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DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:DriDyn, Ann Press/MPR, Comp NEU POR, GR, CBL, MudlogNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleC12/17/20194390 90 Electronic Data Set, Filename: (2954) GP-53RD, CBL, 11-14-19, Field Log.las31683EDDigital DataC12/17/2019 Electronic File: (2954) GP-53rd, CBL, 11-14-19, Field Log.pdf31683EDDigital Data0 0 2190790 GRANITE POINT 53RD LOG HEADERS31683LogLog Header Scans0 0 2190790 GRANITE POINT 53RD LOG HEADERS31690LogLog Header ScansC12/13/20194536 14407 Electronic Data Set, Filename: DD_Depth_MEM_0.25_Hilcorp_GP-53RD.las31690EDDigital DataC12/13/20194540 14407 Electronic Data Set, Filename: FE_MEM_0.25_Hilcorp_GP-53RD.las31690EDDigital DataC12/13/2019 Electronic File: FE_MD2MEM_Hilcorp_GP-53RD.cgm31690EDDigital DataC12/13/2019 Electronic File: FE_MD5MEM_Hilcorp_GP-53RD.cgm31690EDDigital DataC12/13/2019 Electronic File: FE_TVD2MEM_Hilcorp_GP-53RD.cgm31690EDDigital DataC12/13/2019 Electronic File: FE_TVD5MEM_Hilcorp_GP-53RD.cgm31690EDDigital DataC12/13/2019 Electronic File: VSS_MD5MEM_Hilcorp_GP-53RD.cgm31690EDDigital DataC12/13/2019 Electronic File: VSS_TIME_MEM_Hilcorp_GP-53RD.cgm31690EDDigital DataC12/13/2019 Electronic File: FE_MD2MEM_Hilcorp_GP-53RD.pdf31690EDDigital DataFriday, April 3, 2020AOGCCPage 1 of 23PB1~,FE_MEM_0.25_Hilcorp_GP-53RD.lasSupplied by OPSupplied by OP DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: FE_MD5MEM_Hilcorp_GP-53RD.pdf31690EDDigital DataC12/13/2019 Electronic File: FE_TVD2MEM_Hilcorp_GP-53RD.pdf31690EDDigital DataC12/13/2019 Electronic File: FE_TVD5MEM_Hilcorp_GP-53RD.pdf31690EDDigital DataC12/13/2019 Electronic File: VSS_MD5MEM_Hilcorp_GP-53RD.pdf31690EDDigital DataC12/13/2019 Electronic File: VSS_TIME_MEM_Hilcorp_GP-53RD.pdf31690EDDigital DataC12/13/2019 Electronic File: GP-53RD_Surveys.pdf31690EDDigital DataC12/13/2019 Electronic File: GP-53RD_Surveys.txt31690EDDigital DataC12/13/2019 Electronic File: FE_MD2MEM_Hilcorp_GP-53RD.tif31690EDDigital DataC12/13/2019 Electronic File: FE_MD5MEM_Hilcorp_GP-53RD.tif31690EDDigital DataC12/13/2019 Electronic File: FE_TVD2MEM_Hilcorp_GP-53RD.tif31690EDDigital DataC12/13/2019 Electronic File: FE_TVD5MEM_Hilcorp_GP-53RD.tif31690EDDigital DataC12/13/2019 Electronic File: VSS_MD5MEM_Hilcorp_GP-53RD.tif31690EDDigital DataC12/13/2019 Electronic File: VSS_TIME_MEM_Hilcorp_GP-53RD.tif31690EDDigital DataC12/18/20194100 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Report 08192019.pdf31692EDDigital DataC12/13/2019 Electronic File: Hilcorp GP-53RD, Nabors AM Report 08202019.pdf31692EDDigital DataC12/13/2019 Electronic File: Hilcorp GP-53RD, Nabors AM Report 08212019.pdf31692EDDigital DataFriday, April 3, 2020AOGCCPage 4 of 23GP-53RD.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp GP-53RD, Nabors AM Report 08222019.pdf31692EDDigital DataC12/13/2019 Electronic File: Hilcorp GP-53RD, Nabors AM Report 08232019.pdf31692EDDigital DataC12/13/2019 Electronic File: Hilcorp GP-53RD, Nabors AM Report 08242019.pdf31692EDDigital DataC12/13/2019 Electronic File: Hilcorp GP-53RD, Nabors AM Report 08252019.pdf31692EDDigital DataC12/13/2019 Electronic File: Hilcorp GP-53RD, Nabors AM Report 08262019.pdf31692EDDigital DataC12/13/2019 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53RD - Formation Log MD.pdf31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - Formation Log TVD.pdf31692EDDigital DataFriday, April 3, 2020AOGCCPage 6 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: GP 53RD - Gas Ratio Log MD.pdf31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - Gas Ratio Log TVD.pdf31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - LWD Combo Log MD.pdf31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - LWD Combo Log TVD.pdf31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - 5in Drilling Dynamics Log MD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - 5in Drilling Dynamics Log TVD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - 5in Formation Log MD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - 5in Formation Log TVD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - 5in Gas Ratio Log MD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - 5in Gas Ratio Log TVD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - 5in LWD Combo Log MD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - 5in LWD Combo Log TVD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - Drilling Dynamics Log MD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - Drilling Dynamics Log TVD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - Formation Log MD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - Formation Log TVD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - Gas Ratio Log MD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - Gas Ratio Log TVD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - LWD Combo Log MD.tif31692EDDigital DataC12/13/2019 Electronic File: GP 53RD - LWD Combo Log TVD.tif31692EDDigital DataFriday, April 3, 2020AOGCCPage 7 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10860'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10880'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10890'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10900'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10910'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10920'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10924'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10928'.jpg31692EDDigital DataC12/13/2019 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Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11085'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11090'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11095'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11100'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11120'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11140'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11160'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11180'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11200'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11220'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11240'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11260'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11280'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11300'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11320'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11340'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11360'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11380'.jpg31692EDDigital DataFriday, April 3, 2020AOGCCPage 9 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11400'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11420'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11440'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11460'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11480'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11500'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11520'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11540'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11560'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11580'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11584'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11587'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11594'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11600'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11610'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11615'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11620'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11640'.jpg31692EDDigital DataFriday, April 3, 2020AOGCCPage 10 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11660'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11680'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11700'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11720'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11740'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11760'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11780'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11800' hard mineral.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11800'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11820'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11840'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11860'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11880'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11900'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11916'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11920'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11940'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11960'.jpg31692EDDigital DataFriday, April 3, 2020AOGCCPage 11 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11980'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12000'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12020'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12040'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12060'.jpg31692EDDigital DataC12/13/2019 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12390'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12420'.jpg31692EDDigital DataFriday, April 3, 2020AOGCCPage 12 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12450'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12480'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12510'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12540'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12570'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12600'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12630'.jpg31692EDDigital DataC12/13/2019 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No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12960'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 12990'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13020'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13050'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13080'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13110'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13140'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13170'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13200'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13230'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13260'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13290'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13320'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13350'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13380'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13410'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13440'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13463'.jpg31692EDDigital DataFriday, April 3, 2020AOGCCPage 14 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13470'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13500'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13530'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13560'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13590'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13620'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13650'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13680'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13710'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13740'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13770'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13800'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13830'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13845'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13860'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13875'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13880'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13890'.jpg31692EDDigital DataFriday, April 3, 2020AOGCCPage 15 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13920'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13950'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 13980'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14010'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14040'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14070'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14100'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14130'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14160'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14190'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14220'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14250'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14280'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14310'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14340'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14370'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14400'.jpg31692EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 14407 BU'.jpg31692EDDigital DataFriday, April 3, 2020AOGCCPage 16 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Show Report 1 GP 53RD 10270-10305.pdf31692EDDigital DataC12/13/2019 Electronic File: Show Report 2 GP 53RD 10780-10875.pdf31692EDDigital DataC12/13/2019 Electronic File: Show Report 3 GP 53RD 10952-11138.pdf31692EDDigital DataC12/13/2019 Electronic File: Show Report 4 GP 53RD 11370-11493.pdf31692EDDigital DataC12/13/2019 Electronic File: Show Report 5 GP 53RD 11574-11663.pdf31692EDDigital DataC12/13/2019 Electronic File: Show Report 6 GP 53RD 11665-13405.pdf31692EDDigital DataC12/13/2019 Electronic File: Show Report 7 GP 53RD 13528-13793.pdf31692EDDigital DataC12/13/2019 Electronic File: Show Report 8 GP 53RD 13927-14407.pdf31692EDDigital DataC12/13/20194000 11920 Electronic Data Set, Filename: GP-53RD PB1.las31693EDDigital DataC12/13/2019 Electronic File: gp_53-PB1rd.hdr31693EDDigital DataC12/13/2019 Electronic File: gp_53-PB1rdr.dbf31693EDDigital DataC12/13/2019 Electronic File: gp_53-PB1rdr.mdx31693EDDigital DataC12/13/2019 Electronic File: GP_53RD-PB1.dbf31693EDDigital DataC12/13/2019 Electronic File: GP_53RD-PB1.mdx31693EDDigital DataC12/13/2019 Electronic File: GP_53RD-PB1_SCL.DBF31693EDDigital DataC12/13/2019 Electronic File: GP_53RD-PB1_SCL.MDX31693EDDigital DataC12/13/2019 Electronic File: GP_53RD-PB1_TVD.DBF31693EDDigital DataC12/13/2019 Electronic File: GP_53RD-PB1_TVD.mdx31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Drilling Dynamics Log MD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Drilling Dynamics Log TVD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Formation Log MD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Formation Log TVD.pdf31693EDDigital DataFriday, April 3, 2020AOGCCPage 17 of 23GP-53RD PB1.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Gas Ratio Log MD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Gas Ratio Log TVD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in LWD Combo Log MD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in LWD Combo Log TVD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Drilling Dynamics Log MD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Drilling Dynamics Log TVD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Formation Log MD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Formation Log TVD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Gas Ratio Log MD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Gas Ratio Log TVD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - LWD Combo Log MD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - LWD Combo Log TVD.pdf31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Drilling Dynamics Log MD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Drilling Dynamics Log TVD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Formation Log MD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Formation Log TVD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Gas Ratio Log MD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in Gas Ratio Log TVD.tif31693EDDigital DataFriday, April 3, 2020AOGCCPage 18 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: GP 53RD_PB1 - 5in LWD Combo Log MD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - 5in LWD Combo Log TVD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Drilling Dynamics Log MD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Drilling Dynamics Log TVD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Formation Log MD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Formation Log TVD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Gas Ratio Log MD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - Gas Ratio Log TVD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - LWD Combo Log MD.tif31693EDDigital DataC12/13/2019 Electronic File: GP 53RD_PB1 - LWD Combo Log TVD.tif31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10860.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10880.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10890.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10900.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10910.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10920.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10924.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10928.jpg31693EDDigital DataFriday, April 3, 2020AOGCCPage 19 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10940.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10960.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 10980.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11000.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11020.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11040.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11060.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11140.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11160.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11180.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11200.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11220.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11240.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11260.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11280.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11300.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11320.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11340.jpg31693EDDigital DataFriday, April 3, 2020AOGCCPage 20 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11360.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11380.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11400.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11420.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11500.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11520.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11540.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11560.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11580.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11600.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11620.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11640.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11660.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11680.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11700.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11720.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11740.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11760.jpg31693EDDigital DataFriday, April 3, 2020AOGCCPage 21 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:11/19/2019Release Date:6/12/2019C12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11780.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11858(BU).jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11860.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11880.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11900.jpg31693EDDigital DataC12/13/2019 Electronic File: Hilcorp Alaska LLC GP 53RD 11913.jpg31693EDDigital Data0 0 2190790 GRANITE POINT 53RD PB1 LOG HEADERS31693LogLog Header Scans9/30/20199000 144071723Cuttings9/30/201911560 11913 PB11724CuttingsFriday, April 3, 2020AOGCCPage 22 of 23 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20471-01-00Well Name/No. GRANITE POINT 53RDCompletion Status1-OILCompletion Date11/19/2019Permit to Drill2190790Operator Hilcorp Alaska LLCMD14406TVD10435Current Status1-OIL4/3/2020UICNoComments:Compliance Reviewed By:Date:Friday, April 3, 2020AOGCCPage 23 of 23M. Guhl5/14/2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION GEC 19 2u99 WELL COMPLETION OR RECOMPLETION REPORT QC 1 a. Well Status: Oil ❑✓ • Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAG❑ WDSPL ❑ No. of Completions: 1 1 b. Well Ia +-.0 Development Q ' Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 11/19/2019 14. Permit to Drill Number / Sundry: 219-079 / 319-336 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: July 13, 2019 15. API Number: 50-733-20471-01-00 ' 4a. Location of Well (Governmental Section): Surface: 2434' FNL, 1310' FWL, Sec 13, T10N, R12W, SM, AK - Top of Productive Interval: 1043' FNL, 668' FEL, Sec 23, T1 ON, R1 2W, SM, AK Total Depth: 1133' FSL, 353' FWL, Sec 24, T10N, R12W, SM, AK 8. Date TD Reached: September 6, 2019 16. Well Name and Number: GP 53RD 9. Ref Elevations: KB: 132' - GL: N/A BF: N/A 17. Field / Pool(s): Granite Point Field Middle Kenai Oil Pool 10. Plug Back Depth MD/TVD: 14,319' MD / 10,412' TVD 18. Property Designation: ADLO18761 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 263342 • y- 2544497 Zone- 4 • TPI: x- 261287 y- 2540649 Zone- Total Depth: x- 262246 y- 2537524 Zone- 4 11. Total Depth MD/TVD: ' 14,406' MD / 10,435' TVD 19. DNR Approval Number: LOCI 19-001 12. SSSV Depth MD/TVD: 351'/ 351' 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: Yes ✓ (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: 75 (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: 4,551' MD / 4,093' TVD 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary DRILLING DYNAMICS, ANNULAR PRESSURE / MPR, COMP NEUTRON POROSITY, GR / P61, CBL 11-14-19 / Mudlog 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD HOLE SIZE CEMENTING RECORD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM PULLED 7" 29# L-80 4,301' 10,860' - 3,907' 9,450' 8-3/8" L - 403 sx / T - 122 sx 5" 18# P-110 10,681' 14,405' 9,356' 10,435' 6-1/8" L - 296 sx 24. Open to production or injection? Yes Q No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 10,880'- 13,880' MD / 9,459'- 10,272' TVD ' 6 SPF, 3-1/8", 11/16/19 COMPLETION Dq� fl 1 In 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 2-7/8" 10,725' 10,644' MD / 9,335' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes [:]No Q Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): 11/23/2019 Gas Lift Date of Test: 12/15/2019 Hours Tested: 24 Production for Oil -Bbl: Test Period 110951 > Gas -MCF: 440 Water -Bbl: 0 Choke Size: N/A Gas -Oil Ratio: 401 Flow Tubing Press. 60 Casing Press: 847 Calculated Oil -Bbl: 24 -Hour Rate _.Jo� 1095 Gas -MCF: 440 Water -Bbl: 0 Oil Gravity - API (corr): 37 Form 10-407 Revised 5/2017 _� CONTINUED ON PAGE 2 Submit ORIGINIAL only RnM--"' DEC 2 4 2019 SFD 4/2/2020 SDSR-4/2/2020 G 28. CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cores: Yes ❑ No Q If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD ND Well tested? Yes ❑ No ❑✓ If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base N/A N/A Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 10,880' C5 9,459' information, including reports, per 20 AAC 25.071. C1 9,932' 8,815' C2 10,234' 9,060' C5C1 10,629' 9,326' C5C2 10,736' 9,386' C5A 10,780' 9,410' Formation at total depth: C5 31. List of Attachments: Wellbore Schematic, Drilling and Completions reports, Definitive Directional Surveys, Csg and Cmt Reports. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilli g Vanager. Contact Email: cdinger@hilcorp.com Authorized 2 Contact Phone: 777-8389 Signature: ate: INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only G r i Granite Point Field SCHEMATIC Well: GP -53RD Last Completed: 11/19/2019 PTD: 219-079 Hilcorp Alaska, LLC API: 50-733-20471-01 ORKB to MLLW 156.22'; ORKB to Mudline = 231.22' PBTD:14,277' TD: 14,407 CASING DETAIL Size Wt Grade Conn ID Top Btm 33" Outside Driven Conductor Welded 11.000 Surf 229' 26" Inside Driven Conductor Welded 4.650" Surf 294' 13-3/8" 68 K-55 BTC 12.415" Surf 1,031' 4,799' 47 L-80 BTC 8.681" Surf 73' 9-5/8- 53.5 P-110 BTC 8.535" 73' 4,551' 7" 29 L-80 DWC/C 6.184" 4,301' 10,860' 5" 18 P-110 ICY Hydril513 4.194" 10,681' 14,405' TUBING DETAIL 2-7/8" 6.5 L-80 8 rnd EUE 1 2.441" 1 Surface 10,725' jq JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item Date 55.47' 55.47' 3.500 11.000 Hanger—Cactus-en-ccl w/ 3.5" 8RD lift and suspension threads w/ CIW Type "H" BPV profile w/ 3 control line ports, 17-4ph SS material 1 351' 351' 2.313" 4.650" SSSV — Halliburton NE TRSV 2,497' 2,481' 2.441" 4.750" GLM #1— Priority PSPO-1M w/R-1 valve & BK -2 latch 4,799' 4,286' 2.441" 4.750" GLM #2 — Priority PSPO-1M w/R-1 valve & BK -2 latch 6,258' 5,547' 2.441" 4.750" GLM #3 — Priority PSPO-1M w/R-1 valve & BK -2 latch 7,216' 6,400' 2.441" 4.750" GLM #4 — Priority PSPO-IM w/R-1 valve & BK -2 latch 2 7,831' 6,948' 2.441" 4.750" GLM #5 — Priority PSPO-1M w/R-1 valve & BK -2 latch 8,446' 7,496' 2.441" 4.750" GLM #6 — Priority PSPO-11V! w/R-1 valve & BK -2 latch 9,124' 8,100' 2.441" 4.750" GLM #7 — Priority PSPO-11V! w/R-1 valve & BK -2 latch 9,801' 8,702' 2.441" 4.750" GLM #8 — Priority PSPO-1M w/R-1 valve & BK -2 latch 10,572' 9,293' 2.441" 4.750" GLM #9 — Priority PSPO-1M w/R-1 orifice & BK -2 latch 3 10,625' 9,324' 2.421" 4.966" Halliburton ROC Gauge Mandrel w/ 0.25" TEC wire 4 10,644' 9,335' 2.416" 5.968" Packer — Map Oil Tools - MFH Hydraulic 5 10,684' 9,358' 2.205" 3.668" XN-Nipple 6 10,725' 9,380' 2.370" 3.230" Indexing WLEG PERFORATION DETAIL ie Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status i 10,880' 13,880' 9,459' 10,272' 3,000' 11/16/19 Open Updated By: JLL 12/02/19 iii Well Name: GPF GP -53RD Field: Granite Point Unit County/State: , Alaska (LAT/LONG): oration (RKB): API #: Spud Date: Job Name: 1911671D GP -53RD Drilling Contractor Spartan 151 AFE #: AFE $: Hilcorp Energy Company Composite Report Activity. Pate, Ops 5t rt ttt 7/7/2019 Clearing main deck. Hanging wing decks, Off load and spot service shacks. Getting spool measurements for nippling up BOPs.;Wire in and RU service shacks. Change shaker screens to 80s, RU hose from GP Platform to Spartan for taking on OBM. RU vac unit to suck cuttings from cuttings tank. Pump OBM from platform beam tanks to Spartan mud pits.;Continue pumping OBM from GP Platform Beam tank to Spartan mud pits. Total 1365 bbls MOBM on Spartan 151 @ 21:00 hrs. Blow Dn transfer hoses from GPP. Continue staging miscellaneous equipment off main deck. Offload MN Sovereign onto Spartan 151.;Install #2 deep well pump. Install suction screens on #1 & #2 mud pumps Stage & prep BOP components for N/U. M/U 11" x 13 5/8" riser components on main deck.;P/U riser to rig floor. Lower & M/U riser to wellhead on GP 53RD. M/U DSA to riser. P/U & M/U BOP stack to riser. Be in M/U BOP control lines. 7/8/2019 Continue nipple up. Finish rigging up accumulator lines, choke and kill line. Change the upper rams to 5 x 2 7/8 VBRs. Secure stack. Start plumbing LVT tank and lines. Baker hands checking tools. Canrig working on PVTs.;Install both sections of the flow nipple. Baker running lines and getting all their equip set up. Continue working on plumbing in LVT lines. Ended up pulling top section of flow nipple and cutting it down. Re -install flow nipple. Install trip tank & bleed off lines on bell nipple.;R & R Kelly hose to install Baker pressure unit. Relocate valve on pump #1 suction strainer basket. Set & stage test pump on rig floor. Clean & clear main deck in prep for receiving DP. General rig clean up. Clean up Texas deck area. Baker hands continue checking & strapping tools.;Begin offload M/V Titan. Offload 166 jts 5' DP & strap on main deck. Clean & Clear chemical room Begin offload Baroid mud products. Plumb in test pump. Continue plumbing LVT tank. 7/9/2019 Bring on potable water off the boat. Finish offloading M/V Titan. Unload mud products and store in chem room and under pipe racks. Clean out chemical hopper room. Prep to PU DP. Rig up LVT lines. Wire & check test pump. Calibrate Canrig sensors on rig floor & shakers.;Prespud meeting for GP 53RD w/ Anchorage, GPP, & Rig Teams.;P/U 5' DP & M/U stands in the mouse hole. Rack back same in derrick. Drift all jts. (54 stands in derrick) R/U diesel hose f/ Spartan 151 t/ GPP. Hold PJSM w/ Rig & GPP operators. Pump diesel f/ GPP to Spartan 151. Prep to pretest BOPs. Crane over test jt and equipment from GPP to Spartan 151.;Finish pumping diesel f/ GPP to Spartan 151. (20,790 gals) M/U BOP test assembly. Set test plug. Begin pretest BOPS @ 250 psi low / 3500 psi high. .Begin offloading M/V Titan. 7/10/2019 Pull and reconfigure test joint in order to put tool jts above Ann. and below BPR.;Fill BOPE with water. R/U test hose and pump.;Tie salt water hose to side entry sub and fill test joint, kill line, choke line and choke manifold with water. Installed Baker Hughes directional sensor on stand pipe while waiting on lines to fill. (Weather hold lifted @ 11:30 hours);Change out bad Canrig PVT sensor and calibrate new one. Change out 15K chart recorder for 6K recorder. Verify chart and gauge read the same.;Shell test BOPE /w 250 psi low and 3500 psi high. Inspect all flanges and connections for leaks- GOOD. AOGCC; Housekeeping and general cleanup while waiting on AOGCC inspector Guy Cook to arrive for rig inspection and initial BOPE test.;Conduct rig inspection with Guy Cook (AOGCC), Bruce Hebert (Spartan OIM) and Cliff Horn (Spartan HSE). All good with the exception of needing to install strobes in well head room.;Test BOPE per PTD with AOGCC inspector Guy Cook as witness. Begin testing to 250 psi low / 3500 psi high for 5 min. per test.;On 2nd test realized chart recorder had a 4 hr chart with clock set at 90 min. (No 4 hr setting on clock). Changed clock setting. Function test hydril and manual chokes.;Test PVT system and gas alarms. (Total Safety installed strobes in well head room during BOPE testing). All tests performed @ 250 psi low / 3500 psi high for 5 min. per test. Test all manifold valves, Manual & HCR chokes, Floor safety valves. Test upper & lower IBOPs.;Test Annular @ 250 psi low 13500 psi high. Test Upper, Lower & Blind Shear Rams. Perform draw down test on accum. Remove test plug. Drain stack. Change out two isolation valves on test pump. C/O IBOP floor valve.;Offload MfV Titan. 7/11/2019 Test IBOP valve w/ 250psi low/ 3500 psi high chart and hold for 5 min ea. test.; Rig down test equipment and clear rig floor of same.; Run and set wear ring. Run in 2 LDS (marked with blue paint) UD running tool assembly.;P/U clean out assembly: 8.375" bit, bit sub, NM filter sub, NM float sub, NM 8.25" string stb, 2 ea compressive DP = 76.75 ft.;RIH picking up 60 singles off deck to 1972' MD. Drift pipe while picking up.;RIH with pipe out of derrick (check and tighten all connections). Tag cement at 4087'.; Hang tarp under flow line to mud trough interchange from rig sub base to top deck to eliminate any potential leaks from reaching open water below transition area. R/U 2" hi psi hose from well head to GPP for water displacement.; Mix 45 bbl hi vis spacer in slug pit #1. Add 15 bbls LVT to slug pit, Check all valve line ups. Hold PJSM w/ mud engineers, rig crew, and GPP for displacement f/ water t/ 9.0 MOBM.;Begin displacement from Spartan 151 U GPP per Baroid procedure. Drain stack & pump 50 bbls water fl trip tank 1 to GPP. Close Hydril. Pump 10 bbls LVT down hole f/ slug pit 2. Troubleshoot stroke counter on Pump 1. Swap to pump 2. Pump 40 bbls hi vis spacer down hole.;Pump MOBM down hole @ 5 BPM from active pits taking water to GPP. (1981 stks). Stop pumps. Open Hydril. Take returns to Trip tank 1 & 2. Continue pumping at 5 BPM. At 2600 stks, take returns over shakers to active system. Displacement complete. Drain water from 2" hi psi hose from well head to GPP.;Drill cement f/ 4087't/ 4247'. 50-75 RPM. 625 GPM. 5-10 K WOB. 1100 PSI. Check Canrig auto driller. Not functioning. (Calling out Canrig).;Calibrate MWD while P/U @ 10' intervals f/ 4247 U 4142'. Transfer displacement spacer f/ trip tank 1 to active system. Check minor hydraulic leak on top drive. Tighten same.;Drill cement f/ 4247't/ 4340' 50-75 RPM. 625 GPM. 5-15 K WOB. 1100 PSI. Re-Calibrate MWD while P/U @ 10' intervals f/ 4340 t/ 4274'. Drill cement f/ 4340' t/ 4377'50-75 RPM. 625 GPM. 1100 PSI P/U 135, S/O 130. ROT 130, 5-15 K WOB. RPM 60, TQ 3K. 7/12/2019 Drill cement f/ 4377't/ 4561'. 1079 PSI , 576 GPM, P/U 135, S/O 130. ROT 130, 15-20 K WOB, RPM 75, TQ 4K. (While drilling down last 2' Canrig adjusted settings on Auto Driller).; Circulate Bottoms up. Pump dryjob.;POOH with 5" DP. Break off bit and stand back BHA.;Remove vent hose from top drive and replace with fitting. Hang "Slow Descent" device in derrick.; P/U BHA #2. (Baker ATK OnTrak rotary steerable). Shallow pulse test MWD per Baker. (250 GPM, 350 PSI).;P/U & drift 14 its 5" HWDP. RIH while P/U & drift 78 its 5" DP from pipe deck to 3054'.;Shallow pulse test MWD per Baker. (250 GPM, 380 PSI).;Continue RIH while P/U & drift 36 jts 5" DP to 4169'. TIH w/ 5" DP stds to 4461'. Wash do to 4555'. SimOps: R/U rig vacuum system to rig floor & 7/13/2019 Drill cement f/4561' (out of 9-5/8" shoe @ 4566) to 4600' w/ Baker Hughes ATK OnTrak rotary stegrable turned to exit cement on low side away from original _ well bore. PU 150K, SO 145K, ROT 145K, RPM 75, TQ 4K, 517 gpm, 1450 psi.;Side track hole f/4600'. PU 150K, SO 145K, ROT 145K, RPM 90, TQ 4.5K, 517 gpm, 1500 psi Note: Cuttings @ 4601' = 50% formation, @ 4615' = 80% formation.;Control drill ahead to 4645' watching ABI for separation from previous wellbore. PU 150K, SO 145K, ROT 145K, WOB 3K, RPM 90, TQ 4.5K, 517 gpm, 1500 psi. Take survey per Baker.;CBU w/ 100% formation in cuttings w/ trace cement. -30% coal seen in cuttings. 1 ft separation from old well bore. Work stand per Baker while circulating.;POH to 4493' inside shoe. R/U for FIT. Line up to pump down DP and annulus.;Close Hydril. Perform FIT test to 13.0 ppg EMW w/ 9.1 ppg MW. Chart same. Stage pump 29 stks to 845 psi. Hold 5 mins. Bleed off. 2.4 bbls pumped. 2.4 bbls returned to trip tank. Modify top drive vent hose.;RIH f/ 4493' t/ 4465'.;Continue control drilling f/4645' to 4670' w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 150K, SO 145K, ROT 145K, WOB 5K, RPM 90, TQ 4.51K, 517 lapm, 1550 psi. Currently 2' separation from previous wellbore. 7/14/2019 Control drilling (/4670' to 4683'w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 150K, SO 145K, ROT 145K, WOB 7K, RPM 75, TQ 5K, 523 gpm, 1500 psi., ROP 5.19 fph.;Control drilling (/4683' to 4705'w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 150K, SO 145K, ROT 145K, WOB 8K, RPM 75, TQ 5K, 523 gpm, 1470 psi, ROP 19.38 fph.;Drill f/ 4705' to 4746' w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 150K, SO 145K, ROT 145K, WOB 11 K, RPM 80, TQ 6K, 527 gpm, 1537 psi, ROP 47.51 fph. Survey @ 4708.95' inst. depth = inc. 39.6°, az. 183.30°.;Drill f/ 4746' to 4835' w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 150K, SO 145K, ROT 150K, WOB 20K, RPM 80, TQ 6.5K, 527 gpm, 1517 psi, ROP 61.24 fph. Unable to get Survey @ 4708.95' inst. depth due to magnetic interference.; Drill f/ 4835' to 4930' w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 150K, SO 145K, RT 150K, WOB 22K, RPM 90, TQ 7K, 527 gpm, 1517 psi, ROP 58.97 fph. Survey @ 4894.67' inst, depth = inc. 36.82°, az. 191.03°, TVD 4360.96'.;Drill f/ 4930' to 5022'w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 155K, SO 135K, RT 150K, WOB 22K, RPM 97, TQ 7.2K, 521 gpm, 1550 psi, ROP 90 fph. Survey @ 4986.50' inst. depth inc. = 35.97°, az. 194.54°, TVD 4434.92'.;Drill f/ 5022' to 5115'w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 155K, SO 135K, RT 150K, WOB 22K, RPM 117, TQ 6.6K, 522 gpm, 1550 psi, ROP 90 fph. Survey @ 5084.95' inst. depth inc. = 34.31', az. 199.37, TVD 4515.40'. 15' Low / 7' Right of plan.;Drill f/ 5115' to 5205'w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 160K, SO 135K, RT 150K, WOB 21K, RPM 117, TQ 7.OK, 521 gpm, 1500 psi, ROP 70 fph. Survey @ 5180.70' inst. depth inc. = 32.89`, az. 204.12°, TVD 4595.17'.;Drill f/ 5205to 5307'w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 160K, SO 135K, RT 150K, WOB 21 K, RPM 117, TQ 7.OK, 521 gpm, 1500 psi, ROP 90 fph. Survey @ 5274.32' inst. depth inc. = 31.1', az. 208.97°, TVD 4674.58'.;Drill f/ 5307' to 5395' w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 160K, SO 135K, RT 150K, WOB 21 K, RPM 117, TQ 7.OK, 521 gpm, 1500 psi, ROP 85 fph Survey @ 5368.83' inst. depth inc. = 29.57°, az. 214.83°, TVD 4756.16'7' Low / 7' Right of plan.;Drill f/ 5395' to 5497'w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 160K, SO 135K, RT 150K, WOB 21 K, RPM 98, TQ 5.7K, 521 gpm, 1550 psi, ROP 51 fph. Survey @ 5463.34' inst. depth inc. = 28.03°, az. 222.06°, TVD 4839.01'. 5' Low / 5" Right of plan.;Drill f/ 5497' to 5511' w/ Baker Hughes ATK OnTrak rotary steerable turned down & away from original well bore. PU 160K, SO 135K, RT 150K, WOB 21 K, RPM 98, TQ 5.7K, 521 gpm, 1550 psi, ROP 91 fph.;Offloaded 54 bbls solids to KGF G&I Cumulative Solids 90 bbls 7/15/2019 Drill f/ 5511' to 5591'w/ Baker Hughes ATK OnTrak RT steerable. PU 170K, SO 150K, RT 150K, WOB 21 K, RPM 75, TQ 6.6K, 527 gpm, 1685 psi, ROP 72 fph.;Drill f/ 5591' to 5686'w/ Baker Hughes ATK OnTrak RT steerable. PU 170K, SO 150K, RT 150K, WOB 21 K, RPM 95, TQ 6K, 512 gpm, 1600 psi, ROP 90 fph.;Drill N 5685' to 5780'w/ Baker Hughes ATK OnTrak RT steerable. PU 170K, SO 150K, RT 150K, WOB 21 K, RPM 95, TQ 6K, 512 gpm, 1600 psi, ROP 90 fph Pumped 15 bbl. sweep w/7.5 ppg nut plug @ 5685', no increase in cuttings observed on BU;Switched flow ditches due to plugging. Drill 15' and second ditch started plugging off. Reduced flow rate and drilled the remainder of stand down to 5780' while monitoring ditch.;Work pipe while cleaning out flow ditches to shakers. Install jet in Starboard flow ditch and test same w/ pumps at drilling rate. Sample of material taken out of ditch was 1/8" to 1/4" chunks of sandstone w/PDC scraping.;Drill f/ 5780' to 5874'w/ Baker Hughes ATK OnTrak RT steerable. PU 170K, SO 150K, RT 150K, WOB 20K, RPM 116, TQ 7- 7.5K, 525 gpm, 1780 psi, ROP, 90 fph.;Drill f/ 5874' to 5971'w/ Baker Hughes ATK OnTrak RT steerable. PU 180K, SO 150K, RT 160K, WOB 20K, RPM 118, TQ 7-7.5K, 525 gpm, 1800 psi, ROP, 65 fph.;Drill f/ 5971' to 6065'w/ Baker Hughes ATK OnTrak RT steerable. PU 180K, SO 150K, RT 165K, WOB 22K, RPM 130, TQ 7.51K, 600 gpm, 2300 psi, ROP, 105 fph.;Drill f/ 6065' to 6161'w/ Baker Hughes ATK OnTrak RT steerable. PU 180K, SO 150K, RT 165K, WOB 22K, RPM 130, TQ 7-7.5K, 600 gpm, 2215psi, ROP, 95 fph.;Pumped 15 bbl hi vis sweep w/ 7.5 ppg nut plug @ 6161. - 100% increase in cuttings observed on sweep to surface. R/U diaphragm relief pump on cuttings trough to mitigate fluid Ievel.;Drill V 6161' to 6254'w/ Baker Hughes ATK OnTrak RT steerable. PU 180K, SO 150K, RT 165K, WOB 22K, RPM 130, TQ 7-7.5K, 600 gpm, 2350psi, ROP, 100 fph.;Drill f/ 6254' to 6349' w/ Baker Hughes ATK OnTrak RT steerable. PU 180K, SO 150K, RT 165K, WOB 22K, RPM 130, TQ 7-7.5K, 600 gpm, 2300 psi, ROP, 95 fph. Running centrifuge.; Drill f/ 6349' to 6444'w/ Baker Hughes ATK OnTrak RT steerable. PU 180K, SO 150K, RT 165K, WOB 22K, RPM 130, TQ 7-7.5K, 600 gpm, 2300 psi, ROP, 95 fph. At 6435', P/U off btm & reset MWD. Cont drlg.;Drill f/ 6444' to 6535'w/ Baker Hughes ATK OnTrak RT steerable. PU 180K, SO 150K, RT 165K, WOB 22K, RPM 130, TQ 6-7.5K, 580 gpm, 2150 psi, ROP, 100 fph. Pump 20 bbl hi vis weighted sweep. (10.1 ppg) 100% cuttings increase w/ sweep return.;Oftloaded 72 bbls solids to KGF G&I Cumulative Solids 162 bbls 7/16/2019 Drill f/ 6535' to 6631 ' . PU 180K, SO 150K, RT 150K, WOB 22K, RPM 130, TO 7.5-8K, 578 gpm, 2127 psi, ROP 80 fph.;Drill f/ 6631' to 6726'. PU 180K, SO 150K, RT 150K, WOB 17K, RPM 127, TO 7.5K, 581 gpm, 2165 psi, ROP 95 fph. SPRs @ 20/30/40 spm #2=190 / 240 / 300, #3 = 190 / 240 / 285.;Drill H 6726' to 6821 ' . PU 180K, SO 150K, RT 150K, WOB 20K, RPM 133, TO 7.5K, 570 gpm, 2102 psi, 10.2 ECD, ROP 82 fph.;Drill f/ 6821' to 6916' . PU 180K, SO 150K, RT 150K, WOB 17K, RPM 126, TO 7.5K, 618 gpm, 2360 psi, 10.2 ECD, ROP 101 fph.; Drill f/ 6916' to 7010'. PU 180K, SO 150K, RT 150K, WOB 17K, RPM 130, TO 8-9K, 618 gpm, 2360 psi, 10.1 ECD, ROP, 104 fph. Pump 15 bbl hi vis wt. sweep. 10% cuttings increase w/ sweep return.;Drill f/ 7010' to 7105' . PU 190K, SO 160K, RT 175K, WOB 17K, RPM 130, TO 8-9K, 557 gpm, 2050 psi, 10.1 ECD, ROP 96 fph.;Drill f/ 7105' to 7200' . PU 200K, SO 160K, RT 175K, WOB 23K, RPM 130, TO 8-9K, 557 gpm, 2050 psi, 10.1 ECD, ROP 96 fph.;Drill f/ 7200' to 7295'. PU 210K, SO 160K, RT 180K, WOB 20K, RPM 122, TO 9K, 578 gpm, 2200 psi, 10.1 ECD, ROP 65 fph.;Drill f/ 7295' to 7390'. PU 210K, SO 170K, RT 180K, WOB 22K, RPM 120, TO 9K, 561 gpm, 2150 psi, 10.1 ECD, ROP 50 fph.;Drill f/ 7390' to 7484'. PU 210K, SO 170K, RT 180K, WOB 22K, RPM 130, TO 8-10K, 575 gpm, 2200 psi, 10.1 ECD, ROP 60 fph.;Drill f/ 7484' to 7579'. PU 210K, SO 170K, RT 180K, WOB 22K, RPM 123, TO 8-10K, 5575 gpm, 2200 psi, 10.1 ECD, ROP 60 fph.;Drill f/ 7579' to 7628' . PU 210K, SO 170K, RT 180K, WOB 22K, RPM 130, TO 8-10K, 575 gpm, 2200 psi, 10.2 ECD, ROP 60 fph.;Note: 48 hour notice given to AOGCC for BOPE test 7:56 am on 7/16/19 7/17/2019 Drill f/ 7628' to 7850'w/ Baker Hughes ATK OnTrak RT steerable. PU 210K, SO 170K, RT 180K, WOB 14K, RPM 130, TO 8-10K, 567 gpm, 2215 psi, 10.2 ECD, ROP 50 fph.;Drill f/ 7850' to 8130'w/ Baker Hughes ATK OnTrak RT steerable. PU 225K, SO 170K, RT 195K, WOB 21 K, RPM 118, TO 8-10K, 570 gpm, 2250 psi, 10.1 ECD, ROP 40 fph. Pump hi vis weighted sweep (11 ppg) @ 8039'. Maybe 5% increase in cuttings observed on return to surface.;Jim Regg with AOGCC verbally granted the rig an extension till midnight on 7/21/19 for the BOP test originally due on 7/18/19.;Drill f/ 8130' to 8196' w/ Baker Hughes ATK OnTrak RT steerable. PU 235K, SO 190K, RT 200K, WOB 21 K, RPM 118, TO 8-10K, 577 gpm, 2300 psi, 10.1 ECD, ROP 40 fph.;Circ at 8196' while troubleshoot CanRig RigWatch system.;Drill f/ 8196' to 8300'w/ Baker Hughes ATK OnTrak RT steerable. PU 235K, SO 190K, RT 200K, WOB 21 K, RPM 118, TO 8-1 OK, 577 gpm, 2300 psi, 10 ECD, ROP 40 fph. Pump hi vis weighted sweep (11 ppg) @ 8039'. Maybe 5% increase in cuttings observed on return to surface.;Drill f/ 8300' to 8572'w/ Baker Hughes ATK OnTrak RT steerable. PU 235K, SO 190K, RT 200K, WOB 21 K, RPM 118, TO 8-1 OK. 577 gpm, 2300 psi, 10 ECD, ROP 40 fph.;Offloaded solids to KGF G&I : 144 bbls Cumulative Solids: 522 bbls' 'Corrected cumulative total 7/18/2019 Drill f/ 8572' to 8842'w/ Baker Hughes ATK OnTrak RT steerable. PU 240K, SO 190K, RT 210K, WOB 21 K, RPM 115, TO 10-11 K, 577 gpm, 2360 psi, 10 ECD, ROP 50 fph.;Drill f/ 8842' to 8906'w/ Baker Hughes ATK OnTrak RT steerable. PU 240K, SO 190K, RT 210K, WOB 15K, RPM 130, TO 10-11 K, 585 gpm, 2360 psi, 10 ECD, ROP 40 fph.;Pump 30 bbl. High Vis sweep @ 557 gpm . Work pipe 90'w/ 150 rpm while circulating sweep around. No observable increase in cuttings on sweeps return to surface.;Drill f/ 8906' to 9058'w/ Baker Hughes ATK OnTrak RT steerable. PU 240K, SO 200K, RT 210K, WOB 15K, RPM 120, TO 10-14K, 560 gpm, 2300 psi, 9.9 ECD, ROP 51 fph.;Drill f/ 9058' to 9265'w/ Baker Hughes ATK OnTrak RT steerable. PU 250K, SO 210K, RT 220K, WOB 21 K, RPM 130, TO 10-14K, 552 gpm, 2312 psi, 10 ECD, ROP 35 fph.;Drill f/ 9265' to 9444 w/ Baker Hughes ATK OnTrak RT steerable. PU 255K, SO 210K, RT 225K, WOB 21 K, RPM 130, TO 10-14K, 552 gpm, 2312 psi, 10 ECD, ROP 35 fph.;Offloaded solids to KGF G&I : 378 bbis Cumulative Solids: 880 bbls 7/19/2019 Drill 8.375" tan ent section f/ 9444' to 9664' wl Baker Hughes ATK OnTrak RT steerable. PU 255K, SO 210K, RT 225K, WOB 22K, RPM 130, TO 12-14K, 570 gpm, 2440 psi, 10.0 ECD, ROP 40 fph.;Drill 8.375" tangent f/ 9664' to 9707'w/ Baker Hughes ATK OnTrak RT steerable. PU 255K, SO 210K, RT 225K, WOB 22K, RPM 130, TO 12-14K, 570 gpm, 2440 psi, 10.0 ECD, ROP 40 fph.;Transition out of tangent to building angle (/9707' to 9869'w/ Baker Hughes ATK OnTrak RT steerable. PU 250K, SO 210K, RT 220K, WOB 22K, RPM 130, TO 12-14K, 570 gpm, 2440 psi, 10.0 ECD, ROP 35 fph.;Building angle 9869' to 10,014'w/ Baker Hughes ATK OnTrak RT steerable. PU 260K, SO 210K, RT 200K, WOB 20K, RPM 130, TO 12-14K, 570 gpm, 2470 psi, 10.0 ECD, ROP 18 fph.;Building angle 10,014' to 10,044'w/ Baker Hughes ATK OnTrak RT steerable. PU 260K, SO 210K, RT 200K, WOB 20K, RPM 130, TO 12-14K, 570 gpm, 2470 psi, 10.0 ECD, ROP 18 fph.;Tight hole off btm for connection, 30K over normal. Wash / ream full stand. Wellbore free, no gain / loss. Make connection.; Building angle 10,044' to 10,112' w/ Baker Hughes ATK OnTrak RT steerable. PU 260K, SO 21 OK, RT 200K, WOB 20K, RPM 130, TO 12-14K, 570 gpm, 2470 psi, 10.0 ECD, ROP 18 fph.;Offloaded solids to KGF G&I : 216 bbls Cumulative Solids: 1,096 bbls 7/20/2019 Building angle 10,112' to 10,269'w/ Baker Hughes ATK OnTrak RT steerable. PU 260K, SO 200K, RT 230K, WOB 22K, RPM 130, TO 11-13K, 579 gpm, 2577 psi, 10.0 ECD, ROP 26 fph.;Building angle 10„269' to 10,445'w/ Baker Hughes ATK OnTrak RT steerable. PU 260K, SO 200K, RT 230K, WOB 22K, RPM 130, TO 11-13K, 579 gpm, 2577 psi, 10.0 ECD, ROP 45 fph. Back ream 1 jt. on each connection.; Building angle 10,445' to 10659'w/ Baker Hughes ATK OnTrak RT steerable. PU 262K, SO 202K, RT 230K, WOB 17K, RPM 130, TO 11-13K, 565 gpm, 2677 psi, 10.1 ECD, ROP 35 fph. Back ream 1 jt. on each connection.; Troubleshoot top drive. Stand back one stand DP to bring top drive to floor. Continue troubleshoot noise at top drive while circulate wellbore.;Offloaded solids to KGF G&I : 162 bbls Cumulative Solids: 1278 bbls 7/21/2019 Pump dry job and POOH for top drive repairs to 4390'.;Pick up Drip pan for ODS pipe rack on rig floor.;Continue to POOH.;R/U and pull wear ring.;M/U test joint, set test plug and R/U to test BOPE.;Test BOPE as per AOGCC and Hilcorp requirements. All rams and valves 250 low / 3500 high, Annular 250 low / 2500 high w/ 5" test joint. Charted and held for 5 min ea. Perform accumulator draw down test. Inspect pressure at nitrogen bottles. All tests successful, no re- tests.;AOGCC witness of BOP test verbally waived by State Inspector Mr. Jim Regg 7/21/19 @ 08:12 am.;Rig do BOPE test equip. and pull test plug.;Resume troubleshoot top drive. Swapping out top drive traction motor. (Pinion gear on the traction motor shaft is cracked).; Offloaded solids to KGF G&I : 36 bbls Cumulative Solids: 1314 bbls 7/22/2019 Strip blower, brake and air ducting from Spartan TD. Unwire traction motor from junction box on T and remove traction motor. Simultaneously pull Hilcorp TD from storage connex and begin stripping equipment off it to pull traction motor.; Completed the removal of Hilcorp TDS motor, it was found that the base plate of the motor was different than that of the Spartan unit and they do not appear to be compatible for swapping. Confirm incompatibility of motors and discuss options with all parties.;Prep and load out both motors on boat. Sending to Dukowitz Machine to remove pinions and install new pinion on Spartan traction motor, pending approval form Spartan Superintendent arriving in Anchorage.; Cover open holes on TD gear boxes and service rig. Approval given for Dukowitz to swap pinions on TD traction motors.; Continue prep work prior to change out traction motors. General clean up at rig floor. Flush out flow line ditch. Service top drive and crown. Stow Hilcorp TD Parts back to shipping container.;Wait on arrival top drive traction motor. Estimated completion this afternoon. Well monitoring with flow checks at 30 minute intervals.;Offloaded solids to KGF G&I : 0 bbls Cumulative Solids: 1314 bbls 7/23/2019 Clean and perform rig maintenance while waiting on return of TD traction motor.Motor loaded and headed to OSK dock @ 09:30 for 11:00 load out. Continuously monitor well, flow checks at 30 minute intervals.;Prep rig floor for receiving TD traction motor. Off load motor from boat and sit on rig floor. Mount lifting plate and verify that pinion had not advanced further up shaft while cooling.;Pick up and mount Traction motor to TD. Re-mount auxiliary equipment to TD. RU blower hose, goose neck, and Kelly hose. Wire in TD motor.;Continue getting everything put back together on the TD and test run same. Everything looked good. Install bails and elevators. clean up rig floor.;lnstall wear bushing;Flow check, RIH 8.375" Baker ATK OnTrak BHA RSS. Follow BHA with 5" DP to 9-5/8 csg shoe at 4566 ft.;CBU at 4566 ft, 988 units gas with btms up, circ out through choke. No attending flow increase with gas. Press check, open well, fluid column static.;Resume RIH 5" DP to 8500 ft. filling at 20 stand intervals.;CBU with 570 units gas. Press check, open well, fluid column static.;Resume RIH 5" DP to 10,100 ft. Wellbore exc condition. No gain / loss. Normal up / do drag.;Offloaded solids to KGF G&I : 18 bbls ' 0Cumulative Solids: 1332 bbls �'�✓ 7/24/2019 RIH f/ 10,100't/ 10,517' No tight spots.;Wash and ream f/ 10,517' t/ 10,659'. Looked like we had about 5' of fill.;Drill 8 3/8" hole as per well plan f/ 10,659' t/ 10,780'w/ Baker Hughes ATK OnTrak RT Steerable. ROP av 20.1 fph. Up wt=290, Dn wt=200, RT wt= 245. 560 GPM, 2675 Psi, ECD 10.2, RPM 100, TQ 11 to 12.5.;Drill 8 318" hole as per well plan f/ 10,780' t/ 10,860'w/ Baker Hughes ATK OnTrak RT Steerable. ROP av 20 fph. Up wt=290, Dn wt=200, RT wt= 245. 562 GPM, 2695 Psi, ECD 10.2, RPM 100, TQ 12 to 15.5.;Pump weighted sweep, Chase with mud from active, and followed by Hi-Vis Sweep with 10 ppb wall nut. Circ while rotating and reciprocating. Sweeps came back on time w/ a 10% increase in cuttings. 550 GPM, 2575 psi.;Monitor well for flow. Mud column static. POH 5"DP , 30K overpull at 10790 and 10740 ft. Work free, resume POH to 6823 ft. racking bk in mast. Wellbore exc condition, no swab / gain / loss. Continue POH 5" DP laying do in singles to 2312 ft. Wellbore exc condition.; Offloaded solids to KGF G&I : 126 bbls Cumulative Solids: 1458 bbls 7/25/2019 Continue POH LD 5" DP ft 2312 t/ 571'. Dropping foam ball in pipe and using vac stand to clean pipe out.;Monitor well. Continue POH LD HWDP and Jars. Break bit and download tools. Finish LD smart iron. Bit had the same chipped teeth it had when we re-ran it, but everything else looked good. Bit grade was a 1- 2. No gauge ring available.;Clean and clear floor.;Drain stack, Pull wear ring, & set test plug.;Change lower rams from 5" to 7". Tide changed so we started unloading 7" csg again.;RU to test 7". Test lower oioe rams to 250 & 3500 osi. Test annular to 250 & 2500 psi for 5min on ea test. RD 7" test jt . Finish unloading 7" csg off the boat.;R/D 7" test equip, R/U 4-1/2 test equip, test top VBRs on 4-1/2 DP 250 low / 3500 high 5min . Test 4-1/2 and 7against annular 250/2500 5 min. Tests successful, no re-tests.;R/D test equip, pull test plug, set wear ring.;Place "Hawk Jaw" unit to rig floor, R/U same, Prep P/U 4-1/2 DP.;Commence P/U 4-112 DP in singles. Make, break, inspect all connections as per recommendations. Difficulties with threads. Threads galling and sharp after break out. L/D 10 jts 4-1/2 DP . Total 8 connections fail.;Discuss alternate options with Hilcorp Anchorage, prepare ship 4-1/2 DP to OSK and replace.; Offloaded solids to KGF G&I : 0 bbis Cumulative Solids: 1458 bbls 7/26/2019 Work on rig projects while waiting on DP swap. Line up tools for new HT38 pipe connections. Have electrician working on TD RPM. Vac out 10 jts of 4 1/2 DP that were in OBM. Cleaning hand rails. Bring on diesel from GP Platform. RU vac to ann.;Finish rigging up vac from ann and vac out stack. Unload boat of liner running equip, 3 jts HT38, XOs, and handling tools. Finish working on TD RPM sending unit on TD.; Pull wear ring and RU to test upper rams on 4" DP. Put subs and Handling equip for 4 112 on the boat. Start back loading DP on boat at 1700 hrs.;Test upper rams on 4" DP to 250 and 3500 psi for 5 min each, Test annular on 4" to 250 and 2500 psi for 5 min each.; Pull test plug and set wear bushing. RD test equip.;C/O slip dies to 4", M/U Baker mud motor, stand back in mast.;Clear rig floor, arrange deck, make ready for 7" liner run.; Place csg run equip to rig floor, R/U for 7" liner run.;Commence RIH 7" liner, M/U Reamer Shoe made up to jt 7" liner, follow with jts csg (7, L-80, 29#, DWC/C ) to 1050 ft.;Offloaded solids to KGF G&I Cumulative Solids: 1476 bbls Q r , 7/27/2019 RIH PU 7" liner. to 1901'. Been flowing over the top so we have been using a wet plug.;Circ to get mud thinned out and NlowOK ping a 10 bbl 11.2 ppg dryjob to help hold mud back in the csg.;Continue RIH PU 7" liner (/1901' t/ 2808'. Installing 8 1/4 floating centralizers on .;Have PJSM at crew change. Continue RIH PU 7" liner f/ 2808't/ 3880'. Trying to flow over so we are using a wet plug and bleeding off at the floor.;Wet plug failed so we decided to circ while we are getting the plug repaired. Circ at 293 GPM, 600 Psi, had a high of 714 units of gas. Circ 1 1/2 circulations. Pump 20 bbl weighted pill and chase it.;Continue RIH PU 7" liner f/ 3880't/6500 ft.;M/U circ sub, C/C fluids while R/D csg run equip. Max gas 925 units with no attending flow increase. Clear rig floor all unnecessary equip, and handling tools. Clean oil base from floor area due to overflow running 7" Iiner.;Safety meeting all personnel. Topic : Liner hgr , inner string procedure.;Continue circ out trip gas while clean OBM from rig floor in prep for safe working area while P/U liner tools.; Offloaded solids to KGF G&I 0 bbls Cumulative Solids: 1476 bbls 7/28/2019 Continue to circ to shear mud and load rig floor with equip needed to run the inner string.;RU false table and working platform. Get Hawkjaw rigged back up and get everything adjusted. Latch onto stand w/ mud motor.;Run in liner w/ bit and mud motor. Continue PU inner string BHA. Run in liner w/ BHA and DP to 650'. Brought 5 Schlumberger cmt hands on board.;Continue PU 4" HT 38 DP and R\run in liner f/ 650' U 3102'. Unload 15 cuttings totes and the Schlumberger chemical off the boat.;Continue PU 4" HT 38 DP and run in liner f/ 3102 to 6560 ft.;M/U liner setting sleeve assy, M/U upper and lower quick connect connection. M/U top drive, Pick up on 7" liner. (Break over at 320, Up 245, Dn 220).; Repair top drive hydraulic leak while circ. 60 spm, 1736 psi, 211 gpm. No gain / loss, 177 units gas.;RIH 7" liner with inner string on 5" DP, filling at 10 stand intervals., to 10027 ft.;Offloaded solids to KGF G&I : 0 bbls Cumulative Solids: 1476 bbls 7/2912019 Run 7" liner w/ inner strip on 5" DP f/10,027 t/ 10,640' where we sat down 20k and attempted to work through with no luck.;Attempt to get liner run to bottom. ash liner down f/ 10640' t/ 10,675'. Attempted to rotate but stalled out at 25k and didn't want to go any higher. Trap in torque up to 15k and wash down. at one point we made it to 10,690' but lost hole when it packed off and we had to PU. Packing off on Iiner.;Have have to PU to 500k to break the string loose. Up wt 430k, Dn wt 260k;Continue to Work on getting liner to bottom. Wash do to 10,730'. Having a lot of issues with pressuring up and packing off. Lost hole trying to get back circ. Ended up pumping on the up stroke and killing the pump while going dn. Finally got back good circ at 10,660'.; Pumped 70 bbl 6% NSX lube pill and waited until 10 bbls were out of the bit. Set torque limit ar 30k and PU pipe to 360k. Kicked in TD and when torque hit 25k had him drop the wt to 320k. Pipe started rotating at 28k. Kept pipe rotating and washed and reamed f/10,662' t/10.860' But depth.-Torque kept falling while reaming and at the end it was 22k. 122 GPM, 1145 Psi, Up wt 430k, Dn wt 270k, Rt wt 330k.;Drill w/ inner string 6 1/8" bit f/ 10,860't/10924'. WOB 20, RPM 65, SPM 83, GPM 288, SPP 2900. No gain / Ioss.;C/C fluids, re-cip - rotate string 20 ft strokes. CBU X 2, wellbore clean. Pump remainder pill to 7 X 8-3/8 annulus.;Cease pumping, drop ball to seat liner hgr. Seat ball with 650 psi, build to 3500 and set hgr. Pull up 255K in attempt to pull free and release from liner hgr. no success. Continued efforts pull free, up 400K, do tol 10K. Perform mechanical backoff left hand turn, re-cip, break free with 360K pull.;Offloaded solids to KGF G&I 18 bbls Cumulative Solids: 1494 bbls 7/30/2019 Put right hand turns back in pipe after mechanical release from liner. Get parameters 100 GPM 975 psi, 230 up, 180 dn, 200 rt. PU to where top of bit entered shoe at 10,860' and it pulled tight. Had to backream bit back up into shoe. Pump Dry job.;POH to liner setting tool Wet. Setting tool shear pins were sheared and everything looked good. There was some cuttings packed off around the top of the tool that could have caused the over pull when we released from the Iiner.;Clean floor and mix another dry job. Circ while mixing the dry job.;Pump dry job and LD liner setting tool wrapping it with absorbent and plastic to keep it contained.;POH and stand back 4"DP inner string.;LD inner string BHA. = Float sub & crows foot [recover ball], Ported sub, Stab, XO, 1 jt 4" DP, XO, Motor w/ float, 6 1/8 Kymera Bit. Bit rung out w/ broken teeth. Pics in "O" drive.;Clean and clear MOBM from rig floor. Service top drive. M/U 4" x 10' pup on cement head. Set aside. Begin cleaning pit & lines for cement spacer; PJSM w/ PM crew for running CICR I ZXP 1 Seal assembly. PU & MU ZXP / Seal assy & rack back in derrick. PJSM w/ AM crew for running CICR I ZXP I Seal assembly. P/U Baker CICR. Confirm ball catcher in place. Continue cleaning pit & lines for cement spacer;RIH w/ CICR on 4" DP to 4246'. 100 PU, 100 SO, Begin circ @ 2.5 BPM, 205 PSI. Cont RIH while circ to 4360' inside PBR w/ no issues. Stop pumps & RIH to 4500'w/ no issues. Continue cleaning pit & lines for cement spacer.; Continue RIH w/ CICR on 4" DP f/ 4500' to 6474'. Prep to MU ZXP / Seal assy from derrick on 4" DP. Finish cleaning pit & lines for cmt spacer. Begin mixing cement spacer per SLB recipe.;Offloaded solids to KGF G&I : 54 bbls lCumulative Solids- 1548 bbls 7/31/2019 Finish MU ZXP and seal assembly and RIH on 5" DP.. Bottom of seal 4326'.;Wash do to 4351' where seals started into seal assembly. PU and circ 1 1/2 times inner liner vol.;Space out and PU cmt head. Circ do until seals started in and we seen pressure. Shut down pump and engage seals. Work pipe up to 45k over and back do 30k under 4 times. Then slack off to 200k and break circ up back side of 7" Iiner.;Circ liner ann plus an extra 200 strokes at 121 GPM 850 psi.;Shut down pump and RU cmt lines. Drop ball, Set do 50k, and pressure up slowly to 4200 psi. Held that pressure for 1 min and then bled it back to 1000 1( psi. In 7 1/2 min the sleeve shifted and the press bled off. PU to up wt of 225k plus 8 more feet. Put 15 turns in pipe.;Slack off to 140k and PU to 265k 3 times. Put 15 more rounds to the right. PU and pull off CIBP. Set back do 30 k. Top of cmt plug at 10,811'. Break circ to ensure we still had good circ around liner. PU and unsting.;Circ inside liner while we have PJSM with everybody involved.;Schlumberger pumped 10 bbls seawater, test lines to 3000 psi, Pump 25 bbls mudpush w/ rig. Batch up and laumpl25.5 bbl. 13.5 ppa Lead cmt followed b 25.5 bbls 15.8 ppa tail cmt Swap to ria and Dump 7 bbls 12 P12a mudpush and displace with 133 bbls 9.4 ppg OBM.;Unsting from cmt plug. Cmt in place at 19:47 hrs w/ a final pressure of 2600 psi. Had full returns during most the job. Did start to pressure up several time toward the end and the return flow would slow down but it kept coming back.; RID Schlumberger cement head.;P/U 22' to expose packer setting dog sub. SO & shear packer pins w/ 20K do wt. SO & set SLZXP packer element w/ 40K do wt. S/O 100 K x 3 to confirm packer set.;POOH 5 stds to 10317'.;CBU x 2 @ 6 BPM 11250 PSI. Flush cement from drill pipe. Trace amounts cement seen at shakers. Check flow. Pump dry job.;POOH f/ 10317't/ 6396' LID Baker liner running tools per Baker Rep. Clean tools for offloading & travel. Cont POOH f/ 6396' t/ 4301'. SLB cementers left location 23:00 hrs.;Circ BU @ 4301'w/ 6 BPM to flush top of PBR. Check flow. Pump dry job.;POOH f/ 4301' t/ 780'. 8/1/2019 Continue POH f/ 780 to surface. LD running tool. PU and break down cmt head.;Clear floor of extra tools.; Drain stack. Change lower rams from 7" to 5". Plumb in a second valve on test pump so we can run two test hoses.;RU to test BOPs.. MU 5" test jt. Get test pump put on the rig floor and plugged in. MU 1502 sub on TD. Fill stack, TD, and choke with water. Test gas alarms. Centrifuging active MOBM f/ 9.5 ppg to 8.9 ppg.;Test all BOP equip on 5" and 4" to 250 and 3500 psi with no failures. Test PVTs and everything passed. Perform accumulator test. All tests performed per AOGCC and Hilcorp regulations and standards. AOGCC inspector Austin McCloud on site to witness.;R/D Test equipment. Drain stack. Remove test plug. Lower test pump to deck w/ crane. Install wear bushing. Clean & Clear rig floor. Strap 4" HWDP. Prep to P/U Clean Out BHA. Centrifuging active MOBM f/ 9.1 ppg to 8.9 ppg.;PU & MU Clean Out BHA per Baker DD from surface t/ 497'. PU & MU 5 stds 4" HWDP. Replaced pop off pins on #3 mud pump.; Hawk Jaws' left side control panel bracket bent w/ bolts broken. - Rig motorman made temporary repairs. - Welder will fabricate full repair out of critical path. Substituted Hawk Jaws for Spinner Hawks while motorman made repairs.;TIH w/ Clean Out BHA on 4" DP f/ 497't/ 4275'. Fill pipe. TIH slowly through TOL / PBR f/ 4275' U 4350' w/ no issue. Cont TIH f/ 4350 t/ 6557'.;Offloaded solids to KGF G&I : 18 bbls Cumulative Solids: 1572 bbls 8/2/2019 RIH w/ clean out assem f/ 6567 U 10,400'. fill pipe. RIH U 10,467' and set do 20k.;Drill cmt f/ 10,467' U lDg of cmt retainer at 10 a0G' 291 GPM, 2105 psi, 90 RPM, 6.5k torque, 10k WOB. Avg ROP 80.;Circ hole clean. Pull Hawkjaw off floor for repairs.;Test csg to 2500 psi for 30 min on a chart. Lost 50 psi in 30 min. Good test.;Drill on cmt retainer f/ 10,809' U 10,811' and it started breaking through. Continue centrifuging MOBM to reduce MW to 8.9 ppg.;Drill cement ft 10811' past casing shoe @ 10860'. ROP 30.1 FPH, 210K PU, 200K SO, 190K RT, 290 GPM, 2150 PSI, 30 RPM , 6-7K TQ. Continue drilling pilot hole f/ 10860't/ 10924'. ROP 50-100 FPH, 210K PU, 200K SO, 190K RT, 290 GPM, 2150 PSI, 30 RPM , 6-71K TQ. Stage repaired Hawkjaw on rig floor.;Drill 4' new formation f/ 10924' tt 10928'. ROP <2' FPH, 210K PU, 200K SO, 190K RT, 290 GPM, 2150 PSI, 30 - 100 RPM , 6-7K TQ. - Mill tooth roller cone bit not performing in new formation.: Circulate BU @ 300 GPM, 1975 PSI. MW in & out= 9.05 PPG.;POOH w/ cleanout BHA f/ 10928't/ 4977'.; Transported to KGF G&I: Offloaded solids = 72 bbls Cumulative Offloaded Solids = 1572 bbls 8/3/2019 POH w/ clean out assem f/ 4979' to BHA. Came wet on the last 10 stds.;LD BHA. LD jars and bumper sub, PU and clean off magnet. It had about an inch of fines built up on each magnet strip. Pull up and break bit. Bit grade 2-7-I, pic in O-drive. LD boot baskets. Clean out boot baskets. Recovered 17 /2 lbs f/ basket.;Clear and clean rig floor, Adjust brakes. Bring tools for new BHA to rig floor.;Have PJSM. PU BHA. PU and make up AutoTrak , On Trak MWD, BCN, SDN, NM sub, and NM stab. Up load tool. PU and MU Kymera bit. Finish PU Baker BHA. Hold PJSM and Load Nukes.;Finish M/U & P/U 6 1/8" Kymera /AutoTrak BHA on 4" HWDP t/ 601'. Continue RIH on 4" DP f/ 601' to 4204'.;Slip & Cut 123' of drill line. Adjust draw works brake. Circulate active mud system during slip & cut DL. Install Baker MWD hookload sensor.;RIH w/ 6 1/8" Kymera / AutoTrak BHA on 4" DP f/4025' to 7078'.;P/U & rabbit 33 of 69 jts 4" DP. - Rabbit sticking in some jts due to pipe scale.;Transported to KGF G&I: Offloaded solids = 126 bbls Cumulative Offloaded Solids = 1698 bbls 8/4/2019 RIH w/ directional drilling assem PU 4" DP to 9500'. Set block height.;RIH w/ directional drilling assem t/ 10,850'. Fill pipe.;Wash do to 10,860'. Continue washing and logging to bottom. Tag at 10,926'. Fan bottom to wash away any junk that could have been left on bottom.;Drill f/ 10,926't/10,944'. Original well bore was 10, 924' so we have our 20' of new hole. 250 GPM, 275 Psi, 88 RPM, 6k Tq, 10 to 16 Bit wt.;Circ and condition for 13 ppg FIT. Had even mud wt of 9+.;Perform FIT to a 13 ppa MWE. Pressure up to 1950 psi w/ a vol of 6 bbls. Press bled do f/ 1953 psi U 1905 psi in 5 min. Bled back 5+ bbls.; Directional drill per program w/ Baker 6 1/8" Kymera / AutoTrak BHA f/ 10,944' t/ 11,044'. 10 - 30 FPH ROP, 21 OK PU, 170K SO, 190K RT, 250-300 GPM, 2225 PSI, 9.9 PPG ECD, 120 - 130 RPM, 6 -8K TO. On the line UR & 5' below plan. Adjusting drilling parameters to optimize drilling.; Directional drill w/ Baker 6 1/8" Kymera / AutoTrak BHA f/ 11,044't/ 11,095'. 30 - 60 FPH ROP, 210K PU, 170K SO, 190K RT, 250 GPM, 2250 PSI, 9.9 PPG ECD, 130 RPM, 6 -81K TO. Adjusting drilling parameters to optimize drilling. Replacing #1 module on #2 mud pump.;Troubleshoot, reboot & reset Canrig Rigwatch server. P/U off btm & circulate while working on Rigwatch @ 250 GPM.; Directional drill w/ Baker 6 1/8" Kymera / AutoTrak BHA f/ 11,095't/ 11,138'. 30 - 65 FPH ROP, 200K PU, 170K SO, 185K RT, 20-28K WOB, 250 GPM, 2250 PSI, 9.8 PPG ECD, 130 RPM, 6 -8K TO. On the line UR & 7' below plan. Take SPRs.;Directional drill w/ Baker 6 1/8" Kymera / AutoTrak BHA f/ 11,138' V 11,233'. 20-30 FPH ROP, 210K PU, 170K SO, 190K RT, 20-28K WOB, 250 GPM, 2250 PSI, 9.9 PPG ECD, 130 RPM, 7-8K TO. 3.5' Left & x 6' below plan. 03:45 @ 11,193'. Take check survey. Backream full stand.;Transported to KGF G&I: Offloaded solids = 18 bbls Cumulative Offloaded Solids = 1716 bbls 8/5/2019 Directional drill 6 1/8" hole f/ 11.233' tt 11.328'. 17-25 FPH ROP, 210K PU, 170K SO, 190K RT, 26-28K WOB, 247 GPM, 2150 PSI, MW 8.8 ppg, 9.7 ppg ECD, 125 RPM, 7-8K TO. [At 11275' we pumped a 50 bbl 2% lube sweep. When sweep was going do the press decreased and when it;went out the bit the torque decreased. Trouble is the ROP decreased also.]; Directional drill 6 1/8" hole f/ 11,328' V 11,393'. 12-20 FPH ROP, 210K PU, 170K SO, 190K RT, 28- 30K WOB, 236 GPM, 2025 PSI, MW 8.8+ ppg, 9.7 ppg ECD, 150 RPM, 7-8K TO. [Pumped tandem sweeps with nut plug.. No increase in cuttings].; Directional drill 6 1/8" hole f/ 11,393't/ 11,423'. 12-20 FPH ROP, 210K PU, 170K SO, 190K RT, 28-30K WOB, 236 GPM, 2025 PSI, MW 8.8+ ppg, 9.7 ppg ECD, 150 RPM, 7-8K TO. Backreamed full stand. Pumped 15 bbl / 20 ppb Baracarb sweep. Temp increase in ROP f/ 15 t/ 21' ROP 13' Left & 4' below plan.; Directional drill 6 1/8" hole f/ 11,423't/ 11,517'. 6-18 FPH ROP, 210K PU, 170K SO, 190K RT, 28-30K WOB, 236 GPM, 2025 PSI, MW 8.8+ ppg, 9.7 ppg ECD, 150 RPM, 7-8K TO. Pumped 15 bbl weighted sweep w/ 20 ppb Baracarb x 2. Minimal ROP improvement. 20' Left & 6' Hi of plan.; Directional drill 6 1/8" hole f/ 11,517' V 11,530'. 6-12 FPH ROP, 210K PU, 170K SO, 190K RT, 28-30K WOB, 236 GPM, 2025 PSI, MW 8.8+ ppg, 9.7 ppg ECD, 150 RPM, 7-8K TQ.;Transported to KGF G&I: Offloaded solids = 72 bbls Cumulative Offloaded Solids = 1788 bbls 8/6/2019 Directional drill 6 1/8" hole f/ 11,530't/ 11,610'. 210K PU, 170K SO, 190K RT, 28-30K WOB, 245 GPM, 2180 PSI, MW 8.8 ppg, 9.8 ppg ECD, 150 RPM, 7.7 8.3K TQ.;Directional drill 6 1/8" hole f/ 11,610't/ 11,663'. 210K PU, 170K SO, 190K RT, 30K WOB, 245 GPM, 2180 PSI, MW 8.8 ppg, 9.73 ppg ECD, 150 RPM, 6-12K TO. At 11,658' began seeing increase in tq. P/U and ream back to bottom. Drill 5' to 11,663' with erratic torque (6-12k).; Erratic torque continues w/ zero penetration rate. Calculate bottom stb. to be at previous drilling break (11,615'). Suspect bit to be out of gauge and trying to open hole with stb. Last survey @ 11,573': INC=78.08°, AZ=174.15°, TVD=9650.68, 10' high & 26' left of line.;Discuss situation with town and decide to POOH for bit. Observe well (static) and pump dry job. Notified AOGCC of intention to POOH and test BOPE 1 day early.;POOH slowly 8 std. to shoe @ 10,860'. Monitor well (static). Continue POOH to 4" DP at 9243'.;Change elevators from 5" to 4". Continue to POOH f/ 9243't/ 4299'.;Service Top Drive & Crown. Grease wash pipe. Clean & clear rig floor.;CBU at TOL @ 4299'w/ 300 GPM, 2187 PSI.;Continue to POOH f/ 4299't/ BHA @ 601'.;POH to surface & rack back 6 1/8" Kymera / AutoTrak BHA per Baker DD. Hold PJSM w/ Baker MWD. R & R nukes. - Announce nuclear source R & R on Rig and GPP. Bit 1/4 out of gauge, rung out, cones worn 70%„ shank broken, but all parts accounted for. Pics to follow in O drive. Prep to download MWD. 8/7/2019 Down load MWD.;Drain stack to well head. Make up puller and pull wear bushing.;RU to test BOPs.. MU 5" test jt. Get test pump put on the rig floor and plugged in. MU 1502 sub on TD. Fill stack, TD, and choke manifold with water. Changed out pressure recorders due to the clock on 1st recorder not working. Witness of BOPE test by AOGCC waived by Mr. Jim Regg @ 23:36 on 8/6/19.;Test BOPE with 5" pipe to 250 and 3500 psi as per AOGCC and Hilcorp regulations and standards. UPR door seal failed on 3rd test.; Drain stack and change out door seal on upper pipe rams. Test PVTs and gas alarms while changing out door seal. (All good).; Rig back up test equipment and refill stack, TD, and choke manifold with water.;Continue to test BOPE on 5" and 4" pipe to 250 and 3500 psi with no additional failures. Perform accumulator test. All tests performed per AOGCC and Hilcorp regulations and standards.;Rig down test equipment, pull test plug, pull and break down test joint. Set test pump down to deck w/ crane. Install wear bushing. Clean & clear rig floor. Prep to PU BHA.;Hold PJSM. PU and make up 6 1/8" HDBS PDC / AutoTrak BHA w/, On Trak MWD, BCN, SDN, NM sub, and NM stab V 601'. Up load MWD tool. Hold PJSM and Load Nukes. Shallow pulse test MWD. Clean rig floor after MU BHA.;RIH w/ 6 1/8" PDC / AutoTrak BHA on 4" DP f/ 601' V 4300'. Fill pipe @ 118 GPM, 390 PSI. TIH slowly through TOL / PBR f/ 4275't/ 4350'w/ no issue. Cont RIH f/ 4350't/ 9240.';CO elevators f/ 4" to 5". 8/8/2019 RIH f/ 9240' to 10,860' with 6 1/8" HDBS PDC / AutoTrak BHA w/, On Trak MWD, BCN, SDN, NM sub, and NM stab.;Break circulation and re-log hole with MWD from 10,860' to 10,950' bit depth.;RIH to 11,423'.;Ream from 11,423' to 11,660' (0.5 WOB, 7.2-7.8 TO, 126 RPM, 2262 PSI, 247 GPM).;Drill from 11,660' to 11,700' . Fanned bottom and established cutter pattern on bottom/1-3 K WOB for first foot. Increase parameters to 150 RPM, 8.8 TO, 6.8 WOB, 2404 PSI, 260 GPM, 10.1 ECD, 47 fpm ROP. BHA trying to build angle.;Drill from 11,700' to 11,723' . Control drill @ 5-10 fph in order to get angle back on track. PUW 210, SO 170, ROT 190, 150 RPM, 7-8 TO, 1-5 WOB, 2065 PSI, 240 GPM, 9.94 ECD. Set Auto Trak tool to maximum force down and adjusted drilling parameters with no effect on hole angle.;After discussing options with town decision was made to go back to drilling with original parameters and Auto Trak tool set at max down force. Drill (/11,723' to 11,756'. 150 RPM, 8.8 TO, 6.8 WOB, 2350 PSI, 260 GPM, 10 ECD.;Turn Auto Trak tool to 90° and drill ft 11,756' to 11,778'. Build rate flattened out and held near bit Inc. @ 88.1 ° w/ no noticeable change in Az. 150 RPM, 8.8 TO, 6.8 WOB, 2322 PSI, 258 GPM, 10 ECD, 16 fph ROP. Turn Auto Trak tool to 170° and drill to 11,790' , Near bit Inc. holding @ 88.9°.;Increase WOB to 10 and cont. to drill f/ 11,790' to 11,800' with Auto Trak tool turned to 170°. 150 RPM, 8.8 TO, 10 WOB, 2344 PSI, 258 GPM, 10 ECD, 57 fph ROP. Near bit Inc. built to 91.5°.;Cont. to drill f/ 11,800' to 11,858' adjusting Auto Trak 90° V 280° & reducing to 120 RPM. 120 RPM, 7.1 TO, 10 WOB, 2250 PSI, 258 GPM, 10 ECD, 20 fph ROP. 215K PU, 180K SO, 200 RT. Swapped Auto Trak to hold mode @ 11854'. Near bit Inc built to 93.6°. Decision from town to POOH & CO BHA & bit.;Circulate weighted sweep surfto surftill shakers clean up. Pump dry job. Prep to POOH.;POOH slowly f/ 11858' to shoe @ 10860'. Monitor well (static). Continue POOH f/ 10860' V 9199'.;RD Hawk Jaws @ 9199' to repair die retainer plate / RU Spinner Hawks. POOH V 9102'. RD Spinner Hawks / RU repaired Hawk Jaws @ 9102'.;Cont POOH f/ 9102' to BHA @ 601'. CO elevators f/ 5" to 4".;POH f/ 601' while LD 6 1/8" PDC / AutoTrak BHA per Baker DD. Hold PJSM w/ Baker MWD. R & R nukes. - Announce nuclear source R & R on Rig and GPP.;Transported to KGF G&I: Offloaded solids = 0 bbls Cumulative Offloaded Solids = 1788 bbls 8/9;2019 Break off bit and download MWD tool. UD BHA #7 Baker Smart tools: Stop sub, SDN, BCPM, MWD stb, OnTrak MWD, Flex collar and Auto Trak.;P/U BHA #8 Baker Smart tools: Auto Trak, Flex collar, OnTrak MWD, MWD stb, BCPM, SDN & Stop sub. Upload MWD. M/U Kymera KMX323 6.125 " bit. M/U NM string stb & 2 flex collars, Filter sub , Float sub and x/o from derrick. P/U and load source in MWD.;RIH w/ HWDP and jars out of derrick to 602.88'. Continue to RIH w/ 4" DP to 787' and perform a shallow hole test. Good test! Continue to RIH w/ 4" DP to 9244' (filled pipe @ 4350').;Change elevators f/4" to 5" P/U HT -38 pin X 4-1/2 IF box X/0, RIH w/ 1 std of 5" t/ 9340'. Service TD, Swivel and Crown while filling pipe.;Continue RIH w/ 5" DP to 11530'.;Wash & ream to 11,858' @ 250 GPM, 2377 PSI. Calibrate MWD tools per Baker.;Control time drilling f/ 11858't/ 11863'. 1-3 FPH ROP, 100 RPM., 265 GPM, 2051 PSI. 7- 10K WOB. Set Auto Trak tool to 50% force down for 1 hr. Increase Auto Trak tool to maximum force down . NBI dropped f/ 93.60° t/ 93.43°.;Control time drilling f/ 11863't/ 11864'. 2-3 FPH ROP, 100 RPM., 265 GPM, 2481 PSI. 7-10K WOB. NBI dropped f/ 93.43° t/ 93.34°.;Control time drilling ft 11864't/ 11865'. 3-5 FPH ROP, 100 RPM, 265 GPM, 2481 PSI, 7-10K WOB. NBI dropped ft 93.43° U 93.34° / 93.25°/ 93.12°. Sensor seeing new hole at 11864'. (Sensor 6' back).;Control time drilling f/ 11865' t/ 11897'. 10 -15 FPH ROP, 100 -120 RPM, 251 GPM, 2441 PSI. 7-20K WOB. NBI stepped down slowly f/ 93.12° t/ 92.99°/ 92.81' / 92.78° / 92.72 / 92.64°/ 92.55°, 92.46°, 92.37, 92.11 °, 91.76°.;Reduce Auto Trak tool f/ maximum force t/ 50% down, but NBI increased t/ 93.08°. Increase Auto Trak to max force down. Auto Trak set to maintain 4° / 100' drop beginning at 91.76° / 11897'. Take SPRs.;Transported to KGF G&I: Offloaded solids = 0 bbis Cumulative Offloaded Solids = 1788 bbl 8/10/2019 Control/Time drilling f/ 11897't/ 11913'. 10 -15 FPH ROP, 100 -120 RPM, 251 GPM, 2441 PSI. 7-20K WOB.. Dogleg severity @ 6.72° w/ NBI of 90.53°.;At current track Geology is worried about leaving top of C5A. Pump small dry job and POOH to 11,660' for Open Hole Sidetrack.; Break circulation, Downlink with Baker MWD and set Auto Trak tool to maximum force down.;Trough low side of hole f/ 11,630' to 11,660' 0 WOB, 107 Rot, 7.1-7.6 TQ, 241 GPM, 2230 PSI, 10 ECD. Ream up 3' and back down, Ream up 6' and back down, Ream up 15' and back down, Ream up 30' and back down, Repeat cycle until ribs on tool free spin while set at max force down as per DD.;Cont. to trough low side of hole f/ 11,630' to 11,660' 0 WOB, 106 Rot, 6.5-7.0 TO, 242 GPM, 2230 PSI, 9.9 ECD. Ream up 3' and back down, Ream up 6' and back down, Ream up 15' and back down, Ream up 30' and back down, Repeat cycle until ribs on tool free spin while set at max force down as per DD.;Back ream up and back down 30' slowly (11,660 - 11,630') 3 times with ribs closed on Auto Trak.(no force down) as per DD. 0 WOB, 108 Rot, 6.8-7.5 TQ, 242 GPM, 2230 PSI, 9.9 ECD.;Park bit at 11,660' while rotating and circulating as per DD.;Time drill f/ 11660't/ 11670'. Begin time drilling per Baker DD (Adjusting parameters per NBI and formation indicators). Starting 76.31 ° NBI. 0.5 FPH for 5 hours - 76.11 ° NBI @ 11662', 2.65K WOB. 1.0 FPH for 4 hours - 76.11 ° NBI @ 11664', 2.3 K WOB.;2.0 FPH for 1 hour - NBI increased to 76.2° / 76.38° , 3.1 K WOB. Reduced back to 1 FPH. NBI reduced to 76.29° 3.4 K WOB - Maintaining 1 FPH for separation from old hole. 210K PU, 180K SO, 190K RT, 245 GPM, 2300 PSI, 100 RPM.; Transported to KGF G&l: Offloaded solids = 90 bbis Cumulative Offloaded Solids = 1878 bbis 8/11/2019 Time drill f/ 11,670' to 11,673' for separation from old hole 210K PU, 180K 80, 190K RT, 241 GPM, 2300 PSI, 100 RPM, 6.0-6.5 TQ, 0-1.4 WOB.;Time drill f/ 11,673' to 11,675' for separation from old hole 210K PU, 180K SO, 190K RT, 241 GPM, 2300 PSI, 100 RPM, 5.5-6.5 TQ, 0-4 WOB.;Time drill f/ 11,675' to 11,676'. 0.5 FPH. / 76.55° NBI . Old hole @ 76..90° NBI. 215K PU, 175K SO, 195K RT, 241 GPM, 2360 PSI, 90-100 RPM, 5.5-6.5 TQ, Pump 2 x 25 bbl / 20 ppb Baracarb 600 / 5 ppb steel seal. - Increased pressure and WOB. Reduced RPM. No change in NBI.;P/U to 11,614' due to top drive scraping noise. - Mark pipe & Rack back 1 std. Found blower motor fan cowling "scraping". - Removed cowling. Serviced top drive.;TIH to 11,630'. Lube in w/ 7 SPM, 300 PSI. No rotary. Tag btm of new hole solid w/ 5K WOB @ 11,676'. PU 2' off btm. Stage pumps to 241 GPM. Confirm in new hole w/ NBI @ 76.55°. Stage rotary to 100 RPM.;Ease to btm (11,676'.) w/ 241 GPM, 100 RPH. NBI jumped to 76.90° (Old hole). Pull back 2'& NBI dropped back to 76.55°. Ease to back to btm and remained at 76.5°.;Continue time drilling ft 11,676' tt 11,677'. (2K WOB). 215K PU, 175K SO, 195K RT, 241 GPM, 2360 PSI, 100 RPM, 6.5- 7.1 TQ. .0.5 FPH. / 76.55° NBI. Old hole @ 76..99° NBI.;lncrease time drilling to 1.0 FPH f/ 11,677't/ 11,679'. 76.55° NBI. Old hole @ 77.08° NBI. 215K PU, 175K SO, 195K RT, 241 GPM, 2360 PSI, 130 RPM, 6.5- 7.1 TQ. Pump 35 bbl / 20 ppb Baracarb 600,/ 5 ppb steel seal. - Increased pressure and WOB. Reduced RPM. No change in NBI.;lncrease time drilling to 2.0 FPH @ 11,679' 76.55° NBI to 76.72° NBI Old hole @ 76.81° NBI 215K PU, 175K SO, 195K RT, 241 GPM, 2360 PSI, 130 RPM, 6.5- 7.1 TQ, Pump 35 bbl / 20 ppb Baracarb 600,/ 5 ppb steel seal.;Decrease time drilling to 1 FPH f/ 11,679'. PU 2'. Ease back do to 11,679' when sweep hit bit. Cont time drilling f/ 11,679't/ 11,681'. 76.72° NBI to 76.61° NBI /76.73° Old hole @ 77.20° NBI 215K PU, 175K SO, 195K RT, 241 GPM, 2360 PSI, 130 RPM, 6.5- 7.1 TQ.;Transported to KGF G&I: Offloaded solids = 18 bbis Cumulative Offloaded Solids = 1894 bbis 8/12/2019 Time drillinq f/ 11,681't/ 11,683'. Ramp up from 1 fpm to 2 fph 215K PU, 175K SO, 195K RT, 241 GPM, 2360 PSI, 130 RPM, 6.5- 7.1 TQ, 0-3 WOB. NBI @ 76.73° , Old hole @ 77.20° NBI.;Attempt to control drill by wt. f/11,683' to 11,684' 215K PU, 175K SO, 195K RT, 241 GPM, 2360 PSI, 120 RPM, 7.6 TQ, 3-4 WOB. Drilled 1/2' and lost all WOB. NBI up to 77.49°, Back in old well bore.;P/U to 11,670' zero WOB, Ream down to connection break and re -set depth to tally fl 11,681' to 11,677'. Time drill @ 17hr f/ 11,677' to 11,679' (corrected depth) to re-establish ledge. 215K PU, 175K SO, 195K RT, 241 GPM, 2360 PSI, 120 RPM, 6.5 TQ, 1-2 WOB. NBI @ 76.82°.;Continue to time drill f/ 11,679' to 11,682' 215K PU, 175K SO, 195K RT, 248 GPM, 2430 PSI, 120 RPM, 6.5 TQ, 2-2.5 WOB. NBI @ 77.43°, old hole NBI 77.43°.;P/U to 11,676' and begin time drilling @ 2 fph trying to re-establish a ledge on low side of hole, to 11,679'.; Decision made to POOH for motor and bit change. Observe hole. Mix and pump dryjob.;POOH slowly to 4" DP.;Change elevators from 5" to 4" @ 9225'.;Cont POOH f/ 9225' to BHA @ 602'.;LD & rack back 6 1/8" Kymera / AutoTrak BHA f/ 602' to surface per Baker DD. Hold PJSM w/ Baker MWD. Remove nukes. - Announce nuclear source R & R on Rig and GPP. Download MWD. Retrieved a 1"x 1" piece of metal from hole. 1/2" thick. - Pics in O drive.;Prep to PU BHA #9. Hold PJSM. Begin PU and MU 6 1/8" Varel PDC / Ultra X-treme 1.8° Motor BHA. MU 1.8° motor insert & align motor. Prep to upload MWD.;Transported to KGF G&I: Offloaded solids = 0 bbis Cumulative Offloaded Solids = 1894 bbis 8/13/2019 M/U BHA #9 = Bit, 1.8° Bent Housing 4-3/4" Motor, Stb, Flex jt, MWD Stop Sub, BCPM, SDN, NM Stop Sub, NM Stb, 2 Flex jt.,Filter Sub, Float Sub, X/0, 12 HWDP, X/0, Jars, X10, 2 HWDP=626.59.;RIH w/ BHA#9 to 4277' and fill pipe. (Performed MWD shallow hole test @ 1170').;Continue RIH to 11,636" filling ppe every 2000'. (Did not see TOL when entering).;Fill pipe and establish circulation @ 246 gpm W/ 2500 psi.;Orient Motor down and cut trough f/ 11,650' to 11,680'.•Time drill with motor f/11,680'to 11688' 1f h, 210 PU, 170 SO, 2.6-14.5 WOB, 253 gpm, 2675 psi. 8/14/2019 Time drill with motor f/11,688' to 11,690' @ lfph, 210 PU, 170 SO, 0-6.5 WOB, 252 gpm, 2475 psi., 0-45 psi diff. press. Adjusting for reactive torque as required by DD to maintain tool face orientation of 180°.;Time drill with motor f/11,690' to 11,698' @ 2fph, 210 PU, 170 SO, 0-5 WOB, 251 gpm, 2500 psi, 40- 75 psi diff. press.. Adjusting for reactive torque as required by DD to maintain tool face orientation of 180°.;Time drill with motor f/11,698' to 11,714' @ 5fph, 210 PU, 170 SO, 0-4 WOB, 254 gpm, 2425 psi., 0-75 psi diff. press. Lost WOB, diff, psi & reactive tq f/ 11,702 - 11,706'. Had 1-2 WOB, 40 diff. psi & 0 reactive tq f/ 11,706' to 11,714'. Drill to 11,717' @ 10 fph w/ 0.5 WOB, 40 diff & 0 reactive.;Pick up to 11,660'and orient TF down. Attempt to locate ledge at beginning of sidetrack @ 11,680'. Work down to 10,689' with no ledge contact.; Observe well - Static. Pump dry job.;POOH to 10,511' (357' inside 7" shoe).;Make up wear ring puller on drill string RIH and pull wear ring.;M/U test plug on drill string, lower test plug to wellhead and seat in bowl. Confirm seated. Rig up test equipment.;Test BOPE all components to AOGCC and Hilcorp requirements. 250 low/ 3500 high 5 min per test charted. Perform accumulator drawdown test. AOGCC witness of test waived by Jim Regg on 8/12/19 @ 14:28 hr.;Rig down test equipment and retrieve test plug. Set wear ring with drill string, confirm seated, RILDS., UD run tool.; Transported to KGF G&I: Offloaded solids = 0 bbls Cumulative Offloaded Solids = 1894 bbis 8/15/2019 Service rig/ Change out swivel packing.;Clear and clean rig floor.;RIH to 11,127'. UD top single of 5" stand # 20. P/U to 11,035'.; Break circulation and orient motor tool face to low and right side of hole. Begin cutting trough from 11,035' to 11,067' on low side of hole for OH side track. New swivel packing Ieaking.;Bring blocks to rig floor and hammer wing nuts tight on swivel packing.; Re-orient tool face down and to the right. Resume cutting trough from 11,035' to 11,067' on low side of hole for OH side track.;Time drill f/11,067' to 11,070' @ 0.5 fph 215 PU, 173 SO, 257 gpm, 2525 psi, 0-60 psi diff press. Pickup and wipe hole as required to prevent stabilizers from hanging up.;Time drill f/11,070 to 11,080' @ 1 fph 215 PU, 173 SO, 257 gpm, 2525 psi, 0-40 psi diff press. Pick up and wipe hole as required to prevent stabilizers from hanging up.;Transported to KGF G&I: Offloaded solids = 0 bbls Cumulative Offloaded Solids = 1894 bbls 8/16/2019 Time drill (/11,080 to 11,081' @ 1 fph 215 PU, 170 SO, 257 gpm, 2450 psi, 30-60 psi diff press. Pick up and wipe hole as required to prevent stabilizers from hanging up.;Time drill f/11,081 to 11,084' @ 1 fph 215 PU, 170 SO, 257 gpm, 2450 psi, 50-255 psi diff press. Pick up and wipe hole as required to prevent stabilizers from hanging up. (For the most part seeing good correlation between WOB and differential pressure).;Time drill (/11,084 to 11,087' @ 1 fph 215 PU, 170 SO, 257 gpm, 2450 psi, 20-70 psi diff press. Pick up and wipe hole more often than previously due to stabilizers hanging up and reactive torque.;Time drill f/11,087' to 11,099' @ 2 fph 215 PU, 170 SO, 257 gpm, 2450 psi, 0 - 20 psi diff press. Pick up and wipe hole as needed.;Work string , hanging up at 11099 ft, cannot apply wt to bit. Re-cip and rock drill string through . Regain WOB.;Time drill f/11,099' to 11,106' @ 2 fph 215 PU, 170 SO, 257 gpm, 2550 psi, 50 - 140 psi diff press. Pick up and wipe hole as needed. Begin take weight (5 - 10), increase diff (50 - 150) this interval.;Transported to KGF G&I: Offloaded solids = 72 bbls Cumulative Offloaded Solids = 2088 bbls 8/17/2019 Time drill (/11,106to 11,107' @ 2 fph 215 PU, 170 SO, 250 gpm, 2350 psi, 0 - 12 psi diff press. Pick up and wipe hole as needed. WOB coming up with no differential pressure or reactive torque.; Pick up 30' to 11,067' to wipe and clean hole and improve weight transfer to bit and not the stabilizers.; Time drill f/11,107' to 11,116' @ 5 fph 215 PU, 170 SO, 252 gpm, 2400 psi, 20-45 psi diff press. Pick up and wipe hole as needed. Unable to keep WOB, differential pressure or reactive tq. Try to obtain 8-10 WOB to 11,118' w/o success.;Pick up to 11,100' , turn off pumps and dry tag bottom@ 11,118' w/ 10K over. Pick up to 11,110' and RIH to 11,122' with no weight increase.;Pick up and resume time drilling f/ 11,109 to 11,110' @ 2 fph . Discuss options with Anchorage and make decision to POOH for BHA and bit change.;Mix dry job, observe well (static) and pump dry job. Did not have enough barite on board for dry job and had to transfer more over from GPP to finish building dry job.; Pick up single off of beaver slide. POOH to change out BHA and bit. ).f/ 11,118' to 10,213' Stands 5-10 showed only 1.3 bbl to fill.;Verify hole static and not flowing. Trouble shoot flow path from trip tank to hole. re-route returns to back trip tank only with fluid level equalizing to front trip tank. PVT's showing correct hole fill now.;Continue POOH f/ 10,213'- 1939'. Flow check at 7" shoe and TOL.;Remove CanRig encoder from dwks. Broken fitting with air Ieak.;Flow check, resume POH 4" DP to BHA at 172 ft.;Flow check at BHA, clear rig floor, alert platform, prior unloading MWD (radio active source). Handle BHA #9, unload source, break bit #9 (grade 1-1-in, CT). Re-configure motor / MWD, break subs, stabilizers. Radial and axial bearings, seals good condition, rotor tight in stator.;Handle BHA #10, M/U bit #10, adjust AKO, scribe and document. RIH, surface test same. Test successful.; Flow check, follow BHA with 4" DP to 2300 ft at 0600 hrs.;Transported to KGF G&I: Offloaded solids = 72 bbls Cumulative Offloaded Solids = 2088 bbls 8/18/2019 RIH w/ BHA #10 to 4354' (Did not see TOL when entering). Pick up above TOL and fill pipe.;Continue w/ TIH to 9241'w/ 4" DP.;Change elevators f/ 4" to 5" , M/U X/O (HT-38 Pin X NC-50 Box) and continue TIH w/ 5" DP to 11,611'.;Break circulation and orient motor tool face to 180° down.;Work pipe f/ 11,630' to 11,660' with tool face oriented down to cut a trough in low side of hole. 0 WOB, 301 GPM, 3300 PSI, 10.3 ECD.;Time drill @ 0.5 fph (/11,660' to 11,661' 215 PU, 170 SO, 2-3 WOB, 277 gpm, 2750 psi, 0 Diff. psi, 10.3 ECD.;Time drill @ 1 fph (/11,661' to 11,662' 215 PU, 170 SO, 9-14 WOB 299 gpm, 3110 psi, 0 Diff. psi, 10.2 ECD. WOB stacked up to 20k and when we picked up pipe was stuck.;Work pipe several times up to 250 with no joy Jarred up with 275 , put in 6 turns to the right and alternated jarring up w/ 280 and down w/ 40 three times. Pipe came loose on third time down.;Wash back to bottom and resume time drilling @ 1 fph, 11662 - 11666 ft, 300 gpm, spp 3050, diff 0 - 25, ECD 10.1. Pull up to 11660 and re-pass trough to 11666 at .5 fph. Continued wt stacking on bit at times, diff building and stable at 40 psi. No issues holding tool face. Re-pass trough at 11661.;Transported to KGF G&I: Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2088 bbls 8/19/2019 Time drilling back through previous hole section @ 0.5 fph, 11660 - 11661 300 gpm, sop 3050, diff 40-20, ECD 10.1. Continues stacking WOB at times, diff drops as WOB increases, No issues holding tool face. Having to pull 40-60 over to free pipe on PU.;Discuss conditions with Office. Decide to POOH to 11,060' and attempt to side track there while rounding up stinger and check on availability of hands to spot a 20 bbl. cement kick off plug.;Work pipe f/11,030' to 11,060' to cut trough bottom of hole. 210 PU, 170 SO, 299 gpm, 3015 psi, 0 WOB.;Time drill @ 0.5 fph f/11,060' to 11,062' 210 PU, 170 SO, 299 gpm, 3010 psi, 0-5 WOB, 0 Diff, 10.1 ECD.;Time drill @ 1 fph f/11,062' to 11,066' 210 PU, 170 SO, 300 gpm, 3000 psi3O- 0.5 WOB, 29-45 Diff, 10 ECD, Starting to see a little reactive torque.;Begin build differential, note slow ramp up 0 - 65 psi with continued linear build. Suggests possible "bite" on wellbore. Resume time drill @ 1 fph f/11,066' - 11076' 210 PU, 170 SO, 300 gpm, 3000 psi3O- 5 WOB, 20 - 70 Diff, 9.9 ECD,;Transported to KGF G&I: Offloaded solids = 0 bbis Cumulative Offloaded Solids = 2088 bbls 8/20/2019 Continue to time drill @ 1 fph (/11,076' t/ 11,083' 210 PU, 170 SO, 302 gpm, 2950 psi, 2- 4 WOB, 60 - 87 Diff, 9.9 ECD.;Continue to time drill @ 1 fph (/11,083' t/ 11,088' 210 PU, 170 SO, 303 gpm, 2950 psi, 2- 3 WOB, 70 - 88 Diff, 9.9 ECD. Discuss putting more increasing to 2 fph with town.;Continue to time drill @ 2 fph (/11,088' t/ 11,093'. 303 GPM, 2975 psi, 3 - 5 WOB, 90 - 100 Diff, 9.9 ECD. Decision made to go to 3 fph. [Made 33' from where we started time drilling].;Continue to time drill @ 3 fph f/ 11,093' U 11,102'. 303 GPM, 2975 psi, 1 - 5 WOB, 90 - 105 Diff, 9.9 ECD.;Make connection with single jt DP. Drill string locked in place in rotary. Tool face not disturbed. Bring pump on line, diff press reduced to 25 psi. increasing to 41 psi in 30 min.;Continue to time drill @ 3 fph f/ 11,102' - 11,111'. 301 GPM, 2985 psi, 1 - 5 WOB, 90 - 105 Diff, 9.9 ECD.;Lose diff and WOB. P/U 5 ft, slack off 11,105 - 11,113 ft. Take no wt, no diff, no reactive torque.; Pick up to 11060 ft, re-pass / time drill @ 3 fph ft 11, 060' - 11,103 ft, 301 GPM, 2985 psi, 1 - 5 WOB, 25 - 45 Diff, 9.9 ECD.;Flow check, POH 5" DP for BHA inspect and possible cmt plug for sidetrack. Bit depth 10900 at 0600 hrs. No swab, no gain / Ioss.;Transported to KGF G&I: Offloaded solids = 18 bbls Cumulative Offloaded Solids = 2106 bbls 8/21/2019 POH f/ 10,900't/ BHA.; LD BHA all except for the HWDP and 1 std of flex collars. Bit graded 1 -1 -CT-S-X- I -WT- BHA.; Move HWDP out of the way and RU power tongs to PU 2 7/8 tbg cmt stinger. Had issues getting power tongs rigged up.;PU 2 7/8 tbg stinger, 20 jts tbg, and xo from 2 7/8 IBT to HT 38. BHA = 649.21.;Continue RIH 2-7/8 tbg cmt stinger, on 4" DP.;P/U first std 5" DP, pump through, confirm string clear.;Resume RIH 5" DP. Wash last 300 ft down. Take no wt. Tag at 11,917. Pick up to 11912 ft.;C/C fluids and wellbore while make ready for cmt plug. R/U SBM cmt equip, pre-mix fluids, plumb all steel lines to rig floor, manifold rig lines to cmt head.;Safety meeting all personnel, Commence set cmt plug as follows: Test lines 2500 psi, pump 12 bbls 12 ppg spacer, batch mix 12.8 ppg cmt.;Transported to KGF G&l: Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2106 bbls 8/22/2019 Pump cmt kick off plug. Pump 18.2 bbls 15.8 ppg cmt, Chase w/ 2 bbls water, rig pumped 4 bbls spacer and 130 bbls of OBM to spot cmt. [Cmt in place at 6:401 RD cmt circ head and pull 8 stds slow [11,083'].;Put foam ball in pipe and circ at 327 GPM, 2454 psi to circ pipe clean. Got back spacer at bottoms up and dumped 10 bbls. Circ 1 1/2 circulations and everything was clean. Pump dryjob.;POH to 2 7/8 tbg.;RU to LD 2 7/8 tbg cmt stinger and LD same. Last 396' of the tbg stinger had a sheath of cmt on the side. The foam ball logged in the defuser at about 10' or 1/2 way. RD tbg equip.;Cut drilling Iine.;Drain BOP stack, pull wear ring, set test plug, fill stack with 1-12o, R/U test pump and lines.; PJSM, test BOPE all components:250 - 3500 5 min rams, blinds, annular, choke lines and choke mnfld, kill line , all related valving. Test floor valves, top drive to stand pipe mnfld. All tests against 4" and 5" tubulars. Perform accumulator press, volume drawdown test. Nitrogen bottles 1000 psi.;R/D BOP test equip, pull test plug, set wear bushing.; Transported to KGF G&I: Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2106 bbls 8/23/2019 Finish clearing floor of test equip.;Service Rig.;PU new 6 1/8 side track BHA. Plug in and upload tools.;RIH to 675' and test tools. Everything working good.;Continue RIH filling pipe just before going through top of liner at 4300'. Didn't see top of liner when we went through it. Continue RIH filling pipe again at 9324' and at shoe. RIH to 11,129' and it started take a little wt then falling off.;Wash f/ 11,129' t/ 11,179'. Wash and ream f/ 11,179' t/ 11,568' where it was holding 10k bit wt and had about 200 diff. Shut do rotary and pump and set do 20k. Solid cmt.;Orientate tool to 11569 ft and start trenching 60'. Begin time drill 11569 - 11571 ft.;Weight stack up, lose differential, pull off btm, sticking at 11,560', re-cip string multiple times, max up 310K, max do 163K. Work right hand wraps 1 to 5 turns. Pull free, normal up / do drag, torque normal, all parameters good. Orient string to 180 toolface, slack off to prior depth at 11571'.;Resume time drill sidetrack 11571 - 11573 ft, WOB 0 -6, Bit RPM 150, ROP n/a, SPP 3200, SPM 85, ECD 10.3.;Transported to KGF G&I: Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2106 bbls 8/24/2019 Side tracking. Time drill at 112 fph at 11,573'. Wt stacking and loosing diff press. Oscillate pipe and wt would fall off but didn't gain any diff. Start adding NXS lube and bring up lube content to 2%. Work pipe up rotating 30' to get lube dispersed around hole and on pipe.;Orientate tool and trench back to bottom. Time drill at 1/2 fph f/ 11,573' t/ 11/574'. 284 GPM, 2900 psi. Still having issues getting diff and bit wt stacking.; Continue time drilling at 1/2 fph but started oscillating constantly by manually going from forward to reverse. Time drill f/ 11,577' U 11,579'. Getting back 17 % formation.;Continue time drilling at 1" every 5 min and oscillating the pipe 2 turns to the right and 2 turns to the left then letting it drill off until next 5 min. Drill f/ 11,579' U 11,583'. Started getting back 30% formation at 11,580'. 284 GPM, 2940 psi, 50 diff, 2 to 4 WOB.;Continue time drilling at 1" every 4 min and oscillating the pipe 2 turns to the right and 2 turns to the left then letting it drill off until next 4 min. Drill f/ 11,583' U 11591'. 298 GPM, 3130 psi, 50 diff, 3 to 5 WOB.;Re-cip I oscillate drill string, work stacked weight free, reduced differential. Orientate string to 180 deg. No gain / Ioss.;Resume time drill f/ 11591'- 11600'. 302 GPM, 3230 psi, 55 diff, 3 to 5 WOB. 50% formation with normalized cuttings at 11595'.;Transported to KGF G&I: Offloaded solids = 26 bbls Cumulative Offloaded Solids = 2132 bbls 8/25/2019 Continue side tracking. Time drill 6 118 hole f/ 11,600'V 11,610'. This makes 40' from where we started. Getting back 70% formation. 302 GPM, 3220 psi, 35 to 80 psi diff, 1 to 5 bit wt, Oscillating pipe to break free from wall. Holding 180° to 168° at bit.;PU to 11,568' and rotate and reciprocate between 11,536' and 11,568 while circ 1 1/2 bottoms up. No significant increase or decrease.;Check flow, Pump dry job.;POH on sng to change breaks. POH to BHA, wellbore good condition, normal up drag, no gain I Ioss.;Flow check at BHA, handle BHA #11, LID all components. Break bit #11 (Grade 1 -1 -CT -A -X -In -No -BHA). Motor bearings good, rotor tight, seals effective.; Handle BHA #12, M/U AutoTrak assy, program - download MWD, LWD. , M/U remaining components BHA #12, CIO jars. RIH 5 stds 4" DP. Surface test MWD, test successful.; Flow check, resume RIH BHA #12 on 4" DP 1475 - 9360 ft.;P/U 4" DP in singles total 30 jts.;Transported to KGF G&I: Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2132 bbls 8/26/2019 PU 30 jts of 4" DP. MU 1 std of 5" DP and fill pipe. Put rig tape on stand and pull up through derrick taking measurements for Baker. RIH to 10,873 and screw back into TD. Test and calibrate Baker tools.;RIH to 11,545' with no issues.;Fill pipe and get a survey. Slide in hole to 11,601' with a separation from the old hole of 1.8°. Started taking wt.;Wash and ream do to 11,610' with a separation of 3°. Up wt 210, Dn wt 170, Rt wt 190.; Directional drill w/ rotary steerable f/ 11,610' t/ 11,615 starting at 2 fph until we know we are getting what we want out of the tool. Getting good reaction from tool.; Directional drill w/ rotary steerable f/ 111,615' U 11,622' at 5 fph making sure we are still getting good response from the tool.; Directional drill w/ rotary steerable f/ 11,622' t/ 11,631' at 8 fph making sure we are still getting good response from the tool. 284 GPM, 3055 psi, 120 RPM, 7k torque, 5 to 6 WOB, MW 8.9+, vis 90, EMW 10.2.; Directional drill w/ rotary steerable f/ 11,631' t/ 11,650' at 12 fph making sure we are still getting good response from the tool. 283 GPM, 3045 psi, 120 RPM, 7k torque, 6 to 7 WOB, MW 8.9, vis 87, EMW 10.2.; Directional drill w/ rotary steerable f/ 11,650't/ 11,725'. 283 GPM, 3045 psi, 150 RPM, 8.2k torque, 10 to 15 WOB, MW 8.9, vis 87, EMW 10.2. [Attempted to increase GPM to 302 and ROP fell off to 10] Survey at 11,666', Inc 72.57, Az 174.47, =7.79' center to center.; Directional drill w/ rotary steerable f/ 11,725' t/ 11,828'.; Rotary steerable not building angle. Slow ROP, time drill 5 fph, slow gpm to 250. Discuss with Hilcorp Anchorage options to regain build rate. Decision made to drill ahead reduced ROP and GPM.; Resume drill ahead 11828 - 11870 ft. Build increase to 2.3 with steady build to 73.21 deg. inc. WOB 2-5K, RPM 150, GPM 250. No gain / loss, cuttings return normal quantity' quality.;Transported to KGF G&I: Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2132 bbls 8/27/2019 Directional drill 6 1/8 hole w/ rotary steerable f/ 11,870't/ 11,900'. 250 GPM, 2680 psi, WOB 10k, TQ 7k, 150 RPM. Started dropping angle again.; Discussed w/ town and decided to time drill while preparing to POH for BHA change. Time drill f/ 11,900't/ 11,916' at 5 fph. Did gain .2° build while time drilling.;Take survey, monitor well, fill trip tank, and pump dry job.;POH to BHA, did see a 5k overpull when the MWD stab pulled into the bottom of the motor kick off at 11,610'. the rest of the open hole was clean.;Stand back HWDP and jars. PU and break bit. Bit grade 1-1-1116. Have PJSM for down loading sources. Down load MWD tool. Stand tools back in derrick. LD the auto track assem.;Hold PJSM. PU & MU BHA #13 w/ 6 1/8" Reed PDC / Ultra X-treme 1.5° Motor U 351'. MU & align 1.5° motor insert. Upload MWD. Hold PJSM. Load nuclear sources. Begin offloading 5" casing.;RIH w/ w/ 6 1/8" Reed PDC / Ultra X-treme 1.5° Motor BHA #13 to 11,726', filling pipe every —3,000'. Shallow test MWD tools w/ 250 GPM, @_ 820'/ 1450 PSI and @ 10,695' / 3130 PSI w/ No issues through TOL (4,300') , 7" csg shoe (10,860'), or KOP (11,569') Finish 140 jts of 5" casing.;Wash and ream f/ 11,726 t/ 11,914'. 250 GPM, 2700 PSI, 25 RPM, 197K RW. Take SPRs on pumps #1 & #2.;Work pipe 20' up to lineup high side. Take check survey @ 11,910'. (11,857.77' actual svy tool depth) 72.82° Inc, 170.12° Az.;Slide f/ 11,916' t/ 11,940'. 285 GPM, 3380 psi, 3K WOB, MW 8.9+, vis 90, EMW 10.4 PPG. High side TF.;Rotarydrill f/ 11,940't/ 11,995'. 50- 60 FPH ROP, 225K PU, 180K SO, 195K RT, 275 GPM, 3515 PSI, 10.5 PPG ECD, 60 RPM, 7 -8K TQ.;Transported to KGF G&I: 68 bbls Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2319 bbls 8/28/2019 Directional drill 6 118" hole f/ 11,995't/ 12,008'. Rotating at 58 RPM, 7 - 8k TQ, 275 GPM, 3480 Psi, Built 4° .;Directional drill 6 1/8" hole f/ 12,008' t/ 12,030'. Sliding , WOB 4-6k, 275 GPM, 3480 Psi.; Directional drill 6 1/8" hole f/ 12,030't/ 12,106'. Rotating 58 RPM, 7 - 8k TQ, 275 GPM, 3200 psi, 5 to 8k WOB.; Directional drill 6 1/8" hole f/ 12,106' t/ 12,118. Sliding , WOB 4-6k, 275 GPM, 3480 Psi.; Directional drill 6 1/8" hole f/ 12,118't/ 12,195'. Rotating 55 RPM, 7 - 8k TQ, 275 GPM, 3400 psi, 5 to 8k WOB. ROP slowed do to the low 20s at 12,163' so we increased the RPM to 80 and decreased the flow rate to 250 GPM and we gained about 25 fph on our ROP.; Directional drill 6 1/8" hole f/ 12,195't/ 12,210'. Sliding , WOB 4-6k, 250 GPM, 2880 Psi.; Directional drill 6 1/8" hole f/ 12,210't/ 12,292'. Rotating 80 RPM, 7 - 8k TQ, 250 GPM, 3100 psi, 5 to 8k WOB. Last survey Inc 78.79, Az 165.29, At 12,237.21'.; Directional drill 6 1/8" hole f/ 12,292' t/ 12,325'. Sliding , WOB 7-10k, 250 GPM, 2880 Psi. Had issues with the tool hanging up and holding toolface. Sliding down now.; Directional drill 6 118" hole f/ 12.325't/ 12,388'. Rotating 80 RPM, 7 - 8k TQ, 250 GPM, Diff 137, 3050 psi, 7 to 9k WOB. Took SPRs before connection.; Directional drill 6 1/8" hole f/ 12,388 t/ 12,408'. Sliding , WOB 7-10k, 250 GPM, 2870 Psi. Had issues with the tool hanging up and holding toolface.; Directional drill 6 1/8" hole f/ 12,408'V 12,422'. Rotating 74-80 RPM, 7- 9k TQ, 250 GPM, 3150 psi, 7-9k WOB.; Directional drill 6 1/8" hole f/ 12,422' U 12,442'. Sliding , WOB 7-10k, 250 GPM, 225 psi Diff, 2875 psi SPP. Pump 25 bbl hi vis lube pill. Improved slide / no hanging up.;Directional drill 6 1/8" hole f/ 12,442't/ 12,483'. Rotating 80 RPM, 7 - 8k TQ, 250 GPM, 2930 psi, 5-6k WOB. 100% increase cuttings on hi vis pill back to surface. 32' high & 16' left of line.: Directional drill 6 1/8" hole f/ 12,483' t/ 12,520'. Sliding , WOB 8-1lk, 250 GPM, 300 psi Diff, 2950 psi SPP.; Directional drill 6 1/8" hole f/ 12,520' t/ 12,577'. Rotating 80 RPM, 8k TQ, 250 GPM, 3050 psi, 6k WOB. 34.88' high & 3.5' left of line.; Directional drill 6 118" hole f/ 12,577' t/ 12,603'. Sliding , WOB 8- 1lk, 275 GPM, 100-215 psi Diff, 3315 psi SPP. Hanging up at beginning of slide. Pump 15 bbls hi vis lube pill x 2.;Transported to KGF G&I: 34 bbls Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2353 bbls Rotating Hrs=10.5, Sliding Hrs=9.4 8/29/2019 Directional drill 6 1/8" hole f/ 12,603' t/ 12,606' sliding. Having a lot of trouble trying to hold toolface. Decided to short trip to clean the hole up.;Short trip f/ 12,606' t/ 11,900'. Had one spot right off bottom where we pulled 10k over. Broke it back do and pull through it with no issues. The rest of the hole was in good shape. RIH t/ 12,575' and wash and ream to bottom at 12,606'. Orientate tool.; Directional drill 6 1/8" hole f/ 12,606' t/ 12,618' sliding. 275 GPM, 3190 psi, 4 to 10 WOB. Still having issues with wt stacking. Pump 26 bbl high vis lube sweep.; Directional drill 6 1/8" hole f/ 12,618'V 12,643' Rotating. 80 RPM, 7 to 8k TQ, 270 GPM, 3190 psi, 4 to 10 WOB. Sweep came back w/ a 10 % increase in cuttings.; Directional drill 6 1/8" hole f/ 12,643' t/ 12,653' sliding. 277 GPM, 3223 psi, 4 to 10 WOB. Still having issues getting wt to bit. [Survey at 12,592.72' , Inc. 72.29, Az 157.49].;Work pipe while waiting on dry job, check flow and pump dry job.;POH to BHA.; Hold PJSM and make all call on GPP & Rig. Remove nuclear sources. PU and break bit. Bit in gauge. Bit grade 1 1 CT G XI WT PR. Pics on "O" drive. Download MWD. Stand tools back in derrick. LD BHA per Baker.;Drain MOBM from BOP stack. Pull wear ring. Set test plug. Fill stack with H2O, R/U BOP test equipment, pump and Iines.;Test BOPE per AOGCC and Hilcorp requirements. All tests performed on 4" and 5" test jts to 250 psi low / 3500 psi high @ 5 min per test, charted. Perform accumulator drawdown test. AOGCC witness of test waived by Jim Regg on 8/29/19 @ 11:33 hrs.;Transported to KGF G&I: 0 bbls Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2353 bbls 8/30/2019 RD BOP test equip and set wear ring. Clean and clear rig floor.;PU BHA #14. PU Auto track and MWD, Plug in and upload tool, MU new Reed PDC bit, Load nukes, and RIH to 1560'. Test tools.;RIH filling pipe every 3000' to 12,551'. Took 5k in a couple spots but went right through. No real set down issues.;Fill pipe and log at 100 fph f/ 12,551 to bottom at 12,653'. 253 GPM, 2840 psi, 65 Rpm, 7k TQ. Make connection and get SPR.; Directional drill w/ rotary steerable f/ 12,653' t/ 12,704' at 30 fph. Monitor directional tendency of BHA #14. Stable inclination trend 74.53° - 74.71'. Discuss w/ town. Decision to ease down to 73° per Geo Team. 246 GPM, 2690 psi, 145 RPM, 8k torque, 7-8 WOB, MW 8.9+, vis 144, EMW 10.3.; Directional drill w/ rotary steerable f/ 12,704'V 12,748' at 30 fph. 246 GPM, 2727 psi, 150 RPM, 8k TQ, 7-8 WOB, 8.9+ ppg MW, 115 vis, 10.3 ppg EMW. NBI :74.71° - 74.53° - 73.74°. 20.5' Right & 33' High of Iine.;Conference call w/ Geo Team. Decision to geosteer down to 73° Inc and hold 73° inc till middle of sand zone is called. Then turn up to 74° - 74.5°. Window --50' Left or Right of line.; Directional drill w/ rotary steerable f/ 12,748't/ 12,842' at 30 fph. 225K PU, 190K SO, 205K RT, 246 GPM, 2650 psi, 143 RPM, 8k TQ, 8k WOB, 8.9+ ppg MW, 115 vis, 10.4 ppg EMW. NBI :73.74°.- 73.04. 28.7' Right & 29.9' High of line. Took 5 surveys due to solar interference.; Directional drill w/ rotary steerable N 12,842' t/ 12,936' at 18- 41 fph. 225K PU, 190K SO, 205K RT, 241 GPM, 2628 psi, 143 RPM, 8.5k TQ, 8k WOB, 8.9+ ppg MW, 111 vis, 10.4 ppg EMW. NBI :73.12. 33' Right & 25' High of line as per wp 19. Take SPRs.; Directional drill w/ rotary steerable f/ 12,936' U 12,940' @ 30 fph . 225K PU, 190K SO, 205K RT, 241 GPM, 2650 psi, 143 RPM, 8.5k TQ, 8k WOB, 8.9+ ppg MW, 111 vis, 10.4 ppg EMW. NBI :73.12.; Transported to KGF G&1: 0 bbls Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2353 bbls 8/31/2019 Directional drill 6 1/8" 34 fph avg . 225K PU, 190K SO, 205K RT, 240 GPM, 2575 psi, 144 to 150 RPM, 8.5k TQ OB, 8.9 ppg MW, 108 vis, 10.3 ppg EMW. Keeping Inc at 73'.: Directional drill 6 1/8" hole w/ rotary steerable f/ 13,140' t/ 13,306' @ 28 fph avg . 35K PU, 190K SO, 210K RT, 244 GPM, 2650 psi, 150 RPM, 8.7k TQ, 8 to 10k WOB, 8.8+ ppg MW, 102 vis, 10.3 ppg EMW.; Directional drill 6 1/8" hole w/ rotary steerable fl 13.306't/ 13,395'@ 15 fph avg .235K PU, 190K SO, 210K RT, 245-264 GPM, 2650 psi, 150 RPM, 7 - 11 k TQ, 5 to 10k WOB, 8.8+ ppg MW, 102 vis, 10.5 ppg EMW. Pumped 25 bbl hi vis 10 ppb weighted lube sweep. Cuttings increase 10% on sweep return.;Work through stick slip f/ 13,369' t/ 13,386'. Adjust drilling parameters. Pump 25 bbl hi vis weighted lube pill. Torque cleaned up w/ sweep @ bit.; Directional drill 6 1/8" hole w/ rotary steerable f/ 13,395' t/ 13436' @ 7 fph avg . 235K PU, 190K SO, 210K RT, 245-264 GPM, 2650 psi, 150 RPM, 8.7k TQ, 8 to 10k WOB, 8.8+ ppg MW, 102 vis, 10.5 ppg EMW. Backream full stand. Take SPRs. 23' right & 4.8' high of Iine.;Transported to KGF G&I: 0 bbls Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2353 bbls 9/1/2019 Directional drill 6 1/8" hole f/ 13,436't/ 13,442'. Having issues with slip stick that would stop temporarily when we pump a lube pill. ROP was still staying below 10 fph. Decision made to POH.;Check flow, Pump dry job, and fill trip tank.;POH to 7" shoe. Had 3 spots where we pull 10k over and pulled right through. 12,678', 12600', & 12,548'. Continue to POH to BHA w/ no issues.; Have PJSM and remove nukes, PU and break bit, [Bit grade 1-3-1] Down load MWD tool. Change out SDN tool. MU new Halliburton bit. Up load MWD. Load nukes.;RIH t/ 801'. Shallow pulse test MWD tools. RIH t/ 1270'. Shallow test MWD. No pressure readings from AziTrak tool. POOH. Hold PJSM. Remove nukes. Attempt re-upload AziTrak. Confirmed pressure sensor bad. Swap out AziTrak. Hold PJSM. Reload nukes.;RIH t/ 748'. Shallow pulse test MWD tools / AziTrak @ 260 gpm, 1,137 psi. Good test. Continue RIH t/ 4462'.;RU & circulate active mud system @ 84gpm, 339 psi. Slip & Cut drill line. Adjust brakes on drawworks. Service top drive. RD circulating head. Prep to RIH.;RIH w/ BHA #16 from 4462' t/ 4525' while PU 15 jts 4" DP.;Transported to KGF G&l: 126 bbls Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2479 bbls 9/2/2019 RIH PU 4" DP. Picked up a total of 15 jts. Run 3 stds of HWDP and continue RIH filling pipe every 3000'. To 7" shoe. Lost rig power when they attempted to put another motor on line, Got power right back on and made sure all the equip came back on.;Fill pipe and continue RIH to 13,318' with no issues.;Fill pipe and wash do to 13,413'. Get SPRs, take check shot survey, and wash and ream to 13,440'. Cycle pump to get rotary steerable arms extended.;Ream to bottom slowly and start out drilling slowly to see what the new bit wanted to do as far as direction. Drill 6 1/8 hole from 13,442' to 13,463'. During that time bit built 1 ° in inc. Attempted numerous diff attempts to make bit hold but it continued to build.; Discussed options with town and decided to get everything ready to POH and change bits.;Mix dry job, Fill trip tank, Check flow, Pump dry job.;POH f/ 13,463't/ 7" shoe at 10,860' with no issues.; Continue POH to BHA @ 332'.;Hold PJSM. Make all calls on Rig & GPP. Remove nukes. Plug in, read & reset MWD tools. Swap out 6 1/8" HDBS PDC bit for 6 1/8" Reed PDC bit. C/O float.Make all call. Reload nukes. Prep to RIH.;RIH w/ 6 1/8" Reed bit / AutoTrak BHA #18 f/ 332' t/ 13,021'. Re-adjust brakes on drawworks . Shallow pulse test MWD tools @ 8741 w/ 262 gpm, 1201 psi. Good test Fill pipe per 3000'. Calibrate MWD calipers @ 10,845'. 250 gpm, 2300 psi.;05:40 am. Derrick man injured his hand while RIH w/ drill pipe. Sent to medic.;Transported to KGF G&I: 18 bbls Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2497 bbls 9/3/2019 Continue RIH to 13,412' and fill pipe.;Take a check shot survey. Wash and ream to bottom at 13,463'.;Tag bottom and ease into it slowly to make sure how bit is reacting. Directional drill 6 1/8 hole f/ 13,463't/ 13,504'. 250 GPM, 2910 psi, 135 RPM 7.5k TO, 3 to 6 WOB, Holding back at 16 fph. Holding at 74*.; Directional drill 6 1/8" hole f/ 13,504' t/ 13,600'. 252 GPM, 2915 Psi, Avg ROP 28 fph, 140 RPM, 8.9 k TO. 7.5 WOB, MW 9 ppg, 10.6 ECD.; Directional drill 6 1/8" hole f/ 13,600'V 13,737'. 252 GPM, 2880 Psi, Avg ROP 30 fph, 145 RPM, 8 k TO, 7.6 WOB, MW 9 ppg, 10.6 ECD.; Directional drill 6 118" hole f/ 13,737't/ 13,788'. 240 - 252 GPM, 2750 Psi, Avg ROP 14 fph, 145 RPM, 8k TO, 8k WOB, MW 8.9 ppg, 10.5 ECD. 70. 3° NBI. AT 13,768' MD, began dropping Inc f/ 71 ° to 69° @ 1' per 100' per Geo Team. Pumped 25 bbl hi vis lube pill.; Directional drill 6 1/8" hole f/ 13,788't/ 13,843'. 240 - 252 GPM, 2650 Psi, Avg ROP 6.4 fph, 145 RPM, 8k TO, 8k WOB, MW 8.9 ppg, 10.5 ECD. 70. 05° NBI.;Drilled through shale stringers @ 13,787'- 13,843' w/ stick slip 7k - 11 k TO. Pumped 3 x 25 bbl hi vis lube pills to mitigate SS. Adjusting drilling parameters to improve ROP.;Transported to KGF G&I: 0 bbls Offloaded solids = 0 bbls Cumulative Offloaded Solids = 2497 bbls 9/4/2019 Directional drill 6 1/8" hole f/ 13,843't/ 13,865'. 240 GPM, 2650 Psi, Avg ROP 3.8 fph, 145 RPM, 7.8 TO, 8 WOB, MW 8.9 ppg, 10.5 ECD. (Dropping Inc. f/ 71* to 69° @ V/100' as per Geo team) Mix and pump BaraKlean/Wall-Nut Hull/NXS-Lube sweep & pump @ 13,864' (No noticeable changes in ROP or TQ).; Directional drill 6-1/8" hole f/ 13,865' to 13,872'. Increase drop rate f/ 1 °/100' to 2-3°/100'. 262 GPM, 3000 Psi, Avg ROP 3.8 fph, 145 RPM, 7.5 TO, 5-8 WOB, MW 8.9 ppg, 10.7 ECD. Sweep back on time with no changes in cuttings characteristics or volume.;MWD survey to check LWD tool resistivity readings. Re-log f/ 13,840't/ 13,870'.;Ream to bottom and resume directional drilling 6-1/8" hole f/ 13,872' to 13,882'. Cont. to drop inc. @ 2-3'/100'. 267 GPM, 3100 Psi, Avg ROP 3.5 fph, 160 RPM, 7.5-8.5 TO, .7-8 WOB, MW 8.9 ppg, 10.6 ECD. PUW 230, SOW 185, ROT 205.;Circulate and condition hole while prepping to POOH f/ MWD and bit C/O as per Anchorage Team. Mix and pump dry job. Observe well (static).; POOH w/ BHA #17 f/ 13882't/ 332'. Nicked top face of 5" DP jt w/ elevators @ 11,148'. LD —bad 5" it. Change break on 5" DP. Pickup new it at btm of 5" DP. Perform "Kick while tripping drill" @ 10,324'. TRT 45 sec.;LD & rack back BHA # 17 per Baker DD. Hold PJSM and make all call on GPP & Rig. Remove nuclear sources. PU and break bit. Bit in gauge. Bit pics loaded on "O" drive. Download MWD on deck.;Clean & clear rig floor. Drain MOBM from BOP stack. Pull wear bushing. Set test plug. Fill stack with H2O, Set test pump on rig floor. P/U & R/U BOP test equipment.;Test BOPE per AOGCC and Hilcorp requirements. All tests performed on 4" and 5" test jts to 250 psi low / 3500 psi high @ 5 min per test, charted. Perform accumulator drawdown test. AOGCC witness of test waived by Jim Regg on 9/04/19 @ 16:32 hrs.;Transported to KGF G&I: 90 bbls Offloaded solids = 0 bbis Cumulative Offloaded Solids = 2587 bbls 11 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GP-53RD Spartan 151 50-733-20471-01-00 219-079 7/10/2019 Future Daily Operations: 9/4/19 - Wednesday Directional drill 61/8" hole f/ 13,843't/ 13,865'. 240 GPM, 2650 Psi, Avg ROP 3.8 fph, 145 RPM, 7.8 TCL 8 WOB, MW 8.9 ppg, 10.5 ECD. (Dropping Inc. f/ 71" to 69° @ 1'/100' as per Geo team) Mix and pump BaraKlean/Wall-Nut Hull/NXS-Lube sweep & pump @ 13,864' (No noticeable changes in ROP or TQ). Directional drill 6-1/8" hole f/ 13,865' to 13,872'. Increase drop rate f/ 1°/100' to 2-3°/100'. 262 GPM, 3000 Psi, Avg ROP 3.8 fph, 145 RPM, 7.5 TO, 5-8 WOB, MW 8.9 ppg, 10.7 ECD. Sweep back on time with no changes in cuttings characteristics or volume. MWD survey to check LWD tool resistivity readings. Re-log f/ 13,840't/ 13,870'. Ream to bottom and resume directional drilling 6-1/8" hole f/ 13,872' to 13,882'. Cont. to drop inc. @ 2-3°/100'. 267 GPM, 3100 Psi, Avg ROP 3.5 fph, 160 RPM, 7.5-8.5 T0_7-8 WOB, MW 8.9 ppg, 10.6 ECD. PUW 230, SOW 185, ROT 205. Circulate and condition hole while prepping to POOH f/ MWD and bit C/O as per Anchorage Team. Mix and pump dry job. Observe well (static). POOH w/ BHA #17 f/ 13882't/ 332'. Nicked top face of 5" DP it w/ elevators @ 11,148'. LD —bad 5" it. Change break on 5" DP. Pick up new it at btm of 5" DP. Perform "Kick while tripping drill" @ 10,324'. TRT 45 sec. LD & rack back BHA # 17 per Baker DD. Hold PJSM and make all call on GPP & Rig. Remove nuclear sources. PU and break bit. Bit in gauge. Bit pics loaded on "0" drive. Download MWD on deck. Clean & clear rig floor. Drain MOBM from BOP stack. Pull wear bushing. Set test plug. Fill stack with H2O, Set test pump on rig floor. P/U & R/U BOP test equipment. Test BOPE per AOGCC and Hilcorp requirements. All tests performed on 4" and 5" test its to 250 psi low / 3500 psi high @ 5 min per test, charted. Perform accumulator drawdown test. AOGCC witness of test waived by Jim Regg on 9/04/19 @ 16:32 hrs. 9/5/19 - Thursday Pull 5" test it. and test Blind rams to 250 psi low / 3500 psi high @ 5 min per test, charted. as per AOGCC and Hilcorp requirements. Test Gas alarms and PVT systems. While installing 4" test it. crew inadvertently unseated test plug . Re-seat test plug and fill stack back up with water. Test Annular, UPR w/ 4" pipe, 4" IBOP and 4" safety vlv. to 250 psi low / 3500 psi high @ 5 min per test, charted. as per AOGCC and Hilcorp requirements. Perform accumulator drawdown test. AOGCC witness of test waived by Jim Regg on 9/04/19 @ 16:32 hrs. Rig down test equipment and install wear bushing. Clear and clean rig floor. Pick up BHA # 18. RIH with BHA #18 to 769'. Perform Shallow pulse test MWD tools / OnTrak @ 245 gpm, 961 psi., Good Test. Continue RIM to 13,570' (Filled pipe @ 3541', 6846'& 10,078') Hole condition - good. Wash & ream f/ 13,570' t/ 13,740'. 250 gpm, 2901 psi, 61 rpm. Perform MADD pass f/ 13,740't/ 13,882'. 250 gpm, 2901 psi, 61 rpm. 150 fph. Directional drill 6 1/8" hole w/ Varel 6 1/8" bit / AutoTrak BHA f/ 13,882't/ 13,973'. Avg ROP 20.2 fph. Stage up drilling parameters. 245 GPM, 2850 Psi, 130 -150 RPM, 7-9kTQ 5- 10k WOB, 8.95 ppg MW, 10.5 ECD. (Dropping Inc. f/ 70" to 69° @ 1°/100' as per Geo Team) 68.99° NBI. Directional drill 6 1/8" hole w/ Varel 6 1/8" bit / AutoTrak BHA f/ 13,973't/ 14,009'. Avg ROP 18 fph, 245 GPM, 2750 Psi, 150 RPM, 7-9kTQ, 10k WOB, 8.95 ppg MW, 10.5 ECD. (Raising Inc. f/ 69° to 70° @ 1"/100' as per Geo Team) 70.05° NBI. 9/6/19 - Friday Directional drill 61/8" hole w/ Varel 6 1/8" bit / AutoTrak BHA f/ 14,009't/ 14,130'. Avg ROP 30 fph, 247 GPM, 2725 Psi, 140 RPM, 8-91<TQ, 10k WOB, 8.9 ppg MW, 10.5 ECD, 230 PUW, 190 SOW, 208 ROT. (Raising Inc. f/70° to 71° @ 1°/100' as per Geo Team). Directional drill 6 1/8" hole w/ Varel 6 1/8" bit/ AutoTrak BHA f/ 14,130't/ 14,170'. Avg ROP 33 fph, 250 GPM, 2738 Psi, 140 RPM, 8-9kTQ, 10k WOB, 8.9 ppg MW, 10.5 ECD, 230 PUW, 190 SOW, 208 ROT. (Raising Inc. f/71" targeting inc. of 74.5° @ 2°/100' as per Geo Team). Directional drill 6 1/8" hole w/ Varel 6 1/8" bit / AutoTrak BHA f/ 14,170't/ 14,314'. Avg ROP 30 fph, 250 GPM, 2718 Psi, 140 RPM, 8-9kTQ, 10k WOB, 8.9 ppg MW, 10.5 ECD, 230 PUW, 190 SOW, 208 ROT. (Raising Inc. f/72' targeting inc. of 74.5° @ 2°/100' as per Geo Team). Directional drill 6 1/8" hole w/ Varel 6 1/8" bit / AutoTrak BHA f/ 14,314't/ 14,351'. Avg ROP 33 fph, 252 GPM, 2700 Psi, 150 RPM, 9kTQ, 10k WOB, 9+ ppg MW, 10.5 ECD, 232 PUW, 190 SOW, 210 ROT. (Dropping Inc. @ 3-4°/100' targeting the C7X zone as per Geo Team). Weighted mud up to 9+ ppg for C7X. Directional drill 6 1/8" hole w/ Varel 6 1/8" bit / AutoTrak BHA f/ 14,351't/ 14,405'. Avg ROP 15.4 fph, 252 GPM, 2700 Psi, 150 RPM, 9kTQ 10k WOB, 9+ ppg MW, 10.5 ECD, 232PUW, 190 SOW, 210 ROT. 72.42° NBI. Encountered stick slip w/ downlink to 80% to AutoTrak. Pump 25 bbl hi vis +11b MW Lube pill to mitigate stick slip. Stick slip improved. Troubleshoot due to AutoTrak steering "Tic" magnetic sensor not functioning. Pump lube pill & work pipe. Recycle pumps multiple times. Send diagnostic downlinks. Work through reset checklist. Drill 6 1/8" hole w/ Varel 6 1/8" bit / AutoTrak BHA f/ 14,405't/ 14,407'. Avg ROP 01 fph, 245 GPM, 2670 Psi, 140 RPM, 8k TO, 10k WOB, 9+ ppg MW, 10.6 ECD, 235 PUW, 190 SOW, 210 ROT. 72.25° NBI. Downlink ribs off, then on & continue attempt to reestablish AutoTrak magnetic "tic" sensor. Confirmed AutoTrak magnetic "tic" sensor faulty. Check flow. Static. POOH f/ 14,407' t/ 13,851'. Take check shot survey @ 13,851'. PU to 13,810'. MAD pass logging f/ 13,810't/ 13,377'@ 150 fph. 237 GPM, 2397 PSI. 62 RPM. 7.8k TCL , 9.1 ppg MW, 10.5 ECD. 11Hilcorp Alaska, LLC M1401-1, Ala-ka. LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GP -53RD Spartan 151 50-733-20471-01-00 219-079 7/10/2019 Future 9/7/19 - Saturday Complete Mad pass log f/ 13,377't/ 13,315'@ 150 fph, 237 gpm, 2397 psi, 9.1 ppg MW, 10.5 ECD. Pump dryjob and POOH w/ BHA #18 to push pipe at —5202'. R/U and L/D 9 jt. 4" HWDP push pipe. Continue POOH to top of BHA @ 329.02'. PJSM with all crew members. L/D BHA #18, Remove source and download MWD/LWD tools before laying down. Hang blocks, slip and cut drilling line. RU Weatherford 5" liner running equipment. RU casing fill up line on rig floor. PU liner hanger and break HYD 513 by 4-1/2 BTC crossover off the bottom. LD liner hanger on deck. PU & MU crossover Hyd 513 to HT38 on floor and MU to FOSV. Hold PJSM w/ Weatherford hands & Rig crew. PU & MU 4 1/2" Production Liner shoe track to 130' per program. (Bullnose shoe w/ Baker locked jt, float collar w/ Baker locked jt, landing collar w/ Baker locked jt. Baker lock all shoe track connections.) PU & MU 4-1/2 BTC x Hyd 513 crossover. Prep stabbing board. Run 5" Hydril 513 liner f/ 132't/ 3678' using dog collar on every jt. Install air slips on jt #20. Fill pipe every jt. LD joint # 21 from V door. (Nubbin wouldn't thread in) Lost keeper pin (3/8" x 6") from single jt elevators. RD air slips. RU circulating head & circulating 5" liner while waiting on arrival of Baker completions hand. 9/8/19 - Sunday RD air slips. RU circulating head & circulate through 5" production liner while waiting on weather to clear for Helicopters to fly out Baker hand. Service rig while waiting. Baker hand inspect Baker ZXP liner hanger. P/U liner hanger, M/U plug on bottom of liner 2-3/8" EUE stinger and M/U ZXP liner hanger to top of 5" production liner. L/D Weatherford casing running equipment and clear floor. M/U 1st stand of 4" HT -38 DP to liner hanger, screw into hanger and circulate liner volume. PUW= 100, Liner wt.=60. RIH with 5" production liner on DP t/ 10,855' @ 1+ min/std (Filling each stand with fill up line. (Drifting pipe w/ 2.25" rabbit). Circulate 1.5 x drill pipe & liner volume at 10,855'. 99 GPM, 740 PSI. 210k PU, 170k SO. 10 rpm / 5k TQ, 20 rpm / 5.5k TCI30 rpm / 6.5k TQ. Continue RIH with 5" production liner on DP f/ 10,855't/ 14,353" @ 1+ min/std (Filling each stand with fill up line. (Drifting pipe) MU cement head w/ 2 jts 5" DP. Continue RIH & tag bottom @ 14,407'. PU 2' to 14,405'. 240k PU, 170k SO. 10 rpm / 77k TQ, 20 rpm / 8k TQ, 30 rpm / 9k TQ. Circulate & Condition active mud system in preparation for cement job. 74 GPM, 807 PSI. Reduce low end rheology w/ LVT. RU cement hose on rig floor. Hold PJSM w/ SLB & Rig crew for cement job. PT cement lines f/unit to rig floor w/ 3500 psi (Good test) Pump 30 bbl mud push with rig, SOS pump 70 bbl 15.3# cement @ 4 bpm. Hanger set @ 1150 psi while pumping. Rig um 5 bbl mLw push, Rig pump displace with OBM @ 5 bpm @ 200 psi ICP. Bumped @ 2137 stks, 92 stks early. 2431 psi FCP. 00 'r ,, 9/9/19 - Monday S/0 to 120k & verify hanger set. Staged up to 4200 psi for 5 min to release HRD-E running tool f/ liner. Bleed pressure to check floats. Floats holding. PU to pipe free travel to 200k. Pressure up to 700 psi & PU 22' to remove RS pack off bushing from RS nipple. CIP @ 0613 hr. Pressure dropped quickly w/Pack -off above sealing area. PU & circulate @ 280 GPM to flush cement from drill pipe. Reduced pump rate to circulate —120 bbl of contaminated mud back and into cuttings boxes. Continue circulating until mud balanced in and out of the hole. Loaded out boat while circulating and conditioning mud. Break down 2 jt. 5" DP and Baker cement head in mouse hole and L/D same. Pump dry job and POOH (1st stand out of the hole rotated left as it was pulled, possible trapped torque) to 3567'. POOH laying down 54 jts 4" HT -38 DP. Off load 2-7/8" work string and jewelry from boat. Load out excess 5" casing. POOH laying down 60 jt 4" HT -38 DP. LD HRD-E running tool per Baker. Strap 2 7/8" Tubing & running tools. Last 12 jt 4" had cmt under box end tool jt. which crews wiped off. Clean & clear rig floor. Service top drive. Continue strap 2 7/8" Tubing & running tools. PU & RU 2 7/8" handling equipment. Stage BHA components on rig floor & prep to PU 2 7/8" tubing. PU & MU WTF 4 1/8" junk mill, 5" scraper & XO on first jt 2 7/8" PH -6 tubing to 38'. RIH w/ 2 7/8" PH -6 work string f/ 38't/ 2,565'. .411L Hilcorp Alaska, LLC IIih AIu-ka.LIA Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GP-53RD Spartan 151 50-733-20471-01-00 219-079 7/10/2019 Future 9/10/19 - Tuesday Continue RIH picking up 123 total joints of 2-7/8" PH-6, 7.9# work string w/4-1/8" mill and 5" casing scraper to 3668'. M/U X/0's and 7 casing scraper between 2-7/8" PH-6 and 4" HT-38 DP. Continue RIH w/ 2-7/8" , 4" DP and 5" DP to top of 5" liner @ 10,693'. Did not see TOL on 7" or 5" liners. At 10,703' saw 2-3k bobble and at 10,713 was seeing 1-2k increase going down. PUW 175, SOW 1S0. Pull up above TOL. Circulate and condition mud 245 gpm w/ 3500 psi, rotate and reciprocate pipe @ 20 rpm w/ 4-5 TQ while circulating. Continue to RIH w/ clean out assembly to 13,951'. No excess weight down observed. Wash f/ 13,951' to 14,275' where it started taking weight, 196 gpm w/ 3185 psi. Drill cement f/ 14,275' to 14 277' , 32 rpm, 7-10 TQ, 190 gpm w/ 3032 psi, 2-3 WOB, PUW 210, SOW 200, ROT 190. No progress milling cement past 14,277'. Discussed with Anchorage and decision was made to call this good. Circulate hole clean (With 2 sweeps) 55 spm, 193 gpm, 2978 spp, Rot 20 - 30. SPP stable, no (increase - decrease) entire circulation. PJSM, R/U test equip and chart recorder. Press up to 2400 and bleed air from surface lines. Test 7" csg. 5" liner, 5 X 7" liner lap 2500 psi - 30 min. Test successful, no re-tests. R/D test equip. PJSM, all personnel, discuss displacement procedure and safeguards against incidents and spills. Commence displace wellbore to diesel. Pump 30 bbls Hi Vis sweep with CONDET, pump 45 bbls spacer (4 sks SUSPENTONE, 10.5 ppg, 200 vis). Follow spacer with 487 bbls diesel displacement fluid 4 bpm at 0600 hrs. Hilcorp Alaska, LLC [lilt orpAla4a.1,111 Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GP -53RD Spartan 151 50-733-20471-01-00 219-079 7/10/2019 1 Future Daily Operations: 9/11/19- Wednesday Continue displacing spacer with 533 bbls diesel @ 4 bpm w/ 1250 psi FCP. Flush and clean surface equipment of MOBM. CBU with diesel @ 208 gpm w/ 1725 psi. Wt in and out 6.9 ppg. POOH slowly to 12,723' Had to screw into each stand due to u -tubing of fluids. R/U and circulate to - balance fluid wt. to prevent u -tubing. POH 5" DP 12723 -12600 ft. diesel overflow at tool jt. Circ, attempt balance fluids once more. No success. Lower fluid level on backside to well head and maintain there. Resume POH, stand bk 46 stds 5" DP, stand bk 30 stds 4" DP, L/D 117 jts 4" DP, break 7" scraper and XOs, dress tongs for 2-7/8, begin L/D 2-7/8 tbg (3670 - 3200 ft.) Slow going, wet string. 9/12/19 - Thursday Continue POOH f/ 3200' laying down 2-7/8" work string. Pulling wet. Break off mill, X/0's and 5" scrapper from bottom jt. of 2-7/8" pipe. L/D scrappers, X/O's and 2 -7/8" handling equipment. Mill and bit sub full of scale and debris. Clear and clean floor in preparation N/D BOPE and rig move. Pull master bushings, clean pollution pan, break upper bolts on upper dresser sleeve of bell nipple. M/U pulling tool assembly and pull Wear Bushing. R/D tool assembly. PJSM, N/D BOPE, suspend same. N/D and L/D riser. Nipple up production tree. PJSM, R/U test equip in prep for tree test. Test production tree 2500 psi - 30 min. Slow going, multiple re -tests because of surface leaks. R/D test equip, clear rig floor. 9/13/19 - Friday No Operations to report. 9/14/19 - Saturday No Operations to report. 9/15/19 - Sunday No Operations to report. 9/16/19- Monday No Operations to report. 9/17/19 - Tuesday No Operations to report. Hilcorp Energy Company Composite Report Well Name: GPF GP -53RD Field: Granite Point Unit County/State: , Alaska (LAT/LONG): zvation (RKB): API #: Spud Date: Job Name: 1911671C GP -53RD Completion Contractor AFE #: AFE $: Activity Date ops Summary ..... 11/10/2019 Skid rig over GP -53RD center and safe out hand rails, Remove tree f/ wellehead and stage in cellar,N/U riser and BOP Stack, hammer all connections install bell nipple and center stack,M/U test equipment, Set test plug fill stack and lines with water, Shell test BOP's and check for Ieaks,Test BOP's w/ 5" Test it t/ 250/2500 psi, State Inspector Jim Repq Waived Witness 11/11/2019 Continue test BOP's w/5" Test it U 250/2500 psi, w two F/P one on manual IBOP functioned and re tested (ok) and one on blinds bled air and retest (ok),Swap to 2-7/8" test jt and continue testing unable to get low or high test on annular witness waived by Mr. Jim Regg,Remove water from flow nipple and below annular element. remove nuts from cap of Shaffer annular and remove element (showing signs of chunking out),Install new Blue band (nitrile ) element and new cap seal torque cap bolts,M/U 2 7/8" Test it and test Annular t/ 250/1500/ psi f/ 5 min, change test Jt t/ 5" test it and test annular t/ 250/1500 psi f/ 5 min, perform accumulator test,Make up bell nipple and riser, hook up flow lines and dresser sleeves, hook up trip tank lines, install Wear ring,R/U Pollard Eline to make CBL Run, P/U and M/U tool String, RIH,RIH w/ CBL to 4450' WLM unable to get down, suspect centralizer springs need to be adjusted, POOH Logging 9 5/8", rig crews cleaning and housekeeping after rig move, cleaning rig floor and pits, cleaning sand traps,Change out bow spring centralizers, adjust to 7" Casing ID< RIH w/ CBL on Eline,Total sent to GPP beam tank 1124 bbls of 8.7 ppg OBM last transfer 11-09-19 11/12/2019 _ _b l2ooh logging t/ 90' having concern w/ CBL transient time est ton cmt +-200' P/up back up tool rih w/ E -line w/ CCL and CBL set up for 7" csg set do same spot 4450' RKB WLM, and work tools, w/only 200# over pulls an d continue work tools while waiting on gauge ring was able to work tools U 4600' RKB WLM w/ over pulls @ 700-800#,Pooh recovered soft cmt and scale and metal slivers off tools r/dn a -line discuss options with town 2nd tool still had issue w/ transient time new est top cmt # 3000' ? while crews continue cleaning shakers and pits,Continue cleaning shakers and tanks rig maintenance and house keeping while waiting on boat with drill pipe clout tools, take on diesel in pill pits for short system R/up tbg tongs and 2-7/8" handle equipment,Off load bha and 118 its of 2-718" 7.90#, S-135 ph -6 and strap same, R/U tubing tongs wait on parts f/ tyonek platform,RIH P/U 2 7/8" work string tongs not biting well, change �r l� �J dies and level tongs, working better, continue RIH w/ work string P/U 119 its of PH6 work string t/3624',M/U Smooth OD string mill and jars, P/U 1 stand of DP (1 RIH R/U to circulate, Total sent to GPP beam tank 1124 bbls of 8.7 ppg OBM last transfer 11-09-19 11/13/2019 Continue R/U to circulate X2 btm up the long way wl very minimal cuttings in returns @ 3729' @ 302gpm @ 1500 psi R/up and reverse out an annulus volume @ 282 gpm and 1400 psi w/ very little solids in returns r/dn tiw and pump in sub and reversing Iines,Rih w/ 4" out derrick f/ 3729' U 4407' did not see TOL, Swap to 5" dp wash do (/4407 t/ 4785' w/ 5" dp long way @ 284 gpm @ 1375 psi @ 1200-2000 fph Pup t/ 4757' r/up to reverse circ, Reverse circ @ 4757' @ 207 gpm @ 1500 psi tbg and DP & 7" annular volume with slight amount of cuttings back,r/dn reversing lines & Pooh rack back four std of 5" dp that was used to wash do and resume rih w/ 4" dp out derrick,RiH w/ 4" out derrick f/ 4407' U 7410' M/up std 5" wash do U 7502' P/up t/ 7474' R/up to reverse circ,Reverse circ @ 280 gpm 1310 psi for total 210 bbls out balance reverse circ other 30 bbls still out balance reverse circ other 30 bbls open dp let well balance,P/up rabbit and strap 4" 14# S-135 HT -38 DP total 87 its, RIH w/ 5 stands of 5" DP from derrick t/ 10623,Wash Down f 10623't/ 10645' R/U and reverse Circulate 202 bbls, on bottoms up got back OBM and sand and LCM some fine cement chunks, circulate till shakers cleaned up,Continue RIH f/ work string on 5" DP t/ 14206' wash down 150 gpm 650 psi tag up @14278' set down 10k P/U 6' and R/U to reverse,Reverse Circ 390 bbls 261 gpm 2215 psi, seen same material on bottoms up as prev circulation, POOH w/ 2 7/8" Work String f/ 14274'V 8440",Total sent to GPP beam tank 1124 bbls of 8.7 ppg OBM last transfer 11-09-19 11/ _ '(,9 POOH w/ 2 718" Work String f/ 8440' U 3896',Udn inspect jars , 6" string mill and XO's and rack back 2 std 2-7/8" PH -6 in derrick,Pooh I/dn 2-7/8" work string V total 117 jts brk XO Inspect bit clear and clean floor,R/up-E-line rih w/ CCUGR/CBL t/ top of 5" Liner @ 10681' Log 7" POOH, POOH change springs and G RIH t/ 4301' POOH Logging 9 5/8" Casing, R/D Eline,R/U to run 3 1/8" Tri Point pert guns, PJSM, Seta basket of guns in door w/ crane,RIH w/ 3 1/8" 6 SPF U Super DP TCP U 1008' Total sent to GPP beam tank 1124 bbls of 8.7 ppq OBM last transfer 11-09-19 11/15/2019 Continue RIH p/up w/ 3 118" 6 SPF Super DP TCP f/ / 1008' t/ 3000' total 144 ouns,Crew chg and safety meeting P/up firing head, stop fill and prk assy. p/up (� 3 its 2-7/8" RA sub and two std 2-7/8" out of derrick repair hose on tbg tongs. rih w/ 4" dp did not see top of 7" liner continue rih t/ 6932' Pump do DP and pressure up t/ 900 psi w/ no flow verifying hydrostatic stop fill valve is closed,Cut and slip Drill Iine,Continue w/ 3 1/8" Perf guns on DP f/ 6932' t/ 13,982' didn't /\ see packer going through the 7" liner top, RIH t/ 13985' ran guns through 5" Liner top no issues, saw packer go through the 5" liner top 10k drag down 15k drag up PUW 255k SOW 160k POOH UD single of 5" DP t/ 13950',R/U Pollard Eline RIH w/ GR and CCL to correlate guns on depth, logs showed need to P/U 71' RA tag found @ 10806.5' DP measurement was 10804', Send logs to town for confirmation POOH w/ Eline,Total sent to GPP beam tank 1124 bbls of 8.7 ppq OBM last transfer 11-09-19 11/16/2019 R/D Eline,P/U U 13,874.5' f/ 13,951' P/U 76.5' as per Geo, Set Tri Point Packer 2 turns to the right S/O and set 30k on packer, R/U and Pressure up down back side t/ 2500 psi bleed pressure down t/ 500 psi, hold for 10 min saw confirmation of guns firing at 1500 psi, monitor DP pressure no change, P/U and release packer 500 psi dropped off to zero, R/U to circulate down the drill pipe, pressured up after 82 bbls no flow holding, Pressure, Bleed off pressure, R/U and pump down the back side pressure up to 500 psi and pressure bleeding off vent not opening, Attempt t/ pump down DP still holding pressure, Strip through bag U 13805'Drop mechanical vent valve bar, Attempt to circulate down DP, Circulating at 2 bpm pressure not stable, no returns 1500 psi, pressuring up,Continue strip through bag w/ TDS t/ 13,698' ( prk above Top of 5" liner ),Establish circ and circ BTM X2 through gas buster w/ wide open choke w/ max gas of 55 units do stream of gas buster & 20 bbl increase on first btm up (once started gaining held original DPP until gas was out),Open well mointor static well on trip tank w/ 4 bph loss rate, Pooh and I/dn one single (out balance) circ 30 more bbls do dp to attempt to balance pooh rack back 3 std out balance and getting worse circ other 30 bbls Pooh and rack back other couple std 5" out balance again,Circ btm up @ 13, 366' w/ 5 bbl lost during circ @ 265 gpm @ 751 psi,Pooh racking back 5" dp t/ 9910',Circulate bottoms up 230 gpm 520 psi max gas 16.52 unit,POOH UD 4" DP f/ 9910't/ 3310',R/U Weatherford tongs and tri point equipment„POOH UD Perf Guns f/ 3310't/ 2894',Total sent to GPP beam tank 1124 bbls of 8.7 ppg OBM last transfer 11-09-19 Total Estimated loss to Hole 35 bbls 11/17/2019 POOH UD Perf Guns (/2894' t/ bull nose all shots fired. Halliburton inspecting auger and removing VFD from same,Clear and clean rig floor, Brk /dn safety jt, pull wear ring, r/up test equipment and m/up 2-7/8" test jt and set test plug,Test bopes as per regulations while using left over diesel/lvt and turning interface and spacer back into OBM, power wash centrifuge coffin and bowl. remove clean SLB 1502 iron from rig floor, remove and clean all unneeded subs from rig floor.,R/D Test equipment, blow down lines, drain stack break and UD test Jt,R/U to run completion, R/U Halliburton control lines and equipment, R/U Weatherford power tongs, PJSM,RIH w/ 2 7/8" Completion as per detail, M/U Gauge carrier and gauge test connections, Total sent to GPP beam tank 1124 bbls of 8.7 ppg OBM last transfer 11-09-19 Total loss to Hole today 29 bbls Total loss to Hole 64 bbls 11/18/2019 Continue RIH w/ 2 7/8" Completion as per drillers running tally, installing clamps over every colter and single clamps each side of GLM's and testing guage every 10 jts f/ 433' t/ 3137' (unable to see fluid add 9 bbls to annulus @ 1300' and 5 bbls @ 2000' and using gauge to keep fluid @ +-200' ),Continue RIH w/ 2 7/8" Completion as per drillers running tally, installing clamps over every collar and single clamps each side of GLM's and testing gauge every 10 jts f/ 3137' U 6037' added 5 bbls to annulus @ 4262' and using gauge to keep fluid @ +-200' fluid coming up hole at well head @ 5222') did not see 7" liner top,Continue RIH w/ 2 718" Completion as per drillers running tally, installing clamps over every collar T/6335', started putting clamps on every other jt. from there on out, cont. testing gauge every 10 jts. F/6037'-T/9704', making sure to have fluid 200' or higher on back side, transferred 582 bbls of MOBM to GPP beam tank.,Continue RIH w/ 2 7/8" Completion as per drillers running tally, installing clamps on every other jt., cont. testing gauge every 10 jts. F/9704'- T/10,363', P/U & M/U SSSV & control line and tested 250 Low & 5K High (ok), cont. RIH T/10,650% P/U & M/U hanger, XO, & landing jt., run control line &,- wire through hanger, retested control line & 1-wire (ok), landed out hanger w/ mule shoe on depth @ 10,726' at report time, didn't see 5" liner top w/ mule shoe. P/U-120K S/0-100K,Total sent to GPP beam tank 1706 bbls of 8.7 ppg OBM last transfer 11-18-19 of 582 bbls Total loss to Hole today 44 bbls Total loss to Hole 108 bbls 11/19/2019 R/up slick lino nnri rih w/; rnng and cor in plug to xN niRnlo @ in 983 Riup lines and extra hose on chart recorder to get it in out of weather pressure up do tbg to 3800 psi bump up hold pressure for 30 min to set prk @ 10,644' as per tri-point attempt test do tbg on chart kept bumping up pressure found leak @ MP swap mud pumps and attempt es still ee ing 7=ump up pressure and isolate Mud pump get good test 2745' to 2691 psi in 30 min on chart,R/up to pump do annulus fill an pressure up t/ 2525 to 2420 in 30 min ok blead do and drain lines, Pooh w/ slick line and prong, over pull at SSSV @ 351' bled and work control line pressure still over pulling at SSSV discuss options w/ town Pump and bull head do tbg in cycles f/ 200-2000 psi @ +- 2 bpm in attempt to open flapper 3rd pump cycle was able to pass tools Pooh recover prong. work and exercise control line pressure (not really seeing sleeve travel) rih w/ just weight bar and chk flapper for open,pulling weight @ SSSV again was able to work through w/ two pump cycles pooh. cut excess control line off spool and exercise valve again,Cont. exercising valve up to 6,000 psi w/ no indication of sleeve shifting to open flapper, while P/U & M/U, wireline SB tool, w/ baited GS tool to pull plug, RIH & latched into plug @ 10,683', pulled plug free, POOH w/ plug to SSSV @ 351', made 6 attempts to pull through SSSV while attemptinq,pumping @ 2 bpm and pressuring up to 2000 psi before shutting down the pump w/ no luck, called town to discuss options, decision was made to RIH to XN nipple @ 10,683'and sheer off baited GS tool, and plug, proceeded to RIH, had wireline set down at 4,799' (GLM #2), began working to free,wireline tools, pulled free, ` weight indicated we had left plug in GLM #2.,POOH to SSSV @ 351', made 3 attempts to pull wireline tools through SSSV while pumping w/ no luck, made 11"decision to RIH to 4799' (GLM #2), set down and sheer off SB tool, w./ no indication of weight change, POOH to SSSV, called town, decision was made to R make a couple more attempts to,pull & pump through SSSV before cutting wire, w/ no luck, broke connection below lubricator and cut wire, left 350' of wire in i hole along w/ 1-1/2"-6" RS, 5' stem, 5' stem, 9" KJ, 3' OJ, 7' SJ, along w/ 2" SB, 1-1/2" RS on top of 2-7/8" GS, and a RHCP plug body.,R/D Pollard wireline tools & equip, backed out landing jt., installed BPV, cleared rig floor and started flushing all low pressure surface lines in prep for N/D BOP's.,Total sent to GPP beam tank 1706 bbls of 8.7 ppg OBM last transfer 11-18-19. _,�% Total loss to Hole today 49 bbls Total loss to Hole 157 bbls 11/20/2019 Continue and finish clean flow box and remove both upper and lower flow nipples inspect annular ( shows wear from stripping operations) brk ram door bolts, continue clean pits and flushing lines. Prep loads for boat,Opened rams doors and remove upper VBR rams and inspect the rest, back load boat, trolley stack out of the way, removed DSA. pulled out riser in once section and brk do spools on deck, and cont. cleaning sand trap pits.,lnspected splice made above tubing hanger in control line, determined it was a check valve instead of a regular splice connection, dressed well head & hanger neck, installed API ring, run (- wire & control line through tree, N/U tree„tested tubing hanger void to 250 Low & 5,000 High for 15 min (ok), went to pull BPV, couldn't get valve to break free, tried multiple things before flying out Hilcorp wellhead Rep Clint Chanley for assistance, N/D tree above master valve, shortened T-bar and worked BPV free„N/U tree and tested tree to 250 Low & 5,000 Hiah for 10 min (nk) R/U enerpac to SSSV control line, pressed up control line and seen good indication of sleeve shifting open from 1600-2100 psi, started UD 5” DP out of the derrick vacuuming footballs through each jt. & cleaning threads and installing protectors., Cont. working on house keeping & prepping for rig move, finished LID 5” DP and working on back loading onto boat. 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'� mmryor�mcnm eco �mryrvJr�rnNo V Oi M m "In, M I c O O c [) O O Omi ONi mm Nm O_ (i W M n mmol V'Cch CINN N V �[ni .NmO�O>00_�-N CJ<m m m n m O l O N c"I v m m � m mm lm mm mOIW T.m OOi 000OR— Lease & Well No. County Hilcorp Energy Company CASING & CEMENTING REPORT GPF GP -53RD Date Run 30 -Jul -19 State Alaska Supv. Marvin Rogers CASING RECORD Liner TD 10.924.00 Shoe DeDth: 10.860.00 PBTD: Csg Wt. On Hook: 191 Type Float Collar: No. Hrs to Run: 76 Csg Wt. On Slips: Type of Shoe: Casing Crew: Rig Rotate Csg X Yes No Recip Csg X Yes No Ft. Min. 9.4 PPG Fluid Description: MOBM Liner hanger Info (Make/Model): Baker Liner top Packer?: X Yes No Liner hanger test pressure: 4200 Floats Held Yes No Centralizer Placement: Every joint Shoe @ _ Preflush (Spacer) Type: Lead Slurry Type: Class G Density (ppg) _ Tail Slurry Type Class G CEMENTING REPORT FC @ Top of Liner Density (ppg) Volume pumped (BBLs) Sacks: 403 Yield: 1.75 13.5 Volume pumped (BBLs) 125.8 Mixing / Pumping Rate (bpm): 2.9 Sacks 122 Yield 116 W FDensity (ppg) 15.8 Casing (Or Liner) Detail 25.3 Mixing / Pumping Rate (bpm): 2.9 Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Reamer Shoe 7 29.0 L-80 DWC/C 1.44 10,860.00 10,858.56 159 Casing 7 29.0 L-80 DWC/C 6,499.36 10,858.56 4,359.20 1 Lower Quick Connect 7 29.0 L-80 11.34 4,359.20 4,347.86 1 Upper Quick Connect 7 29.0 L-80 3.08 4,347.86 4,344.78 1 Liner Setting Sleeve 7 Cement returns to surface? 8.66 4,344.78 4,336.12 1 Latch Setting Assy 7 19:47 2.75 4,336.12 4,333.37 1 SLZXP 7*9-5/8" Calc L.__ 32.50 4,333.37 4,300.87 Csg Wt. On Hook: 191 Type Float Collar: No. Hrs to Run: 76 Csg Wt. On Slips: Type of Shoe: Casing Crew: Rig Rotate Csg X Yes No Recip Csg X Yes No Ft. Min. 9.4 PPG Fluid Description: MOBM Liner hanger Info (Make/Model): Baker Liner top Packer?: X Yes No Liner hanger test pressure: 4200 Floats Held Yes No Centralizer Placement: Every joint Shoe @ _ Preflush (Spacer) Type: Lead Slurry Type: Class G Density (ppg) _ Tail Slurry Type Class G CEMENTING REPORT FC @ Top of Liner Density (ppg) Volume pumped (BBLs) Sacks: 403 Yield: 1.75 13.5 Volume pumped (BBLs) 125.8 Mixing / Pumping Rate (bpm): 2.9 Sacks 122 Yield 116 W FDensity (ppg) 15.8 Volume pumped (BBLs) 25.3 Mixing / Pumping Rate (bpm): 2.9 r Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: MOBM Density (ppg) 9.4 Rate (bpm): 6 Volume (actual / calculated): 135/135 FCP (psi): 2600 Pump used for disp: 3 Bump Plug? Yes X No Bump press Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 100 Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: 0 Cement In Place At: 19:47 Date: 7/31/2019 Estimated TOC: 4,592 Method Used To Determine TOC: Calc L.__ www.wellez.net WellEz Information Management LLC ver 04818br Lease & Well No. County TF) 14 407 n0 Hilcorp Energy Company CASING & CEMENTING REPORT GPF GP -53RD State Alaska CASING RECORD Liner *2 Shna np.nth 14 4n5 nn Date Run 9 -Sep -19 Supv. Bob Mize PRTn Csg Wt. On Hook: 240 Csg Wt. On Slips: 60 Rotate Csg Yes X No Fluid Description: MOBM Liner hanger Info (Make/Model): Baker ZXP Liner hanger test pressure: Centralizer Placement: Type Float Collar: Baker Type of Shoe: Baker Recip Csg Yes X No No. Hrs to Run: Casing Crew: Ft. Min. 27.5 9.1 PPG Liner top Packer?: X Yes No Floats Held X Yes No CEMENTING REPORT Casing (Or Liner) Detail Shoe @ 14405 FC @ 14,360.00 Top of Liner 10693 Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Float Shoe 41/2 Sacks: 296 Yield: 1.34 4.5 1 B Baker 2.15 14,405.00 14,402.85 1 Casing 41/2 12.6 L-80 4.51BT HYD 40.63 14,402.85 14,362.22 1 Float Collar 41/2 4.5 IBT Baker 1.56 14,362.22 14,360.66 1 Casing 41/2 12.6 L-80 4.51BT HYD 40.59 14,360.66 14,320.07 1 Landing Collar 41/2 Yes X No Reciprocated? Yes X No % Returns during job 100 4.5 1 B Baker 1.04 14,320.07 14,319.03 1 Casing 41/2 12.6 L-80 4.51BT HYD 41.58 14,319.03 14,277.45 1 X/0 5 Baker 2.73 14,277.45 14,274.72 86 Casing 5 18.0 P -110 -ICY Wedge 513 HYD 3,547.72 14,274.72 10,727.00 1 Liner Hanger Baker 10.52 10,727.00 10,716.48 1 Liner Top Packer Baker 23.13 10,716.48 10,693.35 Csg Wt. On Hook: 240 Csg Wt. On Slips: 60 Rotate Csg Yes X No Fluid Description: MOBM Liner hanger Info (Make/Model): Baker ZXP Liner hanger test pressure: Centralizer Placement: Type Float Collar: Baker Type of Shoe: Baker Recip Csg Yes X No No. Hrs to Run: Casing Crew: Ft. Min. 27.5 9.1 PPG Liner top Packer?: X Yes No Floats Held X Yes No YN_a. ) CEMENTING REPORT Shoe @ 14405 FC @ 14,360.00 Top of Liner 10693 Preflush (Spacer) Type: Mud Push Density (ppg) 12 Volume pumped (BBLs) 30 Lead Slurry Type: ExpandaCEM Sacks: 296 Yield: 1.34 Density (ppg) 15.3 Volume pumped (BBLs) 70 Mixing / Pumping Rate (bpm): 3 Tail Slurry U.1 Type: Sacks: Yield: F Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): N r- Post Flush (Spacer) ir Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: MOBM Density (ppg) 9.1 Rate (bpm): 3 Volume (actual / calculated): 177/185 FCP (psi): 2431 Pump used for disp: Rig Bump Plug? X Yes No Bump press 2150 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 100 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: Cement In Place At: 6:13 Date: 9/9/2019 Estimated TOC: 10,680 Method Used To Determine TOC: Calculated www.wellez.net WellEz Information Management LLC ver_04818br YN_a. ) liilenrn Alm-ka -1,11. DATE 12/12/2019 Debi a Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Resource Evaluation 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 GP 53RD (219-079)& 53RD P61 LWD DATA v GP -53RD ASCII Data CGM PDF Survey Data TIFF GP -53RD 1361 ASCII Data CGM PDF Survey Data TIFF MUDLOG DATA Show Reports Sample Photography Log TIFFS Log PDFs LAS Data Final Well Report DML Data Daily Reports -GP-53 RD_PB1 3 16 93 21 90 79 3 16 93 T TO 93 M.1% DEC 13 1' AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAY to qn7 777 RS1 n DATE 12/12/2019 Deb. a Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Resource Evaluation 333 W. 7th Ave. Ste# 100 Anchorage, AK 99501 DATA TRANSMITTAL GP 53RD (219-079)& 53RD PB1 LWD DATA GP -53RD ASCII Data CGM PDF Survey Data TIFF v GP -53RD 1361 ASCII Data CGM PDF Survey Data TIFF MUDLOG DATA 3 1 6 9 2 Show Reports Sample Photography Log TIFFS Log PDFs LAS Data Final Well Report DML Data Daily Reports GP -53 RD PB1 DEC 13 2019 GC 21 90 %9 3 16 92 Please acknowledge receipt by signinq and returning one coov of this transmittal nr FAX to Qn7 777 Qc;1 n tfilcnrp Alatrku, UA, DATE 12/12/2019 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Resource Evaluation 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 GP 53RD (219-079)& 53RD P61 LWD DATA V GP -53RD ASCII Data CGM PDF Survey Data TIFF GP -53RD PB1 ASCII Data CGM PDF Survey Data TIFF MUDLOG DATA Show Reports Sample Photography Log TIFFS Log PDFs LAS Data Final Well Report DML Data Daily Reports GP -53 RD PB1 a DEC AOGCC 21go79 3 169 1 Please acknowledge receipt by signing and returninq one copy of this transmittal or FAX to 907 777.81310 11 Hilenrp Ahu&ju JJAI DATE 12/12/2019 21 9079 De_ -a Oudean Hilcorp Alaska, LLC 3 1690 GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Resource Evaluation 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 LW D DATA V GP -53RD ASCII Data CGM PDF Survey Data TIFF V GP -53RD PB1 ASCII Data CGM PDF Survey Data TIFF MUDLOG DATA Show Reports Sample Photography Log TIFFS Log PDFs LAS Data Final Well Report DML Data Daily Reports GP -53 RD PB1 RECEIVE' DEC 13 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 DATE 12/12/2019 21 90 ? De. -a Oudean Hilcorp Alaska, LLC 2 1 S S 3 GeoTech 3800 Centerpoint Drive, Suite 1400 J Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Resource Evaluation 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 CBL 11142019 (2954) GP -53RD, CBL„ 11-14-19, Field Log (2954) GP -53rd, CBL, 11-14-19, Field Log RECEIVE® DEC 13 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg��` DATE: P. I. Supervisor j l FROM: Lou Laubenstein SUBJECT: Petroleum Inspector 12/10/19 No Flow Test Granite Point 35RD Hilcorp Alaska PTD 2190790 12/9/19: 1 arrived on the Granite Point Platform to witness a No Flow Test on well GP- 35RD. Sandy Reynolds (Hilcorp) was on location and was performing the day's testing. Test equipment was rigged up and \the well bled down and ready to test when I arrived on location. The digital gauge and flow meter both had current calibration and there is no injection support for this well. The test went without any issue or concerns, everything was in order and had passing results. The following table shows test details: Time Pressures' (psi) Flow Rate Gas — scf/hr Liquid — al/hr Remarks 10:35 0/490/0 Well was SI 11:05 0/490/0 30 -minute pressure readings 11:35 0/490/0 800 0 50 seconds to 0 scf/hr 12:05 0/490/0 30 -minute pressure readings 12:35 0/490/0 850 0 63 seconds to 0 scf/hr 13:05 0/490/0 30 -minute readings 13:35 0/490/0 850 0 64 seconds to 0 scf/hr ' Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr Attachments: Photos (3) 2019-1209—No-Flow GranitePt-53RD ll.docx Pagel of 3 c C N c� J J L O U N Q U) C U U CD O Q >1 CD .MT-- cno O N O t N M 0 N (1000 _0c ■ U aS N N N ■i■1 i■ C C_ c Ql O UN ly ZS -0C a.N E m a� c3� > °c O y_ '� O O� � f L.. C.) ' vi Z W w ;� co V� 4)U C U p 0 y O O O E U "O W V v c w' cn E N a c6 E w 07,0 Cm mu LOT 0 m �a x = d V C N O .f 0 ay a m o < Pa ov n vo > Ecc acm s`m 0 o y 4^rno 2"ic�av mL vc cZri IS oCc wcp E m E€ o m 3 5 L o± 9' Nv c�o3d£ocoov€=.y€Qt3c o'o o`~' y_g i -; s+a ate°=N oocu�mEv... ..n � me vNE c_�a' 10 rniQ `y w�.y E E 2`� c °' c� �m ��. Vic°', 2 �.c��im ct wm.c m'a o✓.Q uz. c� 3c �€ o,m;a �F"'�wrnE.�°em Nm _wa fur c c y m�>oEoEc�= on as v oD myM n s N m m °o s f7 £ n _o _� w m v n N E o ao G E N s O `° L V E 444.1111 pE.��Y�'rnoau.�cow'�cwcc EF�m'o aa s.5 in nY"i.�g�c�m>rnc �, G aim n 8 U c E n ti ,�A' S 3 S! w E K n D i E c •� r'o i Q\ O N O N STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 E CE= i V E. ..._ DEC - 6 2019 AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Op ations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Chang Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Install SSC-SSSV 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service 219-079 3. Address: 3800 Centerpoint Drive, Suite 1400 6. PI q�ber: Anchorage, AK 99503 04471-01-00 7. If perforating: 8. Welland Number: What Regulation or Conservation Order governs well spacing in this pool? NIA � / Will planned perforations require a spacing exception? Yes ❑ No ❑� �V' Granite, t St 53RD 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0018761 Granite Point Field / Middle Kenai Oil Pool 11. PRESENT WELL CONDITION SUMMARY / Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 14,407 10,437 14,277 10,401 2 s N/A N/A Casing Length Size MD D Burst Collapse Structural 229' 33" 229' 229' Conductor 294' 26' 294' 294' Surface 1,031' 13-3/8" 1,031' j 1,031' 3,450 psi 1,950 psi Production 4,551' 9-5/8" 4,551' 4,099' 6,870 psi 4,760 psi Production 6,559' 7" 10,860' 9,449' 8,160 psi 7,020 psi Liner 3,724' 5" 14,405' 10,436' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): / 10,880 - 13,880 9,459 - 10,272 2-7/8" 6.5 / L-80 10,725 Packers and SSSV Type: I4%.and SSSV MD (ft) and TVD (ft): MFH Hydraulic Packer & NE TRSVrj44 (MD) 9,335 (TVD) & 351 (MD) 351 (TVD) 12. Attachments: Proposal Summary Q Wellbore schematic ell Class after proposed work: Detailed Operations Program E]BOP Sketch ❑ ploratory El Stratigraphic 1:1 Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: 12/10/2019 OIL WINJ WDSPL Commencing Operations: ❑ ❑ ❑ Suspended ❑ 16. Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the pro ur pproved herein will not be deviated from without prior written approval. Authorized Name: Stan W. Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlowe hilcor .com q Contact Phone: (907) 283-1329 12- 1 I Authorized Signature: Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so at a representative may witness Sundry Number: C�3 19 -55_CQ Plug Integrity ❑ BOP Te ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 3BDIAS L&DEC 1 12019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required?/ Yes ❑ No ❑ Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: O �(� GINA Submit Form and o �p o Approved application is valid for 12 months from the date of approval. Attachments in Duplicate 'n Hileurp Alaska, LLC Well Work Prognosis Well Name: Granite Point 53RD API Number: 50-733-20471-01-00 Current Status: Gas Lifted Producer Leg: Leg 4 Estimated Start Date: December 10, 2019 Rig: N/A Reg. Approval Req'd? 403 Date Reg. Approval Received: Regulatory Contact: Juanita Lovett Permit to Drill Number: 219-079 First Call Engineer: Dan Marlowe Office: 907-283-1329 Cell: 907-398-9904 Second Call Engineer: Stan Golis Office: 907-777-8356 Current Bottom Hole Pressure: 2,943 psi @ 9,459' TVD 0.315 psi/ft (6.05 ppg) based on downhole gauge Maximum Expected BHP: 2,943 psi @ 9,459' TVD 0.315 psi/ft (6.05 ppg) based on downhole gauge Maximum Potential Surface Pressure: 2,029 psi Using 0.1 psi/ft gradient per 20 AAC 25.280(b)(4) Brief Well Summary The GP -53rd was completed and brought online November 22nd, 2019 but the SSSV appears to have been damaged during completion. An in-house test indicates the valve is operational but fails to fully seal. Hilcorp will shut-in the well December 6th to see if it will pass a no -flow test. If unable to meet no -flow criteria, this project will install a subsurface controlled subsurface safety valve (SSC-SSSV) in accordance with Guidance Bulletin 10-004. SSC-SSSV Suitability Evaluation: Well historic parameters Gross Gas —1 mmcfd Gross Fluid 1,100 BFPD FTP 70 psig Temp 72F This safety valve will be setup with a trip pressure of —100 psig. We will hold backpressure on the well with the production choke to maintain a normal FTP of —125 psig. To test the valve we will lower the FTP and trip the SC- SSSV. To reset the valve the control valve will be closed and well pressured up to above the trip pressure then gradually reopened to the normal operating range. Procedure: 1. MIRU Slick -line, PT lubricator to 2,500 psi Hi 250 Low. RIH and set the subsurface controlled subsurface safety valve. 3. Turn well over to production. 4. Conduct a SVS test within 5 days. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. McMurry-Macco PB Subsurface Safety valve cut sheet. (Alternate Halliburton K -valve may also be used depending on availability) Granite Point Field SCHEMATIC Well: GP -53RD Last Completed: 11/19/2019 PTD: 219-079 Hilcoru Alaska, LLC API: 50-733-20471-01 ORKB to MLLW 156.22'; ORKB to Mudline = 231.22' PBTD:14,277 TD: 14,407' CASING DETAIL Size Wt Grade Conn ID Top Btm 33" Outside Driven Conductor Welded 3.500 Surf 229' 26" Inside Driven Conductor Welded 2.313" Surf 294' 13-3/8" 68 K-55 BTC 12.415" Surf 1,031' 47 L-80 BTC 8.681" Surf 73' 9-5/8' 53.5 P-110 BTC 8.535" 73 4,551' 7" 29 L-80 DWC/C 6.184" 4,301' 10,860' 5" 18 P-110 ICY Hydril513 4.194" 10,681' 14,405' TUBING DETAIL 2-7/8" 6.5 L-80 8 rnd EUE 1 2.441" 1 Surface 1 10,725' JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 9,459' 10,272' 3,000' 11/16/19 Open 55.47' 55.47' 3.500 11.000 Hanger—Cactus-en-ccl w/ 3.5" 811 lift and suspension threads w/ CIW Type "H" BPV profile w/ 3 control line ports, 17-4ph SS material 1 351' 351' 2.313" 4.650" SSSV— HaIIiburtonNETRSV 2,497' 2,481' 2.441" 4.750" GLM #1— Priority PSPO-1M w/R-1 valve & BK -2 latch 4,799' 4,286' 2.441" 4.750" GLM #2—Priority PSPO-11VI w/R-1 valve & BK -2 latch 6,258' 5,547' 2.441" 4.750" GLM #3 — Priority PSPO-1M w/R-1 valve & BK -2 latch 7,216' 6,400' 2.441" 4.750" GLM #4 — Priority PSPO-1M w/R-1 valve & BK -2 latch 2 7,831' 6,948' 2.441" 4.750" 1 GLM #5 — Priority PSPO-1M w/R-1 valve & BK -2 latch 8,446' 7,496' 2.441" 4.750" GLM #6 — Priority PSPO-11V! w/R-1 valve & BK -2 latch 9,124' 8,100' 2.441" 4.750" GLM #7 — Priority PSPO-1M w/R-1 valve & BK -2 latch 9,801' 8,702' 2.441" 4.750" GLM #8 — Priority PSPO-11VI w/R-1 valve & BK -2 latch 10,572' 9,293' 2.441" 4.750" GLM #9 — Priority PSPO-11VI w/R-1 orifice & BK -2 latch 3 10,625' 9,324' 2.421" 4.966" Halliburton ROC Gauge Mandrel w/0.25" TEC wire 4 10,644' 9,335' 2.416" 5.968" Packer— Map Oil Tools - MFH Hydraulic 5 10,684' 9,358' 2.205" 3.668" XN-Nipple 6 10,725' 9,380' 2.370" 3.230" Indexing WLEG PERFORATION DETAIL ne Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status -5 10,880' 13,880' 9,459' 10,272' 3,000' 11/16/19 Open Updated By: AL 12/02/19 Granite Point Field PROPOSED well: GP -53RD Last Completed: 11/19/2019 PTD: 219-079 il;�corn n�aska, [ 1 C API: 50-733-20471-01 ORKB to MLLW 156.22'; ORKB to Medline = 231.22' PBTD: 14,277 TD: 14,407' CASING DETAIL Size Wt Grade Conn ID Top Btm 33" Outside Driven Conductor Welded 3.500 Surf 229' 26" Inside Driven Conductor Welded Surf 294' 13-3/8" 68 K-55 BTC 12.415" Surf 1,031' 47 L-80 BTC 8.681" Surf 73' 9-5/8" 53.5 P-110 BTC 8.535" 73' 4,551' 7" 29 L-80 DWC/C 6.184" 4,301' 10,860' 5" 18 P-110 ICY Hydril513 4.194" 10,681' 14,405' TUBING DETAIL 2-7/8" 6.5 L-80 8 rnd EUE 1 2.441" 1 Surface 1 10,725' JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 55.47' 55.47' 3.500 11.000 Hanger — Cactus-en-ccl w/3.5" 8RD liftand suspension threads w/ CIW Type "H" BPV profile w/ 3 control line ports, 17-4ph SS material 1 ±346' ±346' SSC-SSSV 2 351' 351' 2.313" 4.650" SSSV— Halliburton NE TRSV 2,497' 2,481' 2.441" 4.750" GLM #1—Priority PSPO-1M w/R-1 valve & BKUlatch 4,799' 4,286' 2.441" 4.750" GLM #2 — Priority PSPO-1M w/R-1 valve & BK 6,258' 5,547' 2.441" 4.750" GLM #3 — Priority PSPO-1M w/R-1 valve & BK7,216' 6,400' 2.441" 4.750" GLM #4 — Priority PSPO-1M w/R-1 valve & BK3 7,831' 6,948' 2.441" 4.750" GLM #5 — Priority PSPO-1M w/R-1 valve & BK 8,446' 7,496' 2.441" 4.750" GLM #6 — Priority PSPO-1M w/R-1 valve & BK -2 latch 9,124' 8,100' 2.441" 4.750" GLM #7— Priority PSPO-1M w/R-1 valve & BK -2 latch 9,801' 8,702' 2.441" 4.750" GLM #8—Priority PSPO-1M w/R-1 valve & BK -2 latch 10,572' 9,293' 2.441" 4.750" 1 GLM #9—Priority PSPO-1M w/R-1 orifice & BK -2 latch 4 10,625' 1 9,324' 2.421" 4.966" Halliburton ROC Gauge Mandrel w/ 0.25" TEC wire 5 10,644' 9,335' 2.416" 5.968" Packer— Map Oil Tools - MFH Hydraulic 6 10,684' 9,358' 2.205" 3.668" XN-Nipple 7 10,725' 9,380' 2.370" 3.230" Indexing WLEG PERFORATION DETAIL ne Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status -5 10,880' 13,880' 9,459' 10,272' 3,000' 11/16/19 Open Updated By:JLL 12/05/19 McMiulrry-Macco McMurry-Masco PB Subsurface Safety Valve Advantages • Large flow area. ® No flow through moving parts of safety valve. • No hydraulic seals. Closing force is transmitted through liquid -filled bellows. • Predictable and repeatable valve performance. o Snap -action closure. Valve disc does not throttle in flow stream. • Suitable for gas lift wells. e Easily field tested. With use of a convenient test stand, the PB safety valve can be tested and reset. • No depth limitation. The PB is suitable for a wide variety of special applications. The PB is wireline retrievable and can be sus- pended and packed off in any standard landing nipple with the appropriate locking device. The PB can also be suspended and packed off in the tubing string with a collar lock mandrel. The PB is available in a 50 to 3,000 psi range (PB) and a 100 to 10,000 psi range (HP -PB). Features a Subsurface control. o Wireline retrievability. G 50 to 10,000 psi operating range. Bellows protection unit. o Positive closing pressure. Hard and soft disc -seat closing seal. McMurry-Masco subsurface safety valves are certified to API 14A, ASME SPPE-1 specifications and are available for class I, or 3S service. 72 ///��"---VITON ELASTOMERS All elastomers are j made of Viton. RUBBER VITON SEAT DISC 17-4 ph stainless steel 17-4 ph stainless steel WIPER SEAL LOCK SPRING LOCKING BALLS LOCKING SLEEVE Hold disc In open position. Holds locking balls In lock groove. CLOSING SPRING Provides closing force. RECOCKING SPRING \ TRIP RING Pushes locking sleeve up to release disc. PRESSURE SENSING PORT Two fine mesh screens filter trash and sand. MAIN BELLOWS (3 -PI y Monel) Retains fluid and transmits closing force to trip ring and closing spring. BELLOWS PROTECTION UNIT Traps fluid in bellows to protect against overextension. LOWER BELLOWS (3 -Ply Monel) Retains fluid and transmits dome charge closing force to main bellows. DOME Contains nitrogen charge .TAIL PLUG Backs up dome check valve. LDOME CAP DOME CHECK VALVE Rotains nitrogen dome charge. For high pressure valve (HP -PB), this is replaced with heavy-duty ball check assembly. Schwartz, Guy L (CED) From: Schwartz, Guy L (CED) Sent: Tuesday, December 10, 2019 8:13 AM To: Dan Marlowe Subject: RE: GP -53rd PTD 219-079 Sundry withdrawal Dan, AOGCC will withdrawn sundry application ( No. 319-556) as requested. As we discussed Hilcorp was going to keep the ScSSV functional in the event it is activated even though it had a small leak and wouldn't pass the pressure test (it would still provide substantial protection in the case of line break at surface). Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guy.schwa rtz@alaska.aov). From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Monday, December 9, 2019 3:52 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Stan Golis <sgolis@hilcorp.com> Subject: GP -53rd PTD 219-079 Sundry withdrawal Guy We filed the attached Sundry on Friday and discussed it briefly. Over the weekend we bled down the well and today conducted a successful no -flow test with Mr. Lou Lou Laubenstein witnessing. At this time, we request withdrawal of the sundry. Please advise what the assigned number is for our files. Thanks Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Fax 907-283-1315 Email DMarlowe(cD_hilcorp.com Hilcoq A Company Built on Energy Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Hilenrp Alsvdka, I.M. Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE 9/26/2019 To: Alaska Oil & Gas Conservation Commission Meredith Guhl, Petroleum Geology Assistant 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 Transmitted herewith are cuttings WELL BOX # SAMPLE INTERVAL GP 53RD 1 OF 5 9000'-10,500' GP 53RD 2 OF 5 10,500'-11,560' GP 53RD 3 OF 5 11,560'-12,810' GP 53RD 4 OF 5 12,810'-14,407 GP 53RD PB1 `Z`j 5 OF 5 1 11,560',11,913' Please include current contact information if different from above. lgZ-3 )T2q RECEIVED SEP 3 0 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received Date: \ ( 2 _ \-} / \ o .g § ) E b \ e§- m m o= o - = E 7 \ $ q \ 5 2 \ \ \ G p o= 2 s}§_= E a- w / \ / / \ m \ a ± > 0 2 Z3 r - b m® E& @_ c.g e n = o _£ 2 ± \ \ % ° e °'- 7 � = G / 0) :3 � } � : o k a 2 5/ t/\ f b= a o 4 o E E m�< Fn co) O± a£ 2 O 0 � 0 k < � w �e 0 I 0 .4RNOI \\ 00 m E / � § 17=2 % \ ƒ $ > E > e k a e O n » > Q� ± @ I \ \ Cl) 2 c [ E \ o \ $ \ / 2 E 5 ± \ 0 GG $ ƒ_ , E \ e 2 » 2 ± e\\mE0$c- \ e r-\ 7ƒ//ƒ/\/ƒ/ 07- .§ 0 22E \m _7\ �\ o o � O <b ƒ > \ $E 2 Q Ew o q = 2\� Co 2I \ § 0 \ § ZO kE\ ®g /y E \ 0 .7 o b (n 0 O 0� O I £ « ` � � \ \ \ Q U 6» O \ 2 k � 0 2 % \ E % e F- t t o 9 3 0 iL U) � \ ƒ C) � 02 /� \ \ 0\ / E O o 2 _ \-} / \ o .g § ) E b \ e§- m m o= o - = E 7 \ $ q \ 5 2 \ \ \ G p o= 2 s}§_= E a- w / \ / / \ m \ a ± > 0 2 Z3 r - b m® E& @_ c.g e n = o _£ 2 ± \ \ % ° e °'- 7 � = G / 0) :3 � } � : o k a 2 5/ t/\ f b= a o 4 o E E m�< Fn co) O± a£ 2 O 0 � 0 k < � w �e 0 I 0 .4RNOI \\ 00 m E / � § 17=2 % \ ƒ $ > E > e k a e O n » > Q� ± @ I \m U- 3 I_0 < § %i \ \\ / \ b = 5 e \ /m § \\\ [ ¢\ 2 E a- E E c 2.§ \ > f C/5 k c cn n c< o o e $ f \ f .g 9 > § \ 7 2 \ _ ° 7 \ ° o / e \\\�G\U)L) T-ƒ // m _ 0 w 2 « w 0 V) E 3 V) E E \ / g m R Q LU � � 0 0 cn w � _ � U- I U) e z w � � 0 0 00 co / \ 2 c [ \ o \ $ \ / 3 C / ]ƒ© E 5 ± GG $ ƒ_ \ f 2 e n gcr�oU) e 2 » ± e\\mE0$c- 7ƒ//ƒ/\/ƒ/ \m U- 3 I_0 < § %i \ \\ / \ b = 5 e \ /m § \\\ [ ¢\ 2 E a- E E c 2.§ \ > f C/5 k c cn n c< o o e $ f \ f .g 9 > § \ 7 2 \ _ ° 7 \ ° o / e \\\�G\U)L) T-ƒ // m _ 0 w 2 « w 0 V) E 3 V) E E \ / g m R Q LU � � 0 0 cn w � _ � U- I U) e z w � � 0 0 00 co / THE STATE 'ALASKA GOVERNOR MIKE DUNLEAVY Stan Golis Operations Manager Hilcorp Alaska, LLC. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Granite Point Field, Middle Kenai Oil Pool, Granite PT ST 53RD Permit to Drill Number: 219-079 Sundry Number: 319-336 Dear Mr. Golis: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, nx—'O�— ielowski Commissioner DATED this '%6 day of July, 2019. RBDMS1uJuL 2 6 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 R � Er—^� k ��k�� t� JUL 7 0 -1S 1 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate Q Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: G/L Completion Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 219-079 ' 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20471-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C076A Will planned perforations require a spacing exception? Yes ❑ No Q Granite Pt St 53RD 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0018761 I Granite Point Field / Middle Kenai Oil Pool ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): ±15,684 (proposed) ±11,182 (proposed) ±15,531 (proposed) ±10,811 2,001 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural 229' 33" 229' 229' Conductor 294' 26' 294' 294' Surface 1,031' 13-3/8" 1,031' 1,031' 3,450 psi 1,950 psi Production 4,551' 9-5/8" 4,551' 4,099' 6,870 psi 4,760 psi Production ±6,541 (proposed) 7" ±10,891 (proposed) ±9,478 (proposed) 8,160 psi 7,020 psi Liner ±5,234 (proposed) 5" ±15,934 (proposed) ±11,128 (proposed) Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): N/A N/A N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A N/A 12. Attachments: Proposal Summary 0 Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/15/2019 OIL Q WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan W. Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlOWe hIICOr .COm + Contact Phone: (907) 283-1329 y 5k, L to Authorized Signature: w Date: ( COMMISSION USE ONLY Conditions of approval: Notify Commissions that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test 19 Mechanical Integrity Test ❑ (Location Clearance/ ❑ Other: t � '� TEg�'C'O z.��0� `� /4N/✓v `ar Ta 1-50.0 S / Post Initial Injection MIT Req'd? Yes ❑ No ❑ 7413DIMS� 2 6 2019 Spacing Exception Required? Yes No V Subsequent Form Required: ��� El 1 APPROVED BY /6 `7� Approved by: — COMMISSIONER THE COMMISSION Date: �5 J-Revised RRII II J�A`�� a-VL,4 dr"it Form and Form 4/2017 Approved application i0IRi bdlGo6tis�kAh�ate of approval. Attachments in Duplicate Well Work Prognosis ffileorp Alaska. LLC Well Name: Granite PT ST 53rd (GP -53rd) API Number: 50-733-20471-01 Current Status: New Sidetrack of SI Injector Leg: Leg #4 Estimated Start Date: August 15, 2019 Rig: Spartan 151 or HAK 404 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 219-079 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Monty Myers (907) 777-8431 (0) (907) 538-1168 (M) Current Bottom Hole Pressure: 2,943 psi @ 9,423' TVD 0.312 lbs/ft (6.01 ppg) based on offset producers Maximum Expected BHP: 2,943 psi @ 9,423' TVD 0.312 lbs/ft (6.01 ppg) based on offset producers Maximum Potential Surface Pressure: 2,001 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary GP -53rd is a C-5 and C -7x producer that will be completed with Gas Lift. This new well was side tracked from the current GP -53 a shut-in injector. This workover will run completion and perforate the new well. Timing and completion rig will be based on timeliness of getting well drilled, if we are significantly ahead of schedule we will complete with Spartan 151, if we are running tight on schedule we will complete in November with the HAK-404 Last Casing Test: Casing and liner tested to 2,500 psi under PTD 219-079 Procedure:-� Dp` 1. ***Take over ope ations frXthe Drilling Sidetrack Program *** 2. Test BOP'S every1 ys continued from last test date from PTD 219-079. Test to 250psi low/2,500psi hi / 1,500 psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 3. Completion fluid will be diesel. BOP's will be closed as needed to circulate the well. 4. ** If not already completed under PTD 219-079, Rig up E -Line and run gamma/ccl/cbl. 5. PU and RIH with TCP guns, Correlate on depth and perforate. 6. Circulate bottoms up and assure well is static, release underbalance packer, circulate again and ensure well is static. POOH t 7. PU and RIH with Gas Lift completion. �� 5 L 8. Set Packer / Pressure test completion: �� = ZOD • • • Pressure up and set packer ,� • Test tubing again plug in XN nipple to 2500# and chart for 30 minutes. • Test IA to 2,0 psi and chart for 30 minutes (This will pressure up tubing also). • Pull prong and plug in XN-Nipple. 9. Set BPV. NU tree, test same. 10. Turn over to production. 11. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Proposed 4. BOP Drawing—Spartan 151 5. Fluid Flow Diagrams —Spartan 151 6. BOP Drawing — HAK 404 7. Fluid Flow Diagrams—Spartan 151 8. RWO Sundry Revision Change Form RKB to MLLW 114.75; RKB to Mudline =189.75' CASING DETAIL Size Granite Point Field PROPOSED Well: GP 53 ID Last Completed: 08/29/1997 SCHEMATIC PTD: 196-014 IHilcorp Alaska, LLC API: 50-733-20471-00 RKB to MLLW 114.75; RKB to Mudline =189.75' CASING DETAIL Size Wt Grade Conn ID Top Btm 33" Outside Driven Conductor Welded 14,500' 10,479' 47' 229' 26" Inside Driven Conductor Welded 14,590' 47' 294' 13-3/8" 68 K-55 BTC 12.415" 47' 1,031' 11,020' 47 L-80 BTC 8.681" 46' 73' 9 5/8 53.5 P-110 BTC 8.535" 73' 4,551' 29 P-110 TKC-BTC 6.184" 45' 6,989' 7„ 29 L-80 TKC-BTC 6.184" 6,989' 13,323' 5" 15 L-80 SC-TKC-BTC 4.408" 12,909' 16,634' TUBING DETAIL JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item Date Status C-5 13,339' 14,500' 10,479' 10,730' 1,161' 08/15/97 Isolated C-5 14,590' 14,595' 10,743' 10,744' 5' 08/14/97 Squeezed C-5 15,250' 16,400' 10,817' 11,020' 1,650' 08/04/97 Squeezed 4 12,906' 10,263' 3.880" 3.880" 3.880" 4.770" 5.900" 6.000" HES Seal Bore Extension Bottom Sub Halliburton VLT Versatrieve Packer 5 14,530' 10,735' EZSV Cement Retainer 6 15,112' 10,801' EZSV Cement Retainer PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status C-5 13,339' 14,500' 10,479' 10,730' 1,161' 08/15/97 Isolated C-5 14,590' 14,595' 10,743' 10,744' 5' 08/14/97 Squeezed C-5 15,250' 16,400' 10,817' 11,020' 1,650' 08/04/97 Squeezed PBTD: 14,530' TD: 16,657' Updated By: MJQ 02/07/19 Granite Point Field PROPOSED Well: GP -53RD Last Completed: Future PTD: 219-079 Hilcorp Alaska, LLC API: 50-733-20471-01 RKB to MLLW 156.22; RKB to Mudline = 231.22' CASING DETAIL Size Wt Grade Conn ID Top Btm 33" Outside Driven Conductor Welded Future Proposed 47' 229' 26" Inside Driven Conductor Welded 47' 294' 13-3/8" 68 K-55 BTC 12.415" 47' 1,031' ±5,225 47 L-80 BTC 8.681" 46' 73' 9-5/8- 53.5 P-110 BTC 8.535" 73' 4,551' 7" 29 L-80 DWC/C 6.184" ±4,350' ±10,891' 5" 18 P-110 IC Hydril513 4.194" ±10,700' ±15,934' TUBING DETAIL 2-7/8" 6.5 L-80 8 rnd EUE 2.441" Surface ±10,850' JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 5 43.44' 43.44' ±9,506' ±10,638' ±4,323' Future Proposed Hanger 1 ±350' ±350' 2.313" SSSV ±2,562 ±2,500 2.441" 4.750" GLM #1 ±5,225 ±4,300 2.441" 4.750" GLM #2 ±6,552 ±5,550 2.441" 4.750" GLM #3 ±7,440 ±6,400 2.441" 4.750" GLM #4 2 ±7,963 ±6,900 2.441" 4.750" GLM #5 ±8,485 ±7,400 2.441" 4.750" GLM #6 ±9,060 ±7,950 2.441" 4.750" GLM #7 ±9,634 ±8,500 2.441" 4.750" GLM #8 ±10,499 ±9,236 2.441" 4.750" GLM #9 Orifice 3 ±10,800' ±9,434' Halliburton ROC Gauge Mandrel w/ 0.25" TEC wire 4 ±10,830' ±9,448' Packer 5 ±10,845' ±9,456' 2.205" XN-Nipple 6 ±10,850' ±9,458' WLEG PERFORATION DETAIL ne Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status 5 ±10,954' ±15,277' ±9,506' ±10,638' ±4,323' Future Proposed 7X ±15,656' ±15,726' ±10,909' ±10,964' ±70' Future Proposed PBTD: ±15,734' TD: ±1.5,34' 1 Updated By:JLL 07/12/2019 Hilrvarp Alapka, L(A: Granite Point GPP 53 and 55 133/8 x 95/8 x 31/2 Valve, Swab, 3 1/8 5M FI EE tri Valve, Master, 3 1/8 5M FE EEtrin Valve, Master, 3 1/8 5M FE, EEtrin Tubing head attachment, Cactus -TC -60, 11 5M FE X 13 5/8 5M API hul bottom Unihead, Kvaerner SMS, 3 step system, 13 5/8 5M API Hub top X 13 3/8 BTC casing bottom, w/ 2- 2" LPO, 4- 2 1/16 SM 550 Granite Point Platform GP -53 Proposed 04/30/2019 Tubing hanger, Cactus -TC - EN -CCL, 11 x 3'h EUE 8rd lift and susp, w/ 3" type H-BPV profile, 3-%npt control line port, 6%EN BHTA, Bowen, 3 1/8 5M FE x 2.5 bowen quick union top Ilileorp Alaska, LLC 21.0 BOP Schematic GP 53RD Drilling Procedure Rev 0 Rig Floor Page 34 Revision 0 May, 2019 I lileorp Alaska, TIC 28.0 Choke Manifold Schematic GP 53RD Drilling Procedure Rev 0 rs:xa hqI Pce ry x�lon w xw atw daroe ry }l� �e Ce, 34/16' 15M by f 0 M OSAF 3-1116' IOM by 4.1116' IOM Spool O / 14116'101fibylWOSAF 4-1116' 1011 by 3.1116' tOM OSAF 1358' IOM SINGLE I1}'l 1'JA, p1P STKR CAMERON TYPE RAM 13 1l Sf Ol0[R t(liVf t y/`Ilar Page 43 Revision 0 May, 2019 Granite Point Platform BOP - HAK 404 Variable rams 27/8-5 Blind Rams C) c � o C � r - D m > w �ZZO� �J m G� U)0>-n M :,Er r N n Z O O m � n� D2G� C/) D D DZ--jG)4�1 �G)ODC:1 �CZ U) - �c E C r Cr- m W Zcv m0 Z o G) z D z m m cn co n� CA�� D D ,Zmi O 7J Scn D C S C O Z 41.W O cu - M D m A X r zZ mn m U7 00 J cD N A 3 r w � n o o 0 0 a a m w e c n S S n n n n 0 0 0 0 0 0 0 0 0 0 3 3 a3 3 a3 < aL 0 0 00 0 n l0 N V Q1 In A W N H to A W N 1- O n n O n n 0-0-01-0-1- n O n O n 0 O n 0 0 n o n 0 0 o ° n o 0 X 0 C r T D"+ r � C o Z D C) Z �l n cin w O 0 mO r m —� D -n r C r- 0 0 0 Ooo00 zZ-°��7 G7 > CDD :rtD�-jG)4�1 �cnOZ � Z zcv - D m0 I Z o Z z C r D D Z m n� N A = A - D O p � A A D = G ,zpi mm m = D OZ W O m C m� mA m m� Z*z �4z O) U zu� z4tz Ootitz J tD N 3 > o - o o_ a 0 o n o- n m nnn=n,ss�s nx�cx v v 0 0 0 0 0 0 0 0 0 0 O p-- o?_ 3 3 3 3 r�o m m m ro m m r'co r'co o > > m > > jp O O O O O O D D O O N S O O aO 0 0 - --- - -- a n n ° a a a n a v+ A w n n n o n n n n n 3 p w o O n n O n n O n O n O n 0 o n o 0 n o a a 0 x d CG 6 O U we EW 0 aj � m ca � U U C � E m O •Y c �m E — o -E -0 -0 a) c � o N o > L Q 0 -0- m -0- m a> L C N o m m � c m � 0) C U Co N L � U 0 aoi > 0 0_ O C)-� c� 3 U C) -o -o CD �O c Q a) E � N U O •� a) O .0 _ (D Q) U � f0 U C�Oy O L Q as Q v d N Y > Q o m ;a = a = Q 0 N L 2Cm ^L CL Cl) 'a Z � s U d d U O a 41 m 0 CD m m (L cu 0 Q El 2 0 O LL THE STATE GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Granite Point Field, Middle Kenai Oil Pool, GP -53RD Hilcorp Alaska, LLC. Permit to Drill Number: 219-079 Surface Location: 2434' FNL, 1310' FWL, SEC. 13, TION, R12W, SM, AK Bottomhole Location: 360' FSL, 840' FWL, SEC. 24, TION, R12W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to redrill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 12 day of June, 2019. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 [RECEIVE 1 a. Type of Work: Drill ❑ Lateral F-1Stratigraphic Redrill El • Reentry ❑ 1b. Proposed Well Class: Exploratory - Gas ❑ Test El Development - Oil ❑✓ Exploratory - Oil ❑ Development - Gas ❑ Service - WAG ❑ Service - Disp ❑ Service - Winj El Single Zone ❑� Service - Supply ❑ Multiple Zone ❑ 1c. Spfy if well is proposed for: Coalbed Gas ❑ Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: Hilcorp Alaska, LLC 5. Bond: Blanket ❑✓ Single Well ❑ Bond No. 022035244 11. Well Name and Number: GP -53RD ' 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 6. Proposed Depth: MD: 15,684' TVD: 11,182' 12. Field/Pool(s): Granite Point Field Middle Kenai Oil Pool JAcK,,e p 5PPgrtrA&) 1� 1 4a. Location of Well (Governmental Section): Surface: 2434' FNL, 1310' FWL, Sec 13, T10N, R12W, SM, AK Top of Productive Horizon: 1194' FNL, 678' FEL, Sec 23, T10N, R12W, SM, AK Total Depth: 360' FSL, 840' FWL, Sec 24, T10N, R12W, SM, AK 7. Property Designation: ADLO18761 8. DNR Approval Number: LOCI 19-001 13. Approximate Spud Date: 7/7/2019 9. Acres in Property: 5089 14. Distance to Nearest Property: 4537' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x-263342 y- 2544497 • Zone -4 10. KB Elevation above MSL (ft): 156.2' GL / BF Elevation above MSL (ft): — N/A 15. Distance to Nearest Well Open to Same Pool: 1200' to GP 54 16. Deviated wells: Kickoff depth: 4592 feet • Maximum Hole Angle: 80 degrees 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Downhole: --.5t5332_ Surface: 2609 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) 8-3/8" 7" 29# L-80 DWC/C 6,499' 4,392' 3,980' 10,891' - 9,474' L - 1106 ft3 6-1/8" 5" 18# P-110 Hyd 513 4,993' 10,691' 9,368' 15,684' . 11,182' L - 523 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): 16,657' 11,071' 14,530' / 15,112' Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 14,530' 10,735' N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 294' 26" Driven 294' 294' Surface 1,031' 13-3/8" 1213 sx 1,031' 1,031' Intermediate 4,551' 9-5/8" 1359 sx 4,551' 4,089' Production 13,323' 7" 500 sx 13,323' 10,472' Liner 3,725' 5" 377 sx 16,634' 11,065' Perforation Depth MD (ft): 13,339' - 14,500' Perforation Depth TVD (ft): 10,479' - 10,730' Hydraulic Fracture planned? Yes ❑ No 7 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch B Seabed Report B Drilling Fluid Program ❑ 20 AAC 25.050 requirements 8✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Monty Myers Authorized Name: Monty Myers Contact Email: mm erS hilcor .Com Authorized Title: Drilling Manager Contact Phone: 777-8431 Authorized Signature: "— '�— Date: Z O Commission Use Only Permit to Drill „ Number. G/l ' ��g I Number: ' /_ , r5O-��`�z�%` ���c�f "X� Permit ApprovalSee Date: 2 cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, as hydrates, or gas contained in shales: Other: /f 3 �` S. / `� L Samples req'd: Yes ❑ No [?/ Mud log req'd: Yes ❑ No HZS measures: Yes ❑ No Directional Directional svy req'd: Yes [�No ❑ u T'_ C g& /� L`f �X L £ 5 Spacing exception req'd: Yes ❑ No Inclination -only svy req'd: Yes ❑ No [✓� 0 i Y�,47� �� J` � z Post initial injection MIT req'd: Yes ❑ No ❑ l l/ APPROVED BY / Approved by: COMMISSIONER THE COMMISSION Date: lLl &lq/ q � 1 \ I � I N A� Submn Form and Form -401 Revised 5/2017 This per it i5 Valid for 2 tt h a r val per 20 AAC 25.005(g) Attachments in Duplicate re1410� 19 "az s-zz.• "f Hilcorp Alaska, LLC GP 53RD Drilling Program Granite Point rr� d by: MI My Revision 0 May 18, 2019 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, LLC 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 Summary............................................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 BOP N/U and Test.........................................................................................................................11 11.0 Mud Program and Density Selection Criteria............................................................................12 12.0 Drill 8-3/8" Hole Section...............................................................................................................13 13.0 Run 7" Drilling Liner....................................................................................................................15 14.0 Cement 7" Drilling Liner..............................................................................................................18 15.0 Drill 6-1/8" Hole Section...............................................................................................................22 16.0 Run 5" Production Liner..............................................................................................................25 17.0 Cement 5" Production Casing......................................................................................................28 18.0 Wellbore Clean Up & Displacement............................................................................................32 19.0 Run Completion Assembly...........................................................................................................33 20.0 RD...................................................................................................................................................33 21.0 BOP Schematic..............................................................................................................................34 22.0 Wellhead Schematic......................................................................................................................35 23.0 Days vs Depth.................................................................................................................................36 24.0 Geo-Prog.........................................................................................................................................37 25.0 Anticipated Drilling Hazards.......................................................................................................38 26.0 Rig Layout......................................................................................................................................39 27.0 FIT Procedure................................................................................................................................42 28.0 Choke Manifold Schematic...........................................................................................................43 29.0 Casing Design Information...........................................................................................................45 30.0 8-3/8" Hole Section MASP............................................................................................................46 31.0 6-1/8" Hole Section MASP............................................................................................................47 32.0 Plot (NAD 27) (Governmental Sections)......................................................................................48 33.0 Slot Diagram (As Built) (NAD 27)...............................................................................................49 34.0 Directional Program(wplI).........................................................................................................51 0 Ililcurp Alaska, LLC 1.0 Well Summary GP 53RD Drilling Procedure Rev 0 0 Z re . . Well GP 53RD Pad & Old Well Designation Sidetrack of existing well GP53 (PTD#196-014) / Planned Completion Tye 5" 18# P-110 Liner, 2-7/8" X 2-3/8" Tubing GL Comp Target Reservoir(s) T onek Producer C5 Planned Well TD, MD / TVD 15,684' MD / 11,182' TVD PBTD, MD / TVD 15,531' MD / 11,045' TVD Surface Location (Governmental) 2434' FNL, 1310' FWL, Sec 13, T10N, R12W, SM, AK Surface Location (NAD 27) X=263342.96, Y=2544497.34 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 1194' FNL, 678' FEL, Sec 23, TION, R12W, SM, AK TPH Location (NAD 27) X=261274.99, Y=2540499 TPH Location (NAD 83) BHL (Governmental) 360' FSL, 840' FWL, Sec 24, TION, R12W, SM, AK BHL (NAD 27) X=262718.64, Y=2536742 BHL (NAD 83) AFE Number 1911671D AFE Drilling Days AFE Drilling Amount $6.3 MM Work String 5" 19.5# S-135 NC50 (Rental from Workstrings Int'l) RKB — AMSL 156.2' MSL to ML 75' ' BOP Equipment 13-5/8" 5M Hydril "GK" Annular BOP 13-5/8" 5M Cameron Type U Double Ram 13-5/8" 5M Cameron Type U Single Ram Page 2 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, LLC 2.0 Management of Change Information 11 Hilcorp Alaska, LLC F -'M i �ncr cmYpu,y Changes to Approved Permit to Drill Date: May 10, 2019 Subject: Changes to Approved Permit to Drill for GP -53RD File #: GP -53RD Drilling Program Any modifications to GP -53RD Drilling Program will be documented and approved below. Changes to an approved APD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approved Approved By B Approval. Drilling Manager Date Prepared: Monty M Myers 05.10.2019 Drilling Manager Date Page 3 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Hilcorp Alaska, LLC. 3.0 Tubular Program Hole OD (in) Wt (#/ft) Coupl ID Drift Grade ConTop Section OD in Attom 8-3/8" 7" 29 7.875" 6.184 6.125 L-80 DWC/C 4,392' 10,891' 6-1/8" 5" 18 5.0" 4.194 4.151 P-110IC HYD513 10,691' 15,684' 4.0 Drill Pipe Information Hole OD (in) ID (inj TJ ID in TJ OD in(#/ft) Wt Gr d nu Burst Collapse si(k-lbs) Tension 8-3/8" 5" 4.276 3-1/8 6-5/8 19.5 5-135 NC50 17,100 15,110 560 6-1/8" 4-1/2" 3.826 2.6875" 5.25" 16.6 5-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Hilmrp Alaska, LLC 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. i. Report covers operations from 6am to 6am ii. Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. iii. Ensure time entry adds up to 24 hours total. iv. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates v. Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp.com and cdin er e,hilcorp.com 5.3 5am Weekend Update vi. Submit a short operations update each weekend and holiday to whoever is assigned weekend or vacation duty. Details will be sent before each weekend or holiday. vii. Copy pmazzolinighilcorp.com, and mm ersghilcorp.com 5.4 EHS Incident Reporting viii. Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! a. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 b. Mark Tornai: O: (907) 283-1372 C: (907) 748-3299 c. Thad Eby: O: (907) 777-8317 C: (907) 602-5178 2. Spills: a. Keegan Fleming: 0:907-777-8347 C:907-350-9439 ix. Notify Drlg Manager 1. Paul Mazzolini: O: 907-777-8369 C: 907-317-1275 x. Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally xi. Send final "As -Run" Casing tally to mmyers(2hilcorp.com and cdin eg_rghilcorp.com 5.6 Casing and Cmt report xii. Send casing and cement report for each string of casing to mmyershilcorp.com and cdingerghilcorp.com Page 5 Revision 0 May, 2019 0 Ililcorp Alaska, L[.0 v 6.0 Planned Wellbore Schematic 14 PROPOSED Hil—P AI—La. LLI: RIBtoMLLW156.27; RKBtoMudine=23122' PBTD:±15,531' TD:t15,683' GP 53RD Drilling Procedure Rev 0 Granite Point Field Well: GP 53RD Last Completed: Future PTD: XXX -XXX API: 50 -733 -20471 -XX CASING DETAIL Size Wt Grade Conn ID Top Btm 33' Outside Driven Conductor Welded ±2,000' 47' 2.29 26' Inside Driven Conductor Welded GLM #2 47' 294' 13-3/8' 68 K-55 STC 12415" 47' 1.031' 9-S/8" 47 L-80 53.S P-110 BTC STC 8-681' 8.535" 46' 73' 73' 14,592' KOP 7" 29 L-80 DWC/C 6.184' x4,392' ±10,891' S" 18 P• JOIC Hyqril5l3 4.194" 1-10,691' 315,683' / TUBING DETAIL 2-7/8" 6.5 L-80 8 rnd EUE 1 2.441" 1 Surface 1 ±9,700' 2-3/8" 4.7 L 80 8 rrxl EUE 1.995' 9,700 11,900' JEWELRY DETAIL Depth (MD) Depth (TVD) ID OD Item 3350' 3350' 2.313' SSSV ±2,002' ±2,000' 2.441' GLM #1 33,091' 13,000' 2.441' GLM #2 ±3,757' 33,500' 2.441" GLM #3 ±4,432' ±4,000' 2.441' GLM #4 ±5,059' ±4,500' 2.441- GLM #S 35,626' ±5,000' 2.441' GLM #6 35,192' ±5,500' 2.441- GLM #7 ±6357' 36.000' 2.441- GLM #8 ±7,322' ±6,500' 2.441" GLM #9 ±7,887' ±7,000' 2.441' GLM#10 38,453' ±7,500' 2.441" GLM #11 ±9,018' ±8,000' 2.441- GLM#12 ±9,583 1 ±8.500 2.441" _ GLM #13 39,600' 18,515' 1.995" X -Over 10,116' ±9,000' 1.995' GLM #14 ±11,800' ±9.700' 1.995- GLM#15 ±11,830' ±9,708' 1.975" 3.669' Halliburton ROC Gauge Mandrel w/ 025" TEC wire ±11,860' ±9,715' Packer ±11,890' 19,722' 1.791" XN-Nipple ±11,900 ±9,725' 1 1 WLFG Page 6 Revision 0 May, 2019 PERFORATION DETAIL op (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status 112,000' ±14,900' 39,744' 310,360' 12,900' Future Proposed ±15.231 ±15.431' 110,784' 310,954' ±100' Future Proposed Page 6 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, LIX 7.0 Drilling Summary GP 53RD is an oil production well planned to be re -drilled in a South-westerly direction from the existing GP 53 utilizing the existing casing program down to 4,592' MD / 4,130' TVD. The previous completion will be pulled on a separate sundry, and 7" casing will be cut and pulled, to below the previous 9-5/8" casing shoe at 4,592'. At 4,592' MD the parent wellbore will be sidetracked and new wellbore drilled to 10,891'. An intermediate 7" liner will be run and cemented at 10,891'. A 4,792' x 6-1/8" open hole section is planned to be drilled to TD of 15,684'. A 5" 18# P-1 IOIC HYD513 prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with a 2-7/8" X 2-3/8" gas lift completion. Drilling operations are expected to commence approximately July 7th, 2019. .rz-#" All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. sA 5� ¢ '3 m -0 A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and for running the completion assembly General sequence of operations pertaining to this approved drilling procedure: AA 1. Spartan 151 will be MIRU over (GP 53). FITC �%� `�'`� `� ✓" �'' 2. NU BOPE and test. 3. RIH with clean out assembly and swap well to 9.0 ppg oil based drilling mud 4. Drill shoe 20' of new formation at 4,592'. Perform FIT to 13 ppg EMW 6. POOH and LD cleanout assembly. PU rotary steerable directional BHA and TIH to shoe. 7. Drill intermediate hole from 4,592' to 10,891' MD, performing short trips as needed 8. POOH w/ directional tools. RIH w/ 7" liner. Set liner and cement. Circ wellbore clean. 9. POOH, laying down DP and liner running tools, 10. PU 6-1/8" rotary steerable drilling assembly and TIH to landing collar. 11. Drill out float equipment and 20' of new formation at 10,891'. 12. Perform FIT to 13 ppg EMW 13. Drill production hole from 10,891' to 15,684' MD, performing short trips as needed 14. POOH w/ directional tools. RIH w/ 5" liner. Set liner and cement. Circ wellbore clean. 15. PU liner cleanout assembly and TIH to landing collar. 16. Circ casing clean. POOH laying down DP. 17. Run 2-7/8" X 2-3/8" completion. (Covered under separate sundry) 18. Land hanger and test. 19. ND BOPE, NU tree and test void Page 7 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Irilcorp Alaska, LLC 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling of GP 53RD. Ensure to provide AOGCC 48 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must testALL BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. ���� _ �'S Variance Requests: —� L��� ��,��, �- �l �P ig o Hilcorp would like to request a variance to regulation 20 AAC 25.035(e)(4)(F)(i) which states - "the outlets must be at least two inches in nominal diameter, except that for rotary drilling rig operations, if the operation has a maximum potential surface pressure of greater than 3,000 psi, the nominal diameter of the choke outlets must be at least three inches".��^'�'`� o The calculated Tv T,91i or wellbore when completely evacuated togas is 155 . However, for Cook Inlet Operatioq-y, we assume that the well cqu never flow 100% gas, due to the water in 6 k4 -the reservoir. We reduce this MASP calculation to 735 psi which assumes that only 2/3 of the wellbore is evacuated to gas and 1/3 to 9.0 ppg reservoir fluid. o Hilcorp would like to request to have 2-1/16" outlets on the choke line and kill line due to this assumption Page 8 Revision 0 May, 2019 0 Hikwrp Alaska, TAX Summary of BOP Equipment and Test Requirements GP 53RD Drilling Procedure Rev 0 Hole Section Equipment Test Pressure(psi) • 13-5/8" Shaffer 5M annular 8-3/8" • 13-5/8" 5M Shaffer SL Double gate • Blind ram in bottom cavity Initial Test: 250/3500 (Annular 2500 psi) & • Mud cross 6-1/8" • 13-5/8" 5M Shaffer SL single gate • 3-1/16" 5M Choke Manifold Standpipe, floor valves, etc Subsequent Tests: 250/3500 (Annular 2500 psi) Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex electric driven pump Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 48 hours notice prior to spud. • 48 hours notice prior to testing BOPS. • 48 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Additional requirements may be stipulated on APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regagalaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: g_uy.schwartzgalaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: victoria.loel2p@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectorsgalaska. og_v Test/Inspection notification standardization format: htip:Hdoa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Revision 0 May, 2019 Ililrorp Alaska, LLC 9.0 RX and Preparatory Work 9.1 9.2 9.3 GP 53RD Drilling Procedure Rev 0 Separate sundries will be submitted that will include the following: r/ Pull tubing ei h- s P P&A lower perfs with a cement plug , Q L� Z' Cut and pull 7" casing to below 9-5/8" shoe 3 Spot cement kick off plug f Mix mud for 8-3/8" hole s� ect o ""', �e§ Verify 6.5" liners installed in mud pump #1 and pump #2. (PZ -10's) . Gardner Denver PZ -10's Pumps are rated at 4200 psi (100%) with 6.5" liners and can deliver 496 gpm at 115 spm. Ideal pump rate for drilling will be 500-600 gpm. Both pumps running at 65 spm should achieve this. all0WEIGUzi I]I:��1111121FAq:11M411a111lux>wI,l0114itATHIM MAXIMUM PSI DIAMETER PER REVOLUTION MAXIMUM FLOW RATE inch MM 7 178 gallon liters 5.00 18.92 GPM 575 LPM 2176 PSI 3623 b. 250 6.5 165 4-31 16.31 496 1876 4202 290 6.25 159 3.98 15.08 458 1734 4545 313 6 152 3.67 13.90 422 1598 4932 340 5.5 140 3.09 11-68 355 1343 5000 345 5 127 2.55 9.65 293 1110 5000 345 Weight Complete pump with large steel skid - 41,400 pounds. Ratings are based cry 901'o mechanical efficiency and 100% volumetric efficiency PUMP IJACKSHAFT RPM RPM i» Page 10 Revision 0 May, 2019 504 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, I.Ix 10.0 BOP N/U and Test 10.1 N/U 13-5/8" x 5M BOP as follows (top down): • 13-5/8" x 5M Shaffer annular BOP. • 13-5/8" Shaffer Type "SL" Double ram. (2-7/8" X 5" VBR in top cavity, blind ram in btm cavity) • 13-5/8" mud cross • 13-5/8" Shaffer Type "SL" single ram. (2-7/8" X 5" VBR) • N/U pitcher nipple, install flowline. • Install (2) manual valves on kill side of mud cross. Manual valve used as inside or "master valve". • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 10.2 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened!!! • Test VBRs on 5" test joint. • Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 10.3 R/D BOP test assy. 10.4 Continue mixing mud for 8-3/8" hole section. 10.5 Set wearbushing in wellhead. Ensure ID of wearbushing > 8-3/8". Page 11 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ilileorp Alaska, LIX 11.0 Mud Program and Density Selection Criteria 11.1 8-3/8" Production hole mud program summary: Primary weighting material to be used for the hole section will be barite to minimize solids. We will have enough barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. Canrig PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 80/20 Enviromul MOBM Properties: 11.2 11.3 System Formulation: 80/20 Enviromul MOBM Product Mud Weight LVT 0.662 bbl Water .172 bbl INVERMUL NT 4 ppb MD (PPg) Viscosity Pv YP HTHP WPS ES 4,592-10,891' 9.0-9.5 50-80 25-35 15-22 <5 250-270K >580 11.2 11.3 System Formulation: 80/20 Enviromul MOBM Product Concentration LVT 0.662 bbl Water .172 bbl INVERMUL NT 4 ppb EZ MUL NT 4 ppb GELTONE V 6-10 ppb Lime 7 ppb DURATONE HT 2 ppb Calcium Chloride 21 ppb BAROID 41 9.0 ppg (as needed) BARACARB 5 3-5 ppb BARABLOK 2 ppb BAROTROL PLUS 4 ppb Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. Page 12 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 llileorp Alaska, LLC 12.0 Drill 8-3/8" Hole Section 12.1 P/U 8-3/8" rotary steerable directional drilling assy. 12.2 Ensure BHA Components have been inspected previously. 12.3 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 12.4 Ensure TF offset is measured accurately and entered correctly into the MWD software. 12.5 Confirm that the bit is dressed with a TFA of 0.51 — 0.61 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 500-600gpm. 12.6 Must keep up with 5 deg/100 DLS in the build section of the wellbore. 12.7 Primary bit will be the Baker Hughes 8-3/8" Kymera Hybrid bit. Ensure to have a back up bit available on location. � J 12.8 TIH to cement plug from prior slot recovery/P&A. Shallow test MWD on trip in. 12.9 Tag cement and drill 20' of new formation from 4,592' to below 9-5/8" shoe. ' \ 12.10 Conduct FIT to 13.0 ppg EMW. 12.11 (13.0 — 9.0) * 0.052 * 4130' tvd = 859 psi 12.12 Kick Tolerance / • (13.0 -9.0) * (4130/9474) = 1.74 z/ Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 13.0 ppg FIT results in a 1.74 ppg kick tolerance while drilling the interval with a 9.0 ppg fluid density. 12.13 Drill 8-3/8" hole to 10,891' MD using rotary steerable assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. Page 13 Revision 0 May, 2019 Ililcorp Alaska, LL(: • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. ✓ • Minimize backreaming when working tight hole GP 53RD Drilling Procedure Rev 0 12.14 Hilcorp Geologists will follow mud log closely to determine exact TD. 12.15 At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 12.16 TOH with drilling assembly, handle BHA as appropriate. Page 14 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, LLA: 13.0 Run 7" Drilling Liner 13.1 R/U Weatherford 7" casing running equipment. • Ensure 7" DWC/C x 5" NC50 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted and tally verified prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 13.2 P/U shoe joint, visually verify no debris inside joint. 13.3 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker locked joint. • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked up. • No centralizers to be installed on shoe joint, FC joint, and LC joint. • Install centralizers, one per joint to +/- 4,600' TMD, and leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe & FC. 13.4 Continue running 7" production liner • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 7" DWC/C M/U torques Casing OD Minimum Maximum Yield Tor ue 7" 19,200 ft -lbs 22,100 ft -lbs 25,000 ft -lbs Page 15 Revision 0 May, 2019 Ililcorp AlaAa. 11C Connection Type: Size(O.D.): DWC/C Casing 7 in 2012 API Spec 5CT Coupling O.D. Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Pipe Dimensions 7.000 Nominal Pipe Body O.D. (in) 6.184 Nominal Pipe Body I.D.(in) 0.408 Nominal Wall Thickness (in) 29.00 Nominal Weight (lbs/ft) 28.75 Plain End Weight (lbs/ft) 8.449 Nominal Pipe Body Area (sq in) GP 53RD Drilling Procedure Rev 0 Weight (Wall): Grade: 29.00 Ib/ft (0.408 in) L-80 Pipe Body Performance Properties 676,000 Minimum Pipe Body Yield Strength (lbs) 7,030 Minimum Collapse Pressure (psi) 8,160 Minimum Internal Yield Pressure (psi) 7,500 Hydrostatic Test Pressure (psi) GP 53RD Drilling Procedure Rev 0 Weight (Wall): Grade: 29.00 Ib/ft (0.408 in) L-80 Connection Dimensions 7.875 Connection O.D. (in) 6.184 Connection I.D. (in) 6.125 Connection Drift Diameter (in) 4.50 Make-up Lass (in) 8.449 Critical Area (sq in) 100.0 Joint Efficiency (%) GP 53RD Drilling Procedure Rev 0 Weight (Wall): Grade: 29.00 Ib/ft (0.408 in) L-80 Appoximated Field End Torque Values 19,200 Minimum Final Torque (ft -lbs) 22,100 Maximum Final Torque (ft -lbs) 25,000 Connection Yield Torque (ft -lbs) 1� VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsalesfc-�vamm-usa.com Page 16 Revision 0 May, 2019 Connection Performance Properties 676,000 Joint Strength (lbs) 16,650 Reference String Length (ft) 1.4 Design Factor 718,000 API Joint Strength (lbs) 338,000 Compression Rating (lbs) 7,030 API Collapse Pressure Rating (psi) 8,160 API Intemal Pressure Resistance (psi) 26.2 Maximum Uniaxial Bend Rating [degrees/100 ft] Appoximated Field End Torque Values 19,200 Minimum Final Torque (ft -lbs) 22,100 Maximum Final Torque (ft -lbs) 25,000 Connection Yield Torque (ft -lbs) 1� VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsalesfc-�vamm-usa.com Page 16 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ilileorp Alaska, LL(: 13.5 Ensure to run enough liner to provide for approx 200' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 13.6 Before picking up Baker SDD liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 13.7 M/U Baker SDD liner top packer. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 13.8 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 13.9 RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.10 M/U top drive and fill pipe while lowering string every 10 stands. 13.11 Set slowly in and pull slowly out of slips. 13.12 Circulate 1-1/2 drill pipe and liner volume at 8-3/8" window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 13.13 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 13.14 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 13.15 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack -off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 13.16 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 13.17 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 17 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ilileorp Alaska, I.LC 14.0 Cement 7" Drilling Liner 14.1 Hold a pre job safety meeting over the upcoming cmt operations. 14.2 Attempt to reciprocate the casing during cmt operations until hole gets sticky. 14.3 Pump 15 bbls of water through cement lines to flush them 14.4 Pump 35 bbls 12.5 ppg spacer. 14.5 Test surface cmt lines to 4500 psi. 14.6 Mix and pump 197 bbls of 14.5 ppg class "G" cmt per below recipe with 0.251b/bbl loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to bring cement up to 4,592'. Est TOC 8500' TMD. 14.7 Displacement fluid will be drilling mud. Cement Calculations 8-3/8" OH x 7" Liner: (10,891' — 4,592') x 0.02054 x 1.5 = 194 bbls Shoe Track: 80' x 0.03715 = 3 bbls Total Volume (bbls): 194 + 3 = 197 bbls Total Volume (ft3): 197 bbls 5.615 ft3/bbl = 1106 ft3 Total Volume (sx): 06 ft3 / 1.34 ft3/sk = 826 sx Page 18 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, UA: Slurry Information: System VariCEM Density 14.5 lb/gal Yield 1.34 ft3/sk Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Be at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 94 lb/sk 0.2% BWOC 1.5% BWOC 0.8% BWOC 8.0% BWOC 14.8 Drop DP dart and displace with drilling mud. 14.9 Pump cement at max rate of 8 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point 14.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 14.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 14.12 Slack off total liner weight plus 30k to confirm hanger is set. 14.13 Do not overdisplace by more than '/z shoe track (-1 bbls). Shoe track volume is 2 bbls. 14.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Page 19 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Hilcorp Alaska, LLC 14.15 Bleed pressure to zero to check float equipment. 14.16 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 14.17 Rotate slowly and slack off 50k downhole to set ZXP. 14.18 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS profile. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 14.19 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 14.20 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 14.21 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 14.22 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 14.23 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 14.24 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 14.25 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 20 Revision 0 May, 2019 Hilrorp Alaska, LII GP 53RD Drilling Procedure Rev 0 Ensure to report the following on Wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Note: Send Csg & cmt report + "As -Run" liner tally to mmyers(a)hilcory.com Page 21 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, LLC. 15.0 Drill 6-1/8" Hole Section 15.1 PU 5.500' of 4-1/2" CDS40 Drill pipe for drilling 6-1/8" hole section 15.2 P/U 6-1/8" rotary steerable drilling assy. 15.3 Ensure BHA Components have been inspected previously. 15.4 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics models to ensure optimum TFA. We want to pump at 250 - 450 gpm. 15.7 Production section will be drilled with AutoTrak. Must keep up with 6 deg/100 DLS in the drop section of the wellbore. 15.8 Primary bit will be the Baker Hughes Kymera 6-1/8" HP414. Ensure to have a back up PDC bit available on location. 15.9 TIH to liner hanger. Shallow test MWD on trip in. 15.10 TIH through liner hanger ensure Baker Hughes MWD service rep on rig floor during this operation. Page 22 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, LIX 15.11 Circulate well with 9.0 ppg MOBM to warm up mud until good 9.0 ppg in and 9.0 ppg out. c. C' 15.12 Test casing to 2500 psi and chart for 10 minutes J� 15.13 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream shoe as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through shoe checking for drag. 15.14 Circulate Bottoms Up until MW in = MW out. 15.15 Conduct FIT to 13.0 ppg EMW. • (13.0 — 9.0) * 0.052 * 9474' tvd = 1971 psi 15.16 Kick Tolerance • (13.0 -9.0) * (9474/11182) =339 / Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 13.0 ppg FIT results in a 3.39 ppg kick tolerance while drilling the interval with a 9.0 ppg fluid density. 15.17 System Type: 9.0 ppg 80/20 Enviromul mineral oil based drilling fluid. Properties: MD Mud Weight Viscosity Pv YP HTHP WPS ES EZ MUL NT (PPg) GELTONE V 6-10 ppb Lime 7 ppb DURATONE HT 2 ppb 10,891— 15,684' 9.0— 10.0 �` 50-80 20-30 15-22 <5 250-270K >580 f System Formulation: 90/10 Enviromul MOBM Product Concentration LVT 0.662 bbl Water .172 bbl INVERMUL NT 4 ppb EZ MUL NT 4 ppb GELTONE V 6-10 ppb Lime 7 ppb DURATONE HT 2 ppb Calcium Chloride 21 ppb BAROID 41 9.5 ppg (as needed) BARACARB 5 3-5 ppb BARABLOK 2 ppb BAROTROL PLUS 4 ppb Page 23 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Frilcorp Alaska, LLC. 15.18 Drill 6-1/8" hole to 15,684' MD using rotary steerable assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 15.19 Hilcorp Geologists will follow mud log closely to determine exact TD. 15.20 At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 15.21 TOH with drilling assembly, handle BHA as appropriate. Page 24 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ifilcorp Alaska, LII: 16.0 Run 5" Production Liner 16.1 R/U Weatherford 5" casing running equipment. • Ensure 5" DWC/C x 4-1/2" CDS-40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted and tally verified prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.2 P/U shoe joint, visually verify no debris inside joint. 16.3 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker locked joint. • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked up. • No centralizers will be run on 5" liner • Ensure proper operation of float shoe & FC. 16.4 Continue running 5" production liner to TD • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 5" HYD513 M/U torques Casing OD Minimum Maximum Yield Torque 5" 6500 ft -lbs 11400 ft -lbs 7800 ft -lbs Page 25 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, LLC For the latest performance data, always visit our website: www.tenaris.com Wedge 513® — 02,10112019 Outside Diameter 5.004 in Min. Wall 87.5k - Ncminat Weight 18-00 bol. Drift 4,151 in Nominal ID Thickness 44at Thickness 0.362 m Plain End Weight 17.95lbs.Yt (') Grade P110- & _?ixa ��r PERFORMANCE ICY WaII Thickness 4.362 in Connection OD REGULAR COUPLING PIPE BODY Option Internal Y,eld 15840 psi SMYS 125000 Gs': Collapse 14840 Gal Compressisn Efbcmn.-y731 N. CAompression S:rergth Body White 1st Bard: White Grade P110 -ICY' Drift API Standard Ist Band Pate 2rd Band Pale GreenGreen Type Casing 2nd Band: - 3rd Bard. Pate 3rd Band: - Green ash Band - PIPE BODY DATA GEOMETRY Nomiral OD 5.000 :-, Ncminat Weight 18-00 bol. Drift 4,151 in Nominal ID 4.276 in 44at Thickness 0.362 m Plain End Weight 17.95lbs.Yt 00 Tolerance API PERFORMANCE PERFORMANCE Joim Y,eld strength 419.783 x TOW inter,al Preess>.ae Capacny Baty YieF.d Strength 659 x1040 ibs Internal Y,eld 15840 psi SMYS 125000 Gs': Collapse 14840 Gal Compressisn Efbcmn.-y731 N. �ONNECT[ON DATA GEOMETRY Cornect,cr OD 5.000 Cornec,inn IL's 4.194:n Make -4, Lass 4.320 In Threads per in 3.36 Corrie' a 00 Option REGULAR PERFORMANCE Tension Efficiency 63.7 h. Joim Y,eld strength 419.783 x TOW inter,al Preess>.ae Capacny 15840.000 psi bs Compressisn Efbcmn.-y731 N. CAompression S:rergth 485.683 xTOCO Max A.'raw le Bending 713'0 103 !1 "bs External Pressure Capacity 14940,000 G= - MAKE -UP TORQUES l knirurn 6500 "-Ibs optmrrum 7800 ft4bs Ma,aanum 11400 i'. IL s OPERATION LIMIT TORQUES Opera..*..ng Torque 22000 f: -lbs Yield Tvga .* 33000 ti -Itis Notes Page 26 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, LLC 16.5 Ensure to run enough liner to provide at least 100' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection. 16.6 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. , 16.7 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "XANPLEX", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set Up. 16.8 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 16.9 RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.10 M/U top drive and fill pipe while lowering string every 10 stands. 16.11 Set slowly in and pull slowly out of slips. 16.12 Circulate 1-1/2 drill pipe and liner volume at 7" shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 16.13 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 16.14 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 16.15 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack -off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. ' 16.16 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.17 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 27 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ililwrp Alaska, r.LC 17.0 Cement 5" Production Casing 17.1 Hold a pre job safety meeting over the upcoming cmt operations. 17.2 Attempt to reciprocate the casing during cmt operations until hole gets sticky. 17.3 Pump 15 bbls 12.5 ppg spacer. 17.4 Test surface cmt lines to 4500 psi. 17.5 Pump remaining 10 bbls 12.5 ppg spacer. 17.6 Mix and pump 93 bbls of 15.3 ppg class "G" cmt per below recipe with 0.5 lbs/bbl of loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to bring cement to 10,691' TMD in annulus between 5" liner and 7" liner. 17.7 Displacement fluid will be drilling mud. —207 bbls of displacement fluid in drill pipe and 35 bbls in liner. (5in. DP(.00852 * 10183 = 87)), (4-1/2 DP (.01373*5500 =76), (5" Liner (.01776 4872 = 87)), Total 250 bbls Cement Calculations 6-1/8" OH x 5" Liner: (15684'— 1069F) x 0.01216 x 1.5 = 91 bbls Shoe Track: 90' x 0.01776 = 1.6 bbls Total Volume (bbls): 91 + 1.6 = 93 bbl - Total Volume (ft3): 93 bbls x 5.615 ft3/bbl = 523 ft3 Total Volume (sx): 523 ft3 / 1.34 ft3/sk = 390 sx Page 28 Revision 0 May, 2019 1/ GP 53RD Drilling Procedure Rev 0 llilcorp Alaska, LLC Slurry Information: System ExpandaCEM Density 15.3 lb/gal Yield 1.34 ft3/sk Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Bc at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 941b/sk 0.2% BWOC 1.5% BWOC 0.8% BWOC 8.0% BWOC 17.8 Drop DP dart and displace with 9.5 ppg OBM drilling mud. 17.9 Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point 17.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 17.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. ' 17.12 Slack off total liner weight plus 30k to confirm hanger is set. 17.13 Do not overdisplace by more than 1/2 shoe track (-1 bbls). Shoe track volume is 1.8 bbls. 17.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Page 29 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ililcorp Alaska, LLC. 17.15 Bleed pressure to zero to check float equipment. 17.16 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 17.17 Rotate slowly and slack off 50k downhole to set ZXPN. 17.18 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 17.19 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17.20 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 17.21 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from M 17.22 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 17.23 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 17.24 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 17.25 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 30 Revision 0 May, 2019 Hilcorp Alaska, Lr.0 GP 53RD Drilling Procedure Rev 0 Ensure to report the following on Wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Note: Send Csg & cmt report + "As -Run" liner tally to mmyersWiilcorp.com Page 31 Revision 0 May, 2019 18.0 Wellbore Clean Up & Displacement GP 53RD Drilling Procedure Rev 0 18.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 4" or 4.125" bit or mill • Casing scraper & brush for 5" 18# casing • +/- 5000' 2-7/8" DP. • Casing scraper & brush for 7" 29# casing • (2000') 4-1/2" DP • Casing scraper & brush for 7" 29# casing • 4-1/2" DP to 4300' TMD • 5" DP to surface 18.2 TIH & clean out well to landing collar (+/- 15,563' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. • Ensure 4" bit is worked down to the landing collar. • Space out the cleanout BHA so that the 4" bit reaches the 5" landing collar when crossover is +/- 30' above the 5" liner top. 18.3 After wellbore has been cleaned out satisfactorily using mud, test c sing to 2500 psi / 30 min. Ensure to chart record casing test. 18.4 Displace drilling fluid in wellbore with a hi -vis pill followed by diesel. • Circulate 3 to 4 B/U until clean-up is satisfactory. • After a couple circulations using diesel, short trip the assy to bring the upper 7" scraper assy to surface. • RIH again & tag landing collar w/ 4" bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. 18.5 TOH w/ clean out assy. LDDP on the trip out. Page 32 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ilileorp Alaska, LLC 19.0 Run Completion Assembly 19.1 Run 2-7/8" X 2-3/8" tubing completion assembly as per separate Approved Completion Sundry 20.0 RD 20.1 Install BPV in wellhead. RILDs. 20.2 ND BOPE, NU tree, test void 20.3 Rig Down Page 33 Revision 0 May, 2019 Ililcorp Alaska. LLC 21.0 BOP Schematic GP 53RD Drilling Procedure Rev 0 Rig Floor Page 34 Revision 0 May, 2019 Ililcorl, Alaska. 1.1.1: 22.0 Wellhead Schematic Granite Point Platform GP -53 133/8x95/8 Unihead, Kvaerner SMS, 3 step system, 13 5/8 5M API Hub top X 13 3/8 BTC casing bottom, w/ 2- 2" LPO, 4. 2 1/16 5M SSO GP 53RD Drilling Procedure Rev 0 Temporary abandonment Page 35 Revision 0 May, 2019 0 nil q) Alaska, LLC 23.0 Days vs Depth 0 Ezz• •� 4000 6000 a h a a, 9 8000 d N A d G 10000 12000 14000 16000 + 0 Days Vs Depth GP 53RD Drilling Procedure Rev 0 GP 53RD 11-24 A tual 24-13RD2 Actual 5 10 15 20 25 30 35 40 45 50 Days Page 36 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ilileorp Alaska, LLC 24.0 Geo-Prog TOP NAME EXPE IDD MD LITHOLOGY I I C5 TOP 11,042 C5 BASE 15,562 C7X TOP 16,000 TVD (F7) 9,545.2 10,572.2 10, 869.2 TVD SS ( Pressure -9389 4,250.00 8.56 -10416 4,650.00 8.46 -10713 4,750,00: 8.40 0.45 0.44 0.44 NO INFORMATION CONCERNING THIS WELL IS TO BE RELEASED TO ANYONE EXCEPT THE EMPLOYEES OF HILCORP OR THEIR PARTNERS. Page 3 7 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ilileorp Alaska, LLC 25.0 Anticipated Drilling Hazards Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual -composition carbon -based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control running coals. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. • Minimize swab and surge pressures • Minimize back reaming through coals when possible H2S: 1-12S is not present in this hole section. ' No abnormal temperatures or pressures are present in this hole section. Page 38 Revision 0 May, 2019 26.0 R12 Layout GP 53RD Drilling Procedure Re 0 Page J9 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 iIzaZ g SN Q rt I Z O N_ O Q Z ; Z H _NO oo z z + z � N 4 O O erff A N X z to /X n• \ rn w m N az 0 L NN mz A om Tz Q . �N - p f \ NOD Oz O� \ mm O7 10 C � T Q \+, w `� \tet• ,.--"•p � Q vii `- Ni00B .� O c 4 7{ m X�mg ? �� `aiz�n �Zzo=z `az z �zc� x �oX'mc g"E% 6";,Q, zdoiggozry z zm z� Zm Zmn Co 0 oT r yi[� 09Tm o�r'a ops a. m o. ;D m D $p� ill _mWoOmw 00vm cam g9mB W;Kri AY N .Z1DN rr vDN mDN .ZIDNX A* N O`j �[ ' O. w m .O N 4 F U Page 40 Revision 0 May, 2019 Ilik-orp Alaska, 1.IX GP 53RD Drilling Procedure Rev 0 Page 41 Revision 0 May, 2019 Ililcorp Alaska, LLC 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: GP 53RD Drilling Procedure Rev 0 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 42 Revision 0 May, 2019 1(de—p :%64a, LLC 28.0 Choke Manifold Schematic CEMENT STANDPIPE DIRECT THRU PANIC LINE To Cement Unit R <2 El 3-1116" 15M by 10 M DSAF 3.1116" 10M by 4-1116' 10M Spool CHvFE LO -TORQUE VALVE 3e. «IE O !+�SC SV Sr1aF'fEn AWiLM GP 53RD Drilling Procedure Rev 0 STAND PIPE e2 F� 10-M GUE k0❑6 VALVE STAND PIPE 01 6—.- xesww BLEED Gc¢;mrc :x: »aca Nig 310. V:tta 1lm T4 N:n llM. iGa n! VpC l51 8 4tecws W Ltl2 F� 10-M GUE k0❑6 VALVE STAND PIPE 01 6—.- xesww BLEED :x: »aca cna VpC l51 4tecws W Ltl2 -Eco :. xhtmc«sr. BLEED OFF LINE TO BELL NIPPLE 113- l 8' 110 DOUBLE � 23 TEST 6EOCa i/ rrw a CAMERON TYPE U i°oP BO RA1.1S C 4-1116' 16M Manual and HCR valves on KIII Line Side »ith 101.1 by 15LI DSAF 4-116"10M Manuel and 11/16". 10M HCR on Choke line aide 10M by 15M OSAF 21 i CHOKE AND KILL LINES FROM NCR TO MANIFOLDS ARE 15M 11116-16Y by ISM DSAF 4-V16- 10Y by 11116' 16Y DSAF 13SIS' 10M SING +aaa +ou eor ssAu CAMERON TYPED RAM Page 43 Revision 0 May, 2019 uilcorp Alaska, LLC f/► 'if 4 GP 53RD Drilling Procedure Rev 0 3�i 3F r � fS � bC r � r r • � $ N _� iJi����•+ a � �rr Page 44 Revision 0 May, 2019 i GP 53RD Drilling Procedure Rev 0 lliicvrp Alaska, LLC 29.0 Casing Design Information Calculation & Casing Design Factors DATE: 5/18/2019 WELL: GP 53RD FIELD: Granite Point DESIGN BY: Monty M Myers n Criteria: Hole Size 8-3/8" Mud Density: 9.5 ppg Hole Size 6-1/8" Mud Density: 9.5 ppg Hole Size Mud Density: Drilling Mode MASP: 2609 Production Mode MASP: 3914 psi (See attached MASP determination & calculation) Collapse Calculation: Section Calculation 1, 2 Normal gradient external stress (0.44 psi/ft) and the casing evacuated for the internal stress Page 45 Revision 0 May, 2019 Casing Section Calculation/Specification _.. _.........._ ....... __ 1 2 3 4 ............._ Casing OD ...... 7" ®...__........ 5" Top (MD) 4,392 • _ 10,691 Top VV D) 3,980 9,368 Bottom (MD) 10,891 15,683 Bottom (TVD) 9,474 11,182 Length 99 4,992 Weight (ppf 29 18 Grade L-80 P-110 Connection DWC/C HYD513 Weight w/o Bouyancy Factor (lbs) 274,115 287,640 YJ L Tension at Top of Section (lbs) 274,115 287,640 Min strength Tension (1000 lbs) Worst Case Safety Factor (Tension) ;j2Af 1.46 ? Collapse Pressure at bottom (Psi) 4,100 5 Collapse Resistance w/o tension (Psi) 7,030 14,840 Worst Case Safety Factor (Collapse) 1.71 2.9_8 MASP (psi) 2,102 2,609 Minimum Yield (psi) 8,160 15,840 Worst case safety factor (Burst) 3.88 6.07 Page 45 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ilik•nrp Alaska, 1.1.1: 30.0 8-3/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation xil orp1 8-3/8" Hole Section GP 53RD Kenai, Alaska MD TVD Planned Top: 4592 4130 Planned TD: 10891 9474 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad TD 9,4741 4,100 Oil/Water 8.3 0.43 Offset Well Mud Densities Well MW range Too (TVD) Bottom (TVD) Date A-27RD2 9.3-9.5 7,755 9,718 2016 K-24RD3 8.9-9.3 8,768 9,994 2017 A-27RD 9.5-9.7 6,328 9,950 1997 K-06RD2 9.0-9.3 6,352 9,792 2017 Assumptions: 1. Maximum planned mud density for the 8-3/8" hole section is 9.5 ppg. 2. Calculations assume reservoirs contain 100.1 gas (worst case). 3. Calculations assume worst case event is complete evacuation of wellbore to gas. 4. Anticipated fracture gradient at 413Y TVD =12.5 ppg EMW Fracture Pressure at 8-3/8" window considering a full column of gas from window to surface: 4130 (ft) x 0. 65(psi/ft) = 2685 psi 2685 (psi) - [0.1(psi/ft)*4130(ft)]= I 2272 psi MASP from pore pressure; entire wellbore evacuated to gas from TD 9474 (ft) x 0.43(psi/ft)= 4074 psi 4074(psi) - [0.1(psi/ft)*9474 (ft)]= 3153 psi 4074(psi) - [(1/3)*0.1(psi/ft)*9474(ft)]+[(2/3)*0.43(psi/ft)*9474(ft)]= 2102 psi I Alternate Drilling MASP Summary: 1. MASP while drilling 8-3/8" intermediate hole is govemed by SIBHP minus 1/3 wellbore evacuated to gas from TD. Page 46 Revision 0 May, 2019 Ililcorp Alaska. LLC GP 53RD Drilling Procedure Rev 0 31.0 6-1/8" Hole Section MASP 11 Maximum Anticipated Surface Pressure Calculation 6-1/8" Hole Section Hilcorp GP 53RD Kenai, Alaska MD TVD Planned Top: 10891 9474 Planned TD: 15683 11182 Anticipated Formations and Pressnrws! Formation TVD Est Pressure Oil/Gas/Wet PPG Grad C5 TOP 9,545 4250 Water 8.6 0.45 C5 BASE 10,572 4650 Oil 8.5 0.44 TD 11,182 4750 Oil/Water 8.2 0.42 Offset Well Mud Densities Well MW range Tnn /7vn1 Rnttnm /TVM rinin A-27RD2 9.3-9.5 7,755 9,718 2016 K-24RD3 8.9-9.3 8,768 9,994 2017 A-27RD 9.5-9.7 6,328 9,950 1997 K-06RD2 9.0-9.3 6,352 9,792 2017 Assumptions: 1. Maximum planned mud density for the 6-1/8" hole section is 9.5 ppg. 2. Calculations assume reservoirs contain 100% gas (worst case). 3. Calculations assume worst case event is complete evacuation of wellbore togas. 4. Anticipated fracture gradient at 9474' TVD =12.5 ppg EMW Fracture Pressure at ' shoe considering a full column of gas from windowto surface: 9474 (ft) x 0.65(psi/ft)= 1 6158 psi 6158 (psi) - [0.1(psi/ft)*9474(ft)]= I 5211W :f MASP from pore pressure; entire wellbore evacuated to gas from TD 11182 (ft) x 0.45(psi/ft)= 5032 psi c%`� ZZ ��� 5032(psi) - [0.1(psi/ft)*11182(ft)]= 3914psi 3 psi) - [(2/3)*0.1(psi/ft)*11182(ft)]+[(1/3)*0.45(psi/ft)*11182(ft)]= 2609 psi Alternate Drilling MASP Summary: 1. MASP while drilling 6-1/8" production hole is governed by SIBHP minus 2/3 wellbore evacuated to gas from TD. 2. MASP during production mode is governed by SIBHP minus entire wellbore evacuated to gas from TD. Page 47 Revision 0 May, 2019 GP 53RD Drilling Procedure Rev 0 Ildcorp Alaska, LLC 32.0 Plot (NAD 27) (Governmental Sections) Legend ,- % -11GHL • Plan GP -53RD SHL ti -3-1! � BtiL X Plan GP-53RD_TPH� e41 �e k�l 1 GR.2;438HL ' Plan GP -53RD BHL ` t ` `' , ��'- • GP 51 BHL Other Surface Hak:Location •----- --- - --_ - - - t=ryE�'=Ife,P. Plan GP-�sRD SHL v -� Gni '- GR=?� 13 BHL • Other Bottom Hole Locaticr. � r - - - 'ViePa?hs p. .C17.� � IL:i � r / � •Lipjgg•i3 BHL �,a�c,,f.it, r 3344RO GP:" r / /� r_ PCC afiir„w 1 GP44-14 � i 1 � prp 1 1 GP-214RD .24.13 BML 6HLir` f : I r pig pr < p r r I I I I I I pr FP Gg�•�f23p8i r ,P5&=23 B#1L r� f r f fjr P O <p f O rian J' p GP13�CsRf��r- R(yL < •Y � _ p'J 0 GP42.2340 y �<• BHL _ _ - r « 2.23 BIdL •� - r ' GP -33=238 < r e� < f b r o r O 1 O 4 < • r F l 7 x-54 BHL s ADL37_ tel. 9 1 / I r fi, CiP-5-;RD_TPli t r 1 *z ADLO187611 � 1 Ap t GAc,91.2:RI} PB 1 I ' GR•aa•2fRl} P•:278 SHL P t ~BHL i I t I .24" 13RD2 1 Brll•c7r;�11j� 1 �, - GRANITE DINT UNITI' a 1 0 1 r P 1 O If O , O 1 O ( O t O 1 1 Plan GP -5. RL3_BHL I I ((.Y�__►YY__V...►�y.��y,,.�1Y.Y! GP'f33 PILOT C.�717a Ly:1 •�' I BHL ► ` V Y Y i Granite Point Unit Feet GP -53RD Well Alaska State Plane Zone 4. NAD27 Ild—p Al -L.. i.Ll: WPI 1 Map Date: 5,2012019 Page 48 Revision 0 May, 2019 ff Ililcorp Alaska, LLC GP 53RD Drilling Procedure Rev 0 33.0 Slot Diagram (As Built) (NAD 27) 11 12 PROTRACTED SECTION LINE NOT TO SCALE 14 13 i f 1 EI.+PTY EMPTY EMPTY 1305' ENL (NTS) EMPTY EMPTY EMPTY NOTES 1. BASIS OF HORIZONTAL CONTROL: NAD83 US FEET POSITION (EPOCH 2010) AND VERTICAL CONTROL (NAVD88) IS AN OPUS SOLUTION FROM NGS STATIONS TBON. TSEA. AND ANC2 TO ESTABLISH POINT #1100 THE ALASKA STATE PLANE COORDINATES NAD 63 ZONE 4 IN FEET ARE: N = 2544351.693 E = 1403394.313 ELEV. =115.958 (NAVD88) 2. SECTION LINES SHOWN ARE EXTENSIONS OF PROTRACTED VALUES. 3. COORDINATE CONVERSIONS (NAD83 - NAD27) WERE DONE USING CORPSCON SOFTWARE VERSION 6.0.1 CENTER LEG 4 LAT: 60'57'28.81798'N LON: 151'19'53.62548'W N: 2544501.349 E: 263337.774 ASP ZONE 4 NAD 27 2430' FNL 1305' FWL i f SCALE C 30 60 177— :EI. . 5/2//7 •.•' � EYOMEEltna.lTtPPwG: St1Ra:£Yaur!TESTWG P.o. eox.ea soio°TN.a m seam =E 1=ate= a 92 SECTION CORNER HILCORPALASKA, LLCRt— GRANITE GRANITE POINT PLATFORM WELL SLOTS COOK INLET ALASKA AS BUILT SURFACE LOCATION NAD 27 (FOR INFORMATION ONLY)`JE.T"° • , a 17 - c _7 (PROTRACTED) ED—NO +ao= �ocaTro" PROTRACTED SEC. 13 T1 ON R1 2W SEWARD MERIDIAN, ALASKA "rE, 1 a` 3 N:2546957.328 E: 262081.754 i CENTER LEG 2 LAT: 60' 5T 29.91087-N Z y LON: 151' 19'53.20585'W _ N: 2544611.886 W E: 263360.744 J ASP ZONE 4 NAD 27 U z 2319' FNL (n 1326' FWL ONOWELL6 i F OR SLOTS O 1326' ENL (NTS) OBSERVED Z CENTER LEG 1 LAT: 60'57'29.46354'N LON: 151° 19' 54.53958'W W Z N: 2544567. 808 J E: 263293.981 ASP ZONE 4 NAD 27 Z 2364'FNL EMPTY 12W FWL j—11 LIPTY W c 3-4RO2 12 21 W 1260 `1 ("'S) GRANITE POINT PLATFORM FW- 31.23 32.23 CENTER LEG 3 (J EMPTY ASBUILT WELL LOCATIONS LAT: 60'57'29.26234"N 3},aRD 1313 SECTION 13 T10N R12W P_ , 3+' uRar LON: 151' 19'52.28588'W F- td'a EMPTY N: 2544545.120 Q — ----- H-13RD+ E 263404.821 D_' 1371' FWL (NTS) ASP ZONE 4 NAD 27 CL 1a 2385 FNL 112a 1371' FWL EI.+PTY EMPTY EMPTY 1305' ENL (NTS) EMPTY EMPTY EMPTY NOTES 1. BASIS OF HORIZONTAL CONTROL: NAD83 US FEET POSITION (EPOCH 2010) AND VERTICAL CONTROL (NAVD88) IS AN OPUS SOLUTION FROM NGS STATIONS TBON. TSEA. AND ANC2 TO ESTABLISH POINT #1100 THE ALASKA STATE PLANE COORDINATES NAD 63 ZONE 4 IN FEET ARE: N = 2544351.693 E = 1403394.313 ELEV. =115.958 (NAVD88) 2. SECTION LINES SHOWN ARE EXTENSIONS OF PROTRACTED VALUES. 3. COORDINATE CONVERSIONS (NAD83 - NAD27) WERE DONE USING CORPSCON SOFTWARE VERSION 6.0.1 CENTER LEG 4 LAT: 60'57'28.81798'N LON: 151'19'53.62548'W N: 2544501.349 E: 263337.774 ASP ZONE 4 NAD 27 2430' FNL 1305' FWL i f SCALE C 30 60 177— :EI. . 5/2//7 •.•' � EYOMEEltna.lTtPPwG: St1Ra:£Yaur!TESTWG P.o. eox.ea soio°TN.a m seam =E 1=ate= a 92 Hilcorp Alaska, IAX HILCORPALASKA, LLCRt— GRANITE GRANITE POINT PLATFORM WELL SLOTS COOK INLET ALASKA AS BUILT SURFACE LOCATION NAD 27 (FOR INFORMATION ONLY)`JE.T"° • , a 17 - c _7 III— ED—NO +ao= �ocaTro" PROTRACTED SEC. 13 T1 ON R1 2W SEWARD MERIDIAN, ALASKA "rE, 1 a` 3 Page 49 Revision 0 May, 2019 Hilvaq, Alaska. LG: GP 53RD Drilling Procedure Rev 0 WELL I SLOT NORTHING NAD 27 EASTING LATITUDE (N) LONGITUDE (W) 60° 57'28.81798" CL LEG 3 2544545.120 263404.821 60° 57'29.26234" 151° 19'52.28588" 2544506.617 31-13 1 2544550.59 263401.139 60° 57'29.31546" 151° 19'52.36268" 2 22-13RD2 2 2544551.711 263405.531 60° 57'29.32737" 151° 19'52.27421" 151° 19'53.53143" MUCI-1 3 2544549.723 263409.592 60° 57'29.30862" 151° 19'52.19116" 60"57'28.82129" MUCI-2 4 2544545.606 263411.397 60° 57'29.26844" 151° 19'52.15293" 263342.958 32-13RD S 2544541.274 263410.117 60° 57'29.22553" 151° 19'52.17707" LEG 3 24-13RD 6 2544538.84 263406.528 60° 57'29.20086" 151° 19'52.24873" 42 -23RD 7 2544539.235 263401.999 60° 57'29.20384" 151° 19'52.34061" 151" 19'53.74816" 43063 8 2544542.441 263398.892 60° 57'29.23478" 151° 19'S2.40484" 60" 57'28.83376" 11-13RD 9 2544546.905 263398.51 60° 57' 29.27865" 1519 19'52.41439" 263338.980 EMPTY 10 2544543.272 263406.149 60° 57'29.24441" 151° 19'52.25823" 2544501.035 0 P 11 2544545.15 263402.616 60° 57'29.26219" 151° 19'52.33053"1 12 2544547.233 263405.593160- S7'29.28330" 151° 19'S2.27110., e �.a .EEn,Na :sur>iNa r svm�Ernr„ rEsnf:;, ao Eox xoe soinoTfu uc ssaev -c.cE rxrf ze>azfe csx: fsarf zas.L-c3 Ef.Wi 5M.k4xNEQlACtwNECa CCM Ililcvirp Alaska. LI.(: HILCORP ALASKA. LLC GRANITE POINT PLATFORM WELL SLOTS COOK INLET ALASKA AS BUILT SURFACE LOCATION NAD 27 (FOR INFORMATION ONLY) PROTRACTED SEC. 13 T1 ON R1 2W SEWARD MERIDIAN, ALASKA ORA'h'N 8Y fCE SCPlE' Y. PFa.Ec*Na scox Nc ,e.cs MEE- 3 -= 3 CL LEG 4 2544501.349 263337.774 60° 57'28.81798" 151° 19'53.62548" EMPTY 1 2544506.617 263333.993 60° 57'28.86909" 151° 19'53.70421" EMPTY 2 2544507.720 263338.358 60° 57'28.88083" 151° 19'5161627' 54 3 2544505.736 263342.508 60° 57'28.86212" 151° 19'53.53143" 55 4 2544501.552 263344.322 60"57'28.82129" 151°19'53.49299" LEG 4 53 ® 5 2544497.344 263342.958 60°57'28.77958" 151°19'53.51888" 52 6 2544494.923 263339.453 60° 57' 28.75505" 151" 19'53.58885" EMPTY 7 2544495.296 263334.763 60° 57'28,75778" 151° 19'5168396" EMPTY 8 2544498.575 263331.660 60° 57'28.78944" 151" 19'53.74816" EMPTY 9 2544503.081 263331.389 60" 57'28.83376" 151" 19'53.75548" EMPTY 10 2544499.473 263338.980 60° 57'28.79975" 151° 19'5160030" EMPTY 11 2544501.035 263335.567 60° 57' 28.81445" 151" 19'53.67005" EMPTY 12 2544503.340 263338.779 60" 57'28.83779" 151" 19'53.60597.. e �.a .EEn,Na :sur>iNa r svm�Ernr„ rEsnf:;, ao Eox xoe soinoTfu uc ssaev -c.cE rxrf ze>azfe csx: fsarf zas.L-c3 Ef.Wi 5M.k4xNEQlACtwNECa CCM Ililcvirp Alaska. LI.(: HILCORP ALASKA. LLC GRANITE POINT PLATFORM WELL SLOTS COOK INLET ALASKA AS BUILT SURFACE LOCATION NAD 27 (FOR INFORMATION ONLY) PROTRACTED SEC. 13 T1 ON R1 2W SEWARD MERIDIAN, ALASKA ORA'h'N 8Y fCE SCPlE' Y. PFa.Ec*Na scox Nc ,e.cs MEE- 3 -= 3 GP 53RD Drilling Procedure Rev 0 Hilcnrp Alaska. LLC 34.0 Directional Program (wpll) Page 51 Revision 0 May, 2019 Hilcorp Alaska, LLC Location: Cook Inlet, Alaska (Offshore) Slot: slot #4-5 Well 53 New Field: Granite Point Field Well: GP53RD Facilit : GRANITE POINT Pla form Wellbor GP -53RD BA(ER HUGHES a GE company Plot reference wellpath is GP-53RD_wp12 Grid System: NAD27 / TM Alaska SP, Zone 4 (5004), US feet True vertical depths are referenced to GP 53RD Planned RKB=156.22' (RKB) North Reference: True north Measured depths are referenced to GP 53RD Planned RKB=156.22' (RKB) Scale: True distance GP 53RD Planned RKB=1 56.22'(RKB) to mean sea level: 156.22 feet Depths are in feet mean sea level to Mud line (At Slot: slot #4-5 Well 53 New): 0 feet Created by: uldcard on 2019-05-20 Coordinates are in feet referenced to Slot Database: WA ANC Defn 1250 3750 r 5000 (0 U j 6250 m H 7500 11250 1250Q A, L 13.375in Casing 0 9.625in Casing End of 3D ArDc �4.00./100ft Tie On End of 3D Arc (XS) End of Tangent (XS) 4.00°/100ft .0 71n Casing GP-53RD_T01t, GP -53RD T02 �ac9e GP-53RD_TO3 C16otg9110 '.nd of 3D Arc 6.00°/100ft End of 3D Are GP -53RD -1 04 cSin Casing End of Tangent A ire �O 1 I 1 1 1 1 1 1 1 0 1250 2500 3750 5000 6250 7500 8750 Vertical Section (ft) soak,fooh-2500 Azimuth 150.00° with reference 0.00 N, 0.00 E Easting (ft) -2250 -1500 -750 0 slot #4-5 Well 53 New 13.375in Casingd j 9.625in Casing A I L 7in Casing d -- GP-53RD_T01 GP -53RD T03 750 0 -750 -1500 -3000 Z -3750 0 s cn - 450 0 -5250 -6000 Well Profile Data -6750 \Casing Desi2n Comment MD ft Inc Az TVD ft Local N ft Local E ft DLS °/100ft VS ft Tie On 4731.22 42.300 184.000 4233.69 -1529.63 -20.13 0.81 1314.64 End of 3D Arc 4792.00 42.660 183.840 4278.52 -1570.58 -22.93 0.62 1348.70 End of 3D Arc XS 5521.20 27.252 228.835 4883.90 -1934.90 -168.32 4.00 1591.51 End of Tangent XS 9847.63 27.252 228.835 8730.10 -3238.91 -1659.72 0.00 1975.12 End of 3D Arc XS 10979.97 65.000 191.000 9513.96 -3950.72 -1969.08 4.00 2436.89 End of Tan ant XS 11079.97 65.000 191.000 9556.22 -4039.69 -1986.37 0.00 2505.29 End of 3D no S 11385.80 80.269 190.137 9647.23 -4325.79 -2039.66 5.00 2726.42 End of Tangent S 11427.47 80.269 190.137 9654.27 -4366.22 -2046.89 0.00 2757.81 Endof 3D Arc S 12025.04 75.000 160.000 9785.08 -4940.37 -1998.92 5.00 3279.03 End of 3D Arc S 12266.61 69.622 148.641 9858.67 -5147.46 -1899.72 5.00 3507.97 End of Tangent S 12532.39 69.622 148.641 9951.23 -5360.22 -1770.06 0.00 3757.05 End of 3D Arc S 12697.32 77.400 151.500 9998.01 -5497.19 -1691.30 5.00 3915.06 End of Tan ent 14327.32 77.400 151.500 10353.58 -6895.16 -932.26 0.00 5505.26 End of 3D Arc 14808.72 63.000 152.000 10516.22 -7293.06 -718.36 2.99 5956.79 End of 3D Arc 15434.07 25.496 152.000 10956.22 -7671.49 -517.15 6.00 6385.13 End of Tangent 15684.07 25.496 152.000 11181.87 -7766.50 -466.63 0.00 6492.68 1250 3750 r 5000 (0 U j 6250 m H 7500 11250 1250Q A, L 13.375in Casing 0 9.625in Casing End of 3D ArDc �4.00./100ft Tie On End of 3D Arc (XS) End of Tangent (XS) 4.00°/100ft .0 71n Casing GP-53RD_T01t, GP -53RD T02 �ac9e GP-53RD_TO3 C16otg9110 '.nd of 3D Arc 6.00°/100ft End of 3D Are GP -53RD -1 04 cSin Casing End of Tangent A ire �O 1 I 1 1 1 1 1 1 1 0 1250 2500 3750 5000 6250 7500 8750 Vertical Section (ft) soak,fooh-2500 Azimuth 150.00° with reference 0.00 N, 0.00 E Easting (ft) -2250 -1500 -750 0 slot #4-5 Well 53 New 13.375in Casingd j 9.625in Casing A I L 7in Casing d -- GP-53RD_T01 GP -53RD T03 750 0 -750 -1500 -3000 Z -3750 0 s cn - 450 0 -5250 -6000 -6750 \Casing -7500 GP-53RD_T04 c q Pa -8250 Clearance Summary Report GP-53RD_wp12-C1osest Approach Page 1 of 4 TGHER 0 ES GE company •• Operator Hilcorp Alaska, LLC Slot slot #4-5 Well 53 New Area Cook Inlet, Alaska (Offshore) Well GP53RD Field Granite Point Field Wellbore GP -53RD Facility GRANITE POINT Platform Sidetrack from GSS<83-990'>MWD<1145-139505 at 4731.22M •• Projection System NAD27 / TM Alaska SP, Zone 4 (5004), US feet Software System WellArchitectO 5.1 North Reference True User Ulricard Scale 0.999964 Report Generated 05/20/19 at 12:51 Convergence at slot 1.16° West Database WA ANC Defn •• Ellipse Confidence Limit 3.00 Std Dev Ellipse Start MD 41.22ft Surface Position Uncertainty Local coordinates North[ft] East[ft] Grid coordinates Easting[US ft] Northing[US ft] Geographic coordinates Latitude Longitude Slot Location -2433.66 1310.83 263342.96 2544497.34 60°57'28.780"N 151°19'53.519"W Facility Reference Pt 262082.17 2546957.18 60°57'52.745"N 151°20'20.066"W Field Reference Pt 1 267571.89 2557407.98 60°59'36.731"N 151'18'33.112"W IWELLPATH DATUM Ellipse Confidence Limit 3.00 Std Dev Ellipse Start MD 41.22ft Surface Position Uncertainty Calculation method Minimum Curvature GP 53RD Planned RKB=156.22' (RKB) to 156.22ft Slot Surface Uncertainty 1SD Horizontal 2.000ft Vertical Facility Vertical Datum Facility Surface Uncertainty 1SD Horizontal 50.000ft Horizontal Reference Pt Slot GP 53RD Planned RKB=156.22' (RKB) to 156.22ft mean sea level Vertical Reference Pt GP 53RD Planned GP 53RD Planned RKB=156.22' (RKB) to 156.22ft RKB=156.22' (RKB) Mud Line at Slot (slot #4-5 Well 53 New) MD Reference Pt GP 53RD Planned RKB=156.22' (RKB) Field Vertical Reference mean sea level POSITIONAL UNCERTAINTY CALCULATION SETTINGS Ellipse Confidence Limit 3.00 Std Dev Ellipse Start MD 41.22ft Surface Position Uncertainty included Declination 15.56° East of TN Di An le 73.80° Mag Field Strength 55330 nT Slot Surface Uncertainty 1SD Horizontal 2.000ft Vertical 1.000ft Facility Surface Uncertainty 1SD Horizontal 50.000ft Vertical 5.000ft Positional Uncertainty values in the WELLPATH DATA table are the projection of the ellipsoid of uncertainty onto the vertical and horizontal lanes Clearance Summary Report GP-53RD_wp12-C1osest Approach Page 2 of 4 BER BA 0 GE company IDENTIFICATION]REFERENCE WELLPATH Start MD Operator Hilcorp Alaska, LLC Slot slot #4-5 Well 53 New Area Cook Inlet, Alaska (Offshore) Well GP53RD Field Granite Point Field Wellbore GP -53RD Facility GRANITE POINT Platform Sidetrack from GSS<83-990'>MWD<1145-139505 at 4731.22 MD ANTI -COLLISION RULE Rule Name Hilcorp HSE Stop Drilling ACR Rule Based On Ratio Plane of Rule Closest Approach Threshold Value 1.00 Include Casing & Hole Size yes Apply Cone of Safety no HOLE & CASING SECTIONS - Ref Wellbore: GP -53RD Ref Wellpath: GP-53RD_wp12 Start MD End MD String/Diameter Start MD End MD Interval Start TVD End TVD Start N/S Start E/W I End N/S End EM GSS <83-9905 Ift] ft ft ft ft ft ft ft ft 17.5in Open Hole 0.00 1072.00 1072.00 0.00 1071.56 0.00 0.00 -24.64 -0.82 13.375in Casing 0.00 1072.00 1072.00 0.00 1071.56 0.00 0.00 -24.64 -0.82 12.25in Open Hale 1072.00 4592.00 3520.00 1071.56 4130.03 -24.64 -0.82 -1436.88 -14.46 9.625in Casing 1072.00 4592.00 3520.00 1071.56 4130.03 -24.64 -0.82 -1436.88 -14.46 8.375in Open Hole 4592.00 10891.00 6299.00 4130.03 9474.08 -1436.88 -14.46 -3872.88 -1952.84 7in Casing 4592.00 10891.00 6299.00 4130.03 9474.08 -1436.88 -14.46 -3872.88 -1952.84 6.125in Open Hole 10891.00 15684.07 4793.07 9474.08 11181.87 -3872.88 -1952.84 -7766.50 -466.63 5in Casing 10891.00 15684.07 4793.07 9474.08 11181.87 -3872.88 -1952.84 -7766.50 -466.63 SURVEY PROGRAM - Ref Wellbore: GP -53RD Ref Wellpath: GP-53RD_wp12 Start MD End MD Positional Uncertainty Model _T Log Name/Comment Wellbore Ift] Ift] 41.22 1031.22 Generic gyro - continuous (Drillpipe, Single -Shot) GSS <83-9905 GP53 1031.22 4731.22 BHI MTC (Collar, pre -2000) (Standard) MWD <1145 - 139505 GP53 4731.22 15684.07 BHI OnTrak (Standard) MWD <4792 - 15683'> GP -53RD Clearance Summary Report GP-53RD_wp12-C1osest Approach Page 3 of 4 BER BA 0 GE company CALCULATION RANGE & CUTOFF From: 41.22ft MD To: 15684.07ft MD C -C Cutoff: (none) OFFSET WELL CLEARANCE SUMMARY (40 Offset Wellpaths selected) Ratios are calculated in Closest Approach plane Operator Hilcorp Alaska, LLC Slot slot #4-5 Well 53 New Area Cook Inlet, Alaska (Offshore) Well GP53RD Field Granite Point Field Wellbore GP -53RD Facility GRANITE POINT Platform Sidetrack from GSS<83-990'>MWD<1145-139505 at 4731.22 MD CALCULATION RANGE & CUTOFF From: 41.22ft MD To: 15684.07ft MD C -C Cutoff: (none) OFFSET WELL CLEARANCE SUMMARY (40 Offset Wellpaths selected) Ratios are calculated in Closest Approach plane C -C Clearance Distance ACR Separation Ratio Ref Min C -C Diverging Ref MD of Min Min Ratio ACR Offset Offset Offset Offset Offset MD Clear Dist from MD Min Ratio Ratio Dvrg from Status Facility Slot Well Wellbore Wellpath ft ft ft ft ft GRANITE slot #4_5 POINT Platform Well 53 GP53 GP53 GSS<83-990'>MWD<1145-13950'> 4731.22 0.00 15141.22 4733.15 -1.70 15041.22 FAIL New GRANITE slot #4-5 GP53 POINT Platform New 53 St2 GP53 St2 MWD <13369'- 16657'> 4731.22 0.00 15041.22 4733.15 -1.70 15031.22 FAIL GRANITE slot #4-5 GP53 POINT Platform New 53 St1 GP53 St1 MWD <13881-14556'> 4731.22 0.00 15141.22 4733.15 -1.70 15041.22 FAIL GRANITE slot #1-5 GP32- GP32- GMS <8900-11986'> 11673.69 251.64 11673.69 11752.85 0.77 11752.85 FAIL POINT Platform 23Rd 23Rd GRANITE slot#1-5 GP32-23 GP32-23 GMS <41-12000'> 11425.94 323.92 11425.94 11485.83 0.87 11485.83 FAIL POINT Platform GRANITE POINT Platform slot#1-5 GP33-23 GP33-23 MSS <8630-113765 4731.22 551.46 11741.22 11980.07 1.89 12041.22 PASS GRANITE POINT Platform slot #3-8 GP12-24 GP11-24 GMS <1 00-1 1800'> 4731.22 233.68 5741.22 6441.22 2.69 15341.22 PASS GRANITE slot #4-3 GP54 POINT Platform New 54 St1 GP54 St1 MWD <11289 - 14086'> 4731.22 790.05 11831.22 12187.98 3.00 15041.22 PASS GRANITE slot #4-3 POINT Platform New 54 GP54 GP54 GSS<0-1091>MWD<1130-11944'> 4731.22 790.05 11831.22 12196.64 3.01 12941.22 PASS GRANITE POINT Platform slot#1-9 GP31-23 GP31-23 GMS <75-112005 9918.68 1033.51 9918.68 10241.22 3.50 11241.22 PASS GRANITE POINT Platform slot #1-4 GP12-24 GP12-24 GMS <100-12200'> 4731.22 540.79 12697.32 12341.22 3.78 15341.22 PASS GRANITE slot #3-7 GP42- GP42- MWD <7367 - 13940'> 11531.22 1076.47 11531.22 11741.22 5.06 15441.22 PASS POINT Platform 23RD 23RD GRANITE POINT Platform slot#1-7 GP44-14 GP44-14 GMS <100-10850'> 4731.22 998.00 6641.22 9336.22 6.97 15341.22 PASS GRANITE slot #4-4 POINT Platform New 55 GP55 GP55 GSS<90-1524'>MWD<1594-50115 4731.22 951.29 4731.22 4841.22 8.66 15341.22 PASS GRANITE POINT Platform slot#1-8 GP33-14 GP33-14 GMS <100-114735 4731.22 1606.20 4731.22 10141.22 9.35 15341.22 PASS GRANITE GP33- GP33- POINT Platform slot #1-8 14RD 14RD GMS <9200-11410'> 4731.22 1606.20 4731.22 9336.23 9.39 15341.22 PASS GRANITE POINT Platform slot #3-6 GP24-13 GP24-13 GMS <100-105605 4731.22 1023.96 4731.22 4741.22 11.96 15541.22 PASS GRANITE slot #3-6 GP24- GP24- GMS <9700-10640'> 4731.22 1023.96 4731.22 4741.22 11.96 15541.22 PASS POINT Platform 13RD 13RD GRANITE GMS<50-225'>MSS<518- POINT Platform slot #3-7 GP42-23 GP42-23 9775GMS<1000-145445 4731.22 1188.54 11841.22 13741.22 13.48 15541.22 PASS GRANITE POINT Platform slot #1-6 GP13-13 GP13-13 GMS <75-105725 4731.22 1533.02 4731.22 9336.22 15.86 15641.22 PASS slot #3-5 GP33-13 GP33-13 GMS <2700-11450'> 4731.22 1263.29 4731.22 4741.22 19.73 15641.22 PASS OFFSET WELL CLEARANCE SUMMARY (40 Offset Wellpaths selected) Ratios are calculated in Closest Approach plane C-C Clearance Distance ACR Separation Ratio Ref Min C-C Diverging Ref MD of Min Min Ratio ACR Offset Offset Offset Offset Offset MD Clear Dist from MD Min Ratio Ratio Dvrg from Status FacilitV Slot Well Wellbore Wellpath Ifti rft1ft ft ft GRANITE POINT Platform GRANITE slot #3-11 GP50 GP50 PG IVIS <100-12163'> 4731.22 1565.19 4731.22 9336.22 20.60 15641.22 PASS POINT Platform GRANITE slot #3-12 GP51 GP51 PGMS<100-11839'> 4731.22 1622.05 4731.22 9336.22 0.69 15631.22 PASS POINT Platform GRANITE slot #1-1 GP31- GP31 GMS <0-11011'> 4731.22 2351.44 4731.22 9336.22 20.73 15541.22 PASS POINT Platform 14RD1 14RD1 RANITE F slot #1-1 GP31- GP31 GMS <4900-10191'> 4731.22 2351.44 4731.22 9336.22 1.66 15341.22 PASS OINT Platform 14RD2 14RD2 Clearance Summary Report GP-53RD_wp12-C1osest Approach Page 4 of 4 BER BA GE company CALCULATION RANGE & CUTOFF From: 41.22ft MD To: 15684.07ft MD C -C Cutoff: (none) OFFSET WELL CLEARANCE SUMMARY (40 Offset Wellpaths selected) Ratios are calculated in Closest Approach plane Operator Hilcorp Alaska, LLC Slot slot #4-5 Well 53 New Area Cook Inlet, Alaska (Offshore) Well GP53RD Field Granite Point Field Wellbore GP -53RD Facility GRANITE POINT Platform Sidetrack from GSS<83-990'>MWD<1145-139505 at 4731.22 MD CALCULATION RANGE & CUTOFF From: 41.22ft MD To: 15684.07ft MD C -C Cutoff: (none) OFFSET WELL CLEARANCE SUMMARY (40 Offset Wellpaths selected) Ratios are calculated in Closest Approach plane C -C Clearance Distance ACR Separation Ratio Ref Min C -C Diverging Ref MD of Min Min Ratio ACR Offset Offset Offset Offset Offset MD Clear Dist from MD Min Ratio Ratio jDvrgfrom Status Facility Slot Well Wellbore Wellpath ft ft ft ft ft GRANITE POINT slot #1-1 GP31-14 GP31-14 MSS <4856 - 8876'> 4731.22 2351.44 4731.22 9336.23 23.11 15341.22 PASS Platform GRANITE GP 32- GP32- POINT slot #3-5 MWD <8478 - 12563'> 4731.22 1585.58 4731.22 15248.78 25.18 15641.22 PASS Platform 13RD 13RD GRANITE GP11- GP11- POINT slot #3-9 PGMS <100-11560'> 4731.22 1814.96 4731.22 9336.22 25.41 15684.07 PASS Platform 13RD 13RD GRANITE POINT slot #1-2 GP44-11 GP44-11 GMS<75-306'>MSS<337- 4731.22 2499.43 4731.22 9336.22 27.17 15684.07 PASS 810'>GMS<900-12471'> Platform GRANITE POINT slot #3-2 GP22-13 GP22-13 GCT Gyro <0-7002'>GMS <7100 - 4731.22 1834.90 4731.22 9336.22 27.34 15641.22 PASS 10225'> Platform GRANITE MUC-1- P0INT slot #3-4 MUC-1-02 GMS <100-10830'> 4731.22 2102.47 4731.22 9336.22 27.60 15341.22 PASS Platform 02 GRANITE GP32- GP32- POINT slot #3-5 MWD <9437 - 10270'> 4731.22 1585.58 4731.22 9336.22 28.98 15641.22 PASS Platform 13RD PB 13RD PB GRANITE POINT slot #3-5 GP32-13 GP32-13 PGMS<0-8583'>GMS<8605 - 4731.22 1585.58 4731.22 9336.22 28.98 15641.22 PASS Platform 10200'> GRANITE GP22- GP22- POINT slot #3-2 MWD <11395-13934'> 4731.22 1834.90 4731.22 9336.22 29.12 15641.22 PASS Platform 13RD3 13RD3 GRANITE GP22- GP22- POINT slot #3-2 MWD <11453 - 13821'> 4731.22 1834.90 4731.22 9336.22 29.12 15641.22 PASS 13RD2 13RD2 Platform GRANITE GP22- GP22- POINT slot #3-2 MWD <6738 - 120365 4731.22 1834.90 4731.22 9336.22 29.12 15641.22 PASS Platform 13RD1 13RD1 GRANITE POINT slot #3-9 GP11-13 GP11-13 GMS<350-11653'>PG MS<4025- 4731.22 1814.96 4731.22 9336.22 29.51 15641.22 PASS Platform 79505GMS<8000-116535 GRANITE POINT slot #3-1 GP31-13 GP31-13 GMS <100-108745 4731.22 2208.25 4731.22 9336.22 30.59 15641.22 PASS Platform GRANITE POINT slot #3-3 MUC-1- MUC-1-01 GMS<75-11150'>MSS<12625- 4731.22 2614.62 4731.22 9336.22 33.20 15684.07 PASS Platform 01 157155 GRANITE slot #4-6 POINT Well 52 GP52 GP52 RGSS <0-1122'> 4731.22 3424.87 4731.22 9336.22 113.31 15541.22 PASS Platform New liilcurp ?1la�ska. LLC RKB to MLLW 114.75; RKB to Mudline =189.75 33" 1 26" PROPOSED SCHEMATIC Granite Point Field Well: GP 53 Last Completed: 08/29/1997 PTD: 196-014 API: 50-733-20471-00 CASING DETAIL Size Wt Grade Conn ID Top Btm 33" Outside Driven Conductor Welded FT 47' 229' 26" Inside Driven Conductor Welded C-5 Sand 47' 294' 13-3/8" 68 K-55 BTC 12.415" 47' 1,031' 08/14/97 47 L-80 BTC 8.681" 46' 73' 9-5/8" 53.5 P-110 BTC 8.535" 73' 1 4,551' 29 P-110 TKC-BTC 1 6.184" 45' 6,989' 7„ 9 L 80 I TKC-BTC 6.184" 6,989' 13,323' 5" S L-80 SC-TKC-BTC 1 4.408" 12,909' 16,634' 5- 1 ;A ug,' hoc GBP d- 4850' �f TOC @ - TUBING DETAIL JEWELRY DETAIL () No Depth (MD) Depth (TVD) ID OD Item Zone Top (MD) Btm (MD) Top (TVD) 7' FT Date �r C-5 13,339' 5 10,479' C-5 Sand 1,161' 08/15/97 Isolated C-5 14,590' 14,595' 10,743' 10,744' S' 08/14/97 Squeezed PBTD:14,530' TD: 16,657 16,400' 10,817' 11,020' 1,650' 08/04/97 Squeezed 4 12,906' 10,263' 3.880" 3.880" 3.880" 4.770" 5.900" 6.000" HES Seal Bore Extension Bottom Sub Halliburton AT Versatrieve Packer 5 14,530' 10,735' EZSV Cement Retainer 6 15,112' 10,801' #� EZSV Cement Retainer G F'y�r-?' q� 31�-�/�� Updated By: M1Q 02/07/19 PERFORATION DETAIL 12'9N Zone Top (MD) Btm (MD) Top (TVD) 7' FT Date �r C-5 13,339' 5 10,479' C-5 Sand 1,161' 08/15/97 Isolated C-5 14,590' 14,595' 10,743' 10,744' S' 08/14/97 Squeezed PBTD:14,530' TD: 16,657 31�-�/�� Updated By: M1Q 02/07/19 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status C-5 13,339' 14,500' 10,479' 10,730' 1,161' 08/15/97 Isolated C-5 14,590' 14,595' 10,743' 10,744' S' 08/14/97 Squeezed C-5 15,250' 16,400' 10,817' 11,020' 1,650' 08/04/97 Squeezed 31�-�/�� Updated By: M1Q 02/07/19 Schwartz, Guy L (CED) From: Monty Myers <mmyers@hilcorp.com> Sent: Tuesday, lune 11, 2019 10:41 AM To: Schwartz, Guy L (CED); Regg, James B (CED) Cc: Paul Mazzolini; Davies, Stephen F (CED) Subject: RE: [EXTERNAL] GP -53RD Drilling permit PTD 219-079 Attachments: 2018_GRANITEPOINT_GPTF_MLLW_1 x1_0_110_1.tif Follow Up Flag: Follow up Flag Status: Flagged Guy, The answers to your questions are below in red. Thank you! Let me know if you have any additional questions. Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Wednesday, June 5, 2019 8:59 AM To: Monty Myers <mmyers@hilcorp.com> Cc: Paul Mazzolini <pmazzolini@hilcorp.com>; Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: [EXTERNAL] GP -53RD Drilling permit PTD 219-079 Monty, Had some questions regarding GP -53RD 1) Plan on testing the 9 5/8" to 2500 psi before drillout with the 8 3/8" bit. I believe the P & A sundry only required 1500 psi. Your final casing test for the well will be 2500 psi. Will make this change in the wellplan 2) The sea bed scan will need to be done before spotting the jackup rig. This data must be forwarded to the AOGCC as soon as you have it. See 20 AAC25.061(b). It should be included with the PTD application. Attached is the most current seabed scan. We will perform another one at the site where the rig will sit about 2 weeks from the rig showing up 3) Your alternate calc request for MASP is confusing . What I get is a BHP of 5032 psi and MASP of 2609 psi if 2/3 mud column. Your variance request does not reflect this. Looks like we are using different gradients. I will change mine to reflect what you have. 4) The Spartan 151 rig will be on a 7 day BOPE test cycle for at least the first well. Also, will need to have a rig inspection before you start .. this will likely be during the first BOPE test. Are there any other Coast Guard inspections you will need before the rig is moved to location? All the coast guard inspections are complete to my knowledge. As per our conversation we will shoot to test BOP's on a 7 day cycle not to exceed 14 days as per regulation. You mentioned if we are drilling ahead, and the 7 days come up that we don't have to trip just for testing BOPE. If this is ok by you and Jim Regg, we will aim to test every 7 days with a hardline of not exceeding 14 days between testing. 5) 1 am curious why you didn't run the 7" liner back to the wellhead since the wellhead was already setup up with a casing spool for it? The main reason we didn't run the 7" back to surface is because the lead time for Kvaerner parts is 8 months. We simply didn't have time to get a tubing hanger made for the 7" on GP53. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.aov). The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: 2/9 - v 7 j' f Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD:���0,t POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -� from records, data and logs acquired for well name on pernmnit . The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool GRANITE PT, MIDDLE KENAI OIL - 280150 Date: Well Name: GRANITE POINT 53RD _ _ Program DEV _ Well bore seg ❑ PTD#:2190790 Company _HILCORP ALASKA LLC _ Initial Class/Type DEV/PEND GeoArea 820 Unit 00000 — On/Off Shore Off Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes Entire well lies within ADL 018761.- Adjacent state lease is also owned by-Hilcorp. 3 Unique well name and number Yes 4 Well located in a defined pool Yes Granite Point Middle Kenai Oil Pool - 280150 5 Well located proper distance from drilling unit boundary Yes Conservation Order No. 76A, issued May 20, 2019, governs_ Granite Point Middle Kenai Oil Pool. 6 Well located proper distance from other wells Yes Rule 2, CO 76A; No well spacing restrictions, except that no oil well shall be completed within 500' 7 Sufficient acreage available in drilling unit Yes of an exterior property line where ownership or landownership_ changes. As planned, well conforms 8 If deviated, is wellbore plat included Yes with spacing requirements of CO 76A '9 Operator only affected party Yes - 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order_ - Yes Appr Date 12 �13 Permit can be issued without administrative approval Yes Can permit be approved before 15 -day wait Yes SFD 5/22/2019 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA_ X15 All wells within 1/4 -mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.0300.1_.A),6,2.A-D) NA 18 Conductor string provided NA Engineering I19 Surface casing protects all known USDWs NA �20 CMT vol adequate to circulate on conductor & surf csg NA 21 CMT vol adequate to tie-in long string to surf csg Yes 22 CMT will cover all known productive horizons Yes 7" and 5" liners will -be fully cemented. - 23 Casing designs adequate for C, T, B & permafrost Yes BTC talcs supplied_. 24 Adequate tankage or reserve pit Yes - 25 If a re -drill, has_a 10-403 for abandonment been approved Yes 319-088 for P &_A 26 Adequate wellbore separation proposed Yes 27 If_diverter required, does it meet_ regulations NA Wellhead in place.. Will _u_se BOPE Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max form pressure = 5032 psi (8.6 ppg EMW) will drill with 9-10 ppg mud GLS 6/11/2019 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to _(put psig in comments)_ Yes MASP= 2609 psi ( will test BOPE to 3500 psi) using alt talc method. 31 Choke manifold complies w/API RP -53 (May 84) Yes 32 Work will occur without operation shutdown_ Yes need seabed scan done before setting jackup rig. 33 Is presence of 1-12S gas probable - No H2S not expectetd. 34 Mechanical condition of wells within AOR verified (For service well only) - NA I35 Permit can be issued w/o hydrogen sulfide measures Yes 1-12S is not expected. Spartan 151 has 1-12S sensors and alarms Geology 36 Data presented on potential overpressure zones Yes Planned drilling mud program appears adequate to control operator's forecast pressure gradient. Appr Date 37 Seismic analysis of shallow gas zones NA SFD 5/22/2019 Seabed condition survey (if off-shore)NA �38 39 Contact name/phone for weekly progress reports_ [exploratory only] NA_ — Geologic Date: Engineering Public Will be drilling using jackup Spartan 151 on the Granite Pt platform. Need seabed scan before placing rig on site. Will also Date Date Commissioner: nrs 6 ( ) u f9 Commissioner: A, A", Commissioner require AOGCC rig inspection before commencing operations. GIs L/1 a iq
