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216-090
Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Friday, August 31, 2018 10:57 AM To: 'Starck, Kai' Cc: Loepp, Victoria T (DOA); Davies, Stephen F (DOA); Boyer, David L (DOA) Subject: Expired Permits to Drill: KRU 2B-02A L2 and KRU 213-02A 1-2-01 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 213-02A L2, PTD 216-090, Issued 16 August 2016 • KRU 26-02A 1-2-01, PTD 216-090, Issued 16 August 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. 1 THE STATE 01ALASKA GOVERNOR BILL WALKER Jason Burke CTD Coordinator ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.alaska.gov Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 213-02AL2 ConocoPhillips Alaska, Inc. Permit to Drill Number: 216-090 Surface Location: 744' FSL, 273' FEL, SEC. 19, Tl 1N, R9E, UM Bottomhole Location: 1946' FSL, 2456' FEL, SEC. 30, T11N, R9E, UM Dear Mr. Burke: Enclosed is the approved application for permit to re -drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 216-087, API No. 50-029- 21154-01-00. 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 P. Foerster Chair DATED this �� day of August, 2016. RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 JUL 13 2016 ." AOG :C 1a. Type of Work: / 1b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp V c. Specify if well is proposed for: Drill LJ Lateral m Stratigraphic Test ❑ Development - Oil Service - Winj ❑ Single Zone Coalbed Gas ❑ Gas Hydrates ❑ Redrill 1 Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑✓ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name and Number: ConocoPhillips Alaska Inc Bond No. 5952180 2B-02AL2 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 9900' TVD: 6091 Kuparuk River Field / Kuparuk Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): qlL Surface: 744' FSL, 273' FEL, Sec 19, T11N, R9E, UM ADL 25656 I A 6!6 J Top of Productive Horizon: 8. Land UsePermit: 13. Approximate Spud Date: 2909' FSL, 1652' FEL, Sec 30, T11 N, R9E, UM ALK 2582 9/15/2016 Total Depth 9. Acres in Property: to Nearest Property: . 1946' FSL, 2456' FEL, Sec 30, T11 N, R9E, UM 2560 j' 18000stance 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Eleev"`ation above MSL (ft): ( (e 15. Distance to Nearest Well Open Surface: x-508371 y- 5954890 Zone-4 GL Elevation above MSL (ft): 92' to Same Pool: 950' (213-07) 16. Deviated wells: Kickoff depth: 6630 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 99 degrees . Downhole: 3973 psi , Surface: 3369 psi + 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2-3/8" 4.7# L-80 ST-L 1600' 8300' 6123' 9900, 6091 N/A 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): 6976 6322 N/A 6851 6216 Fish - 6685' MD Casing Length Size Cement Volume MD TVD Conductor/Structural 110' 16" 119 sx Cold Set II 110' 110, Surface 2727' 9.625" 800 sx Cold Set III, 300 sx Cold Set II 2727' 2727' Intermediate Production 6934' 7" 280 sx Class G, 250 sx Cold Set I 16934' 6287' Liner Perforation Depth MD (ft): 6526'-6568', Perforation Depth TVD (ft): 5943'-5978', 6022'-6098' 6620'-6710' 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis[] Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements0 21. Verbal Approval: Commission Representative: Date 7�o fj 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not Mike Callahan 263-4180 be deviated from without prior written approval. Contact mike.callahan(a)-cop.com Email Printed Name Jason Burke Title CTD Coordinator Signatur '— Phone 265-6097 Date Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number.JUG D 50- Q 1,5q — Date: I requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: 13o p ft 5 f h..-rss `v Y..G tp } �j 0 n 5 ycr Samples req'd: Yes ❑ No [A Mud log req'd: Yes ❑ Noy /P re rrwt, �-r r 4-r51— tz' Z ���/ %�512S measures: Yes E6 No ❑,/ Directional svy req'd: Yes [� No Spacing exception req'd: Yes ❑ NoLZ Inclination -only svy req'd: Yes❑ No� Post initial injection MIT req'd: Yes❑ Nopr APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: $— 6 . 0//5/ I(c Submit Form and Form 10401 (Revised 11/2015) This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) Attachments in Duplicate ORIGINAL �� ���sr�s- 'r� 4/ ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 July 13, 2016 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill 5 laterals out of the Kuparuk Well 213-02 using the coiled tubing drilling rig, Nabors CDR2-AC or 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. A sundry application is attached to plug the KRU 213-02 (184-122) perforations to allow these laterals to be drilled. As detailed in the attachments, ConocoPhillips requests a variance from the requirements of 20 AAC 25.112(c)(1) to plug the A/C -sand perforations in 213-02. Attached to this application are the following documents: — 10-403 Sundry Application to Abandon KRU 213-02 (184-122) — Operations Summary in support of the 10-403 sundry application — 10-401 Applications for 213-02A, 213-02AL1, 213-02AL1-01, 213-02AL1-02, and 213-02AL2 — Detailed Summary of Operations — Directional Plans for 213-02A, 213-02AL1, 213-02AL1-01, 213-02AL1-02, and 213-02AL2 — Proposed CTD Schematic If you have any questions or require additional information, please contact me at 907-263-4180. Sincerely, Mike Callahan ConocoPhillips Alaska Coiled Tubing Drilling Engineer = . Kuparuk CTD Laterals NAWASA ASKA .nw.,. 213-02A, AL1, AL1 -011 AL2 & AL2-01 CDq, 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.............................................................................................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. Attachments.......................................................................................................................................7 Attachment 1: Directional Plans for 213-02A, AL1, AL1-01, AU & AL2-01 laterals....................................................... 7 Attachment 2: Current Well Schematic for 213-02........................................................................................................... 7 Attachment 3: Proposed Well Schematic for 213-02A, AL1, AL1-01, AL2 & AL2-01 laterals ........................................... 7 Page 1 of 7 July 13, 2016 PTD Application: 213-02A, AL1, AL1-01. AL2 & Al2-01 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 213-02A, 28-02AL1, 26-02AL1-01, 26-02AL2, & 26- 02AL2-01. All laterals will be classified as Production wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 form for surface and subsurface coordinates of the 26-02A, 213-02AL1, 213-02AL1-01, 213-02AL2, & 26-02AL2-01. 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 3750 psi. Using the maximum formation pressure in the area of 3973 psi in 26-08 (12.6 ppg EMW), the maximum potential surface pressure in 26-02, assuming a gas gradient of 0.1 psi/ft, would be 3369 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 213-02 was measured to be 2142 psi (6.9 ppg EMW) on 5/7/2016. The maximum downhole pressure in the 213-02 vicinity is to the west in the 26-08 injector at 3973 psi (12.6 ppg EMW) from March of 2014. Pressure management in the area is expected to bring the formation pressure down to --11.0 ppg by the time of drilling. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) Wells on 213 pad have injected gas, so there is a chance of encountering free gas while drilling the 26-02 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 213-02 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 26-02 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 July 13, 2016 PTD Application: 213-02A, AL1, AL1-01. AL2 & AL2-01 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 MD MD TVDSS TVDSS Liner Details 213-02A 8385' 9900, 5993' 5969' 2-3/8", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 2B-02AL1 8500' 10425' 5899' 2-3/8", 4.7#, L-80, ST-L slotted liner; E5871,1' aluminum billet on to 2B-02AL1-01 6630' 9800' 5989 2-3/8", 4.7#, L-80, ST-L slotted liner; deployment sleeve on to 2B-02AL2 8300' 9900, 5997' 5965' 2-3/8", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 26-02AL2-01 6600' 10500' 5879' 5896' 2-3/8", 4.7#, L-80, ST-L slotted liner; deployment sleeve on to Existing Casing/Liner Information Category Conductor OD 16" Weight P 62.5 Grade H-40 Connection Welded Top MD 0' Btm MD 110, Top TVD 0' Btm TVD 110, Burst psi 1640 Collapse psi 670 Surface 9-5/8" 36.0 J-55 BTC 0' 2727' 0' 2727' 3620 2020 Production 7" 26.0 J-55 BTC 0' 6934' 0' 6287' 4980 4320 Tubing 3-1/2" 9.3 J-55 EUE-8rd 0 6616' 0 6019' 6980 7400 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) Nabors CDR2-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a diverter system is not required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System A diagram of the Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System — Window milling operations: Chloride -based FloVis mud (8.6 ppg) — Drilling operations: Chloride -based FloPro mud (8.6 ppg). This mud weight will not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. — Completion operations: The well will be loaded with 11.8 ppg NaBr completion fluid (unless unexpected, higher pressure is encountered, in which case higher density NaBr or potassium formate will be used) in order to provide formation over -balance and well bore stability while running completions. Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000 psi rated coiled tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". In the 213-02 laterals we will target a constant BHP of 11.8 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 Page 3 of 7 July 13, 2016 PTD Application: 213-02A, AL1, AL1-01, AL2 & AL2-01 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 2B-02 Window 16640' MD_ 6039' Tvni I kinn Mpn Pumps On 1.5 b m Pum s Off A -sand Formation Pressure (6.9 p 2158 psi 2158 nsi Mud H drosta-c 8.6 2701 psi 2701 si Annular friction i.e. ECD, 0.090 psi/ft) 598 psi 0 psi Mud + ECD Combined no choke pressure)299 3 psi 2701 psi Ta rg et BHP at Window 11.8 3706 psi 3706 psi Choke Pressure eegBuireed to Maintain Tar 407 psi 1005 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 KRU well 213-02 is a Kuparuk A/C -sand producer equipped with 3-1/2" tubing and 7" production casing. The CTD sidetrack will utilize up to five laterals to target the A3/A4 sands to the north and south of 213-02. Prior to CTD operations, E-Line will punch 2' of holes in the 3-1/2" tubing tail at 6609' MD and the "D" nipple at 6611' MD will be milled out to a 2.80" ID. The existing C-Sand perforations will be squeezed with cement to abandon the C-Sand. A second cement job will then be performed to cover the A -Sand perfs and provide the cement pilot hole for the kick -out of the 7" casing. ConocoPhillips requests a variance from the requirements of 20 AAC 25.112(c)(1) to plug the A -sand and C-sand perforations in this manner. Following the cement squeeze Nabors CDR2-AC will drill a pilot hole to 6650' MD and set a mechanical whip -stock in the 2.80" pilot hole to kick off at 6640' MD. All five 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 July 13, 2016 PTD Application: 213-02A, AL1, AL1-01. AL2 & AL2-01 213-02A southern lateral will exit the cement pilot hole at 6640' MD and TD at 9900' MD, targeting the A4 and A3 Sands. It will be completed with 2-3/8" slotted liner from TD up to 8385'MD with an aluminum billet for kicking off the 213-02AL1. The 213-02AL1 lateral will kickoff of the aluminum billet at 8385' and drill to the north to a TD of 10425' MD targeting the A4 Sand. It will be completed with 2-3/8" slotted liner from TD up to 8500' MD with an anchored billet for kicking off the 213-02AL 1-01. The 213-02AL1-01 lateral will kickoff the anchored billet at 8500' and drill to the north to a TD of 9800' MD, targeting the A3 Sand. It will be completed with 2-3/8" slotted liner from TD back into the cement pilot hole with a deployment sleeve. The 213-02AL2 lateral will exit the cement pilot hole at 6630' and drill to the south to a TD of 9900' MD. It will be completed with 2-3/8" slotted liner from TD up to 8300' MD with an anchored billet for kicking off the 2B-02AL2-01. The 2B-02AL2-01 lateral will kickoff the anchored billet at 8300' and drill to the north to a TD of 10500' MD. It will be completed with 2-3/8" slotted liner from TD back into the 3-1/2" tubing tail with a deployment sleeve. Pre-CTD Work 1. RU Slickline: Obtain SBHP, dummy off gas lift mandrels, and pressure test. 2. RU E-line: Punch 2' of holes in the 3%" tubing tail at 6609' MD. 3. RU Pumping Unit: perform injectivity test down the tubing. 4. RU Service Coil: Mill out "D" nipple and cement squeeze the C-sand perforations. Wait on cement for 72 hours. 5. RU Service Coil: Cement squeeze A -Sand perforations and leave plug for cement pilot hole. 6. RU Slick -line: Tag top of cement and pressure test cement. 7. Prep site for Nabors CDR2-AC and set BPV. Riz Work 1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 213-02A Sidetrack (A3/A4 Sands - South) i. Drill 2.80" high -side pilot hole through cement to 6670' MD ii. Caliper pilot hole iii. Set top of whip -stock at 6640' MD iv. Mill 2.80" window at 6640' MD. v. Drill 3" bi-center lateral to TD of 9900' MD. vi. Run 2%" slotted liner with an aluminum billet from TD up to 8385' MD. 213-02AL 1 Lateral (A4 Sand - North) i. Kickoff of the aluminum billet at 8385' MD. ii. Drill 3" bi-center lateral to TD of 10425' MD. iii. Run 2%" slotted liner with anchored billet from TD up to 8500' MD. Page 5 of 7 July 13, 2016 PTD Application: 2B-02A. AL1_ AL1-11111_ Al 2 P. All 9-ni 4. 213-02AL1-01 Lateral (A3 Sand - North) i. Kickoff of the aluminum billet at 8500' MD. ii. Drill 3" bi-center lateral to TD of 9800' MD. iii. Run 2%" slotted liner with deployment sleeve from TD up to 6635' MD. 5. 213-02AL2 Lateral (A3/A4 Sand - South) i. Set top of whipstock at 6630' MD. ii. Mill 2.80" window at 6630' MD iii. Drill 3" bi-center lateral to TD of 9900' MD. iv. Run 2%" slotted liner with anchored billet from TD up to 8300' MD. 213-02AL2-01 Lateral (A3/A4 Sand - North) i. Kick off of the aluminum billet at 8300' MD. ii. Drill 3" bi-center lateral to TD of 10500' MD. iii. Run 2%" slotted liner with deployment sleeve from TD up to 6600' MD. 7. Freeze protect, set BPV, ND BOPE, and RDMO Nabors CRD2-AC. Post -Rip Work 1. Pull BPV 2. Obtain SBHP 3. Install gas lift design 4. Return to production Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slick -line lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slick -line. — 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 26-02 laterals will be displaced to an overbalancing fluid (11.8 ppg NaBr) prior to running liner. See "Drilling Fluids" section for more details. Page 6 of 7 July 13, 2016 PTD Application: 213-02A, AL1, AU-01. AL2 & AL2-01 — While running 2-3/8" slotted liner, a joint of 2-3/8" 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 2-3/8" rams will provide secondary well control while running 2-3/8" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) — The Applicant is the only affected owner. — Please see Attachment 1: Directional 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 I Distance 2B-02A 18000' 2B-02AL1 18900, 26-02AL1-01 18900' 2B-02AL2 18000' 2B-02AL2-01 18900' — Distance to Nearest Well within Pool Lateral Name Distance Well 213-02A 950' 213-07 2B-02AL1 1580' 213-08 2B-02AL1-01 1475' 26-08 213-02AL2 950' 213-07 2B-02AL2-01 1465' 213-08 16. Attachments Attachment 1: Directional Plans for 2B-02A, AL 1, AL 1-01, AL2 & AL2-01 laterals Attachment 2: Current Well Schematic for 2B-02 Attachment 3: Proposed Well Schematic for 2B-02A, AL 1, AL1-01, AL2 & AL2-01 laterals Page 7 of 7 July 13, 2016 -4- ZZE cc i - 1 r .... ....... . . W-) (AYONOAMOS Fl I I ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 213 Pad 2B-02 2B-02AL2 Plan: 2B-02AL2_wp02 Standard Planning Report 11 July, 2016 WE I BAKER HUGNES ✓ ConocoPhillips F&A.■ ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska NSK Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2B Pad Well: 213-02 Wellbore: 2B-02AL2 Design: 2 B-02AL2_wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2B-02 Mean Sea Level 2B-02 @ 126.00usft (26-02) True Minimum Curvature 3roject Kuparuk River Unit, North Slope Alaska, United States Nap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level 3eo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Nap Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk 2B Pad Site Position: Northing: 5,954,944.68 usft Latitude: 70° 17' 17.239 N From: Map Easting: 508,346.10usft Longitude: 149° 55' 56.803 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.06 ° Well 2B-02 Well Position +N/-S 0.00 usft Northing: 5,954,890.07 usft Latitude: 70° 17' 16.702 N +E/-W 0.00 usft Easting: 508,370.93 usft Longitude: 149° 55' 56.081 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft -- Wellbore 2B-02AL2 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BG G M 2016 10/1 /2016 17.90 80.90 57,541 Design 2B-02AL2_wp02 Audit Notes: Version: Phase: PLAN Tie On Depth: 6,600.00 Vr (usft) ✓� (usft) (usft) 0.00 0.00 - 0.00 — 200.00 - — 711112016 12:15:05PM Page 2 COMPASS 5000.1 Build 74 ConocoPhillips Database: EDM Alaska NSK Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2B Pad Well: 2B-02 Wellbore: 2B-02AL2 Design: 2B-02AL2 wp02 ConocoPhillips Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2B-02 Mean Sea Level 2B-02 @ 126.00usft (2B-02) True Minimum Curvature rifaI BAKER HUGHES Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N1-S +E/-W Rate Rate Rate TFO (usft) (°) (I (usft) (usft) (usft) (°1100ft) (`/100ft) (°1100ft) (°) Target 6,600.00 32.25 197.72 5.879.25 -1,819.78 -673.36 0.00 0.00 0.00 0.00 6,630.00 32.32 197.84 5.904.61 -1,835.04 -678.25 0.32 0.23 0.40 42.53 6,651.00 36.52 197.84 5,921.93 -1,846.34 -681.88 20.00 20.00 0.00 0.00 6,799.70 96.00 197.84 5,979.14 -1,970.17 -721.74 40.00 40.00 0.00 0.00 6,900.00 97.95 185.87 5,966.92 -2,067.41 -742.18 12.00 1.94 -11.93 280.00 7,000.00 88.08 179.02 5,961.66 -2,167.00 -746.40 12.00 -9.86 -6.85 215.00 7,200.00 86.22 202.98 5,971.76 -2,361.65 -784.20 12.00 -0.93 11.98 95.00 7,350.00 86.40 184.94 5,981.49 -2,506.31 -820.16 12.00 0.12 -12.02 270.00 7,450.00 96.23 178.05 5,979.19 -2.606.07 -822.78 12.00 9.83 -6.89 325.00 7,520.00 91.38 184.93 5,974.54 -2,675.83 -824.61 12.00 -6.93 9.82 125.00 7,720.00 87.22 208.57 5,977.02 -2,865.94 -881.79 12.00 -2.08 11.82 100.00 7,870.00 85.81 226.55 5,986.22 -2,984.14 -972.67 12.00 -0.94 11.99 95.00 7,940.00 85.85 234.97 5,991.32 -3,028.27 -1,026.69 12.00 0.06 12.03 90.00 8,010.00 89.43 242.58 5,994.20 -3,064.49 -1,086.45 12.00 5.11 10.87 65.00 8,300.00 89.53 277.38 5,996.92 -3,114.17 -1.367.64 12.00 0.04 12.00 90.00 8,400.00 90.58 289.33 5,996.82 -3,091.11 -1,464.76 12.00 1.05 11.95 85.00 8,500.00 99.03 280.77 5,988.44 -3,065.23 -1,560.80 12.00 8.45 -8.56 315.00 8,650.00 99.20 262.54 5,964.48 -3,060.96 -1,708.19 12.00 0.11 -12.15 272.00 8,750.00 97.96 250.47 5,949.51 -3,084.01 -1,804.15 12.00 -1.24 -12.07 265.00 8,900.00 88.78 234.94 5,940.64 -3,152.47 -1,936.62 12.00 -6.12 -10.35 240.00 9,300.00 89.93 186.95 5,945.44 -3,485.56 -2,136.34 12.00 0.29 -12.00 271.00 9,400.00 87.86 175.13 5.947.38 -3,585.34 -2,138.16 12.00 -2.07 -11.82 260.00 9,500.00 87.91 187.14 5,951.09 -3,685.07 -2,140.13 12.00 0.05 12.01 90.00 9,600.00 87.95 199.15 5,954.72 -3,782.21 -2,162.82 12.00 0.05 12.01 90.00 9,900.00 88.34 163.13 5,964.75 -4,077.07 -2,168.66 12.00 0.13 -12.01 270.00 711112016 12:15:05PM Page 3 COMPASS 5000.1 Build 74 ConocoPhillips MCA .. ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska NSK Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2B Pad Well: 2B-02 Wellbore: 213-02AL2 Design: 2B-02AL2_wp02 Planned Survey Measured TVD Below Depth Inclination Azimuth System (usft) (°) (°) (usft) 6,600.00 32,25 197.72 5,879.25 TIP 6,630.00 32.32 197.84 5,904.61 KOP 6.651.00 36.52 197.84 5.921.93 End 20 dis, Start 40 dis 6,700.00 56.12 197.84 5,955.61 6,799.70 96.00 197,84 5,979.14 End 40 dls, Start 12 dis 6,800.00 96.01 197.80 5,979.11 6,900.00 97.95 185.87 5,966.92 6 7,000.00 88.08 179.02 5,961.66 6 7,100.00 87.09 190.99 5,965.89 7,200.00 86.22 202.98 5,971.76 7 7,300.00 86.30 190.95 5,978.31 7,350.00 86.40 184.94 5,981.49 8 7,400.00 91.32 181.50 5,982.49 7,450.00 96.23 178.05 5,979.19 9 7,500.00 92.77 182.97 5,975.27 7,520.00 91.38 184.93 5,974.54 10 7,600.00 89.70 194.38 5,973.78 7,700.00 87.62 206.20 5,976.12 7,720.00 87.22 208.57 5,977.02 11 7,800.00 86.42 218.15 5,981.47 7,870.00 85.81 226.55 5,986.22 12 7,900.00 85.82 230.16 5,988.41 7,940.00 85.85 234.97 5,991.32 13 8,000.00 88.92 241.49 5.994.06 8,010.00 89.43 242.58 5,994.20 14 8,100.00 89.44 253.38 5,995.10 8,200.00 89.47 265.38 5,996.05 8,300.00 89.53 277.38 5,996.92 15 8,400.00 90.58 289.33 5,996.82 16 8,500.00 99.03 280.77 5,988.44 17 8,600.00 99.24 268.62 5,972.50 8,650.00 99.20 262.54 5,964.48 18 8,700.00 98.63 256.50 5,956.73 8,750.00 97.96 250.47 5,949.51 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2B-02 Mean Sea Level 2B-02 @ 126.00usft (2B-02) True Minimum Curvature Vertical Dogleg Toolface Map Map +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (usft) (usft) (°/100ft) (°) (usft) (usft) -1,819.78 -673.36 1,940.34 0.00 0.00 5,953,069.72 507,699.67 -1,835.04 -678.25 1,956.35 0.32 42.53 5,953,054.46 507,694.79 -1,846.34 -681.88 1,968.21 20.00 0.00 5,953,043.16 507,691.17 -1,879.91 -692.69 2,003.45 40.00 0.00 5,953,009.58 507,680.40 -1,970.17 -721.74 2,098.20 40.00 0.00 5,952,919.30 507,651.46 -1,970.45 -721.83 2,098.50 12.00 -80.00 5,952,919.01 507,651.37 -2,067.41 -742.18 2,196.57 12.00 -80.00 5.952,822.04 507,631.13 -2,167.00 -746.40 2,291.60 12.00 -145.00 5,952,722.46 507,627.01 -2,266.35 -755.10 2,387.93 12.00 95.00 5,952,623.11 507,618.43 -2,361.65 -784.20 2,487.44 12.00 94.49 5,952,527.79 507,589.44 -2,456.92 -813.27 2,586.90 12.00 -90.00 5,952,432.50 507,560.48 -2,506.31 -820.16 2,635.67 12.00 -89.21 5,952,383.10 507,553.64 -2,556.20 -822.97 2,683.51 12.00 -35.00 5,952,333.21 507,550.89 -2,606.07 -822.78 2,730.31 12.00 -34.93 5,952,283.35 507,551.13 -2,655.89 -823.23 2,777.28 12.00 125.00 5,952,233.53 507,550.74 -2,675.83 -824.61 2,796.49 12.00 125.39 5,952,213.59 507,549.39 -2,754.60 -838.00 2,875.09 12.00 100.00 5,952,134.82 507,536.08 -2,848.20 -872.61 2,974.88 12.00 100.09 5,952,041.19 507,501.58 -2,865.94 -881.79 2.994.69 12.00 99.81 5,952,023.44 507,492.41 -2,932.57 -925.67 3,072.32 12.00 95.00 5,951,956.76 507,448.62 -2,984.14 -972.67 3,136.85 12.00 94.47 5,951,905.14 507,401.68 -3,004.02 -995.02 3,163.18 12.00 90.00 5,951,885.24 507,379.35 -3,028.27 -1,026.69 3,196.79 12.00 89.74 5,951,860.96 507,347.71 -3,059.80 -1,077.62 3,243.84 12.00 65.00 5,951,829.38 507,296.83 -3,064.49 -1,086.45 3,251.26 12.00 64.70 5,951,824.68 507,288.00 -3,098.18-1,169.76 3,311.42 12.00 90.00 5,951,790.90 507,204.74 -3,116.58-1,267.86 3,362.26 12.00 89.89 5,951,772.40 507,106.67 -3,114.17-1,367.64 3,394.13 12.00 89.78 5,951,774.69 507,006.89 -3,091.11-1,464.76 3,405.67 12.00 85.00 5,951,797.64 506,909.76 -3,065.23-1,560.80 3,414.20 12.00 -45.00 5,951,823.41 506,813.70 -3,057.16 -1,659.00 3,440.21 12.00 -88.00 5,951,831.37 506,715.50 -3,060.96 -1,708.19 3,460.60 12.00 -89.94 5,951,827.51 506,666.32 -3,069.95 -1,756.74 3,485.64 12.00 -95.00 5,951,818.48 506.617.79 -3,084.01 -1,804.15 3.515.07 12.00 -95.94 5,951,804.36 506,570.40 711112016 12:15:05PM Page 4 COMPASS 5000.1 Build 74 11-1 ConocoPhillips ConocoPhillips Planning Report Database: EDM Alaska NSK Sandbox Local Co-ordinate Reference: Company: ConocoPhillips (Alaska) Inc -Kup2 TVD Reference: Project: Kuparuk River Unit MD Reference: Site: Kuparuk 28 Pad North Reference: Well: 213-02 Survey Calculation Method: Wellbore: 2B-02AL2 Design: 2 B-02A L2_wp02 Planned Survey Measured TVD Below Vertical Depth Inclination Azimuth System +N/-S +E/-W Section (usft) (') (') (usft) (usft) (usft) (usft) 19 8,800.00 94.93 245.26 5,943.89 -3,102.73 -1,850.14 3,548.39 8,900.00 88.78 234.94 5,940.64 -3,152.47 -1,936.62 3,624.72 20 9,000.00 89.01 222.94 5,942.58 -3,218.02 -2,011.88 3,712.05 9,100.00 89.29 210.95 5,944.06 -3,297.78 -2,071.87 3,807.52 9,200.00 89.60 198.95 5,945.03 -3,388.28 -2,113.97 3,906.96 9,300.00 89.93 186.95 5,945.44 -3,485.56 -2,136.34 4,006.02 21 9,400.00 87.86 175.13 5,947.38 -3,585.34 -2,138+16 4,100.41 22 9,500.00 87.91 187.14 5,951.09 -3,685.07 -2,140.13 4,194.80 23 9,600.00 87.95 199.15 5,954+72 -3,782.21 -2,162.82 4,293.84 24 9,700.00 88.00 187.14 5,958.27 -3,879.35 -2,185.50 4,392.88 9,800.00 88.13 175A3 5,961.66 -3,979.09 -2,187.47 4,487.28 9,900+00 88.34 163.13 5,964.75 -4,077.07 -2,168.66 4,572.92 Planned TD at 9900.00 ri.s BAKER HUGHES Well 28-02 Mean Sea Level 213-02 @ 126.00usft (28-02) True Minimum Curvature Dogleg Toolface Map Map Rate Azimuth Northing Easting (°1100ft) (I (usft) (usft) 12.00 -120.00 5,951,785.60 506,524.43 12.00 -120.59 5,951,735.76 506,438.01 12.00 -89.00 5,951,670.14 506,362.84 12.00 -88.77 5,951,590.31 506,302.94 12.00 -88.59 5,951,499.78 506,260.95 12.00 -88.47 5,951,402.48 506,238.69 12.00 -100.00 5,951,302.71 506,236.98 12.00 90.00 5,951,202.99 506,235.11 12.00 90.00 5,951,105.83 506,212.54 12.00 -90.00 5,951,008.68 506,189.97 12.00 -89.57 5,950,908.95 506,188.10 12.00 -89.17 5,950,811_00 506,207.03 711112016 12:15:05PM Page 5 COMPASS 5000.1 Build 74 ConocoPhillips WE.. ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska NSK Sandbox Local Co-ordinate Reference: Well 213-02 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2B-02 @ 126.00usft (213-02) Site: Kuparuk 2B Pad North Reference: True Well: 26-02 Survey Calculation Method: Minimum Curvature We I I bore: 213-02AL2 Design: 2B-02AL2_wp02 Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) Latitude Longitude 213-02A_Fault1 0.00 0.00 0.00 -4,064,721,139,312.09 5,952,094.00 1,647,573.00 70° 2' 34.277 N 140° 47' 25.345 W plan misses target center by 1140002.82usft at 6600.00usft MD (5879.25 TVD,-1819.78 N,-673.36 E) Rectangle (sides W1,000.00 H1.00 D0.00) 213-02 CTD Polygon Soy 0.00 0.00 0.00 -3,303.661,139,325.94 5.952,855.00 1,647,586.00 70° 2' 41.646 N 140° 47' 21.678 W - plan misses target center by 1140015.42usft at 6600.00usft MD (5879.25 TVD,-1819.78 N,-673.36 E) Polygon Point 1 0.00 0.00 0.00 5,952,855.00 1,647,586.00 Point 0.00 -207.95 -66.23 5,952,647.00 1,647,520.01 Point 3 0.00 -450.95 -87.49 5,952,404.00 1,647,499.02 Point 0.00 -603.91 -139.66 5,952,251.00 1,647,447.03 Points 0.00 -895.90 -177.97 5,951,958.99 1,647,409.05 Point 0.00 -1,058.81 -276.15 5,951,795.99 1,647,311.06 Point? 0.00 -1,131.70 -387.24 5,951,722.98 1,647,200.06 Point 0.00 -1,148.53 -553.28 5,951,705.97 1,647,034.05 Point 0.00 -1,107.38 -689,25 5,951,746.96 1,646,898.05 Point 10 0.00 -1,086.18 -876.24 5,951,767.95 1,646,711.06 Point 11 0.00 -1,126.98 -1,071.30 5,951,726.94 1,646,516.06 Point 12 0.00 -1,213.81 -1,234.41 5,951,639.94 1,646,353.07 Point 13 0.00 -1,362.65 -1,397.59 5,951,490.93 1,646,190.07 Point 14 0.00 -1,560.58 -1,487.81 5,951,292.92 1,646,100.08 Point 15 0.00 -1,762.58 -1,502.02 5,951,090.93 1,646,086.09 Point 16 0.00 -1,974.58 -1,527.25 5,950,878.92 1,646,061.10 Point 17 0.00 -2,293.59 -1,544.59 5,950,559.92 1,646,044.12 Point 18 0.00 -2,546.56 -1,600.87 5,950,306.91 1,645,988.13 Point 19 0.00 -2,772.51 -1,663.11 5,950,080.92 1,645,926.14 Point20 0.00 -2,835.88 -1,323.14 5,950,017.93 1,646,266.15 Point21 0.00 -2,609.91 -1,273.90 5,950,243.93 1,646,315.13 Point22 0.00 -2,224.92 -1,225.49 5,950,628.94 1,646,363.11 Point 23 0.00 -1,915.91 -1,204.16 5,950,937.94 1,646,384.09 Point24 0.00 -1,647.90 -1,192.87 5,951,205.94 1,646,395.08 Point25 0.00 -1,461.05 -1,033.66 5,951,392.95 1,646,554.07 Point26 0.00 -1,398.24 -852.57 5,951,455.95 1,646,735.07 Point27 0.00 -1,450.51 -599.60 5,951,403.97 1,646,988.07 Point28 0.00 -1,443.76 -362.57 5,951,410.98 1,647,225.07 Point29 0.00 -1,344.01 -119.44 5,951,510.99 1,647,468.07 Point30 0.00 -1,146.17 50.79 5,951,709.00 1,647,638.06 Point 31 0.00 -948.22 117.00 5,951,907.01 1,647,704.04 Point32 0.00 -670.24 165.30 5,952,185.01 1,647,752.03 Point 33 0.00 -503.27 210.49 5,952,352.01 1,647,797.03 Point 34 0.00 -257.27 231.75 5,952,598.01 1,647,818.01 Point 35 0.00 -80.32 294.94 5,952,775.02 1,647,881.00 Point 36 0.00 0.00 0.00 5,952,855.00 1,647,586.00 2B-02AL2_T02 0.00 0.00 5,965.00 -5,595.391,137,976.25 5,950,562.00 1,646,239.00 70° 2' 21.374 N 140° 48' 9.891 W plan misses target center by 1138655.87usft at 6600.00usft MD (5879.25 TVD,-1819.78 N,-673.36 E) Point 213-02 CTD Polygon Nor 0.00 0.00 0.00 -4,754.151,138,740.27 5,951,404.00 - plan misses target center by 1139432.57usft at 6600.00usft MD (5879.25 TVD,-1819.78 N,-673.36 E) - Polygon Point 1 0.00 0.00 0.00 5,951,404.00 Point 0.00 62.22 -200.95 5,951,465.99 Point 3 0.00 187.45 -405.84 5,951,590.98 Point 0.00 350.59 -523.68 5,951,753.97 Point 5 0.00 632.70 -596.39 5,952,035.97 Point 6 0.00 850.69 -565.15 5,952,253.98 Point 0.00 1,041.60 -470.94 5,952,444.97 Point 0.00 1,159.51 -366.81 5,952,562.99 1,647,002.00 70' 2' 28.422 N 140° 47' 44.562 W 1, 647, 002.00 1, 646, 801.00 1, 646, 595.99 1,646,477.98 1,646,404.97 1,646,435.96 1, 646, 529.95 1, 646, 633.94 711112016 12:15:05PM Page 6 COMPASS 5000.1 Build 74 ConocoPhillips WER1 ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska NSK Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 28 Pad Well: 2B-02 Wellbore: 2B-02AL2 Design: 2B-02AL2_wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2B-02 Mean Sea Level 2B-02 @ 126.00usft (2B-02) True Minimum Curvature Point 0.00 1,326.44 -286.62 5,952,729.99 1,646,713.93 Point 10 0.00 1,528.41 -241.40 5,952,931.99 1,646,758.92 Point 11 0.00 1,746.36 -175.16 5,953,149.99 1,646,824.91 Point 12 0.00 1,896.32 -119.00 5,953,300.00 1,646,880.90 Point 13 0.00 2,493.14 103.66 5,953,897.00 1,647,102.87 Point14 0.00 2,433.82 398.63 5,953,838.02 1,647,397.88 Point 15 0.00 1,832.99 182.97 5,953,237.01 1,647,182.91 Point 16 0.00 1,590.04 109.70 5,952,994.00 1,647,109.92 Point 17 0.00 1,309.08 46.40 5,952,713.00 1,647,046.94 Point 18 0.00 1,093.16 -43.84 5.952,497.00 1,646,956.95 Point 19 0.00 920.26 -155.04 5,952,323.99 1,646,845.95 Point20 0.00 718.34 -256.26 5,952,121.98 1,646,744.97 Point21 0.00 500.32 -252.49 5,951,903.99 1,646,748.98 Point22 0.00 350.15 -106.64 5,951,754.00 1,646,894.98 Point 23 0.00 297.97 59.32 5,951.702.01 1.647,060.98 Point24 0.00 0.00 0.00 5,951,404.00 1.647,002.00 2B-02A_Fault3 0.00 0.00 0.00-4,570.011,138,632.46 5,951,588.00 1,646,894.00 plan misses target center by 1139324.31 usft at 6600.00usft MD (5879.25 TVD,-1819.78 N,-673.36 E) Rectangle (sides W1,000.00 H1.00 D0.00) 213-02A_Fault2 0.00 0.00 0.00-4,602.151,138.747.44 5,951,556.00 1,647,009.00 plan misses target center by 1139439.36usft at 6600.00usft MD (5879.25 TVD,-1819.78 N,-673.36 E) Rectangle (sides W1,000.00 H1.00 D0.00) 2B-02AL1_Faultl 0.00 0.00 0.00-3,525.931,138,649.63 5,952,632.00 1,646,910.00 plan misses target center by 1139339.43usft at 6600.00usft MD (5879.25 TVD,-1819.78 N,-673.36 E) Rectangle (sides W1,000.00 H1.00 D0.00) 213-02AL2_T01 0.00 0.00 5,979.00-3,488.791,139,423.74 5,952,670.00 1,647,684.00 plan misses target center by 1140098.33usft at 6600.00usft MD (5879.25 TVD,-1819.78 N,-673.36 E) Point 26-02 CTD Polygon We: 0.00 0.00 0.00 -4,661.861,138,482.34 5,951,496.00 1,646,744.00 - plan misses target center by 1139174.42usft at 6600.00usft MD (5879.25 TVD,-1819.78 N,-673.36 E) Polygon Point 1 0.00 0.00 0.00 5,951,496.00 1,646,744.00 Point 0.00 83.16 -138.93 5,951,579.00 1,646,604.99 Point 0.00 253.37 -322.76 5,951,748.99 1,646,420.99 Point 0.00 489.49 -416.52 5,951,984.98 1,646,326.98 Point 5 0.00 732.51 -413.26 5,952,227.98 1,646,329.97 Point 0.00 965.45 -329.01 5,952,460.99 1,646,413.95 Point 0.00 1,107.29 -165.84 5,952,602.99 1,646,576.94 Point 0.00 1,211.08 35.29 5,952,707.00 1,646,777.94 Point 0.00 1,256.87 237.36 5,952,753.01 1,646,979.94 Point 10 0.00 1,134.84 260.23 5,952,631.02 1,647,002.94 Point 11 0.00 971.79 292.06 5,952,468.02 1,647,034.95 Point 12 0.00 940.93 157.02 5,952,437.01 1,646,899.96 Point 13 0.00 902.03 55.96 5,952,398.00 1,646,798.95 Point 14 0.00 843.11 -27.11 5,952,339.00 1,646,715.95 Point 15 0.00 767.16 -79.19 5,952,262.99 1,646,663.96 Point 16 0.00 663.18 -111.31 5,952,158.99 1,646,631.96 Point 17 0.00 538.17 -107.44 5,952,034.00 1,646,635.97 Point 18 0.00 444.12 -69.54 5,951,940.00 1.646,673.97 Point 19 0.00 350.03 6.37 5,951,846.00 1,646,749.98 Point20 0.00 294.93 90.32 5,951,791.00 1,646,833.98 Point21 0.00 0.00 0.00 5,951,496.00 1,646,744.00 Casing Points 70' 2' 30.368 N 140° 47' 46.836 W 70' 2' 29.887 N 140' 47' 43.705 W 70' 2' 40.481 N 140' 47' 41.861 W 70° 2' 39.705 N 1400 47' 19.694 W 70' 2' 29.697 N 140° 47' 51 A97 W Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 9,900.00 5,964.75 2 3/8" 2 375 3.000 711112016 12:15 05PM Page 7 COMPASS 5000.1 Build 74 i ConocoPhillips rSa ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska NSK Sandbox Local Co-ordinate Reference: Well 28-02 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 213-02 @ 126.00usft (213-02) Site: Kuparuk 213 Pad North Reference: True Well: 26-02 Survey Calculation Method: Minimum Curvature Wellbore: 2B-02AL2 Design: 2B-02AL2_wp02 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 6,600.00 5,879.25 -1,819.78 -673.36 TIP 6.630.00 5,904.61 -1,835.04 -678.25 KOP 6,651.00 5,921.93 -1.846.34 -681.88 End 20 dls, Start 40 dls 6,799.70 5,979.14 -1,970.17 -721.74 End 40 dls, Start 12 dls 6,900.00 5,966.92 -2,067.41 -742.18 5 7,000.00 5,961.66 -2,167.00 -746.40 6 7,200.00 5,971.76 -2,361.65 -784.20 7 7,350.00 5,981.49 -2,506.31 -820.16 8 7,450.00 5,979.19 -2,606.07 -822.78 9 7,520.00 5,974.54 -2,675.83 -824.61 10 7,720.00 5,977.02 -2,865.94 -881.79 11 7,870.00 5,986.22 -2,984.14 -972.67 12 7,940.00 5,991.32 -3,028.27 -1,026.69 13 8,010.00 5,994.20 -3,064.49 -1,086.45 14 8,300.00 5,996.92 -3,114.17 -1,367.64 15 8,400.00 5,996.82 -3,091.11 -1,464.76 16 8,500.00 5,988.44 -3,065.23 -1,560.80 17 8,650.00 5,964.48 -3,060.96 -1,708.19 18 8,750.00 5,949.51 -3,084.01 -1.804.15 19 8,900.00 5,940.64 -3,152.47 -1,936.62 20 9,300.00 5,945.44 -3,485.56 -2,136.34 21 9,400.00 5,947.38 -3,585.34 -2,138.16 22 9,500.00 5,951.09 -3,685.07 -2,140.13 23 9,600.00 5,954.72 -3,782.21 -2,162.82 24 9,900.00 5,964.75 -4,077.07 -2,168.66 Planned TD at 9900.00 711112016 12:15:05PM Page 8 COMPASS 5000.1 Build 74 vlt:. - - KUP 2B-02 Lonocornimps (IK, ,. Wetl Attributes Max An- le & MD TO, -i -____ Wellbore APWWI Field Name Well Status 500292115400 KUPARUK RIVER UNIT PROD Incl (°) MD (ftKB) 39.77 4,200.00 Act it. (ftKB) 6,976.0 Comment H25 (ppm) SSSV: LOCKED OUT 100 Date Annotation Entl Date 12/162012 Last W0: KB-Grtl (RI 38.40 Rig Release Date 823/1984 ..- wall 6/1lVX)13102816AM _ aac-Pdua Annotation Last Tag: SLM Depth (RKB) 1 6,683.0 Entl Dale 5/192011 Annotation Rev Reason: 1-12S, DRILLING DEPTHS/DATES Last Mod ...I End osborl I 6/18/2013 Date CasingStrings HANGER, 30 Casing Descr(ption CONDUCTOR String 0... 16 String ID 15.062 ... Top (RKB) 35.0 Set Deplh (f... 110.0 Set Depth (TVD)... 110.0 String Wt.. String 62.50 ... H-40 String Top Thrd WELDED Casing Description SURFACE String 0... 9 5/8 String ID... 8,921 Top (ftKB) 34.1 Set Depth (f... 2,727.2 Set Depth (TVD) ... 2,726.8 String Wt... String 36.00 ... J-55 String Top Thrd BTC Casing Description PRODUCTION String 0... 7 String ID 6.276 ... Top (ftKB) 31.2 Set Depth (f... 6.933.6 Set Depth (ND) ... 6,286.8 String Wt.. String 26.00 ..; J-55 String Top Thrd BTC Tubing Strings _ - Tubing Description String 0... String ID ... Top (RKB) Set Depth IT- Set Depth (TVD) .., String Wt... String ... String Top Thrd TUBING 312 2.992 30.5 6,615.6 6018.5 930 J-55 EUE8RD Com letion Details Top Depth �- CONDUCTOR, 35710 Tep(30.5 RKS)(R (rvDI Top Incl Item (0.01 Description Comment Nomi... (in) 30.5 HANGER GRAY TUBING HANGER 3, 500 SAFETY vl 1 m 1,891 A 1.891.3 0.73 SAFETY VLV OTIS FMX SAFETY VALVE, LOCKED OUT 4/18/98 2.813 059.5 5,803.4 33.71 SBR CAMCO OEJ-10 SBR 2.973 GAS LIFT, 6,377.3 5,818.1 33.59 PACKER CAMCO HRP-I-SP RETRIEVABLE PACKER 2.867 1.vm 6,489.4 5.911.9 32BLA .73 ST RINGS BLAST RINGS (3) 2994 6,598.7 6,004.1 32.26 SEAL ASSY LOCATOR SEAL ASSEMBLY 3.000 6,599.5 6,004.9 32.25 PACKER BAKER FB-1 PERMANENT PACKER 4.000 6.602.0 6,007.1 32.49 SBE BAKER SEAL BORE EXTENSION 3.000 6,611.4 6,015.0 32.49 NIPPLE CAMCO D NIPPLE NO GO 2.750 SURFACE, 34ACE, 6,614.7 6,017.8 32.49 WLEG - CAMCO SHEAR OUT SUB, ELMD TTL @ 6608' ON SWS PPROF DATED 1/5/07 2.937 GAS LIFT. 3,476 Other In Hole - ----- - Wireline retrievable lu s valves, pumps, fish, etc.) Top Depth GAS LIFT, _ a.e37 (TVD) Top (ftKB) (ftKB) 6,685.0 6,077.1 Top lncl (°) 32.48 FISH Description Comment 3" OK-1 Arm ASSY Lost Downhom on w iz/96 Run Date 9/12/1996 ID (In) 0.000 Perforations & Slots GAS LIFT, 5,864 Shot Top (TVD) Btm (TVD) Dens GAS LIFT, 6,3z5 Top(ftKB) Sim (ftKB) (ftKB) (ftKB) Zone Date (sh... Type Comment 6,526.0 6,568.0 5,942.8 5,978.2 CA 2B-02 10/9/1 g84 12.0 IPERF 120 deg. ph; 5" DA CSg Guns 6,586.0 6,588.0 5,993.4 5,995.1 UNIT B, 213-02 10/10/1984 4.0 IPERF Squeeze Paris-, 4" DA Csg Gun SBR, e359 6,620.0 6,710.0 6.022.2 6,098.2 A-3, A-4, A-5, 2B-02 10/9/1984 4.0 IPERF 120 deg. ph; 4" JJ CSg Gun PACKER, 6,377 Stimuiatfons & Treatments Bottom Min Top Max Stun Top Depth Depth Depth Depth (TVD) (TVD) PRODUCTION, 6.415 (RKB) (ftKB) (ftKB) (ftKB) Type Date Comment 6,526.0 6,568.0 5,942.8 5,978.2 C-SAND FRAC 1122006 Pump C sand fracture treatment at 20 bpm using 50# X-linked gel. Pump total of 138,341# of 1620 PRODUCTION, 6.483 ceramic proppant, placing 126,640# prop behind pipe with 10 ppa on perfs. Screened out while on flush, recovered all tree saver rubber. Cement S ueezes IPERF, W 6,526.6.566 �I Top Depth (TVDI Btm Depth (ND) - C-SAND FRAC, 6,526 Top (ftKB) Btm (RKB) (ftKB) (ftKB Description Start Date Comment 6,586.0 6,588.0 5,993.4 5,995.1 Cement Squeeze t0/1U/1984 Squeeze Perfs Notes: General & Safe End Date _ Annotation ---- 9/162010 NOTE: View Schematic w/ Alaska Schematic9.0 PRODUCTION, 6,562 5/19201I NOTE: MANDREL 3 -SLIGHTLY BENT LATCH IPERF, 6,596-6,568 Cement, 6,586 SEAL ASSY, 6,599 PACKER, 6,600 SEE. 6,602 NIPPLE, 6,611 _1 WLEG, 6,615 ----!_ - - --�--- - Mandrel Details _ A Top 5... (ND)Incl N... Top(RKB) (RKB) Depth Top (1 MakeModel OD (in) _ Sew Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date ` Com1 1,929.0 1,928.9 0.73 CAMCO KBUG 1 GAS LIFT GLV BK 0.156 1,244.0 11l12006PERF, 6,620b710 2 3,478.3 3,458.1 20.84 CAMCO KBUG 1 GAS LIFT GLV BK 0156 1245011g2006 FISH, 6,665 3 4,837.0 4,574.3 36.06 CAMCO KBUG 1 GAS LIFT GLV BK 0.188 1,274.0 11l72006 Note 4 5,863.9 5,396.9 35.53 CAMCO KBUG 1 GAS LIFT GLV BK 6188 1,266.0 11/12006 5 6,324.7 5,774.5 33.92 CAMCO KBUG 1 GAS LIFT OV BK 0.250 0.0 11/6/2006 6 6,414.7 5,849.4 33.05 CAMCO KBUG 1 PROD HFCV BEK 6.000 0.0 5202011 7 6.482.91111 5,906.5 32.75 CAMCO KBUG 1 PROD HFCV BEK 0.000 0.0 5202011 8 6,582.1 5,990.1 32.33 CAMCO KBUG 1 PROD HFCV BEK 0.000 0.0 5202011 PRODUCTION, 31L.934 TD, 6,976 /} Cl)co 7 ® {( ) / ƒ\ E \ 2e 92 \\ \@ a \o e0 E / e§ /§ \ §§ ° 7© �tw /$ /� # \a & \ƒ a -- /te �«I } co /- co rr i � p n » r l I N N N Fr S • k . n T O tJ L. r i 1, i Yi Li Ll L 11 � LI O - _ 1 O O O O O nl O 6] � N v' 0 p O O O O (uysn OSZ) (+IJaNA-AI1 OS T �J O � w. 0p tTo o J LO O C0 O Nr � O t0 f0 m CO N N Q io 0 0 '� to c a v c c O c c o���v�cD��mo�NMv t6 Q H Y W W u'J tD I� 00 m N N N N N Cl- V V 1� O m L o m t D M!- O O N N O c Y N NZ o�MM NNLo (D at tOM V'O W 1�N'-(ON [00 ISO NO tD co Nm OO at' (D to �-g V O� V' coo ct MN i V l)tOmmmeOMMmm�m Z; (O NOOmm N w0 mmD>O N V'tDl I m N M V V V lf)c O O N Lo NNNNNN NN MMMM MM MM M'd'.�'ct 'cY cr cli 1- N O M O O O O O O O O O O O O O O O O O O O O O O O N O L O O O O O O O O O O O O O O O O O O O O O O O O - CDJ C.6 W ON 000 Ll') L!]OLO tlj0 Lo 02S' Ltj� N Lo0 0000 m N 1 N N m N Cl N O m m O m O f t D . 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ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 2B Pad Site Error: 0 00 usft Reference Well: 2B-02 Well Error: 0.00 usft Reference Wellbore 28-02AL2 Reference Design: 26-02AL2_wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 2B-02 213-02 @ 126 00usft (26-02) 213-02 @ 126 00usft (213-02) True Minimum Curvature 1 00 sigma EDM Alaska ANC Prod Offset Datum teference 2B-02AL2_wp02 liter type: GLOBAL FILTER APPLIED: All wellpaths within 2004 100/1000 of reference iterpolation Method: MD Interval 25.00usft Error Model: ISCWSA lepth Range: 6,600.00 to 9,900.00usft Scan Method: Tray. Cylinder North Iesults Limited by: Maximum center -center distance of 1,177.40 usft Error Surface: Elliptical Conic Survey Tool Program Date 7/8/2016 From To (usft) (usft) Survey (Wellbore) Tool Name Description 200,00 6,600.00 2B-02 (213-02) GCT-MS Schlumberger GCT multishot 6,600.00 9,900.00 2B-02AL2_wp02 (2B-02AL2) MWD MWD - Standard Casing Points i Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 9,900.00 6,090.75 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 9 (usft) (usft) (usft) (usft) Kuparuk 2B Pad 213-02 - 28-02 - 28-02 6,649.97 6,650.00 0.69 1.94 -1 24 FAIL - Major Risk 213-02 - 213-02A - 213-02A_wp05 6,625.00 6,625.00 0,00 0.46 -0,45 FAIL - Minor 1/10 28-02 - 2B-02AL1 - 2B-02AL1_wp02 6,625.00 6,625.00 0.00 0.46 -0.45 FAIL- Minor 1/10 213-02 - 28-02AL1-01 - 2B-02AL1-01_wp02 6,625.00 6,625.00 0.00 0.46 -0.45 FAIL - Minor 1/10 213-02 - 2B-02AL2-01 - 2B-02AL2-01_wp01 8,300.00 8,300.00 0,00 0.35 -0.22 FAIL- Minor 1/10 28-03 - 28-03 - 2B-03 8,050.00 6,950.00 1,161.64 217,90 953,99 Pass - Major Risk 213-03 - 2B-03A - 26-03A 8,050.00 6,950.00 1,161.64 217.90 953.99 Pass - Major Risk 28-04 - 213-04 - 28-04 Out of range 28-06 - 213-06 - 28-06 Out of range 213-07 - 28-07 - 28-07 9,775.00 7,575.00 968.48 283.65 711.70 Pass - Major Risk Offset Design Kuparuk 2B Pad Survey Program. 200-GCT-MS Reference Offset - 28-02 - 213-02 - 26-02 Semi Major Axis Rule Assigned: Major Risk Offset Site Error. 0 00 usft Offset Well Error: 0 00 usft Measured Depth (usft) Vertical Depth (usft) Measured Depth (usft) Vertical Depth (usft) Reference (usft) Offset (usft) Toolface+ Azimuth (^) Offset Wellbore +N/S (usft) Centre +E/-W (usft) Casing- Hole Size Centre to Centre (usft) No Go Distance (usft) Allowable Warning Deviation (usft) 6,625,00 6,649.97 6,674,29 6,696.80 6,716.75 6,733.92 6,026,39 6,047.10 6,065.44 6,079,79 6,090,11 6,097.02 6,625.00 6,650.00 6,675.00 6,700.00 6725.00 6,750,00 6,026.39 6,047.51 6,068.62 6,089.71 6.110,80 6,131,89 0.07 0.08 0,09 0.09 0,10 0.11 0,14 0.28 0.42 0.56 0.70 0.84 3,69 17.20 17.36 17.41 17.46 17.50 -1,832.49 -1,845.22 -1,857.96 -1,870,71 -1,883,47 .1,896.23 -677.43 -681.53 -685.67 -689.83 .694,00 .698.17 2-11116 2-11/16 2-11116 2-11116 2-11/16 2-11/16 0,00 0.69 4.43 12.14 23.26 37.19 1,01 1.94 3.32 4.58 5.62 6,46 -0.97 FAIL- Major Risk, CC -1.24 FAIL - Major Risk, ES, SF 1.11 Pass - Major Risk 7.56 Pass - Major Risk 17.64 Pass - Major Risk 30.72 Pass - Major Risk 6,748,46 6,760.00 6.770,00 6,780.00 6,101.37 6.103.80 6,105.17 6,105,85 6,775.00 6,800.00 6,825.00 6,850,00 6,152.99 6,174.08 6,195.17 6,216,26 0,12 0,13 0.14 0.14 0.98 1.12 1.26 1.40 17.54 17.57 17.60 17.61 .1,908,99 -1,921,75 -1,934.51 -1,947.27 -702.34 -706.50 -710.67 -714,83 2-11116 2-11/16 2-11/16 2-11/16 53.32 71A6 90,32 110.49 7.12 7.62 8,03 8,43 46.20 Pass - Major Risk 63.54 Pass - Major Risk 82,31 Pass - Major Risk 102.14 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 71812016 10:39:13AM Page 2 COMPASS 5000.1 Build 74 TRANSMITTAL LETTER CHECKLIST WELL NAME: K JZ U - O � AL I PTD: 1/ Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: POOL: AIV61- l 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. ai 6 -- 0% 7� , API No. 50-�9- Q,15y -01- 00. (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 PTD#:2160900 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Well Name: KUPARUK RIV UNIT 213-02AL2 Program DEV Well bore seg EV 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 ADL0025655, Surf Loc; ADL0025656, Top Prod Intery & TD. 3 Unique well name and number Yes KRU 2B-02AL2 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 7/15/2016 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 Engineering 19 Surface casing protects all known USDWs NA 20 CMT vol adequate to circulate on conductor & surf csg NA 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons No 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes VTL 8/15/2016 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes 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 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Geology 36 Data presented on potential overpressure zones Yes Appr Date 37 Seismic analysis of shallow gas zones NA PKB 7/15/2016 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only) NA Geologic Engineering Public Commissioner: Date: Commission r: Date Commissioner Date / ) J Conductor set in KRU 26-02 Surface casing set in KRU 213-02 Surface casing set and fully cemented Productive interval will be completed with uncemented slotted liner Rig has steel tanks; all waste to approved disposal wells Anti -collision analysis complete; no major risk failures Max formation pressure is 3973 psig(12.6 ppg EMW); will drill w/ 8.6 ppg EMW and maintain overbal w/ MPD MPSP is 3369 prig; will test BOPs to 3750 psig H2S measures required Wells on 26-Pad are H2S-bearing. 112S measures required. Max. potential reservoir pressure is 12.6 ppg EMW; will be drilled using 8.6 ppg mud and MPD technique. Onshore development well to be drilled.
