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Home My WebLink About219-1861 Winston, Hugh E (OGC) From:Winston, Hugh E (OGC) Sent:Thursday, January 13, 2022 3:10 PM To:McLaughlin, Ryan; Germann, Shane Cc:Loepp, Victoria T (OGC) Subject:CPAI Expired Permits Hello, The following permits have expired under regulation 20 AAC 25.005 (g). The permits has been marked expired in their well history file and in the AOGCC database. Please let me know if you have any questions or concerns regarding this expiration.  KRU 1R‐23AL1 expired 12/4/2021  KRU 1R‐23AL3 expired 12/4/2021  KRU 3O‐04L1‐02 expired 12/13/2021 Huey Winston Statistical Technician Alaska Oil and Gas Conservation Commission hugh.winston@alaska.gov 907‐793‐1241 THE STATE °'t1LASKA GOVERNOR MIKE DUNLEAVY James Ohlinger Staff CTD Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk Oil Pool, KRU 30-04L 1-02 ConocoPhillips Alaska, Inc. Permit to Drill Number: 219-186 Alaska Oil and Gas Conservation Commission Surface Location: 789' FNL, 1879' FWL, Sec. 22, T13N, R9E, UM Bottomhole Location: 706' FSL, 2622' FWL, Sec. 16, T13N, R9E, UM Dear Mr. Ohlinger: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the permit to drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 188-062, API No. 50-029- 21826-00-00. Production should continue to be reported as a function of the original API number stated above. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincere_ ll , �)— r `�. Price Chai DATED this N"S day of December, 2019. STATE OF ALASKA ALA + OIL AND GAS CONSERVATION COMMI, N PERMIT TO DRILL 20 AAC 25.005 ��D DEC - 6 2019 1 a. Type of Work: Drill ❑ Lateral ❑� Redrill ❑ Reentry ❑ 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ Stratigraphic Test ElDevelopment - Oil [AService - Winj ❑ Single Zone ❑� Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ 1cA(JJf I i kJoosed for: Coalbed & as Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Bond: Blanket 0 Single Well ❑ Bond No. 5952180 11. Well Name and Number: KRU 30-041-1-02 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 10,350' - TVD: SS: 6478' • 12. Field/Pool(s): Kuparuk River Pool / Kuparuk River Oil Pool 4a. Location of Well (Governmental Section): Surface: 789' FNL, 1879' FWL, Sec. 22, T13N, R9E, UM Top of Productive Horizon: 1306' FSL, 2283' FWL, Sec. 16, T13N, R9E, UM Total Depth: 706' FSL, 2622' FWL, Sec. 16, T13N, R9E, UM 7. Property Designation: ADL 25513 8. DNR Approval Number: LONS 85-100 13. Approximate Spud Date: 12/17/2019 9. Acres in Property: 2560 14. Distance to Nearest Property: 7920' 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 524664 59M5b= ne- 4 10. KB Elevation above MSL (ft): 59' GL / BF Elevation above MSL (ft): 19, 15. Distance to Nearest Well Open to Same Pool: 1739' (30-02) 16. Deviated vMIT. cko depth: 86 5 feet Maximum Hole Angle: 101 degrees 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Downhole: 4244 Surface: 3588 18. Casing Program: V Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2-3/8" 4.7# L-80 ST-L 1680' 8670' 6496' 10,350' 6478' Slotted Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 8,984 Total Depth TVD (ft): 6785 Plugs (measured): 8694 Effect. Depth MD (ft): 8,850 Effect. Depth TVD (ft): 6687 Junk (measured): N/A Casing Length Size Cement Volume MD TVD Conductor 80' 16" 199 Sx ASIII 115' 115' Surface 5064' 9-5/8" 1200 Sx ASIII, 375 Sx Class G 5099' 4029' Production 8928' 7" 300 Sx Class G, 175 Sx ASI 8961' 6799' Liner 899' 4-1/2" 28 bbls Class G 8850' 6687' Perforation Depth MD (ft): 8675' - 8695' Perforation Depth TVD (ft): 6559' - 6573 Hydraulic Fracture planned? ❑ ❑� 20. Attachments: Property Plat ❑ BOP Sketch Diverter Sketch ® Drilling Program Seabed Report Time v. Depth Plot Shallow Hazard Analysis H Drilling Fluid Program 20 AAC 25.050 requirements✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Shane Germann Authorized Name: James Ohlinger Contact Email: Shane. German n COP.com Authorized Title: Staff CTD Engineer Contact Phone: 907-263-4597 Authorized Signature: Date: lal-s/lf Commission Use Only Permit to Drill Number: N-- $6_ API Number: 50- OZ — Z 1812 Z _Q Permit Approval Date: 1211311 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: lilol Other: BoP fi�S t Samples req'd: Yes ❑ No[/ Mud log req'd: Yes❑ Nov 1-�SS �r� fo g O UG 9 �/ H2S measures: Yes `L� Now❑/ Directional svy req'd: Yes l[�No❑ �hhl//Cil� pr�v�nl-r�- �t5f 9 P q' ❑ NoLJ Y Y q' ❑Nov Spacing exception req'd: Yes Inclination -only sv req'd: Yes No Post initial injection MIT req'd: Yes ❑ No L ,ZDo9f�C Z�',o (!o) Ts 9rar�ficd fn �1/ow the ,�� k F pe, fi to be Gill Pol17Y Q-O16?-J / APPROVED BY Approved by: _��pppCCC COMMISSIONER THE COMMISSION Date. °0 1/2NALTsperSubmit Form and F m o his permit is valid for 24 months frpm the date of approval per 20 AAC 25.005(g) Attachments in Duplicate ConocoPhillips s Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 December 5, 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 three laterals out of the KRU 30-04 (PTD# 188-062) using the coiled tubing drilling rig, Nabors CDR3-AC. CTD operations are scheduled to begin in mid December 2019. The objective will be to drill three laterals, KRU 30-041-1, 30-041-1-01 and 30-041-1-02, 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 permit to drill applications are the following documents: — Permit to Drill Application Forms (10-401) for 30-041-1, 30-041-1-01 and 30-041-1-02 — Detailed Summary of Operations — Directional Plans for 30-04L1, 30-041-1-01 and 30-041-1-02 — Current Wellbore Schematic — Proposed CTD Schematic If you have any questions or require additional information, please contact me at 907-263-4597. Sincerel , Shane Germann Coiled Tubing Drilling Engineer ConocoPhillips Alaska Kuparuk CTD Laterals s' 30-04L1, 30-04L1-01 & 30-04L1-02 Application for Permit to Drill Document 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(o and 20 AAC 25.005(b))...................................................................................................................2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2))..................................................................................................................................................2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 2 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7)).................................................................................................................................................. 3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9)).................................................................................................................................................. 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4 11. Seabed Condition Analysis............................................................................................................ 4 (Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................ 4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 4 13. Proposed Drilling Program.............................................................................................................4 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................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 for30-04L1, 30-041-1-01 & 30-041-1-02 laterals.........................................................6 Attachment 2: Current Well Schematic for 2M-21...........................................................................................................6 Attachment 3: Proposed Well Schematic for 30-041-1, 30-041-1-01 & 30-041-1-02 laterals...........................................6 Page 1 of 6 December 3, 2019 PTD Application: 30-6,L-1, 30-041-1-01 & 30-041-1-02 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 30-041-1, 30-041-1-01 & 30-041-1-02. All laterals will be classified as "Development' 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 form for surface and subsurface coordinates of the 30-041-1, 30-04L1-01 & 30-041-1-02. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR3-AC. BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4,000 psi. Using the maximum formation pressure in the area of 4244 psi in 30-10 (i.e. 13.1 ppg EMW), the maximum potential surface pressure in 30-04, assuming a gas gradient of 0.1 psi/ft, would be 3588 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 30-04 was measured at the datum to be 3893 psi (11.82 ppg EMW) on 9/26/2019. The maximum downhole pressure in the 30-04 vicinity is to the south in the 30-10. Pressure was measured to be 4244 psi, at the datum, (13.1 ppg EMW) in June of 2019. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) The offset injection wells to 30-04 have injected gas, so there is a possibility of encountering free gas while drilling the 30-04 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)(c)) The major expected risk of hole problems in the 2M-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 30-04 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 December 3, 2019 PTD Application: 30-6,L.1, 30-04L1-01 & 30-041_1-02 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 30-041_1 9250' 12,000' 6549' 6503' 2-3/8", 4.7#, L-80, ST-L slotted liner, - aluminum billet on to 30-041_1-01 8775' 12,000' 6550' 6523' 2-3/8", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 30-041_1-02 8670' 10,350' 6496' 6478' 2-3/8", 4.7#, L-80, ST-L slotted liner; deployment sleeve on top Existing Casing/Liner Information Category OD Weight f Grade Connection Top MD Btm MD Top TVD Btm TVD Burst si Collapse psi Conductor 16" 62.5 H-40 Welded Surface 115' Surface 115' 1640 [4980 670 Surface 9-5/8" 36.0 J-55 BTC Surface 5099' Surface 4029' 3520 2020 Production 7" 26.0 J-55 BTC Surface 8961' Surface 6769' 4320 Liner 4-1/2" 12.6 L-80 IBTM 7951' 8850' 6038' 6687' 8430 7500 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 PowerVis milling fluid (8.6 ppg) — Drilling operations: Water -based PowerVis mud (8.6 ppg). This mud weight will not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. — Completion operations: The well will be loaded with 11.8 ppg NaCl / NaBr completion fluid in order to provide formation over -balance and well bore stability while running completions. Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000 psi rated coiled tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". In the 30-04 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. Page 3 of 6 December 3, 2019 PTD Application: 30-%.-.L1, 30-041-1-01 & 30-041_1-02 Pressure at the 30-04 Window 8675' MD, 6558' TVD Usin MPD Pumps On 1.9 b m Pumps Off A -sand Formation Pressure 11.8 4023 psi 4023 psi Mud Hydrostatic 8.6 2933 psi 2933 psi Annular friction i.e. ECD, 0.080 si/ft 694 psi 0 psi Mud + ECD Combined no chokepressure) 3627 psi (underbalanced -396 psi) 2933 psi (underbalanced -1090 psi) Target BHP at Window 11.8 4024 psi — 4024psi' Choke Pressure Required to Maintain Target BHP 397 psi 1091 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 KRU well 30-04 is a Kuparuk A -Sand producer equipped with 3-1/2" tubing and 4-1/2" liner. The CTD sidetrack will utilize three laterals to target the A -sands to the north and east of 30-04. The laterals will increase A -sand resource recovery and throughput. Prior to CTD rig up, E-Line will set a mechanical whipstock (TTWS) inside the 442" liner at the planned kick off point of 8675' MD. The 30-041-1 lateral will exit through the 4-1/2" liner and 7" casing at 8675' MD and drill to a planned TD at 12,000' MD, targeting the A sand to the north. The lateral will be completed with 2-3/8" slotted liner from TD up to 9250' MD with an aluminum billet for kicking off. The 30-041-1-01 lateral will kick off at 9250' MD and drill to a planned TD of 12,000' MD targeting the A sand to the north. It will be completed with 2-3/8" slotted liner from TD up to 8775' MD with an aluminum billet for kicking off. The 30-041-1-02 lateral will kick off at 8775' MD and drill to a planned TD of 10,350' MD targeting the A sand to the east. It will be completed with 2-3/8" slotted liner from TD up into the 4-1/2" liner at 8670' MD with a deployment sleeve. Page 4 of 6 December 3, 2019 PTD Application: 30-%.,L1, 30-041_1-01 & 30-041_1-02 CTD Drill and Complete 30-04 Laterals: Pre-CTD Work 1. RU Slickline: Dummy whipstock drift, C/O GLV's 2. RU E-Line: Caliper, set top of whipstock at 8675' MD 3. 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. 30-041-1 Lateral (A sand - North) a. Mill 2.80" window at 8675' MD. b. Drill 3" bi-center lateral to TD of 12,000' MD. c. Run 2-3/8" slotted liner with an aluminum billet from TD up to 9250' MD. 3. 30-041-1-01 Lateral (A sand - North) a. Kick off of the aluminum billet at 9250' MD. b. Drill 3" bi-center lateral to TD of 12,000' MD. c. Run 2-3/8" slotted liner with an aluminum billet from TD up to 8775' MD. 4. 30-04L1-02 Lateral (A sand - East) a. Kick off of the aluminum billet at 8775' MD. b. Drill 3" bi-center lateral to TD of 10,350' MD. c. Run 2-3/8" slotted liner with deployment sleeve from TD up to 8670' MD 5. Obtain SBHP, freeze protect, ND BOPE, and RDMO Nabors CRD3-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 double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slick -line lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slick -line. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment, the steps listed above are observed, only in reverse. Page 5 of 6 December 3, 2019 PTD Application: 30-%.,L1, 30-041-1-01 & 30-041-1-02 Liner Running — The 30-04 laterals will be displaced to an overbalancing fluid (11.8 ppg NaCl / NaBr) 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 (1 R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) — The Applicant is the only affected owner. — Please see Attachment 1: Directional Plans — Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. — MWD directional, resistivity, and gamma ray will be run over the entire open hole section. — Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 30-0411-1 7445' 30-0411-1-01 7450' 30-0411-1-02 7920' — Distance to Nearest Well within Pool Lateral Name Distance Well 30-04L1 21' 3R-26 30-0411-1-01 42' 3R-26 30-0411-1-02 1739' 30-02 16.Attachments Attachment 1: Directional Plans for 30-04L1, 30-04L1-01 & 30-04L 1-02 laterals Attachment 2: Current Well Schematic for 30-04 Attachment 3. Proposed Well Schematic for 30-04L 1, 30-04L 1-01 & 30-04L 1-02 laterals Page 6 of 6 December 3, 2019 Weill KRU XX-XX Nabors CDR3-AC: 4-Ram BOP Configuration 2" Date I 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 Flan CL Blind/Shears CL 2" Combi's CL 2-3/8" Combi's CL 2" Combi's CL of Top E Top of Swa CL Swab 1 Flow Tee CL SSV CL Master LDS Ground Tree Size 3 1/8 ne ConocoPhilli s p ConocoPhillips Alaska Inc—Kuparuk Kuparuk River Unit Kuparuk 30 Pad 30-04 30-04L1-02 Plan: 30-04L1-02_wp02 Standard Planning Report 04 December, 2019 Baker Hughes g ConocoPhillips Database: EDT 14 Alaska Production Company: ConocoPhillips Alaska Inc-Kuparuk Project: Kuparuk River Unit Site: Kuparuk 30 Pad Well: 30-04 Wellbore: 30-04L1-02 Design: 30-04 L 1-02_wp02 ConocoPhillips Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Baker Hughes Well 30-04 Mean Sea Level 30-04: @ 59.00usft (30-04:) True Minimum Curvature Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk 30 Pad Site Position: Northing: 6,022,094.67 usft Latitude: 70° 28' 17.333 N From: Map Easting: 525,478.25 usft Longitude: 149° 47' 30.897 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.20 ° well 30-04 / Well Position +NI-S 0.00 usft Northing: 6,022,030.55 usft 1// Latitude: 70° 28' 16.701 N +E/-W 0.00 usft Easting: 525,515.58 usft 1/ Longitude: 149° 47' 29.806 W LPosition Uncertainty 0.00 usft Wellhead Elevation: - - usft Ground Level: 0.00 usft Wellbore 30-041-1-02 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (1 (nT) BGG M2018 12/30/2019 16.28 80.92 57,401 Design 30-041-1-02_wp02 Audit Notes: Version: Phase: PLAN Tie On Depth: 8,775.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 0.00 0.00 0.00 130.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (I (°) (usft) (usft) (usft) (°/100usft) (°1100usft) (°1100usft) (°) Target 8,775.00 79.68 283.66 6,549.98 2,096.05 -4,880.14 0.00 0.00 0.00 0.00 8,845.00 89.86 253.68 6,556.50 2,094.30 -4,948.94 45.00 14.54 -42.83 -73.00 9,000.00 89.95 323.43 6,556.79 2,140.64 -5,086.97 45.00 0.06 45.00 90.00 9,300.00 90.03 188.43 6,556.87 2,083.45 -5,315.18 45.00 0.03 -45.00 -90.00 9,370.00 91.60 156.97 6,555.84 2,014.90 -5,306.40 45.00 2.23 -44.95 -87.00 9,600.00 91.53 140.86 6,549.52 1,818.65 -5,188.08 7.00 -0.03 -7.00 -90.00 9,850.00 97.37 124.31 6,529.98 1,650.56 -5,005.38 7.00 2.34 -6.62 -70.00 10,050.00 100.76 110.55 6,498.33 1,559.73 -4,830.60 7.00 1.69 -6.88 -75.00 10,350.00 87.01 94.59 6,477.92 1,495.30 -4,540.03 7.00 -4.58 -5.32 -130.00 121412019 3:15:24PM Page 2 COMPASS 5000 14 Build 85H ConocoPhillips 10-1 ConocoPhillips Planning Report Baker Hughes - Database: EDT 14 Alaska Production Local Co-ordinate Reference: Well 30-04 Company: ConocoPhillips Alaska Inc-Kuparuk TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-04: @ 59.00usft (30-04:) Site: Kuparuk 30 Pad North Reference: True Well: 30-04 Survey Calculation Method: Minimum Curvature Wellbore: 30-041-1-02 Design: 30-04 L 1-02_wp02 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +NI-S +E/-W Section Rate Azimuth Northing Easting (usft) (°) (°) (usft) (usft) (usft) (usft) (°1100usft) (°) (usft) (usft) 8,775.00 79.68 283.66 6,549.98 2,096.05 -41880.14 -5,085.72 0.00 0.00 6,024,109.65 520,628.76 TIP/KOP 8,800.00 83.13 272.83 6,553.72 2,099.58 -4,904.57 -5,106.70 45.00 -73.00 6,024,113.09 520,604.33 8,845.00 89.86 253.68 6,556.50 2,094.30 -4,948.94 -5,137.30 45.00 -71.38 6,024,107.67 520,559.99 Start DLS 45.00 TFO 90.00 8,900.00 89.87 278.43 6,556.63 2,090.55 -5,003.38 -5,176.59 45.00 90.00 6,024,103.73 520,505.56 9,000.00 89.95 323.43 6,556.79 2,140.64 -5,086.97 -5,272.82 45.00 89.94 6,024,153.53 520,421.81 Start DLS 45.00 TFO -90.00 9,100.00 89.97 278.43 6,556.87 2,190.73 -5,170.56 -5,369.05 45.00 -90.00 6,024,203.33 520,338.05 9,200.00 90.00 233.43 6,556.90 2,167.04 -5,265.09 -5,426.24 45.00 -89.97 6,024,179.32 520,243.62 9,300.00 90.03 188.43 6,556.87 2,083.45 -5,315.18 -5,410.88 45.00 -89.95 6,024,095.57 520,193.82 Start DLS 45.00 TFO -87.00 9,370.00 91.60 156.97 6,555.84 2,014.90 -5,306.40 -5,360.09 45.00 -87.00 6,024,027.05 520,202.83 Start DLS 7.00 TFO -90.00 9,400.00 91.60 154.87 6,555.01 1,987.52 -5,294.16 -5,333.12 7.00 -90.00 6,023,999.72 520,215.16 9,500.00 91.58 147.86 6,552.24 1,899.84 -5,246.29 -5,240.08 7.00 -90.06 6,023,912.21 520,263.33 9,600.00 91.53 140.86 6,549.52 1,818.65 -5,188.08 -5,143.30 7.00 -90.25 6,023,831.23 520,321.81 Start DLS 7.00 TFO -70.00 9,700.00 93.91 134.27 6,544.77 1,744.97 -5,120.72 -5,044.35 7.00 -70.00 6,023,757.79 520,389.41 9,800.00 96.24 127.64 6,535.91 1,679.72 -5,045.55 -4,944.82 7.00 -70.31 6,023,692.80 520,464.80 9,850.00 97.37 124.31 6,529.98 1,650.56 -5,005.38 -4,895.30 7.00 -70.90 6,023,663.78 520,505.07 Start DLS 7.00 TFO -75.00 9,900.00 98.27 120.89 6,523.18 1,623.87 -4,963.66 -4,846.19 7.00 -75.00 6,023,637.24 520,546.88 10,000.00 99.96 114.01 6,507.32 1,578.38 -4,876.10 -4,749.87 7.00 -75.46 6,023,592.05 520,634.58 10,050.00 100.76 110.55 6,498.33 1,559.73 -4,830.60 -4,703.03 7.00 -76.56 6,023,573.56 520,680.15 Start DLS 7.00 TFO-130.00 10,100.00 98.49 107.84 6,489.97 1,543.53 -4,784.05 -4,656.95 7.00 -130.00 6,023,557.52 520,726.75 10,200.00 93.92 102.50 6,479.15 1,517.56 -4,688.15 -4,566.80 7.00 -130.45 6,023,531.88 520,822.72 10,300.00 89.32 97.23 6,476.32 1,500.45 -4,589.73 -4,480.40 7.00 -131.03 6,023,515.11 520,921.19 10,350.00 87.01 94.59 6,477.92 1,495.30 -4,540.03 -4,439.02 7.00 -131.18 6,023,510.13 520,970.90 Planned TD at 10350.00 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 10,350.00 6,477.92 2-3/8" 2.375 3.000 121412019 3.15:24PM Page 3 COMPASS 5000 14 Build 85H ConocoPhillips ConocoPhillips Planning Report Baker Hughes Database: EDT 14 Alaska Production Company: ConocoPhillips Alaska Inc_Kuparuk Project: Kuparuk River Unit Site: Kuparuk 30 Pad Well: 30-04 Wellbore: 30-04L1-02 Design: 30-041-1-02_wp02 Plan Annotations Measured Vertical Depth Depth (usft) (usft) 8,775.00 6,549.98 8,845.00 6,556.50 9,000.00 6,556.79 9,300.00 6,556.87 9,370.00 6,555.84 9,600.00 6,549.52 9,850.00 6,529.98 10,050.00 6,498.33 10,350.00 6,477.92 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Local Coordinates +NI-S +E/-W (usft) (usft) 2,096.05 -4,880.14 2,094.30 -4,948.94 2,140.64 -5,086.97 2,083.45 -5,315.18 2,014.90 -5,306.40 1,818.65 -5,188.08 1,650.56 -5,005.38 1,559.73 -4,830.60 1,495.30 -4,540.03 Comment Well 30-04 Mean Sea Level 30-04: @ 59.00usft (30-04) True Minimum Curvature TIP/KO P Start DLS 45.00 TFO 90.00 Start DLS 45.00 TFO -90.00 Start DLS 45.00 TFO -87.00 Start DLS 7.00 TFO -90.00 Start DLS 7.00 TFO -70.00 Start DLS 7.00 TFO -75.00 Start DLS 7.00 TFO-130.00 Planned TD at 10350.00 121412019 3:15:24PM Page 4 COMPASS 5000 14 Build 85H ConocoPhillips ConocoPhillips Anticollision Report Baker Hughes Company: ConocoPhillips Alaska Inc_Kuparuk Project: Kuparuk River Unit-2 Reference Site: Kuparuk 30 Pad Site Error: 0.00 usft Reference Well: 30-04 Well Error: 0,00 usft Reference Wellbore 30-04L1-02 Reference Design: 30-04L1-02_wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 30-04 30-04: @ 59.00usft (30-04) 30-04: @ 59.00usft (30-04) True Minimum Curvature 2.00 sigma EDT 14 Alaska Production Offset Datum Reference 30-041-1-02_wp02 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 8,775.00 to 10,350.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum ellipse separation of 3,000.00 usft Error Surface: Combined Pedal Curve Warning Levels Evaluated at: 2.79 Sigma Casing Method: Added to Error Values Survey Tool Program Data 12/4/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description 100.00 8,600.00 30-04 (30-04) BOSS -GYRO Sperry -Sun BOSS gyro multishot 8,600.00 8,775.00 30-04L1_wp02 (30-041-1) MWD OWSG OWSG MWD - Standard 8,775.00 10,350.00 30-04L1-02_wp02 (30-041-1-02) MWD OWSG OWSG MWD - Standard Summary Site Name Offset Well - Wellbore - Design Kuparuk 30 Pad 30-01 - 30-01 A - 30-01 A 30-01 - 30-01AL2 - 30-01AL2 30-01 - 30-01AL3 - 30-01AL3 30-02 - 30-02 - 30-02 30-02 - 30-02A - 30-02A 30-02 - 30-02ALl - 30-02ALl 30-02 - 30-02ALl P131 - 30-02ALl PB1 30-02 - 30-02AL2 - 30-02AL2 30-02 - 30-02AL2-01 - 30-02AL2-01 30-04 - 30-04 - 30-04 30-04 - 30-041-1 - 30-04Ll_wp02 30-04 - 30-041-1-01 - 30-041-1-01_wp01 30-10 - 30-10 - 30-10 Reference Offset Distance Measured Measured Between Between Separation Warning Depth Depth Centres Ellipses Factor (usftl (usft) (usft) (usft) 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 8,905.68 8,984.00 173.74 170.19 48.946 CC, ES, SF 9,080.00 9,100.00 133.41 130.79 50.858 CC, ES, SF 9,080.00 9,100.00 133.41 130,79 50.858 CC, ES, SF Out of range Offset Design Kuparuk 30 Pad - 30-04 - 30-04 - 30-04 Offset Site error: 0.00 usft Survey Program: 100-BOSS-GYRO Onset 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 +N/S +E/•W Centres Ellipses Separation Factor (usft) (usft) (usft) (usft) (usft) (usft) (°i (usft) (usft) (usft) (usft) (usft) 8,782,42 6,610.24 8,800.00 6,650.53 1,32 3.46 100.75 2,096.15 -4,880,83 40.83 38,39 2.44 16.719 8,800,00 6,612.72 8,825.00 6,668.87 1_33 3.89 91.89 2,100.15 -4,897.34 56.61 54,09 2.53 22.384 8,815.02 6,614.23 8,850.00 6,687,24 1.33 4.32 83.03 2.104.16 -4,913.82 73,38 70.75 2.63 27.902 8,828.48 6.615.09 8,875.00 6,705,64 1.34 4.74 74.61 2,108.17 -4,930,26 91.15 88.41 2.75 33.184 8,840.00 6,615.45 8,900,00 6,724.03 1.34 5,17 67.06 2,112,17 -4,946.71 109.87 107.00 2.87 38,349 8,854.70 6,615,52 8,925.00 6,742.43 1.34 5.60 6Z02 2,116.18 -4,963.16 129.30 126.24 3,06 42.321 8,874.97 6,615.57 8,950.00 6,760.83 1.35 6.03 75.17 2,120,19 -4,979.60 148.51 145.20 3.31 44,933 8,897.33 6,615.62 8,975.00 6,779.22 1.35 6.46 85.38 2,124.20 -4,996.05 167.17 163.67 3.50 47.750 8,905.68 6,615.64 8,984.00 6,785.85 1.35 6,61 89,42 2,125.65 -5,001,97 173,74 170.19 3.55 48.946 CC, ES, SF CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 121412019 9:21:13AM Page 2 COMPASS 5000.14 Build 85H 0 0 o 0 0 0 0 000 C,O O O O M LL LL H LL LL LL LL O 000~ H 0 0 0 0 0 C) 0 0 �. j O O Cl O O co � vvvrrr�� Q) 000 .O LL Cn Cn (n (n Cn (n (n o rn m O o 0 0 0 0 0 0 J N p Y= .0 -tf Q Q H N (n Cn Cn [n (n Cn COM r O CO M O Cl)W r v �9 L17 � � lfj 1 q' -p Z D 000 0000 00 O O O O O O O O O O M O O r C, O t l'i O C. r �rnrneorn�rM O J co Oc M N O O O O O OO o 0 0 ou-iuiiri�ri�rr� mo vvvv r -mm �OCY O M COOO o co cD ui6 co ui o� CNCpp � t C O O C O O M C LQ lt7 O d' O to CD M O J WLr) O� O M W O O Lo Q N4. o o � o o C2 H fJ N N N N N w C O O O r N C O M N J O4') r CO Cm M CA Mm J Qi CCJ O c0 Oi CSi r (jJ > V m �!')��Ln V'Nr Qo� COOOCO cO (D OtOO !E O "' M CO CA M M r CO LO O> � O O(D V ct O)NM LO � z N M t •' M M co C o O O V � N N M - �- OCOOOO COM r 4 r cO COOCT 6Y O)OO O L �i 0 0 0 0 0 0 0 0 0 0 J O O O O O O O O O O + l! �0000000 r C XJ O M M C D G O O M CO CO Cn 00CP000 M st .0 CD � O Z O + Uk N d s rn Y 8 00 - 38 )u1-�OI�I/(�glnos 0 7 o _ _ m M. 0 0 0 0 X- KUP PROD WELLNAME 30-04-LLBORE 30-04 (''� �yy „ `onoc6, hil ipS Alaska, Inc. Well Attributes Max Angle & MD TD Field Name We llbore APl/UWI Wellbore Status cl(°) K PARUK RIVER UNIT 5002921 2 PR ID 1.60 MO IKB) Act 2,600.00 Btm(RKB) 8,984.0 Comment H2S (ppm) Date Annotation End Date KB-Grd (R) SSSV:NIPPLE 140 9/25/2013 Last WO: 7/21/2013 40.00 Rig Release Date 7/9/1988 30-04, 9/26r20196:31.57 PM Last Tag Vertical schematic (actual) Annotation Depth (ftKB) I End Date or Wellbe Last Mod By HANGER, 31.1 CONDUCTOR: 35.0-115o NIPPLE; 508.1 GAS LIFT; 3,098.4 GAS LIFT. 4,760.7 SURFACE; 35.0,5,099.2 GAS LIFT; 6,117A GAS LIFT; 7.166.4 GAS LIFT; 7,a43.2 NIPPLE: 7,901 6 LOCATOR; 7,950.4 SEAL ASSY; 7,959.1 Liner Cement, 7,950.0 ftKB CMT SOZ, 8,622.0-8,640.0- CMT SQZ; 8,653.0-8,6S9.0- APERF; 8,675.0.8695.0 APERF; 8,675.08,fi95 0 APERF; 8,675.0-8,695.0 CMT SOZ: 8,675, 0-8.698. 0 Fish: 8,694.0 CMT SQZ: e,710.0-3.7300.0- LINER; 7,951.443,850.0 PRODUCTION; 33.0-8,961.3 Last Tag: RKB 8,696.0 9/26r2019 30-04 zembaej Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Updated Tag Depth 9/26/2019 30-04 zembaej Casing Strings Casing Description CONDUCTOR Do (in) 16 to(In) 15.06 Top(ftKB) 35.0 Set Depth (ftKB) 115.0 Set Depth (TVD)... 115.0 Wtli-en(I... 62.50 Grade H-40 Top Thread Welded Casing Description SURFACE OD (In) 9 5/8 ID (In) 8.92 Top (ftKB) 35.0 Set Depth (ftKB) 5,099.2 Set Depth (TVD)... 4,029.0 Wt/Len (I... 36.00 Grade J-55 Top Thread BTC Casing Description PRODUCTION OD (In) 7 ID (In) 6.28 Top (ftKB) 33.0 Set Depth (RKB) 8,961.3 Set Depth (TVD)... 6,768.7 WVLen (I... 26.00 Grade J-55 Top Thread BTC Casing Description LINER Do (in) 4112 to (in) 3.96 Top(ftKB) 7,951A Set Depth (ftKB) 8,850.0 Set Depth IWO)_ 6,686.8 WVLen(I... 12.60 Grade L-80 Top Thread IBTM Liner Details Top (RKB) Top (TVD) (ftKB) Top Incl (°) Item Des Co. Nominal ID (In) 7,951.4 6,037.9 45.08 PACKER 2RH ZXP w/HD LINER TOP PACKER 4.310 7,970.0 6,051.0 45.08 HANGER DG FLEX -LOCK LINER HANGER 4.400 7,979.8 6,058.0 45.08 SBE BAKER SEAL BORE EXTENSION 4,000 Tubing Strings Tubing Description S(ring Ma.,. ID (in) Top (RKB) Set Depth (ft.. Set Depfh (TVD) (... W[(1 b/R) Grade Top Connection TUBING WO 3 1/2 2.99 31.1 7,987.9 1,063.7 9.30 L-80 EUE 8rd AB Mod Completion Details Top(ftKB) Top (TVD) (ftKB) Topincl I°) Item Des Com Nominal ID (In) 31.1 31.1 0.08 HANGER CIW GEN IV TUBING HANGER w/ Type'H' Profile 2.992 508.1 508.1 0.38 NIPPLE CAMCO IDS NIPPLE 3.5" x 2.875" 2.875 7,901.7 6,002.8 45.10 NIPPLE CAMCO 3.5" x 2.812" IDS NIPPLE SN: T070815 2.812 7,950.4 6,037.2 45.08 LOCATOR BAKER GBH LOCATOR sub w/ 7-ft Space Out 2.992 7,959.1 6,043.3 45.08 SEALASSY Baker 80-40 Seals 2.990 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl I°) Des Com Run Date ID (in) 8.694.0 6,572.4 42.89 Fish SLIP STOP CATCHER SUB FISH. 1/2 OF A SLIP, 2 10/24/201 FULL SLIPS, SLIP RETAINER RING & 2.70" X 30" 8 CATCHER. 0.000 Perforations & Slots Top(ftKB) Btm(ftKB) Top (TVD) (ftKB) St. (TVD) (R(B) United Zone Date Shot Dens (shots/R 1 Type Com 8,622.0 8,640.0 6,519.7 6,532.9 C-4, C-1, UNIT B, 30-04 1/7/1989 12,0 CMT SQZ 2 1/8" EnerJet, 60 deg. phasing -- Squeezed behind 4-1/2" liner during 2013 RWO 8,653.0 8,669.0 6,542.4 6,554.1 A-3, 30-04 5/7/1989 12.0 CMT SQZ 2 1/8" EnerJet, 60 deg. phasing - Squeezed behind 4-1/2" liner during 2013 RWO 8,675.0 8,695.0 6,558.5 6,573.1 A-1, 30-04 1/5/2015 6.0 APERF 2.5" 6SPF, 60 DEGREE PHASING, DEEP penetrating chgs 8,675.0 8,695.0 6,558.5 6,573.1 A-1, 30-04 8/8/2016 6.0 APERF 2.5 POWERJET OMEGA CHARGES 6 SPF, 60 DEG PHASING 8,675.0 8,698.0 6,558.5 6,575.3 A-2, 30-04 5/7/1989 12.0 CMT SOZ 2 1/8" EnerJet, 60 deg. phasing --Squeezed behind 4-1/2" liner during 2013 RWO 8,675.0 8,695.0 6,558.5 6,573.1 A-2, 30-04 7/18/2013 6.0 APERF 3-3/8" OD 6 SPF MILLENNIUM 60 DEG PHASING 25gr HMX 8,710.0 8,730.0 6,584.1 6,598.8 A-1, 30-04 9/25/1988 8.0 CMT SQZ 4 112" HSD Csg Gun, 45 deg. phasing - Squeezed behind 4-1/2" liner during 2013 RWO Cement Squeezes Top Top (ftKB) Btm (ftKB) (TVD) (RKB) Btm (ND) (ftKB) Des Start Date Com 7,950.0 8,8bU.Uj 6,036.91 6,686.8 LINERCMT 7/15/2013 Mandrel Inserts st ad on N Top(RKB) Top (TVD) (ftKB) Make Model Do (in) Valve S., Type Latch Type Port Size (In) TR0 Run (psi) Run Date Com 1 3,098.4 2,599.8 WTF KBMG 1 GAS LIFT DMY BK 0.000 0.0 9/30/2018 2 4,760.7 3,787.1 WTF KBMG 1 GAS LIFT DMY BK 0.000 0.0 9/30/2018 3 6,117.1 4,747.2 WTF KBMG 1 GAS LIFT DMY BK 0.000 0.0 10/1/'2018 4 7,166.4 5,485.2 WTF KBMG 1 GAS LIFT DMY BK 0.000 0.0 5/14/2019 5 7,843.2 5,961.E WTF KBMG 1 GAS LIFT DMY BK 0.000 0.0 11/18/2014 Notes: General & Safety End Date Annotation 7/10/1994 NOTE: WAIVERED WELL: IA x OA COMMUNICATION 9/8/2003 NOTE: 31" Surf CSG Patch covering hole located 32" below OA valve. PT @ 1,500 psi - good 2013 RWO 5/1812009 NOTE: View Schematic w/ Alaska Schematic9.0 10/2/2015 NOTE: Placed total of 8.1-bbl SANDLOCK-V and 1509# sand behind pipe 10/2/2015 NOTE: Pumped SANDLOCK-V resin frac with 8-PPA Jordan Unimin sand, 8.9-BPM, 5000-psi. 1/27/2016 NOTE: MILLED RESIN TO 8,730 CTMD = COMPLETE 10/31/2018 Note: Unable to locate mandrels @ 7166 & 7832' RKB Q §§ , geb '§] �0 \ \k/ §\� ;.000 \a\ B � E a — §CL 3 0 § § 3 / \ / E \ 7 » e _ a / ƒ \ /& b 9%% 2 2 e o 5 / q / ) C/% \\\ \ m w K �mm n nww §5� E co§ E a. 0f 0 R J CD Co / § " §g § $�� 2 i § 3 COw 2 R j � LD § 17U..) k\ fic §�§ �� ) 22g �§ __ 0) S (ZDEDb - G/ ¥§ ƒ �§§E CN kB �e Cb \m§§ <§@ho c.i 01 g 1 N \�1 CL o 3Cim y 3p a V \ c°r OOO N V)F-H �00, U O N w � W ° O M aan`` V L) N \\ N 60 C //�� V N W E Q- n 2 LO !a\ V j H N -�O C O. 'C G U a) \ \\\ N L Q a00 -2 E \ n2 cc 4 a Lu m n o y \ ODO (n L=LI <n � O C00 m O MHF 0 00 0) J r O O O E ca 4k Cl) E E CL coo 4 U ai a1 U 6 U X m N axi co CV CV CN M CV N LL N (V co Cl) Cl) W C7 coC) m C i r•r•r•r•r•r•r•r•2.2•r•2•r•2.2.2.2•r, �• •r•2.2.2.2•r r 2•r•�•r•r•r•r•r•.••. 1.1•L•1.1•L.L•L.L.L.L.L•1.1i• L••. L•L•LK�LgtiS�•.J& 1K•L•1•L•L•L�. l r•r•r•r•r•ra -_ _ 1.1K•L•L•L•1•L� •r•r•r•r•r•r•r•. LK•L•LK•L•L•L� •r•r•r•r•r•r•ra ;� 1•L•1.1.1.1.1.1' ••L•L•L1.1•L•1.1•L•L•LK•L•L•1•L•L•L•L•1•b1•b r1•b1•L•1 �,,M,{�{?L1{�'.�{� .2•r•2•r•t•2•r•r•2.2.2•r•2.2.2•r•r•r• •r•r•r•r•r•r• •r•r• •r•r•r• •r•r•r•ra o v nw n OHO a) 0 CL y N cca M CA 00 O N U00 N O-m 000000 '0 _ i#- ur ° � a co LO r � N CNp 20 L0 Nc0 c0 co ao 0o coLO - m `D � d) Boyer, David L (CED) From: Germann, Shane <Shane.Germann@conocophillips.com> Sent: Thursday, December 12, 2019 9:14 AM To: Boyer, David L (CED) Cc: Loepp, Victoria T (CED) Subject: RE: [EXTERNAL]X, Motherbore Dave, Y Surface Location for Three KRU 30-04 Laterals from 3)-04 Thanks for catching this and letting me know. It does appear the x,y surface location on the BakerHughes documents are accurate. I must have made a mistake while converting the coordinates. Doing the coordinate conversions again, the surface location from box 4a (legal description) matches the x,y surface location from BakerHughes and what you have listed below. I'm sorry for the confusion this caused. Shane Germann Coiled Tubing Drilling Engineer ConocoPhillips Alaska Office: 907-263-4597 Cell: 406-670-1939 700 G St, ATO 664, Anchorage, AK 99501 From: Boyer, David L (CED) <david.boyer2@alaska.gov> Sent: Thursday, December 12, 2019 8:55 AM To: Germann, Shane <Shane.Germann@conocophillips.com> Cc: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Subject: [EXTERNAL]X, Y Surface Location for Three KRU 30-04 Laterals from 3)-04 Motherbore Hi Shane, In reviewing the PTD applications for the three 30-04 laterals, I encountered a large difference in the x, y surface location reported on the PTD vs. the x, y calculated by Baker Hughes for the same wellhead. KRU 30-04 motherbore (1988) was already in the AOGCC database including the Albers -150 Northing and Easting coordinates. The legal government section description was consistent since 1988, but only the Baker x, y surface calculation matched previous records in the RBDMS and GeoGraphix databases. We are using the Baker surface x, y for all three laterals. For example, on the x axis alone, the discrepancy was 4500'. made the corrections on the PTD but wanted to advise you of this anomaly. Perhaps it was a cut and paste error from another well? We are using: x=525515.58 & Y=6022030.55 from the survey file. Best, Dave Boyer AOGCC Loepp, Victoria T (CED) From: Germann, Shane <Shane.Germann@conocophillips.com> Sent: Monday, December 9, 2019 9:13 AM To: Loepp, Victoria T (CED) Cc: Ohlinger, James J Subject: KRU 30-04 PTD & Sundry Applications Attachments: 30-04 Proposed Schematic V1.1.pdf Follow Up Flag: Follow up Flag Status: Flagged Victoria, I'm following up after our conversation on Friday concerning the naming of the proposed 30-04 CTD laterals (1-1, 1-1-01, & L1-02). After some research, the 4-1/2" scab liner that was cemented in place on 7/15/2013 was perforated through to the A2 sand for production. It was perforated on 3 occasions (7/18/2013, 1/5/2015, & 8/8/2016) from 8675' — 8695' MD. The original CTD schematic sent with the PTD applications made it unclear if the cemented scab liner had been perforated, so I've updated and attached the schematic to show these perforations. I believe this would make the L1, 1-1-01, and L1-02 naming convention correct. Please let me know if you have any questions or would like to discuss further. Shane Germann Coiled Tubing Drilling Engineer Office: 907-263-4597 Cell: 406-670-1939 700 G St, ATO 664, Anchorage, AK 99501 Tr s ai'�rm oints Source coordinate system State Plane 1327 - Alaska Zone 4 Datum NAD 1927 - North America Datum of 1927 irAean) 5993905.62 476227.35 1 022030.55 1525515.58. X Target coordinate system Albers Equal ,area Datum: NAD 1927 - North .America Datum of 1927lMean) Easting Northing 1 7931.4 12276521.7 .4 2 — - � �Chi6 hna+che,S Nt<�4` HuSti� X� 4�d o Lf- ,.tee U heu. d Y rupH; , Type values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctrt+C to copy and Ctrs+V to paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. e Back Finish Cancel Help TRANSMITTAL LETTER CHECKLIST WELL NAME: R%c-- 3 O -- 0 L-1— O PTD: — l 3-6' LDevelopment _ Service Exploratory S P ry _ tratigraphic Test _Non -Conventional FIELD: �,_ v GG 1 V POOL: Ku' l'" R i ✓ (� Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER V/ MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. I g$ — O API No. 50- O �--_ 2 ! S g h-, --aa- Gb . (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 fast caught and 10' sam le 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. (Compan Name) must contact the AOGCC to obtain x-approval of such water well testing program - Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 da s after cetion, wsperasion or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field RIVER, KUPARUK RIV OIL - 490100 PTD#:219186 Com Administration 1 Appr Date DLB 12/11/2019 7 8 9 10 11 12 13 14 15 16 17 Initial C Well Name: KUPARUK RIV UNIT 30-041-1-02 Program DEV DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Perm it fee attached_ NA_ Lease number appropriate- - - - - - - - - - - - - - - Yes Unique well name and number _ - - - - - Yes - - - - - - Well located in a_definedpool- - - - - - - - - - - - - - - - - - Yes _ Well located proper distance from drilling unit_boundary_ - - - - Yes .... Well located proper distance from other wells- - - - - - - - - - - - - Yes _ . Sufficient acreage available in drilling unit - - _ _ . _--------- - - - - - - - - - - - - Yes _ - - _ ----------------------------------- ------ - - - - - - - - - - - - - - - - - - If deviated, is_wellbore plat -included - - - - - - _ - - - Yes Directional_plan view & wellbore profile included. Operator only affected party - - - - - - - - - - - - - - - - - - - - - Yes Operator has_appropriate_bondinforce-------------------------- ----- Yes -------._ _ ___--------- _ ----------------------- Permit_can be issued without conservation order_ - - - - _ Yes _ - Permit_ can be issued withoutadministrative- approval_ - - - Yes- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - C-an permit be approved before 15-day wait- - - - - - - - - - - - - Yes _ - - _ - - - _ - _ - - . - - Well located within area and -strata authorized by -Injection Order # (put_10# in_comments)_(For_ NA_ - _ - _ ---------------------------------------------------- All wells- within 1/4_mile area of review identified (For service wel_I only)- - - - - - - - - - NA_ - - - - - - - - . - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Pre -produced injector; duration of pre production less than 3 months- (For service well only) - NA_ - - - Nonconven. gas conforms to AS31,05 030G.1_.A),(j.2.A-D) - - - - - - - - NA- - - - - - - - - - - - - - - - - - - - - - - - - - - _ - - . - _ - - - - - - - - - - - - Well bore seg 0 Annular Disoosal I-1 18 Conductor string -provided - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - .. NA- - _ - - - - Conductor set_for_KRU_ 30-04 - - - - - Engineering 19 Surface casing_p_rotects all known_ USDWs - - - - - - NA_ - - - - Surface casing set for KRU 30-04_ _ _ - - - - - - - - - - - 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_ uncementedproduction 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 - - - - - - - - - - - - - - - - - - - - - - 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 28 Drilling fluid program schematic&equip list adequate- - - - - - - - - - - - - - - - - - Yes - - - - - . - Max for_mation_pressure is_4244 psig(13.1_ ppg_E_MW); will drill_w/ 8.6-ppg EMW and -maintain ov_erbal_w/ MPD _ - VTL 12/13/2019 29 BOPEs,_do they meet regulation - - - - - - - - - - - - - - - - - - -- - - - Yes - - - - - - - - - - _ ----------------------- - - - - - - - - - - - - - - - - - - - - - - - - - - - . - 30 BOPE_press rating appropriate; test to _(put prig in comments)- - - - - - - - - - - - - - - - - - - - Yes . _ _ _ . - - MPSP is 3588 psig; will test BOPs_to 4000_psig - - - _ - _ 31 Choke_manifold complies w/API_RP-53 (May 84)_ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ - _ _ _ _ _ _ - - - - - - - - - - . _ - - _ _ _ _ _ _ _ _ _ _ _ 32 Work will occur without operation shutdown ----- _-------------------------- Yes_______________________________________________________________ 33 --- -- - - - - -- Is presence_ ofH2Sgas probable -- - - - - -- Yes H2Smeasures 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_ _ _ _ _ _ _ _ 30-Pad wells are_H2S-bearing._ H2S_ measures are required. _ _ _ _ _ - - _ _ _ - - - - - - Geology 36 Data -presented on potential overpressure zones - - - - - - - _ - . - - - - - Yes - - - - Managed pressure drilling -with CTD unit - - - - - - - - - - - - - - - - - - - - - - - - - - Appr Date 37 Seismic -analysis of shallow gas -zones --------------- - - _ - - NA_ - - - - - ----------------------------------------------- 38 Seabed condition survey -(ifoff--shore)------------------------ ----------NA----- ------------------------------------ --------, 39 Contact name/phone for weekly -progress reports_ [exploratory only] - - - - NA_ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Geologic Engineering Public Commissioner: Date: Commissioner: Date o m m i s s i ne Date