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Home My WebLink About214-051Guhl, Meredith D (DOA) From: Kuck Marc <marc.kuck@enipetroleum.com> Sent: Wednesday, March 01, 2017 2:33 PM To: Guhl, Meredith D (DOA) Cc: Chaudhry Amjad Subject: RE: Expired Permits to Drill Meredith, Thanks for the update on these permits. We currently don't have any plans to perform this work in the future. Regards, Marc From: Guhl, Meredith D (DOA)[mailto:meredith.guhl@alaska.gov] Sent: Wednesday, March 01, 2017 2:21 PM To: Kuck Marc Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: Expired Permits to Drill Hello Marc, You already saw this in Joshua's email, but just to make sure it's clear, I thought I'd send it to you directly. Permit to Drill 214-051, for OPI 1A 106, issued 15 April 2014 and permit to drill 214-183, for OP17-02 L1, issued 19 November 2014, have expired under Regulation 20 AAC 25.005 (g). The PTDs will be marked expired in the AOGCC database. 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. This message may contain information cnat is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. THE STATE GOVEIRNOR SEAN PARN1=LL Davide Simeone `w'eii Operation Project Manager ENI US Operating Co. Inc. 3800 Centerpoint Drive, Suite 300 Anchorage, AK 99503 333 Wes! Seventh Avenue Anchorage, Alaska. 99KI-3572 Morn: 907.279.1433 Re: Nikaitchuq Field, Schrader Bluff Oil Pool, OPI lA 106 ENI US Operating Co. Inc. Permit No: 214-051 Surface Location: 3228' FSL, 1519' FEL, SEC. 5, T13N, R9E, UM Bottomhole Location: 4005' FSL, 401' FEL, SEC. 28, T14N, R9E, UM Dear Mr. Simeone: Enclosed is the approved application for permit to redrill the above referenced service well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P Foerster Chair DATED this �s day of April, 2014. RECEIVED STATE OF ALASKA ALr%SKA OIL AND GAS CONSERVATION COMMIS.,iON PERMIT TO DRILL 11h 20 AAC 25.005 APR 0 8 2014 AOGCC 1 a. Type of Work: 1 b. Proposed Well Class: Development -Oil ❑ Service - Winj ❑✓ . Single Zone 1 c. Specify if well is proposed for: Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development - Gas ElService - Supply ElMultiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redrill Reentry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11. Well Name and Number: ENI US Operating CO. Inc. Bond no: RLB0008627 OPI 1A 106 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive Suite 300, Anchorage 99503 MD: 18630' TVD: 4040 Nikaitchuq/Schrader Bluff, 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 3228 FSL, 1519 FEL, S5 T13N R9E UM ADL 0390615,0355024,373301 i35.SOa3 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 517 FSL 401 FEL S33 T14N R9E UM ADL 417493 5/17/2014 Total Depth: 9. Acres in Propertv: ?/4J3 14. Distance to Nearest Propertv: 4005 FSL, 401 FEL, S28 T14N R9E UM 375� ;?O1 415' to unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 54.1 feet 15. Distance to Nearest Well Open Surface: x- 516,761' - y- 6,036,581' - Zone- 4 r GL Elevation above MSL: 13.1 feet • to Same Pool: 1300' to OP05-06 16. Deviated wells: Kickoff depth: 209'- /50 feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: q[-89-degrees Downhole: 1818 • Surface: 1374 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 16" 65 X-65 Welded 76 36 36 76 76 pre -installed 16" 13 3/8" 68 L-80 BTC 2756 35 35 2791 2400 LEAD: 495.7 bbls 10.7 ppg ASL TAIL: 62.5 bbls 12.5 ppg DeepCrete 12 1/4" 9 5/8" 47 L-80 Hydril 563 9824 33 33 9857 3756 288.8 bbls 12.5 ppg DeepCRETE 8 3/4" 2' y 11.6 L-80 Hydril 521 1 8973 1 9657 1 3700 1 18630 1 4040 Liner in open hole 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural 76' 16" 76' 76' s... 4f Perforation Depth MD (ft): IPerforation Depth TVD (ft): 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Program ❑✓ Time v. Depth Plot ❑ Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑ 20 AAC 25.050 requirements El 21. Verbal Approval: Commission Representative: Date 12/3/2013 22. 1 hereby certify that the foregoing is true and correct. Lara Occhionero 907 865 3323 Contact Email Lara.occhionero(a)enipetroleum.com Printed Name Davide Si eone Title Well Operation Project Manager Signature rp� Phone 907 865 3320 Date 10/9/2013 Commission Use Only Permit to Dri11 I fyer - Permit Approval See cover letter for other Number: ��tJ� 50-0a�_�33ay _p( -v0 Date: I� / requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane gas hydrates, or gas contained in shales: No Other: 3Ci1� 5� e � �s •J(�CJ �✓ Samples req'd: Yes ❑ 7� Mud log req'd: Yes No n �( * !.t i(: t n .ci Uy �e^� t`' 111 4 L c o r HZS measures: Yes ❑ No [✓ Directional svy req'd: Yes No ❑ r� Inclination y Spacing exception req'd: Yes L✓J No ❑ -only svy req'd: Yes ❑ No s;� P L c e-cJ (T-IP APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: - >/ ^ I`� Submit Form and �pv{1�1 Form 10- 1 (Revised 10/ 012) (� Thi p r t t from the ai � f a (ro (20 AAC 25.005(g)) Attachments in Duplicate t � 4� Einli PoWtirolleuim 3800 Centerpoint Drive Suite 300 Anchorage, Alaska 99503 Davide Simeone Phone (907) 865-3320 Email: Davide.Simeone@enipetroleum.com April 4, 2014 Alaska Oil and Gas Conservation Commission 333 West 7 h Avenue, Suite 100 Anchorage, Alaska 99501 RE: Application for Permit to Drill OP I1A I06 RECEIVED APR 0 8 2014 AOGCC Dear Commissioners, S Eni US Operating Co. Inc. hereby applies for a Permit to Drill (Sidetrack the temporary abandoned Well OP I1) for the Onshore Producer well OP I 1 A I06. This well will be drilled/sidetracked and completed using Nabors rig 245. The planned spud date is 5/22/2014. The proposed plan is to cut and retrieve the existing the 10 1/4" csg from the abandoned original well, spot a cement plug and then sidetrack the new well. An horizontal wellbore will undulates between the OA, OA2, and OA3 sands to a final depth of 18,630'MD ( 4040 TVD). 4 ''/z" slotted liner will be run into the open hole. Please find attached for review the Commission's forms 10-401, the information required by 20 ACC 25.005. If you have any questions or require further information, please contact Lara Occhionero 907 865 3323. Davide Well 0 Project Manager r� Ein! Mdurolleum 2 n j Application for Permit to Drill OP 11A 106 Saved: 4-Apr-14 Application for Permit to Drill Document Producer Well OP I1A I06 Table of Contents 1. Well Name............................................................................................................... 3 Requirements of 20 AAC 25.005(f)........................................................................................................ 3 2. Location Summary................................................................................................. 3 Requirements of 20 AAC 25.005(c)(2)................................................................................................... 3 Please see Attachment 7: Surface Platt.................................................................................................. 3 Requirements of 20 AAC 25.050(b)........................................................................................................ 3 3. Blowout Prevention Equipment Information.................................................... 4 Requirements of 20 AAC 25.005(c)(3)................................................................................................... 4 4. Drilling Hazards Information............................................................................... 4 Requirements of 20 AAC 25.005 (c)(4).................................................................................................. 4 S. Procedure for Conducting Formation Integrity Tests ...................................... 4 Requirements of 20 AAC 25.005 (c)(5).................................................................................................. 4 6. Casing and Cementing Program.......................................................................... 5 Requirements of 20 AAC 25.005(c)(6)................................................................................................... 5 7. Diverter System Information............................................................................... 5 Requirements of 20 AAC 25.005(c)(7)................................................................................................... 5 8. Drilling Fluid Program........................................................................................... 6 Requirements of 20 AAC 25.005(c)(8)................................................................................................... 6 Lateral Mud Program.............................................................................. Error! Bookmark not defined. (MI FazePro Mineral Oil Base)................................................................ Error! Bookmark not defined. 9. Abnormally Pressured Formation Information ................................................. 7 Requirements of 20 AAC 25.005 (c)(9).................................................................................................. 7 10. Seismic Analysis............................................................................................... 7 Requirements of 20 AAC 25.005 (c)(10)................................................................................................ 7 11. Seabed Condition Analysis............................................................................. 7 AOGCC PERMIT Document Page 1 of 8 Printed: 4-Apr-14 Eini PWturolleum 1'0 eno Application for Permit to Drill OP 11A 106 Saved: 4-Apr-14 Requirements of 20 AAC 25.005 (c)(11)................................................................................................ 7 12. Evidence of Bonding........................................................................................ 7 Requirements of 20 AAC 25.005 (c)(12)................................................................................................ 7 13. Proposed Drilling Program............................................................................. 7 Requirements of 20 AAC 25.005 (c)(13)................................................................................................ 7 14. Discussion of Mud and Cuttings Disposal and Annular Disposal ............. 7 Requirements of 20 AAC 25.005 (c)(14)................................................................................................ 7 15. Attachments..................................................................................................... 8 Attachment 1 Drilling Procedure............................................................................................................. 8 Attachment2 Directional Plan................................................................................................................ 8 Attachment 3 Drilling Hazards Summary................................................................................................ 8 Attachment 4 BOP and Diverter Configuration....................................................................................... 8 Attachment 5 Cement Loads and CemCADE Summary.......................................................................... 8 Attachment 6 Formation Integrity And Leak Off Test Procedure........................................................... 8 Attachment7 Surface Platt..................................................................................................................... 8 Attachment 8 Casing Design Program.................................................................................................... 8 AOGCC PERMIT Document Page 2 of 8 Printed. 4-Apr-14 Ein! PDWtardleuim 2nn Application for Permit to Drill OP 11A 106 Saved: 4-Apr-14 1. Well Name Requirements of 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. Well Name: OP05-061-1 2. Location Summary Requirements of 20 AAC 25.005(c)(2) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (2) a plat identifying the property and the property's owners and showing (A)the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines. (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth; Location at Surface 3228 FSL 1519 FEL S5 T13N R9E UM ASP Zone 4 NAD 27 Coordinates Northing: 6,036,581' Easting:516,761' RKB Elevation 54.1' AMSL Pad Elevation 13.1' AMSL Location at Top of Productive Interval 517 FSL 401 FEL S33 T14N R9E UM "OA" Sand ASP Zone 4 NAD 27 Coordinates Measured Depth, RKB: 9 857.28' Northing:6,039,165.41' Easting: 523,144.55 Total Vertical De th RKB: 3 810.30' Total Vertical Depth, SS.- 3 756.2' Location at Total Depth 4005 FSL 401 FEL S28 T14N R9E UM ASP Zone 4 NAD 27 Coordinates Northing: 6, 047, 933' Easting.• 523, 099' Measured Depth, RKB: 18.630' Total Vertical Depth, RKB: 4 040' Total Vertical Depth, SS.• 3 985.9' Please see Attachment 7.• Surface Platt and (D) other information required by 20 AAC 25.050(b); Requirements of 20 AAC 25.050(b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; Please see Attachment 2: Directional Plan and (2) for all wells within 200 feet of the proposed wellbore (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The Applicant is the only affected owner. AOGCC PERMIT Document Page 3 of 8 Printed: 4-Apr-14 Einli PWturdleum eno Application for Permit to Drill OP 11A 106 Saved: 4-Apr-14 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commisslon and identified in the application: (3) a diagram and description of the blowout prevention equipment (ROPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25, 037 as anplirahle; Please see Attachment 4: BOP and Diverter Configuration 4. Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (4) information on on ing hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a methane gradlent,• The expected reservoir pressure in the Schrader Bluff sand is 0.45 psi/ft, or 8.6 ppg EMW (equivalent mud weight). The maximum potential surface pressure (MPSP) based on the above expected pressure gradient, a methane gradient (0.11), and the planned vertical depth of the OA sand formation is: MPSP = (4040' TVDss)(0.45 - 0.11 psi/ft) = 1374 psi (B) data on potential gas zones; The well bore is not expected to penetrate any gas zones. and (C) data concerning potential causes of hole problems such as abnormally geo pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Attachment 2: Drilling Hazards Summary. 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (5) a description of the ororedure for conductino formation integrity tests, as required under 20 AAC 25.030(17; Please see Attachment 6: Formation Integrity And Leak Off Test Procedure AOGCC PERMIT Document Page 4 of 8 Printed: 4-Apr-14 • Einli PWturolleuinn 2nn Application for Permit to Drill OP 11A 106 Saved: 4-Apr-14 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (6) a complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre - perforated liner, or screen to be installed,• Casing and Cementing Program See also Attachment 4: Cement Summary Hole Top Btm CsgjTbg size Weight Length MD/7YD MDITVD OD in in lb ft Grade Connection 6AV ft (ft) Cement Program 16" Driven 65 X-65 Welded 76 36 / 36 76'/ 76' Pre -Installed LEAD:495.7 bbls 10.7 ppg ASL 13-3/8 16 68 L-80 BTC 2,756' 35 / 35 2,791' /2,400" TAIL: 62.5bbls 12.5 ppg DeepCrete 9-5/8 12-1/4 40 L-80 Hydril 563 9,280' 33 / 33 9857/3,756' 288.8 bbls 12.5 ppg DeepCrete 4-1/2 8-3/4" OA Sand 111.6 L-80 Hydril521 8,973' 9,657/3,700' 18,630'/4,040' New Liner in Open Hole - no Lateral cement 7. Diverter System Information Requirements of 20 AAC 25.005(c)(7) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (7) a diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Please see Attachment 4: BOP and Diverter Configuration. AOGCC PERMIT Document Page 5 of 8 Printed: 4-Apr-14 Ein! Natrolleuum eno Application for Permit to Drill OP 11A 106 Saved: 4-Apr-14 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (8) a drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling will be done with muds having the following properties over the listed intervals: Surface Hole Mud Program (extended bentonite) Spud to Base of Permafrost Base of Permafrost to Casing Point Initial Value Final Value Initial Value Final Value Density 8.8 9.2 9.2 9.5 Funnel Viscosity 150 250 200 300 seconds Yield Point 50 70 30 50 lb/100 s Plastic Viscostiy 30 55 15 20 CP H 9.0 9.5 9.0 9.5 API Filtrate NC 8.0 8.0 8.0 cc / 30 min Intermediate Hole Mud Program (LSND) 13-3/8" Cs Shoe to 9-5/8" Cs Point Value Density 8.8 - 9.5 Funnel Viscosity 45 - 60 seconds Plastic Viscostiy 12 - 18 CP Yield Point 18-24 lb/100 s AP1 Filtrate 4-6 cc / 30 min Chlorides m /l <500 H 9.0 - 10.0 MST < 18.0 Lateral Mud Program MI FazePro Mineral Oil Base Blue Density 8.7 - 9. Plastic Viscostiy - 25 CP Yield Point 15 - 20 lb 100 s HTHP Fluid loss (m1/30 min @a <5.0 200 si & 100°F Oil / Water 60 / 40 Ratio Electrical >600 Stability Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. AOGCC PERMIT Document Page 6 of 8 Printed. 4-Apr-14 O` enn-• Einli Petirolleuiinn Application for Permit to Drill OP 11 A 106 Saved: 4-Apr-14 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (9) for an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); Not applicable: Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (10) for an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25. 061(a), Not applicable: Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (11) for a well drilled from an offshore platform, mobile bottom -founded structure, lack -up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); Not applicable: Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (12) evidence showing that the requirements of 20 AAC 25.025 {Bonding}have been met; Evidence of bonding for ENI is on file with the Commission. 13. Proposed Drilling Program Requirements of 20 AAC 25.005 (c)(13) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: Please refer also to Attachment 1— Drilling Procedure 14. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (14) a general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well.; AOGCC PERMIT Document Page 7 of 8 Printed: 4-Apr-14 Einli Nntrolleunn eno Application for Permit to Drill OP 11A 106 Saved: 4-Apr-14 Waste fluids generated during the drilling process will be disposed of by injection down an Oliktok Point or Oliktok Point Class I disposal well. Alternative disposal method will include hauling the fluids to the Prudhoe Bay Grind and Inject Facility. 15. Attachments Attachment 1 Drilling Procedure Attachment 2 Directional Plan Attachment 3 Drilling Hazards Summary Attachment 4 BOP and Diverter Configuration Attachment 5 Cement Loads and CemCADE Summary Attachment 6 Formation Integrity And Leak Off Test Procedure Attachment 7 Surface Platt Attachment 8 Casing Design Program AOGCC PERMIT Document Page 8 of 8 Printed: 4-Apr-14 2no us operraring WELLT- OP-11 A Drilling and Completion Well Plan OP-IIA-106 Oliktok Point Conductor slot #1 Injector (Schrader Bluff) Nikaitchuq Project Revision Prepared Reviewed Approved Date ----------------- Lara Occhionero Maugeri Giuseppe ----------------- James Wright ----------------- Nelson Carballo --------- ------- Davide Simeone ----------------- Guido Tentori 0120-07 Drilling & Completion Well Plan Page 1 of 47 04/04/14 eni us werrarin LIN= OP-IIA-106 Oliktok Point Nikaitchuq Field North eni petro8eum Slope - Alaska OP-I1A-106 DIR / LWD FORM DEPTH HOLE I CASING MUD IWO MID TW MWD SIZE SPECS INFO Cement to Surface 16" (15.25" d) Hole Angle X-65 0° 16" Conductor Shoe 76' 76' o Rat hole Welded WA Pre -Drilling Works Remove 500' of 10 3/4" KOP: 300' N Surface Csa Replace Weflhead 13-3/8" DLS 4-6 deg/100 ft a Install 16" to 20" Swedge 0 68# MW (ppg) Cement Plug to 500' Mud Motor B/Permafrost 1,890' 1,730' L-80, 8TC 8.8 - 9.5 GR / Res w Dir / PWD Top of Tail 2,291' 2,102' Wellbore Stability Lost Circulation 14-3/4" -bit Hole Cleaning 16" UR Casing Sections Flole Angle 55.00 Deg 13-3/8" 2 791' 2,400' 16" 50' F WBM GR/RES/PWD Inter. Casino Wellbore Stability 9-5/8" Lost Circulation Xceed 900 40 # MW (ppg) Hole Cleaning L-80, Hydnl 563 8.8 - 9.5 Torque & Drag Casing Sections Tangent Angle: Casing Wear 78.41 Deg BHA Expense IntemediateTOC 6,686' 3,480' Pick-up Top of Sand NTop 7,686' 3,520' Injection Packer 9,520' 3,760' Hole Angle TOL 9,657' 3,700' 87.00 Deg 9-5/8" 9,857' 3,756' 1 12.25" 85` F WBM GR / RFS / EcoSCOPE/ PWD / I I Wellbore Stability I I Lost Circulation Li— r Hole Cleaning I I 4-1/2" Torque & Drag n; 11.6 # MW (Ppg) Casing Sections Xceed 675 m L-80, Hydril 521 8.7 - 9.4 Casing Wear a L — I I I I I I I I I I BFIA Expense Hole Angle I I I I I I I I I I --� 98.00 Deg 4-1/2" Liner 18,630' 4,040' 8-3/4" 85" F MOBM OP-IIA-106 Drilling & Completion Well Plan Page 2 of 47 04/04/14 1 ;owl -- -F e n i us operrfing WELL OP-I1 A-106 Table of Contents WELLPLAN SUMMARY .............................................................................................................................................................4 PR E D R I LLI N G WORKS...............................................................................................................................................................6 16' SURFACE HOLE SECTION (14-3/4' to 16" UR)....................................................................................•---....8 SurfaceDrilling.................................................................................................................9 SurfaceCasing................................................................................................................ 12 SurfaceCementing......................................................................................................... 15 12-1 /4' INTERMEDIATE HOLE SECTION................................................................................................................. 17 Pick Up Intermediate Drilling Assembly....................................................................... 18 IntermediateDrilling....................................................................................................... 21 IntermediateCasing....................................................................................................... 22 IntermediateCementing................................................................................................. 28 8-3/4' PRODUCTION HOLE SECTION.......................................................................................................................31 Pick Up Production Drilling Assembly..........................................................................32 ProductionDrilling......................................................................................................... 34 ProductionLiner.............................................................................................................35 COMPLETIONSECTION ........................................................................................................................................................ 38 4-1 /2' Injector Completion String................................................................................. 38 Completion Schematic: ....................................................... Error! Bookmark not defined. Injector Completion Assembly:...........................................Error! Bookmark not defined. RunningProcedures: ...................................................................................................... 39 ATTACHMENTS...................................................................................................................Error! Bookmark not defined. RecommendedDrilling Practices..................................................................................41 Health, Safety & Environment.......................................................................................42 SafetyMeeting Topics.................................................................................................... 43 Well Shut In Procedure While Running Production Tubing ........................................ 45 Conductor Broach - Contingency Cementing Plan ..................................................... 46 TAM PORT COLLAR Utilization Decision Tree............................................................ 47 OP-IIA-106 Drilling & Completion Well Plan Page 3 of 47 04/04/14 G • eni us © errafinn WELL I OP-I1 A-106 WELL PLAN SUMMARY Rig: 245E Type of Well: Injector Well Design: 13-3/8' Surface x 9-5/8' Intermediate x 4-1 /2' Liner Completion Design: Blank Liner with 4-1 /2' ICD's with PHL Injection Packer AFE Number: Drilling: XXXX Completion: XXXX APD Permit to Drill: xxx API*: xxx Casing Setting Methods 13-3/8' 68# L80 BTC Conventional: Set on Mandrel Hanger. 9-5/8' 40# L80 H dril 563 Unconventional: Float Rotate & Torque Turn - Set on Emergency Slips. 5-1 /2' 15.5# L80 HiAdril 521 Conventional: SLZXP Liner Packer. Diverter Requirements 16' Surface Hole Section I Will be required Well Histortt Close Approach and Offset Well Interception Risks It is important to stay as close as practical to the planned directional program. The directional program and a summary of close approaches can be found in the attachments. These close approaches will be in conformance with the minimum well separation criteria detailed by the Drilling Anti -Collision Analysis and Close Approach Guidelines. It is the responsibility of the Directional Driller and the Drilling Supervisor to ensure that the directional plan is executed as planned, that the position of the well as it is drilled is monitored on an anti -collision diagram and that no tolerance line for close approach wells is crossed. It is important that the well bore remains close to the planned well path as any major deviations from the profile may adversely affect the ability to drill future wells and still adhere to the current close crossing guidelines. Survey Program & Procedures Take MWD surveys as frequently as needed, but no less than every 100 ft. Carefully review the anticipated close crossings with existing wellbores and future well paths. Make sure that directional drillers are aware of all drilling close crossing issues, hard lines and no-go lines. If a no-go or hard line has been or will be crossed, stop drilling immediately and contact the Drilling Superintendent to discuss options. Mud Logging Program Mudlogging will be utilized from spud to production hole TD. Refer to the Geological Mud Logging Procedure document. OP-I1A-106 Drilling & Completion Well Plan Page 4 of 47 04/04/14 2m us operrfing WELL T OP -I 1 A-106 OBJECTIVES: 1. Drill the well at or under AFE cost and time. Perform work in a safe and professional manner meeting all ENI Petroleum Health, Safety, and Environmental requirements. 2. Land Intermediate casing point within 100' radius of the planned directional target. 3. Land the Intermediate hole section with the targeted inclination of 85' - 87' 26 TVD above the OA Sand Top. Maximum dogleg severity in the landing shall be no greater than 3.5'/100' DLS. 4. Target Greater than 90% within the OA sand Reservoir. 5. Execute Wellhead swap and 10-3/4' washover works in compliance with eni SIMOP and HSE + minimum requirements. 1 6. 8-3/4' hole LWD Failure Requirements: GR/Res/Dir/PWD- Require GR/Res/Dir to achieve TD. OP-I1A-106 Drilling & Completion Well Plan Page 5 of 47 04/04/14 WELL G • Ke usorocrrafin OP-I1 A-106 PREDRILLING WORKS WELLHEAD SWAP / 10-3/4" WASHOVER / CEMENT KICK-OFF PL UG OD (in) WT ( f) Grade Conn. Type ID (in) Collapse (psi) Burst (psi) Tensile yield (kips) 16" 65 H-40 Welded 1 15.25 1 630 1640 439 Existing Conductor - Well OP -I] — 76' GL 1. Confirm that the identification markings on the conductor match the planned surface location with the "as -built survey." If identification markings are not present on the conductor, contact the Drilling Supt. prior to moving the rig onto the well. ➢ Each conductor is to be marked with a common pad elevation survey mark by the surveyors Surveyors to also mark each conductor with a degree of angle to set each horizontal wing valve 2. Move in and rig up. Record move distance and rig floor distance to pad and sea level in WellView and on IADC reports. Initiate a Rig Elevation Record and place it on the N drive. • Ensure all concerned parties (Directional Drillers, MWD Operators, and Geologists) are using the same rig floor elevation. 3. Post drilling permit in the rig office and company office. ➢ Notify AOGCC prior to spudding well 4. Nipple down tree and nipple up 1 1' X 13-5/8" stud/stud adapter spool - Vetco Gray Specialists will be giving 24 hr coverage for the surface section of the well. 5. Nipple up 13-5/8' BOP. - See stack -up drawings in Attachments 6. Pull BPV and tubing hanger yr plugs from all annulus valves. Verify well dead. RE -install BPV and pull three and install test dart. Test. 7. Prior to pulling tubing hanger, circulate well to clean -fluid. Ensure mud engineer monitors returns (It is believed that diesel fuel is in the annular between the 3-1 /2' and 10-3/4 If Arctic "Pack' is present, please follow MI procedure in the Attachments for proper disposal) 8. Pull test dart and BPV and make up landing joint to hanger. Back out hanger lock downs and pull tubing hanger. Maximum pull for 3-1 /2',J55, 9.2# tubing is 120K (80% of yield). (Note-2,000' of 3-1 /2' tubing in well per Kerr McGee "as is" Schematic in the Attachments) 9. Run in hole with tubing/DP and tag Top of Cement Plug (anticipated at 2,400') .Report tag depth on DDR. 10. Close BOP and execute Pressure Test(s). ➢ 500 psi for 10 minutes - Chart record. 1,500 psi for 10 minutes - Chart record 11. Pull 3-1 /2' Kill String. 12. Rig up Schlumberger Wireline. Log Top 600' - Cement Evaluation- Ensure Baker fishing hand and Superintendent receive log upon completion. Objective of Cement Evaluation Logging -Better plan the 10-3/4" (cutting.washover/fishing) works to be performed by Baker Specialists 13. Rig Down Wireline 14. Rig down BOP 15. Remove Wellhead (See Attachments for Vetco Procedure) / landing ring from Conductor OP-I1A-106 Drilling & Completion Well Plan Page 6 of 47 04/04/14 2rnn g us operrfing WELLT_ OP -I I A-106 16. Cut down 28' pipe integral to well house floor to facilitate welding 20" by 16" swedge. 17. Install / Weld 16" X 20' Swedge (Ensure thorough pre -job discussion before beginning works) ASRC Qualified Welder (with firewatch) ➢ Vetco Gray welding procedure in attachments Eni HSE to issue permit(s) ➢ Pre -Welding works to include prep of stump, plug holes in 16' conductor below the well house floor and install 3" nipples in conductor below swedge for cement returns. 18. Allow to cool (per the Vetco procedure) 19. Pressure Test Swedge (per the Vetco procedure) 20. Rig up Riser / Diverter spool and annular preventer- See Attachments for Stack -up drawing, Function Test 21. Rig up Diverter Notify AOGCC 24 hours in advance to performing diverter function test ➢ Confirm proper signage is on the pad indicating the rig has diverter equipment rigged up and to restrict access to diverter area. Place drip berm under the end of diverter line 22. Verify that two 3' threaded nipples have been welded on the conductor on opposite sides. Include ball valves and Cam -Lock male fittings on each nipple. Ensure threaded ball valves can be installed without running into the OD of the diverter head. Nipples are to be used as follows: Assist in washing out surface casing hanger on cement jobs ➢ Take returns to Vac trucks while cementing y Provide access to annulus for top job through small diameter tubing 23. Prepare (Pre -job) for E-line hydraulic multi -string casing cutter. Please see Baker "Field Operation Running Procedure" in the Attachments 24. Hydraulic cuts will be based on the results of the cement evaluation logs; however, if log are inconclusive, plan on cuts at 500, 400', 250', 150', and 60'. 25. Execute Washover/Pulling of 10-3/4" casing, pulling each piece of casing as washed -over - Baker Procedure 26. Upon completion of Washover works, Prepare(pre-job) for Cement plug works - See Schlumberger Cement plug plan in Attachments Run "clean -out BHA to top of 10-3/4' (500') - See BHA in Attachments Bridge plug to be set 50' into top of 10-3/4" ➢ 450' cement plug / balanced AS1 cement blend Circulate/displace out top 70' (122' RKB). After WOC time complete, RIH with Clean out BHA and dress cement plug to 125' 27. Prepare for Sidetrack Works - 14-3/4' BHA (milled tooth bit) - See attachments for BHA ➢ Kick-off point 150' and ➢ 1.83 bend for the motor 28. Build spud mud. Refer to the detailed MI-Swaco Mud Program (Attachments). OP-I1A-106 Drilling & Completion Well Plan Page 7 of 47 04/04/14 WELL G • eni us or�crfin OP-IIA-106 16' SURFACE HOLE SECTION 0 4-3/4' to 16' UR) Formation Markers: All depths 245E: Schlumberger Plan Formation Tops Measured Depth, ft True Vertical Depth, ft Comments SV-4 712 655 SV-3 976 910 SV-2 1257 1169 SV-1 1810 1653 B/ Permafrost 1890 1730 Ugnu Top (UG4) 2196 1982 13-3/8' 2791 2400 SCP UG-2 Coal Bed Marker 2866 2441 Lower Ugnu 5660 3114 Schrader Bluff Top 7299 3441 NikSE Mauve dte 7382 3460 N Top 7686 3520 N-2Top 7769 3535 N-3 Top 7864 3553 N Bottom 7971 3572 N Sequence Base 8313 3627 ReCalc Intermediate Cement w/ Actual 9-5/8' 9857 3756 ICP - Set >_5' TVD Above OA Sand Top OA Top 9900 3761 TD 18630 4040 Total Depth OP-IIA-106 Drilling & Completion Well Plan Page 8 of 47 04/04/14 e n i GIs operrafing WELL OP -I 1 A-106 Surface Close Approach Wells NOTE: It is the responsibility of the Directional Driller and the Drilling Supervisor to ensure that the directional plan is executed as planned, that the position of the well as it is drilled is monitored on an anti -collision diagram and that no tolerance line for close approach wells is crossed. Surface Mud Program: NOTE: Maintain Weight up Schedule as listed below to casing point Density 6 RPM API FluidChlorides Interval Depth (ppg) Reading Loss (mg/1) PH (ml/30min) Surface: 1 10' - 1800' 8.8 - 9.2 16 - 20 <8 <2000 9.0 - 9.5 1800' - C.P. 9.2 - 9.5 20 - 20 <6 <2000 9.0 - 9.5 Surface Logging/Formation Evaluation Program: MWD Directional LWD GR/ Resistivity Surface Drill Pipe Tool Tool Make Joint Body DP Tensile Pipe WT Grade Conn. Joint Joint Body Up Torsion Torsiona capacity Capacit (ppf) type OD ID ID (in) Torque al yield I yield w/ conn. y (kips) (in) (in) (ft.lbs) (ft Ibs) (ft.lbs) ( al / ft) 5" DP - Nabors 19.5 S-135 G-C I NC50 6 5/8 3.25 4.276 26,800 51,700 74,100 .726 712 Surface Drilling Surface Hole Notes: • The area around the conductor should be continuously monitored during drilling, circulating, and cementing operations. If broaching occurs, stop drilling immediately. Contact the AOGCC field inspector and the Drilling Superintendent and inform them of the broach. The Conductor Broach Procedure will then be implemented. • Efforts should be made to minimize high doglegs in surface hole (coming off cement plug). ESP equipment will be damaged running through high doglegs. Inform the Drilling Engineer of any doglegs over 6 degrees per hundred. • Prior to spud, a safety meeting will be held with the rig crews to discuss open hole drilling procedures. Suggested topics include: ■ Conductor broaching operations and contingencies ■ Well control procedures and rig evacuation procedures ■ Flow rates and hole cleaning ■ Sidetrack off cement plug at 150' and ■ Use and male -up of the Smith under -reamer tool • Ported float valves are required in all hole sections • Ensure E-Line Gyro is on location prior to spud OP-I1A-106 Drilling & Completion Well Plan Page 9 of 47 04/04/14 eni us werrakin ►nrx rA OP-I1 A-106 Surface Hole Procedure: 1. Pick up and drift all DP, HWDP, and DC's for surface section to confirm free of debris. 2. PU BHA 3. Comments MD Ind Azlm True TVDSS TVD VSEC NS EW TF DLS (R) P) (I (ft) (ft) 0" (ft) (ft) (1) (VIDOM Is 14-3/4" Smith XR+ It -(- I( U TFA: 1.117 (3x20, 1x16) 1.83° ABH Motor ➢ Include UBHO Kicking off Cement Plug ➢ 1 50'and - Kick-off pt ➢ Low flow rate strategy while sidetracking - within limits of motor RTE 0.00 0.00 0.00 -53.00 0.00 0.00 000 0.00 OM N/A L S 40.90 0-00 0.00 -12.10 40.90 0-00 0.00 0-00 65 13M 000 16, 76.00 0.21 6513 23.00 7000 0.05 003 006 65 13M 0.61 Tie4n Survey 144.58 0.63 65 13 91.58 14458 0.46 0.24 0.52 65.06M 0.61 KOP Cry 1-51100 00 0.72 65.07 9700 150.00 0.51 027 0.57 M 1,62 202D0 00 143 9460 146.99 19999 1.03 036 148 107 6868M 176 76 4/0 300.00 3 13 10766 246.91 299.91 210 -0 56 5.33 110M 176 Cry 21100 350.00 4.D0 110.00 296.81 349 81 2.66 -1 59 8.27 110M 1 76 400.00 5 DO 110.00 34665 399 65 329 -2 93 11 96 110M 200 500.D0 7.00 110.00 446 10 49910 498 -6.51 21.78 11 Om 2.00 Cry 2.5/100 550.00 8.00 11000 49567 W 67 6.D4 -8 74 27.91 1/DM 2.00 600.00 9.25 110.00 545 11 598 11 7.25 -11 30 3496 HS 250 700. DO 1175 11000 64342 69642 1020 17 54 5208. HS 2.50 800.00 1425 110.00 740.85 793.85 13.84 -26.23 73.22 HS 2-50 90000 16 75 11000 837 21 89021 18 16 -34 37 98.33 HS 250 1nnn no 19 75 11n nn 912 11 481,11 71 15 "94 177 19 HS 7 5n 4. Directionally drill surface hole: ➢ Drilling Parameters: ■ Flow Rate: +650 GPM • Lower flow rates of 450-600 GPM will help avoid anti -collision boundaries by minimizing hole washout and optimize dog leg capability in the build section ■ Rotary: 40 - 80 RPM ➢ Avoid anti -collision boundaries ➢ Take MWD surveys as frequently as needed. Carefully review the anticipated close crossings with existing wellbores. Make sure that directional drillers are aware of all drilling close crossing issues, hardlines and no-go lines. If a no-go or hardline has been or will be crossed, stop drilling immediately and contact the Drilling Superintendent to discuss options. 5. Hole conditions will always determine final mud properties. Watch returns closely for signs of gas when near the base of the permafrost and circulate out all gas -cut mud before continuing to drill. • Although hydrates are not expected attempt, keep mud as cool as possible. • Control drill at 100 to 120 fph through any troublesome zone so the hole does not load -up with gas cut mud. ■ Check and report trip gas. ➢ Consider adding 0.5% Drilzone for screen blinding in shallow intervals right below the conductor. 6. Surface casing point: OP-IIA-106 Drilling & Completion Well Plan Page 10 of 47 04/04/ 14 2ni ass operrafing WELLT_ OP -I 1 A-106 Land in good shale found between 2400' SSTVD and 2650' SSTVD. (Land 15' deeper than desired as the Underreamer run will be 15" higher than drillbit, ie, casing pt will be 15' higher) ➢ Below the sand at the base of the Sagavanirktok Formation (SV-1). ➢ Inside the upper Ugnu (UG-4). Drill the hole 15' deeper than typical casing pt to fit casing, if possible, to reduce pup joints in the string. Leave at least 15' rathole. 7. Backream out of the hole at surface casing point: Circulate until shakers are clean as per K&M. Backream one (1) stand per bottoms up very slowly ■ 800 GPM or higher • 80 RPM or higher Backream to the HWDP ■ 800 GPM or higher ■ 80 RPM or higher ■ Pull 5-10 feet per minute, backreaming speed will be dictated by hole conditions. Consult with K&M prior to increasing pulling speed. • Decrease backreaming speed as torque and pump pressure dictate. ■ NOTE: once backreaming in the open hole has been started, DO NOT stop backreaming until the HWDP. DO NOT attempt to pull out on elevators once backreaming has started. ■ Expect +/-100% increase in cuttings from 1800 600'. • Lesson Learned from OP09-Sl : While backreaming out of the hole in the transition from horizontal to vertical, have the shaker box sub -guns running or ready to run at the first sign of clay balling. Have the flow line jets hooked up and ready to activate to assist flow line cleaning. Shaker hand should notify the rig floor at first clay show at the shakers. • If shakers/mud return system becomes overloaded and flow rate is cut to handle the issue, DO NOT continue to backream until the parameters are brought back to full backreaming rate. Once the HWDP is reached, circulate until hole is clean as per K&M 8. Pull and lay down 14-3/4" BHA. 9. Make-up the Smith Rhino -Reamer with bull -nose BHA - See Attachments 10. Execute reamer run to TD. (Please note that the Reamer will be approx. 20' above nose). Casing point will be 15' above TD. 11. Backream out of hole: Abbreviated backreaming plan - To be determined bu K&M representative onsite Rhino Reamer to be closed while back -reaming. 12. Pull and laydown the under -reamer BHA. OP-I1A-106 Drilling & Completion Well Plan Page 11 of 47 04/04/14 WELL -%ni us werrafin OP-I1 A-106 Surface Casing Surface Casing Program: (all depths feet RKB) OD WT Grade Conn. Cplg OD ID (in) Drift (in) Collapse Burst Tensile yield (in) ( f) Type (in) ( si) (psi) (kips) 13-3/8 68 L-80 BTC 14.375 12.415 12.259 2260 5020 1556 13-3/8 68 L-80 521 13.375 12.415 12.259 2260 5020 1556 Flush 200 torque Running Method Casing Running Tool- Utilize Volant Tool Surface Casing Connection Make Up Torque Mks) Opt. OD (in) WT (pp0 Grade Conn. Type Make Up Torque 13-3/8 68 L-80 BTC Triangle 13-3/8 68 L-80 Hydril 521 36K ft-lb Flush Casing Running Notes a. Surface casing will be landed on hanger, emergency casing slips will be used as contingency. b. Rig up and utilize a Volant tool for the casing job. c. Top 3 joints of 13-3/8" casing will be Flush Joint.. Separate Handling tools will be required. d. Crossover from 527 to collared BTC will be required. e. Break circulation before reaching the base of the permafrost if casing run indicates poor hole conditions. f. Any packing off while running casing, and especially while above the base permafrost, should be treated as a very serious problem if major returns are lost. It is preferable to pull casing out until circulation can be re-established rather than risk not getting cement to surface. Contact the Drilling Superintendent if the casing packs off high for discussion of the options. g. Have Vetco representative verify the correct casing hanger is on location prior to the point at which it is needed. h. Torque values for the BTC casing are determined at the rig by making up the connection to the make-up mark (base of triangle). Record torque values for the first 10 connections made up in this manner and average. This average will be used as the make up torque for the remainder of the string. Running Procedure 1. Inspect and drift all surface casing to 12.259 2. Break circulation before reaching the base of the permafrost if casing run indicates poor hole conditions. 3. While RIH with the the Casing: obtain SO Weights as per K&M ➢ obtain PU Weights as per K&M 4. Run the surface casing as follows: OP-IIA-106 Drilling & Completion Well Plan Page 12 of 47 04/04/14 en o us ooerraHna WELL7- OP-I1 A-106 Surface Casing Running Order 1 Float shoe Bakerlock 2 2 joints 13-3/8' 68# L-80 BTC casing Bakerlock 3 Float Collar Bakerlock 4 13-3/8" 68# L-80 BTC casing ** TAM BTC port collar+/- 500 ft Only run if losses are expected 6 13-3/8" 68# L-80 BTC casing Crossover - BTC Pin X Hydril 521 Box Unique machine shop 13-3/8' 68# L-80 Hydril 521 casing Last 3 joint 13-3/8" 68# L-80 Hydrl 521 casing to hanger Vetco Gray 13-3/8' mandrel hanger 13-3/8' landing joint Slick landing joint 5. Please note in the table above that the last three joints will be 13-3/8' Hydril 521 flush. Note that separate handling tools will be needed. Crossover required. **If TAM port collar is run: • A landing joint, which has a connection that can be broken below the rotary table, will need to be run to allow for running the drill pipe inside the 13-3/8" without needing a false rotary table. Also, the drill pipe running tool needs to be on location and stood back in the derrick ready to run in case the TAM port collar needs to be opened to circulate cement to surface. • If decision to run is at the last minute, ensure the additional footage of the port collar plus handling pup will allow for sufficient rathole below the surface casing shoe. Surface Centralizers +/- 18 13-3/8' Tandem Rise Weatherford OP-IIA-106 Drilling & Completion Well Plan Page 13 of 47 04/04/14 WELL e n i us looerrafin 13-3/8" x 16" Tandem Rise Centralizers OP-I1 A-106 • 2 at 5'& 8' above Float shoe on stop collars, using stop buttons or stop collars. • No centralization on collar of 1" joint. • 1 at 10' above Float Collar, using stop buttons or stop collars. • From 3rd joint through tail slurry (500' tail slurry), 1 centralizer per joint run on collars. Do not alloNN centralizer to float bemeen collars. • 2 on 13-3/8" casing collars, inside conductor @ TD so csg can be reciprocated. OP-I1A-106 Drilling & Completion Well Plan Page 14 of 47 04/04/14 2no us operrafing WELL -F OP-IIA-106 Surface Cementing Surface Cementing Program Section Casing Size Type of Fluid / Cmt Volume Properties Mudpush II 100 bbls Densit 10.1 ppg Lead Slurry 512 bbls Density 10.7 ppg Surface 13-3/8' (ArcticSet Lite) yield 2.26 ft3/sk ✓" Tail Slurry (LiteCRETE) 63 bbls Density 12.5 ppg To of Tail 2 259' MD yield 1.54 ft3/sk Casing Cementing Notes a. As OP-11 has 16" conductor vs a 20' conductor the restricted annulus has resulted in higher dynamic ECDs. Please note the Schlumberger Cementing Pumping Plan in the Attachments. b. Obtain and review the Test Report from the cementing lab on the job blend prior to pumping the cement. DO NOT pump cement if there are any doubts as to cement quality, quantities, pumping times, or thickening times. c. Ensure that enough cement retarder is built to keep cement from setting up prior to pumping down disposal well. Cementing Procedure 1. After reaching bottom, rig up and circulate with casing on bottom at 4 bpm, if possible, without losing returns. Reduce mud viscosity prior to pumping cement if necessary. .= To help ensure good cement to surface after running the casing, and if practical for existing hole conditions, condition mud to yP < 20 Ib/100ftz prior to cementing the casing but after the casing is on bottom. Have adequate supply of cold lake water on hand to ensure the desired rheologies can be achieved. 2. Rig up to cement and pressure test cement lines. 3. Pump Mud Push Spacer. Shut down and drop bottom plug. 4. Pump cement job per the attached Schlumberger cementing plan. Cement volumes are based on 35% excess below the Permafrost and 225% excess in the Permafrost. If necessary, verify that the TAM Tech has located the proper crossovers to combo running tool. i If necessary, rack TAM running tool in derrick and ready to run. 5. Report the number of bbls of cement returned to surface: ➢ Task one person to be in charge of monitoring for cement returns and volume of cement returns Recommend that a dye or small amount of celloflake be added to the wash or spacer to give an indication of top of cement. 6. Drop top plug after the tail slurry. 7. Pump displacement at 7.0 bpm maximum. 8. Drop circulation rate 2 BPM for last 20 bbls of displacement prior to bumping plug. 9. Pump until the plug bumps and then pressure up to 500 psi above Final Circulating Pressure (FCP) to ensure the plug has landed. If floats do not hold, maintain FCP on casing and shut in cement head for a minimum of 6 hours before rechecking. ➢ Do not over displace the cement (Pump NO MORE than %z the shoe joint volume). OP-I1A-106 Drilling & Completion Well Plan Page 15 of 47 04/04/14 eni us oDerratin WELL OP-I1 A-106 ➢ Watch for signs of packing -off during pumping operations and closely monitor the cellar area for mud or cement returns around the conductor. ➢ In the event cement is not circulated to surface, pump the calculated volumes and prepare to open the TAM Port Collar (if applicable) for a secondary cement job. ➢ AOGCC and Drilling Superintendent must be contacted prior to beginning top job. Do not proceed with top job without AOGCC approval. 10. Drain and wash cement from riser. Nipple down riser and flush all lines. 11. Nipple up Vetco Gray Well Head, orienting the well head valves as indicated on the conductor markings. ➢ If there is any doubt about the proper orientation, call the Drilling Superintendent. ➢ Ensure that the seal between the casing hanger and well head is tested to 5,000 psi for 10 minutes. Measure the distance from the rig floor to the top flange of the well head and record on the IADC report and in WellView. Complete the Rig Elevation Record and place it in the electronic well folder. 12. Nipple up the 13-5/8' 5M BOP stack and test per the AOGCC Permit to Drill (attached) ➢ Test rams and choke manifold components to 3500 psi high / 250 psi low ➢ Test annular preventer to 2500 psi high / 250 psi low ➢ Do not test BOPE against casing. ➢ Notify AOGCC 24 hours prior to performing BOP test. ■ PERMIT TO DRILL BOP testing frequency: 14 DA(JS as Notified by AOGCC OP-IIA-106 Drilling & Completion Well Plan Page 16 of 47 04/04/14 2ni us operr Hng WELL7- OP -I 1 A-106 12-1 /4' INTERMEDIATE HOLE SECTION Formation Markers: All depths 245E: Schlumberoer Plan Formation Tops Measured Depth, ft True Vertical Depth, ft Comments SV-4 712 655 SV-3 976 910 SV-2 1257 1 169 SV-1 1810 1653 B/ Permafrost 1890 1730 Ugnu Top (UG4) 2196 1982 13-3/8' 2791 2400 SCP UG-2 Coal Bed Marker 2866 2441 Lower Ugnu 5660 3114 Schrader Bluff Top 7299 3441 NikSE Mauve dte 7382 3460 N Top 7686 3520 N-2Top 7769 3535 N-3 Top 7864 3553 N Bottom 7971 3572 N Sequence Base 8313 3627 ReCalc Intermediate Cement w/ Actual 9-5/8' 9857 3756 ICP - Set >_5' TVD Above OA Sand Top OA Top 9900 3761 TD 18630 4040 Total Depth OP-IIA-106 Drilling & Completion Well Plan Page 17 of 47 04/04/14 WELL C�nA us ofnrafin OP -I 1A-106 Pick Up Intermediate Drilling Assembly 1. Install wear bushing. Pickup: ➢ 12-1/4' bit • Hyclog - SKH1716D • TFA:0.969 ■ Xceed ■ Hi -Tool ■ PWD ■ GR/ RES ➢ See BHA attachment for running order and specifications ➢ Flow Rate: +900 GPM ➢ Rotary: +120-200 RPM ➢ Refer to Intermediate drilling strategy below 2. RIH to top of float equipment and pressure test surface casing to 2500 psi for 30 min and record on chart. ➢ Plot Casing Pressure Test on LOT form on N drive. Verify that the test indicates a linear line and that there is no air entrained in the mud. Repeat Casing pressure test if needed. ➢ Note: All BHA trips thru the TAM port collar (if applicable) should be done slowly with slow rotation to avoid accidentally opening port collar. If set -down weight is noted, stop immediately, PU, resume slow rotation and try slacking off through port collar area. 3. Drill out the float collar & shoe. ➢ See Float Equipment and Plugs PDC Bit Drillout Recommendations Attachment 4. Drill 20'- 50' of new hole using spud mud. 5. Displace hole to new LSND mud system. 6. Perform Leak Off Test as per AOGCC requirements following the attached LOT Procedure. ➢ PU into casing and perform LOT. If the pressure continues to rise past 13.0 ppg EMW, shut down and call it a FIT per the FIT Guidelines (attached). ➢ If LOT is less than 11.0 ppg EMW, contact Drilling Superintendent to discuss options. ➢ Plot on LOT form on N drive. OP-I1A-106 Drilling & Completion Well Plan Page 18 of 47 04/04/14 2rnn i us operrafing WELLT- OP-IIA-106 Intermediate Mud Program: NOTE: Weight up to at least a 9.0 ppq MW by the top of the "N" sand Interval Density PV 6 RPM API FL pH Drill Solids MBT (ppg) Reading (m1/30min) N Intermediate: 9.0 - 9.4 12-18 12-15 < 6.0 9-10 <6.0 <18 Intermediate Logging/Formation Evaluation Program: MWD Directional / PWD LWD GR / Res Intermediate Drill Pipe Tool Tool Make Joint Body DP Tensile Pipe WT Grade Conn. Joint Joint Body Up Torsion Torsiona capacity Capacit - (ppO type OD ID ID (in) Torque al yield I yield w/ conn. (kips) (in) (in) (ft.lbs) (ft Ibs) (ft.lbs) ( al / ft) 5' DP - Nabors 19.5 S-135 G-C I NC50 6 5/8 3.25 4.276 26,800 51,700 774,100 .726 712 Intermediate Section Notes: a. If the well is to be an ESP producer, a pump tangent must be placed in the intermediate hole section as per the planned directional profile. The pump tangent must be within 300' TVD from the top of the uppermost OA sand and at least 200' MD in length. b. Efforts should be made to minimize high doglegs above the pump tangent (if applicable). The ESP equipment will be damaged running through high dog legs (> 6 degrees per hundred). c. Shallow test MWD tools. d. Monitor hole conditions carefully. Be alert for early signs of lost circulation and differential sticking. If any of these problems are observed immediately notify the Drilling Supervisor or Toolpusher (attempt to keep the pipe moving and circulation established). Ensure that all team members are communicating with each other on any observed drilling trends and that everyone understands the potential risks. e. Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. f. Keep shut down times to a minimum during connections. g. Swab / Surge: Make "easy on, easy off" slips a standard practice h. Control the ROP if necessary to maintain good hole cleaning i. Ensure the Top Drive Torque Limit is set below the lowest make up torque in the string. Do not run the risk of further make up downhole while drilling. OP-I1A-106 Drilling & Completion Well Plan Page 19 of 47 04/04/14 en A us ®perrafing WELL OP-I1 A-106 Intermediate Drilling_gy ➢ All attempts will be made to drill the intermediate hole section in one run. ■ First Run - 716 PDC Bit ■ Second Run - 716 PDC Bit (The use of a Tri-Cone bit will be evaluated on a well to well basis) ➢ While drilling through the intermediate section attempt to mitigate ledging, excessive shocks/vibrations/ stick slip and impact damage by adhering to the provided mitigation strategy detailed below. ➢ Communication with well site geologist/ driller/ drilling specialist/ directional driller, careful attention to logs and most importantly keeping low WOB and high RPM will greatly increase the chances of drilling this section in one run. ➢ Although some hard streaks can be correlated across the field, most cannot. Hard streaks can be expected upon drilling out of the surface casing shoe to intermediate TD. ➢ While drilling adhere to the following drilling parameters: Soft Formation Drillin9 Recommendations Parameter Optimum Operational Maximum WOB 10K 5-15K 20K RPM +180 180-220 220 Hard Formation Drilling Recommendations Parameter Optimum Operational Maximum WOB 10-12K 8-12K 20K RPM +180 165-180+ 220 ➢ The parameters above have proven to give the best results throughout the course of previous runs. With that being said all parameters shall be modified to provide best results. A BHA will not be pulled due to low ROP until ALL possible WOB and RPM scenarios are explored regardless of shocks to tools. ➢ Higher RPM and lower WOB will decrease stick slip. At higher RPM's higher shocks may be encountered. ➢ The objective of drilling this section is to maintain ROP. ROP's of 5-10 fph should be considered acceptable while drilling hard streaks. Only if the ROP drops off to zero and we have completely run through the entire operational spectrum without success will we consider pulling a BHA. ➢ All operational parameters and results shall be documented. Schlumberger shall provide WOB vs. RPM discrimination plots every 12 hours to effectively optimize drilling parameters. WOB Shall be zeroed at every connection to supply accurate data. OP-I1A-106 Drilling & Completion Well Plan Page 20 of 47 04/04/14 2ni us operrfing WELL OP-I1 A-106 Intermediate Drilling 1. Directionally Drill 12-1/4' hole Use the following Parameters: ■ Flow Rate: +900 gpm ■ Rotary: 120 -200 RPM ■ WOB: Follow Intermediate drilling strategy 2. Casing Point: Land Intermediate casing >5' TVD above the OA Sand Top. Do not set in OA sand as reservoir may be depleted 3. LOW ROP: Consult with Town as ROP drops to < 1-2 ft/hr for one (1) full hour. This usually occurs through the middle and Lower Ugnu at high tangent angles (+80 degrees). Goal is to avoid excessive BHA and DP wear. 4. Backream at Intermediate Casing point: Circulate until shakers are clean as per K&M while backreaming one (1) stand per bottoms up very slowly. ■ +900 GPM ■ +120 RPM Backream to the surface casing shoe. ■ +900 GPM ■ +120 RPM • If any spots of high -torque and/or high -vibration are seen, drop rotary as necessary to work through section. Resume optimum backreaming parameters once excess torque and/or vibrations have subsided. • If shakers/mud return system become overloaded and flow rate is cut to handle the issue, then do not continue to Backream until the parameters are brought back to full backreaming rate • Decrease backreaming speed as torque and pump pressure dictate ■ NOTE: once backreaming in the open hole has been started, DO NOT stop backreaming until the surface casing shoe. DO NOT attempt to pull out on elevators once backreaming has started. r Backream into the surface casing if necessary. Backreaming will continue until the string can be POOH safely on elevators. 5. POOH on elevators and lay down BHA. OP-IlA-106 Drilling & Completion Well Plan Page 21 of 47 04/04/14 2f�1A us o[Derrarin <<.V� OP-I1 A-106 Intermediate Casing Program: (all depths feet RKB) OD WT Grade Conn. Cplg OD ID (in) Drift (in) Collapse Burst Tensile yield (in) ( 0 Type (in) (psi) (psi) (kips) Hydril "Special 9-5/8 40 L-80 10.625 8.835 Drift 3090 5750 916 563 8.75 Running Method Flotation/ Rotation - Tesco Casing Drive System Set using emergency slips Intermediate Connection Make Up Torque (ft.lbs) OD T Min. Target Max. ( Grade FH TMake,Uft- Make Up Make Up yield Torque Ibs Torque Torque 9-5/8 40 L-80 10,800 13,000 N/A 75,000 ""special Untt casing to bl!) Intermediate Casing Interval Notes: a. Casing will be floated and set utilizing emergency slips. b. Ensure proper sized rams are installed and tested prior to running intermediate casing. c. Casing will not be filled with mud as run in the hole and therefore can not be circulated until TD is reached d. Rig up and utilize Tesco Casing Drive System. e. Double valve float equipment will be utilized for floating operations a. Float Collar Type: 700DVSB-LAPN Pre -Run Notes 1. Inspect and drift intermediate casing (drift 8.75"). 2. Confirm Hydroform Centralizers on location (see centralizer running order schematic below) 3. Pull wear bushing. Install 9-5/8" rams and test. 4. Install "Special (short) Vetco Gray Casing Drilling" wear bushing it Wear bushing is short enough to not extend past studs when wellhead is broken and Emergency slips are set. ID should be the same as the actual drilling wear bushing 5. Wellhead and stack will be picked up enough to allow slips to clear the lower flange and upper studs 6. Have spare shoe track on location. OP-I1A-106 Drilling & Completion Well Plan Page 22 of 47 04/04/14 e n i us operrfing WELL OP -I 1 A-106 Casing Running Order 1 Float shoe - Davis -Lynch Model 501-DV-PVTS Baker -Lock down -jet float shoe (double valve)**** 2 2 joints 9-5/8" casing Baker -Lock Float Collar - Davis -Lynch Model Type 700 DVSB- 3 LAPN double -valve float collar w/ anti -rotation Baker -Lock baffle**** 4 9-5/8' Casing 5 Vetco Gray 9-5/8" Emergency Slips Emergency Slips 6 9-5/8' landing joint Slick landing joint for reciprocation purposes Centralizers +/- 38 9-5/8' x 1 1-3/4' Rigid Hydroforms (Floating) Volant Shoe Track: Have a spare float shoe and collar made up with centralizers and on location ready to go. Shoe joint misalignment has caused cross threading with Hydril 563 connection and requires make up by hand for first 10-15 joints ■ Make-up Shoe track (and first 10-15 joints) by hand using chain tongs until enough weight is in the slips to prevent cross threading ■ The shoe track joints should be Bakerlocked. ■ Inspect the float valves as the shoe track is picked up. ■ Run the shoe track into the well to test and confirm the floats are holding negative differential pressure. Preparations: 2. The following should be completed prior to running the casing: 3. The 9-5/8" 40#, L-80, Hydril 563 casing should be, numbered, measured, drifted, cleaned and inspected. y The casing should be drifted to 8.75 y It is important that the casing is internally clear of any rust, scale, or other debris. 4. 20 - 25 joints of casing should be randomly selected and the following inspections made (as accurately as possible with the equipment available onsite): y Caliper the ID for cement displacement calculations and for checking the collapse rating. Check the ovality and eccentricity for collapse rating. This may not be possible onsite, but should be available from the mill and/or pipe inspection company. ➢ Recalculate the weight of the casing based on actual wall thickness measured. 5. The casing run should be modeled with the actual wellbore conditions (e.g. actual survey, active mud weight, depths etc). & Surge modeling should be agreed on by K&M and Eni to determine the safe running speeds to prevent / minimize losses. 7. Careful pit management will be needed with this floated casing run. The total displacement of the casing is +/- 1086 bbls (+/- 909 bbls required to fill the casing). A pit management plan should be developed well in advance of the casing run. Sufficient capacity should be available to store the casing displacement volume. In the event that total returns are lost while running casing, plan to mix enough volume to fill the casing and displace cement. 8. A pit strategy shall be developed to cater for emergency fill up of the well in the event of casing failure, taking into consideration the pit requirements for the subsequent cementing operations. Take the following into consideration when developing the pit strategy: The active volume should be limited to assist with kick detection, with the remainder of the required mud available in the reserve pits. A strategy should be adopted to line up the reserve mud quickly in the event of casing failure (such that the backside can be filled quickly without delay). Pit transfers should only take place when the casing is stationary. 9. Prepare a 'kill sub', comprised of a TIW valve crossed over to 9-`/R' Hydril 563. OP-I1A-106 Drilling & Completion Well Plan Page 23 of 47 04/04/14 G • 1c: us ®ralerrafi rn WELL OP-I1 A-106 10. Have an assortment of 9-%' pup joints available for space out when setting casing on depth 11. Review well control procedures in the case that the floated casing collapses. 12. Note that circulation will not be possible until the string reaches TD as the string is run floated. 13. Contingency 9-%' casing fishing equipment should be located, available and ready to be used if required (e.g. mills, spears, overshoes, casing cutters, large OD magnets, etc). 14. Ensure that a copy of the LWD logs with details of known tight spots, problem areas, doglegs, KOP's, and a theoretical drag chart with potential decision points identified for the casing run, is available on the rig floor. Connection Make Up: 1. Refer to the TenarisHydril "Running Manual General Guidelines" attachment for make up, pipe dope, etc (Also available on Tenaris website) 2. Make up the first joint to the specified target torque and relax the tongs. ➢ Draw a longitudinal line across the pin and box and reapply the published target torque. ➢ If the drawn line does not move more than after the second torque application, continue running the rest of the string normally using the published target torque. ➢ If the drawn line moves more than %z' after the second torque application, this indicates that a portion of the torque was absorbed by other variables in the make-up system. If this occurs, follow these steps: ■ Increase the target torque by 15% and reapply the torque. ■ Draw a second line and apply the original, specified target torque. ■ If the second drawn line does not move more than''/z', continue running the rest of the string normally using the 15% higher target torque. ■ If the second drawn line moves more than %z', recheck the alignment, dope application and tong function, then continue to repeat this procedure from above until the drawn line does not move more than''/z'. ■ It is best practice to repeat this procedure in the event the tongs are changed out during the running of the pipe. 3. Ensure that the joint about to be made up is hanging along the same axis as the joint in the slips. Due to the fact that sometimes the rig is a few inches off center the slips and bell nipple may have to be adjusted. Well Control (Collapsed Casing/ Float Failure): 1. Turn Mud Pumps on and open kill line to fill annulus at high rate. Annulus must stay full of mud. 2. Lower Tesco Casing Drive System into 9-5/8' casing if not already stabbed into casing. 3. Line up to take air to choke manifold. Leave choke manifold shut in and allow air pressure to build. 4. Once it is determined that annulus is being kept full of mud, then begin to bleed air from the casing slowly. ➢ Ensure Annulus is being kept full. *In the event that pipe rams are closed, keep in mind that any surface pressure applied to the annulus will be acting on the surface casing shoe. Some rate of mud losses will occur if pressure is above Leak -Off Test pressure. Running Procedure 1. Hold a pre -job meeting prior to running the casing. Topics to discuss should include: tubular handling, floatation, casing hanger procedures, well control, lost circulation, and other contingency procedures. 1SA's should also be held prior to any new operation and at the start of each tour. 2. Rig up the 9-%" casing running equipment as per Tesco and Nabors guidelines. Tesco Casing Drilling System ■ Ensure that the Tesco casing running tool is not equipped with a "mud -saver" check valve because in the event of a float/ casing failure the plan is to take the air/gas returns up through the Tesco tool and top -drive and then back to the choke manifold while pumping into the back -side through the kill line. 350 ton spider, configured with pneumatic interlock with the Tesco tool ■ ensure that the slips are chained down to the "A' legs to avoid excessive movement ➢ Wrap -around casing tong (strap type) with large circumferential contact area. ■ The casing will be empty and not be heavy enough in the slips to make up without backup. ■ Rig tong backup can damage the casing. ➢ Torque -Turn Monitoring equipment ➢ 9-%" mud bucket (in the event wet casing is pulled out) OP-I1A-106 Drilling & Completion Well Plan Page 24 of 47 04/04/14 2ni us operrfing WELLT_ OP-I1 A-106 3. Pick up the shoe track Shoe joint misalignment has caused cross threading with Hydril 563 connection and requires make up by hand for first 10-15 joints. Shoe Track Running Order ■ Davis -Lynch Model 501-DV-PVTS down -jet float shoe (double valve) ■ Tesco Hydro -Form Rigid Centralizer (free-floating), stop collared 5' above the shoe ■ Tesco Hydro -Form Rigid Centralizer (free-floating), stop collared 10' above the collar ■ Davis -Lynch Model Type 700 DVSB-LAPN double -valve float collar w/ anti -rotation baffle ➢ Bakerloc shoe track. Inspect the float valves as the shoe track is picked up. Run the shoe track into the well to test and confirm the floats are holding negative differential pressure. 4. After picking up the shoe track, fill the shoe track. It is critical to ensure that the entire shoe track has been filled with mud. ■ If left empty, there is potential for an air bubble to be pumped around when circulation is initiated on bottom (i.e. similar to gas kick). 5. Prepare to run the casing in the well: ➢ Commence crosshead circulating across the top of the well from Isolated Pit ■ Before performing the casing job ensure that the choke manifold has been "blown down" and that the blooie line is free of any obstructions or ice plugs. Commence crosshead circulating, taking returns via the flow line to Isolated Pit, to ensure the hole is kept full throughout the casing running procedure. Set the lower flow -out flow line alarm as required to alert the driller as soon as losses occur. ■ Ensure that a minimum of 2 pumps and sufficient mud volume to fill the void casing are available at all times to be able to quickly fill the hole at the maximum rate should losses occur. ■ Displaced mud should be returned to the active system in order to ensure adequate volume is available. If losses occur, be mindful of volumes necessary to fill the hole in the event of casing collapse. ■ While running the 9-5/8" casing have a hard line or high pressure hose rigged up from the outlet valve on the standpipe manifold to the choke manifold so that returns can be taken from the inside of the pipe back to the choke manifold and through the gas buster. 6. Continue running to TD ➢ Pick up slowly out of the slips to avoid inducing swab loads below pore pressure or collapse gradient. The maximum push with the top drive is limited to 25 kips. Circulation will not be possible until the casing is on bottom. ➢ The casing running speed should be optimized based on surge modeling, as per K&M, and actual mud returns. Starting and stopping of casing should be controlled to avoid excessive surge pressures. The slackoff hookloads shall be recorded every joint. ■ This data should be plotted against theoretical curves in real-time to determine S/O friction factors (SOFF's) and allow pro -active decisions to be made. ■ In case of abnormally high friction, hole problems, or otherwise "slow" progress running the casing (>1 min/joint), evaluate using rotation to overcome friction and expedite running the casing to TD. • Be aware, that hookload and torque are highly sensitive to running and rotational speed. ■ If there are distinct divergences from theoretical lines or changes in the friction factor, an attempt should be made to document the causes (e.g. ledges, change in formation, change in driller, etc). If the casing will not pass an obstruction (e.g. ledge, junk, etc), rotation should be discussed in an attempt to work the string down. Landing and Filling Casing 1. Prepare to land the casing on bottom Ensure adequate rathole is allowed below shoe and free pickup weight of casing is observed. OP-I1A-106 Drilling & Completion Well Plan Page 25 of 47 04/04/14 a n i us werrafin WELL OP-I1 A-106 ➢ Make up Landing Joint ( BTC Box x Hydril 563 Pin) ■ Landing Joint Positions collar above the slip area and out of the way in the riser. ➢ Open 350 ton air slips and slide them out of the way. Slack off and land casing using the hand slips. ■ Leave 4'-5' of casing stick up above hand slips. ■ Use rotary hand slips and bushings type: Bushings API #2 and Slips CMS XL. ➢ PU the 150 or 200 Ton side door elevators and latch onto casing (will save 1.5 - 2 hours rig time and eliminate pinch/strain exp osure to the crew). ➢ Take care to ensure that there are no couplings across the casing rams once the casing is on depth. 2. Fill the casing ➢ Install Cement Head ➢ When filling the casing, install high pressure hose to take air returns through the top outlet in the cement head to the choke manifold. ■ Line up choke manifold to allow flow in the least restrictive flow path to the gas buster. Ensure choke manifold is blown down and all other valves and chokes are in the closed position prior to filling the casing. ➢ Venting of the return air through the choke manifold and gas buster is required to provide a controllable method of venting the air. (See illustration below) ■ While filling the casing, opening the needle valve off of the choke line side of the cement head will give a clear indication that air is being vented off to the choke manifold. It will also give a clear indication if we are filling too fast or when the casing is full. Pump through the bottom outlet (on the opposite side of the cement head (see attached picture). ➢ Due to fact that there is no back pressure to the mud pumps it may be difficult to assess a fill up rate which would be typically read off the Epoch screen (i.e. GPM). This is due to the fact that the charge pump may out runs the mud. To counteract this, proper attention must be made to the Total Pit Volume (PVT) & Gain/Loss Volume. ➢ Fill casing with 2-4 BPM. Access the charge pump out put prior to filling the casing. ■ To give the air time to "swap out" with the mud, stop circulation for 1 Omin each at''/z way through the displacement, 3/4 of the way through the displacement and 50 bbls prior to getting mud to surface. After returns are seen at surface wait 5 min and then top off the casing 3 times before breaking off the line. This ensures that the casing is full and that all of the air is free from the inside of the casing. ➢ While filling the casing mud will have to be transferred to the active pits, careful attention must be paid to keeping track of Gain/Loss and PVT volumes. If any volumes are zeroed out via the Epoch monitor the volumes prior must be accounted for to keep track of the total volume pumped. ■ The driller must be notified prior to any mud being moved to the active pits. 3. Once the casing is full and all air is purged, RU cement head to break circulation and install wiper plugs. ➢ By installing the wiper plugs prior to breaking circulation it is possible to get a positive indication that the casing is full. ➢ Also by installing the plugs prior to breaking circulation it is possible to be lined up to pump cement once the mud is conditioned. ➢ Note: Verify the casing is full by checking the volume of mud pumped into the casing against the theoretical casing capacity. 4. Break circulation at %2 bpm assessing losses if any, this will allow any "clabbered up" or cold mud to be circulated out prior to stepping up the rate. ➢ Break circulation at''/z bpm (estimated with 250 psi) without any issues/ losses, then step up the rate gradually to 8 bpm without losses. ■ Pumped a total of roughly 3.5 bottoms up (estimate Final yP 18, from 25) 5. If needed, circulate and thin mud to properties slightly as outlined in CemCADE and Mud plan summary prior to pumping cement. 6. As a reminder, the following aspects of the cement job will be "different" than a normal job: ➢ The casing will not be reciprocated or rotated once at TD ➢ After cementing the casing, the pipe will be pulled into tension and then landed with emergency slips (as opposed to landing on the mandrel hanger). OP-IIA-106 Drilling & Completion Well Plan Page 26 of 47 04/04/14 2ni GIs operr ling WELLT- OP-I1 A-106 Intermediate Centralizer Placement 9-5/8" x 11-3/4" Hydroform Centralizers Run 1 Hydroform: • On Stop collar 5' above Float shoe. • No centralizer on next joint • On Stop collar 10' above Float Collar. • From 4th joint to +/-1000' above the shoe - 1 centralizer floated between collars . 1 centralizer floated between collars from N sand oil bearing zone to +/- 500' above N sand oil bearing zone OP-IIA-106 Drilling & Completion Well Plan Page 27 of 47 04/04/14 G • eni us werrafi WELL I OP-I1 A-106 Intermediate Cementing Program Section Casing Size Type of Fluid / Cmt Volume Properties Intermediate 9-518" Mudpush II 70 bbls Density 10.5 ppg DeepCrete 288.8 bbls Density 12.5 ppg TOC @ 6,686' MD LJield 1.60 ft3/sk Intermediate Cementing Intermediate Cementing Notes: a. Obtain and review the Test Report from cementing lab on the job blend prior to pumping the cement. DO NOT pump cement if there are any doubts as to cement quality, quantities, pumping times, or thickening times. If need be, confer with Drilling Superintendent. b. Do not over displace the cement (no more than''/z the shoe joint volume). c. For injectors, a cement bond log is required. Prefer to run sonic LWD in production hole BHA and log intermediate casing on trip in hole to drill out intermediate shoe. 1. Perform Rig pump efficiency check and confirm +96% efficiency before pumping and displacing cement. 2. Ensure Schlumberger re -calculates cement volume based on 'N" sand actual depth! ➢ Cement volume is based on 50% excess and at least 1000' of annular fill above top of the N sand (highest known hydrocarbon bearing zone). Refer to attached cement detail sheet for volumes. 3. Batch mix cement. Test cement lines and pump cement job as per the attached Schlumberger program. 4. Displace cement with rig pumps and LSND water -based drilling mud. ➢ Ensure that the cement unit and rig pumps are manifolded so there will be redundancy in case of any pump failure during displacement. ➢ Pump cement at 5 bpm and displace with 8.0 bpm if possible without losing returns. Slow rate to 3 bpm during last +/- 30 bbls prior to bumping plug. 5. When the plug bumps, pressure the casing to 500 psi over the final displacement pressure and ensure that the string is holding pressure. Notify the Drilling Superintendent if the string will not hold pressure. Bleed off pressure and ensure the floats are holding. If the floats leak, pressure back up to final displacement pressure and shut in cementing head. 6. Close the annular and perform 20 bbl injectivity test with drilling mud down the 13-3/8" x 9-5/8" annulus no later than (4) hours after cement was mixed and started downhole. Ensure injectivity for freeze protect (offset wells have seen cement channel into the surface casing and prevent freeze protection) 7. Wait on cement to setup per Schlumberger prior to nippling down BOP and setting emergency slips 8. Ensure cement is setup. OP-IIA-106 Drilling & Completion Well Plan Page 28 of 47 04/04/14 W 1 2ni us operraling WELL OP -I 1 A-106 Prior To Liftino The BOP Stack 9. Remove the flow line and choke & kill lines. 10. Radio communication is required for those in the well bay module, cellar and rig floor. Also ensure that radio channel is clear to only those involved in the cellar, rig floor, and well bay modules. 11. Ensure that Vetco Gray/ and one floor hand is in the well bay module with a radio prior to lifting the stack to measure amount of travel to provide enough room to install the emergency slips and casing cutting tool. While Lifting the BOP Stack and Setting the Emergency Slips 12. Upon lifting the Stack and multi -bowl: DO NOT LOWER THE STACK FOR ANY REASON UNTIL ALL PARTIES ARE NOTIFIED PRIOR TO LOWERING THE STACK. i Caution: When the stack is raised, the casing and multi -bowl can become un-centralized and if lowered the multi - bowl seal area can become compromised 13. Confirm with Vetco Gray hand in the well bay module that he has enough room to set the emergency slips. 14. Set emergency slips with casing in Tension r Pull approximately 100K over string block weight and set emergency slips. Slack off and allow casing weight to be transferred to the slips Record weight transferred to the slips in Wellview 15. Prior to cutting the casing ENSURE THAT ALL WEIGHT IS SLACKED OFF. 16. Once the slips are set and the casing is cut be sure that there is radio communication between those in the well bay module and rig floor prior to pulling the casing in the event that the stack has to be slightly lowered. 17. Remove and lay down the cut casing 18. Install Vetco Gray Packoff assembly. 19. Re -Install the Vetco Gray Multibowl and BOP"s ➢ Test wellhead connection to 5000 psi i� Radio communication is necessary for all parties involved when lowering the stack 20. Pressure test packoff per Vetco Gray. Do not exceed 80% of intermediate casing collapse ➢ Record test on IADC report and in WellView 21. Freeze protect 13-3/8" x 9-5/8" annulus to the surface casing shoe. Cement Consistency of 50 Bc (Bingham consistency) is not pumpable. 50 Bc is achieved roughly 4 hrs after mixing cement and starting downhole. Pressure limitations are as follows: 80% of surface burst or 80% of intermediate collapse, whichever is less. ■ 2472 PSI is 80% Intermediate casing collapse (9-5/8" 40# L-80) Freeze protect the surface by intermediate annulus with diesel at 1-1 /2 to 3 BPM. Pump enough diesel to flush and freeze protect to the surface casing shoe. 22. Install rams and test per the AOGCC Permit to Drill (attached) Test rams and choke manifold components to 3500 psi high / 250 psi low i- Test annular preventer to 2500 psi high / 250 psi low Do not test BOPE against casing. OP-I1A-106 Drilling & Completion Well Plan Page 29 of 47 04/04/14 a ani us operrating WELL OP-I1 A-106 r Notify AOGCC 24 hours prior to performing BOP test. ■ PERMIT TO DRILL requires BOP testing frequency everU 14 daus unless notified otherwise by_AOGCC 23. Install wear bushing. 24. Clean mud pits in preparation to receive OBM ■ Pits must be clean and free of all Barite OP-I1A-106 Drilling & Completion Well Plan Page 30 of 47 04/04/14 2rnn o us operafing WELLT- OP-I1A-106 8-3/4' PRODUCTION HOLE SECTION Formation Markers: All depths 245E: Schlumberr er Plan Formation Tops Measured Depth, ft True Vertical Depth, ft Comments SV-4 712 655 SV-3 976 910 SV-2 1257 1 169 SV-1 1810 1653 B/ Permafrost 1890 1730 Ugnu Top (UG4) 2196 1982 13-3/8' 2791 2400 SCP UG-2 Coal Bed Marker 2866 2441 Lower Ugnu 5660 3114 Schrader Bluff Top 7299 3441 NikSE Mauve dte 7382 3460 N Top 7686 3520 N-2 Top 7769 3535 N-3 Top 7864 3553 N Bottom 7971 3572 N Sequence Base 8313 3627 ReCalc Intermediate Cement w/ Actual 9-5/8' 9857 3756 ICP - Set >_5' TVD Above CIA Sand Top OA Top 9900 3761 TD 18630 T 4040 Total Depth OP-IIA-106 Drilling & Completion Well Plan Page 31 of 47 04/04/14 WELL G ■ eni us w rrafin OP-I1 A-106 Pick Up Production Drilling Assembly 1. The section will be drilled with 5" drillpipe ➢ 6,000' of 5" TT525 high torque pipe - Upper String / remaining Nabor's 5", NC50 pipe ➢ Sub w/IBOP valve -bottom of Topdrive (TT525 box x NC50 pin) ➢ Crossover (TT525 box x NC50 pin) 2. PU 8-3/4" BHA Assembly ➢ 8-3/4"PDC ■ Hycalog (new bit): SKH616M-El D • TFA = .888 (6 x 14) ➢ Xceed675 Flow rate: 550 GPM ➢ Rotary: +120 RPM ➢ See BHA attachment for running order and specifications ■ Sonic LWD - Begin recording 1000' above the N Sand Top. 3. RIH to the float equipment. Pressure test the casing to 3000 psi for 30 min and record on chart (AOGCC required casing integrity test). Plot Casing Pressure Test on the Pressure LOT form in N drive Oil Based Mud Fluid Displacement 4. Displace casing to new Oil Based Reservoir Drilling Fluid ➢ Do not contaminate new OBM in rig pits ➢ Displace old water based fluid to trucks or exterior tanks for disposal 5 Drill out the float collar & shoe. See Float Equipment and Plugs PDC Bit Drillout Recommendations Attachment 6, Drill 20'-50' of new hole using the Oil Based Reservoir Drill -In fluid. 7. Perform Leak Off Test as per AOGCC requirements following the attached LOT Procedure. ➢ PU into casing and perform LOT. ➢ If the pressure continues to rise past 13.0 ppg EMW, shut down and call it a FIT per the FIT Guidelines (attached). ➢ If LOT is unacceptable to drill ahead (less than 12.0 ppg EMW), contact Drilling Superintendent to discuss options. ➢ Do not pump more than 112 bbl after leak off is determined. There is no need to pump more than 112 bbl into the leak off and extend the fracture. ➢ Plot on LOT form in N drive OP-I1A-106 Drilling & Completion Well Plan Page 32 of 47 04/04/14 2ni us operr frog WELL OP -I 1A-106 Production Mud Program: FazePro Density HTHP FL Electrical Interval (ppg) 6/3 rpm (m1/30min) Oil:water Stability mlVolts Production 9.0-9.4 7/6 <5.0 65:35 >600 Production Logging/Formation Evaluation Program: Production: Tools MWD Directional / PWD LWD GR / Resistivity / ADN / PeriScope Production Drill Pipe Tool Tool Make Up Joint Body DP Tensile Pipe WT Grade type lODt Joint D (') Torque Torsional Torsional capacity Ca yaci (ppf) (ft.Ibs) yield y eld w/ onn. (in) (in) lbs) (ft.lbs) (al / ft) (kips) 5' DP 19.5 S-135 TT525 6.50 3.87 4.276 49,600 82,700 74,100 .731 712 5' DP - Nabors 19.5 S-135 G-C I NC50 6 5/8 3.25 4.276 26,800 51,700 74,100 .726 712 Production Section Notes: a. Monitor hole conditions carefully. Be alert for early signs of lost circulation and differential sticking. If any of these problems are observed immediately notify the Drilling Supervisor or Toolpusher (attempt to keep the pipe moving and circulation established). Ensure that all team members are communicating with each other on any observed drilling trends and that everyone understands the potential risks. b. Shallow test MWD tools. c. Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. d. Keep shut down times to a minimum during connections. When surveying in this hole section reciprocate the pipe slowly while the survey is transmitted uphole. Keep the pipe rotating whenever possible. e. Ensure the Top Drive Torque Limit is set below the lowest make up torque in the string. Do not run the risk of further make up to a connection while drilling. Openhole Sidetracking Practices: a. Lowside in a fast drilling interval where the wellbore is heading up and where the ABI's show a good build rate b. Orient within 15 degrees either side of lowside and trough with high rotary RPM's while reciprocating from the kickoff point back to the first stabilizer. Trough for approximately 30 minutes. c. Time drill at 4 to 6 feet per hour with high flow rates and rotary RPM's for the first 5 feet. Gradually increase the penetration rate as the openhole sidetrack is achieved. d. If any openhole sidetracks are drilled, confer with Drilling Supt. and consider tripping without circulating or without rotating past the sidetrack point. OP-I1A-106 Drilling & Completion Well Plan Page 33 of 47 04/04/14 2n A us ®pO erafi n a WELL OP -I 1A-106 Production Drilling 1. Directionally drill the 8-3/4' hole to TD. If water is encountered while drilling the production hole section the well will be turned up to evaluate the N-Sand, as per the geologic plan. Ensure that the N Sequence Top is not penetrated. Geosteering will be required to remain in the target boundary 100% of the time ➢ Maintain sufficient flow rate with maximum pipe rotation as needed to bring mud/well properties in line. Maintain proper Calcium Carbonate concentration per MI mud plan. ■ Ensure Centrifuges are operating effectively to remove fine drill solids ➢ Increased rotary in excess of 120 RPM has shown to decrease stick slip and vibrations in the lateral section. 2. Backream at TD: A At TD circulate 50% of calculated TAD cleanup cycle pulling 1 stand per bottoms up. Once the first 50% cleanup cycle is completed circulate the remaining 50% of the calculated cleanup cycle pulling 2 stands per bottoms up. Decrease backreaming speed as torque and pump pressure dictate. ■ 550 GPM ■ +120 RPM r Backream into the intermediate casing shoe. ■ 550 GPM ■ +120 RPM • Slow backreaming speed when pulling BHA into the Intermediate casing shoe/rathole. Hold parameters steady at 550 GPM and 120 RPM. • Decrease backreaming speed as torque and pump pressure dictate ■ NOTE: once backreaming in the open hole has been started, do not stop backreaming 3. Drop rabbit down drill string once bit is above the intermediate shoe: Take SLM coming out of hole. ■ Drift OD dependent on Completion ■ COMPLETION DP RABBIT SIZE: 2-3/8' OD ■ All drifting tools will be accounted for and held in one place at all times. 4. Continue backreaming until depth at which it is possible to pull out on elevators at >9.1 swab EMW at 2.5 min/stand ■ 550 GPM ■ +120 RPM • Determine depth at which swab can be kept >9.1 EMW at 2.5 min/stand as per K&M TAD Model. 5. Circulate until shakers are clean until shakers are clean aster K&MK&M. ■ 550 GPM ■ +120 RPM 6. Slug DP and trip out of hole on elevators. ➢ Utilize K&M"s swab model to control trip speed and avoid swabbing the open hole below 9.1 ppg EMW. 7. Lay down BHA ➢ When out of hole, down load the recorded tool data and send to the Geologist in town OP-I1A-106 Drilling & Completion Well Plan Page 34 of 47 04/04/14 2ni GIs operrfing WELLT_ OP -I 1 A-106 Production Liner OD WT Grade Conn. Type Cplg OD ID (in) Drift (in) Collapse Burst (psi) Tensile yield (in) ( f) (in) (psi) (kips) 5-1/2 11.6 L-80 Hyd "I 4.695 3.960 3.875 6360 7780 171 52 Production Liner Connection Make Up Torque (ft-Ibs) OD WT Min. Target Max. (in) (ppf) Grade Conn. Type Make Up Make Up Make Up yield Torque, ft-Ibs Torque* Torque Torque 5-1/2 11.6 L-80 H dril521 3600 6300 N/A 16000 * See attached TenarisHydril Guidelines for make-up torque recommendations Production Liner Centralization From To Quantity / Joint Fixed / Floating Type Shoe Liner 1 / joint Fixed t 4-1 /2" x 7" to - Mid -joint - Crimped on - H droform Volant (Crimp on) Liner Running Procedure Notes: • Ensure the 4-1/2" WATER -swelling packers are run in the string. • Make up 4-1 /2' H521 liner connections to 1.75 times the minimum make up = 6,300 ft-Ibs. • Ensure proper crossover from DP to slotted liner is on the rig floor in case of a well control situation. • The liner will be run in FazeAway Delayed Breaker. Consult with completions engineer for liner detail. Liner string will be adjusted according to actual depths after drilling. Consult with completion engineer and ops geologist to determine exact placement and number of swell packers and ICD's prior to installation. • Liner top should be placed a minimum of 200 ft above the intermediate casing shoe. • Ensure accurate torque and drag data is gathered. Record pick up and slack off weights every stand and free rotating torque every five stands. Data gathered will assist in future liner running operations throughout the project. • Perform visual inspection, measure and caliper all components prior to running any assembly in the hole. Ensure accurate dimensional data is recorded for all equipment run in the well and recorded in WellView. • Ensure all equipment has been hydraulically and operationally tested. Also ensure all equipment to be run is dimensionally compatible with all other equipment. • Review all setting operations and shear pressures with Baker Oil Tools service hand. • Ensure that all workstring components have been rabbited as ball will be dropped to actuate downhole tools. Rabbit DP on last trip out of prior to running liner. • If any openhole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters the correct hole. OP-IIA-106 Drilling & Completion Well Plan Page 35 of 47 04/04/14 G • eni us ooerrafln WELL I OP-I1 A-106 Torque ratings for string components String Components yield Torque (ft-lb) 5" 19.5# TT525 Drill Pie 82,700 4-1 /2' 16.6# NC46 Drill pipe ( rem) 39,200 HRD Running Tool 40000 7" 29# H dril 563 39000 4-1/2' 11.6# Hydril 521 16000 Shear pressures for liner hanger assemblu: Item Description Shear Value Shear Ran e HRD Running Tool, 7" 6975 mch rel 3 pins Nominal - 3192 psi 15°% + 3671 psi 15 /° - 2713 psi Pusher Tool Activation Nominal - 1986 psi p 15% + 2284 psi 15% - 1688 psi Pusher Tool Neutriz. Nominal - 3588 si 15%+ 4126 psi 3050 psi Ball Seat SOLID *****Make-up torque for liner hanger sub -assembly, including running tool connections, should be torqued to 14,000 ft-lbs prior to deliver to rig. OP-11A-106 Drilling & Completion Well Plan Page 36 of 47 04/04/14 2ni GIs operating WELL OP -I 1 A-106 Procedure: 1. Hold Pre -job safety meeting to ensure all parties understand operation 2. PU the Liner Assembly and Running/Inner String as outlined above. 3. RIH with Liner Assembly. Record PU and SO weights as required. 4. Pick up liner hanger assembly and make up to proper torque. Fill Liner Tieback Sleeve with "pal mix" and ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 minutes for mixture to set up. 5. Trip in hole one stand and circulate 5 bbls to ensure all flow paths are free. Record ROTATE, PU and SO of liner assembly. 6. RIH in hole to casing shoe with DP. RIH with Liner Assembly as hole conditions allow, but do not exceed running speed of one stand per minute. Break circulation and fill DP as necessary. 7. Monitor mud flow while running in open hole and slow running speed if necessary. Circulate minimum of one DP volume and record ROTATE, PU and SO weights. 8. Record PU, SO, and Rotating torque in open hole every 500' to ensure friction factors are sufficient to run the liner to bottom successfully. If friction trend indicates liner will not go to bottom then call Drilling Supt. immediately. 9. Rotating liner 20-60 RPM may be necessary to run to bottom. 10. Continue RIH with Liner Assembly to proper setting depth. Liner should be spaced out to locate the liner top approximately 200 feet above 9-5/8" casing shoe. 11. Trip slightly deeper than desired liner top location with liner top. Last motion of the liner should be up to ensure it is set in tension. Ensure Liner Hanger assembly does not exit 9-5/8' casing shoe. 12. Prior to setting the hanger & packer, double check all pipe tallies and record amount of drill pipe on location. 13. Rig up to pump down workstring with rig pumps. Pressure test lines. Bleed off test pressure. 14. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 15. Pressure up to 3000 psi and hold for 5-15 minutes to set SLZXP hanger packer. Continue pressuring up in 500 psi increments holding for 5 minutes each up to 4000 psi. 16. Packer can now be pressure tested. Bleed DP pressure to zero, close annular preventer and test annulus to 1,500 psi for 10 minutes and chart. 17. Bleed off pressure and pickup to verify that the HRD running tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, 4,650 ft-lbs of left hand torque can mechanically release the tool. 18. Once running tool is free and packer is tested, Displace mud from liner top to surface with 9.0 ppq KCI brine per MI recommended program. 19. POOH and LID and inspect the liner running tools. / OP-I1A-106 Drilling & Completion Well Plan Page 37 of 47 04/04/14 e n i us ®perrafing WELL T OP-I1 A-106 COMPLETION SECTION Completion Tubing Program: (all depths feet RKB) Hole Size Tubing OD Wt/Ft Grade Conn. Length Top MD/TVD Btm MD/TVD Tubin g 4.5" 12.6# L-80 H563 +/-11900' Surf 1190073393' Completion Tubing OD U/T Grade Conn. Cplg OD ID (in) Drift (in) Collapse Burst Tensile (in) ( o T e (in) (psi) (psi) yield (kips) 4-1/2 1 12.6 L-80 H 563 5.20 3.958 1 3.833 7,500 7,700 288 Completion Connection Make Up Torque (ft.lbs) OD U/T Grade Conn. Min. Make Up Opt' Max. Make Up Min. LJield (in) (ppf) Type Torque, ft-lbs Make Up Torque Torque Torque 4-1 /2" 12.6 L-80 H563 3200 3800 N/A 12,600 4-1 /2' 12.6 L80-13 Cr Vam To 4,000 4,440 4,880 4,880 4-1 /2' Injector Completion String Running Notes: a. An oil -based, delayed breaker system will be used to treat the wellbore prior installation of liner and completion. This fluid will be placed in the hole prior to the liner run. This system is designed to remove wall cake after a predetermined time interval. Fluid loss may be experienced beyond this time frame. Make note of time from displacement of this fluid to nipple up of tree. Ensure enough additional fluid is available to manage possible losses. b. Double check measurements of entry guide to ensure fit into liner hanger assembly and also the no-go on top of tieback sleeve. C. Verify the rig is centered over the well prior to running the completion. d. Strap and record the dimensions of each piece of equipment prior to RIH. e. Drift all 4-1 /2", 12.6# tubing and equipment with a 3.833` OD rabbit. f. Three 4-1 /2" x 6" VIT joints will be used below the tubing hanger. Locate VIT prior to beginning completion operations. g. Use BOL 2000 NM thread compound with proper doping procedures. h. If rubber thread protectors, rather than shipping thread protectors, are used on skate, inspect protectors to ensure they will not damage pin connections. i. MU torque for IBTM tubing is determined by averaging the makeup torque required for the first 15 joints. Proper makeup occurs when the bottom of the pin makeup mark is flush with the top of the collar. j. TIH slowly (+/-1 jt/min) and avoid sudden starts and stops which may pre-set packer, especially while setting the rotary slips. k. Verify all completion equipment has been operation and pressure tested, and is dimensionally compatible with other equipment to be run. Record OD's and ID's of all auxiliary equipment on tubing detail. I. PHL Packer must be set below base of Ugnu formation must also be set at least 300' below top of intermediate cement. The planned setting depth on is significantly below this. m. Completion Equipment Pressure Settings: OP-I1A-106 Drilling & Completion Well Plan Page 38 of 47 04/04/14 2ni us operrfing WELLJ- OP -I 1 A-106 GLM Valve Autofill Valve Mirage Plug AHR Packer 2,000 psi ann 1,050 psi 6,000 psi disc, start 1,700 psi, full to tubing 4,250 psi shear set 3,500 psi Running Procedures: 1. Hold pre -job safety meeting prior to start of any operations including review of applicable notes listed above. 2. Pick up no-go entry guide assembly and two full joints. 3. Make up Mirage Plug, Autofill valve, 3.725 XN nipple and PHL Packer assemblies per HAL representative. 4. Continue RIH with 4-1 /2' tubing. Pick up the first 3.813' X nipple. 5. Continue RIH until reaching GLM. Make up KBMG gas lift mandrel with DCK-2 annulus -to -tubing shear valve set for approximately 2,000 psi. 6. Continue RIH until the second 3.813" X nipple is reached. This second nipple should be placed at approximately 2200 feet MD. 7. RIH to crossover and Vaccuum Insulated Tubing (VIT) joints and stop for space out. 8. Prior to picking up the VIT joints, space out the landing of the entry guide and no-go sub in the liner tieback sleeve. Pick up additional joints of 4-1 /2" tubing and land out no-go sub to obtain proper tubing hanger space out measurements. Note: The locator sub on the mule shoe assembly has a shear indicator that will help ensure proper depth control. 9. Ensure engagement and landing of the entry guide in tieback sleeve. After tag, slack off an additional 1 Ok lb down weight to witness shear. Tubing travel of approximately 16" should be seen. Mark pipe, measure and calculate proper space out for tubing hanger placement. 10. Install correct pup joints below VIT section to allow the tubing hanger to land properly while the seal stem is fully engaged in the liner tieback sleeve. Ensure no-go on entry guide will be engaged when tubing hanger is set. 11. Makeup crossover to 4-1 /2" Vam Top and three VIT Joints. 12. Make up tubing hanger, pup joint and crossover to upper VIT joint. The upper most connection may be torque adjusted to allow for proper alignment of tubing hanger if necessary. 13. Drain and rinse BOP stack before landing tubing string and pick up landing joint. 14. Check hanger seal areas and grease hanger per Vetcogray recommendations. Ensure hanger is centered and land same. Run in Lock down screws. 15. Test upper and lower seals to 5,000 psi and hold for ten minutes. 16. Rig up pump to set packer. Test surface lines to 5,000 psi and then bleed pressure to zero. 17. Pressure down tubing string to 1200 psi to close Autofill Valve and monitor for leaks. 18. Increase pressure down tubing to 3,500 psi to set packer and hold for 30 minutes. Record on chart as tubing integrity test. Ensure inner annulus is open and monitor for returns. 19. Reduce tubing pressure to 2,000 psi. Rig up and pressure inner annulus to 2,500 and hold for 30 minutes. Record annulus pressure on chart as inner annulus integrity test. Bleed annulus pressure to zero. �.r i _ 1/4 20. Increase pressure down tubing to 4,400 psi to shear open Mirage Plug. Reduce tubing pressure to zero. 21. Pressure inner annulus to 2,500 to shear valve in GLM. If valve does not open, cycle annular pressure from 0 to 2,500 psi several times while allowing tubing to bleed pressure. OP-11A-106 Drilling & Completion Well Plan Page 39 of 47 04/04/14 eni �s ®perrafing WELL OP -I 1 A-106 22. Pull landing joint and set BPV. 23. Nipple down stack and nipple up tree. Test void to 5,000 psi for ten minutes. 24. Pull BPV and set TWCV. 25. Fill tree with diesel and function valves. Test tree using rig test pump and chart to 500 psi for 5 minutes and then 5,000 psi for 15 minutes. 26. Pull TWCV. 27. Rig up flow manifold to tree. Circulate diesel through GLM to fill annulus and tubing volume from GLM depth to surface. Diesel volume should be approximately 160 bbls. Allow annulus and tubing pressures to equalize. 28. Set BPV and secure tree and wellhead. 29. RDMO. 30. Prepare Handover Form and post to N: drive in the operations folder. Form is located under N:IAlaskalNikaitchug103-Drilling and WeIWOliktok Pointl Wells 10120-07 I 0 7 Operational DatalHandovers. Handover must be completed to ensure a reliable resource for the production engineer to reference during planning and execution of post -rig work. OP-IIA-106 Drilling & Completion Well Plan Page 40 of 47 04/04/14 "7l e n i GIs operrafing WELL OP -I 1 A-106 Recommended Drilling Practices Hole Cleaning With a deviated well path and potential for losses, hole cleaning will require special practices. Pipe rotation is critical for effective hole cleaning. The maximum string RPM, as determined by the BHA, is specified for each hole section in the detailed procedures. The shakers should be monitored as an indicator of adequate circulating time. If circulation is of long duration, then pipe movement to prevent casing wear is critical and a stand should be laid down occasionally to prevent excess hole erosion over the length of pipe reciprocation. In addition the following practices should be employed at all times: a) Use all available solids control equipment to keep mud as clean as possible. b) Emphasize proper hole cleaning after slides by rotating at maximum allowable RPM c) As the hole angle increases, hole cleaning practices must be altered. Maximum pipe rotating speeds along with maximum achievable flow rates will increase hole cleaning efficiencies. Circulating times prior to trips should be increased accordingly to account for longer times required to remove cuttings from higher angle wells. d) Use good connection practices while drilling. After reaching the bottom of a stand, allow a small amount of circulating time to allow cuttings to get above the BHA prior to picking up off bottom. Be sure to pick up slowly to prevent packing off the cuttings bed around the top of the drill collars. Slower Trip / Connection Speeds High POOH and RIH speeds can aggravate fragile shales/formations due to the pressure variations between surge/swab PWD data shows that excessive tripping and reaming speeds can exert pressure spikes in excess of 2 ppg equivalent. Effective ROP Strive to find the maximum effective rate of penetration. That is, the maximum rate at which a clean hole can be produced. While on bottom ROPs in excess of 400 fph may be possible, but such ROPs may load a high angle hole with cuttings that are not being removed fast enough. Using torque and drag trends, ECD and the shakers, establish a base line clean hole ROP, and then try to improve it by altering the hole cleaning practices. Slower Initial Pump Rates PWD data has shown that the most significant period for increased ECD occurs when the pumps are brought on at drilling rate while washing a connection to bottom. The study also concluded the least damaging procedure is if pump rates are held at 40% or less of drilling rate while reaming connections. OP-IlA-106 Drilling & Completion Well Plan Page 41 of 47 04/04/14 WELL eni us © erratnn OP-I1 A-106 Health Safety & Environment The following are part of the mitigation & contingency measures to be put in place in order to complete this project while helping to meet our HS&E goals. It is the Drilling Supervisor's responsibility that these measures are implemented and communicated to the relevant parties on location. Good communication when drilling is essential for increasing the safety of personnel and equipment. HZS Contingency Measures J Assume all locations have the potential for HZS. 1. The AOGCC will be notified within 24 hours if HZS is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic HZS detection equipment meeting the requirements of 20 AAC 25.066. Manual detectors in accordance with 20 AAC 25.065 will also be maintained on location. 3. Self-contained Breathing Apparatus for all rig personnel will be maintained on location. 4. All personnel engaged in the drilling operation will be trained in HZS emergency procedures and the use of proper personal protective equipment. 5. A standard HZS contingency plan will be posted at the rig. All rig personnel should read and familiarize themselves with this document and copies should be posted in the rig floor doghouse and in the camp on location. 6. HZS treating material for the drilling mud system will be available on location in the event that any HZS is encountered. It is expected that the rig and personnel will have the equipment and training to identify and contain a HZS emergency situation. If it becomes necessary to notify the AOGCC of an HZS encounter, drilling will be suspended and will resume only after the development of detailed remedial and contingency procedures, full compliance with 20 AAC 25.065 and the applicable referenced sections of API RP49 and approval of the AOGCC. Lessons Learned Documentation of lessons learned has been proven to reduce downtime and increase efficiency of rig operations. It is expected that planning meetings, daily operations meetings and pre -tour meetings will be held on a regular and consistent basis and that the records of those meetings will be placed on the N drive in the appropriate folder for this well. OP-I1A-106 Drilling & Completion Well Plan Page 42 of 47 04/04/14 2ni us operrfing WELLT_ OP-I1 A-106 Safety Meeting Topics Move In, Rig Up Prior to spud, a safety meeting should be held with the rig crews to discuss open hole drilling procedures. - Subsidence around wellheads - use of buddy system, - Conductor broaching operations and contingencies, - Shallow gas hydrate drilling practices, - Proper tripping practices and hole fill calculations with various sizes of pipe and tubing, - Well control procedures, - Flow rates and hole cleaning, and - Diverter operation and crew responsibilities. ➢ A'Diverting Shallow Gas' drill should be held with rig crews prior to spud, unless each crew on tour has completed this drill within the past 3 months. Document drill and record on morning report. ➢ An 'Accumulator' drill should be held with rig crews prior to spud. Document drill and record on morning report. Shut-in drills should be held on a regularly scheduled basis. A suggested minimum is once per day on alternating tours. Document and record on morning report. Check trip tank for leaks and confirm gauges are calibrated. Complete trip sheets and submit to the Drilling Supervisor after each trip. ➢ Perform and document all drills. Designate crew member to control access at the pad entrance in case of diverter operation. Surface A'Stripping' drill should be held with rig crews prior to drill out, unless each crew on tour has completed this drill within the past 3 months. Document drill and record on morning report. r A'Well Kill' drill should be held with rig crews prior to drill out, unless each crew on tour has completed this drill within the past 3 months. Document drill and record on morning report. ➢ A well kill sheet shall be posted in the doghouse and updated each tour. Intermediate ➢ Prior to picking up the BHA a safety meeting should be held with the rig crews to discuss hole risks and open hole drilling procedures. ➢ Potential formation pressures and mud weight, Well control procedures. i- Hole cleaning best practices, flow rates. Stuck pipe, Lost circulation. Proper tripping practices and hole fill calculations with various sizes of pipe and tubing. Production ➢ Prior to picking up the BHA a safety meeting should be held with the rig crews to discuss production hole risks and open hole drilling procedures. ➢ Potential formation pressures and mud weight, Well control procedures. ➢ Hole cleaning best practices, flow rates. ➢ Stuck pipe, Lost circulation. ➢ Proper tripping practices and hole fill calculations with various sizes of pipe and tubing. Completion OP-I1A-106 Drilling & Completion Well Plan Page 43 of 47 04/04/14 eni us oo rrafin WELL OP-IIA-106 Operation of the control line spooler. ➢ Pinch points associated with tongs and slips. ➢ Proper tripping practices and hole fill calculations with tubing and control line. Well control practices while running production tubing with control line. Y Pressure testing and minimizing personnel exposure to pressurized lines. OP-IIA-106 Drilling & Completion Well Plan Page 44 of 47 04/04/14 en g GIs operr frog WELL OP-I1 A-106 Well Shut In Procedure While Running Production Tubing If well is suspected to be flowing: 1. Install TIW valve and pull back to the first banding point below the BOP stack. 2. Shut off air to control line spool and bleed off line pressure while checking well for flow. 3. If well is confirmed to be flowing, cut control line with bolt cutters directly above a banding point. 4. Slack off until full joint of pipe with no control line attached is spaced out across BOP stack. 5. Close annular and monitor pressure. If well is coming in rapidly and time is not permitted to complete above operations: 1. Install TIW and close annular around pipe and control line. 2. Shut off air to control line spool and bleed off line pressure while picking up a joint of drill pipe and making it up to TIW and top drive. 3. Close IBOP on top drive and open TIW valve. 4. Cut control line and strip the joint of drill pipe across stack for ram closure if needed. 5. If annular does not seal off around tubing and control line and the joint of drill pipe cannot be safely picked up, close blind/shear rams on production tubing. Notes: • Specify location of bolt cutters required to cut control line. • Need to have access to a joint of drill pipe and the appropriately sized elevators at all times. OP-I1A-106 Drilling & Completion Well Plan Page 45 of 47 04/04/14 c ani �s oper Hng WELL OP-I1 A-106 Conductor Broach - Contingency Cementing Plan In the event of a broach to surface of drilling fluids during the drilling of the surface interval, the following contingency plan is recommended to remediate the situation. Conductor Hole Diameter Conductor Casing Size 16' Conductor Setting Depth +/- 80' MD DP / Conductor Annular Volume 5' DP x 18.25' ID: (16 bbls) Conductor Pipe Volume 18 bbls 16' Open Hole Capacity 0.2113 bbls/ft 1. Upon establishing that a broach of the conductor casing has occurred, POOH and stand back BHA. 2. RIH with open -ended drill pipe to 20' below the base of the conductor pipe. 3. Establish circulation with mud at normal drilling rate. Begin circulating and establish rate of flow through broach with drilling fluid. 4. Circulate up to 120 bbls of water or until water returns are seen from the broach. 5. RIH to 200' below the base of the conductor. If mud viscosity is <300sec/qt., spot a 150' pill of 150K cp polymer (Biozan) to 50' below the conductor. POOH to 20' inside the conductor. 6. Mix and displace +/- 80 bbls of Artic Set 1 cement at 15.8 ppg. Cement may U-tube with no ability to obtain squeeze. Do not over displace DP. Monitor and gauge all returns. 7. POOH and WOC for 8 hours. 8. PU 14 3/4' bit and BHA and RIH to clean out cement to 40' below conductor. Establish normal circulating rate and evaluate broaching. If no broaching is seen, continue with planned operations. If additional broaching occurs, repeat steps 6, 7 and 8. OP-I1A-106 Drilling & Completion Well Plan Page 46 of 47 04/04/14 2ni us operraring WELL OP-I1 A-106 TAM PORT COLLAR Utilization Decision Tree TAM Port Collar Utilization Decision Tree Begin Primary One Stage Cement Job ' Drilling Foreman and Engineer determine the I Top of Cement Top of Cement Zel.0- above Port Collar (1000'TVD) Indicators of Cement Top Perform Top Job as per -- If T.o--------ineffe t-----.r Open Port Coll 1. Observation of Tracers in S acer ahead of lead cement If Top Job is ineffective or P requirements of unacceptable to AOGCC using drillpipe. 2. Calculated Displacement AOGCC 3. Displacement Pressures during Primary Cement Job 4. Other indications that cement is near surface Nipple Up and Test BOP's Continue with Completion Circulate to Surface and close Port Collar Nipple Up and Test BOP's IContinue with Completion OP-I1A-106 Drilling & Completion Well Plan Page 47 of 47 04/04/14 | : \ o% y\ G3 r L y@// \7/ ® A@/z \ ■ £k§J■ /\/\\ /\§\ /L-/\ \t\ ?/\zm \9�y 2aEa j�| ~^ 222/ //\ %§ \^ \Zi » r e x # n \§ „ ¥ Q \ «,- i\ ƒ/; %\ % §a � � LLI Z in O_ N � L16 2CO0 �In � � g c O M & , 4 O z �\ \a -r \a � 3 ƒ � Of ■ |! LLJ / §■& §� � E } ! SRE - - e\3 !,@ ,.& § `!&§ >!* 2 � � )$, , « # &�${ )� (& - §} [ \ _ } u o - - - - / j o \ § ml § X a, a� LO Q U C c0 > A 2= co= d Cc E _ E �z Ccz° aD O r cz 0 S P E O IDENTIFICATION CODE PAG 206 OF 338 ENI S.p.A. Eni ESOP Division REVISION STAP-P-1-M-6140 0 11 15. LEAK OFF TEST PROCEDURE A Leak -Off Test (LOT) will be performed On Wild -Cat wells at each casing shoe after setting the surface casing. LOTs are also recommended to be carried out on both appraisal and development wells. Leak Off Test and Formation Integrity Test (FIT), also termed the Limit Test, are for formation strength pressure tests made just below the casing seat prior to drilling ahead. These tests are carried out to: • Investigate the cement seal around the casing shoe which should be at least as high as the predicted fracture pressure for the area. • Investigate the wellbore capability to withstand pressures below the casing shoe in order to allow proper well planning with regard to the setting depth of the next casing, mud weights and alternatives during well control operations. • Collect regional information on formation strengths and stress magnitude for different applications including optimisation of future well planning, hole stability analysis and modelling, reservoir application. Prior to a test, a decision should be made to either increase the pressure until leak off occurs (as in the LOT) or to stop at a predetermined pressure for a (FIT). It should be noted that: • FIT does not obtain information on stress magnitude. • A LOT is designed and should be performed to determine, in a better way, the desired data without breaking down the formation. When a Formation Integrity Test is required, the maximum pumping pressure is often expressed in terms of 'Equivalent Mud Weight' (EMW): Imperial units EMW = P +MW 0.052 x TVD where: P = Pumping Pressure (psi) TVD = True Vertical Depth (ft) MW = Actual Mud Weight (PPG) Metric units EMW = P x 10 + MW TVD where: P = Pumping Pressure (kg/cm2) TVD = True Vertical Depth (m) MW = Actual Mud Weight (kg/1). it S P E o ENI S.p.A. CWF E&P Division IDENTIFICATION CODE STAP-P-1-M-6140 PAG 207 of 338 REVISION 0 11 LOTts or FITs can be carried out in any open hole section and at any time while drilling the hole, even if it is customary to have it performed some metres (6-15 metres) below the casing. For instance, the casing seat can be in a shale and the first sand formation may be encountered several hundred feet deeper. This will certainly be more permeable than the shale, and a test can be performed to ascertain the maximum pressure this sand can hold. If it is lower than the shale just below the casing seat, this sand becomes the limiting factor. Note Information obtained from leak -off tests in straight holes is not applicable to deviated holes in the same field and vice versa. 15.1 TEST PROCEDURE Prior to performing a formation strength test, prepare a sheet of graph paper to record pressure, versus cumulative mud volume. 1) Drill out the float equipment, clean the rat hole and drill 5m of new hole. 2) Circulate a mud quantity equal to the internal string volume plus the new hole plus 50m internal casing volumes. This mud shall be cleaned and conditioned to the density and filtrate as indicated in the Mud Programme to be used for the next drilling phase. 3) Pull the bit back into the casing shoe. 4) Rig up the cementing unit to the drill pipe. The unit shall be equipped with high precision, low pressure gauges. The range of the pressure gauge shall be selected based on the actual mud weight and the estimated (LOT) or predetermined (FIT) pressure. A pressure recorder should be used during the test. The use of the rig pumps for making these tests is unsuitable. 5) Fill and test the lines with mud. 6) Break circulation with the cementing unit to make sure that the bit nozzles are clear. Stop pumping when circulation is established. 7) Close the top pipe rams or the annular. 8) In surface well head both flanged and multistage wellheads, open the annulus of the previous casings. In sub sea well head pay attention to not excide the burst pressure of the previous casing. 9) Pump slowly and in continuous way, until pressure builds up to approximately half the anticipated maximum surface pressure. 10) Once pressure is established, pump uniform volumes of mud and wait for the time required for the pressure to stabilise. The flow rate range is from bbl/min (20 I/min) up to a maximum of 1 bbl/min (160 I/min), however values of 0.25 bbl (121/4" and smaller holes) or 0.50 bbl (171/2" hole) are commonly used. 11) Note the cumulative mud volume pumped, the final pumping and final static pressure. 12) Repeat steps (9) and (10) above and plot pressure versus cumulative mud volume for each increment of pumped volume. .2 S P E O IDENTIFICATION CODE PAG 208 of 338 ENI S.p.A. EF11 UP Division REVISION STAP-P-1-M-6140 0 11 13) Continue this procedure until: • Two or three points on the plot are reached where the pressure deviates and falls below the approximate straight line (or if the pressure does not increase with the injected volume). The point on the plot where the curve begins to bend away from the straight line is called Leak Off Point (Refer to Figure 15-1) • Or the predetermined test pressure is reached. 14) Stop pumping, shut in the well, record and plot pressure versus time until stabilisation (usually it takes 15-20min). In the early stage (2-3min) one value every 15-30sec should be collected while for the remaining a value of pressure every 30- 60sec may be sufficient. The use of PACR or an equivalent device, if available, is preferred. 15) Bleed off the pressure and record the quantity of fluid returned into the cementing unit. Compare it to the volume used for the test to obtain the amount of fluid lost to the formation. 16) Open the BOP and calculate the formation strength in terms of `Equivalent Mud Weight' using the lowest between leak off point pressure and stabilised pressure. 17) Collect the data recorded during the test in a data sheet together with the following information: borehole diameter, depth of test, depth and type of the last casing, mud density, plastic viscosity, filtrate and gels (refer to the example on the next page). Note: The LOT pressure doesn't exceed the pressure which the casing was tested. Note: When a good zonal isolation behind the casing is imperative, the Leak - off test should be carried out with a retrievable packer to avoid pressurising the casing which may cause possible permanent damage to the cement bond by the creation of micro annuli in the cement. Note: The pumping rate should be kept within the limits described in step 9). If the rate is too low, filtration losses will mask any leakage loss, or, if the rate is too high the formation may suddenly break and the leak off pressure will not be determined. Also, the longer the open hole section, the higher should be the injection rate. If the initial pumping rate is not sufficient, the well should be depressurized and the test restarted with a higher rate. Note: If a float valve is used in the drilling string, the test can not be carried out by pumping down the drill pipe. In this case rig up the cementing unit to the choke or kill line, fill and test the lines against the fail-safe and establish circulation through the riser. Close the BOP and perform the formation strength test pumping down the annulus. S P E O IDENTIFICATION CODE PAG 209 of 338 ENI S.p.A. EnO UP Division REVISION STAP-P-1-M-6140 0 11 LEAK -OFF TEST REPORT RepGrttd° Date: WELL NAME: WELL CODE: CONTRACTOR: RIG NAME: RIG CODE: Open hole depth (m): 825 Mud TV e: FWGELS Rig t e: J.uPs HoleDameter(in): 12114 Weight(KgA): 1.3 R.K.B.eleieton(m): 26 Last Cs . Shoe (m): 797 Marsh Mscos seci0t : 44 Water Depth (m): 24 Csg. diameter (in): 13' 8 P .V. c s : 19 Pumps: 12-P-160 Grade: S55 I .9b110D ): 5 Liners (in): 6.6" Wei ht Obft): 61 Gels b/100 t : 2/8 Flow Rate I : 0.25 Max. Burst pres (psi): 3103 W.L =30 min): 105 Litholo r. Shale Expected EMVV 1.68 Kg/cm /10 m Time min Vol urn e bbl Pressure Psi Time Volume min bbl Pressure Psi Time min Voume Pressure bbl Psi 1 025 50 9 2 490 16 2 435 2 050 100 95 2 480 3 0.76 200 10 2 470 4 1D0 300 10.6 2 483 5 125 400 11 2 465 6 150 500 11.5 2 460 7 1.75 570 12 Z 445 8 2D0 800 13 2 440 8 21)0 650 1 14 2 1 437 8.5 2 D 0 605 1 15 2 1 435 Nde: Pumped with a constant tow rate of(bbl): Wlume pumped (bbl): \,blume rewmed (bbl): (psi) 1000 900 800 P stop pump 700 F e 600 S shut in curve S 500 ti U 400 I- 8 minutes e 300 20D 10D OE ---Ji- 0 0,25 0,5 0,76 1 1,25 1,5 1,75 1 2 3 4 5 6 7 8 9 10 11 12 Cumulative Volume (bbl) P. Time mins RESULTS: (Press. ,d + Press. Lo. )x1 Omepth=[(1.3 x 797 f 10) + (430 x 0.07)] x 10 f 797 = 1 .68 (KgicmZ110 m) Note: I Com an Re reserrtati e Figure 15-1 - Leak -Off Test Report 1 12/16/08 MRT I AJR I I Add New Well Conductors 4-24 1 2 12/23/0 JFC I JMS I jAdd New Well Conductor OP26 Oliktok OLIKTOK 0 Point INTAKE DOCK OPP THIS MODULE R\ Ilk P SURVEY TANK 1 N �o DS-3R 9 O DEW UTAE t� (i { SITE STP TANK OUKTOK OINj MODULES N C STAGING REA•, T13N, RGIE DS-30 18 ��'1(1 15 SCALE: 1" = 150' DS-30 c 21�\ 19 "; 2 f---To S TP PAD �\ VICINITY MAP o� \ SCALE: 1 = 1 Mile 0 �� o -o 0(51 01.1 rn a�a ooa-o G o°000 00 � O O OZ \ � `. OLIKTOK 1 013 POINT PAD a \ G • o� \ is \ \� \ 0 0 LA 1� 1 SEE SHEET 3 FOR NOTES \ Existing Conductor LOUNSBURY 1 & ASSOCIATES, INC. • Conductor Asbuilt this survey SUR ORS ENGINEERS PLINNERS AREA: MODULE: UNIT: Eno P tirdleuunn� OWELLO CO DIUCTORD Inlll ' ASBUILT LOCATIONS CADD FILE NO. DRAWING NO: PART: REV: LK680D1 10/9/08 1 NSK 6.80—d1 1 1 OF 3 1 2 1 12/16/08 MRT I AJR I I Add New Well Conductors 4-24 1 2 2/23/0 JFC I JMS I lAdd New Well Conductor OP26 PROTRACTED SECTION 5, T. 13 N., R. 9 E., UMIAT MERIDIAN WELL NO. AK STATE PLANE (NAD83) y x LATITUDE(N) NAD83 LONGITUDE(W) NAD83 SEC. LINE OFFSET PAD ELEV. O.G. ELEV. F.N.L. F.E.L. OP-11 6,036,332.70 1,656,791.89 70° 30' 39.015" 149" 51' 57.587" 2,052 1,519 12.1 4.0 OP-12 6,036,328.85 1,656,784.83 70' 30' 38.977" 149° 51' 57.795" 2,056 1,526 12.2 4.0 OPO3-PO5 6,036,325.10 1,656,777.76 70' 30' 38.940" 149' 51' 58.004" 2,059 1,533 12.2 4.0 OPO4-PO7 6,036,321.43 1,656,770.69 70' 30' 38.904" 149° 51' 58.212" 2,063 1,541 12.2 3.8 OP05 6,036,317.71 1,656,763.67 70° 30' 38.868" 149' 51' 58.419" 2,067 1,548 12.2 3.7 OP06 6,036,313.96 1,656,756.55 70' 30' 38.831" 149' 51' 58.629" 2,070 1,555 12.2 3.6 OP07 6,036,306.41 1,656,742,45 70' 30' 38.757" 149° 51' 59.045" 2,078 1,569 1 12.2 3.5 OP08 6,036,302.66 1,656,735.36 70° 30' 38.720" 149' 51' 59.254" 2,082 1,576 12.2 3.5 OP09 6,036,298.90 1,656,728.32 70' 30' 38.683" 149' 51' 59.462" 2,085 1,583 12.2 3.5 OP10 6,036,295.16 1,656,721.26 70' 30' 38.647" 149' 51' 59.670" 2,089 1,590 12.2 3.7 OP11 6,036,291.38 1,656,714.21 70' 30' 38.610" 149' 51' 59.878" 2,093 1,597 12.2 3.8 OP12 6,036,287.63 1,656,707.14 70' 30' 38.573" 149' 52' 00.086" 2,097 1,604 12.2 4.0 OP13 6,036,276.37 1,656,685.97 70' 30' 38.463" 149' 52' 00.711" 2,108 1,626 12.2 3.6 OP14 6,036,272.66 1,656,678.89 70° 30' 38.426" 149' 52' 00.920" 2,112 1,633 12.2 3.5 OP15 6,036,268.88 1,656,671.79 70' 30' 38.389" 149' 52' 01.129" 2,115 1,640 12.2 3.4 OP16 6,036,265,11 1,656,664.75 70' 30' 38.353" 149' 52' 01.337" 2,119 1,647 12.2 3.3 OP17 6,036,261.36 1,656,657.70 70' 30' 38.316" 149° 52' 01.545" 2,123 1,654 12.2 3.2 OP18 6,036,257.62 1,656,650.62 70' 30' 38.279" 149' 52' 01.753" 2,127 1,661 12.2 3.1 OP19 6,036,250.09 1,656,636.50 70' 30' 38.205" 149' 52' 02.170" 2,134 1,675 12.2 2.5 OP20 6,036,246.31 1,656,629.41 70° 30' 38.168" 149' 52' 02.379" 2,138 1,682 12.2 2.2 OP21 6,036,242.57 1,656,622.39 70' 30' 38.132" 149° 52' 02.586" 2,141 1,689 12.2 1.9 OP22 6,036,238.82 1,656,615.39 70- 30' 38.095" 149' 52' 02.793" 2,145 1,696 12.2 1.7 OP23 6,036,235.05 1,656,60&27 70' 30' 38.058" 149' 52' 03.003" 2,149 1,703 12.2 1.5 OP24 6,036,231.36 1,656,601.27 70' 30' 38.022" 149° 52' 03.209" 2,153 1,710 12.2 1.3 DISPOSAL WELLS WELL NO. AK STATE PLANE (NAD83) 'y' x LATITUDE(N) NAD83 LONGITUDE(W) NAD83 SEC. LINE OFFSET PAD ELEV, O.G. ELEV. F.N.L. F.E.L. OP25 6,036,004.35 1.656,510.91 70° 30' 35.791" 149° 52' 05.885" 2,380 1,802 12.2 -2.7 OP26 6,036,012.10 1,656,525.47 70° 30' 35.867" 149° 52' 05.456" 2,372 1,787 12.2 -2.7 LOUNSBURY & ASSOCIATES, INC. SURVEYORS ENGINEERS PLANNERS AREA: MODULE: UNIT: POINT Einfi PeturdleuIn"ni WELLOCONDUCTOR D End ASBUILT LOCATIONS CADD FILE NO. DRAWING NO: PART: REV: LK680D1 10 9 08 1 NSK 6.80-d1 1 2 OF 3 1 2 REVI DATE IBY ICK IAPPI DESCRIPTION I REV I DATE BY CK APP I DESCRIPTION 1 12/16/08 MRT I AJR I I Add New Well Conductos 4-24 1 2 12/23/0 JFC I JMS Add New Well Conductor OP26 NOTES 1. COORDINATES SHOWN ARE A.S.P. ZONE 4, NAD 83. DISTANCES SHOWN ARE TRUE HORIZONTAL DISTANCES. 2. GEODETIC COORDINATES SHOWN ARE NAD 83. 3. BASIS OF LOCATIONS ARE DERIVED FROM OPUS SOLUTIONS. 4. CONDUCTORS ARE LOCATED WITHIN PROTRACTED SECTION 5, TOWNSHIP 13 NORTH, RANGE 9 EAST, UMIAT MERIDIAN. 5. ALL ELEVATIONS SHOWN ARE B.P.M.S.L. DATUM. 6. SEE LOUNSBURY DOCUMENT L-2539 FOR NAD27 INFORMATION. oF...... `.E. SURVEYOR'S CERTIFICATE % ♦♦♦ I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE i ` h 00,,,,, ,,,,,, , o 0 / LAND SURVEYING IN THE STATE OF 0 � ALASKA AND THAT THIS PLAT REPRESENTS ♦ :, A J. ROOKUS ♦ A SURVEY DONE BY ME OR UNDER MY J LS-803 J i ♦ �F '. : J4 AV AW ♦♦♦1<pp•/jZ3 DIRECT SUPERVISION AND THAT ALL f P�OC3�� CORECDIMENSIONS SAND 07HER DETAILS ARE OF DECEMBER 23, 2008. +,"`�►��• LOUNSBURY & ASSOCIATES, INC. SURVEYORS ENGINEERS PLANNERS AREA: MODULE: UNIT: (� n� D �=�� Ir'etirolle��i Chill WELLONDUCTOR ASBUILT LOCATIONS CADD FILE NO. LK680D1 10 9 08 DRAWING NO: 1 NSK 6.80-d1 PART: 1 3 OF 3 REV: 2 Drilling Hazards Summary 16" Open Hole / 13-3/8" Casing Interval Hazard Risk Level Mitigation Strategy Broach of Conductor Low Monitor continuously during interval. Gas Hydrates Moderate Control drill, Reduced pump rates, Reduced drilling fluid temperatures, Additions of Lecithin. Running Sands and Low Maintain planned mud parameters, Increase Gravels mud weight, use weighted sweeps. Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out 12-1 /4" Open Hole / 9-5/8" Casing Interval Hazard Risk Level Mitigation Strategy Running Sands and Low Maintain planned mud parameters, Increase Gravels mud weight, use weighted sweeps. Gas Hydrates Low Control drill, reduced pump rates, reduced drilling fluid temperatures, additions of Lecithin. Stuck Pipe Low Good hole cleaning, pre-treatment with lost circulation material, stabilized BHA, decreased mud weight Abnormal Reservoir Low BOP training and drills, increased mud weight. Pressure Lost circulation Low Reduced pump rates, mud rheology, LCM Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out 8-1/2" Open Hole / 5-1 /2" Liner Interval Hazard Risk Level Mitigation Strategy Abnormal Reservoir Pressure Low Stripping drills, shut-in drills, increased mud weight. Stuck Pipe Low Good hole cleaning, PWD tools, hole opener runs, decreased mud weight Lost Circulation Low Reduced pump rates, mud rheology, LCM Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets),pumping out, backreamin String 0D7WeightlGrade Connection Surface Casino 13 3/8"• 68.300 ppf, L-80NrA Burst Design (13 3A3" Surface rasing) 800 v 2400 7 N 3200 String Summary MD Interval (m) Drift Dia. (n) Burst C4113pse Axial 40.9.2756.0 12 259 2.49 21.87 (6.00) 3.10 91.119 Total = 01.110 Collapse Design (13 W" Surface Casing) Axial Design (13 "" Surface Casing) 'll N a, D - L Q. N O ou QLI 2400 en M 01) 32DO - - Design Dad Line 4000 Ije filing 4000 - 1100 "DO 4600 Burst Rating (psi) I 1 Deign LIOW -Ripe Roiling Une --- 800 3200 4000 0 760 15DO 2250 Collapse Rating Os) Axial Force Qbf) . ...... ......... Mrrimum Safety Factors (f3 318" Surface Casing) . . . . . . . . . . . . . . . . . . . . . MD (m) OONUalght/Grade Conection Burst(A) Collapse(!) Axial(A) Triaxial(A) 41 13 378", 69.000 ppf, L-80 N/A 2.51 06 + t00.O0 Cl 8,44 A5 3.17 06 ' 41 2.40 85 + IMOD Cl 0.44 A5 3.10 85 41 4.90 012 + 100.DO CI 0.44 AS 0.10 BIZ 42 4.90 Bit + IDo,00 CI 0.44 A5 0.10 012 i 76 5.04 B12 + 1DO.00 Cl 8.55 A6 6.22 812 76 5.04 B12 + 100.00 Cl 8.51 M 0.22 012 i 100 5,19 812 91.64 Cl 041 A5 588 012 000 0.11 812 56.80 CI 6.10 A5 004 Oil i S00 0.64 612 48.63 CI 0.44 A6 0.14 Oil SOD 0.04 812 48.03 C1 0,44 B12 0.14 811 932 6.73 912 47.46 Cl 6.50 912 6.16 Bit 061 7.10 912 43.81 Cl 6.72 912 6.22 Oil 1000 7.20 812 4240 C1 0.79 Al 8,25 811 1200 7,90 912 37.00 Cl 7.00 Al 8.35 oil 1406 0.01 012 34.33 C1 7.40 At 6.46 Bit 1400 Ohl 912 34.33 CI 7.40 At 0.42 Oil • 1502 0,30 sit 32.80 Cl 7.30 At 6.26 Oil ' 1607 0.30 Bit 32.72 CI 7,37 At 6.25 Oil 1617 0.33 BII 31.23 CI 7.35 At 6,00 oil 2000 0.42 BII 26.03 C1 0.06 A6 5,57 oil 2000 0.42 BII 26.03 CI (6.22) C1 5.65 sit 2100 0,44 BII 26.01 C1 (8,26) C1 5,69 all 2100 9.44 811 26.01 C1 (6,26) Ct 5.58 oil 2200 0.48 BII 25.10 CI (6.28) C1 5.62 Oil 2200 9.46 Oil 25.10 CI (e") Ct 5.63 Oil 2200 9.40 Bit 24.00 Cl (0.30) Cl 5.05 oil 2274 9.48 Oil 24.03 Cl (630) 05 5.65 BII 2300 9.40 Oil 24.44 C1 (6,28) 05 5.80 oil 2310 0.49 Oil 24.31 CI (0.26) 05 5.07 all 2367 9.49 Oil 24.05 C1 (0.24) 05 5.08 oil 2400 0.50 oil 23.70 CI (0.21) 96 5.70 Oil 2400 9.50 BII 23.70 CI (0.20) 95 6.00 oil 2500 0,52 Oil 23.18 CI (0.14) 05 5.73 Oil 2500 9,52 B11 23.18 Cf (0.13) 95 5.73 oil 2800 0.54 B11 22.01 CI (0.07) 96 6.70 Oil 2600 9.54 Oil 22.01 CI (0.08) 95 6.77 oil 2700 0.58 all 22.12 CI (0.03) 05 6.00 oil 2766 0,57 911 2117 C1 (0.00) 85 5.02 oil 2750 9.57 Oil 21.87 CI (0.00) 85 5.02 Bit 05 Pressum Test 911 Fraotum @ Shot W IM BHP at Surface 012 Orton Cemem Pressure Test(Burst) C t FntIlPsnial Evacuation Al Running In Holt -Aug. Speed A5 Omen Corners Pressure Test(Axial) () Compression Collapse Load Data (13 3/8" Surface ]asing) Drilling Load: Full/Psnlal Evacuation Mud W4ight: 0.40 Pp0 Mrd Level, MO: 42,0 vsft Assigned External Pressure: Fluid Oocitnts (wl Port Pressure External Pressure; Fluid Oracitms (wl Port Prtssun TOC, MO: 40,9 utft Prior Shot, MD: 404 uslt Fluid Gradient Above TOC: 0.40 ppg Fluid Gradient Below TOC: 0.40 pp0 Pon Pressure In Open We Below TOC: No String Summary String o9f0tightforadt Connection MD Interval (m) Deft pia. (ol) Burst Collapse AaOI Production Casing 9 3/8". 4? DOD ppl. L•80 NIA 400-007.0 8.623 A 3.46 2a8 492 4.01 227.030 Taal • 227.030 Burst Design (9 5:6• Production Casing) Collapse Design 19 5.0• Production Camp) Axial DeSV% 19 SW Production Casing) 800 1- - g00 goo N to N 1000 .. .._. _..__.___._ ____.___.. _-.- __ "Do - L 1400 - - du N cu O I O O a v a v 2400 .... ._ .. v 2400 v 2400 N 11) 6l N a1 Ou N W a ' ! 3200 3200 3200 Design Load Lire Design oad the - Design Load Linei 4000 { Ppe Rafting ` T Pipe R n4. 4000 _ Pipe katng . r 2000 4000 8000 100000 600000 000000 0 2000 4000 Burst Rasing (psi) Collapse Paling (psi) Axial Force Qb) Mnmtrlt Wity Factors (9 Ur Production Cason) MO (m) 00ANeight7Grade Conection Burst(A) Collapse(A) Axial(A) Tnasial(A) 41 9 W. 47 OD0 ppf. L40 NIA 3.45 05 a 100.00 Cl 5.33 05 409 BS 43 3.46 BS a 100.00 Cl 402 05 401 94 43 11.05 ell 4 100.00 Cl 0.33 B5 0.42 Al 76 11.64 Oil 4 100.00 Cl 6.43 all 0.47 At 76 11.84 B11 4 100.00 Cl 6.42 Oil 6.46 At $00 11,66 Bit 1003 Cl 6A7 oil 5.41 At 633 11.55 BH 15.21 Cl 5.62 Ai 6.40 AI Soo 1f.52 Off 12.10 Cl 5.53 Ai 5.38 At 1000 11.41 B11 9.77 Cl 5.54 At I.. Al 120D 11.46 811 8.24 Cl 5.65 At 6.34 At 1400 11.43 911 7.16 CI 5.50 AI $32 At 2000 11.34 Bel 5.19 Cl 5.64 At 520 AI 2100 11.32 oil 4.97 CI 586 At 5.28 Cl 2200 11.31 Bil 4.78 CI s67 AI 5.22 Cl 2300Bn 4W CI 5.69 Al 5.17 CI 2400 IL29 all 4.44 CI 6.71 At 5.11 CI 2500 11.27 BII 4,30 Cl 5.73 At 56 Cl 2600 11.26 B11 4.17 C1 11.76 At 5-01 Cl 2 70 0 11.25 811 446 CI 5.78 Al 406 Cl 2750 11.25 B11 4D1 CI 6.79 At 4.04 Cl 2800 11.24 B11 3.00 CI 6,80 AI 4-00 Cl D 1L24 Oil 3.00 Cl 5.8D Al 492 Cl228000 11B1il1 3m CI 5.93 AI 428 Cl 2900 11.23 38s 6.$3 AI 4 CCt 300D oil 3.880 GI $5 AI 688 4874 3 10 D 11.22 BII 3.74 CI At 4.00 CI 3200 1121 Bit 3.69 cl 5.90 At 4.77 CI 3200 n.21 811 3D8 Cl 5.90 Al 4.78 Ci 3300 11.11 BIl 343 Cl 5.93 AI 4.75 Cs 3400 11.20 B 11 3.80 Cl 590 AI 4.73 CI 3505 1120 B11 3.60 CI 5.98 At 466 Cl 3501 11.20 all 3.56 CI 590 Al 6.44 At 1000 It. 15 oil 3.21 CI 6A1 At 6.50 Cl 5000 11.15 all 3.21 CI 6.41 At 6.30 Cl 5857 ID.95 911 3D4 CI $49 Al SW Cl 7372 10.62 811 3.01 CI 7" AI 4.10 CI 7600 10.60 all3,01 CI 701 BII 404 Cl 7900 10.62 911 3DD CI 8.98 Btt 4ba CI 7045 1041 Bit 3.00 CI 6.01) Bn 4.o Ct 8200 10.45 BII 3D0 CI 6.96 611 403 CI 8200 10.40 an 3.00 CI 6.97 Bu 403 q 8600 10.42 Oil 2.99 CI 0.05 oil 4D2 Ct 9600 10.42 oil 299 CI 0.96 all 4D3 Cl 9534 10.41 oil 2.09 CI 6.96 oil 4D2 CI 8700 1039 Bn 1.99 Cl 6.94 Bl1 4. CI 8700 10.30 all 2.90 CI 6.95 all 402 CI 890o 10.37 Oil 2.99 CI 6.94 BII 402 CI Burst Wad Data (9 W Production Casip) Drilling load: Pressure Test Tut Prusurt; 1991.00 psi Mud Weigh 8,40 ppg Plug Depth, MD: 43.0 usn Assigned Est. Pressure: Fluid Gradients IW Pont Pressure) Drilling Load: Fracture @ Shoe s/ 113 BHP A Surfaet Surface Pressure (In a BHP)' 599.Do psi shot Depth. Mo: 0067.0 usft Fracture Pressure at Shot. 2402.07 psi rraavre Li3* of Ester. 0.00 ppq Eatemal Pressure: Fluid Gradients (ir/ Pont Pressure) TOC. MD: 5000.0 uslt Prior Sloe. W: 2756.0 usft ►tad weight Move TOC: 0A0 ppq Fluid Gradient Belo. TOC: 833 ppq Pero Pressure In Open Hole: Ho fCollapse load Oslo 19 Wr Production Cason) Drilling Load: Full/Partial Evacuaton Mud weight: 9.40 ppq Mad Levtl. MD: 5857.0 will Assigned External Pressure: Fluid ondients (W Pore Pressure External Pressure: Fluid Gradients (W Pere Pressure TOC. MD 5000.0 Wit Prior Shoe, LID: 2756.0 usli Fluid Cradien AOove TOC: 9.40 ppg Fluid Gndiont Below TOC: 0.40 ppq Pore Pressure In Open Hole Belo. TOC: No $000 10.37 all 2.99 Cl 695 all 402 CI - 9100 1036 all 2.99 CI 693 BII 402 CI 9100 10.30 BIt 2199 CI 6.04 an 4102 CI 9128 10.35 all 2.90 CI 7-81 811 4.13 CI - 9188 10.35 Bl1 2.99 CI 8.B4 BII 4.29 Cl Anal Wad Data (9 5Ar Production Casing) 9199 10'35 BIl 299 CI 10.11 At 4.43 CI 9300 1034 all 2.99 CI 10.30 Al 496 Ct Running in Hale - Arq. Speed: 0.0 Ws 9600 10.33 Bll 2.99 Cl 11.33 Al 496 Cl 9850 10.32 BI1 2.98 C1 12.44 Al 4.96 Cl 9857 10.32 oil 2.98 Cl 12.44 Al 4AS Cl 0.erpull Force: 0 Df - 65 Pressure Test Pre -Cement Static Load: 811 Fraot ure @ Shoe W If3 BHP m Surface Pickup Forge: 0 Atf C 1 Full/partial Evacuation Al Running in Hob -Aug. 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R { 00 0 # & »( R ; @ a ;k k / \ \}\ ) . .} . . . \I a ��. _ \ CD CD 0 � _/ ,g % � CD CD \§' : kip La ° Cl - CD ` / t.. ' , »» § ( E \ \ \ f ( \ \ \ , ) \ � $ | _ 'r ) ƒ ` o m Cl) ¥ r ! U009 5eSUa I 3!I Schiumheruer 2ni -1000 0 1000 2000 3000 4000 5000 6000 7000 8000 Oliktok Point I-1A-106 (P5b) iaDu,MD E. Cry 11000 9 17 18123 MD 11000 18120 MD Cry L1W Entl Cry .N 18117 MD 17646 MD 9t 16 17610 MD EM Cry Cry 211M 10000 - Tot is 7123 MD - 17576 MD 10000 17M MD Cry 2IW End Cry 17027 MD 16E01 MD To 14 Entl Cry t6588 MD 9000 16102 MD Cry 21100 1— MD 9000 T9t 13 16078 MO Cry 2�100 End Cry 16061 MD 1559E MO Tg112 15568 MD 8000 End C, 150 8 MD Cry 2 100 15519 MD 80[]0 Tilt 11 t5058 MD Cry 2�100 EM Cry 15066 MD 14WI MD Tgt10 EM Cry 1454] MD 7000 19964 MD Cry v1o9 7000 Tp 9 14504 MD 14036 MO Crv8MD 13978 MD Erd Cry 13526 MD Tgt 8 p t0 6000 13526 MD Cry 21100 8000 13E 3 MD Tgl7 13524 MD 11 13015 MD 0 cry vmo N U � 12969 MD Erd Cry 12550 MD T06 5000 12018MD C.zlw 2�M 5000 Z TM 12461 MD 11994 MD Crv21100 EM Cry 11990 MD 11464 MD Tgt4 4000 Erd Cry 11030 MD 11461 MD Cry y100 4000 1135] MD TV 1.73 MD Crv2i1W 10920 MD EMC, Oliktok Point 1-1 104]7 MD liN,623MD crvvlo9 3000 6938 MO 10448 MD 3000 End Cry t 0093 MD Cry y100 10023 MD T911 8953 MD 2000 aya 2000 9650 MD End Cry 9253 MD 1000 - 4- 1000 2613 MD Te4n Survey 16 145 MID 8MD kOP Cry 1 .1. 150 MD 1}y8' 0 2791 MD Cry 0 0 MD 350 MD Cry }Y100 Cry 2.Y100 6953 MD 550MD Cn O.Y100 Crv3.V100 Ertl Cry 1404 MD 19M MD 3505 MD -1000 0 1000 2000 3000 4000 5000 6000 7000 8000 EW (ft) Scale = 1:650(ft) Borehole: Well: Field: Structure: Oliktok Point I-1A-106 (P5b) Oliktok Point I-1 Nikaitchuq Oliktok Point Gravity 8 Magnetic Parameters Surtace Location NAD27 Alaska State Plane, Zone 04, US Feet Miscellaneous Model: BGGM 2073 Dip: 81.027° Date: 15Jun-2014 Let: N 70 30 40.06 Northing: 6036581.15ttU Grid Cony: 0.1293° Slot: OPOt TVD Ref: Rotary Tablet' 53tt above MSL) MagDec: 79.294° FS: 57620.403nT GravityFS: 1001.989mgn )9.80665 Based) Lon: W 149 51 46.24 Easting: 576760.BSftUS ScaleFact: 0.99990032 Plan: Oliktok Point I-tA4061P56) Oliktok Point 1-1A-106 (P5b) Anti -Collision Summary Report Analysis Date-24hr Time: April 07, 2014- 11:48 Analysis Method: Normal Plane Client: ENI Reference Trajectory: Oliktok Point I-lA-106 (P5b)(Def Plan) Field: Nikailchuq Depth Interval: Every 10,00 Measured Depth (ft) Structure: Oliktok Point Rule Set: D8M AntiColllsion Standard S002 v5.1/5.2 Slot: OP01 Min Pls: All local minima indicated. Well: Oliklok Point 1-1 Version I Patch: 2.7.1043.0 Borehole: Oliklok Point 1-1A-106 Database 1 Project: localhoslldrilling-Nikaitchuq 2.7 1043 Scan MD Range: 144,58f1- 18630.63f1 Traiactory Error Model: ISCWSAO 3-D 95.000%Confidence 2.7955 sigma Offset Trajectories Summary Offset Selection Criteria Wellhead distance scan. Nol performed! Selection filters: Definitive Surveys - Definitive Plans - Definitive surveys exclude definitive plans -All Non-Def Surveys when no Def-Survey is set in a borehole - All Non-Def Plans when no Def-Plan is set in a borehole Offset Trajectory Se aration Allow Sep. Controlling Reference TrajectoryRisk Level Alert Status Ct-Ct H MAS fl EOIl H Dev. H Fact. Rule MD ft TVD ft Alert Minor Major Oliklok Pont 1-1 (Def Surrey) Fel Me1or 000 1075 -754 _1075 -017 OSF 1.60 1"58 1"58 CtCt-15-15.00 OSF,150 OSF�l.W Enr Mala te O.W 1 N - -- -1 69 _ 1 98 1.94 OSF i.W 150.00 150,00 MlnPls 0.01 2.03 -1,71 -2.02 t 81 OSF 1.W 160.00 160.W MINPT-6EOU 0.05 2.09 -171 203 -164 OSF 150 170.00 17000 MInPD0.ADP 2.28 2.90 -0.04 -064 0.96 OSF 1.50 279.96 279.89 OSF>100 Exit Me. 3.02 3.06 0.61 .0.04 1.47 OSF 1. W 299.94 299.84 OSF>1.50 Exit Mirror 48.W 1083 41.00 37.76 7.33 OSF 1.50 861.65 853,39 CtCI<=15-1500 Exit AIM 703.80 58.94 663.94 644. W 18 22 OSF 1.50 2438 W 2222 M MinPt-O-SF 80105 4906 768.02 75199 2496 OSF 1.50 2W9.45 2463.29 MinPt-0 F 831.88 79.79 778.W 752M 15.82 OSF 1.50 3665.55 2767,08 MinPl-CICt 83289 82.63 77754 7W.36 15.30 OBF 1.W 3712.06 2776,42 MINPT-O.EOD 834.00 8381 777.80 7W 1 15.09 OSF 1.so 3735.50 2781.13 MInPt-O-ADP 803.27 117.72 82447 185.55 11.59 OSF i. W -,.1 28B2.W MInPt-O.SF 1276.73 189.94 1/49.77 1086.]9 10.13 OSF 1.W 714243 34&M MInPI-O-SF 28587 87W 227.54 198.87 497 OSF 1.50 10241,55 3823,09 OSF<5.00 Enter Alai 260.62 187.18 135.W 73.44 2.09 OSF 1,60 10521.66 3827.52 TO 0.00 198 -1. -1.g8l -' 91 OSF 1.50 15000 150.00 Ctct-15-15.00 OSF<l50 OSF0W Enter Mgar OW.k Pont 1-2 (Def Survey) Warning "'I'd 8.57 6 62 6.99 195 1503 VAS =2,021m) 1.58 1.58 Ctct-5-15.00 Enter.1 13 91 6 62 1155 ] 28 1003 MAS = 202 (m) 278.73 27867 MInPt-D-SF 49.02 662 45.17 42 40 17 26 MAS = 2.02 (m) 493.37 492.52 ctct-15-15.00 Ent AIM 12823.9' 113.36 12748.05 12710.59 1]11 OSF 1.W 8809.98 37"17 MInPI-0.SF 1OM7.12 90.67 10276.35 1024645 1728 OSF 1.So 9133.36 3771.57 MIoP1-O-SF 11811.W 14805 11712.65 11W363 1N4 OSF 1.W 11348.84 3846.68 MInPt-O-SF 12264, 55 159" 12157.02 12105.11 1160 OSF 1.50 11990.21 3849.W MInPI-O�SF 130W.28 191.63 12952.20 1211:65 10291 OSF 1,60 13003,55 3846.42 MirPt-O.SF 13900,29 221.94 13872.of 1373836 94.7 OSF 1.50 13M 70 3881.51 MinPt-0.SF 14512.35 243.16 14349,92 14269.20 8988 OSF 1. W 1465809 3921.90 TD 10582,M 2441 105W-13 10558.32 6776 OSF 1.W 870,78 862.18 MinPt- F 9876.26 23.19 '6047 9853.W W7.01 OSF 1.W 906.78 8070 MinPt-O-SF W66 Q 2191 9D51.46 90.49 649 W OSF 1,50 953,92 941,66 MInPt-O-SF 8270,05 20.51 6256.05 8249 54 635 11 OSF 1.60 1003.91 989.OD MinPI-O-SF 7745.M 19.22 773ZSo 772642 63717 OSF 1.50 1038.29 1021.35 MInPI-O.Sf 7652,93 1903. 7639.91 7633.% 6W 02 OSF 1.50 1044.22 10M.91 MinPt-0.SF 7392.W 1840 7379.93 7374. 13 6W.67 OSF 1 50 1062,32 1043.86 MInPt-0.SF 7179.05 17.71 7166.91 716133 643 W OSF 1,50 108039 106073 M'InPt-O.SF 7126.32 17.53 7114.31 7108. 79 64599 OSF 1,501085.20 1065.20 MinPt-O-SF 7002.41 17.22 8990.60 6985 19 646 W OSF 1,50 1096.78 1075.88 MInPt-O.SF 6724.35 16.70 6712.89 64171 OSF 1.W 1123.23 1100.W WrPt-0.SF 6694.33 16.63 W82.Of :707.65 667770 64162 OSF1.W 1126.W 11W 09 MInPI-OSF 6177.20 15.87 616630 0161.33 622 33 OSF 1.50 1178.% 1151.82 MinPt-O-SF 3531.14 14.53 3521.1 351561 39100 OSF 1.60 1308.56 1268.W Mir1P1s Oliktok Pont 1-2PB2 (Def Survey) 'Namm9 Alen 8.57 6 62 6.9E 195 15.03 MAS=2.02 (m) I4 M 144.58 C1Ct 15m<15.W Enter Nert 13.B1 882 11.55 7.28 1003 MAS=2.02 (m) 278.73 278.67 MinPt-0.SF 49.02 682 45.17 42 m 17 26 MAS = 2.02 (m) 493.37 492.52 Ctct-15-15.a0 Exit Abrt 12636.12 11170 12561.32 1252442 t)11 OSF 1.50 8830.00 3746.20 MinP40.SF 10337.12 90,66 10276.35 10246 45 1 ]2 8 OSF 1.50 9133.36 3771.57 MinPI.O-SF 11811.68 148.05 11712.W 116636 120.4 OSF 1.W 11348.84 3846.M MinPI-O-SF 159.43 12157.46 12104 116.0 OSF 1.50 11998.65 3849.80 MInPIO-SF :2266.08 259830 171.68 12483.72 12426.83 11070 OSF 1. W 1241167 3853.W TO 8436.32 20.8] 8422.08 841545 63626 OSF 1,50990.38 976,22 MInPt-O.SF 8272.60 20.47 8258.62 825213 6W76 OSF 1.50 999.63 gum Mint-O-SF 7745.64 1922. 7732.50 772642 63716 OSF 1.5010W.M '021.35 MInP1O-SF M5293 19W 7639.91 7633.90 636.02 OSF 1.50 1044.22 1026.91 MInPt-O-SF 7392.53 18.40 7379.93 7374. 13 636.W OSF 1.50 106232 1043.86 M'mPIO-SF 7179.05 17,71 7166.91 7161.33 64 3 57 OSF 1,50 108039 106D 73 MinPI-O-SF 7126,32 17,53 7114," 710880 645.99 OSF 1.50 1085.20 1065.20 MinPt-0.SF 7002.41 17.22 6990.60 698619 64667 OSF/.W 1OW18 107598 MInPI-O-SF 6724,35 16.70 6712.69 6707.65 641 71 OSF 1.50 1123.23 1100.50 MinPt-OSF 6694.33 16.63 6682.91 8677 70 641 62 OSF 1. W 1126.03 1103.09 MinPI-O-SF 6177 20 1587 61 W.W 6161.33 622.33 OSF 7,W 117899 115182 MinPt-OSF 3531.14 14531 3521 12 3516.61 391 W OSF 1. W 1308.56 1268.90 Mints 011ktok Pant 1-2PB1 (Def Surrey) W amng Alert 8.5] 662 699 195 1503 k1AS=2.02 (m) 14458 144.58 C1C1�-15m�15.W Enter. Alert 13.91 8.62 11.55 7.26 10.03 VAS =2.02 (m) 218.73 278.87 MinPt415F 4902 6.62 4517 4240 1726 MAS=2.02 (m) 49337 492,52 CtOt-15-15.00 Ent AIM 1W1156 104.85 10M131 1050672 15338 OSF 1.50 10112.46 3821.66 TD 3740.9 14 71 3730. 791 3726 231 410. W OSF 1. W 1" 72 126191 M.Pts OP03-PO5PB2 (Def Survey) Warning AlM 1]14 13 52 154 363 3411 MAS=4. 12 (m) 14959 14959 Ctc--15-5.00 EnterA n 32.77 13.52 2902 19.2 12a MAS =4.121m) 506.72 605.77 M P1-O�SF 49,05 1352 44.38 35.54 1381 MAS=4.12(m) 632,94 830,58 Ctcl'=15m 15.00 &n AIM 299.31 14.56 26920 284.7 33.54 OSF 1.W 1374.10 13M 88 MInPt-O-SF Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point 1-1A-106 (P5b) Page 1 of 13 Offaet Trajectory 1 Se ration Cl-Ct ft MAS ft EOU ft Allow Dev. ft Sep. Fact. Controlling Rule Reference Tra eel Rink Level Alert Stetua MD ft ND N Alert Minor M,jor 70999 53.97 67362 6W.02dl�l 0"1.W 193 1 2223. 17 MinPt-O-SF 11 W.32 98.28 111440 f08204 OSF 1.W 397725 282D.72 MInPt-0.5F 5001.58 14512 490449 485641 IF1.W 7846.52 362102 MinPtASF771.58 138.75 46]8.72 4632.81 OSF 1.W 808172 3840.25 MinP10SF74531 137,08 465298 4607.3 IF1.W 809770 36092 MWI SF 4687.W 1W 31 45W 38 4551,2 IF 1.50 8132,20 WS2.61 Min%-0.SF 3982.55 77.85 39W 39D4. T7. ]e 1 1,50 OD54.35 3765.96 MinPt-0.AOP 3982.20 77.40 3930.25 3904.W 78.23 IF 1.W 9D61.24 3766.48 MINPT-0.EW 3B81 9 11.10 31W 17 3101. 79.16 IF 1.50 9075.01 3767.50 MinPt-CICt 3982 73.88 391326 3888.99 81.62 OSF 1.50 960746 3797.23 MinPt-Clot 3:63.44 75. 3912.71 3W7.88 79.79 IF 1.50 9686.46 3801,36 MINPT-0.EW 3964.93 77. 3812 3887.33 77.69 IF 1.50 9804.09 380752 MINPT-0.EOU 3965.31 78.07 3812. 3W7.23 77.22 IF 1.W 9833. 77 3809.07 MInP,O0ADP 3908. 11.62 311147 3-111 73.71 IF 1.50 10188.94 W22.83 MinPI-C1Ct 39661 84.28 3909.62 3881.87 71.44 IF 1.50 10338.89 W2620 Min%-CtC1 39M 62 W49 3908.8 38WA3 89.W OSF 1.50 10436.82 3828.77 MINPT-0.EW 396702 8696 390B. 38W.06 69.22 IDS F 1.W 104W17 W2707 MmPt-O-ADP 4002,70 102.98 39M 70 3899.7 58.8 OSF 1.50 10979.90 3830.82 MinPt-C-SF '2246 113.1 3946.8 3909.29 53.78 IF1.50 113�.9/ 3846.59 MinPt4 3981.26 118.30 3903 W 3W4. 51 79 IF 1.50 11995.06 3849.80 MmPt-O-SF 3931. 139.W 3838.22 3]91.98 92.52 IF 1.50 12944.58 W47. 15 MInPt-CICt 3931,84 W.391 3837.91 3791,4 42.31 IFi.W 12874,64 38M 68 MIR, N31.99 140.53 383T. 378148 42.2 OSF 1.50 2994 1.87 W46.47 MinPt-O-SF 3933.06 139.28 3839.86 3793,78 42.66 IF 1,50 13165.56 3850.00 MINPT-O-EW 3933,11 139.35 383SSZj 3703 701 42.64 IF 1.60 13175.64 3850.44 MInPt-O-ADP 3933.78 140. 3839.81 3783.34 4231 IF 1,50 13235.33 3852.71 MINPT-0.EOU 3934.39 141.24 3839. 3783.1 4208. OSF 1.50 13265. 18 3853.84 MinPt-O-ADP 3973.99 16D.52 3866. 3813.47 37.36 IF 1.W 1397187 38W.43 MINPT-0.EW 3974. 10 iW.75 3866. 3813.41 37.31 IF 1.50 13981.80 3580.81 MlnPts OP03-P051.1 (Def Surroy) W-ft Alert 17.14 13.5 1545 3.83 34. 11 MAS=412(m) 149,59 149.59 CIC-15-15.00 Enter Alert 32.77 13.52 29.02 19.25 12.48 MAS=4A2(m) 506.72 505.77 Min%-0.SF 4905 13.52 44.36 35.54 13.81 MAS=4. 12 (m) 02.94 mom CtClc15-15.00 ExitA 299.31 14,59 289,18 284.72 33.4 1 1,50 1374,10 1326.88 MinPtASF 709.99 54,13 673.51 655.80 20.08 IF 1.50 2439.64 2223.17 MInPt-0-SF 1174.49 98,41 1108,50 1076.09 18.1 OSF 1.50 39W.54 2828.17 MinPt- SF 4620.82 13721 452902 4483.81 W.8 IF 1.50 ItM2.27 3873.28 MinPI-O-SF 3982.55 78.49 3929. 3904. 7 14 IF 1.50 W54.35 3765.96 MinPt-0.AOP N82.20 78.08 3929. 3804.13 77.54 OSF 1.W 11.24 31.1 MINPT-0.EW 3881 9 77.20 39W.11 3904.73 78.43 IF 1.50 9075,01 3767.50 MinPt-CICt 3982.0 73.84 3913.33 3889,05 81.57 1 i.W 9618.64 3797.81 MInPt-DIQ 3967.72 96. 3903.03 3871.18 62.27 OSF 1.50 07204 3811.07 Min%s 4110.W 118.85 4032.37 3993.75 W. IF 1.W 1097270 383063 MinPt-0.SF 4144.13 126.39 4059.54 4017.73 49. 1 1,50 113Q 21 384685 M'WtS 4089.99 128.67 4003.88 3961.32 48. OSIF 1.50 11995. 11 3849.80 MinPt-O-SF 4040. 145.04 39M w 3895.28 4206. IF 1,50 12805.33 3848.40 Minplctct 404120 147.48 3942.55 3893. 72 41.37 IF 1,60 12955.31 846 3.82 MINPT-0.EW 4041.32 147.62 3942.58 3893.70 41.33 1 1.50 12975,34 3846.67 MinPt-0.ADP 4041.53 14772 394212 3813.81 41. OSF 1. W 12985 47 3846.46 M'InPt-0.SF 9071.3 1 W.35 39" 14 3:11.02 38.31 IF 1.50 11111 1111 Min%-- 4071.92 162.10 3963. 39M 82 37.90 IF 1.50 13843.25 3875,61 MINPT-PEW 4074.80 185.57 3983.89 380803 37.13 OSF 1.W 13973.17 38W.48 MInPFO-ADP 4075.20 165.82 391M 32 3909.38 37.0 1 1.50 14003.12 3881.71 Min Pt-O-SF 4074.85 186.02 3950.31 3888.63 3302 IF 1.50 14911 41 3931.28 MinPt-Ctm 4030.06 216.67 3885.28 3813. 28.0 IF 1,50 16081.15 3961 60 MinPt- SF 4027.W 216.87 388269 38100..7 279 IF 1.W 16210.,39 1.13 MmPt-CC1 4028.10 28. 307 283 1 50 4039 396581 MINPT-O-EOU 0311 26.54 NO 42 376557 22.93 OSF 1,50 16321.36 3967.89 TD W20.05 133.01 893106 8887.05 102.4 IF 1.W W52.51 3206.62 MinPt-0.SF OP03-P05PBi (Def Surroy) Warning Alert 17.14 13.52 15 45 3.63 34.11 MAS = 4.12 (m) 149.59 149 59 CtC-15-15 00 Enter Akn 32.7] 13.52 2902 19.25 12.48 MAS = 4.12 (m) W6 72 W5. 77 M'mPI.O-SF 49.05 13,52 44.36 35.54 13.81 MAS=4.12(m) 632.94 630.58 CtCI<_15m>15.00 EA Alen 299.31 14.% 289.20 284.7 33.54 IF 1.50 137410 1326.88 Min%-O-SF 70999 53.97 6n 62 6W.0 2(1.1 IF 1.50 2439.64 2223,17 MinPt-0.SF 11 W.32 98.27 111441 1082. 18.22 IF 1.W 397T25 2829,72 MInp-0-SF 3970" 83.30 3920.5 3893.1 IN 129 7261 IF1.50 8938.51 3756,45 MinPt-O-ADP 3975.66 82.37 3920.35 7343 IF 1.50 8952.10 3767.65 MINPT-0.EW 3974.90 10. 16 392107 3-1175.47 IF 1.W 8984.82 376044 MinPICICt 390342 7814 3B50 931 3825 281 IF I 997389 W16.38 MinPts OP03-P05(De1 Surrey) Wama19 Ayrl 17.14 13 52 1545 363 34.11 MAS=4. 12(m) 149.59 149.59 CICt-15-15.00 Enter Alen 32.77 13,52 2902 19.25 12,48 MAS=4. 12(m) SW 72 mi'n MinPt-OSF 49.05 1352 44.36 35.54 13.81 MAS=4.12(m) 0294 630,58 CtCtc-15m115.00 Exit Alen 299.31 1456 289.20 284.76 33. 1 1.50 1374.10 13MW Min%-0.SF 709.99 53.07 673.62 656.02 20 1 IF 1.50 2439.64 2223.17 MinPt-O-SF 1180.32 98.28 1114.40 1082.04 18.12 IF 1.60 3977.25 2829.72 MhPt-0.41F 5001.55 145. 12 4904.49 485045 52.05 1 1.50 7946,52 3621.02 Mln%-0.SF 4771.56 1W15 M78.72 4W281 51.96 IF 1.50 808172 36M 25 MInPt-0.SF 474531 13798 4652.98 4607. 51.96 0IF 1.W 8097.70 3646.92 MinPt-0.SF 4687,59 1W 31 4596.38 4551.28 51.96 OSF 1.50 8132.20 3652,61 MInPt-0.SF 3982,55 77.85 3930. 39D4. 77.78 0SF1.50 9064.35 3756N MInPt-O-ADP 3982.20 77.40 993D.25 39D4.81 78.23 OSF 1,50 9081.24 37W 48 MINPT-0.E0t1 3981.9 71W 1930.11 10143 71,11 OSF 1,11 907501 3717.10 MinPt-CICt 396286 73.87 391326 3888.99 81.62 OSF 1.50 9607,46 3797,23 MinPt-CICt 3963.44 75.58 391271 3887.88 79.79 OSF 1.W 9688.46 3801.36 MINPT-0.EW 3964.93 77. 3912 3887.33 77.69 1 1,50 9804.09 W07. 52 MINPT-0.EOU 396531 78.07 3B72. 3887.2 77.22 1 1.60 0833.77 3509,07 MinPt-0.ADP 3986.23 11.12 3111,47 3-.1173.71 OSF 1,11 10186.94 3112.13 MinPt-Ctct 396615 84.28 3908.62 3881.87 71. 1 1.W 10336.89 3825.20 Min"I-012 39M 62 86. 3908.8 3800.13 IN- IF 1.11 10436.82 3826.T7 MINPT-0.EW 307.02 8098 3908. 38W.06 69.22 IF 1.50 10458.17 382T07 Min%-0-ADP 400270 102,98 3933.]0 3899.72 58.8 IF 1.50 10979.W 3830.82 MinPt-0.SF 4022.46 113.1 3046.8 3809.28 53.79 IF 11 /1-91 3141,19 Mln%s W81.26 116.30 3903.38 3864.96 51.79 IF 1.50 1199608 3849.W MinPI.0.SF 3931.88 /39.69 3838.22 3791.99 42.52 IF 1. W 121W 58 W47. 15 MInPFDIQ 3931.fA /40.39 W37.91 3791.45 42,31 IF 1,50 12874.64 384688 Min%s 3931.99 140. W W3796 3nl,461 42.2 IF 1.50 29 194.87 3846.47 MinPt-O-SF 3933.05 139.28 3839_ 3793.78 42.60 IF 1.50 13185.58 38W.06 MINPT-0.EW 3933,11 139.35 38398 3793. 81 42.64 IF 1.50 13175.54 385044 MinPt-O-ADP 3933.78 140.44 383981 379380 42.31 IF 1.50 13235.33 3852,71 MINPT-0.E0U 39Nm 141.24 383989 3793.15 42.W IF 1.W 13265. 18 385384 MinPt-O-ADP Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point 1-1A-106 (P5b) Page 2 of 13 Offeet Trajectory Se ration Ct-Ct ftMAS ft EOU ft Allow Dev. ft Sep. Fact. Controlling Rule Reference Tra'eeto Risk Level Aad Status MD ft ND ft Abrt Minor Major 3:67.22 1W. 3859. 3806.8 37.32 OSF 1.50 1M82.W 38W.84 Mlnpts 367.31 1W.44 38W.02 38W 37.31 OSF 1.60 13892S7 3881.24 .In,,-O-SF 396918 161.61 3881.11 3807.67 37.06 OSF 1.50 14182,65 3593.18 MINPT-0-EOU 39]2.38 170.68 385827 3801.70 35.11 OSF 1.50 14502.24 M14.76 MinPl-CICt 3972.88 172.16 3857. 3800.72 34.81 OSF 1.50 1455t.94 3917,70 MINPT-D-EOU 3973.63 In 05 3857 3800.58 34.63 OSF 1.W 14581.70 W1905 MinPt-0.ADP 399046 187.5 W65.1 380284 32.08 OSF 1,50 /5051.32 3936.47 MlnPts 3971.05 212.76 M2888 375829 28.12 OSF 1,50 16W2.78 3050,68 Mirpt-CtCt 3973.20 218,12 38P 46 3755.08 27.44 OSF 1.50 16062.62 3961.52 MinPls 3973.51 218.28 382766 2:55.23 27.42 0SF1.50 1W82.04 M6182 KrPI-O-SF 3973.3 223.36 WN 12 37W00 26. OSF 1.50 16325.29 3968.W McTts OPO4-07 (Del Survey) W-1Ig AI®t 25.58 19.B0 23.7 5, 42.49 MAS=6,06(m) 149.33 14932 CiClolSm<16.00 Er.. 4900 1990.4524 29.10 18. MAS=8.06 (m) 643.45 542.19 MinPI-0.SF Q13 1990 45.36 29.23 18.85 MAS=6W(m) 544.42 543-15 CtCtc15m>15.00 Exit AIM 5510.47 51.27 547593 54W. 164. OSF 1.W 2449.01 2229.85 MinPt-QSF 6404,13 W81 B317.23 6384. 247.91 OSF 1.W 27W.W 2462.0 MIrPt-QSF 8349.71 85.38 8305.85 8289. 1B4.5B OSF 1.W 3505.W 2734.94 MinPl-OSF 8418.44 85.81 $374.16 8352. 180.58 OSF 1.50 3514.75 2736.77 MIrpt-QSF 9439.72 71.68 9391.60 9368. 21N1.28 OSF 1.W 3W8.51 275561 MinPt-QSF n55. 11 141.07 7WO 71 7614. 83.08 OSF 1.W WWW 3t139.04 MinPt-0.SF 6514,42 72.71 6465. 8441.71 136.38 OSF 1.50 9190.67 3775.18 Min%-QADP 6514.29 72 6465.5 6441.74 136W OSF 1.50 919394 377SM MINPT-QEOU 6514.1 72.05 11.71 6442,04 137.63 OSF 1,50 9203.74 3775.95 MinPb Ctct 6357.99 115.011 8280. 0242.9 B3. OSF 1.50 11391.59 3846.36 MmPls :20M 118.38 6220.42 61.1,31 W.53 OSF 1.W 11998.45 38Qw MinPt-QSF '96.52 14284 6100.94 6053.68 85.55 OSF 1.50 13005. is 3846.42 MinPt-QSF 61W 48 142.356099231 6052,141 65.76 OSF 1,50 13093.68 3847.49 MiWts 8194.45 142.27 6099.24 5052 17 65.79 OSF 1, W 13106.71 3847.88 MhZCICI 6194.70 142.6 W89. 6052.03 05.61 OSF 1.50 1315915 38Q 82 MINPT-O.EOU 6194.91 142 B2 60882 6051.99 85.49 OSF 1.W 131]8.W 38W.W Min%-QADP 8195,56 143.79 60B9.3 6051.77 65.10 OSF 1.50 13217.50 3852.03 MINPT-0.EW 81066 145.08 SMS8 6051.68 64.53 OSF 1. W 1325638 3853.51 MinPt-o- D 0230.15 166.w 6118. 6063.1 56.32 OSF 1.50 13947.38 W79.51 MinPI-O-ADP 6231.66 167.97 6119.53 6083. 58.00 OSF 1.50 13999.0 3881.57 MinPt-O-SF 5240.24 "1.62 6125.4 8088.E 54.87 OSF 1.50 142WA4 3898.28 MInPt-QADP 6242.64 1W.36 6122.06 6062.29 52.21 OSF 1.50 1453764 M1694 Mine(-CICt 6244.27 1W63 6119. W5765 50.48 OSF 1.W 1471.1 124.41 MINPT-QEW 6245A1 187.50 6119.]1 W57.52 5020 DSF 1,50 '4756.06 3925.56 MInPtAADP 6254.64 195.75 6123. 605889 48.17 OSF 1.50 150 66 3936,29 MinP10-ADP $327,64 224.87 6i77.40 6102.] 42.39 OSF 1,60 iWM01 3961.71 MlnPt-QSF 6312.98 248.18 6147. 19 6054. 38.W OSF 1.50 17102.00 3985,18 MinPl-QSF 6288.93 261.67 8114.15 6027.25 W 18 OSF 1,50 17599,70 4010,88 Mi pP clCI 62N 35 303.83 6086.46 5985.51 31.15 OSF 1. W 17713.57 4014 34 TD 9752.07 51.19 971761 9700 28132 OSF 1.W 2394.74 2190,22 MinPt-QSF 10691.36 $4.14 106549E 106372 W7. OSF 1.W 2448.25 2229.40 Mirpt-QSF 10822.22 37.61 1079681 1078461 443.1 OSF t.50 2483.64 2254.71 MinPI-QSF OPO4-071`131 (Del Survey) W.m1ng AAM 25.59 1990 23] 5.8 42.49 MAS=81)8 (m) 14933 149.32 CICt<=15m<15.00 Enter Alert 4900 19.90 45.24 29.10 19. MAS=6.05(m) 543.45 542.19 MInPI-QSF 49.13 19.80 45.3E 29.23 18.85 MAS=6.05(m) S4442 543.15 CiCI<=15m>t$.00 Exit Abrl 5510,47 51,27 5475.93 5459, 164. OSF 1.W 2448.01 2229-95 MinPt-QSF 6404.13 N81 637M 6364.3 247.92 OSF 1.W 27W 83 2452.0 MinPt-01F 8349.78 65.38 8305.85 8284. 194. OSF 1.W 3W5.66 2734.9d MinPl-0.SF 6418.M 6591 837416 8352. 194. OSF 1.50 3514.76 2736.77 MIrPt-QSF 7755.11 141.0E 766072 7:14.06 83 0-81 OSF 1.60 8050,80 3039W MinPt-0.SF 6614.42 72.63 6465.65 6441. 136.52 OSF i.W 9190,67 3775.18 MhPt-QADP 6514,29 72.4 8485. 6441.82 136.84 OSF 1.W 9193.94 3775,38 MINPT-0.EOU 6514.1 7198 6465.76 6442.12 137.78 OSF 1.W 9203.74 37750 MWICt 6357,99 114.98 662W..6243.. 01W.. OSF 1.50 113941..W 3646.36 Mn,Pts 118.35 200.945 810851 66 OSF 110B45 3849.W MI6289.70 nPt-Q5F 19852 142826 30 / MiPt-0-SF 61g4.Q 142.32 W9 65n OSF 50 10W W47.49 MiMts 8194..45 . 14226099.26 6052.20 65.W OSF 1.W 13106.71 384788 MinPICICI 8194.70 142. W9B.25 6052.0E 65.62 OSF 1.W 13159.15 W4982 MINPT-QEOU 6194,91 142.90 W9929 6.52.01 65,51 OSF 1.50 131]8.00 38W.W MinPt-0-ADP 6195.5E 143.7 6099 3E 6051.W 65.12 OSF 1.50 13217.50 3852.03 MINPT-O-EOU 6196.06 145.05 WON 6051, 84.54 OSF 1,W 132W.38 3853.51 MInPt-0.ADP 6230.15 1W.93 6118.51 81163. W.33 OSF 1.W 13947.38 3879.51 MinPt-OADP 6231.86 167.0 6119.55 6W3.93 W.Ot OSF 1.W 13999.99 3881.57 MinPt-QSF 6240.24 171.59 6125. 608665 54.88 OSF i.W 142W.14 38M 28 Mirpt-o- 6242. 18032 6122,09 6062.32 52.22 OSF 1.50 14537.64 3916.94 MinPt-CtCI 62*127 IN 59 611 B. 6057,69 5047 OSF 1.60 14726.99 3924,45 MINPT-0.EW 6245,11 187.55 6119 N1 6057.56 W.21 OSF 1.W 14756.96 3925.56 Mirpt-aA p 6254.64 195.71 123. W5893 48.18 OSF 1.W 15046.6E 39W,29 MhPt-QADP '03.74 R3.21 224.72 6153. 6079.02 42.2E OSF 1.50 160 7.95 3961.59 MINPTA EW 6303.85 224.84 61 W.6 6079.01 42.24 OSF 1.W IW7739 396173 MinPts 5304. 31 224 83 8154 09 607949 42.25 OSF 1. W 16115.89 396261 Min%s O 05-05PBi (Def Survey) WarningAbrt 33.34 26.22 31.50 ].11 52. 59 MAS = 799 (m) 149.33 149.33 CtC-15m<15.M Enter Alert 49.19 122 4264 22.97 9.00 MAS=1.1 (m) 111 11.1 CICt-15m>15.W Exit Abrt 57.32 26.2 31.10 5.87 MAS=7.89 (m) 910.80 900.54 MINPT-QEW 57.67 26.22 06.76 314 58 MAS=7.99 (m) 947.46 935.51 MlnPl-0.SF 84.89 26.22 88-.78 58.0 58 AhS=O7.9) (m) 149.80 1410.38 MinPl-0.SF 25480 .. 6333 21219 .. 1914 F 1.W 2449.26 2W 12 MIrP4QSF 29575 5521 25.55 2Q OSF 1.50 2791.52 245303 MinPt-QSF 451.80 118,80 372.21 333,00 5.75 1. OSF W 4179.24 2170.12 MINPT-0.EW 453.90 121.3E 372.61 332.55 5.65 OSF 1,50 421081 2577.87 MinPt-O-ADP 460.42 126,16 375,93 334271 5511 OSF 1.60 42W.41 2891,86 MinPt-QSF W2.92 115.89 425.2 387.03 8.56 OSF 1.W 4763 W 2987.77 MINPT-0.EW 503.20 116,25 425,31 3W.95 654 OSF 1.50 477362 29119.78 MinPt-QADP 572.41 151.27 471.1 421.14 5.71 OSF 1.W 5720.42 31W07 MinPt-QADP 621.22 1788E 50159 442.38 5.23 OSF /.W 8468.07 33W.34 MinPV- SF W5.77 191.24 537.88 474.53 525 OSF 1.50 6W3.81 3397.82 MhPt-O-SF 69991 21 66 556,41 05.25 4.91 OSF 1.50 70W.01 3453.38 OSF<5.W Enter Ae,I 704,22 252.141 635.74 452 NJ 4.20 OSF 1.50 7159,85 340.49 MinPls OPOS-061-1 (Det Survey) W emir, Abrt 33.34 26.22 31. 7.11 52.59 MAS=7.99 (m) 149.33 149.33 Ctct-=i5m<1500 Enter Akn 48.19 26.22 4264 22.97 9.. MAS=7.99(m) 653.93 651.23 Ctc-iSm>15.00 EYit AIM 57.32 26.2 98.5 31.10 5.87 MAS=7.99 (m) 910.80 90054 MINPT-0.EW 57,07 26.22 1&76 31.45®5 MAS=7.99 (m) 947.46 935.51 Min%-0.SF Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point 1-1A-106 (P5b) Page 3 of 13 Offset Trajectory Se ration Allow Sep. Controlling Reference Tra eclo Risk Lewl Alert Status Cl-Cl H Mq5 ft EOU H .. ft Fael. Rule MD ft TVD ft Alert Minor M,jor 8489 2022.68,78 58. 5.6 MAS =TO(m) 1469,60 1410.38 MinPt-SF O 254.80 63,43 212.12 181.3 8.17 IF 1.50 2M9.26 2230.12 MinPIOSF 295.75 55.41 268,42 240.34 8.15 IF 1,50 2791.52 245303 MI PI-0-SF 451.80 119.25 371.81 332.11 5.72 IF 1,10 4111124 2110.31 MINPT-0.EW 453.90 121.81 3]230 332. 5.83 OSF 1.50 4216.81 M7787 MinPl40.ADP 46042 12863 375.81 333.80 5.49 IF1.50 4288.41 2891.W M,,Pt-O-SF 502.92 118.E 424.] 386.27 8.12 OSF 1,10 471163 2111.71 MINPT-0.EW 503.20 117.12 424. 388 19 6.50 OSF 1.50 413.62 2989.78 MInPt-O ADP 572.41 152.38 470. 42003 5.607 1 1.50 5720.42 3180.07 MinPt-QADP 619.52 178.00 500.50 441.52 5.24 IF 1,50 6406.85 3318,03 MinPI-OSF 1032. 7/.68 980,67 955.11 2018. IF 1 50 9748.So 380461 MinPIQQ 1033.01 78.39 980. 95462 20.00 IF 1.50 9788.31 38MW MINPTOEW 1034.68 81.5 979-8 953.01 19.24 OSF 1,60 9847.97 3809.81 MINPT-0.EW 1036. 11 83.27 980.2 9528 18.87 IF 1,50 9877.83 3811,38 MInPI-O-ADP 1039.84 11 9]976 950.22 17.58 IF 1.50 9934. is 3814.32 MINPT-0.EW 1047. 16 98.74 981 00 948.4 18. IF 1.50 70028.79 381932 Awl. 1130.42 104.99 1050.09 1025. 16. IF 1.50 10977.17 382T25 MInPI-0.SF 1197.68 117.38 1119 11 1080.32 7542 OSF 7.50 10871.62 3830.61 MinP1.OSF 1184.25 126.78 10%4 105]. 14.11 IF 1.50 I1340.85 38M 32 WWI, 1164.24 12172 1082.n 1042 52 1446 IF 1.50 11660.00 3549.83 MInPPCtCt 1104.40 122.25 1082.5 1042.15 14.39 IF 1,50 11689,99 3849.83 MINPT-OEOII 1164. 72 122.61 1082.E 1042.11 14.35 IF 1.50 11 ]08.99 3849.83 Mi'Pt-0.ADP 1185.82 128.28 1099.97 1057. 13. OSF 1.50 11989.07 3898.80 Min Pt-OSF 1278.92 148.95 1170.2D 11 M.9 12.9 OSF 1.50 12884. ]4 3848.83 MinPtOSF 137783 167,47 1265.85 121036 IF 1.50 13989.95 3881.57 MInPt-0.SF 14M 33 184.29 1286./ 1225. 11.52 IF 7.50 14768.80 3926.00 MinPt-0.ADP 1415.68 794.27 128182 1221.39 1098 IF 1.50 75158.88 3940.55 Min%-C1Ct 1416.33 796.50 1285. 1219,83 10,86 IF 1.50 15230,87 3943.60 MINPTOEW 1417.00 111.21 121114 1219.71 10,82 1 1.60 15267.34 39.08 MMPI-QADP 1470. 16 219.72 1283,35 7190.44 9.80 OSF 1.50 18077.82 3961.74 Mn PI-QSF 1397,8E 222.18 1246.88 1174.19 D.44 IF 1,60 16317.24 3967.79 MinPt-CICI 13917 226.07 1246.71 1171.60 9.31 OSIF 1.50 10427.23 3970.61 MInPt-CICI W241 237.8 1243. 1164.74 a.68 IF 1.50 16597,32 397493 MINPT-0.EW 1409.31 245.13 1245.20 116162 811 IF 1.50 N76.58 MiWWADP 1425.81 25503 125548 1170.78 8 41 IF 1.50 '6687.07 17086.31 3984.93 MinPI.0-SF t383.83 278.46 1197.87 1105. 18 7.47 OSF 1.50 1801424 4021.44 WWI.CICI 137].88 348.91 11"9 1028, 5.94 IF 1.50 1831947 4031.04 MinPts OP05-0e (Def Survey) Waming Alen 33.34 26.2 31. 7.11 5259 MAS =7.D9 (m) 149.33 149,33 Ctc-l51,1500 Entar Akn 49,19 2822 4284 22.97 9,00 MAS=7.99(m) 653.93 661,23 Ctcl-5m-15.00 E4t Plan 57,32 28.22� 31.10 6.87 MAS = 7.99(m) 910.80 900.54 MINPT-0.EW 57.67 26,22 46.76 314 5. MAS - 7.99 (m) 94746 93551 MinPt-0-SF 8489 26.22 68.]8 586 5.8 MAS=1.89 (m) 14�80 141038 MinPI-0-SF 254.80 63.33 212. 19 181 4 6.12 IF 1.50 2,149.26 2230.12 MInPI-OSF 29675 55.21 258.55 240. 8.18 OSF 1.50 2791.62 2453.03 Minh. SF 451.80 118.8 371.21 333.00 S:J IF 1.50 4179,24 2870,32 MINPT-OEW 453.90 121,38 312.Bt 332.5 5.65 1 1.50 4218.81 287787 MinPt-0-ADP 48042 126,16 375.93 334.271 5,511 OSF 1.50 4286.41 2891.86 MInPI-OSF 502.92 1158 425.2 387,03 6.56 OSF 1.W 4763.63 28877 MINPT-0-EW 50320 116.25 425.31 .954 388E 8. 1 1,50 4773.62 2989.78 MinPl-QADP 572.41 151.27 47114 421,1 5.71 OSF 1.50 6720.42 318007 MInPt-O-ADP 619.52 176.00 50143 442.92 5.29 IF 1.50 6406.05 331803 MinPI-0.SF 1022.89 8205.9678E 940.85 18.92 IF 1.50 10237.05 382362 M"PI-Ctcl 1023.25 82 987.80 940.2E 18.71 IF 1.50 1028703 382441 MINPT-OEW 102392 83.73 9677E 840.1 18,55 IF 1.50 1031701 3824,88 MhPt-0-ADP 1032.18 89,35 972,27 W2.83 17,51 IF 1.50 lose 58 3827.78 MInPt.CtCt 1029.70 101.29 gel,1 928.41 1 3 OSF 1.50 '097680 3830.7; M'mPI-QSF 1013.85 112.24 938. 901. 13. 0SF 1.50 11345.07 3848.5 WWI. 1012 22 1 W.88 942.76 908.54 14.78 IF 1.50 115, 4.69 W49 84 M" lP CICI 1012.44 908.07 104.WN13 14. as OSF 1.50 11584.67 3849.84 MINPT-0.EW 1012.75 114.73908.02 14.63 OSF 1.50 11804.68 3849.84 MinPt-O-ADP 10/638 110.31908.04 13,D4 OSF 1.50 11841.43 3849.8/ MINPT-QEW10189g111081 905.91 13.85 OSF 1,50 11874.39 3849.81 MinPt-O-ADP 1023. 13 114421 908.71 13.52 IF 1.50 1199417 384980 MinPt-0.SF1029,02 114645 914,38 1&5 IF 1.50 12D64.75 W%28 MinPl-OSF 1114,40 132.50 981. 12,70 OSF 1,50 12658.82 385167 MinP10-SF 1132.16 13455 997.61 12.71 OSF 1.50 12753.04 3850. 18 MInPW-SF1185.75 138.132 1027.62 127 IF1.50 128 :2 38M 84 MInPtOSF126252 158-089 1104.43 120 OSF 1.50 1398581 388006 M'InPt-O-SF 1301.13 182. 1179.1 1118.70 10 ]5 1 7.50 15056.18 3936.85 MeiPls 1292.78 191.11 1164.73 1111,21 10. 17 IF 1.So 15396.15 3949.58 MinPICICI 128]1 207.30 1148.64 107B.87 8.35 IF 1. FA Isow 69 39W 84 MInPt-CICI 128781 208.20 1148.01 1078,01 927 OSF 1,50 18048.84 3961.33 MINPT-bEW 1288.03 209.52 1148.02 1078.50 9.28 OSF 1,F0 16058.64 3961.45 MinPW-ADP 1288.67 "A3 1148.35 1078.74 9,25 OSF 1.50 18076. 14 3 172 MInPt-QSF 1294.42 21478 1150. 1079.63 907 IF1.50 16366.00 3969.04 MINPT-0.EW 128739 235.22 11W,24 1052.1 8.2 OSF 1.so 1709584 3984.91 MinPt-QSF 1280. 249.59 1093.99 1011.07 7.80 OS F 1,50 1]684.86 4013.03 MinPl-CtCt 1260. 258.52 10878E 101101 7.34 IF 1.50 17114.14 4021.84 MInPI-Ctct 1259.2 30781 1050,01 WAIJ S.1 OSF 1.60 18329. 12 $031 31 MinPts OP05-06P82 (Def Survey) Wvning All 33.34 26.22 31.50 7.11 52.59 MAS =70(m) 14933 149.33 CtC-15m`15.00 Enl4r Alert 49.19 26.22 4264 22.97 9.00 MAS =7.991m) 653.93 651.23 Ctct-15-15.00 E*Alert 57,32 282 48. 31.10 5.87 MAS =7.09 (m) 910.80 900.54 MINPT-QEW 57,07 2622 48.76 314 58 MAS=7.99 (m) 94746 935.51 Min Pt-0.SF 8489 28.22 68.78 586 &0 MAS=7.99(m) 1469,80 1410.38 MInPt-0-SF 254.80 63.33 212.79 191A ISA2 IF 7.50 2449.26 2230.12 MinPt-0-SF 295.75 55.22 258.55 2Q 53 BAs IF 7.50 2791.:2 2453,03 MInPt-0-SF 451,80 11881 372. 33209 5.75 IF 7.50 0179.24 2870.82 MMPT-0.EW 453,90 12136 372. 332. 5.85 IF 1,50 4216.81 2677,87 MmPt-QADP 480.42 126A6 375.92 33428 5.51 IF 1.50 4286.41 2691.86 MinPtOSF 502.92 11590 4'25'M 387,02 656 0.SF 1.50 476363 298777 MINPT-0.EW 503.20 118.26 425. 386. 6.54 1 1,50 4773,62 2989.78 MInPt-OADP 572,41 151.28 471.1 421.1 5.71 OSF 1,50 5720,42 3180,07 MinPt-QADP 619,52 17862 501.42 442.901 5,281 1 1,50 6406.85 3318.03 WWI.OSF 1022. 8205.96785 940.84 18.92 OSF 1,50 1023].05 3823.62 MinPI-CICI 1023.25 82. 987, 940.2] 18.71 OS F 1.50 10287.03 3824.41 MINPT-QEW 102302 83-]4 9877 9401 18.55 03F 1.50 1031701 3824.88 MinPt-0.AOP 1032.18 89.36 972.27 942.82 1751 OSF 1.50 10565,58 382778 mmpt-CICI 1029.70 101.30 961.83 928. 15. OSF 1.50 10975.68 3830.71 MInPt-QSF 101385 11225 938E 901.60 13. IF 1.50 11345.0] 3846.51 MinPts 1012.12 103.68 94276 908.54 74.78 IF 1.50 11W69 3849.0 MInPt-OCI 101244 104.38 942.5 908.06 14.68 OSF 1.50 11584.67 W4984 MINPT-0.EW Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point I-1A-106 (P51b) Page 4 of 13 Offset Trajectory Se ration Cl•Ct ft MAS ft EOU ft Allow Dever ft Sep. Facl. Controlling Rub Rebrence Tra eclo Risk Level Alert Slalus MD ft ND ft Alert Minor Major 1012.75 104.73 942.5 908.0 14.63 IF 1.50 116N 66 3849,84 MinPt-QADP 1016, 36 710.32 942.4 90809 13.93 OSF 1,. 11..41 38 .1 MINPT-QEOU 101699 111.08 942.OA 905.91 13.85 IF 1.50 11874.39 3849.81 MinPI-0-ADP 1023.13 11442 00,51 906.71 13.52 OSF 1.50 11994.17 3849.80 MInP1-QSF 1029.02 114.84 952.25 914. 13.5 OSF 1.50 12064.75 3850.28 Min%-QSF 1114.40 132,50 1025.73 981. 12.] OSF 1.50 12658.82 3851.67 MinPt-OSF 1132.1E 134.65 1042.12 997.61 12.71 OSF 1.60 12753.04 3850. 16 MinPt-OSF 1165.75 138,13 1073.33 1027.6 12.7 IF 1.50 128E ' 3848.84 MinPt-0.SF 1262.52 158.07 1168.80 1104, 12.05 IF 1.50 13985.81 WNW MmPt-0-SF 1301,13 192421 1179,181 1118.71 10.75 IF 1.50 15056.16 39M 65 Mi is 1282.7 191.5E 1164.74 1101.23 10.17 IF 1.50 153% 15 39Q W MinPl um 128001 209.93 1139.72 10]0,W 9.18 OSF 1.50 16076.36 3961.72 MInPI-OSF 1259.03 219.42 111241 1039.61 4 8.84 IF 1.50 16504.87 3972.61 M` '.CtCt 1260.26 222. 1111.41 1037.49 8.662 IF 1.50 16804.9E 3975,08 MINPT-O-ECU 1264.14 271.1 1083.02 9929 7,01 IF 1.50 16727.24 3977.32 MinPts 01W.05 (Def S-Y) Wemltg AJert 41.20 326 39.3 8.53 63.W MAS=9.B61m) 144.58 144,58 CtC-15m<15.00 Enter Abet 49.13 3267 44.88 18.4] 15.81 MAS=9.96 (m) 377.58 3772E Ctd<-15m>15.110 Ent Abn 97.87 3267 7704 65,01 4.97 MAS=996(m) $67.44 849.35 OSF<5.00 Emer Non 12122 46.38 89.90 74.85 3.99 1 1.50 106103 1042.65 Mln%-0.SF 135.36 53.50 99.29 81.88 3.8 IF 1.50 197 &1 1852.26 M,ISF 135,16 533 99.1 81.81 3.85 OSF 1.50 1986.64 1WO.34 Min%s 135.00 5296 99,29 8204.3.88 IF 1,50 2005.22 1878.23 MinPt-CIC1 169.55 52.99 133.86 116. 4.8 IF 1,50 2442.50 2225.24 OSF>5.00 Enl Vert 211.15 64.33 167.91 1112 4.1 IF1.50 3161.W 2632.73 OSF<5.00 Ent. Alen 110.12 8053 56,08 29,59 2.0E IF 1.50 3855.28 2805,21 MInP(-OSF 107.02 7774 54.64 29.2 2.07 IF 1.50 387404 2808-98 Min%-0-ADP 104,30 74.45 54.31 29.85 2,11 OSF 1,50 3892.79 2812.75 MIN PT-00.EW 08.81 48.53 64.20 48.38 3.03 IF 1,50 3995.94 2833,48 Mi pt-ctCt 100.23 32,07 78.90 67.56 4.89 MAS=9.96(m) 4071.00 2848.5E 1S 500 Ent Ab 107,81 33,13 85.37 74.1 4.89 IF 1.50 41127 2811 OSF<5.00 Ent. Akrt 127.08 53.55 B102 7352 360 IF1.50 4221.05 2878.72 MinPt-OAOP 14370 88.25 97.84 75.45 3.18 OSF 1.50 Q86.75 289193 MinPl-0.SF 162.19 63.53 119.48 98.6E 3.8 I 1.SO 435244 2905.13 M'mPI.OSF 330,59 100.34 263,34 230.25 4.98 IF 1,50 4839.65 3003.05 0SF>5.00 Enl Alen 2553.63 167.14 2441 W 23W 49 23.05 1 1.50 779637 3593.7E MinPt-0-SF 22067 100,48 21W 33 2183.19 34. 14 1 1,50 am 91 3753.60 Minp'O-ADP 2258.49 N. 21" 2164.25 36.34 OSF 1.50 9015.08 376291 MINPT-O-EW 2256. 87.57 2197.30 2168.47 3910 OSF 1,50 9151.93 3772.78 MinPt-CICt 222977 01.21 2168.61 2138.66 37. OSF 1.60 9858.04 W%34 MinPt-OSF 2208.2 97.62 2142.85 2110.85 34.28 OSF 1.50 10330.84 3825.10 MInPt-CtCI 2208.48 98.19 2142.E 211029 34.08 IF 1.50 10350.79 W2542 MINPT-OEM 2208.81 98.59 2142.7 2110. 33,05 IF 1.50 10364.78 W2564 MInPt-0-ADP 2212.98 105. 2142. 2107.69 31.82 IF 1.50 10629.73 3828.15 MINPT-OEW 2215.62 108.34 2143. 21W.2 30.98 IF 1.50 10709.08 W2861 M1nPt-0-ADP 2231.80 116.67 2153.71 2111 28.94 1 1.50 10966.95 38X50 MinPt-OSF 2240.59 122. 14 215882 2118.46 27.74 IF 1,50 11304.35 3844.71 MinPt-CtCt 2240.64 121&1 2157.8 2117,01 27 OSF 1.50 11344.27 3846.47 MinPts 2234.58 121.36 2153.31 2113.20 27.84 OSF 1.50 11745.62 38Q,K MinPt-CICt 2 SAS 123221 215268 2111.96 27,43 OSF 1.50 11805.58 384B.82 MINPT-OECU 2235.69 123.84 2152.79 2111.86 27.29 OSF 1,50 11825.55 3649.82 MinPt-O-ADP 2243.64 129.34 215727 2114.:1 28.22 IF 1.60 11995.41 M49.80 MInPI-QSF 2422.94 152.29 2321.07 2270.E 2402 OSF 1.50 129E9.24 384676 MInPl-0-SF 2581.11 167.M 24WW 2413.3 23.21 IF 1.50 13985.45 3880.95 MInPI-QSF 260239 173.90 24W.11 2426, 22.57 IF 1.50 14375.7E 39M 16 MInPI-0-ADP 2608 B] 190.37 2481.71 2418.59 20.68 IF 1.50 14974.75 3933.61 MinPt-CtCt 2605.39 20147 2471074 2403.1 1949 OSF 1.50 15384.11 11ISO MinPt-CICt 258983 21924 2443.35 2370. 17.79 1 /.50 '6074.07 3961.6E MmPtOSF 2538.9 237.16 2380.51 2301.79 i6. 12 OSF 1.50 16811.78 M78.87 MinPl-Ctct 2540.02 240.15 2379. 2289.W 15.92 IF 1.50 16901 74 3980.52 MINPT-0.EW 2541.14 291.48 2379.B4 2299.69 15.84 OSF 1.50 18941.88 3981.25 MinPt-OADP 2547.39 244.82 2383.18 2302 46 15.88 OSF 1,50 17101.61 3885 77 MinPt-OSF 2548.31 247.21 23841E 2302.10 15.52 0.SF 1,50 17271.88 399393 MINPT-0.EW 2:51,47 249.]0 23M 2301.78 15.38 IF 1.60 17351.65 39M N M'mpt o-ADP 255976 256.40 2388.50 2303.3E 15.03 IF1.50 175613E 4008.% ID 5827.81 180.7 57W 971 5U7 071 IF 1.50 700737 3438. 74 Min 0108.OSPOI (Oef Su"Y) W-In9 Alert 41.20 326 39.3 8.53 83.60 MAS=9.96 Im) 144.58 144.58 CICt<=15-15W Enter AW 49.13 3267 44.88 16.47 15.81 MAS=9,96 (m) 377.56 377.29 CIC--15m>15.00 E.1 Abn 97.67 32.67 7704 6501 4,97 MAS=9.96(m) 857.44 84935 OSF<500 Ents, Abrt 121.22 4638 89,90 74.85 3. 1 1,50 1001.03 1042.65 MInPt-OSF 135.36 53,50 99,29 81,5E 3,8 OSF 1.50 1977.54 1852,26 MinPt-0.SF 135.18 53.3 99. 181 81.81 3.85 OSF 1.50 1986.84 IWO 34 Mop s 135.00 52.96 99.29 82.04 3W 0.SF 1,50 2005.22 1876,23 MinPl-Ctcl 169.55 520 133.8E 116.56 4.8 0.SF 1.50 2442.50 2225.24 0SF>500 Exit A. 211-15 64.33 187.91 146.82 4.98 OSF 1.50 3181.50 2832.73 0SF<5.00 Ent. Akn 100.12 8053 5608 29.59 2.0E IF1.50 W5.28 2805.27 MInPt-OSF 1702 77.74 54.84 29.28 2.07 OSF 1.1 174.1 Ill MInPI-OADP 10430 7445 54.31 29.85 2.11 1 1.so 3892.79 2812.76 MINPT-0.EW 96.91 4853 64.20 48.38 3,03 IF 1.50 399594 2833.48 MinPt-CtCt 10023 32.67 78.W 67.5E 489 MAS=9,96(m) 4071.00 2848.5E OSF>5.00 Ent Alert 10781 33.13 85.37 74.1 4.99 IF 1.50 41121 1117 OSF<5.00 Ent. Alert 127.08 $3.56 91.0 73.5 3.60 IF 1.60 4221.05 2878.72 MinPPOADP 143.70 68.25 97.84 75. 4 3 18 IF 1.50 42W 75 289193 MInPt-0.SF 162,19 63.53 119.48 09 38 IF 1.50 4352.44 2905. 13 MinPt-0.SF 330 59 10034 263 U 230.25 4.98 IF 1.50 MN 65 30M 05 OSF>5.00 Ent Alen 2553.63 187.14 2441.88 2386.49 23-0 OSF 1.50 7795.37 3593.7E MinPt-OSF 2263,67 100-48 2196.33 2183.1 34. 14 OSF 1.50 8906.91 375360 MinPt-QADP 2258.49 94.2 2195.31 216425 36.34 OSF 1.50 9015.08 3762,91 MINPT-0.EW 2256.09 87.57 2197.30 2168.47 3910 OSF 1.50 9151.93 3772.78 Mi pt-00 2229 T7 91.21 2168.61 2138.5E 37. OSF 1.50 D858.04 3810.34 MinPI-0-SF 1208.2 97.62 2142.W 2110.65 34.28 IF 1.50 1130.84 121,11 MinPl-CtQ 2208,48 WA 2142.6 2110.29 34.08 1 1,50 10350.79 382542 MINPT-OEOU 2208.81 98,59 2142.7 2110. W95 OSF 1,50 10364.78 362564 MInPt-0.ADP 2212.90 105.30 2142. 2107,69 31,82 OSF 1.60 10E29A3 3828.15 MINPT-OEOU 2215,62 108.34 2143. 21W.2 30.98 OSF 1.50 10709.08 W2861 MinP1.0-ADP 2231.90 11667 2153.77 2115. 28.94 OSF 1.50 10866.95 3830.50 MInPl-OSF 2I40.59 122. 14 2158.82 211845 2].]4 IF 1.50 11304.35 3844.71 M"pt.CICI 2240 64 123.63 2157.8 2177.01 2] 40 OSF 1.50 11344.27 384G.47 MinPls 2234, 56 121.36 2153.31 2113.20 271 IF 11 11162 3849.82 MinPbCtct 2235.18 123.22 2152. 2111.96 27,43 IF 1.50 11805.58 3848.82 MINPT-0.EW 2235.69 123.84 2152.79 2111. 27.29 IF1.50 11825.55 38Q 82 MInP10-ADP 2243.84 129.34 2157.27 2114.51 26.22 OSF 1.50 11995.41 W49W MinPtOSF Drilling Office 2.7.1043.0 Nikaitch uq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point 1-1A-106 (P5b) Page 5 of 13 Offset Trajectory Ct-Cl ft Se ration MAS fl EOD ft Allow Dev.(III ft Sep. Fact. Controlling R.I. Reference Tra'ecto Risk Level Alert Status MD ft TVD ft Alert Minor Major 2422.94 152....29 2321,07 22703..,.E 24...0 CSF 1,50 1290 386-....76 MinPt-0.tSF 25 .79 2468.90 241332 2321 OSF 60 398545 388095 MlnPt-QSF 92 173.902486 11 4288 22.57 OSF150 '437516 390618 MInPt-O-AP 2222W6650908257....9337 19037 2481.;1 241859 206 OSF 1.50 IQ74.15 393361 Mmp1-CCt 201 47 24M 74 240192 19.49 OSF 1,50 .....24 '539418 NQ W MinPl-CtCt 21622 2453.2 23W1810 CSF 1.50 15654 39.39 M`CtCt 47 218.61 2452. 237987 1791 OF W W410 312725W MINPT-QEW 218.77 52 378 7E OSF W 1 608441 396154 MI250.94 Pt-OADP43 13 2923 24Q 23798 1786 OSF 1.W 1741 3961 M2991 Pt-O-SF 260224 221.63 2WW i 1 1 388.9/ MIN W3.49 22311 2454. 3W. 1]9 OSF W 1628321 639 396820 MiPT-OEW nPt-ODP 2N IN 2WA1 2455.5 17, OSF 150 16452,52 3971.2E MinPt-Oi 259100 243.5E 242637 2347.13 16.02 OSF 1.W 17W9.70 3982.68 TO 5827.81 1 W 7 5706.9 5647.0 aul OSF 1.50 700737 343874 MlnPts 0107-04IOef Survey) Pass 57.12 32.81 55.3 24.31 108.W MPS -10.W (m) W98 148.98 MinPts 114.85 32.81 106.04 82. 14.99 AS M= 10.00 (m) 865.20 856,81 MinPt-OSF 659,74 33.02 537.32 526.72 28.3 OSF 1,50 2NOA6 192348 MinPt-0.SF 070.05 40,41 642.76 829.84 2551 OS f 1,50 2274.53 2098.4E MinPt-O-SF 690.68 41.59 662Q 648. 2;_ OSF 1.W 2307.72 2124.30 MinPl-0.SF 3470.36 76,. 38 3419.12 393,. 1.W 379..91 27W.96 MinP0.SF 60195 19W638.32682. W OSF 1. WW.4 6.01 MinP0.SF 6110 13412 6026E 597628 OS 818209 3882.29 in MPt-0.SF 5354.39 .7 88.59 52954 5236,27 91.75 OSF 1.50 9075.56 3767.64 MInPt-0-ADP 5354,37 88.00 5285. 5266.37 92.37 OSF 1,50 9093.52 3788,83 MINPT-0-EW 5363.93 85.35 5296.87 5288.58 9527 OSF 150 9133.91 377161 MInPt-CICt 530609 86.87 5247.82 5219. 92.7 OSF 1.50 9891.53 3812.09 MinPt-0.SF 5210. ]B 104.57 5140,75 510022 75.44 OSF 1.W 10820.13 3829.2E MinPl-CtCI :211.25 105.W 5140.28 :105.26 74,43 OSF 1.W 11 11 11,41 MINPT-O-EW 211.51 106. 5140. 5105.13 74.1E OSF 1.50 '0870.10 3529,55 MINPT-0.EW 6213.33 108.62 51Q 5111 510A.70 72,64 OSF 1.W 1092)06 3629.84 MinPt-QADP 5216,52 109.93 5142.91 5106.59 71.81 CSF 1 W 1MM 79 3830.73 MinPt-0.SF 5234.31 118.25 5155.1 51160E 0694 OSF 1.50 11343.53 W8 .44 WIN, 5224.E 112.58 514929 5112W 70.22 CSF 1,50 17687.66 384083 MinPt-CICt 5227.15 118.89 Sta]. 5108.2E 88.49 OSF 1.W 11914.70 3849.81 MINPT-0.EW 5227.79 119. 5147.51 5107. W 65.81 OSF 1.50 119W 99 384080 mmpt, 6227.86 1199E 55147..WE 5107.91 65. OF1. 1199775 3..W MinPl-QS 5214..13 52902 Sm0 61,97 OSF 1.W 385308 MI12717 nP-CtCt 5214.41 .. 1281 5086,31 61.52 OSF1.W :2410.78 2450.74 3W.41 MINPT-QEO4 :2214.80 128.57 30 OSF 1.50 12470,70 355357 MinPt-0.ADP 4313 141.06 51288.7 47 5102 OSF 1.50 12996.74 38464E MhPt-QSF 5238. 146,14 514170 5W3.32 54A3 OSF 1.W 13427Q 3860.00 Mi'p`CtCI 5241.08 1W.2 5140.5 5090.81 52.65 OSF 1.W 1351i6.26 3885.24 MINPT-0.EW 5244.72 155.28 51408 5089.44 5098 OSF 150 13732.84 W7148 MINPT-QEW 524595 160 T7 5138.41 5085.1 49.2 OSF 1,50 13985.87 3881.39 MinPt-QSF 5147.98 212.00 5006.31 4935.97 36.59 OSF 1,50 15973.:2 39W.W Mint-CICt 5148,33 213.12 5005.92 4935.21 36.40 OSF 1.W iW13.81 39W.96 MINPT-0,E0U 5149..22 214.19 W0.1 9502 OSF1.50 1W5 3961.42 MinP-0.ADP 4971 21445 F 1W127 .16 MinPt-0SF0 515904 221.11E W11.341 493721 35.16 OSF 1.50 16409.22 3970.15 MInPt-QADP 5181.81 23770 5023.01 49.111 32,831 OSF 1.60 1%2761 39W.B9 MinPt-QSF OPN8 L1 (Def Survey) pass 65.02 32.81 63,1 3221 95W MA5=1000(m) 148.91 14891 WWI. W6 32.81 630 339E 26.05 MAS=10.00(m) 326.18 326.04 MINPT-QEW 11225..75 3281 102.W 82,N 706..41 702...69 MInPt-0.SF 3281 115,17 9670 10 75.A 667 MInPt-0.SF 28 M951 AS==1000(.m) 1000 25190 27962 MiWI-0.SF .4 .8 327073 OSF1W 2578W 2320.19 MinnP0.5F33464 65529 9W 6419Q 6353,39 OSF 1.50 W62 375261 MPI-QSF 6542,26 198,37 6409. 6343.W 48.71 OSF 1.W 8953.73 3757.79 MinPts 6542.2 t98.33 64M 70 6343,92 49.72 OSF 1.50 8967.12 3768.08 M.pt-Ctct 64213E 202.44 8286.07 6218.82 47.80 OSF 1.W 10]17.54 3828.W MinPl-CICI 6421.72 203.42 6285.7 6218.W 4].58 OSF 1.50 10777.47 3829.01 MINPT-QEW 6422.W 204.28 6285,98 6218221 47.38 OSF 1.W IN2741 3829_W MinPt-O-ADP 6425.27 2 A2 8287.33 6218.85 46.91 OSF 1.50 10973.45 3830.65 MinP10-SF 6454.23 211.88 6312.65 6242. 45.90 OSF i.W 11348.20 384665 MinPt-0.SF 6494,90 21249 635291 6282,41 46.05 OSF 1.50 11993.54 3849.60 MI Pt-QSF 6642.W 226,30 8491.3E 6418,25 41.21 OSF 1.W 12968.12 3848.78 MinPt-QSF 0811.65 228.00 BBW.32 BW36 45.00 OSF 1.50 13282.27 3854.49 MinPt-0.SF 9273.73 28001 90W.72 899371 Q.85 OSF 1.50 15023.64 393544 TO W29.85 71,07 5982.1 595878 12903 OSF 1.50 2441)W 22W.W himpts 11179.25 204.11 1104285 t097514 825 DSF 1.50 8113,3.98 36W 51 MinPt.O-SF O W0 (Def Survey) Paw 85.02 3281 631 3221 95.M MA5 = 10.110 (m) W 91 148.91 MinPts 06.77 3281 630 33.98 2605 MA-10.00(in) 326.18 326.04 MINPT-QEW 115.75 32.81 102.90 82.94 9 8 MAS =10.00 (m) 706,41 702 W 29.51 32.81 115.17 9670 9.78 MAS=10,00(m) 751.46 746.67 ZPl-QSF Min Pt-0-SF769401 130.78 7806.48 7563 BB OSF 1.50 8209.02 3674.32 MinPt-QSF 6542. 9225 e480.95 645055 107,56 OSF 1.W 103W.69 38 ,W MinPl-CICI 6543.25 93. B4W. 6,149.72 1 M OSF 1.50 1U20.:7 3828.52 MINPT-O-EW 6543.78 W20 64W.64 6449. 105.33 OSF 1.60 10440.85 3826.84 MinPt-O-ADP 6575,57 109.31 8W2.36 8486.27 91.0 OSF 1.W I.WW 38W.82 MInPPO-SF 6506,33 119.44 6515. 6475. 83.53 OSF 1.50 1134660 384 ,53 MinPls 6596,14 108. 6523.1 6487,19 91.67 OSF 1.W 113N 17 3848.44 MINPT-QEW 6577W 122.61 6495.75 6455. 81.13 OSF 1.W 12002.2E W4981 Min Pt-0-SF 6571.32 122.88 6495.0E 5454.44 W.95 OSF 1.50 12055.W 385021 Mi'pl-CtCt 6577,38 123. 10r--6-4-94-93 6454.27 W.W OSF 1.W IM75.W 385037 MINPT-O-EW 8577.....48 1 6 MI nPt-0.ADP 67825 2408 84919 95 .17 OS1. 12125,85 38607 MinPt-O.ADP 68 1W12 6714.10 8884.40 OF 1.W 1284.81 346.4] M InPI-QSF 8/4.52 0,85 1WW 6Wn 6760 6942 .. OSF 1.50 . 1316633 Wsom MinPt-QSF 741721 1 7305,25 724976 .. OSF 1.W 13Q 3870W MinPt-QSF 84377 9083 . 851622 8452 OSF 1.50 1.56.12 391164 MinPt-QSF 879015 9.04 86W.46 85N.11 829 OSF 5.47, MInPt-0.SF 9020,23 ... 19925 8887,07 882098 CSF W 3923.10 MinP1ASF 09519 27.9 928.6 918789 68W OSF 150 1Q1513 91.Q TD 570489 . OF 1.W 2449.9E 2230.63 MinPts CPWB P61(W Survey) Peas 6502 32.81 83 1 32.21 95.88 MAS = low (in) 148.91 148.01 M.I. 68.T7 32.81 6303 33.98 26.05 MAS=10.W (m) 326. 18 326.04 MINPT-O-EW 115.75 32.81 10290 82. 98 MAS =.W (m) 706.41 702,69 MinPt-0.SF Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point 1-1A-106 (P5b) Page 6 of 13 Offset Trajectory I Separation I Allow I Sep. I Controlling I ReferenceTraleelory I Risk Level I Alert I Status I 7684.01 6542. 0543,25 6543.78 6575.57 6595.33 6586.14 6577,83 8577.3 657 38 677.46 6:78.25 6814.62 72a6.93 7223. 10 7372.19 57N 89 OP08-04LiPS1 (Del S-y) 65 01 66.77 115.75 12951 2883.49 3349.64 6552.39 654226 85422 8421. 8421.72 6423 92 6424.61 6425.87 8426.66 6435.84 8481.60 4os3.1 OP09-SlLl (Def Survey) ]2.85 256,20 7402.58 6318.37 018.18 8318. 6188.66 0158.54 6156.78 6157,12 615779 817778 61 ]9 03 6169.34 6118 33 B1i8.1 6119,28 612111 6110.85 6171.14 8114.51 8127.71 6413.07 8796.66 717103 7767M 8583 17 8058.% 11211,55 11022.13 9145.0E 8355.06 OP09-SMP61 (Def Survey) 72 95 256.20 7402.58 6318.37 6318.18 8378. 6188,66 6158.54 8158.78 6167.12 6157.79 a 77.78 6179.03 6189.34 6118 33 8118.11 6119.28 6121,11 8110.8 6111.34 6114.51 6127.71 6413..7 67N 66 7171.03 7787,08 8563.17 8858.88 11211.55 IM.79 76Ma 7663. 88.92 92,25 6480,96 6450.55 107.58 93.64 6480,66 6449.72 106.07 94.20 6480.H4 6449. 105.33 109.31 650236 6466.26 91.0 119.45 8515. 6475. 83.53 ,ORB5 8523.1 8487. /8 9188 122,62 6495.74 6455.21 81.13 122.89 6495.05 6454.43 80.94 123.11 6494.96 6454.28 80.80 123.22 6494.98 6454.2A 80.73 124.09 6405.18 6454.15 80.16 160.14 6714.09 1114. 88. 162.34 709636 7044. 87.00 162.68 7114,31 7080.4 67.01 1651 7261.32 7206.40 67.10 2 .24 5671.03 5854.81 173,72 32.81 63,1 32 21 95.88 32.81 63 0 33.96 26.05 32.81 101290 82. 8.85 32.81 115. 17 86.70 9.78 32.81 2862.48 2850,88 143. M 91 3296.71 3270.7 84.46 199.00 6419.40 63M 39F 49. 198371 6409.64 6343.84 49.71 ,98.33 6409.70 $343.92 49,72 20244 028607 6218,92 4TW 203.42 8285.78 17218.30 47.58 205,86 8286.35 8218. 47.03 206.33 62. n 6218.28 46.92 207.42 r 6287 71 6218.45 48.69 208.36 6287 42 6218.30 46.48 211.83 6294 23 6223.9 45.7 280.40 628767 6201.20 37.36 70.451 400S.Wj 302701 87.50 14.22 32,8=6260.. 40.1 IQ 8 175Pl. 88.6 86.231. 86,00 0260.35 8232.04 111,56 110.73 6114.49 !077.83 84.83 120.80 8077.E .37. 77.1 111.31 6082.22 6045 47 83.75 112.37 W818 0044,75 82.96 113.11 6082.00 6044.64 82,31 123.61 8095.01 6054.1 7561 129.50 6092,34 6049.53 7216 146.19 6071.53 6023. 16 63, 76 166.32 600709 5952 5553 167.15 6004 33 59Q 97 55.23 173.82 6003_ 5945.48 53.12 170.19 8003 5944.8 5242 210.10�59M Q 5900.76 43.84 211.45r 597003 5899.90 43.57 220.81 5980.14 250.59 6245.68 267.40 6618.04 279.69 6984.24 296.15 75%91 57.52 85a4.4 39.46 11184.91 11172, 35,96 10997.83 10988. 5770 9106,23 9087, 328111422 18 40... 2.02"111 14090 B887 786 IF 742 88.0, 6280.34 6232.03 111.55 110,75 6114.47 8077.91 84.E 120.83 8077.83 6037.71 77.1 111.34 6082.20 6045.44 83,73 112. 6081.83 6044,72 82.94 113.18 6081.98 8044.87 82.37 123.65 ma"I 9 8054.13 75.5 129.54 609232 6049.49 72.13 146.23 W71. so 6023, 11 63.74 156.38 6007.05 5951,95 55 51 107.21 Not 29 5948.91 55.21 173, 8003. 5945.39 5310 17025 8003 5944.88 52.40 21017 5970.38 590 M 43.83 211.5 5969.9 58M 82 43.55 216,17 597071 5899.35 42.83 220.89 5960.09 5908.81 41,81 250.88 6245.60 a162. 38- 267.50 6617.97 6529A 3B. 279.80 6884.18 6891.2 38.5 39.45 1118492 11 = -1m) 751.45 74667 MirPt-6SF IF 1.50 82%02 W74.32 MinPt-O-SF IF 1.50 10380.69 3825.89 Ms Pt,CtCt IF 1.50 10420.67 3826,52 MINPT-O-EOU IF 1.50 10440.65 3826,84 MinPIO-ADP IF 1.50 10980.07 MM 82 M rPI-O-SF IF 1,50 11345.60 3846.63 M.Pls IF 1,50 11394. 17 3848.44 MINPT-O-EOU OSF 1,50 12002.26 384D.81 MmPI-O-SF IF 1,60 1M55.86 38M 21 MinPt-Ctct IF 1.50 12075.86 3850.37 MINPT-6EOU IF 1.50 12085,86 3850,45 MinPt-6ADP IF 1.50 12125.85 38%77 MInPt-O-ADP OSF 1,50 12994.01 3846.47 MinP10SF IF 1.50 13523.73 3863.65 MmPI-O-SF IF 1.50 13533.85 3864.03 MInPI-OSF OSF 1.50 IM32.85 3867,73 TO OSF 1.50 2449.96 2230.63 MmPts Pass MAS = 1000 (m) 148.91 148 91 M.N. MAS=10,00 (m) 325,18 325.04 MINPTOEOU MAS=10.00 (m) 706.41 ]0269 MWI-O-SF MAS=10.00 (m) 751,45 746,67 MmPt-OSF MAS=1000(m) 2519.02 2279.52 MInPt-O-SF IF 1.50 2578.63 232019 MinPtOSF IF 1.50 8896.23 3752,61 MInPt-6SF IF 1.50 8953.73 375779 men is IF 1.50 8957,12 3758.08 Mirpt-CtCt IF 1,60 10717.54 3528.06 Mmpt-CtCt IF 1.50 10777.47 11 11 MINPTOEOU OSF 1.50 10817.36 3828.63 MhPl-0.ADP IF 1.50 10973.49 3830.65 MInPt-O-SF IF 1.50 11138.84 3837.43 MINPT-6EOU I 1.So 11189.63 3839.64 MinPt-O-ADP IF 1,50 113 49.15 3846.% MirPSO-SF IF 1.50 11603.04 384984 TO IF 1.50 2622.45 2349. 15 M.Rs Pass MAS = 1000 (m) 141.72 148.71 MlnPls OSF 1.FA 1112.11 1090.20 MhPt-6SF IF 1.50 et 69.31 W58.64 M,Wt-O-SF IF 1.50 tow 10 3769.23 MInPt-O-ADP IF 1.50 9106.09 3769.71 MINPT-O-EOU IF 1,50 9120.05 3770.68 Mirpt-CICt IF 1.50 10973.28 38W 65 MinPt-O-SF IF 1,50 11342.91 3848.41 MinPls IF 1.50 11450.19 W4965 MinPt-CeDt OSF 1.50 I1499.92 3848.85 MINPT-O-EW OSF 1,50 11529.58 3B49.85 M'mPI.6ADP IF1.50 11993.79 384980 MIWI-6SF IF 1.50 12350.13 3552.59 MInPt-CICI IF 1.50 13001.44 3846.93 MinPt-O-SF IF 1.50 14004.08 3881.76 MmPt-6SF IF 1.50 141M 71 3889.BB m1rpt-CtCt IF 7.50 14353.17 390469 MINPT-6EOU IF 1.50 14432.96 3910.06 MinPt-O-ADP IF 1.50 15720.47 395758 MinPICICI IF 1,50 15770,15 3958.15 MINPT-6EOU OSF 1.50 15889. 14 3959.52 MinPt-O-ADP IF 1,50 16074.82 3B61.69 M1rPI-O-SF IF1,50 7702,920 39828E MInPI-O-SF IF 1.60 17580.28 401040 Mr Pt-O-SF IF 1,50 11914.15 4019.75 MInPt-6SF IF 1.50 18630.63 4040.00 TD IF 1.50 244075 2230.48 WWI. IF 1.So 3714.25 277686 MinPt-O-SF IF 1.50 1357.89 1312,63 MInPt O-SF IF 1.50 1385.50 1336.87 MinPtOSF IF 1.50 2449.13 2230.03 MinPt-6SF IF 1.50 37Q3 278274 M,Wls Pecs MAS = 10.00 (m) 148.72 148.71 MinPls OSF 1.50 1112. 11 1090.20 MinPt-6SF IF 1.50 8169.31 3658,64 MInP16SF OSF 1.60 9099. 10 3769.23 MInP.-O-ADP OSF 1,50 :10509 3769.71 MINPT-O-EOU IF 1.50 8120.05 3770,68 MmPt-CICt IF 1,50 10973.28 3830.65 M1nPt-6SF IF 1.50 11191 3846.41 M.ft IF 1.50 1145019 3849.65 MinPt-CtCt IF 1.60 11499,92 3549,85 MINPT-O.EOU IF 1.50 11529.58 3549,85 MInPt-O-ADP IF 1.50 ,1993.79 3849.80 MmP10SF IF 1.50 12350.13 3852.59 MWICICI 1 1.50 13001.44 3846.43 MinPt-O-SF 1 1,50 14004.08 3861.76 MInPt-O-SF 1 1,50 14133.71 38M 88 MMPI-CtCI 1 1.50 14363.17 39Nffl MINPT-O-EW OSF 1.50 1.3296 391008 MinPt-6ADP IF 1.50 157M 47 M5758 MinPI-CtCI I 1.50 15770.16 3958.15 MINPT-O.EOU OSF 1,60 15889. 14 3959.52 MinPt-O-ADP OSF 1.50 1B074.92 3961.69 MhPI.O-SF OSF 1.60 17029.20 39828E MmPt-6SF OSF 1.50 175M 28 4010 at MinPIO-SF OSF 1.50 17914,15 Q19.75 MmPt-6SF IF 1,50 18530,63 4040.OD TO OSF 1,50 2449,75 2230.48 MinPls OSF 1.60 3714.25 2776.86 MInPt40,SF IF 1.50 1357.89 131263 MinPt-6SF Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point I-IA-106 (P5b) Page 7 of 13 I I Offset Trajectory I Separation I Allow I Sep. I Controlling I Reference Trajectory I Risk Level I Alert I Stales OP09-S1 (00 Survey) OP10�091-1 (Def Survey) OP10-09 (0s(Suney) 0111-01PS1 (Dd$.-y) 0111-01 (Del Survey) 9145.06 57.71 B108.23 9M7.35 - 2<2.1 OSF 1.W 2449.13 2230.03 M55.06 83.31 1) 1 9271.7 170.81 1 1. W 3743.48 278274 72.95 32.81f73O7 114.22 MAS = 10.00 (m) 148.72 IQ 71 256.20 40.18 9.62 OSF 1. W 1112. 11 1090.20 7402,58 141.64 Q7;2e�O 78.96 1 1,50 816931 W68.846318,37 8693lW1 OSF 1.60 9099.10 376923 0318.18 W.70 82W.0 6231.1 110.65 OSF 1.50 8106.09 37W.71 M18. 86.26 6260.18 6237.78 111,23 IF 1.50 9120.05 3770.68 6188.66 111.28 8114.12 BOT/.M 84.21 IF 1.W 10973.28 MM65 8158.54 121,4 W" o 6037.0 78.71 1 1.S0 11342.91 3846.41 67 W.7 712.07 8081.71 6044.71 83.18 IF 1,W '1450.19 W49.85 6167.12 113 14r--W-81-.q W43.98 82.30 OSF 1.50 11499.82 3849.85 6157.79 113,93 -1 48 6043, 81.82 IF 1.10 11529.M 3849.85 81 T7.78 124.57 6094.38 6053.211 75o2J IF 1.50 11993.79 3849.80 6178. 130.59 W91.62 6048.45 71 55 IF 1.50 72350.13 3852.59 8189.34 147.42 W70,70 602192 022 IF 1.50 13D01" 3846.43 8118m 167,91 8006.03 S9WA SS.W IF So 14 oli 3881,76 6116. 12 1M.W 6003.M 5WT32 54S8 IF 1.50 14133,71 W89.M 6119.28 175. W01. 5943.75 52.W IF 1,50 1d353.17 3904.69 8121 11 177.112 BW2 1 5943.20 51.91 OSF 1.50 14432 M 3910 W 6110.8 212.20 5969.03 5898.66 QAl OSF 1,50 1572047 3B57.58 6111.34 213.5 5968.81 5897.T7 43. 18 IF 1.W 15770. 11 3BW.15 6114.61 217.24 59W.33 5 997.2 42.42 IF 1.50 15588.14 3959,52 6127,71 223.02 597867 590 M d1,40 IF1.50 1W74.92 3M1.W 6413.07 253.12 6243,97 6l5QS5 IF 1 50 17029.20 3982.86 6775S3 ZW.W 65M04 8508.83 37,891 IF 1.50 17567,14 QM 28 6788.66 270,12 6616.22 652E 64 37.8 IF 1.60 17559.28 4010,40 7970.64 306,02 7766,20 7664.52 39.19 IF 1,50 18630.63 4040.W 8583.17 57.58 8544.Zr 85-2660 1 1. W 2449.75 2230.48 8956.W 81.70 8902.04 8875.1 1W.61 OSF 1.50 3714.25 2776.85 18739.08 89.M 16678.M 18649. 20.4 OSF 1.50 812.52 80598 16637. 50 W,38 16577.59 16548.12 282.31 IF 1.50 816.79 870.71 9145.06 57.76 9106.20 9087.30 241.95 IF 1.50 2449.13 2230.03 9355.06 83. 9299.01 92]1.52 170.1 IF 1.60 37Q 48 2782.74 W,97 32.81 792 M 16 158.73 MAS = 10. W (m) 198.88 14888 195.23 32.81 179.12 162.42 13.04 MAS = 10. W (m) 08. tg 830.79 220.11 32.81 202,10 187. 13.05 MAS=10.W (m) 887.04 877.79 10428.97 12(161 1044.21 loWrZ 124,5 OSF 1.60 M48.95 3726.31 . 9361.62 115.06 9284.56 9246.W IF 1,50 8805.26 3743.68 92T7.52 114.01 92U1.15 9163. 123.20 IF 1.50 W18.72 374506 9095.36 144.31 89M.W 8851.05 M.2 IF 1.W 11348.M 3M68 9562.48 153.79 045960 9408 M.B1 IF 1,50 72()00.90 384981 10230.28 185,46 1011529 1W53. 0. IF 1.W 12899.28 3846.44 11W7.26 215.33 10923.35 10851.93 T7.4 IF 1.50 139M.64 3881.51 I1737.26 240.0 11573.W 11496,43 73. IF 1.50 147M.57 392 W 11970.62 248,96 11804,31 1721 65 IF 1.5D 149W.16 3933.83 12903. W 265.15 12726.56 126M.50 IF 1.50 1582T94 39SB 82 12026. $0 265.60 12748.01 2659,80 7324 IF 1,60 158Q 61 3950 W 13997.8D 28006 13810.77 1 371774 75.2 OSF 1.50 16592,61 3974.84 17192.21 49105 16864 51 16701.18 52,6 OSF 1.W 183W.M 4031.52 17909.31 929.17 172W.54 169W.14 2894 OSF 1.50 1W30.63 4 00 3 17139.0o 173 OSF 1.,W 659.....47 8W....67M 20 16068... W1BB2.21 15505.] OF 1.W 86941 W7.52 16621.52 1451.75 1M53. 7 IF1WW 67510 67202 34 ...... -71 F 70162 Miiol 99611 3281 9954. (m76618 98288 96912 97250 3281 98. 9 3 MAS =10.00 997.M 9038 1965116 17080 195. 73 OSF1W 8378,12 369056 20503 6356 20133 IF 150 3692W 61615 201M 98] 50 23205M.W OSF W 838865 300 W228 61811 20M3.4 0 OF 1.W 8M.]9 3M.012097575 21l&I 42 629.M 074.12 20534 OSF W M7 36937 W.B] 32.81 792 48.1 168.73 MAS =10.00 (m) 148.88 14888 195.23 32.81 179.1204 MAS=10W (..m) 08.....19 22011 3261 202.10 162.4 87W 10 (m) 887 W 87779 1042897 12735 103.71 103018 IF 7.W 895 1131 936162 11505 9284 16 9245,9 IF 50 800526 37308 W9536 145W . 899827 8950.2 7 IF150 1IW88 38468 956248 16487 95&88 407.61 9325 IF 1.60 1200090 38481 1023.28 IN 10114.0 1W52.50 0 03F1W 19992 3846.4 11067.26 21896 1092227 1W50. IF 150 139M.64 3W1.51 1303.M 28921 12841.55 12745. 1 m 16M24 396152 457. 3262 1 41 34,9 IF 1,50 1702572 3082,79 49821 11 333021 476887 140Q1 OSF1,W 1738505 309809....829 1... ..... 37929 17427,27 17301.17 7 1076804 03F1.50 18630.0 4040.01) 17214.75 44.73 171MW 1717002 590.1 OSF 1.W 60.78 65108 1616032 41.64 16132,23 18118.M SM.1 OSF 1.50 68653 683,23 t5813.22 41.06 15885.62 16872.1 5M.7 1 1.W BB473 W1.27 14895.50 37.91 1480990 14557.59 SN IF 160 70.77 729.44 14112.45 35.57 140W.41 14076. 612.0 IF 1.50 76318 75810 12W 72 32.81 12518.03 12507.91 W2.7 MPS=10001m) 837.68 830.30 12051.55 3281 120M 47 120187 599.] MAS=10.00 (m) W1.94 8WM 8932 32.ai 8761 56.52 1]801 MAS =10.00(m) 148.67 1486] 266.21 32.81 251.15 233.40 MAS=10.W(m) 1W8.55 W3.37 321.13 32.81 30290 2M.3 MAS=10.W (m) 10T9.M 106028376.12 3281 35475 343.31 MAS=1o00 (m) t13882 1114.90 81W99 11605 808328 8044 1 dl IF 1.50 8703.90 373270 796076 11355 786470 7847.1 1 IF 1.50 879321 3742,43 771997 12942 763335 7590. IF 1.50 10973,62 383065 78N 72 137.W 7712 fit 766 IF 1.W 11340.29 3846.30 8022,10 139.57 7929.01 7W2.0 W.84 IF 50 11986.93 38Q80 4473.85 3281 "0,301 4441.041 229,55 MAS =10.001m) 1MB.M 1870M 89.32 32.81 7 81 56.5 178.01 MAS = 10.00 (m) 148.67 IQ 67 2M.21 32.81 25F,.15 233 QJ 19 161 MAS=1000(m) 1W8.55 993.37 Alert Minor MmPt-0.SF MinPts Pass MlnPts MinPi-0.SF MinPt-O-SF MinPt-O-ADP MINPT-O-EOU MInP1CtCt MinPt-0.SF MinPln MinPt-CICt MINPT-0.EOU MinPt-O-ADP MmPI-O-SF MinPt-CtCt MinPt-O-SF MInPI-O-SF Minpr-qCt MINPT-O-EOU MinPt-O-ADP MInPt-CtCt MINPT-O-EOII MmPt-O-ADP MmPt. SF WnPI-0.SF MinP1-0.SF MmPt-0.SF TO mmpr. MInPI-O-SF MInPt-0.SF WR-0.SF WN-0.SF mmpts Pess WWI. MinPI-O-SF MinP40-SF MinPI.0.SF MinPt-0.SF MInPt-O-SF MirPt-0.SF MInPt-O-SF MirPt-O-SF MmPt-O-SF MmPt-O-SF MInPt-O-SF MhPI-0-SF MmPt-0.SF MInPI.O-SF MrM TO MinPIO-SF MinPI-0.SF MinPts Min%s MInPt-O-SF MinPt 0.SF WN-O-SF MinPtAADP MhPt-0.SF Kr,PI-OSF MInP1-O-SF Pass M.P. MinPt-0.SF MInPt-O-SF MmPt-O-SF MhPt-0.SF MirPt40.SF MhPt-OSF MmPt-0.SF MinPI-0-SF MinPI-0.SF MmPI-0.SF MInPIO-SF TO MInPt-0.SF MInPt-0.SF MinPt-0.SF MinPt-0.SF MinPt-O-SF MinPt-0.SF MmPtASF Pant: MnPts MInPt-O-SF MinPt-0.SF MInPt-0.SF MinPt-0.SF M1nP(-0.SF MinPl-0.SF MinPt-0.SF TO M,Wft pesa MinPts MinP1-O-SF Drilling Office 2.7.1043.0 Nikaitch uq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\01iktok Point-1A-106 (P5b) Page 8 of 13 Offset Trajectory Sa ration Allow Sep. Controlling Reference Tra'aet Risk Level Alert Stalus Ct-Ct ft MAS ft EOU ft Dev. ft Fact. Rule MD ft ND ft Alert Minor Major CP12-01 (Cef Survey) 0113.03 (Def Survey) OF 14S3 fDef Survey) 321.13 32.81 302.90 288.32 /8.81 MAS - 10.110 (1) 10]9 93 376,12 32.81 354.75 34331 18.W MAS =10.00(m) 1138.82 a 160.99 116.01 8083.32 804498 108.41 OSF 1.50 8703.90 7960,76 113.5E 7884.70 7847. 18 106.0E OSF 1.50 8793.21 7719.97 129.42 76M W 75W 55 90.1 OSF 7.50 10973.62 7804.72 137,66 771261 7667. 85.6 OSF 1.W 11340.29 6032. 19 13R55 ]9W.83 7892,U OSF 1,50 11997.79 8791.63 683 181.35 8.63 sam ia OSF 1.so '2968.09 9656,48 170.53 9542.46 9485.9 85.42 OSF 1,50 13519. DO 10271.92 183.82 10149.04 10088.1 84.2 OSF 1. W 139M 56 10734.03 190.66 1061)B.W 10543.37 84,88 OSF 1.50 14297.13 4473.8 32611 4453,301 4441.041 229,561 MAS= 10 W (m) 1998.80 32 81 95.2 64.18 180.75 MAS = 10.00 (m) 147.28 219 00 32.81 205.83 186,19 lEM: MAS = 10 W(m) 834.24 251.67 3281 236.80 21886 18.36 MAS=10.00 (m) BB8.96 9963.29 112,33 9888.07 8850.W 134,211 OSF 1,50 8806.99 0656.77 10B.90 9583.94 9647.8 134.21 OSF 1.50 8852.03 '30.29 IW 41 0359.02 9323.88 134.16 OSF 1.50 8890.15 8672.09 98,60 8606.03 8573, 133.25 OSF 1.50 9010.78 U71.51 W 59 8405]6 8374.9 133.02 OSF 1.50 904231 9282.31 13061 9194.91 9151.m OSF 7.W 10977.45 BSB4.29 143,87 8468. t8 8440.8 10D.7 OSF 1.So 11345.BB 10ill 59 154.07 10008.55 9957. 99,0 OSF 1,50 11997,13 11084.06 9W 186,87 10.72 108901 88.9 OSF 1.50 12995 .82 12161.01 215.66 12018.91 11845.3 84.9 OSF 1,50 13M 95 13418.46 289.15 /3225.37 13129.31 09.84 OSF 1.50 15539.42 3339.38 32 8 11 3321 871 3306MI 203 WI MAS = 10.00 (m) 1996.79 121.27 32.81 119.48 88.46 209.77 MAS = 10,00 (m) 144. W 235,63 32.81 220.67 202A2 17.08 MAS = 10.00 (m) 733.84 259.52 32,81 243,23 2,71 17.1 MAS=10.eo lml M95 10184.76 132,82 10095,85 10051.E 115.9 OSF 1.so 10B7t1. 18 10545.46 146.05 10447.72 10399. 109.0 OSF 1,50 11346..2 11078.20 156.07 109M 80 10922.1 107.2 OSF 1.50 1;901.73 12013.84 187.. 11888.53 11826. 96.6 OSF 1. W 12997.20 129M 20 21T. 12T7489 12702. 89.5 OSF 1.50 13997.08 14029.12 253,59 138W40 13776.23 83.3 05F 1.50 1506302 14441.48 262.89 1426584 14178.5 82.7 OSF 1.50 15326.72 14952.67 273.24 14770.10 14679. 82. OSF 1.W 15808.96 15714,21 290.03 155M 55 1U24.23 81.5 OSF 1.50 15WB95 16349.0] 300.48 16148.39 16W 81. OSF 1.W 1:06220 16793.21 307.94 16M7.M 16485.2 82.0 OSF 1.W 16802.31 18598. 13 334.65 18374.88 18263.48 S3.6 OSF 1.W 17384.59 18936.61 340.81 18709.05 18595. 836 OSF 1.60 176095 19955.46 382.63 19713,35 19592.8 82.7 OSF 1,50 18122.81 M737.69 3 93 20483.38 20356,76 81.88 OSF 1.60 i88 w 15730.90 33.93 15707.93 1W98. ]180 OSF 1,50 670.65 154W.37 33.31 15.780 1'417.05 718.6 OSF 1.W BM 76 15338.40 33.08 15315 g9 16305.3 718.7 OSF 1. W 691 W 14032.93 32.81 14012.35 14000.1 719.1 MAS = 10.00 (m) 73080 21d]5.2 W 131 21381 46 21335.11 231.6 OSF 1.50 8511.44 129.20 32 81 12745 96.39 2.26 MAS = 10.00 (m) 144. W 258.02 32.81 2.90 21321 25 75 MAS = 10.00 (m) 859.65 2557, 21 32.81 2636.97 252441 In 28 MAS =10.00 (m) 2045.51 6220.08 51.80 6185.19 6168.2 183.8 OSf 1. W 2424.04 8003.06 135.06 79121 ]868. 89.58 OSF 1.50 8064.65 7909.28 133.41 7819.1 7775.8 8963 OSF 1.50 8094.07 7063.94 84,35 7007.3 69 12720 . OSF 1.W 897638 7063,73 B4. 7007. 8979.879.58 4 127.W OSF 1.50 888244 7083. .71 ]00748 6979.93 128.19 OSF 1,60 8991.54 6835,60 102,71 6766.76 6732.W 100.86 OSF 1.50 10976,50 6749.35 115. 6672. 6634,001 F 1.50 11345.05 W58.93 117.21 BSW.43 8541.7 B5. OSF 1.50 11994.54 6454.79 138.87 8381.99 6318.12 70.3 OSF 1.W 13001.54 8422. 1"20 6328.49 8278.78 67,30 OSF 1,50 13429.54 6423.70 146.29 6325.8 62]].41 66.34 OSF 1.50 13499.40 M 4.15 146.88 8325. 8277.2 66.08 OSF 1. W 13519 37 65M 41 180.64 6412.0 63W. 61.28 OSF 1.50 13994.36 6561.68 160.42 645439 6401.2 81.76 OSF 1.50 1Q82.61 7152.22 181.65 7030.76 6970.5 59. OSF 1.W 14704.68 7583.85 192.01 7455.61 7391. 59.54 OSF 1.W 14993.46 B369.82 208.62 82W 41 8161. 60.40 OSF 1.50 15488.49 8478.98 211.33 8337.77 B267.8 60.48 OSF 1.50 15563.61 9153.45 228.88 9000.53 8924.5 60.24 OSF 1.50 16080.87 9457.34 233.31 9301.47 9224. 8106 OSF 1.50 '6258.06 10532.74 261.38 10368,16 10271. 60.6 OSF 1.50 17027.49 11881.12 29T80 11482.26 11383. 59 0 OSF 1. W 18119 M 12340.67 314,16 12130.90 1W26.51 59.1 OSF 1.50 18588.36 12406. 18 315.79 12195,33 12090.39 5911 OSF 1.W 1883 m 17055.90 84.53 169M.22 16971.3 306.2 OSF 1,50 706.90 18978.69 U 16 16922.26 16894. 306.2t OSF 1.50 709.56 16351.62 81.36 1829705 18270.25 305.1 OSF 1.W 732.15 16263.94 W.96 16209,64 18182.M 3050 OSF 1.W 7d4.42 14937. 12 75.72 14M 31 14861. 289.7 OSF 1.50 794.16 1485128 75.31 14800.73 14775.85 289.7 OSF 1.W ]W.Bd 14034.4' 74.17 14564.69 14560,29 2990 OSF 1,50 807.25 14M 19 72.84 14294.31 14270.35 299.41 OSF 1.50 822.84 12813.99 64.00 12771.00 127W.00 W5.0 OSF 1,50 928.62 12559.74 82.70 1251762 1249705 M5.2 OSF 1,50 945.48 12271 41 61.10 12230.35 12210.31 3 A OSF 1. W 963. 19 12163,50 60.57 12122.88 1210302 306. OSF 1.50 970.13 12100.05 125 12059.56 12039 81 305.21 OSF 1. W 914.24 11142,41 56.65 11104.31 11085.7 300. OSF 1.50 '046.17 10723. W 64.38 10688.0 106W 18 301.2 OSF 1. W 1089.07 10M 85 53.96 10603.55 10585.8 W1.2 OSF1.W IM796 6847,38 53 21r-6-811.551 6794.1 1 OF 1.W 2447 W55 13625 2041187 20.78 .. 27 OSF 815920503.03 111490 3732.70 3742.43 3830.65 3846.30 3849.80 384678 3863.50 38W.68 31M 91 1870,65 14728 826.97 87963 37QBe 3748.47 3752.04 3762.56 3765 04 3830.75 3848.55 3849.80 384845 3881.52 395496 1868 95 144.58 729,50 76662 3630.72 3846.59 3649M 3846.45 3881 44 3936,91 3g46 94 3956.30 3961.51 3970.01 3975.03 399B.79 400508 4025.37 4040.110 667.65 67561 678,77 726.64 370901 144 M 851.47 1910,78 2211 W 3641.38 3646.31 3759.73 376024 37W W 3830.73 3846 51 3849.80 3846.43 38W 08 3862,73 3W3 48 3881.32 38W 43 M2392 393432 3953 09 3955.60 3961.W 3966.53 3982.82 4025.27 4038,78 4040 00 703.18 705.78 127.85 ]30 07 788.19 791.56 800.88 8160 917.57 93383 950.46 95704 960 W '028.74 1088.81 107707 2228 00 3657.00 OP14SX I (Def S.-y) 129.20 32.81 12] 45 86.39 2.26 MAS = 10.00 (m) 144.58 144.58 MInPt-O-SF MInPt-QSF MInPt-O-SF MinMOSF Minh-PSF MInPt-0.SF Minh-O-SF M W -0.SF MinPt-0.SF TD M,l NP Pees M pts MinPt-0.SF Min Pt-0.SF MinPt-0.SF MmPtOSF MWI-O-SF MInPI-PSF M,Wt-O-SF M,W-0.SF M.N. SF Minh-0.SF M"Pt-0.SF MinPt-PSF TD Ki NP Pee. MmPts Minh-OSF MinPt-0.SF MInM-PSF MinPt-PSF MinPt-PSF MmRI SF MInPt-0.SF MiWI1 SF MhR-PSF MinPl-0.SF MinP1-0.SF M"Pt-0.SF MInPt-0.SF MinPt-PSF MinPt-PSF M,Wt0SF m MIWt-0.SF KWI-0.SF MInPt-0.SF W I-C-SF MinPls Peas .p. MinPt-PSF MinPt-0.SF MinPtOSF MInPt-0.SF MhPt-0.SF MinPt-O-ADP MINPTOEOU MInPI-Oct MInPt-0.SF MinPte MmPt-PSF MmPt-0.SF MinPt-CtCI MINPT-0.EOU Minh-O-ADP MmPt-PSF MinPtOSF MInPt-0.SF MinPt-PSF MInPtOSF MInP10SF MIr1Pt O-SF WR-O-SF MinPt-0.SF MinPI-O-SF Minh-0.SF m MInP, SF MInPI-0.SF MinPt-0.SF MmPt-PSF MInPIO-SF Min Pt-0.SF MInPF0.SF MinPt-PSF MinPt-PSF MinPt-PSF WN-PSF MinPt-PSF MiWt0SF MinPt-0.SF MInPI-0.SF MmPtOSF MinPle M'mPt-0.SF Pets A1inFts Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point IAA-106 (P5b) Page 9 of 13 OMset Trajectory 1 Ct•Ct k Se aration MAS ft EOU ft Allow Dev. ft S.P. Fact. Controlling Rule Reference Tra ecto Risk Laves Alert Status MD ft ND ft Alert Minor Ma'or 25602 32.81 24490 223.21 25.15 MAS=10, 00(m) 859.65 551.47 MmPt-PSF 2557.21 32.81 2536.95 2524.41 133.1 MAS=1000 (m) 2045,51 1910.78 MinPt-0-SF 6220.08 51.81 6185.19 6168.2 183. OSF 1.50 242k(M 2211,80 MInPt-0.SF 8003.06 13433 7913,15 7888. 90.0 OSF 1,50 8064.65 3641.38 MinPl-0.SF 7903.20 132.59 7814.45 1710.61 90-12 OSF 1,50 8096. 16 3646.66 MinP10SF 7063.94 83.91 7007, 8980. 127,89 OSF 1.50 8911 1711 MmPt-(-ADP 7063.73 83.6 ](q].81 6980.08 128.28 OSF 1.50 898244 3760,24 MINPT-O-EOU 7063. 83,28 7007.76 6980.30 128.86 OSF 1,50 8901.54 378008 Minpt-CICI 6835.60 102.02 6767.23 1733,5 101.5 OSF 1.50 ID976.50 3830.73 MinPt-0.SF 6749.35 114. 8672.5 6834.7' 89.13 OSF 1.50 11345,05 3846.51 MmPls 6658.93 11624 658108 0542.69 88.71 OSF 1.50 11994.54 3819.W MinPt-OSF 645479 13T54 6362.74 63IT2, ]0.93 OSF 1.50 1"1.54 3848.43 MinR-O-SF 8422. 142.90 6327,36 6280.08 67.92 OSF 1.50 13429.54 3860.08 MinPt-CICI 6423,70 144.9 6328. 6278.74 60.95 OSF 1.50 13499.40 3662.73 MINPT-O-EOU B424.15 145.55 8328.78 8278,80 86.88 OSF 1.50 13519.37 3863.48 MInPt-PADP 6520.41 159.13 601391 8361.28 61.8 05F 1.50 13994.36 3881.32 MinPt-OSF 7152.22 179,86 7031.0 69721, 60. OSF 1.50 14700.66 M23.62 MinPt-O-SF 726525 182.86 7143.01 7082.38 5991 OSF 1.50 14778,55 392036 MmPt-0.SF 7566.03 191.57 7437.99 7374,46 59.54 OSF 1,60 14914,06 3031.38 Min PI-O-SF 10586.45 243.2] 10423.94 10343. 11 65.5 OSF 1.50 16954.97 3081.49 MinPt-0-SF 10658.79 244.88 10495.21 10413.91 65.5 OSF 1.50 17022.43 398273 MinPt-PSF 10745.85 246.83 10580.96 10489.0, 65. OSF 1.50 17100.94 3985,14 MhPt-O-SF 10940.78 264.45 10764.15 IM76, 62.2 OSF 1.50 1727137 399391 MInPt-PSF 12741.15 297.22 12542,65 12443.94 84.61 OSF 1,50 18630.63 4040.00 TD 14208,54 401.69 1403041 1WO9 53.5 OSF 1.50 822.80 815.98 MhPI-0.SF 14231.09 362.08 13989. 1 8869.01 59.11 OSF 1.50 82766 820.62 MinPt-O-ADP 11409.02 105.58 11338.30 11303. 1636 OSF 1.50 102186 1005.72 MinR-PSF 11015.21 94.05 10952.18 10921.16 177-5 OSF 1.50 105189 1033.91 MinPt-PSF 82W 23 92.51 8168.23 8137.7 134.86 OSF 1.50 1595.36 1519.76 MmPt-0-SF 6847.38 53.21 8611. 6794,1 198. OSF 1.50 2447.69 2229.00 M ptc 9839.76 144,14 9743.34 9695.6 103. OSF 1.50 7900.50 3628.71 MinPt-0.SF 1730282 265.55 17125.46 17037.2 98.1 OSF 1.50 8131.57 W5251 MinPl-0-SF 20500.91 255.67 20330. 14 20245,24 120.7 OSF 1.50 8173.07 3659.24 MinPt-0.SF 0115-54 (Dd S-y) Pese 137.14 3281 13540 10433 26318 MAS=10.00(m) 14458 144.58 MinPts 25778 3281 145.35 224.98 22.88 MAS =10.00(m) 814.09 807.50 MInPI-0.SF 10264.84 133.91 10175.21 101W0 115.9 OSF 1.50 8418.12 3696.26 Mmt`t-PSF IG194.59 13300 10105.57 10061. 115.9 CSF 1.50 MI 72 3698.17 MiWt-0.3F 9998.02 130.36 010.76 9887. 115.98 OSF 1.50 f1`4 11 37M 87 MMPIOSF 9762.48 126.45 9671.82 9636.03 118.78 OSF 1,60 8527.33 3711.10 MIWt-0.SF 8548.05 133.54 8458.68 $414.53 B6.7B 0.SF 1,50 11344.2: 3848.47 MinPIOSF 8769.01 141.95 86MM 8627.0 83.38 OSF 1.50 IJW725 3819.80 Min Pt- SF 9056.49 1%n M4299 8888. B0. (M 1.50 13002. 10 3846.43 MinPl-PSF 9420. 10 196.21 9288.93 9223.8 72. OSF 1.50 14002.94 3881 ]0 MinP[-PSF 11106.06 2B8.82 10927.85 70839.2 62.8 OSF 1.50 16062.78 3981.52 MinPt-0.SF 12366.13 299.93 12165.8' 120M 620 OSF 1,50 /7022.61 398273 MInPI-PSF 12904.08 310.41 12M 8' 12593. 62.5 OSF 1.50 17385.08 39M 82 MInPbO-SF 13951,28 338.07 13725,17 13613.21 620 OSF 1.50 18117.29 11.1 MinPt-PSF 14578.0 350.99 14343.76 14227.00 624 OSF 1.50 im230 W36.02 M,nR-PSF 14824.23 356,32 14586,36 14467.91 62S7 OSF 1.50 IBM03 4040.00 TD 16842.80 38.83 168M11 18804.0312W OSF 1.50 688.70 655.35 MInPt-O-SF 16473.97 34.96 15450.27 15438. 0.SF 1.50 73772 733.29 MinPt-PSF 14266.56 32.81 1424531 14233.] MAS = 10.00 (m) 790.937 ]84.51 MinPt-PSF 14098.68 3281 14077.67 14065.8 MAS =1000(m) 8 798.98 792.87 MinPt-PSF 1383538 32.81 13814.81 13802,5 MAS=1000(m) 812.74 116.11 MinPt-0.SF 13035.06 32.81 1301S.74 130022 MAS =1000(m) 852.50 844.58 12768.09 32.81 12749.15 12735.2 MAS = 10.00 (m) 867.8/ 859.32 ZPt-PSF MInPMMF 20567.99 147.96 20469.02 20420.03 OSF 1.50 825941 3872.0 MInPt-PSF OP164130 (PB)(Des -) Pess 145.15 32 81 143.43 112.34 291. 11 MAS = 10 00 (m) 148 17 14817 MlnPts 156,85 32,81 153.45 124.N 71 62 MAS = 000(.) 440.39 43987 MinPt-0.SF 282.48 32.81 274,99 249.85 4505 MAS =10.00(m) 854.15 855.80 MMR-PSF 15:02.57 210.74 15051.75 14981. tOB 6 OSF 1.50 9178.13 '774.43 MmPt-0.SF 1577.53 200.71 15M 1097881 11398 OSF 1.50 9181.52 3774.0 MmPt-0.ADP 14834.37 92.58 14778,99 14751. 272.7 OSF 1.50 9234.52 3777.W MmPt-0.SF 14833.57 U87 1471666 14748. 265.21 OSF 1.60 939].86 378626 MhPt-PSF 15165.08 209.40 15025.11 14955.62 IN 11 OSF 1,50 9832.69 3809.01 MInN.0-AW 15178.90 220.04 1503188 14958.86 103.9 OSF 1.50 986004 3810.49 MInPt-PSF 16074.56 24136 15913.33 15833.21 100.3 OSF 1.50 f0994,16 3631,23 MInP10SF 16441.85 236.61 16283.79 16205,25 1046 OSF 1.50 11349.63 38Q 71 MinPt-(),SF 20072.07 257.85 19899.98 19814.4 117.3 OSF 1.50 12967.48 3846.79 MinP1-OSF 20567.80 262.58 2039242 20305.23 117.93 OSF 1.60 13382.61 3858.30 TO 9590.85 152.19 9400, 9438.66 95.1 OSF 1,50 85672 848.66 MinPl-PSF 906291 32.81 9049.07 9030.f0 )OB. MAS =10.00(m) 88365 $74.54 MinPt-OSF 1982. 32.81 1972.2 1949. 211. 'AS =1000(m) 1595.50 1519,88 MmP1s OP16403(Dd Survey) Pass 145.15 3281 143.43 112.34 291.11 MAS =1000 (m) 148.17 1"17 WW'c 158.85 32.81 153,45 124. 71.82 MAS =1000 (m) "0.39 439.87 MmPt-PSF 28246 32,81 274.99 249.65 45.05 MAS = 10,00 (m) 864.15 85580 MmPt-0.SF 21408.68 111.55 2133107 21295.11 290.4 OSF 1.50 888731 3751.77 Mhpt-PSF 21327.27 111.14 21252.85 21216.13 290.41 OSF 1.50 8892.09 375222 MmP10SF 21209.66 110,49 2113507 21099.10 290.51 05F 1.50 8899.05 3752.87 M,Wt-0.SF 2090650 108,82 20832.63 20796.69 290.8 OSF 1,50 8916.96 3754.52 MInPt-O-SF 16771.42 9761 16706.02 16073.81 2603 OSF 1,50 9022.53 3763.50 MInPI-0.SF 16685.13 97.12 16620.05 1658801 260.3 OSF 1.50 9027.61 3700 MinP10-SF 166%,11 1.. 16557. 10 1850. 1%91 (SF 1.50 11346.29 3846.56 MmPt-0.SF 1818278 181.74 180'4.0 18001. /6B. OSF 1.50 11992.59 384980 MInPt-PSF 20356.11 196.61 20223.71 2015B.50 156.0 OSF 1.So 13002.66 3848.43 MinPt-0.SF 21403.60 227.99 21251.34 21176.6 MA OSF 1,So 14001.29 31181.83 MinPt-PSF 21766,80 259.62 21593.39 21507.18 126.23 OSF 1.50 14329.34 3903.08 TD 1687866 3373 168'85 16844. 773.1 OSF 1.50 606.00 604.03 Mi pt-0.SF 16375.52 32.94 16:55m 16342. 768.] OSF 1.50 614.12 612.13 MInPt-PSF 18098.94 32.87 160789E 18088.1 787.71 MAS=1000 (m) 623.00 620.79 MinPt-PSF 15406,48 32.81 15385.70 15373.E T78.1 MAS=10.00 (m) 841.43 8T8.94 MinPt-PSF 11021.77 32.81 1100080 10988, BB7.0 MAS =10.00 (m) ]85.38 779.68 MinPtOSF 10942.93 32.81 10B2593 10910.1 683.2 MAS=10.00 (m) 789.20 783.38 MinPtOSF 10]44.44 32.81 1072788 10711.E 6894 MAS =10.00 (m) 799.67 793.53 MIW-PSF 10504.91 32,81 10088.59 IN72.1 6849 MAS =10.00 (m) 81107 804.57 MinP10SF 9668.72 3281 9053.65 9835.91 666.25 MAS = 10.00 (m) 857,06 848.98 MhPbO-SF 9183,54 32.81 9/89.58 9150.73 ]1110 MAS =10.00(m) 878.82 869.go MInPI-PSF 1982. 32A1 1972. 1949. 211. MAS = 10.00 (m) 1595.50 1519.88 MY tP Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point 1-1A-106 (P5b) Page 10 of 13 Offset Trajectory CI-Cl H Se ration MAS (t EOU H Allow Dev. H Sep. Fact. Controlling Rule Re erenca Tra ecl Risk Leval Alert Minor Ma'or Alert Sletus MD H TVD H 1 -02 01 ( rey) ens 15342 326ir 151.64 120.62 2]2.45 MAS =10.00 (m) 147.92 14792 Min%s 242.35 32.81 232.27 209.54197.7 21 MAS = 10.00 (m) 788.92 781.17 MInPI-0.SF 157W.04 123.20 15647.57 15606.811 OSF 1.W '767.58 37MM MInP1.0.SF 15056.13 118,23 1497697 14937.6 OSF 1.50 881682 3744.76 MinPl-OSF 14W3.84 115.25 145%.66 145C8.585 OSF 1.50 8849.28 3748.11 Min%-OSF 14530,46 114.21 14453.98 14418.25 OSF 1.W 8W1.73 3]49.33 MinPl-0.SF 14428.99 113.44 14353.03 14315.565 OSF 1.50 8871.W 3750,29 MinPt-0-SF 13465.64 150.47 13384.99 MIS 11 OSF 1.50 11343.09 3846.42 MinPt-0-SF 13958.79 162.So 1W50.05 13796.15 OSF 1.50 12002.81 3849.81 MinPtA SF 14796.59 104.93 14666/30 14801.4 OSF 1.50 13W3.66 3846.42 MmPt-0.SF 156M 02 225.1 15409.34 1 3394.5 OSF 1.50 14W2,87 388170 MIWtI SF 17362,12 263.99 17185.78 17098.130 0SF1.50 15104.26 3938.48 MinPt-O-SF 18570.07 285.57 18379.35 18284.8 OSF 1,W 15667.07 3956,97 MInN-O-SF 19203,96 295.57 19006.57 18W6.7 OSF 1.W 15922.46 395991 MinPt-0.SF 19541.28 3W.89 19340.35 192d0.7 OSF 1.50 16058.64 3961,47 MmPt-0.SF 20159.78 308.85 19953.5419850.93 98.23 OSF 1.50 16325,63 3968-00 TD 730399 32,61 7283U8 7271.18 387.23 MAS =1000(m) 1044.55 1027.22 MinPt-O-SF 2053981 IM02 20449.92 20405.5 2318 OSF 1.50 8661.79 372665 M'Wh OP17-02(D Survey) Pas. 153.42 32.81 151. 120.62 2]2.45 MAS = 1000 (m) td792 147.B2 MinPts 242.35 32.81 232.27 209. 27.21 MAS = 10.W (ml 786.92 781.17 MmPt-OSF 15077.40 11867 14997.06 14958. 192.7 OSF 1,50 8804.58 '743.81 MinPt-OSF 14460.37 113.64 14374.29 14336.7 /92. OSF 1.50 8865.05 3749.SS MinPt-OSF 13372.88 149.88 13272.43 13222. 134.7 OSF 1,50 11343.0, 3846.42 MinPt-0.SF 13926.22 162.10 1381782 13764.1 129.E OSF 1.50 12004.00 3 ,112 MinPt41SF '4711.52 114.23 14581.70 14517. t141 OSF 1.50 13W2.21 3846.43 MInPtASF 15549.20 224.65 15399.10 15324,5 1042 OSF 1.W 13W9.19 388t.53 MinPt-OSF 171W.20 262.17 17011.82 16924. 98.7 OSF 7.W 15051.50 39W.85 MInPt-0.SF 17424.26 205.59 17246.87 171588 98.7 OSF 1.50 15163.59 3940.73 MInPt-OSF 18955.18 294.44 11758.64 18660.72 968 OSF 1.W 1591082 3959.77 MinPl-OSF 19450.87 30043 1.250.26 1015044 97.43 OSF 1.50 16063.94 3961.53 ID M030 32.81 7283.08 7271.18 367. MAS =10.00(m) 1044.55 1027.22 M,nP,O-SF OP78-0811(N4 De($,r ) Pe.s 761.21 32.81 159.47 128.40 308.41 MAS=10.W(m) I"58 1"'58 MinPt, 282.05 3281 274.0 249.24 48041 MAS =1000(m) 726.60 722.44 Min%-OSF 10649.88 81.57 10795,14 10768.31 202.1 OSF 1.W :227.53 3777.30 WN-O-SF 107W, 06 W.52 10652.03 10025.55 202.17 O$F 1.50 9241.03 3778.04 MinPD0.SF 10633,12 79.97 10579.45 10553.15 202.11 OSF 1,50 9248.26 3778.43 MInPI-0-$F 14258,25 136.09 14187.17 1412I.18 1W. OSF 1.60 IN74.W 3830.W WPt-O-SF 15060.80 151.W 14%45 t4Wl)W 1W,1 OSF 1,50 11346.98 384,59 MinPt-OSF 16373,15 165.70 16262,33 1620745 149.1 OSF 1.50 11995.77 3849.W WN-OSF 16789.28 171 W 16574.75 16617.98 147. OSF 1, W 12111 3851.31 MinPl-0.SF 18812.90 185.26 18689.07 18627. 153.1 OSF 1.60 '2967.40 3846.79 MInPI-O-SF 19643.73 101.62 10515.W 18452. 11 154.5 OSF 1.50 13522. 11 3863.59 MInPt-OSF 20220.03 202.40 20084.77 20017. 150.5 OSF 1. So 13981.01 3880.78 MW-0-SF 214W 86 22857 21314,16 21M8, 141.4 OSF 1,W 15089.35 3937..1 MInPt-O-SF 21855.57 238.01 21696.57 24617.56 138.30 OSF 1.50 15417.78 3950.40 TO 13725.52 32.81 1370&W 13692,7 MAS=1000 (m) 097.79 694.20 MMPI-O-SF 13676,50 3281 13a59.04 13643:M2Q MAS =10.00 (m) 6WIs 695. so WnPt-O�SF 12487.72 32.81 1247141 12454 MAS=1000 (m) 739,55 735.07 MInPt-OSF 11959.62 32.81 11943.82 11926. MA5=1000(m) 760.29 755.28 Minl`-O-SF 1186661 3281 1185093 11833 MAS =10.W (m) 7W.26 7W.18 MinPt-0.SF 17398.59 108.15 17328.1 17290. OSF 1.W 8932.70 3755.94 Min%s OP18-08PB2(De( Survey) Pas. 161.21 32.81 159.4] 12840 306.41 MAS = 10.00 (ml 1.58 -58 Min% 28205 32.81 274.98 249,24 48.04 MAS=10.W(m) 726.W 722.44 WPl-OSF 10823. W 81.42 10789.04 10742. 202.0 OSF 1. W 9229.93 311 MmPtASF 1070000 W.57 10852.00 1W25. 201.9 OSF 1.60 924103 377804 MinPI-0.SF 10633.12 8002 10579.42 10553,1 201.9 OSF 1.50 9248.26 3778.43 MhPI40-SF 14258.25 136.15 14167.13 14122.1 158.3 OSF 1.W 10974.86 38W.89 MInPt-O-SF 15060.80 151.57 14959.40 IQW.2 1 W.1 OSF I W 11345.98 3646.59 MinPt-OSF 16373.15 16578 16262.28 16207.3 149.1 OSF 1.50 11W .77 3B49.W MinPt-OSF 18631.95 199.58 18498.56 18432. 140.7 OSF 1. So 12971.15 3846.73 MInPI-OSF 18694.50 200.24 18560.W 1B494.25 140.7 OSF 1.50 12999.82 3846.44 MinPt-0.SF 20036.23 232.W 18W1.21 19804.22 130.11 OSF 1.W 14000.83 3881.60 MInPt-OSF 20527,87 244.05 2036482 20283.82 126,70 OSF t60 14386.51 3"W TO 15553.W 32.81 15535.11 15520.5 9023 MAS=10.W (m) 644.59 642.05 MinPt-O-SF 14746,67 ..1 14729.10 14713.8 891.4 MAS=10.W (m) 66293 6W.118 MWt-0.SF 1363937 32.81 13622 75 13606.5 874,81 MAS =10100 (m) 69734 693.82 MinPt-0.SF 1844. 3281 183451 1811. 2103 MAS=10.00 (m) 1282.42 1245.53 MWI. OP18-08PB1 (D S-y) Pie " 161.21 32.81 159.47 128.40 306Al MAS = 10.00 (m) 144.58 1" 58 MOO. 28205 32.81 274.98 249.24 4&041 MAS=10.00 (m) 726.60 722.44 MmPI-OSF 639.10 32.81 628.W 806.W 68.61 MAS=low (m) t06502 1046.38 TO OP18-08 (De Survey) Pass 181.21 32 81r 159.4 228.40 306.41 MAS = 10 00 (m) 144.58 1" 58 MinPts 282.05 32,81 274.08 249.2 48.0 MAS = 10.00 (m) 728 W 722.44 MinPl-OSF 10823.88 81.43 10769.04 10742.25 W201 OSF 1.50 9229.93 3777.44 MinPI-O-SF 1070505 8067 1065/99 10625. 2019 OSF 1.W :241.03 3778.04 MInPI-OSF 10633. 12 8003 10579.41 10553. 201.9 OSF 1,50 9248.26 3778.43 MInPI-O-SF 14258.25 138-17 1416T12 14122.08 158.3 OSF 1. W 10974.So MOW MWt-OSF 15MSo 151,% 149%n 14909.22 150.0 OSF1.50 11346.98 3646-59 WnPl-OSF 16373.15 165.81 16262,26 16207.35 149.0 OSF 1.W 11995.77 3849.W MinPl-0.SF 18831.95 199.61 18498.54 18432.35 740.7 OSF 1.50 12971.15 3846.]3 MInPt-0.SF 18B94.W 20a2] 185W.64 18494.23 140.7 OSF 1.W 12999.82 38a644 MInPt-0.5F 20098.27 232. 18 19943.16 196W.10 1303 OSF 1.W 13998.32 3W1 <9 MinPt-0.SF 21 W 1. W 283.52 21612 62 21518.44 115.74 OSF 1,50 15459.86 3952. W TO 17169.96 32.81 17110.30 17137.1 919.51 MAS =10.W(m) W918 W7.17 Minpt-0.SF 16343.02 32.81 1W24.10 16310.2 911.11 MAS=1000 625.60 623,36 MinPt-O-SF 10052.84 32.87 1W34.26 1So MAS=10.W (m) W1.01 628W MInPt-0.5F 14748.67 3281 14729.10 14713. MAS=tOW(m) W2.93 650.08 MinPt-0.SF 1363937 32.81 13622.75 13606. jM MAS=10.W (m) 897.34 893.82 MmPt-OSF 1844. 32,81 1834.11 1811. MAS =10.00 (m) 128242 124553 MmPts OP 19-T1N (Del Survey) Pass 177.28 32.81r 176 ST WA7 341,21 MS=1000 (m) 14].87 147.87 MinPl, 281.77 32.81 275.01 248.06 W.W MAS=10M (m) W7.55 935.59 MInPt-O-SF 10739.W 113.85 IOW2.77 1W25.1 142.]1 OSF 1.50 8779.08 3740.95 MmPt-OSF W28.63 98.81 9362.43 9329,8 144. OSF 1.60 896755 37MW WPt-OSF Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point 1-1A-106 (P5b) Page 11 of 13 Offset Trajectory Sa ration Ct-Ct k MAS k EOU k Allow Dev. ft Sap. Faol. Controlling Rule Rahrenee MD'It, k Tra aeto TVD k Alert Risk Level Alert Minor Major Status 9]00.08 128.11 961435 9571. 114,4 OSF 1.50 10973.48 3830.65 MInPt-O-SF 10004.07 141,70 99M 28 98628 108.8 OSF 1.50 11349.64 3806.71 MInPt-O-SF 10523.55 152.87 10421.31 10370. 103,9 OSF 1.60 llW9, 37 38a9.80 MInPtASF 11479.09 185.35 11355.20 11203.7 93.3 OSF 1.50 130W 43 3846.44 WIN-0.SF 12499.05 215.85 12354.82 12263. e1.2 CSF 1.W 13997-22 3881.45 MmPt-O-SF 1361741 293.35 13421.51 1332406 09.86 OSF 1,50 15Q7.05 3949.99 TD 1833. 32811 1319851 18W. 144.58 MAS=1000 (m) 2159.51 2006. 16 M,nNt OP19-TlNPB1(D.( Survey) Peas 177.28 32.81 175.54 744.4 341.21 MAS=10.00 (m) 147.87 147.87 MinPts 281.77 32,81 275.01 248.96 50.66 MAS =10.00 (m) 947.55 935,59 MInPt-O-SF 952876 176.77 9410,57 935199 81.32 OSF 1.50 10880.54 W29.61 TD 1833.80 32811 1819851 18 744.58 MAS=10,00 (m) 2159.51 200016 MlnPls 012MM82 (Oe/ Survey) P 328ir 183.59r 152.50 374.72 MAS = 10.00 (m) 747,70 14770 MinPls 213,23 3281 20595 180.43 35011 10.00 (m) 482.92 482,14 MmPt-0.SF 17318.45 102,89 17249,52 1721557 CSF 1.W 10091.18 3821.32 M'InPI-O-SF 19063. 10 130,76 18975.69 18932, 220.41 OSF 1.50 10975.52 3830.70 M1nPI.0-SF 19589.75 1"05 19492.77 10445.09 205.4 OSF 1.60 11347.18 3846.80 MInPt-0-SF 20586.21 154.62 20482,65 20431.39 OSF 1.60 12WZW 3849.81 MInPt-0.SF 20665.78 17588 20548. 18 20089.90 177,28 OSF 1.50 12058.70 3850.23 TD 1212801 32.81 1211087 14".20 75]B MAS=1000 (m) 703. 19 738.63 MinPt-O-SF 1800.78 32.81 78]0.73 IS 213.06 MAS=10.00 (m) 129648 1259,88 MIWI5 0120-07P81 (Del Survey) Pass 18531 32.81 183.59 152.50 374.72 MAS =10.00 (m( 147.70 14770 MlnPls 21323 3281 205.95 180.43 3201. MAS=10,00 (m) 482.92 482,14 M,Wt-0.SF 143]8 51 108.34 14305,92 14270.16 201.04 OSF 1.50 9405.40 3786.65 TO 1880.78 32611 1870731 lU7 971 MAS=10.00(m) 1298.46 1259,W MtnPis 0120.07 (Def Survey) Pass 185.33 32.81 183.61 152.52 371 78 MPS =10.00 (m) 148.W 148.55 MlnPts 213.23 3281 205,95 lWQM332 MAS=10.00(m) 482.92 482.14 MinPt-0.SF 22818.27 103.89 22748.OD 22714. OSF 7.50 889069 375576 MmPt-0.SF 226326410309 22%348 22629.4 OSF 1,50 8937,73 3756,38 MmPI-O-SF 17319.32 103,02 17250.30 17216. OSF 160 10091.46 3821.32 MinPW.SF 1906386 130.94 18976.22 1893292 OSF 1.50 10975.94 3830. 71 MmPl-0.SF 1961329 144.27 19516,78 19469.0 OSF 1.50 11347.81 3848.fi3 MInPt-0.SF 2065831 155. 10 20554,58 20503.21 OSF 1.60 12002Q 384981 WN-0.SF 21949.90 188.54 21825,21 2176335 OSF 1.50 12999.68 384044 MInP,O.SF 22635.49 222.07 22487,12 22413.43 153.57 OSF 1.50 1351647 3863.33 TD 12128.88 32.81 12111.84 12096,07 757.8 MAS=10.00 (m) 743.76 738.59 MinPt-CSF 1881.68 32.81 1871. 1848.8 213.1 MAS=10.00 (m) 1298.45 12%W MinPls OP21-WW01(Daf Survey) Pass 183.28 32.81 191.43 660.47 307 24 MAS = 10.00 (m) 144.58 1.58 MinPts 223.26 32.81 21501 790.4 31.61 MAS =10.00 (m) 545.77 54408 MinPt-0.SF 243.13 32.81 234.25 210.33 31.56 MAS=1000 (m) 865.97 663.05 MinPt43.SF 309.51 32.81 298.72 278.7 32.12 MAS = 10.00 (ml 952.62 940.42 Mir�P(-0.SF 429.42 32.81 416.86 3061 37,77 MAS=1000 (m) 1417.25 1364.59 M'mPl-0.SF 1263,34 3281 1247,22 1230. 84.74 MAS=10.00 (m) 2743.42 2424.79 MInPt-0.SF 1514.87 32.81 1488.99 1482.06 9086 MAS =t0.110 (m) 2917/2 252182 MInPI-QSF 1866, 70 32.81 law 83 1823.89 9869 MAS =10.00 (m) 313.86 2613,50 WPI-0.SF 3956.17 72.68 3907.76 3683.89 82. OSF 1.W 4289.07 2892.39 WR-0.SF 4514.46 58.17 4475.33 4456.29 118. OSF 1.50 4 %72 29%N MInPt-O-SF 4763.49 6141 4722. 19 4702.08 118. OSF 1,50 4825.17 MW 14 M,Wt-0.SF 4931.32 63.42 4888.71 4W7.00 118.45 OSF 1.50 4935.70 302235 WPt-0.SF 4048.02 W63 Q0627 4884. 118,45 OSF 1.50 4946.70 3024.57 MmPt-QSF 5895.63 96.91 583069 5798.71 92.1 OSF 1.50 8181.87 3660.65 MinPt-0.SF 5377.80 71. 19 M. 5306.61 11502 OSF 1.50 9075.50 3767.53 MinPt-O-ACP 5377.71 71.10 5329, 5306.62 115.16 OSF 1.50 9079.20 3767W MINPT-O-EOIt 5377.63 70.M 5330.03 630576 115.55 OSF 1.50 GM 84 3768.50 MinPt-CICI 53538 78.35 5302.44 5277.35 106.86 OSF 1.50 9808.59 380785 MInPI-CtCt 5353.84 76.80 6302.28 5277.04 fM02 OSF 1.50 9030.71 3808.91 MINPT.O.EOU 5354.12 17. 14 530233 5276.9 105.55 OSF 1,50 9848.79 35MN MInPI-0.ADP 5772.72 96,97 5707.75 5675.78 90.20 C8F 1.50 10850.92 3829A4 MmPt-0.SF 6323.28 105.84 8252.39 6217. 90. OSF 1.50 11352.37 384683 MinPt-0.SF 6809.76 109.09 8736,69 6700.66 94.4 OSF 1.50 17428.40 38Q 31 M1nP40.8F OP22-W W03 (Def Survey) Pass 201 32 32 81r 199 54r 168.61 364.61 MAS = 10.00 (m) 14762 14762 MinPts 320. B9 32.81 311 99 2M W 41 fi4 MAS = 10.00 (m) 954.60 942.49 MinPt-0.SF 8687.77 87.93 8628,82 8599.631154,9 OSF 1.W 9005.96 3702.17 M1nPt-0-SF 8387.42 85.62 8329.98 8301. OSF 1,50 907731 3767,67 MinPt-(MF 8182. 19 8338 812625 8D98, 81 OSF 1.50 9135.10 3771% MiWt-0.SF 838408 90.92 832311 8293.1 OSF 1.50 990 0 381274 MinPt-0.SF 844984 9162 8388.40 8358 OSF 1,50 997290 W1635 MmPI-0.SF M94.42 92.09 M32.1i8 8Q2. OSF 1.50 1001638 381863 MinPt-0.SF 8586.02 9301 852360 $49301 OSF 1.50 1005397 382034 MmPt-0.SF 8630.48 9371 8567,67 8538.7 05F 1.50 10068.74 382082 MinPt-0.SF 1014295 018 f0076.S0 IW 7 OSF 1.50 10.5.23 3826,91 MmPl-0.SF OP23-W W02 (Def Survey) Pere 20878 32.81 207.09 175.98 445.12 MAS =1060 (m) 147.35 14734 MinPts 309.88 32.81 303.08 277.07 55.Q MAS = 1060 (m) 948.68 D36.67 MInPI-0.SF 1482,06 32.81 1,145.96 1429.26 98,15 MAS= 10.00 (m) 2177.87 2021.17 MInPI-0.SF 2135,95 MM 2112.22 2100.96 94.82 OSF 1.50 2449.85 2230.55 MInPI-0.SF 4279.85 36.73 4255.01 4243.13 In% CSF 1.W 3104.87 2609.74 MInPt-0.SF 465529 MAI Q29w 4615.46 180.11 OSF 1.50 3193.19 2644.85 MinPIO-SF 4744.89 40.60 4717.47 4704,29 180.00 OSF 1.50 3213,14 2662.21 M'InPt-0-SF 5640.55 Q05 6808A7 6592.51 18006 OSF 1,50 3391,75 2706,40 WInPIOQSF 6181.16 52.77 6145.62 6128.39 179.31 OSF 1.50 3491.86 2732.12 MhPt-0.SF 8543.94 88.21 8455.73 146.92 CSF 1.50 4288.75 2802.33 WPICbF 7830.15 118.Bfi 757/. 9715 OSF 1.50 8136.73 3853.35 MInPt-0.SF 7467. t19 116.45 �6423 7350.64 97. CSF 1,50 8204.78 3669.30 M'InPt-0.SF 6471.Q 70.70 6400. 139.39 OSF 1,50 9074.52 3707.46 M'mPt-QADP U71. 17 70.43 8400.74 13 . CSF 1.60 9080.39 37B7.89 MINPT-O.EOU 64]1.02 7002 642398 6QI.W IQ 74 CSF 1.50 W89. 18 3768.52 MinPt-CICI .69.Q 67,58 6424. 8401.92 14588 OSF 1.W 91 W,72 377270 MinPt-O-ADP 6469.44 67.51 44240 5Q1.92 146.02 OSF 1.50 9153,65 3772.89 MINPT-0.EOI1 8489 87.39 8424,12 8402.01 I-- OSF 1.50 .1-51 3773.27 MOO-CICt 84181 77.38 6366.22 83Q16 126.12 OSF 1.50 10201 76 3823.00 MinPt.CtCt 8017 SS 83.03 Ml 87 6334,55 117.43 OSF 1,50 10424.98 3828.69 MinPt-CICt 6417,87 84.29 8361.3 8333.58 115.86 CSF 1.W 10484.44 3827. 16 MINPT-0.EDU 6418.93 85.52 8361 6333.41 tt3.99 OSF 1.50 10504,89 3827,42 M,Wt-O-ADP Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point 1-1A-106 (P5b) Page 12 of 13 Offset Tratectory I Separation I Allow I Sep. I Controlling I Reference Trajectory I Risk Level I Alert I Status U49. 19 100.95 6381.54 48.2 638121 9..68 OSF 1..0 101..5 3.8 9. 629 11175 . 641810 SF 150 113568 384654 601.34 . 11943 6621.36 81.9 OSF 1,50 11889.59 3849.80 6304.03 152.77 820185 8151,26 8205 OSF 1,50 14088.03 W86.79 7056.20 146.09 6958. is 6910.11 ]2.93 OSF 1.50 13402.24 SWIM 012408 (Def Survey) 216 BO 32.81 215.1 884.09 417.48 MAS = 10.00 (m) 1" 58 144.58 217.13 32.81 215.35 184.32 385.9 MAS = 10.00 (m( 161.30 161.29 313.00 32.81 304.82 280.19 4.8 MAS =10.0F $65...58 16882.61 11628 168U4.7 167663 .. 19 OSF 1.50 88254 3745,45 16420.19 0 19.8 OF 1 885757 3748921 147349 8.4 1 1 488 OS1(.m) S50 1668.....54 13.8 3887 153109 160.94 522346 .. 517015 1437 OSF50 199565 384980 16. 19377 1609867 160340 122 OSF 1.50 1300339 .42 1752628.1288 225,28 17355.76 17260.99 OF0 398020 3880.74 '647.40 305.74 20343.24 20241,65 101.13 OSF 1,50 15794.66 3958.43 I178447 32.81 11782.54 71751.E 582.71 MAS=10.00 (m) T7964 774A0 17346.37 32.81 11326.23 11313.6 662.9 "AS`0.00 (m) 797.9E 791.88 10823.13 32.81 70802.7E 107808 558.2 MAS=t000 (m) 821.70 814.8E 10359.43 32.81 /038981 103588 5518 MAS=10.00 (m) 840.68 833,19 10124.93 3281 10105.58 10092.1 551.21 MAS = 70.00 (m) 8%37 842.53 10036,76 32.81 10017.5E 10003.W 55087 MAS =1000(m) 853.84 845.86 9949,05 32.81 9930.01 9916.24 550.81 MAS=1000(m) 857.68 849.57 9866.12 32.81 :847,18 9833.32 549. 18 MAS=10.00(m) 861.66 853.41 9427.66 32.81 409.21 939484 54021 MAS = 10.00 (m) 879.15 870.21 9212.37 32.81 9194.16 917956 534 93 MAS = 10 00 (m) SW 02 878.72 8831.85 32.81 8814,40 8799,04 536.19 MAS =10.00(m) 909.91 899.70 8723.86 32.81 8706 65 869108 536.70 MAS = 10 00 (m) 917,89 907.32 8598.55 32.81 85BI 54 8565.7 536.52 MAS =10.00(m) 928.44 917.39 8106.66 32.81 80DO 71 8073.84 542.24 MAS = 10.OD (m) 969.03 956.00 7801,45 32.81 7786. 16 7768. 545.30 MAS =10.00(m) 980.34 976.18 7517.59 32,81 7502.86 7484.78 550.10 MAS=1000 (m) 1009.70 999.4E 7022,43 3281 7"11 609.6 5]2. MAS=1000 (m) 1037.77 1020.86 8888 43 32.81 6875.33 8855.E 572.7 MAS = 10.00 (m) 1045.44 1028.0E 2194,8 32.81 2184, 2162,1 227.91 MAS=10.00(m) 1513.29 1448.27 OP26-DSP02 (Def Survey) 418.t5 3281 418_ 385.34 9.87 MAS =10.00(m) t44.58 144.58 420.92 32.81 415 9 388.11 IN 51 MAS = 10 00 (m) 688.25 684,91 421.11 32811 415801 388.30 100.01 MAS =10.00(m) 721.65 717,60 455,14 32.81 448,92 422.33 6385 MAS =10.00 (m) 1000.42 985.70 1325,54 32.81 1311 BD 1292 74L IN 85 MAS =1000(m) 1774.52 1875,70 M75.% 99.46 7808.93 7776.10 119. OSF 1.50 8669.90 3728.78 7434.91 107,47 '62.94 7327451 104 Z4 OSF 1.50 10974.26 3830.6] T727, 17 118,83 7047.62 7608. 98.35 O5F 1,50 11349.21 SWAG T742.94 110.03 78 7632.91 106. OSF 1.50 1169.26 357.5E 3547,06 7930.03 11121 7855 56 7818.82 107.90 OSF 1.50 11380.84 3047,99 MInPt-6SF MinPI.O-SF TD MInPI.O-SF Pecs MinPts MInPt-O-SF MinPI-O-SF MmPI-O-SF MInPI-QSF MinP1-0-SF MInP1.O-SF MInPt- F Min%-O-SF TD MinPt-O-SF MInPI.O-SF MInPI.O-SF MinPl-O-SF Min PI-OSF MmPICO SF MInP40SF MinPt-0-SF MinPI-6SF MinPI-O-SF MInPI-O-SF MInPI-O-SF MinPt-O-SF MInPt-O-SF MinPI-O-SF MinPt-O-SF MmPt- SF Minl`,O-SF Min%s Pess MinPts MinPts MINPT-O.EOU MinPt-6SF MInPt-6SF MinPt-QSF MirIPt-6SF MinPI.O-SF MInP1-0-SF TD Drilling Office 2.7.1043.0 Nikaitchuq\Oliktok Point\Oliktok Point 1-1\Oliktok Point I-1A-106\Oliktok Point I-1A-106 (P5b) Page 13 of 13 Traveling Cylinder Plot NoGo Region EOU's based on: Oriented EOU Dimension N NoGo Region Anti -Collision rule used: Minor Risk - Separation Factor AJ,15/ 280 270 260 North 350 0 10 190 180 170 Well Ticks Type: MD on Oliktok Point 1-1A-106 (P5b) Calculation Method: Normal Plane Ring Interval 10.00 ft Azimuth Interval: 10.00 deg Start Depth: 900.00 ft End Depth: 2800.00 ft Offset Well Count: 51 TRAVELING CYLINDER PLOT Client ENI Field Nikaitchuq Structure Oliktok Point Well Oliktok Point 1-1 Borehole Oliktok Point 1-1A-106 Date 07-Apr-2014 80 90 100 Traveling Cylinder Plot NoGo Region EOU's based on: Oriented EOU Dimension N NoGo Region Anti -Collision rule used: Minor Risk - Separation Factor 280 270 260 North 350 0 10 190 180 170 (Well Ticks Type: IMD on Oliktok Point I-1A-106 (P51b) Calculation Method: lNormal Plane Ring Interval 10.00 ft Azimuth Interval: 10.00 deg Start Depth: 2700.00 ft End Depth: 9900.00 ft Offset Well Count: 51 TRAVELING CYLINDER PLOT Client ENI Field Nikaitchuq Structure Oliktok Point Well Oliktok Point 1-1 Borehole Oliktok Point 1-1A-106 Date 07-Apr-2014 90 100 Traveling Cylinder Plot NoGo Region EOU's based on: Oriented EOU Dimension N NoGo Region Anti -Collision rule used: Minor Risk - Separation Factor 280 270 260 North 350 0 10 190 180 170 Well Ticks Type: MD on Oliktok Point 1-1A-106 (P51b) Calculation Method: Normal Plane Ring Interval 10.00 ft Azimuth Interval: 10.00 deg Start Depth 9800.00 ft End Depth: 118631.00 ft Offset Well Count: 151 TRAVELING CYLINDER PLOT Client ENI Field Nikaitchuq Structure Oliktok Point Well Oliktok Point 1-1 Borehole Oliktok Point I-1A-106 Date 07-Apr-2014 80 90 100 �` VA 2n i y 16 I L ?K9 Schlumbuger Borehole: Oliktok Point I-1A-106 (P6) Well: Oliktok Point 1-1 Field: Nikaitchuq Structure: Oliktok Point Gravity 8 Magnetic Parameters Surface Location NAD27 Alaska State Plane, Zone 04. US Feet Miscellaneous Model: BGGM 2013 Dip: 81.02r Date: 15Jun-Jun Lat: N 70 30 40.06 Northing: 66036581.15ftU Grid Gonv: 0.1293' Slot: OPO7 TVD Ref: Rotary Table(53ft above MSL) MagDec: 19.294' FS: 57620.403nT GravityFS: 1001.989mgn (9.80665 Based) Lon: W 149 51 46.24 Easting: 516760.85ftUS Scale Fact: 0.99990032 Plan: Oliktok Point I-1A406 (P5b) 0 2000 4000 6000 8000 10000 140 120 1001 801 Pi. 60( z Z 40( 20( Oliktok Point 1-2 )0 ° )SP04-S 5 (P2) N I � � P S107-SE4 P2 tr 0 - — SP12-SE3(P2) OP05-06L1 Olikt k Point I-1A-106 (P5b) OP05-06 404 TVD p0 4053 ND 4000 ND ° SI17-SE2 (N) 4400 ID OPO4-07 3935 TVD °�� 0106-05 SP24-SE1L1 40b3106 OSP 3sez 10 - 3954 _ �_ TVD 394TVp TVD SP24-SE1 "gg��Tw 3w OP051-06 62 0P03-PO5L1 OPO4-07P 1 OP03D-POS 3 TW 3 TVD 3.TVD TVID TVD ND 867TVD TVD 3196 10TVD 3873 ND 3 3 TVD 3 21 NO ' i0_ -__— _ -- 3 k25 ND TVD 384 8 ND 8811 iTVD 3906 TVD TVD 13TVD OP03 POSP 2 TVD 38iD 385 ND 3841 TVD R 3837 TVD?; 0 - -- -- -L 386 TVD 3a36TVD3D 3542TVO3871 TVD38523500 ND 3852 TVp 3829 TVD3gy3T DTVD 3630 TVD 0 � 3000 959 ND TV OII Point 1-1 <—`Jc ok 3710TVD� 12 TM/ G 3713 TVD OP03-P05PB1 3777 TvD 3832 0 2600TVD- -- NO 35gg TVD ( O 00 N� 0 4 14 0 2000 4000 6000 8000 1 EW (ft) Scale = 1:800(ft) 14000 12000 10000 3000 3000 t000 Bettis, Patricia K (DOA) From: Occhionero Lara [Lara.Occhionero@enipetroleum.com] Sent: Thursday, April 10, 2014 2:19 PM To: Bettis, Patricia K (DOA) Subject: RE: OP 1-1A-106: Permit to Drill Application Attachments: Oliktok Point I-1A-106 (P5b) SLB quarter mile plot.pdf; Oliktok Point 1-1A-I06 (P5b) SLB quarter mile scan.pdf Patricia, Attached the % mile scan. Let me know if you need anything else. Thanks a lot. La ra From: Bettis, Patricia K (DOA) [maiIto: patricia.bettisC&alaska.gov] Sent: Thursday, April 10, 2014 10:46 AM To: Occhionero Lara Subject: OP I-1A-I06: Permit to Drill Application Good morning Lara, Under 20 AAC 25.402(c), an application for injection must include a plat showing the location of each proposed injection well, abandoned or other unused well, production well, dry hole, and other wells within one -quarter mile of each proposed injection well. This information was missing in the permit to drill application OP I-1A-106. This information may be submitted to me via email. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. Bettis, Patricia K (DOA) From: Occhionero Lara [Lara.Occhionero@enipetroleum.com] Sent: Thursday, April 10, 2014 11:20 AM To: Bettis, Patricia K (DOA) Subject: Re: OP I-1A-106 No pre -produce in this well Patricia. Thanks! Sent from my iPhone On 10/apr/2014, at 11:13, "Bettis, Patricia K (DOA)" <patricia.bettis@alaska.gov> wrote: La ra, Does ENI plan to pre -produce OP 1-1A-106 and if so, for what duration? Thanks, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Thursday, April 10, 2014 10:46 AM To: 'Occhionero Lara' Subject: OP 1-1A-106: Permit to Drill Application Good morning Lara, Under 20 AAC 25.402(c), an application for injection must include a plat showing the location of each proposed injection well, abandoned or other unused well, production well, dry hole, and other wells within one -quarter mile of each proposed injection well. This information was missing in the permit to drill application OP I-1A-106. This information may be submitted to me via email. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. Bettis, Patricia K (DOA) From: Occhionero Lara [Lara.Occhionero@enipetroleum.com] Sent: Tuesday, April 08, 2014 4:46 PM To: Bettis, Patricia K (DOA) Subject: RE: OP I-1A 106 106 (1 should be for Injector) Regards La ra From: Bettis, Patricia K (DOA) [ma iIto: patricia.bettisC,aalaska.gov] Sent: Tuesday, April 08, 2014 4:43 PM To: Occhionero Lara Subject: OP I-1A 106 La ra, Would you please explain the naming nomenclature for this well. And is it 106 or 106? Thanks, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITYNOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. Bettis, Patricia K (DOA) From: Occhionero Lara [Lara.Occhionero@enipetroleum.com] Sent: Tuesday, April 08, 2014 2:29 PM To: Bettis, Patricia K (DOA) Subject: RE: OPI 1A: Permit to Drill Application Attachments: Oliktok Point I-1A-106 (P5b) directional report.pdf Yes Patricia It was my mistake! I've already sent them by mail when I came back to the office. Sorry I realized I didn't attached it when I was already in you r premises! Anyway you get them attached. Sorry about that! Best regards Lara From: Bettis, Patricia K (DOA)[ma iIto: patricia.bettis(&alaska.gov] Sent: Tuesday, April 08, 2014 2:24 PM To: Occhionero Lara Subject: OPI 1A: Permit to Drill Application Lara, OPI 1A will be a sidetrack off the original well Oliktok Point 1-1 (PTD 206-137). The permit to drill application is missing the proposed wellbore survey and the horizontal and sectional plats. These can be submitted to me via email. Thanks, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Tuesday, April 08, 2014 2:24 PM To: 'Occhionero Lara' Subject: OR 1A: Permit to Drill Application La ra, OPI 1A will be a sidetrack off the original well Oliktok Point 1-1 (PTD 206-137). The permit to drill application is missing the proposed wellbore survey and the horizontal and sectional plats. These can be submitted to me via email. Thanks, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. STATE OF ALASKA ALASKA IL AND GAS CONSERVATION COMMISSION APPL)OATION FOR SUNDRY APPROVALS �� •`t•t 20 AAC 25,280 RECEIVED MAR 13 Z014 AOGCC 1. Type of Request: Abandon ❑ Plug for Redrili Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing PI Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well Q ' Stimulate ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit t rill Number: Eni US Operating Co. Inc. Exploratory Development ❑ Stratigraphic ❑ Service ❑ 206-13 3. Address: 6. �P Number 3800 Centerpoint Drive, Ste. 300 Anchorage, AK 99503 �029-23324-0D OD 7. If perforating: 8. Well Ngme and Number. What Regulation or Cons ation Order governs well spacing in this pool? Will planned perforatio require a spacing exception? Yes ❑ No ❑ -11 9. Property Designalign (Lease Number): 10. Field/Pool(s): 1 /Shrader ADL 355023, 355024, 390615 -3 �330� Nikaitchu Bluff 11. PRESENT WELL CONDITION SUMMARY Total Depth M (fl): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TV (ft): Plugs (measured): Junk (mea ed): 8'990 3,912 2391 N/A Ca ng Length Size M TVD Bu /collapse St ctural onductor 76 16" 115 115 Surface 2570 10.75" 2541 207jpA 1 5,210 2,480 Intermediate Perforation Depth MD (ft): Perforation Depth �VQ ): T ing ize: Tubing Grade: Tubing MD (ft): U 3 112 L80 j 2.000 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD t): / N/A N/A J/ 12. Attachments: Description Summary of Proposal ❑ 13. Well Class after. proposed work: WDD Detailed Operations Program BOP Sketch Q Exploratory Slraligr phic ❑ Development ❑ Service 1 14. Estimated Date for 19-May-14 15. Well Status after proposed rk: Commencing Operations: Oil ❑ Gas [-)/ WDSPL ❑ Suspended t[� WINJ [ GINJ WAG ❑ Abandoned ❑ 16. Verbal Approval: Dale: Commission Representative: GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and rrecl to the best of my knowledge. ontacl James Wright Email James.Wright(Wenipetroleum.com Printed Name James Wright --) Title Drilling & CompI ion Engineering Manager Signature _ _ h nt 907-865-3321 Date 3112/2014 COMMISSION U0 ONLY Conditions of approval: Notify Comm' sion so that a representative may witness Sundry Number: 3\Lk - \1(0 o Plug Integrity ❑ B P Test Mechanical Integrity Test Location Clearance ❑ Other: y� [ -w !r/ d 1 5 Spacing Exception Required? Yes ❑ No [ Subsequent orm Required: 7- APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 4-10 U, l I t �! �k f J� /l 1 l y `� 'Submit Form and Form 10 4D3 (Rev' 10/2012) Appr li o rTk a 1�months from the da a of approval. 1b`1, r Attachments in Duplicate %� • Eni Petirolleumn eno 3800 Centerpoint Drive Suite 300 Anchorage, Alaska 99503 James Wright Phone (907) 865-3321 Email: james.wright@enipetroleum.com March 120' , 2014 Alaska Oil and Gas Conservation Commission 333 West 7"' Avenue, Suite 100 Anchorage, Alaska 99501 -� RE: Application for Sundry Appro(alr OP-I1 Rig Workover Dear Commissioners, ENI US Operating Co. Inc. hereby applies for a Workover Sundry for well O1P•-I1. L� P 0 aP�r t e+1 RECEIVED MAR 13 2014 A0GGC OP-I1 was drilled on September 29th, 2006 and suspended December 3151, 2006. Well condition sundry was submitted by eni to AOGCC on November 12, 2010, and October 1 lth, 2011. Next required inspection by Sept 30, 2015. Y• q•/ti The estimated date for beginning this work is May 19" , 2014. Please find attached for the review of the Commission forms 10-403 and supporting documentation. If you have any questions or require further information, please contact at 907-865-3321. weer ly, ti J es right Drilling & Completion Engineering Manager OP-11 Workover — Summary Page OP-I1 Capital Rig Workover PTD#:208-137 Current Status Well OP-I1 is currently dead. Scope of Work Scope of this workover is recover the well to be used as an OA-San/d`Injector. /� General Well info S ' w"" Reservoir Pressure/TVD: Well was suspended (December 318`, 2006). Wellhead type/pressure rating: Vetco Gray, MB-234/5000 psi BOP configuration: Annular/pipe/blind rams/Mudeross/pipe TIFL/MIT-IA/MIT-OA: Inspected by eni on November 12'', 2010, and October 11 ', 2011. Well type: Exploration Estimated start date: May 19th 2014 Drilling rig: Nabors 245 Contact: James Wright: James. Wright@enipetroleum . com Work: 907-865-3321 Procedure: 1. MIRU Nabors 245. R/U 1 1" x 13 318" adapter flange and BOP. � �►n: 2. Ensure well is dead.--"' PT eGs%wj /_ — 3. Pull 3 ''/2" kill string. ,,/Soys,� 4. Remove existing wellhead, Install 16-20" swedge, Riser and Diverter 5. Perform the cuts — 350% 250% 150% 60' 6. Washover 10-3/4" casing with 13-3/8" FJ Nvash pipe or 13 3/8" casing and wash - shoe to approx 350' GL. Pull 10-3/4" intennittently during works. 7. Well clean-up to sidetrack point and set bridge plug and AS cement plug on top 8. Continuing with sidetrack operations. Below the current schematic of the well: 5/7- pj5P7"Y Oliktok Point- e„ c e Injector #1 P131 pnl tlN'p WfJ f�• tRK-RK YD rl rKX! M 3IIL cFiw, ML[1 t -.0 ir�tM.t• WrC ,t. ree,. Kv:�r Phi as I P;LV C3 .-.. ti.n •rl �fTrell� lr,y n Ju 1 - $S16Lm+� �`YY !ri^ ]LDS �tll wwrLwN W/ s�v TRANSMITTAL LETTER CHECKLIST WELL NAME: OU I( QK ?01'nl - PTD: JJy -OsI Development Service _ Exploratory — Stratigraphic Test _ Non -Conventional FIELD: h POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing well Permit (If last two digits No. , API No. 50- - - - in API number are Production should continue to be reported as a function of the original between 60-69) API number stated above. 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 name Pilot Hole ( 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 Spacing Exception conservation 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 Loggingalso 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 4/2014 WELL PERMIT CHECKLIST Field & Pool NIKAITCHUQ, SCHRADER BLUFF OIL - 561100 Well Name: OLIKTOK POINT 1-1A-106 Program SER Well bore seg PTD#:2140510 Company ENI US OPERATING CO INC Initial Class/Type SER / PEND GeoArea 890 Unit 11400 On/Off Shore On Annular Disposal Administration 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0373301. Surf; ADLs 0355024 & 0355023, portion wellbore passes thru; ADL0390615 Top Prod & TD. 3 Unique well name and number Yes OLIKTOK POINT OP I-1A-106 4 Well located in a defined pool Yes NIKAITCHUQ, SCHRADER BLUFF OIL - 561100, governed by Conservation Order 639 5 Well located proper distance from drilling unit boundary Yes CO 639 contains no spacing restrictions with respect to drilling unit boundaries. 6 Well located proper distance from other wells Yes CO 639 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 CO 688 issued 3/25/2014-a spacing exception to well spacing provisions of 20 AAC 25.055(a)(2) for OP 11A-106 10 Operator has appropriate bond in force Yes will not jeopardize correlative rights of adjoining or nearby owners. Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval Yes PKB 4/11/2014 13 Can permit be approved before 15-day wait Yes 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For Yes Nikaitchuq, Scrader Bluff Oil, governed by AIO 36 15 All wells within 1/4 mile area of review identified (For service well only) Yes OP05-06, OP05-061-1, Oliktok Point 1-1. 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) No Eni does not plan to pre -produce this well. 18 Conductor string provided Yes 16" conductor driven to 76 ft. Engineering 19 Surface casing protects all known USDWs Yes No aquifers... 20 CMT vol adequate to circulate on conductor & surf csg Yes 13 3/8" surface casing will be fully cemented. 21 CMT vol adequate to tie-in long string to surf csg No 9 5/8" casing will be cemented to 6700 ft md. ( SC shoe at 2756 ft. ) 22 CMT will cover all known productive horizons Yes -- lateral will have slotted liner. 23 Casing designs adequate for C, T, B & permafrost Yes BTC calc provided and meet industry accpted standards. 24 Adequate tankage or reserve pit Yes Rig has steel pits .. All waste will be injected into onsite disposal well. 25 If a re -drill, has a 10-403 for abandonment been approved Yes 314-160 26 Adequate wellbore separation -proposed Yes proximity analysis performed .. No issues. 27 If diverter required, does it meet regulations Yes Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation press= 1818 psi ( 8.7 PPG EMW) Will drill with 8.7- 9.4 ppg mud GLS 4/14/2014 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP = 1374_psi_ Will test BOPE to 3500 psi 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable No H2S not expected. 34 Mechanical condition of wells within AOR verified (For service well only) Yes 1/4 mile review and plot map provided... OP-11 is P &A'd 35 Permit can be issued w/o hydrogen sulfide measures Yes H2S not expected. Rig has sensors and alarms, and H2S sequestering materials are onsite. Geology 36 Data presented on potential overpressure zones Yes Expected_ reservoir pressure is 8.6 ppg EMW; will drill using_8.8 to 9.5 ppg mud. Appr Date 37 Seismic analysis of shallow gas zones NA PKB 4/10/2014 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weeklyprogressreports_ [exploratory only] - NA Development well drilled from onshore pad. Geologic Engineering Public Sidetrack of existing suspended well OP-11. Will pull existing 10 3/4" casing from 300 ft and do OH sidetrack. GLS Commissioner: Date: Co issio er: Date Commissioner Date O�"S Co