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Home My WebLink About220-072MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, April 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC J-30 MILNE PT UNIT J-30 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/22/2025 J-30 50-029-23690-00-00 220-072-0 W SPT 3799 2200720 1500 526 525 526 526 4YRTST P Kam StJohn 3/16/2025 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-30 Inspection Date: Tubing OA Packer Depth 367 1705 1655 1642IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS250316165542 BBL Pumped:3 BBL Returned:3 Tuesday, April 22, 2025 Page 1 of 1            MEMORANDUM 1'0Jim Regg 7�j 4-114 (.t7A P.J. Supervisor /1 FROM: Bob Noble Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, April 5, 2021 SUBJECT: Mechanical Integrity Tests Hdcmp Alaska, LLC J-30 MILNE I'T UNIT J-30 Src: Inspector Reviewed By: P.L Supry� Comm Well Name MILNE IT UNIT 1-30 API Well Number 50-029-23690-00-00 Inspector Name: Bob Nome Permit Number: 220-072-0 Inspection Date: 3/26/2021 - Insp Num: mitRCN210330075I32 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well J-3o Type Inj N TVD 3799 Tubing 516 517 - 206 1685 515 - - 1632 51d ' FBBL zzoano Type Test SPT Test psi lsoo IA 1618 ' Pumped: 2.9 ' BBL Returned: 2.9 OA Interval IMTAL PAF P Notes: New well. Mono bore. Monday, April 5, 2021 PaLc I of I DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23690-00-00Well Name/No. MILNE PT UNIT J-30Completion Status1WINJCompletion Date2/9/2021Permit to Drill2200720Operator Hilcorp Alaska, LLCMD20001TVD3544Current Status1WINJ3/16/2021UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, ABG, DGR, EWR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF2/16/2021150 20001 Electronic Data Set, Filename: MPU J-30 LWD Final.las34709EDDigital DataDF2/16/20219426 19964 Electronic Data Set, Filename: MPU J-30 ADR Quadrants All Curves.las34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30 LWD Final MD.cgm34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30 LWD Final TVD.cgm34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30i_Definitive Survey Report.pdf34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30i_Definitive Surveys.xlsx34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30i_DSR.txt34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30i_GIS.txt34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30i_Plan Plot.pdf34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30i_VSec Plot.pdf34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30 LWD Final MD.emf34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30 LWD Final TVD.emf34709EDDigital DataDF2/16/2021 Electronic File: MPU_J-30_Geosteering.dlis34709EDDigital DataDF2/16/2021 Electronic File: MPU_J-30_Geosteering.ver34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30 LWD Final MD.pdf34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30 LWD Final TVD.pdf34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30 LWD Final MD.tif34709EDDigital DataDF2/16/2021 Electronic File: MPU J-30 LWD Final TVD.tif34709EDDigital Data0 0 2200720 MILNE PT UNIT J-30 LOG HEADERS34709LogLog Header ScansTuesday, March 16, 2021AOGCCPage 1 of 3MPU J-30 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23690-00-00Well Name/No. MILNE PT UNIT J-30Completion Status1WINJCompletion Date2/9/2021Permit to Drill2200720Operator Hilcorp Alaska, LLCMD20001TVD3544Current Status1WINJ3/16/2021UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:2/9/2021Release Date:11/24/20200 0 2200720 MILNE PT UNIT J-30 LOG HEADERS34710LogLog Header ScansDF2/16/2021 Electronic File: MPU J-30 Geosteering End of Well Report.docx34710EDDigital DataDF2/16/2021 Electronic File: MPU J-30 Geosteering End of Well Report.pdf34710EDDigital DataDF2/16/2021 Electronic File: MPU J-30 Geosteering EOW Plot.emf34710EDDigital DataDF2/16/2021 Electronic File: MPU J-30 Geosteering EOW Plot.pdf34710EDDigital DataDF2/16/2021 Electronic File: MPU J-30 Geosteering EOW Plot.tif34710EDDigital DataDF2/16/2021 Electronic File: MPU J-30 Post-Well Geosteering X-Section Summary.pdf34710EDDigital DataDF2/16/2021 Electronic File: MPU J-30 Post-Well Geosteering X-Section Summary.pptx34710EDDigital DataTuesday, March 16, 2021AOGCCPage 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23690-00-00Well Name/No. MILNE PT UNIT J-30Completion Status1WINJCompletion Date2/9/2021Permit to Drill2200720Operator Hilcorp Alaska, LLCMD20001TVD3544Current Status1WINJ3/16/2021UICYesComments:Compliance Reviewed By:Date:Tuesday, March 16, 2021AOGCCPage 3 of 3M. 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0'5HIHUHQFH038-$FWXDO5.%#XVIW 1RUWK5HIHUHQFH :HOO038-L 7UXH 0' XVIW ,QF $]L (: XVIW 16 XVIW 6XUYH\ 79' XVIW 79'66 XVIW 0DS 1RUWKLQJ IW 0DS (DVWLQJ IW 9HUWLFDO 6HFWLRQ IW '/6 6XUYH\7RRO1DPH 352-(&7('WR7' $SSURYHG%\&KHFNHG%\'DWH 2/1/2021 6:48:13PM COMPASS 5000.15 Build 91E Page 8 Chelsea Wright Digitally signed by Chelsea Wright Date: 2021.02.01 09:50:30 -09'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2021.02.03 00:58:58 -09'00' David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 02/16/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU J-30 (PTD 220-072) FINAL EOW REPORT – GEOSTEERING LOGS (01/24/2021 to 01/30/2021) SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD: 2200720 E-Set: 34710 Received by the AOGCC 02/16/2021 02/16/2021 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 02/16/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU J-30 (PTD 220-072) FINAL LWD FORMATION EVALUATION LOGS (01/13/2021 to 01/30/2021) •DGR, AGR, ABG, ADR, EWR-M5, ADR, Wellbore Profile (2” & 5” MD/TVD Color Logs) •Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD: 2200720 E-Set: 34709 Received by the AOGCC 02/16/2021 02/16/2021 Regg, James B (CED) I r° 2-7t07ZG From: Abhijeet Tambe <Abhijeet.Tambe@hilcorp.com> Sent: Tuesday, February 9, 2021 12:45 PM To: Regg, James B (CED); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (CED); Wallace, Chris D (CED) Cc: Nathan Sperry Subject: Hilcorp J-30 MIT -IA Attachments: MPU J-30 MIT IA.XLSX; J-30 MIT IA.PDF Hello, Please find 10-426 for J-30 MIT -IA. AbbijeetTambe I Sr. Operations Engineer Illilcorp Alaska, LLC 0: (907) 777-5485 1 C: (907)337-91£34 1 Abhijeet.Tambe(@hilcorp.com 3800 Centerpoint Drive, Suite 1400 1 Anchorage, AK 99503 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Submit to: 'Im.reggilbalaskaoov: OPERATOR: FIELD I UNIT I PAD: DATE: OPERATOR REP: AOGCC REP: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Sloan Sunderland Phoebe. brookst@aleska.gov chrismallacel@alaska.gov 11 karz'( Well MPU J30 INTERVAL codes Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 4=Four Year Cycle F=Fal PTO 220-072 -1 Type Inj N Tubing1300 I = Industrial Wastesatet -13001 o=whet (descnbe In none) 1300 N = Not miens, Type Test P Packer TVD 3799 - BBL Pump 58 IA 0 2560 ' 2510 2500' Interval O Test psi 2500 IBBLRetuml 56 OA I I Result P Notes: Witness waived by Guy Cook on 2122021. Initial, Pre -intention MIT -IA perlorred on rig. ✓ Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Tesl Packer TVD BBL Pump IA Interval Test psi BBL Retum OA Result Notes: well Pressures: Pretest initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBI-Retumj I OA I Result Notes: well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Tesl Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: WeIIPressures: Pretest Initial 15 Min. 3a Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Tesl Packer TVD BBL Pump IA Interval Test psi BEL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer WD BBL Pump IA Interval Test psi BBL Return OA Result Ngces: Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Tubing Type Tesl D IA ITest PIBL OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL codes Result Codes W=Witter P=Pressure Teat 1=Initial Teat P=Paso G=Gas C= Coin, (dei Note.) 4=Four Year Cycle F=Fal a - Slurry V=Fequoeo ty".a— 1=lntontleume I = Industrial Wastesatet o=whet (descnbe In none) N = Not miens, Form 10-026 (Revised 0112017) MPu Jag MIT IA S! STATE OF ALASKA Reviewed By: OIL AND GAS CONSERVATION COMMISSION P.I. Sup,v ROPE Test Report for: MILNE PT UNIT 1-30 , Comm Contractor/Rig No.: Doyon 14 Operator: Hilcorp Alaska, LLC Type Operation: DRILL / Sundry No: Type Test: INIT PTD#: 2200720 ' DATE: 123/2021 Operator Rep: Yessak Test Pressures: Rams: Annular: Valves: NIASP: 250/3000 250/3000 ' 250/3000 ' 1297 ,/ TEST DATA Inspector Bob Noble Rig Rep: Hansen Insp Source Inspector Inspection No: bopRCN210124140353 Related Insp No: MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: BOP STACK: P/F FLOOR SAFTY VALVES: Visual Alarm Time/Pressure P/F Location Gen.: P - Trip Tank P P System Pressure 3100 P Housekeeping: P Pit Level Indicators P P. ' Pressure After Closure 1600 P " PTD On Location P Flow Indicator P P 200 PSI Attained 33 P Standing Order Posted P Meth Gas Detector P P Full Pressure Attained 189 P Well Sign P H2S Gas Detector P P Blind Switch Covers: All Stations P Drl. Rig P MS Misc NA NA Nitgn. Bottles (avg): _ 6 (n, 2145 ' P Hazard Sec. P CH Misc 0 NA FSV Misc ACC Misc 0 NA Misc NA 2 7/8" x 5" P Number of Failures: 0 Test Results Remarks: Test Time 6 BOP STACK: CHOKE MANIFOLD: FLOOR SAFTY VALVES: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly 1 P_, Stripper 0 none NA No. Valves 14 P, Lower Kelly 1 P Annular Preventer 1 , 13 5/8" P Manual Chokes I P, Ball Type 3 P_ #1 Rams 1 2 7/8" x 5" P Hydraulic Chokes 1 P Inside BOP 2 P, 42 Rams I Blinds P CH Misc 0 NA FSV Misc 0 NA #3 Rams 1 2 7/8" x 5" P _ #4 Rams 0 none NA INSIDE REEL VALVES: #5 Rams 0 none NA #6 Rams 0 none NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 - 3 1/8" P Quantity P/F HCR Valves 2 '3 1/8" P Inside Reel Valves 0 NA Kill Line Valves 2 '3 1/8" P ' Check Valve 0 none _ NA BOP Misc 0 none NA Number of Failures: 0 Test Results Remarks: Test Time 6 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By: 77l�Z P.t. Supry �r -I 7, Z,1 DIVERTER Test Report for: TALITHA A Comm Contractor/Rig No.: Nordic 3 PTD#: 2200760 ' DATE: 1/11/2021 ' Inspector Jeff Jones - losp Source Operator: Great Bear Pantheon, LLC Operator Rep: J. Otto / Smith Rig Rep: B. Pederson / Henry Inspector Well Class: EXP , MISC. INSPECTIONS: GAS DETECTORS: Visual Alarm Methane: P FP ✓ Hydrogen Sulfide: P P Gas Detectors Misc: NA NA _ TEST DATA P/F Location Gen.: P Housekeeping: P " Warning Sign FP ✓ 24 hr Notice: P Well Sign: P - Drlg. Rig. P Misc: NA GAS DETECTORS: Visual Alarm Methane: P FP ✓ Hydrogen Sulfide: P P Gas Detectors Misc: NA NA _ TEST DATA MUD SYSTEM: P/F Visual Alarm P - Trip Tank: P P Mud Pits: P P " Flow Monitor: P P Mud System Misc: NA NA ACCUMULATOR SYSTEM: Time/Pressure P/F Systems Pressure: 3050 P Pressure After Closure: 1500 P 200 psi Recharge Time: 22 P Full Recharge Time: 152_ P Nitrogen Bottles (Number of): 4 P Avg. Pressure: 2100 _ P Accumulator Misc: I FP Inspection No: divJJ210111123325 Related Insp No: DIVERTER SYSTEM: Size P/F Designed to Avoid Freeze-up? P - Remote Operated Diverter? P No Threaded Connections? P Vent line Below Diverter? P Diverter Size: 20 P_ Hole Size: 12.25 P Vent Line(s) Size: 16_ P Vent Line(s) Length: 85 P Closest Ignition Source: 87 _ P " Outlet from Rig Substructure: 79 P Vent Line(s) Anchored: P Turns Targeted / Long Radius: NA Divert Valve(s) Full Opening: P Valve(s) Auto & Simultaneous: Annular Closed Time: 29 P Knife Valve Open Time: 11 P Diverter Misc: I FP v' Number of Failures: 4 .i Test Time: 7 Remarks: Nordic Rig #3 personnel performed the tests today in a safe and proficient manner with 4 failures observed. The 16" diverter vent line appeared straight, sturdy and well anchored but warning signs were not in place (1). The vent line outlet terminated down inside a larae open too tank which could restrict flow when in use, so the tank was removed (2). When the Diverter system was function tested the knife valve opened in 11 seconds and the annular fully closed in 29 seconds. The #9 accumulator bottle bladder had failed so it was replaced and recharged (3). The gas detection and pit volume totalizer alarm systems were tested and the meth audible alarm failed tooperaterate pro dy. A faulty bypass switch contactor and relay were replaced and the system passed a retest (4). The rig and surrounding—location appeared clean, orderly and in good condition. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU J-30 Hilcorp Alaska, LLC Permit to Drill Number: 220-072 Surface Location: 2698' FSL, 3395' FEL, Sec. 28, T13N, R10E, UM, AK Bottomhole Location: 1680' FSL, 998' FWL, Sec. 24, T13N, R09E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of November, 2020. Sincerely, 24 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 19,803' TVD: 3,516' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 67.3 15. Distance to Nearest Well Open Surface: x-551922 y- 6015096 Zone-4 33.6 to Same Pool: 183' 16. Deviated wells: Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 101 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20" 215# X-52 80' Surface Surface 112' 112' 47# L-80 TXP 2440' Surface Surface 2440' 1977' 40# L-80 TXP 6953' 2440' 1977' 9393' 3816' 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 10560' 9243' 3800' 19803' 3516' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number: 50- Date: 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: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng 12/23/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Nathan Sperry nathan.sperry@hilcorp.com 777-8450 18. Casing Program: Top - Setting Depth - BottomSpecifications 1679 MPU J-30 Milne Point Unit Schrader Bluff Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2698' FSL, 3395' FEL, Sec. 28, T13N, R10E, UM, AK ADL 025906, 025517, 025515 & 025514 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1297 1639' FSL, 1156' FWL, Sec. 20, T13N, R10E, UM, AK 1680' FSL, 998' FWL, Sec. 24, T13N, R09E, UM, AK 88-005 10219 1536' Total Depth MD (ft): Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Effect. Depth TVD (ft): Surface Conductor/Structural LengthCasing Effect. Depth MD (ft): Authorized Signature: Production Liner Commission Use Only Perforation Depth TVD (ft): Intermediate 12-1/4" 9-5/8"Stg 2 - L - 1935 ft3 / T - 313 ft3 See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. GL / BF Elevation above MSL (ft): Cementless Screen Liner ~270 ft3 Stg 1 - L - 2397 ft3 / T - 458 ft3 Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 11.17.2020 By Samantha Carlisle at 10:19 am, Nov 18, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.11.17 17:51:08 -09'00' Monty M Myers X X 029-23690-00-00 MGR23NOV2020 X X X DLB 11/19/2020 X 220-072 BOPE test to 3000 psi. Annular to 2500 psi. X DSR-11/23/2020R23NNNNNNNNNNNNNNNNOV2020 11/24/2020 11/24/2020 Area of Review MPU J-30 SB NB PTD API WELL STATUS Top of SB NB (MD) Top of SB NB (TVD) CBL Top of Cement (MD) CBL Top of Cement (TVD) Schrader NB status Zonal Isolation 220-070 50-029-23688-00-00 MPU J-29 NB Prod Lateral 8821' 3798' N/A N/A Proposed NB Prod Open to Injection Support 220-020 50-029-23671-00-00 MPU M-43 NB Prod Lateral 6488' 3826' N/A N/A Open Open to Injection Support 220-059 50-029-23685-00-00 MPU L-62 NB Prod Lateral 7105' 3999' N/A N/A Open Open to Injection Support 220-048 50-029-23678-00-00 MPU L-60 NB Prod Lateral 6751' 3968' N/A N/A Open Open to Injection Support 220-056 50-029-23683-00-00 MPU L-61 NB WINJ Lateral 7479' 3974' N/A N/A Open Open Injector 220-030 50-029-23673-00-00 MPU M-44 NB WINJ Lateral 5850' 3799' N/A N/A Open Open Injector 220-044 50-029-23676-00-00 MPU M-45 NB Prod Lateral 5258' 3772' N/A N/A Open Open to Injection Support 220-050 50-029-23680-00-00 MPU L-59 NB WINJ Lateral 6926' 3963' N/A N/A Open Open Injector 217-151 50-029-23587-00-00 MPU L-51 NB Prod Lateral 6427' 3937' N/A N/A Open Open to Injection Support Milne Point Unit (MPU) J-30 Drilling Program Version 1 11/10/2020 Table of Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 R/U and Preparatory Work ..................................................................................................... 10 10.0 N/U 21-1/4” 2M Diverter System ............................................................................................. 11 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22 14.0 BOP N/U and Test.................................................................................................................... 27 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28 16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 33 17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 37 18.0 RDMO ...................................................................................................................................... 38 19.0 Doyon 14 Diverter Schematic .................................................................................................. 39 20.0 Doyon 14 BOP Schematic ........................................................................................................ 40 21.0 Wellhead Schematic ................................................................................................................. 41 22.0 Days Vs Depth .......................................................................................................................... 42 23.0 Formation Tops & Information............................................................................................... 43 24.0 Anticipated Drilling Hazards .................................................................................................. 44 25.0 Doyon 14 Layout ...................................................................................................................... 47 26.0 FIT Procedure .......................................................................................................................... 48 27.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 49 28.0 Casing Design ........................................................................................................................... 50 29.0 8-1/2” Hole Section MASP ....................................................................................................... 51 30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 52 31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 53 32.0 Schrader Bluff NB Sand Offset MW vs TVD Chart ............................................................... 54 Page 2 Milne Point Unit J-30 SB Injector Drilling Procedure 1.0 Well Summary Well MPU J-30 Pad Milne Point “J” Pad Planned Completion Type 3-1/2” Injection Tubing Target Reservoir(s) Schrader Bluff Nb Sand Planned Well TD, MD / TVD 19,803’ MD / 3,516’ TVD PBTD, MD / TVD 19,683’ MD / 3,518’ TVD Surface Location (Governmental) 2581' FNL, 1885' FWL, Sec. 28, T13N, R10E, UM, AK Surface Location (NAD 27) X= 551922 Y= 6015096 Top of Productive Horizon (Governmental)1639' FSL, 1156' FWL, Sec 20, T13N, R10E, UM, AK TPH Location (NAD 27) X= 545873 Y= 6019276 BHL (Governmental) 1680' FSL, 998' FWL, Sec 24, T13N, R09E, UM, AK BHL (NAD 27) X= 535208 Y=6019259 AFE Number 2013784 (D,C,F) AFE Drilling Days 23 days AFE Completion Days 4 days Maximum Anticipated Pressure (Surface) 1297 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1679 psig Work String 5” 19.5# S-135 DS-50 & NC 50 KB Elevation above MSL: 33.6 ft + 33.7 ft = 67.3 ft GL Elevation above MSL: 33.6 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit J-30 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit J-30 SB Injector Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25”---X-52Weld 12-1/4”9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086 9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916 8-1/2” 4-1/2” 3.96” 3.795”4.714”13.5 L-80 H625 9020 8540 279 Tubing 3-1/2” 2.992”2.867”4.500”9.3 L-80 EUE 8RD 9289 7399 163 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5”4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560klb 5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit J-30 SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com, nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 907-301-8996 nathan.sperry@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com Geologist Seth Nolan 907.777.8308 907.519.8225 snolan@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com Page 6 Milne Point Unit J-30 SB Injector Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit J-30 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU J-30 is a grassroots injector planned to be drilled in the Schrader Bluff NB sand. J-30 is part of a multi well program targeting the Schrader Bluff sand on J-pad. J-30 will not be pre-produced. The directional plan is a horizontal well with 12.25” surface hole with 9-5/8” surface casing set into the top of the Schrader Bluff Nb sand. An 8.5” lateral section will then be drilled. A 4-1/2” injection liner will be run in the open hole section. The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately December 23rd, 2020, pending rig schedule. Surface casing will be run to 9,393 MD / 3,816’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser 5. Drill 8-1/2” lateral to well TD. Run 4-1/2” injection liner. 6. Run 3-1/2” tubing. 7. N/D BOP, N/U Tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit J-30 SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU J-30. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & 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. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: Hilcorp Alaska LLC does not request any variances at this time. Page 9 Milne Point Unit J-30 SB Injector Drilling Procedure Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only 8-1/2” x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 Subsequent Tests: 250/3000 Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email:guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov TestoInspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit J-30 SB Injector Drilling Procedure 9.0 R/U and Preparatory Work 9.1 J-30 will utilize a newly set 20” conductor on J-pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 6” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 11 Milne Point Unit J-30 SB Injector Drilling Procedure 10.0 N/U 21-1/4” 2M Diverter System 10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit J-30 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit J-30 SB Injector Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Be sure to run a UBHO sub for wireline gyro x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to section TD, in the Schrader NB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). x Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. x Gas hydrates have not been seen on J-pad. However, be prepared for them. In MPU they have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be prepared for hydrates: Page 14 Milne Point Unit J-30 SB Injector Drilling Procedure x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Past wells on E pad have increased MW. After drilling through hydrate sands, MW was cut back to normal x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x AC: x There are no wells with clearance factors < 1.0 11.4 12-1/4” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface –Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone x PVT System: 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, and mud loggers office. x Rheology: Aquagel and Barazan D+ should be used to maintain rheology.Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss:DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. Note: Minimum EMW=8.46 ppg. DLB Page 15 Milne Point Unit J-30 SB Injector Drilling Procedure x Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation:Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute. x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 Milne Point Unit J-30 SB Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x DS50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.75” on the location prior to running. x Top ~2500’ of casing from surface 47# drift 8.525” min x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.2 P/U shoe joint, visually verify no debris inside joint. 12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle 2440' Page 17 Milne Point Unit J-30 SB Injector Drilling Procedure 12.4 Float equipment and Stage tool equipment drawings: Page 18 Milne Point Unit J-30 SB Injector Drilling Procedure 12.5 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POOH with casing and condition hole than to risk not getting cement returns to surface. 12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost (~ 2,500’ MD). x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/8” 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8” 18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8” 21,440 ft-lbs 2,3820 ft-lbs 26,200 ft-lbs Depth Interval Centralization Shoe – 1000’ Above Shoe 1/jt 1000’ above Shoe – 2000’ above Shoe (Top of Ugnu) 1/ 2 jts Page 19 Milne Point Unit J-30 SB Injector Drilling Procedure Page 20 Milne Point Unit J-30 SB Injector Drilling Procedure 12.7 Run 47# 9-5/8” surface casing from stage tool to surface x Ensure drifted to 8.525” min x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: o 1 centralizer every 3 joints to base of conductor 12.8 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Page 21 Milne Point Unit J-30 SB Injector Drilling Procedure 12.9 Slow in and out of slips. 12.10 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.11 Lower casing to setting depth. Confirm measurements. 12.12 Have slips staged in cellar along with all necessary equipment for the operation. 12.13 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 22 Milne Point Unit J-30 SB Injector Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Page 23 Milne Point Unit J-30 SB Injector Drilling Procedure Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: (2500’ x .0747bpf ) + (6893’ x .0758 bpf ) = 696.6 bbls 80 bbls of tuned spacer to be left behind stage tool,confirm spacer is compatible with cement behind stage tool & that sufficient spacer will be above the tool to exit when circulation is established. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Lead Slurry Tail Slurry Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.98 gal/sk Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened and cement is circulated to surface 700.9 .0732 6953-120 =6833 Page 24 Milne Point Unit J-30 SB Injector Drilling Procedure Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.15 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.16 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 25 Milne Point Unit J-30 SB Injector Drilling Procedure Second Stage Surface Cement Job: 13.17 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre-job safety meeting. 13.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.19 Fill surface lines with water and pressure test. 13.20 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.21 Mix and pump cmt per below recipe for the 2 nd stage. 13.22 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.25 Displacement calculation: 2500’ x .0747 bpf = 186.75 bbls mud Lead Slurry Tail Slurry System Permafrost L Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk 189.60.0758 Page 26 Milne Point Unit J-30 SB Injector Drilling Procedure 13.26 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.27 Land closing plug on stage collar and pressure up to 1000 – 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.28 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 27 Milne Point Unit J-30 SB Injector Drilling Procedure 14.0 BOP N/U and Test 14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool. 14.2 N/U 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs x N/U bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 Run 5” BOP test plug 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Test 4-1/2” x 7” rams with 4-1/2” and 5” test joints x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg FloPro fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6” liners in mud pumps. Page 28 Milne Point Unit J-30 SB Injector Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM) x Based on results from M-44 & 45, RSS drillouts have left debris in bit and bit sleeve, may have damaged cutters, and may have impacted our ability to steer. A dedicated motor drill out is preferred. 15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 P/U 8-1/2” RSS directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is R/U and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135 DS50 & NC50. x Run a ported float in the production hole section. Digital data for casing test and FIT to AOGCC. Page 29 Milne Point Unit J-30 SB Injector Drilling Procedure 15.10 8-1/2” hole section mud program summary: x 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.Use appropriate SAFECARB blend on this well x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x 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 tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x 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 – 9.5 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify)50 lb sx 10 SAFE-CARB 20 (verify)50 lb sx 10 Soda Ash 50 lb sx 0.5 Note: Minimum EMW=8.46 ppg DLB Page 30 Milne Point Unit J-30 SB Injector Drilling Procedure 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid 15.13 Begin drilling 8.5” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm x RPM: 120+ x 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. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x 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. x Use ADR to stay in section. x Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream connections x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections x 8-1/2” Lateral A/C: x M-43 has a 0.229 CF. M-43 is an active producer from the NB sands. A collision would result in drilling through an uncompleted section of M-43 (i.e. open hole in the rock below the shoetrack). Slight lost circulation might occur and there is no HSSE risk. x M-43PB2 has a 0.262 CF. This is an open hole PB. No risk. x M-43PB3 has a 0.089 CF. This is an open hole PB. No risk. x Schrader Bluff Concretions: 5-10% of lateral Page 31 Milne Point Unit J-30 SB Injector Drilling Procedure 15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x 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. x Attempt to lowside in a fast drilling interval where the wellbore is headed up.NOTE: In Nb sand wells, it helps to pick a siltier section to help mitigate junction collapse. x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ftomin AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed x Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + Liner volume with viscosified brine. x Proposed brine blend (aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42 ppb Flo-Vis Plus: 1.25 ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. Page 32 Milne Point Unit J-30 SB Injector Drilling Procedure 15.19 Monitor the returned fluids carefully while conditioning the mud. After 4 (or more) BU, Perform production screen test (PST). The mud has been properly conditioned when the mud will pass the production screen test (x3 350ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure x 250 Coupons x Circulate and condition mud as much as needed to pass the production screen test x If not passing after first test, call Completion Engineer 15.20 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (385 gpm max). x Rotate at maximum rpm that can be sustained. x Limit pulling speed to 5 – 10 min/std (slip to slip time, not including connections). x When pulling across any OHST depths, turn pumps off and rotary off to minimize disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct hole section, check with ABI compared to as drilled surveys 15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.22 Monitor well for flow. Increase mud weight if necessary x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure seen x Ensure fluid coming out of hole has passed a PST at the possum belly 15.23 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 33 Milne Point Unit J-30 SB Injector Drilling Procedure 16.0 Run 4-1/2” Injection Liner (Lower Completion) NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them slick. 16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” injection liner with joints of screens, the following well control response procedure will be followed: x With a screen joint across the BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. x With 4-1/2” solid joint across BOP: Slack off and position the 4-1/2” solid joint to MU the TIW valve. Shut in ram or annular on 4-1/2” solid joint. Close TIW valve. 16.2. Confirm VBR’s have been tested on 4-1/2” and 5” test joints to 250 psi low/3000 psi high. 16.3. R/U 4-1/2” liner running equipment. x Ensure 4-1/2” Hydril 625 x DS-50 crossover is on rig floor and M/U to FOSV. x Ensure the liner has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.4. Run 4-1/2” injection liner. x Injection liner will be solid pipe and single screen joints spaced every ~ 800’. Confirm with OE x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Fill 4-½” liner with PST passed mud (to keep from plugging screens with solids) x Install screen joints as per the Running Order x (From Completion Engineer post TD). x Do not place tongs or slips on screen joints x Screen placement ±40’ x The Screen connection is 4-1/2” 13.5# Hydril 625 x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2” 13.5# L-80 H625 Page 34 Milne Point Unit J-30 SB Injector Drilling Procedure Casing OD Minimum Optimum Maximum Operating Torque 4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 35 Milne Point Unit J-30 SB Injector Drilling Procedure 16.6. Ensure that the liner top packer is set ~ 150’ MD above the 9-5/8” shoe. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection. 16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker SLZXP liner top packer to inner string and 4-1/2” liner. 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. 16.9. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH w/ liner on DP no faster than 30 ftomin – this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.11. The liner and inner string will prevent the DP from auto filling. Fill DP every 5 stands, more frequently if SOW trend indicates. 16.12. 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. 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. 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. 16.17. 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. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.18. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release running tools. Page 36 Milne Point Unit J-30 SB Injector Drilling Procedure 16.19. Bleed DP pressure to zero, Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.20. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.21. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.22. Flush liner top at max rate. 16.23. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. 16.24. LD remaining 5” DP. 16.25.Once running tools are L/D, Swap to Completion AFE. Page 37 Milne Point Unit J-30 SB Injector Drilling Procedure 17.0 Run 3-1/2” Tubing (Upper Completion) 17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to abhijeet.tambe@hilcorp.com for submission to AOGCC. 17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. x Ensure wear bushing is pulled. x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. x Monitor displacement from wellbore while RIH. 3-1/2” 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs 3-½” Upper Completion Running Order x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle) x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” “XN” nipple at TBD x 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” SGM-FS XDPG Gauge at TBD x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x Tubing hanger with 3-1/2” EUE 8RD pin down 17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. 17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all space out pups below the first full joint of the completion. Page 38 Milne Point Unit J-30 SB Injector Drilling Procedure 17.5 Makeup the tubing hanger and landing joint. 17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with brine and 1% corrosion inhibitor. 17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel. 17.9 Land hanger. RILDs and test hanger. 17.10 Continue pressurizing the annulus to 2500 psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 17.12 Pull BPV. Set TWC. Test tree to 5000 psi. 17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 17.14 Secure the tree and cellar. 18.0 RDMO 18. RDMO Doyon 14 Page 39 Milne Point Unit J-30 SB Injector Drilling Procedure 19.0 Doyon 14 Diverter Schematic Page 40 Milne Point Unit J-30 SB Injector Drilling Procedure 20.0 Doyon 14 BOP Schematic 2-7/8” x 5” VBR Page 41 Milne Point Unit J-30 SB Injector Drilling Procedure 21.0 Wellhead Schematic Page 42 Milne Point Unit J-30 SB Injector Drilling Procedure 22.0 Days Vs Depth Page 43 Milne Point Unit J-30 SB Injector Drilling Procedure 23.0 Formation Tops & Information MPU J-30 Formations (wp07) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) SV5 1,477 1,402 -1,332 617 8.46 BPRF 2,547 2,009 -1,940 884 8.46 UG3 5,027 2,704 -2,635 1,190 8.46 UG COAL 1 6,189 3,030 -2,960 1,333 8.46 UGNU LA3 7,419 3,374 -3,305 1,485 8.46 UGNU MB 8,046 3,550 -3,480 1,562 8.46 SCHRADER NA 9,101 3,790 -3,720 1,668 8.46 SCHRADER NB 9,340 3,815 -3,745 1,678 8.46 J-pad Data Sheet Formation Description Page 44 Milne Point Unit J-30 SB Injector Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well specific A/C: x There are no wells with a CF < 1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 45 Milne Point Unit J-30 SB Injector Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 46 Milne Point Unit J-30 SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up appropriately 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 > 300 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 H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M- Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well specific AC: x M-43 has a 0.229 CF. M-43 is an active producer from the NB sands. A collision would result in drilling through an uncompleted section of M-43 (i.e. open hole in the rock below the shoetrack). Slight lost circulation might occur and there is no HSSE risk. x M-43PB2 has a 0.262 CF. This is an open hole PB. No risk. x M-43PB3 has a 0.089 CF. This is an open hole PB. No risk. Page 47 Milne Point Unit J-30 SB Injector Drilling Procedure 25.0 Doyon 14 Layout Page 48 Milne Point Unit J-30 SB Injector Drilling Procedure 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 49 Milne Point Unit J-30 SB Injector Drilling Procedure 27.0 Doyon 14 Choke Manifold Schematic Page 50 Milne Point Unit J-30 SB Injector Drilling Procedure 28.0 Casing Design Page 51 Milne Point Unit J-30 SB Injector Drilling Procedure 29.0 8-1/2” Hole Section MASP Page 52 Milne Point Unit J-30 SB Injector Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 53 Milne Point Unit J-30 SB Injector Drilling Procedure 31.0 Surface Plat (As Built) (NAD 27) Page 54 Milne Point Unit J-30 SB Injector Drilling Procedure 32.0 Schrader Bluff NB Sand Offset MW vs TVD Chart 12 October, 2020 Plan: MPU J-30i wp06 Milne Point M Pt J Pad Plan: MPU J-30i MPU J-30i 0133326674000True Vertical Depth (2000 usft/in)01333 2667 4000533366678000 9333 10667 120001333314667 16000 17333 18667Vertical Section at 273.00° (2000 usft/in)MPU J-30 wp04 tgt 5MPU J-30 wp04 tgt 6MPU J-30 wp05 tgt 7MPU J-30 wp05 tgt 8MPU J-30 wp05 tgt 9MPU J-30 wp05 tgt 10MPU J-30 wp05 tgt 11MPU J-30 wp04 tgt 1MPU J-30 wp04 tgt 2MPU J-30 wp04 tgt 3MPU J-30 wp04 tgt 49 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000550060006500700075008000850090009500 1 0 0 0 0 10500 11000 11 5 0 0 1 2 0 0 0 125 0 0 1 3 0 0 0 1 350 0 1400 0 14500 1 5 0 0 0 15500 16000 16500 17000 1750 01800018500190001950019803MPU J-30i wp06Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 4º/100' : 700' MD, 697.08'TVDEnd Dir : 2521.15' MD, 2000.46' TVDStartDir3.5º/100':8167.22'MD,3591.08'TVDEndDir:9292.85'MD,3807.27'TVDStartDir3.1º/100':9392.85'MD,3815.99'TVDEndDir:9936.47'MD,3796.66'TVDStartDir3º/100':9960.79'MD,3792.82'TVDEndDir:10567.83'MD,3751'TVDStartDir3º/100':10990.71'MD,3759.94'TVDEndDir:11135.29'MD,3759.24'TVDStartDir3º/100':11769.64'MD,3739.73'TVDEndDir:11890.29'MD,3735.7'TVDStartDir3º/100':12734.63'MD,3705.32'TVDEndDir:12870.73'MD,3700.59'TVDStartDir3º/100':13653.49'MD,3674.33'TVDEndDir:13713.44'MD,3672.55'TVDStartDir3º/100':14490.13'MD,3652.49'TVDEndDir:14697.07'MD,3643.61'TVDStartDir3º/100':15256.18'MD,3610.11'TVDEndDir:15410.29'MD,3605.32'TVDStartDir3º/100':16195.73'MD,3603.56'TVDEndDir:16292.42'MD,3602.74'TVDStartDir3º/100':17115.6'MD,3590.71'TVDEndDir:18279.15'MD,3533.56'TVDTotalDepth:19802.99'MD,3516.35'TVDSV5BPRFUG3UG COAL 1UGNU LA3UGNU MBSCHRADER NASCHRADER NBWELL DETAILS: Plan: MPU J-30i NAD 1927 (NADCON CONUS) Alaska Zone 0433.60+N/-S +E/-W Northing EastingLatittude Longitude0.00 0.006015095.570 551921.73070° 27' 7.141 N 149° 34' 34.869 WCASING DETAILSTVD TVDSS MD Size Name3815.99 3748.69 9392.85 9-5/8 9 5/8" x 12 1/4"3516.35 3449.05 19802.99 4-1/2 4 1/2" x 8 1/2"FORMATION TOP DETAILSTVDPath TVDssPathMDPathFormation1401.88 1334.58 1476.94 SV52009.44 1942.14 2553.03 BPRF2704.25 2636.95 5019.33 UG33029.80 2962.50 6174.90 UG COAL 13374.40 3307.10 7398.10 UGNU LA33550.06 3482.76 8021.62 UGNU MB3789.91 3722.61 9126.18 SCHRADER NA3814.55 3747.25 9376.33 SCHRADER NBProject: Milne PointSite: M Pt J PadWell: Plan: MPU J-30iWellbore: MPU J-30iDesign: MPU J-30i wp06SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD3 700.00 12.00 5.00 697.08 41.58 3.64 3.00 5.00 -1.46 Start Dir 4º/100' : 700' MD, 697.08'TVD4 900.00 20.00 5.00 889.18 96.45 8.44 4.00 0.00 -3.385 2521.15 73.64 304.24 2000.46 897.69 -686.08 4.00 -67.66 732.12 End Dir : 2521.15' MD, 2000.46' TVD6 8167.22 73.64 304.24 3591.08 3946.20 -5164.32 0.00 0.00 5363.77 Start Dir 3.5º/100' : 8167.22' MD, 3591.08'TVD7 9292.85 85.00 265.76 3807.27 4219.48 -6211.45 3.50 -77.62 6423.77 End Dir : 9292.85' MD, 3807.27' TVD8 9392.85 85.00 265.76 3815.99 4212.12 -6310.80 0.00 0.00 6522.59 MPU J-30 wp04 tgt 1 Start Dir 3.1º/100' : 9392.85' MD, 3815.99'TVD9 9936.47 99.08 256.47 3796.66 4128.71 -6845.65 3.10 -33.36 7052.35 End Dir : 9936.47' MD, 3796.66' TVD10 9960.79 99.08 256.47 3792.82 4123.09 -6869.01 0.00 0.00 7075.38 MPU J-30 wp04 tgt 2 Start Dir 3º/100' : 9960.79' MD, 3792.82'TVD11 10567.83 88.79 271.55 3751.00 4060.67 -7468.81 3.00 123.65 7671.09 End Dir : 10567.83' MD, 3751' TVD12 10990.71 88.79 271.55 3759.94 4072.14 -7891.43 0.00 0.00 8093.74 MPU J-30 wp04 tgt 3 Start Dir 3º/100' : 10990.71' MD, 3759.94'TVD13 11135.29 91.76 268.40 3759.24 4072.07 -8035.98 3.00 -46.71 8238.08 End Dir : 11135.29' MD, 3759.24' TVD14 11769.64 91.76 268.40 3739.73 4054.33 -8669.77 0.00 0.00 8870.08 MPU J-30 wp04 tgt 4 Start Dir 3º/100' : 11769.64' MD, 3739.73'TVD15 11890.29 92.06 272.01 3735.70 4054.75 -8790.34 3.00 85.20 8990.50 End Dir : 11890.29' MD, 3735.7' TVD16 12734.63 92.06 272.01 3705.32 4084.28 -9633.61 0.00 0.00 9834.16 MPU J-30 wp04 tgt 5 Start Dir 3º/100' : 12734.63' MD, 3705.32'TVD17 12870.73 91.92 267.92 3700.59 4084.19 -9769.60 3.00 -91.89 9969.96 End Dir : 12870.73' MD, 3700.59' TVD18 13653.49 91.92 267.92 3674.33 4055.83 -10551.41 0.00 0.00 10749.22 MPU J-30 wp04 tgt 6 Start Dir 3º/100' : 13653.49' MD, 3674.33'TVD19 13713.44 91.48 269.67 3672.55 4054.57 -10611.31 3.00 104.21 10808.97 End Dir : 13713.44' MD, 3672.55' TVD20 14490.13 91.48 269.67 3652.49 4050.04 -11387.73 0.00 0.00 11584.09 MPU J-30 wp05 tgt 7 Start Dir 3º/100' : 14490.13' MD, 3652.49'TVD21 14697.07 93.43 275.56 3643.61 4059.46 -11594.16 3.00 71.54 11790.73 End Dir : 14697.07' MD, 3643.61' TVD22 15256.18 93.43 275.56 3610.11 4113.58 -12149.64 0.00 0.00 12348.28 MPU J-30 wp05 tgt 8 Start Dir 3º/100' : 15256.18' MD, 3610.11'TVD23 15410.29 90.13 272.33 3605.32 4124.18 -12303.27 3.00 -135.60 12502.25 End Dir : 15410.29' MD, 3605.32' TVD24 16195.73 90.13 272.33 3603.56 4156.12 -13088.06 0.00 0.00 13287.64 MPU J-30 wp05 tgt 9 Start Dir 3º/100' : 16195.73' MD, 3603.56'TVD25 16292.42 90.84 269.52 3602.74 4157.68 -13184.73 3.00 -75.83 13384.25 End Dir : 16292.42' MD, 3602.74' TVD26 17065.60 90.84 269.52 3591.44 4151.18 -13957.80 0.00 0.00 14155.93 MPU J-30 wp05 tgt 1027 17115.60 90.84 269.52 3590.71 4150.76 -14007.79 0.00 0.00 14205.83 Start Dir 3º/100' : 17115.6' MD, 3590.71'TVD28 17340.60 84.29 271.16 3600.27 4152.07 -14232.46 3.00 166.00 14430.2529 17910.60 101.39 271.16 3572.15 4163.51 -14799.53 3.00 0.00 14997.1530 18279.15 90.65 273.79 3533.56 4179.40 -15165.13 3.00 166.12 15363.08 End Dir : 18279.15' MD, 3533.56' TVD31 19802.99 90.65 273.79 3516.35 4280.20 -16685.53 0.00 0.00 16886.67 MPU J-30 wp05 tgt 11 Total Depth : 19802.99' MD, 3516.35' TVDSURVEY PROGRAMDate: 2020-10-08T00:00:00 Validated: Yes Version: Depth FromDepth ToSurvey/Plan Tool33.70 1000.00 MPU J-30i wp06 (MPU J-30i) 3_Gyro-GC_Csg1000.00 9392.85 MPU J-30i wp06 (MPU J-30i) 3_MWD+IFR2+MS+Sag9392.85 19802.99 MPU J-30i wp06 (MPU J-30i) 3_MWD+IFR2+MS+Sag -2667-133301333266740005333666780009333South(-)/North(+) (2000 usft/in)-17333 -16000 -14667 -13333 -12000 -10667 -9333 -8000 -6667 -5333 -4000 -2667 -1333 0 1333West(-)/East(+) (2000 usft/in)MPU J-30 wp04 tgt 4MPU J-30 wp04 tgt 3MPU J-30 wp04 tgt 2MPU J-30 wp04 tgt 1MPU J-30 wp05 tgt 11MPU J-30 wp05 tgt 10MPU J-30 wp05 tgt 9MPU J-30 wp05 tgt 8MPU J-30 wp05 tgt 7MPU J-30 wp04 tgt 6MPU J-30 wp04 tgt 59 5/8" x 12 1/4"4 1/2" x 8 1/2"7501000125015001750200022502500275030003250350037503516MPU J-30i wp06Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 4º/100' : 700' MD, 697.08'TVDEnd Dir : 2521.15' MD, 2000.46' TVDStart Dir 3.5º/100' : 8167.22' MD, 3591.08'TVDEndDir:9292.85'MD,3807.27'TVDStartDir3.1º/100':9392.85'MD,3815.99'TVDEndDir:9936.47'MD,3796.66'TVDStartDir3º/100':9960.79'MD,3792.82'TVDEndDir:10567.83'MD,3751'TVDStartDir3º/100':10990.71'MD,3759.94'TVDEndDir:11135.29'MD,3759.24'TVDStartDir3º/100' :11769.64'MD, 3739.73'TVDEndDir:11890.29'MD,3735.7'TVDStartDir3º/100':12734.63'MD,3705.32'TVDEndDir:12870.73'MD,3700.59'TVDStartDir3º/100':13653.49'MD,3674.33'TVDEndDir:13713.44'MD,3672.55'TVDStartDir3º/100':14490.13'MD,3652.49'TVDEndDir:14697.07'MD,3643.61'TVDStartDir3º/100' :15256.18'MD, 3610.11'TVDEndDir:15410.29'MD,3605.32'TVDStartDir3º/100':16195.73'MD,3603.56'TVDEndDir:16292.42'MD,3602.74'TVDStartDir3º/100' :17115.6'MD,3590.71'TVDEndDir:18279.15'MD,3533.56'TVDTotal Depth :19802.99'MD,3516.35'TVDProject: Milne PointSite: M Pt J PadWell: Plan: MPU J-30iWellbore: MPU J-30iPlan: MPU J-30i wp06WELL DETAILS: Plan: MPU J-30i33.60+N/-S +E/-W Northing Easting Latittude Longitude0.000.006015095.570 551921.73070° 27' 7.141 N149° 34' 34.869 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-30i, True NorthVertical (TVD) Reference:MPU J-30 As-staked RKB @ 67.30usftMeasured Depth Reference:MPU J-30 As-staked RKB @ 67.30usftCalculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name3815.99 3748.69 9392.85 9-5/8 9 5/8" x 12 1/4"3516.35 3449.05 19802.99 4-1/2 4 1/2" x 8 1/2" Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU J-30i MPU J-30i Survey Calculation Method:Minimum Curvature MPU J-30 As-staked RKB @ 67.30usft Design:MPU J-30i wp06 Database:NORTH US + CANADA MD Reference:MPU J-30 As-staked RKB @ 67.30usft North Reference: Well Plan: MPU J-30i True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: Grid Convergence: M Pt J Pad, TR-13-10 usft Map usft usft °0.40Slot Radius:"0 6,013,415.230 551,435.100 0.00 70° 26' 50.647 N 149° 34' 49.503 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPU J-30i usft usft 0.00 0.00 6,015,095.570 551,921.730 33.60Wellhead Elevation:usft0.50 70° 27' 7.141 N 149° 34' 34.869 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU J-30i Model NameMagnetics BGGM2020 12/15/2020 15.76 80.83 57,360.03515282 Phase:Version: Audit Notes: Design MPU J-30i wp06 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.70 273.000.000.0033.70 10/12/2020 4:00:55PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU J-30i MPU J-30i Survey Calculation Method:Minimum Curvature MPU J-30 As-staked RKB @ 67.30usft Design:MPU J-30i wp06 Database:NORTH US + CANADA MD Reference:MPU J-30 As-staked RKB @ 67.30usft North Reference: Well Plan: MPU J-30i True Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.000.000.0033.700.000.0033.70 -33.60 0.000.000.000.000.000.00300.000.000.00300.00 232.70 5.000.003.003.003.6441.58697.085.0012.00700.00 629.78 0.000.004.004.008.4496.45889.185.0020.00900.00 821.88 -67.66-3.753.314.00-686.08897.692,000.46304.2473.642,521.15 1,933.16 0.000.000.000.00-5,164.323,946.203,591.08304.2473.648,167.22 3,523.78 -77.62-3.421.013.50-6,211.454,219.483,807.27265.7685.009,292.85 3,739.97 0.000.000.000.00-6,310.804,212.123,815.99265.7685.009,392.85 3,748.69 -33.36-1.712.593.10-6,845.654,128.713,796.66256.4799.089,936.47 3,729.36 0.000.000.000.00-6,869.014,123.093,792.82256.4799.089,960.79 3,725.52 123.652.48-1.693.00-7,468.814,060.673,751.00271.5588.7910,567.83 3,683.70 0.000.000.000.00-7,891.434,072.143,759.94271.5588.7910,990.71 3,692.64 -46.71-2.182.063.00-8,035.984,072.073,759.24268.4091.7611,135.29 3,691.94 0.000.000.000.00-8,669.774,054.333,739.73268.4091.7611,769.64 3,672.43 85.202.990.253.00-8,790.344,054.753,735.70272.0192.0611,890.29 3,668.40 0.000.000.000.00-9,633.614,084.283,705.32272.0192.0612,734.63 3,638.02 -91.89-3.00-0.103.00-9,769.604,084.193,700.59267.9291.9212,870.73 3,633.29 0.000.000.000.00-10,551.414,055.833,674.33267.9291.9213,653.49 3,607.03 104.212.91-0.743.00-10,611.314,054.573,672.55269.6791.4813,713.44 3,605.25 0.000.000.000.00-11,387.734,050.043,652.49269.6791.4814,490.13 3,585.19 71.542.850.943.00-11,594.164,059.463,643.61275.5693.4314,697.07 3,576.31 0.000.000.000.00-12,149.644,113.583,610.11275.5693.4315,256.18 3,542.81 -135.60-2.10-2.153.00-12,303.274,124.183,605.32272.3390.1315,410.29 3,538.02 0.000.000.000.00-13,088.064,156.123,603.56272.3390.1316,195.73 3,536.26 -75.83-2.910.733.00-13,184.734,157.683,602.74269.5290.8416,292.42 3,535.44 0.000.000.000.00-13,957.804,151.183,591.44269.5290.8417,065.60 3,524.14 0.000.000.000.00-14,007.794,150.763,590.71269.5290.8417,115.60 3,523.41 166.000.73-2.913.00-14,232.464,152.073,600.27271.1684.2917,340.60 3,532.97 0.000.003.003.00-14,799.534,163.513,572.15271.16101.3917,910.60 3,504.85 166.120.72-2.913.00-15,165.134,179.403,533.56273.7990.6518,279.15 3,466.26 0.000.000.000.00-16,685.534,280.203,516.35273.7990.6519,802.99 3,449.05 10/12/2020 4:00:55PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU J-30i MPU J-30i Survey Calculation Method:Minimum Curvature MPU J-30 As-staked RKB @ 67.30usft Design:MPU J-30i wp06 Database:NORTH US + CANADA MD Reference:MPU J-30 As-staked RKB @ 67.30usft North Reference: Well Plan: MPU J-30i True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -33.60 Vert Section 33.70 0.00 33.70 0.00 0.000.00 551,921.7306,015,095.570-33.60 0.000 0.00 100.00 0.00 100.00 0.00 0.000.00 551,921.7306,015,095.57032.70 0.000 0.00 200.00 0.00 200.00 0.00 0.000.00 551,921.7306,015,095.570132.70 0.000 0.00 300.00 0.00 300.00 0.00 0.000.00 551,921.7306,015,095.570232.70 0.000 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 400.00 3.00 399.95 2.61 0.235.00 551,921.9406,015,098.179332.65 3.000 -0.09 500.00 6.00 499.63 10.42 0.915.00 551,922.5696,015,105.998432.33 3.000 -0.37 600.00 9.00 598.77 23.42 2.055.00 551,923.6166,015,119.006531.47 3.000 -0.82 700.00 12.00 697.08 41.58 3.645.00 551,925.0776,015,137.166629.78 3.000 -1.46 Start Dir 4º/100' : 700' MD, 697.08'TVD 800.00 16.00 794.09 65.67 5.755.00 551,927.0176,015,161.274726.79 4.000 -2.30 900.00 20.00 889.18 96.45 8.445.00 551,929.4956,015,192.066821.88 4.000 -3.38 1,000.00 21.82 982.62 132.02 8.31355.01 551,929.1206,015,227.628915.32 4.000 -1.39 1,100.00 24.15 1,074.69 170.46 1.97346.66 551,922.5136,015,266.0201,007.39 4.000 6.95 1,200.00 26.86 1,164.96 211.58 -10.55339.81 551,909.7076,015,307.0531,097.66 4.000 21.61 1,300.00 29.84 1,252.97 255.19 -29.19334.18 551,890.7646,015,350.5291,185.67 4.000 42.51 1,400.00 33.01 1,338.31 301.08 -53.86329.51 551,865.7776,015,396.2351,271.01 4.000 69.55 1,476.94 35.56 1,401.88 337.79 -76.87326.43 551,842.5136,015,432.7811,334.58 4.000 94.45 SV5 1,500.00 36.34 1,420.55 349.01 -84.44325.59 551,834.8676,015,443.9491,353.25 4.000 102.59 1,600.00 39.77 1,499.29 398.76 -120.78322.25 551,798.1856,015,493.4391,431.99 4.000 141.48 1,700.00 43.28 1,574.15 450.08 -162.70319.36 551,755.9106,015,544.4621,506.85 4.000 186.04 1,800.00 46.86 1,644.77 502.73 -210.01316.84 551,708.2476,015,596.7721,577.47 4.000 236.03 1,900.00 50.49 1,710.80 556.44 -262.46314.59 551,655.4306,015,650.1121,643.50 4.000 291.22 2,000.00 54.15 1,771.92 610.95 -319.80312.57 551,597.7146,015,704.2231,704.62 4.000 351.33 2,100.00 57.85 1,827.83 666.01 -381.75310.72 551,535.3816,015,758.8411,760.53 4.000 416.09 2,200.00 61.57 1,878.26 721.34 -448.02309.03 551,468.7366,015,813.7011,810.96 4.000 485.16 2,300.00 65.31 1,922.97 776.67 -518.28307.44 551,398.1026,015,868.5341,855.67 4.000 558.22 2,400.00 69.07 1,961.73 831.73 -592.18305.95 551,323.8246,015,923.0741,894.43 4.000 634.90 2,500.00 72.84 1,994.36 886.26 -669.37304.54 551,246.2646,015,977.0561,927.06 4.000 714.84 2,521.15 73.64 2,000.46 897.70 -686.08304.24 551,229.4756,015,988.3761,933.16 4.000 732.13 End Dir : 2521.15' MD, 2000.46' TVD 2,553.03 73.64 2,009.44 914.91 -711.37304.24 551,204.0726,016,005.4111,942.14 0.000 758.28 BPRF 2,600.00 73.64 2,022.67 940.27 -748.62304.24 551,166.6456,016,030.5091,955.37 0.000 796.81 2,700.00 73.64 2,050.84 994.26 -827.94304.24 551,086.9626,016,083.9441,983.54 0.000 878.84 2,800.00 73.64 2,079.02 1,048.26 -907.26304.24 551,007.2806,016,137.3782,011.72 0.000 960.88 2,900.00 73.64 2,107.19 1,102.25 -986.57304.24 550,927.5976,016,190.8122,039.89 0.000 1,042.91 3,000.00 73.64 2,135.36 1,156.24 -1,065.89304.24 550,847.9146,016,244.2462,068.06 0.000 1,124.94 3,100.00 73.64 2,163.53 1,210.24 -1,145.21304.24 550,768.2326,016,297.6812,096.23 0.000 1,206.97 3,200.00 73.64 2,191.71 1,264.23 -1,224.52304.24 550,688.5496,016,351.1152,124.41 0.000 1,289.01 3,300.00 73.64 2,219.88 1,318.22 -1,303.84304.24 550,608.8666,016,404.5492,152.58 0.000 1,371.04 3,400.00 73.64 2,248.05 1,372.22 -1,383.15304.24 550,529.1846,016,457.9842,180.75 0.000 1,453.07 3,500.00 73.64 2,276.22 1,426.21 -1,462.47304.24 550,449.5016,016,511.4182,208.92 0.000 1,535.11 3,600.00 73.64 2,304.39 1,480.20 -1,541.79304.24 550,369.8196,016,564.8522,237.09 0.000 1,617.14 10/12/2020 4:00:55PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU J-30i MPU J-30i Survey Calculation Method:Minimum Curvature MPU J-30 As-staked RKB @ 67.30usft Design:MPU J-30i wp06 Database:NORTH US + CANADA MD Reference:MPU J-30 As-staked RKB @ 67.30usft North Reference: Well Plan: MPU J-30i True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 2,265.27 Vert Section 3,700.00 73.64 2,332.57 1,534.20 -1,621.10304.24 550,290.1366,016,618.2862,265.27 0.000 1,699.17 3,800.00 73.64 2,360.74 1,588.19 -1,700.42304.24 550,210.4536,016,671.7212,293.44 0.000 1,781.21 3,900.00 73.64 2,388.91 1,642.18 -1,779.73304.24 550,130.7716,016,725.1552,321.61 0.000 1,863.24 4,000.00 73.64 2,417.08 1,696.18 -1,859.05304.24 550,051.0886,016,778.5892,349.78 0.000 1,945.27 4,100.00 73.64 2,445.26 1,750.17 -1,938.37304.24 549,971.4056,016,832.0242,377.96 0.000 2,027.31 4,200.00 73.64 2,473.43 1,804.16 -2,017.68304.24 549,891.7236,016,885.4582,406.13 0.000 2,109.34 4,300.00 73.64 2,501.60 1,858.16 -2,097.00304.24 549,812.0406,016,938.8922,434.30 0.000 2,191.37 4,400.00 73.64 2,529.77 1,912.15 -2,176.31304.24 549,732.3576,016,992.3262,462.47 0.000 2,273.41 4,500.00 73.64 2,557.94 1,966.14 -2,255.63304.24 549,652.6756,017,045.7612,490.64 0.000 2,355.44 4,600.00 73.64 2,586.12 2,020.14 -2,334.95304.24 549,572.9926,017,099.1952,518.82 0.000 2,437.47 4,700.00 73.64 2,614.29 2,074.13 -2,414.26304.24 549,493.3106,017,152.6292,546.99 0.000 2,519.51 4,800.00 73.64 2,642.46 2,128.12 -2,493.58304.24 549,413.6276,017,206.0632,575.16 0.000 2,601.54 4,900.00 73.64 2,670.63 2,182.12 -2,572.89304.24 549,333.9446,017,259.4982,603.33 0.000 2,683.57 5,000.00 73.64 2,698.80 2,236.11 -2,652.21304.24 549,254.2626,017,312.9322,631.50 0.000 2,765.60 5,019.33 73.64 2,704.25 2,246.55 -2,667.54304.24 549,238.8606,017,323.2602,636.95 0.000 2,781.46 UG3 5,100.00 73.64 2,726.98 2,290.11 -2,731.53304.24 549,174.5796,017,366.3662,659.68 0.000 2,847.64 5,200.00 73.64 2,755.15 2,344.10 -2,810.84304.24 549,094.8966,017,419.8012,687.85 0.000 2,929.67 5,300.00 73.64 2,783.32 2,398.09 -2,890.16304.24 549,015.2146,017,473.2352,716.02 0.000 3,011.70 5,400.00 73.64 2,811.49 2,452.09 -2,969.47304.24 548,935.5316,017,526.6692,744.19 0.000 3,093.74 5,500.00 73.64 2,839.67 2,506.08 -3,048.79304.24 548,855.8486,017,580.1032,772.37 0.000 3,175.77 5,600.00 73.64 2,867.84 2,560.07 -3,128.11304.24 548,776.1666,017,633.5382,800.54 0.000 3,257.80 5,700.00 73.64 2,896.01 2,614.07 -3,207.42304.24 548,696.4836,017,686.9722,828.71 0.000 3,339.84 5,800.00 73.64 2,924.18 2,668.06 -3,286.74304.24 548,616.8016,017,740.4062,856.88 0.000 3,421.87 5,900.00 73.64 2,952.35 2,722.05 -3,366.05304.24 548,537.1186,017,793.8412,885.05 0.000 3,503.90 6,000.00 73.64 2,980.53 2,776.05 -3,445.37304.24 548,457.4356,017,847.2752,913.23 0.000 3,585.94 6,100.00 73.64 3,008.70 2,830.04 -3,524.69304.24 548,377.7536,017,900.7092,941.40 0.000 3,667.97 6,174.90 73.64 3,029.80 2,870.48 -3,584.10304.24 548,318.0696,017,940.7332,962.50 0.000 3,729.41 UG COAL 1 6,200.00 73.64 3,036.87 2,884.03 -3,604.00304.24 548,298.0706,017,954.1432,969.57 0.000 3,750.00 6,300.00 73.64 3,065.04 2,938.03 -3,683.32304.24 548,218.3876,018,007.5782,997.74 0.000 3,832.04 6,400.00 73.64 3,093.21 2,992.02 -3,762.64304.24 548,138.7056,018,061.0123,025.91 0.000 3,914.07 6,500.00 73.64 3,121.39 3,046.01 -3,841.95304.24 548,059.0226,018,114.4463,054.09 0.000 3,996.10 6,600.00 73.64 3,149.56 3,100.01 -3,921.27304.24 547,979.3406,018,167.8803,082.26 0.000 4,078.14 6,700.00 73.64 3,177.73 3,154.00 -4,000.58304.24 547,899.6576,018,221.3153,110.43 0.000 4,160.17 6,800.00 73.64 3,205.90 3,207.99 -4,079.90304.24 547,819.9746,018,274.7493,138.60 0.000 4,242.20 6,900.00 73.64 3,234.08 3,261.99 -4,159.22304.24 547,740.2926,018,328.1833,166.78 0.000 4,324.23 7,000.00 73.64 3,262.25 3,315.98 -4,238.53304.24 547,660.6096,018,381.6183,194.95 0.000 4,406.27 7,100.00 73.64 3,290.42 3,369.97 -4,317.85304.24 547,580.9266,018,435.0523,223.12 0.000 4,488.30 7,200.00 73.64 3,318.59 3,423.97 -4,397.16304.24 547,501.2446,018,488.4863,251.29 0.000 4,570.33 7,300.00 73.64 3,346.76 3,477.96 -4,476.48304.24 547,421.5616,018,541.9203,279.46 0.000 4,652.37 7,398.10 73.64 3,374.40 3,530.93 -4,554.29304.24 547,343.3966,018,594.3373,307.10 0.000 4,732.84 UGNU LA3 7,400.00 73.64 3,374.94 3,531.95 -4,555.80304.24 547,341.8786,018,595.3553,307.64 0.000 4,734.40 7,500.00 73.64 3,403.11 3,585.95 -4,635.11304.24 547,262.1966,018,648.7893,335.81 0.000 4,816.43 10/12/2020 4:00:55PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU J-30i MPU J-30i Survey Calculation Method:Minimum Curvature MPU J-30 As-staked RKB @ 67.30usft Design:MPU J-30i wp06 Database:NORTH US + CANADA MD Reference:MPU J-30 As-staked RKB @ 67.30usft North Reference: Well Plan: MPU J-30i True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,363.98 Vert Section 7,600.00 73.64 3,431.28 3,639.94 -4,714.43304.24 547,182.5136,018,702.2233,363.98 0.000 4,898.47 7,700.00 73.64 3,459.45 3,693.93 -4,793.74304.24 547,102.8316,018,755.6583,392.15 0.000 4,980.50 7,800.00 73.64 3,487.63 3,747.93 -4,873.06304.24 547,023.1486,018,809.0923,420.33 0.000 5,062.53 7,900.00 73.64 3,515.80 3,801.92 -4,952.38304.24 546,943.4656,018,862.5263,448.50 0.000 5,144.57 8,000.00 73.64 3,543.97 3,855.91 -5,031.69304.24 546,863.7836,018,915.9603,476.67 0.000 5,226.60 8,021.62 73.64 3,550.06 3,867.59 -5,048.84304.24 546,846.5566,018,927.5123,482.76 0.000 5,244.33 UGNU MB 8,100.00 73.64 3,572.14 3,909.91 -5,111.01304.24 546,784.1006,018,969.3953,504.84 0.000 5,308.63 8,167.22 73.64 3,591.08 3,946.20 -5,164.32304.24 546,730.5376,019,005.3133,523.78 0.000 5,363.78 Start Dir 3.5º/100' : 8167.22' MD, 3591.08'TVD 8,200.00 73.89 3,600.25 3,963.65 -5,190.52303.08 546,704.2246,019,022.5733,532.95 3.500 5,390.85 8,300.00 74.68 3,627.34 4,013.65 -5,272.75299.54 546,621.6536,019,072.0013,560.04 3.500 5,475.58 8,400.00 75.54 3,653.04 4,058.69 -5,358.24296.03 546,535.8606,019,116.4323,585.74 3.500 5,563.31 8,500.00 76.44 3,677.25 4,098.58 -5,446.67292.54 546,447.1656,019,155.7003,609.95 3.500 5,653.71 8,600.00 77.40 3,699.89 4,133.17 -5,537.70289.08 546,355.9006,019,189.6603,632.59 3.500 5,746.43 8,700.00 78.39 3,720.86 4,162.35 -5,631.01285.65 546,262.4046,019,218.1833,653.56 3.500 5,841.13 8,800.00 79.43 3,740.10 4,186.00 -5,726.23282.25 546,167.0266,019,241.1643,672.80 3.500 5,937.46 8,900.00 80.51 3,757.52 4,204.03 -5,823.02278.86 546,070.1226,019,258.5183,690.22 3.500 6,035.06 9,000.00 81.61 3,773.06 4,216.37 -5,921.02275.50 545,972.0546,019,270.1783,705.76 3.500 6,133.57 9,100.00 82.75 3,786.67 4,222.99 -6,019.85272.16 545,873.1876,019,276.1033,719.37 3.500 6,232.61 9,126.18 83.05 3,789.91 4,223.77 -6,045.82271.29 545,847.2196,019,276.7033,722.61 3.500 6,258.59 SCHRADER NA 9,200.00 83.91 3,798.30 4,223.84 -6,119.15268.83 545,773.8906,019,276.2693,731.00 3.500 6,331.83 9,292.85 85.00 3,807.27 4,219.48 -6,211.45265.76 545,681.6326,019,271.2663,739.97 3.500 6,423.77 End Dir : 9292.85' MD, 3807.27' TVD 9,300.00 85.00 3,807.90 4,218.96 -6,218.56265.76 545,674.5336,019,270.6903,740.60 0.000 6,430.84 9,376.33 85.00 3,814.55 4,213.34 -6,294.38265.76 545,598.7546,019,264.5413,747.25 0.000 6,506.27 SCHRADER NB 9,392.85 85.00 3,815.99 4,212.12 -6,310.80265.76 545,582.3496,019,263.2103,748.69 0.000 6,522.60 Start Dir 3.1º/100' : 9392.85' MD, 3815.99'TVD - 9 5/8" x 12 1/4" 9,400.00 85.19 3,816.60 4,211.59 -6,317.90265.64 545,575.2496,019,262.6263,749.30 3.100 6,529.66 9,500.00 87.78 3,822.74 4,202.51 -6,417.29263.93 545,475.9396,019,252.8623,755.44 3.100 6,628.44 9,600.00 90.37 3,824.36 4,190.47 -6,516.54262.23 545,376.7876,019,240.1333,757.06 3.100 6,726.92 9,700.00 92.96 3,821.45 4,175.50 -6,615.35260.53 545,278.0866,019,224.4753,754.15 3.100 6,824.82 9,800.00 95.55 3,814.03 4,157.64 -6,713.45258.83 545,180.1236,019,205.9353,746.73 3.100 6,921.85 9,900.00 98.14 3,802.12 4,136.95 -6,810.55257.10 545,083.1846,019,184.5663,734.82 3.100 7,017.73 9,936.47 99.08 3,796.66 4,128.71 -6,845.65256.47 545,048.1426,019,176.0813,729.36 3.099 7,052.35 End Dir : 9936.47' MD, 3796.66' TVD 9,960.79 99.08 3,792.82 4,123.09 -6,869.00256.47 545,024.8356,019,170.3013,725.52 0.000 7,075.37 Start Dir 3º/100' : 9960.79' MD, 3792.82'TVD 10,000.00 98.42 3,786.86 4,114.35 -6,906.76257.46 544,987.1466,019,161.2993,719.56 3.000 7,112.62 10,100.00 96.75 3,773.65 4,094.96 -7,003.95259.97 544,890.0956,019,141.2343,706.35 3.000 7,208.67 10,200.00 95.06 3,763.37 4,079.78 -7,102.25262.46 544,791.9206,019,125.3683,696.07 3.000 7,306.03 10,300.00 93.36 3,756.03 4,068.84 -7,201.36264.94 544,692.8916,019,113.7443,688.73 3.000 7,404.44 10,400.00 91.66 3,751.65 4,062.18 -7,301.03267.41 544,593.2786,019,106.3943,684.35 3.000 7,503.63 10/12/2020 4:00:55PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU J-30i MPU J-30i Survey Calculation Method:Minimum Curvature MPU J-30 As-staked RKB @ 67.30usft Design:MPU J-30i wp06 Database:NORTH US + CANADA MD Reference:MPU J-30 As-staked RKB @ 67.30usft North Reference: Well Plan: MPU J-30i True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,682.95 Vert Section 10,500.00 89.95 3,750.25 4,059.82 -7,400.99269.88 544,493.3566,019,103.3383,682.95 3.000 7,603.32 10,567.83 88.79 3,751.00 4,060.67 -7,468.80271.55 544,425.5416,019,103.7143,683.70 3.000 7,671.09 End Dir : 10567.83' MD, 3751' TVD 10,600.00 88.79 3,751.68 4,061.54 -7,500.95271.55 544,393.3886,019,104.3613,684.38 0.000 7,703.24 10,700.00 88.79 3,753.79 4,064.26 -7,600.89271.55 544,293.4416,019,106.3753,686.49 0.000 7,803.18 10,800.00 88.79 3,755.91 4,066.97 -7,700.83271.55 544,193.4936,019,108.3893,688.61 0.000 7,903.13 10,900.00 88.79 3,758.02 4,069.68 -7,800.78271.55 544,093.5456,019,110.4033,690.72 0.000 8,003.08 10,990.71 88.79 3,759.94 4,072.14 -7,891.43271.55 544,002.8836,019,112.2303,692.64 0.000 8,093.74 Start Dir 3º/100' : 10990.71' MD, 3759.94'TVD 11,000.00 88.98 3,760.12 4,072.37 -7,900.72271.35 543,993.5976,019,112.4013,692.82 2.999 8,103.02 11,100.00 91.04 3,760.11 4,072.82 -8,000.70269.17 543,893.6186,019,112.1563,692.81 3.000 8,202.90 11,135.29 91.76 3,759.24 4,072.07 -8,035.98268.40 543,858.3576,019,111.1603,691.94 3.000 8,238.08 End Dir : 11135.29' MD, 3759.24' TVD 11,200.00 91.76 3,757.25 4,070.26 -8,100.63268.40 543,793.7236,019,108.9003,689.95 0.000 8,302.55 11,300.00 91.76 3,754.18 4,067.46 -8,200.54268.40 543,693.8416,019,105.4063,686.88 0.000 8,402.18 11,400.00 91.76 3,751.10 4,064.67 -8,300.46268.40 543,593.9596,019,101.9133,683.80 0.000 8,501.81 11,500.00 91.76 3,748.02 4,061.87 -8,400.37268.40 543,494.0786,019,098.4193,680.72 0.000 8,601.44 11,600.00 91.76 3,744.95 4,059.07 -8,500.28268.40 543,394.1966,019,094.9263,677.65 0.000 8,701.07 11,700.00 91.76 3,741.87 4,056.27 -8,600.20268.40 543,294.3146,019,091.4333,674.57 0.000 8,800.70 11,769.64 91.76 3,739.73 4,054.33 -8,669.78268.40 543,224.7566,019,089.0003,672.43 0.000 8,870.08 Start Dir 3º/100' : 11769.64' MD, 3739.73'TVD 11,800.00 91.84 3,738.78 4,053.72 -8,700.12269.30 543,194.4256,019,088.1803,671.48 3.000 8,900.35 11,890.29 92.06 3,735.70 4,054.75 -8,790.34272.01 543,104.2066,019,088.5823,668.40 3.000 8,990.50 End Dir : 11890.29' MD, 3735.7' TVD 11,900.00 92.06 3,735.35 4,055.09 -8,800.04272.01 543,094.5076,019,088.8543,668.05 0.000 9,000.20 12,000.00 92.06 3,731.75 4,058.58 -8,899.91272.01 542,994.6206,019,091.6553,664.45 0.000 9,100.12 12,100.00 92.06 3,728.16 4,062.08 -8,999.79272.01 542,894.7346,019,094.4563,660.86 0.000 9,200.04 12,200.00 92.06 3,724.56 4,065.58 -9,099.66272.01 542,794.8486,019,097.2563,657.26 0.000 9,299.96 12,300.00 92.06 3,720.96 4,069.08 -9,199.53272.01 542,694.9626,019,100.0573,653.66 0.000 9,399.88 12,400.00 92.06 3,717.36 4,072.57 -9,299.41272.01 542,595.0756,019,102.8583,650.06 0.000 9,499.80 12,500.00 92.06 3,713.76 4,076.07 -9,399.28272.01 542,495.1896,019,105.6593,646.46 0.000 9,599.72 12,600.00 92.06 3,710.16 4,079.57 -9,499.16272.01 542,395.3036,019,108.4593,642.86 0.000 9,699.65 12,700.00 92.06 3,706.57 4,083.06 -9,599.03272.01 542,295.4166,019,111.2603,639.27 0.000 9,799.57 12,734.63 92.06 3,705.32 4,084.28 -9,633.62272.01 542,260.8266,019,112.2303,638.02 0.000 9,834.17 Start Dir 3º/100' : 12734.63' MD, 3705.32'TVD 12,800.00 92.00 3,703.00 4,085.44 -9,698.93270.04 542,195.5106,019,112.9433,635.70 3.000 9,899.45 12,870.73 91.92 3,700.59 4,084.19 -9,769.60267.92 542,124.8546,019,111.1963,633.29 3.000 9,969.97 End Dir : 12870.73' MD, 3700.59' TVD 12,900.00 91.92 3,699.60 4,083.13 -9,798.84267.92 542,095.6316,019,109.9323,632.30 0.000 9,999.10 13,000.00 91.92 3,696.25 4,079.50 -9,898.72267.92 541,995.7906,019,105.6133,628.95 0.000 10,098.66 13,100.00 91.92 3,692.90 4,075.88 -9,998.59267.92 541,895.9496,019,101.2943,625.60 0.000 10,198.21 13,200.00 91.92 3,689.54 4,072.26 -10,098.47267.92 541,796.1096,019,096.9763,622.24 0.000 10,297.76 13,300.00 91.92 3,686.19 4,068.63 -10,198.35267.92 541,696.2686,019,092.6573,618.89 0.000 10,397.31 13,400.00 91.92 3,682.83 4,065.01 -10,298.23267.92 541,596.4276,019,088.3383,615.53 0.000 10,496.86 13,500.00 91.92 3,679.48 4,061.39 -10,398.11267.92 541,496.5876,019,084.0193,612.18 0.000 10,596.41 10/12/2020 4:00:55PM COMPASS 5000.15 Build 91E Page 7 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU J-30i MPU J-30i Survey Calculation Method:Minimum Curvature MPU J-30 As-staked RKB @ 67.30usft Design:MPU J-30i wp06 Database:NORTH US + CANADA MD Reference:MPU J-30 As-staked RKB @ 67.30usft North Reference: Well Plan: MPU J-30i True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,608.82 Vert Section 13,600.00 91.92 3,676.12 4,057.76 -10,497.98267.92 541,396.7466,019,079.7003,608.82 0.000 10,695.96 13,653.49 91.92 3,674.33 4,055.83 -10,551.41267.92 541,343.3416,019,077.3903,607.03 0.000 10,749.21 Start Dir 3º/100' : 13653.49' MD, 3674.33'TVD 13,700.00 91.58 3,672.91 4,054.69 -10,597.88269.28 541,296.8826,019,075.9303,605.61 3.000 10,795.56 13,713.44 91.48 3,672.55 4,054.57 -10,611.32269.67 541,283.4496,019,075.7123,605.25 2.999 10,808.97 End Dir : 13713.44' MD, 3672.55' TVD 13,800.00 91.48 3,670.31 4,054.06 -10,697.85269.67 541,196.9346,019,074.6053,603.01 0.000 10,895.36 13,900.00 91.48 3,667.73 4,053.48 -10,797.81269.67 541,096.9856,019,073.3263,600.43 0.000 10,995.16 14,000.00 91.48 3,665.15 4,052.90 -10,897.78269.67 540,997.0366,019,072.0483,597.85 0.000 11,094.95 14,100.00 91.48 3,662.57 4,052.31 -10,997.74269.67 540,897.0876,019,070.7693,595.27 0.000 11,194.75 14,200.00 91.48 3,659.98 4,051.73 -11,097.71269.67 540,797.1396,019,069.4903,592.68 0.000 11,294.55 14,300.00 91.48 3,657.40 4,051.15 -11,197.67269.67 540,697.1906,019,068.2113,590.10 0.000 11,394.35 14,400.00 91.48 3,654.82 4,050.57 -11,297.64269.67 540,597.2416,019,066.9333,587.52 0.000 11,494.14 14,490.13 91.48 3,652.49 4,050.04 -11,387.74269.67 540,507.1576,019,065.7803,585.19 0.000 11,584.09 Start Dir 3º/100' : 14490.13' MD, 3652.49'TVD 14,500.00 91.57 3,652.23 4,050.01 -11,397.60269.95 540,497.2926,019,065.6783,584.93 3.001 11,593.94 14,600.00 92.52 3,648.65 4,052.40 -11,497.50272.80 540,397.3926,019,067.3723,581.35 3.000 11,693.83 14,697.07 93.43 3,643.61 4,059.46 -11,594.17275.56 540,300.6846,019,073.7623,576.31 3.000 11,790.73 End Dir : 14697.07' MD, 3643.61' TVD 14,700.00 93.43 3,643.43 4,059.75 -11,597.08275.56 540,297.7716,019,074.0253,576.13 0.000 11,793.66 14,800.00 93.43 3,637.44 4,069.43 -11,696.43275.56 540,198.3666,019,083.0113,570.14 0.000 11,893.38 14,900.00 93.43 3,631.45 4,079.10 -11,795.78275.56 540,098.9606,019,091.9963,564.15 0.000 11,993.10 15,000.00 93.43 3,625.46 4,088.78 -11,895.13275.56 539,999.5556,019,100.9813,558.16 0.000 12,092.82 15,100.00 93.43 3,619.47 4,098.46 -11,994.48275.56 539,900.1496,019,109.9673,552.17 0.000 12,192.54 15,200.00 93.43 3,613.48 4,108.14 -12,093.83275.56 539,800.7446,019,118.9523,546.18 0.000 12,292.26 15,256.18 93.43 3,610.11 4,113.58 -12,149.64275.56 539,744.8986,019,124.0003,542.81 0.000 12,348.28 Start Dir 3º/100' : 15256.18' MD, 3610.11'TVD 15,300.00 92.50 3,607.84 4,117.47 -12,193.23274.64 539,701.2896,019,127.5893,540.54 3.000 12,392.01 15,400.00 90.35 3,605.36 4,123.74 -12,292.99272.55 539,601.4976,019,133.1603,538.06 3.000 12,491.96 15,410.29 90.13 3,605.32 4,124.18 -12,303.27272.33 539,591.2146,019,133.5263,538.02 3.000 12,502.25 End Dir : 15410.29' MD, 3605.32' TVD 15,500.00 90.13 3,605.12 4,127.82 -12,392.91272.33 539,501.5646,019,136.5503,537.82 0.000 12,591.96 15,600.00 90.13 3,604.89 4,131.89 -12,492.83272.33 539,401.6316,019,139.9203,537.59 0.000 12,691.95 15,700.00 90.13 3,604.67 4,135.96 -12,592.74272.33 539,301.6986,019,143.2913,537.37 0.000 12,791.94 15,800.00 90.13 3,604.45 4,140.03 -12,692.66272.33 539,201.7646,019,146.6623,537.15 0.000 12,891.94 15,900.00 90.13 3,604.22 4,144.09 -12,792.58272.33 539,101.8316,019,150.0323,536.92 0.000 12,991.93 16,000.00 90.13 3,604.00 4,148.16 -12,892.49272.33 539,001.8986,019,153.4033,536.70 0.000 13,091.92 16,100.00 90.13 3,603.77 4,152.23 -12,992.41272.33 538,901.9656,019,156.7733,536.47 0.000 13,191.92 16,195.73 90.13 3,603.56 4,156.12 -13,088.06272.33 538,806.2996,019,160.0003,536.26 0.000 13,287.64 Start Dir 3º/100' : 16195.73' MD, 3603.56'TVD 16,200.00 90.16 3,603.55 4,156.29 -13,092.33272.21 538,802.0316,019,160.1393,536.25 3.001 13,291.91 16,292.42 90.84 3,602.74 4,157.68 -13,184.72269.52 538,709.6366,019,160.8873,535.44 3.000 13,384.25 End Dir : 16292.42' MD, 3602.74' TVD 16,300.00 90.84 3,602.63 4,157.62 -13,192.30269.52 538,702.0586,019,160.7703,535.33 0.001 13,391.82 16,400.00 90.84 3,601.17 4,156.78 -13,292.29269.52 538,602.0916,019,159.2333,533.87 0.000 13,491.62 10/12/2020 4:00:55PM COMPASS 5000.15 Build 91E Page 8 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU J-30i MPU J-30i Survey Calculation Method:Minimum Curvature MPU J-30 As-staked RKB @ 67.30usft Design:MPU J-30i wp06 Database:NORTH US + CANADA MD Reference:MPU J-30 As-staked RKB @ 67.30usft North Reference: Well Plan: MPU J-30i True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,532.41 Vert Section 16,500.00 90.84 3,599.71 4,155.94 -13,392.28269.52 538,502.1236,019,157.6953,532.41 0.000 13,591.43 16,600.00 90.84 3,598.25 4,155.10 -13,492.26269.52 538,402.1556,019,156.1583,530.95 0.000 13,691.23 16,700.00 90.84 3,596.79 4,154.25 -13,592.25269.52 538,302.1876,019,154.6213,529.49 0.000 13,791.04 16,800.00 90.84 3,595.32 4,153.41 -13,692.23269.52 538,202.2196,019,153.0833,528.02 0.000 13,890.84 16,900.00 90.84 3,593.86 4,152.57 -13,792.22269.52 538,102.2526,019,151.5463,526.56 0.000 13,990.65 17,000.00 90.84 3,592.40 4,151.73 -13,892.20269.52 538,002.2846,019,150.0093,525.10 0.000 14,090.45 17,065.60 90.84 3,591.44 4,151.18 -13,957.80269.52 537,936.7006,019,149.0003,524.14 0.000 14,155.93 17,100.00 90.84 3,590.94 4,150.89 -13,992.19269.52 537,902.3166,019,148.4713,523.64 0.000 14,190.25 17,115.60 90.84 3,590.71 4,150.76 -14,007.79269.52 537,886.7216,019,148.2313,523.41 0.000 14,205.82 Start Dir 3º/100' : 17115.6' MD, 3590.71'TVD 17,200.00 88.38 3,591.28 4,150.50 -14,092.18270.13 537,802.3426,019,147.3853,523.98 3.000 14,290.09 17,300.00 85.47 3,596.65 4,151.36 -14,192.02270.86 537,702.5076,019,147.5503,529.35 3.000 14,389.84 17,340.60 84.29 3,600.27 4,152.07 -14,232.46271.16 537,662.0716,019,147.9793,532.97 3.000 14,430.25 17,400.00 86.07 3,605.26 4,153.27 -14,291.63271.16 537,602.9006,019,148.7613,537.96 3.000 14,489.40 17,500.00 89.07 3,609.50 4,155.28 -14,391.50271.16 537,503.0196,019,150.0793,542.20 3.000 14,589.25 17,600.00 92.07 3,608.50 4,157.30 -14,491.47271.16 537,403.0546,019,151.3993,541.20 3.000 14,689.18 17,700.00 95.07 3,602.28 4,159.31 -14,591.24271.16 537,303.2786,019,152.7173,534.98 3.000 14,788.93 17,800.00 98.07 3,590.83 4,161.32 -14,690.55271.16 537,203.9656,019,154.0283,523.53 3.000 14,888.21 17,900.00 101.07 3,574.21 4,163.30 -14,789.13271.16 537,105.3866,019,155.3303,506.91 3.000 14,986.75 17,910.60 101.39 3,572.15 4,163.51 -14,799.53271.16 537,094.9866,019,155.4673,504.85 3.000 14,997.15 18,000.00 98.78 3,556.49 4,165.79 -14,887.51271.81 537,007.0056,019,157.1313,489.19 3.000 15,085.12 18,100.00 95.87 3,543.74 4,169.54 -14,986.61272.52 536,907.8906,019,160.1893,476.44 3.000 15,184.28 18,200.00 92.95 3,536.04 4,174.55 -15,086.17273.23 536,808.3016,019,164.5033,468.74 3.000 15,283.98 18,279.15 90.65 3,533.56 4,179.40 -15,165.13273.79 536,729.3206,019,168.8013,466.26 3.000 15,363.08 End Dir : 18279.15' MD, 3533.56' TVD 18,300.00 90.65 3,533.32 4,180.78 -15,185.93273.79 536,708.5106,019,170.0353,466.02 0.001 15,383.93 18,400.00 90.65 3,532.19 4,187.39 -15,285.71273.79 536,608.7016,019,175.9543,464.89 0.000 15,483.91 18,500.00 90.65 3,531.06 4,194.01 -15,385.48273.79 536,508.8936,019,181.8733,463.76 0.000 15,583.89 18,600.00 90.65 3,529.93 4,200.62 -15,485.26273.79 536,409.0846,019,187.7933,462.63 0.000 15,683.88 18,700.00 90.65 3,528.80 4,207.24 -15,585.03273.79 536,309.2756,019,193.7123,461.50 0.000 15,783.86 18,800.00 90.65 3,527.68 4,213.85 -15,684.81273.79 536,209.4676,019,199.6313,460.38 0.000 15,883.85 18,900.00 90.65 3,526.55 4,220.47 -15,784.58273.79 536,109.6586,019,205.5503,459.25 0.000 15,983.83 19,000.00 90.65 3,525.42 4,227.08 -15,884.35273.79 536,009.8506,019,211.4693,458.12 0.000 16,083.81 19,100.00 90.65 3,524.29 4,233.70 -15,984.13273.79 535,910.0416,019,217.3893,456.99 0.000 16,183.80 19,200.00 90.65 3,523.16 4,240.31 -16,083.90273.79 535,810.2336,019,223.3083,455.86 0.000 16,283.78 19,300.00 90.65 3,522.03 4,246.93 -16,183.68273.79 535,710.4246,019,229.2273,454.73 0.000 16,383.77 19,400.00 90.65 3,520.90 4,253.54 -16,283.45273.79 535,610.6156,019,235.1463,453.60 0.000 16,483.75 19,500.00 90.65 3,519.77 4,260.16 -16,383.23273.79 535,510.8076,019,241.0663,452.47 0.000 16,583.73 19,600.00 90.65 3,518.64 4,266.77 -16,483.00273.79 535,410.9986,019,246.9853,451.34 0.000 16,683.72 19,700.00 90.65 3,517.51 4,273.39 -16,582.78273.79 535,311.1906,019,252.9043,450.21 0.000 16,783.70 19,802.99 90.65 3,516.35 4,280.20 -16,685.53273.79 535,208.4006,019,259.0003,449.05 0.000 16,886.67 Total Depth : 19802.99' MD, 3516.35' TVD 10/12/2020 4:00:55PM COMPASS 5000.15 Build 91E Page 9 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU J-30i MPU J-30i Survey Calculation Method:Minimum Curvature MPU J-30 As-staked RKB @ 67.30usft Design:MPU J-30i wp06 Database:NORTH US + CANADA MD Reference:MPU J-30 As-staked RKB @ 67.30usft North Reference: Well Plan: MPU J-30i True Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Tar gets Dip Angle (°) Dip Dir. (°) MPU J-30 wp04 tgt 4 3,739.73 6,019,089.000 543,224.7604,054.33 -8,669.770.00 0.00 -plan hits target center - Point MPU J-30 wp05 tgt 11 3,516.35 6,019,259.000 535,208.4004,280.20 -16,685.530.00 0.00 -plan hits target center - Point MPU J-30 wp05 tgt 10 3,591.44 6,019,149.000 537,936.7004,151.18 -13,957.800.00 0.00 -plan hits target center - Point MPU J-30 wp04 tgt 5 3,705.32 6,019,112.230 542,260.8304,084.28 -9,633.610.00 0.00 -plan hits target center - Point MPU J-30 wp05 tgt 7 3,652.49 6,019,065.780 540,507.1604,050.04 -11,387.730.00 0.00 -plan hits target center - Point MPU J-30 wp05 tgt 8 3,610.11 6,019,124.000 539,744.9004,113.58 -12,149.640.00 0.00 -plan hits target center - Point MPU J-30 wp04 tgt 2 3,792.82 6,019,170.300 545,024.8304,123.09 -6,869.010.00 0.00 -plan hits target center - Point MPU J-30 wp04 tgt 1 3,815.99 6,019,263.210 545,582.3504,212.12 -6,310.800.00 0.00 -plan hits target center - Circle (radius 30.00) MPU J-30 wp04 tgt 3 3,759.94 6,019,112.230 544,002.8804,072.14 -7,891.430.00 0.00 -plan hits target center - Point MPU J-30 wp04 tgt 6 3,674.33 6,019,077.390 541,343.3404,055.83 -10,551.410.00 0.00 -plan hits target center - Point MPU J-30 wp05 tgt 9 3,603.56 6,019,160.000 538,806.3004,156.12 -13,088.060.00 0.00 -plan hits target center - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 9 5/8" x 12 1/4"3,815.999,392.85 9-5/8 12-1/4 4 1/2" x 8 1/2"3,516.3519,802.99 4-1/2 8-1/2 10/12/2020 4:00:55PM COMPASS 5000.15 Build 91E Page 10 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU J-30i MPU J-30i Survey Calculation Method:Minimum Curvature MPU J-30 As-staked RKB @ 67.30usft Design:MPU J-30i wp06 Database:NORTH US + CANADA MD Reference:MPU J-30 As-staked RKB @ 67.30usft North Reference: Well Plan: MPU J-30i True Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 9,376.33 3,814.55 SCHRADER NB 7,398.10 3,374.40 UGNU LA3 9,126.18 3,789.91 SCHRADER NA 1,476.94 1,401.88 SV5 5,019.33 2,704.25 UG3 8,021.62 3,550.06 UGNU MB 2,553.03 2,009.44 BPRF 6,174.90 3,029.80 UG COAL 1 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 300.00 300.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 700.00 697.08 41.58 3.64 Start Dir 4º/100' : 700' MD, 697.08'TVD 2,521.15 2,000.46 897.70 -686.08 End Dir : 2521.15' MD, 2000.46' TVD 8,167.22 3,591.08 3,946.20 -5,164.32 Start Dir 3.5º/100' : 8167.22' MD, 3591.08'TVD 9,292.85 3,807.27 4,219.48 -6,211.45 End Dir : 9292.85' MD, 3807.27' TVD 9,392.85 3,815.99 4,212.12 -6,310.80 Start Dir 3.1º/100' : 9392.85' MD, 3815.99'TVD 9,936.47 3,796.66 4,128.71 -6,845.65 End Dir : 9936.47' MD, 3796.66' TVD 9,960.79 3,792.82 4,123.09 -6,869.00 Start Dir 3º/100' : 9960.79' MD, 3792.82'TVD 10,567.83 3,751.00 4,060.67 -7,468.80 End Dir : 10567.83' MD, 3751' TVD 10,990.71 3,759.94 4,072.14 -7,891.43 Start Dir 3º/100' : 10990.71' MD, 3759.94'TVD 11,135.29 3,759.24 4,072.07 -8,035.98 End Dir : 11135.29' MD, 3759.24' TVD 11,769.64 3,739.73 4,054.33 -8,669.78 Start Dir 3º/100' : 11769.64' MD, 3739.73'TVD 11,890.29 3,735.70 4,054.75 -8,790.34 End Dir : 11890.29' MD, 3735.7' TVD 12,734.63 3,705.32 4,084.28 -9,633.62 Start Dir 3º/100' : 12734.63' MD, 3705.32'TVD 12,870.73 3,700.59 4,084.19 -9,769.60 End Dir : 12870.73' MD, 3700.59' TVD 13,653.49 3,674.33 4,055.83 -10,551.41 Start Dir 3º/100' : 13653.49' MD, 3674.33'TVD 13,713.44 3,672.55 4,054.57 -10,611.32 End Dir : 13713.44' MD, 3672.55' TVD 14,490.13 3,652.49 4,050.04 -11,387.74 Start Dir 3º/100' : 14490.13' MD, 3652.49'TVD 14,697.07 3,643.61 4,059.46 -11,594.17 End Dir : 14697.07' MD, 3643.61' TVD 15,256.18 3,610.11 4,113.58 -12,149.64 Start Dir 3º/100' : 15256.18' MD, 3610.11'TVD 15,410.29 3,605.32 4,124.18 -12,303.27 End Dir : 15410.29' MD, 3605.32' TVD 16,195.73 3,603.56 4,156.12 -13,088.06 Start Dir 3º/100' : 16195.73' MD, 3603.56'TVD 16,292.42 3,602.74 4,157.68 -13,184.72 End Dir : 16292.42' MD, 3602.74' TVD 17,115.60 3,590.71 4,150.76 -14,007.79 Start Dir 3º/100' : 17115.6' MD, 3590.71'TVD 18,279.15 3,533.56 4,179.40 -15,165.13 End Dir : 18279.15' MD, 3533.56' TVD 19,802.99 3,516.35 4,280.20 -16,685.53 Total Depth : 19802.99' MD, 3516.35' TVD 10/12/2020 4:00:55PM COMPASS 5000.15 Build 91E Page 11 12 October, 2020Milne PointM Pt J PadPlan: MPU J-30iMPU J-30iMPU J-30i wp06Reference Design: M Pt J Pad - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Well Coordinates: 6,015,095.57 N, 551,921.73 E (70° 27' 07.14" N, 149° 34' 34.87" W)Datum Height: MPU J-30 As-staked RKB @ 67.30usftScan Range: 33.70 to 9,392.85 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-30i - MPU J-30i wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.70 to 9,392.85 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt J Pad - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPU I-39i - MPU I-39i - MPU I-39i842.34 6,451.25 772.87 13,812.35 12.1266,451.25Centre Distance Pass - MPU I-39i - MPU I-39i - MPU I-39i844.19 6,508.70 771.09 13,826.04 11.5486,508.70Ellipse Separation Pass - MPU I-39i - MPU I-39i - MPU I-39i987.94 6,983.70 882.18 13,953.30 9.3416,983.70Clearance Factor Pass - Plan: MPU I-26 - MPU I-26 - MPU I-26 wp06788.14 7,306.81 711.96 14,987.08 10.3457,306.81Centre Distance Pass - Plan: MPU I-26 - MPU I-26 - MPU I-26 wp06789.75 7,358.70 710.20 14,999.39 9.9277,358.70Ellipse Separation Pass - Plan: MPU I-26 - MPU I-26 - MPU I-26 wp06914.22 7,783.70 804.90 15,100.17 8.3637,783.70Clearance Factor Pass - Plan: MPU I-33 - MPU I-33 - MPU I-33 wp05724.74 7,374.66 647.16 15,266.09 9.3427,374.66Centre Distance Pass - Plan: MPU I-33 - MPU I-33 - MPU I-33 wp05726.97 7,433.70 645.13 15,281.96 8.8837,433.70Ellipse Separation Pass - Plan: MPU I-33 - MPU I-33 - MPU I-33 wp05848.97 7,833.70 735.59 15,389.47 7.4887,833.70Clearance Factor Pass - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11551.28 7,378.32 472.29 15,837.44 6.9797,378.32Centre Distance Pass - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11553.84 7,433.70 469.81 15,852.86 6.5917,433.70Ellipse Separation Pass - Plan: MPU I-40 - MPU I-40 - MPU I-40 wp11636.08 7,708.70 524.16 15,929.44 5.6837,708.70Clearance Factor Pass - M Pt J PadMPJ-01 - MPJ-01 - MPJ-0143.99 33.70 41.93 36.60 21.27633.70Centre Distance Pass - MPJ-01 - MPJ-01 - MPJ-0144.09 308.70 40.91 311.58 13.881308.70Ellipse Separation Pass - MPJ-01 - MPJ-01 - MPJ-0152.18 483.70 47.70 486.28 11.632483.70Clearance Factor Pass - MPJ-01 - MPJ-01A - MPJ-01A43.99 33.70 41.93 32.05 21.27633.70Centre Distance Pass - MPJ-01 - MPJ-01A - MPJ-01A44.09 308.70 40.91 307.03 13.881308.70Ellipse Separation Pass - MPJ-01 - MPJ-01A - MPJ-01A52.18 483.70 47.70 481.73 11.632483.70Clearance Factor Pass - MPJ-01 - MPJ-01AL1 - MPJ-01AL143.99 33.70 41.93 32.05 21.27633.70Centre Distance Pass - MPJ-01 - MPJ-01AL1 - MPJ-01AL144.09 308.70 40.91 307.03 13.881308.70Ellipse Separation Pass - MPJ-01 - MPJ-01AL1 - MPJ-01AL152.18 483.70 47.70 481.73 11.632483.70Clearance Factor Pass - MPJ-02 - MPJ-02 - MPJ-02104.42 33.70 102.85 36.59 66.44533.70Centre Distance Pass - MPJ-02 - MPJ-02 - MPJ-02105.26 308.70 102.18 311.45 34.121308.70Ellipse Separation Pass - MPJ-02 - MPJ-02 - MPJ-02154.35 758.70 147.48 757.65 22.466758.70Clearance Factor Pass - MPJ-03 - MPJ-03 - MPJ-03164.25 33.70 162.83 36.59 116.05233.70Centre Distance Pass - MPJ-03 - MPJ-03 - MPJ-03165.05 308.70 161.97 310.68 53.558308.70Ellipse Separation Pass - 12 October, 2020-16:03COMPASSPage 2 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-30i - MPU J-30i wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.70 to 9,392.85 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt J Pad - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-03 - MPJ-03 - MPJ-03213.22 683.70 207.25 664.69 35.719683.70Clearance Factor Pass - MPJ-04 - MPJ-04 - MPJ-04224.37 284.22 221.39 287.14 75.363284.22Centre Distance Pass - MPJ-04 - MPJ-04 - MPJ-04224.39 308.70 221.23 311.56 71.035308.70Ellipse Separation Pass - MPJ-04 - MPJ-04 - MPJ-04309.48 833.70 302.13 800.88 42.092833.70Clearance Factor Pass - MPJ-08 - MPJ-08 - MPJ-08133.75 108.70 132.03 106.60 77.488108.70Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08133.94 308.70 131.15 306.46 48.092308.70Ellipse Separation Pass - MPJ-08 - MPJ-08 - MPJ-08179.07 733.70 173.64 728.68 33.001733.70Clearance Factor Pass - MPJ-08 - MPJ-08A - MPJ-08A133.75 108.70 132.03 107.40 77.488108.70Centre Distance Pass - MPJ-08 - MPJ-08A - MPJ-08A133.94 308.70 131.15 307.26 48.092308.70Ellipse Separation Pass - MPJ-08 - MPJ-08A - MPJ-08A1,069.01 7,158.70 894.06 8,495.00 6.1107,158.70Clearance Factor Pass - MPJ-10 - MPJ-10 - MPJ-10193.56 310.69 190.75 309.35 68.929310.69Centre Distance Pass - MPJ-10 - MPJ-10 - MPJ-10193.68 333.70 190.73 332.41 65.808333.70Ellipse Separation Pass - MPJ-10 - MPJ-10 - MPJ-10473.51 1,558.70 460.16 1,587.89 35.4681,558.70Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-1174.00 33.70 72.59 31.60 52.35833.70Centre Distance Pass - MPJ-11 - MPJ-11 - MPJ-1174.10 108.70 72.56 106.33 48.224108.70Ellipse Separation Pass - MPJ-11 - MPJ-11 - MPJ-1192.45 558.70 89.09 555.18 27.516558.70Clearance Factor Pass - MPJ-15 - MPJ-15 - MPJ-1543.39 2,211.78 27.67 2,452.42 2.7602,211.78Ellipse Separation Pass - MPJ-15 - MPJ-15 - MPJ-1583.81 2,358.70 42.91 2,581.17 2.0492,358.70Clearance Factor Pass - MPJ-23 - MPJ-23 - MPJ-2314.32 33.70 12.47 28.70 7.74633.70Centre Distance Pass - MPJ-23 - MPJ-23 - MPJ-2314.89 333.70 12.20 328.81 5.534333.70Ellipse Separation Pass - MPJ-23 - MPJ-23 - MPJ-2316.06 383.70 13.08 378.79 5.376383.70Clearance Factor Pass - MPJ-23 - MPJ-23A - MPJ-23A14.32 33.70 12.47 36.20 7.74633.70Centre Distance Pass - MPJ-23 - MPJ-23A - MPJ-23A14.89 333.70 12.20 336.31 5.534333.70Ellipse Separation Pass - MPJ-23 - MPJ-23A - MPJ-23A16.06 383.70 13.08 386.29 5.376383.70Clearance Factor Pass - MPJ-23 - MPJ-23L1 - MPJ-23L114.32 33.70 12.47 28.70 7.74633.70Centre Distance Pass - MPJ-23 - MPJ-23L1 - MPJ-23L114.89 333.70 12.20 328.81 5.534333.70Ellipse Separation Pass - MPJ-23 - MPJ-23L1 - MPJ-23L116.06 383.70 13.08 378.79 5.376383.70Clearance Factor Pass - MPJ-24 - MPJ-24A - MPJ-24A15.17 422.77 11.98 417.15 4.756422.77Centre Distance Pass - MPJ-24 - MPJ-24A - MPJ-24A15.20 433.70 11.95 427.98 4.669433.70Ellipse Separation Pass - MPJ-24 - MPJ-24A - MPJ-24A1,351.74 6,158.70 1,026.16 5,916.96 4.1526,158.70Clearance Factor Pass - 12 October, 2020-16:03COMPASSPage 3 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-30i - MPU J-30i wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.70 to 9,392.85 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt J Pad - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-24 - MPJ-24L1 - MPJ-24L115.17 422.77 11.98 420.86 4.755422.77Centre Distance Pass - MPJ-24 - MPJ-24L1 - MPJ-24L115.20 433.70 11.95 431.69 4.669433.70Ellipse Separation Pass - MPJ-24 - MPJ-24L1 - MPJ-24L11,351.74 6,158.70 1,031.44 5,920.67 4.2206,158.70Clearance Factor Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB115.17 422.77 11.98 420.86 4.755422.77Centre Distance Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB115.20 433.70 11.95 431.69 4.669433.70Ellipse Separation Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB11,351.74 6,158.70 1,031.02 5,920.67 4.2156,158.70Clearance Factor Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB215.17 422.77 11.98 420.86 4.755422.77Centre Distance Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB215.20 433.70 11.95 431.69 4.669433.70Ellipse Separation Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB21,351.74 6,158.70 1,031.45 5,920.67 4.2206,158.70Clearance Factor Pass - MPJ-24 - MPU J-24 - MPJ-2415.17 422.77 11.98 420.86 4.755422.77Centre Distance Pass - MPJ-24 - MPU J-24 - MPJ-2415.20 433.70 11.95 431.69 4.669433.70Ellipse Separation Pass - MPJ-24 - MPU J-24 - MPJ-241,351.74 6,158.70 1,031.45 5,920.67 4.2206,158.70Clearance Factor Pass - MPJ-25 - MPJ-25 - MPJ-2521.57 838.82 13.50 835.24 2.673838.82Ellipse Separation Pass - MPJ-25 - MPJ-25 - MPJ-2521.86 858.70 13.65 854.73 2.663858.70Clearance Factor Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB121.57 838.82 13.50 835.24 2.673838.82Ellipse Separation Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB121.86 858.70 13.65 854.73 2.663858.70Clearance Factor Pass - Plan: MPU J-29 - MPU J-29 - MPU J-29 wp0630.36 283.70 27.77 283.10 11.750283.70Centre Distance Pass - Plan: MPU J-29 - MPU J-29 - MPU J-29 wp0630.37 308.70 27.68 308.10 11.278308.70Ellipse Separation Pass - Plan: MPU J-29 - MPU J-29 - MPU J-29 wp06591.25 7,958.70 310.33 8,002.10 2.1057,958.70Clearance Factor Pass - M Pt L PadMPU L-62 - MPU L-62 - MPU L-621,028.54 9,392.85 863.50 13,520.00 6.2329,392.85Clearance Factor Pass - M Pt M PadM Pt Moose PadMPU M-13 - MPU M-13i - MPU M-13914.11 9,392.85 681.08 16,300.00 3.9239,392.85Clearance Factor Pass - MPU M-14 - MPU M-14 - MPU M-14386.299,183.70111.0517,123.531.4039,183.70Clearance FactorPass - MPU M-14 - MPU M-14 - MPU M-14270.219,392.8581.7416,960.761.4349,392.85Ellipse SeparationPass - MPU M-15i - MPU M-15 - MPU M-15i1,034.21 9,392.85 590.39 16,895.95 2.3309,392.85Clearance Factor Pass - 12 October, 2020-16:03COMPASSPage 4 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-30i - MPU J-30i wp06Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.70 1,000.00 MPU J-30i wp06 3_Gyro-GC_Csg1,000.00 9,392.85 MPU J-30i wp06 3_MWD+IFR2+MS+Sag9,392.85 19,802.99 MPU J-30i wp06 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.12 October, 2020-16:03COMPASSPage 5 of 7 0.001.002.003.004.00Separation Factor0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Measured Depth (1000 usft/in)MPJ-15MPU J-29 wp06MPU M-14No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU J-30i NAD 1927 (NADCON CONUS)Alaska Zone 0433.60+N/-S +E/-W Northing Easting Latittude Longitude0.000.006015095.570551921.73070° 27' 7.141 N149° 34' 34.869 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-30i, True NorthVertical (TVD) Reference:MPU J-30 As-staked RKB @ 67.30usftMeasured Depth Reference:MPU J-30 As-staked RKB @ 67.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-10-08T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1000.00 MPU J-30i wp06 (MPU J-30i) 3_Gyro-GC_Csg1000.00 9392.85 MPU J-30i wp06 (MPU J-30i) 3_MWD+IFR2+MS+Sag9392.85 19802.99 MPU J-30i wp06 (MPU J-30i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Measured Depth (1000 usft/in)MPJ-01MPJ-02MPJ-03MPJ-08MPJ-11MPJ-15MPJ-23MPJ-24MPJ-25MPU J-29 wp06NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 19802.99Project: Milne PointSite: M Pt J PadWell: Plan: MPU J-30iWellbore: MPU J-30iPlan: MPU J-30i wp06Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3815.99 3748.69 9392.85 9-5/8 9 5/8" x 12 1/4"3516.35 3449.05 19802.99 4-1/2 4 1/2" x 8 1/2" 12 October, 2020Milne PointM Pt J PadPlan: MPU J-30iMPU J-30iMPU J-30i wp06Reference Design: M Pt J Pad - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Well Coordinates: 6,015,095.57 N, 551,921.73 E (70° 27' 07.14" N, 149° 34' 34.87" W)Datum Height: MPU J-30 As-staked RKB @ 67.30usftScan Range: 9,392.85 to 19,802.99 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-30i - MPU J-30i wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 9,392.85 to 19,802.99 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt J Pad - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadM Pt J PadMPJ-24 - MPJ-24A - MPJ-24A1,111.97 13,542.85 612.67 12,622.45 2.22713,542.85Clearance Factor Pass - MPJ-24 - MPJ-24A - MPJ-24A1,107.24 13,617.85 611.16 12,679.77 2.23213,617.85Ellipse Separation Pass - MPJ-24 - MPJ-24A - MPJ-24A1,103.95 13,733.42 612.93 12,768.94 2.24813,733.42Centre Distance Pass - MPJ-24 - MPJ-24L1 - MPJ-24L11,020.10 12,892.85 466.58 12,115.00 1.84312,892.85Clearance Factor Pass - MPJ-24 - MPJ-24L1 - MPJ-24L11,010.20 13,034.62 507.41 12,115.00 2.00913,034.62Centre Distance Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB11,056.70 11,467.85 494.44 10,867.00 1.87911,467.85Clearance Factor Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB11,038.30 11,542.85 490.30 10,867.00 1.89511,542.85Ellipse Separation Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB11,014.82 11,762.39 538.71 10,867.00 2.13111,762.39Centre Distance Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB2989.04 11,717.85 429.64 11,115.00 1.76811,717.85Clearance Factor Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB2975.90 11,767.85 426.11 11,115.00 1.77511,767.85Ellipse Separation Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB2956.56 11,940.74 462.15 11,115.00 1.93511,940.74Centre Distance Pass - Plan: MPU J-29 - MPU J-29 - MPU J-29 wp06622.34 14,067.85 252.60 13,807.91 1.68314,067.85Clearance Factor Pass - Plan: MPU J-29 - MPU J-29 - MPU J-29 wp06619.99 14,117.85 252.43 13,849.31 1.68714,117.85Ellipse Separation Pass - Plan: MPU J-29 - MPU J-29 - MPU J-29 wp06618.15 14,214.33 258.07 13,922.21 1.71714,214.33Centre Distance Pass - M Pt L PadMPU L-51 - MPU L-51 - MPU L-511,438.63 13,567.85 1,205.52 13,874.00 6.17113,567.85Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-511,437.39 13,617.85 1,204.66 13,874.00 6.17613,617.85Ellipse Separation Pass - MPU L-51 - MPU L-51 - MPU L-511,437.35 13,628.61 1,204.71 13,874.00 6.17813,628.61Centre Distance Pass - MPU L-59i - MPU L-59i - MPU L-59i1,338.10 12,118.23 1,140.95 13,599.00 6.78712,118.23Centre Distance Pass - MPU L-59i - MPU L-59i - MPU L-59i1,338.33 12,142.85 1,140.77 13,599.00 6.77412,142.85Ellipse Separation Pass - MPU L-59i - MPU L-59i - MPU L-59i1,499.33 12,792.85 1,259.65 13,599.00 6.25512,792.85Clearance Factor Pass - MPU L-60 - MPU L-60 - MPU L-601,129.25 11,259.01 940.97 13,150.00 5.99811,259.01Centre Distance Pass - MPU L-60 - MPU L-60 - MPU L-601,129.28 11,267.85 940.91 13,150.00 5.99511,267.85Ellipse Separation Pass - MPU L-60 - MPU L-60 - MPU L-601,325.86 11,967.85 1,086.93 13,150.00 5.54911,967.85Clearance Factor Pass - MPU L-60 - MPU L-60PB3 - MPU L-60PB31,159.27 11,302.64 971.09 13,130.00 6.16111,302.64Centre Distance Pass - 12 October, 2020-16:05COMPASSPage 2 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-30i - MPU J-30i wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 9,392.85 to 19,802.99 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt J Pad - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU L-60 - MPU L-60PB3 - MPU L-60PB31,159.37 11,317.85 970.92 13,130.00 6.15211,317.85Ellipse Separation Pass - MPU L-60 - MPU L-60PB3 - MPU L-60PB31,340.30 11,992.85 1,106.12 13,130.00 5.72311,992.85Clearance Factor Pass - MPU L-61i - MPU L-61i - MPU L-61i1,175.83 10,572.03 993.85 14,100.00 6.46110,572.03Centre Distance Pass - MPU L-61i - MPU L-61i - MPU L-61i1,179.73 10,667.85 991.66 14,100.00 6.27310,667.85Ellipse Separation Pass - MPU L-61i - MPU L-61i - MPU L-61i1,323.73 11,167.85 1,084.77 14,100.00 5.54011,167.85Clearance Factor Pass - MPU L-61i - MPU L-61PB2 - MPU L-61PB21,158.65 10,597.78 976.55 14,120.00 6.36310,597.78Centre Distance Pass - MPU L-61i - MPU L-61PB2 - MPU L-61PB21,162.55 10,692.85 974.34 14,120.00 6.17710,692.85Ellipse Separation Pass - MPU L-61i - MPU L-61PB2 - MPU L-61PB21,309.38 11,192.85 1,069.07 14,120.00 5.44911,192.85Clearance Factor Pass - MPU L-62 - MPU L-62 - MPU L-62962.26 9,709.87 785.15 13,520.00 5.4339,709.87Centre Distance Pass - MPU L-62 - MPU L-62 - MPU L-62963.00 9,742.85 784.58 13,520.00 5.3979,742.85Ellipse Separation Pass - MPU L-62 - MPU L-62 - MPU L-621,215.44 10,467.85 971.56 13,520.00 4.98410,467.85Clearance Factor Pass - M Pt M PadM Pt Moose PadMPU M-13 - MPU M-13i - MPU M-13906.58 9,493.19 629.44 16,300.00 3.2719,493.19Centre Distance Pass - MPU M-13 - MPU M-13i - MPU M-13943.66 9,717.85 573.78 16,300.00 2.5519,717.85Ellipse Separation Pass - MPU M-13 - MPU M-13i - MPU M-131,006.12 9,867.85 594.45 16,300.00 2.4449,867.85Clearance Factor Pass - MPU M-14 - MPU M-14 - MPU M-14270.219,392.8581.7416,960.761.4349,392.85Clearance FactorPass - MPU M-14 - MPU M-14 - MPU M-14210.12 9,517.85 74.54 16,868.10 1.5509,517.85Ellipse Separation Pass - MPU M-14 - MPU M-14 - MPU M-14170.82 9,689.77 80.61 16,737.10 1.8949,689.77Centre Distance Pass - MPU M-15i - MPU M-15 - MPU M-15i538.26 10,142.85 183.54 16,327.63 1.51710,142.85Clearance Factor Pass - MPU M-15i - MPU M-15 - MPU M-15i197.64 11,020.38 117.39 15,618.97 2.46311,020.38Centre Distance Pass - MPU M-15i - MPU M-15 - MPU M-15i197.68 11,017.85 117.33 15,624.31 2.46011,017.85Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16450.0211,642.85132.4015,225.181.41711,642.85Clearance FactorPass - MPU M-16 - MPU M-16 - MPU M-16300.48 11,942.85 111.51 14,987.86 1.59011,942.85Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16194.70 12,380.28 115.72 14,616.26 2.46512,380.28Centre Distance Pass - MPU M-17i - MPU M-17i - MPU M-17i336.2213,492.8581.4513,969.721.32013,492.85Clearance FactorPass - MPU M-17i - MPU M-17i - MPU M-17i136.17 14,016.63 58.30 13,546.39 1.74914,016.63Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18380.5214,717.85103.5813,342.411.37414,717.85Clearance FactorPass - 12 October, 2020-16:05COMPASSPage 3 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-30i - MPU J-30i wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 9,392.85 to 19,802.99 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt J Pad - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU M-18 - MPU M-18 - MPU M-18217.37 15,142.85 88.64 12,952.29 1.68915,142.85Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18168.62 15,410.31 93.12 12,730.31 2.23415,410.31Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB11,351.86 17,375.76 1,023.30 10,361.00 4.11517,375.76Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB11,362.93 17,542.85 1,011.05 10,361.00 3.87317,542.85Ellipse Separation Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB11,404.38 17,742.85 1,032.65 10,361.00 3.77817,742.85Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2539.33 16,208.21 258.73 11,767.00 1.92216,208.21Centre Distance Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2559.73 16,342.85 229.97 11,767.00 1.69716,342.85Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2575.85 16,392.85 232.44 11,767.00 1.67716,392.85Clearance Factor Pass - MPU M-19i - MPU M-19i - MPU M-19i170.04 16,867.85 83.60 11,827.39 1.96716,867.85Ellipse Separation Pass - MPU M-19i - MPU M-19i - MPU M-19i168.15 16,909.33 83.96 11,794.77 1.99716,909.33Centre Distance Pass - MPU M-19i - MPU M-19i - MPU M-19i359.9417,492.85104.6311,311.891.41017,492.85Clearance FactorPass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1170.04 16,867.85 83.38 11,827.39 1.96216,867.85Ellipse Separation Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1168.15 16,909.33 83.74 11,794.77 1.99216,909.33Centre Distance Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1359.9417,492.85104.4011,311.891.40917,492.85Clearance FactorPass - MPU M-20 - MPU M-20 - MPU M-20658.39 19,802.99 469.06 13,697.28 3.47819,802.99Clearance Factor Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1842.47 19,802.99 587.37 13,188.00 3.30219,802.99Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2658.39 19,802.99 468.94 13,697.28 3.47519,802.99Clearance Factor Pass - MPU M-21i - MPU M-21i - MPU M-21i1,451.49 19,802.99 1,245.66 12,965.44 7.05219,802.99Clearance Factor Pass - MPU M-34 - MPU M-34 - MPU M-34450.04 15,442.85 223.68 12,145.12 1.98815,442.85Clearance Factor Pass - MPU M-34 - MPU M-34 - MPU M-34240.64 15,917.85 162.14 11,847.87 3.06515,917.85Ellipse Separation Pass - MPU M-34 - MPU M-34 - MPU M-34239.99 15,941.44 162.20 11,832.45 3.08515,941.44Centre Distance Pass - MPU M-35i - MPU M-35i - MPU M-35i421.11 14,342.85 181.43 12,916.73 1.75714,342.85Clearance Factor Pass - MPU M-35i - MPU M-35i - MPU M-35i257.13 14,642.85 143.77 12,731.93 2.26814,642.85Ellipse Separation Pass - MPU M-35i - MPU M-35i - MPU M-35i227.15 14,814.65 149.46 12,608.34 2.92414,814.65Centre Distance Pass - MPU M-43 - MPU M-43 - MPU M-4371.8717,392.85-95.9914,896.410.42817,392.85Ellipse SeparationFAIL - MPU M-43 - MPU M-43 - MPU M-4321.3117,462.60-71.8114,906.270.22917,462.60Clearance FactorFAIL - MPU M-43 - MPU M-43PB2 - MPU M-43PB222.3017,523.42-62.8214,901.570.26217,523.42Clearance FactorFAIL - MPU M-43 - MPU M-43PB2 - MPU M-43PB249.8617,567.85-75.3714,904.290.39817,567.85Ellipse SeparationFAIL - MPU M-43 - MPU M-43PB3 - MPU M-43PB336.6417,492.85-118.7414,899.830.23617,492.85Ellipse SeparationFAIL - MPU M-43 - MPU M-43PB3 - MPU M-43PB37.5017,528.81-76.7314,900.740.08917,528.81Clearance FactorFAIL - 12 October, 2020-16:05COMPASSPage 4 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-30i - MPU J-30i wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 9,392.85 to 19,802.99 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt J Pad - Plan: MPU J-30i - MPU J-30i - MPU J-30i wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU M-44i - MPU M-44i - MPU M-44i1,202.57 18,435.56 877.83 13,194.00 3.70318,435.56Centre Distance Pass - MPU M-44i - MPU M-44i - MPU M-44i1,205.38 18,517.85 874.24 13,194.00 3.64018,517.85Ellipse Separation Pass - MPU M-44i - MPU M-44i - MPU M-44i1,229.79 18,692.85 886.95 13,194.00 3.58718,692.85Clearance Factor Pass - MPU M-45 - MPU M-45 - MPU M-451,121.68 19,352.36 789.64 12,192.00 3.37819,352.36Centre Distance Pass - MPU M-45 - MPU M-45 - MPU M-451,125.33 19,442.85 785.55 12,192.00 3.31219,442.85Ellipse Separation Pass - MPU M-45 - MPU M-45 - MPU M-451,152.68 19,617.85 798.78 12,192.00 3.25719,617.85Clearance Factor Pass - Plan: MPU M-46 - MPU M-46 - MPU M-46 wp02666.51 19,802.99 453.49 13,357.56 3.12919,802.99Clearance Factor Pass - Plan: MPU M-47 (MPU M-21i P2 - Slot 30) - M-21i Pha1,402.26 19,802.99 1,182.28 12,681.69 6.37419,802.99Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.70 1,000.00 MPU J-30i wp06 3_Gyro-GC_Csg1,000.00 9,392.85 MPU J-30i wp06 3_MWD+IFR2+MS+Sag9,392.85 19,802.99 MPU J-30i wp06 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.12 October, 2020-16:05COMPASSPage 5 of 7 0.001.002.003.004.00Separation Factor9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950 16500 17050 17600 18150 18700 19250 19800Measured Depth (1100 usft/in)MPJ-24AMPJ-24L1MPJ-24L1PB2MPU J-29 wp06MPU M-14MPU M-15iMPU M-16MPU M-17iMPU M-18PB1MPU M-18PB2MPU M-19iMPU M-20PB1MPU M-35iMPU M-43MPU M-44iMPU M-45No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU J-30i NAD 1927 (NADCON CONUS)Alaska Zone 0433.60+N/-S +E/-W Northing Easting Latittude Longitude0.000.006015095.570 551921.730 70° 27' 7.141 N 149° 34' 34.869 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-30i, True NorthVertical (TVD) Reference:MPU J-30 As-staked RKB @ 67.30usftMeasured Depth Reference:MPU J-30 As-staked RKB @ 67.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-10-08T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1000.00 MPU J-30i wp06 (MPU J-30i) 3_Gyro-GC_Csg1000.00 9392.85 MPU J-30i wp06 (MPU J-30i) 3_MWD+IFR2+MS+Sag9392.85 19802.99 MPU J-30i wp06 (MPU J-30i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950 16500 17050 17600 18150 18700 19250 19800Measured Depth (1100 usft/in)MPU M-43MPU M-43PB2MPU M-43PB3NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 19802.99Project: Milne PointSite: M Pt J PadWell: Plan: MPU J-30iWellbore: MPU J-30iPlan: MPU J-30i wp06Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3815.99 3748.69 9392.85 9-5/8 9 5/8" x 12 1/4"3516.35 3449.05 19802.99 4-1/2 4 1/2" x 8 1/2" Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements 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 (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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