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218-058
Winston, Hugh E (CED) From: Winston, Hugh E (CED) Sent: Thursday, June 4, 2020 9:04 AM To: william.r.long@cop.com Cc: Loepp, Victoria T (CED) Subject: KRU 1L-230-01 and 1L-231-1-03 Permits Expired Hi William, The Permits to drill for both KRU IL-23L1-01 and KRU 1L-23L1-03 which were issued to CPA] on May 30`h 2018, have expired under Regulation 20 AAC 25.005 (g). The permits have been marked expired in their history file and in the AOGCC database. Please let me know if you would like any follow up information on these permits. Huey Winston Statistical Technician Alaska Oil and Gas Conservation Commission h Ih.winston@alaska.xov 907-793-1241 THE STATE 'ALASKA GOVERNOR BILL WALKER James Ohlinger Staff CTD Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 1L-23L1-01 ConocoPhillips Alaska, Inc. Permit to Drill Number: 218-058 Surface Location: 537' FNL, 143' FEL, SEC. 31, T11N, RI OE, UM Bottomhole Location: 1338' FNL, 1307' FEL, SEC. 1, T10N, R9E, UM Dear Mr. Ohlinger: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the permit to redrill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 191-062, API No. 50-029-22167- 00-00. Production should continue to be reported as a function of the original API number stated above. 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. 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. 4 DATED this° day of May, 2018. Sincerely, Hollis S. French Chair STATE OF ALASKA ALA —.,.A OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 MAY 11 2018 1 a. Type of Work: . 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill ❑ Lateral ❑✓ Stratigraphic Test ❑ Development - Oil ❑� • Service - Winj ❑ Single Zone ❑� • 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 1 L-23L1-01 ' 3. Address: 6. Proposed Depth: > ./ 7' 12. Field/Pool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 12250 TVE j6 5887 Kuparuk River Kuparuk River Oil 4a. Location of Well (Governmental Section): 7. Property Designation:: ��L Zi�S� Surface: 537' FNL, 143' FEL, Sec 31, T11 N, R10E, UM ADL 25664 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1635' FNL, 232' FWL, Sec 6, T1 ON, R10E, UM LO/NS 83-139 24-Ma -18 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 1338' FNL, 1307' FEL, Sec 1, T10N, R9E, UM 2501 13500' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 130' 15. Distance to Nearest Well Open Surface: x- 539925 Y- 5948431 - Zoi 4 GL / BF Elevation above MSL (ft): 87' to Same Pool: 1574' (2E-07) 16. Deviated wells: Kickoff depth: 10650 feet • 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 94 degrees Downhole: 4393 • Surface: 3760 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" 4.6# L-80 ST-L 2170 10080 5889 12250 5887 Un-Cemented 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): 10346 6291 N/A 10249 6238 N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 82' 16" 235 sx AS 1 122' 122' Surface 5263' 9-5/8" 750 sx Type E, 600 sx Class G 5306' 3609' Intermediate Production 10300' 7" 250 sx Class G Prem. 10335' 6285' Liner Perforation Depth MD (ft): 9794 - 9874, 10012 - 10050, Perforation Depth TVD (ft): 10156 - 10165 5992 - 6035, 6110 - 6131, 6188 - 6193 Hydraulic Fracture planned? Yes❑ No ❑� 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program ❑ Time v. Depth Plot ❑ ❑ Shallow Hazard Analysis ❑ Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be % deviated from without prior written approval. 6`�f/// Contact Name: William R. Long �� Authorized Name: James Ohlinger Contact Email: William. R.Lon COP.com Authorized Title: Staff CTD Engineer Contact Phone: 907-263-4372 ` �y Authorized Signature: Date: JzO/moo Commission Use Only Permit to Drill API Number: Permit ��� �— ZIIv� Approval 5 3O See cover letter for other Number: J� 50-G%Z—Z (���.% 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: 0 Other: B�� %ems t fo L�pZj �P 5 q Samples req'd: Yes No©� Mud log req'd: Yes❑ N.[v// t �f t t�1 t// Gi r / r� t/f h t e� �s f p Z�s��� �'�isS� rsasures: Yes Nor❑ Directional svy req'd: Yes [� No ❑ yt C e f p Z O �A-.C' 2 S D / �epaci�g�cexception req'd: Yes ❑ No u Inclination -only svy req'd: Yes ❑ No [vt a (� Lt/ � z �� G1� e' /'— C�1 ✓J fa Post initial injection MIT req'd: Yes ❑ No LJ h �✓ GLA-7 �7a2rJ o� iC �a ✓rhl Lit ftrr! _ J / APPROVED BY f Ja Approved by: COMMISSIONER THE COMMISSION Date: I I Jl SE g ✓� Submit Form and Form 10-401 Revised 5/2017 T �s p� mi is valid fo 2 " t f proval per 20 AAC 25.005(g) tachments in Duplicate ConocoPhilli s p Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 10, 2018 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 KRU 1 L-23 (PTD# 191-062) using the coiled tubing drilling rig, Nabors CDR3-AC. . CTD operations are scheduled to begin in late May or early June 2018. The objective will be to drill four laterals, KRU 1L-23L1, 1L-231_1-01, 1L-231_1-02, and 1L-231_1-03, targeting the Kuparuk C-sand interval. 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. Attached to this application are the following documents: — Permit to Drill Application Forms (10-401) for 1L-23L1, 1L-23L1-01, 1L-231_1-02, and 1L-231_1-03 — Detailed Summary of Operations — Directional Plans for 1L-23L1, 1L-231_1-01, 1L-231_1-02, and 1L-231_1-03 — Current wellbore schematic — 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 1L-23L1, 1L-23L1-01, 1L-23L1-02, & 1L-23L1-03 Application for Permit to Drill Document 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))................................................................................................................... 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005 c 2 .......................................2 3. Blowout Prevention Equipment Information ................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 2 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7)).................................................................................................................................................. 3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005 c 8............................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9))..................................................................................................................................................4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4 11. Seabed Condition Analysis............................................................................................................ 4 (Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................ 4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 4 13. Proposed Drilling Program.............................................................................................................4 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................6 14. Disposal of Drilling Mud and Cuttings.......................................................................................... 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 1 L-23L1, 1 L-23L1-01, 1 L-23L1-02, and 1 L-231-1-03 laterals..... .............................. 7 Attachment 2: Current Well Schematic for 1 L-23............................................................................................................7 Attachment 3: Proposed Well Schematic for 1L-231-1, 1L-23L1-01, 1L-231-1-02, and 1L-23L1-03laterals .....................7 Page 1 of 7 May 10, 2018 PTD Application: 1L-23L1, 1L-2311-1-01, 1L-23L1-02, & 1L-23L1-03 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 1L-231-1, 1L-23L1-01, 1L-231-1-02, and 1L-231-1-03. 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 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 4,000 psi. Using the maximum formation pressure in the area of 4393 psi at the datum in 2E-05 (i.e. 13.3 ppg EMW), the maximum potential surface pressure in 1 L-23, assuming a gas gradient of 0.1 psi/ft, would be 3,760 psi. Seethe "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 L-23 was measured to be 3498 psi at the datum (10.6 ppg EMW) on 4/20/2017. The maximum downhole pressure in the 1 L-23 vicinity is the 2E-05 at 4393 psi at the datum or 13.3 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 1 L-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 L-23 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 1 L-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 May 9, 2018 PTD Application: 1L-23L1, 1L-231_1-01, 1L-231_1-02, & 1L-231_1-03 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 1L-23L1 10650' 14400' 5887' 5877' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 1L-23L1-01 10080' 12250' 5889' 5887' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 1L-23L1-02 10500' 15300' 5877' 5898' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 1 L-23L1-03 9840' 12000' 5887' 5894' 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 si Collapse Si Conductor 16" 62.5 H-40 Welded 40' 122' 40' 122' 1640 670 Surface 9-5/8" 36 J-55 BTC 43' 5306' 43' 3609' 3520 2020 Production 7" 26 J-55 BTC-Mod 43' 10335' 43' 6285' 4980 4320 Tubing 3-1/2" 9.3 L-80 EUE 8rd 39' 9810, 39' 6001' 10160 10540 Note: Tubing information is proposed depths, pending completion of the rig workover. 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 Power -Pro drilling mud (8.6 ppg). This mud weight may 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 11.4 ppg NaCl/NaBR completion fluid in order to provide formation over -balance and maintain wellbore stability while running completions. If higher formation pressures are encountered the completion brine will be weighted up with sodium bromide or potassium formate. 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". In the 1 L-23 laterals we will target a constant BHP of 11.4 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 Page 3 of 7 May 9, 2018 PTD Application: 1L-23L1, 1L-23L1-01, 1L-23L1-02, & 1L-23L1-03 reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed for improved borehole stability. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Pressure at the 1 L-23 Window 9845' MD, 6019' TVD Using MPD Pumps On 1.8 b m Pumps Off Formation Pressure 10.6 3318 psi 3318 psi Mud Hydrostatic 8.6 2692 psi 2692 psi Annular friction i.e. ECD, 0.080 si/ft 788 psi 0 psi Mud + ECD Combined no chokepressure) 3480 psi overbalanced —162psi) 2692 psi underbalanced --626psi) Target BHP at Window 11.4 3568 psi 3568 psi Choke Pressure Required to Maintain Target BHP 88 psi 876 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 The 1L-23 CTD producer project targets the C sand to increase throughput and recovery in the I area. Four laterals will be drilled from the 1L-23 parent well in the C-sand, two to the west and two to the south. Nabors CDR3 will mill a 2.80" window off a wedge at 9845'. All laterals will be completed with 2-3/8" slotted liner from TD with the last lateral liner top located inside the production casing. Page 4 of 7 May 9, 2018 PTD Application: 1L-23L1, 1L-23L1-01, 1L-23L1-02, & 1L-23L1-03 Pre-CTD Work 1. Perform rig workover to run new 3-1/2" completion with space for a high expansion wedge and a backup tandem wedge. 2. Prep site for Nabors CDR3-AC. Rid Work 1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. Set high expansion wedge. 3. IL-23L1 Lateral (C sand - West) a. Mill 2.80" window at 9845' MD. b. Drill 3" bi-center lateral to TD of 14400' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 10650' MD. 4. 1L-23L1-01 Lateral (C sand - West) a. Kick off of the aluminum billet at 10650' MD. b. Drill 3" bi-center lateral to TD of 12250' MD. c. Run 2%" slotted liner with aluminum billet from TD up to 10080' MD. 5. 1L-23L1-02 Lateral (C sand - South) a. Kickoff of the aluminum billet at 10080' MD. b. Drill 3" bi-center lateral to TD of 15300' MD. c. Run 2%" slotted liner with aluminum billet from TD up to 10500' MD. 6. 1L-23L1-03 Lateral (C sand- South) a. Kickoff of the aluminum billet at 10500' MD. b. Drill 3" bi-center lateral to TD of 12000' MD. c. Run 2%" slotted liner with deployment sleeve from TD up to 9840' MD. 7. Freeze protect, ND BOPE, and RDMO Nabors CDR3-AC. Post -Rig Work 1. Return to production. Page 5 of 7 May 9, 2018 PTD Application: 1L-23L1, 1L-23L1-01, 1L-2311-1-02, & 1L-23L1-03 Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure 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 — 1 L-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 23/" rams will provide secondary well control while running 2%" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). Page 6 of 7 May 9, 2018 PTD Application: 11--231-1, 1L-2311-1-01, 1L-231-1-02, & 11--2311-1-03 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 L-23L1 13120' 1 L-23L1-01 13500' 1L-2311-1-02 9320' 1 L-231-1-03 11990, — Distance to Nearest Well within Pool Lateral Name Distance Well 1L-23L1 1574' 2E-07 1 L-23L1-01 1574' • 2 E-07 1L-23L1-02 469' 2E-07 1L-2311-1-03 469' 2E-07 16. Attachments Attachment 1: Directional Plans for IL-23L1, 1L-23L1-01, 1L-23L1-02, and IL-23L1-03laterals, Attachment 2: Current Well Schematic for 1 L-23. Attachment 3: Proposed Well Schematic for IL-23L1, 1L-23L1-01, 1L-23L1-02, and 1L-23L1-03 laterals. Page 7 of 7 May 9, 2018 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 1 L Pad 1 L-23 1 L-231-1-01 Plan: 1 L-23L1-01_wp04 Standard Planning Report 24 April, 2018 BER T- GHES GE company ` ConocoPhillips BAT ConocoPhillips Planning Report UGHES a GE company Database: EDTAlaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 1 L Pad Well: 1 L-23 Wellbore: 1 L-23L1-01 Design: 1 L-23L1-01_wp04 Local Co-ordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 1 L-23 Mean Sea Level 1 L-23 @ 130.O0usft (1 L-23) 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 1 L Pad Site Position: Northing: 5,949,190.90usft Latitude: 70° 16' 19.650 N From: Map Easting: 539,916.78usft Longitude: 149° 40' 37.763 W Position Uncertainty: 0.00 usft Slot Radius: 0.000in Grid Convergence: 0.30 ° tWell 1 L-23 --- -- -- Well Position +N/-S +E/-W 0.00 usft Northing: 0.00 usft Easting: 5,948,431.07 usft Latitude: 539,924.55 usft Longitude: 70° 16' 12.176 N 149° 40' 37.655 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 1L-231-1-01 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGGM2017 7/1/2018 16.98 80.86 57,457 Design 1L-23L1-01_wp04 �- -----�- --- --l- - Audit Notes: Version: Phase: PLAN Tie On Depth: 10,650.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 0.00 0.00 0.00 270.00 I Plan Sections Measured Depth Inclination �tr TVD Belo Azimuth System +N/-S +E/-W Dogleg Build Turn Rate Rate Rate TFO (usft) (°) (I (usft) 1 (usft) (usft) (°/100ft) (°/100ft) (°/100ft) (°) Target 10,650.00 93.79 267.45 5,887.0-6,376.78 -4,625.28 0.00 0.00 0.00 0.00 10,800.00 84.69 262.20 5,889.06-6,390.28 -4,774.45 7.00 -6.06 -3.50 210.00 10,950.00 89.99 271.28 5,896.04-6,398.76 -4,923.83 7.00 3.53 6.05 60.00 11,175.00 89.99 287.03 5,896.10-6,363.06 -5,145.27 7.00 0.00 7.00 90.00 11,300.00 85.62 294.62 5,900.89-6,318.71 -5,261.91 7.00 -3.49 6.07 120.00 11,500.00 85.75 280.58 5,916.00-6,258.54 -5,451.52 7.00 0.07 -7.02 270.00 11,700.00 92.80 268.48 5,918.54-6,242.80 -5,650.38 7.00 3.52 -6.05 300.00 11,925.00 92.69 284.24 5,907.70-6,217.98 -5,873.04 7.00 -0.05 7.01 90.00 12,250.00 94.41 306.97 5,887.29-6,078.76 -6,163.63 7.00 0.53 6.99 85.00 41242018 5:13:08PM Page 2 COMPASS 5000.14 Build 85 ConocoPhillips BVER ConocoPhillips Planning Report 1.1UGHES a GEcompany Database: EDT Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 1 L Pad Well: 1 L-23 Wellbore: 1 L-23L1-01 Design: 1 L-23L1-01_wp04 Planned SurveyV-- Measured TVD Below Depth Inclination Azimuth System +N/-S (usft) (°) (°) (usft) (usft) 10,650.00 • 93.79 267.45 5,887.07 -6,376.78 TIP/KOP 10.700.00 90.75 265.70 5,885.09 -6,379.76 10,800.00 84.69 262.20 5,889.06 -6,390.28 Start 7 dls 10,900.00 88.21 268.26 5,895.26 -6,398.56 10,950.00 89.99 271.28 5,896.04 -6,398.76 3 11,000.00 89.99 274.78 5,896.06 -6,396.11 11,100.00 89.99 281.78 5,896.08 -6,381.72 11,175.00 89.99 287.03 5,896.10 -6,363.06 4 11,200.00 89.11 288.55 5,896.30 -6,355.43 11,300.00 85.62 294.62 5,900.89 -6,318.71 5 11,400.00 85.66 287.60 5,908.50 -6,282.81 11,500.00 85.75 280.58 5,916.00 -6,258.54 6 11,600.00 89.27 274.53 5.920.35 -6,245.42 11,700.00 92.80 268.48 5,918.54 -6,242.80 7 11,800.00 92.78 275.48 5,913.67 -6,239.35 11,900.00 92.71 282.49 5,908.88 -6,223.76 11,925.00 92.69 284.24 5,907.70 -6,217.98 8 12,000.00 93.14 289.48 5,903.88 -6,196.26 12,100.00 93.69 296.47 5,897.92 -6,157.32 12,200.00 94.19 303.47 5,891.04 -6,107.51 12,250.00 94.41 306.97 5,887.29 . -6,078.76 Planned TD at 12250.00 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 1 L-23 Mean Sea Level 1 L-23 @ 130.00usft (1 L-23) True Minimum Curvature Vertical Dogleg Toolface Map Map +E/-W Section Rate Azimuth Northing Easting (usft) (usft) (°/100ft) (°) (usft) (usft) -4,625.28 4,625,28 0.00 0.00 5,942,030.48 535,333.61 -4,675.14 4,675.14 7.00 -150.00 5,942,027.23 535,283.77 -4,774.45 4,774.45 7.00 -150.07 5,942,016.19 535,184.53 -4,873.85 4,873.85 7.00 60.00 5,942,007.38 535,085.19 -4,923.83 4,923.83 7.00 59.62 5.942,006.92 535,035.21 -4,973.76 4,973.76 7.00 90.00 5,942,009.29 534,985.28 -5,072.65 5,072.65 7.00 90.00 5,942,023.16 534,886.32 -5,145.27 5,145.27 7.00 90.00 5,942,041.43 534,813.61 -5,169.07 5,169.07 7.00 120.00 5,942,048.94 534,789.77 -5,261.91 5,261.91 7.00 119.99 5,942,085.16 534,696.75 -5,354.86 5,354.86 7.00 -90.00 5,942,120.56 534,603.61 -5,451.52 5,451.52 7.00 -89.47 5,942,144.31 534,506.84 -5,550.50 5,550.50 7.00 -60.00 5,942,156.91 534,407.80 -5,650.38 5,650.38 7.00 -59.74 5,942,159.00 534,307.91 -5,750.14 5,750.14 7.00 90.00 5,942,161.92 534,208.15 -5,848.74 5,848.74 7.00 90.34 5,942,176.99 534,109.48 -5,873.04 5,873.04 7.00 90.68 5,942,182.64 534,085.15 -5,944.69 5,944.69 7.00 85.00 5,942,203.97 534,013.39 -6,036.54 6,036.54 7.00 85.27 5,942,242.42 533,921.35 -6,122.91 6,122.91 7.00 85.68 5,942,291.77 533,834.73 -6,163.63 6,163.63 7.00 86.16 5,942,320.30 533.793.85 412412018 5:13:08PM Page 3 COMPASS 5000.14 Build 85 ConocoPhillips BAKER ConocoPhillips Planning Report 11 IGHES a GE company Database: EDT Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 1 L Pad Well: 1 L-23 Wellbore: 1 L-23L1-01 Design: 1 L-23L1-01_wp04 Targets Local Co-ordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 1 L-23 Mean Sea Level 1L-23 @ 130.00usft (1 L-23) True Minimum Curvature Target Name hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting Shape (°) (1) (usft) (usft) (usft) (usft) (usft) 11--231-1-01_T02 0.00 0.00 5,920.00-12,540.031,134,543.30 5,941,910.00 1,674,407.00 plan misses target center by 1139185.25usft at 10650.O0usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Point 1L-23 CTD Polygon Non 0.00 0.00 0.00 -12,103.031,136,059.79 5,942,355.00 plan misses target center by 1140714.63usft at 10650.00usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Polygon Point 1 0.00 0.00 0.00 5,942,355.00 Point 2 0.00 -344.77 519.25 5,942,013.02 Point 3 0.00 -746.82 141.09 5,941,609.01 Point 0.00 -1,118.58 -484.93 5,941,233.97 Point 5 0.00 -1,303.40 -1,474.01 5,941,043.93 Point 6 0.00 -499.96 -4,967.18 5,941,828.75 Point 7 0.00 1,232.92 -4,337.01 5,943,564.78 Point 8 0.00 -181.49 -672.03 5,942,169.97 Point 9 0.00 0.00 0.00 5,942,355.00 1L-23L1_Fault2 0.00 0.00 5,897.00-12,533.331,134,788.36 5,941,918.00 plan misses target center by 1139430.27usft at 10650.00usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Polygon Point 1 5,897.00 0.00 0.00 5,941,918.00 Point 5,897.00 1.00 1.00 5,941,919.01 1L-231-1-01_T01 0.00 0.00 5,896.00-12,673.651,135,033.64 5,941,779.00 plan misses target center by 1139676.32usft at 10650.00usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Point 1L-231-1-02_Fault1_M 0.00 0.00 0.00 -15,728.221,136,772.64 5,938,734.00 plan misses target center by 1141451.41 usft at 10650.00usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Rectangle (sides W1.00 H2,000.00 D0.00) 1L-231-1_Faultl 0.00 0.00 5,889.00 -12,671.301,135,533.71 5,941,784.00 plan misses target center by 1140176.37usft at 10650.O0usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Polygon Point 1 5,889.00 0.00 0.00 5,941,784.00 Point 2 5,889.00 1.00 1.00 5,941,785.01 1L-231-1_Fault2_M 0.00 0.00 0.00 -12,533.331,134,788.36 5,941,918.00 plan misses target center by 1139445.48usft at 10650.00usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Rectangle (sides W10.00 H2,000.00 D0.00) 1L-23 CTD Polygon Sou 0.00 0.00 0.00 -12,473.541,135,582.77 5,941,982.00 plan misses target center by 1140239.55usft at 10650.00usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Polygon Point 1 0.00 0.00 0.00 5,941,982.00 Point 0.00 -676.75-251.58 5,941,303.99 Point 3 0.00 -1,859.21 1.23 5,940,123.01 Point 0.00 -2,051.23 380.27 5,939,933.02 Point 5 0.00 -2,442.92 314.20 5,939,541.02 Point 6 0.00 -5,424.97 1,020.62 5,936,563.05 Point 7 0.00 -4,717.35 3,012.56 5,937,281.16 Point 8 0.00 -3,504.28 1,692.78 5,938,487.09 Point 9 0.00 -675.70 689.53 5,941,310.03 Point 10 0.00 -175.10 777.17 5,941,811.04 Point 11 0.00 236.83 417.29 5,942,221.02 Point 12 0.00 0.00 0.00 5,941,982.00 1L-231-1-02_Faultl 0.00 0.00 5,940.00 -15,728.221,136,772.64 5,938,734.00 plan misses target center by 1141436.23usft at 10650.00usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Polygon Point 1 5,940.00 0.00 0.00 5,938,734.00 Point 2 5,940.00 1.00 1.00 5,938,735.01 Latitude Longitude 70' 0' 15.296 N 140' 35' 28.071 W 1,675,921.00 70' 0' 17.325 N 140' 34' 43.175 W 1,675,921.00 1,676,442.02 1,676,066.04 1,675,442.06 1,674,454.07 1, 670, 957.03 1,671,577.94 1, 675, 250.01 1, 675, 921.00 1,674.652.00 70' 0' 15.003 N 140° 35' 21.089 W 1, 674, 652.00 1,674,652.99 1,674,898.00 70° 0' 13.283 N 140° 35' 14.728 W 1,676,653.00 69' 59' 41.081 N 140° 34' 38.431 W 1,675,398.00 70° 0' 12.575 N 140° 35' 0.528 W 1,675,398.00 1,675, 398.99 1,674,652.00 70' 0' 15.003 N 140° 35' 21.089 W 1,675,446.00 70° 0' 14.424 N 140' 34' 58.292 W 1,675,446.00 1,675,198.04 1,675,457.09 1,675,837.11 1,675,773.12 1,676,495.28 1,678,483.24 1,677,157.18 1,676,139.04 1,676,224.01 1, 675, 861.99 1.675,446.00 1, 676, 653.00 1, 676, 653.00 1, 676, 653.99 69° 59' 41.081 N 140° 34' 38.431 W 4/24/2018 5:13:08PM Page 4 COMPASS 5000.14 Build 85 ConocoPhillips BA_ KER ConocoPhillips Planning Report BAT a GE company Database: EDTAlaska Sandbox Local Co-ordinate Reference: Well 1L-23 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 1 L-23 @ 130.O0usft (1 L-23) Site: Kuparuk 1 L Pad North Reference: True Well: 1 L-23 Survey Calculation Method: Minimum Curvature Wellbore: 1 L-23L1-01 Design: 1 L-23L1-01_wp04 1L-231-1-01T03 0.00 0.00 5,887.00-12,375.931,133,962.10 5,942,071.00 1,673,825.00 70' 0' 17,738 N 140' 35' 43.864 W plan misses target center by 1138603.19usft at 10650.00usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Point 1 L-231-1 Fault1_M 0.00 0.00 0.00-12,671.301,135,533.71 5,941,784.00 1,675,398.00 70° 0' 12.575 N 140' 35' 0.528 W plan misses target center by 1140191.57usft at 10650.00usft MD (5887.07 TVD,-6376.78 N,-4625.28 E) Rectangle (sides W10.00 1-11,500.00 D0.00) Casing Points Measured Vertical Depth Depth (usft) (usft) 12,250.00 5,887.29 2 3/8" Name Casing Hole Diameter Diameter (in) (in) 2.375 3.000 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 10,650.00 5,887.07 -6,376.78 -4,625.28 TIP/KOP 10,800.00 5,889.06 -6,390.28 -4,774.45 Start 7 dls 10,950.00 5,896.04 -6,398.76 -4,923.83 3 11,175.00 5,896.10 -6,363.06 -5,145.27 4 11,300.00 5,900.89 -6,318.71 -5,261.91 5 11,500.00 5,916.00 -6,258.54 -5,451.52 6 11,700.00 5,918.54 -6,242.80 -5,650.38 7 11,925.00 5,907.70 -6,217.98 -5,873.04 8 12,250.00 5,887.29 -6,078.76 -6,163.63 Planned TD at 12250.00 412412018 5:13.08PM Page 5 COMPASS 5000.14 Build 85 `- Baker Hughes INTEQ BATER ConocoPhillips Travelling Cylinder Report IGHES a GE company Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 1 L Pad Site Error: 0,00 usft Reference Well: 1 L-23 Well Error: 0.00 usft Reference Welibore 1L-231_1-01 Reference Design: 1 L-231_1-01_wp04 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 1 L-23 1 L-23 @ 130.00usft (1 L-23) 1 L-23 @ 130.00usft (1 L-23) True Minimum Curvature 1,00 sigma OAKEDMP2 Offset Datum 2eference 1L-231_1-01_wp04 -iltertype: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference interpolation Method: MD Interval 25.00usft Error Model: ISCWSA )epth Range: 10,650.00 to 12,250.00usft Scan Method: Tray. Cylinder North tesults Limited by: Maximum center -center distance of 1,412.00 usft Error Surface: Pedal Curve Survey Tool Program From (usft) 200.00 9,800.00 10, 650.00 Casing Points Date 4/12/2018 To (usft) Survey (Welibore) 9,800.00 1L-23 (1L-23) 10,650.00 1L-23L1_wp02 (1L-231-1) 12,250.00 1L-23L1-01_wp04 (11--231-1-01) Measured Vertical Depth Depth (usft) (usft) 12,250.00 6,017.29 2 3/8" Tool Name GCT-MS MWD MWD Name Description Schlumberger GCT multi: MWD - Standard MWD - Standard Casing Hole Diameter Diameter 2-3/8 Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Welibore - Design (usft) (usft) (usft) (usft) Kuparuk 1 L Pad 1 L-17 - 1 L-17AL1 - 1 L-17AL1 Out of range 1 L-23 - 1 L-231_1 - 1 L-23L1_wp02 11,484.29 11,475.00 42.58 1.42 42.36 Pass - Minor 1/10 Offset Design Kuparuk 1 L Pad - 1 L-23 - 1 L-231_1 - 1 L-23L1_wp02 Offset Site Error: 0.00 usft Survey Program: 200-GCT-MS, 9800-MWD Rule Assigned: Minor 1/10 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 +NI-S +E/-W Hole Size Centre Distance Deviation (usft) (usft) (usft) (usft) (usft) (usft) (`) (usft) (usft) 1") (usft) (usft) (usft) 10,674.99 6,015.75 10,675.00 6,015.40 0.08 0.11 -34.87 -6,377.51 -4,650.22 2-11/16 0.67 0,66 0.18 Pass- Minor 1/10 10,699.86 6,015,09 10,700.00 6,013.78 0A7 0,22 -34.22 -6,377.48 -4,675,16 2-11116 2.63 0.87 1,94 Pass - Minor 1/10 10,724.55 6,015.09 10,725,00 6,012.29 0.22 0,33 -33.82 -6,376.70 -4,700.10 2-11/16 5.83 1.04 4,97 Pass- Minor 1/10 10,748,95 6,015.72 10,750,00 6,010.94 0.28 0.45 -33.81 -6,375.16 -4,725.02 2-11/16 10,24 1.16 9.25 Pass - Minor 1110 10,772,99 6,016.95 10,775.00 6,009.72 0.35 0.57 -34.00 -6,372.88 -4,749.88 2-11/16 15.87 1.27 14.76 Pass - Minor 1/10 10,796.58 6,018,75 10,800.00 6,008.65 0,41 0,69 -34.28 -6,369.85 -4,774.67 2-11/16 22.67 1.34 21.47 Pass - Minor 1/10 10,821,04 6,020,88 10,825.00 6,007.71 0.49 0.82 -32.51 -6,366.08 -4,799.37 2-11/16 30.15 1.39 28.89 Pass - Minor 1/10 10,845,94 6,022,67 10,850.00 6,006,90 0.56 0.95 -29.91 -6,361,57 -4,823,94 2-11/16 37.52 1.42 36.22 Pass - Minor 1110 10,871.10 6,024.10 10,875.00 6.006,24 0,64 1.08 -27.01 -6,356.31 -4,848,38 2-11/16 44.78 1.44 43.48 Pass - Minor 1/10 10,896,50 6,025.14 10,900.00 6,005,72 0.73 1.22 -23.92 -6,350.33 -4,872,64 2-11/16 51.94 1.45 50.68 Pass - Minor 1/10 10,922.14 6,025.80 10,925.00 6,005.35 0.82 1.35 -20.68 -6,343.62 -4,896.72 2-11/16 59.01 1.45 57.88 Pass- Minor 1/10 10,947.99 6,026.04 10,950.00 6,005.11 0,91 1.49 -17,32 -6,336.19 -4,920,59 2-11/16 66.03 1.45 65,16 Pass - Minor 1/10 10,974.02 6,026.05 10,975.00 6,005.01 1,02 1.63 -13.78 -6,328,05 -4,944.23 2-11/16 73.01 1.44 72.78 Pass - Minor 1/10 11,000.30 6,026,06 11,000.00 6,005.06 1,12 1.77 -10.42 -6,319,20 -4,967.61 2-11/16 79.96 1.45 79,74 Pass - Minor 1/10 11.026,87 6,026.06 11,025.00 6,005.25 1,23 1.91 -7,20 -6,309.65 -4,990,71 2-11/16 86.88 1.46 86.65 Pass - Minor 1/10 11,053.92 6,026.07 11,050.00 6,005.61 1.35 2.06 -4,15 -6,300.10 _5,013.81 2-11/16- 93.04 1.45 92.81 Pass - Minor 1/10 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 4/12/2018 3:43:23PM Page 2 COMPASS 5000.14 Build 85 r 4' C a N Y Y 22 � J N a MN N G a�3ao'' M J c a 0 .] a N a N a IZ P k. ----_---- ------- -- ------- _H V � N � -. 1L-23 I-Ol_ 01-- N N O N ~ 1 -23L -01 T 2- ------ .. j I 23L1- 1 _ T03 - ----- j C 0. j I lo J N ..7 0 0 0 0 0 0 0 0 0 0 0 0 0 (ui/8sn 009) (+)upoN/(-)u1noS 600 1200 1800 2400 3000 3600 azao C 3800 5400 v R 5000 i600 7200 7800 WOO )000 )600 0200 0800 N r'n JM p 0 N m N o �aa � d m tC0 < - M N tl' m N M O C O (A Lriv c^i Lcir�oMri aZ >N I�-N C'co LA to f`m �� V LO yNj Lin in LmO cO co M w ti '- m 0000000000 o 0 0 0 0 0 0 0 0 0 N J N m0 0 0 o Ci 0 0 0 Ln O m ~ O O �2 cD N N M r °o m] Cl 0 0 0 0 0 m000000000 r` p6 ra m L A M r N m c t M N 'crmNO)Lf)MOm L J.1 L i') �r M L o r O N M M � � ti m + CNO n " - mLoto oo clj J w0) (n m m40 LD r� O m c0 Q OJ M , �N r+O r-LA m O) r: w Lo Z o co ri m m N t` as + r• m m to M M M M M N N N O Q f.0 c0 t0 CO c0 cD (O cD t0 � W N r` m v o rno v o rn (n O O O r m O L n� N mr- 0 n o)co t0 O COm f� n CO >mmD7 O)Or r Om )" mmmmorn— r Ln Ln Ln Ln Ln Ln Zc ' N O m M N m V r Q V'NNOm Iq 7N O] tlo N N N N N N N N Cl) r nI D C mOd7m r` mID •V �p OO)Ln tom � p mmmoomm0'l m0 W O + p o 0 0 0 0 0 0 0 0 O O O O O o 0 0 0 O C i O L M 0 0 0 t n 0 Ln O LM f� O O O N LfJ f 0 m O r M L 2 r O) N 0 o O r rrr - o C� _ _ _ _ p U.- zo r 9000 8850 a N a 8700 ` 8550 8400 8250 8 7 7 7 7 • 7 7 I 7 6 0 6 N o 6 N M 6 c6 .- O.L I -1'I£Z I a 6 6 5 5 Zol 0-11If - 11.------------ .-- N ml 5 5 m --- s 5 _----- 4 4 V1 �I 4 `1 _ 4 p N F 4 I N 4 0 4 Y] 0 3 Lil N 0 3 r1 a N a \ 3 � N� 3 3 O O O O O O O O O O O J ut sn da uoi o anz ( /a3 OSI) u� Q I � A .L 100 950 800 650 500 350 200 050 900 750 . 600kn r kn 450 �' O 300 OO O 150 N cz 000 1; O 850 y 700 U 550 400 250 100 950 800 650 500 350 200 050 900 750 600 450 300 KUP PROD 1L-23 ConocoPhillips Alaska. Inc. ... Well Attributes Max Angle & MD TO Wellbore API/UWI 500292216700 Field Name Wellbore Status KUPARUK RIVER UNIT PROD ri T) MD(ftKB) Act 62.82 3,100.00 Sim(ftK8) 10,346.0 Comment H25 SSSV: TRDP P (pp.) Data 20 Annotation Entl 12/21/2015 Last WO: Date KB-Grd (11) Rig 8/24/1992 42.99 Release Data 5/14/1991 1L-23, 4/25R018 551'.43 AM Last Tag Vertical schematic actual Annotation I Depth Last Tag: RKB 10, (ftKe) End 147.0 4/21/2018 Date Last fergusp Mod By _................ _.-....................... _ _... HANGER; 39A CONDUCTOR; 44.0-78.0 SAFETY VLV; 1.978.1 GAS LIFT; 2.057.6 GAS LIFT; 3,779a GAS LIFT; 4,938.2 SURFACE; 43.0-5,301 GAS LIFT; 5,815.0 GAS LIFT; 6,716.5 GAS LIFT; 7,707.3 GAS LIFT; 8,671.2 GAS LIFT; 9,588.3 CHEM CUT; 9,618.0 PER; 9,638.0 PACKER; 9,651.7 NIPPLE; 9,668 0 sos; s,7oo.s APERF; 9,794.0-9,874.0 RPERF; 9.798.0-9'a 4.0� IPERF; 10,012.0-10,050.0 FRAC; 10,U12.O1 a RPERF; 10,012.0-10,050e FISH; 10,060.0 IPERF; 10,1560-10,165.0 FRAC; 10, 156.0 PRODUCTION; 43.2-10,342.9 Last Rev Reason Annotation End DataLast Mad By Rev Reason: Cut Tbg 4/24/2018 Cendijw I I Casing Strings Casing Description CONDUCTOR OD(in) 16 ID (in) Top 15.060 (kKB) 44.0 Set Depth (kKB) Sel Depth 78.) (ND)... WULen(51 78.0 62.58 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (in) 9 5/8 ID (in) lop 8,921 (kKB) 43.0 Set Depth (kKB) Set Depth 5,306.3 (ND)... WULen 3,609.3 (I... Gratle 36,00 J-55 Top Thread BTC Casing Description PRODUCTION OD (in) 7 I ID (in) I Top 6.276 (RKB) 43.2 setDepth (kKB) Sat Deplh 10,342.9 (7VO)... WULen 6,289.7 (I... Grade 26.00 J-55 Top Thread BTC-MOD Tubing Strings Tubing Description String Ma... ID (in) Top (RKB) Set Depth lj% Set Depth (ND) (... Wt (Ibkt) Grade Tap Connection TUBING WO 3 i/2 2.992 39A 9,701.8 5,942.3 9.30 J-55 EUE8rdABMOD Completion Details Top Top (ftKB) (ND) (kKB) Top Incl V Item Des Can Nominal ID (in) 39.4 39.4 0.03 HANGER FMC GEN IV TUBING HANGER 3.500 1,978.1 1,833.4 41.30 SAFETY VLV CAMCO TRDP-4A-RO SAFETY VALVE 2.812 9,638.0 5,908.3 57.89 PBR BAKER PBR 3.000 9,651.7 5,915.6 57.86 PACKER BAKER HB RETRIEVABLE PACKER 2.890 9,668.0 5,924.3 57.82 NIPPLE CAMCO D NIPPLE SEAL BORE NO GO (Trouble getting 20' Perf Guns thnl D-nipple 9/l/92; REPERF 912/92) 2.750 9,700.9 5,941.8 57.73 1 SOS I BAKER SHEAR OUT SUB 2.992 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top Top (RKB) (ND) (RKB) Top Intl (") Des Co. Run Date ID (in) 9,616.0 5,896.E 57.95 1 CHEM CUT CUT TUBING W/ 2.625" OD CHEMICAL CUTTER 4/24/2018 1.994 10,060,0 6,135.8 57.39 FISH 1 1/2" GLV Fell to Rathole 4/6/1995 0.000 Perforations & Slots Top (RKB) Btm (RKB) Top (ND) (RKB) Btm (ND) (RKB) Zone Shot Dens (shotskl Data ) Type Co. 9,794.0 9,874.0 5,991.9 6,035.2 C-4, 1L-23 8/17/1991 6.0 APERF 21/8"Flow Jet; 0deg. phasing 9,796.0 9,874.0 5,992.9 6,035.2 C-4, -23 UNIT B, 1L 9/2/1992 4.0 RPERF 2.5" Hollow Came; 180 deg. ph; Oriented 14 deg. CCW 10,012.0 10,050.0 6,110.0 6,130.5 A-5,1L-23 3/29/2018 6.0 RPERF 2.0"OD POWERJET OMEGA, 6 SPF, 60 DEG PHASED. 10,012.0 10,050.0 6,110.0 6,130.5 A-5,IL-23 6/19/1991 4.0 IPERF 41/2" Carrier; 180 deg. ph; Oriented 12 deg. CCW 10,156.0 10,165.0 6,187.7 6,192.5 A-4,1L-23 6/19/1991 4.0 IPERF 41/2" Carrier, 180 deg. ph; Oriented 12 deg. CCW Stimulations & Treatments Proppant Designed (Ib) Proppant In Formation (Ib) Data 8l1/1991 Stimulations & Treatments Stg # Top (RKB) Btm (RKB) Date Stim/Treat Fluid Vol Clean Pump (bb1) Vol Slurry (bbl) 1 10,156.0 10,165.0 8'111991 Proppant Designed (lb) I Proppant In Formation (Ib) Date BIt11991 Stimulations & Treatments Sly # Top (RKB) Bt. (RKB) Data Stim/Treal Fluid Vol Clean Pump (bbp Vol Slurry (bbl) 1 10,012.0 10,050.0 8/l/1991 Mandrel Inserts St all N Top (RKB) Top (ND) (RKB) Make Model OD (in) Se, Valve Latch Type Type PortSize (in) 7RO Run (psi) Run Date Com 1 2,057.6 1,892.3 MMH FMHO 1 GAS LIFT DMY BK 0.000 0.0 4/22/2018 2 3,779.8 2,805.1 MMH FMHO 1 GAS LIFT DMY BK2 0.000 0.0 12/14/1992 3 4,938.2 3,406.4 MMH FMHO 1 GAS LIFT DMY BK 0.000 0.0 4/21/2018 4 5,815.0 3,899.6 MMH FMHO 1GAS LIFT DMY BK2 0.000 0.09119/2005 5 6,716.5 4,397.2 MMH FMHO 1 GAS LIFT DMY BK 0.000 0.0 4/21/2018 6 7,707.3 4,905.5 MMH FMHO 1 GAS LIFT DMY BK 0.000 0.0 4/2l/2018 7 8,671.2 5,402.E MMH FMHO 1 GAS LIFT DMY SK2 0.000 0.0 8/8/2005 8 9,588.3 5,881.9 CAMCO MMG-2 1 1/2 GAS LIFT OPEN RK 0.0 4/22/2018 Notes: General & Safety End Date Annotation 10/5/2010 NOTE: View Schematic w/ Alaska Schematic9.0 \ \ E } { # In (n_ \ § / § - CO( � co\ \ _ �= e S co m` E/ ui a /e £ \ § �- § E \ ƒf CD% ) \ k 2� ML \ 2 t kk 0 §. kLO §\ CD "IdV/Lo \// \/\ )p0 . \ \\\ §\\ I \ �00 co \ j(/ c VA CM if \ F- ) m0 a)ƒ . 2/=� t SCN C /2 k \0 k\/ ot=== &G°®§\ 0 N)&/ z ,/Z.. { ; § gg -- \ / \§ cl \ \ (0 EL oo \ \\ \\ / yg j ( i / TRANSMITTAL LETTER CHECKLIST WELL NAME: 1<2a IZ_' Z �5 z-1 ' �� PTD: U e�:)s7E V'Develo ment Service Exploratory Strati ra hic Test Non -Conventional p — P rY g p FIELD: POOL: 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. ?_ , API No. 50-6z -7- 60 . / (If last two digits Production should continue to be reported as a function of the original V 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 en it . 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 1L-231_1-01 Program DEV Well bore seg d❑ PTD#: 2180580 Company CONOCOPHILLIPS ALASKA, INC. Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven. gas conforms to AS31.05.030GA.A),(j.2.A-D) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ NA_ - - _ _ _ _ _ _ _ _ _ - - - - - - - - - - _ _ - _ - - - - - _ - - - - - 1 Permit fee attached---------------------------------------- --- NA---------------------------- -------------------- --- 2 Lease number appropriate_ - - - - - - - - - - - Yes - _ - _ With addition: Top Productive Interval -lies in ADL0025664; TD lies -in ADL0025665._ 3 Unique well name and number - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ . 4 Well located in_a_defined-pool --- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Kuparuk River Oil Pool, governed by Conservation Order No. 432D 5 Well located proper distance from drilling unit _boundary- - - - Yes Conservation Order No. 432D has no intenvell_spacing_restrictions. Wellbore_will_ be more than 500' from - 6 Well located proper distance from other wells_ - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - an external property line -where -ownership or landownership -changes. As proposed, -well will 7 Sufficient acreage -available in -drilling unit_ Yes - - - conform to_ spacing- requirements - _ - - - - - - - - 8 If -deviated, is wellbore plat -included - - - - - - - - - - - - - - - - . - - Yes - - - - - - _ _ - . 9 Operator only affected party - - -- ------- - - - - -- - - -- -- Yes 10 Operator has_ appropriate bond in -force --------------------------------- Yes --- --------------------------- Appr Date 11 Permitcan be issued without conservation order_ - - - - - Yes - 12 Permit can be issued without administrativ_e_approval - - - - - - - - - - - - - - - - - - - - - - - Yes - - SFD 5/11/2018 13 Canpermitbeapproved before 15-day_wait ---------------- - - - - - - - - - - - - - Yes ----------------------- 14 Well located within area and -strata authorized by Injection Order # (put 10# in -comments). (For-! NA- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 15 All wells within 1/4_mile-area-of review identified (For service well only)_ - - - - . - - - - _ _ NA_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 16 Pre -produced injector; duration of pre production less than 3 months_ (For_service well only) - _ NA_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 18 Conductor string -provided - - - - - - - - - - - - - - - - ----------------------_ _ _ NA_ - _ - - . _ Conductor set-in KRU 1L-23 Engineering 19 Surface casing_ protects all -known_ USDWs - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ - - - - - - - Surface casing set in KRU 1L-23 20 CMT- vol adequate to circulate -on conductor & surf _csg - - - - - - - - - - - - - - - - - - - - - NA_ - - - - - Surface casing set in KRU 1 L-23 - - - _ 21 CMT-vo1_ adequate_ to tie -in -long string to surf csg_ - - - - - - - - - - - - - - - - - - NA_ - - - - - - - - - - - - - - - - - - - - - - - 22 CMT_will coverall known -productive horizons_ - - - No_ Productive interval will be completed with _uncemented slotted_ liner_ - - -------------------- 23 Casing designs adequate for C,_T, B &_ permafrost- - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - 24 Adequate -tankage or reserve pit - - - - - - - - - -- - - - ----- Yes - - - Rig has steel tanks; all waste -to approved disposal wells_ - - - - - - - - - - - - - - - - 25 If_a_re-drill, has_a 10-403 for abandonment been approved . N _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 26 Adequate wellbore separation proposed- - - - _ _ Yes - - - - - - _ Anti -collision analysis complete; no major risk failures - - 27 If_diverter required, does it meet regulations_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ - - - - - - _ _ _ _ _ - _ _ _ _ _ _ - - - _ - - _ _ - _ - - - _ _ - - - - - - Appr Date 28 _Drilling fluid program schematic _& equip list adequate_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes - - - - - - _Max formation pressure is_4393 psig(13.3 ppg_EMW); will drill_w/ 8,6_ppg EMW and maintain ov_erbal_w/ MPD VTL 5/29/2018 29 BOPEs,-do they meet regulation] - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - _ - . - - . -- 30 DOPE -press rating appropriate; test to_(put psig in comments)_ - - - - - - - Yes - - - - - - - MPSP is 3760 psig; will test SQPs-to 4000_psig - - - - - - - - - - - - - - - - - - - - - - - - 31 Choke_manifold complies WAPIRP-53 (May 84)- - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - 32 Work will occur without operation shutdown- - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - _ _ _ _ _ _ _ _ _ _ - - 33 Is presence of 112S gas probable_ _ - - _ - - - - - - - - - - - - - - - - - - - - - - - - Yes . . ... _ 112S measures required_ _ _ _ _ _ _ _ - 34 Mechanical_condition of wells within AOR verified (For service well only) - - - - - - - - - NA_ 35 Permitcan be issued w/o hydrogen_ sulfide measures - - - - - - - No Wells _on_1L-Pad are H2S-bearing._H2S_measures required-- - - - - - - - - - - - - - - - - Geology 36 Data -presented on potential overpressure zones- - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - Expected reservoir pressure is 10.6ppg EMW_(with a maximum of_1.3.3_ppg EMW)._ Well will be Appr Date 37 Seismicanalysisof shallow gas -zones- - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - _drilled using 8.6_ppg _m_ud,_a coiled -tubing rig, and managed drilling technique to SFD 5/11/2018 38 Seabed condition survey (if off -shore) -------------------------_ _ _ _ _ _ _ _ NA_ - - - - - - control formation pressures -and maintain -shale stability._ - - 39 Contact name/phone for weekly_ progress reports [exploratory only] _ _ _ _ _ _ _ - _ - NA_ - - - - - - Onshore development well branch. Geologic Engineering Public Commissioner: Date: Commissioner: Date mmission Date
