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Home My WebLink About219-130Davies, Stephen F (CED) From: McLaughlin, Ryan <Ryan.McLaughlin@conocophillips.com> Sent: Thursday, November 21, 2019 3:41 PM To: Davies, Stephen F (CED) Cc: Ohlinger, James J Subject: RE: [EXTERNAL]KRU 1R-23 (PTD 191-101; Sundry 319-421, 319-493) - Questions Hello Steve, The existing perforations will be isolated with cement (Sundry #319-493). The cement portion of that work has not occurred yet, but will hopefully commence sometime next week. ConocoPhillips does not plan to attempt to drill 1R-231_1-01, 1R-231_1-02, and 1R-231-1-03 so those permits can be withdrawn. Regards, Ryan McLaughlin Coiled Tubing Drilling Engineer ConocoPhillips Alaska Office:907-265-6218 Cell:907-444-7886 700 G St, ATO 670, Anchorage, AK 99501 From: Davies, Stephen F (CED) <steve.davies@alaska.gov> Sent: Thursday, November 21, 2019 2:22 PM To: McLaughlin, Ryan <Ryan.McLaughlin@conocophillips.com> Subject: RE: [EXTERNAL]KRU 1R-23 (PTD 191-101; Sundry 319-421, 319-493) - Questions Hi Ryan, I'm working on the Permit to Drill applications for the laterals that will be drilled from 1R-23, and I need a bit of clarification. 1. Will all existing perforations in KRU 1R-23 be isolated with cement prior to beginning the currently proposed drilling operations? 2. Does ConocoPhillips wish to withdraw the Permit to Drill applications for 1R-231-1-01, 1R-231-1-02, and 1R-23L1- 03? Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.yov. From: Davies, Stephen F (CED) Sent: Monday, September 16, 2019 11:20 AM To: McLaughlin, Ryan <Ryan.McLaughlin @conocophillips.com> Subject: RE: [EXTERNAL]KRU 1R-23 (PTD 191-101; Sundry 319-421) - Question THE STATE ''ALASKA GOVERNOR MIKE DUNLEAVY Kai Starck CTD Director ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU ConocoPhillips Alaska, Inc. Permit to Drill Number: 219-130 Surface Location: 4854' FNL, 144' FWL, SEC. 17, Bottomhole Location: 4276' FNL, 3330' FWL, SE Dear Mr. Starck: Alaska Oil and Gas Conservation Commission 1 R-23L 1-02 C T 12N, R 1 OE, UM . 4, T 12N, R 1 OE, UM 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Enclosed is the approved application for the permit to redrill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 191-101, API No. 50-029-22200- 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. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this Z% day of September, 2019. STATE OF ALASKA AL, ..,KA OIL AND GAS CONSERVATION COMMIboION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill ❑ Lateral' Stratigraphic Test ❑ Development - Oil Service - Winj ❑ Single Zone 0 ' Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development -Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket 0 Single Well ❑ 11. Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 5952180 • KRU 1 R-231_1-02 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 17,700 TVD: 6827' Kuparuk River Field / Kuparuk River Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 4854' FNL, 144' FWL, Sec 17, T12N, R10E, UM ADL 25627 ALK 2560 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 4031' FNL, 2396' FWL, Sec 9, T12N, R10E, UM LONS 83-134 10/1/2019 9. Acres in Propertv: 14. Distance to Nearest Propertv: Total Depth: 4276' FNL, 333U FWL, Sec 4, T12N, R10E, UM 2560 2541' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 88' 15. Distance to Nearest Well Open Surface: x- 539830 y- 5991630 ° Zone- 4 GL / BF Elevation above MSL (ft): 45' to Same Pool: 2810', 1 R-35 16. Deviated wells: Kickoff depth: 12,500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 98 degrees Downhole: 3515 Surface: 2841 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) 3" 2-3/8" 4.7# L-80 ST-L 6095' 11,605' 6724' 17,700' 6827' Slotted/blank liner with oil & water tracer pups 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): 12180' 7004' N/A 12178' 7003' N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 79' 16" 331 sx AS 1 123' 123' Surface 6289' 9-5/8" 1300 sx PF E, 630 sx Class 'G' 6331' 4072' Production 12149' 7" 380 sx Class 'G' 12178' 7003' Perforation Depth MD (ft): 11710'-11770' Perforation Depth TVD (ft): 6774'-6803' Hydraulic Fracture planned? Yes❑ No 0 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program Time v. Depth Plot ❑ Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 0 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: Ryan McLaugl in Authorized Name: md� Oes MIrger S �� Contact Email: an.mclau hlin co .com Authorized Title: S ngmeer Contact Phone: 907-265-6218 Authorized Signature: Date: Commission Use Only Permit to Drill / _� Number: �(�" /-' API ��Number: _ 50-{-.�1 ` - �� -J� Permit Approval Date: 2, See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: go /�� f �rfssV�-C fD 50 a 5 1 Samples req'd: Yes ❑ No[/ Mud log req'd: Yes ❑ No �� h v`�� Ur�V�h lr ��j` 1- �O �,Qp�5llmeasures: Yes [d No❑ Directional svy req'd: Yes []/No❑ va rl`cl ? ne f O -26 All c 7/5, O �5(��cing ex_c%ption req'd: Yes ❑ No� Inclination -only svy req'd: Yes ❑ No [� Post initial injection MIT req'd: Yes ❑ No� l`5 �rcrhtP� fn alla"i �h� krckof��o/ht ah7 poirq � a,lor9 7`hc P714 -t17f APPROVED BY Approved by: O I O E THE COMMISSION Date: 2li q Form 10-401 Revised 5/2017 . is D rmit is valid f 4 n h o h t Submit Form and oroval Der 20 AAC 25.005fa1 aff.'h,,,o.,f� in n,, ii_+o �/ ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 September 17, 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 1 R-23 (PTD# 191-101) using the coiled tubing drilling rig, Nabors CDR3-AC., CTD operations are scheduled to begin on October 1 st, 2019. The objective will be to drill three laterals — 1 R- 23L1 and 1 R-23L1-01 will be unlined delineation laterals to the north and east, crosscutting through the A3 and C1 sands. 1 R-23L1-02 will be drilled to the north targeting the C1 sands and lined with 2-3/8" solid and slotted liner from TD up into the tubing tail 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 1R-23L1, 1R-23L1-01, & 1R-23L1-02 - Detailed Summary of Operations - Directional Plans for 1R-23L1, 1R-23L1-01, & 1R-23L1-02 - Current wellbore schematic - Proposed CTD schematic If you have any questions or require additional information, please contact me at 907-265-6218. Sincerely, Ryan McLaughlin Coiled Tubing Drilling Engineer ConocoPhillips Alaska Kuparuk CTD Lateral 1 R-231-1, 1 R-231-1-01, & 1 R-231-1-02 Application for Permit to Drill Document 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))................................................................................................................... 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2)).................................................................................................................................................. 2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 2 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7)).................................................................................................................................................. 3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005 c 8......................................................... 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9)).................................................................................................................................................. 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................4 11. Seabed Condition Analysis............................................................................................................4 (Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................ 4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................4 13. Proposed Drilling Program.............................................................................................................4 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................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 1R-23, 1R-23L1-01, & 1R-23L1-02.........................................................................6 Attachment 2: Current Well Schematic for 1 R-23, 1 R-231-1-01, & 1 R-231-1-02...............................................................6 Attachment 3: Proposed Well Schematic for 1 R-23, 1 R-231-1-01, & 1 R-231-1-02...........................................................6 Page 1 of 6 September 16, 2019 PTD Application: 1R-231-1, 1R-231_1-01, & 1R-23L1-02 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 1R-23, 1R-23L1-01, & 1R-23L1-02. The laterals will be classified as "Development - Oil" wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the C1 and A3 sand packages in the Kuparuk reservoir. See attached 10-401 form for surface and subsurface coordinates of 1 R-23, 1 R-231L1-01, & 1 R-231L1-02. 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 3,500 psi. Using the maximum formation pressure in the area of 3517 psi in 1R-23 (i.e. 10.0 ppg EMW), the maximum potential surface pressure in 1 R-23, assuming a gas gradient of 0.1 psi/ft, would be 2841 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 1 R-23 was measured to be 3517 psi (10.0 ppg EMW) on 12/20/2010. The maximum downhole pressure in the 1 R-23 vicinity is the 1 R-23 at 3517 psi or 10.0 ppg EMW on 12/20/2010. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) No specific gas zones will be drilled; gas injection has been performed in this area, so there is a chance of encountering gas while drilling the 1 R-23 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 1 R-23 laterals will be shale instability across faults. Managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossings. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 1R-23L1, 1R-23L1-01, & 1R-23L1-02 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 September 16, 2019 PTD Application: 1R-231-1, 1R-23L1-01, & 1R-231_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 Delineation lateral — will be unlined 1 R-231_1 N/A N/A N/A N/A with an anchored billet set at 14,100' MD Delineation lateral — will be unlined 1R-23L1-01 N/A N/A N/A N/A with an anchored billet set at 12,500' MD 2-3/8", 4.7#, L-80, ST-L slotted/solid 1R-231_1-02 11,605' 17,700' 6636' 6739' liner, with oil and water tracer pups, and sealbore de to ment sleeve Existing Casing/Liner Information Category OD Weight f Grade Connection Top MD Btm MD Top TVD Btm TVD Burs t psi Collapse psi Conductor 16" 62.5 H-40 Welded Surface 123' Surface 123' 1640 670 Surface 9-5/8" 36.0 J-55 BTC Surface 6331' Surface 4072' 3520 2020 Production 7" 26.0 L-80 NSCC Surface 12,178' Surface 7003' 4980 4320 Tubing 3-1/2" 9.3 J-55 TEUEABMOD I Surface 1 11,610 1 Surface 1 6727' 1 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 Power-Vis milling fluid (8.6 ppg) — Drilling operations: Water based PowerVis mud (8.6 ppg). This mud weight may not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. — Completion operations: 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 1 R-23 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 Page 3 of 6 September 16, 2019 PTD Application: 1 R-23L1, 1 R-231_1-01, & 1 R-231_1-02 reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed for improved borehole stability. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Pressure at the 1R-23 Window 01,680' MD, 6760' TVD) Usinq MPD Pumps On 1.8 b m Pumps Off Formation Pressure 10.0 3515 psi 3515 psi Mud Hydrostatic 8.6 3023 psi 3023 psi Annular friction (i.e. ECD, 0.080 si/ft) 934 psi 0 psi Mud + ECD Combined no chokepressure) 3957 psi Overbalanced —442psi) 3023 psi Underbalanced —492psi)' Tar et BHP at Window 11.8 4148 psi 4148 psi Choke Pressure Required to Maintain Target BHP 191 psi 1125 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 1 R-23 is an injector equipped with 3-1/2" tubing and 7" production casing. In preparation for CTD operations on this well, the XN nipple will have to be milled out and a high expansion wedge will be set pre -rig. CDR3-AC will mill a 2.80" window in the production casing at a depth of 11,680' MD. After that, the 1 R-231_1 delineation lateral will be drilled to the north and crosscut through the C1 and A3 sands to determine rock quality and oil -water contact in both sand packages. A anchored billet will be set and the 1 R-231-1-01 lateral will be drilled to the east, crosscutting through the C1 and A3 sands to determine rock quality and OWC in the eastern fault block. Finally, an anchored billet will be set and the 1 R-231_1-02 lateral will be drilled to the north, targeting ' the C1 sands, and lined with 2-3/8" slotted liner to the tubing tail. 7 �10nk- linter Pa- Pre-CTD Work 1. RU Slickline: Dummy whipstock drift, SBHP 2. RU E-line: Caliper 3. RU CTU: Mill D-Nipple Page 4 of 6 September 16, 2019 PTD Application: 1R-231_1, 1R-23L1-01, & 1R-231_1-02 4. RU E-Line: Set High Expansion Wedge Rig Work 1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 1 R-231_1 Lateral (Delineation Lateral A/C Sands - North) a. Mill 2.80" window at 11,680' MD b. Drill 3" bi-center lateral to TD of 14,975' MD c. Set anchored aluminum billet at 14,100' MD 1 R-231_1-01 Lateral (Delineation Lateral A/C Sands - East) a. Kickoff of the aluminum billet at 14,100' MD b. Drill 3" bi-center lateral to TD of 16,520' MD c. Set anchored aluminum billet at 12,500' MD 4. 1 R-23L1-02 Lateral (Cl Sand — North) a. Kick off of the aluminum billet at 12,500' MD b. Drill 3" bi-center lateral to a TD of 17,000' MD c. Run 2-3/8" slotted/blank liner with oil/water tracer pups and sealbore deployment sleeve from TD up to 11,595' MD 5. Freeze protect, ND BOPE, and RDMO Nabors CDR3-AC rig. Post -Rig Work 1. RU E-Line: Set LTP 2. Return well 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 ball valve and check valve isolate reservoir pressure internal to the BHA. Slips on the deployment ram 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 — The 1R-231-1, 1R-231_1-01, & 1R-231_1-02 laterals will be displaced to an overbalancing fluid prior to running liner. See "Drilling Fluids" section for more details. Page 5 of 6 September 16, 2019 PTD Application: 1R-231_1, 1R-231_1-01, & 1R-23L1-02 - 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 and gamma ray will be run over the entire open hole section. - Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 1 R-23L1 4790' 1 R-23L1-01 3041 ' 1R-23L1-02 2541' - Distance to Nearest Well within Pool Lateral Name Distance Well 1 R-23L1 2918' 1 R-35 1 R-23L1-01 2918' 1 R-35 1 R-23L1-02 2810' 1 R-35 16. Attachments Attachment 1: Directional Plans for the 1R-23L1, 1R-23L1-01, & 1R-23L1-02laterals Attachment 2: Current Well Schematic for 1R-23 Attachment 3: Proposed CTD Well Schematic for the 1 R-23L 1, 1 R-23L 1-01, & 1 R-23L1-02 laterals Page 6 of 6 September 16, 2019 1 N U " 0 0 a Q. CL a 0 0 O U ConocoPh i l l i s p ConocoPhillips Alaska Inc—Kuparuk Kuparuk River Unit Kuparuk 1 R Pad 1 R-23 1 R-23L1-02 Plan: 1R-23L1-02 wp02 Standard Planning Report 11 September, 2019 BIUGHES (ER a GE company ConocoPhillips BA ER 0 ConocoPhillips Planning Report F�UGHES a GE company Database: EDT 14 Alaska Production Company: ConocoPhillips Alaska Inc Kuparuk Project: Kuparuk River Unit_2 Site: Kuparuk 1 R Pad Well: 1 R-23 Wellbore: 1 R-23L1-02 Design: 1R-23L1-02_wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 1 R-23 Mean Sea Level 1 R-23 @ 88.00usft (1 R-23) True Minimum Curvature Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk I Pad Site Position: Northing: 5,991,050.01 usft Latitude: 70° 23' 11.370 N From: Map Easting: 539,829.93 usft Longitude: 149° 40' 33.803 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.31 ° Well 1 R-23 Well Position +N/-S 0.00 usft Northing: 5,991 , 630.19 usft Latitude: 700 23' 17.076 N +E/-W 0.00 usft Easting: 539,829.67 usft •• Longitude: 149° 40' 33.721 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 1R-231-1-02 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGG M 2018 11 /1 /2019 16.37 80.88 57,403 Design 1 R-231-1-02_wp02 T Audit Notes: Version: Phase: PLAN Tie On Depth: 12,500.00 Vertical Section: Depth From (TVD) +N/•S +El-W Direction (usft) (usft) (usft) (°) 0.00 0.00 0.00 0.00 Plan Sections _ Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (°) (°) (usft) (usft) (usft) (°/100usft) (°/100usft) (1/100usft) (°) Target 12,500.00 91.15 27.24 6,701.96 6,106.89 7,510.45 0.00 0.00 0.00 0.00 12,600.00 98.15 27.24 6,693.86 6,195.45 7,556.04 7.00 7.00 0.00 0.00 12,850.00 94.79 9.95 6,665.49 6,429.98 7,634.81 7.00 -1.34 -6.92 -100.00 14,050.00 84.55 31.68 6,672.52 7,543.48 8,058.05 2.00 -0.85 1.81 115.00 14,250.00 86.40 17.76 6,688.38 7,724.14 8,141.20 7.00 0.92 -6.96 -83.00 14,550.00 90.20 357.10 6,697.40 8,019.83 8,179.71 7.00 1.27 -6.89 -80.00 14,900.00 88.26 10.96 6,702.13 8,368.06 8,204.23 4.00 -0.55 3.96 98.00 15,200.00 92.37 359.69 6,700.47 8,666.22 8,232.04 4.00 1.37 -3.76 -70.00 15,600.00 90.63 15.60 6,689.92 9,061.24 8,285.07 4.00 -0.44 3.98 96.00 15,900.00 91.66 3.64 6,683.91 9,356.42 8,335.11 4.00 0.34 -3.99 -85.00 16,150.00 89.90 13.49 6,680.50 9,603.29 8,372.29 4.00 -0.70 3.94 100.00 16,700.00 86.92 351.68 6,695.93 10,149.14 8,396.99 4.00 -0.54 -3.97 -98.00 17,200.00 87.11 11.71 6,722.24 10,645.70 8,411.66 4.00 0.04 4.01 90.00 17,700.00 88.99 351.78 6,739.44 11,142.63 8,426.74 4.00 0.38 -3.98 -85.00 911112019 11:13:08AM Page 2 COMPASS 5000.14 Build 85H ConocoPhillips ConocoPhillips Planning Report 13A BAT ER a GE company Database: EDT 14 Alaska Production Local Co-ordinate Reference: Well 1 R-23 Company: ConocoPhillips Alaska Inc Kuparuk TVD Reference: Mean Sea Level Project: Kuparuk River Unit 2 MD Reference: 1 R-23 @ 88.00usft (1 R-23) Site: Kuparuk 1 R Pad North Reference: True Well: 1 R-23 Survey Calculation Method: Minimum Curvature Wellbore: 1 R-23L1-02 Design: 1 R-23L1-02_wp02 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (°) (°) (usft) (usft) (usft) (usft) (°/100usft) (°) (usft) (usft) 12,500.00 91.15 27.24 6,701.96 6,106.89 7,510.45 6,106.89 0.00 0.00 5,997,776.39 547,306.75 TIP/KOP 12,600.00 98.15 27.24 6,693.86 6,195.45 7,556.04 6,195.45 7.00 0.00 5,997,865.19 547,351.86 Start DLS 7.00 TFO-100.00 12,700.00 96.88 20.30 6,680.77 6,286.13 7,595.96 6,286.13 7.00 -100.00 5,997,956.07 547,391.29 12,800.00 95.51 13.39 6,669.98 6,381.22 7,624.74 6,381.22 7.00 -100.91 5,998,051.30 547,419.56 12,850.00 94.79 9.95 6,665.49 6,429.98 7,634.81 6,429.98 7.00 -101.65 5,998,100.11 547,429.37 Start DLS 2.00 TFO 116.00 12,900.00 94.37 10.86 6,661.50 6,479.00 7,643.81 6,479.00 2.00 115.00 5,998,149.18 547,438.11 13,000.00 93.52 12.67 6,654.63 6,576.67 7,664.15 6,576.67 2.00 115.07 5,998,246.94 547,457.94 13,100.00 92.66 14.49 6,649.24 6,673.72 7,687.60 6,673.72 2.00 115.20 5,998,344.11 547,480.86 13,200.00 91.81 16.29 6,645.34 6,770.06 7,714.12 6,770.06 2.00 115.29 5,998,440.57 547,506.86 13,300.00 90.95 18.10 6,642.93 6,865.56 7,743.68 6,865.56 2.00 115.37 5,998,536.22 547,535.91 13,400.00 90.09 19.91 6,642.02 6,960.10 7,776.24 6,960.10 2.00 115.41 5,998,630.92 547,567.97 13,500.00 89.23 21.72 6,642.61 7,053.56 7,811.77 7,053.56 2.00 115.43 5,998,724.57 547,602.99 13,600.00 88.38 23.52 6,644.70 7,145.85 7,850.21 7,145.85 2.00 115.41 5,998,817.04 547,640.95 13,700.00 87.52 25.33 6.648.28 7,236.83 7,891.54 7,236.83 2.00 115.38 5,998,908.24 547,681.78 13,800.00 86.67 27.14 6,653.35 7,326.41 7,935.69 7,326.41 2.00 115.31 5,998,998.04 547,725.45 13,900.00 85.81 28.96 6,659.91 7,414.47 7,982.60 7,414.47 2.00 115.22 5,999,086.34 547,771.89 14,000.00 84.97 30.77 6,667.95 7,500.91 8,032.24 7,500.91 2.00 115.10 5,999,173.03 547,821.06 14,050.00 84.55 31.68 6,672.52 7,543.48 8,058.05 7,543.48 2.00 114.96 5,999,215.74 547,846.64 Start DLS 7.00 TFO -83.00 14,100.00 84.98 28.20 6,677.08 7,586.62 8,082.90 7,586.62 7.00 -83.00 5,999,259.01 547,871.25 14,200.00 85.91 21.24 6,685.03 7,677.12 8,124.55 7,677.12 7.00 -82.68 5,999,349.72 547,912.42 14,250.00 86.40 17.76 6,688.38 7,724.14 8,141.20 7,724.14 7.00 -82.13 5,999,396.82 547,928.82 Start DLS 7.00 TFO -80.00 14,300.00 87.01 14.31 6,691.26 7,772.11 8,154.99 7,772.11 7.00 -80.00 5,999,444.85 547.942.35 14,400.00 88.27 7.42 6,695.38 7,870.17 8,173.81 7,870.17 7.00 -79.80 5,999,543.01 547,960.64 14,500.00 89.55 0.54 6,697.29 7,969.85 8,180.74 7,969.85 7.00 -79.52 5,999,642.71 547,967.04 14,550.00 90.20 357.10 6,697.40 8,019.83 8,179.71 8,019.83 7.00 -79.39 5,999,692.68 547,965.74 Start DLS 4.00 TFO 98.00 14,600.00 89.92 359.08 6,697.35 8,069.80 8,178.04 8,069.80 4.00 98.00 5,999,742.64 547,963.81 14,700.00 89.36 3.04 6,697.98 8,169.76 8,179.88 8,169.76 4.00 98.00 5,999,842.60 547,965.12 14,800.00 88.81 7.00 6,699.57 8,269.34 8,188.63 8,269.34 4.00 97.98 5,999,942.22 547,973.34 14,900.00 88.26 10.96 6,702.13 8,368.06 8,204.23 8,368.06 4.00 97.91 6,000,041.01 547,988.42 Start DLS 4.00 TFO -70.00 15,000.00 89.63 7.21 6,703.97 8,466.77 8,220.02 8,466.77 4.00 -70.00 6,000,139.79 548,003.67 15,100.00 91.00 3.45 6,703.41 8,566.32 8,229.30 8,566.32 4.00 -69.93 6,000,239.37 548,012.42 15,200.00 92.37 359.69 6,700.47 8,666.22 8,232.04 8,666.22 4.00 -69.95 6,000,339.28 548,014.63 Start DLS 4.00 TFO 96.00 15,300.00 91.95 3.67 6,696.69 8,766.08 8,234.96 8,766.08 4.00 96.00 6,000,439.15 548,017.02 15,400.00 91.52 7.65 6,693.67 8,865.53 8,244.81 8,865.53 4.00 96.15 6,000,538.64 548,026.34 15,500.00 91.08 11.62 6,691.41 8,964.07 8,261.54 8,964.07 4.00 96.27 6,000,637.26 548,042.55 15,600.00 90.63 15.60 6,689.92 9,061.24 8,285.07 9,061.24 4.00 96.36 6,000,734.53 548,065.55 Start DLS 4.00 TFO -85.00 15,700.00 90.98 11.61 6,688.51 9,158.40 8,308.59 9,158.40 4.00 -85.00 6,000,831.81 548,088.55 15,800.00 91.32 7.63 6,686.51 9,256.95 8,325.29 9,256.95 4.00 -85.06 6,000,930.44 548,104.73 15,900.00 91.66 3.64 6,683.91 9,356.42 8,335.11 9,356.42 4.00 -85.14 6,001,029.95 548,114.01 Start DLS 4.00 TFO 100.00 16,000.00 90.96 7.58 6,681.63 9,455.89 8,344.88 9,455.89 4.00 100.00 6,001,129.46 548,123.25 16,100.00 90.25 11.52 6,680.57 9,554.48 8,361.46 9,554.48 4.00 100.09 6,001,228.13 548,139.31 16,150.00 89.90 13.49 6,680.50 9,603.29 8,372.29 9,603.29 4.00 100.13 6,001,276.99 548,149.87 911112019 11:13:08AM Page 3 COMPASS 5000.14 Build 85H ConocoPhillips BA ER ConocoPhillips Planning Report IUGHES a GE company Database: EDT 14 Alaska Production Company: ConocoPhillips Alaska Inc Kuparuk Project: Kuparuk River Unit_2 Site: Kuparuk 1 R Pad Well: 1 R-23 Wellbore: 1R-231-1-02 Design: 1 R-23L1-02_wp02 Planned Survey Measured TVD Below Depth Inclination Azimuth System (usft) (1 (a) (usft) Start OILS 4.00 TFO -98.00 Local Co-ordinate Reference: Well 1 R-23 TVD Reference: Mean Sea Level MD Reference: 1 R-23 @ 88-00usft (1 R-23) North Reference: True Survey Calculation Method: Minimum Curvature Vertical Dogleg Toolface Map +N/-S +E/-W Section Rate Azimuth Northing (usft) (usft) (usft) (°/100usft) (1) (usft) Map Easting (usft) 16,200.00 89.62 11.51 6,680.71 9,652.10 8,383.11 9,652.10 4.00 -98.00 6,001,325.86 548,160.43 16,300.00 89.07 7.54 6,681.85 9,750.70 8,399.65 9,750.70 4.00 -97.99 6,001,424.53 548,176.45 16,400.00 88.52 3.58 6,683.95 9,850.19 8,409.34 9,850.19 4.00 -97.95 6,001,524.06 548,185.61 16,500.00 87.98 359.62 6,687.01 9,950.08 8,412.13 9,950.08 4.00 -97.86 6,001,623.95 548,187.86 16,600.00 87.44 355.65 6,691.01 10,049.89 8,408.01 10,049.89 4.00 -97.74 6,001,723.74 548.183.21 16,700.00 86.92 351.68 6,695.93 10,149.14 8,396.99 10,149.14 4.00 -97.58 6,001,822.91 548,171.66 Start DLS 4.00 TFO 90.00 16,800.00 86.93 355.68 6,701.29 10,248.37 8,386.00 10,248.37 4.00 90.00 6,001,922.07 548,160.15 16,900.00 86.95 359.69 6,706.63 10,348.13 8,381.97 10,348.13 4.00 89.79 6,002,021.80 548,155.59 17,000.00 86.99 3.70 6,711.92 10,447.92 8,384.92 10,447.92 4.00 89.57 6,002,121.60 548,158.00 17,100.00 87.04 7.70 6,717.13 10,547.28 8,394.83 10,547.28 4.00 89.36 6,002,220.99 548,167.39 17,200.00 87.11 11.71 6,722.24 10,645.70 8,411.66 10,645.70 4.00 89.15 6,002,319.49 548,183.69 Start DLS 4.00 TFO -85.00 17,300.00 87.46 7.72 6,726.97 10,744.13 8,428.51 10,744.13 4.00 -85.00 6,002,418.00 548,200.01 17,400.00 87.83 3.73 6,731.08 10,843.53 8,438.47 10,843.53 4.00 -84.81 6,002,517.44 548,209.44 17,500.00 88.21 359.75 6,734.54 10,943.40 8,441.50 10,943.40 4.00 -84.65 6,002,617.32 548,211.94 17,600.00 88.60 355.76 6,737.33 11,043.27 8,437.58 11,043.27 4.00 -84.51 6,002,717.15 548,207.49 17,700.00 88.99 351.78 6,739.44 11,142.63 8,426.74 11,142.63 4.00 -84.40 6,002,816.45 548,196.12 Planned TO at 17700.00 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 17,700.00 6,739.44 2-3/8" 2.375 3.000 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 12,500.00 6,701.96 6,106.89 7,510,45 TIP/KOP 12,600.00 6,693.86 6,195.45 7,556.04 Start DLS 7.00 TFO -100.00 12,850.00 6,665.49 6,429.98 7,634.81 Start DLS 2.00 TFO 115.00 14,050.00 6,672.52 7,543.48 8,058.05 Start DLS 7.00 TFO -83.00 14,250.00 6,688.38 7,724.14 8,141.20 Start DLS 7.00 TFO -80.00 14,550.00 6,697.40 8,019.83 8,179.71 Start DLS 4.00 TFO 98.00 14,900.00 6,702.13 8,368.06 8,204.23 Start DLS 4.00 TFO -70.00 15,200.00 6,700.47 8,666.22 8,232.04 Start DLS 4.00 TFO 96.00 15,600.00 6,689.92 9,061.24 8,285.07 Start DLS 4.00 TFO -85.00 15,900.00 6,683.91 9,356.42 8,335.11 Start DLS 4.00 TFO 100.00 16,150.00 6,680.50 9,603.29 8,372.29 Start DLS 4.00 TFO -98.00 16,700.00 6,695.93 10,149.14 8,396.99 Start DLS 4.00 TFO 90.00 17.200.00 6,722.24 10,645.70 8,411.66 Start DLS 4.00 TFO -85.00 17,700.00 6,739.44 11,142.63 8,426.74 Planned TD at 17700.00 911112019 11:13 08AM Page 4 COMPASS 5000.14 Build 85H ConocoPhillips BA ER ConocoPhillips Anticollision Report F IGHES BAT GE company Company: ConocoPhillips Alaska Inc-Kuparuk Project: Kuparuk River Unit_2 Reference Site: Kuparuk 1 R Pad Site Error. 0.00 usft Reference Well: 1 R-23 Well Error. 0.00 usft Reference Wellbore 1 R-231-1-02 Reference Design: 1 R-23L1-02_wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 1 R-23 1 R-23 @ 88.00usft (1 R-23) 1 R-23 @ 88.00usft (1 R-23) True Minimum Curvature 2.00 sigma EDT 14 Alaska Production Offset Datum Reference 1R-23L1-02_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: 12,500.00 to 17,700.00usft 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 Date 9/11/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description 100.00 11,600.00 1 R-23 (1 R-23) GCT-MS Schlumberger GCT multishot 11,600.00 12,500.00 1R-231-1_wp02(1R-231-1) MWD OWSG OWSGMWD- Standard 12,500.00 17,700.00 1R-231-1-02_wp02 (1 R-23L1-02) MWD OWSG OWSG MWD - Standard Summary Reference Offset Distance Measured Measured Between Between Separation Warning Site Name Depth Depth Centres Ellipses Factor Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) Kuparuk I Pad 1R-23-1R-231-1-1R-23L1_wp02 12,825.25 12,825.00 18.56 18.25 59.292 CC 1R-23- 1R-2311 - 1R-231-1_wp02 12,849.00 12,850.00 19.89 18.09 11.062 ES 1R-23 - 1 R-231-1 - 1R-23L1_wp02 14,334.86 14,350.00 78.54 44.33 2.296 Caution Monitor Closely, SF 1R-23-1R-2311-01-1R-2311-01_wp03 12,825.25 12,825.00 18.56 18.25 59.292 CC 1 R-23 - 1 R-23L1-01 - 1 R-2311-01_wp03 12,849.00 12,850.00 19.89 18.09 11.062 ES 1 R-23 - 1 R-231-1-01 - 1 R-231-1-01_wp03 14,153.51 14,150.00 85.59 55.93 2.886 Normal Operations, SF 1 R-35 - 1 R-35 - 1 R-35 Out of range 1 R-35 - 1 R-35 - 1 R-35 Out of range 1 R-35 - 1 R-35 - 1 R-35 TD Projection Out of range 1 R-36 - 1 R-36 - 1 R-36 Out of range Offset Design Kuparuk 1 R Pad - 1 R-23 - 1 R-23L1 - 1 R-231-1_wp02 offset Site Error: o.00 usft Survey Program: 100-GCT-MS, 11600-MWD OWSG 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 +N/S +E/-W Centres Ellipses Separation Factor (usft) (usft) (usft) (usft) (usft) lusft) 0 (usft) (usft) (usft) (usft) (usft) 12,524.99 6,789.08 12,525.00 6.789.45 0.22 0.15 -106.88 6,129.28 7,521.54 0.53 0.13 0.41 1.308 Take Immediate Action 12,549.91 6,787.44 12,550.00 6.788.92 0.44 0.29 -106.84 6,152.00 7,531.95 2.12 1.51 061 3.472 12,574.70 6,785.06 12.575.00 6,788.36 0.48 0.43 -106.77 6,175.03 7,541.66 4.77 4.39 0.38 12.579 12,599.28 6.781.97 12,600.00 6,787.78 0.53 0.58 -106.68 6,198.35 7,550.67 8.47 7.84 0.63 13,521 12,624.19 6,778.50 12,625.00 6,787.18 0.59 0.72 -108.24 6,221.93 7,558.95 12.66 11.77 0.89 14.252 12649.23 6,775+15 12,650.00 6,786.56 0.65 0.86 -109.58 6,245.75 7,566.52 16.76 15.64 1.11 15.049 12,674.47 6,771.91 12,675.00 6,785.76 0.72 1.00 -111.90 6,269.57 7,574.04 20.12 18.81 1.31 15.353 12,699.92 6,768.78 12,700.00 6,784.63 C.79 1.15 -115.85 6,293.17 7,582.21 22.13 20.68 1.45 15.217 12,725.43 6,765.80 12,725.00 6,783,17 0.88 1.31 -121.35 6,316.52 7,591.03 22.85 21.30 1.55 14.725 12,750.86 6,762.99 12,750.00 6,781.37 0.97 1.48 -128.82 6,339.60 7600.47 22.41 20.86 1.55 14.494 12,776.06 6,760.34 12,775.00 6,779.24 1.07 1.66 -139.21 6,362.38 7,610.54 21.09 19.72 1.37 15.380 12,800.90 6, 757.89 12,800.00 6,776.79 1.16 1.84 -154.03 6,384.85 7,621.22 19.46 18.60 0.85 22.773 12,825.25 6,755.63 12,825.00 6,774.01 1.27 2.04 -174.61 6,406.98 7632.50 18.56 18.25 0.31 59.292 CC 12,849.00 6,753.57 12,850.00 6,770.91 1.37 2.23 161.02 6,428.76 7,644.38 19.89 18.09 1.80 11.062 ES 12,872.61 6,751.64 12,875.00 6,767.49 1.48 2.44 141.61 6,450.16 7,656.84 24.11 21.11 3.00 8,029 12,896.09 6,749.80 12,900.00 6,763.75 1.59 2.65 128.12 6.471.16 7,669.87 30.48 26.64 3.84 7.937 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 911112019 10:25:16AM Page 2 COMPASS 5000.14 Build 85H �60 �co ao� n�oo�oi�aoo 0 0 0 0 0 0 0 0 0 0 0 " 0 0 0 0 0 0 0 0 0 0 0 0 ,r o 0 0 0 0 0 0 0 0 0 0 0 • N c I� c�i l� 1� C' C' C' C C' C' C' C' r`: o U) co co U) to U) U) U) Ul (n U) UJ J rn m 0 0 0 0 C) 0 0 O D O C3 O C) � �Y�rr'C r'Crrrrrr c QHV)UJ U)U)Cl) U)(nV)Ul U) co U)d t D6 N C' N m C' O M OmNC•N r-tOd•it to fD tD 00 t,0 00 W W m C" M mc O N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ti 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N J Q� 000 t[JM Oo00t0 tL)OIXi 0 O O � oO W m I� O) C? W CL �)00 00000 0000000 N O O O CD O O O O O O O O O O Or Of- 1-�N ti r-�C'C' C' C'C'C'C' � r -� CD c-M T Ira--MM cO Ct C' O co O N N O O N m t O 1+ OtO .Zr W.-m C'GV to NtO 10 0 W tp a0 m W ti m C' O M J fO 'm W t0,[J m M C'm cd COMm wiCN } O m N C' N O tD (O C' C' C' wC' OMtOO M(O� (O.- tCO CO I� � aO�Nmmm00� 0 J J 0�� W — M A N co I N O m M O Q i •Irr Om tO I�oO mO0a0 W aOmNM I�tO tOmOO � ntO CD t0O1`-I� E(+Q''y� CO (O (O tD (O t0 (O CO t0 �p GO CO cD cO 0 CO N C'C'tr)o](00(Om0 C' mw c-tD Z N N C OIR m to to O� to n cn I I m l l O t 7 i t f) M MLO 10 C m L q C' N N M t0 COO m T .- QmJ ao C' C' (D O co CV 6 m CO r-� aC O m m m oo w m oo m m m c W ap oo O UJO o0000000000000 } 0 0 0 0 0 0 0 0 0 0 0 0 0 0 00000000000000 o C:. O atot000OOtn000 0 0 N t A m N t O m N N N C' C' C' K2 t2 t2 CO CO _� p U— N M C' t O COI co m 0 M C' 0 0 0 0 0 0 �i N i KUP INJ 1 R-23 ConocoPhillips Well Attributes Max Angle & MQ JTD Alaska Inc.Wellbore API/VA Fieltl Name We' Status 500292220000 KUPARUK RIVER UNIT INJ MID ncl C) MD (ftKB) 66.10 3,000.00 Act Btm (ftKB) 12,180.D • • • Comment H2S (ppm) Date SSSV: TRDP Annotation Entl Date Last W0: 116l1992 KB-Grd (ft) Rig Release Date 42.99 10/27/1991 1R-23, 12(30/40153aa:a1 PM vertical mahc(actuall Annotation Depth (ftKB) End Date Annotation Last Motl By End Date Last Tag: SLM 11,692.0 8/9/2015 Rev Reason: PULLED FRAC SLEEVE lehallf 12/30/2015 ................................................. . Casing Strings Casing Description OD (in) 10 (in) Top (ftKB) Set Depth (ftKB) Set Depth (ND)... WtlLen (1... Grade Top Thread CONDUCTOR 16 15.062 44.0 123.0 123.0 62.50 H-40 WELDED Description OD (In) ID (in) Top (ftKB) Set Depth (ftKB) SetDepth(ND)... WtlLen (1... Grade Tap Thread SURFACE 95/8 8.921 42.0 6,330.84,072.4 36.00 J-55 BTC Casing Description OD (in) ID(in)Top (ftKB)SetDepth(ftKB)5et Depth (ND)... WtlLen (I... Grade Top Thread PRODUCTION 7 6.276 29.2 12,177.7 7.002.5 26.00 L-80 NSCC 43-Casing Tubing Strings Tubing Description String Ma... ID (in) Top (ftKB) Set Depth(ft.. Set Depth)(...Wt(Ib/ft)rTop CononTUBING WO 31l2 2.992 38.3 11,609.9 6,726.7 9.311J-55 EUE 10Completion Details Nominal ID Top(ftKB) Top (ND) (ftKB) Top Incl (°) Item Des Com (in)38.3 38.3 0.01 HANGER FMC GEN IV TUBING HANGER 3.500 1,816.0 1,719.4 39.09 SAFETY VLV CAMCO TRDP-1A SAFETY VALVE 2.812 11,529.9 6,689.0 61.87 NIPPLE OTIS X SELECTIVE LANDING NIPPLE 2.813 11,567.5 6,706.7 61.89 PBR BAKER PER 3.000 11,581.2 6,713.1 61.90 PACKER BAKER HB RETRIEVABLE PACKER 2.890 SAFETY VLV; 1,816.0 11,597.5 6,720.8 61.91 NIPPLE OTIS XN NIPPLE NO GO 2.750 11,609.2 6,726.3 61.88 SOS BAKER SHEAR OUT SUB 2.992 Perforations & Slots Shot Den GAS LIFT', 3,250.7 Top (ftKB) St. (ftKB) Top (ND) (ftKB) St. (TV (ftKB) Zone I Date (shotsK t) Type Co. 11,710.0 11,770.0 6,774.1 6,803.1 , C-1, 1/5/1992 10.0 IPERF Csg Gun; 60 deg ph �C-2 UNIT B, iR- 14.5" 23 Stimulations & Treatments Min Top Maz Film Depth Depth Top (ND) Bum (ND) (ftKB) (ftKB) (ftKB) (ftKB) Type Date Core 11,710.0 11,770.0 6,774.1 6,803.1 HPBD 10/11/199 PUMP 12,069# OF 20/40 SAND AND 2,490# OF 5 ROCK SALT. INITIAL ISIP 2780 PSI, FINAL ISIP 2714 PSI. Mandrel Inserts St all 42.0-6,3308 on N Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Valve Sam Type Latch Type Port Size (in) TRO Run (psi) Run Date CornsuRFACE, 3,250.7 2,493.2 CAMC0 KBUG- 1 GAS LIFT DMY BK 0.000 0.0 10/27/1992 M -- 2 11,484.5 6, 667.5 OTIS LBD 1112 GAS LIFT DMY RM 0.0001 0.0 4/l/1992 Notes; General & Safety End Date Annotation GAS LIFT; 11 484.5 10/19l2010 NOTE: View Schematic W/ Alaska Schematic9.0 9/19/2013 NOTE: PROD CSG RKB per RIG DETAIL SHEET NIPPLE, 11, 529.9 PBR: 11 567.fi PACKER; 11,581.3 m NIPPLE, 11,5975 SOS; 11.609.2 HPBD; 11,710.0 p IPERF; 11, 7100-117700 k3@7 PRODUCTION; 29.2-12,177.7 U p CI 22 Mpp [] NH 7 Q 3 N m p O IU O J ^ C p (� N Q 3 m O v c� O 11 J C Z c'UI p2i F-OI O M Q C 0 LQ Cif N In - i0 oo ap O N N Q v v o�(O (0 Q p > j BO a j Q (n I- d U) 'a C a O) L, N CO � cQ J +q'� @ C C_ LQ O N Q c15 a N d Z) == N (0 @ C, Q W _ tIi M N > a d U Q W O D1 U }` O � U UI = f6 0_ cc of O O x c2 S x ul N (V cli— N fn N a) — CV — H m -14 m !— O M ch CM M O 0] �] O c7 I 0 N L cUco O w) to O W L cj n N� c > l9 O <) r <°� Loepp, Victoria T (CED) From: McLaughlin, Ryan <Ryan.McLaughlin@conocophillips.com> Sent: Thursday, September 26, 2019 8:54 AM To: Loepp, Victoria T (CED) Cc: Ohlinger, James J; Knock, Grace E Subject: RE: [EXTERNAL]KRU 1 R-23L1, 1 R-231_1-01, 1 R-23L1-02(PTD 219-128, 219-129, 219-130) Hello Victoria, We are planning on running blank liner from 11,605' MD to 13,850' MD which will straddle the anchored billet and block off any production from the first two delineation laterals. The blank liner is expected to block off flow from the first two laterals, abandoning them without cement. Regards, Ryan McLaughlin Coiled Tubing Drilling Engineer ConocoPhillips Alaska Office:907-265-6218 Cell:907-444-7886 700 G St, ATO 670, Anchorage, AK 99501 From: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Sent: Thursday, September 26, 2019 8:14 AM To: McLaughlin, Ryan <Ryan.McLaughlin @conocophillips.com> Subject: [EXTERNAL]KRU 1R-23L1, 1R-23L1-01, 1R-23L1-02(PTD 219-128, 219-129, 219-130) Ryan, For the two delineation laterals that are unlined, will they be produced or abandoned without cement? How long is the blank portion of the 1R-23L1-02? Will this blank liner prevent any flow from the other two laterals? Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria. Loepp(a�alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Victoria Loepp at (907)793-1247 or Victoria. Loepp@alaska.gov TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: j ! 30 z Y Development _ Service Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: SPOOL: 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. �l� API No. 50- � V (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. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements / Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK RIV UNIT 1_R-231-1-02 Program DEV Well bore seg ❑d PTD#:2191300 Company ConocoPhillips Alaska, Inc. Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑ Administration '1 Permit fee attached NA 2 Lease number appropriate Yes Spoke: KOP, top prod interval, and TD in ADL0025627. j3 Unique well name and number Yes 4 Well located in a defined pool Yes Kuparuk River Oil Pool, governed by Conservation Order No. 432D 5 Well located proper distance from drilling unit boundary Yes Conservation Order No. 432D has no interwell spacing restrictions. Wellbore will be more than 500' 6 Well located proper distance from other wells Yes from an external property line where ownership or landownership changes. As proposed, well 7 Sufficient acreage available in drilling unit Yes branch will conform to spacing requirements. 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes I10 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 SFD 9/23/2019 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wellswithin1/4 mile area of review identified (For service well only) NA I16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA I17 Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D) NA 18 Conductor string provided NA Conductor set for KRU 1 R-23 Engineering 19 Surface casing protects all known USDWs NA Surface casing set for KRU 1R-23 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 I22 CMT will cover -all known productive horizons No Productive interval will be completed with uncemented slotted liner w/ oil & water tracer pups i23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes Anti -collision analysis complete; no major risk failures 27 If diverter required, does it meet regulations NA - Appr Date 128 Drilling fluid program schematic & equip list adequate Yes Max formation pressure is 3515 psig(10 ppg EMW); will drill w/ 8.6 ppg EMW and maintain overbal w/ MPD VTL 9/24/2019 29 �30 BOPEs, do they meet regulation Yes BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 2841 psig; will test BOPs to 3500psig 31 Choke manifold complies w/API- RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of 112S gas_ probable Yes 112S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 1R-Pad are 1-12S-bearing. 112S measures required. Geology 36 Data presented on potential overpressure zones Yes Expected reservoir pressure is 10.0 ppg, with some potential of higher pressure due to gas Appr Date 37 Seismic analysis of shallow gas zones NA injection within this area. Well will be drilled using 8.6 ppg mud, a coiled -tubing rig, and SFD 9/23/2019 38 Seabed condition survey (if off -shore) NA managed pressure drilling technique to control formation pressures and stabilize shale sections by 39 Contact name/phone for weekly progress reports [exploratory only] NA maintaining a constant_ pressure gradient of about 1.1.8 ppg EMW. Geologic Engineering Public Commissioner: Date: Commissioner: Date Commissioner Date