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219-169
1 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 01ALASKA GOVERNOR MIKE DUNLEAVY James Ohlinger Staff CTD Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 1 R-23AL3 ConocoPhillips Alaska, Inc. Permit to Drill Number: 219-169 Surface Location: 4854' FNL, 144' FWL, SEC. 17, T12N, R10E, UM Bottomhole Location: 2674' FNL, 3034' FWL, SEC. 9, T12N, R10E, UM Dear Mr. Ohlinger: 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. 219-166, API No. 50-029-22200- 01-00. 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, 2 re . Price C air DATED this day of December, 2019. STATE OF ALASKA AL, `;A OIL AND GAS CONSERVATION COMMISSION NOV 2 l 210,19 PERMIT TO DRILL 20 AAC 25.005 la. Type of W Drill ❑ Lateral ❑� Redrill ❑ Reentry ❑ MProposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ Stratigraphic Test ❑ Development - Oil 0 Service - Winj ❑ Single Zone Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ 1 c. Specify if well is proposed for: Coalbed Gas ❑ Gas 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 1R-23AL3 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 14,000' ' TVD: 6588' 12. Field/Pool(s): Kuparuk River Field / Kuparuk River Oil Pool ` 4a. Location of Well (Governmental Section): Surface: 4854' FNL, 144' FWL, Sec 17, T12N, R10E, UM ' Top of Productive Horizon: 4051' FNL, 2296' FWL, Sec 9, T12N, R10E, UM Total Depth: 2674' FNL, 3034' FWL, Sec 9, T12N, R10E, UM 7. Property Designation: /I _)z_ Z} /_ Zj ADL 25627 ALK 2560 8. DNR Approval Number: LONS 83-134 13. Approximate Spud Date: 12/5/2019 9. Acres in Property: 2560 14. Distance to Nearest Propertv: 5105' 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 539830 • y- 5991630 • Zone- 4 10. KB Elevation above MSL (ft): 88' GL / BF Elevation above MSL (ft): 45' 15. Distance to Nearest Well Open to Same Pool: 2972', 1 R-35 " 16. Deviated wells: Kickoff depth: 12,400 feet Maximum Hole Angle: 116 degrees 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Downhole: 3515 Surface: 2841 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling I Length MD TVD MD TVD (including stage data) 3" 2-3/8" 4.7# L-80 ST-L 2395' 11,605' • 6724' 14,000 . 6588' Slotted Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 12180' Total Depth TVD (ft): 7004' Plugs (measured): N/A Effect. Depth MD (ft): 12178' Effect. Depth TVD (ft): 7003' Junk (measured): 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 121 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 McLaughli Authorized Name: James Ohlinger Contact Email: rVan.mclauqhlincop.com Authorized Title: Staff CTD Engineer Contact Phone: 907-265-6218 6ha,ne Ger„tQArl Authorized Signature: e Date: r o 0 mmission Use Only Permit to Drill % %/Yy Number: ' —( ` (Cv� 150- API Number: �2-1J — �—e_�'rj Permit Approval Date: 2 �q 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: �fj� rs 7- 7" -' 3517 d -5 J - Samples req'd: Yes ❑, No[Q/ Mud log req'd: Yes❑ No[✓' h h v/ar tt,5 f fo Z5"U&easures: Yes[2 No❑ 0Directional svy req'd: Yes No❑ VCLr7ghC �O ff G' 25. d/SS G�xceptiof�req'd: Yes El tes NoInclination-only svyreq'd:Yes ❑ No[� JJJ Post initial injection MIT req'd: Yes ❑ No[P-- 13 cJ1-aht�c� �'0 2//ow YhC k/cko{{'Poi�f 7`0 6 c o�ny po�hf 6U 0r7 fh-C-�Rrrrt lccl`��a APPROVED BY �)d Approved by: COMMISSIONER THE COMMISSION Date: 1 �/`r - 1Z Submit Form and Form 10-401 evis /2017 T is r it is valid o z� +s rr�r A f approval per 20 AAC 25.005(g) Attachments in Duplicate (L-��+ �� O 11 V 1 1 r ���Z�y -� �i y2•l� ConocoPs philli Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 November 20, 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 four laterals out of the KRU 1 R-23 (PTD# 191-101) using the coiled tubing drilling rig, Nabors CDR3-AC. CDR3-AC previously attempted to drill the 1 R-231-1 (219-128) lateral in October 2019, but after drilling 3 plugbacks due to hole cleaning and hole stability issues, the decision was made to RDMO. The well is currently being set-up for a cement pilot hole exit by cement squeezing the original C-sand perforations up to the tubing tail. CDR3-AC plans to return to the well and CTD operations are scheduled to begin on December 5th, 2019. The objective will be to drill three laterals — 1 R-23A and 1 R-23AL1 will be unlined delineation laterals to the north and east, crosscutting through the A3 and C1 sands. 1 R-23AL2 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. The fourth lateral, 1 R-_ 23AL3, will be a contingency lateral that will target the C1 sands in an upthrown fault -block. This lateral will be drilled only if the oil -water -contact comes in higher than anticipated and the project does not get completed to scope. 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 1 R-23A, 1 R-23AL1, & 1 R-23AL2, & 1 R-23AL3 - Detailed Summary of Operations - Directional Plans for 1 R-23A, 1 R-23AL1, & 1 R-23AL2, & 1 R-23AL3 - 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-23AI 1 R-23AL15 & 1 R-23AL2 & 1 R-23AL3 Application for Permit to Drill Document 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(t) and 20 AAC 25.005(b))................................................................................................................... 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2)).................................................................................................................................................. 2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 2 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7)).................................................................................................................................................. 3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9)).................................................................................................................................................. 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4 11. Seabed Condition Analysis............................................................................................................ 4 (Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................ 4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 4 13. Proposed Drilling Program............................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................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....................................................................................................................................7 Attachment 1: Directional Plans for 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3........................................................7 Attachment 2: Current Well Schematic for 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3.............................................7 Attachment 3: Proposed Well Schematic for 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3..........................................7 Page 1 of 7 November 11, 2019 PTD Application: 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 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 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3. 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-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3. . 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 1 R-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-23A 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-23A laterals will be shale instability across faults. Managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossings. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity test is not required. Page 2 of 7 September 16, 2019 PTD Application: 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 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-23A N/A N/A N/A N/A with an anchored billet set at 14,100' MD Delineation lateral — will be unlined 1R-23ALl 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-23AL2 11,605' 17,700' 6636' 6615' liner, with oil and water tracer pups, and sealbore deployment sleeve 1R-23AL3 11,605' 14,000' , 6636' 6500' 2-3/8", 4.7#, L-80, ST-L slotted liner 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 EUEABMOD I Surface 1 11,610 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". Page 3 of 7 September 16, 2019 PTD Application: 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 In the 1 R-23A laterals we will target a constant BHP of 11.8 EMW at the window. The constant BHP target will be adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if increased reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed for improved borehole stability. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Pressure at the 1R-23A Window 11,650' MD, 6745' TVD Usin MPD Pumps On 1.8 b m Pumps Off Formation Pressure 10.0 3507 psi 3507 psi Mud Hydrostatic 8.6 3016 psi 3016 psi Annular friction i.e. ECD, 0.080 psi/ft) 932 psi 0 psi Mud + ECD Combined no chokepressure) 3948 psi Overbalanced —441psi) 3016 psi (Underbalanced —491psi) Target BHP at Window 11.8 4139 psi 4139 psi Choke Pressure Required to Maintain Target BHP 191 psi 1123 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 In October 2019, CDR3-AC rigged up and attempted to drill 3 laterals out of KRU 1 R-23. After 3 plugbacks while drilling the 1 R-231_1 lateral, due to poor hole conditions and hole cleaning issues, the decision was made to RDMO and reattempt at a later date via cement pilot hole exit. This will require E-line to perforate the tubing tail, and service coil to cement squeeze the C-sand perforations up to the tubing tail. This wellwork is ongoing. CDR3-AC will return to 1 R-23 in mid -December, mill a pilot hole down to 11,680' MD, set a whipstock and mill a 2.80" window in the production casing at a depth of 11,650' MD. After that, the 1 R-23A 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. An anchored billet will be set and the 1 R-23AL1 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-23AL2 lateral will be drilled to the north, targeting the C1 sands, and lined with 2-3/8" slotted liner to the tubing tail. If the C1 sands are found to be wet due to a higher than anticipated oil -water -contact, the1 R-23AL2 lateral will not be drilled and instead a contingency lateral 1 R-23AL3 will be Page 4 of 7 September 16, 2019 PTD Application: 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 drilled targeting the C1 sands in an upthrown block This lateral will be lined with 2-3/8" slotted liner from TD to the tubing tail. Pre-CTD Work 1. RU E-line: Perforate Tubing Tail 2. RU CTU: Injectivity test, cement 1 R-23 up to the tubing tail, mill XN nipple to 2.80", mill cement to 11,609' MD Rig Work 1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 1 R-23A Lateral (Delineation Lateral A/C Sands - North) a. Mill cement from tubing tail (11,609' MD) to 11,680' MD b. Set whipstock at 11,650' MD c. Mill 2.80" window at 11,650' MD d. Drill 3" bi-center lateral to TD of 15,846' MD e. Set anchored aluminum billet at 14,100' MD 3. 1 R-23AL1 Lateral (Delineation Lateral A/C Sands - East) a. Kick off of the aluminum billet at 14,100' MD b. Drill 3" bi-center lateral to TD of 16,665' MD c. Set anchored aluminum billet at 12,500' MD 4. 1R-23AL2 Lateral (C1 Sand — North) a. Kick off of the aluminum billet at 12,500' MD b. Drill 3" bi-center lateral to a TD of 17,700' MD c. Run 2-3/8" slotted/blank liner with oil/water tracer pups and sealbore deployment sleeve from TD up to 11,605' MD 5. 1 R-23AL3 Lateral (Cl Sand — North) a. Kick off of the aluminum billet at 12,400' MD b. Drill 3" bi-center lateral to a TD of 14,000' MD c. Run 2-3/8" slotted liner and sealbore deployment sleeve from TD up to 11,605' MD 6. 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 Page 5 of 7 September 16, 2019 PTD Application: 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 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 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 laterals will be displaced to an overbalancing fluid prior to running liner. See "Drilling Fluids" section for more details. — While running 2-3/8" slotted liner, a joint of 2-3/8" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2-3/8" rams will provide secondary well control while running 2-3/8" liner 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (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-23A 4790' 1 R-23AL1 3041 ' 1 R-23AL2 2541' 1 R-23AL3 5105' - — Distance to Nearest Well within Pool Lateral Name Distance Well 1 R-23A 2935' 1 R-35 1 R-23AL1 3002' 1 R-35 1 R-23AL2 2872' 1 R-35 1 R-23AL3 2972' 1 R-35 Page 6 of 7 September 16, 2019 PTD Application: 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 16. Attachments Attachment 1: Directional Plans for the 1R-23A, 1 R-23AL 1, & 1 R-23AL2 & 1 R-23AL3 laterals Attachment 2: Current Well Schematic for 1 R-23 Attachment 3: Proposed CTD Well Schematic for the 1R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 laterals Page 7 of 7 September 16, 2019 Ij �1 d s rn x L Y 6 m N Q ConocoPhilli s p ConocoPhillips Alaska Inc—Kuparuk Kuparuk River Unit Kuparuk 1 R Pad 1 R-23 1 R-23AL3 Plan: 1 R-23AL3_wp01 (Draft A) Standard Planning Report 18 November, 2019 Baker Hughes 8 ConocoPhillips Database: EDT 14 Alaska Production Company: ConocoPhillips Alaska Inc Kuparuk Project: Kuparuk River Unit Site: Kuparuk I Pad Well: 1 R-23 Wellbore: 1 R-23AL3 Design: 1R-23AL3_wp01 (Draft A) ConocoPhillips Planning Report Baker Hughes 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 ' Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) • System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk 1 R 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 ° WBII 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 1 R-23AL3 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (I (I (nT) BG G M2018 12/1 /2019 16.33 80.88 57,400 Design 1 R-23AL3_wp01 (Draft A) Audit Notes: Version: Phase: PLAN Tie On Depth: 12,400.00 Vertical Section: Depth From (TVD) +NI-S +E/-W Direction (usft) (usft) (usft) (°) 0.00 0.00 0.00 25.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +Nl-S +E/-W Rate Rate Rate TFO (usft) (I (I (usft) (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) Target 12,400.00 87.34 41.22 6,666.63 6,085.64 7,410.81 0.00 0.00 0.00 0.00 12,835.00 116.68 32.78 6,576.94 6,420.38 7,665.21 7.00 6.74 -1.94 345.00 13,260.00 87.80 25.39 6,487.69 6,779.97 7,863.53 7.00 -6.80 -1.74 195.00 13,460.00 87.80 25.39 6,495.38 6,960.52 7,949.23 0.00 0,00 0.00 0.00 13,530.00 89.64 20.85 6,496.95 7,024.86 7,976.71 7.00 2.63 -6.49 292.00 14,000.00 89.64 20.85 6,499.93 7,464.07 8,143.99 0.00 0.00 0.00 0.00 11/1a/2019 9:17:52AM Page 2 COMPASS 5000.14 Build 85H ConocoPhillips ConocoPhillips Planning Report Baker Hughes Database: EDT 14 Alaska Production Local Co-ordinate Reference: Well 1R-23 Company: ConocoPhillips Alaska Inc-Kuparuk TVD Reference: Mean Sea Level Project: Kuparuk River Unit 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-23AL3 Design: 1 R-23AL3_wp01 (Draft A) 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) 12,400.00 87.34 41.22 6,666.63 6,085.64 7,410.81 8,647.41 0.00 0.00 5,997,754.62 547,207.24 TIP/KOP 12,500.00 94.10 39.41 6,665.37 6,161.84 7,475.47 8,743.79 7.00 -15.00 5,997,831.15 547,271.48 12,600.00 100.86 37.56 6,652.36 6,239.39 7,537.14 8,840.14 7.00 -15.02 5,997,909.02 547,332.73 12,700.00 107.61 35.63 6,627.78 6,317.15 7,594.91 8,935.03 7.00 -15.26 5,997,987.08 547,390.08 12,800.00 114.33 33.55 6,592.01 6,393.95 7,647,92 9,027.03 7.00 -15.74 5,998,064.15 547,442.68 12,835.00 116.68 32.78 6,576.94 6,420.38 7,665.21 9,058.30 7.00 -16.48 5,998,090.68 547,459.82 Start DLS 7.00 TFO 195.00 12,900.00 112.28 31.51 6,550.02 6,470.47 7,696.66 9,116.98 7.00 -165.00 5,998,140.92 547,491.00 13,000.00 105.49 29.69 6,517.66 6,551.87 7,744.77 9,211.09 7.00 -165.53 5,998,222.57 547,538.67 13,100.00 98.69 28.00 6,496.73 6,637.48 7,791.90 9,308.59 7.00 -166.11 5,998,308.42 547,585.34 13,200.00 91.88 26.36 6,487.52 6,726.00 7,837.35 9,408.03 7.00 -166.47 5,998,397.18 547,630.32 13,260.00 87.80 25.39 6,487.69 6,779.97 7,863.53 9,468.01 7.00 -166.62 5,998,451.28 547,656.21 Start 200.00 hold at 13260.00 MD 13,300.00 87.80 25.39 6,489.23 6,816.08 7,880.67 9,507.98 0.00 0.00 5,998,487.48 547,673.16 13,400.00 87.80 25.39 6,493.07 6,906.35 7,923.52 9,607.91 0.00 0.00 5,998,577.97 547,715.52 13,460.00 87.80 25.39 6,495.38 6,960.52 7,949.23 9,667.86 0.00 0.00 5,998,632.26 547,740.94 Start DLS 7.00 TFO 292.00 13,500.00 88.85 22.80 6,496.55 6,997.01 7,965.55 9,707.84 7.00 -68.00 5,998,668.84 547,757.06 13,530.00 89.64 20.85 6,496.95 7,024.86 7,976.71 9,737.79 7.00 -67.92 5,998,696.74 547,768.07 Start 470.00 hold at 13530.00 MD 13,600.00 89.64 20.85 6,497.39 7,090.27 8,001.62 9,807.60 0.00 0.00 5,998,762.28 547,792.63 13,700.00 89.64 20.85 6,498.03 7,183.72 8,037.21 9,907.34 0.00 0.00 5,998,855.91 547,827.72 13,800.00 89.64 20.85 6,498.66 7,277.17 8,072.80 10,007.07 0.00 0.00 5,998,949.54 547,862.81 13,900.00 89.64 20.85 6,499.30 7,370.62 8,108.40 10,106.81 0.00 0.00 5,999,043.17 547,897.90 14,000.00 89.64 20.85 6,499.93 7,464.07 8,143.99 10,206.54 0.00 0.00 5,999,136.80 547,932.99 Planned TD at 14000.00 3asing Points m Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 14,000.00 6,499.93 2-3/8" 2.375 3.000 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/_S +E/_W (usft) (usft) (usft) (usft) Comment I 12,400.00 6,666.63 6,085.64 7,410.81 TIP/KOP 12,835.00 6,576.94 6,420.38 7,665.21 Start DLS 7.00 TFO 195.00 13,260.00 6,487.69 6,779.97 7,863.53 Start 200.00 hold at 13260.00 MD 13,460.00 6,495.38 6,960.52 7,949.23 Start DLS 7.00 TFO 292.00 13,530.00 6,496.95 7,024.86 7,976.71 Start 470.00 hold at 13530.00 MD 14,000.00 6,499.93 7,464.07 8,143.99 Planned TD at 14000.00 1111812019 9:17:52AM Page 3 COMPASS 5000.14 Build 85H ConocoPhillips ConocoPhillips Anticollision Report Baker Hughes 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 1R-23AL3 Reference Design: 1 R-23AL3_wp01 (Draft A) 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-23AL3_wp01 (Draft A) Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 12,400.00 to 14,000.00usft 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 11/15/2019 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 12,400.00 1R-23A_wp06 (Draft A) (113-23A) MWD OWSG OWSG MWD - Standard 12,400.00 14,000.00 1R-23AL3_wp01 (Draft A) (1R-23AL3) 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 1 R Pad 1 R-23 - 1 R-23A - 1 R-23A_wp06 (Draft A) 12,710.70 12,725.00 58.88 58.31 102.423 CC, ES 1 R-23 - 1 R-23A - 1 R-23A_wp06 (Draft A) 13,980.26 13,950.00 204.40 197.17 28.258 SF 1 R-23 - 1 R-23AL1 - 1 R-23A1-1_wp04 (Draft A) 12,710.70 12,725.00 58.88 58.31 102.423 CC, ES 1 R-23 - 1 R-23AL1 - 1 R-23A1-1_wp04 (Draft A) 13,980.26 13,950.00 204.40 197.17 28.258 SF 1 R-23 - 1 R-23AL2 - 1 R-23A1-2_wp03 (Draft A) 12,709.88 12,725.00 61.31 60.63 90.402 CC, ES 1 R-23 - 1 R-23AL2 - 1 R-23AL2_wp03 ( Draft A) 13,980.87 13,950.00 239.16 226.81 19.366 SF 1 R-23 - 1 R-231-1 P131 - 1 R-231-1 P131 12,771.13 12,875.00 190.90 182.51 22.741 SF 1 R-23 - 1 R-231-1 PB1 - 1 R-231-1 P81 13,912.61 14,000.00 137.60 134.09 39.231 CC 1 R-23 - 1 R-231-1 PB1 - 1 R-231-1 P131 14,000.00 14,088.00 137.66 133.96 37.177 ES 1 R-23 - 1 R-231-1 PB2 - 1 R-2311 PB2 12,406.71 12,450.00 196.59 190.83 34.124 CC, ES 1 R-23 - 1 R-23L1 PB2 - 1 R-231-1 P82 12,901.83 13,010.00 234.66 225.35 25.223 SF 1 R-23 - 1 R-231-1 PB3 - 1 R-231-1 PB3 13,500.00 13,675.00 204.58 190.26 14.280 SF 1 R-23 - 1 R-231-1 PB3 - 1 R-23L1 P83 13,564.32 13,760.00 186.28 174.10 15.291 CC, ES 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 Offset Design Kuparuk 1 R Pad - 1 R-23 - 1 R-23A - 1 R-23A_wp06 (Draft A) Offset Site Error: 0.00 "sit 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) (usff) (usft) (usft) (usft) (usft) (`) (usft) (usft) (usft) (usft) (usft) 12,424.99 6,755.42 12,425.00 6.755.92 0.08 0.17 -145.21 6,104.45 7,427.23 0.50 0.24 0.26 1.956 Caution Monitor Closely 12,449.91 6,755.48 12,450.00 6,757.46 0.15 0.34 -145.65 6,123.31 7,443.57 2.00 1.71 0.29 6.943 12,474.70 6,754.81 12,475.00 6,759.13 0.24 0.51 -145.64 6,142.26 7,459.79 4.35 4.03 0.32 13.759 12,499.36 6,753.42 12,500.00 6.760.66 0.32 0.69 -145.22 6,161.37 7,475.84 7.29 6.95 0.33 21.852 12,523.84 6,751.33 12,525.00 6,762.06 0.42 0.87 -144.87 6,180.63 7,491.71 10.80 10.46 0.34 31.360 12,548.13 6.748.57 12,550.00 6,763.32 0.51 1.06 -144.64 6.200.05 7,507.41 14.90 14.55 0.35 42.927 12,572.20 6,745.15 12,575.00 6,764.45 0.61 1.25 -144.52 6,219.62 7,522.93 19.56 19.22 0.34 57.591 12,596.02 6,741.10 12,600.00 6,765A3 0.71 1.44 -144.49 6,239.34 7,538.26 24.77 24.46 0.31 79.243 12,619.57 6,736.45 12.625.00 6.766.29 0.81 1.64 -144.54 6,259.21 7,553.41 30.54 30.27 0.27 113.133 12,642.84 6,731.23 12,650.00 6.767.00 0.92 1.85 -144.65 6,279.22 7,568.37 36.84 36.48 0.36 102,201 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 1111512019 2:16.30PM Page 2 COMPASS 5000.14 Build 85H d L 7 x v Y O m 0 0 0 OLL m 0 v o O "O V O O O Cl L O L m C O U` O I Cl N o (n ) co U6 l0 J ryi Q H (n (n d r-O NCO O) V' a � ti r ti t o � � tO Cp CDMO O Cr OCn LSO d 0 0 0 0 0 0 Zr OM 00 0000 �OLC) tlONO N G M N 0 0 0 0 0 0 N 0 0 0 0 0 0 O O C'! O) r W N rA t� O O t L) M CT C p M Cp COS 7t ti cD�OCr c0 J ct W h- N O ti r (p M O t o cd O Q W CCN h SOT OC' V F- G D } O C 60i LU 0 c0 6110 rfJM J COO (DM 00 LLI 0 c0 cn n- co of co�mrnMM �� tD v V Md" a co 10 cn mcom m©m o CO N N aD O O In Ln N I• M M C O C0 N O 0 O C U C CO OO t V C M CO CD oD (D OR ti O � �- O W � p CO zz aO W CO O �+ O O Cl O O O O 0 0 0 0 0 0 O r L J 0 0 0 0 O M CO CO M O -�t a0 N V tL) Cl N_ N M M M Z O } 0 0 F t 15 0 5 0 5 0 5 0 V p N O p Z C_ 76 O LO co00 N M v LO ti N p 9 m to a ao cn o � a m I cif _ oo c0 co M p oo E m w x= a r� _ n p m m@ m p Q' W LO ti_ m Na) > �] a) ca N o cl �' a Cl. L) E UJ m i� a 'cca fn E M O 2 U ai U X ch X N N N N Cn N N D N N c0 M m CM Co O m m O M F.-z 4 ❑ M_ N ❑ V N O m m O O d � L ❑ NV¢ p ~ ❑ N � UI Q] C 0 avL ��rnrn C NV¢ 2 CFO cl N ca m� aC N Ll ¢o Ll ZI I d p N p � L (p C O N y N r W co O O Lr)LO `— �D U1 r co W W p L U O t� d �= a C(oN p CCco ch IY di- ^� W (M O m p fO Y > U io t) p M _ O cq (D N_ 0 Z cQ G Q Q U O C N CO co 00 LO r a M r 11 04 n m m mr m Q p CL p � as a rn " - °co co p m o Q 00 E m 'n w = E c _ °� IS d Q p LU = m m m LO LO V7 m > U m Y d _ r O a) o o E CO rn m H U O U) o7 �) X N N N N fn O O (n CV h N N co Cl) co co O m m O co O O p O L N LO N 00 ifl O LO> Q r LU O Q 3k cG 2 2 co M co Zom d r O> CN C6 O 0 r N o p W J # 00 N _ Loepp, Victoria T (CED) From: Loepp, Victoria T (CED) Sent: Friday, November 1, 2019 10:51 AM To: McLaughlin, Ryan; Boyer, David L (CED) Cc: Ohlinger, James J Subject: KRU 1 R-23(PTD 191-101, Sundry 319-493) Set 261 B Whipstock Follow Up Flag: Follow up Flag Status: Completed Ryan, This sundry work for setting a whipstock in motherbore KRU 111-23 has changed from setting a 261E whipstock(originally the C Sand was left open) to a plug for redrill since now all the perforations will be cemented. The paperwork has just increased. This is what is needed: 1. A plug for redrill sundry for KRU 1R-23(PTD 191-101); we can change this existing sundry(319-492) to plug for redrill by hand. No need to resubmit the whipstock sundry. 2. However, the naming convention of the sidetrack and laterals must change as follows and new PTDs must be submitted: a. Well KRU 111-231-1 will need to be resubmitted as KRU 1R-23A b. Well KRU 1R-231-1-01 will need to be resubmitted as KRU 1R-23A-01 c. Well KRU 1R-23L1-02 will need to be resubmitted as KRU 1R-23A-02 d. These will all be assigned new PTD and API numbers. The motherbore will be abandoned and the KRU 1R-23L1 closed out. I will route the plug for redrill whipstock for KRU 111-23 for approval today or Monday. However, please submit the required new PTDs. So sorry for the additional paperwork. Let me know if any clarification is needed. Thanx, 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(o)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 iictoria.Loepg alaskac, Loepp, Victoria T (CED) From: Loepp, Victoria T (CED) Sent•Tuesday, October 29, 2019 10:18 AM To: McLaughlin, Ryan Cc: Ohlinger, James J Subject: KRU 1 R-231_1(PTD 219-128) Operations Shutdown Request Follow Up Flag: Follow up Flag Status: Completed Ryan, Verbal approval is granted for the Operations Shutdown for CRD3-AC for KRU 1R-23L1(PTD 219-128). Thanx, 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(&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.Loeipp@alaska.ci From: McLaughlin, Ryan <Ryan.McLaughlin @conocophillips.com> Sent: Tuesday, October 29, 2019 10:13 AM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Cc: Ohlinger, James J <James.J.Ohlinger@conocophillips.com> Subject: 111-23 (PTD 191-101) Operations Shutdown Request Hello Victoria On October 16th CDR3-AC rigged up to drill a tri-lateral project on 111-23. After 3 unsuccessful attempts at drilling the 111-231-1 lateral, primarily due to hole cleaning issues in the 7 production casing, the decision was made to rig down CDR3-AC from 111-23 and set the well up for a cement pilot hole exit for the rig to come back at a later date and complete the scope of the project under the approved PTD. In preparation for resuming CTD operations on this well, perforations will be shot in the tubing tail, cement will be pumped to occupy the 7" casing and plug off C-sand perforations, and the XN nipple in the tubing tail will be milled out. CDR3-AC will mill a cement pilot hole, set a 3-1/2" whipstock, and mill a 2.80" window in the production casing at a depth of 11,662' MD and complete the original scope of the project under the existing permits. We are requesting verbal approval for an Operations Shutdown with the Sundry to be submitted today. We will also submit a subsequent sundry request for cement -squeezing the C-sand perforations and setting a new whipstock prior to beginning the service coil work. 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 Loepp, Victoria T (CED) From: Loepp, Victoria T (CED) Sent: Thursday, November 7, 2019 9:18 AM To: Melvin Rixse; Schwartz, Guy L (CED) Cc: Chmielowski, Jessie L C (CED); Carlisle, Samantha J (CED); Boyer, David L (CED) Subject: FYI: KRU/CRU PTD(10-401s) while Victoria on A/L Attachments: Sonic Conditions of Approval.docx; Perm it_219-140_101619.pdf; 8.13.19 Conditions of Approval NFT.SSSV.ESP 3R-111.docx; Perm it_219-134_102219.pdf Mel, Guy, Sam, FYI Rotary PTDs that will be submitted for AOGCC approval include KRU 3R-107(producer) and CRU CD5-96: Guy will handle these. Guy attached are conditions of approval that I'm attaching to DS-3R producers relating to the no flow test required for elimination of the SSSV requirement. I worked on these conditions with Jim and would like to be consistent with the DS-3R producers. CTD PTDs that will be submitted include KRU 1R-23 sidetrack and laterals and 3H-01 sidetrack and laterals: Mel will handle these; Mel, I attached 10-401 "condition" for kickoff point variance so you can see what we have been granting on these CTD laterals. Note, originally the 111-23 PTDs were approved as laterals because C sand was left open in the motherbore. This has changed. They are now plugging the motherbore and drilling a sidetrack (111-23A) plus laterals. The plug for redrill sundry for the motherbore has been approved however they will be submitting new PTDs(10-401s) for the 1R-23 sidetrack and laterals. Also attached is 10-401 Conditions of Approval for running the sonic for cement evaluation for wells to be fracked or injectors which I have been including as a part of the 10-401 approval. Thank you! 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@_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 taw. 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 Vic torin.LoF�pp,4alaska_,gov_ TRANSMITTAL LETTER CHECKLIST WELL NAME: 2 ,q ,� PTD: I/. Development —Service _Exploratory — Stratigraphic Test — Non -Conventional FIELD: ����c J -- 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 w ll Pe t i LATERAL No. API No. 50- c� 22G��! _ ►� (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 rmit . 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' sam le intervals throu 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 (Compan Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (C M Name l must contact the AOGCC to obtain advance approval of such water well testing pro m. 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 (Companv 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 com letion, susperasion or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK RIV UNIT 1R-23AL3 Program DEV — Well bore seg se PTD#:2191690 Company ConocoPhillips Alaska, Inc._ -_ Initial Class/Type DEV / PEND—GeoArea 890 Unit 1.116.0_ On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate- Yes Surface Location lies within ADL0025635; Portion of Well Passes Thru ADL0025636;- 3 Unique well name and number Yes Top Prod Int & TD of this contingency lateral lie within ADL00256.27. 4 Well located in a defined pool Yes Kuparuk River Oil Pool, governed by Conservation Order No. 432D 15 Well located proper distance from drilling unit boundary Yes CO 432D Rule 3: There shall be no restrictions as to well spacing except that no pay shall be opened in 6 Well located proper distance from other wells_ Yes a well closer than 500 feet to an external property line where ownership or landownership changes. 7 Sufficient acreage available in drilling unit Yes As planned, this contingency lateral well branch conforms with spacing requirements._ 18 If deviated, is wellbore plat included Yes - I9 Operator only affected party Yes - 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 112 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15-day wait Yes SFD 11/22/2019 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D) NA 18 Conductor string provided NA Conductor set for_KR_U 1_R-23_ Engineering 119 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 22 CMT will cover all known productive horizons No Productiveintervalwill be completed with uncemented slotted liner 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If_a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes Anti -collision analysis complete; no major risk fail 27 If diverter required, does it meet regulations_ NA Appr Date 28 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 12/4/2019 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 2841 psig; will test BOPs_to 3500_psig 31 Choke manifold complies w/API RP-53 (May 84) Yes 132 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable - Yes H2S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA ---- ----- - 35 Permit can be issued w/o hydrogen_ sulfide measures No Wells on 1R-Pad are_H2_S-bearing. H2S measures required. Geology I36 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 11/22/2019 ':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 weeklyprogressreports [exploratory only] - NA maintaining a constant_ pressure gradient of about_ 11.8_ ppg EMW. - Geologic Engineering Public Contingency lateral that will be drilled instead of 1 R-23AL2 if the C1 sands are found to be wet by 1 R-23AL1. SFD Commissioner: Date: Commissioner: Date mmission Date
