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Home My WebLink About215-162Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Friday, October 6, 2017 1:26 PM To: 'Starck, Kai' Cc: Bettis, Patricia K (DOA); Loepp, Victoria T (DOA) Subject: Expired Permits to Drill: KRU 3K-01 L1-01, L1-02, L1-03 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 3K-01 1-1-01, PTD 215-162, Issued 18 September 2015 • KRU 3K-01 L1-02, PTD 215-163, Issued 18 September 2015 • KRU 3K-01 1-1-03, PTD 215-165, Issued 18 September 2015 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 forth e 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. PT/]' Z!S'1 e-Z Loepp, Victoria T (DOA) From: Ohlinger, James J <James.J.Ohlinger@conocophillips.com> Sent: Tuesday, October 27, 2015 10:42 AM To: Loepp, Victoria T (DOA) Cc: Winfree, Mike A Subject 3K-01 CTD Permits - Amend 3K-011-1-01 PTD.215-162 Attachments: 3K-01 proposed CTD schematic.pdf, 3K-01 REVISED CTD Proposed Schematic.pdf Follow Up Flag: Follow up Flag Status: Flagged Good Morning I've attached our original schematic, and our current+plan schematic. We finished drilling the 3K-01L1 lateral, ran the first segment of liner to bottom. Was in the process of running the second segment to the planned depth to sidetrack off the billet for the 3K-011.1-01 lateral. During this process the liner became stuck, leaving a 1293' gap. We would like to amend the 3K-011-1-01 lateral PTD. Original kick off point was 9800' MD We have to set a 2nd whipstock and kickoff at 8728' MD Please call to discuss. James OflZinger Staff CTD Engineer ConocoPhillips AK, Inc. 907-265-1102 office 907-229-3338 cell 1 3K-01 Proposed CTD Schematic 76" 62.5# H-40 shoe Q 115' MD 9-518" 36# J-55 shoe ®4919' MD i750' proposed TOWS cplps: 8691', 8733', i777, 8793' PDC C Squeeze parts (aI86) 875U-8757 A -sand pens 8818-8893' C E C C 7" 26# J-55 shoe 914W MD 9.39 L-80 EUE 8rd-Mod Tubing to surface Orbit Valve placed at 4021' MD (2.835" min ID) ' Camco MMG gas lift mandrels at 2963% 4767', 6176, 7229'. , and 8503' MD Baker GBH-22 Seal assembly at 8561' Baker 80.40 PBR at 86W MD Baker FHL packer at 85W MD 3.12" X-nippie at 8643' MD (2.812" min ID) 5-12" Big Tail Pipe with wear -sax at SBW-8768 3K-011-1-03 north, Planned TD = 71,150' MD ` lat 2Y." liner top at 8745' 3K-011-1-02 north, Planed TD= 11,150' MD Lat#J ?'/." liner +billet at9586 3K-01L1-01 so.M, Planned TD=11,950'MD tst#2 2Y." liner + billet at 9150' 3K-01 L1 south, Planned TD = 12,350' MD -� _-- --- ----------- 2Y."liner+ billet at9800'MD - -- - TIDE STATE ALASKA Y-Y GOVERNOR BILL STALKER D. Venhaus CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas conserv-,ir,�� . Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 3K-01 L 1-01 ConocoPhillips Alaska, Inc. Permit No: 215-162 Surface Location: 1434' FSL, 318' FWL, Sec. 35, TUN, R9E, UM Bottomhole Location: 578' FNL, 2619' FEL, Sec. 34, T13N, R93, UM Dear Mr. Venhaus: 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov Enclosed is the approved application for permit to drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 186-101, API No. 50-029- 21600-00-00. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy X Foerster Chair DATED this day of September, 2015. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 �iEWED SEP 10 2015 AOGCC 1 a. Type of Work: Drill ❑ -Lateral ✓ Redrill ❑ Reentry E 1 b_ Proposed Well Class: Development - Oil ❑✓ Service - Winj ❑ Single Zone ❑ 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 L Single Well Bond No. 59-52-180 • 11. Well Name and Number: KRU 3K-01 L1-01 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 11950' TVD: 6480' 12. Field/Pool(s): Kuparuk River Field Kuparuk River Oil Pool 4a. Location of Well (Governmental Section): Surface: 1434' FSL, 318' FWL, Sec. 35, T13N, R9E, UM Top of Productive Horizon: 1574' FSL, 1045' FEL, Sec. 27, T13N, R9E, UM Total Depth: 578' FNL, 2619' FEL, Sec. 34, T13N, R9E, UM 7. Property Designation (Lease Number): ADL 25519, 25520 8. Land Use Permit: 2555, 2556 13. Approximate Spud Date: 9/24/2015 9. Acres in Property: ?M0-- 14. Distance to Nearest Property: 4310 41b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 529306 y- 6008429 Zone- 4. 10. KB Elevation above MSL: 69 feet GL Elevation above MSL: 28 feet 15. Distance to Nearest Well Open to Same Pool: 3K-06 , 1732' 16. Deviated wells: Kickoff depth: 9800 ft. Maximum Hole Angle: . 98' deg 17. Maximum Anticipated Pressures in psig (see 20 AAC 25,035) Downhole: 4603 psig , Surface: 3944 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 2800' 9150' 6567' 11950' 6480' Islotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 9150' Total Depth TVD (ft): 6877' Plugs (measured) none Effective Depth MD (ft): 1 9055' Effective Depth TVD (ft): 6809' Junk (measured) 8977' Casing Length Size Cement Volume MD TVD Conductor/Structural 77' 16" 1540 Poleset 115' 115' Surface 4882' 9.675" 1400 sx ASIII, 350 sx Cl G 4919' 3852' Production 9114' 7" 270 sx Class G, 175 sx AS 1 9140' 6871' Perforation Depth MD (ft): 8818'-8896' Perforation Depth TVD (ft): 6641'-6697' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Program ❑✓ 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: S is 22. 1 hereby certify that the foregoing is true and correct. Contact Mike Winfree @ 263-4404 Email Mike.A.WinfreeCcDcop.com Printed Name D. Ve aus Title CTD Engineering Supervisor Signature Phone: 263-4372 Date %' Ls Commission Use Only Permit to Drill Number: aIs- & API Number: 50-'Qa"-+a16�-�Q� oo Permit Approval Date: 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 ane, gas hydrates, or gas contained in shales: Other: G p J-, 5 t J-r_ L} 5-CC /25 15 Samples req'd: Yes No Mud log req'd: YesNo 1-1 r-)L/i a, P �Y b `f A f7� tz5�1` H2S measures: Yes � No ,❑,/ Directional svy req'd: Yes❑ r No fv Z SGG' %� 5 [ q Spacing exception req'd: Yes ❑ No l h Inclination -only svy req'd: Yes ❑ No Approved by: COM APPROVED BY THE IS 10 E COMMISSION Date: Form 10-401 (R ised 10/2012) T i V7' / eq /j ::7-/ / � it a d o hs from the dateRf� la appr�jf�� eC 25.005(gl) �/yam �+i.� U i, ///v — • -- - - •. . - r- r/ ConocoPhillips p Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August 8th, 2015 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: S E P 10 2015 AOGCC ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill four laterals out of the Kuparuk Well 3K-01 using the coiled tubing drilling rig, Nabors CDR2-AC. CTD operations are scheduled to begin at the end of September, 2015. The objective will be to drill laterals KRU 3K-01L1, L1-01, 1-1-02, and L1-03 targeting the Kuparuk A2 and A3 sands. Attached to this application are the following documents: — 10-401 Applications for all planned laterals — Detailed Summary of Operations — Directional Details for all planned laterals including anti -collision — Proposed CTD Schematic If you have any questions or require additional information please contact me at 907-263-4404. Sincerely AAWinfe ConocoPhillips Alaska Coiled Tubing Drilling Engineer Kuparuk CTD Laterals NA@OA.SA_LASKA 3K-01 L1, 3K-01 L1-01, 3K-01 L1-02, 3K-01 L1-03 CIJs9 Application for Permit to Drill Document VAC 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................................................................... 3 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 3 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............................................................................................................. 5 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 5 Summaryof Operations...................................................................................................................................................5 PressureDeployment of BHA..........................................................................................................................................6 LinerRunning...................................................................................................................................................................6 14. Disposal of Drilling Mud and Cuttings.......................................................................................... 6 (Requirements of 20 AAC 25.005 c 14....................................................................... 6 15. Directional Plans for Intentionally Deviated Wells....................................................................... 6 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 6 16. Attachments.................................................................................................................................... 7 Attachment 1: Directional Plans for 3K-011-1, 1-1-01, 1-1-02, L1-03.................................................................................7 Attachment 2: Current Well Schematic for 3K-01............................................................................................................7 Attachment 3: Proposed Well Schematic for 3K-01 L1, L1-01, L1-02, L1-03...................................................................7 Page 1 of 7 9/9/2015 PTD Application: 3K-01L1, L1-01, L1-02, L1-03 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 3K-01L1, 3K-01L1-01, 3K-01L1-02, 3K-01L1-03. 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 packages in the Kuparuk reservoir. See attached 10-401 form for surface and subsurface coordinates of the 3K-01L1, 3K-01L1-01, 3K-01L1-02, 3K-01L1-03. 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 4,500 psi. Using the maximum formation pressure in the area of 4,603 psi in 3K-04, the maximum potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 3,944 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 Expected Downhole Pressure (Requirements of 20 AAC 25.005 (c) (4) (a)) A static bottom hole pressure of 3K-01 A sand on August 8th 2015 indicated a reservoir pressure of 3003 psi or 8.7 ppg equivalent mud weight. The maximum down hole pressure in the 3K-01 pattern is at 3K-04 with 4603 psi. This higher pressure risk only exists in the first southern lateral, 3K-01L1, which is planned to cross a sealing fault into a block that does not appear to have any offtake. The second lateral to the south, 3K-01 L1-01, is planned to stop short of the sealing fault. The northern laterals are drilling towards the producer 30-18 which is currently shut in and the last known BHP was 9.2 ppgemw taken in August 2013. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) No specific gas zones are expected to be drilled. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) One potential cause of hole problems in the 3K-01 CTD laterals, could be managing the pressure differential across the faults. An orbit valve has been installed in the 3K-01 completion to help maintain applied surface pressure on the formation when out of the hole in managed pressure mode. The 3K area is also structurally complex, and the potential for multiple unmapped faults increases the likelihood of encountering high gamma ray interfaces. Managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossing. Along with shale instability as mentioned above the higher pressure risk will also be taken into consideration for potential hole problems. Again, MPD will be used to mitigate the high pressure risk. Page 2 of 7 9/9/2015 PTD Application: 3K-01L1, L1-01, L1-02, L1-03 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(o, thru-tubing drilling operations need not perform additional formation integrity tests. 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 3K-01L1 9,800' 12,350' 6,567' 6,454' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 31K-0111_1-01 9,150' 11,950' 6,567' 6,479' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 3K-01L1-02 9,585' 11,150' 6,556' 6,560' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 3K-01L1-03 8,745' 11,150' 6,519' 6,540' 2%", 4.7#, L-80, ST-L slotted liner; shorty deployment sleeve Existing Casing/Liner Information Category OD Weight (ppf) Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.5 H-40 Welded 38' 115, 38' 115' 1,640 630 Surface 9-5/8" 36 J-55 BTC 37' 4,919' 37' 3,852' 3,520 2,020 Production 7" 26.0 J-55 BTC 25' 9,139' 25' 9,139' 4,980 4,320 Tubing 3-1/2" 9.3 L-80 EUE 35' 8,768' 35' 6,605' 10,160 10,530 Tubing Tail 5-1/2" 14 J-55 STC 8,684' 8,723' 6,544' 6,572' 4,270 3,120 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. 6. 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 -weighted FloVis water -based mud (9.1 ppg) - Drilling operations: Chloride -weighted FloVis water -based mud (9.1 ppg). While this mud weight may not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. - Completion operations: Well 3K-01 contains a downhole deployment valve allowing deployment of tool strings and liner without pumping kill weight fluid. If the valve does not hold, BHA's will be deployed using standard pressure deployments and the well will be loaded with an overbalanced completion fluid in order to provide formation over -balance and maintain wellbore stability while running completions Page 3 of 7 9/9/2015 PTD Application: 3K-01L1, L1-01, L1-02, L1-03 Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 5000 psi rated coiled tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". The targeted MPD BHP will be 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 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 3K-01 Window (8,750 MD, 6,592' TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A -sand Formation 2982 psi 2982 psi Pressure (8.7 ppg) Mud Hydrostatic 9.1 3120 psi 3120 psi Annular friction (i.e. ECD, 788 psi 0 psi 0.09 si/ft) Mud + ECD Combined 3908 psi 3120 psi (no choke pressure) (overbalanced —926 psi) (overbalanced —240 psi) Target BHP at Window 4045 psi 4045 psi (11.8 Choke Pressure Required 137 psi 925 psi to Maintain Target BHP 9. Abnormally Pressured Formation Information (Requirements of 20 AA 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 AA 25.005(c)(11)) N/A - Application is for land -based well. 12. Evidence of Bonding (Requirements of 20 AA 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. Page 4 of 7 9/9/2015 PTD Application: 3K-01L1, L1-01, L1-02, L1-03 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well 3K-01 is a Kuparuk A -sand production well equipped with 3'/2" tubing and 7" production casing. The rig work -over in July 2015 replaced the existing tubing and packers with new 3-1/2" tubing and 5-1/2" "Big Tail Pipe" completion. Four laterals will be drilled from the 3K-01 parent well. 2 laterals will be drilled to the south and 2 laterals will be drilled to the north of the parent well with the laterals targeting the different A sand lobes. A mechanical whip -stock will be set inside the 5'/2" big tail pipe at the planned kick off point of 8,750' MD. The 3K-01 L1 lateral will exit through the big tail pipe at 8,750'MD and TD at 12,350' MD. The L1 lateral will be completed with 2 3/8" slotted liner from TD up to 9,800' MD with an aluminum billet for kicking off the 3K- 01L1-01 lateral The 3K-01L1-01 will drill to a TD of 11,950' MD, with the slotted liner from TD to 9,150' MD and an aluminum billet to kick off the L1-02 lateral. The 3K-01 L1-02 will drill to a TD of 11,150' MD, with slotted liner run from TD to 9,585' MD with an aluminum billet to kick off the L1-03 lateral. The 3K- 01 L1-03 will drill to a TD of 11,150' MD, with the liner top above the whipstock at 8,745' MD. Pre-CTD Work 1. RU Slickline: Pull sheared SOV, dummy all gas lift valves, obtain a KRU A -sand SBHP, and conduct a dummy whipstock drift. DONE 2. RU E-line: Set Baker Hughes 3-1/2" x 5-1/2" Thru-Tubing Whipstock. DONE 3. 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. 3K-01 L1 Lateral (A2 sand to the South) a. Mill 2.80" window at 8,750 MD. b. Drill 3" bi-center lateral to TD of 12,350' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 9,800' MD. 3K-01L1-01 Lateral (A3 sand to the South) i a. Kick off of the aluminum billet at 9,800' MD. b. Drill 3" bi-center lateral to TD of 11,950' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 9,150' MD 4. 3K-01 L 1-02 Lateral (A2 sand to the North) a. Kick off of the aluminum billet at 9,150' MD. b. Drill 3" bi-center lateral to TD of 11,150' MD. c. Run 2%" slotted liner with aluminum billet from TD up to 9,585' MD 5. 3K-0111-1-03 Lateral (A3 sand to the North) a. Kick off of the aluminum billet at 9,585' MD. b. Drill 3" bi-center lateral to TD of 11,150' MD. c. Run 2%` slotted liner with deployment sleeve from TD up to 8,745' MD 6. Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV. 2. Install GLV's. Page 5 of 7 9/9/2015 PTD Application: 3K-01L1, L1-01, L1-02, L1-03 Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure, so installed in this well is a deployment valve. This valve, when closed using hydraulic control lines from surface, isolates the well pressure and allows long BHA's to be deployed/un-deployed without killing the well. If the deployment valve fails, operations will continue using the standard pressure deployment process. A system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slick -line lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slickline. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment, the steps listed above are observed, only in reverse. Liner Running — The 3K-01 well has a deployment valve installed. It will serve to deploy liners into the newly drilled laterals. If the valve fails the laterals will be displaced to an overbalance completion fluid (as detailed in Section 8 "Drilling Fluids Program") prior to running liner. — While running 23/" slotted liner, a joint of 2%" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2%" rams will provide secondary well control while running 2%" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) — The Applicant is the only affected owner. — Please see Attachment 1: Directional Plan — Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. — MWD directional, resistivity, and gamma ray will be run over the entire openhole section. Page 6 of 7 9/9/2015 PTD Application: 3K-01L1, L1-01, L1-02, L1-03 - Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 3K-01L1 3,785' 3 K-01 L1-01 4, 310' 3K-01L1-02 2,865' 3K-01L1-03 2,863' - Distance to Nearest Well within Pool Lateral Name Distance Well 3K-011-1 1,815' 3K-06 3K-011-1-01 1,732" 3K-06 3K-011-1-02 1,222' 30-18 3K-011-1-03 1,222' 30-18 16. Attachments Attachment 1: Directional Plans for3K-01L1, L1-01, L1-02, L1-03 Attachment 2: Current Well Schematic for 3K-01 Attachment 3: Proposed Well Schematic for 3K-01L1, L1-01, L1-02, L1-03 Page 7 of 7 9/9/2015 3K-01 Past-RW® Schematic 16" 62.5# H-40 shoe @ 11 5'MD 9-5/8" 36# J-55 shoe @ 4919' MD proposed TOWS cpl9s: 8691', 8733', 72', 8793' PDG A -sand perfs 8818-8893' 7" 26# J-55 shoe @ 9140' MD 3-1/2" 9.3# L-80 EUE 8rd-Mod Tubing to surface Baker Orbit Valve placed at 4021' MD (2.835" min ID) 1/2" Camco MMG gas lift mandrels at 2963', 4767', 6176', 7229', )06', and 8503' MD Baker GBH-22 Seal assembly at 8561' Baker 80-40 PBR at 8566' MD Baker FHL packer at 8590' MD 3-1/2" X-nipple at 8643' MD (2.812" min ID) 5-1/2" Big Tail Pipe with wear -sox at 8686'-8768 Squeeze perfs (8/86) 8750-8752, u 2 E g � u m c ¥ U � 0 § 0. 2 � 9 � n CN J ED r- . ) / zCD )10 E / 00 / / / G { ) « / 2 q 2 E \§§ E+a « § k . / _ \_ )m) / \ o > \ kz \/\ \ \ § � ca co cL \ a 6 o f o 2 LL F Q a & ] \§ 222 / 3 _§ § ] o _ § § § ) § ) a 75 \} 2® )) �- o� fƒ \f }\ j) § 2¥ 2¥ 2/ �§ \ 2042 - §k » 0{§ k I§ [\ NADConversion Kuparuk River Unit Kuparuk 3K Pad 3 K-01 3K-01 L1-01 Plan: 3K-01 L1-01_wp05 Standard Planning Report 12 August, 2015 MAP a BAKER HUGHES YNTF,Q ConocoPhillips Database: EDM Alaska ANC Prod Company: NADConversion Project: Kuparuk River Unit Site: Kuparuk 3K Pad Well: 3K-01 Wellbore: 3K-01 L1-01 Design: 3K-011-1-01_wp05 ConocoPhillips Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3K-01 Mean Sea Level 3K-01 @ 69.00usft (3K-01) True Minimum Curvature Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor nRG R„t�� 1NTEQ Site Kuparuk 3K Pad Site Position: Northing: 6,008,428.74usft Latitude: 70' 26' 2.781 N From: Map Easting: 529,306.18usft Longitude: 149° 45' 39.930 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.23 ° Well 3K-01 Well Position +N/-S 0.00 usft Northing: 6,008,428.74 usft Latitude: 70° 26' 2.780 N +E/-W 0.00 usft Easting: 529,306.18 usft Longitude: 149° 45' 39.930 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 3K-011-1-01 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2015 11/1/2015 18.76 81 03 57,498 Design Audit Notes: Version: Vertical Section: 3K-01 L1-01_wp05 Phase: Depth From (TVD) (usft) 0 00 PLAN +N/-S (usft) 0.00 Tie On Depth +E/-W (usft) 0.00 9,800.00 Direction (°) 210.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (I (°) (usft) (usft) (usft) (°/100usft) (°/100usft) (°/100usft) V) Target 9,800.00 90.00 228.81 6,567.12 5,118.27 -1,922.96 0.00 0.00 0.00 0.00 9,906.00 97.42 228.81 6,560.27 5,048.66 -2,002.51 7.00 7.00 0.00 0.00 10,012.00 90.11 227.53 6,553.31 4,978.17 -2,081.27 7.00 -6.89 -1.21 190.00 10,362.00 90.10 203.03 6,552.67 4,694.62 -2,281.88 7.00 0.00 -7.00 270.00 10,532.00 92.82 191.44 6,548.33 4,532.60 -2,332.15 7.00 1.60 -6.82 283.30 10,662.00 92.78 200.55 6,541.97 4,407.91 -2,367.89 7.00 -0.03 7.01 90.00 10,762.00 92.93 193.54 6,536.98 4,312.48 -2,397.14 7.00 0.15 -7.01 271.40 11,062.00 92.74 214.57 6,521.98 4,040.41 -2,518.60 7.00 -0.06 7.01 90.00 11,212.00 91.33 204.16 6,516.65 3,909.94 -2,591.99 7.00 -0.94 -6.94 262.50 11,412.00 91.29 218.16 6,512.06 3,739.26 -2,695.18 7.00 -0.02 7.00 90.00 11,512.00 98.18 216.93 6,503.81 3,660.30 -2,755.88 7.00 6.89 -1.23 350.00 11,612.00 97.63 209.89 6,490.04 3,577.67 -2,810.38 7.00 -0.55 -7.05 266.00 11,712.00 90.74 208.68 6,482.74 3,490.73 -2,859.13 7.00 -6.89 -1.21 190.00 11,950.00 90.71 192.01 6,479.72 3,268.39 -2,941.58 7.00 -0.01 -7.00 270.00 8/12/2015 2:20:19PM Page 2 COMPASS 5000.1 Build 74 ConoCoPhillips ConocoPhillips Planning Report I ERI HUGHIE5 INTEQ Database: EDM Alaska ANC Prod Local Co-ordinate Reference: Well 3K-01 Company: NADConversion TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 3K-01 @ 69.00usft (3K-01) Site: Kuparuk 3K Pad North Reference: True Well: 3K-01 Survey Calculation Method: Minimum Curvature Wellbore: 3K-01 L1-01 Design: 3K-01 L1-01_wp05 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N1-S +E/-W Section Rate Azimuth Northing Easting (usft) (°) (°) (usft) (usft) (usft) (usft) (°/100usft) (°) (usft) (usft) 9,800.00 90.00 228.81 6,567.12 5,118.27 -1,922.96 -3,471.07 4.00 -90.00 6,013,538.90 527,363.32 TIP/KOP 9,900.00 97.00 228.81 6,561.02 5,052.58 -1,998.03 -3,376.65 7.00 0.00 6,013,472.93 527,288.51 9,906.00 97.42 228.81 6,560.27 5,048.66 -2,002.51 -3,371.01 7.00 0.00 6,013,468.99 527,284.05 Start 7 dls 10,000.00 90.94 227.67 6,553.42 4,986.26 -2,072.41 -3,282.02 7.00 -170.00 6,013,406.32 527,214.41 10,012.00 90.11 227.53 6,553.31 4,978.17 -2,081.27 -3,270.58 7.00 -170.08 6,013,398.20 527,205.58 3 10,100.00 90.11 221.37 6,553.15 4,915.37 -2,142.86 -3,185.41 7.00 -90.00 6,013,335.17 527,144.24 10,200.00 90.11 214.37 6,552.96 4,836.48 -2,204.21 -3,086.41 7.00 -90.01 6,013,256.05 527,083.21 10,300.00 90.10 207.37 6,552.78 4,750.70 -2,255.48 -2,986.49 7.00 -90.02 6,013,170.07 527,032.27 10,362.00 90.10 203.03 6,552.67 4,694.62 -2,281.88 -2,924.72 7.00 -90.04 6,013,113.89 527,006.10 4 10,400.00 90.71 200.44 6,552.40 4,659.32 -2,295.95 -2,887.12 7.00 -76.70 6,013,078.54 526,992.17 10,500.00 92.31 193.62 6,549.76 4,563.80 -2,325.21 -2,789.76 7.00 -76.72 6,012,982.92 526,963.29 10,532.00 92.82 191.44 6,548.33 4,532.60 -2,332.15 -2,759.27 7.00 -76.90 6,012,951.69 526,956.48 5 10,600.00 92.81 196.20 6,544.99 4,466.66 -2,348.37 -2,694.06 7.00 90.00 6,012,885.70 526,940.52 10,662.00 92.78 200.55 6,541.97 4,407.91 -2,367.89 -2,633.42 7.00 90.23 6,012,826.88 526,921.23 6 10,700.00 92.84 197.89 6,540.10 4,372.07 -2,380.38 -2.596.14 7.00 -88.60 6,012,791.00 526,908.88 10,762.00 92.93 193.54 6,536.98 4,312.48 -2,397.14 -2,536.15 7.00 -88.73 6,012,731.34 526,892.35 7 10,800.00 92.93 196.21 6,535.04 4.275.81 -2,406.89 -2,499.51 7.00 90.00 6,012,694.63 526,882.75 10,900.00 92.89 203.21 6,529.96 4,181.85 -2,440.55 -2,401.31 7.00 90.14 6,012,600.55 526,849.46 11,000.00 92.81 210.22 6,524.98 4,092.69 -2,485.43 -2,301.66 7.00 90.49 6,012,511.23 526,804.94 11,062.00 92.74 214.57 6,521.98 4,040.41 -2,518.60 -2,239.80 7.00 90.84 6,012,458.83 526,771.98 8 11,100.00 92.39 211.93 6,520.28 4,008.67 -2,539.41 -2,201.90 7.00 -97.50 6,012,427.00 526,751.30 11,200.00 91.44 204.99 6,516.94 3,920.85 -2,587.00 -2,102.06 7.00 -97.62 6,012,339.01 526,704.05 11,212.00 91.33 204.16 6,516.65 3,909.94 -2,591.99 -2,090.12 7.00 -97.85 6,012,328.08 526,699.11 9 11,300.00 91.32 210.32 6,514.61 3,831.76 -2,632.23 -2,002.28 7.00 90.00 6,012,249.75 526,659.18 11,400.00 91.29 217.32 6,512.33 3,748.75 -2,687.84 -1,902.59 7.00 90.14 6,012,166.53 526,603.90 11,412.00 91.29 218.16 6,512.06 3,739.26 -2,695.18 -1,890.71 7.00 90.30 6,012,157.02 526,596.60 10 11,500.00 97.35 217.08 6,505.43 3,669.80 -2,748.72 -1,803.77 7.00 -10.00 6,012,087.35 526,543.33 11,512.00 98.18 216.93 6,503.81 3,660.30 -2,755.88 -1,791.97 7.00 -10.08 6,012,077.82 526,536.21 11 11,600.00 97.71 210.73 6,491.64 3,587.94 -2,804.38 -1,705.06 7.00 -94.00 6,012,005.28 526,488.00 11,612.00 97.63 209.89 6,490.04 3,577.67 -2,810.38 -1,693.16 7.00 -94.86 6,011,994.99 526,482.04 12 11,700.00 91.57 208.82 6,482.98 3,501.25 -2,853.36 -1,605.50 7.00 -170.00 6,011,918.41 526,439.37 11,712.00 90.74 208.68 6,482.74 3,490.73 -2,859.13 -1,593.50 7.00 -170.09 6,011,907.87 526,433.64 13 11,800.00 90.73 202.52 6,481.61 3,411.42 -2,897.12 -1,505.81 7.00 -90.00 6,011,828.41 526,395.96 11,900.00 90.72 195.51 6,480.34 3,316.94 -2,929.68 -1,407.71 7.00 -90.08 6,011,733.82 526,363.78 11,950.00 90.71 192.01 6,479.72 3,268.39 -2.941.58 -1,359.72 7.00 -90.17 6,011,685.22 526,352.08 Planned TD at 11950.00 - 2 3/8" 8/12/2015 2:20:19PM Page 3 COMPASS 5000.1 Build 74 ConocoPhiiiips Database: EDM Alaska ANC Prod Company: NADConversion Project: Kuparuk River Unit Site: Kuparuk 3K Pad Well: 3K-01 Wellbore: 3K-01 L1-01 Design: 3K-01 L1-01_wp05 Casing Points Measured Vertical Depth Depth (usft) (usft) 11,950.00 6,479.72 2 3/8" Plan Annotations Measured Vertical Depth Depth (usft) (usft) 9,800.00 6,567.12 9,906.00 6,560.27 10,012.00 6,553.31 10,362.00 6,552.67 10,532.00 6,548.33 10,662.00 6,541.97 10,762.00 6,536.98 11,062.00 6,521.98 11,212.00 6,516.65 11,412.00 6,512.06 11,512.00 6,503.81 11,612.00 6,490.04 11,712.00 6,482.74 11,950.00 6,479.72 ConocoPhillips / FIG BAKER Planning Report HUGHES INTEQ Local Co-ordinate Reference: Well 3K-01 TVD Reference: Mean Sea Level MD Reference: 3K-01 @ 69.00usft (3K-01) North Reference: True Survey Calculation Method: Minimum Curvature Name Local Coordinates +N/-S +E/-W (usft) (usft) Comment 5,118.27 -1,922.96 TIP/KOP 5,048.66 -2,002.51 Start 7 cis 4,978.17 -2,081.27 3 4,694.62 -2,281.88 4 4,532.60 -2,332.15 5 4,407.91 -2,367.89 6 4,312.48 -2,397.14 7 4,040.41 -2,518.60 8 3,909.94 -2,591.99 9 3,739.26 -2,695.18 10 3,660.30 -2,755.88 11 3,577.67 -2,810.38 12 3,490.73 -2,859.13 13 3,268.39 -2,941.58 Planned TD at 11950.00 Casing Hole Diameter Diameter 2-3/8 3 811212015 2:20:19PM Page 4 COMPASS 5000.1 Build 74 ConocoPhillips ConocoPhillips (Alaska) Inc. -Ku p2 Kuparuk River Unit Kuparuk 3K Pad 3 K-01 3 K-01 L 1-01 3K-01 L1-01_wp05 Travelling Cylinder Report 12 August, 2015 rf..I BAKER HUGHES INTEQ 10-1 ConocoPhillips Aal RA ConocoPhillips Travelling Cylinder Report HUGHEs Company: ConocoPhillips (Alaska) Inc -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3K Pad Site Error: 0.00 usft Reference Well: 3K-01 Well Error: 0 00 usft Reference Wellbore 3K-01Ll-01 Reference Design: 3K-01 L1-01_wp05 Local Co-ordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 3K-01 Mean Sea Level 3K-01 @ 69.00usft (3K-01) True Minimum Curvature 1.00 sigma EDM Alaska ANC Prod Offset Datum teference 3K-01L1-01_wp05 iltertype: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference iterpolation Method: MD Interval 25.00usft Error Model: ISCWSA )epth Range: 9,800.00 to 90,000.00usft Scan Method: Tray. Cylinder North tesults Limited by: Maximum center -center distance of 1,388.10 usft Error Surface: Elliptical Conic Survey Tool Program Date 8/6/2015 From To (usft) (usft) Survey (Wellbore) Tool Name Description 100.00 8,700.00 3K-01 (3K-01) GCT-MS Schlumberger GCT multishot 8,700.00 9,800.00 3K-011_1_wp10(3K-01L1) MWD MWD- Standard 9,800.00 11,950.00 3K-01L1-01_wp05(3K-0111-01) MWD — MWD- Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 11,950.00 6,479.72 2 3/8" 2-3/8 3 Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) Kuparuk 3K Pad 3K-01 - 3K-01 - 3K-01 Out of range 3K-01 - 3K-01 - 3K-01 Out of range 3K-01 - 3K-01 L1 - 3K-01 L1_wp10 11,459.17 11,450.00 40.01 151.77 -91.16 FAIL - Major Risk 3K-01 - 3K-01 L1 - 3K-01 L1_wpl0 11,908.95 11,900.00 41.95 350.33 -289.03 FAIL - Major Risk 3K-01-3K-01Ll-01-3K-01L1-01_wp05 11,875.00 11,875.00 0.38 346.84 -342.60 FAIL - Major Risk 3K-01 - 3K-01 L1-02 - 3K-01 L1-02_wp04 Out of range 3K-01 - 3K-01 L1-02 - 3K-01 L1-02_wp04 Out of range 3K-01 - 3K-011-1-03 - 3K-01L1-03_wp02 Out of range 3K-01 - 3K-01 L1-03 - 3K-01 L1-03_wp02 Out of range 3K-02 - 3K-02 - 3K-02 11,200.00 8,250.00 1,140.18 297.06 855.35 Pass - Major Risk 3K-03 - 3K-03 - 3K-03 Out of range 3K-05 - 3K-05 - 3K-05 Out of range 3K-06 - 3K-06 - 3K-06 Out of range 3K-07 - 3K-07 - 3K-07 Out of range 3K-09 - 3K-09B - 3K-09B Out of range 3K-09 - 3K-09BL1 - 3K-09BL1 Out of range 3K-09 - 3K-09BL1-01 - 3K-09BL1-01 Out of range 3K-102 - 3K-102 - 3K-102 Out of range 3K-102 - 3K-102L1 - 3K-102L1 Out of range 3K-102 - 3K-1021_1 PB1 - 3K-1021-1 PB1 Out of range 3K-108 - 3K-108 - 3K-108 Out of range 3K-108 - 3K-108 L1 - 3K-108 L1 Out of range 3K-19 - 3K-19 - 3K-19 Out of range 3K-20 - 3K-20 - 3K-20 Out of range 3K-22 - 3K-22 - 3K-22 Out of range 3K-22 - 3K-22A - 3K-22A Out of range 3K-23 - 3K-23 - 3K-23 Out of range 3K-24 - 3K-24 - 3K-24 Out of range CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 811212015 10:22:47AM Page 2 COMPASS 5000.1 Build 74 i a F I 9 ti of e 3 4 - 0 Y q ry, Y (m/gsn OOZ) (+)quoN/(-)glnoS N � a o7i � m 0 0 rn R c p gar 2 Q F uJ C J- l h (D - m - - - - - d a [/Jc; 7 r � O�Oi te0 (TiOpl+J t60i N Z N t T l t O t t) N O m l m t 0 M Ma?NNNNNN� -- m00pp00000000pp 00 OOOOth 0 CY O t1100000 O � JN U-OOOOtn OeVOOt000 `L M N °o rno o Oo o O o o o o o 000 0 0 0 0 0 0 0 0 0 0 0 0 0 <O� Ism to O» O m CG m m a2m la'e N m m ee O� m cn ta7 �m . . eV eV � � (4 Iw tri O m T NOmm[�J e00>��ILJ� LO O�OONM[h th try tt7 t l�mm y (O � N N N N N N N N N N N N N e J W MI(n�0. �M ZNtm0.N W to�VR'�Q'�a mtl;mm� J N Nm tulle e0mmmmwm LLl C/3 p g N .6 � g N e 0` e+e CS f V I t - tO tO to to--tn I -IA IO0 L O6 a t O t D t 0 m e 0 m m m m m . t . . . S O.) m ml�m�-0f7� meDt`j N N� c o"I C—C!ma— o o rn rn M - M - - - M - - - - _W + o p o 0 0 0 0 0 0 0 0 0 0 0 0 0 � o 0 0 0 0 0 0 0 0 0 0 0 0 0 O <O N CV fV tV CV fV (V eV (V N <V O �.-.-.-In rn rn o 0 0 0 0 O �� NM�tfJm n mTO�^P't 0 i C O .N.. N q tCC 8 4 Y I 4 8 X � L �g e e �o (U!/l3sn 09) g1daQ [eoijjoA owl C Bettis, Patricia K (DOA) -P I� giE l(p'2 From: Winfree, Mike A <Michael.A.Winfree@conocophillips.com> Sent: Monday, September 14, 2015 8:58 AM To: Bettis, Patricia K (DOA) Subject: FW: [EXTERNAL]KRU 3K-011-1: Permit to Drill Application (PTD 215-161) Attachments: 3K-01L1_wp10 VPO - NAD27.pdf; 3K-01L1-01_wp05 VPO - NAD27.pdf; 3K-011-1-02 _wp04 VPO - NAD27.pdf; 3K-01L1-03_wp02 VPO - NAD27.pdf Good Morning Patricia, Attached are the cross-section and map view wellbore plots for all of the KRU 3K-01 laterals. Sorry for the delay. Please let me know if you need more information to process this permit application. Thank you, -Mike Drilling Engineer I Conoco Phillips Alaska I ATO-660 I Direct: +1 (907) 263-4404 1 Cell: +1 (907) 202-2887 From: Burke, Jason Sent: Friday, September 11, 2015 8:05 PM To: Winfree, Mike A Cc: Eller, J Gary; Venhaus, Dan E Subject: FW: [EXTERNAL]KRU 3K-01L1: Permit to Drill Application (PTD 215-161) Sent with Good (www.good.com) From: Callahan, Mike S Sent: Friday, September 11, 2015 10:08:42 PM To: Burke, Jason; Pohler, Cody J Subject: Fwd: [EXTERNAL]KRU 3K-011-1: Permit to Drill Application (PTD 215-161) Sent from my iPhone Begin forwarded message: From: "Bettis, Patricia K (DOA)" <patricia.bettis@alaska.gov> Date: September 11, 2015 at 4:17:54 PM AKDT To: "Callahan, Mike S (Mike.Callahan@conocophillips.com)" <Mike.Callahan@conocophillips.com> Subject: [EXTERNAL]KRU 3K-01L1: Permit to Drill Application (PTD 215-161) Good afternoon Mike, Please submit the cross -sectional and planar wellbore plats for KRU 3K-011-1. Only the spider map was included in the applications. Thank you and have a great weekend. Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7tn Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If 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 Patricia Bettis at (907) 793-1238 or patricia.bettisCa@alaska.gov. TRANSMITTAL LETTER CHECKLIST WELL NAME: L�R(,_ PTD: als- - /(0 2 Development _ Service Exploratory Stratigraphic Test _ Non -Conventional FIELD: U POOL: t A r � 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. / 8(o — JOl , API No. 50-Da- 9 ) (v 00 - DO - OC-N . (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - from records, data and logs acquired for well (name onpermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where sam les 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#:2151620 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Well Name: KUPARUK RIV UNIT 3K-011-1-01 Program DEV Well bore seg ❑d DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal Administration 17 Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025519, Surf Loc; ADL0025520, Top Prod Intery & TD. 3 Unique well name and number Yes KRU 3K-011-1-01 4 Well located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order No. 432C 5 Well located proper distance from drilling unit boundary Yes CO 432C contains no spacing restrictions with respect to drilling unit boundaries. 6 Well located proper distance from other wells Yes CO 432C has no interwell spacing restrictions. 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes Wellbore will be more than 500' from an external property line where ownership or landownership changes. 10 Operator has appropriate bond in force Yes Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval Yes PKB 9/14/2015 13 Can permit be approved before 15-day wait Yes 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 18 Conductor string provided NA Conductor set in KRU 3K-01 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in KRU 3K-01 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing set and fully cemented 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons No Productive interval will be completed with uncemented slotted liner 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes Anti collision analysis complete; no major risk failures 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pressure is 4603 psig(13.7 ppg EMW); will drill w/ 9.1 ppg EMW and maintain overbal w/ MPD VTL 9/16/2015 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 3944 psig; will test BOPs to 4500 psig 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable Yes 112S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 3K-Pad are H2-S bearing. H2-S measures required. Geology 36 Data presented on potential overpressure zones Yes Maximum expected reservoir pressure is 13.74 ppg EMW; will be drilled using 9.1 ppg mud and MPD technique. Appr Date 37 Seismic analysis of shallow gas zones NA 3K area structurally complex with potential for unmapped faults; MPD PKB 9/14/2015 38 Seabed condition survey (if off -shore) NA shale instability associated with fault crossings. 39 Contact name/phone for weekly progress reports [exploratory only] NA Onshore development well to be drilled. Geologic Engineering Public Date: Date Date Commissioner: Coo issioner: 9 /8 � Commissioner