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216-070
David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 6/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250602 (IGB 25-001) Well API #PTD #Log Date Log Company Log Type Format AOGCC E-Set# KTU 43-6XRD2 50133203280200 205117 07/14/2014 POLLARD CBL PDF MPU C-15A 50029213580100 216070 07/06/2016 HALLIBURTON RCBL PDF LAS PPTX PBU L-103 50029231010000 202139 08/06/2002 SCHLUMBERGER USIT/TEMP/GR PDF PBU L-108 50029230900000 202109 06/30/2002 SCHLUMBERGER USIT/TEMP/GR PDF PBU L-111 50029230690000 202030 03/02/2002 SCHLUMBERGER USIT/TEMP/GR PDF TIF PBU S-104 50029229880000 200196 02/02/2001 SCHLUMBERGER USIT PDF PBU V-212 50029232790000 205150 12/14/2005 SCHLUMBERGER USIT PCU 04 50283201000000 201193 11/04/2001 SCHLUMBERGER USIT/CBL PDF TIF Please include current contact information if different from above. T40515 T40516 T40517 T40518 T40519 T40520 T40521 T40522 PDF MPU C-15A 50029213580100 216070 07/06/2016 HALLIBURTON RCBL LAS PPTX Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.03 08:26:36 -08'00' DATA SUBMITTAL COMPLIANCE REPORT 11/1/2016 Permit to Drill 2160700 Well Name/No. MILNE PT UNIT KR C -15A MD 9928 TVD 9250 Completion Date 7/18/2016 REQUIRED INFORMATION Mud Log Yes,✓ DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name ED C 27378 Digital Data ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C Log C ED C ED C ED C ED C ED C Operator HILCORP ALASKA LLC API No. 50-029-21358-01-00 Completion Status 1 -OIL Current Status 1 -OIL UIC No Samples Yes ✓ Directional Survey Yes Vz ROP -GM -ADR 21N MD, GM -ADR 21N TVD / "L06 27378 Digital Data 27378 Digital Data 27378 Digital Data 27378 Digital Data 27378 Digital Data 27378 Digital Data 27378 Digital Data 27378 Digital Data 27378 Digital Data 27378 Digital Data 27378 Digital Data 27378 Digital Data 27378 Log Header Scans 27433 Digital Data 27433 Digital Data 27433 Digital Data 27433 Digital Data 27433 Digital Data (data taken from Logs Portion of Master Well Data Maint) Log Log Run Interval OH / Scale Media No Start Stop CH Received Comments 7610 9928 7/14/2016 Electronic Data Set, Filename: MPC - 15A FS Final.las 7/14/2016 Electronic File: MPC -15A FS MD.cgm ' 7/14/2016 Electronic File: MPC -15A FS TVD.cgm 7/14/2016 Electronic File: MPC -15A- Definitive Survey.pdf 7/14/2016 Electronic File: MPC -15A -Definitive Surveys.txt 7/14/2016 Electronic File: MPC -15A FS MD.emf 7/14/2016 Electronic File: MPC -15A FS TVD.emf 7/14/2016 Electronic File: MPC -15A FS Final.dlis . 7/14/2016 Electronic File: MPC-15A_FS_Final.ver P 7/14/2016 Electronic File: MPC -15A FS MD.pdf 97/14/2016 Electronic File: MPC -15A FS TVD.pdf 7/14/2016 Electronic File: MPC -15A FS MD.tif ' 7/14/2016 Electronic File: MPC -15A FS TVD.tif 0 0 2160700 MILNE PT UNIT KR C -15A LOG ' HEADERS 7550 9990 7/27/2016 Electronic Data Set, Filename: MPC-15A.las 7/27/2016 Electronic File: C-15A.dbf 7/27/2016 Electronic File: C-15A.mdx 7/27/2016 Electronic File: C-15A.zip 7/27/2016 Electronic File: C -15A SCL.DBF - AOGCC Page 1 of 7 Tuesday, November 01, 2016 DATA SUBMITTAL COMPLIANCE REPORT 11/1/2016 Permit to Drill 2160700 Well Name/No. MILNE PT UNIT KR C -15A Operator HILCORP ALASKA LLC API No. 50-029-21358-01-00 MD 9928 TVD 9250 Completion Date 7/18/2016 Completion Status 1-0I1- Current Status 1-0I1- UIC No ED C 27433 Digital Data 7/27/2016 Electronic File: C -15A SCL.MDX ED C 27433 Digital Data 7/27/2016 Electronic File: C -15A TVD.DBF ' ED C 27433 Digital Data 7/27/2016 Electronic File: C -15A TVD.mdx ED C 27433 Digital Data 7/27/2016 Electronic File: c-15a.hdr ' ED C 27433 Digital Data 7/27/2016 Electronic File: c-15ar.dbf - ED C 27433 Digital Data 7/27/2016 Electronic File: c-15ar.mdx- ED C 27433 Digital Data 7/27/2016 Electronic File: MPU C -15A AM Report 6-18- 16.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPU C-1 5A AM Report 6-19- 16.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPU C -15A AM Report 6-20-, 16.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPU C -15A AM Report 6-21-- 16.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPU C-1 5A AM Report 6-22- 16.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPU C-1 5A AM Report 6-23-' 16.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPU C-1 5A AM Report 6-24- 16.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPU C -15A AM Report 6-25- 16.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPC -15A- Final Well Report.doc ED C 27433 Digital Data P7/27/2016 Electronic File: MPC -15A - Final Well Report.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: Hilcorp Milne Point MPC -15A Lithology Spreadsheet.xls ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_Lithology , Decriptions.doc ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A—Show Zone lithology.doc ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9680'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9680'MD.jpg.xml , ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9690'MD.jpg AOGCC Page 2 of 7 Tuesday, November 01, 2016 DATA SUBMITTAL COMPLIANCE REPORT 11/1/2016 Permit to Drill 2160700 Well Name/No. MILNE PT UNIT KR C -15A Operator HILCORP ALASKA LLC API No. 50-029-21358-01-00 MD 9928 TVD 9250 Completion Date 7/18/2016 Completion Status 1-0I1- Current Status 1-0IL UIC No ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9690'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9700'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9700'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9710'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9710'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9720'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9720'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9730'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9730'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9740'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9740'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9750'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9750'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9760'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9760'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9770'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9770'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9780'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9780'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9790'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9790'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9800'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9800'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9810'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9810'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9820'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9820'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9830'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9830'MD.jpg.xml AOGCC Page 3 of 7 Tuesday, November 01, 2016 DATA SUBMITTAL COMPLIANCE REPORT 11/1/2016 Permit to Drill 2160700 Well Name/No. MILNE PT UNIT KR C -15A Operator HILCORP ALASKA LLC API No. 50-029-21358-01-00 MD 9928 TVD 9250 Completion Date 7/18/2016 Completion Status 1-0I1- Current Status 1-0I1- UIC No ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9840'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9840'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9850'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9850'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9870'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9870'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9880'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9880'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9890'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9890'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9900'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9900'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9910'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9910'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9920'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC -15A 9920'MD.jpg.xml ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9930'MD.jpg ED C 27433 Digital Data 7/27/2016 Electronic File: MPC-15A_9930'MD.jpg.xml ED C 27433 Digital Data R 7/27/2016 Electronic File: MPC -15A - 5in Formation Log MD.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPC -15A - 5in Formation Log ' TVD.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPC -15A - Drilling Dynamics Log (� MD.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPC -15A- Drilling Dynamics Log ' {� TVD.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPC -15A- Formation Log MD.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPC -15A -Formation Log . TVD.pdf ED C 27433 Digital Data 7/27/2016 Electronic File: MPC -15A- Gas Ratio Log MD.pdf AOGCC Page 4 of 7 Tuesday, November 01, 2016 DATA SUBMITTAL COMPLIANCE REPORT 11/1/2016 Permit to Drill 2160700 Well Name/No. MILNE PT UNIT KR C -15A MD 9928 TVD 9250 ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data ED C 27433 Digital Data Operator HILCORP ALASKA LLC API No. 50-029-21358-01-00 Completion Date 7/18/2016 Completion Status 1 -OIL Current Status 1-0I1- UIC No 7/27/2016 Electronic File: MPC -15A - Gas Ratio Log TVD.pdf 7/27/2016 Electronic File: MPC -15A - LWD Combo Log - P MD.pdf 7/27/2016 Electronic File: MPC -15A - LWD Combo Log ' 1' TVD.pdf 7/27/2016 Electronic File: MPC -15A - 5in FORMATION LOG MD.tif 7/27/2016 Electronic File: MPC -15A - 5in FORMATION LOG TVD.tif 7/27/2016 Electronic File: MPC -15A - DRILLING DYNAMICS LOG MD.tif 7/27/2016 Electronic File: MPC -15A - DRILLING DYNAMICS LOG TVD.tif 7/27/2016 Electronic File: MPC -15A - FORMATION LOG MD.tif 7/27/2016 Electronic File: MPC -15A - FORMATION LOG TVD.tif 7/27/2016 Electronic File: MPC -15A - GAS RATIO LOG MD.tif 7/27/2016 Electronic File: MPC -15A - GAS RATIO LOG TVD.tif 7/27/2016 Electronic File: MPC -15A - LWD COMBO LOG. MD.tif 7/27/2016 Electronic File: MPC -15A - LWD COMBO LOG. TVD.tif 7/27/2016 Electronic File: MPC -15A Show Report # 1 Pixler , Plot.pdf 7/27/2016 Electronic File: MPC -15A Show Report # 1.pdf 7/27/2016 Electronic File: MPC -15A Show Report # 1.xls , 7/27/2016 Electronic File: MPC -15A Show Report # 2.pdf , 7/27/2016 Electronic File: MPC -15A Show Report # 3.pdf 7/27/2016 Electronic File: mpc-15A Show Report # 2 Pixler Plot.pdf 7/27/2016 Electronic File: mpc-15A Show Report # 2.xls AOGCC Page 5 of 7 Tuesday, November 01, 2016 DATA SUBMITTAL COMPLIANCE REPORT 11/1/2016 Permit to Drill 2160700 Well Name/No. MILNE PT UNIT KR C -15A MD 9928 ED C ED C Log C Log C ED C Log C TVD 9250 Completion Date 7/18/2016 27433 Digital Data 27433 Digital Data 27433 Log Header Scans 27433 Mud Log 27639 Digital Data 27639 Log Header Scans Well Cores/Samples Information: Name Cuttings INFORMATION RECEIVED Completion Report 0 Production Test Information " NA Geologic Markers/Tops Q COMPLIANCE HISTORY Completion Date: 7/18/2016 Release Date: 5/27/2016 Description 25 Interval Start Stop 7658 9928 Operator HILCORP ALASKA LLC API No. 50-029-21358-01-00 Completion Status 1 -OIL Current Status 1-0I1- UIC No 7/27/2016 Electronic File: mpc-15A Show Report # 3 Pixler Plot.pdf 7/27/2016 Electronic File: mpc-15A Show Report # 3.xls 0 0 2160700 MILNE PT UNIT KR C -15A LOG HEADERS 7657 9928 7/27/2016 Final Well Report - Mudlogging Data 2" MD/TVD Gas Ratio Log 2" MD/TVD Drilling Dynamics Log 2" MD/TVD LWD Combo Log 2" MD/TVD Formation Log 5" MD/TVD Formation Log 9/26/2016 Electronic File: 50-029-21358-01-00-9232016 15053 PM-2406-Hilcorp Alaska Frac Focus.pdf 404 CD - PTD Hydraulic Fracture Data 9 5" 114Q.41 EWffl'qt;-- Sent Received 7/8/2016 Sample Set Number Comments 1590 Directional / Inclination Data Mud Logs, Image Files, Digital Data ' / NA Core Chips Y& /NA Mechanical Integrity Test Information Y /e Composite Logs, Image, Data Files 0 Core Photographs Y ?G Daily Operations Summary (D Cuttings Samples ()NA Laboratory Analyses Y /E) NA Date Comments AOGCC Page 6 of 7 Tuesday, November 01, 2016 DATA SUBMITTAL COMPLIANCE REPORT 11/1/2016 Permit to Drill 2160700 Well Name/No. MILNE PT UNIT KR C -15A Operator HILCORP ALASKA LLC MD 9928 TVD 9250 Completion Date 7/18/2016 Completion Status 1-0I1- Current Status 1-011- Comments: -OIL Comments: Compliance Reviewed By: API No. 50-029-21358-01-00 UIC No Date: ( 1 2 ((�o AOGCC Page 7 of 7 Tuesday, November 01, 2016 21 6070 STATE OF ALASKA DATA -LoGUED ALASKA OIL AND GAS CONSERVATION COMMIS, N 27 6 3 9 Lo/1K/201% REPORT OF SUNDRY WELL OPERATIONS M K. BENDER 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing H Operations shutdown Ll Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ arforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: CT FCO 0 2. Name: 4. Well Class Before Work: 5. Permit to Drill Number: Hilcorp Alaska LLC Development Q Exploratory ❑ Stratigraphic❑ Service ❑ 216-070 3. Address: 6. API Number: 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-21358-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL047434 & ADL025516 MPU C -15A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point Unit / Sag River Oil Pool 11. Present Well Condition Summary: Total Depth measured 9,928 feet Plugs measured 9,845 feet true vertical 9,250 feet Junk measured N/A feet Effective Depth measured 9,845 feet Packer measured 6,845 & 6,908 feet true vertical 9,178 feet true vertical 6,548 & 6,607 feet Casing Length Size MD TVD Burst Collapse Conductor 80' 13-3/8" 105' 105' 1,740psi 750psi Surface 4,655' 9-5/8" 4,692' 4,584' 3,520psi 2,020psi Production 7,616' 7" 7,653' 7,307' 7,240psi 5,410psi Liner 3,020' 4-1/2" 9,928' 9,250' 8,430psi 7,500psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6# / 13Cr-80 / Vam Top 6,938' 6,635' 7" x 4-1/2" TNT 13Cr Perm Packers and SSSV (type, measured and true vertical depth) 7"x4-1/2" ZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): See schematic perforation interval. Treatment descriptions including volumes used and final pressure: Please see attachments. 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 65 14 50 3,444 207 Subsequent to operation: 246 105 140 3,452 209 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations 21 Exploratory❑ Development❑✓ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil � Gas U WDSPL Printed and Electronic Fracture Stimulation Data F21 �GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 316-409 Contact Paul Chan Email pchan@hilcorp.com Printed Name Bo York Title Operations Engineer y Signature Phone 777-8345 Date 9/23/2016 Form 10-404 Revised 5/2015 16- _(z-( (- X016) 4 RBDMS ;,,-/ SEP 2 6 2016 Submit Original Only Hilcorp Alaska, LLC I K KB Elev.: 50.4' / GL Elev.: 16.7 TD = 9,928 (MD) / TD = 9,250'(TVD) PBTD= 9,845' (MD) / PBTD= 9,178'(TVD) SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU C -15A Last Completed: 7/18/2016 PTD: 216-070 Tree CIW 4-1/16'5M 9-5/8" FMC M.P w/ 11" x 5M top flange. Wellhead Cmt w/ 250 sx Class G in 8-1/2" 4-%" 4" CIW "H" BPV Profile OPEN HOLE/ CEMENT DETAIL 13-3/8" Cmt to surface 9-5/8" Cmt w/1,315 sx Permafrost E/ 250sx Class G in a 12-1/4" Hole 7" Cmt w/ 250 sx Class G in 8-1/2" 4-%" Cmt w/ 304 sxs HalCem in 6-1/8" CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 48 / H-40 / Weld 12.5" Surface 105' 9-5/8" Surface 36 / K-55 / BTC 8.921" Surface 4,692' 7" Production 26 / L-80 / BTC 6.276" Surface 7,653' 4-1/2" Liner 12.6/13Cr-80/Vam TOP 1 3.958" 1 6,928 1 9,928' TUBING DETAIL 4-1/2" 1 Tubing I 12.6/13Cr-80/Vam TOP 1 3.958" Surf 6,938' WELL INCLINATION DETAIL KOP @ 3,000' MD Max Hole Angle = 36.8 deg at 8,888' MD Hole angle through perforated interval: 32° JEWELRY DETAIL No Depth Item 1 31' Tubing Hanger, 4-1/2" TC -II top & 5" TC -II btm 2 6,780' Halliburton "XD" Sliding Sleeve w/3.813" min ID 3 6,845' 7" x 4-1/2" Halliburton TNT 13Cr permanent packer 4 6,915' 4-1/2 "XN" profile with 3.725" No -Go 5 6,908' 7" x 4-1/2" Baker ZXP Liner top packer 6 6,938' 4-1/2" WLEG (Stung into Tie Back Receptacle) PERFORATION DETAIL Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup C1 7,226' 7,240' 6,904' 6,917' 14 Multiple Closed B -silts 7,314' 7,318' 6,986' 6,990' 4 Multiple Closed B -silts 7,338' 7,342' 7,009' 7,013' 4 Multiple Closed Kup A3 7,410' 7,430' 7,077' 7,096' 20 Multiple Closed Kup A2 7,442' 7,468' 7,107' 71132' 26 Multiple Closed Sag B 9,538' 9,575' 8,919' 8,950' 37 7/13/16 Open Sag A 9,575' 9,592' 8,950' 8,964' 17 7/13/16 Open Ref Log: 07 July 2016 HAL Jewelry Log. 3-1/8" Millennium, 6 SPF, 21 gm HMX Charges, 60° Phasing, EH D=0.34" / TTP= 24.9" Mid -pert: 8,884' TVDss / 9,557' MD WELL STIMULATION DETAIL 8/23/2003 -143,440# of 16/20 CarboBond Lite. GENERAL WELL INFO API: 50-029-21358-01-00 Drilled and Cased by AUD #3 - 5/31/1985 Swap to WAG INJ by Nabors 4ES -4/20/1995 Deepened by Doyon 14 -June 30, 2016 Revised by: TDF 9/21/2016 .4 k Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP C -15A Pumps 50-029-21358-01-00 1 216-070 1 8/21/16 8/27/16 Daily Operations: 8/17/2016 - Wednesday No activity to report. 8/18/2016 - Thursday No activity to report. 8/19/2016 - Friday No activity to report. 8/20/2016 -Saturday No activity to report. 8/21/2016 -Sunday MIRU SLB Frac equipment. 5 frac tanks in place with 450 bbls ea of 90 deg F fresh water. Sand Chief spotted and loaded with 123,560# 16/20 CarboBond light. PU Stinger Tree Saver and MU 3.760" OD x 2.25" ID mandrels and cup mandrel. Cups for 4-1/2" 12.61b tubing. Stab tree saver, PT flange to 4k, and stroke down - 120" stroke. Top of cups at 22" below tubing hanger. Set cups by bleeding 400 psi WHP. ASRC spot separator. Spot flowback tanks. RU flowback lines from separator to tanks. Rig up line to flow from separator to C-14. 8/22/2016 - Monday Spot remainder of frac equipment. Rig up treating line. Start up equipment, ensure all communications working with equipment, bucket test LAS, PT treating line against valves on treesaver. Low PT to 1,950psi/ high PT to 8,345psi. 81psi loss in 5 minutes. LRS PT line to inner annulus to 4k. Check and set pop -offs to 3,500psi. No Activity - Daylight work only. 8/23/2016 -Tuesday Frac crew on site. PJSM. Start equipment. Prime pumps. Mix up tank of gel in PCM. Hold PJSM with all on site. Discuss safety, emergency, roles and responsibilities, pump schedule. Pump up IA to 2,500psi for injection test. Open well to 462 psi SITP. Pump injection test using 30# linear gel fluid. SD. Monitor pressure. Pumped 150 bbls - Ave. rate 29 bpm. Ave. pressure - 3,714psi. ISIP = 2,280psi. Pump calibration Test with 300 bbls X-linked gel (YF130FIexD system). Displace with linear gel. Decision made to increase job size. Call for 20,000 lbs additional proppant. Ongoing frac modelling. Wait for proppant. Install new starter on Sand Chief. Offload proppant. Pumymain frac as per design using 30# YF130FIexD system. 500 bbl Pad.`1ppg. 2ppg-8ppg ramp. 9ppg-12ppg_ steps Linear Rel and 38 bbl _�i_e �l.fl sh,(Underflush_by 3bbls). Ave rate: 29.5 bpm, Ave pressure: 3,691 psi, Max pressure: 4,498 psi, Max prop cont.: 12.5 PPA, ISIP: 3,827 psi. Monitor pressure for 15 min. Shut in Well. Bleed down and evacuate all lines. Total water pumped: 1,775 bbls, Total slurry: 1,941 bbls, Freeze protect fluid: 38 bbls, Total proppant pumped: 143,440 lbs, Prop_pant placed in formation: 141.424 lbs. RD frac equipment and backside pump. Pull Tree Saver and flow cross. RD annulus lines and pop -offs. Prepare for post frac cleanout, clear out bleed tanks, spot and load water into uprights for coil cleanout, RU flow cross on tree and run inlet line Ito portable test seperator, stage CT equip. Hilcorp Alaska, LLC Weekly Operations Summary. Well Name Rig API Number Well Permit Number Start Date End Date MP C -15A Pumps 50-029-21358-01-00 1 216-070 8/21/16 8/27/16 Daily Operations: 8/24/2016- Wednesday MIRU Halliburton CTU. Crane unit. 18,340' of 2" CT. CV = 50 bbls. LRS portable test separator rigged up to take returns and complete frac flowback. BOPE test. Cut pipe, MU BHA #1 - 2.88" OD CTC, DFCV, JARS, HYD DISCO, 3.60" OD HYD G SPEAR. OAL = 10.77'. Protective sleeve is 4.83' long x 3.85" OD. Total length with sleeve = 15.6'. On well, PT to 3,500psi. Open well - initial T/ IA/OA = 991 psi / 0 psi / 0 psi. RIH for w/ BHA #1. Returns to portable test separator. Try to maintain 900-1000 psi WHIP - 20/64ths choke. Set down (pumping) and latch protective sleeve set in SS at 6,780' MD. SD pump. PU and observe 5k overpull and pull free. POOH cleanly through tubing. Slight overpulls through the tree due to close ID/OD tolerances. Tag up, shut in well, L/D tools. Sleeve Recovered. Slight scratches and flatted 0 -ring from POOH. MU BHA # 2 - 2.13" OD CRC, 2" OD DPCV, 2 x 5' stingers, 2.3" OD JSN. OAL = 12.1'. Stab on well. PT low and high 300/3,700psi. RIH circulating gelled fluid to 9,000'. RIH and dry tag at 9,267' CTD corrected to KB. Hard tag. Unable to initially jet thru TOS. Reduce WHP, increase pump rate and able to start cleaning out. Cleanout to 9,867' CTD (P.BTD) using slick 1% and gel sweeps. POOH at 80%;Returns during cleanout - linear gel in tubing, mostly X-linked gel from liner. Traces of proppant, maybe 1% other solids. Started getting some oil after 1st BU. CT pump rates during clean out - 2.7 bpm ave. Return rate - 2.6 to 3.5 bpm. Fluid pumped = 340 bbls / Fluids returned = 370 bbls / Ave choke setting-70/64ths. Tag up at surface. Shut in well. RD CT from well. Turn well over to LRS portable test separator. LRS POP well 2 hrs after shut in. Continue post frac cleanup / flowback. 8/25/2016 - Thursday Flowback and clean up well post Frac through LRS portable test separator. 535 bbls fluid recovered - 950 bpd - .2mm scf gas (diverted to production) - 195 psi FTP - 80% WC at 18:00 25 -Aug. 1078 bbls fluid recovered - 1,000 bpd - .2mm scf gas (diverted to production) - 197 psi FTP - 50% WC at 06:00 26 -Aug. 8/26/2016 - Friday Flowback and Cleanup well post frac. Divert gas down C-14 flowline. Well rates - —1,000 bpd /.2 mmscf / 40% WC. Divert all flow from Portable test separator directly to production via C-14. 8/27/2016 - Saturday RDMO LRS Portable Test Separator. 8/28/2016 - Sunday No activity to report. 8/29/2016 - Monday No activity to report. 8/30/2016 - Tuesday No activity to report. Hydraulic Fracturing Fluid Product Component Information Disclosure Job Start Date: 8/23/2016 Job End Date: 8/23/2016 State: Alaska County: Beechey Point RPI Number: 50-029-21358-01-00 Operator Name: Hilcorp Alaska, LLC Well Name and Number: MPC -15A Latitude: 70.48958000 Longitude: -149.52601700 Datum: NAD83 Federal Well: NO Indian Well: NO True Vertical Depth: 8,950 Total Base Water Volume (gal): 72,594 Total Base Non Water Volume: 0 Hydraulic Fracturing Fluid Composition: ::. will, UC Cfthemical i Diso•re Registry Chemical Maximum Maximum Abstract Ingredient Ingredient Trade Name Supplier Purpose Ingredients Service Concentration Concentration Comments Number in Additive in HF Fluid (CAS #) (% by mass)** (% by mass)** Water Schlumberger N/A Water (Including Mix 7732-18-5 80.31509 Water Supplied by Client)* J450 Schlumberger Stabilizing Agent Listed Below M002 Schlumberger Additive Listed Below J604 Schlumberger Crosslinker Listed Below M275 Schlumberger Bactericide Listed Below S526-1620 Schlumberger Propping Agent Listed Below J569 Schlumberger Breaker Listed Below L071 Schlumberger Clay Control Agent Listed Below J580 Schlumberger Gelling Agent Listed Below F103 Schlumberger Surfactant Listed Below Ceramic materials and 66402-68-4 wares, chemicals 96.60201 19.01601 Guar gum 9000-30-0 1.41074 0.27770 2-hydroxy-N,N,N- trimethylethanaminium chloride 67-48-1 0.60742 0.11957 Boronatrocalcite 1319-33-1 0.39750 0.07825 Ethylene Glycol 107-21-1 0.23013 0.04530 2,2',2"-nitrilotriethanol 102-71-6 0.15765 0.03103 Diammonium peroxodisulphate 7727-54-0 0.11174 0.02200 Propan-2-ol 67-63-0 0.08637 0.01700 2-butoxyethanol 111-76-2 0.08637 0.01700 Sodium hydroxide 1310-73-2 0.08553 0.01684 Alcohol, C11 linear, ethoxylated 34398-01-1 0.07933 0.01562 Vinylidene chloride/methylacrylate copolymer 25038-72-6 0.05388 0.01061 C12-15 alcohol ethyoxylated 68131-39-5 0.04305 0.00848 Sodium tetraborate 1330-43-4 0.03347 0.00659 Fumaric acid 110-17-8 0.01045 0.00206 Monosodium fumarate 7704-73-6 0.01045 0.00206 Boric acid 10043-35-3 0.01046 0.00206 Diatomaceous earth, calcined 91053-39-3 0.00774 0.00152 1-undecanol 112-42-5 0.00691 0.00136 Non -crystalline silica (impurity) 7631-86-9 0.00354 0.00070 Magnesium nitrate 10377-60-3 0.00155 0.00030 5 -chloro -2 -methyl -2h- isoth iazolol-3-one 26172-55-4 0.00083 0.00016 poly(tetrafluoroethylene) 9002-84-0 0.00077 0.00015 Magnesium chloride 7786-30-3 0.00077 0.00015 Magnesium silicate hydrate (talc) 14807-96-6 0.00063 0.00012 Diutan gum 125005-87-0 0.00052 0.00010 * Total Water Volume sources may include various types of water including fresh water, produced water, and recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% *** If you are calculating a percentage of total ingredients do not add the water volume below the green line to the water volume above the green line Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(1) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) 2-methyl-2h-isothiazol-3- one 2682-20-4 0.00025 0.00005 Acetic acid, potassium salt 127-08-2 0.00026 0.00005 Cristobalite 14464-46-1 0.00015 0.00003 Quartz, Crystalline silica 14808-60-7 0.00015 0.00003 Acetic acid(impurity) 64-19-7 0.00004 0.00001 * Total Water Volume sources may include various types of water including fresh water, produced water, and recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% *** If you are calculating a percentage of total ingredients do not add the water volume below the green line to the water volume above the green line Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(1) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) MPC -15A Prop Frac Treatment, As Measured Pump Schedule Stage Pressures & Rates MeasuredAs Pump Schedule Step f Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Step Ste I Ste p Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Prop p PPA) Prop Cone (PPA) Prop Mass (lb) 1 PAD 2 450.0 30.0 15.1 YF130FlexD 18900 29.6 0.0 0.0 2 2 1.0 PPA 60.0 29.6 2.0 YF130FIexD 2411 16/20 CarboBond Lite 1.1 0.2 2339 3 2.0 PPA 59.4 29.5 2.0 YF130FlexD 2322 16/20 CarboBond Lite 2.2 0.8 3671 4 3.0 PPA 60.0 28.0 2.2 YF130FIexD 2219 16/20 CarboBond Lite 3.4 2.4 6461 5 4.0 PPA 60.0 30.6 2.0 YF130FIexD 2117 16/20 CarboBond Lite 6.3 3.9 8654 6 5.0 PPA 60.0 30.5 2.0 YF130FIexD 2089 16/20 CarboBond Lite 7.9 0.4 9335 7 6.0 PPA 60.0 30.6 2.0 YF130FIexD 1989 16/20 CarboBond Lite 6.6 1.3 11444 8 7.0 PPA 60.0 30.6 2.0 1 YF130FIexD 1937 16/20 CarboBond Lite 7.3 2.6 12563 9 8.0 PPA 59.5 30.6 1.9 YF130FlexD 1842 16/20 CarboBond Lite 8.0 4.4 14155 10 9.0 PPA 60.0 30.5 2.0 YF130FlexD 1784 16/20 CarboBond Lite 9.2 6.9 15857 11 10.0 PPA 60.0 30.5 2.0 YF130FlexD 1727 16/20 CarboBond Lite 10.1 8.4 17099 12 11.0 PPA 60.0 30.5 2.0 YF130FIexD 1677 16/20 CarboBond Lite 11.4 10.6 18183 13 12.0 PPA 89.1 30.5 2.9 YF130FIexD 2495 16/20 CarboBond Lite 12.5 0.0 27050 14 JWF Flush 1 98.0 30.0 3.5 1 WF130 4116 0.0 0.0 0 15 Freeze Protect 43.0 12.8 4.9 Freeze Protect 1806 0.0 0.0 0 Stage Pressures & Rates Step f Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) 1 PAD 29.5 30.0 3091 3656 1234 2 PAD 2 30.0 30.3 3640 3908 1140 3 1.0 PPA 29.6 30.2 3868 3907 3837 4 2.0 PPA 29.5 29.6 3796 3836 3743 5 3.0 PPA 28.0 30.6 3654 3737 3591 6 4.0 PPA 30.6 30.6 3552 3591 3514 7 5.0 PPA 30.5 30.6 3538 3593 3499 8 6.0 PPA 30.6 30.7 3602 3615 3585 9 7.0 PPA 30.6 30.7 3605 3613 3597 10 8.0 PPA 30.6 30.6 3605 3619 3597 11 9.0 PPA 30.5 30.6 3638 3668 3613 12 10.0 PPA 30.5 30.6 3689 3704 3665 13 11.0 PPA 30.5 30.6 3725 3750 3693 14 12.0 PPA 30.5 30.6 3765 3797 3735 15 WF Flush 130.0 1 30.6 4316 4745 3673 16 Freeze Protect 1 12.8 1 15.1 3154 4347 0 schiumbeplep Client: Hilcorp Alaska Well: MPC -15A Formation: Sag River District: Prudhoe Bay Country. United States Average Treating Pressure: 3691 psi Maximum Treating Pressure: 4745 psi Minimum Treating Pressure: 0 psi Average Injection Rate: 29.5 bbl/min Maximum Injection Rate: 30.7 bbl/min Average Horsepower: 2679.9 hhp Maximum Horsepower: 3537.8 hhp Maximum Prop Concentration: 12.5 PPA Schlumbepp Section 8: DataFRAC Plots FracCAT DataFRAC PRC n N w w a E a d m Tient: Hilcorp Alaska Well: MPC -15A Formation: Sag River District: Prudhoe Bay Country: United States Hilcorp Alaska LLC Milne Point C-15 August 23, 2016 1 FracCAT DataFRAC PCM Additives Time - hh:mm:ss Hilcorp Alaska LLC Milne Point C-15 August23,2016 10- U J604 9 — U028 45 — F103 — L071 8 PCM Vinosity 40 — Slurry Rate — Clean Fluid Rate 7 35 g 30 5 25 q 20 3 15 2 10 1 5 0 0 08:15:51 08:32:31 08:49:11 09:05:51 09:22:31 Time - hh:mm:ss rn C A m m 3 '13 n 0 Schlumbepgop .hent: Pp Alaska MC - Well: MPC -15A Formation: Sag River District: Prudhoe Bay Country: United States Section 9: Main Treatment Plots 500 400 300 ww a D: ~ 200 100 M FracCAT DataFRAC PRC Hik:orpAlaska LLC Milne Point C-15 August 23, 2016 0 40 T—ng Pressure Amid r, Pressure Sl-yRe Clean Flud Rei Nw C- 0. 2H P,. CO, 30 0- 20 0 .._.__..__. 10 0 0 1 :47:37 12:04:17 12:20:57 12:37:37 12:54:17 Time - hh:mm:ss © Schlumberger 19942012 Schlumberger THE STATE Ell X V - I 1 0- 11 GOVERNOR BILL WALKER Bo York Area Operations Manager Hilcorp Alaska, Inc. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Sag River Oil Pool, MPU C -15A Permit to Drill Number: 216-070 Sundry Number: 316-409 Dear Mr. York: Conservati®n 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 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, Cathy P. toerster Chair DATED this /9 day of August, 2016. RBDMS L, L-' AUG 15 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ECEIVE'& 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 Casing ❑ Other. _CT FCO 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development 0 Stratigraphic ❑ Service ❑ 216-070 - 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 50-029-21358-01-00 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 21 MPU C -15A 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL047434, 25516 Milne Point Unit / 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): 9,928' 9,250' 9,845' 9,178' 3,206 NIA N/A Casing Length Size MD Ti Burst Collapse Conductor 80' 13-3/8" 105' 105' 1,740psi 750psi Surface 4,655' 9-5/8" 4,692' 4,584' 3,520psi 2,020psi Production 7,616' 7" 7,653' 7,307' 7,240psi 5,410psi Liner 3,020' 4-1/2" 9,928' 9,250' 8,430 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic Detail See Schematic Detail 4-1/2" 13CR-80 6938' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 7"1 ZXP Liner Top Packer and N/A 6,845' MD 16,547' TVD and NIA 12. Attachments: Proposal Summary ❑✓ Wellbore schematic ❑✓ 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: 8/23/2016 Commencing Operations: 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. Contact Paul Chan �v Email chap hilcor .com Printed Name Bo York Title Area Operations Manager o Signature Phone 777-8345 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. -1 Plug Integrity ❑ BE]^OP Test Mechanical Integrity Test ❑ Location Clearance Other. lyrerl� 3i n <.c:. c"L QC'7 t i` oNo Post Initial Injection MIT Req'd? Yes [ ❑ i Spacing Exception Required? Yes ❑ No 0 Subsequent Form Required: `O _ /1 OL4 RBDMS L V PIG 15 2016 APPROVED BY Approved by: �r—� COMMISSIONER THE COMMISSION Date: i / (& o W r/1 0/101 � x 1 �y oR11"Go Lid Submit Form and Fo 10-403 Revised 11/2015 1 c i for 12 months from the date of approval. Att chments in Duplicate Hilcorp Alaska, LLC August 4TH, 2016 Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Paul Chan Senior Operations Engineer (907)777-8333 Cathy Foerster, Chair RECEIVED Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 1400 AUG 0 4 2016 Anchorage, Alaska 99501 AOGCC RE: Hydraulic Fracturing Application, Milne Point Unit, MP C -15A Dear Commissioner Foerster, Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Milne Point Unit, herein submits its application to fracture stimulate MP C -15A. Please do not hesitate to contact Paul Chan at 907-777-8333 should you have any questions regarding this application. Sincerely, Bo Yo, Operations Manager HILCORP ALASKA, LLC Enclosures: Form 10-403 Sundry Attachments Hilcoep Alaska, LLI Well Prognosis Well: MPU C -15A Date: 08/04/2016 Well Name: MPU C -15A API Number: 50-029-21358-01 Current Status: Oil Well Pad: C -Pad Estimated Start Date: August 22ND' 2016 Rig: N/A Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 216-070 First Call Engineer: Paul Chan (907) 777-8333 (0) (907) 444-2881 (M) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) AFE Number: Current Bottom Hole Pressure: 4,081 psi @ 8,750' TVD (SBHPS 07/14/2016 / 8.98 ppg EMW) Maximum Expected BHP: 4,081 psi @ 8,750' TVD (No new perfs being added) MPSP for SL or CTU: 3,206 psi (0.1 psi/ft gas gradient) MPSP: 3,985 psi (Calculated fracture stimulation pump pressure) CjN.:1(&-moi `/ F Brief Well Summary: MPU C-15 was drilled and completed with a single selective completion in June 1985, fracture stimulated in September and converted to water injection in December 1986. The well was worked over April 1995 in preparation for WAG injection. The well has being deepened to the Sag River formation as well MP C - 15A. The Sag River formation has been perforated and the well placed on production. Due to low productivity, the well will be fracture stimulated. Notes Regarding Wellbore Condition • 7" Production Casing tested to 3,600 psi for 30 minutes down to 6,845' MD on 07/19/2016 • 4-1/2" Production tubing and 4-1/2" liner tested to 4,950 psi for30 minutes on 06/30/2016 Objective: Fracture stimulate the Sag River formation. Procedure: See attachments as per 20 AAC 25.283 Coil Tubing Unit Fluid Flow Diagram Fill Cleanout Coil Tubing Unit Fluid Flow Diagram oa r + sY• I.ta; Cleanout w/ Nitrogen 500 BBL KILL TANK SEAWATER I W/ FOAMER 4008BLUPRIGHT SEAWATER I W/ 400 BBL UPRIGHT FOAMER 50 BBL FREEZE PROTECT TANK Updated 11/22/15 LEGEND: Fluids Pumped . Fluids Returned Q Valve Open r Valve Closed Wd Gate Valve C'4 Ball Valve M4 • � e .i 1• ram .- -,..•-...�i111�C�r �/r��r. Pressure Gauge Q — r..To r ` I0'0t Flowline 50 BBL FREEZE PROTECT TANK Updated 11/22/15 LEGEND: Fluids Pumped . Fluids Returned Q Valve Open M Valve Closed Wd Gate Valve C'4 Ball Valve M4 Butterfly Valve Lo Torq Valve Check Valve Manual Choke 'A Pressure Gauge Q 11 STANDARD WELL PROCEDURE I itcorpAlaska,LL(: NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -Job Safety Meeting. 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/O2 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.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 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 MPC -15A 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 MPC -15A 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 4th day of August 2016. (L Paul an, Sr. Operations Engineer Hilcorp Alaska, LLC STATE OF ALAKSA THIRD JUDICIAL DISTRICT SUBSCRIBED TO AND SWORN before me this 4th day of August 2016 JUL (0 r(0� NOTARY PUB IC IN AND FOR q..* NOTARY' .try, r THE STATE OF ALSKA My Commission expires: o� •.ter �.t: N 0F ALP. 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 i ADL0474 + ADL0.47_433, Sec 11 F Sec. 10 R � t i MILNE f POINT i UNIT i WIPU G PAD — -- t f 1t � U013N010E _ r � ar ,t � r a +. IV, +, o + e. Sec. 15 ,.•"0 Sec. 14 ADL025516 .' ADL047437 Legendr« s• . /tiz� e Top of Frac Zone • Base of Frac Zone f� MPC 15A SHL MPC-15A Half-mile Radius from SHL MPC-ISA-Well Trajectory (definitive survey) HAK Petra Well Database; MPC-15A Definitive Survey Milne Point Unit No Water Wells within 112 mile apDaW7 81 MPC-15AWell 0 500 1,000 mommommorMap Date.728120�6 Feet Plat depicting the MP C -15A well location with no water wells within % mile radius of MP C -15A surface location ® MPC -03 C-39 MPC -39 Legend C-10 MPC -10 C-11 e MPc-v Sec. 10 ADL047434 Sec: 11 C-26L1PB2 . C,26 MPC-26LI PB2 ADL041433 MPC=26 C-26L1PB1 C-20 MPC -26 1PB1- - C-26L1PB3 0 f01�A,r .'a,- • ► pC20 MPC-26L1PPW" •ti C -26L1.-0 _W MPC-26L1 P,^,PUC pCISA C-15 t ,PAD MtLNE MPC -15 i .. POINT + UNIT i w j C-14, j - MPt-14 i PC -15A U013NO10E i • C-24 C-13 0 MPC -24 C-24APB1 ► ® MPC -13 MPC-24APB1 i • I C -24A • MPC44A "e, Sec: 15 _ ADL047437 4 # ADL025516 "�. C-06 •;., .:'ngpc'-os Sec. 14 112 Mile Radius - MPC15A Wellbore Oil and Gas Lease !-.1% ADL025516 116— J 112 Mite Radius - MPC15A Frac Zone „ WELL SYMBOL (Kuparuk) Frac Zone ADL047433 INJECTOR Top of Frac Zone ADL047434 ` PLUG BACK • Base of Frac Zone ,., ADL047437 -- SHUT-IN �-- C-01 Sag Trajectory OIL -ACTIVE Other Well Trajectories P&A (Kuparuk) HAK Petra Wel Milne Point Unit MPC -15A Well Map Data: 7!2912016 MPC -22A C-22 MPC -22 q0C-22A 13A Sec. 23 Database; MPC -15A Definitive Survey 0 500 1,000 1,500 Feet Plat depicting all well types within % mile of MP C -15A f Plat depicting all Sag wells within % mile of MP C -15A i. Sec. 11 Sec. 10 .r, ADL047434 it fix* iii .,... t ; MPU:C. AfPC_j'5 # aafl MILNE i POINT • UNIT i R i R " f - R i U013NO10E ' = i � t i ♦ i Sec. 14 Sec. 15 �. ADL047437 ............ ADI-0251516 Legend 1/2 Mile Radius - MPC15A Wellbore Oil and Gas Lease 1/2 Mile Radius - MPC15A Frac Zone _ ADL025516 Frac Zone Lf,ADL047433 * Top of Frac Zone ADL047434 WELL SYMBOL • Base of Frac Zone 1� IL (ACTIVE) : ADL047437 O Sec: 23 HAK Petra Well Database; MPC-15A Definitive Survey Milne Point Unit MPC-15A Well Map Date: 712912016 0 500 1,000 1,500 Feet Plat depicting all Sag wells within % mile of MP C -15A 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" 36#/ft K-55 buttress surface casing set at 4692' MD and cemented with 1315 sxs of Permafrost "E" lead cement with 5#/sx gilsonite and 250 sxs of Class "G" tail cement with 3% NaCl/1% CFR -2. 7" 26#/ft L-80 buttress production casing set at 7653' MD and cemented with 250 sxs of Class "G" cement with 0.3% Halad 24/1% CFR -2. External casing packers located at 7374' MD and 7395' MD. 4-%' 12.6#/ft 13Cr-80 liner from 6908'-9928' MD. Centralizers run from 8774'-9928' MD. 4-%" liner cemented with 83 bbls of 15.8 ppg HalCem cement. The liner was rotated and reciprocated during the cement job until wellbore conditions dictated otherwise. Detailed Casing Information Size Type Wt/ Grade/ Conn Pipe Body Yield (lbs) Collapse Pressure (psi) Internal Yield Pressure (psi) Conductor N/A N/A N/A N/A 9-5/8" Surface 36 / K-55 / BTC 1,086,000 2,020 3,520 7" Production 26 / L-80 / BTC 676,000 5,410 7,240 4-'/z" Liner 12.6 / 13Cr-80 / Vam Top 288,000 7,500 8.430 Detailed Tubing Information 4-'/2" Tubing 12.6 / 13Cr-80 / Vam Top 288,000 7,500 8,430 20 AAC 25.283 (a)(6) Assessment of Each Casing and Cementing Operation Performed to Construct or Repair the Well MP C-15 was constructed in accordance with 20 AAC 25.030. 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/Na Br 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%" 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. All hydrocarbon zone penetrated by the wellbore are isolated and all casing and liner strings are cemented in accordance with 20 AAC 25.030. 7750 7800 7850 09KAILI 7950 IR414F--- -T4 y"J --i- t asx asx Al it" Th, 8000 8050 8100 P -MI -11 8200 4- -+4-4-4 4 Um sm 8350 8400 800 8500 8550 :m 8650 8700 8750 8800 RM 8950 9000 9050 I 9150 9200 9250 9300 nwo mol 9450 0 D 9500 9550 9600 9700 i qiy t 9750 44 5 _ _r �_ _ .. .� - I � I i 9800 f %✓it f f i i ' r y' l"- - I 300 TT (usec) 200 0 Amplitude (mV)150 AVG Sector Amplitude 200 MSG 1200 SECTORS ----------------------- CCL Amplitude x10 0 150 -50 500 0 100 0 Gamma 200 0 (mV) 15 MAX Sector Amplitude 300(Line Tens (lb) 0 0 150 MIN SectorAmplitude - 0 150 ----------------------- MAIN PASS REPEAT PASS Database File hilcorp_c15a_rcbl_rmt3d_6july16.db Dataset Pathname pass13 Presentation Format szrcbl Dataset Creation Wed Jul 06 16:17:00 2016 Charted by Depth in Feet scaled 1:240 300 TT (usec) 200 0 Amplitude (mV)150 AVG Sector Amplitude 200 MSG 1200 SECTORS ----------------------- CCL Amplitude x10 0 150 -50 500 0 100 0 Gamma 200 0 (mV) 15 MAX Sector Amplitude 300(Line Tens (lb) 0 T 0 150 MIN SertnrAmnlitnriP 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 2000 psi during initial cementing operations on May 25, 1985. The 7" casing was pressure tested to 3100 psi on May 5, 2016 as part of the pre -rig prep. The 7" casing ,✓ was pressure tested to 3600 psi on July 19, 2016 (post -rig MIT). The 4%" liner and tubing tested to 4950 psi for 30 minutes on June 30, 2016 in preparation for the 4 fracture stimulation. Note: As part of the test of the 4-1/2" liner and completion, the 7" casing between the 4-%" x 7" production packer and the 4-%" liner top packer was exposed to 4950 psi of pressure, which is 69% of the rated internal yield pressure of the 7" 26 #/ft L-80 casing. 20 AAC 25.283 (a)(8) Pressure Ratings and Schematics for the Wellbore, Wellhead, BOPE, and Treating Head Size Weight #/ft Grade API Collapse Pressure (psi) API Internal Yield Pressure (psi) 9-5/8" 36 K-55 2,020 3,520 7" 26 L-80 5,410 7,240 4-'/2" 12.6 13Cr-80 7,500 8.430 Treating 15M Head Wellhead 5M BOPE N/A 0 IIiicorp Alaska, LLC KB Elev.: 50.4' / GL Elev.: 16.7' 13-3/8" ON �2 3 4 SCHEMATIC CASING DETAIL Milne Point Unit Well: MPU C -15A Last Completed: 7/18/2016 PTD: 216-070 Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 48 / H-40 / Weld 12.5" Surface 105' 9-5/8" Surface 36 / K-55 / BTC 8.921" Surface 4,692' 7" Production 26 / L-80 / BTC 6.276" Surface 7,653' 4-1/2" Liner 12.6/13Cr-80/Vam TOP 3.958" 6,928 9,928' TUBING DETAIL 4-1/2" 1 Tubing I 12.6/13Cr-80/Vam TOP 1 3.958" Surf 6,938' JEWELRY DETAIL No Depth Item 1 31' Tubing Hanger, 4-1/2" TC -II top & 5" TC -II btm 2 6,780' Halliburton "XD" Sliding Sleeve w/3.813" min ID 3 6,845' 7" x 4-1/2" Halliburton TNT 13Cr permanent packer 4 6,915' 4-1/2 "XN" profile with 3.725" No -Go Closed 6,908' 7" x 4-1/2" Baker ZXP Liner top packer 65 6,938' 4-1/2" WLEG (Stung into Tie Back Receptacle) PERFORATION DETAIL Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup C1 7,226' 7,240' 6,904' 6,917' 14 Multiple Closed B -silts 7,314' 7,318' 6,986' 6,990' 4 Multiple Closed `\1 B -silts 7,338' 7,342' 7,009' 7,013' 4 Multiple Closed Kup A3 7,410' 7,430' 7,077' 7,096' 20 Multiple Closed Kup A2 7,442' 7,468' 7,107' 7,132' 26 Multiple Closed Sag B 9,538' 9,575' 8,919' 8,950' 37 7/13/16 Open Sag A 9,575' 9,592' 8,950' 8,964' 17 7/13/16 Open Ref Log: 07 July 2016 HAL Jewelry Log. 3-1/8" Millennium, 6 SPF, 21 gm HMX Charges, 60` Phasing, EHD=0.34" / TTP= 24.9" Mid -pert: 8,884' TVDss / 9,557' MD h Sag B gf36 r Sag A iS°t0 TD = 9,928 (MD) / TD = 9,25U(TVD) PBTD = 9,845' (MD) / PBTD = 9,17&(TVD) OPEN HOLE/ CEMENT DETAIL 13-3/8" Cmt to surface 9-5/8" Cmt w/1,315 sx Permafrost E/ 250sx Class G in a 12-1/4" Hole 7" Cmt w/ 250 sx Class G in 8-1/2" 4-%" Cmt w/ 304 sxs HalCem in 6-1/8" WELL INCLINATION DETAIL TREE & WELLHEAD Tree CIW 4-1/16" 5M FMC MY w/ 11" x 5M top flange. Wellhead 4" CIW "H" BPV Profile GENERAL WELL INFO Created By:LEK 5/6/2016 Modified by: CD 8/3/2016 NPC -15A 7-1-16 Note, this tbg HGr can be plugged on top for B®PE equipment testing Swab Valve CIW 4 1/16" 5K, manual gate valve, EE PSL2,PR2 PN 141522-31X02-01 Wine valve CIW FL -4 1/16" SK, reverse actuating gate valve, EE.PSL2,PR2 w/ CIW 03/03 actuator. Assy PN SSV CIW FL -4 1/16" 5K, reverse actuating gate valve, EE.PSL2,PR2 w/ ClW 03/03 Ass PN 14122-31-02-01 Master CIW 41/16" 5K„ manual gate valve, EE PSL2,PR2 PN 141522-31-02-01 ibR Hd adapter FMC 11" SK x 41/16" 5K, w/2ea'l3" control line preps and no penetrator preps. Centralized Bottom prepped for 4 Y"" seal sleeve,4" "H" r OIL STATES Energy Services (Canada) Inc. Maximum Allowable Pumping Rates PROPOSAL: Casing Isolation Tool SIZE CSG 'ID 2.250 •r 3.750 10 m3/min 3 1/2" Big Bore 1.750 2.750 6 m3/min 2 718" & 3 1/2" 1.438 2.360 4 m'/min 2 3/8" 1.000 . 1.900 2 m'/min 3 1116 & 4 1/16 with tapered mandrel 2.750 4.000 15 m'/min 41116 X Tool Mandrel 3.610 4.750 24 m3/min wcauu ax cto 15M Treating Head OPEN POSITION CLOSED POSITION �,,:KN:JFI VlSEC'F0� www.StingerCanada.com 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 9,501' MD / 8887' TVD. The estimated fracture gradient for the Sag River interval is 0.575 psi/ft. The overlying confining zone consists of 1312' TVD of Kingak shales. The top Kingak shale is at 7933' MD / 7575' TVD. The estimated fracture gradient for the Kingak is 0.689 psi/ft. The underlying confining zone consists of 168' TVD of Shublik mixed carbonates, siltstones and shales. The top Shublik is at 9,595' MD / 8,967' TVD. The estimated fracture gradient for the Shublik is 0.601 psi/ft. 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 wellbore. The Kingak shale will provide a competent barrier to these wellbores. MP C-01 is the only well penetrating the Sag River formation within %2 mile radius of the MP C -15A wellbore. 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. There are no other penetrations into the Sag River formation within % mile radius of the subject well. 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 \ l MPC -01 MPC -15A ss � 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 -15A 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 % mile radius of the proposed MPC - 15A 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 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. MIRU frac fleet. MIRU frac and slop tanks. MIRU CTU and associated equipment. Stump test CT BOPE, if possible. MIRU all ancillary support equipment. 2. Fill frac tanks with filtered 2%KCI brine. Heat water as needed. 3. Lay all hardlines and manifolds. Install pressure monitoring equipment on wellhead and tree. 4. RU 15K tree saver and hard line. 5. Pressure test all high pressure treating lines to 8000 psi. 6. Set the GORV (gas operated relief valve) at ±6800 psi. Set the staggered pump kickouts between 6800 psi and 6300 psi. �-- 7. Pressurize annulus to 2500 psi. Set annular PRV at 3500 psi. 8. Prepare frac fleet to pump. 9. Pump Sag DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 10. Fracture stimulate Sag interval with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule" for proposed design. 11. Underdisplace by 3 bbls. Do not over displace. 12. Shut well in. RDMO. i 9 13. RU CTU BOPE and PT to 3500 psi. RIH a�1d cleanout frac sand/frac fluid to a portable test / separator with filtered 2% KCI brine and NZ as needed to 9,843' MD. 14. POOH jetting liner and tubing clean. RD CTU. 15. RU SL. Pull sleeve from XD sliding sleeve. Drift and tag tubing to maximum TD with GR/JB. 16. Brush sliding sleeve. Shift sleeve open. Set jet pump. RDMO. 17. 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 The total wlumr listed in the tables above represents the summation of water and odtfiri . Water n .supplied by dknt. CAS Number _ Client: Hilcorp Alaska, LLC Schbeppr Well: MPCrj — Sorbitol Basin/Field: Milnee Point _ State: Alaska 67.48-1 __,.....,__._.-,.-.._.... County/Parish: North Slope Borough - <1 % Case: 6859766 , ._ .............. ...... __ ---- Propan-2-ol Disclosure Type: Pre -Job --- Well Completed: 7/16/2016 110-17-8 Date Prepared: 6/17/2016 3:24 PM % Report 10: RPT -43023 The total wlumr listed in the tables above represents the summation of water and odtfiri . Water n .supplied by dknt. CAS Number _ Chemical Name Water (including Mix Water Supplied by Client)* Mass Fraction 82 % _ 50-70-4 — Sorbitol <01 % 64-19-7 _ _ - Acetic acid(impuray) - <0.0001 % 67.48-1 __,.....,__._.-,.-.._.... .... ...--, ._ .,,,,.. 2-h rotry_N N N tnmethylethanammmm chloride . - <1 % 67-63-0 , ._ .............. ...... __ ---- Propan-2-ol . _..- _ ____-...,.. ....__. ...____ ._.._ <0.1 % 107-21-1 ----------------------- --- EthyleneGlycol -- ----------- ------ _ <0.1 % --------------- 110-17-8 Fumaricacid<0.01 % 111-76-2 - - -- -_- ---------._ 2-butoethanol w _ <0.1 % 112-42-5 - -----...------_xy�._... - - - --- ---- 1-undecanol -- -- -- - _ <0.01 % __ - _ ___ __ -_ 127.08.2 _ _ - _ - Acetic acid, potassium salt < 0.0001 % 1310 73 2 Sodium hydroxlde <0.1 % --1319-33-1 Boronatrocalcite <01 % 1330434 - --- - - - -- Sodium tetraborate <0.01 % „____- 2682-20.4 . ------ ---- 2 -methyl 2h-isothiazol-3-one _ - - <0.0001 % 7631-86-9 Silicon Dioxide _ '0.001 % 7704.73-6 Monosodium_fum_arate 7727-54-0 _ - - Diammonium peroxodisulPhate < 0.01 % 7786-303 Magnesium chloride -- <0001 % 900030-0 -- < 1 % 9002-84-0 poly(tetrafluoroethylene) < 0.0001 % 10043-35-3 Boric acid < 0.01 % 10377 60-3M nesium nnrate < 0,001 % 14464-46-1 Cristobalite <0.0001 % 14807.96-6 Magnesium silicate hydrate (talc) < 0.0001 % 14808 60 7Quartz, Crystalline silica _ <0.0001 % 25038J2 6 Vinylidene chloride/methylacrylate copolymer < 0.01 % --- -. 26172-55-4 __ - -- -- - 5-chloro-2-methyl-2h-isothiazolol-3-one 34398-01-1 Alcohol, C11 linear, ethoxylated _ _ Distillates petroleum, hydrotreated light -- —t-- - - - <0.1 % «. < 1 % 64742-47-8 66402-68-4 Ceramic materials and wares, chemicals _ _ -17% 68131-39-5 - C12-15 alcohol ethyoxylated <0.01 % 68153.30-0 -- - Amine treated smectite clay - ------ - - -- - •; <0.01 %_ 91053-39-3 --�--- Diatomaceous earth, calcined < 0.01 % 125005-87-0 Diutan gum hux water Is supplied by the «rent. Schlumberger has pejormed no analysis of the water and cannot provide a breakdown of components that may have been added to the woterby thhd-ponies. ® Schlumberger 2016. Used by Hikorp Alaska, UC by permission. Page: 1 / 1 Schlumbepp FracCADE* STIMULATION PROPOSAL Operator Hilcorp Alaska Well MPC -15 Field Milne Point Formation Sag River Well Location : County North Slope Borough State Alaska Country : United States Prepared for Paul Chan Service Point Prudhoe Bay Proposal No. Business Phone 907 2731700 Date Prepared 26 Jul 2016 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 and should be used for comparison purposes ratherthan absolute values. The quality of input data, and hence results, maybe 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 bythe treatment proposed herein it is the Operator's responsibility to notifythe 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 Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough loadcase 120kibs Contents schloOgep Section 1: Wellbore Configuration.................................................................................................. 3 Section2: Zone Data...................................................................................................................... 4 Section 3: Propped Fracture Schedule.......................................................................................... 6 Section 4: Propped Fracture Simulation......................................................................................... 8 Section 5: Propped Fracture Simulation Results.......................................................................... 11 Section 6: Fluid Descriptions........................................................................................................ 13 Section 7: Treatment Fluid Data................................................................................................... 14 Section8: Proppant Data............................................................................................................. 15 Section9: Hole Survey................................................................................................................. 16 Pa Client Hilcorp Alaska Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120kibs Section 1: Wellbore Configuration Bottom Hole Temperature --------------- 35 degF Deviated Hole ------------------------------- YES Treat Down TUBING Well Type ------------------------- ----------Vertical 3.960 Well Location ------------------------------- OnShore Tubing Data OD (in) Weight (Ib/ft) ID (in) Depth (ft) 4.500 12.6 3.960 6938.0 Casing Data OD (in) Weight (Ib/ft) ID (in) Depth (ft) 7.000 26.0 6.276 6938.0 4.500 12.6 3.960 9928.0 Perforation Data Top MD (ft) Top TO (ft) Bottom MD (ft) Bottom TO (ft) Shot Density (shot/ft) Number Diameter (in) 9538.0 8918.6 9575.0 8949.9 6.00 222 0.32 9575.0 8949.9 9592.0 8964.2 6.00 102 0.32 scI II 11POOP Client Hilcorp Alaska Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120klbs Section 2: Zone Data schlmhorgop Formation Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.in0.5) Kingak 8699.0 80.0 0.682 5962 2.957E+6 0.36 1000 Kingak 8779.0 68.0 0.693 6104 2.672E+6 0.36 1000 Kingak 8847.0 27.0 0.702 6224 2.365E+6 0.37 1000 Sag D 8874.0 7.0 0.574 5095 3.909E+6 0.26 1000 Sag D 8881.0 9.0 0.607 5392 3.118E+6 0.29 1000 Sag C 8890.0 13.0 0.626 5573 2.685E+6 0.31 1000 Sag C 8903.0 8.0 0.585 5213 3.852E+6 0.27 1000 Sag C 8911.0 5.2 0.559 4982 4.161 E+6 0.25 1000 Sag B 8916.2 3.8 0.544 4851 4.295E+6 0.23 700 Sag B 8920.0 19.0 0.539 4816 4.110E+6 0.23 1200 Sag B 8939.0 7.3 0.555 4964 4.229E+6 0.24 1200 Sag B 8946.3 3.7 0.570 5096 4.451 E+6 0.26 700 Sag A 8950.0 16.0 0.569 5101 4.313E+6 0.26 1200 Sag A 8966.0 5.0 0.571 5123 4.630E+6 0.26 1200 Sag A 8971.0 2.0 0.605 5427 5.286E+6 0.29 1000 Sag A 8973.0 5.0 0.591 5306 4.887E+6 0.28 700 Shublik 8978.0 3.7 0.625 5616 6.739E+6 0.31 1000 Shublik 8981.7 2.3 0.655 5887 8.427E+6 0.34 1000 Shublik 8984.0 3.0 0.640 5749 8.298E+6 0.32 1000 Shublik 8987.0 4.0 0.620 5575 8.381E+6 0.31 1000 Shublik 8991.0 8.0 0.590 5304 7.928E+6 0.28 700 Shublik 8999.0 6.2 0.546 4916 7.262E+6 0.23 1200 Shublik 9005.2 5.5 0.554 4990 6.598E+6 0.24 700 Shublik 9010.7 3.8 0.617 5560 4.361 E+6 0.29 1000 Shublik 9014.5 31.0 0.580 5239 5.043E+6 0.27 700 Shublik 9045.5 10.5 0.635 5745 3.969E+6 0.32 1000 Shublik 9056.0 24.8 0.627 5686 4.465E+6 0.31 1000 Shublik 9080.8 9.2 0.579 5257 5.868E+6 0.27 1000 Shublik 9090.0 20.0 0.606 5513 5.148E+6 0.29 1000 SHALE 9110.0 9.0 0.698 6360 8.794E+6 0.36 1000 SILTSTONE 9119.0 20.0 0.636 5803 8.502E+6 0.32 1000 SILTSTONE 9139.0 16.0 0.595 5440 6.121E+6 0.28 1000 SILTSTONE 9155.0 7.0 0.620 5679 7.282E+6 0.30 1000 SHALE 9162.0 7.0 0.556 5092 6.082E+6 0.24 1000 SILTSTONE 9169.0 17.0 0.603 5537 6.581 E+6 0.29 1000 DIRTY -SANDSTONE 9186.0 18.0 0.556 5117 5.403E+6 0.25 700 DIRTY -SANDSTONE 9204.0 55.0 0.525 4843 5.025E+6 0.21 700 Client Hilcorp Alaska Weil MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 12Oklbs schlumtopoep Formation Transmissibility Properties Zone Name Top TVD (ft) Net Height (ft) Perm (md) Porosity M Res. Pressure (psi) Gas Sat. M) Oil Sat. (%) Water Sat. M Kingak 8699.0 0.1 0.001 1.0 4090 65.0 10.0 25.0 Kingak 8779.0 0.1 0.001 1.0 4124 65.0 10.0 25.0 Kingak 8847.0 0.1 0.001 1.0 4147 65.0 10.0 25.0 Sag D 8874.0 1.0 0.100 10.0 4155 65.0 10.0 25.0 Sag D 8881.0 1.5 0.100 10.0 4158 65.0 10.0 25.0 Sag C 8890.0 2.0 0.100 10.0 4164 65.0 10.0 25.0 Sag C 8903.0 1.0 0.100 10.0 4168 65.0 10.0 25.0 Sag C 8911.0 0.1 0.001 1.0 4172 65.0 10.0 25.0 Sag B 8916.2 3.0 1.000 10.0 4100 65.0 10.0 25.0 Sag B 8920.0 19.0 10.000 14.0 4100 65.0 10.0 25.0 Sag B 8939.0 7.3 10.000 14.0 4100 65.0 10.0 25.0 Sag B 8946.3 3.0 2.000 12.0 4100 65.0 10.0 25.0 Sag A 8950.0 16.0 10.000 14.0 4100 65.0 10.0 25.0 Sag A 8966.0 5.0 10.000 14.0 4197 65.0 10.0 25.0 Sag A 8971.0 0.5 0.100 10.0 4199 65.0 10.0 25.0 Sag A 8973.0 3.0 2.000 12.0 4201 65.0 10.0 25.0 Shublik 8978.0 0.1 0.001 1.0 4203 65.0 10.0 25.0 Shublik 8981.7 0.1 0.001 1.0 4204 65.0 10.0 25.0 Shublik 8984.0 1.0 0.100 10.0 4205 65.0 10.0 25.0 Shublik 8987.0 1.0 0.100 10.0 4207 65.0 10.0 25.0 Shublik 8991.0 6.0 1.000 12.0 4210 65.0 10.0 25.0 Shublik 8999.0 6.2 5.000 14.0 4213 65.0 10.0 25.0 Shublik 9005.2 4.0 1.000 12.0 4216 65.0 10.0 25.0 Shublik 9010.7 1.0 0.100 10.0 4218 65.0 10.0 25.0 Shublik 9014.5 25.0 1.000 12.0 4226 65.0 10.0 25.0 Shublik 9045.5 2.0 0.100 10.0 4236 65.0 10.0 25.0 Shublik 9056.0 4.0 0.100 10.0 4244 65.0 10.0 25.0 Shublik 9080.8 2.0 0.100 10.0 4252 65.0 10.0 25.0 Shublik 9090.0 5.0 0.100 10.0 4259 65.0 10.0 25.0 SHALE 9110.0 0.1 0.001 1.0 4266 65.0 10.0 25.0 SILTSTONE 9119.0 2.0 0.100 10.0 4272 65.0 10.0 25.0 SILTSTONE 9139.0 2.0 0.100 10.0 4281 65.0 10.0 25.0 SILTSTONE 9155.0 2.0 0.100 10.0 4286 65.0 10.0 25.0 SHALE 9162.0 0.1 0.001 1.0 4289 65.0 10.0 25.0 SILTSTONE 9169.0 3.0 0.100 10.0 4295 65.0 10.0 25.0 DIRTY -SANDSTONE 9186.0 12.0 1.000 10.0 4306 65.0 10.0 25.0 DIRTY -SANDSTONE 9204.0 35.0 1.000 10.0 4320 65.0 10.0 25.0 Client : Hilcorp Alaska clur�r Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120kibs Section 3: Propped Fracture Schedule Pumping Schedule The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 258.1 ft with an average conductivity (Kfw) of 4264 md.ft. Fluid Totals 38568 gal of YF130FlexD Proppant Totals 119400 Ib of 16/20 CarboBond Pad Percentages % PAD Clean 43.6 % PAD Dirty 38.1 Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (gal) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 30.0 YF130FlexD 8400 30.0 0.00 0.0 PPA 30.0 YF130FlexD 2100 30.0 0.00 PAD 2 30.0 YF130FlexD 8400 30.0 0.00 1.0 PPA 30.0 YF130FlexD 2007 30.0 16/20 CarboBond Lite 1.00 2.0 PPA 30.0 YF130FIexD 1922 30.0 16/20 CarboBond Lite 2.00 3.0 PPA 30.0 YF130FlexD 1844 30.0 16/20 CarboBond Lite 3.00 4.0 PPA 30.0 YF130FIexD 1772 30.0 16/20 CarboBond Lite 4.00 5.0 PPA 30.0 YF130FlexD 1705 30.0 16/20 CarboBond Lite 5.00 6.0 PPA 30.0 YF130FlexD 1643 30.0 16/20 CarboBond Lite 6.00 7.0 PPA 30.0 YF130FlexD 1586 30.0 16/20 CarboBond Lite 7.00 8.0 PPA 30.0 YF130FlexD 1532 30.0 16/20 CarboBond Lite 8.00 9.0 PPA 30.0 YF130FlexD 1482 30.0 16/20 CarboBond Lite 9.00 10.0 PPA 30.0 YF130FlexD 1435 30.0 16/20 CarboBond Lite 10.00 11.0 PPA 30.0 YF130FlexD 1391 1 30.0 1 16/20 CarboBond Lite 1 11.00 12.0 PPA 30.0 YF130FlexD 1350 1 30.0 1 16/20 CarboBond Lite 1 12.00 Fluid Totals 38568 gal of YF130FlexD Proppant Totals 119400 Ib of 16/20 CarboBond Pad Percentages % PAD Clean 43.6 % PAD Dirty 38.1 Client Hilcorp Alaska Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120klbs Scllcrgcr Summary for This Stage: Average Pump Rate Volume Weighted Average Rate Total Fluid Volume Total Proppant Mass Total Slurry Volume Total Pump Time Pumping Schedule Totals 30.0 bbl/min 30.0 bbl/min 38568 gal 119400 Ib 1050.0 bbl 35.0 min Fluid Based Totals for This Stage Average Job Execution Total Total Total Total Step Name Step Fluid Volume (gal) Cum. Fluid Volume (gal) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (Ib) Cum. Prop. (I b) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 8400 8400 200.0 200.0 0 0 3951 6.7 6.7 0.0 PPA 1 2100 10500 50.0 250.0 0 1 0 3970 1.7 8.3 PAD 2 8400 18900 200.0 450.0 0 0 39 6.7 15.0 1.0 PPA 2007 20907 50.0 500.0 2007 2007 3437 1.7 16.7 2.0 PPA 1922 22829 50.0 550.0 3844 5851 3307 1.7 18.3 3.0 PPA 1844 24673 50.0 600.0 5531 11382 3211 1.7 20.0 4.0 PPA 1772 26444 50.0 650.0 7087 18468 3146 1.7 21.7 5.0 PPA 1705 28149 50.0 700.0 8525 26993 3137 1.7 23.3 6.0 PPA 1643 29792 50.0 750.0 9859 36852 3173 1.7 25.0 7.0 PPA 1586 31378 50.0 800.0 11100 47952 3257 1.7 26.7 8.0 PPA 1532 32910 50.0 850.0 12257 60209 3371 1.7 28.3 9.0 PPA 1482 34392 50.0 900.0 13338 73546 3490 1.7 30.0 10.0 PPA 1435 35827 50.0 950.0 14350 87897 3511 1.7 31.7 11,0 PPA 1391 37218 50.0 1000.0 15301 103198 3243 1.7 33.3 12.0 PPA 1350 38568 50.0 1050.0 16195 119393 2886 1.7 35.0 Summary for This Stage: Average Pump Rate Volume Weighted Average Rate Total Fluid Volume Total Proppant Mass Total Slurry Volume Total Pump Time Pumping Schedule Totals 30.0 bbl/min 30.0 bbl/min 38568 gal 119400 Ib 1050.0 bbl 35.0 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/rrtin) (bbl/min) (gal) (lb) (bbl) (min) YF130FIexD 30.0 30.0 38568 119393 1050.0 35.0 NOR 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) (lb) (bbl) (min) 16/20 CarboBond Lite 30.0 30.0 21768 119393 650.0 21.7 Client Hilcorp Alaska Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 12Oklbs Section 4: Propped Fracture Simulation schl6crgcr 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------------------------- 8920.0 ft Initial Fracture Bottom TO 8939.0 ft Propped Fracture Half -Length ---------------- 258.1 ft ` EOJ Hyd Height at Well------------------------- 186.1 ft Average Propped Width------------------------ 0.160 in Average Gel Concentration-------------------- 886.5 Ib/mgal Average Gel Fluid Retained Factor--------- 0.50 Net Pressure---------------------------------------- 947 psi Efficiency--------------------------------------------- 0.336 Effective Conductivity---------------------------- 6283 md.ft Effective Fcd 4.8 Max Surface Pressure--------------------------. 3985 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 64.5 12.1 0.205 183.8 1.79 286.0 5441 64.5 129.0 11.6 0.198 177.9 1.76 289.0 1 5344 129.0 193.6 11.2 0.182 142.2 1.63 866.7 5410 193.6 258.1 4.5 0.062 78.3 0.55 2058.0 1538 Proppant bridged at 238 ft after 5 bbl in step 10 8 Client Hilcorp Alaska Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120kibs m 115 In, 1' I' Fracture Geometry Data Per Zone for Production Prediction Zone Name Top MD (ft) Top TVD (ft) Gross Height (ft) Net Height Fracture Width (in) Fracture Length (ft) Fracture Conductivity (md.ft) Kingak 9274.5 8699.0 80.0 .1 0.000 .0 0 Kingak 9372.3 8779.0 68.0 .1 0.000 .0 0 Kingak 9453.5 8847.0 27.0 .1 0.019 164.4 517 Sag D 9485.4 8874.0 7.0 1.0 0.039 186.1 1028 Sag D 9493.6 8881.0 9.0 1.5 0.077 203.2 2054 Sag C 9504.3 8890.0 13.0 2.0 0.125 234.4 3303 Sag C 9519.6 8903.0 8.0 1.0 0.176 251.7 4600 Sag C 9529.1 8911.0 5.2 .1 0.211 257.9 5481 Sag B 9535.2 8916.2 3.8 3.0 0.236 258.1 6120 Sag B 9539.7 8920.0 19.0 19.0 0.258 258.1 6665 Sag B 9562.1 8939.0 7.3 7.3 0.253 258.1 6557 Sag B 9570.7 8946.3 3.7 3.0 0.242 258.1 6289 Sag A 9575.1 8950.0 16.0 16.0 0.220 255.1 5742 Sag A 9594.1 8966.0 5.0 5.0 0.193 247.7 5058 Sag A 9600.0 8971.0 2.0 .5 0.178 244.9 4664 Sag A 9602.4 8973.0 5.0 3.0 0.157 243.2 4156 Shublik 9608.4 8978.0 3.7 .l 0.139 231.2 3683 Shublik 9612.8 8981.7 2.3 .1 0.124 211.9 3303 Shublik 9615.5 8984.0 3.0 1.0 0.117 192.3 3112 Shublik 9619.1 8987.0 4.0 1.0 0.116 188.5 3086 Shublik 9623.8 8991.0 8.0 6.0 0.119 181.4 3179 Shublik 9633.4 8999.0 6.2 6.2 0.121 171.5 3236 Shublik 9640.8 9005.2 5.5 4.0 0.115 166.3 3063 Shublik 9647.4 9010.7 3.8 1.0 0.102 164.3 2718 Shublik 9651.9 9014.5 31.0 25.0 0.069 154.7 1839 Shublik 9688.8 9045.5 10.5 2.0 0.022 108.0 575 Shublik 9701.3 9056.0 24.8 4.0 0.003 4.1 74 Shublik 9730.6 9080.8 9.2 2.0 0.000 .0 0 Shublik 9741.5 9090.0 20.0 5.0 0.000 .0 0 SHALE 9765.0 9110.0 9.0 .1 0.000 .0 0 SILTSTONE 9775.6 9119.0 20.0 2.0 0.000 .0 0 SILTSTONE 9799.0 9139.0 16.0 2.0 0.000 .0 0 SILTSTONE 9817.6 9155.0 7.0 2.0 0.000 .0 0 SHALE 9825.7 9162.0 7.0 .1 0.000 .0 0 SILTSTONE 9833.9 9169.0 17.0 3.0 0.000 .0 0 DIRTY -SANDSTONE 9853.6 9186.0 18.0 - 12.0 0.000 .0 0 DIRTY -SANDSTONE 9874.6 9204.0 55.0 - 35.0 0.000 .0 0 Client Hilcorp Alaska Well MPC -15 Formation : Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120klbs schlumhPgop 10 Exposure Time Prediction by Step Step Name Fluid Name Pump Rate (bbl/min) Fluid Volume (gal) Perforation Injection Temp. (degF) Exposure at BHST of 235 degF (min) Exposure aboveWatch Temp. of 230 degF (min) PAD YF130FlexD 30.0 8400 163 1.4 1.4 0.0 PPA YF130FlexD 30.0 2100 115 1.6 1.6 PAD 2 YF130FlexD 30.0 8400 106 2.6 2.6 1.0 PPA YF130FIexD 30.0 2007 102 8.1 8.1 2.0 PPA YF130FlexD 30.0 1922 101 5.2 5.2 3.0 PPA YF130FlexD 30.0 1844 100 0.0 0.0 4.0 PPA YF130FlexD 30.0 1772 100 0.0 0.0 5.0 PPA YF130FlexD 30.0 1705 99 0.0 0.0 6.0 PPA YF130FIexD 30.0 1643 99 0.0 0.0 7.0 PPA YF130FIexD 30.0 1586 98 0.0 0.0 8.0 PPA YF130FlexD 30.0 1532 98 0.0 0.0 9.0 PPA YF130FIexD 30.0 1482 98 0.0 0.0 10.0 PPA YF130FlexD 30.0 1435 97 0.0 0.0 11.0 PPA YF130FlexD 30.0 1391 97 0.0 0.0 12.0 PPA YF130FlexD 30.0 1350 97 0.0 0.0 10 Client Hilcorp Alaska sttl{Ifill-gop Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120kibs Section 5: Propped Fracture Simulation Results (1) ACL Fracture Profile and Proppant Concentration Piot FracCADE* ACL Fracture Profile and Proppant Concentration Stress - psi Fracture# 1 Initiation MD =9 50 -0.2 -0.1 0 0.1 0.2 ACL Width at Wellbore -in Hilcorp Alaska MPC -15 120Wbs 26 Jul 2016 ..,- < 0.0 Ib/ft2 0.0 - 0.31b/ft2 0.3 - 0.6 Ib/ft2 0.6 - 0.9 I b/ft2 0.9 -1.1 Ib/ft2 1.1 -1.4 1b/f12 1.4 -1.7 1b/ft2 1.7 - 2.01 b/ft2 2.0-2.31b/ft2 > 2.3 Ib/ft2 0 100 200 300 400 500 Fracture Half -Length - ft *Mark of Schlumberger Schlumberger Client Hilcorp Alaska Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120kibs (2) Treating Plot Bdb"de Preastre ----- Se—Pr— -----•- Taal 1q. Rale EOJ 6D00 5000 4000 a` 3000 SCMUMWOOP ----------------- i i toxo i 0 10 20 30 40 53 00 Tre —t Ti— -mn 12 Client Hilcorp Alaska �clurg�r Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120kibs Section 6: Fluid Descriptions 2% KCI brine • M117, Potassium Chloride 166.00 Ib/mgal YF130FIexD • J891, Guar Polymer Slurry 6.97 gal/mgal • L071, Temporary Clay Stabilizer 2.00 gal/mgal • U028, Activator 2.00 gal/mgal • J604, Crosslinker 2.50 gal/mgal • F103, EZEFLO Surfactant 1.00 gal/mgal • M275, Microbiocide 0.30 Ib/mgal • J569, EB -CLEAN Med Temp Breaker 3.00 Ib/mgal • J450, Stabilizer 0.50 gal/mgal W F130 • M275, Microbiocide 0.50 Ib/mgal • L071, Temporary Clay Stabilizer 2.00 gal/mgal • J891, Guar Polymer Slurry 6.74 gal/mgal • F103, EZEFLO Surfactant 1.00 gal/mgal • J569, EB -CLEAN Med Temp Breaker 4.00 Ib/mgal 13 Client Hilcorp Alaska Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120klbs Section 7: Treatment Fluid Data Fluid data is given at 8.944 md. Scllrger Fluid Name 2% KCI brine YF130FIexD WF130 Friction Rate Low (bbl/min) 5.0 1.0 1.0 Pressure Low ( si/1000ft) 10.0 20.0 1.2 Rate Pivot (bbl/min) 25.0 10.0 30.0 Pressure Pivot (psi/i 000ft) 400.0 80.0 70.0 Rate High (bbl/min) 60.0 1 100.0 100.0 Pressure High (psi/1000ft) 1000.0 1 770.0 300.0 Fluid Loss CW (ft/min0.5) 1.0E+0 6.4E-3 6.4E-3 Spurt(gal/100ft2) 0.0 1.9 1.9 Ct (ft/min0.5) 1.4E-2 5.1E-3 5.1E-3 Rheology Temperature (degF) 235 235 235 Time (hr) 0.0 0.0 0.0 Behavior Index (N') 1.00 0.67 1.00 Consist. Index (K') (Ibf.s^n/ft2) 5.21E-6 5.18E-2 2.09E-5 Viscosity Q Shear Rate (0) 0.250 318.567 1.000 Shear Rate (1/s) 170 170 170 14 Client Hilcorp Alaska Well MPC -15 Formation Sag River District Prudhoe Bay Country North Slope Borough Loadcase 120klbs Section 8: Proppant Data Proppant Permeability is calculated based on the following parameters: BH Static Temperature: 235 degF Stress on Proppant: 2816 psi Propped Fracture Conc.: 1.00 Ib/ft2 Average Young's Modulus: 4.232E+06 psi Schl6orgor Proppant Data Proppant Name Specific Gravity Mean Diameter (in) Pack Porosity (°/D) Permeability (md) Jordan Unimin 20/40 2.65 0.022 35.0 192472 CarboLite 16/20 1 2.74 1 0.043 1 35.0 1 993334 16/20 CarboBond Lite 1 2.59 1 0.041 1 39.3 1 583325 1000DO Proppant Permeability Plot Pmppant Pesmaa Billty R— m Pr - 0 100D 2DOD 30th 4000 MW 8300 70M WM 9= 10000 11000 I= 13000 14WO ctmrre 9.. (ri) 15 --e— Jo d. Unimn --+7'-• Cab ,160 ....... 1620 (:arWEbrd Ute Prap Stress 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- % "production tubing and liner have been tested to 4950 psi for 30 minutes. The maximum differential pressure the tubing will be subjected to will be 4300 psi (6800 psi GORV maximum pressure setting - 2500 psi of pressure on the casing x tubing annulus). The calculated maximum treating pressure is 3,985 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: 1 9501' MD / 8887' TVD (ii) a description of each method and assumption used to determine designed fracture height and length: The MP C -15A fracture stimulation was modeled using Schlumberger FracCADE program. The input parameters are attached. 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. 6900 9106 O`r0 �• �\ � 01 dgSO .g .9�0 �`°a itif? l_ '9USp o 81s MPC•1 °A 9200 900 9 50 n /2 He ° � '- SO °° e9S0 �So o g fc, -8900-- PO 9-0 g95, / O (PSO -8900 950 (( unig Map provided by operator. Circle and annotation by AOGCC. SFD8/11/2016 MPU C -15A: Lower Confining Layers Shublik_Top II I Expected 1 It to f 1 layer Confining Barrier Formation Mechanical Properties Zone Name Top TVD Zone Frac Insitu�Young's Pois oughness (ft) Height Grad. Stress atio (pslAn0.5) (ft) (Psiltt) (psi)i) Shublik 9056.0 24.8 0.627 5686 4.465 0.31 1000 Shublik 9080.8 9.2 0.579 5257 5.868 0.27 1000 �'0.��p�siP Secondary Barrier (Not Shale layer Formation Mechanical Properties react�+ Zone Name Top TVD Zone Frac Insitu Young's son's Toughne ^--- - - - . - --,---__ (tt) Height Grad. Stress M Ratio 00 (psiAt) (psi "6 psi) SHALE 9110.0 9.0 0.698 636 . 4 0.36 1000 SILTSTONE 9119.0 20.0 0.636 803 8.502 0.32 1000 SILTSTONE 9139.0 16.0 0.595 5440 6.121 0.28 1000 Diagram provided by operator. Data tables from Schlumberger. Annotation by AOGCC. SFD8/11/2016 Formation Mechanical Properties Zone Name Top TVD (ft) Zone Height 00 Frac Grad. (psit t) Insitu Stress (psi) Young's Modulus (E"5 psi) Poisson's Ratio Toughness (pal.ino.5) Shublik 8978.0 3.7 0.625 5616 6.73 0.31 1000 Shublik 8981.7 2.3 0.655 5887 8.42 0.34 1000 Shublik 8984.0 3.0 0.640 5749 8.29 0.32 1000 Shublik 8987.0 4.0 0.620 5575 8.38 0.31 1000 Shublik 8991.0 8.0 0.590 5304 7.92 0.28 700 Shublik 8999.0 6.2 0.546 4916 7.26 0.23 1200 Shublik 9005.2 5.5 0.554 4990 6.59 0.24 700 Shublik 9010.7 3.8 0.617 5560 4.36 0.29 1000 Shublik Shublik 9014.5 9045.5 31.0 10.5 0.580 0.635 5239 5.04 0.27 0.32 700 1000 II I Expected 1 It to f 1 layer Confining Barrier Formation Mechanical Properties Zone Name Top TVD Zone Frac Insitu�Young's Pois oughness (ft) Height Grad. Stress atio (pslAn0.5) (ft) (Psiltt) (psi)i) Shublik 9056.0 24.8 0.627 5686 4.465 0.31 1000 Shublik 9080.8 9.2 0.579 5257 5.868 0.27 1000 �'0.��p�siP Secondary Barrier (Not Shale layer Formation Mechanical Properties react�+ Zone Name Top TVD Zone Frac Insitu Young's son's Toughne ^--- - - - . - --,---__ (tt) Height Grad. Stress M Ratio 00 (psiAt) (psi "6 psi) SHALE 9110.0 9.0 0.698 636 . 4 0.36 1000 SILTSTONE 9119.0 20.0 0.636 803 8.502 0.32 1000 SILTSTONE 9139.0 16.0 0.595 5440 6.121 0.28 1000 Diagram provided by operator. Data tables from Schlumberger. Annotation by AOGCC. SFD8/11/2016 Shublik Top —0.63psi/ft ExpectedSItStOne layer Confining Barrier —0.70psi/ft Secondary Barrier Shale layer (Not expected to reach that far) Ivishak Top Max Expected Fracture Interval (168' Height, 8892'— 9060' TVD) ��L4�vAA/�.t'�rf� 4 GL. �� o� pt -7,:1 � Ash � ��� W-- 7"� Davies, Stephen F (DOA) From: Anthony McConkey <amcconkey@hilcorp.com> Sent: Wednesday, August 10, 2016 4:30 PM To: Davies, Stephen F (DOA) Cc: Paul Chan; Daniel Yancey Subject: RE: MPU C -15A (PTD 216-070; Sundry Application 316-409) - Questions and Requests Attachments: C -15A Annotated Logs.pptx; MPC-15A_CONTOUR.PNG Hey Steve, I've attached some documents which should help satisfy the questions you have. The first slide contains an annotated C -15A log in which I labeled some of the zone tops as well as the confining siltstone and shale layers within the Shublik. The second slide shows similar annotations corresponding to the cement bond log, to more clearly show the cement integrity within the frac zones and confining layers. I've also attached an updated contour map with better labels. Please don't hesitate to call either of the numbers listed below or e-mail with any additional questions, Thanks! Anthony McConkey Reservoir Engineer Northern Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w) 907-777-8460 (c) 907-529-6199 From: Paul Chan Sent: Tuesday, August 09, 2016 2:21 PM To: Anthony McConkey Subject: FW: MPU C -15A (PTD 216-070; Sundry Application 316-409) - Questions and Requests Anthony Some questions we need to have answered Thanks Paul Chan Senior Operations Engineer Alaska North Slope Team Hilcorp Alaska LLC (907) 777 — 8333 (w) (907) 444 — 2881 (c) 1 L 110 1p,s \ Baso -8,812 Mudiw3 0 ` -9050 +9 8TS0 / l \ MPC.,6A - 9200 / I ..\............. -S. 837 OgS� 90 1p iP I 00 ?S0 n 00 1 sO 00 _ 610 lolp B9S Z900 ShublikTop —0.63psi/ft Expected Confining Barrier I.-Siltstone layer —0.70psi/ft Secondary Barrier Shale layer (Not expected to reach that far) Ivishak Top Max Expected Fracture Interval (168' Height, 8892'— 9060' TVD) Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Tuesday, August 09, 2016 1:51 PM To: pchan@hilcorp.com Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: MPU C -15A (PTD 216-070; Sundry Application 316-409) - Questions and Requests Paul, I'm reviewing Hilcorp's application to fracture -stimulate MPU C -15A, and I have some questions and requests. 1. 1 note in Hilcorp's application section 20 AAC 25.283(a)(9) that Hilcorp estimates the fracture gradient for the Sag River interval as 0.575 psi/ft and the gradient for the underlying Shublik as 0.601 psi/ft. Based on this apparent 0.026 psi/ft differential, how can Hilcorp be certain that fractures induced in the Sag River will not propagate to and through the Shublik, which is the lower confining layer? 2. Could Hilcorp please provide a copy of the structure map shown in application section 20 AAC 25.283(a)(11) which has legible contour labels? 3. Based on the cement bond log presented in application section 20 AAC 25.283(a)(6), how can Hilcorp ensure that fracturing fluids injected into the Sag River will not migrate down the wellbore into the underlying Shublik and Ivishak Formations? Thank you for your help. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU C -15A (PTD No. 216-070; Sundry No. 316-409) Paragraph Sub -Paragraph L (a) Application for ! (a)(1) Affidavit Sundry Approval (a)(2) Plat (a)(2)(A) Well location (a)(2)(8) Each water well within % mile a)(2)(C) Identify all well types within nile (a)(3) Freshwater aquifers: geological name section Complete?� Provided with application j SFD 8/5/2016 Provided with application SFD 8/5/2016 Provided on plat SFD 8/5/2016 None. Nearest water well is Milne Point Unit (MPU) A -2A located 1.4 miles to the SE, having a drilled depth of 3,603'. SFD (See LAS Case File 2280.) Nearest surface water: is 8/5/2016 located 0.8 miles SW. (See LAS Case File 1936.) MPU C-01 (1 -Oil), C-02 (WAGIN), C-06 (WAGIN), C-13 (1 - OIL), C-14 (1 -Oil), C-15 (P&A), C-20 (1 -Oil), C-24 (P&A), C - 24A (1 -Oil), C-24AP131 (lost while drilling), and C-261_1 (1- Oil). Of these, only C-01 was drilled to the Sag River Formation (Sag River); all of the other wells are, or were, Kuparuk Formation (Kuparuk) producers and injectors, SFD which reached total depth about 1,650' true vertical depth 8/9/2016 above the Sag River. In C-01, after an unsuccessful drillstem test of the Sag River, perforations in that reservoir were cement -squeezed and the well was plugged back to a depth of 7,624' MD (1,280' above the Sag River) using EZSV packers and cement in 1982. Aquifer Exemption Order No. 2 states that freshwater j aquifers lying directly below the MPU portion of the Kuparuk River Field qualify as exempt freshwater aquifers under 20 AAC 25.440. Also, Federal regulation 40 CFR 147.102(b)(3) exempts the portions of aquifers lying SFD directly below and % mile beyond the Kuparuk River Unit 8/8/2016 (KRU). In 1998, the EPA's Waste Water branch provided a map and coordinates for the boundary of this exempted KRU area, and it includes the Area of Review for the MPU AOGCC Page 1 August 12, 2016 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU C -15A (PTD No. 216-070; Sundry No. 316-409) I Paragraph Sub -Paragraph Section Complete? C -15A well along with a large portion of the current MPU . (See Kuparuk River Unit Area Exemption w Map 19980305, which is stored on the AOGCC's Geology drive.) (a)(3) Freshwater aquifers: measured and true vertical death Exempt (a)(4) Baseline water sampling plan Exempt (a)(5) Casing and cementing information provided (a)(6) Casing and cementing operation assessment (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 (a)(6)( B) Each hydrocarbon zone is isolated (a)(7) Pressure test: information and pressure -test plans for casing and tubing installed in well (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPS, treating head (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone SFD 8/8/2016 SFD 8/8/2016 CDW provided CDW Aquifers exempt per AEO 2. Surface casing set at 4,692' MD (-4,534' true vertical feet subsea) below Schrader Bluff SFD and Ugnu oil-bearing intervals. Surface casing cement 8/9/2016 operations successfully completed with returns to surface. Schrader Bluff and Ugnu isolated by 9-5/8" surface casing and cement. Kuparuk interval isolated by 7" casing with SFD top of cement estimated 500' above Kuparuk. 4 %" liner 8/9/2016 set across previously open Kuparuk perforations. gls _ 9 5/8" test to 2000 psi. 7" test to 3100 psi and 360 psi. 4 %2" liner and tubing test to 4950 psi. CDW 15M treating head schematic provided, 5M wellhead, I CDW Upper confinement by Kingak Shale that is about 1300' thick. Fractured interval is Sag River Formation: fine-grained, cemented, marine sandstone that is about 45' thick. Lower confinement by Shublik Formation siltstone and shale layers that are collectively about 20' thick. SFD 8/9/2016 AOGCC Page 2 August 12, 2016 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU C -15A (PTD No. 216-070; Sundry No. 316-409) EParagraph Sub -Paragraph Section Complete? 9(C) and (a)(9)(D) Measured and true Upper confinement -- Kingak shale top 7933' MD, 7575' TVD SFD cal depths Fractured interval — Sag River top 9501' MD, 8887' TVD 8/9/2016 Lower Confinement — Shublik top 9595' MD, 8967' TVD _ Upper confinement - Kingak shale (0.69 psi/ft) is expected to fully arrest vertical growth of the induced fractures. 1)(E) Fracture pressure for each zone Fractured interval (^'170' in height)— Sag River (0.575 SFD psi/ft) and the upper % of the Shublik (0.61 psi/ft) 8/11/2016 (a)(10) Location, orientation, report on mechanical condition of each well (a)(11) Sufficient information to determine wells will not interfere with containment within 'z mile (a)(11) Faults and fractures, Location, orientation (a)(11) Faults and fractures, Sufficient information to determine no interference with containment within % mile Lower Confinement — Shublik siltstone and shale layers (0.63 and 0.70 psi/ft, respectively) provided CDW Nearest well that penetrates the Sag River is MPU C-01, which is located 2300' to the NW within the Sag River reservoir. The Sag River in MPU C-01 has been abandoned: SFD perforations in the Sag River were cement squeezed and 8/9/2016 then isolated using packers and cement during 1982. Additionally, in 1994 a bridge plug was set at 7287' MD. The seismically derived fault map provided by the operator displays four small, normal faults that cut the top of the Sag River within the %-mile radius Area of Review (AOR). Three of these faults trend NW and they range in vertical displacement from 0' to 90' within the 1/2 mile AOR. They SFD are located 2500'S, 1000' SW, and 1200' NE of the planned 8/11/2016 fracture interval in MPU C -15A. According to Hilcorp's fracture model, the half-length of the induced fractures will be about 260'. The principal regional stress direction is estimated to be NW -directed, so growth of the induced fractures is anticipated to be parallel with these three AOGCC Page 4 August 12, 2016 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU C -15A (PTD No. 216-070; Sundry No. 316-409) Paragraph Sub -Paragraph T Section Complete? faults. Since the induced fractures will not approach these three faults, none of them are expected to interfere with containment. At the point of closest approach, the fourth fault lies about i 1200' NE of the planned fracture interval. This fault trends NE, and it ranges in vertical displacement from 0'—no displacement— at its point of first appearance on the map (1200' from MPU C -15A) to 90' displacement at the edge of the AOR, which is 2640' NE of C -15A. Since the induced fractures are anticipated to grow along a NW -directed trend from the wellbore, the fractures will not approach (a)(12) Proposed program for fracturing this fault, and it will not interfere with containment. operation (a)(12)(A) Estimated volume Provided plus pump schedule. CDW 918 bbl, 120K Ib proppant CDW (a)(12)(8) Additives: names, purposes, CDW concentrations Provided, no confidential CAS (a)(12)(C) Chemical name and CAS number CDW of each _ provided, Schlumberger (a)(12)(D) Inert substances, weight or CDW volume of each Provided, Schlumberger (a)(12)(E) Maximum treating pressure with Max surf press calc as 3985 psi. GORV to be set as 6800 psi supporting info to determine with2500 psi held backside meaning a 4300 psi tubing CDW appropriateness for program _ (a)(12)(F) Fractures — height, length, MD pressure (tubing test to 4950 psi) CDW and TVD to top, description of fracturing Schlumberger FracCADE model CDW (a)(13) Proposed program for post- fracturing well cleanup and fluid recovery Milne Point disposal well. AOGCC Page 5 August 12, 2016 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU C -15A (PTD No. 216-070; Sundry No. 316-409) Paragraph Sub -Paragraph Section Complete? (b)Testing of casing 9 5/8" test to 2000 psi. 7" test to 3100 psi and 3600 psi CDW or intermediate Tested >110% of max anticipated pressure (with expected backpressure of 2500 psi). 4 %2" liner and casing tubing test to 4950 psi with maximum anticipated pressure of 4300 psi. Permanent packer set at 6845 ft, liner top packer set at CDW below TOC (c) Fracturing string rod ctionPacko inter in production or intermediate casing 6908 ft, TOC for 7"estimated as 5364 gage to 5892 ft (30% exc.) (c)(2) Tested >110% of max anticipated Tubing and liner tested to 4900 psi (max surface pressure GLS pressure differential expected at 3980 psi. Test lines to 8000 psi, gas operated relief valve (GORY) set (d) Pressure relief Line pressure <= test pressure, remotely at 6800 psi with staggered pump kickouts between 6800 valve controlled shut-in device psi and 6300 psi. Max estimated line pressure during frac CDW is 3985 psi. Frac fluids confined to approved (e) Confinement ----------— - -- ---- _..-- expected --- ----- CDW formations (f) Surface casing Monitored with gauge and pressure relief IA PRV set at 3500 psi, holding IA at 2500 psi. during pressures device (g) Annulus stimulation. Wellhead and tree pressure monitoring. CDW pressure monitoring & 500 psi criteria notification (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i)Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (J) Post- rac water f - -- I AOGCC Page 6 August 12, 2016 Paragraph sampling plan (k) Confidential information (I) Variances requested 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU C -15A (PTD No. 216-070; Sundry No. 316-409) Sub -Paragraph Clearly marked and specific facts supporting nondisclosure Modifications of deadlines, requests for variances or waivers Section Complete? AOGCC Page 7 August 12, 2016 Davies, Stephen F (DOA) From: Anthony McConkey <amcconkey@hilcorp.com> Sent: Wednesday, August 10, 2016 4:30 PM To: Davies, Stephen F (DOA) Cc: Paul Chan; Daniel Yancey Subject: RE: MPU C -15A (PTD 216-070; Sundry Application 316-409) - Questions and Requests Attachments: C -15A Annotated Logs.pptx; MPC-15A_CONTOUR.PNG Hey Steve, I've attached some documents which should help satisfy the questions you have. The first slide contains an annotated C -15A log in which I labeled some of the zone tops as well as the confining siltstone and shale layers within the Shublik. The second slide shows similar annotations corresponding to the cement bond log, to more clearly show the cement integrity within the frac zones and confining layers. I've also attached an updated contour map with better labels. Please don't hesitate to call either of the numbers listed below or e-mail with any additional questions, Thanks! Anthony McConkey Reservoir Engineer Northern Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w)907-777-8460 (c) 907-529-6199 From: Paul Chan Sent: Tuesday, August 09, 2016 2:21 PM To: Anthony McConkey Subject: FW: MPU C -15A (PTD 216-070; Sundry Application 316-409) - Questions and Requests Anthony Some questions we need to have answered Thanks Paul Chan Senior Operations Engineer Alaska North Slope Team Hilcorp Alaska LLC (907) 777 — 8333 (w) (907) 444 — 2881 (c) 1 From: Davies, Stephen F (DOA) [mai Ito: Steve. daviesna alaska.gov] Sent: Tuesday, August 09, 2016 1:51 PM To: Paul Chan Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: MPU C -15A (PTD 216-070; Sundry Application 316-409) - Questions and Requests Paul, I'm reviewing Hilcorp's application to fracture -stimulate MPU C -15A, and I have some questions and requests. 1. 1 note in Hilcorp's application section 20 AAC 25.283(a)(9) that Hilcorp estimates the fracture gradient for the Sag River interval as 0.575 psi/ft and the gradient for the underlying Shublik as 0.601 psi/ft. Based on this apparent 0.026 psi/ft differential, how can Hilcorp be certain that fractures induced in the Sag River will not propagate to and through the Shublik, which is the lower confining layer? 2. Could Hilcorp please provide a copy of the structure map shown in application section 20 AAC 25.283(a)(11) which has legible contour labels? 3. Based on the cement bond log presented in application section 20 AAC 25.283(a)(6), how can Hilcorp ensure that fracturing fluids injected into the Sag River will not migrate down the wellbore into the underlying Shublik and Ivishak Formations? Thank you for your help. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov. ShubIikTop —0.63psi/ft Expected Confining Barrier Siltsto=ne layer —0.70psi/ft Secondary Barrier Shale layer (Not expected to reach that far) Ivishak Top Max Expected Fracture Interval (168' Height, 8892'— 9060' TVD) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑/ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 20AAC 25.105 20AAc 25.110 GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No. of Completions: 1 1b. Well Class: Development 01 Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 7/18/2016 14. Permit to Drill Number/ Sundry: 216-070 / 316-345 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: June 18, 2016 15. API Number: 50-029-21358-01-00 " 4a. Location of Well (Governmental Section): Surface: 724' FSL, 2098' FEL, Sec 10, T13N, R10E, UM, AK Top of Productive Interval: 515' FNL, 351' FEL, Sec 15, T13N, R10E, UM, AK Total Depth: 715' FNL, 354' FEL, Sec 15, T13N, R10E, UM, AK 8. Date TD Reached: June 24, 2016 16. Well Name and Number: MPU C -15A ' 9. Ref Elevations: KB: 50.4 GL:16.7 BF: 16.7 17. Field / Pool(s): Milne Point Unit / Sag River Oil Pool 10. Plug Back Depth MD/TVD: 9,845' MD / 9,178' TVD ' 18. Property Designation: ADL047434 (SHL) ADL025516 (TPH/BHL) 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 558366 y- 6029007 Zone- 4 TPI: x- 560124 y- 6027783 Zone- 4 Total Depth: x- 560123 y- 6027582 Zone- 4 11. Total Depth MD/TVD: 9,928' MD / 9,250' TVD - 19. Land Use Permit: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: —1,676' MD / 1,675' TVD 5. Directional or Inclination Survey: Yes . ✓❑tached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: 7,665' MD / 7,231' TVD 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 ROP -GM -ADR 2IN MD, GM -ADR 2IN TVDRECEi y p JUL 2 9 7016 23. CASING, LINER AND CEMENTING RECORD WT. PGRADE ER SETTING DEPTH MD HOLE SIZE CEMENTING RECORD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM PULLED 4-1/2" 12.6# 13CR-80 6,908' 9,928' 6,606' 9,250' 6-1/8" 83 bbls of 15.8 ppg 3 bbls 24. Open to production or injection? Yes Q No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number): 9,538'- 9,575' MD / 8,919'- 8,950' TVD COMPLETION 9,575'- 9,592' MD / 8,950'- 8,964' TVD DAT 3-1/8" 6 SPF VERIFIED L� 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4-1/2" 6,938' 6,845' MD / 6,547' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No ✓❑ Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 7/17/2016 Method of Operation (Flowing, gas lift, etc.): Jet Pump Date of Test: 7/23/2016 Hours Tested: 24 Production for Test Period Oil -Bbl: 94.2 Gas -MCF: 15.4 Water -Bbl: 0 Choke Size: N/A Gas -Oil Ratio: 163.6 Flow Tubing Press. 207.9 Casing Press: 3400 Calculated 24 -Hour Rate —.0o. Oil -Bbl: 94.2 , Gas -MCF: 15.4 Water -Bbl: 0 Oil Gravity - API (corr): 35 Form 10-407 Revis d 11201 CONTINUED 0 PAGE 2 Submit ORIGINIAL only 7'► 8r��6y d -�s !� RBDMS LL- Ail` - 2 2016 /`•.r1 28. CORE DATA Conventional C., _ks): Yes ❑ No ❑✓ Sidewall Cores. des ❑ No P] 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 ❑✓ If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 1,676' 1,675' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 9,538' 8,918' information, including reports, per 20 AAC 25.071. Kingak F 7,949' 7,590' Kingak B 9,279' 8,703' Sag River 9,501' 8,887' Shublik 9,595' 8,967' Eileen 9,794' 9,135' Sadelrochit 9,856' 9,188' Formation at total depth: Sadelrochit 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Days vs Depth, MW vs Depth, Casing and Cement Reports. 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. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Cody Dinger Email: cdin er hIICOr .com Printed Name: Cod D' er ) Title: Drilling Tech Q Z �f Signatur2�K Phone: 907-777-8389 Date: 1 INSTRUCTIONS General: This 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 1a: 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 1 b: 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 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 11/2015 Submit ORIGINAL Only Hileorp Alaska, LLC KB Elev.: 50.4' / GL Elev.: 16.7' TD = 9,928 (MD) / TD = 9,250'(TVD) PBTD = 9,845' (MD) / PBTD = 9,178'(TVD) SCHEMATIC CASING DETAIL Milne Point Unit Well: MPU C -15A Last Completed: 7/18/2016 PTD: 216-070 Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 48 / H-40 / Weld 12.5" Surface 105' 9-5/8" Surface 36 / K-55 / BTC 8.921" Surface 4,692' 7" Production 26 / L-80 / BTC 6.276" Surface 7,653' 4-1/2" Liner 12.6/13Cr-80/Vam TOP 1 3.958" 6,928 9,928' TUBING DETAIL 4-1/2" 1 Tubing I 12.6/13Cr-80/Vam TOP 1 3.958" Surf 1 6,938' JEWELRY DETAIL No Depth Item 1 31' Tubing Hanger, 4-1/2" TC -II top & 5" TC -II btm 2 6,780' Halliburton "XD" Sliding Sleeve w/3.813" min ID 3 6,845' 7" x 4-1/2" Halliburton TNT 13Cr permanent packer 4 6,915' 4-1/2 "XN" profile with 3.725" No -Go 5 6,908' 7" x 4-1/2" Baker ZXP Liner top packer 6 6,938' 4-1/2" WLEG (Stung into Tie Back Receptacle) PERFORATION DETAIL Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup C1 7,226' 7,240' 6,904' 6,917' 14 Multiple Closed B -silts 7,314' 7,318' 6,986' 6,990' 4 Multiple Closed B -silts 7,338' 7,342' 7,009' 7,013' 4 Multiple Closed Kup A3 7,410' 7,430' 7,077' 7,096' 20 Multiple Closed Kup A2 7,442' 7,468' 7,107' 7,132' 26 Multiple Closed Sag B 9,538' 9,575' 8,919' 8,950' 37 7/13/16 Open Sag A 9,575' 9,592' 8,950' 8,964' 17 7/13/16 Open Ref Log: 07 July 2016 HAL Jewelry Log. 3-1/8" Millennium, 6 SPF, 21 gm HMX Charges, 60° Phasing, EHD=0.34" / TTP= 24.9" Mid -pert: 8,884' TVDss / 9,557' MD OPEN HOLE / CEMENT DETAIL 13-3/8" Cmt to surface 9-5/8" Cmt w/1,315 sx Permafrost E/ 250sx Class G in a 12-1/4" Hole 7" Cmt w/ 250 sx Class G in 8-1/2" 4-%" Cmt w/ 304 sxs HalCem in 6-1/8" WELL INCLINATION DETAIL P @ 3,000' MD ix Hole Angle = 36.8 deg at 8,888' MD le angle through perforated interval: 32° TREE & WELLHEAD Tree CIW 4-1/16" 5M FMC MY w/ 11" x 5M top flange. Wellhead 4" CIW "H" BPV Profile GENERAL WELL INFO API: 50-029-21358-01-00 Drilled and Cased by AUD #3 - 5/31/1985 Swap to WAG INJ by Nabors 4ES - 4/20/1995 Deepened by Doyon 14 -June 30, 2016 Created By:LEK 5/6/2016 Modified by: PC 7/25/2016 Hilcorp Energy Company Composite Report Well Name: MP C-1 5A Field: Milne Point County/State: , Alaska i (LAT/LONG): avation (RKB): API #: Spud Date: Job Name: 1610896D MP C -15A DRILLING Contractor AFE #: AFE $: Activity Date Ops Summary 6/12/2016 PJSM, skid rig floor into move position, move rock washer, prep pad for pulling off well. R/D Doyon 14 camp to C-pad;PJSM, with well secure, move off J-28, position rig and Install rear boosters, cleanup around J-28, move rig mats. Mobilize and stage rig mats for rig move. Move rig camp to C-Pad;lnstall front gooseneck and front boosters, finish Matting soft road areas f/ J -Pad to I-Pad,;Notify MP security, move rig f/ J -Pad to I -Pad entrance,;Stage rig on I- Pad, Shuffle rig mats from behind rig to in front of rig.;Move rig from I -Pad access road to H -Pad entrance;Stage rig on H -Pad, Shuffle rig mats from behind rig to in front of rig.;Move rig from H -Pad to G-Pad;Stage rig on G -Pad, Shuffle rig mats from behind rig, Mat soft road areas f/ G -Pad to Spine road. 6/13/2016 Move Rig f/G-Pad to MPU Spine road intersection and attempt to make corner. Busted through Road at the Spine/Tract 14 Intersection.;Back rig up and lay mats through intersection.; Move rig from Track 14 intersection to A -Pad Entrance.;Stage rig on A -Pad Entrance and shuffle and lay mat boards to front of rig.;Move Rig from A -Pad entrance to L -Pad Entrance.;Stage rig on L -pad Entrance, Shuffle and Lay Mat Boards down C -Pad access Road;Move rig from L -Pad entrance to C -Pad, stage rig on Pad;PJSM, Remove rig boosters and gooseneck. Notify DSO before backing over well. Note: C/A = 0 psi, I/A =700 psi, tbg= 0 psi;PJSM, Line up rig to back over well. 6/14/2016 Continue to spot rig over C-15.;Skid Rig floor into drilling position. Spot Flow back tank;Rig up floor, air, water, steam, stage manual IBOP on rig and MU to top drive, continue to rig up flow back tank to rig choke manifold, spot rock washer skid, DSL tank, Mud Log shack,;Mud Engineer shack, continue R/U conveyors and tightening chains, prep mud pits and bring on 10.5 ppg mud system. R/U circulating equipment on IA and Tree. Test and calibrate rig gas alarms.;PT lines to flow back tank to 2000 psi.;Rig Evacuation Drill. PJSM on Killing well to flow back tank.;Bleed down IA to tank from 700 psi to o psi. 10 bbls bled back to Kill Tank. Pump down TBG taking returns up IA to kill tank pumping 60 bbls FW, follow with 10.5 ppg Drilling Mud.;Pumped 250 bbis to flow back tank and additional 80 bbis to rock washer pit. Circulate additional 60 bbis tubing volume to active system with 10.5 in/ out. ICP @ 4 bpm 1090 psi, FCP @ 5 bpm 980 psi.; Monitor well , well static. Lost 6 bbls while circulating final tubing volume to active.;Suck out circulating line on Tree. Chase BPV Profile BPV Thread chase. Set BPV.;Blow down surface circulating lines, R/D same.;N/D Tree. Inspect tbg hgr. Lift threads good. Function LDS (ok) 4-3/4" out, 3-3/4" in. Pack top of hanger profile (graphite) for testing. Verify BPV on seat (ok).;N/U BOP equipment. Charge koomey and function components (ok).;R/U BOP test equipment. M/U 2-7/8" test jt (donut anchor). Attempt to fluid pack test jt but lower rams would not seal. Function rams several times and verify koomey psi. Unable to seal lower rams;Troubieshoot lower rams. Drain stack and verify positive closure (ok). Verify leak at ram body around pipe. Bleed do koomey lines to lower rams, open and change out ram elements.;Daily losses to formation 5 bbls for total = 5 bbis Hauled 60 bbis to MP G&I for total = 60 bbls Hauled 280 bbls to B-50 for total = 280 bbls Hauled 205 bbls from L -Lake for total = 205 bbis 6/15/2016 Continue to change out Seals on lower 2-7/8 x 5 VBR's.;Continue to Test BOP and associated equipment to 250/4000 psi, 5 min hold on each. Test Rams to 2- 7/8", 4" and 4-1/2" pipe size. Test Annular to 2-7/8" pipe size.;Test gas alarms, Perform Accumulator Test: Start 3000 psi, After closure 1625 psi, 200 psi build 42 seconds, Full recovery 185 seconds. N@ Bottles 6 @ 1975 psi Average.;R/D test equipment. Blowdown surface equipment and lineup same for upcoming operations.; Pull TWC. Had difficulty removing TWC due to debris in profile. Drain stack and flush profile several times before we were able to remove TWC from hanger profile. Well had slight vac.;M/U landing jt w/ xo's. Engage hanger and M/U same. Kelly up w/ TDS. BOLDS. Unseat hgr @ 101 k, up wt 107k. P/U and space out in stack. Close Annular and lineup on choke.;Stage pumps up and CBU @ 7,136' MD via choke manifold. 5 BPM @ FCP 500 psi. Saw moderate amounts of sand w/ residual crude @ btms up then quickly cleaned up.;Monitor Well (Static). B/D choke line and manifold. Drain gas buster and lineup choke for tripping operations. M/U FOSV w/ xo.;C/O elevators. POOH w/ 3-1/2" tbg F/ 7,136' - T/ 936' MD . Replaced pivot bracket for handle on power tongs (15-20 mins). No other issues.;Daily losses to formation 3 bbls for total = 8 bbls Hauled 57 bbls to MP G&I for total = 117 bbis Hauled 0 bbis to B-50 for total = 280 bbls Hauled 75 bbls from L -Lake for total = 280 bbls;Rig went on Hi -Line @ 17:45 hrs. Check OA every 12 hrs, Maintain 0 psi throughout day 6/16/2016 POOH w/ 3-1/2" tbg F/ 936'- T/ surface. 226 total jts + 3.05' cutoff jt w/ 4-1/16" flare.;Clean up tools and equipment. R/D Weatherford casing. Mob milling tools and equipment to pipe shed and rig floor. Install wear ring = 9" ID.;Make up packer mill assy w/ 18" stinger on nose (2.875" OD). Packer mill+3x boot baskets+bit sub+Bumper+Oil Jar+XO+gXDC+XO+Intensifier+pumpout sub+XO = 333' total Iength;Single in with Milling assy on 4" dp to 7,113' MD. 160K up, 140k dn. Hole took proper displacement; Establish parameters and wash do F/ 7,113' to tag depth of 7,138' MD. Mill F/ 7,138' to 7144' MD.Various milling parameters - 40-80 rpm, 2-5 bpm, 3-15k wob.;Saw slight increase inflow. P/U and S/D pump. Fluid dropped est 6' in stack. slight gas breaking out @ surface. Circulate btms up as planned thru choke.. 4 BPM, 565 psi.;Blow down choke lines and line back up for milling operations. Continue milling lower slip section on packer w/ same parameters F/ 7,144'- T/ 7146' MD.;Daily losses to formation 0 bbis for total = 8 bbls;Hauled 0 bbis to MP G&I for total = 117 bbls Hauled 0 bbis to B-50 for total = 290 bbis Hauled 480 bbls from L -lake for total = 760 bbls 6/17/2016 Continue milling lower slip section on pa—er from 7146'. Adjusting parameters as needed. torque up ..,,d stalled out @ 7146.50'. PU and set back down PKR fell free.;TIH on elevators chasing PKR f/ 7137' to 7430'. Start taking wt @ 7430'. Wash and ream PKR to No Go @ 7437' TOF and Tail Pipe @ 7471'. PUW 164K/SOW 140K/Rot 145K/2.5BPM/460 psi/90 RPM/3K Tq;Bottom of fish @ 7471'. Bottom Perfs f/ 7442'-7468'. PBTD @ 7572'. Est 100'+- fill below fish.;CBU from 7437'@ 8.5 bpm/1770 psi. Had about 50% increase in fine sands at bottoms up. Continue circulate clean. Monitor well, well static.;POOH on elevators standing back 4" DP from 7437' to 330'. Work BHA standing back DC's. Lay down PKR Mill BHA. Clean out boot baskets and recover 52 lbs metals, recover 28lbs from possum belly.;Mu PKR Spear Assy: 2 13/16" ITCO Spear/4-3/4" Bumper sub/Oil Jar/XO/9-4 3/4" DC's/XO/intensifier/ Pump out sub/XO to DP. BHA length=319.88;TIH on elevators with 4" DP from derrick f/319' to 7,382' MD. Hole took proper displacement.; Establish parameters @ 7,382' MD. 165k up, 145k dn, 2 bpm/750 psi. S/O F/ 7,382' and tag top offish on depth @ 7,436' MD w/ pump on. Saw 180 psi increase @ top offish. S/D pump.;Continue S/O to 7,442' w/ 12K set dn. P/U 5'w/no increase in up wt. S/O and set do 15k. P/U w/ increase in up wt. Up wt w/ fish 200k-175k.;POOH w/ fishing assy F/ 7,442'- T/ 5,028' MD.;Service rig.;Continue POOH w/ fishing assy F/ 5,028'- T/ 320' MD. Monitor well (static) prior to working BHA. Hole took proper displacement. ;Stand back DC's. Release spear from fish (36.15'). Clean and UD (Fish) Pkr/xo/pupf'X"nipple/pup and WLEG w/ all jewelry intact and in good shape.;Clean and clear rig floor. Bring tools to rig floor for upcoming BHA.;M/U BHA #3 - 6-1/8" Junk mill/3x Boot baskets/bit sub/(6-1/8")string mill/bumpers/oil jar/xo/9 DC's/xo/intensifiers/pump out sub/xo = 338.18' Iength;TIH w/junk mill assy picking up 4" dp (93 jts) out of shed F/ 338'- T/ 3,256' MD.;Daily losses 0 bbis for total = 8 bbls;Hauled 0 bbis to MP G&I for total = 117 bbis Hauled 0 bbis to B-50 for total = 280 bbis Hauled 110 bbis from L -Lake for total = 870 bbis 6/18/2016 Continue to TIH w/ junk mill assy from 3256' to 7400'.;Wash down from 7400'. Start taking weight @ 7446' in bottom perf interval. Wash/Ream to 7490'. 3 bpm/470 psi/60 rpm/3K tq/PU 163K/SO 144K/Rot 150K. Increase pump to 6 bpm and CBU from 7490';Attempt to achieve FIT on Perfs to 13 ppg. had leak off @ 685 psi for 12.4 EMW;Mix, Pump and spot 20 bbls, 40 ppb Baracard/Steel Seal Pill across perfs from 7226' to 7468'. Squeeze pill into perfs. Attempt 13 ppg FIT on perfs and had Leak off @ 850 psi for 12.8 EMW;Continue to wash and ream from 7490', start taking weight @ 7554'. Mill hard CMT from 7554' to 7559'. 6-15K WOM/4 bpm/730 psi/70-100 rpm/4-8k tq/165 PU/ 145 SO/150K Rot. Broke through @ 7559'.;with plug rubber and CMT back at shakers. Mill cement from 7559' to 7575'w/10-12 WOB/100 rpm/4-5K Tq. Set down hard @ 7575'.;Continue shoe track F/ 7,575' to 7637' MD. Tagged FC and FS 14' high. Drill shoe and wash down rathole F/ 7,637' to 7,652' MD.;6-15K WOM/4 bpm/730 psi/70-100 rpm/4-8k tq/165 PU/ 145 SO/150K Rot,Driling new formation w/6-1/8" junk mill F/ 7,652' - T/ 7,657' MD. Very slow ROP and samples @ shakers confirm shale formation being drilled.;4 bpm, 620 psi, 20% flow, 70 rpm, 3k tq on, 2k tq off, 163k up, 144k dn, 150k rot. 2' ROP avg.;P/U and spot 17 bbl LCM pill (40 ppb -Steel seal/safe carb) F/ 7615' - T/ 7175' MD.; Pull wet F/ 7,615' - T/ 7,115' MD. Monitor well (static). Pump dryjob. Pullout of hole F/ 7,115' - T/ 650' MD.; Daily losses to formation 25 bbls for total= 33 bbls;Hauled 290 bbis to MP G&I for total= 407 bbis Hauled 0 bbis to B-50 for total = 280 bbis Hauled 160 bbis from L -Lake for total = 1030 bbis 6/19/2016 Continue to POOH from 650' to BHA.;POOH laying down 4 3/4" DC's, L/D BOT Junk Mill Assy. Clean out boot baskets w/42lbs metals recovered. Clean and clear rig floor and pipe shed of fishing tools. Stage Directional BHA on rig floor.;MU Drilling BHA #1: 6- 1/8" NOV SKH1519S PDC Bit, 5" SperryDrill Mtr, Integral Blade @ 5 7/8", 4 3/4" Float Sub, DM Collar, GM Collar, Inline Stabilizer @ 6", ADR Collar PWD, TM HOC;Up Load MWD Tools;Continue PU BHA: 3) 4-3.4" NM Flex Collar's, X -Over Sub, 1 jt 4" HWDP;Pulse test MWD @ 200 gpm/640 psi, 225 gpm/780 psi.;Continue to PU remaining BHA: 5 jts 4" HWDP HT38, Weatherford HYD Jar, 11 jts 4" HWDP. Total BHA Length = 739.99;TIH on elevators from 739' to 7630';C/O drilling line spool. Restring Blocks, Crown and drum w/ 1800' new line. Adjust COM, brakes and roller guides. Service rig. Sym ops - squeeze Icm pill w/ 500 psi during cut and slip operations;Wash do F/ 7,630' to 7,657' and drill ahead. Drill ahead F/ 7,657'- T/ 7,686' MD. 250 gpm, 2080 psi, 40 rpm, 4k tq on. Clean hole ECD's 11.35 EMW.;Circulate and condition mud for FIT. 250 gpm, 1690 psi. 10.6 mw IN/OUT.;P/U inside shoe to 7,611' MD. R/U test equipment. Fluid pack lines and purge air. Shut rams and lineup do dp and annulus.;Pump .5 bpm. Psi up to 860 psi @ 29 stks (2.9 bbls pumped). S/D pumps and record psi every min for 10 mins when psi stabilized @ 433 psi.;upper perfs @ 6,904' TVD. (13-10.6)x.052x6904' TVD=860 psi. FIT @ 13ppg @ upper perfs, FIT 12.8 ppg EMW @ btm (7,686' MD/7,340' TVD). Bled back 1.5 bbls;R/D test equipment. B/D lines and lineup for drilling operations.;Wash do F/ 7,611'- T/ 7,686' MD. 250 gpm, 1730 psi, 40 rpm, 3k tq. 175k up, 145k dn, 151k rot.;Drill ahead F/ 7,686'- T/ 7,815' MD . 129'(21.5 fph avg). 250 gpm, 2,030 psi on, 1780 psi off, 23% flow, 5-7k wob, 75 rpm, 4k tq on, 3k tq off, 200 psi diff;Daily losses to formation 14 bbis for total = 47 bbls;Hauled 332 bbis to MP G&I for total = 739 bbis Hauled 0 bbis to B-50 for total = 280 bbls Hauled 115 bbis from L Lake for total = 1145 bbis 6/20/2016 Drill ahead F/ 7,815'- T/ 7,916' MD. 101' (15.5 fph avg). 275 gpm, 22080 psi on, 1980 psi off, 23% flow, 5-7k wob, 80 rpm, 4-5k tq on, 3k tq off, 200 psi diff, MW 10.5/ECD 11.4;Having issue sliding. Lube mud system up to 1 % . Still having same issues. Discuss options with DD and Engineer. Decision made to trip for less aggressive bit and drop stabs.;Set back 1 stand and CBU from 7895'. Work pipe 90' Rot 155K/40 rpm/3k Tq/275 gpm/1860 psi.;POOH on elevators from 7895' to761 V( inside shoe) with no issues. PUW 178K/SOW 145K;Monitor well, slug pipe, blow down top drive.;POOH from 7611' to BHA @ 739'. Monitor well, well static.;Stand back HWDP/Jars and NM Flex Collars in derrick.;Down Load MWD Data.;Continue POOH w/ BHA #1. Drain and B/O bit. Bit grade = O,O,NO,A,I,X,NO,PR. B/O and laydown Inline stab, IBS and mtr stab.;M/U new 6.125" HDBS 6 blade PDC w/ slick mtr assy. RFO = 259.92° (witnessed). Download MWD (30 min). RIH w/ Monels and 1 std HWDP T/ 259.92' MD.;Shallow Pulse test (ok). 225 gpm, 720 psi (20 min). Continue RIH out of derrick w/ remaining BHA. BHA #2 total length = 731.83';TIH F/ 731'- T/ 7,321' MD. Fill pipe every 25 stds.;Service blocks, TDS and crown.;TIH F/ 7321'- T/ 7,886' MD. Wash do F/ 7,886' to 7,916' MD. Hole took proper displacement.; Drill ahead F/ 7,916'- T/ 7,942' MD . 101'(6 fph avg). 300 gpm, 2410 psi on, 2220 psi off, 26% flow, 15-20k wob, MW 10.5/ECD 11.4;Improved steerability after removing stabilizers from BHA #1 but reduced ROP w/ new bit.;Daily losses 3 bbis for total = 50 bbls Kick while drilling DRILL @ 04:00 hrs. Good response.; Hauled 57 bbis to MP G&I for total = 796 bbis Hauled 0 bbis to B-50 for total = 280 bbis Hauled 290 bbis from L -Lake for total = 1435 bbls 6/21/2016 Drill ahead F/ 7.942'- T/ 8243' 301' 25 fph avg). 300 gpm, 2350 psi on, 2220 psi off, 15-20k wob, MW 10.5/ECD 11.5.;Drill ahead F/ 8,243'- T/ 8389' 146'(25 fph avg). 300 gpm, 2370 psi on, 200 diff, 7-10k wob, MW 10.5/ECD 11.5.;Drill ahead F/ 8389'- T/ 8545' 156'(26 fph avg). 300 gpm, 2400 psi on, 200 diff, 7- 10k wob, MW 10.5/ECD 11.5.;Distance to Plan= 3' high/.6' Left Pumped 20 bbl Lo vis (condet/walnut) sweep @ 8,425' MD w/ 30% inc (clay/shale). On time. Daily losses 0 bbis for total = 50 bbls;Hauled 550 bbis to MP G&I for total = 1346 bbis Hauled 0 bbis to B-50 for total = 280 bbis Hauled 390 bbis from L -Lake for total 1825 bbis 6/22/2016 Drill ahead F/ 8545'- T/ 8829' 284'(24 fph avg). 300 gpm, 2400 psi on, 200 diff, 7-12k wob, MW 10.5/ECD 11.6;Drill ahead F/ 8829'- T/ 8961' 132'(22 fph avg). 310 gpm, 2750 psi on, 210 diff, 7-12k wob, MW 10.5/ECD 11.7;Drill ahead F/ 8961'- T/ 9090' MD. 139'(22 fph avg). 310 gpm, 2750 psi on, 210 diff, 7- 12k wob, MW 10.5/ECD 11.6 Pump Hi Vis sweep @ 8,781'w/ 20% Inc / On time;Distance to Plan =11.5' High / 3' Left Daily losses 0 bbis for total = 50 bbis End of tour / OA=165 psi - bled off to 0 psi;Hauled 587 bbls to MP G&I for total = 1933 bbis Hauled 0 bbls to B-50 for total = 280 bbis Hauled 350 bbis from L -Lake for total = 2175 bbis 6/23/2016 Drill ahead F/ 9090'- T/ 9194' MD. 94' � , o.75 fph avg). 250-310 gpm, 2750 psi on, 210 diff, 7-18k —o, MW 10.5/ECD 11.6 Pump Hi Vis sweep @9150 w/ 150% Inc / On time;Decide to POOH for bit due to Low ROP & needing to make a wiper trip. Monitor well. POOH F/ 9094' T/ Shoe @ 7560'. 15-20k bobbles. No issues. Hole took the correct fill for the trip. Pump Dry job;POOH F/ 7560'T/ BHA. Rack back HWDP w/ Jars. Rack back DC's. P/U and drain mtr (2.5mm end play / good). B/O bit (bit grade= 1,1,PN,N,X,I, NO,PR);M/U new Smith 6.125" Z513. TIH w/ BHA #3 (total length=731.7'). Shallow pulse test @ 731' (ok). TIH T/ 9100' MD. Wash do last stand. Obtain SPRs. Hole took proper displacement.; Drill ahead F/ 9194' - T/ 9278' MD. 84' (15 fph avg). 250-310 gpm, 2750 psi on, 210 diff, 10-22k wob, MW 10.6/ECD 11.7;Observed slight amount of 1" to 1-1/2" shale slivers @ shakers (9,202' MD). Slowly increase MW to 10.7 ppg. Distance to Plan= 13' High/2' Left;Daily losses 0 bbls for total = 50 bbls Pumped Hi Vis sweep @ 9095'w/ 150% inc (on time). Switch over to Rig Power @ 04:15 hrs.;Hauled 609 bbis to MP G&I for total =2542 bbls Hauled 870 bbls to B-50 for total = 1150 bbls Hauled 275 bbls from L -Lake for total = 2450 bbls 6/24/2016 Drill ahead F/ 9278' - T/ 9660' MD. 382' (32 fph avg). 250-310 gpm, 2636 psi on, 210 diff, 10-16k wob, MW 10.6/ECD 11.7.;Drill ahead F/9660'- T/9928' MD/9250' TVD (TD). 268' (36 fph avg). 300 gpm, 2640 psi on, 100 diff, 6k wob, MW 10.8/ECD 11.7.;Encountered connection gas w/ 50 unit bump @ 9687' MD. 100-150 BGG. Increase MW F/ 10.6 to 10.8 MW. BGG decreased F/ 100 to 40 units (Totco).;Circulate and condition hole @ TD (9928' MD). Circ 3.5 btm's up @ 300 gpm, 2540 psi w/ 24% flow, 100 rpm, 6k tq. ECD=11.7 EMW.;Pump 20 bbl hi vis sweep @ TD w/ 200% inc (on time), mostly shale and sand.;Flow check (slight flow). Work pipe and monitor w/ no change (slight flow w/ slight increase). Cont circulating. Inc MW from 10.8 to 11 ppg MW. Initial BGG=35, BU gas max = 230 units.;Final ECD=11.9 w/ 275 gpm, 2300 psi, 24 bgg. Flow check w/ 11 ppg MW.;Distance to plan @ original target depth = 9' Low/12' Right Daily losses 0 bbls for total = 50 bbls;Hauled 810 bbls to MP G&I for total = 3352 bbls Hauled 0 bbls to B-50 for total = 1150 bbls Hauled 520 bbls from L -Lake for total = 2970 bbls 6/25/2016 POOH F/ 9928' T/ 7792'. Pump Dry job. POOH T/ 7792'. Drop 2" Drift on wire. POOH T/ 7508'. Shoe. No over pulls on the trip. Hole took the correct hole fill. Monitor well. Static.;POOH F/ 7708'T/ BHA. UD HWDP & Jars. Dowload BHA. UD BHA & Grade bit. 1-1-WT-A-X-1-LT-TD;Clean & Clear Floor. Change over to completion AFE. Hilcorp Energy Company Composite Report Well Name: MP C -15A Field: Milne Point County/State: , Alaska i (LAT/LONG): :vation (RKB): API #: Spud Date: Job Name: 1610896C MP C -15A COMPLETION Contractor AFE #: AFE $: Activity Date I Ops Summary 6/25/2016 Working on the drilling report. Switch to Completion AFE @ 1400.,R/U Weatherford torque turn equipment. PJSM P/U 4.5 Vam Top Chrome Liner. M/U Shoe, FC, & LC joints. Baker lock same. Check Floats.,Service rig while receiving and M/U Floor valve XO.,P/U 4.5 Vam Top 12.6# L-80 13 CR F/ 120'T/ 3020' MD. Tq Turn Connections. Verify 69 total jt run (ok), 6 left in shed. M/U plug assy on btm LRT. Verify 840# shear pins (ok). Verify 6 shear pins on tool (2284 psi) and 5 pins on setting tool @ 24,500# for pkr ZXP. Mix and install "Pal Mix'.,Circulate 1x liner Vol @ 3020' MD. Stage up 5 bpm, 490 psi. Obtain parameters= 15 rpm, 1k tq, 80k up, 80k dn, 80k rot., Run 4.5" liner in hole on drill pipe out of derrick F/ 3020' to 6983' MD. Fill on the fly., Service rig., Continue run 4.5" liner on dp F/ 6,983' to 7,641' MD., Circulate 1-1/2 dp+liner volume @ 7,641' MD. Stage up 5 bpm, 790 psi, 22% flow. Obtain parameters- 20 rpm/2k tq, 30 rpm/2k tq, 140k up, 123k dn, 130k rot.,RIOH w/ liner F/ 7,641' to 9900' MD. Hole took proper displacement. Clean trip.,P/U BOT rot cmt head. R/U lines and manifold. Wash do F/ 9900' to 9928' MD. Tag upon depth. Stage pumps up to 3.5 bpm, 810 psi, 15 rpm, 6k tq. Condition mud for cmt job. R/U Halliburton Cmtrs. 6/26/2016 Circ & condition staging pumps up to 5 bpm @ 950-1100 psi. ROT @ 15-30 RPM @ 4-7000K. Work pipe 30'. UP/DN/Rot 210/140/165. Conduct PJSM with Halliburton cmt crew Baker hand and Rig crew.,Line up to Halliburton. Fill lines with H2O. Test lines to 4500 psi. Good. Pump 20 bbl 12 PPG Clean Spacer, Pump 304 SX @ 1.525 CUFT& 15.8 PPG. (83 BBL Total). Shut down. Flush lines to cmt head. R/D Circ lines to TD. Drop dart. Verify dart released. Line up to Rig Pump 10 bbl H2O. Displace with RIG. Caught pressure @ 260 STKS away. Latched plug @ 580 stks. 16.1 BBL Early. Saw 350 psi pressure spike.,We were able to Rot @ 30 rpm 7K TQ & Work pipe until 90 bbl away where we started pressuring up over our 1500 decided max pressure. Decided to put pipe in tension and shut down ROT then finish pumping. Continue pumping @ 1-4 bpm. Had intermittent packing off but were able to maintain flow throughout the job. Bumped plug @ 1023 stks with 2400 psi. 16.16 BBL early. Pressure up to 4200 psi. Hold.,Slack off & Slips appear to be slipping. Slack off to 120K. P/U to 135 & Liner jumped. Assumed Liner running tool released. Bleed off 4200 PSI pressure. Checked Floats. Good. Slack off & set down to 60K. Looked like it was slipping while slacking off. Decide to test the back side. Test annulus to 1500 psi. Good., Bleed off & open rams. P/U with 700 psi on the drill pipe. Had to pull up to 250K to release. Wt fell off to 135k. P/U Above LT with running tool while bringing pumps to 11 bpm @ 2600 psi. We got Mud push back @ 1370 stks. We did get estimated 3 bbl cmt returned to surface.,CIP @ 11:05. Circ & condition. Pump total 3 btm up. Mud in good shape.,Break off cmt swivel & double in mouse hole. Slip & cut drilling line. Clean surface lines. Pump Dry job., POOH on elevators F/ 6900' T/ 3109' MD standing back stands in the derrick., POOH laying down 4" DP F/ 3109' to surface. B/O and UD LRT. LRT had good indicators of setting tool hydraulic set but dog sub had not sheared. Found debris between dog sub (formation)., Clean and clear rig floor. Bring scraper BHA tools to rig floor. Verify lengths, ID's, and OD'S. Bring Weatherford casing equipment to floor, R/U same. Sym Ops -Kelly up and flush stack. Verify pipe count in shed (97 jts).,Rig Service.,M/U Scraper assy - 3-3/4" junk mill, bit sub, 4.5" scraper, xo (total=7.92'), 2-7/8" HT PAC drill pipe (2965.98'), xo, 7" scraper, brush, xo., Daily losses 0 bbls for total - 50 bbls Hauled 646 bbls to MP G&I for total - 4230 bbls Hauled 0 bbls to B-50 for total - 1200 bbls Hauled 330 bbls from L -Lake for total - 3420 bbls 6/27/2016 RIH With 3-3/4" junk mill, bit sub, 4.5" scraper, 2 7/8 Pipe xo, 7" scraper, brush, xo & 4" DP T/ 6600' +/-. P/U 7" RTTS & set one stand in the hole @ 104'. Release from RTTS and POOH. Test RTTS to 1000 psi for 10 min. GOOD.,N/D BOPS. N/D Tubing spool. Steam & heat up to break bolts. Remove valves and spool. B.O.L.D. M/U pack off pulling tool and pull pack off free with no problem., Rebuild packoff assy and install same. M/U tbg spool. Test void 5k w/ 15 min hold (ok). N/U BOP equipment.,R/U and body test BOP 250/4000 w/ 5/5 min hold (ok). R/D test equipment. Pull test plug and install wear bushing.,PJSM, RIH engage RTTS w/ no psi present @ RTTS. Retrieve RTTS and pull out of hole. Clean and UD same.,M/U upper 7" scraper assy and RIH F/ 6474' to 9676' MD. Washed do last stand F/ 9676' to 9771' MD. No tags, No issues entering liner top @ 6908' MD. We did see a bobble @ Liner top depth of 6910'.,R/U and test 7", 26# casing w/ 4.5", 12.6# L-80 Cr13 liner. Psi test 3000 psi w/30 min hold. Chart and record same. 3.1 s pumped w 1673 psi shut in psi. Bleed off pressure and blow down surface lines., Rig on Hi -Line Power @ 22:30 hrs. Hauled 489 bbls to MP G&I for total = 4719 bbls Hauled 0 bbls to B-50 for total = 1200 bbls Hauled 535 bbis from L -Lake for total =3955 bbls 6/28/2016 Wash do and tag landing collar @ 9832' MD. Displace 11 ppg mud w/ 8.34 ppg fresh water. Circulate hole clean @ 5 bpm, 2150 psi FCP, 20% flow.,Monitor well (static). Negative test (900 psi underbalanced)., POOH F/ 9832'- T/ 6474' MD. Upper scraper assy. Monitor well (static),RIH F/ 6474' - T/ 9832' MD with scraper assy. No issues entering top of liner @ 6908' MD., Circulate hole clean with 8.3 Freshwater. Circulate 2x btm's up @ 5 bpm w/ 2225 psi FCP, 19% flow. Shutdown pumping and prep pits for displacing completion fluid. Displace freshwater with 8.6 ppg, 2% Brine. Pump @ 5.9 bpm, 3075 psi, 20 flow.,Perform 10 min flowcheck, well static. POH UD 4" drill pipe from 9832' to 2990' laying down 7" scrapers, brushes and XO.,R/U 2 7/8" handling equipment, ready safety joint. UD 2 7/8" Pac workstring from 2990' to 2000',Service blocks, top drive and draworks, inspect brake linkage., Continue UD 2 7/8" worksting from 2000' to surface, UD 4 1/2" scraper, bit sub and 3 3/4" junk mill. Note: correct displacement on trip out.,Clear and clean rig floor, swap to 4 1/2" handling equipment. R/U power tongs. Pull 9" ID wear bushing.,PJSM, Baker lock and M/U XN / WLEG, fluted no go collar, pup jt, XN nipple w/ RHC -M Plug installed. 3.725" bttm no go, 3.813" packing bore, pup jt, 1 jt, pup jt, TNT 4 1/2" X 7" HES packer, pup jt. Verify elements / slips and 6 shear pins set for 1937 psi start -fully set @-3000 psi.,M/U and RIH w/ 4 1/2" vam top 12.6# 13 cr upper completion. Use WFD torque turn- torq to 4440 ft/Ibs, use jet lube seal guard pipe dope, utilize collar clamp on 1st 10 jts ran w/ running speed @ 90 fpm. RIH to 417',Rig on Hi -Line Power Hauled 1370 bbls to MP G&I for total = 6089 bbls Hauled 0 bbls to B-50 for total = 1200 bbls Hauled 605 bbls from L -Lake for total =4560 bbis 6/29/2016 Continue RIH w/ 4.5" , 12.6#, L-80 Cri-. Aper completion F/417'- T/ tag depth @ 6940' MD (Mule a .,e depth). Tq Turn connections (WOT). 4,440 ft/lbs tq on connections., Tag @ 6,940'3k, P/U and retag @ same depth w/ 5k. Spaceout completion w/ 2.14' from No Go. Final shoe depth 6,937' MD. TOL @ 6,929.12' (Actual). 164 jts w/ 2 pups + shoe track/packer assy. 127k up, 118k dn. See "Upper completion tally" in "O" drive/tallys for details. S/O and land out w/ 63,000 string wt on hanger on depth.,RILDS. Rig up to spot corrosion inhibitor and freeze protect. Establish reverse circulation via IA @ 3 bpm, 330 psi. Spot 82 bbls 8.6 ppg 2% KCL Brine w/ 1% baracor 100, Line up to LRS, Reverse circulate 85 bbls diesel @ 2 bpm, 480 psi. Let well U-tube for 1 hr freeze protecting tubing and I/A to 2500'.,PJSM. close I/A, RID head pin. Drop ball and rod, LID landing jt. Close blind ram, line up kill line, open I/A, Pressure to 300 psi, hold for 5 min, pressure to 3700 psi, seen shear @ 2000 psi, packer fully set @ 3000 psi. pressure test tbg @ 3500 psi f/ 30 min charted, good. 1.8 bbls pumped.,Bleed off tbg to 1500 psi, line up and pump down I/A, pressure up and test I/A to 3000 psi for 30 min, charted. good. Bleed off I/A slowly to 0 psi, then bleed off tbg slowly to 0 psi. Open blind ram. 4.5 bbls pumped.,PJSM, R/U WL. M/U 3.6" bell guide, 2" RB pulling tool, spang jar, oil jar, 2 stems, rope socket= 20.92'. RIH to 6909', POH with ball and rod, LID tools. RID WL,PJSM, R/U and pump down 4" x 7" I/A to 2500 psi and shut in. Close blind ram, pump down kill line pressuring up tbg in 750 psi increments to 4950 psi, with pressure stabilizing on tbg @ 4950 psi and 2920 psi on I/A, test tubing and liner for 30 charted min, good, bleed off tbg slowly, bleed off I/A slowly, open blind rams. RID test pump. Pumped 4.2 bbls down I/A, 3.4 bbls down tbg.,lnstall TWC per wellhead rep, Flush choke and lines with bara clean, open rams doors and inspect ram cavities for cement buildup.,Rig on Hi-Line Power Hauled 29 bbls to MP G&I for total = 6118 bbls Hauled 290 bbls to B-50 for total = 1490 bbls Hauled 0 bbls from L-Lake for total =4560 bbls 6/30/2016 Finish cleaning BOP cavities and elements. Remove kill hose and N/D BOPs. Rack back on stump., Dress top of hanger & adaptor. Install adaptor & N/U tree. Test tree & hanger void to 250/5000 psi. Good. Pull TWC & Install BPV. Secure Well.,Skid rig Floor & Start rig prep for rig move. Move rock washer. Move MM shack. Jack up rig & remove shims. Ri released from C-15A @ 18:00 HRSV 7/4/2016 CHECK IN W/ CO REP, P/U DMY GUN DRIFT, TRAVEL TO LOC,AOL, CONTACT PAD OP, JSSM, MISU, JSA, LIFT PLAN, MOVE SUPPORT EQUIP, WELL S/I ON ARRIVAL,BEGIN R/U, C/O STEM, .125" CARBON (23 turns), TS=1.75" RS,QC,10'x1-7/8" STEM (2.6" whls),QC,OJs,QC,KN,LSS,QC = 300.5" / 25.04',R/U COMPLETE, PIT TO 250/2500, RIH W/ 4-1/2" GR (steel), SID @ LATCH 4-1/2" RHC PLUG BODY @ 6887' SLM / 6915' MD, 1 OJ LICK, COME FREE, HANG UP IN XD SLIDING SLEEVE, WORK THROUGH ... POOH,OOH, SIBD, HAVE 4-1/2" RHC PLUG BODY, RECOVER ALL PACKING & NUBBINS, C/O BHA,P/T TO 250/2500, RIH W/ 15'x 3.60" DMY GUN DRIFT, SEE SEVERAL TIGHT SPOTS BETWEEN 7650' SLM TO 8260' SLM, SID @ 8728' SLM, TAP DOWN, UNABLE TO MAKE HOLE, 300# OVERPULL... POOH,OOH, SIBD, TOOLS CLEANED, C/O BHA,P/T TO 250/2500, RIH W/ 10'x 3.50" PUMP BAILER, MULE SHOE FLAPPER BTM, DRIFT TBG FREELY & SID @ 9833' SLM / 9861' MD... POOH,OOH, SIBD, THICK SCHMOO IN BAILER W/ FLUID, C/O BHA,P/T TO 250/2500, RIH W/ 15'x 3.60" DMY GUN DRIFT, WORK THROUGH TIGHT SPOT @ 8728' SLM, DRIFT TO 9831' SLM / 9859' MD... POOH, PULL 300# OVERULL COMING THROUGH TIGHT SPOT @ 8728' SLM,OOH, SIBD, BEGIN R/D,R/D COMPLETE, TREE CAP ON & TESTED, WELL HOUSE SECURED, PAD OP NOTIFIED, PARK UNIT @ Y, TRAVEL TO CAMP 7/5/2016 SPOT TRUCK, CRANE, AND HAVE PJSM,START TO RIG UP CRANE, PULL HOSES, AND TAKE PCE BASKET OFF CRANE. RAISE LINE IN THE AIR, STACK LUBE/WLV, MAKE UP RCBL TOOLSTRING, VERIFY SENSORS, AND STAB ON WELL.,ON THE WELL. HOOK UP HOSES AND PREP FOR PRESSURE TEST,P/T 275/4000 PSI RIH WITH RCBL TOOLSTRING,RIH TO 400' AND NOT GETTING COLLARS, POOH TO INVESTIGATE. SHUT IN AND BLEED DOWN LUBE. DURING POP AND DROP, DIESEL CAME OUT OF THE CONNECTION AND DOWN THE WELLHEAD. CONTACT WSL ABOUT DIESEL ON WELLHEAD. CLEANED UP THE WELLHEAD.,BREAK OFF WELL AND TEST CCL. CCL WORKS PERFECTLY. SWAP OUT CCL TO VERIFY. SPARE CCL WORKS THE SAME AS OTHER TOOL.,ON THE WELL WITH RCBL TOOLSTRING. TEST QTS. HAVE MEETING ABOUT THE DIESEL SPILLING ON WELLHEAD. RIH WITH RCBL TOOLSTRING,RIH WITH RCBL TOOLSTRING. CALIBRATE FREE PIPE AND LOG FREE PIPE PASS FROM 2900'- 2700',RIH TO BOTTOM. START REPEAT PASS FROM 9845'9600'. START MAIN PASS FROM 9845'- 6800'. DONE LOGGING. POOH.,CREW CHANGEOUT,BUMP UP, PJSM, BLEED PRESSURE, BLOW DOWN LUBE, RIG DOWN RCBL TOOLSTRING, RU RMT3D STRING, STAB ONTO STACK, TEST QTS. OPEN SWAB, OPEN SSV, RIH,ON BOTTOM, FIRE UP NEUTRON GENERATOR, ALLOW FOR HV DETECTORS TO LOCK,CAPTURE PASS #1 9840'-9450'. RIH. CAPTURE PASS #2 9840'-9450'. RIH, SWAP TO C/O MODE, HV DETECTORS LOCK. C/O PASS #1 9840'-9450'. RIH. C/O PASS #2 9840'-9450'. RIH C/O PASS #3 9840'-9450 7/6/2016 JEWELRY LOG REPEAT T.D. - 9600'. JEWELRY LOG MAIN PASS T.D. - 6700'. DONE LOGGING, POOH. TOOLSTRING OUT OF THE HOLE. SHUT IN WELL AND BLEED DOWN LUBE.,BREAK OFF LUBE, BREAK DOWN TOOLSTRING, DOWN STACK PCE IN BASKET, LAY 30' STICK OF LUBE ON SIDE OF WHALE, AND TAKE LINE OUT OF THE AIR.,TOP SHEAVE IS OUT OF THE AIR. PUT PCE BASKET ON CRANE AND LOAD EVERYTHING UP. CREW LEAVING LOCATION. 7/12/2016 0420 - 0430: PRE JOB SAFETY MEETING. 0430 - 0500: RIG UP PCE AND TOOLSTRING. FUNCTION TEST TOOLS. 0500 - 0550: STANDBY FOR DAY CREW TO GET ACCESS TO WEL. 0550 - 0610: HES MEET WITH MATT LINDER AND JEFF JONES. REVIEW JOB. 0610 - 0630: DAY CREW ARRIVE AT LOCATION. CHANGEOVER. PRE JOB SAFETY MEETING.,PREP EXPLOSIVES. CHECK THAT SWAB IS LEAK TIGHT. STAB ONTO WELL. START FILLING LUBE WITH DIESEL.,TRIPLEX KEEPS OVERHEATING AND TURNING OFF. CALL WELL SUPPORT TO SEND MECHANIC. MECHANIC ADJUSTED AIR FLOW FOR RADIATOR.,COME ONLINE WITH TRIPLEX. FILL LUBE WITH DIESEL AND PUMP DOWN RETURN LINE. PRESSURE TEST TO 220 PSI LOW/4000 PSI HIGH.,BLOW DOWN LUBE WITH NITROGEN. LAY DOWN LUBE ON WHEELS. CHECK FIRE. ARM GUN. STAB ONTO WELL.,OPEN SWAB AND SSV. RIH W/ CH, GPLT, HSC 3-1/8" X 20'.,REACH BOTTOM. CORRELATE TO HAL JEWELRY LOG DATED 7-JUL-16.,SEND CORRELATION PASS TO HILCORP TOWN FOR VERIFICATION. STANDBY FOR APPROVAL.,APPROVAL RECEIVED. JEFF JONES ON LOCATION. PULL INTO POSITION TO SHOOT. PUMP WHP UP TO 450 PSI. PERFORATE 9572'-9592'- CCL TO TOP SHOT 8'- CCL STOP DEPTH 9564'. WHIP BOUNCED BETWEEN 250 & 650 AND EVENED OUT AT 350 PSI AFTER PERF.,PULL OUT OF HOLE,BUMP UP. CLOSE SWAB AND SSV. BLOW DOWN LUBE WITH NITROGEN. BREAK AT QT SUB. LAY DOWN LUBE. CHECK FIRE. ARM GUN. STAB ONTO WELL. PT QT SUB TO 4000 PSI,OPEN SWAB AND SSV. RIH W/ CH, GPLT, HSC 3-1/8" X 20'.,REACH BOTTOM. CORRELATE TO HAL JEWELRY LOG DATED 7-JUL-16. SEND CORRELATION PASS TO HILCORP ENGINEER FOR VERIFICATION. STANDBY FOR APPROVAL.,APPROVAL RECEIVED. JEFF JONES ON LOCATION. PERFORATE 95521-9572'- CCL TO TOP SHOT 8'- CCL STOP DEPTH 9544'. POOH.,BUMP UP. CLOSE SWAB AND SSV. BLOW DOWN LUBE WITH NITROGEN. BREAK AT QT SUB. LAY DOWN LUBE. CHECK FIRE. ARM GUN. STAB ONTO WELL. PT QT SUB TO 4000 PSI,OPEN SWAB AND SSV. RIH W/ CH, GPLT, HSC 3-1/8" X 20'.,REACH BOTTOM. CORRELATE TO HAL JEWELRY LOG DATED 7-JUL-16. SEND CORRELATION PASS TO HILCORP ENGINEER. STANDBY FOR COMPANY MAN TO ARRIVE TO VERIFY AND SHOOT GUN,COMPANY MAN ON LOCATION, PERFORATE 9538'-9552'- CCL TO TOP SHOT 14.1' - CCL STOP DEPTH 9523.9',PULL OUT OF HOLE,BUMP UP. CLOSE SWAB AND SSV. BLOW DOWN LUBE WITH NITROGEN. BREAK OFF WELL, CONFIRM GUN FIRED, RIG DOWN TOOLS/PCE/LUBE, PACK UP TRUCKS, INSPECT LCOATION. LEAVE LOCATION, DROP OFF LOGS AND WELL FILE, HEAD BACK TO DEADHORSE. 7/13/2016 CHECK IN W/WSL, NOTIFY PAD -OP, .....5U, PJSM, R/U W/.125" CARBON (23 turns), TS=1-7/8" R, JC, 10'x1-7/8" STM, QC, K -JT, LSS, PT PCE 250L/2500H (good) DISCUSS JOB W/WSL, RUN DRIFT TO XN AND GET CORRECTION, **PUT ON OJ's** C/O BHA RIH W/QC, 3'x1-7/8" STM, 3.805" G -RING, SD ON SS @ 6753' SLM/6780' MD, UNABLE TO GET PASSED, DISCUSS W/WSL, USE 6764' ELM FOR CORRECTION (11' correction), POOH,OOH W/TOOLS, **REMOVE OJ's** C/O BHA MAKE 10min LUBE STOP @ 10:47 RIH W/QC, 2.17" CENT, SOFT SET, DUAL SPARTEK GAUGES, STOP & PUH TO 9326' SLM/9337' MD MAKE 30min BOTTOM STOP @ 9326' SLM/9337' MD/8750' TVD, @ 12:23 PUH MAKE 5min STOP @ 9203' SLM/9214' MD/8650' TVD, @ 12:30 PUH MAKE 5min STOP @ 9080' SLM/9091' MD/8550' TVD, @ 12:37 PUH,MAKE 5min STOP @ 7896' SLM/7907' MD/7550' TVD, @ 12:51 PUH MAKE 10min LUBE STOP, @13:54 SIBO, OOH W/TOOLS, HOT SHOT GAUGES TO WSL WSL CHECK DATA (good data), DISCUSS JOB SCOPE W/WSL, OPEN XD SS @ 6780' MD, **PUT ON OJ's** C/O BHA,RIH W/QC, 4-1/2" 42 -BO (keys down), 1-7/8" RS, SD IN SS @ 6753' SLM/6780' MD, JAR DOWN 3 TIMES AND SEE-100psi LOSS ON TBG AND-100psi GAIN ON IA, JAR DOWN 3 TIMES AND PASS BY, PASS BY A COUPLE TIMES, POOH OOH W/42-130 (pin not sheared, metal shavings packed in tool, get sample for WSL), DISCUSS W/WSL, UD FOR THE NIGHT, SECURE WELL, L/D PCE, NOTIFY PAD -OP, READY UNIT AND TOOLS FOR MORNING UD COMPLETE 7/14/2016 CHECK IN W/WSL, NOTIFY PAD -OP, PJSM, R/U W/.125" CARBON (23 turns), TS=1-7/8" RS, QC, 10'x1-7/8" STM, QC, OJ, QC, K -JT, LSS, PT PCE 250L/2500H (good) RIH W/QC, K -JT, 4-1/2" BRUSH (loose), 3.5" MAGNET, MAKE 3 PASSES FROM 6900' SLM TO 6700' SLM, POOH SLOWLY OOH W/TOOLS (recovered -1/2cup of metal shavings), RERUN TOOL,RIH W/QC, K -JT, 4-1/2" BRUSH (loose), 3.5" MAGNET, MAKE 3 PASSES FROM 6900' SLM TO 6700' SLM, POOH SLOWLY OOH W/TOOLS (recovered --1/2cup of metal shavings), RERUN TOOL RIH W/QC, K -JT, 4-1/2" BRUSH (loose), 3.5" MAGNET, MAKE 3 PASSES FROM 6900' SLM TO 6700' SLM, POOH SLOWLY,OOH W/TOOLS (recovered -1/2cup of metal shavings), DISCUSS W/WSL, RERUN TOOL TO -1500' SLM AND CHECK IF ANY AT SURFACE RIH W/QC, K -JT, 4-1/2" BRUSH (loose), 3.5" MAGNET, STOP @ 1500' SLM, POOH OOH W/TOOLS (recovered -1/2cup of metal shavings), DISCUSS W/WSL, CONTINUE MAKING RUNS TO 6900' SLM, RERUN TOOL,RIH W/QC, K -JT, 4-1/2" BRUSH (loose), 3.5" MAGNET, STOP @ 6900' SLM, POOH OOH W/TOOLS (recovered -1/2cup of metal shavings), WINDS AT 30mph, DISCUSS W/WSL, L/D FOR WEATHER, SECURE WELL, L/D PCE **START WEATHER STANDBY TIME** WINDS 44mph, MONITOR WINDS HOURLY, REPACK S -BOX W/.125 CARBON (25 turns), CLEAN TOOLS, PERFORM TOOL INVENTORY,L/D COMPLETE, WIND SPEED @ 39mph, CONTINUE TO MONITOR WIND SPEED @ 40m h, CONTINUE TO MONITOR. SDFN. 7/15/2016 CHECK IN W/WSL, NOTIFY PAD -OP, PJSM, R/U W/.125" CARBON (23 turns), TS=1-7/8" RS, QC, 10'x1-7/8" STM, QC, OJ, QC, K -JT, LSS, PT PCE 250U2500H (good) RIH W/QC, RX RUNNING TOOL W/3" JET PUMP W/SOFT SET & SPARTEK GAUGE (serial # BP -1071, ratio: 9C, OAL=109"), SD IN XD SS @ 6753' SLM/6780' MD, SET JET PUMP, POOH,OOH W/TOOLS (recovered all pins & nubbins), SECURE WELL AND NOTIFY PAD -OP & WSL, RDMO, UD PCE, READY UNIT FOR TRAVEL TO J -PAD UD JOB COMPLETE 7/18/2016 CHECK IN W/WSL, NOTIFY PAD -OP, MISU, PJSM, R/U W/.125" CARBON (24" turns), TS=1-7/8" RS, QC, 10'x2-1/8" STM, QC, OJ, QC, K -JT, LSS, PT PCE 250U2500H (good) RIH W/QC, 4-1/2" GR, SD & LATCH @ 6752' SLM, COME FREE W/2 JAR LICKS, SEE -1501b WEIGHT GAIN, POOH OOH W/JET PUMP (serial #BP -1071, ratio: 9C) W/SPARTEK GAUGE (serial #75838), WSL CHECK DATA (good data),RIH W/QC, K -JT, 4-1/2" BRUSH, 3.50" G -RING, BRUSH XD SS @ 6780' MD, DRIFT TO 9826' SLM, JAR DOWN ONCE TO 9829' SLM, COME FREE W/-300lb OVER PULL (soft bottom), POOH BUMP UP IN LUBE, WELL SUPPORT ON LOCATION TO SHOOT A FLUID LEVEL (FL @ -250'), SIBO, OOH W/TOOLS (clean), NOTIFY WSL, SET CAT STANDING VALVE AND CMIT-TxIA TO 3600psi W/LRS LRS ON LOCATION, PJSM W/LRS & CREW, LRS R/U TO P -SUB PT HOSE & PCE 25OU4100H (GOOD),RIH W/QC, 4-1/2" GR W/4-1/2" CAT STANDING VALVE, SD & SET CAT IN XN-NIP @ 6888' SLM/6915' MD, LRS CMIT-TxIA (see LRS log for results, pass), PULL CAT, POOH BUMP UP IN LUBE, LRS BLEED BACK LUBE & R/D, OOH W/TOOLS, NOTIFY WSL, C/O BHA,RIH W/QC, 4-1/2" RX (3 brass) W/3" JET PUMP (serial #MPE 24-01, ratio: 9C) & ONE SPARTEK GAUGE (SERIAL # 75838 -START TIME @ 16:11) OAL=104" lock open, secondary lock down), SD IN XD SS @ 6752' SLM/6780' MD, SET JET PUMP, POOH OOH W/TOOLS (recovered all pins & nubbins), NOTIFY WSL, RDMO, SECURE WELL, L/D PCE, NOTIFY PAD -OP, READY UNIT FOR TRAVEL TO F-54 R/D COMPLETE Hilcorp Energy Company Milne Point M Pt C Pad MPC -15A 50-029-21358-01-00 Sperry Drilling Definitive Survey Report 27 June, 2016 HALLIBURTON Sporry Drilling Company: Hilcorp Energy Company Project: Milne Point Site: M Pt C Pad Well: MPC -15 Wellbore: MPC -15A Design: MPC -15A Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPC -15 MPC -1 5A Actual @ 50.34usft MPC-15AActual @ 50.34usft True Minimum Curvature 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 MPC -15, MPC -15 Azi Well Position +N/ -S 0.00 usft Northing: (usft) +E/ -W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: 33.64 0.00 0.00 Wellbore MPC -15A Magnetics Model Name Sample Date 197.69 BGGM2016 6/24/2016 Design MPC -15A Audit Notes: Version: 1.0 Vertical Section: 6,029,007.58 usft Latitude: 70° 29'23.502 N 558,366.14 usft Longitude: 149'31'22.374 W usft Ground Level: 16.70 usft Declination (°) Phase: ACTUAL Depth From (TVD) +N/ -S (usft) (usft) Dip Angle Field Strength (°) (nT) i 18.26 81.07 57,567 Tie On Depth: 7,528.34 +E/ -W Direction (usft) (°) 0.00 200.00 - --- - Survey Program Date 6/27/2016 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 98.34 7,528.34 1 : Sperry -Sun BOSS gyro multi (MPC -15 SRG-MS Surface readout gyro multishot 05/30/1985 7,596.80 9,896.03 MWD+IFR2+MS+sag (MPC -15A) MWD+IFR2+MS+sag Fixed:v2:IIFR dec & 3 -axis correction + sag 06/16/2016 Survey - MD Inc Azi TVD TVDSS +N/ -S (usft) (°) (°) (usft) (usft) (usft) 33.64 0.00 0.00 33.64 -16.70 0.00 98.34 0.42 197.69 98.34 48.00 -0.23 198.34 0.47 225.30 198.34 148.00 -0.86 298.34 0.55 187.10 298.33 247.99 -1.63 398.34 0.55 249.80 398.33 347.99 -2.27 498.34 0.42 255.60 498.33 447.99 -2.53 598.34 0.30 267.39 598.32 547.98 -2.63 698.34 0.25 303.70 698.32 647.98 -2.52 798.34 0.22 157.00 798.32 747.98 -2.58 898.34 0.05 75.39 898.32 847.98 -2.74 998.34 0.37 337.40 998.32 947.98 -2.43 1,098.34 0.18 317.70 1,098.32 1,047.98 -2.02 1,198.34 0.23 264.89 1,198.32 1,147.98 -1.92 6127/2016 5:46:59PM Page 2 COMPASS 5000.1 Build 81 Map Map Vertical +E/ -W Northing Easting DLS Section (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 0.00 6,029,007.58 558,366.14 0.00 0.00 UNDEFINED -0.07 6,029,007.35 558,366.07 0.65 0.24 SRG-MS (1) -0.47 6,029,006.71 558,365.67 0.22 0.97 SRG-MS (1) -0.83 6,029,005.95 558,365.33 0.34 1.81 SRG-MS(1) -1.34 6,029,005.30 558,364.82 0.57 2.59 SRG-MS (1) -2.14 6,029,005.04 558,364.02 0.14 3.11 SRG-MS (1) -2.76 6,029,004.93 558,363.40 0.14 3.41 SRG-MS(1) -3.20 6,029,005.03 558,362.96 0.18 3.46 SRG-MS (1) -3.31 6,029,004.98 558,362.85 0.45 3.55 SRG-MS (1) -3.19 6,029,004.81 558,362.97 0.22 3.67 SRG-MS(1) -3.27 6,029,005.12 558,362.89 0.38 3.41 SRG-MS (1) -3.50 6,029,005.53 558,362.65 0.21 3.10 SRG-MS(1) -3.81 6,029,005.63 558,362.35 0.19 3.11 SRG-MS (1) 6127/2016 5:46:59PM Page 2 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPC -15 Project: Milne Point TVD Reference: MPC-15AActual @ 50.34usft Site: M Pt C Pad MD Reference: MPC-15AActual @ 50.34usft Well: MPC -15 North Reference: True Wellbore: MPC -15A Survey Calculation Method: Minimum Curvature Design: MPC -15A Database: Sperry EDM - NORTH US + CANADA Survey 6/27/2016 5:46:59PM Page 3 COMPASS 5000.1 Build 81 Map Map Vertical MD Inc Azi TVD TVDSS +N1S +E1 -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°l100') (ft) Survey Tool Name 1,298.34 0.22 265.19 1,298.32 1,247.98 -1.95 -4.20 6,029,005.59 558,361.96 0.01 3.27 SRG-MS (1) 1,398.34 0.05 200.80 1,398.32 1,347.98 -2.01 -4.41 6,029,005.53 558,361.75 0.20 3.40 SRG-MS (1) 1,498.34 0.18 292.70 1,498.32 1,447.98 -1.99 -4.57 6,029,005.55 558,361.59 0.19 3.43 SRG-MS (1) 1,598.34 0.22 282.11 1,598.32 1,547.98 -1.89 -4.90 6,029,005.65 558,361.26 0.05 3.45 SRG-MS (1) 1,698.34 0.15 301.00 1,698.32 1,647.98 -1.78 -5.20 6,029,005.76 558,360.96 0.09 3.45 SRG-MS (1) 1,798.34 0.17 112.61 1,798.32 1,747.98 -1.77 -5.17 6,029,005.77 558,360.98 0.32 3.44 SRG-MS (1) 1,898.34 0.07 328.50 1,898.32 1,847.98 -1.78 -5.07 6,029,005.76 558,361.09 0.23 3.40 SRG-MS (1) 1,998.34 0.18 199.19 1,998.32 1,947.98 -1.87 -5.15 6,029,005.67 558,361.00 0.23 3.52 SRG-MS (1) 2,098.34 0.22 196.10 2,098.32 2,047.98 -2.21 -5.26 6,029,005.33 558,360.90 0.04 3.87 SRG-MS (1) 2,198.34 0.25 166.50 2,198.32 2,147.98 -2.60 -5.26 6,029,004.94 558,360.90 0.12 4.25 SRG-MS (1) 2,298.34 0.15 61.30 2,298.31 2,247.97 -2.75 -5.09 6,029,004.79 558,361.07 0.32 4.33 SRG-MS (1) 2,398.34 0.27 66.30 2,398.31 2,347.97 -2.60 -4.76 6,029,004.95 558,361.40 0.12 4.07 SRG-MS (1) 2,498.34 0.00 312.70 2,498.31 2,447.97 -2.50 -4.55 6,029,005.04 558,361.61 0.27 3.90 SRG-MS (1) 2,598.34 0.12 169.11 2,598.31 2,547.97 -2.60 -4.53 6,029,004.94 558,361.63 0.12 3.99 SRG-MS (1) 2,698.34 0.17 110.70 2,698.31 2,647.97 -2.76 -4.37 6,029,004.79 558,361.79 0.15 4.09 SRG-MS (1) 2,798.34 0.32 76.19 2,798.31 2,747.97 -2.74 -3.96 6,029,004.80 558,362.20 0.20 3.93 SRG-MS (1) 2,898.34 0.77 204.50 2,898.31 2,847.97 -3.29 -3.97 6,029,004.26 558,362.20 1.00 4.45 SRG-MS (1) 2,998.34 0.28 277.11 2,998.31 2,947.97 -3.87 -4.49 6,029,003.67 558,361.68 0.74 5.17 SRG-MS (1) 3,098.34 0.57 122.61 3,098.30 3,047.96 -4.11 -4.31 6,029,003.44 558,361.86 0.83 5.33 SRG-MS (1) 3,198.34 2.65 115.00 3,198.26 3,147.92 5.35 -1.80 6,029,002.21 558,364.39 2.09 5.65 SRG-MS (1) 3,298.34 5.30 107.50 3,298.01 3,247.67 -7.72 4.70 6,028,999.90 558,370.90 2.69 5.65 SRG-MS (1) 3,398.34 7.77 93.20 3,397.36 3,347.02 -9.49 15.86 6,028,998.22 558,382.07 2.94 3.49 SRG-MS (1) 3,498.34 10.25 91.11 3,496.12 3,445.78 -10.04 31.51 6,028,997.79 558,397.72 2.50 -1.35 SRG-MS (1) 3,598.34 12.68 99.20 3,594.12 3,543.78 -11.96 51.24 6,028,996.02 558,417.47 2.91 -6.28 SRG-MS (1) 3,698.34 15.68 101.81 3,691.07 3,640.73 -16.49 75.31 6,028,991.69 558,441.57 3.07 -10.27 SRG-MS (1) 3,798.34 18.43 107.40 3,786.66 3,736.32 -23.98 103.63 6,028,984.42 558,469.94 3.20 -12.91 SRG-MS (1) 3,898.34 21.22 106.61 3,880.73 3,830.39 -33.88 136.06 6,028,974.77 558,502.45 2.80 -14.70 SRG-MS (1) 3,998.34 23.12 99.81 3,973.35 3,923.01 -42.40 172.76 6,028,966.54 558,539.21 3.19 -19.24 SRG-MS (1) 4,098.34 25.97 98.31 4,064.30 4,013.96 -48.91 213.78 6,028,960.35 558,580.27 2.92 -27.15 SRG-MS (1) 4,198.34 28.38 99.81 4,153.26 4,102.92 -56.13 258.87 6,028,953.49 558,625.42 2.51 -35.79 SRG-MS (1) 4,298.34 28.97 100.70 4,240.99 4,190.65 -64.67 306.08 6,028,945.32 558,672.69 0.73 -43.91 SRG-MS (1) 4,398.34 29.12 101.31 4,328.42 4,278.08 -73.94 353.74 6,028,936.42 558,720.42 0.33 -51.50 SRG-MS (1) 4,498.34 29.12 102.11 4,415.78 4,365.44 -83.82 401.39 6,028,926.92 558,768.14 0.39 -58.52 SRG-MS (1) 4,598.34 29.37 102.61 4,503.03 4,452.69 -94.28 449.11 6,028,916.84 558,815.94 0.35 -65.01 SRG-MS (1) 4,698.34 29.47 102.20 4,590.14 4,539.80 -104.83 497.09 6,028,906.67 558,863.99 0.22 -71.51 SRG-MS (1) 4,798.34 30.12 103.00 4,676.92 4,626.58 -115.67 545.58 6,028,896.20 558,912.56 0.76 -77.90 SRG-MS (1) 4,898.34 28.57 101.31 4,764.08 4,713.74 -126.01 593.48 6,028,886.25 558,960.53 1.76 -84.57 SRG-MS (1) 4,998.34 27.73 100.70 4,852.26 4,801.92 -135.02 639.78 6,028,877.60 559,006.90 0.89 -91.95 SRG-MS(1) 5,098.34 26.80 104.70 4,941.15 4,890.81 -145.06 684.46 6,028,867.91 559,051.65 2.05 -97.79 SRG-MS (1) 5,198.34 25.63 104.90 5,030.86 4,980.52 -156.34 727.16 6,028,856.97 559,094.44 1.17 -101.79 SRG-MS (1) 6/27/2016 5:46:59PM Page 3 COMPASS 5000.1 Build 81 Company: Hilcorp Energy Company Project: Milne Point Site: M Pt C Pad Well: MPC -15 Wellbore: MPC -15A Design: MPC -15A Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPC -15 MPC-15AActual @ 50.34usft MPC-15AActual @ 50.34usft True Minimum Curvature Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +EI -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 5,298.34 24.48 107.11 5,121.46 5,071.12 -168.00 767.87 6,028,845.63 559,135.23 1.48 -104.76 SRG-MS (1) 5,398.34 23.97 103.61 5,212.65 5,162.31 -178.87 807.42 6,028,835.07 559,174.86 1.52 -108.07 SRG-MS (1) 5,498.34 24.30 102.00 5,303.91 5,253.57 -187.93 847.28 6,028,826.32 559,214.79 0.74 -113.19 SRG-MS(1) 5,598.34 22.33 100.40 5,395.74 5,345.40 -195.64 886.10 6,028,818.92 559,253.66 2.07 -119.22 SRG-MS (1) 5,698.34 21.98 101.11 5,488.36 5,438.02 -202.67 923.15 6,028,812.18 559,290.76 0.44 -125.28 SRG-MS (1) 5,798.34 22.30 101.20 5,580.99 5,530.65 -209.97 960.12 6,028,805.18 559,327.79 0.32 -131.08 SRG-MS (1) 5,898.34 22.72 101.11 5,673.37 5,623.03 -217.37 997.68 6,028,798.07 559,365.40 0.42 -136.97 SRG-MS(1) 5,998.34 22.88 101.40 5,765.55 5,715.21 -224.94 1,035.69 6,028,790.80 559,403.46 0.20 -142.86 SRG-MS (1) 6,098.34 22.82 101.61 5,857.71 5,807.37 -232.68 1,073.74 6,028,783.36 559,441.57 0.10 -148.59 SRG-MS (1) 6,198.34 23.13 99.81 5,949.78 5,899.44 -239.93 1,112.09 6,028,776.41 559,479.97 0.77 -154.90 SRG-MS (1) 6,298.34 23.12 100.81 6,041.74 5,991.40 -246.96 1,150.73 6,028,769.68 559,518.66 0.39 -161.51 SRG-MS (1) 6,398.34 22.68 101.70 6,133.86 6,083.52 -254.55 1,188.89 6,028,762.39 559,556.88 0.56 -167.43 SRG-MS (1) 6,498.34 22.32 101.31 6,226.25 6,175.91 -262.18 1,226.39 6,028,755.05 559,594.44 0.39 -173.08 SRG-MS (1) 6,598.34 22.15 101.11 6,318.81 6,268.47 -269.54 1,263.51 6,028,747.99 559,631.61 0.19 -178.86 SRG-MS (1) 6,698.34 21.65 101.20 6,411.59 6,361.25 -276.76 1,300.11 6,028,741.06 559,668.25 0.50 -184.60 SRG-MS (1) 6,798.34 21.50 100.31 6,504.59 6,454.25 -283.62 1,336.23 6,028,734.48 559,704.43 0.36 -190.50 SRG-MS (1) 6,898.34 21.10 100.70 6,597.76 6,547.42 -290.24 1,371.95 6,028,728.14 559,740.19 0.42 -196.50 SRG-MS(1) 6,998.34 20.77 100.70 6,691.16 6,640.82 -296.87 1,407.06 6,028,721.79 559,775.35 0.33 -202.27 SRG-MS (1) 7,098.34 20.80 100.70 6,784.65 6,734.31 -303.46 1,441.93 6,028,715.47 559,810.26 0.03 -208.01 SRG-MS (1) 7,198.34 20.87 100.61 6,878.11 6,827.77 -310.04 1,476.88 6,028,709.17 559,845.27 0.08 -213.78 SRG-MS(1) 7,298.34 20.28 100.20 6,971.73 6,921.39 -316.39 1,511.44 6,028,703.09 559,879.88 0.61 -219.64 SRG-MS (1) 7,398.34 18.95 98.90 7,065.93 7,015.59 -321.97 1,544.54 6,028,697.77 559,913.02 1.40 -225.71 SRG-MS (1) 7,498.34 17.90 99.70 7,160.80 7,110.46 -327.07 1,575.74 6,028,692.92 559,944.24 1.08 -231.59 SRG-MS (1) 7,528.34 17.47 98.70 7,189.38 7,139.04 -328.53 1,584.73 6,028,691.53 559,953.25 1.75 -233.29 SRG-MS(1) 7,596.80 16.50 97.52 7,254.85 7,204.51 -331.36 1,604.53 6,028,688.86 559,973.06 1.50 -237.41 MWD+IFR2+MS+sag (2) 7,666.79 16.08 96.22 7,322.03 7,271.69 -333.71 1,624.02 6,028,686.66 559,992.57 0.79 -241.86 MWD+IFR2+MS+sag (2) 7,760.12 17.66 114.10 7,411.40 7,361.06 -340.89 1,649.81 6,028,679.68 560,018.41 5.79 -243.93 MWD+IFR2+MS+sag (2) 7,856.17 19.12 128.23 7,502.59 7,452.25 -356.59 1,675.48 6,028,664.19 560,044.20 4.87 -237.97 MWD+IFR2+MS+sag(2) 7,946.50 19.97 140.76 7,587.76 7,537.42 -377.70 1,696.87 6,028,643.25 560,065.76 4.73 -225.44 MWD+IFR2+MS+sag (2) 8,040.98 22.81 157.17 7,675.80 7,625.46 -407.10 1,714.20 6,028,613.98 560,083.31 6.98 -203.74 MWD+IFR2+MS+sag (2) 8,134.29 25.05 167.37 7,761.12 7,710.78 -443.07 1,725.54 6,028,578.11 560,094.94 5.03 -173.82 MWD+IFR2+MS+sag (2) 8,229.68 29.57 172.20 7,845.86 7,795.52 -486.12 1,733.16 6,028,535.12 560,102.89 5.27 -135.97 MWD+IFR2+MS+sag (2) 8,323.31 32.93 175.56 7,925.90 7,875.56 -534.40 1,738.26 6,028,486.89 560,108.38 4.04 -92.35 MWD+IFR2+MS+sag (2) 8,418.30 35.63 178.36 8,004.39 7,954.05 -587.81 1,741.05 6,028,433.51 560,111.59 3.29 -43.11 MWD+IFR2+MS+sag (2) 8,512.63 35.80 178.03 8,080.98 8,030.64 -642.85 1,742.79 6,028,378.49 560,113.75 0.27 8.01 MWD+IFR2+MS+sag (2) 8,607.61 35.84 177.37 8,158.00 8,107.66 -698.39 1,745.02 6,028,322.97 560,116.42 0.41 59.44 MWD+IFR2+MS+sag (2) 8,700.58 35.53 176.76 8,233.51 8,183.17 -752.55 1,747.80 6,028,268.84 560,119.62 0.51 109.39 MWD+IFR2+MS+sag (2) 8,793.74 36.20 179.51 8,309.01 8,258.67 -807.09 1,749.56 6,028,214.32 560,121.81 1.87 160.03 MWD+IFR2+MS+sag (2) 8,887.51 36.81 178.96 8,384.38 8,334.04 -862.87 1,750.31 6,028,158.56 560,123.00 0.74 212.19 MWD+IFR2+MS+sag (2) 8,982.88 34.51 180.16 8,461.87 8,411.53 -918.46 1,750.75 6,028,102.98 560,123.88 2.52 264.28 MWD+IFR2+MS+sag (2) 612712016 5:46:59PM Page 4 COMPASS 5000.1 Build 81 Company: Hilcorp Energy Company Project: Milne Point Site: M Pt C Pad Well: MPC -15 Wellbore: MPC -15A Design: MPC -15A Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPC -15 MPC -15A Actual @ 50.34usft MPC-15AActual @ 50.34usft True Minimum Curvature Sperry EDM - NORTH US + CANADA 6/27/2016 5:46:59PM Page 5 COMPASS 5000.1 Build 81 Map Map Vertical MD Inc Azi TVD TVDSS +WS +E/ -W Northing Fasting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°llow) (ft) Survey Tool Name 9,077.37 35.63 179.78 8,539.20 8,488.86 -972.75 1,750.78 6,028,048.69 560,124.33 1.21 315.28 MWD+IFR2+MS+sag (2) 9,171.33 35.72 177.03 8,615.53 8,565.19 -1,027.51 1,752.31 6,027,993.95 560,126.29 1.71 366.22 MWD+IFR2+MS+sag (2) 9,266.47 36.31 177.91 8,692.49 8,642.15 -1,083.40 1,754.77 6,027,938.09 560,129.19 0.82 417.89 MWD+IFR2+MS+sag (2) 9,359.29 34.39 183.32 8,768.21 8,717.87 -1,137.05 1,754.26 6,027,884.44 560,129.10 3.95 468.49 MWD+IFR2+MS+sag (2) 9,452.94 32.11 184.72 8,846.53 8,796.19 -1,188.27 1,750.68 6,027,833.20 560,125.92 2.57 517.84 MWD+IFR2+MS+sag (2) 9,548.00 32.10 180.64 8,927.06 8,876.72 -1,238.71 1,748.32 6,027,782.75 560,123.96 2.28 566.04 MWD+IFR2+MS+sag (2) 9,641.91 33.17 179.42 9,006.14 8,955.80 -1,289.35 1,748.30 6,027,732.12 560,124.34 1.34 613.64 MWD+IFR2+MS+sag (2) 9,736.13 32.11 180.97 9,085.48 9,035.14 -1,340.16 1,748.14 6,027,681.31 560,124.57 1.43 661.44 MWD+IFR2+MS+sag (2) 9,830.15 30.55 180.94 9,165.79 9,115.45 -1,389.04 1,747.32 6,027,632.43 560,124.14 1.66 707.65 MWD+IFR2+MS+sag (2) 9,896.03 30.78 182.37 9,222.46 9,172.12 -1,422.62 1,746.35 6,027,598.84 560,123.43 1.16 739.54 MWD+IFR2+MS+sag (2) 9,928.00 30.78 182.37 9,249.93 9,199.59 -1,438.97 1,745.67 6,027,582.49 560,122.88 0.00 755.14 PROJECTED to TD Checked By: brian.wlwda@r hawbunon. com Approved By: �,«.. ,� ° Date: 6/27/2016 6/27/2016 5:46:59PM Page 5 COMPASS 5000.1 Build 81 Lease & Well No. County TD 9.928.00 Hilcorp Energy Company CASING & CEMENTING REPORT MP C -15A State CASING RECORC Liner IF Shoe nenth- 9.928.0C Alaska Date Run 26 -Jun -16 Supv. S. Sunderland / S. Barber PRTD- 9.84.1i 00 Csg Wt. On Hook: 210,000 Type Float Collar: DHP Csg Wt. On Slips: Casing (Or Liner) Detail DHP Rotate Csg X Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Float Shoe 5 IBT Downhole Products 1.14 9,928.00 9,926.86 1 4.5" liner 41/2 12.6 L-80 IBT VamTop 40.50 9,926.86 9,886.36 1 Float Collar 5 Volume pumped (BBLs) L-80 IBT Downhole Products 1.12 9,886.36 9,885.24 2 4.5" liner 41/2 12.6 L-80 IBT VamTop 39.40 9,885.24 9,845.84 1 Landing Collar 5 disp: Rig L-80 Vam HTTC Halliburton LC 0.81 9,845.84 9,845.03 69 4.5" liner 41/2 12.6 L-80 VamTop VamTop 2,899.58 9,845.03 6,945.45 1 HRD-E ZXP 6 L-80 Vam Top BOT 37.11 6,945.45 6,908.34 Csg Wt. On Hook: 210,000 Type Float Collar: DHP Csg Wt. On Slips: 140,000 Type of Shoe: DHP Rotate Csg X Yes No Recip Csg X Yes Fluid Description: Top of Liner 3019.66 Liner hanger Info (Make/Model): Baker ZXP Liner hanger test pressure: 3000 Density (ppg) Centralizer Placement: 1 on each shoe it, 1 on every other ioint to ioint 28. 16 Total. _ No. Hrs to Run: Casing Crew: WFD No Ft. Min. PPG Liner top Packer?: X Yes No Floats Held X Yes No Calculated Cmt Vol @ 0% excess: 77 Total Volume cmt Pumped: Cmt returned to surface: 3 Calculated cement left in wellbore: OH volume Calculated: 38.2 OH volume actual: 64.5 Actual % Washout: www.wellez.net WellEz Information Management LLC 80 68 ver 051316bf 83 CEMENTING REPORT Shoe @ 9928 FC @ 9,885.24 Top of Liner 3019.66 Preflush (Spacer) Type: Cleanspacer III Density (ppg) 12 Volume pumped (BBLs) 20 Lead Slurry Type: HalCem Sacks: 304 Yield: 1.53 Density (ppg) 15.8 Volume pumped (BBLs) 83 Mixing / Pumping Rate (bpm): 5 Tail Slurry W Type: Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): y Post Flush (Spacer) Lk Type: Density (ppg) Rate (bpm): Volume: LL Displacement: Type: WBM Density (ppg) 11 Rate (bpm): 6 Volume (actual / calculated): 101/117 FCP (psi): 2400 Pump used for disp: Rig Bump Plug? X Yes No Bump press 4200 Casing Rotated? X Yes _ No Reciprocated? X Yes No % Returns during job 100 Cement returns to surface? X Yes _ No Spacer returns? X Yes No Vol to Surf: 3 Cement In Place At: 11:00 Date: 6/26/2016 Estimated TOC: 6,908 Method Used To Determine TOC: Pipe strap/tally Post Job Calculations: Calculated Cmt Vol @ 0% excess: 77 Total Volume cmt Pumped: Cmt returned to surface: 3 Calculated cement left in wellbore: OH volume Calculated: 38.2 OH volume actual: 64.5 Actual % Washout: www.wellez.net WellEz Information Management LLC 80 68 ver 051316bf 83 500 1000 1500 2000 2500 0111I11, 3500 4000 $ 4500 r 4, v 5000 0 2 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 MPC -15A FINAL Days vs Depth MPC -15A Actual MPC -15A Plan MPC -15A Stretch Goal 0 5 10 15 20 25 Days 7/29/2016 10:21 AM MPC -15A MW vs Depth MPC -15A Plan 1000 MPC -15A Actual 2000 3000 4000 5000 I $ s 6000 0 v a 3 N f6 7000 8000 9000 - 10000 11000 12000 8 9 10 11 12 13 14 Mud Density (ppg) DATE 7/27/2016 Debra Oudean AK_GeoTech RECEI'V.;, JUL 2 7 2016 PC Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Meredith Guhl, Petroleum Geologist Assistant 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 CANRIG FINAL WELL DATA Prints: WE FINAL WELL REPORT FORMATION LOG SIN MD / TVD FORMATION LOG 2IN MD / TVD LWD COMBO LOG MD / TVD DRILLING DYNAMICS MD / TVD GAS RATIO LOG MD / TVD Daly Reports 7/16/2016 1:41 PM File folder DML Data 7/16/2016 1:41 PM Fie folder Fnal Wel Report 7/16/2016 1:41 PM File folder LAS Data 7/16/2016 1:41 PM File folder Lithology & Sample Photography 7/16/2016 1:41 PM File folder Log PDFs 7/16/2016 1:41 PM File folder Log TIFFS 7/16/2016 1:41 PM File folder Show Reports 7/16/2016 1:41 PM File folder 216070 27 433 DATA LOGGED Z /'a1201G M. K. BENDER Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: I Date: 11 RECEIVED '3lAt_ AOGCC Date: 7/13/2016 21 6070 Maile Sweigart 27 3 7 8 Alaska North Slope Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Ste 1400 1 Anchorage, Alaska 99503 Office: 907.777.8473 msweigart@hilcorp.com To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 ROP -GM -ADR 2IN MD, GM -ADR 21N TVD E log data CD 1 : Final Well Data _ l"Jame Cate modified Type Files Currently on the Disc (7) Log Viewers 6:/28x`20162:711 PM File folder CGM 6/28/20162:2_n Pt,,l Filefelder Definitive Survey 6/28/2016.2213 Phut File folder EMF 6`28/20162:20 P1`0 File folder LAS 6/28/20162,23 PM File folder PDF 6/28/2016 2:201 PM File folder TIFF 6/28/20162:2:1 MI Filefelder DATA LOGGED I / Ci/201(a M K BENDER Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By%� }2 Date: a' ca- b-7 Debra Oudean Hilcorp Alaska, LLC -90 AK_GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 111b (111' Fax: 907 777-8510 E-mail: doudean@hilcorp.com�ECE'"CD DATE 7/8/2016 jUL 0 8 7016 To: Alaska Oil & Gas Conservation Commission AOGCC Meredith Guhl, Petroleum Geologist Assistant 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 Transmitted herewith are cuttings WELL BOX SAMPLE INTERVAL MPC -15A BOX 1 OF 4 76581- 8640' MPC -15A BOX 2 OF 4 8640' - 9380' MPC -15A BOX 3 OF 4 9380' - 9700' MPC -15A BOX 4 OF 4 9700' - 9928' Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Re&Lved By.. /_�. X J Date: THE STATE of LASKA GOVERNOR BILL WALKER BoYork Area Operations Manager P.O. Box 196612 Anchorage, AK 99519-6612 Re: Milne Point Unit, Sag River Oil Pool, MPU C -15A Permit to Drill Number: 216-070 Sundry Number: 316-345 Dear Mr. York: Alaska Oil and Gas COT - * 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 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 �� v� Cathy P. oerster Chair DATED this I day of July, 2016. RBDMS UL JUL 0 6 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED JUN 2 7 2010 STs ((O 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 Casing ❑ Other. n 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑✓ Stratigraphic ❑ Service ❑ 216-070 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 50-029-21358-01-00 7. If perforating: y al 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 4 Will planned perforations require a spacing exception? Yes El No Q ✓ MPU C-1 5X 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL047434 asb 1 . Milne Point Unit / 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): 9,928' 9,250' ' 9,843' 9,177' 3,768 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 13-3/8" 105' 105' 1,740psi 750psi Surface 4,655' 9-5/8" 4,692' 4,584' 3,520psi 2,020psi Production 7,616' T' 7,653' 7,307' 7,240psi 5,410psi Liner 3,020' 4-1/2" 9,928' 9,250' 8,430 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic Detail See Schematic Detail N/A NIA N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 7"x4-1/2" ZXP Liner Top Packer and N/A 6,908' MD (6,607' TVD) and N/A 12. Attachments: Proposal Summary Q Wellbore schematic Q 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: Commencing Operations: 7/1/2016 OIL Q 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 _ A herein will not be deviated from without prior written approval. Contact Paul Chan _ST Email chan hilcor .com Printed Name !3a York �1 Title Area Operations Manager Signature ZZ -- _ ._ Phone 777-8345 Date 6 z7 r " COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑p Other. tE �'�zOn l%L�l �►�tz�{ y�e p��/Y3L �v�t� IC �� �'�� �j��� Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: 7 RBDMS LA-- JUL 0 6 20 E APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Form 10-403 Revised 11/2015 0 �ravQ3l IN aA Lalid for 12 months from the date of approval. Submit Form and Attachments in Duplicate Hilcorp Alaska, LLI Well Prognosis Well: MPU C -15A Date: 6/27/2016 Well Name: MPU C -15A API Number: 50-029-21358-01 Current Status: Cleaning out liner Pad: C -Pad Estimated Start Date: July 1St, 2016 Rig: E -line Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: ± 9,537' Regulatory Contact: Tom Fouts Permit to Drill Number: 216-070 First Call Engineer: Paul Chan (907) 777-8333 (0) (907) 444-2881 (M) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Current Bottom Hole Pressure: 4,459 psi @ 8,750' TVDss (Estimated Pressure / 9.8 ppg EMW) Maximum Expected BHP: 4,459 psi @ 8,750' TVDss (Initial Sag perforations) MPSP: 3,584 psi (0.1 psi/ft gas gradient) Brief Well Summary: MPU C-15 was drilled and completed with a single selective completion in June 1985, fracture stimulated in September and converted to water injection in December 1986. The well was worked over April 1995 in preparation for WAG injection. The well has being deepened to the Sag River formation as well MP C - 15A. Note: The Kuparuk sands will be isolated from the wellbore by the 4-1/2" Sag production liner. ✓ Notes Regarding Wellbore Condition • The 4-1/2" liner has been run and cemented. Currently, running in hole to cleanout the liner. Objective: Initial perforations in the Sag River formation. Brief Procedure: 1. MIRU Slickline. PT lubricator to 1500 psi. Note: Wellbore will be hydraulically isolated from the reservoir with a cemented production liner. 2. Pull ball/rod. Pull RHC ball catcher. 3. Drift and tag to PBTD with dummy gun. 4. RDMO slickline. 5. MIRU e -line 6. Pressure test lubricator to 4000 psi. 7. Run GR/CCL/PNL/CBL logs. 8. Perforate the Sag River A and B formations. TVD and MD depths are from the open hole log and will be adjusted after running the cased hole reference logs. 9. RDMO a -line. Formation Top (TVD) Bottom (TVD) Top (MD) Bottom (MD) Sag A ± 8,949' ± 8,963' ± 9,574' ± 9,591' Sag B ± 8,918' ± 8,949' ± 9,537' ± 9,574' 9. RDMO a -line. Hilcaru Alaska, LU Attachments: 1. Proposed Schematic Well Prognosis Well: MPU C -15A Date: 6/27/2016 Milne Point Unit Well: MPU C -15A PROPOSED SCHEMATIC Last Completed: June, 2016 Ililcorp Alaska, LLc PTD: 216-070 KB Elev.: 50.4' / GL Elev.: 16.7' TD = 9,928 (MD) / TD = 9,25U(TVD) PBTD = 9,843' (MD) / PBTD = 9,177'(TVD) TREE & WELLHEAD Tree 4-1/16" 5M Wellhead FMC M.P w/ 11" x 5M top flange. CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 48 / H-40 / Weld 12.5" Surface 105' 9-5/8" Surface 36 / K-55 / BTC 8.921" Surface 4,692' 7" Production 26 / L-80 / BTC 6.276" Surface 7,653' 4-1/2" Liner 12.6/13Cr-80/Vam TOP 3.958" 6,908 9,928' TUBING DETAIL 4-1/2" Tubing 12.6/13Cr-80/Vam TOP 1 3.958" 1 Surf 6,918' JEWELRY DETAIL No Depth Item 1 30' Tubing Hanger, 4-1/2" EUE 8rd threads on top & btm 2 6,755' Halliburton "XD" Sliding Sleeve 3 6,825' 7" x 4-1/2" Chrome permanent packer 4 6,900' 4-1/2 "XN" profile with RHC Ball Catcher 5 6,908' 7" x 4-1/2" Baker ZXP Liner top packer 6 6,918' Mule Shoe WLEG WELL INCLINATION DETAIL 7" Shoe at 7653' at 17.47 deg incl. Max Hole Angle = 36.3 deg at 9,266' MD PERFORATION DETAIL Sag River Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status Sag B 9,537' 9,574' 8,918' 8,949' 37 Proposed Sag A 9,574' 9,591' 8,949' 8,963' 17 Proposed Created By:LEK 5/6/2016 Modified by: STP 6/27/2016 Schwartz, Guy L (DOA) From: Stan Porhola <sporhola@hilcorp.com> Sent: Friday, July 01, 2016 8:47 AM To: Schwartz, Guy L (DOA) Cc: Wyatt Rivard; Paul Chan Subject: MPU C -15A PTD 216-070 (Sundry submitted 6-27-16) request for packer depth variance per CO 423 Rule 6 Follow Up Flag: Follow up Flag Status: Flagged Guy, A sundry was submitted for the perforating of well MPU C -15A (PTD 216-070) on 6/27/16. The 4-1/2" liner top is located at 6,908' inside the 7" production casing since this well was deepened by drilling out the casing shoe in the Kuparuk and drilled down to the Sag River at +/- 9,500' MD (+/- 8,850' TVD). To maintain an entire 4-1/2" completion string, the packer had to be set above the liner top. Therefore, we would like to request a variance to CO 423 Rule 6 to set the completion packer more than 200'_..above the productive interval. Regards, Stan Porhola I Operations Engineer North Slope Asset Team Hilcorp Alaska, LLC sporhola@hilcorp.com Office: (907) 777-8412 Mobile: (907) 331.-8228 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Thursday, June 30, 2016 4:59 PM To: 'Wyatt Rivard' Cc: Bettis, Patricia K (DOA) Subject: RE: CO 423 Sag Pool Rule 6 "Tapered Casing" Packer Set Depth (C -15A PTD 216-070) Wyatt, CO 423 states that both producers and injectors need to have a packer or equivalent device within 200 ft. You will need to submit a request for a variance for the packer placement.. we still have the perforation sundry so it could be amended with the request. It looks like this slipped through the "cracks" in the PTD approval process as the completion was part of the drilling application. I would submit a formal request by email for the variance. 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). From: Wyatt Rivard [mailto:wrivard(&hilcorp.com) Sent: Thursday, June 30, 2016 3:39 PM To: Schwartz, Guy L (DOA) Subject: CO 423 Sag Pool Rule 6 'Tapered Casing" Packer Set Depth Hello Guy, Hilcorp is seeking clarification regarding the CO 423 Sag Pool Rules at Milne Point (attached). Specifically, Rule 6 Well Completions states: "Production or injection wells may be completed with tapered casing provided a sealbore packer, or other isolation device is positioned not more than 200 feet above the top of the productive interval." We would like to confirm that "tapered casing" refers to production casing strings in which one size/weight of casing crosses over to a different size/weight of casing using a threaded connection. This would be to differentiated from a well completed with a different size/weight production liner hung off a liner top packer set inside the production casing. As the 200 foot requirement applies to both injectors and producers, Hilcorp is seeking clarification on this with respect to MPC -15A (PTD # 216070). MPC -15A was recently sidetracked as a SAG producer with a liner top packer hung roughly 2000' TVD above the producing formations and we would like to verify that we do not need to seek a variance to CO 423 due to the packer height. Thank You, THE STATE 01ALASKA GOVERNOR BILL WALKER Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Milne Point Field, Sag River Oil Pool, MPU C -15A Hilcorp Alaska, LLC Permit to Drill Number: 216-070 Surface Location: 724' FSL, 2098' FEL, SEC. 10, T13N, RI OE, UM, AK Bottomhole Location: 698' FNL, 342' FEL, SEC. 15, TI 34N, RI OE, UM, AK Dear Mr. Keller: Enclosed is the approved application for permit to re -drill the above referenced development well. All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. 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 27 day of May, 2016. STATE OF ALASKA AL. :A OIL AND GAS CONSERVATION COMM,. JN PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: 1 h. Proposed Well Class: Exploratory -Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development - Oil Service - Winj ❑ Single Zone 21. Coalbed Gas ❑ Gas Hydrates ❑ Redril 0 ' Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket [Z. Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 , MPU C -15A 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 9,873' ' TVD: 9,197' Milne Point Unit Sag River Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 724' FSL, 2098' FEL, Sec 10, T1 3N, R1 OE, UM, AK ADL047434 (SHL) ADL025516 (TPH/BHL) Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 484' FNL, 346' FEL, Sec 15, T13N, R10E, UM, AK N/A 6/8/2016 9. Acres in Propertv: 14. Distance to Nearest Propertv: Total Depth: 698' FNL, 342' FEL, Sec 15, T1 3N, R1 OE, UM, AK - ADL047434 (2560) ADL025516 (1280) • 10,915' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): lr(ei7 4 15. Distance to Nearest Well Open Surface: x-558366 y- 6029007 Zone - 4 GL Elevation above MSL (ft): 1 16.7 to Same Pool: 6900' MPC -23 16. Deviated wells: Kickoff depth: 7,700 feet , 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 35 degrees , Downhole: 4687 • Surface: 3768 . 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole I Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 6-1/8" 4-1/2" 12.6# L-80 13Cr Vam Top 2,873' 7,000' 6,692' 9,873' 9,197' 423.4 ft3 of 15.8 ppg 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): 7,665' 7,319' N/A 7,572' 7,231' N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 80' 13-3/8" To Surface 105' 105' Surface 4,655' 9-5/8" 1,565 sx 4,692' 4,584' Intermediate Production 7,616' 7" 250 sx 7,653' 7,307' Liner Perforation Depth MD (ft): See MPC -15 Schematic Attached Perforation Depth TVD (ft): See MPC -15 Schematic Attached 20. Attachments: Property Plat ❑✓ BOP Sketch 0 Drilling Program Q Time v. Depth Plot E] Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements 21 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Luke Keller Email Ikeller hilcor .com Printed Name Luke Keller Title Drilling Engineer Signature Phone 777-8395 Date 5/9/2016 Commission Use Only Permit to Drill � API Number: 1 Permit Approval See cover letter for other Number: — Q �10 50- ()19 Date: J 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: amu/ Other:oo® -�— 'f,�!s� 6r�� ��� r Samples req'd: Yes No 11 Mud log req'd: Yes No ❑ H2S Yes No[] Yes [INo ❑ / measures: svy req'd: Spacing exception req'd: Yes ❑ No V Inclination -only svy req'd: Yes E] No d C C L i -e— u_fin r'/ 4v Post initial injection MIT req'd: Yes E] No ❑ �`j� �y^ J��►^ APPROVED BY Approved by(;m COMMISSIONER THE COMMISSION Date: Z?_ / S '`�� t RdA2 Submit Form and Form 10-401 ( evi 11/2015) GiRJ aLthsfro'm"th'ed'at-e'o'f"approvoael'(2'0-A/ACW2'5'005(g)) Attachments in Duplicate 0 Hikorp Ala l.a, LLC May 9th, 2016 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Luke Keller Drilling Engineer Re: MPC -15A 'S C, - Cb -near Commissioner r ( Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com MAY 11 2016 A 0 MPU C -15A peneng of the parent well. C-15. C-15 is currently a producer in the Kuparuk formation. The wellbore will first be prepared by cutting and pulling the existing 3-1/2" injection tubing, burning over and recovering the permanent Baker model "S-3" packer, then drilling out the existing 7" 26# production casing. The target formation of C-1 5A is the Sag River sand package which is mostly untested in this fault block. The well will be deepened approx 3000' MD to get a look at the Sag River Sands. Drilling operations are expected to commence approximately June 8th, 2016. Doyon #14 will be used to drill and complete the wellbore. The existing 7" surface casing will be used and a pressure test conducted prior to cutting and pulling the production tubing. This well is a candidate for a fracture stimulation later after a period of stable production is obtained. The base plan is to produce the well without a fracture stimulation. A 10-403 Sundry application for the fracture stimulation will be submitted separate from the drilling permit. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, zz1d1z___ Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page i of 1 Hilcorp Alaska, LLC Milne Point Unit (MPU) C -15A Drilling Program Version 1 May 9th, 2016 Milne Point Drilling Procedure 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 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work.........................................................................................................10 10.0 Rig Orientation on "C" Pad.........................................................................................................11 11.0 6-1/8" Hole Section Mud Program...............................................................................................12 12.0 Drill 6-1/8" Hole Section...............................................................................................................13 13.0 Run 4-1/2" Production Liner.......................................................................................................16 14.0 Cement 4-1/2" Production Liner.................................................................................................19 15.0 Wellbore Clean up and Upper Completion................................................................................23 16.0 Production Tubing Installation....................................................................................................24 17.0 BOP Schematic..............................................................................................................................26 18.0 Wellhead Schematic......................................................................................................................27 19.0 Days vs Depth................................................................................................................................28 20.0 Anticipated Drilling Hazards.......................................................................................................29 21.0 Doyon #14 Rig Layout...................................................................................................................30 22.0 FIT Procedure...............................................................................................................................31 23.0 Choke Manifold Schematic..........................................................................................................32 24.0 Casing Design Information...........................................................................................................33 25.0 6-1/8" Hole Section MASP............................................................................................................34 26.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................35 27.0 Surface Plat (As Built) (NAD 27).................................................................................................36 28.0 Drill Pipe Specifications................................................................................................................37 Milne Point Drilling & Completion Procedure Ililrorp UaAa, LLC 1.0 Well Summary Well MPU C -15A Pad Milne Point "C" Pad Planned Completion Type Jet Pump on 4-1/2" Production Tubing Target Reservoir(s) Sag River B & A sands Planned Well TD, MD / TVD 9,873' MD / 9,197' TVD PBTD, MD / TVD 9,800' MD / 9,137' TVD Surface Location (Governmental) 724' FSL, 2098' FEL, Sec 10, TON, R10E, UM, AK Surface Location (NAD 27 — Zone 4) X=558,366.14, Y=6,029,007.58 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 484' FNL, 346' FEL, Sec 15, TUN, R10E, UM, AK TPH Location (NAD 27) X=560,129 Y=6,027,813.57 TPH Location (NAD 83) BHL (Governmental) 698' FNL, 342' FEL, Sec 15, TON, R10E, UM, AK BHL (NAD 27) X=560,135.34 Y=6,027,599.64 BHL (NAD 83) AFE Number 1610896D AFE Drilling Das 10 AFE Completion Das 5 AFE Drilling Amount AFE Completion Amount AFE Facility Amount Maximum Anticipated Pressure (Surface) 3768 psig Maximum Anticipated Pressure Downhole/Reservoir i 4687 psig Work String 4" 14# S-135 HT -38 (Weatherford Rental) KB Elevation above MSL: 33.7 + 16.7 ft = 50.4 ft AMSL GL Elevation above MSL: 16.7 ft AMSL BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ilileor1) k1aAa.. LLC 2.0 Management of Change Information Hilcorp Alaska, LLC hxWC rP Changes to Approved Permit to Drill Date: 3-15-2016 Subject: Changes to Approved Permit to Drill for MPU C -15A File #: MPU C -15A Drilling and Completion Program Any modifications to MPU C -15A Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved by the AOGCC_ Approval: Prepared: Drilling Manager Drilling Engineer Date Date Page 3 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ililrorp Alaska, LLC 3.0 Tubular Program: Hoe ` D (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section S-135 HT -38 18,428 in OD (in(#/ft) (psi) (psi)(k-lbs) 6-1/8" 4-1/2" 3.958 3.83 4.93 12.6 L-80 VAM 8430 7500 288 13 Cr TOP 4.0 Drill Pipe Information: Hole OD (in) ID (in) Section TJ ID in TJ OD in Wt WHO Grade Conn Burst (psi) Collapse (psi) Tension (k -lbs) 6-1/8" 4" 3.34" 2.563" 4.875" 14 S-135 HT -38 18,428 13,836 403 All casing will be new, PSL 1 (100% mill inspected). Page 4 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ilileurp Ua.Aa. LLC 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. i. Report covers operations from 6am to 6am ii. 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. iii. Ensure time entry adds up to 24 hours total. iv. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. v. Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates i. Submit a short operations update each work day to pmazzolinighilcorp.com , lkeller@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update i. Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting i. Health and safety: Notify EHS field coordinator. ii. Environmental: Drilling Environmental coordinator iii. Notify Drlg Manager & Drlg Engineer iv. Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally i. Send final "As -Run" Casing tally to Ikeller@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report i. Send casing and cement report for each string of casing to Ikeller@hilcorp.com and cdinger@hilcorp.com 5.7 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 Luke Keller 907.777.8395 832.247.3785 lkeller@hilcorp.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 pchan@hilcorp.com Geologist Daniel Yancey 907.777.8458 907.250.9632 dyancey@hilcorp.com Reservoir Engineer Anthony McConkey 907.777.8460 907.529.6199 amcconkev@hilcorp.com Drlg Environmental Coord I Julieanna Orczewska 1 907.777.8444 907.715.7060 0orczewska@hilcorp.com EHS Manager/ Coordinator Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 March, 2016 Ilileur1. kla,ka.1.1.0 6.0 Planned Wellbore Schematic IB Elev.: 50.4 / GL Elev.:16.7' TD = 9,873 (ND) / TD = 9,197(M) PBTD = 9,800' (ND) / PBTD = 9,137(M) T -P P -4S Milne Point Drilling & Completion Procedure TREE & WELLHEAD Tree FMC 3-1/8" 5M (will change to 5-1/8" x SM post completion] Wellhead FMC M.P w/ 11" x 5M top flange. CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 48 / H-40 / Weld 12.5" Surface 105' 9-5/8" Surface 36 / K-55 / BTC 8.921" Surface 4,692' 7" Production 26 / L-80 13Cr / BTC 6.276" Surface 7,653' 4-1/2" Liner 12.6 / L-801 Cr / Vam 3.958" 7,000 9,873' TUBING DETAIL 4-1/2" Tubing 12.6/L-80o133Cr/Vam 7,010' 3.958" Surf JEWELRY DETAIL No Depth Item 1 30' Tubing Hanger 4-1/2" x 7-5/8" EUE 8rd threads on top & btm 2 2000' "X" profile 3 6855' Halliburton "XD" Sliding Sleeve 4 6925' 7" x 4-1/2" Chrome permanent packer 5 7000' "XN" profile with RHC Ball Catcher 6 7000' 7" x 4-1/2" Baker ZXP Liner top packer 7 7010' Mule Shoe WLEG WELL INCLINATION DETAIL 7" Shoe at 7653' at 17.47 de incl. Max Hole Angle= 35 degfrom 8376' MD to 9873' MD r5c.l.c be"—P' �:'n: a l- . Page 6 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ililrurp Alaska. IJA: 7.0 Drilling / Completion Summary MPU C -15A is a deepening of the parent well, C-15. C-15 is currently a producer in the Kuparuk formation. The wellbore will first be prepared by cutting and pulling the existing 3-1/2" injection tubing, burning over and recovering the permanent Baker model "S-3" packer, then drilling out the existing 7" 26# production casing. The target formation of C -15A is the Sag River sand package which is mostly untested in this fault block. The well will be deepened approx 3000' MD to get a look at the Sag River Sands. Drilling operations are expected to commence approximately June 8�', 2016. Doyon #14 will be used to drill and complete the wellbore. The existing 7" surface casing will be used and a pressure test conducted prior to cutting and pulling the production tubing. This well is a candidate for a fracture stimulation later after a period of stable production is obtained. The base plan is to produce the well without a fracture stimulation. A 10-403 Sundry application for the fracture stimulation will be submitted separate from the drilling permit. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility on "B" pad. The back-up option is to haul all mud and cuttings to the BP G&I facility at Prudhoe Bay. / A separate sundry notice will be submitted to cover wellbore preparation for the deepening and will be included with the PTD submittal to the AOGCC. The P&A/wellbore preparation sundry will cover the following operations: 0 3/6 1. Circ kill weight fluid in well. Conduct pressure test of the 7" x 3-1/2" annulus to 3000 psi/30 min. 2. Cut 3-1/2" tubing above pkr at 7142'., 3. MOB Doyon # 14 to the well site. 4. N/D tree, N/U & test BOP. 5. Recover 3-1/2" tubing 6. Mill Baker model S-3 permanent packer, fish and recover S-3 packer. 7. Commence drilling operations on 10-401. General sequence of operations pertaining to this approved drilling procedure: 1. M/U 6-1/8" directional drilling assy, TIH and drill 6-1/8" production hole section to TD. 2. Run 4-1/2" production liner and 4-1/2" production tubing. 3. N/D BOP, N/U tree, RDMO. Reservoir Evaluation Plan: 1. Production Hole: Mud loggers. No on site geologist. LWD: GR + Res. 2. Cased Hole Logs: GR + CCL + PNL + CBL will be run via wireline after Doyon 14 RDMO. Page 7 Version 1 March, 2016 Milne Point Drilling & Completion Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. 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 C -15A. 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 10/10 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, 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". • Ensure both AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: • There are no variance requests at this time. Page 8 Version 1 March, 2016 Hile-1; :Ua.ka.. LLC Milne Point Drilling & Completion Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate o Blind ram in btm cavity Initial Test: 250/4000 (Annular 2500 psi) • Mud cross w/ 3" x 5M side outlets 6-1/8" • 13-5/8" x 5M Hydril MPL 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: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, 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. Additional requirements may be stipulated on APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regg_kalaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy. schwartzkalaska.gov Mike Quick / Petroleum Engineer / (0):907-793-1231 / Email: mike.quick o,alaska. ov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria. loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors o,alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.htmi Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 1 March, 2016 Milne Point Drilling & Completion Procedure 114corp .%64a, 1.11: 9.0 R/U and Preparatory Work 9.1 Level pad and layout rig mats for footprint of rig. 9.2 Drive rig over well and ensure rotary centered over wellhead. Confirm that rig is over appropriate well — C -15A. 9.3 Spot & tie in service company shacks and water/displacement tanks. 9.4 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.5 Mud Loggers WILL be used on C -15A.' 9.6 Mix mud for 6-1/8" hole section. 9.7 Set test Plug in wellhead prior to N/U BOP to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.8 Keep 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. 9.9 Conduct P&A operations which include: • Circ kill weight fluid in well. Conduct pressure test of the 7" x 3-1/2" annulus to 3000 psi/30 min. • MOB Doyon # 14 to the well site. • N/D tree, N/U & test BOP. • Recover 3-1/2" tubing. • Burn over Baker model S-3 permanent packer, fish and recover S-3 packer. • Commence drilling operations on 10-401. NOTE: A separate sundry will be submitted to the AOGCC that covers P&A operations, and will accompany the PTD application. 44 316 "d( Page 10 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ifiie—If uaAa. LII: 10.0 Rig Orientation on "C" Pad. 8-= - 8 oz Page 11 Version 1 March, 2016 11.0 6-1/8" Hole Section Mud Program Milne Point Drilling & Completion Procedure • 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: 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. • Shale Stabilization: Maintain adequate concentrations of shale stabilizer while drilling the Jurassic (Kingak) formation. BAROTROL PLUS and BDF-515 should be run at 4 ppb (2 ppb each) background and raised to 8 ppb (4 ppb each) while drilling through the Kingak shale. • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • MD Totco 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: 10.5 — 12 ppg 3% KCL LSND Properties: System Formulation: 3% KCL LSND Product Mud Water 0.94 bbl KCL 11 ppb Caustic soda 0.2 ppb BARAZAN D PLUS 1.25 ppb (as required for 14 - 18 YP) PAC L 1.0 ppb Plastic Yield BARACARB 5/25/50 5.0 ppb BAROTROL PLUS/BDF-515 4.0 ppb (2 ppb each) Depths Weight Viscosity 1.0 ppb BARASCAV D pH MBT 0.25 b LGS pg Viscosity Point HPHT 7,653'- 10.5— 14— 9.0— <6 40-53 15-25 <10 < 11.0 9,873' 12 18 10.0 — % System Formulation: 3% KCL LSND Product Concentration Water 0.94 bbl KCL 11 ppb Caustic soda 0.2 ppb BARAZAN D PLUS 1.25 ppb (as required for 14 - 18 YP) PAC L 1.0 ppb DEXTRID LT 3.0 ppb BARACARB 5/25/50 5.0 ppb BAROTROL PLUS/BDF-515 4.0 ppb (2 ppb each) BAROID 41 as required for a 10.0 — 10.5 ppg MW BARACOR 700 1.0 ppb BARASCAV D 0.5 ppb ALDACIDE G 0.25 b Page 12 Version 1 March, 2016 12.0 Drill 6-1/8" Hole Section Milne Point Drilling & Completion Procedure 12.1 P/U 6-1/8" 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 TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. • Workstring will be 4" 14# S-135 HT -38. • Install ported float above motor. 12.2 6-1/8" BHA (Includes GR+Res LWD components & PWD): COMPONENT Rem DATA Description Serial Number .. ID Gouge Weight (tbpf) Top Connection Length N Length (ft) 1 PDC SKH1519S 4.900 1.500 6.125 58.24 P 3-112" REG 0.70 0.70 2 5" SperryDnill Lobe 6f7 - 6.0 sig 5.000 3.120 48.00 B 3-112" IF 23.50 24.20 Stabilizer 6.000 3 4-314" Float Sub 4.750 2.250 46.84 B 3-112" IF 2.20 26.40 4 4-314" Stabilizer 4.750 2.250 6.000 46.84 B 3-112" IF 3.00 29.40 5 4-314" DM (Directional) 4.750 2.610 47.00 B 3-112" IF 9.20 38.60 6 4-314" SP4 (Resistivity & Gamma) 4.750 1.250 48.20 B 3-112" IF 24.25 62.85 7 4-314' PWD (Pressure) 4.750 1.250 47.90 B 3-112" IF 9.17 72.02 8 4-314" TM (Telemetry) 4.750 2.000 49.69 B 3-112" IF 11.00 83.02 9 4-314" NM Flex Collar 4.750 2.250 46.84 B 3-112" IF 30.00 113.02 10 4-314" NM Flex Collar 4.750 2.250 1 46.84 B 3-112" IF 30.00 143.02 11 4-314" NM Flex Collar 4.750 2.250 46.84 B 3-112" IF 30.00 173.02 12 XO Sub 3.5 IF Pin x HT38 5.000 2.625 48.47 B 4" HT38 2.00 175.02 13 6 jts 4-1t2- HWDP HT38 4.000 2.563 29.70 180.00 355.02 14 4-314" Jar 4.750 2250 43.90 B 4" HT38 30.00 385.02 15 11 jts 4-112' HWDP HT38 4.000 2.563 29.74 330.00 715-02 Bit Number Bit Size (in) : 6.125 Manufacturer : NOV 1 ReedHycalog Madel SKH1519S Serial Number .. 715.02 Nozzles : 5x11 TFA (In2) :0.4640 Dull Grade to Dull Grade Out Page 13 Version 1 March, 2016 Ililvoilr ua4ar..I'Ll: 12.3 Primary Bit: KOYWellbore Technologies 6 1/8" SKH1519S Design Features of this bit Seekern Directional Drill Oita Seeker— directional drill bits are designed to overcome directional drilling challenges for both motor or RSS tools in a wide range of directional applications. Milne Point Drilling & Completion Procedure Design Specifications Make up Length (ft): 70 Shank Diad (ins): 0 Connection std: Y Connection Size(ins): 3.500 Connection Type: Api Reg Pin Make up Torque (ft -lbs): 8500 IADC Code: M222 Diameter(ins) 6 1W Body Material: Steel JSA(in2): 9.030 Face Volume:(in') 39.68 Normailised Face vol: 60,51% Blade City 5 Gauge Length:(ins) 3.000 Hellon r" Impact Extreme Durability cutters Advanced thermostable PDC cutters integrating the Gauge GeometrT Spiral -Trailing improved thermal toughness of our Helios— cutter technology with improved impact -resistant edge Gauge Profile: Slickgauge geometry_ These extreme durability cutters are better suited to withstand edge chipping experienced Gauge Protection: Hardfaced in harsh interbedded applications, where impact and cutter overload are the predominant cutter failure 5 BACK -ANGLE 13 mm CYLINDER mechanism. Semi-Acthre Gauge- Gauge design configuration featuring a unique combination of reaming Bit Profile: Snort raper - sapumw Ci— eternents and optional tapered gauge geometry. Engineered to achieve moderate dog legs, maintain verticality. and resist unintended dropping or buildlig events. Recommended Operating Parameters HardFacing- A coating of erosion resistant carbide material applied to steel -bodied bits and tools dramatically enhances the erosions resistance of the body. By virtue of the strength of steel, high Max Operating WOB (kibs):27 blades and face volumes allow higher ROPs to be achieved. Min TFA (in2): 0.2455 Max TFA (in2): 1.8560 Spiral Gauge- Stability is improved by increasing the circumferential contact of the bit gauge. Improved stability enhances steerability and ROP. Max Flow (gpm): 779 HSI: 1-6 This bodied PDC bit features computer aided cutter placement and hydraulics optimized by nozzle location to deliver high performance and longer bit life. Cutting Structure —iiiii_. -- ..._ ....- city Lora"M Dbnww shape Primary 13 FACE 19 mm IMPACT Primary 9 GAGE 19 mm CYLINDER Primary 5 BACK -ANGLE 13 mm CYLINDER Bit Breaker. Thick 1 h' M sax appecainns LM bN is mo s-ce—W be~ 11— p-6— 6— C—f—t your NOV R-dHycmbp RepreseM Wt fpr mc—ilydaMraVg P—Mrs M)nuc mppacatnrr. NOV Reearyrmbp.msarves Lie HOW to MWW Masa 6pecaxmdp based art mtlNapces and Nal—its er tactsndbpy. This report is va4id for 30 days from 08-0ec-2015 Nozzles & Ports QtY ljfPa size 5 TNZ VARIABLE Page 14 Version 1 March, 2016 Milne Point Drilling & Completion Procedure 12.4 TIH w/ 6-1/8" directional assy, shallow test MWD and LWD on trip in. 12.5 Drill out remaining shoe track + 20' of new hole. Conduct FIT to 13 ppg EMW. • If 13 ppg not achieved, be prepared to squeeze shoe. 12.6 Drill 6-1/8" hole section to section TD per Geologist and Drilling Engineer. • Pump at 250-300 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 water or other low vis sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips every 1500 — 2000 ft if necessary. • Take MWD surveys every stand drilled. 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. 12.7 At TD; pump hi vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the shoe. If backreaming is necessary: • Circulate at full drill rate (250-290 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. V 12.8 TOH with the drilling assy, stand back BHA if possible. Rabbit DP on TOH. 12.9 No additional OH logs are planned for the 6-1/8" hole section. Page 15 Version 1 March, 2016 Milne Point Drilling & Completion Procedure (lileorp .uaAa. LLA: 13.0 Run 4-1/2" Production Liner 13.1 Ensure rams have been tested on 4-1/2" test joint prior to running liner. 13.2 Ensure wear bushing is installed in wellhead. 13.3 M/U and rack cement stand in derrick. Ensure to drift components prior to M/U. Ensure dart is loaded correctly and that it will pass through ALL components in the cmt stand + running string. Confirm largest OD of packer assy will pass through the wear bushing. 13.4 R/U 4-1/2" casing running equipment. • Ensure 4" HT -38 x 4-1/2" VAM TOP crossover is on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck 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. 13.5 P/U shoe joint, visually verify no debris inside joint. 13.6 Continue M/U and thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar installed INSIDE pin end. • Solid body centralizers will be pre-installed on shoe joint & FC joint. Install a solid body centralizer on landing collar joint. Leave centralizers free floating so that they can slide up and down the joint. Ensure proper operation of float shoe. 13.7 Run 4-1/2" liner per completion tally. • Use "Jet Lube Seal Guard" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every joint to 8800', every 4 1 joint there after • Utilize a collar clamp until weight is sufficient to keep slips set properly. Bottom connection on liner hanger is 4-1/2" Vam Top pin Torque turn liner Page 16 Version 1 March, 2016 Milne Point Drilling & Completion Procedure I lilcm p .ua.ka. ILC 4-1/2" VAM TOP M/U toraues Casinj:0D= Minimum Optimum Maximum 4.5" 1 4,000 ft -lbs 4,440 ft -lbs 4,880 ft -lbs Issued on: 18 Mar. 2016 0 Tensile Yield Strength 288 Mb Min. Make-up torque 4000 ft.lb Compression Resistance Connection Data Sheet OD Weight Wali Th.I Grad API Drift Connection 4 112 in. 12.60 Iblft I I 0.271 in. 1_80 13Cr 3.833 in. I I VAM@ TOP Tubing PIPE PROPERTIES m CONNECTION PROPERTIES Nominal OD 4.500 in. Connection Type PremiumT&C Nominal ID 3.958 in. Connection OD (nom) 4.937 in. Nominal Cross Section Area 3.600 sqin. Connection ID (nom) 3.913 in. Grade Type 13%Cr Make-up Loss 3-222 in. Min. Yield Strength 80 ksi Coupling Length 7.44 in. Max. Yield Strength 95 ksi Critical Cross Section 3.600 sgin. Min. Ultimate Tensile Strength 95 ksi Tension Efficiency 100 °l of pipe Compression Efficiency 100 %of pipe Internal Pressure Efficiency 100 % of pipe External Pressure Efficiency 100 % of pipe CONNECTION PER•• t TORQUE Tensile Yield Strength 288 Mb Min. Make-up torque 4000 ft.lb Compression Resistance 288 kib Opti. Make-up torque 4440 ft. lb Internal Yield Pressure 8430 psi Max. Make-up torque 4880 ft.lb External Pressure Resistance 7500 psi Max. Bending with Seatability (CAL IV) 30 `1100 ft Max. Load on Coupling Face 162 k)b VAM TOP Iz a 4'1,") VAW TOP tubing (2 318"-4 'A") is the most used premium vMe rA@1tanlence fi, vNope tubing connection throughout the world Poe 8wf YME LA nttt- VIAE The product line has been extensively tested as per IS013679 CAL IV, with more than 60 qualification tests, on AV. loovays the full pipe body envelope. d: o — f F 10W. AM 10 i I53 1xr w a oi; IW Ani L -d iK PWM Page 17 Version 1 March, 2016 Milne Point Drilling & Completion Procedure llilvoq) Ala,k.. LIA: 13.8 Ensure to run enough liner to set liner top at 7000' MD. Ensure hanger/pkr will not be set in a 7" connection. The long overlap is to cover the existing Kuparuk perf interval. 13.9 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. N. 13.10 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 13.11 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. Circ a minimum of one liner volume. 13.12 RIH w/ liner on DP no faster than 1-1 /2 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.13 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 13.14 Circulate 1-1 /2 drill pipe and liner volume at 7" shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. Nominal liner hanger setting pressure is 2500 psi. 60% of this value is 1500 psi 13.15 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10; 20, & 30 rpm. 13.16 Continue to fill the DP every stand down using fill up line on rig floor. Do not stop to fill casing. 13.17 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack -off and pick-up weights. Record rotating torque values at 10, 20, & A0 rpm. 13.18 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure (1500 psi). Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 13.19 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 18 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ilitrorp AlaAa.. LIA: 14.0 Cement 4-1/2" Production Liner 14.1 Hold a pre job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates. • How to handle cmt 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 cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. Need to be ready for a backup plan if there is an issue with the primary displacement pump. 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 cmt pump or treating iron will not be pumped downhole. 14.4 Attempt to reciprocate the liner during cmt operations. 14.5 Pump 5 bbls 12 ppg Cleanspacer III. 14.6 Test surface cmt lines to 4500 psi. 14.7 Pump remaining 15 bbls 12 ppg Cleanspacer III. 14.8 Mix and pump 15.8 ppg "Ha1Cem" curt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 100% OH excess. Section: Calculation: Vol (BBLS) Vol (ft3) 7" x 4 DP" Overlap: 200' x 0.023 = 4.5 25.3 7" x 4.5" Liner Overlap: 653' x 0.019 = 12.4 69.6 6-1/8" OH x 4.5" Liner: (9,873 — 7,653) x 0.017 1.5 = 57 320.1 Shoe Track: 90' x 0.015 = 1.5 8.4 Total Volume: 1 75.4 423.4 s Page 19 Version 1 March, 2016 �7 X Milne Point Drilling & Completion Procedure Hile—p %laAa. LH: Slurry Information: 14.9 Drop DP dart and displace with 10.5 ppg drilling fluid. 14.10 Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point. 14.11 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 14.12 Bump the plug and pressure up as required by Baker procedure to set the liner hanger (20% above nominal setting pressure. 2500 psi is nominal setting pressure. Pressure up to 3000 psi to confirm hanger setting. 14.13 Slack off total liner weight plus 20k to confirm hanger set. 14.14 Do not overdisplace by more than 1/2 shoe track. Shoe track volume is 1.5 bbls. 14.15 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner. 14.16 Bleed pressure to zero to check float equipment. 14.17 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve. 14.18 Rotate slowly and slack off 50k downhole to set the ZXPN liner top packer. 14.19 P/U to P/U weight plus 1 ft. 14.20 Close annular and test 4" DP x 7" annulus to 1500 psi / 10 min to test liner top packer. 14.21 Bleed off pressure, open up annular. Page 20 Version 1 March, 2016 HaICEM System HaICEM TM System Density 15.8 lb/gal Yield 1.526 ft3/sk �- Mix Fluid 6.2 gal/sk 14.9 Drop DP dart and displace with 10.5 ppg drilling fluid. 14.10 Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point. 14.11 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 14.12 Bump the plug and pressure up as required by Baker procedure to set the liner hanger (20% above nominal setting pressure. 2500 psi is nominal setting pressure. Pressure up to 3000 psi to confirm hanger setting. 14.13 Slack off total liner weight plus 20k to confirm hanger set. 14.14 Do not overdisplace by more than 1/2 shoe track. Shoe track volume is 1.5 bbls. 14.15 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner. 14.16 Bleed pressure to zero to check float equipment. 14.17 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve. 14.18 Rotate slowly and slack off 50k downhole to set the ZXPN liner top packer. 14.19 P/U to P/U weight plus 1 ft. 14.20 Close annular and test 4" DP x 7" annulus to 1500 psi / 10 min to test liner top packer. 14.21 Bleed off pressure, open up annular. Page 20 Version 1 March, 2016 uilrurlr Alaska. LLC Milne Point [Drilling & Completion Procedure 14.22 Pressure up to 500 psi down DP and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops off rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 14.23 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 14.24 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 14.25 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 14.26 POOH, verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 14.27 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 14.28 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 14.29 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. 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, do 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 Page 21 Version 1 March, 2016 Milne Point Drilling & Completion Procedure • Note time cement in place • Note calculated top of cement • Add any comments which would describe the successor problems during the cement job Send final "As -Run " casingtally & casing and cement report to lkellerghilcorp. com. This will be included with the EOW documentation that goes to the AOGCC. Page 22 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ililcorp Alaska, LLC. 15.0 Wellbore Clean up and Upper Completion 15.1 M/tJ casing clean out assy complete with casing scraper assys for each size casing in the hole. • 3-3/4" bit or mill 7` • Casing scraper for 4-1/2" 12.6# casing • +/- 2800' 2-3/8" workstring. rcSf • Crossover (No PBR Polish Mills) • Casing scraper & brush for 7" 26# casing • (3500') 4" DP • Casing scraper & brush for 7" 26# casing • 4" DP to surface. 15.2 TIH & clean out well to landing collar (+/- 9,800' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. • Ensure bit is worked down to the landing collar. • Space out the cleanout BHA so that the bit reaches the landing collar when crossover is +/- 30' above the liner top. • The primary objective of the clean out run is to ensure the post rig logging runs & perf guns will reach intended depth. 15.3 After wellbore has been cleaned out satisfactorily using mud, test casing to 3000 psi / 30 min. 15.4 Displace drilling fluid in wellbore with a hi -vis pill followed by completion fluid. • Circulate fresh water into wellbore until clean-up is satisfactory. Do not recirculate fluid. • After a couple circulations, short trip the assy to bring the upper 7" scraper to surface. • RIH again & tag landing collar w/ 3-3/4" bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Displace well to completion fluid. 15.5 TOH w/ clean out assy. LDDP on the trip out. Note any abnormal wear on the clean out assy. Page 23 Version 1 March, 2016 Milne Point Drilling & Completion Procedure uileurp Uaska. LH: 16.0 Production Tubing Installation 16.1 M/U 4-1/2" tubing completion assy and RIH with same. • Ensure appropriate well control crossovers on are rig floor and ready. • M/U production packer per on site rep. Remove any protective packing from element. • Ensure all tubing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck 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. • Use "Jet Lube Seal Guard" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Torque turn tubing 0 4-1/2" Vam Top''/2 Mule Shoe WLEG, 5" OD @ —7010' 0 10' 4-'/2" 13Cr Vam Top pup with 5.75" OD oversized coupling (to no-go on top of tie back extension). OAL (from bottom of no-go to end of WLEG) = 10.0' 0 10' 4-'/z" 13Cr Vam Top bxp pup joint 0 4-'/2" 9Cr 'AN" profile with RHC ball catcher 0 10'4-V2" 13Cr Vam Top bxp pup joint o 1 joint 4-'/2" 12.6#/ft, 13Cr-80 Vam Top tubing o 10'4-V2" 13Cr Vam Top bxp pup joint o 7" x 4-'/2" Chrome permanent packer, Vam Top box x pin @ —6,925' MD o 10' 4-'/2" 13Cr Vam Top bxp pup joint o 1 joint 4-'/2" 13Cr Vam Top tubing o 10' 4-'/2" 13Cr crossover pup joint, Hydril 521 box x Vam Top pin o 4-'/2" Halliburton XD Sliding Sleeve, Hydril 521 box x pin @ — 6,855' MD o 10' 4-'/2" 13Cr crossover pup joint, Vam Top x Hydril 521 pin o 4-'/2" 13Cr Vam Top tubing o 10'4-V2" 13Cr Vam Top bxp pup joint o 4-'/2" 9Cr "X" profile at 2000' MD o 10'4-V2" 13Cr Vam Top bxp pup joint o 4-'/2" 13Cr Vam Top tubing o 4-'/2" 13Cr Vam Top space out pups o 1 joint 4-'/2" 13Cr Vam Top tubing o Tubing hanger w/ 4-1/2" TC -II pin x Vam Top pin crossover pup Page 24 Version 1 March, 2016 4-1/2" VAM TOP M/U torques Milne Point Drilling & Completion Procedure Casing OD Minimum optimum Maximum 4.5" 4,000 ft -lbs 4,440 ft -lbs 4,880 ft -lbs Take all the normal precautions while running the chrome tubing: clean threads if contaminated, use a stabbing guide, properly dope and hand -start each pin. Use Jet Lube Seal Guard thread compound and torque turn each connection. Tubing should arrive on location with the proper thread dope. Confirm type of thread compound prior to RIH. 16.2 RIH with completion to top of tie back receptacle at 7000' MD. Record PU and SO weights. SO past top of tieback receptacle and land on 5.75" no go. Slack off 15k pounds. Space out 5.75" no-go 1' - 2' above the tie back receptacle. Makeup the tubing hanger and landing joint 16.3 Reverse circulate the well with 129 bbl of seawater with corrosion inhibitor at 3 BPM. 16.4 Land the tubing hanger and RILDS. Lay down landing joint. Test tubing hanger packoff to 5000 psi. 16.5 Drop the ball & rod and set the packer. Increase the pressure and test the tubing to 3500 psi for 30 minutes. Bleed off the tubing to 1500 psi. Test the IA to 3000 psi for 30 minutes. Bleed off the IA pressure. Bleed off the tubing pressure. Record and notate all pressure tests on chart. 16.6 Set TWC. ND BOPE and NU adapter flange and tree. Test to 5000 psi. 16.7 Pull TWC and install BPV. 16.8 RDMO. Post -Rig Work 16.9 RU SL and open sliding sleeve. Freeze protect well. RD SL. 16.10 RU E -line and PT lubricator to 4000 psi. 16.11 Run following e -line logs: GR/CCL/PNL/CBL. 16.12 Perforate Sag River A and B formations. Depths are approximate and will be adjusted based upon Geology picks from the cased hole reference log. Please reference the 94tached we bore schematic for prognosed TVD depths.�j:ti ,ti <kjµq re e(_ car ' 16.13 RD c -line J 16.14 RU SL. Set jet pump in sliding sleeve at 6,855' MD. RD SL 16.15 Put well on production. Page 25 Version 1 March, 2016 isic„up AkAa. LII: 7.0 BOP Schematic Kill Line— ---- Milne Point Drilling & Completion Procedure 7" Casing Ow "IFImeICI :hoke Line al Gate Valve Page 26 Version 1 March, 2016 llih-orp Alaska, LIX 18.0 Wellhead Schematic CMO(� Wellhead Equipment Division - Anchorage Date. `!- L b System.• /4 � Well Num her: � C- S' --r Rig #: AI"z est 3 A FLANGE boo d !/ FLANGE FLANGE Milne Point Drilling & Completion Procedure / �4' Page 27 Version 1 March, 2016 19.0 Days vs Depth MPU C -15A Days Vs Depth 9500 r w v 9000 9500 W •:•f•IN Milne Point Drilling & Completion Procedure 0 2 4 6 9 10 12 14 16 18 20 Days Page 28 Version 1 March, 2016 0 IIihoorp Alaska, LLC 20.0 Anticipated Drilling Hazards Milne Point Drilling & Completion Procedure 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 continuously. 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 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. Reactive Shales: Stabilize shale sections (Kingak) with shale stabilizers. Barotrol plus and BDF-515 should be run at 4 ppb (2ppb each) background and raised to 8 ppb (4ppb each) while drilling through the Kingak shale. H2S: Treat every hole section as though it has the potential for H2S. No 1-12S events have been documented on drill wells on "C" pad. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Pressure in the Kuparuk is likely over the 9.7 original pressure due to heavy water injection in the area. This will attempt to be mitigated by shutting in injection in the block 1 month prior to drilling the well, and continuing to produce the producer (C-15 and C-02 Injectors were shut in 3-15-2016. C-15 was converted to producer on April 30, 2016). A SBHP survey will be conducted on C-15 prior to the well kill. The exact pressure in the Kuparuk will be known prior to killing the well in preparation of the rig MIRU. Page 29 Version 1 March, 2016 21.0 Dovon #14 Rig Lavout n V_ i W Milne Point Drilling & Completion Procedure N V Q .cansmu* Page 30 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ilil •orp %Iaska. LLA: 22.0 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. J Page 31 Version 1 March, 2016 u 118e-1, klaska. LII: 23.0 Choke Manifold Schematic Milne Point Drilling & Completion Procedure < < < 0 M > M z X z M 0 w 10 L y 3 01 3 to z I 1;0 T 1: -I RJ (D - CT -1 :7 U, CO -7 —7 rL Oj CL M a< 2 > M < 4 9:0 7r < M < z w Cj C) %0 C) O CA CA Page 32 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ililrorp UaAa.. 1.1,1: 24.0 Casing Design Information Calculation & Casing Design Factors DATE: 3-21-2016 WELL: MPU C -15A DESIGN BY:Luke Keller Design Criteria: Hole Size 6-1/8" Mud Density: 12 ppg {MAX) Hole Size Mud Density: Hole Size Mud Density: Drilling Mode MASP: 3768 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 3768 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 12 ppg external stress (0.624 psitft) and the casing evacuated for the internal stress Page 33 Version 1 March, 2016 Casing Section Calculation/Specification 1 2 3 4 Casing OD 4-112' Top (MD) 7,000 To TVD 6,692 Bottom MD 9,873 Bottom VD 9,197 Length 2,873 Wei ht 12.6 Grade L-80 13Cr Connection VAMTOP Weight w/o Bou ncy Factor Ibs 36,200 Tension at Top of Section Ibs 36,200 Min strength Tension 1000 lbs 288 Worst Case Safety Factor Tension 7.96 Collapse Pressure at bottom Psi 5,739 Collapse Resistance w/o tension (Psi) 7,500 Worst Case Safety Factor (Collapse) 1.31 MASP si 3,768 Minimum Yield (psi) 8,430 Worst case safety factor Burst 2.24 Page 33 Version 1 March, 2016 Milne Point Drilling & Completion Procedure 25.0 6-1/81' Hole Section MASP Maximum Anticipated Surface Pressure Calculation 6-1/8" Hole Section Hsi cor$ MPU C -15A Milne Point Unit MD TVD Planned Top: 7226 6904 (Upper exposed perf) Planned TD: 9873 9197 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Water PPG Grad Kuparuk 7,132 3894.072 Oil/Wet 10.5 0.546 Sag River 8,951 4561.4296 Oil 9.8 0.5096 Shublik 8,969 4570.6024 Oil 9.8 0.5096 Ivishak 9,197 4686.7912 Water 9.8 0.5096 Offset Well Mud Densities Well MW range Too (TVD1 Bottom (TVD) Date MPC -43 10-12.5 6,900 7,547 2004 MPC -42 9-12.9 6,550 7,496 2004 MPC -28A 10-10.5 6,401 7,339 2006 MPC -40 9.6-11 6,821 7,408 2001 MPC -12 10-10.5 6,450 7,578 1985 MPC -11 9.7-10.3 6,830 7,526 1985 Assumptions: 1. Field test data suggests the Fracture Gradient at the upper exposed pert will be 14 ppg EMW after a 30 day shut in period. 2. Maximum planned mud density for the 6-1/8" hole section is 12.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 7" upper pert considering a full column of gas from 6904' to surface: 6904 (ft) x 0.728(psi/ft)= 5026 psi 5026(psi) - [0.1(psi/ft)'6904(ft))= 5336 psi MASP from pore pressure (complete evacuation of wellbore to gas) From Kuparak: 7132 (ft) x 0.546(psi/ft)= 3894 psi 3894(psi) - 0.1(psi/ft)•7132(ft)= 3181 psi From Ivishak: 9197 (ft) x 0.5096(psi/ft)= 4687 psi �- 4687 (psi) - 0.1(psi/ft)'9197(ft)= 3768 psi Summary: 1. MASP while drilling 6-1/8" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 34 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ilileorp Alaska, LI.0 26.0 Spider Plot (NAD 27) (Governmental Sections) , 1`` \ \ ' 1 \ I Y \ `♦ �+� \`,yell ,-_-r. L -'.P6 ��, AD2047434 ADL047433 -- -- ---- - - - - -- -- l ` s MILNE POINT UNIT U013N010f \\ °o o - � I vk. - I: x_ I r I i------� WPC-15A-BHL j r ` ADL025516 Se6.15 \\ Sec. 14\, �\ ADLO47437 , Legend • Plan MPC -ISA -SHL \v �. c -Ma R j X Plan MPC -15A TPH \\ Plan MPC-ISA-BHL \r \ \\ . Other Surface Hulas (SHL) Other Bottom Holes (BHL) \\ - - - - Other Wall Paths \ C3Oil and Gas Unit Boundary r \ \� Milne Point Unit II o 500 1000 I...p,1..4.. r7l MPC -15A Well , Feet MaP Dsk.': 371712pi6 Page 35 Version 1 March, 2016 Milne Point Drilling & Completion Procedure Ilileorp Alaska, LLC 27.0 Surface Plat (As Built) (NAD 27) SEPAP"N LAGOON 1 � �•z h- rC.1 ' 9� G'T { �s 4, G.ta G; • C•0 i { G.12 N 94, r-�- r- a,r I■ n ,�.` `4 ,T r NOTES: 1- STATE PLANE COORDINATES ARE ZONE 4. 2. ALL 6EOOCTIC POSITIONS ARE EASED ON N A.O, 1927, 3. OFFSETS TO SECTION LINES ARE COMPUTED EASED ON PROTRACTED VALUES OF THE SECTION CORNER POSITIDfts. 4. LOCATED WITHIN SECT. 10. T 13 N. R IOE . U.V., Ail. h 2. 2, GEODETIC POSITION I -Ell. jROM S. LIN rwo- E. LINE NORTHINGS EASTIN65 LATITUDE LONGITUDE DATE CHECIIEO S\ ■ C -O 1068' 2203' T7 29 TT is y E !. 050 � li T7 BJ,83 y° 22-85 G•12 494' 2047" A f2 IV 1-4 fS 10 32 S) Y,]4 J.IE 22-95 C • 13 954' 2169' 6 .029 , 237.99 9 :o 70029' 23.768" IL 149°31'24,464 "I■ rr J. A S, 22-W IF 839' 4 A 4,02912294 f. 35/132908 I_e_T ""-"�"-" •' _II • t • 60 r r w..�'•�. C -t5 [ -14 SCALE Rr MILES 6 ,029 007 S8 6., OY B. 8 44 CONOCO 70 2T' 23..302`14. e4$ 3a • 22. 374 W —70° 29'22_!9T'N 149° 31'21.337'' M. IIILNE POINT UNIT 2YT " 2419, • Icy 165.94 558 244.2 EMI STI NG DEVC-L 14C NT L.O. NOTES: 1- STATE PLANE COORDINATES ARE ZONE 4. 2. ALL 6EOOCTIC POSITIONS ARE EASED ON N A.O, 1927, 3. OFFSETS TO SECTION LINES ARE COMPUTED EASED ON PROTRACTED VALUES OF THE SECTION CORNER POSITIDfts. 4. LOCATED WITHIN SECT. 10. T 13 N. R IOE . U.V., Ail. - r liy1 I CERTIFICATE DP 01- lit"' 9r I SURVEYOR C PAD ^� AS -GUILT WELL LOCATION I hE RE BV CERfIrY 1N41 1 AN PROVE RLY J✓L� ' R"�:". ;.� AGr '�. `�,T �� C6 AND LICENSED 70 PA sC SICE SrIV i,*'•f iia: LAND SUR VE TIN W 114 E IV •r•`- b.r..AAA}• 3�JNMN.• s... r *'P G E SEAT Or ALASKA C•+•++�/ T'+ h L EY C 0 AND THAI TH.S PLAT ■'CPNf.E NISe••�AAAA4A..A.."•".e.Ae�.r}I I . LOCATION .VovET MADE bV e,( ON UNDER 6)�; • B4r"rd 1:+nUlafh-+r>j '�Ls SO GI 111 SUPLNVISIOr/, A:� INAt ALL UINIENSIO•IS 4r LP 'a LS.r37985 �g'��� Ej17IJ SCALE � sNEEr eq,AND Or,.tN OLTAII: ANC CONNECT. 4V4 +p.`'•FSS•..... iPY 1 "I ,18 Enr.INECNS I' . �QV L P .. �j, ?.. C6TArn►rsloPl CoR1.[NTS= 'Icc N-, • rr.w: Page 36 Version 1 March, 2016 LOCATION IN SECTION STATE PLANE COVADS. GEODETIC POSITION I -Ell. jROM S. LIN rwo- E. LINE NORTHINGS EASTIN65 LATITUDE LONGITUDE DATE CHECIIEO FlELO 8001 C -O 1068' 2203' 8,029.331.58 558,255.76 7TP 29'26.894"N. 14091'23_343`w- BJ,83 J_b.S. 22-85 G•12 494' 2047" 6 028.290.21 55 111 438.90 70°29'21.260"N 149031'20,260"W 11-I-85 J.IE 22-95 C • 13 954' 2169' 6 .029 , 237.99 S58, 292.56 70029' 23.768" IL 149°31'24,464 "I■ b. f , 4! J. A S, 22-W -C•14 839' 2134' 2094 2043' 4,02912294 f. 35/132908 7G°Y9'24.639"N, 14831'23.438"V6' ""-"�"-" •' _II • t • 60 1 w..�'•�. C -t5 [ -14 • _ L 6 ,029 007 S8 6., OY B. 8 44 558,36614 99 402.27 70 2T' 23..302`14. e4$ 3a • 22. 374 W —70° 29'22_!9T'N 149° 31'21.337'' M. C•IT C•i8- _12874. 437: 2YT " 2419, b 029 569. 51020, 719 Icy 165.94 558 244.2 0 .044 U • t' 70029'20.860" 1490 31'25. 9"91l. II -9-85 L.O. 44'86 Oh I 1468' 2389' 6,029.749.80 556, US. 0/ 70• 29'30.821' 4 1490 31'29.200' 1 11 -?0-85 L. 5 _ - r liy1 I CERTIFICATE DP 01- lit"' 9r I SURVEYOR C PAD ^� AS -GUILT WELL LOCATION I hE RE BV CERfIrY 1N41 1 AN PROVE RLY J✓L� ' R"�:". ;.� AGr '�. `�,T �� C6 AND LICENSED 70 PA sC SICE SrIV i,*'•f iia: LAND SUR VE TIN W 114 E IV •r•`- b.r..AAA}• 3�JNMN.• s... r *'P G E SEAT Or ALASKA C•+•++�/ T'+ h L EY C 0 AND THAI TH.S PLAT ■'CPNf.E NISe••�AAAA4A..A.."•".e.Ae�.r}I I . LOCATION .VovET MADE bV e,( ON UNDER 6)�; • B4r"rd 1:+nUlafh-+r>j '�Ls SO GI 111 SUPLNVISIOr/, A:� INAt ALL UINIENSIO•IS 4r LP 'a LS.r37985 �g'��� Ej17IJ SCALE � sNEEr eq,AND Or,.tN OLTAII: ANC CONNECT. 4V4 +p.`'•FSS•..... iPY 1 "I ,18 Enr.INECNS I' . �QV L P .. �j, ?.. C6TArn►rsloPl CoR1.[NTS= 'Icc N-, • rr.w: Page 36 Version 1 March, 2016 Lii 28.0 Drill Pipe Specifications Milne Point Drilling & Completion Procedure 400204138036211 rrA, Weatherford 4" 14.00 lb/ft Internal Coating S-135 w/ HT 38 4-718" OD x 2-9116" ID w/ X 7000 Hard Banding Tool Joint DRfLL PIPE SPECIFICATIONS Grade iS-135 Connection HT 38 Interchangeable With 2-7/16" Upset Type I IU Internal Coatin TK 34 XT Nominal Weight er Foot ; 14.00 lbs Adjusted Weight With Tool Joint per Foot 15.65 lbs i TOOL JOINT DATAS Outside Diameter 4-7i8" — Inside Diameter _ 2-9/16" --- API Drift 2-7/16" Rabbit OD, Suggested 2-318" (' Hard Band X 7000 Minimum Make-up Torque Maximum Recommend Make-up To ue 12.200 ft -lbs 17,700 ft -lbs Torsional Yield Strength 29.500 ft -lbs L Tensile Strength 649,200 lbs TUBE DATA Page 37 Version 1 March, 2016 New I Premium Outside Diameter 4.000" 3.868" Inside Diameter 3:340" 3.340- .340Wall WallThickness 0.330" 0.264" Cross Sectional Area 3.805 sq in 2.989 sq in Maximum Hook LoadlTensile Strength 513,600 lbs 403,500 lbs Slip Crushing (SDXL) 431,900 lbs 341,300 lbs Burst Pressure 19,500 psi 18,400 psi Collapse Pressure 20,100 psi 13,800 psi Torslonal Yield Strength _ 41 900 ft -lbs 32 800 ft -lbs Capacity W/ Tool Joint 0.442 US galfft 0.442 US_gaUft Displacement W/ Tool Joint 0.240 US gal/ft 0.223 US galtft Excessive heat or pulling when tube Is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford In no way assumes responsibility or liability for any loss, damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responslbillty. Page 37 Version 1 March, 2016 Hilcorp Energy Company Milne Point M Pt C Pad MPC -15 Plan MPC -15A Plan: MPC -15A wp04a Standard Proposal Report 14 March, 2016 HALLIBURTON Sperry Drilling Services Project: Milne Point REFERENCE INFORMATION WELL DETAIIS: MPC -15 NAD1927(NADCONCONUS) Alaska .04 NALLlBURTON Site: M Pt C Pad a,Mlmt. (NIE) Referent.: Well MP615, True N.dh Dowd Level: 16.70 Sperry Ori111ng Well: MPC -15 Wdka1(1VD) Re f.re— MP 15A@46.70w d W ffi +-S +E/ -W N.,g Ewting Latiltude Longitude Slot Wellbore: Plan MPC -15A Mea.ur.d Depth Raf.=: MPO15A allyl.tl.e M. nm: Mlnlm @ 4817 ft vn cy .eu. 0.00 0.00 6029007.58 558366.14 70° 29' 23.502 N149° 31' 22.374 W Plan: MPC -15A wp04a 1 0 CASING DETAILS i.7"TVD TVDSS MD Size Name 9064.68 9017.98 9711.00 4-1/2 4 1/2" 7666 - - - - Start DLS 5.00 TFC, 105.00 7400 -125- 7600— -250— MPC -15 8000- 0007800 7800— -375 Vr)0° Start DLS 5.00 TFO 105.00 Start 1495.58 hold at 8376.59 MD 8000 -500 175° 8200 a S25 8000 w � C o o 0 v 8400 + -750 CI 8250 0 � D 9000 o v 8600 -875 C y 8500 8800 -1000 179° 1- 9000 -1125 8750 4 1/2" 9200 - TD at 9873.17 -1250- 9��9 4 1/2", X9000 MPC -15A wp04a T 9400 1375 MAzimuthe to True North Magnetic North: 18.79' 9198 Magnetic Field Strength: 57504.5snT MPC -15A wp04a Dip Angle: 81.09° 6600 1600 Date: 11712016 Model: BGGM2015 9800 1250 1375 1500 1625 1750 1875 2000 2125 2250 2375 -600 -400 -200 0 200 400 600 800 1000 West( -)/East(+) (250 usft/in) Vertical Section at 200.00° (400 usft/in) HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Milne Point Site: M Pt C Pad Well: MPC -15 Wellbore: Plan MPC -15A Design: MPC-15Awp04a Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well MPC -15 / MPC -15A @ 46.70usft MPC -15A @ 46.70usft True Minimum Curvature 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 FS11e M Pt C Pad, TR -13-10 sition: 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 ° Well MPC -15, MPC -15 Well Position +N/ -S 0.00 usft Northing: 6,029,007.58 usft Latitude: 70° 29'23.502 N +E/ -W 0.00 usft Easting: 558,366.14 usft Longitude: 149° 31'22.374 W Position Uncertainty - 0.00 usft Wellhead Elevation:- usft Ground Level: 16.70usft Wellbore Plan MPC -15A Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGGM2015 1/7/2016 18.79 81.09 57,504 -Des - Design - MPC-15Awp04a - Audit Notes: Version: Phase: PLAN Tie On Depth: 7,660.70 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) 30.00 0.00 0.00 200.00 Plan Sections i Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +Nl-S +E/ -W Rate Rate Rate Tool Face (usft) (1 (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 7,660.70 17.47 98.70 7,315.47 7.26877 -334.70 1,625.09 0.00 0.00 0.00 0.00 8,376.59 35.00 178.75 7,971.59 7.924.89 -563.72 1,739.54 5.00 2.45 11.18 105.00 9,872.17 35.00 178.75 9,196.70 9,150.00 -1,421.34 1,758.25 0.00 0.00 0.00 0.00 j 9,873.17 35.00 178.75 9,197.52 9,150.82 -1,421.92 1,758.26 0.00 0.00 0.00 0.00 J 3/14/2016 2:23:33PM Page 2 COMPASS 5000.1 Build 73 Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Milne Point Site: M Pt C Pad Well: MPC -15 Wellbore: Plan MPC -15A Design: MPC-15Awp04a Planned Survey Measured Depth (usft) 100.00 109.70 13 3/8" 200.00 300.00 400.00 500.00 600.00 700.00 800.00 900.00 1,000.00 1,100.00 1,200.00 1,300.00 1,400.00 1,500.00 1,600.00 1,700.00 1,800.00 1,900.00 2,000.00 2,100.00 2,200.00 2,300.00 2,400.00 2,500.00 2,600.00 2,700.00 2,800.00 2,900.00 3,000.00 3,100.00 3,200.00 3,300.00 3,400.00 3,500.00 3,600.00 3,700.00 3,800.00 3,900.00 4,000.00 4,100.00 4,200.00 4,300.00 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well MPC -15 TVD Reference: MPC -15A @ 46.70usft MD Reference: MPC -15A @ 46.70usft North Reference: True Survey Calculation Method: Minimum Curvature Vertical 223.09 200.00 153.30 Map Map 6,029,006.68 Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS (°) (°) (usft) usft (usft) (usft) (usft) (usft) 53.30 0.42 199.27 100.00 53.30 -0.26 -0.08 6,029,007.32 558,366.06 0.00 0.42 202.14 109.70 63.00 -0.33 -0.11 6,029,007.25 558,366.03 0.22 311412016 2:23:33PM Vert Section 0.28 0.35 0.47 223.09 200.00 153.30 -0.89 -0.51 6,029,006.68 558,365.64 0.19 1.01 0.53 189.88 299.99 253.29 -1.68 -0.83 6,029,005.90 558,365.32 0.29 1.86 0.54 250.04 399.99 353.29 -2.29 -1.38 6,029,005.28 558,364.78 0.54 2.62 0.41 256.05 499.99 453.29 -2.54 -2.18 6,029,005.03 558,363.98 0.14 3.13 0.29 268.91 599.98 553.28 -2.63 -2.79 6,029,004.93 558,363.38 0.14 3.43 0.23 302.08 699.98 653.28 -2.51 -3.22 6,029,005.05 558,362.94 0.16 3.46 0.21 156.28 799.98 753.28 -2.60 -3.30 6,029,004.96 558,362.86 0.42 3.57 0.05 51.87 899.98 853.28 -2.74 -3.19 6,029,004.81 558,362.98 0.23 3.66 0.36 336.89 999.98 953.28 -2.40 -3.28 6,029,005.15 558,362.87 0.35 3.38 0.18 314.57 1,099.98 1,053.28 -2.01 -3.51 6,029,005.55 558,362.64 0.21 3.09 0.23 264.89 1,199.98 1,153.28 -1.92 -3.83 6,029,005.63 558,362.33 0.18 3.12 0.21 264.54 1,299.98 1,253.28 -1.96 -4.22 6,029,005.59 558,361.94 0.02 3.28 0.05 212.26 1,399.98 1,353.28 -2.02 -4.41 6,029,005.53 558,361.75 0.18 3.40 0.18 292.03 1,499.98 1,453.28 -1.99 -4.58 6,029,005.56 558,361.58 0.18 3.43 0.22 282.79 1,599.98 1,553.28 -1.89 -4.92 6,029,005.65 558,361.24 0.05 3.45 0.13 301.57 1,699.98 1,653.28 -1.78 -5.21 6,029,005.76 558,360.95 0.10 3.45 0.16 111.82 1,799.98 1,753.28 -1.78 -5.16 6,029,005.76 558,361.00 0.29 3.44 0.06 321.51 1,899.98 1,853.28 -1.77 -5.07 6,029,005.77 558,361.08 0.21 3.40 0.18 198.99 1,999.98 1,953.28 -1.89 -5.16 6,029,005.65 558,361.00 0.22 3.54 0.22 194.39 2,099.98 2,053.28 -2.23 -5.26 6,029,005.31 558,360.90 0.04 3.89 0.23 164.63 2,199.98 2,153.28 -2.63 -5.25 6,029,004.91 558,360.91 0.12 4.26 0.16 61.76 2,299.97 2,253.27 -2.75 -5.08 6,029,004.79 558,361.08 0.31 4.32 0.26 66.30 2,399.97 2,353.27 -2.59 -4.74 6,029,004.96 558,361.42 0.10 4.05 0.01 169.11 2,499.97 2,453.27 -2.50 -4.55 6,029,005.04 558,361.61 0.26 3.91 0.12 165.40 2,599.97 2,553.27 -2.61 -4.52 6,029,004.93 558,361.64 0.11 4.00 0.18 107.56 2,699.97 2,653.27 -2.76 -4.35 6,029,004.78 558,361.81 0.15 4.09 0.28 82.77 2,799.97 2,753.27 -2.74 -3.93 6,029,004.81 558,362.23 0.14 3.92 0.73 205.61 2,899.97 2,853.27 -3.35 -4.00 6,029,004.20 558,362.17 0.92 4.52 0.24 273.98 2,999.97 2,953.27 -3.87 -4.51 6,029,003.68 558,361.66 0.68 5.18 0.68 121.04 3,099.96 3,053.26 -4.14 -4.26 6,029,003.41 558,361.91 0.90 5.35 2.79 114.25 3,199.91 3,153.21 -5.46 -1.57 6,029,002.11 558,364.62 2.12 5.67 5.42 106.43 3,299.65 3,252.95 -7.86 5.18 6,028,999.76 558,371.38 2.68 5.62 7.90 93.06 3,398.97 3,352.27 -9.53 16.58 6,028,998.19 558,382.80 2.91 3.28 10.37 91.63 3,497.69 3,450.99 -10.06 32.46 6,028,997.78 558,398.67 2.48 -1.65 12.84 99.37 3,595.65 3,548.95 -12.15 52.40 6,028,995.84 558,418.63 2.91 -6.50 15.82 102.15 3,692.53 3,645.83 -16.78 76.72 6,028,991.40 558,442.98 3.06 -10.47 18.58 107.35 3,788.05 3,741.35 -24.48 105.23 6,028,983.93 558,471.55 3.15 -12.99 21.31 106.22 3,882.03 3,835.33 -34.43 137.90 6,028,974.24 558,504.30 2.76 -14.82 23.27 99.72 3,974.58 3,927.88 132.76 174.82 6,028,966.20 558,541.27 3.15 -19.61 26.10 98.40 4,065.42 4,018.72 139.25 216.08 6,028,960.03 558,582.58 2.88 -27.62 28.41 99.86 4,154.28 4,107.58 -56.56 261.35 6,028,953.08 558,627.90 2.41 -36.24 28.98 100.73 4,241.99 4,195.29 -65.15 308.61 6,028,944.86 558,675.22 0.71 -44.33 Page 3 COMPASS 5000.1 Build 73 Halliburton HALL1BURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well MPC -15 Company: Hilcorp Energy Company ND Reference: MPC -15A @ 46.70usft Project: Milne Point MD Reference: MPC -15A @ 46.70usft Site: M Pt C Pad North Reference: True Well: MPC -15 Survey Calculation Method: Minimum Curvature Wellbore: Plan MPC -15A (usft) 1°) Design: MPC-15Awp04a usft (usft) j Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +El -W Northing Easting DLS Vert Section (usft) 1°) (^) (usft) usft (usft) (usft) (usft) (usft) 4,282.71 4,400.00 29.12 101.35 4,329.41 4,282.71 -74.45 356.27 6,028,935.94 558,722.95 0.33 -51.89 4,500.00 29.13 102.14 4,416.77 4,370.07 -84.36 403.91 6,028,926.40 558,770.66 0.38 -58.87 4,600.00 29.38 102.59 4,504.01 4,457.31 -94.84 451.65 6,028,916.29 558,818.48 0.33 -65.35 4,686.70 29.46 102.23 4,579.53 4,532.83 -104.00 493.24 6,028,907.47 558,860.13 0.22 -70.97 95181, 4,700.00 29.50 10224 4,591.11 4,544.41 -105.38 499.64 6,028,906.13 558,866.54 0.32 -71.86 4,800.00 30.04 102.91 4,677.86 4,631.16 -116.27 548.17 6,028,895.63 558,915.15 0.63 -78.23 4,900.00 28.53 101.28 4,765.10 4,718.40 -126.50 595.96 6,028,885.77 558,963.02 1.71 -84.96 5,000.00 27.68 100.91 4,853.31 4,806.61 -135.48 642.21 6,028,877.16 559,009.33 0.87 -92.34 5,100.00 26.74 104.71 4,942.24 4,895.54 -145.66 686.77 6,028,867.33 559,053.96 1.98 -98.01 5,200.00 25.57 105.01 5,032.00 4,985.30 -156.93 729.38 6,028,856.39 559,096.66 1.18 -102.00 5,300.00 24.45 106.93 5,122.64 5,075.94 -168.64 769.97 6,028,845.01 559,137.33 1.38 -104.88 5,400.00 23.99 103.52 5,213.86 5,167.16 -179.38 809.51 6,028,834.58 559,176.95 1.47 -108.31 5,500.00 24.20 101.92 5,305.11 5,258.41 -188.38 849.41 6,028,825.89 559,216.92 0.69 -113.50 5,600.00 22.31 100.44 5,397.01 5,350.31 -196.00 888.08 6,028,818.57 559,255.65 1.97 -119.56 5,700.00 22.00 101.11 5,489.64 5,442.94 -203.06 925.10 6,028,811.81 559,292.71 0.41 -125.59 5,800.00 22.32 101.20 5,582.25 5,535.55 -210.36 962.10 6,028,804.80 559,329.77 0.33 -131.39 5,900.00 22.73 101.13 5,674.62 5,627.92 -217.77 999.69 6,028,797.69 559,367.42 0.41 -137.28 6,000.00 22.88 101.41 5,766.80 5,720.10 -225.34 1,037.71 6,028,790.41 559,405.49 0.19 -143.16 6,100.00 22.84 101.51 5,858.95 5,812.25 -233.09 1,075.76 6,028,782.96 559,443.59 0.06 -148.90 6,200.00 23.13 99.86 5,951.01 5,904.31 -240.29 1,114.14 6,028,776.07 559,482.03 0.71 -155.27 6,300.00 23.10 100.86 6,042.98 5,996.28 -247.35 1,152.77 6,028,769.31 559,520.71 0.39 -161.84 6,400.00 22.66 101.68 6,135.11 6,088.41 -254.96 1,190.89 6,028,761.99 559,558.88 0.54 -167.72 6,500.00 22.31 101.30 6,227.51 6,180.81 -262.58 1,228.37 6,028,754.68 559,596.41 0.38 -173.38 6,600.00 22.12 101.11 6,320.08 6,273.38 -269.93 1,265.47 6,028,747.62 559,633.57 0.20 -179.17 6,700.00 21.64 101.15 6,412.88 6,366.18 -277.14 1,302.02 6,028,740.70 559,670.17 0.48 -184.90 6,800.00 21.48 100.33 6,505.88 6,459.18 -283.97 1,338.14 6,028,734.15 559,706.34 0.34 -190.83 6,900.00 21.08 100.70 6,599.06 6,552.36 -290.59 1,373.82 6,028,727.80 559,742.07 0.42 -196.80 7,000.00 20.77 100.70 6,692.47 6,645.77 -297.22 1,408.90 6,028,721.45 559,777.20 0.31 -202.57 7,100.00 20.80 100.70 6,785.96 6,739.26 -303.81 1,443.77 6,028,715.14 559,812.12 0.03 -208.31 7,200.00 20.84 100.59 6,879.42 6,832.72 -310.39 1,478.73 6,028,708.84 559,847.12 0.05 -214.09 7,300.00 20.21 100.14 6,973.06 6,926.36 -316.71 1,513.25 6,028,702.78 559,881.68 0.65 -219.95 7,400.00 18.89 98.94 7,067.30 7,020.60 -322.24 1,546.24 6,028,697.52 559,914.72 1.37 -226.04 7,500.00 17.82 99.53 7,162.20 7,115.50 -327.34 1,577.34 6,028,692.66 559,945.85 1.09 -231.88 7,600.00 17.47 98.70 7,257.57 7,210.87 -331.95 1,607.08 6,028,688.29 559,975.62 0.43 -237.72 7,646.70 17.47 98.70 7,302.11 7,255.41 -334.07 1,620.93 6,028,686.28 559,989.49 0.00 -240.47 7" 7,660.70 17.47 98.70 7,315.47 7,268.77 -334.70 1,625.09 6,028,685.67 559,993.65 0.00 -241.29 7,700.00 17.06 105.18 7,353.00 7,306.30 -337.11 1,636.49 6,028,683.36 560,005.06 5.00 -242.93 7,800.00 17.01 122.30 7,448.67 7,401.97 -348.77 1,663.03 6,028,671.90 560,031.69 5.00 -241.05 7,900.00 18.33 138.25 7,544.01 7,497.31 -368.33 1,685.87 6,028,652.52 560,054.69 5.00 -230.48 8,000.00 20.77 151.35 7,638.28 7,591.58 -395.64 1,704.86 6,028,625.37 560,073.89 5.00 -211.32 8,100.00 23.98 161.45 7,730.78 7,684.08 -430.48 1,719.83 6,028,590.65 560,089.13 5.00 -183.70 8,200.00 27.70 169.14 7,820.79 7,774.09 -472.60 1,730.68 6,028,548.63 560,100.31 5.00 -147.83 8,300.00 31.75 175.07 7,907.63 7,860.93 -521.67 1,737.32 6,028,499.62 560,107.34 5.00 -103.99 3/14/2016 2:23.33PM Page 4 COMPASS 5000.1 Build 73 HALLIBURTON Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well MPC -15 Company: Hilcorp Energy Company TVD Reference: MPC -15A @ 46.70usft Project: Milne Point MD Reference: MPC -15A @ 46.70usft Site: M Pt C Pad North Reference: True Well: MPC -15 Survey Calculation Method: Minimum Curvature Wellbore: Plan MPC -15A (usft) (usft) Design: MPC-15Awp04a 178.75 7,971.59 Planned Survey Measured 0.00 695.69 Vertical 0.00 734.27 560,135.34 Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing (usft) (°) (°) (usft) usft (usft) (usft) (usft) 8,376.59 35.00 178.75 7,971.59 7,924.89 -563.72 1,739.54 6,028,457.59 8,400.00 35.00 178.75 7,990.77 7,944.07 -577.14 1,739.83 6,028,444.17 8,500.00 35.00 178.75 8,072.68 8,025.98 -634.48 1,741.08 6,028,386.84 8,600.00 35.00 178.75 8,154.60 8,107.90 -691.83 1,742.33 6,028,329.51 8,700.00 35.00 178.75 8,236.51 8,189.81 -749.17 1,743.58 6,028,272.19 8,800.00 35.00 178.75 8,318.43 8,271.73 -806.52 1,744.83 6,028,214.86 8,900.00 35.00 178.75 8,400.34 8,353.64 -863.86 1,746.09 6,028,157.53 9,000.00 35.00 178.75 8,482.26 8,435.56 -921.20 1,747.34 6,028,100.21 9,100.00 35.00 178.75 8,564.18 8,517.48 -978.55 1,748.59 6,028,042.88 9,200.00 35.00 178.75 8,646.09 8,599.39 -1,035.89 1,749.84 6,027,985.55 9,300.00 35.00 178.75 8,728.01 8,681.31 -1,093.24 1,751.09 6,027,928.23 9,400.00 35.00 178.75 8,809.92 8,763.22 -1,150.58 1,752.34 6,027,870.90 9,500.00 35.00 178.75 8,891.84 8,845.14 -1,207.92 1,753.59 6,027,813.57 9,600.00 35.00 178.75 8,973.75 8,927.05 -1,265.27 1,754.84 6,027,756.24 9,700.00 35.00 178.75 9,055.67 9,008.97 -1,322.61 1,756.10 6,027,698.92 9,711.00 35.00 178.75 9,064.68 9,017.98 -1,328.92 1,756.23 6,027,692.61 4 112' 9,800.00 35.00 178.75 9,137.58 9,090.88 -1,379.96 1,757.35 6,027,641.59 9,872.17 35.00 178.75 9,196.70 9,150.00 -1,421.34 1,758.25 6,027,600.22 9,873.17 35.00 178.75 9,197.52 9,150.82 -1,421.92 1,758.26 6,027,599.64 Targets Target Name - hittmiss target Dip Angle Dip Dir. TVD +N/ -S Shape (°) (°) (usft) (usft) MPC-15Awp4TSGRB 0.00 0.00 8,896.70 -1,556.48 - plan misses target center by 282.94usft at 9703.76usft MD (9058.75 TVD, -1324.77 N, 1756.14 E) -Circle (radius 100.00) MPC-15Awp1 TSGRB 0.00 0.00 8,917.70 -958.63 plan misses target center by 319.46usft at 9375.30usft MD (8789.69 TVD, -1136.42 N, 1752.03 E) Point MPC-15Awp2 TSGRD 0.00 0.00 8,811.00 -909.52 - plan misses target center by 1152.88usft at 9248.42usft MD (8685.75 TVD, -1063.66 N, 1750.45 E) - Point Casing Points Map Easting (usft) 560,109.88 560,110.28 560,111.98 560,113.68 560,115.38 560,117.08 560,118.78 560,120.48 560,122.19 560,123.89 560,125.59 560,127.29 560,128.99 560,130.69 560,132.39 560,132.58 DLS 7,924.89 5.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Vert Section -65.24 -52.72 0.74 54.19 107.65 161.11 214.57 268.02 321.48 374.94 428.40 481.86 535.31 588.77 642.23 648.11 560,134.09 0.00 695.69 560,135.32 0.00 734.27 560,135.34 0.00 734.80 +E/ -W Northing Easting (usft) (usft) (usft) 1,745.87 6,027,465.00 560,124.00 1,519.53 6,028,061.00 559,893.00 614.80 6,028,103.00 558,988.00 Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 9,711.00 9,064.68 41/2" 4-1/2 6-1/8 3/14/2016 2:23:33PM Page 5 COMPASS 5000.1 Build 73 Hilcorp Energy Company Milne Point M Pt C Pad MPC -15 Plan MPC -15A 5002921358 MPC -15A wp04a Sperry Drilling Services Clearance Summary Anticollision Report 09 March, 2016 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt C Pad -MPC-15- Plan MPC -15A- MPC -15A wp04a Well Coordinates: 6,029,007.56 N, 558,366.14E (70° 29' 23.50" N, 149° 31' 22.37" W) Datum Height:MPC-15A @ 46.70usft Scan Range: 7,660.70 to 9,673.17 usft. Measured Depth. Scan Radius is 1,184.32 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 73 Scan Type: GLOBAL FILTERAPPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTOI Sperry Orilling Services Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for MPC -15 - MPC -15A wp04a Closest Approach 30 Proximity Scan on Current Survey Data (North Reference) Reference Design: MPte Pad -MPC -15 -Plan MPC-LSA-MPC-1SAwp04a Scan Range: 7,660.70 to 9,873.17 usft. Measured Depth. Scan Radius is 1,184.32 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 -15 - MPC -15 - MPC -15 - Survey too/ program From To Survey/Plan (usft) (usft) 94.70 7,660.70 7,660.70 9,873.17 MPC-15Awp04a 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. Survey Tool SRG-MS MWD+IFR2+MS+sag 09 March, 2016 - 12:20 Page 2 oro COMPASS HALLIBURTON Anticollision Report for MPC -15 - MPC -15A wp04a Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to MPC -15A @ 46.70usft. Northing and Easting are relative to MPC -15. Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04. Central Meridian is -150.00°, Grid Convergence at Surface is: 0.45 ". C N 1050- C:) tf ) Cl) C O 700- 0- (D U) N C U 350- 0 0 0 Ladder Plot -- -.._------ I i i i i I I I ------------------------- I I I I I I I --------- I I I - I I I I I I I I I I I I I I I I I I I I I I I I I _I- - - _ _ i I I I I _ _ - _ _I--------- I I I I I J _ _ _ _ _ I I I I I _ _ _ _ _I__1_ I I I I I _ _ _ _ I I i i _ _ _ _ _I_ I i I I I --------- I I I I I i -- - - -'--- - - I I I i I I I I - -- ----------- i I I i I I I J--- - I I I I I i I I --'--- -- I I I I -----'-- " I I I I F 1 1 2000 4000 6000 8000 10000 Measured Depth (2000 usftrin) Hilcorp Energy Company Milne Point $ MPC05,MPC-05,MPG05V1 $ MPG05,MPG05A,MPC-05AVI $ WC -06, MPG06, MPC -06 V1 $ MPC08,MP408,MPC-08V1 $ MPC-10,MPG10,MPG10V1 $ MPC-11'MPC-11,MPG11 V1 -} MPGI2,MPG12,MPG12V9 -+- MPG12,MPG12A,MPG12AV3 $ MPG12,MPG12APB1,MPG12APB1V6 $ MPGI3,MPG13,MPG13V4 $ WC -14, MPG14, MPC -14 V1 -� MPG15,MPG15,MPG15V1 �- MPGI6,MPG16,MPG16V1 $ MPG18,MPG18,MPG18V1 $ MPC20,WC-20,MPC-20V1 $ MPC -22, MPC -22, MPC -22 V1 $ MPC22,MPG22A,MPC-22AV1 $ MPC24,MPG24,MPC-24V13 -� MPC24,MPG24A,MPC-24AV0 $ WC24,MPC-24APBI,MPG24APB1V0 $ MPC -28, MPC -28, MPC -28 V1 $ MPC -28, MPC -28A, MPG28AV6 $ MPG39,MPG39,MPG39V3 — — MPG40, MPG40, MPG40 V19 $ MPG4I,MPG4I,MPG41V0 $ MPG4I,MPG41L1,MPC-4111 VO 09 March, 2016 - 12:20 Page 3 of 4 COMPASS HALLIBURTON Anticollision Report for MPC -15 - MPC -15A wp04a Clearance Factor Plot: Measured Depth versus Separation(Clearance) Factor 10.00 I 8.75 7.50-- ,50 6.25 6.25- o � I I LL GO 5.00 N mp UD 3.75 i 2.50 -- - --- Collision Avoidance Req No -Go Zona - Stop Win 1.25- ,25 000 000 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 Measured Depth (1500 LdVn) Hilcorp Energy Company Milne Point Jt MVLrul, MNC:ui, MI'(rul VI ♦- MPG -05, MPC -05, MPC -05V1 $ MPG05,MPC-05A,MPC-05AV1 $ MPC-06,MPC-06,MPC-06V1 -X- MPC-08,MPC-08,MPC-08V1 -e-MPC-1 0, MPC -1 0, MPG -1 0 V1 $ MPC-11,MPC-11,MPC-11V1 $ MPC -1 2, MPC -1 2, MPC -1 2 V9 $ MPC -1 2, MPC -1 2A, MPC-12AV3 $ MPC -1 2, MPC -1 2APB1, MPG-MPB1 V6 $ MPC -1 3, MPC -1 3, MPC -1 3 V4 $ MPC-14,MPC-14,MPC-14V1 -� MPCI5,MPC-15,MPC-15 V1 -� MPC-I6,MPC-16,MPC-16V1 $ MPC -1 8, MPC -1 8, MPC -1 8 V1 $ MPG-20,MPG20,MPG-20V1 $ MPC-22,MPC-22,MPC-22V1 $ MPC -22, MPC -22A, MPC -22A V1 $ MPC -24, MPC -24, MPC -24 V 13 -�- MPC -24, MPC -24A, MPC -24A VO $ MPC -24, MPC-24APB 1, MPC-24APB1 VO $ M PC -28, MPC -28, MPC -28 V1 $ MPC-28,MPC-28A,MPC-28AV6 $ MPC -39, MPC -39, MPC -39 V3 3- MPC40,MPC40,MPG40V19 $ MPC41,MPC41,MPC41VO $ MPC41,MPC41LI, MPC41L1VO -&- MPC -41, MPC41 L2, MPG -41 L2 VO 09 March, 2016 - 12:20 Page 4 o/ 4 COMPASS TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: 1. ( — O R O ZDevelopment _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: M'I t1L Ajv� POOL: &JAL ?��� aj 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 onpermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Compare Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SAG RIVER OIL - 525150 Well Name: MILNE PT UNIT KR C -15A Program DEV_ Well bore seg ❑ PTD#: 2160700 Company HILCORP ALASKA LLC _ - — _ Initial Class/Type DEV/PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached_ _ _ _ - - - _ _ N -A - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - 2 Lease number appropriate_ - - - - - - - - Yes - - _ ADL0047434, Surf Loc; ADL002551(3,Top Prod_Intenr A- TD-. 3 Unique well name and number - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ - - - - _ MPU C -15A------------------ - - - - - - - - - - 4 Well -located in_a_defined -pool - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - MILNE POINT, SAG RIVER OIL - 525150,_govetmed by Conservation Order No._ 423. 5 Well -located proper distance from drilling unit_boundary_ Yes -- - - - _ Conforms to -CO 423, Rule 3, -which specifies 40 -acre spacing. - - _ - 6 Well -located proper distance from other wells_ - - - - - - - - - - - - - - - - - - - Yes _ _ - - - - - - - - - - - - - - - - - _ - - - - _ _ _ _ _ ---------------------------------------------- 7 Sufficient acreage- avail_able in_drilling unit_ - - - - Yes 8 If_ deviated, is_we_Ilboreplatinclu_ded - - - - - - - - - - - - - - - - - - - - - - Yes - - - - _ - _ _ _ _ _ _ _ _ _ _ - - _ - _ - - - - - - - - - - - _ _ - _ 9 Operator only affected party- - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - Yes - - _ - _ _ _ The_pool shall -not be opened -in, any well closer than 500 -feet to an -external boundary-whereownership changes. 10 Operator has_appropriat-bo nd in force - - - - - - - - - - - - - - - - - - - _ _ Yes - 11 Permit can be issued without conservation order_ - _ _ _ _ Yes _ _ _ _ _ _ _ Appr Date 12 Permit_can be issued without administrative_approval _ _ _ _ _ - _ - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - 13 Can permit be approved before 15 -day wait_ _ _ _ _ _ _ _ _ _ _ _ Yes - PKB 5/11!2016 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ - - - - _ - - - - _ _ - _ _ _ _ _ - - _ _ - - 14 Well located within area and -strata authorized by Injection Order # (put IO# in -comments)_ (For_ NA_ _ - - - - - - 15 All wells_within_1/4_mile area -of review identified (For service well only)- - - - - - - - - - - - - - NA- - - - - - - - - - - - - - _ - - - - - - - - - - - - - _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - _ _ _ - - 16 Pre -produced injector. duration -of pre -production less than 3 months_ (For service well only) - _ NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 17 Nonconven. gas conforms to AS31,05.030(i.1_.A),Q.2.A-D) - - -- - - - - _ - ----- -- - --- NA- - ------------------------------------------------ - - - - - - - - - - - - - - --- 18 Conductor string -provided - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ _ _ _ N_A_ - - - _ _ _ _ Conductor set-in C-15 _ _ _ _ - - _ - - - - - - - - - - - Engineering 19 Surface casing_ protects all -known USDWs - - - - - - - NA- _ _ _ _ _ _ _ Surface casing set in C-15 and -fully cemented. 20 CMT_v_ol adequate to circulate -on conductor & surf_csg - - - - - - - - - - - - - - - - - - - - - - - NA_ _ _ _ _ - _ - _ - - - - - - - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - - - - - - - - _ - - - - - - - - - _ _ - ------------------- 21 CMT_vot adequate to tie-in long string to -surf csg- - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ _ _ _ _ _ - _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - 22 CMT_will coverall known -productive horizons_ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - _ _ _ _ _ _ 4.5"_liner_will be_fully cemented_and Kup perfs cov_ere_d with liner lap ---------- 23 Casing designs adequate for CJ, 13 &_permafrost---------------------------- Yes _ _ _ _ _ _ _ BTC calc supplied .. Meet_industry_standards-- - - - - - - _ - - _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - 24 Adequatetankage_or reserve pit - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - Yes- - _ _ __ Rig -has steel pits_.._ All -waste toapproved disposalwells - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - 25 Af_a_re-drill, has_a 10-403 for abandonment been approved - - - - - - - - - - - - - - - - - - - - - - Yes - - _ _ _ _ _ 316-269 _This is a drillout of the production_ casing shoe to_Sag fm._ Kup will be covered in -liner -lap - _ - - - - - - - - 26 Adequate wellbore separation_ proposed_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _Proximity_ analysis is provided and no issues, - - - - - - - _ - - - - - - - _ - - - _ - - - - - _ - - - - - - - - - - - 27 If_diverter required, does it meet regulations_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _N_A_ - - _ _ _ _ _ wellhead -in place_—BOPE will be used to drill the 6 1/8" -OH section. - Appr Date 28 Drilling fluid_ program schematic_& equip_list adequate- - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ _ _ _ Max form pressrue =_4687 psi (9,8_ ppg E_M_W)_ will drill with 10.5-_ 1.2_ppg mud._ GLS 5/26/2016 29 _B_O_PEs,_do they meet regulation _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes - - - - - - _Doyon 14 has 13 5/8- 5000_psi-BOP_E_ - _ _ _ _ _ _ _ _ _ . _ _ _ _ - - -I - - - - - 30 BOPE_press rating appropriate; test to -(put psig in comments)- - - - - - - - - - - - - - - - - - - - Yes - - - - - - _ MASP = 3768_psi_will test BOPE_to 4000 -psi -(annular to -2500-psi) - - - - -- 31 Choke_ manifold complies w/API_ RP -53 (May 84)- - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 32 Work will occur without operation shutdown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - _ _ _ Completion program is approved_ in PTD but need sundry to_ perforate ----------------- 33- 33 Js presence of H2S gas probable _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - _ _ H2S on_ pad _ ._Rig has sensors and alarms. _ _ _ _ _ _ _ _ _ _ _ - - - 34 Mechanical_condition of wells within AOR verified fFor service well only _ _ _ _ NA_ _ _ _ _ _ _ _ _ 35 Permit_canbeissuedw/ohydrogen- sulfidemeasures------------------------- No____-___H2Smeasuresrequired- _---_-----__-_-__ ___-----_____________---_--__- Geology 36 Data_presented on potential overpressure zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - _ _ _ _ _ _ Expected reservoirpressure is 9.82EMW. will be drilled using_ 10,5_to 12.0 pP9 - PP-gmud _. - - - - Appr Date 37 Seismic_analys_is of shallow gas -zones ----------------------------------- N_A------------ ---------------------------------------------------------------- PKB 5/11/2016 38 Seabed condition survey (if off -shore) _ _ _ _ _ _ _ NA_ _ _ _ _ _ _ _MPU C -15 -is a Kuparuk C_ injector._ The well will beside tracked to_ a deeper depth to target the -- - River _ - _ _ _ 39 Contact name/phone for weekly_progress reports (exploratory only] - - - - - - - - - - - - - - - - NA_ _ _ _ _ _ _ _ reservoir in an untested fault block. _ _ _ - - - - - - _ _ _ _ _ _ - - - - - - - - - - - _ - - - _ _ _ _ _ Geologic Engineering Public Will drill out 7" casing shoe to Sag Fm target. 4.5" Liner lap will P & A the existing Kup sand perforations. GIs Commissioner: Date: Co stoner: . Date Commissioner Date Y) j�S -7 /it �St Z FINAL WELL REPORT MUDLOGGING DATA MPC-15A Milne Point Unit North Slope Borough Provided by: Approved by: Daniel Yancey Compiled by: Steve Pike David Deatherage Allen Odegaard Chad Record Distribution: 7/15/2016 T.D. Date: 6/25/2016 MPC-15A 1 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW ................................................................................................ 2 1.1 Equipment Summary ...................................................................................................................... 2 1.2 Crew ................................................................................................................................................ 2 2 WELL DETAILS ..................................................................................................................................... 3 2.1 Well Summary ................................................................................................................................ 3 2.2 Hole Data ........................................................................................................................................ 3 2.3 Daily Activity Summary ................................................................................................................... 4 3 GEOLOGICAL DATA ............................................................................................................................. 5 3.1 Lithostratigraphy ............................................................................................................................. 5 3.2 Lithologic Descriptions .................................................................................................................... 6 3.3 Mudlog Summary .......................................................................................................................... 24 3.4 Connection Gases ........................................................................................................................ 25 3.5 Sampling Program / Sample Dispatch .......................................................................................... 26 4 DRILLING DATA .................................................................................................................................. 27 4.1 Survey Data .................................................................................................................................. 27 4.2 Bit Record ..................................................................................................................................... 30 4.3 Mud Record .................................................................................................................................. 31 4.4 Drilling Progress Chart .................................................................................................................. 32 5 SHOW REPORTS ............................................................................................................................... 33 6 DAILY REPORTS ................................................................................................................................ 37 Enclosures: 5”/100’ Formation Log (MD/TVD) 2”/100’ Formation Log (MD/TVD) 2”/100’ Drilling Dynamics Log (MD/TVD) 2”/100’ LWD / Lithology Log) MD/TVD) 2”/100’ Gas Ratio Log (MD/TVD) Final Data CD MPC-15A 2 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type / Position Total Downtime Comments Ditch gas Canrig QGM Agitator (Mounted in possum belly) Canrig E-Series Flame ionization total gas & chromatography. 0 Carbon Dioxide Ditch Gas Monitoring 0 Drilling Parameters Provided by TOTCO WITS Feed 2hrs Comm issues ROP, Mud Flow In Rigwatch Calculations 0 Logging unit computer system Intel(R)Core(TM)2 Duo CPU 0 Pit Volumes, Pit Gain/Loss Provided by TOTCO WITS Feed 2hrs Comm issues 1.2 Crew Unit Type : Steel Arctic Unit Number : ML57 Mudloggers Years1 Days2 Technician Days Steve Pike 16 06/17/16 David Deatherage 34 06/17/16 Allen Odegaard 19 06/17/16 Chad Record 8 06/17/16 1 Years experience as Mudlogger 2 Days at wellsite between spud and total depth of well MPC-15A 3 2 WELL DETAILS 2.1 Well Summary Well: MPC-15A API Index #: 50-029-21358-01-00 Field: Milne Point Unit Surface Co- Ordinates: Lat 70°, 29’, 7.200’ N Long 149°, 31’, 31.821’ W, AK Borough: North Slope Borough Primary Target Depth: 9400’ MD / 8810.70’ TVD State: Alaska TD Depth: 9928’ MD / 9249.92’ TVD Rig Name / Type: Doyon Drilling #14 Arctic Triple - Topdrive Suspension Date: Primary Target: Sag River Formation License: 214-027 Spud Date: 6/12/2016 Mud Line: 50.34’ Completion Date: KB: 33.64’ Completion Status: Secondary Target: Depth: Shublick 9505’ MD / 8896.70’ TVD Classification: Development TD Date: 6/25/2016 TD Formation: Sadlerochit Days Testing: Days Drilling: 8 2.2 Hole Data Hole Section Maximum Depth TD Formation Mud Weight (ppg) Dev. (oinc) Casing/ Liner Shoe Depth LOT (ppg) MD (ft) TVDSS (ft) MD (ft) TVDSS (ft) 6 1/8” 9928 9250 Sadlerochit 11.8 30.78 9928 9250 11.0 MPC-15A 4 2.3 Daily Activity Summary 6/17/2016 Mill on tubing packer 7144’-7146’. Observed flow increase. Spaced out tool joint, stopped rotary and mud pumps. Monitor well. Shut in well. Circulate bottoms up thru fully open choke. Monitor well. Open annular. Blow down choke. Mill on tubing packer 7146’-7146.5’, packer released. Wash/ream 7146.5-7437’, took 15k. Circulate bottoms up. Monitor well. POOH to collars. Flow check. Pull collars. Lay down milling BHA and mill. Clean out boot baskets. RIH to 7382’. Locate packer. Spear into packer. POOH to 5028’. Lubricate rig. POOH with fish to 320’ 6/18/2016 POOH. Lay down fish and BHA. Clean flor. Make up BHA. Pick up drill pipe and RIH to 3255’. RIH to 7400’. Wash 7400’-7446’. Wash/ream 3 to 6 bbl/min. Attempt F.I.T. to 13.0ppg EMW. Obtained 12.4 PPG EMW. Circulate and condition mud. Pump Baracarb/Steel Seal pill across perfs. Work pressure up bull heading into pits. Bleed back to trip tank. Monitor well. Blow down choke and kill lines. Wash 7464’-7555’. Mill 7555’-7654’, cement plug at 7557’, float collar at 7637’. 6/19/2016 7653’-7687’ (34’) Mill 7637’-7657’. Spot Baracarb/Steel Seal pill. Check flow. Monitor well. Pull to 7115’. Pump dry job. POOH to 430’. Flow check. POOH. Inspect mill. Clean boot baskets. Beaver slide OPS. Clean floor. Mobilize Halliburton and hold PJSM. Make up Mudmotor, bit LWD and MWD BHA. RIH to 7611’ filling pipe every 2000’. Spool on 1800’ of drill line. Inspect crown-o-matic, saver sub and deadman anchor. Service IBOP and swivel packing. Drill 7657’-7686’. Circulate. Perform F.I.T. to 13.0ppg EMW. Bleed back, blowdown choke and kill lines. Wash down 7611’-7687’. 6/20/2016 7687’-7916’ (229’) Drill 7687’-7916’. Circulate bottoms up. Pull to 7611’. Pump dry job. POOH to 739’, BHA. Monitor well. Stand back BHA in derrick. Download LWD. Break out stabilizer. Make up new bit. Shallow test MWD/LWD. RIH to 7321’. 6/21/2016 7916’-8396’ (480’) Service topdrive, blocks and draw works. RIH 7321’-7603’. Fill pipe, survey. RIH to 7886’. Wash 7886’- 7916’. Drill 7916’-8396’. 6/22/2016 8396’-8969’ (573’) Drill 8396’-8969’. 6/23/2016 8969’-9194’ (225’) Drill 8969’- 9194’. SPR’s. POOH TP 7603’. Monitor well, break circulation. Pump dry job. POOH. Stand back BHA. Change bit, NB #2 plugged jet. RIH tools. Shallow test MWD/LWD. RIH to 3055’. Fill pipe. RIH to 6346’. Fill pipe: RIH to 8828’. 6/24/2016 9194’-9882’ (688’) RIH 8828’-9111’. Wash 9111-9194’. Drill 9194’-9882’. 6/25/2016 9882’-9928’ (46’) Drill 9882’-9928’. Circulate; Flow check, positive flow. Circulate, MW increase to 11.0. Flow check Negative. Pull to 8800’. Pump dry job. Pull to BHA. Download LWD/MWD. Laydown BHA. Rigup and run liner. Makeup hanger. RIH liner on drill pipe. MPC-15A 5 3 GEOLOGICAL DATA 3.1 Lithostratigraphy Tops compiled by Hilcorp geologist Daniel Yancey. FORMATION MARKER Projected Actual MD SSTVD MD SSTVD KUPARAK Top Not Seen ------ ------ ------ ------ KINGAK MP_KNG_TJF 7949 -7540 MP_KNG_TJE 8180 -7751 MP_KNG_TJD 8610 -8109 MP_KNG_TJC 9052 -8468 MP_KNG_TJB 9279 -8652 MP_KNG_TJA 9424 -8772 SAG RIVER MP_SGR_SGD -8806 9501 -8837 MP_SGR_SGC -8827 9524 -8856 MP_SGR_SGB -8845 9538 -8868 MP_SGR_SGA -8876 9574 -8898 SHUBLIK MP_TSHU -8898 9595 -8916 EILEEN (IVISHAK) MP_TEIL 9794 -9084 SADLEROCHIT MP_TSAD 9856 -9137 MPC-15A 6 3.2 Lithologic Descriptions 7657-7680 SILTSTONE = Occasional to dominantly dark grayish brown, occasional olive brown hues. Occasionally firm to dominantly soft, mushy hydrated and easily soluble; Matte luster with variable micro mica and pyrite sparkle; dominantly very fine abrasive to occasionally smooth texture. No evident sedimentary structures. Scattered interbedded poorly fissile shale; scattered very fine disseminated sand grains. Grading to soft to firm dirty poorly sorted matrix supported sandstone. Common black carbonaceous material; occasionally grades to claystone and mudstone. No oil indicators present. 7680-7710 CLAYSTONE = Light to occasionally dark grayish brown, scattered olive brown. Soft mushy, sectile hydrated and easily soluble. Dull luster with scattered very fine micro sparkle; Smooth to common very fine abrasive texture. Noncalcareous. Scattered to common black carbonaceous lignitic debris. Variable silt content grading to siltstone; Minor very fine disseminated sand. Trace disseminated pyrite. No oil indicators present. 7710-7740 SANDSTONE = Overall dominantly dirty matrix supported brownish gray. Scattered light to dark gray grain packed, very fine grained, dominantly subrounded and moderately spherical. predominately quartz with minor feldspar. Non-cemented. Clean sandstone is firm semi friable with moderate porosity and permeability occurring as thin discontinuous stringers. The dirty matrix supported sandstone is soft, mushy, lacks porosity and permeability and grades to siltstone. Traces of pyrite are evident. Scattered black carbonaceous material is present. No oil attributes were observed. 7740-7770 SILTSTONE = Dark brown to light brown. Mushy to somewhat slightly pasty consistency. Occasionally crumbly. Rounded blocky amorphous cuttings habit. predominately dull luster with some waxy areas and fine micro sparkle. Abundant clay versus silt, highly variable grading to claystone. Scattered very fine disseminated quartz sand. Occasional interbedded shale. No visible sample fluorescence. 7770-7800 SILTSTONE = Dark brown to light brown mushy to somewhat slightly pasty; very crumbly; irregular fracture; amorphous cuttings habit; predominately dull luster with some waxy to greasy in places; mostly clayey throughout with some slightly gritty in places; interbedded with lesser amounts of shale, and lower fine to lower medium grain very well rounded quartz sand, and abundant very dark colored lithic fragments throughout the sample; no visible sample fluorescence. 7800-7830 CLAYSTONE = Dark gray to medium gray; clumpy to clotted to pasty; mostly brittle with some slightly crumbly in places; predominately irregular fracture with some slightly planar; mostly amorphous cuttings habit; resinous to somewhat waxy luster; predominately clayey to smooth texture with some slightly gritty in places; thinner beds of claystone interbedded with larger beds of slightly sandy siltstone and smaller amounts of loose grain well rounded quartz sand; abundant dark colored lithic fragments throughout the sample; no visible sample fluorescence was observed throughout the sample. MPC-15A 7 7830-7860 SILTSTONE = Occasional medium to dominate dark grayish-brown, occasional olive-brown hues; moderately firm to soft mushy hydrated, easily soluble; matte luster with variable micromica, pyrite sparkle; occasional smooth to very fine abrasive texture; no evident structure; scattered firm interbedded pyrite fissile shale; scattered disseminated sand, soft to firm sandstone; black carbonaceous debris; occasional grading to clay/mud stone; no oil attributes. 7860-7890 SHALE = Medium dark gray to medium gray; moderately firm to slightly stiff; somewhat dense to occasionally brittle in places; mostly planar to somewhat irregular fracture; mostly resinous to slightly vitreous luster; predominately smooth texture with some slightly clayey in places; thinner beds of shale interbedded with larger beds of brownish gray very clayey siltstone, and trace amount of salt and pepper, upper very fine to upper fine grain sand, predominately quartz grain sandstone, very friable throughout; no visible sample fluorescence throughout; no other oil indicators were observed. 7890-7920 CLAYSTONE = Predominantly dark gray to medium gray; clumpy to pasty to clotted; mostly brittle with some slightly crumbly to crunchy in places; predominately irregular fracture with some slight ly planar; mostly amorphous cuttings habit; resinous to somewhat waxy luster; predominately clayey to smooth texture with some slightly gritty in places; thinner beds of claystone interbedded with larger beds of slightly sandy siltstone and smaller amounts of loose grains of well-rounded quartz sand; abundant dark colored lithic fragments throughout; no visible sample fluorescence was observed throughout. 7920-7932 GLAUCONITE = Common medium to dark green glauconite is present in all lith types, sandstone, siltstone and claystone. Precipitate is in small rounded globules, occasional flakes and commonly staining clays and silts. No oil indicators are present. 7932-7950 SILTSTONE = Brownish gray to light olive gray; punky to pasty to mushy; crumbly to crunc hy to slightly brittle; mostly irregular fracture; massive cuttings habit; mostly dull luster with some waxy to greasy; mostly silty overall with some extremely gritty in places; no visible sample fluorescence throughout. 7950-7980 SHALE = Medium gray to blackish gray; clumpy to pasty to slightly stiff; mostly crumbly to v brittle throughout; predominately amorphous fracture with some occasionally irregular; massive cuttings habit; predominately earthy luster with some occasionally slightly dull; very clayey texture with some silty to slightly gritty in places; thicker beds of shale interbedded with thinning lenses of sandy siltstone; occasionally very thin lens of very fine quartz sand; no visible sample fluorescence was observed; no other oil indicators. 7980-8010 SILTSTONE = Brownish gray to medium gray; punky to mushy to pasty; crumbly to crunchy with some brittle; predominately irregular fracture; massive cuttings habit; mostly dull luster with some greasy to waxy; predominately silty overall with some extra gritty in places; no visible sample fluorescence was observed. MPC-15A 8 8010-8040 SILTSTONE = Brownish gray to light brownish gray; Clotted, lumpy to somewhat clumpy; irregular fracture; amorphous cuttings habit; predominately dull luster with some greasy to waxy; predominately clayey with some gritty in places; interbedded with lesser amounts of shale, and very fine grain, very well rounded, friable quartz sand, trace glauconite; no visible sample fluorescence was observed; no other oil indicators were observed. 8040-8070 CLAYSTONE = Light to occasionally dark grayish brown, scattered olive brown. Soft mushy, sectile hydrated and easily soluble. Dull luster with scattered very fine micro sparkle. Smooth to common very fine abrasive texture. Noncalcareous. Scattered to common black carbonaceous lignite debris. Variable silt content grading to siltstone. Minor very fine disseminated sand. Trace disseminated pyrite. No oil indicators present. 8070-8100 SILTSTONE = Brown to gray brown; punky to pasty to somewha t slightly mushy; crunchy to crumbly to slightly brittle; irregular fracture; amorphous cuttings habit; dull luster with some waxy to greasy in places; predominately clayey throughout with some slightly gritty in places; interbedded with lesser amounts of shale, and lower fine grain to lower medium grain very well rounded quartz sand, and abundant very dark colored lithic fragments; no visible sample fluorescence; no other oil indicators were observed. 8100-8130 CLAYSTONE = Medium gray to greenish gray; clumpy to clotted to pasty; mostly crumbly to very brittle with some crunchy; predominately amorphous fracture with some occasional irregular; massive cuttings habit; predominately earthy luster with some occasionally slightly dull; very clayey texture with some slightly gritty in places; thicker beds of claystone interbedded with thinning lenses of sandy siltstone; occasional very thin lenses of very fine quartz sand; no visible sample fluorescence was observed; no other oil indicators were observed. 8130-8160 SILTSTONE (8130-8160) = Brownish gray to light brownish gray; Clotted, lumpy to somewhat clumpy; irregular fracture; amorphous cuttings habit; predominately dull luster with some greasy to waxy; predominately clayey with some gritty in places; interbedded with lesser amounts of shale, and very fine grain, very well rounded, friable quartz sand, trace glauconite; no visible sample fluorescence was observed; no other oil indicators were observed. 8160-8190 SILTSTONE = brownish gray to light brownish gray; lumpy to somewhat clumpy; irregular fracture; amorphous cuttings habit; predominately dull luster with some greasy to waxy; predominately clayey with some gritty in places; interbedded with lesser amounts of shale, and very fine grain, very well rounded, friable quartz sand, trace glauconite; no visible sample fluorescence was observed; no other oil indicators were observed. 8190-8220 CLAYSTONE = Medium dark gray to greenish gray; clotted to clumpy to pasty; mostly crumbly to very brittle throughout; predominately amorphous fracture with some occasionally irregular; massive cuttings habit; predominately earthy luster with some occasionally slightly dull; very clayey texture with some silty to slightly gritty in places; thicker beds of claystone interbedde d with thinning lenses of sandy siltstone; other oil indicators were observed. MPC-15A 9 8220-8250 SILTSTONE = Medium to occasional dark grayish-brown; soft hydrated, easily soluble, mushy, very sticky; very fine abrasive texture; dull luster; occasional faint bedd ing; minor very fine sand; occasional grading to claystone; scattered interbedded shale; trace calcareous; scattered black carbonaceous material; trace micro mica, disseminated pyrite; rare botryoidal pyrite; no oil indicators. 8250-8280 CLAYSTONE = Dominantly medium light brownish gray with common yellowish hue; soft hydrated, sol sticky, pasty, mushy; smooth to very fine abrasive texture; dull luster with variable micro sparkle, scattered micro mica, trace disseminated pyrite; blocky rounded cuttings habit; common silty grading to siltstone; trace disseminated very fine sand; occasionally faint bedding; trace black lignitic fragments; dominant no calcareous with trace calcareous areas; no oil attributes. 8280-8310 SHALE + Minor amounts present. Dark olive black to grayish black. Firm slightly crumbly. Smooth texture. Matte to slightly waxy luster with scattered pyrite micro sparkle. Noncalcareous. Poorly fissile. Non-laminated. Occur as thin probably discontinuous interbeds in host sand/silt sequence. No oil attributes were seen. 8310-8340 SANDSTONE = Dominantly dirty matrix supported. Scattered clean grain support. Light to medium grayish brown, brownish-gray, occasional off white, trace white. Very fine to occasional fine grained. Grains range from trace angular to rounded and are dominantly subrounded and exhibit dominantly moderate sphericity. Clean sandstone is grain packed and very well sorted. Whereas the dirty matrix rich sandstone is grain to dominantly matrix supported and poorly sorted. No evident sedi mentary structures are present. Compositionally quartz is dominant with minor feldspar, trace mica and black carbonaceous specs. Overall poor to trace good porosity and permeability. Non -cemented. Dirty sandstone is soft, hydrated easily soluble, mushy. Clean sandstone is firm and semi friable. Dirty sand grades to siltstone. Clean sands occur as thin discontinuous stringers, lenses. No oil indicators were observed. 8340-8370 SILTSTONE = Dominantly medium grayish brown, occasional yellowish hues. Soft, hydrated, mushy, pasty to sticky easily soluble. Dull luster with scattered pyrite micro sparkle. Very fine abrasive texture. Noncalcareous. Trace grading to claystone. Common to scattered very fine disseminated sand grading to dirty matrix supported sandstone. Occasional faint parallel bedding, laminations are evident. Occasional micro mica and common black carbonaceous material along bedding planes. No oil attributes are present. 8370-8400 ASH = Dark gray. Firm slightly crumbly. Matte luster. Smooth texture. Common pyrite. Non- fluorescent. No associated oil attributes. 8400-8430 CLAYSTONE = Light grayish brown, pale yellowish brown, scattered grayish laminations, lentils. Smooth texture. Matte luster. Soft hydrated easily soluble mushy, pasty to sticky. Good a dhesion. Slightly expansive. Round cuttings habit. Variable silt content grading to siltstone. Rare black carbonaceous material. Trace micro mica and abundant pyrite is present. Noncalcareous. Scattered faint bedding and laminations are present. Laminations are dominantly discontinuous and parallel. No oil attributes were observed. MPC-15A 10 8430-8460 SILTSTONE = Light grayish brown, pale yellow brown. Soft mushy hydrated soluble. Dull luster w ith scattered very fine sparkle; Smooth to fine abrasive texture. Round blocky cuttings habit. Scattered very fine sand; Overall very argillaceous; Scattered micro mica. Trace pyrite. Noncalcareous Trace black carbonaceous material. Grades to claystone; Scattered faint discontinuous laminations, trace sandy lenses. No oil indicators. 8460-8490 SANDSTONE = Overall pale yellowish brown to grayish brown when dirty, light to dark gray when clean. Dirty sand is soft hydrated, mushy grain to matrix supported, poorly sorted very fine grained and grades to siltstone. Clean sands are very well sorted grain supported, grain packed, very fine to trace fine grained. Grains in both are occasionally angular to well rounded, dominantly subrounded and moderately spherical. Compositionally quartz is dominant with scattered feldspar and rare mafics, occasional mica. Scattered black carbonaceous debris is present. Pyrite is variable, common to scattered, dominantly disseminated to minor packets. Occasional faint bedding is evident, parallel and apparently discontinuous. Sandstone appears to be thin and lenticular. Overall porosity and permeability are poor. No oil attributes were seen. 8490-8520 SANDSTONE = translucent to clear, with white, dark yellowish, light gray, dark gray, moderate brown hues; predominately quartz sand matrix throughout; mos tly grain supported, very friable throughout; lower very fine to lower medium grain; very well to moderately sorted; very well rounded to subrounded with some slightly subangular in places; mod sphericity; some grains appear to be slightly polished in places; thin beds of fine grain sandstone interbedded with thicker beds of slightly gritty dark gray to brownish gray siltstone throughout; no visible sample fluorescence was observed. 8520-8550 SAND = clear to translucent with some opaque, white, tan, and pinkish gray hues; quartz grain sand matrix throughout; lower very fine grain to lower medium grain; well sorted throughout; very well rounded with some subrounded and some subangular; moderate sphericity; some grains show signs of mechanical abrasion; thinner beds of sand interbedded with thinner beds of very fine sandstone and thicker beds of sandy siltstones and shale; no visible sample fluorescence was observed. 8550-8580 SILTSTONE = light brownish gray to light olive gray; pasty to somewhat mushy; predominately brittle with some slightly crumbly in places; irregular fracture; amorphous to massive cuttings habit; dull luster; predominately silty texture with some v gritty; thick beds of siltstone interbedded with very thin laminations of very fine quartz grain sandstone, grain supported, very friable; trace loose sand grains throughout; no visible sample fluorescence was observed. 8580-8610 SHALE = Black to grayish black; firm to stiff; dense with some brittle; irregular to planar fracture; blocky cuttings habit; resinous luster with some slightly vitreous; overall smooth texture; thinner beds of shale interbedded with sandy siltstones and very fine grained sandstones with some loose sand; no visible sample fluorescence was observed. MPC-15A 11 8610-8640 SANDSTONE = Translucent to clear, with white, dark yellowish, light gray, dark gray, moderate brown hues; mostly quartz grain sand matrix throughout; mostly grain supported, very friable throughout; lower very fine to lower medium grain; very well to moderately sorted; very well rounded to subrounded with some slightly subangular in places; mod sphericity; some grains show signs of mechanical abrasion; thin beds of fine grain sandstone interbedded with thicker beds of slightly gritty dark gray to brownish gray siltstone throughout; no visible sample fluorescence was observed. 8640-8670 SILTSTONE = olive gray to light brownish gray with some dark greenish gray; mostly mushy to somewhat slightly pasty; crunchy; irregular fracture; amorphous cuttings habit; dull luster with some greasy to waxy; predominately very silty throughout with some slightly gritty in places; interbedded with smaller amounts of very fine grain quartz sandstone laminations throughout the sample, and abundant very dark colored lithic fragments; no visible sample fluorescence; no other oil indicators were observed. 8670-8700 SILTSTONE = brownish gray to light olive gray; pasty to mushy; crumbly to crunchy; mostly irregular fracture; massive cuttings habit; predominately dull luster with some waxy to greasy; mostly silty overall with some extremely gritty in places; no visible sample fluorescence throughout. 8700-8730 CLAYSTONE = Brownish gray to medium grayish brown; crumbly to crunchy to tacky; mostly brittle with some crumbly to crunchy; irregular fracture; amorphous cuttings habit throughout; dull to earthy luster with some slightly waxy in places; predominately silty overall with some grading to gritty; no visible sample fluorescence was observed; no other oil indicators were observed. 8730-8760 SANDSTONE = predominately clear to translucent, with some white, gray, light gray, light brownish gray, pinkish gray, and moderate reddish brown hues; mostly quartz grain sand matrix, with some dark colored carbonaceous material throughout; very friable, grain supported; lower very fine to lower medium grain; well to moderately sorted; very well rounded to subrounded with some subangular in places; moderate sphericity; grains appear to be polished in places; thin beds of fine grain sandstone interbedded with thick beds of very gritty dark gray to olive gray siltstone throughout sample; trace pyrite; no visible sample fluorescence was observed; no other oil indicators were observed 8760-8790 SAND (8760-8790) = Translucent to clear with some white, light gray, and pinkish gray hues; mostly quartz sand matrix with some dark colored lithic fragment throughout the sample; friable; lower very fine to lower medium grain sand; very well rounded to subrounded with some subangular to very angular in places; moderate sphericity; thinner beds of loose sand interbedded with thicker beds of sandy siltstones and shale; no oil indicators were observed. MPC-15A 12 8790-8820 SANDSTONE = Predominantly clear to cloudy quartz. Scattered light gray transparent to translucent feldspar. Scattered variable color mica, brown, clear, silver. Scattered pyrite growths. Common disseminated pyrite. Trace to scattered black carbonaceous debris. Very fine to scattered lower fine grains. Grains are dominantly subrounded and range from angular to rounded and display dominantly moderate sphericity. Variable sorting depending upon matrix content. Commonly dirty poorly sorted silty to argillaceous. Scattered to common very well sorted grain supported. Scattered parallel laminations. Laminations are dominantly discontinuous, lenticular. Scattered organic material along bedding planes. Non-cemented firm friable to dominantly hydrated mushy grading to siltstone. Dominantly poor to occasional moderate porosity. Dominantly poor permeability. Scattered interbedded gray clay. No oil indicators. 8830-8850 SHALE = Dark olive black to dark grayish black. Moderately firm well indurated. Smooth texture with occasionally slightly hackly fracture. Matte to waxy luster with variable micro sparkle from occasionally abundant pyrite and trace micro mica. Noncalcareous. trace organic material. Poor to moderate fissility. Scattered thin parallel laminations/bedding features. Some organic debris along bedding planes. Pyrite is variable, disseminated and in small packets. No oil attributes. 8850-8880 SILTSTONE = Light grayish-brown, pale yellowish brown. Soft, hydrated, mushy. Easily soluble. Very sticky with good adhesion. Dull luster with scattered disseminated pyrite and mica sparkle. Very fine abrasive texture. Noncalcareous. Trace to scattered black organic debris, dominantly lignitic. Occasional dark gray interbedded clay. Minor pyritic shale. Commonly grades to dirty matrix supported sandstone. No oil attributes. 8880-8910 CLAYSTONE = Medium to dominantly dark gray. Soft. Crumbly to sectile. common thin discontinuous laminations. Laminations dominantly color variations light to dark and occasionally sandy to silty. Scattered disseminated pyrite. Trace black carbonaceous material along bedding planes. No oil indicators. 8910-8940 SANDSTONE = Overall light gray to pale yellow brown and grayish brown, occasionally off white. Very fine to scattered fine grained. Grains range from angular to scattered well rounded and are dominantly subrounded. Grains are dominantly moderately spherical. Variable sorting ranging from clean grain support very well sorted to dirty, argillaceous and silty matrix supported poor sorting grading to siltstone. Composition is dominantly quartz with scattered feldspar and rare mafics. Occasional small black carbonaceous specs are present. Trace to common disseminated pyrite throughout with occasional small pyrite masses also present. Sparkling micro mica is present in trace amounts. The sandstone exhibits overall poor porosity and permeability. Thin irregular medium to dark clays are interbedded, thinly laminated. Laminations are parallel, discontinuous and lenticular. No oil attributes are present. 8940-8970 CLAYSTONE = Light to dominantly dark gray. Soft to slightly firm. Less hydratable than earlier yellowish, brownish claystone. Sectile to mushy. Common thin discontinuous laminations bedding. Laminations dominantly color variations light to dark and occasional compositional variations, sandy to silty. Occasionally common disseminated pyrite. Trace black carbonaceous debris. Noncalcareous. No associated oil indicators. MPC-15A 13 8970-9000 SAND = Increasingly loose, disaggregated in clay and silt matrix associated with increasing grain size. Dominantly clear to occasionally cloudy quartz. Scattered light gray, rare opaque feldspar. Rare dark mafic grains. Very fine to scattered lower medium, dominantly very fine grained. Grains range from occasional angular to trace well rounded and are dominantly subrounded and moderately spherical. Grains are bit disaggregated to disseminated in abundant clay and silt matrix. Overall in cuttings faint bedding is present with occasional black carbonaceous along planes. Common pyrite is present, disseminated and in small packets. No oil attributes are present. 9000-9030 SILTSTONE = Light to dark gray with decreasing yellowish-gray and brownish hues. Soft hydrated, easily soluble to occasionally firm and sectile. Exhibits an abrasive texture and dull luster. Noncalcareous. Faint laminations and bedding are evident with variations in grain/particle size, color and traces on black carbonaceous debris. Disseminated pyrite is present occasionally heavier along bedding planes. Cuttings can be very sandy grading to dirty sandstone. Gray clay interbeds are evident. Traces of glauconite are evident. No oil indicators are present. 9030-9060 CLAYSTONE = Medium to dark gray. Soft, mushy, sectile, occasionally crumbly. Dull luster with scattered to trace micro sparkles. Smooth to occasional abrasive silty texture. noncalcareous. Common thin discontinuous laminations dominantly color variations and occasionally sandy to silty. Scattered disseminated pyrite. Trace black carbonaceous material, dominantly specs, occasional large along bedding planes. Variable dominantly low silt content. No oil indicators present. 9060-9090 SANDSTONE/SAND = gray to light gray, with some white, translucent to clear; predominately quartz grain sand matrix, with abundant dark colored lithic fragments; lower very fine to lower medium grain; well to moderately sorted; well-rounded to subrounded with some subangular in places; mod sphericity; grains appear to be polished in places; thin beds of fine grain sandstone interbedded with thicker beds of very gritty dark gray to brownish gray siltstone throughout sample; trace pyrite; no visible sample fluorescence was observed. 9090-9120 SHALE = Dark gray to grayish black; firm to stiff; mostly dense with some brittle; irregular to slightly planar fracture; blocky cuttings habit; mostly resinous luster with some slightly vitreous; overa ll smooth texture with some clayey in places; thicker beds of shale interbedded with sandy siltstones and very fine grained sandstones with some loose sand; no visible oil indicators were observed. 9120-9150 SILTSTONE = dark gray to medium gray; clotted to clumpy with some mushy; predominantly brittle with some crumbly in places; irregular fracture; amorphous to massive cuttings habit; dull luster; predominantly silty texture with some v gritty; thick beds of siltstone interbedded with very thin beds of very fine quartz grain sandstone, grain supported, very friable; trace loose sand grains throughout; no visible sample fluorescence was observed. 9150-9180 SANDSTONE = Overall light to medium gray. Individual grains dominantly clear, occasionally cloudy quartz. Very fine to scattered medium. Grains range from occasional angular to rounded and are dominantly subrounded with moderate sphericity. Very well to well sorted grain support when clean. Poorly sorted grain to matrix support when dirty grading to siltstone. Occasional bedding is evident; Poor to occasional moderate porosity and permeability is evident. Minor black carbonaceous material is present. No oil indicators were observed. MPC-15A 14 9180-9210 SHALE = Dark olive gray with scattered dark olive brown. Firm to occasionally moderately hard. Matte to very fine sparkling luster. Smooth texture. Poor to moderate fissility. Non-laminated. Occasional silt. Trace to scattered black carbonaceous material. Scattered pyrite, dominantly disseminated, scattered patches. No oil attributes. 9210-9240 CLAYSTONE = Dominantly medium, common dark and occasional light olive gr ay, occasional brownish hues; Soft hydrated, mushy to firm sectile. Smooth to very fine abrasive texture. Dull luster with scattered micro mica and pyrite sparkle; noncalcareous; Minor evident faint bedding. Occasionally very silty grading to siltstone. Pyrite is dominantly disseminated, rare crystal packets. scattered black organic debris, small specs to trace large flakes. Non-fissile. Non-laminated. No oil indicators observed. 9240-9270 SILTSTONE = Brownish gray to medium gray; mushy to pasty; crumbly to crunchy; predominantly irregular fracture; massive cuttings habit; mostly dull luster with some greasy to waxy; predominately silty overall with some extra gritty in places; trace pyrite; no visible sample fluorescence was observed. 9270-9300 SILTSTONE = medium gray to brownish gray; pasty to clumpy; crunchy to crumbly; mostly irregular fracture; massive cuttings habit; predominately dull luster with some w axy to greasy; mostly silty overall with some extra gritty in places; trace pyrite; no visible sample fluorescence was observed. 9300-9310 SAND/SANDSTONE = Predominately translucent to clear, with some light gray to medium dark gray, and white hues; quartz grain sand matrix throughout; sandstone is grain supported and very friable throughout; lower very fine to upper medium, with some lower course in places; fair to poorly sorted; subangular to very angular; moderate to high sphericity; thick beds of sand/sandstone interbedded with thin beds of clay to gritty siltstone; some sand grains appear to show signs of mechanical abrasion; no visible sample fluorescence was observed. 9310-9320 SILTSTONE = Brownish gray to medium dark gray; clotted to clumpy; crunc hy to crumbly; mostly irregular fracture; massive cuttings habit; some somewhat dull to greasy luster; very silty to grading up too somewhat gritty; thin siltstone beds interbedded with thick beds of sand and sandstone; no visible sample fluorescence was observed. 9320-9330 SHALE = Medium dark gray to medium gray; pretty firm to stiff; somewhat brittle with some appearing slightly dense; planar fracture; platy to massive cuttings habit; predominantly resinous to slightly vitreous luster; mostly smooth with some slightly clayey in places; shale percentages appears to increase at this depth; no visible sample fluorescence was observed. 9330-9340 SANDSTONE/SAND = Mostly clear to translucent with some medium gray to light gray, and off white hues; predominately quartz grain sand matrix with abundant dark colored lithic fragments; sandstone is grain supported and very friable lower very fine grain to upper medium grain; fair to poorly sorted throughout sample; very angular to subangular; moderate to high sphericity; thicker beds of sandstone/sand interbedded with thick beds of shale and thinner beds of clayey to somewhat gritty siltstone; some sand grains appear to show signs of mechanical abrasion; no visible sample fluorescence was observed. MPC-15A 15 9340-9350 SILTSTONE = Gray to med dark gray; clotted to lumpy to mushy; crumbly to crunchy; irregular fracture; massive cuttings habit; mostly dull to earthy to waxy luster; mostly silty to gritty; siltstone beds interbedded with thicker beds of sand and sandstone, and thi nner beds of shale; no visible sample fluorescence was observed. 9350-9360 SHALE = Medium gray to medium dark gray; firm to slightly stiff with some tacky; brittle to dense with some tough; somewhat planar fracture; massive to slightly platy cuttings habi t; mostly resinous to slightly vitreous with some greasy luster; predominately smooth with some slightly clayey in places; no visible oil indicators were observed. 9360-9370 SILTSTONE = Dark gray to medium dark gray; mushy to pasty to punky; crunchy to crumbly; mostly irregular fracture; massive cuttings habit; smooth to dull to earthy luster; very silty to somewhat gritty; thinner siltstone beds interbedded with thicker beds of sand and sandstone, and shale; no visible sample fluorescence was observed. 9370-9380 SAND = Clear to translucent to opaque, with some gray to medium dark gray, and white hues; mostly quartz grain sand matrix throughout with abundant dark colored lithic fragments; some sand grains appear to show signs of mechanical abrasion; lower very fine to upper medium, with some lower coarse; fair to poorly sorted; subangular to very angular; moderate to high sphericity; beds of sand interbedded with thin beds of sandstone and thinner beds of clayey to gritty siltstones and shale; no visible oil indicators was observed. 9380-9390 SHALE = Dark medium gray to dark gray to black; very firm to stiff to tacky; mostly brittle to somewhat dense; predominantly planar fracture; mass to slightly platy cuttings habit; resinous to slightly vitreous to greasy luster; mostly smooth with some slightly clayey; no visible sample fluorescence was observed. 9390-9400 SANDSTONE = Medium gray to light gray, with some white hues; quartz grain sand; sandstone is grain supported and very friable; lower very fine to up per medium; fair to poorly sorted; angular to subangular with some well-rounded to subrounded; moderate sphericity; thinner beds of sandstone interbedded with shale and thicker beds of clayey to somewhat gritty siltstone; no visible oil indicators were observed. 9400-9410 SILTSTONE = Gray to medium gray; clumpy to clotted to mushy; crumbly to crunchy and brittle; predominately irregular fracture; mostly massive cuttings habit, with some PDC buttercurl; dull to earthy to slightly resinous luster; very silty to slightly gritty; thicker siltstone beds interbedded with thicker beds of shale and thin lenses of laminated sandstone and sand; no visible sample fluorescence was observed. 9410-9420 SHALE = Black to gray to dark gray; mostly firm to slightly stiff to punky; tough to somewhat dense to brittle; planar fracture; massive to slightly platy cuttings habit; predominately resinous to vitreous luster; mostly some with some very clayey in places; thicker beds of shale, int erbedded with thicker beds of sandy siltstone and laminated very fine sand; no oil indicators were observed. MPC-15A 16 9420-9430 SAND = Mostly clear with some slightly translucent and opaque; quartz grain sand matrix; some sand grains show signs of mechanical abrasion; lower very fine to lower medium; f air to poorly sorted; subangular to very angular with some subrounded; moderate to high sphericity; thinner beds of sand interbedded with thick beds of clayey to gritty siltstone and shale; no visible sample fluorescence was observed. 9430-9440 SILTSTONE = Medium dark gray to dark gray; clumpy to pasty to lumpy; crunchy to crumbly; predominately irregular fracture; mostly massive cuttings habit, with PDC buttercurl; earthy to dull to somewhat greasy luster; very silty to somewhat gritty; thicker siltstone beds interbedded with thick beds of shale and thinner lenses of laminated sandstone and sand; no visible oil indicators were observed. 9440-9450 SHALE = Black to dark gray; predominately firm to stiff to tough; most dense to slightly brittle; planar fracture; massive to slightly platy cuttings habit; predominately resinous to vitreous luster; mostly smooth with some very clayey in places; thicker beds of shale, interbedded with thick beds of sandy siltstone and laminated very fine sand; no vis sample fluorescence was observed. 9450-9460 SANDSTONE = Light gray to medium gray, with some white and dark gray; predominately quartz grain sand matrix; sandstone is grain supported and very friable; lower very fine to upper medium; fair to well sorted; subangular to angular with some subrounded; moderate to high sphericity; thinner beds of sandstone interbedded with thicker beds of shale and somewhat gritty siltstone; no oil indicators were observed. 9460-9470 SHALE = Blackish gray to black; dense to firm to stiff; predominately dense to brittle; mostly planar fracture; platy cuttings habit; most vitreous to resinous luster; smooth with some slightly clayey; thicker beds of shale, interbedded with thicker beds of sandy siltstone and laminated very fine sand; no vis sample fluorescence was observed. 9470-9480 SILTSTONE = Dark gray to medium gray; clotted to lumpy to clumpy; crumbly to brittle; irregular fracture; mostly massive cuttings habit; mostly dull to earthy luster with some slightly waxy; very silty to gritty; thicker siltstone beds interbedded with thick beds of shale and thin lenses of laminated sandstone and sand; no visible sample fluorescence was observed. 9480-9490 SANDSTONE = Gray to light gray, with some grayish white; quartz grain sand matrix; sandstone is mostly grain supported and very friable; lower very fine to lower medium; fair to poorly sorted; angular to subangular with some well-rounded; moderately to high sphericity; thinner beds of sandstone interbedded with thick beds of shale and sandy si ltstone; some laminations of very fine sand throughout; no visible oil indicators were observed. 9490-9500 SHALE = Black to blackish gray; dense to stiff to firm; mostly dense with some brittle in places; planar fracture; platy cuttings habit; mostly vitreous to resinous luster; some with smooth slightly clayey; beds of shale interbedded with thicker beds of sandy siltstone and laminated very fine sand and sandstone; no visible sample fluorescence was observed. MPC-15A 17 9500-9510 SILTSTONE = Medium gray to medium dark gray; lumpy to clotted to clumpy; crunchy to brittle; irregular fracture; predominately massive cuttings habit; mostly dull to earthy luster; very silty to gritty; thicker siltstone beds interbedded with thick beds of shale and thinner beds of laminat ed sandstone and sand; no visible oil indicators were observed. 9510-9520 SAND = Translucent to clear; predominately quartz grain sand matrix; some sand grains show signs of mechanical abrasion; lower very finer to lower medium; fair to poorly sorted; ver y angular to subangular with some well-rounded; moderate to high sphericity; thinner beds of sand interbedded with thicker beds of clayey to gritty siltstone and shale; no visible sample fluorescence was observed. 9520-9530 SILTSTONE = Medium gray to dark gray; mushy to pasty to curdy; crumbly to crunchy to brittle; irregular fracture; predominately massive cuttings habit, with PDC buttercurl; mostly dull to earthy luster; very silty to gritty; thicker siltstone beds interbedded with thicker beds of shale and thin lenses of laminated sandstone and sand; no visible sample fluorescence was observed. 9530-9540 SANDSTONE = Dark gray to light gray, with some grayish white very pale green and pale green; mostly quartz grain sand; sandstone is mostly grain supported and very friable lower very fine to lower medium; fair to well sorted; subangular to angular with some well-rounded; moderate to high sphericity; thicker beds of sandstone interbedded with thin beds of shale and sandy siltstone; some laminations of very fine sand throughout; approximately 50% sample fluorescence; dull pale green fluorescence; delayed milky white solvent cut; fair to poor sample porosity. 9540-9550 SANDSTONE = Gray to light gray, with some grayish white very pale green and pale green h ues; predominately quartz grain sand matrix; very friable; lower very fine to lower medium; fair to well sorted; subangular to very angular with some very well rounded; moderate to high sphericity; thicker beds of sandstone interbedded with thinner beds of shale and sandy siltstone; some laminations of very fine sand throughout; trace glauconite; approximately 75% sample fluorescence; dull pale green sample fluorescence; delayed milky white solvent cut; fair to poor sample porosity. 9550-9560 SANDSTONE = Light gray to medium gray, with some grayish white very pale green and pale green hues; mostly quartz grain sand; very friable; lower very fine grain to lower medium grain; fair to well sorted; subangular to very angular with some well-rounded; moderate to high sphericity; thicker beds of sandstone interbedded with thin beds of shale and sandy siltstone; abundant laminations of very fine sand throughout; trace glauconite; approx. 30% sample fluorescence was observed; very dull pale green fluorescence; delayed milky white solvent cut; fair to poor sample porosity. 9560-9570 SANDSTONE = Dark gray to light gray, with some grayish white, very pale green and pale green hues; mostly quartz sand matrix; very friable; lower very fine grain to lower medium grain; fa ir to well sorted; angular to subangular with some well-rounded to subrounded; moderate to high sphericity; thinner beds of sandstone interbedded with thicker beds of shale and sandy siltstone; some laminated very fine sand throughout; trace glauconite; ap proximately 20% sample fluorescence; a very dull pale green sample fluorescence; delayed milky white solvent cut. MPC-15A 18 9570-9580 SHALE = Black to blackish gray; very dense to stiff to firm; dense to brittle to crumbly; planar fracture; platy cuttings habit; mostly vitreous to resinous luster; smooth to slightly clayey; beds of shale interbedded with thicker beds of sandy siltstone and laminations of very fine sand and sandstone; very faint sample fluorescence was observed, approximately 10%. 9580-9590 SHALE = Black to grayish black; predominately stiff to firm; dense to brittle to crumbly; planar fracture; platy cuttings habit; mostly vitreous to resinous luster; predominantly smooth with some slightly clayey; thicker beds of shale, interbedded with thinner beds of sandy siltstone very fine sand and sandstone; no visible sample fluorescence. 9590-9600 SILTSTONE = Medium gray to light gray; slightly stiff to mushy; crunchy to brittle; irregular fracture; predominately massive cuttings habit; mostly dull to earthy luster; very silty to slightly gritty; thicker siltstone beds interbedded with thicker beds of shale and thin lenses of laminated sandstone and sand; abundant carbonaceous material throughout sample; no visible sample fluorescence was observed. 9600-9610 Siltstone (9600-9610) = light gray to gray; stiff; crumbly to brittle; irregular fracture; mostly massive cuttings habit; earthy to dull luster; very silty to slightly gritty; thick siltstone beds interbedded with thin beds of shale and thin lens of laminated sandstone and sand; abundant carbonaceous material thru sample, no visible sample fluorescence was observed. 9610-9620 SHALE = Black; tacky to stiff to firm; very tough to dense to brittle in places; planar fracture; platy cuttings habit; mostly vitreous to resinous luster; smooth with some slightly very clayey; beds of shale interbedded with thick beds of sandy siltstone and laminated very fine sand and sandstone; abundant carbonaceous material throughout samp le; no visible sample fluorescence was observed. 9620-9630 KAOLINITIC SANDSTONE = Off white, white, light gray, common light to dark gray, black streaks and areas. Dominantly firm and crumbly semi friable to occasionally soft and moderately soluble. Very fine to occasional fine grained. Grains are angular to occasionally rounded and dominantly subrounded with moderate sphericity. Well to very well sorted with a high degree of feldspar alteration to kaolinite. The kaolinite is very calcareous reacting instantly and violently with HCl. Scattered quartz and trace mafics are present. Kaolin is dominantly in situ alteration with minor apparent mobile filing pore space as matrix; Trace glauconite, trace to scattered disseminated pyrite and traces of black carbonaceous debris are present. Non-cemented. Dominantly low porosity and permeability due to high kaolin content. Traces of glauconite are evident along with occasional glauconite stain. Minor stain from weathered micas. No odor, fluorescent pops, stain or free oil. 30% dull orange sample fluorescence. Occasional fast weak pale yellow cut fluorescence with a weak light orange residual cut fluorescence. 9630-9640 SHALE = Dark olive gray to dominantly olive black. Firm to occasionally moderately hard. Matte occasionally waxy to very fine sparkling luster. Smooth texture. Poor to common moderate fissility. Scattered parallel laminations. Occasional silt grading to siltstone. Trace to scattered black carbonaceous material. Rare glauconite. Minor disseminated pyrite, trace in crystal packets. No oil MPC-15A 19 9640-9650 SILTSTONE = Dominantly medium to dark olive gray, common olive black, scattered dusky yellow brown. Firm slightly tough to soft slightly hydrated. Dull to matte luster with scattered to common micro sparkles. Abrasive texture. Minor poor incipient fissility occasionally grading to poorly fissile shale. Trace to scattered black carbonaceous debris, dominantly small specs. Scattered disseminated pyrite, trace in packets. Trace small glauconite flakes. Scattered thin laminations, bedding. No oil indicators observed. 9650-9660 SANDSTONE = Minor amounts, kaolinitic. Overall off white to white, light gray. Very fine to occasional fine grained. Angular to occasional rounded, dominantly subangular with moderate sphericity. Scattered black, light to dark gray streaks. Kaolin is highly calcareous, occurs dominantly as in situ alteration but is also mobile filling pore space. Minor brown stain from mica alteration, weathering is present. Altered feldspar is the dominant composition. Scattered very fine quartz, tra ce mafics are also present. Traces of disseminated pyrite and black carbonaceous flecks are evident. No oil indicators are present. 9660-9670 SILTSTONE = Medium to dark brownish gray, olive gray, occasional dark to dusky yellow brown, olive black. Soft hydrated to occasionally firm crumbly. Smooth to dominantly abrasive texture. Occasional non to dominantly very calcareous. Trace to scattered disseminated pyrite, micro mica. Trace black carbonaceous material. Rare glauconite. Scattered laminations, interbeds, argillaceous to very finely sandy. Minor incipient fissility. No oil attributes. 9670-9680 SHALE = Dark olive gray to olive black. Firm to occasionally moderately hard. Smooth to occasional silty abrasive texture. Matte to very fine sparkling occasionally waxy luster. Flat tabular cuttings habit. Non to scattered very calcareous. Occasional moderate to dominantly poor fissility. Trace faint laminations. Variable silt content, clean to moderately silty. Scattered to common micro mica; Common disseminated, occasional pyrite packets. Trace to scattered black carbonaceous material. No oil attributes. 9680-9690 SILTSTONE = Medium to dark grayish brown, brownish gray, olive gray, occasional olive black. Soft hydrated mushy sectile to firm crumbly. Dominantly abrasive texture. Dominantly very calcareous. Trace to scattered disseminated pyrite, micro mica. Trace to scattered black carbonaceous material. Scattered to dominantly trace glauconite. Occasional evident laminations, interbeds, argillaceous to very finely sandy grading to very fine grained dirty matrix supported sandstone. No oil indicators. 9690-9700 SHALE = Olive black to dark olive Gray. Firm to occasionally moderately hard slightly tough. Dominantly smooth texture. Dull occasionally waxy to very fine sparkling luster. Tabular cuttings habit. Non to moderately calcareous. Moderate to dominantly poor fissility. Rare faint laminations. Traces of silt. Scattered to dominantly rare micro mica; Scattered disseminated, Trace crystalline pyrite patches. Scattered black carbonaceous material. No oil indicators were observed. 9700-9710 SILTSTONE = Dominantly dark, grayish brown, brownish gray, olive gray. Soft hydrated sectile to firm crumbly. Abrasive texture. Moderate to very calcareous. Common to scattered disseminated pyrite, micro mica. Scattered black carbonaceous debris. rare glauconite. Trace laminations, interbeds, scattered very fine sand grading to very fine grained dirty sandstone. No oil indicators are present. MPC-15A 20 9710-9720 KAOLINITIC SANDSTONE = White, off white, common gray, occasional black streaks, areas. Very fine to medium grained. Angular to scattered rounded, dominantly subangular with moderate sphericity. Well sorted. High degree kaolinitic alteration feldspar filling pore space. Low overal l porosity and permeability. Dominantly altered feldspar with clear to cloudy quartz, trace mafics and lithic fragments. No evident structure present. Occasional organic debris. Trace glauconite and disseminated pyrite. Kaolin is very calcareous. 20% slightly moderate yellow to dull orange sample fluorescence. Fast streaming, slow diffuse weak to moderate pale to milky yellow cut fluorescence. Clear visible cut. Moderate light yellow residual cut fluorescence. No oil indicators in mud. 9720-9730 KAOLINITIC SANDSTONE = Overall white, off white, common grayish mottling, occasional black streaks, areas. Very fine to medium grained. Angular to scattered rounded, dominantly subangular Moderate to poor sphericity. Well sorted. Kaolinitic alterated feldspar filling pore space. Low porosity and permeability. Dominantly feldspar with clear, cloudy quartz, trace mafics. Occasional black carbonaceous material. Trace glauconite. Scattered disseminated pyrite. Kaolin is very calcareous. 400% moderate yellow sample fluorescence. Fast weak pale yellow, slow diffuse moderate milky yellow cut fluorescence. Clear visible cut. Moderate light yellow residual cut fluorescence. No odor, sheen, fluorescent pops or free oil. 9730-9740 KAOLINITIC SANDSTONE = White, off white, scattered gray, common black streaks, areas. Very fine to trace medium grained. Angular to rounded, dominantly subangular with dominantly moderate, occasional poor sphericity. Well sorted. High degree kaolinitic alteration of feldspar. Low porosity and permeability. Dominantly altered feldspar with clear to cloudy quartz, trace mafics, occasionally altered. Common argillaceous, occasionally silty irregular thin interbeds, laminations are present. Common organic debris. Trace disseminated pyrite. Kaolin is very calcareous. 30% slightly moderate yellow sample fluorescence. Fast streaming, slow to moderate milky yellow cut fluorescence. Clear visible cut. Moderate light yellow residual cut fluorescence. No oil indicators in mud. No visible stain. 9740-9750 KAOLINITIC SANDSTONE = Dominantly white, off white, occasional grayish mottling, common black streaks, areas. Very fine to fine grained. Dominantly angular to occasionally rounded, dominantly subangular and moderately spherical. Well to very well sorted. High degree of feldspar alteration to kaolinite. Low apparent porosity and permeability. Dominantly altered feldspar with clear to cloudy quartz, trace mafics. Scattered argillaceous to silty interbeds, irregular, lenticular. Common black organic debris. Rare glauconite. Trace disseminated pyrite. Kaolin highly calcareous. 20% slightly moderate yellow to dull orange sample fluorescence. Fast weak pale yellow, slow to moderate milky cut fluorescence. No visible cut. Moderate light yellow residual cut fluorescence. No visible stain. 9750-9760 KAOLINITIC SANDSTONE = White, off white, occasional gray mottling and common black streaks. Very fine to occasional fine grained. Angular to common rounded, dominantly subangular. Poor to moderate sphericity. Well to very well sorted. Abundant kaolinitic alteration of feldspar filling pore space. Low overall porosity and permeability. Dominantly altered feldspar with clear to cloudy occasional white opaque quartz, trace to scattered mafics. Scattered thin bedding structure pr esent. Scattered black organic debris. Trace disseminated pyrite. Kaolin is very calcareous. 10% slightly moderate yellow sample fluorescence. Slow diffuse weak to moderate pale to milky yellow cut fluorescence. Clear visible cut. Moderate light yellow residual cut fluorescence. No oil indicators in mud. No visible stain. MPC-15A 21 9760-9770 SILTSTONE = Medium to dark olive gray, occasional olive black. Soft hydrated mushy sectile to firm crumbly. Abrasive texture. Very to moderately calcareous. Trace to scattered disseminated pyrite, micro mica. Trace sand size mica flakes. Scattered black carbonaceous material. Scattered evident laminations, interbeds, argillaceous to very finely sandy grading to very fine grained dirty matrix supported sandstone. Occasional white calcareous, kaolinitic? interbeds. No oil indicators associated with siltstone. Trace sample fluorescence and weak cuts from sandstone. 9770-9780 KAOLINITIC SANDSTONE = Dominantly white, off white, occasional grayish mottling, black streaks. Very fine to medium grained. Dominantly angular to occasional rounded, dominantly subangular and moderately spherical. Well sorted. High degree of feldspar alteration to kaolinite. Low apparent porosity and permeability. Dominantly altered feldspar with clear to cloudy quartz, trace mafics. Rare argillaceous interbeds, irregular. Scattered black organic debris. Trace disseminated pyrite. Kaolin highly calcareous. 20% slightly moderate yellow sample fluorescence. Fast weak pale yellow, slow to moderate milky cut fluorescence. No visible cut. Moderate light yellow residual cut fluorescence. No oil in mud. No visible stain. 9780-9790 SILTSTONE = Medium to dark olive gray, scattered brownish hues with common off white, white thin laminations. Soft hydrated mushy sectile to firm crumbly. Abrasive texture. Very to moderately calcareous. Scattered disseminated pyrite, micro mica. Common black carbonaceous debris. Common evident laminations, interbeds, argillaceous, kaolinitic to very finely sandy grading to dirty matrix supported sandstone. No associated oil indicators. Sandstone exhibits Trace sample fluorescence and weak cuts. 9790-9800 SHALE = Dark olive black, olive gray. Occasional dark gray. Firm to slightly moderately hard. Matte to occasionally waxy luster with variable micro sparkle. Smooth texture. Non to moderately calcareous. Poor incipient to occasional moderate flaky fissility. Occasionally silty. Scattered micro mica, disseminated pyrite. Trace glauconite. No associated oil attributes. 9800-9810 SILTSTONE = Medium to dark olive gray, scattered dark yellowish brown. Soft hydrated mushy sectile to common firm crumbly. Abrasive texture. Moderately calcareous. Scattered disseminated pyrite, micro mica, black organic material. Occasional thin discontinuous laminations, interbeds. No associated oil indicators. Trace sample fluorescence and weak cuts confined to sands. 9810-9820 SANDSTONE = Dominantly loose, disaggregated. Overall light to medium gray. Individual grains clear, cloudy, transparent light gray, opaque white, dark to medium gray, trace black. Very fine to occasional coarse grained with traces of granules, dominantly very fine to medium. Grains are dominantly angular to subangular with trace well rounded granules with poor to occasional good sphericity. Minor white kaolin alteration is present. Dominantly quartz with scattered feldspar, trace mafics and lithic fragments. Rare glauconite and pyrite. Non-cemented. Grain packed, grain support with little or no matrix; Good apparent porosity and permeability. Minor in terbedded shale and siltstone. No evident structures present. 30% moderate yellow sample fluorescence. Fast weak, slow to moderate milky cut fluorescence. No oil indicators in mud. No odor or visible stain. MPC-15A 22 9820-9830 SANDSTONE = Loose, bit disaggregated. Overall gray. Individual grains dominantly clear, cloudy, transparent light gray, occasional opaque white, dark to medium gray, trace black. Very fine to occasional coarse grained. Dominantly fine to medium. Grains are dominantly angular to subangular with trace well rounded with poor to good sphericity. Scattered white kaolin alteration is evident. Dominantly quartz with scattered feldspar, trace mafics and lithic fragments. Rare pyrite. Loose unconsolidated grain support no apparent matrix; Good apparent porosity and permeability. No evident structures present. 40% moderate yellow sample fluorescence. Fast weak pale yellow, slow diffuse moderate milky cut fluorescence. No odor, visible stain, sheen or free oil in mud. 9830-9840 SANDSTONE = Dominantly loose, non-cemented. Overall light to medium gray. Individual grains dominantly clear, cloudy, scattered transparent light gray, opaque white, dark to medium gray, trace black. Very fine to occasional coarse grained with scattered lithic granules, dominantly fi ne to medium. Grains are dominantly angular to subangular with trace well rounded clasts Dominantly poor to occasional good sphericity is present. Trace white kaolin alteration. Dominantly quartz with scattered feldspar, trace mafics and dark gray lithic fragments. Little or no apparent matrix; Grain support. Moderate to poorly sorted. Good to moderate apparent porosity and permeability. Minor interbedded mud rocks. No evident structures present. 30% moderate yellow sample fluorescence. Fast weak, slow to moderate milky cut fluorescence. No oil indicators 9840-9850 SILTSTONE = Medium to dark olive gray, occasional brownish hues. Soft hydrated sectile to firm crumbly. Abrasive texture. Dull luster with variable micro sparkle. Moderately calcareous. Trace to scattered disseminated pyrite, micro mica. Scattered black organic debris. No oil indicators associated with siltstone. Sample fluorescence and cuts from sandstone. 9850-9860 SHALE = Olive black to dark olive gray. Firm to slightly moderately hard. Matte to waxy luster with variable micro sparkle. Smooth texture. Non to moderately calcareous. Poor to moderate fissility. Non- laminated. Minor silt. Scattered micro mica, disseminated pyrite. Trace glauconite. No associated oil attributes. 9860-9870 SANDSTONE = Granular, increasingly coarse. Dominantly loose, disaggregated. Overall light to medium gray. Individual grains dominantly clear, cloudy, common transparent light gray, opaque white, dark to medium gray, black, scattered orangish, trace dark blue, green. Very fine to occasional very coarse grained with scattered granules, dominantly medium. Grains are dominantly angular to subangular with trace well rounded granules with poor to occasional good sphericity. Minor white kaolin alteration is present. Dominantly quartz with scattered feldspar, scattered mafics and dark rounded to well-rounded lithic fragments. Rare glauconite and pyrite. Non-cemented. Apparent grain packed, grain support. No apparent matrix present; Good apparent porosity and permeability. Minor interbedded shale and siltstone. No evident structures present. 40% moderate yellow sample fluorescence. Fast weak pale yellow , slow diffuse to moderate milky cut fluorescence. No oil indicators in mud. No odor or MPC-15A 23 9870-9880 SANDSTONE = Dominantly loose, unconsolidated, disaggregated. Overall light to medium gray. Individual grains dominantly cloudy transparent to opaque white, milky, common clear, transparent light gray, dark to medium gray, black, scattered orangish. Trace rusty brownish stain, hematit e? Limonite? Very fine to occasional very coarse grained with trace scattered granules, dominantly medium. Dominantly angular to subangular with trace well rounded granules. Poor to occasional good dominantly moderate sphericity. Minor but increasing white kaolin alteration is present. Dominantly quartz with scattered feldspar, scattered mafics and dark rounded to well-rounded lithic fragments. Non-cemented. Grain support with no apparent matrix. Good apparent porosity and permeability. No evident structures present. 30% weak to moderate yellow sample fluorescence. Fast streaming weak , slow diffuse moderate milky cut fluorescence. No stain or oil indicators in mud. 9880-9890 SANDSTONE = Dominantly loose, unconsolidated. Individual grains dominantly cloudy, transparent to opaque white, milky, common clear, transparent light gray, dark to medium gray, black. Increasing kaolin altered grains and rusty brownish stain, hematite? Limonite? Very fine to occasional very coarse grained with rare granules, dominantly medium with increasing fine. Dominantly angular to subangular with trace well rounded. Poor to occasional good dominantly moderate sphericity. Dominantly quartz with abundant feldspar, scattered dark mafics and trace lithic fragments. Non - cemented. No apparent matrix. Good to moderate apparent porosity and permeability. No evident structures present. 20% weak to moderate yellow sample fluorescence. Fast weak , slow to moderate milky cut fluorescence. No stain, odor, free oil, sheen or fluorescent pops. 9890-9900 SANDSTONE = Dominantly loose, unconsolidated, non-cemented, scattered competent cuttings and increasing kaolin alteration. Increasing rusty stain on grains and kaolin. Individual grains dominantly cloudy, transparent to opaque white, milky, scattered clear, transparent light gray, dark to medium gray, black. Very fine to occasional coarse grained, dominantly medium to fine. Dominantly angular to subangular, Poor to occasional good, dominantly moderate sphericity. Dominantly quartz with increasingly abundant feldspar, scattered dark mafics and trace lithic fragments. No apparent clay or silt matrix. Low to moderate apparent porosity and permeability. No evident structures present. 20% weak to moderate yellow sample fluorescence. Slow moderate milky slightly yellow cut fluorescence. No oil attributes in mud. No visible stain. 9900-9910 SANDSTONE = Dominantly loose, non-cemented. Overall light brown from increasing rusty stain on grains and kaolin. Individual grains dominantly clear, cloudy, common transparent to opaque white, milky, transparent light gray, scattered dark to medium gray, black. Very fine to trace coarse grained, dominantly medium to fine. Dominantly angular to subangular with minor to rounded, Dominantly poor to occasional good, sphericity. Moderate to well sorted. Dominantly quartz with increasingly abundant feldspar and increasing kaolin altered grains. Scattered mafics and lithic fragments. No apparent matrix. Low to moderate apparent porosity and permeability. 10% weak to moderate yellow sample fluorescence. Fast weak pale yellow wispy, slow to slightly moderate milky slightly yellow cut fluorescence. No visible stain. MPC-15A 24 9910-9920 TUFF = Trace amounts. Pale green, whitish green. Firm. Waxy luster. Smooth texture. Moderate yellow mineral fluorescence. 9920-9928 SANDSTONE = Overall Off white, light brown from rusty stain and common kaolin. Individual grains dominantly clear, cloudy, common transparent to opaque white, milky, transparent light gray, scattered dark to medium gray, black. Very fine to trace coarse grained, dominantly medium to fine. Dominantly angular to subangular. Dominantly poor to moderate sphericity. Moderate to well sorted. Dominantly quartz with increasingly feldspar. Scattered. No apparent matrix. Low apparent porosity and permeability. No oil indicators present. 3.3 Mudlog Summary Formation / Marker Depth Drill rate (ft/hr) Total Gas (units) MD SSTVD Max Min Avg Max Min Avg KUPARAK Top Not Seen ‘------ 251 8 43 12 0.1 1.2 MP_KNG_TJF 7949 -7540 112 10.6 53.3 11 0.4 3.5 MP_KNG_TJE 8180 -7751 79 2.5 32.6 13 2.5 6.7 MP_KNG_TJD 8610 -8109 85.3 6 31 22 7.5 8.4 MP_KNG_TJC 9052 -8468 67.4 4.2 22.6 20 2.2 7.6 MP_KNG_TJB 9279 -8652 74.2 13.4 35.2 18 4 10.8 MP_KNG_TJA 9424 -8772 83.6 20.3 50.5 25 11.8 19.3 MP_SGR_SGD 9501 -8837 57.3 17.6 41.2 15 13 19.8 MP_SGR_SGC 9524 -8856 68.6 19.8 42.4 34 20.7 26.5 MP_SGR_SGB 9538 -8868 56.9 19 42.8 72 21 41.4 MP_SGR_SGA 9574 -8898 76.2 30.5 46.7 36 13.8 21.8 MP_TSHU 9595 -8916 80.9 12.3 41.6 222 9.1 33.1 MP_TEIL 9794 -9084 62.8 31 47.3 54 10.2 29.1 MP_TSAD 9856 -9137 71 19.6 39.2 36 6.2 14.3 MPC-15A 25 3.4 Connection Gases MPC-15A 26 3.5 Sampling Program / Sample Dispatch From 7657’ to 9300’ 2 set of samples were collected and saved as washed and dried in 30’ intervals. From 9300’ to to 9928’ in 10’ intervals 2 sets of washed and dried and 2 sets of unwashed wet were collected. Set Type and Purpose Interval Frequency Distribution A Washed and Dried Reference 7657’-9300’’ 9300’-9928’ 30’ 10’ Daniel Yancy Hilcorp Alaska LLC 3800 Center Point Drive, Suite 1400 Anchorage, AK 99503 B Washed and Dried Reference 7657’-9300’’ 9300’-9928’ 30’ 10’ AOGCC 333 W 7th Ave #100 Anchorage, AK 99501 All samples were given to the rig expediter for delivery. MPC-15A 27 4 DRILLING DATA 4.1 Survey Data Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (ft) Dogleg Rate (o/100ft) 33.64 0 0 33.64 0 0 0 0 98.34 0.42 197.69 98.34 -0.23 -0.07 0.24 0.65 198.34 0.47 225.3 198.34 -0.86 -0.47 0.97 0.22 298.34 0.55 187.1 298.33 -1.63 -0.83 1.81 0.34 398.34 0.55 249.8 398.33 -2.27 -1.34 2.59 0.57 498.34 0.42 255.6 498.33 -2.53 -2.14 3.11 0.14 598.34 0.3 267.39 598.32 -2.63 -2.76 3.41 0.14 698.34 0.25 303.7 698.32 -2.52 -3.2 3.46 0.18 798.34 0.22 157 798.32 -2.58 -3.31 3.55 0.45 898.34 0.05 75.39 898.32 -2.74 -3.19 3.67 0.22 998.34 0.37 337.4 998.32 -2.43 -3.27 3.41 0.38 1098.34 0.18 317.7 1098.32 -2.02 -3.5 3.1 0.21 1198.34 0.23 264.89 1198.32 -1.92 -3.81 3.11 0.19 1298.34 0.22 265.19 1298.32 -1.95 -4.2 3.27 0.01 1398.34 0.05 200.8 1398.32 -2.01 -4.41 3.4 0.2 1498.34 0.18 292.7 1498.32 -1.99 -4.57 3.43 0.19 1598.34 0.22 282.11 1598.32 -1.89 -4.9 3.45 0.05 1698.34 0.15 301 1698.32 -1.78 -5.2 3.45 0.09 1798.34 0.17 112.61 1798.32 -1.77 -5.17 3.44 0.32 1898.34 0.07 328.5 1898.32 -1.78 -5.07 3.4 0.23 1998.34 0.18 199.19 1998.32 -1.87 -5.15 3.52 0.23 2098.34 0.22 196.1 2098.32 -2.21 -5.26 3.87 0.04 2198.34 0.25 166.5 2198.32 -2.6 -5.26 4.25 0.12 2298.34 0.15 61.3 2298.32 -2.75 -5.09 4.33 0.32 2398.34 0.27 66.3 2398.32 -2.6 -4.76 4.07 0.12 2498.34 0 312.7 2498.32 -2.5 -4.55 3.9 0.27 2598.34 0.12 169.11 2598.32 -2.6 -4.53 3.99 0.12 2698.34 0.17 110.7 2698.32 -2.76 -4.37 4.09 0.15 2798.34 0.32 76.19 2798.32 -2.74 -3.96 3.93 0.2 2898.35 0.77 204.5 2898.32 -3.29 -3.97 4.45 1 2998.35 0.28 277.11 2998.31 -3.87 -4.49 5.17 0.74 3098.35 0.57 122.61 3098.31 -4.11 -4.31 5.33 0.83 3198.35 2.65 115 3198.27 -5.35 -1.8 5.65 2.09 3298.35 5.3 107.5 3298.02 -7.72 4.7 5.65 2.69 3398.35 7.77 93.2 3397.37 -9.49 15.86 3.49 2.94 3498.35 10.25 91.11 3496.13 -10.04 31.51 -1.35 2.5 3598.35 12.68 99.2 3594.13 -11.96 51.24 -6.28 2.91 3698.35 15.68 101.81 3691.07 -16.49 75.31 -10.27 3.07 3798.35 18.43 107.4 3786.67 -23.98 103.63 -12.91 3.2 MPC-15A 28 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (ft) Dogleg Rate (o/100ft) 3898.35 21.22 106.61 3880.74 -33.88 136.06 -14.7 2.8 3998.35 23.12 99.81 3973.35 -42.4 172.76 -19.24 3.19 4098.35 25.97 98.31 4064.31 -48.91 213.78 -27.15 2.92 4198.35 28.38 99.81 4153.27 -56.13 258.87 -35.79 2.51 4298.35 28.97 100.7 4241 -64.67 306.08 -43.91 0.73 4398.35 29.12 101.31 4328.43 -73.94 353.74 -51.5 0.33 4498.35 29.12 102.11 4415.79 -83.82 401.39 -58.52 0.39 4598.35 29.37 102.61 4503.04 -94.28 449.11 -65.01 0.35 4698.35 29.47 102.2 4590.15 -104.83 497.09 -71.51 0.22 4798.35 30.12 103 4676.93 -115.67 545.58 -77.9 0.76 4898.35 28.57 101.31 4764.09 -126.01 593.48 -84.57 1.76 4998.35 27.73 100.7 4852.27 -135.02 639.79 -91.95 0.89 5098.35 26.8 104.7 4941.16 -145.06 684.46 -97.79 2.05 5198.35 25.63 104.9 5030.87 -156.34 727.17 -101.79 1.17 5298.35 24.48 107.11 5121.47 -168 767.87 -104.76 1.48 5398.35 23.97 103.61 5212.66 -178.87 807.42 -108.07 1.52 5498.35 24.3 102 5303.92 -187.93 847.29 -113.19 0.74 5598.35 22.33 100.4 5395.75 -195.64 886.1 -119.22 2.07 5698.35 21.98 101.11 5488.37 -202.67 923.15 -125.28 0.44 5798.35 22.3 101.2 5581 -209.97 960.13 -131.08 0.32 5898.35 22.72 101.11 5673.38 -217.37 997.69 -136.97 0.42 5998.35 22.88 101.4 5765.57 -224.94 1035.69 -142.86 0.2 6098.35 22.82 101.61 5857.72 -232.68 1073.74 -148.59 0.1 6198.35 23.13 99.81 5949.79 -239.93 1112.09 -154.9 0.77 6298.35 23.12 100.81 6041.75 -246.96 1150.73 -161.51 0.39 6398.35 22.68 101.7 6133.87 -254.55 1188.9 -167.43 0.56 6498.35 22.32 101.31 6226.26 -262.18 1226.4 -173.08 0.39 6598.35 22.15 101.11 6318.82 -269.54 1263.51 -178.86 0.19 6698.35 21.65 101.2 6411.61 -276.76 1300.11 -184.6 0.5 6798.35 21.5 100.31 6504.6 -283.62 1336.23 -190.5 0.36 6898.35 21.1 100.7 6597.77 -290.24 1371.95 -196.5 0.42 6998.35 20.77 100.7 6691.17 -296.87 1407.06 -202.27 0.33 7098.35 20.8 100.7 6784.66 -303.46 1441.93 -208.01 0.03 7198.35 20.87 100.61 6878.12 -310.04 1476.88 -213.78 0.08 7298.35 20.28 100.2 6971.74 -316.39 1511.45 -219.64 0.61 7398.35 18.95 98.9 7065.94 -321.97 1544.55 -225.71 1.4 7498.35 17.9 99.7 7160.81 -327.07 1575.74 -231.59 1.08 7528.35 17.47 98.7 7189.39 -328.53 1584.73 -233.29 1.75 7666.79 16.08 96.22 7321.93 -333.75 1624.33 -241.93 1.13 7760.12 17.66 114.1 7411.31 -340.94 1650.13 -244 5.79 7856.17 19.12 128.23 7502.49 -356.63 1675.79 -238.04 4.87 7946.5 19.97 140.76 7587.76 -377.69 1696.86 -225.45 4.72 8040.98 22.81 157.17 7675.8 -407.1 1714.19 -203.74 6.98 MPC-15A 29 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (ft) Dogleg Rate (o/100ft) 8134.29 25.05 167.37 7761.13 -443.07 1725.53 -173.82 5.04 8229.68 29.57 172.2 7845.86 -486.12 1733.15 -135.97 5.27 8323.31 32.93 175.56 7925.91 -534.4 1738.25 -92.34 4.04 8418.3 35.63 178.36 8004.39 -587.81 1741.05 -43.11 3.29 8512.63 35.8 178.03 8080.98 -642.86 1742.78 8.03 0.27 8607.61 35.84 177.37 8157.99 -698.4 1745.01 59.45 0.41 8700.58 35.53 176.76 8233.51 -752.56 1747.79 109.4 0.51 8793.74 36.2 179.51 8309 -807.1 1749.55 160.04 1.87 8887.51 36.81 178.96 8384.38 -862.88 1750.3 212.2 0.74 8982.88 34.51 180.16 8461.87 -918.46 1750.74 264.28 2.52 9077.37 35.63 179.78 8539.2 -972.75 1750.77 315.29 1.21 9171.33 35.72 177.03 8615.54 -1027.52 1752.3 366.23 1.71 9266.47 36.31 177.91 8692.48 -1083.4 1754.77 417.9 0.83 9359.29 34.39 183.32 8768.21 -1137.06 1754.25 468.5 3.96 9452.94 32.11 184.72 8846.52 -1188.28 1750.67 517.85 2.57 9548 32.1 180.64 8927.05 -1238.72 1748.31 566.06 2.28 9641.91 33.17 179.42 9006.13 -1289.36 1748.29 613.65 1.34 9736.13 32.11 180.97 9085.47 -1340.18 1748.13 661.46 1.43 9830.15 30.55 180.94 9165.78 -1389.05 1747.31 707.67 1.66 9896.03 30.78 182.37 9222.45 -1422.64 1746.34 739.56 1.16 PROJECTED TD 9928 30.78 182.37 9249.92 -1438.99 1745.66 755.15 0 MPC-15A 30 4.2 Bit Record Bit Size Make Type / Serial Number Jets / TFA Depth In MD / Total Footage Bit Hrs Avg. ROP (ft/hr) WOB (Klbs) RPM PP (psi) Wear BHA NB 1 6 1/8” HOV PDC SKH159S A213805 5x11 0.4638 7657 259 8.5 45.8 7 54 1910 0-0-NO-A-X-In-NO- PR Motor NB 2 6 1/8” HDBS PDC MM64D 12603023 6x10 0.4602 7916 1278’ 48.76 20.2 10.39 89 2351 0-0-NO-A-X-In-PN-PR Motor NB 3 6 1/8” SMITH PDC Z513 JM1381 5x11 0.4638 9194 734’ 20.77 40.4 10.4 95 2626 1-1-WT-A-X-In-LT-TD Motor MPC-15A 31 4.3 Mud Record Contractor: Halliburton Date Depth MW (ppg) ECD (ppg) VIS (s/qt) PV YP Gels FL (cc) FC Sols (%) NAP/ Water Sd (%) pH Cl (ml/l) FLT 3% KCl LSND 6/19/16 7657 10.5 11.55 42 6 24 5/7/9 4.0 1 8.1 0/90.6 0.05 10.5 16000 6/19/16 7687 10.55 11.55 42 8 17 5/7/9 4.1 1 8.3 0/90.4 0.05 11.0 16000 6/20/16 7911 10.5 11.5 43 10 19 7/8/9 3.6 1 8.2 0.8/90 0.1 10.1 15000 88 6/20/16 7917 10.5 11.5 43 10 19 6/8/10 3.4 1 8.2 0.8/89.8 0.1 10.7 15000 6/21/16 8012 10.5 11.43 41 9 18 4/5/7 3.2 1 8.6 0.2/90.0 0.1 10.5 15000 88 6/21/16 8356 10.5 11.43 42 11 20 6/8/12 3.6 1 8.5 0.1/90.1 0.1 9.2 17000 92 6/22/16 8730 10.5 11.48 39 9 19 5/6/8 4.0 1 8.7 0.2/89.9 0.1 9.4 15000 98 6/22/16 8924 10.55 11.48 39 10 18 5/7/11 4.3 1 9.3 0.1/89.5 0.05 9.4 14000 98 6/23/16 9129 10.5 11.5 40 10 23 7/11/14 4.8 1 8.8 0.0/90.0 0.05 9.5 15000 101 6/23/16 9194 10.55 11.5 41 9 21 6/10/15 4.4 1 8.9 0.0/89.9 0.05 9.3 16000 6/24/16 9338 10.6 11.59 39 9 20 5/7/10 4.8 1 8.6 0.2/90.0 0.05 9.5 15000 98 6/24/16 9786 10.55 11.59 38 9 18 4/7/13 5.0 1 8.6 0.2/89.9 0.05 9.8 16000 100 6/25/16 9928 11.0 37 8 21 4/7/11 5.0 1 10.1 0.8/88.0 0.05 8.9 15000 Abbreviations MW = Mud Weight Gels = Gel Strength Sd = Sand content ECD = Effective Circulating Density FL = Water or Filtrate Loss Cl = Chlorides VIS = Funnel Viscosity FC = Filter Cake Ca = Hardness Calcium PV = Plastic Viscosity Sols = Solids O/W = Oil to Water ratio YP = Yield Point MPC-15A 32 4.4 Drilling Progress Chart 33 5 SHOW REPORTS 34 35 36 37 6 DAILY REPORTS 38 39 40 41 42 43 44
