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HomeMy WebLinkAbout213-156213-156: The Current Well Status was changed to EXPIR on the effective date of 10/28/2015. This change was performed by user MDG. Ferguson, Victoria L (DOA) From: Ferguson, Victoria L (DOA) Sent: Wednesday, December 18, 2013 2:16 PM To: 'Ohlinger, James Y Cc: Bettis, Patricia K (DOA) Subject: 2G-12AL1(PTD 213-156) Thanx James. That's fine. Please reply with a request to withdrawn 2G-12AL1(PTD 213-156) Victoria From: Ohlinger, James J [mailto:James.J.Ohlinger(@conocophillips.com) Sent: Wednesday, December 18, 2013 1:57 PM To: Ferguson, Victoria L (DOA) Subject: FW: 2G-12 completion report Ms. Ferguson — This email is to inform AOGCC that we will hold off sending in the completion report for the plugging operations for 2G-12 (sundry 313-479) until all the drilling of the laterals on 2G-12 have been completed. If you have any questions, please feel free to call James Ohlinger (265-1102). We have also submitted the PTD for the 2G-12AL3-01 today. At this point the 2G-12AL1 PTD will not be used. Thank you, James THE STATE Akasqkz 01i and, Gas- ®f `i� : Con GOVERNOR SEAN PARNELL 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Lamar Gantt CTD Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk Oil Pool, 2G-12AL1 ConocoPhillips Alaska, Inc. Permit No: 213-156 Surface Location: 303' FNL, 272' FWL, Sec. 5, T10N, R9E, UM Bottomhole Location: 1389' FNL, 774' FWL, Sec. 8, T10N, R9E, UM Dear Mr. Gantt: 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. 213-155, API No. 50- 21159-01-00. 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 a AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, a4 /?�L� Cathy P. oerster Chair, Commissioner DATED this ! d of October, 2013. RECEIVED STATE OF ALASKA OC 1 is 4 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL AOGCC 20 AAC 25.005 1a. Type of Work: 1 b Proposed Well Class: Development - Oil ❑ Service - Winj ❑ Single Zone a Drill ❑ Lateral ✓ 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 Single Well Bond No. 59-52-180 - 11. Well Name and Number: 2G-12AL1 ' 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 10800' , TVD: 5984' • 12. Field/Pool(s): Kuparuk River Field Kuparuk River Oil Pool 4a. Location of Well (Governmental Section): Surface: 303' FNL, 272' FWL, Sec. 5, T1 ON, R9E, UM . Top of Productive Horizon: 139' FNL, 1511' FWL, Sec. 8, T10N, R9E, UM Total Depth: 1389' FNL, 774' FWL, Sec. 8, T10N, R9E, UM 7. Property Designation (Lease Number): ADL 25667 8. Land Use Permit: 2588 13. Approximate Spud Date: 11/1/2013 9. Acres in Property: 2580--9Sot to1µelt3 14. Distance to Nearest Property: 3800' 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 508970 y- 5943285 Zone- 4 - 10. KB Elevation above MSL: 140 feet GL Elevation above MSL: 40 feet 15. Distance to Nearest Well Open to Same Pool: 2G-13 , 3425' 16. Deviated wells: Kickoff depth: Maximum Hole Angle: • 9800 ft. • 104° deg 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 4706 psig , Surface: 4091 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 1600' 9200' 6056' 10800' 5984' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 8167 Total Depth TVD (ft): 6622 Plugs (measured) none Effective Depth MD (ft): 1 7971' Effective Depth TVD (ft): 6446' Junk (measured) none Casing Length Size Cement Volume MD TVD Conductor/Structural 80, 161, 202 sx CS II 116' 116' Surface 2848' 9.625" 800 sx PF E, 250 sx PF C 2884' 2730' Intermediate Production 8019, 7" 330 sx Class G & 8053, 6517' Liner 250 sx PF C Perforation Depth MD (ft): 7582-7600, 7615-7654' 1 Perforation Depth TVD (ft): 6120-6135', 6148-6180' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Diverter Sketcl- ❑ Drilling Program ❑✓ Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Seabed Report ❑ Drilling Fluid Program ❑ 20 AAC 25.W requirements a 21. Verbal Approval: Commission Representative: 22. 1 hereby certify that the foregoing is true and correct. Printed Name Lamar Gantt Signature Date: Contact as�,rk,5-6097 Email Jason.Burke(c�conocophillips. com Title CTD Supervisor Phone: 265-6120 Date Commission Use Only Permit to Drill Number: 3 I S API Number: 50-0 `a9 _ a 159 _ Q — Q O Permit Approve)Tfoereother Date:&All� cover letter requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed met ane, gas hydrates, or gas contained in shales: Other: G fiG St �J`—U G' �S 7 Samples req'd: Yes ❑ No Mud log req'd: YesNo Q 1­12S measures: Yes © No ❑ Directional svy req'd: Yes Q No ❑ Spacing exception req'd: Yes ❑ No Z Inclination -only svy req'd: Yes ❑ No[ [ DAPPROVED BY THE Approved by: 014 COMMISSIONER COMMISSION Date: D - Z Form 10-401 (Re,/sed 10/2012) This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))(3�_ / Lam'/G/ZZ / / 3 G ConocoPhilli s p Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 10, 2013 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: RECEIVED OCT 14 2013 ConocoPhillips Alaska, Inc. hereby submits permit to drill applications for a quad lateral out of the Kuparuk Well 2G-12 using the coiled tubing drilling rig, Nabors CDR2-AC.The work is scheduled to begin in November 2013. The CTD objective will be to drill dual laterals (2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3), targeting the A sand intervals. It is our intention that the well will be produced for more than 30 days before it is returned to injection once again. Note that sundry 313- .�98'authorized plugging existing perforations. Attached to this application are thfollowing documents: — Permit to Drill Application Form for 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 — Detailed Summary of Operations — Directional Plans — Current Schematic — Proposed CTD Schematic If you have any questions or require additional information please contact me at 907-265-6097. Sincerely, ason Burke Coiled Tubing Drilling Engineer Kuparuk CTD Laterals NASORS ALASKA 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 CD`q Application for Permit to Drill Document 2AC 1. Well Name and Classification...........................................................................................................2 (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))......................................................................................................................2 2. Location Summary.............................................................................................................................2 (Requirements of 20 AAC 25.005(c)(2))......................................................................................................................................................2 3. Blowout Prevention Equipment Information...................................................................................2 (Requirements of 20 AAC 25.005(c)(3)).....................................................................................................................................................2 4. Drilling Hazards Information and Reservoir Pressure....................................................................2 (Requirements of 20 AAC 25.005(c)(4)).....................................................................................................................................................2 5. Procedure for Conducting Formation Integrity tests.....................................................................2 (Requirements of 20 AAC 25.005(c)(5))......................................................................................................................................................2 6. Casing and Cementing Program......................................................................................................3 (Requirements of 20 AAC 25.005(c)(6))......................................................................................................................................................3 7. Diverter System Information.............................................................................................................3 (Requirements of 20 AAC 25.005(c)(7))......................................................................................................................................................3 8. Drilling Fluids Program.....................................................................................................................3 (Requirements of 20 AAC 25.005(c)(8))......................................................................................................................................................3 9. Abnormally Pressured Formation Information...............................................................................4 (Requirements of 20 AAC 25.005(c)(9))......................................................................................................................................................4 10. Seismic Analysis................................................................................................................................4 (Requirements of 20 AAC 25.005(c)(10))................... ............................................................................ -......... ........................... ............... 4 11. Seabed Condition Analysis...............................................................................................................4 (Requirements of 20 AAC 25.005(c)(11))....................................................................................................................................................4 12. Evidence of Bonding.........................................................................................................................4 (Requirements of 20 AAC 25.005(c)(12))....................................................................................................................................................4 13. Proposed Drilling Program...............................................................................................................4 (Requirements of 20 AAC 25.005(c)(13))............................................................:.......................................................................................4 Summaryof Operations.................................................................................................................................................. 4 PressureDeployment of BHA.......................................................................................................................................... 6 LinerRunning.................................................................................................................................................................. 6 14. Disposal of Drilling Mud and Cuttings.............................................................................................7 (Requirements of 20 AAC 25.005(c)(14))....................................................................................................................................................7 15. Directional Plans for Intentionally Deviated Wells..........................................................................7 (Requirements of 20 AAC 25.050(b))..........................................................................................................................................................7 16. Quarter Mile Injection Review (for injection wells only).................................................................7 (Requirements of 20 AAC 25.402).............................................................................................................................................................. 7 17. Attachments.......................................................................................................................................7 Attachment 1: Directional Plans for 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3.......................................................... 7 Attachment 2: Current Well Schematic for 2G-12........................................................................................................... 7 Attachment 3: Proposed Well Schematic for 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3............................................ 7 Page 1 of 7 1 10/10/2013 PTD Application: 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) The proposed laterals described in this document are 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3. All of these laterals will be classified as "Service — Water Alternating Gas Injection" 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 the attached 10-401 form for surface and subsurface coordinates of the 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 laterals. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors 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 4706 psi in the 2G-10, the maximum potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 4091 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 2G-12, measured in August 2013, indicated a reservoir pressure of 3518 psi or /11.2 ppg equivalent mud -weight. The maximum down -hole pressure in the area is from the 2G-10 well of 4706 psi or 14.7 ppg equivalent. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) No specific gas zones will be drilled; gas injection has not been performed since 2009, so low probability of encountering gas Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) The largest, expected risk of hole problems in the 2G-12 laterals will be fluid losses due to lower reservoir pressure in the offset producing wells. 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 7 10/10/2013 PTD Application: 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 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 Name MD MD TVDSS TVDSS Liner Details 2G-12A 9800' 10800' 6028' 6010' 2%" 4.7#, L-80, ST-L slotted liner; anchored aluminum billet on top. 2G-12AL1 9200' 10800, 6056' 5983' 2%" 4.7#, L-80, ST-L slotted liner; anchored aluminum billet on to 2G-12AL2 7840' 11100, 6054' 6025' 2%" 4.7#, L-80, ST-L slotted liner; anchored aluminum billet on top 23/", 4.7#, L-80, ST-L slotted liner, 2G-12AL3 7500' 11100, 5890' 6003' deployment sleeve on top inside 3.5" tubing Existing Casing/Liner Information Category OD Weight ppf) Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.50 H-40 Welded 36' 116' 0' 110' 1640 630 Surface 9-5/8" 36.0 L-80 BTC 36' 2884' 0' 2725' 5120 2370 Casing 7" 26.0 J-55 BTC 34.4' 8053' 0' 6524' 4980 4330 Tubing 3 V 9.2 J-55 EUE-MOD 32' 7514' 0' 6071' 10160 10540 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 FloVis mud (9.8 ppg) — Drilling operations: Chloride -based Flo -Pro PowerVis mud (9.5 ppg). While this mud weight may not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. — Completion operations: 2G-12 does not contain a subsurface safety valve (SSSV). The well will be loaded with 12.2 ppg NaBr completion fluid in order to provide formation over -balance while running completions. — Emergency Kill Weight fluid: Two well bore volumes (-204 bbl) of at least 12.2 ppg emergency kill weight fluid will be within a short drive to the rig during drilling operations. Managed Pressure Drilling Practice Page 3 of 7 �; _ 10/10/2013 PTD Application: 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 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 the minimum of 11.8 ppg will be initially targeted at the window based on the recent static bottom -hole pressure. 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 2G-12A Window (7,580' MD, 6,126' TVD) Usinq MPD Pumps On 1.5 b m Pumps Off A -sand Formation Pressure 11.2 ) 3568 psi 3568 psi Mud Hydrostatic 9.5 p) 3026 psi 3026 psi Annular friction i.e. ECD, 0.080 si/ft) 606 psi 0 psi Mud + ECD Combined 3633 psi 3568 psi (no choke pressure) (overbalanced (underbalanced —65psi) —542psi) Target BHP at Window (11.8 p) 3759 psi 3759 psi Choke Pressure Required to Maintain 126 psi 733 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)) Summary of Operations Page 4 of 7 11 10/10/2013 PTD Application: 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 Background Well 2G-12 is a Kuparuk A -sand injection well equipped with 3'h" tubing and 7" production casing. Four proposed A -sand CTD laterals will help support producer 2G-11. Prior to drilling, the tubing will be punctured in the tubing tail and cement will be pumped to isolate existing A -sand perforations. This cement will also serve as a medium to drill a pilot hole and place a whip -stock in to mill a casing window; this has been approved with sundry number 313-479. A mechanical whip -stock will be placed in the cement pilot hole drilled in the 7" production casing for a planned kickoff point (7580' MD). The 2G-12A side track will exit through the 3-1/2" tubing at 7580' MD and will target the A4 sand southeast of the existing well with a 3220' lateral. The hole will be completed with a 2 %" slotted liner to the TD of 10,800' MD with an anchored aluminum billet at 9800' MD. The 2G-12AL1 lateral will kick off from the anchored aluminum billet at 9800' MD and will target the A5 sand southeast of the existing well with a 1000' lateral. The hole will be completed with a 2%" slotted liner to the TD of 10800' MD with an anchored aluminum billet at 9200' MD. The 2G-12AL2 lateral will kick off from the anchored aluminum billet at 9200' MD and will target the A4 sand south of the existing well with a 1900' lateral. The hole will be completed with a 2%" slotted liner to the TD of 11100' MD with an anchored aluminum billet at 7840' MD The 2G-12AL3 lateral will kick off from the anchored aluminum billet at 7840' MD and will target the A5 sand south of the existing well with a 3260' lateral. The hole will be completed with a 2%" slotted liner to the TD of 11100' MD with liner being ran back inside of the 3.5" tubing tail. Pre-CTD Work 1. RU Slickline. a. Drift and tag PBTD b. Obtain static bottom hole pressure, (SBHP) 2. RU Eline: Perforate tubing tail at 7505'-7507' RKB (2' of perfs) 3. RU coil: Mill out Cameo `D' nipple out at 7,502' MD Place cement in the 7" casing, squeeze off A sand existing perfs. 4. RU Slickline. Tag top of cement and pressure test. RD Slick -line. 5. Prep site for Nabors CDR2-AC, including setting BPV Ria Work 1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 2G-12A Sidetrack (A4 sand, south) a. Drill 2.80" high -side pilot hole through cement to 7,630' MD b. Drift pilot hole with whip -stock dummy c. Set whip -stock at 7,580' MD with high -side orientation. d. Mill 2.80" window at 7,580' MD. e. Drill 2.70" x 3" bi-center lateral to TD of 10,800' MD f. Run 2%" slotted liner with an aluminum billet from TD up to 9,800' MD 3. 2G-12AL1 Lateral (A5 sand, south) a. Kick off of the aluminum billet at 9,800' MD b. Drill 2.70" x 3" bi-center lateral to TD of 10,800' MD c. Run 2%" slotted liner with an aluminum billet from TD up to 9,200' MD 4. 2G-12AL2 Lateral (A4 sand, south) a. Kick off of the aluminum billet at 9,200' MD b. Drill 2.70" x 3" bi-center lateral to TD of 11,100' MD Page 5 of 7 10/10/2013 PTD Application: 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 c. Run 2%" slotted liner with an aluminum billet from TD up to 7,840' MD 5. 2G-12AL3 Lateral (A5 sand, south) a. Kick off of the aluminum billet at 7,840' MD b. Drill 2.70" x 3" bi-center lateral to TD of 11,100' MD c. Run 23/8" slotted liner from TD up to 7,500' MD, inside the 3'/z" tubing tail 6. Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV 2. Obtain static BHP. Install GLV (if needed). 3. Turn over to pre -production for less than 30 days 4. Return well to injection 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. Because of this, 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 slickline lubricator. 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 2G-12 CTD laterals will be displaced to an overbalancing fluid (12.2 ppg NaBr) 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 2'/" liner. Page 6 of 7 10/10/2013 PTD Application: 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AA 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). 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AA 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 2G-12A 3800 2G-12AL1 3800 2G-12AL2 3240 2G-12AL3 3240 — Distance to Nearest Well within Pool (heel measured to offset well) Lateral Name Distance Well 2G-12A 3425 2G-13 2G-12AL1 3425 2G-13 2G-12AL2 4100 2G-11 2G-12AL3 4100 2G-11 16. Quarter Mile Injection Review (for injection wells only) (Requirements of 20 AAC 25.402) There are no wells within a quarter mile of any of the planned laterals. 17. Attachments Attachment 1: Directional Plans for 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 Attachment 2: Current Well Schematic for 2G-12 Attachment 3: Proposed Well Schematic for 2G-12A, 2G-12AL1, 2G-12AL2 & 2G-12AL3 Page 7 of 7 10/10/2013 KUP 2G-12 Conoco`I' illips Aaska, klc. : HANGER, CONDUCTOR, 36-116 SAFETY VLV. Q 1,782 SURFACE 10.75-xg.625", 36-2.884 GAS LIFT, 7,429 PER. 7.471 PACKER, 7,485- NIPPLE. 7.502- SOS , 7.514- IPERF, 7,615-7,654 Well. Atkributes Max Angle & MD TO Wellbore AP11Wl Field Name 500292115900 KUPARUK RIVER UNIT Well Status INJ Incl (°) 48.45 MD (RKB) 3,000.00 Act Bim (ftKB) 8, 167.0 Comment H2S (ppm) SSSV: LOCKED OUT Date Annotation Last WO: End Date 2/11/1987 KB-Grd (it) 40.98 Rig Release Date 9/24/1984 Annotation Depth Last Tag: SLM (ftKB) 7,933.0 End Data 6111/2111 Annotation Rev Reason: WELL REVIEW Last Mod... End osborl 7/11/2012 Date _ Casing Strings Casing Description CONDUCTOR String 0... 16 String ID 15.062 ... Top (ftKB) Set 36.0 Depth If... 116.0 Set Depth (TVD)... String 116.0 Wt.. String... 62.50 H-40 String Top Thrd WELDED Casing Description SURFACE 10.75"xg.625" String 0... 95/8 String lD 8.921 ... Top(ftKB) Set 36.0 Depth If... 2,884.2 Set Depth (TVD) String 2,729.5 Wt... String... 36.00 L-80 String Top Thrd BTC Casing Description PRODUCTION String 0... 7 String ID 6.276 ... Top (ftKB) Set 34.4 Depth (f... 8,053.2 Set Depth (TVD) ... String 6,517.1 Wt... String 26.On ... J-55 String Top Thrd BTC Tubina Strings Tubing Description String 0... String1D ... Top(ftKB) Set Depth (f... Set Depth(TVD)... String Wt.. String... String Top Thrd TUBING 31/2 2.992 32.0 7,514.7 6,064.3 9.30 J-55 EUE8rdABMOD Com letion Details Top (ftKB) Top Depth (ND) (ftKB) Topincl (°) It.. Description Comment Noml... ID (in) 32.0 32.0 0.10 HANGER McEVOY TUBING HANGER 1,781.6 1,778.7 13.11 SAFETY VLV BAKER FVL SSSV (LOCKED OUT 1/3/1989) 7,471.5 6,028.4 34.31 PBR BAKER PBR w/SEAL ASSEMBLY 7,485.3 6,039.8 34.24 PACKER BAKER FHL PACKER 12992 7,502.4 6,054.1 34.12 NIPPLE CAMCO'D' NIPPLE 7,513.9 6,063.6 34.07 SOS BAKER SHEAR OUT SUB Perforations & Slots Top(ftKB) Btm(ftKB) Top (TVD) (ftKB) Bt. (TVD) (ftKB) Zone Data Shot Dens sh- Type Comment 7,582.0 7,600.01 6,120.0 6,134.9 A-5, 2G-12 11/1/1984 4.0 IPERF 4"Schlum. Casing 7,615.0 7,654.01 6,147.51 6,179.9 A-4, 2G-12 11/1/1984 4.0 IPERF 4" Schlum. Casing Notes: General & Safety End Date Annotation 6/12/2009 NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 Mandrel Details Sin Top (ftKB) Top Depth (TVD) (ftKB) ToPort Inc"l V) Make Model OD (in) 5ery Valve Type Latch Type Size (in) 7R0 Run (psi) Run Date Com... 11 7,428.81 5,993.3134.521 OTIS JUBX 1 1 1/2 GAS LIFT IDMYIRO-5 10.00010.0 2/19/1987 PRODUCTION TD. 8.167 O O Z O E 0 i0 o r V O @ N N O : @ O 2 N `` V O O t0 � $ 7F) -Q C j M E 2i 2i a n 00 C V U) aar`` aati11 J � W Vv C a1 t>L L 03 U w0 OU n U 01 at E NJ E S [0 0) U r) lL U (V (V (V N N Y Y N (V C7 Cl) Cl) CO O] M M Ile 0 L V+ Ll r U a� !� 0 cl 0 L a co ;t 00 co LL1 N ��_ �Ua r 1 e O O Lm N �� 10t N 000O J cS rn � � II II 7 I OCJF I� F w n I O •. II w a I I � J O N wUd G Q 0] o � 82 m Zo o o V >N Q Q O m II oN � it N 2N 11 v0 11 II II I _� II ° H6�i I� N 0 0 II II Ij Q Q 0 it II II N II \ \ J \ \ 11 II II II I I R I 0 LO Lo a N Lo O r W ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2G Pad 2G-12 2G-12AL1 Plan: 2G-12AL1 wp04 Standard Planning Report 09 October, 2013 BAKER NUGNES ConocoPhillips Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2G Pad Well: 2G-12 Wellbore: 2G-12AL1 Design: 2G-12AL 1 _wp04 Baker Hughes INTEQ Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2G-12 Mean Sea Level 2G-12 @ 140.00ft (2G-12) True Minimum Curvature Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Has BAKER HUGHES Site Kuparuk 2G Pad Site Position: Northing: 5,944,015.12ft Latitude: 70° 15' 29.733 N From: Map Easting: 508,649.96ft Longitude: 149° 55' 48.314 W Position Uncertainty: 0.00 ft Slot Radius: 0.000 in Grid Convergence: 0.07 ° Well 2G-12 Well Position +N/-S 0.00 ft Northing: 5,943,285.17 ft Latitude: 70° 15' 22.550 N +E/-W 0.00 ft Easting: 508,969.84 ft Longitude: 149° 55' 39.032 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00 ft Wellbore 2G-12AL1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°1 (nT) BG G M2012 12/1 /2013 15.26 79.86 57,346 Design 2G-12AL1_wp04 Audit Notes: Version: Phase: PLAN Tie On Depth: 9,800.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (ft) (ft) (ft) (I 0.00 0.00 0.00 175.29 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +Nl-S +E/-W Rate Rate Rate TFO (ft) (1 (°) (ft) (ft) (ft) (°/100ft) (°/100ft) (°/100ft) (°) Target 9,800.00 95.41 236.69 6,028.28-5,519.35 829.30 0.00 0.00 0.00 0.00 9,892.00 104.04 233.46 6,012.75-5,571.18 755.02 10.00 9.38 -3.51 340.00 9,962.00 103.94 226.25 5,995.81-5,614.94 703.14 10.00 -0.15 -10.30 270.00 10,112.00 89.80 221.17 5,977.90-5,722.35 600.60 10.00 -9.42 -3.39 200.00 10,512+00 89.21 181.17 5,981.50-6,087.82 459.08 10.00 -0.15 -10.00 269.00 10,662.00 89.70 166.18 5,982.94-6,236.47 475.56 10.00 0.33 -10.00 271.80 10,800.00 89.71 152.38 5,983.66-6,365.23 524.27 10.00 0.01 -10.00 270.00 1OW013 4:16:42PM Page 2 COMPASS 2003.16 Build 69 ✓ Baker Hughes INTEQ WE.■ ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox v16 Local Co-ordinate Reference: Well 2G-12 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2G-12 @ 140.00ft (2G-12) Site: Kuparuk 2G Pad North Reference: True Well: 2G-12 Survey Calculation Method: Minimum Curvature Wellbore: 2G-12AL1 Design: 2G-12AL1 _wp04 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (ft) (°) (I (ft) (ft) (ft) (ft) (°/100ft) (°) (ft) (ft) 9,800.00 95.41 236.69 6,028.28 -5,519.35 829.30 5,568.79 0.00 0.00 5,937,767.37 509,805.63 TIP/KOP 9,892.00 104.04 233.46 6,012.75 -5,571.18 755.02 5,614.35 10,00 -20.00 5,937,715.45 509,731.42 Start 10 dls 9,900.00 104.04 232.63 6,010.81 -5,575.84 748.82 5,618.49 10.00 -90.00 5,937,710.78 509,725.22 9,962.00 103.94 226.25 5,995.81 -5,614.94 703.14 5,653.71 10.00 -90.20 5,937,671.63 509,679.59 3 10,000.00 100.36 224.93 5,987.81 -5,640.94 676.61 5,677.44 10.00 -160.00 5,937,645.61 509,653.10 10,100.00 90.94 221.57 5,977.98 -5,713.35 608.53 5,744.02 10.00 -160.28 5,937,573.12 509,585.12 10,112.00 89.80 221.17 5,977.90 -5,722.35 600.60 5,752.34 10.00 -160.61 5,937,564.11 509,577.20 4 10,200.00 89.65 212.37 5,978.32 -5,792.78 547.98 5.818.21 10.00 -91.00 5,937,493.63 509,524.67 10,300.00 89.49 202.37 5,979.07 -5,881.47 502.07 5,902.83 10.00 -90.96 5,937,404.89 509,478.86 10,400.00 89.35 192.37 5,980.08 -5,976.78 472.26 5,995.38 10.00 -90.88 5,937,309.55 509,449.17 10,500.00 89.22 182.37 5,981.34 -6,075.82 459.45 6,093.03 10.00 -90.78 5,937,210.50 509,436.48 10,512.00 89.21 181.17 5,981.50 -6,087.82 459.08 6,104.96 10.00 -90.66 5,937,198.51 509,436.12 5 10,600.00 89.49 172.37 5,982.51 -6,175.59 464.03 6,192.83 10.00 -88.20 5,937,110.76 509,441.17 10,662.00 89.70 166.18 5,982.94 -6,236.47 475.56 6,254.46 10.00 -88.10 5,937,049.89 509,452.78 6 10.700.00 89.70 162.38 5,983.14 -6,273.04 485.85 6,291.75 10.00 -90.00 5,937,013.34 509,463.11 10,800.00 89.71 152.38 5,983.66 -6,365.23 524.27 6,386.78 10.00 -89.98 5,936,921.20 509,501.64 Planned TD at 10800.00 10/9/2013 4:16:42PM Page 3 COMPASS 2003.16 Build 69 Baker Hughes INTEQ MAP.. ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk2G Pad Well: 2G-12 Wellbore: 2G-12AL1 Design: 2G-12AL1_wp04 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2G-12 Mean Sea Level 2G-12 @ 140.00ft (2G-12) True Minimum Curvature Targets Target Name hittmiss target Dip Angle Dip Dir. TVD +Nl-S +E/-W Northing Easting Shape (°) (°) (ft) (ft) (ft) (ft) (ft) Latitude Longitude 2G-12AL1_T3 0.00 0.00 5,978.00 -7,328.231,140,747.21 5,937,316,00 1,649,611.00 70' 0' 7.774 N 140' 47' 31.337 W plan hits target center Point 2G-12 CTD Polygon_WE 0.00 0.00 0.00 -6,439.851,140,503.25 5,938,204.00 1,649,366.00 70° 0' 16.759 N 140' 47' 34.450 W plan hits target center Polygon Point 1 0.00 -6,439.851,140,503.25 5,938,204.00 1,649,366.00 Point 0.00 -6,705.611,141,144.01 5,937,939.03 1,650,007.01 Point 0.00 -9,579.561,140,851.71 5,935,065.02 1,649,718.16 Point 0.00 -9,446.841,140,225.79 5,935,196.98 1,649,092.15 Point 0.00 -6,439.851,140,503.25 5,938,204.00 1,649,366.00 2G-12A_Fault 2—North 0.00 0.00 0.00 -5,548.661,141,254.38 5,939,096.00 1,650,116.00 700 0' 24.310 N 140' 47' 9.313 W plan hits target center Rectangle (sides W300.00 H1.00 D0.00) 2G-12 CTD Polygon_Ea 0.00 0.00 0.00 -5,343.661,141,273.63 5,939,301.00 1,650,135.00 70' 0' 26.272 N 140' 47' 7.887 W plan hits target center Polygon Point 1 0.00 -5,343.661,141,273.63 5,939,301.00 1,650,135.00 Point 0.00 -9,667.611,140,851.66 5,934,976.98 1,649,718.22 Point 0.00 -9,580.341,141,498.82 5,935,065.01 1,650,365.21 Point 0.00 -5,443.241,141,777.57 5,939,202.03 1,650,639.01 Point 0.00 -5,343.661,141,273.63 5,939,301.00 1,650,135.00 2G-12AL1_T1 0.00 0.00 6,028.00 -7,126.481,140,974.48 5,937,518.00 1,649,838.00 70° 0' 9.400 N 140° 47' 24.024 W plan hits target center Point 2G-12A_Fault 6 0.00 0.00 0.00 -6,713.951,141,406.01 plan hits target center Rectangle (sides W555.00 H1.00 D0.00) 2G-12AL1 T2 0.00 0.00 6,004.00 -7,199.371,140,875.38 plan hits target center Point 2G-12A_Fault 2_South 0.00 0.00 0.00 -7,046.641,141,110.59 plan hits target center Rectangle (sides W300.00 H1.00 D0.00) 2G-12AL1_T4 0.00 0.00 5,983.00 -7,972.201,140,669.44 plan hits target center Point Casing Points 5,937,931.00 1,650,269.00 70' 0' 12.772 N 140° 47' 10.011 W 5,937,445.00 1,649,739.00 70° 0' 8.837 N 140° 47' 27.148 W 5,937,598.00 1,649,974.00 70° 0' 9.975 N 140° 47' 19.820 W 5,936,672.00 1,649,534.00 70° 0' 1.635 N 140° 47' 36.304 W Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (in) (in) 2,884.00 2,584.97 9 5/8" 9.625 12.250 10,800.00 5,983.66 2 3/8" 2.375 3.000 101912013 4:16.42PM Page 4 COMPASS 2003.16 Build 69 Baker Hughes INTEQ Fur a9 ConocoPhillips Planning Report BMER HUGHES Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 2G Pad Well: 2G-12 Wellbore: 2G-12AL1 Design: 2G-12AL 1 _wp04 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 2G-12 Mean Sea Level 2G-12 @ 140.00ft (2G-12) True Minimum Curvature Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/S +E/-W (ft) (ft) (ft) (ft) Comment 9,800.00 6,028.28 -5,519.35 829.30 TIP/KOP 9,892.00 6,012.75 -5,571.18 755.02 Start 10 dls 9,962.00 5,995.81 -5,614.94 703.14 3 10,112.00 5.977.90 -5,722.35 600.60 4 10,512.00 5,981.50 -6,087.82 459.08 5 10,662.00 5,982.94 -6,236.47 475.56 6 10,800.00 5,983.66 -6,365.23 524.27 Planned TD at 10800.00 10/9/2013 4:16:42PM Page 5 COMPASS 2003.16 Build 69 Baker Hughes INTEQ MAP .r ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 2G Pad Site Error: 0.00ft Reference Well: 2G-12 Well Error: 0.00ft Reference Wellbore 2G-12AL1 Reference Design: 2G-12AL1_wp04 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 2G-12 2G-12 @ 140.O0ft (2G-12) 2G-12 @ 140.00ft (2G-12) True Minimum Curvature 1.00 sigma EDM Alaska Prod 06 Offset Datum Reference 2G-12AL1_wp04 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00ft Error Model: ISCWSA Depth Range: 9,800.00 to 10,800.00ft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,266.00ft Error Surface: Elliptical Conic Survey Tool Program Date 10/9/2013 From To (ft) (ft) Survey (Wellbore) Tool Name Description 150.00 7,500.00 2G-12 GyroData (2G-1 2) GYD-CT-CMS Gyrodata cont.casing m/s 7,500,00 9,800.00 2G-12A_wp06 (2G-12A) MWD MWD - Standard 9,800.00 10,800.00 2G-12AL1 wp04 (2G-12AL1) MWD MWD - Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name 2,884.00 2,724.97 9 5/8" 9-5/8 12-1/4 10,600.00 6,123.66 2 3/8" 2-3/8 3 Summary Site Name Offset Well - Wellbore - Design Kuparuk 2G Pad 2G-12 - 2G-12A - 2G-12A_wp06 2G-12 - 2G-12AL2 - 2G-12AL2_wp03 2G-12 - 2G-12AL3 - 2G-12AL3_wp02 2G-13 - 2G-13 - 2G-13 Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Depth Depth Distance (ft) from Plan (ft) (ft) (ft) (ft) 9,824.98 9,825.00 0.59 1.58 -0.38 FAIL - Major Risk 9,824.56 10,075.00 512.04 70.48 444.84 Pass - Major Risk 9,819.85 10,200.00 687.61 94.41 595.63 Pass - Major Risk Out of range CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 101912013 9:37.56AM Page 2 of 6 COMPASS 2003.16 Build 69 ( ;A to ^S 0 c V ) � \ d 2 . ) ) § (ut/U k 9u oN/(- S§ *Sg5§§25 15 GG � ,»sasses -| R°k2R@6R $d))d$»5 \, 8 ! / �R k ) +@&&N&A k ;! egr&mmm« $§ §@asa§@q _;m _. ( /)j gt,) qidoa 1 *3 o I k TRANSMITTAL LETTER CHECKLIST WELL NAME: 9RU- 2G-I? AL,( PTD: 213/SG Development ✓ Service Exploratory Stratigraphic Test _ Non -Conventional FIELD: I U-06J-4C Rt'UhJr POOL: 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. 13)5S API No. 50-oV - 9.11E9 -61- 00. (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are Well Logging rn also required for this well: 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 5/2013 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 PTD#:2131560 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Well Name: KUPARUK RIV UNIT 2G-12AL1 Program SER Well bore seg 41 SER / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal Administration 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025667, entire wellbore 3 Unique well name and number Yes KRU 2G-12AL1 4 Well located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order 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 where 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 10/16/2013 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For Yes Area Injection Order No. 2B-Kuparuk River Unit 15 All wells within 1/4 mile area of review identified (For service well only) Yes 2G-12, 2G-12A 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) Yes 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA 18 Conductor string provided Engineering 19 Surface casing protects all known USDWs 20 CMT vol adequate to circulate on conductor & surf csg 21 CMT vol adequate to tie-in long string to surf csg 22 CMT -will cover all known productive horizons 23 Casing designs adequate for C, T, B & permafrost 24 Adequate tankage or reserve pit 25 If a re -drill, has a 10-403 for abandonment been approved 26 Adequate wellbore separation_ proposed 27 -If-diverter required, does it meet regulations- Appr Date 28 Drilling fluid_ program schematic & equip list adequate VLF 10/22/2013 29 BOPEs, do they meet regulation 30 BOPE press rating appropriate; test to (put psig in comments) 31 Choke manifold complies w/API RP-53 (May 84) 32 Work will occur without operation shutdown 33 Is presence of H2S gas probable 34 Mechanical_ condition of wells within AOR verified (For service well only) 35 Permit can be issued w/o hydrogen sulfide measures Geology 36 Data presented on potential overpressure zones Appr Date 37 Seismic_analysis of shallow gas zones PKB 10/16/2013 38 Seabed condition survey (if off -shore) 39 Contact name/phone for weekly -progress reports [exploratory only] NA NA NA NA No Yes Yes No Yes NA Yes Yes Yes Yes Yes Yes H2S measures required Yes No wells within a quarter mile radius No Wells_on 2G-Pad are H2S-bearing. H2S measures_ required. Yes Expected reservoir pressure is 11.2 ppg EMW, but may range to 14.7 ppg; will be drilled using 9.5 ppg mud and NA_ managed pressure drilling_ technique. Two wellbore volumes of at least 12.2 kill -weight mud will be available. NA NA Onshore service well. Geologic Engineering Public Commissioner: Date: C ssioner Date loner Date ��S [a z5I � f lv'�'� e6-ZF-4f Conductor set in KRU 2G-12 Surface casing set in KRU 2G-12 Surface casing set and fully cemented Productive interval will be completed with slotted liner Rig has steel tanks; all waste to approved disposal wells Anti -collision report generated; no major risk failures Max formation pressure is 4706 psi(14.7 ppg EMW); will dirll w/ 9.5 ppg EMW and MPD to maintain constant BHP MPSP is 4091 psi; BOPs tested to 4500 psi