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Home My WebLink About216-117Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Monday, November 26, 2018 9:39 AM To: Phillips, Ron L Cc: Loepp, Victoria T (DOA); Boyer, David L (DOA) Subject: KRU 2X-13 L1-04, L1-05, PTDs 216-117 and 216-119, Permits Expired Hello Ron, 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 2X-13 L1-04, PTD 216-117, Issued 23 September 2016 • KRU 2X-13 1-1-05, PTD 216-119, Issued 23 September 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. TIDE STATE 0f L S KA GOVERNOR BILL WALKER J. Ohlinger CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2X-13L1-04 ConocoPhillips Alaska, Inc. Permit to Drill Number: 216-117 Surface Location: 1229' FSL, 238' FEL, Sec. 4, TI IN, R9E, UM Bottomhole Location: 3690' FSL, 3042' FEL, Sec. 3, TI IN, R9E, UM Dear Mr. Ohlinger: Alaska Oil and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Enclosed is the approved application for permit to drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 184-174, API No. 50-029- 21197-00-00. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy . Foerster Chair DATED this 2 3 day of September, 2016. STATE OF ALASKA AL .A OIL AND GAS CONSERVATION COMM[ JN PERMIT TO DRILL SEP082016 20 AAC 25.005 a(1(;r , , 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 2X-131_1-04 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 11,300' TVD: 6,018'. Kuparuk River Field Kuparuk Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 1229' FSL, 238' FEL, Sec. 4, T11 N, R9E, UM ADL 25645 , Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 3635' FSL, 1085' FEL, Sec. 3, T11N, R9E, UM ALK 2576 11/1/2016 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 3690' FSL, 3042' FEL, Sec. 3, T11N, R9E, UM 2560 • 36,960' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 112 15. Distance to Nearest Well Open Surface: x- 518889 y- 5,971,233 Zone- 4 • GL Elevation above MSL (ft): 77 to Same Pool: 2X-17, 870' 16. Deviated wells: Kickoff depth: 9,150 feet • 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 97' degrees Downhole: 2,670 prig , Surface: 2,066 psig 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling I Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7# L-80 ST-L 2,400' 8,900, 5,997' 11,300' 6,018' slotted liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 8,539' 6,187' none 8,428' 6,108' 8,428' Casing Length Size Cement Volume MD TVD Conductor/Structural 66' 16" 260 sx Cold set II 103' 103' Surface 3,711' 9-5/8" 900 sx CS III & 650 sx CS II 3,747' 3,030' Production 8,476' 7" 315 sx Class G 8,510' 6,163' Perforation Depth MD (ft): 7970'-8060', 8214'-8240', 8248'-8288' Perforation Depth TVD (ft): 5779'-5845', 5956'-5975', 5981'-6009' 7719'-7729' 20. Attachments: Property Plat BOP Sketch ❑ Drilling Program 0 Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program �✓ 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not R. Phillips @265-6312 be deviated from without prior written approval. Contact Email ron.l.phillips(aDcop.com Printed Name J.Ohlinger Title CTD Engineering Supervisor Signature Phone 265-1102 Date Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: 50- Qa —p21 — 3 —v0 Date:—Z2j—� 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: Q U 6) Samples req'd: Yes ❑ No[� Mud log req'd: Yes ❑ No H2S measures: Yes Z No ❑ Directional Yes 2"No ❑ �z5�` svy req'd: /iv�nvla��rcvch fz� Spacing exception req'd: Yes No Inclination -only svy req'd: Yes ❑ No [/r /�U tU Z n r Post initial injection MIT req'd: Yes El No❑y n e Zf �6 Z 0,4,1 C Z 57-, b t S c/ b > car f-c C1 to R bl o t v t-PT -r I- k� < any Poet 1( $11 (;' �hz pk✓rIt Z�ttt-ka- . c/ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: ,Z3 YW4 ��ly Submit Form and Form 10Ao1 (Rev 1 015) Th �`affdFN t s from the date of approval (20 AAC 25.005(g►) Attachments in Duplicate ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 September 7, 2016 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: RECEIVED SEP082016 ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill six laterals out of the newly worked over Kuparuk well 2X-13 well using the coiled tubing drilling rig, Nabors CDR2-AC or Nabors CDR3-AC. 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. The work is scheduled to begin November 3, 2016. The objective will be to drill laterals KRU 2X-131-1, 2X-131-1- 01, 2X-131-1-02, 2X-131-1-03, 2X-131-1-04 and 2X-131-1-05 targeting the Kuparuk A -sands. Attached to this application are the following documents: — 10-401 Applications for 2X-131-1, 2X-131-1-01, 2X-131-1-02, 2X-131-1-03, 2X-131-1-04 and 2X-131-1-05 — Detailed Summary of Operations — Directional Plans for 2X-131-1, 2X-131-1-01, 2X-131-1-02, 2X-131-1-03, 2X-131-1-04 and 2X-131-1-05 — Proposed CTD Schematic If you have any questions or require additional information, please contact me at 907-265-6312. Sincerely, �� --). Pig, Ron Phillips ConocoPhillips Alaska Coiled Tubing Drilling Engineer Kuparuk CT® Laterals �NASOASALASKA 2X-1311-1, 2X-1311-1-01, 2X-131-1-02, 2X-1311-1-03, 2X-13L1-04 & 2X-1311-1-05 Application for Permit to Drill Document 2RC 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))................................................................................................................... 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2)).... ............................................. ............................... ........................................ - ........ ....... ......... 2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 2 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7)).................................................................................................................................................. 3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9))...................................................................-............................................................................. 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4 11. Seabed Condition Analysis............................................................................................................4 (Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................ 4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005 c 12........................................................ 4 13. Proposed Drilling Program.............................................................................................................4 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................6 14. Disposal of Drilling Mud and Cuttings.......................................................................................... 6 (Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 6 15. Directional Plans for Intentionally Deviated Wells....................................................................... 7 (Requirements of 20 AAC 25.050(b))................................................................................................................................-.................... 7 16. Attachments.................................................................................................................................... 7 Attachment 1: Directional Plans for 2X-131-1, 2X-13L1-01, 2X-13L1-02, 2X-13L1-03, 2X-131-1-04 and.........................7 2X-13L1-05 laterals..........................................................................................................................................................7 Attachment 2: Current Well Schematic for 1 L-13............................................................................................................7 Attachment 3: Proposed Well Schematic for 2X-131-1, 2X-131-1-01, 2X-131-1-02, 2X-13L1-03, 2X-13L1-04..................7 & 2X-131-1-05 laterals......................................................................................................................................................7 Page 1 of 7 March 8, 2016 PTD Application: 2X-13L1, 2X-13L1-01, 2X-13L1-02, 2X-1311-1-03, 2X-1311-1-04 & 2X-1311-1-05 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 2X-131-1, 2X-13L1-01, 2X-131-1-02, 2X-131-1-03, 2X- 131-1-04 and 2X-131-1-05. All laterals will be classified as "Development -Oil" wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 forms for surface and subsurface coordinates of the 2X-131-1, 2X-131-1-01, 2X-131_1-02, 2X-131-1-03, 2X-131-1-04 and 2X-131-1- 05 laterals. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR2-AC and CDR3-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 3,000 psi. Using the maximum formation pressure in the area of 2,670 psi in 1Y-13 (i.e. 8.5 ppg EMW), the maximum potential surface pressure in 2X-13, assuming a gas gradient of 0.1 psi/ft, would be 2,066 psi.-' See the "Drilling Hazards Information and Reservoir Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2,500 psi. 4. Drilling Hazards Information and Reservoir Pressure (Requirements of 20 AAC 25.005 (c)(4)) Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005 (c)(4)(a)) The formation pressure in KRU 2X-13 was measured to be 2,136 psi (6.9 ppg EMW) on 2/2/2016. All of the wells in the 2X-13 vicinity are between 6.9 ppg and 8.6 ppg. The combined A and C sand SBHP readings suggest pressures will be close to 7.5 ppg. The maximum downhole pressure in the 2X-13 vicinity, is the 1Y-13 at 2,670 psi or 8.5 ppg EMW. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) The offset injection wells to 2X-13 have injected gas, so there is a chance of encountering free gas while drilling the 2X-13 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 2X-13 laterals will be shale instability across faults. Managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossings. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 2X-13 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity test is not required. Page 2 of 7 September 7, 2016 PTD Application: 2X-13L1, 2X-131_1-01, 2X-13L1-02, 2X-13L1-03, 2X-13L1-04 & 2X-13L1-05 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Lateral Name Liner Top Liner Btm Liner Top Liner Btm Liner Details MD MD TVDSS TVDSS 2X-131_1 9,200' 11,250' 5,898' 5,949' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 2X-13L1-01 9,150' 11,300' 5,894' 5,912' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 2X-13L1-02 8,800' 11,080' 5,885' 5,903' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 2X-131_1-03 8,750' 11,050' 5,887' 5,858' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 2X-13L1-04 8,900' 11,300' 5,885' 5,906' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 2X-131_1-05 8,160' 11,050' 5,805' 5,847' 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 37' 103' 37' 103' 1,640 670 Surface 9-5/8" 36 J-55 BTC 36' 3,747' 36' 3,030' 3,520 2,020 Production 7" 26 J-55 BTC 34' 8,510' 34' 6,167' 4,980 4,320 Tubing 3-1/2" 9.3 L-80 EUE 31' 8,181' 31' 5,933' 10,160 10,540 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) Nabors CDR2-AC or CDR3-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 or CDR3-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)./While this mud weight will hydrostatically overbalance the reservoir pressure, overbalanced conditions will also be maintained using MPD practices described below. - Completion operations: CTD will utilize an Orbit valve for formation isolation while running liner. In the event of an Orbit valve failure 11.4ppg NaBr completion fluid will be utilized to provide formation over- balance and well bore stability while running completions. Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000 psi rated coiled tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". Page 3 of 7 September 7, 2016 PTD Application: 2X-1311-1, 2X-1311-1-01, 2X-13L1-02, 2X-13L1-03, 2X-13L1-04 & 2X-1311-1-05 In the 2X-13 laterals we will target a constant BHP of 11.4 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. Pressure at the 2X-13 Window (8165' MD, 5921' TVD) Usinq MPD Pumps On (1.5 bpm) Pumps Off A -sand Formation Pressure 6.9 2124 psi 2124psi' Mud Hydrostatic 8.6 2648 psi 2648 psi Annular friction i.e. ECD, 0.080 si/ft 653 psi 0 psi Mud + ECD Combined (no choke pressure) 3301 psi overbalanced —1177psi) 2648 psi overbalanced —524psi) Target BHP at Window (11.4 pp) 3510 psi 3510 psi Choke Pressure Required to Maintain Target BHP 209 psi 862 psi 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005(c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005(c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A - Application is for a land based well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well 2X-13 was originally drilled and completed in 1984 as a Kuparuk A -sand producer. The A -sand was stimulated with a fracture treatment in September 1988. In October 1990, the upper completion was pulled and replaced to perforated the Kuparuk C-sand. A Rig Work Over was performed in September 2016 to fix these issues: January 2016 the IC Packoffs failed, a known tubing leak at 8059'and subsidence related helically buckled tubing found in June of 2016. The 3-1/2" selective completion was replaced, the permanent tubing patch removed, IC packoffs replaced and the 7" casing was allowed to grow. Prior to CTD operations, a whipstock will be set with E-line. Nabors CDR2-AC will mill a 2.80" window off the whipstock at 8165'. Six laterals will be drilled: three to the west and three to the east of the parent well with the laterals targeting the Kuparuk A4 and A3 sands. All laterals will be completed with 2-3/8" slotted liner from TD with the last lateral liner top located inside the 3-1/2" tubing tail. Page 4 of 7 September 7, 2016 PTD Application: 2X-13L1, 2X-13L1-01, 2X-13L1-02, 2X-13L1-03, 2X-13L1-04 & 2X-13L1-05 Pre-CTD Work 1. Perform RWO to install new 3-1/2" tubing, Orbit valve and packers. 2. RU Slickline: Pull sheared out SOV. Perform a dummy whipstock drift. Set a tubing tail plug. 3. RU E-line: Set 3-1/2" Northern Solutions Whipstock in tubing tail at 8165'. 4. Prep site for Nabors CDR2-AC or CDR3-AC and set BPV. 1. MIRU Nabors CDR2-AC or CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 2X-13L1 Lateral (A3 sand - West) a. Mill 2.80" window at 8165' MD. b. Drill 3" bi-center lateral to TD of 11,250' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 9200' MD. 3. 2X-13L1-01 Lateral (A4 sand- West) a. Kick off of the aluminum billet at 9200' MD. b. Drill 3" bi-center lateral to TD of 11,300' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 9150' MD. 4. 2X-13L1-04 Lateral (A4 sand - West) / a. Kick off of the aluminum billet at 91�.' MD. b. Drill 3" bi-center lateral to TD of 11,300' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 8900' MD. 2X-13L1-02 Lateral (A3 sand - East) a. Kick off of the aluminum billet at 8900' MD. b. Drill 3" bi-center lateral to TD of 11,080' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 8800' MD. 6. 2X-13L1-03 Lateral (A4 sand - East) a. Kick off of the aluminum billet at 8800' MD. b. Drill 3" bi-center lateral to TD of 11,050' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 8750' MD. 7. 2X-13L1-05 Lateral (A4 sand- East) a. Kickoff of the aluminum billet at 8750' MD. b. Drill 3" bi-center lateral to TD of 11,050' MD. c. Run 2%" slotted liner from TD up into the tubing at 8160' MD. 8. Freeze protect, set BPV, ND BOPE, and RDMO Nabors CRD2-AC or CDR3-AC. Post -Rig Work 1. Pull BPV. 2. Obtain SBHP. 3. Install GLV's . 4. Return to production. Page 5 of 7 September 7, 2016 PTD Application: 2X-13L1, 2X-13L1-01, 2X-13L1-02, 2X-13L1-03, 2X-13L1-04 & 2X-13L1-05 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 2X-13 well has a deployment valve installed. It will serve to deploy liners into the newly drilled laterals. If the valve fails, the laterals will be displaced to an overbalance completion fluid (as detailed in Section 8 "Drilling Fluids Program") prior to running liner. — 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). Page 6 of 7 September 7, 2016 PTD Application: 2X-13L1, 2X-131-1-01, 2X-13L1-02, 2X-13L1-03, 2X-13L1-04 & 2X-13L1-05 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 Plans — 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 2X-131-1 36,960' 2X-131-1-01 36,960' 2X-1311-1-02 35,376' 2X-13L1-03 35,376' 2X-131-1-04 36,960' 2X-13L1-05 35,376' — Distance to Nearest Well within Pool Lateral Name Distance Well 2X-13L1 870' 2X-17 2X-13L1-01 870' 2X-17 2X-13L1-02 1290' 2X-14 2X-131-1-03 1290' 2X-14 2X-131-1-04 870' 2X-17 2X-131-1-05 1290' 2X-14 16. Attachments Attachment 1: Directional Plans for2X-13L1, 2X-13L1-01, 2X-13L1-02, 2X-13L1-03, 2X-13L1-04 and 2X-13L 1-05 laterals. Attachment 2: Current Well Schematic for 1 L-13 Attachment 3. Proposed Well Schematic for 2X-13L1, 2X-13L1-01, 2X-13L1-02, 2X-13L1-03, 2X-13L1-04 & 2X-13L1-05laterals. Page 7 of 7 September 7, 2016 COCIt)C6lP'YIlfip5 ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2X Pad 2X-13 2X-13L1-04 Plan: 2X-13L1-04 wp01 Standard Planning Report 07 September, 2016 Few P kP"-- I BAKER HU6HE5 Conoco,illips Database: OAKEDMP2 Company: ConocoPhillips (Alaska) Inc, -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2X Pad Well: 2X-13 Wellbore: 2X-13 L 1-04 Design: 2X-13 L1-04_wp01 Baker Hughes INTEQ Planning Report Local Co-ordinate Reference: Well 2X-13 TVD Reference: Mean Sea Level MD Reference: 2X-13 @ 112.00usft (2X-13) North Reference: Grid Survey Calculation Method: Minimum Curvature Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk 2X Pad Site Position: Northing: From: Map Easting: Position Uncertainty: — 0.00 usft Slot Radius: Well 2X-13 Well Position +N/-S 0.00 usft Northing: +E/-W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: Wellbore 2X-131-1-04 Magnetics Model Name Sample Date BGGM2016 12/1/2016 Design 2X-131-1-04_wp01 Version: Phase: Vertical Section: Depth From (TVD) (usft) 0,00 Survey Tool Date 8/31/2016 Program From T (usft) (rfbft) Survey (Wellbore) 200.00 8,100.00 2X-13 (2X-13) 8,100.00 9,150.00 2X-1311_wp03 (2X-1311) 9,150.00 11,300.00 2X-131-1-04_wp01 (2�f F3L9_O4}—_ ri.s BAKER HUGHES 5,970,513.01 usft Latitude: 70' 19' 50.180 N 518,889.00 usft Longitude: 149° 50' 48.451 W 13-3/16" Grid Convergence: 0.14 - 5,971,233.11 usft Latitude: 70' 19' 57.263 N j 518,889.15 usft Longitude: 149' 50' 48.394 W usft Ground Level: 0.00 usft Declination Dip Angle Field Strength (nT) 17.84 80.94 57,544 PLAN Tie On Depth: 9,150.00 +N/S +E/-W Direction (usft) (usft) (°) 0.00 0.00 269.86 Tool Description Name GCT-MS Schlumberger GCT multishot MWD MWD - Standard MWD MWD - Standard 91712016 9:48:11AM Page 2 COMPASS 5000. 1 Build 74 V_ Baker Hughes INTEQ ConocoPhillips Planning Report Database: OAKEDMP2 Local Co-ordinate Reference: Well 2X-13 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2X-13 @ 112.00usft (2X-13) Site: Kuparuk 2X Pad North Reference: Grid Well: 2X-13 Survey Calculation Method: Minimum Curvature Wellbore: 2X-131-1-04 Design: 2X-13L1-04_wp01 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +El-W Rate Rate Rate TFO (usft) (°) (°) (usft) (usft) (usft) (°I100usft) (°/100usft) (°/100usft) (°) 9,150.00 86.77 212.52 5,894.49 2,182.88 4,346.86 0.00 0.00 0.00 0.00 9,285.00 94.89 226.55 5,892.52 2,079.11 4,261.23 12.00 6.01 10.40 60.00 9,400.00 91.91 240.06 5,885.67 2,010.70 4,169.39 12.00 -2.59 11.74 102.00 9,550.00 90.28 257.98 5,882.78 1,957.23 4.029.94 12.00 -1.09 11.95 95.00 9,750.00 88.63 281.93 5,884.73 1,957.07 3,831.40 12.00 -0.82 11.97 94.00 9,875.00 89.96 296.87 5,886.28 1,998.48 3,713.85 12.00 1.07 11.95 85.00 9,945.00 97.23 301.09 5,881.88 2,032.29 3,652.78 12.00 10.38 6.03 30.00 10,015.00 97.16 309.56 5,873.10 2,072.41 3,596.18 12.00 -0.11 12.09 90.00 10,145.00 91.65 324.20 5,863.08 2,166.77 3.507.91 12.00 -4.24 11.26 110.00 10,245.00 91.61 312.20 5,860.23 2,241.15 3,441.40 12.00 -0.04 -12.00 -90.00 10,345.00 89.51 300.38 5,859.25 2,300.22 3,360.95 12.00 -2.10 -11.82 -100.00 10,535.00 85.69 277.88 5,867.32 2,362.08 3,182.81 12.00 -2.01 -11.84 -100.00 10,755.00 83.03 304.28 5,889.35 2,440.00 2,980.34 12.00 -1.21 12.00 97.00 10,830.00 82.02 295.26 5,899.13 2,476.89 2,915.87 12.00 -1.34 -12.03 263.00 10,950.00 89.35 282.82 5,908.19 2,515.76 2,803.03 12.00 6.11 -10.37 -60.00 11,100.00 90.62 264.87 5,908.23 2,525.78 2,653.99 12.00 0.84 -11.97 -86.00 11,300.00 90.56 240.86 5,906.14 2,467.29 2,464.27 12.00 -0.03 -12.00 270.00 rG.I BAKER HUGHES Target 91712016 9:48:11AM Page 3 COMPASS 5000 1 Build 74 Baker Hughes INTEQ rel.. ConoC8P1illipS Planning Report BAKER HUGHES Database: OAKEDMP2 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2X Pad Well: 2X-13 Wellbore: 2X-131-1-04 Design: 2X-13L1-04_wp01 Planned Survey Measured TVD Below Depth Inclination Azimuth System (usft) (°) (°) (usft) 9,150.00 86.77 212.52 5,894.49 TIP/KOP 9,200.00 89.78 217.71 5,895.99 9,285.00 94.89 226.55 5,892.52 Start 12 dis 9,300.00 94.51 228.32 5,891.29 9,400.00 91.91 240.06 5,885.67 3 9,500.00 90.83 252.01 5,883.27 9,550.00 90.28 257.98 5,882.78 4 9,600.00 89.86 263.97 5,882.73 9,700.00 89.03 275.94 5,883.70 9,750.00 88.63 281.93 5,884.73 5 9,800.00 89.16 287.91 5,885.70 9,875.00 89.96 296.87 5,886.28 6 9,900.00 92.56 298.37 5,885.72 9,945.00 97.23 301.09 5,881.88 7 10,000.00 97.18 307.75 5,874.97 10,015.00 97.16 309.56 5,873.10 8 10,100.00 93.58 319.16 5,865.13 10,145.00 91.65 324.20 5,863.08 9 10,200.00 91.63 317.60 5,861.50 10,245.00 91.61 312.20 5,860.23 10 10,300.00 90.46 305.70 5,859.23 10,345.00 89.51 300.38 5,859.25 11 10,400.00 88.37 293.88 5,860.27 10,500.00 86.36 282.04 5,864.89 10,535.00 85.69 277.88 5,867.32 12 10,600.00 84.78 285.66 5,872.74 10,700.00 83.57 297.66 5,882.92 10,755.00 83.03 304.28 5,889.35 13 10,800.00 82.40 298.87 5,895.06 10,830.00 82.02 295.26 5,899.13 14 10.900.00 86.27 287.98 5,906.28 10.950.00 89.35 282.82 5,908.19 15 11,000.00 89.77 276.84 5,908.57 11,100.00 90.62 264.87 5.908.23 16 11,200.00 90.60 252.86 5,907.17 11,300.00 90.56 240.86 5,906.14 91712016 9:48:11AM +N/-S (usft) 2,182.88 2,142.02 2,079.11 2,069.00 2,010.70 1,970.17 1,957.23 1,949.39 1,949.31 1,957.07 1,969.94 1,998.48 2,010.06 2,032.29 2,063.11 2,072.41 2,131.51 2,166.77 2,209.41 2,241.15 2,275.70 2,300.22 2,325.29 2,356.04 2,362.08 2,375.28 2,411.91 2,440.00 2,463.37 2,476.89 2,502.51 2,515.76 2,524.30 2,525.78 2,506.50 2,467.29 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Vertical +E/-W Section (usft) (usft) 4,346.86 -4,352.23 4,318.12 -4,323.39 4,261.23 -4,266.34 4,250.22 -4,255.31 4,169.39 -4,174.34 4,078.21 -41083.05 4,029.94 -4,034.75 3,980.58 -3,985.37 3,880.76 -3,885.56 3,831.40 -3,836.22 3,783.12 -3,787.97 3,713.85 -3,718.77 3.691.70 -3,696.65 3,652.78 -3,657.79 3,607.80 -3,612.88 3,596.18 -3,601.28 3,535.77 -3,541.01 3,507.91 -3,513.24 3.473.25 -3,478.69 3,441.40 -3,446.92 3,398.66 -3,404.26 3,360.95 -3,366.62 3,312.04 -3,317.77 3,217.19 -3,222.99 3,182.81 -3,188.63 3,119.44-3,125.29 3,027.15-3,033.09 2,980.34-2,986.35 2,942.33-2,948.40 2,915.87-2,921.97 2,851.18-2,857.35 2,803.03-2,809.23 2,753.79-2,760.01 2,653.99-2,660.21 2,556.05-2,562.23 2,464.27-2,470.35 Page 4 Well 2X-13 Mean Sea Level 2X-13 @ 112.00usft (2X-13) Grid Minimum Curvature Dogleg Rate (°/100usft) 0.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 Toolface Map Map Azimuth Northing Easting (°) (usft) (usft) 0.00 5,973,415.77 523,235.58 60.00 5,973,374.92 523,206.84 59.84 5,973,312.02 523,149.95 102.00 5,973,301.91 523,138.94 102.14 5,973,243.61 523,058.13 95.00 5,973,203.08 522,966.95 95.29 5,973,190.14 522,918.68 94.00 5,973,182.31 522,869.33 94.01 5,973,182.23 522,769.53 93.89 5,973,189.99 522,720.17 85.00 5,973,202.85 522,671.89 84.88 5,973,231.39 522,602.63 30.00 5,973,242.97 522,580.49 30.03 5,973,265.19 522,541.57 90.00 5,973,296.02 522,496.59 90.84 5,973,305.31 522.484.97 110.00 5,973,364.41 522,424.56 110.90 5,973,399.66 522,396.71 -90.00 5,973,442.30 522,362.06 -90.19 5,973,474.04 522,330.21 -100.00 5,973,508.58 522,287.47 -100.12 5,973,533.11 522,249.77 -100.00 5,973,558.17 522,200.86 -99.88 5,973,588.92 522,106.02 -99.33 5,973,594.96 522,071.64 97.00 5,973,608.15 522,008.28 96.35 5,973,644.78 521,916.00 95.13 5,973,672.87 521,869.19 -97.00 5,973,696.23 521,831.19 -96.31 5,973,709.75 521,804.73 -60.00 5,973,735.37 521,740.05 -59.26 5,973,748.62 521,691.90 -86.00 5,973,757.15 521,642.67 -85.95 5,973,758.64 521,542.87 -90.00 5,973,739.36 521,444.95 -90.13 5,973,700.15 521,353.17 COMPASS 5000.1 Build 74 },- ConocoPhillips Baker Hughes INTEQ Planning Report Was B"ER HUGHES Database: OAKEDMP2 Local Co-ordinate Reference: Well 2X-13 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2X-13 @ 112.00usft (2X-13) Site: Kuparuk 2X Pad North Reference: Grid Well: 2X-13 Survey Calculation Method: Minimum Curvature Wellbore: 2X-13L1-04 Design: 2X-13 L 1-04_wp01 Planned Survey _ _-- - -- -- — Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (°) (°) (usft) (usft) (usft) (usft) (°/100usft) (°) (usft) (usft) Planned TD at 11300.00 - Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 11,300.00 5.906.14 2 3/8" 2-3/8 3 Plan Annotations Measured Vertical Local Coordinates Depth Depth +Nl-S +E/-W (usft) (usft) (usft) (usft) Comment 9,150.00 5,894.49 2,182.88 4,346.86 TIP/KOP 9,285.00 5,892.52 2,079.11 4,261.23 Start 12 dls 9,400.00 5,885.67 2.010.70 4,169.39 3 9,550.00 5,882.78 1,957.23 4,029.94 4 9,750.00 5,884.73 1,957.07 3,831.40 5 9,875.00 5,886.28 1,998.48 3,713.85 6 9,945.00 5,881.88 2,032.29 3,652.78 7 10,015.00 5,873.10 2,072.41 3,596.18 8 10,145.00 5,863.08 2,166.77 3,507.91 9 10,245.00 5,860.23 2,241.15 3.441.40 10 10,345.00 5,859.25 2,300.22 3,360.95 11 10,535.00 5,867.32 2,362.08 3,182.81 12 10,755.00 5,889.35 27440.00 2,980.34 13 10,830.00 5,899.13 2,476.89 2,915.87 14 10,950.00 5,908.19 2,515.76 2,803.03 15 11,100.00 5,908.23 2,525.78 2,653.99 16 11,300.00 5,906.14 2,467.29 2,464.27 Planned TD at 11300.00 91712016 9:48.11AM Page 5 COMPASS 5000.1 Build 74 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2X Pad 2X-13 2X-13L1-04 2X-13L1-04_wp01 Travelling Cylinder Report 01 September, 2016 FSA P aw' I BAKER HUGNES *. Baker Hughes INTEQ rigs ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 2X Pad Site Error: 0 00 usft Reference Well: 2X-13 Well Error. 0.00 usft Reference Wellbore 2X-131-1-04 Reference Design: 2X-13L1-04_wp01 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 2X-13 2X-13 @ 112.00usft (2X-13) 2X-13 @ 112.00usft (2X-13) True Minimum Curvature 1.00 sigma OAKEDMP2 Offset Datum Reference 2X-13L1-04_wp01 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 9,150.00 to 11,300.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,318.80 usft Error Surface: Elliptical Conic Survey Tool Program Date 8/31/2016 From To (usft) (usft) Survey (Wellbore) Tool Name Description 200.00 8,100.00 2X-13 (2X-13) GCT-MS Schlumberger GCT multishot 8,100.00 9,150.00 2X-13L1_wp03 (2X-1311) MWD MWD - Standard 9,150.00 11,300.00 2X-131-1-04_wp01 (2X-131-1-04) MWD MWD- Standard Casing Points i Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name () ( ) 11.300.00 6,018.14 2 3/8" 2-3/8 3 Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) Kuparuk 2X Pad 2X-13 - 2X-13 - 2X-13 10,245.00 7,500.00 813.31 29.54 788.06 Pass - Major Risk 2X-13 - 2X-131-1 - 2X-131-1_wp03 9,174.99 9,175.00 0.50 0.49 0.12 Pass - Minor 1/10 2X-13 - 2X-1311-01 - 2X-13L1-01_wp03 9,174.99 9,175.00 0.50 0.49 0.12 Pass - Minor 1/10 2X-13 - 2X-13L1-02 - 2X-131_1-02_wp03 9,160.97 9,225.00 139.08 1.77 137.31 Pass - Minor 1/10 2X-13 - 2X-1311-03 - 2X-1311-03_wp02 9,157.64 9,200.00 93.79 1.71 92.11 Pass - Minor 1/10 2X-13 - 2X-13L1-05 - 2X-13L1-05_wp01 9,156.32 9,200.00 97.45 1.72 95.76 Pass - Minor l/10 2X-14 - 2X-14 - 2X-14 Out of range 2X-15 - 2X-15 - 2X-15 Out of range 2X-16 - 2X-16 - 2X-16 Out of range 2X-17 - 2X-17 - 2X-17 9,990.44 7,575.00 865.26 188.85 679.20 Pass - Major Risk Offset Design Kuparuk 2X Pad - 2X-13 - 2X-13 - 2X-13 offset Site Error: 0.00 usa Survey Program: 200-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) (") (usft) (usft) ("1 (usft) (usft) (usft) 10,232,69 5,972.57 7,625.00 5,52468 2.45 0.00 10,87 2,714,35 3,943,73 2-11/16 823.88 29,16 798.54 Pass - Major Risk 10,234.90 5,972.51 7,600.00 5,506.44 2.46 0.00 8.92 2,705.88 3,928,88 2-11/16 820.33 29.22 795.01 Pass- Major Risk 10,237.19 5,972,45 7,57500 5,488,23 2.46 0.00 6,94 2,697,40 3,914,00 2-11/16 817.47 29.29 792.17 Pass - Major Risk 10,245.00 5,972,23 7,500.00 5,433.66 2.49 0.00 0.85 2,672,07 3,869.21 2-11/16 813.31 29.54 788.06 Pass - Major Risk, CC, ES, SF 10,245.00 5,972,23 7,525.00 5,451.84 249 0,00 2.56 2,680,50 3, 884.16 2-11/16 813.97 29,54 78865 Pass -Major Risk 10,245,00 5,972.23 7,550,00 5,470.03 2.49 0.00 4.27 2,688,94 3,899.09 2-11/16 815.39 29.54 789.99 Pass- Major Risk 10,247.00 5,972,17 7,475.00 5,415.53 2A9 0.00 -1.10 2663.64 3, 854,22 2-11/16 813,35 29.60 788.14 Pass - Major Risk 10,250,00 5, 972.09 7,400,00 5, 361.59 2,50 0.00 -6,57 2638.14 3, 808.77 2-11/16 817,35 29.70 792.33 Pass -Major Risk 10,250,00 5.972.09 7,425.00 5, 379.49 2.50 0.00 -4.88 2,646.67 3,823.99 2-11/16 815.36 29,70 790.26 Pass- Major Risk CC - Min Centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 91112016 11:38:42AM Page 2 COMPASS 5000.1 Build 74 %- g 0 J M �q -0 N X N � J Qj Q F 02 C j O W c `cF O m Co `m w 3 L ..1 O N ry M X N I N o a N � N 0.. 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O N - + 'w 7 - N 3 m e C W a F N C o X X N < -- rai � M I < O X � N N N O m O O O O o J C (u!/ljsn 09) y;daQ poijan anil I | u IN 00 # _ \ � J \ \ c § { a c g o ING �04 $ @ CL � � \ ( \ _§ -a / co *§ § \ I \ \ ( m � k ( LLLJ ( \ \ [ G { cmo ® [ 4 / # ) / 6 0 \{ 2 > ( / $ ƒ / y 2 - / °\ S/ S/ G 2 \" 2 } y§ ¥ b b f 2\\/ G 3 2 J A 2 3 7 a � \ ] $0 \-CL 'o - £ 3 ¥§ < cl < \ \\\ \ c, k§{ \ ® \ e00 \/\ 0 dI � - jg k/ g \' < < rck �c! mow'' �\\ co \\/( � � � TRANSMITTAL LETTER CHECKLIST WELL NAME: K{� k AY — / 3 /' PTD: C�) 6 -117 ✓ Development Service Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: kC.t,J 46f POOL: ) �IVIF- 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. % , API No. 50-_` T- oZI ?- - do - by . (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 PTD#:2161170 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Well Name: KUPARUK RIV UNIT 2X-131-1-04 Program DEV Well bore seg d❑ DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025645, entire wellbore. 3 Unique well name and number Yes KRU 2X-131-1-04 4 Well located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order No. 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 wellbore plat included Yes 9 Operator only affected party Yes Wellbore will be more than 500' from an external property line where ownership or landownership changes. 10 Operator has appropriate bond in force Yes Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval Yes PKB 9/9/2016 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 NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 18 Conductor string provided NA Conductor set in KRU 2X-13 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in KRU 2X-13 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing set and fully cemented 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons No Productive interval will be completed with uncemented slotted liner 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes Anti -collision analysis complete; no major risk failures 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pressure is 2670 psig(8.5 ppg EMW); will drill w/ 8.6 ppg and maintain overbal w/ MPD VTL 9/22/2016 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 2066 psig; will test BOPS to 3000 psig 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable Yes 112S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 2X-Pad are H2S-bearing. H2S measures required. Geology 36 Data presented on potential overpressure zones Yes Max. potential reservoir pressure is 8.5 ppg EMW; will be drilled using 8.6 ppg mud and MPD technique. Appr Date 37 Seismic analysis of shallow gas zones NA PKB 9/9/2016 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Onshore development lateral to be drilled. Geologic Engineering Public Commissioner: Date: Commissioner: Date Com issioner Date