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217-010
Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Friday, March 29, 2019 1:28 PM To: jlongo@bluecrestenergy.com'; 'Tom McKay' Cc: Davies, Stephen F (DOA); Schwartz, Guy L (DOA) Subject: Hanse H-14 L1, PTD 217-010, Permit Expired Hello Joseph and Tom, The Permit to Drill 217-010, issued to BlueCrest Alaska Operating on March 17, 2017, expired under Regulation 20 AAC 25.005 W. The PTD 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.guhIPalaska.gov. THE STATE 'ALASKA GOVERNOR BILL WALKER Randy Frazier Drilling Manager BlueCrest Alaska Operating, LLC 3301 C Street, Suite 202 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Hansen Field, Undefined Oil Pool, H-14L1 BlueCrest Alaska Operating, LLC Permit to Drill Number: 217-010 Surface Location: 2368' FSL, 1517' FEL, Sec. 2, T4S, R15W, SM Bottomhole Location: 3126' FSL, 1921' FEL, Sec. 29, T3S, R15W, SM Dear Mr. Frazier: 333 West Seventh Avenue Anchorage, Alaska 99501-3572, Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Enclosed is the approved application for permit to drill the above referenced development well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to producer is contingent upon issuance of a conservation order approving a spacing exception. BlueCrest Alaska Operating, LLC assumes the liability of any protest to the spacing exception that may occur. The permit is for a new wellbore segment of existing well Permit No. 217-007, API No. 50-231-20052-00- 00. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P Foerster Chair DATED this L� �day of March, 2017. STATE OF ALASKA ECEIVED AKA OIL AND GAS CONSERVATION CON,. .. LION AN 17 ?01% PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: 1 b. Proposed Well Class: Exploratory -Gas LJ Service - WAG ❑ Service - Disp PM 1c. Specify if well is proposed for: Drill ❑ Lateral ❑✓ Stratigraphic Test ❑ Development - Oil El' Service - Winj ❑ Single Zone 'oalbed Gas ❑ Gas Hydrates ❑ Redrill ElReentry ❑ Exploratory - Oil ❑ Development - Gas ElService - Supply ElMultiple ZoneGeothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11. Well Name and Number: BlueCrest Alaska Operating LLC Bond No.: BG984tir r� Z 5 / 55/% , a3 /7 1-114-1-1 ° 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3 3301 "C" Street, Suite 202, Anchorage, AK 99503 MD: 22,713' • TVD: 7,077' Hansen, Undefined C0&RM;VFeM Oil 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Pool Surface: 2368' FSL, 1517' FEL, Sec. 2, T4S, R15W SM k'`�`'-ADL18790, ADL384403 Top of Productive 4074' FSL, 587' FEL, Sec. 33, T3S, R15W SM 8. Land se e� . 13. Approximate Spud Date: Horizon: LOCI 14-007 2/15/2017 Total Depth: 3126' FSL, 1921' FEL, Sec. 29, T3S, R15W SM 9. Acres in Property: 14. Distance to Nearest Property: 14,422.91 1,406' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 180.25 • 15. Distance to Nearest Well Open urface: X - 168853.294 Y- 2144816.902 Zone- 4 GL Elevation above MSL (ft): 145.63 - to Same Pool: 1,600' - H16 16. Deviated wells: Kickoff depth: 14,735 feet • 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 96.96 degrees Downhole: 3,462 psi - Surface: 2,772 psi ° 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) 8.5 4.5 15.2 P-110 Hyd 563 8128 14585 7032 22713 7077 Uncemented 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 Surface Intermediate Production Liner Perforation Depth MD (ft): N/A Perforation Depth TVD (ft): N/A 20. Attachments: Property Plat ❑✓ BOP Sketch ❑✓ Drilling Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis❑✓ Diverter Sketch ❑✓ Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements ❑✓ 21. Verbal Approval: Commission Representative: Date 1/16/2017 22, 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Joseph Longo Email jlongo@bluecrestenergy.com Printed Name Randy Frazier Title Drilling Manager LSignature Phone 907-754-9560 Date 1/16/2017 Commission Use Only Permit to Drill API Number: _ Permit Approval See cover letter for other Z17-©/0 Z� ._ Number: 50- ,Z.�' ' �G �. ? Date: 7j . \i - ,2 p L-1 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: ❑✓ Other: 35oU It95J90 Samples req'd: Yes ❑ No ❑- Mud log req'd: Yes❑ No ©' dK O HzS measures: Yes ❑ No Lrf Directional svy req'd: Yes® No L Spacing exception req'd: Yes ❑ No ❑ Inclination -only svy req'd: Yes[:] No E] L � Post initial injection MIT req'd: Yes❑ No ❑ D APPROVED BY Approved b : COMMISSIONER THE COMMISSION Date: orm se gm� achments in Duplic e lust Energy 3301 C Street, Suite 202, Anchorage, AK 99503 Joseph Longo Phone: (907) 754-9561 Email: JLongo@bluecrestenergy.com January 16, 2017 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: Application for Permit to Drill: Horizontal Production Well H14-L1 Dear Commissioners, Cosmopolitan Project RECEIVED JAN 17 2017 A0GC"O"C BlueCrest Alaska Operating LLC hereby applies for a Permit to Drill for the onshore horizontal production well H14-0. This well will be drilled and completed using BlueCrest Rig #1. The planned spud date could be as early as 03/01/2016. The 1-114-1-1 is the upper lateral the 1-114 wellbore. Please find attached for the review of the Commission forms 10-401 and the information required by 20 ACC 25.005 for this well bore. If you have any questions or require further information, please do not hesitate to contact Joseph Longo at 907-947-4323. Sincerely, Randy Frazier Drilling Manager llue est Energy Cosmopolitan Project H14-L1 10-401 APD Application for Permit to Drill Document Horizontal Producer H14-L1 Table of Contents 1. Well Name.................................................................................................................. 3 Requirementsof 20 AAC 25.005 (f)............................................................................................................. 3 2. Location Summary ....................................................................................................... 3 Requirements of 20 AAC 25.005(c)(2).......................................................................................................... 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 Drilling Hazards Summary:..................................................................................................................... 6 5. Procedure for Conducting Formation Integrity Tests ....................................................... 7 Requirements of 20 AAC 25.005 (c)(5)......................................................................................................... 7 6. Casing and Cementing Program.................................................................................... 7 Requirements of 20 AAC 25.005(c)(6).......................................................................................................... 7 7. Diverter System Information........................................................................................ 7 Requirements of 20 AAC 25.005(c)(7).......................................................................................................... 7 8. Drilling Fluid Program................................................................................................... 8 Requirements of 20AAC25.005(c)(8).......................................................................................................... 8 9. Abnormally Pressured Formation Information............................................................... 8 Requirements of 20 AAC 25.005 (c)(9).................................................... .................................. I.................. 8 10. Seismic Analysis........................................................................................................... 8 Requirements of 20 AAC 25.005 (c)(10)....................................................................................................... 8 11. Seabed Condition Analysis............................................................................................ 8 Requirements of 20 AAC 25.005 (c)(11)....................................................................................................... 8 12. Evidence of Bonding..................................................................................................... 8 Requirements of 20 AAC 25.005 (c)(12)....................................................................................................... 8 13. Proposed Drilling Program............................................................................................ 9 Requirements of 20 AAC 25.005 (c)(13)....................................................................................................... 9 11Page H14-LI 10-401 APD IuNest Energy Cosmopolitan Project H14-L1 10-401 APD 14. Discussion of Mud and Cuttings Disposal and Annular Disposal ....................................... 9 Requirements of 20 AAC 25.005 (c)(14)....................................................................................................... 9 15. Attachments................................................................................................................ 9 Attachment1 Drilling Procedure................................................................................................................. 9 Attachment2 Directional Plan.................................................................................................................... 9 Attachment 3 Casing Design Calculations.................................................................................................... 9 Attachment 4 Formation Integrity And Leak Off Test Procedure.................................................................... 9 Attachment 5 BOP & Choke Manifold Configuration..................................................................................... 9 Attachment 6 Wellhead & Tree Configuration.............................................................................................. 9 Attachment 7 Surface Platt & Diverter Configuration................................................................................... 9 21Page H14-Ll 10-401 APD Ilu est Energy 1. Well Name Cosmopolitan Project H14-L1_10-401 APD 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 20AAC 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: H14-Ll 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; (D) other information required by 20 AAC 25.050(b); Location at Surface 2368' FSL, 1517' FEL, Sec. 02, T4S, R15W SM ASP Zone 4 NAD 2 7 Coordinates Northing: 2,144,816.09' Easting: 168,853.29' RKB Elevation 180.25' AMSL Pad Elevation 145.63' AMSL Location at Top of Productive Interval ("Starichkof" Sand) 4074' FSL, 587' FEL, Sec. 33, T3S, R15W SM ASP Zone 4 NAD 27 Coordinates Northing: 2,152,065.52 Easting: 159,412.16' Measured Depth, RKB: 14,735' Total Vertical Depth, RKB: 7,060' Total Vertical Depth, SS: 6,880' Location at Total Depth 3126' FSL, 192V FEL, Sec. 29, T3S, R15W SM ASP Zone 4 NAD 27 Coordinates Northing: 2,156,583' Easting: 152,917' Measured Depth, RKB: 22,713' ' Total Vertical Depth, RKB: 7,077' Total Vertical Depth, SS: 6,896' 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 Please see Attachment 7: Surface Platt & Diverter Configuration (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. 31Page H14-L1 10-401 APD llueNest Energy Cosmopolitan Project H14-Ll 10-401 APD 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 on item already on file with the commission and identified in the application: (3) a diagram and description of the blowout prevention equipment (BOPf) as required by 20 AAC 25.035, 20 AAC 25.036, or 20AAC 25.037, as applicable; Please see Attachment 5: BOP & Choke Manifold 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 drilling 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 gradient; The expected reservoir pressure in the Starichkof/ Hemlock Sands is -0.472 psi/ft, or 9.07 ppg EMW at 6,951' TVDss ✓ taken per MDT's on Cosmopolitan 1. The maximum known pressure in the upper Kenai sands is 9.66 ppg @ 3,841' TVDss per MDT's taken on Cosmopolitan 1. To be conservative the highest pressure gradient of 9.66 ppg or 0.502 psi/ft will be used to determine MPSP at the production interval of 6,900' TVDss The maximum potential surface pressure (MPSP) based on the above maximum pressure gradient, a methane gradient (0.11), and the planned vertical depth of the Starichkof/ Hemlock formation is: MPSP = (6,900 TVDss) (0.502 - 0.1 psi/ft) = 2,498 psi (B) data on potential gas zones; The Sterling, Beluga and Tyonek sands within the Kenai group have been known to contain gas. The intermediate section will be drilled with a minimum mud weight of 10.5 ppg, the maximum known pressure through these sections is 9.66 ppg @ 3,841' TVDss per MDT's taken on Cosmopolitan 1. —_- (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 the Drilling Hazards Overview below. 41Page H14-L1 10-401 APD llueNest Energy 111 111 .—. 4000 N N 0 S p 5000 111 :1/1' • • • 9. P g • I • M 9. 7 Pg, • 8 9 10 11 —Lithostatic Stress • MD Cosmopolitan Project H14-L1 10-401 APD 5 1 P a g e H14-L1 10-401 APD llueNest Energy Drilling Hazards Summary: 17%" Hole Section 13-%" Casing Cosmopolitan Project H14-L1 10-401 APD Event Risk Level Mitigation Strategy Clay Balling Maintain planned mud parameters, Increase mud weight, use weighted sweeps, reduce fluid viscosity, control ROP. Abnormal Pressure in Low Diverter drills, increased mud weight. Surface Formations Directional Control BHA design, on -sight geologic review, avoid "drilling the line". Lost Circulation Low Reduced pump rates, mud rheology, lost circulation material, use of low density cement slurries, control running speeds. 12-%" Hole Section / 9-%" Casing Event Risk Level Mitigation Strategy Reduced pump rates, reduced trip speeds, real time equivalent Lost Circulation Low circulating density (ECD) monitoring, mud rheology, Pre -planned LCM pills, lost circulation material. Hole swabbing on Reduced trip speeds, mud properties, proper hole filling, real time trips Low equivalent circulating density (ECD) monitoring, weighted sweeps. Sloughing Coals, Increased mud density and fluid composition according to plan, Tight Hole controlled trip speeds, ECD monitoring, optimized hydraulics for hole cleaning. Abnormal Reservoir Low Well control drills, increased mud weight. Pressure Hydrogen Sulfide HzS drills, detection systems, alarms, standard well control Gas Low practices, mud scavengers. 8-%" Hole Section / 4-%" Liner Event Risk Level Mitigation Strategy Fluid density according to plan, reduced pump rates, reduced trip Lost Circulation Low speeds, real time equivalent circulating density (ECD) monitoring, mud rheology, lost circulation material. Hole swabbing on Reduced trip speeds, mud properties, proper hole filling, real Low time equivalent circulating density (ECD) monitoring, weighted trips sweeps. Directional Control Low BHA design, on -sight geologic review. Abnormal Reservoir Low Well control drills, increased mud weight. Pressure Hydrogen Sulfide Gas Low HzS drills, detection systems, alarms, standard well control practices, mud scavengers. 61Page H14-L 1 10-401 APD llueNep�slt Energy Cosmopolitan Project H14-Ll 10-401 APD S. 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 on item already on file with the commission and identified in the application: (5) a description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please see Attachment 4: Formation Integrity and Leak off Test Procedure 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 on 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 Csg/Tbg OD (in) Hole Size Weight (Ib/ft) Grade Conn Length (ft) Top MD/TVD Btm MD/TVD Cement Program (in) (ft) (h) 14,585'/ 22,713'/ 41/2" 8-1/2" 15.2 P-110 Hydril563 8,128' Uncemented 7,032' 7,077' Please see Attachment 3: Casing Design Calculations 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); As this is a sidetrack in the production section of the H14 well diverter equipment will not be required. Please see Attachment 5: BOP and Choke Manifold Configuration 71Page H14-L1 10-401 APD ^uest Energy Cosmopolitan Project H14-Ll 10-401 APD 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 on 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 fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. Drilling will be done with muds having the following properties over the listed intervals: Parameter Production Type OBM Name Versa Pro Density (ppg) 9.5 Oil:Water Ratio 80:20 6/3 RPM 8-10 PV (lbs/100ftz) <28 API Fluid Loss (cc/30min) HTHP Fluid Loss (cc/30min) <5.0 Electric Stability (mlVolts) >600 PH Chlorides 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) An application for a Perrnit 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 on 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 Perrnit 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 on offshore platform, mobile bottom founded structure, jack -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 BlueCrest Alaska Operating LLC is on file with the Commission. 8 1 P a g e H14-L1 10-401 APD ZuNest Energy Cosmopolitan Project H14-Ll 10-401 APD 13. Proposed Drilling Program Requirements of 20 AAC 25.005 (c)(13) A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 20 AAC 25.283(m), to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting on Application for Sundry Approvals (Form 10- 403) with the information required under 20 AAC 25.280 and 20 AAC 25.283; (13) a copy of the proposed drilling program; Please refer also to Attachment 1— Drilling Procedure The H14-L1 well will be hydraulically stimulated. BlueCrest Alaska Operating LLC is aware of the hydraulic fracturing regulations and will submit the appropriate auxiliary information along with the 10-403 prior to executing stimulation operations as required by the AOGCC. 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 on 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 on annular disposal operation in the well.; Solid and liquid wastes generated during the drilling process will be disposed of at Hilcorp Alaska, LLC's Kenai Gas Field (KFG) Grind & Injection (G&I) Facility or AIMM Technologies' (hydrokinetics) facility in Kenai. 15. Attachments Attachment 1 Drilling Procedure Attachment 2 Directional Plan Attachment 3 Casing Design Calculations Attachment 4 Formation Integrity And Leak Off Test Procedure Attachment 5 BOP & Choke Manifold Configuration Attachment 6 Wellhead & Tree Configuration Attachment 7 Surface Platt & Diverter Configuration 91Page H14-L1 10-401 APD BlueCrest Energy H14/ H14-Ll Drilling and Completion Well Plan Joseph Longo JLongo@BIueCrestEnergy.com Lowell Anderson LAnderson@BIueCrestEnergy.com IlueNest EnLdrgy Attachment 1 Cosmopolitan Project H14-1-1 10-401 APD Attachments H14-L 1 10-401 APD Attachments ZuNest Energy Table of Contents Cosmopolitan Project H14 H14-L1 Well Plan WellPlan Summary...........................................................................................................................3 General...................................................................................................................................................................4 Signageand Documentation.................................................................................................................................................4 Close Approach and Offset Well Interception Risks..............................................................................................................4 SurveyProgram & Procedures..............................................................................................................................................4 Casing/Liner/Tubing/DP/HWDP Drifts..................................................................................................................................5 PipeDope..............................................................................................................................................................................5 ProjectOverview..............................................................................................................................6 Structure................................................................................................................................................................. 6 Stratigraphy............................................................................................................................................................6 WellOverview..................................................................................................................................8 WellSchematic.......................................................................................................................................................9 SectionReview.................................................................................................................................................... 10 GeologicHazards................................................................................................................................................. 12 Pre -Rig Operations..........................................................................................................................13 Conductor/ Cellar Installation............................................................................................................................. 14 Operations..........................................................................................................................................................................14 MIRU..............................................................................................................................................15 MIRUOperations................................................................................................................................................. 16 DiverterInstallation............................................................................................................................................. 16 Drilling............................................................................................................................................17 Surface................................................................................................................................................................. 18 GeneralNotes.....................................................................................................................................................................18 DrillingProcedure...............................................................................................................................................................19 CasingProgram...................................................................................................................................................................20 CasingRunning Notes.........................................................................................................................................................20 RunningProcedure..............................................................................................................................................................21 CentralizerPlacement.........................................................................................................................................................21 Cementing...........................................................................................................................................................................23 0 1 P a g e H14 H14-L1 Well Plan nuest Energy Cosmopolitan Project H14 H14-L1 Well Plan CementingNotes................................................................................................................................................................23 CementingProcedure.........................................................................................................................................................23 Intermediate........................................................................................................................................................ 25 Overview.............................................................................................................................................................................25 GeneralNotes.....................................................................................................................................................................25 DrillOut Procedure.............................................................................................................................................................26 DrillingProcedure...............................................................................................................................................................27 CasingProgram...................................................................................................................................................................29 CasingRunning Notes.........................................................................................................................................................29 CasingRunning Order.........................................................................................................................................................30 CentralizerPlacement.........................................................................................................................................................30 Pre-Run...............................................................................................................................................................................30 RunningProcedure..............................................................................................................................................................32 Cementing...........................................................................................................................................................................33 CementingNotes................................................................................................................................................................33 CementingProcedure.........................................................................................................................................................33 Priorto Lifting The BOP Stack.............................................................................................................................................34 While Lifting the BOP Stack and Setting the Emergency Slips............................................................................................34 Production— Lower Lateral................................................................................................................................. 35 Overview.............................................................................................................................................................................35 GeneralNotes.....................................................................................................................................................................35 CementBond Log................................................................................................................................................................36 DrillOut Procedure.............................................................................................................................................................36 DrillingProcedure...............................................................................................................................................................37 Completion: Lower Lateral..............................................................................................................39 LinerRun.............................................................................................................................................................. 40 Overview.............................................................................................................................................................................40 GeneralNotes.....................................................................................................................................................................40 OperationalSpecifics..........................................................................................................................................................42 LinerRunning Order............................................................................................................................................................43 LinerRunning......................................................................................................................................................................44 EquipmentSetting Pumping Sequence...............................................................................................................................45 H14-L1: 8-1/2" Production...............................................................................................................47 Production— Upper Lateral................................................................................................................................. 48 11Page H14 H14-L1 Well Plan IuNest Energy Cosmopolitan Project H14 H14-L1 Well Plan Overview.............................................................................................................................................................................48 GeneralNotes.....................................................................................................................................................................48 Preparationof Main wellbore.............................................................................................................................................49 Preparationof Main wellbore.............................................................................................................................................49 Millingthe Window.............................................................................................................................................................52 Important Whipstock/ Window Drilling Guidelines...........................................................................................................53 DrillOut Procedure.............................................................................................................................................................53 DrillingProcedure...............................................................................................................................................................54 Retrievalof WindowMaster Whipstock..............................................................................................................................55 Completion: Upper Lateral..............................................................................................................S6 LinerRun.............................................................................................................................................................. 57 Overview.............................................................................................................................................................................57 GeneralNotes.....................................................................................................................................................................57 OperationalSpecifics..........................................................................................................................................................59 LinerRunning Order............................................................................................................................................................60 LinerRunning......................................................................................................................................................................61 EquipmentSetting Pumping Sequence...............................................................................................................................63 UpperCompletion...........................................................................................................................64 FracString............................................................................................................................................................ 65 Overview.............................................................................................................................................................................65 FracString Running Sequence.............................................................................................................................................65 2 1 P a g e H14 H14-L1 Well Plan nuest Energy Well Plan Summary Rig BlueCrest Rig #1 Well Type Multilateral Producer Well Design 13-3/8" Surface x 9-5/8" Intermediate x 4-1/2" Liner Lower 4-1/2" 15.2# H563 P110 Liner with swells packer and frac sleeves Lateral Completion Upper 4-1/2" 15.2# H563 P110 Liner with swells packer and frac sleeves Design Lateral Frac 4-1/2" 15.2# H563 P110 frac string String AFE H14-DC PTD Lower Lateral API # PTD Upper Lateral API # Cosmopolitan Project H14 H14-L1 Well Plan 3 1 P a g e H14 H14-L1 Well Plan llueNest Energy General Signage and Documentation 1. Ensure that all well signage is on location and displayed properly. • Well Sign ■ "On Diverter" Signage 2. Ensure the following documents are stored TOGETHER in the company man's office: ■ Application for Permit to Drill (APD 10-401) 4 Display in Dog House as well ■ Onshore ODPCP ■ SPCC Plan ■ Air Permit ■ FAA obstruction determination ■ Lease Operations Plan LO/CI 14-007 Cosmopolitan Project H14 H14-L1 Well Plan 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. - ---------------------------- NOTE: 1. Directional Drillers are to be continuously monitoring upcoming potential crossings. 2. It is the Directional Drillers responsibility to keep the drilling team aware of any and all potential issues concerning anti -collision issues. 4 1 P a g e H14 H14-L1 Well Plan Iu�C.�est Cosmopolitan Project Energy H14 H14-L1 Well Plan Casing/Liner/Tubing/DP/HWDP Drifts Ensure the following drifts are on location and stored properly, in one spot, on the rig. Casing 12.250" Nylon Solid Casing 8.500" Nylon Solid Liner 3.701" Nylon Solid Tubing 3.833" Nylon Solid Drill Pipe 3.875" Steel Hollow Drill Pipe 3.125" Steel Hollow HWDP 3.000" Steel Hollow HWDP 2.500" Steel Hollow Pipe Dope Ensure that the following pipe dopes are on location upon rig up. 1. Drill Pipe/ HWDP: ■ ZN-50 4 *All XT-## Drill Pipe and HWDP Connections 2. API Casing Threads: ■ Jet Lube Run and Seal Arctic 4 Surface Casing: 72# L80 Buttress Casing Only 4 Shipped from the mill with Kendex Storage Compound on the pin end, wipe this off thoroughly prior to applying Just Lube Run and Seal Arctic 3. Hydril Threads: ■ Jet Lube Seal Guard ECF 4 All Hydril Casing, Liner and Tubing Threads Hydril connections are shipped with Jet Lube Seal Guard ECF already applied and are "Rig Ready". Wipe the box ends down with a clean cloth prior to running. 5 1 P a g e H14 H14-L1 Well Plan llueNest Energy Project Overview Structure Cosmopolitan Project H14 H14-L1 Well Plan The Hansen Field (hereinafter referred to as Cosmopolitan or Cosmopolitan project) structure is a NE/SW doubly plunging asymmetric anticline bounded along its west flank by a high angle reverse fault that strikes parallel to the structural axis. Associated tear faults with normal throw cut the northern and southern portions of the feature and one smaller fault was found in the Cosmopolitan State #1. This structure, which is four and one-half miles by 2 miles in size, has approximately 600 feet of vertical closure over an area of over 6,000 acres at the Starichkof sand (Lower Tyonek sandstone just above the Hemlock Conglomerate). Structural control includes six wellbores, (three of these are vertical and penetrate the entire geological section on the structure and three are extended reach wells drilled from the Hansen shore -side drilling pad) 3D seismic acquired by Pioneer Resources in 2005, dip meter data in two of the vertical wells, and migrated 2D high resolution seismic data acquired by GeoTek Alaska, Inc. in 2013. 3D seismic data was used to tie all of the wells to generate several levels of structure maps (see the following discussion on seismic data and interpretation). Although there is a .3 to .5 second seafloor reverberation on the 3D data, the shallow high resolution Geo-Hazard 2D seismic shows that the structure is typical of parallel folding. Stratigraphy Approximately 8,600 feet of Tertiary age Kenai Group non -marine sedimentary rocks are present at Cosmopolitan. The Kenai Group is represented here by approximately 1,000 feet of the Beluga Formation (USGS unpublished data) characterized by thin bedded sandstones, coals, siltstone and silty shale intervals that were deposited in a braided stream environment. Based on estimates from seismic data and log correlation approximately 1,050 feet of Beluga was penetrated in the Starichkof State Unit #1 well, about 500 feet was present in the Starichkof State #1 and it appears to be missing in the Cosmopolitan State #1 well. The difference in thickness in the Beluga across the Cosmopolitan structure is related to erosion and does not represent depositional thinning. The overlying Sterling Formation is not present and has also been removed by erosion. Unconformably underlying the Beluga sequence is 5,945 feet of Miocene age Tyonek Formation, a basin wide series of fluvial conglomerate, conglomeratic sandstone, sandstone, coal, siltstone and shale which represent deposition in meandering streams, associated fluvial sediments and lacustrine environments. It is a major producer of both biogenic natural gas and thermogenic oil throughout the basin and is charged with gas and oil at Cosmopolitan. BlueCrest Energy, Inc. has informally divided the Tyonek into an upper section that contains gas productive sandstones and a lower interval that is predominately oil prone. The two zones are separated by a laterally correlative shale section that is easily recognized in all of the existing wells. The lowest section of the Lower Tyonek, from 6,742 to 7,104 feet MD has been referred to as the "Starichkof' sand by Conoco/Phillips, Pioneer Resources and by BlueCrest Energy, Inc. and is the oil discovery zone found in 1967 by Pennzoil in their Starichkof State #1 well. Immediately underlying the Starichkof sand (Lower Tyonek) is the Oligocene Hemlock Conglomerate. It was drill stem tested in the Starichkof State #1 well and recovered brackish water from two separate intervals beneath the 6 1 P a g e H14 H14-L1 Well Plan llueNest Energy Cosmopolitan Project H14 H14-L1 Well Plan oil/water contact at approximately -7030 ft. Conoco/Phillips tested water free oil in higher structural positions in both the Hansen 1 and Hansen 1A wells. The Hemlock generally consists of medium to coarse grained, thick bedded sandstone with substantial conglomeratic beds and lenses. In the Starichkof State #1 well it is 485 feet thick, and in the Cosmopolitan State #1 it is 500 feet thick. Underlying the Hemlock is the Paleocene to Eocene age West Foreland Formation, a 1,155 feet thick sequence of volcanic tuffs and volcanoclastic sandstone and siltstone devoid of oil or gas shows and without reservoir quality rocks. The West Foreland unconformably overlies the Upper Cretaceous marine Matanuska Formation that is at least 3,339 feet of shale containing an abundance of Inoceramus shell fragments. 7 1 P a g e H14 H14-L1 Well Plan ]ue est Energy Well Overview Cosmopolitan Project H14 H1441 Well Plan Well Schematic Section Review Geologic Hazards 8 1 P a g e H14 H14-L1 Well Plan luNest Energy Well Schematic Cosmopolitan Project H14 H14-L1 Well Plan 60. ,fir. Proposed liuNst T.. oD Energy se9rnlargr4W H14/H14-L1-9.5/8" Producer C13ni�ral9�ijscemtt_& Dual -Lateral Completion with 7ipph-G.°° 7' x 9-5/8" S-3 HOOK B49a 4.5- 5-3HYbifc Pd. Fa 93ra- 32J-63.6P c4Op Complete Sequence: I3-ST7Er BTCL- A. S14,44T Spna"D"A ".- 3mroxmum 1. Run Main Bore Liner 2. Run Whipstock 4 � +50 3. Retrieve Whipstock sa �4,41T „M 4B-Whop 4. Run Upper Lateral Liner ft.@ R A1050 5. Run Main Bore Re -Entry Diverter 6. Run 4" Seals; Frac; Pull seals and diverter together 7. Run Lateral Re -Entry Diverter 8. Run 4" Seals; Frac; Pull seals and diverter together ft"7 9. Run 4.5" production string LIP59ra- UPL Top Pater ne l Douro 10' 7315-Tk04rA r-0- 1140r Er. P.0 Vrur sma UDAer Lateral RS 3J?r MI, 5390' OD xt9wbP 541w c Apo �� 41/Z'ta.M HY91i 6p 44T Benr./ont IWabw HtaLoor N H/0ra0e IV Leer tYnpr Cro4eota4 S*S /a4W 47? TI d 40O 011w Tntli St4.51r ON r ■ kook N4,N7 ,.r, 4-t/r t530 Hydi SST, P-110 Li,- 4A9'ID S4Y Ban: Heibabn4 1LZPI 83 $"*Z7,71YNM7,OrrTVD Bt9M 74W a 9.Wr a0' Lapp Fm SYPtK *~Y 4W ZZPL9wTop Pa9a Y t1o1FD_ 9-SA' 474 HS03 P.110 C.*4 EaulDmmt Sweifleatloro tr T1T5-re.d F�bn :tt91r frWpven ^r X 9.51r HDOX Hanger us NiW* Main Bore Ht®atur IaerM PR r./4Mr� 6M 5"7-W.9.W 4-Vr 116.20 M7N. N3 W"1/LtWewrOMrOpr W Fktleot N Hj*r k /wBPaOYn 1YrPfw ir�LnMnQ 4.9T Lb -Haw ta—y400 4t7l t7aea0b sh. rar3 iMb 2tFr M4,9Tr `. ww TO' L4rpN � 4.Vr I5M HY60 SST, P-/1E LYrr 9-S/0'S1,59 M559R11 hfb(S w- inc SlrstC }nary 400' W Set ",WW7,01B'TVD w e.s-- tsoir am Ba nL5 9 1 P a g e H14 H14-L1 Well Plan ZuNpslt Energy Section Review Last Updated: )A 01/09/2017 H14 C "As Planned" -193'MD/TVD o 20" 0.500" Wall A252 ERW Bit: 17.5" G15BODCPS V C) RSS: PDX6 r MWD: Telescope LWD: arcVISION (GR/RES) VIVID/ 3.530' Bit: 12.25" Z716 RSS: Xceed900 MWD: Telescope LWD: arcVISION (GR/RES) C1 0 E-Line: CBL Bit; 8.5" Z716 RSS: Xceed675 MWD: TeleScope LWD: GeoSphere CL 0 EcoScope 00 - - 17 -- — — Cosmopolitan Project H14H14-1-1 Well Plan llueNest Energy PIP 12.0 Lead NL 727 bbis WBM 50P6 XS 9.0 - 9.8 ppg Top of Tail — 3,942' MD Spud Mud ... 15.8 Class "G" Tail 197 bbls W16 XS Inc. 68.52' L; 13-3/8" 72# L80 BTC Azi. 306.54' 9-5/8" 47# P110 H563 OBM TOC 0 13,250'MD 10.5 ppg ACTIMUL RD 15.8 ppg Class "G" 153 bbIs 7' x 9-5/8" Baker 50% XS Hanger/Packer Inc. 90.00' .X, 9-5/8" 53.5# P110 H563 (1,500') Azi. 305.50' 4-1/z" x 8-V Swell Packer OBM HES Frac Sleeve 10.0 ppg Un-cemented Liner ACTIMUL RD HES DSC Inc. 90.00' 11 1 ID 4-1/2"15.2# P110 H563 Azi. 302.33' 1 pp (ppl!) I 10 1 P a g e 1-1141-114-1-1 Well Plan nueest Energy Last Updated: JA 01/09/2017 r `193' MD/ TVD o 20" 0.500" Wall A w Bit: 17.5" G15B0DCPS c RSS: PDX6 x c MWD: Telescope c ;�;; LWD: arcVIS10N (GR/RE5) 0 �r: 4 941' MD 3 530' TVD N u, 13-3/8" 72# L80 BT N Bit: 12.25" Z716 V _ x v RSS: Xceed900 o m 9 sIB" 47# P110 H563 MWD: Telescope T LWD: arcVISION (GR/RES) a =: Lx 0 n, n 333 E-Line: CBL ? B/ Windmv 14 58S' MD 7 032' TVD ri f3 ' {- 7" x 9-5/8" Baker Hanger/Packer 9-5/8" 53.5# P110 H563 (1,501 4-'1A" x 8-''A" Swell Packer Bit: 8.5" Z716 v RSS: Xceed675 0 x MWD: Telescope HES Frac Sleeve LWD: GeoSphere a 0 EcoScope 00 r__-- HES DSC 22,713' MD/ 7,077' TVD 4-1/2"15.2# P110 H563 Cosmopolitan Project H14 H14-L1 Well Plan H14-L1 Iue est "As Planned" Energy PP 12.0 Lead 727 bbls WBM 50°.6 XS 9.0 - 9.8 ppg Top of Tail — 3,942' MD Spud Mud 15.8 Class "G" Tail 197 bbls 500,E XS Inc. 68.52' Azi. 306,54` OBM TOC ® 13,250' MD 10.5 ppg ACTIMUL RD 15.8 ppg Class "G" 153 bbis 5006 XS Inc. 90.00` Azi. 305.5W OBM 10.0 ppg Un-cemented Liner ACTIMUL RD Inc. 90.00` Azi. 302.33` 111Page H14 H14-L1 Well Plan nuest Energy Geologic Hazards 17-%" Hole Section 13-%" Casing Cosmopolitan Project H14 H14-L1 Well Plan Event Risk Level Mitigation Strategy Clay Balling Maintain planned mud parameters, Increase mud weight, use weighted sweeps, reduce fluid viscosity, control ROP. Abnormal Pressure in Low Diverter drills, increased mud weight. Surface Formations Directional Control BHA design, on -sight geologic review, avoid "drilling the line". Lost Circulation Low Reduced pump rates, mud rheology, lost circulation material, use of low density cement slurries, control running speeds. 12%" Hole Section / 9-%" Casing Event Risk Level Mitigation Strategy Reduced pump rates, reduced trip speeds, real time equivalent Lost Circulation Low circulating density (ECD) monitoring, mud rheology, Pre -planned LCM pills, lost circulation material. Hole swabbing on Reduced trip speeds, mud properties, proper hole filling, real trips Low time equivalent circulating density (ECD) monitoring, weighted sweeps. Sloughing Coals, Increased mud density and fluid composition according to plan, Tight Hole controlled trip speeds, ECD monitoring, optimized hydraulics for hole cleaning. Abnormal Reservoir Low Well control drills, increased mud weight. Pressure Hydrogen Sulfide Gas Low H2S drills, detection systems, alarms, standard well control practices, mud scavengers. 8-Y2" Hole Section / 4-%" Liner Event Risk Level Mitigation Strategy Fluid density according to plan, reduced pump rates, reduced trip Lost Circulation Low speeds, real time equivalent circulating density (ECD) monitoring, mud rheology, lost circulation material. Hole swabbing on Reduced trip speeds, mud properties, proper hole filling, real trips Low time equivalent circulating density (ECD) monitoring, weighted sweeps. Directional Control Low BHA design, on -sight geologic review. Abnormal Reservoir Pressure Low Well control drills, increased mud weight. Hydrogen Sulfide Gas Low H2S drills, detection systems, alarms, standard well control practices, mud scavengers. 121 Page H14 H14-L1 Well Plan nueSt Energy Pre -Rig Operations Cosmopolitan Project H14 H14-L1 Well Plan Conductor & Cellar Installation 131Page H14 H14-L1 Well Plan lueNepst Energy Conductor/ Cellar Installation Operations Cosmopolitan Project H14 H14-L1 Well Plan 1. 20" Conductor was preset via Kraxberger Drilling via their dual rotary drilling rig to a depth of 152' BGL ■ Conductor Pipe: 20", 0.500" Wall, A252 ERW Welded • The conductor is NOT cemented to surface • Cut off at 1' above ground level 2. 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 tree. 3. A 10' x 10' x 8' well cellar was installed and the 20" conductor cut off 60" below ground level. ■ The additional stick up is to allow GE Oil & Gas to make a clean cut on the conductor prior to installing the 20" landing ring --> Final top of conductor to be 71-1/4" BGL. ■ Verify that the access ladder is located to the South. ■ Ensure the conductor plate is installed and welded around the 20" conductor. 4. 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 • Provide access to annulus for top job through small diameter tubing ■ If these valves are not currently installed contact GE Oil & Gas Representative to have them installed 4 Kevin Krause — Lead Service Manager 4 Kevin. Kra use@ge.com 4 Cell:907-398-9995 141 Page H14 H14-Li Well Plan llueNest Cosmopolitan Project Energy H14 H14-L1 Well Plan MIRU MIRU Operations Diverter Installation 151Page H14 H14-L1 Well Plan llueNpst Energy Cosmopolitan Project H14 H14-L1 Well Plan MIRU Operations 1. MIRU BlueCrest #1 over preinstalled 20" conductor casing set at -152' BGL. 2. Move in and rig up. Record move distance and rig floor distance to pad and sea level in Daily Report and on IADC reports. • 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. Diverter Installation 1. Secure 13-3/8" landing ring on 20" conductor with lock down screws. ■ 20" Landing Ring ID: 17.62" 2. Nipple up VetcoGray starter head and test the lower seals. ■ DO NOT Exceed 500 psi. 3. Install 21-1/4"x 2000 psi diverter and riser equipment with 18" outlet line. ■ Ensure diverter is run in accordance with the specified diverter diagram shown below. 4. Place slop tank under the end of the diverter line. 5. Function test the diverter to verify the valve on the diverter line opens BEFORE the annular fully closes. ■ Give AOGCC 48-hour notice to witness test. ■ The diverter control system must open the side outlet valve and close the diverter element within 45 seconds for this size of diverter. ■ Fill diverter & riser with water to check for leaks. -> Record on IADC drilling report. --) Hold diverter and rig abandonment drill prior to drilling surface hole. 6. Make sure the 3" outlets on the 20" conductor have valves and connections for taking mud returns. Diverter lines to be as straight as possible. ■ Ensure "Warning Zone - ON DIVERTER" and rig well signs are spotted correctly on location. 161 Page H14 H14-L1 Well Plan INst Energy Drilling Cosmopolitan Project H14 H14-L1 Well Plan Surface Intermediate Production 171 Page H14 H14-L1 Well Plan lust Energy Surface Overview Cosmopolitan Project H14 H14-L1 Well Plan 17.5 13.375 9.2-10.0 Spud Mud RSS Tri-Cone 4,941' 3,530' 67° Fluids Gel Spud Mud 9.2-10.0 150' 4,941' 14-17 NC <2,000 8.5 — 9.5 *Allow fluid to weight up naturally — Do not exceed 10.0 ppg BHA Min Max RSS 8.25" PD X6 PowerPulse GR/Res 600 1200 Bit Smith Tri-Cone (Insert) GF15BODCPS 3 x 18, 1 x 20 1.052 General Notes ■ Prior to spud, a safety meeting will be held with the rig crews to discuss open hole drilling procedures. Suggested topics include: o Conductor broaching operations and contingencies o Well control procedures and rig evacuation procedures o Flow rates and hole cleaning ■ The area around the conductor should be continuously monitored during drilling, circulating, and cementing operations. o If broaching occurs, stop drilling immediately. Contact the AOGCC field inspector and the Drilling Superintendent to inform them of the broach. ■ Efforts should be made to minimize high doglegs in surface hole. o Inform the Drilling Engineer of any doglegs over 5 degrees per hundred. ■ Ported float valves are required in all hole sections. • Conduct 13-3/8" Casing dummy run prior to drilling out. 181 Page H14 H14-L1 Well Plan nuest Cosmopolitan Project Energy H14 H14-L1 Well Plan Drilling Procedure 1. Ensure 13-3/8" Casing dummy run has been conducted prior to drilling out. 2. Pick up and drift all DP, HWDP, and DC's for surface section to confirm free of debris. 3. PU BHA ■ Bit: 17 %:" G15BODCPS - Insert 4 TFA: 1.052 (3 x 18, 1 x 20) 4 PD 1100 X6 4. Directionally drill surface hole: ■ Drilling Parameters: Flow Rate: 850+ GPM -� Rotary: 120+ RPM ■ 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. Keep in mind that lower flow rates below the tool threshold may pose difficulty steering. A backup motor is on location in the event that steering becomes an issue. ■ 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 Engineer to discuss options. 5. Hole conditions will always determine final mud properties. 6. Surface casing point: • Land in good shale found between 3,115' — 3,350' TVDss. ■ Circulate bottom hole samples to verify shale, confirm with wellsite geologist. ■ DO NOT set in coal, if coal is encountered drill another 20' MD. ■ Drill the hole to fit casing, if possible, to reduce pup joints in the string. Leave at least 15' rathole. 7. Circulate the hole clean per K&M and POOH on elevators. 8. If BROOH is required, contact Drilling Engineer prior to commencing: ■ Circulate until shakers are clean per K&M. Backream one (1) stand per bottoms up very slowly. 4 900+ GPM 4 120+ RPM ■ BROOH at full drilling parameters, 3-5 min per stand. NOTE: ■ 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. ■ 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. 9. 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. 10. Once the HWDP is reached, circulate until hole is clean per K&M 11. Pull and lay down BHA. 191Page H14 H14-L1 Well Plan IuNrst Energy 12. Perform a dummy hanger run before running casing, if not already conducted. Casing Program Cosmopolitan Project H14 H14-L1 Well Plan 13.375 12.347 72 L-80 BTC 12.191 2,670 5,380 1,661,000 Connection Make Up Operational Limit in. in. in. ft-Ibs. ft-Ibs. ft-Ibs. ft-Ibs. ft-Ibs. 14.375 12.335 10.825 Average 10 to the Diamond Method:Running Casing Running Notes ■ Perform dummy run prior to running casing, if not already conducted. ■ Surface casing will be set on mandrel hanger. ■ Any packing off while running casing, should be treated as a very serious problem if major returns are lost. o 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. ■ Have Vetco representative verify the correct casing hanger is on location prior to running surface casing. ■ 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. ■ Utilize Volant Casing Running tool for make-up and fill up. 201 Page H14 H14-L1 Well Plan Ily est Energy Cosmopolitan Project H14 H14-L1 Well Plan Running Procedure 1. Inspect and drift all surface casing to 12.25". 2. While RIH with the Casing: ■ obtain SO Weights per K&M every joint ■ DO NOT take PU weights ■ IF IT IS NECESSARY TO PICK UP THE STRING ENSURE THAT THE PUMPS ARE ON TO REDUCE SWAB LOADS 3. Run the surface casing as follows: Float shoe 2 joints 13-3/8" 72# L-80 BTC casing Float Collar 13-3/8" 72# L-80 BTC casing TAM BTC port collar +/- 500 ft 13-3/8" 72# L-80 BTC casing to hanger VetcoGray 13-3/8" mandrel hanger 13-3/8" landing joint BakerLok BakerLok BakerLok Slick landing joint if not running the TAM port collar NOTE: **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. ■ Ensure the drill pipe running tool is 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 the decision to run is made at the last minute, ensure the additional footage of the port collar plus handling pup will allow for sufficient rat hole below the surface casing shoe. Centralizer Placement +/-18 13-3/8" x 17-1/2" VariForm Weatherford 211 Page H14 H14-L1 Well Plan llueNest Energy 13-3/8" x 17-1/2" VariForm Centralizer 1. One (1) — 5' Above Float Shoe 2. One (1) — 8' Above Float Shoe 3. No Centralization on 2"d Joint 4. One (1) — 10' Above the Float Collar 5. From 3`d Joint Through Tail Slurry (500') o One (1) Each per Joint o Center of Joint 6. Two (2) — Center of Joint Inside Conductor ALL CENTRALIZERS TO BE RUN ON STOP COLLARS LOR Cosmopolitan Project H14 H14-L1 Well Plan 221Page H14 H14-L1 Well Plan llueNest Cosmopolitan Project Energy H14 H14-L1 Well Plan Cementing Volum Properties ` , Excess Mud Push II 80 bbl. Density: 10.0 ppg N/A 17-1/2" 13-3/8" Kenai Surface Lead 727 bbl. Density: 12.0 ppg 50% Yield: 2.44 ft3/sk Kenai Suface Tail 197 bbl. Density: 15.8ppg 50% Top of Tail @ 3,942 MD Yield: 1.22 ft3/sk Cementing Notes ■ 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. h Use split landing joint if TAM port collar is utilized. It will need to be opened by running tool on drill pipe and this will allow using standard rotary slips. ■ Ensure that enough cement retarder is built to keep cement from setting up prior to disposal. ■ OUTLINE CEMENTING TRUCKS NEEDED, TYPE OF RETARDER, ETC... Cementing Procedure 1. After reaching bottom, rig up and circulate with casing on bottom at 5 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/100ft' prior to cementing the casing but after the casing is on bottom. Have adequate supply of cold 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 excess. NOTE: ■ If necessary, verify that the TAM Tech has located the proper crossovers to combo running tool. ■ 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 cello -flake 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 ; ,, maximum. 231 Page H14 H14-L1 Well Plan llueNest Energy Cosmopolitan Project H14 H14-L1 Well Plan 8. Drop circulation rate 3 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 % the shoe joint volume). ■ 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 RIH with TAM Combo tool 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. ■ Establish circulation and continue until pumping secondary cement job through TAM collar. ■ Pump secondary cement job until cement is seen at surface. ■ Close the TAM Port Collar. ■ PU with Combo Tool and circulate out cement in drill pipe. ■ POOH with Combo Tool. 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 and Daily Report. Complete the Rig Elevation Record and place it in the electronic well folder. 12. Nipple up the 13-S/8" 10M BOP stack and test per the AOGCC Permit to Drill (attached) ■ Notify AOGCC 24 hours prior to performing BOP test. ■ Do not test BOPE against casing. ■ Test rams and choke manifold components to 3500 psi high / 250 psi low ■ Test annular preventer to 2500 psi high / 250 psi low --) PERMIT TO DRILL BOP testing frequency: Every 14 days unless noted otherwise by AOGCC 241Page H14 H14-L1 Well Plan llueNest Energy Intermediate Overview Cosmopolitan Project H14 H1.4-L1 Well Plan 12.25 9.625 RSS PDC ACTIMUL RD 10.50 15,022' 7,080' 850 Fluids ACTIMUL RD BHA 0 ppg 10.50 From 4,941' To 15,022' 0 13-15 RSS 8.25" PD Xceed 900 TeleScope arcVISION Smith PDC Z716 ml/30 min <5 Min 600 10 x 14 80:20 mlVolts >600 Max 1200 1.503 General Notes ■ Shallow test MWD tools. ■ 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). ■ If cavings are noted at surface pictures shall be taken to clearly identify cavings structure and geometry. ■ Ensure that all team members are communicating with each other on any observed drilling trends and that everyone understands the potential risks. ■ 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 or coal sections for any extended period of time. ■ Keep shut down times to a minimum during connections. ■ Swab / Surge: Make "easy on, easy off" slips a standard practice ■ 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. ■ Contact the drilling engineer prior to commencing back reaming at any point while drilling the well. 251Page H14 H14-L1 Well Plan llueNest Cosmopolitan Project Energy H14 H14-L1 Well Plan Drill Out Procedure 13. Install wear bushing 14. Pick up and drift all DP, HWDP, and DC's for surface section to confirm free of debris. 15. PU drill out BHA ■ Bit: 12-1/4" Mill Tooth 4 TFA: 0.994 (4 x 18) --> Dumb Iron Assembly 16. TIH to top of float equipment and pressure test surface casing to 2,500 psi for 30 min. Chart and record same. ■ Plot casing pressure test on LOT form and submit to drilling engineer ■ Verify the test indicates a linear line and there is no air entrained in the mud. Repeat casing pressure test if needed. NOTE: ■ All BHA trips through the TAM Port Collar (if run) should be done slowly with slow rotation to avoid accidentally opening the collar. If the string takes weight, stop immediately, pick up, resume slow rotation and try slacking off through the port collar area. 17. Drill out float collar and shoe. ■ Take note of any green cement or lack of necessary WOB to drill out shoe track. ■ If no cement or green cement is encountered DO NOT drill out the shoe. 4 Call drilling superintendent prior to continuing operations. 18. Clean out rat hole and POOH on elevators & LD drill out BHA. 19. PU Drilling BHA ■ 12-1/4" Z716 PDC 4 TFA: 1.503 (10 x 14) 4 PD Xceed 900 RSS BHA 20. Shallow test MWD/LWD tools. 21. Displace new hole to 10.50 ppg VersaPro OBM. 22. Drill 20' of new formation, below the rat hole, with VersaPro OBM. 23. POOH to surface casing shoe and perform LOT per AOGCC requirements following the attached LOT procedure: ■ Required FIT: 13.00 ppg EMW 4 Recorded LOT/FIT pressures shall follow the format below: ('Surface I. EMW = + MW 0.052*(TVD) II. XX.XX ppg EMW FIT/LOT w/ XXX psi and XX.XX ppg MW @ X,XXX' TVD Offset Hansen 1: 13.00 ppg EMW FIT w/ 540 psi and 9.9 ppg MW @ 3,349' TVD ■ All data shall be recorded on the provided "BlueCrest Casing/FIT/LOT Form". ■ Pressure test is to be taken to leak off but not to exceed 1,000 psi surface pressure. • If LOT is below 13.00 ppg EMW, contact drilling superintended prior to drilling ahead. 261Page H14 H14-L1 Well Plan nuest Energy Cosmopolitan Project H14 H14-L1 Well Plan Drilling Procedure 1. Directionally drill intermediate hole: ■ Drilling Parameters: -> Flow Rate: 900+ GPM 4 Rotary: 120+ RPM ■ PU and Slack -off Weights will be taken EVERY stand Per K&M ■ Follow Recommended Connection Practices ■ Avoid anti -collision boundaries ■ Take MWD surveys as frequently as needed maintaining at least 1 survey per stand. 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. NOTE: COAL DRILLING PRACTICES ■ Drill coal seams slowly to avoid allowing large chunks from entering the wellbore Stop, Drop & Roll ■ Monitor ROP, torque and pump pressure for signs of drilling into a new • Stop— When coming seam. out of the hole if o Coals tend to drill fast with low WOB and low torque overpull is encountered o Torque spikes may indicate sticking pipe and the bit DO NOT KICK PUMPS ON! o Drill 1'-3', pick up off bottom above coal • Drop — Run back into o Circulate/rotate above the coal before continuing to drill o Continue drilling at 2'-5' intervals, pulling above to circulate the hole 3-5 stands or area where the pipe ■ Use ECD management techniques to minimize cycling the formation was last free. o Use high angle tripping practices (STOP, DROP & ROLL) to avoid • Roll — Initiate rotation packing off and bring the pump up o Slowly bring pumps on after connections or breaking circulation. slowly to full circulating Rotate first to break gel strength. Stage into the hold to shear gels. rate. Clean the hole at Control trip speeds to manage surge/swab loads. full rotary and o Maintain "thin" low end rheology and gels circulating rate prior to o DO NOT PUMP SWEEPS commencing tripping o DO NOT CONDUCT WIPER TRIPS operations. • Maintain a broad particle size distribution (PSD) of bridging agents in the • CHECK — Pull back mud through area of overpull o Increasing mud weight will prevent coals from destabilizing, but & monitor PU weight. only if the mud is able to seal the fractures. 271Page Fi14 H14-L1 Well Plan llueNest Energy Cosmopolitan Project H14 H14-L1 Well Plan 2. Intermediate casing point: ■ Land within the Starichkof Sand. ■ TD will be +/- 400' past the base of the shale marker (Top of Starichkof) This well may be sidetracked in the future, enough room needs to be made for the rathole (-15'), liner overlap (-150') and whipstock offset (-150') while remaining below the shale above the Starichkof. 3. Circulate until shakers are clean per K&M. Backream one (1) stand per bottoms up very slowly while circulating clean at full drilling parameters. -� 900+ GPM 120+ RPM 4. Attempt to POOH on elevators. 5. If tight hole is encountered, TIH 3 stands and circulate shakers clean. Attempt to trip back through depth of tight hole: ■ If tight hole is still encountered, ream the section clean, and confirm it is free of obstruction prior to continuing to POOH. ■ If area is free continue to POOH on elevators making sure monitor drag trends for signs of excessive over pull. 6. If the hole is swabbing or reoccurring issues are encountered while POOH, BROOH to the surface casing shoe. ■ Contact Drilling Engineer prior to commencing back reaming operations at any point in the well ■ BROOH at full drilling parameters 900+ G P M 120+ RPM NOTE: ■ 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. • 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 until the shoe has been reached and sufficiently cleaned. ■ If shakers/mud return system becomes overloaded and flow rate needs to be reduced, DO NOT continue to BROOH until the parameters are brought back to full backreaming rate. 7. Circulate the hole clean per K&M 8. POOH on elevators. 9. Pull and lay down BHA. 10. Perform a dummy hanger run before running casing, if not already completed. 281 Page H14 H14-L1 Well Plan nuest Energy Casing Program 9.625 9.625 Pipe poll lbs. 47 53.5 8.681 47 8.535 53.5 Cosmopolitan Project H14 H14-L1 Well Plan P-110 H563 8.525 5,300 9,440 1,493,000 P-110 H563 8.500 7,950 10,900 1,710,000 Connection Make Up lime in. in. ft-Ibs. ft-Ibs. 10.625 8.681 9.25 13,200 15,800 10.625 8.535 9.25 15,500 18,600 Operational Limit ft-Ibs. ft-Ibs. ft-Ibs. 2 3, 000 I 69,000 103,000 27,000 69,000 103,000 Casing Running Notes Perform dummy run prior to running casing o A slick landing joint will be utilized. Intermediate casing will be landed on emergency casing slips. o Verify the modified wear ring is installed prior to running casing. Have Vetco representative verify the correct emergency slips are on location prior to running in the hole. Utilize Volant CRTi Tool for running, fill up and circulation. Have a spare shoe track on location prior to running casing. Ensure the casing run is modeled with actual wellbore conditions (i.e. actual survey, active mud weights, depths, etc...) Surge modeling shall be agreed upon by K&M and Drilling Engineer to determine safe running speeds to prevent/ minimize potential losses. Have an assortment of 9-%" pup joints available for space out when setting casing on depth 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. 291Page H14 H14-L1 Well Plan llueNpst Energy Casing Running Order Float shoe 2 joints 9-5/8" 53.5# P-110 Hydril 563 Casing Float Collar -35 joints 9-5/8" 53.5# P-110 Hydril 563 Casing 9-5/8" 47# P-110 Hydril 563 Casing to surface 9-5/8" landing joint Centralizer Placement +/- 38 . 11 BakerLok BakerLok BakerLok Note Cosmopolitan Project H14 H14-L1 Well Plan Bottom 1,500' will be 53.5# P-110 Hydril 563 Take note that this is 47# P-110 Hydril 563 Slick landing joint 9-5/8" x 12-1/4" Hydro Form Volant Pre -Run 1. Confirm Hydroform centralizers are on location and crimped to pipe prior to loading the in the shed. 2. Inspect and drift all surface casing to 8.500". This is to be done AFTER centralizers are crimped to casing. -> The crimping tool can affect the inner diameter. 3. Pull wear bushing. Install test plug. Then install 9-5/8" casing rams and test same. Pull test plug. 4. Install modified wear ring. To protect hangers if casing needs to be rotated while running. Wear bushing is short enough to not extend past studs when the wellhead is broken when emergency slips are set. ID should be the same as the actual drilling wear bushing. 5. Perform dummy run with 9-5/8" slick landing joint, confirm and record length to break. Casing will be set on emergency slips. 6. Ensure a spare float shoe and collar made up with centralizers is on location as backup. 7. Ensure the 9-5/8" floor valve or "kill sub", comprised of a TIW valve crossed over to 9-5/8" Hydril 563 is on the rig floor. Function valve and leave in the open position. 301 Page H14 H14-L1 Well Plan llueNest Energy 9-5/8" x 12-1/4" Crimped HydroForm Centralizer 1. One (1) — 5' Above Float Shoe o Floating between stop collar and float shoe 2. No Centralization on 2nd Joint 3. One (1) —10' Above the Float Collar o Floating Between Stop Collar and Float Collar 4. From 3rd Joint Through Top of Cement o One (1) Each per Joint o Crimped +/- 3' From Pin End ALL CENTRALIZERS CRIMPED +/- 3' FROM PIN END UNLESS STATED OTHERWISE M O 0 Cosmopolitan Project H14 H14-L1 Well Plan 3' L t 5' 311Page H14 H14-L1 Well Plan IuNpst Energy Cosmopolitan Project H14 H14-L1 Well Plan Running Procedure 1. Bring Volant CRTi Tool to the rig floor and rig up same. 2. Pick up the shoe track and make up by hand using chain tongs until enough weight is in the slips to prevent cross threading. ■ The shoe track is to be BakerLok'd ■ Inspect the float valves as the shoe track is picked up 3. Run the shoe track into the well and confirm the floats are holding negative pressure. 4. Run the first 10 joints using chain tongs. 5. Continue running in the hole utilizing the Volant CRTi Tool. While TIH with Casing: ■ Fill every joint. ■ Obtain SO Weights Every Joint per K&M ■ DO NOT take PU weights. DO NOT POOH without the pumps on. ■ This data shall be plotted against theoretical curves in real-time to determine SO friction factors (SOFF's) and allow pro -active decisions to be made. ■ 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, doglegs, etc.) ■ If the casing will not pass an obstruction, rotation should be discussed in an attempt to work the string down o DO NOT attempt to rotate the casing until the expected torque values are modeled to determine is casing rotation is possible as the string will be full. ■ Contact drilling engineer immediately if problems are encountered while TIH. 6. Prepare to land the casing on bottom ■ Ensure adequate rathole is allowed below shoe and free pickup weight of casing is observed. ■ 10' rathole 7. Makeup slick Landing Joint 8. Open 350 ton air slips and slide them out of the way. 9. 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. ■ Take care to ensure that there are no couplings across the casing rams once the casing is on depth. 10. Break circulation at % bpm assessing losses if any, this will allow any "clabbered up" or cold mud to be circulated out prior to stepping up the rate. 11. After at % bpm without any issues/ losses, then step up the rate gradually to 8 bpm. ■ If losses are encountered contact the drilling engineer immediately. 12. CBU 3.5 (estimate Final YP < 20) ■ If needed, circulate and thin mud to properties slightly as outlined in CemCADE and Mud plan summary prior to pumping cement. 321 Page H14 H14-L1 Well Plan nuest Energy NOTE: Cosmopolitan Project H14 H14-L1 Well Plan 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). Cementing 12-1/4" 9-5/8" CemPRIME Scrub 80 bbl. Density: 11.8 ppg N/A Class "G" 153 bbl. Density: 15.8 ppg Top of Cement @ 13,250' MD Yield: 1.16 ft3/sk 50% Cementing Notes ■ Obtain and review the UCA Compressive Strength Test Report on the job blend from the cementing lab at least 24 hours prior to pumping the cement. DO NOT pump cement if there are any doubts as to cement quality, quantities, pumping times, or thickening times. ■ DO NOT over displace more than half the shoe track volume if plugs do not bump on strokes. ■ Perform rig pump efficiency check prior to pumping and displacing cement. • Check cement calculations with SLB and drilling engineer. Cementing Procedure 1. Rig up to cement and pressure test cement lines per Schlumberger. 2. Pump Mud Push Spacer. Shut down and drop bottom plug. 3. Pump cement job per the attached Schlumberger cementing plan. ■ Cement volumes are based on 50% excess and at least 500' TVD above the intermediate casing shoe. 4. Drop top plug and cleanup on top. ■ Ensure to capture cleanup volumes when calculating necessary displacement volumes. 5. Pump displacement at 8.0 bpm maximum. ■ Drop circulation rate to 3 BPM for last 20 bbls of displacement prior to bumping plug. 6. Bump plugs and 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 4 Pump NO MORE than % the shoe track volume if plugs do not bump on calculated strokes. 7. Wait on cement to setup per Schlumberger UCA minimum required compressive strength time requirement prior to nippling down BOPE and setting emergency slips. ■ 500 psi compressive strength minimum. 331Page H14 H14-L1 Well Plan ZuNest Energy Cosmopolitan Project H14 H14-L1 Well Plan Prior to Lifting The BOP Stack 1. P/U 1 stand of 5" drill pipe make up 8' pup and floor valve (closed). Run stand inside casing all the way down to the elevators, this will displace the mud from the casing down to the wellhead then pull the stand and rack it back. This allows for a "dry" casing cut saving time and eliminating having to clean mud out of the well bay. 2. Remove the flow line and choke & kill lines. 3. Radio communication is required for those in the cellar and on the rig floor. ■ Also ensure that radio channel is clear to only those involved in the cellar, rig floor, and subbase. 4. Ensure that Vetco Gray/ and one floor hand is in the cellar 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 1. 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. ■ 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 2. Confirm with Vetco Gray hand in the cellar that there is enough room to set the emergency slips. 3. Set emergency slips with casing in Tension • 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 on Daily Report. 4. Prior to cutting the casing ENSURE THAT ALL WEIGHT IS SLACKED OFF. 5. Once the slips are set and the casing is cut be sure that there is radio communication between those in the cellar and rig floor prior to pulling the casing in the event that the stack has to be slightly lowered. 6. Remove and lay down the cut casing 7. Install Vetco Gray Packoff assembly. 8. Re -Install the Vetco Gray Multibowl and BOP's ■ Test wellhead connection to 5000 psi ■ Radio communication is necessary for all parties involved when lowering the stack 9. Pressure test pack off per Vetco Gray. ■ Do not exceed 80% of intermediate casing collapse ■ Record test on IADC report and Daily Report 10. Install rams 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 requires BOP testing frequency every 14 days unless notified otherwise by AOGCC 11. Install wear bushing. 12. Clean mud pits in preparation to receive production OBM. 341Page H14 H14-L1 Well Plan last Energy Production — Lower Lateral Overview Cosmopolitan Project H14 H14-L1 Well Plan 8.50 4.5 RSS PDC ACTIMUL RD 10.0 23,032' 7,080' 90.000 Mud Fluid Type Weigl pp ;W. RSS From To 15,022' 23,032' o ml/30 min % 7-11 <5.0 80:20 mlVolts >600 Max 6.75" Xceed675 Telescope/ GeoSphere/ 300 600 PWD/ MVC EcoScope • Make Type Name Nozzles TFA Smith PD General Notes ■ A tapered 5-1/2" x 4-1/2" drill string will be utilized. ■ The 9-5/8" Intermediate String will require a CBL prior to drilling out ■ Shallow test MWD tools. ■ 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). • If cavings are noted at surface pictures shall be taken to clearly identify cavings structure and geometry. ■ Ensure that all team members are communicating with each other on any observed drilling trends and that everyone understands the potential risks. ■ 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 or coal sections for any extended period of time. ■ Keep shut down times to a minimum during connections. ■ Swab / Surge: Make "easy on, easy off' slips a standard practice ■ 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. 351Page H14 H14-L1 Well Plan ZuNest Energy Cement Bond Log C- f -) L Cosmopolitan Project H14 H14-L1 Well Plan 1. Rig up Schlumberger wireline and cement evaluation tool 2. Trip in the hole per Schlumberger requirements ■ Acquire CBL per Schlumberger 3. POOH and download the data for processing. Notify drilling engineer as soon as tools are on the bank to expedite future drill out. Drill Out Procedure 4. Install wear bushing 5. Pickup and drift all DP, HWDP, and DC's for surface section to confirm free of debris. 6. PU drill out BHA ■ Bit: 8-1/2" XR+ TFA: 0.994 (4 x 18) Dumb Iron Assembly 7. TIH on 4-1/2" XT46 DP to—7,500' MD. 8. Change out bails and crossover to 5-1/2" XT54 DP. 9. TIH to top of float equipment and pressure test intermediate casing to 3,500 psi for 30 min. Chartand record same. ■ Plot casing pressure test on LOT form and submit to drilling engineer ■ Verify the test indicates a linear line and there is no air entrained in the mud. Repeat casing pressure test if needed. 10. Bleed off pressure. 11. Drill out float collar and shoe. ■ Take note of any green cement or lack of necessary WOB to drill out shoe track. ■ If no cement or green cement is encountered DO NOT drill out the shoe. 4 Call drilling superintendent prior to continuing operations. 12. Clean out rat hole and POOH on elevators & LD drill out BHA. 13. PU Drilling BHA ■ Bit: 8-1/2" Z716 PDC 4 TFA: 0.773 (7 x 12) 4 PD Xceed 900 RSS BHA 14. TIH on 4-1/2" XT46 DP to—7,500' MD. 15. Change out bails and crossover to 5-1/2" XT54 DP. 16. Displace to new 10.0 ppg VersaPro OBM. 17. Drill 20' of new formation, below the rat hole. 18. POOH to surface casing shoe and perform LOT per AOGCC requirements following the attached LOT procedure. ■ Required LOT: 12.50 ppg EMW 4 Recorded LOT/FIT pressures shall follow the format below: I. EMW = PSurface+ MW 0.052*(TVD) II. XX.XX ppg EMW FIT/LOT w/ XXX psi and XX.XX ppg MW @ X,XXX' TVD 4 Offset Hansen 1: 12.80 ppg EMW FIT (Depth, MW and pressure not recorded) ■ All data shall be recorded on the provided "BlueCrest Casing/FIT/LOT Form". 361Page H14 H14-L1 Well Plan nuest Energy Cosmopolitan Project H14 H14-L1 Well Plan Pressure test is to be taken to leak off but not to exceed 1,000 psi surface pressure. IF If LOT is below 12.50 ppg EMW, contact drilling superintended prior to drilling ahead. Drilling Procedure 19. Directionally drill production hole: ■ Drilling Parameters: Flow Rate: +500 GPM Rotary: +120 RPM ■ PU and Slack -off Weights will be taken EVERY stand Per K&M ■ 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. 20. Production casing point: Landing point will be determined by wellsite geologist after exiting the Starichkof to evaluate western structure. 21. Circulate until shakers are clean per K&M. Backream one (1) stand per bottoms up very slowly while circulating clean at full drilling parameters. 500+ GPM 120+ RPM 22. Attempt to POOH on elevators. 23. If tight hole is encountered, TIH 3 stands and circulate shakers clean. Attempt to trip back through depth of tight hole: If tight hole is still encountered, ream the section clean, and confirm it is free of obstruction prior to continuing to POOH. If area is free continue to POOH on elevators making sure monitor drag trends for signs of excessive over pull. 24. If the hole is swabbing or reoccurring issues are encountered while POOH, BROOH to the surface casing shoe. 51 BROOH at full drilling parameters -) 500+ GPM 4 120+ RPM N01E. 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. 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 until the shoe has been reached and sufficiently cleaned. ■ If shakers/mud return system becomes overloaded and flow rate needs to be reduced, DO NOT continue to BROOH until the parameters are brought back to full backreaming rate. 371Page H14 H14-L1 Well Plan llueNepst Energy Cosmopolitan Project H14 H14-L 1 Well Plan 25. Circulate the hole clean per K&M 26. Drop 2" hollow DP rabbit once bit is above the intermediate shoe, POOH on elevators taking SLM and LD BHA. Ensure a wireline tail longer than the longest stand is attached. 381Page H14 H14-L1 Well Plan llueNst Energy Cosmopolitan Project 1-114 H14-L1 Well Plan Completion: Lower Lateral Lower Lateral - Liner Run 391Page H14 H14-L1 Well Plan lue est Energy Liner Run Overview Cosmopolitan Project H14 H14-L1 Well Plan 8.500 4.500 RSS PDC ACTIMUL RD 10.0 23,032' 7,080' 90.000 4.500 3.826 15.2 P-110 H563 3.701 14,350 14,420 485,000 Connection I Make Up I Operational Limit in. in. in. ft-Ibs. ft-Ibs. ft-Ibs. ft-Ibs. ft-Ibs. 5.200 3.826 9.25 I 5,100 6,100 8,900 I 16,700 25,000 General Notes PJSM: Include all company, rig and service personnel. ■ Discuss: 4 Dropped objects --) Trapped pressure 4 Handling of the non-standard length equipment about to be handled. 4 Anyone may stop the job for HSE issues. Well Control: Discuss with ODE prior to liner running operation. ■ Ensure VBR's installed will cover 4-1/2" liner and 5-1/2" DP. Pressure requirements: ■ HES and Baker must agree that pressure setting requirements and limitations are understood and compatible. Liner String: ■ The majority of the liner will consist of 4-1/2" 15.2# P-110 pipe with frac sleeve assemblies 24'+- length and swell packers built on range 3 pipe. ■ Frac sleeves and swell packers will be approximately 400' apart per run schedule included. This will be crossed over to a 20' Seal Bore Receptacle, then to a Flexlock 7 x 9-5/8" liner hanger/ZXP liner top packer and then RIH on drill pipe as required. RA Tag: ■ Place one RA tag (3 pips) in top joint of 4.5" liner. ■ This will be the first full joint below the 7" x 4-1/2" crossover. ■ Lost Circulation: Drilling mud will be used for any lost circulation issues as swellable packers in the string require SBM to expand. Un-cemented Liner w/Swell Packers: ■ This liner will not be cemented. 401Page H14 Fi14L1 Well Plan llueNest Energy Cosmopolitan Project H14 H14-L1 Well Plan . The ZXP liner top packer will be a primary barrier between production hole and intermediate casing. Swell Packers: 17 per liner. The 4.5" x 8.25" x 4.5m swell packers are designed to swell in oil. According to HES simulations, at maximum differential pressure and 145° F, first sealing of the packers in oil is estimated at 8.7 days. Full setting of the swell packers is anticipated around 31.4 days in an 8.25" hole. Time to frac 32 days. Max differential at frac time 9966 psi. Frac Sleeves: ® 17 per liner. Frac sleeves to be delivered w/10' pup on each end with assembly pressure tested. Ball and baffle sizes in chart included. Verify the dimensions of each with HES representative prior to R Frac Ball and Baffle Sizing: r See Chart Below. Verify with HES rep. Zone 1 Ball •D 1.450 Baffle I 1.415 2 1.495 1.460 3 1.540 1.505, 4 1.585 1.5502 5 1.630 1.595 6 1.720 1.640 7 1.811 1.730 8 1.906 1.821 9 1.955 1.916 10 2.005 1.965 11 2.056 2.015 12 2.108 2.066 13 2.161 2.118 14 2.215 2.171 15 2.270 2.225 16 2.326 2.280 17 2.383 2.336 411 Page H14 H14-L1 Well Plan ^uest Energy Cosmopolitan Project H14 H14-L1 Well Plan Operational Specifics 1. Drift all liner and completion equipment prior to RIH. (HES and Baker Reps to be present) 2. Follow GBR rep and HYD 563 running procedures and recommendations. 3. Use Jet Lube Seal Guard ECF on HYD 563 Connections. 4. Utilize GBR/torque turn equipment w/record provided to BlueCrest rep at end of liner installation. 5. RIH speed: ■ Not to exceed 90'/min. 6. Circulation rate: ■ Not to exceed 5 bbl/min around Swell packers. 42 1 Page H14 H1.4-L1 Well Plan llueNest Energy Liner Running Order Guide shoe w/perfed pup instead Liner joint(s) as required Downhole Shut Off Collar 10' pup jt. Liner jt. 10' pup jt. HES Initiator Sleeve 10' pup jt. Liner Joints as needed Swell Packer 4.5" 15.2# base pipe x 8.25" Liner Joints as needed 10' pup jt. HES Frac Sleeve 10' pup jt. Liner Joints as needed Swell Packer 4.5" 15.2# base pipe x 8.25" Liner Joints as needed The Frac Sleeve/Joints/Swell Packer Sequence will repeat as needed. RA Tag top liner joint 4.5" 15.2# H 563 x 5.5" 23# H 563 XO Baker 4.0" ID Seal Bore Receptacle (20' length) 5.5" H 563 5.5" 23# H 563 x 7" 26# H 563 XO 7" x 9-5/8" Baker Flexlock 7" 26# H 563 Hyd. liner hanger pinned for —2,200 psi 7" x 9-5/8" Baker'ZXP' packer w/ 10' tie -back sleeve 7" 26# H 563 Baker'HRD-E' running tool w/ Rotating Dog Sub (and no shear out Ball Seat to set hanger) Cosmopolitan Project H14 H14-L1 Well Plan 15.2 P-110 H-563 Baker -Lock 15.2 P-110 H-563 Baker -Lock 15.2 P-110 H-563 15.2 P-110 H-563 15.2 P-110 H-563 15.2 P-110 H-563 15.2 P-110 H-563 15.2 P-110 H-563 15.2 P-110 H-563 200' ± TBD 3m element - placement TBD 15.2 P-110 H-563 based on logs 15.2 P-110 H-563 200' ± TBD 15.2 P-110 H-563 3m element - placement TBD 15.2 P-110 H-563 based on MWD logs 15.2 P-110 H-563 15.2 P-110 H-563 200' ± TBD 3m element - placement TBD 15.2 P-110 H-563 based on logs 15.2 P-110 H-563 200' ± TBD Exact Running Order TBD after 15.2 P-110 H-563 logging 15.2 P-110 H-563 RA pip(s) in top liner joint 15.2/23 P-110 H-563 23 125 ksi H-563 23/26 P-110 H-563 26 L-80 H-563 26 L-80 H-563 P-110 IF 150'-200' Liner Lap 450,000# Tensile Torque Same as 7" H563 below 460,000# Tensile Torque Same as 7" H563 below 595,000# Tensile 40,000 ft. lbs. Torque 431 Page H14 H14-Ll Well Plan Zu est Energy =Drill Pipe - Below HRD to 4-1/2" Liner Baker Tubulars Specifications Liner Running 1. Centralization: Cosmopolitan Project H14 H14-L1 Well Plan - To surface - psi psi IV. In ft-lbs. Min: 5100 100% 14,350 14,420 485,000 3.826 Optimum:6100 Max:8900 80% 11,480 11536 388,000 3.701 drift Make Up Loss: 4.090" Min:7,700 100% 14,540 14,530 729,000 4.670 Optimum:9,200 Max: 13,500 80% 11,632 11,624 583,200 4.545 drift Make Up Loss: 3.990" Min: 7,800 100% 5,410 7,240 640,000 6.276 Optimum:9,400 Max: 13,700 80% 4,328 5,792 512,000 6.151 drift Make Up Loss: 4.050" One 4-1/2" x 8-1/4" Volant crimp on centralizer above the shoe on the first joint. 4 with eccentric nose guide shoe One 4.5" x 8-1/4"" Volant crimp on centralizers per joint from joints #3 -> DO NOT put centralizers on Swell Packer joints. 2. Baker -lock the shoe joints. PU shoe track and check the floats. 3. K&M/SLB will provide "Broomstick' T&D chart. Pay attention to weight loss trends and FF trends. If weight losses do not follow expected FF trends from last BHA trips stop and circulate as necessary. Rotation will not be possible. 441 Page H14 H14-L1 Well Plan llueNest Cosmopolitan Project Energy H14 H14-L1 Well Plan 4. Follow HES/Baker equipment limitation recommendations. 5. Keep liner full. 6. Fill each joint while running in the hole until on DP. 7. 5 BPM max circ. rate. 8. 90'/min. max. RIH speed. 9. Break circulation after liner is fully made up and note weight of liner in mud. Check to see if floats are holding. 10. Record hanging weight. Record SO weights every joint/ stand. Take PU and ROB weights every 10 joints/Stands. Record ROB weight prior to exiting the shoe and lock in cased hole friction factors. 11. Maximum pull at the liner top is limited to 80% of the weakest yield point in the string. 12. Break circulation every thousand feet and maintain good hole conditions. 13. Check hole displacement while RIH. 14. Monitor mud returns while running pipe in hole. 15. If returns decrease or are lost, reduce running speed. 16. When on DP fill every 5 stands and check displacement while RIH. 17. Break circulation before entering the open hole (do not exceed 1,500 psi at surface or maximum psi set by HES or Baker). 18. Continue RIH with liner. 19. Control running speed as hole conditions dictate to reduce pressure surges to the formation. 20. Do not exceed 90'/min. 21. Space out Atom Ball dropping drop. 22. Position the liner hanger/packer assembly ±150-ft above the intermediate casing shoe such that the hanger/packer is not set in Intermediate float equipment/landing collar. 23. Tag bottom with liner, bring pumps up slowly. 24. Rig up to circulate 25. Ramp up to 5 bpm and continue circulating, minimum 1 annular volumes 26. Watch for packing off. Equipment Setting Pumping Sequence 1. Swell Packers require oil based mud to begin and complete swelling process. 2. Drop pusher tool ball and pump on seat per Baker. 3. Hydraulically set the liner hanger per Baker ■ Pinned to +/-1500 psi 4. Slack off liner weight plus 50K Ibs to ensure liner is hung off properly. 5. Increase pressure to ±4,200 psi to activate the pusher tool, set the ZXP liner top packer and release the HRDE running tool. 6. Release pressure slowly and check floats. 7. Pressure up drill pipe to 500 psi and pick up to expose dog sub per Baker rep. 8. Bleed off pressure and slack off 50K at liner top to verify pusher tool set the liner top packer. 9. Pressure test liner top prior to pulling RS Packoff off seat by pressuring DP annulus to 3500 psi. 10. Release annulus test pressure and pick back up, repeat set process with rotating dog sub if necessary, and set down 50K Ibs at liner top if Baker rep requires. 11. Increase drill pipe pressure 500 psi. Slowly pull out of liner top and note when pressure bleeds off. Mark DP at RKB per Baker rep when stinger above liner top. 451 Page H14 H14-L1 Well Plan lIue'Cest Energy ■ At this point, the IRS pack -off has been pulled from the IRS nipple. • DO NOT slack off beyond mark on DP once the pack -off has been pulled. 12. Check up weight verifying liner is in left in place. 13. Pull 30' above liner top and circulate well bore to completion brine. 14. Flow check well. 15. POOH managing drill pipe as required. 16. LD running tool assembly. 17. Check brass indicators on rotating dog sub for indication of dog sub function. Cosmopolitan Project H14 H1441 Well Plan 461Page H14 H14-L1 Well Plan nueest Energy Cosmopolitan Project H14 H14-L1 Well Plan H14-Llee 8-1/2" Production 8-1/2" Production Section Drilling 471 Page H14 H14-L1 Well Plan llueNest Energy Production — Upper Lateral Cosmopolitan Project H14 H14-L1 Well Plan Overview Liner Mud Hole- Size BHA ype Weight Casing Point Max in In ppg MD TVD Type Inclination Fluids Mud 6 RPM HTHP Oil:Water ES Fluid Type Weig Fluid Loss Ratio •••mlvolts ACTIMUL •D :0.00 BHA -73S Min Max RSS 6.75" GeoSphere/ 300 600 C EcoScope Make Type Name Nozzles TFA Smith •D General Notes ■ A tapered 5-1/2" x 4-1/2" drill string will be utilized. % ■ The 9-5/8" Intermediate String has already been logged for cement integrity. ■ Shallow test MWD tools. ■ 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). ■ If cavings are noted at surface pictures shall be taken to clearly identify cavings structure and geometry. ■ Ensure that all team members are communicating with each other on any observed drilling trends and that everyone understands the potential risks. ■ 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 or coal sections for any extended period of time. ■ Keep shut down times to a minimum during connections. ■ Swab / Surge: Make "easy on, easy off" slips a standard practice ■ 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. 481Page H14 H14-L1 Well Plan llueNest Energy Cosmopolitan Project H14 H14-L1 Well Plan Preparation of Main wellbore 1. Install wear bushing 2. Pick up and drift all DP, HWDP, and DC's for surface section to confirm free of debris. 3. PU Baker casing scraper assembly 9-5/8" Casing Scraper w/ 4-1/2 Reg. Conn. F 9-5/8" Boot Basket w/ 4-1/2 Reg. Conn. X-O 4-1/2 IF Box x 4-1/2 Reg. Pin 2 stands 6-1/2" Drill collars —8000' 4-1/2 Drill Pipe ■ 5-1/2" DP to surface 4. TIH on 4-1/2" XT46 DP to—8,000' MD, change out bails and crossover to 5-1/2" XT54 DP. 5. TIH to 14,500' MD and rotate through the production packer, liner hanger packer and whipstock setting area to 14,775' MD. 6. Circulate the well clean before POOH with the casing scraper. Preparation of Main wellbore NOTE: ■ Verify measurements of all assemblies prior to picking up. Use enough drill pipe between the Shear Type Disconnect and the Unloader Sub to position the WindowMaster Whipstock at the proper casing exit point. • The final setting depth is based on the actual Whipstock BHA measurements. ■ The window length will be +/- 16 ft. • All measurements are to be double-checked and approved by the Customer Wellsite supervisor prior to running assemblies in the hole. Hold Safety meeting with all appropriate Wellsite personnel prior to commencement of operations to insure all safety and operational procedures have been reviewed. The Total G2 WindowMaster whipstock assembly is as follows: F Seal Assembly to locate in Lower lateral Extension Sleeve 4-1/2" Drill Pipe or DP Pup Joint (As required, not to exceed 7K LBS "Static") X-O Sub 4-1/2" IF Pin x 4-1/2" IF Pin ■ Retrievable Bottom Trip Anchor w/ 4-1/2" IF Box x Box {m Shear Type Disconnect w/ 120K Lbs shear ring w/ 4-1/2 IF Conn. ■ Unloader Valve Sub 4 %" IF Box x Pin (+- 30K Shear- 36" travel when sheared) s Debris Excluder Sub 4 %2" IF Box x Pin 6,YV V ■ 8.0" OD G2 WindowMasterTM Whipstock w/ 4-1/2 IF Pin ■ 8.5" OD G2 WindowMasterTM Window Mill 4-1/2 Reg. Pin (45 K Shear Bolt) ■ 8.375" OD G2 WindowMasterTM Lower Watermelon Mill 4-1/2 Reg. Box x 4-1/2 IF Box ■ WindowMasterTM Flex Joint 4-1/2 IF Box x Pin ■ 8.5" OD G2 WindowMasterTM Upper Watermelon Mill 4-1/2 IF Box x Pin ■ XO, 5-1/2" XT54 Box x 4-1/2" IF Pin ■ 1 Joint 5-1/2" HWDP ■ 6-5/8"MWD Thread TBD ■ 5-1/2" Drill pipe to surface as required 491 Page H14 H14-L1 Well Plan llueNst Energy Cosmopolitan Project H14 H14-L1 Well Plan PROPOSED WELL SgEMATC ' EOUPMEM APD SERVICES LOCATON Baker Oil Tools Insert Product Line here SALES I-- Baker Oil Tools Insert Address Here Insert Phone here _ BAKER HUGHES Baker Oil Tools �ERArDR FM# ANY REP. Plp1E. MIr1X DEV. ZpE OEY. Page : 1 FIELD WELL ND. SCREEN sm sTARTNG V1ELL TALE LEASE SAlO SRE CDMPIEIIONFLUD(MyiWrype) COAntL MP•) LOApN3 DOCK PItlNE / PERFORATIONS SIZE GRADE THREAD we NWE RgNE� CASING LINER TUBING PREPARED EY - --- PHDFEt DALE SIEINITTED - - ,oR• ".^'�,•, JOB REPORTS -—.--.---._ - WEUTYPE- WRKSTR. No. DEPTH LENGTH OD ID DESCRIPTION 1 WindowMaster G2 WHIPSTOCK w/ 4-1/2 IF Pin down 2 Excluder Sub w/ 4-1/2 IF Box x Pin 3 Unloader Sub w/ 4-112 IF Box x Pin 4 Shear Type Disconnect w/ 4-1/2 IF Box x Pin 51 1 Bottom Trip Anchor w/ 6 X-O Sub (If required) 7 Drill Pipe w/ 4-1/2 IF Box x Pin f/ Spaceout 8 Liner Top locator I F f 501Page H14 H14-L1 Well Plan lue rest Energy Cosmopolitan Project H14 H14-L1 Well Plan 7. Pick up the following assembly and TIH: ■ Seal Assembly to locate in Lower lateral Extension Sleeve ■ 4-1/2" Drill Pipe or DP Pup Joint (As required, not to exceed 7K LBS "Static") 8. Pickup the following assembly and TIH —Should be made up complete prior to being shipped to location: ■ X-O Sub 4-1/2" IF Pin x 4-1/2" IF Pin ■ Retrievable Bottom Trip Anchor w/ 4-1/2" IF Box x Box ■ Shear Type Disconnect w/ 120K Lbs shear ring w/ 4-1/2 IF Conn. ■ Unloader Valve Sub 4 %2" IF Box x Pin (+- 30K Shear- 36" travel when sheared) ■ Debris Excluder Sub 4 %2" IF Box x Pin ■ 8.0" OD G2 WindowMasterTM Whipstock w/ 4-1/2 IF Pin 9. Pickup the following assembly and TIH —Should be made up complete prior to being shipped to location: ■ 8.5" OD G2 WindowMasterTM Window Mill 4-1/2 Reg. Pin (45 K Shear Bolt) ■ 8.375" OD G2 WindowMasterTM Lower Watermelon Mill 4-1/2 Reg. Box x 4-1/2 IF Box ■ WindowMasterTM Flex Joint 4-1/2 IF Box x Pin ■ 8.5" OD G2 WindowMasterTM Upper Watermelon Mill 4-1/2 IF Box x Pin ■ XO, 5-1/2" XT54 Box x 4-1/2" IF Pin NOTE: ■ Pick up whipstock with a chain through its retrieving slot. DO NOT use cloth straps. ■ Exercise caution while running in the hole with the whipstock. ■ Avoid any sudden starts and stops while running in the hole. 10. PU 1 joint of 5-1/2" DP and TIH 11. PU MWD and TIH ■ Scribe the MWD to the WindowMaster Whipstock face to 360° (high side). After scribing the line pick up the assembly and visually inspect the scribe line. The MWD will be oriented to the scribe line by SLB. Before the tool is run 12. Shallow test MWD and continue TIH on 5-1/2" DP NOTE: ■ Do not exceed 90-120 seconds per stand while TIH ■ Avoid sudden movement or jarring of the drill string while TIH ■ Ensure that the drill string is stationary prior to setting slips and that the slips are removed slowly when releasing the string to continue TIH. ■ These precautions are to avoid any weakening of the whipstock shear bolt 13. At 45' avoe the Hanger/Packer depth, establish pickup and slackoff weights with and without the pumps on. Take care not to create any sudden movements that could affect the whipstock shear bolt. 14. Survey the whipstock with the MWD and orient the whipstock face to the kickoff azimuth 15. Slowly slack off while attempting to land the locator in the extension sleeve. 16. Slack off +/- 25' with 30,000 Ibs down weight setting the bottom trip anchor. 17. Pick up slowly to a Maximum Overpull of 7 K to confirm the bottom trip anchor is set. When overpull is seen, return the drill string to its neutral weight. ■ The unloader sub shear is pinned to 30,000 lbs. 18. Survey the whipstock with the MWD to recheck the orientation of the whipstock face. 511 Page H14 H14-L1 Well Plan ZeNerst Energy Cosmopolitan Project H14 H14-L1 Well Plan 19. Apply 45,000 Ibs down weight to shear the window mill shear release bolt. DO NOT apply more than 45,000 Ibs down weight. Continue to pick to neutral and slack off to 45,000 Ibs down weight until the shear release bolt shears. If a positive shear is not seen at surface repeat the above four (4) times. W) N0 7 overpull more than 15,000 Ibs and [;(, NC— increase overpull on each pull. 20. Pick up to neutral weight, break circulation and establish rotation in preparation of milling the window. NOTE: ■ Ensure that the drilling fluids properties are the same in and out. Consider pre -treating the drilling fluids for cement contamination. ■ Pump high viscosity sweeps after the window is cut to clean the hold of metal cuttings. Milling the Window 21. The following parameters are for general use. The baker representative on location may adjust them to hole conditions as operations dictate: Depth (ft) ROP (ft/hr) RPM Start 1-2 90-120 1.0-9.0 2-5 100-130 9.0-11.0 1 /2-3.0 100-130 11.0-17.0 2-4 100-130 22. Maintain an annular velocity of at least 150 ft/min and 6 RPM rheology reading of at least 12 to assist in removing steel cuttings. NOTE: ■ Past experience has shown that after the lower watermelon mill has left the whipstock the weight and RPM can be increased to a maximum of 35,000 Ibs and 130 RPM as needed. 23. Continue milling until the upper watermelon mill is out in open hole. Once depth has been reached, the window can be reamed as required. Avoid excess rotation of mills to prevent damage to the whipstock face 24. Continue to work the watermelon mill back and forth through the window until the assembly can be run through the window with minimum drag without using the pump and without rotating. 25. Pull above the window and circulate the well clean. 26. POOH and lay down milling assembly. 521Page H14 H14-L1 Well Plan llueNest Cosmopolitan Project Energy H14 H14-L1 Well Plan Important Whipstock / Window Drilling Guidelines F Never engage pumps (with a mud motor in the BHA) while the bit is on the face of the whipstock. Orient the BHA above the window before attempting to exit the window. Bit rotation may "catch" the edge of the whipstock and damage the face making recovery operations more difficult. Never rotate up or down on the face of the whipstock with a rock bit or stabilizer. These items may "catch" the edge of the whipstock and damage it or cause it to turn inside the casing thereby either partially or completely covering the window exit. If at any time during operations a problem is encountered tripping through the window area, a watermelon or string mill should be run in the drilling assembly to clean up the window area. It is highly recommended that stabilizers are NOT rotated until a minimum of 70'-100' of progress is made outside the window. This will help minimize damage to the whipstock face. Always trip slowly and carefully (+/- 90 seconds per stand) with all BHA's through the milled window. g If fishing operations are required through the window area, always run the smallest OD fishing tool allowable for that particular fishing scenario. If over shots or box taps are utilized, small cut lips (1/2" —1") are recommended. Fishing assemblies should be as flexible as possible. Use a bit size string mill run directly above any fishing tool to provide standoff and prevent and cut lip or other "edges" from hanging up on the top and bottom edge of the whipstock face. If required, the string mill can be used to clean up any preexisting window damage before the fish is engaged and pulled back through the window. Drill Out Procedure 27. PU Drilling BHA ■ Bit: 8-1/2" Z716 PDC TFA: 0.773 (7 x 12) PD Xceed 900 RSS BHA 28. TIH on 4-1/2" XT46 DP to—7,500' MD. 29. Change out bails and crossover to 5-1/2" XT54 DP. 30. Drill 20' of new formation, below the rat hole. 31. POOH to surface casing shoe and perform LOT per AOGCC requirements following the attached LOT procedure. Required LOT: 12.50 ppg EMW Y Recorded LOT/FIT pressures shall follow the format below: IPSurface . EMW = + MW 0.052-(rvo) II. XX.XX ppg EMW FIT/LOT w/ XXX psi and XX.XX ppg MW @ X,XXX' TVD Offset Hansen 1: 12.80 ppg EMW FIT (Depth, MW and pressure not recorded) ■ All data shall be recorded on the provided "BlueCrest Casing/FIT/LOT Form". ■ Pressure test is to be taken to leak off but not to exceed 1,000 psi surface pressure. • If LOT is below 12.50�EMW, contact drilling superintended prior to drilling ahead. 531Page H14 H14-L1 Well Plan lueNest Energy Cosmopolitan Project H14 H14-L1 Well Plan Drilling Procedure 32. Directionally drill production hole: • Drilling Parameters: Flow Rate: +500 GPM Rotary: +120 RPM ■ PU and Slack -off Weights will be taken EVERY stand Per K&M ■ 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. 33. Production casing point: • Landing point will be determined by wellsite geologist after exiting the Starichkof to evaluate western structure. 34. Circulate until shakers are clean per K&M. Backream one (1) stand per bottoms up very slowly while circulating clean at full drilling parameters. 4 500+ GPM 4 120+ RPM 35. Attempt to POOH on elevators. 36. If tight hole is encountered, TIH 3 stands and circulate shakers clean. Attempt to trip back through depth of tight hole: ■ If tight hole is still encountered, ream the section clean, and confirm it is free of obstruction prior to continuing to POOH. ■ If area is free continue to POOH on elevators making sure monitor drag trends for signs of excessive over pull. 37. If the hole is swabbing or reoccurring issues are encountered while POOH, BROOH to the surface casing shoe. ■ BROOH at full drilling parameters 4 500+ GPM 4 120+ RPM NOTE: ■ 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. • 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 until the shoe has been reached and sufficiently cleaned. ■ If shakers/mud return system becomes overloaded and flow rate needs to be reduced, DO NOT continue to BROOH until the parameters are brought back to full backreaming rate. 38. Circulate the hole clean per K&M 39. Drop 2" hollow DP rabbit once bit is above the intermediate shoe, POOH on elevators taking SLM and LD BHA. Ensure a wireline tail longer than the longest stand is attached. 541Page H14 H14-L1 Well Plan nuest Energy Cosmopolitan Project H14 H14-L1 Well Plan Retrieval of WindowMaster Whipstock 40. Make up the following assembly to retrieve the WindowMaster whipstock assembly and TIH Fixed Lug (Bent) Retrieving Tool 4 %2" IF Box (1 port 180 degrees from lug) 4-3/4" Bumper Sub 4 %:" IF Box x Pin XO, 5-1/2" XT54 Box x 4-1/2" IF Pin 1 joint of 5-1/2" XT54 Drill Pipe MWD 5-1/2" XT54 DP to surface 41. Align Fixed Lug Retrieving Tool with MWD. Orientation should be 180' from previous MWD to Whipstock alignment. 42. Slack off onto Whipstock face and continue down hole until retrieving tool top sub is +/- 7 ft. below retrieving slot. (Top of Retrieving slot is 6' below top of Whipstock) 43. Pick up Fixed Lug Tool above Whipstock and align lug with whipstock face using MWD. 44. Lower Fixed Lug Tool onto whipstock face until lug is at the desired depth to engage the retrieval slot. 45. Pick up and slack off several times to confirm that the lug in landed in the slot. If the lug does not land in the slot, repeat the above process. 46. At this point attempt, straight pull release of Bottom Trip Anchor with 60-65,000 lbs. overpull at the Bottom Trip Anchor. 47. If the Anchor does not release at 55,000 lbs., continue overpull to 80-100,000 lbs. to release Emergency Shear Disconnect Sub. 48. If Whipstock or Emergency Shear Disconnect Sub cannot be released with straight pull, light jarring may be required to complete the recovery operation. (The retrieving tool can be released by right hand torque and slight down weight.) NOTE: R If an overbalance fluid situation is present, the Unloader Valve Sub below the Excluder can be opened with +/- 30 K overpull allowing the upper and lower formations to equalize which will free the Seal Assembly. When the Unloader Valve Sub shears open, an additional 18" of travel will be noted. The well, depending on overbalance or under balance of drilling mud, may start losing or gaining fluid. A backup Whipstock fishing contingency consisting of above BHA with first, a hydraulic overshot, and second, a Box Tap will be on location during the Whipstock recovery process. Further, a Bowen overshot will also be on location to fish the 3.00" OD Emergency Disconnect should it be necessary. 551Page H14 H14-L1 Well Plan lue est Energy Cosmopolitan Project H14 H1441 Well Plan Completion: Upper Lateral Upper Lateral - Liner Run 561 Page H14 H14-L1 Well Plan llueNest Energy Liner Run Overview Cosmopolitan Project H14 H14-L1 Well Plan 8.500 4.500 RSS PDC ACTIMUL RD 10.0 23,032' 7,080' 90.00" 4.500 3.826 15.2 P-110 H563 3.701 14,350 14,420 485,000 Connection I Make Up I Operational Limit •�Length Min•.Max Operating in. in. in. ft-Ibs. ft-Ibs. ft-Ibs. ft-Ibs. ft-Ibs. 3.826 9.25 5,100 6,100 8,900 16,700 25,000 General Notes PJSM: Include all company, rig and service personnel. ■ Discuss: Dropped objects Trapped pressure -� Handling of the non-standard length equipment about to be handled. 4 Anyone may stop the job for HSE issues. ,Well Control: Discuss with ODE prior to liner running operation. ✓ Ensure VBR's installed will cover 4-1/2" liner and 5-1/2" DP. Pressure requirements: ■ HES and Baker must agree that pressure setting requirements and limitations are understood and compatible. Liner String: ■ The majority of the liner will consist of 4-1/2" 15.2# P-110 pipe with frac sleeve assemblies 24'+- length and swell packers built on range 3 pipe. ■ Frac sleeves and swell packers will be approximately 400' apart per run schedule included. This will be crossed over to a 20' Seal Bore Receptacle, 7x 9-5/8" S3 Hook Hanger, Flexlock IV 7 x 9-5/8" liner hanger/ZXP liner top packer and then RIH on drill pipe as required. ■Thp hook hanger must be set in the window. Prior t• picking up the 4-1/2" Frac String, verify the casing tally of the liner and components to be run. The length of the later must have sufficient rat hole to ensure that the liner is hung off in the window and not sitting on bottom. RA Tag: ■ Place one RA tag (3 pips) in top joint of 4.5" liner. ■ This will be the first full joint below the 7" x 4-1/2" crossover. 571Page H14 H14-L1 Well Plan llueNst Energy Cosmopolitan Project H14 H14-1 1 Well Plan ■ Lost Circulation: Drilling mud will be used for any lost circulation issues as swellable packers in the string require SBM to expand. Un-cemented Liner w/Swell Packers: This liner will not be cemented. The ZXP liner top packer will be a primary barrier between production hole and intermediate casing. Swell Packers: 17 per liner. The 4.5" x 8.25" x 4.5m swell packers are designed to swell in oil. According to HES simulations, at maximum differential pressure and 145' F, first sealing of the packers in oil is estimated at 8.7 days. Full setting of the swell packers is anticipated around 31.4 days in an 8.25" hole. Time to frac 32 days. Max differential at frac time 9966 psi. Frac Sleeves: 17 per liner. Frac sleeves to be delivered w/10' pup on each end with assembly pressure tested. Ball and baffle sizes in chart included. Verify the dimensions of each with HES representative prior to R Frac Ball and Baffle Sizing: See Chart Below. Verify with HES rep. Zone 1 Ball •D 1.450 Baffle ID 1.415 2 1.495 1.460 3 1.540 1.505, 4 1.585 1.5502 5 1.630 1.595 6 1.720 1.640 7 1.811 1.730 8 1.906 1.821 9 1.955 1.916 10 2.005 1.965 11 2.056 2.015 12 2.108 2.066 13 2.161 2.118 14 2.215 2.171 15 2.270 2.225 16 2.326 2.280 17 2.383 2.336 581 Page H14 H14-L1 Well Plan llueNest Energy Cosmopolitan Project H14 H14-L1 Well Plan Operational Specifics 49. Drift all liner and completion equipment prior to RIH. (HES and Baker Reps to be present) 50. Follow GBR rep and HYD 563 running procedures and recommendations. 51. Use Jet Lube Seal Guard ECF on HYD 563 Connections. 52. Utilize GBR/torque turn equipment w/record provided to BlueCrest rep at end of liner installation. 53. RIH speed: Not to exceed 907min. 54. Circulation rate: ■ Not to exceed 5 bbl/min around Swell packers. 591Page H14 H14-L1 Well Plan llueNest Energy Liner Running Order 3uide shoe w/perfed pu� nstead with bent joint -inerjoint(s) as required )ownhole Shut Off Collar LO' pup it. .iner it. LO' pup it. -IES Initiator Sleeve LO' pup it. _iner Joints as needed ,well Packer 4.5" 15.2# base )ipe x 8.25" .iner Joints as needed �0' pup it. iES Frac Sleeve '0' pup it. .iner Joints as needed well Packer 4.5" 15.2# base )ipe x 8.25" .iner Joints as needed -he Frac Sleeve/Joints/Swell 'acker Sequence will repeat as seeded. to Tag top liner joint 1.5" 15.2# H 563 x 5.5" 23# H '063 XO taker 4.0" ID Seal Bore teceptacle (20' length) 5.5" H 163 ,.5" 23# H 563 x 7" 26# H 563 ;0 '11 x 9-5/8" Baker Flexlock 7" 26# 1563 Hyd. liner hanger pinned or —2,200 psi '' x 9-5/8" Baker'ZXP' packer v/ 10' tie -back sleeve 7" 26# H ,63 !aker'HRD-E' running tool w/ rotating Dog Sub (and no shear out Ball Seat to set hanger) Cosmopolitan Project H14 H14-L1 Well Plan 15.2 P-110 H-563 Baker -Lock 15.2 P-110 H-563 Baker -Lock 15.2 P-110 H-563 15.2 P-110 H-563 15.2 P-110 H-563 15.2 P-110 H-563 15.2 P-110 H-563 15.2 P-110 H-563 15.2 P-110 H-563 200' ± TBD 3m element - placement TBD 15.2 P-110 H-563 based on logs 15.2 P-110 H-563 200' ± TBD 15.2 P-110 H-563 3m element - placement TBD 15.2 P-110 H-563 based on MWD logs 15.2 P-110 H-563 15.2 P-110 H-563 200' ± TBD 3m element - placement TBD 15.2 P-110 H-563 based on logs 15.2 P-110 H-563 200' ± TBD Exact Running Order TBD after 15.2 P-110 H-563 logging 15.2 P-110 H-563 RA pip(s) in top liner joint 15.2/23 P-110 H-563 23 125 ksi H-563 23/26 P-110 H-563 150'-200' Liner Lap 26 L-80 H-563 450,000# Tensile Torque Same as 7" H563 below 460,000# Tensile 26 L-80 H-563 Torque Same as 7" H563 below 595,000# Tensile P-1.10 IF 40,000 ft. lbs. Torque 601 Page H14 H14-L1 Well Plan nuest Energy =Drill Pipe - Below HRD to 4-1/2" Liner Baker Tubulars Specifications psi psi Ibf. 100% 14,350 14,420 485,000 In 3.826 - To surface 80% 11,480 11536 388,000 3.701 drift 100% 14,540 14,530 729,000 4.670 11,624 583,200 4.545 drift 100% 5,410 7,240 640,000 6.276 4,328 5,792 512,000 6.151 drift Cosmopolitan Project H14 H14-L1 Well Plan ft-lbs. Min: 5100 Optimum: 6100 M a x:8900 Make Up Loss: 4.090" Min:7,700 Optimum: 9,200 Max: 13,500 Make Up Loss: 3.990" Min: 7,800 Optimum: 9,400 Max: 13,700 Make Up Loss: 4.050" Liner Running 55. Centralization: r One 4-1/2" x 8-1/4" Volant crimp on centralizer above the shoe on the first joint. 4 with eccentric nose guide shoe One 4.5" x 8-1/4"" Volant crimp on centralizers per joint from joints #3 --> DO NOT put centralizers on Swell Packer joints. 56. Baker -lock the shoe joints. PU shoe track and check the floats. 57. K&M/SLB will provide "Broomstick" T&D chart. Pay attention to weight loss trends and FF trends. If weight losses do not follow expected FF trends from last BHA trips stop and circulate as necessary. Rotation will not be possible. 611 Page H14 H14-L1 Well Plan ZuNrs t Energy Cosmopolitan Project H14 H14-L1 Well Plan 58. Follow HES/Baker equipment limitation recommendations. 59. Keep liner full. 60. Fill each joint while running in the hole until on DP. 61. 5 BPM max circ. rate. 62. 90'/min. max. RIH speed. 63. Break circulation after liner is fully made up and note weight of liner in mud. Check to see if floats are holding. 64. Record hanging weight. Record SO weights every joint/ stand. Take PU and ROB weights every 10 joints/Stands. Record ROB weight prior to exiting the shoe and lock in cased hole friction factors. 65. Maximum pull at the liner top is limited to 80% of the weakest yield point in the string. 66. Break circulation every thousand feet and maintain good hole conditions. 67. Check hole displacement while RIH. 68. Monitor mud returns while running pipe in hole. 69. If returns decrease or are lost, reduce running speed. 70. When on DP fill every 5 stands and check displacement while RIH. 71. Control running speed as hole conditions dictate to reduce pressure surges to the formation. 72. Do not exceed 90'/min. 73. At +/- 45' above the 8-1/2" casing window, check and report the Pickup and Slack off string weights. 74. Slack off slowly out of the 8-1/2" casing window looking for any abnormal resistance. 75. Continue in the hole looking for set down at the main wellbore liner hanger/packer setting depth. 76. If no hanger/packer indication is seen, the 4-1/2" liner has entered the upper lateral. Continue running the liner assembly. ■ If the liner does not successfully enter the lateral, pull back up the hole +/- 15' above the window. ■ Reorient the bent joint and slack off the liner assembly. Continue reorienting in increments until the bent joint successfully exits the window. NOTE: -- -------------- ■ This process should involve both the BOT Fishing Tool Supervisor and BOT Liner Hanger Personnel. ■ Both supervisors should be on the rig floor while attempting to exit the window. 77. With the casing pup joint and swivel sitting in the slips pick up the pre -assembled Hook Hanger assembly and stab carefully into the liner. Make up to the required make-up torque. ■ DO NOT set the slops on the liner setting sleeve. Ensure that slips are set on the lift nipple. ■ Draw a scribe line from the top of the Torque Tube slot to the top of the setting tool. Rotate the line 180° and orient to the UBHO sub. 78. Align the key in the UBHO Sub to the hook on the hook hanger assembly. 79. Continue to TIH. 80. When the hook hanger assembly is +/- 30' above the window, check and record pickup and slack off weights. 81. Attempt to land the hook hanger. Set slips on DP. 82. Rig up the Surface Readout Gyro equipment. Surface test the Surface Readout Gyro equipment. 83. Run in hole with Surface Read out Gyro equipment. 621 Page H14 H14-L1 Well Plan llueNest Energy NOTE: Cosmopolitan Project H14 H14-L1 Well Plan ■ It will be necessary to pump down the Surface Readout Gyro equipment. Ensure that all necessary equipment is on location and has been properly inspected. ■ The running tool will shear with set down weight and 4600 ft/Ibs left hand torque. 84. Orient the Hook hanger 180 degrees from the previous MWD readings taken to set the WindowMaster Whipstock assembly. (SEE BOT RIG SITE COORDINATOR FOR CORRECT ORIENTATION OF HOOK) The hook should be orientated to be directly opposite the window, i.e. Hook Profile to be on low side. 85. Pull out of the hole with the Surface Readout Gyro equipment. Rig down Gyro Data equipment. 86. Pick up drill pipe and drill pipe pup joints as required engaging Hook Hanger in the Window 87. Slack off slowly and engage the Hook Hanger. Set the Hook Hanger in the window by slacking off a maximum of 30,000-Ibs. Pick backup to neutral point. Equipment Setting Pumping Sequence 88. Swell Packers require oil based mud to begin and complete swelling process. 89. Drop pusher tool ball and pump on seat per Baker. 90. Pressure up to 2500 PSI to activate Hydraulic Pusher Tool 91. Cont. to pressure up to 4500 PSI to Neutralize Pusher Tool, slack off again to ensure HRDE has released. 92. Bleed Pressure to Zero. Pick up 1-3 ft. to verify HRD-E tool is released. 93. If desired or unconfirmed Pusher Tool activation, the Dog Sub may be used as a back up method to set the ZXP. POOH WARNING: ■ The HRD-E (Hydraulic Release /Left Hand Mechanical Release) Setting Tool is designed to transmit torque with the liner weight on the tool. If the liner is put in compression (slacked off) and left-hand torque of 4600 ft/Ibs is applied, the HRD-E setting tool will release. 94. Pressure test liner top prior to pulling RS Packoff off seat by pressuring DP annulus to 3500 psi. 95. Release annulus test pressure and pick back up, repeat set process with rotating dog sub if necessary, and set down 50K Ibs at liner top if Baker rep requires. 96. Increase drill pipe pressure 500 psi. Slowly pull out of liner top and note when pressure bleeds off. Mark DP at RKB per Baker rep when stinger above liner top. At this point, the RS pack -off has been pulled from the RS nipple. ■ DO NOT slack off beyond mark on DP once the pack -off has been pulled. 97. Check up weight verifying liner is in left in place. 98. Pull 30' above liner top and circulate well bore to completion brine. 99. Flow check well. 100. POOH managing drill pipe as required. 101. LD running tool assembly. 102. Check brass indicators on rotating dog sub for indication of dog sub function. 631 Page H14 H14-L1 Well Plan Zu(.-�`est Cosmopolitan Project Energy H14 H14-L1 Well Plan Upper Completion Frac String 641 Page H14 H14-L1 Well Plan lue est Energy Frac String Overview Cosmopolitan Project H14 H14-L1 Well Plan 4.500 3.826 15.2 P-110 H563 3.701 14,350 14,420 485,000 Connection Make Up operational Limit •r •_.Max Operating, in. in. in. ft-Ibs. ft-Ibs. ft-Ibs. ft-Ibs. ft-Ibs. 5.200 3.826 9.25 I 5,100 6,100 8,900 I 16,700 25,000 Frac String Running Sequence 1. Tally and Drift 4-1/2" P-110 15.2# TSH563 frac string in pipe shed. Drift to 3.701". 2. Make dummy run w/tubing hanger. 3. PU Baker 20' 4-1/2" Seal Stack and associated equipment. (Seal O.D. 4.00", I.D. of stack 2.867"). 4. PU and RIH with frac string. 5. Keep hole full. 6. Use Jet Lube Seal Guard ECF per Tenaris recommendations. 7. RIH to 100' above liner top per tally and slow running speed. 8. RIH to liner top and begin slow circulation. Rotation may be required to pass liner top w/mule shoe. 9. RIH until seals engage PBR below liner hanger, at pressure increase SD pumps. 10. RIH w/seal stack and tag NO-GO with string. (20'+-). 11. Slack off weight per tubing movement calculation to be provided. 12. Measure for space out and PU as required to lay down top joint. 13. Pup up as required 1 joint below tubing hanger point. 14. MU tubing hanger. 15. Land tubing. 16. GE run TWC and observe well for flow. 17. Drain BOPE stack. 18. ND BOPE stack and place on stump. 19. MU Frac Head. 20. GE pull TWC. 21. Pressure test annulus to 3500 psi for 30? minutes. Bleed off. 22. GE run BPV and check well for flow. 23. Shut frac head valves. 24. RDMO 651Page H14 H14-L1 Well Plan nuest Energy Attachn Cosmopolitan Project H14-L1 10-401 APD Attachments H14-L1 10-401 APD Attachments r- L (U W L4 _ m m N N O O m > N UFg 8 B E Hc Mm E °ss C. m an o° m� E 25o Z'N �e M� ��iZOM _= dui�O'? 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I'll eeos.n WPTOEW eA —1 R-0ACP 1 I']W�.rat'I �-o�..1SiB1LJ.'.'41�1 osFl n m,3.+� bow u�nw Traveling Cylinder Plot NoGo Region FOU's based on Onented FOU 0,mension Minor Risk Ant: Coniston rub used 0306( Ant,Coli,ston Standard S602 v5 Ii5 2 11137 28( 270 26( North 350 190 180 1!U Production hole TRAVELING CYLINDER PLOT Client BluoCrest Fteld Cosmopolitan Una Sl-cture Cosmoptitan Pad Well H14 Boretwle H14L1 Odle OS-Jul-2016 90 00 llue)est Energy Attad Cosmopolitan Project H14-L1 10-401 APD Attachments H14-L 110-401 APD Attachments llueNest Cosmopolitan Project Energy p � MASP & Casing Design Maximum Anticipated Surface Pressure (MASP): 17.5" Hole Section This hole section will be drilled with a diverter only, no BOPE. While MASP will equal the formation pore pressure at the surface casing shoe depth of 3,350' TVDss less a gas gradient to the surface, it cannot be shut in, only diverted. Offset well information indicates that the pore pressure at 3,350' TVDss will be a maximum of 9.0 ppg (0.468 psi/ft). Calculation for MASP (17.5" hole) _ (3,350') x (0.468-0.10) = 1,233 psi. 12.25" Hole Section The MASP for 12.25" hole section will be the formation pore pressure (less a full gas column to the surface) at 15,022' MD/ 6,900' TVDss Offset well information indicates that pore pressure at 6,900' TVDss will be a maximum of 9.66 ppg (0.502 psi/ft). Calculation for MASP (12.25" hole) _ (6,900') x (0.502-0.10) = 2,776 psi. 8.5" Hole Section The MASP for the 8.5" hole section will be the formation pore pressure (less a full gas column to the surface) at 23,032' MD/ 6,900' TVDss. Offset well information indicates that pore pressure at 6,900' TVDss will be a maximum of 9.0 ppg (0.468 psi/ft). Calculation for MASP (8.5" hole) _ (6,900') x (0.468 - 0.10) = 2,539 psi. With MASP in the 8.5" open hole section calculated to be 2,539 psi, the 5,000 psi BOPE system to be used will be adequate. 10-401 APD Attachments MASP & Casing Design lueNp�st Energy Casing Design Verification: Planned Casing program: Cosmopolitan Project MASP & Casing Design 13.375" 9.625" Surface Casing Intermediate Casing Depth (MD) 4,941' 15,022' Depth (TVDss) 3,350' 6,900' Hole size 17.5" 12.25" Weight (ppf) 72 47/53.5 Grade L-80 P-110 Connection BTC Hydril 563 Nominal ID (in) 12.347" 8.681" API Casing Design Factors Design factors are essentially "safety factors" that allow the design of safe, reliable casing strings. Each operator may have his own set of design factors based on his experience and the condition of the pipe. Here we use operator's recommended design factors. Design Factors: Tensile Joint Strength: Collapse (from external pressure): Burst (from internal pressure): Nt = 1.8 SF Nc= 1.125 SF Ni=1.25SF The pore pressures and fracture gradients used here are those derived from studies of offsetting Cosmopolitan 1, Hansen 1 and Hansen 1A. 10-401 APD Attachments MASP & Casing Design lueCtest Energy Casing Design Factor Calculations: Burst Requirements Cosmopolitan Project MASP & Casing Design Use maximum anticipated surface pressures (MASP) for each casing string. For each casing string MASP is the formation pressure at the next casing point less a gas column to surface. 13.375", 72#, L-80, BTC Surface Casing: MASP at 12.25" hole section TVDss of 6,900': MASP = (6,900') x ((10.5 ppg x 0.052)-0.10 psi/ft) = 2,932 psi (burst stress) DFB,rst = burst strength / burst stress = 5,380psi / 2,932 psi = 1.83 vs minimum SF of 1.25. 9.625", 47#, P-110, Hydril 563 Intermediate Casing: MASP at 8.5" hole section TVDss of 6,900': MASP = (6,900') ((10.0 ppg x 0.052)-0.10 psi/ft) = 2,760 psi (burst stress) Nmrst = burst strength / burst stress = 9,440 psi / 2,760 psi = 3.42 vs minimum SF of 1.25. 10-401 APD Attachments MASP & Casing Design llueNest Energy Collapse Requirements Cosmopolitan Project MASP & Casing Design Use an external pressure consisting of the formation pore pressure at the casing shoe and an internal pressure of a gas column to surface. 13.375", 72#, L-80, BTC Surface Casing: External pore pressure = 9.0 x 0.052 x 3,350' = 1,568 psi Internal pressure w/gas only = 0.10 x 3,350'= 335 psi Collapse stress = 1,568 psi - 335 psi = 1,233 psi. DFcoiiapse = collapse rating / collapse stress = 2,670 / 1,233 = 2.17 vs minimum SF of 1.125. 9.625", 47#, P-110, HVdril 563 Intermediate Casing: External pore pressure Internal pressure w/gas only = 9.66 x 0.052 x 6,900' = 3,466 psi = 0.10 x 6,900' = 690 psi Collapse stress = 3,466 psi — 690 psi = 2,776 psi DFcouapse = collapse rating/collapse stress = 5,300 psi/ 2,776 psi = 1.91 vs minimum SF of 1.125. 10-401 APD Attachments MASP & Casing Design llueNest Energy Axial Requirements 13.375", 72#, L-80, BTC Surface Casing: Weight in air = 4,941' x 72 Ib/ft Pipe weight in mud = Pipe wt (in air) x Buoyancy Factor (BF) BF for 9.6 ppg mud = (65.5-9.6)/ 65.5 Pipe weight in mud = 355,752 lbs x 0.8534 = 355,752 lbs. = 0.8534 = 303,611 lbs. Cosmopolitan Project MASP & Casing Design DFAxial = body tensile strength / buoyed wt. = 1,661,000 lbs. / 303,611 lbs. = 5.47 vs minimum SF of 1.8. 9.625", 47#, P-110, Hydril 563 Intermediate Casing: Weight in air = (1500' x 53.5 Ib/ft) + (13,522' x 47 Ib/ft) = 715,784 lbs. Pipe weight in mud = Pipe wt. (in air) x Buoyancy Factor (BF) BF for 10.5 ppg mud = (65.5-10.5) / 65.5 = 0.8397 Pipe weight in fluid = 715,784 lbs. x 0.8397 = 601,040 lbs. DFAxial = joint tensile strength / buoyed wt = 1,493,000 lbs. / 601,040 Ibs. = 2.48 vs minimum SF of 1.8. 10-401 APD Attachments MASP & Casing Design lue)est Energy Attachmi Cosmopolitan Project H14-L1 10-401 APD Attachments H14-L1 10-401 APD Attachments Zue)rest Cosmopolitan smopolitan Project LOT/FIT Procedure BlueCrest LOT/FIT Procedure 1. Drill out the shoe track and clean out any rat hole from the previous hole section below the shoe. From this depth, drill an additional 20 ft (minimum) to 50 ft (maximum) of new hole. 2. Circulate the wellbore clean and ensure MW in = MW out. Record this value. Line up one mud pump on the kill line. Isolate the other pump(s). 3. Turn on the pump to flood the kill line and to ensure the hole is full and that no air is present in the circulating system. 4. While pumping, ensure that the pump pressure gauge and the gauge on the chart recorder are reading the same pressure. 5. Shut down the pump, position a tool joint at the rig floor and close the upper pipe rams. 6. Bring the mud pump on line slowly at % - % bbl per minute and watch for pressure to start increasing. 7. Verify no fluid is leaking past the closed pipe rams. Record the pressure from the chart recorder vs strokes pumped every 2 or 3 strokes pumped. The pressure should increase in a linear fashion vs strokes (Volume) pumped. 8. To perform a LOT (Leak -off Test), continue pumping and recording pressure vs strokes until the pressure deviates from a straight line trend. Obtain two additional readings to confirm this deviation from linearity. 9. Shut down the pump and continue to record pressure vs time, initially every 30 seconds for 2 minutes and then every minute for an additional 8 minutes. 10. Plot the points for the pressure build up vs volume pumped on one chart and the pressure drop vs time on a second chart. 11. By looking at the chart of pressure vs volume pumped, the leak -off pressure is the point at which the curve deviates from a straight line trend. 12. Use the formula: MW + Pressureceak off MWEquivaient = TVDShoe x 0.052 13. Report using the format below: 0 XX.XX ppg EMW FIT/LOT w/ XXX psi and XX.XX ppg MW @ X,XXX' TVD 14. The FIT follows the same operational steps as previously described, except that the pressure is increased to a pre -determined value previously calculated, where the plot of pressure vs volume pumped does not deviate from a straight line. Using the same formula, the FIT value is obtained. If, however, deviation from a straight line does occur, do not keep pumping. The leak off pressure has been reached and additional pumping may cause the formation to break down. 15. The final step is to bleed off the pressure from the test and measure the volume of fluid returned to a small pit such as the trip tank or small pill pit. Depending on well design and depth, this volume bled back could be small — maybe no more than 1 bbl. 10-401 APD Attachments LOT/FIT Procedure llueNest Energy Attach Cosmopolitan Project H14-L1_10-401 APD Attachments H14-L1 10.401 APD Attachments IlUeNest Energy Cosmopolitan Project BOP & Choke Manifold Configuration I 5/81) 27 3/4 13 5/8f)X 10K# CAMERON BOP STACK BLUECREST ENERGY 13 5/87dOK CAMERON BOP STACK -- �I�T 04%., _ wrt1n1t LATEST wo rtHr -- %6j6 55 TED AWAWA" --6/22/15 CA' n« AM ICIILE R Il 16F BSBC7002 10-401 APD Attachments BOP & Choke Manifold Configuration llueNep�st Energy Cosmopolitan Project BOP & Choke Manifold Configuration 10-401 APD Attachments BOP & Choke Manifold Configuration rNest Energy Diverter a w ca a ' OPENINC PORT J �O CLOSING PORT G FLANGED M AS CAST N O L AS CAST Cosmopolitan Project BOP & Choke Manifold Configuration t E AS CAST m t (L U P m AS CAST 4 F CLAMP HUB Nominal Dimensions —Inches —with 2000 psi Bottom Connections A s Bi I C 0 E F G H J K L M N O P i 52" HOW 51 12)2 I Hub 1 23% 6 7h 62ha 27;6 46% 51% $8IA 52% b0 tYa 511 Wye6 Nominal Dimensions —Inches —with 3000 psi Bottom Connections A B C 1 1) E F G H J K L M N O P H60% ' 1 54$14 12�i I 23% � 9V4 pis 2746 45% 51*4 58% 52% 50 1% � 10-401 APD Attachments BOP & Choke Manifold Configuration Il.TeS[ Energy Attad i:.101 Cosmopolitan Project H14-L1_10-401 APD Attachments H14-L1 10-401 APD Attachments llueNest Energy . I I I I I ws1' I r' H 1 1/16' S.000 PSI MSP I i I I I I 1r ii I i I i I i i i I i 13 SPo'WC%-----—I 4 519' r UL' 00�- 2" v r 1/16 sow P5 A If 56 5,000 OSi -- -- --- - 631, IS SAS' S.000 Pa Z L16' S.000 P51 MSY i 4 15 Sfd' S,000` oSi SW P11CKOf, LS.§S -4 S/!' C$G HGR 13 -SAS' $POO PSI —15- SAY'FLUTED "AM l H"EQ Cosmopolitan Project Wellhead/Tree 10-401 APD Attachments Wellhead/Tree nuest Energy Attachi Cosmopolitan Project H14-L1 10-401 APD Attachments H14-L1 10-401 APD Attachments J_ w r-I r-i > � O t J r{ O O a o O >. a LLJ 00000 cn Q 00 u 00 0 ®®®®nB ❑pp 60000 0 Q D o o 00000 o '� m CO 00 oc ❑ o AL li LJ o � .gym •o � o a � LIE: *1 s FJ WI �n �Ea^ F' �zi* tl 0 � o 0 Id a% Va I� 'cuW 0 0 0 0 m M O O O O t\ M ~ N ~ H N N M J M 0 N co 00 M O y N QI � ~ M N N Q M a o 999Z6£laV 0 � a d C N M f0 Q � J - L7 x Al.NC, rl 01 W LL 0. 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M 00 V1 i 00 M p \ 0/ N 00 N O Ln r4 \ C^ N N O = Lr) N j� \ 01 rl W O M t\ r, \ .--I O C �-1 V 00 N N ei N 2 LD " ' U1 01 .--I tD N 06 '0 w •--I 0) u LI) Ln N .--1 ri LNL N = _ Lr) Lr) J N M w V LEAJ -Lr, 7 rl '-I LL M = J I -I c-1 LL . 4 0 0 N BO �7 0 ^j O w N O -0 0 N C M V) a C N ti G n t+l N N Q V 1 C ^O �--1 CL N Q m N U.0 fV0 C N w CU 0 Y C S u L C M L bU 0 y C Y 6b PN" I C M Y NCL ` N N U Q N Z w( O Z L11 Ur M O O H Z L J L! 0 O F- Z W :7 M G F Z ui 0 0 O O C N O O N N O N 44JoN (:4) 43noS O N O O N N STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 71' Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF BlueCrest Alaska Operating, LLC to drill and complete the Hansen H-14L1 development oil well branch within the same governmental quarter section as a well that is, or may be capable of, producing from the same pool. IT APPEARING THAT: Docket Number: CO-17-003 Conservation Order 729 Cosmopolitan Unit Hansen Undefined Oil Pool Hansen H-14L 1 Oil Development Well Branch Kenai Borough, Alaska March 15, 2017 By a letter received January 23, 2017, BlueCrest Alaska Operating LLC (BlueCrest) requested an exception to the spacing requirements of 20 AAC 25.055 to drill the Hansen H-14L1 well branch within the same governmental quarter sections as development well branch Hansen lA-L1 and development well Hansen H-16, which are, or may be capable of, producing from the same pool. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) tentatively scheduled a public hearing for March 2, 2017. On January 27, 2017, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On January 27, 2017, the AOGCC published the notice in the ALASKA DISPATCH NEWS. 3. Pursuant to 20 AAC 25.055(d)(1), BlueCrest sent by certified mail notice of the application to all owners, landowners, and operators of all properties within 1,000 feet of the proposed Hansen H-14L1 development well branch, i.e., the Bureau of Ocean Energy Management and the State of Alaska. BlueCrest provided the AOGCC the notice, addresses to which the notices were delivered, and Certified Mail receipts. 4. No comments or request for hearing were received regarding B1ueCrest's application. 5. The tentatively scheduled public hearing was vacated on February 22, 2017. 6. BlueCrest's application provided sufficient information upon which to make an informed decision. FINDINGS: 1. BlueCrest is the operator and sole working interest owner of the Cosmopolitan Unit, which is located within the Cook Inlet, Kenai Peninsula Borough, Alaska. 2. The proposed Hansen H-14L1 well branch will be a horizontal development well drilled from an onshore surface location of 2368 feet from the south line and 1517 feet from the east line of Section 2, Township 4 South, Range 15 West, Seward Meridian (S.M.) to an offshore bottom -hole location of 3126 feet from the south line and 1921 feet from the east line of Section 29, Township 3 South, Range 15 West, S.M. CO 729 March 15, 2017 Page 2 of 3 3. The surface location for the proposed Hansen H-14L1 lies on private property. The top - of -productive -interval and bottom -hole locations will lie within State of Alaska leases ADL 18790 and ADL 384403, respectively. 4. Hansen H-14L1 will target reservoirs within the Hansen Undefined Oil Pool. 5. Hansen H-14L1 will be located within the same governmental quarter section as development well branch Hansen lA-L1 and development well Hansen H-16. 6. Hansen IA-L1 and Hansen 16 are, or may be capable of, producing from the Hansen Undefined Oil Pool. 7. The well branch path and bottom -hole location for Hansen H-14L1 were chosen —based on reservoir mapping and modeling results —to ensure greater ultimate recovery by maximizing the amount of wellbore open to the reservoirs and extracting oil that cannot be efficiently produced by existing wells. CONCLUSIONS: 1. An exception to the well spacing provisions of 20 AAC 25.055(a)(3) is necessary to allow the drilling, completion, testing, and regular production of the Hansen H-14L1 development well branch 2. Granting an exception to the well spacing provisions of 20 AAC 25.055(a)(3) for the Hansen H-14L1 well will not result in waste or jeopardize correlative rights of adjoining or nearby owners. NOW THEREFORE IT IS ORDERED: AOGCC grants BlueCrest's January 23, 2017, application for an exception to the well spacing provisions of 20 AAC 25.055(a)(3) to allow drilling, completion, testing, and regular production of the Hansen H-14L1 development well branch within the Hansen Undefined Oil Pool. BlueCrest may proceed as long as it complies with all applicable laws, and all other legal requirements. DONE at Anchorage, Alaska and dated March 15, 2017. Hsignature on file// Hsignature on file// Hsignature on file// Cathy P. Forester Daniel T. Seamount, Jr. Hollis French Chair, Commissioner Commissioner Commissioner CO 729 March 15, 2017 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period, the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. TRANSMITTAL LETTER CHECKLIST WELL NAME:�-` /7 PTD: 2-1-7 -- v lb Development Service _Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: c'% L3� ``-Y� POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit / LATERAL No. 2-17--DQ7, API No. 50- Z3/-9-OnS:2- -1fCU-ZCi. V (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -� from records, data and logs acquired for well (name onpermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where sample are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool HANSEN, HANSEN UNDEF OIL - 290100 Well Name: HANSEN H-14L1 _ Program DEV _ Well bore seg PTD#: 2170100 Company BLUECREST ALASKA OPERATING LLC Initial Class/Type DEV / PEND GeoArea 820 Unit 10370 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 Surface Location lies_ within _F_ee-Hans_en;_Top Productive Interval lies in_ADL001.8790_; - - - - - - i3 Unique well _n_ame and number . _ Yes TD lies in ADL0384403.. - - - - - - - - - - - - - 4 Well located in_a_defined_pool - - No_ - - - - - HANSEN, HANSEN UNDEF OIL--290100, governed by statewide spacing. regulations._ 5 Well_located proper distance_ from drilling unit -boundary- Yes - - As planned, this well does NOT conform with statewide spacing requirements._ 6 Well located proper distance_ from other wells. - - - - - - - Yes SPACING EXCEPTION REQUIRED 7 Sufficient acreage available indrilling unit_ No - Well will lie within same governmental quarter section as intervals that are, -or will be, open in wells 8 -If deviated, is_wellbore plat included - - - - - - - Yes Hansen 1AL1 and Hansen H-16._ Operator_ notified 1/20/2017. Application will be submitted_ 9 Operator only affected party - - Yes - - 10 Operator has.appropriate bond in force - - - - - - - - - - - - - Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Appr Date 11 Permit can be issued without conservation order_ - - - - - No SPACING EXCEPTION REQUIRED: Well will -lie within same_ governmental quarter section as intervals -that are, 12 Permit can be issued without ad ministrative_approval _ Yes or will_ be, open in wells Hansen 1AL1 Hansen H-16._ Operator notified 1/20/2017. SFD SFD 3/16/2017 _and - - - - _ - - - 13 Can permit be approved before 15-day wait_ . _ Yes _ SPACING EXCEPTION_ ISSUED: _Conservation Order -No. 729, March 15, 2017. SFD_3/1.6/17 _ 14 Well located within area and -strata authorized by Injection Order # (put 10# in.comments)_ (For_ _NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 15 All wells_within_1/4_mil_e_area_of review identified (For service well only) NA_ - - .. ... ,16 Pre -produced injector: duration -of pre production Less than_ 3 months_ (For -service well only) _ NA_ - - - - - - - - - - - - - - - 18 Conductor string -provided - - - - - - - - N_A_ Conductor set-in mot_her_bore H-1.4_ Engineering 19 Surface casing_ protects all -known_ USDWs - - - _ _ _ - _ _ NA_ _ - - - 20 CMT_vol adequate_to circulate_on conductor & surf_csg _ - - - - N_A- - - - - - - - - - - - - - - - - - - - - - - - - - - - - 21 CMT-vol adequate- to tie-in -long string to -surf csg_ _ - - - - - - - No_ _ _ _ _ _ _ _ 8.5"-window to be cut at.14585' to drill_ lateral. I22 CMT_will coverall known _productive horizons_ - - - _ _ Yes - _ _ _ _ _ _ La -use 4.5" frac liner -sleeves with swell packers. - _ - _ - - - _ _ _ 23 Casing designs adequate for C,_T, B &_ permafrost --------- -- ---- Yes - _ - _ _ - ------------------------------------------------------------- 24 Adequate tankage_or reserve pit - - _ _ _ - - Yes - _ _ _ - - Rig has steel pits. All waste to approved disposal well. _ Hilcorp a& 1 25 If a_ re -drill, has_ a 1.07403 for abandonment been approved . - - . - - _ _ NA . _ . - . - Lateral drilled from moth_erbore. Sundry not required. - - - - - - - - �26 Adequate wellbore separation_proposed_ - _ - _ _ _ - Yes - - - - - close crossing to Cosmo State #1 - - - - - - - - - - - - - - - - - - - - - - - - - - - - 27 If_diverter required, does it meet_ regulations_ _ - - - - - - - - - - N_A_ Wellhead in place._ Will use BOPS_ _ Appr Date 28 Drilling fluid_ program schematic-&- equip_list_adequat_e_ Yes Max formation- pressure= 3462_psi_ Will drill with 10 ppg_mud. GLS 3/13/2017 29 BOPEs, do they meet regulation - - _ _ _ - - - - _ - - - - - - - Yes - - - Blucrest rig has_13 5/8" 10,00.0,psi BOPS - - . - . 30 BOPE_press rating appropriate; test to -(put psig in comments) - - - - Yes - - - - MASP = 2772-psi_ Will test BOPS to 3500 psi - - - - - - - - 31 Choke_ manifold complies w/API_RP-53(May 84)_-- Yes- ------------------------------------------------------ 32 Work will occur without operation shutdown_ _ _ ._ - - - - - - - Yes Need sundry_ approval to hydraulically stimulate well. _ _ _ - - 33 Is presence of H2S gas probable _ _ . _ _ - - - - - - - N_o_ H2S no_t expected .. Rig has sensors and -alarms -- - - - - - - - - - - - :34 Mechanical condition of wells within AOR verified (For service well only) _ser- NA 35 Permit can be issued w/o hydrogen_ sulfide measures Yes _ _ _ _ _ _ _ H2S not observed in nearby Hansen wells. -Rig will have -sensors -and alarms_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Geolo 9y 36 Data presented on potential overpressure zones - - - - - _ _ Yes - - _ Well will kick off in Starichkof_sand. Planned -mud weight 9 ._5-_10,0- g ( ppg)_adequ- - to contr--- Date Apprl 37 Seismic_analys_is_ of shallow gas -zones_ _ NA anticipated pressure of 9.1 ppg_ in the Sta_richkof and Hemlock, which is -based -on offset wells SFD 1/23/2017 38 Seabed condition survey -(if off -shore) - - _ _ NA_ - - - - - - - an_d_MDT measurements of -reservoir pressure_ in nearby _well ---- 39 Contact name/phone for weekly_ progress reports_ [exploratory only] NA_ Geologic Engineering Public Some Collision Potential: Well will pass within 180' of suspended well Cosmopolitan State 1 & within 500' of P&A'd well Starichkof Commissioner: Date: Commissioner: Date Commissioner Date St 1. SFD pT5
