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Home My WebLink About217-036Carlisle, Samantha J (DOA) From: Loepp, Victoria T (DOA) Sent: Tuesday, April 04, 2017 8:15 AM To: Carlisle, Samantha J (DOA) Cc: Bettis, Patricia K (DOA) Subject: FW: Withdrawal of PTDs # 217-034 to 217-039 Sam, Please handle these PTD withdrawals. Patricia, FYI, change from laterals to plug for redrill. We should be seeing the new PTDs tomorrow - From: Callahan, Mike S [mailto:Mike.Callahan@conocophillips.com] Sent: Tuesday, April 04, 2017 7:26 AM To: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Subject: Withdrawal of PTDs # 217-034 to 217-039 Victoria, as we discussed on the phone, could you please withdraw the following PTD's for the 1C-23 CTD Project? Due to a change in plans, we will be resubmitting these as a plug for re -drill, along with a sundry to plug the motherbore. 217-034(1C-23L1) 217-035 (1C-23L1-01) 217-036 (1C-23L1-02) 217-037 (1C-231-1-03) 217-038 (1C-23L1-04) 217-039 (1C-231-1-05) Thanks, Mike Callahan CTD Engineer ConocoPhillips Alaska ATO 660 Office: (907) 263-4180 Cell: (907) 231-2176 THE STATE P I I I i F4010 WAMIS - GOVERNOR BILL WALKER James Ohlinger Staff CTD Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 1C-23L1-02 ConocoPhillips Alaska, Inc. Permit to Drill Number: 217-036 Surface Location: 1659' FNL, 1277' FWL, Sec. 12, T11N, R10E, UM Bottomhole Location: 4532' FNL, 2358' FEL, Sec. 5, T11N, RI IE, UM Dear Mr. Ohlinger: 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. 199-034, API No. 50-029- 22942-00-00. 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 P. Foerster Chair DATED this day of March, 2017. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 MAR 15 2017 0GCC 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp 1c. Specify if well is proposed for: Drill ❑ Lateral ❑v Stratigraphic Test ❑ Development - Oil FZI Service - Winj ❑ Single Zone e Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11. Well Name and Number: ConocoPhillips Alaska Inc Bond No. 5952180 kQIJ 1C-2311-02 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 15000' TVD6 6445' Kuparuk River Field / Kuparuk Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 1659' FNL, 1277' FWL, Sec 12, T11 N, R10E, UM ADL 28242 a,5 6q Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 226' FNL, 2736' FEL, Sec8, T11N, R11E, UM 2292 4/1/2017 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4532' FNL, 2358' FEL, Sec 5, T11 N, R11 E, UM 2560 2300' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 95 15. Distance to Nearest Well Open Surface: x- 562285 y- 5968580 Zone- 4 GL Elevation above MSL (ft): 55 to Same Pool: 2500' (1 C-22) 16. Deviated wells: Kickoff depth: 13660 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 99 degrees Downhole: 3750 • Surface: 3105 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2-3/8" 4.7# L-80 ST-L 2600' 13800' 6474' 15000' 6445' N/A 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 13975' 6718' N/A 13960' 6712' N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 115' 16" 9 cu yds High Early 121' 121' Surface 8894' 9-5/8" 1260 sx AS III, 345 sx Class G 8894' 4573' Intermediate 13960' 7" 300 sx Class G 13960' 6712' Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 13537'-13587' 6530'-6551' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Program ❑✓ Time v. Depth Plot ❑ Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements❑✓ 21. Verbal Approval: Commission Representative: Date 3 �/ % 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not Mike Callahan (263-4180) j%L(� be deviated from without prior written approval Contact Email mike.callahan(@cop.com Printed Name James Ohlinger Title Staff CTD Engineer Z' / 3��/% Signaturecl�7� Phone 265-1102 Date Commission Use Only Permit to Drill " W (0 API Number: 1 I Permit Approval 2S - ( -7 See cover letter for other Number: 50-'Ja - - Date: - 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: 50P tt5 -to 3 ✓r-G C) » �J Samples req'd: Yes Noi Mud log req'd: Yes[-] NoV rtr-:5 � I+tl "1V Lct 2r-7e rt.h 7-Cr t Z �L y�HZS measures: Yes No Directional svy req'd: Yes No❑ I'll,(/Lt r/ cl hC Z5 f0 a 6 /} f} C' ZS—, 0 J�ol cing 14ption req'd: Yes ❑ NoZJ Inclination -only svy req'd: Yes❑ No✓�,, /S yrq k-1-frd -F0 a I o l.V f hG %/ Ck-o f F po t n t fd %z n Post initial injection MIT req'd: Yes❑ Nc yDJul�fi �' loamy �t rJaYt�-F la�cra �- APPROVED BY Approved by. COMMISSIONER THE COMMISSION Date:3 - 2 - 1 PSIIJHI -�- v77- 31,2 311 7- Submit Form and Form 10-401 Revise 11/ o This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) Attachments in Duplicate 0 1 N A 4 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 March 15, 2017 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: [RECEIVED LIAR 15 2017 ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill six laterals out of the Kuparuk well 1C-23 well using the coiled tubing drilling rig, Nabors CDR3-AC. To account for geological uncertainties, ConocoPhillips requests a variance from the requirements of 20 AAC 25.015 to allow the actual kick-off point to be anywhere along the length of the parent lateral instead of being limited to 500' from the original point. The work is scheduled to begin April 1s', 2017. The objective will be to drill laterals KRU 1C-231_1 and 1C-231-1- 01 through 1C-231-1-05 targeting the Kuparuk C-sands. Attached to this application are the following documents: — 10-401 Applications for 1C-231_1 and 1C-231_1 -01 through 1C-231-1-05 — Detailed Summary of Operations — Directional Plans for 1C-231-1 and 1C-231_1 -01 through 1C-231-1-05 — Proposed CTD Schematic If you have any questions or require additional information, please contact me at 907-263-4180. Sincerely, /ice Mike Callahan ConocoPhillips Alaska Coiled Tubing Drilling Engineer Kuparuk Ci® Laterals IC-23L1, 1C-23L1-01, 1C-23L1-02, 1C-23L1-03, 1C-231-1-04, & 1C-23L1-05 Application for Permit to Drill Document 1. Well Name and Classification......................................................................................................... 2 (Requirements of 20 AAC 25.005(t) 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 20AAC 25.005 (c)(3))..................................................................................,..................................I.............I............ 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 of20AAC25.005c 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 Liner Running............................................ 6 14. Disposal of Drilling Mud and Cuttings...........................................................................................6 (Requirements of 20 AAC 25.005(c)(14)) ................ ................. 6 15. Directional Plans for Intentionally Deviated Wells........................................................................7 (Requirements of 20 AAC 25.050 b............................................................................................................................ 7 16. Attachments.................................................................................................................................... 7 Attachment 1: Directional Plans for IC-23L1, 1C-231-1-01 through 1C-23L1-05 laterals ............................................... 7 Attachment 2: Current Well Schematic for 1 C-23........................................................................................................... 7 Attachment 3: Proposed Well Schematic for 1C-23L1, 1C-231-1-01 through 1C-23L1-05 laterals ................................. 7 Page 1 of 7 December 5, 2016 PTD Application: 1C-23L1, 1C-23L1-01, 1C-2311-1-02, 1C-23L1-03, 1C-23L1-04, & 1C-23L1-05 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) The proposed laterals described in this document are 1C-231-1, 1C-231-1-01, 1C-231-1-02, 1C-231-1-03, 1C- 231-1-04, 1C-231-1-05. All laterals will be classified as "Development -Oil' wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the C sand package in the Kuparuk reservoir. See attached 10-401 forms for surface and subsurface coordinates of each of the 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 CDR3-AC. BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. Using the maximum formation pressure in the area of 3750 psi in 1 C-14A (i.e. 11.7 ppg EMW), the maximum potential surface pressure in 1C-23, assuming a gas gradient of 0.1 psi/ft, would be 3,105 psi. See the "Drilling Hazards Information and Reservoir Pressure' section for more details. — The annular preventer will be tested to 250 psi and 2,500 psi. 4. Drilling Hazards Information and Reservoir Pressure (Requirements of 20 AAC 25.005 (c)(4)) Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005 (c)(4)(a)) The formation pressure in KRU 1 C-23 was measured to be 3055 psi (9.0 ppg EMW) on 1/10/2015. The maximum downhole pressure in the 1 C-23 vicinity is the 1 C-14A at 3750 psi or 11.7 ppg EMW. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) No specific gas zones will be drilled; gas injection has been performed in this area, so there is a chance of encountering gas while drilling the 1C-23 laterals. If significant gas is detected in the returns the contaminated mud can be diverted to a storage tank away from the rig. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) The major expected risk of hole problems in the 1 C-23 laterals will be differential sticking. The relaxation method will be used to free differentially stuck pipe, as shale stability is not a major concern in the C Sand. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 1C-23 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity test is not required. Page 2 of 7 March 14, 2017 PTD Application: 1C-23L1, 1C-23L1-01, 1C-231_1-02, 1C-231-1-03, 1C-23L1-04, & 1C-23L1-05 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Lateral Name Liner Top Liner Btm Liner Top Liner Btm Liner Details MD MD TVDSS TVDSS 1C-23L1 14,000' 16,600' 6,469' 6,501' 2W, 4.7#, L-80, ST-L slotted liner; aluminum billet on top 2W, 4.7#, L-80, ST-L slotted liner; 1C-231-1-01 13,660' 16,475' 6,476' 6,517' aluminum billet on top 2%", 4.7#, L-80, ST-L slotted liner; 1C-23L1-02 13,800' 15,000' 6,474' 6,445' aluminum billet on to 1C-231_1-03 13,640' 14,925' 6,474' 6,504' 2'/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 2%", 4.7#, L-80, ST-L slotted liner; 1C-23L1-04 13,690' 16,600' 6,477' 6,501' aluminum billet on to 1C-23L1-05 13,503' 15,000' 6,515' 6,449' 2W, 4.7#, L-80, ST-L slotted liner; deployment sleeve on top Existing Casing/Liner Information Category OD Weight (ppf) Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.5 H-40 Welded 0' 121' 0' 121' 1640 670 Surface 10-3/4" 40 L-80 BTC 0' 8894' 0' 4573' 5910 3090 Production 7" 26 L-80 BTC 0' 13960 0' 6712' 7240 5410 Tubin 3-112" 9.3 L-80 EUE 0' 13504' 0' 6516' 7180 7400 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) Nabors CDR3-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a diverter system is not required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System A diagram of the Nabors CDR3-AC mud system is on file with the Commission. Description of Drilling Fluid System - Window milling operations: Water based Power-Vis milling fluid (8.6 ppg) - Drilling operations: Water based Flo -Pro drilling mud (8.6 ppg). This mud weight will not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. - Completion operations: BHA's will be deployed using standard pressure deployments and the well will be loaded with 11.8 ppg sodium bromide completion fluid in order to provide formation over -balance and maintain wellbore stability while running completions. Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 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". Page 3 of 7 March 14, 2017 PTD Application: 1C-23L1, 1C-23L1-01, 1C-23L1-02, 1C-23L1-03, 1C-23L1-04, & 1C-23L1-05 In the 1C-23 laterals we will use MPD to maintain formation overbalance. We will target an EMW at the window of whatever formation pressure we see while drilling, with 11.7 ppg as the maximum expected. 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. IF t th 1 C 23 Window NTRAZ MD 6540'TVDI Usin MPD I uboul G a e Pumps On (1.5 bpm) Pumps Off C-sand Formation Pressure (9.0 ppg) 3055 psi 3055 psi Mud Hydrostatic 8.6 2925 psi 2925 psi Annular friction i.e. ECD, 0.080 sift 1085 psi 0 psi Mud + ECD Combined 4010 psi 2925 psi (no choke pressure) overbalanced —955psi) underbalanced —130 psL Tar et BHP at Window (11.7 ) 3980 psi 3980 psi Choke Pressure Required to Maintain 0 psi 1055 psi Target BH,P 9. Abnormally Pressured Formation Information (Requirements of 20AAC 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 a 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. 13. Proposed Drilling Program (Requirements of 20 AA 25.005(c)(13)) Summary of Operations Background Producer 1 C-23 is located in the southeast portion of the Kuparuk River field. This well produces only from the C-Sands, as the A -Sands are below the oil water contact in this area. This project seeks to improve the C-Sand throughput and ultimate recovery in the area via six CTD laterals out of producer 1C-23. These laterals will be drilling in two directions — to the southwest and northeast — and will be stacked in the 0/C4-Sands. Nabors CDR3 will set a whipstock and mill a 2.80" window off the whipstock at 13,590'. Three laterals will be drilled to the southwest and three to the northeast of the parent well with the laterals targeting the Kuparuk C sands. All laterals will be completed with 2-3/8" slotted liner from TD with the last lateral liner top located inside the 3-1/2" tubing tail. Page 4 of 7 March 14, 2017 PTD Application: 1C-23L1, 1C-23L1-01, 1C-23L1-02, 1C-23L1-03, 1C-23L1-04, & 1C-23L1-05 Pre-CTD Work 1. Mill D nipple out to 2.80". 2. Run caliper across whipstock setting area on e-line. 3. Prep site for Nabors CDR3-AC and set BPV. Rig Work 1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. IC-23L1 Lateral (C3/C4 sand - Southwest) a. RIH and set a 3-1/2" x 7" high expansion whipstock at 13590' MD. b. Mill 2.80" window at 13590' MD. c. Drill 3" bi-center lateral to TD of 16600' MD. d. Run 2%" slotted liner with an aluminum billet from TD up to 14000' MD. 3. 1C-23L1-01 Lateral (C3/C4 sand- Southwest) a. Kick off of the aluminum billet at 14000' MD. b. Drill 3" bi-center lateral to TD of 16475' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 13660' MD. 4. 1C-23L1-02 Lateral (C3/C4 sand -North) a. Kickoff of the aluminum billet at 13660' MD. b. Drill 3" bi-center lateral to TD of 15000' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 13800' MD. 5. lC-23L1-03 Lateral (C3/C4 sand- North) a. Kickoff of the aluminum billet at 13800' MD. b. Drill 3" bi-center lateral to TD of 14925' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 13640' MD. 6. 1C-23L1-01 Lateral (C3/C4 sand- Southwest) a. Kick off of the aluminum billet at 13640' MD. b. Drill 3" bi-center lateral to TD of 16600' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 13690' MD. 7. 1 C-23L 1-01 Lateral (C3/C4 sand -North) a. Kickoff of the aluminum billet at 13690' MD. b. Drill 3" bi-center lateral to TD of 15000' MD. c. Run 2%" slotted liner with a deployment sleeve up into the tubing tail at 13500' MD. 8. Freeze protect, set BPV, ND BOPE, and RDMO Nabors CDR3-AC. Post -Rig Work 1. Pull BPV. 2. Obtain SBHP. 3. Install GLV's . 4. Return to production. Page 5 of 7 March 14, 2017 PTD Application: 1C-2311_1, 1C-2311_1-01, 1C-23U-02, 1C-2311_1-03, 1C-2311-1-04, & 1C-23L1-05 Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slick -line lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slick -line. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment, the steps listed above are observed, only in reverse. Liner Running — 1C-23 CTD laterals will be displaced to an overbalance completion fluid (as detailed in Section 8 "Drilling Fluids Program") prior to running liner. — While running 2'/" slotted liner, a joint of 2%" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2'/" rams will provide secondary well control while running 2%" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). Page 6 of 7 March 14, 2017 PTD Application: 1C-2311-1, 1C-23L1-01, 1C-231-1-02, 1C-23L1-03, 1C-23L1-04, & 1C-23L1-05 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) — The Applicant is the only affected owner. — Please see Attachment 1: Directional Plans — Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. — MWD directional, resistivity, and gamma ray will be run over the entire open hole section. — Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 1 C-23L1 2480' 1 C-23L1-01 2500' 1 C-23L1-02 2300' 1C-23L1-03 2300' 1C-23L1-04 2480' 1 C-23L1-05 2500' — Distance to Nearest Well within Pool Lateral Name Distance Well 1 C-2311-1 1727' 1 C-27 1 C-23L1-01 1715' 1 C-27 1 C-23L1-02 2500' 1 C-22 1 C-23L1-03 2500' 1 C-22 1 C-23L1-04 1727' 1 C-27 1 C-23L1-05 2500' 1 C-22 16. Attachments Attachment 1: Directional Plans for 1 C-23L 1, 1 C-23L 1-01 through 1 C-23L 1-05 laterals. Attachment 2: Current Well Schematic for 1 C-23 Attachment 3: Proposed Well Schematic for 1 C-23L1, 1 C-23L 1-01 through 1 C-23L 1-05 laterals. Page 7 of 7 March 14, 2017 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kupl Kuparuk River Unit Kuparuk I Pad 1 C-23 1 C-23L1-02 Plan: 1 C-23L1-02_wp01 Standard Planning Report 08 March, 2017 WE i ' A"-- I BAKER HUGHES ConocoPhillips Database: EDM Alaska NSK Sandbox Company: ConocoPhillips (Alaska) Inc. -Kupl Project: Kuparuk River Unit Site: Kuparuk 1 C Pad Well: 1 C-23 Wellbore: 1 C-23L1-02 Design: 1 C-23L1-02_wp01 ConocoPhillips Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 1 C-23 Mean Sea Level 1C-23 @ 95.20usft 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 FSk2 BAKER HUGHES Site Kuparuk 1 C Pad Site Position: Northing: 5,968,522.46 usft Latitude: 70° 19' 28.285 N From: Map Easting: 562,372.05 usft Longitude: 149° 29' 39.293 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.48 ° Well 1 C-23 Well Position +N/-S 0.00 usft Northing: 5,968,579.61 usft Latitude: 70' 19' 28.855 N +E/-W 0.00 usft Easting: 562,285.45 usft Longitude: 149' 29' 41.807 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 55.20 usft Wellbore 1C-231-1-02 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (1 (°) (nT) BGGM2016 6/1/2017 17.65 80.95 57,544 Design 1C-23L1-02_wp01 Audit Notes: Version: Phase: PLAN Tie On Depth: 13,660.00 Vertical Section: Depth From (TVD) +Nl-S +E/-W Direction (usft) (usft) (usft) (°) -60.30 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 (usft) (°) (°) (usft) (usft) (usft) (°/100ft) (°/100ft) (°/100ft) (°) Target 13,660.00 86.23 83.50 6,476.22 1,404.05 11,318.79 0.00 0.00 0.00 0.00 13,730.00 91.51 74.42 6,477.61 1,417.45 11,387.38 15.00 7.54 -12.98 300.00 13,800.00 95.06 64.52 6.473.59 1,441.91 11,452.74 15.00 5.07 -14.14 290.00 13,900.00 89.83 78.59 6,469.31 1,473.41 11,547.25 15.00 -5.23 14.08 110.00 14,000.00 89.83 63.59 6,469.61 1,505.72 11,641.59 15.00 0.01 -15.00 270.00 14,100.00 89.32 48.60 6,470.36 1,561.34 11,724.35 15.00 -0.51 -14.99 268.00 14,200.00 88.57 33.62 6,472.21 1,636.45 11,789.90 15.00 -0.75 -14.98 267.00 14,350.00 90.21 11.18 6,473.84 1,774.24 11,846.68 15.00 1.09 -14.96 274.00 14,525.00 89.74 344.93 6,473.93 1,947.62 11.840.78 15.00 -0.26 -15.00 269.00 14,605.00 87.68 356.75 6,475.73 2.026.43 11,828.07 15.00 -2.58 14.78 100.00 14.685.00 89.80 8.57 6,477.50 2,106.18 11,831.78 15.00 2.65 14.77 80.00 14,835.00 97.33 347.31 6,468.08 2,254.83 11,826.55 15.00 5.02 -14.17 290.00 15,000.00 98.75 12.27 6,444.64 2,416.86 11,825.90 15.00 0.86 15.13 85.00 31612017 3:26:21PM Page 2 COMPASS 5000.1 Build 74 `r ConocoPhillips rigs ConocoPhillips Planning Report BAKERHUGHS Database: EDM Alaska NSK Sandbox Local Co-ordinate Reference: Well 1C-23 Company: ConocoPhillips (Alaska) Inc. -Kupl TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 1 C-23 @ 95.20usft Site: Kuparuk 1C Pad North Reference: True Well: 1 C-23 Survey Calculation Method: Minimum Curvature Wellbore: 1 C-23L1-02 Design: 1C-23L1-02_wp01 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing (usft) Easting (usft) (usft) (_) (I (usft) (usft) (usft) (usft) (°/100ft) V) 13,660.00 86.23 83.50 6,476.22 1,404.05 11,318.79 1,404.05 0.00 0.00 5,970,077.42 573,591.11 TIP/KOP 13,700.00 89.24 78.31 6,477.80 1,410.37 11,358.24 1,410.37 15.00 -60.00 5,970,084.07 573,630.50 13,730.00 91.51 74.42 6,477.61 1,417.45 11,387.38 1,417.45 15.00 -59.79 5,970.091.38 573,659.59 Start 15 dls 13,800.00 95.06 64.52 6,473.59 1,441.91 11,452.74 1,441.91 15.00 -70.00 5,970,116.39 573,724.73 3 13,900.00 89.83 78.59 6,469.31 1,473.41 11,547.25 1,473.41 15.00 110.00 5,970,148.66 573,818.97 4 14,000.00 89.83 63.59 6,469.61 1,505.72 11,641.59 1,505.72 15.00 -90.00 5,970,181.75 573,913.03 5 14,100.00 89.32 48.60 6,470.36 1,561.34 11,724.35 1,561.34 15.00 -92.00 5,970,238.05 573,995.31 6 14,200.00 88.57 33.62 6,472.21 1,636.45 11,789.90 1,636.45 15.00 -93.00 5,970,313.70 574,D60.23 7 14,300.00 89.65 18.65 6,473.78 1,725.96 11.833.82 1,725.96 15.00 -86.00 5,970,403.56 574,103.40 14,350.00 90.21 11.18 6,473.84 1,774.24 11,846.68 1,774.24 15.00 -85.77 5,970,451.94 574,115.86 8 14,400.00 90.07 3.68 6,473.72 1,823.79 11,853.14 1,823.79 15.00 -91.00 5,970,501.53 574,121.91 14,500.00 89.81 348.68 6.473.83 1,923.28 11,846.49 1,923.28 15.00 -91.02 5,970,600.96 574,114.44 14,525.00 89.74 344.93 6,473.93 1,947.62 11,840.78 1,947.62 15.00 -91.00 5,970,625.24 574,108.53 9 14,600.00 87.81 356.01 6,475.54 2,021.44 11,828.39 2,021.44 15.00 100.00 5,970,698.96 574,095.52 14,605.00 87.68 356.75 6,475.73 2,026.43 11,828.07 2.026.43 15.00 99.76 5.970.703.94 574,095.17 10 14,685.00 89.80 8.57 6,477.50 2,106.18 11,831.78 2,106.18 15.00 80.00 5,970,783.71 574.098.22 11 14,700.00 90.57 6.46 6,477.46 2,121.05 11,833.75 2,121.05 15.00 -70.01 5,970,898.14 05 574,098.18 14,800.00 95.63 352.31 6,472.03 2,220.61 11,832.70 2,220.61 15.00 70.01 5,970,898.14 574,098.18 14,835.00 97.33 347.31 6,468.08 2,254.83 11,826.55 2,254.83 15.00 -70.78 5,970,932.30 574,091.75 12 14,900.00 98.07 357.12 6,459.35 2,318.56 11,817.84 2,318.56 15.00 85.00 5,970,995.96 574,082.51 15,000.00 98.75 12.27 6,444.64 2,416.86 11,825.90 2,416.86 15.00 86.32 5,971,094.30 574,089.75 Planned TD at 15000.00 31812017 3:26:21 PM Page 3 COMPASS 5000.1 Build 74 ConocoPhillips Database: EDM Alaska NSK Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup1 Project: Kuparuk River Unit Site: Kuparuk 1C Pad Well: 1 C-23 Wel I bore: 1 C-23L1-02 Design: 1 C-23L1-02_wp01 Targets ConocoPhillips Planning Report Local Co-ordinate Reference: Well 1C-23 TVD Reference: Mean Sea Level MD Reference: 1C-23 @ 95.20usft North Reference: True Survey Calculation Method: Minimum Curvature Target Name hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Shape (1) (1) (usft) (usft) (usft) (usft) 1C-23 CTD Polygon Nor 0.00 0.00 0.00 -8,440.061,151,319.22 5,969,696.00 plan misses target center by 1139530.70usft at 14400.00usft MD (6473.72 TVD, 1823.79 N, 11853.14 E) Polygon Point 1 0.00 0.00 0.00 5,969,696.00 Point 2 0.00 111.25 455.98 5,969,811.02 Point 3 0.00 240.63 655.07 5,969,942.04 Point 0.00 546.33 696.60 5,970,248.04 Points 0.00 1.452.57 681.07 5,971,154.03 Point 0.00 1,529.94 394.67 5,971,229.02 Point 7 0.00 743.66 416.19 5,970,443.02 Point 0.00 493.05 365.11 5.970,192.02 Point 9 0.00 317.22 -21.39 5,970,013.00 Point 10 0.00 0.00 0.00 5,969,696.00 1C-231-1-02_T04 0.00 0.00 6,445.00 -7,298.941,151,924.77 5,970,842.00 plan misses target center by 1140108.13usft at 14400.O0usft MD (6473.72 TVD, 1823.79 N, 11853.14 E) Point 1C-23 CTD Polygon We. 0.00 0.00 0.00 -8,711.911,151,537.99 5,969,426.00 plan misses target center by 1139751.94usft at 14400.00usft MD (6473.72 TVD, 1823.79 N, 11853.14 E) Polygon Point 1 0.00 0.00 0.00 5,969,426.00 Point2 0.00 264.48-1,872.06 5,969,674.91 Point 0.00 -48.02-1,938.65 5,969,361.90 Point4 0.00 -220.69-1,131.97 5,969,195.94 Point 5 0.00 -324.43-559.75 5,969,096.97 Point 6 0.00 -472.58-179.92 5,968,951.99 Point 0.00 -472.68 75.11 5,968,954.00 Point 0.00 -291.77 331,64 5,969,137.02 Point 9 0.00 177.78 393.52 5,969,607.02 Point 10 0.00 487.38 83.03 5,969,914.01 Point 11 0.00 525.14-251.70 5,969,948.98 Point 12 0.00 309.00-237.48 5,969,732.99 Point 13 0.00 0.00 0.00 5,969,426.00 1C-231-1-02_T03 0.00 0.00 6,477.00 -7,606.031,151,931.22 5,970,535.00 plan misses target center by 1140117.08usft at 14400.00usft MD (6473.72 TVD, 1823.79 N, 11853.14 E) Point WE as BAKER Easting (usft) Latitude Longitude 1,713,525.00 1,713,525.00 1,713, 980.00 1,714,177.99 1,714,216.98 1,714,193.93 1,713,906.92 1,713, 934.96 1,713, 885.97 1,713, 500.98 1,713,525.00 1,714,121.00 1,713,746.00 1,713,746.00 1,711,871.99 1,711,808.00 1,712,616.01 1,713,189.02 1,713, 570.03 1,713, 825.02 1, 714, 080.02 1,714,137.99 1,713,824.97 1,713,489.97 1,713, 505.99 1,713,746.00 1,714,130.00 70' 3' 44.604 N 140° 14' 52.763 W J 70' 3' 54.780 N 140" 14' 30.571 W 70' 3' 41.641 N 140- 14' 47.725 W i 70" 3' 51.790 N 140' 14' 31.725 W 1C-231-1-02_T01 0.00 0.00 6,469.00-8,239.731,151,643.92 5,969,899.00 1,713,848.00 70' 3' 46.066 N 140' 14' 42.656 W plan misses target center by 1139635.21 usft at 14400.00usft MD (6473.72 TVD, 1823.79 N, 11853.14 E) Point 1C-23L1-02_T02 0.00 0.00 6,472.00-8,080.721,151,886.27 5,970,060.00 1,714,089.00 70' 3' 47.249 N 140° 14' 35.071 W plan misses target center by 1140076.16usft at 14400.00usft MD (6473.72 TVD, 1823.79 N, 11853.14 E) - Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 15,000.00 6,444.64 2 3/8" 2.375 3.000 31812017 3:26.21 PM Page 4 COMPASS 5000.1 Build 74 ConocoPhillips Has ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska NSK Sandbox Local Co-ordinate Reference: Well 1C-23 Company: ConocoPhillips (Alaska) Inc. -Kup1 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 1 C-23 @ 95.20usft Site: Kuparuk 1C Pad North Reference: True Well: 1C-23 Survey Calculation Method: Minimum Curvature Wellbore: 1 C-23L1-02 Design: 1C-231-1-02_wp01 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 13,660.00 6,476.22 1,404.05 11,318.79 TIP/KOP 13,730.00 6,477.61 1.417.45 11,387.38 Start 15 dls 13,800.00 6,473.59 1,441.91 11,452.74 3 13,900.00 6,469.31 1,473.41 11,547.25 4 14,000.00 6,469.61 1,505.72 11,641.59 5 14,100.00 6,470.36 1,561.34 11,724.35 6 14,200.00 6,472.21 1,636.45 11,789.90 7 14,350.00 6,473.84 1,774.24 11,846.68 8 14,525.00 6,473+93 1,947.62 11,840.78 9 14,605.00 6.475.73 2,026.43 11,828.07 10 14,685.00 6,477.50 2,106.18 11,831.78 11 14,835.00 6,468.08 2,254.83 11,826.55 12 15,000.00 6.444.64 2,416.86 11,825.90 Planned TD at 15000.00 31812017 3:26:21PM Page 5 COMPASS 5000.1 Build 74 ✓ Baker Hughes INTEQ relF1. i ConocoPhillps Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kupl Project: Kuparuk River Unit Reference Site: Kuparuk 1 C Pad Site Error: 0.00 usft Reference Well: 1C-23 Well Error: 0.00 usft Reference Wellbore 1C-231-1-02 Reference Design: 1 C-23L1-02_wp01 Local Co-ordinate Reference: Well 1 C-23 TVD Reference: 1C-23 @ 95.20usft MD Reference: 1 C-23 @ 95.20usft North Reference: True Survey Calculation Method: Minimum Curvature Output errors are at 1.00 sigma Database: OAKEDMP2 Offset TVD Reference: Offset Datum teference 1C-231_1-02_wp01 filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference iterpolation Method: MD Interval 25.00usft Error Model: ISCWSA )epth Range: 13,660.00 to 15,000.00usft Scan Method: Tray. Cylinder North tesults Limited by: Maximum center -center distance of 1,696.51 usft Error Surface: Elliptical Conic Survey Tool Program Date 3/7/2017 From To (usft) (usft) Survey (Wellbore) Tool Name Description 159.17 1,748.98 IC-23PB1 (1C-23PB1) MWD MWD- Standard 1,832.00 13,544.46 1C-23 (1C-23) MWD MWD - Standard 13,544.46 13,660.00 1C-231_1_wp04 (1C-23L1) MWD MWD- Standard 13,660.00 15.000.00 1C-231-1-02_wp01 (lC-23L1-02) MWD MWD- Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 8,894.00 4,572.09 9 5/8" 9-5/8 12-1/4 15,000.00 6,539.84 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 1C Pad 1 C-20 - 1 C-20 - 1 C-20 Out of range 1 C-20 - 1 C-20 - Plan: 1 C-20 (wpl0) Out of range 1C-20 - 1C-20PB1 - 1C-20PB1 Out of range 1 C-23 - 1 C-23 - 1 C-23 13,671.03 13,675.00 15.88 13.87 13.07 Pass - Major Risk 1 C-23 - 1 C-231-1 - 1C-23L1_wp04 13,674.98 13,675.00 0.64 0.61 0.17 Pass - Minor 1/10 1C-23-1C-23L1-01-1C-23L1-01_wp01 13.674.98 13,675.00 0.64 0.61 0.17 Pass -Minor l/10 IC-23 - 1C-231-1-03 - 1C-231-1-03_wp01 13,800.00 13,800.00 0.00 0.33 -0.22 FAIL- Minor 1/10 1C-23-1C-231-1-04-1C-23L1-04_wp00 13,674.98 13,675-00 0.64 0.93 -0.05 FAIL - Minor l/10 1C-23-1C-231-1-05-1C-23L1-05_wp00 13.674.98 13,675.00 0.64 0.93 -0.05 FAIL - Minor l/10 1 C-28 - 1 C-28 - 1 C-28 Out of range 1 C-28 - 1 C-28L1 - 1 C-281_1 Out of range 1 C-28 - 1 C-28PB1 - 1 C-28PB1 Out of range Offset Design Kuparuk 1 C Pad - 1 C-23 - 1 C-23 - 1 C-23 Offset Site Error: 0.00 usft Survey Program: 159-MWD, 1832-MWD Rule Assigned: Major Risk Offset Well Error: 0.00 usft Reference Offset Semi Major Axis Measured Vertical Measured Vertical Reference Offset Toolface+ Offset Wellbore Centre Casing - Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/S +E/-W Hole Size Centre Distance Deviation (usft) (usft) (usft) (usft) (usft) (usft) (') (usft) (usft) (") (usft) (usft) (usft) 13,671+03 6,572.07 13 675.00 6,587.93 1.15 1.88 -98.40 1,405.20 11,328.92 2-11/16 15.88 13.87 13.07 Pass - Major Risk, CC, ES, SF 13,693.32 6,572.89 13,700.00 6,598.63 1.33 2.24 -103.66 1,407.71 11,351.37 2-11116 25.78 15.48 22.29 Pass - Major Risk 13,714.89 6,573.06 13,725.00 6,609.33 1.51 2.60 -109.27 1,410.21 11,373+83 2-11/16 36.45 17.03 32.10 Pass- Major Risk 13,735.71 6,572.64 13,750.00 6,620.03 1.68 2.96 -114.85 1,412.67 11,396.29 2-11116 47.93 18.49 4262 Pass - Major Risk 13,755.95 6,571.83 13,775.00 6,630.76 1.85 3.32 -120.50 1,415.08 11,418.74 2-11116 60.16 19.88 53.82 Pass -Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 31712017 3:49:31PM Page 2 COMPASS 5000.1 Build 74 o �&z U ° o E 3�si c5� v� K IYKKa z �Zv= 0 J 0 c) J o N no C7 N •- U a7 �r tQ 02 w = c 0 3a w m ¢ 1= o 0 m � J a w E4 2. p8a m 2�me om El a CL 0 a 0 0 �a c 0.d � ry vs U o% oKV I N U N U NOI O `LG � U N N U U 0 a N U N N N F 0 0 0 0 0 (ui/3jsn OSZ) (+)q-pok(-)u1noS 13000 12750 12500 12250 12000 1750 150( jj 125( v 100( 075( u 050( i 025( a 0000 750 500 250 )00 750 U a� J t p) 04 0 0 0 m w 0 F— mO!�2 C c� Q F— U) M t t n c fl l w m r r r 0- M CO U to tc)r Nt u: IR MOO 0000 O�Otm� (�MtN t0 U) t I`rM sflr cO� f� cO c0 tc0 N Z Ort� 0cO M1� tNOtnr �� r (r �� O N t � _0 Lc) ate- at- N N N N CN N U o 0 0 0 0 0 0 0 0 0 0 0 0 N _IN LLo000oao aoio6ot0 (� LL Clm��mcD I-W OepM M N N N N N N N ° m o 0 0 0 0 0 0 0 0 0 0 0 0 o N O O O O o 0 0 0 0 0 0 0 0 I� O to ta7 tf') to t0 tO to !2 to t2 tc) t2 m to O wa tiM toO ISM INN tL7 M mcO I- Ol-tnm O1LO IJ.IN�Nn �Mc ONco Uf - Ct . 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Annotation Depth (RKB) End Date Last Tag: SLM 13,555.0 1/102015 Annotation Rev Reason: GLV C/O, PULL PLUG & CATCHER, TAG Last Mod By End hipshkf Oate 1/172015 HANGER; 30.0 CONDUCTOR; 34.0-121.0 NIPPLE; 486.2 GAS UFT; 3,537.1 GAS LIFT, 6.29SA GAS LIFE; 6.214.2 SURFACE; 33.3A,894.4- GAS LIFT; 9,9220 GAS UFT: 11,474.7 GAS LIFT; 13,349.6 NIPPLE; 13,394.8 SEAL ASSY: 13,436.0 PACKER; 13,436.9 NIPPLE; 13,4923 SOS; 13,503.3 IPERF: 13,537.0-13,587.0 PRODUCTION; 3B.CM3,950.0 a. asmg rags Casing Description OD(in) CONDUCTOR 16 ID (in) 15.062 Top(ftKB) 34.0 Set Oepth(RKB) Set 121.0 Depth(IVD)... 121.0 WttLen(I... 62.58 Grade HAO Top Thread WELDED Casing Deseriptcn OD SURFACE (in) 95/8 ID (in) 8.835 Top (RKB) 33.3 Set Depth (ftl(B) Set 8'894.4 Depth IWO)- 4.573.0 Wt/Len (1... 40.00 Grade L-80 1BTC-MOD Top Thread BTC Casing Description OD PRODUCTION (in) 7 ID (In) 6.276 Top (RK8) 38.0 Set Depth (RKB) Set 13,960.0 Depth (TVD)... 6,711.6 Will -en (1... 26.00 Grade L-80 Top Thread Tubing Strings Tubing Description String Ma... ID (in) Top (RKB) Set Depth M Set Depth (TVD) (... Wt (II" Grade Top Connection TUBING 312 2.992 30.0 13,5042 6,515.8 9.30 L-80 EUESROMOD Completion Details Top IRKS) Top I TVD) (RKB) Top Incl M Item Des Co. Nominal ID On) 30.0 30.0 0.12 HANGER FMC GEN IV 5M HANGER 3.500 4862 485.8 5.80 NIPPLE CAMCO DS NIPPLE 2.875 13,394.8 6,469.7 65.28 NIPPLE CAMCO W NIPPLE 2.812 13,436.0 6,487.0 65.11 SEALASSY KBH-22 ANCHOR SEAL ASSEMBLY 2.992 13,436.9 6,487.4 65.11 PACKER BAKER SB-3 PERMANENT PACKER 2937 13,4923 6,510.8 64.95 NIPPLE CAMCO D NIPPLE w/ NO GO PROFILE 2.750 13,503.3 6,515.4 64.93 SOS BAKER SHEAR OUT SUB 3.015 Perforations & Slats Top (ft)(B) Bt. (RKB) Top (TVD) St. (RKB) (ND) (RKB) Zane (shotsR Date Shot Oens t) Type Com 13,537.0 13,587.0 6,529.7 6,551.0 C-4, 1C-23 6/6/1999 1 4.0 IPERF 2.5" =/- HSD, 180 phasing, 90 deg orient Mandrel Inserts St at, N Top (RKB) Top(TVD) (ftKB) Make Model OD (in) Sere Valve Type latch Type PortSize (in) TRO Run (psi) Run Date Cam 3.537.1 2,3332 CAMCO KBMM 1 GAS LIFT GLV BK 0.156 1,250.0 1/92015 2 6,295.4 3.495.2 CAMCO KBMM 1 GAS LIFT GLV BK 0.188 1,281.0 1/92015 3 8,2142 4,291.7 CAMCO KBMM 1 GAS LIFT OV BK 0.250 0.0 1/82014 4 9,922.0 4,999.2 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 6162012 5 11,474.7 5,647.1 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 6162012 6 13,349.fi 6,450.9 CAMCO MMM 1 12 GAS LIFT DMY RK 0.000 0.0 12/52014 Notes: General & Safety End Date Annotation 8/132010 NOTE: View Schematic w/ Alaska Schematic9.0 N co 0) ❑ � ❑ ❑ N o U M M C Lf) M Cl)(O < M co m i0 �❑ M ❑ O toF- � U �M m m E N -0 �_ E _ o C a _ N a)p N N •� 00 Q m Y O 2 � CA .._. (13 N N =O V L C CV W m Y In rn c f0 _N m o in cl m E 0 00 J O c- O N N CV a r M U E� U E is J:M CA m C m a) m m E a w U m U a YcA mL a • = CV CV N N C' N C Y _5C •U v ❑ c) Cl) CD Cl) m m ❑ M Q 0 b ❑m Quo o zr) o2m oCL2 p 30mm oMCD vo a r 0�0 3o Jr n oor po o, O o N - J aO 3�C C) N� y Jp-, V y U D C p` O N J to On O 0 U J N < F J V N U O C co N U 4) J< O V N�y II 11 II 11 'I II 1 i l 11 11 11 1/ I I 1 1 I' 11 11 1 Y 1 11 11 11 11 11 ,1 '1 II 1 ,. 11 11 II II it , I i 11 � , I 11 11 11 11 II 11 '1 '1 1 1 I 11 '1 Bmf � wlA �1 N 00 O m m o (30 o L C M CA L In a r r In C) O_ i N .M- _ O N M O CO N 00 Go co � �? ao m rn TRANSMITTAL LETTER CHECKLIST WELL NAME: KR 1, I C. - a3 41 - Q Z PTD: o x /Development Service _ Exploratory — Stratigraphic Test _ Non -Conventional FIELD: TrW` &W, POOL: 1� < %� iV E.d' Rlvi<'r Q� Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER / / MULTI LATERAL The permit is for a new wellbore segment of existing well Permit No. - d 3 � , API No. (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals throug 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#:2170360 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Well Name: KUPARUK RIV UNIT 1C-231-1-02 Program DEV Well bore seg d DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal Administration 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025649, Surf Loc; ADL0028242, Top Prod Intery & TD. 3 Unique well name and number Yes KRU 1C-231-1-02 4 Well located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order No. 432D. 5 Well located proper distance from drilling unit boundary Yes CO 432D contains no spacing restrictions with respect to drilling unit boundaries. 6 Well located proper distance from other wells Yes CO 432D has no interwell spacing restrictions. 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes Wellbore will be more than 500' from an external property line where ownership or landownership changes. 10 Operator has appropriate bond in force Yes Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval Yes PKB 3/17/2017 13 Can permit be approved before 15-day wait Yes 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 18 Conductor string provided NA Engineering 19 Surface casing protects all known USDWs NA 20 CMT vol adequate to circulate on conductor & surf csg NA 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons No 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes VTL 3/21/2017 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 112S 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 3/17/2017 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Conductor set in KRU 1C-23 Surface casing set in KRU 1C-23 Surface casing set and fully cemented Productive interval will be completed with slotted liner Rig has steel tanks; all waste to approved disposal wells Anti -collision analysis complet; no major risk failures Max formation pressure is 3750 psig(11.7 ppg EMW); will drill w/ 8.6 ppg EMW and maintain overbal w/ MPD MPSP is 3105 psig; will test BOPs to 3500 psig 112S measures required Wells on 1C-Pad are H2S-bearing. 112S measures required. Max potential reservoir pressure is 11.7 ppg EMW; will be drilled using 8.6 ppg mud and MPD technique. Onshore development lateral to be drilled. Geologic Engineering Public Commissioner: Date: Commissioner: Date C mmissioner Date