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219-020
Winston, Hugh E (CED) From: Winston, Hugh E (CED) Sent: Wednesday, March 10, 2021 9:24 AM To: keith.e.herring@cop.com Subject: KRU 2G Laterals: Expired Permits Hi Keith, The following two permits to drill have expired under regulation 20 AAC 25.005 (g). The permits have been marked expired in their well history file and in the AOGCC database. • KRU 2G-06AL1 (issued to CPAI February 191h 2019) • KRU 2G-06AL2-01 (issued to CPAI February 191h 2019) Please let me know if you have any questions. Thanks Huev Winston Statistical Technician Alaska Oil and Gas Conservation Commission huph.w'inston_@alaska.gov 907-793-1241 1 Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Friday, March 1, 2019 10:05 AM To: 'Herring, Keith E' Cc: Guhl, Meredith D (DOA); Boyer, David L (DOA); Kair, Michael N (DOA) Subject: RE: Issue with APIs for recent KRU 2G-06 wells Keith, I made a mistake when assigning API numbers to CPAI's planned KRU 2G-06A redrill and its laterals that must be corrected. Please accept my apology. To fix this as painlessly as possible: • For consistency with past practices, the API number for KRU 2G-06A must be changed from 50-029-21121-64-00 (wrong API) to 50-029-21121-01-00 (correct API) on all forms and in all databases. To minimize the paperwork chaos that could ensue for the remaining laterals (2G-06AL1, 2G-06AL2, and 2G- 06AL2-01), I propose leaving the API numbers that I assigned to those laterals unchanged and simply not assigning 50-029-21121-64-00 to any lateral. A copy of this email and an explanatory "Note to File" in CPAI's and AOGCC's well history files for 2G-06A and 2G-06AL1 will adequately explain to future users why API number 50-029-21121-64-00 was never assigned. • Please note that all assigned Permit to Drill numbers will remain unchanged. All production from laterals 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 must be reported against redrilled well KRU 2G-06A, API number 50-029-21121-01-00, Permit to Drill number 219-019. Please forward this email to anyone affected by this change, and please extend my apologies for this mistake. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) 907-793-1224 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.daviesLDalaska.gov. From: Guhl, Meredith D (DOA) Sent: Wednesday, February 27, 2019 2:54 PM To: Davies, Stephen F (DOA) <stev .davifs iai .goy>; Boyer, David L (DOA) <david.boyer2 a alaska. ov> Subject: Issue with APIs for recent KRU 2G-06 wells Hi Steve and Dave, We've got an API number issue with recently permitted KRU 25-06 wells. API WELL # I PTD # I Conf I MITPermit# I O er Name I Well Name I Status I Status DI 50-029-21121-00-00 1840820 No CONOCOPHILLIPS ALASKA, INC. KUPARUK RIV UNIT 2G-06 1-OIL 24-Se - 50-029-21121-60-00 2181120 No CONOCOPHILLIPS ALASKA, INC. KUPARUK RIV UNIT 2G-061_1 50-029-21121-61-00 2181130 No CONOCOPHILLIPS ALASKA, INC. KUPARUK RIV UNIT 2G-061-1-01 CANC 11-Feb- 50-029-21121-62-00 2181140 No CONOCOPHILLIPS ALASKA, INC. KUPARUK RIV UNIT 2G-061-1-02 CANC I 11-Feb- 50-029-21121-63-00 218,1150 No CONOCOPHILLIPS ALASKA, INC. KUPARUK RIV UNIT 2G-061-1-03 CANC 11-Feb- 50-029-21121-64-00 2190190 No CONOCOPHILLIPS ALASKA, INC. KUPARUK RIV UNIT 2G-06A 50-029-21121-65-00 2190200 No CONOCOPHILLIPS ALASKA, INC. KUPARUK RIV UNIT 2G-06AL1 50-029-21121-66-00 2190210 No CONOCOPHILLIPS ALASKA, INC. KUPARUK RIV UNIT 2G-06AL2 50-029-21121-67-00 2190220 No CONOCOPHILLIPS ALASKA, INC. KUPARUK RIV UNIT 2G-06AL2-01 The highlighted well should have an API of 50-029-21121-01-00 as it is a sidetrack from the mainbore, and then the API needs to be adjusted for the laterals following. Unless we've changed our numbering conventions? Thanks, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. THE STATE 'ALASKA GOVERNOR MIKE DUNLEAVY Kai Starck CTD Director ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2G-06AL1 ConocoPhillips Alaska, Inc. Permit to Drill Number: 219-020 Surface Location: 547' FSL, 236' FWL, SEC. 32, TI 1N, R9E, UM Bottomhole Location: 5221' FNL, 1312' FEL, SEC. 29, T11N, R9E, UM Dear Mr. Starck: 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 re -drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 219-019, API No. 50-029-21121-64- 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. hi addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Daniel T. Seamount, Jr. Chair DATED this day of February, 2019. "1Lal i1k.# = � STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMIS.SiuN FEB 11 2019 PERMIT TO DRILL ?n AAc 95 nn.s 1 a. Type of Work: Drill ❑ Lateral FZI 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 ^ Single Well ❑ Bond No. 5952180 ^ 11. Well Name and Number: KRU 2G-06AL1 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 9750' TVD: 5999' 12. Field/Pool(s): Kuparuk River Field / Kuparuk River Oil Pool ' 4a. Location of Well (Governmental Section): Surface: 547' FSL, 236' FWL, Sec 32, T11 N, R9E, UM Top of Productive Horizon: 1238' FNL, 11 75'FEL, Sec 32, T11 N, R9E, UM Total Depth: 5221' FNL, 1312' FEL, Sec 29, T1IN, R9E, UM 7. Property Designation: ADL 25656 8. DNR Approval Number: LONS 82-180 13. Approximate Spud Date: 2/26/2019 9. Acres in Propertv: 2491 14. Distance to Nearest Propertv: 23075' 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 508930 • y- 5944135 Zone- 4 10. KB Elevation above MSL (ft): 140' • GL / BF Elevation above MSL (ft): 104' 15. Distance to Nearest Well Open to Same Pool: 525', 2F-20 16. Deviated wells: Kickoff depth: 8400' feet Maximum Hole Angle: 99 degrees 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Downhole: 4,908 Surface: 4,320 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 1450' 8300' 6053' 9750' 5999' Slotted 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 8485' Total Depth TVD (ft): 6253' Plugs (measured): N/A Effect. Depth MD (ft): 8368' Effect. Depth TVD (ft): 6158' Junk (measured): 8136' Casing Length Size Cement Volume MD TVD Conductor/Structural 72' 16" 202 sx Cold Set II 110, 110, Surface 3097' 9-5/8" 1035 sx PF E, 250 sx PF C 3134' 2774' Production 8413' 7" 575 sx Class G, 250 sx PF C 8449' 6224' Perforation Depth MD (ft): 8188' - 8198' 8216' - 8246' Perforation Depth TVD (ft): 6013' - 6021' 6035' - 6060' Hydraulic Fracture planned? Yes ❑ No Q . 20. Attachments: Property Plat ❑ BOP Sketch Diverter Sketch Drilling Program ❑ Seabed Report Time v. Depth Plot Shallow Hazard Analysis 8 Drilling Fluid Program ❑ 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Keith Herring Authorized Name: Kai Starck Contact Email: Keith. E. Herrir'�CO .COITI Authorized Title: CTD Director Contact Phone: 907-263-4321 Authorized Signature: Date: - - Commission Use Only Permit to Drill 77 // ,, Number: �� vt/ 150-0-747.-7l�2 API Number: Permit ��75 �v Approval Date: ]requirements. See cover letter for other Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Q Other: BAP 7-`57- fo 4-e 00 /-�) S � ` Samples req'd: Yes ❑, No af Mud log req'd: Yes ❑ No 2 �✓lrl lv/G_/-�/'�V-e,V? 1l�'�t,574- fa 25_00P5iS H2S measures: Yes ❑v No❑/ Directional svy req'd: Yes NoEl/ VGLI / a hC fo a O 4 A C a 5, b J5 �,js(7acing exception req'd: Yes ❑ No d Inclination -only svy req'd: Yes ❑ No � fo %5 Post initial injection MIT req'd: Yes El No0'" 9rCih �'cci fo �t//oru tti� c�lG.�oF�' Doi»f no,Yii C"l6nJc tl�� APPROVED BY /� Q Approved by: COMMISSIONER THE COMMISSION Date: GJ7 J/ S`bmit Foreandi 10-401 Revised 5/2017 This per i i valid foroval per 20 AAC 25.005( z/ ttachments in Duplicate r A X / &Rt1-Gn1tNaAfLPp ConocoPhilli s p Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 08, 2018 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 sundry application to set a mechanical whipstock and cement squeeze the A -sand perforations in the KRU well 2G-06 (PTD# 184-082). ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill four laterals out of the KRU 2G-06 (PTD #184-082) using the coiled tubing drilling rig, Nabors CDR3-AC. , Pre -rig operations are scheduled to begin in late February with CTD operations following in early March 2019. The objective will be to drill four laterals, KRU 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 targeting the Kuparuk A -sand interval. ConocoPhillips requests a variance to the requirements of 20 AAC 25.112(c) for the alternate plugging - - method to isolate the 2G-06 A -sand perforations utilizing an A -sand cement squeeze via service coil. To account for geologic 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 the sundry application are the following documents: - 10-403 Sundry Application for KRU 2G-06 - Operations Summary in support of the 10-403 sundry application - Current Wellbore Schematic - Proposed CTD Schematic Attached to the permit to drill applications are the following documents: - Permit to Drill Application Forms (10-401) for 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 - Detailed Summary of Operations - Directional Plans for 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 - Current Wellbore Schematic - Proposed CTD Schematic If you have any questions or require additional information, please contact me at 907-263-4321. Sincerely, Keith Herring Coiled Tubing Drilling Engineer ConocoPhillips Alaska Kuparuk CTD Laterals 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 Application for Permit to Drill Document 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))................................................................................................................... 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2))..................................................................................................................................................2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 2 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7))..................................................................................................................................................3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9))..................................................................................................................................................4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4 11. Seabed Condition Analysis............................................................................................................ 4 (Requirements of 20 AAC 25.005(c)(11))................................. --........ ................ .............................. ..................................................... 4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 4 13. Proposed Drilling Program.............................................................................................................4 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................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....................................................................... 7 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 7 16. Attachments....................................................................................................................................7 Attachment 1: Directional Plans for 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 laterals....................................7 Attachment 2: Current Well Schematic for 2G-06...........................................................................................................7 Attachment 3: Proposed Well Schematic for 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 laterals......................7 Page 1 of 7 February 08, 2019 PTD Application: 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 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 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01. All laterals will be classified as "Development -Oil' wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 forms for surface and subsurface coordinates of each of the laterals. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR3-AC. BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4,800 psi. Using the maximum formation pressure in the area of 4,908 psi in 213-05 (i.e. 15.5 ppg EMW), the maximum potential surface pressure in 2G-06, assuming a gas gradient of 0.1 psi/ft, would be 4,320 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 2G-06 was measured to be 3,829 psi (12.4 ppg EMW) on 10/13/2018. The maximum downhole pressure in the 2G-06 vicinity is the 213-05 at 4,908 psi or 15.5 ppg EMW on 7/7/2016. 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 2G-06 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 2G-06 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 2G-06 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 February 08, 2019 PTD Application: 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 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 2G-06A 8,400' 9,750' 5,912' 5,887' 2%", 4.7#, L-80, ST-L slotted liner -,aluminum billet on to 2G-06AL1 8,300' 9,750' 5,913' 5,859' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 2G-06AL2 8,400' 9,900, 5,914' 5,898' 2'/", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 2G-06AL2-01 8,006' 9,900, 5,730' 5,873' 2%", 4.7#, L-80, ST-L slotted liner / blank; deployment sleeve on to Existing Casing/Liner Information Category OD Weigh t f Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.5 H-40 Welded Surface 110, Surface 110, 1640 670 Surface 9-5/8" 36 J-55 BTC Surface 3134' Surface 2774' 3520 2020 Production 7" 26 J-55 BTC Surface 8449' Surface 6224' 4980 4320 Tubing 3-1/2" 9.3 L-80 EUE 8rd MOD Surface 8044' Surface 5899' 10,160 10,540 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) Nabors CDR3-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a diverter system is not required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System A diagram of the Nabors CDR3-AC mud system is on file with the Commission. Description of Drilling Fluid System — Window milling operations: Water based Power-Vis milling fluid (8.6 ppg) — Drilling operations: Water based Power -Pro drilling mud (8.6 ppg). This mud weight may not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using --- MPD practices described below. — Completion operations: BHA's will be deployed using standard pressure deployments and the well will be loaded with 12.6 ppg potassium formate completion fluid in order to provide formation over -balance and maintain wellbore stability while running completions. If higher formation pressures are encountered the completion brine will be weighted up with potassium formate. Page 3 of 7 February 08, 2019 PTD Application: 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000-psi rated coiled tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". In the 2G-06 laterals we will target a constant BHP of 12.4 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 2G-06 Window (8,095' MD, 5,939' TVD) Using MPD Pumps On 1.8 b m Pumps Off Formation Pressure 12.4 3829 psi 3829 psi Mud Hydrostatic 8.6 2655 psi 2655 psi Annular friction i.e. ECD, 0.080 si/ft 647 psi 0 psi Mud + ECD Combined no chokepressure) 3302 psi underbalanced —527psi) 2655 psi underbalanced —1174psi) Target BHP at Window 12.4 3830 psi 3830 psi Choke Pressure Required to Maintain Target BHP 528 psi 1175 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 2G-06 is a Kuparuk producer equipped with 3-1/2" tubing and 7" production casing. The CTD sidetrack will utilize four laterals to target the Kuparuk A -sands to the north and south of the existing 2G-06 wellbore. The laterals will reclaim resource from the long term shut in rock producer 2G-06 and provide additional offtake in a high-pressure area. E-line will set a high expansion wedge in the 7" production casing at the planned kick off point at 8095' MD. Service coil will cement the high expansion wedge in the 7" casing and squeeze cement the A -sand perforations. Page 4 of 7 February 08, 2019 PTD Application: 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 CDR3-AC will cut a window in the 2G-06 production casing and drill the 2G-06A sidetrack to a planned TD at 9,750' MD, targeting the A sand to the north. It will be completed with 2-3/8" slotted liner from TD up to 8,400' MD with an aluminum billet for kicking off the 2G-06AL1 lateral. The 2G-06AL1 lateral will drill to a TD of 9,750' MD targeting the A sand to the north. It will be completed with 2-3/8" slotted liner from TD up to 8,300' MD with an aluminum billet for kicking off the 2G-06AL2 lateral. The 2G-06AL2 lateral will drill to TD of 9,900' MD targeting the A sand to the south. It will be completed with 2-3/8" slotted liner from TD up to 8,400' MD with an aluminum billet for kicking off the 2G-06AL2- 01 lateral. The 2G-06AL2-01 lateral will drill to TD of 9,900' MD targeting the A sand to the south. It will be completed with 2-3/8" slotted/blank liner from TD up into the 3-1/2" tubing at 8,006' MD with a deployment sleeve. Pre-CTD Work 1. RU Slickline: Obtain caliper of 7" casing. 2. RU E-line: Set high expansion wedge in 7" casing. 3. RU Service Coil: Cement high expansion wedge and squeeze cement the A -sand perforations. 4. Prep site for Nabors CDR3-AC. Rig Work 1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 2G-06A Sidetrack (A4 sand - North) a. Mill 2.80" window at 8,095' MD. b. Drill 3" bi-center lateral to TD of 9,750' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 8,400' MD. 3. 2G-06AL 1 Lateral (A4 sand - North) a. Kickoff of the aluminum billet at 8,400' MD. b. Drill 3" bi-center lateral to TD of 9,750' MD. c. Run 2%" slotted liner with aluminum billet from TD up to 8,300' MD. 4. 2G-06AL2 Lateral (A4 sand - South) a. Kickoff of the aluminum billet at 8,300' MD. b. Drill 3" bi-center lateral to TD of 9,900' MD. c. Run 2%" slotted liner with aluminum billet from TD up to 8,400' MD. 5. 2G-06AL2-01 Lateral (A4 sand - South) a. Kick off of the aluminum billet at 8,400' MD. b. Drill 3" bi-center lateral to TD of 9,900' MD. c. Run 2%" slotted/blank liner with deployment sleeve from TD up to 8,006' MD. 6. Obtain SBHP, freeze protect, ND BOPE, and RDMO Nabors CDR3-AC. Post -Rig Work 1. Return to production. Page 5 of 7 February 08, 2019 PTD Application: 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slick -line lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slick -line. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment, the steps listed above are observed, only in reverse. Liner Running — 2G-06 CTD laterals will be displaced to an overbalance completion fluid (as detailed in Section 8 "Drilling Fluids Program") prior to running liner. — While running 23/" slotted liner, a joint of 2%" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2'/" rams will provide secondary well control while running 2%" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (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). Page 6 of 7 February 08, 2019 PTD Application: 2G-06A, 2G-06AL1, 2G-06AL2, and 2G-06AL2-01 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) - The Applicant is the only affected owner. - Please see Attachment 1: Directional Plans - Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. - MWD directional, resistivity, and gamma ray will be run over the entire open hole section. - Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 2G-06A 23,075' 2G-06AL1 23,075' ° 2G-06AL2 22,200' 2G-06AL2-01 22,200' - Distance to Nearest Well within Pool Lateral Name Distance Well 2G-06A 525' 2F-20 2G-06AL1 525' - 2F-20 2G-06AL2 1285' 2G-08 2G-06AL2-01 1285' 2G-08 16. Attachments Attachment 1: Directional Plans for 2G-06A, 2G-06AL 1, 2G-06AL2, and 2G-06AL2-01 laterals. Attachment 2: Current Well Schematic for 2G-06. Attachment 3: Proposed Well Schematic for 2G-06A, 2G-06AL 1, 2G-06AL2, and 2G-06AL2-01 laterals. Page 7 of 7 February 08, 2019 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2G Pad 2G-06 2G-06AL1 Plan: 2G-06AL1_wp05 Standard Planning Report 02 November, 2017 BER BA GE comaanv ConocoPhillips Database: EDT Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2G Pad Well: 2G-06 Wellbore: 2G-06AL1 Design: 2G-06A L 1 _wp05 ConocoPhillips Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: BA ER I-UGHES a GE mrnpany Well 2G-06 Mean Sea Level 2G-06 @ 140.00usft (2G-06) ' 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 2G Pad Site Position: Northing: 5,944,015.12 usft Latitude: 70° 15' 29.733 N From: Map Easting: 508,649.96 usft Longitude: 149° 55' 48.314 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.07 ° Well 2G-06 Well Position +NI-S 0.00 usft Northing: 5,944,135.21 usft • Latitude: 70° 15' 30.911 N +E/-W 0.00 usft Easting: 508,929.90 usft Longitude: 149° 55' 40.165 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 2G-06AL1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°l (°) (nT) BGGM2017 2/1/2018 17.14 80.85 57,466 Design Audit Notes: Version: Vertical Section: 2G-06AL1_wp05 Phase: PLAN Tie On Depth: 8,400.01 Depth From (TVD) +N/S +E/-W Direction (usft) (usft) (usft) (I 0.00 0.00 0.00 0.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +El-W Rate Rate Rate TFO (usft) (I (I (usft) (usft) (usft) (°/100ft) (°/100ft) (°/100ft) (°) Target 8,400.00 94.14 29.17 5,912.25 3,496.13 3,857.18 0.00 0.00 0.00 0.00 j 8,470.00 86.86 24.97 5,911.65 3,558.40 3,889.00 12.00 -10.40 -5.99 210.00 8,600.00 92.24 10.32 5,912.67 3,681.90 3,928.29 12.00 4.14 -11.27 290,00 8,700.00 92.19 358.32 5,908.80 3,781.36 3,935.80 12.00 -0.05 -12.01 270.00 8,900.00 98.45 335.03 5,890.01 3,973.73 3,890.45 12.00 3.13 -11.64 286.00 9,075.00 89.28 353.99 5,878.12 4,141.08 3,844.23 12.00 -5.24 10.83 115.00 9,200.00 85.96 339.34 5,883.34 4,262.26 3,815.53 12.00 -2.65 -11.72 257.00 9,425.00 90.91 5.90 5,889.59 4,483.26 3,786.98 12.00 2.20 11.80 80.00 9,750.00 99.47 327.66 5,859.07 4,792.32 3,715.15 12.00 2.63 -11.77 284.00 11/2/2017 4:54:41PM Page 2 COMPASS 5000.14 Build 85 ConocoPhillips Database: EDT Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2G Pad Well: 2G-06 Wellbore: 2G-06AL1 Design: 2G-06A L 1 _wp05 Planned Survey Measured Depth Inclination Azimuth (usft) (a) (I 8,400.00 94.14 29.17 TIPIKOP 8,470.00 86.86 24.97 Start 12 dls 8,500.00 88.10 21.59 8,600.00 92.24 10.32 3 8,700.00 92.19 358.32 4 8,800.00 95.43 346.73 8,900.00 98.45 335.03 5 9,000.00 93.26 345.91 9,075.00 89.28 353.99 6 9,100.00 88.60 351.06 9,200.00 85.96 339.34 7 9,300.00 88.12 351.16 9,400.00 90.35 2.96 9,425.00 90.91 5.90 8 9,500.00 93.07 357.16 9,600.00 95.83 345.45 9,700.00 98.34 333.62 9,750.00 99.47 327.66 Planned TD at 9750.00 ConocoPhillips BAT Planning Report IGHES a GE company Local Co-ordinate Reference: Well 2G-06 TVD Reference: Mean Sea Level MD Reference: 2G-06 @ 140.00usft (2G-06) North Reference: True Survey Calculation Method: Minimum Curvature (( ( 1 tt ` TVD Below v Vertical Dogleg Toolface Map Map System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) I (usft) (usft) (usft) (°/100ft) V) (usft) (usft) 5,912.25 3,496.13 3,857.18 3,496.13 0.00 0,00 5,947,635.56 512,782.54 5,911.65 3,558.40 3,889.00 3,558.40 12.00 -150.00 5,947,697.86 512,814.29 5,912.97 3,585.93 3,900.85 3,585.93 12.00 -70.00 5,947,725.40 512,826.10 5,912.67 3,681.90 3,928.29 3,681.90 12.00 -69.85 5,947,821.39 512,853.43 5,908.80 3,781.36 3,935.80 3,781.36 12.00 -90.00 5,947,920.85 512,860.82 5,902.13 3,880.11 3,922.87 3,880.11 12.00 -74.00 5,948,019.58 512,847.77 5,890.01 3,973.73 3,890.45 3,973.73 12.00 -74.77 5,948,113.15 512,815.25 5,879.78 4,067.33 3,857.30 4,067.33 12.00 115.00 5,948,206.70 512,781.99 5,878.12 4,141.08 3,844.23 4,141.08 12.00 116.11 5,948,280.43 512,768.84 5,878.58 4,165.86 3,840.98 4,165.86 12.00 -103.00 5,948,305.21 512,765.56 5,883.34 4,262.26 3,815.53 4,262.26 12.00 -102.95 5,948,401.57 512,739.99 5,888.52 4,358.67 3,790.17 4,358.67 12.00 80.00 5,948,497.93 512,714.52 5,889.86 4,458.34 3,785.05 4,458.34 12.00 79.39 5,948,597.59 512,709.29 5,889.59 41483.26 3,786.98 4,483.26 12.00 79.23 5,948,622.51 512,711.19 5,886.98 4,558.12 3,788.99 4,558.12 12.00 -76.00 5,948,697.36 512,713.11 5,879.20 4,656.49 3,773.96 4,656.49 12.00 -76.30 5,948,795.70 512,697.96 5,866.82 4,749.29 3,739.36 4,749.29 12.00 -77.22 5,948,888.46 512,663.25 5,859.07 - 4,792.32 3,715.15 4,792.32 12.00 -78.68 5,948,931.46 512,639.00 11/2/2017 4:54:41PM Page 3 COMPASS 5000.14 Build 85 ConocoPhillips Database: EDT Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2G Pad Well: 2G-06 Wellbore: 2G-06AL1 Design: 2G-06AL1_wp05 Targets ConocoPhillips Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2G-06 Mean Sea Level 2G-06 @ 140.00usft (2G-06) True Minimum Curvature BAI-UGHES a GE company Target Name hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) Latitude Longitude 2G-06AL1_T02 0.00 0.00 5,878.00 2,523.801,143,951.19 5,948,015.00 1,652,763.00 70° V 46.980 N 140° 45' 15.574 W plan misses target center by 1140016.08usft at 8700.00usft MD (5908.80 TVD, 3781.36 N, 3935.80 E) Point 2G-06 CTD Polygon Sor 0.00 0.00 0.00 2,064.671,144,019.65 5,947,556.00 1,652,832.00 70° V 42.421 N 140° 45' 15.609 W plan misses target center by 1140100.45usft at 8700.00usft MD (5908.80 TVD, 3781.36 N, 3935.80 E) Polygon Point 1 0.00 0.00 0.00 5,947,556.00 1,652,832.00 Point 2 0.00 -23.24 210.99 5,947,533.01 1,653,043.00 Point 3 0.00 -125.51 434.90 5,947,431.02 1,653,267.01 Point 0.00 -372.62 510.63 5,947,184.02 1,653,343.02 Point 5 0.00 -592.57 448.37 5,946,964.02 1,653,281.03 Point 0.00 -912.56 413.01 5,946,644.02 1,653,246.05 Point 0.00 -1,276.52 348.59 5,946,280.02 1,653,182.07 Point 0.00 -1,760.61 383.04 5,945,796.02 1,653,217.09 Point 0.00 -1,778.06-107.03 5,945,777.99 1,652,727.09 Point 10 0.00 -1,628.01-133.86 5,945,928.00 1,652,700.08 Point 11 0.00 -1,334.96-153.53 5,946,220.99 1,652,680.07 Point 12 0.00 -1,146.96-136.32 5,946,408.99 1,652,697.05 Point 13 0.00 -907.97-111.04 5,946,647.99 1,652,722.05 Point 14 0.00 -699.98 -76.80 5,946,856.00 1,652,756.04 Point 15 0.00 -410.04 -0.47 5,947,146.00 1,652,832.02 Point 16 0.00 -303.94 -78.35 5,947,252.00 1,652,754.02 Point 17 0.00 9.09 -77.00 5,947,565.00 1,652,755.00 Point 18 0.00 0.00 0.00 5,947,556.00 1,652,832.00 2G-06AL1_T04 0.00 0.00 5,859.00 3,183.031,143,813.96 5,948,674.00 1,652,625.00 70' V 53.582 N 140° 45' 16.630 W plan misses target center by 1139878.3lusft at 8700.00usft MD (5908.80 TVD, 3781.36 N, 3935.80 E) Point 2G-06 CTD Polygon Nor 0.00 0.00 0.00 1,864.041,143,687.38 5,947,355.00 1,652,500.00 70° 1' 40.963 N 140° 45' 25.912 W plan misses target center by 1139768.51 usft at 8700.00usft MD (5908.80 TVD, 3781.36 N, 3935.80 E) Polygon Point 1 0.00 0.00 0.00 5,947,355.00 1,652,500.00 Point 0.00 100.88 115.13 5,947,456.01 1,652,615.00 Point 3 0.00 325.88 136.38 5,947,681.01 1,652,635.98 Point 0.00 504.95 86.58 5,947,860.00 1,652,585.97 Point 5 0.00 703.01 52.80 5,948,058.00 1,652,551.96 Point 6 0.00 908.08 8.03 5,948,263.00 1,652,506.95 Point 0.00 1,108.12 -8.74 5,948,463.00 1,652,489.95 Point 8 0.00 1,243.18 -45.59 5,948,598.00 1,652,452.94 Point 0.00 1,441.22 -69.37 5,948,795.99 1,652,428.93 Point 10 0.00 1,336.89 216.54 5,948,692.01 1,652,714.93 Point 11 0.00 1,241.62 448.45 5,948,597.03 1,652,946.93 Point 12 0.00 1,103.58 465.30 5,948,459.02 1,652,963.94 Point 13 0.00 856.56 468.02 5,948,212.03 1,652,966.96 Point 14 0.00 662.49 505.80 5,948,018.02 1,653,004.96 Point 15 0.00 395.38 582.51 5,947,751.03 1,653,081.98 Point 16 0.00 157.36 582.24 5,947,513.03 1,653,081.99 Point 17 0.00 -45.56 486.00 5,947,310.02 1,652,986.01 Point 18 0.00 -186.46 391.83 5,947,169.02 1,652,892.01 Point 19 0.00 -292.32 258.69 5,947,063.02 1,652,759.01 Point20 0.00 0.00 0.00 5,947,355.00 1,652,500.00 2G-06AL1_T03 0.00 0.00 5,889.00 2,874.91 1,143,885.60 5,948,366.00 1,652,697.00 70° 1' 50.485 N 140° 45' 15.924 W plan misses target center by 1139950.16usft at 8700.00usft MD (5908.80 TVD, 3781.36 N, 3935.80 E) Point 2G-06AL1_T01 0.00 0.00 5,911.00 2,137.691,144,009.74 5,947,629.00 1,652,822.00 70° V 43.145 N 140° 45' 15.576 W - Ian misses target center by 1140075.12usft at 8700.00usft MD 5908.80 TVD 3781.36 N 3935.80 E 111212017 4:54:41PM Page 4 COMPASS 5000.14 Build 85 - ConocoPhillips BAT BA_ I(ER ConocoPhillips Planning Report a GE company Database: EDT Alaska Sandbox Local Co-ordinate Reference: Well 2G-06 Company: ConocoPhillips (Alaska) Inc. -Kup2 ND Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2G-06 @ 140.00usft (2G-06) Site: Kuparuk 2G Pad North Reference: True Well: 2G-06 Survey Calculation Method: Minimum Curvature Wellbore: 2G-06AL1 Design: 2G-06AL1_wp05 - Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 9,750.00 5,859.07 2 3/8" — 2.375 3.000 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/S +E/-W (usft) (usft) (usft) (usft) Comment 8,400.00 5,912.25 3,496.13 3,857.18 TIP/KOP 8,470.00 5,911.65 3,558.40 3,889.00 Start 12 dls 8,600.00 5,912.67 3,681.90 3,928.29 3 8,700.00 5,908.80 3,781.36 3,935.80 4 8,900.00 5,890.01 3,973.73 3,890.45 5 9,075.00 5,878.12 4,141.08 3,844.23 6 9,200.00 5,883.34 4,262.26 3,815.53 7 9,425.00 5,889.59 4,483.26 3,786.98 8 9,750.00 5,859.07 4,792.32 3,715.15 Planned TD at 9750.00 11/2/2017 4:54:41PM Page 5 COMPASS 5000.14 Build 85 Baker Hughes INTEQ BA_ �{ER ConocoPhillips Travelling Cylinder Report F1 IGHES BAT GE company Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 2G Pad Site Error. 0.00 usft Reference Well: 2G-06 Well Error: 0.00 usft Reference Wellbore 2G-06AL1 Reference Design: 2G-06AL1_wp05 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 2G-06 2G-06 @ 140.00usft (2G-06) 2G-06 @ 140.00usft (2G-06) True Minimum Curvature 1.00 sigma OAKEDMP2 Offset Datum Reference 2G-06AL1_wp05 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 8,400.00 to 9,750.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,161.00 usft Error Surface: Pedal Curve Survey Tool Program From (usft) 200.00 8,100.00 8,400.00 Casing Points Date 11 /2/2017 To (usft) Survey (Wellbore) Tool Name Description 8,100.00 2G-06 (2G-06) SEEKER MS BHI Seeker multishot 8,400.00 2G-06A_wp03(2G-06A) MWD MWD- Standard 9,750.00 2G-06AL1_wp05(2G-06AL1) MWD MWD- Standard Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 9,750.00 5,999.07 2 3/8" 2-3/8 3 Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) Kuparuk 2F Pad 2F-20 - 2F-20 - 2F-20 Out of range 2F-20 - Plan: 2F-20A - 2F-20A (wp01) Out of range Kuparuk 2G Pad 2G-06 - 2G-06A- 2G-06A_wp03 9,293.39 9,275.00 23.87 1.49 23.64 Pass- Minor 1/10 2G-06 - 2G-06AL2 - 2G-06AL2_wp03 8,403.80 8,425.00 49.00 0.66 48.56 Pass - Minor 1110 2G-06 - 2G-06AL2-01 - 2G-06AL2-01_wp03 8,403.95 8,425.00 48.91 0.69 48.45 Pass - Minor 1/10 Offset Design Kuparuk 2G Pad - 2G-06 - 2G-06A - 2G-06A_wp03 offset Site Error: 0.00 usft Survey Program: 200-SEEKER MS, 8100-MWD Rule Assigned: Minor 1110 Offset Well Error: 0.00 usft Reference Offset Semi Major Axis Measured vertical Measured Vertical Reference Offset Toolface+ Offset Wellbore Centre Casing - Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/S +E/-W Hole Size Centre Distance Deviation (usft) (usft) (usft) (usft) (us") (usft) (1) (usft) (usft) (") (usft) (usft) (usft) 8,424.94 6,051.02 8,425.00 6.050.16 0.04 0.02 -26.01 3,518.56 3,867.98 2-11/16 1.45 0.45 1.12 Pass - Minor 1/10 8,449.53 6,050.90 8,450.00 6,047.50 0.05 0.04 -27.75 3,542.07 3,876.00 2-11/16 5.79 0.49 5.43 Pass - Minor 1/10 8,473.53 5,051.83 8,475.00 6,044.31 0.06 0.06 -29.77 3,566.33 3,881.09 2-11/16 12.92 0.56 12.52 Pass - Minor 1/10 8,498.06 6,052.90 8,500.00 6,040.98 0.07 0.08 -33.40 3,590.88 3,884.34 2-11/16 20.91 0.65 20.46 Pass - Minor 1/10 8,523.23 6,053.54 8,525.00 6,037.85 0.09 0.11 -37.16 3,615.56 3,886.86 2-11/16 28.17 0.75 27.67 Pass- Minor 1110 8,549.02 6,053.73 8.550.00 6,034.92 0.11 0.13 -41.09 3,640.32 3.888.66 2-11/16 34.67 0.85 34.12 Pass - Minor 1/10 8,575.45 6,053.42 8,575.00 6,032.51 0.14 0.16 -45.42 3,665.17 3.889.96 2-11/16 40.03 0.95 39.42 Pass - Minor 1110 8,602.40 6,052.58 8,600.00 6,030.76 0.17 0.18 -50.25 3,690.09 3,890.89 2-11/16 44.05 1.03 43.39 Pass - Minor 1/10 8,629.47 6,051.52 8,625.00 6,029.67 0.21 0.22 -55.38 3,715.06 3,891.44 2-11/16 46.84 1.12 46.11 Pass - Minor 1/10 8,656.81 6,050.46 8,650.00 6,029.23 0.24 0.25 -60.49 3,740.05 3,891.60 2-11/16 48.45 1.20 47.66 Pass - Minor 1/10 8,684.30 6,049.40 8,675.00 6,029.14 0.28 0.29 -65.49 3,765.05 3,891.14 2-11/16 49.23 1.28 48.36 Pass - Minor 1/10 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 111212017 10.15:21AM Page 2 COMPASS 5000.14 Build 85 C J da c YY < 22 `� 4 CLCL Y YNt�v ap. 7Ei3 d�l O a` 3¢ 0 0 C IL i L s a _ eO' V O c 0 6 6 5 5 0 5 0 5 0 0 C7 0 4 �Up N 4. 4: 4 3' o F I ry 3: C7 ry C7 b � N r C7 3( a 2, 2: 2. 2( 1, 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (aygsn OSZ) (+)qjjoN/(-)ulnoS � � _ 11) � mco c CO LO a5 Cl 0 n rn m N p -O F- R �� o y c Q H Cn d V U{ O O C O M O c O C O N N • Cif M I+ONN 11 �oMN >� Ncn co — o rn a i o 0 o O o O O o O o j o m o 0 0 0 0 0 0 0 0 0C, Co CD a' CM L rn�m��aom ~ N Lo NNNN�--N N o ai000000000 F- O cj c-,i c-� r c-� c r-i 0 0 0 C A O C O M M a 0 T O NIR R N Ci- _ W 1� M O �(J O ItLo CO + t[] 00 N MCA C0 00 00 rn Cn oo m ao l� l� i L04 uM Cn�00Ca M a0 c0 CON Q 00 V C A M I `� O C V N M OO r wZ} CA e0 1� O a0 m Q MMMt*�JMd' V C' Vr' J Cn CO CO IqO �N V Oi w a C C� Cl) N C O O 0 0 � M u] O O1N Q N a-- O M _N 601 a00 Qi CA M 00 COM 00 a0 ~ Lo 10 in z 1 f M C A• t O C O CA M M O In m CA Co C O N N Ir � M 10 t [M M N M C) M M M ci cr co v rn � a 10 O <t c ICON V NCn10 �p 001M O>CA CA a0 a0 CiOiO O ('} 0 0 0 O o 0 o O o O O o 0 0 0 0 0 0 0 O D C7 C� CD tCj O � C=> �m OO n v0.. COO O0 G0 a0 C0 a0 CA CA O CA �O C� U�NM V tO Co i�aO [A + :50 100 'S0 00 50 00 5C OC O 5( OC 5( C 0( y 3 50 00 50 )0 50 ]o 50 0 50 o rn � ¢ o e R 49 49, aic b0 48, 47: 47( & 46( 45' - col,Mo Z.._..-_...---- __ -- . _.._. m 45( 44` 44C 435 r 43C 425 420 OZ 1 90- Z------- ------ __ ---- --- 415 410 405 400 395 390 385 _ a 380 f0 l'Itl 0-DZ 375 370 365 N b 360 b 0 354 350 F 345 I 340 335 330, o ry 3251 2 o 3201 O N 0 3151 N ry l• l 3101 0 00 0 00 0 00 0 0 o n. a C (ui/Usn OS) uldoC poi an onil 10 0 0 0 0 0 0 0 0 0 7 I I 1 I 1 �� 4 f r � I � O { I f r O � r � O ,t KUP PROD WELLNAME 2G-06 LLBORE 213-06 COtl000Pl1llIpS Well Attributes Max Angle & MD TO Alaska, Inc. Field Name KUPARUK RIVER UNIT Wellbore APIIUWI 500292112100 Wellbore Status PROD ncl (') 4.60 MD (ftKB) 4'000.00 Act Btm (ftKB) 8.485.0 Comment 12S (pp.) Date Annotation End Date KBGrd (ft) Rig Release Date SSSV: NIPPLE 110 12/19/2017 Last W0; 7/14/2010 36.00 6/18/1984 2G-06, 2!7/20198:25:37 AM Last Tag Vertical schematic (actual) Annotation Depth (ftKB) End Date Wellbore last Mod By Last Tag: RKB 8,031.0 2/6/2019 2G-06 zembaej HANv'ER. 30.1 Last Rev Reason Annotation I End Date Welibore Last Mod By Rev Reason: Pulled Rockscreen & Updated Tag Depth 2/6/2019 2(3-O6 I zembaej Casing Strings Casing Description OD (in) ID (In) Top (ftKB) Set Depth (ftKB) Set Depth (TVD)... WVLen (I... Grade Top Thread CONDUCTOR 16 15.0E 38.0 110.0 110.0 62.58 H-40 Welded Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD)... WtlLen (I... Grade Top Thread SURFACE 9518 9.21 37.2 3,133.9 2,773.7 36.00 J-55 BTC Casing Description PRODUCTION OD(in) 7 ID(in) 6.28 Top (ftKB) 35.9 Set Depth (ftKB) 8,449.1 Set Depth RVD)... 6,223.8 Wt/Len(I... 26.00 Grade J-55 Top Thread BTC CONDUCTOR; 38.0.110.0 Tubing Strings Tubing Description Skiing Ma... ID (in) Top (ftKB) Set Depth (ft.. Set Depth (TVD) (... W[ (Ib/ft) Grade Top Connection TUBING WO 31/2 2.99 30.1 7,969.3 5,841.4 9.30 L-SO EUE8rdABMOD NIPPLE; 524.7 Completion Details Top (TVD) Top Incl Nominal Top (ftKB) (ftKB) C) It.. Des Com ID (in) 30.1 30.1 0.09 HANGER Vetco/Gray Gen II TUBING HANGER 2.938 524.7 524.6 1.18 NIPPLE 3.5" Cameo "DS" Nipple w/ 2.875 profile 2.875 GAS LIFT; 2,951.5 7,956.6 5,831.6 39.63 PBR PER Seal Assembly (sheared) w/ 2' space out STABBED PACKER ASSEMBLY INTO 2.980 Tubing Description Ma... ID (in) Top (ftKB) Set Depth (ft.. Set Depth (TVD) (... Wt (Ila t) Grade Top Connection TUBING PACKER 3 112 2.99 7,968.3 is 8,043.6 5,899.1 9.30 L-80 8RD EUE ASSY Completion Details Top(TVD) Top Ind Nominal SURFACE; 37.2-3,133.9- Top (ftKB) (ftKB) (°) Item Des Com 7,968.3 5,840.71 39.50 PACKER FHL Packer 3.030 8,011.2 5,873.5 39.03 NIPPLE 2.1113" DS Nipple 2.813 GAS LIFT; 4,945.4 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (TVD) Top Incl Top IKB) (ftKB) (°) Des Co. Run Date 10 (in) 8,097.5 5,941.4 37.98 Window in 7" HEW WS failed & fell down hole, leaving window 10/21/201 2.800 casing exposed in 7" casing 8 GAS LIFT: 6250.3 8,132.0 5,968.7 37.54 NS Expansion High NS High Expansion Wedge WS 10121/201 8 0.000 Wedge WS Note: WS slid down -hole. Likely tap at 8136' MD (10123/18) 8, 136.0 5,971.8 37.49 NS High NS High Expansion Wedge WS 10/16/201 0.000 Expansion 8 GAS UFT; 7,246.0 Wedge WS 8, 158.0 5,989.3 37.21 FISH LOWER PACKER FROM OLD COMPLETION, PXX 1/6/2008 0.000 PLUG, & REST OF TUBING DOWN TO WIRELINE RE- ENTRY GUIDE IS IN FILL. TAGGED HARD MUD @ 8158 SLM. GAS LIFT; 7,898.2 Perforations & Slots Shot Den Top (TVD) Bt. (TVD) (shotsttt Top (ftKB) Btm (ftKB) (ftKB) (ftKB) Linked Zone Date I Type Com 8,188.0 8,198.0 6,013.3 6,021.3 A-5, 2G-06 9/24/1988 4.0 IPERF 90 deg. Phasing; 4" PBR; 7,956.E Schlumberger Casi 8,216.0 8,246.0 6,035.7 6,059.9 A4, 2G-06 9/24/1988 4.0 IPERF 90 deg. Phasing; 4" PACKER; 7,968.3 =. Schlumberger Casi Mandrel Inserts St ati NIPPLE; 8,011.2 on N Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) valve Sew Type Latch Type Port Size TRO (in) (psi) Run Run Date Co. 2,951.5 2,655.4 Cameo MMG 1 1/2 GAS LIFT GLV RK 0.188 1,240.0 2/8/2018 9:30 2 4,945.5 3,851.9 Cameo MMG 1 1/2 GAS LIFT GLV RK 0.188 1,220.0 2/8/2018 10:30 3 6,250.3 4,646.2 Cameo MMG 1 1/2 GAS LIFT GLV RK 0.188 1,217.0 2/8/2018 1:00 4 7,246.0 5,310.6 Cameo MMG 1 1/2 GAS LIFT GLV RK 0.188 1,232.0 2/8/2018 9:30 5 7, 898.2 5,786.8 Cameo MMG 1 112 GAS LIFT OV RK 0.250 0.0 2/7/2018 10:30 Notes: General & Safety End Date Annotation NS High Expansion Wedge WS; 1/2/2000 NOTE: WORKOVER 8, 132.0 12/10/2007 NOTE: "MIT TESTING WILL HAVE TO USE DS NIPPLE oQ 8008"" NS High Expansion Wedge WS; 12/10/2007 NOTE: WORKOVER 8,136.0 7/2/2009 NOTE: 5005' = TIGHT SPOT, UNABLE TO WORK 2.6" GAUGE RING PAST 6/27/2009 7/2/2009 NOTE: View Schematic w/ Alaska Schematic9.0 FISH; 8,158.0 IPERF; 8,188.M 198.0- IPERF; 8,216.6$246.0----- PRODUCTION; 35.9$449.1 2 / 2 $ c R 0 � $ 0 a 0 � 9 O 04 ` o � g � » ZD 0 \\\ \(( e= )2/ ©g\ R (\ib 5 ) \ \ / 7 { $ / � & / \ \ \ 7 = / 3 c a \ -- k \ § - } e « k § k § § § § ® @ £ R 5 a § ® _e LO G m (D Cl) w &� q # / \ �� p o= -q r c \{ §-i -T / ) § 0 /ƒ § § § \ ) } § § Cl) / Cl) p I ] 3 \ K e ■ ( § e _0fff & . . . % $ \ kd �� Go / -° n Q� 2§ _ m 8 D §\ \\ /\ /% 0 m $ \ a k6 }/ \ Cl) fc ea P am L) /\ #b m� \j 22 j% \/ \\ e& __ // ®c �� LL� §{ §§ ' �k ea - uo kQ Liz TRANSMITTAL LETTER CHECKLIST WELL NAME: ez�G Z_ PTD: 2/ l , e 2 Development Service _ Exploratory Stratigraphic Test Non -Conventional FIELD: f%'� POOL: L / Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existm* well Permit No. �� f API No. 50-CJZ - Z//Z -_�` e-_Yi (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 ( PIT) 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 1/ Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK RIV UNIT 2G-06AL1--- _ _ Program DEV Well bore seg �/❑ PTD#: 2190200 Company CONOCOPHILLIPS ALASKA, INC._ _ Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j,2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes Entire Well lies within ADLO.025656.- 3 Unique well name and number Yes 4 Well located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100 5 Well located proper distance from drilling unitboundaryYes Kuparuk River Oil_ Pool, governed by Conservation Order No. 432D 6 Well located proper distance from_ other wells Yes Conservation Order No. 432D has no interwell spacing restrictions.. Wellbore will be more than 500' 7 Sufficient acreage available in drilling unit Yes from an external property line where ownership or landownership changes. As proposed, well will 8 If deviated, is wellbore plat included Yes conform to spacing requirements. 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval Yes SFD 2/11/2019 13 Can permit be approved before 15-day_wait Yes 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_ I18 Conductor string_ provided NA- Conductor set in KRU 2G-06 - Engineering 19 Surface casing protects all known_ USDWs NA Surface casing set in KRU 2G-06 20 CMT voladequateto circulate -on conductor & surf csg - NA Surface casing set and fully cemented CMT vol adequate to tie-in long string to surf csg NA �21 22 CMT will cover all known _productive horizons No Productive interval will 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 I26 Adequate wellbore separation proposed - Yes Anti -collision analysis complete; no major risk failure I27 If-diverter required, does it meet regulations_ NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pressure is_4908 psig(15.5 ppg EMW); will drill w/ 8.6 ppg EMW and maintain overbal w/ MPD VTL 2/15/2019 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes - MPSP is 4320 psig; will test BOPs to 4800psig I31 Choke manifold complies w/API_RP-53 (May 84) Yes - - - - - - 132 Work will occur without operation shutdown Yes - 33 Is presence of 112S gas_ probable Yes H2S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA I35 Permit -can be issued w/o hydrogen _s-ulfide measures - - - - _ - _ NO. Wells on 2G-Pad are- H2S--bearing. H2S measures required. Geology 36 Data presented on potential overpressure zones Yes Max. potential res. pressure is 15.5 ppg EMW; expected res. pressure is 12.4 ppg EMW. Well will be Appr Date 37 Seismic analysis of shallow gas zones NA drilled using 8.6 ppg mud, a coiled -tubing rig, and managed pressure drilling technique to control SFD 2/11/2019 38 Seabed condition survey (if off -shore) NA formation pressures and stabilize shale sections with constant BHP of about 12.4 ppg EMW. 39 Contact name/phone for Weekly_ progress reports [exploratory only] - _ - - - - - - NA _ - NOTE: Chance of encountering free. gas while drilling due to gas _injection_ performed in this area. Geologic Engineering Public Commissioner: Date: Commissioney: DateCommissioner Date
