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Home My WebLink About215-029n T 0 z 1�5_-o2-7 Loepp, Victoria T (DOA) From: Eller, 1 Gary <J.Gary.Eller@conocophillips.com> Sent: Wednesday, March 18, 2015 9:38 AM To: Loepp, Victoria T (DOA) Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA); Starck, Kai; Venhaus, Dan E Subject: RE: Change in Completion Configuration, KRU 30-16AL1 (215-029) Victoria — ConocoPhillips just signed a new 10-401 for KRU 30-16B and a 10-403 for the plugging of KRU 30-16A, as outlined below. Those documents should arrive at the AOGCC later today. As you requested, I am furthermore requesting that the names of the subsequent proposed laterals be changed as follows: • 30-16AL1-01 (215-030) will be renamed to 30-16BL1. API number shall remain as 50-029-21769-61. • 30-16AL1-02 (215-031) will be renamed to 30-16BL2. API number shall remain as 50-029-21769-62. Please let me know if there are any questions about this. Thanks for your patience in working through this. -Gary Eller ConocoPhillips Alaska From: Loepp, Victoria T (DOA)[mailto:victoria.loepp@alaska.gov] Sent: Tuesday, March 17, 2015 9:39 AM To: Eller, J Gary Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: [EXTERNAL]RE: Change in Completion Configuration, KRU 30-16AL1 (215-029) Gary, Please see comments in red. Let me know if there is any confusion. Thanx, Victoria Lateral PTD API Name 30-16AL1215- 50-029- 029 21769-60 Proposed Renaming Proposed Proposed API Comments Lateral Name Submit 407 for abandon 30-16A to close out. Email 30-16B 50-029- request for alternate plug placement variance. 21769-02 Resubmit 401 PTD for 30-16B w/out PTD# or API#. Change all 30-16ALl references to 30-1613. 30- 215- 50-029- 30-16BL1 50-029- Email to change name from 30-16AL1-01 to 30-16F 16AL 1-01 030 21769-61 21769-60 ? 30- 215- 50-029- 30-16BL2 50-029- Email to change name from 30-16AL 1-02 to 30-16F 16AL 1-02 031 21769-62 21769-61 ? From: Schwartz, Guy L (DOA) Sent: Tuesday, March 17, 2015 9:24 AM To: Loepp, Victoria T (DOA) Subject: FW: Change in Completion Configuration, KRU 30-16AL1 (215-029) 1 Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226) or (Guy.schwartz@alaska.gov). From: Eller, J Gary [mailto:J.Garv•Eller(cbconocophillips.com] Sent: Monday, March 16, 2015 12:27 PM To: Schwartz, Guy L (DOA) Cc: Venhaus, Dan E; Starck, Kai; Burke, Jason Subject: Change in Completion Configuration, KRU 30-16AL1 (215-029) Guy — As I briefly indicated over the phone, we've had some complications early in the planned CTD lateral from KRU 30- 16A. As the attached proposed schematic of 10-7-14 shows, 30-16AL1 (215-029) has been planned as a sidetrack off of a Starburst packer/whipstock at 7815' MD. The Starburst has a hollow tray, so the Starburst in combination with a packer provides isolation from the 30-16A motherbore during drilling but hydraulic communication can be restored by perforating into the hollow tray post-CTD. All of that has gone awry. The packer is set at the correct depth, but we've been unable to latch the Starburst tray into the packer. We've reached the point where we need to move uphole by setting another whipstock, the top of which will be —7780' MD. Once we sidetrack and run our 3V liner and cement it in place, we'll permanently lose communication to the 30-16A motherbore. I've attached a second schematic that attempts to communicate what the completion will look like now. So we have two issues we need to address: (1) wellbore naming & API numbering since this will now be a sidetrack instead of a lateral, and (2) abandonment of the 30-16A completion. Regarding naming, the table below shows the current approved lateral naming and assigned API numbers as well as ConocoPhillips' recommendation for revised naming. If it is possible to do so, it would be simplest to rename the planned/approved laterals and assign new API numbers. Hopefully that can be accomplished without submitting replacements 10-401's. Approved Drilling Permits Lateral PTD API Name Lateral Name v 30-16AL1 215- 029 30-16AL1- 215- 01 030 30-16AL1- 215- 02 031 50-029-21769- 30-16B 60 50-029-21769- 30-16BL1 61 50-029-21769- 30-16BL2 62 Proposed Renaming Proposed API Comments 50-029-21769-02 Change from lateral to sidetrack 50-029-21769-60 Has same API number as old 30- 16AL1? 50-029-21769-61 Has same API number as old 30- 16AL 1-01 ? Regarding abandonment of the KRU 30-16A completion, there's no way we can meet the plugging requirements of 20 AAC 25.112(c)(1) while still sidetracking at 7780' MD, so a variance will clearly be needed. ConocoPhillips proposes that we accomplish the abandonment of 30-16A following drilling, lining, and cementing the 3%2' hole section in 30-16B. That is, after cementing the 3'/" liner in place, we'll perform a pressure test of the 31/2' liner lap. If cement integrity is adequate around the 3%2" liner lap then that will have effectively isolated 30-16A. If the liner lap fails the integrity test, then 30-16A can be isolated via a liner lap squeeze and/or a liner top packer (post-CTD). Either of these solutions will serve to confine the hydrocarbons to their respective strata, as is intended by 20 AAC 25.112(c)(1). On the attached updated schematic diagram, I have left the original lateral names to minimize confusion (I hope). If you approve of both the renaming and the abandonment plan then I'll issue a new proposed schematic reflecting the revised naming. I realize that this is a lot to throw at you at once, and I apologize for that. Please call to discuss when you have opportunity. J. Gary Eller Wells Engineer ConocoPhillips - Alaska work: 907-263-4172 cell: 907-529-1979 THE STATE °fALASKA GOVERNOR BILL WALKER D.Venhaus CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaskc.gov Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 30-16AL1 ConocoPhillips Alaska, Inc. Permit No: 215-029 Surface Location: 1106' FNL, 2060' FWL, Sec. 22, T13N, R9E, UM Bottomhole Location: 299' FNL, 2438' FEL, Sec. 28, T13N, R9E, UM Dear Mr. Venhaus: Enclosed is the approved application for permit to drill the above referenced service well. The permit is for a new wellbore segment of existing well Permit No. 188-043, API No. 50-029- 21796-01-00. Production should continue to be reported as a function of the original API number stated above. 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, lJ P�y� Cathy P oerster Chair DATED this l day of March, 2015. q (041IVFn STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 FEB 13 2015 1a. Type of Work: 1 In Proposed Well Class: Development -Oil ❑ Service - Wini ❑ Single Zone Q • Drill ❑ - Lateral J Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Redrill ❑ Reentry Exploratory ❑ Service - WAG Service - Disp ❑ 1c. Specify if well is proposed for: Coalbed Gas ❑ Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: ConocoPhillips Alaska, Inc. - 5. Bond: Blanket. HSingle Well Bond No. 59-52-180 - 11. Well Name and Number: KRU 30-16AL1 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 10650' • TVD: 6429' • 12. Field/Pool(s): Kuparuk River Field ' �1L�vQi Kuparuk Oil Pool , 4a. Location of Well (Governmental Section): Surface: 1106' FNL, 2060' FWL, Sec. 22, T13N, R9E, UM Top of Productive Horizon: 1877' FSL, 1080' FEL, Sec. 21, T13N, R9E, UM Total Depth: 299' FNL, 2438' FEL, Sec. 28, T13N, R9E, UM 7. Property Designation (Lease Number): ADL 25513, 25520 8. Land Use Permit: 2554, 2556 13. Approximate Spud Date: 3/1/2015 9. Acres in Property: Y!( -2.5s 14. Distance to Nearest Property: 7100 41b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 525698 y- 6021714 Zone- 4' 10. KB Elevation above MSL: 59 feet ` GL Elevation above MSL 24 feet 15. Distance to Nearest Well Open to Same Pool: 30-16 , 728 16. Deviated wells: Kickoff depth: 7815 ft. Maximum Hole Angle: 101' deg 17. Maximum Anticipated Pressures in psig (see 20 AAC 25,035) Downhole: 5300 psig • Surface: 4651 psig - 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks (including stage data) Hole Casing Weight Grade Coupling Length MD TVD MD TVD 4" 3.5" 9.2# L-80 Hydril 511 1000, 7815' 6461' 8815' 6495' solid liner 2g S 3" 2.375" 4.7# L-80 ST-L 1725' 8925' 6478' 10650, 6429' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 8351' Total Depth TVD (ft): 6901' Plugs (measured) none Effective Depth MD (ft): 8115 Effective Depth TVD (ft): 6709' Junk (measured) none Casing Length Size Cement Volume MD TVD Conductor/Structural 79' 16" 175 sx AS 1 115' 115' Surface 2340' 9.625" 900 sx AS 111, 300 sx AS II, 2375' 2215' 100 sx AS I Liner 8168' 7" 700 sx TLW, 300 sx Class G, 175 sx 8201' 6778' Liner 238' 4.5" liner 7945' 6571' Perforation Depth MD (ft): ]Perforation 7794-7804, 7838-7848, 7850-7860, 7869-7889, 7908-7928 Depth TVD (ft): 6444-6452, 6480-6488, 6489-6498, 6505-6522, 6537-6553 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program ✓ Time v. Depth Plot F1 Shallow Hazard Analysis El Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑ 20 AAC 25.050 requirements Q 21. Verbal Approval: Commission Representative: Date: 22. 1 hereby certify that the foregoing is true and correct. Contact Jason Burke @ 265-6097 Email Jason. urke co .com Printed Name - D. Verlhaus Title CTD Engineering Supervisor - o Signature ��LZ './�`G 'L'�'—'" Phone: 263-4372 Date Z — 1 t S Commission Use Only Permit to Drill Number: ' G 15— �� API Number: 50- Q'101 — �' I (V _ 6� Permit Approval �/ Date: ( n /n See cover letter for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coal ed methane,✓gas hydrates, or gas contained in shales: Other: Jn On f L - -/v -f 16 0 PS / Samples req'd: Yes ❑ No [� Mud log req'd: Yes❑ No ©' fJr n v/c yp 1'C vCvi %15f� 25ZO62S measures: Yes [_4 No ❑ Directional svy req'd: Yes ff No❑ S fli fi� (✓i th 5 5 �d /✓, i TrA Spacing exception req'd: Yes ❑ No 9 Inclination -only svy req'd: Yes ❑ No [� r`r� d f �'t � 5 fa 1✓- i f, �� d �'r�f'c c f� a„ APPROVED BY THE / Approved by:TAA COMMISSIONER., ; 1 C M IS l0 Date: 3^IO _/ Form 10-461 (Re ised 10/2012) ' This permit is valid or 4Aft7t ftftj approval (20 AA 25_ 09 (y YAk� ConocoPhilli s p Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 11, 2015 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: RECEIVED FEB 13 2015 A0GCG ConocoPhillips Alaska, Inc. hereby submits an application for a permit to drill a lateral from the existing well bore on KRU 30-16A using the coiled tubing drilling rig, Nabors CDR2-AC. ✓ The work is scheduled to begin on March 1, 2015. The CTD objective will be to drill 3 laterals (30-16AL1, L1-01 & L1-02), targeting the Al, A2 & A3 sands.✓This well will be classified as an injection well. Attached to this application are the following documents: Permit to Drill Application Form 10-401 for 30-16AL1, L1-01 & L1-02 Detailed Summary of Operations Directional Plans — Current Schematic Proposed Schematic If you have any questions or require additional information please contact me at 907-265-6097. Sincerely, ason Burke Coiled Tubing Drilling Engineer 907-231-4568 Kuparuk CTD Laterals NABORSA1ASXA 30-16AL17 L1-01 & L1-02 C , Application for Permit to Drill Document ZRC 1. Well Name and Classification...........................................................................................................2 (Requirements of 20 AAC 25.005(t) and 20 AAC 25.005(b))...................................................................................................................... 2 2. Location Summary .............................................................................................................................2 (Requirements of 20 AAC 25.005(c)(2))......................................................................................................................................................2 3. Blowout Prevention Equipment Information...................................................................................2 (Requirements of 20 AAC 25.005(c)(3)).....................................................................................................................................................2 4. Drilling Hazards Information and Reservoir Pressure....................................................................2 (Requirements of 20 AAC 25.005(c)(4)).....................................................................................................................................................2 5. Procedure for Conducting Formation Integrity tests.....................................................................2 (Requirements of 20 AAC 25.005(c)(5))......................................................................................................................................................2 6. Casing and Cementing Program......................................................................................................3 (Requirements of 20 AAC 25.005(c)(6))......................................................................................................................................................3 7. Diverter System Information.............................................................................................................3 (Requirements of 20 AAC 25.005(c)(7))......................................................................................................................................................3 8. Drilling Fluids Program.....................................................................................................................3 (Requirements of 20 AAC 25.005(c)(8))......................................................................................................................................................3 9. Abnormally Pressured Formation Information...............................................................................4 (Requirements of 20 AAC 25.005(c)(9))......................................................................................................................................................4 10. Seismic Analysis................................................................................................................................4 (Requirements of 20 AAC 25.005(c)(10))....................................................................................................................................................4 11. Seabed Condition Analysis...............................................................................................................4 (Requirements of 20 AAC 25.005(c)(11))....................................................................................................................................................4 12. Evidence of Bonding.........................................................................................................................4 (Requirements of 20 AAC 25.005(c)(12))....................................................................................................................................................4 13. Proposed Drilling Program...............................................................................................................4 (Requirements of 20 AAC 25.005(c)(13))....................................................................................................................................................4 Summaryof Operations.................................................................................................................................................. 5 PressureDeployment of BHA.......................................................................................................................................... 6 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.......................................................................................................................................8 Attachment 1: Directional Plans for 30-16AL1, L1-01 & L1-02...................................................................................... 8 Attachment 2: Current Well Schematic for 30-16A........................................................................................................ 8 Attachment 3: Proposed Well Schematic for 30-16AL1, L1-01 & L1-02........................................................................ 8 Page 1 of 8 J R I G I N A L 2/11/2015 PTD Application: 30-16AL1, L1-01 & L1-02 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) The proposed laterals described in this document 30-16AL1, L1-01 & L1-02. This lateral will be classified as "Service — WAG Injection" well. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) This lateral will target the Al, A2 & A3 sand packages in the Kuparuk reservoir. See the attached 10-401 form for surface and subsurface coordinates of the 30-16AL1, L1-01 & L1-02. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR2-AC. BOP equipment is as required per 20 AAC 25.036, for thru-tubing drilling operations. 4�6(',Ps < — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 500(fpsi. Using the maximum formation pressure in the area of 5300'psi in the 30-10, the maximum'potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 4646 psi. See the "Drilling Hazards Information and Reservoir Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2500 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)) A static bottom hole pressure of 30-16A in June 2013 indicated a reservoir pressure of 4095 psi or 12.1 ppg equivalent mud weight. The recent work over done on this well was done with a 12.2 ppg NaBr. The maximum down hole pressure in the 30-16A pattern is at 30-10 with 5300 psi. It is not expected that reservoir pressure as high as 30-10 will be encountered while drilling the 30-16AL1, L1-01 & L1-02 because we are drilling away from the 30-10 and the two wells are separated by 2 separate faults. Using the 30-10 pressure as the maximum possible, the maximum possible surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 4651 psi. ✓ Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) No specific gas zones will be drilled; gas injection has been performed on the 30 pad, so cuttings will be monitored for entrained gas. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) The largest, expected risk of hole problems in the 30-16A laterals will be drilling into a highly faulted zone directly outside of the mother bore. Managed pressure drilling will be used to reduce this risk. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) N/A for this thru-tubing drilling operation. According to 20 AAC 25.030(f), thru-tubing drilling operations need not perform additional formation integrity tests. Page 2 of 8 JRIGINAL 2/11 /2015 PTD Application: 30-16AL1, L1-01 & L1-02 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Lateral Liner Top Liner Btm Liner Top Liner Btm Liner Details Name MD MD TVDSS TVDSS 3 1/", 9.2#, L-80, Hydril 511 solid 30-16AL1 7815' 8815' 6461' 6495' liner; cemented in place with a 6' (first stage) seal bore deployment sleeve on top. 30-16ALl 23/", 4.7#, L-80, ST-L slotted liner; (second 8925' 10650' 6478' 6429' with an aluminum billet on top. stage) 30-16ALl-01 8885' 10650' 6486' 6413' 2%", 4.7#, L-80, ST-L slotted liner; with an aluminum billet on top. 2%", 4.7#, L-80, ST-L slotted liner; 30-16ALl-02 7805' 10650' 6449' 6462' with a shorty deployment sleeve on top. Existing Casing/Liner Information Category OD Weight Grade Conn. Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.5 H-40 Welded 36' 115' 0' 115' 1640 630 Surface 9-5/8" 36 J-55 BTC 35' 2375' 0' 2214' 3520 2020 Casing 7" 26 L-80 TCII 35' 1056' 0' 1056' 7240 5410 Casing 7" 26 J-55 BTC 1800' 8201' 1756' 6778' 4980 4330 Liner 4'/2" 11.6 L-80 EUE 7707' 7945' 6309' 6448' 7780 6360 Tubing 4'/2" 12.6 L-80 IBT-Mod 35' 7707' 0' 6309' 8430 7500 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) N/A for this thru-tubing drilling operation. Nabors CDR2-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 Diagram of Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System — Window milling operations: Chloride -based Flo -Pro mud (10.0 ppg) — Drilling operations: Chloride -based Flo -Pro mud (10.0 ppg). This mud weight will not hydrostatically overbalance the reservoir pressure. — Completion operations: BHA's will be deployed using standard pressure deployments and the well will be loaded with 12.5 ppg K-Formate completion fluid in order to provide formation over -balance while running completions. Page 3 of 8 2/11/2015 ORIGINAL PTD Application: 30-16AL1, L1-01 & L1-02 - Kill Weight fluid: Two wellbores of^kill weight fluid will be stored at a central location in the Kuparuk field and accessible for trucking to the rig during CTD operations. Managed Pressure Drilling Practice ' Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole formation throughout the coiled tubing drilling (CTD) process. Maintaining a constant BHP promotes wellbore stability, particularly in shale sections, while at the same time providing an overbalance on the reservoir. Through experience with drilling CTD laterals in the Kuparuk sands, 11.8 ppg has been identified as the minimum EMW to ensure stability of shale sections. Since this well is proposed as an infield development candidate in an actively water flooded field, expected reservoir pressures can be difficult to estimate. In this case, however, a constant BHP of 12.5 ppg will be initially targeted at the window based on the recent static bottom -hole pressure and the fault blocks being drilled into. The constant BHP target will be adjusted to maintain overbalanced conditions if increased reservoir pressure is encountered during drilling. The constant BHP target will be maintained utilizing the surface choke. 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 30-16A Window (7815' MD, 6461' TVD) Usinq MPD Pumps On (1.5 bpm) Pumps Off A -sand Formation Pressure 12.1 ppg) 4066 psi 4066 psi Mud Hydrostatic 10.0 3360 psi 3360 psi Annular friction (i.e. ECD, 0.050 si/ft) 391 psi 0 psi Mud + ECD Combined 3751 psi 3360 psi (no choke pressure) (underbalanced (underbalanced -315psi) -y706psi) Target BHP at Window (12.5 ) 4200 psi 4200 psi Choke Pressure Required to Maintain 449 psi 840 psi Target BHP 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 not for an exploratory or stratigraphic test 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)) Page 4 of 8 'RIGINAL 2/12/2015 PTD Application: 30-16AL1, L1-01 & L1-02 Summary of Operations Background Well 30-16A is a Kuparuk A -sand service well equipped with 4'/2" tubing and a 4'/z" liner. Three laterals will be drilled from the mother bore in order to provide injection support to the area. A mechanical whip -stock will be placed in the 4 '/2" liner at the planned kickoff point of 7815' MD. A protection hole (4.125") will be drilled from the mother bore for 1000', then 3 %2" tubing will be cemented in place. From there we will pick up 3" tools and drill the AL to a depth of 10650' in the A2 sand. We will run 2-3/8" slotted liner with an aluminum billet back up to 8925'. We will kick off the AL1-01 and drill to a depth of 10650' in the A3 sand. We will run 2-3/8" slotted liner with an aluminum billet back up to 8885'. We will kick off the AL1-02 and drill to a depth of 10650' in the Al sand. We will run 2-3/8" slotted liner with 6' deployment sleeve back up to 7815'. Pre-CTD Work • Coil: Perform FCO of old mud left over from RWO • E-line: Perform jewelry log from 7900' — 7550' MD. Perforate the A sand from 7908`— 7928`, 7869`- 7889`& 7838`— 7860`MD. • Pump: Perform breakdown at 2 BPM. • Slick -line: Run a dummy whip -stock down to 7830' MD, and obtain a SBHP • E-line: Set a 4%2" starburst packer -whip -stock at 7815' MD and 0° HS Rig Work 1. MIRU Nabors CDR2-AC rig using 2%" coil tubing. NU 7-1/16" BOPE, test. 2. 30-16AL1 Lateral (A2 sand - Southwest) i. Mill 3.80" window at 7815' MD ii. Drill 3.74" x 4.13" bi-center lateral to TD of 8815' MD iii. Run 3 'h" solid liner and cement in place iv. Swap over to 2" CT v. Drill 2.74" x 3.00" bi-center lateral to TD of 10650' MD vi. Run 2%" slotted liner with an aluminum billet from TD up to 8925' MD 3. 30-16AL1-01 Lateral (A3 sand - Southwest) i. Kick off the billet at 8925' ii. Drill 2.74" x 3.00" bi-center lateral to TD of 10650' MD iii. Run 2%" slotted liner with an aluminum billet from TD up to 8885' MD 4. 30-16AL1-02 Lateral (A3 sand - Southwest) i. Kick off the billet at 8885' ii. Drill 2.74" x 3.00" bi-center lateral to TD of 10650' MD iii. Run 2%" slotted liner with 6' deployment sleeve from TD up to 7805' MD Page 5 of 8 2/11/2015 ORIGINAL PTD Application: 30-16AL1, L1-01 & L1-02 5. Freeze protect the well. Set BPV, ND BOPE. RDMO Nabors CRD2-AC. Post -Rig Work Pull BPV Obtain static BHP. MIRU CT and N2 lift well for flow back (less than 30 days) Return to operations Pressure Deployment of BHA The planned bottomhole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree, so we will use the standard pressure deployment process. 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 slickline. — 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 — All the laterals will be displaced to an overbalancing fluid (12.5 ppg K-Formate) prior to running liner. See the "Drilling Fluids" section for more details. — While running 2%" 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 23/" 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 (1R-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 8 ORIGINAL 2/11/2015 PTD Application: 30-16AL1, L1-01 & L1-02 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 Plan — 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 openhole section. — Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 30-16AL1 7100' 30-16AL1-01 7100' 30-16AL1-02 7100' — Distance to Nearest Well within Pool (measured to offset well) Lateral Name Distance Well 30-16AL1 728' 30-16 30-16AL1-01 1253' 3N-13 30-16AL1-02 1253' 3N-13 16. Quarter Mile Injection Review (for injection wells only) (Requirements of 20 AAC 25.402) 30-16AL1 is within %-mile of the 30-16 well 30-16AL1, L1-01 & L1-02 is within %-mile of the 3N-13 well 30-16A (mother bore) Injector • Recently worked over and new 7" 26# casing was run from 1056' to surface and cemented in place with 15 bbl G neat cement • Classified as a "Normal Well" • C-sand perforations (cemented): 7794'-7804' MD • A -sand perforations: A1: 7908'— 7928', A2: 7869'— 7889'& A3: 7838'— 7860'MD • Packer is located at 7687' and 4'/z" liner below is cemented in place • MetalSkin patch was installed during RWO from 1015— 1128' and pressure tested to 3500 psi • The cement bond log shows adequate cement as per original injection order. The proposed kick-off point for the CTD sidetrack is in the A -sand perfs and should not compromise existing conformance. 30-16 (abandoned well bore), —728' away from AL1 lateral to south • 9-5/8" casing was cemented down to 2375', 900 sks ASIII @ 12.1 ppg and 300 sks ASH @ 15.2 ppg • Set a balanced cement plug of 183 sks 15.8 ppg "G" cement from TD of 7980' — 7680' MD • Set a balanced cement plug of 194 sks 16.5 ppg "G" cement from 5195' — 4900' MD • Well was sidetracked in 1988 from 5100' MD. 3N-13 (injector), —1253' away from 30-16AL1, L1-01 & L1-02 lateral to southwest • The 3N-13 is currently injecting into the Kuparuk A&C-sand intervals. • Recently received RWO to fix communication problem, original waiver cancelled r • Completed with 7", 26#, J-55 casing • C-sand perforations: C1: 7485'-7505' MD • A -sand perforations: A3: 7557'-7571' MD, A2: 7580'-7607' MD & A1: 7621'-7654' MD • Packers at 7333', and 7253' MD, for a C-sand Straddle • Classified as a "Normal Well" and passed the last MIT -IA on 9/08/13 • The cement bond log shows adequate cement as per original injection order Page 7 of 8 ORIGINAL 2/11/2015 PTD Application: 30-16AL1, L1-01 & L1-02 17. Attachments Attachment 1: Directional Plans for 30-16AL1, L1-01 & L1-02 Attachment 2: Current Well Schematic for 30-16A Attachment 3: Proposed Well Schematic for 30-16AL1, L1-01 & L1-02 Page 8 of 8 2/11/2015 ORIGINAL v �4 N H U O Q L a cfl 1 O y0 C N � a) U U co co Q a 2 M 00 Y C cm c o co v co c) ro C) Q.O E a) co U 0 CA co Q C ~ L m Q i coo�! L cn O 00 c QX= co s 75 a� ca N Z c m a Cn O co a) C _ J CV (V CV as m �•�. � (V X � Lo V V p p Q c p N � O Q w g N in Q 00 Cl) V N tD (O @ tD W m N l0 d _ O0 O oUa v —Ua n r� N 1 i7 77 +�u•'ci:L21•uu IT, :tiiSyYa{+;•�s::�;`'�'"`tY't:%ti::cr.C:Y-''<r,'�;'G`,r:-Y'^::OY.r;?:. ;Y-:ir. .. u�- a;•.rr:,;•�:4:•s iI:.L'.;n'Ciuryr4''r:',:'uY� uo o-000 0 O N O O bo N In C) D 0 C) C) Qa0 -per Ncco coO ln� h Oo n•hhh' 04 =� �2 �mo m;t Q� mzob)co (oN cO c0 ui LOM =r-ooco0 Nh O`Q ycM0(D0 Nh 1- u)2 OION hhhhh Uh d Qhh h ORIGINAL g il f ~ co 10 \ ( § $ L cCL 0 � �\ — \ /cl>{ ( $ 2 # §co / \ ( ƒ - . co c>co to -oo IL2 TOA to w �o _ V § \ 0 f3 \ / 0. z ) / ƒ _ul z J RIGINAL � I WGi1I ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 30-16 Company: ConocoPhillips(Alaska) Inc. NAD83-NAD27 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-16A @ 59.00usft (30-16A) Site: Kuparuk 30 Pad North Reference: True Well: 30-16 Survey Calculation Method: Minimum Curvature Wellbore: 30-16ALl Design: 30-16AL1 _wp07 Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk 30 Pad Site Position: Northing: 6,022,094.67 usft Latitude: 70' 28' 17.333 N From: Map Easting: 525,478.25 usft Longitude: 149' 47' 30.897 W Position Uncertainty: 0.00 usft Slot Radius: 13.200 in Grid Convergence: 0.20 ° Well 30-16 Well Position +N/-S 0.00 usft Northing: 6,021,714.15 usft Latitude: 70' 28' 13.583 N +E/-W 0.00 usft Easting: 525,698.17 usft Longitude: 149° 47' 24.470 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 30-16ALl Magnetics Model Name Sample Date Declination Dip Angle Field Strength (I V) (nT) BGGM2014 2/1/2015 19.01 81.01 57,582 Design 30-16AL1_wp07 Audit Notes: Version: Phase: PLAN Tie On Depth: 7,800.00 Vertical Section: Depth From (TVD) +NI-S +E/-W Direction (usft) (usft) (usft) V) 0.00 0.00 0.00 225.12 112312015 12: 26:23PM Page 2 ORIGINAL COMPASS 5000.1 Build 61 //.FAI ConocoPhillips Planning Report BAKER Alaska HUGFIES Database: EDM Alaska Sandbox Company: ConocoPhillips(Alaska) Inc. NAD83-NAD27 Project: Kuparuk River Unit Site: Kuparuk 30 Pad Well: 30-16 Wellbore: 30-16AL1 Design: 30-16AL1_wp07 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 30-16 Mean Sea Level 30-16A @ 59.00usft (30-16A) True Minimum Curvature Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E1-W Rate Rate Rate TFO (usft) V) V) (usft) (usft) (usft) (°/100ft) (°1100ft) (°/100ft) (1) Target 7,800.00 35.62 245.40 6,390.21 -2,293.24 -3,127.86 0.00 0.00 0.00 0.00 7,815.00 35.55 245.34 6,402.40 -2,296.87 -3,135.80 0.52 -0.47 -0.40 -153.52 7,840.00 40.05 245.34 6,422.15 -2,303.26 -3,149.72 18.00 18.00 0.00 0.00 7,992.71 93.50 245.34 6,480.22 -2,359.71 -3,272.69 35.00 35.00 0.00 0.00 8,192.71 92.19 259.30 6,470.24 -2,420.21 -3,462.54 7.00 -0.66 6.98 95.00 8,412.71 90.52 243.98 6,465.01 -2,489.28 -3,670.65 7.00 -0.76 -6.96 264.00 8,562.71 93.04 233.79 6,460.34 -2,566.64 -3,798.83 7.00 1.68 -6.80 284.00 8,712.71 96.57 223.86 6,447.75 -2,664.89 -3,911.20 7.00 2.35 -6.62 290.00 8,862.71 100.89 214.18 6,424.94 -2,779.86 -4,004.46 7.00 2.88 -6.46 295.00 9,012.71 90.89 210.95 6,409.55 -2,905.46 -4,084.62 7.00 -6.67 -2.15 198.00 9,412.71 90.04 182.96 6,406.23 -3,284.27 -4,200.10 7.00 -0.21 -7.00 268.40 9,522.71 88.97 175.33 6,407.18 -3,394.17 -4,198.46 7.00 -0.97 -6.93 262.00 9,972.71 90.01 206.82 6,411.30 -3,830.22 -4,283.84 7.00 0.23 7.00 88.30 10,222.71 95.63 190.22 6,398.92 -4,066.04 -4,362.92 7.00 2.25 -6.64 289.00 10,372.71 91.97 200.08 6,388.96 -4,210.29 -4,402.01 7.00 -2.44 6.58 110.00 10,472.71 94.35 193.49 6,383.45 -4,305.83 -4,430.83 7.00 2.38 -6.59 290.00 10,650.00 94.24 205.93 6,370.12 -4,471.93 -4,490.34 7.00 -0.06 7.02 90.00 112312015 12:26:23PM Page 3 ORIGINAL COMPASS 5000.1 Build 51 Has ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Sandbox Company: ConocoPhillips(Alaska) Inc. NAD83-NAD27 Project: Kuparuk River Unit Site: Kuparuk 30 Pad Well: 30-16 Wellbore: 30-16AL1 Design: 30-16AL1 _wp07 Planned Survey Measured Depth Inclination Azimuth (usft) (1) (1) 7,800.00 35.62 245.40 TIP 7,815.00 35.55 245.34 KOP 7,840.00 40.05 245.34 End 18 d1s, Start 35 dis 7,900.00 61.05 245.34 7,992.71 93.50 245.34 End 35 dis, Start 7 dis 8,000.00 93.46 245.85 8,100.00 92.82 252.83 8,192.71 92.19 259.30 5 8,200.00 92.14 258.79 8,300.00 91.39 251.83 8,400.00 90.62 244.87 8,412.71 90.52 243.98 6 8,500.00 91.99 238.05 8,562.71 93.04 233.79 7 8,600.00 93.93 231.33 8,700.00 96.27 224.71 8,712.71 96.57 223.86 8 8,800.00 99.11 218.25 8,862.71 100.89 214.18 9 8,900.00 98.41 213.36 9,000.00 91.74 211.22 9,012.71 90.89 210.95 10 9,100.00 90.72 204.84 9,200.00 90.51 197.84 9,300.00 90.29 190.85 9,400.00 90.07 183.85 9,412.71 90.04 182.96 11 9,500.00 89.19 176.91 9,522.71 88.97 175.33 12 9,600.00 89.13 180.74 9,700.00 89.36 187.74 9,800.00 89.59 194.74 9,900.00 89.83 201.73 9,972.71 90.01 206.82 13 10,000.00 90.63 205.01 10,100.00 92.90 198.39 10,200.00 95.13 191.73 10, 222.71 95.63 190.22 14 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 30-16 Mean Sea Level 30-16A @ 59.00usft (30-16A) True Minimum Curvature TVD Below Vertical Dogleg Toolface Map Map system +N/-S +El-W Section Rate Azimuth Northing Easting (usft) (usft) (usft) (usft) (11400ft) (1) (usft) (usft) 6,390.21 -2,293.24 -3,127.86 3,834.50 0.00 0.00 6,019,410.36 522,578.55 6,402.40 -2,296.87 -3,135.80 3,842.69 0.52 -153.52 6,019,406.69 522,570.63 6,422.15 -2,303.26 -3,149.72 3,857.06 18.00 0.00 6,019,400.26 522,556.73 6,460.06 -2,322.48 -3,191.59 3,900.30 35.00 0.00 6,019,380.89 522,514.93 6,480.22 -2,359.71 -3,272.69 3,984.03 35.00 0.00 6,019,343.39 522,433.97 6,479.77 -2,362.72 -3,279.31 3,990.84 7.00 95.00 6,019,340.36 522,427.36 522,237.21 521, 960.35 521,879.13 521,740.04 521,683.41 521, 583.47 521, 514.78 521,507.73 521,416.17 1/23/2015 12:26:23PM Page 4 COMPASS 5000.1 Build 61 Has ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 30-16 Company: ConocoPhillips(Alaska) Inc. NAD83-NAD27 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-16A @ 59.00usft (30-16A) Site: Kuparuk 30 Pad North Reference: True Well: 30-16 Survey Calculation Method: Minimum Curvature Wel lbore: 30-16ALl Design: 30-16AL 1 _wp07 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) (°/100ft) V) (usft) (usft) 10,300.00 93.76 195.31 6,392.60 -4,141.13 -4,379.93 6,025.64 7.00 110.00 6,017,558.34 521,332.99 10,372.71 91.97 200.08 6,388.96 -4,210.29 -4,402.01 6,090.08 7.00 110.42 6,017,489.10 521,311.16 15 10,400.00 92.62 198.29 6,387.87 -4,236.04 -4,410.96 6,114.60 7.00 -70.00 6,017,463.33 521,302.29 10,472.71 94.35 193.49 6,383.45 -4,305.83 -4,430.83 6,177.92 7.00 -70.07 6,017,393.48 521,282.67 16 10,500.00 94.34 195.40 6,381.38 -4,332.17 -4,437.62 6,201.32 7.00 90.00 6,017,367.12 521,275.97 10,600.00 94.29 202.42 6,373.84 -4,426.44 -4,469.92 6,290.73 7.00 90.15 6,017,272.74 521,244.00 10,650.00 94.24 205.93 6,370.12 -4,471.93 -4,490.34 6,337.29 7.00 90.67 6,017,227.19 521,223.74 Planned TD at 10650.00 112312015 12:26:23PM Page 5 COMPASS 5000.1 Build 61 ORIGINAL //.raI ConocoPhollips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Sandbox Company: ConocoPhillips(Alaska) Inc. NAD83-NAD27 Project: Kuparuk River Unit Site: Kuparuk 30 Pad Well: 30-16 Wellbore: 30-16AL1 Design: 30-16AL1_wp07 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/-S +El-W Northing Shape (1) (1) (usft) (usft) (usft) (usft) 30-16AL1_T04 0.00 351.30 6,447.00-2,666.83-3,913.29 6,019,034.10 plan misses target center by 0.45usft at 8715.63usft MD (6447.42 TVD,-2666.98 N,-3913.20 E) Point Well 30-16 Mean Sea Level 30-16A @ 59.00usft (30-16A) True Minimum Curvature Easting (usft) Latitude Longitude 521,794.49 70' 27' 47.345 N 149' 49' 19,468 W 30-16AL1_Fault4 0.00 351.30 0.00 -4,595.82 -4,539.06 6,017,103.14 521,175.45 700 27' 28.370 N 1490 49' 37.823 W plan misses target center by 6371.51 usft at 10650.00usft MD (6370.12 TVD,-4471.93 N,-4490.34 E) Rectangle (sides W500.00 H1.00 D0.00) 30-16AL1_T01 0.00 351.30 6,402.00 -2,296.50 -3,135.90 6,019,407.07 522,570.53 70' 27' 50.991 N 149° 48' 56.628 W plan misses target center by 0.42usft at 7814.63usft MD (6402.11 TVD, -2296.78 N,-3135.61 E) Point 30-16AL1_Faultl 0.00 351.30 0.00 -2,417.42 -3,450.36 6,019,285.08 522,256.51 70' 27' 49.800 N 149° 49' 5.868 W plan misses target center by 6399.54usft at 7800.00usft MD (6390.21 TVD, -2293.24 N,-3127.86 E) Rectangle (sides W220.00 H1.00 D0.00) 30-16AL1_T05 0.00 351.30 6,426.00 -2,775.53 -4,001.68 6,018,925.10 521,706.49 70' 27' 46.275 N 149' 49' 22.064 W plan misses target center by 0.17usft at 8857.47usft MD (6425.92 TVD, -2775.61 N,-4001.55 E) Point 30-16AL1_T08 0.00 351.30 6,394.00 -4,120.35 -4,375.39 6,017,579.13 521,337.46 70' 27' 33.047 N 149° 49' 33.023 W plan misses target center by 0.86usft at 10278.68usft MD (6394.09 TVD,-4120.55 N, -4374.57 E) Point 30-16AL1_Fault2 0.00 351.30 0.00 -2,666.83 -3,913.29 6,019,034.10 521,794.49 70' 27' 47.345 N 149' 49' 19.468 W plan misses target center by 6416.01 usft at 9000.00usft MD (6409.85 TVD,-2894.57 N,-4078.06 E) Rectangle (sides W280.00 H1.00 D0.00) 30-16AL1_T03 0.00 351.30 6,370.00 -4,471.98 -4,490.63 6,017,227.14 521,223.45 700 27' 29.588 N 1490 49' 36.402 W plan misses target center by 0.31 usft at 10650.O0usft MD (6370.12 TVD,-4471.93 N, -4490.34 E) Point 30-16AL1_T06 0.00 351.30 6,406.00 -3,242.89 -4,196.33 6,018,457.11 521,513.48 70' 27' 41.678 N 149' 49' 27.776 W plan misses target center by 0.64usft at 9371.15usft MD (6406.29 TVD, -3242.83 N,-4196.90 E) Point 30-16AL1 T02 0.00 351.30 6,480.00 -2,350.10 -3,252.10 6,019,353.07 522,454.52 70' 27' 50.463 N 149° 49' 0.042 W plan misses target center by 0.28usft at 7970.21 usft MD (6480.04 TVD, -2350.33 N,-3252.25 E) Point 30-16A CTD Polygon 0.00 351.30 0.00 -2,192.24 -3,208.55 6,019,511.07 522,497.52 70' 27' 52.016 N 149' 48' 58.764 W plan misses target center by 6391.51 usft at 7800.00usft MD (6390.21 TVD, -2293.24 N,-3127.86 E) Polygon Point 1 0.00 0.00 0.00 6,019,511.07 522,497.52 Point 0.00 -137.88 -334.50 6,019,323.12 522,188.41 Point 0.00 -434.77 -963.58 6,018,932.52 521,612.89 Point 0.00 -903.10 -1,174.19 6,018,437.29 521,477.29 Point 5 0.00 -1,403.02 -1,213.90 6,017,937.30 521,515.39 Point 0.00 -1,794.60 -1,350.24 6,017,529.38 521,441.28 Point 0.00 -2,214.26 -1,462.68 6,017,097.42 521,395.12 Point 0.00 -2,316.26 -1,172.00 6,017,041.63 521,698.05 Point 0.00 -1,875.75 -1,013.48 6,017,501.31 521,786.51 Point 10 0.00 -1,477.09 -901.12 6,017,912.51 521,835.83 Point 11 0.00 -991.25 -840.46 6,018,401.84 521,820.60 Point 12 0.00 -616.68 -700.17 6,018,793.56 521,901.25 Point 13 0.00 -343.13 -265.19 6,019,131.08 522,288.63 Point 14 0.00 -202.35 96.32 6,019,326.08 522,623.98 Point 15 0.00 0.00 0.00 6,019,511.07 522,497.52 30-16AL1_T09 0.00 351.30 6,370.00 -4,471.98 -4,490.63 6,017,227.14 521,223.45 70' 27' 29.588 N 149' 49' 36.402 W plan misses target center by 0.31 usft at 10650.00usft MD (6370.12 TVD,-4471.93 N, -4490.34 E) Point 30-16AL1_Fault3 0.00 351.30 0.00 -4,120.35 -4,374.39 6,017,579.13 521,338.46 70° 27' 33.047 N 149° 49' 32.993 W 112312015 12:26:23PM Page 6 COMPASS 5000.1 Build 61 Of?IGINAL ConocoPhilli s p Planning Report BAKER Alaska HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 30-16 Company: ConocoPhillips(Alaska) Inc. NAD83-NAD27 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-16A @ 59.00usft (30-16A) Site: Kuparuk 30 Pad North Reference: True Well: 30-16 Survey Calculation Method: Minimum Curvature Wellbore: 30-16AL1 Design: 30-16AL1_wp07 plan misses target center by 6380.86usft at 10650.00usft MD (6370.12 TVD,-4471.93 N,-4490.34 E) Rectangle (sides W340.00 H1.00 D0.00) 30-16AL1_T07 0.00 351.30 6,411.00-3,816.66-4,277.33 6,017,883.12 521,434.47 70' 27' 36.034 N 149' 49' 30.147 W plan misses target center by 0.34usft at 9957.68usft MD (6411.30 TVD,-3816.74 N,-4277.17 E) Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 10,650.00 6,370.12 2 3/8" 2.375 3.000 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 7,800.00 6,390.21 -2,293.24 -3,127.86 TIP 7,815.00 6,402.40 -2,296.87 -3,135.80 KOP 7,840.00 6,422.15 -2,303.26 -3,149.72 End 18 dls, Start 35 dls 7,992.71 6,480.22 -2,359.71 -3,272.69 End 35 dls, Start 7 dls 8,192.71 6,470.24 -2,420.21 -3,462.54 5 8,412.71 6,465.01 -2,489.28 -3,670.65 6 8,562.71 6,460.34 -2,566.64 -3,798.83 7 8,712.71 6,447.75 -2,664.89 -3,911.20 8 8,862.71 6,424.94 -2,779.86 -4,004.46 9 9,012.71 6,409.55 -2,905.46 -4,084.62 10 9,412.71 6,406.23 -3,284.27 -4,200.10 11 9,522.71 6,407.18 -3,394.17 -4,198.46 12 9,972.71 6,411.30 -3,830.22 -4,283.84 13 10,222.71 6,398.92 -4,066.04 -4,362.92 14 10,372.71 6,388.96 -4,210.29 -4,402.01 15 10,472.71 6,383.45 -4,305.83 -4,430.83 16 10,650.00 6,370.12 -4,471.93 -4,490.34 Planned TD at 10650.00 112312015 12:26.23PM Page 7 COMPASS 5000.1 Build 61 nRIGINAL ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 30 Pad 30-16 30-16AL1 30-16AL1_wp07 Travelling Cylinder Report 21 January, 2015 we P P �_- 'A as BAKER HUGHES ORIGINAL e� Baker Hughes INTEQ FeA.■ ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 30 Pad Site Error: 0 00usft Reference Well: 30-16 Well Error: 0.00usft Reference Wellbore 30-16ALl Reference Design: 30-16AL1_wp07 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 30-16 30-16A @ 59.00usft (30-16A) 30-16A @ 59.00usft (30-16A) True Minimum Curvature 1.00 sigma OAKEDMP2 Offset Datum Reference 30-16AL1_wp07 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 7,800.00 to 10,650.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,259.10usft Error Surface: Elliptical Conic Survey Tool Program Date 1/21/2015 From To (usft) (usft) Survey (Wellbore) Tool Name Description 100.00 7,800.00 30-16A (30-16A) GCT-MS Schlumberger GCT multishot 7,800.00 10,650.00 30-16AL1_wp07 (30-16AL1) MWD MWD - Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 10,650.00 6,429.12 2 3/8" 2-3/8 3 Summary Site Name Offset Well - Wellbore - Design Kuparuk 30 Pad 30-10 - 30-10 - 30-10 30-15 - 30-15 - 30-15 30-16 - 30-16 - 30-16 30-16 - 30-16A - 30-16A 30-16 - 30-16AL1-01 - 30-16ALl-01_wp02 30-16 - 30-16ALl-02 - 30-16AL1-02_wp02 30-17 - 30-17 - 30-17 30-19 - 30-19 - 30-19 Kuparuk UGNU Plan: UGNU SAGD - UGNU SAGD - UGNU SAGD Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Depth Depth Distance (usft) from Plan (usft) (usft) (usft) (usft) Out of range Out of range 7,815.98 7,900.00 728.53 244.14 485.67 Pass - Major Risk 7,825.00 7.825.00 0.16 1.13 -0.96 FAIL - Major Risk 8,925.00 8,925.00 0.38 0.29 0.16 Pass - Minor 1/10 8,900.00 8,900.00 0.08 0.48 -0.33 FAIL- Minor 1/10 Out of range Out of range Out of range CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 112112015 5:17:19PM Page 2 of 9 COMPASS 5000.1 Build 65 ORIGINAL r 0 O c V _ L+a 0. 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S 0, c ILI o o o c y N (ui/{;sn 08) gldaQ leotuaA owl � in RIGINAL Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Wednesday, February 18, 2015 4:39 PM To: Burke, Jason(Jason.Burke@conocophillips.com) Subject: KRU 30-16AL1, 30-16AL1-01, 30-16-AL1-02: Permit to Drill Application Good afternoon Jason, Does ConocoPhillips plan to pre -produce any of the KRU 30-16A laterals? On page 4 of the "Application for Permit to drill Document" it states that "two wellbores of kill weight fluid will be available". What would be the weight of the available KWF? Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. Loepp. Victoria T (DOA) From: Burke, Jason <Jason.Burke@conocophillips.com> Sent: Tuesday, March 03, 2015 1:43 PM To: Loepp, Victoria T (DOA) Cc: Venhaus, Dan E Subject: RE: KRU 30-16AL1(PTD 215-029) Production Liner Cement The 3.5" liner will be cemented in with -6 bbl of 15.8 ppg cement 4.25" OH ID 3.5" Liner OD 4.5" 11.6# tubing OH from 7815' MD to 8815' MD Top of liner 7750' Total annular volume in open hole = 5.64 bbl Total annular volume in tubing = .24 bbl Total cement volume = 5.88 bbl Please let me know if you need any further details Thanks ConocoPhillips Jason Burke CTD Engineer - Greater Xuparuk Area 700CiSt#1210 .Anchorage, .AX 99501 (0): (907)-265-6o97 (-M): (907)-231-4568 Jason.Burke@conocophillips.com _ZS/ s� gg his � ��3� �, ► � �3 From: Loepp, Victoria T (DOA)[mailto:victoria.loeppcdalaska.gov] Sent: Tuesday, March 03, 2015 8:27 AM To: Burke, Jason Subject: [EXTERNAL]KRU 30-16AL1(PTD 215-029) Production Liner Cement Jason, This lateral is completed with a 4" cemented production liner. Please provide the cement volume calculations. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer 1 Bettis, Patricia K (DOA) ?/-2� From: Burke, Jason<Jason.Burke@conocophillips.com> Sent: Monday, February 23, 2015 4:03 PM To: Bettis, Patricia K (DOA) Subject: RE: KRU 30-16AL1, 30-16AL1-01, 30-16-AL1-02: Permit to Drill Application Patricia Sorry for the delayed response, I was out of the office quite sporadically last week. This well will not be pre -produced and the KWF will be at least 12.2 ppg. Jason ConocoPhiiiip5 Jason Burke CITI) Engineer - Greater Xupciruk,_Area -00 CJ St #1210 Anchrn-age, _AX 9�501 (0): (n07)-26545097 (914): (g07)-2,31-4568 Jason.Burke@conocophiIIips.com From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Monday, February 23, 2015 1:43 PM To: Burke, Jason Subject: [EXTERNAL]FW: KRU 30-16AL1, 30-16AL1-01, 30-16-AL1-02: Permit to Drill Application Good afternoon Jason, Did you receive my email of last Wednesday? Thanks, Patricia From: Bettis, Patricia K (DOA) Sent: Wednesday, February 18, 2015 4:39 PM To: Burke, Jason (Jason.BurkeCa>conocophillips.com) Subject: KRU 30-16AL1, 30-16AL1-01, 30-16-AL1-02: Permit to Drill Application Good afternoon Jason, Does ConocoPhillips plan to pre -produce any of the KRU 30-16A laterals? On page 4 of the "Application for Permit to drill Document" it states that "two wellbores of kill weight fluid will be available". What would be the weight of the available KWF? Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. Bettis, Patricia K (DOA) 1� 0 a 2 From: Bettis, Patricia K (DOA) Sent: Wednesday, February 18, 2015 4:39 PM To: Burke, Jason (Jason.Burke@conocophillips.com) Subject: KRU 30-16AL1, 30-16AL1-01, 30-16-AL1-02: Permit to Drill Application Good afternoon Jason, Does ConocoPhillips plan to pre -produce any of the KRU 30-16A laterals? On page 4 of the "Application for Permit to drill Document" it states that "two wellbores of kill weight fluid will be available". What would be the weight of the available KWF? Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. Loepp, Victoria T (DOA) From: Burke, Jason <Jason.Burke@conocophillips.com> Sent: Tuesday, February 17, 2015 9:05 AM To: Loepp, Victoria T (DOA) Cc: Venhaus, Dan E Subject: 30-16A Permit Follow Up Flag: Follow up Flag Status: Flagged Victoria As you are processing the 30-16A drilling permit you'll notice it recommends a 5000 psi pressure test. I was wondering if we could bump that down to 4900 psi on the approved permit. It will give us a little cushion for pressure testing, so if we bump a little high (say 4920 psi) we aren't exceed the working pressure of our BOP stack. Thanks Jason v-, ConocoPhillips Jason Burke C?M Engineer - Greater Xuparuk .Area 700 G St #1210 .Anchorage, ✓ X 99501 (0): (907)-265-6097 (M): (9o7)-231-4568 Jason.Burke@conocophilIips.com TRANSMITTAL LETTER CHECKLIST WELL NAME: M' U' PTD: a Js - 02,9 Development ✓ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: ��lni lU POOL: KL"'O �� Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit / LATERAL No. M- 093 API No. 50-DQ3_-2Ln_�_-P- a"� . (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 onpermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 PTD#:2150290 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Well Name: KUPARUK RIV UNIT 30-16AL1 Program SER Well bore seg SER / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025513, Surf & Top Prod Inter; ADL0025520, TD 3 Unique well name and number Yes KRU 30-16AL1 4 Well located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order No. 432C 5 Well located proper distance from drilling unit boundary Yes CO 432C contains no spacing restrictions with respect to drilling unit boundaries. 6 Well located proper distance from other wells Yes CO 432C has no interwell spacing restrictions. 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes Wellbore will be more than 500' from an external property line wehre ownership or landownership changes. 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15-day wait Yes PKB 2/23/2015 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For Yes AIO 2C-Kuparuk River Unit 15 All wells within 1/4 mile area of review identified (For service well only) Yes KRU 30-16A, 30-16, KRU 3N-13 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) No Jason Burke (2/23/2015) 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA 18 Conductor string provided NA Conductor set in PBU 30-16 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in PBU 30-16 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing set and fully cemented 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons No Productive interval will be completed with slotted liner 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes Anti -collision analysis complete; no major risk failures 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max expected form pressure during drilling is 12.1 ppgEMW; will drill w/ 12.1ppg& overbal w/ MPD VTL 3/3/2015 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 4651 psi; will test BOPs to 4900 psi 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of 112S gas probable Yes H2S measures required 34 Mechanical condition of wells within AOR verified (For service well only) Yes AOR complete and wells reviewed. 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 30-Pad are H2S-bearing. H2S measures required Geology 36 Data presented on potential overpressure zones Yes Max expected reservoir pressure is 15.89 ppg EMW; will be drilled using 10.0 ppg mud and MPD Appr Date 37 Seismic analysis of shallow gas zones NA technique. Two wellbore volumes of at least 12.2 ppg KW F will be available. PKB 2/24/2015 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Onshore service well to be drilled . Geologic Engineering Public Commissioner: Date: Commissioner: Date Commissioner Date )�-'T -� 3I � J I' /0�� 3-G IS