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214-087
Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Thursday, March 02, 2017 8:29 AM To: Starck, Kai Cc: Loepp, Victoria T (DOA); Bettis, Patricia K (DOA) Subject: Expired Permits to Drill: 214-086, 214-087, 214-156 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 3Q-14AL4, PTD 214-086, issued 23 June 2014 • KRU 3Q-14AL5, PTD 214-087, issued 23 June 2014 • KRU 1G08AL2-01, PTD 214-156, issued 7 October 2014 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. T HE STAT E GOVERNOR SEAS,? PARNELL D. Venhaus f%-" T D Enginccring 1upei visor ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 hair: 907.279.1 a33 =cx: 9C�; . '76.754:% Re: Kuparuk River Field, Kuparuk River Oil Pool, 3Q-14AL5 ConocoPhillips Alaska, Inc. Permit No: 214-087 Surface Location: 2289' FNL, 2013' FEL, Sec. 17, T13N, R09E, UM Bottomhole Location: 2068' FNL, 1280' FEL, Sec. 20, T13N, R09E, UM Dear Mr. Venhaus: Enclosed is the approved application for permit to re -drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. The permit is for a new wellbore segment of existing well Permit No. 214082, API No. 50-029- 21665-01-00. Production should continue to be reported as a function of the original API number stated above. 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 a AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P oerster Chair DATED this day of June 2014. FIECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 JUN 18 2014 n. 1-1,. 1a. Type of Work: Drill ❑ - Lateral E Redrill ❑ Reentry E 1 b_ Proposed Well Class: Development -Oil ❑ ' Service - Winj ❑ Single Zone D• Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ 1c. Specify if well is proposed for: Coalbed Gas ❑ Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Bond: Blanket Single Well Bond No. 59-52-180 , 11. Well Name and Number: 3Q-14AL5 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 9150' TVD: 6319' , 12. Field/Pool(s): Kuparuk River Field . Kuparuk Oil Pool 4a. Location of Well (Governmental Section): Surface: 2289' FNL, 2013' FEL, Sec. 17, T13N, R09E, UM Top of Productive Horizon: 1395' FNL, 823' FEL, Sec. 20, T13N, R09E, UM Total Depth: 2068' FNL, 1280' FEL, Sec. 20, T13N, R09E, UM - 7. Property Designation (Lease Number): ADL 25512 8. Land Use Permit: 2553 13. Approximate Spud Date: 7/1/2014 9. Acres in Property: 2560 - 14. Distance to Nearest Property: 11600 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 516324 y- 6025783 Zone- 4 10. KB Elevation above MSL: 1 60 feet GL Elevation above MSL: 22 feet 15. Distance to Nearest Well Open to Same Pool: 3N-09 , 1100' 16. Deviated wells: Kickoff depth: 8525 ft. Maximum Hole Angle: _ 105° deg 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 4378 psig Surface: 3728 psig , 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks (including stage data) Hole Casing Weight Grade Coupling Length MD TVD MD TVD 3' 2.375" 4.7# L-80 ST-L 1030' 8120' 6301' 9150' 6319' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 8506 Total Depth TVD (ft): 6657 Plugs (measured) none 1 Effective Depth MD (ft): 8401' Effective Depth TVD (ft): 6580' Junk (measured) 8356', 8395' Casing Length Size Cement Volume MD TVD Conductor/Structural 78' 16" 1875# Poleset 115' 115' Surface 4490' 4527' 1250 sx AS III, 300 sx Cl G 4527' 3747' Intermediate Production 8455' 8489' 300 sx Class G, 175 sx AS 1 8489' 6645' Perforation Depth MD (ft): 8204'-8248', 8258'-8302' Perforation Depth TVD (ft): 6438'-6470', 6477'-6509' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Prograrr ❑ 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 correct. Contact Jason Burke @ 265-6097 Email Jason. Burke(o)conocophillips.com Printed Name D. Venhaus Title CTD Engineering Supervisor Signature ,2L �� Phone: 265-6120 Date Commission Use Only Permit to Drill Number: I L` Q API Number: 50- Q l — 6— GQ Permit Approval Date: _ 2']J - �`� See cover letter for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed m thane, gas hydrates, or gas contained in shales: Other: to Z!) , S f Samples req'd: Yes ❑ Nc ❑� Mud log req'd: Yes❑ No H2S measures: Yes [� No Directional svy req'd: Yes[{ No Spacing exception req'd: Yes ElNo U Inclination -only svy req'd: Yes ❑ No ❑ Approved by: COMMISSIONER 7 Date: 3 Pn In-dn l /p— of innni9i Thie n mif is v Iirl fn 9d h f n rl } 1 AC !9n A9G nnc n b 1 / - 16 lu G �,,, `., �_� ....,, ,......... .., .........,. _�................................,...,,,..., .... ,_., ,v... ...........�tiu ti'� lolze/�q- i s ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 June 9, 2014 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: RECEIVED JUN 18 2014 rr�a ConocoPhillips Alaska, Inc. hereby submits an application for permits to drill a six lateral well out of the Kuparuk well 3Q-14 using the coiled tubing drilling rig, Nabors CDR2-AC. The work is scheduled to begin in July 2014. The CTD objective will be to drill six laterals (3Q-14A, 3Q-14AL1, 3Q-14AL2, 3Q-14AL3, 3Q-14AL4 & 3Q-14AL5), targeting the A sand intervals. A cement plug must be placed in the 7" casing of well 30-14 to facilitate a casing exit for these laterals, which will likewise effectively plug off the existing perforations. There is insufficient room to plug the perfs in accordance with 20 AAC 25.112 (c), so ConocoPhillips requests a variance from the plugging requirements of 20 AAC 25.112 (c) to facilitate the casing exit of the 3Q-14 horizontal laterals. The proposed plugging procedure meets the overall objective of this section, providing an equally effective plugging of the well to prevent migration of fluids to other hydrocarbon zones or freshwater. Attached to this application are the following documents: — 10-403 Sundry application to plug A -sand perfs in 3Q-14 — Permit to Drill Application Form 10-401 for 3Q-14A, 3Q-14AL1, 3Q-14AL2, 3Q-14AL3, 3Q-14AL4 & 3Q- 14AL5 — Detailed Summary of Operations — Directional Plans — Current Schematic — Proposed Schematic If you have any questions or require additional information please contact me at 907-265-6097. Sincerely, Jason Burke Coiled Tubing Drilling Engineer 907-231-4568 Kuparuk CTD Laterals 3Q-14A, AL1, AL2, AL3, AL4 & AL5 Application for Permit to Drill Document NABOAS ALASKA C3.9 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))..................................................................................................................................................A 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.................................................................................................................................................. 5 PressureDeployment of BHA.......................................................................................................................................... 6 LinerRunning.................................................................................................................................................................. 7 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).....................Error! Bookmark not defined. (Requirements of 20 AAC 25.402).............................................................................................................. Error! Bookmark not defined. 17. Attachments.......................................................................................................................................8 Attachment 1: Directional Plans for 2T-32A & 2T-32AL1............................................................................................... 8 Attachment 2: Current Well Schematic for 2T-32........................................................................................................... 8 Attachment 3: Proposed Well Schematic for 2T-32A & 2T-32AL1................................................................................. 8 Page 1 of 8 ORIGINAL 6/11/2014 PTD Application: 3Q-14A, AL1, AL2, AL3, AL4 & AL5 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 3Q-14A, AL1, AL2, AL3, AL4 & AL5. 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 the attached 10-401 form for surface and subsurface coordinates of the 30-14A, AL1, AL2, AL3, AL4 & AL5. 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 4200 psi. Using the maximum formation pressure in the area of 4378 psi in the 3N-11, the maximum potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 3728 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)) A static bottom hole pressure of 3Q-14 in February 2014 indicated a reservoir pressure of 2462 psi or 7.3 ppg equivalent mud weight. The maximum down hole pressure in the 3Q-14 pattern is at 3N-11 with 4378 psi. It is expected that reservoir pressure as high as 3N-11 may be encountered while drilling the 3Q-14 laterals because we will be drilling towards that fault block. Using the 3N-11 pressure as the maximum possible, the maximum possible surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 3728 psi. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) No specific gas zones will be drilled; gas injection is currently being performed on the 3Q-13, so the drilling fluid will need to be monitored for entrained gas. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) The largest, expected risk of hole problems in the 3Q-14 laterals will be high differentials between fault blocks because we are drilling from a low pressure block into a higher pressure block. Managed pressure drilling will be used to reduce this risk. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) N/A for this thru-tubing drilling operation. According to 20 AAC 25.030(f), thru-tubing drilling operations need not perform additional formation integrity tests. Page 2 of 8 ORIGINAL 6/11/2014 PTD Application: 3Q-14A, AL1, AL2, AL3, AL4 & AL5 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Lateral Liner Top Liner Btm Liner Top Liner Btm Liner Details Name MD MD TVDSS TVDSS 3Q-14A 10,750' 11,400' 6,369' 6,377' 2%", 4.7#, L-80, ST-L slotted liner, - aluminum billet on top. 3Q-14AL1 10,150' 11,400' 6,391' 6,377' 2'/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top. 3Q-14AL2 10,080' 10,600' 6,391' 6,413' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top. 3Q-14AL3 9,305' 10,580' 6,360' 6,360' 2%", 4.7#, L-80, ST-L slotted liner;aluminum billet on top. 3Q-14AL4 8,525' 9,900' 6,409' 6,373' 2'/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top. 3Q-14AL5 8,120' 9,150' 6,301' 6,319' 2%", 4.7#, L-80, ST-L slotted liner; Existing Casing/Liner Information Category OD Weight (ppf) Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.50 H-40 Welded 37' 115, 0 115' 1640 630 Surface 9-5/8" 36 J-55 SMLS 37' 4527' 0' 3747' 3520 2020 Casing 7" 26 J-55 BTC 34' 8489' 0' 6644' 4980 4330 Tubing 3'/z" 9.2 L-80 EUE-MOD 34' 8135' 0' 6387' 10160 10540 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) N/A for this thru-tubing drilling operation. Nabors CDR2-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a diverter system is not required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System Diagram of Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System - Window milling operations: Chloride -based Flo -Pro mud (9.2 ppg) - Drilling operations: Chloride -based Flo -Pro mud (9.2 ppg). This mud weight will hydrostatically overbalance the reservoir pressure, we will maintain these conditions using MPD practices described below. - Completion operations: 30-14 does not contain a subsurface safety valve (SSSV). The well will be loaded with 12.0 ppg NaBr completion fluid in order to provide formation over -balance while running completions. - Emergency Kill Weight fluid: Two well bore volumes (-198 bbl) of at least 13.1 ppg emergency kill weight fluid will be within a short drive to the rig during drilling operations. Page 3 of 8 �,.� I G I NAL R6/11/2014 PTD Application: 3Q-14A, AL1, AL2, AL3, AL4 & AL5 Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole formation throughout the coiled tubing drilling (CTD) process. Maintaining a constant BHP promotes wellbore stability, particularly in shale sections, while at the same time providing an overbalance on the reservoir. Through experience with drilling CTD laterals in the Kuparuk sands, 11.8 ppg has been identified as the minimum EMW to ensure stability of shale sections. Since this well is proposed as an infield development candidate in an actively water flooded field, expected reservoir pressures can be difficult to estimate. In this case, however, a constant BHP of the minimum of 12.0 ppg will be initially targeted at the window based on the recent static bottom -hole pressure and expected draw down reservoir pressure. The constant BHP target will be adjusted to maintain overbalanced conditions if increased reservoir pressure is encountered during drilling. The constant BHP target will be maintained utilizing the surface choke. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Pressure at the 3Q-14 Window 8,215' MD, 6386' TVD Usin MPD Pumps On (1.5 bpm) Pumps Off A -sand Formation Pressure 7.3 ppg) 2447 psi 2447 psi Mud Hydrostatic (9.2 ppg) 3084 psi 3084 psi Annular friction (i.e. ECD, 0.090 si/ft) 739 psi 0 psi Mud + ECD Combined 3828 psi 3084 psi (no choke pressure) (overbalanced (overbalanced —1376psi) —637psi) Target BHP at Window (12.0 ) 4022 psi 4022 psi Choke Pressure Required to Maintain 199 psi 938 psi Target BHP 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005(c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005(c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A - Application is not for an exploratory or stratigraphic test well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Page 4 of 8 ORIGINAL 6/11/2014 PTD Application: 30-14A, AL1, AI-2, AL3, AL4 & AL5 Summary of Operations Background Well 3Q-14 is a Kuparuk A -sand development well equipped with 3'/2" tubing and 7" production casing. Six laterals from well 3Q-14 will be drilled to the Southwest side of parent well 3Q-14 to access reserves in an adjacent fault block. These laterals will target the Al, A2 & A3 sands. The D-Nipple located at 8125' MD will have the ID milled out to a 2.80" to allow the drilling assemblies access through the tubing tall. The tubing tail will also be perforated prior to cementing to allow cement between the 3-1/2" tubing tail and 7" casing. Prior to drilling, the existing A -sand perfs in 3Q-14 will be squeezed with cement to provide a means to kick out of the 7" casing. ConocoPhillips requested a variance from the requirements of 20 AAC 25.112(c)(1) to plug the A -sand perfs in this manner in the Sundry application (Approved 314-146) After plugging off the existing A -sand perfs with cement, pilot hole drilled, a mechanical whipstock will be placed in the 7" casing at the planned kickoff point. The 3Q-14A sidetrack will exit through the 7" casing at 8215' MD and all subsequent laterals will be drilled off of this sidetrack. The laterals will be completed with 2-%" slotted liner. The final liner will be run with the top located inside the 3'/2" tubing at 8120' MD. Pre-CTD Work 1. RU slickline — Dummy off GLM adn obtain a SBHP 2. RU Pump — Perform injectivity test 3. RU E-Liner — Perforate tubing tail at 8119' — 8121' MD 4. RU coil — Mill out D-nipple at 8125' MD then pump cement and squeeze A-perfs. 5. RU slick -line - Tag top of cement and pressure test. 6. 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. 3Q-14A Sidetrack (Al & A2 sand - Southwest) a. Drill 2.80" high -side pilot hole through cement to 8265' MD b. RU Slickline — caliper pilot hole c. Drift pilot hole with whip -stock dummy d. Set whip -stock at 8215' MD with high -side orientation e. Mill 2.80" window at 8215' MD f Drill 2.74" x 3.0" bi-center lateral to TD of 11400' MD g. Run 2%" slotted liner with an aluminum billet from TD up to 10750' MD 3. 3Q-14AL1 Lateral (A2 & A3 sand - Southwest) a. Kickoff of the aluminum billet at 10750' MD b. Drill 2.74" x 3.0" bi-center lateral to TD of 11400' MD c. Run 2%" slotted liner from TD up to 10150' MD Page 5 of 8 :'� �a � G I NAL 6/11/2014 PTD Application: 3Q-14A, AL1, AL2, AL3, AL4 & AL5 4. 3Q-14AL2 Lateral (Al sand - Southwest) a. Kick off of the aluminum billet at 10150' MD b. Drill 2.74" x 3.0" bi-center lateral to TD of 10600' MD c. Run 2%" slotted liner from TD up to 10080' MD 5. 3Q-14AL3 Lateral (A3 sand - Southwest) a. Kickoff of the aluminum billet at 10080' MD b. Drill 2.74" x 3.0" bi-center lateral to TD of 10580' MD c. Run 2%" slotted liner from TD up to 9305' MD 6. 3Q-14AL4 Lateral (Al & A2 sand - Southwest) a. Kick off of the aluminum billet at 9305' MD b. Drill 2.74" x 3.0" bi-center lateral to TD of 9900' MD c. Run 2%" slotted liner from TD up to 8525' MD 7. 3Q-14AL5 Lateral (Al & A2 sand - Southwest) a. Kick off of the aluminum billet at 8525' MD b. Drill 2.74" x 3.0" bi-center lateral to TD of 9150' MD c. Run 2%" slotted liner into the tubing tail at 8120' MD 8. Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV 2. Obtain static BHP. Install GLV. 3. Turn over to production Pressure Deployment of BHA The planned bottomhole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. Because of this, MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slickline lubricator. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slickline. Page 6 of 8 [ RIGINAL 6/11/2014 PTD Application: 3Q-14A, AL1, AL2, AL3, AL4 & AL5 — 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 3Q-14 CTD laterals will be displaced to an overbalancing fluid (12.0 ppg NaBr) prior to running liner. See the "Drilling Fluids" section for more details. — While running 2%" slotted liner, a joint of 23/" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 23/" rams will provide secondary well control while running 23/" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (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 AA 25.050(b)) — The Applicant is the only affected owner. — Please see Attachment 1: Directional Plan — Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. — MWD directional, resistivity, and gamma ray will be run over the entire openhole section. — Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 3Q-14A 11600' 3Q-14AL1 11600' 3Q-14AL2 11600' 3Q-14AL3 11600' 3Q-14AL4 11600' 3Q-14AL5 11600' — Distance to Nearest Well within Pool (heel measured to offset well) Page 7 of 8 ORIGINAL 6/11/2014 PTD Application: 3Q-14A, AL1, AL2, AL3, AL4 & AL5 Lateral Name Distance Well 3Q-14A 1100, 3N-09 3Q-14AL1 1100, 3N-09 3Q-14AL2 1100, 3N-09 3Q-14AL3 1100, 3N-09 3Q-14AL4 1100, 3N-09 3Q-14AL5 1100, 3N-09 16. Attachments Attachment 1: Directional Plans for 3Q-14A, AL1, AL2, AL3, AL4 & AL5 Attachment 2: Current Well Schematic for 3Q-14 Attachment 3: Proposed Well Schematic for 3Q-14A, AL1, AL2, AL3, AL4 & AL5 Page 8 of 8 0 R I GINA L 6/11/2014 Lo k & § o \ /\ - 04 �; \ \ / �\ e cm/ M $ J 7 e \ \ \ § ± J a) ~ f 2 \ § 9 ` f { \ \ \-- \ \\ o\ / ) ! a 4 e m / _ G a J/ ] 3) J \ cD co co § / co co G 3 § q \ \ } } § co )9 � . =co §\ \) § \\ % §\ z jeg &\J \§§ ORIGINAL AW KUP PROD 3Q-14 l mocot'nimp5 Well Attributes - -- Max Angle & MD TD Alaska, inc. Wellbore API/UWI Field Name Wellbore Status ncl I') MD (ftKB) Act St. (ftKB) 500292166500 KUPARUK RIVER UNIT PROD 47.28 4,000.00 8,506.0 • • • Comment I H2S (pp.) Date SSSV: NIPPLE 150 12/24/2012 Annotation End Date Last W0: 2/1/1998 KB-Grd If) Rig Release Date 42.51 12/4/1986 30-14, 2H1f2014t08:47 PM Mica schematic (actual Annotation Depth (ftKB) End Date Annotation fast Mod By End Date .......................... _....................................... ......................................... . Last Tag: SLIM 8,274.0 2!7/2014 Rev Reason: TAG hipshkf 2/11/2014 HANGER; 34.0 Casing Strings MCasing Description CONDUCTOR OD (in) ID 16 (in) 15.062 Top (ftKB) Set 37.0 Depth (ftKB) 115.0 Set Depth (ND)... 115.0 WULen (I... 62.50 Grade H-40 Top Thread Welded CONDUCTOR; 37.0-115. 0 Casing Description SURFACE OD (in) ID 95/8 (in) 8.765 Top (ftKB) Set 37.0 Depth (ftKB) 4,527.2 Set Depth (ND)... 3,747.0 WULen (I... 36.00 Grade J-55 Top Thread SMLS Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (ND)... Wt/Len (I... Grade Top Thread NIPPLE; 509.3 PRODUCTION 7 6.276 34.0 8,488.9 6,644.6 26.00 J-55 BTC Tubing Strings GAS LIFT: Z884.0 Tubing Description String Ma.-. ID (in) Top (ftKB) Set Depth (ft.. Set Depth (ND) (... Wt (Ib/ft) Grade Top Connection TUBING WO 3 1/2 2.992 34.0 8,135.2 6,387.5 9.30 L-80 EUE 8rd Mod Completion Details GAB LIFT; 4,425.1 Top (ftKB) Top (TVD) (ftKB) Top Incl V) Item Des Com Nominal ID (In) 34.0 34.0 0.03 HANGER 3.5" 5M CIW Gen IV Tubing Hanger w/ 3.5" L-80 EUE 8rd 3.500 Mod Pin Down 509.3 509.3 0.35 NIPPLE 3.5" Camco'DS' Nipple w/ 2.812" No -Go Profile 2.812 8,068.6 6,338.8 42.71 NIPPLE 3.5"Camco'W Nipple w/ 2.812" Selective Profile 2.812 SURFACE; 37.04,527.2 8,108.2 6,367.8 42.94 PACKER 3.5" x 7" Baker'SAB-T Permanent Packer w/ K22 Anchor 3.250 Latch Seal Assy GAS LIFT; 5.654.2 8,125.1 6,380.2 43.03 NIPPLE 3.5"Camco'D'Nipple w/ 2,750" No -Go Profile 2.750 8,134.3 6,386.9 43.08 SOS I Baker 3.5" Shear Out Sub j 2.992 GAS LIFT; 6,599.5 Other In Hale (Wireline retrievable plugs, valves, pumps, fish, etc.) Up(TVD) Top Intl Top (ftKB) (ftKB) (°) Des Co. Run Date ID (in) 8,356.0 6,548.0 43.43 FISH 1"X 2" Piece of Tree Saver Left in Hale 10/14/1991 0.000 GAS LIFT; 7,414.0 8,395.0 6,576.4 43.43 FISH 1 1/2" OV w/ RK Latch Empty Pocket; Dropped to 2/8/1998 0.000 Rathole GAS LIFT; 8, 023.0 Perforations & Slots Shot Den Top (ND) Dim (TVD) (shots/f Top (ftKB) St. (ftKB) (ftKB) (ftKB) Zone Date 0 Type Com NIPPLE; 8,068.E 8,204.0 8,248.0 6,437.7 6,469.6 A-3, A-2, 30- 4/11/1991 6.0 RPERF 2 1/8" Dyna Strip; 0 deg 14 ph 8,211.0 8,212.0 6,442.7 6,443.5 A-4, 310-14 3/2/1987 1.0 IPERF 2 1/8" HJ II EnerJet; 0 deg. phasing PACKER; 8,108.2 8,214.0 8,215.0 6,444.9 6,445.6 A-3, 3Q-14 3/2/1987 1.0 IPERF 2 1/8" HJ II EnerJet; 0 deg. phasing NIPPLE; 8,125.1 8,234.0 8,235.0 6,459.4 6,460.2 A-2, 3Q-14 3/2/1987 1.0 IPERF 2 1/8" HJ II EnerJet; 0 deg. phasing 8,237.0 8,238.0 6,461.6 6,462.3 A-2, 3Q-14 3/2/1987 1.0 IPERF 2 1/8" HJ II EnerJet; 0 SOS; 8,134.3 deg. phasing 8,258.0 8,302.0 6,476.9 6,508.8 A-11, 3Q-14 4/11/1991 6.0 RPERF 21/8" Dyne Strip; 0 deg ph 8,259.0 8,261.0 6,477.6 6,479.0 A-1, 3Q-14 3/2/1987 1.0 IPERF 21/8" HJ II EnerJet; 0 deg. phasing 8,264.0 8,265.0 6,481.2 6,482.0 A-1, 310-14 3/2/1987 1.0 IPERF 2 1/8" HJ II EnerJet; 0 IPERF; 8,211 0-8,212.0 deg. phasing 8,266.0 8,267.0 6,482.7 6,483.4 A-1, 3Q-14 3/2/1987 1.0 IPERF 2 1/8" HJ II EnerJet; 0 deg. phasing IPERF; 8,2140-8.215.0 8,269.0 8,270.0 6,484.9 6,485.6 A-1, 30-14 3/2/1987 1.0 IPERF 21/8" HJ II EnerJet; 0 RPERF;8,204.0-8.2480 deg. phasing IPERF; 8,234D-8.235.0 8,274.0 8,276.0 6,488.5 6,489.9 A-1, 3Q-14 3/2/1987 1.0 IPERF 21/8" HJ II EnerJet; 0 deg. phasing 8,278.0 8,279.0 6,491.4 6,492.1 A-1, 3Q-14 3/2/1987 1.0 IPERF 21/8" HJ II EnerJet; 0 IPERF; 8,237.0-8.238.0 deg. phasing 8,286.0 8,288.0 6,497.2 6,498.7 A-1, 3Q-14 3/2/1987 1.0 IPERF 2 1/8" HJ II EnerJet; 0 1 deg. phasing Mandrel Inserts IPERF; 8,259.0-8,261.0 IPERF; a264.0-8,265.0 - all on No St Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Sery Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date C in 1 2,884.0 2,605.2 WTF KBUG 1 GAS LIFT GLV BK 0.15E 1,296.0 10/4/2013 2 4,425.1 3,677.1 WTF KBUG 1 GAS LIFT GLV BK 0.156 1,295.0 10/4/2013 IPERF; 8,266.0-8,267.0 3 5,654.2 4,553.0 WTF KBUG 1 GAS LIFT GLV BK 0.156 1,292.0 10/4/2013 4 6,599.5 5,259.3 WTF KBUG 1 GAS LIFT GLV BK 0.188 1,324.o 10/5/2013 5 7,414.0 5,859.8 V/TF KBUG 1 GAS LIFT GLV BK 0.188 1,316.0 1015/2013 IPERF; 8,269.0-8,270.0 6 8, 023.0 6,3052 WTF MMM 11/2 GAS LIFT OV RK 0.188 0'0 10/3/2013 Notes: General & Safety IPERF; 8,274.0-8,276.0 1/30/2004 End Date Annotation NOTE: WAIVERED WELL: IAxOA COMMUNICATION 3/26/2010 NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 IPERF; 8,2780-8,279.0 RPERF; 8,2550-8,302.0- IPERF; 8,286.0-8,288.0 FISH; 8,356.0 FISH; 8,395.0 PRODUCTION; 34.0-8,488.9 SS ;r Y 01 IN PA L 0 ConocoPhilli s p ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 3Q Pad 3Q-14 3Q-14AL5 Plan: 3Q-14AL5_wp01 Standard Planning Report 14 May, 2014 BAKER HUGNES 4f21GIN,4L ConocoPhillips Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3Q Pad Well: 3Q-14 Wel lbore: 3Q-14AL5 Design: 3 Q-14AL5_wp01 Planning Report Local Co-ordinate Reference: Well 3Q-14 TVD Reference: Mean Sea Level MD Reference: 3Q-14 @ 60.00ft (3Q-14) North Reference: True 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 Has BAKER HUGHES Site Kuparuk 3Q Pad Site Position: Northing: 6,025,873.15ft Latitude: 70' 28' 54.757 N From: Map Easting: 515,959.89ft Longitude: 149' 52' 10.513 W Position Uncertainty: 0.00 ft Slot Radius: 0.000 in Grid Convergence: 0.12 ° Well 3Q-14 Well Position +N/-S 0.00 ft Northing: 6,025,783.47 ft Latitude: 700 28' 53.867 N +E/-W 0.00 ft Easting: 516,323.80 ft Longitude: 149' 51' 59.814 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00 ft Wellbore 3Q-14AL5 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (I (°) (nT) BGGM2013 8/1/2014 15.07 80.01 57,400 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (ft) (°) (°) (ft) (ft) (ft) (°/100ft) (°/100ft) (°/100ft) (°) Target 8,525.00 96.13 214.05 6,409.21 -4,668.02 1.209.98 0.00 0.00 0.00 0.00 8,615.00 105.13 214.05 6,392.62 -4,741.24 1,160.50 10.00 10.00 0.00 0.00 8,685.00 103.57 221.09 6,375.26 -4,794.94 1,119.17 10.00 -2.23 10.06 102.00 8,755.00 96.57 221.09 6,363.03 -4,846.85 1,073.90 10.00 -10.00 0.00 180.00 8,855.00 96.47 231.16 6,351.65 -4,915.62 1,002.37 10.00 -0.10 10.06 90.00 8,925.00 101.39 236.20 6,340.79 -4,956.57 946.71 10.00 7.03 7.20 45.00 8,995.00 94.49 237.42 6,331.12 -4,994.50 888.72 10.00 -9.85 1.74 170.00 9,150.00 94.33 252.96 6,319.14 -5,059.14 748.88 10.00 -0.11 10.03 90.00 511412014 2:27:06PM Page 2 COMPASS 2003.16 Build 69 ORIGINAL ri.I ConocoPhillips Planning Repoli BAKER HUGHES Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3Q Pad Well: 3Q-14 Wel lbore: 3Q-14AL5 Design: 3 Q-14A L 5_wp 01 Planned Survey Measured TVD Below Depth Inclination Azimuth System +N/-S (ft) (°) V) (ft) (ft) 8,525.00 96.13 214.05 6,409.21 -4,668.02 TIP/KOP 8,600.00 103.63 214.05 6,396.35 -4,729.20 8,615.00 105.13 214.05 6,392.62 -4,741.24 Start 10 dls 8,685.00 103.57 221.09 6,375.26 -4,794.94 3 8,700.00 102.07 221.09 6,371.93 -4,805.96 8,755.00 96.57 221.09 6,363.03 -4,846.85 4 8,800.00 96.55 225.62 6,357.89 -4,879.35 8,855.00 96.47 231.16 6,351.65 -4,915.62 5 8,900.00 99.64 234.38 6,345.35 -4,942.57 8,925.00 101.39 236.20 6,340.79 -4,956.57 6 8,995.00 94.49 237.42 6,331.12 -4,994.50 7 9,000.00 94.49 237.92 6,330.73 -4,997.16 9,100.00 94.41 247.95 6,322.95 -5,042.47 9,150.00 94.33 252.96 6,319.14 -5,059.14 Planned TD at 9160.00 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3Q-14 Mean Sea Level 3Q-14 @ 60.00ft (30-14) True Minimum Curvature Vertical Dogleg Toolface Map Map +E/-W Section Rate Azimuth Northing Easting (ft) (ft) (°/100ft) (°) (ft) (ft) 1,209.98 4,794.88 0.00 0.00 6,021,118.58 517,543.90 1,168.64 4,849.34 10.00 0.00 6,021,057.32 517,502.69 1,160.50 4,860.06 10.00 0.00 6,021.045.26 517,494.59 1,119.17 4,907.13 10.00 102.00 6,020,991.48 517,453.38 1,109.56 4,916.63 10.00 -180.00 6,020,980.43 517,443.79 1,073.90 4,951.86 10.00 -180.00 6,020,939.47 517,408.22 1,043.22 4,979.51 10.00 90.00 6,020,906.91 517,377.61 1,002.37 5,009.41 10.00 90.52 6,020,870.55 517,336.86 966.91 5,030.88 10.00 45.00 6,020,843.52 517,301.46 946.71 5,041.77 10.00 45.45 6,020,829.48 517,281.28 888.72 5,070.80 10.00 170.00 6,020,791.43 517,223.39 884.51 5,072.82 10.00 90.00 6,020,788.76 517,219.18 795.85 5,104.65 10.00 90.04 6,020,743.26 517,130.63 748.88 5,114.27 10.00 90.82 6,020,726.49 517,083.70 511412014 2:27.06PM Page 3 COMPASS 2003.16 Build 69 ORIGINAL ConocoPhilli s ��`� P Planning Report BAKER HUGHES Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3Q Pad Well: 3Q-14 Wellbore: 3Q-14AL5 Design: 3Q-14AL5_wp01 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3Q-14 Mean Sea Level 3Q-14 @ 60.00ft (3Q-14) True Minimum Curvature Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting Shape (°) (°) (ft) (ft) (ft) (ft) (ft) Latitude Longitude 3Q-14AL5_T3 0.00 0.00 6,335.00 -7,690.751,141,038.83 6,020,597.00 1,657,263.00 70° 13' 24.771 N 140° 37' 47.904 W plan hits target center Point 3Q-14 CTD Polygon 0.00 0.00 0.00 -7,162.071,141,211.01 6,021,126.00 1,657,434.00 70° 13' 29.647 N 140° 37' 40.649 W plan hits target center Polygon Point 1 0.00 -7,162.071,141,211.01 6,021,126.00 1,657,434.00 Point 0.00 -7,307.101,141,217.70 6,020,981.00 1,657,441.01 Point 0.00 -7,448.871,141,103.38 6,020,838.99 1,657,327.01 Point 0.00 -7,702.981,140,678.80 6,020,583.98 1,656,903.03 Point 0.00 -8,152.701,140,055.77 6,020,132.94 1,656,281.05 Point 0.00 -8,540.561,139,508.88 6,019,743.92 1,655,735.07 Point? 0.00 -8,879.591,139,037.11 6,019,403.89 1,655,264.09 Point 0.00 -9,253.631,139,038.31 6,019,029.89 1,655,266.11 Point 9 0.00 -9,026.351,139,383.83 6,019,257.90 1,655,611.10 Point 10 0.00 -8,552.631,140,004.91 6,019,732.94 1,656,231.07 Point 11 0.00 -8,225.581,140,463.66 6,020,060.96 1,656,689.06 Point 12 0.00 -7,706.181,141,234.85 6,020,582.00 1,657,459.03 Point 13 0.00 -7,491.621,141,454.33 6,020,797.02 1,657,678.02 Point 14 0.00 -7,293.751,141,520.76 6,020,995.01 1,657,744.01 Point 15 0.00 -7,120.641,141,477.13 6,021,168.01 1,657,700.00 Point 16 0.00 -7,162.071,141.211.01 6,021,126.00 1,657,434.00 3Q-14AL5_T1 0.00 0.00 6,369.00 -7,568.181,141,240.12 6,020,720.00 1,657,464.00 70° 13' 25.662 N 140° 37' 41.596 W plan hits target center Point 3Q-14A_Faultl 0.00 0.00 0.00 -7,285.491,141,398.76 6,021,003.00 1,657,622.00 70' 13' 28.170 N 140° 37' 35.808 W plan hits target center - Rectangle (sides W310.00 H1.00 D0.00) 3Q-14AL5_T4 0.00 0.00 6,319.00 -7,768.381,140,867,64 6,020,519.00 1,657,092.00 70° 13' 24.271 N 140° 37' 53.152 W plan hits target center Point 3Q-14A_Fault2 0.00 0.00 0.00 -7,824.181,140,775.51 6,020,463.00 1,657,000.00 70° 13' 23.867 N 140° 37' 56.038 W plan hits target center - Rectangle (sides W310.00 H1.00 D0.00) 3Q-14AL5_T2 0.00 0.00 6,352.00 -7,643.921,141,120.94 6,020,644.00 1,657,345.00 70° 13' 25.103 N 140° 37' 45.345 W plan hits target center Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (it) Name (in) (in) 9,150.00 6,319.14 2-3/8" 2.375 3.000 511412014 2:27.06PM Page 4 COMPASS 2003.16 Build 69 :RIJINAL FEW ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3Q Pad Well: 3Q-14 Welibore: 3Q-14AL5 Design: 3Q-14AL5_wp01 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3Q-14 Mean Sea Level 3Q-14 @ 60.00ft (3Q-14) True Minimum Curvature Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (ft) (ft) (ft) (ft) Comment 8,525.00 6,409.21 -4,668.02 1,209.98 TIP/KOP 8,615.00 6,392.62 -4,741.24 1,160.50 Start 10 dls 8,685.00 6,375.26 -4,794.94 1,119.17 3 8,755,00 6,363.03 -4,846.85 1,073.90 4 8,855.00 6,351.65 -4,915.62 1,002.37 5 8,925.00 6,340.79 -4,956.57 946.71 6 8,995.00 6,331.12 -4,994.50 888.72 7 9,150.00 6,319.14 -5,059.14 748.88 Planned TD at 9150.00 511412014 2:27:06PM Page 5 COMPASS 2003.16 Build 69 ORIGINAL ConocoPhillips ConocoPhillips (Alaska) Inc. -Ku p2 Kuparuk River Unit Kuparuk 3Q Pad 3Q-14 3Q-14AL5 3Q-14AL5_wp01 Travelling Cylinder Report 12 May, 2014 F39 &I BAKER HUGHES ORIGINAL HIM ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3Q Pad Site Error. 0.00ft Reference Well: 3Q-14 Well Error: 0.00ft Reference Wellbore 3Q-14AL5 Reference Design: 3Q-14AL5_wp01 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 3Q-14 3Q-14 @ 60.00ft (3Q-14) 3Q-14 @ 60.00ft (3Q-14) True Minimum Curvature 1.00 sigma EDM Alaska Prod v16 Offset Datum Reference 3Q-14AL5_wp01 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00ft Error Model: ISCWSA Depth Range: 8,525.00 to 9,150.00ft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,109.00ft Error Surface: Elliptical Conic Survey Tool Program Date 5/12/2014 From To (ft) (ft) Survey (Wellbore) Tool Name Description 100.00 8,200.00 3Q-14 (3Q-14) BOSS -GYRO Sperry -Sun BOSS gyro multishot 8,200.00 8,525.00 3Q-14A_wp04 (3Q-14A) MWD MWD - Standard 8,525.00 9,150.00 3Q-14AL5_wp01 (3Q-14AL5) MWD MWD - Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name 9,150.00 6,379.14 2-3/8" 2-3/8 3 Summary Site Name Offset Well - Wellbore - Design Kuparuk 3Q Pad 3Q-14 - 3Q-14A - 3Q-14A_wp04 3Q-14 - 3Q-14AL1 - 3Q-14AL1_wp01 3Q-14 - 3Q-14AL2 - 3Q-14AL2_wp01 3Q-14 - 3Q-14AL3 - 3Q-14AL3_wp01 3Q-14 - 3Q-14AL4 - 3Q-14AL4_wp01 Reference Offset Centre to Measured Measured Centre Depth Depth Distance (ft) (ft) (ft) 8.525.00 8,525.00 0.00 8,525.00 8,525.00 0.00 8,525.00 8,525.00 0.00 8,525.00 8,525.00 0.00 8,525.00 8,525.00 0.00 No -Go Allowable Distance Deviation Warning (ft) from Plan (ft) 0.29 -0.22 FAIL - Major Risk 0.29 -0.22 FAIL - Major Risk 0.29 -0.22 FAIL - Major Risk 0.29 -0.22 FAIL - Major Risk 0.29 -0.22 FAIL - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 511212014 10:16:04AM Page 2 of 8 COMPASS 2003.16 Build 69 nRIGINAL ConoeoPhillips Travelling Cylinder Report Company: ConocoPhillips (Alaska) Inc. -Kup2 Local Co-ordinate Reference: Project: Kuparuk River Unit ND Reference: Reference Site: Kuparuk 3Q Pad MD Reference: Site Error. 0.00ft North Reference: Reference Well: 3Q-14 Survey Calculation Method: Well Error- 0.00ft Output errors are at Reference Wellbore 3Q-14AL5 Database: Reference Design: 3Q-14AL5_wp01 Offset ND Reference: Offset Design Kuparuk 3Q Pad - 3Q-14 - 3Q-14A - 3Q-14A_wp04 Survey Program: 100-BOSS-GYRO, 8200-MWO Reference Offset Semi Major Axis Measured Vertical Measured Vertical Reference Offset Toolface + Offset Wellbore Centre Depth Depth Depth Depth Azimuth +N/-S +El-W (ft) (ft) (ft) (a) (ft) (ff) V) (ftl (ft) 8,525.00 6,469.21 8,525.00 6,46921 0.00 0.00 -145.95 -4,668.02 1,209.98 8,549.98 6,466.00 8,550.00 6,466.60 0.06 0.02 2.47 4,688.41 1,195.75 8,574.83 6,461.74 8,575.00 6,463.99 0.07 0.04 0.72 4,708.35 1,180.91 8,599.46 6,456.48 8,600.00 6,461.35 0.08 0.07 -0.09 -4,727.83 1,165.46 8,623.99 6,450.29 8,625.00 6,458.70 0.10 0.10 0.60 -4,746.82 1,149.42 8,649.00 6,443.96 8,650.00 6,456.03 0.12 0.13 3.79 -4,765.31 1,132.81 8,674.22 6,437.81 8,675.00 6,453.35 0.14 0.16 7.24 -4,783.28 1,115.64 8,699.69 6,432.00 8,700.00 6,450.65 0.16 0.20 8.46 -4,800.71 1,097.92 8,725.37 6,427.18 8,725.00 6,447.95 0.18 0.24 5.87 -4,817.59 1,079.68 8,751.09 6,423.49 8,750.00 6,445.24 0.21 0.29 1.26 -4,833.91 1,060.93 8,776.73 6,420.55 8,775.00 6,442.53 0.24 0.34 -1.49 -4,849.63 1,041.69 8,802.56 6,417.60 8,800.00 6,439.82 0.27 0.39 -2.60 4,864.76 1,021.97 8,828.60 6,414.63 8,825.00 6,437.10 0.31 0.45 -2.78 4,879.28 1,001.80 8,854.83 6,411.67 8,850.00 6,434.43 0.36 0.51 -2.19 4,893.17 981.20 8,879.98 6,408.46 8,875.00 6,431.98 0.41 0.58 -1.39 -4,906.47 960.17 8,905.11 6,404.48 8,900.00 6,429.77 0.46 0.66 0.72 -4,919.17 938.75 8,930.43 6,399.74 8,925.00 6,427.79 0.51 0.74 3.53 -4,931.24 916.95 8,956.83 6,395.36 8,950.00 6,426.06 0.58 0.82 4.40 -4,942.69 894.79 8,983.36 6,392.15 8,975.00 6,424.57 0.65 0.91 4.12 -4,953.49 872.29 9,010.12 6,389.94 9,000.00 6,423.33 0.72 1.01 4.48 -4,963.64 849.48 9,037.19 6,387.82 9,025.00 6,422.34 0.81 1.11 6.37 -4,973.14 826.38 9,064.49 6,385.70 9,050.00 6,421.56 0.90 1.21 8.90 -4,982.21 803.09 9,091.99 6,383.57 9,075.00 6,420.89 1.01 1.29 12.47 -4,991.86 780.05 9,119.45 6,381.46 9,100.00 6,420.32 1.12 1.37 17.08 -5,002.22 757.30 9,146.58 6,379.40 9,125.00 6,419.84 1.23 1.46 22.82 -5,013.25 734.87 Well 3Q-14 3Q-14 @ 60.00ft (3Q-14) 3Q-14 @ 60.00ft (3Q-14) True Minimum Curvature 1.00 sigma EDM Alaska Prod v16 Offset Datum Rule Assigned: Major Risk Casing - Centre to No Go Hole Size Centre Distance (n) (ft) (ft) 0.22 0,00 0.29 0.22 0.71 0.93 0.22 2.74 1.22 0.22 6.06 1.52 0.22 10.54 1.85 0.22 14.98 2.17 0.22 19.03 2.53 0.22 22.66 2.91 0.22 25.79 3.35 0.22 28.54 3.79 0.22 31.17 4.27 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 33.74 36.15 38.36 40.77 43.72 47.21 50.80 64.26 57.61 60.78 63.48 64.75 64.49 62.83 4.76 5.29 5.83 6.40 6.98 7.60 8.26 8.95 9.66 10.42 11.16 11.87 12.58 13.30 rik2 BAKER HUGHES Offset Site Error: 0.00 ft Offset Well Error: 0.00 it Allowable Warning Deviation (ft) -0.22 FAIL - Major Risk, CC, ES, SF -0.20 FAIL - Major Risk 1.53 Pass - Major Risk 4.55 Pass - Major Risk 8.74 Pass - Major Risk 12.89 Pass - Major Risk 16.66 Pass - Major Risk 20.01 Pass - Major Risk 22.86 Pass - Major Risk 25.40 Pass - Major Risk 27.44 Pass - Major Risk 29.46 Pass - Major Risk 31.31 Pass - Major Risk 32.96 Pass - Major Risk 34.82 Pass - Major Risk 37.25 Pass - Major Risk 40.21 Pass - Major Risk 43.24 Pass - Major Risk 46.07 Pass - Major Risk 48.73 Pass - Major Risk 51.18 Pass - Major Risk 53.20 Pass - Major Risk 53.86 Pass - Major Risk 53.06 Pass - Major Risk 50.96 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 5/12/2014 10:16:04AM Page 3 of 8 COMPASS 2003.16 Build 69 .- WEa9 ConocoPhillips Travelling Cylinder Report BJMR It LWHIS Company: ConocoPhillips (Alaska) Inc. -Kup2 Local Co-ordinate Reference: Well 3Q-14 Project: Kuparuk River Unit TVD Reference: 3Q-14 @ 60.00ft (3Q-14) Reference Site: Kuparuk 3Q Pad MD Reference: 3Q-14 @ 60.00ft (3Q-14) Site Error: 0.00ft North Reference: True Reference Well: 3Q-14 Survey Calculation Method: Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore 30-14AL5 Database: EDM Alaska Prod v16 Reference Design: 3Q-14AL5_wp01 Offset TVD Reference: Offset Datum Offset Design Kuparuk 3Q Pad - 3Q-14 - 3Q-14AL1 - 3Q-14AL1_wp01 Offset Site Error: 0.00ft Survey Program: 100-BOSS-GYRO, 8200-MWD, 10750-MWD Rule Assigned: Major Risk Offset Well Error: 0.00It Reference offset Semi Major Axis Measured Vertical Measured Vertical Reference Offset Toofface+ Offset Wellbore Centre Casing- Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/-S +E/-W Hole Size Centre Distance Deviation iff) Ift) (ft) (ft) Iff) (ft) (1 (ft) (tt) (it) Iff) (ft) V* 8,525,00 6,469.21 8,525.00 6,469,21 0.00 0.00 -145,95 -4,668,02 1,209.98 0.22 0,00 0,29 -0.22 FAIL - Major Risk, CC, ES, SF 8,549,98 6,466.00 8,550.00 6,466.60 0.06 0.02 2.47 -4,688A1 1,195.75 0.22 0.71 0.93 -0,20 FAIL - Major Risk 8,574.83 6,461,74 8,575,00 6,463.99 0.07 0.04 0.72 -4,708.35 1,180.91 0.22 2.74 1.22 1.53 Pass - Major Risk 8,599.46 6,456.48 8,600.00 6,461.35 0.08 0.07 -0.09 -4,72T83 1,165,46 0.22 6.06 1.52 4.55 Pass - Major Risk 8,623,99 6,450.29 8,625.00 6,458,70 0.10 0.10 0,60 -4,746,82 1,149.42 0.22 10,54 1,85 8.74 Pass - Major Risk 8,649,00 6,443.96 8,650.00 6,456,03 0,12 0.13 3.79 -4,765,31 1.132.81 0.22 14.98 2,17 12,89 Pass - Major Risk 8,674,22 6,437.81 8,675,00 6,453.35 0.14 0,16 7.24 -4,783.28 1, 115.64 0.22 19.03 2.53 16.66 Pass - Major Risk 8,699s9 6,432.00 8,700.00 6,450,65 0.16 0.20 8.46 -4,800.71 1,097.92 0.22 22.66 2.91 20.01 Pass - Major Risk 8,725.37 6,427.18 8,725.00 6,447.95 0.18 0.24 5.87 -4,817,59 1,079.68 0.22 25.79 3,35 22.86 Pass - Major Risk 8,751.09 6,423.49 8,750.00 6,445.24 0,21 0.29 1.26 -4,833.91 1,060.93 0,22 28.54 3,79 25.40 Pass - Major Risk 8,776,73 6,420.55 8,775.00 6,442.53 0.24 0.34 -1A9 -4,849,63 1.041.69 0.22 31,17 4.27 27.44 Pass - Major Risk 8,802.56 6,417.60 8,800,00 6,439.82 0.27 0.39 -2.60 -4,864,76 1,021.97 0.22 33.74 4.76 29A6 Pass - Major Risk 8,828.60 6,414.63 8,825.00 6,437.10 0.31 0.45 -2,78 -4,879,28 1,001.80 0.22 36.15 5.29 31.31 Pass - Major Risk 8,854,83 6,41167 8,850,00 6,434,43 0.36 0.51 -2.19 -4,893,17 981.20 0.22 38,36 5.83 32,96 Pass - Major Risk 8,879,98 6 408A6 8,875.00 6,431,98 0.41 0.58 -1.39 -4,906,47 960.17 0.22 40.77 6,40 34.82 Pass - Major Risk 8,905,11 6,404,48 8,900,00 6,429.77 0,46 0.66 0,72 -4,919.17 938,75 0.22 43.72 6,98 37.25 Pass - Major Risk 8,930.43 6,399.74 8,925.00 6,427.79 0.51 0,74 3.53 -4,931.24 916,95 0.22 47.21 7.60 40.21 Pass - Major Risk 8,956,83 6,395.36 8,950.00 6,426,06 0.58 0.82 4.40 -4,942.69 894,79 0.22 50.80 8.26 43.24 Pass - Major Risk 8,983.36 6,392.15 8,975.00 6,424,57 0.65 0.91 4.12 -4,953.49 872,29 0.22 54,26 8.95 46.07 Pass - Major Risk 9,010.12 6,389.94 9,000.00 6,423,33 0.72 1.01 4.48 -4,963,64 849.48 0.22 57.61 9,66 48,73 Pass - Major Risk 9,037A9 6,387.82 9,025,00 6422,34 0.81 1.11 6,37 -4,973,14 826.38 0,22 60.78 10,42 51.18 Pass - Major Risk 9,064,49 6,385,70 9,050,00 6,421.56 0.90 1.21 8.90 -4,982.21 803,09 0.22 63.48 11,16 53.20 Pass - Major Risk 9,091.99 6,383.57 9,075.00 6,420,89 1.01 1.29 12.47 -4,991.86 780.05 0.22 64.75 11.87 53.86 Pass - Major Risk 9,119.45 6,381.46 9,100.00 6,420.32 1.12 1.37 17.08 -5,002.22 757.30 0,22 64.49 12.58 53.06 Pass - Major Risk 9,146,58 6,379.40 9,125,00 6,419.84 1.23 1,46 22.82 -5,013.25 734.87 0.22 62.83 13.30 50.96 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 5/12/2014 10:16:04AM Page 4 of 8 COMPASS 2003.16 Build 69 ORIGINAL .- HAS ConocoPhillips Travelling Cylinder Report BMER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Local Co-ordinate Reference: Well 3Q-14 Project: Kuparuk River Unit TVD Reference: 3Q-14 @ 60.00ft (3Q-14) Reference Site: Kuparuk 3Q Pad MD Reference: 3Q-14 @ 60.00ft (3Q-14) Site Error: 0.00ft North Reference: True Reference Well: 3Q-14 Survey Calculation Method: Minimum Curvature Well Error. 0.00ft Output errors are at 1.00 sigma Reference Wellbore 3Q-14AL5 Database: EDM Alaska Prod v16 Reference Design: 3Q-14AL5_wp01 Offset TVD Reference: Offset Datum Offset Design Kuparuk 3Q Pad - 3Q-14 - 3Q-14AL2 - 3Q-14AL2_wp01 Offset Site Error: 0.00 ft Survey Program: 100-BOSS-GYRO, 8200-MWD, 10150-MWD Rule Assigned: Major Risk Offset Well Error: 0.00 ft 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 +N1-S +E1-W Hole Size Centre Distance Deviation (ft) Ift) (ft) (ft) (ft) (ft) V) Ift) (ft) Oil (ft) (it) (ff) 8,525.00 6,469.21 8,525.00 6,469.21 0.00 0.00 -145.95 -4,668.02 1,209.98 0.22 0.00 0.29 -0.22 FAIL - Major Risk, CC, ES, SF 8,549.98 6,466.00 8,550.00 6,466.60 0.06 0.02 2.47 -4,688.41 1,195.75 0.22 0,71 0.93 -0.20 FAIL - Major Risk 8,574.83 6,461.74 8,575.00 6,463.99 0.07 0,04 0.72 -4,708.35 1,180,91 0.22 2,74 1.22 1.53 Pass - Major Risk 8,599.46 6,456,48 8,600.00 6,461.35 0.08 0.07 -0.09 -4,72T83 1,165,46 0.22 6.06 1,52 4.55 Pass - Major Risk 8,623.99 6,450,29 8,625.00 6,458.70 0.10 0.10 0.60 -4,746.82 1,149.42 0.22 10,54 1.85 8,74 Pass - Major Risk 8,649.00 6,443.96 8,650.00 6,456.03 0.12 0.13 3.79 -4,765.31 1,132.81 0.22 14,98 2.17 12,89 Pass - Major Risk 8,674.22 6,437.81 8,675.00 6,453.35 0.14 0.16 7.24 -4,783.28 1,115.64 0,22 1903. 2.53 16.66 Pass - Major Risk 8,699.69 6,432.00 8,700,00 6,450.65 0,16 0.20 8.46 -4,800.71 1,09T92 0,22 22,66 2.91 20.01 Pass - Major Risk 8,725.37 6,427,18 8,725.00 6,447.95 0.18 0.24 5.87 -4,817.59 1,079,68 0.22 25,79 3,35 22.86 Pass - Major Risk 8,751.09 6,423.49 8,750.00 6,445.24 0.21 0.29 1.26 -4,833.91 1,060,93 0.22 28.54 3.79 25.40 Pass - Major Risk 8,776.73 6,420.55 8,775.00 6,442.53 0.24 0.34 -1,49 -4,849,63 1,041.69 0.22 31.17 4.27 27.44 Pass - Major Risk 8,802,56 6,417.60 8,800.00 6,439.82 0.27 0.39 -2.60 -4,864.76 1,021.97 0.22 33,74 4.76 29.46 Pass - Major Risk 8,828.60 6,414,63 8,825,00 6,437.10 0.31 0,45 -2.78 -4,879.28 1,001,80 0.22 36,15 5.29 31.31 Pass - Major Risk 8,854.83 6,411.67 8,850.00 6,434.43 0.36 0,51 -2.19 -4,893.17 981,20 0,22 38,36 5.83 32,96 Pass - Major Risk 8,379.98 6,408.46 8,875.00 6,431.98 0,41 0,58 -1.39 -4,906A7 960.17 0.22 40.77 6.40 34,82 Pass - Major Risk 8,905.11 6,404.48 8,900.00 6,429.77 0.46 0.66 0.72 -4,919A7 938,75 0.22 43.72 6.98 37.25 Pass - Major Risk 8,930.43 6,399.74 8,925.00 6,427.79 0.51 0.74 3.53 -4,931.24 916,95 0.22 47.21 7.60 40,21 Pass - Major Risk 8,956.83 6.395.36 8,950.00 6,426.06 0.58 0.82 4.40 -4,942.69 894.79 0.22 50.80 8.26 4324 Pass - Major Risk 8,983.36 6,392.15 8,975,00 6,424.57 0.65 0.91 4A2 -4,953.49 872.29 0.22 54.26 8.95 46,07 Pass - Major Risk 9,010.12 6,389.94 9,000.00 6,423.33 0.72 1.01 4,48 -4,963.64 849.48 0.22 5T61 9,66 48,73 Pass - Major Risk 9,037.19 6,387.82 9,025.00 6.422.34 0,81 1.11 6.37 -4,973.14 826.38 0.22 60,78 10.42 51,18 Pass - Major Risk 9,064.49 6,385.70 9,050.00 6,421.56 0.90 1.21 8.90 -4,982.21 803.09 0.22 63.48 11,16 53.20 Pass - Major Risk 9,091.99 6,383.57 9,075.00 6,420,89 1.01 1.29 12.47 -4,991.86 780,05 0,22 64,75 11.87 53.86 Pass - Major Risk 9,119.45 6,381.46 9,100,00 6,420,32 1.12 1.37 17.08 -5,002,22 757.30 0.22 64A9 12.58 53.06 Pass - Major Risk 9,146.58 6,379A0 9,125.00 6,419.84 1.23 1.46 22.82 -5,013,25 734,87 0.22 62.83 13.30 50,96 Pass - Major Risk CC - Min Centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 5/122014 10:16.04AM Page 5 of 8 COMPASS 2003.16 Build 69 ORIGINAL ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Local Co-ordinate Reference: Well 3Q-14 Project: Kuparuk River Unit TVD Reference: 3Q-14 @ 60.00ft (30-14) Reference Site: Kuparuk 3Q Pad MD Reference: 3Q-14 @ 60.00ft (3Q-14) Site Error. 0.00ft North Reference: True Reference Well: 3Q-14 Survey Calculation Method: Minimum Curvature Well Error. 0,00ft Output errors are at 1.00 sigma Reference Wellbore 3Q-14AL5 Database: EDM Alaska Prod v16 Reference Design: 3Q-14AL5_wp01 Offset TVD Reference: Offset Datum Offset Design Kuparuk 3Q Pad - 3Q-14 - 3Q-14AL3 - 3Q-14AL3_wp01 Offset Site Error: 0.00 ft Survey Program: 100-BOSS-GYRO, 8200-MWD, 10080-MWD Rule Assigned: Major Risk Offset Well Error: 0.00 ft 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 (ft) (ft) Ift) (ft) (ft) (ft) V) Ift) 00 (ft) (ft) (rt) (ft) 8,525.00 6,469.21 8,525,00 6,469.21 0.00 0.00 -145.95 -4,668.02 1,209.98 0.22 0.00 0.29 -0.22 FAIL- Major Risk, CC, ES, SF 8,549.98 6,466.00 8,550.00 6,466.60 0.06 0.02 2,47 -4,688,41 1,195.75 0.22 0,71 0.93 -0.20 FAIL - Major Risk 8,574.83 6,461.74 8,575.00 6,463.99 0,07 0.04 0,72 -4,708.35 1,180.91 0.22 2.74 1.22 1.53 Pass - Major Risk 8,599.46 6,456.48 8,600.00 6,461.35 0,08 0.07 -0,09 -4,727.83 1,165.46 0.22 6.06 1,52 4.55 Pass - Major Risk 8,623.99 6,450.29 8,625.00 6,458,70 0.10 0,10 0.60 -4,746.82 1,149.42 0.22 10.54 1,85 8.74 Pass - Major Risk 8,649.00 6,443.96 8,650.00 6,456.03 0.12 0.13 3.79 -4.765.31 1,132.81 0.22 14.98 2,17 12.89 Pass - Major Risk 8,674.22 6,437.81 8,675.00 6,453.35 0,14 0.16 7.24 -4,783,28 1,115.64 0.22 19.03 2.53 16.66 Pass - Major Risk 8,699.69 6,432.00 8,700.00 6,450.65 0.16 0.20 8,46 -4,800,71 1,097.92 0.22 22.66 2,91 20.01 Pass - Major Risk 8,725.37 6,427.18 8,725.00 6,44Z95 0.18 0.24 5.87 -4,817.59 1,079,68 0.22 25.79 3.35 22.86 Pass - Major Risk 8,751.09 6,423.49 8,750.00 6,445.24 0.21 0.29 1.26 -4,833.91 1,060,93 0.22 28.54 3,79 25.40 Pass - Major Risk 8,776.73 6420.55 8,775.00 6,442,53 0,24 0.34 -1.49 -4,849.63 1,041,69 0.22 31 A 4.27 27.44 Pass - Major Risk 8,802,56 6,417,60 8,800.00 6,439.82 0.27 0,39 -2.60 -4,864.76 1,021.97 0.22 33,74 4.76 29A6 Pass - Major Risk 8,828,60 6,414.63 8,825.00 6,437,10 0.31 0.45 -2.78 -4,879.28 1,001.80 0,22 36,15 5.29 31,31 Pass - Major Risk 8,854.83 6,411.67 8,850.00 6,434.43 0.36 0,51 -2,19 -4,893.17 981.20 0.22 38,36 5S3 32.96 Pass - Major Risk 8,879.98 6,408.46 8,875.00 6,431.98 0,41 0.58 -1,39 -4,906.47 960,17 0.22 40.77 6.40 34.82 Pass - Major Risk 8,905,11 6,404A8 8,900.00 6429,77 0,46 0.66 0.72 -4,919.17 938,75 0.22 43.72 6.98 37.25 Pass - Major Risk 8,930.43 6,399.74 8,925.00 6,427.79 0.51 0,74 3,53 -4,931.24 916.95 0.22 47.21 7.60 40.21 Pass - Major Risk 8,956.83 6,395.36 8,950.00 6,426.06 0,58 0,82 4,40 -4,942.69 894.79 0.22 50,80 8.26 43.24 Pass - Major Risk 8,983.36 6,392.15 8,975.00 6,424.57 0.65 0,91 4,12 -4,953.49 872.29 0.22 54,26 8,95 46.07 Pass - Major Risk 9,010.12 6,389.94 9,000.00 6,423,33 0.72 1_01 4.48 -4,963.64 849.48 0.22 57.61 9.66 48.73 Pass - Major Risk 9,037.19 6,38Z82 9,025.00 6,422,34 0.81 1.11 6.37 -4,973.14 826.38 0.22 60.78 10,42 51.18 Pass - Major Risk 9,064.49 6,385,70 9,050,00 6,421.56 0.90 1.21 8.90 -4,982.21 803.09 0.22 63.48 11.16 53.20 Pass - Major Risk 9,091.99 6,383.57 9,075.00 6,420.89 1.01 1.29 12.47 -4,991,86 780.05 0.22 64.75 11.87 53.86 Pass - Major Risk 9,119.45 6,381.46 9,100.00 6,420.32 1,12 1.37 1Z08 -5,002.22 757.30 0.22 64.49 12,58 53,06 Pass - Major Risk 9,146.58 6,379.40 9,125,00 6,419,84 1.23 1A6 22.82 -5,013.25 734.87 0.22 6283 13.30 50,96 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 511212014 10:16:04AM Page 6 of 8 COMPASS 2003.16 Build 69 Has ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Local Co-ordinate Reference: Well 3Q-14 Project: Kuparuk River Unit TVD Reference: 3Q-14 @ 60.00ft (30-14) Reference Site: Kuparuk 3Q Pad MD Reference: 3Q-14 @ 60.00ft (3Q-14) Site Error: 0.00ft North Reference: True Reference Well: 3Q-14 Survey Calculation Method: Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore 3Q-14AL5 Database: EDM Alaska Prod v16 Reference Design: 30-14AL5_wp01 Offset TVD Reference: Offset Datum Offset Design Kuparuk 3Q Pad - 3Q-14 - 3Q-14AL4 - 3Q-14AL4_wp01 offset site Error: 0 00 It Survey Program: 100-BOSS-GYRO, 8200-MWD, 9305-MWD Rule Assigned: Major Risk Offset Well Error: 0.00 ft Reference Offset Semi Major Axis Measured Vertical Measured Vertical Reference Offset Toofface+ Offset Wellbore Centre Casing - Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/-S +E/-W Hole Size Centre Distance Deviation (ft) (I (ft) (ftl (1 (ft) 1°) ift) iff) (ft) (ft) (ft) Ift) 8,525.00 6,469.21 8,525.00 6,469.21 0.00 0.00 -145.95 -4,668.02 1,209.98 0.22 0.00 0,29 -0.22 FAIL - Major Risk, CC, ES, SF 8,549.98 6,466.00 8,550.00 6,466.60 0.06 0.02 2.47 -4,688.41 1,195.75 0.22 0.71 0,93 -0.20 FAIL - Major Risk 8,574.83 6,461.74 8,575.00 6,463.99 0.07 0.04 0.72 -4,708.35 1,180.91 0.22 2.74 1.22 1.53 Pass - Major Risk 8,599.46 6,456.48 8,600.00 6,461.35 0.08 0.07 -0.09 -4,727.83 1,165.46 0.22 6.06 1.52 4.55 Pass - Major Risk 8,623.99 6,450.29 8,625.00 6,458.70 0.10 0.10 0.60 -4,746.82 1,149.42 0.22 10,54 1.85 8.74 Pass - Major Risk 8,649.00 6,443.96 8,650.00 6,456.03 0.12 0.13 3.79 -4,765.31 1,132.81 0.22 14.98 2.17 12.89 Pass - Major Risk 8,674.22 6,437.81 8,675.00 6,453.35 0.14 0.16 7.24 -4,783.28 1,115.64 0.22 19.03 2.53 16.66 Pass - Major Risk 8,699.69 6,432.00 8,700.00 6,450.65 0.16 0.20 8.46 -4,800.71 1,097.92 0.22 22.66 2.91 20.01 Pass - Major Risk 8,725.37 6,427.18 8,725.00 6,447.95 0.18 0.24 5.87 -4,817.59 1,079.68 0.22 25.79 3.35 22.86 Pass - Major Risk 8,751.09 6,423.49 8,750.00 6,445.24 0.21 0.29 1.26 -4,833.91 1,060.93 0.22 28.54 3.79 25.40 Pass - Major Risk 8,776.73 6,420.55 8,775.00 6,442.53 0.24 0.34 -1.49 -4,849.63 1,041.69 0.22 31.17 4.27 27.44 Pass - Major Risk 8,802.56 6,417.60 8,800.00 6,439.82 0.27 0.39 -2.60 -4,864.76 1,021.97 0.22 33.74 4.76 29.46 Pass - Major Risk 8,828.60 6,414.63 8,825.00 6,437.10 0.31 0.45 -2.78 -4,879.28 1,001.80 0.22 36.15 5.29 31.31 Pass - Major Risk 8,854.83 6,411.67 8,850.00 6,434.43 0.36 0.51 -2.19 -4,893.17 981.20 0.22 38.36 5.83 32.96 Pass - Major Risk 8,879.98 6,408.46 8,875.00 6,431.98 0.41 0.58 -1.39 -4,906.47 960.17 0.22 40.77 6.40 34.82 Pass - Major Risk 8,905.11 6,404.48 8,900.00 6,429.77 0.46 0.66 0.72 -4,919.17 938.75 0.22 43.72 6.98 37.25 Pass - Major Risk 8,930.43 6,399.74 8,925.00 6,427.79 0.51 0.74 3.53 -4,931.24 916.95 0.22 47.21 7.60 40.21 Pass - Major Risk 8,956.83 6,395.36 8,950.00 6,426.06 0.58 0.82 4.40 -4,942.69 894.79 0.22 50.80 8.26 43.24 Pass - Major Risk 8,983.36 6,392.15 8,975.00 6,424.57 0.65 0.91 4A2 -4,953.49 872.29 0.22 54.26 8.95 46.07 Pass - Major Risk 9,010.12 6,389.94 9,000.00 6,423.33 0.72 1.01 4.48 -4,963.64 849.48 0.22 57.61 9.66 48.73 Pass - Major Risk 9,037.19 6,387.82 9,025.00 6,422.34 0.81 1.11 6.37 -4,973.14 826.38 0.22 60.78 10.42 51.18 Pass - Major Risk 9,064.49 6,385.70 9,050.00 6,421.56 0.90 1.21 8.90 -4,982.21 803.09 0.22 63.48 11.16 53.20 Pass - Major Risk 9,091.99 6,383.57 9,075.00 6,420.89 1.01 1.29 12.47 -4,991.86 780.05 0.22 64.75 11.87 53.86 Pass - Major Risk 9,119.45 6,381.46 9,100.00 6,420.32 1.12 1.37 17.08 -5,002.22 757.30 0.22 64.49 12.58 53.06 Pass - Major Risk 9,146.58 6,379.40 9,125.00 6,419.84 1.23 1.46 22.82 -5,013.25 734.87 0.22 62.83 13.30 50.96 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 5112/2014 10:16:04AM Page 7 of 8 COMPASS 2003,16 Build 69 0 R 1G'* I N A L /.h/ ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3Q Pad Site Error: 0.00ft Reference Well: 3Q-14 Well Error: 0.00ft Reference Welibore 3Q-14AL5 Reference Design: 3Q-14AL5_wp01 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 3Q-14 3Q-14 @ 60.00ft (30-14) 3Q-14 @ 60.00ft (3Q-14) True Minimum Curvature 1.00 sigma EDM Alaska Prod v16 Offset Datum eference Depths are relative to 3Q-14 @ 60.00ft (3Q-14) Coordinates are relative to: 3Q-14 Iffset Depths are relative to Offset Datum Coordinate System is US State Plane 1927, Alaska Zone 4 entral Meridian is 150' 0' 0.000 W ° Grid Convergence at Surface is: 0.12' Ladder Plot so 60 c 0 co Q N CO N (r-D 40 U _o a� C a)U 20 0 0 1500 3000 4500 6000 7500 9000 Measured Depth LEGEND —0-3Q-14, 3Q-14A, 3Q-14A_wp04 V0 3Q-14, 3Q-14AL2, vvp 3Q-14AL2_01 VO —8-3Q-14, 3414AL4, 3Q-14AL4 W:)01 VO $ 3Q-14, 3Q-14AL1, 3Q-14AL1_m 01 VO 3Q-14, 3Q-14AL3, 3Q-14AL3_wp01 VO I G I I I I I I I I I I i I I I I I I I I I I I I i I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I 1 I I I I I I I I I I I I I I I I 1 I I I I I I I I I 1 I I I I I I I I I i I I I I I I I I I I I 1 I I I I 1 I I I I I I I I I i I I I I I I I I I I I I I I t I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I 1 1 1 I I I 1 1 IOR CC -Min centre to center distance or covergent point, SF -min separation factor, ES -min ellipse separation 5/12/2014 10:16:04AM Page 8 of 8 COMPASS 2003.16 Build 69 � \© � � m a } � . / % § \ \ ) * s)( qu +u o j . . . /\ -j� _ \ )§\ \ )/ k)§jj\j)) §q _■�,�2�� § \ 04 )BEEBESSE § {2 9§«=2k§&# ]/ _____ / Lo \ }d)§))§)\ § 7§»7777§ = \§ k)§()k§§§ 0 )))j.cl! }8 I (u aggaE§7a §gAgqmmq5 a a_--_---- fCD ORIGINAL _,LOS _. (ui@ s»;a1o(I t *o o I \ % k WELL NAME: lC(a(,� 3 g — I4 ALS PTD: � 1 Y 0g "Development Service Exploratory Stratigraphic Test Non -Conventional FIELD: Y�c� i '�Ls— POOL: �"A/ i ✓ �� 1 %— Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing well Permit (If last two digits No. �I V Ogg , API No. 50- 01� _- 0,166S -_.CLL-00 . in API number are Production should continue to be reported as a function of the original between 60-69) API number stated above. In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name Pilot Hole ( PH) and API number (50- - - - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce / inject is contingent upon issuance of a Spacing Exception conservation order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are Well Logging also required for this well: Requirements per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 4/2014 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 PTD#:2140870 Com Administration 1 2 3 4 5 6 7 8 9 10 11 Appr Date 12 13 PKB 6/19/2014 14 15 16 17 18 Engineering 19 20 21 22 23 24 25 26 27 Appr Date 28 VLF 6/20/2014 29 30 31 32 33 34 35 Geology 36 Appr Date 37 PKB 6/19/2014 38 39 ny CONOCOPHILLIPS ALASKA INC Initial ClassF Permit fee attached Lease number appropriate Unique well name and number Well located in a defined pool Well located proper distance from drilling unit boundary Well located proper distance from other wells Sufficient acreage available in drilling unit If deviated, is wellbore plat included Operator only affected party Operator has appropriate bond in force Permit can be issued without conservation order Permit can be issued without administrative approval Can permit be approved before 15-day wait Well located within area and strata authorized by Injection Order # (put 10# in comments) (For All wells within 1/4 mile area of review identified (For service well only) Pre -produced injector: duration of pre -production less than 3 months (For service well only) Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D) Conductor string provided Surface casing protects all known USDWs CMT vol adequate to circulate on conductor & surf csg CMT vol adequate to tie-in long string to surf csg CMT will cover all known productive horizons Casing designs adequate for C, T, B & permafrost Adequate tankage or reserve pit If a re -drill, has a 10-403 for abandonment been approved Adequate wellbore separation proposed If diverter required, does it meet regulations Drilling fluid program schematic & equip list adequate BOPEs, do they meet regulation BOPE press rating appropriate; test to (put psig in comments) Choke manifold complies w/API RP-53 (May 84) Work will occur without operation shutdown Is presence of H2S gas probable Mechanical condition of wells within AOR verified (For service well only) Permit can be issued w/o hydrogen sulfide measures Data presented on potential overpressure zones Seismic analysis_ of shallow gas zones Seabed condition survey (if off -shore) Contact name/phone for weekly progress reports_ [exploratory only) Geologic Engineering Public Commissioner: Date: Commissioner: Date Commissioner Date NA Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes NA NA NA NA NA NA NA NA Yes Yes Yes NA Yes NA Yes Yes Yes Yes Yes Yes NA No Yes NA _NA_ NA Well Name: KUPARUK RIV UNIT 3Q-14AL5 DEV / PEND GeoArea 890 Unit 11160 Program DEV Well bore seg V On/Off Shore On Annular Disposal ADL0025512, entire wellbore KRU 30-14AL5 KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order 432C CO 432C contains no spacing restrictions with respect to drilling unit boundaries. CO 432C has no interwell spacing restrictions. Wellbore will be more than 500' from an external property line where ownership or landownership changes. Conductor set in 3Q-14 Surface casing set in 3Q-14 Surface casing set and fully cemented Productive interval will be completed with slotted liner Rig has steel tanks, all waste to approved disposal wells Anti -collision analysis performed; major failures with laterals in same producing interval Max formation pres is 4378 psi(13.2 ppg EMW); will drill w/ 9.2 ppg EMW and maintain overpressure w/ MPD MPSP is 3728 psi; will test BOPS to 4200 psi H2S measures required Wells on 3Q-Pad are H2S bearing. H2S measures required. Expected reservoir pressure is 7.3 ppg EMW, but may range to 13.23_ppg; will be drilled using 9.2 ppg mud and MPD technique. Two wellbore volumes of 13.1 ppg KWF will be available. Onshore development well. - - - - - -------------- ---------
