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219-066
Winston, Hugh E (CED) From: Winston, Hugh E (CED) Sent: Thursday, May 13, 2021 9:51 AM To: keith.e.herring@cop.com Cc: Loepp, Victoria T (CED) Subject: KRU 3H-21A/3H-21AL1 Expired permits Hi Keith, The following two permits to drill have expired under regulation 20 AAC 25.005 (g). The permits have been marked expired in their well history file and in the AOGCC database. • KRU 3H-21A (issued to CPAI May 7th 2019) • KRU 3H-21AL1 (issued to CPAI May 7th 2019) Please let me know if you have any questions. Thanks Huey Winston Statistical Technician Alaska Oil and Gas Conservation Commission h Ah.winston@alaska. ov 907-793-1241 THE STATE 'ALASKA GOVERNOR MIKE DUNLEAVY James Ohlinger Staff CTD Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 95510-0360 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 3H-21A ConocoPhillips Alaska, Inc. Permit to Drill Number: 219-066 Surface Location: 982' FNL, 282' FWL, SEC. 12, T12N, R8E, UM Bottomhole Location: 2445' FNL, 1492' FWL, SEC. 36, TUN, R8E, UM Dear Mr. Ohlinger: Enclosed is the approved application for the permit to drill the above referenced development well. 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. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this 7 day of May, 2019. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISbi�N APR 2 9 `019 PERMIT TO DRILL 20 AAC 25.005 A L"! t-- f % 1 a. Type of Work: 1 b. Proposed Well Class: Exploratory -Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specy i W, i t s drfor: Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development -Oil 0 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 ❑✓ Single Well ❑ 11. Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 5952180 ° KRU 3H-21A 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 14000' TVD: 6288' Kuparuk River Field / Kuparuk River Oil Pool 4a. Location of Well (Governmental Section): Surface: 982' FNL, 282' FWL, Sec 12, T12N, R8E, UM 7. Property Designation: ADL 255-3 a ADL 25523 Top of Productive Horizon: 8. DNR Approval Number: - 13. Approximate Spud Date: 3745' FNL, 4850' FWL, Sec 35, T13N, R8E, UM LONS 84-149 5/15/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 2445' FNL, 1492' FWL, Sec 36, T13N, R8E, UM 2560 13,080' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 76' 15. Distance to Nearest Well Open Surface: x- 498656 y- 6000675 Zone- 4 GL / BF Elevation above MSL (ft): 39' to Same Pool: 950', 3M-22 16. Deviated wells: Kickoff depth: 11000 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 96 degrees Downhole: 4983 Surface: 4362 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling I Length MD TVD MD TVD (including stage data) 3" 2-3/8" 4.7# L-80 ST-L 2400' 11350' 6245' 14000' 6288' Slotted Liner 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): 11, 346' 6376' N/A 11, 300' 6352' 11,029 Casing Length Size Cement Volume MD TVD Conductor/Structural 80' 16" 250 sx AS 1 115' 115' Surface 4586' 9-5/8" 2000 sx AS 111, 400 sx Class "G" 4621' 3084' Production 111,265' 7" 1050 sx Class G & 175 sx AS 1 11,300' 6352' Perforation Depth MD (ft): 10774-10804, 10776-10795, 10795-10814, 10804-10814, Perforation Depth TVD (ft): 10860-10890, 10868-10887, 10904-10907, 10904-10909, 6100-6114, 6101-6110, 6110-6119, 6114-6119, 6142-6157, 6146-6155, 10910-10930, 10923-10942, 10954-10956, 10954-10973, 6163-6165, 6163-6166, 6166-6176, 6173-6182, 6188-6189, 6188-6197, 10965-10985, 10973-10992, 11010-11030, 11030-11050, 6193-6203, 6197-6206, 6215-6224, 6224-6234, 6238-6244 11058-11072 Hydraulic Fracture planned? Yes❑ No ❑� 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program Diverter Sketch g Seabed Report Time v. Depth Plot ® Drilling Fluid Program Shallow Hazard Analysis �✓ 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. Contact Name: Keith Herring Authorized Name: James Ohlinger Contact Email: keith.e.herrin c0 .com Authorized Title: Staff CTD Engineer Contact Phone: 907-263-4321 Authorized Signature: Date: y/ Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: ;1, \Ck— OG)e 50-103 — Ooq — Q f _ 00 Date: b I ) 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: Q� Other: �8G0 ��P fes P�' g Samples req'd: Yes ❑ No[�]' Mud log req'd: Yes❑ No[� a �h Lj /Gt r ,fjre VIvI 1-7,J1 �S z J—GV/�Si S measures: Yes [ No❑ Directional svy req'd: Yes No❑ T Spacirlig eXcegption req'd: Yes ❑ NoE7/ Inclination -only svy req'd: Yes❑ Nor[��.' Post initial injection MIT req'd: Yes❑ NoL 1 Approved b ep4� APPROVED BY COMMISSIONER THE COMMISSION Date: [^����� V 5���f 9 t Submit Form and 1 e 5/2017 This permit is valid foGWU loyal er 20 25.00519) Attachments in Duplicate �s �, �y °'B5io//9 ConocoPhilli s p Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 25, 2019 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 laterals out of the KRU 3H-21 (PTD# 188-008) using the coiled tubing drilling rig, Nabors CDR3-AC. The window exit type for KRU 3H-21 has been modified from a High Expansion Wedge to a cement pilot -hole casing exit. CTD operations are scheduled to begin in May 2019 and the objective will be to drill two laterals, KRU 3H-21A & 3H-21AL1 targeting the Kuparuk A -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 3H-21A & 3H-21AL1 - Detailed Summary of Operations - Directional Plans for 3H-21A & 3H-21AL1 - Current wellbore schematic - Proposed CTD schematic If you have any questions or require additional information, please contact me at 907-263-4321. Sincerely, Keith Herring Coiled Tubing Drilling Engineer ConocoPhillips Alaska Kuparuk CTD Laterals 31-1-21A and 3H-21AL1 Application for Permit to Drill Document 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(t) and 20 AAC 25.005(b)).......................... .... ....-............................................................................... 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2)).................................................................................................................................................. 2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 2 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6))..................... ................... ..-............................................ .......................................................... 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7))..................................................................................................................................................3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9)).................................................................................................................................................. 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4 11. Seabed Condition Analysis............................................................................................................ 4 (Requirements of 20 AAC 25.005(c)(11))................................................................................-.............................................................. 4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 4 13. Proposed Drilling Program............................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................5 14. Disposal of Drilling Mud and Cuttings.......................................................................................... 6 (Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 6 15. Directional Plans for Intentionally Deviated Wells....................................................................... 6 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 6 16. Attachments.................................................................................................................................... 6 Attachment 1: Directional Plans for 3H-21A and 3H-21AL1............................................................................................6 Attachment 2: Current Well Schematic for 31-1-21............................................................................................................6 Attachment 3: Proposed Well Schematic for 31-1-21A and 3H-21AL1..............................................................................6 Page 1 of 6 April 24, 2019 PTD Application: 3H-21A & 3H-21AL1 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 31-1-21A and 31-1-21AL1. All laterals will be classified as "Development -Oil" wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 forms for surface and subsurface coordinates of 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 4,800 psi. Using the maximum formation pressure in the area of 4,983 psi in 31-1-22 (i.e. 15.5 ppg EMW), the maximum potential surface pressure in 31-1-21, assuming a gas gradient of 0.1 psi/ft, would be 4,362 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)) IZtC"h to rP.iS � a♦ cow Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005 (c)(4)(a)) The formation pressure in KRU 31-1-21 was measured to be 3,472 psi (10.9 ppg EMW) on 02/07/2019.1The maximum downhole pressure in the 31-1-21 vicinity is the 3H-22 at 4,983 psi or 15.5 ppg EMW on 06/17/2018. � J ecf�oti, ,h ar�0. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) L.efs oP7 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 31-1-21 laterals. If 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)(0) The major expected risk of hole problems in the 31-1-21 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 31-1-21 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 April 24, 2019 PTD Application: 3H-21A & 3H-21AL1 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 3H-21A 11,350' 14,000' 6169' 6212' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 3H-21AL1 10,663' 14,000' 5969' 6160' 23/", 4.7#, L-80, ST-L slotted liner; ..deployment sleeve on to Existing Casing/Liner Information Category OD Weigh t f Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.5 H-40 Welded Surface 115' Surface 115' 1640 670 Surface 9-5/8" 36 J-55 BTC Surface 4621' Surface 3084' 3520 2020 Production 7" 26 J-55 BTC Surface 11,300' Surface 6352' 4980 4320 Tubing 3-1/2" 9.2 J-55 BTC AB -MOD Surface 10,672' Surface 6049' 6980 7400 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) Nabors CDR3-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a diverter system is not required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System A diagram of the Nabors CDR3-AC mud system is on file with the Commission. Description of Drilling Fluid System — Window milling operations: Water based Power-Vis milling fluid (8.6 ppg) — Drilling operations: Water based 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 a weighted completion fluid in order to provide formation over -balance and maintain wellbore stability while running completions. ,' Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000-psi rated coiled tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". In the 3H-21 laterals we will target a constant BHP of 11.8 EMW at the window. The constant BHP target will be adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if increased reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed for improved borehole stability. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Page 3 of 6 April 24, 2019 PTD Application: 3H-21A & 3H-21AL1 Pressure at the 3H-21 Window (11,000' MD, 6210' TVD) Usinci MPD ►.$11r Pumps On 1.8 b m Pumps Off Formation Pressure 10.9 3520 psi 3520 psi Mud Hydrostatic 8.6 2777 psi 2777 psi Annular friction i.e. ECD, 0.080 si/ft 880 psi 0 psi Mud + ECD Combined no chokepressure) 3657 psi overbalanced —137psi) 2777 psi underbalanced —743psi) Target BHP at Window 11.8 3810 psi 3810 psi Choke Pressure Required to Maintain Target BHP 153 psi 1033 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 KRU well 3H-21 is a Kuparuk A -Sand and C-sand producer equipped with 3-1/2" tubing and 7" production casing. The CTD sidetrack will utilize two laterals to target the A -sands to the northeast of 3H-21. The laterals will increase A -sand resource recovery and throughput. Prior to CTD operations, E-line will punch 2' of holes in the 3-1/2" tubing tail at 10,643' MD. The existing perforations will be squeezed with cement and the 3-1/2" tubing tail will be cemented in place to provide a means to kick out of 7" casing. Following the cement squeeze Nabors CDR3-AC will mill a 2.80" pilot hole to 11,030' MD and set a mechanical whipstock at 11,000' MD. A window will be milled in the 7" casing at 11,000' MD and the 3H- 21A lateral will be drilled to TD at 14,000' MD, targeting the A -sand to the northeast. It will be completed with 2-3/8" slotted liner from TD up to 11,350' MD with an aluminum billet for kicking off the 3H-21AL1 lateral. The 3H-21AL1 lateral will drill to TD at 14,000' MD targeting the A -sand to the northeast. It will be completed with 2-3/8" slotted liner from TD up into the 3-1/2" tubing at 10,663' MD with a deployment sleeve. Page 4 of 6 April 24, 2019 PTD Application: 3H-21A & 3H-21AL1 Pre-CTD Work 1. RU E-line: Punch 2` of holes in the 3-1/2" tubing tail. 2. RU Pumping Unit: Perform injectivity test down tubing. 3. RU E-line: Cement squeeze the perforations up to the holes in tubing tail. 4. RU Slickline: Tag top of cement. 5. Prep site for Nabors CDR3-AC. Rig Work 1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 3H-21A Lateral (Al sand - Northeast) a. Mill 2.80" high -side pilot hole through cement to 11,030' MD. b. Caliper pilot hole and set top of whipstock at 11,000' MD. c. Mill 2.80" window at 11,000' MD. d. Drill 3" bi-center lateral to TD of 14,000' MD. e. Run 2%" slotted liner with an aluminum billet from TD up to 11,350' MD. 3. 3H-21AL1 Lateral (A2/A3 sand - Northeast) a. Kickoff of the aluminum billet at 11,350' MD. b. Drill 3" bi-center lateral to TD of 14,000' MD. c. Run 23/" slotted liner with deployment sleeve from TD up to 10,663' MD. 4. Obtain SBHP, freeze protect, ND BOPE, and RDMO Nabors CDR3-AC. Post -Rig Work 1. Return to production Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the swab valve on the Christmas tree. MPD operations require the BHA to be lubricated under pressure using the swab valve on the Christmas tree, deployment ram on the BOP, check valve and ball valve in the BHA, and a slick -line lubricator. This pressure control equipment listed ensures reservoir pressure is contained during the deployment process. During BHA deployment, the following steps are observed. - Initially the swab valve on the tree is 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 valve. The swab valve is opened and the BHA is lowered in place via slick -line. - When the BHA is spaced out properly, the deployment ram is closed on the BHA to isolate reservoir pressure via the annulus. A closed set of ball valve and check valve isolate reservoir pressure internal to the BHA. Slips on the deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment ram. - The coiled tubing is made up to the BHA with the ball valve in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the ball valve is opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment ram is 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 - 3H-21 CTD laterals will be displaced to an overbalance completion fluid (as detailed in Section 8 "Drilling Fluids Program") prior to running liner. Page 5 of 6 April 24, 2019 PTD Application: 3H-21A & 3H-21AL1 — While running 2%" slotted liner, a joint of 23/" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2%" rams will provide secondary well control while running 2'/" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). 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 3H-21A 13,080' 3H-21 AL1 13,100' — Distance to Nearest Well within Pool Lateral Name Distance Well 3H-21A 950' 3M-22 3H-21AL1 998, 3M-22 16. Attachments Attachment 1: Directional Plans for 3H-21A and 3H-21AL1 laterals. Attachment 2: Current Well Schematic for 3H-21. Attachment 3., Proposed Well Schematic for 3H-21A and 3H-21AL1 laterals. Page 6 of 6 April 24, 2019 ConocoPhilli s p ConocoPhillips Alaska Inc—Kuparuk Kuparuk River Unit Kuparuk 3H Pad 3H-21 3H-21A Plan: 31-1-21A_wp03 (Draft A) Standard Planning Report 24 April, 2019 BER BA 0 GE company ConocoPhillips Database: EDT 14 Alaska Production Company: ConocoPhillips Alaska Inc—Kuparuk Project: Kuparuk River Unit Site: Kuparuk 3H Pad Well: 31-1-21 Wellbore: 31-1-21 A Design: 3H-21 A_wp03 (Draft A) ConocoPhillips Planning Report Local Co-ordinate Reference: Well 31-1-21 TVD Reference: Mean Sea Level MD Reference: 31-1-21 @ 76.00usft (31-1-21) 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 T�UIEGRIHSE GE company Site Kuparuk 3H Pad Site Position: Northing: 6,000,110.73 usft Latitude: 70° 24' 41.531 N From: Map Easting: 498,655.44 usft Longitude: 150° 0' 39.416 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: -0.01 ° Well 31-1-21 Well Position +N/-S 0.00 usft Northing: 6,000,675.40 usft Latitude: 70° 24' 47.085 N +E/-W 0.00 usft Easting: 498,655.63 usft Longitude: 150° 0' 39.414 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft F-Wellbore 3H-21A Magnetics Model Name Sample Date Declination Dip Angle Field Strength (1) (1 (nT) BGGM2018 5/1/2019 16.56 80.89 57,417 Design 3H-21A_wp03 (Draft A) Audit Notes: Version: Phase: PLAN Tie On Depth: 10,900.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (I 0.00 0.00 0.00 45.00 4/24/2019 2:44:48PM Page 2 COMPASS 5000.14 Build 85D 'W ConocoPhillips COno4hilfips Planning Report Database: EDT 14 Alaska Production Local Co-ordinate Reference: Well 31-1-21 Company: ConocoPhillips Alaska Inc-Kuparuk TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 31-1-21 @ 76.00usft (31-1-21) Site: Kuparuk 3H Pad North Reference: True Well: 3H-21 Survey Calculation Method: Minimum Curvature Wellbore: 3H-21 A Design: 3H-21 A_wp03 (Draft A) BAIUGHES a GE company Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +Nl-S +El-W Rate Rate Rate TFO (usft) (°) (°) (usft) (usft) (usft) (°HOOusft) (°/100usft) (°/100usft) (°) Target 10,900.00 60.73 20.51 6,085.34 7,715.42 3,479.39 0.00 0.00 0.00 0.00 11,000.00 61.27 20.44 6,133.82 7,797.35 3,509.99 0.54 0.54 -0.07 -6.49 11,029.00 67.07 20.44 6,146.45 7,821.80 3,519.10 20.00 20.00 0.00 0.00 11,079.96 90.00 20.44 6,156.51 7,868.29 3,536.42 45.00 45.00 0.00 0.00 11,120.00 90.00 2.42 6,156.51 7,907.37 3,544.33 45.00 0.00 -45.00 270.00 11,190.00 90.00 357.52 6,156.51 7,977.35 3,544.29 7.00 0.00 -7.00 270.00 11,300.00 83.03 0.79 6,163.20 8,087.05 3,542.66 7.00 -6.34 2.97 155.00 11,500.00 82.02 14.87 6,189.35 8,282.99 3,569.59 7.00 -0.50 7.04 95.00 11,700.00 88.09 27.55 6,206.65 8,468.24 3,641.59 7.00 3.03 6.34 65.00 11,925.00 89.51 11.86 6,211.39 8,679.36 3,717.18 7.00 0.63 -6.97 275.00 12,125.00 89.53 25.86 6,213.07 8,868.15 3,781.67 7.00 0.01 7.00 90.00 12,525.00 89.11 53.86 6,217.90 9,172.13 4,035.46 7.00 -0.10 7.00 91.00 12,750.00 85.12 69.11 6,229.29 9,279.11 4,232.27 7.00 -1.78 6.78 105.00 12,950.00 90.44 82.08 6,237.07 9,328.66 4,425.36 7.00 2.66 6.48 68.00 13,150.00 92.36 95.95 6,232.16 9,332.11 4,624.77 7.00 0.96 6.94 82,00 13,350.00 93.74 109.90 6,221.48 9,287.56 4,818.95 7.00 0.69 6.98 84.00 13,500.00 95.67 120.26 6,209.15 9,224.29 4,954.16 7.00 1.29 6.90 79.00 13,600.00 90.70 115.31 6,203.59 9,177.79 5,042.44 7.00 -4.96 -4.94 225.00 14,000.00 86.88 87.57 6,212.19 9,099.19 5,430.50 7.00 -0.96 -6.94 262.00 4/24/2019 2:44:48PM Page 3 COMPASS 5000.14 Build 85D ConocoPhillips BAT ConocoPhillips Planning Report IGHES a GE company Database: EDT 14 Alaska Production Local Co-ordinate Reference: Well 31-1-21 Company: ConocoPhillips Alaska Inc Kuparuk TVD Reference; Mean Sea Level Project: Kuparuk River Unit MD Reference: 31-1-21 @ 76.00usft (31-1-21) Site: Kuparuk 3H Pad North Reference: True Well: 31-1-21 Survey Calculation Method: Minimum Curvature Wellbore: 31-1-21A Design: 31-1-21A_wp03 (Draft A) Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +EI-W Section Rate Azimuth Northing Easting (usft) (°) (°) (usft) (usft) (usft) (usft) (°/100usft) (°) (usft) (usft) 10,900.00 60.73 20.51 6,085.34 7,715.42 3,479.39 7,915.93 0.00 0.00 6,008,389.42 502,136.07 TIP 11,000.00 61.27 20.44 6,133.82 7,797.35 3,509.99 7,995.50 0.54 -6.49 6,008,471.34 502,166.67 KOP 11,029.00 67.07 20.44 6,146.45 7,821.80 3,519.10 8,019.23 20.00 0.00 6,008,495.79 502,175.79 Start 20 DLS 11,079.96 90.00 20.44 6,156.51 7,868.29 3,536.42 8,064.35 45.00 0.00 6,008,542.26 502,193.12 End 20 DLS, Start 45 DLS 11,100.00 90.00 11.42 6,156.51 7,887.54 3,541.92 8,081.85 45.00 -90.00 6,008,561.51 502,198.62 11,120.00 90.00 2.42 6,156.51 7,907.37 3,544.33 8,097.58 45.00 -90.00 6,008,581.35 502,201.03 End 45 DLS, Start 7 DLS 11,190.00 90.00 357.52 6,156.51 7,977.35 3,544.29 8,147.03 7.00 -90.00 6,008,651.32 502,201.00 6 11,200.00 89.37 357.82 6,156.57 7,987.34 3,543.88 8,153.81 7.00 155.00 6,008,661.31 502,200.60 11,300.00 83.03 0.79 6,163.20 8,087.05 3,542.66 8,223.45 7.00 155.00 6,008,761.01 502,199.39 7 11,400.00 82.47 7.82 6,175.84 8,185.91 3,550.10 8,298.61 7.00 95.00 6,008,859.85 502,206.85 11,500.00 82.02 14.87 6,189.35 8,282.99 3,569.59 8,381.04 7.00 94.11 6,008,956.92 502,226.35 8 11,600.00 85.03 21.24 6,200.64 8,377.40 3,600.38 8,469.57 7.00 65.00 6,009,051.31 502,257.16 11,700.00 88.09 27.55 6,206.65 8,468.24 3,641.59 8,562.95 7.00 64.28 6,009,142.14 502,298.38 9 11,800.00 88.71 20.57 6,209.45 8,559.46 3,682.32 8,656.25 7.00 -85.00 6,009,233.35 502,339.12 11,900.00 89.35 13.60 6,211.14 8,654.98 3,711.68 8,744.54 7.00 -84.80 6,009,328.84 502,368.49 11,925.00 89.51 11.86 6,211.39 8,679.36 3,717.18 8,765.68 7.00 -84.69 6,009,353.22 502,374.01 10 12,000.00 89.52 17.11 6,212.02 8,751.95 3,735.94 8,830.27 7.00 90.00 6,009,425.80 502,392.77 12,100.00 89.52 24.11 6,212.86 8,845.49 3,771.11 8,921.28 7.00 89.96 6,009,519.32 502,427.96 12,125.00 89.53 25.86 6,213.07 8,868.15 3,781.67 8,944.77 7.00 89.90 6,009,541.98 502,438.52 11 12,200.00 89.44 31.11 6,213.74 8,934.04 3,817.42 9,016.65 7.00 91.00 6,009,607.86 502,474.28 12,300.00 89.33 38.11 6,214.82 9,016.29 3,874.18 9,114.94 7.00 90.95 6,009,690.09 502,531.05 12,400.00 89.23 45.11 6,216.09 9,091.01 3,940.54 9,214.70 7.00 90.88 6,009,764.79 502,597.41 12,500.00 89.13 52.11 6,217.52 9,157.08 4,015.50 9,314.42 7.00 90.79 6,009,830.85 502,672.38 12,525.00 89.11 53.86 6,217.90 9,172.13 4,035.46 9,339.18 7.00 90.69 6,009,845.89 502,692.34 12 12,600.00 87.76 58.93 6,219.95 9,213.61 4,097.88 9,412.65 7.00 105.00 6,009,887.35 502,754.76 12,700.00 85.98 65.71 6,225.41 9,259.97 4,186.25 9,507.91 7.00 104.86 6,009,933.69 502,843.13 12,750.00 85.12 69.11 6,229.29 9,279.11 4,232.27 9,553.99 7.00 104.49 6,009,952.82 502,889.14 13 12,800.00 86.43 72.37 6,232.98 9,295.56 4,279.33 9,598.90 7.00 68.00 6,009,969.26 502,936.21 12,900.00 89.10 78.84 6,236.87 9,320.38 4,376.06 9,684.84 7.00 67.76 6,009,994.06 503,032.93 12,950.00 90.44 82.08 6,237.07 9,328.66 4,425.36 9,725.56 7.00 67.51 6,010,002.33 503,082.23 14 13,000.00 90.93 85.54 6,236.48 9,334.05 4,475.06 9,764.52 7.00 82.00 6,010,007.71 503,131.92 13,100.00 91.89 92.48 6,234.02 9,335.78 4,574.95 9,836.37 7.00 82.04 6,010,009.42 503,231.80 13,150.00 92.36 95.95 6,232.16 9,332.11 4,624.77 9,869.00 7.00 82.21 6,010,005.74 503,281.62 15 13,200.00 92.72 99.43 6,229.95 9,325.42 4,674.27 9,899.27 7.00 84.00 6,009,999.05 503,331.11 13,300.00 93.41 106.41 6,224.60 9,303.10 4,771.54 9,952.27 7.00 84.15 6,009,976.71 503,428.36 13,350.00 93.74 109.90 6,221.48 9,287.56 4,818.95 9,974.80 7.00 84.53 6,009,961.16 503,475.77 16 412412019 2:44:48PM Page 4 COMPASS 5000.14 Build 85D `, ConocoPhillips BA ER ConocoPhillips Planning Report BAT a GE company Database: EDT 14 Alaska Production Company: ConocoPhillips Alaska Inc_Kuparuk Project: Kuparuk River Unit Site: Kuparuk 3H Pad Well: 31-1-21 Wellbore: 3 H-21 A Design: 31-1-21 A_wp03 (Draft A) Planned Survey Measured TVD Below Depth Inclination Azimuth System (usft) V) (I (usft) 13,400.00 94.40 113.35 6,217.93 13,500.00 95.67 120.26 6,209.15 17 13,600.00 90.70 115.31 6,203.59 18 13,700.00 89.73 108.38 6,203.21 13,800.00 88.75 101.45 6,204.53 13,900.00 87.80 94.51 6,207.54 14,000.00 86.88 87.57 6,212.19 Planned TD at 14000.00 Casing Points Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3H-21 Mean Sea Level 31-1-21 @ 76.00usft (31-1-21) True Minimum Curvature Vertical Dogleg Toolface Map Map +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (usft) (usft) (°/100usft) V) (usft) (usft) 9,269.18 4,865.30 9,994.59 7.00 79.00 6,009,942.78 503,522.11 9,224.29 4,954.16 10,025.68 7.00 79.24 6,009,897.88 503,610.96 9,177.79 5,042.44 10,055.22 7.00 -135.00 6,009,851.36 503,699.22 9,140.60 5,135.20 10,094.51 7.00 -98.00 6,009,814.16 503,791.96 9,114.87 5,231.76 10,144.60 7.00 -98.03 6,009,788.42 503,888.51 9,101.00 5,330.69 10,204.74 7.00 -97.93 6,009,774.53 503,987.42 9,099.19 5,430.50 10,274.04 7.00 -97.73 6,009,772.70 504,087.23 Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 14,000.00 6,212.19 2 3/8" 2.375 3.000 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +El-W (usft) (usft) (usft) (usft) Comment 10,900.00 6,085.34 7,715.42 3,479.39 TIP 11,000.00 6,133.82 7,797.35 3,509.99 KOP 11.029.00 6,146.45 7,821.80 3,519.10 Start 20 DLS 11,079.96 6,156.51 7,868.29 3,536.42 End 20 DLS, Start 45 DLS 11,120.00 6,156.51 7,907.37 3,544.33 End 45 DLS, Start 7 DLS 11,190.00 6,156.51 7,977.35 3,544.29 6 11,300.00 6,163.20 8,087.05 3,542.66 7 11,500.00 6,189.35 8,282.99 3,569.59 8 11,700.00 6,206.65 8,468.24 3,641.59 9 11,925.00 6,211.39 8,679.36 3,717.18 10 12,125.00 6,213.07 8,868.15 3,781.67 11 12,525.00 6,217.90 9,172.13 4,035.46 12 12,750.00 6,229.29 9,279.11 4,232.27 13 12,950.00 6,237.07 9,328.66 4,425.36 14 13,150.00 6,232.16 9,332.11 4,624.77 15 13,350.00 6,221.48 9,287.56 4,818.95 16 13,500.00 6,209.15 9,224.29 4,954.16 17 13,600.00 6,203.59 9.177.79 5,042.44 18 14,000.00 6,212.19 9,099.19 5,430.50 Planned TD at 14000.00 412412019 2:44:48PM Page 5 COMPASS 5000.14 Build 85D F4-i �vj 28. 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ConocoPhillips BA ER ConocoPhillips Anticollision Report t IGHES BAT GE company Company: ConocoPhillips Alaskalnc_Kuparuk Project: Kuparuk River Unit-2 Reference Site: Kuparuk 3H Pad Site Error: 0.00 usft Reference Well: 31-1-21 Well Error: 0.00 usft Reference Wellbore 31-1-21A Reference Design: 31-1-21A_w1003 (Draft A) Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 3H-21 31-1-21 @ 76.00usft (31-1-21) 31-1-21 @ 76.00usft (31-1-21) True Minimum Curvature 2.00 sigma EDT 14 Alaska Production Offset Datum Reference 3H-21A_wp03 (Draft A) Filter type: NO GLOBAL FILTER: Using user defined selection & filtering criteria Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 10,900.00 to 14,000.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,592.40 usft Error Surface: Combined Pedal Curve Warning Levels Evaluated at: 2.79 Sigma Casing Method: Added to Error Values Survey Tool Program Date 4/25/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description 100.00 10,900.00 31-1-21 (31-1-21) GCT-MS Schlumberger GCT multishot 10,900.00 14,000.00 3H-21A_wp03(Draft A)(3H-21A) MWD MWD- Standard Summary Site Name Offset Well - Wellbore - Design Kuparuk 3H Pad 31-1-21 - 31-1-21 - 31-1-21 31-1-21-3H-21AL1 - 31-1-21AL1_wp02 (Draft A) 31-1-21-3H-21AL1-3H-21AL1_wp02 (Draft A) 31-1-21 - 3H-21AL1 - 3H-21AL1_wp02 (Draft A) 31-1-22 - 31-1-2211-02 - 31-1-221-1-02 31-1-22 - 31-1-221-1-02 - 31-1-221-1-02 31-1-22 - 31-1-2211-03 - 31-1-2211-03 31-1-22 - 31-1-2211-03 - 3H-2211-03 31-1-22 - 31-1-221-1-03P61 - 31-1-221-1-03P81 31-1-22 - 3H-22L1-03PB2 - 31-1-2211-03PB2 31-1-31 - 31-1-31A- 31-1-31A 31-1-31-3H-31A-3H-31A 31-1-31-3H-31A-3H-31A 31-1-31-3H-31AL1-3H-31AL1 31-1-31-3H-31AL1-3H-31AL1 31-1-31-3H-31AL1-3H-31AL1 Kuparuk 31 Pad 31-09 - 31-09 - 31-09 31-12 - 31-12L1 - 31-121-1 Kuparuk 3M Pad 3M-22 - 3M-22 - 3M-22 3M-22 - 3M-22 - 3M-22 Reference Offset Distance Measured Measured Between Between Separation Warning Depth Depth Centres Ellipses Factor (usft) (usft) (usft) (usft) 11,218.23 11,250.00 104.69 93.82 9.632 CC, ES, SF 13,687.93 13,650.00 28.18 16.52 2A16 Caution Monitor Closely, CC 13,738.65 13,700.00 28.69 15.64 2.199 Caution Monitor Closely, ES 13,789.36 13,750.00 30.04 16.06 2.149 Caution Monitor Closely, SF Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range 13,450.00 8,725.00 1,589.91 1,410.96 8.885 CC, ES, SF 13,783.82 8,485.00 1,339.07 1,156.10 7.319 CC, ES, SF 12,500.00 9,725.00 952.08 617.67 2.847 Normal Operations, ES, SF 12,525.00 9,650.00 949.77 618.16 2.864 Normal Operations, CC Offset Design Kuparuk 3H Pad - 31-1-21 - 3H-21 - 31-1-21 Onset Site Error: 0.00 usft Survey Program: 100-GCT-MS Offset Well Error: 0.00 usft Reference offset Semi Major Axis Distance Measured Vertical Measured Vertical Reference Offset Azimuth Offset Wellbore Centre Between Between Minimum Separation Warning Depth Depth Depth Depth from North +NIS +E/-W Centres Ellipses Separation Factor (usft) (usft) (usff) (usft) (usft) (usft) l°I (usft) (usft) usft) (usft) (usft) 10,925.00 6,173.54 10,925.00 6,173.54 0.21 0.42 20.49 7,735.86 3,487.04 0.00 -0.42 0.42 0.000 STOP Drilling 10,950.00 6,185.68 10,950.00 6,185.68 0.42 0.84 20.47 7,756.33 3,494.68 0.00 -0.42 0.42 0.000 STOP Drilling 10,975.00 6,197.78 10,975.00 6,197.78 0.63 1.26 20.46 7,776.83 3,502.33 0.00 -0.42 0.42 0.000 STOP Drilling 11,000.00 6,209.82 11,000.00 6,209.82 0.84 1.68 3.57 7,797.35 3,509.99 0.00 -2.33 2.33 0.000 STOP Drilling CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 412512019 9:26:49AM Page 2 COMPASS 5000.14 Build 85D 221 am a (ut/Usn OOZ) (+)tpoNA-)q;noS a OC 6i o¢r-1(nww(mrc+oa) J Q J p � Q O V r O m m u) c C J O O J - 1 Q N O tt] C d d y a M OM-M M Mln �-M-lo M Mt0000° N V to 1nN1(J O�O� r�M((]O GOO NO J 9 1 A M r r M N 1 S 4 M M 10 M V 10 'US O (O MIA N N Z > V (O o, p CD CD " M >�r- � C,C, �r-m �g� om000 co cO c co J r pp p po po pO p p po po p Qo p p U 0 MV S O S S S O O S S O O S O O O S S 0 10 10 1 L] 10 0 lf l O (V V M l n N = N N V= (o N M M O t O o o N r N N Cl) N~ O r M O V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 U( 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 _N Q o o cD M M O N M M O M M O O O M M M N 11] In (O N M M ' OI C) C' t0 ? (O M (O V C (V 6 r--: L6 " l V' CO R (V CD + r 0 M V' V CO e{ m M M N N Ln M �U)�to Lo (Or r ONvtON M �R C (O M M M Cl) M M M M M M M V V V V 1(] LC) d6 J N Lo w co(n N Ln OM r 1(')1nM QO tOM �O EOM MM Q pp M RM CO N MCl) OM NCl) ---(O-1O N 1� Z r m r r N 066 W N M m N r V r M F- L U V+ M N t D O r � O c V ( O r co r r N M O N r M r r t O O O M M O N Q O t q.- (u M M N N O Q r r r r r r a D a D N t D a O M M M M M M M M J W y N l f O l[ 3 1 n M r O M Cl- (O m 1 A M M � to V 10101n NM (O(M O NO ef� to iT0 C R> Q1(7 M(G t0 (p (O MM t0 Z Mr O) I�(V Oi MN C O M V ((� O a 0 0 N( M t M N 0 0 L In O N N N N N N N N N N N O = t0 (O (O w w w O (O l0 O to O t0 CO t0 t0 (D r ZO'N N NMr 10(O (O(OCoLoQ(O r O O t0 ¢l()et7 sf a 1n rN w=O°cDm oM N M((7 p 0 0 0 N r O� r l f Y M O N (� r n O l (') N (O NNNN N�NlOm o MON.-. W M � CM N0000 C) = 1 1MC V' r(r0 Crco O O C.G ;r OOOMN copj to Oj In C(V MU1 C(O cot0 f0 M M 0) O 0D a° co O M M M M M M LU + O 0 0 0 0 tD O O O O 0 0 0 C. 0 0 0 0 0 0 0 O O O M O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 OOM M000001() 1n 1t700a c� pG m 000N M10A SIN I�(r11-m M1-cD 10. - O N N N N M M M M u)_ O U NM e{1('J0 r co MOr- MQ tOrcOM + 3 (u?/Usn 06) T1dOQ 73?V0A ansl KUP PROD WELLNAME 31-1-21 LLBORE 3H-21 COt1000Pit1llIpS _ Alaska, nc.WIC.mv.-LOCKED Well Attributes Max Angle & MD TD Field Name Wel@ore APIIUWI KUPARUK RIVER UNIT 501032009400 Wellbore Status PROD n11 (°) 5.94 MM (ftKB) 5,800.00 Act Bhn (ftKB) 11,346.0 OUT 200 H2S(ppm)DleAnnotation 11/25/2016 Last WO: End Date KB-Grd(ft) 36.99 Rig Release Rig Release Date 3H-21, 4/1/2019 8:59.58 PM Last Tag Venical schematic (actuah Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag: RKB (All 212' of A -sands are Covered / All C- 10,829.0 Z4/2019 31-1-21 zembaej ._......................_....._.................................. ......, sands are Open) HANGER 35.1pirlaunLast 1 Rev Reason Annotation End Date Wellbore Last Mod By CONDUCTOR; 36.0-115.0 Rev Reason: MILLED D NIPPLE, POSSIBLE CASING DAMAGE 4/l/2019 3H-21 9 condijw Casing Strings SAFETY VLV; 1,803.1 Casing Description CONDUCTOR OD (in) 16 to (in) Top 15.06 36.0 (ftKB) Set Depth (ftKB) 115.0 Set Depth (TVD)... 115.0 WtlLen (I... 62.50 Grade H-40 Top Thread WELDED GAS LIFT; 3,191.3 Casing Description SURFACE OD (in) 9 5/8 ID lin) Top 8.92 35.0 (ftKB) Set Depth (ftKB) 4,620.6 Set Depth (TVD)... 3,083.9 Wt/Len (I... 36.00 Grade J-55 Top Thread BTC Casing Description PRODUCTION OD (in) 7 ID (in) I Top 6.28 35.0 (ftKB) Set Depth IRKS) 11,300.3 Set Depth IWO)- 6,352.0 Wt/Len (I... 26.00 Grade J-55 Top Thread BTC Tubing Strings Tubing Description I String Ma... ID (in) Top (ftKB) Se[ Depth (ft.. Set Depth (TVD) (... Wt (Ib"t) Grade Top Connection TUBING 31/2 2.99 35.1 10,6724 6,049.4 9.20 J-55 BTC AB -MOD SURFACE; 35.04,620.6- Completion Details GAS LIFT; 6,683.4 Top (TVD) Top Incl Nominal Top (ftKB) (ftKB) (1 Item Des Com ID (in) 35.1 35.1 0.05 HANGER MEVOY TUBING HANGER 3.500 GAS LIFT; 8,591.5 1,803.1 1,642.0 44.73 SAFETY VLV CAMCO TRDP-IA-SSA SAFETY VALVE (LOCKED OUT 12/26/88) 2.812 GAS LIFT; 9,575.6 10,579.9 6,003.1 59.73 PBR BAKER PBR 3.000 10,599.6 6,013.0 59.83 PACKER BAKER FHL PACKER 2.992 GAS LIFT; 10,099.0 10,638.2 6,032.3 60.01 NIPPLE- CAMCO D NIPPLE NO GO (MILLED TO 2.80" ON 3131/19) 2.800 MILLED OUT GAS LIFT; 10,538.2 10,671.4 bm;3.9 60.17 SOS BAKER SHEAR OUT SUB 3.000 PBR; 10,579.9 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top(TVD) Topincl PACKER; 10,599.E Top (ftKB) (ftKB) (°) Des Co. Run Date ID (in) 10,801.0 6,112.9 60.61 -POSSIBLE UNABLE TO FCO PAST 10801' W/ 2.0" DJN, TRIED 4/1/2019 6.280 NIPPLE -MILLED OUT; 10,638.2 CASING DAMAGE 1 2.73 MILL AND 2.13" MOTOR, 8 STALLS AND ONE OVERPULL AT THIS DEPTH, 4/l/19 11,029.0 6,223.8 61.35 FISH 1 1/2" OV Empty Pocket; Assume Fell to Rathole 7/18/1996 SOS; 10,671.4 Perforations & Slots Shot Dens Top (TVD) Bt. (TVD) (shotslft Top (ftKB) Bt. (ftKB) (ftKB) (ftKB) Linked Zone Date ) Type Co. 10,774.0 10,804.0 6,099.6 6,114.4 C4, 31-1-21 11/14/1988 6.0 IPERF 2 1/8" EnerJet, Zero deg ph 10,776.0 10,795.0 6,100.6 6,110.0 C-4, 3H-21 5/2/2018 6.0 RPERF 2 1/8" PowerSpiral Enerjet 60 deg ph RPERF; 10,776.0-10,795.0-_ IPERF; 10,774.610,804.0- 10,795.0 10,814.0 6,110.0 6,119.3 C4, 3H 5/1/2018 6.0 RPERF 2 118" Powers Iral Ener et p )-21 60 deg ph RPERF; 10,795.0-10,814.0 "'POSSIBLE CASING 10,804.0 10,814.0 6,114.4 6,119.3 C-4, 3H-21 11/14/1988 12.0 IPERF 2 1/8" EnerJet, 60 deg ph DAMAGE-; 10,801.0 IPERF; 10,804.0-10,814.0- 10,860.0 10,890.0 6,141.8 6,156.5 A-3, 31-1-21 5/31/1996 4.0 RPERF 2 1/8" EnerJet,180 deg phasing; (+/-) 90 deg. F/ Lowside 10,868.0 10,887.0 6,145.8 6,155.0 A-3, 3H-21 5/1/2018 6.0 RPERF 21/8" PowerSpiral Enerjet 60 deg ph 10,904.0 10,907.0 6,163.4 6,164.8 A-2, 3H-21 4/30/2018 6.0 RPERF 21/8" PowerSpiral EnerJet, 60 deg ph 10,904.0 10,909.3 6,163.4 6,165.9 A-2,31-1-21 4130/2018 6.0 RPERF 21/8" PowerSpiral EnerJet, 60 deg ph 10,910.0 10,930.0 6,166.3 6,176.0 A-2, 31-1-21 8/25/1988 8.0 IPERF Gearhart Big Hole, 60 deg phasing RPERF; 10,860.0�10,890.0 RPERF; 10.868.0-10,887.0� 10,923.0 10,942.0 6,172.6 6,181.9 A-2, 3H-21 4/30/2018 6.0 RPERF 2 1/8" PowerSpiral EnerJet, 60 deg ph 10,954.0 10,956.0 6,187.7 6,188.7 A-1, 31-1-21 4/27/2018 6.0 RPERF 2 1/8" PowerSpiral EnerJet, 60 deg ph 10,954.0 10,973.0 6,187.7 6,196.9 A-1, 31-1-21 4/28/2018 6.0 RPERF 21/8" PowerSpiral EnerJet, RPERF; 10.904.0-10,907.0 60 deg ph RPERF; 10,904.0-10,909.3- 10,965.0 10,985.0 6,193.0 6,202.7 A-1, 31-1-21 7/3/1999 6.0 APERF 2.5" HSD/DP, 60 deg ph, spiral chg 10,973.0 10,992.0 6,196.9 6,206.0 A-1, 31-1-21 4/27/2018 6.0 RPERF 2118" PowerSpiral EnerJet, IPERF; 10, 910.(M0,930o- 60 deg ph RPERF; 10,923.0-10.942.0- 11,010.0 11,030.0 6,214.7 6,224.3 A-1, 31-1-21 11/14/1999 4.0 APERF 2 1/8" Enerjet DP, 180 deg +/- 90 deg 11,030.0 11,050.0 6,224.3 6,233.9 A-1, 31-1-21 7/311999 6.0 APERF 2.5" HSD/DP, 60 deg pH, spiral chg RPERF; 10,954.0-10,956.0---- 11,058.0 11,072.0 6,237.7 6,244.4 A-1, 31-1-21 8/25/1988 4.0 IPERF 4.5" Ultra Pack, 120 deg ph RPERF; 10,954.0-10,973.0- Mandrel Inserts at APERF; 10,965.0-10,985.0- art RPERF; 10,973.0-10,992.0- on N Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Valve So, Type Latch Port Type Size (in) TRO Run (psi) Run Date Com 3,191.3 2,423.2 CAMCO KBUG 1 GAS LIFT GLV BK-2 0.313 1,225.0 3/26/2019 2 6,683.4 4,026.6 CAMCO KBUG 1 GAS LIFT GLV BK-2 0.188 1,225.0 3/26/2019 3 8,591.5 4,970.7 CAMCO KBUG 1 GAS LIFT OV BK-2 0.250 0.0 3/25/2019 APERF; 11,010.0-11 030.0 4 9,575.6 5,482.7 CAMCO KBUG 1 GAS LIFT DMY BK-2 0.0 3/25/2019 5 10,099.0 5,755.0 CAMCO KBUG 1 GAS LIFT DMY SK-2 0.000 0.0 4/13/1993 FISH; 11,029.0 6 10,538.2 5,982.0 CAMCO MMG-2 1 112 GAS LIFT DMY RK 0.0 3/23/2019 APERF; 11,030.0-11,050.0- Notes: General & Safety End Date Annotation IPERF; 11,058.&11,072.0- 12/5/2005 NOTE: WAIVERED WELL: IA x CA COMMUNICATION 9/Z2010 NOTE: View Schematic w/ Alaska Schematic9.0 PRODUCTION; 35.0-11,300.3 0 Cm G N L V U) 0 H U m N O CL O L a T N S Cl) as m � � m o m N O ❑ N� ID m O n N O d) m O O N 'O U m d O .0 _ U M N O O O W O) _ m 0 W O C M Cl)N O a N y < O O o_ v O " o a U) c LO co 'E ❑ Q Q o o rn C cL U �� m C `° H m m m U ❑ a U � O U O. O U N N N 2 2 ro O U m U m LL U U cV (V (V Cl) N Ul fV (V Y Y ro ro Cl) Cl) M� in m Cl) Cl) U 0 0 IN 0 I w ❑ ❑❑❑❑ o N LO 0 N O '❑ N m m b N❑ N a 3k O coN� ron CO O LC)O NM OY M000 0 �� Q Weill KRU XX-XX Nabors CDR3-AC: 4-Ram BOP Configuration 2" Date April 24, 2019 Coiled Tubing and 2-318" BHA Quick Test Sub to Ot Top of 7" Otis Distances from top o Excluding quick -test Top of Annular CL Annular Bottom Annular Fianl CL Blind/Shears CL 2" Combi's CL 2-3/8" Combi's CL 2" Combi's CL of Top S Top of Swal CL Swab 1 Flow Tee CL SSV CL Master LDS Ground Tree Size 3 1/8 ne TRANSMITTAL LETTER CHECKLIST WELL NAME: K Rck, 3 H — 3 1 A PTD: q - © Ge VDevelopment _ Service _Exploratory _ Stratigraphic Test Non -Conventional FIELD: Ck V'U � 1 VQF OL: dw-u K 1 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- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -) from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals 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. hi addition to the well logging program proposed by V/ (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 3H-21A_ _ Program DEV — _ Well bore seg ❑ PTD#:2190660 Company CONOCO_PHILLIPS ALASKA, INC_ — — Initial Class/Type D_EV /-PEND __GeoArea 890 Unit 11160 On/Off Shore On _ Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes 3 Unique well name and number Yes - 4 Well located in a defined pool _ - - - - Yes 5 Well located proper distance from drilling unit _boundary Yes 6 Well located proper distance from other wells_ Yes 7 Sufficient acreage available in_drilling unit _ - Yes - 8 If deviated, is wellbore plat included Yes Directional_ plan view & wellbore profile included. 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15-day wait_ Yes DLB 5/1/2019 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 I 17 Nonconve_n, gas conforms to AS31.05.030.1.A),0.2.A-D) - NA �18 Conductor string provided NA Conductor set in KRU 31-1-21 Engineering 19 Surface casing protects all known_ USDWs NA Surface casing set in KRU 31-1-21 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 No 22 CMT will cover all known productive horizons No Productive_ interval will be completed with uncemented production 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 1.0-403 for abandonment been approved Yes PTD 188-008, Sundry 319-216 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 4983 psig(15.5 ppg EMW); will drill w/ 8.6 ppg and maintain overbal w/ MPD 29 BOPEs, do they meet regulation Yes 30 BOPE_press rating appropriate; test to _(put psig in comments) Yes MPSP is 4362 psig; will test BOPs to 4800 psig I31 Choke manifold complies w/API_ RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable Yes H2S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 135 Permit can be issued w/o_ hydrogen sulfide measures No 3H-Pad wells are H2S-bearing. 112S measures are required. - Geology 36 Data presented on potential overpressure zones Yes Appr Date 37 Seismic analysis of shallow gas zones NA DLB 5/1/2019 38 Seabed condition survey (if off -shore) NA :39 Contact name/phone for weeklyprogressreports_ [exploratory only] NA- Geologic Engineering Public Commissioner: Date: Commissioner: Date Commissioner Date
