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217-052
THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, Inc. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Sag River Oil Pool, MPU C-46 Permit to Drill Number: 217-052 Sundry Number: 319-394 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this 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. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner� "i DATED this _/ day of September, 2019. -1BDMSH-'5v' SFP 0 5 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n AAc 95 9An �i l - 'i-rv"- its✓� l iva ? 6 `' �' i i 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casingp y ❑� ❑ Other: Install Rev. Slip Loc Assy. 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Numbe , 1,, Hilcorp Alaska LLC Exploratory ❑ Development ❑✓ • Stratigraphic ❑ Service ❑ 217-0 ' 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23576-00-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 423 Will planned perforations require a spacing exception? Yes ❑ No ❑✓ MPU C-46 - 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL047434 / ADL025516 Milne Point Field / Sag River Oil Pool ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 10,430' • 9,011' 10,285' 8,883' 942 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 140' 16" 140' 140' N/A N/A Surface 4,929' 9-5/8" 4,955' 4,650' 5,750psi 3,090psi Production 10,393' 7" 10,416' 8,998' 7,240psi 5,410psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 2-7/8" 6.4/ 13Cr85 / JFE Bear 10,003' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): PHIL Hyd. Retrievable and N/A 9,920(MD) / 8,569(TVD) and N/A 12. Attachments: Proposal Summary ✓ Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑✓ BOP Sketch ❑ Exploratory p ry ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 9/15/2019 OIL ❑✓ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: Wyatt Rivard Authorized Title: Operations Manager Contact Email: wrivard hilcor .com Contact Phone: 777-8547 Authorized Signature: Date: 8/28/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: // (� , -501 _ 1 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test E] Location Clearance ❑{J Other: .¢ /0" L �O �wvv-/Ydf,,t 1. e7 WeY Post Initial Injection MIT Req'd? Yes ❑ No ❑ ,�BDMS�L SEP 0 5 2019 Spacing Exception Required? Yes ❑ No Subsequent Form Required: ! (� y 0y APPROVED BY Approved by COMMISSIONER THE COMMISSION Date: / / 1 jlu— oi)go� 7-4/ 7s -/s ORIGINAL Approved application is valid for 12 months from the date of approval.Submit Form and qty/ Attachmentupl11 Form 10-403 Revised 4/2017 U Hil.p M.A., Lb Well Prognosis Well: MPU C-46 Date: 8/20/2019 Well Name: MP C-46 API Number: 50-029-23576-00 Current Status: Oil Well Pad: C -Pad Estimated Start Date: September 15th, 2019 Rig: WSS Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 217-052 First Call Engineer: Wyatt Rivard (907) 777-8547 (0) (509) 670-8001 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) Current Bottom Hole Pressure: 1817 psi @ 8,750' TVD (Based on current pressure gage BHP Reading) Maximum Expected BHP: 1817 psi @ 8,750' TVD (Based on current pressure gage BHP Reading) MPSP: 942 psi (0.1 psi/ft gas gradient) Min ID: 2.205" ID 2-7/8" XN Nip at 9968' MD Brief Well Summary: The Milne Point C-46 well is a recently drilled Sag River development well. The well's surface casing was fully cemented and hung off a slip style casing hanger as part of a conductor supported wellhead system. The system has since been identified has having the potential to cause wellhead movement in the event of conductor subsidence. In order to fully tie well load back to the surface casing, conductor will be cut and a reverse acting slip style hanger assembly will be installed. Notes Regarding Wellbore Condition • MIT -IA to 3500 psi passed on 7/26/17 Objective: Cut conductor bell nipple below starting head and install Reverse Slip Loc assembly to ensure fully supported by surface casing. Procedure: Pre -Sundry Work Slickline 1. MIRU SL unit. 2. Pressure test to 300psi low and at least 1500 psi high. 3. MU plug setting toolstring and set 2-7/8" XN at 9968' MD. a. Bleed down the tubing pressure to -0 psi to confirm set. 4. RDMO Prep Work 5. Disconnect flowline and instrumentation. 6. Verify tubing, IA and OA pressures have been bled to Opsi. 7. Sniff cellar and adjacent area with multi -gas meter for LEL, CO, H2S and 02• Ensure confined space, egress and ventilation is adequate for operations 8. Vac out gravel from well cellar down to cellar liner to remove residual hydrocarbons. 9. Install fire blankets around the conductor landing ring to protect surface casing holes from hot machining debris. H Hilwrn Alaska, LU Well Prognosis Well: MPU C-46 Date: 8/20/2019 Sundry Work (Approval required to proceed) Surface Casing Support Retrofit 10. Sniff cellar and adjacent area with mutli-gas meter for LEL, CO, H2S and 02. Ensure confined space, egress and ventilation is adequate for operations 11. Flush conductor with waterfrom the conductor starting head valve and while taking fluid returns from the cement return line bull plug. Flush until clean returns are observed. 12. Move in and rig up Well Support Structure. Place rig mats as needed to level out support structure legs. 13. Install BPV and nipple down tree at master valve or tubing head adapter as needed to makeup Wellhead Support Structure adapter flange. 14. Prepare to transfer load to the Well Support Structure. Pretension load cells according to operating manual. 15. Pull 8000 lbs (Wellhead Weight) gradually building up load in 1000 Ib increments. a. Monitor the wellhead for any signs of movement and discontinue increasing tension if movement observed. 16. Increase weight up to 60,000 lbs (50 K preloading) 17. Once pre loaded, begin cutting conductor horizontally at bottom of conductor bell nipple using air arc cutter. a. Monitor load on Well Support Structure in addition to wellhead vertical displacement during cutting operations. a. Maximum dry production casing, tubing and wellhead load= 26#*6750'+6.4#*9920'+8K = 247K b. Maintain constant vertical displacement while well support structure is loaded by well. 18. Proceed to cut conductor bell nipple below the starting head then remove conductor bell nipple section. a. Ensure minimum of 12" of clearance between bottom of starting head and top of conductor. b. Record Well Support Structure Load in WSR once conductor fully loaded. 19. Leave remaining bell nipple section engaged in starting head. Bevel as needed to ensure smooth entry of slip assembly. 20. Place each half of Reverse Slip Loc assembly around surface casing, bolt halves together. 21. Install energizing plate halves at 90 degree offset from slip assembly such that joint between halves are perpendicular to slips. 22. Lift Reverse Slip Loc up inside conductor starting head. 23. In a criss cross pattern, begin to tighten bolts on energizing plates initially to 50 ft -lbs on first pass then to a final torque of 100-125 ft -lbs on second pass. 24. Mark casing at the bottom of the Reverse Slip Loc 25. Release tension, observe for any slippage. If slipping occurs, retension and tighten bolts to 150 ft -lbs. 26. Once load is released to Reverse Slip Loc, conduct MIT -OA to 1000 psi to confirm SC integrity. 27. Unbolt and remove the adapter flange 28. Reinstall 5K production tree. 29. Remove BPV and install TWC. Pressure test tree to 5000psi. 30. Re -install flowline and instrumentation 31. Weld centralizer/landing ring onto top of conductor. 32. Reinstall well house and backfill gravel over cellar liner. 33. Install Corrosion Inhibitor in SC by Conductor Annulus up to the conductor top. Slickline 34. MIRU SL unit. Well Prognosis Ih6m, Alaska. Lb Well: MPU C-46 Date: 8/20/2019 35. Pressure test to 300psi low and at least 1500 psi high. 36. RIH and pull 2-7/8" XN at 9413' MD. 37. RDMO 38. Turn well back over to production Attachments: -Wellbore Schematic H Ililoon, Alaska. LLC KB Elea.: 31.5' / GL Dev.: 15' TD =10,430 (ND) / TD= 9,011'(TVD) P8TD=10,289 (MD) / PBTD= 8,883M) SCHEMATIC TREE & WELLHEAD Tree 1 4-1/16" 5M Wellhead Seaboard Weir, w/11" x 5M top flange 4-1/2" Tubing Hanger Milne Point Unit Well: MPU C-46 Last Completed: 7/25/2017 PTD: 217-052 SAFETY NOTE Seaboard conductor supported wellhead. 50-80 Klbs max compressive load. OPEN HOLE/ CEMENT DETAIL 251 bbl Type 1/11, 100 bbl Permafrost'L' in 12-1/4" Hale 7" 72 bbl Class "G" in 8-1/2" Hole CASING DETAII Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 1 164/A-10613/Weld 14" Surface 140' 3 Surface 40 / L-80 / DWC/C 8.835" Surface 4,955' 7" Production 26 / L-80 / DWC/C 6.276" Surface 10,416' TUBING DETAIL 2-7/8" 1 Tubing 1 6.4/13Cr-85/1FE Bear 1 2.441" Surface 10,003' WELL INCLINATION DETAIL KOP @ 1,150' MD Max Hole Angle = 53.05° @ 6,329' MD JEWELRY DETAIL No Depth ID Item 1 2,273' 2.441" STA 11: 2-7/8" 13Cr80 SPMO-1.OM GLM (12/64" Dome) 2 3,457' 2.441" STA 10: 2-7/8" 130r80 SPMO-1.0M GLM (12/64" Dome) 3 4,106' 2.441" STA 9: 2-7/8" 13Cr80 SPMO-1.0M GLM (12/64" Dome) 4 4,786' 2.441" STA 8: 2-7/8" 13Cr80 SPMO-1.OM GLM (16/64" SO) 5 5,465' 2.441" STA 7: 2-7/8" 13Cr80 SPMO-1.OM GLM (Dummy Valve) 6 6,334' 2.441" STA 6: 2-7/8" 13Cr80 SPMO-S.OM GLM (Dummy Valve) 7 7,204' 2.441" STA 5: 2-7/8" 13Cr80 SPMO-1.OM GLM (Dummy Valve) 8 7,945' 2.441" STA 4: 2-7/8" 13Cr805PMO-1.0M GLM (Dummy Valve) 9 8,657 2.441" STA 3: 2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 30 9,275' 2.441" STA 2: 2-7/8" 13Cr80 SPMO-1.OM GLM (Dummy Valve) 11 9,733' 2.441" STA 1: 2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 12 9,784' 2.313" - ' ""' 9Cr XD Sliding Sleeve 13 91831' 2.412" 2-7/8" 13Cr-80 Pressure Intake Gauge (8,494' TVD BKB) 14 9,909' 2.313" 2-7/8" 9Cr X Profile 15 9,920' 2.360" 7" x 2-7/8" 13Cr-80 PHIL Hydraulic Retrievable Packer 16 9,968'2.5"3-,/'7L11",' 9C r XN Profile (2.205" No -Go) 17 9,973' 2.44120 " 2- WLEG —Bottom @ 10,003' PERFORATION DETAII Sand Top (MID) ) Btm (MD) Top (TVD) Btm (TVD) FT Date Status SagI lv'lu5 1 10,135' 8,728' 1 8,753' 1 30 1 7/11/2017 1 Open GeoDynamics 3-1/8" Razor XDP. 6 SPF 60 deg phasing Ref Log: Haliburton LWD 6/19/2017 GENERAL WELL INFO API: 50-029-23576-00-00 Drilled, Cased & Completed by Innovation #16/24/20 Fracture stimulated with 228.11v lbs of 16-20 mesh Carbol3ond proppa nt 7/11/2017 RWO— Recomplete with 2-7/8"13Cr tubing 7/25/2017 Revised by: TDF 8/23/2019 Confidential Business Information As Per 18 AAC 83.165 9-5/8" Reverse Slip -Lock (Split) Installation Operation Approved By: Josh Douglas WEIR PRESSURE CONTROL 9-5/8 Reverse Slip -Lock Assembly (Split) Installation Operation CONTROLLED DOCUMENT Any Printed Copies Are Consbered Uncontrolled. All information in Ibis manual is Proprietary and Confidential and the exclusive property of ® 2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or Instructions, either expressed or Implied, is forbidden without the expressed wntlen permission of Weir Oil & Gas or its suntanned agent(s). Confidential Business Information As Per 18 AAC 83.165 OEM on 9-5/8" Reverse Slip -Lock (Split) P-21476 �MmInstallation Operation Rev: 0 Page: 2 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: Reviewed by Thinh Nguyen Engineer Approved by Josh Douglas Engineering Manager CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All intonation in this manual is Proprietary and Confidential and the exdusive property of ® 2013 seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or Instructions, either expressed or implied. is forbidden without the expressed written permission of Weir Oil & Gas or Its authorized agent(s). Confidential Business Information As Per 18 AAC 83.165 0 Emm Reviewed By: Thinh Nguyen 9-5/8" Reverse Slip -Lock (Split) Installation Operation Approved By: Josh Douglas REVISION AND HISTORY PAGE P-21476 Rev: 0 Page: 3 of 12 Date Approved: Rev Description Release Date 0 Initial Release 10/05/2018 CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive property of* 20135ealooard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or Instructions, either expressed or implied, is fortsidden without the expressed written permission of Weir Oil & Gas or Its authorized agent(s). Confidential Business Information As Per 18 AAC 83.165 TABLE OF CONTENTS 1.0 EQUIPMENT OVERVIEW............................................................................................................ 5 2.0 CASING CUT-OFF........................................................................................................................ 5 3.0 INSTALLATION OF REVERSE SLIP LOCK.............................................................................. 8 TABLE OF FIGURES Figure1: Original Configuration................................................................................................................ 6 Figure2: Cut Made..................................................................................................................................... 7 Figure3: Install Split Halves...................................................................................................................... 9 Figure 4: Install Lower Halves and Install................................................................................................ ] 0 Figure5: Final Installation........................................................................................................................ 12 CONTROLLED DOCUMENT Any printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive properly of ® 2013 seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures. or Instructions, either expressed or implied, is forbidden Without the expressed written permission of Weir Oil & Gas or Its authorized agent(s). 9-518" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 4 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: TABLE OF CONTENTS 1.0 EQUIPMENT OVERVIEW............................................................................................................ 5 2.0 CASING CUT-OFF........................................................................................................................ 5 3.0 INSTALLATION OF REVERSE SLIP LOCK.............................................................................. 8 TABLE OF FIGURES Figure1: Original Configuration................................................................................................................ 6 Figure2: Cut Made..................................................................................................................................... 7 Figure3: Install Split Halves...................................................................................................................... 9 Figure 4: Install Lower Halves and Install................................................................................................ ] 0 Figure5: Final Installation........................................................................................................................ 12 CONTROLLED DOCUMENT Any printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive properly of ® 2013 seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures. or Instructions, either expressed or implied, is forbidden Without the expressed written permission of Weir Oil & Gas or Its authorized agent(s). Confidential Business Information As Per 18 AAr: R-1 I F9 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 5 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: 1.0 EQUIPMENT OVERVIEW The Reverse Slip -Lock (W20932-001) is designed as a retrofit component to an existing well. It will divert the load of the wellhead from the surface casing/conductor and reload it to the intermediate string. 2.0 CASING CUT-OFF 2.1 The original tree configuration should be as shown in Figure 1. For installation of the Reverse Slip -Loc the bell nipple will be removed and the 9-5/8 casing exposed. 2.2 Pull tree in tension then do casing cut-off with minimum 12.0" clearance between the bottom of the casing head and 20" conductor. See figure 2. 2.3 The slip loc design requires that the remaining bell nipple remain in the bottom of the SOW prep. If the bell nipple is not welded at the top retain this piece for further use. 2.4 Bevel prep as required to ensure a smooth entry. CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All intmmation in this manual is Proprietary, and Confidential and the exdusive property of 02013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, Procedures, or instructions, either expressed or Implied. Is forbidden without the expressed written permission of Weir Oil & Gas or Its authoruned agent(s). Confidential Business Informatinn Ac Par 1A o nr% Q1 1 CM, 9-5/8" Reverse Slip -Lock (Split) Installation Operation P-21476 Rev: 0 1 Page: 6 of 12 Reviewed By: Thinh Nguyen I Approved By: Josh Douglas Date Approved: CASING HA 13-5/8 X 9- 13-3/8 SC 20 CASING 9-5/8 CA Figure 1: Original Configuration 3-5/8 5M CONTROLLED DOCUMENT Any printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive property OtO 2013 seaboard HoMings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or ins"dions, either expressed or implied, Is forbidden Without the expressed wniten pennission of Weir 0118 Gas or its authon¢ed agent(s). Confidential Business Information As Per 18 AAC 83.165 ONCE MEN 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 7 of 12 Reviewed By: Think Nguyen Approved By: Josh Douglas g Date Approved: CASING HA 13-5/8 X 9 CAS 20 CASING 9-5/8 CA FIGURE 1 Figure 2: Cut Afade 3-5/8 5M CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information in his manual is Propnetary and Confidential and the exclusive ProPeny of 02013 seaboard Holdings Inc. Any reproduction or use of the Calculations, drewings, photographs, procedures, or instructions, either expressed or implied is forbidden without the expressed written permission of Weir Oil & Gas 01 its authorized agent(s). Confidential Business Information As Per 18 AAC 83.165 N MEMO I9-5/8" Reverse Slip -Lock (Split) MEN Installation Operation Reviewed By: Thinh Nguyen I Approved By: Josh Douglas 3.0 INSTALLATION OF REVERSE SLIP LOCK 3.1 3.2 3.3 3.4 P-21476 Rev: 0 Page: 8 of 12 Date Approved: Visually inspect the Slip Set thread for any damage. Place a board or plate over the 20" casing to provide a work area. Qj WARNING -SAFETY ALERT -- Each half of the Reverse slip-loc is approximately 50lbs, utilize proper7methods using provided .500-13UNC lift holes. Using proper lifting equipment place each half around the 9-5/8 casing. Bolt the two halves together. CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All infomralion in this manual is Proprietary and Confidential and the ex'shi- a property of 02013 Seabosrd Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or Implied, is forbidden Without the expressed written permission of Weir Oil & Gas or its authorized agent(s). Confidential Business Information As Per 18 AAC 83.165 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 9 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: Figure 3: Install Split Halves CONTROLLED DOCUMENT Any Panted Copies Are Considered Unwntrolled. All information in this manual is Prolsilt' y and Canfidential and the exclusive property of 02013 Seaboam Holdings Inc. Any reproduction w use of the calwlations, drawings, photographs, procedures, 0, instructions, either expressed Or implied, is forbidden without the expressed Written permission of Weir Oil 8 Gas or its authonz d agent(s). Confidential Business Information As Per 18 AAC 83.165 I 9-5/8" Reverse Slip -Lock (Split) Installation Operation Reviewed By: Thinh Nguyen I Approved By: Josh Douglas Figure 4: Install Lower Halves and Install CONTROLLED DOCUMENT P-21476 Rev: 0 Page: 10 of 12 Date Approved: Any Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive property of ® 2013 seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or Instructions, either expressed or implied, is fotbldden w4hout the expressed written PWmission of Welr Oil B Gas or its authodzed agends). Confidential Business Information As Per 18 AAC 83.165 ONCE 9-5/8" Reverse Slip -Lock (Split) 1-21476 Installation Operation Rev: 0 Page: 11 of 12 :Reviewed:By: Thinh Nguyen Approved By: Josh Douglas Date Approved: 3.5 Install bottom plate (2X) 90 degrees from each other such that the splits do not align. 3.6 Install nuts hand tight. 3.7 Using appropriate lifting equipment insert the Reverse slip-loc into the bottom of the casing head. See Figure 3. © WARNING — SAFETY ALERT _ To properly function the Reverse slip loc must fit inside the casing head. If the nipple from Section 2.0 was removed utilize it when installing the Reverse slip loc ll to ensure a tight fit. The bolts are not designed to hold the two halves together under loadino. 3.8 Loosen the bolt and nut keeping the two halves together, but do not remove. 3.9 Remove cap screws retaining the slip segments. 3.10 Pull final tension required. 3.11 3.12 3.13 The Reverse Slip Loc is designed to a maximum of 50% of casing plain end yield. In an alternating criss-cross pattern tighten the bolt pattern to 50 ft -lbs in the first pass, and to the final torque of 100-125 ft -lbs in the final pass. Make a mark on the casing at the bottom of the reverse slip lock. Release tension and observe for any slippage tension and apply up to 150 ft -lbs of torque on occurs, contact engineering. CONTROLLED DOCUMENT If slippage has occurred re-pull the bolting. If slippage still Any Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidentialfand the exclusi Procedures, or ins[vctlons, sumer expressetl or implied.d,is ve property of ® 2013 Seaboard Holdings Inc. Any reproduction ar use of the calculations, drewings, photographs, oNitltlen vnthouI the expressed wdnen permission of Weir Oil & Gas or its authorized agent(s). Confidential Business Information As Per 18 AAC 83.165 Reviewed By: Thinh Nguyen CASING HF 13-5/8 X 9 20 CASING 9-5/8 CA 9-5/8" Reverse Slip -Lock (Split) Installation Operation Approved By: Josh Douglas Figure 5: Final Installation CONTROLLED DOCUMENT P-21476 Rev: 0 1 Page: 12 of 12 Date Approved: 3-5/8 5M Any Pnnled Copies Are Considered Uncontrolled. All information in this manual is PmPrietary end Confidential end the exdusive roe of ® 2013 Seaboard Holdings Inc. An 9 P reproduction or use of the Calculations, drewin s, hotogrophs, procedures, or instmdions, either expressed or ImcludL Is forbidden without the expressed wnnen Perrnle5l0n of Weir Oil 8 Gas or its authorized agent(s). • i o i , . no o 0) 0 0 IN nI N Nl N N- •Q z CO U) E o a N r6 0 Z_ Z W W T co Z C C '07 LLI nI Q Q 0 C Z ccl N V 7 a a n e- W W c I.L O C d. _U NI. NI Tr NI Q c j = = a p 0 I N y NI NI 15 Z 7 v 0 0 a > > >; c c O O 2 1- ?' >• 0 N. NI cI (0 CO . I- I- a) Lo w z Z E E-'I E-I JI -�I C C E U U UI UI p Tr c it HTr I it I-I Hl HI JI �I �.I D D U al 0 aI 0 00 (n (7 H 1- D p P p gm � i� � �I 0 DI =I a a a < iI I I I gl gl pp n U°' m m aaiiii cc w w ZZ �� � aicmU o m 0t 000 ° � iE pa co0a - iia _ ia iia iia iia 5LLw it i y o2- g2 c (.)25 (.)g a '()g ()g (fi - 0 I c.) I 'c.) 3 E 'c I 'c IE 'c I 'cIE c I c I c 1 0 O ca 'cac O O Ea' O 0 O E-co O O O cO Q. O 2. 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VV yU aN n mO 1 E a p0 o Ti 0 a o d• ° ° u- U 20 0 °a [w _, i a 0 0 0 i STATE OF ALASKA AUG 0 9 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AREDEOX la.Well Status: Oil ❑� ,, Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20AAC 25.105 20AAC 25.110 Development ❑✓ ' Exploratory ❑ GINJ ❑ WINJ ❑ WAGE WDSPL❑ No.of Completions: _1 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6. Date Comp.,Susp.,or 14. Permit to Drill Nurrytlgr/ Sundry: 4,-.1) Hilcorp Alaska, LLC Aband.: 7/25/2017 ,. . 217-052/317-299/317-322 3.Address: 7.Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 May 18,2017 50-029-23576-00-00 ' 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: 1 Surface: 923'FSL,2369'FEL,Sec 10,T13N, R10E, UM,AK June 18,2017 MPU C-46 ' Top of Productive Interval: 9. Ref Elevations: KB: 41.5 17. Field/P•• - : . - -Id 2538'FNL,2194'FEL,Sec 15,T13N, R10E, UM,AK GL:15' BF:15' Sag River Oil Pool • Total Depth: 10. Plug Back Depth MD/TVD: 18. Prope i- - •- : 2611'FNL,2331'FEL,Sec 15,T13N, R10E, UM,AK 10,285'MD/8,883'TVD • (SHL)ADL047434/(TPH/BHL)ADL025516 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 558093 y- 6029204 Zone- 4 10,430'MD/9,010'TVD . LONS 84-123 TPI: x- 558300 y- 6025745 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 558163 y- 6025670 Zone- 4 N/A 1,860'MD/1,800'TVD 5. Directional or Inclination Survey: Yes U (attached) No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and,pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first.Types of logs to be listed include, but are not limited to: mud log,spontaneous potential, gamma ray, caliper, resistivity,porosity, magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary CAL-Y/EDTC/MAST/USIT-D/USRS-B(CEMENT LOG),CAL-Y/EDTC/MAST/USIT-D/USRS-B(CASING PROFILE IMAGER) CAL-Y/EDTC/MAST/USIT-D/USRS-B(CEMENT BOND LOG),DGR-EWR-ADR-ALD-CTN 2"15"ND C-46 ✓ DGR-EWR-ADR-ALD-CTN 2"/5"ND C-46PB1,ROP-DGR-EWR-ADR-ALD-CTN 2"15" MD C-46 ROP-DGR-EWR-ADR-ALD-CTN 2"15"MD C-46PB1 CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH ND AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT. PULLED 16" 164# Al 06B Surface 140' Surface 140' Driven Stg 1 L-435 sx/T-225 sx Z 9-5/8" 40# L-80 Surface 4,955' Surface 4,650' 12-1/4" Stg 2 L-315 sx/T-340 sx Stg 1 L-138 sx 7" 26# L-80 Surface 10,416' Surface 8,998' 8-1/2" Stg 2-145 sx 24.Open to production or injection? Yes Q No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/ND of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number; Date Perfd): 2-7/8" 10,003' 9,920'MD/8,569'ND 10,105'MD-10,135'MD/8,728'-8,753'ND 3-1/8"6 SPF 7/11/17 k. j ,gPLE1 ION 26.ACID, FRACTURE,CEMENT SQUEEZE, ETC. DATEWas hydraulic fracturing used during completion? Yes 0 N ❑ -/21 -7 . 1 Per 20 AAC 25.283(i)(2)attach electronic and printed information VERIFIED DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED _‘=---- -Frac Focus Attached** 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 8/2/2017 Gas Lift Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 8/5/2017 24 Test Period —"821 1636.1 191 N/A 1992 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 230 733 24-Hour Rate —4 821 1636.1 191 38 VO Q. Form 10-407 Re i ed 5/2017 CONTIIyJJED O PAGE 2 ubmit ORIGINIAL onl JINN � , io'(S Ili 7/7 ��_(� RBDMS �.� AUG 1 0 201 • 28.CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cores: Yes ❑ No If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No Q Permafrost-Top If yes, list intervals and formations tested,briefly summarizing test results. Permafrost-Base 1,860' 1,800' Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval 10,105'Sag 8,728' information, including reports, per 20 AAC 25.071. Ugnu 3,930' 3,720' Schrader NA 4,480' 4,120' HRZ 7,030' 6,150' Kuparuk C 7,870' 6,850' Miluveach 8,500' 7,400' Kingak 9,620' 8,320' Sag D 10,060' 8,695' Shublik 10,150' 8,770' Ivishak 10,360' 8,950 Formation at total depth: Ivishak 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys,Csg and Cmt Reports,Surveillance Graphs, Frac Focus. Information to be attached includes, but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Paul Mazzolini Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdinger p[Nhllcofp.co171 Authorized \ no -� ' FoR PRuL. MA22OUt. t Contact Phone: 777-8389 Signature: \ ` , Date: g-q-loth INSTRUCTIONS General: form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC,no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item lb: Well Class-Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 19: Report the Division of Oil&Gas/Division of Mining Land and Water: Plan of Operations(LO/Region YY-123), Land Use Permit(LAS 12345), and/or Easement(ADL 123456)number. Item 20: Report measured depth and true vertical thickness of permafrost.Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and,pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension, or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results,including, but not limited to:porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including,but not limited to:core analysis,paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only • Milne Point Unit SCHEMATIC Well: MPU C-46 Last Completed: 7/25/2017 Hilcarp Alaska,LLC PTD: 217-052 KB Elev.:31.5'/GL Elev.:15' TREE&WELLHEAD Tree 4-1/16"5M 1. Wellhead Seaboard Weir,w/11"x 5M top flange 16„ 4-1/2"Tubing Hanger OPEN HOLE/CEMENT DETAIL i. 4- ' 9-5/8" 251 bbl Type I/1I,100 bbl Permafrost'L'in 12-1/4"Hole 7" 72 bbl Class"G"in 8-1/2"Hole f$ (� CASING DETAIL ES Cementer .. @1,899 ';;, Size Type Wt/Grade/Conn ID Top Btm I 16" Conductor 164/A-106B/Weld 14" Surface 140' y 9-5/8" Surface 40/L-80/DWC/C 8.835" Surface 4,955' 7" Production 26/L-80/DWC/C 6.276" Surface 10,416' r' TUBING DETAIL fS e,SWo' 2-7/8" Tubing . 6.4/13Cr-85/JFE Bear 2.441" Surface 10,003' 9-5/8" '4 ' WELL INCLINATION DETAIL 4---:::::'Wre KOP @ 1,150' MD Max Hole Angle=53.05°@ 6,329' MD JEWELRY DETAIL No Depth ID Item a� w• , 1 2,273' 2.441" STA 11:2-7/8" 13Cr80 SPMO-1.0M GLM (12/64" Dome) 9' 2 3,457' 2.441" STA 10:2-7/8" 13Cr80 SPMO-1.OM GLM (12/64" Dome) 3 4,106' 2.441" STA 9:2-7/8" 13Cr80 SPMO-1.0M GLM (12/64" Dome) 4 4,786' 2.441" STA 8:2-7/8" 13Cr80 SPMO-1.0M GLM(16/64"SO) `' ' 5 5,465' 2.441" STA 7:2-7/8" 13Cr80 SPMO-1.OM GLM (Dummy Valve) S1+C,---- 1-11 6 6,334' 2.441" STA 6:2-7/8" 13Cr80 SPMO-1.OM GLM (Dummy Valve) 7 7,204' 2.441" STA 5:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 4 8 7,945' 2.441" STA 4:2-7/8" 13Cr80 SPMO-1.OM GLM(Dummy Valve) it II 9 8,657 2.441" STA 3:2-7/8" 13Cr80 SPMO-1.OM GLM (Dummy Valve) 12 10 9,275' 2.441" STA 2:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) I 13 11 9,733' 2.441" STA 1:2-7/8" 13Cr80 SPMO-1.OM GLM(Dummy Valve) 12 9,784' 2.313" 2-7/8"9Cr XD Sliding Sleeve l� i E—1 14 13 9,831' 2.412" 2-7/8" 13Cr-80 Pressure Intake Gauge(8,494'TVD BKB) 4 14 9,909' 2.313" 2-7/8"9Cr X Profile ' ` . A 15 15 9,920' 2.360" 7"x 2-7/8" 13Cr-80 PHL Hydraulic Retrievable Packer 16 9,968' 2.205" 2-7/8"9Cr XN Profile(2.205" No-Go) I al 16 17 10,003' 2.441" 2-7/8"WLEG `r f PERFORATION DETAIL i 5k4 44 44 14 17 Sand TopB I' t• (MD) Btm (MD) Top(TVD) Btm(TVD) FT Date Status Sag 10,105' 10,135' 8,728' 8,753' 30 7/11/2017 Open GeoDynamics 3-1/8"Razor XDP. 6 SPF 60 deg phasing sag Ref Log: it y V GENERAL WELL INFO ' 1 : - API:50-029-23576-00-00 7" f `" " _ 11k: Drilled,Cased&Completed by Innovation#1 6/24/2017 TD=10,430(MD)/TD=9,011'(TVD) Fracture stimulated with 228.1M lbs of 16-20 mesh PBTD=10,285'(MD)/PBTD=8,883'(TVD) Ca rboBond pro ppa nt 7/11/2017 RWO—Recomplete with 2-7/8"13Cr tubing 7/25/2017 Revised by:PC 7/27/2017 • .n Hilcorp Energy Company Composite Report Well Name: MP C-46 Field: Milne Point County/State: ,Alaska (LAT/LONG): evation(RKB): API#: Spud Date: 5/18/2017 Job Name: 1710173D MPC-46 Drilling Contractor Innovation AFE#: 1710173D AFE$: 5/16/2017 Secure stairways and landings. Ready modules for demob. Peak on location @ 0900 hrs. PJSM, Demob rig from B-pad @ 1400 hrs. On C-Pad location @ 1700 hrs.;Demob/Mob rig shop and spot on Iocation.;R/D satellite camp. Demob from B-Pad to C-Pad and setup same. Spot sub over C-46 slot. Spot catwalk.;Spot pipeshed,pits and motor complex. R/U stairways and landings. Spot containment and cuttings box.Begin hooking up service lines. Prep pits to take on spud mud. Bring on steam throughout rig.;Witness Notification for upcoming diverter test sent to AOGCC via email @ 03:44 hrs(5-17-17). Peak Released @ 0500 hrs 5/17/17 5/17/2017 Continue R/U on C-46:Finish install steam traps.,.Bring water on line.Re-work cutting box and berm same.Button up MP's.Redress shaker bed inserts.Assist electricians with Rig plug in.;RU flow line sleeve extensions.RU out riggers on sub.Misc maintenance on conveyor.Spot secondary shacks/conex's.Stage mud product on pad.Scope derrick and bridle down.RU conductor valves.;Lay cords for Camp and rig shop Hi Line.Safe out landings and walk ways.;RU conductor valves.Install comp flange on Kill Line.check PVT system.Check all limits on DRWKS/TD.Work on rig Acceptance check list.Move FW around through all lines in pits.;Prep for N/U.PT Mud Line to 2500 psi.House keep through out rig.Test run handling equipment in shed.;Grab Stack,Set and Tq Same.MU Knife Valve &2 diverter sections.Stage Koomey hoses.;Continue making up diverter line between sub base and cattle chute. Modify riser to fit w/high well head(7.5"cut off riser). Install same w/new air boot.Flange up flowline and install drip pan.;Hook up drain lines. Hook up koomey lines and charge koomey unit. Finish pre rig acceptance checklist.;M/U wear bushing running tool. Install 13-5/8 wear bushing w/12-3/8"Pass through I.D.;P/U and rack back 105 stds 5"DS-50 drill pipe. Tq connections to 40k. Drift=3.15". Update AOGCC via email @ 0330 hrs of upcoming diverter test @ estimated 6-7 am.;Bring on spud mud into pits @ 04:00 hrs.;M/U and rack back 17 jts 5"HWDP w!jars.Drift=2.83".;Hauled 650 bbls H2O from 6 mile lake for total=650 bbls Note:AOGCC rep Matt Herrera waived witness to diverter test Rig accepted @ 18:00 hrs. 5/18/2017 Test LEL,H2s and 02 alarms, PU 1 Stand DP.Fgnction test Diverter System.Bag close 5 Sec.Knife Open 5 Sec.Accumulator:3000 start,2050 After,14 Sec 200 psi,40 Sec.Full Recovery.;Prep to PU BHA.Stage tools on Rig Floor.;Hold Pre Spud Meeting with all parties.Discuss Muster areas.Discuss Conductor Broaching.Discuss Rig Evacuation.;MU BHA with Baker 12.25" 606 PDC Bit,Sperry Mtr and HWDP.Tag @ 86'.;Clean out conductor from 86'to 164'.Control Drill staging pump to 500 GPM/560 psi/30 RPM/1.5Tq.;Drill formation from 164'to 280'.460 GPM/550 psi/30 RPM/1.5Tq/100 to 125 ROP.Encountered some large gravels,but were able manage flow line with jetting.;Did not have to shut down to clear flow line while drilling to 280'. CBU x3 @ drilling rate.;TOH setting back Wt Pipe to Mtr.;Blow Down TD.P/U Mtr/MWD assembly as per Sperry to UBHO Sub.Rig up GYRO while Up Loading MWD.;Orient UBHO.Grab DC's.UD HW.Run Gyro to 273'for Survey.;Drill 12.25"surface Hole F/273'-T/645'MD(645'ND). 1k WOB,425 gpm,870 psi,70 rpm,1.5k tq on 72k up/dn/rot. Gyro svy's.;Drill 12.25"surface Hole F/645'-T/1084'MD(1084'TVD). 2k WOB,500 gpm,1095 psi,80 rpm,1.9k tq on 82k up/dn/rot. Continue w/Gyro svy's.;Screened up @ 516'from 80's to 100's. Encountered significant sand w/clay @ est 600'and and had to screen back down to 80's. Able to screen back up to 100's @ 1000'MD w/no issues.;Last svy @ 918'MD/918'ND-6'Right,1.5'Low w/6.15'distance to plan.;Hauled 390 bbls H2O from 6 mile lake for total=1040 bbls Hauled 401 bbls cuttings to G&I for total=401 bbls Daily losses to formation 0 bbls for total=0 bbls 5/19/2017 Drill 12.25"surface Hole F/1084'-T/1496'MD(412'=69 ft/hr AROP). 2k WOB,550 gpm,1305 psi,80 rpm,2k tq on KOP @ 1250'MD. Continue w/Gyro svy's.;Drill 12.25"surface Hole F/1496'-T/1800'MD(305=76 ft/hr AROP). 6k WOB,550 gpm,1550 psi,80 rpm,2.2k tq on 3 clean MWD surveys from 1292-1418',Put gyro on standby.;1 more clean MWD survey and then got a hot survey,Run gyro again.The next MWD survey was clean again,Put Gyro back on standby.;CBU 2x @ 1800'MD. Rot and recip pipe @ 550 gpm,1500 psi to reduce ECD's f/10.2 T/9.8.;Drill 12.25"surface Hole F/1800'-T/1955'MD(155'=103 ft/hr AROP). 4k WOB,550 gpm,1550 psi,80 rpm,3.3k tq on Release Gyro @ 1900'MD.;Drill 12.25"surface Hole F/1955'-T/2660'MD(705'=118 ft/hr AROP). 5k WOB,470 gpm,1235 psi,80 rpm,6k tq on 9.9 ECD's,24 units BGG.;Drill 12.25"surface Hole F/2660'-T/3255'MD(595'=99 ft/hr AROP). 5k WOB,450 gpm,1185 psi,60 rpm,5.5k tq on 9.9 ECD's,20 units BGG.;Field estimate for base of permafrost @ 1700'ND/1707'MD. Last svy @ 3180'MD,25.1°Inc,161.5°Az=1.3'high,3.5'right,3.7'total distance from plan.;Dump 164 bbls mud and bring on 285 bbls fresh mud to reduce climbing mud temp. Reduced mud temp estimated 4°F. Significant amounts of clay and sand throughout drilling interval.;Hauled 798 bbls cuttings to G&I for total=1199 bbls Hauled 650 bbls H2O from 6 mile lake for total=1690 bbls n 661.-f.,,.4..M1-n 1,1.1,. • . 5/20/2017 Drill 12.25"surface Hole Fl 3257-T/3390'MD 5k WOB,450 gpm,1185 psi,60 rpm,5.5k tq on 9.9 ECD's,20 units BGG.;@ 3365,pump and circulate out 40 bbls 8.9 ppg hi/vis nut plug/condent sweep @ 550 GPM/1625 psi.Back on time,with hole unloading.Screen up to 120's.;Drill F/3390'to 4637' 600 GPM/2085 PSI,80 RPM/8K TQ,WOB 2-10K.PU/SO/Rot 162/126/139 Encounter UGNU Tar from 4032'to 4166'before cleaning up @ shakers.;@ 4625',pump 40 bbls 9 ppg/50 Vis Nut Plug/Condent Sweep w/no inc in cuttings. See 16K Stalls @ 4130'/4200'.;Drill F/4637'-T/4966'MD,4659'TVD(TD). (329'-94 ft/hr AROP) 600 GPM/2100 psi,82 RPM,10.2k tq,7 BGG SB OA base @ 4760'MD as per Geo.;CBU 4x @ 4966'MD. Rot and recip pipe. 600 gpm,1820 psi,79%flow. ECD's start 10.2 w/final ECD's 9.6. Reduce YP to 20,vis @ 55 w/9.2 MW. 172k up,137k dn,155k rot.7 BGG.;Pump 35 bbl hi vis sweep @ TD w/no inc in cuttings.;Monitor well(slight losses). Dropped 18"from flowline in 15 min.;Pump out of hole F/4966'-T/3100'MD. 490 gpm,1280 psi w/no rot. Orient HS. POOH w/no significant overpulls or packing off issues.;Extrapolated to TD @ 4966'MD. 3'High,1.3'Left for a total of 3.3'distance to plan.;Hauled 741 bbls cuttings to G&I for total=1940 bbls Hauled 910 bbls H2O from 6 mile lake for total=2600 bbls Daily losses to formation 0 bbls for total=0 bbls 5/21/2017 Continue to pump OOH f/3100'to 2020',w/485 GPM/1320 PSI.See slight pack offs while in slide intervals.Work through with no issues.;Pit Watcher notice increase in cuttings at shaker.CBU from 2050'.485 GPM/1175 PSI.Hole unloaded through 1st half of circulation,cleaning up shortly after BUS.;Continue to Pump OOH from 2020'to 1200'.Losing returns and packing off.Bring on rotary @ 40 RPM/6K Tq, Re establish full returns.@ 200 GPM.Stage pump to 300 GPM/490 PSI.;BROOH from 1200'to 950'.See increase in cutting @ shaker.Mostly clays.CBU while pulling stand slow.Continue to BROOH to HWDP @ 710'. Attempt to pull on elevators with Swabbing.;Pump OOH from 710'to 500'.Pull on elevators f/500'to DC's.UD DC's.Plug in and down load data.UD MWD tools. Break Bit,Milk Mtr. Bit Graded:1-1-CT-N-X-1-ER-TD.Picture in 0 Drive.;Note:Had significant balling of clays on Bit,Stabs,and tool jts.Pictures in the 0 Drive.;Clean and clear Rig Floor.Prep for casing run.Pull Wear Bushing.;Rig up to run 9 5/8"Csg.RID DP handling equipment.RU Csg Handling equipment. MU Volant Tool.Install WOT Link Extension.RU Power Tongs.;PJSM with all parties on running 9 5/8"Csg.;P/U Shoe track assy.With thread lock.Flash light Jts verify no debris.Verify By Pass Baffle in FC.Pu Baffle adapter.Check Floats.;Note:Note:Reposition Bail Ext Pins away from service loop.Re Position Service Loop Skirting.Adjust U-Bolt on Link Tilt bail clamp.;Continue to run 9 5/8",40#,L-80,DWC/C casing from 124'to 1888'MD. Broke circulation @ 800'MD. Fill on the fly. Top off every 5 jts.;Circulate and condition mud @ 1888'MD. Stage pumps up to 6 bpm,95 psi,53%. Slight losses initially with full returns shortly after. Circulated a total of 60 bbls.;Continue RIH w/9-5/8",40#,L-80,DWC/C csg from 1888'to 3052'MD. M/U @ Bakerlok HES cmt stg tool(6 pins wl 3300 psi to open). 11 bbl loss to midnight depth of 2511'MD. Cont RIH T/3096'MD.;Circulate and condition hole @ 3096'MD. Stg pumps up from 2,4 to 6 bpm,130 psi,53%flow w/slight losses initially then full returns same as before. Circulated a total of 86 bbls. 2 bbl loss.;Continue RIH w/9-5/8",40#,L-80,DWC/C csg from 3096'to 4132'MD. Give notice to cmtrs.;Circulate and condition hole @ 4132'MD. Stg pumps up from 2,4 to 6 bpm,145 psi,53%flow w/slight losses initially then full returns same as before. Circulated a total of 58 bbls.;Continue RIH w/9-5/8",40#,L-80,DWC/C csg from 4132'to 4917'MD. 19 bbl loss for total trip.;Wash down last jt from 4917'to 4956'MD. Stage up to 6 bpm,165 psi,55%flow,220k up,160k dn. R/D WOT casing.Clear rig floor. Bring cmt equipment to floor and stage. R/U cmtrs.;Note:AOGCC notification sent via email for upcoming BOP test(James Lott).;Hauled 551 bbls cutting to G&I for total=2491 bbls Hauled 390 bbls H2O from 6 mile lake for total=2990 bbls Daily losses to formation 11 bbls for total=11 bbls 5/22/2017 UD Volant Tool,Blow down TD,RU HES CMT Head.DSM Witness loading By Pass Plug.Circ and condition lower YP 15,Vis 51.Circ Csg volume X2 @ 6 BPM/385 psi.PU 210/SO156.Loss rate @ 11 BPH w/circ.;PJsm on pumping 1st stage cement.;Pump 1st stage CMT:With cementers,pump 7 bbls water, pressure test lines to 800 psi low,4000 psi. Pymo 54 bbls 10.5 opo tuned spacer with red dye. `S Drop bypass plug,load closing plug.;Mix and pump 435 sxs(200 bbls)Extenda Cern Lead Cement at 11.7 ppg. Mix and pump 225 sxs(51 bbls)Swift CemTail Cement at 15.8 ppg. 6,�. set Drop Shut off Plug.;Displace cmt WI 20 bbls RN f/Cmt Unit r Rig Pump 165 bbls,9.5 ppg mud 5 ,I�Ua /0 Uc gh Cmt Unit 80 bbls RN tJ�( 0/o Rig Pump 104.7 bbls 9.5 ppg mud. Ot Total Displacement @ 369.7 bbls CIP @ 14:30 hrs.;1 st Stage Details: Lost 48 bbls during displacement. Pump Cement @ 5.5 BPM Average. Pump Disp @ 5 BPM Average.Calculated Disp 369.7 bbl,Actual Disp 369 bbl. FCP 847 psi 0 2 BPM.;Bump plug 500 psi over FCP to 1350 psi. Floats held with 3.5 bbls.ac .; oa•c o . . • •- s.Using rig pump,stage pressure up 2730 psi to en ES Cementer.a BU through Stage tool staging up to 6 bpm,bringing all of spacer an.67 bbls green C to surface.Overboarded Total of 173 bbls.;Shu down pumping. Disconnect knife valve. Flush stack and work annular with"Black Wate . •a e :lack Water'through flowline jets and all surface lines.;Continue to circulate through ESCMTR @ 4 bpm,while prepping for 2nd stage cement. Prep pits for displacement. Build blackwater pill. Shut down and line up to cmtrs.;PJSM 2nd stg. Pump 2nd stage CMT: Pump 55 bbls 10.5 ppg tunned spacer with red dye. Mix and pump 315 sxs(243 bbls)Permafrost"L"Lead Cement at 10.7 ppg.;Saw spacer @ 208 bbls lead pumped.Lead cmt @ surface 243 bbls pumped. Shut down and swap to tail. 1 44 is/ Mix and pump 340 sxs(85 bbls)slurry cement at 14.5 ppg. ( 0(F Drop closing plug.;HES pumped 20 bbls H2O. Shut down. Turnover to rig. �yj� � Displace with rig MP#1 @ 5 bpm,170 ICP. Disp w/9.5 ppg mud. s Reduce rate @ 1600 stks to 2 bpm,410 ICP.;Max circ psi 480 @ 1660 stks. Reduced rate to 1.6 bpm trying to re-establish full returns(no success). 4 Total loss returns @ 1780 stks. Bumped @ 1996 stks(144 actual/144.6 calc) w/FCP 411 psi.;Psi up and saw stg tool shift close @ 1381 psi. Held 5 min and bled off. No flow. CIP @ 00:12 hrs. Cmt and displacement pumped @ avg 5 bpm. 228 bbls total cmt to surface.;Bled back.5 bbls 38 bbls lost to hole during 2nd stage cement job. R/D cmtrs and release @ 02:00 hrs.;Drain and flush stack with 1� • • 5/23/2017 Prepare cellar and wellhead. N/D and LID bell nipple. Lift stack and rack back. Remove diverter"T"from cellar. Dress 9-5/8"stump.Install packoff. N/U multibowl wellhead.;Test void 500/5 min,2500/15 min(test good). Remove 4"conductor valves.;N/U 13-5/8",5M Class IV stack. Modify bell nipple and install. Hook up flowline,kill and choke lines. M/U koomey lines. Install drip pans and mousehole. On going pits cleaning.;C/O impeller to 10"on charge pump#1.;R/U BOP test equipment. Set test plug. Fill stack. Attempt body test(Fail). Leaking gland nut,Leaking 5"dart valve,leaking test manifold fittings. Troubleshoot psi drop on choke manifold.;Re-grease and function choke manifold. Svc upper and lower IBOP:Test BOP Pguipment as ppr,pLpcjure w/5"test joint. 250 low/ 4000 high w/5 min hold on each. Chart and record same. (2)failures. 5"dart and super choke. Replace dart. Rebuild super choke.;AOGCC rep Bob Noble waived witness.;Koomey drawdown Test- Start psi 3050 Drawdown psi=1650 200 psi inc-18 secs Full charge-68 sec 6 bottle avg N-2292 psi.;R/D test equipment. Blowdown lines. M/U running tool and set 10"ID wear bushing(RILDS). Continue repair super choke.;Svc rig. Replace several small hydraulic hoses and bring BHA tools to rig floor. Test super choke(good test).;M/U 8.5"Hughes Milltooth w/1.5°ABH mtr. RIH w/HWDP and jars(588.48'total length).;RIH w/singles NC-50(30 jts)F/588'-T/1530'MD. Continue RIH picking up DS-50 F/1530'-T/tag depth of 1884'MD. Fill pipe.;Hauled 707 bbls cutting to G&I for total=4275 bbls Hauled 450 bbls H2O from 6 mile lake for total=4330 bbls n titiiz fnr 4n4n1-1 nr kklc 5/24/2017 Wash down&circ contaminated cmt out F/1884'T/1898'.Tag @ Es Cmt blue and tool on depth. Drill ES cmt tool&work through clean with and without pumps and rot.;Continue running in the hole taking wt @ 8-10k.Attempt to drill through but just pushing down.RIH F/1910'T/3921'Picking up 5"DP. RIH with stands st< . F/3921'T/4800'. Wash down F/4800'T/4836'.Set down 10K.;Crc well clean. Getting contaminated mud back.Dump 85 bbl and continue to clean up mud through out btm up.Lots of contaminated cmt. Rack a stand back.;Test casino to 2900 psi. Chasing slight bleed off.Double shut choke valves and got a solid / test for 30 min. Attempt to bleed down well with super choke and could not bleed down.;Bleed off with Manual choke. Trouble shoot super choke.;Wash and ream down F/4836'T/4870'. Drill cmt @ 600 GPM,20 RPM, Slow rate&drill plug and Baffle adapter @ 300 gpm. Drill plug and Baffle adapter on depth. Work through clean.;Drill cmt F/4873'T/4909'.Drill plug and Float collar Ff 4909'T/4913'. Drill shoe @ 4954'.Work through clean.;Drill rat hole F/4954 T! 4966'. Drill 20'New formation T/4986'.@ 465 GPM,60 RPM.;Pump 30 bbl High vis spacer&displace to 9.5 LSND. 465 gpm,760 psi,55%flow.;Obtain SPR @ 4986'MD/4678'ND w/9.5 MW. Pull into casing @ 4924'MD. R/U test equipment and perform FIT to 12 5 PPG 775 psi,1 bbl pumped,Bled dn over 10 min to 672 psi.1 bbl bled back.;See"O"drive for scanned chart and results. Monitor well(static).;Pump dry job and POOH F/4924'-T/surface. UD 6 jts 5" HWDP. Rack back remaining stds HWDP w/jars. Bit Grade-0,0,NO,A,E,I,NO,BHA.;CIean and clear rig floor.Stage BHA components on floor.;PJSM,M/U 8.5" HDBS MME54 bit,Geo-pilot and MWD. Attempt to RIH. String landed out when cutters on Geo-Pilot entered top of 9-5/8"csg. Made 2 attempts. P/U and re- gauge BHA(ok).;No damage noted to BHA assembly. RIH and tag same depth 25.5'from btm of cutters on Geo-pilot housing. Make 3 attempts. 3rd attempt, BHA went down est 3'. Saw 6k overpull w!breakback.;P/U and inspect BHA. Found 1 housing cutter had slight damage to edge. Inspect backup Geo-Pilot (same build for cutters and gauge profiles). Discuss with DD coordinator and Sperry Shop.;C/O Geo-Pilots. M/U MWD and proof run prior to making up bit. RIH with no issues. P/U and M/U bit. Continue making up remaining BHA. Download MWD.Shallow pulse test(good)450 gpm,520 psi.;Install sources. Install corrosion ring between NMDC and 8.25"integral blade stabilizer.;Hauled 707 bbls cutting to G&I for total=4275 bbls Hauled 450 bbls H2O from 6 mile lake for total=4330 bbls Daily losses to formation 13.5 bbls for total=105 bbls 5/25/2017 Finish picking up BHA.RIH with HWDP T/564'.Shallow pulse test.Good.RIH from derrick through ES cmt tool 0 1900'.Clean. Fill pipe and shallow pulse test @ 2450'.Good. RIH T/4900'.;Slip&cut drilling line.;Service rig.;Wash&Ream down through shoe @ 500 gpm,60 RPM,T/4986'. Saw 6'of fill. Drill ahead Fl 4986'T/5113'at same parameters @ 70-100 fph.;Drop 1.75 ball&pump down at 500 gpm.Ball on seat @ 800 stks. Saw 300 psi pressure drop from 1275 psi to 948 psi. Engage rotary and cutters to make shoulder.Shut down rot and over pull 7K.;Good indication of cutters open 9-7/8"gauge. Pull reamer up to 4945& pump and rot to open hole.Pull reamer in to shoe with no rot.Over pulled 8K @ shoe.Good indication reamer on depth @ 4955'.;Ream down @ 550 gpm,30 rpm,10 k tq,.Stage up rot to 60 rpm @ 9.3 tq. &open up hole from shoe @ 4955'T/5150'Bit depth.;Drill ahead F/5150'T/5291'MD.Staging up parameters To 600 gpm,120 rpm,15 wob drilling @ 30-80 FPH ROPs. Adjust parameters to find best ROPs. Work RPM up to 140,WOB 15-20.;Pumped 30 bbl sweep with no ROP increase.Adjusting parameters for better ROPS. MW 9.5,vis 44.;Drill ahead F/5291'T/5420'MD(129'-AROP 43 ft/hr).500-600 gpm,80-150 rpm,10- 30k wob. Adjust parameters to find best ROPs. Slower than expected ROP w/inconsistent tq and rop.;Pump 25 bbl Condent/Nut plug sweep @ 5343'back on time wf 50%inc(no change in ROP).;Drill ahead F/5420'T/5575'MD(155'-AROP 52 ft/hr).500-600 gpm,80-150 rpm,10-30k wob. Adjust parameters to find best ROPs.Significant stick slip with WOB above 20k.;Various RPM's w/bit wt above 20k. Significant stick slip with WOB above 20k.;Drill ahead F/5575'T/ 5847'MD(27'-AROP ft/hr).600 gpm,1400 psi,80-135 rpm,10-13k tq,15-25k wob. Max rpm's on Riptide 150 as per rep. Continually adjust parameters to maximize ROP.;Hauled 173 bbls cuttings to G&I for total=5395 bbls Hauled 280 H2O from 6 mile lake for total=4950 bbls Daily losses to formation 0 bbls for total=115 bbls 4.6'Low/3.3'/5.7'dist to plan 5/26/2017 Drill 8.5 X 9.875 Hole Ff 5847'T/6224' 377' 62 FPH Average,70-100 FPH on btm. 600 GPM,15-25 WOB, 120-150 RPM.UP/DN/ROT 219/130/155.MW 9.4,ECD 10.3,vis 44.;Drill 8.5 X 9.875 Hole Ff 6224'T/6565' 341' 56 FPH Average,60-110 FPH.600 GPM,1640 PSI.15-25 WOB,140 RPM.UP/DN/ROT 220/125/160.MW 9.4,ECD 10.3,vis 44.Pump sweep @ 6300 100%increase.;Drill 8.5 X 9.875 Hole F/6565'T/6914' 349' 58 FPH Average,60-110 FPH. 600 GPM,1640 PSI.15-25 WOB,140 RPM.UP/DN/ROT 230/136/166.MW 9.6,ECD 10.4,vis 44.;Pump 25 bbl,9.6 mw,160 vis nut plug sweep @ 6800'MD- Back on time w/100%inc in cuttings.Start build and turn @ 6700'MD.;CBU @ 6914'MD. 600 gpm,1540 psi,61%flow,80 rpm,11k tq,6 units BGG.;Monitor well(static).POOH on elevators F/6914'-T/4,963'MD. Pulled clean into casing with reamer and remaining BHA. Hole took proper displacement. No swabbing pulling off btm.;222k up,142k dn. Saw a 8k reduction in up wt after lower BHA entered 9-7/8"hole.Starting up wt from 4946'MD was 214k up. Trip Drill @ 4963'w/31 sec response.;Service Rig. Grease Crown,TDS,w/blocks,drawworks and spinners. Inspect same(ok).;TIH F/4963'-T/5910'MD. Hole took proper displacement.;Grid resistor hi-temp alarm on console. DC chopper breaker tripped. Attempt to reset lx(no go). Call out rig electrician. Kelly up @ 5910' MD. Break circulation and begin weighting up.;Circulate @ 500 gpm,1045 psi,59%flow. Wt up system from 9.6 to 10.4 MW while troubleshooting drawworks. Maintain 1.25%lubes by vol active mud system.;Last Survey @ 6882'MD-.5'low,4.3'right of plan(4.3'distance to plan).;Hauled 399 bbls cuttings to G&I for total=5794 bbls Hauled 510 bbls H2O from 6 mile lake for total=5460 bbls Daily losses to formation 0 bbls for total=115 bbls • • 5/27/2017 Continue to circ @ 300 gpm while working Draw works&replace wires to DC Chopper Blower. Work on DC Chopper breaker and starter. Function test good. Bring MW up to 10.4 While waiting on rig.;RIH Fl 5914'T/6305'.Set down 10k.PIU&work through on elevators. RIH,Fl 6305'T/6850'.Wash down @ 80 RPM,600 GPM,T/6914'No fill.No losses for the trip.;Drilling ahead, F/6914'T/7230'(316'@ 45 FPH Average)60-80 On btm.600 GPM,1900 PSI.140 RPM,12K TQ.MW,10.4 ECD 11.2.Lubes @ 1%.;Drilling ahead, F/7230'T/7545'(315'@ 53 FPH Average)60-80 On btm.600 GPM,2100 PSI,61%flow, 25k WOB.140 RPM,12K TQ.ECD 11.3.;Drilling ahead, F/7545'T/7740'(195'@ 33 FPH Average)60-80 On btm.594 GPM,2040 PSI,60%flow,16k WOB. 140 RPM,12-16K TQ.ECD 11.3.Fire drill in pump room @ 04:33(pass). Inc lube to 1.5%.;Last svy @ 7638'MD,36.7°Inc,197.1°Az-1'low,2'right of plan w/ total distance to plan @ 2.3'Extremely slow ROP @ 7470'MD. Saw erratic tq and MWD vibration when reamer reached 7470'depth.;Hauled 342 bbls cuttings to G&I for total=6136 bbls Hauled 390 bbls H2O from 6 mile lake for total=5850 bbls faily Inss?s to fnrmatinn fnr tntal=115 hhls 5/28/2017 prill ahead Fl 7734'T/7920'. Driller noticed increase in gain Ips after zeroing out gain loss the gain was more than H2o Being added.Logs showing increase in MV @7905'@ 10:58.;Shutin well with a static flow of 28%.✓ Shut in pressures on DP 160&251 psi on the casing. \li Consult drilling manager and engineer&decide to perform drillers method.;Took 16 min for initial shut in pressures to reach steady 250&160 psi. vAfter strapping pits an estimated 26 bbl kick was taken in to the well.;drillers method.We wanted to add a safety factor on the casing so we bumped the float @ 1.5 BPM.We were only able to get the casing pressure to 265 and fluid started to inject. We pumped away 5 bbl.;Casing pressure was held constant while bringing the pumps up to rate and a final circ pressure @ 3 bpm was determined @ 310 psi. While circulating the dp started to increase along with casing PSI;and we were pumping fluid away.Pumped away 25 more bbl in the first 1200 strokes pumped.;Dp pressure was held constant @ 310-330 psi having to open the choke to get returns and we started getting a pit gain. @ 4800 strokes(Roughly%btm up) we had gained 52 bbl back to the pits.;The pumps were shut down and the well shut in @ 14:21 to check pressures. Mud returns were coming back cut with water by 3/10s.Good 10.4 going in.Shut in pressures 200 psi on the Drill pipe 405 psi in the annulus;We attempted to bump the float again to get a safety factor due the he pit gain while circulating but were only able to gain 15 psi on the annulus pumping away 7 bbls.New shut in pressures 205 DP 220 Annulus;While were we moving fluid in the pits and getting a plan together shut in pressures changed. AN @ 1600 shut in pressures were 170 Drill pipe 225 annulus;Pumps were started up holding casing pressure constant until up to slow circ rate of 3 BPM @ 320 psi We were monitoring gain loss to maintain from gaining or losing in the pits.;We saw cut mud from 8.9-10.1. We circulated two btm ups losing slightly @ 3 bpm k10 getting back 10.1 consistently after the second btm up.Thinking we have a water flow while circulating @ 3 bpm.;Holding Dp pressure constant.Mud WT in 10.5 17e' ( MWout 10.1. Shut in pressures 168 on the DP&330 on the casing @ 20:15 Adjusted Pressure on annular to 600 psi& moved pipe and are free. UP 250.;Discuss options with drilling team. Decision made to pump LCM pill and displace with 10.7 mud. Wt'd up active to 10.7 w/5 ppb background LCM. M Build Hi Vis 40 ppb LCM pill(10.7 ppg).;Weighted up active to a 10.7 ppg(old mud wt 10.5). Pumped 47 bbl hi vis,40 ppb LCM pill(10.7 MW)displaced with new 10.7 mud.;Once LCM pill was 50%out of bit,we choked back and established est 40%returns.Cont circ @ 3 BPM w/diminished returns until 28 bbls lost and casing psi started more of a gradual descent @ 360psi.;We then slowed our loss rate wl est 70%returns and cont circulating.;After a estimated 127 bbls of 10.7 mud was circulated from bit,we kept choke positioned to minimize G/L and erred on the loss side for remainder of circulation.;Circulated a surface to surface volume(includes 10%for washout and 74 bbls lost during circulation)with 10.7 mud in and 10.55 mud out.;Final DP @ 91 psi,Final casing @ 265 psi. Bled down casing to 239 psi then shut right back in. Casing came straight up to 261 psi and stabilized.;Wellbore was strengthened by est.2 ppg with new numbers over prior shut in numbers of 330 casing shut in w/10.1 MW out. Stripped up @ 248k up free(12k overpull),143k dn.;Our lightest mud wt was a 9 ppg @ btm's up. Max gas @ 9 units w/6-8 units bgg. Bump test gas trap several times throughout operation(good). No gas observed in mud out.;Wt up active from 10.7 to 5/29/2017 Pump 50 bbl 40 PPB LCM pill chase with 10.9 ppg mud with 10 PPB LCM.Spot pill out of bit and slowly close in the choke to push in LCM.Continue to circ losing slightly.;Continue to circ holding slight losses on the choke.Circ sts getting cut mud @ 8.9.Mostly cut at btm up. Started getting cut mud @ 3/4 btm up. After STS came back 10.6.Continue to circ while;maintaining 10.9 going in. Circ additional btm up with MW continuing to climb.to 10.6+-10.7.Lost 150 bbl total with Squeezing LCM pill&circulating.;Bring pumps to 5 bpm maintaining pit volume by adjusting the choke. Circ btm up with MW continuing to climb to 10.9. 5 BPM,490 psi on the DP Casing pressure continuing to drop from 145 to 110.;Continue to circ with 10.9 while bringing wt up to 11.1 on the fly. Circ 11.1 ppg to the bit+700 stks.Starting to lose more and having to open the choke to maintain losses. Shut down pumps due;to riser in the pits floating up and losing suction. Shut in well and monitor. Initial shut in 0 PSI on DP 190 on the annulus.;Shut in well and monitor.Bring on 300 bbl 10.9 in to the pits.Bring wt in active to 11.1.Build 40 ppb LCM pill.;Shut in pressures 0 psi on Annulus. Move pipe though annular.250 up.Good. Move pipe 5'.;Pump 50 bbl LCM pill chasing with 11.1 ppg mud @ 5 bpm holding pit volume level or slightly losing. Circ pill out of the bit and slow pumps slowly close in the choke to squeeze away LCM. Lost 23 bbls;Circ pill out of the bit and slow pumps to 2 bpm.Slowly close in the choke to squeeze away LCM while maintaining circ. Lost 23 bbls Continue pumping @ 5 bpm.;Continue circulating 11.1 mud around @ 5 BPM,DP 420 psi,Csg 70 psi. Increase mud wt to 11.2 in active. Consistently saw 11 ppg mw back.;Pump 45 bbl 11.2 ppg,40 ppb LCM,chase with 100 bbls 11.2 mud then pump another 50 bbl LCM pill. Slow pumps to 3 BPM once pill exited bit. Squeeze 30 bbls pill into formation.;Establish balance G/L until second pill cleared bit. Squeeze 34 bbls LCM pill while circulating pill around BHA. Open choke and continue circ @ 5 BPM with full open choke,Dp 430 psi,Csg 42 psi.;Shut down and shut in-Pressure stabilized DP 66 psi,Csg 96 psi. Shut in with pumps down for 20 min. Screen down shakers from 170's to 120's for LCM retention in system.;Move pipe(248k up,136k dn)no issues. Stage pumps up w/full open choke @ 5 BPM. 420 dp psi,35 psi wl slight losses. Wt up on the fly from 11.2 to 11.4 MW maintaining 15 ppb background LCM.;Reduce rate to 4 BPM,290 psi DP,30 psi Csg due to increasing losses at higher rates.No notable background gas @ anytime during circulation operations. Last MW In/Out 11.4/11.3.;Hauled 171 bbls cutting to G&I for total=6595 bbls Hauled 180 bbls H2O from 6 mile lake for total=6550 bbls Daily losses to formation 183 bbls for total=328 bbls • • 5/30/2017 Reduce rate to 4 BPM,290 psi DP,30 psi Csg due to increasing losses at higher rates.No notable background gas @ anytime during circulation operations. Last MW In/Out 11.4/11.3.;Finish btm up after full circulation with 11.4.Getting 11.3 back.Choke full open.Pumping @ 4 bpm keeping gain loss at 0.;Shut in well. DP 0 psi,Casing 61 psi. Bleed to full open choke to TT.Bled back 25 bbl in 10 min.Shut in for 10 min and pressure on casing @ 45 psi.;Bleed off 10 min to full open choke.Bled back 19 bbl in 10 min. Shut in well and initial shut in pressures @ 34 on casing pressure came to 42 in 20 min. Bled down another 10 min.Bled back 19 bbl.;Shut in pressure 32. Pressure came to 47 psi in 1 hr. Slowly rising. Prep for btm up. Screen down to 80s to conserve LCM material.;Pump btm up with mud cut up from 11.4 to 9.4. Start down hole with 11.6.;Circ 11.6 up to show controlling losses with pump rate. Start off with full open choke and slow pump rate as losses increase after 11.6 reached bit.Continue to slow pumps losing more and more.;We were able to get the 11.6 to the shoe @ 4900'and pumps were @ 1.8 BPM.Shut down and shut in prepping to open up and drill ahead.;Prep pits to drill.Build 100 bbl 40 ppb LCM. #1 Pill 50 bbl=8 ppb SteelSeal 400,7 ppb SteelSeal 50,6 ppb Baracarb 50,10 ppb Baracarb 150,4 ppb Walnut.;#2 Pill=8 ppb each of Baracarb 5,25,50,and 8 ppb of SteelSeal 50.;Monitor well.DP on vac,Casing Shut in pressure 5 psi. Open up well,and drill ahead pumping 100 bbl LCM Bring on pumps @ 375 GPM,@ 1080 psi, Rot @ 60-120 RPM,TQ 10-27K.Had one stall out.;Drill F/7920'T/7982'.Able to get detection. WOB 15-25K.30-120 ROP, Pumping 11.6 losing 65%returns. Pumped away 416 bbl. Building 60 BPH mud while drilling.;Pumped STS.Got trip gas and flow spike at STS.Gas units 128 units. Shut down and monitor well.Seen water cut mud at btm up to 9.4 ppg. Well flowing static. Shut in well at kelly down.;Monitor well. Shut in Casing pressure 0. Shut in DP Pressure 0 Open up well and monitor on TT. Slight losses @.5 BPH.;Attempt to pull out.Well flowing while pulling and loosing when pipe goes in. 11.6 in and out. Bullhead down annulus 50 bbl 11.8 @ 3 bpm 50 psi. Shut down and open annular.Monitor well.Static.;Pull one stand. No swab.Proper displacement. Pulling tight @ 10-30K over. Free down wt. POOH F/7985 T/7837'.Pulling 40K over. Unable to pull through. PU,SO 248K/150K.;Kelly up and back ream 25 rpm,16k-18k tq pumping 200 gpm 160 psi F/7838'T/7837'w/no returns,slow pump to 84 gpm,6 psi,no returns,continue to back ream F/7837'to 7770'. Pumped 74 bbls away.;Note:Kuparuk river bridge went out @ 23:00 hrs.;POOH on elevators F/7770'to 7465'w/25-40k overpulls @ 7709',7694',7684',7620', Flow check well,static loss rate @ 36 bph.Continue POOH on elevators to 7150'.;Started pulling with no drag @ 7665 with 10k overpull @ 7638'and 20k 5/31/2017 Stand back HWDP,L/D BHA T/117'. Loss Rate @ 50 BPH.;PJSM,Remove nuclear sources. Pull Nuclear Sources. Clear rig floor. Static loss rat @ 5 BPH.;Flnish UD BHA.Monitor well.Slight flow. Lost 168 BBL while UD BHA.;Shut in well with Blind Rams.SICP,5 psi in 20 min. Bull Head 45 bbl of 12 ppg mud @ 37 PSI.Monitor well.Still flowing on choke. SICP 8 psi.;Build and pump 50 bbl 12.5.Bull head @ 3 bpm 20 psi.FCP. Shut down and SICP @ 2 psi.Open up well and monitor.Slight losses @+/-10 BPH. RIU Hole fill line on annulus.;Test bops,Annular, Blinds,Super choke,HCR Choke and kill, Choke valve#7,TD Hyd IBOP.Test to 250/4000 psi.Perform bleed test on Super choke.Good. Monitor annulus on TT.Filling as needed.;Losses increasing and over 160 BPH. Fill with 5 bbl every 10 min. R/D all testing equipment&clear floor.;Prep for dumb iron BHA. MIU BHA#3.8.5 Tricone Bit.Full open Jets.Bit sub,Ported float, 8.312 Stab,6-5"HWDP,Jars,1-HWDP,Well commander,4-HWDP. 394'Total.;TIH F/394'to 4920'slow just above shoe(std 72)fill pipe w/38 bbls @ 2000'with no returns,add fluid as needed while RIH to maintain static level @ lower pipe rams.;72 bbl losses TIH,Pumped 29 bbls over calculated displacement while TIH to shoe to maintain fluid level @ lower pipe rams. Continue mixing 200 bbls of 11.6 ppg mud w/15 ppb LCM in pit 5 while TIH.;M/U FOSV and top drive,fill pipe w/49 bbls pumping 2 bpm with very slight returns @1%after 30 bbls pumped.Shut off pump and monitor well,very slight flow,shut in annular and choke.;Monitor casing and DP pressures,0 psi on casing and DP in 30 min,open choke and annular,no flow,well static,monitor same,continue mixing 200 bbls 11.6 ppg in pit 5 and transfer to vac truck,;build another 200 bbls 11.6 ppg in pit 5.;Well slightly flowing,shut in well,monitor DP and casing pressures,49 psi on DP,0 psi csg in 15 min.Bullhead 50 bbls 11.6 ppg down DP and casing,bleed csg and DP to 0 psi.;Monitor pressures,30 psi DP,5 psi csg 10 min,casing and DP pressures stabilized 28 psi on DP and 4 psi on casing. Continue mixing 11.6 ppg mud.;Hauled 57 bbls cutting to G&I for total=6709 bbls Hauled 650 bbls H2O from 6 mile lake for total=7330 bbls Daily losses to formation 665.2 bbls for total=1738.6 bbls. 6/1/2017 Build mud volume up to 500 bbl 11.6 ppg,50 bbl 13 ppg,50 bbl 80 PPB LCM,170 bbl Low wt to chase LCM in to place and open Commander. Trucks with mud still unable to get over bridge.;Shut in pressures on casing 37 psi,DP 23 psi.;Bullhead 15 bbls 13 ppg down drill pipe pumping 3 bpm,170 psi, bullhead 40 bbls 13 ppg mud down annulus 5 bpm,100 psi. open choke,static.Open well,on slight vac.;TIH on elevators f/4920'to 6554'getting very slight returns. PU/SO 165/122.;Well flowing,shut in well,in 10 min csg 15 psi,DP 0 psi.30 min csg stabilized @ 8 psi,DP 0 psi.Line up and bullhead 25 bbls 13 ppg mud down annulus pumping 5 bpm,55 psi.0 psi on csg and DP.;Open choke,open well,static.;RIH on elevators f/6554',30k set down @ 6762',work thru turn section,7065 set down 30k,unable to work past on elevators.4.5 deg dog leg. No returns.;M/U top drive,pump 2 bpm,fill pipe.Wash and ream pumping 2 bpm,100 psi 25 rpm.10-22k tq f/7065'to 7075 with severe packing off f/200 psi up to 1400 psi.work pipe attempting to free packing.;Lost 78 bbls washing and reaming.;Backream out of hole pumping 2 bpm,25 rpm,10-22k tq f/7075'to 6988',continues to packoff seeing up to 800 psi,regaining 50%of flow at 24 to 37%returns.;Pump 4 bpm,210 psi,working pipe,circulate seeing 50%of returns, with 11.6 ppg to 12.5 ppg @ returns.Shut off pump,well slightly flowing.;TIH f/6988'to 7000'with 25k set down.Wash and ream pumping 2 bpm,80 psi,25 rpm,tq 10-12k.very tight hole reaming f/7075'to 7083'@ 4.42 deg dog leg,wash to 7147' PU/SO/ROT 210/140/167.;Continue to wash and ream pumping 2 bpm 80 psi work tight hole f/7147'to 7170'working pipe due to packing off issues up to 1000 psi.Losing 12 bph pumping 2 bpm.MW in/out 11.6/11.3+.;Continue to wash and ream pumping 2 bpm 80 psi work very tight hole f/7170'to 7183'finally working thru,cont to wash and ream tight hole f/7183'to 7190'working thru,packing off to 1000 psi.;Continue to wash and ream 2-3 bpm,100 psi f/7190'to 7283',continue fighting severe packing off issues and tq stalling @ 27k.MW in/out 11.6/11.5.Losses reaming 315 bbls.;Reaming @ 7283'lost returns, slow pump to 1 bpm,6 psi,reciprocate pipe,having to fill annulus with trip tank,when fluid falls below stack.;Pump 45 bbl LCM pill(80 ppb w/bara fiber,walnut,steel seal 400/50,baracabs 1200/400)pumping 4 bpm,550 psi,chase with 85 bbls 9.5 ppg mud,seeing 22%returns.Losses pumping LCM 55 bbls.;Hauled 57 bbls cutting to G&I for total=6768 bbls Hauled 650 bbls H2O from 6 mile lake for total=7980 bbls GG[.LLI.,i..L.L.1-9'f AC G C LLi.. • • 6/2/2017 Circ at 2 bpm while waiting on LCM pill.Establish returns at higher flow rates up to 4 BPM. Working pipe.Losing 70%Returns. Continue to wash and ream to 7280'. 25 RPM,10k TO,35K set downs. Drop opening ball for Commander and see good shift of tool @ 500 stks 1500 psi.;Drop opening ball for Commander and see good shift of tool @ 500 stks 1500 psi. Pressure drop and also gained in flow out and losses slowed down.Continue to circ btm up with return.;coming up to 52%. Starting to gain in the pits.Gained back 100 bbl while circ btm up. Saw mud cut from 11.6 to 10.4.;After btm up started losing again @ reduced rate of 60 BPH. Drop BHA isolation ball,Pump 80 PPB LCM pill to commander and shut in annular.;Bull head out of pipe and chase with 75 bbl.Never saw pressure jump just steady increase on casing pressure up to 115 psi then fell off to 60 @. Bull head pressure 260 psi.;Monitor well.Flowing through choke. Flow slowing down. Open annular and circ btm up at 5 bpm with slight losses. Got LCM pill back indicating loss zone above Well commander @ 7000'. Drop closing ball and close tool @ 1500 psi.;Wash and ream Fl 7280'T/7366'.Very tight hole with pack offs. Hanging upon set downs. Unable to work past 7366'. Not wanting to fall through acting like wanting to drill. Consult drilling Team and Decide to POOH for cmt plugs to P&A and side track.;Lost 100 bbl while reaming. Worked RPMs up to 60,WOB 5-20,GPM 42-400, Pack offs up to 1000 psi,Having to hit jars to get free several times.;Pump out of the hole F/7366'T/5899'. Pulling clean. Pumping 5 BPM 240 psi, Well flowing on connections.;Pump out of the hole F/5899'T/4920'. Pulling clean. Pumping 4 BPM 200 psi, Well flowing on connections.Flow check well,flowing out drill pipe and annulus. Install FOSV.;Shut in well,10 min DP 0 psi,casing 15 psi.Line up and bullhead 25 bbls 13 ppg mud down annulus 3 bpm,60 psi,then bullhead 15 bbls 13 ppg mud down DP 3 bpm,160 psi.shut down,bleed off pressure;Open choke,open bag,well flowing out annulus with slight flow out DP.Sut in well,10 min csg 14 psi,DP 0 psi,30 min csg 17 psi,DP 0 psi.Mix 50 bbls 13 ppg mud in pill pit.;Bullhead 35 bbls 13 ppg down annulus 3 bpm,60 psi,open well,slightly on vac, breakout TD,slight flow out DP,pump 10 bbls 13 ppg down DP,continues to flow out DP.;POOH f/4920'to 4093'M/U TD each std while prepping 50 bbls 13 ppg mud.Pump 20 bbls 13 ppg mud down DP,pipe Dry.BD TD.;Continue POOH on elevators at moderate speed f/4093'to 394'@ HWDP,use double pipe displacement keeping fluid around lower pipe rams. 45 bbls over calculated displacement on trip out.;Well continues on vac.POOH racking HWDP and jars in derrick filling double displacement,LID well commander,pull BHA to surface,14 bbls to fill, close blind rams.;L/D stab,bit sub and bit,bit grade-=0-0-BU-A-E-I- PN-HP.;Pull 10"ID wear bushing,R/U test equipment with 5"test jt and fill line to annulus,Fill stack with water.;Hauled 57 bbls cutting to G&I for total=6825 bbls Hauled 130 bbls H2O from 6 mile lake for total=8110 bbls Daily losses to formation 310 bbls for total=2656.5 bbls 6/3/2017 Finish testing BOPS as per AOGCC after using for well control. Test annular,HCR Kill&Choke, Choke Valve&7&IBOP. Test to 250/4000 psi.;R/D testing equipment&set 10in ID WB.RILD.;P/U 2 7/8 Cmt diffuser with 41/2 in holes per foot for 27'. P/U 21 Joints of 2 7/8 EUE to 651'. RIH with 5"DP T/4920'. Service rig.;RIH with 5"DP F/4620'T/6810'.Driller noticed pipe was not filling. Attempt to fill pipe and break circ.Unable to circ.Work pipe attempting to free string.No over pull or set downs.;Stage up pumps to 2400 psi.Unable to free string.;POOH wet F/6810'T/4573'Standing pipe back in the derrick.;POOH wet F/ 4573'T/655'Standing pipe back in the derrick. 39.05 bbls over calculated displacement to 2 718"tbg.;Swap to 2 7/8"handling equipment,Ready FOSV and XO.7 bbls to fill,POOH wet fl 655'to surface racking 2 7/8"tbg in derrick,1st full jt tubing and stinger totally packed off solid with sand.;L/D 1 jt 2 7/8 along w/ packed jt and stinger.;Monitor well with fluid level static @ lower pipe rams,clean rig floor from wet trip,load 1 jt 2 7/8"tbg into pipe shed to replace packed jt and new stinger. Establish Static loss rate,6 bph.;M/U up new stinger,drift and P/U 2 jts 2 7/8", while starting to P/U last jt tbg,elevators unlatched from jt of tbg on skate,causing elevators to strike employee on left side. Send to MP medic.;Held Post incident review with Rig crew,DSM and Tool pusher.;TIH with 9 stds tbg f/derrick to 655',M/U XO,RIH w/stds 5"DP to 4924'just above shoe. Correct displacement on trip to csg shoe. PU/SO 124/104.;Wash down from 4924'to 5560' pumping 2 bpm,100 psi.;Hauled 57 bbls cutting to G&I for total=6882 bbls Hauled 130 bbls H2O from 6 mile lake for total=8240 bbls Daily losses to formation 9 bbls for total=2665.5 bbls 6/4/2017 Wash down F/5561'TI 7071'.@ 3 BPM,250 PSI. Started taking wt @ 7071'.Bring rate up to 5 BPM @ 320 PSI.;Circ&condition while conducting PJSM for CMT plug.;R/U Cmt lines&Head pin.Circ with rig while Halliburton batched up and lined up. Static flow @ 24 BPH but diminishing when pumps are off.;Line up to Halliburton and pump 5 BBL water.Test lines to head pin to 3000 psi.Good. Pump 20 bbl H2O Spacer,46 BBL 15.3 PPG Premium G Cmt. Chase with 3.85 BBL Water.Line up to rig and pump.;Line up to rig and pump 11.6 ppg WBM&Displace with 115.5 bbl @ 5 bpm.Slow rate to 3 BPM @ 100 BBL Away.Final pressure @ 265 psi. CIP @ 13:39.;Monitor well.Slight flow.Break off circ lines.Well flowing out Dp.;Pull one stand and shut in to stabilize. Let sit two minuets. Open up.No flow out of DP.POOH F/7256'T/6930'Slow. Slight flow out of Annulus.Fill stack with 13#MUD. NO flow on annulus.;@ 6930'Pipe started flowing.Back side dropping. Est Top of cmt 6930. Well out of balance.POOH to 6500'. Drop wiper ball.Circ down @ 5 BPM. Circ btm up. Well flowing 15 BPH while circulating;No cement returns. Shut down Pumps&flow check.,well flowing @ 60 BPH static. Shut in well with annular @ 17:34. Monitor Pressures. SIDP @ 3 SICP 15PSI.Pressures Balanced out after one hr.;SIDP 16&SICP 16 PSI @ 18:34. Strip pipe up and down 10'in 15 min intervals w/no issues. Stabilized w/SIDP 25 PSI&SICP 18 PSI. SIDP 25&SICP 18 PSI @ 20:05.SIDP 25 PSI&SICP 17 PSI @ 21:15.;SIDP 25 PSI,SICP 19 PSI @ 21:30.Bleed off DP to 0 psi,Bleed off csg to 0 PSI,bled back.2 bbls,well flowing 1.9 bbls in 5 min.Shut in well @ 21:35.;Initial shut in pressure on csg 12 psi,0 psi on DP.Consult with Town team,decision made to continue to monitor and record shut in pressures while W/O cement.;Strip pipe up and down 10'@ 30 min intervals.SIDP 0 PSI,SICP 16 PSI @ 22:05/SIDP 0 PSI,SICP 20 PSI @ 23:45/ SIDP 16 PSI,SICP 20 PSI @ 00:00. PU/SO 187/104.;Continue to Monitor shut in pressures,strip pipe 10'up and down every 30 min. SIDP 26 PSI,SICP 20 PSI @ 00:10/SIDP 28 PSI,SICP 22 PSI @ 00:30/SIDP 31 PSI,SICP 23 PSI @ 01:00.;SIDP 29 PSI,SICP 24 PSI @ 01:30/SIDP 28 PSI,SICP 25 PSI @ 02:00,SIDP 26 PSI,SICP 32 PSI @ 06:00. Clean and organize on rig.;Hauled 60 bbls cutting to G&I for total=6942 bbls Hauled 130 bbls H2O from 6 mile lake for total=8370 bbls Daily losses to formation 9.4 bbls for total=2674.9 bbls • • 6/5/2017 Monitor Well. SICP 34 SIDP,26 PSI. Perform bleed down.Bleed down 2.7 bbl in 3 min. Monitor pressures.Pressures came back up to SICP 38&SIDP 25.;Open up well and circ btm up @ 7 BPM. Lost 60 bbl while circulating. MW out at btm up 12ppg. Slow pumps to 3 BPM&gain back 60 bbl. Shut down pump and well flowing @ 36 BPH.;RIH on elevators F/6605'T/6693'. Well flowing back©14 bph.;Wash down @ 3 bpm F/6693'T/6930'. Tag cmt plug at expected depth of 6930'.10 K set down.Good.;Circ btm up at 5 bpm.No mud wt change.Good 11.6 in and out. Lost 10 bbl while circulating at 5 bpm.;Pump 40 bbl 13#slug.Monitor well.Flowing @ 24 bph.POOH with dry pipe Fl 6930'T/5498'.Current flow rate of 8 bph.;Continue POOH f/5498'to 4840'above shoe,flowcheck well for 10 min,well taking fluid,2 bbls to fill. Static loss rate 12 bph.;Continue POOH f/4840'to 655'@ 2 7/8"tbg. Note:hole fill 6 bbls under calculated disp.;Flowcheck well,on slight vac.Swap over to 2 7/8"handling equipment.Ready FOSV,POOH racking 10 stds tbg in derrick f/655'to surf,LID stinger. Note:hole fill.6 bbls over calculated disp.;Monitor well cont.on slight vac,R/U and pull 10"ID wear bushing,R/U test equipment with 5"test jt,R/U trip tank on annulus to monitor well while testing. Flood stack and lines wt fresh water.;Shell test BOP to 4000 psi,good,Test BOP equipment as per procedure w/5"test joint. 250 low/4000 high w/5 min hold on each. Chart and record same. Well is static.;AOGCC rep Chuck Scheve waived witness©15:37 on 6/5/17,Perform accumulator draw down test.Perform hydraulic and manual choke bleed test. No failures.;Close annulus valve.R/D annulus fill line and test equipment. Blowdown lines. M/U running tool and set 10"ID wear bushing(RILDS).;Service drawworks,blocks and top drive.Inspect drawworks brakes.;Hang blocks,cut and slip 100'drilling line. Continue to monitor well.;Hauled 57 bbls cutting to G&I for total=6999 bbls Hauled 260 bbls H2O from 6 mile lake for total=8630 bbls Daily losses to formation 77 bbls for total=2751.9 bbls 6/6/2017 Stage ECP in Pipe shed.PJSM with all hands on PU&Run ECP.PU and MU ECP Per BOT Rep.Pump through to verify floats clear.;TIH with ECP on 5"DP to 5433'.PUW 145/SOW 114'.(PU/SO @ Shoe 131/104K.Displacement correct on TIH.;Wash down(/5433'to 5500'.Circulate Drill string volume w/FCP's @ 2/5 BPM 60/160 PSI FCP.Hold PJSM on setting procedure w/circulating.;RU pump in sub and 5"DP Pup joint below Top Drive.Load Pump Down Plug.MU Top Drive.Chase plug @ 5 BPM/160 PSi.Slow pump to 2 BPM/80 psi,seat plug and hold 630 psi for 5 min.;lnitiate setting/inflating procedure as per BOT rep. Hydraulic release @ 3300 psi.PUH bring on pump @ bpm w/60 psi.Confirm release.Tag ECP w/2K Dn @ 5501'.Placing Top of PKR @ 5477'.;Monitor well for 10 min.Static.Pump 15 bbls 15 ppg slug.Blow down Top Drive.Install air slips. POOH from 5477'to surface,LID running tool. 1 5 bbls over calculated displacement.;Monitor well,on slight vac,swap to 2 7/8 handling equipment.M/U stinger,drift and P/U 2 jts 2 7/8"tbg.RIH w/10 stds 2 7/8"tbg to 715',M/U XO.;Swap to 5"handling equipment,RIH w/stds 5"DP ft 715'to 4900'just above 9 518"shoe. PU/SO 123/104.;Wash down pumping 2 bpm, 80 psi ft 4900'to 5463'. Correct displacement onTdR/U cementers. l: vPU/SO 1351108.;M/U Head pin and circ hose,pump 2 bpm,80 psi.Continue to R/U cementers,PJSM.Clean rig MP screens.Slow pump to 1 bpm 60 psi 1/1 returns.work pipe slow 15'. r Note:circ 2 bpm,15 bph loss rate.;Batch mix 74 bbl 15.8 ppg type 1 cement @ 2:30.Pump 5 bbls of water,test lines to 500 psi low/3000 psi high. 380 sx/45 bbls mix water/1.55 YP.;Pump 20 bbls 11.5 ppg tuned spacer 2 bpm,240 psi. , s�i. , Pump 74 bbls 15.8 ppg type 1 cement 3.5 bpm,300 Pump 6.9 bbls 11.5 ppg tuned spacer 3 bpm,300 psi. 100%returns.;Swap to rig pump,displace w/73.2 bbls 11.6 ppg pumping 2 bpm,23 psi,13 bbls away observed 100%loss rate as soon as cement @ stinger. 0 returns with 73 bbl losses,Pump off @ 05:20,R/D circ hose.;Note:fluid level in annulus @ wellhead level while displacing cement.;Pipe on vac,POOH f/5463' to 4742',pipe started pulling wet @ 5170'. Estimated TOC @ 5170'.;Hauled 70 bbls cutting to G&I for total=7069 bbls Hauled 130 bbls H2O from 6 mile lake for total=8760 bbls Daily losses to formation 94 bbls for total=2845.7 bbls 6/7/2017 Continue to POOH above TOC f/4720'to 4490'.WI 8 bbls over displacement for total trip.;Load Wiper Ball.Pump 1 1/4 Pipe Volume @ 3 BPM/150 psi.Lost 26 bbls during circulation.;Monitor well on Trip Tank with 7.5 bbls back in 30 min.;CBU @ 3 BPMI150 PSI.Showed initial loss of 5 bbls at start and static overall during circulation.;Continue to monitor hole on trip tank.Return @ 21 BPH diminishing to.5 bph.Returned 52.5 bbls to Trip Tank and 60.5 bbls overall.;While Monitor well and WOC: C/O IBOP Actuator on TD.Adjust Drag Chain.Service mud manifold valves.LO/TO and inspect Mud Pump Elec panels.Clean and maintain rig. HES;Blending 60 bbls cement.;RIH on elevators ft 4485'to 4900',wash 2 bpm,120 psi f/4900'to 5230'seeing intermittent 2-4k wob,not a solid tag on plug as of yet.;P/U 30'to 5200',CBU pumping 4 bpm,230 psi with full returns,stage pump to 6 bpm,350 psi Note:see PH on returns increase to 12.5 @ 57 bbls pumped.;Continue to wash down 1.5 bpm,60 psi f/5230'to 5672'with 5k set down @ TOC plug. No losses while washing down.;Circulate @ 5670'CBU pumping 3 bpm 145 psi.Work pipe 15',Fuel and R/U cementers. No losses.;Rack 1 std back,P/U working jt,R/U head pin and hose.Circulate @ 5651'3 bpm,PJSM with cementers. No losses.;Batch mix 60 bbls 15.8 ppg type 1 cement @ 03:00,pump 5 bbls water,test lines to 500/3000 psi.Pump 15 bbls water 3 bpm,300 psi. 295 sx 158 bbls mix water/1.155 YP.;Pump 60 bbls 15.8 ppg cement 3 bpm,320 psi,Displace w/84 bbls 11.6 ppg mud 3 bpm 58 psi ICP,70 bbls away pressure increase to 130 psi,slow pump to 2 bpm,180 psi,FCP 240 psi. Shut off pump.;11.7 bbl losses while displacing cement, Estimated TOC @ 5043' CIP @ 05:25.;R/D circ hose,POOH fl 5651',L/D single working jt w/head pin,POOH wet to 5303'. Note:7 bbls to fill annulus when starting out of hole.;Hauled 182 bbls cutting to G&I for total=7251 bbls Hauled 260 bbls H2O from 6 mile lake for total=9020 bbls Daily losses to formation 33.2 bbls for total=2878.9 bbls 6/8/2017 Continue to POOH above cement f/5303-4550'@ 30-40 fpm.;Load wiper ball,circulate full circulation @ 4 bpm/200 psi.Observed PH spike @ 55 bbls before bottoms up.No losses during circulation.;Monitor well on trip tank.Observe 1 bph flow to static with 2 bbls back to Trip Tank as of 15:30 hrs.While WOC;Clean and organize rig areas.Paint pump room floor.Repair steam heater UPR Utilidoor;Mix mud additives to pre treat mud system.Break down Head pin and working jt.;Continue to WOC,Screen up shakers f/#80 to 100#screens,circulate 4 bpm,250 psi,lower MW f/11.6 ppg to 10.4 ppg,currently @ 11 ppg in/out.;RIH ft 4550'to 4928'just above shoe.Wash down 1.5 bpm,130 psi f/4928'to 5010'w/5k set down @ TOC plug. PU/SO 128/102.;P/U to 5005'circulate 4 bpm,260 psi,continue to condition mud lowering MW f/11 ppg to 10.4 ppg In/out,BD TD.Pull 2 stds to 4926',R/U head pin and circ hose.;Flood surface equip to perform FIT.Close annular,Pump down kill line and DP,perform FIT to 13.5 ppg EMW using existing 10.4 ppg MW.Apply 749 psi.1.24 bbls pumped.;10 sec 747 psi,5 min 729 psi,good test.bled back 1.24 bbls,open annular.;POOH from 4926'to 4000'.;Hauled 271 bbls cutting to G&I for total=7522 bbls Hauled 260 bbls H2O from 6 mile lake for total=9280 bbls Daily losses to formation 11.1 bbls for total=2880 bbls re7 6/912017 Continue to TOH from 4300'to 715', C/O to 2 7/8"Handling Equipment.L/D 2 7/8"Cmt String.Correct Displacement on TOH.;PU Kick Off BHA w/VM-3 Tricone,Mtr w/1.50 bend,MWD Tools.Shallow Pulse Test @ 429'.TIH to 4921'.Wash down& tag TOC @ 4986'.Clean up from 4986'to 5010 and see good hard cement.;Time drill from 5012'to 5110'w/good surveys. 500 GPM/1625 PSI,Up 151 KIDn 114K,Rt 132K,40 Rpm/9-10K Tq.;CBU,Monitor well,static.Pump dry job.;POOH for RRS BHA,TOH from 5110'to 459',rack back HWDP and jars.L/D KO BHA.Bit grade= 0-0-NO-A-E-I-NO-BHA.Load tools out. Correct displacement on trip out.;Service top drive,crown sheaves and pipe spinners. Monitor welI.;PJSM,M/U BHA 7-8.5"PDC bit,geo pilot w/stab,DMC,ILS,DGR,OWD,ADR,ALD,stab,CTN,TM,stab.;Upload MWD,M/U NMDC,shallow pulse test tools. PJSM,Load sources.M/U remaining BHA,IBS,PC,Ghost reamer,6-5"HWDP,Combo jar,1-5"HWDP,well commander,4-5"HWDP= 574.80'.;RIH f/575'to 1563',shallow test MWD.;Hauled 57 bbls cutting to G&I for total=7579 bbls Hauled 260 bbls H2O from 6 mile lake for total=9540 bbls naily IossPQ to formation 0 hhls for total='Ran hhls 6/10/2017 Park @ 1580'Attempt to test tools. Service Rig while assist Sperry with trouble shoot Geo Span Skid.;Assit Sperry W/Geo Span repair.Geo Span packed off with LCM/Bar.C/O relief cartridge valve on TD Lube Oil Pump.Shallow test MWD tools.450 GPM/1050 Psi.;TIH from 1580'to 4915'.;Kelly up,fill pipe.Break circulation and CBU @ 515 GPM/1625 PSI.Monitor well,Well static.RU TIW.;Slip and cut 37'Drill line.Well Static.;C/O TD Lube Oil Pump.Discovered that the Electric Mtr was seized up.C/O both electric Mtr and pump.;Kelly Up,Break Circulation 450 GPM/1290 PSI,60 RPM/10.5 free Tq.Up/DnlRot 162/115/134. Wash f/4914'to 5110'(BTM).;Drill from 5110'-5166'bit depth UR depth 5000'.450 gpm/1560 psi,60 rpm/9-10K Tq,50-100 ROP,12-15 WOB.;Drop ball and open under reamer as per WOT Rep,observed UR open @ 2630 psi.;Drill 9 7/8" hole F/5166'T/5513'(347')AROP 63 FPH(58 FPH on btm) GPM 600,1740 PSI WOB 10-15k,160 RPM TQ 12.5k MW 10.5/59 Vis,11.4 ECD PU/SO/ROT 177/111/132.;Adjust parameters to find best ROPs.Significant stick slip,add 1%lubes to mud.;Drill 9 7/8" hole F/5531'T/5737'(206')AROP 34 FPH(45 FPH on btm) GPM 600,1730 PSI WOB 10-15k,120-160 RPM TQ 10-13k MW 10.4/49 Vis,11.2 ECD PU/SO/ROT 185/11011 39.;Pump 20 bbl hi vis sweep @ 5600',sweep back on time w/50%increase mostly clay. Slip stick continues. Currently 1.33'below the line,1.82'right;Hauled 114 bbls cutting to G&I for total=7750 bbls Hauled 0 bbls H2O from 6 mile lake for total=9540 bbl Hauled 130 bbls H2O from B-Pad for total=130 bbl;Daily losses to formation 0 bbls for total=2880 bbls 6/11/2017 Drill 9 7/8" hole F/5737'T/5973'(236')AROP 39 FPH(47 FPH on btm) GPM 600,1750 PSI WOB 15-20k,120 RPM TQ 10-20k MW 10.4/49 Vis,11.2 ECD PU/SO/ROT 189/108/140.;Drill 9 7/8" hole Fl 5973'T/6350'(377')AROP 62 FPH(75 FPH on btm) GPM 600,1880 PSI WOB 18-20k,150 RPM TO 10-12k MW 10.4/49 Vis,11.4 ECD PU/SO/ROT 201/111/138.;Adjusted parameters as need to mitigate erratic slip stick.Drilled to 6040'and slip stick and Torque went away.No further issues with at all to 6350'.;Pumped 25 bbl hi vis sweep w/walnut @ 6170',sweep back on time,200%increase @ shakers,clay/sand.;Drill 9 7/8" hole F/6350'T/6670' (320')AROP 53 FPH(57 FPH on btm) GPM 600,1900 PSI WOB 18-20k,140-160 RPM TQ 12-13k MW 10.4/52 Vis,11.2 ECD PU/SO/ROT 202/110/147.;Start drop @ 6525'MD,5 deg/100'.;Drill 9 7/8" hole F/6670'T/6970'(300')AROP 50 FPH(51 FPH on btm) GPM 600,2050 PSI WOB 16-20k,140-160 RPM TQ 12-13.5k MW10.4/52 Vis,11.1 ECD PU/SO/ROT 208/112/146.;Pumped 25 bbl hi vis sweep w/walnut @ 6672',sweep back on time, 100%increase @ shakers,clay/sand. Currently 2'below the line,1.91'left.;Hauled 342 bbls cutting to G&I for total=8092 bbls Hauled 0 bbls H2O from 6 mile lake for total=9540 bbl Lln„InA S')(1 MI.U.Linn f.nw,D DnA Fir 1n+nl-Rrdl kkl.r1-,l..I +n fn....ntin,.,o kklo fn.+n+nl-')5Q0 kkl.. 6/12/2017 Drill 9 7/8" hole F/6970'T/7365"(395')AROP 56 FPH(79 FPH on btm)WIPER INTERVAL GPM 600,2090 PSI WOB 18-20k,120 RPM TQ 12-15k MW10.4/52 Vis,11.2 ECD PU/SO/ROT 208/112/146.;@ 7208'ECD spikes to--12ppg.Pump hi vis sweep.ECD down to 11.2 ppg @ 600 GPM,100%Increase of clays.;CBU X 2(/7365' work pipe 60'.600 gpm/1985 psi,85 rpm/12.5 Tq,PU 227K/Dn 128K/Rot 158JK.Monitor static well.;Short trip to shoe on elevators from 7365'.Park inside casing @ 4905'.No issues on trip to shoe.Pass BHA through shoe with no issues or drag.Leave btm w/203k PU/142K Dn,no pump.;Service Rig.;TIH on elevators f/4905'to 7301'w/no issues,wash and ream last std to bottom @ 7365',tag 5'fill.Pump 20 bbl hi vis tandem sweep. PU/SO/ROT 220/125/160 Correct displacement on TIH.;Drill 9 7/8" hole Fl 7365'T/7509'(144')AROP 48 FPH(549FPH on btm) GPM 600,2090 PSI WOB 18-22k,140 RPM TQ 13-15k MW10.4/49 Vis,11.2 ECD PU/SO/ROT 225/125/162.;Tandem sweep back 340 stks early,100%increase,clay. Adjusted parameters as need to mitigate erratic slip stick.;Drill 9 7/8" hole F/7509'T/7695'(186')AROP 31 FPH(38 FPH on btm) GPM 600,2150 PSI WOB 20-28k,140-160 RPM TQ 13-15k MW10.4/49 Vis,11.1 ECD PU/SO/ROT 225/125/162.;Continue to adjust parameters as need to mitigate erratic slip stick. Currently 3'below the line,10.6'Ieft.;Hauled 342 bbls cutting to G&I for total=8434 bbls Hauled 0 bbls H2O from 6 mile lake for total=9540 bbl Hauled 260 bbls H2O from B-Pad for total=910 bbl;Daily losses to formation 0 bbls for total=2880 bbls • • 6/13/2017 Cont to drill f/7695 to 7724'.Encountering slow ROP rates from 2-10 fph.Adjust parameters as needed to gain higher ROP with no success.80-160 RPM/2-28K WOB.Pump 40 bbls low wt/lo vis Nut plug/con;Pump 40 bbls Low wt/Low vis Nut plug/condent sweep to bit.PU 1 ft off bottom w/160 RPM/20-22K Tq clearing sweep from pipe.Feather into bottom and see 50 fph,declining to 5 fph.;Repeat with 2nd Sweep with no change in ROP.Decision made to TOH for BHA change.;Utilizing 11.8 Spike fluid from Vac truck,increase MW in/out to 10.8 for shale stability prior to TOH.Monitor static well.;TOH on elevator from 7724'to the shoe.No issues at all pulling to the shoe.Correct hole fill to the shoe.Monitor static well at shoe.Pump Slug.;TOH on elevators from 4914'to BHA.;Set back Wt Pipe.Lay down BHA to Under Reamer.Blank off jet ports on Under Reamer.MU TD,pump through and open Reamer blades at surface..Some worn teeth but no substantial damage to Reamer.LID UR;PJSM.Remove NUKES.Plug in Down Load MWD.;Cont LID BHA#7. No notable damage to BHA components. Bit grade=1,1,ER,N,X,I,PN,PR.;CIean and clear rig floor. Drain stack. Pull wear bushing.;Set test plug. R/U and test BOP equipment. 250/4000 psi w/5/5 min hold. Chart and record same. AOGCC waived witness via phone by Brian Bixby.;Drawdown test- Start-3100 psi Drawdown-1750 psi 200 psi inc-22 secs Full charge-68 secs 6 bottle N'avg-2317 psi.;Set 10"I.D wear bushing. Prep floor for making up BHA.;M/U BHA#8 w/8.5"rerun bit from BHA#7-NOV PDC SKF1616MP1 D(6x14's)to CTN collar=96'MD.;Hauled 0 bbls to G&I for total=8434 bbls Hauled 260 bbls from B-pad for total=1170 bbls Hauled 130 bbls from 6 mile lake for total=9670 bbls Daily losses 0 bbls for total=2880 bbls(old hole);7724'MD=3.1'low,11.4'left from WP-07. 6/14/2017 Continue MU BHA as per DD.Plug in and up load MWD.Test Gas alarms while uploading.Load Sources,Grab DC's/HWDP/Jar.Total BHA Length= 553.63.;TIH @ 58 fpm as per Trip Speed Schedule f/563'to 2400'.;Break in Geo pilot seals,shallow test MWD tools 400 gpm/995 psi.;TIH as per Trip Schedule f/2400'to 4936'.Fill Pipe.Up Wt 164K/Dn Wt 127K.correct displacement to shoe.;Ease into OH @ 35 fpm to 6210'.;MADD Pass from 6210'to 6016'@ 180 FPH w/200 gpm/500 psi,40 Rrpm/11.5 Tq,Up/Dn/Rot 180K/127K/146K.;TIH f/6016'to 6778'.;MADD Pass from 6778"to 6582'@ 180 FPH w/200 gpm/500 psi, 40 Rrpm/11.8 Tq,Up/Dn/Rot 182K/127K/153K.;TIH F/6582'-T/7650'MD @ 17 ft/min trip schedule as per drilling engineer. Tag @ 7650'w/20k dn.;Fill pipe and attempt to establish circ w/no go. Psi up to 1040. Rotate temporarily then stalled out @ 19k. Release tq and P/U T/280k(45k over)-No Go.;S/O @ 130k. P/U and fire jars w/45k over(1'progress). Repeat w/55k over(2'progress). S/O and cock jars free dn wt @ 110-130k dn. P/U and fire jars w/55k over(lost 1').;S/O to free point and P/U to neutral wt @ 160k. Establish circ @.5 bpm and eventually staging up to 600 gpm,establish rotation @ 60 rpm with erratic tq& periodic stalls @ 19k. CBU(mostly clay).;Lost communication with MWD tools below PWD. Attempt to reset MWD(no go). Troubleshoot MWD.;Slowly backream out of hole F/7650'-T/7467'MD. 550 gpm,2040 psi,60 rpm,13-19k,62%F/O. 132k dn,235k up,160k rot. Attempt MWD hard reset @ 7467'(no go).;Wash down Fl 7467'-T/7650'MD. 500 gpm,1700 psi. No issues.;Wash and Ream down F/7650'-T/7724'MD. Packing off issues w/stalling issues. 400 gpm,1220 psi,80 rpm,14.3k tq(19k stalls).;Drill F/7724'-T/7740'MD w/various parameters. Saw low ROP w/parameters 5-25k WOB,120-180 rpm, 600 gpm,2390 psi,13-16k tq,62%F/O. ROP avg 20 ft/hr.;CBU @ 7740'MD. 600 gpm,2390 psi,80 rpm,14.3k tq.8 units bgg.;Monitor well(static). POOH clean F/7740'-T/7070'MD to changeout MWD. Saw no losses throughout stuck pipe operations.;Hauled 187 bbls to G&I for total=8869 bbls Hauled 0 bbls H2O from 6 mile lake for total=9670 bbls Hauled 130 bbls H2O from B-Pad for total=1300 bbls Daily losses 0 bbls for total=2880 bbls. 6/15/2017 Continue to TOH from 7070'to 563'(BHA)following trip speed schedule.;Set back Wt Pipe/DC's.RD sources.Plug in and down load MWD.Lay down remaining BHA. Bit grade=1,1,ER,N,X,I,NO,DTF.;CIean and Clear rig floor.Prep for PU BHA.Monitor static well.;MU BHA#9 w/8.5"Nov DTX619MD6 Bit,1.5 bend MTR, PU MWD,plug in and Upload same.PU remaining BHA w/well commander.Shallow test w/450 GPM/685 psi(ok).;TIH Fl 531'-T/4930'MD following trip schedule. 158k up,118k dn,Hole took proper displacement.;Rig service. Grease drawworks,crown,TDS,blocks and handling equipment.;Continue TIH F! 4930'-T/7670'MD. Tripped clean through HRZ with no issues to 7670'MD. 228k up,140k dn. Hole took proper displacement.;Wash and Ream dn F/7670'- T/7698'MD with no issues. 312 gpm,920 psi,20 rpm,15k tq.;Circulate and condition mud. Reduce MW from 10.8 to 10.4. Circulate @ 500 gpm,1900 psi ICP,40 rpm,15k tq,W/pumps 164k rot. 6-8 units BGG. Inc lubes to 1.5%by vol.;Hauled 0 bbls cuttings to G&I for total=8869 bbls Hauled 0 bbls H2O from 6 mile lake for total=9670 bbls Hauled 130 bbls H2O from B-Pad for total=1140 bbls Daily losses 0 bbls for total=2880;Projected to bit-3.1'Low,11.4 Left(11.8'distance to plan). 6/16/2017 Drill 8 1/2" hole F/7740'T/7852'(112')AROP 19 FPH GPM 530,1885 PSI WOB 10-28k,80 RPM TQ 13-15k MW10.4/49 Vis,10.7 ECD PU/SO/ROT 233/139/165.;See 75-200 FPH ROP @ short intervals.Adjust parameters as needed.;Drill 81/2" hole F/7852'T/7985'(133')AROP 22 FPH GPM 530,1830 PSI WOB 12-30k,80 RPM TQ 12-13k MW10.4/49 Vis,10.7 ECD PU/SO/ROT 224/140/172.;Adjust parameters as need to obtain ROP.Slide @ 10-20 ROP, Rot 20-50 ROP.Broke through hard drilling @ 7890'w/80-110 fph Slide/130-220 fph Rotate.;Drill 8 1/2"hole F/7985'T/8313'(328')AROP 55 FPH GPM 530, 2110 PSI WOB 12-25k,80 RPM TQ 16.9k MW10.4/49 Vis,10.9 ECD PU/SO/ROT 228/144/179.;Finish turn at end of tangent @ 8172'MD w/240°Az. Continue drilling ahead with maintenance slides from 8172'MD @ 10-12%slide percentage. BHA has a drop tendency while rotating(.5-1°/100).;Drill 8 1/2"hole F/8313'-T/8694'MD(381')AROP 64 FPH GPM 530,2250 PSI WOB 15-20k,80 RPM TQ 17k 300 diff,MW10.4/49 Vis,11 ECD PU/SO/ROT 253/142/182.;Pump 25 bbl sweep lo vis/condet/walnut sweep @ 8640'w/15%inc in cuttings.;Hauled 456 bbls cuttings to G&I for total=9325 bbls Hauled 0 bbls H2O from 6 mile lake for total=9670 bbls Hauled 130 bbls H2O from B-Pad for total=1270 bbls Daily losses 0 bbls for total=2880:Start increasing black product from 4 ppb to 8 ppb starting @ 8500'MD. 6/17/2017 Drill 8 1/2"hole F/8694'-T/9145'MD(451')AROP 75 FPH(116.8 FPH on btm)GPM 531,2518 PSI WOB 10-15k,80 RPM TQ 18-19k 300 diff,MW10.4/49 Vis,11 ECD PU/SO/ROT 266/146/176;Drill 8 1/2"hole F/9145'-T/9397'MD(252')AROP 63 FPH GPM 530,2475 PSI WOB 10-18k,80 RPM TQ 18-19k 300 diff,MW10.4/49 Vis,11 ECD PU/SO/ROT 280/147/178;Pumped 25 bbls Nut plug Hi vis sweep @ 9335'.;Finish Circulate out sweep.No Increase @ shakers.ECD @ 11.1.;Drill 8 1/2"hole F/9397'-T/9512'MD(115')AROP 77 FPH GPM 530,2475 PSI WOB 10-18k,80 RPM TQ 18-19k 300 diff, MW10.4/49 Vis,11 ECD PU/SO/ROT 281/149/182.;Drill 8 1/2"hole F/9512'-T/9897'MD(385')AROP 64 FPH GPM 534,2550 PSI WOB 10-18k,80 RPM TQ 18-19k 300 diff,MW10.4/49 Vis,11 ECD PU/SO/ROT 281/149/182.;Drill 8 1/2"hole F/9897'-T/10216'MD(319')AROP 54 FPH GPM 533,2570 PSI WOB 10-18k,90 RPM TQ 23k 400 diff,MW10.4/49 Vis,11 ECD PU/SO/ROT 325/149/207.;22 bbl Hi-Vis Walnut Sweep @ 9839'MD. 0%inc in cuttings on time. Increase lubes from 2%to 2.5%due to increasingly high tq. Started lube increase @ 9950'MD.10,216'MD-13'low,4'right.;Hauled 1140 bbls cutting to G&I for total=10465 bbls Hauled 230 bbls H2O from 6 mile lake for total=9900 bbls Hauled 490 bbls H2O from B-Pad for total=1760 bbls losses to sidetrack hole=0 bbls;Carrying 8 ppb black products,15 ppb background Icm with 2.5%lubes in active mud system. Sum(Inc-Install tlivarfar"T"anti nran nari art,tnrA',agar ama fnr wall C`47 • • 6/18/2017 Drill 8 112"hole Fl 10216'-T/10330'MD(114)AROP 57 FPH GPM 530,2675 PSI WOB 18-25k,90 RPM TQ 20-24k 400 diff,MW10.4149 Vis,11 ECD PU/SO/ROT 329/152/200.;Top Drive shut down.Trouble shoot Top Drive Fiber Optic Comms Issue while circulating.;Drill 8 1/2"hole F/10330'-T/10430'MD (100)AROP 50 FPH(Section TD)GPM 530,2580 PSI WOB 18-25k,90 RPM TQ 21-26k 400 diff,MW10.4/49 Vis,11 ECD PU/SO/ROT 342/152/204.;Final Survey at TD MD 10390.48 INC 27.26 AZI 241.56 Distance to Plan=29.38' 28.85 Low 5.56'Right.;10430'TD,Straight line projection. Distance to Plan=33.64' 33.;Pump 30 bbls Hi Vis Nut Plug Sweep and chase with 11.7 ppg spike mud and increase MW f/10.4 to 10.8 ppg.Sweep back 6 bbls early w/no increase @ shakers.Monitor Static Well.No losses on circulation.;Pull 5 stand short trip on elevators from 10430'to 10150'.See 25K Over,work through with no issues.Up wt 340K, Dn wt 168K.Trip back to bottom with no issues.No Losses on Trip.;CBU f 10430'.@ 7000stks into CBU,start casing running pull down pipe.Spot Black/Lube/Graphite CSG Pill from TD to above Kingak @ 8890'.(1538'pill).Monitor Static Well.No Losses on circulation.;TOH on elevators f/10430'to 9950',laying down 5"DP @ 500 fph/8 fpm as per Swab/Surge Trip Schedule.No issues pulling to 9950'.;Continue TOH wet on elevators F/ 9950'to 9462'MD laying down 5"dp. Work moderate tight spot @ 9683'-9693'w/no pump(60k max over). 4.8 bbl over calc disp. 500 fph as per trip schedule.;Monitor well(static). Pump 20 bbl slug. Continue TOH F/9462'-T/8456'MD laying down 5"dp as per trip schedule. Flush jts with fresh water cap in string.;Continue TOH F/8462'-T/6946'MD laying down 5"drill pipe. Work tight spot @ 8140'MD(correlates to possible formation change as per logs SSDS- Sand/Shale).;Saw 20-30k drag intermittent until 7802'then pulled clean with no drag or over pulls. 9.9 bbl over calc disp as of 6946'MD. 202k up,130k do- wts @ 6946'MD.;Hauled 0 bbls from 6 mi lake for total=9900 bbls Hauled 390 bbls from B-Pad for total=2150 bbls Hauled 684 bbls cuttings to G&I for total=10149 bbls 0 bbls total lost to formation(sidetrack) 6/19/2017 TOH F/7000'to 5020'L/D 5"DP @ 1000 fph/16.7 fpm as per Swab/Surge Trip Schedule.No Issues to 5020'.;CBU @ 530 GPM/1750 PSI.Up 152K/Dn 118K. Monitor static well.Pump Slug.;TOH F/5000'to 4000'LID 5"DP @ 1500 fph/25 fpm as per Swab/Surge Trip Schedule.;TOH F/4000'to 3000'LID 5"DP @ 2000 fph/33 fpm as per Swab/Surge Trip Schedule.;TOH F/3000'to BHA'L/D 5"DP @ 3000 fph/50 fpm as per Swab/Surge Trip Schedule.;Lay down BHA:HWDP, �L Well commander,Jars,Flex Collars.Plug in and down load MWD Data.Finish laying down BHA.Bit grade=2,4,S,CT,X,I,HC,TD.;Pull wear bushing. Clean and U clear rig floor. Continue cleaning pits.;Set test plug and monitor well via annulus. C/O upper pipe rams to 7"fixed body rams. Test 250/4000 psi w/5 min hold G1% n ea. Chart and record same(test good).;R/U WOT casing equipment. M/U 7"Hydril 563 shoe track. Inspect shoe track prior to make up(clear). Bakerlok C./ shoe track,9400 ft/lbs M/U tq. 8.25"OD+/-reamer shoe. Check floats(good).;Pump thru shoe track(good). RIH as per detail F/surface to 4940'MD with 7",L- U 80,HTTC,26#casing as per running schedule. Track disp every 10 jts. Hole taken proper displacement.;CBU @ 4940'MD. Stage pumps up to 4 BPM,120 psi with no losses.;Continue RIH as per detail F/4940'-T/5107'MD_with_7" L-80 HTTC 76#casing Change AFE to completions for 6/21/17 report.M/U ES cmtr between 55-56(6 shear screws-3300 psi)w/bakerlok.;Hauled 171 bbls cuttings to G&I for total=10320 bbls Hauled 0 bbls H2O from 6 mile lake for total=9900 bbls0 1 4 7 Hauled 130 bbls H2O from B-Pad for total=2280 bbls c u 0 losses to formation for sidetrack ✓✓ 6/20/2017 Continue RIH as per detail F15107'T/7300'MD with 7",L-80,HTTC,26#casing. Break circ every 15 joints @ 4bpm.;Stage up pumps to 4BPM,@ 350 PSI, 5,10,15 RPMs @ 10-11K tq. Circ Casing Volume,While working pipe.188K,up,134K dn.;Run Casing,F/7300'T/7775'.Set down.Had to work to get circ and rot. Pull 60k over to break free.280K.ROT @ 16K getting pipe rot and circulation @ 2 bpm.;Wash and ream F/7775'T/ 9065'.Run joints without rot and Pump as it would allow. Never run over 600'without circ. Slight pack offs on set downs.Work free with rot. No losses. i . Hilcorp Energy Company Composite Report Well Name: MP C-46 Field: Milne Point County/State: ,Alaska (LAT/LONG): svation(RKB): API#: Spud Date: Job Name: 1710173C MPC-46 Completion Contractor AFE#: 1710173C AFE$: •iiKitillittiti iMMEMINIMINIMMINIIIIIIIIIIIIIIIIIIIMEINIENOW$4. 6/20/2017 Continue RIH as per detail F/5107'T/7300'MD with 7", L-80 HTTC 26#casing Break circ every 15 joints @ 4bpm.,Stage up pumps to 4BPM,@ 350 PSI,5,10,15 RPMs @ 10-11K tq. Circ Casing Volume,While working pipe. 188K,up,134K dn.,Run Casing,F/7300'TI 7775'.Set down.Had to work to get circ and rot. Pull 60k over to break free.280K.ROT @ 16K getting pipe rot and circulation @ 2 bpm.,Wash and ream F/7775'T/ 9065.Run joints without rot and Pump as it would allow. Never run over 600'without circ. Slight pack offs on set downs.Work free with rot. No losses.,Continue wash and ream down 7", L-80,26#,HTTC casing F/9065-T/10,000'MD. Wash dn @ 3 BPM to 9900'then increase to 4 BPM,400 psi. Inc tq F/18k to 20k @ 9973'MD.,Continue wash and ream F/10,000'-T/final set depth of 10,415 MD as per tally. Verify extra jts-6(ok). Saw moderate packing off and rotary stalls while working pipe down.Increase tq to 23k @ 10,385'MD to cont ream dn.,While working pipe to btm,we were unable to P/U above 10,385'with a max up wt of 375K(free up wt @ 342k w/pumps on). Mostly fines back across shakers with small 1 to 2 ea 1/2"blocky pieces periodically(shale).,Did not observe losses to hole during wash and ream operations spite packing of issues throughout the later part of casing run.,Circulate and condition mud while rotating and reciprocating pipe from 10,415'to 10,385 MD. No losses observed while circulating @ 4 BPM,345 psi,39%flow,3-10 rpm,21-23k tq,340k up,160k dn while rot/pump.,R/U cmtrs and prep for cmt job. Reduce surface volume in active pits for upcoming cmt job. 10.8 MW IN/OUT.,Hauled 114 bbls cuttings to G&I for total=10,434 bbls Hauled 0 bbls H2O from 6 mile lake for total=9900 bbls Hauled 230 bbls H2O from B-Pad lake for total=2310 bbls 0 bbls total losses to sidetrack hole 6/21/2017 Circ and condition while prepping for cmt job.MW in and out 10.8,Vis 44 YP 16 Have PJSM for cmt job with all personnel.Circ 4 btm up total. Rot&Reciprocate @ 10 RPM 23K tw Hook up cmt hose to Halliburton cmt swivel. Blow down TD.,Line up to Halliburton, Pump 20 bbl water,Test lines to 4000 psi, Good Drop bypass plug. Pump 30 bbl 11.5 Tuned Spacer III @ 4 BPM, p '✓ Mix and pump 40 bbl 15.3 pea Class G CMT 138sx.Drop opening plug.,Pump 20 bbl H2O to clear lines. Swap to rig,Displace with 353 bbl mud+20 BBL 1 fresh water to cover ES cmt tool.Displace @ 4 bpm. Bump plug on calculated strokes. slow to 2 BPM last 20 bbl.6016 stks total. Final lift 2 BPM 500 psi. Est top of cmt from calculated volumes 8862'.,CIP @ 10:25, Pressure up to 500 over lift to 1000 psi.Hold for 5 min.Good.Bleed down and check floats. Good.Bled back 1.2 bbl. Pressure up to 3100 psi&open ES Cmt tool.Circ btm up @ 5 BPM.Saw spacer at surface.Dump 25 bbl.,Circ&condition @ 5 bpm @ 400 psi. MW 10.8 vis 44 YP 14.,PJSM for second stage cmt job. Break out volont to verify break out before pumping cmt. Batch mix 11.5 tune III spacer.,Line up to Halliburton. Pump 20 bbl H20,30 bb tune III 11.5 Spacer,32 bbl/145 sx 15.3#Class G cmt.Drop closing plug,Halliburton displace 20 bbl fress water to clean lines. Swap to rig and displace with 294 bbls 10.8 LSND mud @ 5 bpm.Slow pumps to 4 bpm last 20 bbl.,4 BPM,FCP 520 psi. Bump closing plug @ 294 bbls (291.3 bbls calc).CIP @ 19:30 hrs. Psi up to 2000 psi with good indication of ES cmtr shift close @ 1350 psi. Hold 2000 psi for 5 min. Bled off psi w/3 bbls bled back and no flow. 100%returns throughout cmt job(0 bbls lost).,Monitor annulus from 19:30 hrs to 22:30 hrs(3 hrs)w/annulus staying static. Sym Ops- V-' R/ D WOT CRT and UD same. Prep low psi side of BOP equipment for N/D. Continue load and process 4"dp in shed. Clean pits,treat and haul off spent 1dril4U , ling fluid for disposal.,Drain stack and N/D and separate flanges on wellhead between multibowl and tbg spool. Clean and inspect wellhead profile. Set C21 5 "E"slips with 152k string wt. Make rough cut. Pull and UD cutoff jt. Set stack back down and set tbg spool on multi bowl.,P/U BOP stack and rack back clear of wellhead. R/U and pull tbg head with tugger. Stage clear of wellhead.,Make final cut on stump and dress same. Final cutoff length 23.54'RKB/Cutoff. Install packoff. N/U tbg head and RILDS. Test void 500/3750 psi w/5 min hold on each(Test good).,Set stack and N/U same. Tighten flanges.,Hauled 0 bbls H2O from 6 mile lake for total=9900 bbls Hauled 570 bbls H2O from B-Pad for total=2880 bbls Hauled 1121 bbls cutting to G&I for total=11,555 bbls 0 bbls total lost to formation for sidetrack cl it 6/22/2017 N/U BOPS,R/U Choke and Kill Line,Install Bell Nipple to flow line,Set Mouse Hole.,Freeze Protect 7"X 5/8.1 BPM @ 450 Psi,2 BPM,475 PSi,Final pressure @ 2 BPM 750 psi.Shut in annulus with 690 psi.,Change top rams, to 2 7/8 X 5 1/2 VBR.Test annular&Top rams to 4"&4.5 pipe.250/4000 psi. UD testing equipment,Set Wear bushing.,P/U BHA#10,Hughes STX-1 Tricone Bit,5"Motor,Stabe, NMFC,FS,XO,10 joints 4"HWDP T/367'.,Slip&cut drilling line.Service rig.,Rig down time, Perform PM inspection of crown sheaves&DW Brake pads.,RIH F/367'-T/8072'MD with 4", 14#,S-135 HT-38 picking up singles from shed. Fill pipe every 2500'MD.,Kelly up and wash down F/8072'-T/8121'MD. Drill stringers from 8121'to 8129'then drill green cmt F/8129'to ES cmt @ 8138'MD(on depth). 200 gpm,20 rpm,7k tq,1100 psi. Saw 150 psi loss. P/U and monitor parameters(good w/new pump psi @ 850 and holding).,S/O and continue drilling"ES"cementer with no issues.Inc rot 30 rpm. Total time drilling stg tool 45 mins. Saw plug and debris back at shakers. Work thru"ES"cmtr TI 8047'MD 2x with pump but no rot then work thru with no pump/rot(clean all 3x). B/O and UD Kelly jt. B/D TDS.,Continue TIH picking up singles F/8047'-T/10,178'MD.,Wash dn F/10178'-Tl 10208'MD. 250 gpm, 1730 psi.20 rpm,13k tq, OA 5 psi @ 06:00 hrs,Hauled 686 bbls Fluid/Cuttings to G&I for total=12241 bbls Hauled 0 bbls H2O from 6 mi lake for total=9900 bbls Hauled 260 bbls from B-Pad lake for total=3140 bbls 0 bbls lost to sidetrack formation. • 1111 6/23/2017 Wash&ream Fl 10208'T/10285. Tag soft cmt @ 10259'. Drill soft cmt to 10285'. Drill baffle adapter @10285'. Drill cmt to 10328'.,Circ&condition while rot and reciprocate.30 RPM @ 12k TQ. Circ btm up @ 335 GPM @ 2675'. Pump 50 bbl Sweep around.,Shut down and build 50 bbl High Vis sweep.Pump sweep&Chase with 9.5 3%KCL,@ 335 GPM. Over displace by 287 bbl.NTUs down to 94.,Shut down and monitor well. Static. Test 7"casing to 3500 psi for 30 min. Good.,POOH UD 4"DP F/10328'T/5925'.,Continue POOH L/D 4"DP Fl 5925'-T/surface. B/O bit and UD all BHA components. Bit grade= 2,1,CT,M,E,I,NO,TD. Clean and clear rig floor. Continue cleaning pits.,PJSM w/SLM E-line crews and Rig crew. Bring tools and equipment to floor. R/U same w/.46"E-line. M/U 3.625"USIT tool string w/CCL(39.6'length,6.25"bow centralizers. RIH and shallow test with slight issue CCL due to centralization. Cont RIH to final depth of 10,303'WLM. Log Fl 10,303'-T/150'MD. 1st stg CBL TOC©9300'WLM,2nd stg CBL TOC©7055'WLM. R/D SLB"E"line. Logs in"0"drive.,Pull wear bushing. R/U WOT casing equipment to run 4.5"production tbg.,Hauled 957 bbls cuttings/fluid to G&I for total= 13,198 bbls Hauled 0 bbls H2O from 6 mi lake for total=9900 bbls Hauled 260 bbls H2O from B-Pad for total=3400 bbls 0 bbls lost to formation for sidetrack. Hole loaded w/9.5 ppq,3%KCL filtered brine. 6/24/2017 R/U 4.5 Completion equipment. Check all Weatherford handling equipment.,PJSM,Run 4.5 Hydril packer completion. Inspect all completion equipment with Weatherford,Baker& Halliburton.,M/U Jewelry, Mule shoe Joint, Supermax Joint,Mirage Plug,Auto Fill,Premier Packer, RN Nipple,Hydril 625 Joints of tubing.Make tubing up to 9600#. RIH F/Surface T/7212'. LID 2 Damaged joints due to snagging a thread. L/D Joint 174&175.Continue running on Joint 176.RIH F/7212'T/7582'. Changed elevators due to not biting correct on the slick pipe.R/U 200 Ton YT @ 6550'.Pipe auto filling on the trip in,Continue RIH w/4.5"Hydril 625 completion assy F/7582'-T/9925'MD as per detail. Auto fill. Tq connections 9600 ft/lbs.,P/U 9.83'pup jt between jts 239 and 240(last jt). M/U 4.5"x11"5M tubing hanger w/3.78'hgr pup jts M/U landing jt to hanger. Drain stack. RIH and landout on depth @ 10,001'MD as per detail. 72k string wt landed in well head. 102k dn,165k up,108k static.RILDS.,PJSM, LRS and crew. P/T line 4600 psi(test good). Freeze protect via 7"x 4.5"annulus. Pump 215 bbls(185 bbls annulus,30 bbls tbg)©2 BPM,FCP=1175 psi. Shut in IA psi=1005. Bled down and leveled off©835 psi.,R/U LRS to monitor/ chart and record psi down tbg and annulus. Rig-Psi up tbg to 500 psi w/5 min hold(good)w/IA psi inc from 835 to 846 psi. Bleed dn IA to 0 psi. PSI up tbg T/670 psi to shift autofill closed. Bleed dn tbg and psi up IA to 1070 psi(good isolation from IA/Tbg-autofill shifted).,Bleed IA psi to 0. Psi up tbg to 3310 wl 30 min hold. Bled down 101 psi first 15 min/82 psi 2nd 15 min. 3127 final psi. Psi up to 3556 psi w/10 min hold. Bled dn to 3506 psi. Bleed dn tbg to 1654 psi. Psi up IA to 3748 w/30 min hold. Bled down 65 psi first 15 min,38 psi 2nd 15 min. Final psi 3645. Bleed dn psi. R/D LRS and release.,Spot bleed tank. R/U on annulus and tbg to pump and chart using rig equip. Purge lines with clean fluid, pump up sensators and test chart recorder(good). Psi up tbg to 4200 psi and hold. Saw a 200 psi drop after 30 secs and gradually kept falling until stabilizing @ 3690 psi after 5 min. Good indicators that 8K rupture disk went and Mirage plug dissolved as designed. 6/25/201 R/U Test pump to tubing.Test Tubing to 3500 psi.Had to bump up&held for 30 min.Good. Monitor IA.Good. Bleed down to 1600 on the tubing. Pressure up with test pump on the annulus to 3700 psi to test packer. Bumped up once and held for 30 min. Monitor tubing pressures and pressure came to 2200& \K t Held.Good test. Bled down both sides to 0 to bleed tank. UD Landing joint.Set TWC.Test to 1000 psi from the top.,Flush all surface equipment with fresh vtd ,/ water.Blow down all surface equipment. Clear rig floor. Remove choke and kill lines.Remove riser and prep stack for N/D. Pull mouse hole. Rack back stack _.,,,\. &Secure same.,Clean profile and install NIU tree and adapter flange. Test void to 250/5000 psi. Leave tree loose for production to line up after moving rig as per production foreman.,Scope down mast,&unload fluid from pits.Blow down water. Swap to C-47 AFE#1800.Rig Released er 18_0011rs to r-47 Hauled 59bbls to B-50bbls for &I l 590 bbls Hauled 134 bbls to G&I for total=13446 bbl Hauled 0 bbls H2O from 6 mi lake for total=9900 bbls �� Hauled 130 bbls H2O from B-Pad for total=3530 bbls 6/29/2017 Lay out containment and spot 6 x 500 bbl frac tanks for upcoming frac 7/2/2017 Spot Sand Chief and begin loading with 16/20 Carbolite. Program calls for 229,429 lbs 7/3/2017 Finish loading remaining 16/20 Carbolite into Sand Chief.Loaded approximately 229,000 lbs 7/4/2017 Start loading 6 frac tanks with 100 degree F.fresh water from the NSB water plant.Biocide added to tanks by SLB prior to loading with water. Begin staging SLB frac equipment on C-Pad. 7/5/2017 Continue filling frac tanks with fresh water. 11:00 to 12:00-MIT-T PASSED to 4950 psi. LRS pressured up tubing/Packer/Liner to 4952 psi with 2.3 bbls of diesel. MIT-T lost 119 psi in 1st 15 minutes(4833/4/114)and 48 psi in 2nd 15 minutes(4785/3/114)for a total of 167 psi during 30 minute test. Bled tubing to 0 psi(2.3 bbls recovered).Final T/I/O=0/0/113 7/7/2017 Rig up frac equipment.All except surface lines 7/9/2017 MIRU Pollard E-Line for perforation.Install BOPE on well. PU 40'of lub with grease head.Stab on BOPE and PT to 2500 psi.Bleed down and UD lubricator. Night cap BOPE. Pollard return to Deadhorse to PU charges for guns at airport,load into gun carriers,and will return later tonight to perforate. SLB frac guys arrive-14:00.Spot any remaining equipment and make last minute checks with Equip.,Pre-Frac meeting at MP base with SLB and Hilcorp to (----;-----)revi ew pumpshedule and operation. 10/2 !lard arrive back to site with 3-1/8"perf guns.MU,arm,and RIH(0 psi WHP)with 30'of Geodynamics 3-1/8"3323 Razor XDP EC2-33A2322/6 SPF/60 g phasing pert guns.CCL to Top shot+72"(6').Make correlation pass from 10,200' to 10,000'WLM. Tie into Sperry Log- MPU C- 46_DGR_EWR_ADR_ALD_CTN MD Final dated 18-May_2017.Make-21'depth shift to get on depth.,RBIH and log up to shooting depth.CCL depth at 10,099'putting top shot at 10,105'.Fire guns-good indication seen on line tension drop.Shoot 10,105'to 10,135'.Log off shooting depth to 10,000'.POOH. ( rfa.`r At surface,still 0 psi WHP.All shots fired.RDMO Pollard wireline.,SLB frac crew on site.Complete Frac RU.Spot bleed tanks,Stab Treesaver,complete surface line RU. RU LRS to annulus pop off skid. PT IA line to 4000 psi.Set pop-offs to 3500 psi.,Open IA-on vac. Prime frac pumps.PT surface lines to 8000 psi. Leak at hammer union.Change out seal.Retest to 8000 psi.Prepare linear gel.,Pump injection test(160 bbls).Monitor pressure.Pump data frac kik) (460 bbls)monitor pressure and verify modelling.Pump main frac(1900 bbls) Ave Rate-30 bpm/Ave pressure- 3800 psi/Prop pumped=231,586 lbs/prop behind pipe-231,415 lbs/ Total volume pumped was 2542 bbls Est prop in wellbore=2925 lbs.Est Top of sand=9903'MD.SI well at Tree Saver.WHP at 3400 psi.,Flush lines. RD LRS pump unit.SDFN. Haul off fluids. RD IA lines and pop off skid 7/11/2017 Pull Tree Saver.RDMO SLB Frac • i 7/19/2017 Continue to R/D on L-46.Blow down all service Lines,Disconnect Accumulator Lines,Nipple down bop stack to Four Bolts,Remove pipe Racks cat walk, Hilcorp Electricians Disconnect Fire and Gas Alarms,Haul off 520 bbls Sea Water to B-50,Super Sucker Clean Pits,Break over Top Section Lay over Derrick, Move ASR Rig to MPC-Pad,ASRC Crane Remove Rig Floor and Well House,,Nipple down Bop Sack Load Bop House Trailer,Haul Cat Walk Pipe Racks,to MPC-Pad,(Schlumberger E-Line Arrived on MPC-46 at 1430 hrs.),Nipple up Production Tree,Test Hanger Void 5,000 Psi, Final ESP Check(tested Good) Clean Cellar and Location of Trash.SIMOPS:SLB E-line rigging up on C-46.Having issues w/E-line unit electrical.Trouble shoot.,SLB unable to find solution to electrical issue.Call town and locate another unit.Have 24hr crew from Prudhoe re-locate f/BP location to Milne Point.SIMOPS:Rig crew continue to shuffle equipment f/L-46 to C-46.,Replacement E-line unit mobilize and relocate to Milne Point C-46.Arrive on location @ 10:45pm.SLB crews change out. SIMOPS:Rig crew move Co Rep trailer and Doghouse f/L-Pad to C-Pad.PEAK truck on loan f/I-rig arrive on location w/load of 9.8ppg KWF f/Baroid mud plant.,Spot replacement E-line unit into position on C-46,R/U pressure control equipment,M/U drift run BHA.Relocate triplex pressure test pump f/B-pad to C- pad and test SLB pressure control equipment. B/O lubricator at QT sub,M/U drift BHA to E-line,M/U QT sub,zero drift at swab valve,and RIH.SIMOPS:Rig crew help roads and pads/work on rig maintenance.,RIH w/E-line drift run to RN nipple.Tag nipple @ 9858'md Eline md. Paint marker flag on E-Iine.,POOH wt E-line drift run BHA.,UD E-line drift run BHA,M/U chemical cutter,CCL, BHA and prep to RIH. 7/20/2017 Schlumberger E-Line M/U chemical cutter,BHA and prep to RIH.(CCL at 9,885 ft.)(TOP at 9,884 ft.)(Cut Depth at 9,893.3 ft.)Pooh Lay down Tools,Pooh Lay down Tools I Change out Tools to Tubing Punch,Schlumberger E-Line Make up Tubing Punch Tool,TIH to(9,834 to 9,835 ft.) Punch 1'ft.of Holes on first joint above Packer,Pooh Break down Tools Schlumberger Rig down Move off MPC-46,Spot LRS Pump Truck,Well support Rig up Hard Line and Choke t /iskid for well Kill Operations,LRS circulate down the TBG taking returns out to flow back tank#1 for hydrocarbon recycle at the ORT. Recover 120bbls of diesel, swapping over to flow back tank#2 at first sign of weighted brine.Pump a total of 365bbls of 9.8ppg brine before seeing 9.8ppg brine at flowback tank.No losses throughout job.Pump @ 3.5-5BPM w/1000-1400psi.Occasional pressure surge increasing up to 2400psi then dropping off quickly.,R/D LRS,Roads and Pads on location w/Cusco to haul diesel to ORT.Suck out fluid lines and tree w/Cusco,placing returns in flow back tank#2.Roads and pads on location 4, w/crane to remove tree.Greg Ruge on location to set BPV,bleed tree void N/D tree,M/U landing jnt crossover to TBG hanger and count rotations(7-3/4 turns), and function LDS.,N/U BOPE on C-46,spot mud boat into position for rigging up Carreir,set well house and rig floor over well utilizing crane.Back rig carrier into position on mud boat,raise mast and pin in place. Back tool pushes trailer into position. Roads and pads on location w/mud pits.Spot mud pits into position along side Carrier.Set up stairways for rig floor access.,Continue to R/U on C-46.Lay out herculite containment for pipe racks.Pull out circulation lines and connect mud pits w/Carrier. Hook up choke and kill lines to mud cross.Spot catwalk into place and connect hydraulic lines from accumulator to BOP stack.N/U riser on BOP stack,spot cuttings tank into position behind mud pits.,Greg Ruge on location to pull BPV and set TWC.Warm up accumulator system and function in prep for BOP test.,Take on fresh water from I-rig water truck into pit#1,fill fluid lines and BOP stack,work out any air in system.Notify AOGCC rep Matthew Herrera that we were prepared to put a shell test on the system.Mr.Herrera instructed to get our shell test and wait for his arrival to proceed.,Perform BOPE shell test to 250psi low f/5 charted mins,and 4000psi high f/5 charted mins.Grease all valves on choke manifold and wait on AOGCC rep arrival. 7/21/2017 Service Rig Check Fluids and Grease,Test Bop as per Sundry Test all Valves and Rams to 250/4,000 psi 5 min each,Test joints 2-7/8 and 4-1/2 Test Annular w/2-7/8 Test Joint,Record Accumulator Pre-Charge Pressures and Chart Test(AOGCC Matthew Herrera on Location Witness Test),Well Head Rep Greg Ruge Tee Bar Removed TWC Valve,Made up Landing Joint into Hanger BOLDS, Pull on Hanger with a Max Pull of 162k Unable to Free up Packer,worked Pipe 8 Times Same Results,Break out Lay down Landing,Nipple down Spacer Spools, Hoist and Install Casing Jacks on Annular,Pull on hanger From 150k to 245k Work Pipe in 10k Increment's,Called Engineer Paul Chan Work Pipe From 245k to 275k,CSG jacks caught in a bind when trying to work pipe.One of the 4 hydraulic rams was bleeding off faster than the other 3 which caused the jacks to bind. Unable to work out the bind,contact Atlas Casing Jacks and ProStar. Adjust counter balance valves and tighten counter balance spring on hydraulic cylinders.Able to work out bind and adjust valves and springs until all 4 are in sequence.,Contact Pollard E-line and discuss potential options to move forward with the well. Pollard required to do job for BP prior to coming out to Milne. Contact BP E-line scheduler and discuss options.Able to get Pollard to come out to Milne prior to the work at BP.,Pollard arrive on C-pad. Back into position and R/U to RIH w/drift run/CCL.M/U 2.5"OD drift w/CCL on floor.Zero depth indicator at the rig floor.Contact Baker completions and get engineered drawing of PKR for creating plan forward.,RIH w/Pollard E-line drift/CCL BHA down to 9900'md.No issues getting through cut area.Continue to RIH down to 10,026'md and tag up on top of frac sand.Pick up to 9950'md.,Correlate across jewelry surrounding PKR w/CCL. Note CCL mark where SLB chemical cut was made,that was not on the previous SLB log prior to the cut.Make 2 more CCL correlation passes and park tool.,Contact Baker fishing and discuss potential fishing options depending on where we place our next cut.Contact engineer and discuss potential options for moving forward. Decision made to attempt another cut w/Radial Cutting Torch(RCT)in PKR cut zone and attempt to pull on TBG.,POOH w/Pollard E-line drift/CCL BHA.,M/U Pollard RCT BHA as per Pollard.Place RCT nozzles 18.2'md f/the middle of the CCL so that we are able to pull up to base of RN nipple and use the CCL signature to verify our depth,prior to firing RCT.,RIH WI Pollard E-line RCT BHA f/surface to 9950'md. Locate cut depth on CCL,fire RCT.Good indication of cut.,POOH w/E- line RCT BHA f/9950'md to surface.UD Pollard equipment.,M/U 4.5"landing joint and pull TBG up to 150klbs w/derrick.Weight indicator did not break over. UD landing joint and prep to P/U 5"joint of DP and pull w/Casing Jacks. 7/22/2017 Service Rig Check Fluids and Grease,Changed out Landing Joint to 5'Make up in to Hanger,Pulled Packer Free at 251k,Changed over to Carrier Mode, Tubing Pulling Free at 135k,Land Hanger Break and lay down Landing Joint,ASRC Crane on Location Hoist Casing Jacks off Rig Floor, Nipple up Spacer Spools,Make up Landing Joint into Hanger Pull hanger to the rig Floor at 135k Break and Lay down UJT&Hanger„Pooh laydown 4-1/2 Hydrill 625 Tubing to 2,550ft.62 Joints, Pipe Started Pulling Wet,R/U Circulation Hose,Circulate Hole volume with a pump Rate of 3.2 BPM at 1,780 psi Total STKS=10,272 Monitor well,Pooh laydown 4-1/2 Hydrill 625 Tubing F/2,550 ft.to 3,900 ft.,Continue to POOH wt Baker Premier PKR on 4.5"Hydril 625,13.5ppf frack string f/ 3900'md to PKR @ 9886'md. PKR intact,upper slip elements not entirely released,sand behind PKR cone not allowing upper slips to fall completely and release.,L/D RN nipple,Baker Premier PKR,Mirage Plug,and the tail pipe assembly.Recover 240 JNTs of 4.5"Hydril 625, 7 pup jnts, RN nipple,Premier PKR,Mirage Plug,2 jnts of 4.5"supermax TBG w/mule shoe.,M/U Baker bladed mill BHA.Load and tally new 3.5"9.5ppf,NC-31 work string.,RIH w!Baker bladed mill BHA on 3.5"9.5ppf NC-31 work string f/surface to 4,600'md. 7/23/2017 Service Rig Check Fluids and Grease,RIH w/Baker bladed mill BHA on 3.5"9.5ppf NC-31 work string f/ 4,600'ft.to 10,039 ft.Tagged Hard,R/U Circulation Hose,Break Circulation with a Pump Rate ICP of Bpm=3/Psi 600 Rpm=50 Rotate on Hard Spot Broke Free,Picked back up to nest Tool Joint, Lined up to Reverse,Circulate Frc Sand from 10,039 ft.to PBMD of 10,286 ft.FCP Bpm=4 at 1,060 Psi Pumping 10 bbl.Hi Vis sweeps through out Circulation Recovered 12 bbl. Frc Sand(No Fluid Losses to Formation)Monitor Well,Pooh w/Baker bladed mill BHA on 3.5"9.5ppf NC-31 work string f/10,285 ft.to 8,685 ft.,Continue to POOH w/Baker fishing bladed junk mill BHA on 3.5"9.5ppf NC-31 work string f/8685'md to surface.UD Mill BHA.,Remove ASR tongs and support arm from derrick, P/U Weatherford TQ turn tongs and set in place on rig floor.Load and strap 308 jnts of 2-7/8"6.4ppf,JFE Bear Pipe. 7/24/2017 Service Rig Check Fluids and Grease,Continue to Load and strap 310 jnts of 2-7/8"6.4ppf,JFE Bear Pipe.,JSA Weatherford, Halliburton,IWS Crew Company Man Tool Pusher, Pick and make up Packer Assembly,Made up Completion Packer and Assembly,(Well Kill Operation on MPB-10 Pumped 580 bbl. 10.1 ppg Brian,Well holding Pressure IA=650 Psi Tubing=650 psi Did Fluid shot both Tubing and IA at 1,000 ft.),TIH w/Completion Packer Assembly and 2- 7/8"6.4ppf,JFE Bear Tubing to 5,700 ft.,Continue to RIH w/Halliburton PHL PKR completion as per completion tally.,On JNT 307,acquire P/U and S/O weights(63klbs/35klbs),M/U 11"x 2-7/8"TBG hanger,splice TEC wire through TBG hanger and wrap around hanger neck,in prep for landing well. R/U to flow back tank for taking returns.Land TBG hanger and RILDS. Issue getting hanger to seat. P/U hanger,circulate over the TBG bowl to rinse any possible debris off of bowl.,Land TBG hanger,RILDS, 6/0 landing jnt,close blind rams and prepare to circulate corrosion inhibitor down the IA,taking returns through the TBG,out the choke,and back to the flow back tank.R/D Weatherford TQ turn and remove equipment f/rig floor.Total of 307 jnts of 2-7/8"TBG ran,w/xn and x nipple,ROC gauge,sliding sleeve,11 GLM's. Land TBG tail @ 10,003'md. • S 7/25/2017 Service Rig Check Fluids and Grease,Continued to circulate corrosion inhibitor down the IA,taking returns through the TBG,out the choke,and back to the flow back tank(Total bbl.Pump 220),Make up Landing Joint into Hanger,Drop Ball and Rod(1 -5/16 OD)Pick up Power Tong Rack and install on Derrick„R/U LRS P/T Lines to 4,500 psi,Circulate Flush and fill Test Path, Bring Pressure up Slowly on Tubing to 1,500/2,500/4,000 psi Hold for 30 min Charted, Bleed Pressure down to 2,000 psi, Pressure up on IA 1,500/3,500 Hold for 30 min Charted,Blow down and disconnect all service Lines,Well Head rep Greg Ruge Tee bar Install BPV in hanger profile,Hilcorp Electricians,Disconnect Fire and Gas Alarms on Rig(Release Rig at 11:30 Hrs.on 7-25-17),Nipple down Bop stack to Four Bolts,ASRC Vac Truck Skim oil off top fluid in pits,Suck out Fluid from Tank, Break down Hydraulic Lines to Bop Stack, Remove Pipe Racks and Cat Walk,Prep Rig Floor,Unpin Top Section and Lower Derrick onto Carrier Drive to A-Pad,ASRC Crane Remove Rig Floor and Well House,Finish Nipple down bop stack and Load on Flat Bed Trailer, Nipple up Production Tree,Test Void to 5,000 Psi • • Hilcorp Alaska, LLC Milne Point M Pt C Pad MPU C-46 50-029-23576-00-00 Sperry Drilling Definitive Survey Report 19 June, 2017 HALLIBURTON 1111 Sperry Drilling 1111 11111 • S Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU C-46 Project: Milne Point TVD Reference: Actual:@ 41.70usft Site: M Pt C Pad MD Reference: Actual:@ 41.70usft Well: MPU C-46 North Reference: True Wellbore: MPU C-46 Survey Calculation Method: Minimum Curvature Design: MPU C-46 Database: Sperry EDM-NORTH US+CANADA Project Milne Point,ACT,MILNE POINT Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU C-46 Well Position +N/-S 0.00 usft Northing: 6,029,204.76 usft Latitude: 70°29'25.462 N +E/-W 0.00 usft Easting: 558,093.18 usft Longitude: 149°31'30.361 W Position Uncertainty 0.00 usft Wellhead Elevation: 41.70 usft Ground Level: 15.00 usft Wellbore MPU C-46 mq. Magnetics Model Name Sample Date Alt Declination Dip Angle Field Strength x Sze§v j' °._: .`{. i " '.,1:7,4',-",,. 3 ,-,� , ,.' s: €' ., () (°) (nT) BGGM2017 5/12/2017 17.76 81.05 57,512 Design MPU C-46 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 4,997.37 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 26.70 0.00 0.00 179.00 Survey Program Date 6/19/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 100.00 1,547.00 SRG-SS(MPU C-46 PB1) SRG-SS Surface readout gyro single shot 05/17/2017 1,607.15 4,920.24 MWD+IFR2+MS+sag(1)(MPU C-46 PB MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 05/19/2017 4,997.37 4,997.37 MWD+IFR2+MS+sag(2)(MPU C-46 PB MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 05/25/2017 5,012.00 5,012.00 MWD_Interp Azi+sag(MPU C-46) MWD_Interp Azi+sag Fixed:v2:std dec with interpolated azimuth+sag 06/06/2017 5,066.08 10,390.48 MWD+IFR2+MS+sag(MPU C-46) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 06/10/2017 •,b#rY Survey R4� fix�. Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.70 0.00 0.00 26.70 -15.00 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 UNDEFINED 100.00 0.59 99.26 100.00 58.30 -0.06 0.37 6,029,204.70 558,093.55 0.80 0.07 SRG-SS(1) 170.00 1.00 98.54 169.99 128.29 -0.21 1.33 6,029,204.56 558,094.51 0.59 0.23 SRG-SS(1) 231.00 1.21 103.41 230.98 189.28 -0.44 2.49 6,029,204.34 558,095.67 0.38 0.48 SRG-SS(1) 295.00 1.25 97.14 294.97 253.27 -0.68 3.84 6,029,204.11 558,097.02 0.22 0.75 SRG-SS(1) 354.00 1.21 100.87 353.95 312.25 -0.88 5.09 6,029,203.92 558,098.27 0.15 0.97 SRG-SS(1) 416.00 0.88 90.67 415.94 374.24 -1.01 6.20 6,029,203.80 558,099.39 0.61 1.12 SRG-SS(1) 479.00 1.00 112.79 478.93 437.23 -1.23 7.20 6,029,203.59 558,100.38 0.60 1.35 SRG-SS(1) 541.00 0.69 101.58 540.93 499.23 -1.51 8.06 6,029,203.31 558,101.25 0.56 1.65 SRG-SS(1) 603.00 0.53 107.62 602.92 561.22 -1.67 8.70 6,029,203.16 558,101.89 0.28 1.82 SRG-SS(1) 6/19/2017 1:54.44PM Page 2 COMPASS 5000.1 Build 81 • III Halliburton Definitive Survey Report i Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU C-46 Project: Milne Point TVD Reference: Actual:@ 41.70usft I Site: M Pt C Pad MD Reference: Actual:@ 41.70usft Well: MPU C-46 North Reference: True Wellbore: MPU C-46 Survey Calculation Method: Minimum Curvature Design: MPU C-46 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 666.00 0.42 91.82 665.92 624.22 -1.77 9.21 6,029,203.06 558,102.40 0.27 1.93 SRG-SS(1) 729.00 0.24 68.48 728.92 687.22 -1.73 9.56 6,029,203.11 558,102.75 0.35 1.89 SRG-SS(1) 792.00 0.39 259.67 791.92 750.22 -1.72 9.47 6,029,203.12 558,102.66 1.00 1.88 SRG-SS(1) 855.00 1.89 275.30 854.91 813.21 -1.66 8.23 6,029,203.16 558,101.42 2.41 1.80 SRG-SS(1) 918.00 2.25 273.22 917.86 876.16 -1.49 5.96 6,029,203.31 558,099.15 0.58 1.60 SRG-SS(1) 981.00 2.32 271.28 980.81 939.11 -1.40 3.45 6,029,203.39 558,096.64 0.17 1.46 SRG-SS(1) 1,043.00 2.32 269.47 1,042.76 1,001.06 -1.38 0.94 6,029,203.39 558,094.13 0.12 1.40 SRG-SS(1) 1,106.00 0.91 279.97 1,105.74 1,064.04 -1.31 -0.83 6,029,203.45 558,092.36 2.28 1.29 SRG-SS(1) 1,169.00 0.51 280.17 1,168.73 1,127.03 -1.17 -1.60 6,029,203.58 558,091.59 0.63 1.14 SRG-SS(1) 1,232.00 0.88 229.45 1,231.73 1,190.03 -1.43 -2.24 6,029,203.31 558,090.95 1.08 1.39 SRG-SS(1) 1,295.00 2.83 201.30 1,294.69 1,252.99 -3.20 -3.17 6,029,201.54 558,090.03 3.33 3.14 SRG-SS(1) 1,358.00 4.94 190.67 1,357.55 1,315.85 -7.31 -4.24 6,029,197.41 558,089.00 3.52 7.24 SRG-SS(1) 1,418.00 7.38 186.19 1,417.19 1,375.49 -13.68 -5.14 6,029,191.04 558,088.15 4.14 13.59 SRG-SS(1) 1,483.00 9.48 182.06 1,481.49 1,439.79 -23.18 -5.78 6,029,181.53 558,087.58 3.36 23.08 SRG-SS(1) 1,547.00 11.74 181.76 1,544.39 1,502.69 -34.96 -6.17 6,029,169.76 558,087.29 3.53 34.85 SRG-SS(1) 1,607.15 12.34 177.16 1,603.22 1,561.52 -47.50 -6.04 6,029,157.22 558,087.51 1.88 47.38 MWD+IFR2+MS+sag(2) 1,668.97 14.98 170.70 1,663.29 1,621.59 -61.98 -4.42 6,029,142.75 558,089.25 4.93 61.90 MWD+IFR2+MS+sag(2) 1,732.91 18.82 168.79 1,724.46 1,682.76 -80.26 -1.08 6,029,124.50 558,092.73 6.07 80.23 MWD+IFR2+MS+sag(2) 1,795.23 20.51 170.19 1,783.14 1,741.44 -100.88 2.74 6,029,103.91 558,096.71 2.82 100.91 MWD+IFR2+MS+sag(2) 1,858.55 24.34 169.03 1,841.66 1,799.96 -124.63 7.11 6,029,080.20 558,101.27 6.09 124.74 MWD+IFR2+MS+sag(2) 1,921.43 26.07 168.24 1,898.55 1,856.85 -150.88 12.40 6,029,053.99 558,106.75 2.80 151.07 MWD+IFR2+MS+sag(2) 1,984.39 24.59 165.02 1,955.46 1,913.76 -177.08 18.60 6,029,027.84 558,113.16 3.21 177.38 MWD+IFR2+MS+sa9(2) 2,047.52 24.20 164.68 2,012.95 1,971.25 -202.25 25.42 6,029,002.73 558,120.17 0.66 202.66 MWD+IFR2+MS+sag(2) 2,110.43 22.55 164.34 2,070.70 2,029.00 -226.30 32.08 6,028,978.74 558,127.02 2.63 226.83 MWD+IFR2+MS+sag(2) 2,173.62 23.82 164.10 2,128.78 2,087.08 -250.24 38.85 6,028,954.85 558,133.98 2.02 250.88 MWD+IFR2+MS+sag(2) 2,236.42 23.51 164.57 2,186.30 2,144.60 -274.51 45.65 6,028,930.64 558,140.97 0.58 275.27 MWD+IFR2+MS+sag(2) 2,299.41 25.20 163.40 2,243.69 2,201.99 -299.48 52.83 6,028,905.73 558,148.34 2.79 300.35 MWD+IFR2+MS+sag(2) 2,362.00 25.61 164.45 2,300.22 2,258.52 -325.28 60.26 6,028,879.99 558,155.97 0.97 326.28 MWD+IFR2+MS+sag(2) 2,424.94 24.44 164.55 2,357.25 2,315.55 -350.93 67.37 6,028,854.40 558,163.29 1.86 352.06 MWD+IFR2+MS+sag(2) 2,488.16 25.63 163.34 2,414.53 2,372.83 -376.64 74.78 6,028,828.75 558,170.89 2.05 377.89 MWD+IFR2+MS+sag(2) 2,550.62 26.07 163.64 2,470.74 2,429.04 -402.75 82.52 6,028,802.70 558,178.83 0.73 404.13 MWD+IFR2+MS+sag(2) 2,613.93 25.75 162.30 2,527.69 2,485.99 -429.20 90.62 6,028,776.32 558,187.14 1.05 430.72 MWD+IFR2+MS+sag(2) 2,676.31 25.57 163.17 2,583.92 2,542.22 -455.00 98.64 6,028,750.59 558,195.36 0.67 456.65 MWD+IFR2+MS+sag(2) 2,739.56 25.22 164.04 2,641.06 2,599.36 -481.02 106.29 6,028,724.63 558,203.22 0.81 482.80 MWD+IFR2+MS+sag(2) 2,802.28 24.50 164.54 2,697.96 2,656.26 -506.40 113.43 6,028,699.31 558,210.56 1.20 508.30 MWD+IFR2+MS+sag(2) 2,865.24 23.96 165.56 2,755.38 2,713.68 -531.36 120.10 6,028,674.40 558,217.42 1.09 533.38 MWD+IFR2+MS+sag(2) 2,928.37 25.30 161.90 2,812.77 2,771.07 -556.60 127.49 6,028,649.23 558,225.00 3.22 558.74 MWD+IFR2+MS+sag(2) 2,991.14 25.99 160.97 2,869.35 2,827.65 -582.35 136.14 6,028,623.55 558,233.85 1.27 584.64 MWD+IFR2+MS+sag(2) 3,053.84 24.97 161.24 2,925.95 2,884.25 -607.87 144.88 6,028,598.10 558,242.79 1.64 610.31 MWD+IFR2+MS+sag(2) 3,116.53 23.64 161.54 2,983.09 2,941.39 -632.32 153.11 6,028,573.71 558,251.21 2.13 634.90 MWD+IFR2+MS+sag(2) 6/19/2017 1:54:44PM Page 3 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU C-46 Project: Milne Point TVD Reference: Actual:@ 41.7ousft Site: M Pt C Pad MD Reference: Actual:@ 41.70usft Well: MPU C-46 North Reference: True Wellbore: MPU C-46 Survey Calculation Method: Minimum Curvature ki Design: MPU C-46 Database: Sperry EDM-NORTH US+CANADA Ei Survey Map Map Vertical MID Inc Azi TVD TVDSS +NI-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,180.00 25.11 161.48 3,040.90 2,999.20 -657.16 161.42 6,028,548.94 558,259.71 2.32 659.88 MWD+IFR2+MS+sag(2) 3242.38 24,89 162.37 3,097.43 3,055.73 -682.22 169.60 6,028,523.95 558,268.09 0.70 685.08 MWD+IFR2+MS+sag(2) 3,305.15 24.65 163.19 3,154.43 3,112.73 -707.34 177.39 6,028,498.89 558,276.07 0.67 710.33 MWD+IFR2+MS+sag(2) 3,368.23 24.45 163.32 3,211.81 3,170.11 -732.44 184.94 6,028,473.86 558,283.82 0.33 735.56 MWD+IFR2+MS+sag(2) 3,431.06 23.75 163.92 3,269.16 3,227.46 -757.05 192.17 6,028,449.30 558,291.24 1.18 760.29 MWD+IFR2+MS+sag(2) 3,493.59 23.25 164.37 3,326.50 3,284.80 -781.04 198.99 6,028,425.37 558,298.24 0.85 784.39 MWD+IFR2+MS+sag(2) 3,556.86 24.44 161.92 3,384.37 3,342.67 -805.51 206.41 6,028,400.97 558,305.86 2.45 808.99 MWD+IFR2+MS+sag(2) 3,619.64 25.78 161.65 3,441.22 3,399.52 -830.81 214.74 6,028,375.73 558,314.39 2.14 834.44 MWD+IFR2+MS+sag(2) 3,682.33 25.79 162.47 3,497.67 3,455.97 -856.76 223.14 6,028,349.85 558,322.99 0.57 860.52 MWD+IFR2+MS+sag(2) 3,745.51 25.97 163.05 3,554.51 3,512.81 -883.10 231.32 6,028,323.58 558,331.36 0.49 887.00 MWD+IFR2+MS+sag(2) 3,808.35 26.05 163.63 3,610.99 3,569.29 -909.50 239.22 6,028,297.25 558,339.47 0.42 913.53 MWD+IFR2+MS+sag(2) 3,871.59 26.23 163.84 3,667.76 3,626.06 -936.24 247.02 6,028,270.57 558,347.48 0.32 940.41 MWD+IFR2+MS+sag(2) 3,934.40 25.58 163.16 3,724.26 3,682.56 -962.55 254.81 6,028,244.32 558,355.48 1.14 966.85 MWD+IFR2+MS+sag(2) 3,997.22 24.94 162.35 3,781.07 3,739.37 -988.15 262.75 6,028,218.78 558,363.62 1.16 992.59 MWD+IFR2+MS+sag(2) 4,060.14 25.05 162.43 3,838.10 3,796.40 -1,013.49 270.80 6,028,193.51 558,371.86 0.18 1,018.07 MWD+IFR2+MS+sag(2) 4,123.07 25.24 162.23 3,895.06 3,853.36 -1,038.97 278.91 6,028,168.10 558,380.18 0.33 1,043.68 MWD+IFR2+MS+sag(2) 4,185.83 25.11 162.10 3,951.86 3,910.16 -1,064.39 287.09 6,028,142.75 558,388.55 0.23 1,069.23 MWD+IFR2+MS+sag(2) 4,248.48 24.82 162.36 4,008.66 3,966.96 -1,089.57 295.16 6,028,117.64 558,396.82 0.49 1,094.55 MWD+IFR2+MS+sag(2) 4,311.63 24.53 162.16 4,066.04 4,024.34 -1,114.68 303.19 6,028,092.59 558,405.04 0.48 1,119.80 MWD+IFR2+MS+sag(2) 4,374.58 23.63 162.28 4,123.51 4,081.81 -1,139.13 311.04 6,028,068.20 558,413.08 1.43 1,144.39 MWD+IFR2+MS+sag(2) 4,437.34 23.50 161.99 4,181.04 4,139.34 -1,163.01 318.73 6,028,044.38 558,420.96 0.28 1,168.40 MWD+IFR2+MS+sag(2) 4,499.72 23.30 162.41 4,238.29 4,196.59 -1,186.60 326.31 6,028,020.86 558,428.72 0.42 1,192.12 MWD+IFR2+MS+sag(2) 4,563.19 24.76 162.95 4,296.26 4,254.56 -1,211.28 334.00 6,027,996.25 558,436.60 2.33 1,216.92 MWD+IFR2+MS+sag(2) 4,626.39 25.32 163.47 4,353.52 4,311.82 -1,236.89 341.72 6,027,970.70 558,444.52 0.95 1,242.66 MWD+IFR2+MS+sag(2) 4,689.67 25.36 163.79 4,410.71 4,369.01 -1,262.87 349.36 6,027,944.78 558,452.36 0.23 1,268.78 MWD+IFR2+MS+sag(2) 4,752.00 25.52 163.46 4,466.99 4,425.29 -1,288.56 356.91 6,027,919.15 558,460.11 0.34 1,294.59 MWD+IFR2+MS+sag(2) 4,815.21 25.75 163.35 4,523.98 4,482.28 -1,314.77 364.72 6,027,893.01 558,468.12 0.37 1,320.93 MWD+IFR2+MS+sag(2) 4,878.00 25.66 163.81 4,580.56 4,538.86 -1,340.89 372.42 6,027,866.95 558,476.02 0.35 1,347.19 MWD+IFR2+MS+sag(2) 4,920.24 25.51 163.66 4,618.66 4,576.96 -1,358.40 377.52 6,027,849.48 558,481.27 0.39 1,364.78 MWD+IFR2+MS+sag(2) 4,997.37 25.98 162.25 4,688.13 4,646.43 -1,390.43 387.35 6,027,817.53 558,491.34 1.00 1,396.98 MWD+IFR2+MS+sag(3) 5,012.00 25.95 161.95 4,701.28 4,659.58 -1,396.53 389.32 6,027,811.45 558,493.36 0.92 1,403.11 MWD_Interp Azi+sag(4) 5,066.08 22.44 154.97 4,750.62 4,708.92 -1,417.14 397.35 6,027,790.91 558,501.55 8.36 1,423.86 MWD+IFR2+MS+sag(5) 5,133.59 22.26 154.91 4,813.05 4,771.35 -1,440.39 408.23 6,027,767.74 558,512.61 0.27 1,447.30 MWD+IFR2+MS+sag(5) 5,197.00 23.86 158.16 4,871.40 4,829.70 -1,463.18 418.09 6,027,745.03 558,522.65 3.22 1,470.25 MWD+IFR2+MS+sag(5) 5,260.56 27.24 155.85 4,928.74 4,887.04 -1,488.39 428.83 6,027,719.91 558,533.58 5.54 1,495.65 MWD+IFR2+MS+sag(5) 5,323.45 30.23 152.18 4,983.88 4,942.18 -1,515.53 442.11 6,027,692.87 558,547.07 5.52 1,523.02 MWD+IFR2+MS+sag(5) 5,386.25 32.69 147.37 5,037.45 4,995.75 -1,543.81 458.64 6,027,664.73 558,563.82 5.59 1,551.58 MWD+IFR2+MS+sag(5) 5,448.57 35.02 143.88 5,089.21 5,047.51 -1,572.43 478.26 6,027,636.26 558,583.66 4.87 1,580.54 MWD+IFR2+MS+sag(5) 5,512.00 37.79 141.72 5,140.26 5,098.56 -1,602.40 501.03 6,027,606.48 558,606.67 4.81 1,610.90 MWD+IFR2+MS+sag(5) 5,574.27 39.98 138.45 5,188.73 5,147.03 -1,632.35 526.13 6,027,576.73 558,631.99 4.82 1,641.28 MWD+IFR2+MS+sag(5) 6/19/2017 1:54:44PM Page 4 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU C-46 Project: Milne Point TVD Reference: Actual:@ 41.70usft Site: M Pt C Pad MD Reference: Actual:@ 41.70usft Well: MPU C-46 North Reference: True Wellbore: MPU C-46 Survey Calculation Method: Minimum Curvature Design: MPU C-46 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,637.34 42.20 134.57 5.236.27 5,194.57 -1,662.39 554.66 6,027,546.92 558,660.76 5.36 1,671.81 MWD+IFR2+MS+sag(5) 5,700.00 44.72 132.06 5,281.75 5,240.05 -1,691.93 586.03 6,027,517.62 558,692.35 4.87 1,701.90 MWD+IFR2+MS+sag(5) 5,762.99 47.48 131.00 5,325.42 5,283.72 -1,722.01 620.01 6,027,487.81 558,726.56 4.55 1,732.57 MWD+IFR2+MS+sag(5) 5,825.99 50.49 130.98 5,366.76 5,325.06 -1,753.19 655.89 6,027,456.92 558,762.68 4.78 1,764.37 MWD+IFR2+MS+sag(5) 5,888.53 51.88 130.70 5,405.96 5,364.26 -1,785.05 692.75 6,027,425.34 558,799.79 2.25 1,796.87 MWD+IFR2+MS+sag(5) 5,951.22 51.90 130.22 5,444.65 5,402.95 -1,817.06 730.28 6,027,393.63 558,837.56 0.60 1,829.53 MWD+IFR2+MS+sag(5) 6,009.62 52.20 130.01 5,480.57 5,438.87 -1,846.73 765.50 6,027,364.24 558,873.01 0.59 1,859.81 MWD+IFR2+MS+sag(5) 6,077.26 52.49 129.86 5,521.89 5,480.19 -1,881.11 806.56 6,027,330.19 558,914.33 0.46 1,894.90 MWD+IFR2+MS+sag(5) 6,140.03 52.67 130.04 5,560.03 5,518.33 -1,913.12 844.78 6,027,298.48 558,952.80 0.37 1,927.57 MWD+IFR2+MS+sag(5) 6,202.96 52.46 130.19 5,598.28 5,556.58 -1,945.32 882.99 6,027,266.59 558,991.26 0.38 1,960.43 MWD+IFR2+MS+sag(5) 6,265.77 52.64 130.13 5,636.48 5,594.78 -1,977.48 921.10 6,027,234.73 559,029.61 0.30 1,993.25 MWD+IFR2+MS+sag(5) 6,328.61 53.05 129.59 5,674.43 5,632.73 -2,009.57 959.55 6,027,202.94 559,068.30 0.95 2,026.01 MWD+IFR2+MS+sag(5) 6,391.58 52.42 130.22 5,712.56 5,670.86 -2,041.72 997.99 6,027,171.09 559,106.99 1.28 2,058.83 MWD+IFR2+MS+sag(5) 6,454.23 52.56 129.44 5,750.71 5,709.01 -2,073.55 1,036.15 6,027,139.56 559,145.40 1.01 2,091.32 MWD+IFR2+MS+sag(5) 6,517.00 51.13 130.01 5,789.49 5,747.79 -2,105.10 1,074.12 6,027,108.32 559,183.61 2.39 2,123.52 MWD+IFR2+MS+sag(5) 6,580.40 49.97 131.34 5,829.77 5,788.07 -2,137.00 1,111.25 6,027,076.71 559,220.98 2.44 2,156.07 MWD+IFR2+MS+sag(5) 6,643.52 47.38 133.67 5,871.45 5,829.75 -2,169.00 1,146.20 6,027,044.98 559,256.18 4.95 2,188.68 MWD+IFR2+MS+sag(5) 6,706.18 46.04 136.73 5,914.42 5,872.72 -2,201.35 1,178.34 6,027,012.89 559,288.56 4.15 2,221.58 MWD+IFR2+MS+sag(5) 6,769.28 43.95 142.88 5,959.06 5,917.36 -2,235.37 1,207.14 6,026,979.11 559,317.62 7.64 2,256.09 MWD+IFR2+MS+sag(5) 6,832.32 43.15 146.78 6,004.76 5,963.06 -2,270.85 1,232.15 6,026,943.82 559,342.92 4.45 2,292.01 MWD+IFR2+MS+sag(5) 6,895.02 40.39 149.68 6,051.52 6,009.82 -2,306.33 1,254.16 6,026,908.52 559,365.20 5.37 2,327.87 MWD+IFR2+MS+sag(5) 6,957.64 38.81 154.65 6,099.78 6,058.08 -2,341.59 1,272.81 6,026,873.41 559,384.12 5.65 2,363.45 MWD+IFR2+MS+sag(5) 7,020.85 37.79 160.05 6,149.40 6,107.70 -2,377.71 1,287.90 6,026,837.42 559,399.49 5.53 2,399.82 MWD+IFR2+MS+sag(5) 7,083.67 35.23 164.26 6,199.90 6,158.20 -2,413.25 1,299.39 6,026,801.97 559,411.26 5.70 2,435.56 MWD+IFR2+MS+sag(5) 7,146.33 33.55 168.06 6,251.61 6,209.91 -2,447.59 1,307.88 6,026,767.69 559,420.01 4.35 2,470.05 MWD+IFR2+MS+sag(5) 7,209.12 32.82 172.20 6,304.17 6,262.47 -2,481.43 1,313.78 6,026,733.91 559,426.17 3.79 2,503.98 MWD+IFR2+MS+sag(5) 7,272.32 32.54 177.02 6,357.37 6,315.67 -2,515.38 1,316.98 6,026,699.99 559,429.65 4.14 2,537.98 MWD+IFR2+MS+sag(5) 7,332.42 33.18 181.16 6,407.86 6,366.16 -2,547.97 1,317.49 6,026,667.41 559,430.41 3.89 2,570.57 MWD+IFR2+MS+sag(5) 7,397.89 32.71 187.29 6,462.82 6,421.12 -2,583.44 1,314.88 6,026,631.92 559,428.08 5.14 2,605.99 MWD+IFR2+MS+sag(5) 7,460.81 33.21 193.34 6,515.62 6,473.92 -2,617.08 1,308.75 6,026,598.24 559,422.21 5.29 2,639.52 MWD+IFR2+MS+sag(5) 7,524.22 33.36 196.80 6,568,64 6,526.94 -2,650.67 1,299.70 6,026,564.58 559,413.42 3.00 2,672.95 MWD+IFR2+MS+sag(5) 7,586.70 33.66 203.01 6,620.75 6,579.05 -2,683.06 1,287.97 6,026,532.10 559,401.94 5.51 2,705.13 MWD+IFR2+MS+sag(5) 7,649.78 33.52 204.45 6,673.30 6,631.60 -2,715.01 1,273.92 6,026,500.05 559,388.15 1.28 2,736.82 MWD+IFR2+MS+sag(5) 7,691.87 33.76 205.32 6,708.34 6,666.64 -2,736.16 1,264.11 6,026,478.83 559,378.51 1.28 2,757.80 MWD+IFR2+MS+sag(5) 7,723.58 33.88 207.53 6,734.68 6,692.98 -2,751.96 1,256.26 6,026,462.96 559,370.78 3.90 2,773.46 MWD+IFR2+MS+sag(5) 7,786.64 34.42 206.82 6,786.87 6,745.17 -2,783.45 1,240.09 6,026,431.35 559,354.86 1.06 2,804.67 MWD+IFR2+MS+sag(5) 7,849.47 33.94 211.12 6,838.85 6,797.15 -2,814.32 1,223.01 6,026,400.35 559,338.02 3.92 2,835.23 MWD+IFR2+MS+sag(5) 7,912.95 33.38 215.16 6,891.70 6,850.00 -2,843.77 1,203.79 6,026,370.75 559,319.04 3.64 2,864.35 MWD+IFR2+MS+sag(5) 7,976.00 31.50 219.66 6,944.91 6,903.21 -2,870.64 1,183.29 6,026,343.73 559,298.74 4.85 2,890.85 MWD+IFR2+MS+sag(5) 8,039.51 30.87 228.03 6,999.27 6,957.57 -2,894.32 1,160.57 6,026,319.87 559,276.22 6.89 2,914.13 MWD+IFR2+MS+sag(5) 6/19/2017 1:54:44PM Page 5 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU C-46 Project: Milne Point TVD Reference: Actual:@ 41.70usft Site: M Pt C Pad MD Reference: Actual:@ 41.70usft Well: MPU C-46 North Reference: True Wellbore: MPU C-46 Survey Calculation Method: Minimum Curvature Design: MPU C-46 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +El-W Northing Easting DLS Section (usft) (1 (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,101.92 31.35 233.25 7,052.72 7,011.02 -2,914.74 1,135.66 6,026,299.26 559,251.46 4.39 2,934.12 MWD+IFR2+MS+sag(5) 8,166.23 31.69 238.20 7,107.55 7,065.85 -2,933.66 1,107.89 6,026,280.13 559,223.85 4.06 2,952.55 MWD+IFR2+MS+sag(5) 8,227.49 31.06 240.04 7,159.85 7,118.15 -2,950.03 1,080.52 6,026,263.55 559,196.61 1.87 2,968.44 MWD+IFR2+MS+sag(5) 8,289.87 33.31 237.47 7,212.64 7,170.94 -2,967.28 1,052.14 6,026,246.08 559,168.36 4.22 2,985.19 MWD+IFR2+MS+sag(5) 8,352.11 34.59 238.86 7,264.27 7,222.57 -2,985.61 1,022.60 6,026,227.52 559,138.98 2.41 3,003.00 MWD+IFR2+MS+sag(5) 8,415.19 34.68 239.35 7,316.18 7,274.48 -3,004.01 991.84 6,026,208.87 559,108.36 0.46 3,020.87 MWD+IFR2+MS+sag(5) 8,477.81 33.99 238.68 7,367.88 7,326.18 -3,022.20 961.56 6,026,190.46 559,078.23 1.26 3,038.52 MWD+IFR2+MS+sag(5) 8,541.00 33.66 239.70 7,420.38 7,378.68 -3,040.21 931.35 6,026,172.21 559,048.16 1.04 3,056.00 MWD+IFR2+MS+sag(5) 8,603.12 33.33 239.15 7,472.18 7,430.48 -3,057.65 901.84 6,026,154.54 559,018.79 0.72 3,072.92 MWD+IFR2+MS+sag(5) 8,666.67 32.11 238.43 7,525.65 7,483.95 -3,075.45 872.45 6,026,136.52 558,989.55 2.02 3,090.20 MWD+IFR2+MS+sag(5) 8,729.39 34.88 239.20 7,577.95 7,536.25 -3,093.36 842.84 6,026,118.38 558,960.08 4.47 3,107.60 MWD+IFR2+MS+sag(5) 8,792.52 36.08 238.86 7,629.35 7,587.65 -3,112.22 811.43 6,026,099.28 558,928.82 1.93 3,125.90 MWD+IFR2+MS+sag(5) 8,855.55 35.36 239.10 7,680.53 7,638.83 -3,131.18 779.89 6,026,080.07 558,897.43 1.16 3,144.31 MWD+IFR2+MS+sag(5) 8,918.40 34.79 238.97 7,731.96 7,690.26 -3,149.76 748.92 6,026,061.25 558,866.61 0.91 3,162.35 MWD+IFR2+MS+sag(5) 8,981.27 34.55 239.05 7,783.67 7,741.97 -3,168.18 718.26 6,026,042.60 558,836.10 0.39 3,180.23 'MWD+IFR2+MS+sag(5) 9,044.09 33.69 239.13 7,835.68 7,793.98 -3,186.28 688.03 6,026,024.26 558,806.01 1.37 3,197.80 MWD+IFR2+MS+sag(5) 9,107.00 33.01 239.24 7,888.23 7,846.53 -3,203.99 658.33 6,026,006.31 558,776.45 1.09 3,215.00 MWD+IFR2+MS+sag(5) 9,169.98 32.08 238.79 7,941.32 7,899.62 -3,221.43 629.28 6,025,988.65 558,747.55 1.53 3,231.93 MWD+IFR2+MS+sag(5) 9,232.36 31.99 238.83 7,994.20 7,952.50 -3,238.57 600.98 6,025,971.29 558,719.38 0.15 3,248.57 MWD+IFR2+MS+sag(5) 9,295.42 32.78 240.88 8,047.45 8,005.75 -3,255.52 571.77 6,025,954.11 558,690.31 2.14 3,265.01 MWD+IFR2+MS+sag(5) 9,358.67 33.05 241.77 8,100.55 8,058.85 -3,272.01 541.62 6,025,937.39 558,660.29 0.88 3,280.97 MWD+IFR2+MS+sag(5) 9,421.42 35.18 241.94 8,152.50 8,110.80 -3,288.61 510.58 6,025,920.55 558,629.39 3.40 3,297.02 MWD+IFR2+MS+sag(5) 9,484.34 35.16 241.03 8,203.93 8,162.23 -3,305.91 478.74 6,025,903.00 558,597.68. 0.83 3,313.77 MWD+IFR2+MS+sag(5) 9,543.43 34.52 240.93 8,252.43 8,210.73 -3,322.29 449.22 6,025,886.40 558,568.30 1.09 3,329.62 MWD+IFR2+MS+sag(5) 9,609.57 33.51 241.07 8,307.25 8,265.55 -3,340.23 416.86 6,025,868.21 558,536.08 1.53 3,347.00 MWD+IFR2+MS+sag(5) 9,672.50 33.01 241.16 8,359.87 8,318.17 -3,356.90 386.64 6,025,851.31 558,506.00 0.80 3,363.14 MWD+IFR2+MS+sag(5) 9,735.18 32.00 241.28 8,412.73 8,371.03 -3,373.12 357.12 6,025,834.86 558,476.61 1.61 3,378.84 MWD+IFR2+MS+sag(5) 9,798.61 32.89 243.42 8,466.26 8,424.56 -3,388.90 326.98 6,025,818.84 558,446.59 . 2.29 3,394.09 MWD+IFR2+MS+sag(5) 9,861.16 31.76 243.77 8,519.12 8,477.42 -3,403.78 297.02 6,025,803.74 558,416.75 1.83 3,408.44 MWD+IFR2+MS+sag(5) 9,924.34 31.76 244.56 8,572.84 8,531.14 -3,418.27 267.09 6,025,789.01 558,386.94 0.66 3,422.41 MWD+IFR2+MS+sag(5) 9,987.68 30.24 244.41 8,627.13 8,585.43 -3,432.32 237.65 6,025,774.73 558,357.61 2.40 3,435.94 MWD+IFR2+MS+sag(5) 10,049.75 31.08 242.80 8,680.52 8,638.82 -3,446.39 209.30 6,025,760.44 558,329.38 1.89 3,449.52 MWD+IFR2+MS+sag(5) 10,112.55 31.26 242.29 8,734.26 8,692.56 -3,461.38 180.46 6,025,745.23 558,300.66 0.51 3,464.00 MWD+IFR2+MS+sag(5) 10,175.94 31.21 242.38 8,788.46 8,746.76 -3,476.64 151.35 6,025,729.74 558,271.67 0.11 3,478.75 MWD+IFR2+MS+sag(5) 10,238.82 30.37 241.43 8,842.47 8,800.77 -3,491.80 122.95 6,025,714.37 558,243.39 1.54 3,493.41 MWD+IFR2+MS+sag(5) 10,301.47 28.72 241.69 8,896.98 8,855.28 -3,506.51 95.79 6,025,699.44 558,216.35 2.64 3,507.65 MWD+IFR2+MS+sag(5) 10,364.35 27.64 241.60 8,952.40 8,910.70 -3,520.61 69.66 6,025,685.14 558,190.33 1.72 3,521.29 MWD+IFR2+MS+sag(5) 10,390.48 27.26 241.56 8,975.59 8,933.89 -3,526.34 59.06 6,025,679.32 558,179.78 1.46 3,526.84 MWD+IFR2+MS+sag(5) 10,430.00 27.26 241.56 9,010,72 8,969.02 -3,534.96 43.15 6,025,670.58 558,163.94 0.00 3,535.18 PROJECTED to TD • 6/19/2017 1:54:44PM Page 6 COMPASS 5000.1 Build 81 • 0 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU C-46 Project: Milne Point TVD Reference: Actual:@ 41.70usft Site: M Pt C Pad MD Reference: Actual:@ 41.70usft Well: MPU C-46 North Reference: True Wellbore: MPU C-46 Survey Calculation Method: Minimum Curvature Design: MPU C-46 Database: Sperry EDM-NORTH US+CANADA brian.wheeler@halliburton.co D...,s9.. a m tu., 6/19/2017 Checked By: m ��____�� Approved By: p„a=,==_•_•� """°'"""°"`�"" Date: 6/19/2017 1:54:44PM Page 7 COMPASS 5000.1 Build 81 • S Hilcorp Alaska, LLC Milne Point M Pt C Pa—- MPU C 6 PB1 50-029-2 -70-00 t Sperry Drilling Definitive Survey Report 19 June, 2017 HALLIBURTON Sperry Drilling • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: 1' Well MPU C-46 Project: Milne Point TVD Reference: Actual:@ 41.70usft Site: M Pt C Pad MD Reference: Actual:@ 41.70usft Well: MPU C-46 North Reference: True Wellbore: MPU C-46 P81 Survey Calculation Method: Minimum Curvature Design: MPU C-46 PB1 Database: Sperry EDM-NORTH US+CANADA Project Milne Point,ACT,MILNE POINT Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU C-46 '' Well Position +N/-S 0.00 usft Northing: 6,029,204.76 usft Latitude: 70°29'25.462 N +E/-W 0.00 usft Easting: 558,093.18 usft Longitude: 149°31'30.361 W Position Uncertainty 0.00 usft Wellhead Elevation: 41.70 usft Ground Level: 15.00 usft Wellbore MPU C-46 PB1 Magnetics f Model Name x Sample Date Declination Dip Angle Field Strength '' ° t:z i``a p; i_ () a� O (aT) BGGM2017 5/12/2017 17.76 81.05 57,512 Design MPU C-46 PB1 i Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.70 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) �..R° ,`(usft) (usft) (°) 26.70 0.00 0.00 179.00 Survey Program Date 6/19/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 100.00 1,547.00 SRG-SS(MPU C-46 PB1) SRG-SS Surface readout gyro single shot 05/17/2017 1,607.15 4,920.24 MWD+IFR2+MS+sag(1)(MPU C-46 PB MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 05/19/2017 4,997.37 7,887.54 MWD+IFR2+MS+sag(2)(MPU C-46 PB MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 05/25/2017 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.70 0.00 0.00 26.70 -15.00 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 UNDEFINED 100.00 0.59 99.26 100.00 58.30 -0.06 0.37 6,029,204.70 558,093.55 0.80 0.07 SRG-SS(1) 170.00 1.00 98.54 169.99 128.29 -0.21 1.33 6,029,204.56 558,094.51 0.59 0.23 SRG-SS(1) 231.00 1.21 103.41 230.98 189.28 -0.44 2.49 6,029,204.34 558,095.67 0.38 0.48 SRG-SS(1) 295.00 1.25 97.14 294.97 253.27 -0.68 3.84 6,029,204.11 558,097.02 0.22 0.75 SRG-SS(1) 354.00 1.21 100.87 353.95 312.25 -0.88 5,09 6,029,203.92 558,098.27 0.15 0.97 SRG-SS(1) 416.00 0.88 90.67 415.94 374.24 -1.01 6.20 6,029,203.80 558,099.39 0.61 1.12 SRG-SS(1) 479.00 1.00 112.79 478.93 437.23 -1.23 7.20 6,029,203.59 558,100.38 0.60 1.35 SRG-SS(1) 541.00 0.69 101.58 540.93 499.23 -1.51 8.06 6,029,203.31 558,101.25 0.56 1.65 SRG-SS(1) 603.00 0.53 107.62 602.92 561.22 -1.67 8.70 6,029,203.16 558,101.89 0.28 1.82 SRG-SS(1) 666.00 0.42 91.82 665.92 624.22 -1.77 9.21 6,029,203.06 558,102.40 0.27 1.93 SRG-SS(1) 729.00 0.24 68.48 728.92 687.22 -1.73 9.56 6,029,203.11 558,102.75 0.35 1.89 SRG-SS(1) 6/19/2017 1.52:29PM Page 2 COMPASS 5000.1 Build 81 • 1111 Halliburton Definitive Survey Report a Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU C-46 Project: Milne Point TVD Reference: Actual:@ 41.70usft Site: M Pt C Pad MD Reference: Actual:@ 41.70usft Well: MPU C-46 North Reference: True 11 Wellbore: MPU C-46 PBI Survey Calculation Method: Minimum Curvature Design: MPU C-46 PB1 Database: Sperry EDM-NORTH US+CANADA il Survey ', . _, : it . r , Map Map Vertical ', , MD Inc Azi TVD TVDSS +N/-S '. +E/-W Northing Easting DLS Section iv (usft) (°) (°) (usft) (usft) (usft) e^(usft) (ft) (ft) (°/100') (ft) Survey Tool Name 792.00 0.39 259.67 791.92 750.22 -1.72 9.47 6,029,203.12 558,102.66 1.00 1.88 SRG-SS(1) 855.00 1.89 275.30 854.91 813.21 -1.66 8.23 6,029,203.16 558,101.42 2.41 1.80 SRG-SS(1) 918.00 2.25 273.22 917.86 876.16 -1.49 5.96 6,029,203.31 558,099.15 0.58 1.60 SRG-SS(1) 981.00 2.32 271.28 980.81 939.11 -1.40 3,45 6,029,203.39 558,096.64 0.17 1.46 SRG-SS(1) 1,043.00 2.32 269.47 1,042.76 1,001.06 -1.38 0.94 6,029,203.39 558,094.13 0.12 1.40 SRG-SS(1) 1,106.00 0.91 279.97 1,105.74 1,064.04 -1.31 -0.83 6,029,203.45 558,092.36 2.28 1.29 SRG-SS(1) 1,169.00 0.51 280.17 1,168.73 1,127.03 -1.17 -1.60 6,029,203.58 558,091.59 0.63 1.14 SRG-SS(1) 1,232.00 0.88 229.45 1,231.73 1,190.03 -1.43 -2.24 6,029,203.31 558,090.95 1.08 1.39 SRG-SS(1) 1,295.00 2.83 201.30 1,294.69 1,252.99 -3.20 -3.17 6,029,201.54 558,090.03 3.33 3.14 SRG-SS(1) 1,358.00 4.94 190.67 1,357.55 1,315.85 -7.31 -4.24 6,029,197.41 558,089.00 3.52 7.24 SRG-SS(1) 1,418.00 7.38 186.19 1,417.19 1,375.49 -13.68 -5.14 6,029,191.04 558,088.15 4.14 13.59 SRG-SS(1) 1,483.00 9.48 182.06 1,481.49 1,439.79 -23.18 -5.78 6,029,181.53 558,087.58 3.36 23.08 SRG-SS(1) 1,547.00 11.74 181.76 1,544.39 1,502.69 -34.96 -6.17 6,029,169.76 558,087.29 3.53 34.85 SRG-SS(1) 1,607.15 12.34 177.16 1,603.22 1,561.52 -47.50 -6.04 6,029,157.22 558,087.51 1.88 47.38 MWD+IFR2+MS+sag(2) 1,668.97 14.98 170.70 1,663.29 1,621.59 -61.98 -4.42 6,029,142.75 558,089.25 4.93 61.90 MWD+IFR2+MS+sag(2) 1,732.91 18.82 168.79 1,724.46 1,682.76 -80.26 -1.08 6,029,124.50 558,092.73 6.07 80.23 MWD+IFR2+MS+sag(2) 1,795.23 20.51 170.19 1,783.14 1,741.44 -100.88 2.74 6,029,103.91 558,096.71 2.82 100.91 MWD+IFR2+MS+sag(2) 1,858.55 24.34 169.03 1,841.66 1,799.96 -124.63 7.11 6,029,080.20 558,101.27 6.09 124.74 MWD+IFR2+MS+sag(2) 1,921.43 26.07 168.24 1,898.55 1,856.85 -150.88 12.40 6,029,053.99 558,106.75 2.80 151.07 MWD+IFR2+MS+sag(2) 1,984.39 24.59 165.02 1,955.46 1,913.76 -177.08 18.60 6,029,027.84 558,113.16 3.21 177.38 MWD+1F52+MS+sag(2) 2,047.52 24.20 164.68 2,012.95 1,971.25 -202.25 25.42 6,029,002.73 558,120.17 0.66 202.66 MWD+IFR2+MS+sag(2) 2,110.43 22.55 164.34 2,070.70 2,029.00 -226.30 32.08 6,028,978.74 558,127.02 2.63 226.83 MWD+IFR2+MS+sag(2) 2,173.62 23.82 164.10 2,128.78 2,087.08 -250.24 38.85 6,028,954.85 558,133.98 2.02 250.88 MWD+IFR2+MS+sag(2) 2,236.42 23.51 164.57 2,186.30 2,144.60 -274.51 45.65 6,028,930.64 558,140.97 0.58 275.27 MWD+IFR2+MS+sag(2) 2,299.41 25.20 163.40 2,243.69 2,201.99 -299.48 52.83 6,028,905.73 558,148.34 2.79 300.35 MWD+IFR2+MS+sag(2) 2,362.00 25.61 164.45 2,300.22 2,258.52 -325.28 60.26 6,028,879.99 558,155.97 0.97 326.28 MWD+IFR2+MS+sag(2) 2,424.94 24.44 164.55 2,357.25 2,315.55 -350.93 67.37 6,028,854.40 558,163.29 1.86 352.06 MWD+IFR2+MS+sag(2) 2,488.16 25.63 163.34 2,414.53 2,372.83 -376.64 74.78 6,028,828.75 558,170.89 2.05 377.89 MWD+IFR2+MS+sag(2) 2,550.62 26.07 163.64 2,470.74 2,429.04 -402.75 82.52 6,028,802.70 558,178.83 0.73 404.13 MWD+IFR2+MS+sag(2) 2,613.93 25.75 162.30 2,527.69 2,485.99 -429.20 90.62 6,028,776.32 558,187.14 1.05 430.72 MWD+IFR2+MS+sag(2) 2,676.31 25.57 163.17 2,583.92 2,542.22 -455.00 98.64 6,028,750.59 558,195.36 0.67 456.65 MWD+IFR2+MS+sag(2) 2,739.56 25.22 164.04 2,641.06 2,599.36 -481.02 106.29 6,028,724.63 558,203.22 0.81 482.80 MWD+IFR2+MS+sag(2) 2,802.28 24.50 164.54 2,697.96 2,656.26 -506.40 113.43 6,028,699.31 558,210.56 1.20 508.30 MWD+IFR2+MS+sag(2) 2,865.24 23.96 165.56 2,755.38 2,713.68 -531.36 120.10 6,028,674.40 558,217.42 1.09 533.38 MWD+IFR2+MS+sag(2) 2,928.37 25.30 161.90 2,812.77 2,771.07 -556.60 127.49 6,028,649.23 558,225.00 3.22 558.74 MWD+IFR2+MS+sag(2) 2,991.14 25.99 160.97 2,869.35 2,827.65 -582.35 136.14 6,028,623.55 558,233.85 1.27 584.64 MWD+IFR2+MS+sag(2) 3,053.84 24.97 161.24 2,925.95 2,884.25 -607.87 144.88 6,028,598.10 558,242.79 1.64 610.31 MWD+IFR2+MS+sag(2) 3,116.53 23.64 161.54 2,983.09 2,941.39 -632.32 153.11 6,028,573.71 558,251.21 2.13 634.90 MWD+IFR2+MS+sag(2) 3,180.00 25.11 161.48 3,040.90 2,999.20 -657.16 161.42 6,028,548.94 558,259.71 2.32 659.88 MWD+IFR2+MS+sag(2) 3,242.38 24.89 162.37 3,097.43 3,055.73 -682.22 169.60 6,028,523.95 558,268.09 0.70 685.08 MWD+IFR2+MS+sag(2) 6/19/2017 1'52.29PM Page 3 COMPASS 5000.1 Build 81 • 0 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU C-46 Project: Milne Point TVD Reference: Actual:@ 41.70usft Site: M Pt C Pad MD Reference: Actual:@ 41.70usft Well: MPU C-46 North Reference: True Wellbore: MPU C-46 PB1 Survey Calculation Method: Minimum Curvature Design: MPU C-46 PB1 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 3,305.15 24.65 163.19 3,154.43 3,112.73 -707.34 177.39 6,028,498.89 558,276.07 0.67 710.33 MWD+IFR2+MS+sag(2) 3,368.23 24.45 163.32 3,211.81 3,170.11 -732.44 184.94 6,028,473.86 558,283.82 0.33 735.56 MWD+IFR2+MS+sag(2) 3,431.06 23.75 163.92 3,269.16 3,227.46 -757.05 192.17 6,028,449.30 558,291.24 1.18 760.29 MWD+IFR2+MS+sag(2) 3,493.59 23.25 164.37 3,326.50 3,284.80 -781.04 198.99 6,028,425.37 558,298.24 0.85 784.39 MWD+IFR2+MS+sag(2) 3,556.86 24.44 161.92 3,384.37 3,342.67 -805.51 206.41 6,028,400.97 558,305.86 2.45 808.99 MWD+IFR2+MS+sag(2) 3,619.64 25.78 161.65 3,441.22 3,399.52 -830.81 214.74 6,028,375.73 558,314.39 2.14 834.44 MWD+IFR2+MS+sag(2) 3,682.33 25.79 162.47 3,497.67 3,455.97 -856.76 223.14 6,028,349.85 558,322.99 0.57 860.52 MWD+IFR2+MS+sag(2) 3,745.51 25.97 163.05 3,554.51 3,512.81 -883.10 231.32 6,028,323.58 558,331.36 0.49 887.00 MWD+IFR2+MS+sag(2) 3,808.35 26.05 163.63 3,610.99 3,569.29 -909.50 239.22 6,028,297.25 558,339.47 0.42 913.53 MWD+IFR2+MS+sag(2) 3,871.59 26.23 163.84 3,667.76 3,626.06 -936.24 247.02 6,028,270.57 558,347.48 0.32 940.41 MWD+IFR2+MS+sag(2) 3,934.40 25.58 163.16 3,724.26 3,682.56 -962.55 254.81 6,028,244.32 558,355.48 1.14 966.85 MWD+IFR2+MS+sag(2) 3,997.22 24.94 162.35 3,781.07 3,739.37 -988.15 262.75 6,028,218.78 558,363.62 1.16 992.59 MWD+IFR2+MS+sag(2) 4,060.14 25.05 162.43 3,838.10 3,796.40 -1,013.49 270.80 6,028,193.51 558,371.86 0.18 1,018.07 MWD+IFR2+MS+sag(2) 4,123.07 25.24 162.23 3,895.06 3,853.36 -1,038.97 278.91 6,028,168.10 558,380.18 0.33 1,043.68 MWD+IFR2+MS+sag(2) 4,185.83 25.11 162.10 3,951.86 3,910.16 -1,064.39 287.09 6,028,142.75 558,388.55 0.23 1,069.23 MWD+IFR2+MS+sag(2) 4,248.48 24.82 162.36 4,008.66 3,966.96 -1,089.57 295.16 6,028,117.64 558,396.82 0.49 1,094.55 MWD+IFR2+MS+sag(2) 4,311.63 24.53 162.16 4,066.04 4,024.34 -1,114.68 303.19 6,028,092.59 558,405.04 0.48 1,119.80 MWD+IFR2+MS+sag(2) 4,374.58 23.63 162.28 4,123.51 4,081.81 -1,139.13 311.04 6,028,068.20 558,413.08 1.43 1,144.39 MWD+IFR2+MS+sag(2) 4,437.34 23.50 161.99 4,181.04 4,139.34 -1,163.01 318.73 6,028,044.38 558,420.96 0.28 1,168.40 MWD+IFR2+MS+sag(2) 4,499.72 23,30 162.41 4,238.29 4,196.59 -1,186.60 326.31 6,028,020.86 558,428.72 0.42 1,192.12 MWD+IFR2+MS+sag(2) 4,563.19 24.76 162.95 4,296.26 4,254.56 -1,211.28 334.00 6,027,996.25 558,436.60 2.33 1,216.92 MWD+IFR2+MS+sag(2) 4,626.39 25.32 163.47 4,353.52 4,311.82 -1,236.89 341.72 6,027,970.70 558,444.52 0.95 1,242.66 MWD+IFR2+MS+sag(2) 4,689.67 25.36 163.79 4,410.71 4,369.01 -1,262.87 349.36 6,027,944.78 558,452.36 0.23 1,268.78 MWD+IFR2+MS+sag(2) 4,752.00 25.52 163.46 4,466,99 4,425.29 -1,288.56 356.91 6,027,919.15 558,460.11 0.34 1,294.59 MWD+IFR2+MS+sag(2) 4,815.21 25.75 163.35 4,523.98 4,482.28 -1,314.77 364.72 6,027,893.01 558,468.12 0.37 1,320.93 MWD+IFR2+MS+sag(2) A-46 .5 4,878.00 25.66 163.81 4,580.56 4,538.86 -1,340.89 372.42 6,027,866.95 558,476.02 0.35 1,347.19 MWD+IFR2+MS+sag(2) 4,920.2 5.51 163.66 4,618.66 4,576.96 -1,358.40 377.52 6,027,849.48 558,481.27 0.39 1,364.78 MWD+IFR2+MS+sag(2) 4,997.37 25.98 162.25 4,688.13 4,646.43 -1,390.43 387.35 6,027,817.53 558,491.34 1.00 1,396.98 MWD+IFR2+MS+sag(3) 5,060.07 25.84 160.97 4,744.53 4,702.83 -1,416.43 395.99 6,027,791.61 558,500.18 0.92 1,423.12 MWD+IFR2+MS+sag(3) 5,123.03 25.54 161.58 4,801.26 4,759.56 -1,442.28 404.75 6,027,765.83 558,509.15 0.64 1,449.12 MWD+IFR2+MS+sag(3) 5,185.46 25.07 164.25 4,857.71 4,816.01 -1,467.77 412.60 6,027,740.39 558,517.19 1.98 1,474.75 MWD+IFR2+MS+sag(3) 5,249.15 24,30 164.81 4,915.58 4,873.88 -1,493.41 419.69 6,027,714.82 558,524.49 1.26 1,500.51 MWD+IFR2+MS+sag(3) 5,311.78 23.82 165.10 4,972.76 4,931.06 -1,518.07 426.32 6,027,690.22 558,531.31 0.79 1,525.28 MWD+IFR2+MS+sag(3) 5,374.53 23.60 164.62 5,030.22 4,988.52 -1,542.42 432.91 6,027,665.91 558,538.08 0.47 1,549.74 MWD+IFR2+MS+sag(3) 5,436.46 23.01 164.70 5,087.09 5,045.39 -1,566.05 439.39 6,027,642.34 558,544.75 0.95 1,573.48 MWD+IFR2+MS+sag(3) 5,500.40 22.77 165.65 5,146.00 5,104.30 -1,590.09 445.76 6,027,618.35 558,551.30 0.69 1,597.63 MWD+IFR2+MS+sag(3) 5,563.56 22,59 166.18 5,204.28 5,162.58 -1,613.71 451.68 6,027,594.78 558,557.41 0.43 1,621.35 MWD+IFR2+MS+sag(3) 5,626.11 23.30 165.64 5,261.88 5,220.18 -1,637.36 457.62 6,027,571.18 558,563.53 1.18 1,645.10 MWD+IFR2+MS+sag(3) 5,688.80 24.68 164.28 5,319.15 5,277.45 -1,661.98 464.24 6,027,546.62 558,570.35 2.37 1,669.82 MWD+IFR2+MS+sag(3) 5,752.00 25.45 162.81 5,376.40 5,334.70 -1,687.65 471.83 6,027,521.01 558,578.14 1.57 1,695.63 MWD+IFR2+MS+sag(3) 6/19/2017 1:52:29PM Page 4 COMPASS 5000.1 Build 81 • S Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU C-46 Project: Milne Point TVD Reference: Actual:@ 41.70usft Site: M Pt C Pad MD Reference: Actual:@ 41.70usft Well: MPU C-46 North Reference: True Wellbore: MPU C-46 PBI Survey Calculation Method: Minimum Curvature Design: MPU C-46 PBI Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi ND TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 5,814.55 25.01 161.76 5,432.98 5,391.28 -1,713.05 479.94 6,027,495.68 558,586.44 1.00 1,721.16 MWD+IFR2+MS+sag(3) 5,877.76 24.38 161.47 5,490.41 5,448.71 -1,738.11 488.27 6,027,470.69 558,594.97 1.01 1,746.36 MWD+IFR2+MS+sag(3) 5,937.71 24.48 161.96 5,544.99 5,503.29 -1,761.65 496.05 6,027,447.21 558,602.93 0.38 1,770.04 MWD+IFR2+MS+sag(3) 6,003.41 24.99 162.76 5,604.67 5,562.97 -1,787.85 504.38 6,027,421.08 558,611.46 0.93 1,796.38 MWD+IFR2+MS+sag(3) 6,066.47 25.80 162.03 5,661.63 5,619.93 -1,813.62 512.56 6,027,395.37 558,619.84 1.38 1,822.29 MWD+IFR2+MS+sag(3) 6,129.08 26.01 163.68 5,717.95 5,676.25 -1,839.76 520.62 6,027,369.30 558,628.11 1.20 1,848.56 MWD+IFR2+MS+sag(3) 6,192.22 25.73 163.08 5,774.76 5,733.06 -1,866.16 528.50 6,027,342.97 558,636.19 0.61 1,875.10 MWD+IFR2+MS+sag(3) 6,255.02 25.51 162.25 5,831.39 5,789.69 -1,892.08 536.59 6,027,317.11 558,644.48 0.67 1,901.16 MWD+IFR2+MS+sag(3) 6,317.45 25.48 160.73 5,887.74 5,846.04 -1,917.56 545.12 6,027,291.70 558,653.21 1.05 1,926.78 MWD+IFR2+MS+sag(3) 6,380.35 25.11 160.94 5,944.61 5,902.91 -1,942.94 553.94 6,027,266.39 558,662.23 0.61 1,952.32 MWD+IFR2+MS+sag(3) 6,443.36 24.48 159.46 6,001.81 5,960.11 -1,967.81 562.89 6,027,241.60 558,671.37 1.40 1,977.33 MWD+IFR2+MS+sag(3) 6,506.10 24.82 161.29 6,058.83 6,017.13 -1,992.45 571.67 6,027,217.03 558,680.35 1.33 2,002.13 MWD+IFR2+MS+sag(3) 6,569.13 25.18 164.06 6,115.96 6,074.26 -2,017.88 579.60 6,027,191.67 558,688.47 1.94 2,027.68 MWD+IFR2+MS+sag(3) �- 4ri3L 6,631.79 25.04 165.96 6,172.70 6,131.00 -2,043.56 586.48 6,027,166.04 • 558,695.55 1.31 2,053.48 MWD+IFR2+MS+sag(3) 6,694.71 24.25 165.86 6,229.89 6,188.19 -2,069.01 592.87 6,027,140.65 558,702.13 1.26 2,079.04 MWD+IFR2+MS+sag(3) • 6,758.17 24.96 174.32 6,287.60 6,245.90 -2,094.97 597.38 6,027,114.72 558,706.85 5.66 2,105.08 MWD+IFR2+MS+sag(3) 6,821.22 . 26.51 179.40 6,344.41 6,302.71 -2,122.29 598.84 6,027,087.42 558,708.52 4.27 2,132.42 MWD+IFR2+MS+sag(3) 6,882.73 28.71 183.91 6,398.91 6,357.21 -2,150.76 597.98 6,027,058.94 558,707.88 4.93 2,160.87 MWD+IFR2+MS+sag(3) 6,946.52 31.17 188.32- 6,454.19 6,412.49 -2,182.39 594.54 6,027,027.29 558,704.70 5.17 2,192.43 MWD+IFR2+MS+sag(3) 7,009.55 32.36 192.38 6,507.79 6,466.09 -2,215.01 588.56 6,026,994.63 558,698.97 3.88 2,224.95 MWD+IFR2+MS+Sag(3) 7,072.54 34.07 196.40 6,560.49 6,518.79 -2,248.41 579.97 6,026,961.17 558,690.64 4.42 2,258.19 MWD+IFR2+MS+sag(3) 7,135.29 35.53 198.23 6,612.02 6,570.32 -2,282.59 569.30 6,026,926.91 558,680.24 2.86 2,292.18 MWD+IFR2+MS+sag(3) 7,198.60 35.76 197.05 6,663.47 6,621.77 -2,317.75 558.12 6,026,891.66 558,669.34 1.15 2,327.14 MWD+IFR2+MS+sag(3) 7,262.27 35.77 195.97 6,715.13 6,673.43 -2,353.43 547.55 6,026,855.91 558,659.04 0.99 2,362.62 MWD+IFR2+MS+sag(3) 7,324.25 35.40 195.17 6,765.54 6,723.84 -2,388.17 537.86 6,026,821.10 558,649.63 0.96 2,397.19 MWD+IFR2+MS+sag(3) 7,387.00 34.16 193.71 6,817.08 6,775.38 -2,422.83 528.93 6,026,786.37 558,640.97 2.38 2,431.69 MWD+IFR2+MS+sag(3) 7,449.82 34.56 195.38 6,868.94 6,827.24 -2,457.14 520.03. 6,026,751.99 558,632.34 1.63 2,465.84 MWD+IFR2+MS+sag(3) 7,513.27 35,44 195.79 6,920.91 6,879.21 -2,492.20 510.25 . 6,026,716.86 558,622.83 1.44 2,500.72 MWD+IFR2+MS+sag(3) 7,575.81 36.50 196.52 6,971.53 6,929.83 -2,527.48 500.02 6,026,681.51 558,612.89 1.83 2,535.82 MWD+IFR2+MS+sag(3) 7,638.40 36.68 197.06 7,021.78 6,980.08 -2,563.20 489.25 6,026,645.71 558,602.39 0.59 2,571.34 MWD+IFR2+MS+sag(3) 7,701.72 36.25 196.31 7,072.70 7,031.00 -2,599.24 478.44 6,026,609.58 558,591.87 0.98 2,607.20 MWD+IFR2+MS+sag(3) 7,764.50 35.22 196.32 7,123.66 7,081.96 -2,634.43 468.14 6,026,574.32 558,581.84 1.64 2,642.20 MWD+IFR2+MS+sag(3) 7,827.59 35.68 196.70 7,175.06 7,133.36 --2,669.52 457.74 6,026,539.16 558,571.72 0.81 2,677.10 MWD+IFR2+MS+sag(3) 7,887.54 35.21 196.16 7,223.90 7,182.20 -2,702.86 447.91 6,026,505.74 558,562.15 0.94 2,710.27 MWD+IFR2+MS+sag(3) 7,920.00 35.21 196.16 7,250.42 7,208.72 -2,720.84 442.70 6,026,487.73 558,557.08 0.00 2,728.15 PROJECTED to TD c brian.wheelerChalliburton.aua.....* *0..dw9.4....d Checked By: corn 'CW:tte 2011.1.I - Approved By: D°°e n-t° "'"*"''"''''' Date: 6/19/2017 6/19/2017 1:52:29PM Page 5 COMPASS 5000.1 Build 81 • Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. MP C-46 Date Run 21-May-17 County State Alaska Supv. J.Lott/S.Barber CASING RECORD Surface �r TD 4,966.00 Shoe Depth: 4,954.80 PBTD: 4,871.72 No.Jts.Delivered 120 No.Jts.Run 120 No.Jts.Returned Ftg.Delivered 4,954.80 Ftg.Run 4,954.80 Ftg.Returned Length Measurements W/O Threads Ftg.Cut Jt. 25.62 Ftg.Balance 4,929.18 RKB RKB to BHF RKB to CHF RKB to THF Casing(Or Liner)Detail Setting Depths �,'s `� Jts. Component Size Wt. Grade THD Make Length Bottom Top `}-" ,/e" 1 shoe 10 DWC/C 1.66 4,954.80 4,953.14 J tj- 1 Casing 9 5/8 40.0 L-80 DWC/C VamTop 40.65 4,953.14 4,912.49 1 Foat Collar 10 DWC/C 1.18 4,912.49 4,911.31 1 Casing 9 5/8 40.0 L-80 DWC/C VamTop 38.02 4,911.31 4,873.29 1 BFL 10 DWC/C 1.57 4,873.29 4,871.72 72 Casing 9 5/8 40.0 L-80 DWC/C VamTop 2,969.32 4,871.72 1,902.40 1 ESCMTR 103/4 DWC/C HES 3.08 1,902.40 1,899.32 46 Casing 9 5/8 40.0 L-80 DWC/C VamTop 1,873.70 1,899.32 25.62 Csg Wt.On Hook: 200,000 Type Float Collar: Coventional wl Baffle G No.Hrs to Run: 13 Csg Wt.On Slips: 165,000 Type of Shoe: Conventional Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg Yes X No 60 Ft Min. 9.5 PPG Fluid Description: Spud Mud Liner hanger Info(Make/Model): "E"slips Liner top Packer?: _Yes_No Liner hanger test pressure: 2450 Floats Held X Yes_ No Centralizer Placement: 2ea on jt#1(10'from each end).lea jt#2 in middle of tube,lea jt#3 in middle tube. Every other jt to#21(Total of 14 bow spring centralizers). 3 before and 3 after stage tool @ 1900'MD. Total bow springs ran 20 ea. 4ea stop rings. CEMENTING REPORT Shoe @ 4954.8 FC @ 4,911.31 Top of Liner Preflush(Spacer) Type: Tuned Spacer II Density(ppg) 10.5 Volume pumped(BBLs) 54 Lead Slurry Type: Class"G" Sacks: 435 Yield: 2.46 Density(ppg) 11.7 Volume pumped(BBLs) 191 Mixing/Pumping Rate(bpm): 5 V' 1.- Tail Slurry m Type: Class"G" Sacks: 225 Yield: 1.16 F Density(ppg) 15.8 Volume pumped(BBLs) 46.3 Mixing/Pumping Rate(bpm): 5 Post Flush(Spacer) 7 y re Type: Density(ppg) Rate(bpm): Volume: LL Displacement: Type: Spud Mud Density(ppg) 9.5 Rate(bpm): 5 Volume(actual/calculated): 369/369.7 FCP(psi): 847 Pump used for disp: Rig MP#1 Bump Plug? X Yes No Bump press 1350 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job :1 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: ak Cement In Place At: 14:30 Date: 5/22/2017 Estimated TOC: 1,900 . Method Used To Determine TOC: Calc/Stage Tool Depth Stage Collar @ 1899.32 Type Closure OK OK Preflush(Spacer) Type: Tuned Spacer III Density(ppg) 10.5 Volume pumped(BBLs) _ 55 Lead Slurry i')/ Type: Perm"L" Sacks: 315 Yield: 4.33 1 // Density(ppg) 10.7 Volume pumped(BBLs) 243 Mixing/Pumping Rate(bpm): 5 _li Tail Slurry G�'K_ Leji Type: Class"G" Sacks: 340 Yield: 1.39 Density(ppg) 14.5 Volume pumped(BBLs) 85 Mixing/Pumping Rate(bpm): 5 °z Post Flush(Spacer) 8 Type: Density(ppg) Rate(bpm): Volume: y Displacement: Type: Spud Mud Density(ppg) 9.5 Rate(bpm): 5 Volume(actual/calculated): 144.7/144 FCP(psi): 411 Pump used for disp: Rig MP#1 Bump Plug? X Yes No Bump press 1381 Casing Rotated? Yes X No Reciprocated? X Yes No %Returns during job 85 e w Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: /Mi) 21-1VZ A'' Cement In Place At: 0:12 Date: 5/23/2017 Estimated TOC: 0 j 4'*- 1_ Method Used To Determine TOC: visual i" Post Job Calculations: / Calculated Cmt Vol @ 0%excess: 268 Total Volume cmt Pumped: 579 Cmt returned to surface: 298 Calculated cement left in wellbore: 281 OH volume Calculated: 268.8 OH volume actual: 292 Actual%Washout: 9 www.wellez.net WellEz Information Management LLC ver_102716bf Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. MP C-46 Date Run 21-Jun-17 County State Alaska Supv. J.Lott/S.Barber CASING RECORD Production V TD 10,430.00 Shoe Depth: 10,416.30 PBTD: 10,285.00 No.Jts.Delivered 252 No.Jts.Run 252 No.Jts.Returned Ftg.Delivered 10,406.12 Ftg.Run 10,416.30 Ftg.Returned Length Measurements W/O Threads Ftg.Cut Jt. 23.54 Ftg.Balance 10,382.58 RKB 26.64 RKB to BHF 22.57 RKB to CHF RKB to THF Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 EZ reamer shoe 8 5/8 Hydril 563 Baker 2.72 10,416.30 10,413.58 1 Casing 7 26.0 L-80 Hydril 563 41.78 10,413.58 10,371.80 1 Float Collar 85/8 Hydril 563 HES 2.36 10,371.80 10,369.44 2 Casing 7 26.0 L-80 Hydril 563 82.07 10,369.44 10,287.37 1 BFL Collar 8 5/8 Hydril 563 HES 2.03 10,287.37 10,285.34 f'- 52 Casing 7 26.0 L-80 HTTC 2,144.21 10,285.34 8,141.13 it 1�- 1 "ES"cmt stg tool 85/8 Hdril 563 HES 3.07 8,141.13 8,138.06 198 Casing 7 26.0 L-80 HTTC 8,114.52 8,138.06 23.54 1 Cutoff 7 26.0 L-80 HTTC 23.54 23.54 0 Csg Wt.On Hook: 188,000 Type Float Collar: Conventional No.Hrs to Run: 30 Csg Wt.On Slips: 152,000 Type of Shoe: EZ reamer Baker Casing Crew: Weatherford Cat Rotate Csg X Yes No Recip Csg X Yes_ No 15 Ft.Min. 10.8 PPG Fluid Description: LSND Liner hanger Info(Make/Model): Liner top Packer?: Yes No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: Solid body centralizers every jt from TD to 9544'MD(21 ea). Solid body every other jt from 9544'-T/ 8144'(16 ea).Solid body centralizer every jt F/8144'-T/7401'MD(20 ea). Note:atg tool @ 8140'+/-and centralized above and below. 3 solid body centralizers across 9-5/8"shoe F/4978'-T/ 4897'MD. 60 solid body centralizers total for 7"casing run. CEMENTING REPORT Shoe @ 10416 FC @ 10,371.00 Top of Liner Preflush(Spacer) Type: Tuned Spacer III Density(ppg) 11.5 Volume pumped(BBLs) 30 Lead Slurry Type: Class"G"premium cmt Sacks: 138 Yield: 1.63 Density(ppg) 15.3 Volume pumped(BBLs) 40 Moving/Pumping Rate(bpm): 4 Tail Slurry w Type: Sacks: Yield: L":- Q1.- ''' Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): //' 6�✓ ur Post Flush(Spacer) C !•� ~ S ( re Type: Density(ppg) Rate(bpm): Volume: w Displacement: q�lk Type: LSND mud Density(ppg) 10.8 Rate(bpm): 4 Volume(actual/calculated): 393.7/393.7 r FCP(psi): 330 Pump used for disp: RIG Bump Plug? X Yes No Bump press 1010 / Casing Rotated? X Yes _No Reciprocated? X Yes No %Returns during job 100 ( Cement returns to surface? Yes X No Spacer returns? X Yes No Vol to Surf: 0 r....0 Cement In Place At: 10:25 Date: 6/21/2017 Estimated TOC: 0 Method Used To Determine TOC: Y tV Stage Collar @ 8138 Type "ES"collar Closure OK ok 0(1-Pc' Preflush(Spacer) Type: Tuned Spacer III Density(ppg) 11.5 Volume pumped(BBLs) 30 Lead Slurry Type: Sacks: Yield: .11'� Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): 1 1 Tail Slurry 1 Type: Class"G"Premium Cmt Sacks: 145 Yield: 1.24 lir w Density(ppg) 15.3 Volume pumped(BBLs) 32 Mixing/Pumping Rate(bpm): 3 zo Post Flush(Spacer) 8 Type: Density(ppg) Rate(bpm): Volume: w yr Displacement: Type: LSND Mud Density(ppg) 10.8 Rate(bpm): 4 Volume(actual/calculated): 314/311.4 FCP(psi): 520 Pump used for disp: Rig Bump Plug? X Yes No Bump press 2000 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 100 Cement returns to surface? _Yes X No Spacer returns? _Yes X No Vol to Surf: 0 Cement In Place At: 19:30 Date: 6/21/2017 Estimated TOC: 7,151 Method Used To Determine TOC: Calculated www.wellez.net WellEz Information Management LLC ver_102716bf i i MPC-46 Days vs Depth 0 500 -MPC-46 Plan 1000 -MPC-46 Actual 1500 2000 2500 3000 3500 4000 4500 .c 5000 0 O. 5500 to 6000 v c 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 I 1 0 5 10 15 20 25 30 35 40 45 Days 8/8/2017 • • v; co C3 c E 016 E 0 >. U 0) C --"Z Ct o co ... iii. e.., .._ -0 cTi X o 4) E o) @ m U o) CDN C M ) bi U 0 Euo O . ,„ o ,.... E c . 0>• (n (1110 144 v � E'". :0 E(i) a) 0Q �p tO i u.. _2 (ct . . . . E ov 0 ._ cr, .._.. O o _ ... z 0 I ►- a) (n , Q m 0 bc JD iii X_ O r N . (0 � O (.) (0 0 0 N O ti 0 . O NNNZZ — co C m O N ac cl.E N 6 a. 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U O� s E -c E >'a cc _c }- ca � a a) � a`) 0 v Tu E a D No - cn x c L ca m co o ax) .� o v -2 o Q N 2 .� Q o its `o ,S -c 2 a) U 0 N ,L o D W c4i 0 o U) Cn C O "iii 5 0 o SD C c0i Z L.7., C s o 2E cn .Ca 0 � 2E o 0 1 0 w m m 0 C 0 Q CD p X a) a) _c _c u) a) P a Z a) N F- T a a) 0 o ca u) E a) • S • & 2 0 0 0 0 0 0 0 0 0 0 i o o 0 0 0 o N- o o - CO co co \ 0 CD 0 0 0 0 / 0 0 0 0 0 0 0 ƒ 0 0 0 0 0 0 2 m Q \ 03 , 0 2 / 5 • 7 . o 9 » • - » # = k %\ • \ CO 0 y \ \ \ \ 2§ o 0 c.„!.) / / 0 § 2 \§ CO \ \ CO \ • CO ] _} { = '-g � § ; \ \ 2§ ( \ e ) ® 0 > W /} • \ - / )\\ \/ \ - &>s - ° \ / E \ \ a) \Ta\/ 00 I1) 0) \ > \ }o§ \ - \ 2 c c - f N §/ ! �f , /6 5 / E c » \ R § � ; > 6 z & § \ 0 f/ 7 §ƒ • o /- / - c ec \ 0 .0\ /\\ 3 k§ §© j± }\ 20 ca \/ \) / E1c1p» ® >- \- / k® n/ § }] §- E 7] j § / E0 /kai\ \k \-) §� �/ e •- \ 8_\ - *:: 0k }3 RECEIVED Schlombarger JAN 0 9 2018 FracCAT Treatment Report AOGCC Well :MPC-46 Field :Milne Point Formation :Sag River Prepared for Client :Hilcorp Alaska Client Rep :Jim Fagnant Date Prepared :July 11,2017 Prepared by Name :Michael Hyatt Division :Schlumberger Phone :907 227 9897 Pressures Initial Wellhead Pressure(psi) 91 Maximum Surface Treating Pressure(psi) 5,270 Injection ISIP(psi) 2,133 Maximum Rate(bbl/min) 30.4 Calibration ISIP(psi) 2,615 Post Job ISIP (psi) 4,008 Treatment Totals Total Slurry Pumped(Freeze Protect+Water+ 2,542 Total Water Pumped from Straps(bbl) 2,368 Adds+Proppant)(bbl) Total Clean Fluid Pumped(Water+Freeze 2,286 Total 16/20 CarboBOND Lite Pumped(lb) 229,720 Protect)(bbl) Total YF130FIexD(bbl) 1 818 (Total 16/20 CarboBOND Lite Placed in Formation 228,100 Total WF130(bbl) 440 Freeze protect(bbl) 28 Total Chemical Additives Consumed Past WH Consumed Past WH J580,Guar gel(Ib) 2,773 2,710 M275,Biocide(Ib) 36 30 L071,Temporary Clay Stabilizer 182 182 J569,Mid-Temperature 290 290 (gal) Encapsulated Breaker(Ib) J450,Stabilizer(gal) 36 36 J218,Live Breaker 55 55 F112,Surfactant(gal) 86 86 J134,Enzyme Breaker(Ib) 15 0 J604,Crosslinker(gal) 193 193 Freeze Protect(bbl) 28 19 M002,Activator(Ib) 182 182 Disclaimer Notice This information is presented in good faith,but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service.The results given are estimates based on calculations produced by a computer model including various assumptions on the well,reservoir and treatment.The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model,the assumptions and such input data.The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values.The quality of input data,and hence results,may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well,the reservoir,the field and conditions affecting them.If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue.Actual charges may vary depending upon time,equipment,and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. • • Schlumbevger Client:Hilcorp Alaska Well:MPC-46 Formation:Sag River District:Prudhoe Bay Country:United States Section 1 : Executive Summary On July 11,2017 Schlumberger successfully completed a single stage fracturing treatment on Milne Point C-46.The frac crew arrived on location at 6:15. At this time,Schlumberger was able to spot bleed tanks,assist Stinger in rigging up the treesaver,complete the rigup of our treating iron, and bleed lines. At approximately 10:30,we started firing up backside equipment and performing bucket checks. At 12:30,we started firing up our pumps. At 14:26 we had a successful pressure test and began our safety meeting. After the safety meeting, Schlumberger started to mix gel and we confirmed a 30 lb gel at 15:40. Once the gel was confirmed,the wellhead was opened and we began the job. The DataFRAC was pumped, consisting of 160bbl linear gel(WF130),followed by 100bbI crosslinked gel(YF130FIexD), a 50 bbl 1 PPA Scour step, 150 bbl of YF130FIexD, which was displaced with 160bbl WF130. Based off the analysis of the DataFRAC, no design changes were made to the designed pumped volumes. However,the decision was made by on-site Hilcorp representatives to pump a slightly more aggressive breaker schedule. Schlumberger's engineers did not see a potential problem with the new schedule,and the changes were made to the pump design. The calibration analysis showed a closure pressure of 5,552 psi,fluid efficiency of 49% and resulted in a new total leak off coefficient of 2.2E-3 ft/min0.5. During the prop frac all of the planned 229,720 lb of CarboBOND Lite 16/20 was pumped in a total of 2,542 bbl of slurry(all fluid volumes considered). Flush was called at a wellhead density of 10.0 ppg or a total slurry volume of 2,394 bbl. We shutdown at a total slurry volume of 2,542 bbls. This yields a total flush volume of 148 bbl,or a 5 bbl underflush. This 5 bbl was 12 PPA slurry and resulted in a total of 228,100 lb of proppant placed into formation. The final ISIP was 4,008 psi. Schlumberger closed the wellhead at 20:24 with 3,797 psi on surface. On July 12, 2017 Schlumberger assisted Stinger in rigging down the treesaver and rigged down our treating equipment. Once complete,we began the demobilization of our equipment. • i Schiumberger Client:Hilcorp Alaska Well:MPC-46 Formation:Sag River District:Prudhoe Bay Country:United States Section 1 : As Measured Pump Schedule As Measured Pump Schedule Ste Ste Slurry Slurry Pump Fluid MaxrProp Prop p p Volume Rate Time Fluid Name Volume Proppant Name p Conc Mass # Name (bbl) (bbl/min) (min) (gal) (PPA) (PPA) (Ib) 1 Injection n 160.6 27.4 6.7 WF130 6727 0.0 0.0 0 2 OF 100.0 28.9 3.7 YF130FIexD 4178 0.0 0.0 0 3 DF 48.0 29.7 1.6 YF130FIexD 1939 16/20 CarboBond Lite 1.0 0.6 1639 4 DF 150.0 30.0 5.0 YF130FIexO 6282 16/20 CarboBond Lite 1.0 0.0 387 5 DF Flush 160.0 29.9 5.7 WF130 6716 0.0 0.0 0 6 PAD 550.0 29.7 18.6 YF130FIexD 23085 0.0 0.0 0 7 1.5 PPA 122.0 29.4 4.2 YF130FIexD 4844 16/20 CarboBond Lite 1.9 1.2 5961 8 2.5 PPA 122.0 29.5 4.1 YF130FIexD 4602 16/20 CarboBond Lite 3.0 1.2 11163 9 3.5 PPA 122.0 29.5 4.1 YF130FIexD 4417 16/20 CarboBond Lite 3.9 0.2 15124 10 4.5 PPA 122.0 29.4 4.1 YF130FIexD 4247 16/20 CarboBond Lite 5.0 1.3 18765 11 5.5 PPA 122.0 29.4 4.1 YF130FIexD 4090 16/20 CarboBond Lite 5.9 3.6 22120 12 6.5 PPA 122.0 29.4 4.1 YF130FIexD 3945 16/20 CarboBond Lite 6.9 5.0 25227 13 7.5 PPA 122.0 29.4 4.2 YF130FIexD 3809 16/20 CarboBond Lite 8.0 5.6 28146 14 8.0 PPA 69.9 29.3 2.4 YF130FIexD 2143 16/20 CarboBond Lite 8.1 5.0 16975 15 9.0 PPA 69.4 29.3 2.4 YF130FIexD 2064 16/20 CarboBond Lite 9.1 2.3 18238 16 10.0 PPA 70.2 29.3 2.4 YF130FIexD 2022 16/20 CarboBond Lite 10.2 3.1 19869 17 11.0 PPA 69.4 29.2 2.4 YF130FIexD 1937 16/20 CarboBond Lite 11.1 5.2 20964 18 12.0 PPA 93.0 29.1 3.2 YF130FIexD 2741 16/20 CarboBond Lite 12.3 0.0 25143 19 Flush 120.0 26.5 4.6 WF130 5032 16/20 CarboBond Lite 0.0 0.0 0 Freeze 20 Protect 27.4 18.5 1.8 Freeze Protect 1172 0.0 0.0 0 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step# Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 Injection Test 27.4 30.1 4279 5270 211 2 DF 28.9 30.4 3670 4026 733 3 DF 29.7 30.1 3549 3603 3501 4 DF 30.0 30.2 3572 3682 3474 5 DF Flush 29.9 30.3 3751 3811 884 6 PAD 29.7 30.1 3825 4068 1877 7 1.5 PPA 29.4 29.9 3870 4054 3677 8 2.5 PPA 29.5 29.8 3635 3684 3602 9 3.5 PPA 29.5 29.6 3766 3829 3684 10 4.5 PPA 29.4 29.5 3873 3921 3829 11 5.5 PPA 29.4 29.6 3969 4035 3913 12 6.5 PPA 29.4 29.6 4087 4152 4026 13 7.5 PPA 29.4 29.6 4201 4258 4150 14 8.0 PPA 29.3 29.4 4280 4316 4245 15 9.0 PPA 29.3 29.5 4329 4357 4314 16 10.0 PPA 29.3 29.4 4399 4427 4356 17 11.0 PPA 29.2 29.3 4470 4510 4413 18 12.0 PPA 29.1 29.6 4554 4621 4473 19 Freeze Protect 26.5 30.2 4770 5082 4257 i • Schlumbevger Client:Hilcorp Alaska Well:MPC-46 Formation:Sag River District:Prudhoe Bay Country:United States Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step# Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 20 Freeze Protect 18.5 19.2 4449 4638 3812 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) I 2542 89.5 95994 229720 Average Treating Pressure: 3991 psi Maximum Treating Pressure: 5270 psi Minimum Treating Pressure: 211 psi Average Injection Rate: 29.1 bbl/min Maximum Injection Rate: 30.4 bbl/min Average Horsepower: 2844.7 hhp Maximum Horsepower: 3819.2 hhp Maximum Prop Concentration: 12.3 PPA • • Schiumberger Client:Hilcorp Alaska Well:MPC-46 Formation:Sag River District:Prudhoe Bay Country:United States Section 2: Job Messages Message Log Treating Annulus Time Message Pressure Pressure Total Slurry Slurry Rate Prop.Conc. (psi) (psi) (bbl) (bbl/min) (PPA) 1 12:16:18 Reset Executed Steps 0 0 0.0 0.0 0.0 2 12:16:18 Reset Executed Steps 0 0 0.0 0.0 0.0 3 12:35:18 Firing Pumps -15 -27_ 0.0 2.7 0.0 4 13:04:13 Priming the POD -0 0 0.0 0.0 0.0 5 13:18:01 Priming Pumps 65 99 0.0 5.7 0.0 6 13:32:34 Pumps are primed 78 99 0.0 0.0 0.0 7 13:34:15 Low PT 3135 99 0.0 0.0 0.0 8 13:38:31 Bleeding Down.Leak on HP Iron. 0 99 0.0 0.0 0.0 9 13:58:43 Replaced rubber seal.Rolling pumps to verify 60 100 0.0 4.0 0.0 Prime. 10 14:08:19 Low PT 3454 100 0.0 0.0 0.0 11 14:24:55 High PT 7915 100 0.0 0.0 0.0 12 14:41:10 PJSM Complete 87 101 0.0 0.0 0.0 13 14:46:50 Brining IA to 2500 psi 85 248 0.0 0.0 0.0 14 15:40:36 30#Verified by QC 92 2512 0.0 0.0 0.0 15 15:40:46 Wellhead Open 91 2512 0.0 0.0 0.0 16 15:40:53 Start Injection Test Automatically 175 2516 0.0 0.0 0.0 17 15:40:53 Start Propped Frac Automatically 175 2516 0.0 0.0 0.0 18 15:40:53 Start 230klbs slow Automatically _ 175 2516 0.0 0.0 0.0 19 15:40:53 Started Pumping 175 2516 0.0 0.0 0.0 20 15:40:57 Activated Extend Stage 313 2540 0.1 1.6 0.0 21 15:46:26 79 Degrees 26 visc 4017 2914 128.7 30.1 0.0 22 15:47:30 Stage at Perfs:Injection Test 926 2892 160.5 10.1 0.0 23 16:25:33 Deactivated Extend Stage 741 2919 160.6 0.0 0.0 24 16:25:34 Start DF Automatically 741 2919 160.6 0.0 0.0 25 16:30:23 Started Pumping Prop 3601 2957 260.4 30.1 0.0 26 16:30:24 Start DF Automatically 3612 2943 260.9 30.1 0.1 27 16:31:39 87 degrees 22cp 3530 2993 298.1 29.5 1.0 28 16:32:01 Start DF Automatically 35011 3020 308.9 29.5 1.0 29 16:32:23 Stopped Pumping Prop 34901 3026 319.8 29.6 0.2 30 16:32:25 Stage at Perfs:DF 3454 3028 320.7 29.6 0.0 31 16:35:36 83 deg 25cp 3589 3071 416.4 30.1 0.0 32 16:35:45 Stage at Perfs:DF 3597 3074 420.9 30.0 0.0 33 16:37:01 Start DF Flush Automatically 3688 3059 459.0 30.2 0.0 34 16:37:04 Activated Extend Stage 3704 3062 460.5 30.3 0.0 35 16:37:21 Stage at Perfs:DF 3718 3066 469.0 30.2 0.0 36 19:00:18 85 deg 27cp 886 3052 617.7 0.0 0.0 37 19:02:04 Deactivated Extend Stage 884 3055 617.7 0.0 0.0 38 19:02:33 Stage at Perfs:DF Flush 2572 3148 618.6 8.6 0.0 39 19:02:33 Start PAD Automatically 2572 3148 618.6 8.6 0.0 40 19:08:08 Stage at Perfs:PAD 3698 3043 778.6 30.0 0.0 41 19:10:03 86 deg 27cp 3795 3078 835.9_ 30.0 0.0 42 19:19:46 84deg 25cp 4066 3069 1126.2 29.9 0.0 43 19:21:11 Start 1.5 PPA Automatically 4064 3065 1168.6 29.9 0.0 44 19:21:54 Started Pumping Prop 4002 3064 1189.8 29.2 0.0 45 19:25:21 Start 2.5 PPA Automatically 3684 3046 1291.1 29.6 2.0 46 19:26:37 Stage at Perfs:1.5 PPA 3594 3038 1328.4 29.5 2.2 • 0 Schiumberger Client: Pp Alaska MPC-46 PG46 Formation:Sag River District:Prudhoe Bay Country:United States Message Log Message Treating Annulus Total Slurry Slurry Rate Prop.Conc. # Time Pressure Pressure (psi) (psi) (bbl) (bbl/min) (PPA) 47 19:28:03 83deg 25cp 3634 3033 1370.5 29.6 2.6 48 19:29:29 Start 3.5 PPA Automatically 3675 30361 1412.8 29.5 3.0 49 19:30:47 Stage at Perfs:2.5 PPA 3760 3026 1451.1 29.6 3.3 50 19:33:37 Start 4.5 PPA Automatically 3832_ 3000 1534.6 293 3.9 51 19:34:55 Stage at Perfs:3.5 PPA 3864 2979 1572.8 29.3 4.3 52 19:37:46 Start 5.5 PPA Automatically 3926 3034 1656.7 29.4 4.9 53 19:39:03 Stage at Perfs:4.5 PPA 3941 3030 1694.5 29.5 5.2 54 19:41:55 Start 6.5 PPA Automatically 4019 3045 1778.9 29.4 5.9 55 19:43:12 Stage at Perfs:5.5 PPA 4070 3054 1816.7 29.4 6.3 56 19:43:19 29cp 86deg 4047 3057 1820.1 29.4 63 57 19:46:04 Start 7.5 PPA Automatically 4172 3079 1901.0 29.3 6.9 58 19:47:21 Stage at Perfs:6.5 PPA 4191 3081 1938.7 29.3 7.3 59 19:50:13 Start 8.0 PPA Automatically 4259 3030 2023.0 29.3 8.0 60 19:51:31 Stage at Perfs:7.5 PPA 4274 3022 2061.0 29.4 7.9 61 19:52:36 Start 9.0 PPA Automatically 4318 3010 2092.8 29.2 8.0 62 19:54:58 Start 10.0 PPA Automatically 4370 3033 2162.1 29.3 9.1 63 19:55:41 Stage at Perfs:8.0 PPA 4395 3017 2183.1 29.4 10.2 64 19:56:07 83deg 30cp 4394 3011 2195.7 29.2 9.8 65 19:57:22 Start 11.0 PPA Automatically 4429 2993 2232.3 29.2 10.0 66 19:58:04 Stage at Perfs:9.0 PPA 4462 2988 2252.8 29.3 11.1 67 19:59:29 Stop mixing gel 4506 3045 2294.1 29.2 11.2 68 19:59:45 Start 12.0 PPA Automatically 4503 3040 2301.8 29.0 11.1 69 19:59:46 Activated Extend Stage 4509 3038 2302.3 29.0 11.0 70 20:00:26 Stage at Perfs:10.0 PPA 4550 3035 2321.8 28.9 12.2 71 20:02:51 Stage at Perfs:11.0 PPA 4421 3014 2392.2 29.6 0.0 72 20:02:56 Deactivated Extend Stage 4304 2986 2394.6 28.4 0.0 73 20:02:56 Start Flush Manually 4304 2986 2394.6 28.4 0.0 74 20:05:30 Stage at Perfs:12.0 PPA 5074 3016 2461.9 27.6 0.0 75 20:07:32 Start Freeze Protect Automatically 4277 3007 2514.9 19.0 -13 76 20:07:36 Activated Extend Stage 4418 3101 2516.2 18.7 -1.8 77 20:07:38 Stopped Pumping Prop 4225 3040 2516.8 18.7 -2.0 78 20:09:16 Shutdown 3969 3048 2542.0 0.6 0.0 79 20:24:08 well shut in 3797 3124 2542.0 0.0 0.0 • , Schiumberger Client:Hilcorp Alaska Well:MPC-46 Formation:Sag River District:Prudhoe Bay Country:United States Section 3: Treatment Plots - TR_PRESS - AN PRESS HilcorpE Test MPC-46 July 11,2017 Clean Fluid� Rate --^ - PROP_CON BH_PROP_CON 9000 20 -7 8000 -6 ^16 7000 -5 6000 -12 w 5000 -4 v ea � • g o — a � 4000 -3 D 18 3000 • -2 2000 -4 -1 1000 -_- t 0 """P� ,�Yl , ` 0 -0 13:41:14 13:57:54 14:14:34 14:31:14 14:47:54 Time-hh:mm:ss ©Schlumberger 1994-2015 Schlumberger • • Schiumberger ClientAa Well:MPC-46 Formation:Sag River District:Prudhoe Bay Country:United States — TR_PRESS — AN PRESS H ilcof DataFrac MPC-46 SLUR_RATE July 11,2017 — Clean Fluid Rate ---✓ — PROP_CON - BN_PROP CON 7000 • 35 -7 6000-------..._- - 30 -6 5000- — 25 -5 T. to a\ 4000- -20 ° -4 v a ® O b _ ~ 3600 1. -15 2" -3 D .... ...kr ..., 2000- ice- -10 -2 1000 4 ------- --...-. .._�_.}._, - 5 -1 0 t . 0 -0 15:33:39 1623:39 17:1'3:39 18:03:39 18:53:39 Time-hh:mm:as C Schlumberger 1994-2015 Schlumberger • • Schiumberger Client:Hilcorp Alaska Well:MPC-46 Formation:Sag River District:Prudhoe Bay Country:United States {. __._ .---- — AN_PRESS Hilcorp — SLUR_RATE i Main Treatment MPC-46 July 11,2017 Clean Fluid Rate - PROP_CON — BH_PROP_CON 7000 . • , 35 15 6000 --30 12 5000 25 ...41110 ce o. 4000 -- --- 9 (6.., v 20 o a 0 W f7 a` 4,111c v 3000 -.J -a/1� 15 3 D -6 2000 - 10 1000�J 5 0' - 0 -0 18:57:19 19:22:19 19:47:19 20:12:19 20:37:19 Time-hh:mm:es Schlumberger©Schlumberger 1994-2015 • • Schiumberger MC- Client: PpAlaska Well:MPC 46 Formation:Sag River District Prudhoe Bay Country:United States — Slurry Rate DataFrac Liquid Additive Plot Hilcorp Alaska — Clean Fluid Rate MPC-4b — 0028-5 Conc 35 , 07-11-2017 — J604 Conc 7 - J450 Conc — 1071 Conc 30 - — F112 Cone 6 Van C 25 5 E 1r• .0 a 20 —4 C: D ill a H n 15 3 O {L Z n 10 -1 — — --2 m 91 3 5 _ — 1 m I o 0 16:15:39 16:2904 16:3829 1646:54 16:57:19 Time•hh:mm:s ©Schlumberuer 1994-2016 Schlumberger — Slurry Rate Main Treatment Liquid Additive Plot Hiicom Alaska — Clean Fluid Rate MPC-46 — 0028-5 Conc 35 07-11-2017 — J604 Conc 7 — J450 Conc - L071 Conc ' 30 (yam ••••••••• F112 Conc 6 i C 25'_ 5 r Ea c a20- — — -- —a a D 15 3 Q Z n 10 2 11:1m 5- i . 3 CO 1 y 0 0 1644:55 19:09:55 19:34:55 1959:55 20:24:55 Time-hh:mm:s ©Schlumberger 1994-2016 Schlumberger 0 i Scifiumberger Client:Hilcorp Alaska Well:MPC-46 Formation:Sag River District:Prudhoe Bay Country:United States — Slurry Rate DataFrac Dry Additive Plot Hilcorp Alaska — Clean Fluid Rate MPC-46 07-11-2017 — Breaker Concentration 35 , 14 30 1 i zr +�"- 12 _r 25 10 c c a T. E 20 8 a 7o 0 .a O Z I- 15— s n Q IX v 10-.._._._............. -q 12 d 5l'( - . 2 l'j 0-, A o 153359 15:54:49 161519 113:i629 16:5719 Time-hh:mms ©Schlumberger 1994-2016 Schlumberger — Slurry Rate Main Treatment Dry Additive Plot Hilcorp Alaska MPC-46 07-11-2017Breaker Concentration 35 14 30- ___...._ �..... — _— -12 r 25 10 a c c a E D a „yn,y Z W 15 6 n Q 10-- 4 fC d frjrin 5- 2 18:50:08 19:1508 19:468 20:05:08 20:30.08 Time-hh:mm:ss ©$chlumberper 1991-2016 Schlumberger �► 217052 Seth Nolan Hilcorp Alaska, LLC 2 8 4 8 GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 RECEIVED Tele: 907 777-8308 Hilenarp Alaska,t.1.t: Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATA A5/LOGGED1 AUG 0 9 2017 M K BENDER DATE 08/08/2017 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU C-46 Prints: GR/CCL/3.375"Chem Cutter/1.56"Tubing Punch CD 1: Hilcorp MPC-96 TUBING CUT_20JUL 17-FINAL 7/31/2017 3:11 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received Bm 4 Date: t , 4IWA Ptk - 4c. FM Regg, James B (DOA) zi7o5z From: Sloan Sunderland <ssunderland@hilcorp.com> Sent: Monday, June 5, 2017 11:09 AM To: DOA AOGCC Prudhoe Bay; Regg, James B (DOA) Cc: Paul Mazzolini;Joe Engel; Doug Yessak - (C);James Lott - (C) Subject: Innovation BOP usage Report 6/4/2017 Attachments: Notice of BOP Usage B.docx Sloan Sunderland Hilcorp Drilling Forman Office-907-670-3094 Cell-907-715-0591 1 • • 11# rrp.%6f ,1.l{: Notice of BOP Use • Date/Time: 6/4/2017 at 17:34 hrs. • Well: MPU-C46 • Location: Milne Point, C pad, C-46 • PTD: 217-052 • Rig Name: Hilcorp Innovation • Operator Contact: Sloan Sunderland at 907-670-3094 ssunderland@hilcorp.com • Operation Summary: After setting a balanced cmt plug @ 7320- 6800 +/- we pulled out to 6500' and circ btm up. Well was still flowing after shutting pumps off. • BOPE Used: Annular • Reason For BOPE Use: Had drilling mud flowing out the annulus @ 60 BPH. The well was shut in to hold cmt plug in place until 2500 psi compressive strength has been reached. • Actions Taken: Monitored SICP throughout the day and pressure built to 34 psi, SIDP psi built to 26 psi. We have bled back a total of 4.2 bbls and pressures have came back up to SICP 36 & SIDP @ 18psi. We are going to open up the well and circ btm up to check MW. We have been shut in for 21.5 hrs waiting on cmt. 4 • • Zi 775-7 Regg, James B (DOA) From: Sloan Sunderland <ssunderland@hilcorp.com> 61r,11 Sent: Friday, June 2, 2017 12:04 AM To: DOA AOGCC Prudhoe Bay; Regg,James B (DOA); Schwartz, Guy L (DOA) Cc: Paul Mazzolini;Joe Engel; Doug Yessak - (C) Subject: Hilcorp Notice of BOPs usage Attachments: Notice of BOP Usage.docx See attached report for BOP usage. Sloan Sunderland Hilcorp Drilling Forman Office-907-670-3094 Cell-907-715-0591 1 • S Hol..rp,cho.,oi.I.i i Notice of BOP Use • Date/Time: 6/1/2017 at 02:15 hrs. • Well: MPU-C46 C46 • Location: Milne Point, C pad, C-46 • PTD: 217-052 • Rig Name: Hilcorp Innovation • Operator Contact: Sloan Sunderland at 907-670-3094 ssunderland@hilcorp.com • Operation Summary: Fill drill pipe after RIH to shoe @ 4918'. Build volume at shoe in prep to heal up loss zone and kill water flow. • BOPE Used: Annular • Reason For BOPE Use: Had drilling mud slowly start to flow down the flow line @ 1 BPH. • Actions Taken: Monitored SICP and pressure built to 4 psi, SIDP psi built to 49 psi. Bullhead 50 bbl. Shut down and monitor pressure while building mud volume. Pressure built to 33 psi on the casing in 14 hrs. SIDP 20 Psi. Pump 15 bbl 13 PPG mud down DP. @ 1630 Bull head 35 bbl down the annulus. SICP Opsi, SICP 0 psi. Open up well and monitor. Slight losses. RIH from shoe @ 4954' T/ 6554'. Had slight flow while making a conection. Shut in annular and monitor pressure @ 1800. Bull head 25 bbl 13 ppg mud down annulus. Well slightly loosing. @ 1830 Open annular and Continue RIH F/ 6554' trying to get to 7920' to heal losses and kill well. of Tits S ,e,�1//7'i; THE STATE Alaska Oil and Gas OfA LAsKA. Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 \ Main: 907.279.1433 ALAS*P Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manger Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Sterling-Sag River Oil Pool, MPU C-46 Permit to Drill Number: 217-052 Sundry Number: 317-322 Dear Mr. York: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this 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. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, atja Hollis S. French Chair DATED this 11' day of July, 2017. RBDMS l/ti JUL 1 3 2017 0 • RECEIVED STATE OF ALASKA JUL S 7017 �, ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AG ( 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑., I Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing 2 , Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other:Complete❑., ' 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development E r 217-052 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-029-23576-00-00 , 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.423 r Will planned perforations require a spacing exception? Yes ❑ No 0 / MPU C-46 i 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL047434/ADL025516 , Milne Point Field/Sag River Oil Pool . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 10,430' 9,011' , 10,285'• 8,883' . 3,728 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 16" 140' 140' N/A N/A Surface 4,929' 9-5/8" 4,955' 4,650' 5,750psi 3,090psi Production 10,393' 7" 10,416' 8,998' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic 4 See Schematic 4-1/2" 13.5/L-80/Hydril 625 10,003' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 4.5 X 7"Premier and N/A ti 9,886(MD)/8,540(TVD)and N/A 12.Attachments: Proposal Summary Q Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑., Exploratory ❑ Stratigraphic❑ Development • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 7/21/2017 ❑ • ❑ WDSPL ❑ Suspended ❑ Commencing Operations: OIL WINJ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York Contact Name: Paul Chan Authorized Title: Operations Manager Contact Email: pChantu�hiIcorp.Com Contact Phone: 777-8333 Authorized Signature: r‘--------- Date: 13`�� ,7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 317- 3 2. 2 Plug Integrity,,``❑ BOP�Testr� Mechanical Integrity1111Test ❑ Location Clearance Other: T `L > .i 4�1.) b E'S�; 2S©1 P�4 ;k�N 0...AARSz..- Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: 10--4.)4 "``1111 RBDMS JUL 1 3 2017 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: a I'2- It,q Ctii..11 fAh ?1114/9-- 1 7/W/47 IGINAL Submit Form and Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate • • Well Prognosis Well: MP C-46 Hilcorp Alaska,LL Date:7/11/2017 Well Name: MP C-46 API Number: 50-029-23576-00 Current Status: Oil Well (New Well) Pad: C-Pad Estimated Start Date: July 17th, 2017 Rig: ASR#1 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 217-052 First Call Engineer: Paul Chan (907) 777-8333 (0) (907)444-2881 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907)947-9533 (M) Current Bottom Hole Pressure: 4,603 psi @ 8,750' TVD (Estimated reservoir pressure/ 10.1 ppg EMW) Maximum Expected BHP: 4,603 psi @ 8,750' TVD (Estimated reservoir pressure/ 10.1 ppg EMW) MPSP: 3,728 psi (0.1 psi/ft gas gradient)t----- Brief Brief Well Summary: The Milne Point C-46 well was drilled as a Sag River development well in June 2017 and completed with a 4-1/2" fracture stimulation string. After the fracture stimulation, the 4-1/2" tubing string will be replaced by a 2-7/8" permanent completion.The well is cased and cemented. Objective: Replace the 4-1/2"tubing with a 2-7/8" 13Cr-80 completion. Pre-Rig Procedure: 1. RU E-line.Test lubricator to 250 psi low/4,000 psi high. 2. RIH w/chemical cutter and cut the Baker Premier packer mandrel. 3. POOH. RD E-line. 4. Clear and level pad area in front of well. Spot rig mats and containment. 5. RD well house and flowlines. Clear and level area around well. 6. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 7. Pressure test lines to 4,000 psi. 8. Circulate at least one wellbore volume with ±8.5 ppg seawater down tubing,taking returns up casing to 500 bbl returns tank. Calculate kill weight fluid and circulate the well dead. 9. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 10. RD Little Red Services and reverse out skid. 11. RU crane. Set BPV. ND Tree. NU 11" BOPE. RD Crane. 12. NU BOPE house. Spot mud boat. Brief RWO Procedure: 13. MIRU Hilcorp ASR#1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 14. Contingency Casing Jack Operation: a. PU Casing Jacks via the beaver slide and tugger winches to rig floor. b. Set Casing Jacks on top of the BOP Annular with tugger winches. Connect hydraulics and function test same. 15. Check for pressure and if 0 psi pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well with kill weight fluid prior to pulling BPV. Set TWC. • • . Well Prognosis Well: MPC-46 Allcorn Alaska,LL) Date:7/11/2017 16. Test BOPE to 250 psi Low/4,000 psi High, annular to 250 psi Low/2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. p - .. �` b. Notify AOGCC 24 hours in advance of BOP test. W` r 'C4 c. Confirm test pressures per the Sundry Conditions of approval. ` �y d. Test Annular,VBR and pipe rams on 2-7/8" and 4-1/2" test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 17. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV ..,)/< profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer(Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr.Jim Regg (AOGCC)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure � .? c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor � the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed,test the remainder of the system following the normal test procedure (floor valves,gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/ penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 18. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/ kill weight fluid (estimated ±10.1 ppg brine) as needed. 19. Contingency Casing Jack Procedure. a. RU Casing Jack hydraulics to the ASR#1 Control Panel. b. Body Yield strength of 4-1/2" 13.5# L-80 Hydril 625= 307,000 lbs. c. PU weight of string= 130K lbs (Innovation#1 in May 2017). d. Cycle jacks up and down to ensure proper function (dry run without being connected to the tubing hanger). 20. MU landing joint or spear to the tubing hanger. BOLDS. e. Slowly pressure up on jacks. Hold for 5 min. f. If tubing hanger does not unseat or packer does not release, increase in 100 psi increments holding for 5 min between pressure increases. If unable to release tubing hanger, contact Ops Engineer for further discussion. 21. Once hanger and packer comes free, check for flow to ensure well is dead. Recover the tubing hanger. Contingency(If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE per standard procedure. g. Once the tubing hanger is laid down and the packer is unset and moving uphole,set tubing in the lower slips, retract Casing Jacks into lowered position and swap to 'Carriage mode'. �t22. Contingency: If the packer will not release. • • Well Prognosis Well: MP C-46 Ililcorp Alaska,LLQ Date:7/11/2017 a. RU E-line.Test lubricator to 250/4,000 psi. b. RIH w/chemical cutter. Correlate across packer w/GR/CCL. c. Make cut across packer to release Baker Premier Packer. d. POOH. RD E-line. 23. POOH and lay down the 4-1/2"tubing and completion jewelry. Rig down Casing Jacks if needed. • Use lift nubbins and dog collar(as needed)while POOH. • Send 4-1/2" Hydril 625 tubing in for cleaning and store with thread protectors. • Junk 4-1/2" Baker Premier Packer. • Send 4-1/2"Jewelry to Halliburton Shop for re-dress. 24. PU new as lift completion and RIH on 2-7/8" tubing. Set tailpipe at± 10,000' MD. a. RU Weatherford to torque turn the chrome completion. b. Use stabbing guides on connection c. RU i-wire spooling unit for TEC wire d. Space out GLM and jewelry per proposed schematic. 25. Land tubing hanger. RILDS. Note PU (Pick Up) and SO (Slack Off) weights on tally. 26. Drop ball and rod. Pressure up and set Halliburton PHL packer(start 2,500 psi/final 4,000 psi). 27. Pressure up and test tubing to 4,000 psi for 30 min and chart. Bleed tubing to 1500- 1700 psi. 28. Test inner annulus to 3,700 psi for 30 min and chart. Bleed off the tubing pressure and shear the valve in GLM#1. Bleed all pressures to 0 psi. 29. Lay down landing joint. 30. RU hot oil pump and freeze protect the tubing and IA to 2000' MD with diesel. Allow freeze protect to U-tube down tubing. 31. Set BPV. Rig down ASR. Post-Rig Procedure: 32. RD mud boat. RD BOPE house. Move to next well location. 33. RU crane. ND BOPE. 34. NU new 2-9/16" 5,000#tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. Set TWC. Pressure test tree flanges. 35. RD crane. Move 500 bbl returns tank and rig mats to next well location. 36. Replace gauge(s) if removed. 37. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Proposed Tree/Wellhead 5. Blank RWO MOC Form 11 S • Milne Point Unit SCHEMATIC well: MPU C-46 Last Completed: 6/24/2017 • Bacon)Alaska,LLC PTD: 217-052 KBEIev.:31.5'/GLEIev.:15' TREE&WELLHEAD Tree 4-1/16"5M A is a 6 Wellhead Seaboard Weir,w/11"x 5M top flange 16 ' 4-1/2"Tubing Hanger 64 r44 h OPEN HOLE/CEMENT DETAIL 4 4 9-5/8" 251 bbl Type I/II,100 bbl Permafrost'L'in a 12-1/4"Hole ll :', 7" 72 bbl Class"G"in a 8-1/2"Hole CASING DETAIL ES Cementer' i @1898 Size Type Wt/Grade/Conn ID Top Btm 16" Conductor 164/A-106B/Weld 14" Surface 140' 9-5/8" Surface 40/L-80/DWC/C 8.835" Surface 4,955' i ( 7" Production 26/L-80/DWC/C 6.276" Surface 10,416' 1 e' TUBING DETAIL t 4-1/2" Tubing 13.5/L-80/Hydril 625 3.920" Surface 10,003' 9-5/8" 4 g 11"s WELL INCLINATION DETAIL KOP@1,150' MD Max Hole Angle=53.05*@ 6,329' MD ,, JEWELRY DETAIL 4 No Depth ID Item %I 1 9,875' 3.456 4-1/2" RN Nipple 6t l {{ 44 2 9,886' 3.880 4.5 X 7" Premier Packer 4 ; I 4 3 9,932' 3.880 Auto Fill Sub&Mirage Plug 4 10,003' 3.958 Mule Shoe—Btm @ 10,003' p I at 4; '444 Vt. fl I a `' r s;,. 2 LII 44 _ PERFORATION DETAIL 4 " Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status i, \I Sag 10,105' 10,135' 8,728' 8,753' 30 7/11/2017 Open 41 Sag h 7" mea r ,,. , TD=10,430(MD)/TD=9,011'(1VD) PBTD=10,285'(MD)/PBTD=8,883'(ND) Revised by:PC 7/11/2017 11 S Milne Point Unit PROPOSED • Well: MPU C-46 Last Completed: 6/24/2017 • Hilcorp Alaska.LLC PTD: 217-052 KBEIev.:31.5'/GLEIev.:15' TREE&WELLHEAD Tree 4-1/16"5M € t., L Wellhead Seaboard Weir,w/11"x 5M top flange 4-1/2"Tubing Hanger r 16" OPEN HOLE/CEMENT DETAIL ti 4. 9-5/8" 251 bbl Type I/II,100 bbl Permafrost'L'in a 12-1/4"Hole 7" 72 bbl Class"G"in a 8-1/2"Hole 1 • CASING DETAIL ES Cementer @1,898 Size Type Wt/Grade/Conn ID Top Btm ' 16" Conductor 164/A-106B/Weld 14" Surface 140' O ' 9-5/8" Surface 40/L-80/DWC/C 8.835" Surface 4,955' 7" Production 26/L-80/DWC/C 6.276" Surface 10,416' TUBING DETAIL 2-7/8" Tubing 6.4/13Cr-85/JFE Bear 2.441" Surface ±10,000' 9-5/8" > WELL INCLINATION DETAIL KOP @ 1,150' MD 1 Max Hole Angle=53.05° @ 6,329' MD R LI j 2 JEWELRY DETAIL No Depth ID Item 4 4+ & x 1 ±2,260' 2.441" STA 11:2-7/8" 13Cr80 SPMO-1.OM GLM (Dummy Valve) 2 ±3,465' 2.441" STA 10:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 3 ±4,110' 2.441" STA 9:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) i i 4 ±4,775' 2.441" STA 8:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 5 ±5,475' 2.441" STA 7: 2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) '" 6 ±6,350' 2.441" STA 6: 2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) _ 11 7 ±7,210' 2.441" STA 5:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 4 8 ±7,940' 2.441" STA 4:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) _, 9 ±8,660 2.441" STA 3:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) kt toe ?7 12 10 ±9,275' 2.441" STA 2:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 13 11 ±9,740' 2.441" STA 1:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 12 ±9,790' 2.313" 2-7/8"9Cr XD Sliding Sleeve r114 13 ±9,835' 2.414" 2-7/8" 13Cr Pressure Intake Gauge 2 14 ±9,910' 2.313" 2-7/8"9Cr X Profile ' ,;_' WI 15 15 ±9,920' 2.360" 7"x 2-7/8" 13Cr PHL Hydraulic Retrievable Packer ii tt 16 ±9,965' 2.205" 2-7/8"9Cr XN Profile j 16 17 ±10,000' 2.350" 2-7/8" 13Cr WLEG PERFORATION DETAIL — 17 Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Sag 10,105' 10,135' 8,728' 8,753' 30 7/11/2017 Open i Asag GENERAL WELL INFO �. s API:50-029-23576-00-00 7" E � .t Drilled,Cased&Completed by Innovation#1 6/24/2017 TD=10,430(MD)/TD=9,011'(TVD) PBTD=10,285'(MD)/PBTD=8,883'(WD) Revised by:PC 7/11/2017 • • II Milne Point 2016 ASR Rig 1 n11,K.<<, ‘i.4.cx.I.rr. Knight Oil Tools BOP 111 Slips * III 200 Ton Slips Jacking System g AK Shaffer • 11" - 5000 lit l i Iii itiiii Illi tri ill Illi illy a ,�, 2 7/8•' — 5" VBR itiorLtii1 µ 1 -_ 1' `.i l ab l.. 2" Kill Line 2" Choke Line tut III III III ,Ill y 44;*!: ■ ■ e i • t III Iti Ill lit Illi Manual Manual lv'laniial HC_F Updated 2/08/16 • • II PROPOSED TREE/WELLHEAD MPU C-46 Wellhead/Tree 'Warp Alaska.j.j.c. Milne Point Unit MPU C-46 WELL tilr DATE 7/11/17 PROPOSED Hi!carp Alaska, LLC RE NII. .4110 Swab valve Seaboard Tree Cap. Otis stylefit io la t 2 9/16"5K 4'/z"ACME 29/16"5K 0e Vi fp• SI Sell R ,C0 , i Wing valve Seaboard A. �A' V - 2 9/16"5K 0p000 ii 0 0 15) 000 0. bill iliblIIIIIIIIIii SSV valve Seaboard ... R. 2 9/16"5K (e,.. - � � E� 1 Master valve Seaboard "43 2 9/16"SK eila Tbg Hgr,Seaboard SM- k:1 '� ,� E-CL 11 x 4 W'EUE BOX , I API 11"5K top and bottom,4""H" BPV,ported for 2 ea 3/ 8"Control line, [ ' I r 4 1 o 41 ,w/3'pup L-U,DD-NL, T- 1 `- i PN W10220 :: _,� l = API 13 5/6"5K SN \ u' 11x7",SMB 22,8.54 stub Csg Hgr,Seaboard (1 # -,'' acme top x DWC box 5-2213 5/8 x 9 5/8" d�-11 bottom,w/DWC-C pup, Slip type hanger 6.844 bore PN A34330 LU,DD-NL = PN A16232-001 q SN . . • 0. R / � J2 a0 cli o 00_ a, .e o < o.a. n o < a E e o .g V co a \ Ytd / a) 0. ff � � - .- - \ \ / 0 07 // $ $. 03 e % .q 2e \ ƒ k k o m Co 0 - i 0 / 2 > .0 \ U \ a co > co eu c CD 0 &a ■ Ex = — p \ 0 ( -a Lei ° O 0 ƒ < 2 Q) W E § a- a) o e 2 / '\ § / / o a — = § 2 2» 7 th c c # § — \ > 0 k § e ■ _ / / c « E C CD 2 k \ \ k.- o o - .- o •- R O CO _ g e ■ ■ w 0 c _ % £ o_ o. o o » 0 0 .. •. 0 \ / .. \ U c $ g > \ 0 k // a 2 RI 0 c @ @ < < < 2 21 7052 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 Hilenrp:t1sikw.t.t,C. RECEIVED Fax: 907 777-85777-830810 E-mail: snolan@hilcorp.com DATA LOGGED 2017 -r/czr201-7 JUL 0 7 Yl.K BENDER DATE 07/07/2017 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU C-46 Prints: CAL-Y/EDTC/MAST/USIT-D/USRS-B (CEMENT LOG) CAL-Y/EDTC/MAST/USIT-D/USRS-B (CASING PROFILE IMAGER) CAL-Y/EDTC/MAST/USIT-D/USRS-B (CEMENT BOND LOG) DGR-EWR-ADR-ALD-CTN 2"/5"TVD C-46 DGR-EWR-ADR-ALD-CTN 2"/5"TVD C-46PB1 ROP-DGR-EWR-ADR-ALD-CTN 2"/5" MD C-46 ROP-DGR-EWR-ADR-ALD-CTN 2"/5" MD C-46PB1 CD1: 28370 Hilcorp_MPC-46 CBL-USIT 24-]UN-2017 6/30/2017 3:06 PM File folder CD2: 28371 28372 MPU C-46+PB 1_DATA CD 6/24/2017 9:11 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: �� 6.egueet Date: OF 74, • • THE STATE Alaska Oil and Gas Of�LQ KA Conservation Commission 333 West Seventh Avenue M GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OFA 5�� Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manger Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Sag River Oil Pool, MPU C-46 Permit to Drill Number: 217-052 Sundry Number: 317-299 Dear Mr. York: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this 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. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this R day of July, 2017. RBDMS 1/i JUL 1 1 2017 • • RECEIVED STATE OF ALASKA J IN 2 8 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate 0 ' Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate Q . Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other:Complete❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC 1 Exploratory ❑ Development ❑✓ 217-052 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-029-23576-00-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.423 ' Will planned perforations require a spacing exception? Yes ❑ No ❑✓ ( rftPV C-46 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL047434/ADL025516 Milne Point Field/Sag River Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 10,430' . 9,011' . 10,285' s 8,883' . 3,699 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 16" 140' 140' N/A N/A Surface 4,929' 9-5/8" 4,955' 4,650' 5,750psi 3,090psi Production 10,393' 7" 10,416' 8,998' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic , See Schematic 4-1/2" 13.5/L-80/Hydril 625 10,003' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 4.5 X 7"Premier and N/A • . 9,886(MD)/8,540(TVD)and N/A 12.Attachments: Proposal Summary Q Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch E Exploratory ❑ Stratigraphic❑ Development❑✓ • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 7/11/2017 OIL Q . WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. q Authorized Name: Bo York Contact Name: Paul Chan .-r--•—"" Authorized Title: Operations Manager Contact Email: pchantG7hiIcorp.com Contact Phone: 777-8333 Authorized Signature: Date: �v"t ,? COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3t7-2a9 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ .,C'"' {'� Other: Feo«-�-o4Lxs. JuR'r��"CCRt- c&-t1u►R.m Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS V- J V L 1 1 2017 Spacing Exception Required? Yes ❑ No LCJ Subsequent Form Required: \0 ...... 4 0 4 APPROVED BY .q 1-4 I 1 q Approved by: (7.1)._acC----1. COMMISSIONER THE COMMISSION Date: C 'W- ;I Ig-In f x/3/17 0 R I G I N AI-1,1-,7 cAsP4 e ffo/,i? 7/17 1 Submit Form and Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate • • T Post Office Box 244027 LC Anchorage,AK 99524-4027 Hilcorp Alaska, L 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Paul Chan Senior Operations Engineer June 28t", 2017 RECEIVED (907)777-8333 JUN 2 8 2017 AOGCC Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: Hydraulic Fracturing Application,Milne Point Unit, MP C-46 Dear Commissioner Foerster, Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Milne Point Unit, herein submits its application to fracture stimulate MP C-46. Please do not hesitate to contact Paul Chan at 907-777-8333 should you have any questions regarding this application. Sincerely, <f i r—o York, Operations Manager HILCORP ALASKA, LLC Enclosures: Form 10-403 Sundry Attachments • • 20 AAC 25.283 (a)(1) Affidavit Affidavit stating that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided a notice of operations that is in compliance with 20 AAC 25.283 (a)(1) • • VERIFICATION OF NOTICE PER 20 AAC 25.283(a) MILNE POINT UNIT MP C-46 I, PAUL CHAN, Hilcorp Alaska, LLC, ("Hilcorp") do hereby verify the following: I am acquainted with Hilcorp Alaska, LLC's application for sundry approval to the Alaska Oil and Gas Conservation Commission to enhance production of the MP C-46 well via hydraulic fracturing. Pursuant to 20 AAC 25.283(a)(1), I assert that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided notice of Hilcorp Alaska, LLC's proposed operations. DATED at Anchorage, Alaska this 2.g day of 1 U 2017 • Paul han, Sr. Operations Engineer Hilcorp Alaska, LLC STATE OF ALAKSA ) THIRD JUDICIAL DISTRICT ) SUBSCRIBED TO AND SWORN before me this 4' day of ° A-,--e— 2017 YA/L,--‘ NOTARY PUBLIC IN AND FOR THE STATE OF ALSKA My Commission expires: 7— 9-oxo/9 �L1.E Ic rrorr! .. • 20 AAC 25.283 (a)(2) A Plat (A)Showing The Well Location; (B) Identifying each Water Well, if any, Located within a One-Half Mile Radius of the Well's Surface Location;and (C) Identifying for all Well Types each Well Penetration Well API PTD Pool Type Status MPC-01 50029206630000 1811430 KR ESP Producing MPC-02 50029208660000 1821940 KR WAG Injecting MPC-03 50029207860000 1820500 KR 1-OIL Producing MPC-04 50029208010000 1821260 KR 1-OIL Producing MPC-05A 50029212440100 1842430 KR 1-OIL Shut In MPC-06 50029212570000 1842410 KR WAG Injecting MPC-07 50029212660000 1850020 KR 1-OIL Producing MPC-08 50029212770000 1850140 KR WAG Shut In MPC-09 50029212990000 1850360 KR 1-OIL Producing MPC-10 50029212780000 1850150 KR WAG Injecting MPC-11 50029213210000 1850590 KR PWI LTSI MPC-12A 50029213730100 1990910 KR SUSP Suspended MPC-13 50029213280000 1850670 KR ESP Producing MPC-14 50029213440000 1850880 KR ESP Producing MPC-15A 50029213580100 2160700 SR JET Producing MPC-16 50029213640000 1851100 KR SUSP Suspended MPC-17 50029214730000 1852630 KR WAG Shut In MPC-18 50029214790000 1852690 P&A P&A MPC-19 50029215040000 1852960 KR WAG Shut In MPC-20 50029219140000 1890150 KR 1-OIL LTSI MPC-21 50029224860000 1940800 KR 1-OIL Shut In MPC-22A 50029224890100 1951980 KR ESP Producing MPC-23 50029226430000 1960160 SR JET Producing MPC-24A 50029230200100 2091340 KR 1-OIL Producing MPC-25A 50029226380100 1960210 KR WAG Shut In MPC-26 50029226340000 1952060 KR JET Producing MPC-28A 50029226480100 2051630 KR WAG Injecting MPC-36 50029228530000 1980010 KR WAG Injecting MPC-39 50029228490000 1972480 KR WAG Shut In MPC-40 50029228710000 2002130 KR JET Producing MPC-41 50029230140000 2010780 SB PWI Injecting MPC-42 50029231960000 2040280 KR WAG Injecting MPC-43 50029232000000 2040390 KR ESP Producing • • i .,�''ts`.�y�yoytiirtir�ryr yrlrir,r,, 1• e •, 4 ,*5- 4 ,� 4 d v MILNE • g Sec. 10 POINT Sec. 11 s UNIT $ ADL047433 i ADL047434 i i i l 1 i MPC 46_SHL \ I - i ' c p n i Sec. 9 1 IC li i I Sec. 161 4 ADL315848 "4 U013N010E s i •,4 , ,4 .,# 40/ 'lwr4j"ryri,yutyr>i�tsyt. Sec. 15 0111 ‘10'. Frac Zone Sec. 14 ADL047437 ADL025516 MPC-46 BHL Legend Top of Frac Zone • Base of Frac Zone MPC-46 SHL Well Trajectory MPC-46 (definitive survey) Ai...r■ N.r�t�- 1/2 Mile Radius from SHL Pad Footprint Petra Well Databaser MSurvey MPC-46 Definitive Ssurvey Milne Point Unit No Water Wells Within 1/2 Mile MPC-46 WellN 3800 Centerpoint Dr,Suite 7400 0 500 1,000 Anchorage,AK,99503 Plat Depicting No Water Wells with 1/2 mile of MP C-46 SHL Feet Map Date:6/28/2017 i • 4 ADL047434 AD L047433 Sec. 9 Sec. 10 Sec. 11 I i 1 MFTC. -46_SHL ------.04'' NIPU.01'C-ISA 1.* ®lr •• i,: MILNE �`� ,i�POINT UNIT * p •I �; 0 _ ) i` • U013N010E x Sec. 14 Sec. 16 MPC-46_BHL Sec. 15 i i t. I rat..loft-. Y i 6 n ;.: ADL025516 ADL047437 ADL315848 ' - ,. /4,0 a 4= i (`''r'`tt.>f 'I, ;:3ti 90!&A ''4"“pm Legend 1...”. i tet1/ 2 Mile Radius-Frac Zone Sag Trajectory Oil and Gas Lease 1/2 Mile Radius-Well Bore Pad Footprint ADL025516 Sec. 23 • Top of Frac Zone ADL047433 • Base of Frac Zone ADL047434 WELL SYMBOL MPC-46 SHL ADL047437 ® Oil(ACTIVE) ADL31 5848 I II Milne Point Unit MPC-46 Well Petra Well Database-HAK MPC-46 Definitive Survey 1lilarp 11v,t.n,t.t.f N 3800 Centerpoint Dr,Suite 1400 0 1,000 2,000 Anchorage,AK,99503 Plat Depicting all Sag Wells within 1/2 mile of MP C-46 Feet Map Date:6/28/2017 • • C-10 1 al �� C-11 or '..5 ''i�`\: \ �‘' � �� / .. it t ill tl % 1 e i ‘ t '`' ' C-26L1 PB2 r' ADL047434 c-26ADL047433 ,•, , C-26L1 PB1C-20 C-26L1PB3 , Sec. 9 '' 4 C-26L1 - Sec. 11 N. vSec10 , , _0 a -- ''- ` Vv ` k C-02 _ ""' ..-_. � t.1.----`_. -01 ~-~-- .._ MPC-46_SHL ---. c`ot� y _..-----.,..4 C-15 '00' MILNE POINT. C-14 ►"� UNIT 'o,, e MPC-.15A • Cr24 C 13 C-24APB1 1 0 ' C-24A U013N010E ` . Sec. 14 0 Sec. 16 i. MPC-46 BHL'\Sec. 15 - _3 r Fa iG Zone1 i i L` 1 11 ADL025516 ' ! ADL047437 1 ADL315848 `" 4 -4 k 4"4, C-22 ., C-22A , , f° E-13Ai Legend WELL SYMBOL(Kuparuk) 'Pi"1/2 Mile Radius-Frac Zone Sag Trajectory Oil and Gas Lease Ili r•ti INJECTOR �" j 1/2 Mile Radius-Well Bore Other Well Trajectories ADL025516 C. 23 Top of Frac Zone (Kuparuk) ADL047433 PLUG BACK • Pad Footprint ADL047434 OIL-ACTIVE E-13APB2 • Base of Frac Zone MPC-46 SHL ADL047437 0 P&A E-13 ADL315848 E'1••3APB1 A-03 II Milne Point Unit Petra Well Database-HAK MPC-46 Well MPC-46 Definitive Survey Ilitrurp Uv-k.t.11 N 3800 Centerpoint Dr,Suite 1400 0 1,000 2,000 Anchorage,AK,99503 Plat Depicting all Well Types within 1/2 mile of MP C-46 Feet Map Date:6/28/2017 • • 20 AAC 25.283 (a)(3) Identification of Freshwater Aquifers There are no underground sources of drinking water within a one-half mile radius of the current wellbore trajectory. Any and all freshwater aquifers lying below the Milne Point Unit are exempted aquifers under Aquifer Exemption Order 2 (AEO-2). See the Conclusion of AEO-2, which states that"The portions of freshwater aquifers lying directly below Milne Point Unit qualify as exempt freshwater aquifers under 20 AAC 25.440." / • 20 AAC 25.283 (a)(4) Baseline Water Well Sampling / There are no water wells located within one-half mile radius of the current wellbore trajectory. ./ A water sampling program is not required. • • 20 AAC 25.283 (a)(5) Detailed Casing and Cementing Information 9-5/8"40#/ft L-80 DWC/C surface casing set at 4,956' MD. First stage cemented with 435 sxs of 11.7 ppg ExtendaCEM followed by 225 sxs of 15.8 ppg SwiftCEM. Second stage cemented with 315 sxs of 10.7 ppg PermaFrost L followed by 340 sxs of 14.5 ppg SwiftCEM. 7" 26#/ft L-80 HTTC production casing set at 10,416' MD. Cemented first stage with 40 bbls/138 sxs of 15.3 ppg Class G. Cemented second stage through stage tool at 8,138' MD with 32 bbls/145 sxs of 15.3 ppg Class G cement. Detailed Casing Information Size Type Wt/Grade/Conn Pipe Body Yield Collapse Pressure Internal Yield (lbs) (psi) Pressure(psi) Conductor N/A N/A N/A N/A 9-5/8" Surface 40#/L-80/DWC/C 916,000 3,090 5,750 7" Production 26#/L-80/HTTC 604,000 5,410 7,240 Detailed Tubing Information 4-W Tubing 13.5/L-80/Hydril 625 307,000 8,540 9,020 S 20 AAC 25.283 (a)(6) Assessment of Each Casing and Cementing Operation Performed to Construct or Repair the Well The 9-5/8" surface casing was set below the base of the Schrader Bluff sands. The first stage cement job was started by pumping a 10.5 ppg tuned spacer with red dye followed by 435 sxs of 11.7 ppg ExtendaCEM lead cement and 225 sxs of 15.8 ppg SwiftCEM tail cement at 5.5 BPM average rate. 48 bbls was lost during the first stage cement job/The stage tool was then opened and the tuned spacer and 67 bbls of green cement were circulated out. The second stage was cemented by first pumping 55 bbls of 10.5 ppg tuned spacer with red dye followed by 315 sxs of 10.7 ppg PermaFrost L lead cement and 340 sxs of 14.5 ppg SwiftCEM tail cement. Recovered over 200 bbls of cement at surface. Bumped plug and closed stage tool at 1381 psi. Floats held. The job was pumped with cement to surface indicating a competent cement job. The 7" production casing was set through the Sag River sands/Rotated and reciprocated casing while conditioning the hole. The first stage cement job was started by pumping a 11.5 ppg tuned spacer followed by 40 bbls/138 sxs of 15.3 ppg Class G at 4 BPM average rate. Bump plug on calculated strokes. No losses occurred during the first stage cement job. The stage tool at 8,138'was then opened and the hole conditioned. Observed tuned spacer at surface. The second stage was cemented by first pumping 30 bbls of 11.5 ppg tuned spacer followed by 32 bbls/145 sxs of 15.3 ppg Class G cement at 5 BPM. 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CustomCustom — MAST-B[1] LHF1_ERAV RHF1_IRAV "; Normalization 1 Mrayl Normalization Liquid 200 us 1200 :CableDrag— USIT-Acoustic Acoustic USIT-Acoustic ,.,..- -z- I I External Radii External Radii Impedance Impedance Impedance With .Micro-debondi: Gamma Ray Average(ERAV) Average(ERAV) (AIBK)USIT-D[1] Average(AIAV) ngf. 9 Micro-debondin (ECGR_EDT USIT-D[1] USIT-D[1] � � C) (Mrayl) USIT-D[1] g Image Synthetic CBL EDTC B[1] 3.7 in 2.7 2.7 in 3.7 -1 Mrayl 9 (AI_MDEBOND_I from MG)USIT-D[1] 0 gAPI 200 Internal Radius Internal Radius (Mrayl) Discriminated Averaged Value Averaged Value Impedance Attenuation Casing (IRAV)USIT-D[1] (IRAV) USIT-D[1] Maximum(AIMX) (DCBL) Collar MAST-B1 Locator 3.7 in 2.7 2.7 in 3.7 USIT D[1] [ ] Amplitude -1 Mrayl 9 0 mV 100 (CCL) Internal Radius Internal Radius — CAL-YA[1] Maximum Value Maximum Value (IRMX) (IRMX) -19 1 USIT-D[1] USIT-D[1] Amplitude of 3.7 in 2.7 2.7 in 3.7 Eccentering Internal Radius Internal Radius (ECCE) Minimum Value Minimum Value USIT-D[1] (IRMN) (IRMN) 0 in 0.5 USIT-D[1] USIT-D[1] Memorized 3.7 in 2.7 2.7 in 3.7 Sonde Deviation (SDEVM) GPIT-F[1] 0 deg 50 F TIME_1900-Time Marked every 60.00(s) Description: USI VDL Cement Format: Log (USI VDL Cement 7inch) Index Scale: 5 in per 100 ft Index Unit:ft Index Type: Measured Depth Creation Date:24-Jun-2017 04:49:56 Channel Processing Parameters 1: Parameters Parameter Description Tool Value Unit AOFFX X Accelerometer Offset GPIT-F 0 ft/s2 AOFFY Y Accelerometer Offset GPIT-F 0 ft/s2 AOFFZ Z Accelerometer Offset GPIT-F 0 ft/s2 • • 20 AAC 25.283 (a)(7) Plans to Pressure-Test the Casings and Tubing Installed in the Well The 9-5/8" casing was pressure tested to 2900 psi for 30 minutes on May 24, 2017. The 7" casing was pressure tested to 3500 psi for 30 minutes on June 23, 2017. The 4-%2"tubing was tested to 3300 psi for 30 minute. The 4-1/2"x 7" annulus tested to 3645 psi for 30 minutes. The tubing will be tested to 4950 psi post-rig in preparation for the fracture stimulation. 411/ • 20 AAC 25.283 (a)(8) Pressure Ratings and Schematics for the Wellbore,Wellhead, BOPE,and Treating Head Size Weight Grade API Collapse API Internal Yield #/ft Pressure(psi) Pressure(psi) 9-5/8" 40 L-80 3,090 5,750 7" 26 L-80 5,410 7,240 4-Y2" 13.5 L-80 8,540 9,020 Treating 15M Head Wellhead 5M BOPE N/A Milne Point Unit 11 4110 SCHEMATIC a well: MPU C-46 Last Completed: 6/24/2017 Hilcorp Alaska,LLC PTD: 217-052 KBEIev.:31.5'/GLEIev.:15' TREE&WELLHEAD Tree 4-1/16"5M ,. �� V Wellhead Seaboard Weir,w/11"x 5M top flange � � 16" p, 4-1/2"Tubing Hanger OPEN HOLE/CEMENT DETAIL 9-5/8" 251 bbl Type I/II,100 bbl Permafrost'L'in a 12-1/4"Hole is 1 7" 72 bbl Class"G"in a 8-1/2"Hole ' # (3 CASING DETAIL ES Cementer @1899' Size Type Wt/Grade/Conn ID Top Btm ; 16" Conductor 164/A-106B/Weld 14" Surface 140' 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 4,955' w 7" Production 26/L-80/DWC/C 6.151" Surface 10,416' TUBING DETAIL 4-1/2" Tubing 13.5/L-80/Hydril 625 3.795" Surface 10,003' 9-50 4 0 WELL INCLINATION DETAIL KOP @ 1,150' MD Max Hole Angle=53.05'@ 6,329' MD JEWELRY DETAIL No Depth ID Item 1 9,875' 3.456 4-1/2" RN Nipple 2 9,886' 3.880 4.5 X 7" Premier Packer N 3 9,932' 3.880 Auto Fill Sub& Mirage Plug r ,r, 4 10,003' 3.958 Mule Shoe—Btm @ 10,003' ,s `qr 4 tz P If ': 3 + w t , 'l TD=10,430(MD)/TD=9,011'(WD) PBTD=10,285'(MD)/PBTD=8,883'(TVD) Revised by:TDF 6/26/2017 Milne Point Unit PROPOSED • Well: MPU C-46 Last Completed: 6/24/2017 lliileoru Alaska,LLC PTD: 217-052 KBEIev.:31.5'/GLEIev.:15' TREE&WELLHEAD Tree 4-1/16"5M jtoLSeaboard Weir,w/11"x 5M top flange w 44 Wellhead 16" 4-1/2"Tubing Hanger I 9 OPEN HOLE/CEMENT DETAIL 4= 9-5/8" 251 bbl Type I/II,100 bbl Permafrost'L'in a 12-1/4"Hole r 7" 72 bbl Class"G"in a 8-1/2"Hole 0 ' (5 CASING DETAIL ES Cementer, + @1899 i Size Type Wt/Grade/Conn ID Top Btm 's 16" Conductor 164/A-106B/Weld 14" Surface 140' 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 4,955' 7" Production 26/L-80/DWC/C 6.151" Surface 10,416' TUBING DETAIL 9-5/8" '* 4. 4-1/2" Tubing 13.5/L-80/Hydril 625 3.795" Surface 10,003' WELL INCLINATION DETAIL KOP@1,150' MD s Max Hole Angle=53.05°@ 6,329' MD tr.r. r JEWELRY DETAIL No Depth ID Item 1 9,875' 3.456 4-1/2" RN Nipple 2 9,886' 3.880 4.5 X 7" Premier Packer 1 3 9,932' 3.880 Auto Fill Sub&Mirage Plug 4 10,003' 3.958 Mule Shoe—Btm @ 10,003' 11, • PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status �, ±10,100' ±10,150' 8,724' 8,766' 50 Proposed '''4 .,:#.: I ( 1 i i i + 2 3 !ESa9 7" �t TD=10,430(MD)/TD=9,011'(TVD) PBTD=10,285'(MD)/PBTD=8,883'(TVD) Revised by:PC 06/28/2017 . • WELL MPC-46 DATE 6/24/17 PROPOSED Hileorp Alaska, LLC .i.11111111... illil^'"' Swab valve Seaboard Tree Cap. Otis style, 6 3/8" O � Model 510,4 1/16" 5K, ACME 4 1/16" 5K, FE,DD L-U * V FE,DD L-U PN 348218-000 4 "" PN 564680-WD1 "' "' SN SN to o-'''' '#)R..4 I Li 6I• Ia o Wing valve Seaboard Model 510,4 1/16"55K, FE,DD L-U ®® ®mu PN 564680-WD1 ® o SN tie 0 o o m ®o o 0 SSV valve Seaboard Model ION WNW MO ,,,,$ 510, 4 1/16" 5K, FE,DD L-U El O PN 348434 r, SN 'mewl'� Master valve Seaboard Model 510, 4 1/16" 5K, FE,DD L-U PN 564680-WD1 Tbg Hgr,Seaboard SM- rill _' '", o SN E-CL 11 x 4'A" EUE BOX SII [� API 11" 5K top and bottom,4" "H" u--, f BPV,ported for 2 ea 3/ - a 8" Control line, L ®. ,w/3' pup L-U,DD-NL, m PN W10220 . — API 13 5/6" 5K SN 1 1 m 11 x 7", SMB 22, 8.54 stub Csg Hgr,Seaboard !PATE--. :,■ acme top x DWC box u S-22 13 5/8 x 9 5/8" bottom, w/ DWC-C , p p Slip type hanger i• 6.844 bore PN A34330 LU,DD-NL ANIP ' Ilk PN A16232-001 SN r oli sTATEs PROPOSAL: Casing Isolation Tool Energy Services(Canada) Inc. Maximum Allowable Pumping Rates SIZE ID OD RATE m3/min CSG 2.250 3.760 10 m'/min 3 1/2"Big Bore 1.750 2.750 6 m'/min 2 7/8"&31/2" 1.438 2.360 4 m3/min 2 3/8" 1.000 .1.900 2 m3/min 31116&41/16 with tapered mandrel 2.750 4.000 15 m3/min 41/16 X Tool Mandrel 3.610 4.750 24 m'/min OPEN PosmoN CLOSED PosmoN (MA T<7 tiW:171;t1.IvstomoYi (.4Nout mewl 4044U/41,Off/Mila /AVSI[R VALVE lea \ ; ,PI IX . f- r `o MI Au}IER VAIVF 3 '.4 ! .....wren[" —11,1i°,i ■ I r'I l.dl.'w"'.Yurty r.l ,14 r.Il ,. n` t 5 " ROWI[EMI,01 4 err-Srf, """*v[ m"v yr 4 }-.4 4u1-2�M onMli �1�[� G , * ' IT , wEuluw ; t r�\ ,' MHO WO/r N.II;1`H Aft[.W1V IN D . PUKE 4}}WAG frO1 ‘&0 1; ,33 i10044 : O�._... a www.Sti ngerCanada.com 15M Treating Head • • 20 AAC 25.283 (a)(9) Data for the Fracturing Zone and Confining Zones (A) a lithologic description of each zone; (B)the geological name of each zone; (C) the measured depth and true vertical depth of each zone; (D)the measured thickness and true vertical thickness of each zone; and (E) the estimated fracture pressure for each zone; The Sag River formation is a Triassic-aged, fine-grained marine sandstone. The productive Sag River interval is—45'TVD thick. The top Sag River is at 10,100' MD/8724'TVD. The estimated fracture gradient for the Sag River interval is 0.575 psi/ft. The overlying confining zone consists of"'425'TVD of Kingak shales. The top Kingak shale is at 9600' MD /8299'TVD. The estimated fracture gradient for the Kingak is 0.689 psi/ft. The underlying confining zone consists of"'175'TVD of Shublik mixed carbonate mudstones, siltstones and shales.The top Shublik is at 10,160' MD/8,775'TVD. The estimated fracture gradient for the Shublik is 0.601 psi/ft. 1110 20 AAC 25.283 (a)(10) The Location,the Orientation,and a Report on the Mechanical Condition of Each Well that May Transect the Confining Zones None of the wells identified as per 20 AAC 25.283 (a)(2)(C) penetrate through the 1300'thick Kingak confining shale except for the MP C-01 and MP C-15A wellbores. The Kingak shale will provide a competent barrier to these Kuparuk formation wellbores. MP C-01: 9-5/8" casing was run and cemented through the Ivishak sands in 1982. The Ivishak was drill stem tested and then cement squeezed through a retainer with 100 sxs of cement. The Sag River formation was drill stem tested and then cement squeezed through a retainer with 100 sxs of cement. Additionally, a bridge was set at 7,287' MD during the December 1994 RWO. The MP C-01 Sag River formation is hydraulically isolated from the Kuparuk formation by 9-5/8" casing, primary cement job, cement retainer, bridge plug, cement plug and squeeze cemented perforations. The well is currently an ESP lifted Kuparuk well. MP C-15: The 9-5/8" surface casing was set below the base of the Schrader Bluff sands and cemented to surface. The 7" casing was set across the Kuparuk sands with estimated top of cement at 6600' MD (-500' above top Kuparuk). The Schrader Bluff and Kuparuk hydrocarbon zones are isolated by the 9- 5/8" and 7" casing strings, respectively. 9-5/8" casing was run to 4692' MD. A pre-flush of 35 bbls of 11 ppg Sepiolita was pumped followed by 1315 sxs/461 bbls of 12. 3 ppg Permafrost E cement w/5 lbs/sx Gilsonite followed by 51 bbls of Class G cement with 3%salt and 1%CFR-2. The cement was displaced with 351 bbls of 9.4 ppg mud and 124 bbls of cement was recovered at surface. Bumped plug with 2000 psi and floats held. The job was pumped as designed with full returns indicating a competent cement job. 7" casing was run to 7652' MD with ECPs at 7374' and 7395' MD. A pre-flush of 35 bbls of 12 ppg Sepiolita was pumped followed by 250 sxs/51 bbls Class G cement with 1%CFR-2 and 0.3% Halad-24. The cement was displaced with 291 bbls of 10.2 ppg NaCl/NaBr completion brine. Bumped plug with 2850 psi and inflated ECPs. Floats held. The job was pumped as designed with full returns indicating a competent cement job. Casing pressure tested to 3034 psi on May 5, 2016. The 9-5/8" x 7" annulus was subsequently downsqueezed with 180 sxs/30 bbls Permafrost C cement followed by 60 bbls of Arctic Pack. The 4-%2" liner was run and cemented with 83 bbls of 15.8 ppg cement. The liner was rotated and reciprocated for the majority of time while displacing the cement around the liner. Minor packoffs were noted during the cement job and approximately 3 bbls of cement were circulated out. The plug bumped early but was subsequently tagged at the landing collar during the cleanout. The floats held. The cement bond log indicates very good cement from the liner top at 6920'to 8110', excellent cement from 8110'—9540', and slightly gas or water cut cement across the zone of interest from 9540'—9625' ELM. • • 20 AAC 25.283 (a)(11) The Location of, Orientation of, and Geological Data for Each Known or Suspected Fault or Fracture that May Transect the Confining Zones N t. . ..,,, \'''' co, `L= `� MPC-01 ` %14 S7 \ MPC-15A \ \ r V`\ )11 ,, ' '. \_ -,.- ' \ -------..,,..,.,.... ! CI \4,1, \ 13. t'"1 N b �C C46 S'Port -.01,15 MPC-46 ` \\\ The map above shows the structure at the top of the Sag River interval. All faults shown are inferred from seismic data.The MPC-01 well did not encounter any faults during drilling. MPC-46 was planned to stay away(>500')from suspected faults based off of seismic data and did not encounter any faults during drilling. • • There are several faults based off of seismic data that are within the%z mile radius of the proposed MPC- 46 wellbore. However, MPK-33 and MPC-23 (both vertical, hydraulically fractured Sag River producers, similar to what is proposed here) are both closer to mapped faults elsewhere in the field and did not encounter containment problems. Horizontal principal stress from well data indicate that the fracture should propagate approximately NW-SE (SHmax is NW-SE, SHmin is NE-SW). Based on current mapping, the fracture wings should not extend into suspected faults based off of seismic data. • • 20 AAC 25.283 (a)(12) Proposed Hydraulic Fracturing Program 1. RU SL. PT to 1500 psi. Note that the wellbore is hydraulically isolated from the reservoir with pressure tested cemented 7" casing. 2. Drift tubing with dummy perf gun to 10,285' PBTD. i 3. RDMO SL. # P�Ess"a -rear 441:, Twsiou d..� . 4. RU e-line and PCE. PT to 4000 psi. 44150 k ccrL 3c s'^1+-' I (,i.k.arzz -MST' lkIo 5. Perforate the Sag River formation from ±10,100'-±10,150' MD. 6. RDMO e-line. 7. MIRU frac fleet. MIRU frac and slop tanks. MIRU all ancillary support equipment. 8. Fill frac tanks with fresh water. Heat water as needed. 9. Lay all hardlines and manifolds. Install pressure monitoring equipment on wellhead and tree. 10. RU 15K tree saver and hard line. 11. Pressure test all high pressure treating lines to 8000 psi.Z/ 12. Set the GORV(gas operated relief valve) at±6800 psi. Set the staggered pump kickouts between 6800 psi and 6300 psi. 13. Pressurize annulus to 3000 psi. Set annular PRV at 3500 psi. ✓ 14. Prepare frac fleet to pump. 15. Pump Sag DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 16. Fracture stimulate Sag interval with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule"for proposed design. 17. Displace with 20 bbl diesel freeze protect. Underdisplace by 3 bbls. Do not over displace. 18. Shut well in. RDMO. 19. Contingency CT FCO a. MIRU CTU and associated equipment. Stump test CT BOPE, if possible. b. RU CTU BOPE and PT to 3500 psi. RIH and cleanout frac sand/frac fluid to a portable test separator with filtered 2% KCI brine and N2 as needed to PBTD. c. POOH jetting liner and tubing clean. RD CTU. 20. RU SL. Drift tubing and tag to maximum TD with GR/JB. RDMO. 21. Turn well over to operations. • 20 AAC 25.283 (a)(12) (A) Estimated Total Volumes Planned 20 AAC 25.283 (a)(12) (B) Trade Name,Generic Name,and Purpose of each Base Fluid and Additive to be Used; 20 AAC 25.283 (a)(12) (C) Chemical Ingredient Name of,and the Chemical Abstracts Service(CAS)Registry Number Assigned to, each Base Fluid and Additive to be used; 20 AAC 25.283 (a)(12) (D) Estimated Weight or Volume of each Inert Substance, including a Proppant or other Substance injected • • Client: Hilcorp Alaska,LLC Schimberger Well: MPC-46 Basin/Field: Milne Point State: Alaska County/Parish: North Slope Borough Case: Disclosure Type: Pre-Job Well Completed: 7/10/2017 Date Prepared: 6/26/2017 2:51 PM Report ID: RPT-49543 Fluid Name&Volume Additive Additive Description Concentration Volume 8534 l Temporary Clay Stabilizer 2.1 Gal/1000 Gal 170.0 Gal F112 Surfactant 1.1 Gal/1000 Gal 85.0 Gal 1218 Breaker 0.6 Lb/1000 Gal 50.0 Lb 1450 Stabilizing Agent 0.5 Gal/1000 Gal 40.0 Gal _ YF130FIexD:WF130 80,430 Gal J569 Breaker 4.7 Lb/1000 Gal 380.0 Lb J580 Gelling Agent 31.1 Lb/1000 Gal 2,500.0 Lb J604 Crosslinker 2.5 Gal/1000 Gal 200.0 Gal M002 Additive 2 Lb/1000 Gal 160.0 Lb M300 M300 0.3 Gal/1000 Gal 25.0 Gal S526-1620 Propping Agent varied concentrations 230,000.0 Lb The total volume fisted in the tables above represents the summation of water and additives. Water Is supplied by client. CAS Number Chemical Name Mass Fraction Water(Including Mix Water Supplied by Client)* ^'74 % 66402-68-4 Ceramic materials and wares,chemicals ' 25% 9000-30-0 Guar gum <1% 1319-33-1 Ulexite <0.1 % 67-48-1 2-hydroxy-N,N,N-trimethylethanaminlum chloride <0.1 % 107-21-1 Ethylene Glycol <0.1 % 7727-54-0 Diammonium peroxidisulphate <0.1 % 102-71-6 2,2',2"-nitrilotriethanol <0.1 % 1310-73-2 Sodium hydroxide <0.1 % 7786-30-3 Magnesium chloride <0.1 % 25038-72-6 Vinylidene chloride/methylacrylate copolymer <0.1 % 1303-96-4 Sodium Tetraborate Decahydrate <0.1% 31726-34-8 Poly(oxy-1,2-ethanediyl),alphahexyl-omega-hydroxy- <0.01% 7647-14-5 Sodium chloride <0.01 % 111-30-8 Glutaraldehyde <0.01 % 110-17-8 but-2-enedioic acid <0.01 % 10043-52-4 Calcium chloride <0.01 % 7631-86-9 Non-crystalline silica(impurity) <0.001 % 61789-77-3 Dicoco dimethyl quaternary ammonium chloride <0.001 % 9002-84-0 poly(tetrafluoroethylene) <0.001 % 14807-96-6 Magnesium silicate hydrate(talc) <0.001 % 595585-15-2 Diutan <0.001 % 125005-87-0 Diutan gum <0.001 % 67-63-0 Propan-2-ol <0.0001 % Total 100% *mix water is supplied by the client.Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. *The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC-Chemicals as of the date of the document was produced.Any new updates will not be reflected in this document. 8 Schlumberger 2017.Used by Hilcorp Alaska,LLC by permission. Page:1/1 • 20 AAC 25.283 (a)(12) (E) Maximum Anticipated Treating Pressure and Information Sufficient to Support a Determination that the Well is Appropriately Constructed for the Proposed Hydraulic Fracturing Program. The 4-%2 "production tubing and 7" casing will be tested to 4950 psi for 30 minutes prior to the fracture stimulation. The maximum differential pressure the tubing will be subjected to will be 3800 psi (6800 psi GORV maximum pressure setting-3000 psi of pressure on the casing x tubing annulus). The calculated maximum treating pressure is 4,344 psi. • • 20 AAC 25.283 (a)(12) (F) Designed Height And Length Of Each Proposed Fracture (i) the calculated measured depth and true vertical depth of the top of the fracture: 10,104' MD/8727'TVD (ii) a description of each method and assumption used to determine designed fracture height and length: The MP C-46 fracture stimulation was modeled using Schlumberger FracCADE program. The input parameters are attached. • • Scblumberger FracCADE* STIMULATION PROPOSAL Operator : Hilcorp Alaska Well : MPC-46 Field : Milne Point Formation : Sag River Well Location : Milne Point County : North Slope State : Alaska Country : United States Prepared for : Paul Chan Service Point : Prudhoe Bay Proposal No. Business Phone : 907 659 2434 Date Prepared : 21 Jun 2017 FAX No. : 907 659 2538 Prepared by : Gunther Rutzinger Phone : 907 2731788 E-Mail Address : grutzinger@slb.com "Mark of Schlumberger Disclaimer Notice- This information is presented in good faith,but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service.The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment.The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model,the assumptions and such input data.The information presented is Schlumberger's best estimate of the actual results that may be achieved end should be used for comparison purposes rather than absolute values.The quality of input data,end hence results,may be improved through the use of certain tests end procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well,the reservoir,the field and conditions affecting them.If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein his the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue.Actual charges may vary depending upon time,equipment,and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. • . Client : Hilcorp Alaska Scblr��r Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230klbs Contents Section 1: Wellbore Configuration 3 Section 2: Zone Data 4 Section 3: Propped Fracture Schedule 6 Section 4: Propped Fracture Simulation 8 Section 5: Propped Fracture Simulation Results 11 Section 6: Proppant Data 12 Section 7: Hole Survey 13 2 • • Client : Hilcorp Alaska Schlumberger Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230kIbs Section 1: Wellbore Configuration Bottom Hole Temperature 235 degF Deviated Hole YES Treat Down TUBING Well Type Vertical Well Location OnShore Tubing Data OD Weight ID Depth (in) (lb/ft) (in) (ft) 4.500 12.8 3.960 10000.0 Casing Data OD Weight ID Depth (in) (lb/ft) (in) (ft) 7.000 26.0 6.276 10415.0 Perforation Data Top Top Bottom Bottom Shot Number Diameter MD TVD MD TVD Density (ft) (ft) (ft) (ft) (shot/ft) _ (in) t 10100.0 8727.0 10150.0 8769.7 6.00 300 0.32 3 • • Client : Hilcorp Alaska Schlumberger Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230klbs Section 2: Zone Data Formation Mechanical Properties Zone Name Top TVD Zone Frac Insitu Young's Poisson's Toughness (ft) Height Grad. Stress Modulus Ratio (psi.in0.5) (ft) (psi/ft) (psi) (psi) Kingak 8518.6 79.6 0.823 7044 2.957E+6 0.36 1000 Kingak 8598.2 69.5 0.833 7191 2.672E+6 0.36 1000 Kingak 8667.7 29.7 0.843 7319 2.365E+6 0.37 1000 Sag D 8697.4 5.9 0.715 6221 3.909E+6 0.26 1000 Sag D 8703.3 8.9 0.748 6513 3.118E+6 0.29 1000 Sag C 8712.2 4.9 0.767 6684 2.685E+6 0.31 1000 Sag C 8717.1 3.9 0.726 6330 3.852E+6 0.27 1000 Sag C 8721.0 3.0 0.700 6106 4.161E+6 0.25 1000 Sag B 8724.0 2.9 0.685 5977 4.295E+6 0.23 700 Sag B 8726.9 15.7 0.680 5940 4.110E+6 0.23 1200 Sag B 8742.6 4.9 0.696 6087 4.229E+6 0.24 1200 Sag B 8747.5 3.0 0.710 6212 4.451E+6 0.26 700 Sag A 8750.5 13.3 0.710 6218 4.313E+6 0.26 1200 Sag A 8763.8 4.2 0.712 6241 4.630E+6 0.26 1200 Sag A 8768.0 1.8 0.746 6542 5.286E+6 0.29 1000 Sag A 8769.8 4.2 0.732 6421 4.887E+6 0.28 700 Shublik 8774.0 3.1 0.837 7345 6.739E+6 0.31 1000 Shublik 8777.1 2.0 0.867 7611 8.427E+6 0.34 1000 Shublik 8779.1 2.5 0.851 7472 8.298E+6 032 1000 Shublik 8781.6 3.4 0.831 7299 8.381E+6 0.31 1000 Shublik 8785.0 6.7 0.731 6424 7.928E+6 0.28 700 Shublik 8791.7 5.2 0.687 6042 7.262E+6 0.23 1200 Shublik 8796.9 4.7 0.695 6115 6.598E+6 0.24 700 Shublik 8801.6 3.2 0.758 6673 4.361E+6 0.29 1000 Shublik 8804.8 25.8 0.721 6358 5.043E+6 0.27 700 Shublik 8830.6 8.8 0.776 6856 3.969E+6 0.32 1000 Shublik 8839.4 20.4 0.768 6796 4.465E+6 0.31 1000 Shublik 8859.8 7.6 0.719 6373 5.868E+6 0.27 1000 Shublik 8867.4 16.4 0.747 6630 5.148E+6 0.29 1000 SHALE 8883.8 7.3 0.839 7457 8.794E+6 0.36 1000 SILTSTONE 8891.1 16.4 0.777 6915 8.502E+6 0.32 1000 SILTSTONE 8907.5 12.9 0.736 6561 6.121E+6 0.28 1000 SILTSTONE 8920.4 5.6 0.761 6791 7.282E+6 0.30 1000 SHALE 8926.0 5.7 0.696 6214 6.082E+6 0.24 1000 SILTSTONE 8931.7 13.7 0.744 6650 6.581E+6 0.29 1000 DIRTY-SANDSTONE 8945.4 14.5 0.697 6240 5.403E+6 0.25 700 DIRTY-SANDSTONE 8959.9 55.0 0.666 5986 5.025E+6 0.21 700 4 • • Client : Hilcorp Alaska UChIll1bGg61Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230klbs Formation Transmissibility Properties Zone Name Top TVD Net Perm Porosity Res. Gas Oil Sat. Water (ft) Height Imd) (%) Pressure Sat. 1%) Sat. (ft) (psi) (%) 1%) Kingak 8518.6 0.1 0.001 1.0 4005 65.0 10.0 25.0 Kingak 8598.2 0.1 0.001 1.0 4040 65.0 10.0 25.0 Kingak 8667.7 0.1 0.001 1.0 4063 65.0 10.0 25.0 Sag D 8697.4 1.0 0.100 10.0 4072 65.0 10.0 25.0 Sag D 8703.3 1.5 0.100 10.0 4075 65.0 10.0 25.0 Sag C 8712.2 2.0 0.100 10.0 4078 65.0 10.0 25.0 Sag C 8717.1 1.0 0.100 10.0 4080 65.0 10.0 25.0 Sag C 8721.0 0.1 0.001 1.0 4082 65.0 10.0 25.0 Sag B 8724.0 2.5 1.000 10.0 4083 65.0 10.0 25.0 Sag B 8726.9 15.7 8.000 14.0 4088 65.0 10.0 25.0 Sag B 8742.6 4.9 8.000 14.0 4093 65.0 10.0 25.0 Sag B 8747.5 2.0 2.000 12.0 4095 65.0 10.0 25.0 Sag A 8750.5 13.3 8.000 14.0 4098 65.0 10.0 25.0 Sag A 8763.8 4.2 8.000 14.0 4102 65.0 10.0 25.0 Sag A 8768.0 0.5 0.100 10.0 4104 65.0 10.0 25.0 Sag A 8769.8 3.0 2.000 12.0 4105 65.0 10.0 25.0 Shublik 8774.0 0.1 0.001 1.0 4107 65.0 10.0 25.0 Shublik 8777.1 0.1 0.001 1.0 4108 65.0 10.0 25.0 Shublik 8779.1 1.0 0.100 10.0 4109 65.0 10.0 25.0 Shublik 8781.6 1.0 0.100 10.0 4111 65.0 10.0 25.0 Shublik 8785.0 5.0 1.000 12.0 4113 65.0 10.0 25.0 Shublik 8791.7 5.2 5.000 14.0 4116 65.0 10.0 25.0 Shublik 8796.9 3.5 1.000 12.0 4118 65.0 10.0 25.0 Shublik 8801.6 1.0 0.100 10.0 4120 65.0 10.0 25.0 Shublik 8804.8 20.0 1.000 12.0 4127 65.0 10.0 25.0 Shublik 8830.6 2.0 0.100 10.0 4135 65.0 10.0 25.0 Shublik 8839.4 4.0 0.100 10.0 4142 65.0 10.0 25.0 Shublik 8859.8 2.0 0.100 10.0 4148 65.0 10.0 25.0 Shublik 8867.4 5.0 0.100 10.0 4154 65.0 10.0 25.0 SHALE 8883.8 0.1 0.001 1.0 4159 65.0 10.0 25.0 SILTSTONE 8891.1 2.0 0.100 10.0 4165 65.0 10.0 25.0 SILTSTONE 8907.5 2.0 0.100 10.0 4172 65.0 10.0 25.0 SILTSTONE 8920.4 2.0 0.100 10.0 4176 65.0 10.0 25.0 SHALE 8926.0 0.1 0.001 1.0 4179 65.0 10.0 25.0 SILTSTONE 8931.7 3.0 0.100 10.0 4183 65.0 10.0 25.0 DIRTY-SANDSTONE 8945.4 12.0 1.000 10.0 4206 65.0 10.0 25.0 DIRTY-SANDSTONE 8959.9 35.0 1.000 10.0 4206 65.0 10.0 25.0 5 • i client : Hilcorp Alaska Schlumberger Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230klbs Section 3: Propped Fracture Schedule Pumping Schedule The following is the Pumping Schedule to achieve a propped fracture half-length(Xf)of 325.9 ft with an average conductivity(Krw)of 6693 md.ft. Job Description Step Pump Fluid Name Step Fluid Gel Prop. Prop. Name Rate Volume Conc. Type and Mesh Conc. (bbl/min) (gal) (Ib/mgal) (PPA) PAD 30.0 YF130FIexD 18900.0 30.0 0.00 1.0 PPA 30.0 YF130FIexD 2408.4 30.0 16/20 CarboBond Lite 1.00 2.0 PPA 30.0 YF130FIexD 2306.3 30.0 16/20 CarboBond Lite 2.00 3.0 PPA 30.0 YF130FIexD 2212.4 30.0 16/20 CarboBond Lite 3.00 4.0 PPA 30.0 YF13OFIexD 2126.0 30.0 16/20 CarboBond Lite 4.00 5.0 PPA 30.0 YF130FIexD 2046.0 30.0 16/20 CarboBond Lite 5.00 6.0 PPA 30.0 YF130FIexD _ 1971.8 30.0 16/20 CarboBond Lite 6.00 _ 7.0 PPA 30.0 YF130FIexD 1902.8 30.0 16/20 CarboBond Lite 7.00 8.0 PPA 30.0 YF130FIexD 1838.5 30.0 16/20 CarboBond Lite 8.00 a`a 9.0 PPA 30.0 YF130FIexD 1778.4 30.0 16/20 CarboBond Lite 9.00 10.0 PPA 30.0 YF130FIexD 1722.1 30.0 16/20 CarboBond Lite 10.00 11.0 PPA 30.0 YF130FIexD 1669.2 30.0 16/20 CarboBond Lite 11.00 12.0 PPA 30.0 YF130FIexD 8772.3 30.0 16/20 CarboBond Lite 12.00 co Please note that this pumping schedule is under-displaced by 5.0 bbl. 2 2 Fluid Totals 49654 gal of YF130FIexD Proppant Totals 229100 lb of 16/20 CarboBond Lite Pad Percentages %PAD Clean 38.1 %PAD Dirty 31.4 6 • • Client : Hilcorp Alaska Schlumberger Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230kIbs Job Execution Step Step Cum.Fluid Step Cum. Step Cum. Avg. Step Cum. Name Fluid Volume Slurry Slurry Prop Prop. Surface Time Time Volume (gal) Volume Volume (Ib) (lb) Pressure (min) (min) (gal) (bbl) (bbl) (psi) PAD 18900.0 18900.0 450.0 450.0 0 0 4340 15.0 15.0 1.0 PPA 2408.4 21308.4 60.0 510.0 2408 2408 4026 2.0 17.0 2.0 PPA 2306.3 23614.7 60.0 570.0 4613 7021 _ 4000 2.0 19.0 3.0 PPA 2212.4 25827.1 60.0 630.0 6637 13658 4029 2.0 21.0 4.0 PPA 2126.0 27953.1 60.0 690.0 8504 22162 4089 2.0 23.0 5.0 PPA 2046.0 29999.1 60.0 750.0 10230 32392 4161 2.0 25.0 6.0 PPA 1971.8 31970.9 60.0 810.0 11831 44223 4187 2.0 27.0 7.0 PPA 1902.8 33873.7 60.0 870.0 13320 57542 4178 2.0 29.0 8.0 PPA 1838.5 35712.2 60.0 930.0 14708 72250 4199 2.0 31.0 9.0 PPA 1778.4 37490.5 60.0 990.0 16005 88256 4225 2.0 33.0 10.0 PPA 1722.1 39212.6 60.0 1050.0 17221 105476 4262 2.0 35.0 11.0 PPA 1669.2 40881.8 60.0 1110.0 18361 123837 4303 2.0 37.0 12.0 PPA 8772.3 49654.1 325.0 1435.0 105267 229105 4344 10.8 47.8 Pumping Schedule Totals Summary for This Stage: Average Pump Rate 30.0 bbl/min Volume Weighted Average Rate 30.0 bbl/min Total Fluid Volume 1182 bbl Total Proppant Mass 229100 lb Total Slurry Volume 1435.0 bbl Total Pump Time 47.8 min Fluid Based Totals for This Stage Average Volume Total Total Total Total Fluid Pump Weighted Fluid Proppant Slurry Pump Rate Average Rate Volume Mass Volume Time (bbl/min) (bbl/min) (gal) (lb) (bbl) (min) YF130FIexD 30.0 30.0 49654 229105 1435.0 47.8 Proppant Based Totals for This Stage Average Volume Total Total Total Total Proppant Pump Weighted Fluid Proppant Slurry Pump Rate Average Rate Volume Mass Volume Time (bbl/min) (bbl/min) (gal) (Ib) (bbl( (min) 16/20 CarboBond Lite 30.0 30.0 30754 229105 985.0 32.8 7 ! S Client : Hilcorp Alaska A► ii11li61gGIWell : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230klbs Section 4: Propped Fracture Simulation The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model.Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Initial Fracture Top TVD 8726.9 ft Initial Fracture Bottom TVD 8742.6 ft Propped Fracture Half-Length 325.9 ft EOJ Hyd Height at Well 193.3 ft Average Propped Width 0.270 in Average Gel Concentration 354.8 lb/mgal Average Gel Fluid Retained Factor 0.50 Net Pressure 1248 psi Efficiency 0.392 Effective Conductivity 9817 md.ft u' Effective Fcd 15.1EF Max Surface Pressure 4475 psi ty co El m Simulation Results by Fracture Segment Co From To Prop.Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Width Height Prop. Gel Conc. Conductivity Pumping (in) (ft) Conc. (lb/Inge') (md.ft) (PPA) (lb/ft2) 0.0 81.5 13.4 0.291 182.0 2.57 252.5 7061 81.5 162.9 17.2 0.326 149.8 2.91 178.9 8169 162.9 244.4 22.0 0.337 117.8 3.01 161.6 8448 244.4 325.9 11.6 0.137 86.4 1.22 826.3 3372 Proppant bridged at 315 ft after 30 bbl in step 8 8 • i Client : Hilcorp Alaska Schlumberger Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230klbs Fracture Geometry Data Per Zone for Production Prediction Zone Name Top MD Top Gross Net Fracture Fracture Fracture (ft) TVD Height Height Width Length Conductivity (ft) (ft) (in) (ft) (md.ft) Kingak 9856.5 8518.6 79.6 .1 0.000 .0 0 Kingak 9950.1 8598.2 69.5 .1 0.000 .0 0 Kingak 10030.8 8667.7 29.7 .1 0.070 171.3 1733 Sag D 10065.5 8697.4 5.9 1.0 0.159 292.7 3915 Sag D 10072.4 8703.3 8.9 1.5 0.241 325.9 5935 Sag C 10082.8 8712.2 4.9 2.0 0.299 325.9 7351 Sag C 10088.5 8717.1 3.9 1.0 0.333 325.9 8176 Sag C 10093.0 8721.0 3.0 .1 0.362 325.9 8871 Sag B 10096.5 8724.0 2.9 2.5 0.384 325.9 9404 Sag B 10099.9 8726.9 15.7 15.7 0.416 325.9 10204 Sag B 10118.3 8742.6 4.9 4.9 0.422 325.9 10352 Sag B 10124.0 8747.5 3.0 2.0 0.415 325.9 10179 Sag A 10127.5 8750.5 13.3 13.3 0.391 325.9 9612 Sag A 10143.1 8763.8 4.2 4.2 0.357 325.9 8806 Sag A 10148.0 8768.0 1.8 .5 0.335 325.9 8259 Sag A 10150.1 8769.8 4.2 3.0 0.305 325.9 7546 Shublik 10155.0 8774.0 3.1 .1 0.278 322.9 6885 Shublik 10158.7 8777.1 2.0 .1 0.255 314.3 6340 R. Shublik 10161.0 8779.1 2.5 1.0 0.249 307.7 6192 Shublik 10163.9 8781.6 3.4 1.0 0.250 299.1 6231 Shublik 10167.9 8785.0 6.7 5.0 0.265 285.3 6584 Shublik 10175.7 8791.7 5.2 5.2 0.274 266.7 6815 Shublik 10181.8 8796.9 4.7 3.5 0.264 250.5 6570 Shublik 10187.3 8801.6 3.2 1.0 0.249 237.5 6191 Shublik 10191.0 8804.8 25.8 20.0 0.185 205.8 4601 Shublik 10221.1 8830.6 8.8 2.0 0.090 144.0 2228 Shublik 10231.3 8839.4 20.4 4.0 0.049 106.9 1204 Shublik 10254.9 8859.8 7.6 2.0 0.022 60.1 549 Shublik 10263.7 8867.4 16.4 5.0 0.012 34.9 290 SHALE 10282.5 8883.8 7.3 .1 0.000 .0 0 SILTSTONE 10290.8 8891.1 16.4 2.0 0.000 .0 0 SILTSTONE 10309.6 8907.5 12.9 2.0 0.000 .0 0 SILTSTONE 10324.2 8920.4 5.6 2.0 0.000 .0 0 SHALE 10330.6 8926.0 5.7 .1 0.000 .0 0 SILTSTONE 10337.1 8931.7 13.7 3.0 0.000 .0 0 DIRTY-SANDSTONE 10352.6 8945.4 14.5 12.0 0.000 .0 0 DIRTY-SANDSTONE 10368.9 8959.9 55.0 35.0 0.000 .0 0 9 S • Client : Hilcorp Alaska Schlumberger Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230kIbs Exposure Time Prediction by Step Step Name Fluid Name Pump Fluid Perforation Exposure at Exposure Rate Volume Injection BHST of aboveWatch (bbl/min) (gal) Temp. 235 degF Temp.of (degF) (min) 230 degF (mini PAD YF130FIexD 30.0 18900.0 128 6.8 6.8 1.0 PPA YF130FIex0 30.0 2408.4 100 12.2 12.2 2.0 PPA YF130FIexD 30.0 2306.3 99 10.2 10.2 3.0 PPA YF130FIexD 30.0 2212.4 98 11.7 11.7 4.0 PPA YF130FIexD 30.0 2126.0 97 5.3 5.3 5.0 PPA YF130FIexD 30.0 2046.0 97 0.0 0.0 6.0 PPA YF130FIexD 30.0 1971.8 96 0.0 0.0 7.0 PPA YF130FIexD 30.0 1902.8 96 0.0 0.0 8.0 PPA YF130FIexD 30.0 1838.5 95 0.0 0.0 9.0 PPA YF130FIexD 30.0 1778.4 95 0.0 0.0 10.0 PPA YF130FIexD 30.0 1722.1 95 0.0 0.0 11.0 PPA YF130FIexD _ 30.0 1669.2 95 0.0 0.0 12.0 PPA YF130FIexD 30.0 8772.3 94 0.0 0.0 10 • • Client : Hilcorp Alaska Sc[ I !lr��r Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230klbs Section 5: Propped Fracture Simulation Results (1) ACL Fracture Profile and Proppant Concentration Plot FracCADEe Hilcorp Alaska MPC-06 23014bs 21 Jun 2017 ACL Facture Profile and Proppant Concentration 8600 r r r 8700- i - <0.016flt2 0.0-O./lb fp 0.4-0.9 Ib ft2 \ r 0.9.1316.1f2 / 1.3-1.7 1602 1.7-2 2 16112 2.2-261,02 E. 8800- - - ® 2.8-3.01602 Ili 3.0-3.51602 3.516/112 8900. - - - - 4y FarSure41 Initiation MO=10109.12't E 1 9005400 8600 7800 -0.3 -0.2 -0.1 -0 0.1 0.3 0 150 360 460 660 750 Strew-pa ACI.Width at Wenbo,-in facture Half-Length-11 0 (2) Treating Plot zs — Bottomnae Pressure — Surface Pressure — Total lnj.Rate —8— EOJ ett 8000 • 40 7000 6000 n v A -20 6 3 5000 -10 4000 • 3000 I I I I • 0 0 10 20 30 40 50 60 70 80 Treatment Time-min 11 • • Client : Hilcorp Alaska Schlumberger Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230klbs Section 6: Proppant Data Proppant Permeability is calculated based on the following parameters: BH Static Temperature: 235 degF Stress on Proppant: 3985 psi Propped Fracture Conc.: 1.00 lb/ft2 Average Young's Modulus: 4.311E+06 psi Proppant Data Proppant Name Specific Mean Pack Permeability Gravity Diameter Porosity (md) (in) (%) Jordan Unimin 20/40 2.65 0.022 35.0 131416 CarboLite 16/20 2.74 0.043 35.0 790097 16/20 CarboBond Lite 2.59 0.041 39.3 522348 Proppant Permeability Plot Proppant Penneabi l y ww• ,,,.. -. a� wrk Stress on Preppanl a 1100000 ^'"4 1000000 ^5 900000 �Y Bb 800000 700000 E 600000 = Jom U mm 2QV0 � CarEOLifa 16/20 E • 16/20 CerboBmE Lit"" 500000 Vra BMc 400000 300000 200000 100000 - • 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 Closure Stress{psi) 12 • • Client : Hilcorp Alaska Schl� �rg�r Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230klbs Section 7: Hole Survey Hole Survey MD TVD Deviation Deviation Azimuth Azimuth Dogleg (ft) (ft) Angle Build Rate Angle Build Rate Severity (deg) (deg/100ft) (deg) (deg/100ft) (deg/100ft) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 100.0 100.0 0.6 0.6 99.3 99.3 0.6 231.0 231.0 1.2 0.5 103.4 3.2 0.5 354.0 354.0 1.2 _ 0.0 100.9 -2.1 0.0 479.0 478.9 1.0 -0.2 112.8 9.5 0.2 603.0 _ 602.9 0.5 -0.4 107.6 -4.2 0.4 729.0 728.9 0.2 -0.2 68.5 -31.1 0.3 855.0 854.9 1.9 1.3 275.3 -121.6 1.7 981.0 980.8 2.3 0.3 271.3 -3.2 0.4 1106.0 1105.8 0.9 -1.1 280.0 7.0 1.1 1232.0 1231.7 0.9 -0.0 229.4 -40.1 0.6 1358.0 1357.6 4.9 3.2 190.7 -30.8 3.4 co 1418.0 1417.2 7.4 4.1 186.2 -7.5 4.1 1483.0 1481.5 9.5 3.2 182.1 -6.4 3.4 1547.0 1544.4 11.7 3.5 181.8 -0.5 3.5 g 1607.2 1603.2 12.3 1.0 177.2 -7.6 1.9 c 1669.0 1663.3 15.0 4.3 170.7 -10.4 4.9 ro 1732.9 1724.5 18.8 6.0 168.8 -3.0 6.1 1795.2 1783.2 20.5 2.7 170.2 2.2 2.8 tu• 1858.6 1841.7 24.3 6.0 169.0 -1.8 6.1 ° 1921.4 1898.6 26.1 2.8 168.2 -1.3 2.8 1984.4 1955.5 24.6 -2.4 165.0 -5.1 3.2 2047.5 2013.0 24.2 -0.6 164.7 -0.5 0.7 2110.4 2070.7 22.5 -2.6 164.3 -0.5 2.6 2173.6 2128.8 23.8 2.0 164.1 -0.4 2.0 2236.4 2186.3 23.5 -0.5 164.6 0.7 0.6 2299.4 2243.7 25.2 2.7 163.4 -1.9 2.8 2362.0 2300.2 25.6 0.7 164.4 1.7 1.0 2424.9 2357.3 24.4 -1.9 164.6 0.2 1.9 2488.2 2414.5 25.6 1.9 163.3 -1.9 2.0 2550.6 _ 2470.8 26.1 0.7 _ 163.6 0.5 0.7 2613.9 2527.7 25.8 -0.5 162.3 -2.1 1.1 2739.6 2641.1 25.2 -0.4 164.0 1.4 0.7 2865.2 2755.4 24.0 -1.0 165.6 1.2 1.1 2991.1 2869.5 26.0 1.6 161.0 -3.6 2.2 3116.5 2983.3 23.6 -1.9 161.5 0.5 1.9 3242.4 3098.1 24.9 1.0 162.4 0.7 1.0 3368.2 3212.4 24.5 -0.3 163.3 0.8 0.5 3493.6 3327.1 23.3 -1.0 164.4 0.8 1.0 3619.6 3441.8 25.8 2.0 161.6 -2.2 2.2 13 • • Client : Hilcorp Alaska Schlumberger Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230kIbs Hole Survey MD TVD Deviation Deviation Azimuth Azimuth Dogleg (ft) (ft) Angle Build Rate Angle Build Rate Severity (deg) (deg/100ft) (deg) (deg/100ft) (deg/100ft) 3745.5 3555.0 26.0 0.2 163.1 1.1 0.5 3871.6 3668.2 26.2 0.2 163.8 0.6 0.3 4123.1 3894.8 25.2 -0.4 162.2 -0.6 0.5 4374.6 4123.7 23.6 -0.6 162.3 0.0 0.6 4563.2 4295.8 24.8 0.6 162.9 0.4 0.6 4689.7 4410.4 25.4 0.5 163.8 0.7 0.6 4815.2 4523.6 25.8 0.3 163.4 -0.4 0.3 4920.2 4618.3 25.5 -0.2 163.7 0.3 0.3 5012.0 4701.0 26.0 0.5 161.9 -1.9 0.9 5133.6 4811.9 22.3 -3.0 154.9 -5.8 3.8 5260.6 4927.2 27.2 3.9 155.9 0.7 3.9 5386.3 5036.1 32.7 4.3 147.4 -6.7 5.5 _ 5512.0 5138.8 37.8 4.1 141.7 -4.5 4.8 5637.3 5234.8 42.2 3.5 134.6 -5.7 5.1 a 5763.0 5324.0 47.5 4.2 131.0 -2.8 4.7 „" 5888.5 5405.2 51.9 3.5 130.7 -0.2 3.5 "1 6009.6 5479.7 52.2 0.3 130.0 -0.6 0.5 6140.0 5559.2 52.7 0.4 130.0 0.0 0.4 to 6265.8 5635.4 52.6 -0.0 130.1 0.1 0.0 ,w 6391.6 5712.0 52.4 -0.2 130.2 0.1 0.2 1' 6517.0 5789.6 51.1 -1.0 130.0 -0.2 1.0 6643.5 5872.1 47.4 -3.0 133.7 2.9 3.7 6769.3 5960.0 44.0 -2.7 142.9 7.3 5.9 6895.0 6053.3 40.4 -2.8 149.7 5.4 4.6 7020.9 6151.0 37.8 -2.1 160.1 8.2 5.6 7146.3 6253.0 33.5 -3.4 168.1 6.4 5.0 7272.3 6358.7 32.5 -0.8 177.0 7.1 4.0 7397.9 6464.5 32.7 0.1 187.3 8.2 4.4 7524.2 6570.5 33.4 0.5 196.8 7.5 4.1 7649.8 6675.4 33.5 0.1 204.4 6.1 3.4 7723.6 6736.8 33.9 0.5 207.5 4.2 2.4 7849.5 6841.3 33.9 0.0 211.1 2.9 1.6 7976.0 6947.7 31.5 -1.9 219.7 6.7 4.1 8101.9 7055.2 31.4 -0.1 233.3 10.8 5.6 8227.5 7162.8 31.1 -0.2 240.0 5.4 2.8 8289.9 7215.6 33.3 3.6 237.5 -4.1 4.2 8415.2 7319.5 34.7 1.1 239.3 1.5 1.4 8541.0 7423.6 33.7 -0.8 239.7 0.3 0.8 8666.7 7529.1 32.1 -1.2 238.4 -1.0 1.3 8792.5 7633.3 36.1 3.2 238.9 0.3 3.2 8918.4 7735.9 34.8 -1.0 239.0 0.1 1.0 9044.1 7839.8 33.7 -0.9 239.1 0.1 0.9 14 • • Client : Hilcorp Alaska Schlumberger Well : MPC-46 Formation : Sag River District : Prudhoe Bay Loadcase : 230klbs Hole Survey MD TVD Deviation Deviation Azimuth Azimuth Dogleg (ft) (ft) Angle Build Rate Angle Build Rate Severity (deg) (deg/100ft) (deg) (deg/100ft) (deg/100ft) 9170.0 7945.5 32.1 -1.3 238.8 -0.3 1.3 9295.4 8051.4 32.8 0.6 240.9 1.7 1.1 9421.4 8155.9 35.2 1.9 241.9 0.8 2.0 9543.4 8256.0 34.5 -0.5 240.9 -0.8 0.7 9672.5 8363.3 33.0 -1.2 241.2 0.2 1.2 9735.2 8416.2 32.0 -1.6 241.3 0.2 1.6 9798.6 8469.7 32.9 1.4 243.4 3.4 2.3 9861.2 8522.5 31.8 -1.8 243.8 0.6 1.8 9924.3 8576.3 31.8 0.0 244.6 1.3 0.7 9987.7 8630.6 30.2 -2.4 244.4 -0.2 2.4 10049.8 8683.9 31.1 1.4 242.8 -2.6 1.9 10112.5 8737.7 31.3 0.3 242.3 -0.8 0.5 10175.9 8791.9 31.2 -0.1 242.4 0.1 0.0 10238.8 8845.9 30.4 -1.3 241.4 -1.5 1.5 10301.5 8900.4 28.7 -2.6 241.7 0.4 2.6 10364.3 8955.8 27.6 -1.7 241.6 -0.1 1.7 ID 10390.5 8979.0 27.3 -1.5 241.6 -0.2 1.5 0. ea 10430.0 9014.1 27.3 0.0 241.6 0.0 0.0 M 15 • ! 20 AAC 25.283 (a)(13) Description of the Plan for Post-Fracture Wellbore Cleanup and Fluid Recovery through to Production Operations The well will be cleaned up through a portable separation system before turning the well over to Production. Initial returns will be taken to the permitted Milne Point G&I facility for disposal. • • 4 0 CD • co / � ƒ 2 o ai0 ° _ > k / 02S .o 7 2 0- 2 § m « ..... Ea c O . -0CO % E Ytd f 2 f k- % ±.E m 7 m =o \ \ 22 $ f " @ « 2 _ ��e e _ C \ / LCO % .q ■ m 2 \ k k % % Ef / 4- % B ow CD / § C.) $ / C) > 0 14. \/ / "0 % 0 \ Q ._ \ ts0 k ) § ww 2 E G a & 0 3 m O 2 / '\ 4 0/ \ a \/ Li 2 »7 co f\ /$ § § � E §Q j a. / 0 0. / \ 2 2 I 0,-- Q. INI \ C) 0 C C o * @ g COCI & m .2 \ C 2 $ 0 0 C) ■ / O O § 0 .. _ % \ C T ( / 0. > \ /U Cl)Q k /\ 0. • . 2 o 2 a s., 1 § 11 � to coms = p C C V A O ' U at F ;'" m w W > F A V F- w F w Uww aom Q om 1L, 1.—_ If. i , g g Z ON V 2 , 0. 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Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets(formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines,adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure),whichever is higher.Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) 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'`� cu v o � ) a E o o U �- _._ l__.....__. -- Q • A P(4. c--4G PM ZI76,z.o Regg, James B (DOA) From: Sloan Sunderland <ssunderland@hilcorp.com> Sent: Wednesday, May 31, 2017 4:26 PM c'' e1 141/7 To: DOA AOGCC Prudhoe Bay; Regg, James B (DOA) Cc: Paul Mazzolini; Joe Engel Subject: Hilcorp Innovation Notice of BOP Usage Attachments: Notice of BOP Usage.docx Here is the notice of BOP usage on the Hilcorp Innovation for 5/31/2017. Sloan Sunderland Hilcorp Drilling Forman Office- 907-670-3094 Cell-907-715-0591 From: Paul Mazzolini Sent: Wednesday, May 31, 2017 4:00 PM To: Schwartz, Guy L (DOA) Cc: Sloan Sunderland; David Buehring; Cody Dinger; Doug Yessak - (C); Joe Engel Subject: MPU C 46 Update Guy, Here is a written update on the operations for MPU C 46. This morning we got out of the hole and the well was static. While laying down the rotary steerable tool and density tools the well began to show a very slight flow. At this point the blind rams and choke were closed and casing pressure showed 6 psi. A 50 bbl pill of 12 ppg mud was mixed and bullheaded downhole. Hole was then monitored and early this afternoon pressure built to 8 psi. 50 bbls of 12.5 ppg mud was then bullheaded. At that point the well has gone back and forth from slight flow to slight loss (+1- 10 bbls/hr whether gaining or losing). The well is now being monitored on the trip tank as the test plug is set to test BOP components used to shut in on the well flow that now includes the blind rams. BOP closure on well flow notice to follow. Plan forward: - Mix 11.6 ppg mud to replace the 500 bbls lost, 12-18 hours to complete this task - PU dumb iron BHA with Commander sub to spot aggressive fiber/larger particle size LCM pills - RIH to Kuparuk C Sand, top at 7688' MD - Spot& squeeze 50 bbl of 80 ppb LCM pill(s) as required to cure losses using hesitation squeeze method (cement available on location should it be required to cure losses to be able to drill ahead) - Heal losses to be able to circulate at drilling rate of 450—550 gpm with 11.6 ppg mud - POH & PU rotatory steerable BHA& drill to +/-9300' MD - Run &cement 7" casing @9300' MD Let me know if you have any questions. Regards Paul • r€tsar . , Notice of BOP Use • Date/Time: 5/31/2017 at 10:10 hrs. • Well: MPU-C46 • Location: Milne Point, C pad, C-46 • PTD: 217-052 • Rig Name: Hilcorp Innovation • Operator Contact: Sloan Sunderland at 907-670-3094 ssunderland@hilcorp.com • Operation Summary: L/D BHA. Current mud weight 11.6 ppg, background gas was 0 units. After killing the well with 11.6 from a water flow and not being able to slow losses due to BHA and limitations for LCM we could pump we tripped to surface to change out BHA. The well started a slight flow. Losses for the trip were 131 bbl over calculated. • BOPE Used: Blinds • Reason For BOPE Use: Had drilling mud slowly start to flow down the flow line @ .5 BPH. • Actions Taken: Monitored SICP and pressure built to 6 psi. We bullheaded 45 bbl of 12 ppg mud and monitor SICP. Pressure @ 8 psi. Check choke and still had slight flow. Bled back 1 bbl & checked pressure. Still 8 psi. Bullhead 50 bbl 12.5 ppg mud. Check SICP. Pressure @ 0. Open blinds and flow check. Well very close to balanced. Losing +/- 10 BPH. Drain stack & set test plug. Monitor well with open annulus. Well balanced with BOPs drained. Put well on TT to annulus while testing components used in well control on last two shut ins. Test Blinds, Annular, TD Hyd IBOP, HCR Kill & Choke, Super Choke, Choke valve #7. • • Schwartz, Guy L (DOA) From: Regg,James B (DOA) Sent: Tuesday, May 30, 2017 11:29 AM To: Schwartz, Guy L(DOA) Subject: FW: Hilcorp Innovation Reporting use of BOPs to Prevent Flow. ( rD 17o5Z, fyi Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or jim.regg@alaskago- . From:Sloan Sunderland [mailto:ssunderland@hilcorp.com] Sent: Monday, May 29,2017 7:23 AM To: DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe.bay@alaska.gov>; Regg,James B (DOA)<jim.regg@alaska.gov> Cc: Paul Mazzolini <pmazzolini@hilcorp.com>;Joe Engel <jengel@hilcorp.com>;Shane Barber-(C) <sbarber@hilcorp.com> Subject: Hilcorp Innovation Reporting use of BOPs to Prevent Flow. Hilcorp Innovation Rig, MPC-46 Milne Point C-Pad Permit to Drill#217-052 Last BOP test 5-24-2017 The well was shut in @ 11:37 with the Annular. Contact-Sloan Sunderland 670-3094 Or 670-3070 Dog House While drilling ahead @ 7920 (7250 TVD) . Btm of the Kaparuk A.the driller notices an increase in pit gain. Pumps were shut down and the well was flowing @ 28%.There was only 1%increase on the flow meter while drilling. The well was shut in @ 11:37 with the annular and pit straps were taken. It was noted that a 26 bbl kick was taken in to the bore while drilling.The shut in pressures stabilized in 16 min @ 160 psi on the Dp and 250 on the casing. Currant MW @ 10.4. Drilling manager and drilling engineer were notified and it was determined to start the drillers method. Milne Point production was notified and all injectors on C pad were shut in until further evaluation. We wanted to add a safety factor on the casing so we bumped the float @ 1.5 BPM. We were only able to get the casing pressure to 265 and fluid started to inject. We pumped away 5 bbl. While circulating the dp started to increase along with casing pressure and we were pumping fluid away. Pumped away 25 more bbl in the first 1200 strokes pumped. Dp pressure was held constant @ 310-330 psi having to open the choke to get returns and we started getting a pit gain. @ 4800 strokes( Roughly%2 btm up) we had gained 52 bbl back to the pits.The pumps were shut down and the well shut in @ 14: 21to check pressures. Mud returns were coming back cut with water by 3/10s. Good 10.4 going in. 1 • 200 psi on the Drill pipe 405 psi in the annulus We attempted to bump the float again to get a safety factor due the pit gain while circulating but were only able to gain 15 psi on the annulus pumping away 7 bbls. New shut in pressures 170 DP 225 Annulus Drillers method was started again holding Dp pressure constant. We were monitoring gain loss to maintain from gaing or loosening in the pits. We have seen cut mud from 8.9- 10.1. We circulated two btm ups loosing slightly @ 3 bpm and we are now getting back 10.1 consistently. We have a water flow while circulating @ 3 bpm holding Dp pressure constant with losses. Mud WT in 10.5 MW out 10.1. Shut in pressures 168 on the DP&330 on the casing @ 20:15 We moved pipe and are free @ 250 up. We weighted up the active system to 10.7 and built a 50 BBL pill of 40 ppb LCM. Pill was spotted and well was shut in. We squeezed away 23 bbl in to formation. Continued to circ kill wt mud to surface. Circ 1.2 btm up. Came back @ 10.5. Pumping in 10.7. Decide to repeat steps with @ 10.9 kill mud weight. We have not had any gas during the well kill. Currently we are spotting another LCM pill chasing down with 10.9 ppg. Our plan is to get the well killed along with healing up the loss zone.We will then discuss the plan forward before proceeding. Sloan Sunderland Hilcorp Drilling Forman Office-907-670-3094 Cell-907-715-0591 2 ),Apc,,c C- piN6 2,17c 52.c, Regg, James B (DOA) From: Sloan Sunderland <ssunderland@hilcorp.com> Sent: Monday, May 29, 2017 7:23 AM \ o 5(3o(1 To: DOA AOGCC Prudhoe Bay; Regg, James B (DOA) Cc: Paul Mazzolini;Joe Engel; Shane Barber- (C) Subject: Hilcorp Innovation Reporting use of BOPs to Prevent Flow. Hilcorp Innovation Rig, MPC-46 Milne Point C-Pad Permit to Drill#217-052 - Last BOP test 5-24-2017 J The well was shut in @ 11:37 with the Annular. Claati7 Contact-Sloan Sunderland 670-3094 Or 670-3070 Dog House While drilling ahead @ 7920 ( 7250 TVD) . Btm of the Kaparuk A. the driller notices an increase in pit gain. Pumps were shut down and the well was flowing @ 28%.There was only 1% increase on the flow meter while drilling. The well was shut in @ 11:37 with the annular and pit straps were taken. It was noted that a 26 bbl kick was taken in to the Jgare while drilling.The shut in pressures stabilized in 16 min @ 160 psi on the Dp and 250 on the casing. Currant MW @ 10.4. Drilling manager and drilling engineer were notified and it was determined to start the drillers method. Milne Point production was notified and all injectors on C pad were shut in until further evaluation. We wanted to add a safety factor on the casing so we bumped the float @ 1.5 BPM. We were only able to get the casing pressure to 265 and fluid started to inject. We pumped away 5 bbl. While circulating the dp started to increase along with casing pressure and we were pumping fluid away. Pumped away 25 more bbl in the first 1200 strokes pumped. Dp pressure was held constant @ 310-330 psi having to open the choke to get returns and we started getting a pit gain. @ 4800 strokes( Roughly%2 btm up) we had gained 52 bbl back to the pits.The pumps were shut down and the well shut in @ 14: 21to check pressures. Mud returns were coming back cut with water by 3/10s. Good 10.4 going in. 200 psi on the Drill pipe 405 psi in the annulus We attempted to bump the float again to get a safety factor due the pit gain while circulating but were only able to gain 15 psi on the annulus pumping away 7 bbls. New shut in pressures 170 DP 225 Annulus Drillers method was started again holding Dp pressure constant. We were monitoring gain loss to maintain from gaing or loosening in the pits. We have seen cut mud from 8.9- 10.1. We circulated two btm ups loosing slightly @ 3 bpm and we are now getting back 10.1 consistently. We have a water flow while circulating @ 3 bpm holding Dp pressure constant with losses. Mud WT in 10.5 MW out 10.1. Shut in pressures 168 on the DP & 330 on the casing @ 20:15 We moved pipe and are free @ 250 up. We weighted up the active system to 10.7 and built a 50 BBL pill of 40 ppb LCM. Pill was spotted and well was shut in. We squeezed away 23 bbl in to formation. Continued to circ kill wt mud to surface. Circ 1.2 btm up. Came back @ 10.5. Pumping in 10.7. Decide to repeat steps with @ 10.9 kill mud weight. We have not had any gas during the well kill. Currently we are spotting another LCM pill chasing down with 10.9 ppg. 1 Our plan is to get the well killed along•with healing up the loss zone. We will then discuss the plan forward before proceeding. Sloan Sunderland Hilcorp Drilling Forman Office- 907-670-3094 Cell- 907-715-0591 2 yoFto g \%1/// . s? THE STATE Alaska Oil and Gas �,:, of/� T /� c K /� Conservation Commission _ S -Mi 11LI1�7 `I1 fi } 333 West Seventh Avenue "T'i ' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 SFA^:,.S1' ' Fax: 907.276.7542 www.aogcc.alaska.gov Paul Maz7olini Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Milne Point Field, Sag River Oil Pool,MPU C-46 Permit to Drill Number: 217-052 Sundry Number: 317-205 Dear Mr. Maz7olini: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this 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. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, P 9,4_, Cathy P. oerster Chair DATED this Z.`ay of May,2017. RBDMS ''' M,".? 2 4 2017 RECEIVE . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 1 9 _O17 APPLICATION FOR SUNDRY APPROVALS AOGCC°j SQL ? 7 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations❑ Fracture Stimulate ❑ Repair Well 0 Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate ❑ Pull Tubing 0 Change Approved Program❑r Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory 0 Development ❑✓ 217-052 ` 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 50-029-23576-00-00 , 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 423 1 MPU C-46 a Will planned perforations require a spacing exception? Yes 0 No ❑� 9. Property Designation(Lease Number): 10. Field/Pool(s): (SHL)ADL047434/(TPH/BHL)ADL025516 ' Milne Point Field/Sag River Oil Pool 1 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): ±1,084'Drlg Ahead ±1,084'Drlg Ahead ±1,084'Drlg Ahead ±1,084'DrIg Ahead Casing Length Size MD TVD Burst Collapse Structural Conductor 140' 16" 140' 140' Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 12.Attachments: Proposal Summary ❑✓ Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory ❑ Stratigraphic 0 Development 2 . Service ❑ 14. Estimated Date for 15.Well Status after proposed work: 5/19/2017 Commencing Operations: OIL ❑r 4 WINJ ❑ WDSPL 0 Suspended 0 16.Verbal Approval: Date: GAS 0 WAG 0 GSTOR 0 SPLUG 0 Commission Representative: GINJ ❑ Op Shutdown 0 Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Paul Mazzolini Contact Name: Joe Engel Authorized Title: Drilling Manager q Contact Email: lengei(Cr7hiIcorp.Com e---_ fag- PIT fnAZ.^1.•LIN1 Contact Phone: 777-8395 Authorized Signature: =� `, L � Date: 5/19/2017 ` COMMISSION USE ONLY Conditions of approval: Notify ommission so that a representative may witness Sundry Number: 3 t—t- 206 Plug Integrity ❑ BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: RBDMS -t— MAY 2 4 2017 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No IYJ Subsequent Form Required: I o,,,LI 0 7 �t ,/)i J 6' -4: APPROVED BY Approved by: /40 7 COMMISSIONER THE COMMISSION Date: S—Z (' r 4-15:CL-.;tole 5-44477 't. $23 /7 Submit Form and Form 10-403 Revised 4/2017 ® tGatpliiittLid for 12 months from the da a of approval. Attachments in Duplicate •• Joe Engel Hilcorp Alaska, LLC • Drilling Engineer P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8395 Email jengel@hilcorp.com llileorp Alaska,LLC 5/19/2017 Commissioner Alaska Oil &Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 RECEIVED MAY 192017 Re: Sundry Application for Change of Approved Plan for MPC-46 (PTD#217-052) AOG GC Dear Commissioner, Hilcorp Alaska, LLC hereby submits for review and approval for a change to the approved drilling program for the onshore production well at Milne Point'C' Pad, well slot 46. Drilling operations commenced on May 18, 2017. To ensure a successful casing run and adequate TOC in the production section, Hilcorp Alaska LLC proposes the following changes to MPC-46 drilling program: • 8-1/2" production hole to be changed to an under reamed 8-1/2"x 9-7/8" OH • 8-1/2"x 9-7/8" production hole will be drilled with a rotary steerable directional BHA • 7" production casing connection to be changed to VAM HTTC • 7" casing will be cemented via a two stage cement job, with a stage tool at the base of the Kup C, to ensure isolation of both the Sag River and Kuparuk Formation. Proposed cement volumes(including 25%OH excess) are: o 1st Stage: 349 ft3 o 2nd Stage: 166 ft3 • 7"casing will be landed with a slip and seal casing hanger assembly to facilitate rotatioluring the cement job o The 9-5/8"x 7"annulus will be monitored for 3 hours prior to setting slips Please find attached the Form 10-403,Application for Sundry Approval and the proposed wellbore schematic for MPC- 46. If you have any questions, or require further information, please do not hesitate to contact myself(Joe Engel) at 777- 8395 or jengel@hilcorp.com or Paul Mazzolini at 777-8369. Sincerely, Joe Engel Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 0 0 Milne Point Unit . ini PROPOSED SCHEMATIC Well: MPU C-46 Last Completed: Future Hilcorp Alaska,LLC PTD: 217-052 TREE&WELLHEAD KB Elev.:41.5' GL Elev.:15' Tree 4-1/16"5M t'i kii, w ,? i 1 }* Wellhead Seaboard Weir,w/11"x 5M top flange 20 4-1/2"Tubing Hanger CASING DETAIL I Size Type Wt/Grade/Conn Drift ID Top Btm rscemerrterc) 16" Conductor 164/A-106B/Weld 14" Surface 140' @ 1,900' ;0 1 29-5/8" Surface 40/L-80/DWC/C 8.679" Surface 4,800' r 7" Production 26/L-80/HTTC 6.151" Surface 10,128' ' TUBING DETAIL ', 4-1/2" Tubing 13.5/L-80/Hydril 625 3.795" Surface ±9,735' 9-5/8" °4 1 WELL INCLINATION DETAIL KOP@1150' MD Max Hole Angle=35° F/7700'T/TD JEWELRY DETAIL TOC @±7,348' No Depth Drift ID Item 14 ;•, 1 ±23' 3.833" 11"x 4-1/2"Tubing Hanger(4-1/2"TC-II Top& Btm) 2 ±9,673' 3.725" 4-1/2" R Profile Min ID=3.688" :; 3 ±9,615' 3.870" Baker 7"x 4-1/2" Premier Packer(598-387) Min ID=3.870" I 4 ±9,719' 3.833" 4-1/2"WLEG Btm @±9,735' //�''�Stage Tool @ `✓BaseKuparuk E-5 C"7,848'MD C��=„.,",,_,,' TOC @±9,074' C,r E l,) I . 2 a $`� I i I 1 s PERFORATION DETAIL *1 Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status 22` hi r 4 l4 4 I4 a Ori Hi ii 7" Itffin TD=10,128(MD)/TD=9,041'(TVD) PBTD=10,038'(MD)/PBTD=8,970J(TVD) Revised by:G0 5/19/17 OFT S \ ly7,- "s, THE STATE Alaska Oil and Gas 64•41 -7.;�� Of Q T A KA Conservation Commission Sf�- 333 West Seventh Avenue '. GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 w, Main: 907.279.1433 OF Sift.pv Fax: 907.276.7542 www.aogcc.alaska.gov Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Sag River Oil Pool, MPC-46 Hilcorp Alaska, LLC Permit to Drill Number: 217-052 Surface Location: 923' FSL, 2369' FEL, SEC. 10, T13N, R10E, UM, AK Bottomhole Location: 2247' FSL, 2313' FEL, SEC. 15, T13N, R10E, UM, AK Dear Mr. Mazzolini: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05,Title 20,Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy . Foerster Chair DATED this 0- day of April, 2017. RECEIVED STATE OF ALASKA APR 0 2017 A OIL AND GAS CONSERVATION COM ION PERMIT TO DRILL 20 AAC 25.005 AOGCC la.Type of Work: lb.Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp ❑ lc.Specify if well is proposed for: Drill El Lateral ❑ Stratigraphic Test ❑ Development-Oil Q' Service- Winj ❑ Single Zone 0' Coalbed Gas ❑ Gas Hydrates ❑ Redrill❑ Reentry❑ Exploratory-Oil ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket Q, Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244- MPC-46` 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 10,087' . TVD: 9,041' , Milne Point Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Sag River Oil Pool • Surface: 923'FSL,2369'FEL,Sec 10,T13N,R10E, UM,AK (SHL)ADL047434(TPH/BHL)ADL025516 Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 2557'FSL,2216'FEL,Sec 15,T13N,R10E,UM,AK N/A 4/28/2017 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 2247'FSL,2313'FEL,Sec 15,T13N,R10E,UM,AK ADL047434-2560/ADL025516-1280 17,976'to nearest unit boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 41.5 • 15.Distance to Nearest Well Open Surface: x-558093 - y- 6029204 • Zone-4 GL Elevation above MSL(ft): 15 . to Same Pool: 3000'to MPC-15A 16.Deviated wells: Kickoff depth: 1,150 feet - 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 36 degrees • Downhole: 4603 Surface: 3699 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) Gond 16" 164# A-1068 Weld 140' Surface Surface 140' 140' Driven Stg 1 L-977.5 ft3/T-256.7 ft3 12-1/4" 9-5/8" 40# L-80 DWC/C 4,800' Surface Surface 4,800', 4,497' Stg 2 L-1286 ft3/T-470 ft3 8-1/2" 7" 26# L-80 DWC/C 10,087' Surface Surface 10,087'• 9,041' e 497 ft3 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): Perforation Depth TVD(ft): 20. Attachments: Property Plat Q BOP Sketch Q Drilling Program 0 Time v.Depth Plot Q Shallow Hazard Analysis Diverter Sketch ❑✓ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Paul Mazzolini Email pmazzolini@hilcorp.com Printed Name Paul Mazzolini Title Drilling Manager 5 Signature 0,44.e n/a4/ • /0 Phone 777-8369 Date /zoi 7 Commission Use Only Permit to Drill API Number: �'� Permit Approval >>>> See cover letter for other Number: Z f 7. � _ 50-02....' —�S 76--66-Date: q l y/i') requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: d,. Other: .A y 000 ,p5" /,!�U f) "f' Samples req'd: Yes 0 N Q Mud log req'd:Yes❑,No El/ / H25 measures: Yes © No❑ Directional svy req'd:Yes 21No❑ * G' L Kerc_c ^e— Spacing exception req'd: Yes [1] No❑f Inclination-only svy req'd:Yes❑ No[+� J Re s Edi « C ^.t;0.-,, t Post initial injection MIT req'd:Yes❑ No❑ I APPROVED BY Approved by: �`+'(/� COMMISSIONER THE COMMISSION f/• Date:-f��/ �-1.3-/ 7 l((go Submit Form and Form 10-4 1(Revised 11/2015) 0444.4wAs months from the date of approval(20 C 25.005(9) Attachments in Duplicate Paul Mazzolini • Hilcorp Alaska, LLC Drilling Manager P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8369 Email pmazzolini@hilcorp.com Hilcorp Alaska,LLC RECEIVED 4/5/2017 APR 0 5 2017 Commissioner AO GCC Alaska Oil &Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: MPC-46 Dear Commissioner, Enclosed for review and approval is the Permit to Drill for MPC-46 well. MPU C-46 is a grassroots producer with the Sag River as the primary target and the Kuparuk C sand as a secondary target. The directional plan is a slant well with the kick off point at 1150' MD/TVD. The hole is built to 25 degrees and held to 7319' MD/6780'TVD where the hole angle is increased to 36 degrees and held to TD. Drilling operations are expected to commence approximately April 28th, 2017. • The Innovation Rig will be used to drill and complete the well. After reviewing the LWD logs obtained while drilling the well, a determination will be made whether or not fracture stimulation will be required at a later date. The base plan, ✓' however, is to fracture stimulate the well if a Sag River producer and will be reviewed if a Kuparuk producer. A CBL will be run on the 7" production casing in the event fracture stimulation is required at a later date. If you have any questions, please don't hesitate to contact myself at 777-8369. Sincerely, /-"potA j ?Noire Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC Page 1 of 1 • • H Hilcorp Alaska, LLC Milne Point Unit (MPU) C-46 Drilling Program Version 1 April 3, 2017 • Milne Point Drilling Procedure Hilcorp Energy Company Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program: 4 4.0 Drill Pipe Information: 4 5.0 Casing Inspection 4 6.0 Internal Reporting Requirements 5 7.0 Planned Wellbore Schematic 6 8.0 Drilling/Completion Summary 7 9.0 Mandatory Regulatory Compliance/Notifications 8 10.0 R/U and Preparatory Work 10 11.0 N/U 13 5/8"5M Diverter System 10 12.0 Drill 12-1/4"Hole Section 12 13.0 Run 9-5/8"Surface Casing 17 14.0 Cement 9-5/8"Surface Casing 21 15.0 BOP N/U and Test 26 16.0 Drill 8-1/2"Hole Section 27 17.0 Run 7"Production Casing 31 18.0 Cement 7"Production Casing 33 19.0 Run 4-1/2"Fracture Stimulation String Error!Bookmark not defined. 20.0 Contingency String: 37 21.0 Wellbore with contingency 4-1/2"liner installed 38 22.0 Diverter Schematic Error!Bookmark not defined. 23.0 BOP Schematic 40 24.0 Wellhead Schematic 41 25.0 Days Vs Depth 42 26.0 Formation Description 43 27.0 Anticipated Drilling Hazards 44 28.0 Innovation Rig Layout 47 29.0 FIT Procedure 48 30.0 Choke Manifold Schematic 49 31.0 Casing Design Information 50 32.0 8-1/2"Hole Section MASP 51 33.0 Spider Plot(NAD 27)(Governmental Sections) 52 34.0 Surface Plat(As Built)(NAD 27) 53 35.0 Offset MW vs TVD Chart 54 36.0 Drill Pipe Information 5" 19.5#5-135 DS-50 55 S a Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well MPU C-46 Pad Milne Point"C"Pad Planned Completion Type 4-1/2"Production tubing Target Reservoir(s) Sag River • Planned Well TD, MD/TVD 10,087' MD/9041' TVD • PBTD, MD/TVD 9,997' MD/8,970' TVD Surface Location(Governmental) 923' FSL,2369' FEL, Sec 10, T13N, R10E,UM,AK • Surface Location(NAD 27—Zone 4) X=558,093.18,Y=6,029,204.76 • Surface Location(NAD 83) Top of Productive Horizon (Governmental) 2557'FSL, 2216'FEL, Sec 15, T13N,R10E,UM,AK TPH Location(NAD 27) X=558,280 Y=6,025,560 TPH Location(NAD 83) BHL(Governmental) 2247'FSL,2313'FEL, Sec 15,T13N,R10E,UM,AK BHL(NAD 27) X=558,186.21 Y=6,025,249.56 BHL(NAD 83) AFE Number 1710173D AFE Drilling Days 25 Days AFE Completion Days AFE Drilling Amount $5,278,760 AFE Completion Amount AFE Facility Amount Maximum Anticipated Pressure (Surface) 3699 psig Maximum Anticipated Pressure (Downhole/Reservoir) 4603 psig . 5" 19.5# S-135 DS-50 (Weatherford Rental) Work String 4" 14# S-135 HT-38 (Weatherford Rental—Contingency) KB Elevation above MSL: 26.5 ft+ 15.0 ft=41.5 ft GL Elevation above MSL: 15.0 ft BOP Equipment 13-5/8'x 5M Annular,(3)ea. 13-5/8"x 5M Rams Page 2 Version 1 April 2017 • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp Changes to Approved Permit to Drill Date: 02-08-2017 Subject: Changes to Approved Permit to Drill for MPU C-46 File#: MPU C-46 Drilling and Completion Program Any modifications to MPU C-46 Drilling&Completion Program will be documented and approved below. Changes to an approved APD will be approved by the AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Version 1 April 2017 • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section (in) OD (in) 4 Ift) (psi) (psi) (k- Cond 16" 14" - - 164 A-106B Weld 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 DWC/C 5750 3090 916 8-1/2" 7" 6.276" 6.151" 7.656" 26 L-80 DWC/C 7240 5410 604 *6-1/8" 4.5" 3.920" 3.795" 4.93" 13.5# L-80 VAM 9,020 8,540 1 HTTC *Note: Contingency string highlighted in yellow. 4.0 Drill Pipe Information: Hole OD ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section (in) (in) (in) (#/ft) (Min) (Max) (k-lbs) Surface& 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k Intermediate *6-1/8" 4" 3.34" 2.5625" 4.875" 14 S-135 HT-38 12,200 17,700 649,200 *Note: Contingency drill pipe highlighted in yellow V 5.0 Casing Inspection All casing will be new, PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 April 2017 • 41110 Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area—this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, jengel@hilcorp.com and cdinger@hilcorp.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drilling Manager& Drilling Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final "As-Run" Casing tally to pmazzolini@hilcorp.com,jengel@hilcorp.com and cdinger@hilcorp.com 6.6 Casing and Cmt report • Send casing and cement report for each string of casing to pmazzolini(a,hilcorp.com, ✓ jengel@hilcorp.com and cdinger@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 pchan@hilcorp.com Geologist Matt Brown 907.777.8448 713-458-8667 mbrown@hilcorp.com Reservoir Engineer Anthony McKonkey 907.777.8460 amckonkey@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350-9439 jorczewska@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com EHS Field Coordinator Jimmy Watson 907.777.8450 907.744.7376 jiwatson@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 April 2017 • 0 Milne Point Unit II PROPOSED SCHEMATIC Well: MPU C-46 Last Completed: Future C!Iacono Aia,ka,1.1 PTD: TBD KBEIev.:31.5'/GLEIev.:15' TREE&WELLHEAD Tree 4-1/16"5M J ! t L Wellhead Seaboard Weir,w/11"x 5M top flange 20" 4-1/2"Tubing Hanger CASING DETAIL 0 0 Size Type Wt/Grade/Conn Drift ID Top Btm Es cementer 16" Conductor 164/A-106B/Weld 14" Surface 140' 1,900 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 4,800' 7" Production 26/L-80/DWC/C 6.151" Surface 10,087' TUBING DETAIL 4-1/2" Tubing 13.5/L-80/Hydril 625 3.795" Surface ±9,735' 9-5/8" 4 WELL INCLINATION DETAIL KOP @ 1150' MD Max Hole Angle=35°F/7700'T/TD JEWELRY DETAIL No Depth Drift ID Item 1 ±23' 3.833" 11"x 4-1/2"Tubing Hanger(4-1/2"TC-II Top&Btm) . 2 ±9,505' 3.813" 4-1/2" RD Sliding Sleeve Min ID=3.688 3 ±9,560' 3.842" 4-1/2" ROC Pressure Intake Gauge Min ID=3.842" . 4 ±9,615' 3.870" Baker 7"x 4-1/2" Premier Packer(598-387)Min ID=3.870" 5 ±9,673' 3.725" 4-1/2" R Profile S.btty 6 ±9,719' 3.833" 4-1/2"WLEG Btm ew 19,735' ' 0 2 ?3 4 PERFORATION DETAIL " Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status : :L 5 6 14jej TD=10,087(MD)/TD=9,041'(TVD) PBTD=9,997'(MD)/PBTD=8,970'(TVD) Revised by:STP 4/13/17 ! •• Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 7.0 Planned Wellbore Schematic 0 -- in Milne Point Unit PROPOSED SCHEMATIC Well:MPUC-4s Last Completed:Future 1:17rnrp 5.Lt. PTD: TBD 1B EeV.:3L5'i'GLEesi.:15' TREE&WELLHEAD F Tree 4-1/15'S1v1 " i Wellhead Seaboard Weir,uy11 x 5M tap f ange 4-1/2'Tut,rg Hanger ;; CASING DETAIL 0 c$ �� _re T;p= Wt/Grade/Conn Cif=:II Ti.: 5trr Earner er.. L,1J lc" Conducts' 154/A-1058/Weld 14' Sura:e 140' ', G 9-5/V' Surface 4D/L-0i DWC/C 8.a?9' Sura:e 4,3re + ,e. .✓- Product or 25; L-5C/CWC/.. 5.151v Surae 20,057 TUB NG DE7A'L 4-1/2" I Tubing I 13.5/L-ac/H'/•dill 525 I 3.795" I Sura:e I -5,00.7e 119°- WELL INCLINATION DETAIL r0 C- KOPg1150'MD Max\Hole Angle=35'F/7700'T,trD JEWELRY DETAIL i Depth Drift ID Item 23' 1.533" 11"x 4-1,/2 TLb?ng Hanger ±9,000' 3.533" 4-112"WLEG 4,1 '706. ( p PERFORATION DETAIL --- '• :`-: Top[MD: BtrniMD} Top I:710i Etm(7,r,..1 F-- Da:= Status , t. 4( tk w, ' Y ry TD=40E7(MC}/TD=c.c4i'MIDI P15TD=9,991(Mai/FWD=8,9:0'ITUDI Rv,,ed try:OD 3/29/17 Page 6 Version 1 April 2017 9 • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 21.0 Wellbore with contingec 4-1/277 liner installed Milne Point Unit PROPOSED SCHEMATIC Well:MPU C-46 114 Last Completed:Proposed IIit..a„ 41.-,., 1 PTD: TBD KB Eay.:3L5.7LLEa. TREE&WELLHEAD I Tree :I'W 7-1/16"5M jt i L Wellhead See boa-d.Weir,3 spcc'is,w.i11"x SM bap flange •••'.o tubing hanger*"' CASING DETAIL 0 0 Size Type V.'t/Grade/Conn Drift ID Tcp Etrr ECe-re•r'w .1 1E" Conducts- 164 r A-1055/Weld 14• surface 14:-I 9-57/'3" Surface t7; L '7Cr[ ¢.6?9'" $urfe'.e A=[C' 7° Intermediate X51 L C D.'.'[:[ 6.152" Sur`a S,a3A' 4-1/2" Product on 13.5:LCC;V..V HTTC 3.955° 9,350' . 17,037' TUBING DETAIL . 4-1/2" I Tubing I 13.5 1-801t4.625 I 3.795" I Surra:= I -9,000 WELL INCLINATION DETAIL KOP?:71150'MD VEX Date Angle=35'F/7,030'MD Te'TD JEWELRY DETAIL Depth Drift ID Item 23' 3.833" 11"x 4-1/2"Tubing Hanger 1 ±3,000' 3.533" 4-1)/2'WLEG ;p .v n k ' PERFORATION DETAIL _a _ Tcp(MD; Btm(MD} Top(TVD) Ban(TVD) FT Dii:e -t_tz T F , I COPS/ tis I i 4L2" Itytie TD=9!i2I Ivni 1T=4 (n'D4 PBTD=9,43D'(rvtyt PBTD=$875(TW4 Rev i:ed t'-GD 443/17 Page 38 Version 1 April 2017 410 Milne Point Unit C-46 111 Drilling Procedure Hilcorp Energy Company 8.0 Drilling / Completion Summary MPU C-46 is a grassroots producer with the Sag River as the primary target and the Kuparuk C sand as a secondary target. The directional plan is a slant well with the kick off point at 1150' MD/TVD. The hole is built to 25 degrees and held to 7319' MD/6780' TVD where the hole angle is increased to 36 degrees and held to TD. Drilling operations are expected to commence approximately April 28th,2017. " The Innovation Rig will be used to drill and complete the well. After reviewing the LWD logs obtained while drilling the well, a determination will be made whether or not fracture stimulation will be performed at a later date. The base plan,however, is to fracture stimulate the well if a Sag River producer and will be reviewed if a Kuparuk producer. A CBL will be run on the 7" production casing in the event fracture stimulation is required at a later date. .i Surface casing will be run to 4800' MD/4497' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, a - temp log will be run between 12—24 hours after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC personnel. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on"B"Pad. General sequence of operations: 1. MIRU Innovation Rig to well site 2. N/U 13-5/8", 5K BOP stack in diverter configuration with a 13-5/8" diverter T & 16"knife gate valve on the conductor and 16" diverter line. Function test diverter. 3. Drill 12-1/4"hole to TD of surface hole section. Run& cement 9-5/8" surface casing. 4. N/D diverter line, diverter T&knife gate valve. N/U casing head, N/U &test 13-5/8"BOPE. 5. Drill 8-1/2"hole to TD. • 6. Obtain rotary sidewall cores (optional). • 7. Run and cement 7"production casing. 8. Run 4-1/2" fracture stimulation string. - {°',.��"�' 9. N/D BOP,N/U tree, RDMO. 10. A separate 10-403 sundry will be submitted for the hydraulic fracture stimulation operations. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. LWD: GR+Res 2. Production Hole: No mud logging. LWD: GR+Res+ CTN 3. Obtain rotary sidewall cores (optional, depending upon hole conditions) 4. Cased Hole Logs: CBL over 7"production casing. Page 7 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU C-46. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. ✓ • The initial test of BOP equipment will be to 250/4000 psi& subsequent tests of the BOP equipment will be to 250/4000 psi for 5/5 min(annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore,AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. Page 8 Version 1 April 2017 • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12 1/4" • 13-5/8"5M CTI Annular BOP w/16"diverter line Function Test Only • 13-5/8"x 5M Control Technology Inc Annular BOP • 13-5/8"x 5M Control Technology Inc Double Gate Initial Test:250/4000 ' o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/3"x 5M side outlets 8-1/2" • 13-5/8"x 5M Control Technology Single ram • • 3-1/8"x 5M Choke Line Subsequent Tests: • 3-1/8"x 5M Kill line 250/4000 • 3-1/8"x 5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event(BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236(During normal Business Hours) Notification/Emergency Phone: 907-659-2714(Outside normal Business Hours) Page 9 Version 1 April 2017 • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 10.0 R/U and Preparatory Work 10.1 C-46 will utilize a newly set conductor on C Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 10.2 Dig out and set impermeable cellar inside existing culvert. 10.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 10.4 Install Seaboard slip-on 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 10.5 Insure (2) 4"threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack-off 10.6 Level pad and ensure enough room for layout of rig footprint and R/U. 10.7 MIRU Innovation Rig. 10.8 Mud loggers WILL NOT be used on either hole section. 10.9 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 10.10 Install 5" liners in mud pumps. • White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. 11.0 N/U 13-5/8" 5M Diverter Configuration 11.1 N/U 13-5/8" CTI BOP stack in diverter configuration(Diverter Schematic in Sec 21 of program). • N/U16" SOW • N/U 13 5/8", 5M diverter"T". • NU Knife gate & 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 11.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. Page 10 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 11.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone"must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running equipment. • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle traffic only. 11.4 Set wear bushing in wellhead. 11.5 Rig & Diverter Orientation: I , 11.11111111011 i I , � I ,w I I i . tri:4 i IV 11; 111=Eh I I II _Ts[— r_ I I r j I � I j I I �� I r I n I I I Page 11 Version 1 April 2017 • • 11 Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 12.0 Drill 12-1/4" Hole Section 12.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill pipe will be 5" 19.5# S-135 DS50. • Run a solid float in the surface hole section. 12.2 12-1/4" BHA (GR+ Res LWD and PWD planned in surface hole): ' COMPONENTflAT I Number OD ID Gauge Weight Top Length Cumulative (in) (In) (in) (lbpf) Connection {tt) Length (ft) 1 Varel PDC 7.500 2.875 12.250 128.44 1.05 1.05 En 8'Sperrydrill Lobe 4/5-5.3 stg IIIIIIIMI 8.000 5.000 ® 121.08 : • : " 32.07 MIEMI Stabilizer -__ 12.125 _--- 3 6-Integral Blade Stab 8.000 3.250 11.500 143.03 B 6-5/8"REG 7.85 40.97 Ell 8"DM Collar MIIIIIIII 8.000 3500 147.40 B 6-5/8"REG 9.16 50.13 ® 8"DGR Collar • -. 8.000 1.920 142.70 B 6-518"REG 6.41 5654 MI 8'EWR-P4 Collar 8.000 2.000 151.00 B 6-5/8"REG 12.16 68.70 7 8"PWD8.000 1.920 143.40 B 6-5/8"REG 4.36 73.06 8 8"HCIM Collar 8.000 1.920 149.90 cmazimmig 80.83 9 8"HOC B_150 3.250 151.20 B 6-5/8"REG 9.85 90.68 10 6"Non-Mag UBHO 8.000 Eli gm gm B 6-5/8"REG 3.50 94.18 11 8"Non-Mag Flex 7.400 2.875 124.5 B 6-5/8"REG 30.16 124.34 MI 8"Non-Mag Flex IIIIIIIIIII 7.610 3.250 126.74 El=MEM 153.85 13 8-Non-Mag Flex 7.750 2.875 138.64 B 6-5/8"REG 30.06 183.91 14 X-Over Sub 7.938 2.875 146.51 B 4-1/2"IF 2.65 186.56 15 6 Jts x 5"X 3"HWDP#49.3 NC50 5.000 3.000 49.30 184.85 371.41 16 Jar 6.250 2.250 91.01 B 4-112"IF 29.76 401.17 17 13 Jts x 5"X 3"HWDP#49.3-NC50 - 5.000 3.000 49.30 402.30 803.47 Total: 803.47 / Page 12 Version 1 April 2017 • • II Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 12.3 Primary Bit: 12-1/4"PDC 2 1/4" (3112mm) \* Assembly: �_.. A09591 k.,,_ '. .1.111_,° ai er 'ADC Code: $323 SERIES PRODUCT SPECIFICATIONS e S Cutter Size: 16 mm ;os Cutter Back Up: Carbide Shock Studs se =\.,41 Total Cutter Count: 53 '� �"`'— Face Cutter Count: 47 • . S 44 Connection: 6 518"API Regular " Nozzle 1 Qty/Type: 9-Series 65 Nozzle 2 Qty/Type: - Junk Slot Area: 29.1in2(187.7cm2) Gage Pad Length: 6"(152mm) " ' t dMake Up Length: 12.5"(316.2mm) It� � '�w41 Shank Diameter: 7.6"(193mm) , 4tie :'til 0 14OPERATING PARAMETERS* ti % . -,. 34 0 - Rotary Speed: For all rotary and motor applications A , Flowrate Min-Max: 300-900GPM(1.14-3.41 m3lmin) k Max Weight On Bit: 36,000Ibs(16014daN) OP Makeup Torque: 28,000-32,000Ft-Lbs. (37963-43386Nm) 'Operating parameters shorfn aro typicar for are art type specaiea. Fir recommendalons on your specirc applicaboncontact your „d` Vara!Inte€nat,nal representative. Bit Features H -Increased number of nozzles for improved bit cleaning. X -Shock studs limit drill bit vibration and increase stability allowing smooth cutting action increasing cutter life and overall bit performance. 12.4 5" drill pipe, 5" HWDP, and Jars will come from Weatherford. 12.5 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. Page 13 Version 1 April2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 12.6 Drill 12-1/4"hole section to 4800' MD/4497' TVD. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation. • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 500-600 gpm. Monitor shakers closely to ensure shaker screens and returns line are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW and viscosity as necessary to maintain hole stability. • Ensure TD of the hole section is— 100' MD below Schrader Bluff Sands. ' • Take Gyro &MWD surveys every stand+/- 60'. Gyro surveys until clear of magnetic interference. • No gas hydrates have been encountered on C Pad wells, however be prepared if hydrates are seen. • Have the water and air flowline jets hooked up and be ready to jet the flowline at the first sign of flowline backup. The combination of air and water is useful to minimize volume of fluid added to the system. • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is>4. • Do not slide for 100' MD above the base of the permafrost or 100' below the base. We want to leave this transition as undisturbed as possible. Page 14 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 12.7 12-1/4"hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1)ppg above highest anticipated MW. We will start with a simple gel +FW spud mud at 8.8 ppg. - • PVT System: An electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the Driller's console, Co Man office and Toolpusher office. • i Hydrates: Hydrates have not been encountered on any "C" Pad wells drilled to date. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin sstem with a 45 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5—9.0 range with caustic soda. Daily additions of ALDACIDE G/X-CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP <20 (check with the cementers to see what YP value they have targeted). System Type: 8.8—9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Densit Viscosity Plastic Viscosity Yield Point API FL Temp pH 110'-4800' 8.8-9 5' 75-175 20-40 25-45 <10 < 70° F 8.5-9.0 Page 15 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 -20 ppb caustic soda 0.1 ppb(8.5—9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8—9.5 ppg PAC-L/DEXTRID LT if required for<10 FL ALDACIDE G 0.1 ppb 12.8 At TD; pump sweeps, Circulate 2-3 BU at high flow rates and rpm—racking back 1 stand per BU and alternating reciprocation depths to minimize risk of troughing and dropping inclination, . Pump out of the hole holding TF high side. Pull slow if hole starts unloading. • MPB-33 LL: Drop vise to —50 cp and MW of 9.4 at TD before coming out of the hole resulting in smooth BROOH out and casing run 12.9 Should backreaming be necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 —4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (500-600 gpm) and maximize rotation below permafrost Minimize backreaming in permafrost, backreaming is a last resort • Pull slowly, 5— 10 ft/minute,monitor torque closely. • Monitor well for any signs of packing off or losses. • Have the air and water flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 12.10 Trip/Pump/BR OOH as necessary with the drilling assembly and handle BHA components as required. 12.11 No open hole logging program planned. Page 16 Version 1 April 2017 Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 13.0 Run 9-5/8" Surface Casing 13.1 The plan is to set slips for 9-5/8" casing. 13.2 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8"DWC/C x DS50 XO on rig floor and M/U to FOSV. • Use "Besto Life 2000"thread compound. Dope pin end only w/paint brush. • Consider R/U of CRT if hole conditions require. • R/U a fill up line to fill casing while running. • Ensure all casing has been strapped &drifted to 8.750" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor & model info. 13.3 P/U shoe joint, visually verify no debris inside joint. 13.4 Continue M/U &thread locking shoe track assembly consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end &thread locked. Install (1) centralizer mid tube over a stop collar. • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. flailLeto • (1) Joint with Halliburton bypass baffle adapter bucked on pin&threadlocked. Install (1) centralizer mid tube over a stop collar. Page 17 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. 13.5 Float equipment and Stage tool equipment drawings: "A Overall Length III Type H ES Cementer B Part No. Mie.ID After Drillout � SO No. C Max.Tool OD RIM i D ',Warp ES-111 Running Order ( Opening Seat ID A Closing Sleeve No.Shear Pins M E Cbsing Seat ID Opening Sleeve ii I I�. Na.Shear Pins Plug set EMI Cementer ES Cementer Part No. Depth L.*ter SO No. \ 7 Closing Plug illi r = Baffle Adapter(if used) t:::=-- OD — Shut Off Plug a 1 111ICOpening PlugOMR Depth OD Raffle Adapter OD a 'fir !rii I Bypass or Shut-off Baffle I 11 ID p lug friDemShut-off Plug Depth Float Collar l� ic l Depth M "'Pass Baffle ..■1 OD Float Collar F Float Shoe Depth Bypass Plug f 1 (•d used) u MI Hole TD Float Shoe "Reference Camp OD sas Sales Manual Section 5 Page 18 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 13.6 Continue running 9-5/8" surface casing • Fill casing while running in the hole every joint and top off every 5, using fill up line on rig floor or CRT. Circ through shoe track. • Install (1) centralizer every other joint for the first 15 joints. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • M/U DWC/C connections as per recommended torque ratings below. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 13.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at 1900' MD/ 1868' TVD. This will position the stage collar comfortably below the permafrost. • Install centralizers over couplings on 3 joints below and above stage tool. • Do not place tongs on ES cementer, this can cause damage to the tool. • Ensure tool is pinned with 6 opening shear pins. There are 6 holes,the tool is normally sent with only 4 pins installed. This will allow the tool to open at 3300 psi. 9-5/8" 40#L-80 DWC/C Make Up Torques: Min MU Torque Max MU Torque 28,900 ft-lbs 34,800 ft-lbs 13.8 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.9 Slow in and out of slips. 13.10 P/U landing joint and M/U to casing string. Position the casing shoe+/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at(1) ft intervals to use as a reference when getting the casing on depth. 13.11 Lower casing to setting depth. Confirm measurements. 13.12 Have slips staged in cellar. Page 19 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWC+G Casing 9-5f8 in 40.00 lb/ft(0.395 in) L-84 Ste nCa rd Material L-80 Grade 80,000 Minimum Yield Strength (psi) 11•11111111111111111111111111111111,t1 SA 95,000 Minimum Ultimate Strength (psi) yAhn USA 4424 W.Sam Houston Pkwy.Suite 150 Pipe Dimensions Houston,TX 77041 3200 9.625 Nominal Pipe BodyO.D. (in) Fax:713-479-3234 8.835 Nominal Pipe Body I.D.(in) E-mail:VAMUSAsalestavam-usa_com 0.395 Nominal Wall Thickness (in) 40.00 Nominal Weight (lbs?ft) 38.97 Plain End Weight(lbs/ft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916,000 Minimum Pipe Body Yield Strength (lbs) 3,090 Minimum Collapse Pressure (psi) 5,750 Minimum Internal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection O_D_ (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter(in) 4.81 Make-up Loss (in) 11.454 Critical Area (sq in) 100.0 Joint Efficiency (%) Connection Performance Properties 916,000 Joint Strength (lbs) 16,360 Reference String Length (ft) 1.4 Design Factor 947.000 API Joint Strength (lbs) 916,000 Structural Compression Rating (lbs) 3,090 API Collapse Pressure Rating (psi) a{� 5,750 API Internal Pressure Resistance (psi) ,fi4 19.0 Maximum Uniaxial Bend Rating [degrees/100 ft] Appoxlmated Field End Torque Values 29,800 Minimum Final Torque (ft-lbs) 34,800 Maximum Final Torque (ft-lbs) 39,800 Connection Yield Torque (ft-lbs) 13.13 R/U circulating equipment and circulate B/U. Reduce YP to <20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. 13.14 Hold casing string and reciprocate casing if possible while conditioning mud. Page 20 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 14.0 Cement 9-5/8" Surface Casing 14.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud& water can be delivered to the cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron lines and connections used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 14.4 R/U cementing head (if not already done so). Witness loading of the top and bottom plugs to ensure done in correct order. 14.5 Fill surface cement lines with water and pressure test. 14.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug (flexible bypass plug)—HEC rep to witness. Mix and pump cement per below calculations for the Pt stage, confirm actual cement volumes with cementer after TD is reached. 14.8 Cement volume based on annular volume+ 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Mt' s+.r L- Estimated Total Cement Volume: Section: Calculation: Vol(BBLS) Vol(ft3) 12-1/4" OH x 9-5/8" Casing (4300'- 1900') x .0558 bpf x 1.3 = 174 bbls 977.5ft3 annulus: Total LEAD: 174 bbls 977.5 ft3 12-1/4" OH x 9-5/8" Casing (4800'- 4300') x .0558 bpf x 1.3 = 37 bbls 207.8 ft3 annulus: 12-1/4" Rat Hole (4810' - 4800' ) x .145 bpfx 1.3 = 1.9 bbls 10.67 ft3 9-5/8" Shoe track: 90' x .0758 bpf = 6.8 bbls 38.2 ft3 Total TAIL: 45.7 bbls 256.67 ft3 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company Cement Slurry Design (both 1St and 2nd stage cement jobs): Lead Slurry Tail Slurry System ArcticCEM TM System SwiftCEM TM System Density 10.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed 21.13 gal/sk 5.04 gal/sk Water 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, f the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. HEC Rep to witness. 14.11 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically,the plug must be bumped. CS 14.12 Displacement calculation: ✓ rga5 (4800'-90') x .0758 bpf=357 bbls total (173 bbl mud+ 80 bbl water+ 104 bbl mud) The 80 bbls of water must be left across stage tool to ensure proper operation once opened. 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Be prepared to pump out fluid from cellar. Have retarder available to contaminate the cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, 3.4 bbls before consulting with Drilling Engineer. 14.15 If plug is not bumped consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold,pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. Page 22 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 14.17 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface. Circulate until YP <20 again in preparation for the 2"a stage of the cement job. 14.18 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components hard lines and BOP stack that may have come in contact with the cement. Page 23 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company Second Stage Surface Cement Job: 14.19 Prepare for the 2nd stage as necessary. Circulate until 1 stage reaches sufficient compressive strength. Hold pre job safety meeting. 14.20 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 14.21 Fill surface lines with water and pressure test. 14.22 Pump remaining 60 bbls 10.5 ppg tuned spacer. 14.23 Mix and pump cement per below recipe for the 2nd stage. 14.24 Cement volume based on annular volume+200% open hole excess. Job will consist of lead& tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. p Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 16" Conductor x 9-5/8- (140') x .1289 bpf x 1 = 18 bbls 101.3 ft3 casing annulus: 12-1/4" OH x 9-5/8" Casing (1400'- 140') x .0558 bpf x 3 = 210.9 bbls 1184.3 ft3 annulus: Total LEAD: 228.9 bbls 1285.6 ft3 12-1/4" OH x 9-5/8" Casing (1900'- 1400') x .0558 bpf x 3 = 83.7 bbls 470 ft3 annulus: Total TAIL: 83.7 bbls 470 ft3 14.25 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 14.26 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 14.27 Displacement calculation: 1900' x .0758 bpf= 144 bbls mud o I- Page 24 Version 1 April 2017 • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 14.28 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have some sacks of sugar available to retard setting of cement. 14.29 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 14.30 Land closing plug on stage collar and pressure up to 1000— 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Set slips and back out and L/D landing joint. Flush out wellhead with FW and BOP stack thoroughly to ensure cement, mud and cuttings are removed. 14.31 M/U pack-off running tool and pack-off to bottom of the landing joint. Set casing slips pack off Run in lock downs and inject plastic packing element. Pressure test to 2450 psi. 14.32 Lay down landing joint and pack-off running tool. Ensure to report the following on WellEz: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm,note any shutdown during mixing operations with a duration a. Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure and if floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job.Final circulating pressure e. Note if pre flush or cement returns at surface&volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to jengel@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 15.0 BOP N/U and Test 15.1 N/D the diverter T, 16"knife gate, 16" diverter line &N/U 11"x 13-5/8" 5M casing spool. 15.2 N/U 13-5/8"x 5M CTI BOP as follows: • BOP configuration from top down: 13-5/8"x 5M annular/ 13-5/8"x 5M double gate / 13- 5/8"x 5M mud cross/ 13-5/8"x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram should be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (manual valve closest to f)C)1?)( mud cross). e" 9 • Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to mud cross) 15.3 Run 5" BOP test assembly, land out test plug (if not installed previously). • Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Confirm test pressures with PTD • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. • We will need to test on the following sizes: 5" (for 5"DP) 15.4 R/D BOP test assembly. 15.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 15.6 Mix 10.0 ppg Baradrill-N fluid for production hole. 15.7 Set 10"ID wear bushing in wellhead. 15.8 Keep 5" liners in mud pumps. Page 26 Version 1 April2017 S 0 II Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 16.0 Drill 8-1/2" Hole Section 16.1 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill pipe will be 5" 19.5# S-135. • Install ported float in the BHA. / 16.2 8-1/2" Mud Motor Directional Assembly (Includes triple combo LWD, PWD): COMPONENT DATA Item Description Serial Number OD ID Gauge Weight Top Length Cumulative it (in) (in) (In) Connection (ft) Length (1t) Ell PDC 6.360 2.750 8.500 88.03 P 4-112"IF 0.91 0.91 lel T SperryDrill Lobe 7/8-6.0 stg MEM 7.000 gin mg gm umai mai gem - Stabilizer -__ 8.250 _--- ® 6 3/4"Integral Blade 6.750 2.813 8.313 100.78 B 4-1/2"IF 6.95 35.19 Ell 6 314"DM Collar 6.750 3.125 103.40 B 4-112"IF 9.21 44.40 En 6 3.44"DGR Collar 6.750 1.920 97.80 B 4-112"IF 6.75 51.15 I 6 3/4"EWR-P4 Collar • 6.750 2.000 . 104.30 ECM 12.11 63.26 © 6 314"PWD Collar . 6.750 1.905 96.30 B 4-1/2"IF 4.44 67.70 ICI 6 3;4"HCIM Collar ® 6.750 1.920 gm 101.70 B 4-1/2"IF MEM MEM Q 6 314"ALD Collar . 6.750 1.920 8.250 104.30 B 4-112"IF 16.27 90.80 11111 Stabikzer 8.250 NMI 10 6 314"CTN Collar 6.750 1.905 Mil 02.30 CEO MEE 102.63 ® 6 3/4"TM Collar 6.750 2.810 100.82 B 4-112"IF 10.01 112.64 Li 6 314"Non Mag Flex Collar 111111.1.11 6.700 Emi NE cm 30.98 m 6 3/4"Non Mag Flex Collar 6.880 2.813 105.52 B 4-112"IF 30.97 174.59 MI 6 its x 5"X 3'HWDP 5.000 3.0001111111133111111111111 184.0011E3311 ® Jar 6.250 2.250 91.01 B 4-112"IF 31.79 390.38 CZ 23 jts x 5"X 3'HWDP MEN5.000 3.000 1111111 ® 402.00 MON Total: 792.38 Page 27 Version 1 April 2017 0 • 1 1 Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 16.3 Primary Bit: 8-1/2" PDC 8 1/2- (215.9mm tO' Assemtsty: AOSI4a VM61 3P' Navigator - 11A0C Code Pa433 Shiri--12C.S ,ve i ir PRODUCT SPECIFICATIONS k , . Ve 4 Cutter Size_ 13 mm < Cutter Back Up 13mm POC & Replaceable Shock Studs 4 .. .... JIP Total Cutter Count: 76 - . rrrwrisio. Face Cutter Count: 58 Eli isio ..1., 0 r-- Connection 4 112" API Regular Nozzle 1 City/Type 6 -Series 55 ..i. 40, Nozzle 2 Oty/Type: - - ..., _ Junk Slot Area 14.3in1(92.3cm1 Allit Gage Pad Length: Make Up Length 11.4288,8mm) Shank Diameter OPERATING PARAMETERS* Rotary Speed. 2 1/2" (64mm) - ( 5.13"(147.3mm) For all rotary and motor applications Flowrate Mm Max 250 -750GPM (0.95-2.84m /min) Max Weight On Bit- 420001bs (18683daN) 10 .0 ei Makeup Torque. 12000 - 16000Ft-Lbs.(16270 - 21693NrnI 0.. 4'""4... 4 L 4 li,/ 4414#li ..i. ,.- Navigator Series Bits -Varei's six step design r manufacturing process utilizes GeoSoienceinlerpreted lOgs proprietary design software SPOT 3D modeling programs.CPC).,and special zed manufacturing techniques to produce the best possible bit for tne app i cation..Navigator bits are engineered to a specific Directional prolue for a given application Navigator bits possess the key design elements affecting bit steerabaity and directional behavior helping you achieve your drilling objectives. Bit Features P - Partial PowerCutters rw provide extra cutter density on the shoulder reducing excessive wear or cutting structure damage when drilling interbedded formations Shock Studs - Snock studs limit cind bit Oration and increase stability allowing smooth cutting action increasing ": cuttei life m .d overall hit performance Liocirill Cutters - PDC cutlers strategically placed to help reduce hole problems when up drilling or back reaming Premium Gage - The premium gage consists of thermally stable polycrystalline diamond and plc(polycrystalline diamond compact}cutters:designed to insure that correct hole diameter is maintained. ,,,... . IllOr VAREL www.varettnti.com , *,. Page 28 Version 1 April 2017 • • 14 Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 16.4 8-1/2"hole section mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system(1) ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Run the centrifuge continuously while drilling the production hole, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. • Canrig PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 9.5 — 11.6 ppg KC1 Inhibited WBM Properties: Depths (Density Plastic Viscosity Yield Point LGS MBT HPHT pH 4800'-10,087' 9.5— . 15-25 15-20 <6% <20 <11.0 9-10 11.6 ppg System Formulation: Baradrill-N Product Concentration Water 0.94 bbl KCL 22 ppb Barazan D Plus 1.25 ppb(as req'd for YP) PAC L 1.0 ppb Dextrid LT 3.0 ppb Barotrol Plus 5.0 ppb BDF-515 4.0 ppb Caustic Soda 0.2 ppb Baroid 41 As req'd for MW Aldacide G 0.25 ppb 16.5 Single in the hole w/ 8-1/2" directional assembly on 5"DP from pipe shed to stage tool. Shallow test MWD Page 29 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 16.6 Note depth TOC tagged on AM report. Drill out stage tool as follows: • Do not exceed 75 rev/min rotation speed. A good range is 40 to 75 rpm. • Drilling with minimal WOB is recommended, 2-5 K# is enough. • Apply weight and allow it to drill off before applying more. • After drilling out, chase any remaining debris to bottom with the drill bit. 3 'r9(0-s. c 16.7 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 16.8 R/U and test casing to 2900 psi/30 min. Ensure to record volume/pressure and plot on FIT graph. AOGCC reg is 50% of burst= 5750/2 =2875 psi. Test pressure for the well is 2900 psi. 16.9 Drill out shoe track and 20' of new formation. 16.10 CBU and condition mud for FIT. OWFF and pull into casing shoe 16.11 Conduct FIT to 12.5 ppg EMW. If 12.5 ppg EMW is not obtained call and discuss with Drilling Engineer. 16.12 Drill 8-1/2"hole section to section TD per Geologist and Drilling Engineer. / • Pump at 500 gpm. • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Pump high vis sweeps to aid in hole cleaning. • Closely monitor PWD information while drilling to minimize ECD, especially important • when drilling the Miluveach and Kingak Formations. • Keep swab and surge pressures low when tripping, especially important when tripping through the Miluveach and Kingak Formations. • Slow and smooth pulling in and out of slips on each connection. • Slowing ramp pumps on/off on each connection • Monitor hole cleaning indicators, PUW, Pump pressure and ECD, Make wiper trips as necessary. • Perform wiper trip 200' before penetrating HRZ • Take MWD surveys every stand+/- 60'. Surveys can be taken more frequently if deemed • necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. 16.13 At TD; pump low vis sweeps, CBU at full rate and RPM at least 3 times at maximum circulation and rotation, Alternate reciprocation depths while CBU to reduce risk of toughing 16.14 Weight up at TD for shale stability while TOOH 16.15 If back reaming is necessary: • Circulate at full drill rate (500 gpm). Page 30 Version 1 April 2017 S Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std(slip to slip time, not including connections). • If back reaming operations are commenced, continue back reaming to the shoe and circ at least a b/u once at the shoe. Back reaming is a last resort to clean up the hole in the Miluveach and Kingak Formations. 16.16 TOH with the drilling assembly, L/D BHA. • While TOOH, watch swab pressures and keep string speeds below 500 fph until above shales 16.17 Rotary sidewall cores (RSWC) are planned in the Sag River Formation if hole conditions will allow. 16.18 A cleanout trip to TD may occur after the RSWC are obtained,pending hole conditions. 16.19 POOH with Cleanout BHA. L/D BHA. 16.20 Change top rams to 7" for upcoming casing job. Test 250/4000 psi. 17.0 Run 7" Production Casing 4 fi 17.1 R/U 7" casing running equipment. ZA- t • Ensure 7"DWC/C x NC-50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been strapped& drifted in the pipe shed prior to running. • Be sure to count the total # of joints in the pipe shed before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. • R/U CRT. • Make dummy run with 7"hanger and landing joint. 17.2 M/U &threadlock shoe track assembly consisting of: • (1)Float shoe joint w/float shoe bucked on. Install (2) solid body centralizers 10' from each end. • (1) Baker locked joint. Install (1) solid body centralizer mid joint. • (1) Float collar joint w/float collar bucked on pin end. Install (1) solid body centralizer mid joint. • Ensure proper operation of float shoe and float collar. 17.3 Run 7"26#L-80 DWC/C casing. • Fill casing while running using CRT or fill up line. • Use BestoLife 2000 thread compound. Dope pin end only w/paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 31 Version 1 April 2017 • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company • Install solid body centralizers on each joint from shoe track to 9000' MD and 7800' to 7400' MD (across the Kuparuk). No centralizers required above that. 17.4 Watch displacement carefully and avoid surging the hole. Slow down running speed as necessary, especially through the Miluveach and Kingak Formations. 17.5 Slow in and out of slips. 17.6 Stage up pumps slowly to minimize potential packoffs. Work pipe while staging up pumps and circulating. Circ clean before rigging down CRT and M/U casing hanger to landing joint. 17.7 P/U casing hanger joint and M/U to string. Position the shoe as close+/- 10' from TD. Strap the landing joint while it is in the pipe shed and mark the joint at(1) ft intervals to use as a reference when landing the hanger. 17.8 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 17.9 Have emergency slips ready to go in the event we cannot land the hanger. 17.10 R/U circulating equipment and circulate B/U. Reduce YP to <20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 17.11 After circulating, lower string and land hanger in wellhead again. 7" DWC/C M/U Torque Min Casing MU Torque Max Casing MU Torque 18,300ft-lbs 21,100 ft-lbs Page 32 Version 1 April 2017 • i Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company Connection Type: Size(O D.): Weight(Wall): Grade: DWC/C Casing 7 in 26.00 lb/ft(0.362 in) L-80 2012 API SPEC 5CT COUPLING O.D. Material L-80 Mn 80.000 Minimum Yield Strength(psi.) 95,000 Minimum Ultimate Strength(psi.) �lJ>19A Pipe Dimensions VAM USA 7.000 Nominal Pipe Body O.D. (in.) 4424 w.Sam Houston Pkwy.Suits 150 6.276 Nominal Pipe Body I.D. (in.) Houston.TX.77041 0.362 Nominal Wall Thickness(in.) FF.5 71one 3479 32342oo 26.00 Nominal Weight(lbs./ft.) E-mail:VAMw USAsaleaam-usa.cum 25.69 Plain End Weight(lbs./ft.) 7.549 Nominal Pipe Body Area(sq.in.) 3v; Pipe Body Performance Properties ' 604,000 Minimum Pipe Body Yield Strength(lbs.) $tai`s 5.410 Minimum Collapse Pressure(psi.) ,`. 7,240 Minimum internal Yield Pressure(psi.) 6,600 Hydrostatic Test Pressure(psi.) Connection Dimensions 7.875 Connection O.D. (In.) 6.276 Connection 1.0. (In.) 6.151 Connection Drift Diameter(in.) 4.50 Make-up Loss(in.) 7.549 Critical Area(sq. in.) 100.0 Joint Efficiency(%) Connection Performance Properties 604,000 Joint Strength(lbs.) 16,590 Reference String Length(ft) 1,4 Design Factor 641,000 API Joint Strength (lbs.) 302,000 Compression Rating(lbs.) 5,410 API Collapse Pressure Rating(psi.) 7.240 API Internal Pressure Resistance(psi.) 26.2 Maximum Uniaxial Bend Rating[degrees/100 ft] Approximated Field End Torque Values !+ 18.300 Minimum Final Torque(ft.-lbs.) 21.100 Maximum Final Torque(ft.-lbs.) 23.800 Connection Yield Torque(ft.-lbs.) For detailed Information on performance properties.refer to DINC Connection Data Notes on following page(s). 18.0 Cement 7" Production Casing 18.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. • How to handle cement returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cement operation. • Document efficiency of all possible displacement pumps prior to cement job. 18.2 R/U cementing head (if not already done so). Witness loading of top and bottom plugs to ensure they are loaded correctly. Page 33 Version 1 April 2017 • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 18.3 Fill lines with water. Close low torque on plug dropping head,test surface cementing lines to 4000 psi. 18.4 Pump remaining 40 bbls 13.5 ppg spacer. 18.5 Drop bottom plug, Mix and pump slurry per below calculations: Assume 25% excess cement until hole volume is established at TD. Section: Calculation: Vol (BBLS) Vol (ft3) Cement: (10'010' —7000')x .0226 bpf x 1.25 = 85 bbls 477.3 ft3 8-1/2" OH x 7" csg: Cement: 7" Shoe Track: 90' x .0382 bpf= 3.4 bbls 19.3 ft3 Total Tail: 88.4 bbls 496.6 ft3 7ccV System Conventional Density 15.8 lb/gal Yield 1.523 ft3/sk Mixed Fluid 6.17 gal/sk Expected Thickening 5:00 HR:MIN Expected ISO/API 13 mL in 30 min Fluid Loss Additives Code Description Concentration G Cement 94 lb/sk WBWOB D110 Retarder 0.05 gal/sk VBWOC D046 Anti Foam 0.2%BWOB D202 Dispersant 1.5%BWOB D400 Gas Control Agent 0.8%BWOB D154 Extender 8.0%BWOB D174 Expanding Agent 1.5%BWOB Page 34 Version 1 April 2017 1 1 • II Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 18.7 After pumping cement, drop top plug and displace cement with completion fluid. If it is not feasible to do this, use mud and a clean out trip will be made later. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calculations: • 10,010' x .0382 bpf= 382.4bbls. 'l 18.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 18.9 Do not over displace by more than 1/2 shoe track volume. Total volume in shoe track is 3.5 bbls 18.10 There should be no cement returns to surface. TOC is planned to be at 7000' MD (500' above Kuparuk). 18.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. • If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. Ensure to report the following on WellEz: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing, bpm,note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure and if floats hold • Percent mud returns during job, if intermittent note timing during pumping of job.Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally& casing and cement report to jengel@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC 18.12 R/D cementing equipment. 18.13 Back out and L/D landing joint, flush out wellhead and BOP stack thoroughly with FW. Page 35 Version 1 April 2017 • i Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 18.14 M/U pack-off running tool and pack-off to bottom of landing joint. Set casing hanger pack-off. Run in lock downs and inject plastic packing element. Test void to 250/5000 psi for 10 min. 18.15 Lay down landing joint and pack-off running tool. cep e6 �- 19.0 Run 4-1/2" Tubing String 19.1 PU 6"cleanout BHA and RIH on 4"workstring to PBTD. I'r .1 .to the wellbore clean with kill weight brine at maximum rate. Rotate and reciprocate work : ing as needed. Reverse circulate if needed get clean returns from wellbore. POOH a LD • orkstring. 19.2 Close blind rams. Pressure test 7" casin• to 351► es' or 30 charted minute_ 19.3 Spot e-line unit and rig up. RU e-line line wipe the well will be hydraulically isolated from the reservoir with pressure tested casing). 19.4 Run cement bond log from PBTD to det- ine TOC near 7000' MD. CBL will be across the Sag River and Kuparuk formations. 19.5 RD e-line. 0,e,4(1 P (- 19.6 U and run 4-1/2" L-80 tubi .4as ler Corn.letion En.R/ • Ensure appropriate well 'ontrol crossovers on rig floor and ready. • Monitor displacement om wellbore while RIH. 19.7 Land tubing hanger. 'I LDS. LD landing joint. Note PU/SO weights on tubing tally. Test hanger to 500 psi lo /5000 psi high. 19.8 Circulate freeze %rotect down IA and allow freeze protect to U-tube down tubing. 19.9 Bullhead die -1 (or dead crude) freeze protection down 9-5/8"x 7" annulus with 60 bbls (2100') Leave well ut in, do not allow flowback to occur. 19.10 Install : 'V and N/D BOP. 19.11 N/U ree adapter and tree. Conduct pressure tests of same to 500 psi low/ 5000 psi high. 19.12 S r ut in well. Page 36 Version 1 April 2017 I Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 20.0 Contingency 4-1/2" Liner / 6-1/8" Hole: 20.1 Excessive MW may be required to stabilize the wellbore after opening up the Miluveach and Kingak shales, as they can are very reactive,prone to swelling and being unstable when drilled at higher hole angles, >40 deg. Minimize ECD's, reaming, swab and surge pressures through these formations to improve hole stability. 20.2 If significant overpulls are noted through theses sections and do not improve consult with Drilling Engineer and determine feasibility of drilling ahead with planned well design. 20.3 If it is not feasible to drill ahead, set the 7"casing through the Miluveach and Kingak shales. 20.4 Adjust cement program so that TOC remains at 7000' MD, with 7" shoe at+/- 9550' MD. 20.5 After bumping the plug, pressure up to 3500 psi and test casing for 30 min. Record volume pumped and volume bled back, note in WellEz report. 20.6 R/D cement equipment, install and test pack off, bullhead freeze protect down annulus. 20.7 Install 2-7/8"x 5"VBR rams in both upper and lower BOP cavities. TEST BOP to 250/4000 psi/5 min. Annular to 250/2500 psi/5 min. 20.8 P/U 4"DP & 6-1/8" directional drilling BHA, drill out float equipment and 20' new formation. CBU and conduct FIT to 13.5 ppg EMW. 20.9 Drill 6-1/8"hole to well TD, 10,087' MD. 20.10 Run and cement 4-1/2"production liner. Cement coverage will be from liner shoe to TOL. 20.11 Well completion will remain the same. A proposed well schematic is shown on the next page. Page 37 Version 1 April 2017 • 0 11 Milne Point Unit C-46 Drilling Procedure 1 Hilcorp Energy Company 22.0 Innovation Rig Diverter Configuration 0 0 f II l 11 fil lfli-1111 [ll 1 I i 1 ---------13.518"5M Control Technology Annular BOP -L......::— I OD io 114 i EO____— o »,. i ----'------13-518"5M Control O� 10 Technology Double Ram ilEa2l Fi -_93 VT 31;8"Kill Line --- ^ �4 — - /'`�? VV ' -3.118"Choke Line 1---C--; © —+J lO O "-- 13-518"5M Control—" It Technology Single Ram ----` 4� olto 13-518"x 5M € € 1 ` �'' � €] 16"Diverter Line d5fcV 0,. , ,''''','---- 13-5Z"x 5M -I- I I \--2-1,16"x 5M 20"Casing Page 39 Version 1 April 2017 a • 11 Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 23.0 Innovation Rig BOP Schematic LI o L I rn-rr m ------------13-5/8"5M Control Technology Annular BOP 1-1 imi E p .yl i 1: I_ - Z ii$ 1M°; £1 ------"-------13-5/8" '---"-- -13-5/8" 5M Control a` Technology Double Ram .T. .. =1 — IA - 1T�i. i 3-1/8'"Kill Line rr r� ,,��IIy��I •I1`7. ' ------------3-1/8"Choke Line Ali «:: MI_; 13-5/8" 5M Control Technology Single Ram --^ 13-5/8"x 5M 11"x5M . % _, [t..::i ( .''1 p , `r,. v .0—ii .10Ilh -I ['i _ ul[kp :. i1 9-5/8" DBL D Seal `I 21/16"x5M ` --- ��;[( j__•_13..5/8%r "x 5M Casing Haner it .1 13-5/8" SNOM � ` v` 9-5/8" BTC Btm x 2-1/16"x 5M 10.5"-4 SA Pin Top W/Primary Seal 20"Casing 9-5/8"Casing Page 40 Version 1 April 2017 • • II Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 24.0 Wellhead Schematic HILCORP ALASKA, LLC MPC-46 MQ-390 0 I. I CD n 41.3 3-1/8 5M— EST 0043-1/8 5M • ® / 90.6 ` EST : *i0 0, 3-1/8 5M HYDRAULIC ACTUATED . al O .N 43.3 EST 3-1/8 5M ® ADAPTER, TUBING HEAD IN f0v6 154.1 SM-E-2ClN EST 11 5M X 3-1/8 5M (SPECIAL) 67 C� WITH TWO (2) 3/8 CL 11-1.W. 3_1/8 5M 6.1 iiii EST 15M '2CL i o ' 11 X 3-1/2 EU 8RD BOX TOP 17.2 J X 3-1/2 OD API MOD BOX BTM moi " lJ EST WITH TWO (2) 3/8 LP PORTS fammors `Ii 1 - - ' - ij 11 SM kit"1111 'e ? _ CASING HANGER, SMB X22 1�1 L1..1I 2--1/16 5M 26.O# L-80 DWC/C BOX BTM I�I ,' . T - - op 25.8 X 8.500-4 - 63.5 EST STUB ACME-2G-LH PIN TOP Me MalI•MI !Om #_ EST W/SEAL ASSEMBLY i 'lli...471 - I 9-5/8 DBL IPS �MWS k 2-..1/16 5M 1 --- 13-5/8 SM !-1�� ���� 11 -1/16 5M CASING HANGER, S-22____......-4-11' r!' El 20.5 13-5/8 X 9-5/8 EST i MIN C.__SI--'-'' IDT0 t 0 e‘693ef 13-3/8 CASING - I 9-5/8 CASING L- MEM CASING J 4-1/2 TUBING 5,000 PSI WELLHEAD ASSEMBLY NOTE: 13-3/8 X 9-5/8 X 7 X 4-1/7 DIMENSIONS SHOWN ON THIS DRAWING ARE RESTRICTED CONFIDENTIAL DOCUMENT ESTIMATES ONLY AND CAN VARY SIGNIFICANTLY ?WS COL.ENC ANC Ali INFCISIA TIC.%et*NCI..AI.ME C"'" JS "� 1-10 I'"'11/3/16 REV DEPENDING ON RAW MATERIAL LENGTHS. own.rc.a NOGUARANTEE OF STACKUPIOULOC HEIGHT IS IMPLIED. �� P-21 576 A DIMENSIONS SHOWN SHOULD BE CONSIDERED FOR REFERENCE PURPOSES ONLY. ca,ss,.+n g « .eaw ar " P"Of`" .w.w, ..c "' •n. Page 41 Version 1 April 2017 t/ 1110 Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 25.0 Days Vs Depth Days Vs Depth ° I .mmaC-D46 2030 4000 6000 • • w 2 s000 10000 12000 — 14000 --- 0 5 10 15 20 25 30 35 Days Page 42 Version 1 April 2017 • S 11 Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 26.0 C Pad Formation Description C Heavy clay interval 4300 to 4800 ft,especially 4700 to 4800 ft(C-01). TO FACILITATE PRODUCTION WIRE LINE 5 5,000' L OPERATIONS.PLAN TO LIMIT HOLE INCLINATION A TO 70 DEGREES AND DOG LEGS TO Seabee y IS VERY IMPORTANT.OLE SMOOTHNESS Sea bee (Colville) Interval: Predominantly interbedded siltstone and clay with beds of sand,shale and occasional seams of coal. The Seabee is generally uneventful until reaching the HRZ TIGHT/PACKING OFF INl- ...._-...._ ,ASING: • Expect good penetration rates. C-43: 7-518"CASING STOPPED AT 9413(4755 TVD), UNABLE TO RUN DEEPER,HAD TO PULL. POOR HOLE CLEANING,INSUFFICIENT 6,000' CIRCULATING, MADE HOLE OPENER RUN AND 6 RERAN CASING. H RZ: highly Radioactive Zone. Very dark. fissile type shale,organic,good source rock. G-28A crossed a fault at 8895(681 5 Fed)and experienced minor seepage • I �,.W1Tl V Tuff(bentoritic)zone possible at top of HRZ • {15-20 bphl which eras cored with LCM treatment Top V plus 10'JaTuffs["V'IFau £d�:i(r.]7) u 6490' KalubikShale: [rood lag marker MKlDat RESERVOIR OVER-PRESSURE RESULTING IC-01) V +i-0704. Silts vrithin lower aiubikand Ki9ruk"n- IN WELL FLOWS AFTER PENETRATING 6570' BaseHR2 V o rpressuredduetatrigh nyection v''' KALUBIK, KUPARUK "D" 8.KUPARUK: ' (C-61) pressures into the Kuparuk sands causing the over- Ka I u b i k V pressure problems noted below to lower right). WELL PROBLEM MD listed} FOFteet. IMOD WECHT COMMFJIT 6760' I KALUBIK SILTS.SEE OVER-PRESSURE SUMMARY, C-20 GCM 7586168911 KALUBIK 16'A/162 IC-Cl) Kuparuk Interval: C20 FLOWING 7696;69831 RUN"C" MA 12A FAULT RELATED •--•C-22 OIL&GCM 9656;70491 KUPARUK 72.81132 "D"Shale The"D"Shale is the top Kuperuft sediment and is C-22A GCM 9995;72291 KUPARUK 1G8111A LOW VIS SWEEP 6900' known as the"Cap Rock". KUPARUK OVER- ;, C-28 FLOW,GCM 8897(6783) KUP"D" 911110.9 Tap sat Keg and drill {C-011 C PRESSURE MAY OCCUR IN THE DSHALEKuparvkwl 13.6 ppg. 6910' '111C-25 FLOW/CCM 11868{74301 KUPARUK 105111.1 (C-Oi 1 LCU C SAND: Sandstone,shales upward. C-39 GCN 7215;6se71 INP"D- 102/16.8 OIL BEARING TARGET FOR EASTERN C-PAD. C-39 EL FLOW 792217491} KUPARUK 10.51112 7,000' B LCU: Lower Cretaceous Unconformity C-39 ANN FLOW 792217491} KUPARUK BULLHEAD 91:5 + C-12A FLOW 8933(6943) KALUBIK ale X11.8 K,lrs sruk B SHALE OR LAMINATED ZONE: c-12A SL FLOW 693116893) KALUBIK 11A/12.7 r� Laminated Zone begins beton'LCU. .4" C-12A FLOW 131i FLOWED WHILE 7060' - Fine to medium grain sands becoming RUItN'G 2-309 LINER IC-01) TED A3 more shaley with depth. Hydrocarbon C40 FLOW FLOW 10449168211 KUP"f7" DA/161 03 7AULNLT RLEL9� bearing. a+i-70'thick. The B shale is very FL CM-e" unstable for CTU build enclitic'horizontal • C42 FLOW 8985;7496 TV( 'II 9.019.7 FLC hole drilling(C-26L1). RA' 7090' A3: Fine grain sandstone coarsening .1,,,,,, (C-011 upward,relatively I cw permeability. SERIOUS POTENTIA;_ili e , r:L,u0,i,,kr,4, L_ 17-23%porosity.14 to 100 and RUNNING,CIRCULATING AND CEMENTING PRODUCTION A2 7130' permeability. Hydrocarbon bearing. CASING(ESPECIALLY IF SURFACE CASING IS SHALLOW (c-6t) SET). ALSO BE PREPARED FOR POSSIBLE "BREATHING" A2 &Al: Similar to A3 FOLLOWING THE CEMENTING JOB. C-01,-02,-05,-06,-07, 7155' Al but finer grained and shaley. -08,-14,-17,-19,-22,-26,-23,-28,-39,-36.-12A. ,c-ol) Miluveach Miluveach shales: Predominantly Shale silty shale. Extend 30D-400ftbelow KU PARUK FORMATION Kuparuk Al.{Casing Seat for Kuparuk - ""°-..- PRESSURE MAP 2006 completion). Serious potential for lost , , Kingak returns while running,circulating Of Shale cementing casing. 6195' TJO Kingak: Marine shalewltt tin interbeds of 2+.,. 8445' TJC siltstone. The Kingak is known to become 662k TJBunstable the longer it is left open to drilling , -- 8870' TJA fluids. In hole angles above 45 degrees, _ additional mud weight is required for hole '1. Sag River stabilization. In addition,hole stablytion _ mud products are recommended for wells0. SandSand exposing the Kingak. See Recommended Practices. '_ ll# 6917" . ...,. SAG RIVER SAND Maraisawrdatwre.giaauoonitic, l ariaars,quartzosa Potential hydrocarbon bearing. - € C-23 targeted the Sag River Sand. e " 4u# Shublik SHUBUK: Carbonates.(limestone.dolomiteand ay siderite),phosphates,shales,siltstones and occasional . .t7 {t I sandstone. _.v Tie atone depths are based on C-01 1-bragltt Inc el ark9 C-21 and - ..."' C-22 prognosis.. Generally,formatlons dip dc'.v^to the north. Major faults run lgi.SE and secondary faults run N30EE'S3OW. ill Secondary faults may be major depending on where you are at. -" Faults are not telt to be the cause of lost circulation en the C-Pad area. C-23(19961drilled to the Sag R.sand. Page 43 Version 1 April 2017 O s Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 27.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. We do not want to drill through the hydrates with anything less than a 9.5 ppg ✓ MW however. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section efficiently—control ROP and avoid loading the hole with gas. Minimize gas belching by reducing flow rate if necessary. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Utilize cold water when building any mud volume. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0—2.0 ppb DRILTREAT to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore,pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs (>100 RPM's required for effective hole cleaning)when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of adjacent wells in the vicinity. Take directional surveys every 90'•60'. Additional surveys can be taken as required. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with Production Foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the surge and swab pressures generated by the BHA. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase viscosity and/or MW to combat running sands and gravel formations. Page 44 Version 1 April 2017 • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company H2S: Treat every hole section as though it has the potential for H2S. Review offset wells for documented encouters of H2S. No H2S events have been documented when drilling wells on"C"Pad 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected,the well will be secured,rig operations suspended and personnel evacuated until a detailed mitigation procedure can be developed. Mitigation efforts can include - additives to the mud system, use of personal H2S monitors for rig crews and service personnel and training/deploying SCBA's throughout the rig. Page 45 Version 1 April 2017 ! • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 8-1/2" & Contingency 6-1/8" Hole Sections: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as required to maintain proper fluid properties. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs (>100 RPM's required for most effective hole cleaning) when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 500 gpm. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate or other LCM. Faulting: There is at least(1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When crossing faults monitor the hole closely for lost circulation(diminished returns) and wellbore stability issues (high or spikey torques, higher pick up weights). H2S: Treat every hole section as though it has the potential for H2S. Review offset wells for documented encounters of H2S. No H2S events have been documented when drilling wells on"C" Pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, the well will be secured, rig operations suspended and personnel evacuated until a detailed mitigation procedure can be developed. Mitigation efforts can include additives to the mud system,use of personal H2S monitors for rig crews and service personnel and training/deploying SCBA's throughout the rig. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures expected while drilling this well. ✓ Page 46 Version 1 April 2017 • • ti Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 28.0 Innovation Rig Layout — — — -- —..— 170'-3 „ I 1 yr I4 , 91—+F al—='14 1..•2m- • la II I II_ ' -� II ��^i !I i'i1I ' 11111111111111 {I =re- ' n el '' - -- -- I 'I:.27- I ��^yy r II : I �iI SII ��I I I 1 © I II «-i I O (� I:I'' I }(��y i i �. i 11 SII .y��-.Jy c0 II1.-+i�■yW7y n b it 1 14 i L__-_--- - - EI t� I � i!I iil _ IIlL' I 56' 4" _I HAK 2 FOOT 11111Filli r ino,„„,..-!, •_,.. PRINT 05/21/16 - — — — . .,,.: .sq�, l IP lu ' hili_. s.;.. 1 ' PM] • R ! 11 ma 113'-112" —i— 36'-1 i" Page 47 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 29.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure.Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 48 Version 1 April 2017 s • II Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 30.0 Innovation Choke Manifold Schematic 7 a n �, d 1Jb I-1 -1 l— b q A ^ = J S _ _P d 11 -1 1' --0 _ ce a13-11 G—U pd II rI _ ' 4.iPP.I' J h_ ,-J a_ pp . a1 I te ti I\vv ver n n ^ �� 2-9/16"5L1 BB29E1 L ;j----(< a ..............L l 1771 1 IIv �_ as as a�a as I.1 In,,.1114', e Li Or; il �/4 � WOO 11110 Mt K111�1 ler vers Iww a=l �w erwl Page 49 Version 1 April 2017 • • II Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 31.0 Casing Design Information Calculation & Casing Design Factors Milne Point Unit DATE:2-08-2017 WELL: MPU C-46 DESIGN BY: Paul Mazzolini Design Criteria: Hole Size E,-1;2 Mud Density: 10.5 ppg Hole Size 116•' Mud Density: 10.5 ppg (Contingency:: Hole Size Mud Density: Drilling Mode MA SP(8-1 s2"): 3699 psi (see attached MASP determination & calculation: Production Mode MASP: 2E99 psi rsee attached MASP determination & calculation:: Collapse Calculation: Section Calculation r 1, 2, 3 Max MW gradient external stress and the casing e..acuated for the internal stress Casing Section a Calculation/Specification 1 • 2 3 I. a a e Casing OD 1 9-51.ri r 4-1!2* = 4 Top (MD) 0 0 a 9,300 ¢ + Top (TVD) 1 0 1 0 1 8,600 1 1 Bottom(MD) 1 4,800 1 10,090 1 10,090 4 0 Bottom (TVD) 4,543 i 9,043 9x043 Length4,800 10,090 790 i Weight (,ppf) 45.5 I 26 i 13.5 i g Grade L-80 i L-80 '_. L-80 a Connection i MCCi OW= IVAM HTTCj Weight who Bouyancy Factor (lbs) i 218,400 i 262,340 i 10,665 i i Tension at Tap of Section (lbs) € 218,400.x/i 262,340 f 10,665 i Min strength Tension (1000 lbs.) i 916 * 604 307 Worst Case Safety Factor(Tension) i 4.19 "�a 2.30 s'i 28.79 1 Collapse Pressure at bottom (Psi) i 2x044 . i 4,612 4,612 1 Collapse Resistance w/a tension (Psi) = 3,_090 • i 5,410 8',540 Worst Case Safety Factor(Collapse) i 1.51 i 1.17 i 1.85 ii MASP (psi) i 3x699 i 3,699 i 3699 i $ Minimum Yield (psi) i 5,750 i 7,240 i 9,020 1 a Worst case safety factor(Burst) i 1.55 ' I 1.96 1 2.44 i i Page 50 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 32.0 8-1/2" Hole Section MASP II Maximum Anticipated Surface Pressure Calculation 8-1/2" Hole Section xitF.°.. MPU C-46 Milne Point MD WD Planned Top: 4800 4543 Planned TC: 10,090 9043 Anticipated Formations and Pressures: Formation TVC Est Pressure Cil?GasiWet FFG Grad Tcp Kuparuk C Sha e 6,797 3355 - 9.5 D.494 Top Kuparuk C Sand 6,943 3430 C 9.5 0.494 Tcp Kuparuk 4.Sand 7,193 3553 Water 9.5 0.494 Tcp r•l uveach _ 7.197 3555 - 9.5 0.494 Top Jurass 7,605 3757 - 9.5 0.494 Top Sag River 5.593 '245 C 9.5 0.494 Tcp Shub l ik 5,650 . 4273 " - 9.5 • 0.494 Offset Well Mud Densities Well Flax Crig F:1:4d Tcp(TVD) Bottom (7.1C) Cate C-15A 10.7 8,886 8,972 2019. C-43 12.5 6,900 7,547 2004 C-28A _ 10.5 6,401 7,339 20%05 0-40 11 6,821 7,408 2001 C-12 10.5 6,450 7,578 1955 C-11 10.3 6,830 7,526 1955 Assumptions: 1. Fracture grad lent at shoe is estimated at 0.7 psi/ft based on field test data. 2. Maximum planned mud density for the 8-1/2" hole section is 10.5 ppg. 3. Calculations assume Kuparuk reservoir contains 100%gas (worst case). 4. Calculations assume worst case event is complete evacuation of vrei ibore tc gas. i Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: T _ s_3 (ft)xo7(ps ;`t:,= 315ps1 T— I 3180(psi) [0.1(psi/ftr4543(it)]= 272€ ps Dr-:-ng F.,lode 1%1ASF i ! ) X1.41 MASP from pore pressure (,.�,ellhore completely evacuated to pf 1^1 I l f 1 9043(ft)x 0.509(psi/ft)= 4603 psi • 4603 (psi)-[0.1(psi/ft)'9043(ft)]= 3699 psi . Summary: 1. MASP while drilling 5-1'2" production hole is governed by wellbore completely evacuated to gas from the Kuparuk interval. Page 51 Version 1 April 2017 • •• Milne Point Unit C-46 1 n Drilling Procedure Hilcorp Energy Company 33.0 Spider Plot (NAD 27) (Governmental Sections) I • • h\ ♦ \ \ „ \` \ '\. �`t.+ p' 1 r J J r +f \ \, p `\ alt%%;,:.. f '"- 4,, \ alb♦ J p 1• _, `, \ ',p`?4* , r' IMF ADL047434 • .` z 'Seep.`:7'1.11; f Q)) �` _ h —..rL _ _ .._ — .._ .. \` _ .rtr r 411 i. 1.--In •`1 ' ~- "1`-v ft w -- r `, p \h 'h 4 1 h I r .` >• r • h • \h ` MLN .Ps T11, 1 U013N010E \ , \ om \ •h h o° \ h h \ \ h o \ \ h o \ .• o \\\ ADL047437 • ADL025518 ..'a+.CO ' c \\i Set 14 ` _ R \ • Legend \ i 'tPU C-46_SHL • Other Surface Holes(SHL) >., MPU C-46_TPH • Other Bottom Holes(BHL) - Other Well Paths PWU C-46-BHL Q Oil and Gas Unit Boundary EIA I j Ped Fart 1. Irl Milne Point Unit -46 Well 0 500 1,aoo MPC __ .: Feel Page 52 Version 1 April 2017 • • II Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 34.0 Surface Plat (As Built) (NAD 27) . IT M1 + M 2440 1 �I A 's ,:\ II 7 ' THE rnomar - ("..-._:.. •. 19 1 C.J. * C-PAO D-PAC VQ el 4 3 I k ■ 43 I ts. I B-PAD 2 U • 17 ' _ A-PAD LI ■ 21 ti 23 `�� E-PAD 7 i • 11 • ... I 44 ! VICINITY MAP I 36 46 I NTS I' 10 1415 ■ 13 I I 28 39 ■ I ■20 I FGFND l 1 40 1 1 U 1 • 4 -4- AS-BUILT CONDUCTOR I41 47 U EXISTING c066)ucTOR 6 1f I ■ 15 I I 5 ■ 1 ■ 16 pIOTF '7J 1 8006�a- POMP1. SURVEY DATE MARCH 12. 2017 n I 2.REFERENCE FOLD BOCK: HC17-01 PGS. 14-21 16 a I • .2 I 3.ALAS A27At SII PLANE CCORpINA1E5 SAS ALASKA ZONE 4. NADrr��� O rt fl I_ O 1 4, GE00ETIC COORDINATES ARE NAD 27, ' + l I 4, PAD SCALE FACTOR IS 0,999903135 I 5.1./HORIZONTAL A CA-ND AND ARTICAL CONTROL IS BASED Cl Q6.ELEVATICNS ARE BASED ON BPx MILNE PT. DATUM (Y_S11 I ❑ I 11 IS i 1 4 1 -- N 800 GRAPHIC SCALE 0 125 250 500 1 momimm.. 1 MPU C?-PAD " ( It+ FEET) 1 Inch " 260 it LCCATED VATHIN PROTRACTED SEC. 10, T, 13 N., R. 10 L. UMIAT MERIDIAN, M. WELL A.S.P. PLANT GEODETIC GEODETIC TOP OF SECTION CELLER BOX NO. COORDINATES COORDINATES POSITION(DMS) POSITION(D.DD) GRAVEL PAD OFFSETS RIM ELEV. C-46 N:6029204.76 N:1757.87 N70-29'25.4623" N70.4904062' i5.b • 923' ' ESL 15.22 Er 558093.18 • E:600.35 W149'31'30,3608" W149,5251002' 2,369' FEL C-45 N:6029147.50 N:1697.85 N70'29'24.8978" N70.4902494' 14 8 866' FSL 14,78 E:558111.14 E:599.98 W149'31'29,6454" W149.5249571' 2.351• FEL C_47 N:6029004.74 N:1547.94 N70'29'23.4902" N70.4898584' ' 15 2 722' FS 15,15 E:558156.85 E:599.93 W149'31'28.5331- W149.5245925' I 2,307' FEL - SAPi9NCTOw - stp Hilcorp Alaska 64171 X17 4Pc 22-01 MPU C-PAD "ch .e.11a V J,n1/17.4[y11Eo 11 ro N-a..0 Sse I.,. x i WELLS C-44, C-45. C-46 w s+n4na�am IVR tlnnuaul Tl 1-.. 264' AS-BUILT WELL LOCATIONS 1 N 1 X0. CIVIL 110,,1011 IT 046 Page 53 Version 1 April 2017 • • Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 35.0 Offset MW vs TVD Chart 0 - – MPC-15A Plan 1000 immimhilPC-15.A Actual 2000 3000 1/1 4000 5000 6000 — 7000 - 8000 9000 10000 11000 12000 S 9 10 11 12 13 14 Mud Density(ppg) Page 54 Version 1 April 2017 • • II Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company 36.0 Drill Pipe Information 5" 19.5# S-135 DS-50 Drill Pipe Configuration Pipe Body OD I n,5.000 80^:.;Inspection Class Pipe Body Wall Thickness in..0.362 Nominal Weight Designation 19.50 Pipe Body Grade S-135 Drill Pipe Approximate length, .i 31.5 I Drill Pipe Length Range2 SmoothEdge Height 0,4 3132 Raised Connection GDDS50 Tool Joint Sh1YS •.ri,i 120.000 ' Tool Joint Ofl 6.625 Upset Type IEU Tool Joint ID 1 n.3.250 Max Upset OD (DTE) •.Irl 5.125 Pin Tong 9 Friction Factor X1.0 Box Tong 1 n 12 Nrt. Toro maze Tag Include nare"adrd Drill Pipe Performance Drill-Pipe Length Range2 Performance of Drill Pipe with Pipe Body at Best Estimates I Nominal iil 80%Inspection Class Wrl'IWICoetrryl (wen Cpabrq) I Mast accurate', ���^�' O erational Max Te sir- Drill Pipe Adjusted Weight navrt 24.11 2329 rcrclr t-ab-> Torque in-last rt:: =1uid Displacement ':oa:'nl 0.37 0.36 "ax+n+uT 'J-43,100 Tension Only ()Operational 560.800 =1uid Displacement eh nl 00088 0.0085 CcrnPred tpaany 39.600 410,500 =1uid Capacity twlmi 0.71 0.70 0.72 =1uid Capacity teetsrt)0.0169 0.0167 0.0172 ',r rni.rn mut 36,100 Tension Only 0 560.800 l ,irft Size un)3.125 combined tawny 32.100 467.400 J rlo:e Di tr_la aanel equals 42 us uailms. Nate-DNI ppe annerntly Yatacn are seen(entmanes and may vsy due to pipe beery moll tolerance,[Mental pia5.,'l,00ain0.arta oirer forlorn. Connection Performance GPDS50 ( 6.625 on) OD X 3.250(ri) ID ) 120,000 ire) ALD led rfah,ap Tendo-al-_ntulac- Trash.a".CarnrCaan Tool Joint Dimensions Ta-q::e e_......�_r Yed on. abs; pas) Balanced 00 in;6.435 9Maximum Make-up Torque 43,100 Tensile v pitted 1,046,900 Minim,.Tow.lona CO for Apt 5,930 M:rimumMake-up Torque 36,100 1.202,590 1.250.000 PrirILMICtazs Ir'I - c'! The Fa,-.191 IraVo- ,,,,e.> o.e shoei to ac:.lei.,re-,,:sne ',Amman Tool dont CO Vr 5.93 0 h '.Ir: I,c'< i:rcs.-..c._,ec.: ._ � ..:1-.., er .l ..c....'_T.T:.•3T.^C0{n.lbs;snooty be apCled. Tool Joint Torsional Strenctth a.mn1 71,800 Tool Joint Tensile Strenat1 on:. 1.250.{X}0 Caunterbpre Elevator Shoulder Information Elevator OD 3/32 Raised 6.812 Ir9) Smooth Edge Height Nominal Tool Joint Worn to Bevel Worn to Min TJ OD for 3132 Raised OD Diameter API Premium Class Box OU r6.812 6.625 6.063 5.930 Elevator Capacity obs1,658,000 1,440,200 823,606 685,600 rn:�5219 Nine:Eieval_r capacty tasec cc assumed Eeva:cr Bore.nc•near racier,and pentad stress of 1 10,10CpsI Assumed Elevator Bore Diameter Nue:A raised eeoabar 00 irrraseseevater Capacty'wt(hpuf 00e0ln0 crake-up fmpue. Pipe Body Slip Crushing Capacity Pipe Body Configuration( 5 m) OD 0.362 on) Wall S-135) Nominal 80%Inspection Class API Premium Class 4rr Slio Crushing Capacity es:496.300396.500 396.500 Assumed Stip Length tri?16.5 hideyea` Offidnabad's`x awe aiimF.o r.ncnnala�uarIr nvrnccezo :Pr. p (1 sop Area'World Ci, M's tr the Sri tenor are hansceme load?add lirBar and a tom-reeve Transverse Load Factor(10 4.2 air.Sly costing a deoetaer)Cr trio Op des an and Candler,coefficient el lr0ton Ware arenas tree SW/.WI neap oo ani tai variance.and other'says Casjl•Art Sesta marutx'laer to ady)ral rtm mKn. Pipe Body Performance Pipe Body Configuration( 5(0) OD 0.362 tri) Wall S-135) Nominal 80%Inspecton Class API Premium Class Pipe Tensile Strength {itni 712,100 560.800 560.800 [7_1 Pipe Torsional Strengthn_Itnl 74.100 0 58.100 58.103 TJ1PipeBody Torsional Ratio .97 1.24 1.24 80%Pipe Torsional St-en_th ,:Ie.itsl•59.3CC 46.500 46.500 Burst {lata)17.105 15.63$ 15.638 Nide:Nominal eu s Collapse ipu'1 15.672 117.629 l0 029 rYtxtpfe4 at z-s:a RBA' API. Pipe OD 0.4 5.060 4.855 4.855 Wall Thickness :ei 0.362 0.290 0.290 Nominal Pipe ID on)4276 4.276 4.276 Cross Sectional Area of Pipe Body (l'0,,5.275 4.154 4.154 Cross Sectional Area of OD tkt^zi 19.635 18.51418.514 Cross Sectional Area of ID o'i°. 14.360 14.360 14.360 Section Modulus on's)5.708 4.476 4.476 Polar Section Modulus [I,^ai 11.415 8.953 8.953 Page 55 Version 1 April 2017 • s II Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company Operational Limits of Drill Pipe Connection GPDS50 Tool Join:CD ,r. 6.625 Tool Joint ID ,,,.3250 -cal Joel Specified Minh--,.r" 'MOW Yield S:rengh p.: Pipe Body 80%Inspection Class Pipe Body OD ,., 5 Wall Thickness ,,,,0.362 Pipe Body Grade S-135 Combined Loading for Drill Pipe at Combined Loading for Drill Pipe at i+ 'iI Maximum Make-up Torque= 43,100 in-esi Minimum Make-up Torque= 36,100 Irt-lbs) 0 erationa Assembly Pare ecdy ecenetaon ©Torque a` Max Assembly Pipe Body Tension on Max I o TorqueyMax Tenalon Max Terelon Max Tension Max Tension rq Max Tension in-Incl ;Ion res) trbsr t1.7bsl tits' tins (ces) 0 560.800 560,800 1.046.900 0 560.800 553 0.00 1,202,500 2,100 560,400 560,400 1,046.900 1,700 560,500 550.500 1,202.500 4,200 559.300 559,300 1.046.900 3.400 559.800 559.000 1.202,50 6,300 557.500 557.500 1,046.900 5,100 558,600 556.600 1.202,500 8,300 555.000 555,000 1.046.900 6.800 556.900 555.900 1.202.50: 10,400 551,700 551,700 1,046.900 8,400 554,900 554.900 1,202,502 12.500 547.600 547,600 1046.900 10.'00 552.200 552.200 1.202.50: 14.600 542.800542.800 1.046.900 11.800 549,100 549.100 1,202,500 16.700 537.100 537,100 1.046.900 13.500 545.400 545.430 1.202.500 18,800 530,600 530,600 1,046,900 15.200 541,200 541200 1,202,500 20,800 523,600 523,600 1.046.900 16.900 536.500 5'-.6.530 ,1.202.500 22,900 515,400 515,400 1,046.900 18,600 531,300 531.300 1,202,500 25,000 506.200 536,200 1..046.900 20.300 525.400 525.430 1.202,500 27.100 496.100 496,100 1,046.900 22,000 519,000 519.000 1,202,500 29.200 484.800 484,800 1.046.900 23.700 512 000 5:2.000 1.202,500 31,300 472.500, 472,500 1.046.900 25.300 504,600 534 .800 1,202,500 33,300 459,600 459.600 1.046.900 27.000 496.600 4-5.500 1.202.500 35,400 444.700 444,700 1,046.900 28.700 487,600 407500 1,202,500 37.500 428.400 428,400 1.046.900 30 400 477.900 4 7.030 1.202,500 39.600 410.500 1410,500 1.046.900 32..100 467.400 457.400 1,202,500 Operations'drill reg torque is limited by the Mai.e-up Torque. Operational drilling torque is Limited by the Make-up Torque. Connection Make-up Torque Range I Make-up Torque Connection Max ,.,_m,Tension at:, FAin MUT 36.100 1,202,500 36.900 1,229,200 37.700 1,243,600 ..__ffil) 38.400 1,218,100 39.200 1,189,000 40.000 1,159,800 40.600 1,130.700 41.500 1,105,200 42.300 1,076,100 Max MUT 43.100 1,046,900 Page 56 Version 1 April 2017 • 0 II Milne Point Unit C-46 Drilling Procedure Hilcorp Energy Company Connection Wear Table Connection GDDS50 Tool Join:OD ,n16.625 Toot Joint ID ,,,13.250 Tool Joint Specified Minimum 120,000 Yield Strength (psi) Connection Wear Tool Connection Max Connection Max Mln MUT Connection Max OD Joint OD Torsional MUT Tension Tension NewStren th 9 s, -dbss ub:7 rob:, 1 b.> 6.625 71,800 43,100 1,046,900 35,900 1,195,900 6.562 71,800 43,100 1,034,900 35,900 1.208.700 6.499 71,800 43,100 1,022,600 35,900 1,222.400 !-'.1.. 6.435 71,800 43,100 1,009,800 35,900 1.237.500 6.372 71,200 42,700 1,008,100 35.600 1,245.200 6.309 68,000 40.800 1,057,300 34.000 1.207.700 6.246 64,800 38,900 1,104,800 32,400 1,169.800 6.183 61,700 37.000 1,150,400 30.80,3 1.131.300 6.12 58,600 35,200 1,190,900 29,300 1,096.100 = 6.056 55,500 33.300 1,232,300 27,800 1.060.800 Worn OO 5.993 52,600 31.500 1,227,200 26,300 1,024.600 5.93 49,600 29.800 1,187,100 24.800 987.900 atzuzzl,,,wikvio,,Lomie-t, :11W'4411115054,0 Pipe Body Combined Loading Table(Torque-Tension) Pipe Body 80':; nspector Class Pipe Body OD n,. 5 W_IlThckness ,n)0.362 Pipe Body Grade S-135 <tti V f I'' Pine BodyTorgJe I 5.300 10.600 15.600 21.100 26.400 31.700 37.000 42.900 47.500 52.600 58.100 Pipe Body Max Tension 364,800 558.400 551,400 539.600 522,500 499.600 470.000 432.400 384,500 323.100 234.300 12.200 :1 0 Page 57 Version 1 April 2017 ! I Hilcorp Alaska, LLC Milne Point M Pt C Pad Plan: MPU C-46 , MPU C-46 ti:: Plan: MPU C-46 wp04 Standard Proposal Report 16 March, 2017 i ' HALLIBURTON Sperry Drilling Services • HA LL I B U RTO N WELL DETAILS: Plan:MPU C-46 NAD 1927(NADCON CONUS) Alaska Zone 04 H Hileorp Ground Level: 15.22 Sperry Drilling +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6029204.76 558093.18 70°29'25.462 N 149°31'30.361 W SECTION DETAILS - Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00 2 1150.00 0.00 0.00 1150.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4°/100':1150'MD,1150'TVD -2000 3 1774.93 25.00 168.60 1755.29 -131.53 26.51 4.00 168.60 131.97 End Dir :1774.93'MD,1755.29'TVD - 4 7319.26 25.00 168.60 6780.28 -2428.21 489.48 0.00 0.00 2436.38 Start Dir 5°/100':7319.26'MD,6780.28'TVD 5 7621.90 35.78 190.00 7041.72 -2578.89 486.74 5.00 54.79 2586.99 MPU C-46 wp3 Top Kup C - 6 7706.74 35.78 197.26 7110.58 -2627.02 475.07 5.00 92.88 2634.91 End Dir :7706.74'MD,7110.58'TVD - 7 9532.49 35.78 197.26 8591.72 -3646.46 158.35 0.00 0.00 3648.67 MPU C-46 wp3 Top Sag 810087.18 35.78 197.26 9041.72 -3956.19 62.13 0.00 0.00 3956.67 Total Depth:10087.18'MD,9041.72'TVD 1000- FORMATION TOP DETAILS - TVDPath TVDssPath MDPath Formation 1673.20 1631.48 1685.59 BPRF 1 4443.20 4401.48 4740.64 SBOA - 0 6393.20 6351.48 6892.17 CM1 0- 6593.20 6551.48 7112.84 THRZ 6693.20 6651.48 7223.18 TKLGM Start Dir 4°/100':1150'MD, 1150'TVD 7043.20 7001.48 7623.73 TKUC 500 - 7193.20 7151.48 7808.59 TKA3 - 7197.20 7155.48 7813.52 TMLV - 7569.20 7527.48 8272.07 TJF 1000 1000' 8593.20 8551.48 9534.31 TSGRA End Dir :1774.93'MD,1755.29'TVD SURVEY PROGRAM 1500 -- Date:2016-12-13T00:00:00 Validated:Yes Version: BPRF 2000 Depth From Depth To Survey/Plan Tool 2000- 26.50 1750.00 MPU C-46 wp04 SRG-SS - 1750.00 4800.00 MPU C-46 wp04 MWD+IFR2+MS+sag 2500 4800.00 10087.18 MPU C-46 wp04 MWD+IFR2+MS+sag c 3000 w 3000- CASING DETAILS N 0 3500 TVD TVDSS MD Size Name o - 4497.00 4455.28 4800.00 9-5/8 9-5/8"X 12-1/4" - 9041.72 9000.00 10087.18 7 7"X 8-1/2" ,-- p00 4000- k� 5.`61"' .` (w x500 U V b SBOA , 5000 0• 5000- 9-5/8"X 12-1/4r 5500 I- - _ 6000 6000- 6500 Start Dir 5°/100':7319.26'MD,6780.28'TVD - CM1 - THRZ .1000 - 00 TKLGM X5MPU C-46 wp3 Top Kup C 7000- ---- _,_TKUC- k -- 00� End Dir :7706.74'MD,7110.58'TVD - TMLV $500 - TJF MPU C-46 wp3 Top Sag 8000- 9000 - cif --" TSGRA %* 9000- k.. 7"X 8-1/2' Project: Milne Point ‘, Total Depth:10087.18'MD,9041.72'TVD Site: M Pt C Pad 10000- Well: Plan: MPU C-46 Wellbore: MPU C-46 MPU C-46 wp04 Design: MPU C-46 wp04 I i I , I I I I I I I I I I I - r - -I , I' I II I [ I I I I-. , . i I I-.... . . I I -.r i ii -2000 -1000 0 1000 2000 3000 4000 5000 6000 7000 8000 Vertical Section at 179.00°(1500 usft/in) 11111/ WELL DETAILS: Plan:MPU C-46 HALLIBURTON Hilcorp Ground Level: 15.22 Sperry DMIHng +N/-S +EI-W Northing Easting Latittude Longitude 0.00 0.00 602920476 558093.18 70°29'25.462 N 149°31'30.361 W 1, REFERENCE INFORMATION Start Dir 4°/100':1150'MD,11507VD - ___-- Co-ordinate(N/E)Reference:Well Plan:MPU C-46,True North 0— - Vertical(TVD)Reference:As-Built©41.72usft 1500 Measured Depth Reference:As-Built ifft 41.72usft _ Calculation Method:Minimum Curvature v15_0_ SURVEY PROGRAM End Dir:1774.93'MD,1755.29'TVD -250— 2000 Date:2016-12-13700:00:00 Validated:Yes Version: - -2250 Depth From Depth To Survey/Plan Tool 26.50 1750.00 MPU C-46 wp04 SRG-SS - 1750.00 4800.00 MPU C-46 wp04 MWD+IFR2+MS+sag 2500 -500— 4800.00 10087.18 MPU C-46 wp04 MWD+IFR2+MS+sag 2150 CASING DETAILS 3000 -750— TVD TVDSS MD Size Name 3258 4497.00 4455.28 4800.00 9-5/8 9-5/8"X 12-1/4" 9041.72 9000.00 10087.18 7 7"X 8-1/2" 3500 -1000- - 375000MPANY DETAILS: Hilcorp Alaska,LLC 4000 Calculation Method: Minimum Curvature -1250— 4250Error System: ISCWSA 9-5/8"X 12-1/4" Scan Method: Closest Approach 3D -- Error Surface: Elliptical Conic 4500- Warning Method: Error Ratio -1500— 4950 5000 -1750— 5250 o - 5500 -2000— o 5150 6000 6250 o -2250-- c/7 6500 Start Dir 5°/100':7319.26'MD,6780.28TVD 675°- -2500— _ (MPU C-46 wp3 Top Kup -7000 -2750— 7250 - - End Dir:7706.74'MD,7110.58'TVD 7soo -3000- 7750 -3250— 8000 8250 -3500— IMPU C-46 wp3 Top Soya 8500 -3750— 7"X 8-1/2" 8750 4000— eyr.r-- Project: Milne Point --- Site: M Pt C Pad Met/ Total Depth:10087.18'MD,9041.72'TVD Well: Plan: MPU C-46 47304 Wellbore: MPU C-46 -4250— Plan: MPU C-46 wp04 I II I I I I 11 I I I I 1 I I 1 1 1 1 1 1 1 -500 -250 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 West(-)/East(+)(500 usft/in) II) • Halliburton HALLIBURi O J Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU C-46 Company: Hilcorp Alaska,LLC TVD Reference: As-Built @ 41.72usft Project: Milne Point MD Reference: As-Built @ 41.72usft Site: M Pt C Pad North Reference: True ^ Well: Plan:MPU C-46 Survey Calculation Method: Minimum Curvature - Wellbore: MPU C-46 Design: MPU C-46 wp04 Project Milne Point,ACT,MILNE POINT Map System: US State Plane 1927(Exact solution) ' System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) ^ Using Well Reference Point Map Zone: Alaska Zone 04 - Using geodetic scale factor Site M Pt C Pad,TR-13-10 Site Position: Northing: 6,027,347.71 usft Latitude: 70°29'7.200 N From: Map Easting: 558,058.04 usft Longitude: 149°31'31.821 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.45 ° I Well Plan:MPU C-46 ,Well Position +N/-S 0.00 usft Northing: 6,029,204.76 usft Latitude: 70°29'25.462 N +E/-W 0.00 usft Easting: 558,093.18 usft Longitude: 149°31'30.361 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 15.22 usft Wellbore MPU C-46 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) I (nT) BGGM2016 12/13/2016 17.98 81.07 57,561 Design MPU C-46 wp04 Audit Notes: Version: Phase: PLAN Tie On Depth: 26.50 Vertical Section: ®` d - +N/-S +El-W Direction '(us ) (usft), ,(usft) (°) . 27.98 0.00 0.00 179.00 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S +EI-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) a O 26.50 0.00 0.00 26.50 -15.22 0.00 0.00 0.00 0.00 0.00 0.00 1,150.00 0.00 0.00 1,150.00 1,108.28 0.00 0.00 0.00 0.00 0.00 0.00 1,774.93 25.00 168.60 1,755.29 1,713.57 -131.53 26.51 4.00 4.00 0.00 168.60 7,319.26 25.00 168.60 6,780.28 6,738.56 -2,428.21 489.48 0.00 0.00 0.00 0.00 7,621.90 35.78 190.00 7,041.72 7,000.00 -2,578.89 486.74 5.00 3.56 7.07 54.79 7,706.74 35.78 197.26 7,110.58 7,068.86 -2,627.02 475.07 5.00 0.01 8.56 92.88 9,532.49 35.78 197.26 8,591.72 8,550.00 -3,646.46 158.35 0.00 0.00 0.00 0.00 10,087.18 35.78 197.26 9,041.72 9,000.00 -3,956.19 62.13 0.00 0.00 0.00 0.00 I 3/16/2017 6:29:12PM Page 2 COMPASS 5000.1 Build 81 • 0 Halliburton R IALLIBURTOIV Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU C-46 Company: HilcorpAlaska,LLC TVD Reference: As-Built @ 41.72usft . Project: Milne Point MD Reference: As-Built @ 41.72usft Site: M Pt C Pad North Reference: True Well: Plan:MPU C-46 Survey Calculation Method: Minimum Curvature ' Wellbore: MPU C-46 Design: MPU C-46 wp04 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +El-1N - Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) z =: (usft) (usft) -15.22 26.50 0.00 0.00 26.50 -15.22 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 100.00 0.00 0.00 100.00 58.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 200.00 0.00 0.00 200.00 158.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 300.00 0.00 0.00 300.00 258.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 400.00 0.00 0.00 400.00 358.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 500.00 0.00 0.00 500.00 458.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 600.00 0.00 0.00 600.00 558.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 700.00 0.00 0.00 700.00 658.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 800.00 0.00 0.00 800.00 758.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 900.00 0.00 0.00 900.00 858.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 1,000.00 0.00 0.00 1,000.00 958.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 1,100.00 0.00 0.00 1,100.00 1,058.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 1,150.00 • 0.00 0.00 1,150.00 1,108.28 0.00 0.00 6,029,204.76 558,093.18 0.00 0.00 Start Dir 4°1100':1150'MD,1150'TVD 1,200.00 2.00 168.60 1,199.99 1,158.27 -0.86 0.17 6,029,203.91 558,093.36 4.00 0.86 1,300.00 6.00 168.60 1,299.73 1,258.01 -7.69 1.55 6,029,197.08 558,094.79 4.00 7.72 1,400.00 10.00 168.60 1,398.73 1,357.01 -21.33 4.30 6,029,183.46 558,097.65 4.00 21.40 1,500.00 14.00 168.60 1,496.53 1,454.81 -41.71 8.41 6,029,163.12 558,101.91 4.00 41.85 1,600.00 18.00 168.60 1,592.63 1,550.91 -68.72 13.85 6,029,136.15 558,107.57 4.00 68.96 1,685.59 21.42 168.60 1,673.20 1,631.48 -97.02 19.56 6,029,107.90 558,113.49 4.00 97,35 BPRF 1,700.00 22.00 168.60 1,686.58 1,644.86 -102.24 20.61 6,029,102.69 558,114.59 4.00 102.59 1,774.93 25.00 168.60 1,755.29 1,713.57 -131.53 26.51 6,029,073.45 558,120.72 4.00 131.97 End Dir :1774.93'MD,1755.29'TVD 1,800.00 25.00 168.60 1,778.01 1,736.29 -141.91 28.61 6,029,063.09 558,122.89 0.00 142.39 1,900.00 25.00 168.60 1,868.65 1,826.93 -183.34 36.96 6,029,021.73 558,131.56 0.00 183.95 2,000.00 25.00 168.60 1,959.28 1,917.56 -224.76 45.31 6,028,980.38 558,140.24 0.00 225.52 2,100.00 25.00 168.60 2,049.91 2,008.19 -266.19 53.66 6,028,939.03 558,148.91 0.00 267.08 2,200.00 25.00 168.60 2,140.55 2,098.83 -307.61 62.01 6,028,897.67 558,157.58 0.00 308.64 2,300.00 25.00 168.60 2,231.18 2,189.46 -349.03 70.36 6,028,856.32 558,166.26 0.00 350.21 2,400.00 25.00 168.60 2,321.81 2,280.09 -390.46 78.71 6,028,814.97 558,174.93 0.00 391.77 2,500.00 25.00 168.60 2,412.45 2,370.73 -431.88 87.06 6,028,773.61 558,183.60 0.00 433.33 2,600.00 25.00 168.60 2,503.08 2,461.36 -473.31 95.41 6,028,732.26 558,192.27 0.00 474.90 2,700.00 25.00 168.60 2,593.71 2,551.99 -514.73 103.76 6,028,690.91 558,200.95 0.00 516.46 2,800.00 25.00 168.60 2,684.34 2,642.62 -556.15 112.11 6,028,649.55 558,209.62 0.00 558.02 2,900.00 25.00 168.60 2,774.98 2,733.26 -597.58 120.46 6,028,608.20 558,218.29 0.00 599.59 3,000.00 25.00 168.60 2,865.61 2,823.89 -639.00 128.81 6,028,566.85 558,226.97 0.00 641.15 3,100.00 25.00 168.60 2,956.24 2,914.52 -680.42 137.16 6,028,525.49 558,235.64 0.00 682.71 3,200.00 25.00 168.60 3,046.88 3,005.16 -721.85 145.51 6,028,484.14 558,244.31 0.00 724.28 3,300.00 25.00 168.60 3,137.51 3,095.79 -763.27 153.86 6,028,442.79 558,252.98 0.00 765.84 3,400.00 25.00 168.60 3,228.14 3,186.42 -804.70 162.21 6,028,401.43 558,261.66 0.00 807.40 3,500.00 25.00 168.60 3,318.77 3,277.05 -846.12 170.56 6,028,360.08 558,270.33 0.00 848.97 3,600.00 25.00 168.60 3,409.41 3,367.69 -887.54 178.91 6,028,318.73 558,279.00 0.00 890.53 3,700.00 25.00 168.60 3,500.04 3,458.32 -928.97 187.26 6,028,277.37 558,287.67 0.00 932.09 3,800.00 25.00 168.60 3,590.67 3,548.95 -970.39 195.61 6,028,236.02 558,296.35 0.00 973.66 3/16/2017 6:29:12PM Page 3 COMPASS 5000.1 Build 81 • 0 /� Halliburton HALL1 B L RTO r Standard Proposal Report ,, Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU C-46 V#y Company: Hilcorp Alaska,LLC TVD Reference: As-Built @ 41.72usft Project: Milne Point MD Reference: As-Built @ 41.72usft Site: M Pt C Pad North Reference: True Well: Plan:MPU C-46 Survey Calculation Method: Minimum Curvature Wellbore: MPU C-46 Design: MPU C-46 wp04 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,639.59 3,900.00 25.00 168.60 3,681.31 3,639.59 -1,011.82 203.96 6,028,194.67 558,305.02 0.00 1,015.22 4,000.00 25.00 168.60 3,771.94 3,730.22 -1,053.24 212.31 6,028,153.31 558,313.69 0.00 1,056.78 4,100.00 25.00 168.60 3,862.57 3,820.85 -1,094.66 220.66 6,028,111.96 558,322.37 0.00 1,098.35 4,200.00 25.00 168.60 3,953.21 3,911.49 -1,136.09 229.01 6,028,070.61 558,331.04 0.00 1,139.91 4,300.00 25.00 168.60 4,043.84 4,002.12 -1,177.51 237.36 6,028,029.25 558,339.71 0.00 1,181.47 4,400.00 25.00 168.60 4,134.47 4,092.75 -1,218.94 245.71 6,027,987.90 558,348.38 0.00 1,223.04 4,500.00 25.00 168.60 4,225.10 4,183.38 -1,260.36 254.06 6,027,946.55 558,357.06 0.00 1,264.60 4,600.00 25.00 168.60 4,315.74 4,274.02 -1,301.78 262.41 6,027,905.19 558,365.73 0.00 1,306.16 4,700.00 25.00 168.60 4,406.37 4,364.65 -1,343.21 270.76 6,027,863.84 558,374.40 0.00 1,347.73 4,740.64 25.00 168.60 4,443.20 4,401.48 -1,360.04 274.16 6,027,847.03 558,377.93 0.00 1,364.62 SBOA 4,800.00 25.00 168.60 4,497.00 4,455.28 -1,384.63 279.11 6,027,822.49 558,383.08 0.00 1,389.29 9-5/8"X 12-1/4" 4,900.00 25.00 168.60 4,587.64 4,545.92 -1,426.05 287.46 6,027,781.13 558,391.75 0.00 1,430.85 5,000.00 25.00 168.60 4,678.27 4,636.55 -1,467.48 295.81 6,027,739.78 558,400.42 0.00 1,472.42 5,100.00 25.00 168.60 4,768.90 4,727.18 -1,508.90 304.16 6,027,698.42 558,409.09 0.00 1,513.98 5,200.00 25.00 168.60 4,859.54 4,817.82 -1,550.33 312.51 6,027,657.07 558,417.77 0.00 1,555.54 5,300.00 25.00 168.60 4,950.17 4,908.45 -1,591.75 320.86 6,027,615.72 558,426.44 0.00 1,597.11 5,400.00 25.00 168.60 5,040.80 4,999.08 -1,633.17 329.22 6,027,574.36 556,435.11 0.00 1,638.67 5,500.00 25.00 168.60 5,131.43 5,089.71 -1,674.60 337.57 6,027,533.01 558,443.78 0.00 1,680.23 5,600.00 25.00 168.60 5,222.07 5,180.35 -1,716.02 345.92 6,027,491.66 558,452.46 0.00 1,721.80 5,700.00 25.00 168.60 5,312.70 5,270.98 -1,757.45 354.27 6,027,450.30 558,461.13 0.00 1,763.36 5,800.00 25.00 168.60 5,403.33 5,361.61 -1,798.87 362.62 6,027,408.95 558,469.80 0.00 1,804.92 5,900.00 25.00 168.60 5,493.97 5,452.25 -1,840.29 370.97 6,027,367.60 558,478.48 0.00 1,846.49 6,000.00 25.00 168.60 5,584.60 5,542.88 -1,881.72 379.32 6,027,326.24 558,487.15 0.00 1,888.05 6,100.00 25.00 168.60 5,675.23 5,633.51 -1,923.14 387.67 6,027,284.89 558,495.82 0.00 1,929.61 6,200.00 25.00 168.60 5,765.86 5,724.14 -1,964.57 396.02 6,027,243.54 558,504.49 0.00 1,971.18 6,300.00 25.00 168.60 5,856.50 5,814.78 -2,005.99 404.37 6,027,202.18 558,513.17 0.00 2,012.74 6,400.00 25.00 168.60 5,947.13 5,905.41 -2,047.41 412.72 6,027,160.83 558,521.84 0.00 2,054.30 6,500.00 25.00 168.60 6,037.76 5,996.04 -2,088.84 421.07 6,027,119.48 558,530.51 0.00 2,095.87 6,600.00 25.00 168.60 6,128.40 6,086.68 -2,130.26 429.42 6,027,078.12 558,539.18 0.00 2,137.43 6,700.00 25.00 168.60 6,219.03 6,177.31 -2,171.68 437.77 6,027,036.77 558,547.86 0.00 2,178.99 I 6,800.00 25.00 168.60 6,309.66 6,267.94 -2,213.11 446.12 6,026,995.42 558,556.53 0.00 2,220.56 6,892.17 25.00 168.60 6,393.20 6,351.48 -2,251.29 453.81 6,026,957.30 558,564.52 0.00 2,258.97 CM1 6,900.00 25.00 168.60 6,400.30 6,358.58 -2,254.53 454.47 6,026,954.06 558,565.20 0.00 2,262.12 7,000.00 25.00 168.60 6,490.93 6,449.21 -2,295.96 462.82 6,026,912.71 558,573.88 0.00 2,303.68 7,100.00 25.00 168.60 6,581.56 6,539.84 -2,337.38 471.17 6,026,871.36 558,582.55 0.00 2,345.25 7,112.84 25.00 168.60 6,593.20 6,551.48 -2,342.70 472.24 6,026,866.05 558,583.66 0.00 2,350.58 THRZ 7,200.00 25.00 168.60 6,672.19 6,630.47 -2,378.80 479.52 6,026,830.00 558,591.22 0.00 2,386.81 7,223.18 25.00 168.60 6,693.20 6,651.48 -2,388.40 481.45 6,026,820.42 558,593.23 0.00 2,396.44 TKLGM 7,300.00 25.00 168.60 6,762.83 6,721.11 -2,420.23 487.87 6,026,788.65 558,599.89 0.00 2,428.37 3/16/2017 6:29:12PM Page 4 COMPASS 5000.1 Build 81 ! i Halliburton I-IALLIB(JRTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU C-46 Company: Hilcorp Alaska,LLC ND Reference: As-Built @ 41.72usft Project: Milne Point MD Reference: As-Built @ 41.72usft Site: .M Pt C Pad North Reference: True Well: Plan:MPU C-46 Survey Calculation Method: Minimum Curvature Wellbore "`MPU C-46 Design: MPU C-46 wp04 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 6,738.56 7,319.26 25.00 168.60 6,780.28 6,738.56 -2,428.21 489.48 6,026,780.69 558,601.56 0.00 2,436.38 Start Dir 5°/100':7319.26'MD,6780.28'TVD 7,400.00 27.51 175.76 6,852.71 6,810.99 -2,463.54 494.23 6,026,745.39 558,606.59 5.00 2,471.79 7,500.00 31.04 183.01 6,939.95 6,898.23 -2,512.35 494.58 6,026,696.59 558,607.33 5.00 2,520.60 7,600.00 34.90 188.87 7,023.85 6,982.13 -2,566.39 488.81 6,026,642.51 558,601.98 5.00 2,574.53 7,621.90 35.78 190.00 7,041.72 7,000.00 -2,578.89 486.74 6,026,630.00 558,600.00 5.00 2,586.99 7,623.73 35.77 190.16 7,043.20 7,001.48 -2,579.94 486.55 6,026,628.95 558,599.82 5.00 2,588.04 TKUC ., . 7,700.00 35.77 196.68 7,105.11 7,063.39 -2,623.25 476.22 6,026,585.56 558,589.83 5.00 2,631.16 7,706.74 35.78 197.26 7,110.58 7,068.86 -2,627.02 475.07 6,026,581.79 558,588.71 5.00 2,634.91 End Dir :7706.74'MD,7110.58'TVD 7,800.00 35.78 197.26 7,186.23 7,144.51 -2,679.09 458.89 6,026,529.59 558,572.94 0.00 2,686.69 7,808.59 35,78 197.26 7,193.20 7,151.48 -2,683.89 457.40 6,026,524.79 558,571.49 0.00 2,691.46 TKA3 7,813.52 35.78 197.26 7,197.20 7,155.48 -2,686.64 456.54 6,026,522.03 558,570.65 0.00 2,694.20 TMLV 7,900.00 35.78 197.26 7,267.36 7,225.64 -2,734.93 441.54 6,026,473.63 558,556.03 0.00 2,742.22 8,000.00 35.78 197.26 7,348.49 7,306.77 -2,790.77 424.19 6,026,417.66 558,539.12 0.00 2,797.74 8,100.00 35.78 197.26 7,429.61 7,387.89 -2,846.60 406.85 6,026,361.70 558,522.21 0.00 2,853.27 8,200.00 35.78 197.26 7,510.74 7,469.02 -2,902.44 389.50 6,026,305.73 558,505.30 0.00 2,908.80 8,272.07 35.78 197.26 7,569.20 7,527.48 -2,942.68 377.00 6,026,265.40 558,493.12 0.00 2,948.81 TJF 8,300.00 35.78 197.26 7,591.86 7,550.14 -2,958.28 372.15 6,026,249.77 558,488.40 0.00 2,964.32 8,400.00 35.78 197.26 7,672.99 7,631.27 -3,014.11 354.81 6,026,193.80 558,471.49 0.00 3,019.85 8,500.00 35.78 197.26 7,754.11 7,712.39 -3,069.95 337.46 6,026,137.83 558,454.58 0.00 3,075.37 8,600.00 35.78 197.26 7,835.24 7,793.52 -3,125.79 320.11 6,026,081.87 558,437.67 0.00 3,130.90 8,700.00 35.78 197.26 7,916.36 7,874.64 -3,181.62 302.77 6,026,025.90 558,420.76 0.00 3,186.42 8,800.00 35.78 197.26 7,997.49 7,955.77 -3,237.46 285.42 6,025,969.94 558,403.85 0.00 3,241.95 8,900.00 35.78 197.26 8,078.61 8,036.89 -3,293.30 268.07 6,025,913.97 558,386.94 0.00 3,297.47 9,000.00 35.78 197.26 8,159.74 8,118.02 -3,349.14 250.72 6,025,858.01 558,370.04 0.00 3,353.00 9,100.00 35.78 197.26 8,240.86 8,199.14 -3,404.97 233.38 6,025,802.04 558,353.13 0.00 3,408.53 9,200.00 35.78 197.26 8,321.99 8,280.27 -3,460.81 216.03 6,025,746.08 558,336.22 0.00 3,464.05 9,300.00 35.78 197.26 8,403.11 8,361.39 -3,516.65 198.68 6,025,690.11 558,319.31 0.00 3,519.58 9,400.00 35.78 197.26 8,484.24 8,442.52 -3,572.48 181.34 6,025,634.15 558,302.40 0.00 3,575.10 9,500.00 35.78 197.26 8,565.37 8,523.65 -3,628.32 163.99 6,025,578.18 558,285.49 0.00 3,630.63 9,532.49 35.78 197.26 8,591.72 8,550.00 -3,646.46 158.35 6,025,560.00 558,280.00 0.00 3,648.67 9,534.31 35.78 197.26 8,593.20 8,551.48 -3,647.48 158.04 6,025,558.98 558,279.69 0.00 3,649.68 TSGRA 9,600.00 35.78 197.26 8,646.49 8,604.77 -3,684.16 146.64 6,025,522.22 558,268.58 0.00 3,686.15 9,700.00 35.78 197.26 8,727.62 8,685.90 -3,739.99 129.30 6,025,466.25 558,251.68 0.00 3,741.68 9,800.00 35.78 197.26 8,808.74 8,767.02 -3,795.83 111.95 6,025,410.28 558,234.77 0.00 3,797.21 9,900.00 35.78 197.26 8,889.87 8,848.15 -3,851.67 94.60 6,025,354.32 558,217.86 0.00 3,852.73 10,000.00 35.78 197.26 8,970.99 8,929.27 -3,907.50 77.25 6,025,298.35 558,200.95 0.00 3,908.26 10,087.18 • 35.78 197.26 9,041.72 . 9,000.00 -3,956.18 62.13 6,025,249.56 558,186.21 0.00 3,956.66 Total Depth:10087.18'MD,9041.72'TVD-7"X 8-1/2" 3/16/2017 6:29.12PM Page 5 COMPASS 5000.1 Build 81 i S Halliburton HA LLI B U RTO N Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA `Local Co-ordinate Reference: Well Plan:MPU C-46 Company: Hilcorp Alaska,LLC TVD Reference: As-Built @ 41.72usft Project: Milne Point MD Reference: As-Built @ 41.72usft Site: M Pt C Pad North Reference. 13.: True Well: Plan:MPU C-46 Survey Calculation Method: Minimum Curvature Wellbore: MPU C-46 Design: MPU C-46 wp04 .M.. Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPU C-46 wp3 Top Kup C 0.00 0.00 7,041.72 -2,578.89 486.74 6,026,630.00 558,600.00 -plan hits target center -Point MPU C-46 wp3 Top Sag 0.00 0.00 8,591.72 -3,646.46 158.35 6,025,560.00 558,280.00 -plan hits target center 1 -Point 1 Casing Points a) Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 4,800.00 4,497.00 9-5/8"X 12-1/4" 9-5/8 12-1/4 10,087.18 9,041.72 7"X 8-1/2" 7 8-1/2 Formations '° m...: :.,: *x ,.. ,, .<.: r a race .<a,.,7'' Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (1 (°) 7,813.52 7,197.20 TMLV 4,740.64 4,443.20 SBOA 9,534.31 8,593.20 TSGRA 6,892.17 6,393.20 CM1 7,112.84 6,593.20 THRZ 7,223.18 6,693.20 TKLGM 7,808.59 7,193.20 TKA3 1,685.59 1,673.20 BPRF 7,623.73 7,043.20 TKUC 8,272.07 7,569.20 TJF 1 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) a (usft) (usft) Comment 1,150.00 1,150.00 0.00 0.00 Start Dir 4°/100':1150'MD,1150'TVD 1,774.93 1,755.29 -131.53 26.51 End Dir :1774.93'MD,1755.29'TVD 7,319.26 6,780.28 -2,428.21 489.48 Start Dir 5°/100':7319.26'MD,6780.28'TVD 7,706.74 7,110.58 -2,627.02 475.07 End Dir :7706.74'MD,7110.58'TVD 10,087.18 9,041.72 -3,956.18 62.13 Total Depth:10087.18'MD,9041.72'TVD 3/16/2017 6.29.12PM Page 6 COMPASS 5000.1 Build 81 • • Hilcorp Alaska, LLC Milne Point M Pt C Pad Plan: MPU C-46 MPU C-46 MPU C-46 wp04 Sperry Drilling Services Clearance Summary Anticollision Report 16 March,2017 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt C Pad-Plan:MPU C-46-MPU C-46-MPU C-46 wp04 Well Coordinates: 6,029,204.76 N,558,093.18 E(70°29'25.46"N,149"31'30.36"W) Datum Height As-Built @ 41,72usft Scan Range: 0.00 to 10,087.18 usft.Measured Depth. Scan Radius is 1,206.07 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version:5000.1 Build:81 Scan Type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 •NA HALLIBURTON Sperry Drilling Services • • Hilcorp Alaska,LLC HALLI B U RTO N Milne Point Anticollision Report for Plan: MPU C-46 -MPU C-46 wp04 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt C Pad-Plan:MPU C46-MPU C-46-MPU C-46 wp04 Scan Range: 0.00 to 10,087.18 usft.Measured Depth., Scan Radius is 1,206.07 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft M Pt C Pad MPC-01-MPC-01-MPC-01 1,036.54 260.60 1,036.54 248.14 1,011.87 20.914 Centre Distance Pass- MPC-01-MPC-01-MPC-01 1,150.00 261.00 1,150.00 247,24 1,123.71 18.967 Ellipse Separation Pass- MPC-01-MPC-01-MPC-01 1,475.00 292.01 1,475.00 274.83 1,448.47 16.996 Clearance Factor Pass- MPC-05-MPC-05-MPC-05 1,788.24 264.14 1,788.24 240.56 1,753.50 11.201 Clearance Factor Pass- MPC-05-MPC-05A-MPC-05A 1,768.24 264.14 1,788.24 240.56 1,753.50 11201 Clearance Factor Pass- MPC-06-MPC-06-MPC-06 649.64 264.27 849.84 253.99 860.15 25.703 Centre Distance Pass- MPC-06-MPC-06-MPC-06 925.00 264.69 925.00 253.57 932.15 23.805 Ellipse Separation Pass- MPC-06-MPC-06-MPC-06 2,025.00 306.14 2,025.00 265.67 1,900.00 14.953 Clearance Factor Pass- MPC-07-MPC-07-MPC-07 399.88 90.03 399.88 84.67 410.16 16.608 Centre Distance Pass- MPC-07-MPC-07-MPC-07 525.00 90.74 525.00 83.99 534.25 13.447 Ellipse Separation Pass- MPC-07-MPC-07-MPC-07 800.00 104.40 800.00 94.54 800.00 10.584 Clearance Factor Pass- MPC-08-MPC-08-MPC-08 1,273.81 107.80 1,273.81 91.54 1,293.85 6.631 Centre Distance Pass- MPC-08-MPC-08-MPC-08 1,275.00 107.80 1,275.00 91.53 1,294.94 6.625 Ellipse Separation Pass- MPC-0B-MPC-08-MPC-08 1,325.00 109.61 1,325.00 92.79 1,339.30 6.517 Clearance Factor Pass- MPC-09-MPC-09-MPC-09 26.50 200.12 26.50 199.16 36.78 208.178 Centre Distance Pass- MPC-09-MPC-09-MPC-09 625.00 201.69 625.00 195.17 632.87 30.915 Ellipse Separation Pass- MPC-09-MPC-09-MPC-09 1,025.00 236.42 1,025.00 226.17 1,000.00 23.061 Clearance Factor Pass- MPC-10-MPC-10-MPC-10 1,415.69 27.98 1,415.69 11.20 1,424.35 1.668 Centre Distance Pass- MPC-10-MPC-10-MPC-10 1,425.00 28.03 1,425.00 11.14 1,433.49 1.660 Clearance Factor Pass- MPC-11-MPC-11-MPC-11 1,075.85 218.77 1,075.85 205.67 1,086.13 16.698 Centre Distance Pass- MPC-11-MPC-11-MPC-11 1,175.00 218.92 1,175.00 204.70 1,185.08 15.393 Ellipse Separation Pass- MPC-11-MPC-11-MPC-11 1,400.00 235.00 1,400.00 218.49 1,400.00 14.238 Clearance Factor Pass- MPC-12-MPC-12-MPC-12 1,728.74 299.20 1,728.74 276.54 1,782.74 14.486 Ellipse Separation Pass- MPC-12-MPC-12-MPC-12 1,774.93 301.63 1,774.93 280.46 1,808.41 14.246 Clearance Factor Pass- MPC-12-MPC-12A-MPC-12A 1,728.74 299.20 1,728.74 278.54 1,782.74 14.484 Ellipse Separation Pass- MPC-12-MPC-12A-MPC-12A 1,774.93 301.63 1,774.93 280.45 1,808.41 14.245 Clearance Factor Pass- MPC-12-MPC-12APB1-MPC-12APB1 1,728.74 299.20 1,728.74 278.54 1,782.74 14.484 Ellipse Separation Pass- MPC-12-MPC-12APB1-MPC-12APB1 1,774.93 301.63 1,774.93 280.45 1,808.41 14245 Clearance Factor Pass- 18 March,2017- 18:30 Page 2 of 8 COMPASS . • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU C-46-MPU C-46 wp04 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt C Pad-Plan:MPU C-46-MPU C-46-MPU C46 wp04 Scan Range:0.00 to 10,087.18 usft.Measured Depth. Scan Radius is 1,206.07 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation Is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPC-13-MPC-13-MPC-13 575.85 202.05 575.85 194.53 586.13 26.845 Centre Distance Pass- MPC-13-MPC-13-MPC-13 1,400.00 202.65 1,400.00 185.97 1,408.97 12.151 Ellipse Separation Pass- MPC-13-MPC-13-MPC-13 7,250.00 945.56 7,250.00 704.22 7,386.48 3.918 Clearance Factor Pass- MPC-14-MPC-14-MPC-14 1,703.19 226.34 1,703.19 206.11 1,666.95 11.185 Centre Distance Pass- MPC-14-MPC-14-MPC-14 1,725.00 226.47 1,725.00 205.98 1,684.00 11.053 Ellipse Separation Pass- MPC-14-MPC-14-MPC-14 1,825.00 231.05 1,825.00 209.54 1,772.56 10.743 Clearance Factor Pass- MPC-15-MPC-15-MPC-15 2,050.62 221.25 2,050.62 197.86 2,015.82 9.377 Ellipse Separation Pass- MPC-15-MPC-15-MPC-15 2,125.00 223.44 2,125.00 199.28 2,083.37 9.246 Clearance Factor Pass- MPC-15-MPC-15A-MPC-15A 2,050.62 221.25 2,050.82 197.66 2,014.16 9.377 Ellipse Separation Pass- MPC-15-MPC-15A-MPC-15A 2,125.00 223.44 2,125.00 199.26 2,081.71 9.246 Clearance Factor Pass- MPC-20-MPC-20-MPC-20 1,555.77 228.24 1,555.77 209,93 1,552.05 12.468 Centre Distance Pass- MPC-20-MPC-20-MPC-20 1,600.00 228.56 1,600.00 209.62 1,594.66 12.070 Ellipse Separation Pass- MPC-20-MPC-20-MPC-20 1,774.93 240.51 1,774.93 219.01 1,757.17 11.183 Clearance Factor Pass- MPC-23-MPC-23-MPC-23 292.37 119.68 292.37 117.27 295.65 49.677 Centre Distance Pass- MPC-23-MPC-23-MPC-23 350.00 119.86 350.00 117.06 352.51 42.749 Ellipse Separation Pass- MPC-23-MPC-23-MPC-23 1,075.00 171.24 1,075.00 163.25 1,056.35 21.431 Clearance Factor Pass- MPC-24-MPC-24-MPC-24 1,257.37 231.88 1,257.37 218.57 1,283.48 17.663 Ellipse Separation Pass- MPC-24-MPC-24-MPC-24 1,450.00 247.85 1,450.00 233.07 1,474.27 16.765 Clearance Factor Pass- MPC-24-MPC-24A-MPC-24A 1,257.37 231.68 1,257.37 218.57 1,283.48 17.663 Ellipse Separation Pass- MPC-24-MPC-24A-MPC-24A 1,450.00 247.85 1,450.00 233.07 1,474.27 16.785 Clearance Factor Pass- MPC-24-MPC-24APB1-MPC-24APB1 1,257.37 231.68 1,257.37 218.57 1,283.48 17.683 Ellipse Separation Pass- MPC-24-MPC-24APB1-MPC-24APB1 1,450.00 247.85 1,450.00 233.07 1,474,27 16.765 Clearance Factor Pass- MPC-25-MPC-25-MPC-25 262.17 229.60 262.17 227.42 265.90 105.239 Centre Distance Pass- MPC-25-MPC-25-MPC-25 300.00 229.71 300.00 227.28 302.38 94.443 Ellipse Separation Pass- MPC-25-MPC-25-MPC-25 1,175.00 300.63 1,175.00 292.40 1,126.33 36.492 Clearance Factor Pass- MPC-25-MPC-25A-MPC-25A 262.17 229.60 262.17 227.42 265.90 105.239 Centre Distance Pass- MPC-25-MPC-25A-MPC-25A 300.00 229.71 300.00 227.28 302.38 94.443 Ellipse Separation Pass- MPC-25-MPC-25A-MPC-25A 1,175.00 300.63 1,175.00 292.40 1,126.33 36.492 Clearance Factor Pass- MPC-25-Plan MPC-25B-MPC-25B wp02 262.17 229.60 262.17 227.42 270.95 105.238 Centre Distance Pass- MPC-25-Plan MPC-25B-MPC-25B wp02 300.00 229.71 300.00 227.28 307.43 94.443 Ellipse Separation Pass- MPC-25-Plan MPC-25B-MPC-25B wp02 1,175.00 300.63 1,175.00 292.40 1,131.38 36.491 Clearance Factor Pass- 16 March,2017- 18:30 Page 3 of8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU C-46-MPU C-46 wp04 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt C Pad-Plan:MPU C-46-MPU C-46-MPU C46 wp04 Scan Range:0.00 to 10,087.18 usft.Measured Depth. Scan Radius is 1,206.07 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPC-26-MPC-20-MPC-26 26.50 170.66 26.50 169.32 31.08 126.799 Centre Distance Pass- MPC-26-MPC-26-MPC-26 350.00 171.66 350.00 168.82 353.46 60.364 Ellipse Separation Pass- MPC-26-MPC-26-MPC-26 1,150.00 219.35 1,150.00 210.79 1,124.18 25.620 Clearance Factor Pass- MPC-26-MPC-26L1-MPC-28L1 26.50 170.66 26.50 169.32 31.08 126.799 Centre Distance Pass- MPC-26-MPC-26L1-MPC-26L1 350.00 171.66 350.00 168.82 353.48 60.365 Ellipse Separation Pass- MPC-26-MPC-26L1-MPC-26L1 1,150.00 219.35 1,150.00 210.79 1,124.18 25.618 Clearance Factor Pass- MPC-26-MPC-26L1PB1-MPC-26L1PB1 26.50 170.66 26.50 169.32 31.08 126.799 Centre Distance Pass- MPC-26-MPC-26L1PB1-MPC-26L1P81 350.00 171.66 350.00 168.82 353.46 60.365 Ellipse Separation Pass- MPC-26-MPC-26L1PB1-MPC-26L1PB1 1,150.00 219.35 1,150.00 210.79 1,124.18 25.616 Clearance Factor Pass- MPC-26-MPC-26L1PB2-MPC-26L1PB2 26.50 170.66 26.50 169.32 31.08 126.799 Centre Distance Pass- MPC-26-MPC-26L1PB2-MPC-26L1PB2 350.00 171.66 350.00 168.82 353.46 60.365 Ellipse Separation Pass- MPC-26-MPC-26L1PB2-MPC-26L1PB2 1,150.00 219.35 1,150.00 210.79 1,124.18 25.618 Clearance Factor Pass- MPC-26-MPC-26L1PB3-MPC-26L1PB3 26.50 170.66 26.50 169.32 31.08 126.799 Centre Distance Pass- MPC-26-MPC-26L1PB3-MPC-26L1PB3 350.00 171.66 350.00 168.82 353.46 60.365 Ellipse Separation Pass- MPC-26-MPC-26L1PB3-MPC-26L1PB3 1,150.00 219.35 1,150.0D 210.79 1,124.16 25.618 Clearance Factor Pass- MPC-28-MPC-28-MPC-28 1,410.73 31.91 1,410.73 17.96 1,416.03 2.288 Clearance Factor Pass- MPC-28-MPC-28A-MPC-28A 1,410.73 31.91 1,410.73 18.07 1,419.71 2.306 Clearance Factor Pass- MPC-36-MPC-36-MPC-36 100.00 30.31 100.00 29.14 95.18 25.981 Centre Distance Pass- MPC36-MPC-36-MPC-36 200.00 30.60 200.00 28.76 194.99 16.610 Ellipse Separation Pass- MPC-36-MPC-36-MPC-36 625.00 46.09 625.00 41.28 817.80 9.576 Clearance Factor Pass- MPC-39-MPC-39-MPC-39 1,760.90 34.13 1,760.90 21.09 1,748,23 2.618 Clearance Factor Pass- MPC-40-MPC-40-MPC-40 26.50 .179.66 26.50 178.32 31.06 133.545 Centre Distance Pass- MPC-40-MPC-40-MPC-40 75.00 179.77 75.00 176.26 78.84 118.940 Ellipse Separation Pass- MPC-40-MPG-40-MPC-40 1,275.00 225.96 1,275.00 215.54 1,241.04 21.683 Clearance Factor Pass- MPC-41-MPC-41-MPC-41 26.50 239.58 26.50 238.51 28.67 224.306 Centre Distance Pass- MPC41-MPC-41-MPC-41 75.00 239.66 75.00 238.43 77.65 193.763 Ellipse Separation Pass- MPC41-MPC-41-MPC-41 1,125.00 324.49 1,125.00 315.87 1,062.60 37.662 Clearance Factor Pass- MPC41-MPC-41L1-MPC-41L1 26.50 239.58 28.50 238.51 28.67 224.306 Centre Distance Pass- MPC-41-MPC-41L1-MPC-41L1 75.00 239.66 75.00 238.43 77.65 193.763 Ellipse Separation Pass- MPC-41-MPC-41L1-MPC-41L1 1,125.00 324.49 1,125.00 315.98 1,062.60 38.123 Clearance Factor Pass- 18 March,2017- 18:30 Page 401 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU C-46-MPU C-46 wp04 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt C Pad-Plan:MPU C-46-MPU C-46-MPU C-46 wp04 Scan Range: 0.00 to 10,087.18 usft.Measured Depth. Scan Radius is 1,206.07 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPC-41-MPC-41L2-MPC-41L2 26.50 239.58 26.50 238.51 28.67 224.306 Centre Distance Pass- MPC41-MPC-41L2-MPC-41L2 75.00 239.66 75.00 238.43 77.65 193.763 Ellipse Separation Pass- MPC-41-MPC-41L2-MPC-41L2 1,125.00 324.49 1,125.00 315.98 1,062.60 38.123 Clearance Factor Pass- MPC-41-MPC-41PB1-MPC-41P81 28.50 239.58 26.50 238.51 28.67 224.306 Centre Distance Pass- MPC-41-MPC-41PB1-MPC-41PB1 75.00 239.68 75.00 238A3 77.65 193.763 Ellipse Separation Pass- MPC41-MPC-41PB1-MPC-41PB1 1,100.00 318.84 1,100.00 310.11 1,043.56 38.527 Clearance Factor Pass- MPC-41-MPC-41PB2-MPC-41PB2 26.50 239.58 26.50 238.51 28.67 224.306 Centre Distance Pass- MPC41-MPC41PB2-MPC41PB2 75.00 239.66 75.00 238.43 77.65 193.762 Ellipse Separation Pass- MPC41-MPC-41PB2-MPC-41PB2 1,125.00 324.49 1,125.00 315.87 1,062.60 37.659 Clearance Factor Pass- Plan:MPC-35 Kuparuk/Sag-Kuparuk/Sag River-MP 1,150.00 60.13 1,150.00 51.29 1,158.28 6.798 Ellipse Separation Pass- Plan:MPC-35 Kuparuk/Sag-Kuparuk/Sag River-MP 1,200.00 61.00 1,200.00 51.85 1,208.27 6.668 Clearance Factor Pass- ' Plan:MPU C-44-MPU C-44(Jump in the Fire)-MPU 325.00 59.91 325.00 57.19 326.48 22.042 Centre Distance Pass- Plan:MPU C-44-MPU C-44(Jump in the Fire)-MPU 375.00 60.06 375.00 57.00 376.13 19.629 Ellipse Separation Pass- Plan:MPU C-44-MPU C-44(Jump in the Fire)-MPU 650.00 71.08 650.00 66.12 646.10 14.331 Clearance Factor Pass- Plan:MPU C-45-MPU C-45(Hey You)-MPU C-45 w 525.00 80.02 525.00 55.92 526.48 14.853 Centre Distance Pass- Plan:MPU C-45-MPU C-45(Hey You)-MPU C-45 w 575.00 80.21 575.00 55.77 576.01 13.579 Ellipse Separation Pass- Plan:MPU C-45-MPU C-45(Hey You)-MPU C-45 w 800.00 68.31 800.00 62.37 797.15 11.490 Clearance Factor Pass- Survey tool program From To Survey/Plan Survey Tool (usft) (usft) 26.50 1,750.00 MPU C-46 wp04 SRG-SS 1,750.00 4,800.00 MPU C-46 wp04 MWD+IFR2+MS+sag 4,800.00 10,087.18 MPU C48 wp1:14 MWD+IFR2+MS+sag 16 March,2017-18:30 Page 5 of 8 COMPASS • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU C-46-MPU C-46 wp04 Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 16 March,2017- 18:30 Page 6 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU C-46-MPU C-46 wp04 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to As-Built @ 41.72ustt. Northing and Easting are relative to Plan:MPU C46. Coordinate System is US State Plane 1927(Exact solution),Alaska Zone 04. Central Meridian is-150.00°,Grid Convergence at Surface is:0.45°. $.MPC-09 MPC__-0_9 MPC-09 V6 * MPC-10,MPC-10,MPC-10 V1 Ladder Plot 4- MPC-11,MPC-11,MPC-11 V1 -4- MPC-12,MPC-12,MPC-12V9 MPGI2,MPG12A,MPG12AV3 � i -1 (r -} MPG12,MPG12APB1 MPG12APB1 V6 ��' �� �� [] $ EEE 1050 �I Lo ' _ / C P� _ $ MPGI5,MPG15A,MPG15AV0 ►- �, -�(- MPG20,MPG20,MPG20V1 i $ MPC-23,MPC-23,MPG23V1 m 700 //P/I1 �_�� r , / $ MPG24,MPG24,MPG24V13 p., i l ) / ii/ fl $ MPG24,MPG24A,MPG24AV0 N i / / / i 4 'e j,t i $ MPC-24,MPG24APB1,MPG24AP61 V0 ( f r J J} -e- MPC-25,MPC-25,MPC-25V1 C1 ,PA r A $ MPC-25,MPG25A,MPG25AV1 a) A2.�of/r//,ir�'�� • -�f MPC-25,PIanMPC-25B,MPG258wp02V13 3 S r,��' :•. !',,,, , -*- MPG26,MPC-26,MPC-26 V5 _ 555er, _ -4- MPC-26,MPC-26 L1,MPG26L1V4 L ---7. / J J $, MPC-26,MPG26L1PB1,MPC-26L1PB1V1 i ' -6- MPG26,MPG26L1PB2,MPG26L1PB2V1 -6- MPC-26,MPC-26L1PB3,MPC-26L1P B3 V1 -I- MP C-28,MPC-28,MPC-26V1 0 1500 3000 4500 6000 7500 $ MPC-28,MPG28A,MPC-28AV6 -rel- MPC-36,MPC-36,MPC-36V3 Measured Depth(1500 ustt/in) -e- MPC-39,MPC39,MPC-39V3 -40"101r'L-4u,mrr 4u,Nlru-4u V IV 16 March,2017- 18:30 Page 7 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU C-46-MPU C-46 wp04 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor _.. - MPGUB,MF'-UB,MI't.-UOVO MPC-10,MPC-10,MPG10 V 1 10.00 - __� MPC-11,MPC-11,MPC-11 V1 MPG12,MPG12,MPG12V8 ` MPC-12,MPC-12A,MPC-12A V3 8.75- .. MPC-12,MPC-12APB1,MPC-12APB1 VS F.. MPC-13,MPC-13,MPC-13V4 - I I MPC-14,MPC-14,MPC-14 V1 �l �-- -_i . . . MPC-15,MPC-15,MPC-15 V1 .... /l 7.50- _._._ .-- r�� P' MPC -15A,MPG15AV0 IOC us o _ MPG20,MPG20,MPG20V1 If 6.25- -- - - F. MPC-23,MPC-23,MPC-23V1 p, _MPC-24,MPC-24,MPC-24V13 co u_ L-' MPC -24,MPG24A,MPG24AV0 c0 5.00- ■` _ _, MPG24,MPG24APB1,MPG24APB1V0 MPC-25,MPC-25,MPC-25 V1 a Cl) 3.75- -- '_, MPG25,MPG25A,MPG25AV1 MPC-25,Plan MPC-25B,MPC-25B wp02 V13 !t MPC-26,MPC-26,MPC-26V5 2.50- _ _ -._-; MPC-26,MPC-26L1,MPC-26L1 V4 Collision Avoidance Req- MPG-26,MPC-26L1 PB1,MPC-26L1 PB1 V1 MPC-26,MPC-26L1 PB2,MPC-26L1 PB2 V1 -No-Go Zone-Stop Drilling 1.25- -- ---- ------- -- -- - - --�- `• MPC-26,MPC-26L1PB3,MPC-26L1PB3 V1 f` MPC-28,MPC-28,MPC-25V1 - f: MPC-28,MPC-28A,MPC-28A V6 0.00 , i i , i i i a i i iiiii , , , , IiiiiiiIIiliiiiiiiii i i T i iiiiiiiii i MPC-36,MPt 36,MPC-36 V3 0 750 1500 2250 3000 3750 4500 5250 8000 6750 7500 8250 9000 MPG39,MPG39,MPG39 V3 Meowed Depth(1500 taftfin) MPC-40,MPC-40,MPC-40 V19 18 March,2017- 18:30 Page 8 o18 COMPASS • Schwartz, Guy L (DOA) From: Joe Engel <jengel@hilcorp.com> Sent: Friday,April 14, 2017 11:04 AM To: Schwartz, Guy L(DOA) Cc: Paul Mazzolini;Cody Dinger; Stan Porhola; Paul Chan Subject: Re: MPC-46 Sag Well completion (PTD 217-052) Attachments: MP C-46 Proposed Schematic 2017-04-13 (Frac String).pdf Ok.Thank you.Attached is the revised schematic for MP?C-46,with a ?packer added to the 4-1/2"tubing string. I appreciate the feedback. Let me know if you have any other questions. Thanks. Joe 805-235-6265 From:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Sent:Thursday,April 13, 2017 5:18 PM To:Joe Engel Subject: RE: MPC-46 Sag Well completion (PTD 217-052) Just a revised schematic is fine. I was expecting something more like MPU B-30's completion diagram (with packer). Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793- 1226 ) or(Guy.schwartz@alaska.gov<mailto:Guy.schwartz@alaska.gov>). From:Joe Engel [mailto:jengel@hilcorp.com] Sent:Thursday,April 13, 2017 4:51 PM To:Schwartz, Guy L(DOA)<guy.schwartz@alaska.gov> Subject: RE: MPC-46 Sag Well completion (PTD 217-052) Thank you for the forward,Guy. I will talk with the completion folks and see how we want to revise the design. 1 • • Should we resubmit the entire permit package,or will a revised schematic suffice? Thanks. Joe From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Thursday,April 13,2017 12:21 PM To:Joe Engel <jengel@hilcorp.com<mailto:jengel@hilcorp.com» Subject: FW: MPC-46 Sag Well completion (PTD 217-052) FYI... guess everyone is out of country!!! Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it,and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at(907-793- 1226)or(Guy.schwartz@alaska.gov<mailto:Guy.schwartz@alaska.gov>). From: Schwartz, Guy L(DOA) Sent:Thursday,April 13, 2017 12:00 PM To: Paul Chan (pchan@hilcorp.com<mailto:pchan@hilcorp.com>)<pchan@hilcorp.com<mailto:pchan@hilcorp.com»; pmazzolini@hilcorp.com<mailto:pmazzolini@hilcorp.com> Cc: Bettis, Patricia K(DOA)<patricia.bettis@alaska.gov<mailto:patricia.bettis@alaska.gov>> Subject: MPC-46 Sag Well completion (PTD 217-052) Paul, The PTD 217-052 for C-46 includes running a 41/2"tubing string after the CBL and the 7" casing is tested.As the tubing does not have a packer to isolate the casing the AOGCC will not approve this configuration if used to hydraulically fracture stimulate the well. I understand your motive to use this"annulus" for pressure monitoring during the stimulation but the AOGCC is firm on using two barriers during fracturing operations if at all feasible. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may 2 • • TRANSMITTAL LETTER CHECKLIST WELL NAME: W/` Art ( lCc i PTD: /Development Service Exploratory _Stratigraphic Test Non-Conventional FIELD: ille:/A-e_ 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. , API No. 50- - - - . (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name)in the attached application,the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(dX2)(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. 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