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Home My WebLink About220-056MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, July 18, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC L-61 MILNE PT UNIT L-61 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/18/2025 L-61 50-029-23683-00-00 220-056-0 W SPT 3979 2200560 1500 401 402 400 401 10 205 198 193 4YRTST P Kam StJohn 4/27/2025 4 Year 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 L-61 Inspection Date: Tubing OA Packer Depth 310 1780 1723 1711IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS250427111720 BBL Pumped:1.2 BBL Returned:1.2 Friday, July 18, 2025 Page 1 of 1 9 9 9 9 9 99 999 99 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.07.18 11:20:00 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Operable: MPL-61 (PTD# 2200560) - Return to Injection Date:Tuesday, April 15, 2025 9:36:00 AM From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Tuesday, April 15, 2025 9:27 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: Operable: MPL-61 (PTD# 2200560) - Return to Injection Mr. Wallace, Source water injection well MPL-61 (PTD# 2200560) will be returned to injection and is now classified as Operable. An AOGCC witnessed MIT-IA will be performed once the well is on stable injection. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Friday, September 27, 2024 2:08 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; jim.regg <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: NOT OPERABLE: MPL-61 (PTD# 2200560) - Shut in for AOGCC MIT-IA Mr. Wallace – Source water injection well MPL-61 (PTD# 2200560) is currently shut in and will not be brought online for its scheduled 4 year MIT-IA due this month. The well is now classified as NOT OPERABLE and will remain shut in. A witnessed MIT-IA will be scheduled once the well is returned to injection. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 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 deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: NOT OPERABLE: MPL-61 (PTD# 2200560) - Shut in for AOGCC MIT-IA Date:Monday, September 30, 2024 9:33:44 AM From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Friday, September 27, 2024 2:08 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: NOT OPERABLE: MPL-61 (PTD# 2200560) - Shut in for AOGCC MIT-IA Mr. Wallace – Source water injection well MPL-61 (PTD# 2200560) is currently shut in and will not be brought online for its scheduled 4 year MIT-IA due this month. The well is now classified as NOT OPERABLE and will remain shut in. A witnessed MIT-IA will be scheduled once the well is returned to injection. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified 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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23683-00-00Well Name/No. MILNE PT UNIT L-61Completion Status1WINJCompletion Date8/19/2020Permit to Drill2200560OperatorHilcorp Alaska, LLCMD14100TVD3861Current Status1WINJ10/15/2020UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, ABG, DGR, EWR, ADR MD & TVD for PB1&PB2NoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF10/5/2020 Electronic File: MPU L-61 Customer Survey.xlsx34044EDDigital DataDF10/5/2020 Electronic File: MPU L-61 Geosteering End of Well Report.pdf34044EDDigital DataDF10/5/2020 Electronic File: MPU L-61 Geosteering log.emf34044EDDigital DataDF10/5/2020 Electronic File: MPU L-61 Geosteering log.pdf34044EDDigital DataDF10/5/2020 Electronic File: MPU L-61 Geosteering log.tif34044EDDigital DataDF10/5/2020 Electronic File: MPU L-61 Post-Well Geosteering X-Section Summary.pdf34044EDDigital Data0 0 2200560 MILNE PT UNIT L-61 LOG HEADERS34044LogLog Header Scans0 0 2200560 MILNE PT UNIT L-61 LOG HEADERS34049LogLog Header ScansDF10/5/2020112 14100 Electronic Data Set, Filename: MPU L-61 LWD Final.las34049EDDigital DataDF10/5/20207758 14062 Electronic Data Set, Filename: MPU L-61 ADR Quadrants All Curves.las34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61 LWD Final MD.cgm34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61 LWD Final TVD.cgm34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61 final surveys.xlsx34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61i_Definitive Survey Report.pdf34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61i_DSR.txt34049EDDigital DataThursday, October 15, 2020AOGCCPage 1 of 4PB1PB2MPU L-61 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23683-00-00Well Name/No. MILNE PT UNIT L-61Completion Status1WINJCompletion Date8/19/2020Permit to Drill2200560OperatorHilcorp Alaska, LLCMD14100TVD3861Current Status1WINJ10/15/2020UICYesDF10/5/2020 Electronic File: MPU L-61i_GIS.txt34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61 LWD Final MD.emf34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61 LWD Final TVD.emf34049EDDigital DataDF10/5/2020 Electronic File: MPU_L-61_Geosteering.dlis34049EDDigital DataDF10/5/2020 Electronic File: MPU_L-61_Geosteering.ver34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61 LWD Final MD.pdf34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61 LWD Final TVD.pdf34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61 LWD Final MD.tif34049EDDigital DataDF10/5/2020 Electronic File: MPU L-61 LWD Final TVD.tif34049EDDigital DataDF10/5/2020112 13010 Electronic Data Set, Filename: MPU L-61PB1 LWD Final.las34050EDDigital DataDF10/5/20207758 12972 Electronic Data Set, Filename: MPU L-61PB1 ADR Quadrants All Curves.las34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1 LWD Final MD.cgm34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1 LWD Final TVD.cgm34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1_Definitive Survey Report.pdf34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1_DSR.txt34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1_GIS.txt34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1 LWD Final MD.emf34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1 LWD Final TVD.emf34050EDDigital DataDF10/5/2020 Electronic File: MPU_L-61PB1_Geosteering.dlis34050EDDigital DataDF10/5/2020 Electronic File: MPU_L-61PB1_Geosteering.ver34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1 LWD Final MD.pdf34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1 LWD Final TVD.pdf34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1 LWD Final MD.tif34050EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB1 LWD Final TVD.tif34050EDDigital DataThursday, October 15, 2020AOGCCPage 2 of 4MPU L-61PB1LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23683-00-00Well Name/No. MILNE PT UNIT L-61Completion Status1WINJCompletion Date8/19/2020Permit to Drill2200560OperatorHilcorp Alaska, LLCMD14100TVD3861Current Status1WINJ10/15/2020UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVED0 0 2200560 MILNE PT UNIT L-61 PB1 LOG HEADERS34050LogLog Header ScansDF10/5/2020112 14120 Electronic Data Set, Filename: MPU L-61PB2 LWD Final.las34051EDDigital DataDF10/5/20207758 14082 Electronic Data Set, Filename: MPU L-61PB2 ADR Quadrants All Curves.las34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2 LWD Final MD.cgm34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2 LWD Final TVD.cgm34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2_Definitive Survey Report.pdf34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2_DSR.txt34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2_GIS.txt34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2 LWD Final MD.emf34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2 LWD Final TVD.emf34051EDDigital DataDF10/5/2020 Electronic File: MPU_L-61PB2_Geosteering.dlis34051EDDigital DataDF10/5/2020 Electronic File: MPU_L-61PB2_Geosteering.ver34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2 LWD Final MD.pdf34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2 LWD Final TVD.pdf34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2 LWD Final MD.tif34051EDDigital DataDF10/5/2020 Electronic File: MPU L-61PB2 LWD Final TVD.tif34051EDDigital Data0 0 2200560 MILNE PT UNIT L-61 PB2 LOG HEADERS34051LogLog Header ScansThursday, October 15, 2020AOGCCPage 3 of 4MPU L-61PB2LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23683-00-00Well Name/No. MILNE PT UNIT L-61Completion Status1WINJCompletion Date8/19/2020Permit to Drill2200560OperatorHilcorp Alaska, LLCMD14100TVD3861Current Status1WINJ10/15/2020UICYesCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud 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:8/19/2020Release Date:7/7/2020Thursday, October 15, 2020AOGCCPage 4 of 4M. Guhl10/15/2020 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 10/05/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-61, MPU L-61PB1, MPU L-61PB2 (PTD 220-056) FINAL LWD LOGS (16AUG2020): EWR-M5, AGR, ABG, DGR, ADR, HORIZONTAL PRESENTATION (MD/TVD) AND DEFINITIVE DIRECTIONAL SURVEY Final CD Main Folders: Subfolders: Received by the AOGCC 10/05/2020 PTD: 2200560 E-Set: 34049 Abby Bell 10/06/2020 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 10/05/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-61 (PTD 220-056) FINAL GEOSTEERING LOGS, EOW REPORTS (14AUG2020): Final GEOSTEERING CD: PTD: 2200560 E-Set: 34044 Received by the AOGCC 10/05/2020 Abby Bell 10/06/2020 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 10/05/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-61, MPU L-61PB1, MPU L-61PB2 (PTD 220-056) FINAL LWD LOGS (16AUG2020): EWR-M5, AGR, ABG, DGR, ADR, HORIZONTAL PRESENTATION (MD/TVD) AND DEFINITIVE DIRECTIONAL SURVEY Final CD Main Folders: Subfolders: PTD: 2200560 E-Set: 34050 Received by the AOGCC 10/05/2020 Abby Bell 10/06/2020 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 10/05/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-61, MPU L-61PB1, MPU L-61PB2 (PTD 220-056) FINAL LWD LOGS (16AUG2020): EWR-M5, AGR, ABG, DGR, ADR, HORIZONTAL PRESENTATION (MD/TVD) AND DEFINITIVE DIRECTIONAL SURVEY Final CD Main Folders: Subfolders: PTD: 2200560 E-Set: 34051 Received by 10/05/2020 Abby Bell 10/06/2020 MEMORANDUM TO: Jim Regg P.I. Supervisor FROM: Jeff Jones Petroleum Inspector Well Name MILNE PT UNIT L-61 Insp Num: mitJJ200911111756 Rel Insp Num: NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, September 11, 2020 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC L-61 MILNE PT UNIT L-61 Src: Inspector Reviewed By: P.I. Supry 'i 7Z— Comm API Well Number 50-029-23683-00-00 Inspector Name: Jeff Jones - Permit Number: 220-056-0 Inspection Date: 9/7/2020 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well L-61;Type Inj W TVD ! 3979 Tubing 377 1 378 377 377 — BBL Pumped: - Testi SPT Test psi 1500 IA 272 1706 1652 1642 PTD i zzoos6o I Type p 1.2I 1.3 Returned: 1.3 OA o 0 0 0 Interval INITAL PIF P Notes' 1 well inspected, no exceptions noted. Friday, September 11, 2020 Page 1 of 1 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name:6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address:7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section):8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:9. Ref Elevations: KB: 17. Field / Pool(s): GL: 15.70' BF: Total Depth:10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27):11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone-4 TPI:x- y- Zone-4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth:x- y- Zone-4 5. Directional or Inclination Survey: Yes (attached) No 13.Water Depth, if Offshore: 21.Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: BOTTOM 20" A-53 114' L-80 2078' L-80 3980' 7" L-80 3980' 4-1/2"L-80 3861' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production:Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate 9-5/8"12-1/4" ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, Uncemented TiebackTieback TUBING RECORD Uncemented Screen Liner 7584'3-1/2" 9.3# L-80 SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 7574'14100' Stg 2 L-588sx/T-270sx, 270sx 3980' 42" 13.5# Surface 2274'Stg 1 L - 855 sx / T - 400 sx 8-1/2" ±270 ft3 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 8/19/2020 3674' FSL, 5063' FEL, Sec. 08, T13N, R10E, UM, AK 2636' FNL, 260' FEL, Sec. 19, T13N, R10E, UM, AK 220-056 Milne Point Field, Schrader Pluff Oil Pool 49.57' 14100' / 3861' HOLE SIZE AMOUNT PULLED 15.70' 50-029-23683-00-00 MPU L-61 544814 6031863 1410' FNL, 1088' FWL, Sec. 17, T13N, R10E, UM, AK CEMENTING RECORD 6026785 SETTING DEPTH TVD 6020272 BOTTOM TOP Surface Surface CASING WT. PER FT.GRADE 26# 545734 544448 TOP SETTING DEPTH MD Surface Surface Per 20 AAC 25.283 (i)(2) attach electronic information 40# 7588' 2078' Surface DEPTH SET (MD) 7556' / 3979' PACKER SET (MD/TVD) 216# 47# 114' 2274'7754' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST N/A Date of Test: Flow Tubing Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A 4-1/2" Screen Liner 8/16/2020 ***Please see attached Schematic for detail*** ROP, AGR, ABG, DGR, EWR, ADR MD & TVD PB1: ROP, AGR, ABG, DGR, EWR, ADR MD & TVD PB2: ROP, AGR, ABG, DGR, EWR, ADR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl:Water-Bbl: 8/13/2020 7/16/2020 ADL 025515 & 025509 88-002 2314' / 2099' N/AN/A None 14100' / 3861' G s d 1 0 p d P l L (att Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 9:45 am, Sep 08, 2020 RBDMS HEW 9/8/2020 Completion Date 8/19/2020 HEW SFD MGR10SEP2020 G SFD 9/9/2020 Bluff DSR-10/14/2020 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 18' 18' 2332' 2117' Top of Productive Interval 1510' 1452' 2390' 2155' 5865' 3473' 7309' 3952' 7479' 3974' SB NB 7479'3974' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Joe Lastufka Contact Email:joseph.lastufka@hilcorp.com Authorized Contact Phone: 777-8400 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Schrader Bluff NB Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered):FORMATION TESTS Permafrost - Top Schrader Bluff NA SV5 SV1 This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: Ugnu LA3 Plugback Summary, LOT / FIT Data Sheet, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report, Wellbore Schematic Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. N Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 9.8.2020Digitally 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: 2020.09.08 09:12:04 -08'00' Monty M Myers 6%1% PB1 TD 13010' MD / 3864' TVD KOP 11570' MD / 3868' TVD Date 8/1/2020 PB2 TD 14120' MD / 3858' TVD KOP 10750' MD / 3891' TVD Date 8/2/2020 MPU L-61 OH Sidetrack Summary PTD: 220-056 / API: 50-029-23683-70-00 PTD: 220-056 / API: 50-029-23683-71-00 CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU L-61 Date:7/28/2020 Csg Size/Wt/Grade:9.625"40# x 47#, L-80 Supervisor:Yessak/Vanderpool Csg Setting Depth:7770 TMD 3979 TVD Mud Weight:9.3 ppg LOT / FIT Press =570 psi LOT / FIT =12.05 ppg Hole Depth =7798 md Fluid Pumped=1.3 Bbls Volume Back =1.3 bbls Estimated Pump Output:0.101 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->00 ->00 ->261 ->550 ->4 147 ->10 160 ->6 228 ->15 360 ->8 326 ->20 600 ->10 421 ->25 810 ->12 516 ->30 940 ->13 570 ->32 1050 ->14 -> ->18 -> ->20 -> ->22 -> ->24 -> ->26 -> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 570 ->0 1020 ->1 562 ->5 1010 ->2 560 ->10 1005 ->3 556 ->15 1000 ->4 552 ->20 1000 ->5 550 ->25 1000 ->6 547 ->30 1000 ->7 546 -> ->8 545 -> ->9 543 -> ->10 541 -> ->11 540 -> ->12 539 -> ->13 538 -> ->14 ->15 ->16 0 2 4 6 8 10 12 13 0 5 10 15 20 25 30 32 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 10203040Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 570562560556552550547546545543541540539538 1020 1010 1005 1000 1000 1000 1000 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA Activity Date Ops Summary 7/15/2020 Completing MPU L-59, see L-59 completions report for details Rig released from L-59 at 18:00;R/D circulation lines, clean pit #3, blow down rig floor water & steam, cut 90' mousehole from cellar and weld cover, prepare to skid rig floor and prepare to move rock washer *** Notified AOGCC of upcoming diverter test at 18:23 on 15 July ***;Skid rig floor into moving position. Move rock washer.;Move rig off MPU L-59. Remove matting board off L-59. Move to upright brine tanks to provide room for rig move.;Move rig from east side of the pad to west side.;Utilize Milne roads & pads crane to: Spot tubing spool and injection tree behind L-61. Remove riser from diverter. Install surface annular on speed head.;Spot rig on L-61. Limited area on pad required more maneuvering to center rig on well. Shim rig level.;Skid rig floor into moving position. Hang stand of drill pipe in elevators to ensure rig was level and centered over well.;Install all landings and handrails, ready beaverslide, P/U 22" surface riser. Hook up air, steam, water & high pressure mud lines to the rig floor. Spot cuttings tank, fuel trailer, rock washer & all service buildings. Work on rig acceptance checklist. 7/16/2020 N/U surface annular and diverter system. Power up koomey, Spot water pump house and upright, Spot cuttings tank, fuel trailer, rock washer & all service buildings. Set cmt silos, C/O saver sub, inspect grabber dies, ready pits for mud. Work on rig acceptance checklist. Rig on High line power @ 11:30;PJSM, .Slip and cut 93' drilling, re calibrate block height, C/O shaker screens, Totco calibrate PVT system. Off load 580 bbls 8.8 spud mud to pits. Secure cellar. Load BHA and 17 joints HWDP along w/ jars into the shed. Work on rig acceptance checklist. Accept Rig @ 14:00;PJSM, P/U and rack 5 stands 5'' HWDP and jar stand in derrick;Load 5'' drill pipe into pipe shed, Install 3 x 12 timbers in cellar, Rig electrician test rig gas alarms. NOV Tech installing new PVT sensor in pit 1, Latch stand 5'' HW, RIH and Tag @ 56';Perform diverter function test on 5" drill pipe. AOGCC inspector Austin McLeod waived witness of test at 15:38. Knife valve open 23 sec & annular close 43 sec. 3000 PSI system pressure, 1925 PSI after closing, 200 PSI recovery in 37 sec, full recovery in 152 sec. 6 nitrogen bottle avg 2080 PSI.;PJSM. M/U 12-1/4" Kymera bit, 8" mud motor, XO and stand of HWDP. RIH to 56'.;Pre-spud meeting with all parties. Brief overview of well. Identify hazards and review safe briefing/muster areas. Discuss well control and rig evacuation procedures.;Fill lines & diverter stack with water - no leaks. Pressure test mud lines to 3500 PSI - good. Clean out conductor f/ 56' t/ 114' w/ 450 GPM, 470 PSI, 40 RPM, 1K TQ, 1-2K WOB. Observe sand and pea gravel, swap to mud at 105'. Flow line packed off at 114' (base of conductor at 114');Clear flow line & circulate hole clean. Stage pumps up f/ 300 t/ 450 GPM. Rotate & reciprocate to clean up 19-1/4" I.D. conductor w/ 12-1/4" bit. Hole unloaded sand & gravel.;Drill 12-1/4" surface hole f/ 114' t/ 219' (219' TVD), 105' drilled, 105'/hr AROP. 400-420 GPM, 550-600 PSI, 40 RPM, 1-2K TQ, 1-2K WOB. 50K PU / 50K SO / 50K ROT.;BROOH f/ 219' t/ 126', flow check static. POOH f/ 126' & inspect bit - good. PJSM for BHA. P/U MWD DM collar - bad threads. L/D & P/U backup DM collar. Continue to M/U MWD tools & UBHO sub to 88'.;Initialize MWD tools. R/U gyro while plugged into MWD. Perform MWD offset. 3.05/8.11*360=135.39°) & UBHO orientation. Continue to P/U three NMDC f/ 88' t/ 175'. M/U stand of HWDP & pulse test MWD. Wash down f/ 175' t/ 219'.;Drill 12-1/4" surface hole f/ 219' t/ 435' (434' TVD) 216' drilled, 61.71'/hr AROP. 500 GPM, 1070 PSI, 60 RPM, 2K TQ, 3-5K WOB. MW 9.15 in / 9.2 out, vis 300+ in / 300+ out, 9.38 ECD. 65K PU / 68K SO / 68K ROT. Take 1st gyro survey: 352' MD/TVD, 0.49° inc, 40.37° azm, 1.04' from plan.;Daily losses = 0 bbls, Cumulative losses = 0 bbls H2O from L-Pad: 605 bbls Daily/ 605 bbls Total H2O from G&I Source Water: 0 bbls Daily/ 0 bbls Total Cuttings/mud/cement to MPU G&I: 57 bbls Daily / 57 bbls Total 50-029-23683-00-00API #: Well Name: Field: County/State: MP L-61 Milne Point Hilcorp Energy Company Composite Report , Alaska 7/16/2020Spud Date: 7/17/2020 Drill 12-1/4" surface hole f/ 435' t/ 697' (696' TVD) 262' drilled, 74.8'/hr AROP. 437 GPM, 1150 PSI, 60 RPM, 1-2K TQ, 10-20K WOB. MW 9 ppg in /9.1 out, vis 291 in / 300 out, 9.9 ECD. 74K PU / 76K SO / 76K ROT. Gyro survey every stand drilled, kickoff, build 3 deg/100';#2 draig chain jumped sprocket. Found large rock wedged in drag chain, remove same;Drill 12-1/4" surface hole f/ 697' t/ 829' (826' TVD) 132' drilled, 66'/hr AROP. 476 GPM, 1100 PSI, 60 RPM, 1-2K TQ, 8-20K WOB. MW 9.1 in / out, vis 210 in / 200 out, 9.9 ECD. 80K PU / 82K SO / 82K ROT. Build 3 deg/100';Continue with gyro surveys ea. stand drilled;Drill 12-1/4" surface hole f/ 829' t/ 1493' (1438' TVD) 664' drilled, 110.67'/hr AROP. 475 GPM, 1350 PSI, 60 PRM, 2-6K TQ, 5-20K WOB. MW 9.1 in / 9.2 out, vis 231 in / 233 out, 10.1 ECD, 18u max gas 91K PU / 87K SO / 90K ROT. Build 3°/100' to 905', then 4 °/100' build & turn;Continue with gyro surveys ea. stand drilled, first clean MWD survey @ 885', next 2 at 979' and 1074'- clean, R/D and release Gyro @ 1150';Service rig and inspect top drive.;Drill 12-1/4" surface hole f/ 1493' t/ 2065' (1921' TVD) 572' drilled, 104'/hr AROP. 440 GPM, 1230 PSI, 60 RPM, 3K TQ, 3K WOB. MW in 9.35 / out 9.4, vis in 185 / out 300, ECD 10.36, max gas 40u. 106K PU / 90K SO / 96K ROT.;Drill 12-1/4" surface hole f/ 2065' t/ 2798' MD (2386' TVD) 733' drilled, 122.17'/hr AROP. 495 GPM, 1470 PSI, 60 RPM, 4K TQ, 5-7K WOB. MW in 9.3 / 9.4 out, vis in 97 / out 170, ECD 10.00, max gas 98u. 112K PU / 90K SO / 102K ROT. 30 bbl high vis sweep @ 2636', did not see at shakers.;Base of permafrost at 2101' MD / 1950' TVD. Last survey at 2692.21' MD / 2333.75' TVD, 58.38° inc, 163.93° azm, 7.07' from plan, 4.99' high and 5.01' right.;Daily losses = 0 bbls, Cumulative losses = 0 bbls H2O from L-Pad: 1,330 bbls Daily/ 1,935 bbls Total H2O from G&I Source Water: 0 bbls Daily/ 0 bbls Total Cuttings/mud/cement to MPU G&I: 1,383 bbls Daily / 1,440 bbls Total 7/18/2020 Drill 12-1/4" surface hole f/ 2798' t/ 3587' MD (2672' TVD) 789' drilled, 131.5'/hr AROP. 550 GPM, 1820 PSI, 80 RPM, 7K TQ, 5K WOB. MW in 9.3 / 9.4 out, vis in 76 / out 106, ECD 9.9, max gas 77u. 115K PU / 85K SO / 100K ROT.;Build and turn 4 deg/100' to EOB @ 3073', hold 69.61 deg tangent. UG4 top logged at 2890' md. Pump 30 bbl hi vis sweep @ 3107', back 300 stks late, 20% increase;Drill 12-1/4" surface hole f/ 3587' t/ 4445' MD (2973' TVD) 858' drilled, 143'/hr AROP. 550 GPM, 2240 PSI, 80 RPM, 12K TQ, 12-14K WOB. MW in 9.3 / out 9.3. vis in 121 / out 101, ECD 10.31. max gas 78u. 134K PU / 136K SO / 101K ROT. Hold 69.61 deg tangent;4061' pump 30 bbl hi vis sweep, didn't see it come back, strung out. UG3 top logged at 3993' MD. UG Coal 2 logged at 4301'. UG Coal 1 top logged at 4835' MD.;Drill 12-1/4" surface hole f/ 4445' t/ 5145' (3228' TVD) 700' drilled, 116.67'/hr AROP. 545 GPM, 2150 PSI, 80 RPM, 13K TQ, 10-25K WOB. MW in 9.25 / out 9.3, vis in 159 / out 154, ECD 10.33, max gas 111u. PU 150K / SO 87K / ROT 110K Pump 30 bbl hi vis sweep at 5018', did not see it come back.;Drill 12-1/4" surface hole f/ 5145' t/ 5874' (3473' TVD) 729' drilled, 121.5'/hr AROP. 540 GPM, 2170 PSI, 80 RPM, 13-14K TQ, 3-25K WOB. MW in 9.3 / out 9.2, vis in 118 / out 110, ECD 10.52, max gas 65u. PU 160K / SO 85K / ROT 115K;Last survey at 5740.19' MD / 3215.94' TVD, 70.79° inc, 178.02' azm, 8.39' from plan, 2.33' high and 8.06' left.;Daily losses = 0 bbls, Cumulative losses = 0 bbls H2O from L-Pad: 1,810 bbls Daily/ 3,745 bbls Total H2O from G&I Source Water: 0 bbls Daily/ 0 bbls Total Cuttings/mud/cement to MPU G&I: 1,725 bbls Daily / 3,165 bbls Total 7/19/2020 Drill 12-1/4" surface hole f/ 5874' t/ 6565' (3719' TVD) 691' drilled, 115.17'/hr AROP. 549 GPM, 2300 PSI, 80 RPM, 16K TQ, 12K WOB. MW in 9.3 / out 9.4, vis in 115 / out 250, ECD 10.5, max gas 271u. PU 181K / SO 84K / ROT 119K Hold 69.61 deg tangent;At 6000'- pre treat mud w/.5% screen-kleen, shortly after start seeing oil at shakers, screens blinding off, slow to 420 gpm, 1700 psi, recover 70 bbls mud from rock washer back across shakers, increase back to 540 gpm Pump 30 bbl hi vis sweep @ 6059', back 1000 stks late, 25% increase.;Drill 12-1/4" surface hole f/ 6565' t/ 7110' (3909' TVD) 545' drilled, 90.83'/hr AROP. 560 GPM, 2310 PSI, 80 RPM, 17-20K TQ, 10-20K WOB. MW in 9.4 / out 9.4, vis in 180 / out 190, ECD 10.62, max gas 87u. 205K PU / 78K SO / 123K ROT. 30 bbl hi vis sweep @ 7013' not seen at surface.;Hold 69.61 deg tangent 6938', start build and turn 4 deg/100' Top MB sand logged at 6640' md, 3745' tvd. At 6700' Increase screen kleen content to 1% to keep shakers from blinding off Fault A @ 7086' MD/3900' TVD, ~30' DTN throw.;Drill 12-1/4" surface hole f/ 7110' t/ 7431' (3973' TVD) 310' drilled, 53.5'/hr AROP. 550 GPM, 2490 PSI, 80 RPM, 15-25K TQ, 15-30K WOB. MW in 9.3 / out 9.35, vis in 130 / out 204, ECD 10.45, max gas 103u. 198K PU / 69K SO / 119K ROT. SB NA @ 7307' MD / 3951' TVD.;Drill 12-1/4" surface hole f/ 7431' t/ 7748' (3983' TVD) 317' drilled, 52.83'/hr AROP. 570 GPM, 2430 PSI, 80 RPM, 18-22K TQ, 8-25K WOB. MW in 9.3 / out 9.25, vis in 87 / out 105, ECD 10.63, max gas 128u. 195K PU / 73K SO / 117K ROT. SB NB @ 7481' MD / 3975' TVD.;Last survey at 7645.23' MD / 3981.53' TVD, 88.69° inc, 188.73° azm, 13.29' from plan, 0.16' low and 13.29' left.;Daily losses = 0 bbls, Cumulative losses = 0 bbls. H2O from L-Pad: 1,805 bbls Daily/ 5,550 bbls Total H2O from G&I Source Water: 0 bbls Daily/ 0 bbls Total Cuttings/mud/cement to MPU G&I: 1707 bbls Daily / 4,872 bbls Total 7/20/2020 Drill 12-1/4" surface hole f/ 7748' t/ 7778' at TD (3979' TVD) Landed out @ 92.5 deg in th NB Sand 561 GPM, 2210 PSI, 80 RPM, 18K TQ, 12K WOB. MW in 9.2+ / out 9.3, vis in 69 / out 110, ECD 10.1, max gas 26u. 195K PU / 75K SO / 116K ROT.;Take final survey= 6.76' below the line, 15.88' left. Pump Hi-Vis sweep w/ nut plug marker & circulate hole clean while BROOH f/ 7778' t/ 7580'. 550 GPM, 2100 PSI, 80 RPM, 18K Tq, Total of 2x BU circ. until clean. Sweep back on time with no increase. Final YP: 25;Orient hi side, RIH on elevators f/ 7580' to TD, PJSM for BROOH, flow check the well, static;BROOH f/ 7778' t/ 6828' at 5-10 min. stand, 550 GPM, 2160 PSI, 80 RPM, 18K TQ, no issues with unloading or packing off at this point.;BROOH f/ 6828' t/ 735' at 5-10 min. stand, 550 GPM, 2160 PSI, 80 RPM, 18K TQ, slow down as needed for any packing off or tight areas. Pulled slowly 2257’ to 2066’ below the permafrost for a bottoms up, no unloading observed. Slowed rotary to 60 RPM in the permafrost.;Increased the viscosity to 90-100 to help clean/stabilize the permafrost. Hole unloaded at 1413', slow to 380 GPM, hole cleaned up in 1400 strokes. Circulated 3x bottoms up while pulling f/ 831' t/ 735', no unloading observed. 10 bbls losses while BROOH.;Performed 5 min. flow check - static. POOH on elevators racking back HWDP & jars f/ 735' t/ 177'. L/D XO, 3 NMDC & UBHO to 85'. Read MWD tools. L/D BHA from 85'. Bit grade: 2-2-BT-N-I-WT-TD Clear rig floor. 4 bbls losses.;Mobilize casing equipment to the rig floor. Begin rigging up casing equipment. 3.5 BPH losses.;Daily (midnight) losses = 10 bbls, Cumulative losses = 10 bbls H2O from L-Pad: 1,410 bbls Daily/ 6,960 bbls Total H2O from G&I Source Water: 0 bbls Daily/ 0 bbls Total Cuttings/mud/cement to MPU G&I: 1,445 bbls Daily / 6,317 bbls Total 7/21/2020 Clear rig floor and mobilize casing equipment to the rig floor. R/U 9-5/8" Volant CRT, spiders, bail extensions and elevators. PJSM for running casing. Monitor well-Static loss rate 4 bph;PJSM, M/U and baker loc jt 9-5/8" shoe track, round nose float shoe, install top hat after M/U FC joint. Ensure proper float operation - good. M/U baffle adapter & joint #4 to 160'.;Torque all connections to 21,000 ft/lbs w/ Volant tool, Two 9-5/8" x 12-1/4" centralizer & 4 stop rings on shoe joint, 1 free floating centralizer on Baker-Loc joint, 1 centrailizer w/ 2 stop rings on the float collar and baffle adapter joints.;Run 9-5/8" 40# L-80 TXP-BTC casing f/ 160' t/ 1993' @ jt 50. Torque to 21,000 ft/lbs with the Volant tool. Install 9-5/8" x 12-1/4" bow spring centralizers on jts #5-26 then every other joint to 48, then 1 every 3rd jt, Fill casing on the fly & top off every 10 joints. 6-8 BPH loss rate;Continue to run 9-5/8" 40# L-80 TXP-BTC casing f/ 1993' t/ 2593'. Tq to 21,000 ft/lbs. Install 1 centralizer on every 3rd jt, Fill on the fly & top off every 10 jts. 9-11 BPH loss rate;CBU, stage pump from 3 bpm, 190 psi to 5 bpm, 190 psi, circulate out thick mud. clean at BU. 11 bbl losses circulating.;Continue to run 9-5/8" 40# L-80 TXP-BTC casing f/ 2630' t/ 5417'. Tq to 21,000 ft/lbs. Install 1 centralizer on every 3rd jt t/ #132 then every jt t/ #136, Fill on the fly & top off every 10 jts. Loss rate slowing to 4 bph 255k PU / 99k SO;CBU, stage pump from 3 bpm, 270 psi to 5 bpm, 303 psi, circulate out thick mud. clean at BU. 14 bbl losses circulating. 203k PU / 101k SO;Run jt #157, 9-5/8" 40# L-80 TXP-BTC casing f/ 5417' t/ 5457'. M/U ESC tool w/ pup above and below to 5495', verify 6 pins set @ 3300 psi. BakerLoc top & btm connections.;Run 9-5/8" 47# L-80 TXP-BTC casing f/ 5495' t/ 7754 TQ to 24,000 ft/lbs with the Volant tool. M/U 20' pup, wash to depth @ 7770' Install 1 centralizer every jt 138-146 and every other jt 148-190. Fill casing on the fly & top off every 10 joints 123 bbl losses running casing PU 310k, SO 90k;C/O Volant cup, stage pump f/ 2 bpm, 470 psi, to 6 bpm, 340 psi. Start rotary w/ torque limit set at 20K, 5 RPM when reciprocating. Reciprocate 30', cementers rigging up. Condition mud for cement job. **Sent 24hr notification to AOGCC for upcoming BOPE test**;Daily (midnight) losses = 143 bbls, Cumulative losses = 153 H2O from L-Pad: 375 bbls Daily/ 7,335 bbls Total H2O from G&I Source Water: 390 bbls Daily/ 390 bbls Total Cuttings/mud/cement to MPU G&I: 518 bbls Daily / 6,835 bbls Total 7/22/2020 Cementers finished rigging up and filled cement water tank w/ 80°. PJSM. Blow down top drive & R/U cement lines. Pre-treat mud in pit #4. Hold PJSM for cement job. Pump 50 bbls of pre-treated mud, 5 BPM, 180 PSI. 9 bbls losses while circulating. P/U 310K, S/O 90K;HES Pump 5 bbls water. PT lines to 820 psi / 4030 psi, good. Mix and pump 60 bbl 10 ppg tuned spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 4 BPM, 160 psi. Drop Bypass bottom plug. Mix & Pump 358 bbl 12 ppg ExtendaCem Lead cmt (855 sx,), 5 BPM, 350 psi.;Mix & Pump 82 bbl 15.8 ppg Premium G tail cement (400 sx ) 4 BPM, 320 psi. Drop shutoff plug. Chase with 20 bbl fresh water. Rig displace with 376 bbl 9.4 ppg spud mud at 6 BPM, 470 psi. Seen polyflake at surface 361 bbls into displacing. HES pump 80 bbl 9.4 ppg tuned spacer, 4 BPM, 460 psi.;Displace 100.7 BBLS w/ rig at 6 bpm, 750 psi 9.4 mud. Park w/ string in tension @ 7770', at 4260 stks, good spacer @ surface. Slow to 3 bpm on last 20 bbls, lift pressure 670 psi, FCP 760 psi. Bump plug @ 4720 strokes. 27 stks over calc.;Pressure 500 psi over FCP @ 1290 psi, hold 5 min. Good. Bleed down, check floats- 2 bbls bled back, good. CIP @ 12:05;Pressure to 3100 psi shifting ESC open, Circulate hole clean through ES cementer at 2296'. 5 bpm, 730 psi, 2000 stks away, very thick mud returns, Slow to 1.5 bpm, 190 psi, dump to rock washer, increase to 6 bpm, 760 psi;Total contaminated mud, interface and trace cement dumped to rock washer 320 bbls, then take clean mud to pits, pump total 3 BU after opening ESC. 67 bbls losses while cementing and displacing.;Shut down pump, disconnect knife valve hyd line, drain stack and flush with black water, function annular, re-connect knife valve hyd. Continue to circ at 6 bpm, 700 psi while waiting on cmt and preparing for second stage. Hold PJSM with all parties involved. No losses while circulating.;Perform 2nd stage cement job. Mix & pump 60 bbls of 10 ppg Tuned Spacer at 5 BPM, 362 PSI (4# red dye & 5# Pol-E-Flake in 1st 10 bbls). Mix & pump 308 bbls of 10.7 ppg ArcticCem lead cement (588 sks, 2.944 ft^3/sk yield) at 5 BPM, 514 PSI.;Mix & pump 56 bbls of 15.8 ppg Tail cement (270 sks, 1.169 ft^3/sk yield) at 5 BPM, 590 PSI. Drop closing plug. Pump 20 bbls fresh water at 5 BPM, 387 PSI.;Displace w/ 9.4 ppg spud mud w/ rig mud pump at 6 BPM, 440 PSI ICP, Slow down t/ 3 BPM for final 10 bbls. 700 PSI FCP. Bump plug at 1459 stks.(147.36 bbls) 7 stks early of calculated. Pressure up to 1900 psi and hold for 3 minutes. Bleed off pressure. Observe flow back.;Pressure up to 2170 psi and see indication of tool shift closed. Hold for 3 minutes, bleed off. Held Good. B/D & R/D cementers. CIP @ 21:25. 40 bbls interface, 60 bbl mud push and 214 bbl cement returned to surface. 44 bbls losses during 2nd stage.;Drain stack to the cellar. Disconnect knife valve accumulator lines. Function annular and flush w/ black water. Rig vac fluid out of casing to cellar level. Disconnect & begin N/D diverter line.;Back out speed head LDS on diverter adapter, hoist stack. Install 9-5/8" casing slips and set with 100K on slips. Cut 9-5/8" casing (47# Jt 56 = 41.20' – 16.08' = 25.12' left in hole). Set stack down. N/D annular & diverter tee, remove from Cellar. Sim-ops: clean pits, R/D and load out csg tools;Welder dress casing stump. Install and N/U FMC SlipLock head.;Interval Daily (Midnight) Loss = 111 bbls, Cumulative losses = 264 bbls H2O from L-Pad: 325 bbls Daily/ 7,660 bbls Total H2O from G&I Source Water: 690 bbls Daily/ 1080 bbls Total Cuttings/mud/cement to MPU G&I: 1,480 bbls Daily / 8,315 bbls Total pump 308 bbls of 10.7 ppg ArcticCem lead cement (588 sks, 2.944 ft^3/sk yield)at 5 BPM, 514 PSI.;Mix & pump 56 bbls of 15.8 ppg Tail cement (270 sks, 1.169 ft^3/sk yield) at 5 BPM, 590 PSI. Pump 358 bbl 12 ppg ExtendaCem Lead cmt (855 sx,), 5 BPM, 350 psi.;Mix & Pump 82 bbl 15.8 ppg Premium G tail cement (400 sx ) 4 7/23/2020 Finish installing FMC slip lock head and tbg spool WHR test same to 500 psi 5 min and 3800 psi for 10 min, good;PJSM, N/U adapter flange, spacer spool and BOP stack. Install MPD trip nipple and kill line. SimOps: Clean pits;Record stack Measurements, Rig up test equipment, install 3 1/2'' test joint and test plugj, Flush flow line. Fill stack and lines.-no leaks. Perform BOP shell test to 3000 psi, good.;Test BOP equipment to 250 PSI low / 3000 PSI high. Tests held for 5 min each & charted. AOGCC inspector Jeff Jones on location to witness test. All tests performed with fresh water against a test plug. 1. Annular on 3.5" test joint, choke valves 1, 12, 13, 14, kill Demco & Lower IBOP;2. Upper IBOP 3. Lower 3.5"x6" VBR on 3.5" test joint 4. Upper 4.5"x7" VBR on 4.5” test joint, choke valves 9, 11, HCR kill & 5" dart valve 5. Upper 4.5"x7" VBR on 5” test joint, choke valves 5, 8, 10, manual kill & 5" FOSV #1 6. Choke valves 4, 6, 7 & 5" FOSV #2;7. Choke valve 2 & 3.5” dart valve 8. HCR choke & 3.5” FOSV 9. Manual choke 10. Lower 3.5" x 6" VBR on 5" test joint 11. Blind rams & choke valve 3 12. Manual choke A 13. Manual choke B;Perform Accumulator test: 3000 PSI sys pressure, 1600 PSI after closure, 200 PSI recovery in 44 sec, full recovery in 203 sec, 6 N2 bottle avg = 2177 PSI. Rig electrician tested rig gas alarms;R/D test equipment, BD choke and kill lines;Mobilize BHA components to rig floor, Install 90' mousehole, R/U 5" handling equipment. PJSM, Make up 8-1/2" Smith XR+ Milltooth bit to Mud Motor ABH set @ 1.5°. SimOps: Trouble shoot leaking Annular & HRC 4-way valves on Accumulator. Rebuild all three valves. Annular still leaking fluid by.;Rebuild Annular 4-way valve and test. Still leaking. Consult with Doyon field superintendent and additional rig mechanics. Decision made to replace seals in Hydril Annular Preventer. SimOps: Install MPD drip pan. build tank farm containment.;PJSM, Remove drip pan, Rig down MPD assembly and trip nipple.;Drain hydraulic fluid from bag and disassemble annular preventer; remove element and piston.;Clean and Inspect annular preventer cylinder body and seals on piston. Cylinder bore shows fair amount of scoring.;Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls H²O from L-Pad: 255 bbls Daily/ 7,915 bbls Total H²O from G&I Source Water: 690 bbls Daily/ 1080 bbls Total Cuttings/mud/cement to MPU G&I: 618 bbls Daily / 8,933 bbls Total 7/24/2020 Continue to work on annular preventer, Rig mechanic buff out cylinder scoring with emery cloth, install new seals on piston, fill with hyd oil, reassemble same, install new element, w/ masher install annular cap.;With test plug in, install 3 1/2'' test joint, power up accumulator, cycle bag several times purging out air, no leaks on annular 4 way, fill stack with water, R/U and test bag on 3 1/2'' to 250/3000 psi 5 min ea. good. Chart test;Perform accumulator test, 3000 psi sys pressure, after closure 1650 psi, 200 psi attained in 48 sec, full press in 203 sec. good, N2 avg 6 bttls avg 2177 psi,;L/D test jt, install MPD head and lines, install test flange, test MPD head flange and lines to 1500 psi, good, remove test flange, install trip nipple, no leaks,;Blow down lines and drain gas buster. Remove test plug, install 9 1/8'' ID wear bushing. Install 90' mouse hole.;PJSM, P/U 8 1/2'' mill tooth bit, 1.5 deg mtr, run 2 stds 5'' HW, jar stand, 3 tds 5'' HW to 590' TIH w/ 5" DP t/ 2207'.;M/U top drive. Fill pipe and wash down f/ 2207'. 160 GPM, 270 psi. Take 5k wt @ 2273'. 105k PU, 85k SO;Wash and ream down f/ 2273’' to 2290' 2-8k WOB tagging on depth , 350 gpm, 500 psi, 40 rpm, 6k tq, drill plugs and ESC f/ 2292' to 2296', 2-10K wob. Ream 2 times, pass thru w/ pumps off and no rotary 2x, good PU 105K, SO 85K, ROT 95K;Attempt to RIH and take 15k wt @ 2302'. Kelly up and wash/ream through cement f/ 2302' t/ 2683' 450 GPM, 760 psi, 40 RPM, 6k Tq. 5-15k WOB.;TIH w/ 5" drillpipe on elevators t/ 7633'. Fill pipe every 2000';Circulate bottoms up. 500 GPM, 1220 psi. 40 RPM, 16k Tq. Reciprocate string 90';R/U testing equipment, flood lines and purge air from system;Attempt to perform casing test. Line up and pump down drillpipe and annulus against UPR . Pressure drop at 840 psi t/ 600 psi. Stop pumping and pressure continue to bleed off down t/ 140 psi. Check surface lines and equipment and attempt to pressure up again. Pressure level off at 540 psi.;Bleed off pressures and isolate surface lines from downhole. Pressure up to 1300 psi and hold good. Isolate choke manifold with HCR choke and pressure up again leveling off at 530 psi. Bleed pressure down and open UPR, Pumped total of 9 bbls, with 4 bbls returned.;Check all equipment lines and wellhead area. Discuss options with town engineers. Decision made to pull out of hole and P/U RTTS R/D test equipment, Blow down Topdrive and surface lines.;Daily (midnight) loss = 0 bbl, Cumulative loss = 0 bbl H2O from L-Pad: 75 bbls Daily/ 7,990 bbls Total H2O from G&I Source Water: 690 bbls Daily/ 1080 bbls Total Cuttings/mud/cement to MPU G&I: 114 bbls Daily / 9,047 bbls Total Decision made to pull out of hole and P/U RTTS 7/25/2020 Blow down lines, top drive and choke manifold, Well static is static.;TOOH with 8 1/2'' cleanout assembly f/ 7633' to 590', rack back HW and jar stand, L/D motor and BIT, grade = 1-1-NO-A-E-I-N0-BHA. Correct displacement;Clear and clean rig floor, strap and load tools to the rig floor, PJSM for handling and running retrievable storm packer.;P/U BOT 9 5/8'' Model -L retrievamatic storm packer as per Baker rep, RIH 90 fpm f/ 17' to 928', easy in/out of the slips using caution not to turn the pipe., Set and test packer as per BOT rep, close UPR, press 9 5/8 x 5'' to 1000 psi 5 min,, bleed off, open UPR and release packer. PU/SO 70K;RIH, tag at 2237' with 30k, M/U TD, wash down slow at 4 bpm, 70 psi to 2299', just past ESC with no issues, RIH to 2338', in center of 9 5/8 casing jt 137 just below ESC, set packer;Line up and pressure up annulus above packer, injecting at 400 psi, bleed off, line up and pressure up below packer to 700 psi, seals leaking by, RIH to 2373' at center of 2nd csg joint below ESC, set packer, test below packer to 1400 psi, good. Line up and test above packer, injecting @ 400 psi,;Bleed off pressure, rack 1 std back, pull up hole to center of csg joint above ESC @ 2254', pump 4 bpm, flush seals, set and test above packer to 1500 psi. good test. Pressure up below and verify injecting 1 bpm, 400 psi at ESC tool. Bleed off pressure, release packer;Blow down top drive choke, kill line. POOH f/ 2206'. Rack drillpipe in Derrick and lay down RTTS assembly. RTTS slips area had cement packed in and a 1"x1" piece of aluminum found embedded within the cement;Mobilize Baker casing scraper components to rig floor. PJSM, M/U 9-5/8" casing scraper assembly. 8-1/2" Smith Milltooth bit, 9-5/8" Baker casing scraper, Baker 7" boot basket, bit sub to drill pipe.;RIH with Baker 9- 5/8" casing scraper assembly on 5" drill pipe t/ 2421' Work scraper 2x f/ 2231' t/ 2263' & f/ 2326' t/ 2358'. No issues running in hole and passing the ES Cementer. 95k PU, 80k SO;Circulate hole clean, 3x bottoms up @ 650 GPM, 970 psi. No significant cuttings or debris seen at shakers while circulating.;Blow down TopDrive and POOH f/ 2421' t/ 42' racking 5" drillpipe in Derrick. Lay down the Baker 9-5/8" casing scraper assembly. Scraper blades packed with cement and 1/2 gallon of cement "wall cake" removed from boot basket.Clear and clean rig floor. Mobilize Baker cement retainer to rig floor.;M/U BOT K-1 Cement retainer to bottom of stand 5” drillpipe. TIH with cement retainer t/ 2334’ and set as per BOT Rep. 90k PU / 77k SO;Verify retainer set, PU t/ 130k & SO t/ 40k. Attempt to test retainer element and start to see flow at 860 psi.;Work string up t/ 130k and down t/ 40k multiple times and attempt tests again, start to see flow at 1000 psi. Consult BOT supervisor. P/U t/ 92k shutting retainer valve and isolating DP against running tool seals. Pressure up t/ 1000 psi and holds w/ no flow.;Work string to Max tool rating 140k up and 40k down with no success at holding more than 1150 psi when tested. Decision made to release from retainer and POOH.;Daily (midnight) loss = 0 bbl, Cumulative loss = 0 bbl H2O from L-Pad: 150 bbls Daily/ 8,140 bbls Total H2O from G&I Source Water: 0 bbls Daily/ 1080 bbls Total Cuttings/mud/cement to MPU G&I: 57 bbls Daily / 9,104 bbls Total 7/26/2020 With 9 5/8 retainer set at 2332', P/U to neutral weight at 90k, release from retainer as per BOT rep, TOOH f/ 2332', L/D running tool;P/U upper 9 5/8'' cement retainer, TIH to set depth at 2256', set retainer, Park with string in tension for 30 min, test above retainer to 2500 psi. good. PU 90K, SO;Line up to pump down drill pipe, establish injection rate, stage to 6 bpm, 680 psi, inject total 24.3 bbls and maintaining, shut off pump, bled down to 360 psi and holding, bleed off pressure, 4.5 bbls bled back.;Unsting out of retainer as per Baker rep, Set double in mouse hole, L/D top single M/U pump in sub, FOSV and 10' pup jt on top single, M/U single and TD, S/O to 2255' just above retainer, R/U cement line and valves.;Wait on cementers to complete 1st stage on I-Rig, prep pits, build 35 bbl black water pill in pill pit, clean on rig while waiting, cementers. Cementers on location at 16:00, spot and R/U same;Sting in setting down w/ 17k, close UPR, Pressure above retainer to 1000 psi, held, bleed off same, open UPR. P/U snap out plus 1',;Hold PJSM for cement job. HAL Pump 5 bbls of water and PT lines t/ 1190 psi low & 3700 psi high Mix & pump 54 bbls of 15.8 ppg cement (270 sks, 1.172 ft^3/sk yield) at 3 BPM, 630 PSI. Pump 5 bbls fresh water at 2 BPM, 140 PSI.;Displace 31 BBLS, 9.1 ppg mud w/ Rig. Initial rate 3 bpm, 280 psi. Slow to 2 bpm, 470 psi @ 21 bbls pumped and final 1 BPM, 420 psi last 3 bbls. Shut down, snap out of retainer, pick up 2’ and rig down cement lines. –drill string on a vac- CIP @ 19:27;Pick up to 2201’ @ 50’/min & lay down 2 jts drillpipe via mousehole. Kelly up and pick up to 2137’. Pump 5” wiper ball down drill string @ 350 gpm, 380 psi.;Increase rate t/ 600 GPM, 590 psi & circulate 5x BU while conditioning mud. Dump 10 bbls thick return to rockwasher @ first bottoms up.;Pull up t/ 2105’ & blow down topdrive, Monitor well –static- POOH f/ 2105’ t/ surface laying down the BOT K-1 Retainer running tool. Clear and clean rig floor.;Hold PJSM, M/U 10’ pup jt, Slip & Cut 66’ Drilling line. Service Drawworks, Topdrive and Iron Roughneck. Clean cement valves.;Clean wind walls, Inspect saver sub, Finish processing 4-/2" liner. Perform general cleaning throughout Rig and various equipment PM work.;Daily (midnight) loss (Surface section) = 55.5 bbl, Cumulative loss = 319.5 bbl H2O from L-Pad: 195 bbls Daily/ 8,335 bbls Total H2O from G&I Source Water: 120 bbls Daily/ 1200 bbls Total Cuttings/mud/cement to MPU G&I: 144 bbls Daily / 9,248 bbls Total set retainer, Park with string in tension for 30 min, test above retainer to 2500 psi. good . 7/27/2020 While WOC to reach 1000 psi compressive strength, clean wind walls, rig floor, pit area, general house keeping throughout the rig, complete various equipment PM work orders.;While WOC, PJSM, M/U cleanout BHA, 8 1/2'' Mill tooth bit, 1.5 deg motor, flush out flowline, run 5 stds 5'' HWDP and jar stand to 590', TIH to 2000', fill pipe.;Continue to wait for cement to reach 1000 psi compressive strength at 19:30, resume with maintenance and cleaning projects;TOOH f/ 2000' to 590', rack back HW and jar stand, L/D BHA, Pull wear bushing. Simops: Initiate critical lift plan to set well head equipment behind the rig with Crane. Pad operator, Crane operator, Doyon and Hilcorp HSE reps in attendance. Lift WH equipment and set in place behind rig.;Pull MPD trip nipple. Remove kill line and Nipple down the BOP stack. Remove spacer spool and set Stack on moving pedestal. Remove Modified FMC slip lock Wellhead.;Service Rig bridge crane, replace hydraulic fitting.;Install and nipple up new non-modified FMC Wellhead. Test void to 500psi – 5 min & 3800 psi – 10 min. Good test. Install new tubing spool, Lift BOP stack from pedestal and set in place on tubing spool. Nipple up tubing spool, adapter flange & BOP stack. Install trip nipple.;Rig up test equipment. Set test plug, Flood stack with H²O, purge air from system Test Three flanges on stack and kill line connection. Pump down kill line and pressure against Blind rams, test plug and HRC choke. Test 500 psi for 5 min, 3000 psi for 5 minutes. R/D test equipment and blow down lines;Install 9" ID Wear bushing. Install 90' Mousehole. P/U Mud Motor with Smith 8.5" XR+ Milltooth bit and RIH on 5" drillpipe t/ 1919' Kelly up and wash/ream down at 150 GPM, 150 psi, Tag firm cement @ 2242' with 15k;Kelly up and wash down at 150 GPM, 150 psi, Tag firm cement @ 2242' with 15k;Drill cement f/ 2242' t/ 2254'. Tag to of BOT K-1 cement retainer on depth. 350 GPM -550 psi, 40 RPM - 5k Tq. 5-8k WOB Drill cement retainer with 370 GPM - 550 psi. 40 RPM - 7k Tq. 2-5k WOB;Interval (Lateral) Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls H2O from L-Pad: 60 bbls Daily/ 8,395 bbls Total H2O from G&I Source Water: 120 bbls Daily/ 1200 bbls Total Cuttings/mud/cement to MPU G&I: 96 bbls Daily / 9,344 bbls Total 7/28/2020 Drill upper 9 5/8 cement retainer on depth f/ 2254' to 2256.7' with 370 GPM - 550 psi. 40 RPM - 7k Tq. 2-5k WOB, drill firm cement to 2265, then hard cement and retainer junk to 2267, using varying parameters, 375-550 gpm, 30-60 rpm, 5-8k tq. Drill cement to 2332', drill lower retainer on depth,;Note: hard cement at shakers.;Continue to drill lower retainer f/2332' to 2334' using varying parameters, 375- 550 gpm, 30-60 rpm, 5-8k tq, wash down to 2395'. Recovered 52 lbs fine metal from ditch magnets;TIH on elevators f/ 2395 to 7633' slight bobble at 3033', junk wedged along side bit, P/U 30' and S/O with no other issues. Fill pipe every 2500';Circulate B/U 520 gpm, 1450 psi, reciprocate pipe PU 215K, SO 60K;R/U test equipment. Flood lines, close UPR, Test 9 5/8'' casing to 1000 psi for 30 min, charted, good test, bleed off pressure, open UPR, R/D test equipment 3.2 bbls pumped, 3.2 bbl bled back;Wash down at 450 GPM - 1200 psi. Tag cement @ 7633' Drill 9-5/8" shoe track w/ 450 GPM, 1250 PSI, 40 RPM, 18K TQ. Drill baffle adapter @ 7650’ w/ 5-8K WOB, Float collar @ 7688' w/ 5k. Drill shoe @ 7770’ w/ 5K WOB, then cleanout rathole to 7778'. All FE tagged on depth.;Reamed through baffle adapter, float collar and shoe 2x times each, pass through each with no rotary/pumps. Cement in shoe track drilled w/ 10k WOB;Drill 8-1/2" production hole f/ 7778' t/ 7798', 450 GPM, 1270 PSI, 40 RPM, 19K TQ, 15-17K WOB. 245k PU 70k SO 120k ROT Max gas @ 78u with BU. Recovered 30 pounds metal from ditch magnets.;Pump a stand out to 7730’. Circulate wellbore clean until 9.3 ppg MW in/out. 550 GPM, 1690 PSI, 40 RPM, 30u max gas. Work string 90’;Rig up test equipment, flood lines and purge choke and kill lines. Perform FIT to 12.0 ppg EMW with 9.3 ppg MW at 3979' TVD. Pressure up to 560 PSI, 1.3 bbls pumped, 1.3 bbls bled back. R/D test equipment and blow down lines.;Perform 5 min. flow check - static. POOH on elevators f/ 7730' t/ 7252', good displacem ent. Pump 25 bbls 11.3 ppg dry job. Blow down top drive. POOH on elevators f/ 7252' t/ 1222' 4.7 bbls losses;Troubleshoot Topdrive hydraulic pump issues. Hydraulic pump tripping and power down.;Daily (midnight) loss = 0 bbl, Cumulative loss = 0 bbl H2O from L-Pad: 125 bbls Daily/ 8,520 bbls Total H2O from G&I Source Water: 120 bbls Daily/ 1200 bbls Total Cuttings/mud/cement to MPU G&I: 114 bbls Daily / 9,458 bbls Total 7/29/2020 Parked at 1222', Troubleshoot Topdrive hydraulic pump, rig electrician found aux power plug on TD had shorted out pins on 19 pin connector, C/O plug end on TD, remove aux service loop, Monitor well, static;Finish removing shorted Aux service loop, Install new service loop brought from DDI yard, continue to troubleshoot TD hydraulic issues. Change out 35 amp 600 volt fuses in VFD house and test Topdrive operation. Good. Fill hydraulic oil and adjust service loop orientation. Well remains static;TOOH with 8 1/2'' cleanout assembly f/ 1222' to 590', L/D excess HW, rack back jar stand, L/D motor and bit. grade = 1-2-WT-A-E-1-NO- TD;PJSM. M/U 8-1/2" NOV SK616M-J1D bit, NBS, 7600 Geo-Pilot, MWD w/ ADR, ILS, DGR, PWD, Directional collars and spiral blade stabilizer to 91’.;Test & initialize MWD tools.;M/U, float sub, 3 NMFCs & 2nd float sub t/ 187'. RIH w/ HWDP & jar stand to 280'. Note: corrosion ring installed at top of NMFC's;M/U stand DP and TD, shallow test MWD. TIH with 5" DP stands from Derrick to 7516', Fill drill pipe every 2000' Pressure test Geo-Span to 3000 psi. Break in Geo-Pilot seals at first pipe fill. Correct displacement TIH.;Single in hole w/ 5" DP f/ 7516' t/ 7770' Hold PJSM for removing trip nipple & installing MPD RCD. 225k P/U, 76k S/O SimOPps; Prep mud pits and rockwasher for upcoming displacement;Daily losses (midnight) = 0 bbls, Cumulative lateral losses = 0 bbls H²O from L-Pad: 145 bbls Daily/ 8,665 bbls Total H²O from G&I Source Water: 120 bbls Daily/ 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 171 bbls Daily / 9,629 bbls Total Test 9 5/8'' casing to 1000 psi for 30 min, charted, good test, 7/30/2020 PJSM, Remove trip nipple, install RCD bearing, no leaks. Pressure test MPD lines to 250/1500 psi, good, PJSM for displacing. Run to bttm @ 7798' PU 225K, SO 76K;Pump 30 bbl hi vis spacer then displace w/566 bbls new 8.8 ppg Flo-Pro mud w/ 1.5% screen kleen and .5% lube added, 377 gpm, 930 psi, 40 rpm, 19K TQ, w/ new mud out bit, finish displacing in casing f/ 7769' to 7710' working pipe 60'. Dump spud mud and interface to rock washer;Clean under shakers and pit 4, record new parameters and SPRs Monitor MPD for pressure build, none PU 175K, SO 80K, ROT 121K;Drill 8-1/2" production hole f/ 7798' t/ 8082' (3975' TVD) 284' drilled, 113.6'/hr AROP. 500 GPM, 1400 PSI, 110 RPM, 15K TQ, 10K WOB. 8.9 ppg MW, 44 vis, 10.4 ECD, 194u max gas. 180K PU / 70K SO / 110K ROT. Holding 60 PSI on conn. w/ MPD, 60 PSI line restriction w/ choke open drilling.;Drill 8-1/2" production hole f/ 8082' t/ 8751' (3955' TVD) 669' drilled, 111.5'/hr AROP. 550 GPM, 1820 PSI, 110 RPM, 16K TQ, 10-16K WOB. 8.9+ ppg MW, 44 vis, 10.69 ECD, 668u max gas. 170K PU / 80K SO / 110K ROT. Drilling in NB sand targeting 92°;Holding 85 PSI on conn. w/ MPD, 60 PSI line restriction w/ choke open drilling. Pump 30 bbl hi vis sweep @ 8465', back on time w/ 50% increase.;Drill 8-1/2" production hole f/ 8751' t/ 9373' (3945' TVD) 622' drilled, 103.6'/hr AROP. 550 GPM, 2030 PSI, 110 RPM, 15k Tq, 13k WOB. 8.9+ ppg MW, 43 vis, 11.29 ECD, 546u max gas. 165k PU / 65k SO / 103k ROT. Drilling in NB sand targeting 89.5-92°;Holding 100 psi on conn. w/ MPD, 80 psi drilling Pump 30 bbl hi vis sweep @ 9126', back on time w/ 20% increase.;Drill 8-1/2" production hole f/ 9373' t/ 10083' (3924' TVD) 710' drilled, 118.3'/hr AROP. 515 GPM, 1900 PSI, 110 RPM, 12k Tq, 10k WOB. 9.0+ ppg MW, 44 vis, 11.17 ECD, 405u max gas. 150k PU / 77k SO / 100k ROT. Drilling in NB sand targeting 93° Holding 125 PSI on conn. w/ MPD, 80 PSI while drilling.;Last survey @ 9915.09' MD / 3927.10' TVD, 91.98° inc, 190.17° azm, 13.40’ from plan, 4.01' high, 12.79' right. We have drilled 10 concretions for a total thickness of 44' (2.0% of the lateral) 25lbs Metal recovered from ditch magnets on the day (midnight);Daily (midnight) loss = 0 bbl, Cumulative loss = 0 bbl H2O from L-Pad: 680 bbls Daily/ 9,345 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total 7/31/2020 Drill 8-1/2" production hole f/ 10083' t/ 10693' (3893' TVD) 610' drilled, 101.6'/hr AROP. 500 GPM, 1950 PSI, 110 RPM, 11k Tq, 5-15k WOB. 9 ppg MW, 43 vis, 11.26 ECD, 583u max gas. 145k PU / 70k SO / 105k ROT. Drilling in NB sand targeting 93°;30 bbl hi vis sweep pumped at 9986', back on time with 30% increase, pump another at 10460' on time w/ 50% increase. Holding 180 PSI on conn. w/ MPD, 80 PSI while drilling.;Drill 8-1/2" production hole f/ 10693' t/ 11450' (3870' TVD) 757' drilled, 126.17'/hr AROP. 500 GPM, 1950 PSI, 110 RPM, 11k Tq, 5-15k WOB. 9 ppg MW, 43 vis, 11.58 ECD, 553u max gas. 152k PU / 65k SO / 105k ROT. Drilling in NB sand targeting 92.5°;Pump 30 bbl hi vis sweep @ 11035', back on time with 60% increase. Holding 180 PSI on conn. w/ MPD, 80 PSI while drilling.;Drill 8-1/2" production hole f/ 11450' t/ 12096' (3850' TVD) 646' drilled, 107.67'/hr AROP. 515 GPM, 2060 PSI, 130 RPM, 15k Tq,10k WOB. 9 ppg MW,41 vis, 11.5 ECD, 535u max gas. 160k PU / 50k SO / 100k ROT. Drilling in NB sand targeting 92.0°;Pump 30 bbl hi vis sweep @ 11512', back on time with 100% increase. Pump 30 bbl hi vis sweep @ 11988', back on time with 50% increase. Holding 180 PSI on conn. w/ MPD, Full open choke w/ 60 psi line pressure while drilling. Perform 290 bbl whole mud dilution at 11667’;Drill 8-1/2" production hole f/ 12096' t/ 12621' (3846' TVD) 525' drilled, 87.5'/hr AROP. 500 GPM, 2050 PSI, 130 RPM, 15k Tq,10k WOB. 9.0 ppg MW,41 vis, 11.44 ECD, 359u max gas. 167k PU / 0k SO / 100k ROT. Drilling in NB sand targeting 89.5°;Crossed Fault #1 @ 12465' with a 5' throw DTS within the NB sand. Pump 30 bbl hi vis sweep @ 12559', still in hole at report time.. Holding 180 PSI on conn. w/ MPD, Full open choke w/ 60 psi line pressure while drilling. Lost dn wt @ 12559';Last survey @ 12485.24' MD / 3845.25' TVD, 89.76° inc, 189.20° azm, 13.22’ from plan, 9.06' high, 9.63' right. We have drilled 21 concretions for a total thickness of 90' (1.9% of the lateral). 3.5lbs Metal recovered from ditch magnets on the day (midnight) Total of 122 lbs recovered;Daily (midnight) loss = 0 bbl, Cumulative loss = 0 bbl H²O from L-Pad: 970 bbls Daily/ 10,315 bbls Total H²O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 1,452 bbls Daily / 12,274 bbls Total 8/1/2020 Drill 8-1/2" production hole f/ 12621' t/ 13010' at PB1 TD (3869' TVD) 389' drilled, 77.8'/hr AROP. 480 GPM, 1950 PSI, 130 RPM, 14k Tq,14k WOB. 8.9 ppg MW ,40 vis, 11.64 ECD, 356u max gas. 165k PU / 50k SO / 101 ROT.;Drilling in NB sand targeting 90.5°, at 12623' drop to 85° looking for quality sand as per Geo, good sand at 12823', decision made to pull back and side track at 11570'. 30 bbl hi vis sweep pumped @ 12522' back on time w/ 20% increase. 12750' MBT @ 7, perform 290 bbl dump/dilute w/ new 8.8 ppg mud.;Later Geo determined we crossed fault #2 @ 12694' with 8' DTS throw. Take final survey, 17.77' above the line, 3.84' left;Pump out from 13010' to 11570', 495 gpm, 2050 psi to side track point w/ 91.99 deg inc, at start of a ramp that builds to 94.2 deg in the target sand. MPD hold 180 psi during connections and 60 psi pumping out, Verify depth against pipe tally and stds in derrick;Rack back std to 11605', M/U single, Set with 100% deflection at 170L tool face, ABI @ 91.99°, time drill 25 fph f/ 11570' t/ 11600', with ABI @ 91.11° at 1.49° f/ original wellbore at 92.6°. 500 GPM, 2050 PSI, 130 RPM, 13K TQ, 170K PU / No SO / 105K ROT.;Increase ROP to 50 fph, drop to 90° drill to 11639', BR 2 times f/ 11639' to 11560', Pass thru with pumps off and no rotary, good, L/D single;Drill 8-1/2" hole f/ 11639' t/ 12252' (3863' TVD) 613' drilled, 87.5'/hr AROP. 500 GPM, 2020 psi, 110 RPM, 13k Tq, 5k WOB. 8.9 ppg MW ,40 vis, 11.41 ECD, 523u max gas. 160k PU / 55k SO / 105k ROT. Target 90.5-93° to maintain lower NB sands.;Pump 30 bbl hi vis sweep @ 12083', Back 200 stks late w/ 75% increase in cuttings. Holding 200 PSI on conn. & 100 psi back pressure while drilling w/ MPD,;Drill 8- 1/2" hole f/ 12252' t/ 12464' (3847' TVD) 212' drilled, 70.67'/hr AROP. 500 GPM, 2170 psi, 110 RPM, 13k Tq,10-15k WOB. 8.9 ppg MW ,40 vis, 11.50 ECD, 457u max gas. 162k PU / 55k SO / 103k ROT.;MPD holding 200 PSI on connections. & 100 psi back pressure while drilling. Drilling in NB sand targeting 90- 92.5°. See lower quality NB sand on logs started at 12400’;Backream stand 90’ f/ 12464' t/ 12374' while Geologists discuss logs and plan forward. 500 GPM, 2050 psi. 105 RPM, 14k Tq. Decision made proceed with drilling.;Drill 8-1/2" hole f/ 12464' t/ 12654' (3844' TVD) 190' drilled, 95’/hr AROP. 500 GPM, 2170 psi, 110 RPM, 13k Tq,10-15k WOB. 8.9 ppg MW ,40 vis, 11.50 ECD, 457u max gas. 157k PU / 55k SO / 102k ROT. Drilling in NB sand targeting 89.5°;Drilled through fault #1 at 12465’ with a 5’ throw DTS. Perform 290 bbl whole mud dilution at 12530’ with MBT’s @ 7.5 MPD holding 225 PSI on connections. & 125 psi back pressure while drilling;Last survey @ 12486.26' MD / 3847.22' TVD, 92.10° inc, 192.03° azm, 14.73’ from plan, 5.8' high, 13.54' right. We have drilled 28 concretions for a total thickness of 104' (2.2% of the lateral). 17lbs Metal recovered from ditch magnets on the day (midnight) Total of 139 lbs recovered;Daily (midnight) loss = 0 bbl, Cumulative loss = 0 bbl H²O from L-Pad: 1,025 bbls Daily/ 11,340 bbls Total H²O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 1,383 bbls Daily / 13,657 bbls Total 8/2/2020 Drill 8-1/2" hole f/ 12654' t/ 13130' (3847' TVD) 476' drilled, 79.3’/hr AROP. 500 GPM, 2170 psi, 110 RPM, 15k Tq,10-15k WOB. 8.9 ppg MW ,40 vis, 11.42 ECD, 482u max gas. 165k PU / no SO / 100k ROT. MPD holding 200 psi on connections, 80 psi drilling;Geo reports crossed Fault #2 @ 12,699’ w/ 6' DTS throw,. Target 88°, back in good NB sand @ 12749', target 90° Pump 30 bbl hi vis sweep @ 13305', back 300 stks late w/ 20% increase. Reached PB1 depth of 13010' at 09:30;Drill 8-1/2" hole f/ 13130' t/ 13700' (3852' TVD) 570' drilled, 95’/hr AROP. 500 GPM, 2130 psi, 110 RPM, 15k Tq, 5-15k WOB. 9 ppg MW ,43 vis, 11.38 ECD, 459u max gas. 172k PU / no SO / 105k ROT. Target 88°;At 13183' perform 290 bbl dump/dilute lowering MBT from 7 to 6.5 Drilled into the SB_NB Clay from 13450' t/ 13584' Pump 30 bbl hi vis sweep @ 13505', back 400 stks late w/ 20% increase MPD holding 200 psi on connections, 80 psi drilling;Drill 8-1/2" hole f/ 13700' t/ 14120' (3858' TVD) 420' drilled, 84’/hr AROP. 500 GPM, 2150 psi, 110 RPM, 17k Tq, 5-15k WOB. 8.9 ppg MW ,40 vis, 11.7 ECD, 441u max gas. 175k PU / no SO / 105k ROT. Target 89.5° MPD holding 200 psi on connections, 60 psi w/ full open choke while drilling.;41 concretions were drilled for a total footage of 138’ (2.2% of the lateral). 6123' drilled in NB sand, 134' in NB clay and 93' above the NB sand. Total of 227' out of zone. Final survey at 14047.75' MD / 3858.02' TVD, 89.82° inc, 188.71° azm, 50.17' from plan, 50.17' low and 0.80' right.;Pump 30 bbl hi vis sweep, back 500 stks late w/ 20% increase. BROOH while racking stds back to 13734', pump total 4x BU cleaning up the wellbore, 500 gpm, 2100 psi, 110 rpm, 17k torque Prep pits for displacing and hold PJSM on displacement;Wash/Ream to bottom due to no slack off weight f/ 13734’ t/ 14120' pumping 430 gpm, 1650 psi, 65 RPM, 17k Torque.;Pump SAPP pill treatment, 30 bbl hi vis spacer, 3- 20 bbl SAPP pills with 50 bbl seawater spacers, chase with 300 bbls seawater 9 bpm, 1300 psi, 105 rpm, 16-20k torque. Pump 30 bbl hi vis spacer. Start displace w/ 8.45 ppg, 3% lubed vissed brine 315 gpm, 984 psi;Daily losses (midnight) = 0 bbls, Cumulative lateral losses = 0 bbls H²O from L-Pad: 910 bbls Daily/ 12,250 bbls Total H²O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 1,554 bbls Daily / 15,211 bbls Total 8/3/2020 Displace w/ 1008 bbls 8.45 ppg, 3% lubed vissed brine f/ 14120' at 9 bpm, 1300 psi, 105 rpm, 16-20k torque. Take lubricated brine back to pits @ 15674 stks, at 72 bbls over caculated displacement. No losses displacing. Max gas 555u;Monitor MPD for pressure build 3 times while c leaning under shakers, 1st- Bleed off For 3 mins – 12 Psi Built to 72 Psi over 6 mins with last Bleed off for 2 mins – Well Flowed at 15 GPM, Shut in well – Built to 60 Psi over 6 Mins. 8.8 ppg EMW.;Screen up shakers to 230 mesh, stage to 550 gpm, 1620 psi, 40 rpm, 13k, working pipe f/ 14120' to 14082', perform PST as per mud man, PST in passed,4.8, 4.9, 4.9 sec. Under shakers passed, 5.0, 5.1, 5.0 sec, At possum belly failed. Circulated total 1.5 BU @ 10350 stks. 30 bbl losses;Obtain new parameters and SPRs, no change in torque at 100 rpm at 17-19k. In mud PU 175K, no SO, ROT 105K. In brine PU 190K, SO 45K, ROT 100K;BROOH pulling 5-10 min stand f/ 14120' to 13322' pumping 550 gpm, 1650 psi, 110 rpm, 19k tq, slow down as needed for pressure increases L/D 5'' DP utilizing the mousehole while BR. MPD holding 190 psi on connections, 75 psi BR. Loss rate 17.5 bph;BROOH pulling 5-10 min stand f/ 13322' to 11037' pumping 500 gpm, 1550 psi, 110 rpm, 19k tq, slow down as needed for pressure increases, L/D 5'' DP utilizing the mousehole while BR. MPD holding 190 psi on connections, 75 psi BR. Slowing 9 bph loss rate. Off hi line power @ 14:00, on rig gen power;Note: Pass thru past side track point @ 11570' with pumps off and no rotary, survey to confirm wellbore, good;BROOH pulling 5-10 min stand f/ 11037' to 9012' pumping 500 gpm, 1500 psi, 110 RPM, 18k Tq. Max Gas = 623u. L/D 5'' DP utilizing the mousehole while BR. MPD holding 190 psi on connections, Full open choke w/ 65 psi line pressure while backreaming. 3 bph loss rate;String torquing up and stall @ 10116’, also see packing off, work area 2x – clean. Hole unload sand and shakers blinding off @ 9070’. Slow flow t/ 350 gpm to keep mud on shakers, and reduce pulling speed to 125’/hr until cleaned up – 1.3x BU. 18.5 lbs metal on the day (midnight). Total 172.5 lbs;BROOH pulling 5-10 min stand f/ 9012' t/ 7897’ pump through the 9-5/8” casing shoe t/ 7707’. 500 GPM, 1330 psi, 110 rpm, 17k Tq Slow down as needed for pressure increases, L/D 5'' DP utilizing the mousehole while BR MPD holding 170 psi on conn, 65 psi line pressure BR 111 bbl losses BR to shoe;Pump 30 bbl high vis sweep, 500 GPM, 1300 PSI, 40 RPM, 6K TQ, reciprocate 90'. Sweep on time w/ 40% increase, continue to see fair amount sand, Pump 2nd 30 bbl hi vis sweep around. 3 bph loss rate circulating.;Daily losses (midnight) = 115 bbls, Cumulative lateral losses = 115 bbls H²O from L-Pad: 570 bbls Daily/ 12,820 bbls Total H²O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 2,519 bbls Daily / 17,730 bbls Total 8/4/2020 Continue to see fair amount sand, Pump 2nd 30 bbl high vis sweep, 500 GPM, 1300 PSI, 40 RPM, 6K TQ, reciprocate 90'. Sweep on time w/ 10% increase and cleaning up the 9 5/8 casing. Perform passing PST at possum belly returns, 4.8, 4.8, 4.9 sec 6 bph loss rate;Monitor MPD for pressure build 3 times with final flow slowing to 5 gpm, shut in building from 10 psi to 48 psi in 10 min and leveling off;Weight up brine from 9 to 9.2+ ppg over 1.3 circulations with oilfield salt, 400 gpm, 820 psi, 40 RPM, 6K TQ. Reciprocate 90', cap the well from shoe up;With 9.2+ in/out shut down, flowing 8 gpm receding to 2.4 gpm in 45 min and not slowing, continue to wt up to 9.3+, water back heavy spots, until good 9.3+ in/out, shut down Pumped total 3 circulations. No losses;Monitor well, flowing 11 gpm slowing to small pencil size stream in 15 min, finally going static in 50 min;PJSM, remove MPD RCD and install trip nipple. Fill stack, check for leaks - none.;PJSM, TOOH f/ 7733' to 3325' L/D 5'' DP to the pipe shed Pumped dry job at 7675';Drop 2.45" drift on wire, POOH f/ 3325' t/ 280' racking back 32 stands. Flow check - static. L/D HWDP, jar, 3 NMDC, 2 float subs & stabilizer to 86'. Read MWD tools. L/D remainder of BHA f/ 86'. Observed wear on the up hole side of string stabilizer. ILS blades worn down 8-3/8" to 7-7/8" O.D.;Bit grade: 2-3-BT-N-X-I-WT-TD Piece of metal found lodged in jar mandrel, 11 pieces found in Geo-Pilot debris shield & 2 found stuck w/ clay to bit sleeve. All metal ~1/16" thick, from 1" x 1" to 2.5" x 3", majority 2.5" x 2.5". 13 bbls lost on trip out from the shoe.;Consult drilling engineer, will perform cleanout run w/ string magnet, boot baskets & casing scraper. Load 5" drill pipe into the shed for cleanout run. Pull wear bushing, function rams & flush stack with Johnny Wacker twice. 7 pieces of metal about 3/4"x3/4" out of stack. 2 BPH static losses.;Daily losses (midnight) = 79 bbls, Cumulative lateral losses = 295.1 bbls H2O from L-Pad: 420 bbls Daily/ 13,240 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 535 bbls Daily / 18,265 bbls Total;Daily metal recovered from magnets = 10#, total 182.5# 8/5/2020 L/D wash tool, install 9" ID wear bushing, clean and clear the rig floor, load BOT cleanout tools to the rig floor. PJSM Static loss rate 1 bph.;M/U 6.5'' bull nose, string magnet, XO, boot bskt, 9 5/8'' csg scraper, 2 boot bskts, bit sub and jar to 67.71', TIH w/ 32 stands 5'' DP to 3112', single in with 5'' DP to 3873' Submitted 24 hr BOP test notification @ 09:39;Continue to single in with 5'' DP from 3873' to 7646', M/U TD, RIH to 7660' putting 9 5/8'' scraper 10' above Baffle adaptor. 6.5 bbl losses TIH PU 145K, SO 100K;Pump 30 bbl hi vis sweep, Circulate 500 gpm, 550 psi, with sweep out bull nose, work string cleaning up SLZXP LTP setting depth f/ 7578'-7600', make 1 pass rotating 30 rpm, 5k tq f/ 7578' to 7660' Sweep back on time with no increase, No losses;Shut down, flow check well for 15 min, static. fill trip tank, ready pipe shed.;TOOH f/ 7660' to 3016' L/D singles 5'' DP to the pipe shed. Pumped dry job at 7205'. 93K PU / 80K SO.;Rack back 31 stands 5" drill pipe f/ 3016' t/ 67'. Inspect string magnet: 18# of large 5/8" to 3/4" thick cement retainer slip segments up to 2"x3" & 35# of smaller pieces recovered. L/D jar, 3 boot baskets, scraper, magnet & XOs. One cup metal recovered from boot basket below casing scraper.;9.9 bbls lost on the trip out of the hole.;Clear rig floor. Mobilize casing equipment to the rig floor. R/U hydraulic double stack tongs, elevators and slips. PJSM for running liner. 2 BPH loss rate.;P/U shoe joint to 43' w/ Innovex eccentric solid bull nose guide shoe w/ two 7-1/4" centralizers & 4 stop rings. Run 4-1/2" 13.5# L-80 Hydril 625 f/ 43' t/ 3270' as per tally. Torque to 9,600 ft/lbs w/ Doyon double stack tongs.;Install stop ring & 7-1/2" centralizer on each solid joint. Install RGL 250u Pro-Mesh screens as per tally. 2 bbls losses running liner to this depth.;Daily (midnight) losses = 18.5 bbls, Cumulative lateral losses = 313.6 bbls H2O from L-Pad: 65 bbls Daily/ 13,305 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 289 bbls Daily / 18,554 bbls Total;Metal recovered from ditch magnets: 4.5# daily, 187# total. 8/6/2020 Run 4-1/2" 13.5# L-80 Hydril 625 f/ 3270' t/ 6499' as per tally. Torque to 9,600 ft/lbs w/ Doyon double stack tongs. Install stop ring & 7-1/2" centralizer on each solid joint. Install RGL 250u Pro-Mesh screens as per tally. Verify pipe count.;(148 jts 4.5'' liner, 11 -250 mesh screens, 1- 8 1/2'' tendeka swell packer with pups ran) (150- 4 1/2'' x 7 1/4'' centralizers with 154 stop rings ran) Loss rate continues at .5 bph, 4.5 bbls total.;PJSM, C/O handling equipment to 5''. M/U Baker 7 x 9-5/8" SLZXP liner top packer assy as per BOT rep, verify 9 pins w/ shear set @ 44100#, pusher tool 8 pins @ 2648 psi, Run 1 std to 6642', PU 95K, SO 76K;Record parameters, M/U TD, pump 10 bbls at 3 bpm, 110 psi to ensure clear flow path, set TD torque at 9k, rotate 10/20 rpm w/ 3k torque PU 95k, SO 76K, ROT 85K;TIH w/ 4 1/2'' liner on stds of 5'' DP no faster than 30 fpm, f/ 6642' to 7964', M/U TD, , get parameters before exiting shoe @ 7770', PU 113k, SO 88K, Easy in/out of the slips, slow auto filling, fill on the fly and top off every 10 with clean 9.3+ brine;TIH w/ 4 1/2'' liner on total 30 stds of 5'' DP no faster than 30 fpm, f/ 7964' to 9391', single in with 5'' HWDP to 9605' Easy in/out of the slips, slow auto filling, fill on the fly and top off every 10 with clean 9.3+ brine. 9.3 bbl losses at this point.;Service rig / Inspect top drive found shot pin leaking.;Install FOSV, top drive shot pin assembly leaking on the rotating gear, replace and test same, good, wire tie and secure TD, work pipe to break over, good. PU 140K, SO 86K;TIH w/ 4-1/2" liner on 5" HWDP singles from the pipe shed f/ 9605' t/ 13010'. Set 15K down. 225K PU / 135K SO.;P/U & verify tally depth. Set 10K & 25K down which confirms tagging bottom of PB1 wellbore. POOH f/ 13010' racking back HWDP to 11547'. 35K overpull at 12160', work down then P/U no problem. Obtain parameters 200K PU / 125K SO / 155K ROT;Rotate 15 RPM, 7.5K TQ f/ 11555' t/ 11650'. Began at 8-9 FPM. Started taking 5K weight at 11590' & 10K at 11597', slow to 1-2 FPM. Weight decreased at 11612', increased to 3-5 FPM. TIH @ 30 FPM f/ 11650' (10K bobble at 12172') t/ 13010', tagged PB1 TD again 3 times w/ 25K. 225K PU / 130K SO.;POOH f/ 13010' t/ 11540' rack backing 5" HWDP. Reciprocate liner nine times f/ 11540' t/ 11580'. Work liner past sidetrack point at 11570' at 1-2'/min. f/ 11570' t/ 11592', began taking 10K weight at 11581'.;Daily (midnight) losses = 23.5 bbls, Cumulative lateral losses = 337.1 bbls H2O from L-Pad: 50 bbls Daily/ 13,355 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 294 bbls Daily / 18,848 bbls Total 8/7/2020 Work liner slowly past sidetrack point f/ 11592' t/ 11610' at 1-2'/min. Increase to 5'/min f/ 11610' t/ 11650'. TIH w/ liner on 5" HWDP stands f/ 11650' t/ 13010', set down 25k 2 times to confirm PB1 TD;POOH f/ 13010' t/ 11540' racking back 5" HWDP. M/U single, work pipe from 11540' to 11585' slow 20 times attempting to shave down ramp to the transition point of PB1 and new wellbore ,;BR slow from 11585' to 11540' at 15 rpm, 7k tq, then ream down slow to 11585', from 11580' to 11585' seeing 9k tq with 2-5 k wt, from 11585' to 11595' seeing 20k wt working down slow at 15 rpm, 9K tq, shut off rotary. TIH w/ stds HW 12990', M/U single HW, tag at 13010', PB1 TD. 3.5 bbl losses;Flow check the well, static, L/D single, TOOH f/ 12990' to 7487'. racking back stands HW & drill pipe. 9 bbls lost on trip. *** On highline power at 18:00 ***;Perform 15 min flow check, dropped 1.5' = 2 BPH. M/U Baker 9-5/8" model B2 retrieve-a- matic storm packer & TIH w/ stand of 5" drill pipe to 7596'. Set storm packer w/ 45K weight set on packer. Center of element at 103.2'. Rack back stand. Close blind rams & test packer to 500 PSI for 5 min. charted.;Pull wear bushing, install test plug & rig up test equipment. Gland nut stripped out on LDS when removing bushing. Replaced gland nut. Perform BOP shell test w/ annular on 3.5" test joint to 250 PSI low / 3000 PSI high - good.;Perform bi-weekly BOP test. AOGCC Inspector A. McLeod waived the right to witness testing. All tests performed w/ fresh water, 250 PSI low & 3000 PSI high for 5 min each & charted. 1) Annular on 3.5" test joint, choke valves 1, 12, 13, 14, kill line Demco & lower IBOP. 2) Upper IBOP; 3) Lower 3.5"x6" VBR on 3.5" test joint. 4) Upper 4.5"x7" VBR on 5" test joint, choke valves 5, 8, 10, manual kill & 5" FOSV #1. 5) Choke valves 4, 6, 7 & 5" FOSV #2 6) Choke valve 2 & 3.5" dart valve 7) HCR choke & 3.5" FOSV 8) Manual choke 9) Lower 3.5"x6" VBR on 5" test joint;10) Blind rams & choke valve 3 11) Upper 4.5"x7" VBR on 7" test joint 12) Super choke A 13) Super choke B Accumulator: 3075 PSI system, 1725 PSI after closure, 200 PSI recovery in 39 sec, full recovery in 184 sec.. 6 Nitrogen bottle avg 2083 PSI. No failures. Test gas & PVT alarms - good.;Daily losses = 20 bbls, Cumulative lateral losses = 357.1 bbls H2O from L-Pad: 85 bbls Daily/ 13,440 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 57 bbls Daily / 18,905 bbls Total 8/8/2020 R/D Test equipment, remove test plug, install 9'' ID wear bushing., clear rig floor.;PJSM, slip and cut 132' drilling line, recalibrate block height, service rig;RIH with stand DP and single, screw into packer @ 103', M/U FOSV, close bag, open valve on storm packer, check for pressure under packer, none, release packer as per BOT rep, L/D FOSV, open bag, Pull packer to surface, L/D same. 4 bbls to fill the hole;Flowcheck the well 10 min, 6 bph static loss rate. TOOH f/ 7487' to 6536' rack 10 stds 5'' DP in the derrick. L/D LTP assy, R/U 4 1/2'' handling equipment Remove burst disk/ball seat assy to send to baker for inspection.;PJSM, TOOH from 6498', L/D 4 1/2'' lower completion to the pipe shed. 0 losses.;Clear and clean the rig floor. Rig vacuum mud out of the shoe joint. PJSM for re-running the 4-1/2" liner.;P/U 4-1/2" shoe joint w/ 2.1° bend 16' from end w/ rounded solid shoe. Run 4-1/2" 13.5# L-80 Hydril 625 liner as per tally to 5954'. Torque to 9600 ft/lbs w/ Doyon double stack tongs. 4.5 bbls losses.;Daily losses = 20 bbls, Cumulative lateral losses = 377.1 bbls H2O from L-Pad: 40 bbls Daily/ 13,480 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 0 bbls Daily / 18,905 bbls Total 8/9/2020 Run 4-1/2" 13.5# L-80 Hydril 625 liner as per tally f/ 5954' to 6498' (148 jts 4.5'' liner, 11 -250 mesh screens, 1- 8 1/2'' tendeka swell packer with pups ran) (147- 4 1/2'' x 7 1/4'' centralizers with 147 stop rings ran) 5 bbl losses;PJSM, C/O handling equipment to 5''. Inspect and M/U Baker 7" x 9-5/8" SLZXP liner top packer assy as per BOT rep, Run 1 std to 6631', M/U TD, pump 5 bbls 4 bpm, 240 psi, set TD tq @ 9k, 10-20 rpm, 3k tq. PU 97K, SO 75K;TIH w/ 4 1/2'' liner on 30 stds of 5'' DP no faster than 30 fpm, f/ 6631' to 9390', get parameters before exiting shoe @ 7770', PU 113k, SO 88K, TIH w/ stds HW to 11512', rotate thru tight spot f/ 10181' to 10207', 15 rpm, 5k tq, Easy in/out of the slips, pipe is auto filling, 7.9 bbl losses;M/U another std and TD, mark pipe, put 1/2 turn to right in, S/O to 11570' at sidetrack point, work pipe 30' up 4 x, work turn down hole, pass thru sidetrack point to 11605', RIH to 13010', set down 25k 2 times @ PB1 TD (attempt #1) PU 205K, SO 120K;TOOH f/ 13010' to 11560', M/U TD, rotate 15 rpm, 7 k tq, S/O real slow, to 11603', taking 15k wt f/ 11580' to 11603', TIH to 13010', set down 25k 2 times @ PB1 TD (attempt #2) PU 205K, SO 120K;TOOH f/ 13010' to 11515', M/U TD, Orient original mark + 60° plus three revolution to work torque down. Reciprocate f/ 11530' t/ 11570' 4x to work torque down to bent joint S/O @ 5'/min f/ 11570' t/ 11630', observed 2-5K weight f/ 11586' t/ 11604'.;TIH @ 30'/min, tagged 13010' two time w/ 25K @ PB1 TD (attempt #3) 11.5 bbls losses.;TOOH f/ 13010' to 11515', M/U TD, Orient original mark + 120° plus three revolution to work torque down. Reciprocate f/ 11530' t/ 11570' 4x to work torque down to bent joint. S/O @ 5'/min f/ 11570' t/ 11630', observed 5-7K weight f/ 11570' t/ 11630'.;TIH @ 30'/min, tagged 13010' two time w/ 25K @ PB1 TD (attempt #4) 13.6 bbls losses.;TOOH f/ 13010' to 11515', M/U TD, Orient original mark + 180° plus three revolution to work torque down. Reciprocate f/ 11530' t/ 11570' 4x to work torque down to bent joint. Pumped 20 bbls 9.35 ppg down DP due to pipe running over.;S/O @ 5'/min f/ 11570' t/ 11630', observed 2-5K weight f/ 11570' t/ 11630'. TIH @ 30'/min, tagged 13010' two time w/ 25K @ PB1 TD (attempt #5) 1.9 bbls losses.;TOOH f/ 13010' to 11515', M/U TD, Orient original mark + 240° plus three revolution to work torque down. Reciprocate f/ 11530' t/ 11570' 4x to work torque down to bent joint. 4.5 bbls losses.;Daily (midnight) losses = 46 bbls, Cumulative lateral losses = 423.1 bbls. H2O from L-Pad: 40 bbls Daily/ 13,520 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 114 bbls Daily / 19,019 bbls Total 8/10/2020 S/O @ 5'/min f/ 11570' to 11630', observed 2-5K weight f/ 11570' t/ 11630'. TIH @ 30'/min, tag at 13010' at PB1 set down 25k 2x;Decision made to TOOH for Geo-Pilot assy, TOOH f/ 13010' to 9390' racking 39 stds 5'' HWDP on DS, TOOH to 6536' at LTP racking 30 sts 5'' DP on ODS. L/D LTP, R/U 4-1/2'' handling equipment. 7.5 bbls losses.;PJSM, R/U 4-1/2'' handling equipment. TOOH from 6498' laying down 4-1/2'' lower completion to the pipe shed, pressure wash screens before L/D 2 bbls losses.;Clean & clear rig floor. R/D casing equipment. Mobilize BHA to the rig floor. Remove master bushings and install split bushings. Load & process 5" drill pipe 1 BPH losses.;M/U BHA #7: 8-1/2" SK616M-J1D bit, Geo-Pilot, MWD w/ ADR, DGR, PWD & DIR and stabilizer to 88'. Initialize MWD tools. Continue to M/U BHA f/ 88' t/ 275': float sub, 3 NMDC, float sub, HWDP, jar & HWDP. Installed corrosion ring in top of NMDC.;P/U 3 joints of 5" drill pipe to 365'. Break-in Geo-Pilot seals and pulse test MWD - 350 GPM, 370 PSI - good test. 1 BPH losses.;Single in the hole w/ 5" drill pipe f/ 365' t/ 941'. Nolosses. 1 bbl losses.;22 bbls daily losses, 445.1 bbls cumulative lateral losses. H2O from L-Pad: 35 bbls Daily/ 13,555 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 57 bbls Daily / 19,076 bbls Total 8/11/2020 Single in the hole w/ 5" drill pipe f/ 941' t/ 6939', fill pipe every 2000'. 141K PU / 87K SO. TIH on elevators f/ 6939' t/ 7699', 143K PU / 85K SO.;Slip & cut 53' of drilling line.;C/O saver sub, inspect & service top drive & drawworks, calibrate block height.;TIH on elevators f/ 7699' t/ 9889' then picked up singles f/ 9889' t/ 10460' Took 20K weight at 7884'. P/U then slack off again, made a few feet then took 40K. P/U w/ 28K overpull briefly. S/O with minimal drag. Work down 30' and back up again without problem.;Work through multiple areas of tight hole / drag, rotated 30 RPM at 8220', 8590', 9185', 9265', 9734', 10190' & 10338'. With only 35K down weight available, hole drag & tight hole was slowing us down too much. Decided to rotate down. Sim-ops: test MPD lines to 250 / 1400 PSI - good.;PJSM. Remove trip nipple & install MPD head. Fill lines - no leaks.;Ream in the hole due to drag f/ 10460' t/ 11791' 4 BPM, 660-820 PSI, 30 RPM, 10-15K TQ, 10-15'/min running speed to allow time to build stands in the mousehole. Slowed rotary to minimum 10-15 & running speed to 5-10'/min at sidetrack point f/ 11570' t/ 11615'. 157K PU / 50K SO / 117K ROT;Pull up and survey @ 11696' bit depth. Survey @ 11623' showed 94.45° inc, 194.93° azm. 0.67° higher than PB1 & 5.31° higher than final wellbore. PB1 was 93.78° inc, 194.99° azm. final wellbore was 89.76° inc, 192.23° azm. Determined to be in PB1 wellbore. Heavy sand & max gas of 1493u at bottoms up.;Never saw 8.8 ppg back to surface when circulating in the lateral. 10.25 ppg MW in / 10.3 ppg out MPD holding 90 PSI dymanic and 140 PSI static in preparation for light mud. Pressure built to 200 PSI on connection at bottoms up. Quit holding back pressure;Perform pressure check w/ MPD - none & line up to pump injection line to fill the hole through MPD equipment- not holding back pressure. POOH f/ 11696' t/ 10840'.;Daily losses = 19 bbls, Cumulative lateral losses = 464.1 bbls H2O from L-Pad: 100 bbls Daily/ 13,655 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 57 bbls Daily / 19,133 bbls Total 8/12/2020 CBU @ 336 GPM, 1100 PSI, 30 RPM, 10K TQ while reciprocate f/ 10840' t/ 10745'. Displace well to new 8.8 ppg Flo-Pro, 252 GPM, 860 PSI, 20 RPM, 10K TQ while reciprocate f/ 10840' t/ 10745'.;Perform openhole sidetrack @ 10750' as per DD, 495 GPM, 1670 PSI, 120 RPM, 13-15K TQ, 3-10K WOB. Orient 170°L & control drill f/ 10750' t/ 10770' @ 150'/hr. Increase to 200'/hr t/ 1010785' then 250'/hr to 10810'. At 10810' ABI increased f/ 92.07° t/ 92.34° on a hard streak.;P/U to 10780' & ream down @ 100'/hr. Hard drilling continued to 10820'. Drilled stand down to 10839'. 3° drop from PB2 wellbore, 90.8° inc. vs. 93.8°.;Backream f/ 10839' t/ 10739' three times. S/O f/ 10739' t/ 10839' w/ no pump or rotary. 145K PU / 65K SO / 110K ROT. MW 8.8 ppg in / 9.3 ppg out, vis 53 in / 53 out, max gas 268u, ECD 10.79.;Drill 8-1/2" injection lateral f/ 10839' t/ 11435', 596' drilled, 149'/hr AROP. 495 GPM, 1720 PSI, 120 RPM, 13K TQ, 8-13K WOB. 158K PU / 68K SO / 107K ROT. MW in 8.8 ppg, vis 44, max gas 843u, ECD 10.7. Pumped high vis sweep at 11316', back on time w/ no increase.;Drill 8-1/2" injection lateral f/ 11435' t/ 12171', 736' drilled, 113.23'/hr AROP. 480 GPM, 1710 PSI, 120 RPM, 13K TQ, 10K WOB. 167K PU / 64K SO / 103K ROT. MW in 8.8 ppg, vis 42, max gas 503u, ECD 10.63. Pumped high vis sweep at 11791', not seen.;Service top drive. Investigate noise from conveyor, found sprocket shaft bearing seized.;Replace #1 conveyor sprocket shaft and bearings. Circulate and condition while performing repairs, 380-410 GPM, 1200-1300 PSI, 60 RPM, 13K TQ, 10.45 ECD. Circulated 15600 stks, 2.5 bottoms up. ECD 10.45.;Drill 8-1/2" injection lateral f/ 12171' t/ 12361', 190' drilled, 95'/hr AROP. 490 GPM, 1810 PSI, 120 RPM, 13-14K TQ, 10K WOB. 160K PU / 64K SO / 105K ROT. MW in 8.9 ppg, vis 42, max gas 451u, ECD 10.79. MPD holding 190 PSI on connections, 70 PSI while drilling.;Last survey at 12291.59' MD / 3859.88' TVD, 92.23° inc, 195.43° azm, 60.7' from plan, 0.33' high and 30.70' left.;Daily losses = 64 bbls, Cumulative losses for lateral = 765.1 bbls H2O from L-Pad: 1,165 bbls Daily/ 14,820 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 1,334 bbls Daily / 20,467 bbls Total;Drilled 17 concretions for a total thickness of 80' (1.8% of the lateral). Two plugbacks have been drilled so far. 8/13/2020 Drill 8-1/2" injection lateral f/ 12361' t/ 12775' (3851' TVD) 414' drilled, 69'/hr AROP. 500 GPM, 1980 PSI, 120 RPM, 15K TQ, 15-18K WOB. 160K PU / 55K SO / 104K ROT 8.95 ppg MW, 40 vis, 10.91 ECD, 366u max gas. Fault #1 at 12450', NB sand to NB sand.;On rig power at 11:30, investigate rig connection to highline power. Drill 152' out of zone (12678' - 12830') above the NB sand due to fault #2 at 12678';Drill 8-1/2" injection lateral f/ 12775' t/ 13125' (3856' TVD) 350' drilled, 58.33'/hr AROP. 488 GPM, 1930 PSI, 120 RPM, 15K TQ, 7-20K WOB. 175K PU / no SO / 104K ROT. 8.9 ppg MW, 43 vis, 11.07 ECD, 671u max gas. Pumped hi vis sweep @ 13124', no increase observed.;Drill 8-1/2" injection lateral f/ 13125' t/ 13884' ( 3853' TVD) 759' drilled, 126.5'/hr AROP. 485 GPM, 2010 PSI, 120 RPM, 15K TQ, 5-12K WOB. 174K PU / no SO / 101K ROT. Lost SOW at 13125'. 8.85 ppg MW, 43 vis, 11.33 ECD, 504u max gas.;Drill 8-1/2" injection lateral f/ 13884' t/ 14100' (3861' TVD) 216' drilled, 144'/hr AROP. 475 GPM, 2080 PSI, 120 PRM, 16K TQ, 4-13K WOB. 168K PU / no SO / 100K ROT. 9.0 ppg MW / 42 vis, 11.65 ECD, 456u max gas.;Last survey at 14030.05' MD / 3859.13' TVD, 88.47° inc, 190.23° azm, 56' from plan, 50.75' low and 23.66' left. Sim-ops: Install diverter tee on L-62.;Pump 30 bbl lo vis sweep followed by 30 bbl hi vis 10.7 ppg sweep, 480 GPM, 2000 PSI, 120 RPM, 16K TQ. 9.0 ppg MW, 44 vis, 11.25 ECD, 568u max gas. Reciprocate f/ 14100' t/ 14013'. Sweep back 2000 stks late w/ 200% increase. Circulated 3.75 of 4x bottoms up. rack back a stand every BU to 13823';Daily losses = 24 bbls, Cumulative lateral losses = 789.1 bbls H2O from L-Pad: 910 bbls Daily/ 15,730 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 1,197 bbls Daily / 21,664 bbls Total 8/14/2020 Continue to circulate 4x bottoms up, 475 GPM, 1960 PSI, 120 RPM, 15K TQ. Add an additional 8000 strokes for washout based upon the sweep return. Reciprocate pipe to aid in hole cleaning. Racked back stands to 13853'.;Ream in the hole f/ 13853' t/ 13926', tagged with 25K. Ream past concretion f/ 13926' t/ 14100' w/ 450 GPM, 1960 PSI, 120 RPM, 15-20K TQ. Ream stand 4x slowly through tight spot until cleaned up.;Pump another sweep to clean up the hole after reaming tight spot, 480 GPM, 2250 PSI, 120 RPM, 17K TQ. Sweep back 2100 stks late w/ 5% increase. 168 PU / no SO / 100K ROT, 11.43 ECD.;PJSM. Displace to 8.45 ppg viscosified, lubricated brine. Rotate & reciprocate f/ 14100' t/ 14005'. Pump 30 bbl hi vis spacer, three 20 bbl SAPP pills separated by 50 bbls seawater, hi vis spacer then brine. 295 GPM, 950 ICP, 700 FCP, 60 RPM, 15-19K TQ. Good 8.45 ppg brine back, return to the pits.;10 bbls lost during displacement.;Continue to circulate until brine passes a PST. 295 GPM, 700 PSI, 60 RPM, 15K TQ. Observe sand coming out. Screen down from 170 to 200 shaker screens. Start centrifuges. Increase flow to 490 GPM, 1360 PSI., PST not passing. Slow to 350 GPM w/ 40 RPM for another bottoms up. PST pass w/ 7, 8 & 8 secs.;Obtain slow pump rates. 170K PU / 57K SO / 123K ROT. BROOH f/ 14100' t/ 10735', 500 GPM, 1450 PSI, 100-110 RPM, 19K TQ, 10.3 ECD. Laying down 5" drill pipe in the mousehole. MPD holding 190 PSI on connections & 90 PSI reaming. PST test @ 11625' passing after shakers, 5.5, 5.5 & 5.5 sec.;TIH f/ 10735' t/ 10839' with no pumps or rotary, 165K PU / 80K SO. Open hole sidetrack point at 10750'. Shoot MWD survey. 10769', 92.28° inc, 191.61° azm and ABI at 10832' 91.02° & 90.93° inc confirmed BHA in the correct wellbore. Pump out with no rotary f/ 10839' to 10750'.;BROOH f/ 10735' t/ 10355', 500 GPM, 1360 PSI, 110 RPM, 17K TQ. Laying down 5" drill pipe in the mousehole. MPD holding 190 PSI on connections & 90 PSI reaming. 16.1 bbls lost while BROOH.;Daily losses = 100 bbls, Cumulative lateral losses = 879.1 bbls H2O from L-Pad: 450 bbls Daily/ 16,180 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 2,509 bbls Daily / 24,173 bbls Total 8/15/2020 BROOH f/ 10355' t/ 9600', 500 GPM, 1380 PSI, 110 RPM, 15 TQ, 5 min/stand. Lay down drill pipe in the mousehole. 155K PU / 85K SO.;Service rig / Change fuse on draw works control in driller's console.;BROOH f/ 9600' t/ 7761' (inside 9-5/8" shoe), 500 GPM, 1250 PSI, 110 RPM, 12K TQ, 5 min/stand. Lay down drill pipe in the mousehole.;Pump 27 bbl high vis sweep, 550 GPM, 1470 PSI, 60 RPM, 8K TQ, reciprocate f/ 7761' t/ 7666'. Hole unloaded before sweep back, no increase from sweep. Circulated a total of 2.5 bottoms up, good passing PST before & after the shakers (5, 5 & 5 sec);Weight up mud pits f/ 8.8 ppg to 9.1 ppg then weight up on the fly, 7 BPM, 600 PSI, 60 RPM, 8K TQ. Weight up to 9.35 ppg on second circulation.;Monitor well through MPD 2" line. Initial 2 BPM flow slowed to static in one hour. Sim-ops: shut down rig power & investigate highline connection on rig. Electrician found loose connections on breaker to the bus caused heat damage. Replaced breaker.;PJSM, remove MPD RCD and install the trip nipple. Fill stack, check for leaks - air boot leaking. PJSM for laying down drill pipe.;POOH f/ 7761' t/ 3226' laying down 5" drill pipe. Pumped dry job at 7593' Drop 2.45" drift on 100' of wire. POOH racking back 31 stands of 5" drill pipe f/ 3226' t/ 275'.;L/D jar & 2 HWDP, 3 NMDC, float subs and stabilizer (1/16" under gauge). Read MWD tools - need to read ADR data in the pipe shed. L/D MWD tools, Geo-Pilot, near bit stabilizer & bit. Bit graded: 1-1-CT-N-X-I-WT-TD. 7.7 bbls lost on trip out from 7761'.;Clean & clear rig floor of BHA components. Mobilize 4-1/2" casing equipment to the rig floor. Remove split bushings & install master bushings. Rig up casing equipment.;Daily losses = 1 bbls, Cumulative losses for lateral = 880.1 bbls H2O from L-Pad: 275 bbls Daily/ 16,455 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 513 bbls Daily / 24,686 bbls Total 8/16/2020 Finish rigging up 4-1/2" elevators, slips and double stack hydraulic tongs to run liner.;P/U 4-1/2" eccentric solid shoe on shoe joint. Run 4-1/2" 13.5# L-80 Hydril 625 liner as per tally to 6499'. M/U Baker SLZXP packer to 6537'. Torque connections to 9600 ft/lbs with Doyon double stack tongs.;148 blank joints w/ 146 7.5" O.D. centralizers & stop rings installed. 11 RGL Pro-Mesh 250u screens & one Tendeka water swell packer ran. 9.5 bbls losses.;RIH w/ 4-1/2" liner on 31 drill pipe stands f/ 6537' t/ 9393' @ 30'/min. 130K PU / 85K SO. At 6622', pumped 2 BPM, 50 PSI & 4 BPM, 180 PSI to ensure clear flow path through liner running tool.;Single in the hole w/ 33 HWDP f/ 9393' t/ 10409' then RIH w/ HWDP stands f/ 10409' t/ 13010 @ 30'/min. 233K PU / 140K SO. At openhole sidetrack point, slow to 5'/min f/ 10750' t/ 10840'.;TIH w/ liner on 5" HWDP f/ 13010' t/ 14100' @ 30'/min, tag bottom with 15K. 245K PU / 137K SO P/U to 245K place string in tension. Circulate a drill pipe volume at 6 BPM, 790 PSI - 930 strokes. 13.7 bbls losses running liner on HWDP & drill pipe.;Drop 29/32" phenolic ball & pump down w/ 22 bbl high vis sweep. Ball on seat at 847 strokes. Pressure up set packer at 2860 PSI. Pressure up to 3200 PSI, hold for 1 min, then S/O to 100K. Pressure up to release, sheared at 4375 PSI. P/U observe travel @ 217K, verified release.;R/U test equipment. Close upper pipe rams on 5" drill pipe & pump down kill line. Test 7" x 9-5/8" packer to 1700 PSI for 10 min. on chart. Liner set @ 14100', TOL 7574'.;P/U f/ 7607' out of pack-off t/ 7598'. Circulate @ 7.5 BPM, 700 GPM. Slowly P/U to 7550'. L/D working joint + two singles. Circulate casing clean @ 10.8 BPM, 1310' PSI reciprocate f/ 7550' t/ 7450'. Mild sand over shakers while circulating, sweep ran over shakers then cleaned up after 650 more stks;Displace to 9.35 ppg 2% KCl/NaCl brine 8 BPM, 910 PSI. Pump 30 bbl high vis spacer then 525 bbls of brine. Dumped 35 bbls of interface before returning to the pits. Shut down, monitor for flow - slight rise in fluid.;Circulate a bottoms up at 11 BPM, 1820 PSI to ensure even fluid weight. Good 9.35 ppg in/out. 8.3 bbls losses. Flow check - slight breathing. Observe well on trip tank. Initial breathing of 0.25 bbl in 5 min to static in 45 min.;POOH laying down 5" HWDP f/ 7550' t/ 6445'. Losses 1 BPH.;Daily losses: 35 bbls, Cumulative lateral losses: 615.1 bbls. H2O from L-Pad: 100 bbls Daily/ 16,555 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 498 bbls Daily / 25,184 bbls Total 8/17/2020 POOH laying down 5" HWDP f/ 6445' t/ 2898' then laydown 5" drill pipe t/ 423'. 8 bbls losses.;Swap to completions AFE at 12:00. Please see completions report for details.;Daily Losses = 30 bbls, Cumulative lateral losses = 945.1 bbls H2O from L-Pad: 90 bbls Daily/ 16,645 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 860 bbls Daily / 26,044 bbls Total Liner set @ 14100', ;TIH w/ liner on 5" HWDP f/ 13010' t/ 14100' @ 30'/min, tag bottom with 15K. TOL 7574'.;P/U f/ 7607' oT Activity Date Ops Summary 8/17/2020 POOH laying down 5" HWDP f/ 6445' t/ 2898' then laydown 5" drill pipe t/ 423'. 8 bbls losses.,L/D 5" drill pipe f/ 424' t/ 43'. Monitor well, slight losses. L/D Baker liner running tool.,Clear & clean rig floor. Drain BOP stack & pull wear bushing. Flush BOP stack with Johnny Wacker, 510 GPM, 60 PSI. Blow down top drive. M/U hanger & landing joint. Make dummy run & mark landing joint.,R/U 7" casing equipment: Doyon double stack tongs, slips, elevators & M/U XO on FOSV.,P/U Baker bullet seal assembly to 15.37'. Run 7"26# L-80 TXP-BTC liner tie-back. Torque to 14,750 ft/lbs w/ Doyon double stack tongs. No-go w/ 10K at 36' in on joint #187, 7589.99' with locator at 7580.40'. Close annular, pressure up to 300 PSI in 7 strokes to verify seals engaged.,L/D joint #187. Torque circulating subs & XO. M/U landing joint & hanger - no space out subs required.Land hanger. R/U circulating equipment. Test lines to 2000 PSI. PJSM for displacement. Close annular, pressure up to 300 PSI & P/U until pressure dumps.,Pump 150 bbls of 9.35 ppg KCl/NaCl brine w/ 1% Concor 303 corrosion inhibitor, 4 BPM, 520 PSI. Pump 60 bbls of diesel freeze protection, 4 BPM, 490 PSI ICP, 700 PSI FCP. Slack off and land hanger, 90K SO (20K drag w/ annular closed),Blow down lines to cuttings tank & R/D same. L/D landing joint. RILD & test void to 500/5000 5 min/ 10 min. Good. R/U to test casing and baker seals. 7'' X 9 5/8. Pressure up to 1000 psi on OA on chart.,H2O from L-Pad: 90 bbls Daily/ 16,645 bbls Total H2O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 860 bbls Daily / 26,044 bbls Total 8/18/2020 Test 7'' X 9 5/8 to 1000 psi for 30 min. Charted.,R/U 3-1/2" handling equipment and Doyon casing double stack tongs. PJSM on running 3-1/2" 9.3# L-80 EUE Tubing,Pick up, 3-1/2” Mirage Plug / Autofill sub assembly, make up 7” x 3-1/2” PHL Hydraulic-Set Permal-Lach retrievable packer t/ 35’. Run 3-1/2" 9.3# L-80 EUE Tubing f/ 35’ t/ 762’. M/U XN Nipple, jt 3-1/2” tubing & 3-1/2” Gauge Carrier Assembly t/ 824’ Connect Tec wire to gauge assembly. Perform test on Tec wire. Good test,RIH with 3-1/2" 9.3# L-80 EUE Tubing f/ 824’ to 7501'. Install cannon clamp every connection jts #24-27. Install cannon clamp every other connection from jt #29-239 and one below the hanger pup jt. Test cable connection every 1000’. Losses @ 1 BPH,M/U 11" x 3-1/2" FMC tubing hanger and 5" landing joint. Terminate Tec wire. Drain BOP Stack & blow down surface lines. Land 3-1/2" tubing on tubing hanger @ 7583’ & RILS. L/D landing jt & install BPV 85K PU / 66K SO, 26K on hanger,Clear rig floor of tubing equipment. Remove mouseholes and trip nipple. N/D BOP stack and set on moving stump, prep wellhead & install dart in BPV,N/U tree. Well head rep test hanger void to 500 psi low for 5 min, 5000 psi high for 10 min. Test tree with diesel to 250 and 5000 psi. 5 min ea. charted. R/D test equipment, and pull BPV w/dart.,R/U to pump down IA & tubing. Test surface lines & reverse circulate 9.3 ppg corrosion inhibited brine down I/A, ICP 3 bpm, 500 psi,Daily Losses = 13 bbls, Cumulative lateral losses = 958.1 bbls H²O from L-Pad: 45 bbls Daily/ 16,690 bbls Total H²O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 285 bbls Daily / 26,329 bbls Total 8/19/2020 Finish reverse circulating 9.3 ppg corrosion inhibited brine down 7’’ X 3-1/2" IA. 187 bbls total pumped. 3 BPM, 520 psi. Reverse circulate 60 bbls diesel freeze protect down IA, 3 BPM, ICP = 380 psi, FCP = 730 psi.,Line up to the tubing and pressure up to 500. Hold for 5 min. Pressure up to 3600 psi & set packer. Hold for 10 min. Good Bleed tubing down to 1000 psi. Pressure up on the 7’’ X 3-1/2" IA to 2500 psi. ( MIT IA) Tubing pressure climbed to 1490 psi. Hold for 30 min. Good test,Bleed pressure off. Pressure up on tubing to 4075 psi & sheared out salt plug. Pressure bled to 0 Bullhead 28 bbls diesel down tubing freeze protecting to 3200',Secure tree, Flush mud pumps and lines with fresh H²O. and blow down same. Clean cellar box and prep for welder to cut & cap mousehole. Prep rig floor to skid into moving position. Release rig @ 12:00,RDMO. See L-62 Drilling Report for details.,H²O from L-Pad: 80 bbls Daily/ 16,770 bbls Total H²O from G&I Source Water: 0 bbls Daily / 1,200 bbls Total Cuttings/mud/cement to MPU G&I: 446 bbls Daily / 26,775 bbls Total 50-029-23683-00-00API #: Well Name: Field: County/State: MP L-61 Milne Point Hilcorp Energy Company Composite Report , Alaska Test 7'' X 9 5/8 to 1000 psi for 30 min. R/U to test casing and baker seals. 7'' X 9 5/8. Pressure up to 1000 psi on OA on chart. Pressure up on the 7’’ X 3-1/2" IA to 2500 psi. ( MIT IA) Tubing pressure climbed to 1490 psi. Hold for 30 min. Good test,B TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. 1 2 1 1 1 134 1 1 1 55 1 X Yes No X Yes No Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns? Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:Yes No Bump press Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: 1.17 7/22/2020 34 Spud Mud Lead Type I/II 855 2.35 Premium G Tail 400 1.15 5 2,274.89 Casing 9 5/8 47.0 L-80 TXP BTC-SR Tenaris 2,217.75 2,274.89 57.14 2,296.16 2,292.44 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 17.55 2,292.44 16.16 2,312.32 2,296.16 ES II Cementer 10 3/4 TXP BTC-SR HES 3.72 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 7,650.34 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 5,338.02 7,650.34 2,312.32 7,688.37 7,651.81 Baffle Adapter 10 3/4 TXP BTC-SR HES 1.47 7,651.81 1.30 7,689.67 7,688.37 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 36.56 Float Collar 10 3/4 TXP BTC-SR Innovex 104 total 9-5/8"x12-1/4" bowspring centralizers ran. 2 on joint #1 with 4 stop rings. 1 free floating on joint #2. 1 each mid-joint on #3&4 wit 4 stop rings. 1 each free floating on joints #5 to 26. 1 each free floating every other joint #28 to 48. 1 each free floating every third joint #51 to 129. 1 each free floating on joint #132 to 137. 1 each on pup joint above and below ES cementer w/ 2 stop rings. 1 each free floating on joint #138 to 146. 1 each free floating every other joint #148 to 190 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 78.67 7,768.34 7,689.67 Stage II G Tail 270 1.17 www.wellez.net WellEz Information Management LLC ver_04818br Bump Plug? 3.2 Ftg. Returned Ftg. Cut Jt.25.12 Ftg. Balance 16.08 No. Jts. Delivered No. Jts. Run Length Measurements W/O Threads Ftg. Delivered Ftg. Run 33.87 RKB to CHF Type of Shoe:Innovex Casing Crew:Doyon Rig 0 Spud Mud 12 358 9.1 3 31/31 ES II Cementer Closure OK 56 ArcticCem Type Premium G 270 Tuned Spacer 588 2.94 Stage Collar @ 60 Bump press 99 214 7,770.007,778.00 CEMENTING REPORT Csg Wt. On Slips:100,000 Spud Mud 0 19:27 7/26/2020 2,292 12:05 7/22/2020 2,296 2292 15.8 82 3 Bump press Returns to surface Bump Plug? Y 5 9.4 6 147.36/148.07 476.8/474.3 1290 1 RigFIRST STAGETOP OUT JOB10Tuned Spacer 60 15.8 700 9.4 6 2170 10 10.7 308 5 99 770 Bump Plug? Csg Wt. On Hook:350,000 Type Float Collar:Innovex No. Hrs to Run:20 9 5/8 47.0 L-80 TXP BTC-SR Tenaris TXP BTC-SR Innovex 1.66 7,770.00 7,768.34 25.12 57.14 32.02 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP L-61 Date Run 22-Jul-20 CASING RECORD County State Alaska Supv.D. Yessak / J. Vanderpool 7,688.00 Floats Held 9.7 54 054 15.8 54 Spud Mud Rotate Csg Recip Csg Ft. Min. PPG9.4 Shoe @ 7770 FC @ Top of Liner SECOND STAGERig 21:25 Returns to Surface 420 Casing (Or Liner) Detail Shoe Cut Joint of Casing 10 3/4 14 August, 2020 Milne Point M Pt L Pad MPU L-61i 500292368300 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61i Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i 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 Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU L-61i usft usft 0.00 0.00 6,031,863.02 544,814.39 15.70Wellhead Elevation:15.70 usft0.50 70° 29' 52.511 N 149° 38' 0.662 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU L-61i Model NameMagnetics IFR 7/24/2020 15.95 80.91 57,371.40000000 Phase:Version: Audit Notes: Design MPU L-61i 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:10,675.44 191.700.000.0033.87 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 8/14/2020 Survey Date 3_Gyro-GC_Csg H049Gb: North seeking on wireline in casing100.00 917.00 MPU L-61PB1 E-Line Gyro (MPU L-61PB 07/10/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa979.62 7,739.38 MPU L-61PB1 MWD+IFR2+MS+Sag (1) 07/17/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa7,823.29 10,675.44 MPU L-61PB1 MWD+IFR2+MS+Sag (2) 07/30/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa10,750.00 14,030.05 MPU L-61i MWD+IFR2+MS+Sag (5) (MP 08/11/2020 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 33.87 0.00 0.00 33.87 0.00 0.00-15.70 6,031,863.02 544,814.39 0.00 0.00 UNDEFINED 100.00 0.21 57.60 100.00 0.06 0.1050.43 6,031,863.09 544,814.49 0.32 -0.08 3_Gyro-GC_Csg (1) 200.00 0.32 304.44 200.00 0.32 0.03150.43 6,031,863.34 544,814.41 0.45 -0.32 3_Gyro-GC_Csg (1) 300.00 0.30 339.40 300.00 0.72 -0.30250.43 6,031,863.74 544,814.09 0.19 -0.65 3_Gyro-GC_Csg (1) 352.00 0.49 40.37 352.00 1.02 -0.20302.43 6,031,864.04 544,814.18 0.83 -0.96 3_Gyro-GC_Csg (1) 446.00 1.06 74.44 445.99 1.56 0.90396.42 6,031,864.59 544,815.28 0.75 -1.71 3_Gyro-GC_Csg (1) 539.00 3.05 92.95 538.92 1.66 4.20489.35 6,031,864.71 544,818.58 2.23 -2.48 3_Gyro-GC_Csg (1) 632.00 5.61 95.94 631.65 1.07 11.19582.08 6,031,864.15 544,825.57 2.76 -3.31 3_Gyro-GC_Csg (1) 728.00 8.82 98.93 726.88 -0.56 23.13677.31 6,031,862.60 544,837.52 3.37 -4.14 3_Gyro-GC_Csg (1) 823.00 11.05 95.81 820.45 -2.61 39.39770.88 6,031,860.64 544,853.79 2.41 -5.43 3_Gyro-GC_Csg (1) 917.00 14.72 89.14 912.07 -3.35 60.30862.50 6,031,860.04 544,874.70 4.21 -8.95 3_Gyro-GC_Csg (1) 8/14/2020 12:18:47PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61i Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 979.62 15.49 84.32 972.53 -2.40 76.58922.96 6,031,861.08 544,890.97 2.35 -13.18 3_MWD+IFR2+MS+Sag (2) 1,074.60 20.03 84.97 1,062.96 0.28 105.411,013.39 6,031,863.94 544,919.79 4.78 -21.65 3_MWD+IFR2+MS+Sag (2) 1,170.19 25.59 88.17 1,151.04 2.38 142.391,101.47 6,031,866.26 544,956.74 5.96 -31.20 3_MWD+IFR2+MS+Sag (2) 1,264.71 27.33 89.77 1,235.66 3.12 184.491,186.09 6,031,867.25 544,998.84 1.99 -40.46 3_MWD+IFR2+MS+Sag (2) 1,359.96 27.79 97.29 1,320.13 0.39 228.391,270.56 6,031,864.78 545,042.75 3.68 -46.69 3_MWD+IFR2+MS+Sag (2) 1,455.32 29.28 103.12 1,403.92 -7.73 273.171,354.35 6,031,856.94 545,087.57 3.31 -47.83 3_MWD+IFR2+MS+Sag (2) 1,549.45 28.73 108.79 1,486.26 -20.24 317.011,436.69 6,031,844.69 545,131.48 2.98 -44.46 3_MWD+IFR2+MS+Sag (2) 1,644.94 28.29 115.31 1,570.19 -37.31 359.201,520.62 6,031,827.88 545,173.78 3.29 -36.30 3_MWD+IFR2+MS+Sag (2) 1,739.98 31.51 125.40 1,652.62 -61.35 399.841,603.05 6,031,804.09 545,214.56 6.27 -21.01 3_MWD+IFR2+MS+Sag (2) 1,834.72 33.99 133.82 1,732.34 -94.05 439.161,682.77 6,031,771.63 545,254.06 5.47 3.04 3_MWD+IFR2+MS+Sag (2) 1,929.67 33.92 141.21 1,811.13 -133.09 474.921,761.56 6,031,732.80 545,290.06 4.35 34.02 3_MWD+IFR2+MS+Sag (2) 2,026.73 36.37 148.89 1,890.53 -178.87 506.781,840.96 6,031,687.22 545,322.19 5.20 72.39 3_MWD+IFR2+MS+Sag (2) 2,121.73 38.81 154.72 1,965.82 -229.93 534.061,916.25 6,031,636.33 545,349.77 4.54 116.85 3_MWD+IFR2+MS+Sag (2) 2,215.16 42.91 155.75 2,036.47 -285.43 559.631,986.90 6,031,581.00 545,375.68 4.45 166.01 3_MWD+IFR2+MS+Sag (2) 2,310.59 48.46 157.55 2,103.12 -348.11 586.642,053.55 6,031,518.49 545,403.06 5.97 221.91 3_MWD+IFR2+MS+Sag (2) 2,406.66 49.56 158.97 2,166.13 -415.47 613.492,116.56 6,031,451.30 545,430.31 1.60 282.43 3_MWD+IFR2+MS+Sag (2) 2,502.37 53.37 160.55 2,225.75 -485.70 639.362,176.18 6,031,381.23 545,456.60 4.18 345.96 3_MWD+IFR2+MS+Sag (2) 2,597.45 54.75 162.11 2,281.56 -558.63 663.992,231.99 6,031,308.46 545,481.67 1.97 412.37 3_MWD+IFR2+MS+Sag (2) 2,692.21 58.38 163.93 2,333.76 -634.25 687.052,284.19 6,031,232.99 545,505.19 4.15 481.75 3_MWD+IFR2+MS+Sag (2) 2,788.79 61.46 166.26 2,382.17 -715.00 708.522,332.60 6,031,152.37 545,527.14 3.81 556.47 3_MWD+IFR2+MS+Sag (2) 2,884.36 64.52 168.98 2,425.57 -798.15 726.742,376.00 6,031,069.34 545,545.86 4.08 634.19 3_MWD+IFR2+MS+Sag (2) 2,978.74 68.35 174.27 2,463.32 -883.69 739.282,413.75 6,030,983.89 545,558.91 6.55 715.41 3_MWD+IFR2+MS+Sag (2) 3,073.52 70.01 176.89 2,497.01 -972.01 746.092,447.44 6,030,895.63 545,566.25 3.12 800.51 3_MWD+IFR2+MS+Sag (2) 3,169.26 69.41 177.45 2,530.21 -1,061.69 750.532,480.64 6,030,805.97 545,571.23 0.83 887.44 3_MWD+IFR2+MS+Sag (2) 3,264.79 69.21 178.34 2,563.96 -1,151.00 753.812,514.39 6,030,716.70 545,575.05 0.90 974.22 3_MWD+IFR2+MS+Sag (2) 3,359.65 69.67 179.00 2,597.28 -1,239.79 755.872,547.71 6,030,627.93 545,577.65 0.81 1,060.75 3_MWD+IFR2+MS+Sag (2) 3,455.28 70.65 178.85 2,629.73 -1,329.73 757.562,580.16 6,030,538.01 545,579.88 1.04 1,148.48 3_MWD+IFR2+MS+Sag (2) 3,548.67 68.55 177.20 2,662.29 -1,417.20 760.562,612.72 6,030,450.57 545,583.41 2.79 1,233.53 3_MWD+IFR2+MS+Sag (2) 3,643.94 68.88 175.42 2,696.87 -1,505.79 766.282,647.30 6,030,362.03 545,589.66 1.78 1,319.11 3_MWD+IFR2+MS+Sag (2) 3,739.32 68.82 176.14 2,731.29 -1,594.50 772.832,681.72 6,030,273.36 545,596.74 0.71 1,404.65 3_MWD+IFR2+MS+Sag (2) 3,834.92 68.74 177.00 2,765.89 -1,683.46 778.162,716.32 6,030,184.45 545,602.61 0.84 1,490.68 3_MWD+IFR2+MS+Sag (2) 3,930.89 68.36 177.51 2,800.99 -1,772.68 782.442,751.42 6,030,095.27 545,607.42 0.63 1,577.18 3_MWD+IFR2+MS+Sag (2) 4,023.75 69.94 176.60 2,834.04 -1,859.34 786.902,784.47 6,030,008.64 545,612.41 1.93 1,661.13 3_MWD+IFR2+MS+Sag (2) 4,121.27 68.88 177.14 2,868.33 -1,950.49 791.882,818.76 6,029,917.53 545,617.94 1.20 1,749.38 3_MWD+IFR2+MS+Sag (2) 4,216.09 70.91 177.29 2,900.92 -2,039.42 796.212,851.35 6,029,828.63 545,622.80 2.15 1,835.59 3_MWD+IFR2+MS+Sag (2) 4,310.73 71.45 177.90 2,931.45 -2,128.92 799.972,881.88 6,029,739.17 545,627.10 0.84 1,922.47 3_MWD+IFR2+MS+Sag (2) 4,406.67 70.60 176.31 2,962.65 -2,219.53 804.552,913.08 6,029,648.60 545,632.22 1.80 2,010.26 3_MWD+IFR2+MS+Sag (2) 4,501.86 69.68 174.68 2,994.99 -2,308.78 811.572,945.42 6,029,559.40 545,639.79 1.88 2,096.23 3_MWD+IFR2+MS+Sag (2) 4,596.48 67.95 177.06 3,029.19 -2,396.76 817.942,979.62 6,029,471.47 545,646.68 2.97 2,181.10 3_MWD+IFR2+MS+Sag (2) 4,691.70 68.29 177.39 3,064.67 -2,485.02 822.223,015.10 6,029,383.25 545,651.49 0.48 2,266.65 3_MWD+IFR2+MS+Sag (2) 8/14/2020 12:18:47PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61i Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 4,786.01 68.22 177.79 3,099.61 -2,572.54 825.903,050.04 6,029,295.76 545,655.70 0.40 2,351.61 3_MWD+IFR2+MS+Sag (2) 4,882.45 69.20 178.81 3,134.63 -2,662.36 828.563,085.06 6,029,205.97 545,658.91 1.42 2,439.02 3_MWD+IFR2+MS+Sag (2) 4,978.16 69.15 179.27 3,168.66 -2,751.80 830.063,119.09 6,029,116.54 545,660.94 0.45 2,526.30 3_MWD+IFR2+MS+Sag (2) 5,073.31 69.41 178.15 3,202.32 -2,840.77 832.063,152.75 6,029,027.59 545,663.49 1.13 2,613.02 3_MWD+IFR2+MS+Sag (2) 5,168.81 70.47 175.25 3,235.08 -2,930.32 837.243,185.51 6,028,938.09 545,669.20 3.06 2,699.65 3_MWD+IFR2+MS+Sag (2) 5,263.79 69.14 173.84 3,267.87 -3,019.05 845.703,218.30 6,028,849.42 545,678.20 1.98 2,784.82 3_MWD+IFR2+MS+Sag (2) 5,359.04 70.28 174.69 3,300.90 -3,107.94 854.633,251.33 6,028,760.59 545,687.66 1.46 2,870.06 3_MWD+IFR2+MS+Sag (2) 5,454.66 70.85 175.32 3,332.72 -3,197.77 862.483,283.15 6,028,670.82 545,696.05 0.86 2,956.43 3_MWD+IFR2+MS+Sag (2) 5,550.52 68.99 177.13 3,365.63 -3,287.60 868.423,316.06 6,028,581.04 545,702.52 2.63 3,043.19 3_MWD+IFR2+MS+Sag (2) 5,644.58 70.15 177.49 3,398.46 -3,375.64 872.553,348.89 6,028,493.03 545,707.19 1.28 3,128.56 3_MWD+IFR2+MS+Sag (2) 5,740.19 70.79 178.02 3,430.43 -3,465.68 876.083,380.86 6,028,403.02 545,711.26 0.85 3,216.02 3_MWD+IFR2+MS+Sag (2) 5,835.42 69.21 176.53 3,463.00 -3,555.06 880.333,413.43 6,028,313.68 545,716.05 2.22 3,302.68 3_MWD+IFR2+MS+Sag (2) 5,931.21 70.28 177.56 3,496.16 -3,644.80 884.963,446.59 6,028,223.97 545,721.22 1.51 3,389.62 3_MWD+IFR2+MS+Sag (2) 6,026.69 69.00 177.27 3,529.38 -3,734.23 888.993,479.81 6,028,134.59 545,725.79 1.37 3,476.36 3_MWD+IFR2+MS+Sag (2) 6,122.07 69.02 178.10 3,563.55 -3,823.20 892.593,513.98 6,028,045.64 545,729.93 0.81 3,562.76 3_MWD+IFR2+MS+Sag (2) 6,217.28 68.35 178.27 3,598.15 -3,911.86 895.403,548.58 6,027,957.02 545,733.27 0.72 3,649.00 3_MWD+IFR2+MS+Sag (2) 6,311.25 68.22 178.28 3,632.92 -3,999.12 898.033,583.35 6,027,869.78 545,736.42 0.14 3,733.92 3_MWD+IFR2+MS+Sag (2) 6,407.06 69.80 179.33 3,667.24 -4,088.55 899.893,617.67 6,027,780.37 545,738.82 1.94 3,821.11 3_MWD+IFR2+MS+Sag (2) 6,502.07 70.92 179.71 3,699.17 -4,178.02 900.643,649.60 6,027,690.91 545,740.11 1.24 3,908.58 3_MWD+IFR2+MS+Sag (2) 6,598.49 70.27 178.75 3,731.21 -4,268.96 901.863,681.64 6,027,600.00 545,741.88 1.16 3,997.37 3_MWD+IFR2+MS+Sag (2) 6,692.81 70.32 178.35 3,763.01 -4,357.72 904.113,713.44 6,027,511.25 545,744.66 0.40 4,083.84 3_MWD+IFR2+MS+Sag (2) 6,787.70 70.14 176.30 3,795.11 -4,446.92 908.273,745.54 6,027,422.09 545,749.37 2.04 4,170.34 3_MWD+IFR2+MS+Sag (2) 6,883.36 68.40 176.69 3,828.97 -4,536.21 913.743,779.40 6,027,332.84 545,755.38 1.86 4,256.67 3_MWD+IFR2+MS+Sag (2) 6,978.10 69.00 176.79 3,863.39 -4,624.34 918.763,813.82 6,027,244.76 545,760.93 0.64 4,341.95 3_MWD+IFR2+MS+Sag (2) 7,072.45 70.73 180.67 3,895.87 -4,712.88 920.713,846.30 6,027,156.24 545,763.41 4.27 4,428.25 3_MWD+IFR2+MS+Sag (2) 7,167.67 75.25 182.82 3,923.72 -4,803.86 917.923,874.15 6,027,065.25 545,761.16 5.21 4,517.91 3_MWD+IFR2+MS+Sag (2) 7,263.20 80.38 184.72 3,943.88 -4,897.00 911.763,894.31 6,026,972.09 545,755.57 5.71 4,610.36 3_MWD+IFR2+MS+Sag (2) 7,358.72 79.94 187.06 3,960.21 -4,990.61 902.113,910.64 6,026,878.43 545,746.48 2.46 4,703.98 3_MWD+IFR2+MS+Sag (2) 7,453.67 85.05 189.23 3,972.61 -5,083.76 888.773,923.04 6,026,785.21 545,733.70 5.84 4,797.90 3_MWD+IFR2+MS+Sag (2) 7,549.57 87.77 188.90 3,978.61 -5,178.27 873.693,929.04 6,026,690.62 545,719.20 2.86 4,893.50 3_MWD+IFR2+MS+Sag (2) 7,645.23 88.69 188.73 3,981.57 -5,272.75 859.043,932.00 6,026,596.06 545,705.11 0.98 4,989.00 3_MWD+IFR2+MS+Sag (2) 7,739.38 92.03 191.74 3,980.98 -5,365.38 842.313,931.41 6,026,503.34 545,688.95 4.78 5,083.09 3_MWD+IFR2+MS+Sag (2) 7,823.29 91.67 192.21 3,978.27 -5,447.42 824.913,928.70 6,026,421.21 545,672.05 0.71 5,166.95 3_MWD+IFR2+MS+Sag (3) 7,918.30 90.87 192.97 3,976.16 -5,540.12 804.213,926.59 6,026,328.39 545,651.90 1.16 5,261.93 3_MWD+IFR2+MS+Sag (3) 8,013.14 91.55 193.91 3,974.16 -5,632.34 782.173,924.59 6,026,236.05 545,630.42 1.22 5,356.70 3_MWD+IFR2+MS+Sag (3) 8,107.61 92.29 191.76 3,970.99 -5,724.39 761.203,921.42 6,026,143.88 545,610.01 2.41 5,451.09 3_MWD+IFR2+MS+Sag (3) 8,203.14 92.48 192.34 3,967.02 -5,817.73 741.273,917.45 6,026,050.43 545,590.65 0.64 5,546.54 3_MWD+IFR2+MS+Sag (3) 8,298.40 91.18 191.71 3,963.98 -5,910.85 721.433,914.41 6,025,957.20 545,571.38 1.52 5,641.75 3_MWD+IFR2+MS+Sag (3) 8,393.25 91.06 191.73 3,962.12 -6,003.71 702.173,912.55 6,025,864.24 545,552.67 0.13 5,736.58 3_MWD+IFR2+MS+Sag (3) 8,487.76 91.37 190.52 3,960.12 -6,096.42 683.943,910.55 6,025,771.43 545,535.00 1.32 5,831.06 3_MWD+IFR2+MS+Sag (3) 8/14/2020 12:18:47PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61i Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,583.31 91.18 191.80 3,957.99 -6,190.14 665.453,908.42 6,025,677.61 545,517.08 1.35 5,926.58 3_MWD+IFR2+MS+Sag (3) 8,678.54 90.87 192.55 3,956.29 -6,283.21 645.373,906.72 6,025,584.43 545,497.57 0.85 6,021.79 3_MWD+IFR2+MS+Sag (3) 8,773.83 91.24 193.31 3,954.53 -6,376.07 624.053,904.96 6,025,491.45 545,476.81 0.89 6,117.04 3_MWD+IFR2+MS+Sag (3) 8,868.51 92.85 193.42 3,951.15 -6,468.12 602.183,901.58 6,025,399.28 545,455.50 1.70 6,211.62 3_MWD+IFR2+MS+Sag (3) 8,964.55 90.99 192.73 3,947.94 -6,561.61 580.473,898.37 6,025,305.67 545,434.35 2.07 6,307.57 3_MWD+IFR2+MS+Sag (3) 9,058.76 89.57 192.29 3,947.48 -6,653.58 560.063,897.91 6,025,213.58 545,414.50 1.58 6,401.77 3_MWD+IFR2+MS+Sag (3) 9,153.64 90.26 192.79 3,947.62 -6,746.20 539.463,898.05 6,025,120.85 545,394.46 0.90 6,496.64 3_MWD+IFR2+MS+Sag (3) 9,249.00 90.44 194.90 3,947.03 -6,838.78 516.643,897.46 6,025,028.14 545,372.20 2.22 6,591.92 3_MWD+IFR2+MS+Sag (3) 9,345.17 88.96 194.51 3,947.54 -6,931.80 492.233,897.97 6,024,934.99 545,348.36 1.59 6,687.96 3_MWD+IFR2+MS+Sag (3) 9,439.90 92.42 193.84 3,946.40 -7,023.62 469.043,896.83 6,024,843.04 545,325.72 3.72 6,782.58 3_MWD+IFR2+MS+Sag (3) 9,535.20 92.29 193.26 3,942.48 -7,116.19 446.733,892.91 6,024,750.35 545,303.97 0.62 6,877.75 3_MWD+IFR2+MS+Sag (3) 9,629.81 92.17 191.90 3,938.80 -7,208.46 426.143,889.23 6,024,657.97 545,283.94 1.44 6,972.27 3_MWD+IFR2+MS+Sag (3) 9,724.82 92.04 190.38 3,935.31 -7,301.61 407.803,885.74 6,024,564.71 545,266.16 1.60 7,067.21 3_MWD+IFR2+MS+Sag (3) 9,820.82 92.91 191.01 3,931.16 -7,395.86 390.003,881.59 6,024,470.37 545,248.93 1.12 7,163.10 3_MWD+IFR2+MS+Sag (3) 9,915.09 91.98 190.17 3,927.14 -7,488.43 372.693,877.57 6,024,377.70 545,232.18 1.33 7,257.27 3_MWD+IFR2+MS+Sag (3) 10,009.79 92.60 190.60 3,923.36 -7,581.51 355.633,873.79 6,024,284.54 545,215.69 0.80 7,351.87 3_MWD+IFR2+MS+Sag (3) 10,104.89 92.48 190.47 3,919.14 -7,674.91 338.263,869.57 6,024,191.04 545,198.88 0.19 7,446.85 3_MWD+IFR2+MS+Sag (3) 10,200.77 93.28 189.39 3,914.33 -7,769.23 321.753,864.76 6,024,096.63 545,182.94 1.40 7,542.56 3_MWD+IFR2+MS+Sag (3) 10,295.65 92.66 189.56 3,909.41 -7,862.69 306.153,859.84 6,024,003.08 545,167.91 0.68 7,637.25 3_MWD+IFR2+MS+Sag (3) 10,390.75 91.55 189.43 3,905.92 -7,956.43 290.473,856.35 6,023,909.27 545,152.80 1.18 7,732.21 3_MWD+IFR2+MS+Sag (3) 10,485.17 91.55 191.06 3,903.36 -8,049.30 273.693,853.79 6,023,816.30 545,136.57 1.73 7,826.56 3_MWD+IFR2+MS+Sag (3) 10,580.54 92.54 193.71 3,899.96 -8,142.39 253.253,850.39 6,023,723.10 545,116.70 2.96 7,921.85 3_MWD+IFR2+MS+Sag (3) 10,675.44 91.98 192.86 3,896.22 -8,234.67 231.463,846.65 6,023,630.70 545,095.47 1.07 8,016.64 3_MWD+IFR2+MS+Sag (3) 10,750.00 92.99 192.26 3,892.98 -8,307.38 215.263,843.41 6,023,557.90 545,079.71 1.58 8,091.12 3_MWD+IFR2+MS+Sag (4) 10,768.66 92.29 192.20 3,892.13 -8,325.60 211.313,842.56 6,023,539.66 545,075.87 3.77 8,109.76 3_MWD+IFR2+MS+Sag (4) 10,864.48 91.24 191.57 3,889.17 -8,419.32 191.593,839.60 6,023,445.84 545,056.71 1.28 8,205.53 3_MWD+IFR2+MS+Sag (4) 10,959.14 91.43 188.90 3,886.97 -8,512.44 174.773,837.40 6,023,352.62 545,040.46 2.83 8,300.13 3_MWD+IFR2+MS+Sag (4) 11,054.89 90.56 188.68 3,885.31 -8,607.05 160.143,835.74 6,023,257.94 545,026.41 0.94 8,395.74 3_MWD+IFR2+MS+Sag (4) 11,149.89 91.61 188.56 3,883.51 -8,700.95 145.913,833.94 6,023,163.95 545,012.74 1.11 8,490.58 3_MWD+IFR2+MS+Sag (4) 11,244.67 92.36 188.77 3,880.22 -8,794.60 131.643,830.65 6,023,070.24 544,999.03 0.82 8,585.17 3_MWD+IFR2+MS+Sag (4) 11,339.92 93.84 189.45 3,875.07 -8,888.50 116.583,825.50 6,022,976.25 544,984.54 1.71 8,680.18 3_MWD+IFR2+MS+Sag (4) 11,435.57 91.86 187.93 3,870.32 -8,982.93 102.153,820.75 6,022,881.75 544,970.68 2.61 8,775.58 3_MWD+IFR2+MS+Sag (4) 11,529.79 90.07 186.45 3,868.73 -9,076.39 90.363,819.16 6,022,788.23 544,959.46 2.46 8,869.49 3_MWD+IFR2+MS+Sag (4) 11,625.03 91.06 187.63 3,867.79 -9,170.91 78.693,818.22 6,022,693.65 544,948.36 1.62 8,964.40 3_MWD+IFR2+MS+Sag (4) 11,720.01 90.56 186.94 3,866.45 -9,265.11 66.643,816.88 6,022,599.39 544,936.88 0.90 9,059.09 3_MWD+IFR2+MS+Sag (4) 11,815.75 90.44 187.31 3,865.61 -9,360.11 54.773,816.04 6,022,504.33 544,925.58 0.41 9,154.52 3_MWD+IFR2+MS+Sag (4) 11,910.41 91.06 188.42 3,864.37 -9,453.86 41.823,814.80 6,022,410.50 544,913.20 1.34 9,248.96 3_MWD+IFR2+MS+Sag (4) 12,006.03 89.95 189.68 3,863.53 -9,548.29 26.783,813.96 6,022,316.00 544,898.73 1.76 9,344.47 3_MWD+IFR2+MS+Sag (4) 12,101.65 90.63 190.95 3,863.05 -9,642.36 9.663,813.48 6,022,221.84 544,882.18 1.51 9,440.06 3_MWD+IFR2+MS+Sag (4) 12,196.30 90.44 194.46 3,862.16 -9,734.67 -11.163,812.59 6,022,129.41 544,861.92 3.71 9,534.68 3_MWD+IFR2+MS+Sag (4) 8/14/2020 12:18:47PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61i Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 12,291.59 92.23 195.43 3,859.94 -9,826.71 -35.723,810.37 6,022,037.23 544,837.92 2.14 9,629.78 3_MWD+IFR2+MS+Sag (4) 12,387.61 91.67 194.46 3,856.68 -9,919.43 -60.473,807.11 6,021,944.38 544,813.73 1.17 9,725.59 3_MWD+IFR2+MS+Sag (4) 12,481.47 91.68 193.54 3,853.93 -10,010.46 -83.173,804.36 6,021,853.22 544,791.58 0.98 9,819.33 3_MWD+IFR2+MS+Sag (4) 12,576.71 90.93 192.82 3,851.76 -10,103.16 -104.883,802.19 6,021,760.39 544,770.44 1.09 9,914.52 3_MWD+IFR2+MS+Sag (4) 12,672.16 90.13 192.63 3,850.88 -10,196.26 -125.903,801.31 6,021,667.18 544,749.98 0.86 10,009.95 3_MWD+IFR2+MS+Sag (4) 12,766.34 88.59 192.18 3,851.93 -10,288.24 -146.133,802.36 6,021,575.09 544,730.30 1.70 10,104.11 3_MWD+IFR2+MS+Sag (4) 12,862.66 87.79 193.37 3,854.97 -10,382.12 -167.423,805.40 6,021,481.09 544,709.58 1.49 10,200.36 3_MWD+IFR2+MS+Sag (4) 12,958.17 91.25 194.42 3,855.77 -10,474.82 -190.353,806.20 6,021,388.27 544,687.21 3.79 10,295.78 3_MWD+IFR2+MS+Sag (4) 13,053.13 89.88 194.32 3,854.84 -10,566.80 -213.913,805.27 6,021,296.15 544,664.21 1.45 10,390.63 3_MWD+IFR2+MS+Sag (4) 13,148.34 89.58 193.80 3,855.29 -10,659.16 -237.043,805.72 6,021,203.67 544,641.64 0.63 10,485.76 3_MWD+IFR2+MS+Sag (4) 13,243.65 90.57 193.04 3,855.16 -10,751.86 -259.163,805.59 6,021,110.84 544,620.08 1.31 10,581.03 3_MWD+IFR2+MS+Sag (4) 13,338.77 90.63 192.02 3,854.17 -10,844.71 -279.803,804.60 6,021,017.88 544,600.00 1.07 10,676.13 3_MWD+IFR2+MS+Sag (4) 13,433.88 90.01 192.81 3,853.63 -10,937.60 -300.253,804.06 6,020,924.88 544,580.12 1.06 10,771.23 3_MWD+IFR2+MS+Sag (4) 13,528.70 88.96 192.43 3,854.49 -11,030.12 -320.963,804.92 6,020,832.24 544,559.96 1.18 10,866.03 3_MWD+IFR2+MS+Sag (4) 13,624.56 89.27 191.20 3,855.97 -11,123.94 -340.593,806.40 6,020,738.32 544,540.91 1.32 10,961.88 3_MWD+IFR2+MS+Sag (4) 13,719.34 90.20 191.62 3,856.41 -11,216.84 -359.343,806.84 6,020,645.31 544,522.72 1.08 11,056.65 3_MWD+IFR2+MS+Sag (4) 13,814.63 89.08 192.84 3,857.00 -11,309.96 -379.523,807.43 6,020,552.08 544,503.10 1.74 11,151.94 3_MWD+IFR2+MS+Sag (4) 13,908.94 90.38 192.37 3,857.45 -11,402.00 -400.103,807.88 6,020,459.93 544,483.08 1.47 11,246.23 3_MWD+IFR2+MS+Sag (4) 14,004.11 88.40 191.15 3,858.46 -11,495.16 -419.503,808.89 6,020,366.67 544,464.25 2.44 11,341.39 3_MWD+IFR2+MS+Sag (4) 14,030.05 88.47 190.23 3,859.17 -11,520.64 -424.313,809.60 6,020,341.16 544,459.59 3.56 11,367.31 3_MWD+IFR2+MS+Sag (4) 14,100.00 88.47 190.23 3,861.04 -11,589.45 -436.723,811.47 6,020,272.28 544,447.59 0.00 11,437.22 PROJECTED to TD Approved By:Checked By:Date: 8/14/2020 12:18:47PM COMPASS 5000.15 Build 91E Page 6 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.08.14 09:23:14 -08'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.08.14 12:26:23 -08'00' 04 August, 2020 Milne Point M Pt L Pad MPU L-61PB1 500292368370 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61PB1 Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61PB1 Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i 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 Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU L-61i usft usft 0.00 0.00 6,031,863.02 544,814.39 15.70Wellhead Elevation:15.70 usft0.50 70° 29' 52.511 N 149° 38' 0.662 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU L-61PB1 Model NameMagnetics IFR 7/24/2020 15.95 80.91 57,371.40000000 Phase:Version: Audit Notes: Design MPU L-61PB1 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.87 191.700.000.0033.87 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 8/1/2020 Survey Date 3_Gyro-GC_Csg H049Gb: North seeking on wireline in casing100.00 917.00 MPU L-61PB1 E-Line Gyro (MPU L-61PB 07/10/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa979.62 7,739.38 MPU L-61PB1 MWD+IFR2+MS+Sag (1) 07/17/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa7,823.29 12,936.99 MPU L-61PB1 MWD+IFR2+MS+Sag (2) 07/30/2020 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 33.87 0.00 0.00 33.87 0.00 0.00-15.70 6,031,863.02 544,814.39 0.00 0.00 UNDEFINED 100.00 0.21 57.60 100.00 0.06 0.1050.43 6,031,863.09 544,814.49 0.32 -0.08 3_Gyro-GC_Csg (1) 200.00 0.32 304.44 200.00 0.32 0.03150.43 6,031,863.34 544,814.41 0.45 -0.32 3_Gyro-GC_Csg (1) 300.00 0.30 339.40 300.00 0.72 -0.30250.43 6,031,863.74 544,814.09 0.19 -0.65 3_Gyro-GC_Csg (1) 352.00 0.49 40.37 352.00 1.02 -0.20302.43 6,031,864.04 544,814.18 0.83 -0.96 3_Gyro-GC_Csg (1) 446.00 1.06 74.44 445.99 1.56 0.90396.42 6,031,864.59 544,815.28 0.75 -1.71 3_Gyro-GC_Csg (1) 539.00 3.05 92.95 538.92 1.66 4.20489.35 6,031,864.71 544,818.58 2.23 -2.48 3_Gyro-GC_Csg (1) 632.00 5.61 95.94 631.65 1.07 11.19582.08 6,031,864.15 544,825.57 2.76 -3.31 3_Gyro-GC_Csg (1) 728.00 8.82 98.93 726.88 -0.56 23.13677.31 6,031,862.60 544,837.52 3.37 -4.14 3_Gyro-GC_Csg (1) 823.00 11.05 95.81 820.45 -2.61 39.39770.88 6,031,860.64 544,853.79 2.41 -5.43 3_Gyro-GC_Csg (1) 917.00 14.72 89.14 912.07 -3.35 60.30862.50 6,031,860.04 544,874.70 4.21 -8.95 3_Gyro-GC_Csg (1) 979.62 15.49 84.32 972.53 -2.40 76.58922.96 6,031,861.08 544,890.97 2.35 -13.18 3_MWD+IFR2+MS+Sag (2) 8/4/2020 10:42:56AM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61PB1 Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61PB1 Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 1,074.60 20.03 84.97 1,062.96 0.28 105.411,013.39 6,031,863.94 544,919.79 4.78 -21.65 3_MWD+IFR2+MS+Sag (2) 1,170.19 25.59 88.17 1,151.04 2.38 142.391,101.47 6,031,866.26 544,956.74 5.96 -31.20 3_MWD+IFR2+MS+Sag (2) 1,264.71 27.33 89.77 1,235.66 3.12 184.491,186.09 6,031,867.25 544,998.84 1.99 -40.46 3_MWD+IFR2+MS+Sag (2) 1,359.96 27.79 97.29 1,320.13 0.39 228.391,270.56 6,031,864.78 545,042.75 3.68 -46.69 3_MWD+IFR2+MS+Sag (2) 1,455.32 29.28 103.12 1,403.92 -7.73 273.171,354.35 6,031,856.94 545,087.57 3.31 -47.83 3_MWD+IFR2+MS+Sag (2) 1,549.45 28.73 108.79 1,486.26 -20.24 317.011,436.69 6,031,844.69 545,131.48 2.98 -44.46 3_MWD+IFR2+MS+Sag (2) 1,644.94 28.29 115.31 1,570.19 -37.31 359.201,520.62 6,031,827.88 545,173.78 3.29 -36.30 3_MWD+IFR2+MS+Sag (2) 1,739.98 31.51 125.40 1,652.62 -61.35 399.841,603.05 6,031,804.09 545,214.56 6.27 -21.01 3_MWD+IFR2+MS+Sag (2) 1,834.72 33.99 133.82 1,732.34 -94.05 439.161,682.77 6,031,771.63 545,254.06 5.47 3.04 3_MWD+IFR2+MS+Sag (2) 1,929.67 33.92 141.21 1,811.13 -133.09 474.921,761.56 6,031,732.80 545,290.06 4.35 34.02 3_MWD+IFR2+MS+Sag (2) 2,026.73 36.37 148.89 1,890.53 -178.87 506.781,840.96 6,031,687.22 545,322.19 5.20 72.39 3_MWD+IFR2+MS+Sag (2) 2,121.73 38.81 154.72 1,965.82 -229.93 534.061,916.25 6,031,636.33 545,349.77 4.54 116.85 3_MWD+IFR2+MS+Sag (2) 2,215.16 42.91 155.75 2,036.47 -285.43 559.631,986.90 6,031,581.00 545,375.68 4.45 166.01 3_MWD+IFR2+MS+Sag (2) 2,310.59 48.46 157.55 2,103.12 -348.11 586.642,053.55 6,031,518.49 545,403.06 5.97 221.91 3_MWD+IFR2+MS+Sag (2) 2,406.66 49.56 158.97 2,166.13 -415.47 613.492,116.56 6,031,451.30 545,430.31 1.60 282.43 3_MWD+IFR2+MS+Sag (2) 2,502.37 53.37 160.55 2,225.75 -485.70 639.362,176.18 6,031,381.23 545,456.60 4.18 345.96 3_MWD+IFR2+MS+Sag (2) 2,597.45 54.75 162.11 2,281.56 -558.63 663.992,231.99 6,031,308.46 545,481.67 1.97 412.37 3_MWD+IFR2+MS+Sag (2) 2,692.21 58.38 163.93 2,333.76 -634.25 687.052,284.19 6,031,232.99 545,505.19 4.15 481.75 3_MWD+IFR2+MS+Sag (2) 2,788.79 61.46 166.26 2,382.17 -715.00 708.522,332.60 6,031,152.37 545,527.14 3.81 556.47 3_MWD+IFR2+MS+Sag (2) 2,884.36 64.52 168.98 2,425.57 -798.15 726.742,376.00 6,031,069.34 545,545.86 4.08 634.19 3_MWD+IFR2+MS+Sag (2) 2,978.74 68.35 174.27 2,463.32 -883.69 739.282,413.75 6,030,983.89 545,558.91 6.55 715.41 3_MWD+IFR2+MS+Sag (2) 3,073.52 70.01 176.89 2,497.01 -972.01 746.092,447.44 6,030,895.63 545,566.25 3.12 800.51 3_MWD+IFR2+MS+Sag (2) 3,169.26 69.41 177.45 2,530.21 -1,061.69 750.532,480.64 6,030,805.97 545,571.23 0.83 887.44 3_MWD+IFR2+MS+Sag (2) 3,264.79 69.21 178.34 2,563.96 -1,151.00 753.812,514.39 6,030,716.70 545,575.05 0.90 974.22 3_MWD+IFR2+MS+Sag (2) 3,359.65 69.67 179.00 2,597.28 -1,239.79 755.872,547.71 6,030,627.93 545,577.65 0.81 1,060.75 3_MWD+IFR2+MS+Sag (2) 3,455.28 70.65 178.85 2,629.73 -1,329.73 757.562,580.16 6,030,538.01 545,579.88 1.04 1,148.48 3_MWD+IFR2+MS+Sag (2) 3,548.67 68.55 177.20 2,662.29 -1,417.20 760.562,612.72 6,030,450.57 545,583.41 2.79 1,233.53 3_MWD+IFR2+MS+Sag (2) 3,643.94 68.88 175.42 2,696.87 -1,505.79 766.282,647.30 6,030,362.03 545,589.66 1.78 1,319.11 3_MWD+IFR2+MS+Sag (2) 3,739.32 68.82 176.14 2,731.29 -1,594.50 772.832,681.72 6,030,273.36 545,596.74 0.71 1,404.65 3_MWD+IFR2+MS+Sag (2) 3,834.92 68.74 177.00 2,765.89 -1,683.46 778.162,716.32 6,030,184.45 545,602.61 0.84 1,490.68 3_MWD+IFR2+MS+Sag (2) 3,930.89 68.36 177.51 2,800.99 -1,772.68 782.442,751.42 6,030,095.27 545,607.42 0.63 1,577.18 3_MWD+IFR2+MS+Sag (2) 4,023.75 69.94 176.60 2,834.04 -1,859.34 786.902,784.47 6,030,008.64 545,612.41 1.93 1,661.13 3_MWD+IFR2+MS+Sag (2) 4,121.27 68.88 177.14 2,868.33 -1,950.49 791.882,818.76 6,029,917.53 545,617.94 1.20 1,749.38 3_MWD+IFR2+MS+Sag (2) 4,216.09 70.91 177.29 2,900.92 -2,039.42 796.212,851.35 6,029,828.63 545,622.80 2.15 1,835.59 3_MWD+IFR2+MS+Sag (2) 4,310.73 71.45 177.90 2,931.45 -2,128.92 799.972,881.88 6,029,739.17 545,627.10 0.84 1,922.47 3_MWD+IFR2+MS+Sag (2) 4,406.67 70.60 176.31 2,962.65 -2,219.53 804.552,913.08 6,029,648.60 545,632.22 1.80 2,010.26 3_MWD+IFR2+MS+Sag (2) 4,501.86 69.68 174.68 2,994.99 -2,308.78 811.572,945.42 6,029,559.40 545,639.79 1.88 2,096.23 3_MWD+IFR2+MS+Sag (2) 4,596.48 67.95 177.06 3,029.19 -2,396.76 817.942,979.62 6,029,471.47 545,646.68 2.97 2,181.10 3_MWD+IFR2+MS+Sag (2) 4,691.70 68.29 177.39 3,064.67 -2,485.02 822.223,015.10 6,029,383.25 545,651.49 0.48 2,266.65 3_MWD+IFR2+MS+Sag (2) 4,786.01 68.22 177.79 3,099.61 -2,572.54 825.903,050.04 6,029,295.76 545,655.70 0.40 2,351.61 3_MWD+IFR2+MS+Sag (2) 8/4/2020 10:42:56AM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61PB1 Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61PB1 Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 4,882.45 69.20 178.81 3,134.63 -2,662.36 828.563,085.06 6,029,205.97 545,658.91 1.42 2,439.02 3_MWD+IFR2+MS+Sag (2) 4,978.16 69.15 179.27 3,168.66 -2,751.80 830.063,119.09 6,029,116.54 545,660.94 0.45 2,526.30 3_MWD+IFR2+MS+Sag (2) 5,073.31 69.41 178.15 3,202.32 -2,840.77 832.063,152.75 6,029,027.59 545,663.49 1.13 2,613.02 3_MWD+IFR2+MS+Sag (2) 5,168.81 70.47 175.25 3,235.08 -2,930.32 837.243,185.51 6,028,938.09 545,669.20 3.06 2,699.65 3_MWD+IFR2+MS+Sag (2) 5,263.79 69.14 173.84 3,267.87 -3,019.05 845.703,218.30 6,028,849.42 545,678.20 1.98 2,784.82 3_MWD+IFR2+MS+Sag (2) 5,359.04 70.28 174.69 3,300.90 -3,107.94 854.633,251.33 6,028,760.59 545,687.66 1.46 2,870.06 3_MWD+IFR2+MS+Sag (2) 5,454.66 70.85 175.32 3,332.72 -3,197.77 862.483,283.15 6,028,670.82 545,696.05 0.86 2,956.43 3_MWD+IFR2+MS+Sag (2) 5,550.52 68.99 177.13 3,365.63 -3,287.60 868.423,316.06 6,028,581.04 545,702.52 2.63 3,043.19 3_MWD+IFR2+MS+Sag (2) 5,644.58 70.15 177.49 3,398.46 -3,375.64 872.553,348.89 6,028,493.03 545,707.19 1.28 3,128.56 3_MWD+IFR2+MS+Sag (2) 5,740.19 70.79 178.02 3,430.43 -3,465.68 876.083,380.86 6,028,403.02 545,711.26 0.85 3,216.02 3_MWD+IFR2+MS+Sag (2) 5,835.42 69.21 176.53 3,463.00 -3,555.06 880.333,413.43 6,028,313.68 545,716.05 2.22 3,302.68 3_MWD+IFR2+MS+Sag (2) 5,931.21 70.28 177.56 3,496.16 -3,644.80 884.963,446.59 6,028,223.97 545,721.22 1.51 3,389.62 3_MWD+IFR2+MS+Sag (2) 6,026.69 69.00 177.27 3,529.38 -3,734.23 888.993,479.81 6,028,134.59 545,725.79 1.37 3,476.36 3_MWD+IFR2+MS+Sag (2) 6,122.07 69.02 178.10 3,563.55 -3,823.20 892.593,513.98 6,028,045.64 545,729.93 0.81 3,562.76 3_MWD+IFR2+MS+Sag (2) 6,217.28 68.35 178.27 3,598.15 -3,911.86 895.403,548.58 6,027,957.02 545,733.27 0.72 3,649.00 3_MWD+IFR2+MS+Sag (2) 6,311.25 68.22 178.28 3,632.92 -3,999.12 898.033,583.35 6,027,869.78 545,736.42 0.14 3,733.92 3_MWD+IFR2+MS+Sag (2) 6,407.06 69.80 179.33 3,667.24 -4,088.55 899.893,617.67 6,027,780.37 545,738.82 1.94 3,821.11 3_MWD+IFR2+MS+Sag (2) 6,502.07 70.92 179.71 3,699.17 -4,178.02 900.643,649.60 6,027,690.91 545,740.11 1.24 3,908.58 3_MWD+IFR2+MS+Sag (2) 6,598.49 70.27 178.75 3,731.21 -4,268.96 901.863,681.64 6,027,600.00 545,741.88 1.16 3,997.37 3_MWD+IFR2+MS+Sag (2) 6,692.81 70.32 178.35 3,763.01 -4,357.72 904.113,713.44 6,027,511.25 545,744.66 0.40 4,083.84 3_MWD+IFR2+MS+Sag (2) 6,787.70 70.14 176.30 3,795.11 -4,446.92 908.273,745.54 6,027,422.09 545,749.37 2.04 4,170.34 3_MWD+IFR2+MS+Sag (2) 6,883.36 68.40 176.69 3,828.97 -4,536.21 913.743,779.40 6,027,332.84 545,755.38 1.86 4,256.67 3_MWD+IFR2+MS+Sag (2) 6,978.10 69.00 176.79 3,863.39 -4,624.34 918.763,813.82 6,027,244.76 545,760.93 0.64 4,341.95 3_MWD+IFR2+MS+Sag (2) 7,072.45 70.73 180.67 3,895.87 -4,712.88 920.713,846.30 6,027,156.24 545,763.41 4.27 4,428.25 3_MWD+IFR2+MS+Sag (2) 7,167.67 75.25 182.82 3,923.72 -4,803.86 917.923,874.15 6,027,065.25 545,761.16 5.21 4,517.91 3_MWD+IFR2+MS+Sag (2) 7,263.20 80.38 184.72 3,943.88 -4,897.00 911.763,894.31 6,026,972.09 545,755.57 5.71 4,610.36 3_MWD+IFR2+MS+Sag (2) 7,358.72 79.94 187.06 3,960.21 -4,990.61 902.113,910.64 6,026,878.43 545,746.48 2.46 4,703.98 3_MWD+IFR2+MS+Sag (2) 7,453.67 85.05 189.23 3,972.61 -5,083.76 888.773,923.04 6,026,785.21 545,733.70 5.84 4,797.90 3_MWD+IFR2+MS+Sag (2) 7,549.57 87.77 188.90 3,978.61 -5,178.27 873.693,929.04 6,026,690.62 545,719.20 2.86 4,893.50 3_MWD+IFR2+MS+Sag (2) 7,645.23 88.69 188.73 3,981.57 -5,272.75 859.043,932.00 6,026,596.06 545,705.11 0.98 4,989.00 3_MWD+IFR2+MS+Sag (2) 7,739.38 92.03 191.74 3,980.98 -5,365.38 842.313,931.41 6,026,503.34 545,688.95 4.78 5,083.09 3_MWD+IFR2+MS+Sag (2) 7,823.29 91.67 192.21 3,978.27 -5,447.42 824.913,928.70 6,026,421.21 545,672.05 0.71 5,166.95 3_MWD+IFR2+MS+Sag (3) 7,918.30 90.87 192.97 3,976.16 -5,540.12 804.213,926.59 6,026,328.39 545,651.90 1.16 5,261.93 3_MWD+IFR2+MS+Sag (3) 8,013.14 91.55 193.91 3,974.16 -5,632.34 782.173,924.59 6,026,236.05 545,630.42 1.22 5,356.70 3_MWD+IFR2+MS+Sag (3) 8,107.61 92.29 191.76 3,970.99 -5,724.39 761.203,921.42 6,026,143.88 545,610.01 2.41 5,451.09 3_MWD+IFR2+MS+Sag (3) 8,203.14 92.48 192.34 3,967.02 -5,817.73 741.273,917.45 6,026,050.43 545,590.65 0.64 5,546.54 3_MWD+IFR2+MS+Sag (3) 8,298.40 91.18 191.71 3,963.98 -5,910.85 721.433,914.41 6,025,957.20 545,571.38 1.52 5,641.75 3_MWD+IFR2+MS+Sag (3) 8,393.25 91.06 191.73 3,962.12 -6,003.71 702.173,912.55 6,025,864.24 545,552.67 0.13 5,736.58 3_MWD+IFR2+MS+Sag (3) 8,487.76 91.37 190.52 3,960.12 -6,096.42 683.943,910.55 6,025,771.43 545,535.00 1.32 5,831.06 3_MWD+IFR2+MS+Sag (3) 8,583.31 91.18 191.80 3,957.99 -6,190.14 665.453,908.42 6,025,677.61 545,517.08 1.35 5,926.58 3_MWD+IFR2+MS+Sag (3) 8/4/2020 10:42:56AM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61PB1 Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61PB1 Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,678.54 90.87 192.55 3,956.29 -6,283.21 645.373,906.72 6,025,584.43 545,497.57 0.85 6,021.79 3_MWD+IFR2+MS+Sag (3) 8,773.83 91.24 193.31 3,954.53 -6,376.07 624.053,904.96 6,025,491.45 545,476.81 0.89 6,117.04 3_MWD+IFR2+MS+Sag (3) 8,868.51 92.85 193.42 3,951.15 -6,468.12 602.183,901.58 6,025,399.28 545,455.50 1.70 6,211.62 3_MWD+IFR2+MS+Sag (3) 8,964.55 90.99 192.73 3,947.94 -6,561.61 580.473,898.37 6,025,305.67 545,434.35 2.07 6,307.57 3_MWD+IFR2+MS+Sag (3) 9,058.76 89.57 192.29 3,947.48 -6,653.58 560.063,897.91 6,025,213.58 545,414.50 1.58 6,401.77 3_MWD+IFR2+MS+Sag (3) 9,153.64 90.26 192.79 3,947.62 -6,746.20 539.463,898.05 6,025,120.85 545,394.46 0.90 6,496.64 3_MWD+IFR2+MS+Sag (3) 9,249.00 90.44 194.90 3,947.03 -6,838.78 516.643,897.46 6,025,028.14 545,372.20 2.22 6,591.92 3_MWD+IFR2+MS+Sag (3) 9,345.17 88.96 194.51 3,947.54 -6,931.80 492.233,897.97 6,024,934.99 545,348.36 1.59 6,687.96 3_MWD+IFR2+MS+Sag (3) 9,439.90 92.42 193.84 3,946.40 -7,023.62 469.043,896.83 6,024,843.04 545,325.72 3.72 6,782.58 3_MWD+IFR2+MS+Sag (3) 9,535.20 92.29 193.26 3,942.48 -7,116.19 446.733,892.91 6,024,750.35 545,303.97 0.62 6,877.75 3_MWD+IFR2+MS+Sag (3) 9,629.81 92.17 191.90 3,938.80 -7,208.46 426.143,889.23 6,024,657.97 545,283.94 1.44 6,972.27 3_MWD+IFR2+MS+Sag (3) 9,724.82 92.04 190.38 3,935.31 -7,301.61 407.803,885.74 6,024,564.71 545,266.16 1.60 7,067.21 3_MWD+IFR2+MS+Sag (3) 9,820.82 92.91 191.01 3,931.16 -7,395.86 390.003,881.59 6,024,470.37 545,248.93 1.12 7,163.10 3_MWD+IFR2+MS+Sag (3) 9,915.09 91.98 190.17 3,927.14 -7,488.43 372.693,877.57 6,024,377.70 545,232.18 1.33 7,257.27 3_MWD+IFR2+MS+Sag (3) 10,009.79 92.60 190.60 3,923.36 -7,581.51 355.633,873.79 6,024,284.54 545,215.69 0.80 7,351.87 3_MWD+IFR2+MS+Sag (3) 10,104.89 92.48 190.47 3,919.14 -7,674.91 338.263,869.57 6,024,191.04 545,198.88 0.19 7,446.85 3_MWD+IFR2+MS+Sag (3) 10,200.77 93.28 189.39 3,914.33 -7,769.23 321.753,864.76 6,024,096.63 545,182.94 1.40 7,542.56 3_MWD+IFR2+MS+Sag (3) 10,295.65 92.66 189.56 3,909.41 -7,862.69 306.153,859.84 6,024,003.08 545,167.91 0.68 7,637.25 3_MWD+IFR2+MS+Sag (3) 10,390.75 91.55 189.43 3,905.92 -7,956.43 290.473,856.35 6,023,909.27 545,152.80 1.18 7,732.21 3_MWD+IFR2+MS+Sag (3) 10,485.17 91.55 191.06 3,903.36 -8,049.30 273.693,853.79 6,023,816.30 545,136.57 1.73 7,826.56 3_MWD+IFR2+MS+Sag (3) 10,580.54 92.54 193.71 3,899.96 -8,142.39 253.253,850.39 6,023,723.10 545,116.70 2.96 7,921.85 3_MWD+IFR2+MS+Sag (3) 10,675.44 91.98 192.86 3,896.22 -8,234.67 231.463,846.65 6,023,630.70 545,095.47 1.07 8,016.64 3_MWD+IFR2+MS+Sag (3) 10,771.73 93.28 192.08 3,891.80 -8,328.59 210.693,842.23 6,023,536.67 545,075.27 1.57 8,112.82 3_MWD+IFR2+MS+Sag (3) 10,866.88 92.66 193.50 3,886.87 -8,421.25 189.653,837.30 6,023,443.89 545,054.79 1.63 8,207.82 3_MWD+IFR2+MS+Sag (3) 10,962.56 93.40 193.75 3,881.81 -8,514.11 167.153,832.24 6,023,350.91 545,032.85 0.82 8,303.31 3_MWD+IFR2+MS+Sag (3) 11,057.95 91.49 193.55 3,877.74 -8,606.71 144.663,828.17 6,023,258.17 545,010.92 2.01 8,398.56 3_MWD+IFR2+MS+Sag (3) 11,153.30 91.74 191.97 3,875.05 -8,699.67 123.613,825.48 6,023,165.10 544,990.43 1.68 8,493.85 3_MWD+IFR2+MS+Sag (3) 11,248.35 90.87 189.15 3,872.89 -8,793.08 106.193,823.32 6,023,071.60 544,973.58 3.10 8,588.85 3_MWD+IFR2+MS+Sag (3) 11,343.61 90.56 188.39 3,871.70 -8,887.21 91.673,822.13 6,022,977.39 544,959.63 0.86 8,683.97 3_MWD+IFR2+MS+Sag (3) 11,439.05 90.38 189.95 3,870.92 -8,981.43 76.463,821.35 6,022,883.09 544,944.99 1.65 8,779.31 3_MWD+IFR2+MS+Sag (3) 11,534.37 90.81 192.55 3,869.93 -9,074.90 57.873,820.36 6,022,789.52 544,926.96 2.76 8,874.62 3_MWD+IFR2+MS+Sag (3) 11,629.99 93.78 194.99 3,866.10 -9,167.68 35.133,816.53 6,022,696.61 544,904.79 4.02 8,970.08 3_MWD+IFR2+MS+Sag (3) 11,724.39 92.35 195.47 3,861.05 -9,258.64 10.373,811.48 6,022,605.52 544,880.58 1.60 9,064.16 3_MWD+IFR2+MS+Sag (3) 11,819.92 92.23 194.02 3,857.23 -9,350.94 -13.923,807.66 6,022,513.08 544,856.84 1.52 9,159.48 3_MWD+IFR2+MS+Sag (3) 11,915.11 91.43 194.38 3,854.19 -9,443.18 -37.263,804.62 6,022,420.71 544,834.06 0.92 9,254.53 3_MWD+IFR2+MS+Sag (3) 12,008.11 91.24 193.24 3,852.03 -9,533.46 -59.453,802.46 6,022,330.30 544,812.42 1.24 9,347.44 3_MWD+IFR2+MS+Sag (3) 12,100.72 91.74 190.62 3,849.62 -9,624.03 -78.593,800.05 6,022,239.63 544,793.83 2.88 9,440.01 3_MWD+IFR2+MS+Sag (3) 12,193.94 91.43 189.97 3,847.04 -9,715.72 -95.243,797.47 6,022,147.86 544,777.73 0.77 9,533.17 3_MWD+IFR2+MS+Sag (3) 12,291.16 90.37 189.82 3,845.51 -9,811.48 -111.953,795.94 6,022,052.01 544,761.61 1.10 9,630.32 3_MWD+IFR2+MS+Sag (3) 12,390.16 90.07 189.41 3,845.13 -9,909.09 -128.483,795.56 6,021,954.31 544,745.66 0.51 9,729.26 3_MWD+IFR2+MS+Sag (3) 8/4/2020 10:42:56AM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61PB1 Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61PB1 Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 12,485.24 89.76 189.20 3,845.27 -10,002.91 -143.863,795.70 6,021,860.40 544,730.86 0.39 9,824.25 3_MWD+IFR2+MS+Sag (3) 12,580.32 89.51 189.82 3,845.88 -10,096.68 -159.573,796.31 6,021,766.54 544,715.71 0.70 9,919.26 3_MWD+IFR2+MS+Sag (3) 12,675.67 90.25 190.21 3,846.08 -10,190.58 -176.153,796.51 6,021,672.56 544,699.70 0.88 10,014.57 3_MWD+IFR2+MS+Sag (3) 12,770.56 89.51 190.08 3,846.28 -10,283.99 -192.863,796.71 6,021,579.06 544,683.55 0.79 10,109.42 3_MWD+IFR2+MS+Sag (3) 12,865.32 85.49 190.17 3,850.41 -10,377.16 -209.503,800.84 6,021,485.80 544,667.48 4.24 10,204.04 3_MWD+IFR2+MS+Sag (3) 12,936.99 84.26 190.54 3,856.81 -10,447.38 -222.333,807.24 6,021,415.51 544,655.07 1.79 10,275.40 3_MWD+IFR2+MS+Sag (3) 13,010.00 84.26 190.54 3,864.12 -10,518.80 -235.623,814.55 6,021,344.02 544,642.21 0.00 10,348.03 PROJECTED to TD Approved By:Checked By:Date: 8/4/2020 10:42:56AM COMPASS 5000.15 Build 91E Page 6 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.08.04 07:47:30 -08'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.08.14 12:14:23 -08'00' 14 August, 2020 Milne Point M Pt L Pad MPU L-61PB2 500292368371 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61PB2 Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61PB2 Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i 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 Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU L-61i usft usft 0.00 0.00 6,031,863.02 544,814.39 15.70Wellhead Elevation:15.70 usft0.50 70° 29' 52.511 N 149° 38' 0.662 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU L-61PB2 Model NameMagnetics IFR 7/24/2020 15.95 80.91 57,371.40000000 Phase:Version: Audit Notes: Design MPU L-61PB2 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:11,534.37 191.700.000.0033.87 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 8/11/2020 Survey Date 3_Gyro-GC_Csg H049Gb: North seeking on wireline in casing100.00 917.00 MPU L-61PB1 E-Line Gyro (MPU L-61PB 07/10/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa979.62 7,739.38 MPU L-61PB1 MWD+IFR2+MS+Sag (1) 07/17/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa7,823.29 11,534.37 MPU L-61PB1 MWD+IFR2+MS+Sag (2) 07/30/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa11,570.00 14,047.75 MPU L-61PB2 MWD+IFR2+MS+Sag (3) 08/01/2020 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 33.87 0.00 0.00 33.87 0.00 0.00-15.70 6,031,863.02 544,814.39 0.00 0.00 UNDEFINED 100.00 0.21 57.60 100.00 0.06 0.1050.43 6,031,863.09 544,814.49 0.32 -0.08 3_Gyro-GC_Csg (1) 200.00 0.32 304.44 200.00 0.32 0.03150.43 6,031,863.34 544,814.41 0.45 -0.32 3_Gyro-GC_Csg (1) 300.00 0.30 339.40 300.00 0.72 -0.30250.43 6,031,863.74 544,814.09 0.19 -0.65 3_Gyro-GC_Csg (1) 352.00 0.49 40.37 352.00 1.02 -0.20302.43 6,031,864.04 544,814.18 0.83 -0.96 3_Gyro-GC_Csg (1) 446.00 1.06 74.44 445.99 1.56 0.90396.42 6,031,864.59 544,815.28 0.75 -1.71 3_Gyro-GC_Csg (1) 539.00 3.05 92.95 538.92 1.66 4.20489.35 6,031,864.71 544,818.58 2.23 -2.48 3_Gyro-GC_Csg (1) 632.00 5.61 95.94 631.65 1.07 11.19582.08 6,031,864.15 544,825.57 2.76 -3.31 3_Gyro-GC_Csg (1) 728.00 8.82 98.93 726.88 -0.56 23.13677.31 6,031,862.60 544,837.52 3.37 -4.14 3_Gyro-GC_Csg (1) 823.00 11.05 95.81 820.45 -2.61 39.39770.88 6,031,860.64 544,853.79 2.41 -5.43 3_Gyro-GC_Csg (1) 917.00 14.72 89.14 912.07 -3.35 60.30862.50 6,031,860.04 544,874.70 4.21 -8.95 3_Gyro-GC_Csg (1) 8/14/2020 12:20:19PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61PB2 Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61PB2 Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 979.62 15.49 84.32 972.53 -2.40 76.58922.96 6,031,861.08 544,890.97 2.35 -13.18 3_MWD+IFR2+MS+Sag (2) 1,074.60 20.03 84.97 1,062.96 0.28 105.411,013.39 6,031,863.94 544,919.79 4.78 -21.65 3_MWD+IFR2+MS+Sag (2) 1,170.19 25.59 88.17 1,151.04 2.38 142.391,101.47 6,031,866.26 544,956.74 5.96 -31.20 3_MWD+IFR2+MS+Sag (2) 1,264.71 27.33 89.77 1,235.66 3.12 184.491,186.09 6,031,867.25 544,998.84 1.99 -40.46 3_MWD+IFR2+MS+Sag (2) 1,359.96 27.79 97.29 1,320.13 0.39 228.391,270.56 6,031,864.78 545,042.75 3.68 -46.69 3_MWD+IFR2+MS+Sag (2) 1,455.32 29.28 103.12 1,403.92 -7.73 273.171,354.35 6,031,856.94 545,087.57 3.31 -47.83 3_MWD+IFR2+MS+Sag (2) 1,549.45 28.73 108.79 1,486.26 -20.24 317.011,436.69 6,031,844.69 545,131.48 2.98 -44.46 3_MWD+IFR2+MS+Sag (2) 1,644.94 28.29 115.31 1,570.19 -37.31 359.201,520.62 6,031,827.88 545,173.78 3.29 -36.30 3_MWD+IFR2+MS+Sag (2) 1,739.98 31.51 125.40 1,652.62 -61.35 399.841,603.05 6,031,804.09 545,214.56 6.27 -21.01 3_MWD+IFR2+MS+Sag (2) 1,834.72 33.99 133.82 1,732.34 -94.05 439.161,682.77 6,031,771.63 545,254.06 5.47 3.04 3_MWD+IFR2+MS+Sag (2) 1,929.67 33.92 141.21 1,811.13 -133.09 474.921,761.56 6,031,732.80 545,290.06 4.35 34.02 3_MWD+IFR2+MS+Sag (2) 2,026.73 36.37 148.89 1,890.53 -178.87 506.781,840.96 6,031,687.22 545,322.19 5.20 72.39 3_MWD+IFR2+MS+Sag (2) 2,121.73 38.81 154.72 1,965.82 -229.93 534.061,916.25 6,031,636.33 545,349.77 4.54 116.85 3_MWD+IFR2+MS+Sag (2) 2,215.16 42.91 155.75 2,036.47 -285.43 559.631,986.90 6,031,581.00 545,375.68 4.45 166.01 3_MWD+IFR2+MS+Sag (2) 2,310.59 48.46 157.55 2,103.12 -348.11 586.642,053.55 6,031,518.49 545,403.06 5.97 221.91 3_MWD+IFR2+MS+Sag (2) 2,406.66 49.56 158.97 2,166.13 -415.47 613.492,116.56 6,031,451.30 545,430.31 1.60 282.43 3_MWD+IFR2+MS+Sag (2) 2,502.37 53.37 160.55 2,225.75 -485.70 639.362,176.18 6,031,381.23 545,456.60 4.18 345.96 3_MWD+IFR2+MS+Sag (2) 2,597.45 54.75 162.11 2,281.56 -558.63 663.992,231.99 6,031,308.46 545,481.67 1.97 412.37 3_MWD+IFR2+MS+Sag (2) 2,692.21 58.38 163.93 2,333.76 -634.25 687.052,284.19 6,031,232.99 545,505.19 4.15 481.75 3_MWD+IFR2+MS+Sag (2) 2,788.79 61.46 166.26 2,382.17 -715.00 708.522,332.60 6,031,152.37 545,527.14 3.81 556.47 3_MWD+IFR2+MS+Sag (2) 2,884.36 64.52 168.98 2,425.57 -798.15 726.742,376.00 6,031,069.34 545,545.86 4.08 634.19 3_MWD+IFR2+MS+Sag (2) 2,978.74 68.35 174.27 2,463.32 -883.69 739.282,413.75 6,030,983.89 545,558.91 6.55 715.41 3_MWD+IFR2+MS+Sag (2) 3,073.52 70.01 176.89 2,497.01 -972.01 746.092,447.44 6,030,895.63 545,566.25 3.12 800.51 3_MWD+IFR2+MS+Sag (2) 3,169.26 69.41 177.45 2,530.21 -1,061.69 750.532,480.64 6,030,805.97 545,571.23 0.83 887.44 3_MWD+IFR2+MS+Sag (2) 3,264.79 69.21 178.34 2,563.96 -1,151.00 753.812,514.39 6,030,716.70 545,575.05 0.90 974.22 3_MWD+IFR2+MS+Sag (2) 3,359.65 69.67 179.00 2,597.28 -1,239.79 755.872,547.71 6,030,627.93 545,577.65 0.81 1,060.75 3_MWD+IFR2+MS+Sag (2) 3,455.28 70.65 178.85 2,629.73 -1,329.73 757.562,580.16 6,030,538.01 545,579.88 1.04 1,148.48 3_MWD+IFR2+MS+Sag (2) 3,548.67 68.55 177.20 2,662.29 -1,417.20 760.562,612.72 6,030,450.57 545,583.41 2.79 1,233.53 3_MWD+IFR2+MS+Sag (2) 3,643.94 68.88 175.42 2,696.87 -1,505.79 766.282,647.30 6,030,362.03 545,589.66 1.78 1,319.11 3_MWD+IFR2+MS+Sag (2) 3,739.32 68.82 176.14 2,731.29 -1,594.50 772.832,681.72 6,030,273.36 545,596.74 0.71 1,404.65 3_MWD+IFR2+MS+Sag (2) 3,834.92 68.74 177.00 2,765.89 -1,683.46 778.162,716.32 6,030,184.45 545,602.61 0.84 1,490.68 3_MWD+IFR2+MS+Sag (2) 3,930.89 68.36 177.51 2,800.99 -1,772.68 782.442,751.42 6,030,095.27 545,607.42 0.63 1,577.18 3_MWD+IFR2+MS+Sag (2) 4,023.75 69.94 176.60 2,834.04 -1,859.34 786.902,784.47 6,030,008.64 545,612.41 1.93 1,661.13 3_MWD+IFR2+MS+Sag (2) 4,121.27 68.88 177.14 2,868.33 -1,950.49 791.882,818.76 6,029,917.53 545,617.94 1.20 1,749.38 3_MWD+IFR2+MS+Sag (2) 4,216.09 70.91 177.29 2,900.92 -2,039.42 796.212,851.35 6,029,828.63 545,622.80 2.15 1,835.59 3_MWD+IFR2+MS+Sag (2) 4,310.73 71.45 177.90 2,931.45 -2,128.92 799.972,881.88 6,029,739.17 545,627.10 0.84 1,922.47 3_MWD+IFR2+MS+Sag (2) 4,406.67 70.60 176.31 2,962.65 -2,219.53 804.552,913.08 6,029,648.60 545,632.22 1.80 2,010.26 3_MWD+IFR2+MS+Sag (2) 4,501.86 69.68 174.68 2,994.99 -2,308.78 811.572,945.42 6,029,559.40 545,639.79 1.88 2,096.23 3_MWD+IFR2+MS+Sag (2) 4,596.48 67.95 177.06 3,029.19 -2,396.76 817.942,979.62 6,029,471.47 545,646.68 2.97 2,181.10 3_MWD+IFR2+MS+Sag (2) 4,691.70 68.29 177.39 3,064.67 -2,485.02 822.223,015.10 6,029,383.25 545,651.49 0.48 2,266.65 3_MWD+IFR2+MS+Sag (2) 8/14/2020 12:20:19PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61PB2 Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61PB2 Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 4,786.01 68.22 177.79 3,099.61 -2,572.54 825.903,050.04 6,029,295.76 545,655.70 0.40 2,351.61 3_MWD+IFR2+MS+Sag (2) 4,882.45 69.20 178.81 3,134.63 -2,662.36 828.563,085.06 6,029,205.97 545,658.91 1.42 2,439.02 3_MWD+IFR2+MS+Sag (2) 4,978.16 69.15 179.27 3,168.66 -2,751.80 830.063,119.09 6,029,116.54 545,660.94 0.45 2,526.30 3_MWD+IFR2+MS+Sag (2) 5,073.31 69.41 178.15 3,202.32 -2,840.77 832.063,152.75 6,029,027.59 545,663.49 1.13 2,613.02 3_MWD+IFR2+MS+Sag (2) 5,168.81 70.47 175.25 3,235.08 -2,930.32 837.243,185.51 6,028,938.09 545,669.20 3.06 2,699.65 3_MWD+IFR2+MS+Sag (2) 5,263.79 69.14 173.84 3,267.87 -3,019.05 845.703,218.30 6,028,849.42 545,678.20 1.98 2,784.82 3_MWD+IFR2+MS+Sag (2) 5,359.04 70.28 174.69 3,300.90 -3,107.94 854.633,251.33 6,028,760.59 545,687.66 1.46 2,870.06 3_MWD+IFR2+MS+Sag (2) 5,454.66 70.85 175.32 3,332.72 -3,197.77 862.483,283.15 6,028,670.82 545,696.05 0.86 2,956.43 3_MWD+IFR2+MS+Sag (2) 5,550.52 68.99 177.13 3,365.63 -3,287.60 868.423,316.06 6,028,581.04 545,702.52 2.63 3,043.19 3_MWD+IFR2+MS+Sag (2) 5,644.58 70.15 177.49 3,398.46 -3,375.64 872.553,348.89 6,028,493.03 545,707.19 1.28 3,128.56 3_MWD+IFR2+MS+Sag (2) 5,740.19 70.79 178.02 3,430.43 -3,465.68 876.083,380.86 6,028,403.02 545,711.26 0.85 3,216.02 3_MWD+IFR2+MS+Sag (2) 5,835.42 69.21 176.53 3,463.00 -3,555.06 880.333,413.43 6,028,313.68 545,716.05 2.22 3,302.68 3_MWD+IFR2+MS+Sag (2) 5,931.21 70.28 177.56 3,496.16 -3,644.80 884.963,446.59 6,028,223.97 545,721.22 1.51 3,389.62 3_MWD+IFR2+MS+Sag (2) 6,026.69 69.00 177.27 3,529.38 -3,734.23 888.993,479.81 6,028,134.59 545,725.79 1.37 3,476.36 3_MWD+IFR2+MS+Sag (2) 6,122.07 69.02 178.10 3,563.55 -3,823.20 892.593,513.98 6,028,045.64 545,729.93 0.81 3,562.76 3_MWD+IFR2+MS+Sag (2) 6,217.28 68.35 178.27 3,598.15 -3,911.86 895.403,548.58 6,027,957.02 545,733.27 0.72 3,649.00 3_MWD+IFR2+MS+Sag (2) 6,311.25 68.22 178.28 3,632.92 -3,999.12 898.033,583.35 6,027,869.78 545,736.42 0.14 3,733.92 3_MWD+IFR2+MS+Sag (2) 6,407.06 69.80 179.33 3,667.24 -4,088.55 899.893,617.67 6,027,780.37 545,738.82 1.94 3,821.11 3_MWD+IFR2+MS+Sag (2) 6,502.07 70.92 179.71 3,699.17 -4,178.02 900.643,649.60 6,027,690.91 545,740.11 1.24 3,908.58 3_MWD+IFR2+MS+Sag (2) 6,598.49 70.27 178.75 3,731.21 -4,268.96 901.863,681.64 6,027,600.00 545,741.88 1.16 3,997.37 3_MWD+IFR2+MS+Sag (2) 6,692.81 70.32 178.35 3,763.01 -4,357.72 904.113,713.44 6,027,511.25 545,744.66 0.40 4,083.84 3_MWD+IFR2+MS+Sag (2) 6,787.70 70.14 176.30 3,795.11 -4,446.92 908.273,745.54 6,027,422.09 545,749.37 2.04 4,170.34 3_MWD+IFR2+MS+Sag (2) 6,883.36 68.40 176.69 3,828.97 -4,536.21 913.743,779.40 6,027,332.84 545,755.38 1.86 4,256.67 3_MWD+IFR2+MS+Sag (2) 6,978.10 69.00 176.79 3,863.39 -4,624.34 918.763,813.82 6,027,244.76 545,760.93 0.64 4,341.95 3_MWD+IFR2+MS+Sag (2) 7,072.45 70.73 180.67 3,895.87 -4,712.88 920.713,846.30 6,027,156.24 545,763.41 4.27 4,428.25 3_MWD+IFR2+MS+Sag (2) 7,167.67 75.25 182.82 3,923.72 -4,803.86 917.923,874.15 6,027,065.25 545,761.16 5.21 4,517.91 3_MWD+IFR2+MS+Sag (2) 7,263.20 80.38 184.72 3,943.88 -4,897.00 911.763,894.31 6,026,972.09 545,755.57 5.71 4,610.36 3_MWD+IFR2+MS+Sag (2) 7,358.72 79.94 187.06 3,960.21 -4,990.61 902.113,910.64 6,026,878.43 545,746.48 2.46 4,703.98 3_MWD+IFR2+MS+Sag (2) 7,453.67 85.05 189.23 3,972.61 -5,083.76 888.773,923.04 6,026,785.21 545,733.70 5.84 4,797.90 3_MWD+IFR2+MS+Sag (2) 7,549.57 87.77 188.90 3,978.61 -5,178.27 873.693,929.04 6,026,690.62 545,719.20 2.86 4,893.50 3_MWD+IFR2+MS+Sag (2) 7,645.23 88.69 188.73 3,981.57 -5,272.75 859.043,932.00 6,026,596.06 545,705.11 0.98 4,989.00 3_MWD+IFR2+MS+Sag (2) 7,739.38 92.03 191.74 3,980.98 -5,365.38 842.313,931.41 6,026,503.34 545,688.95 4.78 5,083.09 3_MWD+IFR2+MS+Sag (2) 7,823.29 91.67 192.21 3,978.27 -5,447.42 824.913,928.70 6,026,421.21 545,672.05 0.71 5,166.95 3_MWD+IFR2+MS+Sag (3) 7,918.30 90.87 192.97 3,976.16 -5,540.12 804.213,926.59 6,026,328.39 545,651.90 1.16 5,261.93 3_MWD+IFR2+MS+Sag (3) 8,013.14 91.55 193.91 3,974.16 -5,632.34 782.173,924.59 6,026,236.05 545,630.42 1.22 5,356.70 3_MWD+IFR2+MS+Sag (3) 8,107.61 92.29 191.76 3,970.99 -5,724.39 761.203,921.42 6,026,143.88 545,610.01 2.41 5,451.09 3_MWD+IFR2+MS+Sag (3) 8,203.14 92.48 192.34 3,967.02 -5,817.73 741.273,917.45 6,026,050.43 545,590.65 0.64 5,546.54 3_MWD+IFR2+MS+Sag (3) 8,298.40 91.18 191.71 3,963.98 -5,910.85 721.433,914.41 6,025,957.20 545,571.38 1.52 5,641.75 3_MWD+IFR2+MS+Sag (3) 8,393.25 91.06 191.73 3,962.12 -6,003.71 702.173,912.55 6,025,864.24 545,552.67 0.13 5,736.58 3_MWD+IFR2+MS+Sag (3) 8,487.76 91.37 190.52 3,960.12 -6,096.42 683.943,910.55 6,025,771.43 545,535.00 1.32 5,831.06 3_MWD+IFR2+MS+Sag (3) 8/14/2020 12:20:19PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61PB2 Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61PB2 Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,583.31 91.18 191.80 3,957.99 -6,190.14 665.453,908.42 6,025,677.61 545,517.08 1.35 5,926.58 3_MWD+IFR2+MS+Sag (3) 8,678.54 90.87 192.55 3,956.29 -6,283.21 645.373,906.72 6,025,584.43 545,497.57 0.85 6,021.79 3_MWD+IFR2+MS+Sag (3) 8,773.83 91.24 193.31 3,954.53 -6,376.07 624.053,904.96 6,025,491.45 545,476.81 0.89 6,117.04 3_MWD+IFR2+MS+Sag (3) 8,868.51 92.85 193.42 3,951.15 -6,468.12 602.183,901.58 6,025,399.28 545,455.50 1.70 6,211.62 3_MWD+IFR2+MS+Sag (3) 8,964.55 90.99 192.73 3,947.94 -6,561.61 580.473,898.37 6,025,305.67 545,434.35 2.07 6,307.57 3_MWD+IFR2+MS+Sag (3) 9,058.76 89.57 192.29 3,947.48 -6,653.58 560.063,897.91 6,025,213.58 545,414.50 1.58 6,401.77 3_MWD+IFR2+MS+Sag (3) 9,153.64 90.26 192.79 3,947.62 -6,746.20 539.463,898.05 6,025,120.85 545,394.46 0.90 6,496.64 3_MWD+IFR2+MS+Sag (3) 9,249.00 90.44 194.90 3,947.03 -6,838.78 516.643,897.46 6,025,028.14 545,372.20 2.22 6,591.92 3_MWD+IFR2+MS+Sag (3) 9,345.17 88.96 194.51 3,947.54 -6,931.80 492.233,897.97 6,024,934.99 545,348.36 1.59 6,687.96 3_MWD+IFR2+MS+Sag (3) 9,439.90 92.42 193.84 3,946.40 -7,023.62 469.043,896.83 6,024,843.04 545,325.72 3.72 6,782.58 3_MWD+IFR2+MS+Sag (3) 9,535.20 92.29 193.26 3,942.48 -7,116.19 446.733,892.91 6,024,750.35 545,303.97 0.62 6,877.75 3_MWD+IFR2+MS+Sag (3) 9,629.81 92.17 191.90 3,938.80 -7,208.46 426.143,889.23 6,024,657.97 545,283.94 1.44 6,972.27 3_MWD+IFR2+MS+Sag (3) 9,724.82 92.04 190.38 3,935.31 -7,301.61 407.803,885.74 6,024,564.71 545,266.16 1.60 7,067.21 3_MWD+IFR2+MS+Sag (3) 9,820.82 92.91 191.01 3,931.16 -7,395.86 390.003,881.59 6,024,470.37 545,248.93 1.12 7,163.10 3_MWD+IFR2+MS+Sag (3) 9,915.09 91.98 190.17 3,927.14 -7,488.43 372.693,877.57 6,024,377.70 545,232.18 1.33 7,257.27 3_MWD+IFR2+MS+Sag (3) 10,009.79 92.60 190.60 3,923.36 -7,581.51 355.633,873.79 6,024,284.54 545,215.69 0.80 7,351.87 3_MWD+IFR2+MS+Sag (3) 10,104.89 92.48 190.47 3,919.14 -7,674.91 338.263,869.57 6,024,191.04 545,198.88 0.19 7,446.85 3_MWD+IFR2+MS+Sag (3) 10,200.77 93.28 189.39 3,914.33 -7,769.23 321.753,864.76 6,024,096.63 545,182.94 1.40 7,542.56 3_MWD+IFR2+MS+Sag (3) 10,295.65 92.66 189.56 3,909.41 -7,862.69 306.153,859.84 6,024,003.08 545,167.91 0.68 7,637.25 3_MWD+IFR2+MS+Sag (3) 10,390.75 91.55 189.43 3,905.92 -7,956.43 290.473,856.35 6,023,909.27 545,152.80 1.18 7,732.21 3_MWD+IFR2+MS+Sag (3) 10,485.17 91.55 191.06 3,903.36 -8,049.30 273.693,853.79 6,023,816.30 545,136.57 1.73 7,826.56 3_MWD+IFR2+MS+Sag (3) 10,580.54 92.54 193.71 3,899.96 -8,142.39 253.253,850.39 6,023,723.10 545,116.70 2.96 7,921.85 3_MWD+IFR2+MS+Sag (3) 10,675.44 91.98 192.86 3,896.22 -8,234.67 231.463,846.65 6,023,630.70 545,095.47 1.07 8,016.64 3_MWD+IFR2+MS+Sag (3) 10,771.73 93.28 192.08 3,891.80 -8,328.59 210.693,842.23 6,023,536.67 545,075.27 1.57 8,112.82 3_MWD+IFR2+MS+Sag (3) 10,866.88 92.66 193.50 3,886.87 -8,421.25 189.653,837.30 6,023,443.89 545,054.79 1.63 8,207.82 3_MWD+IFR2+MS+Sag (3) 10,962.56 93.40 193.75 3,881.81 -8,514.11 167.153,832.24 6,023,350.91 545,032.85 0.82 8,303.31 3_MWD+IFR2+MS+Sag (3) 11,057.95 91.49 193.55 3,877.74 -8,606.71 144.663,828.17 6,023,258.17 545,010.92 2.01 8,398.56 3_MWD+IFR2+MS+Sag (3) 11,153.30 91.74 191.97 3,875.05 -8,699.67 123.613,825.48 6,023,165.10 544,990.43 1.68 8,493.85 3_MWD+IFR2+MS+Sag (3) 11,248.35 90.87 189.15 3,872.89 -8,793.08 106.193,823.32 6,023,071.60 544,973.58 3.10 8,588.85 3_MWD+IFR2+MS+Sag (3) 11,343.61 90.56 188.39 3,871.70 -8,887.21 91.673,822.13 6,022,977.39 544,959.63 0.86 8,683.97 3_MWD+IFR2+MS+Sag (3) 11,439.05 90.38 189.95 3,870.92 -8,981.43 76.463,821.35 6,022,883.09 544,944.99 1.65 8,779.31 3_MWD+IFR2+MS+Sag (3) 11,534.37 90.81 192.55 3,869.93 -9,074.90 57.873,820.36 6,022,789.52 544,926.96 2.76 8,874.62 3_MWD+IFR2+MS+Sag (3) 11,570.00 91.92 193.46 3,869.08 -9,109.61 49.853,819.51 6,022,754.77 544,919.16 4.03 8,910.23 3_MWD+IFR2+MS+Sag (4) 11,629.73 89.76 194.19 3,868.20 -9,167.60 35.583,818.63 6,022,696.70 544,905.24 3.82 8,969.91 3_MWD+IFR2+MS+Sag (4) 11,724.56 89.20 192.23 3,869.06 -9,259.91 13.913,819.49 6,022,604.27 544,884.13 2.15 9,064.69 3_MWD+IFR2+MS+Sag (4) 11,819.70 91.12 191.54 3,868.80 -9,353.01 -5.683,819.23 6,022,511.06 544,865.10 2.14 9,159.83 3_MWD+IFR2+MS+Sag (4) 11,914.98 91.92 191.99 3,866.27 -9,446.25 -25.103,816.70 6,022,417.71 544,846.24 0.96 9,255.07 3_MWD+IFR2+MS+Sag (4) 12,010.21 90.50 191.96 3,864.26 -9,539.38 -44.853,814.69 6,022,324.47 544,827.05 1.49 9,350.28 3_MWD+IFR2+MS+Sag (4) 12,105.45 90.69 191.86 3,863.27 -9,632.57 -64.513,813.70 6,022,231.18 544,807.96 0.23 9,445.51 3_MWD+IFR2+MS+Sag (4) 12,200.14 91.62 192.56 3,861.36 -9,725.10 -84.533,811.79 6,022,138.54 544,788.50 1.23 9,540.18 3_MWD+IFR2+MS+Sag (4) 8/14/2020 12:20:19PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Definitive Survey Report Well: Wellbore: MPU L-61i MPU L-61PB2 Survey Calculation Method:Minimum Curvature MPU L-61i Actual RKB @ 49.57usft Design:MPU L-61PB2 Database:NORTH US + CANADA MD Reference:MPU L-61i Actual RKB @ 49.57usft North Reference: Well MPU L-61i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 12,295.57 93.10 193.29 3,857.43 -9,818.03 -105.863,807.86 6,022,045.49 544,767.74 1.73 9,635.50 3_MWD+IFR2+MS+Sag (4) 12,390.03 93.53 193.18 3,851.97 -9,909.82 -127.453,802.40 6,021,953.58 544,746.70 0.47 9,729.77 3_MWD+IFR2+MS+Sag (4) 12,486.26 92.10 192.03 3,847.24 -10,003.62 -148.423,797.67 6,021,859.67 544,726.30 1.91 9,825.87 3_MWD+IFR2+MS+Sag (4) 12,580.11 89.63 192.16 3,845.83 -10,095.37 -168.083,796.26 6,021,767.81 544,707.19 2.64 9,919.70 3_MWD+IFR2+MS+Sag (4) 12,675.67 89.58 193.40 3,846.49 -10,188.56 -189.223,796.92 6,021,674.50 544,686.62 1.30 10,015.24 3_MWD+IFR2+MS+Sag (4) 12,771.35 88.03 192.43 3,848.48 -10,281.79 -210.603,798.91 6,021,581.15 544,665.81 1.91 10,110.87 3_MWD+IFR2+MS+Sag (4) 12,866.49 90.20 192.82 3,849.95 -10,374.61 -231.393,800.38 6,021,488.21 544,645.58 2.32 10,205.98 3_MWD+IFR2+MS+Sag (4) 12,961.13 90.38 193.58 3,849.47 -10,466.75 -253.003,799.90 6,021,395.96 544,624.52 0.83 10,300.59 3_MWD+IFR2+MS+Sag (4) 13,057.07 90.87 192.68 3,848.43 -10,560.18 -274.793,798.86 6,021,302.41 544,603.30 1.07 10,396.49 3_MWD+IFR2+MS+Sag (4) 13,152.02 88.34 190.08 3,849.08 -10,653.24 -293.523,799.51 6,021,209.24 544,585.13 3.82 10,491.42 3_MWD+IFR2+MS+Sag (4) 13,247.32 88.84 187.49 3,851.43 -10,747.39 -308.073,801.86 6,021,115.02 544,571.15 2.77 10,586.56 3_MWD+IFR2+MS+Sag (4) 13,342.45 87.47 187.35 3,854.49 -10,841.67 -320.353,804.92 6,021,020.68 544,559.44 1.45 10,681.37 3_MWD+IFR2+MS+Sag (4) 13,437.35 88.47 190.82 3,857.85 -10,935.30 -335.323,808.28 6,020,926.96 544,545.03 3.80 10,776.10 3_MWD+IFR2+MS+Sag (4) 13,532.71 90.38 192.55 3,858.81 -11,028.67 -354.633,809.24 6,020,833.49 544,526.29 2.70 10,871.45 3_MWD+IFR2+MS+Sag (4) 13,627.45 90.81 193.16 3,857.82 -11,121.03 -375.713,808.25 6,020,741.01 544,505.77 0.79 10,966.16 3_MWD+IFR2+MS+Sag (4) 13,723.05 89.70 190.49 3,857.40 -11,214.59 -395.303,807.83 6,020,647.34 544,486.75 3.02 11,061.75 3_MWD+IFR2+MS+Sag (4) 13,817.92 90.87 190.63 3,856.93 -11,307.86 -412.693,807.36 6,020,553.99 544,469.93 1.24 11,156.60 3_MWD+IFR2+MS+Sag (4) 13,913.21 89.26 190.33 3,856.82 -11,401.55 -430.023,807.25 6,020,460.20 544,453.16 1.72 11,251.86 3_MWD+IFR2+MS+Sag (4) 14,008.51 89.58 188.98 3,857.78 -11,495.50 -446.003,808.21 6,020,366.17 544,437.75 1.46 11,347.09 3_MWD+IFR2+MS+Sag (4) 14,047.75 89.82 188.71 3,857.99 -11,534.27 -452.033,808.42 6,020,327.36 544,431.95 0.92 11,386.29 3_MWD+IFR2+MS+Sag (4) 14,120.00 89.82 188.71 3,858.22 -11,605.68 -462.973,808.65 6,020,255.89 544,421.44 0.00 11,458.44 PROJECTED to TD Approved By:Checked By:Date: 8/14/2020 12:20:19PM COMPASS 5000.15 Build 91E Page 6 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.08.14 09:24:45 -08'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.08.14 12:18:15 -08'00' _____________________________________________________________________________________ Revised By: JNL 8/31/20 Proposed Schematic Milne Point Unit Well: MPU L-61 PTD: 220-056 API: 50-029-23683-00-00 4-1/2” SOLID LINER DETAIL 4-1/2” SCREEN LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 1 8309’ 3964’ 8351’ 3963’ 1 8721’ 3956’ 8763’ 3955’ 1 9819’ 3932’ 9861’ 3930’ 1 10229’ 3913’ 10271’ 3911’ 1 10995’ 3886’ 11037’ 3886’ 1 11322’ 3877’ 11364’ 3874’ 1 11851’ 3866’ 11892’ 3865’ 1 12544’ 3853’ 12586’ 3852’ 1 12994’ 3855’ 13036’ 3855’ 1 13645’ 3857’ 13686’ 3857’ 1 13974’ 3858’ 14016’ 3859’ Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 6 7601’ 3981’ 7839’ 3978’ 11 7858’ 3978’ 8309’ 3964’ 9 8351’ 3963’ 8721’ 3956’ 26 8763’ 3955’ 9819’ 3932’ 9 9861’ 3930’ 10229’ 3913’ 18 10271’ 3911’ 10995’ 3886’ 7 11037’ 3886’ 11322’ 3877’ 12 11364’ 3874’ 11851’ 3866’ 16 11892’ 3865’ 12544’ 3853’ 10 12586’ 3852’ 12994’ 3855’ 15 13036’ 3855’ 13645’ 3857’ 7 13686’ 3857’ 13974’ 3858’ 1 14016’ 3859’ 14057’ 3860’ Jts 6 11 9 26 9 18 7 12 16 10 15 7 1 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 216 / A53 / Weld N/A Surface 114’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,274’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,274’ 7,754’ 0.0758 7” Tieback 26 / L-80 / TXP 6.292” Surface 7,588’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.795” 7,574’ 14,100’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 7,584’ 0.0087 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 6801’ 3-1/2” Gauge Carrier Assy. 2.898” 2 6852’ XN Nipple Assy, 2.75" Bottom No-Go, 2.813" Packing Bore 2.750” 3 7556’ 3-1/2” Packer (3979’ TVD) 2.885” 4 7576’ Mirage Plug 2.880” Lower Completion 5 7574’ SLZXP Liner Hanger / Packer 6.190” 6 7844’ Tendeka Swell Packer 3.850” 7 14098’ Shoe Bottom @ 14100’ MD 4.121” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4" Stg 1 –Lead 855 sx / Tail 400 sx Stg 2 –Lead 588 sx / Tail 270 sx, Top Job (through stage tool): 270 sx 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 446’ Hole Angle @ XN = 69° Hole Angle @ Liner Top = 88° Max Hole Angle = 94° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23683-00-00 Completed by Doyon 14: 8/19/2020 1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.W ell Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7778'None Casing Collapse Structural Conductor Surface 4760 / 3090 Intermediate Production Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 7/27/2020 None None Authorized Title: Drilling Manager Authorized Name: Monty Myers Perforation Depth MD (ft): None Perforation Depth TVD (ft):Tubing Size: 20" 9-5/8" 80' 7754' MD 6870 / 5750 114' 3980' 114' 7754' Milne Point Field, Schrader Bluff Oil Pool MPU L-61 PRESENT WELL CONDITION SUMMARY TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509 & 025515 220-056 3800 Centerpoint Drive, Suite 1400, Acnhorage, AK 99503 50-029-20683-00-00 Hilcorp Alaska, LLC COMMISSION USE ONLY Tubing Grade:Tubing MD (ft): Nathan Sperry nathan.sperry@hilcorp.com 3979'2256'2066'2256' Length Size m n P 66 t _ s Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. 7.28.2020 By Jody Colombie at 9:36 am, Jul 28, 2020 320-312 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: 2020.07.28 09:01:39 -08'00' Monty M Myers SFD 7/28/2020 DLB 07/28/2020 SFD 7/28/2020 X 50-029-23683-00-00 DSR-7/28/2020 10-407 (completion report) MGR29JUL20Comm. 7/29/2020 dts 7/29/2020 JLC 7/29/2020 RBDMS HEW 7/30/2020 July 27, 2020 MPU L-61 PTD #220-056 / API #50-029-23683-00-00 Over the weekend, we tried to pressure test the casing to 2500 psi and the pressure broke down at 840 psi. We used an RTTS to determine that the leak is at the ES cementer (2292’ to 2296’ MD), which is about 2100’ TVD. We set a cement retainer in the first full joint below the ES. We also set one in the first full joint above. We squeezed 50 bbls of our 15.8ppg class G stage 2 tail cement into the leak. We’re currently waiting on cement to develop at least 1000’ psi compressive strength. I’m proposing the following changes to the well: x FIT from 12.0ppg if Casing PT to 1000 psi – notify AOGCC if PT fails, then to 11.5ppg x Regardless of whether the casing test passes or fails, drill ahead in the 8-1/2” lateral per plan. x After installing the lower completion, run a 7” tieback and pressure test the tieback casing to 2500 psi. x Run the upper completion per the approved PTD. Additional relevant information: x The casing test leaked off at 840 psi, which is about a 17ppg LOT at the ES cementer. x The pressure levels off at 540 psi, which 14 ppg. x This is a Schrader bluff injector w/ a well understood pore pressure. x We will be drilling with MPD. x We put 2500 psi on the casing above the upper retainer prior to squeeze cementing and the 5 minute test held solid. Both stages of the cement job went well. After stage 1, we circulated cement out of the hole from the ES cementer. During stage 2, we got over 200 bbls of cement to surface. _____________________________________________________________________________________ Revised By: JNL 7/27/20 Schematic Milne Point Unit Well: MPU L-61 PTD: 220-056 API: 50-029-23683-00-00 4-1/2” SOLID LINER DETAIL 4-1/2” Screens LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) TBD Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) TBD Jts TBD CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 216 / A53 / Weld N/A Surface 114’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,274’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,274’ 7,754’ 0.0758 TUBING DETAIL JEWELRY DETAIL No Top MD Item ID Upper Completion Lower Completion OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4" Stg 1 –Lead 855 sx / Tail 400 sx Stg 2 –Lead 588 sx / Tail 270 sx 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 446’ Hole Angle @ XN = TBD° Hole Angle @ Liner Top = TBD° Max Hole Angle = 92° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23683-00-00 Completed by Doyon 14: Future _____________________________________________________________________________________ Revised By: JNL 7/27/20 Proposed Schematic Milne Point Unit Well: MPU L-61 PTD: 220-056 API: 50-029-23683-00-00 4-1/2” SOLID LINER DETAIL 4-1/2” Screens LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) TBD Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) TBD Jts TBD CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 216 / A53 / Weld N/A Surface 114’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,274’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,274’ 7,754’ 0.0758 7” Intermediate 26 / L-80 / TXP 6.292” Surface 7,461’ 0.0459 4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.795” 7,461’ 14,320’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 7,461’’ 0.0087 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 TBD 3-1/2” Liner Top Packer 2 TBD Bottom 3-1/2” Tubing Lower Completion 3 TBD Liner Hanger / Packer 4 TBD Polished Bore Receptacle 5 TBD Shoe Bottom @ TBD’ MD OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4" Stg 1 –Lead 855 sx / Tail 400 sx Stg 2 –Lead 588 sx / Tail 270 sx 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 435’ Hole Angle @ XN = TBD° Hole Angle @ Liner Top = TBD° Max Hole Angle = 92° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23683-00-00 Completed by Doyon 14: Future STATE OF ALASKA �� Reviewed 6y: OIL AND GAS CONSERVATION COMMISSION P,I, Supry W7/ efZ,v BOPE Test Report for: MILNE PT UNIT L-61 Comm Contractor/Rig No.: Doyon 14 PTD#: 2200560 DATE: 7/24/2020 Inspector JeffJones Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: D. Yessak Rig Rep: F. Carlo Inspector Type Operation: DRILL Sundry No: Test Pressures: Inspection No: bopJJ200727101719 Rams: Annular: Valves: NIASP: Type Test: INIT 250/3000 ' 250/3000 ' 250/3000 ' 1393 ' Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: P/F ACCUMULATOR SYSTEM: 1 P P/F 1 Visual Alarm Ball Type Time/Pressure P P/F Location Gen.: P Trip Tank P _ P System Pressure 3050 _ P Housekeeping: P Pit Level Indicators -P P Pressure After Closure - 1650 P PTD On Location P Flow Indicator P P 200 PSI Attained 48 P Standing Order Posted P Meth Gas Detector P P Full Pressure Attained 203 P Well Sign P H2S Gas Detector P P Blind Switch Covers: All P Drl. Rig P _ MS Misc NA -NA 1 Nitgn. Bottles (avg): 6 @2177 P ' Hazard Sec. P 2 " 3 1/8 P ACC Misc 0 NA Misc NA P Check Valve 0 FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Upper Kelly 1 P Lower Kelly 1 -- P Ball Type _3_ _ P Inside BOP 2 P FSV Misc 0 NA BOP STACK: CHOKE MANIFOLD: Quantity Size P/F Quantity P/F Stripper 0 NA No. Valves 14 P Annular Preventer 1 - 135/8 _ FP_ v' Manual Chokes 1 P #1 Rams 1' 4.5 x 7 P Hydraulic Chokes 1 P #2 Rams 1 " Blind P CH Misc 0 NA #3 Rams 1 3.5x_6_ P #4 Rams 0- NA #5 Rams 0 - NA INSIDE REEL VALVES: #6 Rams 0 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 31/8 P Check Valve 0 NA BOP Misc 0 NA Number of Failures: 1 Test Results Test Time 8 Remarks: Doyon personnel performed the tests today using 3.5", 4.5" and 5" test joints in a safe and proficient manner with one_IaLuLe observed. The Koomey unit failed to maintain proper manifold pressure and hydraulic fluid was continuously flowing ick to the resevoir from the annular preventer return line. The annular piston seals and the annular 4 -way valve on the koomey were replaced and these items passed retests. The gas detection and pit volume totalizer alarm systems were tested and operated properly. The rig and surrounding location appeared clean, orderly and in good condition. °' Number of Failures: 1 Remarks: Doyon personnel performed the tests observed. The Koomev unit failed to i resevoir from the annular oreventer rt replaced and these items passed rets properly. The rig and surrounding loci Test Results Test Time 8 using 3.5', 4.5' and 5" testjoints in a safe and proficient manner with aln proper mannoltl pressure and hydraulic fluid was continuously flowina back to the line. The annular piston seals and the annu ar 4-wav valve on the koomey were The gas detection and pit volume totalizer alarm systems were tested and operated appeared clean, orderly and in good condition. ✓ STATE OF ALASKA Reviewed By: -lr..T/ OIL AND GAS CONSERVATION COMMISSION P•I. Suprv2�2 BOPE Test Report for: MILNE PT UNIT L-61 Comm Contractor/Rig No.: Doyon 14 PTD#: 2200560 DATE: 7/24/2020 Inspector Jeff Jones Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: D. Yessak Rig Rep: F. Carlo Inspector Type Operation: DRdL Sundry No: Test Pressures: Inspection No: bopJJ200727101719 Rams: Annular: Valves: MASP: Type Test: WIT 250/3000 ' 250/3000 ' 250/3000 ' 1393 - Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: P/F Visual Alarm Time/Pressure P/F Location Gen.: P Trip Tank P P System Pressure 3050 P " Housekeeping: _ P Pit Level Indicators P _ P Pressure After Closure _ 1650 P - PTD On Location P Flow Indicator P P 200 PSI Attained 48 - P Standing Order Posted P ' Meth Gas Detector P P Full Pressure Attained _ 203 P_ Well Sign P 112S Gas Detector P P Blind Switch Covers: All P Dirt. Rig P MS Mise NA NA Nitgn. Bottles (avg): X2177 - P ' Hazard Sec. P ACC Mise 0 NA Misc NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly _ I "_- P • Stripper 0 NA No. Valves 14 P ' Lower Kelly 1 P_ Annular Preventer 1 '135/8 FP v/ Manual Chokes 1 P " Ball Type 3 __ P • #1 Rams _ 1 '4.5 x 7 P _ Hydraulic Chokes 1 P " Inside BOP 2 _• P • #2 Rams _ 1 'Blind P CH Misc 0 _NA FSV Misc 0 NA #3 Rams 1 3.5 x 6 P " 44 Rams 0 NA #5 Rams 0 NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 31/8 P Quantity P/F HCR Valves 2 -31/8 P Inside Reel Valves 0 NA Kill Line Valves 2 -31/8 P Check Valve 0 NA BOP Misc 0 NA Number of Failures: 1 Remarks: Doyon personnel performed the tests observed. The Koomev unit failed to i resevoir from the annular oreventer rt replaced and these items passed rets properly. The rig and surrounding loci Test Results Test Time 8 using 3.5', 4.5' and 5" testjoints in a safe and proficient manner with aln proper mannoltl pressure and hydraulic fluid was continuously flowina back to the line. The annular piston seals and the annu ar 4-wav valve on the koomey were The gas detection and pit volume totalizer alarm systems were tested and operated 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 Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU L-61 Hilcorp Alaska, LLC Permit to Drill Number: 220-056 Surface Location: 3674' FSL, 5063' FEL, Sec. 8, T13N, R10E, UM, AK Bottomhole Location: 2427' FSL, 332' FEL, Sec 19, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service 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 July, 2020. y, JMPi 7 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: 14,320' TVD: 3,798' 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): 48.9' 15. Distance to Nearest Well Open Surface: x-544814 y- 6031863 Zone- 4 15.2' to Same Pool: 130' to MPL-48 16. Deviated wells:Kickoff depth: 435 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 92 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 20" 216# A53 Weld 114' Surface Surface 114' 114' 9-5/8" 47# L-80 TXP 2,000' Surface Surface 2,000' 1,870' 9-5/8" 40# L-80 TXP 5,611' 2,000' 1,870' 7,611' 3,979' 8-1/2" 4-1/2" 13.5# L-80 Hydril 625 6,859' 7,461 3,965' 14,320' 3,798' Tieback 3-1/2" 9.3# L-80 EUE 8RD 7,461' Surface Surface 7,461' 3,965' 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 5462' to nearest unit boundary 7/18/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Joe Engel jengel@hilcorp.com 777-8395 18. Casing Program:Top - Setting Depth - BottomSpecifications MPU L-61 Milne Point Field Schrader Bluff Oil Pool (NB Sand) 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 3674' FSL, 5063' FEL, Sec. 8, T13N, R10E, UM, AK ADL025509, ADL025515 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Stg 2 L - 1937 ft3 / T - 314 ft3 1393 1566' FNL, 1051' FWL, Sec 17, T13N, R10E, UM, AK 2427' FSL, 332' FEL, Sec 19, T13N, R10E, UM, AK LONS 88-002 5077 1750 Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) ~270 ft3 Stg 1 L - 1674 ft3 / T - 458 ft3 Effect. Depth TVD (ft): Conductor/Structural Length Cementless Injection Liner w/ ICDs Tieback Tubing Surface Production Liner Casing Intermediate Commission Use Only Authorized Signature: Effect. Depth MD (ft): 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. Perforation Depth TVD (ft): 12-1/4" GL / BF Elevation above MSL (ft): 6/30/2020 es N ype of W L l R L 1b S Class: os N es No s N o D s s s D 84 o : well is p G S S 20 S S S es No s No S G E S es No s Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Samantha Carlisle at 9:12 am, Jun 30, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp AK, ou=Drilling Manager, email=mmyers@hilcorp.com Reason: I am approving this document Location: Anchorage AK Date: 2020.06.30 09:07:03 -08'00' Monty M Myers X DSR-6/30/2020 X X X DLB 07/01/2020 X MGR02JUL2020 X 220-056 XBOPE test to 3000 psi, annular to 2500 psi. 029-23683-00-00 2JUL2ULULULUUULULULLL020222222222222 7/7/2020 7/7/2020 Area of Review MPL-61PTDAPI WELL STATUSTop of SB NB (MD)Top of SB NB (TVD)CBL Top of Cement (MD)CBL Top of Cement (TVD)Schrader NB statusZonal Isolation218-165 50-029-23617-00-00 MPM-10 OA Prod5754' 3836' Surface Surface Cased/CementedLateral in OA219-010 50-029-23621-00-00 MPM-11 OA WINJ4734' 3789' Surface Surface Cased/CementedLateral in OA218-176 50-029-23619-00-00 MPM-12 OA Prod4157' 3747' Surface Surface Cased/CementedLateral in OA219-087 50-029-23638-00-00 MPM-13 OA WINJ4206' 3716' Surface Surface Cased/CementedLateral in OA219-040 50-029-23625-00-00 MPM-14 OA Prod4301' 3713' Surface Surface Cased/CementedLateral in OA219-141 50-029-23653-00-00 MPM-15 OA WINJ4966' 3675' Surface Surface Cased/CementedLateral in OA215-118 50-029-23551-00-00 MPL-46 OA Prod5712' 4016' Surface Surface Cased/CementedLateral in OA215-120 50-029-23552-00-00 MPL-48 OA WINJ6003' 3987' Surface Surface Cased/CementedLateral in OA215-117 50-029-23550-00-00 MPL-47 OA Prod6923' 3956' Surface Surface Cased/CementedLateral in OA215-132 50-029-23555-00-00 MPL-50 OA WINJ7583' 3910' Surface Surface Cased/CementedLateral in OA220-048 50-029-23678-00-00 MPL-60 NB Prod 6751' 3968' Surface Surface OpenOpen to Injection Support LM8712171813201924L-01L-02L-17L-32L-34L-35L-39L-20L-36J-18L-40L-42L-37L-45F-81LIVIANO 1LIVIANO 1APESADO 1PESADO 1AL-12L-50L-47L-46L-49L-48L-51L-53L-56L-54L-57L-52F-110M-03M-12M-11M-14M-15M-13M-10M-16M-20M-2122M-35M-34M-43PB3M-44M-45M-43L-60L-61 wp06HILCORP ALASKA LLCMILNE POINT FIELDAOR MAPL-61 Injector (Proposed)FEET01,0002,000POSTED WELL DATAWell NumberWELL SYMBOLSActive OilD&AShut In OilINJ Well (Water Flood)P&A OilAbandoned InjectorSWDPlug BackInjector LocationProducer LocationShut In INJREMARKSWell Symbols at top of Schrader Bluff NB Sand.Black dash circle = 1320' radius from NB sand in heeland toe of proposed L-61 drill well.June 11, 2020PETRA 6/11/2020 10:16:54 AM Milne Point Unit (MPU) L-61 Drilling Program Version 1 6/29/2020 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 L-61 SB Injector Drilling Procedure 1.0 Well Summary Well MPU L-61 Pad Milne Point “L” Pad Planned Completion Type 3-1/2” Injection Tubing Target Reservoir(s) Schrader Bluff Nb Sand Planned Well TD, MD / TVD 14,319’ MD / 3,798’ TVD PBTD, MD / TVD 14,309’ MD / 3,798’ TVD Surface Location (Governmental) 3674' FSL, 5063' FEL, Sec. 8, T13N, R10E, UM, AK Surface Location (NAD 27) X= 544814 Y= 6031863 Top of Productive Horizon (Governmental) 1566' FNL, 1051' FWL, Sec 17, T13N, R10E, UM, AK TPH Location (NAD 27) X= 545697 Y= 6026629 BHL (Governmental) 2427' FSL, 332' FEL, Sec 19, T13N, R10E, UM, AK BHL (NAD 27) X= 544377 Y=6020055 AFE Number 2011923M (D,C,F) AFE Drilling Days 18 days AFE Completion Days 3 days AFE Drilling Amount AFE Completion Amount AFE Facility Amount Maximum Anticipated Pressure (Surface) 1393 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1750 psig Work String 5” 19.5# S-135 DS-50 & NC 50 KB Elevation above MSL: 33.7 ft + 15.2 ft = 48.9 ft GL Elevation above MSL: 15.2 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit L-61 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit L-61 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-52 Weld 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 L-61 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, jengel@hilcorp.com and cdinger@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 jengel@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and cdinger@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 Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@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 Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 6 Milne Point Unit L-61 SB Injector Drilling Procedure 6.0 Planned Wellbore Schematic @7465' MD Page 7 Milne Point Unit L-61 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU L-61 is a grassroots injector planned to be drilled in the Schrader Bluff NB sand. L-61 is part of a multi well program targeting the Schrader Bluff sand on L-Pad. L-61 will not be pre-produced. The directional plan is a catenary well path build, 12.25” 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 July 18, 2020, pending rig schedule. Surface casing will be run to 7,611 MD / 3,978’ 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 c ement 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 L-61 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 L-61. 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 L-61 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 Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit L-61 SB Injector Drilling Procedure 9.0 R/U and Preparatory Work 9.1 L-61 will utiliz e a newly set 20” conductor on L-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. Ensure Page 11 Milne Point Unit L-61 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 L-61 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit L-61 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. Page 14 Milne Point Unit L-61 SB Injector Drilling Procedure x Gas hydrates have not been seen on L-Pad. However, be prepared for them. In MPU they have been encountered typically around 2100-2400’ TVD (just below permafrost). Be prepared for hydrates: 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: EMW=8.46 ppg DLB Page 15 Milne Point Unit L-61 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 t/ bottom, proceed to BROOH t/ 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. Note: EMW=8.46 ppg DLB Page 16 Milne Point Unit L-61 SB Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 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. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 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 Page 17 Milne Point Unit L-61 SB Injector Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: Page 18 Milne Point Unit L-61 SB Injector Drilling Procedure 12.6 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 POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 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 L-61 SB Injector Drilling Procedure Page 20 Milne Point Unit L-61 SB Injector Drilling Procedure 12.8 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 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Page 21 Milne Point Unit L-61 SB Injector Drilling Procedure 12.10 Slow in and out of slips. 12.11 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. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 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 L-61 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 amounts 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. Estimated 1st Stage Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" Casing (6,611' - 2500') x .0558 bpf x 1.3 = 298.2 1674.3 Total Lead 298.2 1674.3 12-1/4" OH x 9-5/8" Casing (7,611' - 6,611') x .0558 bpf x 1.3 = 72.5 407 9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09 Total Tail 81.6 458LeadTail 711 sx 394 sx Page 23 Milne Point Unit L-61 SB Injector Drilling Procedure 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 ) + (4,991’ x .0758 bpf )= 565.1 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 Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 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 okay Page 24 Milne Point Unit L-61 SB Injector Drilling Procedure 13.15 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. 13.16 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. 13.17 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 L-61 SB Injector Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre-job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 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: Section Calculation Vol (bbl) Vol (ft3) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1 = 28.6 161 12-1/4" OH x 9-5/8" Casing (2000' - 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 12-1/4" OH x 9-5/8" Casing (2500' - 2000') x .0558 bpf x 2 = 55.8 314 Total Tail 55.8 314LeadTail Cement Slurry Design (2nd stage cement job): 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 439 sx 270 sx Page 26 Milne Point Unit L-61 SB Injector Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500’ x .0747 bpf = 186.75 bbls mud 13.27 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. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 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 13.30 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. okay Page 27 Milne Point Unit L-61 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 3-1/2” x 6” 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 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. 24 hour notice to AOGCC Page 28 Milne Point Unit L-61 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. 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. 15.10 8-1/2” hole section mud program summary: FIT and casing test digital data to AOGCC for review. Page 29 Milne Point Unit L-61 SB Injector Drilling Procedure 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, this will help with solids removal. 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 Note: EMW=8.46 ppg DLB Page 30 Milne Point Unit L-61 SB Injector Drilling Procedure SAFE-CARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 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 .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. Reservoir plan is to undulate between Schrader OA1 & OA3 lobes in 1000-1500’ MD increments, and keep ing DLS <3° when moving between lobes 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 without having to backream connections x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections x AC, wells with CF less than 1.0: x M-11 is a SB OA injector, geologically there is no risk x M-12PB2 is a plug back/OHST of a SB OA producer, geologically there is no risk x M-13 is a SB OA injector, geologically there is no risk x Schrader Bluff Concretions: 5-10% of lateral 15.15 Reference: Open hole sidetracking practice: Page 31 Milne Point Unit L-61 SB Injector Drilling Procedure 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. x Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. 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 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x Ensure mud has necessary lube % for running liner x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0ppg minimum 15.17 Once hole is clean, displace to lubricated, viscosified 8.8 ppg 2% KCl brine. 15.18 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 15.19 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 If backreaming operations are commenced, continue backreaming to the shoe 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 15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.21 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 Page 32 Milne Point Unit L-61 SB Injector Drilling Procedure 15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.23 Continue to POH and stand back BHA if possible. 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 L-61 SB Injector Drilling Procedure 16.0 Run 4-1/2” Injection Liner (Lower Completion) 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 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 compo nents 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 Casing OD Minimum Optimum Maximum Operating Torque 4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 34 Milne Point Unit L-61 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. Page 35 Milne Point Unit L-61 SB Injector Drilling Procedure 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 ft/min – 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. 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. Page 36 Milne Point Unit L-61 SB Injector Drilling Procedure 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. With running tool line liner top, 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 L-61 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 wrivard@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” “X” nipple at TBD MD 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. , and XX joints of 3-1/2" tubing gauge mandrel Page 38 Milne Point Unit L-61 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 24 hour notice. Page 39 Milne Point Unit L-61 SB Injector Drilling Procedure 19.0 Doyon 14 Diverter Schematic Page 40 Milne Point Unit L-61 SB Injector Drilling Procedure 20.0 Doyon 14 BOP Schematic Page 41 Milne Point Unit L-61 SB Injector Drilling Procedure 21.0 Wellhead Schematic Page 42 Milne Point Unit L-61 SB Injector Drilling Procedure 22.0 Days Vs Depth Page 43 Milne Point Unit L-61 SB Injector Drilling Procedure 23.0 Formation Tops & Information MPU L-61 Formations (wp07) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2,048 -1860 1,909.4 840 8.46 LA3 5,826 -3414 3,463.4 1524 8.46 Ugnu MB 6,611 -3688 3,737.4 1644 8.46 Schrader Bluff NA 7,397 -3910 3,959.4 1742 8.46 Schrader Bluff NB 7,750 -3935 3,984.4 1753 8.46 L-Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) 8.46 Page 44 Milne Point Unit L-61 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. Page 45 Milne Point Unit L-61 SB Injector Drilling Procedure 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. Page 46 Milne Point Unit L-61 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 with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 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-11 is a SB OA injector, geologically there is no risk x M-12PB2 is a plug back/OHST of a SB OA producer, geologically there is no risk x M-13 is a SB OA injector, geologically there is no risk x p M-11 is a SB OA injector, geolo gicall y there is no risk x jggy M-12PB2 is a plug back/OHST of a SB OA producer, geologically there is no risk x pg p g M-13 is a SB OA injector, geologically there is no risk Page 47 Milne Point Unit L-61 SB Injector Drilling Procedure 25.0 Doyon 14 Layout Page 48 Milne Point Unit L-61 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 L-61 SB Injector Drilling Procedure 27.0 Doyon 14 Choke Manifold Schematic Page 50 Milne Point Unit L-61 SB Injector Drilling Procedure 28.0 Casing Design 12-1/4"Mud Density:9.2 ppg 8-1/2"Mud Density:9.2 ppg Mud Density: 1393 psi (see attached MASP determination & calculation) 1393 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress 1234 9-5/8"4-1/2" 07,611 03,978 7,611 14,320 3,978 3,798 7,611 6,709 40 12.6 L-80 L-80 DWC H625 304,440 84,533 304,440 84,533 916 279 3.01 3.30 1,965 1,876 3,090 8,540 1.57 4.55 1,393 1,393 5,750 9,020 4.13 6.48 Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) DESIGN BY: Joe Engel Hole Size Casing Section Collapse Resistance w/o tension (Psi) Worst case safety factor (Burst) MASP: Production Mode Minimum Yield (psi) Weight (ppf) MASP (psi) Worst Case Safety Factor (Tension) Collapse Pressure at bottom (Psi) Worst Case Safety Factor (Collapse) Length Top (TVD) Tension at Top of Section (lbs) Design Criteria: Hole Size Grade Connection Calculation & Casing Design Factors Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) MASP: Drilling Mode MASP: Hole Size DATE: 6.29.2020 WELL: MPU L-60 3.01 3.30 4.13 6.48 1.57 4.55 Page 51 Milne Point Unit L-61 SB Injector Drilling Procedure 29.0 8-1/2” Hole Section MASP MD TVD Planned Top: 7611 3978 Planned TD: 14320 3798 Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NB Sand 3,978 3,936 1750 Oil 8.46 0.440 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date MPU L-52 8.8-9.35 Surface 3952 2017 MPU L-51 8.9-9.3 Surface 3930 2017 MPU L-53 9-9.25 Surface 3891 2017 MPU J-27 9-9.3 Surface 3666 2015 MPU J-28 9-9.3 Surface 3617 2015 MPI - 19 9 - 9.3 ppg Surface 4,079 2004 MPI - 18 9 - 10 ppg Surface 3,848 2011 MPI - 17 9 - 9.5 ppg Surface 3,864 2004 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3978 (ft) x 0.78(psi/ft)= 3103 3103(psi) - [0.1(psi/ft)*3978(ft)]= 2705 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff NB sand) 3978 (ft) x 0.45(psi/ft)= 1790.0 psi 1790(psi) - 0.1(psi/ft)*3978(ft) 1393.0 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. Maximum Anticipated Surface Pressure Calculation 8-1/2" Hole Section MPU L-61 Milne Point Unit EMW=8.46 ppg DLB 3978 (ft) x 0.45(psi/ft)= 1790.0 psi 790(psi) - 0.1(psi/ft)*3978(ft)1393.0 psi 3978(ft) 0 45( i/ft) 1790 0 i 179 Page 52 Milne Point Unit L-61 SB Injector Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 53 Milne Point Unit L-61 SB Injector Drilling Procedure 31.0 Surface Plat (As Built) (NAD 27) Page 54 Milne Point Unit L-61 SB Injector Drilling Procedure 32.0 Schrader Bluff NB Sand Offset MW vs TVD Chart 08 June, 2020 Plan: MPU L-61i wp07 Milne Point M Pt L Pad Plan: MPU L-61i MPU L-61i 0750150022503000375045005250True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250Vertical Section at 191.70° (1500 usft/in)MPI-L-61 wp01 HeelMPI-L-61 wp01 Toe9 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000550060006500700075008 0 00 8 5 00 9 0 00 9 5 00 1 0 0 0 0 1 0 5 0 0 11 0 00 11 5 00 1 2 0 0 0 12 5 0 0 13 0 0 0 13 5 0 0 14 00 0 14 3 2 0MPU L-61i wp07Start Dir 3º/100' : 435' MD, 435'TVDStart Dir 4º/100' : 905' MD, 900.27'TVDEnd Dir : 3079' MD, 2506.17' TVDStartDir4º/100':6938.82'MD,3850.84'TVDEndDir:7460.97'MD,3965.83'TVDStartDir2º/100':7610.97'MD,3978.9'TVDEndDir:7946.22'MD,3988.53'TVDTotalDepth:14319.99'MD,3798.9'TVDHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Pedal CurveWarning Method: Error RatioWELL DETAILS: Plan: MPU L-61i15.20+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006031863.02544814.39 70° 29' 52.511 N 149° 38' 0.662 WSURVEY PROGRAMDate: 2020-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.20 1200.00 MPU L-61i wp07 (MPU L-61i) 3_Gyro-GC_Csg1200.00 7610.97 MPU L-61i wp07 (MPU L-61i) 3_MWD+IFR2+MS+Sag7610.97 14319.99 MPU L-61i wp07 (MPU L-61i) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSNo formation data is availableREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU L-61i, True NorthVertical (TVD) Reference:MPU L-61 As-built RKB @ 48.90usftMeasured Depth Reference:MPU L-61 As-built RKB @ 48.90usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt L PadWell:Plan: MPU L-61iWellbore:MPU L-61iDesign:MPU L-61i wp07CASING DETAILSTVD TVDSS MD SizeName3978.90 3930.00 7610.97 9-5/8 9 5/8" x 12 1/4"3798.90 3750.00 14319.99 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.20 0.00 0.00 33.20 0.00 0.00 0.00 0.00 0.002 435.00 0.00 0.00 435.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 435' MD, 435'TVD3 905.00 14.10 90.00 900.27 0.00 57.54 3.00 90.00 -11.67 Start Dir 4º/100' : 905' MD, 900.27'TVD4 1250.00 27.87 87.45 1221.62 3.60 180.73 4.00 -5.00 -40.185 2250.00 43.17 155.16 2062.73 -309.24 574.04 4.00 100.00 186.416 2650.00 57.98 163.06 2316.29 -597.51 681.62 4.00 25.00 446.877 3079.00 69.61 177.17 2506.17 -975.13 745.00 4.00 50.77 803.79 End Dir : 3079' MD, 2506.17' TVD8 6938.82 69.61 177.17 3850.84 -4588.74 923.54 0.00 0.00 4306.11 Start Dir 4º/100' : 6938.82' MD, 3850.84'TVD9 7460.97 85.00 191.70 3965.83 -5093.44 882.42 4.00 44.51 4808.67 End Dir : 7460.97' MD, 3965.83' TVD10 7610.97 85.00 191.70 3978.90 -5239.76 852.12 0.00 0.00 4958.10 MPI-L-61 wp01 Heel Start Dir 2º/100' : 7610.97' MD, 3978.9'TVD11 7946.22 91.70 191.70 3988.53 -5567.72 784.21 2.00 -0.01 5293.01 End Dir : 7946.22' MD, 3988.53' TVD12 14319.99 91.70 191.70 3798.90 -11806.33 -507.63 0.00 0.00 11663.97 MPI-L-61 wp01 Toe Total Depth : 14319.99' MD, 3798.9' TVD -12000 -11250 -10500 -9750 -9000 -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 South(-)/North(+) (1500 usft/in)-3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 West(-)/East(+) (1500 usft/in) MPI-L-61 wp01 Toe MPI-L-61 wp01 Heel 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 2 0 0 0 2 2 5 0 25 00 2 7 5 0 3 0 0 0 325 0 3 5 0 0 37 5 0 3799 MPU L-61i wp07 Start Dir 3º/100' : 435' MD, 435'TVD Start Dir 4º/100' : 905' MD, 900.27'TVD End Dir : 3079' MD, 2506.17' TVD Start Dir 4º/100' : 6938.82' MD, 3850.84'TVD End Dir : 7460.97' MD, 3965.83' TVD Start Dir 2º/100' : 7610.97' MD, 3978.9'TVD End Dir : 7946.22' MD, 3988.53' TVD Total Depth : 14319.99' MD, 3798.9' TVD CASING DETAILS TVD TVDSS MD Size Name 3978.90 3930.00 7610.97 9-5/8 9 5/8" x 12 1/4" 3798.90 3750.00 14319.99 4-1/2 4 1/2" x 8 1/2" Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-61i Wellbore: MPU L-61i Plan: MPU L-61i wp07 WELL DETAILS: Plan: MPU L-61i 15.20 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6031863.02 544814.39 70° 29' 52.511 N 149° 38' 0.662 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU L-61i, True North Vertical (TVD) Reference:MPU L-61 As-built RKB @ 48.90usft Measured Depth Reference:MPU L-61 As-built RKB @ 48.90usft Calculation Method:Minimum Curvature Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61 As-built RKB @ 48.90usft Design:MPU L-61i wp07 Database:NORTH US + CANADA MD Reference:MPU L-61 As-built RKB @ 48.90usft North Reference: Well Plan: MPU L-61i 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 L Pad, TR-13-10 usft Map usft usft °0.34Slot Radius:"0 6,029,799.28 544,529.55 0.00 70° 29' 32.230 N 149° 38' 9.412 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPU L-61i usft usft 0.00 0.00 6,031,863.02 544,814.39 15.20Wellhead Elevation:15.70 usft0.50 70° 29' 52.511 N 149° 38' 0.662 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU L-61i Model NameMagnetics BGGM2020 10/6/2020 15.89 80.89 57,376.29470126 Phase:Version: Audit Notes: Design MPU L-61i wp07 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.20 191.700.000.0033.20 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 0.000.000.000.000.000.0033.200.000.0033.20 -15.70 0.000.000.000.000.000.00435.000.000.00435.00 386.10 90.000.003.003.0057.540.00900.2790.0014.10905.00 851.37 -5.00-0.743.994.00180.733.601,221.6287.4527.871,250.00 1,172.72 100.006.771.534.00574.04-309.242,062.73155.1643.172,250.00 2,013.83 25.001.973.704.00681.62-597.512,316.29163.0657.982,650.00 2,267.39 50.773.292.714.00745.00-975.132,506.17177.1769.613,079.00 2,457.27 0.000.000.000.00923.54-4,588.743,850.84177.1769.616,938.82 3,801.94 44.512.782.954.00882.42-5,093.443,965.83191.7085.007,460.97 3,916.93 0.000.000.000.00852.12-5,239.763,978.90191.7085.007,610.97 3,930.00 -0.010.002.002.00784.21-5,567.723,988.53191.7091.707,946.22 3,939.63 0.000.000.000.00-507.63-11,806.333,798.90191.7091.7014,319.99 3,750.00 6/8/2020 4:22:54PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61 As-built RKB @ 48.90usft Design:MPU L-61i wp07 Database:NORTH US + CANADA MD Reference:MPU L-61 As-built RKB @ 48.90usft North Reference: Well Plan: MPU L-61i 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 -15.70 Vert Section 33.20 0.00 33.20 0.00 0.000.00 544,814.396,031,863.02-15.70 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 544,814.396,031,863.0251.10 0.00 0.00 200.00 0.00 200.00 0.00 0.000.00 544,814.396,031,863.02151.10 0.00 0.00 300.00 0.00 300.00 0.00 0.000.00 544,814.396,031,863.02251.10 0.00 0.00 400.00 0.00 400.00 0.00 0.000.00 544,814.396,031,863.02351.10 0.00 0.00 435.00 0.00 435.00 0.00 0.000.00 544,814.396,031,863.02386.10 0.00 0.00 Start Dir 3º/100' : 435' MD, 435'TVD 500.00 1.95 499.99 0.00 1.1190.00 544,815.506,031,863.03451.09 3.00 -0.22 600.00 4.95 599.79 0.00 7.1290.00 544,821.516,031,863.06550.89 3.00 -1.44 700.00 7.95 699.15 0.00 18.3690.00 544,832.746,031,863.13650.25 3.00 -3.72 800.00 10.95 797.78 0.00 34.7790.00 544,849.166,031,863.23748.88 3.00 -7.05 905.00 14.10 900.27 0.00 57.5490.00 544,871.926,031,863.37851.37 3.00 -11.67 Start Dir 4º/100' : 905' MD, 900.27'TVD 1,000.00 17.89 991.58 0.27 83.7188.92 544,898.096,031,863.80942.68 4.00 -17.24 1,100.00 21.88 1,085.60 1.16 117.7088.18 544,932.076,031,864.881,036.70 4.00 -25.00 1,200.00 25.88 1,177.02 2.64 158.1587.66 544,972.506,031,866.611,128.12 4.00 -34.65 1,250.00 27.87 1,221.62 3.60 180.7387.45 544,995.076,031,867.711,172.72 4.00 -40.18 1,300.00 27.59 1,265.88 3.78 203.9891.71 545,018.326,031,868.031,216.98 4.00 -45.06 1,400.00 27.42 1,354.61 -1.06 249.80100.37 545,064.166,031,863.471,305.71 4.00 -49.62 1,500.00 27.79 1,443.26 -12.78 294.51108.97 545,108.956,031,852.011,394.36 4.00 -47.21 1,600.00 28.67 1,531.40 -31.34 337.91117.22 545,152.456,031,833.721,482.50 4.00 -37.83 1,700.00 30.02 1,618.59 -56.65 379.78124.91 545,194.466,031,808.671,569.69 4.00 -21.55 1,800.00 31.79 1,704.42 -88.57 419.91131.91 545,234.796,031,776.991,655.52 4.00 1.58 1,900.00 33.89 1,788.46 -126.95 458.11138.19 545,273.226,031,738.841,739.56 4.00 31.42 2,000.00 36.28 1,870.30 -171.62 494.20143.77 545,309.576,031,694.401,821.40 4.00 67.84 2,100.00 38.90 1,949.56 -222.34 528.00148.73 545,343.676,031,643.891,900.66 4.00 110.65 2,200.00 41.71 2,025.83 -278.88 559.34153.14 545,375.346,031,587.551,976.93 4.00 159.66 2,250.00 43.17 2,062.73 -309.24 574.04155.16 545,390.226,031,557.282,013.83 4.00 186.41 2,300.00 44.99 2,098.65 -340.96 588.31156.36 545,404.696,031,525.652,049.75 4.00 214.57 2,400.00 48.66 2,167.07 -408.30 616.23158.54 545,433.016,031,458.482,118.17 4.00 274.85 2,500.00 52.37 2,230.65 -480.59 643.21160.48 545,460.426,031,386.372,181.75 4.00 340.17 2,600.00 56.10 2,289.09 -557.46 669.11162.24 545,486.786,031,309.662,240.19 4.00 410.19 2,650.00 57.98 2,316.29 -597.51 681.62163.06 545,499.536,031,269.692,267.39 4.00 446.87 2,700.00 59.26 2,342.33 -638.53 693.40164.86 545,511.566,031,228.752,293.43 4.00 484.65 2,800.00 61.89 2,391.47 -723.23 713.56168.33 545,532.226,031,144.172,342.57 4.00 563.51 2,900.00 64.59 2,436.50 -811.14 729.06171.62 545,548.266,031,056.372,387.60 4.00 646.44 3,000.00 67.37 2,477.20 -901.82 739.85174.77 545,559.596,030,965.762,428.30 4.00 733.05 3,079.00 69.61 2,506.17 -975.13 745.00177.17 545,565.186,030,892.502,457.27 4.00 803.79 End Dir : 3079' MD, 2506.17' TVD 3,100.00 69.61 2,513.48 -994.79 745.97177.17 545,566.276,030,872.842,464.58 0.00 822.85 3,200.00 69.61 2,548.32 -1,088.41 750.60177.17 545,571.466,030,779.262,499.42 0.00 913.58 3,300.00 69.61 2,583.16 -1,182.03 755.23177.17 545,576.656,030,685.682,534.26 0.00 1,004.32 3,400.00 69.61 2,618.00 -1,275.65 759.85177.17 545,581.846,030,592.102,569.10 0.00 1,095.06 3,500.00 69.61 2,652.83 -1,369.27 764.48177.17 545,587.036,030,498.512,603.93 0.00 1,185.80 3,600.00 69.61 2,687.67 -1,462.90 769.10177.17 545,592.226,030,404.932,638.77 0.00 1,276.54 6/8/2020 4:22:54PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61 As-built RKB @ 48.90usft Design:MPU L-61i wp07 Database:NORTH US + CANADA MD Reference:MPU L-61 As-built RKB @ 48.90usft North Reference: Well Plan: MPU L-61i 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 2,673.61 Vert Section 3,700.00 69.61 2,722.51 -1,556.52 773.73177.17 545,597.416,030,311.352,673.61 0.00 1,367.27 3,800.00 69.61 2,757.35 -1,650.14 778.35177.17 545,602.606,030,217.772,708.45 0.00 1,458.01 3,900.00 69.61 2,792.19 -1,743.76 782.98177.17 545,607.796,030,124.182,743.29 0.00 1,548.75 4,000.00 69.61 2,827.02 -1,837.38 787.60177.17 545,612.986,030,030.602,778.12 0.00 1,639.49 4,100.00 69.61 2,861.86 -1,931.00 792.23177.17 545,618.176,029,937.022,812.96 0.00 1,730.23 4,200.00 69.61 2,896.70 -2,024.62 796.86177.17 545,623.366,029,843.442,847.80 0.00 1,820.96 4,300.00 69.61 2,931.54 -2,118.24 801.48177.17 545,628.556,029,749.852,882.64 0.00 1,911.70 4,400.00 69.61 2,966.37 -2,211.86 806.11177.17 545,633.746,029,656.272,917.47 0.00 2,002.44 4,500.00 69.61 3,001.21 -2,305.49 810.73177.17 545,638.936,029,562.692,952.31 0.00 2,093.18 4,600.00 69.61 3,036.05 -2,399.11 815.36177.17 545,644.126,029,469.112,987.15 0.00 2,183.92 4,700.00 69.61 3,070.89 -2,492.73 819.98177.17 545,649.316,029,375.523,021.99 0.00 2,274.65 4,800.00 69.61 3,105.73 -2,586.35 824.61177.17 545,654.506,029,281.943,056.83 0.00 2,365.39 4,900.00 69.61 3,140.56 -2,679.97 829.23177.17 545,659.696,029,188.363,091.66 0.00 2,456.13 5,000.00 69.61 3,175.40 -2,773.59 833.86177.17 545,664.886,029,094.783,126.50 0.00 2,546.87 5,100.00 69.61 3,210.24 -2,867.21 838.49177.17 545,670.076,029,001.193,161.34 0.00 2,637.61 5,200.00 69.61 3,245.08 -2,960.83 843.11177.17 545,675.256,028,907.613,196.18 0.00 2,728.34 5,300.00 69.61 3,279.91 -3,054.46 847.74177.17 545,680.446,028,814.033,231.01 0.00 2,819.08 5,400.00 69.61 3,314.75 -3,148.08 852.36177.17 545,685.636,028,720.453,265.85 0.00 2,909.82 5,500.00 69.61 3,349.59 -3,241.70 856.99177.17 545,690.826,028,626.863,300.69 0.00 3,000.56 5,600.00 69.61 3,384.43 -3,335.32 861.61177.17 545,696.016,028,533.283,335.53 0.00 3,091.30 5,700.00 69.61 3,419.27 -3,428.94 866.24177.17 545,701.206,028,439.703,370.37 0.00 3,182.03 5,800.00 69.61 3,454.10 -3,522.56 870.87177.17 545,706.396,028,346.123,405.20 0.00 3,272.77 5,900.00 69.61 3,488.94 -3,616.18 875.49177.17 545,711.586,028,252.533,440.04 0.00 3,363.51 6,000.00 69.61 3,523.78 -3,709.80 880.12177.17 545,716.776,028,158.953,474.88 0.00 3,454.25 6,100.00 69.61 3,558.62 -3,803.43 884.74177.17 545,721.966,028,065.373,509.72 0.00 3,544.99 6,200.00 69.61 3,593.46 -3,897.05 889.37177.17 545,727.156,027,971.793,544.56 0.00 3,635.72 6,300.00 69.61 3,628.29 -3,990.67 893.99177.17 545,732.346,027,878.203,579.39 0.00 3,726.46 6,400.00 69.61 3,663.13 -4,084.29 898.62177.17 545,737.536,027,784.623,614.23 0.00 3,817.20 6,500.00 69.61 3,697.97 -4,177.91 903.24177.17 545,742.726,027,691.043,649.07 0.00 3,907.94 6,600.00 69.61 3,732.81 -4,271.53 907.87177.17 545,747.916,027,597.463,683.91 0.00 3,998.68 6,700.00 69.61 3,767.64 -4,365.15 912.50177.17 545,753.106,027,503.873,718.74 0.00 4,089.41 6,800.00 69.61 3,802.48 -4,458.77 917.12177.17 545,758.296,027,410.293,753.58 0.00 4,180.15 6,900.00 69.61 3,837.32 -4,552.39 921.75177.17 545,763.486,027,316.713,788.42 0.00 4,270.89 6,938.82 69.61 3,850.84 -4,588.74 923.54177.17 545,765.496,027,280.383,801.94 0.00 4,306.11 Start Dir 4º/100' : 6938.82' MD, 3850.84'TVD 7,000.00 71.37 3,871.28 -4,646.37 925.47178.98 545,767.776,027,222.773,822.38 4.00 4,362.16 7,100.00 74.27 3,900.82 -4,741.88 924.75181.86 545,767.626,027,127.263,851.92 4.00 4,455.83 7,200.00 77.21 3,925.46 -4,838.62 919.22184.66 545,762.686,027,030.503,876.56 4.00 4,551.68 7,300.00 80.18 3,945.06 -4,936.12 908.92187.39 545,752.966,026,932.963,896.16 4.00 4,649.24 7,400.00 83.17 3,959.54 -5,033.89 893.88190.08 545,738.516,026,835.103,910.64 4.00 4,748.03 7,460.97 85.00 3,965.83 -5,093.44 882.42191.70 545,727.426,026,775.493,916.93 4.00 4,808.67 End Dir : 7460.97' MD, 3965.83' TVD 7,500.00 85.00 3,969.23 -5,131.51 874.54191.70 545,719.766,026,737.373,920.33 0.00 4,847.55 7,600.00 85.00 3,977.94 -5,229.06 854.34191.70 545,700.156,026,639.713,929.04 0.00 4,947.17 6/8/2020 4:22:54PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61 As-built RKB @ 48.90usft Design:MPU L-61i wp07 Database:NORTH US + CANADA MD Reference:MPU L-61 As-built RKB @ 48.90usft North Reference: Well Plan: MPU L-61i 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 3,930.00 Vert Section 7,610.97 85.00 3,978.90 -5,239.76 852.12191.70 545,698.006,026,629.003,930.00 0.00 4,958.10 Start Dir 2º/100' : 7610.97' MD, 3978.9'TVD - 9 5/8" x 12 1/4" 7,700.00 86.78 3,985.28 -5,326.72 834.11191.70 545,680.526,026,541.953,936.38 2.00 5,046.89 7,800.00 88.78 3,989.15 -5,424.56 813.85191.70 545,660.856,026,443.993,940.25 2.00 5,146.81 7,900.00 90.78 3,989.54 -5,522.48 793.57191.70 545,641.176,026,345.973,940.64 2.00 5,246.81 7,946.22 91.70 3,988.53 -5,567.73 784.20191.70 545,632.076,026,300.673,939.63 2.00 5,293.02 End Dir : 7946.22' MD, 3988.53' TVD 8,000.00 91.70 3,986.93 -5,620.37 773.30191.70 545,621.496,026,247.973,938.03 0.00 5,346.77 8,100.00 91.70 3,983.96 -5,718.24 753.04191.70 545,601.816,026,149.983,935.06 0.00 5,446.73 8,200.00 91.70 3,980.98 -5,816.12 732.77191.70 545,582.146,026,051.993,932.08 0.00 5,546.69 8,300.00 91.70 3,978.01 -5,914.00 712.50191.70 545,562.466,025,954.003,929.11 0.00 5,646.64 8,400.00 91.70 3,975.03 -6,011.88 692.23191.70 545,542.796,025,856.013,926.13 0.00 5,746.60 8,500.00 91.70 3,972.06 -6,109.76 671.96191.70 545,523.116,025,758.023,923.16 0.00 5,846.55 8,600.00 91.70 3,969.08 -6,207.64 651.70191.70 545,503.446,025,660.033,920.18 0.00 5,946.51 8,700.00 91.70 3,966.11 -6,305.52 631.43191.70 545,483.766,025,562.043,917.21 0.00 6,046.46 8,800.00 91.70 3,963.13 -6,403.40 611.16191.70 545,464.096,025,464.053,914.23 0.00 6,146.42 8,900.00 91.70 3,960.16 -6,501.28 590.89191.70 545,444.416,025,366.063,911.26 0.00 6,246.38 9,000.00 91.70 3,957.18 -6,599.16 570.63191.70 545,424.736,025,268.073,908.28 0.00 6,346.33 9,100.00 91.70 3,954.21 -6,697.04 550.36191.70 545,405.066,025,170.083,905.31 0.00 6,446.29 9,200.00 91.70 3,951.23 -6,794.92 530.09191.70 545,385.386,025,072.093,902.33 0.00 6,546.24 9,300.00 91.70 3,948.26 -6,892.80 509.82191.70 545,365.716,024,974.103,899.36 0.00 6,646.20 9,400.00 91.70 3,945.28 -6,990.68 489.55191.70 545,346.036,024,876.113,896.38 0.00 6,746.15 9,500.00 91.70 3,942.30 -7,088.56 469.29191.70 545,326.366,024,778.123,893.40 0.00 6,846.11 9,600.00 91.70 3,939.33 -7,186.43 449.02191.70 545,306.686,024,680.133,890.43 0.00 6,946.07 9,700.00 91.70 3,936.35 -7,284.31 428.75191.70 545,287.016,024,582.143,887.45 0.00 7,046.02 9,800.00 91.70 3,933.38 -7,382.19 408.48191.70 545,267.336,024,484.153,884.48 0.00 7,145.98 9,900.00 91.70 3,930.40 -7,480.07 388.21191.70 545,247.656,024,386.153,881.50 0.00 7,245.93 10,000.00 91.70 3,927.43 -7,577.95 367.95191.70 545,227.986,024,288.163,878.53 0.00 7,345.89 10,100.00 91.70 3,924.45 -7,675.83 347.68191.70 545,208.306,024,190.173,875.55 0.00 7,445.84 10,200.00 91.70 3,921.48 -7,773.71 327.41191.70 545,188.636,024,092.183,872.58 0.00 7,545.80 10,300.00 91.70 3,918.50 -7,871.59 307.14191.70 545,168.956,023,994.193,869.60 0.00 7,645.76 10,400.00 91.70 3,915.53 -7,969.47 286.87191.70 545,149.286,023,896.203,866.63 0.00 7,745.71 10,500.00 91.70 3,912.55 -8,067.35 266.61191.70 545,129.606,023,798.213,863.65 0.00 7,845.67 10,600.00 91.70 3,909.58 -8,165.23 246.34191.70 545,109.936,023,700.223,860.68 0.00 7,945.62 10,700.00 91.70 3,906.60 -8,263.11 226.07191.70 545,090.256,023,602.233,857.70 0.00 8,045.58 10,800.00 91.70 3,903.63 -8,360.99 205.80191.70 545,070.586,023,504.243,854.73 0.00 8,145.53 10,900.00 91.70 3,900.65 -8,458.87 185.53191.70 545,050.906,023,406.253,851.75 0.00 8,245.49 11,000.00 91.70 3,897.68 -8,556.74 165.27191.70 545,031.226,023,308.263,848.78 0.00 8,345.45 11,100.00 91.70 3,894.70 -8,654.62 145.00191.70 545,011.556,023,210.273,845.80 0.00 8,445.40 11,200.00 91.70 3,891.73 -8,752.50 124.73191.70 544,991.876,023,112.283,842.83 0.00 8,545.36 11,300.00 91.70 3,888.75 -8,850.38 104.46191.70 544,972.206,023,014.293,839.85 0.00 8,645.31 11,400.00 91.70 3,885.78 -8,948.26 84.19191.70 544,952.526,022,916.303,836.88 0.00 8,745.27 11,500.00 91.70 3,882.80 -9,046.14 63.93191.70 544,932.856,022,818.313,833.90 0.00 8,845.22 11,600.00 91.70 3,879.83 -9,144.02 43.66191.70 544,913.176,022,720.323,830.93 0.00 8,945.18 11,700.00 91.70 3,876.85 -9,241.90 23.39191.70 544,893.506,022,622.333,827.95 0.00 9,045.14 6/8/2020 4:22:54PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61 As-built RKB @ 48.90usft Design:MPU L-61i wp07 Database:NORTH US + CANADA MD Reference:MPU L-61 As-built RKB @ 48.90usft North Reference: Well Plan: MPU L-61i 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 3,824.98 Vert Section 11,800.00 91.70 3,873.88 -9,339.78 3.12191.70 544,873.826,022,524.343,824.98 0.00 9,145.09 11,900.00 91.70 3,870.90 -9,437.66 -17.15191.70 544,854.146,022,426.353,822.00 0.00 9,245.05 12,000.00 91.70 3,867.92 -9,535.54 -37.41191.70 544,834.476,022,328.363,819.02 0.00 9,345.00 12,100.00 91.70 3,864.95 -9,633.42 -57.68191.70 544,814.796,022,230.373,816.05 0.00 9,444.96 12,200.00 91.70 3,861.97 -9,731.30 -77.95191.70 544,795.126,022,132.383,813.07 0.00 9,544.91 12,300.00 91.70 3,859.00 -9,829.18 -98.22191.70 544,775.446,022,034.393,810.10 0.00 9,644.87 12,400.00 91.70 3,856.02 -9,927.06 -118.49191.70 544,755.776,021,936.403,807.12 0.00 9,744.83 12,500.00 91.70 3,853.05 -10,024.93 -138.75191.70 544,736.096,021,838.413,804.15 0.00 9,844.78 12,600.00 91.70 3,850.07 -10,122.81 -159.02191.70 544,716.426,021,740.423,801.17 0.00 9,944.74 12,700.00 91.70 3,847.10 -10,220.69 -179.29191.70 544,696.746,021,642.433,798.20 0.00 10,044.69 12,800.00 91.70 3,844.12 -10,318.57 -199.56191.70 544,677.076,021,544.443,795.22 0.00 10,144.65 12,900.00 91.70 3,841.15 -10,416.45 -219.82191.70 544,657.396,021,446.453,792.25 0.00 10,244.60 13,000.00 91.70 3,838.17 -10,514.33 -240.09191.70 544,637.716,021,348.463,789.27 0.00 10,344.56 13,100.00 91.70 3,835.20 -10,612.21 -260.36191.70 544,618.046,021,250.473,786.30 0.00 10,444.52 13,200.00 91.70 3,832.22 -10,710.09 -280.63191.70 544,598.366,021,152.483,783.32 0.00 10,544.47 13,300.00 91.70 3,829.25 -10,807.97 -300.90191.70 544,578.696,021,054.493,780.35 0.00 10,644.43 13,400.00 91.70 3,826.27 -10,905.85 -321.16191.70 544,559.016,020,956.503,777.37 0.00 10,744.38 13,500.00 91.70 3,823.30 -11,003.73 -341.43191.70 544,539.346,020,858.513,774.40 0.00 10,844.34 13,600.00 91.70 3,820.32 -11,101.61 -361.70191.70 544,519.666,020,760.523,771.42 0.00 10,944.29 13,700.00 91.70 3,817.35 -11,199.49 -381.97191.70 544,499.996,020,662.533,768.45 0.00 11,044.25 13,800.00 91.70 3,814.37 -11,297.37 -402.24191.70 544,480.316,020,564.543,765.47 0.00 11,144.21 13,900.00 91.70 3,811.40 -11,395.24 -422.50191.70 544,460.646,020,466.553,762.50 0.00 11,244.16 14,000.00 91.70 3,808.42 -11,493.12 -442.77191.70 544,440.966,020,368.563,759.52 0.00 11,344.12 14,100.00 91.70 3,805.45 -11,591.00 -463.04191.70 544,421.286,020,270.573,756.55 0.00 11,444.07 14,200.00 91.70 3,802.47 -11,688.88 -483.31191.70 544,401.616,020,172.583,753.57 0.00 11,544.03 14,300.00 91.70 3,799.49 -11,786.76 -503.58191.70 544,381.936,020,074.593,750.59 0.00 11,643.98 14,319.99 91.70 3,798.90 -11,806.33 -507.63191.70 544,378.006,020,055.003,750.00 0.00 11,663.97 Total Depth : 14319.99' MD, 3798.9' TVD Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Tar gets Dip Angle (°) Dip Dir. (°) MPI-L-61 wp01 Toe 3,798.90 6,020,055.00 544,378.00-11,806.33 -507.630.00 0.00 -plan hits target center - Point MPI-L-61 wp01 Heel 3,978.90 6,026,629.00 545,698.00-5,239.76 852.120.00 0.00 -plan hits target center - Point 6/8/2020 4:22:54PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt L Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU L-61i MPU L-61i Survey Calculation Method:Minimum Curvature MPU L-61 As-built RKB @ 48.90usft Design:MPU L-61i wp07 Database:NORTH US + CANADA MD Reference:MPU L-61 As-built RKB @ 48.90usft North Reference: Well Plan: MPU L-61i True Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 4 1/2" x 8 1/2"3,798.9014,319.99 4-1/2 8-1/2 9 5/8" x 12 1/4"3,978.907,610.97 9-5/8 12-1/4 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 435.00 435.00 0.00 0.00 Start Dir 3º/100' : 435' MD, 435'TVD 905.00 900.27 0.00 57.54 Start Dir 4º/100' : 905' MD, 900.27'TVD 3,079.00 2,506.17 -975.13 745.00 End Dir : 3079' MD, 2506.17' TVD 6,938.82 3,850.84 -4,588.74 923.54 Start Dir 4º/100' : 6938.82' MD, 3850.84'TVD 7,460.97 3,965.83 -5,093.44 882.42 End Dir : 7460.97' MD, 3965.83' TVD 7,610.97 3,978.90 -5,239.76 852.12 Start Dir 2º/100' : 7610.97' MD, 3978.9'TVD 7,946.22 3,988.53 -5,567.73 784.20 End Dir : 7946.22' MD, 3988.53' TVD 14,319.99 3,798.90 -11,806.33 -507.63 Total Depth : 14319.99' MD, 3798.9' TVD 6/8/2020 4:22:54PM COMPASS 5000.15 Build 91E Page 7 08 June, 2020Milne PointM Pt L PadPlan: MPU L-61iMPU L-61iMPU L-61i wp07Reference Design: M Pt L Pad - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,031,863.02 N, 544,814.39 E (70° 29' 52.51" N, 149° 38' 00.66" W)Datum Height: MPU L-61 As-built RKB @ 48.90usftScan Range: 33.20 to 7,610.97 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 L-61i - MPU L-61i wp07Comparison 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: 33.20 to 7,610.97 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt L PadMPL-05 - MPL-05 - MPL-05278.31 1,693.72 263.56 1,702.10 18.8721,693.72Ellipse Separation Pass - MPL-05 - MPL-05 - MPL-05284.36 1,783.20 268.83 1,762.03 18.3161,783.20Clearance Factor Pass - MPL-06 - MPL-06 - MPL-06107.16 2,131.41 89.41 2,117.54 6.0382,131.41Centre Distance Pass - MPL-06 - MPL-06 - MPL-06107.17 2,133.20 89.39 2,118.59 6.0282,133.20Ellipse Separation Pass - MPL-06 - MPL-06 - MPL-06109.39 2,158.20 91.16 2,133.02 5.9982,158.20Clearance Factor Pass - MPL-07 - MPL-07 - MPL-07168.14 1,701.57 154.88 1,612.11 12.6791,701.57Ellipse Separation Pass - MPL-07 - MPL-07 - MPL-07169.53 1,733.20 156.01 1,635.11 12.5381,733.20Clearance Factor Pass - MPL-07 - MPL-07PB1 - MPL-07PB1168.14 1,701.57 154.88 1,612.11 12.6791,701.57Ellipse Separation Pass - MPL-07 - MPL-07PB1 - MPL-07PB1169.53 1,733.20 156.01 1,635.11 12.5381,733.20Clearance Factor Pass - MPL-08 - MPL-08 - MPL-0850.55 1,400.73 38.71 1,366.94 4.2681,400.73Clearance Factor Pass - MPL-09 - MPL-09 - MPL-09120.07 1,657.54 106.05 1,588.86 8.5601,657.54Centre Distance Pass - MPL-09 - MPL-09 - MPL-09120.07 1,658.20 106.04 1,589.44 8.5581,658.20Ellipse Separation Pass - MPL-09 - MPL-09 - MPL-09120.52 1,683.20 106.32 1,611.19 8.4881,683.20Clearance Factor Pass - MPL-09 - MPL-09A - MPL-09A120.07 1,657.54 106.05 1,588.86 8.5601,657.54Centre Distance Pass - MPL-09 - MPL-09A - MPL-09A120.07 1,658.20 106.04 1,589.44 8.5581,658.20Ellipse Separation Pass - MPL-09 - MPL-09A - MPL-09A120.52 1,683.20 106.32 1,611.19 8.4881,683.20Clearance Factor Pass - MPL-09 - MPL-09APB1 - MPL-09APB1120.07 1,657.54 106.05 1,588.86 8.5601,657.54Centre Distance Pass - MPL-09 - MPL-09APB1 - MPL-09APB1120.07 1,658.20 106.04 1,589.44 8.5581,658.20Ellipse Separation Pass - MPL-09 - MPL-09APB1 - MPL-09APB1120.52 1,683.20 106.32 1,611.19 8.4881,683.20Clearance Factor Pass - MPL-10 - MPL-10 - MPL-10142.88 1,801.72 127.43 1,712.88 9.2491,801.72Centre Distance Pass - MPL-10 - MPL-10 - MPL-10142.91 1,808.20 127.42 1,718.39 9.2251,808.20Ellipse Separation Pass - MPL-10 - MPL-10 - MPL-10143.56 1,833.20 127.91 1,739.57 9.1751,833.20Clearance Factor Pass - MPL-11 - MPL-11 - MPL-1170.95 1,733.20 54.47 1,715.87 4.3061,733.20Clearance Factor Pass - MPL-11 - MPL-11 - MPL-1170.01 1,748.20 54.21 1,725.54 4.4321,748.20Ellipse Separation Pass - MPL-12 - MPL-12 - MPL-12108.19 3,133.20 46.90 2,814.13 1.7653,133.20Clearance Factor Pass - MPL-12 - MPL-12 - MPL-12101.87 3,158.20 45.28 2,831.75 1.8003,158.20Ellipse Separation Pass - MPL-12 - MPL-12 - MPL-1297.63 3,199.91 51.08 2,861.40 2.0973,199.91Centre Distance Pass - MPL-14 - MPL-14 - MPL-14119.26 1,476.66 107.40 1,417.14 10.0541,476.66Ellipse Separation Pass - 08 June, 2020-16:24COMPASSPage 2 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-61i - MPU L-61i wp07Comparison 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: 33.20 to 7,610.97 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPL-14 - MPL-14 - MPL-14119.35 1,483.20 107.45 1,421.94 10.0271,483.20Clearance Factor Pass - MPL-16 - MPL-16 - MPL-16103.26 761.09 96.65 781.08 15.613761.09Centre Distance Pass - MPL-16 - MPL-16 - MPL-16103.35 783.20 96.57 803.84 15.232783.20Ellipse Separation Pass - MPL-16 - MPL-16 - MPL-16113.33 1,008.20 104.74 1,036.43 13.1891,008.20Clearance Factor Pass - MPL-16 - MPL-16A - MPL-16A103.26 761.09 96.65 775.29 15.613761.09Centre Distance Pass - MPL-16 - MPL-16A - MPL-16A103.35 783.20 96.57 798.05 15.232783.20Ellipse Separation Pass - MPL-16 - MPL-16A - MPL-16A113.33 1,008.20 104.74 1,030.64 13.1891,008.20Clearance Factor Pass - MPL-17 - MPL-17 - MPL-1712.73 325.41 10.05 327.52 4.757325.41Centre Distance Pass - MPL-17 - MPL-17 - MPL-1712.93 383.20 9.91 385.24 4.291383.20Ellipse Separation Pass - MPL-17 - MPL-17 - MPL-1715.20 558.20 11.15 559.78 3.757558.20Clearance Factor Pass - MPL-20 - MPL-20 - MPL-20110.25 273.35 107.44 274.30 39.241273.35Centre Distance Pass - MPL-20 - MPL-20 - MPL-20110.34 308.20 107.28 308.51 36.048308.20Ellipse Separation Pass - MPL-20 - MPL-20 - MPL-20135.23 658.20 129.51 648.11 23.652658.20Clearance Factor Pass - MPL-21 - MPL-21 - MPL-2114.77 458.20 10.57 455.57 3.521458.20Centre Distance Pass - MPL-21 - MPL-21 - MPL-2114.88 483.20 10.49 480.58 3.393483.20Ellipse Separation Pass - MPL-21 - MPL-21 - MPL-2116.19 558.20 11.23 555.59 3.265558.20Clearance Factor Pass - MPL-24 - MPL-24 - MPL-24117.74 458.20 113.42 462.01 27.260458.20Ellipse Separation Pass - MPL-24 - MPL-24 - MPL-24140.65 758.20 133.98 760.71 21.094758.20Clearance Factor Pass - MPL-25 - MPL-25 - MPL-2545.46 33.20 44.05 30.30 32.17133.20Centre Distance Pass - MPL-25 - MPL-25 - MPL-2545.56 108.20 43.97 105.18 28.723108.20Ellipse Separation Pass - MPL-25 - MPL-25 - MPL-2553.99 583.20 49.83 578.63 12.958583.20Clearance Factor Pass - MPL-28 - MPL-28 - MPL-28131.09 400.80 127.22 401.83 33.904400.80Centre Distance Pass - MPL-28 - MPL-28 - MPL-28131.17 433.20 127.06 433.58 31.930433.20Ellipse Separation Pass - MPL-28 - MPL-28 - MPL-28161.38 733.20 154.95 726.95 25.128733.20Clearance Factor Pass - MPL-28 - MPL-28A - MPL-28A131.09 400.80 127.22 401.83 33.904400.80Centre Distance Pass - MPL-28 - MPL-28A - MPL-28A131.17 433.20 127.06 433.58 31.930433.20Ellipse Separation Pass - MPL-28 - MPL-28A - MPL-28A161.38 733.20 154.95 726.95 25.128733.20Clearance Factor Pass - MPL-29 - MPL-29 - MPL-2973.32 458.20 69.84 461.67 21.081458.20Centre Distance Pass - MPL-29 - MPL-29 - MPL-2973.44 483.20 69.81 486.64 20.246483.20Ellipse Separation Pass - MPL-29 - MPL-29 - MPL-2987.19 758.20 81.85 759.76 16.330758.20Clearance Factor Pass - 08 June, 2020-16:24COMPASSPage 3 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-61i - MPU L-61i wp07Comparison 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: 33.20 to 7,610.97 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPL-32 - MPL-32 - MPL-32152.64 267.69 149.76 269.28 53.133267.69Centre Distance Pass - MPL-32 - MPL-32 - MPL-32152.85 333.20 149.50 333.59 45.640333.20Ellipse Separation Pass - MPL-32 - MPL-32 - MPL-32188.11 708.20 181.93 691.98 30.411708.20Clearance Factor Pass - MPL-33 - MPL-33 - MPL-33105.93 329.33 102.59 331.15 31.741329.33Centre Distance Pass - MPL-33 - MPL-33 - MPL-33106.18 408.20 102.25 409.32 27.016408.20Ellipse Separation Pass - MPL-33 - MPL-33 - MPL-33128.88 708.20 122.66 700.15 20.715708.20Clearance Factor Pass - MPL-42 - MPL-42 - MPL-42223.89 1,250.63 214.92 1,186.22 24.9691,250.63Ellipse Separation Pass - MPL-42 - MPL-42 - MPL-421,623.66 6,708.20 1,464.69 6,594.68 10.2146,708.20Clearance Factor Pass - MPL-43 - MPL-43 - MPL-4321.78 829.18 16.10 828.34 3.835829.18Ellipse Separation Pass - MPL-43 - MPL-43 - MPL-4321.80 833.20 16.11 832.22 3.830833.20Clearance Factor Pass - MPL-43 - MPL-43PB1 - MPL-43PB121.78 829.18 16.10 828.34 3.835829.18Ellipse Separation Pass - MPL-43 - MPL-43PB1 - MPL-43PB121.80 833.20 16.11 832.22 3.830833.20Clearance Factor Pass - MPL-45 - MPL-45 - MPL-45129.65 411.54 126.74 413.22 44.534411.54Centre Distance Pass - MPL-45 - MPL-45 - MPL-45129.69 433.20 126.65 434.38 42.714433.20Ellipse Separation Pass - MPL-45 - MPL-45 - MPL-451,371.32 7,610.97 1,124.74 7,293.26 5.5617,610.97Clearance Factor Pass - MPL-46 - MPL-46 - MPL-46267.57 2,337.10 250.17 2,057.89 15.3812,337.10Ellipse Separation Pass - MPL-46 - MPL-46 - MPL-46505.49 7,083.20 410.41 8,529.53 5.3167,083.20Clearance Factor Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB1267.57 2,337.10 250.17 2,057.89 15.3812,337.10Ellipse Separation Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB1505.49 7,083.20 410.24 8,529.53 5.3077,083.20Clearance Factor Pass - MPL-47 - MPL-47 - MPL-47328.66 1,204.70 314.19 1,154.26 22.7131,204.70Centre Distance Pass - MPL-47 - MPL-47 - MPL-47328.67 1,208.20 314.16 1,156.64 22.6591,208.20Ellipse Separation Pass - MPL-47 - MPL-47 - MPL-471,181.47 7,610.97 1,071.12 9,453.79 10.7067,610.97Clearance Factor Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1328.66 1,204.70 314.19 1,154.26 22.7131,204.70Centre Distance Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1328.67 1,208.20 314.16 1,156.64 22.6591,208.20Ellipse Separation Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB11,181.47 7,610.97 1,070.95 9,453.79 10.6907,610.97Clearance Factor Pass - MPL-48 - MPL-48 - MPL-48246.61 7,610.97 154.10 9,073.65 2.6667,610.97Clearance Factor Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3232.74 7,610.97 142.01 9,084.34 2.5657,610.97Clearance Factor Pass - MPL-49 - MPL-49 - MPL-49359.53 1,552.86 349.92 1,402.42 37.4021,552.86Centre Distance Pass - MPL-49 - MPL-49 - MPL-49359.53 1,558.20 349.89 1,406.31 37.2911,558.20Ellipse Separation Pass - MPL-49 - MPL-49 - MPL-49993.10 6,383.20 912.65 6,906.67 12.3446,383.20Clearance Factor Pass - 08 June, 2020-16:24COMPASSPage 4 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-61i - MPU L-61i wp07Comparison 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: 33.20 to 7,610.97 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPL-50 - MPL-50 - MPL-50490.04 177.09 487.52 179.70 193.900177.09Centre Distance Pass - MPL-50 - MPL-50 - MPL-50490.31 233.20 487.24 231.12 159.311233.20Ellipse Separation Pass - MPL-50 - MPL-50 - MPL-501,618.56 4,183.20 1,576.25 2,735.87 38.2564,183.20Clearance Factor Pass - MPU L-41 - MPU L-41 - MPU L-41118.76 33.20 117.35 34.50 84.06733.20Centre Distance Pass - MPU L-41 - MPU L-41 - MPU L-41118.93 158.20 117.17 159.05 67.759158.20Ellipse Separation Pass - MPU L-41 - MPU L-41 - MPU L-41138.48 1,008.20 132.73 1,034.15 24.0641,008.20Clearance Factor Pass - MPU L-41 - MPU L-41PB1 - MPU L-41PB1118.76 33.20 117.35 34.50 84.06733.20Centre Distance Pass - MPU L-41 - MPU L-41PB1 - MPU L-41PB1118.93 158.20 117.17 159.05 67.759158.20Ellipse Separation Pass - MPU L-41 - MPU L-41PB1 - MPU L-41PB1138.48 1,008.20 132.73 1,034.15 24.0641,008.20Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-51163.10 233.01 160.97 226.31 76.502233.01Centre Distance Pass - MPU L-51 - MPU L-51 - MPU L-51163.18 258.20 160.94 250.46 72.714258.20Ellipse Separation Pass - MPU L-51 - MPU L-51 - MPU L-51199.23 658.20 194.98 626.89 46.797658.20Clearance Factor Pass - MPU L-52 - MPU L-52 - MPU L-52171.66 438.92 168.56 432.93 55.406438.92Ellipse Separation Pass - MPU L-52 - MPU L-52 - MPU L-52198.33 708.20 193.86 684.48 44.412708.20Clearance Factor Pass - MPU L-53 - MPU L-53 - MPU L-53186.65 33.20 185.24 26.50 132.22233.20Centre Distance Pass - MPU L-53 - MPU L-53 - MPU L-53187.02 158.20 185.03 149.84 93.730158.20Ellipse Separation Pass - MPU L-53 - MPU L-53 - MPU L-53240.15 708.20 234.63 666.96 43.527708.20Clearance Factor Pass - MPU L-54 - MPU L-54 - MPU L-54112.77 518.09 109.18 522.56 31.433518.09Centre Distance Pass - MPU L-54 - MPU L-54 - MPU L-54112.82 533.20 109.15 537.77 30.771533.20Ellipse Separation Pass - MPU L-54 - MPU L-54 - MPU L-541,619.75 4,783.20 1,551.15 4,065.80 23.6134,783.20Clearance Factor Pass - MPU L-55 - MPU L-55 - MPU L-5554.73 816.45 49.96 811.79 11.472816.45Ellipse Separation Pass - MPU L-55 - MPU L-55 - MPU L-5555.58 858.20 50.66 851.17 11.312858.20Clearance Factor Pass - MPU L-56 - MPU L-56 - MPU L-56150.24 200.62 147.49 201.09 54.591200.62Centre Distance Pass - MPU L-56 - MPU L-56 - MPU L-56150.53 283.20 146.90 282.24 41.532283.20Ellipse Separation Pass - MPU L-56 - MPU L-56 - MPU L-56186.76 708.20 178.50 686.02 22.622708.20Clearance Factor Pass - MPU L-57 - MPU L-57 - MPU L-57135.56 33.20 134.15 34.00 96.02833.20Centre Distance Pass - MPU L-57 - MPU L-57 - MPU L-57136.36 483.20 133.05 484.47 41.224483.20Ellipse Separation Pass - MPU L-57 - MPU L-57 - MPU L-57155.94 733.20 151.32 718.61 33.735733.20Clearance Factor Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1135.56 33.20 134.15 34.00 96.02833.20Centre Distance Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1136.36 483.20 133.05 484.47 41.224483.20Ellipse Separation Pass - 08 June, 2020-16:24COMPASSPage 5 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-61i - MPU L-61i wp07Comparison 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: 33.20 to 7,610.97 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU L-57 - MPU L-57PB1 - MPU L-57PB1155.94 733.20 151.32 718.61 33.735733.20Clearance Factor Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp0550.04 1,052.24 39.37 1,079.40 4.6891,052.24Ellipse Separation Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp0550.08 1,058.20 39.38 1,085.20 4.6791,058.20Clearance Factor Pass - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09198.99 311.01 196.30 311.31 74.169311.01Centre Distance Pass - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09199.06 358.20 196.16 357.55 68.858358.20Ellipse Separation Pass - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp091,560.01 7,610.97 1,414.85 6,974.32 10.7467,610.97Clearance Factor Pass - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp05489.37 234.76 486.98 236.06 205.161234.76Centre Distance Pass - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp05531.94 5,058.20 464.98 4,171.22 7.9445,058.20Ellipse Separation Pass - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp05786.77 7,610.97 639.39 7,083.66 5.3387,610.97Clearance Factor Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09507.95 260.49 505.45 261.89 203.707260.49Centre Distance Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09507.95 283.20 505.36 283.66 196.305283.20Ellipse Separation Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09766.64 7,610.97 626.41 6,482.37 5.4677,610.97Clearance Factor Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60507.95 33.20 506.03 34.67 265.73733.20Centre Distance Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60508.05 208.20 505.83 207.66 228.832208.20Ellipse Separation Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60774.19 7,610.97 632.14 6,484.67 5.4507,610.97Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.20 1,200.00 MPU L-61i wp07 3_Gyro-GC_Csg1,200.00 7,610.97 MPU L-61i wp07 3_MWD+IFR2+MS+Sag7,610.97 14,319.99 MPU L-61i wp07 3_MWD+IFR2+MS+Sag08 June, 2020-16:24COMPASSPage 6 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-61i - MPU L-61i wp07Ellipse 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.08 June, 2020-16:24COMPASSPage 7 of 9 0.001.002.003.004.00Separation Factor0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600Measured Depth (800 usft/in)MPL-11MPL-08MPL-12MPL-43MPL-48 PB3MPL-48MPL-21MPL-17No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU L-61i NAD 1927 (NADCON CONUS)Alaska Zone 0415.20+N/-S +E/-W Northing Easting Latittude Longitude0.000.006031863.02544814.39 70° 29' 52.511 N149° 38' 0.662 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU L-61i, True NorthVertical (TVD) Reference:MPU L-61 As-built RKB @ 48.90usftMeasured Depth Reference:MPU L-61 As-built RKB @ 48.90usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.20 1200.00 MPU L-61i wp07 (MPU L-61i) 3_Gyro-GC_Csg1200.00 7610.97 MPU L-61i wp07 (MPU L-61i) 3_MWD+IFR2+MS+Sag7610.97 14319.99 MPU L-61i wp07 (MPU L-61i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600Measured Depth (800 usft/in)MPU L-51MPL-33MPL-29MPL-28MPU L-52MPL-45MPU L-55MPL-16MPL-20MPU L-56MPL-43MPL-25MPU L-41MPL-21MPU L-54MPL-32MPU L-57MPL-24MPL-17MPU L-58 wp05NO GLOBAL FILTER: Using user defined selection & filtering criteria33.20 To 14319.99Project: Milne PointSite: M Pt L PadWell: Plan: MPU L-61iWellbore: MPU L-61iPlan: MPU L-61i wp07Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3978.90 3930.00 7610.97 9-5/8 9 5/8" x 12 1/4"3798.90 3750.00 14319.99 4-1/2 4 1/2" x 8 1/2" 08 June, 2020Milne PointM Pt L PadPlan: MPU L-61iMPU L-61iMPU L-61i wp07Reference Design: M Pt L Pad - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,031,863.02 N, 544,814.39 E (70° 29' 52.51" N, 149° 38' 00.66" W)Datum Height: MPU L-61 As-built RKB @ 48.90usftScan Range: 7,610.97 to 14,319.99 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 L-61i - MPU L-61i wp07Comparison 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: 7,610.97 to 14,319.99 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt L PadMPL-45 - MPL-45 - MPL-451,202.48 9,710.97 873.38 9,365.00 3.6549,710.97Clearance Factor Pass - MPL-45 - MPL-45 - MPL-451,200.65 9,760.97 872.71 9,365.00 3.6619,760.97Ellipse Separation Pass - MPL-45 - MPL-45 - MPL-451,200.50 9,779.97 873.14 9,365.00 3.6679,779.97Centre Distance Pass - MPL-46 - MPL-46 - MPL-46894.93 7,610.97 773.32 8,797.68 7.3597,610.97Clearance Factor Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB1894.93 7,610.97 773.15 8,797.68 7.3497,610.97Clearance Factor Pass - MPL-47 - MPL-47 - MPL-47168.64 8,893.60 117.36 9,957.65 3.2888,893.60Centre Distance Pass - MPL-47 - MPL-47 - MPL-47179.34 8,960.97 112.35 9,986.20 2.6778,960.97Ellipse Separation Pass - MPL-47 - MPL-47 - MPL-47212.35 9,035.97 121.88 10,017.57 2.3479,035.97Clearance Factor Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1168.64 8,893.60 117.19 9,957.65 3.2778,893.60Centre Distance Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1179.34 8,960.97 112.18 9,986.20 2.6708,960.97Ellipse Separation Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1212.35 9,035.97 121.71 10,017.57 2.3439,035.97Clearance Factor Pass - MPL-48 - MPL-48 - MPL-48137.74 7,827.90 92.79 9,159.14 3.0657,827.90Centre Distance Pass - MPL-48 - MPL-48 - MPL-48148.13 7,885.97 83.18 9,183.02 2.2817,885.97Ellipse Separation Pass - MPL-48 - MPL-48 - MPL-48170.92 7,935.97 87.34 9,204.69 2.0457,935.97Clearance Factor Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3141.28 7,802.11 95.04 9,148.31 3.0557,802.11Centre Distance Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3152.30 7,860.97 84.48 9,168.36 2.2467,860.97Ellipse Separation Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3191.53 7,935.97 93.65 9,193.96 1.9577,935.97Clearance Factor Pass - MPL-50 - MPL-50 - MPL-50172.28 10,050.55 113.92 11,107.55 2.95210,050.55Centre Distance Pass - MPL-50 - MPL-50 - MPL-50188.06 10,135.97 105.28 11,147.09 2.27210,135.97Ellipse Separation Pass - MPL-50 - MPL-50 - MPL-50223.31 10,210.97 117.12 11,179.53 2.10310,210.97Clearance Factor Pass - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp091,516.21 14,258.95 1,256.47 13,606.75 5.83714,258.95Clearance Factor Pass - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp05680.98 14,260.25 420.31 13,727.59 2.61214,260.25Centre Distance Pass - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp05682.87 14,310.97 419.00 13,727.59 2.58814,310.97Ellipse Separation Pass - Plan: MPU L-62 - MPU L-62 - MPU L-62 wp05683.60 14,319.99 419.31 13,727.59 2.58714,319.99Clearance Factor Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09744.88 14,235.97 489.10 13,129.37 2.91214,235.97Clearance Factor Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09744.47 14,260.67 489.19 13,129.37 2.91614,260.67Centre Distance Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60773.45 7,960.97 617.72 6,840.00 4.9677,960.97Clearance Factor Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60773.33 7,974.60 618.16 6,840.00 4.9847,974.60Centre Distance Pass - 08 June, 2020-16:25COMPASSPage 2 of 6 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-61i - MPU L-61i wp07Comparison 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: 7,610.97 to 14,319.99 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt Moose PadMPU M-10 - MPU M-10 - MPU M-10212.5410,760.9743.7714,337.061.25910,760.97Clearance FactorPass - MPU M-10 - MPU M-10 - MPU M-10197.0710,785.9741.3714,345.211.26610,785.97Ellipse SeparationPass - MPU M-10 - MPU M-10 - MPU M-10154.40 10,915.70 92.87 14,387.74 2.50910,915.70Centre Distance Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3233.8310,735.9761.1514,303.871.35410,735.97Clearance FactorPass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3219.6810,760.9759.6114,314.441.37210,760.97Ellipse SeparationPass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3177.11 10,904.18 113.55 14,374.82 2.78710,904.18Centre Distance Pass - MPU M-11 - MPU M-11 - MPU M-11178.2211,660.97-56.9714,892.270.75811,660.97Ellipse SeparationFAIL - MPU M-11 - MPU M-11 - MPU M-11162.1711,685.97-54.6414,901.460.74811,685.97Clearance FactorFAIL - MPU M-11 - MPU M-11 - MPU M-11122.35 11,800.98 44.79 14,943.91 1.57711,800.98Centre Distance Pass - MPU M-12 - MPU M-12 - MPU M-12231.4312,535.97-5.6515,463.240.97612,535.97Clearance FactorFAIL - MPU M-12 - MPU M-12 - MPU M-12171.02 12,703.02 85.89 15,519.21 2.00912,703.02Centre Distance Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2231.4312,535.97-5.7715,463.240.97612,535.97Clearance FactorFAIL - MPU M-12 - MPU M-12PB2 - MPU M-12PB2171.02 12,703.02 85.77 15,519.21 2.00612,703.02Centre Distance Pass - MPU M-13 - MPU M-13i - MPU M-13216.6913,435.97-27.9915,140.270.88613,435.97Clearance FactorFAIL - MPU M-13 - MPU M-13i - MPU M-13161.89 13,597.58 74.40 15,212.16 1.85013,597.58Centre Distance Pass - MPU M-14 - MPU M-14 - MPU M-14276.1514,319.9943.3315,535.531.18614,319.99Clearance FactorPass - MPU M-15i - MPU M-15 - MPU M-15i1,011.78 14,319.99 700.92 15,411.98 3.25514,319.99Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.20 1,200.00 MPU L-61i wp07 3_Gyro-GC_Csg1,200.00 7,610.97 MPU L-61i wp07 3_MWD+IFR2+MS+Sag7,610.97 14,319.99 MPU L-61i wp07 3_MWD+IFR2+MS+Sag08 June, 2020-16:25COMPASSPage 3 of 6 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-61i - MPU L-61i wp07Ellipse 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.08 June, 2020-16:25COMPASSPage 4 of 6 0.001.002.003.004.00Separation Factor7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500 13875 14250 14625Measured Depth (750 usft/in)MPL-45MPU M-10MPU L-60 wp09No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU L-61i NAD 1927 (NADCON CONUS)Alaska Zone 0415.20+N/-S +E/-W Northing Easting Latittude Longitude0.000.006031863.02544814.3970° 29' 52.511 N149° 38' 0.662 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU L-61i, True NorthVertical (TVD) Reference:MPU L-61 As-built RKB @ 48.90usftMeasured Depth Reference:MPU L-61 As-built RKB @ 48.90usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.20 1200.00 MPU L-61i wp07 (MPU L-61i) 3_Gyro-GC_Csg1200.00 7610.97 MPU L-61i wp07 (MPU L-61i) 3_MWD+IFR2+MS+Sag7610.97 14319.99 MPU L-61i wp07 (MPU L-61i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500 13875 14250 14625Measured Depth (750 usft/in)MPL-50NO GLOBAL FILTER: Using user defined selection & filtering criteria33.20 To 14319.99Project: Milne PointSite: M Pt L PadWell: Plan: MPU L-61iWellbore: MPU L-61iPlan: MPU L-61i wp07Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3978.90 3930.00 7610.97 9-5/8 9 5/8" x 12 1/4"3798.90 3750.00 14319.99 4-1/2 4 1/2" x 8 1/2" _____________________________________________________________________________________ Revised By: CJD 6/30/20 Proposed Schematic Milne Point Unit Well: MPU L-61 PTD: TBD API: TBD Depth MD Depth TVD ICD/Swell Packer Detail TBD TD = 14,320’ (MD) / TD = 3,798’ (TVD) 20” Orig. KB Elev.: 48.9’/ GL Elev.:15.2’ 3-1/2”2 9-5/8”88 1 3/4 6 See ICD & Swell Packer Detail PBTD = 14,320’ (MD) / PBTD = 3,798’(TVD) 9-5/8” ‘ES’ Cementer @ ±2200’ MD 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"Conductor 216 /A53 / Weld N/A Surface 114’N/A 9-5/8"Surface 47 / L-80 / TXP 8.525”Surface 2,000’0.0732 9-5/8"Surface 40 / L-80 / TXP 8.679”2,000’7,611’0.0758 4-1/2”Liner 13.5 / L-80 / Hyd 625 3.795” 7,461’14,320’0.0149 TUBING DETAIL 3-1/2"Tubing 9.3 / L-80 / EUE 8RD 2.867”Surf 7,461’’0.0087 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 ±6,001’3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 ±6,064’Brace XN Landing Nipple w/ 2.750” Packing Bore 2.813” 3 7,461’8.25” No Go Locater Sub ( 1.45’ off No-go)6.170” 4 7,465’Bullet Seals –Mule Shoe bottom @ 7,465’ MD 6.170” Lower Completion 5 7,461’7” x 9-5/8” SLZXP Liner Top Packer 6.180” 6 14,318’Shoe Bottom @ 14,320’’ MD 3.970” OPEN HOLE / CEMENT DETAIL 42"±270 ft3 12-1/4" Stg 1 –Lead 1674 ft3 /Tail 458 ft3 Stg 2 –Lead 1937 ft3 / Tail 314 ft3 8-1/2”Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 435’ Hole Angle @ XN = TBD° Hole Angle @ Liner Top = TBD° Max Hole Angle = 92° TREE & WELLHEAD Tree Cameron 3 1/8"5M w/3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: TBD Completed by Doyon 14:Future Depth MD Depth TVD ICD/Swell Packer Detail 5,020’ 3,826’ Tendeka Water Swell Packer 5,245’ 3,823’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 5,348’ 3,822’ Tendeka Water Swell Packer 5,985’ 3,820’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,253’ 3,820’ Tendeka Water Swell Packer 6,767’ 3,833’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,076’ 3,831’ Tendeka Water Swell Packer 8,002’ 3,887’ Tendeka Water Swell Packer 8,144’ 3,895’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,531’ 3,908’ Tendeka Water Swell Packer 8,838’ 3,918’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,938’ 3,922’ Tendeka Water Swell Packer 9,322’ 3,900’ Tendeka Water Swell Packer 9,583’ 3,890’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,985’ 3,890’ Tendeka Water Swell Packer 10,300’ 3,897’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,819’ 3,915’ Tendeka Water Swell Packer 11,085’ 3,920’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,558’ 3,928’ Tendeka Water Swell Packer 11,942’ 3,933’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,292’ 3,936’ Tendeka Water Swell Packer 12,765’ 3,953’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 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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