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Home My WebLink About215-192Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Thursday, November 16, 2017 10:53 AM To: 'Starck, Kai' Cc: Loepp, Victoria T (DOA); Bettis, Patricia K (DOA) Subject: Expired Permit to Drill: KRU 30-01A L1 Hello Kai, The following Permit to Drill, issued to ConocoPhillips Alaska, has expired under Regulation 20 AAC 25.005 (g). The PTD will be marked expired in the AOGCC database. • KRU 30-01A L1, PTD 215-192, Issued 3 November 2015 If you have any questions, please contact me. Thank you, 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 01ALASKA GOVERNOR BILL WALKER Dan Venhaus CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Alaska Oil d Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 30-OIALI ConocoPhillips Alaska, Inc. Permit No: 215-192 Surface Location: 724' FNL, 3438' FEL, SEC. 22, T13N, R9E, UM Bottomhole Location: 5076' FNL, 2460' FEL, SEC. 9, T13N, R9E, UM Dear Mr. Venhaus: Enclosed is the approved application for permit to re -drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 215-191, API No. 50-029- 21836-01-00. 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, Cathy P oerster Chair DATED this Aday of November, 2015. RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION OCT 2 3 2015 PERMIT TO DRILL �� 20 AAC 25.005 1a. Type of Work: 1 h_ Proposed Well Class: Development - Oil ❑ Service - Winj ❑ Single Zone ❑ Drill ❑ Lateral d Stratigraphic Test ❑ Development - Gas El 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 30-01ALl 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 11200' , TVD: 6631' 12. Field/Pool(s): Kuparuk River Field Kuparuk River Oil Pool , 4a. Location of Well (Governmental Section): Surface: 724' FNL, 3438' FEL, Sec. 22, T13N, R9E, UM Top of Productive Horizon: 823' FNL, 945' FEL, Sec. 16, T13N, R9E, UM Total Depth: 5076' FNL, 2460' FEL, Sec. 9, T13N, R9E, UM 7. Property Designation (Lease Number): ADL 25513, 355023 8. Land Use Permit: 2554, 3573 13. Approximate Spud Date: 12/1/2015 9. Acres in Property: 2� 5? 14. Distance to Nearest Property: 7072 41b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 525478 y- 6022095 Zone- 4 ' 10. KB Elevation above MSL: 59 feet GL Elevation above MSL: 24 feet 15. Distance to Nearest Well Open to Same Pool: 30-08L1 , 1827 16. Deviated wells: Kickoff depth: . 10400 ft. Maximum Hole Angle: . 95° deg 17. Maximum Anticipated Pressures in psig (see 20 AAC 25,035) Downhole: 4504 psig Surface: 3841 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 3" 2.375" 4.7# L-80 ST-L 1850' 9350' 6623' 11200' 6631' Islotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 9173 Total Depth TVD (ft): 6890 Plugs (measured) none Effective Depth MD (ft): 1 9065 Effective Depth TVD (ft): 6805 Junk (measured) 9000, Casing Length Size Cement Volume MD TVD Conductor 82' 16" 200 sx ASH 115' 115, Surface 5270' 9.625" 1250 sx AS III, 370 sx Cl G 5305' 4066' 80 sx AS I Production 9113' 7' 200 sx Class G 9248' E371' Perforation Depth MD (ft): 8832-8847, 8850-8866, 8890-8910 Perforation Depth TVD (ft): 6623-6634, 6637-6649, 6668-6684 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Prograrr ❑✓ Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑ 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: Date: 22. 1 hereby certify that the foregoing is true and correct. Contact Cody Pohler @ 265-6435 Email Cod .J.Pohler co .corn L Printed Name Dan Venh us Title CTD Engineering Supervisorol Signature Phone: 263-4372 Date Commission Use Only Permit to Drill Number: aIS 19 API Number: 50- 10'k'9 — �, �=3�0 �6� —(� Permit Approval Date: 11 13) ly See cover letter for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed . thane, gas hydrates, or gas contained in shales: Other. 06P 1-,-3t fo 46-00fi51 g S leeq'd: Yes No ❑1 Mud log req'd: Yes[] No ❑ �-�� v( o v nrevet r fCk- i?4- HA me5le "sures: Yes No Directional svy req'd: Yesd No ❑ Spacing exception req'd: Yes ❑ No R Inclination -only svy req'd: Yes ❑ No [� APPROVED BY THE Approved by: JOWIVIJNJR A ICOMMISSION Date: Form 10401 (Rev' ed 10/2012) i i !/T/ /"l /. !� L i v f t from the date of approval (20 AAC 25.005(g)) 1 ♦f /"� ®n®coillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 6, 2015 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: OCT 2 3 2015 ConocoPhillips Alaska, Inc. hereby submits an application for permits to drill a quad -lateral out of the Kuparuk Well 30-01 using the coiled tubing drilling rig, Nabors CDR2-AC. The work is scheduled to begin end of December 2015. The CTD objective will be to drill four laterals (30-01A, 30-01AL1, 30-01AL2, 30-01AL3), targeting the A sand intervals. Attached to this application are the following documents: — Permit to Drill Application Form 10-401 for 30-01A, 30-01AL1, 30-01AL2, 30-01AL3 — Detailed Summary of Operations — Directional Plans — Proposed Schematic If you have any questions or require additional information please contact me at 907-265-6435. Sincerely, Cody Pohler Coiled Tubing Drilling Engineer li,` f1 fi p a r p �u( C T D L aj to ra � NASOH'� SKA - Il ��1115JJ C91 tl y'W�lj�7�1�j p C�Ji g �p dJ y� Application for Permit to ®rill Document 2At 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................................................................... (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 20AAC 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............................................................................................................. 5 (Requirements of 20 AAC 25.005 c 13................................. 5 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.................................................................................................................................... 7 Attachment 1: Directional Plans for 30-01A, AL1, AL2, AL3...........................................................................................7 Attachment 2: Current Well Schematic for 30-01...........................................................................................................7 Attachment 3: Proposed Well Schematic for 30-01A, AL1, AL2, AL3.............................................................................7 Page 1 of 7 10/22/2015 PTD Application: 30-01A, AL1, AL2 and AL3 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 30-01A, 30-01AL1, 30-01AL2 & 30-01AL3. 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 form for surface and subsurface coordinates of the 30-01A, 30-01AL1, 30-01AL2 & 30-01AL3. 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. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4500 psi. Using the maximum formation pressure in the area of 4504 psi in 30-05, the maximum potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 3841 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 Expected Downhole Pressure (Requirements of 20 AAC 25.005 (c)(4)(a)) Well 30-01 has a formation pressure of 10.6 ppg EMW as of 2/1/2015 (3679 psi at 6652' TVD). The maximum potential formation pressure in the area is to the east, well 30-05 with a 13.4 ppg EMW as of 7/18/2015 (4504 psi at 6472' TVD). Since we are drilling away from 30-05 we do not expect to see the higher 30-05 pressure while drilling the 30-01 laterals. Well 3R-22 has a formation pressure of 12.7 ppg EMW as of 9/29/2015 (4406 psi at 6668' TVD). We expect 3R-22 pressure to decline to 12.5 ppg by the time we spud. The maximum expected pressure along the proposed well path is less than 12.5 ppg EMW due to the distance and baffling faults in between the laterals and 3R-22. The 3R-22 pressure would be more likely to influence the 30-01 laterals than the 30-05 pressure. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) Well 30-07 to the east injected lean gas (2014) and well 30-05 to the east injected MI (2013) however all planned laterals are to the northwest; no specific gas zones are expected to be drilled. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) The largest, expected risk of hole problems in the 30-01 laterals will be shale instability across the faults, managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossing. Along with shale instability as mentioned above the higher pressure risk will also be taken into consideration for potential hole problems. Again MPD will be used to mitigate the high pressure risk. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) NIA for this thru-tubing drilling operation. Page 2 of 7 10/22/2015 PTD Application: 30-01A, AL1, AL2 and AL3 According to 20 AAC 25.030(t), thru-tubing drilling operations need not perform additional formation integrity tests. 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 30-01A 10,400' 11,150' 6,610' 6,665' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 30-01ALl 9,350' 11,200' 6,623' 6,631' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 30-01AL2 9,065' 11,200' 6,627' 6,604' 23/", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 23/", 4.7#, L-80, ST-L slotted liner; 30-01AL3 8,730' 10,500' 6,462' 6,569' shorty deployment sleeve in 3-1/2" tubing tail Existing Casing/Liner Information Category OD Weight (ppf) Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.5 H-40 Welded 33' 115' 33' 115' 1,640 630 Surface 9-5/8" 36 J-55 BTC 35' 5,305' 35' 4,066' 3,520 2,020 Production 7" 26.0 J-55 BTC 35' 9,148' 35' 6,870' 4,980 4330 Tubing 3-1/2" 9.3 L-80 EUE 33' 1 8,736' 33' 1 6,754' 1 10,160 10,530 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 -weighted FloVis water -based mud (8.9 ppg) - Drilling operations: Chloride -weighted FloVis water -based mud (8.9 ppg) This mud weight does not hydrostatically overbalances 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 ppg NaBr completion fluid in order to provide formation over -balance and maintain wellbore stability while running completions. Page 3 of 7 10/22/2015 PTD Application: 30-01A, AL1, AL2 and AL3 Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole 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 5000 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". The targeted MPD BHP will be 11.8 ppg 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 30-01 Window (8,840' IViD, 6,629' TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A -sand Formation 3679 psi 3679 psi Pressure (10.6 pp ) Mud Hydrostatic 8.9 pp) 3068 psi 3068 psi Annular friction (i.e. ECD, 796 psi 0 psi 0.090 psi/ft) Mud + ECD Combined 3864 psi 3068 psi (no choke pressure) (overbalanced —185 (underbalanced —612 psi) psi) Target BHP at Window 4069 psi 4069 psi 11.8 Choke Pressure Required 205 psi 1001 psi to Maintain 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 for 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. Page 4 of 7 10/22/2015 PTD Application: 30-01A, AL1, AL2 and AL3 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well 3 0-01 is a Kuparuk A -sand producer well equipped with 3 %2" tubing and 7" production casing. A rig work -over was completed in 2009 to isolate the production casing leak between 5,551' MD to 5,556' MD. Four laterals will be drilled to the north west of the parent well bore with the laterals targeting the different A sand lobes. These laterals will access reserves in the adjacent fault blocks targeting the A1, A2, and A3 sands. Prior to CTD operations, the 3-1/2" tubing tail will be perforated and the D nipple at 8,701' MD will be milled out to a 2.80" ID. The existing A -sand perfs will be squeezed with cement to provide a means to kick out of the 7" casing. ConocoPhillips has submitted at 10-403 sundry application for a variance from the requirements of 20 AAC 25.112(c)(1) to plug the A -sand perfs in this manner. Sundry has been approved; Sundry #315-498. Following the cement squeeze Nabors CDR2-AC will drill a pilot hole to 8,840' MD and set a mechanical whipstock in the 2.80" pilot hole to kick off at 8,840' MD. All four laterals will be completed with 2-3/8" slotted liner from TD with the final liner top located inside the 3-1/2" tubing tail. Pre-CTD Work 1. RU Slickline: dummy off gas lift mandrels. 2. RU E-line: Shoot 2' of holes in the 31/2" tubing tail at 8696' MD. 3. RU Pumping Unit: perform injectivity test down the tubing. 4. RU Service Coil: Mill out D nipple and cement squeeze the A sand perforations up to the perforations in the tubing tail. 5. RU Slickline: Tag top of cement and log. 6. Prep site for Nabors CDR2-AC, including setting BPV. Rig Work 1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 30-01A Lateral (Al sand to north west) a. Drill 2.80" high -side pilot hole through cement to 8,840' MD b. Caliper pilot hole c. Set whipstock at 8,840' MD d. Mill 2.80" window at 8,840' MD. e. Drill 3" bi-center lateral to TD of 11,150' MD. f. Run 2%" slotted liner with an aluminum billet from TD up to 10,400' MD. 3. 30-01ALl Lateral (A2 sand) a. Kick off of the aluminum billet at 10,400' MD. b. Drill 3" bi-center lateral to TD of 11,200' MD. c. Run 2%" slotted liner from TD up to 9,350' MD 4. 30-01AL2 Lateral (A2 & A3 sands) a. Kickoff of the aluminum billet at 9,350' MD. b. Drill 3" bi-center lateral to TD of 11,200' MD. c. Run 2%" slotted liner from TD up to 9,065' MD 5. 30-01AL3 Lateral (A3 sand) a. Kick off of the aluminum billet at 9,065' MD. Page 5 of 7 10/22/2015 PTD Application: 30-01A, AL1, AL2 and AL3 b. Drill 3" bi-center lateral to TD of 10,500' MD. c. Run 2%" slotted liner from TD up to 8,730' MD, above the whipstock and in the 3-1/2" tubing. 6. Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV. 2. Install GLV's. 3. Return to production. 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 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 — The 30-01 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 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 (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. Page 6 of 7 10/22/2015 PTD Application: 30-01A, AL1, AL2 and AL3 ® Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) - The Applicant is the only affected owner. - Please see Attachment 1: Directional 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 30-01 A 5872' 30-01AL'I 7072' 30-01AL2 6210' 30-01AL3 6009' - Distance to Nearest Well within Pool Lateral Name Distance Well 30-01A 633' 30-081-1 30-01AL1 1827' 30-08L1 30-01AL2 960' 30-08L1 30-01AL3 762' 30-08L1 16. Attachments Attachment 1: Directional Plans for 30-01A, AL1, AL2, AU Attachment 2: Current Well Schematic for 30-01 Attachment 3: Proposed Well Schematic for 30-01A, AL1, AL2, AU Page 7 of 7 10/22/2015 Conoc®Phillips ' Alaska. II1C. KUP 30-01 Well Attributes Max Angle & MD TD Wellbore API/UWI 500292183600 Field Name KUPARUK RIVER UNIT Well Status PROD Incl (°) MD (ftKB) 52.62 3,700.00 Act St. (ftKB) 9, 173.0 Comment H2S (ppmj SSSV: NIPPLE 165 Date Annotation End Date KB-Grd (ft) 11252011 Last WO: 2/262009 1 34.98 Rig Release Date 8/5/1988 Annotation Oeplh Last Tag: SLM [ftKB] 8,951.0 End Date 3292009 Annotation Rev Reason: GLV C/O Last Mod ... End ninam 3242012 Date Casjn_q Strip s Casing Description CONDUCTOR String 0... 16 Stang ID 15.062 ... Top (ftKB) 33.0 Set Depth If_. 115.0 Set Depth (ND) ... 115.0 Stang Wt... String- 62.50 H-40 String Top Thrd WELDED Casing Description SURFACE String 0... 9518 String 10 8.765 ... Top (ftKB) 34.6 Set Depth (L. 5,305.0 Set Depth (TVD) ... 4,066.0 String Wt... String... 36.00 J-55 String Top Thrd BTC Casing Description PRODUCTION String 0... 7 String ID 6.276 ... Top (ftKB) 35.2 Set Depth (f... 9.148.0 Set Depth (TVD) ... 6.870.7 String Wt.. String... 26.00 J-55 String Top Thrd BTC Tubinn Shims Tubing Description 15tring D... String to... TIP(ftKS) Set Depth (f... Set Depth (fVD)... string Wt... String... String Top Thrd TUBING 31/2 2.990 33.2 5,399.8 4,129.6 9.30 L80 EUEBRD Com II>tion Details Top (ftKB) Top Depth (TVD) (ftKB) Top Inc] (°) Item Description Comment Noml... ID (in) 33.2 33.2 0.55 HANGER C.I.W. TUBING HANGER 2.950 511.0 510.8 3.42 NIPPLE CAMCO 2.875"'DS' NIPPLE 2.875 5,334.0 4.085.5 47.73 NIPPLE CAMCO 2.813"DS' NIPPLE 2.813 5,377.0 4,114.4 47.86 LOCATOR LOCATOR 2.990 5.378.3 4,115.2 47.86SEAL ABBY SEAL ASSEMBLYw/2'SPACEOUT 3.OD0 Tubing Description IStringO... String ID ... Top (ftKB) Set Depth (f... Set Depth (IVD) ... String Wt-. String ... String Top Thrd Straddle Packer 3 1/2 2.992 5,368.1 8,575.0 6,423.6 9.30 L-80 EUE 8rd AB Mad Completion Details Top (ftKB) Top Depth OW) (ftKB) Top Ind (°) Item Description Comment Nomi... 10 (in) 5,368.1 4,108.4 47.83 SLEEVE "HR" LINER SETTING SLEEVE 4.420 5.381.7 4,117.5 47.87 SBE SEAL BORE EXTENSION 4.000 5,401.7 4,130.8 47.72 XO - Reducing CROSSOVER SUB 2.990 5,411.6 4.137.5 47.72 PACKER BAKER 47132-7" 26# FHL PACKER 2.970 8,479.E 6,35D.2 39.74 PACKER BAKER 47132-7" 26# FHL PACKER 2.976 8,529.0 6,388.2 39.57 NIPPLE OTIS 2.813" W NIPPLE 2.813 8,568.51 6,418.61 39.52 OVERSHOT BAKER 7" x 3.625" POOR BOY OVERSHOT w/ 6.10" SWALLOW 3.620 Tubing Description String 0... String to -. Top (ftKB) I Set Depth If... Set Depth (TVD)... String Wt... String... String Top Thrd TUBING Original 31/2 2.992 3.570.6 8,736.0 6,548.1 9.30 1 J-55 Com letion Details Top (ftKB) Top Depth (ND) (ftKB) Top Incl 11 Item Description Comment Nom1... ID (in) 8.652.3 6.483.4 39.57 PBR AVA PBR/LOCATOR 3.000 8,665.9 6,493.9 39.51 PACKER AVA RMS PACKER 3.000 8,701.4 6,521.2 39.34 NIPPLE CAMCO'D' NIPPLE 2.750 8,735.2 6,547.5 39.18 SOS SHEAR OUT SUB 2.992 Other In Hole ireline retrievable plugs, valves pumps, fish etc. Top lop (ftKB) Depth (ND) (ftKB) Top Incl (°) Description Comment Run Date ID (in) 9,0001 6,754.3 38.18 FISH PIECE OF 3" JD DOG 1"x 1.5" 8/31/2008 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (ND) (ftKB) Sim (ND) (ftKB) Zone Type Comment 8,832 5,847 6,622.E 6,634.4 A-3, 30-01 a101311 IPERF 2 1/8" EnerJet; 60 deg. ph 8,850 8,86E 6,636.7 6,649.2 A-2, 30-01 IPERF 2 1/8" EnerJet; 6D deg. ph 8,890 8,910 6,668.0 6,683.7 A-1, 30-07 IPERF 4.5" Csg Gun; 45 deg. ph Notes:General & Saf End Date I Annotation 2/28M09 I NOTE: View Schematic w/ Alaska Schematic9.0 Mandrel Details Stn Top (ft(B) Top Depth (TVD) (ftKB) Top incl (°) Make Model OD (In) Sam Valve Type Latch Type Port Size (in) TRO Run I (psi) Run Data Com... 1 2,928.2 2.504.0 47.95 Camco MMG 1 1/2 GAS LIFT GLV RK 0.188 1,258.0 321/2012 2 4,697.1 3,649.5 47.37 CamcD MMG 1 1/2 GAS LIFT GLV RK 0.188 1,259.0 3212012 3 5,287.0 4,053.9 47.58 Camco MMG 1 1/2 GAS LIFT OV RK 0.250 0.0 3/212012 4 8,611.6 6,452.2 39.77 OTIS LBX 1 12 GAS LIFT OPEN 0.000 0.0 1/282009 Co1'1oC(}ffi1flIp5 NADConversion Kuparuk River Unit Kuparuk 30 Pad 30-01 30-01AL1 Plan: 30-01AL1 wp03 Standard Planning Report 14 October, 2015 FMA Pp� I BAKER HUGNES ConocoPhillips Database: OAKEDMP2 Company: NADConversion Project: Kuparuk River Unit Site: Kuparuk 30 Pad Well: 30-01 Wellbore: 30-01 AL 1 Design: 30-01 AL1_wp03 Baker Hughes INTEQ Planning Report Local Co-ordinate Reference: Well 30-01 TVD Reference: Mean Sea Level MD Reference: 30-01 @ 59.00usft (30-01) North Reference: True Survey Calculation Method: Minimum Curvature Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Has BAKER HUGHES Site Kuparuk 30 Pad Site Position: Northing: 6,022,094.67usft 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: 0" Grid Convergence: 0.20 ° Well 30-01 Well Position +N/-S 0.00 usft Northing: 6,022,095.27 usft Latitude: 700 28' 17.339 N +E/-W 0.00 usft Easting: 525,478.27 usft Longitude: 149' 47' 30.897 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 30-01ALl Magnetics Model Name Sample Date Declination Dip Angle Field Strength (`) (°) (nT) BG G M2015 1 /1 /2016 18.65 81.05 57,496 Design 30-01AL1_wp03 Audit Notes: Version: Phase: PLAN Tie On Depth: 10,400.00 Vertical Section: Depth From (TVD) +Nl-S +E/-W Direction (usft) (usft) (usft) (°) 0.00 0.00 0.00 315.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +Nl-S +E/-W Rate Rate Rate TFO (usft) (°) (I (usft) (usft) (usft) (°/100usft) (°/loousft) (°1100usft) (°) Target 10,400.00 87.98 300.87 6,610.29 5,783.09 -3,646.28 0.00 0.00 0.00 0.00 10,495.00 94.63 300.87 6.608.13 5,831.79 -3,727.75 7.00 7.00 0.00 0.00 10,565.00 90.02 302.55 6,605.29 5,868.54 -3,787.24 7.00 -6.58 2.39 160.00 10,750.00 90.02 315.50 6,605.22 5,984.77 -3,930.66 7.00 0.00 7.00 90.00 10,820.00 90.02 310.60 6,605.19 6,032.54 -3,981.80 7.00 0.00 -7.00 -90.00 10,920.00 87.63 304.02 6,607.24 6,093.10 -4.061.27 7.00 -2.39 -6.58 -110.00 11,200.00 82.56 285.01 6,631.18 6,208.38 -4,313.81 7.00 -1.81 -6.82 -105.00 1011412015 7.37:22AM Page 2 COMPASS 5000.1 Build 74 V--" Baker Hughes INTEQ FAN ConoCOPhillips Planning Report BAKER HUGHES Database: OAKEDMP2 Company: NADConversion Project: Kuparuk River Unit Site: Kuparuk 30 Pad Well: 30-01 Welibore: 30-01 AL 1 Design: 30-01 A L 1 _wp03 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 30-01 Mean Sea Level 30-01 @ 59.00usft (30-01) True Minimum Curvature Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (°) (°) (usft) (usft) (usft) (usft) (°/100usft) (°) (usft) (usft) 10,400.00 87.98 300.87 6,610.29 5,783.09 -3,646.28 6,667.57 0.00 0.00 6,027,865.27 521.812.58 TIP/KOP 10,495.00 94.63 300.87 6,608.13 5,831.79 -3,727.75 6,759.62 7.00 0.00 6,027,913.69 521,730.95 Start 7 dls 10,500.00 94.30 300.99 6.607.74 5,834.35 -3,732.03 6,764.45 7.00 160.00 6,027,916.24 521,726.67 10,565.00 90.02 302.55 6,605.29 5,868.54 -3,787.24 6,827.67 7.00 159.96 6,027,950.23 521,671.35 3 10,600.00 90.02 305,00 6,605.28 5,888.00 -3,816.33 6,861.99 7.00 90.00 6,027,969.58 521,642.19 10,700.00 90.02 312.00 6,605.24 5,950.20 -3,894.54 6,961.29 7.00 90.00 6,028,031.52 521,563.77 10,750.00 90.02 315.50 6,605.22 5,984.77 -3.930.66 7,011.27 7.00 90.00 6,028,065.96 521,527.54 4 10,800.00 90.02 312.00 6,605.20 6,019.34 -3,966.77 7,061.25 7.00 -90.00 6,028,100.40 521,491.31 10,820.00 90.02 310.60 6,605.19 6,032.54 -3,981.80 7,081.21 7.00 -90.00 6,028,113.55 521,476.24 5 10,900.00 88.11 305.33 6,606.49 6,081.73 -4,044.84 7,160.56 7.00 -110.03 6,028.162.51 521,413.04 10,920.00 87.63 304.02 6,607.24 6,093.10 -4,061.27 7,180.22 7.00 -110.02 6,028,173.83 521,396.57 6 11,000.00 86.18 298.60 6,611.56 6,134.59 -4,129.49 7,257.81 7.00 -105.13 6,028,215.08 521,328.21 11,100.00 84.37 291.81 6,619.80 6,177.01 -4,219.61 7,351.52 7.00 -105.26 6,028,257.19 521,237.97 11.200.00 82.56 285.01 6,631.18 6,208.38 -4,313.81 7,440.31 7.00 -105.37 6,028,288.23 521,143.67 Planned TD at 11200.00 teasing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 11,200.00 6,631.18 23/8" 2-3/8 3 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 10,400.00 6,610.29 5,783.09 -3,646.28 TIP/KOP 10,495.00 6,608.13 5.831.79 -3,727.75 Start 7 dls 10,565.00 6.605.29 5,868.54 -3,787.24 3 10,750.00 6,605.22 5,984.77 -3,930.66 4 10,820.00 6,605.19 6,032.54 -3,981.80 5 10,920.00 6,607.24 6,093.10 -4,061.27 6 11,200.00 6,631.18 6,208.38 -4,313.81 Planned TD at 11200.00 1011412015 7:37:22AM Page 3 COMPASS 5000.1 Build 74 10 VA kv_ O NAz 6 a CCo O J 22ep4 6 6 O Y Y n v M uy�0 I d J 1 3 Q O a Q o. o� a 0 V o Z of F� I i _ i I o o 5 a 6 N � J M 1� m o d N � C d N N C Q V NcV N -°oZ rn cn roi r��oo ��moomc m m m r n r n cn R N O O O o O O O o 0 0 0 0 0 0 o I.L000 OOOu'i CJ zo � C 0 0 0 0 0 0 0 N 0 0 0 0 0 0 0 o> r C N t0ti I�.O��nj LP Ca n n rn rn O m N Juj (q rn rn<< n o m O I-� K 1 nt' h jmmmOmiOON N I p J .J LL.I (q 0 (J Of N Qf 'cf 67 V]N ?� rnl� pomui ui uir.= o 0 0 0 o m c N iri co co ao co co in co �mmomco� o p Z N O — ¢ mm 1[)YJOO 0 0 (V N 6s f y y t7� mt7mmN p C Omi tm0 O O O fm0 1{09 an0 Obi 001 rn OOi anO aNp W� + O p o 0 0 0 0 0 0 0 0 0 0 0 0 0 �o.ri ui0000 V <<OfI�ONO ONiN C/) O 000000�-- N M u t O n Z Oco (ul/}jsn OL) gldoQ IeoploA onis, ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 30 Pad 30-01 30-01AL1 30-01AL1_wp03 Travelling Cylinder Report 13 October, 2015 WE P Is I BAKER NUGHES �,- ConocoPhillips rigs ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project Kuparuk River Unit Reference Site: Kuparuk 30 Pad Site Error. 0.00 usft Reference Well: 30-01 Well Error. 0.00 usft Reference Wellbore 30-01AL1 Reference Design: 30-01 AL1_wp03 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 30-01 30-01 @ 59-00usft (30-01) 30-01 @ 59-00usft (30-01) True Minimum Curvature 1.00 sigma EDM Alaska ANC Prod Offset Datum Reference 30-01AL1_wp03 =iltertype: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference nterpolation Method: MD Interval25.00usft Error Model: ISCWSA )epth Range: 10,400.00 to 11,200.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,314.10 usft Error Surface: Elliptical Conic Survey Tool Program Date 9/22/2015 From TO (usft) (usft) Survey (Wellbore) Tool Name Description 100.00 8,800.00 30-01 (30-01) BOSS -GYRO Sperry -Sun BOSS gyro multishot 8,800.00 10,400.00 30-01A_wp03(30-01A) MWD MWD-Standard 10,400.00 11,200.00 30-01AL1_wp03 (30-01AL1) MWD MWD - Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 11.200.00 6,690.18 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 30 Pad 30-01 - 30-01A- 30-01A_wp03 10,424.99 10,425.00 0.54 0.72 -0.11 FAIL - Minor 1/10 30-01 - 30-01AL2 - 30-01A1_2_wp03 10,421.00 10,425.00 49.72 1.38 49.49 Pass - Minor 1/10 30-01 - 30-01AL3 - 30-01AL3_wp03 10,422.21 10,450.00 184.06 1.36 183.84 Pass - Minor 1110 30-02 - 30-02 - 30-02 Out of range 30-02 - 30-02A- 30-02A Out of range 30-02 - 30-02ALl - 30-02AL1 Out of range 30-02 - 30-02AL1 P131 - 30-02ALl PB1 Out of range 30-02 - 30-02AL2 - 30-02AL2 Out of range 30-02 - 30-02AL2-01 - 30-02AL2-01 Out of range Offset Design Kuparuk 30 Pad - 30-01 - 30-01 A- 30-01A_wp03 Offset Site Error: 0.00 usft Survey Program: 100-BOSS-GYRO, 8800-MWD Rule Assigned: Minor 1/10 Offset Well Error: 0.00 usft Reference Offset Semi MajorAxis Measured Vertical Measured Vertical Reference Offset Toolface + Offset Wellbore Centre Casing - Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +NRS +E/-W Hole Sae Centre Distance Deviation (usft) (usft) (usft) (usft) (usft) (usft) (^) (usft) (usft) (") (usft) (usft) (usft) 10,424+99 6,669.79 10,425.00 6,670.17 0.14 0.19 75.79 5,796.23 -3,667.52 2-11/16 0.54 0.72 -0.11 FAIL- Minor 1110, CC, ES, SF 10,449.91 6.669.53 10,450.00 6,671.05 0.28 0.38 75.75 5,810.02 -3,688+36 2-11116 2.15 1.01 1.25 Pass - Minor 1/10 10,474.69 6,668.52 10,475+00 6,671.92 0.38 0.57 75.68 5,824.44 -3,708.76 2-11/16 4.84 1.18 3.78 Pass - Minor 1/10 10.499.34 6,666.79 10500.00 6,672.79 0.47 D.75 75.61 5,839,47 -3,728.71 2-11/16 8.57 1.28 7.38 Pass - Minor 1110 10,524.30 6,665.26 10,525.00 6,673.66 0.57 0.94 73.57 5,855.11 -3,748.20 2-11116 12.57 1.32 1L29 Pass - Minor 1/10 10,649.44 6,664.44 10,550.00 6,674.59 0.68 1.13 71.63 5,870.75 -3,767.68 2-11/16 15.98 1.34 14.65 Pass- Minor 1/10 10,574.77 6,664.29 10,575.00 6,675.65 0.79 1.33 71.73 5,885.80 -3,787.62 2-11116 18.25 1,34 16.94 Pass - Minor 1/10 10,600.19 6,664.28 10,600.00 6,676.84 0.90 1.52 75.32 5,900.23 -3,807+99 2-11/16 19.42 1.35 18.15 Pass - Minor 1/10 10,625.58 6,664.27 10,625.00 6,678.16 1.01 1.73 82.00 5,914.04 -3,828.79 2-11/16 19.58 1.35 18.35 Pass - Minor 1/10 10650.79 6,664.26 10,650.00 6,679.61 1.12 1.94 92,28 5,927.21 -3,849.99 2-11/16 19.04 1.35 17.76 Pass - Minor 1/10 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 1011312015 1:11:05PM Page 2 COMPASS 5000.1 Build 74 TRANSMITTAL LETTER CHECKLIST WELL NAME: /Qu_ -3O - PI A L I PTD: c2I S -17 Z ' Development Service Exploratory _ Stratigraphic Test _ Non -Conventional n FIELD: koafli 2%'U POOL: 9C dEJ' i,✓ �. 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. a / S' I `t l , API No. 50-aZcl -� 18 3 6 - 01 - t . (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) 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#:2151920 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Well Name: KUPARUK RIV UNIT 30-01AL1 Program DEV Well bore seg d❑ DEV / 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 Interv; ADL0355023, TD 3 Unique well name and number Yes KRU 30-01AL1 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 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 where ownership of 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 10/28/2015 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D) NA 18 Conductor string provided NA Conductor set in KRU 30-01 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in KRU 30-01 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 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 wast 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 formation pressure is 4505 psig(13.4 ppg EMW); will drill w/ 8.9 ppg EMW and maintain overbalance w/ MPD VTL 10/29/2015 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 3841 psig; will test BOPs to 4500 psig 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of 112S gas probable Yes 112S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 30-pad are H2S-bearing. 112S measures required. Geology 36 Data presented on potential overpressure zones Yes Maximum potential reservoir pressure is 13.4 ppg EMW; will be drilled using 8.9 ppg mud and MPD technique. Appr Date 37 Seismic analysis of shallow gas zones NA PKB 10/28/2015 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Onshore development lateral to be drilled. Geologic Engineering Public Commissioner: Date: CorDmissioner Date Commissioner Date 3V