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Home My WebLink About217-149Winston, Hugh E (CED) From: Winston, Hugh E (CED) Sent: Wednesday, November 6, 2019 2:15 PM To: Kai.Starck@conocophillips.com Cc: Loepp, Victoria T (CED); Boyer, David L (CED); Guhl, Meredith D (CED) Subject: KRU 2G-151-1-03 Permit Expired Hi Kai, The Permit to drill for well KRU 2G-151-1-03 which was issued to ConocoPhillips Alaska on November 2"d, 2017, has expired under Regulation 20 AAC 25.005 (R). The permit has been marked expired in the AOGCC database. Please let me know if you have any questions. Huey Winston Statistical Technician Alaska Oil and Gas Conservation Commission huyh.wingtgn@alaska.gov 907-793-1241 THE STATE V I I I 44651 W401 GOVERNOR BILL WALKER Kai Starch CTD Director ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2G-15L1-03 ConocoPhillips Alaska, Inc. Permit to Drill Number: 217-149 Surface Location: 183' FNL, 88' FEL, Sec. 6, T10N, R9E, UM Bottomhole Location: 3815' FNL, 591' FEL, Sec. 6, T1ON, R9E, UM Dear Mr. Starch: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907,276.7542 www.00gcc.olaska.gov Enclosed is the approved application for permit to drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 184-131, API No. 50-029- 21162-00-00. 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, Hollis S. French Chair DATED this Z day of November, 2017. STATE OF ALASKA AL A OIL AND GAS CONSERVATION COMMA DN PERMIT TO DRILL 20 AAC 25.005 RECEIVED OCT 2 4 2017 1 a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. fy I 's sed for: Drill ElLateral, ❑� Stratigraphic Test ❑ Development - Oil ❑✓ • Service - Winj [I 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 0 • Single Well ❑ 11. Well Name and Number: ConocoPhillips Alaska Inc Bond No. 5952180 KRU 2G-1511-03 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 9500' TVD: 6025' Kuparuk River Pool / 4a. Location of Well (Governmental Section): 7. Property Designation: Kuparuk River Oil Pool Surface: 183' FNL, 88' FEL, Sec 6, T10N, R9E, UM ADL 25667 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1559' FNL, 1050' FEL, Sec 6, T1 ON, R9E, UM LONS 82-180 11/3/2017 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 3815' FNL, 591' FEL, Sec 6, T10N, R9E, UM 2501 6820' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 140'• Distance to Nearest Well Open Surface: x- 508610 Y- 5943405 Zone- 4 , GL / BF Elevation above MSL (ft): 105' 115. to Same Pool: 537' (2G-13) 16. Deviated wells: Kickoff depth: 7100 feet 17. Maximum Potential Pressures in prig (see 20 AAC 25.035) Maximum Hole Angle: 94 degrees Downhole: 4379 • Surface: 3768, 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) 3" 2-3/8" 4.7# L-80 ST-L 2842' 6658' 5967' 9500' 6025' Slotted 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): 6997' 6346' N/A 6900' 6277' N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 70' 16" 202 sx Cold Set II 105' 105' Surface 2693' 9-5/8" 735 sx Permafrost E & 370 sx Permafrost C 2727' 2726' Production 6950' 7" 340 sx Class G 6983' 6336' Perforation Depth MD (ft): 6566' - 6580' Perforation Depth TVD (ft): 6044' - 6054' 6658' - 6728' 6107' - 6156' Hydraulic Fracture planned? Yes❑ No ❑� P Sketch 20. Attachments: Property Plat ❑ lling Program e D e v. Depth Analysis Shallow duirementsB✓ e✓ DivertOer Sketch Sieabed Report Drilling I ngeFluid P ogram 20 AAC 25 050 regot 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: William Long Authorized Name: Kai Starck Contact Email: William. R.Lon COP.com Authorized Title: CTD Director Contact Phone: 263-4372 Authorized Signature: � � Date:� �^ " Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number:du 1 r 50- — I b� "6 —Q� Date: 2 l requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methan , gas hydrates, or gas contained in shales: Other: QO P tv 4 5G� P� G Samples req'd: Yes ❑ No [� Mud log req'd: Yes ❑ No x /1 V[a ✓ rC V2 k) 1—Yy� T lJS t to 2 5� 12 5 �zS measures: Yes [► No,❑/ Directional svy req'd: Yes [/ No ❑ I7 `j I �► G G fQ c lq tC.25' .0 y S(Spacing exception req'd: Yes El No L>J Inclination -only svy req'd: Yes ❑ No V' �/a r cr t{d tj a j � o I� fh z (C� O p D IN t f0 t- Post initial injection MIT req'd: Yes ❑ No ❑" I S a" a� p e m t of t o kl �h P a re-'l f 14 �t va 1. kjQQ�'APPROVED BY 11 } \ -9 Approved by: COMMISSIONER THE COMMISSION Date: 10-401 Revi d / 1 W is is valid for 21jhl h Submit Form and roval 20 AAC 25.005(g) \�orm permit p per Attachments in Duplicate �� ikb f"I ) U/ Z ;-1i % ConocoPhilli s p Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 23, 2017 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill four laterals out of the newly worked over KRU 2G-15 (PTD# 184-131) 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 early November 2017. The objective will be to drill four laterals KRU 2G-15L1, 2G-151_1-01, 2G-151_1-02, and 2G-151_1-03 targeting the Kuparuk A -sands. Attached to this application are the following documents: — Permit to Drill Application Forms (10-401) for2G-15L1, 2G-151_1-01, 2G-15L1-02, and 2G-151_1-03 — Detailed Summary of Operations — Directional Plans for2G-15L1, 2G-151_1-01, 2G-151_1-02, and 2G-151_1-03 — Proposed CTD Schematic If you have any questions or require additional information, please contact me at 907-263-4372. Sincerely, William R. Long Coiled Tubing Drilling Engineer ConocoPhillips Alaska Kuparuk CTD Laterals 2G-151-1, 2G-15L.1-01, 2G-151-1-02, & 2G-151-1-03 Application for Permit to Drill Document 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(o and 20 AAC 25.005(b))................................................................................................................... 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2)).................................................................................................................................................. 2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 2 (Requirements of 20 AAC 25.005(c)(5))..................................................................................................................................................2 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7)).................................................................................................................................................. 3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9)).................................................................................................................................................. 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4 11. Seabed Condition Analysis............................................................................................................ 4 (Requirements of 20 AAC 25.005(c)(11))..............................................................................................................................................-4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005(c)(12)).............................................. .......... -.--.... .................................... ......................................... 4 13. Proposed Drilling Program............................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................5 14. Disposal of Drilling Mud and Cuttings.......................................................................................... 6 (Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 6 15. Directional Plans for Intentionally Deviated Wells....................................................................... 6 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 6 16. Attachments.................................................................................................................................... 6 Attachment 1: Directional Plans for 2G-151-1, 2G-151-1-01, 2G-151-1-02, and 2G-151-1-03 laterals................................6 Attachment 2: Current Well Schematic for 2G-15...........................................................................................................6 Attachment 3: Proposed Well Schematic for 2G-151-1, 2G-151-1-01, 2G-151-1-02, and 2G-151-1-03 laterals.................6 Page 1 of 6 October 23, 2017 PTD Application: 2G-1511-1, 2G-,i5L1-01, 2G-1511-1-02, and 2G-15L1-03 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) The proposed laterals described in this document are 2G-151-1, 2G-151-1-01, 2G-15L1-02, and 2G-151-1-03. All laterals will be classified as "Development -Oil' wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 forms for surface and subsurface coordinates of the 2G-151-1, 2G-151-1-01, 2G-151-1-02, and 2G-15L1-03 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 4,500 psi. Using the maximum formation pressure in the area of 4,379 psi in 2G-12A (i.e. 13.9 ppg EMW), the maximum potential surface pressure in 2G-15, assuming a gas gradient of 0.1 psi/ft, would be 3,768 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 2G-15 was measured to be 3,786 psi (11.8 ppg EMW) on 10/17/2017. The maximum downhole pressure in the 2G-15 vicinity, is the 2G-12A at 4,379 psi (13.9 ppg EMW) from July 2017. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) The offset injection wells to 2G-15 have injected gas, so there is a chance of encountering free gas while drilling the 2G-15 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 2G-15 laterals will be shale instability across faults. Managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossings. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 2G-15 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 6 October 23, 2017 PTD Application: 2G-15L1, 2G-i5L1-01, 2G-151_1-02, and 2G-15L1-03 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 2G-15L1 7,200' 11,200' 6,019' 6,001' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 2G-151_1-01 6,950' 11,200' 6,019' 5,976' 2'/", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 2G-15L1-02 7,100' 9,500' 6,009' 6,047' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 21K-041_1-03 6,658' 9,500' 5,967' 6,025' 23/", 4.7#, L-80, ST-L slotted liner; deployment sleeve on to Existing Casing/Liner Information Category OD Weight Grade Connection Top MD Btm MD Top TVD Btm TVD Burst Collapse psi Conductor 16" 62.5 H-40 Welded 35' 105' 36' 105' 1,640 670 Surface 9-5/8" 36 J-55 BTC 34' 2,727' 34' 2,726' 3,520 2,020 Production 7" 26 J-55 BTC 33' 6,983' 33' 6,336' 4,980 4,320 Tubing 3-1/2" 9.3 L-80 EUE 32' 6,680' 32' 6,123' 10,160 10,540 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: Chloride -based FloVis mud (8.7 ppg) - Drilling operations: Chloride -based FloVis mud (8.7 ppg). This mud weight will not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. - Completion operations: The well will be loaded with 12.0 ppg NaBr completion fluid to provide formation over -balance and well bore stability while running completions. Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000 psi rated coiled tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". In the 2G-15 laterals we will target a constant BHP of 12.0 ppg EMW at the window. The constant BHP target will be adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if increased reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed for improved borehole stability. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Page 3 of 6 October 23, 2017 PTD Application: 2G-15L1, 2G-i5L1-01, 2G-15L1-02, and 2G-15L1-03 Pressure at the 2G-15 Window (6,663' MD, 6111' TVD) Usinq MPD Pumps On 1.5 b m Pumps Off A -sand Formation Pressure 11.8 3786 psi 3786 psi Mud Hydrostatic 8.7 2765 psi 2765 psi Annular friction i.e. ECD, 0.080 si/ft 533 psi 0 psi Mud + ECD Combined no chokepressure) 3298 psi underbalanced --488psi) 2765 psi underbalanced --1021psi) Target BHP at Window 12.0 3813 psi 3813 psi Choke Pressure Required to Maintain Target BHP 515 psi 1048 psi 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005(c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005(c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A - Application is for a land based well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well 2G-15 is a Kuparuk A -sand and C-sand producer equipped with 3-1/2" tubing and 7" production casing. A recent rig workover installed new 3-1/2" tubing, and a big tail pipe to facilitate CTD laterals. The laterals will target the A -sands to the north and south of the 2G-15 parent wellbore. The project will improve the ultimate recovery in the parent pattern as well as provide offtake from the patterns to the north and the south. Pre-CTD Work 1. Perform RWO to install new 3-1/2" tubing and big tail pipe. 2. RU Slickline: Perform a dummy whipstock drift. 3. RU E-line: Obtain jewelry log and set 3-1/2" x 4-1/2" whipstock at 6,663' MD. 4. Prep site for Nabors CDR3-AC. Rid Work 1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPS, test. 2G-15L1 Lateral (A4 sand - North) a. Mill 2.80" window at 6,663' MD. Page 4 of 6 October 23, 2017 PTD Application: 2G-15L1, 2G-i5L1-01, 2G-15L1-02, and 2G-15L1-03 b. Drill 3" bi-center lateral to TD of 11,200' MD. c. Run 2-3/8" slotted liner with an aluminum billet from TD up to 7,200' MD. 3. 2G-15L1-01 Lateral (A4 sand - North) a. Kick off the aluminum billet at 7,200' MD. b. Drill 3" bi-center lateral to TD of 11,200' MD. c. Run 2-3/8" slotted liner with an aluminum billet from TD up to 6,950' MD. 4. 2G-15L1-02 Lateral (A4 sand - South) a. Kick off the aluminum billet at 6,950' MD. b. Drill 3" bi-center lateral to TD of 9,500' MD. c. Run 2-3/8" slotted liner from TD up into the tubing tail at 7,100' MD. 5. 2G-15L1-03 Lateral (A4 sand - South) ✓ a. Kickoff the aluminum billet at 7,100' MD. b. Drill 3" bi-center lateral to TD of 9,500' MD. c. Run 2-3/8" slotted liner frorn TD up into the tubing tail at 6,658' MD. 6. Obtain SBHP, freeze protect, ND BOPE, and RDMO Nabors CDR3-AC. Post -Rid Work 1. Return to production. Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slick -line lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slickline. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA un-deployment, the steps listed above are observed, only in reverse. Liner Running — The 2G-15 laterals will be displaced to an overbalancing completion fluid prior to running liner. See "Drilling Fluids" section for more details. — 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 23/" rams will provide secondary well control while running 2%" liner. Page 5 of 6 October 23, 2017 PTD Application: 2G-1511-1, 2G-i5L1-01, 2G-15L1-02, and 2G-15L1-03 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 11 disposal well (1 R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) - The Applicant is the only affected owner. - Please see Attachment 1: Directional Plans - Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. - MWD directional, resistivity, and gamma ray will be run over the entire open hole section. - Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 2G-15L1 13,136' 2G-15L1-01 13,136' 2G-15L1-02 6,820' 2G-15L1-03 6,820' - Distance to Nearest Well within Pool Lateral Name Distance Well 2G-1511-1 303' 2G-02 2G-15L1-01 303' 2G-02 2G-15L1-02 537' 2G-13 2G-15L1-03 537' 2G-13 16. Attachments Attachment 1: Directional Plans for 2G-15L1, 2G-15L1-01, 2G-15L1-02, and 2G-15L1-03laterals. Attachment 2: Current Well Schematic for 2G-15 Attachment 3. Proposed Well Schematic for 2G-15L1, 2G-15L1-01, 2G-15L1-02, and 2G-15L1-03 laterals. Page 6 of 6 October 23, 2017 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2G Pad 2G-15 2G-15L1-03 Plan: 2G-15L1-03 wp03 Standard Planning Report 20 October, 2017 BEFL BA 0 GE company - ConocoPhillips BA_ j(ER ConocoPhillips Planning Report IGHES BAT GE company Database: EDT Alaska Sandbox Company: ConocoPhillips (Alaska) Inc -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2G Pad Well: 2G-15 Wellbore: 2G-1511-03 Design: 2G-15L1-03_wp03 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2G-15 Mean Sea Level 2G-15 @ 140.00usft (2G-15) 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 Site Kuparuk 2G Pad Site Position: Northing: 5,944,015.12 usft Latitude: 70° 15' 29.733 N From: Map Easting: 508,649.96usft Longitude: 149° 55' 48.314 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.07 ° all 2G-15 all Position +N/-S 0.00 usft Northing: 5,943,405.25 usft Latitude: 70° 15' 23.735 +E/-W 0.00 usft Easting: 508,609.95 usft Longitude: 149° 55' 49.499 isition Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 u: Wellbore 2G-15L1-03 ' Magnetics Model Name Sample Date Declination Dip Angie Field Strength (°) (°) (nT) BG G M 2017 11 /1 /2017 17.28 80.85 57,474 Design 2G-15L1-03_wp03 Audit Notes: Version: Phase: PLAN Tie On Depth: 7,100.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (I 0.00 0.00 0.00 180.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (°) (I (usft) (usft) (usft) (°1100ft) (°1100ft) (°/100ft) (°) Target 7,100.00 94.30 133.14 6,009.30 -1,376.13 -957.51 0.00 0.00 0.00 0.00 7,250.00 83.80 133.14 6,011.79 -1,478.54 -848.23 7.00 -7.00 0.00 180.00 7,325.00 83.83 138.42 6,019.87 -1,531.96 -796.24 7.00 0.03 7.04 90.00 7,500.00 90.02 149.01 6,029.28 -1,672.57 -693.06 7.00 3.54 6.05 60.00 7,700.00 92.43 162.80 6,024.99 -1,854.65 -611.62 7.00 1.20 6.90 80.00 7,900.00 92.12 176.81 6,017.02 -2,050.85 -576.35 7.00 -0.16 7.00 91.00 8,100.00 90.84 162.86 6,011.83 -2,247.15 -541.15 7.00 -0.64 -6.97 265.00 8,300.00 89.61 176.81 6,011.03 -2,443.52 -505.95 7.00 -0.62 6.97 95.00 8,550.00 84.01 193.42 6,025.03 -2,691.17 -528.02 7.00 -2.24 6.64 109.00 8,800.00 90.16 177.01 6,037.83 -2,938.85 -550.52 7.00 2.46 -6.57 290.00 8,975.00 91.21 164.80 6,035.73 -3,111.31 -522.92 7.00 0.60 -6.97 275.00 9,275.00 91.13 185.81 6,029.51 -3,408.57 -498.50 7.00 -0.03 7.00 90.00 9,500.00 91.09 170.05 6,025.12 -3,632.67 -490.40 7.00 -0.02 -7.00 270.00 1012012017 6:08.29PM Page 2 COMPASS 5000.14 Build 85 y.- ConocoPhillips BA_ I(ER ConocoPhillips Planning Report UGIHES GE cornpany Database: EDT Alaska Sandbox Local Co-ordinate Reference: Well 2G-15 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2G-15 @ 140.00usft (2G-15) Site: Kuparuk 2G Pad North Reference: True Well: 2G-15 Survey Calculation Method: Minimum Curvature Wellbore: 2G-151-1-03 Design: 2G-15L1-03_wp03 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (1) (1) (usft) (usft) (usft) (usft) (°/100ft) (1) (usft) (usft) 7,100.00 94.30 133.14 6,009.30 -1,376.13 -957.51 1,376.13 0.00 0.00 5,942,028.16 507,654.11 TIP/KOP 7,200.00 87.30 133.14 6,007.91 -1,444.46 -884.60 1,444.46 7.00 -180.00 5,941,959.92 507,727.09 7,250.00 83.80 133.14 6,011.79 -1,478.54 -848.23 1,478.54 7.00 -180.00 5,941,925.89 507,763.50 Start 7 dis 7,300.00 83.81 136.66 6,017.18 -1,513.62 -813.02 1,513.62 7.00 90.00 5,941,890.85 507,798.74 7,325.00 83.83 138.42 6,019.87 -1,531.96 -796.24 1,531.96 7.00 89.62 5,941,872.54 507,815.54 3 7,400.00 86.47 142.97 6,026.22 -1,589.77 -748.93 1,589.77 7.00 60.00 5,941,814.79 507,862.92 7,500.00 90.02 149.01 6,029.28 -1,672.57 -693.06 1,672.57 7.00 59.61 5,941,732.05 507,918.87 4 7,600.00 91.23 155.90 6,028.19 -1,761.18 -646.84 1,761.18 7.00 80.00 5,941,643.51 507,965.18 7,700.00 92.43 162.80 6,024.99 -1,854.65 -611.62 1,854.65 7.00 80.08 5,941,550.09 508,000.51 5 7,800.00 92.29 169.81 6,020.86 -1,951.66 -587.98 1,951.66 7.00 91.00 5,941.453.11 508,024.26 7,900.00 92.12 176.81 6,017.02 -2,050.85 -576.35 2,050.85 7.00 91.29 5,941,353.95 508,036.00 6 8,000.00 91.49 169.84 6,013.87 -2,150.06 -564.73 2,150.06 7.00 -95.00 5,941,254.77 508,047.73 8,100.00 90.84 162.86 6,011.83 -2,247.15 -541.15 2,247.15 7.00 -95.22 5,941,157.71 508,071.42 7 8,200.00 90.23 169.84 6,010.89 -2,344.26 -517.57 2,344.26 7.00 95.00 5,941,060.63 508,095.11 8,300.00 89.61 176.81 6,011.03 -2,443.52 -505.95 2,443.52 7.00 95.07 5,940,961.40 508,106.84 8 8,400.00 87.34 183.43 6,013.69 -2,543.42 -506.16 2,543.42 7.00 109.00 5,940,861.50 508,106.75 8,500.00 85.10 190.08 6,020.28 -2,642.45 -517.88 2,642.45 7.00 108.82 5,940,762.47 508,095.14 8,550.00 84.01 193.42 6,025.03 -2,691.17 -528.02 2,691.17 7.00 108.39 5,940,713.74 508,085.06 9 8,600.00 85.22 190.12 6,029.72 -2,739.90 -538.17 2,739.90 7.00 -70.00 5,940,665.01 508,074.96 8,700.00 87.67 183.55 6,035.93 -2,838.94 -550.04 2,838.94 7.00 -69.69 5,940,565.97 508,063.21 8,800.00 90.16 177.01 6,037.83 -2,938.85 -550.52 2,938.85 7.00 -69.28 5,940,466.06 508,062.84 10 8,900.00 90.77 170.03 6,037.02 -3,038.15 -539.25 3,038.15 7.00 -85.00 5,940,366.79 508,074.23 8,975.00 91.21 164.80 6,035.73 -3,111.31 -522.92 3,111.31 7.00 -85.06 5,940,293.65 508,090.64 11 9,000.00 91.21 166.55 6,035.20 -3,135.53 -516.73 3,135.53 7.00 90.00 5,940,269.44 508,096.85 9,100.00 91.20 173.55 6,033.09 -3,233.94 -499.48 3,233.94 7.00 90.04 5,940,171.06 508,114.22 9,200.00 91.17 180.56 6,031.02 -3,333.73 -494.34 3,333.73 7.00 90.18 5,940,071.29 508,119.47 9,275.00 91.13 185.81 6,029.51 -3,408.57 -498.50 3,408.57 7.00 90.33 5,939,996.45 508,115.39 12 9,300.00 91.13 184.06 6,029.02 -3,433.47 -500.65 3,433.47 7.00 -90.00 5,939,971.55 508,113.27 9,400.00 91.12 177.05 6,027.05 -3,533.39 -501.62 3,533.39 7.00 -90.03 5,939,871.65 508,112.42 9,500.00 91.09 170.05 6,025.12 -3,632.67 -490.40 3,632.67 7.00 -90.17 5,939,772.38 508,123.75 Planned TD at 9600.00 1012012017 6:08:29PM Page 3 COMPASS 5000.14 Build 85 ConocoPhillips ConocoPhillips Planning Report Database: EDT Alaska Sandbox Local Co-ordinate Reference: Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Project: Kuparuk River Unit MD Reference: Site: Kuparuk 2G Pad North Reference: Well: 2G-15 Survey Calculation Method: Wellbore: 2G-151-1-03 Design: 2G-15 L 1-03_wp03 Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Shape (1) (`) (usft) (usft) (usft) (usft) 213-151-1-03 T3.4 0.00 0.00 6,025.00 -5,239.241,139,533.66 5,939,469.00 plan misses target center by 1140025.20usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Point 2G-15 CTD Polygon Soi 0.00 0.00 0.00 -5.633.471,138,828.14 5,939,074.00 plan misses target center by 1139336.23usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Polygon Point 1 0.00 0.00 0.00 5,939,074.00 Point 2 0.00 -430.42 346.56 5,938,644.02 Point 3 0.00 -69.75 680.99 5,939,005.04 Point 4 0.00 402.16 806.52 5,939,477.04 Point 5 0.00 972.31 723.13 5,940,047.04 Point 0.00 1,291.22 835.49 5,940,366.05 Point 0.00 1,819.30 808.07 5,940,894.04 Point 8 0.00 2,249.18 961.55 5,941,324.05 Point 9 0.00 2,666.20 975.01 5,941,741.05 Point 10 0.00 3,819.14 1,143.29 5,942,894.06 Point 11 0.00 3,902.80 546.32 5,942,977.03 Point 12 0.00 2,388.90 308.64 5,941,463.01 Point 13 0.00 1,472.84 279.64 5,940,547.01 Point 14 0.00 1,110.91 182.23 5,940,185.01 Point 15 0.00 347.78 236.40 5,939,422.02 Point 16 0.00 0.00 0.00 5,939,074.00 2G-1 5L1 -03 T3.2 0.00 0.00 6,010.00 -3,996.091,139,508.08 5,940.712.00 plan misses target center by 1139998.54usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Point 2G-151-1-037T02 0.00 0.00 6,009.00 -3,961.331,138,847.06 5,940,746.00 plan misses target center by 1139337.50usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Point 2G-151-1-037T04 0.00 0.00 6,024.00 -5,241.491,138,881.60 5,939,466.00 plan misses target center by 1139373.13usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Point 2G-15L1_Fault1_M 0.00 0.00 0.00 -501.161,139,004.03 5,944,206.00 plan misses target center by 1139514.66usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Rectangle (sides W1.00 H2,000.00 D0.00) 2G-151-1-02 Polygon 0.00 0.00 0.00 -3,065.271,138,880.08 5,941,642.00 plan misses target center by 1139386.56usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Polygon Point 1 0.00 0.00 0.00 5,941,642.00 Point 2 0.00 444.65 361.52 5,942,087.02 Point 0.00 249.36 611.33 5,941,892.03 Point4 0.00 -236.96 860.83 5,941,406.05 Point 5 0.00 -723.12 958.31 5,940,920.05 Point 0.00 -1,306.13 915.67 5,940,337.05 Point 0.00 -1,737.25 984.20 5,939,906.05 Point 8 0.00 -2,279.29 969.61 5,939,364.05 Point 9 0.00 -2,361.61 344.46 5,939,281.02 Point 10 0.00 -1,736.60 387.14 5,939,906.02 Point 11 0.00 -1,444.51 332.46 5,940,198.02 Point 12 0.00 -986.52 387.96 5,940,656.02 Point 13 0.00 -541.36 277.44 5,941,101.01 Point 14 0.00 -222.25 208.78 5,941,420.01 Point 15 0.00 0.00 0.00 5,941,642.00 2G-151-1-03T3.3 0.00 0.00 6,039.00-4,494.141,139,516.51 5,940,214.00 - plan misses target center by 1140007.24usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E' BA <ER all I UGHES a GE company Well 2G-15 Mean Sea Level 2G-15 @ 140.00usft (2G-15) True Minimum Curvature Easting (usft) Latitude Longitude 1,648,035.00 70' 0' 31.010 N 140' 48' 6.828 W 1,647,330.00 70° 0' 28.216 N 140° 48' 28.540 W 1, 647, 330.00 1,647,677.02 1,648,011.00 1,648,135.98 1, 648, 051.95 1,648,163.93 1,648,135.91 1,648, 288.88 1,648,301.86 1,648,468.81 1,647,871.80 1,647,635.88 1,647,607.93 1, 647, 510.94 1, 647, 565.98 1, 647, 330.00 1, 648, 008.00 70' 0' 43.119 N 140° 48' 2.226 W 1,647,347.00 70' 0' 44.426 N 140° 48' 20.841 W 1,647,383.00 70' 0' 31.944 N 140° 48' 25.344 W 1,647,500.00 70' 1' 17.796 N 140° 48' 1.550 W 1,647,379,00 70' 0' 53.079 N 140° 48' 16.063 W 1,647,379.00 1,647,739.98 1,647,989.98 1,648,240.01 1,648,338.04 1,648,296.07 1,648,365.09 1,648,351.12 1,647,726.12 1,647,768.09 1,647,713.08 1,647,768.05 1,647,657.03 1,647,588.01 1,647,379.00 1,648,017.00 70' 0' 38.270 N 140' 48' 4.122 W I 10/20/2017 6:08:29PM Page 4 COMPASS 5000.14 Build 85 ConocoPhillips BAKER ConocoPhillips Planning Report UGHES a GE cornpany Database: EDT Alaska Sandbox Local Co-ordinate Reference: Well 2G-15 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2G-15 @ 140.00usft (2G-15) Site: Kuparuk 2G Pad North Reference: True Well: 2G-15 Survey Calculation Method: Minimum Curvature Wellbore: 2G-151-1-03 Design: 2G-15L1-03_wp03 - Point 2G-151-1-037T01 0.00 0.00 6,026.00 -3,272.161,138,761.83 5,941,435.00 1,647,261.00 70' 0' 51.243 N 140' 48' 20.307 W plan misses target center by 1139252.29usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Point 2G-15 CTD Polygon Nor 0.00 0.00 0.00 1,341.741,139,256.16 5,946,049.00 1,647,750.00 70° 1' 35.321 N 140° 47' 46.482 W plan misses target center by 1139773.34usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Polygon Point 0.00 0.00 0.00 5,946,049.00 1,647,750.00 Point 0.00 -28.69 625.03 5.946,021.03 1,648,375.00 Point 3 0.00 -750.58 458.23 5,945,299.02 1,648,209.04 Point4 0.00 -1,736.46 262.13 5,944,313.01 1,648,014.09 Points 0.00 -2,292.49 233.52 5,943,757.01 1,647,986.12 Point 0.00 -2,792.48 177.97 5,943,257.00 1,647,931.14 Point 0.00 -3,195.58 232.53 5,942,854.01 1,647,986.16 Point 8 0.00 -3,792.60 204.88 5,942,257.02 1,647,959.19 Point 9 0.00 -4,320.31 -115.73 5,941,728.99 1,647,639.22 Point 10 0.00 -4,347.72 -657.81 5,941,700.97 1,647,097.23 Point 11 0.00 -4,055.42 -907.52 5,941,992.95 1,646,847.21 Point12 0.00 -3,597.43 -851.01 5,942,450.96 1,646,903.19 Point 13 0.00 -3,819.76 -573.23 5,942,228.97 1,647,181.19 Point 14 0.00 -3,097.88 -392.42 5,942,950.98 1,647.361.16 Point 15 0.00 -2,360.82 -377.62 5,943,687.99 1,647,375.12 Point 16 0.00 -1,722.82 -320.91 5,944,325.99 1,647,431.09 Point 17 0.00 -1,374.86 -251.53 5,944,673.99 1,647,500.07 Point 18 0.00 0.00 0.00 5,946,049.00 1,647,750.00 2G-151-1-03 Polygon 0.00 0.00 0.00 -3,162.361,138,949.98 5,941,545.00 1,647,449.00 70° 0' S2.033 N 140° 48' 14.495 W plan misses target center by 1139456.41 usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Polygon Point 1 0.00 0.00 0.00 5,941,545.00 1,647,449.00 Point 0.00 430.56 444.51 5,941,976.02 1,647,892.97 Point 0.00 223.29 666.31 5.941,769.03 1,648,114.99 Point 0.00 -236.95 846.83 5,941,309.04 1,648,296.02 Point 5 0.00 -807.20 1,026.22 5,940,739.05 1,648,476.04 Point 0.00 -1,432.17 942.53 5,940,114.05 1,648,393.07 Point 0.00 -2,112.33 1,024.80 5,939,434.05 1,648,476.11 Point 0.00 -2,292.71 441.54 5,939,253.03 1,647,893.12 Point 0.00 -1,917.63 399.95 5,939,628.02 1,647,851.10 Point 10 0.00 -1,361.57 400.55 5,940,184.02 1,647,851.07 Point 11 0.00 -903.47 346.05 5,940,642.02 1,647,796.05 Point 12 0.00 -389.37 304.61 5,941,156.02 1,647,754.02 Point 13 0.00 0.00 0.00 5,941,545.00 1,647,449.00 2G-151-1-03 T03 0.00 0.00 6,039.00-4,505.351,138,819.43 5,940,202.00 1,647,320.00 70' 0' 39.184 N 140' 48' 23.956 W plan misses target center by 1139310.17usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Point 2G-15L1_Fault1 0.00 0.00 6,000.00-501.161,139,004.03 5,944,206.00 1,647,500.00 70' 1' 17.796 N 140° 48' 1.550 W plan misses target center by 1139498.73usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Polygon Point 1 6,000.00 0.00 0.00 5,944,206.00 1,647,500.00 Point 6,000.00 1.00 1.00 5,944,207.00 1,647,501.00 2G-151-1-03 T3.1 0.00 0.00 6,028.00-3,208.971,139,478.98 5,941,499.00 1,647,978.00 70° 0' 50.805 N 140° 47' 59.677 W plan misses target center by 1139969.46usft at 9500.00usft MD (6025.12 TVD,-3632.67 N,-490.40 E) Point Casing Points Measured Vertical Depth Depth (usft) (usft) 9,500.00 6,025.12 2 3/8" Name Casing Hole Diameter Diameter (In) (in) - - 2.375 3.000 1012012017 6:08:29PM Page 5 COMPASS 5000.14 Build 85 ConocoPhillips ConocoPhillips Planning Report BA ER F IGHES BAT GE company Database: Company: Project: Site: Well: Wellbore: Design: EDT Alaska Sandbox ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2G Pad 2G-15 2G-151-1-03 2G-15 L 1-03_wp03 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2G-15 Mean Sea Level 2G-15 @ 140.00usit (2G-15) True Minimum Curvature Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 7,100.00 6,009+30 -1,376.13 -957.51 TIP/KOP 7,250.00 6,011.79 -1,478.54 -848.23 Start 7 dls 7,325.00 6,019.87 -1,531.96 -796.24 3 7,500.00 6,029.28 -1,672.57 -693.06 4 7,700.00 6,024.99 -1,854.65 -611.62 5 7,900.00 6,017.02 -2,050.85 -576.35 6 8,100.00 6,011.83 -2,247.15 -541.15 7 8,300.00 6,011.03 -2,443.52 -505.95 8 8,550.00 6,025.03 -2,691.17 -528.02 9 8,800.00 6,037.83 -2,938.85 -550.52 10 8,975.00 6,035.73 -3,111.31 -522.92 11 9,275.00 6,029.51 -3,408.57 -498.50 12 9,500.00 6,025.12 -3,632.67 -490.40 Planned TD at 9500.00 10/20/2017 6.08.29PM Page 6 COMPASS 5000.14 Build 85 ConocoPhillips Company: ConocoPhillips (Alaska) Inc -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 2G Pad Site Error: 0.00 usft Reference Well: 2G-15 Well Error: 0 00 usft Reference Wellbore 2G-151-1-03 Reference Design: 2G-15L1-03_wp03 Baker Hughes INTEQ Travelling Cylinder Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Bll FUG ES a GE company Well 2G-15 2G-15 @ 140.00usft (2G-15) 2G-15 @ 140.00usft (2G-15) True Minimum Curvature 1.00 sigma OAKEDMP2 Offset Datum Reference 2G-15L1-03_wp03 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 7,100.00 to 9,500.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,136.00 usft Error Surface: Pedal Curve Survey Tool Program Date 10/17/2017 From To (usft) (usft) Survey (Wellbore) Tool Name Description 200.00 6,600.00 2G-15 (2G-15) GCT-MS Schlumberger GCT multishot 6,600.00 6,950.00 2G-15L1_wp06 (2G-15L1) MWD MWD - Standard 6,950.00 7,100.00 2G-151-1-02_wp03 (2G-1511-02) MWD MWD - Standard 7,100.00 9,500.00 2G-151-1-03_wp03 (2G-15L1-03) MWD MWD - Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 9,500.00 6,165.12 2 3/8" 2-3/8 3 Summary Site Name Offset Well - Wellbore - Design Kuparuk 2G Pad 2G-10 - 2G-10 - 2G-10 2G-13 - 2G-13 - 2G-13 2G-13 - 2G-13A - 2G-13A 2G-13 - 2G-13AL1 - 2G-13AL1 2G-13 - 2G-13AL2 - 2G-13AL2 2G-14 - 2G-14 - 2G-14 2G-14 - 2G-14A - 2G-14A 2G-14 - 2G-14AL1 - 2G-14AL1 2G-15 - 2G-15 - 2G-15 2G-15 - 2G-1511 - 2G-15L1_wp06 2G-15 - 2G-15L1-01 - 2G-151-1-01_wp03 2G-15 - 2G-151-1-02 - 2G-151-1-02_wp03 2G-16 - 2G-16 - 2G-16 Plan: 2G-19 - Plan: 2G-19 - 2G-19wp02 Plan: 2G-20A - Plan: 2G-20A - 2G-20Awp02 Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Depth Depth Distance (usft) from Plan (usft) (usft) (usft) (usft) Out of range 9,432.71 7,400.00 641.67 267.62 376.71 Pass - Major Risk 9,432.71 7,400.00 641.67 267.60 376.73 Pass - Major Risk 9,432.71 7,400.00 641.67 267.60 376.73 Pass - Major Risk 9,432.71 7,400.00 641.67 267.60 376.73 Pass - Major Risk Out of range Out of range Out of range Out of range Out of range Out of range 7,400.81 7,400.00 43.37 1.47 43.05 Pass - Minor 1/10 Out of range Out of range Out of range Offset Design Kuparuk 2G Pad - 2G-13 - 2G-13 - 2G-13 Offset Site Error: 0.00 usft Survey Program: 200-GCT-MS 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) 1°1 (usft) (usft) 1") (usft) (usft) (usft) 8665.85 6,174,29 6,175.00 5,090,28 35.96 31.39 -159.40 -2,835,75 -838.83 3 1,122.96 228,58 985.70 Pass -Major Risk 8,685.84 6,175,31 6,200,00 5,108,64 36,10 31,55 -160.20 -2,851.73 -844,55 3 1,107.18 229.54 968.96 Pass -Major Risk 8,705.29 6,176.14 6,225.00 5,126.97 36.24 31,71 -160.94 -2,867.73 -850.28 3 1,091.45 230,45 952.16 Pass -Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 1011712017 12:28:07PM Page 2 COMPASS 5000.14 Build 85 W a mmo ti� @ T m 4 o= E m M c 4' 7 � J d � N 4 N CL o.17 "L�a YYNNo, a aN3aM a' 341' � I N C I a� 4 3 0 0 0 3 0 2 N N C � V N N N 1. 61 U - On N = _1 F., o o N -2 -3 -3 _4 _q -5 -6 -6 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (ui/gsn 009) (+)u1�oN/(-)ujrioS -0 M J'C*- E, LO m 0 0 rn O � C Cd �6 OrN N Q F-U)m V �O CO I�OOOrr� d U d' CO t'- 'O l/] cq F+ F'- V t2 NN �O)u�cD o] U a OR MAGO >c2 Lfl C^O OO N'' COO Olr V r.W -N N N N NC+lM MCO aLO .— CO y 000000 0 0 00000 LO 61` U 000 000 0 00000 0 J C6, 66C=; L[) LO M6 Ln66 N oO O'!tfl W 0700)OO)�O) ti N N N N L J 10 0 0 0 Cl 0 0 0 0 0 0 0 0 N Cl 0 Cl 0 Cl 0 0 0 0 0 0 0 0 M Cl! N O C O M OU� M LO V + A V O)Ql� r- V ON �N00) a1� a0 n C.Q CO Ln L�! Ln Lf! V' J (Q W00 ��CO r-Lr) LC! L('!N r-CAr r- �nrn In cfl m.-LArMM C+]CO Q w O LO Z O co C' V V' O 1- M 00 a D N + r- r+M r- Ln LO V ct 6i M r O M M:t COV ON ct C9m CC N N CV N N Cr! C'�] M W � Cl? n 0 0 N O! O� O O� n 0)LO QO)r O)O'i ct r-rr LO r-ui O) LO O N N N M M N N C N> � O OCOO O COLD �LOO COO COOO CO COOO O--;t' N V V' N � O r C O N r O L f J Z� a�� V NaCl aO CO 'R OOO O]O O m L.() MMaD cn to M r0 Nc,O• V Ln M M M cY CO r- CO rr a7 C+ CO GO r- C Cl? a0 cO O V' c0 cO O N O 3F O 6NJ O 00! r O m q7 CO m I O i. Q O O O O O O O O O O O O O ni O O o 0 0 0 0 0 0 0 0 0 0 0 0 O o 0 o O o LCj Cj CO LCi Ln O L n N O O O O O L n O r• r- O N MC2'l r-Q7M 0N u] � r-r-r-r-r-mclo�mmrnrn 0 V C {'l 10 r- m rn C:. M + o r 00 00 00 00 00 00 0 G )0 CD )0Q S00 fil S00 )00 i00 M 00 00 i00 �00 4 N CJ C7 4 0 a o " 0 3 i� 3 NN 3 a N . - _ N 3 3 N 3 3. 3: 3: 3 3f -------------- 21 21 rn 2( 2' 21 2-- 2' �1 2c 1< 1c IE 1 - t o nsr z- --_v li .._.. en if v 15 a � 14 a 13 - h 12 � 11 C7 N 10 95 J o 85 76 LL CJ 66 57 O O O O O J C (u?/gsn 96) q;daQ iva►laan onil 80 )85 )90 195 00 '05 10 15 20 25 30 35 40 45 50 55 50 CN 55 - O 0 70 O f)O 75 30 p U 35 30 0 .-E 35 )0 )5 10 15 >_0 25 30 35 30 is KUP PROD 2G-15 ConocoPhillips Well Attributes Max Angle & MD TD Alaska Inc.nWellbore ' AP IIUWI Field Name Wellbore Status 500292116200 KUPARUK RIVER UNIT PROD Ind C) MD (ftKB) 47.88 6,000.00 Act Btm TIKB) 6'997.0 Comment 1-12S (pp.) Dale SSW NONE 150 11/1/2014 Annotation Entl Date KB-Grd (ft) Last WO: 7/20/2017 Rig Release Date 35.00 10/16/1984 DEVIATED- 2G-159/51201711'03:02 AM Vertical schematic equal) Annotation Depth (ftKB) Entl Dale Annotation Last Mod By End Date - --"'" Last Tag: RKB 6,835.0 8/13/2017 Rev Reason: W/O, SET WRP & CATCHER, GLV jennalt 9/5/2017 Hanger; 32 0 C/O, PULL WRP & CATCHER, TAG Casing Strings Casing Description OD (in) ID (in) Top (ftKB) Set Depth (RKB) Set Depth (TVD)... Wt/Len (I... Gratle Top Threatl CONDUCTOR 16 15.062 35.0 105.0 105.0 62.50 H-40 WELDED Casing Description OD (in) ID (1n) Top (ftKB) Set Depth (ftKB) Set Depth (ND)... Will -en (I... Gmde Top Thread ......._... _..... ............. _-............ _... �............... ... ... .. ...... SURFACE 95/8 8.921 34.0 2,726.5 2,726.1 36.00 J-55 BUTT Casing Description OD (in) ID (in) 1 Top (ftKB) Set Depth (ftKB) Set Depth (ND)... WtlLen (I... Gratle Top Threatl PRODUCTION 7 6.2761 33.1 6,983.0 6,336.3 26.00 J-55 BUTT CONDUCTOR; 35.0-105.0 Tubing Strings Tubing Description etdng Ma... ID (in) Top (ftKB) Set Depth (ft.. Set Depth (ND) (... Wl (Ib/ft) Grade Top Connection 3-1/2 Upper Gas lift 31/2 2.992 0.0 5757.2 5,495.E 9.30 L-80 EUE 8rd Mod GAS LIFT; 2,491.5 completion 2017 RWO Completion Details Nominal ID Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Co. (in) 32.0 32.0 0.23 Hanger Tubing Hanger, McEvoy, MSDP, 7-1116" x 3-1/2" EUE 8rd 2.992 Tap x Bottom with 3" H BPVG SURFACE; 34.0-2,726.5- 5,745.1 5,487.2 46.21 Locator Locator, Baker, GBH-22 (bottom of locator spaced out 3') 2.990 GAS LIFT; 3,652 9 5,748.4 5,489.5 46.24 Seal Assembly Seal Assembly, Baker, 8040 (total seal assembly = 2.990 11.79) Tubing Description Me Ma.., ID (in) Top (ftKB) Set Depth (ft.. Set Depth (ND) (... Wt (Ibfft) Grade Top Connection Straddle Completion 3 1/2 2.992 5,748.7 6,390.9 5,924.2 9,30 L-80 EUE aid Mod 2017 RWO GAS LIFT; 4,466.8 Completion Details Nominal ID Top (ftKB) I Top (ND) (fIKB) Top Inc] (°) It.. Des Com (in) 5,748.7 5,489.8 46.24 PBR PBR, Baker, 10' 80-40 4.000 5,761.7 5,498.8 46.36 FHL Packer Packer, Baker, 4782 FHL (shear release = 60K) 2.940 - 6,378.8 5,915.9 47.03 Locator Locator, Baker, GBH-22 (bottom of locator spaced out 3') 2.990 GAS LIFT; 5,093.1 6,381.1 5,917.5 47.02 Seal Assembly Seal Assembly, Baker, 80-00 (total seal assembly = 2.990 GAS LIFT; 5,688.3 11.80') Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (ft.. Set Depth (TVD) (... Wt (lb"')Grade Top Connection Lower Comp let ion 4112 3.958 6,381.1 6,680.1 6,122.5 12.60 L-80 IBTM 2017 RWO Locator; 5.745.1 Completion Details Nominal ID Seal Asserrbly; 5,748A PBR; 5,]48 7 Top (ftKB) Top (ND) (ftKB) Top Incl (°) Item Des Com (in) 6,381.1 5,917.5 47.02 PER PBR, Baker, 10' 80-40 4.000 6,394.1 5,926.4 46.99 FHL Packer Packer, Baker, 4782 FHL (shear release = 60K) 2.940 FHL Packer; 5,761.7 6,447.6 5,962.9 46.87 Nipple -2.813" Nipple, Camoo, 2.813" DS profile, SN: 3651-18 2.813 DS 6,553.5 6,035.5 46.72 Crossover Crossover, 3-1/2" EUE 8rd Mod Box x 4-1/2" IBT Pin 2.992 6,655.0 6,036.5 46.72 Wearsox Wearsox, Northern Solutions, 4-1/2", 12.6#, L-80, IBTM 3.958 Locator; 6,378.E Box x Pin Seal Assembly; 6,3B1.1 PBR ; 6,381.1 Perforations & Slots FHL Packer; 6,394.1 Shot Dens Top (ND) Bun (TVD) (shots" Top (ftKB) Bt. (ftKB) (ftKB) (ftK8) Zone Data 0 Type Com 6,566.0 6,580.0 6,044.0 6,053.6 CC-4, 2G-15 2/23/2005 6.0 APERF 2.5" HSD, 60 deg. ph 6,658.0 6,674.0 6,107.3 6,118.3 A-5, 2G-15 9/30/1985 4.0 RPERF 2 1/8"Dresser, 0 Ph 6,660.0 6,662.0 6,108.6 6,110.0 A-5, 2G-15 11/8/1984 1.0 IPERF 4" DA JJ; 90 deg. Phasing Nipple-2.813'DS;6,447.6 6,666.0 6,667.0 6,112.8 6,113.5 A-5,2G-15 11/8/1984 1.0 IPERF 4" DA JJ; 90 deg. Phasing 6,668.0 6,669.0 6,114.2 6,114.9 A-5, 2G-15 11/8/1984 1.0 IPERF 4" DA JJ; 90 deg. Phasing 6,694.0 6,738.0 6,132.2 6,162.8 A-4,2G-15 9/30/1985 4.0 RPERF 21/8"Dresser, 0Ph 6,697.0 6,698.0 6,134.3 6,135.0 A-4, 2G-15 11/8/1984 1.0 IPERF 4" DA JJ; 90 deg. Phasing 6,700.0 6,702.0 6,136.4 6,137.7 A-4,213-15 11/8/1984 1.0 IPERF 4" DA JJ;90 deg. Crossover; 6,553.5 Phasing 6,705.0 6,706.0 6,139.8 6,140.5 A-4, 2G-15 11/8/1984 1.0 IPERF 4" DA JJ; 90 deg. Phasing 6,710.0 6,712.0 6,143.3 6,144.7 A-4, 2G-15 11/8/1984 1.0 IPERF 4" DA JJ; 90 deg. APERF; 6,566.0-6,580.0- asmg Wearsox: 6,555 0 6,716.0 6,718.0 6,147.5 6,148.9 A-4, 2G-15 11/8/1984 1.0 IPERF 4" Phasing DA JJ; 90 deg. IPERF; s,sso.6-fi,fifi2.a,_ RPERF; 6,658.0-6,674 a IPERF; 6.666.0-6,667.0� 6,724.0 6,725.0 6,153A 6,153.8 A-4, 2G-15 11/8/1984 1.0 IPERF 4" Phasing DA JJ; 90 de g' IPERF; 6,668.0-6,669.0- 6,727.0 6,728.0 6,155.1 6,155.8 A-4, 2G-15 11/8/1984 1.0 IPERF 4" Phasing DA JJ; 90 deg. Mandrel Inserts IPERF; 6 697.0-6 698.0 St all IPERF; 6 700.0-6,702.0- N Top (ftKB) Top (ND) (ftKB) Make Model OD (in) Sam Valve Type Latch Type PortSize (in) TRO Run (psi) Run Data Com i 2,491.5 2,491.2 Cameo MMG 1 1/2 GAS LIFT GLV RK 0.188 1,257.0 8/12/2017 IPERF; fi,7080-6,706.0- 2 3,652.9 3,652.1 Cameo MMG 11/2 GAS LIFT GLV RK 0.188 1,245.0 8/12/2017 IPERF; 6,710.0-6,712.0 4,466.8 4,444.6 Cameo MMG 1112 GAS LIFT GLV RK 0.188 1,244.0 8/12/2017 RPERF; 6,694 0-6,738 0 PERF; 6,716.0-6,718.0- 4 5,093.1 4,990.8 Cameo MMG 11/2 GAS LIFT GLV RK OA88 1,240.0 8/12/2017 IPERF; 6,724.0-6, 725.0- 5 5,688.3 5,447.8 Cameo MMG 11/2 GAS LIFT OV RK 0.250 0.0 8/12/2017 Notes: General & Safety IPERF; 6,727.0-6,728.0- End Date Annotation 10/21/2010 NOTE: View Schematic w/ Alaska Schematic9.0 1/19/2016 NOTE: 100' balanced 11# WellLock Resin plug into both the Tubing and IA- C/O on 2017 RWO PRODUCTION; 33.1-6,983.0 V E N t V co cl a m to O CL 0 a ,LO V N C) Opp Oo p CL O O CD O O J N t n _ J a n If) O r � J J NF-0 NF I n V V Cl) 0) N U O to (6 co N m p U o to c a rn S rn Q -E 00 � N M F- a N Ib a N00 E co toQ M N V @ CO W N m O) � N M N60 O. D1Y V J O� �If)\ V@ /(0 lJCc CDN ik U - E CL afJ Q J 16 O) U N 0- LL CL LL Q m N N C') N N N N C N M M Cl) cuC13 m m (Uc CO m 0 L f) .0 roto ❑ p N O rL it r O O M N 00cl) i. i. N 2 =� ❑ a COO Q� li `�. L u❑ (V V M N N (0 cc [O CO a)OD I� N O :/>i NCO I I i '� m O N U > Q I r ik � aa11 ,i O Ii 11 ,1 I, 'I , I� M O CL �oc) II '� , ; „ II ; ; ° ❑ oY) 'I „ l „ ! OLi _ OCOO 1 1 , 1 F NO�O� C9❑O N F 1- TRANSMITTAL LETTER CHECKLIST WELL NAME: k1kU_ a G - I 1, I - 03 PTD: a21 - NJ J Development Service _ Exploratory _ Stratigraphic Test Non -Conventional FIELD: '`� V�.� POOL: &C 0 ) 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. % g y - 13 , API No. 50- Qg - -_ZJ _- (DO - a�) . (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 ermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK. RIV UNIT 2G-151-1-03 _Program DEV Well bore seg ❑�/ PTD#:2171490 Company CONOCOPHILLIPS ALASKA _INC._ —__ _ Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 __ On/Off Shore On --Annular Annular Disposal ❑ Administration 17 Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025667, entire wellbore. 3 Unique well name and number Yes KRU 2G-151-1-03 4 Well located in adefined 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 PKB 10/27/2017 12 Permit can be issued without administrative approval Yes 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_ I18 Conductor string provided NA_ Conductor set in KRU 2G-15 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in KRU 2G-15 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing set and fully cemented 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons No Productive interval will be completed with uncemented slotted liner 23 Casing designs adequate for C, T, B & permafrost Yes 124 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells i25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separationproposedYes Anti -collision analysis complete; no major risk failures 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pressure is 4379 psig(13.9 ppg EMW); will drill w/ 8.7 ppg EMW and maintain overb_al w/ MPD VTL 10/31/2017 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 3768 psig; will test BOPs to 4500_psig 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of 112S gas probable Yes H2S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 2G-Pad are H2S-bearing. 112S measures required. Geology i36 Data presented on potential overpressure zones Yes Maximum potential reservoir pressure is 13.9 ppg EMW; will be drilled using 8.7 ppg mud and MPD technique. Appr Date 37 Seismic analysis of shallow gas zones NA PKB 10/27/2017 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Onshore development spoke to be drilled. Geologic Engineering Public Commissioner: Date: �C�mis�sionor: Date Commissi eq0 r� Date