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Home My WebLink About216-146Guhl, 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 1-1-05, 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 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 31-1-22L 1-01 ConocoPhillips Alaska, Inc. Permit to Drill Number: 216-146 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.aiaska.gov Surface Location: 957' FNL, 282' FWL, Sec. 12, T12N, R8E, UM Bottomhole Location: 4679' FNL, 1188' 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, V/--� Daniel T. Seamount, Jr. ( 4-1- 1 Commissioner DATED this `) day of November, 2016. STATE OF ALASKA AL r A OIL AND GAS CONSERVATION COMM. _ i,1N PERMIT TO DRILL 20 AAC 25.005 13-1 V NOV 0 3 2016 1 a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas ❑ Service WAG ❑� Service Disp ❑ 1 c. Sdeci #'wE7P 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 Q Single Well ❑ 11. Well Name and Number: ConocoPhillips Alaska Inc Bond No. 59-52-180 KRU 31-1-221-1-01 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 11150' TVD: 6084' Kuparuk River Field/ Kuparuk Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 957' FNL, 282' FWL, Sec. 12, T12N, R8E, UM ADL 25523 ISSA Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 4248' FNL, 2159' FWL, Sec. 35, T13N, R8E, UM ALK 2559 12/5/2016 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4679' FNL, 1188' FWL, Sec. 35, T13N, R8E, UM 25,/ `,LO 10060' 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: 10,070' feet t 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) *07 Maximum Hole Angle: )OD 94 degrees Downhole: S 4 4 psig Surface: 10S 3 1 psig 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Qu ntity, c.f. or sacks Hole I Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7* L-80 ST-L 9815 6103 11150 6084 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' T' 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 0 Time v. Depth Plot ❑ Shallow Hazard Analysis El Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑� 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date a/ Z W4 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 jeff.s.connellyC_cop.com Printed Name G. Eller Title CTD Team Lead Signature Phone 263-4172 Date Z 1 Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: K I J 50- 3^ O0 — O Date: 1 I 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: XL(Sop 6 C Po / 2S Samples req'd: Yes ❑ No Mud log req'd: Yes ❑ No [V ¢ 5 /¢N.t ��✓ HZS measures: Yes [ No ❑ Directional svy req'd: Yes [WNo ❑ OO j /1Spacin exception req'd: Yes ❑ No V Inclination -only svy req'd: Yes ❑ No [✓� k � 'Cr— - tt t" 6re,✓' CAll� - C-c :^cV c..17 A %Q -2, C'-, Post initial injection MIT req'd: Yes ❑ No El Z6 AAC Z5.0/S�Cb> �ru> eta' ilt d(oc,, peLnl- A Q1"� PK 6 f -r bC APPROVED BY I I I Approved by: COMMISSIONER THE COMMISSION Date: l O 1R J ^ if NkLmonths Submit Form and Form 10-401 (Revised 11/201 e m 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: �,R_ _ i�C NOV 0 3 2016 ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill a hex@ -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-22L1-02, 3H-22L1- 03, 3H-22L1-04, and 3H-22L1-05), 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-2� 2L1-01, 3H-221_1-02, 3H-221_1-03, 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-221_1-04, 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, CIA 31-1-221-1-04, and 3H-221-1-05 2AC Application for Permit to Drill Document 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(t) 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 for3H-22L1, 3H-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-22L1, 3H-22L1-01, 3H-22L1-02, 3H-221_1-03, 3H-221_1-04, and 3H- 22 L 1-05............................................................................................................................................................................ 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-221_1-01, 3H-221_1-02, 3H-221_1-03, 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-221_1-01, 3H-22L1-02, 3H-221_1-03, 3H-221_1-04, and 3H-221_1- 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 3H-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: 3H-22L1, L1-01, L1-02, L1-03, L1-04, and L1-05. 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details V Lateral Liner Top Liner Btm Liner Top Liner Btm Liner Details Name MD MD TVDSS TVDSS 3H-22L1 10,070' 11,750' 6,036' 6,725' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 3H-22L1-01 9,815' 11,150' 6,028' 6,008' 2'/", 4.7#, L-80, ST-L slotted liner, - aluminum billet on top 31-1-221-1-02 9,900, 11,750' 6,037' 6,102' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 3H-22L1-03 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 31-1-221-1-05 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' 1 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: 31-1-221-1, 1-1-01, 1-1-02, U-03, 1-1-04, and 1-1-05. 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 b m) Pumps Off A -sand Formation Pressure (13.1 p) 4107 psi 4107 psi Mud Hydrostatic 8.6 2778 psi 2778 psi Annular friction i.e. ECD, 0.080 si/ft 777 psi 0 si Mud + ECD Combined 3555 psi 2778 psi (no choke pressure) (underbalanced —552 (underbalanced psi) —1329 psi) Target BHP at Window 13.1 pp 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 3'/z" 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 Al, 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- 22L1-02 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 A1, 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) 1 a. Kickoff 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. 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 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, L1-01, L1-02, L1-03, L1-04, and L1-05. c. Run 2%" slotted liner from TD up to 9765' MD. 3H-22L1-04 Lateral (A sand - west) a. Kick off of aluminum billet at 9,765 MD. b. Drill 3" bi-center lateral to TD of 11,750' MD. c. Run 2%" slotted liner from TD up to 9,815' MD. 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. Freeze protect. Set BPV, ND BOPS. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV. Pre -produce for less than 30 days 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: 3H-22L1, L1-01, 1-1-02, L1-03, L1-04, and L1-05. — While running 2%" slotted liner, a joint of 2%" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2%" rams will provide secondary well control while running 2%" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal." • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (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' 3H-22L1-05 11,075 — Distance to Nearest Well within Pool Lateral Name Distance Well 3H-22L1 1551' 3H-191_1 3H-22L1-01 1551' 3H-191-1 3H-22L1-02 1322' 3M-29 3H-22L1-03 1322' 3M-29 3H-22L1-04 1551' 3H-191_1 3H-22L1-05 1322' 31VI-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 3H-221-1, 3H-22L1-01, 3H-221-1-02, 3H-221-1-03, 3H-221-1-04, and 3H- 221-1-05 laterals Page 7 of 8 October 27, 2016 PTD Application: 3H-22L1, 1-1-01, 1-1-02, 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-22L1-02, 3H-221_1-03, & 3H-221-1-05 are planned at 1322' from 3M-29, 3M-29A, & 3M-29APB1, which is 2' outside of/4 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-22L 1-04, and 3H-22L 1-05 Page 8 of 8 October 27, 2016 `-11, ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 3H Pad 3H-22 3H-22L1-01 Plan: 31-1-221-1-01_wp01 Standard Planning Report 27 September, 2016 F i 2 Z Pl BAKER NUGHES ConocoPhillips Database: EDM Alaska NSK Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3H Pad Well: 3H-22 Wellbore: 3H-221-1-01 Design: 3H-22L1-01_wp01 ConocoPhillips Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3H-22 Mean Sea Level 3H-22 @ 76.00usft (3H-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: 1500 0' 39.411 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 3H-221-1-01 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°1 (nT) B G G M 2016 12/ 1 /2016 17.83 80.98 57,545 Design 31-1-221-1-01_wp01 Audit Notes: Version: Phase: PLAN Tie On Depth: 10,070.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 0.00 0.00 0.00 260.00 Plan Sections i 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) (°/1ooft) (°) Target 10,070.00 89.03 269.55 6,036.28 7,269.26 819.76 0.00 0.00 0.00 0.00 10,220.00 89.96 259.09 6,037.61 7,254.43 670.71 7.00 0.62 -6.97 275.00 10,350,00 89.17 250.02 6,038.60 7,219.84 545.55 7.00 -0.61 -6.97 265.00 10,450.00 84.68 244.64 6,043.97 7,181.39 453.46 7.00 -4.49 -5.38 230.00 10,550.00 90.75 241.15 6,047.97 7,135.88 364.57 7.00 6.07 -3.49 330.00 10,620.00 95.65 241.15 6,044.06 7,102.17 303.37 7.00 7.00 0.00 0.00 10,700.00 100.49 238.30 6,032.84 7,062.26 234.99 7.00 6.05 -3.56 330.00 10,770.00 98.01 234.02 6,021.58 7,023.79 177.63 7.00 -3.54 -6.12 240.00 10,850.00 92.74 232.10 6,014.09 6,975.94 114.00 7.00 -6.58 -2.39 200.00 11,000.00 90.89 242.44 6,009.32 6,895.01 -11.96 7.00 -1.24 6.89 100.00 11,150.00 89.96 252.90 6,008.21 6,838A0-150.51 7.00 -0.62 6.97 95.00 9/27/2016 4:30:57PM Page 2 COMPASS 5000.1 Build 74 ConocoPhillips Has ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska NSK Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3H Pad Well: 31-1-22 Wellbore: 3H-22L1-01 Design: 3 H-22 L 1-01 _wp 01 Planned Survey Measured TVD Below Depth Inclination Azimuth System (usft) V) (a) (usft) 10,070.00 89.03 269.55 6,036.28 TIP/KOP 10,100.00 89.21 267.45 6,036.74 10,200.00 89.83 260.48 6,037.57 10,220.00 89.96 259.09 6,037.61 Start 7 dls 10,300.00 89.47 253.51 6,038.01 10,350.00 89.17 250.02 6,038.60 3 10,400.00 86.92 247.34 6,040.31 10,450.00 84.68 244.64 6,043.97 4 10,500.00 87.71 242.89 6,047.29 10,550.00 90.75 241.15 6,047.97 5 10,600.00 94.25 241.15 6,045.79 10,620.00 95.65 241.15 6,044.06 6 10,700.00 100.49 238.30 6,032.84 7 10,770.00 98.01 234.02 6,021.58 8 10,800.00 96.04 233.30 6,017.92 10,850.00 92.74 232.10 6,014.09 9 10,900.00 92.13 235.55 6,011.96 11,000.00 90.89 242.44 6,009.32 10 11,100.00 90.27 249.42 6,008.31 11,150.00 89.96 252.90 6,008.21 Planned TD at 11150.00 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 Vertical Dogleg Toolface Map Map +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (usft) (usft) (°/100ft) V) (usft) (usft) 7,269.26 819.76 -2,069.60 0.00 0.00 6,007,968.81 499,476.72 7,268.48 789.78 -2,039.94 7.00 -85.00 6,007,968.03 499,446.74 7,257.98 690.40 -1,940.24 7.00 -84.97 6,007,957.55 499,347.36 7,254.43 670.71 -1,920.24 7.00 -84.91 6,007,954.00 499,327.68 7,235.49 593.02 -1,840.44 7.00 -95.00 6,007,935.07 499,250.00 7,219.84 545.55 -1,790.97 7.00 -94.97 6,007,919+44 499,202.52 7,201.68 499.00 -1,741.98 7.00 -130.00 6,007,901.29 499,155+98 7,181.39 453.46 -1,693.60 7.00 -129.91 6,007,881.01 499,110.44 7,159.34 408.71 -1,645.71 7.00 -30.00 6,007,858.97 499,065.69 7,135.88 364.57 -1,598.17 7.00 -29.88 6,007,835.52 499,021.55 7,111.78 320.83 -1,550.90 7.00 0.00 6,007,811.43 498,977.80 7,102.17 303.37 -1,532.04 7.00 0.00 6,007,801.82 498,960.35 7,062.26 234.99 -1,457.77 7.00 -30.00 6,007,761.93 498,891.97 7,023.79 177.63 -1,394.60 7.00 -120.00 6,007,723.48 498,834.61 7,006.15 153.65 -1,367+92 7.00 -160.00 6,007,705+84 498,810.62 6,975.94 114.00 -1,323.62 7.00 -160.09 6,007,675.64 498,770.97 6,946.46 73.68 -1,278.80 7.00 100.00 6,007,646.17 498,730.65 6,895.01 -11.96 -1,185.53 7.00 100.15 6,007,594.74 498,645.02 6,854.25 -103.20 -1,088.60 7.00 95.00 6,007,554.00 498,553.77 6,838.10 -150.51 -1,039+20 7.00 95.07 6,007,537.87 498,506.46 912712016 4:30:57PM Page 3 COMPASS 5000.1 Build 74 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 3H Pad 3H-22 3H-22L1-01 3H-22L1-01_wp01 Travelling Cylinder Report 14 September, 2016 Few Oi k I BAKER HUGHES - Baker Hughes INTEQ FIRM ConocoPhillips 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: 3H-22 Well Error: 0.00 usft Reference Wellbore 3H-22L1-01 Reference Design: 3H-22L1-01_wp01 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 (3H-22) True Minimum Curvature 1.00 sigma OAKEDMP2 Offset Datum teference 3H-22L1-01_wp01 alter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference nterpolation Method: MD Interval 25.00usft Error Model: ISCWSA )epth Range: 10,070.00 to 11,150.00usft Scan Method: Tray. Cylinder North tesults Limited by: Maximum center -center distance of 1,307.40 usft Error Surface: Elliptical Conic Survey Tool Program Date 9/14/2016 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 10,070.00 3H-22L1_wp04 (3H-22L1) MWD MWD - Standard 10,070.00 11,150.00 3H-22L1-01_wp01 (3H-22L1-01) MWD MWD- Standard Casing Points Measured Vertical Depth Depth (usft) (usft) 115.00 115.00 16" 4,348.00 3,127.05 9 5/8" 11,150.00 6,084.21 23/8" Summary Site Name Offset Well - Wellbore - Design Kuparuk 3H Pad 31-1-14 - 3H-14 - 3H-14 3H-14 - 3H-14A- 3H-14A 3H-14-3H-14APB1-3H-14APB1 3H-14 - 3H-1413 - 3H-14B 3H-14 - 3H-14BL1 - 3H-14BL1 3H-14 - 3H-14BL2 - 3H-14BL2 3H-14 - 3H-14BL3 - 3H-14BL3 3H-14 - 3H-14BL4 - 3H-14BL4 3H-17 - 3H-17 - 3H-17 3H-19 - 31-1-1911 - 3H-19L1_wp03 3H-19 - 31-l-191-1-01 - 3H-191-1-01_wp02 3H-19 - 31-1-1911-02 - 3H-19L1-02_wp01 3H-20 - 3H-20 - 31-1-20 3H-20 - 3H-201_1 - 3H-201_1 3H-20 - 3H-201_1-01 - 3H-201_1-01 3H-20 - 3H-201-1-01 PB1 - 3H-2011-01 P131 3H-20 - 3H-201-1-02 - 3H-201-1-02 3H-20 - 3H-2011-03 - 3H-2011-03 3H-20 - 3H-201-1-03PI31 - 3H-201-1-03P131 3H-20 - 3H-2011-04 - 3H-201-1-04 3H-20-3H-201-1-04PB1-3H-20L1-04PB1 3H-20 - 3H-2011-05 - 3H-20L1-05 3H-20 - 3H-2011-06 - 3H-20L1-06 31-1-21 - 3H-21 - 3H-21 31-1-22 - 3H-22 - 3H-22 Casing Hole Diameter Diameter Name 16 26 9-5/8 13-1/2 2-3/8 3 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 911412016 3:40:55PM Page 2 COMPASS 5000.1 Build 74 i Baker Hughes INTEQ rigs 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 (31-1-22) 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: 31-1-22 Survey Calculation Method: Minimum Curvature Well Error: 0.00 usft Output errors are at 1.00 sigma Reference Wellbore 31-1-221-1-01 Database: OAKEDMP2 Reference Design: 3H-221-1-01_wp01 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 31-1-22 - 31-1-221-1 - 31-1-221-1_wp04 10,075.00 10,075.00 0.02 0.35 -0.25 FAIL - Minor 1/10 31-1-22 - 31-1-221-1-02 - 31-1-221-1-02_wp02 Out of range 31-1-22 - 31-1-221-1-03 - 3H-221_1-03_wp02 Out of range 31-1-22 - 31-1-221-1-04 - 3H-22L1-04_wp02 10,075.01 10,075.00 0.00 0.83 -0.57 FAIL - Minor 1/10 31-1-22 - 31-1-221-1-05 - 3H-22L1-05_wp02 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 3H-34 - 31-1-34 - 31-1-34 Out of range 3H-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 31-1-34 - 31-1-341-1-01 PB1 - 31-1-341-1-01 PB1 Out of range 31-1-34 - 31-1-341-1-02 - 31-1-341-1-02 Out of range 31-1-34 - 31-1-341-1 PB1 - 31-1-341-1 PB1 Out of range Offset Design Kuparuk 3H Pad - 31-1-22 - 31-1-221-1 - 3H-22L1_wp04 Offset Site Error: 0.00 usft Survey Program: 100-GCT-MS, 9700-MWD Rule Assigned: Minor 1110 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 +NIS +E/-W Hole Size Centre Distance Deviation (usft) (usft) (usft) (usft) (usft) (usft) M (usft) (usft) (") (usft) (usft) (usft) 10,075.00 6,112.36 10,075.00 6,112.35 0.03 0.01 -43.30 7,269.22 814.76 2-11116 0.02 0,35 -0.25 FAIL- Minor 1/10, CC, ES, SF 10,099.98 6,112.74 10,100.00 6,112.24 0.16 0.06 -45.03 7,269.03 789.76 2-11116 0.74 0.47 0.37 Pass- Minor 1110 10,124.89 6,113.05 10,125.00 6,111.36 0.18 0.12 -46.79 7,268.83 764.78 2-11116 2.49 0.59 202 Pass- Minor 1110 10,149.65 6,113.29 10,150.00 6,109.72 0.20 0.18 -48.57 7,268.63 739.84 2-11/16 5.27 0.70 4.71 Pass - Minor 1/10 10,174.22 6,113.46 10,175.00 6,107.33 0.22 0.24 -50.37 7,268.43 714.95 2-11/16 9.05 0.82 8.40 Pass - Minor 1/10 10,198.53 6,113.57 10,200.00 6,104.17 0.25 0.31 -52.18 7,268.24 690.16 2-11/16 13.84 0.92 13.11 Pass - Minor 1/10 10,222.52 6,113.61 10,225.00 6,100.28 0.28 0.39 -53.96 7,268.03 665.46 2-11/16 19.59 1.03 18.77 Pass - Minor 1/10 10,246.28 6,113.66 10,250.00 6,096.60 0.32 0.46 -54.65 7,267.57 640.74 2-11116 25.55 1.12 24.63 Pass- Minor 1/10 10,269.91 6,113.78 10,275.00 6,093.58 0.37 0.55 -54.47 7,266.73 615.94 2-11/16 31.38 1.22 30.37 Pass- Minor 1/10 10,293.38 6,113.95 10,300.00 6,091.21 0.42 0.64 -53.79 7,265.50 591.08 2-11/16 37.13 1.29 36.03 Pass- Minor 1110 10,316.68 6,114.18 10,325.00 6,089.50 0.47 0.73 -52.81 7,263.89 566.19 2-11/16 42.85 1.37 41.65 Pass - Minor 1110 10,339.78 6,114.46 10,350.00 6,088.46 0.53 0.83 -51.62 7,261.91 541.29 2-11/16 48.59 1.42 47.30 Pass - Minor 1/10 10,362.61 6,114.85 10,375.00 6,088.07 0.60 0.93 -50.15 7,259.54 516.41 2-11/16 54.40 1A7 53.04 Pass - Minor 1/10 10,385.25 6,115.60 10,400.00 6,087.91 0.66 1.04 -49.23 7,256.53 491.59 2-11/16 60.31 1.50 58.90 Pass - Minor 1/10 10,40T79 6,116.75 10,425.00 6,087.78 0.73 1.15 -49.06 7,252.77 466.88 2-11116 66.26 1.52 64.83 Pass - Minor 1/10 10,430.22 6,118.29 10,450.00 6,087.67 0.80 1.26 -49.46 7,248.25 442.29 2-11116 72.21 1.53 70.77 Pass - Minor 1/10 10,452.74 6,120.22 10,475.00 6,087.59 0.87 1.38 -50.25 7,242.99 417.85 2-11/16 78.12 1.55 76.70 Pass - Minor 1110 10,476.89 6,122.09 10,500.00 6,087.52 0.96 1.50 -50.76 7,236.98 393.59 2-11116 83.66 1.54 82.29 Pass - Minor 1/10 10,501.14 6,123.34 10,525.00 6,087.45 1.04 1.62 -51.07 7,230.24 369.52 2-11/16 88.58 1.54 87.33 Pass- Minor 1110 10,525.44 6,123.97 10,550.00 6,087.38 1.12 1.74 -51.19 7,222.76 345,66 2-11116 92.91 1.53 91.86 Pass- Minor 1/10 10,550.00 6,123.97 10,575.00 6,087.31 1.21 1.87 -51.15 7,214.56 322.05 2-11116 96.66 1.51 96.23 Pass - Minor 1110 10,575.65 6,123.23 10,600.00 6,087.24 1.30 2.00 -50.05 7,205.64 298.69 2-11/16 99.63 1.48 99.19 Pass- Minor 1110 10,601.58 6,121.67 10,625.00 6,087.17 1.40 2.13 -48.75 7,196.01 275.62 2-11/16 101.66 1.48 101.21 Pass - Minor 1/10 10,626.99 6,119.35 10,650.00 6,087.10 1.49 2.26 -47.49 7,185.69 252.86 2-11/16 102.78 1.46 102.31 Pass - Minor 1/10 10,651.12 6,116.49 10,675.00 6,087.01 1.59 2.39 -46.68 7,174.67 230.41 2-11/16 103.32 1.45 102.85 Pass - Minor 1/10 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 911412016 3:40:55PM Page 3 COMPASS 5000.1 Build 74 W •IM_ lz � y alco pr--: J M O O t2 m d ti (O Q , N 0 Y C c c a n p o U) V' N CDN mcD O1-CO CO Ll�N 47Z W m C) p M c0 N 1— V M c n m > NmmmMLomN co -Oy Nmr—co In 4)V MO CV (O V N O ClO O O O O O O O O N J N U p 0 0 0 0 0 0 0 0 0 0 Q j j C i 0 0 0 0 0 _ LL 1�(OMM MCOOm C `") N N N M C) C V N m 0 Cl O O O O O p 0 0 0 0 N O O O p O O O O O O O �tD� cn cD I� �m C)O cO �"'d' cf)M mcOOm cL'J w OiO m I—V.-O mLo C� } a0 c0 c�fJ V'MMN�� Y'J (J Luyc) UJ cOM�ma01`cOm V �O Q (M CO NNN f")c0 c-N r- m0 � W C Z m v m c n N N M c0 cCJ COS OcON 1�mM } Z7, N N O O m c 0 a 0 J J w co mIRp 1� � c0-R W mN co N c 0 c 0 m m 0 e 0 c /) O M N m1— 0co IS O m i -'r" d'm a0 C _ = CO > c `7 M M t `d' �' Cl) c V 0 0 O O O O O Cl O Cl O O O ~ (D m (O O O c0 c0 cp cD c0 c0 Z' ' N[] m N V c l' ] O N O V O -.:I- Q c g O O c 0 •- M O V m m N N N N N N N N N N N N N N U MCD i� 0�V mc0 C O m � c R 0 1- "RD V O 1- a 0 m W W CD W N O M O O O +LLJ 0 0 0 0 0 0 0 0 0 0 0 iE 0 0 0 0 0 0 0 0 0 0 0 O O O 6 6 6 O O 6 O O 1 N i t cn N O 1 c p c O N M V c D 1.-n a 0 O 0 0 0 0 0 0 0 0 0 �O O UM V ci'Jm tiOOmO.- d) Zo + (ui/gsn 09) gldaQ ieailian awL KUP INJ 3H-22 conocomillips Well Attributes Max Angle & MD TD Alaska. Inc. Wellb- APIMINI Field Name Wellbore Status ncI C) MD (ftKB) 501032009700 KUPARUK RIVER UNIT INJ 60.15 5,100.00 Act Btm (ftKB) 10,234.0 .. Comment 112S (ppm) I Date SSSV: None Annotation End Dale KE rE Last WO: 3/20/2016 (ft) Rig Release Date 42.01 2/28/1988 3H-22,101]20163:42:55 PM Vertical schemaae(actual) Annotation Depth (ftKB) End Dat¢ Annotation Last Mad By End Data Last Tag: SLM 9,803.0 5/26/2016 Rev Reason: SET WHIPSTOCK ppmven 10/7/2016 HANGER; 35.0 VT Casing Strings Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD)... Wt/Len (I... Grade Top Thread CONDUCTOR 16 15.062 36.0 115.0 115.0 62.50 H-40 WELDED Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD)... WVLen (I... Grade 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 (ftKB) Set Depth IRK'Set Depth (TVD)... WtlLen (I... Grade Top Thread PRODUCTION 7 6.276 35.0 10,052.2 6,267.8 26.00 J-55 ETC Tubing Strings Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (6% Sol Depth (TVD) (... Wt pblfl) Gmde Top Connection )2 TUBING RWO 201E 3 1/2 992 35.0 9,586.8 5,984.E 9.30 L-80 EUE Srd Mod corvoucroR: 3s.0-n50 Completion Details Nominal ID Top (ftKB) Top (TVD) (ftKB) Top Ind (°) Item Des Co. (in) GAS LIFT: 3,246.3 35.0 35.0 0.09 HANGER McEvoy Gen III Tubing Hanger, MSDP-1-6.5-MS-3, 1116" 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 5,977.6 52.65 SEAL ASSY Seal Assembly, 80-40 3.020 Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (ft.. Set Depth (TVD) (... Wt (IbHI) Grade Top Connection LOWER COMP RWO 4112 3.958 9, 578.3 9,736.0 6,075.3 12.60 L-80 STC 201E Completion Details SURFACE; 35.0-4,347 6- Nominal ID Top (ftKB) Tap (ND) (ftKB) Top Inc] (°) Item Des Com (in) 9,578.3 5,979.4 52.65 PACKER 587-400 Model Production Packer 4.000 . GAS LIFT; 5,5989 9,581.6 5,981.4 52.64 SEE 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 3-1/2" EUE 8rd 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, 3-1/2" EUE 8rd Mod Box x 4-1/2" STC 2.992 CROSSOVER Pin GAS LIFT; 7,260.2 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 Com Run Date ID (in) 9,715.0 6,062.5 52.52 WHIPSTOC BAKER 3.5"X4.5" WHIPSTOCK(GENII DELTA). 10/612016 GAS LIFT; 8,576 a 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; 9,51T2 Dens Top (TVD) Bum (TVD) (she Top (ftKB) Bum IRKS) (ftKB) (ftKB) Zone Date t) Type Com 9,690.0 9,710.0 6,047.3 6,059.4 A-3, 31-1-22 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, 31-1-22 8/11/1988 8.0 APERF 2 1/8 EnerJet; 60 deg ph LOCATOR', 9,5742 9,754.0 9,774.0 6,086.2 6,098.4 A-1, 31-1-22 4/25l1988 4.0 IPERF SOS 4.5" Ultra P; 120 deg ph PACKER; 9,578.3 Mandrel Inserts SEAL ASSY; 9,575.3 Sl SBE ; 9,581.E ati N Top (ft(B) Top (ND) (ftKB) Make Motl¢I OD (in) Sery Valve Type Latch Type Port Size TRO (in) (psi) Run Run Date Com 1 3,246.3 2,509.1 Camco MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 3119/2016 xO Reducing; 9,591.0 2 5,598.9 3,802.4 Camco MMG 1 11 GAS LIFT DMY RK 0.000 0.0 3/19/2016 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 Camco MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 31191201E 5 9,517.3 5,942.4 Camco MMG 1 112 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 0=6.45"; Tested to 2600psi w/10 ppg Brine. 11/2/2010 NOTE: View Schematic w/ Alaska Schematic9.0 PORTED CROSSOVER; 9,651.6 PORTED W EARSOx; 9,653.4 APERF; 9,690.0-9,]10.0- W HIPSTOC, 9, 7150 APERF; 9 716.0-9, 736,0 IPERF; 9,754.0-9,774.0- PRODUCTION; 350-10 052 2 U O O7 Q F- -O co W W CD OP J N co ci c� G U U) U M O N O 0- 0 d CV N M (D Q co 76 co N LO C O CO � (6 > 0 M — E0 N 2 N N a cu N X 61 ^ a M 6) O10 (O N rn `o C � C a� V) (0 4-5 rn _ C_ (u _L OU d� N O N a_ U O Y N 00 C m C H E r m Lr) oS dp W N .o m Um o(Lao 2 m N(D V Y Y v N O N O m (0 C)(l- JCOm m V'v 04 0 L L O N r c Cl) VV O 0 n N N O U1 N � N p\ N G Ul N @ C� N V .- m J 1 M F J p\ O N V M J V _ ❑ C M F Q '1 II I O o � " O a o g 3 C, 3 0 N�� '�1 N 00 o� m o m C? CL — 0 l�l0 N� II II Iir N V� J O N N I I I I 2 0 C = C I I M F J = Q C M ! J lil I'1 i i I I h I� I � � l i 11 11 11 �1 1 II i ICI 1 I'It 1� 11 '� 1' 11 11' 111 II II 11 1; I�% i N 'D IIi ICI 111I O o N oa o N � ❑ ink o cl) M 1 N N .-- M a0 W OCM] O^1 OniT 'N It m 0 a zo v m o O N V N m N M N Q Q Q Q W W � we `M_ f� �,a 0 0 c 0 V (U?/Usn Ogg) (+)uljoN/(-)glnog C 0 W H i W �kilz We wo m Y Y 41 o ' V O r r - b. �1 -LI O n � O - N N o 2 ar ' a o w dmm m m m - w uw E2 c2 p m m p u � N Nam. r N N _ O Q W NO � 1 N ir - o I c O m O c a�m�te�l O Q - O vt �ma� sd �mo�o 0 I o a ^ O b 7 9 J m M N ;v r. ^ a - o5 o 0 O N N m (v V N O O tA Y! i N o W o0 o 0 0 0 0 0 0 0 0 0 o a o 0 0 0 0 O O Or P m m V (ui/gsn OOZ) (+)uljoN/(-)ulnoS m W 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 3H-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 31-1-22, 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 TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD:�, Development Service _ Exploratory Stratigraphic Test _ Non -Conventional FIELD: K� i V / POOL: U&r V<J— Cr/ 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. _JgJ?— (f 0 , API No. 50- I O 3 - C7� o q ? - G'Q- 00 (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 on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a 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 3H-22L1-01 _ Program SER _ - _ Well bore seg ❑d PTD#: 2161460 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type SER / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven. gas conforms to AS31.05.0304.1_.A),(j.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_n_ame-and number Yes . KRU 3H-22L1-01_ 4 Well located in a_defined_pool _ Yes KUPARUK RIVER,_ KUPARUK_ RIV OIL - 4901.00,_governed _by Conservation. Order No. 43.2D._ 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_we_llbore plat -included Yes _ 9 Operator only affected party Yes Wellb_ore will be more than 500' from an external property line where_ ownership or landownership changes. I10 Operator has -appropriate_ bond in force Yes Date Appr Date 11 Permit- can be issued -without conservation order Yes 12 .Permit. can be issued -without administrative Yes PKB 11 6 -approval 13 Can permit be approved before 15-day_wait Yes 14 Well.located within area and -strata authorized by Injection Order# (put_10# incomments)-(For Yes AIO.2_C-Kuparuk River. Unit_ ----- -------------------- 15 All wells within _1/4_mile.area of review identified (For service well only) Yes KRU 3H-22,_3H-2.21_1_ 16 Pre -produced injector: duration of pre production less than 3 months (Forservicewell only) Yes Will pre -produce for Less_ than_ 30_d_ays. 18 Conductor string -provided NA_ Conductor set_ in Motherbore 3H-22 . _ Engineering I19 Surface casing _ protects all -known- USDWs NA_ Surface casing set and fully_ cemented in 3H-22_ 20 CMT_vol adequate -to circulate -on conductor & surf csg NA_ 21 CMT_v_ol_ adequate to tie-in long string to -surf csg NA_ 7"_production casing _propoerly cmented ._ - -- - - ------ - - - - - - - - - 22 CMT_will cover -all known -productive horizons_ Yes . Sett_ing 2 3/8" sl_otted_Iiner_in the lateral wellbores.. 23 -Casing designs adequate for C,_T, B &_ permafrost_ Yes - 24 Adequatetankageor reserve pit Yes 25 If_a_ re -drill, has a 1.0-403 for abandonment been approved NA_ Motherbore not P_& A 'd_ Did RWO to run new completion with oversize_tubin tial for whipstock._ - - - - - - - - 26 Adequate wellbore separation proposed- Yes - . an_ticollision data provided_.. No issues.- . 27 If_diverter required, does it meet_ regulations_ NA- Wellhead in place. BOPE will be used- Appr Date 28 Drilling fluid_ program schematic-&- equip_list_adequate_ Yes - - - - - - Max formation. pressure = 4825 psi (15 ppg EMW) Will -drill with 8.6 ppg_mud_and maintain_ BHP with-MPD GLS 11/14/2016 29 _B_OPEs,_do they meet regulation Yes . CDR2 has 5000 psi BOPE - 30 BOPE-press rating appropriate; test to -(put psig in comments)- Yes MASP = 4205_p5i_ Will_test BOPS _to 4500-psi_ 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 112S on pad-. Rig -has sensors and alarms. 34 .Mechanical_condition of wells within AOR verified (For service well only) Yes AOR completed/ _No -wells ith KUP A san_d_penetr_atio_ns in_ 1/4 Wile area. 35 Permit can be issued w/o hydrogen. sulfide measures No Wells Wells. on-3H Pad are H2S-bearing, H2S _measures _required . Geology 36 Data. presented on_ potential overpressure zones - - - - - - - - - - - - - - -Yes - - - - - _Maximum potential reservoir pressure 15.0 ppg_EMW;_will be drilled using 8,6_ppg mud and-MPDtechnique. Appr Date 37 Seismic analysis_ of shallow gas_zones_ NA_ PKB 11/9/2016 38 Seabed condition survey -(if off -shore) NA_ _ _ - - - _ I39 Contact name/phone for weekly- progress reports_ [exploratory only] - - - - - - - N_A_ - _ _ - _ _ - Onshore service well_to be drilled. - . - - - - - - - - Geologic Engineering Public 3H-22L1-01 is second lateral planned. Will be drilled west of current motherbore BHL. Targeting Kup A sand. GIs ,--Commissioner: Date Commissioner: Date Commis ' er Date