Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
218-011
Winston, Hugh E (CED) From: Winston, Hugh E (CED) Sent: Monday, January 27, 2020 9:33 AM To: william.r.long@cop.com Cc: Loepp, Victoria T (CED); Guhl, Meredith D (CED) Subject: KRU 1A-201-1-03 Permit Expired Hi William, The Permit to drill for well KRU 1A-20L1-03 which was issued to CPAI on January 24th 2018, has expired under Regulation 20 AAC 25.005 (g). The permit has been marked expired in its history file and in the AOGCC database. Please let me know if you would like any follow up information on this permit. Huey Winston Statistical Technician Alaska Oil and Gas Conservation Commission hugh.winston@alaska.gov 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 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 1 A-20L 1-03 ConocoPhillips Alaska, Inc. Permit to Drill Number: 218-011 Surface Location: 1091' FSL, 314' FWL, SEC. 5, T11N, RIOE, UM Bottomhole Location: 336' FNL, 984' FEL, SEC. 8, T11N, R10E, UM Dear Mr. Ohlinger: Enclosed is the approved application for permit to re -drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 190-162, API No. 50-029- 22112-00-00. 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, *aniel T. Seamount, Jr. Commissioner DATED this 2 / day of January, 2018. STATE OF ALASKA AL r1 OIL AND GAS CONSERVATION COMMI' ON PERMIT TO DRILL 20 AAC 25.005 RECEIVED JAN 18 2018 1 a. Type of Work: Drill ❑ Lateral 'El Redrill ❑ Reentry ❑ 1 b. Proposed Well Class: Exploratory -Gas ❑ Service - WAG ❑ Service - Disp ❑ Stratigraphic Test ❑ Development - Oil ❑v Service - Winj ❑ Single Zone ❑ Exploratory - Oil ❑ Development -Gas ❑ Service - Supply ❑ Multiple Zone ❑ 1 c. Speci if s�p ,�F, �for: CoalbedsP�a�"Fly�fiates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Bond: Blanket ❑� . Single Well ❑ Bond No. 5952180 • 11. Well Name and Number: Kuparuk Riv Unit 1A-201-1-03 + 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 12000' TVD 6204' ss 12. Field/Pool(s): Kuparuk River ^ Kuparuk River Oil 4a. Location of Well (Governmental Section): Surface: 1 091'FSL, 314' FWL, Sec 5, T11 N, R10E, UM Top of Productive Horizon: 1791' FSL, 290' FWL, Sec 4, T11 N, R10E, UM Total Depth: 336' FNL, 984' FEL, Sec 8, T11 N, R10E, UM 7. Property Designation: ADL 25648, 25647 8. DNR Approval Number: LONS 83-134 13. Approximate Spud Date: 1/25/2018 9. Acres in Property: 5029 14. Distance to Nearest Property: 22000' 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 540180 y- 5971179 Zone- 4 ' 10. KB Elevation above MSL (ft): 102 GL / BF Elevation above MSL (ft): 58.9 15. Distance to Nearest Well Open to Same Pool: 400' (1A-04A) 16. Deviated wells: Kickoff depth: 9200 feet Maximum Hole Angle: 103 degrees , 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Downhole: 3472 ' Surface: 2850 ' 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2-3/8" 4.6 lb/ft L-80 ST-L 2800' 8580' 6311' 12000' 6204' Slotted Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 9034' Total Depth TVD (ft): 6721' Plugs (measured): 8665' Effect. Depth MD (ft): 9010, Effect. Depth TVD (ft): 6705' Junk (measured): N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 90, 16" 222 sx AS 1 90, 90, Surface 4961' 9-5/8" 1300 sx AS III, 470 sx Class G 4961' 3901' Production 9010, 7" 275 sx Class G Perforation Depth MD (ft): 8344' - 8506', 8747' - 8810' Perforation Depth TVD (ft): 6252' - 6363', 6526' - 6569' Hydraulic Fracture planned? Yes❑ No ❑� 20. Attachments: Property Plat ❑ BOP Sketch Diverter Sketch Drilling Program 8 Seabed Report Time v. Depth Plot ❑ Drilling Fluid Program Shallow Hazard Analysis ❑ 20 AAC 25.050 requirements [A 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: James Ohlinger Contact Email: William. R.Lon COP.com Authorized Title: Staff CTD Engineer Contact Phone: 263-4372 Authorized Signature: Date: 0-10-1 Commission Use Only Permit to Drill Number: - API Number: 50- - a p2 - 3 - Q6 Permit Approval Date: See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: �O� �fS 3 D D ` Samples req'd: Yes ❑ No Q Mud log req'd: Yes ❑ No [� �J 5L _9 HZS measures: Yes [' No ❑ Directional svy req'd: Yes � No ❑ AkI k-t 1J Icy l't l�f� { ft� 7 r�'t- tV 7;� �Ucqtion re d: Yes No Inclination-onl sv re d: Yes �(�q' ❑ Y Y q' ❑ No LrJ V4 f j e4Y7e-z�' tD a o ,�� c� �-, /j /s�(� / Post initial injection MIT req'd: Yes ❑ No l 5 CJ rGf 17 tC� f0 G� I O LcJ ytL1 AC I C ,e O fa cj G ✓! �/ P D 1 %t �f ii APPROVED BY ` / � � / � , Approved by: 22 T OMMISSION Date: ( l 1 4, � , —) fQ 7111Submit Form and Fprm 10-401 �RJewi�e 017 /� h s permit f3 valid for 24 moWXs Jrgrnjth�la10 p7'-1P7TJV r TEr 20 AAG 25.0U5(g) Attachments in Duplicate ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 January 18, 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 two additional laterals out of the KRU 1A-20 (PTD# 190-162) using the coiled tubing drilling rig, Nabors CDR3-AC. Current drilling operations have crossed a section of reservoir that should support four laterals as opposed to the two originally planned. 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 CTD objective will be to drill two additional laterals (1A-201_1-02 & 1A-201_1-03), targeting the Kuparuk C- sand interval. The work is scheduled to continue immediately following the L1 and L1-01 laterals currently being drilled by CDR3-AC. Attached to this application are the following documents: — Permit to Drill Application Forms (10-401) for 1A-201_1-02 & 1A-20L1-03 — Detailed Summary of Operations — Directional Plans for 1A-201_1-02 & 1A-201_1-03 — Current wellbore schematic — Proposed wellbore 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 1A-201-1, 1A-201-1-01, 1A-201-1-02, & 1A-1-1-03 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....................................................................... 6 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 6 16. Attachments....................................................................................................................................6 Attachment 1: Directional Plans for 1A-20, 1A-201-1, 1A-201-1-02, and 1A-201-1-03 laterals..........................................6 Attachment 2: Current Well Schematic for 1A-20............................................................................................................6 Attachment 3: Proposed Well Schematic for 1A-20, 1A-201-1, 1A-201-1-02, and 1A-201-1-03 laterals ............................6 Page 1 of 6 January 10, 2018 PTD Application: 1A-20L1, 1A-201-1-01, 1A-201_1-02, & 1A-201_1-03 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 1A-201-1, 1A-201-1-01, 1A-201-1-02, and 1A-201-1-03. The 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 form for surface and subsurface coordinates of the 1A-20, 1A-201-1, 1A-201-1-02, and 1A-201-1-03. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR3-AC. BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. Using the maximum formation pressure in the area of 3472 psi in 1A-04 (i.e. 10.8 ppg EMW), the maximum potential surface pressure in 1A-20, assuming a gas gradient of 0.1 psi/ft, would be 2850 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 1A-20 was measured to be 2431 psi (7.5 ppg EMW) on 11/17/2017. The maximum downhole pressure in the 1A-20 vicinity is to the south in the 1A-04 injector at 3472 psi (10.8 ppg EMW) measured on 7/10/2017. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) Wells on 1A pad have injected gas, so there is a chance of encountering free gas while drilling the 1A-20 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 1A-20 lateral will be losses to the formation. Managed pressure drilling (MPD) target pressure will be reduced to manage losses to the formation in the event of significant losses. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 1A-20 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 January 10, 2018 PTD Application: 1A-20L1, 1A-201-1-01, 1A-201-1-02, & 1A-201-1-03 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Lateral Name Liner Top MD Liner Btm MD Liner Top TVDSS Liner Btm TVDSS Liner Details 1 A-20L1 9,484' 11, 575' 6,188' 6,156' 2-3/8", 4.7#, L-80, ST-L slotted liner 1A-20L1-01 10,500' 12,000' 6,160' 6,238' 2-3/8", 4.7#, L-80, ST-L slotted liner 1A-20L1-02 9,200' 12,000' 6,250' 6,286' 2-3/8", 4.7#, L-80, ST-L slotted liner 1A-201_1-03 8,580' 12,000' 6,311' 6,204' 2-3/8", 4.7#, L-80, ST-L slotted liner Existing Casing/Liner Information Category OD Weight (ppf)MD Grade Connection Top Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 65 H-40 Welded 0' 90, 0' 90, 1640 670 Surface 9-5/8" 36.0 J-55 BTC 0' 4,961' 0' 3,901' 3520 2020 Production 7" 26.0 J-55 BTC MOD 0' 2,343' 0' 2,084' 4980 4330 Production 7" 26.0 K-55 BTC 2,384' 9,010' 2,084' 6,705' 4980 4330 Tubing 4" 11.0 J-55 DSS-HTC 0' 4,192' 0' 3,354' 6300 6590 Tubing 3-1/2" 9.3 L-80 EUE8rd 4,192' 8,628' 3,354' 6,446' 10160 10540 Tubing 2-7/8" 6.5 J-55 EUE8rd 8,628' 8,677' 6,446' 6,479' 7260 7680 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 PowerVis mud (8.6 ppg) - Drilling operations: Chloride -based PowerVis 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: The well will be loaded with 11.8 ppg NaBr completion fluid in order to provide formation over -balance and shale 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 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". Page 3 of 6 January 10, 2018 PTD Application: 1A-20L1, 1A-201-1-01, 1A-201-1-02, & 1A-201-1-03 In the 1A-20 laterals we will target a constant BHP of 11.8 ppg EMW at the window. The constant BHP target will be adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if increased reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed for improved borehole stability. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Pressure at the 1A-20 Window (8587' MD, 6316' TVD) Using MPD Pumps On 1.8 b m Pumps Off C-sand Formation Pressure 7.5 2431 psi 2431 psi Mud Hydrostatic 8.6 2825 psi 2825 psi Annular friction i.e. ECD, 0.03 si/ft 258 psi 0 psi Mud + ECD Combined no chokepressure) 3083 psi Overbalanced 2825 psi Overbalanced Target BHP at Window 11.8 3875 psi 3875 psi Choke Pressure Required to Maintain Target BHP 792 psi 1050 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 KRU 1A-20 is a Kuparuk C sand producer equipped with 4" x 3-1/2" tubing, and 7" production casing. Pre -rig work is being conducted to cement off the 3-1/2" x 7" annulus between two production packers to provide stability for a CTD kickoff (approved sundry number 317-544). The IA-20L1, lA- 20L1-01, 1 A-20L1-02, and 1A-201-1-03 CTD laterals will target the C sands to the south and north of 1 A- 20. The laterals will increase recovery and add additional resources. Pre-CTD Work 1. E-line: Dummy GLV's, punch holes in tubing 2. Coil: Set cement retainer, cement off 3-1 /2" x 7" annulus between production packers 3. h line: Set whipsteek 4. Prep site for Nabors CDR3-AC. Page 4 of 6 January 10, 2018 PTD Application: 1A-20L1, 1A-201_1-01, 1A-201_1-02, & 1A-201_1-03 Rig Work MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPS, test. a. Make cleanout run to below whipstock set depth. b. Set thru tubing whipstock. 1A-20L1 Lateral (C sand -south) a. Mill 2.80" window at 8587' MD. b. Drill 3" bi-center lateral to TD of 12028' MD. c. Run 2-3/8" slotted liner with aluminum billet from 1 1.575' up to 9484' MD. 1 A-20L 1 -0 1 Lateral (C sand - north) a. KO billet at 9484' and drill 3" bi-center lateral to TD of 12000' MD. b. Run 2-3/8" slotted liner with aluminum billet from TD up to 10,500' MD. 1 A-20L 1-02 Lateral (C sand - north) a. KO billet at 10500' and drill 3" bi-center lateral to TD of 12000' MD. b. Run 2-3/8" slotted liner with aluminum billet from TD up to 9200' MD. 1A-20L1-03 Lateral (C sand - south) a. KO billet at 9200' and drill 3" bi-center lateral to TD of 12000' MD. b. Run 2-3/8" slotted liner with deployment sleeve from TD up to 8580' MD. 6. Freeze protect, ND BOPS, and RDMO Nabors CDR3-AC rig. Post -Rig Work 2. Install GLV's 3. Return well 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 undeployment, the steps listed above are observed, only in reverse. Page 5 of 6 January 10, 2018 PTD Application: 1A-201-1, 1A-201_1-01, 1A-201-1-02, & 1A-201-1-03 Liner Running - The 1A-20 laterals will be displaced to an overbalancing fluid prior to running liner. See "Drilling Fluids" section for more details. - While running 2-3/8" slotted liner, a joint of 2-3/8" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2-3/8" rams will provide secondary well control while running 2-3/8" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). 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 A-20L1 22000' 1 A-20L1-01 22000' 1A-20L1-02 22000' 1A-20L1-03 22000' - Distance to Nearest Well within Pool Lateral Name Distance Well 1A-20L1 390' 1A-04A 1A-20L1-01 645' 1G-121-1-01 1A-201-1-02 655' 1G-121-1-01 1 A-20L1-03 400' 1 A-04A 16. Attachments Attachment 1: Directional Plans for IA-20, 1 A-20L 1, 1 A-20L 1-02, and 1 A-20L 1-03 laterals Attachment 2: Current Well Schematic for 1A-20 Attachment 3: Proposed Well Schematic for 1A-20, IA-20L1, 1A-20L1-02, and 1A-20L1-03laterals Page 6 of 6 January 10, 2018 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup1 Kuparuk River Unit Kuparuk 1A Pad 1 A-20 1A-20L1-03 Plan: 1A-20L1-03 wp00 Standard Planning Report 09 January, 2018 BER TGHES GE company ConocoPhillips Database: EDT Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kupl Project: Kuparuk River Unit Site: Kuparuk 1A Pad Well: 1 A-20 Wellbore: 1 A-20L1-03 Design: 1 A-20L1-03_wp00 ConocoPhillips Planning Report Local Co-ordinate Reference: Well 1A-20 TVD Reference: Mean Sea Level MD Reference: 1A-20 @ 102.00usft (1A-20) North Reference: True Survey Calculation Method: Minimum Curvature Project Kuparuk River Unit. North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor BAF�NGHES a GE company Site Kuparuk I Pad Site Position: Northing: 5,971,467.26usft Latitude: 70' 19' 58.741 N From: Map Easting: 540,178.17usft Longitude: 149' 40' 26.679 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.31 ° Well 1 A-20 Well Position +N/-S 0.00 usft Northing: 5,971,179.05 usft Latitude: 70' 19' 55.906 N +E/-W 0.00 usft Easting: 540,180.17 usft Longitude: 149' 40' 26.666 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 1A-201-1-03 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2017 2/1/2018 17.24 80.91 57,475 Design 1A-20L1-03_wp00 ` Audit Notes: Version: Phase: PLAN Tie On Depth: 9,200.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (') 0.00 0.00 0.00 225.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (°) (1 (usft) (usft) (usft) (°I100ft) (°/t00ft) (°/100ft) (°) Target 9,200.00 103.27 212.52 6,250.32 701.88 5,253.67 0.00 0.00 0.00 0.00 9,400.00 91.08 219.47 6,225.36 541.83 5,137.22 7.00 -6.10 3.47 150.00 9,475.00 90.98 224.72 6,224.01 486.20 5,086.97 7.00 -0.13 7.00 91.00 9,725.00 90.94 242.22 6,219.79 337.99 4,886.89 7.00 -0.02 7.00 90.00 9,975.00 90.29 259.71 6,217.09 256.78 4,651.49 7.00 -0.26 7.00 92.00 10,225.00 88.78 242.27 6,219.14 175.67 4,416.05 7.00 -0.61 -6.97 265.00 10,675.00 88.43 210.77 6,230.37 -129.98 4,093.72 7.00 -0.08 -7.00 269.00 11,225.00 90.64 172.33 6,234.99 -658.76 3,985.72 7.00 0.40 -6.99 273.00 11,525.00 92.39 193.26 6,226.97 -956.62 3,971.21 7.00 0.58 6.98 85.00 11,900.00 93.03 166.99 6,208.94 -1,327.91 3,970.38 7.00 0.17 -7.01 272.00 12,000.00 93.00 174.00 6,203.67 -1,426.34 3,986.86 7.00 -0.02 7.01 90.00 11912018 8:47:14PM Page 2 COMPASS 5000.14 Build 85 ConocoPhillips BAT BA- ICER ConocoPhillips Planning Report F1 IGHES GE company Database: EDT Alaska Sandbox Local Co-ordinate Reference: Well 1A-20 Company: ConocoPhillips (Alaska) Inc. -Kup1 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 1A-20 @ 102.00usft (1A-20) Site: Kuparuk 1A Pad North Reference: True Well: 1A-20 Survey Calculation Method: Minimum Curvature Well bore: 1 A-20L1-03 Design: 1A-201-1-03 wp00 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +El-W Section Rate Azimuth Northing Easting (usft) (°) (°) (usft) (usft) (usft) (usft) (°/100ft) (°) (usft) (usft) 9,200.00 103.27 212.52 6,250.32 701.88 5,253.67 -4,211.21 0.00 0.00 5,971,908.99 545,429.49 TIP/KOP 9,300.00 97.19 216.04 6,232.56 620.63 5,198.26 -4,114.58 7.00 150.00 5,971,827.46 545,374.52 9,400.00 91.08 219.47 6,225.36 541.83 5,137.22 -4,015.69 7.00 150.63 5,971,748.34 545,313.91 Start 7 dls 9,475.00 90.98 224.72 6,224.01 486.20 5,086.97 -3,940.83 7.00 91.00 5,971,692.45 545,263.96 3 9,500.00 90.98 226.47 6,223.58 468.71 5,069.11 -3,915.83 7.00 90.00 5,971,674.86 545,246.20 9,600.00 90.97 233.47 6,221.87 404.44 4,992.60 -3,816.29 7.00 90.03 5,971,610.19 545,170.04 9,700.00 90.95 240.47 6,220.20 349.98 4,908.83 -3,718.54 7.00 90.15 5,971,555.28 545,086.57 9,725.00 90.94 242.22 6,219.79 337.99 4,886.89 -3,694.55 7.00 90.27 5,971,543.18 545,064.70 4 9,800.00 90.75 247.47 6,218.69 306.12 4,819.04 -3,624.04 7.00 92.00 5,971,510.95 544,997.03 9,900.00 90.49 254.46 6,217.60 273.53 4,724.57 -3,534.19 7.00 92.08 5,971,477.86 544,902.74 9,975.00 90.29 259.71 6,217.09 256.78 4,651.49 -3,470.67 7.00 92.15 5,971,460.71 544,829.77 6 10,000.00 90.14 257.97 6,217.00 251.94 4,626.97 -3,449.91 7.00 -95.00 5,971,455.74 544,805.27 10,100.00 89.53 250.99 6,217.29 225.19 4,530.68 -3,362.91 7.00 -95.01 5,971,428.49 544,709.13 10,200.00 88.93 244.02 6,218.64 186.96 4,438.35 -3,270.59 7.00 -94.99 5,971,389.76 544,617.02 10,225.00 88.78 242.27 6,219.14 175.67 4,416.05 -3,246.84 7.00 -94.89 5,971,378.36 544,594.78 6 10,300.00 88.69 237.02 6,220.80 137.80 4,351.37 -3,174.32 7.00 -91.00 5,971,340.14 544,530.31 10,400.00 88.59 230.02 6,223.17 78.40 4,271.03 -3,075.51 7.00 -90.88 5,971,280.32 544,450.30 10,500.00 88.52 223.02 6,225.70 9.66 4,198.54 -2,975.64 7.00 -90.72 5,971,211.19 544,378.18 10,600.00 88.46 216.02 6,228.34 -67.41 4,134.97 -2,876.20 7.00 -90.54 5,971,133.80 544,315.03 10,675.00 88.43 210.77 6,230.37 -129.98 4,093.72 -2,802.78 7.00 -90.36 5,971,071.01 544,274.12 7 10,700.00 88.53 209.02 6,231.04 -151.65 4,081.26 -2,778.66 7.00 -87.00 5,971,049.28 544,261.79 10,800.00 88.91 202.03 6,233.28 -241.81 4,038.21 -2,684.46 7.00 -86.95 5,970,958.90 544,219.23 10,900.00 89.31 195.04 6,234.84 -336.56 4,006.45 -2,595.01 7.00 -86.80 5,970,863.99 544,187.98 11,000.00 89.72 188.05 6,235.69 -434.47 3,986.46 -2,511.64 7.00 -86.69 5,970,765.98 544,168.51 11,100.00 90.13 181.06 6,235.83 -534.09 3,978.52 -2,435.58 7.00 -86.63 5,970,666.33 544,161.10 11,200.00 90.54 174.07 6,235.24 -633.94 3,982.76 -2,367.98 7.00 -86.62 5,970,566.52 544,165.88 11,225.00 90.64 172.33 6,234.99 -658.76 3,985.72 -2,352.52 7.00 -86.66 5,970,541.71 544,168.97 8 11,300.00 91.10 177.56 6,233.85 -733.43 3,992.33 -2,304.39 7.00 85.00 5,970,467.08 544,175.98 11,400.00 91.69 184.53 6,231.42 -833.32 3,990.51 -2,232.47 7.00 85.08 5,970,367.19 544,174.70 11,500.00 92.25 191.52 6,227.98 -932.22 3,976.57 -2,152.68 7.00 85.25 5,970,268.23 544,161.29 11,525.00 92.39 193.26 6,226.97 -956.62 3,971.21 -2,131.64 7.00 85.49 5,970,243.81 544,156.06 9 11,600.00 92.56 188.01 6,223.73 -1,030.24 3,957.39 -2,069.81 7.00 -88.00 5,970,170.12 544,142.63 11,700.00 92.76 181.00 6,219.08 -1,129.76 3,949.54 -1,993.89 7.00 -88.23 5,970,070.57 544,135.32 11,800.00 92.91 174.00 6,214.12 -1,229.48 3,953.89 -1,926.45 7.00 -88.55 5,969,970.89 544,140.20 11,900.00 93.03 166.99 6,208.94 -1,327.91 3,970.38 -1,868.51 7.00 -88.90 5,969,872.55 544,157.21 10 12,000.00 93.00 174.00 6,203.67 -1,426.34 3,986.86 -1,810.56 7.00 90.00 5,969,774.23 544,174.22 Planned TD at 12000.00 11912018 8.47:14PM Page 3 COMPASS 5000.14 Build 85 ConocoPhillips BAI(ER ConocoPhillips Planning Report UGHES a GE company Database: EDT Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kupl Project: Kuparuk River Unit Site: Kuparuk 1 A Pad Well: 1 A-20 Wellbore: 1A-201-1-03 Design 1A-20L1-03_wp00 Targets Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 1 A-20 Mean Sea Level 1A-20 @ 102.00usft (1A-20) True Minimum Curvature Target Name hit/miss target Dip Angle Dip Dir. TVD +NI-S +E/-W Northing Easting Shape (1) (1) (usft) (usft) (usft) (usft) (usft) 1A-20L1-037T01 0.00 0.00 6,199.00-7,759.011,144,118.00 5,969,549.00 plan misses target center by 1138895.75usft at 9200.00usft MD (6250.32 TVD, 701.88 N, 5253.67 E) - Point 1A-20L1-017Faultl 0.00 0.00 6,203.71 -4,596.171,144,399.97 5,972,713.00 plan misses target center by 1139158.62usft at 9200.00usft MD (6250.32 TVD, 701.88 N, 5253.67 E) Polygon Point 1 6,203.71 0.00 0.00 5,972,713.00 Point 2 6,203.71 1.00 1.00 5,972,714.01 1A-20 CTD Polygon Sot 0.00 0.00 0.00 -5,321.631,145,218.18 5,971,992.00 plan misses target center by 1139997.55usft at 9200.00usft MD (6250.32 TVD, 701.88 N, 5253.67 E) - Polygon Point 1 0.00 0.00 0.00 5,971,992.00 Point 2 0.00 -0.61 115.01 5,971,992.01 Point 3 0.00 -495.53 -287.66 5,971,494.98 Point 0.00 -740.55 -855.02 5,971,246.95 Point 0.00 -1,119.80 -1,192.07 5,970,865.94 Point 0.00 -2,438.62 -1,254.08 5,969,546.94 Point? 0.00 -2,949.81 -1,229.79 5,969,035.93 Point 8 0.00 -2,918.63 -884.58 5,969,068.96 Point 9 0.00 -2,417.27 -941.93 5,969,569.96 Point 10 0.00 -1,278.33 -907.88 5,970,708.95 Point 11 0.00 -1,049.11 -754.65 5,970,938.97 Point 12 0.00 -703.15 14.27 5,971,289.01 Point 13 0.00 -429.69 309.76 5,971,564.02 Point 14 0.00 11.63 446.11 5,972,006.02 Point 15 0.00 148.96 386.83 5,972,143.02 Point 16 0.00 246.58 272.34 5,972,240.01 Point 17 0.00 275.10 -12.54 5,972,267.00 Point 18 0.00 0.00 0.00 5,971,992.00 1A-201-1-01_Faultl_M 0.00 0.00 0.00 -4,596.171,144,399.97 5,972,713.00 plan misses target center by 1139175.76usft at 9200.00usft MD (6250.32 TVD, 701.88 N, 5253.67 E) Rectangle (sides W10.00 H1,000.00 D0.00) 1A-20 CTD Polygon Nor 0.00 0.00 0.00 -5,321.631,145,218.18 5,971,992.00 plan misses target center by 1139997.55usft at 9200.00usft MD (6250.32 TVD, 701.88 N, 5253.67 E) Polygon Point 1 0.00 0.00 0.00 5,971,992.00 Point 0.00 -0.61 115.01 5,971,992.01 Point 3 0.00 -455.71 -252.45 5,971,534.99 Point 0.00 -245.10 -552.36 5,971,743.97 Point 0.00 1,415.49 -627.56 5,973,403.97 Point 0.00 1,866.49 -618.17 5,973,854.97 Point 0.00 1,875.26 -951.16 5,973,861.95 Point 0.00 1,423.29 -967.56 5,973,409.95 Point 0.00 -131.95 -954.81 5,971,854.95 Point 10 0.00 -548.76 -810.00 5,971,438.96 Point 11 0.00 -759.82 -427.08 5,971,229.98 Point 12 0.00 -702.17 17.28 5,971,290.00 Point 13 0.00 -429.69 309.76 5,971,564.02 Point 14 0.00 11.63 446.11 5,972,006.02 Point 15 0.00 148.96 386.83 5,972,143.02 Point 16 0.00 246.58 272.34 5,972,240.01 Point 17 0.00 275.10 -12.54 5,972,267.00 Point 18 0.00 0.00 0.00 5,971,992.00 1,684,211.00 1,684,476.00 1,684,476.00 1,684,476.99 1,685,298.00 1,685,298.00 1,685,413.00 1,685,013.03 1,684,447.04 1,684,112.06 1,684,057.12 1, 684, 084.15 1,684,429.15 1,684,369.12 1,684,397.07 1,684,549.05 1,685,316.03 1,685,610.03 1,685,744.00 1,685,683.99 1, 685, 568.99 1, 685, 283.99 1,685, 298.00 1,684,476.00 1,685, 298.00 1,685,298.00 1,685,413.00 1,685,048.02 1, 684, 747.01 1,684, 662.93 1,684, 669.90 1,684,336.90 1,684,322.93 1,684,344.00 1,684,491.03 1,684,875.04 1,685, 319.04 1,685,610.03 1,685,744.00 1,685,683.99 1, 685, 568.99 1,685,283.99 1,685,298.00 Latitude Longitude 700 4' 28.553 N 140° 28' 46.658 W 70' 4' 58.840 N 140' 28' 24.923 W 70' 4' S0.588 N 140° 28' 4.773 W 70' 4' 58.840 N 140' 28' 24.923 W 70' 4' 50.588 N 140' 28' 4.773 W 11912018 8.47:14PM Page 4 COMPASS 5000.14 Build 85 ConocoPhillips Database: EDT Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup1 Project: Kuparuk River Unit Site: Kuparuk 1A Pad Well: IA-20 Wellbore: 1 A-20L1-03 Design: 1 A-20L1-03_wp00 Casing Points ConocoPhillips Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 1 A-20 Mean Sea Level 1A-20 @ 102.00usft (1A-20) True Minimum Curvature BA ER F IGHES BAT GE company Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 12,000.00 6,203.67 2 3/8" 2.375 3.000 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +El-W (usft) (usft) (usft) (usft) Comment 9,200.00 6,250.32 701.88 5,253.67 TIP/KOP 9,400.00 6,225.36 541.83 5,137.22 Start 7 dls 9,475.00 6,224.01 486.20 5,086.97 3 9,725.00 6,219.79 337.99 4,886.89 4 9,975.00 6,217.09 256.78 4,651.49 5 10,225.00 6,219.14 175.67 4,416.05 6 10,675.00 6,230.37 -129.98 4,093.72 7 11,225.00 6,234.99 -658.76 3,985.72 8 11,525.00 6,226.97 -956.62 3,971.21 9 11,900.00 6,208.94 -1,327.91 3,970.38 10 12,000.00 6,203.67 -1,426.34 3,986.86 Planned TD at 12000.00 11912018 8:47.14PM Page 5 COMPASS 5000.14 Build 85 .✓ Baker Hughes INTEQ BAj(ER ConocoPhillips Travelling Cylinder Report BAT a GE company Company: ConocoPhillips (Alaska) Inc. -Kupl Project: Kuparuk River Unit Reference Site: Kuparuk 1A Pad Site Error. 0.00 usft Reference Well: 1A-20 Well Error: 0.00 usft Reference Wellbore 1A-201-1-03 Reference Design: 1A-201-1-03_wp00 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 1 A-20 1A-20 @ 102.00usft (1A-20) 1A-20 @ 102.00usft (1A-20) True Minimum Curvature 1.00 sigma OAKEDMP2 Offset Datum Reference 1A-20L1-03_wp00 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 9,200.00 to 12,000.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,389.80 usft Error Surface: Pedal Curve Survey Tool Program Date 1/9/2018 From To (usft) (usft) Survey (Wellbore) 200.00 8,500.00 1A-20 (1A-20) 8,500.00 9,200.00 1A-20L1_wp02 (1A-201-1) 9,200.00 12,000.00 1A-201-1-03_wp00 (1A-20L1-03) Casing Points Measured Vertical Depth Depth (usft) (usft) 12,000.00 6,305.67 2 3/8" Summary Site Name Offset Well - Wellbore - Design Kuparuk 1A Pad 1 A-01 - 1 A-01 - 1 A-01 1 A-02 - 1 A-02 - 1 A-02 1 A-03 - 1 A-03 - 1 A-03 1 A-04 - 1 A-04 - 1 A-04 1 A-04 - 1 A-04A - 1 A-04A 1 A-05 - 1 A-05 - 1 A-05 1 A-12 - 1 A-12 - 1 A-12 1 A-13 - 1 A-13 - 1 A-13 1 A-14 - 1 A-14 - 1 A-14 1 A-15 - 1 A-15 - 1 A-15 1 A-16 - 1 A-16 - 1 A-16 1A-16 - 1A-16RD - 1A-16RD 1 A-17 - 1 A-17 - 1 A-17 1A-18-1A-18-1A-18 1A-19- 1A-19- 1A-19 1 A-20 - 1 A-20 - 1 A-20 1A-20 - 1A-201-1 - 1A-201-1_wp02 1A-20 - 1A-20L1-01 - 1A-201-1-01_wp01 1A-20 - 1A-201-1-02 - 1A-201-1-02_wp00 1 A-22 - 1 A-22 - 1 A-22 1 A-23 - 1 A-23 - 1 A-23 Kuparuk 1 B Pad 1 B-02 - 1 B-02 - 1 B-02 1 B-13 - 1 B-1312 - 1 B-131-2 Kuparuk 2Z Pad 2Z-21 - 2Z-21 ST - 2Z-21 ST Tool Name Description GYD-CT-CMS Gyrodata cont.casing m/s MWD MWD - Standard MWD MWD - Standard Name Reference Offset Centre to Measured Measured Centre Depth Depth Distance (usft) (usft) (usft) 11,429.52 8,550.00 400.61 10,850.00 7,950.00 646.32 9,202.43 8,000.00 720.24 9,521.60 9,525.00 53.66 9,523.69 9,525.00 52.91 9,523.69 9,525.00 52.91 11,984.05 7,775.00 687.15 9,200.00 7,300.00 1,326.87 Casing Diameter r'1 2-3/8 Hole Diameter 3 No -Go Allowable Distance Deviation Warning (usft) from Plan (usft) Out of range Out of range Out of range Out of range 170.16 231.28 Pass - Major Risk Out of range Out of range Out of range 186.31 471.39 Pass - Major Risk Out of range Out of range Out of range Out of range Out of range Out of range 14.48 709.92 Pass - Major Risk 1.42 52.36 Pass - Minor 1/10 1.47 51.68 Pass - Minor 1/10 1.47 51.68 Pass - Minor 1/10 173.08 515.84 Pass - Major Risk Out of range 152.32 1,183.16 Pass - Major Risk Out of range Out of range CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 1/9/2018 12:33:48PM Page 2 COMPASS 5000.14 Build 85 i m E o O N O O 4 � o � Q N O J u+ p N a� w — c a 3m 0 w 0 c~ d m J a w IA Q 8 7 0 N Q 7 0 6 9 6 6 N < c N ¢ 7 a a 0 5 N N Q 0 N 5 U 4' O 4, 41 = u: o 3, 0 a 0 3: N Q o I 27 2, zt if 1: 8( 0 0 00 0 0 0 0 0 0 0 0 0 (uT/ljsn OOb) (+)quoNj(-)glnoS � � coo cmco c J N p v 0 O 0 m C N O d a mOr a�i c c d m o �° ¢1---U)M'cl'�n mr-cow.--a v ((,,,,)) OM fir. •amN V NCO N Ntfl o7 u')O W r-�O itJ � (/J��O V OONN � aDO Z >NO�O V NOJ M*-p2 CR q' M M M t�) t V N t V O m N O O O O O O O O O O O t� o 0 0 0 0 0 0 0 0 0 0 N J Lo LL O O � O[ V � f J O) M A t V O Q � � m O O C NO C O r• O O I O 6) N N N O?O 0 0 0 0 0 0 0 0 0 0 O O O O O O O I� 0 O r• r• i� � r- r• h- r- r• r- ?) I�.N r-rnrn u"�NN� c0 to t 0 N O cc! V Or- r• N M t 0 O� _ W M 1 w w r w O t0 �n rnor.tim + �n^2 V OoO t V 0mO) V m V M M M W J W u)00 MO O)cO r,Ow V Q O L N cO r to d7 t" ) co r- t0 u] (71 11_ 1 0 r• V) V M N T Qf M V J J (n NCO a7O V 1�O)r• V r- W U) M M O r- O M 0) Co O C O OLo OOu V (D' Q Og t0 wm c 0 wc6 > A N N M M N O O N N N N N N tV N N N N tO tO tO tO tO t0 Z' N N N N �- r• 1 `- M O O O ¢�V r-Nr-N 1�MN tnO L[7 N V' � V' � r• O O P CN000)N r- V toM 00 O C J +""' O O O W a 0 cD N M M O O O m 0 0 eo a O) 6) O) O L+ O D 0 0 0 0 0 0 Cl 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 O O r• N N 0 0 m N V V r- O) N O S ate- 0 0 1O O U�NM V �tD 1�07 W Or zo )00 i00 20 100 00 00 00 c oc oc Op oc + OC oc U 00 00 00 30 00 00 3 o 0 NFT aT- O N e O '�4 o N Q -4 I -4 C (ui/gsn S8) uldaQ jsoillan anil 1530 1615 1700 1785 1870 1955 2040 Z125 MO !295 1380 '465 :550 .635 720 805 .� U, 890 ❑ N 975 S O 060 O N 145 }N C� z~ 230 O .y U 315 400 , V N 485 570 655 740 825 910 995 380 165 250 335 320 505 590 575 760 KUP PROD 1A-20 ConocoPhlllip5 Well Attributes T Angle & MD TD Alaska, Inc. Field Name status We0ll2bore2API2/UWI ncl (°) MD (ftKB) 502100 KUPARUK RIVER UNIT PROD 48.50 2,100.00 Act Btm (ftKB) 9,034.0 •-• Comment 112S (pp.) Date SSSV: LOCKED OUT 50 9/10/2016 Annotation End Data KB-Grd Last NA'J: 7/26/1991 (it) Rig Release Da 35.01 1te2/21/1990 1A-20. 5r29201711:46.45 AM Verticalechematic actwl Annotation Depth (ftKB) End Date Annotation Last Mod By End Date - ---- ---- - --- Last Tag: RKB 8,814.0 4/17/2017 Rev Reason: OPEN CMU(to produce the C- pproven 5/29/2017 HANGER; 31.3- Sand) Casing Strings I Description OD (in) ID (in) Top (RKB) Set Depth (RKB) Set Depth (TVD)... Wt/Len (1... Grade Top Thread CONDUCTOR 16 15.062 36.D 90.0 90.0 65.00 H-40 WELDED Casing Description OD (in) ID (in) Top (ftKB) Set Depth (RKB) Set Depth (TVD)... WtlLen (I... Grade Top Thread 5Casing SURFACE 9 5/8 8.921 35.0 4,960.5 3,901.1 36.00 J-55 BTC Casing Description OD (in) ID (in) Top (kKB) Set Depth (RKB) Set Depth (TVD)... WtlLen (I... Grade Top Thread PRODUCTION 7" 7 6.276 23.5 2,343.0 2,084.4 26.00 J-66 BTC- CONDUCTOR; 36.0-900 TIE-IN ABMOD Casing Description OD (in) ID (in) Top (ftKB) Set Depth (RKB) Set Depth (TVD)... WtlLen (I Grade Top Thread PRODUCTION Post 7 6.276 2,343.0 9,010.3 6,705.4 26.00 K-55 BTC WO SAFETY VLV; 1.7976 Tubing Strings Tubing Description String Ma... ID (in) Top (RKB) Set Depth (ft.. Set Depth (TVD) (... Wt (lblft) IGmdr, Top Connection TUBING I 4 3.476 I 31,3 8,677.9 6,479.E 11.00 J-55 DSS-HTC I 4"x3.5"x2.875 Completion Details Nominal ID PRODUCTION 7"TIE-IN: 23.52,343.0 I Top (ftKB) Top (TVD) (ftKB) Top Intl (°) Item Des Com (in) GAS LIFT; 3,075.8 31.3 31.3 0.05 HANGER McEVOY GEN IV TUBING HANGER 4.000 1,797.6 1,705.7 37.17 SAFETY VLV CAMCO 4" TRDP4A SSSV(LOCKED OUT 7/15/05) 3.312 4,192.3 3,354.3 44.21 XO Reducing CROSSOVER 4"x3.5" 3.500 GAS LIFT; 4,256 z 8,250.9 6,187.3 45.73 PBR BAKER PBR 10 STROKE 3.000 8,264.6 6,196.9 45.84 PACKER BAKER HB RETRIEVABLE PACKER 2.870 8,322.4 6,237.0 46.23 BLAST RINGS BLAST RINGS (4) 2.992 8,448.4 6,323.6 46.85 SLEEVE-C CAMCO CB-1 SLIDING SLEEVE NO GO PROFILE 2.812 SURFACE; 35.0-4,960.5- (OPENED 5/28/2017) 8,458.9 6,330.8 46.90 PACKER BAKER HB RETRIEVABLE PACKER 63K # PULL OR 2.870 GAS LIFT; 5,094.3 ROTATION RELEASE GAS LIFT, 5,813.8 8,608.0 6,432.2 47.38 SLEEVE-C CAMCO CB-1 SLIDING SLEEVE NO GO PROFILE (CLOSED 2/19/96) 2.750 GAS LIFT; 6,375 5 8,622.4 6,441.9 47.37 SEAL ASSY TIW LOCATOR/SEAL ASSEMBLY W/MULE BTM SHOE ON 3.000 GAS LIFT; 6,969.t 8,624.3 6,443.2 47.36 PACKER TIW SS'BB'PERMANENT PACKER 4.000 8,628.1 6,445.7 47.36 SBE TIW SEAL BORE EXTENSION - "CROSSOVER TO 4.000 GAS LIFT; 7,4104 7/8" TBG" 8,665.5 6,471.1 47.32 NIPPLE CAMCO'D' NIPPLE, 2,25" PACKING BORE NO GO 2.250 PROFILE GAS LIFT; 8,1 gg.1 8,677.2 6,479,0 47.31 SOS ELMD TTL @ 8674' during PPROF on 6/1/2008 / BAKER 2.441 SHEAR OUT SUB Other in Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) TOp(TVD) Top Intl PBR; 8.2509 PACKER; 8,264E Top (RKB) (kKB) (°) Des Com Run Date ID (in) 8,665.0 6,470.8 47.32 PLUG CA-2 PLUG (OAL 26') 4/17/2017 0.000 1 (A -SANDS ISOLATED) PRODUCTION; 8,307.9 Perforations & Slots Shot Den IPERF; 8,344.0-8,383.0� Top (ftKB) Btm (ftKB) Top (TVD) St. (ftKB) (TVD) (RKB) Zone Date (shotslf 0 Type Co. 8,344.0 8,383.0 6,25t9 6,278.8 C-0, 1A-20 8/3/1991 10.0 IPERF HLS 4.5" CG IPERF; 8.384.0-8,4070- 8,384.0 8,407.0 6,279.5 6,295.3 C-3,1A-20 8/3/1991 6.0 IPERF HLS 4.5"CG IPERF; 8,426.0-8,434.0- 8,426.0 8,434.0 6,308.3 6,313.8 C-2,1A-20 8/3/1991 5.0 IPERF HLS 4.5"CG 8,480.0 8,506.0 6,345.2 6,362.9 C-1,IA-20 8/3/1991 10.0 IPERF HLS 4.5"CG 8,747.0 8,755.0 6,526.4 6,531.8 1 A-5,1A-20 8/3/1991 1 4.0 1 IPERF I HLS 4.5"CG SLEEVE-C; 8,448.4 8,770.0 1 8,610.0 6,542.0 6,569.0 A-4, 1A-20 8/3/1991 1 4.0 1 IPERF I HLS 4.5"CG PACKER; 8,458.9 Mandrel Inserts St ati IPERF; 8,4800-8,506:0- on N Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Se, Valve Type Latch Type Port Size TRO (in) (psi) Run Run Date Com 1 3,075.8 2,586.2 CAMCO KBMG 1 GAS LIFT GLV BK 0.156 1,305.0 6/6/2015 1:00 2 4,256.2 3,400.2 MACCO SPM-1A 1 GAS LIFT GLV BK 0.156 1,291.0 6/7/2015 2:00 PRODUCTION; 8,556.5 3 5,094.3 3,995.5 MACCO SPM-1A 1 GAS LIFT GLV BK 0.156 1,276.0 6/5/2015 4:00 4 5,813.8 4,497.7 MACCO SPMAA 1 GAS LIFT GLV BK 0.156 1,261.0 6/5/2015 12:30 SLEEVE-C, 8,608.0 5 6,375.5 4,882.2 MACCO SPM-1A 1 GAS LIFT GLV BK 0.188 1,283.0 6/4/2015 8:00 SEAL ASSY: 8,622.4 6 6,969.1 5,282.9 MACCO SPM-1A 1 GAS LIFT OV BK 0.250 7/22/2016 PACKER; 8.624.3 SEE; 8,628.0 7 7,410.4 5,591.1 MACCO SPM-1A 1 GAS LIFT DMY SK 0.000 0.0 7/20/2016 PLUG; 8,665.0 NIPPLE; 8,665S 8 8,199.1 6,151.0 CAMCO MMG-2 1 112 GAS LIFT DMY RK 0.000 0.0 7/22/2016 9 8,307.9 6,226.9 MERLA TGPDC 1112 PROD DMY RK 0.000 0.0 2/14/1992 10:30 Close d SOS; 8.677.2 1 g,55fi.5 6,397.3 MERLA TGPDC 11/2 PROD DMY 0.000 0.0 2114/1992 900 0 IRK Close d IPERF;8.7470-8,755.0- Notes General &Safety End Date Annotation 7/26/1991 NOTE: 7" TIEBACK RKB TO LOCKDOWN SCREWS; TUBING RKB TO TBG HEAD FLANGE IPERF; 8,770.0-8.810.0- 2/2/2009 NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 PRODUCTION Post WO; 2.343.0.9,010.3 < rJ c § 2 2 / fCD / §LO \$ : §/ 5§R 7§= //? | \?, ƒ0 \ _CD \j 9° 5��� 3�/ \a° Eq$\ }F \qo | kq° �F- B/F- F- «/f . & \ / _ / g _ / \ / 7' Q a }J 6 © 2 I$ R in 2 U S = G 0 \ } 3 S - 2 � 5 \ & S S § ƒ U) e G E - Q 7 LO@ S + U 3 \ \ 0 k ? } \ ƒ \ a c a 4- m> ® 2> 2 c a \ � \ -0 \ \ _0 I \ § 0 m e a 2 ± ® _ = @ \ E m \ \ 7 \ ) 0 } \ \ \ ® £ £ ° \ \ j t 12 % 2 - - a -c 7� \f \ ®\u/ A 2 / > a 0 Cƒ0 0= oo mm/ /\ l// \ o o 0 Q Cl) G/ k 0 2}// /// � � : 2 } I § a% \ = S 2 %r = 2 § 2 \ f\ ± a 0 G I c Gc m« E� f$ 0 2» �§ m� o» ## �f 00 2 gG 22 7§ /\ §% \f _, fa @$ 6g kS 2a \\ \\ Loepp, Victoria T (DOA) From: Long, William R <William.R.Long@conocophillips.com> Sent: Wednesday, January 24, 2018 10:22 AM To: Loepp, Victoria T (DOA) Cc: Starck, Kai Subject: RE: [EXTERNAL]RE: Additional Laterals for KRU 1A-20 Victoria, Phase conditions lasted longer than anticipated and we had a BHA failure. We just called TD early this morning. We are currently conditioning the hole to run liner. We should be ready to kick off to drill the 1A-201-1-02 tomorrow, Thursday. Thanks, William From: Loepp, Victoria T (DOA) [mailto:victoria.loepp@alaska.gov] Sent: Wednesday, January 24, 2018 10:03 AM To: Long, William R <William.R.Long@conocophillips.com> Subject: RE: [EXTERNAL]RE: Additional Laterals for KRU 1A-20 What is the timing status on drilling 1A-201-1-02? From: Long, William R [mailto:William.R.Long@conocophillips.com] Sent: Friday, January 19, 2018 3:59 PM To: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Cc: Starck, Kai<Kai.Starck@conocophillips.com>; Ohlinger, James J <James.J.Ohlinger@conocophillips.com> Subject: Re: [EXTERNAL]RE: Additional Laterals for KRU 1A-20 Victoria, We have been shutdown during the day today for Phase 3 weather conditions. If the weather lifts and we are able to resume drilling this evening and things go smoothly for the remainder of this lateral, it could be as early as sometime Tuesday we would be ready to kick off for the new lateral. Thanks, William From: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Sent: Friday, January 19, 2018 2:57:41 PM To: Long, William R Cc: Starck, Kai; Ohlinger, James J Subject: [EXTERNAL]RE: Additional Laterals for KRU 1A-20 What's the update on the drilling timing of the first new lateral? Later than Tuesday, 1/23/18? Victoria From: Long, William R [mailto:William.R.Long@conocophillips.com] Sent: Thursday, January 18, 201812:29 PM To: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Cc: Starck, Kai <Kai.Starck@conocophillips.com>; Ohlinger, James J <James.J.Ohlineer@conocophillips.com> Subject: Additional Laterals for KRU 1A-20 Victoria, We are currently working on the Kuparuk 1A-20 CTD project. This project was originally permitted for 2 laterals. While drilling the first lateral we crossed a sand that we believe could support 2 additional laterals, 4 in total for the project. I will be dropping off permits today for the 1A-201-1-02 and 1A-20L1-03 laterals. I have highlighted the changes in red. Depending on the drilling of our second lateral we could potentially need to drill one of these new laterals as soon as early next week. I apologize that we were not able to get these 2 permits for the additional laterals to you with as much lead time as is customary. Please let me know if you would like any additional information. Thanks, William R. Long Staff CTD Engineer ConocoPhillips 907-263-4372 (office) 281-723-6000 (cell) William.R.Long@ConocoPhillips.com TRANSMITTAL FETTER CHECKLIST WELL NAME: K14- PTD: )US - 011 J Development _ Service _ Exploratory _ Stratigraphic Test Non -Conventional FIELD: 4 ` 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. Q — API No. 50-�-�- (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -) from records, data and logs acquired for well (name onpermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where 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) 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--1A-201-1-03 __Program DEV Well bore seg PTD#:2180110 Company CONOCOPHILLIPS ALASKA -1NC. Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On _ Annular Disposal ❑ Administration 17 Nonconven. gas conforms to AS31,05.0300.1.A),(j.2.A-D) NA I1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025647, Surf, Top Prod & TD; ADL0025648, Portion -of well. 3 Unique well name and number Yes KRU 1A-201-1-03 A Well _located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed -by Conservation Order No. 432D- 5 Well located proper distance from drilling unit boundary Yes CO 432D contains no spacing restrictions with respect to drilling unit boundaries. 6 Well located proper distance from other wells Yes CO 432D has no interwell spacing restrictions. 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes i9 Operator only affected party- Yes - - - Wellbore will be more than 500' from an external property line where ownership or landownership changes.- i10 Operator has appropriate bond in force Yes - Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval Yes PKB 1/22/2018 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- I16 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 1A-20 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in KRU 1A-20 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 slotted liner 23 Casing designs adequate for C, T, B &_ permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes Anti- collision analysis complete; no major risk failures 27 If diverter required, does it meet regulations NA Appr Date I28 Drilling fluid program schematic & equip list adequate Yes Max formation_ pressure is 3472 psig(10.8 ppg EMW); will drill w/ 8.6 ppg EMW and maintain overbal w/ MPD VTL 1/24/2018 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 2850 psig; will test BOPS to 3500 psig 31 Chokemanifoldcomplies w/API-RP-53 (May 84) Yes I32 Work will occur without operation shutdown Yes I33 Is presence of H2S gas probable Yes 112S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 1A-Pad are 112S-bearing. 112S measures required. Geology 36 Data presented on potential overpressure zones Yes Maximum potential_ reservoir pressure is 10.8 ppg EMW; will be drilled using 8.6 ppg mud. Appr Date 37 Seismic analysis of shallow gas zones NA PKB 1/24/2018 '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: Commissioner: Date Commissioner Date M Q y 14-3
