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Home My WebLink About216-149Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Monday, November 26, 2018 9:27 AM To: 'Starck, Kai' Cc: Loepp, Victoria T (DOA); Boyer, David L (DOA) Subject: KRU 3H-22 L1-01, L1-04, L1-05, PTDs 216-146, 216-149, 216-150, Permits Expired Hello Kai, The following Permits to Drill, issued to ConocoPhillips Alaska, have expired under Regulation 20 AAC 25.005 (g). The PTDs will be marked expired in the AOGCC database. • KRU 3H-22 1-1-01, PTD 216-146, Issued 15 November 2016 • KRU 3H-22 1-1-04, PTD 216-149, Issued 15 November 2016 • KRU 3H-22 L1-05, PTD 216-150, Issued 15 November 2016 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.gov. THE STATE GOVERNOR BILL WALKER G. Eller CTD Team Lead 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.alaska.gov Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 3H-22L1-04 ConocoPhillips Alaska, Inc. Permit to Drill Number: 216-149 Surface Location: 957' FNL, 282' FWL, Sec. 12, T12N, R8E, UM Bottomhole Location: 4838' FNL, 629' FWL, Sec. 35, T13N, R8E, UM Dear Mr. Eller: Enclosed is the approved application for permit to redrill the above referenced service well. The permit is for a new wellbore segment of existing well Permit No. 188-110, API No. 50-103- 20097-00-00. 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, )X Daniel T. Seamount, Jr. zCommissioner DATED this [ `day of November, 2016. STATE OF ALASKA At_ ,r�A OIL AND GAS CONSERVATION COMIC/,. ,jN PERMIT TO DRILL 20 AAC 25.005 RECEIVED Nnv 0 3 2016 1 a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑� Service - Disp ❑ 1 c. Specify if well is proposed for: Drill ❑ Lateral ❑✓ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj ❑ Single Zone ❑� Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development -Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket 0 Single Well ❑ 11. Well Name and Number: ConocoPhillips Alaska Inc Bond No. 59-52-180 KRU 31-1-221-1-04 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 1 1,750' ' TVD: 6026' Kuparuk River Field/ Kuparuk Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): yj�u] Surface: 957' FNL, 282' FWL, Sec. 12, T12N, R8E, UM • ADL 25523 J Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 4409' FNL, 2369' FWL, Sec. 35, T13N, R8E, UM ALK 2559 12/5/2016 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4838' FNL, 629' FWL, Sec. 35, T13N, R8E, UM 25V0 9820' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 76 15. Distance to Nearest Well Open Surface: x- 498656 y- 6000700 Zone-4 • GL Elevation above MSL (ft): 39 to Same Pool: 1551' to 3H-191-1 16. Deviated wells: Kickoff depth: 9765' feet • 17� 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle( 6 .3 degrees Downhole: &,. 4 4 psig Surface: 37 1 psig 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Qu ntity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7# L-80 ST-L 9815 6103 11750 6026 Slotted 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): 10234' 6379' None 9818, 6125' None Casing Length Size Cement Volume MD TVD Conductor/Structural 115' 16" 250 sx AS 1 115' 115' Surface 4348' 9-5/8" 1500 sx AS III & 500 sx Class G 4348' 3127' Intermediate Production 10052' 7" 1280 sx Class G & 175 sx AS 1 10052' 6268' Liner Perforation Depth MD (ft): 9690'-9710', 9716'-9736', 9754'-9774' Perforation Depth TVD (ft): 6047'-6059', 6063'-6075',6086'-6098' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Program ❑✓ Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program E] 20 AAC 25.050 requirements0 21. Verbal Approval: Commission Representative: Date /1 L?_-Zo / j 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not Jeff Connelly @ 263-4112 be deviated from without prior written approval. Contact Email efF.S.COrlllell CO .COtll Printed Name VG. Eller Title CTD Team Lead Signature Phone 263-4172 Date Z Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: / 50- �3 (� Q -Q Date: 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: �� %� i ,tjl�e f— Samples req'd: Yes ❑ Nov Mud log req'd: Yes ❑ No J GC U P' �. /4nr�w�n v �S-4 - HZS measures: Yes [�No❑ Directional svy req'd: Yes No❑ Inclination Yes ❑ z / Spacin exception req'd: Yes ❑ No -only svy req'd: No $A� Post initial injection MIT req'd: Yes❑ No❑ Zv AAA- Z57 D1,S(6) tar- i 4n�wk� ae"L) mew,,&e-,Z_, APPROVED BY / Approved by: COMMISSIONER THE COMMISSION Date: f ,� r% '/(l Submit Form and Form 10-401 (ReJed 11/2015) GIRtleS 4 onths from the date of approval (20 AAC 25.005(g)) Attachments in Duplicate ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 27, 2016 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: RECEIVE® NOV 0 3 2016 ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill a hexa-lateral out of the Kuparuk Well 3H-22 (PTD# 188-011) using the coiled tubing drilling rig, Nabors CDR2-AC or CDR3-AC (Note: The 3H-22 CTD project is planned for CDR2-AC drilling at the time of PTD submittal, please be aware that for scheduling purposes, CDR3 may be utilized for drilling activities should the need arise). The work is scheduled to begin December 5, 2016. The CTD objective will be to drill six laterals (3H-22L1, 3H-221_1-01, 3H-221_1-02, 3H-221_1- 03, 3H-221_1-04, and 3H-221_1-05), targeting the Kuparuk A -sand intervals. A 4-1/2" big tail pipe was installed during RWO prior to CTD operation. To account for geological uncertainties, ConocoPhillips requests a variance from the requirements of 20 AAC 25.015 to allow the actual kick-off point to be anywhere along the length of the parent lateral instead of being limited to 500' from the original point. Attached to this application are the following documents: — Permit to Drill Application Forms (10-401) for 3H-22L1, 3H-22L1-01, 3H-22L1-02, 3H-22L1-03, 3H- 221_1-04, and 3H-221_1-05 — Detailed Summary of Operations — Directional Plans for 3H-22L1, 3H-221_1-01, 3H-221_1-02, 3H-221_1-03, 3H-22L1-04, and 3H-22L1-05 — Current wellbore schematic — Proposed wellbore schematic If you have any questions or require additional information, please contact me at 907-263-4112. Sincerely, Jeff Connelly Coiled Tubing Drilling Engineer Kuparuk CTD Laterals �NABORS ALASKA 3H-22L1, 3H-22L1-01, 3H-22L1-02, 3H-22L1-03, CPJ9i, 3H-221-1-04, and 31-1-221-1-05 2AC Application for Permit to Drill Document 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 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................6 14. Disposal of Drilling Mud and Cuttings.......................................................................................... 7 (Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 7 15. Directional Plans for Intentionally Deviated Wells....................................................................... 7 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 7 16. Quarter Mile Injection Review (for injection wells only)............................................................... 7 (Requirements of 20 AAC 25.402).......................................................................................................................................................... 7 17. Attachments.................................................................................................................................... 8 Attachment 1: Directional Plans for 3H-22L1, 31-1-221-1-01, 31-1-221-1-02, 31-1-221-1-03, 31-1-221-1-04, and 3H-22L1-05... 8 Attachment 2: Current Well Schematic for 31-1-22............................................................................................................8 Page 1 of 8 October 27, 2016 Attachment 3: Proposed Well Schematic for 3H-221-1, 3H-221-1-01, 31-1-221-1-02, 3H-221-1-03, 3H-22L1-04, and 3H- 22L1-05............................................................................................................................................................................8 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 3H-22L1, 3H-22L1-01, 3H-22L1-02, 31-1-22L1-03, 3H- 22L1-04, and 3H-221-1-05. 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 attached 10-401 form for surface and subsurface coordinates of the 3H-22L1, 3H-22L1-01, 3H-221-1-02, 3H-22L1-03, 3H-22L1-04, and 3H-22L1- 05. 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 4700 psi. Using the maximum formation pressure in the area of 3H-31 (i.e. 15 ppg EMW), the maximum potential surface pressure in 3H-22, assuming a gas gradient of 0.1 psi/ft, would be 4205 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)) The formation pressure in KRU 3H-22 was measured to be 4107 psi (13.01 ppg EMW) on 9/25/2016. The maximum downhole pressure in the 3H-22 vicinity is 31-1-31 at 4825 psi (15 ppg EMW) measured 10/8/2016. The lowest downhole pressure in the 3H-22 vicinity is to the east in the 3H-21 producer at 3290 psi (10.22 ppg EMW) measured 6/24/2016. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) MI gas injection has occurred in the area, there is the potential of encountering free gas while drilling the 3H-22 laterals. 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 3H-22 laterals will be shale instability at large fault crossings. Managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with the fault crossing. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 3H-22 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 8 October 27, 2016 PTD Application: 31-1-221-1, 1-1-01, 1-1-02, L1-03, 1-1-04, and L1-05. 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 3H-221_1 10,070' 11,750' 6,036' 6,725' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 3H-221_1-01 9,815' 11,150' 6,028' 6,008' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 3H-221_1-02 9,900, 11,750' 6,037' 6,102' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 3H-221_1-03 9,765' 11,825' 6,013' 6,071' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 3H-22L1-04 9815 11,750' 6028' 5,950' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 3H-221_1-05 9,715' 11,750' 5,987' 6111 2%", 4.7#, L-80, ST-L slotted liner; deployment sleeve 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' 1640 630 Surface 9-5/8" 36.0 J-55 BTC 0' 4,348' 0' 3,126' 3520 2020 Production 7" 26.0 J-55 BTC 0' 10,052' 0' 6269' 4980 4330 Tubing 3-1/2" 9.3 L-80 EUE 0' 9664' 0' 6457' 10180 10540 Tubing Tail 4-1/2" 12.6 L-80 STC 9664' 9748' 6402' 6457' NA NA 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 (8.6 ppg) - Drilling operations: Chloride -based FloVis mud (8.6 ppg). 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 NaBr or K-Formate 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 5000 psi rated coiled tubing Page 3 of 8 October 27, 2016 PTD Application: 3H-22L1, L1-01, L1-02, L1-03, L1-04, and L1-05. pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". In the 3H-22 laterals we will target a constant BHP of 13.1 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. Reservoir pressure at 3H-22 is expected to continue to come down, as it has in the past two months through pressure management in the area. Target pressure at the window will likely be modified to reflect this decrease in pressure at time of CTD drilling, though for purposes of planning 13.1 ppg at the window will be used for the calculations below. Pressure at the 3H-22 Window (9715' MD, 6435' TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A -sand Formation Pressure (13.1 pp) 4107 psi 4107 psi Mud Hydrostatic 8.6 2778 psi 2778 psi Annular friction i.e. ECD, 0.080 si/ft 777 psi 0 psi Mud + ECD Combined 3555 psi 2778 psi (no choke pressure) (underbalanced —552 (underbalanced psi) —1329 psi Target BHP at Window (13.1 ppg) 4383 psi 4383 psi Choke Pressure Required to Maintain Target 828 psi 1605 psi 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. 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well KRU 3H-22 is a Kuparuk A -sand injection (service) well that has been recently worked over to install new 3Y2" tubing with a 4-1/2" Big Tail Pipe (BTP). Six CTD laterals will be drilled from the 3H-22, three to the north and three to the west, with the laterals targeting the Kuparuk A1, A2, and A3 sands. Page 4 of 8 October 27, 2016 PTD Application: 3H-22L1, L1-01, L1-02, L1-03, L1-04, and L1-05. The 3H-22L1 lateral will exit through the 4'h" BTP and 7" casing at 9715' MD and TD at 11,750' MD, targeting the A1, A2 and A3 sands. It will be completed with 2%" slotted liner from TD up to 10,070' MD with aluminum billet for kicking off the 3H-22L1-01 lateral. The 3H-22L1-01 lateral will drill west to a TD of 11,150' MD targeting the Al and A2 sands. It will be completed with 2%" slotted liner from TD up to 9,815' MD with an aluminum billet for kicking off the 3H- 22L 1-02 lateral. The 3H-22L1-02 lateral will drill north to a TD of 11,750' MD targeting the Al sand. It will be completed with 2%" slotted liner from TD up to 9,900' MD with an aluminum billet for kicking off the 3H-22L1-03 lateral. The 3H-22L1-03 lateral will drill south to a TD of 11,825' MD targeting the Al, A2, and A3 sands. It will be completed with 2%" slotted liner from TD up to 9765' MD with an aluminum billet for kicking off the 3H-22L 1-04 lateral. The 3H-22L1-04 lateral will drill west to a TD of 11,750' MD targeting the A sands. It will be completed with 2%" slotted liner from TD up to —9815' MD with an aluminum billet for kicking off the 3H-22L1-05 lateral. The 3H-22L1-05 lateral will drill north to a TD of 11,750' MD targeting the A3 sands. It will be completed with 2%" slotted liner from TD up to TOWS with a deployment sleeve. Pre-CTD Work 1. RU Slickline: Pull sheared SOV, injection test, obtain an A -sand SBHP, drift a dummy whip -stock. 2. RU E-line: Perform a jewelry log 3. RU E-line: Set Baker Hughes whipstock at 9715' 4. 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. 3H-22L1 Lateral (A sand - west) a. Mill 2.80" window at 9715' MD. b. Drill 3" bi-center lateral to TD of 11,750' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 10,070' MD. 3. 3H-22L1-01 Lateral (A sand -west) a. Kick off of aluminum billet at 10,070' MD. b. Drill 3" bi-center lateral to TD of 11,150' MD. c. Run 2%" slotted liner from TD up to 9,815' MD. 4. 3H-22L1-02 Lateral (A sand -north) a. Kick off of aluminum billet at 9,815' MD. b. Drill 3" bi-center lateral to TD of 11,750' MD. c. Run 2%" slotted liner from TD up to 9,900' MD. 5. 3H-22L1-03 Lateral (A sand -north) a. Kick off of aluminum billet at 9,900' MD. b. Drill 3" bi-center lateral to TD of 11,825' MD. Page 5 of 8 October 27, 2016 PTD Application: 3H-22L1, 1_1-01, 1_1-02, 1_1-03, L1-04, and L1-05. c. Run 2%" slotted liner from TD up to 9765' MD. 6. 3H-22L1-04 Lateral (A sand -west) a. Kick off of aluminum billet at 9,765 MD. i•w �� 4 b. Drill 3" bi-center lateral to TD of 11,750' MD. c. Run 2%" slotted liner from TD up to 9,815' MD. 7. 3H-22L1-05 Lateral (A sand - north) a. Kickoff of aluminum billet at 9,815' MD. b. Drill 3" bi-center lateral to TD of 11,750' MD. c. Run 2%" slotted liner from TD up to TOWS at 9715' MD. 8. Freeze protect. Set BPV, ND BOPS. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV. 2. Pre -produce for less than 30 days 3. Return to injection. 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, so installed in this well is a deployment valve. This valve, when closed using hydraulic control lines from surface, isolates the well pressure and allows long BHA's to be deployed/un-deployed without killing the well. If the deployment valve fails, operations will continue using the standard pressure deployment process. 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 3H-22 laterals will be displaced to an overbalanced fluid (K-Formate or NaBr depending on pressures encountered at time of drilling) prior to running liner. See "Drilling Fluids" section for more details. Page 6 of 8 October 27, 2016 PTD Application: 31-1-221-1, L1-01, L1-02, L1-03, L1-04, and L1-05. — While running 23/" 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 (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). 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 open hole section. — Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 3H-22L1 9820' 3H-22L1-01 10060' 3H-22L1-02 11075' 3H-22L1-03 11075' 3H-22L1-04 9820' 31HI-221-1-05 11,075' — Distance to Nearest Well within Pool Lateral Name Distance Well 3H-22L1 1551' 3H-191_1 3H-221-1-01 1551' 3H-191-1 3H-22L1-02 1322' 3M-29 3H-221-1-03 1322' 31VI-29 3H-22L1-04 1551' 3H-191-1 3H-22L1-05 1322' 3M-29 16. Quarter Mile Injection Review (for injection wells only) (Requirements of 20 AAC 25.402) There are no wells within %4-mile of the 31-1-221-1, 3H-221-1-01, 3H-221_1-02, 3H-221-1-03, 31-1-221-1-04, and 3H- 221-1-05 laterals Page 7 of 8 October 27, 2016 PTD Application: 3H-22L1, L1-01, L1-02, L1-03, L1-04, and L1-05. 3H-22 (mother bore) Injector • Classified as a "Normal Well" • Original PTD is 188-011 & API Number is 50-103-20097-00 • The well was completed in RWO with 3.5" 9.3# L-80 tubing, 4.5" 12.6# L-80 Big Tail Pipe, and 7" 26# J- 55 production casing. • A -sand perforations: • Measure Depth: 9690' — 9710' MD, 9716'-9736' MD, and 9754'-9774' MD • TVD: 6047'-6059' TVD, 6060'-6075' TVD, and 6086'-6098' TVD • Production packer at 9578' MD — 5979' TVD, which is less than 200' from A -sand perforations • Well is currently off-line • 7" production casing was cemented with 200 sx class G (minimum) • TOC 500' above top of Kuparuk • 3H-221-1-02, 3H-22L1-03, & 3H-22L1-05 are planned at 1322' from 3M-29, 3M-29A, & 3M-29APB1, which is 2' outside of mile radius. 17. Attachments Attachment 1: Directional Plans for 3H-22L1, 3H-22L1-01, 3H-22L1-02, 3H-22L1-03, 3H-22L1-04, and 3H-22L1-05 Attachment 2: Current Well Schematic for 3H-22 Attachment 3: Proposed Well Schematic for 3H-22L1, 3H-22L1-01, 3H-22L1-02, 3H-22L1-03, 3H-22L1-04, and 3H-22L1-05 Page 8 of 8 October 27, 2016 ConocoPh i I I i ps ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 3H Pad 3H-22 3H-22L1-04 Plan: 31-1-221-1-04_wp00 Standard Planning Report 25 October, 2016 we P P"-- 'A Fag BAKER HUGHES ConocoPhillips Database: EDM Alaska NSK Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3H Pad Well: 31-1-22 Wellbore: 31-1-2211-04 Design: 3 H-22 L 1-04_wp00 ConocoPhillips Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3H-22 Mean Sea Level 31-1-22 @ 76.00usft (31-1-22) 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 ri.s BAKER HUGHES Site Kuparuk 3H Pad Site Position: Northing: 6,000,110.73 usft Latitude: 70° 24' 41.531 N From: Map Easting: 498,655.44usft Longitude: 150° 0' 39.416 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: -0.01 ° Well 3H-22 Well Position +N/-S 0.00 usft Northing: 6,000,700.42 usft Latitude: 70° 24' 47.331 N +E/-W 0.00 usft Easting: 498,655.73 usft Longitude: 150° 0' 39.411 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 31-1-221-1-04 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) B G G M 2016 12/1 /2016 17.83 80.98 57,545 Design 31-1-221-1-04_wp00 Audit Notes: Version: Phase: PLAN Tie On Depth: 9,765.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (I 0.00 0.00 0.00 260.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (°) (1) (usft) (usft) (usft) (°/100ft) (°/100ft) (°/100ft) (°) Target 9,765.00 64.25 353.49 6,013.57 7,108.25 1,030.36 0.00 0.00 0.00 0.00 9,835.00 89.00 339.91 6,029.71 7,173.74 1,014.45 40.00 35.36 -19.40 330.00 10,000.00 89.59 273.91 6,031.99 7,267.44 889.70 40.00 0.36 -40.00 270.00 10,100.00 89.60 266.91 6,032.70 7,268.15 789.77 7.00 0.00 -7.00 270.00 10,250.00 99.94 265.07 6,020.25 7,257.73 640.86 7.00 6.89 -1.23 350.00 10,400.00 90.81 259.84 6,006.21 7,238.10 493.03 7.00 -6.08 -3.49 210.00 10,700.00 90.76 238.84 6,002.04 7,132.85 213.92 7.00 -0.02 -7.00 270.00 10,800.00 97.65 237.61 5,994.71 7,080.37 129.18 7.00 6.89 -1.22 350.00 10,900.00 91.58 234.12 5,986.66 7,024.46 46.74 7.00 -6.07 -3.49 210.00 11,000.00 91.57 227.12 5,983.91 6,961.08 -30.48 7.00 -0.01 -7.00 270.00 11,150.00 91.54 237.62 5,979.83 6,869.66 -149.06 7.00 -0.02 7.00 90.00 11,330+00 100.40 246.64 5,961.09 6,786.05 -306.95 7.00 4.92 5.01 45.00 11,500.00 89.20 250.69 5,946.90 6,724.57 -464.48 7.00 -6.59 2.38 160.00 11,750.00 89.23 268.19 5,950.34 6,678.94 -709.27 7.00 0.01 7.00 90.00 1012512016 3:53:35PM Page 2 COMPASS 5000.1 Build 74 ConocoPhillips MFAI ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska NSK Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3H Pad Well: 3H-22 Wellbore: 31-1-221-1-04 Design: 3 H-22 L 1-04_wp 00 Planned Survey Measured TVD Below Depth Inclination Azimuth System (usft) (°) (1 (usft) 9,765.00 64.25 353.49 6,013.57 TIP/KOP 9.800.00 76.53 346.35 6,025.31 9,835.00 89.00 339.91 6.029.71 Start 40 dls 9,900.00 89.10 313.91 6,030.81 10,000.00 89.59 273.91 6,031.99 End 40 dls, Start 7 dls 10,100.00 89.60 266.91 6,032.70 4 10,200.00 96.49 265.69 6,027.39 10,250.00 99.94 265.07 6,020.25 5 10,300.00 96.90 263.31 6.012.93 10,400.00 90.81 259.84 6,006.21 6 10,500.00 90.81 252.84 6,004.79 10,600.00 90.79 245.84 6,003.39 10,700.00 90.76 238.84 6,002.04 7 10,800.00 97.65 237.61 5,994.71 8 10,900.00 91.58 234.12 5,986.66 9 11,000.00 91.57 227.12 5,983.91 10 11,100.00 91.56 234.12 5,981.18 11,150.00 91.54 237.62 5,979.83 11 11,200.00 94.01 240.10 5.977.41 11,300.00 98.93 245.12 5,966.13 11,330.00 100.40 246.64 5,961.09 12 11,400.00 95.79 248.33 5,951.24 11,500.00 89.20 250.69 5,946.90 13 11,600.00 89.20 257.69 5,948.29 11,700.00 89.22 264.69 5,949.67 11,750.00 89.23 268.19 5,950.34 Planned TD at 11750.00 Local Co-ordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 31-1-22 Mean Sea Level 31-1-22 @ 76.00usft (31-1-22) True Minimum Curvature Vertical Dogleg Toolface Map Map +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (usft) (usft) (°/100ft) (°) (usft) (usft) 7,108.25 1,030.36 -2,249.04 0.00 0.00 6,007,807.77 499,687.26 7,140.61 1,024.52 -2,248.91 40.00 -30.00 6,007,840.13 499,681,43 7,173.74 1,014.45 -2,244.74 40.00 -27.59 6,007,873.26 499,671.37 7,227.73 979.27 -2,219.47 40.00 -90.00 6,007,927.25 499,636.20 7,267.44 889.70 -2.138.16 40.00 -89.56 6,007,966.97 499,546.65 7,268.15 789.77-2,039.87 7.00 -90.00 6,007,967.70 499,446.73 7,261.71 690.18 -1,940.68 7.00 -10.00 6.007,961.28 499,347.15 7,257.73 640.86 -1,891.42 7.00 -10.06 6,007,957.31 499,297.83 7.252.72 591.66 -1,842.09 7.00 -150.00 6,007,952.31 499,248.64 7,238.10 493.03 -1,742.42 7.00 -150.26 6,007,937.70 499.150.01 7,214.50 395.93-1,642.70 7.00 -90.00 6,007,914.12 499,052.92 7,179.24 302.43-1,544.49 7.00 -90.10 6,007,878.89 498,959.42 7,132.85 213.92-1,449.27 7.00 -90.20 6,007,832.51 498,870.91 7.080.37 129.18-1,356.71 7.00 -10.00 6,007,780.06 498,786.17 7,024.46 46.74-1,265.81 7.00-150.00 6.007,724.17 498,703.73 6,961.08 -30.48-1,178.76 7.00 -90.00 6,007,660.81 498,626.51 6,897.70 -107.70 -1,091.71 7.00 90.00 6,007,597.45 498,549.28 6,869.66 -149.06 -1,046.10 7.00 90.19 6,007,569.42 498,507.92 6.843.84 -191.80 -999.53 7.00 45.00 6.007,543.60 498,465.18 6,798.13 -279.96 -904.78 7.00 45.12 6,007,497.92 498,377.02 6,786.05 -306.95 -876.10 7.00 45.69 6,007,485.84 498,350.03 6,759.52 -370.95 -808.46 7.00 160.00 6,007,459.33 498,286.03 6,724.57 -464.48 -710.29 7.00 160.24 6,007,424.41 498,192.51 6,697.35 -560.63 -610.87 7.00 90.00 6,007,397.20 498,096.36 6,682.04 -659.38 -510.97 7.00 89.90 6,007,381.91 497,997.62 6,678.94 -709.27 -461.29 7.00 89.81 6,007,378.82 497,947.74 1012512016 3:53:35PM Page 3 COMPASS 5000.1 Build 74 ConocoPh i I I i ps ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 3H Pad 3H-22 3H-22L1-04 3H-22L1-04_wp00 Travelling Cylinder Report 25 October, 2016 BAKER NUGHES Baker Hughes INTEQ FIN.. ConocoPhlllips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3H Pad Site Error: 0.00 usft Reference Well: 31-1-22 Well Error: 0.00 usft Reference Wellbore 3H-2211-04 Reference Design: 3H-221-1-04_wp00 Local Co-ordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 3H-22 3H-22 @ 76.00usft (3H-22) 3H-22 @ 76.00usft (31-1-22) True Minimum Curvature 1.00 sigma OAKEDMP2 Offset Datum Zeference 31-1-221-1-04_wp00 :filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference nterpolation Method: MD Interval 25.00usft Error Model: ISCWSA )epth Range: 9,765.00 to 11,750.O0usft Scan Method: Tray. Cylinder North Zesults Limited by: Maximum center -center distance of 1,367.40 usft Error Surface: Elliptical Conic Survey Tool Program Date 10/25/2016 From To (usft) (usft) Survey (Wellbore) Tool Name Description 100.00 9,700.00 3H-22 (3H-22) GCT-MS Schlumberger GCT multishot 9,700.00 9,765.00 3H-22L1_wp04 (3H-221-1) MWD MWD - Standard 9,765.00 11,750.00 3H-221_1-04_wp00 (3H-221_1-04) MWD MWD - Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 115.00 115.00 16" 16 26 4,348.00 3,127.05 9 5/8" 9-5/8 13-1/2 11,750.00 6,026.34 2 3/8" 2-3/8 3 Summary Site Name Offset Well - Wellbore - Design Kuparuk 3H Pad 3H-13 - 3H-13 - 3H-13 3H-13 - 3H-13A - 31-1-13A 3H-14 - 3H-14 - 3H-14 3H-14 - 3H-14A - 3H-14A 31-1-14 - 3H-14APB1 - 3H-14APB1 31-1-14 - 3H-14B - 3H-14B 31-1-14 - 3H-14BL1 - 3H-14BL1 31-1-14-3H-14BL2-3H-14BL2 31-1-14-31-1-141313-31-1-14131-3 31-1-14 - 3H-14BL4 - 3H-14BL4 3H-15 - 31-1-15 - 31-1-15 31-1-16 - 31-1-16 - 3H-16 3H-16 - 3H-16A - 3H-16A 31-1-16 - 3H-16APB1 - 3H-16APB1 31-1-17 - 3H-17 - 3H-17 31-1-18 - 3H-18 - 3H-18 3H-19 - 3H-19 - 3H-19 3H-19 - 31-1-1911 - 31-1-191-1_wp03 31-1-19 - 3H-1911-01 - 3H-1911-01_wp02 3H-19 - 3H-19L1-02 - 3H-19L1-02_wp01 3H-19 - 3H-19L1-03 - 3H-19L1-03_wp02 3H-19 - 3H-19L1-04 - 3H-19L1-04_wp01 3H-20 - 3H-20 - 3H-20 3H-20 - 3H-20L1 - 31-1-201-1 3H-20 - 3H-2011-01 - 3H-2011-01 Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Depth Depth Distance (usft) from Plan (usft) (usft) (usft) (usft) Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 1012512016 11:26:57AM Page 2 COMPASS 5000.1 Build 74 1 Baker Hughes INTEQ ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Local Co-ordinate Reference: Well 31-1-22 Project: Kuparuk River Unit TVD Reference: 31-1-22 @ 76.00usft (3H-22) Reference Site: Kuparuk 3H Pad MD Reference: 31-1-22 @ 76.00usft (31-1-22) Site Error: 0.00 usft North Reference: True Reference Well: 3H-22 Survey Calculation Method: Minimum Curvature Well Error: 0.00 usft Output errors are at 1.00 sigma Reference Wellbore 31-1-221-1-04 Database: OAKEDMP2 Reference Design: 3H-22L1-04_wp00 Offset TVD Reference: Offset Datum 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 3H Pad 31-1-20 - 3H-20L1-01PB1 - 3H-20L1-01PB1 Out of range 31-1-20 - 31-1-201_1-02 - 31-1-201-1-02 Out of range 31-1-20 - 31-1-201-1-03 - 31-1-201_1-03 Out of range 31-1-20 - 3H-20L1-03PB1 - 31-1-201-1-03P61 Out of range 31-1-20 - 31-1-201_1-04 - 3H-201_1-04 Out of range 3H-20 - 3H-20L1-04PB1 - 3H-20L1-04P61 Out of range 31-1-20 - 31-1-2011-05 - 31-1-201-1-05 Out of range 31-1-20 - 31-1-201_1-06 - 31-11-201-1-06 Out of range 31-1-21 - 31-1-21 - 31-1-21 Out of range 31-1-22 - 31-1-22 - 31-1-22 9,773.55 9,775.00 7.18 4.66 2.55 Pass - Major Risk 31-1-22 - 31-1-221-1 - 3H-22L1_wp04 9,775.00 9,775.00 0.01 0.28 -0.23 FAIL - Minor 1/10 31-1-22 - 31-1-221_1-01 - 3H-22L1-01_wp01 9.775.00 9,775.00 0.01 0.28 -0.23 FAIL - Minor 1/10 31-1-22 - 3H-221_1-02 - 3H-22L1-02_wp02 9,775.00 9,775.00 0.01 0.28 -0.23 FAIL- Minor 1/10 31-1-22 - 31-1-221_1-03 - 3H-22L1-03_wp02 9,775.00 9,775.00 0.01 0.28 -0.23 FAIL - Minor 1/10 31-1-22 - 31-1-221_1-05 - 3H-22L1-05_wp00 9,824.99 9,825.00 0.33 0.29 0.04 Pass - Minor 1/10 31-1-23 - 31-1-23 - 31-1-23 Out of range 31-1-23 - 3H-23A - 3H-23A Out of range 31-1-24 - 31-1-24 - 31-1-24 Out of range 3H-28 - 3H-28 - 31-1-28 Out of range 31-1-28 - 3H-28A - 3H-28A Out of range 31-1-28 - 3H-28APB1 - 3H-28APB1 Out of range 31-1-31 - 31-1-31 - 31-1-31 Out of range 31-1-32 - 3H-32 - 31-1-32 Out of range 31-1-32 - 3H-32PB1 - 3H-32PB1 Out of range 31-1-33 - 31-1-33 - 31-1-33 Out of range 31-1-33 - 3H-33A- 3H-33A Out of range 31-1-33 - 3H-33AL1 - 3H-33AL1 Out of range 31-1-33 - 3H-33AL1 PB1 - 3H-33AL1 PB1 Out of range 31-1-33 - 3H-33AL2 - 3H-33AL2 Out of range 31-1-33 - 3H-33AL2-01 - 3H-33AL2-01 Out of range 31-1-34 - 31-1-34 - 31-1-34 Out of range 31-1-34 - 31-1-341-1 - 31-1-341-1 Out of range 31-1-34 - 31-1-341-1-01 - 31-1-341-1-01 Out of range 3H-34 - 3H-34L1-01 PB1 - 3H-34L1-01 PB1 Out of range 31-1-34 - 3H-34L1-02 - 31-1-341_1-02 Out of range 31-1-34 - 31-1-341_1 P131 - 3H-34L1 PB1 Out of range Offset Design Kuparuk 3H Pad - 31-1-22 - 31-1-22 - 3H-22 Offset Site Error: 0.00 usft Survey Program: 100-GCT-MS 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) V) (usft) (usft) 1") (usft) (usft) (usft) 9,773.55 6,093.08 9.775.00 6,099.05 0.07 0.57 145.90 7,113.95 1,032.80 5 7.18 4.66 2.55 Pass - Major Risk, CC, ES, SF 9,795.14 6,100.11 9,800.00 6,114.26 0.08 0.76 142.20 7,133.79 1,033.14 5 16.19 6.24 9.98 Pass - Major Risk 9,814.06 6,103.98 9,825.00 6,129.46 0.08 0.95 138.90 7,153.63 1,033.46 5 28.38 7.54 20.88 Pass - Major Risk 9,830.00 6,105.55 9,850+00 6,144.66 0.08 1.15 135.99 7,173.48 1,033.76 5 43.14 8.57 34.61 Pass - Major Risk 9,845.71 6,105.90 9,875.00 6,159.86 0.09 1.34 130.32 7,193.33 1,034.04 5 59.70 9.38 50A6 Pass - Major Risk 9,860.00 6,106.14 9,900.00 6,175.04 0.09 1.53 123.13 7,213+19 1,034.29 5 77.18. 10.05 67.35 Pass - Major Risk 9,873.49 6,106.37 9,925.00 6,190.24 0.10 1.72 115.96 7,233.04 1,034.54 5 95.49 10.66 85A2 Pass - Major Risk 9,885.05 6,106.57 9,950.00 6,205.46 0.10 1.91 109.56 7,252.87 1,034.77 5 114.59 11.15 103.75 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 1012512016 11:26:57AM Page 3 COMPASS 5000.1 Build 74 z�2.v a O N co ac0 C r,:Y J p V' 6) 0 y O a � r• � t6 U m N O F OvC�- c r c CW O N M QH UJ a Cn COrMm---d V- C O I l- N N r• C D O O m m '5 O r• nD V V N r• e0 r• N N �j -O M M m V t o C O r• t O N CN O M r• E M N O o D 1 V Cj N N N N N .M N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N J N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N C; O O C j O 0 0 C 7 C 7 0 C) C A O C� _ zo L, M r- r r- C O r--m V c 0 m Cl) (fl M N N M N N ) N N C J I 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O G] O O O O O O O O O O O O O o ti p o � oa r.. r• r• r r- r• r• � � r• r• CO Cf) O r• CO c') N aD 'S a0 CO CC) a0 r• M r• r• a0 O m r• 7 0 m� N � y J O �' m m O M C2 m O O m w"t m C } M 'D W a0 �' m C j N t C`7 O CO O 00a01� V N� �C?� 1� v J � N _ Q W (A UJ �[]cY V' Cn M OCO r•m aOO fir• V _ ' N r• V'r-�"'a0M V OCD Otom Cl)" � ZaoM r•oo r•.0 C.i O mGO T a0 W } O r-CO CO Cn M _M W NOCO ODN ti N N N N O O m W r- r- O r• r• r• r• r• r. r• r• r• O CO CO t0 CO J LU C n i. m o C O.- V C O e- M m O It CO m r• N N O r• CD m c O O m M t=> L 'C CO N M M N O O m o0 M M C m LO O O O O O O O m m m m m m m m O CO CO CO CD CO CO tt) CO � CA Ct) CO Cn z OHO r• a V m m m O C0 00 O CO CO CO O) CO MmMm Cn ma r. V r• r•COOaO CO M r• O CO CO M M M N M V CO M M N N N N N N N N N N N N U COOmO��m Cn 00 r••�T C N O CO Cp mO r•CO to CO Lq V NN , O COOcONmmmmmmm0 WLLJ N CD+0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ui �ri00000000 CD o Coo O O o 0 Cn M O Cn r• W O R N V r• O m O � M Cn r- m O N M CO O r• a0 m O Z O N 00 ry ca x J N 101 40-I ZZ-H£ G O ca W 3 s a s x a x ml a N x 9 r C p a c y t: a N W p O O v � M y a N�'•. N N N ._. f o �o O o o O o c O o QO,I, N (ut/gsn 09) ujdaQ 1poilzon onji -• KUP INJ 3H-22 ConocoF'i iliip5 Well Attributes Max Angle & MD TD Alaska. Inc. Wellbore APIIUWI Field Name Wellbore Status ncl (°) MD(1, Act St. (ftKB) 501032009700 KUPARUK RIVER UNIT INJ 60.15 51100000 10,234.0 ••• Comment H2S (ppm) I Date SSW None Annotation End Dala KBt°rtl (k) Last WO: 3/20/2016 Rig Release Date 42.01 Z218/1988 3H-22, 10/7/20163:42:55 PM Venical schemaft actual Annotation Depth (ftKB) Entl Dale Annotation Last Mod By End Date Last Tag: SLM 9,803.0 5/26/2016 'Casing Rev Reason: SET WHIPSTOCK pproven 10/7/2016 HANGER', 350 Strings Casing Description OD (in) ID (in) Top(ftKB) Set Depth (ftKB) Set Depth (ND)... Wt/Len (I... Grade Top Thmad CONDUCTOR 16 15.062 36.0 115.0 11") 62.50 H-40 WELDED Casing Description OD (in) ID "' Top (ftKB) Set Depth (ftKB) Set Depth (ND)... Wt/Len (I... Gratle Top Thread SURFACE 95/8 8.921 35.0 4, 347.6 3, 126.8 36.00 J-55 BTC Casing Description OD (in) ID (in) Top (kKB) Set Depth (ftKB) Set Depth (ND)... Wt/Len (I... Grade Top Thread PRODUCTION 7 6.276 I 35.0 10,052.2 6,267.8 26.00 J-55 BTC 'T Tubing Strings Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (% Set Depth (ND) (... Wt (Ib/fl) Grade Top Connection TUBING RWO 201E 3 1/2 2.992 35.0 9,586.8 5,984.E 9.30 L-80 EUE 8rd Mod CONDUCTOR; 36.0-115.0 Completion Details Nominal to Top (ftKB) Top (ND) (ftKB) I Top Ind V) Item Des Com (in) GAS LIFT; 3 246.3 35.0 35.0 0.09 HANGER McEvoy Gen III Tubing Hanger, MSDP-1-6.5-MS-3, 1/16" x 3-1/2" EUE 8rd Box x Box, 3" H BPVG 7- 2.950 9,574.2 5,976.9 52.65 LOCATOR Locator Sub, GBH-22 (bottom of the locator spaced out 2.990 3.83') 9,575.3 5,977.E 52.65 SEAL ASSY Seal Assembly, 8040 3.020 Tubing Description I String Ma... ID (in) Top (ftKB) Set Depth (k.. Set Depth (ND) (... Wt (lbkl) Gratle Top Connection LOWER COMP RWO 41/2 3.958 9,578.3 9,736.0 6,075.3 12.60 L-80 STC 2016 Completion Details SURFACE; 35.04,347.6- Nominal ID Top (ftKB) Top (ND) (ftKB) I Top Ind (°) Item Des Co. (in) 9,578.3 5,979.4 52.65 PACKER 587-400 Model'F' Production Packer 4.000 GAS LIFT; 5,598.9 9,581.6 5,981.4 52.64 SBE 80-40 Seal Bore Extension (SBE) 4.000 9,591.0 5,987.1 52.62 XO Reducing Crossover, 4-3/4" Stub Acme Box x 3-112" EUE Brd Pin 2.970 9,639.7 6,016.7 52.57 NIPPLE Nipple, HES, 2.813" X, SN: C-3562596 2.812 9,651.6 6,023.9 52.56 PORTED Ported Crossover, 3-12" EUE 8rd Mod Box x 4-1/2" STC 2.992 CROSSOVER Pin GAS LIFT, 7 2602 9,653.4 6,025.0 52.56 PORTED Ported Wearsox Joint, 4-1/2", 12.6#, L-80, STC Box x 3.958 WEARSOX Mule Shoe Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (TVD) Top Incl Top (ftKB) (ftKB) (°) Des Co. Run Data ID (in) 9,715.0 6,0625 52.52 WHIPSTOC BAKER 3.5"X4.5" WHIPSTOCK(GENII DELTA). 10/6/2016 GAS LIFT; 8,576.8 TOWS = 9715, WHIPSTOCK ORIENTATION = 330DEG, CCL TO TOP OF WHIPSTOCK = 14.9', RA TAG @7.35 FROM TOP, WHIPSTOP OAL=12.97 Perforations & Slots Shot GAS LIFT; 9617.2 Dens Top (ND) Btm (ND) (shots/f Top (ftKB) Blm (ftKB) (ftKB) (kKB) Zone Date t) Type Com 9,690.0 9,710.0 6,047.3 6,059.4 A-3, 3H-22 8/11/1988 8.0 APERF 2 1/8 EnerJet; 60 deg ph 9,716.0 9,736.0 6,063.1 6,075.3 A-2, 3H-22 8/11/1988 8.0 APERF 2118 EnerJet; 60 deg ph LOCATOR; 9,574.2 9,754.0 9,774.0 5,086.2 6,098.4 A-1, 3H-22 4/25/1988 4.0 WERE SOS 4.5" Ultra P; 120 deg ph PACKER; 9,576.3Mandrel Inserts SEAL ASSY; 9,575.3 St SSE; 9,581 6all N Top (ftKB) Top (ND) (IRKS) Make Model OD (in) Sery Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Co. 1 3,246.3 2,509.1 Camco MMG 1 112 GAS LIFT DMY RK 0.000 0.0 3/19/2016 XO Reducing; 9,591.042 5,598.9 3,802A Camco MMG 11/2 GAS LIFT DMY RK 0.000 0.0 3/192016 3 7,260.2 4,693.3 Camco MMG 1 1/2 GAS LIFT DMY RKP 0.000 0.0 5/27/2016 4 8,576.8 5,395.5 CamMMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 3/19/2016 5 9,517.3 5,942.4 Camco co MMG 1 1/2 1 GAS LIFT DMY RK 0.000 0.0 3/19/2016 Notes: General &Safety End Date Annotation NIPPLE; 9,639.6 4/28/1988 NOTE: Bad spot in 7"CSG 8257'-8281'; Max ID=6.45"; Tested to 2600psi w/10 ppg Brine. 11/2/2010 NOTE: View Schematic w/ Alaska Schematic9.0 PORTED CROSSOVER; 9,651.E PORTED W EARSOX; 9,653 4 APERF; 9,690.0-9,710.0� W HIPSTOC; 9,715 0 AP ER F; 9,716 0-9,736 0 - IPERE; 9,754.0-9,774.0- PRODUCTION; 35.0-10,052.2 \ m \ § \ ` ) § § \ § � k \ } } \ � = E - '® _ - U) § o \ §£ \ 0 \ \_ ( c m $ u 2 = c ]J EB E[ \ f/ 7o§ §c�§ - JA /E\/ \ f \\00 3- f7 9 >J &LL° ab� >/ 0§ Cl) \/ j)/ \� 0 % E @ � u m � w U � 0 m 0 CL 2 CL � z n \ \ § 0 0 04 �co � \ Ret tam \F5 ƒ%/ o , § \ \\ o §\ )\f d \ f c) °� �/� \ \ _ *) }/ §o /// --co - \§ �o� « \ )k \/ --- C71 2® \r. \ $ ))\ N W �Luz we 'g_ (ui/gsn Ogg) (+)uuoN/(-)ulnoS H i W �Lvz We `g_ ,T C C N � ' \a C • rl - , - C M. = M M O � _ r Z m � c I O W m � W a m c m a > y F 1J o i o O = _ b N O J^ w »jp Q F - O N 'or ii,"r, omC� �f 9iva� Al , o O : ',\ _ O p 'C ' aAA O 1 N .,og .. O I N W N - r. _ a o p 0 I o ' z ` I N , O x G V O O ✓ , Yi ♦� � N 2Y O o o0 M 17-1 u r 0 op o 0 0 o 0 0 0 0 0 0 0 0 0 o ON 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 00 0 o �o N 0 ^ ^ (ui/}jsn OOZ) (+)gpoN/(-)ulnos 3 Bettis, Patricia K (DOA) From: Connelly, Jeff <Jeff.S.Connelly@conocophillips.com> Sent: Wednesday, November 09, 2016 5:47 AM To: Bettis, Patricia K (DOA) Subject: RE: KRU 31-1-221-1 (PTD 216-145): Permit to Drill Application Patricia, The maximum down -hole pressure and potential surface pressure should be based on 3H-31 as follows: Maximum down -hole pressure: 4825 psi Maximum potential surface pressure: 4205 psi (assuming a gas gradient of 0.1 psi/ft) I apologize for the inconsistency between the two documents. Regards, Jeff Connelly From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Tuesday, November 08, 2016 4:32 PM To: Connelly, Jeff <Jeff.S.Connelly@conocophillips.com> Subject: [EXTERNAL]KRU 3H-22L1 (PTD 216-145): Permit to Drill Application Good afternoon Jeff, On Form 10-401, Box 17, the maximum downhole pressure is shown as 4384 psig; whereas the maximum potential surface pressure is stated as 3741 psig. On page 2 of the "Application for Permit to Drill Document", it is stated that the maximum downhole pressure in the 3H- 22 vicinity is 3H-31 at 4825 psi; whereas the maximum potential surface pressure in 3H-22, assuming a gas gradient of 0.1 psi/ft would be 4205 psi. Please clarify what ConocoPhillips anticipates to be the maximum downhole pressure in the 3H-22 vicinity and the maximum potential surface pressure for 3H-22. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Schwartz, Guy L (DOA) From: Connelly, Jeff <Jeff.S.Connelly@conocophillips.com> Sent: Monday, November 14, 201610:50 AM To: Schwartz, Guy L (DOA) Cc: Bettis, Patricia K (DOA); Connelly, Jeff Subject: RE: KRU 31-1-221-1 (PTD 216-145) Guy, I checked with our directional team at Baker Hughes and you are indeed correct. Below is the pertinent information regarding 3H-31, including cementing information. 3H-31 (Injector), —1000' away from 3H-22L1 at 11,750' MD • Classified as a "Normal Well" • The well is an injector • The well is completed with 3.5" 9.3# L-80 tubing and 7" 26# L-80 production casing. • Packer located at 10,311' MD which is located less than 200' from the top of the perforations. • A/C -sand perforations: C4: 10,426'—10,444 MD, A2/A1: 10,452—10,482' MD, and Al: 10,482'—10,494' MD • Well is currently SI for Pre-CTD well work (shut-in since 10/6/2016). • Production casing was cemented with 250 sx Class 'G' • Surface casing was cement with 1100 sx AS III & 600 G • Conductor casing was cemented with 200 sx AS I Please let me know if you have additional questions. Regards, -Jeff From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Monday, November 14, 2016 8:58 AM To: Connelly, Jeff <Jeff.S.Connelly@conocophillips.com> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov> Subject: [EXTERNAL]KRU 31-1-221-1 (PTD 216-145) Jeff, it appears that 3H-31 transects the % mile AOR. Can you verify that the wellbore is cemented or that the A sand is not present . I can't tell looking at a mapview. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226 ) or (Guv.schwartz@alaska.gov). TRANSMITTAL LETTER CHECKLIST WELL NAME: (� �} - ��,� (A PTD: Development Service _ Exploratory _ Stratigraphic Test Non -Conventional FIELD: �� / POOL: 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. 1$1- /J C7 API No. 50-]U- 0 0 - 0 0 - O 0 . v (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' 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 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 _ _ Well Name: KUPARUK RIV UNIT 31-1-221-1-04 Program SER Well bore seg d❑ PTD#: 2161490 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type SER / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑ Administration I17 Nonconven. gas conforms to AS3.1.05.030Q.1_.A),0.2.A-D) - - - NA_ 1 Permit -fee attached_ NA 2 Lease number appropriate_ Yes ADL0025531, Surf Loc; ADL0025523,Top_Prod _Intery & TD. 3 Unique well name and number - - Yes KRU 31-1-221-1-04_ 4 Well located in a_defined -pool - " Yes KUPARUK RIVER, KUPARUK-RIV OIL -.490100,"governed _by Conservation-Order_N_a. 432D. 5 Well located proper distance_ from drilling unit- boundary- - Yes CO 432D contains no spacing restrictions with respect to drilling unit boundaries. 6 Well located proper distance_ from_ other wells- Yes CO 432D has no interwell spacing_restrictions._ - - - - - - 7 Sufficient acreage available in.drilling unit- Yes _ 8 If deviated, is_wellboreplat.inc_luded 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 11/9/2016 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- Yes A10-2C-Kuparuk River Unit - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 15 All wells within _1/4_mile_area_of review identified (For service well only) Yes KRU 3H-22,_3H-22L1, 3H-22L101,_3H-31_ 16 Pre -produced injector: duration of pre production Less_ than 3 months (Forservice well only) Yes Well will be pre produced for less than 30 days. - 18 Conductor string -provided - - - - - - NA_ Conductor set_in motherbore 3H-22 - Engineering 19 Surface casing- protects all -known USDWs NA_ - - - - Surface casing_set and fully cemented in 3H-22 20 CMT_vol _adequate _tocirculate onconductor_&surf _csg- - - . . - - - - - - NA_ - - - - _ 21 CMT_vol_ adequate to tie -in -long string to surf csg_ - - - - N_A_ Setting 2.3/8" slotted" liner in the horizontal laterals.. 22 _C_MT_will coverall known -productive horizons_ Yes - - - 7"-production casing set.and porpoerly cemented. Cutting window -out of tubing tail._ 23 _Casing designs adequate for C,_T, B &_ permafrost_ Yes 24 Adequate tankage_ or reserve pit - - _ _ Yes Rig has steel pits. All waste to -approved disposal wells._ - 25 If -a_ re -drill, has_a 10-403 for abandonment been approved NA_ - - - - Motherbore will not.be P & A'd- ._ _ - _ _ _ _ _ - - - 26 Adequate wellbore separation Yes Anti -collision data provided. No issues._ _ _ _ " " " _ - _ _ " " " - " " - 27 If_diverter required, does it meet_ regulations_ NA_ " . " . _ Wellhead in place. -Will use CT BOPE - - - - _ - - - - Appr Date 28 -Drilling fluid_ program schematic-&- equip_list_adequate. ---------------- Yes . Max formation_ pressure =_4825 psi (1.5_ppg EMW) Will drill with 8.6ppg mud and -maintain BHP with MPD. GLS 11/14/2016 29 -BOPEs,_do-they meet regulation - - - - - - - - - - Yes - - - - - CDR2 has.5000 psi BOPE . . 30 _BOPE-press rating appropriate; test to_(put psig in comments). Yes - - _ _ _ - - MASP= 4206 psi -Will test BOPE to 4500 psi ( annular -to 2500 si 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 on_ pad._ Ri has_ sensors_ and a1_arms_. 9- - --- - - --------- -- - 34 Mechanical -condition of wells within AOR verified (Forservice well only) - Yes . - _ - _ - - AOR completed. -No-wells with_KUP A sand penetrations in-1/4 mile area - - - _ - _ - - 35 Permit can be issued w/o hydrogen_ sulfide measures - No" _ _ _ _ _ _ _ Wells_o_n_3H-Pad are_H2_S-bearing. H2S measures required. _ _ _ _ _ Geology 36 Data -presented on potential overpressure zones Yes . _ _ _ _ Maximum poten_tial_res_ervoir pr_ess_ure_ is 15.0 ppg_EMW;_wil[ be drilled_ using 8,6_ppg mud and_ MPD techn_ique._ Appr Date �37 Seismic_ analysis_ of shallow gas_zones_ - - - - NA- . _ _ _ _ - - - - - - - - - - PKB 11/9/2016 38 Seabed condition survey -(if off -shore) _ - _ _ NA_ - - - - - - - - - - - - - - - - - - 39 Contact.name/pho_ne for weekly_ progress reports_ [exploratory only] NA_ Onshore service well to be drilled. - - - - - Geologic Engineering Public 31-1-221-1-04 is the 5th lateral planned to target Kup A sand west of current motherbore BHL. GIs Commissioner: Date: Commissioner: Date Commissiacer Date