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Home My WebLink About216-120MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, April 1, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC J-24A MILNE PT UNIT J-24A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/01/2025 J-24A 50-029-22976-01-00 216-120-0 W SPT 3537 2161200 1500 463 466 464 461 4YRTST P Kam StJohn 2/22/2025 4 Year MIT-IA Monobore 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT J-24A Inspection Date: Tubing OA Packer Depth 235 1765 1707 1700IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS250222111423 BBL Pumped:1 BBL Returned:1 Tuesday, April 1, 2025 Page 1 of 1 9 9 9 9 9 9 9 999 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.04.01 12:14:55 -08'00' David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 07/13/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type MPU L-06 50029220030000 190010 5/26/21 Caliper Survey MPU J-23A 50029229700100 215154 7/3/21 Injection Profile MPU E-12 50029232620000 205067 6/26/2021 Coil Flag MPU J-24A 50029229760100 216120 7/4/21 Injection Profile Please include current contact information if different from above. eived By: 07/13/2021 37' (6HW By Abby Bell at 3:30 pm, Jul 13, 2021 MEMORANDUM TO: Jim Regg P.P.I. Supperveisor i7.C�l/[� Z�Z'i l FROM: Adam Earl Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, February 23, 2021 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC J -24A MILNE PT UNIT 1-24A Src: Inspector Reviewed By: P.I. Sup" JT3F-- Comm Well Name MILNE PT UNIT J -24A API Well Number 50-029-22976-01-00 Inspector Name: Adam Earl Permit Number: 216-120-0 Inspection Date: 2/16/2021 _ IBsp Num: mitAGE210221074603 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well J -24A Type Inj W TVD 7537 - Tubing 775 780 779 781 PTD 1 2161200 IType Test I SPT Test psi 1506 IA za6 1750 1700 1698 . BBL Pumped: I BBL Returned: I OA Interval F 4YRTST PIF P ✓ Notes: MONO BORE INJ. MIT -IA Tuesday, February 23, 2021 Page 1 of I • • 21 61 20 Seth Nolan Hilcorp Alaska, LLC 2 8 4 7 9 GeoTech 3800 Centerpoint Drive, Suite 100 ��'�� Anchorage, AK 99503 Tele: 907 777-8308 Hilrnrp Alaeko,I.1.t: Fax: 907 777-8510 AUG 0 9 2017 E-mail: snolan@hilcorp.com DATA LOGGED S n5/2o17 M.K.BENDER DATE 08/09/17 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU 3-24A SCANNED Pic, 1 8 2 0 Prints: GR/CCL/PRES/TEMP/SPIN CD 1: Hilcorp MPJ-24A_IPROF 25111_17 FINAL 7/31/2017 5:42 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: �� 6,„..eat Date: • ! MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday,March 07,2017 TO: Jim Regg P.I.Supervisor h(i-ti 31 Z((7 SUBJECT:Mechanical Integrity Tests HILCORP ALASKA LLC J-24A FROM: Brian Bixby MILNE PT UNIT J-24A Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry 3L--- NON-CONFIDENTIAL Comm Well Name MILNE PT UNIT J-24A API Well Number 50-029-22976-01-00 Inspector Name: Brian Bixby Permit Number: 216-120-0 Inspection Date: 2/28/2017 Insp Num: mitBDB170228172307 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well J-24A ' Type Inj W' TVD 3537 - Tubing 711 711 705 , 703 — PTD 2161200 ' Type Test SPT Test psi 1500 IA 528 1800 - 1758 • 1747 - BBL Pumped: 0.9 BBL Returned: 0.9 OA Interval INITAL P/F P ✓ Notes: Monobore Well,there is no OA SCANNED M A,v 0 , Tuesday,March 07,2017 Page 1 of 1 DATA SUBMITTAL COMPLIANCE REPORT 4/7/2017 Permit to Drill 2161200 Well Name/No. MILNE PT UNIT J -24A Operator HILCORP ALASKA LLC API No. 50-029-22976-01-00 MD 13402 TVD 3602 Completion Date 1/4/2017 Completion Status 1WINJ Current Status 1WINJ UIC No REQUIRED INFORMATION / Mud Log No ✓ Samples No ✓ Directional Survey Yes V /11 DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name ED C 27914 Digital Data ROP -GM -ADR -Horizontal Pres 2in MD, GM-ADR-inverted/reverted inte (data taken from Logs Portion of Master Well Data Maint) ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data ED C 27914 Digital Data Log C 27914 Log Header Scans Well Cores/Samples Information: Name Log Log Run Interval OH/ Scale Media No Start Stop CH Received Comments 7540 13402 1/12/2017 Electronic Data Set, Filename: MPU J- 24A_GM_ADR.las 1/12/2017 Electronic File: MPU J-24A_GM_ADR MD.cgm 1/12/2017 Electronic File: MPU J-24A_GM_ADR TVD.cgm 1/12/2017 Electronic File: MPJ -24A - Definitive Survey.pdf ' 1/12/2017 Electronic File: MPJ -24A - Definitive Surveys.txt ' 1/12/2017 Electronic File: MPU J -24A GM ADR MD.emf ' 1/12/2017 Electronic File: MPU J -24A GM ADR TVD.emf 1/12/2017 Electronic File: MPU J -24A GM ADR.dlis - 1/12/2017 Electronic File: MPU J -24A GM ADR.ver' 1/12/2017 Electronic File: MPU J -24A Geosteering.dlis . 1/12/2017 Electronic File: MPU J -24A Geosteering.ver pl/12/2017 Electronic File: MPU J-24A_GM_ADR MD.pdf . (� 1/12/2017 Electronic File: MPU J-24A_GM_ADR TVD.pdf 1/12/2017 Electronic File: MPU J -24A GM ADR MD.tif 1/12/2017 Electronic File: MPU J -24A GM ADR TVD.tif ' 0 0 2161200 MILNE PT UNIT J -24A LOG HEADERS Sample Interval Set Start Stop Sent Received Number Comments AOGCC Page 1 of Friday, April 7, 2017 DATA SUBMITTAL COMPLIANCE REPORT 4/7/2017 Permit to Drill 2161200 Well Name/No. MILNE PT UNIT J -24A Operator HILCORP ALASKA LLC API No. 50-029-22976-01-00 MD 13402 TVD 3602 Completion Date 1/4/2017 Completion Status 1WINJ Current Status 1WINJ UIC No INFORMATION RECEIVED Completion Report Directional / Inclination Data Mud Logs, Image Files, Digital Data Y f& Core Chips Y / f A Production Test Information Y / l� Mechanical Integrity Test Information Y kyA Composite Logs, Image, Data Files) Core Photographs Y/9 Geologic Markers/Tops U Daily Operations Summary O/ Cuttings Samples Y / l/ Laboratory Analyses Y / lA COMPLIANCE HISTORY Completion Date: 1/4/2017 Release Date: 10/10/2016 Description Date Comments Comments: Compliance Reviewed By: Date: / * /1 7- AOGCC Page 2 of 2 Friday, April 7, 2017 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ 0 WAGE] WDSPL ❑ No. of Completions: 1 1 b. Well Class' Development ❑ Exploratory ❑ Service [A Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 1/4/2017 14. Permit to Drill Number/ Sundry: 216-120, 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: -51-r December 19, 2016 15. API Number: 50-029-22976-01-00 . 4a. Location of Well (Governmental Section): Surface: 2713' FSL, 3402' FEL, Sec 28, T1 3N, R1 OE, UM, AK Top of Productive Interval: N/A Total Depth: 264' FSL, 1132' FWL, Sec 19, T1 3N, R1 OE, UM, AK 8. Date TD Reached: December 29, 2017 16. Well Name and Number: MPU J -24A 9. Ref Elevations: KB: 62.8' GL: 36.3' BF: 36.3' 17. Field / Pool(s): Milne Point Field Schrader Bluff Oil Pool . 10. Plug Back Depth MD/TVD: 13,367' MD / 3,605' TVD 18. Property Designation: ADL: 025906, 025517, 025515 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 551914 y- 6015110 Zone- 4 TPI: x- y- Zone- Total Depth: x- 540629 y- 6017870 Zone- 4 11. Total Depth MD/TVD: 13,402' MD / 3,602' TVD 19. Land Use Permit: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 2,000' MD / -1,800' TVD 5. Directional or Inclination Survey: Yes 0(attached) 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: 7,560' MD / 3,628' 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 -HORIZONTAL PRES 21N MD GM-ADR-INVERTED/REVERTED INTERVALS 21N TVD 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 4-1/2" 13.5# L-80 7,265' 13,372' 3,537' 3,604' 8-1/2" Cementless Linerw/ICDs, Swell Packers 24. Open to production or injection? Yes F�J No ❑ If Yes, list each interval open (MDrFVD of Top and Bottom; Perforation Size and Number): (10) WTF Injection Control Devices w/ 1-1-1 Nozzle Configuration 'See attached schematic for details' %;OIVIPLETION DATE VERIFIED 25. TUBING RECORD SIZE DEPTH SET (MD) IPACKER SET (MD/TVD) 4-1/2" 7,274 Bullet Nose Seal @ 7,274' MD / 3,540' 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: N/A Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Hours Tested: Production for Test Period —1111. Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casing Press: Calculated 24 -Hour Rate —.0o. Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Form 1Q-407 Revise 11/2015 CONTINUED ON PAGE 2 � (� �. u. [-�p��s L,-- FEB - 3 Z��bmit ORIGINIAL on] y- 28. CORE DATA Conventional G. a(s): Yes ❑ No ❑� Sidewall Cores. Yes ❑ No ❑� If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No 0 If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,000' 1,800' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval information, including reports, per 20 AAC 25.071. Schrader Bluff NA 7,780' 3,680' Schrader Bluff NB 8,064' 3,710' Formation at total depth: Schrader Bluff 31. List of Attachments: Wellbore Schematic, Daily Drilling and Completion Composite, Definitive Directional Surveys, MW vs Depth, Days vs Depth Graph. 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 hilcor .com Printed Name: Cod Din er Title: Drilling Tech Signature: APhone: 777-8389 Date: 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 Ilih—J' Al-kx. LLC RKB – Hanger: 23.0' (innovation Rig) M \77771 F 7" window @ 7,560' MD a 2 3 i 4 5 SCHEMATIC Milne Point Unit Well: MPJ -24A PTD: 216-120 API: 50-029-22976-01-00 CASING DETAIL Size Type Wt Grade Conn. Drift ID Top Btm 20" Conductor 92 H-40 Weld 19.00" Surf 108' 7" Surf. Csg 26 L-80 BTC 6.151" Surf 7,560' 4-1/2" Prod Liner 13.5 L-80 Vam HTTC 3.795" 7,265' 13,372' TUBING DETAIL 4-1/2" Tubing 12.6 1 L-80 I Supermax 3.833" 1 Surf 1 7,274' JEWELRY DETAIL No. Item Top MD Btm MD ID OD 1 Tubing Hanger 23' 24' — 2 Stage Tool – Halliburton ES Cementer 2,398' 2,400' 6.151" 7.000" 3 4-1/2" XN Profile (3.725" No -Go) 7,150' 7,151' 3.725" 4.785" 4 BOT Bullet Nose Seal (5.75" No -Go OD) 7,255' 7,274' 4.000" 5.235" 5 Liner Top Packer (HRD-E ZXP) 7,265' 7,285' 4.360" 5.960" 6 XO, 5" Hydril 521 x 4-1/2" Vam HTTC 7,307' 7,310' 3.920" 5.250" 7 WTF Fraxis Swell Packer #5 7,929' 7,940' 3.862" 5.750" 8 WTF ICD #10 w 1-1-1 Nozzle Configuration 8,454' 8,458' 3.866" 4.739" 9 WTF ICD #9 w 1-1-1 Nozzle Configuration 8,894' 8,899' 3.866" 4.739" 10 WTF Fraxis Swell Packer 44 9,319' 9,331' 3.862" 5.750" 11 WTF ICD #8 w 1-1-1 Nozzle Configuration 9,771' 9,775' 3.866" 4.739" 12 WTF ICD #7 w 1-1-1 Nozzle Configuration 10,384' 10,389' 3.866" 4.739" 13 WTF Fraxis Swell Packer #3 10,606' 10,618' 3.862" 5.750" 14 WTF ICD #6 w 1-1-1 Nozzle Configuration 10,937' 10,942' 3.866" 4.739" 15 WTF ICD #5 w 1-1-1 Nozzle Configuration 11,382' 11,386' 3.866" 4.739" 16 WTF Fraxis Swell Packer #2 11,681' 11,692' 3.862" 5.750" 17 WTF ICD #4 w 1-1-1 Nozzle Configuration 11,846' 11,850' 3.866" 4.739" 18 WTF ICD #3 w 1-1-1 Nozzle Configuration 12,327' 12,331' 3.866" 4.739" 19 WTF Fraxis Swell Packer #1 12,668' 12,679' 3.862" 5.750" 20 WTF ICD #2 w 1-1-1 Nozzle Configuration 12,873' 12,878' 3.866" 4.739" 21 WTF ICD #1 w 1-1-1 Nozzle Configuration 13,074' 13,079' 3.866" 4.739" 22 BOT WIV Valve (Ball on Seat/Closed) 13,367' 13,370' 4.980" OPEN HOLE/ CEMENT DETAIL 20" 260 sx Arctic Set curt to surface 7" 1600 sx Cement, 2 stages, curt to Surface GENERAL WELL INFO API: 50-029-22976-01 Sidetracked and Cased b Innovation - 1/04/2017 6� KAs �► r"t. 7 q'�zt 10 13 8 91112 Pill P a w " IF " ire 1.w�""1" " Y - � 16 19 2.`i L14 1517 18 20 21 !* W 2 2 22 ;ll 4-1/2" shoe 13,372' li i1i11 iW iW � iJ+ Y E =13,367'MD / 3,605' TVD3,402' MD / 3,603'TVDeviation: 94.58' Updated by STP 1/25/17 ff Hileurp Alaska, LLC Orig. KB Elev = 66.5' GL Elev. 36.3' RKB—Tbg Hngr: 21.3' (Nabors 3S) Milne Point Unit Well: MPU J-2441 Schematic Abandoned: 12/19/2016 PTD: 200-149/200-150 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surf 108' 7" Surface 26 / L-80 / BTC 6.151" Surf 8,664' 4-1/2" Liner Ll 12.6 / L-80 / IBT 3.833" 8,284' 11,987' 11,987' Liner 12.6 / L-80 / IBT 3.833" 8,554' 11,975' TD =11,975' (MD) / TD = 3,858'(TVD) PBTD =11,975' (MD) / PBTD = 3,858'(TVD) Downhole Proposed TUBING DETAIL /2" Tubing 12.6 / L-80 /IBT-M 3.833" 7,891 8,208' JEWELRY DETAIL Depth Item 7,577' Cement Retainer (Squeeze 46 bbl (193 sx)of 15.8 ppg Cement below) 7,891' Cut 4-1/2" Tubing 8,010' HES XD Sliding Sleeve (Closed 7/18/08) 8,073' Baker S-3 Packer 9Cr 8,136' HESX Nipple -3.813" ID 8,196' HES XN Nipple — 3.725" ID 8,207' WLEG 8,296' Baker ML Torque Master Packer 8,315' WLEG 8,563' Baker HMC Liner Hanger 11,964' OA Lateral 4-1/2" Pack -off Bushing 11,987' OA Lateral 4-1/2" Btm of Guide Shoe 11,952' OB Lateral 4-1/2" Pack -off Bushing 11,975' OB Lateral 4-1/2" Btm of Guide Shoe OPEN HOLE / CEMENT DETAIL 20" 260 sx Arctic Set cmt to surface 7" 1600 sx Cement, 2 stages, cmt to Surface GENERAL WELL INFO API: 50-029-22976-00/(60)-00 Drilled and Cased by Doyon 141- 11/9/2000 ESP Installed by Nabors 4ES —11/21/2000 ESP Replaced by Nabors 4ES — 5/20/2005 ESP Replaced by Nabors 4ES — 9/01/2005 ESP Replaced by Nabors 4ES — 9/10/2006 ESP Replaced by Nabors 3S — 7/02/2007 Convert to Jet Pump by Nabors 3S — 4/15/2008 Decomplete/Abandon by Innovation Rig- -21f L I s-7-14 Updated By: CJD 2/02/2017 Hilcorp Energy Company Composite Report Well Name: MP J -24A Field: Milne Point County/State: , Alaska Location (LAT/LONG): Elevation (RKB): 26.04 API #: Spud Date: Job Name: 1511740D MP J -24A DRILLING Contractor AFE #: AFE $: Activity Date Ops Summary 12/9/2016 Cont T/prep derrick T/scope down. Unhook both derrick asst. cables f/top of cat walk, unhook geronimo line f/roof of pipe shed, p/u blocks stage bridle line's @ sheave and install sheave guide bolts.;Unplug top section derrick lights and crown saver. P/U V80k visual check bridle lines, p/u 1:1130k, s/o t/1 10k, massage derrick work f/120k-V145k multiple times, p/u t1150k and hold, cont. Vmassage;Set over pull V140k and work, stage up over pull V142k and p/u @ faster rate. Wt will climb V147k, p/u off dogs, pull dog pins, visual inspect dogs out, scope derrick down s/o=130k, p/u=140k.;Install tong sheave extension, fill pipe shed jet heat day tanks w/fuel. Asst. White Star rep. w/replumbing internal bearing lube system on m.p. #2, refill m.p. #2 w/gear oil;Open suction caps #1 mud pump, hard to remove, Whitestar Rep. present, found that sealing surfaces were gaulled, investigating reason for gaulling. Inspect #2 same (good).;Blow down water throughout rig. Offload cutting box to vac and send for disposal. Offload 160 bbls water from pits for disposal. Lay herculite and mats on well J-24. Install BPV.;Scope derrick, 138k to 155k up. R/U tongs and adjust lines. Inspect sheave clearance during scoping operations (ok). Attempt to pull pins but linkage failed to pull pins.;;Manually pull pins. Scope derrick down. Install shipping pins in derrick and tq tube. Take on 2K gal fuel. Install 80 psi regulator for blowing down steam system. Blowdown and drain water heater.;Freeze protect washer machines, blowdown water heaters. R/D welding hooch. Remove peripheral equipment from around rig and prep for rig move. Coil and stage wt bucket w/ Geronimo lines on sub.;Shut in steam. Remove steam traps from system and blowdown same. Lay herculite and mats on J-24. Install BPV and remove upper tree. Double stack master valves and blind off. Secure well. 12/10/2016 Continue rigging down service lines and prepping rig for demob. Lift and secure landings and stairs.;PJSM for rig move. Demob rig and stage on location. Pick up and demob mats. Clean up containment and discard. Demob equipment from around entrance of pad. Remove blinds from master valve.;Move rig F/ D pad T/ J pad (7.9 miles). est 4 MPH avg. No issues during rig move. Road and route prep was done prior to move. Work included removing guardrails and signs. Scarifier corners.;Remove rear tires on sub. Remove traveling hitch from sub. Walk sub 90° and prep to walk back over J-24 well. Spot both Geo Skids on rig. Spot mats for other modules.;Slowly walk rig back over well J-24 and ctr. Lower stairs and install landing inside sub.;Spot catwalk. Set pit module and adjust alignment w/ catwalk. Continue installing landings and setting stairways as modules get spotted.;Notify AOGCC of upcoming rig inspection and BOP test. 12/11/2016 Spot power module, remove jeep. Plug in power from sub to pits. Set up floor plates and roof hatches.; Mobilize company man / Toolpusher camp to J -pad and spot. Lay liner and matting boards for cuttings tank. Spot cuttings tank utilizing roads and pads front end loader. Plug in power from pits to power; Begin cto fluid end on #1 mud pump. Take on fuel to rig. Con't insulating rig. Take on 587 bbls of sea water to pits 3, 4 and 5. Berm cuttings tank. Stage sub base tires by jeeps. Assist canrig tech;lnstall chain on tong arm extensions for secondary retention, load outriggers, cont, install pump mod. In m.p. #1 dress pump w/5" liners and swabs, m.p.#2 pull all swabs inspect Iiners.;Change out swabs in pod 2,3 & 4. Perform pre scope derrick inspection. Install drag chain belt. Pump through all centrifugal pumps, ready centrifuge's, du steam Vcutting box.;Charge water header Vpits. R/U steam Vpit #5 and V140 degree's. Install cmt line chixson. Spot drilling connex and warmup shack.;Attempt to scope derrick. 140k initial up wt. Pulled heavy towards the last 2' prior to pin (160k). Cycle derrick several times with little to no change in final up wt.;Add light oil to reduce friction. Continue scope and pin w/ final up wt 158k. Plug in lights and crown saver. Continue insulating around rig and rigging up peripheral equipment on location. 12/12/2016 Continue Canrig install. Troubleshoot and fix intercom system. Continue labeling and bonding electrical. Ran mud pumps, completed interlocks/shutdown checklist.; Monitor mud pump inverters cooling / air flow (ok). Continue heating seawater in pits maintaining 140° F. Stage welding equipment on floor. Repair derrick pin Iatch.;Fix leak on drawworks HPU. Re -wire plug on catwalk. Dress shakers w/ 140's (API).;Stage mud product in hopper room. Finish commission pumps (ok). Swap to hi -line @ 14:30 hrs. R/U "T' bar and pull BPV. R/U to kill well taking returns back to flowback tank.;Scope derrick up to free scoping pins (152K up). Function derrick pin latch (ok). Secure derrick w/ scoping pins and relax bridle line.;R/D bridle line and equipment.;Walk lines and verify valve alignment to flowback tank (ok). Lineup and blow air through choke line and both manual chokes (ok). Wet lines with 8.5 ppg heated seawater.;P/T lines w/ 250 low and 2000 high (ok). Slowdown line and lineup to pump down 4-1/2" tbg and take returns from 7"x4-1/2" annulus to flowback tank. Verify chart recorder vs rig standpipe gauge (ok).; Bring pump #2 on @ 1 bpm/34 psi (1/2 open choke pos). Saw gas first 2 bbls then straight crude. Increase pump 2 bpm/102 psi (full open choke pos). Stage up to 5 bpm/425 psi w/ partial returns.; Saw transition from oil to water @ 157 bbls pumped (est 90 bbls oil return). Continue circulating 140°F, 8.5 ppg seawater do tbg. Pump 454 bbls total w/ 265 bbis return (58% returns).;Shut down pump. Tbg and annulus on very slight vac. Blowdown lines. R/U hole fill on annulus (pump 20 bbls every hour do annulus). N/D 1502 tree flange and install TWC as per plan.;N/D tree and setback on rig mats. Graphite pack hanger for BOP test. Dummy run hanger XO to TC -11 (8 rds - Ok).;N/U BOP equipment. Install 11"x 13-5/8" 5M DSA. N/U Class IV stack 5M stack. Dress upper and lower rams w/ VBR's (2-7/8" x 5-1/2"). Blind rams in middle.;Hauled 0 bbls to B-50 for total = 430 bbis 12/13/2016 Finish torqueing DSA, Choke & Kill flanges to spec. Cont filling annulus with 20 bbl per hr seawater. Build 40 bbl batches to maintain 300 bbl volume. PIU weatherford 9 5/8 casing tongs to test fit.;Bring 4.5 weatherford tongs and test on rig hydraulic system. Flushed 10 gallons through tongs before taking returns to rig. Take IRKS measurements. Pressure up accumulator. Bump test rams & annular;good. Fix Hyd leak on HCR Kill. Change plumbing on annular to clear mouse hole. Finish N/U BOPs. TWC leaking in to BOPs. Close blinds and pressure up to 500 to seat popit.;ACE assist Canrig, Mud Module, drive lineup and added covers for the open busway, tested the air flow in the MP cabinets, Run MPs and monitor temps, test and fine tune catheads, C/O PLC program.;Note: 24hr notification for initial BOP test sent to AOGCC @ 14:03 PM on 12/13/2016; Leave blinds closed to fix leak on pitcher nipple. Open blinds and monitor well. Static. Annulus on vac. Canrig continues to R/U, Calibrate / test PVT system and gas alarms.;P/U mouse hole f/cat walk and install, test rotating mouse hole functions, M/U test equipment w/ 4 1/2" test jt. Note: monitor IA continues on vac;Top drive functions not working, trouble shoot top drive, fault shown on main power panel, drill console alarm showed low oil press, coolant fault and VFD fault, ACE rep came to help trouble shoot.; Found coolant pump locked out, Top drive is operational.; Decision made Vshut down and not operate top drive, notify NOV in the morning.; Instal test joint, flood stack and lines w/ water, PJSM, review BOP testing procedure Note: monitor I/A, continues on vac, fill @ 10-15 bph;Pre test BOPE, choke manifold valves to 250 psi low, 5000 psi high 5 min ea. Chart all tests. Attempt accumulator drawdown, manifold pressure bleeding off 200 psi after pumps shut down.;Perform electric and manual choke bleed test.; Daily losses to well, 459 bbls 8.5 ppg seawater for total= 459 bbls. Hauled 0 bbls to B-50 for total = 430 bbls 12/14/2016 Test bops annular with 4.5 test joint. Troubleshoot annular leak @ 2500-4000 psi. Brought up annular pressure from 850 to 1500 psi as per Manufacture recommendation. Retested 250 5000 psi good.;Tested Both manual and Hyd TD valves to 250/5000 psi. Performed accumulator test. 3050 psi Starting pressure 1725 psi Pressure after shut in 200 psi increase in 19 sec. 71 sec to full recovery.; Functioned top rams twice to simulate closing blinds.;Work on installing safety cables on interconnects. Continue filling annulus with 10 bph seawater. Reprogram accumulator controls for Remote operation on the annular pressure adjustment. Good.;Canrig finished installing and calibrating rig floor PVT screen and pit sensors. Calibrate flow meter, Gain loss & alarms. Good.;ACE: wire and test gen kill, Test utility going online f/ blackout scenario, adjust accumulator PLC-add master supply valve to annular increase/decrease, Modify data logger software.;Lable ram size upper and lower on BOP control in dog house and on accumulator. Label accumulator bottles and nitrogen bottles.-,Training w/ Total Safety on rig alarm's and sensors. R/U and test flow sensor on flow line, calibrate same. Continue installing hose hangers around rig.;Continue w/rig acceptance check list, R/U hard line f/cellar trash pump t/flow line, continue w/general house keeping and ready rig for AOGCC inspection.;Continue to R/U hard line plumbing f/cellar pump t/flowline, stage WFD 4.5" elevator's on rig floor and inspect, paint plumbing on test pump.; Place lower section of block hang line behind derrick gurt, blow air through MP #1 & #2 pop off line. Stage liner and dunnage for pipe racks. Continue hole fill down I/A 10 bph w/ 8.5 ppg seawater.;Daily losses to well, 144 bbis 8.5 ppg seawater for total= 574 bbls. Hauled 0 bbis to B-50 for total = 430 bbis Hauled 0 bbis to ORT for total= 190 bbls. 12/15/2016 Conduct Pre spud safety meeting with both drilling crews at Milne point. Keep Toolpusher on rig to monitor. Note: accept rig on J-24A @ 06:OO.;R/U to test BOPE. Fill stack and lines with freshwater. Perform rig inspection with Chuck Scheve with the AOGCC. Good.;Test BOPE to 250/5000 psi all valves and blow out equipment as per sundry. Test annular to 250/3500. All test pass. Perform accumulator drawdown. Monitor VA, Continue 10 bph hole fill w/ 8.5 ppg SW.;3000 psi starting pressure, 1700 after starting, 200 psi Increase in 9 sec. Full pressure attained in 62 sec. 2300 psi average on 6 bottles.;Close I/A valve. R/D test equipment, Blow down top drive, choke manifold and lines.; Finish hot work projects on rig floor. R/U hole fill and bleeder line. Pull TWC per wellhead rep, pump 20 bbis 8.5 ppg SW down annulus. Close blind ram. Note: tbg on vac.;Conduct training with both crews operating rig ESD blacking out rig and bringing back online.;PJSM with crew, WFD and wellhead rep. M/U landing jt and XOs. BOLDS, unseat hanger @ 92k, P/U 3 times staging up wt to 115k parting tbg @ 7900' (@ jet cut depth) continue 10 bph hole fill w/ 8.5 SW.;Pull hanger to rig floor. UD hanger, blast rings, pup jt and landing jt. C/O to 4 1/2" elevators, Ready FOSV.;P/U 85k, POH UD 4 1/2" IBT 12.6# L-80 tbg f/ 7875' to 1300 ' (starting off slow as hands get familiar with operation and equipment) 165 jts out Note: UD 2 pup jts and GLM @ jt #72.;Note: use double displacement hole fill on trip out.;Conduct valve drill @ 7660' (AAR: valve handle mixed with others on tool rack, use strap to stab FOSV so chain on hoist doesn't bind up when M/U, test run any XOs on FOSV); Daily losses to well, 230 bbis 8.5 ppg seawater for total= 744 bbis. Hauled 0 bbis to B-50 for total = 430 bbis Hauled 0 bbis to ORT for total= 190 bbls. 12/16/2016 POOH F/ 1300'T/ Surface. UD 199 joints total + 31.16 cut joint. One GLM with Pups.;R/D Weatherford casing Equipment. Clean rig floor.; Flush oil out of stack. R/U Test equipment. M/U 4" Test joint & Test Plug. Set Test plug.;Test BOPE with 4" test joint. Lower Rams, Upper Rams, & Annular to 250/3000 psi. All tests good.;Found leak on TD. Inspect TD & Found leaking hydraulic filter tattle tell leaking at connection. UO TD & Repair bad O ring.;R/D test joint. Pull test plug.;PJSM, install 9" ID wear bushing, R14LDS, clean and clear rig floor. PJSM for WU BHA.;M/U Cleanout BHA #1, 6 1/8" Mill tooth bit, BS, 6.151 upper window mill, DPS, 7" scraper, BS, Jar, XO, 20 jts 4" HWDP= 632.94' Note: 1 jt HWDP would not drift;Drift, P/U and single in the hole with 4" XT-38 DP f/ 633' to 6195' (177jts ran) Use 5 bph hole fill on trip in. Note: Conduct valve drill @ 695', 1 min 40 sec to secure well.;Daily losses to well, 139 bbis 8.5 ppg seawater for total= 883 bbis. Hauled 0 bbis to B-50 for total = 430 bbis Hauled 0 bbis to ORT for total= 190 bbls. 12/17/2016 P/U DP F/ 6321'T/7891'. Tag top of tubing stump 2K. UP/DN 105170k.;POOH F/ 7891'T/ 7644'. Circ 1.5 DP volumes to clear pipe. Work pipe across planned setting area @ 7585'. Reciprocate F/ 7600'T 7560'.;POOH with 4" DP F/ 7644'T/ BHA 632'. Stand back HWDP out of the way. UD Cleanout BHA. Clean and clear the rig floor. Fill hole with double pipe displacement while tripping.;PJSM, M/U running tool and XO, Dummy run same thru stack, M/U 7" EZ DRILL SVB cement retainer, retainer only= 2.65', OA= 14.16' Note: use 10 bph hole fiII;RIH with stands of 4" DP from derrick to 3156', fill pipe, Discoverd leak on TD gooseneck connection. Note: use 5 bph hole fill on trip in.;Tighten gooseneck connection, pressure test mudline to top drive to 500/3000 psi, good. Blow down top drive.;Continue to RIH f/ 3156' to 6994' (111 stds DP) Single in with 19 jts DP to 7585', P/U 94K, S/O 69K. Fill pipe @ 6000'.;M/U top drive, Pump 20 bbis seawater 3 bpm, 200 psi to clear any debris @ set depth, see returns @ 13 bbis away. Blow down top drive.;M/U pump in sub, FOSV closed with 5' pup loaded with DP wiper ball, M/U top drive, P/U 13' to set depth matching old RKB 6.28' difference.; Set retainer per Haliburton rep, apply 35 turns to right, stage up to 141 k @ shear @ 50K Over pull , P/U T and unsting, apply 25 turns to right.;R/U lines to test 7" csg. With new RKB top retainer set @ 7576.1.;Daily losses to well, 189 bbis 8.5 ppg seawater for total= 1072 bbls. Hauled 0 bbis to B-50 for total = 430 bbis Hauled 0 bbis to ORT for total= 190 bbis.; Hauled 300 bbis from 6 mile lake for total= 300 bbis. 12118/2016 R/U to test casing. Break circ and fill well up. Close Top rams and pump down DP & Kill line. Test casing to 1500 psi. Monitor Lower annulus. Pressure came up to 1500 psi also. Hold for 10 Min Good;PJSM, Cmt job. Sting in to retainer @ 7576' DP Measurement, Corrected Depth with RKB Difference 7580'top of Retainer. Set down 15K. Pump 2 bbl with rig to verify injection.;Swap to cmt unit & batch mix cmt. Pump 20 bbl freshwater and 46 bbl(193 sx) 15.8 ppg Class G cmt. Displace with Halliburton 20 bbl H2O & 66 bbl seawater. 2 bbl over calculated displacement.; Final injection pressure @ 1360 @4 bpm. Unsting from retainer and see pressure drop. Swap to rig and clear lines pumping 20 bbl. Shut in cmt line and swap to TD. Pump down wiper ball. CIP @I 0:00.;Circ STS & never saw wiper bailor cmt to surface. Shutdown and monitor well. Static. Blow down surface equipment.; UD single, POOH U 6800' while looking in to lower annulus communication. Found old workover report that showed well head changed out. Both upper and lower valves are on the 7" casing.;Test 7" casing T/ 1500 psi for 30 min. Straight line. Good. Blow down all surface equipment.;POOH T/ 6400'. Found leak on TD.;Inspect TD & fixed leak on TD. Tighten hyd fittings behind diving board. Note: load pits w/ 580 bbis 8.9 ppg BARADRIL-N Drlg mud.;Continue POOH f/ 6400' to surface, inspect and UD and load out running tool. Note: correct displacement on trip out.;Service top drive, crown and drawworks.;PJSM, M/U cleanout BHA 3- 6 1/8" Window mill, 5 7/8" Lower string mill, flex jt, 6.151" upper WM mill, 1 jt 3 1/2" HWDP, XO, 20 jts 4" HWDP= 656.97', RIH w/ 4" stds DP f/ derrick to 7070'.;Note: correct displacement on trip in.;Daily losses to well, 146 bbis 8.5 ppg seawater for total= 1218 bbls. Hauled 0 bbis to B-50 for total = 580 bbis Hauled 0 bbis to ORT for total= 190 bbls.; Hauled 640 bbis from 6 mile lake for total= 940 bbis 12/19/2016 RIH F/ 7070" T/ 7577'. Tag top of retainer. 2K.;Circ & condition 3 bpm 275 psi while prepping for displacement.; Displace well from seawater to 8.9 ppg Baradrill N. Pump 23 bbl high vis sweep ahead. Circ @ 10 bpm 2400 psi. Reciprocate while circulating. Displacement came back early from calculated strokes.;Sweep came back 200 strokes early. Build and pump dry job. Monitor well. Good.;POCH F/ 7577'T/ 5371'. TD started leaking oil. Shutdown and look for Ieak.;Trouble shoot leak and tighten fitting.;POOH F/ 5371'T/ Surface standing back the HWDP.;PJSM, M/U Whipstock. Remove shipping bolt. Remove 3 of 6 shear pins. 3563# Each shear for the anchor. Set to shear @ 10695#. P/U Whipstock scribe whipstock to tool face @ 100 Deg offset.;RIH slow @ 90 fpm w/ 10 stds 4" HWDP, WS BHA= 697.25', shallow hole test MWD tools, good. Note: very easy in and out of slips.;RIH slow @ 90 fpm with stds 4" DP from 697' to 7488' (Test MWD @ 6340' good) Note: very easy in and out of slips/ fill DP every 3000' No issues on trip in, correct displacement.; M/U trop drive, fill pipe, 225 gpm @ 1150 psi orient 51 deg Left TF, reciprocate string several times working out torque f/ 7488' to 7549'. Pump on P/U 104K, S/O 60K, pumps off P/U 117K, S/O 60K.;WU stand 110 and top drive, work out torque, check tool face, holding 51 Left. S/O tagging retainer @ 7577.18', set down 12k shearing anchor, P/U 10K over pull confirming anchor set.; Over pull 12k, set down 40k several times until shearing WS shear Bolt. P/U 20', reset bit depth 17.63' shorter. PU/SO/ROT 117/60/76, 80 rpm 8K free TQ, 230 gpm, 1190 psi, SPR 1 & 2 MP.; Ditch magnets in place, S/O to top of WS with light wt and low torque. Mill window per BOT rep f/ 7560' to 7571'. 220 qpm WOM 24K, 80 rpm, 8.2-10K TQ. MW in/out 8.9 ppg, vis 44.;Collect metal from milling operations.; Daily losses to well, 0 bbis ddg mud for total= 0 bbls Hauled 0 bbis to B-50 for total = 580 bbls 12/20/2016 Cont milling 80 rpm, 8.5 WOB 225 GPM, 1200 Psi F/ 7570;' T/ 7573'. Drill 20' new hole T/ 7593'. Top of window @ 7560' btm of window @ 7573'. Total Metal recovered 130#.; Ream through window. Work through several times with and without pumps and rotary. No drag. Circ sweep around @ max rate 302 gpm, 1500 psi. Sweep came back with 50 % increase.;Open manual valves, blow through choke and kill. Pump through stack. Close upper pipe rams.;Perform FIT to 12 ppg EMW. Pump down DP & Kill line 11 stks to 555 psi. Bled down and leveled out @ 500 psi with and EMW of 11.75. Bled back 1/2 bbl to pits.;Open up upper rams. Pump 20 bbl dryjob @ 10.4 ppg. Worked good. Blow down all Iines.;POOH F/ 7534'T/5080'. Shutdown and adjust elevator indicator. Continue to POOH F/ 5080' T/Surface. UD all HWDP. UD Mills. Upper WM mill= 6.125" gauge ring no go.;M/U jetting tool, flush and clean stack 2 times clearing any metal cuttings f/ milling operations. PT Geo -span to 500/3000 psi, good.;Service blocks, top drive, pipe spinner, clean MP suction screens.;PJSM, M/U BHA #5, 6 1/8" PDC bit, geo-pilot, GM, ILS, ADR, ILS, PWD, DMC, TMC, upload data, M/U 3 NMFCs, XO, 1 jt HWDP, Jar, 1 jt HWDP= 276.96' Note: install corrosion r1 ring @ top NMFCs.;Drift and single in the hole w/ 4" DP f/ 277' to 1000' M/U top drive.; Break in Geo -pilot, shallow test MWD tools. Troubleshoot Geo span unit, choke does not cycle fully open or closed. Blow down geo-span lines and Top drive. C/O geo span.; Continue to drift and single in the hole w/ 4" DP f/ 1000' to 2250' M/U top drive.;Pressure test geo span lines to 500/3000 psi. Test Geo span and MWD/LWD tools. Blow down top drive. Investigate small hydraulic leak on top drive w/ Rig mechanic and NOV rep. Note: Monitor well.; Investigate small hydraulic leak on top drive w/ rig mechanic and NOV rep tighten 3 hoses dripping under diving board and on top drive. f Note: Monitor well.; Daily losses to well, 0 bbis drlg mud for total= 0 bbls y. Hauled 0 bbis to B-50 for total = 580 bbis Hauled 0 bbis to ORT for total= 190 bbls.;Hauled 0 bbls from 6 mile lake for total= 1090 bbis Hauled to G & I, 4 bbis for total= 382 12/21/2016 Bit depth @ 2287'. Test MWD and Geo Pilot, 250 gpm, 800 psi, 60 rpm, 2.7K Tq. Test Good.;Continue to single in the hole picking up 4" DP (/2252' to 4975'. Fill pipe and SPT @ 225 gpm 1060 psi, 88K PUW, 60K SOW. Blow down top drive.;Continue to single in the hole with 4" DP (/4975' to 6568'. (P/U Total of 200 joints from pipe shed).;TIH with stands from derrick f/6568' to 7510'.; PJSM on slip and cut drill line. Fill pipe and test MWD tools @ 225 gpm, 1330 psi, PUW 108K, SOW 58K.;Monitor well, PJSM. Slip and cut 90' drlg line. Calibrate and test crown saver.; NOV rep upload software for top drive and perform top drive inspection, service top drive, blocks, crown sheaves, drwks, tugger and manrider sheaves.;RIH f/ 7510' passing thru window w/ pumps off @ 7560' with no issues, tag @ 7587', pump 205 gpm, 1170 psi, 40 rpm, ream undergauge hole f/ 7587' to bftm @ 7593' PU 115K, SO 64K, ROT 72K.;Drill 6 1/8" hole f/ 7593' to 7699' Av ROP 23.5 fph, 106', 268 gpm, 1920 psi, 13-14k wob, 80 rpm, 7-8k tq. MW in/out 9 ppg, vis 44, ECD 10.5.;Drill 6 1/8" hole f/ 7699' to 7886' Av ROP 31 fph, 187', 248 gpm, 1700 psi, 13-14k wob, 120 rpm, 7-8k tq. PU/SO/ROT 115/55/75, MW in/out 9 ppg, vis 45, ECD 10.7.;Build rates have been inconsistent and range anywhere f/ 2 deg/100 to 11 deg/ 100 w/ deflection anywhere f/ 15% to 70%. Balled up- Pump 25 bbl, 10 ppb walnut sweep @ 7768', sweep back @ calc stks.;Unable to get clean survey, signal starting to cleanup, Last survey @ 781 1' = 81.2 deg inc.;Daily losses to well, 0 bbls drlg mud for total= 0 bbis Hauled 0 bbis to B-50 for total = 580 bbis Hauled 0 bbls to ORT for total= 190 bbls.;Hauled 150 bbls from 6 mile lake for total= 1090 bbls Hauled 24 bbis to G & I, bbls for total= 406 12/22/2016 Drill 6 1/8" hole f/ 7886' to 7935' Av ROP 49 fph, 49', 248 gpm, 1700 psi, 13-14k wob, 120 rpm, 7-8k tq. PU/SO/ROT 115/55/75, MW in/out 9 ppg, vis 45, ECD 10.6.; Back ream f/ 7935' to 7900' @ 300 fph, 250 gpm, 100 rpm, 8.2k TQ due to 14 deg dogleg.; Drilling f/ 7935' to 8005' Av ROP 20 fph, 70', backream 30' on connections. 248 gpm, 1700 psi, 13-14k wob, 120 rpm, 7-8k tq. PU/SO/ROT 112/52/72, MW in/out 9 ppg, vis 45, ECD 10.6.; Drilling f/ 8005' to 8266' Av ROP 43.3 fph, 261', Get check shot survey @ 8264', 225 gpm, 1760 psi, 13-14k wob, 120 rpm, 8.2k tq. PU/SO/ROT 112/52/72, MW in/out 9.1 ppg, vis 45, ECD 11.2.;Drilling f/ 8266' to 8388' Av ROP 48.8 fph, 122', backream 30' on connections. 247 gpm, 1800 psi, 13-14k wob, 120 rpm, 8.2k tq. PU/SO/ROT 112/52/72, MW in/out 9.1+ vis 48/45, ECD 11.1.;On connection with drill pipe in slips, going after a stand, dwks fault tripped setting drum brake fouling drilling line on drum, cannot slack off w/ blocks.;M/U FOSV and headpin circulate 2 bpm 500 psi. PJSM, R/U hang line in derrick, hang off blocks and top drive, unfoul drlg line on drum, inspect line, good. RID hang line, headpin and FOSV.;M/U top drive, pump 2 bpm, work and make sure pipe is free, Remove hang line from derrick. Make connection.; Drilling f/ 8388' to 8474', after down link, 300 psi pressure drop to 1500 psi in less than 1 minute, 247 gpm, 1800 psi, 0-3k wob, 120 rpm, 9k tq. PU/SO/ROT 111/50/76, MW in/out 9.1 vis 45/45, ECD 11.;Note: 8470' max gas @ 1029u.;P/U off bttm to 8440', troubleshoot 300 psi pressure loss, test all surface equip and mud pumps, good. Check SPR, @ 30 SPM, original 440 psi, new 405 psi, difference of 35 psi.;Test geo-pilot and MWD tools, all functioning properly, no issues w/ tools. Decision made to continue drilling ahead and monitor for drill string pressure loss. Note: possible plugged nozzle cleared.; Drilling f/ 8474' to 8551' Note: 21.8 deg dog leg in 11', 247 gpm, 1530 psi, 0-8k wob, 120 rpm, 8.2k tq. PU/SO/ROT 112/52/72, MW in/out 9.1+ vis 48/45, ECD 11.;Backream 247 gpm, 1530 psi, 80 rpm f/ 8551' to 8530'@ 100 fph down/ 300 fph up reducing dog leg to 14 deg or Iess.;Currently 5.8' below the line, 26.4' Ieft.;Trouble shoot centrifuges/ would not kick out solids, try various settings @ per NOV/Brandt rep. Currently Running #1 centrifuge.; Daily losses to well, 0 bbis drlg mud for total= 0 bbls Hauled 0 bbls to B-50 for total = 580 bbis Hauled 0 bbls to ORT for total= 190 bbls.;Hauled 300 bbls from 6 mile lake for total= 1540 bbis Hauled 143 bbis to G & I, bbls for total= 549 12/23/2016 Drilling f/ 8551' to 8950'(399') AROP 66.5 FPH, back ream 30' on connections. 248 gpm, 1580 psi, 0-4k wob, 120 rpm, 8.8k tq. PU/SO/ROT 116/48/74, MW in/out 9.1+ vis 45/44, ECD 11.1.;07:00 hrs swap rig f/ high line power to rig generator power. Note: Concretions f/ 8558' to 8565'.;Drilling f/ 8950' to 9353' (403') AROP 67.1 FPH, back ream 30' on connections. 248 gpm, 1580 psi, 0-4k wob, 120 rpm, 8.8k tq. PU/SO/ROT 116/48/74, MW in/out 9.1+ vis 45/44, ECD 11.1.;Note: Concretions f/ 9349' to 9353'. 9050' Max gas @ 1401 u.;Drilling f/ 9353' to 9572'(219') AROP 36.5 FPH, back ream 30' on connections. 220 gpm, 1370 psi, 1-3k wob, 120 rpm, 9.5k tq. PU/SO/ROT 116/47/72, MW in/out 9.1 vis 44/44, ECD I l.;Note: Concretions f/ 9353' to 9356', 9365' to 9368', 9451' to 9455', 9458' to 9460', 9532' to 9537', 9569' to 9572'.;Drilling f/ 9572' to 9818'(246') AROP 70.2 FPH, Note: 15.12 deg dog leg in 11', 220 gpm, 1370 psi, 1-3k wob, 120 rpm, 10k tq. PU/SO/ROT 118/41/73, MW in/out 9.1 vis 44/44, ECD 11.;Concretions f/ 9628' to 9637', 9648' to 9654', 9760' to 9764', 9767' to 9770'. Note: 80 psi quick spike in pump pressure, Pump 30 bbl to vis sweep @ 9770' sweep back on time, 10% increase sand.;Backream 220 gpm, 1410 psi, 80 rpm f/ 9818' to 9788'@ 100 fph down/ 300 fph up reducing dog leg to 11.94 deg, Note: Add 4 drums EZ GLIDE increasing lube to .5%.;Drilling f/ 9818' to 9881'(63'), 220 gpm, 1370 psi, 1-3k wob, 80 rpm, 10k tq. PU/SO/ROT 118/41/73, MW in/out 9.1 vis 44/44, ECD 11.2.;Currently 28.3' below the line, 27.8' IefU 100% in zone;Daily losses to well, 0 bbls drlg mud for total= 0 bbls Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total= 190 bbls.;Hauled 300 bbls from 6 mile lake for total= 1840 bbls Hauled 114 bbls to G & I bbls for total= 663 12/24/2016 Drilling f/ 9881' to 10220'(339') AROP 56.5 FPH, back ream 30' on connections. 220 gpm, 1480 psi, 2-6k wob, 120 rpm, 9.6k tq. PU/SO/ROT 120/37/70, MW in/out 9.1+ vis 45/45, ECD 11.2.;Note: follow recommended drilling strategy when encountering concretions. Increase lubes to 1.5% adding EZ GLIDE. Concretions f/ 9924' to 9927', 10058' to 10061'. @ 10180' Max gas 1620u.;Continue drlg f/ 10220' to 10294' Note: 16 deg dog leg in 11', 220 gpm, 1480 psi, 2-6k wob, 120 rpm, 9.6k tq. PU/SO/ROT 120/37/70, MW in/out 9.1+ vis 45/45, ECD 11.2.;Backream 220 gpm, 1410 psi, 80 rpm f/ 10269' to 10294'@ 100 fph down/ 300 fph up reducing dog leg to 11.3 deg.;Continue drlg f/ 10294' to 10527'(233') AROP 58.2 FPH, back ream 30' on connections. 220 gpm, 1485 psi, 2-6k wob, 120 rpm, 10.2k tq. PU/SO/ROT 122/36/70, MW in/out 9.1+ vis 45/45, ECD 11.4.;Concretions f/ 10296' to 10302', 10526- to 10527'. Pump 25 bbl to vis sweep w/ 5 ppb walnut @ 10487', sweep back on time w/ 10% increase in sand. Note: Swap rig to high line power @16:30.;Continue drig f/ 10527' to 10714'(187') AROP 31.2 FPH, back ream 30' on connections. 221 gpm, 1490 psi, 2-6k wob, 120 rpm, 10.7k tq. PU/SO/ROT 122/36170, MW in/out 9.1+ vis 45/45, ECD 11.4.;10702' pump tandem 20 bbl to vis / 20 bbl 10 ppb weighted sweep, sweep back 200 stks late w/ 10% increase @ shakers, all sand.; Concretions f/ 10527'-10533', 10572'- 10575', 10616'- 10645', 10682'-10687', 10690'-10706'.;Continue drlg f/ 10714' to 10879' (165') AROP 55 FPH, back ream 30' on connections. 221 gpm, 1490 psi, 2-6k wob, 120 rpm, 10.7k tq. PU/SO/ROT 122/36/70, MW in/out 9.1 vis 46/46, ECD 11.6.;1270u gas, observed slight flow increase, shut down and monitor well for 10 min while moving pipe, no flow, continue circulating w/ gas receding to 140 units.;Continue drlg f/ 10879' to 11075'(196') AROP 78.4 FPH, back ream 30' on connections. 221 gpm, 1450 psi, 2-6k wob, 120 rpm, 10.3k tq. PU/SO/ROT 120/35/72, MW in/out 9.1+ vis 46/46, ECD 11.6.; Concretions f/ 10718'-10722', 10745'-10756', 10856'-10859', 10876-10880' Currently 28.9' below the line, 17.7' left, 100% in zone.;Daily losses to well, 0 bbls drlg mud for total= 0 bbls Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total= 190 bbls.;Hauled 250 bbls from 6 mile lake for total= 20900 bbls Hauled 171 bbls to G & I, bbls for total= 834 12/25/2016 Continue drlg f/ 11075-11114' Max gas @ 10980' 1544u, 221 gpm, 1450 psi, 2-6k wob, 120 rpm, 10.3k tq. PU/SO/ROT 120/35/72, MW in/out 9.1+ vis 46146, ECD 11.6.;Backream 11093'-11114' to drop INC as per GEO to 92 deg.;Continue drlg f/ 111 14'to 11595' (481') AROP 53.4 FPH, back ream 30' on connections. 221 gpm, 1450 psi, 2-6k wob, 120 rpm, 10.3k tq. PU/SO/ROT 120/35/72, MW in/out 9.1+ vis 46/46, ECD 12.2.; Pump tandem to vis to wt sweep followed with hi vis hi wt sweep. Hole unloaded 300%. Dropped ECD from 12.2 to 11.7.;After connection @ 11596', geo-pilot pumped deflection reading @ 118%, tool would not send home command after several attempts. MWD performed manual mode switch.;on MWD tools, nothing worked to change actual geo pilot deflection.; Continue drlg f/ 11595' to 11616' (20') 220 gpm, 1350 psi, 2-6k wob, 120 rpm, 10.3k tq. PU/SO/ROT 125/35/72, MW in/out 9.1+ vis 46/46, ECD 11.7.;After drilling 20' of hole to get cutters in new formation, attempt to send home command, no difference in geo pilot was seen, decision made to POOH.;Pump and backream out of hole 290 gpm, 2150 psi, 100 rpm, 11 k TQ f/ 11616' to 8832'.;Pump and backream out of hole 290 gpm, 2150 psi, 100 rpm, 8k TQ f/ 8832' to 8012' ECD climbing to 12 ppg.;Pump 25 bbl hi vis sweep 290 gpm, 1700 psi, 100 rpm POH 60 fph f/ 8012' to 7949', @ BU hole unloaded w/ 200% increase @ shaker, sweep back on time, 300% increase;at shakers consisting mostly sand, ECD after sweep 11 ppg.;Pump and backream out of hole 290 gpm, 2150 psi, 100 rpm, 8.3k TQ f/ 7949' to 7635', POH on elevators f/ 7635' to 7543' in 7" casing.; Note: clean pulling BHA thru window @ 7573'.; Blow down top drive, M/U FOSV, monitor well for 30 min. Well is static. Pump dry job, BD top drive.;POH on elevators f/ 7543' to 6929'.;Currently 24.4' below the line, 7.8' right. 100% in zone.;Daily losses to well, 0 bbls drlg mud for total= 0 bbls Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total= 190 bbls.;Hauled 300 bbls from 6 mile lake for total= 2390 bbls Hauled 171 bbls to G & I, bbls for total= 1005 12/26/2016 POH on elevators f/ 6929' to 277. Monitor Well @ BHA. Well Static.;Set back HWDP+Jars+NMFC. Remove corrosion ring.;Plug in to ADR and Download MWD Data.;Break off bit, UD Geo Pilot. UD TM Collar. Stage new Geo Pilot on skate. Bit Graded 0-1. In gauge with 1 chipped cutter.;P/U and M/U new Geo -Pilot and rerun bit. P/U and M/U TM Collar and Upload @ ADR.;Clean rig floor areas while continue to upload ADR.;M/U 1 jt HWDP, jars, 1 jt HWDP, TIH to 1220', surface test MWD and break in geo pilot.; RIH f/ 1220' to 7508' just above window, fill pipe @ 3700', test geo pilot and MWD tools, good. Correct displacement on trip to window.; Circulate BU 290 gpm, 1700 psi, test geo pilot and MWD tools, good. Blow down top drive, install FOSV, Monitor well for 10 min, static. PU/SO/ROT 102/58/73.;PJSM, close annular, weld draworks drum kickplate in place on DS of drum per manufacturers recommendations. Test run, drlg line spooling correctly, check f/ pressure, open annular;RIH on elevators f/ 7508', pass thru window @ 7573'w/ no issues, RIH to 8329'. Note: take check shot survey @ 8269'= 285.65 deg az, 88.52 deg inc. BD TD.;RIH on elevators f/ 8329' to 11534', fill pipe as needed f/ 9857' to obtain enough S/O wt to RIH, ream std 180, tag bttm @ 11616', no fill. PU/SO/ROT 130/35/82, 200 gpm, 60 rpm, TQ off 11.5k.;Note: correct displacement on trip in. Off unplanned DHT failure @ 03:30.;Drlg f/ 11616' to 11710' (94) AROP 37.6 FPH, max gas @ BU 1450u, 221 gpm, 1530 psi, 2-4k wob, 120 rpm, 10.9k tq. PU/SO/ROT 130/35182, MW in/out 9.1 vis 47/47, ECD 11.6.;Last survey 11582.84'= 91.49 inc, 268.85 az, 24.1' below the line, 8.8' right.; Daily losses to well, 0 bbls drlg mud for total= 0 bbls Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total= 190 bbls.;Hauled 150 bbls from 6 mile lake for total= 2540 bbls Hauled 57 bbls to G & I, bbls for total= 1062 12/27/2016 Drlg ahead F/ 11,742'- T/ 12,062' MD. 120 rpm, 11.2k tq, 2-8k wob, 220 gpm, 1575 psi, 11.4 ECD. 122k up, 35k dn, 69k rot.;Drlg ahead F/ 12,062'- T/ 12,248' MD. 120 rpm, 11.5-12k tq, max wob 8k, 220 gpm, 1550 psi, 11.4 ECD. 122k up, 35k dn, 69k rot.;Wash and ream F/ 12225' - T/ 12248' MD to reduce inclination as per geo.;Ddg ahead F/ 12,248'- T/ 12,695' MD / 3,629' TVD. 80 rpm, 12.5k tq, 3-6k WOB, 180 gpm, 1203 psi, 40% flow w/ 9.1 MW, 11.4 ECD. 126k up, 35k dn, 71 k rot.;Wash and ream F/ 12,694'- T/ 12,670' MD to reduce high dogleg (18°/100')indicated by ABI. Wash and ream @ 250 gpm, 1810 psi, 80 rpm, 12k tq.;Ddg ahead F/ 12,695'- T/ 12,909' MD / 3618' TVD. 80 rpm, 12.5k tq, 3-6k WOB, 180 gpm, 1203 psi, 40% flow w/ 9.1 MW, 11.6 ECD. 126k up, 35k dn, 71 k rot.;Last survey @ 12778' MD / 3,618' TVD - 92.1* Inc, 269° Az. 21' Right of plan and currently in middle of NB sand matching dip @ 92°. Crossed fault (throw - 4' DTE).; Daily losses to well, 0 bbls drlg mud for total= 0 bbls Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total= 190 bbls. Hauled 171 bbls to G&I for total = 1233 bbls;Hauled 300 bbls water from 6 mile lake for total = 2840 bbls. 12/28/2016 Drlg ahead F/ 12,919'- T/ 13020' MD. 80 rpm, 12.5k tq, 2-8k WOB, 220 gpm, 1600 psi, 40% flow w/ 9.1 MW, 11.6 ECD. 126k up, 35k dn, 71k rot.;Ream out 15.2 deg dog leg with drilling parameters f/12982'-13020'. Reduced dog leg to 9.5 deg.;Drlg ahead F/ 13020'- T/ 13113' MD. 80 rpm, 12.5k tq, 2-8k WOB, 220 gpm, 1600 psi, 40% flow w/ 9.1 MW, 11.6 ECD. 126k up, 35k dn, 71 k rot.;Ream out 15.2 deg dog leg with drilling parameters (/13100'-13112'.;Drlg ahead F/ 13113'- T/ 13162' MD /. 120 rpm, 12.7k tq, 2-8k WOB, 220 gpm, 1625 psi, 40% flow w/ 9.1 MW, 11.6 ECD. 132k up, 35k dn, 70k rot. Increase lubes to 2.5%.;Ream out 24.5 dog leg with drilling parameters f/13115 - 13145' MD to sub 15° dog leg indicated by ABI.;Drlg ahead F/ 13,162'- T/ 13,227' MD / 3,607' TVD. 80 rpm, 12.5k tq on, 12.1k tq off, 2-8k WOB, 180 gpm, 1288 psi, 37% flow w/ 9.1 MW, 11.5 ECD. 132k up, 35k dn, 70k rot. Maintain lubes @ 2.5%.;Drlg ahead F/ 13,227' - T/ 13,360' MD / 3,607' TVD. 80 rpm, 13.3k tq on, 12.8k tq off, 6-9k WOB, 180 gpm, 1409 psi, 37% flow w/ 9.1 MW, 11.6 ECD. 132k up, 35k dn, 71k rot. Maintain lubes @ 2.5%.; Last survey @ 13219' MD / 3,608' TVD - 89° Inc, 264` Az. 4' Right of plan and currently @ base of NB sand. Dip est @ 92°. Max gas last 24 hrs was 1385 units. Pumped 20/20 hi/lo sweep @ 12,920' MD;50% increase in cuttings from sweep.;Daily losses to well, 0 bbls ddg mud for total= 0 bbls Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total= 190 bbls. Hauled 57 bbls to G&I for total = 1290 bbls;Hauled 150 bbls water from 6 mile lake for total = 2990 bbls;AOGCC notified of upcoming BOP test via email for 22:00 12/29/2016 12/29/2016 Drlg ahead F/ 13,360'- T/ 13,402' MD / 3,602' TVD. 80 rpm, 13.3k tq on, 12.8k tq off, 6-9k WOB, 180 gpm, 1409 psi, 37% flow w/ 9.1 MW, 11.6 ECD. 132k up, 35k dn, 71 k rot. Maintain lubes @ 2.5%.;Geologist call TD @ 13,402'. Current BHL appears to be 10' below the NB base and 12' right of plan -- Fault at 13322' -10 to 12' DTE - estimated local formation dip is 92.5°.;last Survey: 13327.91'MD/3606.67'TVD/92.97°inc/263.23°azi.;CBU x2 from 13,402' working pipe w/150 RPM/12K Tq/290 gpm/2775 psi/PU 136K/SO 35K/Rot 70K. ECD 12.6. 50% increase on shakers @ 1st circulation, cleaned up on 2nd bottoms up. All fine sands.;Back Ream Out of hole from 13400'- T/ 8014' MD. w/100 RPW290 GPM. @ 13390'-Rt Wt 71K, 290 GPM/2800 PSI, 100 RPM/12K Tq. @ 8204' - Rt Wt 66K, 290 GPM/1750 PSI, 100 RPM/8.7K Tq ECD 11.2.;Pump 20 bbls Low Vis sweep and chase with 20 bbls Hi Vis Sweep @ 290 GPM/1730 PSi, 150 RPM/8.3K Tq. 100% increase in cuttings. Sweep on time. 11.1 ECD's. (2x) STS circulated.; B/D TDS. Lineup on trip tank and pull on elevators F/ 8014'- T/ 7430' MD. Clean through window (no issues). Hole took proper displacement. 116k up, 60k dn.;WU BOT RTVBL-TS 3T storm packer. RIH 100'f/ surface and set. B/O @ packer valve while trying to release. Pull packer to surface and redress. RIH, set 100' from surface with no issues, bit @ 7530'.; Pullout of hole w/ running tool and UD same. psi test packer to 1000 psi / 10 min hold (ok).;Pull wear bushing. Set test plug and R/U BOP test equipment. Flood stack, manifold and associated lines. Purge air. Test BOP equipment 250/3000 w/ 5 min hold. Test annular 250/2500 w/ 5 min hold.;Chart and record same. AOGCC waived witness by Lou Grimaldi. Drawdown - 3000 start, 1750 drawdown, 200 psi inc (20 sec), Full charge (69 sec). 2308 psi 6 bottle avg.;Test annular, UPR, LPR, IBOP, Dart, Kill HCR, Kill Manual, Choke HCR, Choke Manual, CM valves 1-15. Tested upr/lpr/annular w/ 4" and 4.5" test jts.;Daily losses to well, 0 bbls ddg mud for total= 0 bbls Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total= 190 bbls. Hauled 114 bbls to G&I for total = 1404 bbls;Hauled 150 bbls water from 6 mile lake for total = 3140 bbls Hilcorp Energy Company Composite Report Well Name: MP J -24A Field: Milne Point County/State: , Alaska (LAT/LONG): oration (RKB): API #: Spud Date: Job Name: 1511740C MP J -24A COMPLETION Contractor AFE #: AFE $: Activity Date Ops Summary 12/30/2016 Test PVT and Gas alarms. Rig down and lay down BOP Test equipment. Set Wear Rig. Blow down Surface/Test Equipment.,PJSM, PU RTTS running tool. RIH on 1 stand and retrieve RTTS. Lay down RTTS Tools.,CBU @ 290 GPM/1710 PSI, 150 RPM/8K Tq. Monitor Well -Static. Pump 25 bbls slug. Drop 2" Drift down DP. Blow down Top Drive.,TOH on elevators from 7450' to BHA (277').,Lay down BHA to ADR. Plug in and down load MWD. Continue to L/D BHA as per Sperry rep.,M/U and set BK 1 std HWDP. Clean and clear rig floor. Mob Weatherford casing tools to rig floor. Tear down MP#1 for fluid end replacement. Stage and spot liner jewelry in shed., Bring XO's to rig floor and M/U on TIW. M/U handling sub w/ swivel to liner hanger w/ pup extension. Rack back same. R/U Weatherford power tongs and test run (ok). Continue clean pits. Offload excess mud from pits. Onload brine into pits for completion operations.,Continue working on MP #1 replacing fluid ends. Flush pits and lines with brine.,PJSM, Run 4.5' HTTC, L-80, 13.5# liner as per detail F/ surface to 2854' MD. Fill on the fly w/ brine, top off every 15 jts for displacement. Adjust link tilt on bails after first 3 jts (good). 8100 ft/lbs tq. Running order qc'd by WOT rep & BOT rep along with drill crew and DSM,WIV set w/ (2) pins @ 1100 psi. 170 jts total 4.5" HTTC in shed prior to start of job (136 jts to be run).,Weatherford double stack tongs failed. Internal hydraulic valve bank. Unable to reach proper tq on connections. C/O power tongs and continue running pipe with no issues., Continue running liner F/ 2,854' - T/ 4300' MD. Hole took proper displacement for trip thus far.,Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total = 190 bbls Hauled 704 bbls to G&I for total = 2108 bbls Hauled 0 bbls water from 6 mile Ik for total = 3140 bbls 12/31/2016 Continue run 4.5" HTTC, 13.5#, L-80 liner F/ 4,868'- T/ 6,074' MD. 77k up, 55k dn.,R/D 4.5" handling equipment. R/U 2-3/8" handling equipment. M/U safety valve on floor. Run 2-3/8" inner string (195 jts, 8' and 1 p pups . Space out inner string, no-go @ 6,037' MD. 56k up, 44k dn.,R/D 2-3/8" handling equipment. IV P/U and M/U liner hanger. M/U and load pal mix. R/U handling equipment for 4" drill pipe. Ready safety valve for 4" drill pipe.,Run liner on drill pipe out of derrick F/ 6119'- T/ 7502' MD.,VFD threw fault (Ramp fail / Insufficient lube). Call Varco Tech and troubleshoot issues. Reset VFD. Rotate and warm lube oil. TDS (Good).,Obtain parameters @ 7502' MD. 1 bpm/230 psi, 1.5 bpm/518 psi, 2 bpm/793 psi. 5 rpm/9.1 k tq, attempt to rotate @ 10 rpm but stalled @ 10k tq. 115k up, 66k dn, 85k rot.,Continue running 4.5" liner F/ 7,502'- T/ 10207' MD. No issues exiting window. Lost string wt @ 10207' MD. Well showing 8 bbl loss for liner trip to 10,207' MD.,Rotate do w/ liner F/ 10,207'- T/ 11,274' MD. 5-10 rpm, 6-9k tq @ 60-80 ft/min. Fill pipe every 30 stds.,Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total = 190 bbls Hauled 48 bbls to G&I for total = 2156 bbls Hauled 150 bbls water from 6 mile Ik for total = 3290 bbls 1/1/2017 Continue to rotate liner down from 11274'to 11,900'. Wash/Ream liner from 11,900 - 13,400'. Lose Dn Wt and Push to bottom f/12,400'. PUH and park @ 13388', placing [CD's/Swell PKRs on depth as per tally. TOL @ 6106'. Parameters : 10 RPM/9-12K Tq, 1.5 BPm/785 PSI, PUW 130K, @ 13,388'., Displace mud w/ 9.1 ppg 3% KCL brine.R/U and break circulation. Lead w/ 40 bbl hi vis sweep, Follow w/ Follow w/ 40 bbl sapp pill, 40 bbl Brine, 40 bbl Sapp Pill.Circulate on depth @ 3 bpm, 1980 psi, . Continue to Displace mud w/ 9.1 ppg 3% KCL brine.,Saw moderate wall cake across shakers after last Sapp pill was circulated out of hole. Circulated a total of 620 bbls.,Shut down pumps. B/O std and drop 1.45" phenolic ball. Pump ball on seat @ 3.5 bpm/1950 psi to 750 stks. Reduce rate to 2 bpm / 1090 psi. Bumped @ 1270 stks (1510 stks calculated). Psi up 2900, S/O to 35k. PSI up 3900 psi w/ 5 min hold. Bleed to 0. P/U to 163k (no release).,S/O to 35k. PSI up 4000. Bleed to 0. P/U to 170k (no release). Repeat sequence using 4500 psi and again @ 5000 psi with same results (no release).,Close annular and attempt to psi test liner top via annulus. Pump 2 bbls away @ .5 bpm w/ max psi of 340 psi. Shut down and verify lineup. Saw 90 psi drop over 5 min while checking surface equipment. Pump @ 1 bpm for another 2 bbl loss w/ psi leveling off @ 450 psi. Shut down pumping.,Repeat release sequence with max up wt 173k and 5000 psi (no release).,B/D TDS. Troubleshoot and discuss options with onsite BOT rep and BOT supervisor in Prudhoe.,M/U TDS, P/U to 193k with breakover back to 165k. S/O to 35k. Lost 2.5' of hole. P/U and broke over @ 180k. S/O to 35k and lost another 1.4' of hole (4' total). Attempt left hand release. Max left hand tq @ 9500 ft/lbs w/ 9 wraps. Broke out @ top drive.,Lineup and attempt to release hanger. Release sequence 5000 psi. Work pipe w/ psi. Bleed to 0 psi. P/U to 190k and broke over to 163k. S/O to 45k and attempt to pt liner top via annulus (no test). Pump a total of 5.2 bbls away @ 1 bpm, 450 psi. Bleed to 0 psi.,Discuss options with BOT management. Discuss options and plan forward with completion engineer.,P/U 10' and attempt to disengage slick stick from packoff sub if liner is released (no go). Rotate @ 10 rpm, w/ tq dropping to 7.3k. Work pipe while rotating. Shut down and repeat left hand safety release procedure. P/U wt now 122k (liner set and released). Lineup and attempt liner top test (no test).,Stand back one std to disengage slick stick from packoff sub. Establish circulation. Displace 2-3/8" x 4.5" liner with 9.1 ppg filtered brine. 170 gpm, 3,400 psi, 29% flow.,Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total = 190 bbls Hauled 731 bbls to G&I for total = 2887 bbls Hauled 75 bbls water from 6 mile Ik for total = 3365 bbls 1/2/2017 Continue circulate and condition filtered brine inside 4.5" liner. 168 gpm/3300 psi. B/D TDS and monitor well (2.5 bph static loss rate).,POOH F/ 13,372' - T/ 6050' MD. Inspect LRT. LRT was not Left hand released. LRT indicated that hanger was hydraulically set. Sent LRT to Baker shop for further investigation.,PJSM, UD LRT and R/U to UD 2-3/8" inner string. M/U safetyvalve. R/U WOT casing., Rig Service. Grease TDS, Blocks and drawworks.,POOH F/ 6050'- T/ surface laying down 2-3/8" inner string (195 jts).,Clean and Clear rig floor. R/D WOT casing and UD same. Bring seal assy w/ dog sub and bumpers to rig floor. Seal assy showed damage to seals. BOT recommended changing out., Inspect and service rig handling equipment. Prep shaker and stage material. Inspect mud pumps and ready for cleanup cycle. Wait on replacement seal assy.,M/U new 5.25" seal assy w/ mule shoe, spacer, dog sub, bumpers and xo (29.43' length). Trip in hole T/ 6696' MD. P/U HWDP and trip in from shed F/ 6,696' to tag depth of 7275' MD (10' seals to No -Go). Moderate set down 31k on liner top (5x). TOL @ 7265', 4.5" liner shoe @ 13,372' MD.,14 bbl under calc disp for trip in. 112k up, 66k dn. Trip drill @ 600' MD w/ 41 sec response time for well secure.,Close annular and test liner top via annulus. .6 bpm, to 1500 psi w/ 10 min hold (test good). Chart and record same. 1 bbl pumped, 1 bbl bled back.,POOH T/ 7,260' MD. Circulate 7" casing clean just above TOL. 310 gpm / 1020 psi, 46% flow, 20 rpm, 7k tq. 14 bbl loss for cleanup cycle. Circulated 2x btms up total., B/D TDS. POOH laying down HWDP F/ 7,260'- T/ 6,696' MD.,Cut and slip drilling line (98' cut length)., POOH F/ 6,696' - T/ 6,506' MD laying down 4" drill pipe. Static losses @ 6 BPH.,Hauled 0 bbls to B-50 for total= 580 bbls Hauled 0 bbls to ORT for total = 190 bbls Hauled 1042 bbls to G&I for total = 3929 bbls Hauled 400 bbis water from 6 mile lake for total = 3765 bbls 45 bbl daily loss for total = 45 bbls loss to formation 1/3/2017 Continue pull out of hole laying down 4" drill pipe F/ 6506'- T/ seal (dog sub) assy. L/D same.,Prep floor. RIH out of derrick with remaining stds drill pipe T/ 7000' MD. Hole @ 5 bph static loss rate.,Service rig. C/O make up cathead cable. Adjust wt buckets for tongs. Grease Blocks, TDS, drawworks and laydown machine.,Pull out of hole laying down 4" drill pipe F/ 7000' to surface. Pull wear bushing. Monitor well (5-6 bph static losses).,Clean and clear rig floor. Bring casing running equipment to floor. R/U Weatherford Casing. Load and tally 4.5" completion string in shed. Stage jewelry on floor.,PJSM, Run 4.5", 12.6#, L-80 Supermax completion string as per detail F/ surface to 4248' MD. M/U bullet nose (5.20" bullet nose OD) seal assy. 3 jts tbg, "XN" w/ 3.813" profile (RHC loaded). Continue with tubing to current depth of 4248' MD. P/U GLM, OD 6.625" (no go). Discuss with completion engineer. L/D GLM and continue running without.,Hauled 0 bbls to B-50 for total = 580 bbls Hauled 0 bbls to ORT for total = 190 bbls Hauled 1042 bbls to G&I for total = 3929 bbls Hauled 150 bbls water from 6 mile lake for total = 3915 bbls 119 bbl daily loss for total = 164 bbls loss to formation 1/4/2017 P/U 4.5 Tubing F/ 4250'T/ 7262'. P/U Joint 228. Pump down 2 bpm 60 psi. See seals engage @ 7268'. Shut down pump. Bleed off Pressure. NO Go out @ 7277'. P/U to up wt Plus 2'. Up/Dn 88K/58K Close annular and pressure test annulus to 500 psi for 5 min. Good. Bleed down. Open annular. L/D Joint 228, 227 & Joint 226'. P/U Pups 9.1' , 4.03 for space out. Run Joint 226. M/U 4.07 XO pup .,Blow down TD. Change handling equipment to 4". P/U landing joint and XOs. M/U hanger & Pup to string. RIH & sting in to LT with shoe leaving port open.,Wait on LRS change out before starting Corrosion inhibitor & Freeze protecting the annulus. Plane Delayed. Work on housekeeping & R/D Prep. Remove mouse hole & UD Same.,Pump 78 bbl 1 %Baricor 9.1 ppg Brine down the annulus taking returns up the tubing. Line up LRS & pump 51 bbl @ 2 bpm. FCP 280 psi. Barracor spotted F/ 3000'T/ 7265'. Diesel spotted Surface T/ 3000',Slack off and engage seals closing off port. Bleed lip down annulus and drain stack. Open annular. Land hanger. Well Head Specialist verify Good. RILDS. Blow down Surface equipment. l"\ LRS Test annulas to 3000 psi for 30 min while monitoringtubing. Pressure up to 3109 psi. Bled down to 3044 psi in the first 15 min. Bled to 3033 psi in the last 1,1615 min. Tubing @ 0 psi during.,Rig down LRS and secure well. Break out landing joint from top drive and drop 1.875" ball and rod w/ 1 set rollers down tubing. R/U and test 4.5", 12.6#, L-80 SuperMax production tubing. Pump 1 bbl @ .6 BPM to 2500 psi. Shut in and chart w/ 30 min hold. Bled down to 2495 in 15 min, Final psi 2490. Bled back 1 bbl. R/D test equipment.,B/O landing joint and laydown same. Blowdown top drive back to pumps and clear lines. Install TWC. Sent MIT form 10-426 to AOGCC.,Nipple down BOP equipment. Nipple up wellhead equipment. Remove pitcher nipple, R/D fill and bleeder lines. Place choke and kill in open. Bleed down Koomey unit. R/D choke and kill lines. N/D stack and set back on mob stump. R/D DSA & stage in cellar.,N/U dry hole tree. Test hanger void 500/5000 w/ 5/15 min hold (test good). Continue cleaning pits in preparation for upcoming gravel pack.,Stage Hydraulic plate cover in shed. Clean cellar and secure wellhead for handover to production. Grease choke manifold, Continue cleaning in pits. R/D MP #1- Drain and inspect. PJSM, bridle up, prep derrick to scope. Secure lines. R/D tongs and derrick board. Disconnect escape and wt bucket Iines.,Hauled 0 bbls to B-50 for total = 580 bbis Hauled 0 bbls to ORT for total = 190 bbls Hauled 1042 bbls to G&I for total = 3929 bbls Hauled 150 bbls water from 6 mile lake for total = 4015 bbls 111 bbl daily loss for total = 275 bbls loss to formation Hilcorp Alaska, LLC Milne Point M Pt J Pad MPJ -24A MPU J -24A 50-029-22976-01-00 Sperry Drilling Definitive Survey Report 03 January, 2017 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPJ -24 Project: Milne Point TVD Reference: Actual:J-24A @ 62.34usft Site: M Pt J Pad MD Reference: Actual:J-24A @ 62.34usft Well: MPJ -24 North Reference: True Wellbore: MPJ -24A Survey Calculation Method: Minimum Curvature Design: MPJ -24A Database: Sperry EDM - NORTH US + CANADA Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well - MPJ -24 - - Well Position +N/ -S 0.00 usft Northing: +E/ -W 0.00 usft Easting: LPosition Uncertainty 0.00 usft Wellhead Elevation: Wellbore MPJ -24A Magnetics Model Name Sample Date BGGM2016 12/15/2016 Design MPJ -24A Audit Notes: Version: 1.0 Phase: Vertical Section: Depth From (TVD) (usft) Survey Program Date 1/3/2017 From To 6,015,110.45 usft Latitude: 551,914.26 usft Longitude: usft Ground Level: Declination V) 17.95 ACTUAL +N/ -S (usft) 0.00 70° 27' 7.288 NII 149° 34'35.085 W 36.30 usft Dip Angle Field Strength V) (nT) 81.04 57,557 Tie On Depth: 7,496.88 +E/ -W Direction (usft) (I 0.00 284.00 (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 110.28 7,496.88 MPJ -24 mwd (MPU J-24) MWD MWD v3:standard declination 10/21/2000 7,560.00 8,000.48 MWD_Interp Azi+sag (MPJ -24A) MWD_Interp Azi+sag Fixed:v2:std dec with interpolated azimuth + sag 12/10/2016 8,062.30 13,327.91 MWD+IFR2+MS+Sag (MPJ -24A) MWD+IFR2+MS+sag Fixed:v2:IIFR dec & 3 -axis correction + sag 12/23/2016 0.06 -0.02 MWD (1) 201.94 0.18 -- 201.94 139.60 Map Map Vertical 6,015,110.25 MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting OLS Section 0.16 (usft) (I V) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.04 0.00 0.00 26.04 -36.30 0.00 0.00 6,015,110.45 551,914.26 0.00 0.00 UNDEFINED 110.28 0.05 153.27 110.28 47.94 -0.03 0.02 6,015,110.42 551,914.28 0.06 -0.02 MWD (1) 201.94 0.18 153.27 201.94 139.60 -0.20 0.10 6,015,110.25 551,914.36 0.14 -0.14 MWD (1) 292.36 0.16 212.94 292.36 230.02 -0.43 0.09 6,015,110.02 551,914.36 0.19 -0.20 MWD (1) 322.45 0.62 256.79 322.45 260.11 -0.50 -0.09 6,015,109.95 551,914.18 1.72 -0.04 MWD (1) 415.86 2.94 278.04 415.81 353.47 -0.28 -2.95 6,015,110.15 551,911.31 2.54 2.80 MWD (1) 508.50 5.65 276.73 508.18 445.84 0.58 -9.83 6,015,110.97 551,904.42 2.93 9.68 MWD (1) 600.09 8.54 288.71 599.06 536.72 3.29 -20.76 6,015,113.60 551,893.48 3.53 20.94 MWD (1) 694.63 10.89 295.67 692.24 629.90 9.42 -35.46 6,015,119.62 551,878.74 2.77 36.68 MWD (1) 786.84 13.70 297.54 782.33 719.99 18.24 -52.99 6,015,128.32 551,861.15 3.08 55.83 MWD (1) 878.51 16.30 296.27 870.87 808.53 28.95 -74.16 6,015,138.88 551,839.91 2.86 78.96 MWD (1) 971.15 18.78 292.76 959.20 896.86 40.48 -99.57 6,015,150.23 551,814.42 2.91 106.41 MWD (1) 1/3/2017 12:27:22PM Page 2 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPJ -24 Project: Milne Point TVD Reference: Actual:J-24A @ 62.34usft Site: M Pt J Pad MD Reference: Actual:J-24A @ 62.34usft Well: MPJ -24 North Reference: True Wellbore: MPJ -24A Survey Calculation Method: Minimum Curvature Design: MPJ -24A Database: Sperry EDM - NORTH US + CANADA Survey 1/3/2017 12:27:22PM Page 3 COMPASS 5000.1 Build 81 Map Map Vertical MD Inc Az1 TVD NDSB +N/ -S +E/.W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/too) (ft) Survey Tool Name 1,063.31 21.99 289.23 1,045.58 983.24 51.91 -129.55 6,015,161.45 551,784.36 3.73 138.26 MWD (1) 1,158.27 24.62 292.07 1,132.79 1,070.45 65.20 -164.68 6,015,174.49 551,749.15 3.01 175.56 MWD (1) 1,251.11 28.14 290.48 1,215.95 1,153.61 80.13 -203.12 6,015,189.15 551,710.61 3.87 216.47 MWD (1) 1,343.06 31.83 290.03 1,295.58 1,233.24 96.02 -246.23 6,015,204.75 551,667.39 4.02 262.14 MWD (1) 1,435.37 35.60 288.79 1,372.35 1,310.01 113.02 -294.55 6,016,221.41 551,618.96 4.15 313.14 MWD(1) 1,527.63 36.64 290.02 1,446.87 1,384.53 131.10 -345.84 6,015,239.12 551,567.55 1.37 367.28 MWD (1) 1,620.50 40.69 288.11 1,519.37 1,457.03 150.00 -400.68 6,015,257.64 551,512.59 4.55 425.06 MWD (1) 1,714.15 42.09 289.35 1,589.63 1,527.29 169.89 -459.31 6,015,277.12 551,453.82 1.73 486.77 MWD (1) 1,805.92 44.88 289.23 1,656.21 1,593.87 190.75 -518.91 6,015,297.56 551,394.08 3.04 549.65 MWD (1) 1,902.30 46.30 291.66 1,723.66 1,661.32 214.81 -583.41 6,015,321.17 551,329.43 2.33 618.05 MWD (1) 1,993.94 48.37 291.57 1,785.76 1,723.42 239.63 -646.05 6,015,345.55 551,266.62 2.26 684.83 MWD (1) 2,085.98 49.88 290.78 1,845.99 1,783.65 264.77 -710.95 6,015,370.23 551,201.56 1.76 753.88 MWD (1) 2,179.01 51.00 290.99 1,905.24 1,842.90 290.34 -777.95 6,015,395.33 551,134.38 1.22 825.09 MWD (1) 2,271.41 55.12 292.72 1,960.76 1,898.42 317.85 -846.47 6,015,422.36 551,065.68 4.70 898.22 MWD (1) 2,362.91 59.53 294.20 2,010.15 1,947.81 348.52 -917.09 6,015,452.54 550,994.85 5.01 974.17 MWD (1) 2,456.88 63.63 291.82 2,054.87 1,992.53 380.79 -993.15 6,015,484.27 550,918.58 4.90 1,055.77 MWD (1) 2,549.64 67.07 294.46 2,093.56 2,031.22 413.94 -1,070.64 6,015,516.88 550,840.86 4.52 1,138.98 MWD (1) 2,643.61 70.11 293.39 2,127.86 2,065.52 449.40 -1,150.60 6,015,551.78 550,760.67 3.40 1,225.15 MWD (1) 2,762.85 69.67 294.07 2,168.85 2,106.51 494.46 -1,253.11 6,015,596.12 550,657.86 0.65 1,335.50 MWD (1) 2,855.63 70.37 291.71 2,200.56 2,138.22 528.37 -1,333.43 6,015,629.47 550,577.31 2.51 1,421.65 MWD (1) 2,948.43 72.19 293.44 2,230.34 2,168.00 562.11 -1,414.58 6,015,662.64 550,495.94 2.64 1,508.55 MWD (1) 3,039.38 72.26 290.95 2,258.11 2,195.77 594.83 -1,494.76 6,015,694.79 550,415.54 2.61 1,594.26 MWD (1) 3,127.43 71.98 287.16 2,285.16 2,222.82 622.18 -1,573.95 6,015,721.59 550,336.17 4.11 1,677.71 MWD (1) 3,222.49 71.17 287.29 2,315.20 2,252.86 648.89 -1,660.09 6,015,747.69 550,249.85 0.86 1,767.76 MWD (1) 3,314.92 70.34 287.25 2,345.67 2,283.33 674.79 -1,743.42 6,015,773.02 550,166.35 0.90 1,854.88 MWD (1) 3,411.96 71.34 289.17 2,377.52 2,315.18 703.44 -1,830.49 6,015,801.05 550,079.10 2.13 1,946.29 MWD (1) 3,501.62 71.89 290.04 2,405.80 2,343.46 731.99 -1,910.63 6,015,829.04 549,998.76 1.11 2,030.97 MWD (1) 3,594.59 69.40 291.40 2,436.61 2,374.27 763.01 -1,992.67 6,015,859.49 549,916.51 3.01 2,118.07 MWD (1) 3,686.67 69.08 290.49 2,469.25 2,406.91 793.79 -2,073.08 6,015,889.71 549,835.90 0.99 2,203.54 MWD (1) 3,779.95 70.70 290.60 2,501.32 2,438.98 824.53 -2,155.10 6,015,919.87 549,753.68 1.74 2,290.56 MWD (1) 3,869.27 73.75 291.51 2,528.58 2,466.24 855.09 -2,234.47 6,015,949.87 549,674.11 3.55 2,374.96 MWD (1) 3,967.34 72.92 291.72 2,556.71 2,494.37 889.70 -2,321.81 6,015,983.87 549,586.53 0.87 2,468.08 MWD (1) 4,056.55 72.34 292.16 2,583.34 2,521.00 921.51 -2,400.78 6,016,015.12 549,507.35 0.80 2,552.40 MWD (1) 4,152.62 72.12 292.00 2,612.66 2,550.32 955.90 -2,485.56 6,016,048.92 549,422.34 0.28 2,642.98 MWD (1) 4,246.93 71.27 292.36 2,642.28 2,579.94 989.70 -2,568.47 6,016,082.14 549,339.20 0.97 2,731.61 MWD (1) 4,339.55 71.13 292.98 2,672.13 2,609.79 1,023.49 -2,649.38 6,016,115.36 549,258.07 0.65 2,818.29 MWD (1) 4,431.31 71.14 292.95 2,701.80 2,639.46 1,057.37 -2,729.33 6,016,148.68 549,177.90 0.03 2,904.06 MWD (1) 4,526.79 71.38 290.42 2,732.48 2,670.14 1,090.78 -2,813.34 6,016,181.50 549,093.66 2.52 2,993.65 MWD (1) 4,619.67 71.42 290.97 2,762.10 2,699.76 1,121.89 -2,895.69 6,016,212.03 549,011.11 0.56 3,081.08 MWD (1) 4,712.64 71.42 291.07 2,791.72 2,729.38 1,153.50 -2,977.95 6,016,243.06 548,928.64 0.10 3,168.54 MWD (1) 1/3/2017 12:27:22PM Page 3 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report 1/312017 12:27.22PM Page 4 COMPASS 5000.1 Build 81 Company: Hilcorp Alaska, LLC Local Coordinate Reference: Well MPJ -24 Project: Milne Point TVD Reference: Actual:J-24A @ 62.34usft Site: M Pt J Pad MD Reference: Actual:J-24A @ 62.34usft Well: MPJ -24 North Reference: True Wellbore: MPJ -24A Survey Calculation Method: Minimum Curvature Design: MPJ -24A Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +El -W Northing Easting DLS Section (usft) (°) 0 (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 4,805.37 73.90 290.09 2,819.36 2,757.02 1,184.60 -3,060.81 6,016,273.59 548,845.57 2.86 3,256.47 MWD (1) 4,898.29 74.62 290.50 2,844.57 2,782.23 1,215.63 -3,144.69 6,016,304.02 548,761.48 0.88 3,345.37 MWD (1) 4,990.81 74.94 289.68 2,868.86 2,806.52 1,246.29 -3,228.53 6,016,334.10 548,677.44 0.92 3,434.14 MWD (1) 5,083.46 74.68 289.38 2,893.13 2,830.79 1,276.18 -3,312.80 6,016,363.40 548,592.97 0.42 3,523.13 MWD (1) 5,176.16 75.19 289.88 2,917.23 2,854.89 1,306.25 -3,397.11 6,016,392.88 548,508.46 0.76 3,612.21 MWD(1) 5,268.81 75.42 289.85 2,940.73 2,878.39 1,336.71 -3,481.40 6,016,422.74 548,423.97 0.25 3,701.36 MWD (1) 5,360.11 73.59 289.59 2,965.12 2,902.78 1,366.39 -3,564.22 6,016,451.85 548,340.96 2.02 3,788.90 MWD (1) 5,454.30 73.75 289.51 2,991.60 2,929.26 1,396.64 -3,649.39 6,016,481.50 548,255.58 0.19 3,878.87 MWD (1) 5,546.73 73.29 289.15 3,017.82 2,955.48 1,425.98 -3,733.03 6,016,510.25 548,171.75 0.62 3,967.12 MWD (1) 5,640.88 73.18 289.39 3,044.98 2,982.64 1,455.73 -3,818.13 6,016,539.40 548,086.45 0.27 4,056.89 MWD (1) 5,730.20 74.14 288.67 3,070.11 3,007.77 1,483.67 -3,899.15 6,016,566.78 548,005.24 1.32 4,142.27 MWD (1) 5,825.31 74.93 289.32 3,095.47 3,033.13 1,513.51 -3,985.83 6,016,596.01 547,918.37 1.06 4,233.58 MWD (1) 5,916.96 73.20 289.00 3,120.63 3,058.29 1,542.44 -4,069.07 6,016,624.35 547,834.94 1.92 4,321.35 MWD (1) 6,013.42 70.91 288.77 3,150.35 3,088.01 1,572.14 -4,155.89 6,016,653.45 547,747.92 2.38 4,412.78 MWD (1) 6,106.16 70.56 288.43 3,180.95 3,118.61 1,600.06 -4,238.87 6,016,680.79 547,664.76 0.51 4,500.04 MWD (1) 6,198.82 70.16 287.95 3,212.09 3,149.75 1,627.30 -4,321.77 6,016,707.45 547,581.67 0.65 4,587.08 MWD (1) 6,291.30 70.55 287.78 3,243.18 3,180.84 1,654.02 -4,404.67 6,016,733.59 547,498.60 0.46 4,673.98 MWD (1) 6,383.97 71.73 287.59 3,273.14 3,210.80 1,680.66 -4,488.22 6,016,759.64 547,414.88 1.29 4,761.49 MWD (1) 6,476.24 72.16 287.75 3,301.74 3,239.40 1,707.29 -4,571.81 6,016,785.68 547,331.11 0.49 4,849.04 MWD (1) 6,56281 71.97 288.94 3,329.94 3,267.60 1,734.71 -4,654.50 6,016,812.52 547,248.24 1.25 4,935.90 MWD (1) 6,662.95 72.59 288.67 3,358.89 3,296.55 1,763.92 -4,740.29 6,016,841.14 547,162.26 0.71 5,026.21 MWD (1) 6,755.74 72.44 290.74 3,386.77 3,324.43 1,793.76 -4,823.60 6,016,870.39 547,078.75 2.13 5,114.27 MWD (1) 6,848.31 73.05 290.59 3,414.23 3,351.89 1,824.96 -4,906.32 6,016,901.01 546,995.82 0.68 5,202.08 MWD (1) 6,941.33 73.99 290.38 3,440.62 3,378.28 1,856.17 -4,989.87 6,016,931.64 546,912.06 1.03 5,290.70 MWD (1) 7,033.84 72.18 290.59 3,467.54 3,405.20 1,887.15 -5,072.78 6,016,962.03 546,828.95 1.97 5,378.64 MWD (1) 7,127.08 72.60 290.62 3,495.74 3,433.40 1,918.42 -5,155.97 6,016,992.72 546,745.55 0.45 5,466.92 MWD (1) 7,219.63 72.08 290.27 3,523.82 3,461.48 1,949.23 -5,238.60 6,017,022.95 546,662.72 0.67 5,554.55 MWD (1) 7,311.55 72.99 290.88 3,551.41 3,489.07 1,980.04 -5,320.69 6,017,053.19 546,580.42 1.18 5,641.66 MWD (1) 7,404.82 71.56 292.17 3,579.80 3,517.46 2,012.63 -5,403.33 6,017,085.20 546,497.56 2.02 5,729.73 MWD (1) 7,496.88 71.85 293.10 3,608.70 3,546.36 2,046.27 -5,484.00 6,017,118.27 546,416.67 1.01 5,816.14 MWD (1) 7,560.00 71.61 292.84 3,628.49 3,566.15 2,069.66 -5,539.19 6,017,141.28 546,361.32 0.55 5,875.35 MWD_1nterpAzi+sag(2) 7,621.81 74.52 291.95 3,646.49 3,584.15 2,092.19 -5,593.85 6,017,163.41 546,306.51 4.91 5,933.84 MWD_lnterpAzi+sag (2) 71684.47 77.45 291.05 3,661.67 3,599.33 2,114.46 -5,650.41 6,017,185.29 546,249.80 4.88 5,994.11 MWD _InterpAzi+sag (2) �~ 7,748.30 78.65 290.17 3,674.88 3,612.54 2,136.44 -5,708.86 6,017,206.86 546,191.21 2.31 6,056.14 MWD _InterpAzi+sag (2) 7,811.21 81.09 289.30 3,685.95 3,623.61 2,157.35 -5,767.15 6,017,227.36 546,132.78 4.11 6,117.75 MWD_InterpAzi+sag (2) 7,874.69 82.16 288.44 3,695.19 3,632.85 2,177.66 -5,826.58 6,017,247.26 546,073.22 2.15 6,180.33 MWD _InterpAzi+sag (2) 7,936.29 86.06 287.61 3,701.51 3,639.17 2,196.62 -5,884.83 6,017,265.80 546,014.84 6.47 6,241.44 MWD _InterpAzi+sag (2) 8,000.48 86.43 286.76 3,705.72 3,643.38 2,215.54 -5,946.02 6,017,284.30 545,953.52 1.44 6,305.39 MWD_InterpAzi+sag (2) 8,062.30 86.12 285.94 3,709.73 3,647.39 2,232.91 -6,005.22 6,017,301.25 545,894.21 1.42 6,367.03 MWD+IFR2+MS+sag (3) 8,125.90 87.17 285.75 3,713.46 3,651.12 2,250.24 -6,066.30 6,017,318.16 545,833.02 1.68 6,430.48 MWD+IFR2+MS+sag (3) 1/312017 12:27.22PM Page 4 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPJ -24 Project: Milne Point TVD Reference: Actual:J-24A @ 62.34usft Site: M Pt J Pad MD Reference: Actual:J-24A @ 62.34usft Well: MPJ -24 North Reference: True Wellbore: MPJ -24A Survey Calculation Method: Minimum Curvature Design: MPJ -24A Database: Sperry EDM - NORTH US + CANADA Survey 3/2017 12:27.22PM Page 5 COMPASS 5000.1 Build 81 Map Map Vertical MD Inc Azi TVD TVDSS +W -S +EI -W Northing Easting DLS Section (usft) (°) V) (usft) (usft) (usft) (usft) (ft) (ft) (°H00') (ft) Survey Tool Name 8,188.27 87.61 284.63 3,716.30 3,653.96 2,266.57 -6,126.42 6,017,334.06 545,772.79 1.93 6,492.77 MWD+IFR2+MS+sag (3) 8,250.49 90.38 284.01 3,717.39 3,655.05 2,281.95 -6,186.69 6,017,349.03 545,712.42 4.56 6,554.98 MWD+IFR2+MS+sag (3) 8,314.34 92.05 284.35 3,716.03 3,653.69 2,297.59 -6,248.58 6,017,364.23 545,650.43 2.67 6,618.81 MWD+IFR2+MS+sag (3) 8,376.53 91.74 284.49 3,713.98 3,651.64 2,313.07 -6,308.78 6,017,379.29 545,590.13 0.55 6,680.96 MWD+IFR2+MS+sag (3) 8,439.86 89.58 284.82 3,713.25 3,650.91 2,329.09 -6,370.04 6,017,394.88 545,528.76 3.45 6,744.28 MWD+IFR2+MS+sag (3) 8,502.86 89.52 285.48 3,713.74 3,651.40 2,345.55 -6,430.85 6,017,410.92 545,467.85 1.05 6,807.27 MWD+IFR2+MS+sag (3) 8,565.98 91.19 287.19 3,713.35 3,651.01 2,363.30 -6,491.42 6,017,428.24 545,407.17 3.79 6,870.33 MWD+IFR2+MS+sag (3) 8,629.42 89.52 287.16 3,712.96 3,650.62 2,382.03 -6,552.03 6,017,446.55 545,346.44 2.63 6,933.67 MWD+IFR2+MS+sag (3) 8,691.46 89.27 286.58 3,713.61 3,651.27 2,400.04 -6,611.39 6,017,464.14 545,286.95 1.02 6,995.63 MWD+IFR2+MS+sag (3) 8,754.77 89.27 287.07 3,714.42 3,652.08 2,418.36 -6,671.99 6,017,482.04 545,226.24 0.77 7,058.85 MWD+IFR2+MS+sag (3) 8,817.15 90.94 287.64 3,714.31 3,651.97 2,436.97 -6,731.52 6,017,500.23 545,166.58 2.83 7,121.12 MWD+IFR2+MS+sag (3) 8,879.50 91.74 287.59 3,712.85 3,650.51 2,455.83 -6,790.93 6,017,518.67 545,107.04 1.29 7,183.33 MWD+IFR2+MS+sag (3) 8,940.90 90.45 286.20 3,711.67 3,649.33 2,473.67 -6,849.67 6,017,536.10 545,048.19 3.09 7,244.64 MWD+IFR2+MS+sag (3) 9,004.54 91.37 285.56 3,710.66 3,648.32 2,491.08 -6,910.87 6,017,553.09 544,986.87 1.76 7,308.24 MWD+IFR2+MS+sag (3) 9,064.08 91.06 284.52 3,709.40 3,647.06 2,506.53 -6,968.36 6,017,568.13 544,929.28 1.82 7,367.75 MWD+IFR2+MS+sag (3) 9,127.02 91.06 283.66 3,708.24 3,645.90 2,521.85 -7,029.40 6,017,583.02 544,868.15 1.37 7,430.68 MWD+IFR2+MS+sag (3) 9,194.11 91.80 282.25 3,706.56 3,644.22 2,536.88 -7,094.75 6,017,597.60 544,802.69 2.37 7,497.74 MWD+IFR2+MS+sag (3) 9,257.56 89.77 281.64 3,705.69 3,643.35 2,550.01 -7,156.82 6,017,610.30 544,740.54 3.34 7,561.14 MWD+IFR2+MS+sag (3) 9,318.93 91.25 282.26 3,705.15 3,642.81 2,562.72 -7,216.86 6,017,622.58 544,680.42 2.61 7,622.46 MWD+IFR2+MS+sag (3) 9,383.40 90.26 281.79 3,704.30 3,641.96 2,576.15 -7,279.91 6,017,635.57 544,617.29 1.70 7,686.89 MWD+IFR2+MS+sag (3) 9,445.49 90.26 281.92 3,704.02 3,641.68 2,588.90 -7,340.67 6,017,647.90 544,556.44 0.21 7,748.93 MWD+IFR2+MS+sag (3) 9,508.87 89.58 281.76 3,704.10 3,641.76 2,601.91 -7,402.70 6,017,660.47 544,494.33 1.10 7,812.27 MWD+IFR2+MS+sag (3) 9,572.04 90.32 281.88 3,704.16 3,641.82 2,614.85 -7,464.53 6,017,672.98 544,432.42 1.19 7,875.39 MWD+IFR2+MS+sag (3) 9,635.14 90.26 282.61 3,703.84 3,641.50 2,628.23 -7,526.20 6,017,685.93 544,370.67 1.16 7,938.46 MWD+IFR2+MS+sag (3) 9,697.43 89.34 283.29 3,704.06 3,641.72 2,642.19 -7,586.90 6,017,699.47 544,309.87 1.84 8,000.74 MWD+IFR2+MS+sag (3) 9,760.57 90.07 283.83 3,704.38 3,642.04 2,656.99 -7,648.28 6,017,713.84 544,248.40 1.44 8,063.88 MWD+IFR2+MS+sag (3) 9,821.91 91.06 283.97 3,703.78 3,641.44 2,671.73 -7,707.82 6,017,728.16 544,188.76 1.63 8,125.21 MWD+IFR2+MS+sag (3) 9,884.21 90.38 283.75 3,703.00 3,640.66 2,686.65 -7,768.30 6,017,742.66 544,128.19 1.15 8,187.51 MWD+IFR2+MS+sag (3) 9,947.05 90.08 281.48 3,702.74 3,640.40 2,700.37 -7,829.62 6,017,755.95 544,066.78 3.64 8,250.32 MWD+IFR2+MS+sag (3) 10,009.52 90.14 278.77 3,702.62 3,640.28 2,711.36 -7,891.11 6,017,766.50 544,005.22 4.34 8,312.65 MWD+IFR2+MS+sag (3) 10,073.23 90.94 275.71 3,702.02 3,639.68 2,719.38 -7,954.30 6,017,774.09 543,941.98 4.96 8,375.90 MWD+IFR2+MS+sag (3) 10,134.77 90.94 275.38 3,701.01 3,638.67 2,725.33 -8,015.54 6,017,779.61 543,880.70 0.54 8,436.76 MWD+IFR2+MS+sag (3) 10,197.50 89.58 275.75 3,700.73 3,638.39 2,731.41 -8,077.98 6,017,785.26 543,818.23 2.25 8,498.81 MWD+IFR2+MS+sag (3) 10,260.20 91.80 277.19 3,699.97 3,637.63 2,738.48 -8,140.27 6,017,791.89 543,755.90 4.22 8,560.96 MWD+IFR2+MS+sag (3) 10,323.23 93.47 279.73 3,697.07 3,634.73 2,747.74 -8,202.54 6,017,800.71 543,693.57 4.82 8,623.63 MWD+IFR2+MS+sag (3) 10,386.08 93.16 281.10 3,693.44 3,631.10 2,759.08 -8,264.25 6,017,811.62 543,631.79 2.23 8,686.25 MWD+IFR2+MS+sag (3) 10,449.27 92.11 280.19 3,690.54 3,628.20 2,770.74 -8,326.28 6,017,822.85 543,569.68 2.20 8,749.26 MWD+IFR2+MS+sag (3) 10,513.56 91.06 276.28 3,688.76 3,626.42 2,779.94 -8,389.87 6,017,831.61 543,506.04 6.29 8,813.19 MWD+IFR2+MS+sag (3) 10,576.81 90.51 276.00 3,687.89 3,625.55 2,786.71 -8,452.75 6,017,837.93 543,443.12 0.98 8,875.84 MWD+IFR2+MS+sag (3) 10,639.83 91.68 276.36 3,686.69 3,624.35 2,793.49 -8,515.39 6,017,844.28 543,380.44 1.94 8,938.26 MWD+IFR2+MS+sag (3) 3/2017 12:27.22PM Page 5 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPJ -24 Project: Milne Point TVD Reference: Actual:J-24A @ 62.34usft Site: M Pt J Pad MD Reference: Actual:J-24A @ 62.34usft Well: MPJ -24 North Reference: True Wellbore: MPJ -24A Survey Calculation Method: Minimum Curvature Design: MPJ -24A Database: Sperry EDM - NORTH US + CANADA Survey 11312017 12:27.22PM Page 6 COMPASS 5000.1 Build 81 Map Map Vertical MD Inc Azi TVD TVDSS +N1 -S +E/ -W Northing Easting DLS Section (usft) (°) 0 (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 10,702.62 88.47 276.15 3,686.60 3,624.26 2,800.33 -8,577.80 6,017,850.68 543,317.99 5.12 9,000.47 MWD+IFR2+MS+sag (3) 10,765.26 90.69 276.20 3,687.06 3,624.72 2,807.07 -8,640.07 6,017,856.99 543,255.68 3.54 9,062.52 MWD+IFR2+MS+sag (3) 10,828.93 90.57 276.85 3,686.36 3,624.02 2,814.30 -8,703.33 6,017,863.78 543,192.38 1.04 9,125.64 MWD+IFR2+MS+sag (3) 10,892.50 90.75 276.47 3,685.63 3,623.29 2,821.67 -8,766.46 6,017,870.71 543,129.20 0.66 9,188.69 MWD+IFR2+MS+sag (3) 10,956.81 90.14 277.57 3,685.13 3,622.79 2,829.53 -8,830.29 6,017,878.13 543,065.33 1.96 9,252.52 MWD+IFR2+MS+sag (3) 11,019.34 90.63 277.08 3,684.71 3,622.37 2,837.50 -8,892.31 6,017,885.66 543,003.26 1.11 9,314.62 MWD+IFR2+MS+sag (3) 11,081.71 91.74 277.56 3,683.42 3,621.08 2,845.45 -6,954.15 6,017,893.18 542,941.37 1.94 9,376.55 MWD+IFR2+MS+sag (3) 11,145.22 91.74 278.65 3,681.49 3,619.15 2,854.40 -9,017.00 6,017,901.69 542,878.47 1.72 9,439.70 MWD+IFR2+MS+sag (3) 11,207.25 91.56 278.41 3,679.71 3,617.37 2,863.60 -9,078.32 6,017,910.46 542,817.09 0.48 9,501.42 MWD+IFR2+MS+sag (3) 11,269.79 93.41 279.02 3,676.99 3,614.65 2,873.06 -9,140.07 6,017,919.49 542,755.28 3.11 9,563.63 MWD+IFR2+MS+sag (3) 11,332.24 92.54 277.92 3,673.75 3,611.41 2,882.25 -9,201.76 6,017,928.25 542,693.54 2.24 9,625.71 MWD+IFR2+MS+sag (3) 11,395.08 91.06 276.33 3,671.78 3,609.44 2,890.04 -9,264.08 6,017,935.60 542,631.17 3.46 9,688.06 MWD+IFR2+MS+sag (3) 11,457.87 91.62 273.31 3,670.31 3,607.97 2,895.31 -9,326.62 6,017,940.44 542,568.60 4.89 9,750.02 MWD+IFR2+MS+sag (3) 11,520.60 91.19 270.46 3,668.77 3,606.43 2,897.37 -9,389.29 6,017,942.06 542,505.92 4.59 9,811.33 MWD+IFR2+MS+sag (3) 11,582.84 91.49 268.85 3,667.32 3,604.98 2,897.00 -9,451.51 6,017,941.26 542,443.71 2.63 9,871.61 MWD+IFR2+MS+sag (3) 11,643.42 90.88 269.15 3,666.06 3,603.72 2,895.94 -9,512.07 6,017,939.78 542,383.17 1.12 9,930.11 MWD+IFR2+MS+sag (3) 11,706.54 92.98 269.15 3,663.94 3,601.60 2,895.01 -9,575.14 6,017,938.40 542,320.11 3.33 9,991.09 MWD+IFR2+MS+sag (3) 11,769.95 93.53 267.64 3,660.34 3,598.00 2,893.23 -9,638.42 6,017,936.19 542,256.85 2.53 10,052.06 MWD+IFR2+MS+sag (3) 11,832.66 94.58 268.38 3,655.90 3,593.56 2,891.06 -9,700.94 6,017,933.58 542,194.36 2.05 10,112.19 MWD+IFR2+MS+sag (3) 11,895.54 93.47 268.26 3,651.49 3,589.15 2,889.22 -9,763.64 6,017,931.31 542,131.68 1.78 10,172.58 MWD+IFR2+MS+sag (3) 11,958.52 92.48 268.94 3,648.22 3,585.88 2,887.69 -9,826.51 6,017,929.33 542,068.82 1.91 10,233.22 MWD+IFR2+MS+sag (3) 12,020.66 91.93 267.17 3,645.83 3,583.49 2,885.58 -9,888.57 6,017,926.79 542,006.79 2.98 10,292.92 MWD+IFR2+MS+sag (3) 12,083.84 93.04 268.31 3,643.09 3,580.75 2,883.09 -9,951.64 6,017,923.86 541,943.75 2.52 10,353.51 MWD+IFR2+MS+sag (3) 12,145.99 92.79 269.21 3,639.93 3,577.59 2,881.75 -10,013.69 6,017,922.09 541,881.71 1.50 10,413.40 MWD+IFR2+MS+sag (3) 12,213.12 94.27 270.41 3,635.80 3,573.46 2,881.52 -10,080.69 6,017,921.40 541,814.72 2.84 10,478.35 MWD+IFR2+MS+sag (3) 12,273.22 93.35 270.08 3,631.80 3,569.46 2,881.78 -10,140.65 6,017,921.24 541,754.76 1.63 10,536.60 MWD+IFR2+MS+sag (3) 12,336.92 89.77 268.74 3,630.07 3,567.73 2,881.12 -10,204.32 6,017,920.14 541,691.11 6.00 10,598.21 MWD+IFR2+MS+sag (3) 12,400.73 92.36 269.68 3,628.88 3,566.54 2,880.24 -10,268.10 6,017,918.81 541,627.34 4.32 10,659.89 MWD+IFR2+MS+sag (3) 12,462.76 92.30 271.52 3,626.36 3,564.02 2,880.89 -10,330.08 6,017,919.03 541,565.37 2.97 10,720.18 MWD+IFR2+MS+sag (3) 12,525.86 91.00 272.79 3,624.54 3,562.20 2,883.27 -10,393.10 6,017,920.96 541,502.33 2.88 10,781.91 MWD+IFR2+MS+sag (3) 12,588.91 88.96 272.27 3,624.57 3,562.23 2,886.05 -10,456.09 6,017,923.31 541,439.34 3.34 10,843.69 MWD+IFR2+MS+sag (3) 12,651.91 91.55 271.56 3,624.29 3,561.95 2,888.15 -10,519.05 6,017,924.97 541,376.37 4.26 10,905.29 MWD+IFR2+MS+sag (3) 12,715.52 93.77 270.46 3,621.33 3,558.99 2,889.27 -10,582.57 6,017,925.65 541,312.84 3.89 10,967.20 MWD+IFR2+MS+sag (3) 12,778.09 91.99 269.57 3,618.19 3,555.85 2,889.29 -10,645.06 6,017,925.23 541,250.36 3.18 11,027.84 MWD+IFR2+MS+sag (3) 12,839.58 91.31 268.64 3,616.42 3,554.08 2,888.33 -10,706.52 6,017,923.84 541,188.92 1.87 11,087.24 MWD+IFR2+MS+sag (3) 12,903.91 90.69 267.01 3,615.30 3,552.96 2,885.89 -10,770.79 6,017,920.96 541,124.67 2.71 11,149.01 MWD+IFR2+MS+sag (3) 12,966.27 91.55 264.55 3,614.08 3,551.74 2,881.30 -10,832.96 6,017,915.94 541,062.54 4.18 11,208.23 MWD+IFR2+MS+sag (3) 13,029.05 91.99 265.73 3,612.14 3,549.80 2,875.98 -10,895.48 6,017,910.19 541,000.06 2.01 11,267.61 MWD+IFR2+MS+sag (3) 13,092.66 91.74 265.08 3,610.07 3,547.73 2,870.89 -10,958.86 6,017,904.65 540,936.73 1.09 11,327.86 MWD+IFR2+MS+sag (3) 13,154.79 91.37 264.78 3,608.38 3,546.04 2,865.40 -11,020.72 6,017,898.73 540,874.91 0.77 11,386.56 MWD+IFR2+MS+sag (3) 11312017 12:27.22PM Page 6 COMPASS 5000.1 Build 81 Company: Project: Site: Well: Wellbore: Design: Survey Hilcorp Alaska, LLC Milne Point M Pt J Pad MPJ -24 MPJ -24A MPJ -24A Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPJ -24 Actual:J-24A @ 62.34usft Actual:) -24A @ 62.34usft True Minimum Curvature Sperry EDM - NORTH US + CANADA 1/3/2017 12:27:22PM Page 7 COMPASS 5000.1 Build 81 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (') (usft) (usft) (usft) (usft) (ft) (ft) (°H00') (ft) Survey Tool Name 13,219.62 89.03 264.20 3,608.16 3,545.82 2,859.18 -11,085.24 6,017,892.06 540,810.44 3.72 11,447.66 MWD+IFR2+MS+sag (3) 13,280.54 90.81 263.89 3,608.24 3,545.90 2,852.86 -11,145.83 6,017,885.32 540,749.90 2.97 11,504.92 MWD+IFR2+MS+sag (3) 13,327.91 92.97 263.23 3,606.68 3,544.34 2,847.55 -11,192.88 6,017,879.68 540,702.90 4.77 11,549.28 MWD+IFR2+MS+sag (3) 13,402.00 92.97 263.23 3,602.84 3,540.50 2,838.83 -11,266.35 6,017,870.45 540,629.50 0.00 11,618.47 PROJECTED to TO Checked By: mi[chell.laird@halliburtm.com 2ov.01.0310-33:12-aroo• beniamin.hand@hallibunon.com Approved By: 2017.01.0309.47:20 -WOO' Date: 1/3/2017 1/3/2017 12:27:22PM Page 7 COMPASS 5000.1 Build 81 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 t CL 7000 v 7500 v L p H 8000 f0 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 MPJ -24A FINAL Days vs Depth -- -MPJ-24A Actual MPJ -24A Plan MPJ -24A Stretch Goal Geo Pilot Failure 35.5 hrs NPT Nam 0 5 10 15 20 25 Days 2/2/2017 8:30 AM MPJ -24A MW vs Depth 0 MPJ -24A Plan 1000T MPJ -24A Actual 2000 i -- 3000 4000 5000 6000 s Q, 7000 a 0 v v L p 8000 43 m 9000 10000 11000 12000 13000 14000 15000 8 9 10 11 12 13 14 Mud Density (ppg) Maile Sweigart 27 9 14 Alaska North Slope Team Hilcorp Alaska, LLC i 3800 Centerpoint Drive, Ste 1400 1 Anchorage, Alaska 99503 A FFilfufp r1}JPkif_ i.F.(, I' l ,. 2011 Office: 907.777.8473 msweigart@hilcorp.com DATA LOGGED i i30/20" 7 M.K BENDER Date: 1/12/2017 To: Alaska Oil & Gas Conservation Commission Makana Bender 333 W 7th Ave Ste 100 Anchorage, AK 99501 J -24A Prints: ROP -GM -ADR -HORIZONTAL PRES 2IN MD, GM-ADR-INVERTED/REVERTED INTERVALS 21N TVD E log data CD i : Final Well Data _Leg Viewers 1/5;'20171:07 PM File fcddete CGM 1/5123171:07 PM File fc1der Definitive Survey L+51'20171:137 PM File folder EMF 1./5r'20171:137 Phut Filefclder LAS 1,/5x'23171:07 PM Filefclder RDF 1/5/20171:137 PM File fclder TIFF 1/5:/20171:07 P1`0 Filefclder Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: A THE STATE GOVERNOR BILL WALKER Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU J -24A Hilcorp Alaska, LLC Permit to Drill Number: 216-120 Surface Location: 497' FSL, 3402' FEL, SEC. 28, TI 3N, RI OE, UM, AK Bottomhole Location: 266' FSL, 661' FWL, SEC. 19, TUN, RlOE, UM, AK Dear Mr. Keller: Enclosed is the approved application for permit to redrill the above referenced service well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy . Foerster Chair DATED this l day of October, 2016. STATE OF ALASKA AL/- A OIL AND GAS CONSERVATION COMMIL -)N PERMIT TO DRILL 20 AAC 25.005 SEP 0 9 2016 0G00 1 a. Type of Work: 1 In. 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 El ' Single Zone Coalbed Gas ❑ Gas Hydrates ❑ Redril Q - Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 MPU J -24A b 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 13,878' TVD: 3,562' 4 Milne Point Unit " Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 2713' FSL, 3402' FEL, Sec 28, T13N, R1 OE, UM, AK (SHL) ADL025906 / (TPH) ADL025517/ (BHL) ADL025515 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 497' FNL, 1619' FWL, Sec 29, T13N, R10E, UM, AK N/A 11/1/2016 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 266' FSL, 661' FWL, Sec 19, T13N, R10E, UM, AK 7659 710' to nearest unit boundry 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 62.8' 15. Distance to Nearest Well Open Surface: x- 551914 y- 6015110 Zone -4 GL Elevation above MSL (ft): 36.3', to Same Pool: 1145' to MPJ -27 16. Deviated wells: Kickoff depth: 7,575' feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 92 degrees Downhole: 1625 " Surface: 1262 ' 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 6-1/8" 4-1/2" 13.5# L-80 HTTC 6,403 7,475' 3,602 13,878' 3,562' Cementless Liner ICDs & Swell Pkrs 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): 11,975' 3,858' N/A 11,975' 3,858' N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 108' 20" 260 sx 108' 108' Surface 8,664' 7" 1710 sx 8,664' 3,920' Intermediate Production Liner 3,421' 4-1/2" Cementless Slotted Liner 11,975' 3,858' Perforation Depth MD (ft): Slotted Liner 8,657' - 11,954' Perforation Depth TVD (ft): Slotted Liner 3,920' - 3,859' 20. Attachments: Property Plat ❑✓ BOP Sketch ❑✓ Drilling Program 0 Time v. Depth Plot ❑� Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements0 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 Email Printed Name Luke Keller Title Drilling Engineer G� ` Signature Phone 777-8395 Date / -7 20` Commission Use Only Permit to Drill Number: p21 �p �' API Number: 50- — oC — a Permit Approval Date: t ` See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other.3 0 oola 5- � / Samples req'd: Yes ❑ No 7f Mud log req'd: Yes ❑ No [e '? H2S measures: Yes No Directional svy req'd: Yes ff No ❑ Spacing exception req'd: Yes ❑ No Inclination -only svy req'd: Yes ❑ No [17� ATU % c> /j Post initial injection MIT req'd: Yes ❑ No ❑ -k- /4I+,k- �k�. �, 1 �,��,. �� - - Z -O AAC- ZS.tiizCbj APPROVED BY Approved by: DMI N1 A I COMMISSIONER THE COMMISSION Date: �� .6 A t _ 1. p y {.., auom I Form ana Form 10-401 Revise 1 5 is r t9'ev I11 r 4 months from the date of approval (20 AAC 25.005(g)) Attachments in Duplicate Hilcorp Energy C—pZy 9/7/2016 Luke Keller Drilling Engineer Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: MPJ -24A Permit to Drill Dear Commissioner, Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com ,IVD SEP 0 9 2016 !' OGVC MPU J -24A is part of a/4) well pilot program and will be used as a horizontal water injector in the Schrader Bluff NT sandal It is planned as a sidetrack out of the parent well, J-24 which is a shut in dual lateral producer In the OA and OB sands. Effective formation isolation was never achieved so the well produces rocks when online. It is currently shut in. The parent well will be P&A'd, and sidetracked at 7575' MD. The base plan is a lateral well in Schrader NB sand, then completed with an injection liner.Ack e, Drilling operations are expected to commence approximately Nov 1St, 2016.GJ The Hilcorp UmGvettarrwill be used to drill and complete the wellbore. The existing 7" surface casing will be used and a pressure test conducted prior to drilling the sidetrack. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility on "B" pad. A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and will be included with the PTD submittal to the AOGCC. The P&A sundry will cover the following operations: 1. Circ kill weight fluid in well. 2. MOB drilling rig to the well site. 3. N/D tree, N/U & test BOP. Install 2-7/8" x 5" VBRs in upper and lower ram, blind rams in middle ram cavity. 4. Cut 4-1/2" tubing above pkr at 8000', POOH and UD tubing. 5. RIH w/ cmt retainer, set at 7585', bullhead cmt down well to P&A. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, /Z A�Z�� Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of i Area of Review — Proposed MPJ -24A Injection Well Prior to completion of the MPJ -24A Schrader Bluff NB injection well, an Area of Review (AOR) must be conducted. This AOR found MPJ -24, MPJ -27: within % mile of MPJ-24A's entry into the SB NB formation. The tables below illustrate the wells within the AOR, the distance from MPJ - 24A, completion details and integrity conditions based on in-depth review of each well. Table 1: Wells within AOR Well Name PTD Distance, Ft. Annulus Integrity Production hole lined with 4.5" Screens to 13,940' with a 7" x 9-5/8" Liner Top Packer at 8,430' (Tested to 1500 psi). 9- MPJ -27 215-153 1145' 5/8" casing was run to 8,620' and cemented back to surface. J-24 7" L-1 slotted liner lateral and mother bore below MPJ -24/L1 200-149/ 7585' to be P&A'd. 4.5" tubing to be cut/pulled above 200-150 316' packer at 7900'. Cement retainer will be set at 7585' and cement bullheaded to P&A. Cement plug to be tested to 1750 psi. 4.5" injection tubing will be completed with tieback MPJ -24A TBD assembly at 7,370' 4.5"by 7" Inner Annulus will be tested to 3000 psi to verify integrity. 7" casing was cemented with 1710 sx cement, cement returns observed at surface. LIVIANO 1A 11 HILCORP ALASKA LLC MILNE POINT FIELD AOR MAP tProposed MPJ -24A Injector 0 1.000 2.000 FEET WELL SYMBOLS \ • Active Oil \ \ ¢ DBA \ \ ® INJ Well (Water Flood) \ 1 PBA Oil - amonomom - \ Injector Locafion REMARKS Well Symbol at top of Schrader Bluff NB Sand Pink Paris =Active NB pens (screens in J -27/J-28) Lt Blue Perfs = highlight Inactive NB pens/Swell packer \ depths in J -23A Black Dash Circle = 1320' radius from proposed NB top (heel) and TD (toe) in MPJ -24A �- ;Z q A L 4r -e7, RL _ \ \ Augusti,2016 _ T- z' -24A Prop v g J -20A \ JJ-2�— J-171_ ,,23 =-�-I- -01 J-23Aw-U =, J-28 �J_2& -� / J-21 Hilcorp Alaska, LLC Milne Point Unit (MPU) J -24A Drilling Program Version 1 July 20th, 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 RX and Preparatory Work.........................................................................................................10 10.0 Rig Orientation on "J" Pad..........................................................................................................11 11.0 6-1/8" Hole Section Mud Program...............................................................................................12 12.0 Whipstock Running Procedure....................................................................................................13 13.0 Whipstock Setting Procedure: ..................................................................................................... 15 14.0 Drill 6-1/8" Hole Section...............................................................................................................17 15.0 Run 4-1/2" Injection Liner...........................................................................................................20 16.0 Run Injection Assembly................................................................................................................23 17.0 RDMO............................................................................................................................................23 18.0 BOP Schematic..............................................................................................................................24 19.0 Wellhead Schematic......................................................................................................................25 20.0 Days vs Depth................................................................................................................................26 21.0 Formation Tops.............................................................................................................................27 22.0 Anticipated Drilling Hazards.......................................................................................................28 23.0 Innovation Rig Layout..................................................................................................................29 24.0 FIT Procedure...............................................................................................................................30 25.0 Choke Manifold Schematic..........................................................................................................31 26.0 Casing Design Information...........................................................................................................32 27.0 6-1/8" Hole Section MASP............................................................................................................33 28.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................34 29.0 Surface Plat (As Built) (NAD 27).................................................................................................35 30.0 Drill Pipe Specifications................................................................................................................36 Milne Point Drilling & Completion Procedure Ililrorp UaAa. LI.I: 1.0 Well Summary Well MPU J -24A Pad Milne Point "J" Pad Planned Completion Type 4-1/2" Injection String Target Reservoirs Schrader Bluff NB Sand Planned Well TD, MD / TVD 13,878' MD / 3,562' TVD PBTD, MD / TVD 13,800' MD / 3,565' TVD Surface Location (Governmental) 2713' FSL, 3402' FEL, Sec 28, TI 3N, RI OE, UM, AK Surface Location (NAD 27 — Zone 4) X=551,914.26 Y=6,015,110.45 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 497' FNL, 1619' FWL, Sec 29, TON, RIDE, UM, AK TPH Location NAD 27 X= 546,357.34, Y= 6,017,142.92 TPH Location (NAD 83) BHL (Governmental) 266' FSL, 661' FWL, Sec 19, T13N, R10E, UM, AK BHL (NAD 27) X= 540,158.3, Y= 6,017,869.79 BHL NAD 83) AFE Number 1511740 AFE Drilling Das 10 AFE Completion Das 4 AFE Drilling Amount $2,676,786 AFE Completion Amount $1,166,800 AFE Facility Amount $100,000 Maximum Anticipated Pressure Surface 1262 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1625 psig Work String 4" 14# S-135 HT -38 (Weatherford) KB Elevation above MSL: 26.5 + 36.3 ft = 62.8 ft AMSL GL Elevation above MSL: 36.3 ft AMSL BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Version 1 July, 2016 2.0 Management of Change Information Milne Point Drilling & Completion Procedure Hilcorp Alaska, LLC Hilcorp E-0 C-Miy Changes to Approved Permit to Drill Date: July 7th, 2016 Subject: Changes to Approved Permit to Drill for J -24A File #: J -24A Drilling and Completion Program Any modifications to J -24A Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to and approved by the AOGCC_ Approval Prepared: Drilling Manager Date Drilling Engineer Date Page 3 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Hilcorp Alaska, LIA: 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section in OD in(#/ft)(psi) (psi) (k -lbs) 6-1/8" 4-1/2" 3.849 3.75 4.93 13.5 L-80 VAM 9020 8540 307 HTC 4.0 Drill Pipe Information: Hole OD (in) ID (in) TJ ID Section in TJ OD in(#/ft) Wt Grade Conn Burst (psi) Collapse Tension si) (k-lbs 6-1/8" 4" 3.34" 2.813" 5" 14 S-135 HT -38 18,428 13,836 403 All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ililcorp Alaska.. LI.1: 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 the "Save and Exit' or "Save" buttons on the bottom right hand corner to save work. 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 pmazzoliniAhilcorp.com , lkellerAhilcorp.com and cdingerAhilcorp.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 lkeller@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report i. Send casing and cement report for each string of casing to lkeller@hilcorp.com and cdin er e,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(c@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Coordinator Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcgD.com Page 5 Version 1 July, 2016 Ilil,•nrp Alaska.. L1.1: 6.0 Planned Wellbore Schematic KB Elev.: 628'/ GL Elev.: 36.3' TD =13,878' (M D) / TD = 3,562.8'(TVD) PBTD=13,800' (MD) / PBTD=3,565'(TVD) Milne Point Drilling & Completion Procedure OPEN HOLE / CEMENT DETAIL 20" Driven 7" 1600 sx cement, 2 stages, cmt to Surface 4-1/2" Qqrrlent!gss Injection Liner in 6-1/8" hole CASING DETAIL Size Type Wjt Grade/ Conn Drift 10 Top Btm BPF 20" Conductor 54.5 / K-55 /Weld N/A Surface 106' N/A 7" Surface 26 / L-80 / BTC 6.151 Surface 7,575' 0.0383 4-1/2" Liner 13.5 / L-80 / HTTC 3.833 7,475' 13,878' 0.0152 TUBING DETAIL 4-1/2" 1 Tubing 12.6 / L-80 /SupgE91ax 1 3.833 1 Surf 1 7,475' 0.0152 WELL INCLINATION DETAIL KOP @ 420' Max Hole Angle = 92 deg JEWELRY DETAIL No. Top MD Item ID 9,200' 4-1/2" 12.6#Hyd 521 BxP WOT ICDw/ (10) 1/8" nozzles Upper Completion 4-1/2" 12.6#Hyd 5218xP WOT ICDw/(10) 1/8" nozzles 1 3,000' 4.5"xl" w/1" DCK-2 Shear valve w/ BEK Latch 3.833" 2 7,300' 4.5" XN Nipple w/ RHCP plug, 3.725" No -Go, 3.813" Packing Bore 3.725" S 12,700' 4-1/2" 12.6#H vd 521 BxP, WOT ICDw/(10) 1/8" nozzles Lower Completion 4-1/2" 12.6#H d 521 BxP WOT ICDw/(10) 1/8" nozzles 3 7,360' BOT HRD-E Liner Top Packer 5" x 7" 4.283" 4 Btm@ 7,370' Tieback Assy. (5.75" OD No -Go top @ 7,659') 4.151" 5 See Below 4-1/2" 13.5#Swell Packers 3.920' 6 13,800' 4-1/2" Drillable Packoff Sub 2.400" 7 13,881' WIV Valve LTC Bx8 (1.5" Ball on Seat/Closed) - ICD DETAIL o Depth ICD Detail I 8,500' 4-1/2" 12.6# H d 521 BxP WOT ICDw/ (10) 1/8" nozzles 9,200' 4-1/2" 12.6#Hyd 521 BxP WOT ICDw/ (10) 1/8" nozzles S 9,800' 4-1/2" 12.6#Hyd 5218xP WOT ICDw/(10) 1/8" nozzles S 10,300' 4-1/2" 12.6#H.yd 521 BxP, WOT ICD w/(10) 1/8" nozzles i 10,800' 4-1/2" 12.6# H d 521 BxP WOT ICD w/ (10) 1/8" nozzles i 11,200' 4-1/2" 12.6# Hyd 521 BxP WOT ICD w/ (10) 1/8" nozzles i 11,700' 4-1/2" 12.6#Hy4 521 BxP, WOT ICDw/(10) 1/8" nozzles S 12,700' 4-1/2" 12.6#H vd 521 BxP, WOT ICDw/(10) 1/8" nozzles I 13,000 4-1/2" 12.6#H d 521 BxP WOT ICDw/(10) 1/8" nozzles D 13,600' 4-1/2" 12.6# H d 521 BxP WOT ICD w/ (10) 1/8" nozzles bN SWELL PACKER DETAIL Top (MD) Btm (MD) 8,209' 8,221' 10,987' 10,998' 12,335' 12,347' GENERAL WELL INFO API: Page 6 Version 1 July, 2016 LLI 7.0 Drilling / Completion Summary Milne Point Drilling & Completion Procedure MPU J -24A is part of a (4) well pilot program and will be used as a horizontal water injector in the Schrader Bluff NB sand. It is planned as a sidetrack out of the parent well, J-24 which is a shut in dual lateral producer in the OA and OB sands. Effective formation isolation was never achieved so the well produces rocks when online. It is currently shut in. The parent well will be P&A'd, and sidetracked at 7575' MD. The base plan is a lateral well in Schrader NB sand, then completed with an injection liner. Drilling operations are expected to commence approximately Nov 1St, 2016. The Hilcorp Innovation will be used to drill and complete the wellbore. The existing 7" surface casing will be used and a pressure test conducted prior to drilling the sidetrack. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility on `B" pad. A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and will be included with the PTD submittal to the AOGCC. The P&A sundry will cover the following operations: Circ kill weight fluid in well. MOB drilling rig to the well site. N/D tree, N/U & test BOP. Install 2-7/8" x 5" VBRs in upper and lower ram, blind rams in middle ram cavity. Cut 4-1/2" tubing above pkr at 8000', POOH and L/D tubing. RIH w/ cmt retainer, set at 7585', bullhead cmt down well to P&A. General sequence of operations pertaining to this approved drilling procedure: 1. Run whipstock, mill window in 7" 26# casing. 2. Drill 6-1/8" production hole section to TD. 3. Run 4-1/2" injection liner. 4. Run 4-1/2" injection tubing. 5. N/D BOP, N/U tree, RDMO. Page 7 Version 1 July, 2016 Milne Point Drilling & Completion Procedure I1ile-10 kla=ka, LH: 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 J -24A. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. The initial test of all rams, choke manifold, kill line valves, standpipe equipment, floor & top drive valves will be to 250/5000 psi (Annular to 250/3500 psi) per API RP 53 17.3.2.2 prior to the equipment being put into operational service. The initial test will be conducted under the plug for redrill sundry. Subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation we must report the BOP use to the AOGCC. Prior to the next wellbore entry, all BOP components utilized for well control must be pressure tested the same as the normal 7/14 day BOP test and charted as such. • 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. • AOGCC regulations can be found at the following website: http://doa.alaska. ov/o cg /Regulations/Reglndex.html • AOGCC Industry guidance bulletins can be found at the following website: http://doa.alaska.gov/oac/bulletins/bulletindex.html Variance Requests: • A variance from regulation 20 AAC 25.412.b is requested: The Production packer will be set > 200' MD from the closest injection control device. The current plan is to set the production packer 1,000 ft MD from the first ICD. 5- 1 10 C Y 2, ® 1 ' ^ 0 Page 8 Version 1 July, 2016 Ililcorp Alaska, 111.1: Milne Point Drilling & Completion Procedure 1b V-- Summary of BOP Equipment and Test Requirements -P3 1 Hole Section Equipment Test Pressure(psi) • 13-5/8" x 5M Control Technology Inc Annular BOP / • 13-5/8" x 5M Control Technology Inc Double Gate Initial Test: 25Q/5000 o Blind ram in btm cavity (Annular 3500 psi) • Mud cross w/ 3" x 5M side outlets 6-1/8" • 13-5/8" x 5M Control Technology Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc Primary closing unit: Control Technology Inc, 6 station, 20 bottle, 3000 psi, 220 gal EHPLC Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is 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@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Mike Quick / Petroleum Engineer / (0): 907-793-1231 / (C): 907-317-2969 / Email: Michael.quick@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forfns/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 1 July, 2016 9.0 R/U and Preparatory Work 9.1 Level pad and layout rig mats for footprint of rig. Milne Point Drilling & Completion Procedure 9.2 Drive rig over well and ensure rotary centered over wellhead. Confirm that rig is over appropriate well — J-24. 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 NOT be used for J -24A. 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 5" liners in mud pumps. • White Star 1300 HP Quatro mud pumps are rated at 4097 psi, 380 gpm @ 140 spm @ 90% mechanical efficiency & 100% volumetric efficiency. 9.9 Conduct P&A operations which include: • Circ kill weight fluid in well. • MOB drilling rig to the well site. • N/D tree, N/U & test BOP. Install 2-7/8" x 5" VBRs in upper and lower ram, blind rams in middle ram cavity. • Cut 4-1/2" tubing above pkr at 8000', POOH and L/D tubing. • RIH w/ cmt retainer, set at 7585', bullhead cmt down well to P&A. NOTE. A separate sundry will be submitted to the AOGCC that covers P&A operations, and will accompany the PTD application. Page 10 Version 1 July, 2016 Ilileurp Alaska. LIA: 10.0 Milne Point Drilling & Completion Procedure Rig Orientation on "J" Pad. Page 11 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ililcorp Ahv-ka, LIA: 11.0 6-1/8" Hole Section Mud Program • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running slightly off the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible and keep solids out of the mud system. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use water or low vis sweeps. • 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: 8.9 — 9.2 ppg Baradrill-N drilling fluid Properties: Depths Densi ✓ Plastic Viscosity Yield Point Total Solids MBT HPHT pH 7575— 13,878' 8.9-9.2 15-25 15-25 <10% <7 <1 1.0 8.5-9.5 System Formulation: Baradrill-N Product Concentration Water 0.955 bbl KCL 11 ppb KOH 0.1 ppb N -VIS 1.0 — 1.5 ppb N-DRIL HT PLUS 5 ppb BARACARB 5 11.5 ppb BARACARB 25 16.8 ppb BARACOR 700 1.0 ppb BARASCAV D 0.5 ppb X-CIDE 207 0.015 ppb EZ -GLIDE 2.0% Page 12 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ililrorp .kla,ku, LLC 12.0 Whipstock Running Procedure 12.1 M/U window milling assembly and TIH w/ 4" DP • Use a 6-1/8" Upper String mill and a 6-1/8" string mill above to ensure CIBP & whipstock assy will pass freely. • Ensure BHA components have been inspected previously. • Caliper and drift all BHA components before running them in the hole. 12.2 Make up mills on a joint of HWDP. 12.3 RIH & set in slips. 12.4 Make up float sub, install float. 12.5 Install MWD for orientation. 12.6 Make up UBHO sub. 12.7 Orient UBHO to starter mill. 12.8 TIH to cmt retainer (7585' MD). Verify proper operation of MWD. 12.9 CBU & circ at least (1) hi -vis sweep to remove any debris created by the clean out run. Anything left in the wellbore could affect the setting of the Whipstock. 12.10 Drop drift and TOH. 12.11 Leave assembly hanging in the elevators, and stand back on floor. 12.12 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe skate. 12.13 Pick up Whipstock per Baker rep using the Baker Whipstock handling system using air hoist. Allow assy to hang while Baker Rep inspects and removes shear screws as needed and any safety screws. Note: Anchor should be pinned with 6 shear screws initially. Shear screws are rated for 6,630 lbs each. REMOVE 3 screws for a set down shear of 6,630 x 3=19,890lbs. Note: Attach mills to Whipstock with (1) 35k mill shear bolt. 12.14 If needed, open BOP Blinds. Page 13 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ilifcogi Alaska. LLC 12.15 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. 12.16 Release pick up system at this point, Make up mills. 12.17 With the top drive, pick the assembly and position the starting mill to align with the hole in the slide. The Baker Rep will instruct the driller when the slot is lined up, the shear bolt then can be made up by the Baker Rep. 12.18 The assembly can now be picked up to ensure that the shear bolt is tight. 12.19 Remove the handling system. 12.20 Slowly run in the hole as per Baker Rep. run extremely slow through the BOP & wear bushing. 12.21 Run in hole at 1 1/z to 2 minutes per stand. 12.22 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 12.23 Call for Baker Rep. 15 — 10 stands before being to bottom. 12.24 Orient at least 30' — 45' above the CIBP using the MWD. Consider having gyro personnel on standby in the event the MWD is not working. WindowMaster G2 Svstem on TernueMaster BTA BHA #1 Connection Length O.D. BOTTOM TRIP ANCHOR 3 Y2" IF -B X Anchor 3.21 5.680 WINDOWMASTER G2 WHIPSTOCK 3'/ IF -P X 35K Shear bolt 18.5 5.500 WINDOW MILL 3'h REG -P X MILL 1.38 6.125 NEW LOWER WATERMELON MILL 3 Y2 IF -13 X 3 Y2 IF -P 5.50 6.125 FLEX JOINT 3 Y IF -13 X 3 Yz IF -P 6.55 4.750 UPPER WATERMELON MILL 3'/2" IF -13 X 3 Y2" IF -P 5.83 6.125 1 jt - HWDP 3 Y2" IF -13 X 3 Y2" IF -P 30 4.750 MWD collar 3 %" IF -13 X 3'/" IF -P 18 4.750 FLOAT SUB 3'/2" IF -13 X 3 Yz" IF -P 3 4.750 UBHO 3'/2" IF -13 X 3 Y2" IF -P 4 4.750 X -O sub + 30 jts-HWDP 4" HT -38 4" HT -38 B X 4" HT -38-P 900' 4.750 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY Page 14 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ililo•orp Alaska.. LLC 13.0 Whipstock Setting Procedure: 13.1 With the bottom of the Whipstock 30 — 45' above the CIBP, measure and record P/U and S/O weights. Run gyro survey to orient Whipstock face. 13.2 Orient Whipstock to desired direction by turning DP in'/4 round increments. P/U and S/O on DP to work all torque out (Being careful not to set BTA). 60L Whipstock Orientation Diagram: Desired orientation of the Whipstock face is 30L to 60L Hole Angle at window interval (7,575 MD) is —71 deg. 13.3 Once Whipstock is in desired orientation, slack off and tag CIBP to set Bottom Trip Anchor. 13.4 Set down 15-20K on anchor to trip, P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the Whipstock shear bolt. (35k shear value). 13.5 P/U 5-10' above top of Whipstock. 13.6 Displace to Baradrill-N fluid system. I 13.7 Record P/U, S/O weights, and free rotation. Slack off to top of Whipstock and with light weight and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings. �( 13.8 Install catch trays in shaker underflow chute to help catch iron. 13.9 Keep iron in separate bbls. Record weight of iron recovered on ditch magnets. Page 15 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ilihwp:UaAa, HIC 13.10 Estimated metal cuttings volume from cutting window: 7" 26# L-80 Cuttings Weight Window Length Casing Weight Min (Ibs) Avg (Ibs) Max (Ibs) 16 26# 60 85 115 13.11 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 13.12 Circulate Bottoms Up until MW in = MW out. 13.13 Conduct F to 12 ppg EMW. S \` 13.14 Slug pipe and auge Mills for wear. 13.15 Should a second run be required pick up the following BHA. Back Un Mills Connection I pnnth n n WINDOW MILL 3'/2 REG -P X MILL 1.38 6.125" NEW LOWER WATERMELON MILL 3 % IF -13 X 3'/ IF -P 5.50 6.125" FLEX JOINT 3'/2 IF -13 X 3 % IF -P 6.55 4.750 UPPER WATERMELON MILL 3 %" IF -13 X 3'/2" IF -P 5.83 6.125" FLOAT SUB 3'/z" IF -13 X 3 %" IF -P 3 4.750 X -O sub 30 jts-HWDP 4" HT -38 4" HT -38 B X 4" HT -38-P 900' 4.750 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY.! Page 16 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ilih-mli:klaAa, LLC 14.0 Drill 6-1/8" Hole Section 14.1 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. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 4" 14# 5-135 HT -38 • Install ported float above motor. 14.2 6-1/8" BHA (Includes GR+Res+ADR LWD components & PWD): COMPONENTOATA Item # 1 Description Serial HDBS MME64 PDG Number .r (in) 4.500 10 (in) 1.500 Gauge (in) 6.125 Weight (Ibpf) 48.18 Top Connection P 3-112" REG Length (11t) 0.83 Cumulative Lengffi (A) 0.83 2 Geo -Pilot 5200 EDL 5.250 1.125 6.000 45.13 B 3-112" IF 16.35 17.18 Stabilizer 6.062 Ret Housing Stabilizer 6.000 3 4 314' GM (Gamma) 4.664 1 2.610 47.00 B 3-1;2" IF 9.22 26.40 4 Inline Stabilizer (ILS) 4.750 1.920 5.938 50.52 B 4-112" IF 3.58 29.98 5 4 314' ADR (Resistivity) ✓ 4.720 1.250 53.70 B 3-1;2" IF 27.29 57.27 6 Inline Stabilizer (ILS) 4.750 1.920 5.925 50.52 B 4-112" IF 3.60 60.87 7 4 314" PWD (Pressure) 4.710 1.250 47.90 B 3-112" IF 10.81 71.68 8 4 34' DM (Directional) 4.640 2.610 47.00 B 3-112" IF 9.21 80.89 9 4 14" TM (Telemetry) 4.630 2.812 46.10 B 3-112" IF 10.88 91.77 10 Float Sub 4.750 2.250 46.84 B 3-112" IF 2.93 94.70 11 Non Mag Flex Collar 4.700 2.250 45.58 B 3-112" IF 30.60 125.30 12 Non Mag Flex Collar 4.730 2.250 46.33 B 3-112" IF 30.84 156.14 13 Non Mag Flex Collar 4.730 2.313 45.57 B 3-1J2" IF 31.05 187.19 14 X -Over Sub 4.800 2.375 46.57 B 4" HT -38 1.30 188.49 15 4" HWDP #28.4 HT -38 4.000 2.563 28.40 30.31 218.80 16 4 3l4" Weatherford Hyd Jar 4.750 2.250 46.84 29.66 248.46 17 4" HWDP #28.4 HT -38 4.000 2.563 28-40 30.47 278.93 278.93 Page 17 Version 1 July, 2016 Ililcorp klaska.. LLC 14.3 Primary Bit: PRODUCT SPECIFICATIONS Cutter Type IADC Code Body Type Total Cutter Count Cutter Distribution Face Gauge Up Drill Number of Large Nozzles Number of Medium Nozzles Number of Small Nozzles Number of Micro Nozzles Number of Ports (Size) Number of Replaceable Ports (Size) Junk Slot Area (sq in) Normalized Face Volume API Connection Recommended Make -Up Torque' Nominal Dimensions" Make -Up Face to Nose Gauge Length Sleeve Length Shank Diameter Break Out Plate (Mala%tegacyt!) Approximate Shipping Weight SelectCutter M434 MATRIX 43 13mm -5 12 6 0 0 0 6 0 0 5.37 25.99% 3-1+2 REG. PIN 5.173 - 7,665 Ft;lbs. 9.35 in - 237 mm tin -51 mm Din -0 mm 45 in - 114 mm 181953;44030 861_bs. - 39Ku. SPECIAL FEATURES 132" Relieved Gage, Optimized Dual Row - "D" Feature Milne Point Drilling & Completion Procedure HALLIBURTON':; f.3 Material #791888 `Bit specific raommendcd make-up torque is a function of the bit LD. and actual bit sub O.D. utilized as specified in AN RP76 Section A.8.2. "Design dimensions aro nominal and may vary slightly on manufactured product_ Halliburton (hill Bits and Services models arc continuously rcviawvcd and refined. Product specifications may change without notice. C 2014 Halliburton. All rights reserved. Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. Page 18 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ilile—p .%IaAa.. LI.(: 14.4 TIH w/ 6-1/8" directional assy to one stand above window. Shallow test MWD and LWD on trip in. 14.5 Orient motor and continue lowering assy through window. 14.6 Drill 6-1/8" hole section to section TD per Geologist and Drilling Engineer. • Pump at 250-290 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 drld. 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. • Use ADR to stay in section. Ideally, we would like to stay in section 100% of the time and DO NOT want to serpentine between the upper and lower lobes. 14.7 Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 14.8 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the window. 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. 14.9 TOH with the drilling assy, stand back BHA if possible. Rabbit DP on TOH. 14.10 No additional logs are planned for the 6-1/8" hole section. Page 19 Version 1 July, 2016 0 Ililcorp thiska, LLI: 15.0 Run 4-1/2" Injection Liner Milne Point Drilling & Completion Procedure 15.1 Ensure rams have been tested on 4-1/2" test joint prior to running liner. 15.2 Ensure wear bushing is installed in wellhead. 15.3 R/U 4-1/2" casing running equipment. • Ensure 4-1/2" HTTC x HT -38 crossover is on rig floor and M/U to FOSV. • 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. 15.4 Run 4-1/2" injection liner per completion tally. • Use "API Modified" or "BOL 4010 NM" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install swell packers & ICDs as per Operations Engineer completion liner tally. • Ensure all plastic packing is removed from swell pkr elements. • Do not place tongs or slips on pkr elements or ICDs. 4-1/2" VAM HTTC M/U torques Casing OD Minimum Maximum Yield Torque 4.5" 6,910 ft -lbs 9,350 ft -lbs 14,400 ft -lbs Page 20 Version 1 July, 2016 Milne Point Drilling & Completion Procedure 1,-d an: n5 Tun. 20115 by ]ean-Guillaume Bess BATA SED ON SI -PD 1011VE ONLY. Connection Data Sheet BASED ON SI -PD 101156 OD Weight Wall Th. Grade API Drift Connection 4 1/2 in. 1 13.50 Ib/ft 0.290 In. Lao 3.795 in. "No HTTC Nominal OD 4.500 in. Connection Type Premium T&C Nominal ID 3.920 in. Connection OD (nom) 4.930 in. Nominal Cross Section Area 3.836 sgin. Connection ID (nom) 3.849 in. Grade Type API SCT Make -Up Loss 4.380 in. ;Min. Yield Strength 80 ksi Coupling Length 9.917 in. ;Max. Yield Strength 95 ksi Critical Cross Section 3.836 sqin. Min. Ultimate Tensile Strength 95 ksi Tension Efficiency 100 % of pipe Tensile Yield Strength 307 klb Compression Efficiency 100 % of pipe Compressive Yield Strength 307 klb Compression Efficiency with Sealability 80 % of pipe Internal Yield Pressure 9,020 psi J Internal Pressure Efficiency 100 % of pipe (Collapse pressure 8,540 psi External Pressure Efficiency_, 100 % of pipe CONNECTION ''TORQUE Tensile Yield Strength 07 kill Min. Make-up torque 6,910 ft.lb Compression Resistance 307 klb Opti. Make-up torque 8,130 ft.lb Compression with Sealabifity 246 kib 'Max. Make-up torque 9,350 ft.lb Internal Yield Pressure 9,020 psi Max. Torque with Sealability 12,350 ft.lb External Pressure Resistance 8,540 psi Max. Torsional Value 14,400 ft.lb Max. Bending 77 a/100ft Max. Bending with Sealability 33 0/1008 Max. Load on Coupling Face 158 klb Do you need help an this product? - Remember no one knows VAMe like VAM cenade0vemfMMsemke.com uk0vamneMserv1ce.com china0vamrteWervlce.com use0vam/leldservice.com dubaipvamfiektservke.com bsku@vamne/dservlce.ccm mexk'o0vanifteWervice.com n/gertapvamReMservke.corn singapone(Dvamrteldswvice.corn brazilmvamneldservice. aom ango1a0vamAeMservice.rom ausba11a0vamne1d5ervke.com Over 240 VAMP Specialists available worldwide 24/7 for Rig Site Assistance Other Connection Data Sheets are available at www.vamse-S.totn 15.7 Ensure to run enough liner to provide for approx 100' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection. 15.8 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. 15.9 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. 15.10 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 15.11 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. Page 21 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ililemp:UaAa, LI.I; 15.12 DP should autofill. 15.13 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. 15.14 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 15.15 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 15.16 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 15.17 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 15.18 Rig up to pump down the work string with the rig pumps. 15.19 Displace entire wellbore to completion fluid (8.9 ppg KCl). Pump at 10-12 bpm. Catch mud for future use if feasible. Once KCl observed at surface shut down pumps. 15.20 Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 15.21 Pressure up to 3000 psi and hold for 5-15 minutes to set SLZXP hanger packer. Continue pressuring up in 500 psi increments holding for 5 min each up to 4000 psi. 15.22 Bleed DP pressure to zero, close BOP and test annulus to 1500 psi for 10 min and chart record same. 15.23 Bleed off pressure and pickup to verify that the HRD setting tool has released. If packer did not test, rotating dob sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 15.24 POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. 15.25 L/D remaining DP out of derrick. Page 22 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ilih- rp Uazku. LIA: 16.0 Run Injection Assembly 16.1 M/U injection assy and RIH to setting depth. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while RIH. 16.2 Wash down last couple remaining joints above liner top. Observe pressure spike as seal assy enters polished bore. Continue slacking off and land no go on liner top. Mark pipe for space out, Test annulus to 1500 psi / 10 min to test seal assy. 16.3 Space out tubing, note any crossovers used on AM report. M/U tubing hanger. Lower string until seal assy just above seal bore. 16.4 Reverse circulate packer fluid to cover section of production annulus from GLM to seal assy. • Packer Fluid: —9.1 ppg KCL Brine with 0.01 % Baricor 100 16.5 Pump additional 10 bbls down tubing to clear ball seat. 16.6 Lower string and land out hanger. RILDs. Test annulus to 500 psi 5 min. Bleed off. DROP RHCP ball and rod. R/U and pressure test the tubing to 2500 psi / 30 min. Bleed tubing to 1000 psi. Test annulus to 3000 psi / 30 min. Bleed off annulus and tubing. Pressure up and shear out GLM at 2600 psi. R/D circ equipment. 16.7 Install TWC. N/D BOP equipment and secure for rig move. 16.8 N/U tree. Test void to 5000 psi / 10 min. Test internal to 5000 psi / 10 min. Pull TWC. 16.9 R/U pump truck and circ freeze protect down IA and up into tubing. R/D circ equipment. Secure tree, install gauges and cap flanges. Clean up and prep to hand over well to production. 17.0 RDMO Page 23 Version 1 July, 2016 Ililcorp :klaAa, I.I.1; 18.0 BOP Schematic 3-118" Kill Milne Point Drilling & Completion Procedure _-13-518" %Khtrol Technology Annular 9 ET -AL -7 i'''`13-518" 5M Control o Technology Double Ram �-3-118" Choke Line ® �a x--13-518" 5M Control Technology Single Ram 13-518" 5M X 11" 5M DSA ---2-1116" FMC HWO Valve -.=--11" x 11" 5M FMC Gen 5 Tubing Spool �------FMC Starting Head -----2-1116" FMC HWO Valve ---20" Conductor 7" Casing Page 24 Version 1 July, 2016 nilvorp .ua.ka. 1.1.1: 19.0 Wellhead Schematic MPJ -24 4 1/16 CIW Tr( 11' X 11" SM FMC Gen 5 tubing spool FMC starting head Milne Point Drilling & Completion Procedure 2 1/16 FMC HWO valve 2 1/16 FMC HWO valve Page 25 Version 1 July, 2016 11'X 4 W hanger 4" H gpV profile TC. 11 Threads T&g Ilileorp Alaska, LII: 20.0 Days vs Depth J -24A Days Vs Depth 7000 sono „1 S r 1=0 14000 Milne Point Drilling & Completion Procedure 2 4 6 8 10 12 14 16 18 20 Days Page 26 Version 1 July, 2016 0 Ilileorp Uaska.. LU: Milne Point Drilling & Completion Procedure 21.0 Formation Tops Formation TVD (Top) TVD (Bottom) Anticipated Pressure (Psi) KOP 1 3633 SB NB Sand 1 3562 1 3732 1 1625 11 Page 27 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ililcorp UaAa, LLA: 22.0 Anticipated Drilling Hazards 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. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 1-12S. No H2S events have been documented on drill wells on "J" pad. 1. The AOGCC will be notified within 24 hours if 142S 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 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on "J" pad. Page 28 Version 1 July, 2016 23.0 Innovation Rig Layout Milne Point Drilling & Completion Procedure Page 29 Version 1 July, 2016 Milne Point Drilling & Completion Procedure llilcorp AN.A.e. LLC 24.0 FIT Procedure Formation Inteirity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 30 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ilih-orp k1aAa, LLA: 25.0 Choke Manifold Schematic Page 31 Version 1 July, 2016 Milne Point Drilling & Completion Procedure 11ilcog) Alaska, LLC 26.0 Casing Design Information Maximum Anticipated Surface Pressure Calculation 11 6-1/8" Hole Section Hilcorp MPU J -24A Milne Point Unit MD TVD Planned Top: 7575 3633 Planned TD: 13878 3562 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NBSand7 3,633 1625 Oil/Wet 8.6 1 0.447 Offset Well Mud Densities Well MW ranee Too (TVD) Bottom ITVDI Date MPI - 19 9 - 9.3 ppg Surface 4,079 2004 MPI - 18 9 - 10 ppg Surface 3,848 2011 MPI - 17 9 - 9.5 ppg Surface 3,864 2004 MPI - 16 9 - 9.3 ppg Surface 4,101 2004 MPI -15 9 - 10.8 ppg Surface 4,042 2002 MPI - 14 9.1- 9.3 ppg Surface 3,979 2004 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 6-1/8" hole section Is 9.2 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 7" window considering a full column of gas from shoe to surface: 3633 (ft) x 0.78(psi/ft)= 2834 2834(psi) - (0.1(psi/ft)"3633(ft))= 2471 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 3633 (ft) x 0.447(psi/ft)= 1625 0-si 1625(psi) - 0.1(psi/ft)'3633(ft)= 1262 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 32 Version 1 July, 2016 Ilileurp Alaska, LI.0 Milne Point Drilling & Completion Procedure 27.0 6-1/8" Hole Section MASP Calculation & Casing Design Factors DATE: 7/20/2016 WELL: MPU J -24A DESIGN BY:Luke Keller Design Criteria: Hole Size 6-1/8" Mud Density: 9.2 ppg Hole Size Mud Density: Hole Size Mud Density: Drilling Mode MASP: 1262 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1262 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress Page 33 Version 1 July, 2016 Casing Section Calculation/Specification 1 2 3 4 Casing OD 4-1/2" To MD 7,475 To TVD 3610 Bottom MD 13,878 Bottom TVD 3,562 Length 6,403 Weight 13.5 Grade L-80 Connection VAM HTTC Weight w/o Bouyancy Factor(lbs)-86,441 Tension at Top of Section lbs 86,441 Min strength Tension 1000 lbs 307 Worst Case Safety Factor Tension 3.55 Collapse Pressure at bottom Psi 1,760 Collapse Resistance w/o tension (Psi) 8,540 Worst Case Safety Factor (Collapse) 4.85 p MASP(psi) 1,262 Minimum Yield (psi) 9,020 Worst case safety factor Burst 7.15 Page 33 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ilikorp U:uku. LLC 28.0 Spider Plot (NAD 27) (Governmental Sections) 11 Milne Point Unit'164� 111 0 1,500 3,000 Map Date: 7120120% MPJ -24A Well Feet Page 34 Version 1 July, 2016 Ililcogp .Ua4a, LIX 29.0 Surface Plat (As Built) (NAD 2 N 1800 fl J-1 NORTH � W MPU J—PAD r----------------1 i 1 A.S.P. PLANT 1 I 1 Y ! CELLAR SECTION 1 I COORDINATES COORDINATES POSITION(OMS) J-24 1 OFFSETS J-23 1 1 I 70'27'07.009 t ■ I i 2685' FSL J-23 ti ■ E- 1119.45 1 1 149.5763106' 2 ■ 1 i Y= 6,015,110.45 B ■ 70'27'07.288' 1 36.3' 3 ■ 1 X= 551 914.6 = 1,119.14 10 ■ j I� 3402` FEL 4 ■ 1 1 1 I 1 t 1 15 ■ ■ 6 j 16 ■ • 12 1 17 ■ 9 i 18 ■ :13 1 19 ■ ■ 5 1 20 ■ 814 1 1 1 21 ■ ■ 7 1 i 1 22 ■ 1 I 1 I Y ------------------- I I 1 1 � J-2 SOUTH 1 I 1 I I ' ' I I I I I Milne Point Drilling & Completion Procedure 20 21 PROJECT AREA 29 PA n NOTES 1. DATE OF SURVEY: JULY 26. 2000, 2. REFERENCE FIELD BOOK& MP00-01 (POS. 28-29). 3. ALASKA STATE PLANE COORDINATES ARE ZONE 4. ALASKA, NAD 27- 4. GEODETIC COORDINATES ARE NAD 27. 5. PAD SCALE FACTCR IS 0.9999031. 6. HORIZONTAL & VERTICAL CONTROL 15 BASED ON J PAD WELLS J-1 AND J-2. 7. ELEVATIONS ARE BPX MILNE POINT DATUM M.S.L. o LEGEND +N 400 + AS -BUILT CONDUCTOR ■ EXISTING CONDUCTOR G PAD 34 PAD VICINITY MAP N. T- S. C, ; Jeffrey J. Cotton LS 8306 �'F'SSiaiu�. ti� SURVEYOR'S CERTIFICATE t HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASXA AND THAT THIS PLAT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DIMENSIONS .AND OTHER DETAILS ARE CORRECT AS OF AUGUST 8. 2000. 1.0CATFD WITHIN PROTRACTED SEC. 28. T. 13 N., R. 10 E., UMIAT MERIDIAN, ALASKA 'NELL A.S.P. PLANT GEODETIC GEODETIC CELLAR SECTION NO. COORDINATES COORDINATES POSITION(OMS) POSITION(D.OD) BOX ELEV. OFFSETS Y= 6,015,082.24 N= 1,329.77 70'27'07.009 70.4519469' 36.1` 2685' FSL J-23 X= 551,926.95 E- 1119.45 149'34'34.718' 149.5763106' 3390'FEL Y= 6,015,110.45 N-1,360.69 70'27'07.288' 70.4520244' 36.3' 2713' FSL J-24 X= 551 914.6 = 1,119.14 14934'35.085' 149.5764125' 3402` FEL BP EXPLORATION MPU J -PAD 11MI AS -BUILT CONDUCTOR WELL MP J-23 & J-24 1pr7 Page 35 Version 1 July, 2016 Milne Point Drilling & Completion Procedure Ilik-orp %laska, LLC 30.0 Drill Pipe Specifications 400204138036211 1W Weatherford 4" 14.00 lb/ft Internal Coating S-135 wt HT 38 4-7t8" OD x 2-9116" ID wJ X 7000 Hard Banding Tool Joint DRILL PIPE SPECIFICATIONS 4-718" Grade . S-135 Connection > HT 38 Interchangeable With f 2-318" Ups Tte yep IU Internal Coatin TK 34 XT _ Nominal Weight per Foot 14.00 lbs Adjusted Weight With Tool Joint Rer Foot 15.65 lbs TOOL JOINT DATA Outside Diameter 4-718" Inside Diameter 2-9/16" API Drift 2-7116" Rabbit OD, Suggested 2-318" Hard Band X 7000 Minimum Make-up Torque 12,200 ft -lbs Maximum Recommend Make-up Torque 17.700 ft -lbs Torsional Yield Strength 29.500 ft -lbs Tensile Stren th 649,200 lbs TUBE DATA New Premium Outside Diameter 4.000" 3.868" y Inside Diameter 3.340" 3.340 - Wall Thickness 0.330" 0.264 - Cross Sectional Area 3.805 sq in 2.989 sq in Maximum Hook LoadfTensile Strength 513,600 lbs 403,500 lbs SlipCrushing (SDXL) 431.900 lbs 341300 lbs Burst Pressure 1%u 00 psi 18,400 psi Co►lapse Pressure 20,100 psi 13,81 s1 Torsional Yield Strength 41,900 ft -lbs 32,800 ft -lbs 0.442 USclallft Capacity W/ Tool Joint 0.442 US galift Displacement W/ Tool Joint 1 0.240 US gal/ft 0.223 US galin I 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 toss, 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 responsibility. Page 36 Version 1 July, 2016 Hilcorp Energy Company Milne Point M Pt J Pad MPJ -24 Plan: MPJ -24A Plan: MPJ -24A wp05 Standard Proposal Report 20 July, 2016 HALLISURTON Sperry Drilling Services HALLIBURTON Sperry Orilling CASING DETAILS Project. Milne Point Hilcorp Energy Company Site: M Pt J Pad Well: MPJ -24 Calculation Method: Minimum Curvature Error System: ISCWSA Wellbore: Plan: MPJ -24A Scan Method: Closest Approach 3D Design: MPJ -24A wp05 Error Surface: Elliptical Conic Warning Method: Error Ratio Easting Letittude DI = 6.990 0 Plan:J�24A @ 62.80usft .00 0.00 6015110.45 FORMATION TOP DETAILS N 149° 34' 35.085 W 400 Curvature No formation data is available $'� 800- 0.1 1200 SECTION DETAILS REFERENCE INFORMATION CASING DETAILS WELL DETAILS: MPJ -24 Co-ordinate (WE) Reference: Well MPJ -24, True North TVDSS MD Size Name Ground Level: 36.30 3567.59 7565.00 7 7" TOW Vertical (TVD) Reference: Plan:J-24A @ 62.80usft /-S +E/ -W Northing Easting Letittude Longitude Measured Depth Reference: Plan:J�24A @ 62.80usft .00 0.00 6015110.45 551914.26 70. 27' 7.288 N 149° 34' 35.085 W Calculation Method: Minimum Curvature 0 $'� 6o'.C10 0.1 SECTION DETAILS Sec MD Inc Azi TVD +N/ -S +E/ -W Dleg TFace VSect 1 7497.34 71.85 293.10 3609.16 2046.27 -5484.00 0.00 0.00 5816.14 2 7565.00 71.59 292.82 3630.39 2071.33 -5543.16 0.55 -134.40 5879.61 3 7577.60 73.26 291.82 3634.19 2075.89 -5554.27 15.24 -30.00 5891.49 4 7597.60 73.26 291.82 3639.95 2083.01 -5572.05 0.00 0.00 5910.46 5 7765.33 80.13 298.91 3678.58 2152.97 -5719.29 5.81 45.97 6070.25 6 7772.27 80.13 298.91 3679.77 2156.28 -5725.28 0.00 0.00 6076.86 7 8044.54 86.00 284.11 3712.80 2254.85 -5975.98 5.81 -69.25 6343.96 8 8153.70 91.44 284.49 3715.23 2281.81 -6081.69 5.00 4.03 6453.06 9 9898.34 91.44 284.49 3671.25 2718.34 -7770.26 0.00 0.00 8197.08 10 10072.58 90.82 275.80 3667.80 2749.01 -7941.57 5.00 -94.03 8370.72 11 10080.57 90.75 276.20 3667.69 2749.84 -7949.52 5.00 99.90 8378.64 12 11324.02 90.75 276.20 3651.43 2884.08 -9185.60 0.00 0.00 9610.47 13 11473.57 92.03 268.83 3647.80 2890.63 -9334.85 5.00 -80.10 9756.88 14 13878.31 92.03 268.83 3562.80 2841.46 -11737.59 0.00 0.00 12076.34 SURVEY PROGRAM Date: 2015-05-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 110.74 7497.34 MPJ -24 mad+iifr MWD (MWD+IFR:AK) 7497.34 7830.00 MPJ -24A wp05 MWD_Interp Azi+sag 7830.00 13878.31 MPJ -24A wp05 MWD+IFR2+MS+sag y°y9�(1 ��9'C, y°y9gy 2000 y40, y�03 916`0' �0 11`I0 r,�. 1yy y11. .1y y8 1g. n 2400 1yry��1°� . �ca0`t .1 ty91yy �0 y6191ryry1 �0 31NIL 8 oa �O` 1yy. 6,D" 2800 `1,OQ c0`t y01 H �S�ao4 Sir`° t ° �O`�,O• 0,0 y1 3200 0 °1y�. y\100 t . �c°a01 3600-1m , O 7" TOW O O O O O MPJ -24A Heel v2 MPJ -24A NB Intermed Tgt 7 MPJ -24A Intermed Tgt 2 , 1 1 1 1 1 1 1 1 1 r 1-1 1 F�f -T r - I 5200 5600 6000 6400 6800 7200 7600 8000 8400 8800 9200 9600 10000 10400 10800 11200 11600 12000 12400 12800 Vertical Section at 284.00" (800 usft/in) CASING DETAILS TVD TVDSS MD Size Name 3630.39 3567.59 7565.00 7 7" TOW 3562.80 3500.00 13878.31 4-12 41rY'x 61/8" Ate' 0 O°y1. 0 3yyti. 0 $'� 6o'.C10 0.1 N O\ty`100'. 111x, �O 5�a �C°a0 4 1/2" x 6 1/8" / MPJ -24A wp05 N N Q N W O MPJ -24A Toe v2 MPJ -24 MPJ -24A Permitted BHL MPJ -24A Intermed Tgt 2 , 1 1 1 1 1 1 1 1 1 r 1-1 1 F�f -T r - I 5200 5600 6000 6400 6800 7200 7600 8000 8400 8800 9200 9600 10000 10400 10800 11200 11600 12000 12400 12800 Vertical Section at 284.00" (800 usft/in) J� 4 ell 3733 6./ //,,� //3 /�'$ J' X40,. O'J 10 0,� 'k ) I ./� ) �• alp. ..) .� )sy) O �. seV ' �2T- 3200 >y a 1/2" z 6 1/8^ MPJ.24A Tce v O p•'yp H .45 1,1.Ep 4ip H� O 1 �p MPJ -24A vry05- _ _ \_ _ _ Lp •'/) •./ p �O 2667 O MPI -24A Inlenred Tgt 2 g IMPJ-24A NO Intemcd Tet ao } MPI -24 r TOW 2133 rl �/ 8 MPJ -24A Pemtined BH MPJ -24A Heel v O rA SURVEY PROGRAM SECTION OETAILS WALLIBLJRTON EM REFERENCE INFORMATION T M WELL DETAILS: MPJ -24 +E/ -W Depth From Depth To Survey/Plan C -finale (NA=) Relewnca: Well MPJ -24. lru Norel ~ Ground tavel: 36.30 0 110.74 7497.34 MPJ -24 mwd+iifr Ventral(TVD) Reference: PMn:J-2N 662.80wft Meanurod Depth Reterake: F n"24A Q 62'a" +N/ -S +F/ -W Nonning Evatin6 lalinude lalPjOde Project: Milne Point Calod"en Metlgtl: MlMmmn C n 0.00 0.00 6015110:3 551914.26 70° 27 7.288 N 141'14'11,011 W Site: M Pt J Pad MWD+IFR2+MS+ug -30.00 Strength: 57582.4wT Well: MPJ -24 393915 2093.01 CASING DETAILS Wellbore: Plan: MPJ -24A 0.00 TVD TVDSS MD Size Name Plan: MPJ -24A Wp05 2152.97 2156.28 3530.39 3507.89 7565.00 7 r TOW 6070.25 W78.86 3562.00 3500.00 13878.31 4-12 4 12^ z 51/8' J� 4 ell 3733 6./ //,,� //3 /�'$ J' X40,. O'J 10 0,� 'k ) I ./� ) �• alp. ..) .� )sy) O �. seV ' �2T- 3200 >y a 1/2" z 6 1/8^ MPJ.24A Tce v O p•'yp H .45 1,1.Ep 4ip H� O 1 �p MPJ -24A vry05- _ _ \_ _ _ Lp •'/) •./ p �O 2667 O MPI -24A Inlenred Tgt 2 g IMPJ-24A NO Intemcd Tet ao } MPI -24 r TOW 2133 rl �/ 8 MPJ -24A Pemtined BH MPJ -24A Heel v O rA 533 -12800 -12267 -11731 -11200 -10667 -10133 -9600 -9067 -8533 -8000 -7467 -6933 -6400 -5867 -5333 West(-YEast(+) (800 usft/in) SURVEY PROGRAM SECTION OETAILS Date: 2015-M26T00:00:00 Validated: Yea Version: T M A2imu11m 10 True NoM +E/ -W Depth From Depth To Survey/Plan Tool ~ Magnetic North: 18.86' 0 110.74 7497.34 MPJ -24 mwd+iifr MWD (MWD+IFR:AK -5484.00 -5543.1-6 0.00 0.55 0.00 -134.40 7497.34 7830.00 MPJ -24A wpO5 MWD_Interp Azi+sag 3 7577.60 73.28 291.82 Magnetic Field 2075.89 7630.00 13878.31 MPJ -24A wp05 MWD+IFR2+MS+ug -30.00 Strength: 57582.4wT 4 7597.60 73.26 291.82 393915 2093.01 Dry A,,*: 81.06° 0.00 0.00 5110AB Data: 505r2015 3676.59 3679.77 2152.97 2156.28 -571919 -5725.28 5.81 0.00 Model: BGGM2016 533 -12800 -12267 -11731 -11200 -10667 -10133 -9600 -9067 -8533 -8000 -7467 -6933 -6400 -5867 -5333 West(-YEast(+) (800 usft/in) SECTION OETAILS Sec MOInc Ad TWD +W8 +E/ -W Oleo TF- ~ Target 1 7497.34 71.85 293.10 2 7565.00 11.59 292.82 3609.19 36:W.38 2018.27 2071.33 -5484.00 -5543.1-6 0.00 0.55 0.00 -134.40 5816.14 587961 3 7577.60 73.28 291.82 ]634.19 2075.89 -5554.27 15.24 -30.00 589118 4 7597.60 73.26 291.82 393915 2093.01 -5572.05 0.00 0.00 5110AB 5 7785.33 80.13 296.91 6 7772.27 80.13 2%.9/ 3676.59 3679.77 2152.97 2156.28 -571919 -5725.28 5.81 0.00 45.97 0.00 6070.25 W78.86 7 9044.54 88.00 284.11 3712.60 2254.95 -5975.% 5.91 89.256343.% MPJ -24A Neel n 8 8153.70 91.44 284.49 3715.23 2261.01 801.89 5.00 4.03 6153.08 99898.34 91.44 284.49 10 1W72.56 90.82 275.80 3671.25 3667.80 2719.34 2749.01 -7770.26 -7941.57 0.00 5.00 000 -91.03W70.72 8197.08 MPJ -24A N8 InWn-I T91 1 11 10080.57 90.75 278.20 3867.69 2749.84 -7949.52 5.00 99.90 8378.64 12 it32402 90.75 27620 3851.43 2884.08 -9185.60 0.00 0.00 9610A7 13 11473.57 92.03 268.83 14 13878.31 92.03 268.83 WITI 0 3562.% 2890.63 2841.46 -9334.05 -11737.59 5.00 0.00 80.10 0.00 9756.88 12076.34 MPJ -272 1,&-W T9t 2 MPJ -24A Tae Y2 533 -12800 -12267 -11731 -11200 -10667 -10133 -9600 -9067 -8533 -8000 -7467 -6933 -6400 -5867 -5333 West(-YEast(+) (800 usft/in) Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Milne Point Site: M Pt J Pad Well: MPJ -24 Wellbore: Plan: MPJ -24A Design: MPJ-24Awp05 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well MPJ -24 Plan:J-24A @ 62.80usft Plan:J-24A @ 62.80usft 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 Site M Pt J Pad, TR -13-10 Site Position: Northing: 6,013,415.23 usft Latitude: 70° 26'50.647 N From: Map Easting: 551,435.10usft Longitude: 149° 34'49.503 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.40 ° Well MPJ -24 Well Position +N/ -S 0.00 usft Northing: 6,015,110.45 usft Latitude: 70° 27'7.288 N +E/ -W 0.00 usft Easting: 551,914.26 usft Longitude: 149° 34'35.085 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 36.30 usft Wellbore Plan: MPJ -24A Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) i BGGM2016 5/26/2015 18.86 81.06 57,582 Design MPJ-24Awp05 I Audit Notes: Version: Phase: PLAN Tie On Depth: 7,497.34 i Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) 26.50 0.00 0.00 284.00 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +Nl-S +E/ -W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°I100usft) (°/100usft) (°1100usft) (°) 7,497.34 71.85 293.10 3,609.16 3,546.36 2,046.27 -5,484.00 0.00 0.00 0.00 0.00 7,565.00 71.59 292.82 3,630.39 3,567.59 2,071.33 -5,543.16 0.55 -0.38 -0.41 -134.40 7,577.60 73.26 291.82 3,634.19 3,571.39 2,075.89 -5,554.27 15.24 13.22 -7.96 -30.00 7,597.60 73.26 291.82 3,639.95 3,577.15 2,083.01 -5,572.05 0.00 0.00 0.00 0.00 7,765.33 80.13 298.91 3,678.58 3,615.78 2,152.97 -5,719.29 5.81 4.10 4.23 45.97 7,772.27 80.13 298.91 3,679.77 3,616.97 2,156.28 -5,725.28 0.00 0.00 0.00 0.00 8,044.54 86.00 284.11 3,712.80 3,650.00 2,254,85 -5,975.98 5.81 2.15 -5.44 -69.25 8,153.70 91.44 284.49 3,715.23 3,652.43 2,281,81 -6,081.69 5.00 4.99 0.35 4.03 9,898.34 91.44 284.49 3,671.25 3,608.45 2,718.34 -7,770.26 0.00 0.00 0.00 0.00 10,072.58 90.82 275.80 3,667.80 3,605.00 2,749.01 -7,941.57 5.00 -0.36 -4.99 -94.03 10,080.57 90.75 276.20 3,667.69 3,60489 2,749.84 -7,949.52 5.00 -0.86 4.93 99.90 11,324.02 90.75 276.20 3,651.43 3,588.63 2,884.08 -9,185.60 0.00 0.00 0.00 0.00 11,473.57 92.03 268.83 3,647.80 3,585.00 2,890.63 -9,334.85 5.00 0.85 -4.93 -80.10 13,878.31 92.03 268.83 3,562.80 3,500.00 2,841,46 -11,737.59 0.00 0.00 0.00 0.00 712012016 11:57 14AM Page 2 COMPASS 5000.1 Build 81 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well MPJ -24 Company: Hilcorp Energy Company TVD Reference: Plan:J-24A @ 62.80usft Project: Milne Point MD Reference: Plan:J-24A @ 62.80usft Site: M Pt J Pad North Reference: True Well: MPJ -24 Survey Calculation Method: Minimum Curvature Wellbore: Plan: MPJ -24A Design: MPJ-24Awp05 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +El -W Northing Easting DLS Vert Section (usft) V) (I (usft) usft (usft) (usft) (usft) (usft) -36.30 26.50 0.00 0.00 26.50 -36.30 0.00 0.00 6,015,110.45 551,914.26 0.00 0.00 110.74 0.05 153.27 110.74 47.94 -0.03 0.02 6,015,110.42 551,914.28 0.06 -0.02 202.40 0.18 153.27 202.40 139.60 -0.20 0.10 6,015,110.25 551,914.36 0.14 -0.14 292.82 0.16 212.94 292.82 230.02 -0.43 0.09 6,015,110.02 551,914.36 0.19 -0.20 322.91 0.62 256.79 322.91 260.11 -0.50 -0.09 6,015,109.95 551,914.18 1.72 -0.04 416.32 2.94 278.04 416.27 353.47 -0.28 -2.95 6,015,110.15 551,911.31 2.54 2.80 508.96 5.65 276.73 508.64 445.84 0.58 -9.83 6,015,110.97 551,904.42 2.93 9.68 600.55 8.54 288.71 599.52 536.72 3.29 -20.76 6,015,113.60 551,893.48 3.53 20.94 695.09 10.89 295.67 692.70 629.90 9.42 -35.46 6,015,119.62 551,878.74 2.77 36.68 787.30 13.70 297.54 782.79 719.99 18.24 -52.99 6,015,128.32 551,861.15 3.08 55.83 878.97 16.30 296.27 871.33 808.53 28.95 -74.16 6,015,138.88 551,839.91 2.86 78.96 971.61 18.78 292.76 959.66 896.86 40.48 -99.57 6,015,150.23 551,814.42 2.91 106.41 1,063.77 21.99 289.23 1,046.04 983.24 51.91 -129.55 6,015,161.45 551,784.36 3.73 138.26 1,158.73 24.62 292.07 1,133.25 1,070.45 65.20 -164.68 6,015,174.49 551,749.15 3.01 175.56 1,251.57 28.14 290.48 1,216.41 1,153.61 80.13 -203.12 6,015,189.15 551,710.61 3.87 216.47 1,343.52 31.83 290.03 1,296.04 1,233.24 96.02 -246.23 6,015,204.75 551,667.39 4.02 262.14 1,435.83 35.60 288.79 1,372.81 1,310.01 113.02 -294.55 6,015,221.41 551,618.96 4.15 313.14 1,528.09 36.64 290.02 1,447.33 1,384.53 131.10 -345.84 6,015,239.12 551,567.55 1.37 367.28 1,620.96 40.69 288.11 1,519.83 1,457.03 150.00 -400.68 6,015,257.64 551,512.59 4.55 425.06 1,714.61 42.09 289.35 1,590.09 1,527.29 169.89 459.31 6,015,277.12 551,453.82 1.73 486.77 1,806.38 44.88 289.23 1,656.67 1,593.87 190.75 -518.91 6,015,297.56 551,394.08 3.04 549.65 1,902.76 46.30 291.66 1,724.12 1,661.32 214.81 -583.41 6,015,321.17 551,329.43 2.33 618.05 1,994.40 48.37 291.57 1,786.22 1,723.42 239.63 -046.05 6,015,345.55 551,266.62 2.26 684.83 2,086.44 49.88 290.78 1,846.45 1,783.65 264.77 -710.95 6,015,370.23 551,201.56 1.76 753.88 2,179.47 51.00 290.99 1,905.70 1,842.90 290.34 -777.95 6,015,395.33 551,134.38 1.22 825.09 2,271.87 55.12 292.72 1,961.22 1,898.42 317.85 -846.47 6,015,422.36 551,065.68 4.70 898.22 2,363.37 59.53 294.20 2,010.61 1,947.81 348.52 -917.09 6,015,452.54 550,994.85 5.01 974.17 2,457.34 63.63 291.82 2,055.33 1,992.53 380.79 -993.15 6,015,484.27 550,918.58 4.90 1,055.77 2,550.10 67.07 294.46 2,094.02 2,031.22 413.94 -1,070.64 6,015,516.88 550,840.86 4.52 1,138.98 2,644.07 70.11 293.39 2,128.32 2,065.52 449.40 -1,150.60 6,015,551.78 550,760.67 3.40 1,225.15 2,763.31 69.67 294.07 2,169.31 2,106.51 494.46 -1,253.11 6,015,596.12 550,657.86 0.65 1,335.50 2,856.09 70.37 291.71 2,201.02 2,138.22 528.37 -1,333.43 6,015,629.47 550,577.31 2.51 1,421.65 2,948.89 72.19 293.44 2,230.80 2,168.00 562.11 -1,414.58 6,015,662.64 550,495.94 2.64 1,508.55 3,039.84 72.26 290.95 2,258.57 2,195.77 594.83 -1,494.76 6,015,694.79 550,415.54 2.61 1,594.26 3,127.89 71.98 287.16 2,285.62 2,222.82 622.18 -1,573.95 6,015,721.59 550,336.17 4.11 1,677.71 3,222.95 71.17 287.29 2,315.66 2,252.86 648.89 -1,660.09 6,015,747.69 550,249.85 0.86 1,767.76 3,315.38 70.34 287.25 2,346.13 2,283.33 674.79 -1,743.42 6,015,773.02 550,166.35 0.90 1,854.88 3,412.42 71.34 289.17 2,377.98 2,315.18 703.44 -1,830.49 6,015,801.05 550,079.10 2.13 1,946.29 3,502.08 71.89 290.04 2,406.26 2,343.46 731.99 -1,910.64 6,015,829.04 549,998.76 1.11 2,030.97 3,595.05 69.40 291.40 2,437.07 2,374.27 763.01 -1,992.67 6,015,859.49 549,916.51 3.01 2,118.07 3,687.13 69.08 290.49 2,469.71 2,406.91 793.79 -2,073.08 6,015,889.71 549,835.90 0.99 2,203.54 3,780.41 70.70 290.60 2,501.78 2,438.98 824.53 -2,155.10 6,015,919.87 549,753.68 1.74 2,290.56 3,869.73 73.75 291.51 2,529.04 2,466.24 855.09 -2,234.47 6,015,949.87 549,674.11 3.55 2,374.96 3,967.80 72.92 291.72 2,557.17 2,494.37 889.70 -2,321.81 6,015,983.87 549,586.53 0.87 2,468.08 4,057.01 72.34 292.16 2,583.80 2,521.00 921.51 -2,400.78 6,016,015.12 549,507.35 0.80 2,552.40 7120/2016 11:57:14AM Page 3 COMPASS 5000.1 Build 81 HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Company. Hilcorp Energy Company TVD Reference: Project: Milne Point MD Reference: Site: M Pt J Pad North Reference: Well: MPJ -24 Survey Calculation Method: Wellbore: Plan: MPJ -24A 292.00 Design: MPJ-24Awp05 4,247.39 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) V) V) (usft) usft 4,153.08 72.12 292.00 2,613.12 2,550.32 4,247.39 71.27 292.36 2,642.74 2,579.94 4,340.01 71.13 292.98 2,672.59 2,609.79 4,431.77 71.14 292.95 2,702.26 2,639.46 4,527.25 71.38 290.42 2,732.94 2,670.14 4,620.13 71.42 290.97 2,762.56 2,699.76 4,713.10 71.42 291.07 2,792.18 2,729.38 4,805.83 73.90 290.09 2,819.82 2,757.02 4,898.75 74.62 290.50 2,845.03 2,782.23 4,991.27 74.94 289.68 2,869.32 2,806.52 5,083.92 74.68 289.38 2,893.59 2,830.79 5,176.62 75.19 289.88 2,917.69 2,854.89 5,269.27 75.42 289.85 2,941.19 2,878.39 5,360.57 73.59 289.59 2,965.58 2,902.78 5,454.76 73.75 289.51 2,992.06 2,929.26 5,547.19 73.29 289.15 3,018.28 2,955.48 5,641.34 73.18 289.39 3,045.44 2,982.64 5,730.66 74.14 288.67 3,070.57 3,007.77 5,825.77 74.93 289.32 3,095.93 3,033.13 5,917.42 73.20 289.00 3,121.09 3,058.29 6,013.88 70.91 288.77 3,150.81 3,088.01 6,106.62 70.56 288.43 3,181.41 3,118.61 6,199.28 70.16 287.95 3,212.55 3,149.75 6,291.76 70.55 287.78 3,243.64 3,180.84 6,384.43 71.73 287.59 3,273.60 3,210.80 6,476.70 72.16 287.75 3,302.20 3,239.40 6,568.27 71.97 288.94 3,330.40 3,267.60 6,663.41 72.59 288.67 3,359.35 3,296.55 6,756.20 72.44 290.74 3,387.23 3,324.43 6,848.77 73.05 290.59 3,414.69 3,351.89 6,941.79 73.99 290.38 3,441.08 3,378.28 7,034.30 72.18 290.59 3,468.00 3,405.20 7,127.54 72.60 290.62 3,496.20 3,433.40 7,220.09 72.08 290.27 3,524.28 3,461.48 7,312.01 72.99 290.88 3,551.87 3,489.07 7,405.28 71.56 292.17 3,580.26 3,517.46 7,497.34 71.85 293.10 3,609.16 3,546.36 7,500.00 71.84 293.09 3,609.99 3,547.19 7,565.00 71.59 292.82 3,630.39 3,567.59 KOP: Start Dir 15.2401100': 7665' MD, 3630.39'TVD - 7" TOW 7,575.00 72.91 292.02 3,633.43 3,570.63 7,577.60 73.26 291.82 3,634.19 3,571.39 End Dir : 7577.6' MD, 3634.19' TVD 6,017,053.19 546,580.42 7,597.60 73.26 291.82 3,639.95 3,577.15 Start Dir 5.81°1100' : 7597.6' MD, 3639.95'TVD Halliburton Standard Proposal Report Well MPJ -24 Plan:J-24A @ 62.80usft Plan:J-24A @ 62.80usft True Minimum Curvature 7/2012016 11:5714AM Page 4 COMPASS 5000.1 Build 81 Map Map +N1S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 2,560.32 955.90 -2,485.56 6,016,048.92 549,422.34 0.28 2,642.98 989.70 -2,568.47 6,016,082.14 549,339.20 0.97 2,731.61 1,023.49 -2,649.38 6,016,115.36 549,258.07 0.65 2,818.29 1,057.37 -2,729.33 6,016,148.68 549,177.90 0.03 2,904.06 1,090.78 -2,813.34 6,016,181.50 549,093.66 2.52 2,993.65 1,121.89 -2,895.69 6,016,212.03 549,011.11 0.56 3,081.08 1,153.50 -2,977.95 6,016,243.06 548,928.64 0.10 3,168.54 1,184.60 -3,060.81 6,016,273.59 548,845.57 2.86 3,256.47 1,215.63 -3,144.69 6,016,304.02 548,761.48 0.88 3,345.37 1,246.29 -3,228.53 6,016,334.10 548,677.44 0.92 3,434.14 1,276.18 -3,312.80 6,016,363.40 548,592.97 0.42 3,523.13 1,306.25 -3,397.11 6,016,392.88 548,508.46 0.76 3,612.21 1,336.71 -3,481.40 6,016,422.74 548,423.97 0.25 3,701.36 1,366.39 -3,564.22 6,016,451.85 548,340.96 2.02 3,788.90 1,396.64 -3,649.39 6,016,481.50 548,255.58 0.19 3,878.87 1,425.98 -3,733.03 6,016,510.25 548,171.75 0.62 3,967.12 1,455.73 -3,818.13 6,016,539.40 548,086.45 0.27 4,056.89 1,483.67 -3,899.16 6,016,566.78 548,005.24 1.32 4,142.27 1,513.51 -3,985.83 6,016,596.01 547,918.37 1.06 4,233.58 1,542.44 -4,069.07 6,016,624.35 547,834.94 1.92 4,321.35 1,572.14 -4,155.89 6,016,653.45 547,747.92 2.38 4,412.78 1,600.06 -4,238.87 6,016,680.79 547,664.76 0.51 4,500.04 1,627.30 -4,321.77 6,016,707.45 547,581.67 0.65 4,587.08 1,654.02 -4,404.67 6,016,733.59 547,498.60 0.46 4,673.98 1,680.66 -4,488.22 6,016,759.64 547,414.88 1.29 4,761.49 1,707.29 -4,571.81 6,016,785.68 547,331.11 0.49 4,849.04 1,734.71 -4,654.50 6,016,812.52 547,248.24 1.25 4,935.90 1,763.92 -4,740.29 6,016,841.14 547,162.26 0.71 5,026.21 1,793.76 -4,823.60 6,016,870.39 547,078.75 2.13 5,114.27 1,824.96 -4,906.32 6,016,901.01 546,995.82 0.68 5,202.08 1,856.17 -4,989.87 6,016,931.64 546,912.06 1.03 5,290.70 1,887.15 -5,072.78 6,016,962.03 546,828.95 1.97 5,378.64 1,918.42 -5,155.97 6,016,992.72 546,745.55 0.45 5,466.92 1,949.23 5,238.60 6,017,022.95 546,662.72 0.67 5,554.55 1,980.04 -5,320.69 6,017,053.19 546,580.42 1.18 5,641.66 2,012.63 -5,403.33 6,017,085.20 546,497.56 2.02 5,729.73 2,046.27 -5,484.00 6,017,118.27 546,416.67 1.01 5,816.14 2,047.26 -5,486.33 6,017,119.25 546,414.33 0.55 5,818.64 2,071.33 -5,543.16 6,017,142.92 546,357.34 0.55 5,879.61 2,074.97 -5,551.96 6,017,146.49 546,348.51 15.24 5,889.03 2,075.89 -5,554.27 6,017,147.40 546,346.20 15.24 5,891.49 2,083.01 -5,572.05 6,017,154.39 546,328.37 0.00 5,910.46 7/2012016 11:5714AM Page 4 COMPASS 5000.1 Build 81 Planned Survey Halliburton H A L L I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Coordinate Reference: Well MPJ -24 Company: Hilcorp Energy Company TVD Reference: Plan:J-24A @ 62.80usft Project: Milne Point MD Reference: Plan:J-24A @ 62.80usft Site: M Pt J Pad North Reference: True Well: MPJ -24 Survey Calculation Method: Minimum Curvature Wellbore: Plan: MPJ -24A Depth Inclination Design: MPJ-24Awp05 Depth TVDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,577.84 7,600.00 73.35 291.92 3,640.64 3,577.84 2,083.87 -5,574.18 6,017,155.24 546,326.23 5.81 5,912.74 7,650.00 75.38 294.08 3,654.12 3,591.32 2,102.68 -5,618.50 6,017,173.74 546,281.79 5.81 5,960.29 7,700.00 77.43 296.19 3,665.87 3,603.07 2,123.33 -5,662.49 6,017,194.08 546,237.66 5.81 6,007.97 I, 7,750.00 79.50 298.28 3,675.87 3,613.07 2,145.75 -5,706.04 6,017,216.19 546,193.96 5.81 6,055.65 7,765.33 80.13 298.91 3,678.58 3,615.78 2,152.97 -5,719.29 6,017,223.32 546,180.66 5.81 6,070.25 End Dir : 7765.33' MD, 3678.58' TVD 7,772.27 80.13 298.91 3,679.77 3,616.97 2,156.28 -5,725.28 6,017,226.58 546,174.66 0.00 6,076.86 Start Dir 5.8111100': 7772.27' MD, 3679.77'TVD 7,800.00 80.71 297.38 3,684.38 3,621.58 2,169.18 -5,749.38 6,017,239.31 546,150.46 5.81 6,103.37 7,850.00 81.76 294.65 3,692.00 3,629.20 2,190.85 -5,793.79 6,017,260.67 546,105.91 5.81 6,151.70 7,900.00 82.83 291.92 3,698.71 3,635.91 2,210.43 -5,839.30 6,017,279.93 546,060.27 5.81 6,200.60 7,950.00 83.91 289.21 3,704.48 3,641.68 2,227.87 -5,885.79 6,017,297.05 546,013.66 5.81 6,249.93 8,000.00 85.01 286.51 3,709.31 3,646.51 2,243.13 -5,933.16 6,017,311.98 545,966.20 5.81 6,299.58 8,044.54 86.00 284.11 3,712.80 3,650.00 2,254.85 -5,975.98 6,017,323.40 545,923.30 5.81 6,343.97 Start Dir 5°/100' : 8044.54' MD, 3712.8'TVD 8,100.00 88.77 284.31 3,715.33 3,652.53 2,268.45 -6,029.68 6,017,336.62 545,869.51 5.00 6,399.36 8,153.70 91.44 284.49 3,715.23 3,652.43 2,281.81 -6,081.69 6,017,349.61 545,817.41 5.00 6,453.06 i End Dir : 8153.7' MD, 3715.23' TVD 8,200.00 91.44 284.49 3,714.07 3,651.27 2,293.39 -6,126.50 6,017,360.88 545,772.52 0.00 6,499.34 8,300.00 91.44 284.49 3,711.54 3,648.74 2,318.41 -6,223.29 6,017,385.23 545,675.57 0.00 6,599.31 8,400.00 91.44 284.49 3,709.02 3,646.22 2,343.43 -6,320.08 6,017,409.57 545,578.63 0.00 6,699.27 8,500.00 91.44 284.49 3,706.50 3,643.70 2,368.46 -6,416.86 6,017,433.92 545,481.68 0.00 6,799.23 8,600.00 91.44 284.49 3,703.98 3,641.18 2,393.48 -6,513.65 6,017,458.26 545,384.73 0.00 6,899.20 8,700.00 91.44 284.49 3,701.46 3,638.66 2,418.50 -6,610.43 6,017,482.61 545,287.78 0.00 6,999.16 8,800.00 91.44 284.49 3,698.94 3,636.14 2,443.52 -6,707.22 6,017,506.95 545,190.83 0.00 7,099.13 8,900.00 91.44 284.49 3,696.42 3,633.62 2,468.54 -6,804.01 6,017,531.29 545,093.88 0.00 7,199.09 9,000.00 91.44 284.49 3,693.90 3,631.10 2,493.56 -6,900.79 6,017,555.64 544,996.93 0.00 7,299.06 9,100.00 91.44 284.49 3,691.37 3,628.57 2,518.58 -6,997.58 6,017,579.98 544,899.98 0.00 7,399.02 9,200.00 91.44 284.49 3,688.85 3,626.05 2,543.61 -7,094.37 6,017,604.33 544,803.04 0.00 7,498.99 9,300.00 91.44 284.49 3,686.33 3,623.53 2,568.63 -7,191.15 6,017,628.67 544,706.09 0.00 7,598.95 9,400.00 91.44 284.49 3,683.81 3,621.01 2,593.65 -7,287.94 6,017,653.01 544,609.14 0.00 7,698.91 9,500.00 91.44 284.49 3,681.29 3,618.49 2,618.67 -7,384.72 6,017,677.36 544,512.19 0.00 7,798.88 9,600.00 91.44 284.49 3,678.77 3,615.97 2,643.69 -7,481.51 6,017,701.70 544,415.24 0.00 7,898.84 9,700.00 91.44 284.49 3,676.25 3,613.45 2,668.71 -7,578.30 6,017,726.05 544,318.29 0.00 7,998.81 9,800.00 91.44 284.49 3,673.73 3,610.93 2,693.73 -7,675.08 6,017,750.39 544,221.34 0.00 8,098.77 9,898.34 91.44 284.49 3,671.25 3,608.45 2,718.34 -7,770.26 6,017,774.33 544,126.00 0.00 8,197.08 Start Dir 5°/100' : 9898.34' MD, 3671.25'TVD 9,900.00 91.44 284.41 3,671.21 3,608.41 2,718.75 -7,771.87 6,017,774.73 544,124.39 4.99 8,198.74 10,000.00 91.08 279.42 3,669.00 3,606.20 2,739.39 -7,869.66 6,017,794.69 544,026.47 5.00 8,298.62 10,072.58 90.82 275.80 3,667.80 3,605.00 2,749.01 -7,941.57 6,017,803.80 543,954.50 5.00 8,370.72 10,080.57 90.75 276.20 3,667.69 3,604.89 2,749.84 -7,949.52 6,017,804.58 543,946.55 5.00 8,378.63 End Dir : 10080.57' MD, 3667.69' TVD 10,100.00 90.75 276.20 3,667.44 3,604.64 2,751.94 -7,968.84 6,017,806.54 543,927.22 0.00 8,397.88 10,200.00 90.75 276.20 3,666.13 3,603.33 2,762.74 -8,068.24 6,017,816.64 543,827.75 0.00 8,496.95 10,300.00 90.75 276.20 3,664.82 3,602.02 2,773.53 -8,167.65 6,017,826.75 543,728.28 0.00 8,596.01 712012016 11:57:14AM Page 5 COMPASS 5000.1 Build 81 Planned Survey Halliburton H A LL I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well MPJ -24 Company: Hilcorp Energy Company TVD Reference: Plan:J-24A @ 62.80usft Project: Milne Point MD Reference: Plan:J-24A @ 62.80usft Site: M Pt J Pad North Reference: True Well: MPJ -24 Survey Calculation Method: Minimum Curvature Wellbore: Plan: MPJ -24A Depth Inclination Design: MPJ-24Awp05 Depth TVDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/.S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,600.71 10,400.00 90.75 276.20 3,663.51 3,600.71 2,784.33 -8,267.06 6,017,836.85 543,628.81 0.00 8,695.08 10,500.00 90.75 276.20 3,662.20 3,599.40 2,795.12 -8,366.47 6,017,846.95 543,529.34 0.00 8,794.15 10,600.00 90.75 276.20 3,660.90 3,598.10 2,805.92 -8,465.87 6,017,857.05 543,429.87 0.00 8,893.21 10,700.00 90.75 276.20 3,659.59 3,596.79 2,816.71 -8,565.28 6,017,867.15 543,330.40 0.00 8,992.28 10,800.00 90.75 276.20 3,658.28 3,595.48 2,827.51 -8,664.69 6,017,877.25 543,230.93 0.00 9,091.34 10,900.00 90.75 276.20 3,656.97 3,594.17 2,838.30 -8,764.09 6,017,887.36 543,131.46 0.00 9,190.41 11,000.00 90.75 276.20 3,655.66 3,592.86 2,849.10 -8,863.50 6,017,897.46 543,031.99 0.00 9,289.48 11,100.00 90.75 276.20 3,654.36 3,591.56 2,859.89 -8,962.91 6,017,907.56 542,932.52 0.00 9,388.54 11,200.00 90.75 276.20 3,653.05 3,590.25 2,870.69 -9,062.31 6,017,917.66 542,833.05 0.00 9,487.61 11,300.00 90.75 276.20 3,651.74 3,588.94 2,881.48 -9,161.72 6,017,927.76 542,733.58 0.00 9,586.67 11,324.02 90.75 276.20 3,651.43 3,588.63 2,884.08 -9,185.60 6,017,930.19 542,709.68 0.00 9,610.47 Start Dir 501100': 11324.02' MD, 3651.43'TVD 11,400.00 91.40 272.45 3,650.00 3,587.20 2,889.81 -9,261.33 6,017,935.39 542,633.92 5.00 9,685.34 11,473.57 92.03 268.83 3,647.80 3,585.00 2,890.63 -9,334.85 6,017,935.70 542,560.40 5.00 9,756.88 End Dir : 11473.57' MD, 3647.8' TVD 11,500.00 92.03 268.83 3,646.87 3,584.07 2,890.09 -9,361.26 6,017,934.98 542,534.00 0.00 9,782.37 11,600.00 92.03 268.83 3,643.33 3,580.53 2,888.04 -9,461.18 6,017,932.24 542,434.11 0.00 9,878.82 11,700.00 92.03 268.83 3,639.80 3,577.00 2,886.00 -9,561.10 6,017,929.49 542,334.22 0.00 9,975.28 11,800.00 92.03 268.83 3,636.26 3,573.46 2,883.96 -9,661.01 6,017,926.75 542,234.33 0.00 10,071.73 11,900.00 92.03 268.83 3,632.73 3,569.93 2,881.91 -9,760.93 6,017,924.01 542,134.44 0.00 10,168.18 12,000.00 92.03 268.83 3,629.19 3,566.39 2,879.87 -9,860.85 6,017,921.27 542,034.55 0.00 10,264.64 12,100.00 92.03 268.83 3,625.66 3,562.86 2,877.82 -9,960.76 6,017,918.53 541,934.66 0.00 10,361.09 12,200.00 92.03 268.83 3,622.12 3,559.32 2,875.78 -10,060.68 6,017,915.79 541,834.77 0.00 10,457.55 12,300.00 92.03 268.83 3,618.59 3,555.79 2,873.73 -10,160.60 6,017,913.05 541,734.88 0.00 10,554.00 12,400.00 92.03 268.83 3,615.05 3,552.25 2,871.69 -10,260.51 6,017,910.31 541,634.99 0.00 10,650.45 12,500.00 92.03 268.83 3,611.52 3,548.72 2,869.64 -10,360.43 6,017,907.57 541,535.10 0.00 10,746.91 12,600.00 92.03 268.83 3,607.98 3,545.18 2,867.60 -10,460.34 6,017,904.83 541,435.21 0.00 10,843.36 12,700.00 92.03 268.83 3,604.45 3,541.65 2,865.55 -10,560.26 6,017,902.09 541,335.32 0.00 10,939.82 12,800.00 92.03 268.83 3,600.91 3,538.11 2,863.51 -10,660.18 6,017,899.35 541,235.43 0.00 11,036.27 12,900.00 92.03 268.83 3,597.38 3,534.58 2,861.46 -10,760.09 6,017,896.61 541,135.54 0.00 11,132.72 13,000.00 92.03 268.83 3,593.85 3,531.05 2,859.42 -10,860.01 6,017,893.87 541,035.65 0.00 11,229.18 13,100.00 92.03 268.83 3,590.31 3,527.51 2,857.38 -10,959.93 6,017,891.13 540,935.76 0.00 11,325.63 13,200.00 92.03 268.83 3,586.78 3,523.98 2,855.33 -11,059.84 6,017,888.39 540,835.86 0.00 11,422.09 13,300.00 92.03 268.83 3,583.24 3,520.44 2,853.29 -11,159.76 6,017,885.65 540,735.97 0.00 11,518.54 13,400.00 92.03 268.83 3,579.71 3,516.91 2,851.24 -11,259.68 6,017,882.91 540,636.08 0.00 11,614.99 13,500.00 92.03 268.83 3,576.17 3,513.37 2,849.20 -11,359.59 6,017,880.17 540,536.19 0.00 11,711.45 13,600.00 92.03 268.83 3,572.64 3,509.84 2,847.15 -11,459.51 6,017,877.43 540,436.30 0.00 11,807.90 13,700.00 92.03 268.83 3,569.10 3,506.30 2,845.11 -11,559.43 6,017,874.69 540,336.41 0.00 11,904.36 13,800.00 92.03 268.83 3,565.57 3,502.77 2,843.06 -11,659.34 6,017,871.95 540,236.52 0.00 12,000.81 13,878.31 92.03 268.83 3,562.80 3,500.00 2,841.46 -11,737.59 6,017,869.80 540,158.30 0.00 12,076.34 Total Depth: 13878.31' MD, 3562.8' TVD -4112" x 6 118" 7/20/2016 11:57:14AM Page 6 COMPASS 5000.1 Build 81 HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Company: Hilcorp Energy Company TVD Reference: Project: Milne Point MD Reference: Site: M Pt J Pad North Reference: Well: MPJ -24 Survey Calculation Method: Wellbore: Plan: MPJ -24A Dip Angle Design: MPJ-24Awp05 +N/S Halliburton Standard Proposal Report Well MPJ -24 Plan:J-24A @ 62.80usft Plan:J-24A @ 62.80usft True Minimum Curvature Targets Measured Vertical Local Coordinates Target Name Depth Depth +N/ -S +E/ -W (usft) (usft) hit MM target Dip Angle Dip Dir. TVD +N/S +EI -W Northing Easting - Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPJ -24A Permitted SHL 0.00 0.00 3,598.67 2,531.81 -11,718.86 6,017,560.32 540,179.18 plan misses target center by 311.98usft at 13864.66usft MD (3563.28 TVD, 2841.74 N, -11723.95 E) Start Dir 5.811/100': 7772.27' MD, 3679.77'TVD 8,044.54 3,712.80 Circle (radius 500.00) -5,975.98 Start Dir 5°/100' : 8044.54' MD, 3712.8'TVD 8,153.70 3,715.23 2,281.81 -6,081.69 End Dir : 8153.7' MD, 3715.23' TVD MPJ-24AToe v2 0.00 0.00 3,562.80 2,841.46 -11,737-59 6,017,869.80 i 540,158.30 plan hits target center End Dir : 10080.57' MD, 3667.69' TVD 11,324.02 3,651.43 2,884.08 -9,185.60 Start Dir 50/100': 11324.02' MD, 3651.43'TVD 11,473.57 Point 2,890.63 -9,334.85 End Dir : 11473.57' MD, 3647.8' TVD 13,878.31 3,562.80 2,841.46 -11,737.59 MPJ -24A Heel v2 0.00 0.00 3,712.80 2,254.85 -5,975.98 6,017,323.40 545,923.30 plan hits target center Circle (radius 50.00) MPJ -24A NB Intermed Tgt 1 0.00 0.00 3,667.80 2,749.01 -7,941.57 6,017,803.80 543,954.50 plan hits target center Point MPJ -24A Intermed Tgt 2 0.00 0.00 3,647.80 2,890.63 -9,334.85 6,017,935.70 542,560.40 - plan hits target center - Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 7,565.00 3,630.39 7" TOW 7 9-7/8 13,878.31 3,562.80 41/2"x61/8" 4-1/2 6-1/8 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 7,565.00 3,630.39 2,071.33 -5,543.16 KOP: Start Dir 15.241/100': 7565' MD, 3630.39'TVD 7,577.60 3,634.19 2,075.89 -5,554.27 End Dir : 7577.6' MD, 3634.19' TVD 7,597.60 3,639.95 2,083.01 -5,572.05 Start Dir 5.81°/100' : 7597.6' MD, 3639.95'TVD 7,765.33 3,678.58 2,152.97 -5,719.29 End Dir : 7765.33' MD, 3678.58' TVD 7,772.27 3,679.77 2,156.28 -5,725.28 Start Dir 5.811/100': 7772.27' MD, 3679.77'TVD 8,044.54 3,712.80 2,254.85 -5,975.98 Start Dir 5°/100' : 8044.54' MD, 3712.8'TVD 8,153.70 3,715.23 2,281.81 -6,081.69 End Dir : 8153.7' MD, 3715.23' TVD 9,898.34 3,671.25 2,718.34 -7,770.26 Start Dir 51/100': 9898.34' MD, 3671.25'TVD 10,080.57 3,667.69 2,749.84 -7,949.52 End Dir : 10080.57' MD, 3667.69' TVD 11,324.02 3,651.43 2,884.08 -9,185.60 Start Dir 50/100': 11324.02' MD, 3651.43'TVD 11,473.57 3,647.80 2,890.63 -9,334.85 End Dir : 11473.57' MD, 3647.8' TVD 13,878.31 3,562.80 2,841.46 -11,737.59 Total Depth: 13878.31' MD, 3562.8' TVD 7/20/2016 11:57:14AM Page 7 COMPASS 5000.1 Build 81 Hilcorp Energy Company Milne Point M Pt J Pad MPJ -24 Plan: MPJ -24A 500292297600 MPJ -24A wp05 Sperry Drilling Servic®s Clearance Summary Anticollision Report 18 July, 2016 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt J Pad - MPJ -24 - Plan: MPJ -24A - MPJ -24A wp05 Well Coordinates: 6,015,110.45 N, 551,914.26 E (70" 27'07.29" N, 149° 34'35.09" W) Datum Height: Plan:J-24A @ 62.80usft Scan Range: 7,497.34 to 13,878.31 usft. Measured Depth. Scan Radius is 1,585.18 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 81 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'- 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services Measured Depth (700 usft/in) Project: Milne Point SURVEY PROGRAM Site: M Pt J Pad Date: 2015-05-26T00:00:00 Validated: Yes Version: Well: MPJ-24 Wellbore: Plan: MPJ-24A th From Deem To su—ymian Tool Design: MPJ-24A wp05 110.74 7497.34 MPJ-24 d+* MWD (MWD+IFR:AK) 7497.34 7630.00 MPJ-24A wpO5 MWD_Interp Aa+sag 7830.00 13878.31 MPJ-24A wp05 MWD+IFR2+MS+sag Measured Depth (700 usft/in) HALLIBURTON Anticollision Report for MPJ -24 - MPJ -24A wp05 Hilcorp Energy Company Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt J Pad - MPJ -24 - Plan: MPJ -24A - MPJ -24A wp05 Scan Range: 7,497.34 to 13,878.31 usft. Measured Depth. Scan Radius is 1,585.18 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 J Pad MPJ -08 -MPJ -08A -MPJ -08A 7,497.34 1,363.80 7,497.34 1,086.08 8,483.00 4.911 Clearance Factor Pass - MPJ -09 -MPJ -09A -MPJ -09A 7,497.34 880.99 7,497.34 736.98 8,235.00 6.118 Clearance Factor Pass - MPJ -24 - MPJ-24LI - MPJ-24LI 7,797.34 22.54 7,797.34 17.74 7,799.18 4.697 Ellipse Separation Pass - MPJ-24-MPJ-24LI-MPJ-24LI 12,097.34 231.38 12,097.34 154.33 12,115.00 3.003 Clearance Factor Pass - MPJ-24-MPJ-24Li P81-MPJ-24Li PBI 7,797.34 22.54 7,797.34 17.63 7,799.18 4.595 Ellipse Separation Pass - MPJ -24 - MPJ -241-1 PB1 - MPJ -241-1 PBI 10,847.34 214.73 10,847.34 141.59 10,867.00 2.936 Clearance Factor Pass - MPJ-24-MPJ-24LI PB2-MPJ-24Li P82 7,797.34 22.54 7,797.34 17.64 7,799.18 4.597 Ellipse Separation Pass - MPJ -24 - MPJ-24LI P32-MPJ-24LI PB2 11,097.34 247.93 11,097.34 165.70 11,115.00 3.015 Clearance Factor Pass - MPJ -24 - MPU J-24 - MPJ -24 7,797.34 22.54 7,797.34 17.64 7,799.18 4.597 Ellipse Separation Pass - MPJ -24 -MPU J -24 -MPJ -24 11,947.34 471.73 11,947.34 303.19 11,980.12 2.799 Clearance Factor Pass - MPJ -25 - MPJ -25 - MPJ -25 7,497.34 1,080.65 7,497.34 763.91 8,348.00 3.412 Clearance Factor Pass - MPJ -27 - MPJ -27 - MPJ -27 10,264.24 954.59 10,264.24 578.31 10,369.71 2.537 Centre Distance Pass - MPJ -27 - MPJ -27 - MPJ -27 10,272.34 954.69 10,272.34 577.61 10,385.88 2.532 Clearance Factor Pass - Survey too/ aroprarn From To Survey/Plan Survey Toot (usft) (usft) 110.74 7,497.34 MWD (MWD+IFR'AK) 7,497.34 7,830.00 MPJ-24Awp05 MWD_Interp Azi+sag 7,830.00 13,878.31 MPJ-24Awp05 MWD+IFR2+MS+sag 18 July, 2016 - 13:50 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for MPJ -24 - MPJ -24A wp05 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. Hilcorp Energy Company Milne Point 18 July, 2016 - 13,50 Page 3 of 5 COMPASS HALLIBURTON Anticollision Report for MPJ -24 - MPJ -24A wp05 Clearance Factor Plot: Measured Depth versus Separation(Clearance) Factor P 0 N LL(V `o m C 0 2 m CL in Me -fed Depth (2500 usRln) Hilcorp Energy Company Milne Point LEGEND $ MPJ-01,MPJ-01,MPJ-01 V3 $ MPJ-01,MPJ-01A,MPJ-01AV2 $ MPJ-01,MPJ-01ALI,MPJ0IAL1V6 $ MPJ -02, MPJ -02, MPJ -02 V1 $ MPJ -03, MPJ -03, MPJ -03 V1 $ MPJ -04, MPJ -04, MPJ -04 V1 �F MPJ-08,MPJ-08,MPJ-08V1 $ MPM8, MPJ -08A, MPJ -08A V7 -i- MPJ -09, MPJ -09A, MPJ-09AV2 $ MPJ-10,MPJ-10,MPJ-10V1 ♦- MPJ-11,MPJ-11,MPJ-11 V1 -� MPJ-15,MPJ-15,MPJ•15 V5 -4- MPJ-23,MRL23,MPJ-23V2 $ MPJ23,MPJ-23A,MPJ-23AV0 -� MPJ-23,MP,L23L1,MPJ-23L1 V2 $ MPJ-24,MPJ-24L1,MPJ-24L1 V8 -- MP.L24,MPJ-24L1PB1,MPJ•24L1PB1V1 $ MPJ -24, MPJ -24L 1 PB2, MPJ -24L 1 PB2 V4 $ MPJ-24,MPU,L24,MPJ-24V11 -X- MPJ -25, MPJ -25, MPJ -25 V2 $ MPJ-25,MPJ-25PB1,MPJ-25PB1 V3 -� MPJ-27,MRL27,MPJ-27V0 $ MPL24Avp05 18 July, 2016 - 13:50 Page 5 of 5 COMPASS Schwartz, Guy L (DOA) From: Luke Keller <lkeller@hilcorp.com> Sent: Thursday, September 29, 2016 3:44 PM To: Schwartz, Guy L (DOA) Cc: Bettis, Patricia K (DOA); Wallace, Chris D (DOA); Kevin Eastham; Wyatt Rivard Subject: RE: J -24A Injector (PTD 216-120) Follow Up Flag: Follow up Flag Status: Flagged Guy, First stage assessment (Sept 16-17, 2000): 7" casing was cemented in 9-7/8" hole with 7" shoe at 8891' with 870 bbls (1100 sx) of Arctic set lite cement and 112 bbls (542 sx) of 15.8 tail cement. Cement was not circulated to surface on the first stage of the cement job, but when the ported collar at 1004' MD was opened, 60 bbls of spacer was circulated to surface (75 bbls of spacer was pumped intially), which would indicate TOC at 1323' MD if the hole was in -gauge. Estimated tail cement coverage from 8891' to ^'6635', placing good hard cement across the sidetrack interval. TOC was brought to surface via the second stage using the ported collar. A Schlumberger USIT log was run June 29th, 2007 which also shows good quality cement across the sidetrack interval, and shows good cement to —1200'. A copy of this USIT should be on file with the AOGCC, if not we will certainly provide. Below is an attempt at a TVD schematic of the well, with corresponding formation tops. You can see the kick off point below the Ugnu, the first swell packer above the first ICD which would isolate anything above from water injection pressure ;T-�a 4 t,/, -c �j "s- Cc: Bettis, Patricia K (DOA); Wallace, c,nris D (DOA) Subject: RE: 3-24A Injector (PTD 216-120) Luke, A TVD sketch would be perfect (show placement of swell packers and ICDs). Also, I didn't mention during our phone cal that a detailed assessment of the 1st stage 7" cement job is needed. The AOR for J -24A (area of review) only states that the 7" was cemented to surface through the 2nd stage collar . The TOC and cement coverage for the 1s' stage need to be detailed since that is in the area of the sidetrack window. Sorry, I missed the variance request for the packer placement. 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: Luke Keller [mailtodkellerCc0hilcorp.com] Sent: Thursday, September 29, 2016 1:03 PM To: Schwartz, Guy L (DOA) Cc: Bettis, Patricia K (DOA); Wallace, Chris D (DOA) Subject: RE: 3-24A Injector (PTD 216-120) Guy, We will provide a more clear TVD completion sketch for the well. Our plan was to just leave the window open, since the 7" was fully cemented to surface via a 2 stage cement job, so the 7" x OH annulus is fully isolated below the UGNU. The only sand package open below the UGNU will be the Schrader Bluff, which is our primary injection interval. Does this not satisfy 20 AAC 25.030 (d)(6)? The swell packers have been included to ensure equal injection along the lateral. The shallowest of these is actually above the shallowest ICD (Shallowest swell packer: 8209' MD, shallowest ICD: 8500'), which would isolate the window from the ICDs. Concerning 20 AAC 25.412(b), we actually asked for this exception on page 8 of the drilling program. I should have made specific reference to this variance request in an email to highlight. Luke From: Schwartz, Guy L (DOA) [mailto:guy.schwa rtz(abalaska -go v] Sent: Thursday, September 29, 2016 11:50 AM To: Luke Keller Cc: Bettis, Patricia K (DOA); Wallace, Chris D (DOA) Subject: ]-24A Injector (PTD 216-120) Luke, Since this well is a water injector conversion from a producer and will be sidetracked through casing (window is at 7580 ft MD / 3630 ft TVD) there are some mechanical issues that are not quite clear in the PTD application. Can you provide a more clear completion sketch of showing where the swell packers will be located in order to protect the window, also show the window vs NB zone on a TVD well sketch. (TOW is 80 ft TVD above the NB zone as near as I can tell). You may need to request a variance for 20 AAC 25.030 (d)(6) since there is not actually cement placed above the hydrocarbon zone for isolation. Also the packer will be more than Zoo ft from the injection interval per 20 AAC 25.412 (b). In other words... address how the injected fluids will be confined into the NB zone with your proposed completion. A" cartoon" drawing would likely be helpful. 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 (Guv.schwartz@alaska.gov). Schwartz, Guy L (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Thursday, September 29, 2016 10:15 AM To: Schwartz, Guy L (DOA); Quick, Michael J (DOA) Cc: Cody Dinger; Stan Porhola Subject: J -24A (PTD: 216-120) Rig Change Guy/Mike, For the recently submitted MPU J -24A PTD (216-120) and MPU J-24 sundries 316-461 and 316-462 for the parent well P&A, we will be using the Doyon 14 to conduct this work instead of the Hilcorp Innovation. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 Bettis, Patricia K (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Tuesday, September 13, 2016 3:36 PM To: Bettis, Patricia K (DOA) Cc: Cody Dinger Subject: RE: MPU J -24A (PTD 216120): Permit to Drill Application Patricia, We do not plan to pre -produce J -24A. It will have sensitive injection control devices that we do not want to plug up. Sorry for leaving the point of contact info off, but you were correct in shooting me an email. Either myself or Cody Dinger will be the contact for this well. Luke Keller Ikeller@hilcorp.com Cody Dinger cdiner@hilcorp.com Let me or Cody know if there is anything else you require. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Tuesday, September 13, 2016 2:53 PM To: Luke Keller Subject: MPU J -24A (PTD 216120): Permit to Drill Application Good afternoon Luke, Does Hilcorp plan to pre -produce MPU J -24A; and if so, for what duration of time? The information about Hilcorp's point of contact for this well was left off. Please advise and provide the name and email address for the contact. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue 1 Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Tuesday, September 13, 2016 2:53 PM To: Luke Keller (Ikeller@hilcorp.com) Subject: MPU J -24A (PTD 216120): Permit to Drill Application Good afternoon Luke, Does Hilcorp plan to pre -produce MPU J -24A; and if so, for what duration of time? The information about Hilcorp's point of contact for this well was left off. Please advise and provide the name and email address for the contact. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Patricia Bettis at (907) 793-1238 or patrir_ia.bettis@alaska.ov. TRANSMITTAL LETTER CHECKLIST WELL NAME: MP Lk' Z- 2 yA PTD: 21( - aao Development ✓ Service _ Exploratory _ Stratigraphic Test Non -Conventional FIELD: �� Y1� `t'o��r� POOL:JyVIE 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 onpen-nit). 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 sam les 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) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 _Well Name: MILNE PT UNIT SB J -24A Program SER Well bore seg PTD#: 2161200 Company HILCORP ALASKA LLC Initial Class/Type SER / PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal Administration I17 Nonconvengas conforms to AS31 05030r, 1 AN Q2 A -D Appr Date PKB 9/13/2016 Engineering Appr Date GLS 10/5/2016 Geology Appr Date PKB 9/13/2016 Geologic Commissioner: ---------- ------ NA--- --- 1 Permit -fee attached- - - - - - - - - - - - - - - _NA_ Leasenumberappropriate- _ - - - Yes - - - _ ADL0025906,.S_urf;_ADL0025517, Top Prod Inte_rv; ADL0025515,TD. - _ - 3 Unique well name and number - - _ - _ - Yes -- - . - - - MPU J -24A - 4 Well -located in_a, defined pool- - - - - - - - - - - - - - - - - - - - - - Yes - _ - - MILNE POINT, SCHRADER BLFF_ OIL - 525140, governed by Conservation Order 477,05- - 5 Well -located proper distance from drilling unit -boundary- Yes _ _ _ _ - _ _ CO 477.05 specifies no restrictions as to well spacing except that no pay shall -be opened in_a_ well closer_ _ 6 Well located proper distance from other wells- - - . - - - - Yes - - - 500' from the exterior boundary, of the -Affected, Area.. . 7 Sufficient -acreage-available in -drilling unit_ - Yes ------------------------- ----------- 8 If -deviated, is wellbore platinc_luded - _ -- - - - - - _ Yes - 9 Operator only affected party_ - - - - Yes Wellbore -will be more than 500' from an external property line where_ ownership or landownership - changes. -,10 Operator has -appropriate_ bond in force - - - - - - - - - - - - - - - Yes 11 Permit ---- can be issued w -- ------------------------- -without conservation order_ - Yes - 112 Permit can be issued without administrativ_e_appr_oval - - - - - - Yes - -- ------------------------------------- 113 an permit be approved before 15 -day wait Yes - - - 14 Well located within area and -strata authorized by Injection Order # (put. 10# in -comments) -(For_ Yes - - A10 1.0B_ - - - - - - - 15 All wells -within -1/4 mile -area -of review identified (Forservice well only)_ - - - - - - - - _ Yes MPU J - 24,_J-241_1 and J-27. 16 Pre -produced injector: duration -of pre production less_ than 3 months- (For service well only) - N_o_ - - - (Luke_ Keller, 9/1- - -) - - -- -- ---- ---- urConductor sining_p_rovided _ NA- . - - - - - Conductor -set- in J-24 ,. Well to be -sidetracked. ---- ---- ---------- 20 19 Surface -casing- protects all -known USDWs - - _ - - - - - - - NA- Surface casing set and fully cemented. - - ----- ---- ---- -- ------ -- ----------- - - - - - - _CMT vol adequate to circulate conductor_& su_rf_csg _NA _ - 21 CMT_v_ol adequate -to tie -in -long string to -surf csg_ - _ - - -- -- -- - - - - No_ - - Lateral will be slotted liner with ICD and swell packers.. No cement. - - -- 22 CMT_will coverall known -productive horizons_ - - - - - _ _ - - Yes 7"_1st_stage cmt shows good cement per -the USIT log run, 23 Casing designs adequate for C,_T, B &_ permafrost_ - - - Yes ------ ---- 24 equate_tan_kage,or reserve pit - - - - - _ - - Yes - Rig has steel pits_.._All-waste to approved disposal wells- - - - - - - - - - - -25 -If - a_ re -drill, has a 1.0-403 for abandonment been approved _ - _ - - Yes - - - - Sundries -316-461 and 316-462_ are approved. _ _ - _ _ _ --- - -- Adequate.wellbore separation_proposed- Yes Anti_col_lision analysis provided, No issues. _ -- -- - - -- 7 If_diverter required does it meet regulations_ - - - - - - - - - NA_ - - - Wellhead in place _ Will use BOPE.- - _ - 28 Drilling fluid_ program schematic-&- equip listadequate_ - - Yes - - - - - - - Max form pressure= 1625_psi_(8.5 ppg EMW) will drill with_8.9_-9.2 ppg-mud -- - - - - - - - - - - _ 29 BOPEs,_do they meet regulation - - - - - ----- - -- - Yes - - - - - - - on_file.._Doyon 14 BOPE --- 30 BOPE-press rating appropriate; test to -(put psig in comments)_ - - - - - - - - - - - - Yes - - - - - - - MASP = 1262 -psi_ ., .will test BOPE to_3000psi - , 31 Choke -manifold complies w/API_ RP -53 (May 84)- - - - - - - - - - - - - - - - - - Yes --------------------------------- - -- - -- - 32 Work will occur without operation shutdown_ - - - - - - - - Yes - 33 Is presence of H2S ga-probable - - - - - - - - - - - - - - - - - - - - - - - - Yes - H2S on- pad. Rig -has sensors and alarms._ - - - _ 34 Mechanicaloondition of wells within AOR verified (For service well only) - - _ - - - Yes - _ - - _ _ - 1/4 nile_AOR completed. No issues. All wells are -mechanically-sou_ nd_in area _. _ _ _ P 35 Permit can be issued w/o hydrogen sulfide measures No_ _ H2S measures required. 36 Data_p_resented on potential overpressure zones _ - - - - - _ - - - - Yes Expected reservoir press ure 8.6 ppg EMW; will be drilled using 8.9_ to 9.2_ppg mud._ 37 Seismic -analysis of shallow gas_zones_ - _ - - NA ------------------------- ------------------- 38 Seabed condition survey -(if off_ -shore) - - - - - - - - - - - - - - - - - - - - - - - NA - - - - - - - - - - - - - - - - _ 39 Contact name/phone for weekly_ progress reports_ [exploratory only] - - - NA_ - . - - - - - Onshore service well to be drilled. Date: Engineering Public Well will now be drilled with Doyon 14. Not Hilcorp Innovation rig. o issionery /� D�� / Com ssioner Date /o 1 I o,lb � / ! N I