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Home My WebLink About213-085213-085: The Current Well Status was changed to EXPIR on the effective date of 6/11/2015. This change was performed by user SEM. THE STATE 01S A GOVERNOR SEAN PARNELL Lamar Gantt Coiled Tubing Drilling Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 lzska Oil and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Re: Kuparuk River Field, Kuparuk River Oil Pool, 3C-10AL1-01 ConocoPhillips Alaska, Inc. Permit No: 213-085 Surface Location: 1119' FNL, 889' FEL, SEC. 14, T12N, R9E, UM Bottomhole Location: 2109' FNL, 759' FEL, SEC. 12, T12N, R9E, UM Dear Mr. Gantt: 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. 213-083, API No. 50-029- 21356-01-00. 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 Commission 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 Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this ` 1 day of June, 2013. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: Drill r❑r . Lateral ❑✓ Redrill L 1 Reentry ❑ 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 U Single Well Bond No. 59-52-180 • 11. Well Name and Number: 3C-10AL1-01 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 10850' TVDSS: 6580' 12. Field/Pool(s): Kuparuk River Field . Kuparuk River Oil Pool 4a. Location of Well (Governmental Section): Surface: 1119' FNL, 889' FEL, Sec. 14, T12N, R9E, UM • Top of Productive Horizon: 1169' FSL, 1739' FEL, Sec. 12, T12N, R9E, UM Total Depth: 2109' FNL, 759' FEL, Sec. 12, T12N, R9E, UM 7. Property Designation (Lease Number): ADL 25634, 25629 8. Land Use Permit: 2567, 2562 13. Approximate Spud Date: 7/1/2013 9. Acres in Property: Q 2,568 -�� b Q,II31t 14 .Distance to Nearest Property: 5730 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 528685 y- 5995314 Zone- 4 • 10. KB Elevation above MSL: 82 feet GL Elevation above MSL: 47 feet 15. Distance to Nearest Well Open to Same Pool: 3C-08 , 1120' 16. Deviated wells: Kickoff depth: 9050 ft. Maximum Hole Angle: 91 ° deg 17. Maximum Anticipated Pressures in psig (see 20 AAC 25 035) Downhole: 3904 psig • Surface: 3264 psig - 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks stage data Hole Casing Weight Grade Coupling Length MD TVDSS MD TVDSS(including 3" 2.375" 4.7# L-80 ST-L 2680' 8170' 6071' 10850' 6580' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 8980' Total Depth TVD (ft): 6740' Plugs (measured) none Effective Depth MD (ft): 1 8891 Effective Depth TVD (ft): 6674' Junk (measured) none Casing Length Size Cement Volume MD TVD Conductor/Structural 81' 16" 213 sx CS II 116' 116' Surface 4784' 9.625" 1440 sx AS III, 320 sx CI G 4819' 3729' Intermediate Production 8935' 7" 300 sx Class G 8974' 6736' Scab Liner 715' 4.5" 1 22 bbls Class G 8873' 6662' Perforation Depth MD (ft): 8539'-8551', 8697'-8742', 8764'-8790' Perforation Depth TVD (ft): 6419'-6428', 6534'-6566', 6582'-6601' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Prograrr C 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: ` 1 22. 1 hereby certify that the foregoing is true and correct. Contact Kai Starck @ 263-4093 Email Kai.Starckilliio.corn Printed Name Lamar Gant Title Coiled Tubing Drilling Supervisor Signature A Phone: 263-4021 Date �13113 Commission Use Only Permit to Drill Number: �I �(� gS API Number: 50-�'�� — C) S �� _ d� 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 methane, gas hydrates, or gas contained in shales: Other:'5OP fe'.S f • f D f 0 l9 0 12 S •C Samples req'd: Yes ❑ No Mud log req'd: Yes No III H2S measures: Yes Z No Q Directional svy req'd: YesZ No Spacing exception req'd: Yes El No �f Inclination -only svy req'd: Yes ❑ No F4 APPROVED BY THE 6 A/ Approved by: COMMISSIONER COMMISSION Date: A3 Form 107401 (Revised 10/2012) This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) VLF &/////3 ConocoPhillips p Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 29, 2013 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 Permit to Drill (PTD) applications to drill and complete 3C-10A, 3C- 10AL1 and 3C-10AL1-01 from Kuparuk well 3C-10 (PTD#185-101). Coiled tubing drilling (CTD) operations are scheduled to begin July 1, 2013 using the Nabors CDR2-AC rig. Producer 3C-10A is part of a development concept to increase throughput in an unswept A -sand pattern. The planned 3C-09 injector to the west will provide injection support to this new producer. Doyon 141 performed a rig workover in May of 2013 in preparation for CTD operations. The existing A -sand and C-sand perforations have been cemented behind the 4'/" scab liner. ConocoPhillips requests a variance from the requirements of 20 AAC 25.112(c)(1) to plug the perforations in this manner. There is insufficient room to meet these plugging requirements while still accommodating a sidetrack from 8630' MD. Attached to this application are the following documents that explain the proposed job operations. A BOP schematic for slimhole CTD operations from Nabors CDR2 is already on file with the Commission. — Drilling program summary — Permit to Drill application forms for 3C-10A, 3C-10AL1 and 3C-10AL1-01 — Directional plans for 3C-10A, 3C-10AL1 and 3C-10AL1-01 — Current wellbore schematic — Proposed wellbore schematic after CTD operations If you have any questions or require additional information please contact me at my office 907-263-4093. Sincerely, Kai Starck ConocoPhillips Alaska Coiled Tubing Drilling Specialist Kuparuk CTD Laterals NABOF'�SKA 3C-10A, 3C-10AL1 and 3C-10AL1-01 C1Q91 Application for Permit to Drill Document 2RC 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25. 005(o and 20 AA C 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 PressureDeployment of BHA.......................................................................................................................................... 5 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 Attachment 1: Directional Plans for 3C-10A, 3C-11AL1, 3C-10AL1-01..........................................................................6 Attachment 2: Current Well Schematic for 3C-10........................................................................................................... 6 Attachment 3: Proposed Well Schematic for 3C-10A CTD Laterals............................................................................... 6 Page 1 of 6 May 30, 2013 AVIN Kuparuk CTD Laterals NABOBS A"SKA IV 3C-10A3 3C-10AL1, and 3C-10AL1-01 CIJf Application for Permit to Drill Document 21FIC 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25:005(b)) There are three proposed laterals described in this document: KRU 3C-10A, 3C-10AL1 and 3C-10AL1-01. The A sidetrack will be drilled off the motherbore and the AL1 and AL1-01 laterals will be drilled off the A sidetrack. All three will be classified as "Development -Oil' wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) The 3C-10A sidetrack is planned to target the Kuparuk A3 sand to south of the existing well. The 3C-10AL1 lateral is planned to target the Kuparuk A3 sand to the north of the existing well. The 3C-10AL1-01 lateral is planned to target the A2 sand to the north of the existing well. See the attached 10-401 forms for surface and subsurface coordinates of each of the 3C-10 laterals. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR2-AC. 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 4000 psi. Using a maximum potential formation pressure of 3904 psi, the maximum potential surface pressure is 3264 psi assuming a gas gradient of 0.1 psi/ft. See the "Drilling Hazards Information and Reservoir Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2500 psi. 4. Drilling Hazards Information and Reservoir Pressure (Requirements of 20 AAC 25.005 (c)(4)) Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005 (c)(4)(a)) The latest 3C-10 SBHP taken 4/16/13 was 3169 psi for an 9.6 EMW from the C1 and the A2/A3/A4 sands. The 3C-10A sidetrack will be approaching 3C-11 which prior to being put back on production in Feb. 2013 had a SBHP of 3440 psi or 10.3 EMW. The 3C-10AL1 and ALl-01 laterals will be drilled to the north with the nearest well, 3C-08 to the north, having an A sand formation pressure at 3050 psi for an 8.8 EMW. 3C-09 to the west had a 5/26/2013 SBHP at 3904 psi for an 11.6 EMW. It is not expected that pressures as high as 3C-09 will be encountered during the drilling operations due faulting. Using the 3C-09 formation pressure as the maximum possible in 3C-10A, the maximum potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 3264 psi. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) No specific gas zones will be drilled and there has been no gas or MI injection in the area Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) The major expected downhole risk in the 3C-10A laterals is hole stability due to interbedded shales and silts in the A -sand. We will mitigate hole instability by maintaining a minimum ECD target of 11.8 ppg EMW at the window while drilling the CTD laterals, as well as using mud additives that minimize chemical instability. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) Each of the 3C-10A laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so formation integrity tests are not required. Page 2 of 6 May 30, 2013 f iStJ 41,413 /0/�5 PTD Application for KRU 3C-10A, AL1, AL1-01 6. Casing and Cementing Program ECEIV L (Requirements of 20 AAC 25.005(c)(6)) Gar New Completion Details J'!" iU Z 3 Liner Liner Liner Liner Lateral Name Top MD Btm Top Btm Liner Details MD SSTVD SSTVD 3C-10A 8730' 11,650' 6453' 6468' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 3C-10AL1 9050' 10,850' 6477' 6537' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 3C-10AL1-01 8170' 10,850' 6071' 6580' 2%", 4.7#, L-80, ST-L slotted liner; Deployment sleeve on to Existing Casing/Liner Information Weig Top Btm Top Btm Burst Collapse Category OD ht Grade Connection MD MD TVD TVD psi psi pf) Conductor 16" 62 H-40 Welded 34' 116, 0' 116' Surface 9-5/8" 36 J-55 BTC 31.5' 4816' 0' 3727' 3520 2020 Casing 7" 26 J-55 BTC 38.7' 8974' 0' 6736' 4980 4330 Liner 4'/" 12.6 L-80 IBTM 8205' 8873' 6096' 6580' 8430 7500 Tubing 3'/2" 9.3 L-80 EUE-Mod 24' 8201' 0' 9093' 10,160 10,540 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 so no diverter system is required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System Diagram of Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System - Window milling operations: Chloride -based Biozan brine or used drilling mud (-V .5 ppg) - Drilling operations: Chloride -based Flo -Pro Flo Vis mud (9.5—ppg). This mud weight alone will hydrostatically overbalance formation pressure in the 3C-10 motherbore. MPD practices described below will increase the overbalance to enhance shale stability. - Completion operations: The well will be loaded with 11.8 ppg sodium bromide completion fluid in order to maintain pressure over -balance while picking up liner. - Emergency Kill Weight fluid: Two well bore volumes (-200 bbl) of 12 ppg emergency kill weight fluid will be within a short drive of the rig during drilling operations. Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole formation throughout the coiled tubing drilling (CTD) process. Maintaining a constant BHP promotes wellbore stability, particularly in shale sections, while at the same time providing pressure over- balance to the formation. In the 3C-10A laterals we will target a constant BHP of 11.8 ppg EMW at the window. If increased formation pressure is encountered, mud weight or choke pressure will be increased to maintain Page 3 of 6 May 30, 2013 r,HI� 14 PTD 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details alication for KRU 3C-10A, A41, ALl-01 Liner Liner Liner Liner Lateral Name Top MD Btm Top Btm Liner Details MD SSTVD SSTVD 3C-10A 8730' 11,650' 6453' 6468' 23/ , 4.7#, L-80, ST/L slotted liner; aluminum billet orr'to 3C-10AL1 9050' 10,850' 6477' 6537' 23/", 4.7#, L-80, 8T-L slotted liner; aluminum billeton top 3C-10AL1-01 8170' 10,850' 6071' 6580' 2%" 4.7#, L-80, ST-L slotted liner; Deplo ment sleeve on top Existing Casing/Liner Information Category OD Weig ht (ppf) Grade Connection To IVID Btm MD To TVD Btm TVD Burst psi Collapse psi Conductor 66" 62 H-40 Welded 34' 116' 0' 116' Surface 9-5/8" 36 J-55 BTC 31.5' 4816' 0' 3727' 3520 2020 Casing 7" 26 J-55 BTC 38.7' 8974' 0' 6736' 4980 4330 Liner 4%" 12.6 L-80 IBTM 8205' :' 8873' 6096, 6580' 8430 7500 Tubing 3%" 9.3 L-80 EUE-Mod 24', 8201' 0' 9093' 10,160 10,540 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 so no diverter system is required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System Diagram of Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System - Window milling operations: Chloride -based Biozan brine or used drilling mud (-X.X ppg) — Drilling operations: Chloride -based Flo -Pro Flo Vis mud (X.X ppg). This mud weight alone will hydrostatically overbalance formation pressure in the 3C-10 motherbore. MPD practices described below will increase the overbalance to enhance shale stability. — Completion operations: The well will be loaded with 11.8 ppg sodium bromide completion fluid in order to maintain pressure over -balance while picking up liner. — Emergency Kill Weight fluid: Two well bore volumes (-200 bbl) of 12 ppg emergency kill weight fluid will be within a short drive of the rig during drilling operations. Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole formation throughout the coiled tubing drilling (CTD) process. Maintaining a constant BHP promotes wellbore stability, particularly in shale sections, while at the same time providing pressure over- balance to the formation. In the 3C-10A laterals we will target a constant BHP of 11.8 ppg EMW at the window. If increased formation pressure is encountered, mud weight or choke pressure will be increased to maintain Page 3 of 6 May 30, 2013 PTD Application for KRU 3C-10A, AL1, AL1-01 overbalance. Additional choke pressure or increased mud weight may also be employed for improved borehole stability but not necessarily for well control. Pressure at the 3C-10A Window 8630MD, 6403' TVD Usina MPD Pumps On (1.5 b m) Pumps Off A -sand Formation Pressure 8.1 p 2692 psi 2692 psi Mud Hydrostatic 9.5 3158 psi 3158 psi Annular friction i.e. ECD, 0.090 si/ft 711 psi 0 psi Mud + ECD Combined (no choke pressure) 3869 psi (overbalanced 1231psi) 3158 psi (overbalanced 466psi) Target BHP at Window 11.8 ) 3923 psi 3923 psi Choke Pressure Required to Maintain Target BHP 54 psi 765 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 not for an exploratory or stratigraphic test well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c) (12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background The parent 3C-10 well is currently shut-in but was producing from the Kuparuk C, A3, and A2 sandstones. The southern lateral will remain in the same fault block as the parent 3C-10 well. The two northern laterals will cross a down -to -the -north fault and produce from both the parent well fault block and the northern downthrown fault block. The C-sandstone perforations have been abandoned in the parent well because of high water cut. The CTD well plan is to drill the southern lateral first, then kick off from that lateral and drill the northern A3 lateral. The northern A2 lateral will be kicked off from the northern A3 lateral. Doyon 141 performed a rig workover in May of 2013 in preparation for CTD operations. The existing A - sand and C-sand perforations have been cemented behind the 4%2" scab liner. ConocoPhillips requests a variance from the requirements of 20 AAC 25.112(c)(1) to plug the perforations in this manner. There is insufficient room to meet these plugging requirements while still accommodating a sidetrack from 8630' MD. A mechanical whipstock will be placed in the 41/" liner at the planned kickoff point. The 3C-10A sidetrack will exit the 4%" and the 7" casing at 8630' MD and target the A3 sand to the south of the existing well with Page 4 of 6 ��a p May 30, 2013 PTD Application for KRU 3C-10A, AL1, AL1-01 The 3C-10AL1 lateral will kick off from the aluminum billet at 8730' MD and will target the A3 sand north of the existing well with a 2120' lateral. The hole will be completed with a 2%" slotted liner to the TD of 10,850' MD with an aluminum billet at 9050' MD. The 3C-10AL1-01 lateral will kick off from the aluminum billet at 9050' MD and will target the A2 sand north of the existing well with a 1800' lateral. The hole will be completed with a 23/" slotted liner to the TD of 10,850' MD with a liner top deployment sleeve at 8170' MD, inside the 3%" tubing. Pre-CTD Work 1. MIRU slickline. Dummy all GLMs. Run a dummy whipstock and tag PBTD 2. MIRU e-line. Set whipstock at 8630' MD with a highside orientation 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. 3C-10A Sidetrack (A3 sand, south) a. Set whipstock at 8630' MD with HS orientation b. Mill 2.80" window through 3%2" liner C. Drill 2.70" x 3" bi-center lateral to TD of 11,650' MD d. Run 2%" slotted liner with an aluminum billet from TD up to 8730' 3. 3C-10AL1 Lateral (A3 sand, north) a. Kick off of the aluminum billet at 8730' MD b. Drill 2.70" x 3" bi-center lateral to TD of 10,850' MD C. Run 23/" slotted liner with an aluminum billet from TD up to 9050' MD 4. 3C-10AL1-01 Lateral (A2 sand, north) a. Kick off of the aluminum billet at 9050' MD b. Drill 2.70" x 3" bi-center lateral to TD of 10,850' MD C. Run 2%" slotted liner with an aluminum billet from TD up to 8170' MD inside the 3'/2" Tubing 5. Freeze protect. Set BPV, ND BOPE. 6. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV Obtain static BHP, Install gas lift valves Put well on production Pressure Deployment of BHA The planned bottomhole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. Because of this, MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slickline lubricator. This pressure control equipment 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. Page 5 of 6 May 30, 2013 PTD Application for KRU 3C-10A, AL1, AL1-01 — 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 conducted in reverse. Liner Running — Since 3C-10 is equipped with a SSSV, the CTD laterals will not need to be displaced to an over- balancing fluid prior to running liner unless the SSSV fails. In that case, fluid of sufficient density to over -balance the formation will be used to provide well control. See the "Drilling Fluids" section for more details. — While running 2%" slotted liner, a joint of 23/" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 23/" pipe rams provide secondary well control while running 23/" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AA 25.005(c)(14)) — No annular injection on this well. — Class II liquids to KRU 1 R Pad Class II disposal well — Class II drill solids to Grind & Inject at PBU Drill site 4 , — Class I wastes will go to Pad 3 for disposal. 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) — There are no other affected owners — Please see attached directional plans for each lateral. — Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. — MWD directional, resistivity, and gamma ray will be run over the entire openhole section. ✓ — Distance to nearest property line and nearest well in the same pool. Lateral Name Directional Plan Distance to Unit Boundary Distance to Nearest Well Nearest Well 3C-10A 01 9600' 350' 3C-11 3C-10L1 02 5820' 1020' 3C-08 3C-10AL1-01 01 5730' 1120' 3C-08 Attachment 1; Directional Plans for 3C-10A, 3C-10AL1 and 3C-10AL1-01 Attachment 2: Current Well Schematic for 3C-10 Attachment 3: Proposed Well Schematic for 3C-10A CTD Laterals Page 6 of 6 May 30, 2013 p w w U N O 0 o 0 Fm c � U LO co CF) m '_' dU m JC) n �_ p p Q g c rn c J a a E o co "' 11 U moo w t a`) w uco to co a`) p C7 m c_ U v Ud � w DJ W O � A al E O o O N J In col o r' �_ I u �. d J c U ar clip Cl) E (aZ _a a xv X a) O >,o cn - of U X N li ao •- F- p N (V (V (V Y Y N Y N (V cq Y co M (h v A A CO m m m r U M I is m p p 31 co o o i m u'o 11 Qr t co Lo c3 11. o o 0 0 li : � � c J rn it L t 11 0 0 U p _ 1I ~ C�� c') < i0 I i I 11 1 ii+ II - p ll 00 X II C,j CD C N O L co a to YtL I1 Nrn co �- Nr cco pYO II QaOo a~0 p � p m iN o � coco m r t'- L_ co O0 N v Maim .f AdW' KUP 3C-10 ConocoPhillips fillips Well Max Angleg& MD A DBtm tea' ��- lrAttributes APVUWIFeld Name Wellbore Statue 500292135600 KUPARUK RIVER UNIT PROD 50.10 3,300.00 (ftKB) 8,980.0 Comment H2S (ppm) Date Annotation End Data KB-Grd (it) Rig Release Date .. Well coar :.3c-10 snon013 e:0B:0s AM SSSV: TRDP 100 5/1112112 Last W0: 5/10/2013 34.59 7/3/1985 S.a.-lc-Adaal Annotation Depth Last Tag: RKB (ftKB) 8,873.0 End Date Annotation 5/15/2013 Rev Reason: WORKOVER Last Mod By Osborl End Date 5/30/2013 HANGER, 24 't CasinoShin s Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd CONDUCTOR Casing Description SURFACE 16 String 0... 95/8 15.052 String ID 8.921 35.0 ... Top (ftKB) 34.9 116.0 Set Depth (1... 4,819.4 116.0 Set Depth (TVD)... String 3,729.1 62.50 Wt... String... 36.00 H-40 J-55 WELDED String Top Third BTC Casing Description PRODUCTION String 0.-. 7 String ID 6.276 ... Top (ftKB) Set 38.7 Depth If... 8,972.2 Set Depth (TVD) ... String 6,734.3 Wt... String 26.00 ... J-55 String Top Thrd BTC Casing Description SCAB LINER String 0... 4 1/2 String ID 3,958 ... Top (ftKB) Set 8, 157.7 Depth If... 8,873.0 Set Depth (TVD)... String 6.661.9 Wt... String... 12.60 L-80 String Top Thrd IBTM Liner Details CONDUCTOR, Top Depth 35-116 SAFETY VLv, 1.977 Top(ftKB) (TVD) (ftKB) Top Incl (°) Item Description Comment Nomi... 10(in) 8,157.7 6,144.7 45.34 PACKER BAKER C-2 ZXP LINER TOP PACKER 4.970 8, 176.2 lijb7.61 45.05 HANGER BAKER FLEX LOCK HANGER 4.853 8,186.0 6,164.51 44.90 SBE BAKER 80-40 L-80 (4.00ID) SEAL BORE EXTENSION 4.000 Tubing Strin s GAS LIFT. Tubing Description String 0... Strng ID ... Top (RKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... Strin9 Top Thrd 3,138 TUBING WO 3 1/2 2.992 24.2 8,201.8 6,176.1 9.30 L-80 8 rd EUE-Mod Com letion Details Top Depth Top (ftKB) (TVD) (ftKB) Top lncl (°) I Item Description Comment Nomi... ID (in) 24.2 24.2 0.34 HANGER TUBING HANGER 2.992 1,976.9 1,811.8 46.18 SAFETY VLV CAMCO TRMAXX-CMT-SR-5 SCSSV 2.812 SURFACE, 35-4816 - 8,115.0 6,114.7 46.01 NIPPLE HES'X'LANDINGNIPPLE 2.813 8,163.9 6,149.0 45.25LOCATOR BAKER SEAL LOCATOR 2.990 GAS LIFT. 8,165.1 6,149.9 45.23 SEAL ASSY BAKER 80-40 GBH-22 SEAL ASSEMBY 2.996 Perforations & Slots 5,170 Shot (' Top (TVD) St. (TVD) Dens l Top (ftKB) St. (ftKB) AS) (ftKB) Zone Date (sh - Type Comment 8,539.0 8,551.0 6,419.1 6,427.7 C-1, UNIT B, 7/29/1985 12.0 IPERF 12 -deg. phasing; 5 1/2" Scalloped GAS LIFT, 3C-10 HJ 6.520 8,697.0 8,742.0 6,533.6 6,566.4 A-4, A-3, 3C-10 7/29/1985 4.0 IPERF 90 deg. phasing; 4" Carrier Gun HJ II 8764.0 8,790.0 6,582.4 6,601.4 A-2, 3C-10 7/29/1985 4.0 IPERF 90 deg. phasing; 4" Carrier Gun HJ II Notes: General & Safety GAS LIFT, 7,500 �) End Date Annotation 7/15/2010 NOTE: View Schematic w/ Alaska Schematic9.0 GAS LIFT, 8,055 i - --� j NIPPLE, 8,115 -- - LOCATOR, 8.164 SEALASSY, 8.165 IPERF, 8.539-8.561 IPERF, 8,69T8,742 IPERF, Mandrel Details 8,764-8,790 Top Depth Top Port S,,, N... Top (ftKB) (TVD) (ftKB) Ind (°) Make Model OD (in) S., Valve Type Latch Type Size (in) TRO Run (psi) Run Date Com... 1 3,137.6 2,599.3 49.21 Camco MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 5/29/2013 2 5,169.9 3,995.5 39.45 Camco MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 5/19/2013 3 6,520.1 5,007.5 42.71 Camco MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 5/19/2013 4 7,499.9 5,694.7 46.45 Camco MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 5/19/2013 SCAB LINER, 8.158-8.873 5 8,054.9 6,073.5 46.96 Camco MMG 1 112 GAS LIFT DMY RK 0.000 0.0 5/19/2013 PRODUCTION, 39.8,972y TD, 8,96080 - _ ' '� Yt C �� k C ( �.,, ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 3C Pad 3C-10 3C-10AL1-01 Plan: 3C-10AL1-01 _wp01 Standard Planning Report 23 May, 2013 a pw--- BAKER HUGHES ConocoPhillips or its affiliates Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3C Pad Well: 3C-10 Wellbore: 3C-10AL 1-01 Design: 3C-10AL1-01_wp01 Planning Report Local Co-ordinate Reference: Well 3C-10 TVD Reference: Mean Sea Level MD Reference: 3C-10 @ 82.00ft (3C-10) North Reference: True Survey Calculation Method: Minimum Curvature Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk 3C Pad Site Position: Northing: 5,995,835.15ft Latitude: 70' 23' 58.955 N From: Map Easting: 528,205.68ft Longitude: 149° 46' 13.622 W Position Uncertainty: 0.00 ft Slot Radius: 0.000 in Grid Convergence: 0.22 ° Well 3C-10 Well Position +N/-S 0.00 ft Northing: 5,995,314.06 ft Latitude: 70° 23' 53.812 N +El-W 0.00 ft Easting: 528,685.04 ft Longitude: 149' 45' 59.636 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 47.40 ft Wellbore 3C-10AL1-01 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (1 (nT) BGGM2012 8/1/2013 15.49 79.97 57,366 Design 3C-10AL1-01_wp01 Audit Notes: Version: Phase: PLAN Tie On Depth: 9,050.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (ft) (ft) (ft) (I -47.40 0.00 0.00 0.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (ft) (°) (°) (ft) (ft) (ft) (°/100ft) (°1100ft) (°1100ft) (°) Target 9,050.00 90.00 39.20 6,477.23 2,571.06 5,078.16 0.00 0.00 0.00 0.00 9,140.00 79.37 41.10 6,485.56 2,639.46 5,135.85 12.00 -11.82 2.11 170.00 9,390.00 80.80 10.67 6,529.61 2,858.32 5,241.89 12.00 0.58 -12.17 270.00 9,460.00 85.07 3.37 6,538.23 2,927.20 5,250.35 12.00 6.09 -10.42 300.00 9,610.00 85.31 21.44 6,550.92 3,072.57 5,282.33 12.00 0.16 12.04 90.00 9,860.00 86.29 351.37 6,569.67 3,317.48 5,309.78 12.00 0.39 -12.03 270.70 10,110.00 86.79 21.42 6,585.12 3,562.61 5,337.27 12.00 0.20 12.02 90.00 10,210.00 89.94 9.84 6,587.99 3,658.70 5,364.14 12.00 3.15 -11.59 285.00 10,360.00 90.87 351.86 6,586.93 3,808.07 5,366.36 12.00 0.62 -11.98 273.00 10,590.00 90.77 19.46 6,583.59 4,034.71 5,388.83 12.00 -0.04 12.00 90.00 10,850.00 90.66 348.26 6,580.28 4,290.91 5,406.12 12.00 -0.04 -12.00 270.00 5/23/2013 4:30:03PM Page 2 COMPASS 2003.16 Build 69 ConocoPhillips or its affiliates Planning Report Database: EDM Alaska Sandbox v16 Local Co-ordinate Reference: Well 3C-10 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 3C-10 @ 82.00ft (3C-10) Site: Kuparuk 3C Pad North Reference: True Well: 3C-10 Survey Calculation Method: Minimum Curvature Wellbore: 3C-10AL1-01 Design: 3C-10AL 1-01 _wp01 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (ft) (°) (°) (ft) (ft) (ft) (ft) (°/100ft) (°) (ft) (ft) 9,050.00 90.00 39.20 6,477.23 2,571.06 5,078.16 2,571.06 0.00 0.00 5,997,904.33 533,752.79 TIP/KOP 9,100.00 84.09 40.25 6,479.81 2,609.45 5,110.05 2,609.45 12.00 170.00 5,997,942.84 533,784.54 9,140.00 79.37 41.10 6,485.56 2,639.46 5,135.85 2,639.46 12.00 169.95 5,997,972.95 533,810.21 Start 12 dls 9,200.00 79.45 33.78 6,496.60 2,686.25 5,171.67 2,686.25 12.00 -90.00 5,998,019.88 533,845.85 9,300.00 79.96 21.59 6,514.53 2,773.21 5,217.28 2,773.21 12.00 -88.65 5,998,107.00 533,891.13 9,390.00 80.80 10.67 6,529.61 2,858.32 5,241.89 2,858.32 12.00 -86.47 5,998,192.19 533,915.40 3 9,400.00 81.41 9.62 6,531.16 2,868.04 5,243.63 2,868.04 12.00 -60.00 5,998,201.92 533,917.10 9,460.00 85.07 3.37 6,538.23 2,927.20 5,250.35 2,927.20 12.00 -59.84 5,998,261.10 533,923.60 4 9,500.00 85.08 8.19 6,541.67 2,966.84 5,254.37 2,966.84 12.00 90.00 5,998,300.75 533,927.46 9,600.00 85.28 20.23 6,550.10 3,063.26 5,278.79 3,063.26 12.00 89.59 5,998,397.25 533,951.51 9,610.00 85.31 21.44 6,550.92 3,072.57 5,282.33 3,072.57 12.00 88.57 5,998,406.58 533,955.02 5 9,700.00 85.52 10.60 6,558.13 3,158.67 5,307.05 3,158.67 12.00 -89.30 5,998,492.76 533,979.40 9,800.00 85.95 358.58 6,565.60 3,257.89 5,315.02 3,257.89 12.00 -88.43 5,998,592.00 533,986.99 9,860.00 86.29 351.37 6,569.67 3,317.48 5,309.78 3,317.48 12.00 -87.53 5,998,651.57 533,981.52 6 9,900.00 86.30 356.18 6,572.25 3,357.15 5,305.45 3,357.15 12.00 90.00 5,998,691.21 533,977.04 10,000.00 86.45 8.20 6,578.60 3,456.69 5,309.26 3,456.69 12.00 89.69 5,998,790.76 533,980.47 10,100.00 86.75 20.22 6,584.56 3,553.28 5,333.72 3,553.28 12.00 88.93 5,998,887.43 534,004.56 10,110.00 86.79 21.42 6,585.12 3,562.61 5,337.27 3,562.61 12.00 88.21 5,998,896.78 534,008.07 7 10,200.00 89.62 10.99 6,587.95 3,648.87 5,362.34 3,648.87 12.00 -75.00 5,998,983.12 534,032.80 10,210.00 89.94 9.84 6,587.99 3,658.70 5,364.14 3,658.70 12.00 -74.67 5,998,992.96 534,034.57 8 10,300.00 90.50 359.05 6,587.65 3,748.30 5,371.11 3,748.30 12.00 -87.00 5,999,082.57 534,041.19 10,360.00 90.87 351.86 6,586.93 3,808.07 5,366.36 3,808.07 12.00 -87.04 5,999,142.32 534,036.21 9 10,400.00 90.86 356.66 6,586.33 3,847.85 5,362.36 3,847.85 12.00 90.00 5,999,182.08 534,032.06 10,500.00 90.83 8.66 6,584.85 3,947.55 5,366.99 3,947.55 12.00 90.07 5,999,281.79 534,036.31 10,590.00 90.77 19.46 6,583.59 4,034.71 5,388.83 4,034.71 12.00 90.25 5,999,369.03 534,057.81 10 10,600.00 90.77 18.26 6,583.46 4,044.18 5,392.06 4,044.18 12.00 -90.00 5,999,378.50 534,061.00 10,700.00 90.75 6.26 6,582.13 4,141.71 5,413.26 4,141.71 12.00 -90.02 5,999,476.10 534,081.82 10,800.00 90.69 354.26 6,580,87 4,241.52 5,413.71 4,241.52 12.00 -90.18 5,999,575.90 534,081.90 10,850.00 90.66 348.26 6,580.28 4,290.91 5,406.12 4,290.91 12.00 -90.33 5,999,625.26 534,074.11 Planned TD at 10850.00 512312013 4:30:03PM Page 3 COMPASS 2003.16 Build 69 Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3C Pad Well: 3C-10 W el I bo re: 3C-10AL 1-01 Design: 3C-10AL 1-01 _wp01 Targets Target Name hit/miss target Dip Angle Dip Dir. Shape C) (1) 3C-10AL1_Faultl 0.00 0.00 plan hits target center Rectangle (sides W425.00 H1.00 D0.00) ConocoPhillips or its affiliates Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3C-10 Mean Sea Level 3C-10 @ 82.00ft (3C-10) True Minimum Curvature TVD +N/-S +E/-W Northing Easting (ft) (ft) (ft) (ft) (ft) 0.00-1,606.761,145,333.69 5,998,103.00 1,673,903.00 3C-10AL1 CTD Polygon 0.00 0.00 0.00 -2,025.261,144,931.04 5,997,683.00 1,673,502.00 plan hits target center Polygon Point 1 0.00 -2,025.261,144,931.04 5,997,683.00 1,673,502.00 Point 0.00 -1,708.971,145,127.26 5,998,000.01 1,673,696.99 Point 0.00 -979.021,145,162.03 5,998,730.02 1,673,728.95 Point 0.00 -160.101,145,204.13 5,999,549.01 1,673,767.90 Point 5 0.00 -168.831,145,661.15 5,999,542.03 1,674,224.91 Point 0.00 -912.711,145,610.32 5,998,798.04 1,674,176.94 Point 0.00 -1,434.671,145,585.35 5,998,276.04 1,674,153.97 Point 0.00 -2,063.361,145,483.95 5,997,647.03 1,674,055.00 Point 0.00 -2,379.751,145,051.71 5,997,329.01 1,673,624.02 Point 10 0.00 -2,025.261,144,931.04 5,997,683.00 1,673,502.00 3C-10AL1-01 T1 0.00 0.00 6,477.00-2,053.341,145,212.97 5,997,656.00 1,673,784.00 Latitude Longitude 70' 9' 21.295 N 140° 31' 32.317 W 70' 9' 17.831 N 140° 31' 45.651 W 70' 9' 17.139 N 1400 31' 37.719 W plan hits target center Point 3C-10AL1-01_T3 0.00 0.00 6,544.00 -1,652.041,145,406.53 5,998,058.00 1,673,976.00 70' 9' 20.747 N 140' 31' 30.434 W plan hits target center Point 3C-10AL1-01_T4 0.00 0.00 6,588.00 -966.331,145,499.17 5,998,744.00 1,674,066.00 70' 9' 27.266 N 140' 31' 24.788 W plan hits target center Point 3C-10AL1-01_T6 0.00 0.00 6,580.00 -333.421,145,541.60 5,999,377.00 1,674,106.00 70° 9' 33.346 N 140° 31' 20.806 W plan hits target center Point 3C-10AL1-01_T2 0.00 0.00 6,512.00 -1,882.881,145,357.64 5,997,827.00 1,673,928.00 70° 9' 18.579 N 1400 31' 32.840 W plan hits target center Point 3C-10AL1-01_T5 0.00 0.00 6,581.00 -408.461,145,550.31 5,999,302.00 1,674,115.00 70° 9' 32.605 N 140° 31' 20.886 W plan hits target center Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (in) (in) 10,850.00 6,580.28 2 3/8" 2.375 3.000 &23/2013 4:30:03PM Page 4 COMPASS 2003.16 Build 69 } Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3C Pad Well: 3C-10 Wellbore: 3C-10AL 1-01 Design: 3C-10AL 1-01 _wp01 ConocoPhillips or its affiliates Planning Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3C-10 Mean Sea Level 3C-10 @ 82.00ft (3C-10) True Minimum Curvature Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (ft) (ft) (ft) (ft) Comment 9,050.00 6,477.23 2,571.06 5,078.16 TIP/KOP 9,140.00 6,485.56 2,639.46 5,135.85 Start 12 dls 9,390.00 6,529.61 2,858.32 5,241.89 3 9,460.00 6,538.23 2,927.20 5,250.35 4 9,610.00 6,550.92 3,072.57 5,282.33 5 9,860.00 6,569.67 3,317.48 5,309.78 6 10,110.00 6,585.12 3,562.61 5,337.27 7 10,210.00 6,587.99 3,658.70 5,364.14 8 10,360.00 6,586.93 3,808.07 5,366.36 9 10,590.00 6,583.59 4,034.71 5,388.83 10 10,850.00 6,580+28 4,290.91 5,406.12 Planned TD at 10850.00 512312013 4:30:03PM Page 5 COMPASS 2003.16 Build 69 ConocoPhillips ConocoPhillips (Alaska) Inc. -Ku p2 Kuparuk River Unit Kuparuk 3C Pad 3C-10 3C-10AL1-01 3C-10AL1-01_wp01 Travelling Cylinder Report 23 May, 2013 BAKER FIUGHES ConocoPhillips or its affiliates .ela. ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3C Pad Site Error: 0,00ft Reference Well: 3C-10 Well Error: 0.00ft Reference Wellbore 3C-10AL1-01 Reference Design: 3C-10AL1-01_wp01 Local Co-ordinate Reference: Well 3C-10 TVD Reference: 3C-10 @ 82.00ft (3C-10) MD Reference: 3C-10 @ 82.00ft (3C-10) North Reference: True Survey Calculation Method: Minimum Curvature Output errors are at 1.00 sigma Database: EDM Alaska Prod v16 Offset TVD Reference: Offset Datum Reference 3C-10AL1-01_wp01 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00ft Error Model: ISCWSA Depth Range: 9,050.00 to 10,850.00ft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,281.54ft Error Surface: Elliptical Conic Survey Tool Program Date 5/23/2013 From To (ft) (ft) Survey (Wellbore) Tool Name Description 100.00 8,600.00 3C-10 (3C-10) GCT-MS Schlumberger GCT multishot 8,600.00 8,730.00 3C-10A_wp01 (3C-10A) MWD MWD - Standard 8,730.00 9,050.00 3C-10AL1_wp02 (3C-10AL1) MWD MWD - Standard 9,050.00 10,850.00 3C-10AL1-01_wp01 (3C-10AL1-01) MWD MWD- Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (') (11) 10,850.00 6,662.28 2 3/8" 2-3/8 3 Summary Site Name Offset Well - Wellbore - Design Kuparuk 3C Pad 3C-08 - 3C-08 - 3C-08 3C-09 - 3C-091-1-01 - 3C-09L1-01_wp02 3C-10 - 3C-10AL1 - 3C-10AL1_wp02 Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Depth Depth Distance (ft) from Plan (ft) (ft) (ft) (ft) Out of range Out of range 9,074.96 9,075.00 1.00 0.71 0.35 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 512312013 3:23:39PM Page 2 of 5 COMPASS 2003.16 Build 69 ConocoPhillips Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3C Pad Site Error: 0.00ft Reference Well: 3C-10 Well Error: 0.00ft Reference Wellbore 3C-10AL1-01 Reference Design: 3C-10AL1-01_wp01 ConocoPhillips or its affiliates Travelling Cylinder Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 3C-10 3C-10 @ 82.00ft (3C-10) 3C-10 @ 82.00ft (3C-10) True Minimum Curvature 1.00 sigma EDM Alaska Prod v16 Offset Datum rGFAI BAKER HUGNES Offset Design Kuparuk 3C Pad - 3C-10 - 3C-10AL1 - 3C-10AL1_wp02 Offset Site Error: 0.00 ft Survey Program: 100-GCT-MS, 8600-MWD, 8730-MWD Rule Assigned: Major Risk Offset Well Error. 0.00 ft Reference Offset Semi Major Axis Measured Vertical Measured Vertical Reference Offset Toolface+ Offset Wellbore Centre Casing- Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/S +E/-W Hole Size Centre Distance Deviation 9,074.96 6,559.87 9,075.00 6,559.23 0.06 0.05 -10.33 2,590.84 5,093.44 0.22 1.00 0.71 0.35 Pass- Major Risk, CC, ES, SF 9,099.68 6,561.77 9,100.00 6,559.23 0.08 0.10 -9.96 2,611.39 5,107.68 0.22 3.99 1.17 2.93 Pass - Major Risk 9,123.94 6,564.86 9,125.00 6,559.23 0.11 0.15 -9.71 2,632.65 5,120.81 0.22 8.94 1.65 7.47 Pass - Major Risk !, 9,147.91 6,569.02 9,150.00 6,559.23 0.15 0.20 -10.47 2,654.58 5,132.82 0.22 15.69 2.15 13.79 Pass - Major Risk 9,172.72 6,573.59 9,175.00 6,559.57 0.18 0.25 -13.70 2,677.05 5,143.76 0.22 22.57 2.65 20.24 Pass - Major Risk 9,198.01 6,578.24 9,200.00 6,560.69 0.22 0.30 -17.60 2,699.95 5,153.73 0.22 28.75 3.16 25.98 Pass - Major Risk 9,223.75 6,582.93 9,225.00 6,562.56 0.27 0.36 -21.88 2,723.20 5,162.70 0.22 34.23 3.67 30.99 Pass - Major Risk 9,249.92 6,587.66 9,250.00 6,565.20 0.32 0.41 -26.48 2,746.76 5,170.65 0.22 39.01 4.20 35.28 Pass - Major Risk 9,276.46 6,592.40 9,275.00 6,568.59 0.37 0.47 -31.38 2,770.54 5,177.55 0.22 43.08 4.72 38.84 Pass - Major Risk 9,303.34 6,597.12 9,300.00 6,572.72 0.42 0.52 -36.60 2,794.49 5,183.39 0.22 46.46 5.24 41.71 Pass - Major Risk 9,330.51 6,601.79 9,325.00 6,576.95 0.48 0.58 -41.53 2,818.66 5,188.17 0.22 49.54 5.76 44.27 Pass - Major Risk 9,357.93 6,606.39 9,350.00 6,580.46 0.54 0.65 -45.51 2,843A3 5,191.88 0.22 52.69 6.27 46.93 Pass - Major Risk 9,385.57 6,610.90 9,375.00 6,583.25 0.60 0.71 -48.69 2,867.83 5,194.53 0.22 55.85 6.76 49.63 Pass - Major Risk 9,413.71 6,615.11 9,400.00 6,585.32 0.67 0.77 -51.15 2,892.69 5,196.11 0.22 58.95 7.26 52.28 Pass - Major Risk 9,442.14 6,618.53 9,425.00 6,586.65 0.73 0.84 -53.58 2,917.65 5,196.61 0.22 61.89 7.74 54.79 Pass - Major Risk 9,468.35 6,620.95 9,450.00 6,587.24 0.79 0.90 -54.15 2,942.63 5,196.03 0.22 64.81 8.31 57.22 Pass - Major Risk 9,490.46 6,622.85 9,475.00 6,587.42 0.84 0.95 -51.66 2,967.62 5,195.43 0.22 68.45 8.95 60.31 Pass - Major Risk 9,512.46 6,624.73 9,500.00 6,587.60 0.88 0.99 -49.12 2,992.61 5,196.14 0.22 71.97 9.54 63.32 Pass - Major Risk 9,534.36 6,626.60 9,525.00 6,587.78 0.93 1.03 -46.53 3,017.52 5,198.16 0.22 75.35 10.13 66.20 Pass - Major Risk 9,556.16 6,628.45 9,550.00 6,587.96 0.97 1.08 -43.91 3,042.30 5,201.48 0.22 78.59 10.72 68.93 Pass - Major Risk 9,577.88 6,630.27 9,575.00 6,588.14 1.03 1.13 -41.25 3,066.86 5,206.09 0.22 81.67 11.30 71.51 Pass - Major Risk 9,600.00 6,632.10 9,600.00 6,588.31 1.08 1.19 -38.51 3,091.16 5,211.98 0.22 84.61 11.90 73.93 Pass - Major Risk 9,625.09 6,634.15 9,625.00 6,588.58 1.15 1.26 -39.07 3,115.41 5,218.02 0.22 88.01 12.52 76.78 Pass - Major Risk 9,654.66 6,636.54 9,650.00 6,589.08 1.25 1.35 -42.52 3,139.95 5,222.80 0.22 91.33 13.20 79.48 Pass - Major Risk 9,684.50 6,638.92 9,675.00 6,589.81 1.34 1.44 -46.03 3,164.68 5,226.30 0.22 94.29 13.87 81.82 Pass - Major Risk 9,714.58 6,641.27 9,700.00 6,590.76 1.44 1.53 -49.62 3,189.56 5,228.52 0.22 96.87 14.50 83.80 Pass - Major Risk 9,744.88 6,643.57 9,725.00 6,591.93 1.55 1.62 -53.27 3,214.52 5,229.46 0.22 99.06 15.11 85.41 Pass - Major Risk 9,775.38 6,645.83 9,750.00 6,593.31 1.65 1.71 -56.99 3,239.47 5,229.11 0.22 100.86 15.70 86.64 Pass - Major Risk 9,806.03 6,648.02 9,775.00 6,594.91 1.76 1.81 -60.77 3,264.36 5,227.46 0.22 102.25 16.26 87.48 Pass - Major Risk 9,836.82 6,650.14 9,800.00 6,596.72 1.87 1.90 -64.60 3,289.12 5,224.53 0.22 103.22 16.79 87.91 Pass - Major Risk 9,865.24 6,652.01 9,825.00 6,598.73 1.97 2.00 -67.07 3,313.68 5,220.32 0.22 103.85 17.42 87.93 Pass - Major Risk 9,886.14 6,653.36 9,850.00 6,600.95 2.04 2.10 -65.71 3,337.97 5,214.85 0.22 105.77 18.40 88.94 Pass - Major Risk 9,906.80 6,654.69 9,875.00 6,603.26 2.10 2.18 -64.71 3,362.22 5,209.26 0.22 108.73 19.30 91.02 Pass - Major Risk 9,927.35 6,656.01 9,900.00 6,605.58 2.16 2.25 -63.59 3,386.74 5,204.94 0.22 111.55 20.13 93.02 Pass - Major Risk 9,950.00 6,657.46 9,925.00 6,607.88 2.24 2.33 -62.12 3,411.44 5,201.92 0.22 114.24 21.00 94.84 Pass - Major Risk 9,968.17 6,658.61 9,950.00 6,610.16 2.30 2.41 -61.04 3,436.28 5,200.20 0.22 116.70 21.75 96.57 Pass - Major Risk 9,988.46 6,659.88 9,975.00 6,612.42 2.37 2.49 -59.63 3,461.17 5,199.78 0.22 119.01 22.53 98.10 Pass - Major Risk 10,008.68 6,661.14 10,000.00 6,614.64 2.45 2.58 -58.14 3,486.05 5,200.68 0.22 121.12 23.29 99.46 Pass - Major Risk 10,028.83 6,662.37 10,025.00 6,616.83 2.52 2.67 -56.57 3,510.85 5,202.88 0.22 123.04 24.02 100.63 Pass - Major Risk 10,050.00 6,663.64 10,050.00 6,618.98 2.61 2.77 -54.80 3,535.51 5,206.38 0.22 124.75 24.76 101.60 Pass - Major Risk 10,068.97 6,664.77 10,075.00 6,621.07 2.68 2.86 -53.22 3,559.96 5,211.17 0.22 126.23 25.43 102.41 Pass - Major Risk 10,088.97 6,665.93 10,100.00 6,623.11 2.77 2.96 -51.45 3,584.12 5,217.24 0.22 127.50 26.10 103.00 Pass - Major Risk 10,108.85 6,667.06 10,125.00 6,624.87 2.85 3.08 -49.70 3,608.26 5,223.50 0.22 129.66 26.77 104.48 Pass - Major Risk 10,142.16 6,668.64 10,150.00 6,626.08 3.00 3.21 -53.61 3,632.69 5,228.61 0.22 132.87 27.92 106.57 Pass - Major Risk 10,176.69 6,669.65 10,175.00 6,626.73 3.17 3.35 -57.85 3,657.37 5,232.57 0.22 135.61 29.06 108.21 Pass - Major Risk 10,211.54 6,669.99 10,200.00 6,626.81 3.35 3.49 -62.09 3,682.21 5,235.36 0.22 137.84 30.14 109.40 Pass - Major Risk 10,246.20 6,669.96 10,225.00 6,626.58 3.54 3.63 -66.39 3,707.16 5,236.91 0.22 139.57 31.12 110.17 Pass - Major Risk 10,281.05 6,669.79 10,250.00 6,626.32 3.72 3.77 -70.69 3,732.15 5,237.16 0.22 140.80 32.01 110.52 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 5/23/2013 3:23:39PM Page 3 of 5 COMPASS 2003.16 Build 69 ,,.,t f•�. p is � (. k j i ConocoPhillips or its affiliates WE.. ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3C Pad Site Error: 0.00ft Reference Well: 3C-10 Well Error: 0.00ft Reference Wellbore 3C-10AL1-01 Reference Design: 3C-10AL1-01_wp01 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 3C-10 3C-10 @ 82.00ft (3C-10) 3C-10 @ 82.00ft (3C-10) True Minimum Curvature 1,00 sigma EDM Alaska Prod v16 Offset Datum Offset Design Kuparuk 3C Pad - 3C-10 - 3C-10AL1 - 3C-10AL1_wp02 Offset Site Error: 0.00ft survey Program: 100-GCT-MS, 8600-MWD, 8730-MWD Rule Assigned: Major Risk Offset Well Error: 0.00A Reference Offset Send Major Axis Measured Vertical Measured Vertical Reference Offset Toolface+ Offset Wellbore Centre Casing - Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/S +Ei-W Hole Size Centre Distance Deviation (ff) (ff) (ff) (ff) 00 (ff) I°I Ift) (it) (ff) (ff) (ff) (ff) 10,316.03 6,669.49 10,275.00 6,626.05 3,91 3.92 -74.99 3,757.12 5,236.09 0.22 141.51 32.82 110.43 Pass - Major Risk 10,351.08 6,669.06 10,300.00 6,625.75 4.11 4.07 -79.27 3,782.01 5,233.72 0.22 141.70 33.52 109.91 Pass - Major Risk 10,375.00 6,668.71 10,325.00 6,625.44 4,23 4.20 -78.46 3,806.88 5,231.22 0.22 141.02 34.58 108.22 Pass - Major Risk 10,394.04 6,668.42 10,350.00 6,625.13 4.32 4.32 -76.04 3,831.84 5,230.02 0.22 139.97 35.64 106.18 Pass - Major Risk 10,413.58 6,668.12 10,375.00 6,624.82 4.42 4.44 -73.51 3,856.84 5,230.12 0.22 138.66 36.69 103.87 Pass - Major Risk 10,433.16 6,667.83 10,400.00 6,624.51 4.52 4.57 -70.94 3,881.79 5,231.53 0.22 137.07 37.71 101.34 Pass - Major Risk 10,452.77 6,667.54 10,425.00 6,624.21 4.62 4.69 -68.32 3,906.64 5,234.25 0.22 135.22 38.69 98.57 Pass - Major Risk 10,475.00 6,667.21 10,450.00 6,623.91 4.73 4.82 -65.33 3,931.31 5,238.26 0.22 133.14 39.71 95.55 Pass - Major Risk 10,492.16 6,666.96 10,475.00 6,623.62 4.82 4.95 -62.92 3,955.74 5,243.56 0.22 130.74 40.54 92.39 Pass - Major Risk 10,511.95 6,666.67 10,500.00 6,623.33 4.93 5.08 -60.13 3,979.85 5,250.13 0.22 128.12 41.40 88.99 Pass - Major Risk 10,531.80 6,666.39 10,525.00 6,623.05 5.04 5.21 -57.28 4,003.60 5,257.93 0,22 125.27 42.21 85.41 Pass - Major Risk 10,550.00 6,666.14 10,550.00 6,622.78 5,14 5.37 -54.84 4,027.46 5,265.39 0.22 123.76 43.02 83.16 Pass - Major Risk 10,571.93 6,665.83 10,575.00 6,622.50 5.26 5.53 -52.32 4,051.67 5,271.59 0.22 124.43 43.87 82.98 Pass - Major Risk 10,593.01 6,665.55 10,600.00 6,622.22 5.38 5.70 -51.00 4,076.18 5,276.52 0.22 127.30 44.73 84.97 Pass - Major Risk 10,626.17 6,665.11 10,625.00 6,621.95 5.58 5.87 -55.62 4,100.91 5,280.15 0.22 130.87 46.23 87.03 Pass - Major Risk 10,659.75 6,664.66 10,650.00 6,621.68 5.79 6.04 -60.20 4,125.80 5,282.49 0.22 134.04 47.63 88.79 Pass - Major Risk 10,693.70 6,664.21 10,675.00 6,621.41 6.02 6.22 -64.75 4,150.77 5,283.52 0.22 136.78 48.91 90.25 Pass - Major Risk 10,728.00 6,663.77 10,700.00 6,621.15 6.25 6.40 -69.25 4,175.76 5,283.24 0.22 139.08 50.05 91.40 Pass - Major Risk 10,762.57 6,663.33 10,725.00 6,620.90 6.48 6.58 -73.72 4,200.71 5,281.66 0.22 140.92 51.03 92.23 Pass - Major Risk 10,797.36 6,662.90 10,750.00 6,620.65 6.73 6.76 -78.15 4,225.54 5,278.77 0.22 142.27 51.86 92.73 Pass - Major Risk 10,832.30 6,662.48 10,775.00 6,620.40 6.97 6.94 -82.52 4,250.18 5,274.58 0.22 143.14 52.50 92.91 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 5/23/2013 3:23:39PM Page 4 of COMPASS 2003.16 Build 69 ConocoPhillips or its affiliates wel.. ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3C Pad Site Error: 0.00ft Reference Well: 3C-10 Well Error: 0.00ft Reference Wellbore 3C-10AL1-01 Reference Design: 3C-10AL1-01_wp01 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset ND Reference: Well 3C-10 3C-10 @ 82.00ft (3C-10) 3C-10 @ 82.O0ft (3C-10) True Minimum Curvature 1.00 sigma EDM Alaska Prod v16 Offset Datum Reference Depths are relative to 3C-10 @ 82.00ft (3C-10) Coordinates are relative to: 3C-10 Offset Depths are relative to Offset Datum Coordinate System is US State Plane 1927, Alaska Zone 4 Central Meridian is 150' 0' 0.000 W ° Grid Convergence at Surface is: 0.22' Ladder Plot 140 105 0 `m Q N in 2 70 a U 0 m C a)U 35 0 0 2000 4000 6000 8000 10000 12000 Measured Depth LEGEND —� 3G10,3C-10AL1,3C-10AL1 vp02V0 I � I I I I - I I I I I I I I -- I I I I I I I I I I I I I I I I t I I I I I I 1 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I t 1 I I I I I I I 1 I I I I I I CC -Min centre to center distance or covergent point, SF -min separation factor, ES -min ellipse separation 5/23/2013 3:23:39PM Page 5 of 5 COMPASS 2003.16 Build 69 ( M G tA »� »S 0 c 0 !§ /Ij #/(+) om/(- s !2» ,°g2gqm&GqqR » ,akgaG��Rgc6 § 'Umn2§KQ)§ mgm�gq%@mgmn R§§§§§§§§§§§ - a%Rm `&@§QQ))m-G- ®2§2®m2§§§§/ e;e§&mG@q§/ _,_ _. mmn@ m&Oi 9a o I § Bettis, Patricia K (DOA) From: Starck, Kai [Kai.Starck@conocophillips.com] Sent: Monday, June 10, 2013 1:24 PM To: Bettis, Patricia K (DOA) Subject: RE: Permit to Drill Application: KRU 3C-10A, KRU 3C-10AL1, and KRU 3C-10AL1-01 Attachments: 3C-10A PTD Summary.docx My apologies for that, please find attached the corrected application summary. Kai Starck ConocoPhillips AK, Inc. 907-263-4093 office 907-240-0691 cell From: Bettis, Patricia K (DOA)[mailto:patricia.bettis@alaska.gov] Sent: Friday, June 07, 2013 11:56 AM To: Starck, Kai Subject: [EXTERNAL]FW: Permit to Drill Application: KRU 3C-10A, KRU 3C-10AL1, and KRU 3C-10AL1-01 From: Bettis, Patricia K (DOA) Sent: Friday, June 07, 2013 11:54 AM To: 'Kai.Starch@conocophillips.com' Subject: Permit to Drill Application: KRU 3C-10A, KRU 3C-10AL1, and KRU 3C-10AL1-01 Good morning Kai, I started review of the application. Under Section 8. Drilling Fluids Program, page 3 of the Application for Permit to Drill Document, for both window milling operations and drilling operations, the mud weight is not provided. Would you please send me via e-mail a revised page 3 with the correct mud weight for both window milling and drilling operations. This omission is the same, also, for the KRU 3C-10AL1 and KRU 3C-10AL1-01 applications. Thank you very much, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If 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.bettis@alaska.gov. Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Friday, June 07, 2013 11:56 AM To: 'Kai.Starck@conocophillips.com' Subject: FW: Permit to Drill Application: KRU 3C-10A, KRU 3C-10AL1, and KRU 3C-1OAL1-01 From: Bettis, Patricia K (DOA) Sent: Friday, June 07, 2013 11:54 AM To: 'Kai.Starch@conocophillips.com' Subject: Permit to Drill Application: KRU 3C-10A, KRU 3C-10AL1, and KRU 3C-10AL1-01 Good morning Kai, I started review of the application. Under Section 8. Drilling Fluids Program, page 3 of the Application for Permit to Drill Document, for both window milling operations and drilling operations, the mud weight is not provided. Would you please send me via e-mail a revised page 3 with the correct mud weight for both window milling and drilling operations. This omission is the same, also, for the KRU 3C-10AL1 and KRU 3C-10AL1-01 applications. Thank you very much, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If 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.bettis@alaska.gov. TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: 0213 O $S� Development Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: I� rn�l< ��UE� POOL: �� K►i/EJ' !A .J(A 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. a/ 30%3 , API No. 50- Q 29 - 913 s7, - 0/ - DO. (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. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce / inject is contingent upon issuance of a Spacing Exception conservation order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no Dry Ditch Sample greater 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 Commission 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 5/2013 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 PTD#:2130850 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Well Name: KUPARUK RIV UNIT 3C-10AL1-01 Program DEV Well bore seg DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal Administration 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025634, Surf Loc; ADL0025629. Top Prod Intery & TD 3 Unique well name and number Yes KRU 3C-10AL1-01 4 Well located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order 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 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15-day wait Yes PKB 6/9/2013 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 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) 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 Yes 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 VLF 6/11/2013 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 6/11/2013 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Geologic Engineering Pub' Commissioner: Date: Commissioner: Date Co m i r Date Conductor set in 3C-10 Surface casing set in 3C-10 Surface casing set and fully cemented Productive interval will be completed with slotted liner Rig has steel tanks; all waste to approved disposal wells PTD 185-101, Sundry 313-153 Proximity analysis performed. Max formation pressure is 3050 psi(EMW 8.8 ppg); will drill w/ 9.5 ppg using MPD to maintain overbalance MPSP is 3264 psi; BOPs will be tested to 4000 psi H2S measures required. Wells on 3C-Pad are H2S-bearing. H2S measures required. Expected reservoir pressure is 9.5 ppg EMW; will be drilled using 9.5 ppg mud and managed pressure drilling drilling technique. Two wellbore volumes of 12.0 kill -weight mud will be available.