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Home My WebLink About219-140,2J —1<f1"e' Davies, 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 1 R-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 ConocoPhillips does not plan to attempt to drill 1R-23L1-01, 1R-231-1-02, and 1R-231-1-03 so those permits can be withdrawn.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:907-26S-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 113-231-1-01, 111-231-1-02, 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.Qov. 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 GOVERNOR MIKE DUNLEAVY James Ohlinger Staff CTD Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Alaska Oil and Gas Conservation Commission Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 1R-23L1-03 ConocoPhillips Alaska, Inc. Permit to Drill Number: 219-140 Surface Location: 114' FSL, 479' FWL, SEC. 27, T1IN, R8E, UM Bottomhole Location: 2834' FNL, 2818' FWL, SEC. 9, T12N, R10E, UM Dear Mr. Ohlinger: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the permit to redrill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 191-129, API No. 50-103-20156- 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, v 'I' Price Chair DATED thiA4 day of October, 2019. STATE OF ALASKA AL, A OIL AND GAS CONSERVATION COMM1 ON PERMIT TO DRILL (. f 20 AAC 25.005 1 a. Type of Work: . Drill ❑ Lateral ❑� Redrill ❑ Reentry ❑ 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ Stratigraphic Test ❑ Development - Oil ❑ - Service - Winj ❑ Single Zone 0 • 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-231-1-03 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 13,800 TVD: 6677' 12. Field/Pool(s): Kuparuk River Field / 1' + Kuparuk River Oil Pool 4a. Location of Well (Governmental Section): Surface: 4854' FNL, 144' FWL, Sec 17, T12N, R10E, UM Top of Productive Horizon: 4188' FNL, 2350' FWL, Sec 9, T12N, R10E, UM Total Depth: 2834' FNL, 2818' FWL, Sec 9, T12N, R10E, UM 7. Property Designation: ADL 25627.PLK.-2-569T 8. DNR Approval Number: LONS 83-134 13. Approximate Spud Date: 10/16/2019 9. Acres in Property: 2560 14. Distance to Nearest Property: 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: 2909', 1 R-35 16. Deviated wells: Kickoff depth: 12,400 ' feet Maximum Hole Angle: 103 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 I Coupling Length MD TVD MD TVD (including stage data) 3" 2-3/8" 4.7# L-80 ST-L 2195' 11,605' . 6724' 13,800. 6677 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' 161, 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 P1 • 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: an.mclaU h In c0 .com Authorized Title: Staff CTD gineer Contact Phone: 907-265-6218 Authorized Signature: Date: Commission Use Only Permit to Drill G ' Number: / � ��U API NumbLe� 50- U� ` z- Z--Z � ` 0 SS_ Permit Approval Date: `� l See cover letter for other requirements. Conditions of approval : If box is checked, well maynotbe used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: , Other: BOP - j--eS t rJ1'c SS !/% C / D ,3 SD j� S t Samples req'd: Yes ❑ No ❑✓ Mud log req'd: Yes ❑ , No []' �9h n tv 1 a r p /-c ve-� fC r frs f— f D 7Q',� 5 ea�res: Yes 0 No❑ ; Directional svy req'd: Yes [✓] No❑ Spacing Ewceptlon eq'd: Yes ❑ No Inclination -only svy req'd: Yes ❑ No[ /'% C C 7'0 70 411 C 2 5 Post initial injection MIT req'd: Yes ❑ NoR' �S9/�ahtec/ to a�//oLv he- /t/e�Bf�,poj�-i� to b cLny p0/'1) f a, /ovi,y fhe pa rr�� /er, tcr2 . APPROVED BY Approved by: � COMMISSIONER THE COMMISSION Date: `d ^ ' I q VFL /O/�5 % Submit Form and Form 10-401 Revised 5/2017 This permit is valid or 4&Rf d f p ov al per 20 AAC 25.005(g) Attachments in Duplicate ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 14, 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 four 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 41116th, 2019. The objective will be to drill three laterals — 1 R-231_1 and 1 R-231_1-01 will be unlined delineation laterals to the north and east, crosscutting through the A3 and C1 sands. 1 R-231_1-02 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. The fourth lateral, 1 R-231-1-03, 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 f 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 1R-231-1, 1R-231_1-01, & 1R-231_1-02, & 1R-231_1-03 - Detailed Summary of Operations - Directional Plans for 1R-231-1, 1R-231_1-01, & 1R-231_1-02 & 1R-231_1-03 - Current wellbore schematic - Proposed CTD schematic If you have any questions or require additional information, please contact me at 907-265-6218. Sincerely, Ryan McLaughl' Coiled Tubing Drilling Engineer ConocoPhillips Alaska Kuparuk CTD Lateral 1 R-231-15 1 R-231-1-015 & 1 R-231-1-02 & 1 R-231-1-03 Application for Permit to Drill Document 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(o and 20 AAC 25.005(b))................................................................................................................... 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2)).................................................................................................................................................. 2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 2 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7)).................................................................................................................................................. 3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9)).................................................................................................................................................. 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4 11. Seabed Condition Analysis............................................................................................................ 4 (Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................ 4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 4 13. Proposed Drilling Program............................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................4 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................6 14. Disposal of Drilling Mud and Cuttings.......................................................................................... 6 (Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 6 15. Directional Plans for Intentionally Deviated Wells....................................................................... 6 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 6 16. Attachments....................................................................................................................................6 Attachment 1: Directional Plans for 1R-23, 1R-231-1-01, & 1R-23L1-02 & 1R-231-1-03..................................................6 Attachment 2: Current Well Schematic for 1 R-23, 1 R-231-1-01, & 1 R-231-1-02 & 1 R-231-1-03.......................................6 Attachment 3: Proposed Well Schematic for 1R-23, 1R-23L1-01, & 1R-231-1-02 & 1R-231-1-03....................................6 Page 1 of 6 September 16, 2019 P i D Application: 1 R-231-1, 1 R-231-1-U1, & 1 R-23L1-02 & 1 R-231_1-03 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) The proposed laterals described in this document are 1R-23, 1R-23L1-01, & 1R-231_1-02 & 1R-231_1-03. The laterals will be classified as "Development - Oil" wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the C1 and A3 sand packages in the Kuparuk reservoir. See attached 10-401 form for surface and subsurface coordinates of 1R-23, 1R-231_1-01, & 1R-231_1-02 & 1R-231_1-03. . 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR3-AC. BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. Using the maximum formation pressure in the area of 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 1R-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 1 R-23L1, 1 R-231_1-01, & 1 R-231_1-02 & 1 R-23L1-03.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 P i D Application: 1 R-231-1, 1 R-231_1-U1, & 1 R-231_1-02 & 1 R-231_1-03 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 deployment sleeve 1R-231_1-03 11,605'. 13,800' . 6636' 6589' 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 TV D Burs t si Collapse si 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 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 6 September 16, 2019 P i D Application: 1 R-23L1, 1 R-231_1-u1, & 1 R-231_1-02 & 1 R-231_1-03 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 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 (11,680' MD, 6760' TVD) Usinq MPD Pumps On 1.8 b m Pumps Off Formation Pressure 10.0 3515 psi 3515psi' Mud Hydrostatic 8.6 3023 psi 3023 psi Annular friction (i.e. ECD, 0.080 psi/ft) 934 psi 0 psi Mud + ECD Combined no chokepressure) 3957 psi Overbalanced -442psi) 3023 psi Underbalanced -492psi) Target 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 YNI nipple will have + be milled „, �+ 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. If the C1 sands are found to be wet due to a higher than anticipated oil -water -contact, the 1 R-231_1-02 lateral will not be drilled and instead a contingency lateral, 1R-231_1-03, will be 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. Page 4 of 6 September 16, 2019 Pi D Application: 1R-231-1, 1R-231_1-U1, & 1R-231_1-02 & 1R-231_1-03 Pre-CTD Work 1. RU Slickline: Dummy whipstock drift, SBHP 2. RU E-line: Caliper 3. RU G-TI-1: Moll D Nipple 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. 2. 1 R-23L1 Lateral (Delineation Lateral A/C Sands - North) a. Mill2.80" 2.74" window at 11,680' 11,682' MD b. Drill 3" bi-center lateral to TD of 14,975' MD c. Set anchored aluminum billet at 14,100' MD 3. 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-231_1-02 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 17,000' 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. 1 R-231_1-03 Lateral (C1 Sand - North) a. Kick off of the aluminum billet at 12,400' MD b. Drill 3" bi-center lateral to a TD of 13,800' 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 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 Page 5 of 6 September 16, 2019 Pi D Application: 1R-231-1, 1R-231_1-u1, & 1R-231_1-02 & 1R-231_1-03 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 & 1R-231_1-03 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-23L1 4790' 1 R-23 L1-01 3041 ' 1R-23L1-02 2541' 1 R-23L1-03 5105' - - 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 1R-23L1-03 2909' 1R-35 16. Attachments Attachment 1: Directional Plans for the 1R-23L1, 1R-23L1-01, & 1R-23L1-02 & 1R-23L1-03laterals 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-23L 1-02 & 1 R-23L 1-03 laterals Page 6 of 6 September 16, 2019 .: k 2 \ m � s .a 30 0 c 0 - - (u!Gm m%(+)oN/(-)9mS ConocoPs philli ConocoPhillips Alaska Inc—Kuparuk Kuparuk River Unit Kuparuk 1 R Pad 1 R-23 1 R-23 L 1-03 Plan: 1 R-231-1-03 wp01 (Draft A) Standard Planning Report 13 October, 2019 Baker Hughes $ ,0", ConocoPhillips ConocoPhillips Planning Report Baker Hughes Database: EDT 14 Alaska Production Company: ConocoPhillips Alaska Inc Kuparuk Project Kuparuk River Unit Site: Kuparuk 1R Pad Well: 1 R-23 Wellbore: 1 R-23L1-03 Design: 1R-231-1-03_wp01 (Draft A) 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 1 R Pad Site Position: Northing: 5,991,050.01 usft Latitude: 700 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: 70' 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-231-1-03 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BG G M2018 11 /1 /2019 16.37 80.88 57,403 Design 1 R-23L1-03_wp01 (Draft A) T Audit Notes: Version: Phase: PLAN Tie On Depth: 12,400.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction - (usft) -- (usft) (usft) 0.00 0.00 0.00 20.00 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) (°/100usft) (°) Target 12,400.00 90,96 42.14 6,704.07 6,019.30 7,464.94 0.00 0.00 0.00 0.00 12,505.00 98.31 42.14 6,695.60 6,096.85 7,535.11 7.00 7.00 0.00 0.00 12,585.00 102.24 38.09 6,681.32 6,157.01 7,585.82 7.00 4.92 -5.06 -45.00 12,835.00 101.67 20.21 6,629.12 6,369.69 7,704.40 7.00 -0.23 -7.15 -90.00 12,935.00 102.80 13.14 6,607.91 6,463.24 7,732.43 7.00 1.13 -7.07 -80.00 13,120.00 89.85 13.14 6,587.58 6,641.92 7,774.14 7.00 -7.00 0.00 180.00 13,800.00 89.85 13.14 6,589.40 7,304.11 7,928.73 0.00 0.00 0.00 0.00 1011312019 4:12:57PM Page 2 COMPASS 5000.14 Build 85H ConocoPhillips ConocoPhillips Planning Report Baker Hughes Database: EDT 14 Alaska Production Local Co-ordinate Reference: mWell 1 R-23� Y 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-23L1-03 Design: 1R-23L1-03_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) (°1100usft) (°) (usft) (usft) 12,400.00 90.96 42.14 6,704.07 6,019.30 7,464.94 8,209.45 0.00 0.00 5,997,688.57 547,261.71 TIP/KOP 12,500.00 97.96 42.14 6,696.31 6,093.18 7,531.79 8,301.74 7.00 0.00 5,997,762.80 547,328.16 12,505.00 98.31 42.14 6.695.60 6,096.85 7,535.11 8,306.32 7.00 0.00 5,997,766.49 547,331.46 Start DLS 7.00 TFO -45.00 12,585.00 102.24 38.09 6,681.32 6,157.01 7,585.82 8,380.20 7.00 -45.00 5,997,826.91 547,381.85 Start DLS 7.00 TFO -90.00 12,600.00 102.24 37.02 6,678.14 6,168.63 7,594.76 8,394.18 7.00 -90.00 5,997,838.58 547,390.72 12,700.00 102.12 29.86 6,657.01 6,250.15 7,648.58 8,489.18 7.00 -90.23 5,997,920.37 547,444.10 12,800.00 101.82 22.71 6,636.25 6,337.80 7,691.86 8,586.35 7.00 -91.74 5,998,008.24 547,486.91 12,835.00 101.67 20.21 6,629.12 6,369.69 7,704.40 8,620.61 7.00 -93.23 5,998,040.19 547,499.28 Start DLS 7.00 TFO -80.00 12,900.00 102.42 15.62 6,615.55 6,430.15 7,723.95 8,684.11 7.00 -80.00 5,998,100.76 547,518.51 12,935.00 102.80 13.14 6,607.91 6,463.24 7,732.43 8,718.10 7.00 -80.96 5,998,133.88 547,526.81 Start DLS 7.00 TFO 180.00 13,000.00 98.25 13.14 6,596.04 6,525.45 7,746.96 8,781.54 7.00 -180.00 5,998,196.17 547,541.00 13,100.00 91.25 13.14 6,587.77 6,622.44 7,769.60 8,880.42 7.00 -180.00 5,998,293.27 547,563.13 13,120.00 89.85 13.14 6,587.58 6,641.92 7,774.14 8,900.27 7.00 -180.00 5,998,312.76 547,567.57 Start 680.00 hold at 13120.00 MD 13,200.00 89.85 13.14 6,587.80 6,719.82 7,792.33 8,979.70 0.00 0.00 5,998,390.76 547,585.34 13,300.00 89.85 13.14 6,588.06 6,817.20 7,815.07 9,078.98 0.00 0.00 5,998,488.25 547,607.55 13,400.00 89.85 13.14 6,588.33 6,914.58 7,837.80 9,178.27 0.00 0.00 5,998,585.74 547,629.76 13,500.00 89.85 13.14 6,588.60 7,011.97 7,860.53 9,277.55 0.00 0.00 5,998,683.23 547,651.97 13,600.00 89.85 13.14 6,588.87 7,109.35 7,883.27 9,376.84 0.00 0.00 5,998,780.72 547,674.19 13,700.00 89.85 13.14 6,589.14 7,206.73 7,906.00 9,476.12 0.00 0.00 5,998,878.21 547,696.40 13,800.00 89.85 13.14 6,589.40 • 7,304.11 7,928.73 9,575.40 0.00 0.00 5,998,975.71 547,718.61 Planned TD at 13800.00 Casing Points Measured Vertical Casing Depth Depth Diameter (usft) (usft) Name (in) 13,800.00 6,589.40 2-3/8" 2.375 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 12,400.00 6,704.07 6,019.30 7,464.94 TIP/KOP 12,505.00 6,695.60 6,096.85 7,535.11 Start DLS 7.00 TFO -45.00 12,585.00 6,681.32 6,157.01 7,585.82 Start DLS 7.00 TFO -90.00 12,835.00 6,629.12 6,369.69 7,704.40 Start DLS 7.00 TFO -80.00 12,935.00 6,607.91 6,463.24 7,732.43 Start DLS 7.00 TFO 180.00 13,120.00 6,587.58 6,641.92 7,774.14 Start 680.00 hold at 13120.00 MD 13,800.00 6,589.40 7,304.11 7,928.73 Planned TD at 13800.00 Hole Diameter (in) 3.000 10/13/2019 4:12:57PM Page 3 COMPASS 5000.14 Build 85H ConocoPs philli ConocoPhillips Alaska Inc—Kuparuk Kuparuk River Unit _2 Kuparuk 1 R Pad 1 R-23 1 R-23 L 1-03 1 R-23L1-03_wp01 (Draft A) Anticollision Report 13 October, 2019 Baker Hughes g 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-231-1-03 Reference Design: 1R-23L1-03_wp01 (DraftA) 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 1 R-23L1-03_wp01 (DraftA) 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 13,800.00usft 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 From (usft) 100.00 11,600.00 12,400.00 Date 10/13/2019 To (usft) Survey (Wellbore) Tool Name 11,600.00 1 R-23 (1 R-23) GCT-MS 12,400.00 1R-23L1_wp03 (1R-231-1) MWD OWSG 13,800.001R-231-1-03_wp01(DraftA)(1R-231-1-03) MWD OWSG Description Schlumberger GCT multishot OWSG MWD - Standard OWSG MWD - Standard Summary Reference Offset Distance Measured Measured Between Between Separation Warning Site Name Depth Depth Centres Ellipses Factor Offset Well - Wellbore - Design (usftl (usft) (usft) (usft) Kuparuk 1 R Pad 1 R-23 - 1 R-23L1 - 1 R-231-1_wp03 13,190.00 13,175.00 55.54 51.99 15.649 CC, ES 1 R-23 - 1 R-231-1 - 1 R-23L1_wp03 13,706.64 13,700.00 123.77 105.71 6.853 SF 1 R-23 - 1 R-23L1-01 - 1 R-23L1-01_wp03 12,422.25 12,425.00 9.08 1.96 1.275 Take Immediate Action, CC, 1 R-23 - 1 R-23L1-02 - 1 R-23L1-02_wp02 12,422.25 12,425.00 9.08 1.96 1.275 Take Immediate Action, CC, 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_wp03 Offset Site Error: 0.00 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 +Ni-S +Er-W Centres Ellipses separation factor (usft) (usft) (usft) (usft) (usft) (usft) (`) (usft) (usft) (usft) (usft) (usft) 12,424.99 6,791.27 12,425.00 6,791.66 0.14 0.17 -92.88 6,038.09 7,481.43 0.54 0.23 0.31 1.739 Caution Monitor Closely 12,449.91 6,789.72 12,450.00 6,791.24 0.28 0.34 -92.84 6,057.37 7,497.33 2.16 1.83 0.33 6.533 12,474.69 6.787.42 12,475.00 6,790.83 0.33 0.51 -92.77 6,077.13 7,512.64 4.85 4.21 0.63 7.653 12499.26 6,784.41 12,500.00 6,790.41 0.39 0.68 -92.68 6.097.35 7,527.34 8.60 7.75 0.85 10.119 12,523.78 6,780.73 12,525.00 6,790.00 0.46 0.84 -93.92 6.118.01 7,541.41 13.25 12.20 1.05 12.562 12,548.23 6,776.56 12,550.00 6,789.59 0.54 1.01 -96.00 6,139.08 7,554.84 18.44 17.20 1.24 14.864 12,572.56 6,771.90 12,575.00 6,789.19 0.62 1.18 -98.24 6.160.56 7,567.63 24.15 22.74 1.41 17.114 12,597.06 6,766.77 12,600.00 6,788.79 0.71 1.35 -100.76 6.182.42 7,579.75 30.33 28.75 1.58 19.198 12,621.94 6,761.49 12,625.00 6.788.39 0.81 1.51 -103.38 6,204.64 7,591.20 36.57 34.82 1.75 20.897 12,646.96 6,756.20 12,650.00 6.788.00 0.90 1.67 -105.84 6,227.20 7,601.97 42.80 40.88 L92 22.277 12,672.11 6,750.88 12,675.00 6,787.58 1.00 1.83 -108.20 6,250.06 7,612.07 48.97 46.88 2.09 23.424 12,697.59 6,745.52 12,700.00 6,786.60 1.11 1.99 -110.61 6,272.99 7,621.98 54.35 52.09 2.26 24.081 12,723.38 6,740.11 12,725.00 6,784.86 1.22 2.16 -113.11 6,295.89 7,631.87 58.64 56.22 2.42 24.204 12,749.42 6,734.69 12,750.00 6,782.36 1.34 2.33 -115.71 6,318.72 7,641.73 61.82 59.24 2.58 23.959 12,775.63 6,729.26 12,775.00 6,779.13 1.46 2.50 -118.44 6,341.48 7,651.57 63.92 61.18 2.73 23.398 12,801.89 6,723.86 12,800.00 6,775.70 1.58 2.68 -121.57 6,364.21 7,661.39 65.35 62,49 2.85 22.895 12,828.14 6,718.51 12,825.00 6.772.27 1.70 2.86 -125.20 6.386.94 7,671.21 66.30 63.35 2.94 22.537 CC - Min Centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 10/13/2019 3:34:10PM Page 2 COMPASS 5000.14 Build 85H w N Q7 s rn 2 L d Y O CD 0 0 O T �2 �2 O 0000 mm LL LL LL U- M H H H H � •-'N C O1r O CncnwCnpF-- O� �6000QQ to IDJO OY r-crrr c E f— in cn cn in cn a � N 6)c000 O uJ O O c O N NM MHO 1�. O) CO c0 OD CO c0 aD m O'1 N Z j CO N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N J rn m N i f C0 C> 0 0 N O O O O O O O ti ch�NOM� M R LA V N .0 'y CO J N N i M a p O (O N O00 c- Q w Q) + O O 1] co c D V p w if i J O <00 M O OV LL a, 00)aONOCD W L CO (D t0 cO �O tO CO C Cl) 010 Z O N +- Q) R Clj M O M O N U fD ; -It 1� � u C O M N co c0 c0 c0 O c p N N O) O O O m 0 0 0 a D a 0 � O L l J 0 0 0 0 0 0 0 0 + 0 0 0 0 0 0 0 0 0 a0 M M N O Z2 �2 �2 �2 �2 �2 Lo O h- � O N Z O F a a I KUP INJ 1R-23 LonocoYnimp5 Well Attributes Max Angle & MD JTD Aiaska Inc.Wellbom API/UWI Field Name Wellbore Status ncl 500292220000 KUPARUK RIVER UNIT INJ (") MD (ftKB) Act 66.10 3,000,00 St. (ftKB) 12,180.0 • Comment H2S (ppm) I Date SSSV: TRDP Annotation End Date Last W0: 1/6/1992 KB-Grd (ft) Rig Release Date 42.99 10/27/1991 1R-23, 12l30/20153:14:41 PM Vertical schematic(actual) Annotation Depth69(ftKB) Entl Date Annotation Last Mod By End Date Last Tag: SLM 11,2.0 8/9I2015 Rev Reason: PULLED FRAC SLEEVE lehallf 12/30/2015 Casing Strings Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (ND)... WtlLen (I... Grade Top Thread CONDUCTOR 16 15.062 44.0 123.0 123,0 62.50 H40 WELDED HANGER; 38.3 I Casing Description OD SURFACE (in) 9518 ID (In) 8.921 Top (ftKB) 42.0 Set Depth (ftKB) 6,330.8 Set Depth (ND)... 4,072.4 WtlLen (I... 36.OD Grade J-55 Top Thread BTC Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (ND)... WtlLen (I... Grade Top Thread PRODUCTION 7 6.276 29.2 12,177.7 7,002.5 26.00 L-80 NSCC Tubing Strings Tubing Description String Ma... ID (mI Top (ftKB) Set Depth (ft.. Set Depth (ND) (... Wt (Iblft) Grade Top Connection TUBING WO 3 1/2 2.992 38.3 11,609.9 6.726.7 9.30 J-55 EUEABMOD Completion Details Nominal ID Top (ftKB) Top (ND) (ftKB) Top Incl (°) Item Des Com (in) CONDUCTOR; 44.0-123.0 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 PBR 3.000 SAFETY VLV; 1,816.0 11,581.2 6,713.1 61.90 PACKER BAKER HB RETRIEVABLE PACKER 2.890 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 I BAKER SHEAR OUT SUB 2.992 Perforations & Slots Shot Dens GAS LIFT; 3,250.7 Top (ftKB) Btm (ftKB) Top (ND) Rim (ftKB) (ND) (ftKB) Zone (shots/t Date t) Type Com 11,710.0 11,770.0 6,774.1 6,803.1 C-2, C-1, 1/5/1992 10.0 IPERF Gun; 60 deg ph UNIT B, 1R- 1 14.5'Csg 23 Stimulations & Treatments Min Top Maz Dtm Depth Depth Top (ND) Btm (ND) (ftKB) (ftKB) (ftK13) (ftKB) Type Date Com 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 ati SURFACE; 42.06.3308 on N Top (ftKB) Top (ND) (ftKe) Make Model I OD (in) V.1- Sery Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 3,250.7 2,493.2 CAMCO KBUG- I 1 GAS LIFT DMY BK 0.000 0.0 10/27/1992 M 2 11,484.5 6,66Z5 OTIS LBD 1 1 112 1 GAS LIFT DMY IRM 0.000 0.0 4/1/1992 Notes: General & Safety End Date Annotation GAS LIFT, 11,494.5 10/19/2010 NOTE: View Schematic w/ Alaska Schematic9.0 9/19/2013 NOTE: PROD CSG RKB per RIG DETAIL SHEET NIPPLE; 11,529.9 PER; 11,567.E PACKER; 11,581.3 m NIPPLE, 11,597.5 SOS, 11,609.2 HPBD; 11,710011- IPERF; 11,710.0-11,770.0 PRODUCTION, 29.2-12,177 7 u 2 2 2 c L) 2 k a. Q � \ \ (D § \ \CO -- - E ) LO \ \ \ \ m - Co % § } \ ® u =E Q § j i \ $ ) Co S - § e ) Co - \ § E\ \ § / Cu CO k/ J / )/ x f 3 ~ ~ Q �CY) CY) { �u {Cl) Co 2 \ 0 § Co§ $§ \ a /ƒ k� - 7§ _ m§ k Co § \ § \ #a �- Loepp, Victoria T (CED) From: McLaughlin, Ryan < Ryan. McLaughlin @conocophill ips.com> Sent: Monday, October 14, 2019 1:26 PM To: Loepp, Victoria T (CED) Cc: Ohlinger, James J Subject: 1 R-23 Amended PTD Follow Up Flag: Follow up Flag Status: Flagged Hello Victoria, We will be submitting an amended PTD for 111-23 to add a contingency lateral, 1R-23L1-03. This lateral will be drilled and lined instead of the 111-231-1-02 lateral in the event that we encounter a higher than anticipated oil -water -contact. The 1R-23L1-03 will target the C1 sands in the upthrown fault block, pictured below. A 10-401 and all supporting documents for the contingency lateral will be submitted today. 1R-23L1, 1-1-02, & L1-02 CTD Injector Cross-section M 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 TRANSMITTAL LETTER CHECKLIST WELL NAME: k:e Z l - PTD: 2%q- i VU Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER j MULTI LATERAL The permit is for a new wellbore segment of existing well Permit No, lf/—/oZ API No. 50-fJ2�- ZZZG2�-OZ>. ✓ (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 I WELL PERMIT CHECKLIST PTD#:2191400 Company Conoc Administration A P f 10 11 Appr Date 12 13 SFD 10/14/2019 7 Engineering 26 27 Appr Date 28 VTL 10/15/2019 29 30 31 32 33 34 Well Name: KUPARUK RIV UNIT 1R-23L1-03 Program DEV Well bore seg � Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal Ll er_mit_eeattached-----------------------------NA ----------------------------------------------------------------- Lease number appropriate- - - - - - - - - - - - - - - - - - - Yes - - - - - - - Spoke well branch:_KOP, top prod interval, and TD in_ADL0025627- - - - - - - - - - - - - - - - - - - Uniquewell_nameandnumber---------------------- -- - -- Yes------------------------------------------------------------------ Well-locat_ed in a_deiined pool - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - _ Kuparuk River Oil_ Pool, gov_emed by Conservation Order No. 432D Well located proper distance from drilling unit -boundary -- - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Conservation Order No. 432D has no interwell_spacing-restrictions. Wellbore will_ be -more than 500' Well located proper distance from other wells- - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - from an external property line_ where_ ownership or_landownership- changes. As proposed,_well - - - - - Sufficient acreage available in -drilling unit - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - _ _ _ branch will -conform to spacing requirements. - - - - - - ------------------------- If deviated, is_wellbore plat -included - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - Operatoronly affected party - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Operatorhas-appropriate_bond in force -------------------------------- Yes------------------------------------------------------------------- Permit_can be issued without conservation order- - - - - - - - - - - - - - - - Yes - - _ Permit_can be issued without administrative -approval _ - _ - _ - - - - - - - Yes Can permit be approved before 15-day wait- - - - - - - - - - - - - - - _ _ _ - - - - Yes Well located within area and strata authorized by Injection Order# (put_10# in_comments)_(For_ NA_ _ _ _ _ _ _ _ _ _ _ _ _ -------------------------------- All wells -within 1/4_mile area of review identified For service well only) - review G X) NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Pre -produced injector: duration of pre -production less than_3 months _(For service well only) NA_ Nonconven. gas conforms to AS31.05.030(j.1_.A),(j.2.A-D) - - - - - - NA- - - - - - - - - - - - - - - - - - - Conductor string_provided - - - - - - - - - - - - - - - - - - - - NA_ - - - - - - _ Conductor set _ for _KRU_ 1_R-23 ------- Surfacecasing_pmtectsall_knownUSDWs---------------------- NA_ Surface casingset for KRU_1R-23------ - ---------------- CMT_vol_adequate _to circulate -on conductor_& surf_csg - - - - - - - - - - - - - - - - - - - - - - - - NA_ - - - - - - - Surface casing set and fully cemented - _ - - - - - - - - - - - - - - - - - - - - - CMT_vol_adequate_totie-inlongstringto-surf csg-------- --- --------- - - - - - -- NA - - - - -------- - - - - - ------- --------------------------------------- CMT_will cover all known -productive horizons - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - No_ _ - - - - - - Productiv_e_interval will be completed with_uncemented slotted_ liner_ - Casing designs adequate for C, T B &_permafrost- - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Adequate tankage or reserve pit _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - - - Rig has steel tanks; all -waste -to approved disposal wells- _ - - - - - - - - - - - - - - - - - - - - - - _ - - - - - - - - - If a_re-drill, has_a_ 10-403 for abandonment been approved - - - - - - - - - - - - - - - - - - - - - - NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Adequate wellbore separation proposed _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - _ _ - _ Anti -collision analysis compiete; no major risk failures - - - - - - - - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - If_diverter required, does it meet regulations- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 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_ - - - - BOPEs,_dothey-meet regulation ------------------------------------ Yes--------------- ------- - ------------------------------------------------ BOPE_press rating appropriate; test to _(put psig in comments)- - - - - - - - - - Yes - - - - - - - MPSP is 2841_ psig; will test BOPs_to 3500_psig- - - - - - - - - - - - - - - - - - Choke_manifold complies w/API_RP-53 (May 84)--------------- - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Work will occur without operation shutdown- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - _ - _ _ . _ _ _ _ _ _ _ _ _ - - _ - _ _ - - - - - - - - - - - - - - - - - - - ----------------------- Is presence_ of H2S gas probable - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - H2S measures required _ - _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - - - 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_H2S-bearing: H2S measures required. - - - - - - - - - - - - - - - - - - - - - - - - - Geology 36 Data_presented on potential overpressure zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes Expected r_eservoirpressure is 10.0 ppg, with some potential of higher pressure due togas Appr Date 37 Seismic analysis of shallow gas -zones ----------------------------------- A_ _ - - - - - injection within this area. Well will be drilled using 8,6 ppg mud, a coiled -tubing rig, and_ SFD 10/14/2019 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 11.8_ppg EMW. Geologic Engineering Public Commissioner: Date: Commissioner: Date Commissioner Date