab liner during the RWO in January 2016 and the A sand perforations will be re -perforated to monitor the bottom hole pressure prior to CTD moving over this well to re -drill. Attached to this application are the following documents: — Permit to Drill Application Forms (10-401) for 2K-25A, 2K-25AL1 & 2K-25AL2 — Detailed Summary of Operations — Directional Plans for 2K-25A, 2K-25AL1 & 2K-25AL2 — Current wellbore schematic — Proposed wellbore schematic If you have any questions or require additional information please contact me at 907-265-6312. Sincerely, e '?. P" & Z- Ron Phillips Coiled Tubing Drilling Engineer Kuparuk CTD Laterals NA80B'� KA 2K-2 A, 2K-2 ALI 2K-25AL2 CD9, Application for Permit to Drill Document 2RC 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............................................................................................................. 5 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 5 Summaryof Operations...................................................................................................................................................5 LinerRunning...................................................................................................................................................................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....................................................................... 7 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 7 16. Attachments....................................................................................................................................7 Attachment 1: Directional Plans for 2K-25A laterals........................................................................................................7 Attachment 2: Current Well Schematic for 2K-25............................................................................................................7 Attachment 3: Proposed Well Schematic for 2K-25A laterals..........................................................................................7 Page 1 of 7 February 2, 2016 PTD Application: 2K-25A, 2K-25AL1 & 2K-25AL2 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 2K-25A, 2K-25AL1 & 2K-25AL2. All laterals will be classified as "Development -Oil' 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 attached 10-401 form for surface and subsurface coordinates of the 2K-25A, 2K-25AL1 & 2K-25AL2. 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 to 4,400 psi. Using the maximum formation pressure in the area of 4,806 psi in 2K-24 (i.e. 14.5 ppg EMW), the maximum potential surface pressure in 2K-25, assuming a gas gradient of 0.1 psi/ft, would be 4,170 psi. See the "Drilling Hazards Information and Reservoir Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2,500 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)) The formation pressure in KRU 2K-25 was measured to be 4483 psi (14.2 ppg EMW) on 4/09/2011. Wells 2K- 23 and 2K-24 are shut-in and we are monitoring the pressure decline, targeting below 12.0 ppg EMW. From this we expect the formation pressure to be 12.0 ppg EMW while drilling. The maximum downhole pressure in the 2K-25 vicinity is to the west in the 2K-24 injector at 4,806 psi (14.5 ppg EMW) from Nov 2015. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) None of the offset injection wells to 2K-15 have ever injected gas, so there is a low probability of encountering free gas while drilling the 2K-15 laterals. Nevertheless, if significant gas is detected in the returns the contaminated mud can be diverted to a storage tank away from the rig. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) The major expected risk of hole problems in the 2K-25 laterals will be shale instability across faults. Managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossing. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 2K-25 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity test is not required. Page 2 of 7 February 2, 2016 PTD Application: 2K-25A, 2K-25AL1 & 2K-25AL2 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 2K-25A 10,122' 13,400' 6,193' 6,240` 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 2K-25AL1 10,020' 13,400' 6,206' 6,201' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 2K-25AL2 9,915' 11,800' 6,165' 6,131' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top Existing Casing/Liner Information Category OD Weight (ppf) Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.5 H-40 Welded 0' 115' 0' 115' 1,640 670 Surface 9-5/8" 36 J-55 BTC 0' 4,082' 0' 2,918' 3,520 2,020 Production 7" 26.0 J-55 BTC 0' 10,224' 0' 6,514' 4,980 4,320 Tubing 3-1/2" 9.3 L-80 EUE 0 7,620' 0 4,909' 10,160 10,540 Scab liner 4-1/2" 11.6 L-80 BTC 7,571' 10,133' 4,881' 6,457' 7,780 6,350 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) 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 A diagram of the Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System — Window milling operations: Chloride -based FloVis mud (9.3 ppg) — Drilling operations: Chloride -based FloVis mud (9.3 ppg). While this mud weight will not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. — Completion operations: The well will be loaded with 12.2 ppg NaBr completion fluid in order to provide formation over -balance and well bore stability while running completions. Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000 psi rated coiled tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". In the 2K-25 laterals we will target a constant BHP of 12.2 ppg EMW at the window. The constant BHP target will be adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if increased reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed for improved borehole stability. 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. Page 3 of 7 February 2, 2016 PTD Application: 2K-25A, 2K-25AL1 & 2K-25AL2 Pressure at the 2K-25 Window (9,920' MD, 6322' TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A -sand Formation Pressure (12 ppg) 3945 psi 3945 psi Mud Hydrostatic (9.3 ppg) 3057 psi 3057 psi Annular friction (i.e. ECD, 0.080 psi/ft) 794 psi 0 psi Mud + ECD Combined 3851 psi 3189 psi (no choke pressure) (underbalanced —94 (underbalanced psi) - 888psi) Target BHP at Window 12.2 4011 psi 4011 psi Choke Pressure Required to Maintain 160 psi 953 psi Target BHP 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 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 for a land based 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. Page 4 of 7 February 2, 2016 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well 2K-25 was originally drilled and completed in 1990 as an `A' and `C' sand, gas lifted producer in Kuparuk. In 2002, the well was converted to injection. In 2010, communication between the tubing and IA was reported and the well was suspended in 2011. A rig work -over was performed, cementing a 4-1/2" scab liner from 7,571' to 10,133' and replacing the existing tubing and packers with new 3'/z" tubing completion. Three laterals will be drilled two to the south and one to the north of the parent well with the laterals targeting the Kuparuk A4 and A5 sands. A thru-tubing whip -stock will be set pre -rig inside the 4'/2" scab liner at the planned kick off point of 9,920' MD. The 2K-25A sidetrack will exit through the 4'/2" liner and 7" casing at 9,920'MD and TD at 13,400' MD, targeting the Kuparuk A4 sands to the south. It will be completed with 2%" slotted liner from TD up to 10,122' MD with an aluminum billet for kicking off the 2K-25AL 1 lateral. The 2K-25AL1 will also drill south to a TD of 13,400' MD, but invert to target the A5 sands. It will be completed with 2%" slotted liner from TD up to 10,020' MD with an aluminum billet for kicking off the 2K-25AL2 lateral. The 2K-25AL2 will drill north to a TD of 11,800' MD targeting the A4 and A5 sands. It will be completed with 2%" slotted liner from TD up to 9,915' MD with the liner top just inside the 4-1/2" liner 5' above the top of whipstock. Pre-CTD Work 1. Pull the BPV, re -perforate the Kuparuk A -sands and drift for a whipstock. 2. Set a whipstock, perform a SBHP test and set a BPV. 3. Prep site for Nabors CDR2-AC. Ri1Z Work 1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 2K-25A sidetrack (A4 sand south) a. Mill 2.80" window at 9,920' MD. b. Drill 3" bi-center lateral to TD of 13,400' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 10,122' MD. 3. 2K-25AL1 Lateral (A5 sand south) a. Kickoff of the aluminum billet at 10,122' MD. b. Drill 3" bi-center lateral to TD of 13,400' MD. c. Run 2%" slotted liner from TD up to 10,020' MD. 4. 2K-25AL2 Lateral (A4/5 sands north) a. Kick off of the aluminum billet at 10,020' MD. b. Drill 3" bi-center lateral to TD of 11,800' MD. c. Run 2%" slotted liner from TD up to—9,915' MD, just above the whipstock 5. Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV. 2. Install GLV's . 3. Return to production. Page 5 of 7 February 2, 2016 PTD Application: 2K-25A, 2K-25AL1 & 2K-25AL2 Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. 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 slick -line lubricator can be used. 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 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 2K-25 laterals will be displaced to an overbalancing fluid (12.2 ppg NaBr) prior to running liner. See "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 23/" 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 (1 R-18 or 1 B 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). Page 6 of 7 February 2, 2016 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 (measured to KPA boundary at closest point) Lateral Name Distance 2K-25A 1,015' 2K-25AL1 1015' 2K-25AL2 791' — Distance to Nearest Well within Pool Lateral Name Distance Well 2K-25A 2,529' 2K-24 2K-25AL1 2,588' 2K-24 2K-25AL2 2,505' 2K-24 16. Attachments Attachment 1: Directional Plans for 2K-25A laterals Attachment 2: Current Well Schematic for 2K-25 Attachment 3. Proposed Well Schematic for 2K-25A laterals Page 7 of 7 February 2, 2016 W lmm we m � o p p mooa 0 I E - O - N� � O LL v d�.vs � zZZd= p cr o p C ut Y � r b O LLJ w > N 0 in F N _ v J W 0190 y. � _ I.. .1 � r C 71 IG O h O M •C a O _ M IC tC N 1 C. 7 7YY" Y YNNo CL r�j 4 -ILI N r O m a 3Y h O CL : -.�- N- O O.. Oo 0 0 o p o o o o op o op o 0 0 0 0 o 0 0 0 0 o 0 r N O U (ui/-Usn OSZ) (+)uljoN/(-)u;noS N Conoco`Phillips NADConversion Kuparuk River Unit Kuparuk 2K Pad 2K-25 2K-25AL2 Plan: 2K-25AL2_wp03 Standard Planning Report 05 January, 2016 FA Ed P& I BAKER HUGNES ConocoPhillips Database: EDM Alaska ANC Prod Company: NADConversion Project: Kuparuk River Unit Site: Kuparuk 2K Pad Well: 2K-25 Wellbore: 2K-25AL2 Design: 2 K-25AL2_wp03 ConocoPhillips Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2K-25 Mean Sea Level 2K-25 @ 154 00usft (2K-25) True Minimum Curvature 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 WEho BAKER HUGHES Site Kuparuk 2K Pad Site Position: Northing: 5,938,600.18 usft Latitude: 70° 14' 36.519 N From: Map Easting: 498,310.17 usft Longitude: 150° 0' 49.133 W Position Uncertainty: - 0.00 usft Slot Radius: 0" Grid Convergence: -0.01 ° --- j Well 2K-25 Well Position +N/-S 0.00 usft Northing: 5,937,935.20 usft Latitude: 70° 14' 29.979 N +E/-W 0.00 usft Easting: 498,310.13 usft Longitude: 150° 0' 49.130 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 2K-25AL2 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2015 4/1/2016 18.35 80.89 57,486 Design 2K-25AL2_wp03 Audit Notes: Version: Phase: PLAN Tie On Depth: 10,020.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (I 0.00 0.00 0.00 0.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (°) (I (usft) (usft) (usft) (°/100usft) (°/1o0usft) (°/100usft) (°) Target 10,020.00 87.01 151.15 6,205.69-5,871.21 4,320.91 0.00 0.00 0.00 0.00 10,090.00 92.03 123.59 6,206.29-5,922.20 4,367.85 40.00 7.17 -39.37 280.00 10,290.00 98.23 43.41 6,184.84-5,902.24 4,549.65 40.00 3.10 -40.09 278.00 10,390.00 95.65 3.18 6,172.24-5,812+95 4,587.99 40.00 -2.57 -40.23 269.00 10,525.00 95.58 353.68 6,159.00-5,678.81 4,584.31 7.00 -0.06 -7.03 270.00 10,650.00 101.15 346.86 6,140.81-5,557.03 4,563.49 7.00 4.46 -5.46 310.00 10,775.00 96.06 339.66 6,122.09-5,438.80 4,527.88 7.00 -4.07 -5.76 235.00 10,975.00 91.15 352.81 6,109.46-5,245.41 4,480+57 7.00 -2.45 6.57 110.00 11,125+00 91.13 342.30 6,106.46-5,099.16 4,448.29 7.00 -0.01 -7.00 270.00 11,225.00 89.91 349.20 6,105.55-5,002.30 4,423.70 7.00 -1.22 6.89 100.00 11,350.00 86.93 340.97 6,109.00-4,881.68 4,391.57 7.00 -2.39 -6.58 250.00 11,550.00 85.81 354.95 6,121+72-4,686.97 4,350.02 7.00 -0.56 6.99 95.00 11,700.00 88.05 344.68 6,129.77-4,539.75 4,323.55 7.00 1.49 -6.85 282.00 11,800+00 90.45 338.10 6,131.07-4,445.05 4,291.66 7.00 2.40 -6.58 290.00 11512016 10:45:58AM Page 2 COMPASS 5000.1 Build 74 I „= ConocoPhillips ,A.. ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska ANC Prod Local Co-ordinate Reference: Well 2K-25 Company: NADConversion TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2K-25 @ 154.00usft (2K-25) Site: Kuparuk 2K Pad North Reference: True Well: 2K-25 Survey Calculation Method: Minimum Curvature Wellbore: 2K-25AL2 Design: 2 K-25A L 2_w p 03 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (a) (1) (usft) (usft) (usft) (usft) (°/100usft) V) (usft) (usft) 10,020.00 87.01 151.15 6,205.69 -5,871.21 4.320.91 -5,871.21 0.00 0.00 5,932,063.61 502,629.29 TIP/KOP 10,090.00 92.03 123.59 6,206.29 -5,922.20 4,367.85 -5,922.20 40.00 -80.00 5,932,012.62 502,676.22 2 10.100.00 92.58 119.63 6,205.89 -5,927.43 4,376.36 -5,927.43 40.00 -82.00 5,932,007.38 502,684.72 10,200.00 97.01 79.72 6,197.18 -5,943.95 4,472.55 -5,943.95 40.00 -82.16 5,931,990.85 502,780.90 10,290.00 98.23 43.41 6,184.84 -5,902.24 4,549.65 -5.902.24 40.00 -85.64 5,932,032.53 502,858.00 3 10,300.00 98.14 39.37 6,183.42 -5,894.81 4,556.19 -5,894.81 40.00 -91.00 5,932,039.96 502,864.55 10,390.00 95.65 3.18 6,172.24 -5,812.95 4,587.99 -5,812.95 40.00 -91.58 5,932,121.80 502,896.35 End 40 dls, Start 7 dls 10,400.00 95.65 2.48 6,171.26 -5,803.01 4,588.48 -5,803.01 7.00 -90.00 5,932,131.74 502,896.85 10,500.00 95.60 355.44 6,161,44 -5,703.57 4,586.67 -5,703.57 7.00 -90.07 5,932,231.17 502,895.06 10,525.00 95.58 353.68 6,159.00 -5,678.81 4,584.31 -5,678.81 7.00 -90.76 5,932,255.94 502,892.71 6 10,600.00 98.94 349.61 6,149.53 -5,605.22 4,573.52 -5,605.22 7.00 -50.00 5,932,329.52 502,881.94 10,650.00 101.15 346.86 6,140.81 -5,557.03 4,563.49 -5,557.03 7.00 -50.51 5,932,377.71 502.871.92 6 10,700.00 99.13 343.96 6,132.00 -5,509.40 4,551.09 -5,509.40 7.00 -125.00 5,932,425.33 502,859.53 10,775.00 96.06 339.66 6,122.09 -5,438.80 4,527.88 -5,438.80 7.00 -125.51 5,932,495.92 502,836.34 7 10,800.00 95.46 341.32 6,119.58 -5,415.36 4,519.58 -5,415.36 7.00 110.00 5,932,519.37 502,828.04 10,900.00 93.01 347.89 6,112.19 -5,319.27 4,493.12 -5,319.27 7.00 110.17 5,932,615.46 502,801.61 10,975.00 91.15 352.81 6,109.46 -5,245.41 4,480.57 -5,245.41 7.00 110.65 5,932,689,31 502,789.07 8 11,000.00 91.15 351.06 6,108.96 -5,220.66 4,477.06 -5,220.66 7.00 -90.00 5,932,714.06 502,785.57 11,100.00 91.14 344.05 6,106.96 -5,123.09 4,455.53 -5,123.09 7.00 -90.04 5,932,811.62 502,764.06 11.125.00 91.13 342.30 6,106.46 -5,099.16 4,448.29 -5,099.16 7.00 -90.18 5,932,835.55 502,756.84 9 11,200.00 90.22 347.47 6,105.58 -5,026.79 4,428.75 -5,026.79 7.00 100.00 5,932,907.92 502,737.31 11,225.00 89.91 349.20 6,105.55 -5,002.30 4,423.70 -5,002.30 7.00 100.06 5.932,932.40 502,732.26 10 11,300.00 88.12 344.26 6,106.84 -4,929.34 4,406.49 -4,929.34 7.00 -110.00 5.933,005.36 502,715.07 11,350.00 86.93 340.97 6,109.00 -4,881.68 4,391.57 -4,881.68 7.00 -109.92 5,933,053.02 502,700.16 11 11,400.00 86.63 344.46 6,111.81 -4,834.02 4,376.73 -4,834.02 7.00 95.00 5,933,100.68 502,685.34 11,500.00 86.07 351.45 6,118.18 -4,736.48 4,355.92 -4,736.48 7.00 94.80 5,933,198.21 502,664.55 11,550.00 85.81 354.95 6,121.72 -4,686.97 4,350.02 -4,686.97 7.00 94.36 5,933,247.73 502,658.66 12 11,600.00 86.55 351.52 6,125.05 -4,637.43 4,344.14 -4,637.43 7.00 -78.00 5,933,297.26 502.652.80 11,700.00 88.05 344.68 6,129.77 -4,539.75 4,323.55 -4,539.75 7.00 -77.77 5,933,394.93 502,632.23 13 11,800.00 9045 338.10 6,131.07 -4,445.05 4,291.66 -4,445.05 7.00 -70.00 5,933,489.63 502,600.36 Planned TD at 11800.00 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 11,800 00 6,131 07 2 3/8" 2-3/8 3 11512016 10.45:58AM Page 3 COMPASS 5000.1 Build 74 ,,- ConocoPhillips W�.. ConocoPhiiiip5 Planning Report BAKER HUGHES Database: EDM Alaska ANC Prod Company: NADConversion Project: Kuparuk River Unit Site: Kuparuk 2K Pad Well: 2K-25 Wellbore: 2K-25AL2 Design: 2 K-25AL2_wp03 Plan Annotations Measured Depth (usft) 10,020.00 10, 090.00 10, 290.00 10, 390.00 10, 525.00 10, 650.00 10, 775.00 10, 975.00 11,125.00 11,225.00 11, 350.00 11, 550.00 11,700.00 11,800.00 Vertical Depth (usft) 6,205.69 6,206.29 6,184.84 6,172.24 6,159.00 6,140.81 6,122.09 6,109.46 6,106.46 6,105.55 6,109.00 6,121.72 6,129.77 6,131.07 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Local Coordinates +N/-S +El-W (usft) (usft) -5, 871.21 4,320.91 -5,922.20 4,367.85 -5,902.24 4,549.65 -5,812.95 4,587.99 -5, 678.81 4, 584.31 -5,557.03 4,563.49 -5,438.80 4,527.88 -5, 245.41 4,480.57 -5,099.16 4,448.29 -5,00230 4,423.70 -4,881.68 4,391.57 -4,686.97 4,350.02 -4,539.75 4,323.55 -4,445.05 4,291.66 Comment TIP/KOP 2 3 End 40 dls, Start 7 dls 5 6 7 8 9 10 11 12 13 Planned TD at 11800.00 Well 2K-25 Mean Sea Level 2K-25 @ 154.00usft (2K-25) True Minimum Curvature 11512016 10:45:58AM Page 4 COMPASS 5000.1 Build 74 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2K Pad 2K-25 2K-25AL2 2K-25AL2_wp03 Travelling Cylinder Report 04 January, 2016 BAKER HUGHE5 `1 Baker Hughes INTEQ .IN.. ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 2K Pad Site Error: 0.00 usft Reference Well: 2K-25 Well Error: 0.00 usft Reference Wellbore 2K-25AL2 Reference Design: 2K-25AL2_wp03 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 2K-25 2K-25 @ 154.00usft (2K-25) 2K-25 @ 154.00usft (2K-25) True Minimum Curvature 1.00 sigma OAKEDMP2 Offset Datum Reference 2K-25AL2_wp03 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 10,020.00 to 11,800.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,364.60 usft Error Surface: Elliptical Conic Survey Tool Program Date 1/4/2016 From To (usft) (usft) Survey (Wellbore) Tool Name Description 200.00 9,900.00 2K-25 (2K-25) Copy of GYD-CT-CMS Gyrodata cont.casing m/s 9,900.00 10,020.00 2K-25A_wp04 (2K-25A) MWD MWD - Standard 10,020.00 11,800.00 2K-25AL2_wp03 (2K-25AL2) MWD MWD - Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 11,800.00 6,285.07 2 3/8" 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 2K Pad 2K-22 - 2K-22AL1 - 2K-22AL1 Out of range 2K-23 - 2K-23 - 2K-23 Out of range 2K-24 - 2K-24 - 2K-24 Out of range 2K-25 - 2K-25 - 2K-25 10,031.56 10,050.00 44.17 5.64 39.36 Pass - Major Risk 2K-25 - 2K-25A - 2K-25A_wp04 10,025.00 10,025.00 0.11 0.41 -0.18 FAIL - Minor 1/10 2K-25 - 2K-25AL1 - 2K-25AL1_wp02 10,025.00 10,025.00 0.11 0.41 -0.18 FAIL- Minor 1/10 Offset Design Kuparuk 2K Pad - 2K-25 - 2K-25 - 2K-25 offset Site Error: 0.00 use Survey Program: 200-Copy of GYD-CT-CMS Rule Assigned: Major Risk Offset Well Error: 0.00 usft Reference Offset Semi Major Axis Measured Vertical Measured Vertical Reference Offset Toolface + Offset Wellbore Centre Casing - Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/S +E/-W Hole Size Centre Distance Deviation (usft) (usft) (usft) (usft) (usft) (usft) (°) (usft) (usft) ("1 (usft) (usft) (usft) 10,031.56 6,360.21 10,050.00 6,404,34 0.12 0,86 -34.57 -5,880.18 4,325.21 2-11/16 44.17 5.64 39.36 Pass - Major Risk, CC, ES, SF 10,049.48 6,360.69 10,075.00 6,420.21 0.12 1,00 -44.66 -5,897.53 4,333.70 2-11/16 59.69 6,48 54.47 Pass - Major Risk 10,065.67 6,360.78 10,100.00 6,436.06 0.12 1,14 -54.81 -5,915.06 4,341.85 2-11/16 76.02 7,27 70.35 Pass - Major Risk 10,080.00 6,360.58 10,125,00 6,451.86 0,13 1.29 -64,25 -5,932.75 4,349.76 2-11/16 93.27 7.93 87.12 Pass - Major Risk 10,092.53 6,360.20 10,150,00 6,467,59 0.13 1.43 -72,72 -5,950,56 4, 357.54 2-11/16 111,42 8.48 104,83 Pass - Major Risk 10,103.62 6,359,72 10,175,00 6,483.31 0.14 1.57 -80.25 -5, 968.38 4,365.30 2-11/16 13043 8.96 123,42 Pass - Major Risk 10,113.25 6,359.21 10,200,00 6,499.03 0.15 1.72 -86.82 -5,98620 4,373,06 2-11/16 150,20 9.36 142,83 Pass - Major Risk 10,120.00 6,358.80 10,225.00 6,514.75 0.15 1.86 -91.85 -6,004.03 4,380,82 2-11/16 170.64 9.67 162,96 Pass - Major Risk 10,130.00 6,358,12 10,250.00 6,530.47 0,16 2.01 -98.00 -6,021,85 4,388.58 2-11/16 191,63 9.95 183,66 Pass - Major Risk 10,132,61 6,357.93 10,264.00 6,539,27 0.16 2.09 -100,06 -6,031,83 4,392.93 2-11/16 203,61 10.08 195.50 Pass - Major Risk 10,813.00 6,272.38 9,55000 6,092,75 0.63 0.00 -84.49 -5,546,42 4,122.58 2-11/16 455.21 13,14 444,36 Pass - Major Risk 10,82542 6,271,30 9,52500 6,077.03 0,64 0.00 -82.35 -5,531.24 4,110,44 2-11/16 467,38 13.30 456.41 Pass - Major Risk CC - Min Centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 11412016 3:59:54PM Page 2 COMPASS 5000.1 Build 74 I Y V I - p O O h - o Y w Q ti < p O i .. i F v O N p O C N v O N � O N N � X O O b O 7 O O O O O O O O O O O O O O O O O O (ui/Bsn+OSt) (+)u7-ioN/(-)T{1noS� N O O O m p 0 Ln 0 N O � O � W r c vi � -00 v c c a c ¢I-NMw�n<o�oorn���.-a ONNNOcOOOC M(Om�O d Z Cn�NNN W I�mN N W COO �!] 1 o N O I n +A Mo m CO M -O co CA I? a0 LO LO V N O I? 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N N N C (ui/};sn SS) gldaQ laotuan anal, 2K-25 Post RWO Schematic 16", 62.5#, H at 115' MD 9-5/8", 36#, J at 4082' MD C-sand perfs 9778'-9792' N IA -sand perfs 9860'-9880' 11 9912'-9948' 11 Proposed CT @ 9920' MD 7", 26#, J-55 10,230' MD 9.3# L-80 ELIE 8rd-Mod tubing to surface ' Camco gas lift mandrel @ 3315', 5299', 6718', 7474' RKB ' X-nipple @ 7535' RKB (2.813" min ID) 9.3# L-80 Mule Shoe @ 7620' RKB er ZXP packer @ 7571' RKB Baker Flexlock liner hanger at 7590' RKB er SBE @ 7600' RKB %2' scab liner cemented in place. ** Three KO joints 9820' - 9946' PDC for CTD exits ** E-line not needed to log in place, but instead use existing jewelry to correlate depth ** ** No centralizers on these 3 kickout joints. All other 4%" joints are centralized. ** ** Landing collar @ 10065' MD ** k $ \ / � [\ \ / )� cm) to _ - ' m iL� G , - © k § m# )® §%k{2 5 ®n!Z \ #f g =* 4) k k 2 \/ 2221mN0 6 c z ° 8 � � )2 # § /i \ )00 0aa U £ q« LU § // k) 2 = o/ § ƒ) f 8 2 C § CL a- '■@®§�e Cl) N) S p \ / oi 8 8 ƒ ) m m m co Cl) m G e o \/ ]6 CO / p %] TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: 2) � ✓ Development _ Service _ Exploratory Stratigraphic Test _ Non -Conventional FIELD: K �r �� i% POOL: c . �/ h �i a Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. J 9 O -- O 1), , API No. 50-103 - aiDr Z. - - O b . (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) 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 Pilot Hole name ( PH) and API number (50- - - -� from records, data and logs acquired for well (name onpermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception 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' sam le 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 also required for this well: Well Logging 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 2/2015 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 PTD#:2160260 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Well Name: KUPARUK RIV UNIT 2K-251-1-02 Program DEV Well bore seg [I DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal Administration 17 Nonconven. gas conforms to AS31.05.0300.1.A),(j.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025588, Surf Loc & TD; ADL0025605, Top Prod Intery 3 Unique well name and number Yes KRU 2K-251-1-02 4 Well located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order No. 432C. 5 Well located proper distance from drilling unit boundary Yes CO 432C contains no spacing restrictions with respect to drilling unit boundaries. 6 Well located proper distance from other wells Yes CO 432C has no interwell spacing restrictions. 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes Wellbore will be more than 500' from an external property line where ownership or landownership changes. 10 Operator has appropriate bond in force Yes Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval Yes PKB 2/10/2016 13 Can permit be approved before 15-day wait Yes 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 18 Conductor string provided NA Conductor set in KRU 2K-25 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in KRU 2K-25 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing set and fully cemented 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons No Productive interval will be completed with uncemented slotted liner 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes Anti -collision analysis complete; no major risk failures 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pres is 4806 psig(14.5 ppg EMW); will drill w/ 9.3 ppg EMW and maintain overbal w/ MPD VTL 2/12/2016 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 4170 psig; will test BOPS to 4400 psig 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable Yes H2S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 2K-Pad are H2S-bearing. 112S measures required. Geology 36 Data presented on potential overpressure zones Yes Max. expected reservoir pressure is 14.5 ppg EMW; will be drilled using 9.3 ppg mud and MPD technique. Appr Date 37 Seismic analysis of shallow gas zones NA PKB 2/10/2016 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Onshore lateral development well to be drilled. Geologic Engineering Public Commissioner: Date: Commission r: Date Commissioner Date
