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HomeMy WebLinkAbout215-208DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well Name/No. CT 1 MD 7070 TVD 6943 Completion Date 2/19/2016 REQUIRED INFORMATION / Mud Log Yes ✓ Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879.20021-00-00 Completion Status P&A Samples Yes ✓ DATA INFORMATION List of Logs Obtained: SP, GR/Res, Caliper, Porosity, Mag Res, FormTest, Mudlog, Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No ED C 26951 Digital Data ED C 26951 Digital Data Log C 26951 Log Header Scans Log C 26952 Log Header Scans ED C 26952 Digital Data ED C 26952 Digital Data ED C 26952 Digital Data ED C 26952 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data Current Status P&A UIC No Directional Survey Yes Z (from Master Well Data/Logs) Interval OH / Start Stop CH Received Comments 3/18/2016 Electronic File: Caelus_CT-1_R1D2_FMI-SS- PPC_DownLog_MD_LW DDepth.dlis 3/18/2016 Electronic File: Caelus_CT-1_R1D2_FMI-SS- PPC_DownLog_ TVD_LW DDepth.dlis 0 0 2152080 CT 1 LOG HEADERS 0 0 2152080 CT 1 LOG HEADERS 3/18/2016 Electronic File: Caelus_CT-1_R1 D2_FMI-SS- PPC_Up_Bottom_MD_LW DDepth.dlis 3/18/2016 Electronic File: Cactus _CT-1_R1D2_FMI-SS- PPC_Up_Bottom_ TVD_LW DDepth.dlis 3/18/2016 Electronic File: Caelus_CT-1_R1 D2_FMI-SS- PPC_Up_ Top_MD_LW DDepth.dlis 3/18/2016 Electronic File: Caelus_CT-1_R1D2_FMI-SS- PPC_Up_ Top_TVD_LW DDepth.dlis 2376 6502 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1 R1D2_FMI-SS- PPC_ DownLog_MD_LW DDepth.las 2342 6375 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1 RID2 wnLog_ TVD_LW DDepth.las 4506 6614 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1 R1D2 FMI-SS- PPC_Up_ Bottom_MD_LW DDepth.las 4392 6487 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1 R1D2 FMI-SS- PPC_Up_Bottom_TVD_LW DDepth.las AOGCC Page I of 15 Monday, March 2. 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well Name/No. CT 1 Operator Caelus Energy Alaska Smith Bay, LLC API No. 50.879-20021-00.00 MD 7070 TVD 6943 Completion Date 2/19/2016 Completion Status PRA Current Status PRA UIC No ED C 26953 Digital Data 4042 4954 3/18/2016 Electronic Data Set, Filename: Caelus—CT---- 1 R1D2 FMI-SS- PPC_Up_Top_MD_LW DDepth.las ED C 26953 Digital Data 3943 4829 3/18/2016 Electronic Data Set, Filename: Caelus—CT- 1 R1D2 FMI-SS- PPC_Up_Top_TVD_LW DDepth.las ED C 26953 Digital Data 0 621 3/18/2016 Electronic Data Set, Filename: Caelus CT- 1_R1D3_LWD_ConPr_R04_StaD02_MDT_EDTA. las ED C 26953 Digital Data 0 3477 3/18/2016 Electronic Data Set, Filename: Caelus—CT- 1 R1D3_LWD_ConPr_R114_Sta003_MDT_EDTA. las ED C 26953 Digital Data 0 1698 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1 R1D3_LWD_ConPr_R04_Sta004_MDT_EDTA. las ED C 26953 Digital Data 0 3562 3/18/2016 Electronic Data Set, Filename: Caelus CT-! 1 R1D3_LWD_ConPr_R04_Sta005_MDT_EDTA. las ED C 26953 Digital Data 0 6805 3/18/2016 Electronic Data Set, Filename: Caelus CT- 1_R1D3_LWD_ConPr_R04_Stao06_MDT_EDTA. las ED C 26953 Digital Data 0 5397 3/18/2016 Electronic Data Set, Filename: Caelus—CT- 1 R1D3_LWD_ConPr_R04_Sta007_MDT_EDTA. las ED C 26953 Digital Data 0 2799 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1 R1D3 LWD ConPr R04 Sta006 MDT EDTA. las ED C 26953 Digital Data 0 1316 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1_Ri D3_LW D_ConPr_R04_Sta009_MDT_EDTA. las ED C 26953 Digital Data 0 1611 3/18/2016 Electronic Data Set, Filename: Caelus CT - 1 R1 D3_LWD_ConPr_R04_Sta010_MDT_EDTA. las ED C 26953 Digital Data 0 2729 3/18/2016 Electronic Data Set, Filename: Caelus CT - 1 R1D3_LWD_ConPr M R04_Sta011_DT_EDTA. las ED C 26953 Digital Data 0 16172 3/18/2016 Electronic Data Set, Filename: Caelus CT- I R1 D3_LWD_ConPr_R04_Sta012_MDT_EDTA. las AOGCC Page 2 of 15 Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well Name/No. CT 1 MD 7070 TVD 6943 Completion Date 2/19/2016 ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data ED C 26953 Digital Data Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879-20021-00-00 Completion Status P&A Current Status P&A UIC No 2429 6648 3/18/2016 Electronic Data Set, Filename: Caelus CT - 1_R1 D1_TCOM-CMR_Main_MD_LW DDepth.las 2400 6521 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1_R101_TCOM-CMR_Main_TVD_LW DDepth.las 6162 6592 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1 R1D1_TCOM-CMR_Repeat- Slow_MD_LW DDepth.las 6036 6466 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1_R1 D1_TCOM-CMRRepeat- Slow_TVD_LW DDepth.las_ 5546 6583 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1 R1D1 TCOM- CMR_Repeat_MD_LW DDepth.las 5428 6456 3/18/2016 Electronic Data Set, Filename: Caelus_CT- 1 R1D1 TCOM- CMR_Repeat_ TVD_LW DDepth.las 3/18/2016 Electronic File: Caelus CT - 1_R1 D2_FMI_20inMD_LW DDepth_FixHeader.Pd f 3/18/2016 Electronic File: Caelus_CT- 1_R1 D2_PPC _2inMD_LW DDepth_Rev2.Pdf 3/18/2016 Electronic File: Caelus CT- 1_R102_PPC_2inTVD_LW DDepth_Rev2.Pdf 3/18/2016 Electronic File: Caelus_CT- 1_R1 D2_PPC_5inMD_LW DDepth_Rev2.Pdf 3/18/2016 Electronic File: CaelusCT- 1_R1 D2_ PPC_5inTVD__LW DDepth_Rev2.Pdf 3/18/2016 Electronic File: Caelus_CT- 1_R1 D2_Sonic_2inMD_LW DDepth_Rev2.Pdf 3/18/2016 Electronic File: Caelus_CT- 1_R1 D2_Sonic_2inTVD_LW DDepth_Rev2.pdf 3/18/2016 Electronic File: Caelus_CT- 1_R1 D2_Sonic_5inMD_LW DDepth_Rev2.Pdf 3/18/2016 Electronic File: Caelus_CT- 1_R1 D2_Sonic_5inTVD_LW DOepth_Rev2.Pdf 3/18/2016 Electronic File: Caelus_CT- 1 R1D3 LWD ConPr R04 Sta002 MDT EDTA. dlis AOG('(Page 3 of 15 Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well Name/No. CT 1 Operator Caelus Energy Alaska Smith Bay, LLC API No. 50.879-20021-00-00 MD 7070 TVD 6943 Completion Date 2/19/2016 Completion Status P&A Current Status P&A UIC No 1 ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus CT - 1 R1 D3 LWO ConPr R04 Sta003 MDT EDTA. this ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1 R1D3_LWD_ConPr_R04_Sta004_MDT_EDTA. dlis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_R1D3_LWD_ConPr R04_Sta005_MDT_EDTA. dhis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1 R103_LWD_ConPr_R04_Sta006_MDT_EDTA. this ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_R1 D3_LW D_ ConPr_R04_Sta007_MDT_EDTA. dhis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus CT- E R1133 LWD ConPr R04 Sta008 MDT EDTA. this ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1 R1D3_LWD_ConPr_R04_Sta009_MDT_EDTA. this ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_R1D3_LWD_ConPr _R04_Sta010_MDT_EDTA. this ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_R1D3_LWD_ConPr _R04_Sta011_MDT _EDTA. dhis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1 R1D3_LWD_ConPr_R04_Sta012_MDT_EDTA. dhis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT1_R1 D3_ MDT_FullReport_LW DDepth _Revl.pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT1_R1 D3_MDT_Summary_LW DDepth _Revl.pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus CT-1_R1D4_XL- Rock_AIIStation-LW DOepth.dlis AOGCC Page 4 of 15 Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 312/2020 Permit to Drill 2152080 Well Name/No. CT 1 Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879-20021-00-00 MD 7070 TVD 6943 Completion Date 2/19/2016 Completion Status P&A Current Status P&A UIC No ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus CT -1 R1 D4_XL- Rock_Correlation t_LW DDepth.dlis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT-1_R1D4_XL- Rock_Correlation2_LW DOepth.dlis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus CT-1_R1D4_XL- Rock_FullReport_LW DDepth_Rev1. Pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT-1_R1D4_XL- Rock_Summary_LW DDepth_Rev1. Pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus CT -1 R1D1 TCOM- CMR_Main_ MD_LWDDepth.dlis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus CT -1 R1D1_TCOM- CMR_Main _TVD _L W DDepth.dlis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT-1_R1D1_TCOM- CMR_Repeat-Slow—MD _LWDDepth.dlis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus—CT-1—R1D1 TCOM- CMR_Repeat-Slow_ TVD_LWDDepth.dlis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus CT -1 R1 D1_TCOM- CMR_Repeat _MD_LWDDepth.dlis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus CT -1 R1 D1 ICOM- CMR_Repeat—TVD _LWDDepth.dlis ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus—CT- 1R101CMR _2inMD_LW DDepth_Rev2.Pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus _CT - 1_R1 D1_ CMR_2inTVD_LW DDepth_Rev2.Pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus—CT- 1—R1D1CMR _5inMD_LW DOepth_Rev2.Pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_R1D1_CMR_5inTVD_LWDDepth_Rev2.Pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus _CT -1_R1 D1_TCOM- CMR_2inMD_LWDDepth_Rev2.Pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus _CT -1_R1 D1_TCOM- CMR_2inTVD_LW DDepth_Rev2.Pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus _CT -1 R101_TCOM- CMR_5inMD_LW DDepth_Rev2.Pdf ED C 26953 Digital Data 3/18/2016 Electronic File: Caelus CT -1 R1D1 TCOM- CMR_5inTVD_LW DDepth_Rev2.Pdf AOGCC' Page 5 of IS Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well Name/No. CT 1 Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879-20021.00.00 MD 7070 TVD 6943 Completion Date 2/19/2016 Completion Status P&A Current Status P&A UIC No Log C 26953 Log Header Scans 0 0 2152080 CT 1 LOG HEADERS Log C 26954 Log Header Scans 0 0 2152080 CT 1 LOG HEADERS '. ED C 26954 Digital Data 1 1 3/18/2016 Electronic Data Set, Filename: CT- j 1_GeoTap_I DS_Pretest_No_1.las ED C 26954 Digital Data 5 7 3/18/2016 Electronic Data Set, Filename: C1 1_GeoTap_IDS_Pretest_No_10.Ias ED C 26954 Digital Data 7 7 3/18/2016 Electronic Data Set, Filename: CT - 1 _GeoTap_I DS_Pretest_No_11.las ED C 26954 Digital Data 7 8 3/18/2016 Electronic Data Set, Filename: CT- 1_GeoTap_IDS_Pretest_No_12.las li ED C 26954 Digital Data 1 1 3/18/2016 Electronic Data Set, Filename: CT- I _GeoTap_IDS _Pretest _No_2.Ias ED C 26954 Digital Data 3 3 3/18/2016 Electronic Data Set, Filename: CT- 1_GeoTap_IDS_Pretest_No_3.Ias ED C 26954 Digital Data 15 15 3/18/2016 Electronic Data Set, Filename: CT- 1_GeoTap_IDS_Pretest_No_4.Ias j ED C 26954 Digital Data 15 15 3/18/2016 Electronic Data Set, Filename: CT- 1_GeoTap_IDS_Pretest_No_5.1as ED C 26954 Digital Data 16 16 3/18/2016 Electronic Data Set, Filename: CT - 1 _GeoTap_I DS_Pretest_No_Was ED C 26954 Digital Data 16 17 3/18/2016 Electronic Data Set, Filename: CT- 1_GeoTap_IDS_Pretest_No_7.las ED C 26954 Digital Data 4 4 3/18/2016 Electronic Data Set, Filename: CT- 1_GeoTap_IDS_Pretest_No_8.las ED C 26954 Digital Data 4 4 3/18/2016 Electronic Data Set, Filename: CT- 1_GeoTap_IDS_Pretest_No_Was I ED C 26954 Digital Data 5 7 3/18/2016 Electronic Data Set, Filename: CT - 1 _GeoTap_I DS_Pumpout_Test_No_10.1as ED C 26954 Digital Data 2571 6518 3/18/2016 Electronic Data Set, Filename: CT-1_MRIL- WD.las ED C 26954 Digital Data 0 7070 3/18/2016 Electronic Data Set, Filename: CT-1_TC.las ED C 26954 Digital Data 232 7036 3/18/2016 Electronic Data Set, Filename: CT-1_XBAT.las ED C 26954 Digital Data 2532 7037 3/18/2016 Electronic Data Set, Filename: CT-1_XCAL.las ED C 26954 Digital Data 3/18/2016 Electronic File: CT-1_Run0300_GeoTap IDS report _v2.pdf AOGCC Page 6 of 15 Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 312/2020 Permit to Drill 2152080 Well Name/No. CT 1 Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-079-20021-00-00 MD 7070 TVD 6943 Completion Date 2/19/2016 Completion Status P&A ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data ED C 26954 Digital Data AOGCC' Page 7 of 15 Current Status P&A UIC No 3/18/2016 Electronic File: Caelus_CT- 1 _2in_MD_Triple_Com bo.cgm 3/18/2016 Electronic File: Caelus_CT- 1 _2in_MD_Triple_Combo_MRI L.cgm 3/18/2016 Electronic File: Caelus CT- 1_2in_MD_Triple _Combo_XBAT.cgm 3/18/2016 Electronic File: Caelus _CT-1_21n_MD_XCAL.cgm 3/18/2016 Electronic File: Caelus_CT- 1_2in_TVD _Triple _Combo.cgm 3/18/2016 Electronic File: Caelus_CT- 1_2in_TVD_Triple _Combo_MRIL.cgm 3/18/2016 Electronic File: Caelus_CT- 1_2in_TVD_Triple_Combo_XBAT.cgm 3/18/2016 Electronic File: Caelus _CT - 1 _5in_MD_Triple_Com bo. cgm 3/18/2016 Electronic File: Caelus _CT- 1_5in_MD_Triple _Combo_MRIL.cgm 3/18/2016 Electronic File: Caelus CT- 1_5in_MD_Triple_Combo_XBAT.cgm 3/18/2016 Electronic File: Caelus_CT-1_5in_MD_XCAL.cgm. 3/18/2016 Electronic File: Caelus_CT- 1_5in_TVD_Triple_Combo.cgm 3/18/2016 Electronic File: Caelus_CT- 1_5in_TVD _Triple _Combo _MRI L.cgm 3/18/2016 Electronic File: Caelus_CT- 1_5in_TVD _Triple _Combo _XBAT.cgm 3/18/2016 Electronic File: Caelus CT- 1_GeoTap_IDS_Pretests.cgm 3/18/2016 Electronic File: Caelus _CT- 1_GeoTap_IDS_Pumpout.cgm 3/18/2016 Electronic File: Caelus CT- 1_2in_MD_Triple_Combo.emz 3/18/2016 Electronic File: Caelus CT- 1_2in_MD_Triple_Combo_MRIL.emz 3/18/2016 Electronic File: Caelus_CT- 1_2i n_MD_Tdple_Combo_XBAT.emz Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well Name/No. CT 1 Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879-20021-00-00 MD 7070 TVD 6943 Completion Date 2/19/2016 Completion Status P&A Current Status P&A UIC No ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT-1_2in_MD_XCAL.emf ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_2in_TVD_Triple_Combo.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_2in_TVD_Triple _Combo_MRIL.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_2in_T V D_Triple_Combo_XBAT.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_5in_MD_Triple_Combo.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1 _5in_MD_Triple_Combo_MRI L.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1 _5in_MD_THple_Combo_XBAT.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT-1_5in_MD_XCAL.emf ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_5in_TVD_Triple _Combo.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_5in_TVD_Triple_Combo _MRIL.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1 _5in_TVD_Triple Combo—XBAT.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_GeoTap_I DS_Pretests.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_GeoTap_IDS_Pumpout.emz ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_2in_MD_Triple_Combo.pdf ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1 _2in_MD_Triple_Com bo_MRI L.pdf ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1 _2in_MO_Triple_Combo_XBAT.pdf ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT-1_2in_MD_XCAL.pdf ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_2i n_TVD Triple_Combo.pdf ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1 _2in_TVD_Triple_Com bo_MRI L. pdf AOGCC Page & of 15 Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well Name/No. CT 1 MD 7070 ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C AOGCC TVD 6943 Completion Date 2/19/2016 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data 26954 Digital Data Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879-20021-00-00 Completion Status PSA Current Status P&A UIC No 3/18/2016 Electronic File: Caelus_CT- 1_2in_TVD _Triple—Combo _XBAT.pdf 3/18/2016 aelus_CT- Electronic File: Caelus—CT- 1_5in_MD_TdpleCombo.pdf 1-51n—MD—Triple Combo.pdf 3/18/2016 Electronic File: Caelus_CT- 1 _5in_MD_Triple_Com bo_MRI L.pdf 3/18/2016 Electronic File: Caelus_CT- 1_5in_MD_Triple _Combo_XBAT. pdf 3/18/2016 Electronic File: Caelus_CT-1_5in_MD_XCAL.pdf 3/18/2016 Electronic File: Caelus CT- 1_5in_T V D_ Triple_Combo.pdf 3/18/2016 Electronic File: Caelus CT - 1 _5in_TVD_Triple_Com bo_MRI L. pdf 3/18/2016 Electronic File: Caelus_CT- 1_5in_T V D_Triple_Com bo_XBAT. pdf 3/18/2016 Electronic File: Caelus_CT- 1_GeoTap_I DS_Pretests.pdf 3/18/2016 Electronic File: Caelus_CT- 1_GeoTap_IDS_Pumpout.pdf 3/18/2016 Electronic File: Caelus_CT- 1 _2in_MD_Triple_Combo.tif 3/18/2016 Electronic File: Caelus_CT- 1 _2in_MD_Triple_Com bo_MRI L.tif 3/18/2016 Electronic File: Caelus_CT- 1_2in_MD_Triple _Combo _XBAT.tif 3/18/2016 Electronic File: Caelus CT -1 2in MD XCAL.tif 3/18/2016 Electronic File: Caelus CT- 1_2in_TVD_Triple_Com bo.tif 3/18/2016 Electronic File: Caelus CT - 1 _2in_ TVD_ Tdple_Com bo_MRIL.tif 3/18/2016 Electronic File: Caelus_CT- 1_2in_TVD Triple_ Combo_XBAT.tif 3/18/2016 Electronic File: Caelus CT - 1 _5i n_MD_Triple_Combo.tif 3/18/2016 Electronic File: Caelus CT- 1_5in_MD_Triple _Combo_MRIL.tif Page 9 of 15 Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/212020 Permit to Drill 2152080 Well Name/No. CT 1 Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879-20021-00-00 MD 7070 TVD 6943 Completion Date 2/19/2016 Completion Status P&A Current Status P&A UIC No ED C 26954 Digital Data 3!18/2016 T- Electronic File: Caelus_CT- 1_5in_MD_TdpleComboXBAT.tif 1-51n—MD—Triple Combo XBAT.tif ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT-1_5in_MD_XCAL.tif ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_5in_TVD_Triple_Combo.tif ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_5in_TVD_Triple _Combo_MRIL.tif ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_5in_TVD_Triple _Combo_XBAT.tif ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_GeoTap_I DS_Pretests.tif ED C 26954 Digital Data 3/18/2016 Electronic File: Caelus_CT- 1_GeoTap_I DS_Pum pout.tif ED C 26954 Digital Data 3 /1 812 01 6 Electronic File: CT-1_R100_XCAL_QO.cgm ED C 26954 Digital Data 3/18/2016 Electronic File: CT-1_R300_XCAL_QC.cgm ED C 26954 Digital Data 3/18/2016 Electronic File: CT-1_R400_XCAL_QC.cgm ED C 26954 Digital Data 3/18/2016 Electronic File: CT-1_R100_XCAL_QC.emz ED C 26954 Digital Data 3/18/2016 Electronic File: CT -1_ R300_XCAL_QC.emz ED C 26954 Digital Data 3/18/2016 Electronic File: CT-1_R400_XCAL_QC.emz ED C 26954 Digital Data 3/18/2016 Electronic File: CT-1_R100_XCAL_QC.pdf ED C 26954 Digital Data 3/18/2016 Electronic File: CT-1_R300_XCAL_QC.pdf ED C 26954 Digital Data 3/18/2016 Electronic File: CT-1_R400_XCAL_QC.pdf ED C 26954 Digital Data 3/18/2016 Electronic File: CT -1_ R100_XCAL_QC.tif ED C 26954 Digital Data 3/18/2016 Electronic File: CT -1_ R300_XCAL_QC.tif ED C 26954 Digital Data 3/18/2016 Electronic File: CT-1_R400_XCAL_QC.tif ED C 26955 Digital Data 110 7070 3/18/2016 Electronic Data Set, Filename: CT -1 All In One.las ED C 26955 Digital Data 110 7070 3/18/2016 Electronic Data Set, Filename: CT -1 Chromatograph.las ED C 26955 Digital Data 110 7069 3/18/2016 Electronic Data Set, Filename: CT -1 Lith Cuttings.las ED C 26955 Digital Data 110 7069 3/18/2016 Electronic Data Set, Filename: CT -1 Lith Interp.las AOGCC Page 10 of 15 Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well NamelNo. CT 1 MD 7070 TVD 6943 Completion Date 2/19/2016 ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data I ED 1 C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data I ED C 26955 Digital Data ED C 26955 Digital Data ED C 26955 Digital Data Log C 26955 Log Header Scans Log C 27128 Log Header Scans Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879-20021.00-00 Completion Status P&A 111 7070 110 7070 0 0 0 0 Current Status P&A UIC No 3/18/2016 Electronic Data Set, Filename: CT -1 Mass AOGCC Page 11 of 15 Monday, March 2, 2020 Spec.las 3/18/2016 Electronic Data Set, Filename: CT -1 Mudlog.las 3/18/2016 Electronic File: CT -1 FINAL END OF WELL REPORT.pdf 3/18/2016 Electronic File: CT -1 MASS SPEC END OF WELL REPORT.pdf 3/18/2016 Electronic File: CT -1 1MD Gas Interpretation.emf 3/18/2016 Electronic File: CT -1 1 MD Mass Spectroscopy.emf 3/18/2016 Electronic File: CT -1 21VID DEL.emf 3/18/2016 Electronic File: CT -1 21VID FEL.emf 3/18/2016 Electronic File: CT -1 21VID GRL.emf 3/18/2016 Electronic File: CT -1 51VID FEL.emf 3/18/2016 Electronic File: CT -1 1 MD Gas Interpretation.pdf 3/18/2016 Electronic File: CT -1 1MD Mass Spectroscopy.pdf 3/18/2016 Electronic File: CT -1 2MD OEL.pdf 3/18/2016 Electronic File: CT -1 21VID FEL.pdf 3/18/2016 Electronic File: CT -1 2MD GRL.pdf 3/18/2016 Electronic File: CT -1 5MD FEL.pdf 3/18/2016 Electronic File: CT -1 1MD Gas Interpretation.lif 3/18/2016 Electronic File: CT -1 1 MD Mass Spectroscopy.8f 3/18/2016 Electronic File: CT -1 21VID DEL.tif 3/18/2016 Electronic File: CT -1 21VID FEL.tif 3/18/2016 Electronic File: CT -1 21VID GRL.tif 3/18/2016 Electronic File: CT -1 51VID FEL.tif 3/18/2016 Electronic File: CT -1 Definitive surveys.pdf 3/18/2016 Electronic File: CT -1 Definitive surveys.txt 2152080 CT 1 LOG HEADERS 2152080 CT 1 LOG HEADERS AOGCC Page 11 of 15 Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well Name/No. CT 1 MD 7070 TVD 6943 Completion Date 2/19/2016 ED C 27128 Digital Data ED C 27129 Digital Data ED C 27129 Digital Data ED C 27129 Digital Data ED C Log C Log C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C 27129 Digital Data 27129 Log Header Scans 27130 Log Header Scans 27130 Digital Data 27130 Digital Data 27130 Digital Data 27131 Digital Data 27131 Digital Data 27131 Digital Data 27131 Digital Data 27131 Digital Data 27131 Digital Data 27131 Digital Data 27131 Digital Data Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879-20021-00-00 Completion Status P&A 0 0 0 0 0 0 5500 6540 2550 3350 2550 3350 2550 3350 2550 3350 2550 3350 3350 6645 3350 6645 3350 6645 AOGCC Page 12 of 15 Current Status P&A UIC No 5/6/2016 Electronic Data Set, Filename: VSP Report" Will not be released per 20 AAC 25.071(d)(2). MGuhl 7/11/2016 5/6/2016 Electronic Data Set, Filename: Caelus CT1_Anisotropy analysis _4000_6570ftMD.LAS 5/6/2016 Electronic File: Caelus—CTI—Anisotropy analysis _4000_6570ftMD.dlis 5/6/2016 Electronic File: Caelus_CT1_Anisotropy analysis _4000_6570ftMD.dlis.FMA 5/6/2016 Electronic File: Caelus_CT1_Anisotropy analysis _4000_6570ftMD.pdf 2152080 CT 1 LOG HEADERS 2152080 CT 1 LOG HEADERS 5/6/2016 Electronic Data Set, Filename: Caelus_CT- 1_RTScanner_LSA _ 5500_6540ftMD.1as 5/6/2016 Electronic File: Caelus_CT-1_LSA.pdf 5/6/2016 Electronic File: Caelus_CT- 1_RTScanner_LSA_5500_6540ftMO.dlis 5/6/2016 Electronic Data Set, Filename: Caelus_CT- 1_Run2_down_RTScanner_1D_Dip_39in.las 5/6/2016 Electronic Data Set, Filename: Caelus_CT- 1_Run2_down_RTScanner_1 D_Dip_54in.las 5/6/2016 Electronic Data Set, Filename: Caelus_CT- 1_Run2down_RTScanner_1 D_Dip_72in.las 5/6/2016 Electronic Data Set, Filename: Caelus_CT- 1_Run2_down_RTScanner_RvRh.las 5/6/2016 Electronic Data Set, Filename: Caelus _CT- 1_Run2_Down_TRScanner_ZeroD_Dip.las 5/6/2016 Electronic Data Set, Filename: Caelus _CT- 1_Run2_up_RTScanner_1 D_Dip_39in.las 5/6/2016 Electronic Data Set, Filename: Caelus _CT - 1 _Run2_ up_RTScanner_1 D_Dip_54in.las 5/6/2016 Electronic Data Set, Filename: Caelus _CT - 1 _Run2_up_RTScanner_1 D_Dip_72in.las Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well Name/No. CT 7 Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879-20021.00.00 MD 7070 TVD 6943 Completion Date 2/19/2016 Completion Status P&A Current Status P&A UIC No ED C 27131 Digital Data3350 6645 5/6/2016 Electronic Data Set, Filename: Caelus_CT- 1_Run2_up_RTScanner_RvRh.las ED C 27131 Digital Data 3350 6645 5/6/2016 Electronic Data Set, Filename: Caelus _CT - 1 _Ru n2_up_TRScanner_ZeroD_Dip.las ED C 27131 Digital Data 5/6/2016 Electronic File: Caelus CT - 1 Runt_RTScaneer_Inversion_DS_Processed.p df Log C 27131 Log Header Scans 0 0 2152080 CT 1 LOG HEADERS Log C 27132 Log Header Scans 0 0 2152080 CT 1 LOG HEADERS ED C 27132 Digital Data 2372 6583 5/6/2016 Electronic Data Set, Filename: Caelus_CT- 1_CMR_data_100ms_cutoff.las ED C 27132 Digital Data 2372 6583 5/6/2016 Electronic Data Set, Filename: Caelus_CT- 1 _CMR_data_33ms_cutoff.las ED C 27132 Digital Data 5/6/2016 Electronic File: Caelus _CT- 1_CMR_Data_110m s_cutoff.dlis ED C 27132 Digital Data 5/6/2016 Electronic File: Caelus_CT- 1_CMR_Data_33ms_cutoff.dlis ED C 27132 Digital Data 5/6/2016 Electronic File: Caelus_CT- 1 _CMR_100m s_cutoff_log.pdf ED C 27132 Digital Data 5/6/2016 Electronic File: Caelus_CT- 1_CMR_33ms_cutoff_log.pdf ED C 27355 Digital Data 5/6/2016 Electronic File: Caleus Energy _CT 1 _MDT _I SP.zipx ED C 27355 Digital Data 5/6/2016 Electronic File: Caelus _Energy_CT1 _MDT_Final_Data_Evaluatio n_Report.pdf ED C 27355 Digital Data 5/6/2016 Electronic File: Caelus _Energy_CT1 _MDT_ Pressure -Time -Plots .pdf 5/6/2016 Electronic File: Caelus_Energy_CT1_MDT_Test. ED C 27355 Digital Data Point Table.xlsx 8/31/2016 Electronic File: Caelus Energy Alaska Coring ED C 27514 Digital Data Project CT -1 HH -90755 Continued Cleaning Data 5-19-16 (1).xlsx 8/31/2016 Electronic File: Caelus Energy Alaska Coring ED C 27514 Digital Data Project CT -1 HH -90755 Rotary Core Data 2-29- 16 (2).xlsx AOGCC Page 13 of 15 Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/212020 Permit to Drill 2152080 Well Name/No. CT 1 Operator Caelus Energy Alaska Smith Bay, LLC API No. 50.879-20021-00-00 MD 7070 TVD 6943 Completion Date 2/19/2016 Completion Status P&A Current Status P&A UIC No ED C 27514 Digital Data 8/31/2016 Electronic File: CA_Caelus Energy CT-1.pdf ED C 27514 Digital Data 8/31/2016 Electronic File: CA_Caelus Energy CT-1.tdsx j ED C 27514 Digital Data 8/31/2016 Electronic File: HH-90755_Caelus Energy_CT- 1_Rw Measurement Summary_2-10-16 (3).xlsx ED C 27514 Digital Data 8/31/2016 Electronic File: GC_EXTGC_G6160277_1- 3R_5645.00 -_H H-90755.xlsx ED C 27514 Digital Data 8/31/2016 Electronic File: GC_ EXTGC_G6160278_1- 7R_5675.00-_HH-90755.x1sx ED C 27514 Digital Data 8/31/2016 Electronic File: GC_EXTGC_G6160279_1- 10R_5707.00._H H-90755.x1sx ED C 27514 Digital Data 8/31/2016 Electronic File GC_EXTGC_G6160280_1- - 15R_5760.00- HH-90755.xlsx ED C 27514 Digital Data 8/31/2016 Electronic File GC_EXTGC_G6160281_1- 18R_5900.00 -_H H-90755.xlsx ED C 27514 Digital Data 8/31/2016 Electronic File GC_EXTGC G6160282_1- 23R_6033.00-_HH-90755.xlsx ED C 27514 Digital Data 8/31/2016 Electronic File: GC_EXTGC_G6160283_I- 26R_6087.00-_HH-90755.x1sx ED C 27514 Digital Data 8/31/2016 Electronic File GC_EXTGC_G6160284_1- 32R_6347.00-_HH-90755.x1sx ED C 27514 Digital Data 8/31/2016 Electronic File GC_EXTGC_G6160285_t- 38R_6386.50-_H H-90755.x1sx ED C 27514 Digital Data 8/31/2016 Electronic File: GC_EXTGC_G6160286_1- 43R_6416.00-_HH-90755.x1sx Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments Cuttings 130 7070 4/19/2016 1583 INFORMATION RECEIVED ntx;(.t_ Page 14 of 15 Monday, March 2, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/2/2020 Permit to Drill 2152080 Well Name/No. CT 1 Operator Caelus Energy Alaska Smith Bay, LLC API No. 50-879-20021-00-00 MD 7070 TVD 6943 Completion Date 2/19/2016 Completion Status P&A Current Status P&A UIC No Completion Report D Directional / Inclination Data V/ Mud Logs, Image Files, Digital Dat NA Core Chips Y n Production Test Information Y /NA Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files ® Core Photographs Y /(9 Geologic Markers/Tops D Daily Operations Summary 6 Cuttings Samples O/ NA Laboratory Analyse NA COMPLIANCE HISTORY Completion Date: 2/19/2016 Release Date: 1/13/2020 Description Date Comments Comments: Compliance Reviewed By: Date: 31 oZ' -c-O -b AOG('<' Page 15 of 15 Monday, March 2. 2020 Release of Confidential Data Coversheet Well Name: CT 1 PTD: 215-208 E-Set: T26951, T26952, T26953, T26954, T26955, T27129, T27130, T27131, T27132, T27355, T27514 ✓ Physical data labeled with PTD, E-Set # Conf entry: various ✓ Import CD data to RBDMS ✓ (incomplete) entry in Well Data List notes /Confidential V ymport to DigLogs via E-Set tab J$can labeled data ✓,Apply OCR text recognition J ve to Well Log Header Scans New "complete" entry in Well Data List notes Logged by: Meredith Guhl Fully logged: 2/28/2020 THE STATE °fALASKA GOVERNOR MICHAEL J. DUNLEAVY October 31, 2019 Pat Foley Senior Vice President Caelus Energy Alaska aJs-2C Department of Natural Resources RECEYVED 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503 pat.foley(ckaelusenergy.cwm JAN 13 2020 AOGCC OFFICE OF THE 550 West 7m Avenue, Suite 1400 Anchorage, AK 99501-3561 Main: 907.269-8431 Fax: 907-269-8918 CERTIFIED MAIL RETURN RECEIPT REQUESTED Re: Appeal No. 18-005: Decision on Caelus Energy Appeal of Director's Decision, Request for Extended Confidentiality CT -1 and CT -2 Wells, Smith Bay, Alaska. I. DECISION SUMMARY. On April 4, 2018, Caelus Energy Alaska Smith Bay, LLC ("Appellant") filed a timely appeal ("Appeal") of the Department of Natural Resources ("DNR"), Division of Oil and Gas's ("Division") decision regarding the Appellant's request for extended confidentiality, CT -I and CT -2 Wells, Smith Bay, Alaska (the "Decision"). The Appeal reiterates the request for extended confidentiality and questions the Division's authority to grant extended confidentiality for a "limited duration."' For the reasons set forth below, the Appeal is denied. II. RELEVANT FACTS. On November 9, 2017, the Appellant requested extended confidentiality for required reports and information from wells CT -1 and CT -2 (the "Wells") containing significant information relating to the valuation of unleased land in the same vicinity. The Wells are located within a three-mile radius of unleased land within the National Petroleum Reserve in Alaska ("MPR -A"). The NPR -A is currently subject to a Department of Interior, Bureau of Land Management ("BLM") Integrated Activity Plan ("IAP") that makes the lands unavailable for oil and gas leasing. Secretarial Order No. 3352 ("SO No. 3352"), issued on March 31, 2017, ordered a reconsideration of the lands withheld from NPR -A lease sales. SO No. 3352 has not affected NPR -A lease availability in the vicinity of the Wells. r Appeal, at p. 2. Commissioner's Decision on Caelus Appeal re Request for Extended Confidentiality October 31, 2019 Page 2 of 3 III. STATEMENT OF APPLICABLE LAW. Division regulations, at 11 AAC 83.153, describe the confidentiality time frames for well reports or information that the Division finds under AS 31.05.035(c) to contain significant information relating to the valuation of unleased land within certain radii. Under 11 AAC 83.153(a), if the wells in question are located within a three-mile radius of the unleased land, the commissioner will, upon written request, keep the reports or information confidential for a reasonable time not to exceed 90 days after disposal of the unleased land. 11 AAC 83.153(d) defines disposal as the grant or issuance of an oil or gas lease. IV. ANALYSIS. In its Decision, the Division granted the Appellant's request for extended confidentiality, to expire 90 days after the next NPR -A lease sale, regardless of whether acreage relevant to the request is offered at that sale.' In addition, the Division offered to consider a second request for an extension if the Appellant proffered evidence that the unleased lands relevant to the request will be offered at a NPR -A lease sale in a timeframe that necessitates an additional extension.3 Under l 1 AAC 83.153, the Division correctly granted the request for extended confidentiality to expire in 90 days because the Division had determined that the information from the Wells is significant information relating to the valuation of unleased lands in the vicinity of the Wells, that the unleased lands relevant to the request are located within the NPR -A, and that the Wells are within a three-mile radius of the NPR -A.4 However, the condition added by the Division, that the extension shall expire 90 days after the next NPR -A lease sale, regardless of whether acreage relevant to the request is offered at that sale (emphasis added), is not supported by the regulation. For the reasons set forth below, however, this condition constituted harmless error. The Division's grant is upheld, and the Appeal is denied. Per the Decision, "AS 31.05.035 and its accompanying regulations do not contemplate or provide for the indefinite extension of confidentiality.s5 That is, a grant of extended confidentiality under 11 AAC 83.153, set to expire 90 days after the issuance of a lease, on NPR -A lands unavailable for leasing under the IAP as unaffected by SO No. 3352, is a grant for indefinite confidentiality. The IAP as unaffected by SO No. 3352 renders the unleased NPR -A lands within a three-mile radius of the Wells as unavailable for leasing. If the lands cannot be leased, they do not require valuation. Therefore, the significant information from the Wells that would relate to the valuation of these lands, lands that cannot be leased, does not require extended confidentiality. That is, the necessity for extended confidentiality for the Wells information is obviated by the IAP as unaffected by SO No. 3352. I Decision, at p. 2. 3 Id. Decision, at p. 1. 5Id. Commissioner's Decision on Caelus Appeal re Request for Extended Confidentiality October 31, 2019 Page 3 of 3 Finally, the Division offered to consider a second request for an extension if the Appellant proffered evidence that the unleased land relevant to the request will be offered at an NPR -A lease sale in a timeframe that necessitates an additional extension of time. Nonetheless, the Appellant offered no additional evidence, either to the Division or in its Appeal. V. FINDINGS AND DECISION. As stated above, this office is denying the appeal because Alaska law does not contemplate the extension of indefinite confidentiality for well data, most especially when the need for extended confidentiality for that well data has been obviated. VI. APPEAL RIGHTS. This Commissioner's Decision is the final administrative order and decision of the department for the purpose of an appeal to the superior court. An appellant affected by this final administrative order and decision may appeal to superior court within 30 days in accordance with the Alaska Rules of Court and to the extent permitted by applicable law. Sincerely, Com A. Feige Commissioner, Department of Natural Resources cc: Dr. Sara W. Longan, Deputy Commissioner Peter J. Caltagirone, Esq., Senior Legal & Policy Advisor Tom Stokes, Acting Director, Division of Oil & Gas THE STATE °fALASKA GOVERNOR BILL WALKER December 28, 2016 Mr. Dale Hoffman Manager, Land and External Affairs Caelus Energy Alaska, LLC 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503-5818 Re: Location Clearance Smith Bay CTI (PTD 2152080) Smith Bay CT2 (PTD 2160160) Dear Mr. Hoffman: 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 The Smith Bay CT1 and CT2 exploration wells were drilled by Caelus Energy Alaska, LLC (Caelus) during the fust quarter of 2016. Both wells were drilled from offshore ice pads. AOGCC waived witness of the surface abandonments of these wells. A thorough review of the well completion reports for CT t and CT2 show the well abandonments — as described — meet the Alaska Oil and Gas Conservation Commission (AOGCC) regulatory requirements. Post abandonment visual inspections of the locations were performed by Caelus on May 29, 2016. Photographs of the locations taken during the overflight inspections were provided to AOGCC on November 2, 2016. The AOGCC requires no further work on the subject wells or locations at this time. However, Caelus remains liable if any problems were to occur in the future with these wells. Sincerely, CathytP. Foerster Chair, Commissioner RBDMS i-1— DEC 2 8 2016 C CA -PLUS Energy Alaska August 31, 2016 Meredith Guhl Alaska Oil and Gas Conservation Commission 333 W. 71h Ave., Suite 100 Anchorage, AK 99501 CT -1 Well Core Data, Smith Bay, Alaska Dear Meredith: Dale Hcirna ILA Manager. Land and Externat Affai dale. hof fman0cael_usenergy.com Direct: 907-343-2108 Cell: 907-830-2571 RECEIVED CONFIDENTIAL Delivered by Hand AUG 31 2016 AOGCC Caelus Energy Alaska Smith Bay, LLC (CEASB) is providing the enclosed CT -1 core data listed on the attached Exhibit A as required by the Alaska Oil and Gas Conservation Commission. Caelus requests all data transmitted hereunder be maintained CONFIDENTIAL pursuant to 20 AAC 25.537. Should you have any questions on the delivery of the attached, please contact me care of the letterhead address. Sincerely, Caelus Energy Alaska Smith Bay, LLC Dale Hoffman Attachments to and reton this � e'd 1 , 2016. Print Name Exhibit A CONFIDENTIAL Directory of F:\Lab Results\CT-1 08/02/2016 09:52 AM 22,826 HH-90755_Caelus Energy_CT-1_Rw Measurement Summary_2-10-16 (3).xlsx 08/02/2016 09:58 AM 60,052 CA—Caelus Energy CT-1.pdf 08/02/2016 09:58 AM 68,782 CA—Caelus Energy CT-1.xlsx 08/02/2016 09:56 AM 80,440 Caelus Energy Alaska Coring Project CT -1 HH -90755 Rotary Core Data 2-29-16 (2).xlsx 08/02/2016 09:58 AM 76,230 Caelus Energy Alaska Coring Project CT -1 HH -90755 Continued Cleaning Data 5-19-16 (1).xlsx 08/02/2016 10:08 AM <DIR> Caelus Energy CT -1 EGC_High Resolution GC Fingerprint Directory of F:\Lab Results\CT-1\Caelus Energy CT -1 EGC_High Resolution GC Fingerprint 08/02/2016 09:59 AM <DIR> Caelus Energy CT -1 EGC Directory of F:\Lab Results\CT-1\Caelus Energy CT -1 EGC_High Resolution GC Fingerprint\Caelus Energy CT -1 EGC 08/02/2016 09:59 AM 08/02/2016 09:59 AM 08/02/2016 09:59 AM 08/02/2016 09:59 AM 08/02/2016 09:59 AM 08/02/2016 09:59 AM 08/02/2016 09:59 AM 08/02/2016 09:59 AM 08/02/2016 09:59 AM 08/02/2016 09:59 AM 139,733 GC_EXTGC_G6160277_1-3R_5645.00-_HH-90755.xlsx 138,167 GC_EXTGC_G6160278_1-7R_5675.00-_HH-90755.xlsx 136,769 GC_EXTGC_G6160279_1-10R_5707.00-_HH-90755.xlsx 138,652 GC_EXTGC_G6160280_1-15R_5760.00-_HH-90755.xlsx 136,511 GC_EXTGC_G6160281_1-18R_5900.00-_HH-90755.xlsx 134,990 GC_EXTGC_G6160282_1-23R_6033.00-_HH-90755.xlsx 136,475 GC_EXTGC_G6160283_1-26R_6087.00-_HH-90755.xlsx 137,361 GC_EXTGC_G6160284_1-32R_6347.00-_HH-90755.xlsx 137,892 GC_EXTGC_G6160285_1-38R_6386.50-_HH-90755.xlsx 139,161 GC_EXTGC_G6160286_1-43R_6416.00-_HH-90755.xlsx pm zt5zogo Regg, James B (DOA) From: Dale Hoffman <Dale.Hoffman@caelusenergy.com> Sent: Tuesday, August 02, 2016 12:20 PIA To: Regg, James B (DOA); Rachel Davis; Vern Johnson; Ben Anglen Subject: CT -1 & CT -2 Wells AOGCC Forms Attachments: CT -2 AOGCC.pdf; CT -1 AOGCC.pdf; CT1 Looking West.JPG; CT2 Looking South.JPG Jim, Thanks for your time today. Per our conversation, I've attached photos of the CT -1 and CT -2 well sites (located in Smith Bay) in lieu of the AOGCC form 10-407 which was required on the approved application for Sundry Approvals (10-403) for each well. Please indicate Caelus Energy Alaska Smith Bay, LLC has satisfied the requirements of the form 10-407 for the CT -1 and CT -2 wells. Thank you for your assistance in this matter. Dale Hoffman, CPL Manager, Land and External Affairs Caelus Energy Alaska, LLC 3700 Centerpoint Dr., Suite 5001 Anchorage, AK 99503-5818 Direct 907 343 2108 1 Fax 907 343 2193 1 Cell 907 830 2571 dale.hoffman@caelusenergy.com Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. GT__ I — W C fL (Jo - "-7) X&'O( 307(110 - lftle_we� 4116116 3 5A/Lt,�k 1141 CTI `pt ZISzo,�,) CE CAELU S Energy Alaska 22, is Energy Alaska Centerpoint Dr., Suite 500 gage, AK 99503 aca95y ' -f355 LETTER OF TRANSMITTAL : Meredith Guhl W. 7"' Avenue, Suite 100 forage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps ❑ CD -R E Other — Logs, Reports ❑ Agreement ` I T DESCRIPTION CT -1 (50-879-20021-0000) 2 Reports Formation Testing Analysis Report -24p45`1 MDT Pressure -Time -Plots report -zq 355 3 Logs CT -1 R100, CT -1 R300, CT -1 R400 -2(o95 NOWONGERthat all data be treated as confidential information per 20 AAC 25.537(d) CONFIDENTIAL Thank you JAN Received RECEIVE® JUL 2 5 2016 Date: M ��a+ sign and return one copy to: Caelus Energy Alaska ATTN: Shannon Koh 3700 Centerpoint Dr., Suite 500, Anchorage, AK 99503 907-343-2193 fax 907-343-2128 phone shannon.koh(cDcaelusenerov com Guhl, Meredith D (DOA) From: Dale Hoffman <Dale.Hoffman@caelusenergy.com> Sent: Monday, July 11, 2016 3:15 PM To: Guhl, Meredith D (DOA); Davies, Stephen F (DOA); Bettis, Patricia K (DOA) Cc: Vern Johnson; Andy Bond Subject: CT -1 Well Sidewall Cores Meredith, Thanks for your call and advising me of the error on the 10-407 well completion form regarding sidewall cores on the CT -1 well. We did indeed take them and will provide them to the AOGCC once we have them all in house. Again, thanks for alerting me to this and for your patience. Please don't hesitate to call if I can be of assistance. Dale Hoffman, CPL Manager, Land and External Affairs Caelus Energy Alaska, LLC 3700 Centerpoint Dr., Suite 5001 Anchorage, AK 99503-5818 Direct 907 343 2108 1 Fax 907 343 2193 1 Cell 907 830 2571 dale.hoffman@caelusenergy.com Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. C CQELU S Alaska May 6, 2016 Alaska Oil and Gas Conservation Commission 333 W. 7" Ave., Suite 100 Anchorage, AK 99501 CT -1 and CT -2 Well Data Smith Bay, Alaska Dear Sir or Madam: 21 F208 21 6016 Date Hoffman, CPL Manager, Land and External Affairs OVALOGGED date.hoffman@caelusenergy.com it3i201ea Direct: 907-343-2108 id. K. BENDER Cell: 907-830-2571 27 128 27 133 RECEIVED 27 1 2 9 27 13 4 MAY 062016 27 130 27 135 27 13 1 27 136 �0G�C 27132 27 13 7 2'T '355 27 1 3 8 CONFIDENTIAL 2 7 139 Delivered by Hand Caelus Energy Alaska Smith Bay, LLC (CEASB) is providing the data from the CT -1 and CT -2 wells listed on the attached Exhibit A for your files. Caelus requests all data transmitted hereunder be maintained CONFIDENTIAL pursuant to 20 AAC 25.537. Should you have any questions on the delivery of the attached, please contact me care of the letterhead address. Sincerely, Caelus Energy Alaska Smith Bay, LLC ;t Dale Hoffman Attachments Accepted, agreed to and received on this May_, 2016. Print Name 3700 Centerpoint Dr., Suite 500 • Anchorage, AK 99503 - Main Line: 907-277-2700 . Fax: 907-343-2190 • w .caelusenergy.com Exhibit A CONFIDENTIAL CT -1 Well Data Discs NO LONGER CONFIDENTIAL JAN 13 2020 • Schlumberger Wireline Disc: FMI, Sonic, PPC, VSP, MDT, XL -Rock, CMR, TCOM (Disc 3 of 3) • Schlumberger PetroTechnical Services Disc 1: SonicScanner Anisotropy Analysis 4000'-6570' • Schlumberger PetroTechnical Services Disc 2: Laminated Sand Analysis • Schlumberger PetroTechnical Services Disc 3: RT Scanner 1D Inversion • Schlumberger PetroTechnical Services Disc 4: CMR Analysis • Schlumberger PetroTechnical Services Disc 5: MDT, Processed Data, Field Data Paper • Modular Formation Dynamics Tester, Data Evaluation Report • ZVSP — Borehole Seismic Processing Report • Laminated Sand Analysis — Hydrocarbon Identification From RT Scanner • Sonic Scanner, Compressional and Shear Borehole Anisotropy Analysis, 4000' to 6570' • RT Scanner 1D Inversion • CMR Analysis, T2 Cutoff = 100 ms • CMR Analysis, T2 Cutoff = 33 ms CT -2 Well Data Discs • Schlumberger Wireline Disc: ZAIT, PEX, CMR, SBL, VD XLRock • Schlumber etroTechnical Services Disc 1: C nalysis • Schlumberger Pe chnical Services Di : RT Scanner 1D Inversion • Schlumberger PetroTec 'cal Servi Disc 3: LSA • Schlumberger PetroTechnic vices Disc 4: MDT Interpretation • Halliburton Disc: Surfa ata ing, Final Log Files, Final End of Well Report, Final LAS, Log Viewers • Halliburton D' . LWD Formation Evalua ' n Logs (Digital Data in LAS & DLIS format, graphic logs in E , CGM, PDF, and TIFF formats) Paper • Mechanical 'de Wall Coring - Run R1D7 • Mechanical Si all Coring - Run RID-?, • MDT - Run R1D6 Sum Rep • MDT- Run R1D6 Full Repo • Mechanical Side Wal ring - R 1D5 • Mechanical Sid all Coring -Run R • MDT - Run , 4 Summary Report • MDT- n R1D4 Full Report Summary Report Full Report XI -Rock Summary Report XI -Rock Full Report CE CAELU S Enemy Alaska 18, 2016 Letter of Transmittal z( -2T I1�B3 I-KUM TO APR 19 201 Shannon Koh AOGCC Caelus Energy Alaska, LLC Attn: Meredith Guhl A0GC 3700 Centerpoint Dr., Suite 500 333 W. 7t' Avenue, Suite 100 Anchorage, AK 99503 Anchorage, AK 99501 INFORMATION TRANSM ❑ Letter ❑ Maps ❑ Report ❑ Agreement X Other -Dry samples DETAIL QTY DESCRIPTION Well Name: 9 Boxes of well cutting samples CT -1 (50-879-20021-0000) Details on following pages We request that all data be treated as confidential information per 20 AAC 25.537(d) Thank you Received by: `�Xl �-� Date: ! Z aelus E rgy Alaska, LLC Shannon Koh 3700 Centerpoint Dr., Suite 500, Anchorage, AK 99503 907-343-2193 fax 907-343-2128 phone shannon.koh@caelusenergy.com Well Name: CT -1 API : 50.87920021.00-00 AFE: 150036 Halliburton Enefgy Services - Surface Data Logging Contact: (907)275.2602 -lade Miller/ SOL Coordinator Dry Will Cutting Samples BOX/SAMPLE (Dry) TOP DEPTH (MD) I BOTTOM DEPTH (MD) I SAMPLE COUNT I WELL I COMMENTS 1 Of 9 130'- 160' 1150'- 1180' 36 CT -1 SURFACE SECTION - Polymer / BDF499 Mud 2 of 9 1180'- 1210' 2230'- 2260' 36 CT -1 SURFACE SECTION 3 of 9 22601- 2290' 3250'-3280' 36 CT -1 To SURFACE SECTION @ 2564' MD + 1 BU 2564' - 2584' MD BU (odIlIng out Cement) 4 of 9 3280'-3310' 4330'-4360' 36 CT -1 INTERMEDIATE SECTION 5 of 9 4360'- 4390' 5210'- 5220' 36 CT -1 INTERMEDIATE SECTION 6 of 9 5220'- 5230' 5570'-5580' 36 CT -1 INTERMEDIATE SECTION 7 of 9 5580'- 5590' 58101- 5820' 36 CT -1 INTERMEDIATE SECTION 8 of 9 5820' - 5830' 6360'-6390' 36 CT -1 INTERMEDIATE SECTION 9 of 9 G390'-6420' 7060'- 7070' 37 CT -1 INTERMEDIATE SECTION - TD @ 7070' MD DECEIVED STATE OF ALASKA MAR 2 2 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF ANNULAR DISPOSAL AOGCI" 1. Operator: 4a. Well Class: Stretigraphic Li Service 6. Permit to Drill Number: 215-208 Caelus Energy Alaska Smith Bay, LLC Development Exploratory 0 7. Well Name: CT -1 2. Address: 4b. Well Status: Oil Q Gas WAG 8. API Number: 3700 Centerpoint Drive, Suite 500, Anchorage, Alk. 99503 GINJ WINJ ❑ WDSPL [] 50- 879-20021-00-00 3. (Check one box only) 5a. Sundry Number: 51b. Sundry approval dale: 9. Field: Exploration -Smith Bay Initial Disposal R Continuation ❑ Final Q 316-110 Feb.10, 2016 10 (h)(1) drilling mud, drilling (h)(2) drill rig wash fluids (h)(3) Other Commission Volume (bbls): Number of Disposal Disposal Source Wells: cuttings, reserve pit fluids and drill rig domestic waste approved substances (include days Beginning Dates: Ending Dates: cement -contaminated drilling water descriptions in block 12) disposal mud, completion fluids, occurred: formation fluids and any necessary water added. Previous totals 0 0 0 0 0 N/A N/A N/A (bbls): 2016/Q1 1459 77 0 1536 2 02/12/16 02/13/16 CT -1 2016/Q1 2325 0 0 2325 1 02/15/16 02/15/16 CT -1 YYYY/Q# YYYY/Q# Ending Report is due on the 20th Ending Volume 3784 77 0 3861 3 of the month following the final month of the quarter. Ex: (obis): April 20 for the first quarter, July 20 for the second quarter, October 20 for the third quarter, and January 20 for the 11. Attach: Disposal Performance Data: Pressure vs. Time Q Step Rate Test Other (Explain) ❑ 1 fourth quarter. 12. Remarks and Approved Substances Drilling mud, drill cutlings,reserve pit fluids,cement contaminated drilling mud, cement rinsate, completion fluids,diesel,formation fluids associated with the acit of drilling a Description(s): well. Drill rig wash, domestic waste water,any added water needed to facilitate pumping of drilling mud of drilling cuttings and any other fluids associated with drilling a well. Boiler blow down fluids. Density range: 7#/gal to 12#/gal. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature: �` 1'." " Date: PrintedI �/ Title:.V r; (I,ne L "{"{q o.c q e• Phone • 3 - Z_ itnSo._ C� V Number: ao'; Y~ Name: V r r.. —�o Form 10423 Rev. 2/2004 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate CT -1 Annular In edlon =/17/3016 to 7/13/7036 a�m�� NEON ZFERMEOR MESON r MEMO � � ��0��� Ecz•�am� monr �mErmmgmmrrlm ��������� MEtrs�•�E��Q���,���INNER monn-mom olm � WKWITM�s� �n=Mmm�� trrc� iz;>• � Ez� � �.� � �� � � � � �� moi• ter, �� EFTMErtTM s>ear.'ma��aas,�•�tsi ��� �� r1� � �7�t7� �a �sss:'��sa��srs•��������� �rtt! tI oNEF7".1•�ia�tT7f��^������i•����� i.rrMMwrMlMrlM �iR2��tTPf���i:�� tRi•tzftr��^f[±1^� Cr's��Erm � �'1'I-..�"r. �IiI��QLl�tII7�t7fi����tA�tSf orm• a�®mmmm�mmmmmmmm� �m�mmmm��mmmmm•mo�� �musm�mmmm��mmmmm•mo�� �m©mm�0mmmmomm� m�m©mo�mmmmmomm� 0wm �r°+�� m©mm� mmmmmm mm�� a�r�®mamm�mmmmmm.mm� �^n�m•mamm�m,mmmmm.mm�� �^�®mamm�m•mmmmmmo� a��m�mamo�m_mmmmm.mm� arses®m©mm��mmmmmmm� aT`+��mamm��mmmmm•mm�� mamm��mmmmm•mm�m OMIT= xgum"M mmm�mmmmmm•mm�� t�rr�®mmmm�mmmmmmmo� Elm"m�mmmm�ommmm0mm� a�m�mmmm��mmmmm•mm� a�n��mmmm�ommmmm•m©�� ��®mmmo��mmmmm•m©�� �r��mmmm��mmmm�mo�� �r�®mmmm��mmmm�mo� a�r�m,mmmm��mmmmmmo� aT�®mmmm��mmmm�mm� �na'uu�mmmo��mmmm�mm� ass®m,mmmm�®mmmm®mom mmm�®mmmm®mm�� RKM"Im EMT=�mmmm��mmmm�mm� �a"u��mmmm��mmmmm.mo� �'r'am•,mmmm��mmmm�mm�� �ts�msmmmm�®mmmm®mm�� �n�mmmmm��mmmm�mm�� a�s�m�mmmm � ®mmmm®m m� a��mm®mm��mmmm�mm�� ����mm®m��mmmm�mmm ��mmmm��mmmm�mm �r��mmmm��mmmm�mm�� aT-��mmmo��mmmmmmm�� aT-��mo mm��mmmmmmm�� �r-�mmomm�®mmmm®m m�� �r^�mmomm��mmmm�mm� �r+'�m,momm�mmmmm�m®� t�rr� ®mam m �m m mm mmmmm� ��®mamm��mmmm�mm�� a�mmmmm�®mmmm®mm�� �"'.�mmmmo��mmmm�mm� ��®mEmmo��mmmm�mm�� es��mmmm�®mmmm®mm�� a�s'am,mmmm��mmmm�mm�� an*smm®mm��mmmm�mm� ��mmmm��mmmm�mm�� ter-fw�m®mm�®mm MEMO= mm�®mmmm�mm mammmm�®mmmm�m Tulimaniq #1 DAILY INJECTION LOG F 1a. 1 Date: 2/15/2016 �����m�m�������� �����®�m�������� �����®�m�®������ �����m�mm®������ �����®�m�������� �����m�mm®������ �����m�mm������� �����m�mm������� �����m�m�������� • �, ����m�mm������� �����m�mm������� �����m�mm������� �����m�m�������� �����m�mm������� �����m�mm������� �����®�mm®������ �����m�®m������� �����o�®m������� �����m�®m������� �����m�®m������� „ ����m�®m������� . , ����m�®m�������i ����®�m�®m������� ����m�®m������� ��� �� �m�®m������� ����m�®m������� �����m�®m������� ����m�®m������� �����m�®m������� „ ����m�®m������� �����m�®m������� �����m�®m������� ®����m�®m������� �����m�®m������� ®����m�®m������� �����m�®m������� ®����m�®m������� �����m�®m������� �����m�®m������� �����m�®m������� ®����m�®m������� �����m�mm®������ �����m�®m������� �����m�®m®������ ®����m�®m������� �����m�®m������� ®����m�®m������� �����m�®m������� ®����m�®m������� �����m�®m������� �����m�®m������� �����m�®m������� ®����m�®m������� „ ����m�®m������� ���®�m�®m������� ���©�m�®m������� ®����m�mm������� �����m�®m������� ®����m�mm������� �����m�®�������� ®��m�®�®m���C��� ��� �, �®�mm��� ��� �����®�mm������� ®����m�mm������� �����®�mm������.� �����®�mm������� ���®�®�mm��CCCCC ���m.�®�mm������� ���m�®�mm������� CCCmC®CCm���CCC� ®����m�mm����� �����m�m�®������i �����m�mm®������ „ ����m�m�������� �����m�mm������� �����m�mm®������ ®����m�mm������� �����o�mm������� �����o�om ������ ®����o�om������� �����a�om������� �����a�mm������� �����a�mm������� ������������G�ID a Annular Disposal - Injectivity Test Well Name: CT -1 0.25 Date: 2112/2016 160 Csg Size/WUGrade: 8-1/2" x 5" DP (d 3208 ft. md. Supervisor: 1.25 380 1.5 Setting Depth 2,551 TMD 2510 TVD (10-3/4" surf.csg.) 570 2.5 500 2.75 Mud Weight: 10.15 ppg Leakoff pressure = 525 psi 3.5 LOT= 14.10 ppg 500 Depth = 2551 and 4.25 Fluid Pumped= 5.3 Boils Volume Back = 1.5 bbls 5 515 Estimated Pump Output: bbls Barrels/Stroke Enter Holding Enter Holding CT -1 Injectivity Test CASING TEST DATA Enter BBLS Enter Pressure Enter Strokes Enter Pressure Here Here Here Here 0 0 0.25 70 0.5 160 0.75 230 1 300 1.25 380 1.5 457 1.75 510 2 525 2.25 570 2.5 500 2.75 500 3 500 3.25 500 3.5 500 3.75 500 4 510 4.25 510 4.5 510 4.75 510 5 515 5.25 510 Enter Holding Enter Holding Time Here Pressure Here 1 2 3 4 5 6 7 6 g 10 time Here Pressure Hen 800 750 700 650 600 550 500 450 N 6 d 400 N d d 350 300 250 200 150 100 50 0 0 1 2 3 4 5 6 7 8 Volume - BBLS CT -1 Injectivity LOT Test �-CT-1 Injea WYTeet Page 1 CE CAELU S Enei._ 1, Alaska March 18, 2016 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Suite 100 Anchorage, AK 99501 CT -1 Well Data, Smith Bay, Alaska Dear Sir or Madam: RECEIVED 21 5208 Dale Hoffman, CPL Manager, Land and External Atfairs dale. hoffmaii@caelusenergy.com Direct: 907-343-2108 Cell: 907830-2571 MAR 1 S 20% 2 6 9 5 1 AOQCC 26952 CONFIDENTI 0 GER 2 6 9 5 3 �`0NFIDENT)AL2 6 9 5 4 JAN 13 2020 26 9 5 5 Delivered by Hand Caelus Energy Alaska Smith Bay, LLC (CEASB) is providing the data from the CT -1 well listed on the attached Exhibit A for your files. Caelus requests all data transmitted hereunder be maintained CONFIDENTIAL pursuant to 20 AAC 25.537. Should you have any questions on the delivery of the attached, please contact me care of the letterhead address. Sincerely, Caelus Energy Alaska Smith Bay, LLC 'AK 11 l j Attachments Accepted, agreed to and received on this March 18, 2016. AOGCC Received By Proof of Receipt ONLY Print Name 3700 Centerpoint 6r., Suite 500 • Anchorage. Ari 99503 -Main Line: 907-277-"2710 • Fax: 907 3a_-2791 • vnw�.caeWienergv.� reg RECEIVED Exhibit A MAR 18 2016 CT -1 Well Data AOGCC CONFIDENTIAL Discs 26 9 5 1 • Schlumberger Disc 1 of 3 _FMI, PPC, Sonic DLIS; Downlog_MD; Downlog—TVD 26 9 5 2 • Schlumberger Disc 2 of 3:_FMI, PPC, Sonic DLIS; Up_Bottom_MD; Up_Bottom_TVD; 26 9 5 3 Up_Top_MD, Up_Top_TVD • Schlumberger Disc 3 of 3: FMI, Sonic, PPC, MDT, XL -Rock, CMR, TCOM 26 954 Halliburton rton Disc: Daily Drilling Reports, Daily Geologic Reports, End of Well Geologic Well�� �• � Summary, Final Composite -Geologic Strip Log AtA d0m- �fo955 Z 6 y 5 5 • Halliburton Disc: Surface Data Logging, Final Log Files, Final End of Well Report, Final LAS, Log Viewers Paper Copies • Final Composite -Geologic Strip Log • Formation Microresistivity Imager (FMI) 20" • Sonic Scanner 2" MD • Sonic Scanner 2" TVD • Sonic Scanner 5" MD • Sonic Scanner 5" TVD • 4 Arms Caliper (PPC) 2" MD • 4 Arms Caliper (PPC) 2" TVD • 4 Arms Caliper (PPC) 5" MD • 4 Arms Caliper (PPC) 5" TVD • MDT Formation Tester Log—Full Report • MDT Formation Tester Log—Summary • Combinable Magnetic Resonance (CMR) 2" MD • Combinable Magnetic Resonance (CMR) 2" TVD • Combinable Magnetic Resonance (CMR) 5" MD • Combinable Magnetic Resonance (CMR) 5" TVD • Triple Combo CMR (TCOM) 2" MD • Triple Combo CMR (TCOM) 2" TVD • Triple Combo CMR (TCOM) 5" MD • Triple Combo CMR (TCOM) 5" TVD • XL Mechanical Sidewall Coring (XL -Rock) -Full Report • XL Mechanical Sidewall Coring (XL -Rock) -Summary • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal • Lithodensity, Compensated Thermal Neutron (1:240) MD • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal Lithodensity, Compensated Thermal Neutron (1:240) TVD • Dual Gamma Ray, Azimuthal Acoustic Caliper (1:600) MD • Dual Gamma Ray, Azimuthal Acoustic Caliper (1:240) MD • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal Lithodensity, Compensated Thermal Neutron, Azimuthal Acoustic Caliper, Azimuthal Bimodal 9ECEIVE® MAR 18 2016 Acoustic (1:600) MD 0cOC • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal Lithodensity, Compensated Thermal Neutron, Azimuthal Acoustic Caliper, Azimuthal Bimodal Acoustic (1:600) TVD • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal Lithodensity, Compensated Thermal Neutron, Azimuthal Acoustic Caliper, Azimuthal Bimodal Acoustic (1:240) MD • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal Lithodensity, Compensated Thermal Neutron, Azimuthal Acoustic Caliper, Azimuthal Bimodal Acoustic (1:240) TVD • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal Lithodensity, Compensated Thermal Neutron (1:600) MD • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal Lithodensity, Compensated Thermal Neutron (1:600) TVD • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal Lithodensity, Compensated Thermal Neutron, Azimuthal Acoustic Caliper, MRIL-WD Magnetic Resonance (1:240) MD • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal Lithodensity, Compensated Thermal Neutron, Azimuthal Acoustic Caliper, MRIL-WD Magnetic Resonance (1240) TVD • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal Lithodensity, Compensated Thermal Neutron, Azimuthal Acoustic Caliper, MRIL-WD Magnetic Resonance (1:600) MD • Rate of Penetration, Dual Gamma Ray, Electromagnetic Wave Resistivity, Azimuthal • Lithodensity, Compensated Thermal Neutron, Azimuthal Acoustic Caliper, MRIL-WD Magnetic Resonance (1:600) TVD • GeoTap IDS Formation Fluid and Pressure Testing, GeoTap IDS Pretest Pressure Plots,Time Log • GeoTap IDS Formation Fluid and Pressure Testing, GeoTap IDS Pumpout Plot, Time Log • Surface Data Logging — End of Well Report • GasFact End of Well Report • 1" MD Gas Interpretation Out Log • 1" MD Mass Spectroscopy Out Original Log • 2" MD Gas Ratio Log • 2" MD Drilling Engineering Log • 2" MD Formation Evaluation Log • 5" MD Formation Evaluation Log STATE OF ALASKA ALA' 1 OIL AND GAS CONSERVATION COM¢ SION WELL COMPLETION OR RECOMPLETION kEPORT AND LOG 1a. Well Status: Oil LJ Gas SPLUG ❑ Other LJ Abandoned J SuspendedLJ 1b. Well Class: 21AAC 25.105 20AAc25m0 Development ❑ Exploratory ❑� GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No. of Completions: Service ❑ Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Caelus Energy Alaska Smith Bay, LLCAband.: 2/19/2016 215-208 316 - p 3. Address: pudded: 15. API Number: 3700 Centerpoint Drive, Suite 500, Anchorage, Ak. 99503 1/19/2016 50-879-20021-00-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 3129 FSL 3556 FEL SEC 17 T1 7N R09W UM 2/8/2016 CT -1 Top Productive Interval : 4134 FSL 3555 FEL SEC 17 T17N R09W UM 9. Ret Elevations: KB: 23.4 ft. 17. Field / Pool($): Total Depth : 4132 FSL 3553 FEL SEC 17 T17N R09W UM GL : 4.9 ft. Rig (rkb)18.5 ft. Exploration - Smith Bay, Ak.IL ' 10. Plug Back Depth MD/TVD: Mud Line: 15 ft. MD/TVD 18. Property Designation: ADL 392275 . 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19, Land Use Permit: Surface: x- 463001 y- 6152706 Zone- 5 7070 ft. and / 6943 ft. tvd LAS29943 TPI: x- 463004 y- 6153710 Zone- 5 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 463006 y-6153708 Zone- 5 Abandoned Well - N/A 1 906 ft. tvd/ss 5. Directional or Inclination Survey: Yes : attached) No 13. Water Depth, if Offshore: 121. Re-drill/Lateral Top Window MD1TVD: Submit electronic and printed information per 20 AAC 25.050 1 2.5 ft (ft MSL) I Abandoned Well - N/A 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 1. Spontaneous Potential 6. Magnetic Resonance 2. Gamma Ray 7. Formation Tester RECEIVED 3. Caliper 8. Mud Log 4. Resistivity 9. VSP 5. Porosity MAP 2016 A< 23. CASING, LINER AND CEMENTING RECORD ' -.' CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 16•' 155# X-56 23 ft.rkb 110 ft. rkb 23 ft.rkb 110 ft. rkb 24" 43bbis,15.6#, 0.96 ft3/sxs 15 ft. 10-3/4" 45.5# L-80 22 ft.rkb 2551 ft. rkb 22 ft.rkb 2510 ft.rkb 13-1/2" Inner String / Tail: 48bbis 15.8#/gal,1.15 ft3/sxs Lead:142 bbls,10.7#, 4.33 15 ft. ft3/sxs 24. Open to production or injection? Yes ❑ No I �j 25. TUBING RECORD If Yes, list each interval open (MDrfVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MD(TVD) Size and Number): pr>?,RN��ED -66fAPtE�f9M' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DATE 3 t LP Was hydraulic fracturing used during completion? Yes N 191 VERIFIED l.V 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.): Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water-Bbl:Choke Size: Gas -Oil Ratio: Test Period Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity -API (tort): sV-407 Revise 11/20 24 -Hour Rate CONTINUED ON PAGE 2 1 NIAL on RBDMS Lt, MAR 2 1 2016 v(-(xVebb 28. CORE DATA Conventional C ): Yes ❑ No ❑� Sidewall Coresi Is 8 No 0 If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD(ss) Well tested? Yes ❑ No ❑� / If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top 0 0 Permafrost - Base Sonic/not conclusive Sonictnot conclusive Attach separate pages to this form, if needed, and submit detailed test SB1 2941 2858 information, including reports, per 20 AAC 25.071. Top Nanushuk 2963 2880 SB2 4221 4090 SB3 4904 4753 Top Tulimaniq Fan (TP t) 5313 5160 Base Tulimaniq Fan 5994 5841 Top HRZ 6717 6564 LCU 6916 6763 J2 6948 6795 Formation at total depth: J2 31. List of Attachments: CT -1 Well P&A Schematic,Sperry Definitive Survey Report, P&A Casing Cut pictures, CT -1 Drilling Morning Reports. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Email: Printed Name: r /71 Title: Signature:Phone: Date:/// alb, 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 1b: Well Class - Service wells: Gas Injection, Water Injection, Water-Altemating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 11/2015 Submit ORIGINAL Only 4eC--"N C.,ELLJ Energy ALaSKa Prospect Name Tulimani4 Principal Engineer: Wafter Quay Well Type Exploration /^11711 ■`/ Drilling Contractor/Rig: Doyon Drilling/Arctic Fox Ice Dad thickness (n.): 8.0 R. Well Cfassifice[ion Producer 1■ TII! elev. (reference: M 23.42 Zane of Interest /Primary Torok AFE DRILL EVAL 87ESl6J DAYS DRILL. Zone of Interest/Secondary Ellesmenan Plug & Abandonment °"'"-I4bl Smith Bay 6 usMA a7L�5 Mqp as pereare. WEp #mnwP nwP ON. fOP wTpR North Slope, Alaska msen xME LusNoTa 4Yn9 On 16 N. 155MtX5fi ERN Cord. W ec.0 ee WMM°ad'. INC Gen. v ll" NOt1E NONE Pemnh°st 0 p 16' 1, 24" gePtn lRr.6): ISOR to aO fl. Cebw [e red SK 42r /15 bmi, Top Mug#6SWd dev IN 100 MW: Mudlu99in9: USE, BDF G59/PoMIef MW: 9.5 Sent DIVA R TVD/MD Imas"AL gRmw TM[PaOtl Uan @09Rmd/lvd Gaafa<t-mass Spee fiaee PxmwhOst 929 939 ] Le.d CamenF Paroled Freese ProtaeUOn. TOC: O IVSX: 2066 R. Mnuli 7-5)8'z 103/9'(Dese) OINGR/Ru CesM: 10.7m ."T/XM Surfage casing. 2551-TVD/2510-MD D,c :250'•6/40%. EEW 0 moon 103/4' 4550 M/R Ld0 0(C Tep Plug IS arevl Mi 5". pc Tad COMMA'. M76M rAv.e;4m pa $or.�PR�M: e' TOC: 2066ft oast, is am FSSV 024768 '" n E ro 40% I.314-Caming 2551 1 2510 13-12" L4 ak Mud1099i 3%n EiateMW'. matuiv(LOT): 19WMg xMiv. (eapeilaH) Mgdkppin.: NanushuLTOpset 2963 2903 XW'. 1029MWg//PHPA Platform Eaprns105I BASE Plup#s: IWO.R mass pec (C4a69ency)/CMR PotenNel ISMR Iuocrte: Reca—for AIT OPen HOW Pmtsnmdar N a0 orient.—sots, Wj.-mW^al dHpovd 9'a PPe Temt 563 49M 4))6 TOP PW9 R4 FMI/DSI 04907 n. FwmaO°n EvaluaEon Atom '- MOT I. Teli—W Hn 5313 5183 Cg141wenq: Primary OMecere MSR-er-xL-Reh Care-120TOOkITulimaniq Bae Turutwrio Fan 5994 5064 ROPE: TO,WTuamaNq Fan VSP MWD/LVAD: 6-3/Y Triple Combo "Cale MWe u,p Dir/GR/Ra/PWD/Den CCL/GR/OL Neutran-POMIty nwwtawcllten TOPNR2 6717 6507 6-3/rxMT 6 -3/4 -XM LCD 6916 6796 S-3/4' MAIL Wa T° f1 Open MW4 6J/4' GeMug, IDs (TD) 7x70 6943 sqjr ,D Ellesmerian Section - Net Drilled 6-3/4" Max. Wellboare Ia—NL reQrona t vznzprs o -.m mrmu Well Total Depth (TD) 7070 n. and / 6943 N. Wd mx�s sgao-aw-rrrvattsw xx Surface Location (NAD 21 131M ZONE 3 -meters) X:463001 Y: 6152706 We.'p ma.Wnmo.a�mmwuaeaua...r Surface Lmatoo(Gout Sect Line) 3129 FSL, 3S56 FEL T17N R09W Sect. 37 OHL (IUD 27 uTM ZONE 5) X: 463006 Y: 6153708 OHL (Govt Sect Line) 4132 FSL, 3493 FEL T17N RO9W Sect. 17 Projection Method NAD27/ZONE SIMM -meters Rav 1 SMITH BAY -N- QELEVAT,ON2.6. PAD ICEON 7.5'`11- 1II�///,CE.' NOTES I. SECTION LINE AND LOCATION DATA PER BLM-ALASKA. 2 DATE OF SURVEY: JANUARY 10, 2016. 3 REFERENCE FIELD BOOK: M06-01 PGS 03-5 4. COORDINATES WERE COLLECTED IN HAD 27, ALASKA STATE PLANE, ZONE 5 DATUM GEODETIC AND UTIA COORDINATES CONVERTED USING CORPSCON 6,01. 5 BASIS OF HORIZONTAL CONTROL IS PONT M1140635, DETERMINED BY NOS 2014 OPUS STATIC SURVEY SOLUTION, EPOCH 2010. 2011 ADJUSTMENT 5 COMBINED SCALE FACTOR FOR TUUMANIO CT -1 IS. 0999902007 SMITHBAY PROJECT AREA VICINITY MAP N. T LEGEND CONDUCTOR SURFACE LOCATION ICE PAD SHOULDER ---ICE PAD TOE/SEA ICE GRAPHIC SCALE 0 100 200 400 ( IN FEET ) I inch . 200 It LOCATED WITHIN PROTRACTED SECTION 17. T. 17 N.. R. 9 W.. UMIAT MERIDIAN. ALASKA WELL NA027 A. S, P. NAD27 UTM NAD27 GEODETIC NAD27 GEODETIC SECTION SEA ICE PAD N0. I ZONE 5 -US FT ZONE 5 -METERS POSITION(DMS) POSITION(D.DO) OFFSETS ICE ELEVTION CT -I N: 6,152.705 89 N: 7,858,579.03 LAT; 70'49'41.4709' ' " LAT: 70,8281864' 3,129' FSL 2.6'/7.5E: 463 001.43 E� 452 075.28 LONG:1 4'1 7. 4 LONG:1 4. 7 7 4' 3,556' FEL 1. C CllL LV V 1 - — - Tin �)I616 nrutor I TUUMANIO Doll +o HA,r AS -BUILT CONDUCTOR 1a.1 nv.an w. P . 200' WELL CT -1 Operations Summary Report - Stag Well Name: CT -1 C. CAELU S Energy Alaska Wen Name] I--, Job Category: ORIG DRILLING Start Date: 1/11/2016 End Date: 2/19/2016 start Dare End Date Start Depth (ftKa) FwWetera ft Dens Last MW (1b19.1) Summary 1/10/2016 1/11/2016 0.0 9.65 Beginning daily costs balance 1/1112016 1/12/2016 0.0 9.65 Rigging Up 1/12/2016 1/13/2016 0.0 9.65 Rigging Up 1/13/2016 1/14/2016 0.0 9.65 Rigging Up 1/14/2016 1/15/2016 0.0 9.65 Rigging up 1/15/2016 1/16/2016 0.0 9.65 Rigging Up. 1/16/2016 1/17/2016 0.0 9.65 Rigging Up. 1/17/2016 1/18/2016 0.0 3.00 Nipple up diverter system. Load pipe shed with 5" drill pipe. 1/18/2016 1/19/2016 0.0 9.50 Test diverter system and 1-12S combustable alarms. Test witnessed by AOGCC rep Johnny Hill. 1119/2016 1/20/2016 98.0 163.00 9.55 MU 13-1/2" BHA#100. Cleanout 16" conductor from 22'- 98'. Drill 13-1/2" Surface hole from 98' to 261'. 1/2012016 1/21/2016 261.0 1,034.00 9.70 Drill 13-112" Surface hole from 261'to 1295'. 1/2112016 1/22/2016 1,295.0 1,139.00 9.70 Drill 13-1/2" Surface hole from 1295'to 2434'. 1/22/2016 1/23/2016 2,434.0 130.00 9.80 Drill 13-1/2" surface hole from 2434' to 2564', circulate, POOH. PU BHA #1, RIH to 167'. 1/23/2016 1/24/2016 2,564.0 0.00 9.80 RIH w/ BHA #100 to 2564'. POOH from 2564'to 167'. Mad Pass from 400'to 100'. PU FMC landing p and hanger for dummy run. RU GBR casing equipment. 1124/2016 1125/2016 2,564.0 0.00 9.80 RIH w/ 10-3/4" 45.5# L80 BTC casing. MU FMC mandrel hanger and land casing. 1/25/2016 1126/2016 2,564.0 0.00 9.80 Cement 10-3/4" 45.5# L80 BTC surface casing at 2564'. tunea spacer, followed by 335 sacks/258 bbls 10.7 ppg Test ines, pump 5u obis of 10.5 ppg Lead class G cement and 260 sacks, 48.4 bbls, 15.8 ppg Tail class G cement. Drop dart and displace with 42 bbls of fresh water. Bump plug 500 psi over at 1140 psi. Check floats. Bleed off pressure. CIP at 1300 hours. 115 bbls of cement to surface. POOH w/Davis Lynch inner string adapter. NO 21-1/4" diverter. 1/26/2016 1/27/2016 2,564.0 0.00 9.80 ND 21-1/4" diverster system. NU FMC 11" x 5M Gen V wellhead system. NU 11"x 5M shaeffer BOPE. 1127/2016 1/28/2016 2,564.0 0.00 9.80 Test BOPE - 11"x 5" "•AOGCC Matt Herrera witnessed test- PU BHA for drilling out casing shoe -10-3/4" 1/28/2016 1/29/2016 2,564.0 0.00 9.50 RIH w/ 9-7/8" cleanout BHA. Tag float collar at 2463'. Test casing (10-3/4") to 3000 psi for 30 15.7 MWE. POOH, minutes. Drill shoe track plus 20' new hole to 2584'. Perform LOT to ppg LD BHA, PU BHA #3. 1/29/2016 1130/2016 2,584.0 466.00 9.50 RIH wBHA #3 to 2584'. Drill from 2584' to 3050'. (Hole size: 9-718") 1/30/2016 1/31/2016 3,050.0 1,179.00 9.70 Drilling 8-1/2" intermediate hole section from 3050'- 4229'. At 3700', observing stickslip. Adjust drilling parameters. 1131/2016 211/2016 4,229.0 964.00 9.70 Drilling 8-1/2" intermediate hole section from 4229' to 5193'. Backreaming each connection 40'. a,.w. aronn�a Page V3 ,.�N..,., _. _.__._ I Summary Report -Stag Well Name: CT-1 CA-PLUSOperations Energy Alaska Start Date Ertl Date Start Depth flKa FooVMeters (fl Dens Last Mud Q("gol Summary 211/2016 2!2/2016 5,193.0 741.00 9.70 Drill 8-1/2" intermediate hole section from 5193' - 5415'. Notice pump pressure drop from 1910 psi to 1730 psi. POOH -found washout at 668'. RIH, drill from 5415'- 5934'. 2/2/2016 213/2016 5,934.0 620.00 9.65 Drill 8-1/2" intermediate hole from 5934'- 6554'. 2/3/2016 2/412016 6,554.0 91.00 9.80 Drill 8-1/2" intermediate hole from 6554' to intermediate casing point at 6645'. Shorttrip to 10- 3/4" shoe a12547'. RIH fo TD at 6645'. POOH to 6069'. 2/4/2016 2/5/2016 6,645.0 0.00 9.75 POOH & LD BHA #3. Test BOPE. ""AOGCC Lou Grimaldi waived witness*" RD BOPE test equipment. RU SWS for first E-Line logging run. 2/5/2016 2/6/2016 6,645.0 0.00 9.80 Continuing with a-line loggs. 2/6/2016 217/2016 6,645.0 0.00 9.75 Continue with logging having no problems. 2/7/2016 21812016 6,645.0 0.00 9.75 Complete SWS E-Line log run #4. LD SWS E-Line equipment. PU 6-3/4" BHA #4, RIH to 2400'. 2/8/2016 219/2016 6,645.0 425.00 RIH from 2400' to 6645'. Drill 6-3/4" hole from 6645'to 7070'. Short trip to 6449'. Circulate, POOH from 7070'- 5408'. 2/9/2016 2/10/2016 7,070.0 0.00 10.10 POOH from 5408' to surface. LD BHA #4. RU SWS E-Line & VSP logging equipment, RIH. 211012016 2/11/2016 7,070.0 0.00 10.10 Complete wireline logging. LD HWDP, PU 2-7/8" cement stinger string, RIH f/ surface to 7069' MD. Pump abandonment plug #1 'Pump 18.5bbis of 10.5ppg cement spacer. "Pump 44bbls of 15.8ppg cement *Pump 1.5bbls 10.5ppg spacer 'Displace with 98.5bbls of 10.2ppg mud 7/ POOH to 6501' MD and pump abandonment plug #2 *Pump 18.5bbls of 10.5ppg cement spacer. 'Pump 35bbis of 15.8ppg cement "Pump 1.5bbls 10.5ppg spacer 'Displace with 90bbls of 10.2ppg mud POOH to 5996' MD and prepare to pump abandonment plug #3 Note; AOGCC Bob Noble waived witness of BOP test at 09:45 2110116 2/11/2016 2/12/2016 7,070.0 0.00 10.10 At 5996' MD pump abandonment plug #3 17 `Pump 18.5bbis of 10.5ppg cement spacer. `Pump 35bbls of 15.8ppg cement `Pump 1.5bbls 10.5ppg spacer 'Displace with 82bbls of 10.2ppg mud POOH to 5492' MD and pump abandonment plug #4 "Pump 18.5bbls of 10.5ppg cement spacer. `Pump 46bbls of 15.8ppg cement "Pump 1.5bbls 10.5ppg spacer ' *Displace with 72bbls of 10.2ppg mud Top of abandonment plug #4 is 4837' MD, POOH with cement stinger BHA. Test BOPS: Test all BOPe to AOGCC specifications. Test annular to 250 low psi and 2500 high psi, lest both pipe rams, blind rams choke manifold (15 valves), 2 Floor valves, 1 hydraulic choke valve and 1 manual choke valve. Test Koomey unit system pressure = 2950, pressure after Gose 1700, 200 psi increase with electric pump 12 seconds, full pressure attained in 84 seconds. 6 Nitrogen bottles average pressure = 2100 psi Note; AOGCC Bob Noble waived witness of BOP test at 09:45 2/10/16 Page 213 Report Printed: 319/2016 Operations Summary Report - Statin Well Name: CT -1 CE CAELUS Energy Alaska Page 313 Report Printed: 3/9/2016 Start Date End Date Start Depth MKS Fo eters fl Dens Last Mutl (lb/ Summary 2/12/2016 2/1312016 7,070.0 10.20 MU BHA, RIH, circ. and condition mud. Wash/ream down to top of cement plug #4 from 4701' to 4907'. Set 15k down on top plug #4. WOC: 26.5 hrs. Inject mud from pits, rock washer and upright storage facility. INJECTION RATES; 3 bbl/min at 450 psi with 10.2 ppg mud. at 19:30 hrs, 9.9 ppg MW, 48 vis, 508 psi at 3 bbls/min. at 20:10 hrs. 8.7 ppg MW, with 35 vis, 540 psi at 3 bbls/min. at 20:40 hrs. 9.9 ppg MW. with 48 vis. 600 psi at 2.8 bbls/min. at 21:00 hrs. 9.3 ppg MW, with 38 vis, 615 psi at 1.5 bbls/min. at 22:00 hrs. 9.5 ppg MW, with 40 vis, 625 psi at 2 bbls/min with 835 barrels away. at 22:45 hrs. 9.7 ppg MW, with 44 vis, 600 psi at 3 bbls/min. 2/13/2016 2114/2016 7,070.0 10.20 Due to phase 3 weather conditions waste fluid could not be transported from the tank farm to the rig. When injecting waste fluid was stopped the well was opened up to the trip tank and returns and well pressure was monitored. The total fluid returned from the well was 53.5 barrels. After flow from the well had stopped the drill string was moved, pick up weight = 140k and the slack off weight was 80k. The second time the drill string was worked the pickup weight was 90k and the slack off weight was 80k. From then on the drill string was moved every 15 minutes with no fight hole. 2/14/2016 2/15/2016 7,070.0 10.20 Shut down with injecting waste drilling fluid because of phase 3 weather. Start injecting at 02:00 hrs. 4 bbls/min with 450 psi. 2/15/2016 2/16/2016 7,070.0 9.80 Injected a total of 3861 bbls of waste slurry down annulus. Blow down Halliburton lines and R/U to bleed off annulus pressure with a total of 97.4 WIS. POOH fl 3072- 2505' LDDP. Monitor well. CBU X 1.5 while rotating and reciprocating. 2/16/2016 2/17/2016 7,070.0 9.80 MU Halliburton EZSV and RIH on 5" DP. Set at 2476'. Shear pins & CBU. Pump plug : "100 bbls 15.8 cement below EZSV at 2476'. Unsting from EZSV, sump 10 bbls 15.8 cement slurry above EZSV. POOH to 2200', test casing to 1500 psi, test bleeding off. Attempt to retest casing - bleeding off. POOH w/EZSV running tool. RIH w/Halliburton cast iron bridge plug. Attempt to test 10-3/4" casing against bridge plug, test to 1200 psi - lose pressure test. 2/17/2016 2/16/2016 7,070.0 9.80 Monitor well. POOH & PU RTTS tool. RIH to 570'. Pressure test below 570' for 30 minutes at 1500 psi. 10-3/4" pressure test passed. Attempt to pressure teste above RTTS at 570'. Test failed. POOH to 444', set RTTS, test 10-3/4" casing above 444' to 1500 psi - passed. POOH, RIH w/EZSV to 538', set EZSV. POOH and LD running tool. RIH, tag retainer at 538'. RU to pump plug #6. 31 bbls, 15.6 ppg "C" Cement. POOH from 538'to 94'. PU 10' pup, spot tail at 100'. RU for cement job at 100' (Plug #7). 2/18/2016 2/19/2016 7,070.0 9.80 RU & pump Plug #7 from 1 00'to surface. 21 bbls, 15.6 ppg class "C" Walton Cement. GBR cut gusset plates and base place from from 16" conductor. RIH & tag cement top at 48' rkb (21.5' below mudline elevation). MU Baker 10-3/4" casing cutter, RIH, cut 10-3/4" casing at 18' below landing ring (15' below mudline). POOH, RD Baker casing cutter. RD bell nipple, choke & kill lines. 2/19/2016 2/20/2016 7,070.0 9.80 ND BOPE. MU Baker 10-3/4" spear assembly. Pull 18' cut off 10-3/4" casing. MU Baker 16" conductor cutting assembly. Cut 16" at 38'. POOH and LD Baker casing cutter. Cut conductor (16') from cellar and remove 15' of 16" conductor casing. LD. Commence Arctic Fox RD Operations. Release rig @ 2400 hrs 2/19116. Page 313 Report Printed: 3/9/2016 CT -1 P&A 16" 155# X56 ERW Conductor/FMC Weld -on Landing Ring 2-20-2016 .7 4!4;4 VA to CT -1 P&A 16" 155# X56 ERW Conductor Csg. stub removal 2-20-2016 M ate' a �,���. � � +1��"�.."+�;•' '�.� , 4 a. pFpbt r ++ At ® 193 1.94 195 196 CT -1 P&A 16" 155# X56 ERW Conductor Csg. stub removal 2-20-2016 —AOL" ANT Ile L iA. 7 -7; A pr VIA 'If lok APAL 10-3/4" 45.5# L80 BTC '.� •o M �4! Surface Csg. stub removal ,; , ♦* + - 2-20-2016A14 It t � .- �i` �-}•�by�' .+<e�. ",�i��,q may. 'Y_ �4 d�CF``� .. r.. �6i.>�_ +. i't � K�`W"n`f 3•i i.e'I'e""yse....,.�.^. 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T i{ �' !,. �,--- -- /Y �� � . -- /J ;\ , ` '`� Caelus Energy Alaska Smith Bay Tulimaniq CT -1 50-879-20021-00-00 Sperry Drilling Definitive Survey Report 22 February, 2016 HALLIBURTON Sparry Drilling Company: Caelus Energy Alaska Project: Smith Bay Site: Tulimaniq Well: CT -1 Wellbore: CT -1 Design: CT -1 Halliburton Definitive Survey Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well CT-1- Actual:18.5' + 4.9'@ 23.40usft (Arctic Fox) Actual 18.5'+ 4,9•@ 23.40usft(Arctic Fox) True Minimum Curvature EDMPrd 'roject Smith Bay lap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level foo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point lap Zone: Alaska Zone 05 Using geodetic scale factor Well CT -1 Well Position -NIS 0.00 usft Northing: 6,152,705.89 usft Latitude: 70' 49'41.471 N TVD +E/ -W 0.00 usft Easting: 463,001.43 usft Longitude: 154' 18' 27.264 W Position Uncertainty (usft) 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 4.90 usft Wellbore CT -1 Magnetics Model Name IGRF2010 Design CT -1 Audit Notes: Sample Date Declination r) 1/20/2016 Version: 1.0 Phase: Vertical Section: Depth From (TVD) (usft) 18.50 survey Program-- -- _. --Date 2/22/2016 From To (usft) (usft) Surrey (Wellbore) 253.21 2,520.78 MWD+SC+sag (1) (CT -1) 2,599.16 7,015.97 MWD+SC+sag(2)(CT-1) Survey ACTUAL +NIS (usft) 0.00 Tool Name MWD+SC+sag MWD+SC+sag Dip Angle l°) 17.35 Tie On Depth +EAW (usft) 0.00 Field Strength K) 80.87 57,634 18.50 Direction (°i 0.00 Description Fixed:v2:standard dec & axial correction + sag Fixed: v2: standard dec & axial correction + sag 2/22!2015 3:42'11PM Page 2 COMPASS 5000.1 Build 58 Map Map Vertical MD Inc Azi TVD TVDSS +NIS +EI -W Northing Easting DLS Section (usft) rl r) (usft) (usft) (usft) (usft) (f) (ft) ("1100') (ft) Survey Tool Name 1850 0.00 0.00 18.50 4.90 000 0.00 6,152.70589 463,001.43 0.00 000 UNDEFINED 253.21 0.23 14988 25321 229.81 -0.41 0.24 6.152.70548 463,00166 0.10 -0.41 MWD+SC+aag(1) 302.31 0.19 193.31 302.31 27891 4).57 0.27 6,152,705.32 463,001.69 0.33 -0.57 MW +SC+589(1) 368.52 0.39 225.46 368.52 345.12 -0.84 0.08 6,152705.05 463,001.51 0.38 4).84 MWD+SC+sag (1) 423.28 0.53 212.06 423.26 399.86 -1.18 -0.19 6.152,704.71 463,001 24 0.32 -1.18 MWD+SC+sag (1) 529.44 0.45 207.72 52943 506.03 -1.97 -0.M 6,152,70393 463000.78 0.08 -1.97 MWD+SC+sag(1) 555.09 0.32 197.42 55588 531.68 -2.12 -0.71 6,152,703.77 463,00031 0.57 -2.12 MWD+SC+mg(1) 616.77 0.32 284.30 616.76 593.36 -2.25 4).93 6.152.703.65 463.000.49 071 -2.25 MWD+SC+.g(1) 712.59 1.46 349.98 712.57 689.17 -0.98 -1.40 6,152,704.92 463.000.03 1.42 -0.98 MWD+SC+sag(1) 744.46 2.07 349.20 744.42 721.02 -0.01 -1.58 6.152,705.88 462,999.85 1.92 -0.01 MWD+SC+sag(1) $07.31 2.27 349.19 807.23 783.83 2.32 -2.02 6,152.708.22 462,999.42 0.32 2.32 MWD+SC+sag(1) 870.75 3.33 355.09 870.59 847.19 5.39 -2.42 6.152,711.30 462,999.04 1.73 5.39 MWD+$C+mg(1) 933.84 4.07 0.78 933.55 910.15 9.46 -2.54 6,152,715.36 462,998.93 1.31 9.46 MWD+SC+sag(1) 2/22!2015 3:42'11PM Page 2 COMPASS 5000.1 Build 58 Halliburton Definitive Survey Report Company: Caelus Energy Alaska Local Co-ordinate Reference: Well CT -1 - Project: Smith Bay ND Reference: Actual: 18.5'+ 4.9'Q 23.40usit(Arctic Fox) Site: Tulimaniq MD Reference: Actual:18.5' +4,9' & 23.40usft (Arctic Fox) Well: CT -1 North Reference: True Wellbore: CT -1 Survey Calculation Method: Minimum Curvature Design: CT -1 Database: EDMPrd Survey Vertical Section (ft) Survey Tool Name 1441 M'ND+SC+sag(1) 20.35 MWD+SC+sag(1) 27.32 MWD+SC+sag(1) 35.48 MWD+SC+sag(1) 44.68 MWD+SC+sag(1) 54.60 M`ND+SC+sag(1) 65.64 MWD+SC+sag(1) 77.08 M`ND+SC+sag(1) 89.50 MWD+SC+sag(1) 102.58 M'ND+SC+sag 11) 116.21 MWD+SC+sag(1) 130.84 MWD+SC+mg(1) 144.88 MWD+SC+sag(1) 161.06 MWD+SC+sag(1) 176.68 M'ND+SC+sag(1) 192.44 M4ND+SC+sag(1) 208.80 MWD+SC+mg(1) 225.50 MWD+SC+sag(1) 242.41 MWD+SC+sag(1) 259.58 MWD+SC+sag(1) 277,00 MWD+SC+sag (1) 294.15 M`ND+SC+sag(1) 311.40 MWD+SC+sag(1) 325.31 MWD+SC+mg(1) 348.91 MWD+SC+sag(1) 370.57 MWD+SC+sag(2) 387.81 MWD+SC+aag(2) 404.74 M'ND+SC+sag (2) 421.69 MWD+SC+sag(2) 436.86 MWD+SC+sag(2) 455.43 MWD+SC+sag 12) 473.01 MWD+SC+sag(2) 487.42 MWD+SC+sag(2) 50787 MWD+SC+aag(2) 525.16 MWD+SC+sag(2) 542.45 MW13+SC+sag(2) 559.46 MWD+SC+sag(2) 576.87 MW +SC+sag(2) 593.89 MWD+SC+sag(2) 811.27 MWD+SC+sag(2) 2,7212016 3:42:11PM Page 3 COMPASS 5000.1 Build 58 Map Map MD Inc Azi TVD TVDSS +N/.S +E! -W Northing Easting DLS (usR) 11 (1) (usft) (usfy (usft) (usiry (ft) (ft) (°/1001 996.51 4.99 1.37 996.02 972.62 14.41 -245 6,152720.31 462,999.06 147 106027 5.70 1.09 105951 1,036.11 2036. -2.32 6,152726.24 462,999.21 1.11 1,12360 694 1.37 1,122.45 1,09905 27.32 -2.17 6.152.73321 462.999.40 1.96 1,186.53 7.98 359.95 1,184.85 1,161.45 35.48 -2.08 6,152.741.38 462999.53 1.68 1.249.98 8.69 359.87 1,247.63 1,224.23 44.68 -2.10 6,152,750.58 46299958 1,12 131243 9.58 0.00 1309.28 1,285.88 54.60 -2.11 6,152.760.49 462,999.60 1.43 1,376.21 10.36 028 1372.10 1,348.70 6564 -2.08 6,152,771.53 462.999.68 122 1438.47 10.84 2.82 1433.30 1409.90 7708 -1.77 6,152782.97 463,000.05 1.08 1,501.87 1178 2.93 1,495.47 1472.07 89.50 -1.14 6,152,795.39 463,000.74 148 1,564.55 12.34 3.24 1.556.76 1,533.36 102.58 444 6,152,80846 A630151 0.90 1,626.81 12.99 2.05 1,617.51 1,594.11 116.21 0.19 6,152.822.09 463,002.21 1.12 1,690.19 13.71 359.27 1,679.18 1055.78 130.84 0.35 6,152,836.72 463,002.44 1,52 1,749.63 13.62 35900 1,736.93 1,713.53 144.88 0.13 6,152.850.76 463,002,30 0.19 1,816.84 14.24 358.64 1.802.17 1,778.77 161.06 4.20 6,152,866.93 463,002,05 0.93 1,880.33 1425 358.59 1,863.70 1.840.30 176.68 -0.58 6.152,882.55 463,001]5 0,02 1,943.07 14.86 358.93 1924.43 1,901.03 192.44 -0.92 6,152,898.32 463,001.49 0.98 2,00637 15.09 358.61 1985.58 1962.18 208.80 -1.27 6,152.914.67 463,001.22 0.39 2,069.67 15.53 35833 2,04663 2,023.23 225.50 -172 6,152.931.38 463,000.86 070 2,132.89 15.51 358.34 2,107.55 2.084.15 242.41 -2.21 6,152,948.29 463,000.45 0.03 2.196.24 15.94 359.22 2168.53 2,145.13 259.58 -2.57 6,152,965.45 463,000.17 078 2,25981 15.87 359.27 2,22966 2,206.26 277.00 -2.80 6,152,982.87 463.000.03 0.11 2,322% 15M 0.53 2.290.44 2,267.04 294.15 -2.83 6,153,0W 02 463,000.09 0.64 2385.69 16.26 025 2,350.75 2,327.35 311.40 .2.72 6.153 017+27 463000.29 0.96 243549 16.18 0.62 2,398.57 2,375.17 325,31 -2.61 6,153 03118 463,000.47 016 2,520.78 15.95 0.38 2,480.53 2,457.13 348.91 -2.40 6,153,05478 463,000.80 0.28 2,599.16 16.13 359.83 2555.86 2,632.46 370.57 -2.36 6,153,07643 463,000.94 0.30 2,661.81 15.82 359.72 2,616.09 2.592.69 387.81 -2.43 6,153,09367 463000.96 0.50 2.724.39 15.57 359.37 2,676.33 265293 404.74 -2.57 6,15311060 463,000.92 0.43 2387.40 1565 358.33 2.737.02 2,713.62 42169 -2.91 6153.127.55 463,000.66 0.46 2,843,82 15.56 357.18 2.791.36 2767.96 43686 -3.50 6,153,14271 463,000.14 0.57 2912.21 1602 356,03 2,857.17 2,833.77 45543 4.61 6,153,161.29 462.999.13 0.81 2.975.92 16.16 353.73 2,918.38 2,894.98 473.01 6.18 6,153,178.88 462,997.65 1.02 3,028.04 16.10 354.35 2968.45 2,945.05 48742 -7.69 6,153,193.29 462,996.22 0.35 3,102.95 15.70 356.58 3,040.50 3,017.10 50787 -9.31 6.153,213.75 462,994.69 0.97 3,166.90 1570 358.42 3.102.06 3,078.66 525.16 -10.07 6,153,23104 462,994.03 0.78 3,230.68 15.78 35900 3.163.45 3.140.05 542.45 -10.46 6,153,248.34 462,993.72 0.26 3,293.25 15.76 1.06 3,223.66 3,200.26 559.46 -10.45 6,153,265.34 462,993.82 090 3.356.15 16.02 1.01 3284.16 3,260.76 576.67 -10.14 6,153,282.55 462,994.22 0.41 3,418.59 1600 1.13 3,344.18 3,320.78 593.89 -9.82 6,153,299.77 462.994.63 0.06 3,481.50 16.08 2.22 3,40664 3,381.24 611.27 -9.31 6,153,317.14 462,995.22 0.50 Vertical Section (ft) Survey Tool Name 1441 M'ND+SC+sag(1) 20.35 MWD+SC+sag(1) 27.32 MWD+SC+sag(1) 35.48 MWD+SC+sag(1) 44.68 MWD+SC+sag(1) 54.60 M`ND+SC+sag(1) 65.64 MWD+SC+sag(1) 77.08 M`ND+SC+sag(1) 89.50 MWD+SC+sag(1) 102.58 M'ND+SC+sag 11) 116.21 MWD+SC+sag(1) 130.84 MWD+SC+mg(1) 144.88 MWD+SC+sag(1) 161.06 MWD+SC+sag(1) 176.68 M'ND+SC+sag(1) 192.44 M4ND+SC+sag(1) 208.80 MWD+SC+mg(1) 225.50 MWD+SC+sag(1) 242.41 MWD+SC+sag(1) 259.58 MWD+SC+sag(1) 277,00 MWD+SC+sag (1) 294.15 M`ND+SC+sag(1) 311.40 MWD+SC+sag(1) 325.31 MWD+SC+mg(1) 348.91 MWD+SC+sag(1) 370.57 MWD+SC+sag(2) 387.81 MWD+SC+aag(2) 404.74 M'ND+SC+sag (2) 421.69 MWD+SC+sag(2) 436.86 MWD+SC+sag(2) 455.43 MWD+SC+sag 12) 473.01 MWD+SC+sag(2) 487.42 MWD+SC+sag(2) 50787 MWD+SC+aag(2) 525.16 MWD+SC+sag(2) 542.45 MW13+SC+sag(2) 559.46 MWD+SC+sag(2) 576.87 MW +SC+sag(2) 593.89 MWD+SC+sag(2) 811.27 MWD+SC+sag(2) 2,7212016 3:42:11PM Page 3 COMPASS 5000.1 Build 58 Company: Caelus Energy Alaska Project: Smith Bay Site: - Tulimaniq Well: CT -1 Wellbore: CT -1 Design: CT -1 Survey Halliburton Definitive Survey Report Local Coordinate Reference: Well CT -1 TVD Reference: Actual. 18.5'+ 4.9'@ 23.40usft (Arctic Fox) MO Reference: Actual:18.5'+ 4.9'@ 23.40usn(Arctic Fox) North Reference: True Survey Calculation Method: Minimum Curvature Database: EDMPrd Vertical Section (ft) Survey Tool Name 628.86 M'ND+SC+sag (2) 846.12 MWD+SC+sag(2) 66269 MM+SC+sag(2) 679.94 MWO+SC+sag(2) 697.13 MWD+SC+sag(2) 71443 MWO+SC+sag(2) 73160 MWD+SC+sag(2) 74873 MWD+SC+sag(2) 766.06 MWD+SC+sag(2) 782.98 MWD+SC+sag(2) 800.44 MV D SC+sag (2) 817.45 MWD+SC+sag(2) 834.23 MWD+SC+mg(2) 851.68 MWD+SC+sag(2) 868.52 MWD+SC+Sag(2) 886.03 MWD+SC+sag(2) 903.21 MWD+SC+5ag(2) 91950 MWD+SC+Sag(2) 933.94 MWD+SC+sag(2) 948.33 MWD+SC+sag(2) 96004 MWD+SC+sag(2) 97077 MND+SC+sag(2) 979.38 MWD+SC+sag(2) 986.87 MWD+SC+sag(2) 99290 MWD+SC+sag(2) 999.06 MWD+SC+sag(2) 1,002.65 MWD+SC+sag(2) 1,004.12 MWD+SC+sag (2) 1,004.54 MWD+SC+sag(2) 1,00461 MWD+SC+sag(2) 1,004.47 MWD+SC+sag(2) 1004.29 M`ND+SC+sag(2) 1,004.22 MWD+SC+sag(2) 1004.31 MWD+SC+sag(2) 1,004.50 MWD+SC+sag(2) 1.004.71 MWD+SC+Sag(2) 1,004.97 MWD+SC+sag(2) 1,004.72 MWD+SC+sa9(2) 1,004.21 MWD+SC+sag (2) 1,003.95 MWO+SC+sag(2) M212015 3:42:11PM Page 4 COMPASS 5000.1 Build 58 Map Map MD Inc Azi TVD TVDSS +Nl-S +PJ -W Northing Easting DLS Wait) (1) PI Welt) (nsf) 1 -ft) (usft) (ft) (ft) ('110o.) 3,54573 15.77 424 346641 3,443.01 628.86 4.32 6,153334.72 462,996.30 0.95 3,609.59 1570 4.85 3.527.87 3,504.47 646.12 695 6,153,35198 462,997.76 0.28 3,671.02 15.69 3.87 3.587.01 3,56361 66269 ,568 6,153,36854 462,999.11 0.43 3,734.59 15.83 443 3,648.29 3,624.89 679.94 4.43 6,153,385.78 463,000.45 0.32 3,797.66 15.97 5.13 3708.85 3,685.45 697.13 -2.99 6,153402.96 463001.97 0.38 3,860.90 15.92 5.17 3,76966 3746.26 714.43 AA3 6,153,420.25 463,00362 0.08 3,924.04 15.72 2.50 3,830.41 3.807.01 731.60 -0.28 6,153,437.41 463,004.86 1.20 3,986.97 15.89 358.79 3,890.96 3,86]56 748.73 -009 6.153,454.54 463,005.14 1.63 4,050.40 15.82 359.16 3,951.98 3,928.58 766.06 -0.40 6,153,471.87 463,004.91 0.19 4,112.77 15.66 358.82 4,012.01 3,986.61 782.98 670 6,153,488.78 463,004.70 0.30 4,177.14 1563 359.33 4,073.96 4,050.56 80044 -0.98 6,153,506.25 463,004.51 0.34 4,239.64 15.76 1.47 4.134.10 4,11070 817.45 4.86 6,153523.25 463004.71 094 4301.44 15.77 1.82 4,193.58 4,170.18 834.23 -038 6,153540.03 463.005.28 0.15 4,365.81 15.70 172 4,255.53 4,232.13 851.68 0.16 6,153,557.48 463,005.91 0.12 4,427.87 15.79 1.29 4,315.27 4,291.87 868.52 0.60 6.153 574.31 463,008.44 024 4,491.86 15.98 0.85 4,376.81 4,35341 886.03 093 6,153,591.81 463006.85 0.35 4,554.88 15.68 2.49 4.437.44 4,414.04 90321 1.43 6,153608.99 463,007.44 0.85 4,617.88 14.31 2.13 4,498.30 4,474.90 91950 2.09 6,153,625.27 453,008.18 2.18 4,678.50 13.28 2.04 4,557.17 4.533.71 933.94 2.61 6,153,639.71 463,008.78 1.70 4,744.48 1192 0.16 4.621.56 4,598.16 948.33 2.90 5153,654.10 463009.14 2.15 4,805.59 1018 358.21 4,681.53 4,658.13 960.04 2.75 6,153,665.81 463.009.05 291 4,87043 8.89 358.18 4.745.47 4,722.07 97077 2.41 6,153.676.54 463,008.76 1.99 4,931.72 7,28 356.21 4,806.15 4,782.75 979.38 2.01 6,153,6a5A5 463008.40 2.67 4,995.39 6.29 353.64 4,869.38 4,845.98 986.87 1.35 6.153 692.65 463,007.78 1.63 5,053.65 5.67 352.16 4,927.32 4,90392 992.90 0.59 6,153,698.67 463,007.06 1.09 5,124.03 4.51 349.14 4,997.42 4,974.02 99906 -0.40 6,153704.84 463,006.09 1.69 5.186.59 2.20 348.45 5,059.67 5,036.47 100265 -1.10 64153,708.44 463400541 3.69 6,248.68 062 334.11 5,121.92 5,09852 1004,12 -1.49 6,153,709.91 463,005.03 2.59 5,311.81 0.20 351.15 5,185.07 5,161.67 1.004.54 -1.66 6,153,710.32 463,004.87 0.69 5,375.68 0.13 242.94 5.246.94 5,225.54 1004.61 -1.74 6,153,710.40 463,004.79 0.42 5,43870 0.22 200.50 5,311.96 5288.56 1,004.47 -1.84 6,153,710.26 463,004.68 0.24 5,498.97 0.18 134.09 5372.23 5348.83 1,004.29 -1.82 6,153.710.08 463,004,71 0.37 5562.10 0.13 91.18 5,435.36 5,411.96 1,004.22 -1.67 6,153,710.01 463004.85 0.19 5.623.43 022 44.42 5.496.69 5,473.29 1,004.31 -1.52 6,153,710.09 463,005.00 0.26 5.688.56 0.19 9.81 5,561.82 5,538.42 1004.50 4.42 6,153,710.29 463,005.11 0.19 5,746.14 0.24 13.52 5.619.40 5596.00 100471 -1.37 6,153.710.50 463,005.15 0.09 5,811.21 0.31 312.65 5,684.46 swim 1,004.97 -1.47 6,153,71075 463005.06 0.44 5,880.07 0.63 19275 5,753.32 5,72992 1.004.72 -1.69 6,153,710.51 463,004.83 1.20 5942.15 0.39 148.08 5,815.40 5,792.00 1,00421 -1.65 6,153,710.00 463,004.87 0.72 5005.35 026 123.16 5,878.60 5,855.20 1,003.95 -1.42 6,153,709.73 463,005.10 0.30 Vertical Section (ft) Survey Tool Name 628.86 M'ND+SC+sag (2) 846.12 MWD+SC+sag(2) 66269 MM+SC+sag(2) 679.94 MWO+SC+sag(2) 697.13 MWD+SC+sag(2) 71443 MWO+SC+sag(2) 73160 MWD+SC+sag(2) 74873 MWD+SC+sag(2) 766.06 MWD+SC+sag(2) 782.98 MWD+SC+sag(2) 800.44 MV D SC+sag (2) 817.45 MWD+SC+sag(2) 834.23 MWD+SC+mg(2) 851.68 MWD+SC+sag(2) 868.52 MWD+SC+Sag(2) 886.03 MWD+SC+sag(2) 903.21 MWD+SC+5ag(2) 91950 MWD+SC+Sag(2) 933.94 MWD+SC+sag(2) 948.33 MWD+SC+sag(2) 96004 MWD+SC+sag(2) 97077 MND+SC+sag(2) 979.38 MWD+SC+sag(2) 986.87 MWD+SC+sag(2) 99290 MWD+SC+sag(2) 999.06 MWD+SC+sag(2) 1,002.65 MWD+SC+sag(2) 1,004.12 MWD+SC+sag (2) 1,004.54 MWD+SC+sag(2) 1,00461 MWD+SC+sag(2) 1,004.47 MWD+SC+sag(2) 1004.29 M`ND+SC+sag(2) 1,004.22 MWD+SC+sag(2) 1004.31 MWD+SC+sag(2) 1,004.50 MWD+SC+sag(2) 1.004.71 MWD+SC+Sag(2) 1,004.97 MWD+SC+sag(2) 1,004.72 MWD+SC+sa9(2) 1,004.21 MWD+SC+sag (2) 1,003.95 MWO+SC+sag(2) M212015 3:42:11PM Page 4 COMPASS 5000.1 Build 58 Halliburton Definitive Survey Report Company: Caelus Energy Alaska Local Co-ordinate Reference: Well CT -1 Project: Smith Bay TVD Reference: Actual: 18.5' +4.9' Qa 23.40usft (Arctic Fox) Site: Tulimaniq MD Reference: Actual:18.5'+4,9' @ 23.40usft (Arctic Fox) Well: CT -1 North Reference: True Wellbore: CT -1 Survey Calculation Method: Minimum Curvature Design: CT -1 Database: EDMPrd Survey Checked By: n..n, .' "'^-" ^'� Approved By: <°om"'�1o.n'o°vCel°�`"""` = Date: 02/22/2016 2/222016 3:42:11PM Page 5 COMPASS 5000.1 Build 58 Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/.W Northing Easting OLS Section (usft) (1 (') (usft) (usft) (usft) (usfq (ft) (ft) (7100') (ft) Survey Tool Name 6,069.42 0.27 352.61 5,942.67 5,919.27 1,004.02 -1.32 6 15709.80 463,005.20 0.75 1,004.02 M'NO+SC+sag(2) 6,132.20 0.38 303.45 6,005.45 5,982.05 1,004.28 -1,51 6,153 710.07 463005.01 0.46 1,004.28 MWD+SC+sag(2) 6.195.05 0.40 248.75 6,068.30 6,04490 1,004.32 -1,89 6,153710.10 463,004.63 0.57 1,004.32 MWD+SC+sag(2) 6,253.77 0.26 239.25 6,127.02 6,103.62 1,004.17 -2.19 6,153,709.96 463,004.33 0.26 1,004.17 MWD+SC+sag(2) 6,317.21 0.12 254.64 6,190.46 6.16]06 1,004.08 -2.38 6,153,709.87 463004.14 0.23 1,004.08 MWD+SC+sag (2) 6,382.55 0.06 6670 6,255.80 6,23240 1.004.08 4.42 6,153,709.87 463004.11 0.27 1004.08 MWO+SC+sag(2) 6,43940 0.13 166.13 6,312.65 6,289.25 1,004.03 -2.37 6,153,70982 463.004.15 0.27 1,004.03 MWD+SC+sag(2) 6,511.66 0.18 130.48 6,384.91 6,361.51 1,003.87 -2:27 6,153,709.66 463,004.25 0.15 1,003.87 MWU+SC+sag(2) 6,574.21 0.14 161.54 6,447.46 6,424.06 1003.74 -2.17 6.153709.53 463,004.35 0.15 1,003.74 MWD+SC+sag(2) 6,617.60 0.22 123.78 6,490.85 6.467.45 1,00364 -2.08 6,153,709.43 463,00444 032 1,003.64 MWD+SC+sag(2) 6,676.18 0.31 136.50 6,549.42 6,526.02 1,003.46 -1.88 6,153,709.25 463,004.64 0.18 1,003.46 MWD+SC+mg(2) 6.744.14 0.37 110.06 6,617.38 6.593.98 1,003.25 -1.55 6,153709.04 463,004.97 0.24 1,003.25 MWD+SC+sag(2) 6,606.15 0.46 99.84 6,679.39 6.655.99 1,003.14 -1.11 6,153,708.93 463,005.40 0.19 1,003.14 MWD+SC+sa9(2) 6,862.69 0.39 12206 6,735.93 6,712.53 1.003.00 -0.73 6,153,708.78 463,005.79 031 1,00300 M'ND+SC+sag(2) 6,926.64 0.20 124.44 6,799.88 6,776.48 1,002.62 -0.45 6,153.708.60 463,006.06 0.30 1,002.82 MWD+SC+sag(2) 6994.98 0.22 13320 6,868.22 6,844.82 1.00267 -0.26 6,153,708.45 463.008.26 0.06 1002.67 M'NO+SC+sag(2) 7,015.97 0.25 120.41 6.889.21 6,865.81 1.002.62 _019 6.153,708,40 463,006.33 0.29 1,002.62 MWD+SC+sag(2) 7.070.00 0.25 120.41 6,943.24 6,919.84 1,002.50 0.02 6.153,708.27 463,006.53 0.00 1,002.50 PROJECTEDto TO Checked By: n..n, .' "'^-" ^'� Approved By: <°om"'�1o.n'o°vCel°�`"""` = Date: 02/22/2016 2/222016 3:42:11PM Page 5 COMPASS 5000.1 Build 58 Caelus Ersergy Alaska CASING 8 CEMENTING REPORT Lease g Well No. Tufimaniq CTdt Date County North Slope Sumugh State Alaska Sup, CASING RECORD -Surface TO 2563.00 Shoe Depth: 25Jan-16 Cs9 WL On Hook: _ Csg Wt. On Slips: _ Fluid Description: Liner hanger Info (Mekelf40del) Liner hanger test pressure: Type Float Collar: Davis Lynn No. Hm to Run: Type of Shoe: Davis Lynn Casing Crew TESCO Liner top Pecker?: _Yes X No 2- Centralver Per Joint on Shoe Track, 1- Centreltrer per Joint from 2477.76' to 2069.62',1 - Centralizer every Centralizer placement third joint kom 194740to 241.80' CEMENTING REPORT Prellush(Spacer) Casing (Or Liner) Detail Type: Setting Depths No. of Jts. Site Wt. Grade THD Make Length Bottom Top Float Shoe 10.75 45.5 L-80 BTC Davis Lynch 2.07 2,551.00 2,548.93 (1-2) Casing 10.75 45.5 L-80 BTC 15.8 Volume (BBLs/sacks): 81.00 2,548.93 2,467.93 Float Collar 10.75 45.5 L-80 BTC Davis Lynch 2.17 2,467.93 2,465.76 (3)Casing 10.75 45.5 L-80 BTC 40.31 2,465.76 2,425.45 Stab -In 10.75 45.5 L-80 BTC Davis Lynch 2.40 2,425.45 2,423.05 (4-51)Casing 10.75 45.5 L-80 BTC 1,939.45 2,423.05 483.60 Pup Joint 10.75 45.5 L-80 BTC Lead Slurry 5.10 483.60 478.50 Tam Port Collar 10.75 45.5 L-80 BTC TAM 174 478.50 476.76 Pup ldnt 10.75 45.5 L-80 BTC Yield(FtNsack): 4.14 47E 76 472.62 (52-52)Casing 10.75 45.5 L-80 BTC 444.62 472.62 28.00 Puploint 10.75 45.5 L-80 BTC Type: 3.25 28.00 24.75 Hanger 10.75 45.5 L-80 BTC _Yes _No Reciprocated? _Yes 1'2 2337 Landing Joint 10.75 45.5 L-80 BTC Estimated TOC: 24.00 23.37 -0.63 Totals 2,551.63 Cs9 WL On Hook: _ Csg Wt. On Slips: _ Fluid Description: Liner hanger Info (Mekelf40del) Liner hanger test pressure: Type Float Collar: Davis Lynn No. Hm to Run: Type of Shoe: Davis Lynn Casing Crew TESCO Liner top Pecker?: _Yes X No 2- Centralver Per Joint on Shoe Track, 1- Centreltrer per Joint from 2477.76' to 2069.62',1 - Centralizer every Centralizer placement third joint kom 194740to 241.80' CEMENTING REPORT Remarks' Prellush(Spacer) Type: Tunas Spacer 111 Density(ppg) 10.5 Vtlume pumped(BBLs) 50 Lead Blurry Type: Permafrost L Yield (Ft3/sack): 4.33 (Surface Yi ed)1415 (Dcvmhole Yield Dantily(ppg) 11.1 Volume(BBI-slsacks): 258.4/335 Mang) Pumping Rats(bpm): 4.2 Tal Slurry Type: Surface Tal Yield(Ft3lsack): 1.15 Density(Ppg) 15.8 Volume (BBLs/sacks): 48.4/280A Mdtg/ Pumping Rate (bp.): 3.0 Post Flush (Spacer) y Type: FreshWater Density(ppg) 8.33 Rate (bpm) 2.8 Vtlume: 20 Z Displacement: Type: Was! Density(ppg) 9.1 Rate(bpm): S.T9 Volume (adua/calculated(: 42.0/ FCP (psi): 740.00 Pump used for disp: Halliburton Plug Bumped? X Yes_No Bump press 1140 Casing Rotated? _Yes X No Reciprocated? _Yes X No %Returns during job 100 Cement realms to surface? X Yes -No SpasareNms? X Yes No Vdto Sud: 50 bbl Spacer/ 228 bbl Cement Cement In Place At: 13:00 Date: 12J251201B Estimated TOC: Surface Method Laski To Determine TOC: Cement returns to surface. PreBush(Spacer) Type: Densily(ppg) Volume pumped (581s) Lead Slurry Type: Yield(Ft3'sacky Density(ppg) Volume(BBLs/aacks): Mdn9/ Pumping Pae(bpm): Tail Blurry as Type: Yield(FtNsack): a Density(ppg) Volume(BBLs/sacks): Mang l Pumping Fare (bpm). is Post Flush (Spacer) Type: Density(p,) Pat. (bpm): Volume: w in Displacement: Type: Density (M) Rate(bpm): Vdum,(acNal I calculated): FCP(,i): Pump used for disp: Rig pumps %ug Bumped] _Yes -Nis Bump press Casing Rotated? _Yes _No Reciprocated? _Yes _Na his Returns during job Cement returns to surface? _Yes No Spacer returns? _Yes No Vol to Surf. Cement In Place At Date: Estimated TOC: Method Used To Determine TOC: Remarks' CT -1 P&A Plug 1 at 7070' Event Average Pressure (psi) Average Density (ppg) Average Rate (bbl/min) Volume (bbl) Pump Spacer Ahead to Fill Lines 188.01 10.56 1.86 4.75 Pressure Test - Maximum Pressure 3783.03 11.07 0.00 0.00 Pump Tuned Spacer - Begin 441.80 10.72 3.33 18.13 Pump Cement - Begin 270.68 13.91 2.16 5.02 Pump Cement - Resume 255.28 14.57 2.24 7.63 Pump Cement - Resume 143.99 15.38 2.69 9.94 Pump Cement - Resume 57.48 15.62 2.59 27.27 Pump Spacer - Begin 57.08 11.51 1.88 1.99 Pump Mud Displacement - Begin 359.30 10.30 4.76 99.88 Average Average Average Volume Event Pressure Density Rate (bbl) (psi) (ppg) (bbl/min) Spacer 362.54 10.75 2.93 24.87 Cement 126.45 15.24 2.52 49.85 CT -1 P&A Plug 2 at 6570' Average Average Average Average Event Pressure Density Rate Volume Rate (psi) (ppg) (bbl/min) (bbl) Pump Tuned Spacer III -Begin 564.27 10.47 4.78 21.74 Pump Cement - Begin 509.93 15.72 4.36 43.50 Pump Spacer Behind - Begin 69.40 10.82 3.28 2.10 Pump Mud Displacement - Begin 228.87 10.00 4.38 102.32 Average Average Average Volume Event Pressure Density Rate (bbl) (psi) (ppg) (bbl/min) Spacer 520.73 10.50 4.65 23.83 Cement 509.93 15.72 4.36 43.50 CT -1 P&A Plug 3 at 6070' Event Average Pressure (psi) Average Density Average Rate bbl min Average Volume bbl Pump Spacer Ahead - Begin 461.05 10.43 3.89 18.61 Pump Cement - Begin 399.75 15.56 3.65 39.25 Pump Spacer Behind - Begin 139.58 10.57 3.69 1.97 Pump Mud Displacement - Begin 286.74 10.40 4.39 82.86 Average Average Average Average Event Pressure Density Rate Volume (psi) (ppg) (bbl/min) (bbl) Spacer 430.29 10.44 3.87 20.58 Cement 399.75 15.56 3.65 39.25 CT -1 P&A Plug 4 at 5570' Average Average Average Volume Event Pressure Density Rate Volume Event Pressure Density Rate Total Spacer 475.21 10.56 3.97 21.34 Total Cement (bbl) 53.68 (psi) (ppg) (bbl/min) Pump Spacer Ahead - Begin 505.78 10.48 4.11 19.80 Pump Cement - Begin 279.13 15.70 2.98 53.68 Pump Spacer Behind - Begin 84.10 11.48 2.22 1.55 Pump Mud Displacement - Begin 390.17 10.81 4.57 74.80 Average Average Average Volume Event Pressure Density Rate (bbl) (psi) (ppg) (bbl/min) Total Spacer 475.21 10.56 3.97 21.34 Total Cement 279.13 15.70 2.98 53.68 CT -1 P&A Plug 5 at 2476' Event Average Pressure (psi) Average Density (ppg) Average Rate (bbl/min) Volume (bbl) Pump Water Ahead - Begin 201.71 8.25 1.01 4.93 Pressure Test - Maximum Pressure 2503.46 8.47 0.00 0.00 Pump Water Spacer - Begin 472.45 8.41 1.92 34.56 Pump Primary Cement - Begin 515.27 15.66 4.20 115.52 Pump Primary Cement - Resume 153.8315.28 1.90 2.46 Pump Water Behind - Begin 71.15 8.67 2.07 2.73 Pump Mud Displacement 143.97 8.82 3.56 25.81 Average Average Average Event Pressure Density Rate Volume (psi) (ppg) (bbl/min) (bbl) Primary Cement 507.73 15.65 4.15 117.98 CT -1 P&A Plug 6 at 538' Event Event Average Pressure (psi) g Average Density (ppg) Average Pump Rate (bbl/min) Volume Rate First Plug (ppg) (bbl/min) Plug 1 Cement 140.16 Pump Water Ahead - Begin 35.10 8.04 1.35 1.91 Pressure Test - Maximum Pressure 2455.09 8.49 0.00 0.00 Primary Cement - Begin 140.16 15.96 2.73 35.35 Pump Water Behind - Begin 32.34 11.25 1.93 3.67 Second Plug Break Circulation 17.57 7.94 1.38 1.47 Pressure Test - Maximum Pressure 2518.82 8.55 0.00 0.00 Primary Cement - Begin 135.34 16.30 2.62 26.61 Pump Water Behind - Begin 18.75 11.60 1.13 0.70 Average g Average Average Volume Pressure (Psi) Density Rate (ppg) (bbl/min) Plug 1 Cement 140.16 15.96 2.73 35.35 Plug 2 Cement 135.34 16.30 2.62 26.61 THE STATE °fALASKA GOVERNOR BILL WALKER Walter Quay Senior Staff Drilling Engineer Caelus Energy Alaska Smith Bay, LLC 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503 Re: Exploration Field, CT -1 Permit to Drill Number: 215-208 Sundry Number: 316-110 Dear Mr. Quay: 2_X10 -Zo g Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Enclosed is the approved application for sundry approval relating to annular disposal of drilling wastes in the above -referenced well. Please note that any disposal into the surface/production casing annulus of a well approved for annular disposal must comply with the requirements and limitations of 20 AAC 25.080. 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 rehearing. A request for rehearing 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. A person may not appeal an AOGCC decision to Superior Court unless rehearing has been requested. Sincerely, Cathy P oer Chair DATED this ��t of February, 2016. RBDMS L �- FEB 1 1 2016 STATE OF ALASKA ALA:,..., OIL AND GAS CONSERVATION COMM, --.TION ANNULAR DISPOSAL APPLICATION 20 AAC 25.080 RECEIVED FEB 0 8 2016 AQQQ8' Po 1. Operator Name: Caelus Energy Alaska Smith Bay, LLC . 3. Permit to Drill No: 215-208 • 4. API Number: 50- 879-20021-00 2. Address: 3700 Centerpoint Drive, Suite 500 5. Well Name: CT -1 Anchorage, AK 99503 6. Field: Exploration , 7. Publicly recorded wells 8. Stratigraphic description: a) Interval exposed to 10-3/4" casing shoe @ 2551 to TOC @ 5000'+/- 000'+!a) a)All wells within one- open annulus: quarter mile: Not Applicable b) Waste receiving Nanushuk Topset from 2570 to 2980' MD zone: b) water wells within Not Applicable one mile: c) Confinement: 10-3/4" casing cemented to surface to TOC 9. Depth to base of 10. Hydrocarbon zones permafrost: Approx. 929' above waste receiving None zone: 11. Previous volume disposed in annulus and date: 12. Estimated slurry density: 13. Maximum anticipated pressure at shoe: NONE 9.5 to10.2 ppg 2049 psi 14. Estimated volume to be disposed with this request: 15. Fluids to be disposed:. < 10,000 bbls Drilling mud/cutttings, cement contaminated drilling fluid, completion fluids, diesel, formation fluids associated with drilling the well, domestic waste water, any added water needed to facilitate pumping of drilling mud or drill cuttings, boiler blowdown fluids, and any other 16. Estimated start date: fluids associated with drilling the well. 10 -Feb -16 17. Attachments: Well Schematic (Include MD and TVD) ❑ Cement Bond Log (if required) ❑ FIT Records w/ LOT Graph Q Surf. Casing Cementing Data 11 Other ❑ 18. 1 hereby certify th t the foregoing is tru and correct to the best of my knowledge. Signature: Title: Senior Staff Drilling Engineer Printed Phone Name: Walter Quay Number: 343-2129 Date: Commission Use Only Conditions of approval: LOT review and hole L P ©T approval: 1-e9-U,/—c Subsequent form Approval / 110-4-2S required: number: Approved APPROVED BY I by: COMMISSIONER THE COMMISSION Date: 2.—��— ORIGINAL Form 10-403AD Rev.6/2004 *I b aNI& Mn Z+a116 z/�zoi6 INSTRUCTIONS ON REVERSE GDw Submit in Duplicate RBDMS Lt— FFB 1 1 2016 CC= C AE LU S Energy Alaska Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 601 West 5`h Ave. Suite 505 Anchorage, Alaska. 99501 RE: Annular Disposal Application for CT -1 PTD# 215-208 API# 50-879-20021-00 Dear: Ms. Foerster, RECEIVED FEB 0 8 2016 AOGCC Caelus Energy Alaska Smith Bay, LLC 3700 Centerpoint Drive, Anchorage, AK 99503 Tel: (907) 277-2700 Fax: (907) 343-2190 02/08/2016 Caelus Energy Alaska Smith Bay, LLC submits for AOGCC review, a 10-403AD Sundry Approval form to support the fluids disposal effort at CT -1 before completing the P&A. Pertinent information attached to this application includes the following documentation: • 10-403AD Sundry • Well schematic • Annular Disposal procedures • Miscellaneous information to support this request The following are Caelus Energy Alaska Smith Bay, LLC designated contacts for reporting responsibilities to the Commission: 1) Completion Report Walter Quay (20 AAC 25.070) (907) 343-2129 2) Geologic Data and Logs Paul Daggett (20 AAC 25.071) (907) 343-2134 If you have any questions or require additional information, please contact Walter Quay at (907) 343-2129 (Ofc), (907) 230-3961 (Mob), or Vern Johnson at (907) 343-2111 (Ofc), (907) 575- 9430 (Mob) e-mail: vern.johnsonna caelusenergy.com Sincerely, Walter Quay- Senior Staff D ing Engineer cc: Michael Hopkinson, Vern Johnson, Mike Cook, Tom Brassfield CT -1 :Well File Ck2'C,A,7Ej_U Energy Alaska Prospect Name Tulimaniq Principal Engineer: Walter Quay Well Type Explaration�� Well Classification Producer � DHllinaCntractar/Rig: Doyon Drilling/Arctic Fox Ice cad thickness (R.): 8.0 R. Zone of Interval: /Primary Torok an eled. (reference : M: 23A R. Zone of Interest/Secondary Ellesmedan Annular Dkpoml ME DRILL, EVAL S TES167 DAYS Door-pial Smith Bay °..'a r^^TM° .M.D. mxs FPRM,,,PN F eapospox ImP North Slope, Alaska PxoM MD Wo Min. a4RVRX36 EM cordumor to be angered WaIINad fMCGRn.V 11" NONE NONE Pennuent 0 0X. 24" capm(a9): 110 R. 1080 R. BNOw ke WO SZ ekv MUEbpginp: 100 100 Some Mud: Start p300RND/MD REF 499/1sJymn MN: 9.5 germ Top Gas Hydrate TMS Parted Cipher GesFeR-mass spar Stability Zone $28 628 9500 R. and/trd Base Permafrost 929 929 Bae GUNydrate 1692 1638 Stability Zone Lead Cement Parran st Ham Pra eetban OW/GR/Ru TOC: O NB]C: 20%R Annuli 7 5/8'x103/P(Dleul) i&LT/%GL SurfacerWkm: Crri 10.7M, Z551'WD/2510'MO Exa55: 250%/40%. 143/4' 45.501bVft L00 BTC immnlrea: tiro au Tail Cement cwm.xla Pv TOO 2066f all .,n...r.aaaa Pn 13Da�n: 15'am Eaeo 40% 10.314- Caguas 2551 2510 13-1/2" Mudlagging NMmadlaM Mud: LmkgrTal(IaT): Mudlaooino: Nanushuk Topset U61 Mil 3% (Or 499/%IPA 1400 Ppg equiv. Ma111d) PYtbm Esprei MW: 9.6-10.2 Pry GasFact-mazzsper (Qmdgensy)/CMR Potertal suMRute: R6mmer ke AR Open Mole OPto 3000'+/ B atlE orientation some mimulan Interval Toms SE 4915 42N Tap Wog A495o0' 98p°a FMI/O51 Tarek 5113 SaMn<r-MDT I. Tulmem Fan 5180 5041 TWmenlq Fen Farman-Evaluation TEP Central 5313 SMED....enav: Pam"W)acNve MSR-a-XLAccic Tap Labe3 5360 5628 TOP as. a 0 Care AM Tarok/Tulimaniq BaeTukmaltiq FFn 5950 5810 ROPE: Tarek/TuNmanio Fan VSP Tap MRZ I P MWD/LM: 5-0/r Triple Gmb. 87.04 MA. Lay DO/GR/Ra/PWD/Dan CCUMOUL Neutron-Pamoty inevent&well test Top LEU 6840? 62D3+/- 4314n BUT XwnYt? ? 2 5.3/4"XGL S-3/4"MRS. WeRTOploadau Open Nath 6-3/4-GmEmp IDS I 7000+1 1 any &12"BY"NOO Mudloppbg PYMam Espace/DSI GasFact -mass spec Ellesanerian Section - Not Drilled 4 anD wllpn lnntreal U.Sw River 7471 7331 PWDN Oder Top Shubkk 7623 7983 Done sank MWD/LWD: MSLT-ar-30L-Rock 4-3/4' Triple Combe Top lvishak 8161 W21 Rr/GR/Rm,/PWO/Dan Neutron-Porosity Ton L3zbum 8363 8222 4-3/4'XMT VSP 4-3/4"%GL Ta XeYWtrit 8521 8381 4-3/4" Geudp Smmmt 8681 M41 TD 8761 0641 6-3/4" Max. WWIWM Din latum Daectlonal b Profile Well Total Depth (M) 8181 R. and/8641 R. LM SurfaCe Location(NAD 271 MM ZONE 5-meters) X:452075 Y:7656579 ecaoaeaa sou u. Surface Location (Govt Sect. Line) 2149 FNL.1724 FAIL T17N R09W Sect. 17 lacrarne SHL (MAD 27 ETM ZONE 5-meters) X:452082 Y: 7858884 BHL (Govt. Sect. Line) 4132 FSL, 3552 FEL T17N R09W Seat, 12 Projection Method NAD27/Z0NE S/UTM - meters Rov.t Annulus Disposal Transmittal Form - CT -1 AOGCC Regulations, 20 AAC 25.080 (b) 1 Designation of the well or wells to receive drilling wastes: CT -1 2 The depth to the base of freshwater aquifers and permafrost, if No Aquifers / Base Permafrost = +/- 929'MD/TVD resent. 3 A stratigraphic description of the interval exposed to the open From the 10-3/4" shoe to the proposed P&A cement top at annulus and other information sufficient to support a 5000'+1- is interbedded claystones and some siltstones. commission finding that the waste will be confined and will not come to the surface or contaminate freshwater. 4 A list of all publicly recorded wells within one-quarter mile There are no other wells or water wells within 1 mile. and all publicly recorded water wells within one mile of the well to receive drilling waste. 5 Identify the types and maximum volume of waste to be Types of waste may be drilling mud, drilling cuttings, reserve disposed of and the estimated density of the waste slurry. pit fluids, cement -contaminated drilling mud, completion fluids, diesel, formation fluids associated with the act of drilling a well, drill rig wash fluids, domestic waste water, any added water needed to facilitate pumping of drilling mud or drilling cuttings, and any other fluids associated with drilling a well. Boiler blowdown fluids. Densities range from diesel to 12#/gal. Maximum volume to be pumped is 35,000 bbls- 6 A description of any waste sought to be determined as drilling Cement rinsate waste under (h)(3) of this section. 7 An estimate of maximum anticipated pressure at the outer Maximum anticipated pressure at the outer casing shoe during casing shoe during annular disposal operations and disposal operations is 2,049 psi. See attached calculation calculations showing how this value was determined. page. 8 Details that show the shoe of the outer casing is set below the See attached: cementing report. base of any freshwater aquifer and permafrost, if present, and cemented with sufficient cement to provide zone isolation: 9 Details that show the inner and outer casing strings have See attached casing summary sheet and calculation pages. sufficient strength in collapse and burst to withstand anticipated oressure of disposal operations: 10 The downhole pressure obtained during a formation integrity LOT/FIT report and casing test report submitted earlier. test conducted below the outer casing shoe. 11 Identification of the hydrocarbon zones, if any above the N/A depth to which the inner casing is cemented. 12 The duration of the disposal operation, not to exceed 90 days. N/A 13 Whether drilling waste has previously been disposed of in the N/A annular space of the well and, if so, a summary of the dates of the disposal operations, the volumes of waste disposed of, and the wells where the drilling waste was generated. 14 The well(s) where the drilling waste to be disposed of was or CT -1 will be generated. 15 If the operator proposes not to comply with a limitation N/A established in (d) of this section, an explanation of why com Bance would be imprudent. 16 Any additional data required by the commission to confirm N/A containment of drilling waste. Well CT -1 Date F 2/15/2016 CASING/TUBING DESCRIPTION ENTER VALUES in the YELLOW CELLS Version Lo-JM'05 Collapse Bursting Size Wt. Grade PSI PSI Surf. 10.750 1 45.500 L 80 2470.00 5210.00 Next Stringl 7.625 29.700 L 80 4790.00 6890.00 Tubingl 3.500 Fluid in Tubing/Casing Annulus Gas Surface Casin TVD 2510 ft Drilled Mud Weight 9.8 ppg Pore Pressure @ Shoe 0.447 psi/ft (suggest fresh water gradient) Shoe FIT/LOT 15.7 ppg Annuluar FIT/LOT 15.3 ppg Pburst @ 85% 4,429 Max Injected MW 12 ppg Max Surface Pressure 1,500 psi Distance from Pump to Well 350 It Diameter of Pump Line 1.75 inches Estimated TOC 4,680 MD ft Estimated TOC 4,546 TVD ft Gas/Fluid Gradient in tubing/casing annulus 0.1 psi/ft Header Pressure (for wells on gas lift) 0 psi Pcollapse @ 85% 4,072 (suggest 0.06 - 0.07 psi/ft) Well CT Date 2/15/2016 -1 PPg Pressure Calculations for Annular Disposal (for submital with Annular Disposal Application) Assumptions Maximum injection pressure of 1,500 Maximum density of the injection fluid is 12.0 Pore pressure at the 9 5/8" casing shoe is 0.447 psi ppg psi/ft varsim r0-ta"v5 2nd Casing String Gas/Fluid Gradient in cubing/casing annulus 0.1 psi/ft 7.625 in 6,650 TVD Weight 29.7 Header Pressure (for wells on gas lift) 0 psi Grade L 80 .R Maximum Fluid Density to avoid Burst of Surface Casing Maximum psi Pcollapse85% V — PHydrostatic + PApplied - PFormalion f4 f4 Top of Cement 4,546 ft Gas Gradient ,429 =( 2,510 * 0.052 * MWmax )+ 1500 - ( 0.4472 * 2,510 ) Max Surf. Pressure 1,500 psi L-2,510 MWmax = 31 PPg 0 psi TVD Surface Casing String Size 10.75 in Weight 45.5 ppf y V y Grade L 80 on rbunal00% 5,210 psi c '� Pburst85% 4,429 psi U Depth of Shoe 2,510 ft FIT/LOT @ Shoe 15.7 ppg or 2,049 psi n - FIT/LOT for Annulus 15.3 ppg a* not ve- f LPOI Max Surf. Pressure 1,500 psi TOC Est. @ 4,680' MD 4,546' TVD Maximum Fluid Density avoid Collapse of 2nd Casing String Pcollapse85% — PHydmstatk + PApplied - PGasGmdient - PHeader 4,072 =( 4,546 * 0.052 * MWmax )+ ##### - ( 0.1000 * 4,546 ) - 0 Maximum Anticipated Pressure at Surface Casing Shoe Pmax allowable = Shoe TVD Depth *.052 * Shoe FIT/LOT Pmax allowable = ( 2,510 * .052 * 15.7 ) Pmax allowable — 2,049 psi This is the value for the Injection Permit "Maximum Anticipated Pressure at Shoe". MWmax = 12.8 PPg 3.5 "Tubing 2nd Casing String Size 7.625 in 6,650 TVD Weight 29.7 ppf Grade L 80 rcollapse100% 4,790 psi Pcollapse85% 4,072 psi Top of Cement 4,546 ft Gas Gradient 0.1 psi/ft Max Surf. Pressure 1,500 psi Header Press 0 psi Maximum Anticipated Pressure at Surface Casing Shoe Pmax allowable = Shoe TVD Depth *.052 * Shoe FIT/LOT Pmax allowable = ( 2,510 * .052 * 15.7 ) Pmax allowable — 2,049 psi This is the value for the Injection Permit "Maximum Anticipated Pressure at Shoe". CT -1 Surface Injection Pressures with gauge at disposal wellhead and using annulus friction of 50 MW ( )(psi) Injection Pressure MW ( ) Injection Pressure (psi) MW ( ) Injection Pressure (psi) 6.8 1,212 8.8 951 10.8 690 6.9 1,199 8.9 938 10.9 676 7.0 15186 9.0 924 11.0 663 7.1 15172 9.1 911 11.1 650 7.2 1,159 9.2 898 11.2 637 7.3 13146 9.3 885 11.3 624 7.4 15133 9.4 872 11.4 611 7.5 1,120 9.5 859 11.5 598 7.6 15107 9.6 846 11.6 585 7.7 15094 9.7 833 11.7 572 7.8 15081 9.8 820 11.8 559 7.9 108 9.9 807 11.9 546 8.0 1,055 10.0 794 12.0 533 8.1 15042 10.1 781 12.1 520 8.2 1,029 10.2 768 12.2 507 8.3 1,016 10.3 755 12.3 494 8.4 11003 10.4 742 12.4 481 8.5 990 10.5 729 12.5 468 8.6 977 10.6 716 12.6 455 8.7 964 10.7 703 12.7 442 Enter Holding Enter Holding Time Here Pressure Here > CASING AND LEAK -OFF FRACTURE TESTS Well Name: CT1 Date: 1/28/2016 Csg Size/Wt/Grade: 10.75 L80 45.5 Supervisor: Keener/Ross Csg Setting Depth: 2548 TMD 2641 TVD Mud Weight: 9.5 ppg Leakoff pressure = 820 psi LOT= 15.71 ppg Hole Depth = 2585 and Fluid Pumped= 1.3 Bbls Volume Back = 1.0 bbls 3050 Estimated Pump Output: 0.100 Barrels/Stroke LEAK -OFF DATA > CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here Enter Holding Enter Holding Time Here Pressure Here > 0 0 > 0.5 400 -> - 1 — — — 1040 > 1.5 2111 > 2 2654 > 2.5 3000 > 3 3050 > -- > Enter Holding Enter Holding Time Here Pressure Here t LEAK -OFF DATA - CASING TEST DATA 4000 3900 3800 3700-- 3600 3500 3400 3300 3200 3100 --- -- � -- - - - 3000 2900- 2800 2700 2600 2500 2400 2300 - 2200 -� .ea.. 2100 — -- 2000 — 1900 a 1800 1700 1600 1500 1400 1300 1200 1100 1000 900 - 800 700 600 S00 400 300 200 - — 100 0 0 10 2i Strokes (# of) 4000 3900 3800 3700 3600 3500 3400 3300 3200 3100 3000 2900 2800 2700 2600 2500 2400 2300 2200 %n 2100 2000 m d 1900 a 1800 1700 1600 1500 1400 1300 1200 1100 1000 900 800 700 600 500 400 300 200 100 0 BLEAK-OFFDATA CASING TESTDATA 0 5 10 15 20 Time (Minutes) 25 30 CE CAELU S Eneral, Alaska CT -1 DRAFT Annular Disposal Procedures Caelus Energy Alaska, Smith Bay LLC Exploration Test Well Smith Bay, North Slope, Alaska Modified by TJB 02/08/2016 N A SL/n&t-Ls 316- 10� 40o1or" Sun J 1 CE CAELU S Energy Alaska Well Name: CT -1 Drill & Evaluate Summary TVDe of Well: I Exploration Test Well / North Slope Surface Location: 2149' FNL. 1724' FWL. Section 17 T17N R09W UM Target Formation: 4132' FSL. 3552' FEL. Section 17 T17N R09W UM Total Depth 4132' FSL. 3552' FEL. Section 17 T17N R09W UM AFE Number: 1150036 Spud Date: Jan. 19 , 2016 Rig: Doyon Drilling : Arctic Fox Total Operating days to Drill 67 & Evaluate: MD: 667KBft TVD: Funnel Vis PV Max Inc: 17. KOP: 1000 _Rensity 9.5-9.8 1 125-70 1 10-30 1 30-35 9.0-10 BKBft <13% Intermediate Hole Section : 8-1/2" Hole Section Opening : 9-718" 3% KCL/BDF 499/EZ MUD DP PHPA Density (ppg) PVYP PAD -AMS 4.9 ft. Cl-(mg/1) API Filtrate Well Design conventional, slimhole, etc.: I Directional "S" Profile Objective: Primary : Drill & Evaluate Torok/Tulimaniq Fan (8-1/2" intermediate hole sect.) Secondary : Evaluate Ellesmerian Formations (6-3/4" production hole sect. Drillina Fluid Program: Surface Hole Section : 13-1/2" Polymer/BDF 499 (ppg) Funnel Vis PV YP pH API Filtrate LG Solids _Rensity 9.5-9.8 1 125-70 1 10-30 1 30-35 9.0-10 <9 <13% Intermediate Hole Section : 8-1/2" Hole Section Opening : 9-718" 3% KCL/BDF 499/EZ MUD DP PHPA Density (ppg) PVYP HTHP Cl-(mg/1) API Filtrate LG Solids 9.6 — 10.2 8-20 15-25 NA <15K <6 <6% SVf' .r� 316 -/0 7 CE CAELU S Ene;oy Alaska Pnrmnfinn Markarc' CT- 1 Formation Est. Formation Tops TVDss) Actual MD/TVD (Feet) Prospective Hydrocarbon Bearing Top Gas Hydrate Stability 805' Casing Test Pressure 10-3/4" 45.5# L80 BTC 3000 psi Base of Permafrost 906' Planned BOP Test Pressure Rams test to 250 psi/5,000 psi. BGHS (Base Gas Hydrate Stability) 1615' Casing Test Pressure 3500 psi Nanushuk Topset 2788' Torok SB 3 4756' Top Tulimaniq Fan 5018' Top Central Channel 5150' Top Lobe 3 5605' Base Tulimaniq Fan 5787' Top HRZ 6560' LCU/Kingak 6677' ? Top Sag River 7308' NA Top Shublik 7460' NA Top Ivishak 7998' NA Top Lisburne 8199' NA Top Kekiktuk 8358' NA Top Basement 8518' NA TD 8618' NA Well Control - BOPE 541,odr-� 31�-)09 Surface Interval : 13-112" 21 '/4" x 2M Hydril MSP Annular Preventer Maximum Anticipated BHP 1263 psi (9.6 Ib/gal @ 2530 -ft TVD) Maximum Surface Pressure 985 psi (0.11 psi/ft gas gradient to surface) Casing Test Pressure 10-3/4" 45.5# L80 BTC 3000 psi Planned Drilling Fluid Polymer/BDF 499 Intermediate Interval: 11" x 5K Annular BOP. 11" x 5K Double Ram BOP 11" x ➢ Initial Wellbore: 8-1/2' Single Ram BOP w/ 2-7/8" x 5" VBR's ➢ Hole Opening :9-7/8" Maximum Anticipated BHP 3458 -psi (10.0 Ib/gal @ 6650 -ft TVD) Maximum Surface Pressure 2726 psi (0.11 psi/ft gas gradient to surface) Planned BOP Test Pressure Rams test to 250 psi/5,000 psi. Annular test to 250 psi/2,500 psi Casing Test Pressure 3500 psi 7-5/8" 29.7# L80 BTC CE CAELU S Erie, 2v Alaska Planned Drilling FI 'd 3% KCL/BDF 499/EZ MUD DP PHPA Production Interval: 6-31 '° 11" x 5K Annular BOP 11" x 5K Double Ram BOP 11" x 5K Single Ram BOP w/ 2-7/8" x 5" VBR's Maximum Anticipated BHP 4583 -psi (10.2 Ib/gal @ 8641 ft TVD) Maximum Surface Pressure 3633 psi (0.11 psi/ft gas gradient to surface) Planned BOP Test Pressure to 250 psi/5,000 psi. st to 250 psi/2,500 psi %KDF Planned Drilling Fluid 499/EZ MUD DP PHPA Kick Tolerance/Integrity Testing Kick Tolerance / Integrity Testing ummary Table Casing set/ Interval Maximum InfluxExp Mud We ht Pore Min LOT / FIT Volume (bbls) Press Surface : 10-3/4"1263 Diverter 9.5 — 9.8 ppg 12.0 ppg (LOT) 2566/2530 ft. and/tvd Intermediate: 7-5/8" 44 9.6 — 10.2 ppg 3 58 12.5 ppg (FIT) 6790/6650 ft. and/tvd Open Hole : 6-3/4" 64 10.0 — 10.2 ppg 4583 8781/8641 ft. and/tvd Lnew NOTE: All LOT / FIT will be taken with a minimum of 20 -ft and a maximum of 5 hole drilled outside of the previous casing string 5voddj 3I�-10� CI CE CAELU S Fneroy Alaska CT- #1 – Plug & Abandonment Conductor (16") x Surface Casing (10-314") Cut & Retrieve Pre Job Planning Check all Safety procedu s of Doyon Arctic Fox rig operations. Upon arriving on the Rig Si ,Check with the Drilling Foreman or Company Representative to verify Plug & Abandonment a d casing cut & pul work scope objectives. Verify adequate HES cementin P&A blends (sxs) and mix water (bbls) at the appropriate temperature is staged at the CT 1 ell site. Confirm the collection, handling an disposal of cement rinsate and wash-up fluids for each P&A plug. Check all tools sent in baskets to insure I tools arrived at the CT -1 location. Measure lengths, OD's and ID's of all P&A nd Baker Hughes casing cut & pull equipment Verify Drill Collars, Heavy Weight Drill Pipe, " drill pipe and Weatherford - NOV Grand Prideco 2-7/8",10.4#, HT 2-7/8" PAC work strin connections to insure all X -over subs are on location. WPathPrfnrri , 2-71R" Drill Pine Package Quanflyt—I Description 30 2-7/8" 10.4# S-135 D/P 2-7/8" HT PAC pprox.: 930 ft. 10 2-7/8 HT PAC D/P LIFT NUBBINS 1 YT ELEVATOR DRESSED 2-7/8" 1 2-7/8" D/P SLIPS 1 XO, NC50 X2-7/8 HT PAC BXP 1 2-7/8" HT PAC MULE SHOE Ensure that the CT -1 Cellar box annuli/outer shell is being heate with blower air to assist with retrieval. The AOGCC requires a 48 hour advance notice prior to the comm ting of well plugging operations. Plug and Abandonment Procedure 1. Pick up and stand back 30 jts of Weathearford 2-7/8" 10.4# S-135 D/P 2-7/8" HT PAs (approx.: 930 ft.) , 5" 19.5# S-135 NC -50 drill pipe to reach TD. \ 2. Ensure the Shaffer 11"X5M BOPE is configured with VBR/pipe rams to seal against belovit rotary tubular sizes: 5" HWDP/DP, 2-7/8" DP. 3A r3 3 to 9 CE CAELU S Energy Alaska 3. Plan is to pump 4-500' balanced cement plugs from TD back to 5000' +/- MD. Annular fluid disposal will be into open hole from the 10-3/4" shoe to 5000'. The targeted zones are at 2570', 2650', 2960' 2960' MD. MU BHA # PA100: RIH to Plug #1 bottom setting depth at TD or approxim ely 7000 ft +/- md. Displace balanced cement plug 49 bbls from 7000 ft. and to 6500 ft. md. POOH 6500 ft. and or TOC. Halliburton may want to pump a 18.5 +/- bbl spacer in front with 1.5 bbl sp cer behind. Circulate bottoms -up and prepare to set plug #2. 4. Repeat plug placent for plugs #2, #3, and #4. 5. Wait on cement (WO at 3000' +/- ft. and as directed by Halliburton cementing field supervisor until Plug #4 has develo d sufficient compressive strength to allow for a confirmation "tag' of 5- 15 kips. RIH and tag top o lug#4 at 5000' +/- MD. Note top of cement for Plug #4 on HES Job log. Plugs #1, #2, #3, and #4: TD to appr4.. 5000' MD Intermediate Open HoleTA Plug Intermediate CasingN Set Well Input Data Hole Size in 8.5 Bottom of Plug ft 7000,6500, 00,5500 PTA Plug Length ft 500/ lu Top of Plug ft 6500,6000,5500, 000 Excess40% Capacity Output Data Open Hole Capacity Data bbls/If 0.0702 Open Hole Capacity Data w/ Excess bbls/If 0.0983 Spacer & Cement Slurry Input Data Spacer Spacer Type Tuned III Spacer Density 10.5 Mix Water al/bbl 37.56 Spacer Volume bbls 20 Bottom of Spacer ft 6500 Top of Spacer ft 6296 Plug Slurry Cement Slurry Type PTA & Int Blend Downhole Slurry Density 15.80 Downhole slurry Yield cuft/sk 1.15 Mix Water al/sk 4.96 Volume Output Requirements 9 R CE CAELU S Enerev Alaska Spacer Volume Required bbls 20.0 Total Plug Cement Volume bbls 49.1 Total Plug Cement Volume Required sacks 240.00 Cement Mix Water Volume Required bbls 28.3 Spacer Mix Water Requirement bbls 17.9 Wash -Up Volume bbls 50 Total Water Volume per Job bbls 97.0 NOTE: Final P&A procedures need to be approved by the AOGCC as well as the Sundry for fluids disposal into the Nanushuk interval from 2650' to 2980' MD. Once TOC has been confirmed at 5000' +/- pull BHA # PA100 to 3000' +/- or across the bottom injection zone, close the annular or pipe rams and prepare to pump down the pbackside i.e. "annular disposal". A �� apPlO�Ja� S✓nGIrj Guidelines for disposal are: SdnC,t, 3 16— h 0 i IrIAALX- V11?OsOJ • Perform an open hole LOT procedure similar to the surface casing shoe LOT procedure. See attachment. Atteffipt Keep surface pressure plus fluid density below the 15.7 ppg EMW (LOT) at the surface casing shoe. Calculated maximum anticipated pressure at shoe is 2049 psis C -b" 2/g1Zvl b • Notify Anchorage of the results before starting fluids disposal. • Once a rate is established flush the backside with 200 bbls +/- water and begin annular disposal of fluids. o Surface pressure plus the hydrostatic weight of the disposal fluid should not exceed the 2049 psi. o Monitor density of the fluids being pumped downhole. Adjust rates and pressures accordingly. o Keep record of volumes, fluid densities, and surface pump pressures for AOGCC reporting.p a 7i% -1 q V AS { p� aPl J s✓n� .S0/ POOH hole with BHA # PA100. Stand back 30 jts of Weathearford 2-7/8" 10.4# S-135 D/P 2-7/8" HT PAC (approx.: 930 ft.). rA CE CAELU S Energy Alaska Prepare to PU 10-3/4" EZSV and continue the CT -1 P&A. See P&A procedures. 0 Casing Shoe Leak Off Test Procedure: 3. 4. 5. After testing BOPS, pick up the drilling assembly and RIH to the float collar. Circulate to consistent mud weight and rheology. Shut in with the pipe rams and test the casing to the required test pressure. Record the volume of mud required and the corresponding pressures in '/< bbl increments. When the design pressure is reached shut in the well and record the shut in pressure for 30 minutes. Bleed off pressure while taking returns to a calibrated tank and record volume recovered. Drill out the shoe track. Drill 20 ft of new hole and circulate the hole clean with consistent mud weight in/out. Pull up into the casing shoe. Perform a Leak Off Test (or Formation Integrity Test): • Calculate the required test pressure to reach leak off (or formation integrity test limit) with the actual mud weight and the estimated fracture EMW. • Plot the casing test data and the calculated leak off. As a guide, use the data from the casing test to determine the approximate volume of mud required to reach the calculated LOT/FIT. • Shut the well in. R/U the test pump. • Bring the pump on line at 0.25 — 0.50 bpm. Maintain a constant rate. • Record the pressure for every Y< of a bbl pumped. • Continue pumping until the pressure vs. volume curve breaks over indicating leak off. Note: For FIT, do not take to leak off • Discontinue pumping and shut in the well. Record the shut in pressure in 1 minute increments for 10 minutes or until pressure shows stabilization. • Bleed off the pressure and record the volume of mud recovered. • Plot the data to determine the LOT/FIT pressure at the shoe as EMW. • Submit the test results to the Caelus Energy LLC drilling engineer for distribution as required. iCem Service CAELUS ENERGY ALASKA SMITH BAY LLC For: Walter Quay Date'. Monday, January 25, 2016 CT1 10.75" Surface Casing Cement Job Job Date: Monday, January 25, 2016 Sincerely, Jared Miller Notice Warning Disclaimer Although the information contained in this report is based on sound engineering practices, the copyright owner(s) does (do) not accept any responsibility whatsoever, in negligence or otherwise, for any loss or damage arising from the possession or use of the report whether in terms of correctness or otherwise. The application, therefore, by the user of this report or any part thereof, is solely at the user's own risk. Limitations of Liability Except as expressly set forth herein, there are no representations or warranties by Halliburton, express or implied, including implied warranties of merchantability and/or fitness for a particular purpose. In no event will Halliburton or its suppliers be liable for consequential, incidental, special, punitive or exemplary damages (including, without limitation, loss of data, profits, use of hardware, or software). Customer accepts full responsibility for any investment made based on results from the Software. Any interpretations, analyses or modeling of any data, including, but not limited to Customer data, and any recommendation or decisions based upon such interpretations, analyses or modeling are opinions based upon inferences from measurements and empirical relationships and assumptions, which inferences and assumptions are not infallible, and with respect to which professional may differ. Accordingly, Halliburton cannot and does not warrant the accuracy, correctness or completeness of any such interpretation, recommendation, modeling or other products of the Software Product. As such, any interpretation, recommendation or modeling resulting from the Software for the purpose of any drilling, well treatment, production or financial decision will be at the sole risk of Customer. Under no circumstances will Halliburton or its suppliers be liable for any damages. [(.,,i.. ir 1 411, t� I HALLIBUATON Table of Contents 1.0 Real -Time Job Summary ...... 1.1 Job Event Log ............................................. LD Attachments_ ..................... 2.1 Job Graph ................................................... 2.2 Water Ahead .............................................. 2.3 Pressure Test ............................................. 2.4 Tuned Spacer III ......................................... 2.5 Lead Cement .............................................. 2.6 Tail Cement -1 ........................................... 2.7 Tail Cement -2 ........................................... 2.8 Tail Cement -3 ........................................... 2.9 Displacement ............................................. Page 3 I Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job: C #110.75" Surface Casing Cement Job SD:903063962 ........................................... 4 ................................................................. 4 iCern Service (v. 4.2.393) Created: Monday, January 25, 2016 17 HALLIBURTON Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job: aill 10,75- Sur ace Casing Cement lab SQ: 903063962 1.1 Job Event Log Type Sep. Activity Graph Label Data Time Source Onv Ssde Density Combined Combined Comments No. Pump Pump Pump Total Pressure Race faw) (Pro) (bb L/min) (w) RIGGING UP CEMENT AND Event Rig -up Lines Pig -up Lines 1/24/2016 15:00:00 USER BULK LINES. SPOTTING IN STIGERS WITH HERC SKIDS CALLED OUT THE LOCATION TO GO OVER RIG UP AND CEMENTIOB WITHTHE NIGHT CO MAN. IT WAS Event Call Out Call Out 1/24/2016 20:30:00 USER DECIDED THAT THE CEMENT CREW WOULD BE ON LOCATION AT 2 AM FOR THESURFACEJOB ARRIVED AT RIG AT 2 AM Event Ame, at Rig Arrive at Rig 1/25/2016 02:08:88 USER FOR SURFACE CEMENT JOB RIG LANDED CASING AROUND 7 PM 1015" CASINGWASLANDEDAT 2551' RIG C RCUTATED ON THE CASING, THEN LINED Event Casing on Bottom Casing an Bottom 1/25/2016 0430M USER UP THE START RUNNING INTO THE CASED HOLE WITH S" DRILL PIPE. THE DRILL PIPE WAS RUN TO 2476.78' WHERE IT STUNG INTO THE FLOAT COLLAR. RIG LANDED DRILL PIPE INTO FLOAT COLLAR RIG Event Circulate Well Circulate Well 1/25/2016 06:8000 USER BEGAN CIRCULATING WELL, RIG CIRCULATED FROM 6AM TO B:55AM Event Prime Pumps Prime Pumps 1/25/2816 08:30:00 USER -72.89 -0.02 0.00 4.6 iCem Service V. 4.3 393) Page 4 Created'. Monday, January 25, 2016 HA LLI B U R TON Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job : CTk110,75' Surface Casing Cement lob 50:903063962 STAT CEMENT Event 1 Startlob Start lab 1/25/2016 08:36 36 COMB -0 -0485-0A1 000 4B JOBONURFACE CTI Event 2 Pump Water Pump Water Ahead- 1/25/2016 09:04:18 USER -22.89 0.02 1.16 0.8 0egin CEMENT UNIT BROKE CIRCULATION WITH 10 BBL FRESH WATER 130 PSI 2.5 Event 3 Pump Water Pump Warer Ahead -End 1/25/2016 09:09:22 USER 12.00 8.26 a.11 9.6 RPM, AFTER IOBBL WATER AHEAD WAS PU MPED CEMENT UNIT LINED UP TO PRESSURE TEST 15021 RON CEMENTVNITPRESSURED TESTED T01000 PSI THEN WALKE MHE PRESSURE UP T03800 PSI PRESSURE TEST FAILED DUE TO LEAK ON RIG UNIT Event 4 Pressure Test Pressure Test - Begin 1/25/2016 09:12:21 USER 28.34 0.24 1.06 0.0 BLED OOR.CEMEMED BLEDOFFEN RIG FIXED LEAK, CEMENT UNIT PRESSUTHEIN TE 3200 HELD FOR 5 MIN 3700H LD FOR5 MIN TESTED PASSED PSI BLED BACK TO CEMENT UNIT Event 5 Pressure Test PPressureressure Test - Maximum 1/25/2016 09:14:00 USER 4065.75 8.28 0.16 0.1 Event 6 Pressure Test Pressure Test- Bump 1/25/2016 09:1621 USER 3622.95 8.33 0.05 0.1 Pressure Event 7 Pressure Test Pressure Test - End 1/25/2016 09:17:30 USER 311893 8.37 0.00 0.1 Event 8 Pressure Test Pressure Test - Begin 1/25/2016 09:19:15 USER 84.03 8.32 1.11 02 Event 9 PressureTest Presre suTest- Maximum 1/25/2016 09:19:35 USER 3730.60 8A9 0.05 0.3 Pressure Event 10 PressureTest Pressure Test - End 1/25/2016 09:21:26 USER 3516,62 SAS 0.00 0.3 CEMENT UNIT BATCHED UP Event 11 Pump Spacer Pump Spacer - Begin 1/25/2016 09:34:0 USER 243.30 10.13 374 0.7 AND PUMPED 50 BBL 10.5 SPACER, 300 PSI 4.5 BPM, Page 5 iCem' Service I, 4.2.3931 Created: Monday, lanuary 25, 2016 HALLIBURTON Page 6 Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job : CTK110 75- Surface Casing Cement lob SO: 903063962 WE HAD DELIVERY ISSUSE WITH THE SPACER DUE TO THE DISTANCEWE HAD TO SHIP FROM. THIS MADE IT DIFFICULT TO KEEP THE SPACER LINED OUT DUE TO THE PRODUCT COMING IN VARIATIONS. WE HAD TO ADJUST PUMPING RATES TO DEAL WITH THE SPACER. AFTER SPACER WAS PUMPED CEMENT UNIT SHUT DOWN AND LINED UP TO START MIXING LEAD CEMENT Event 12 Pump Spacer Pump Spacer - End 1/25/2016 09:5190 USER 4202. 10.33 069 51.0 CEMENT UNIT BATCHED UP AN D PUMPED A TOTAL OF 258A BBL 10.7 PPG 335 SACKS 4.33 YIELD, 21.41 G/5K,U AD CEMENT,284 PSI. WE STARTED SEEING CEMENT BACK TO SURFACE 234 BBL AWAY THE MUD MAN CAUGHT SAMPLE AND WEIGHED IT UP AT Pump Lead Cement- 10.8 HEAVY. WE THEN SHUT Event 13 Pump Lead Cement Begin 1/25/2016 10:04:28 USER 27.36 10.54 0.84 0.0 IN THE CEMENT SILO AND FINISHED PUMPING OFF THE LEAD CEMENT IN THE STEADY FLOW. SHUT DOWN CLEANED HEAD AND LINE UP THE MIK TAIL CEMENT. AFTER ALL THE CEMENT AND DISPLACEMENT WAS PUMPED WE HAD 100M RETURNS, WE RECEIVED 115 BBL LEAD CEMENT BACKTOSURFACE. Event 14 Pump Lead Cement Pump Lead Cement - End 1/25/2016 11:2843 USER 95.16 10.03 0.21 354.0 iCem` Service (,4Z393) Created: Monday, January 25, 2016 HALLIBURTON Event 15 Pump Tail Cement Pump Tail Cement -Begin 1/25/2016 11:44:56 USER Event 16 Other Combined Pump Total an 3/25/2016 11:53:46 USER Tail Cement Resets Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job: CTM310,75" Surface Casing Cement Job SO: 903063962 CEMENT UNIT PUMPED A TOTAL OF 48.4 BBL 15.8 65016 1501 3.01 1.1 PPG, 1.15 YIELD, 5.01 G/SK, 260 SKS TAIL CEMENT 297.4 PSI, 3 BPM, 195.42 15.92 2.69 353 WHILE PUMPING TAIL CEMENT WE HAD TO SHUT DOWN WE TO DELIVERY ISSUES FOR THE HERC SKID. ONCE THE HALUBURTON Event 17 Shutdown Shutdown 1/25/2016 11:55:33 USER 45.92 1552 0.37 1.7 PERSONAL CLEARED THE BLOCKAGE IN THE DISCHARGE UNE WE BATCHED UP AND STARTED PUMPING 158PPG TAIL CEMENTAGAIN. Event 18 Pump Tail Cement Pump Tail Cement- 1/25/2016 11:5655 USER 37.13 15.49 0J9 17 Resume Event 19 Pump Tailm Ceent Pomp Tall Cement -hutdown 1/25/2016 1202:27 USER Page 7 32.24 14.52 0.26 8.8 DURNING PUMPING OF THE TAIL CEMENT WE HAD TO SHUT DOWN AGAIN DUE TO BLOCKAGE IN OUR DISCHARGE UNE COMING OFF OF THE STEADY FLOW. WE SHUT DOWN BROKE OFF THE CEMENT HOSE AND CLEARED THE BLOCKAGE. WE AM OPENED UP THE CEMENT HEAD AND MADE SURE THATTHERE WAS NO BLOCKAGE.WETHEN BUTTONED EVERYTHING BACK UP AND BATCHED UP ANOTHER TUB OF 15,8 PPG TAILCEMENTAND CONTINUED PUMPING DOWN THE DRILL PIPE iCem Service (v. 4.2.393) Created: Monday, January 25, 2016 HALLIBURTON Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job: CTg110.75" Surface Casing Cement lob SO: 903063962 Event 20 Pump Tail Cement Pump Tall Cement- 1/25/2016 12:14:12 USER 35.18 14.65 0.95 8.8 Resume Event 21 Pump Tail Cement Pump Tail Cement - End 1/25/2016 12:16:47 USER 49.83 15.64 0.16 14.1 DART PLUG LOADED IMO SIDE ENTRY SUB. DART WAS PUSH DOWN BY HAND PAST Event Drop Plug Drop Plug 1/25/2016 12:35:27 USER 70.35 15.61 000 0.0 THE PUMPIN SUB. PLUG WAS THEN DISPIACED WITH 42BBL FRESH WATER BY THE HAW BURTON CEMENTUNIT CEMENT UNIT PUMPED 42 BBL DISPIACEMENT. 34 BBL PUMPED @ 5 BPM 840 PSI, SLOWED TO 1 BPM AT 34 AWAY PRESSURE 730. BUMPED PLUG AT 42 BBL AWAY BUMPED AT 740 PSI Event 22 Pump Displacement Pump Displacement- 1/25/2016 12:3650 USER 14.66 15.75 005 0.0 PRESSURED UP 500 PSI Begin OVER AND HELD FOR 5 MIN, PRESSUREDWASTHEN RELEASED AND FLOATS HELD CALCULATED DISPLACEMEENTWAS44 BBL WE BUMPED 2 BBL EARLY Event 23 Pump Displacement Pump Displacement- 1/25/2016 124031 USER 222.78 8.24 3.22 143 Rate Decrease Pump Displacement- Event 24 Pump Displacement 1/25/2016 12:42:12 USER 145.59 8.17 1.27 163 IntRase Rate Pump Displacement - Event 25 Pump Displacement Decrease Rate to Land 1/25/2016 12:4622 USER 673.23 8.35 3.22 35,6 Plug CEMENT UNIT BUMPED PLUG, 42 BBL Event 26 Bump Plug Bump Plug 1/25/2016 12:5151 USER 1137.36 8.22 0.95 42,6 DISPLACEMENT BUMPED AT 740 PSI PRESSURED 500 PSI Page 8 iCerTi Service (v. 4.2.393 Created: Monday, January 25, 2016 HALLI S U R TO N Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job : CTR110J5- SuH%oe Casing Cementlob 50:903063962 OVER HELD FOR 5 MIN BLED PSI OFF CHECKED FLOATS, .5 BBL FLOW BACK FLOATS HELD CEMENT WAS IN PLACE AT CEM Event Cement in Plate Cement In Place 1/25/2016 13:0013 USER 5.86 8.31 0.00 42.6 IPM END SURFACE CEMENTIOB Event 27 Endlob Endlob 1/25/2016 1302:28 COMB 4.89 8.25 0.00 42.6 OND l Post -lob Safety Post -Job Safety Meeting POST JOB SAFETY MEETING Event Meaning (Pre Rig-Dmvn) (Pre Rig -Down) 1/25/2016 130)52 USER 31.2) 0.09 0.00 p2.6 HELD IN CEMENT UNIT AFTER SURFACE CEMENT JOB THE CEMENT CREW LOAD TYPLE L CEMENT BACK INTO THE HERC SKID TO BETAKEN BACK TO POINT LONEY. TO BE WEIGHED BACK AND Event Other Other 1/25/2016 1330:00 USER STORED IN SKID 3 TANK 1. THE CEMENT CREW ALSO WASHED UP THE CEMENT UNITTHEY HAD TO WAIT ON CRUZ'S SUPER SUCKER TO VAC OFF THE WASH UP WATER.. PRODUCTS USED:5 GALLONS D -AIR W, 25ACK5 1D0 POUNDS SODIUM CITRATE FOR CEMENT Event Other Other 1/25/2016 13:21:00 USER PUMP WASH UP, 4 SACKS 2D0 POUNDS SODIUM CITRATE PILL TO RETARD THECEMENTRETURNS COMING BACK TO SURFACE. Page 9 iCem' Service (v. 4.2.393) Created: Monday, January 25, 2016 HALLIBURTON 2.1 Job Graph CTnl 10 75' Surface Casing Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job: Rg110.15- Surface Casing Cement Job 50:903063962 991q$AM 43S]SMI UX)r45AM 10`205M1 111515AM Ila@<$M1 1T1295 pM 123315 %A x,dd7. oSP,Re.oc Ce_:', ,vvR.t-.-,FranW n 51nbC ,.. ... lftddnsan& i_._ a3Nm1510t1m-b0apa - UNmal)"Mssemnl gepn-5 'O60 r NmpWelaAbead-0epm jtPMwniM Maum PNaura : J, '5-25 SCPmb dN Pl(nalenialCm>n Pe ib . 6nll51 23Nmp00M..d lMleOwons,2 3E ie3I2'41 y NmPS'M�e�AMetl-EIM 1 ' ON—TadEnd0,.. 9shiodmn 2e Nmp onban n-Ineraace ldt'J5, i11 IO, 1�PraprteRM Bp�n: - La. IDNmP spas,-Begn 25Nmp P.Plamme.. pads Pyre to lend Pw9 2J2 zPnddsd,nW It '-a 4"PSpnl End - $Nmphd CBmenl-SAuWl— - NNon Ry - �Nevanial-Bdnd'N M CF'I SNmPbM tilos. Pep _,.— 20Nnp1al Csnem'wmme 22End Jd £PoaopQM End: 'J—'71' 's 8Nmp Wl CkmeN Ed C2t:2 21 NmpTBGncn-I. •MGWSUWDN'. ICE tServiCe e, 11::31 E61 Page 10 iCem Service 1, 4.3.393) Created: Monday, January 25, 2016 I H A LLI B U R TO N Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job : CTg110.75" Surface Casing Cement lob 50:903063962 2.2 Water Ahead C?k1 10 7E SaAaca Casng 5 1 r�pmp � OS Pump Press (pv1 5262 Cement0l Ra"bjLfle S,l Comb Pump RAelbbpminpW - i i _ LS{ �� Nwmun Nanmun OS Pump Ness 0 1192 14931 CMrenl Dm5nAppj) 122 845 1 si Cnmb Pomp AcleW n) I% 264 crl Cnmb No, lomlbbp 001 962 t� 1 i N1 i 215 N.1 90255 UA N345AM 4fa 3S 11 .121. 40M1 15w .1,J1 AM Wss 9mi5.1M ,Y.i�alinrE •MGWal1moO IC- "511 Page 11 iCem' Service 1, 6.2.393) Created Mandey, January 25, 2016 HALLIBURTON 2.3 Pressure Test C-41 10 7B SuAace'as ir.g Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job. 07#110 75" Surface Casing Cement lob 50:903063962 91133 M1 9110. 9t913AN earn MI 4AS3,& 911,oAM JarmTna D50.m tus 'm a, Nr,i imii C[cbt rP fla%LN•'r Co -b PCplaa bt'. •NYWg11NlNN Ir.�m=SHVIC2 -rcae,E n W.i_o_: w Page 12 iCem' Service Iv.4.2.393I Created: Monday, January 25, 2016 HALLIBURTION 2.4 Tuned Spacer III 0411075' Sf,,ICP, Casing +2101W Isles. 933 11 aM 131r? so 9.21. k,ATme Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job: CT41 10.75" Surface Casing Cement lob 50:903063962 ln3 V A. "I N su 4`Al1 PM a1 IDURTON Ct S,F InC_ ink Page 13 iCerro' Service (v 4,2.3931 Created: Monday, latuar, 25, 2016 No. O'e 0 "'nor, D5fi 21062 Cement Dnn�q (,M� 1' 45 Comb Pon, sure (hbv.,r) '29b Rom Vsibles, Mr. eommons DS Purni, N,,, (ll) 6142 51699 Cement (e,,,Jy 1pp9l 955 1314 Comb Pump Ral (ocni )CO 507 Cent, Romp Tl Out 01) OJ5 5099 +2101W Isles. 933 11 aM 131r? so 9.21. k,ATme Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job: CT41 10.75" Surface Casing Cement lob 50:903063962 ln3 V A. "I N su 4`Al1 PM a1 IDURTON Ct S,F InC_ ink Page 13 iCerro' Service (v 4,2.3931 Created: Monday, latuar, 25, 2016 HALLIBURTON 2.S Lead Cement _ _-- C F.. �lo lQ AVUW 05 Pima %esslpal2&39 C.bm oU,Ut)1073 Comb Pump RalelbbVmm1.1.20 Yanatlu Rirvmwn Namur OSWmP%e551p5r) 1951 Cem MEW,bylppgj 9N %9]135 Wmp Ralewft4) 040 UO -Comb • COmb PumpT NMb) 043 35398 43412" 9S132u CT411075' Surface Ca6mg Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job '. a#1 10.7F 5urfem Casing Cement lob 50;903063962 1DIsO 1 L uUm 165432M 1t15]M' UI S2M1 Ml T. DS Pons Rez'md fr•;,"Db-.mr:reN Cara Parp Fx;albof.+r: C bPrprxa. b^,, . Neweurtax I ICem®$mire .._ _ _Eat Page 16 (Cern Service (¢ C13931 Created: Monday, January 25, 2016 HAL LI B U R TO N Customer: CAELUS ENERGY ALASKA SMITH RAY LLC Job: alit 10.75" Surface Casing Cement Job 50:903063962 2.6 Tail Cement -1 C-01 10 75' Surface `os '.9 osPump Pel 09135670 ` Cemeal 0ensy 01,911569 Ccmb vamp bhllninla39 from 1 NneWm Nirc Abvmum 3" MPam, Press Ji) 3171 101316 Cememu msiry(pp91 1510 1)05 - Comb Pum Aale mn 0.3) 912 ' P @NI -. C,nb Pump lold 0G1 ooz 35Je as. Il'm12 AM 113 mu U,INNA Il Si12uM IIMN ru I�lf1]4H k,4imE .. � - '.0 .y..� to ..._..... HALLOURTON. (_ Page 15 iCem Service (P. 0.2393) Created: Monday, January 25, 2016 HALLIBURTON 2.7 Tail Cement -2 CT41 1075 Surface Casing 0 0 rrmmplop armaP< e- DS Pomp press P,411395 Cement Demi]119 15,61 I Comb pump Yale lbbllmin) 201 E 1.5{ P DSN P?,WPu1, 3510 16799 2� rarely Comb Pr PRn, 6 1 bi 05921! Comb Pomp 1,111 IV 121 0.25 i 0 Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job: Cali 10.7F Surbce Casing cement Job 50:90306396] 11wi?. 113.2. 11:=%2: M1 115512 aM iJA103 YM t21?2J A.t Pcmv6Tme ,,, D_.. .fv,. ,-..c. .. •HGWBIIPTON2E�.. fSl Page 16 ili Service 1, 4.2.393) Created: Monday, January 25, 2016 HALLIBURTON 2.8 Tail Cement -3 11.42. U.M2. Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job: Qx11075- surface acne Cement Job 50:903063962 C741 10 75' Sur(, ee Casing nfto JISQa M obtom 121222. knorTare A DS k—, lh�. mi Do,l W Ub' ons',h. I r, C,l, P,111a3Y X61.1-GLg310ICe:nCSPNi<2 Page 17 iCerri Service (y. 0.2.393) Created: Monday, January 25, 2016 0.511 1Ck11i knnAa OS Pump Pe»(psR: 301.61 ,.. UmeiA Di ON) 1593 35 Comb Pmnp Pale lbbl inA 249 vtinmd Ma.mym Maxima, 2 OS Pump fess "l 3811 JIM ',. Unions 0anffiy Innis 10.15 9Q 6 2- Comb Pomp ame(bbbniis 098 212 _ Comb Pump TWA(bbil $78 1414 til �I 1J n5 9_ 11.42. U.M2. Customer: CAELUS ENERGY ALASKA SMITH BAY LLC Job: Qx11075- surface acne Cement Job 50:903063962 C741 10 75' Sur(, ee Casing nfto JISQa M obtom 121222. knorTare A DS k—, lh�. mi Do,l W Ub' ons',h. I r, C,l, P,111a3Y X61.1-GLg310ICe:nCSPNi<2 Page 17 iCerri Service (y. 0.2.393) Created: Monday, January 25, 2016 HALLIBURTON 2.9 Displacement V 35MM 13#1 1075' Surface Casing Mama. tooel. XodTme Customer: CAELU5 ENERGY ALASKA SMITH BAY LLC lob: Ull110.75' Some to Casing Cement lob 50:903963962 DS M:Rra as Ca^s"Ca-sry PX [ c p9zn.G fa'.E P.-erra p5'.'. -ueluewrrlt9 �iCemg Servke _ o:.a.. >a lz Je o,.' Ede iCern' Service (v. 6.2.393) Created Monday, January 2S, 2016 Page IS ti kan ©ro Q --"h S �+pe Y.i DS wap Mu(pl) Sb96 Cement bm£n 019; 961 Comb Pump pale Wbbm'nl_2M i i jfmm©io® g 1 '.Nnmtw Mme llannam DS pwnp pas+ 0l OR 95011 Cement Da"0097 all 15M _ E Comb pump Rs Motor-) 991 S19 Comb wap real ON 00: as6 _- c 1 Xvl ) 0 V 35MM 13#1 1075' Surface Casing Mama. tooel. XodTme Customer: CAELU5 ENERGY ALASKA SMITH BAY LLC lob: Ull110.75' Some to Casing Cement lob 50:903963962 DS M:Rra as Ca^s"Ca-sry PX [ c p9zn.G fa'.E P.-erra p5'.'. -ueluewrrlt9 �iCemg Servke _ o:.a.. >a lz Je o,.' Ede iCern' Service (v. 6.2.393) Created Monday, January 2S, 2016 Page IS Note to File NO LONGER CT -1 (PTD 215-208) CONFIDENTIAL, (Sundry 316-110) (Confidential) .IAN 13 2020 February 9, 2016 Re: Caelus' Application for Sundry Approval for Additional Annular Disposal of Drilling Wastes within CT -1 Request Caelus requests approval to resume disposal of waste fluids generated through drilling operations by injection into the annulus of well CT -1 to a volume limit of 10,000 barrels. Recommendation Approve Caelus' request. Conclusions 1. The 10 3/4" surface casing shoe is set in this well at 2,551' measured depth (MD), -2,486.6' true vertical depth subsea (TVDSS), at the bottom of a 151 -foot thick interval dominated by claystone. This interval will provide confinement to prevent upward migration of injected waste. 2. There appears to be a sufficient volume of sandstone open to the annulus of this well to accept the proposed injected fluids. 3. The lower confining layer is sufficiently thick and laterally persistent to ensure injected materials remain within the target disposal intervals. 4. There are no potential USDWs in this area. 5. Correlative rights will be protected. 6. The proposed disposal injection operations will not affect potential oil or gas reservoirs. 7. The area most strongly impacted by the proposed annular injection activities will be limited to a radius of about 36' from the wellbore. Discussion Caelus' application was reviewed along with records from nearby wells East Simpson Test Well -1 and Drew Point -1, located, located 9.5 miles to the northwest and 10.0 miles to the northeast, respectively. The discussion that follows is based on well records, logs and the mud log from CT -1. An index map is provided, below. The proposed injection interval in this well lies in the Nanushuk Formation within Section 17, T17N, R9W, Umiat Meridian, which is located in the NPR -A. The 10 3/4" surface casing shoe of the well lies at 2,551' MD (-2,486.6' TVDSS), at the bottom of a 151 -foot thick interval that is dominated by claystone that is likely continuous throughout the area. This interval will provide upper confinement for fluids disposed in the annulus of the well. The annulus proposed for disposal of drilling wastes extends downward from the surface casing shoe to the top of open hole cement plug proposed to extend from total depth at approximately 7,070' MD upwards to 5,000' MD. The most likely portion of the open annulus that will accept injected waste are several 10- to 25 -foot thick beds of silty sandstone and sandstone that lie between about 2,573' and 2,980' MD, which is just below the surface casing shoe. The aggregate true vertical thickness of these CT -1 Annular Disposal Application February 9, 2016 Note to File Page 2 of 4 Confidential thin potential injection beds is about 63'. The injection beds are separated by clay intervals. Beneath the injection zones is a 200' thick claystone interval that is likely continuous throughout the area. This interval, which lies between about 2,700' and 2,900' MD, will provide lower confinement for any injected wastes. An addition claystone interval, approximately 1,770' thick, lies between 3,100' and 4,870' MD. Simpson Test Well -1 Drew `lam V` / INDEX MAP Figure 1. Index Map In this area, the base of permafrost occurs at about 929' measured depth (-905.60 TVDSS), which is about 1,644' above the top of the proposed injection intervals. The shallow geologic section in the CT -1 well contains methane gas. Records indicate that traces of methane were first measured at 150' measured depth. The more significant amounts of methane (arbitrarily placed at 25 units of gas on the mudlog) were encountered in the well at 5,043' MD. So, the entire proposed disposal zone may contain some methane gas. Supporting documentation to Caelus' annular disposal applications states: "No aquifers." This is correct. Log analysis calculations indicate formation water salinities exceeding 18,535 ppm NaCl across the likely disposal injection intervals from 2,575 to 2,980' MD. CT -1 Annular Disposal Application Note to File Confidential CT -1 Figure 2. Likely Disposal Injection Intervals February 9, 2016 Page 3 of The shallowest oil indicators observed in CT -1 occur at 5,660' MD, which is more than 2,680 feet below the most likely disposal injection intervals. The following chart provides an estimate of the affected areas surrounding the affected wellbores. Well logs for CT -1 indicates about 63' of net sandstone and silty sandstone are present in the most likely disposal injection intervals. Inspection of the neutron and density porosity logs suggests an average sand and siltstone porosity of 19% at this depth. Based on these values, the area most strongly impacted by the proposed additional annular injection activities will be limited to a radius of about 36' from the wellbore. The limited volume of rock that will be affected by this proposed additional disposal injection program contains methane gas, is situated beneath about 929' of permafrost, and is bounded above and below by continuous layers of claystone. There are no freshwater aquifers present, nor are there any potentially CT -1 Annular Disposal Application Note to File Confidential 300 250 E a° 3 200 E 1w s a 100 rc a 04 0 Injected Fluid vs Affected Radial Distance CT -1 Wellbore (assumes 63' aggregate injection zone thickness and 16'6 porosityl � I VUl11 Amount Of inled d Fkdd t ) February 9, 2016 Page 4 of 4 Figure 3. Estimated Affected Area (Radial Distance in Feet from the CT -1 Wellbore) 20.000 commercial hydrocarbon accumulations within the proposed zone of injection. The area affected by this proposed additional injection operation lies inside Caelus' lease, so correlative rights will not be a concern. I recommend approval of this annular disposal operation. 00 Patricia Bettis 'V Senior Petroleum Geologist Note to File CT -1 (215-208... Sundry 316-110) Exploration Well Caelus Energy Alaska Smith Bay, LLC Caelus made application for annular disposal (AD) on their CT -1 exploration well. The sundry form was originally received as sundry 316-110 and stamped February 8, 2016. Additional information not contained in the application will need to be reviewed with Caelus prior to injection. The well will dispose of the fluids and then continue P&A operations. This document examines the pertinent information for the well and recommends approval of the Caelus request. - Caelus has provided the surface casing cementing record. The 10 %" casing was cemented back to surface with full returns and cement circulated out at surface. - The LOT was performed on 1/28/2016 with the shoe at 2510 ft TVD and open hole to 2548 ft/2541 ft TVD. The chart is interpreted as an increasing gradient until a potential break over point at 820 psi (15.71 ppg EMW) before pressuring up to the maximum of 950 psi (16.57 ppg EMW) - The well drilled the intermediate hole to TD. The well will have cement plugs set as part of the P&A with the top cement plug estimated at 5000 ft and the drill pipe will be run in the well to establish the "annulus" required by regulation. No intermediate casing will be run and the well will be P&A after disposal operations. - A deep FIT/LOT will need to be established to ensure injection can be done at pressures below the surface casing shoe fracture gradient (2049 psi/15.7 ppg EMW) - Fluids to be injected are from the drilling of CT -1 only. No cement evaluation logs were run on the surface cement job. Caelus plans to P&A the well as per Sundry 316-109. The Commission has in the past approved disposal via a retainer set near the surface casing shoe or the intermediate casing shoe. This operation is conducted as part of the P&A process with deep abandonment plug(s) set in the open hole. There is no guideline as to how shallow the wellbore should be plugged prior to starting the disposal operation. Practically, the top of a plug should leave sufficient formations exposed so that the disposal may be conducted. What studies have been conducted regarding AD indicate that the exposed formations within about 200' of the shoe take the pumped fluid. Once such disposal is completed, cement would be pumped to seal the shoe and the disposal formation. Seasonal operational logistical considerations make this operation time critical. Requested fluids for disposal are common exploratory oil field wastes and have been approved in the past by AOGCC. Fluids mixed together (boiler blowdown and camp wastes) offer beneficial re -use by diluting any solids in the waste streams (drilling muds or cement rinses). Based on examination of the submitted information, we recommend approval of the Caelus request for annular disposal in the subject well. Condition of approval is open hole LOT must be established and injection must be below the 15.71 ppg EMW shoe fracture gradient. Chris Wallace C� Sr. Petroleum Engineer February 9, 2016 CCAELU S F,i , Alaska Spacer Volume Required bbls 20.0 Total Plug Cement Volume bbls 49.1 Total Plug Cement Volume Required sacks 240.00 Cement Mix Water Volume Required bbis 28.3 Spacer Mix Water Requirement bbis 17.9 Wash -Up Volume bbis 50 Total Water Volume per Job bbis 97.0 NOTE: Final P&A procedures need to be approved by the AOGCC as well as the Sundry for fluids disposal into the Nanushuk interval from 2650' to 2980' MD Once TOC has been confirmed at 5000' +/- pull BHA # PA100 to 3000' +/- or across the bottom injection zone, close the annular or pipe rams and prepare to pump down the backside i.e. "annular disposal". 4I ipA I ` , f e r Q(Pm Oak S ✓ nd "I 316 _ W � Guidelines for disposal are: s✓nd, 3 � (�- � 1 O flrtAu (aX D/ YoSaJ • Perform an open hole LOT procedure similar to the surface casing shoe LOT procedure. See attachment. •-Attem9pi to �ep surface pressure plus fluid density below the 15.7 ppg EMW (LOT) at the surface casing shoe. Calculated maximum anticipated pressure at shoe is 2049 psi,4irra- �w 21912016 • Notify Anchorage of the results before starting fluids disposal. • Once a rate is established flush the backside with 200 bbls +/-water and begin annular disposal of fluids. o Surface pressure plus the hydrostatic weight of the disposal fluid should not exceed the 2049 psi. o Monitor density of the fluids being pumped downhole. Adjust rates and pressures accordingly. c Keep record of volumes, fluid densities, and surface pump pressures for AOGCC reporting. v As f U al Pro-,� 5✓4r,� 3)6-10/ 6. POOH hole with BHA # PA100. Stand back 30 jts of Weathearford 2-7/8" 10.4# S-135 D/P 2-7/8" HT PAC (approx.: 930 ft.). 7 2 ISSA u � �oct- �-ED 1N� �p�E C,,EL_LJ S Energy Alaska Prospect Name Tulimaniq Principal Engineer: Walter Quay Well Type Exploration Drilling Contractor/Rig : Doyon Drilling/Arctic Fox Well Classification Producer C T # 1 Ice Dad thickness (ft.): 8.0 ft. Zone of Interest /Primary Torok RKB elev. (reference : M 23.4 ft Zone of Interest/Secondary Ellesmerian Plug & Abandonment AFE DRILL, EVAL. &TES167 DAYS D[R/LWp MWp ON LOGS fORMATION DEPTH -ukb) Smith Bay HOLE SIZE USING SPECS MUD INTO/CEMENTING imm INFO »usED North Slope, .Alaska HOLE LOGS Np WD Casing Cut 2. ��� _: lfi in. 841b/ft X-56 ERW Conductor t0 be augeretl Well Head: FMC Gen. V 11" NONE NONE Permafrost 0 0 16, & 10-3/4":,' .. 24" Depry (RKB) :110 ft. W 80 ft. below ice pad SK 38 R rkb , '' elev. Mudlogging : 100 100 Spud Mud: Start @100 ft TVD/MD BDF 499/Porymer MW: 9. E25V @ 224 rkb q R non Top Gas Hydrate TAM Ported Collar GasFact - mass spec Stability Zone 828 828 G 500 R. and/lvd Base Permafrost 929 929 9.e PF9 mw Base Gas Hydrate 1692 1638 Stability Zone Lead Cement: Permafrost Freeze Protection Dir/GR/Res TOC 0 ft/BOC: 2066 ft. Annull 7-5/8"x 10-3/4" (Diesel) XBAT/XCALh Surface Casing: Density: 10.7 Ing. 2530' TVD/2566'MD Excess: 250%/40%. 10-3/4" 45.50 lbs/ft L-80 BTC Inns red: 5,210 psi Tall Cement: TOP#32426 wlaxe:Zlmm TOC: 2066 ft EZSV @ 2476 m: 9.950'. can III- 9.88' Density: 15.8 Presure rest: 3000 psi ppg Excess: 40% 10-3/4" Casino 2551 2510 TOP #22476 13-1/2" Mudlogging Intermediate Mud: Leak OR Test (LOT): Mudlog0inq : Nanushuk Topset 2861 2811 3% KCl/BDF 499/PHPA 14.00 ppg equiv. (expected) Platrorm Express/DSI 2'6,c,'MW: 9.6-10.2 IN GasFact -meas Spec (ConHgerlcy)/CMR potential sobsitute: Rtscanner for ArT Open Mole BASE#2: 3500 & add orientation sonde Injection interval Torok SB3 4915 4779 9.8 ppg FMI/DSI Torok SB 3 Saturn -or- MDT Top Tulimaniq Fan 5180 5041 Tulimaniq Fan Formation Evaluation Top Central 5313 5173 Contingency: Prima Objective ty MSR -or - XL -Rock To Lobe p 5768 5628 TOP#1:5450 t L Core-120'Torok/Tulimaniq Base Tulimaniq 5950 5810 BASE #1:6050-ftug� -- ROPE: Torok/Tulimaniq VSP Top HRZ 6723 6583 MWD/LWD: 6.3/4" Triple Combo *Cased Hole Logs Dir/GR/Res/PWD/Den CCL/GR/CBL Neutron -Porosity in event of well test 9 e PPJ m"d 6-3/4"XBAT 6-3/4" XCAL 6.3/4" MRIL Well Total Depth Open Hole 6-3/4" Geotap IDS (TD) 6645 6518 8-1/2" 8-1/2" Mudlogging Top LCU 6890 6700 Platform Express/DSI GasFact - mass spec Ellesmerian Section - Not Drilled 4 arm caliper included - Top Sao River 7471 7331 PEXIDSI collar Top Shublik 7623 7483 Dipole Sonic MWD/LWD: MSR -or - XL -Rock 4-3/4" Triple Combo Top Ivishak 8161 8021 Dir/GR/Res/PWD/Den Neutron -Porosity Tap Lisburne 8363 8222 4-3/4" XBAT VSP 4.3/4" XCAL Too Kekiktuk 8521 8381 4.3/4" Geotap Basement 8681 8541 TD 8781 8641 6-3/4" Max. Wellbore Deviation Directional "S" Profile DMe Rex by commam. Well Total Depth (TD) 8781 ft. and / 8641 ft. tvd 7mn016 MCxi, SIRIaeu.: 71IM015 Surface Location (NAD 27 UTM ZONE 5 - meters) X:452075 Y:7858579 7/302015 M.Cwk SIR Caelus:7/382015 atR6 M.H. Surface Location (Govt. Sect. Line) 2149 FNL, 1724 FWL T17N R09W Sect. 17 102721015 M.Cwk F.-.wn .P wM eiuvAES Cemmler BHL (NAD 27 DTM ZONE 5 - meters) X:452082 Y:7858884 SHL (Govt. Sect Line) 4132 FSL, 3552 FEL T17N R09W Sect. 17 Projection Method NAD27/ZONE 5/UTM - meters Rev.2 4�G�; C.A4J-L--LJ S -,�_- Alaska Prospect Name Tulimaniq Principal Engineer: Walter Quay Well Type Exploration/"( Well Classification Producer T1 ■`/ 1 Drilling Contractor/Rig : Doyon Drilling/Arctic Fox Ice Dad thickness (ft.): 8.0 ft. Zone of Interest /Primary Torok RK8 elev. (reference: M 23.4 ft. Zone of Interest/Secondary Ellesmerian plug & Abandonment AFE DRILL, EVAL. & TES167 DAYS OIR/LWD MIND ON LOGS FORMATION DEPTH -(rkb) Smith Bay HOLE SIZE GISING SPECS MUD INFO /CEMEXr1NG INFO INFO *CASED HOLE LOGS North Slope, Alaska MD WD Casing Cut ::: 161n. 84 lb/ft X-56 ERW Conductor to be augered Well Head : FMC Ge NONE NONE Permafrost 0 0 6' 16' & 10-3/4'•.::::: ;; 24" Depth (BKa7: 110 ft. to 80 ft. below ice pad SK H rkb elev. Mudl m 099 g 100 100 Spud Mud: Start @100 R WD/MD +. BOF 499/Polymer MW: 9.5 li @ 225 rkb 9.8 717171 Top Gas Hydrate TAM Ported Collar Gii - mass spec Stability Zone 828 828 @ 500 k. rai Base Permafrost 929 929 9 8 ppg mud Base Gas Hydrate 1642 1638 Stability Zone Lead Cement: Permafrost Freeze Protection Dir/GR/Res TOC: 0 ft/BOC: 2066 ft. Annuli 7-5/8"x 10-31- XBAT/XCAL Surface Casing: Density: 10.7 ppg. 2530'WD/2566'MD Excess: 250%/40%. 10-3/4"45.50 lbs/ft L-80 BTC mtemal vreld: 5,210 re Tail Cement: TOP #3 2.426 Collapse :2,470 psi TOC 2066 ft EZSV @ 2476 ID: 9.950^. Drift Dia: 9.875' Density: 15.8 rot... to To,,: 3000 pr. ppg Excess: 40% 10-3/4" Casing 2551 2510 TOP #22476 13-1/2" Mudlogging Intermediate Mud: Leak Off Test (LOT Muclimminu : Nanushuk Topset 2861 2811 3% KCUBDF 499/1PHPA 14.00 ppg equiv. (exl Platform Express/D9I 1/ ';b i MW: 9.6-10.2 ppg GasFact - mass spec (Contigency)/CMR Potential subsitute: Rtscanner for An Open Hole BASE#2 : 3500 & add orientation sonde injection interval Torok SB 3 4915 4779 9.8 ppg FMI/DSI Torok SB 3 Saturn -or- MDT Top Tulimaniq Fan 5180 5041 Tulimaniq Fan Formation Evaluat Top Central 5313 5173 Contingency : Primary Objective MSCT -a, XL -Rock To Lobe 3 P 5768 5628 TOP#1:5450��s,��,,rr�� (r Core-120'Torok/1 Base Tulimaniq 5950 5810 BASE #1:6050 MINESbOO ROPE: Torok/TuIh LISP Top Fri 6723 6583 MWD/LWD: 6-3/4" Triple Combo *Cased Hole Logs Dir/GR/Res/PWD/Den CCL/Gli Neutron -Porosity in event of well test 9 e pro mud 6-3/4"XBAT 6-3/4"XCAL 6-3/4" MRIL Well Total Depth Open Hole NV 6-3/4"Geotap IDS (TD) 6645 6518 B-1/2- 8-1/2" Mudlogging Top LCU 6840 6100 Platform Express/OSI GasFact - mass spec Ellesmerian Section - Not Drilled 4 arm caliper included - Top San River 7471 7331 PEX/DS1 collar Top Shublik 7623 7483 Dipole Sonic MWD/LWD: MSCI -or-XL-Rock 4-3/4" Triple Combo Top Ivishak 8161 8021 Dir/GR/Res/PWD/Den Neutron -Porosity Too Lisburne 8363 8222 4-3/4"XBAT VSP 4-3/4" XCAL Too Kekiktuk 8521 8381 4-3/4"Gentap Basement 8681 8541 TD 8781 8641 6 -3/4 - Max. Wellbore Deviation Directional "S Profl a Dara Rep b cammeore Well Total Depth (TD) 8781 ft. and / 8641 ft. tvd 712"2." u.ceeix 30R odema 71131em5 71am2m5 ucaox SCR Caew, 71301201 edit. u.R. Surface Location (NAD 27 UTM ZONE 5 - meters) X:452075 Y:7858579 Surface Location (Govt. Sect. Line) 2149 li 1724 FWL T17N R09W Sect. 17 1012712015 MCook Formation top mnmrnatiorLS cementer BHL (NAD 27 UTM ZONE 5 - meters) X:452082 Y:7858894 BHL (Govt. Sect. Line) 4132 FSL, 3552 FEL T17N R09W Sect. 17 Projection Method NAD27/ZONE 5/UTM - meters CE CAELU S Erer y Ataska CT -1 DRAFT Plug & Abandon Conductor & Surface Casing Retrieval 1699x 10-3/4" Caelus Energy Alaska, Smith Bay LLC Exploration Test Well Smith Bay, North Slope, Alaska Modified by TJB 02/04/2016 1 CE CAELU S Enemy Alaska Well Name: CT -1 Drill & Evaluate Summary Tvpe of Well: I Exploration Test Well / North Slope Surface Location: 2149' FNL. 1724' FWL. Section 17 T17N R09W UM Target Formation: 4132' FSL. 3552' FEL. Section 17 T17N R09W UM Total Depth 4132' FSL. 3552' FEL. Section 17 T17N R09W UM AFE Number: 1150036 Spud Date: Jan. 20 ., 2016 Rig: Doyon Drilling : Arctic Fox Total Operating days to Drill 67 & Evaluate: MD: 667900 ft TVD: 6ft 6650 ft Max Inc: 17. KOP: 1000 PAD -AMS 14.9 ft8.5 . Well Design conventional, slimhole, etc.: I Directional "S" Profile Objective: Primary : Drill & Evaluate Torok/Tulimaniq Fan (8-1/2" intermediate hole sect.) Secondary : Evaluate Ellesmerian Formation(s) (6-3/4" production hole sect.) Drillina Fluid Proaram: Surface Hole Section : 13-1/2" Polymer/BDF 499 Density (ppg) Funnel Vis PV YP pH JAPI Filtrate LG Solids 9.5-9.8 125-70 10-30 30-35 9.0-10 1 <9 1 <13% Intermediate Hole Section : 8-1/2" Hole Section Opening : 9-7/8" 3% KCL/BDF 499/EZ MUD DP PHPA Density (ppg) PV YP HTHP CI-(mg/1) API Filtrate LG Solids 9.6 — 10.2 8-20 15-25 NA 1 <15K <6 <6% 2 CE CAELU S Fr, -,o. Alaska Formation Markers: CT- 1 Formation Est. Formation Tops (TVDss) Actual MD/TVD ((Feet) Prospective Hydrocarbon Bearing Top Gas Hydrate Stability 805' Casing Test Pressure 10-3/4" 45.5# L80 BTC 3000 psi Base of Permafrost 906' Maximum Surface Pressure 2726 psi (0.11 psi/ft gas gradient to surface) BGHS (Base Gas Hydrate Stability) 1615' Annular test to 250 psi/2,500 psi Nanushuk Topset 2788' 7-518" 29.7# L80 BTC 3500 psi Torok SB 3 4756' Top Tulimaniq Fan 5018' Top Central Channel 5150' Top Lobe 3 5605' Base Tulimaniq Fan 5787' Top HRZ 6560' LCU/Kin ak 6677' ? Top Sag River 7308' NA Top Shublik 7460' NA Top Ivishak 7998' NA Top Lisburne 8199' NA Top Kekiktuk 8358' NA Top Basement 8518' NA TD 8618' NA ITYn I[•1 • O:101 U 4 Surface Interval : 13-112" 21 '/4" x 2M Hydril MSP Annular Preventer Maximum Anticipated BHP 1263 psi (9.6 Ib/gal @ 2530 -ft TVD) Maximum Surface Pressure 985 psi (0.11 psi/ft gas gradient to surface) Casing Test Pressure 10-3/4" 45.5# L80 BTC 3000 psi Planned Drilling Fluid Polymer/BDF 499 Intermediate Interval: 11" x 5K Annular BOP. 11" x 5K Double Ram BOP 11" x r Initial Wellbore: 8-1/2" Single Ram BOP w/ 2-7/8" x 5" VBR's Hole Opening :9-7/8" Maximum Anticipated BHP 3458 -psi (10.0 Ib/gal @ 6650 -ft TVD) Maximum Surface Pressure 2726 psi (0.11 psi/ft gas gradient to surface) Planned BOP Test Pressure Rams test to 250 psi/5,000 psi. Annular test to 250 psi/2,500 psi Casing Test Pressure 7-518" 29.7# L80 BTC 3500 psi 3 CE CAELU S Enernv Alaska Planned Drilling Fluid 13% KCL/BDF 499/EZ MUD DP PHPA Production Interval: 6-3/4" 11" x 5K Annular BOP 11" x 5K Double Ram BOP 11" x 5K Single Ram BOP w/ 2-7/8" x 5" VBR's Maximum Anticipated BHP 4583 -psi (10.2 Ib/gal @ 8641 ft TVD) Maximum Surface Pressure 3633 psi (0.11 psi/ft gas gradient to surface) Planned BOP Test Pressure Rams: test to 250 psi/5,000 psi. Annular: test to 250 psi/2,500 psi Planned Drilling Fluid 3% KCL/BDF 499/EZ MUD DP PHPA Kick Tolerance/Integrity Testing Kick Tolerance / Integrity T sting Summary Table Maximum Influx Exp Casing set / Interval Volume (bbls) Mud Weight Pore Min LOT / FIT Press Surface : 10-3/4" 1263 2566/2530 ft. and/tvd Diverter 9.5 — 9.8 ppg 12.0 ppg (LOT) Intermediate: 7-5/8" 3458 6790/6650 ft. and/tvd 44 9.6 — 10.2 ppg 12.5 ppg (FIT) Open Hole: 6-3/4" 4583 8781/8641 ft. and/tvd 64 10.0 — 10.2 ppg NOTE: All LOT / FIT will be taken with a minimum of 20 -ft and a maximum of 50 -ft of new hole drilled outside of the previous casing string G! CE CAELU S Alaska CT- #1 — Plug & Abandonment Conductor (16") x Surface Casing (10-3/4") Cut & Retrieve Pre Job Planning • Check all Safety procedures of Doyon Arctic Fox rig operations. • Upon arriving on the Rig Site, Check with the Drilling Foreman or Company Representative to verify Plug & Abandonment and casing cut & pul work scope objectives. • Verify adequate HES cementing P&A blends (sxs) and mix water (bbls) at the appropriate temperature is staged at the CT -1 well site. • Confirm the collection, handling and disposal of cement rinsate and wash-up fluids for each P&A plug. Check all tools sent in baskets to insure all tools arrived at the CT -1 location. • Measure lengths, OD's and ID's of all P&A and Baker Hughes casing cut & pull equipment • Verify Drill Collars, Heavy Weight Drill Pipe, 5" drill pipe and Weatherford - NOV Grand Prideco 2-7/8",10.4#, HT 2-7/8" PAC work string connections to insure all X -over subs are on location. Weatherford : 2-7/8" Drill Pipe Package Quantity Description 30 2-7/8" 10.4# S-135 D/P 2-7/8" HT PAC approx.: 930 ft. 10 2-7/8 HT PAC D/P LIFT NUBBINS 1 YT ELEVATOR DRESSED 2-7/8" 1 2-7/8" D/P SLIPS 1 XO, NC50 X2-7/8 HT PAC BXP 1 2-7/8" HT PAC MULE SHOE • Ensure that the CT -1 Cellar box annuli/outer shell is being heated with blower air to assist with retrieval. • The AOGCC requires a 48 hour advance notice prior to the commencing of well plugging operations. Plug and Abandonment Procedure 1. Pick up and stand back 30 jts of Weathearford 2-7/8" 10.4# S-135 D/P 2-7/8" HT PAC (approx.: 930 ft.) , 5" 19.5# S-135 NC -50 drill pipe and 500' of 5" HWDP. 2. Ensure the Shaffer 11"X5M BOPE is configured with VBR/pipe rams to seal against below rotary tubular sizes: 5" HWDP/DP, 2-7/8" DP. 5 CE CAELU S Enemy Alaska 3. MU BHA # PA100: RIH to Plug #1 bottom setting depth at 6050 ft. md. Displace balanced cement plug 59 bbls from 6050 ft. and to 5450 ft. md. POOH to 4950 ft. md. 4. Wait on cement (WOC) at 4950 ft. and as directed by Halliburton cementing field supervisor until Plug #1 has developed sufficient compressive strength to allow for a confirmation "tag" of 10-15 kips. RIH and tag top of Plug#1. Note top of cement for Plug #1 on HES Job log. Plug #1 : Bottom Tulimaniq Fan Horizon Intermediate Open Hole PTA Plug Intermediate Casing Not Set) Well Input Data Hole Size in 8.5 Bottom of Plug ft 6050 PTA Plug Length ft 600 Top of Plug ft 5450 % Excess 40% Capacity Output Data Open Hole Capacity Data bbls/If 0.0702 Open Hole Capacity Data w/ Excess bbls/If 0.0983 Spacer & Cement Slurry Input Data Spacer Spacer Type Tuned III Spacer Density 10.5 Mix Water al/bbl 37.56 Spacer Volume bbls 20 Bottom of Spacer ft 5450 Top of Spacer ft 5246 Plug Slurry Cement Slurry Type PTA & Int Blend Downhole Slurry Density 15.80 Downhole Slurry Yield cuft/sk 1.15 Mix Water al/sk 4.96 Volume Output Requirements Spacer Volume Required bbls 20.0 Total Plug Cement Volume bbls 59.0 Total Plug Cement Volume Required sacks 288.00 Cement Mix Water Volume Required bbls 34.0 Spacer Mix Water Requirement bbls 17.9 Wash -Up Volume bbls 50 Total Water Volume per Job bbls 102.0 R CE CAELU S Energy Alaska NOTE: Final P&A procedures need to be approved by the AOGCC as well as the Sundry for fluids disposal into the Nanushuk interval from 2960' to 2980' MD. Option #1 ford rilled fluids disposal: is to pull BHA # PA100 to the shoe, close the annular or pipe rams and pump down the backside i.e. "annular disposal". Guidelines for disposal are: • Attempt to keep surface pressure plus fluid density below the 15.7 ppg EMW (LOT) at the surface casing shoe. Calculated maximum anticipated pressure at shoe is 2049 psi. It may be necessary to exceed this pressure to establish injection into the zones. • Once a rate is established flush the backside with 200 bbls +/- water and begin annular disposal of fluids. o Surface pressure plus the hydrostatic weight of the disposal fluid should not exceed the 2049 psi. o Monitor density of the fluids being pumped downhole. Adjust rates and pressures accordingly. o Keep record of volumes, fluid densities, and surface pump pressures for AOGCC reporting. 5. POOH hole with BHA # PA100. Stand back 30 jts of Weathearford 2-7/8" 10.4# S-135 D/P 2-7/8" HT PAC (approx.: 930 ft.). 6. PU Halliburton 10-3/4" 45.5# EZSV and RIH on 5" 19.5#/ft S135 NC50 DP to setting depth at 2476 ft. and (75ft. above 10-3/4" surface casing shoe @ 2551 ft. md). Set EZSV at 2476 ft. md. 7. Displace Plug #2 below EZSV at 2476 ft. md. Calculated cement volume is to 3500' MD. Plug #2: Surface Casing - 10-3/4" 45.5# L80 BTC (below shoe) 7 CE CAELU S Energy Alaska Surface Casing/Intermediate Open Hole PTA Plug (Intermediate Casing Not Set Well Input Data Hole Size in 8.5 Hole Size in 9.875 Surface Casing ID in 9.95 Bottom of Plu ft 3500 PTA Plug Length in 8.5" Hole Section ft 929 PTA Plug Length in 9.875" Hole Section ft 20 PTA Plug Length in 11.75" Casing ft 75 Depth of EZSV ft 2476 Top of Plug ft 2476 % Excess 40% Capacity Output Data Open Hale Capacity Data - 8.5" bbls/If 0.0702 Open Hole Capacity Data - 8.5" w/ Excess bbls/I 0.0983 Open Hole Capacity Data - 9.875" bbls/If 0.0947 Open Hole Capacity Data - 9.875" w/ Excess bbls/If 0.1326 Surface Casing Capacity Data bbls/If 0.0962 Spacer & Cement Slurry Input Data Spacer Spacer Type Tuned III Spacer Density 10.5 Mix Water al/bbl 37.56 Spacer Volume bbls 20 Plug Slurry Cement Slurry Type PTA & Int Blend Downhole Slurry Density 15.80 Downhole Slurry Yield cuftlsk 1.15 Mix Water al/sk 4.96 Volume Output Requirements Spacer Volume Required bbls 20.0 Total Plug Cement Volume bbls 101.1 Total Plug Cement Volume Required sacks 494.00 Cement Mix Water Volume Required bbls 58.3 Spacer Mix Water Requirement bbls 17.9 Wash -Up Volume bbls 50 Total Water Volume per Job bbls 127.0 11 CE CAELU S Eoe.ry Alaska 8. Release from EZSV at 2476 w/5" 19.5#/ft S135 NC50 DP. Displace Plug #3 (50 ft.) on top of EZSV. Wait on cement (WOC) per direction of HES cement supervisor. Pressure test cement plug �6to 1500 psig. POOH. �3 Plug #3: Surface Casing - 10-314" 45.5# L80 BTC top EZSV) Suface Casing Plug (Intermediate Casing Not Set) Well Input Data Surface Casing ID (in) 9.95 Bottom of Plug (ft) 2476 PTA Plug Length in 11.75" Casing (ft) 50 Top of Plug (ft) 2426 % Excess 40% Capacity Output Data Surface Casing Capacity Data (bbls/If) 0.0962 Surface Casing Capacity Data w/ Excess (bbls/If) 0.1346 Spacer & Cement Slurry Input Data Spacer Spacer Type Water Spacer Density (ppg) 8.33 Spacer Volume (bbls) 20 Plug Slurry Cement Slurry Type PTA & Int Blend Downhole Slurry Density (ppg) 15.80 Downhole Slurry Yield (cult/sk) 1.15 Mix Water (gal/sk) 4.96 Volume Output Requirements Spacer Volume Required (bbls) 20.0 Total Plug Cement Volume (bbls) 6.7 Total Plug Cement Volume Required (sacks) 33.00 Cement Mix Water Volume Required (bbls) 3.9 Spacer Mix Water Requirement (bbls) 20.0 Wash -Up Volume (bbls) 50 Total Water Volume per Job (bbls) 74.0 9. PU Halliburton 10-3/4" 45.5# EZSV converted to bridge plug. RIH and set a 225 ft. and (rkb). Release from EZSV at 225 ft. and and displace cement Plug #4 from 225 and rkb to mud line elevation at 25.8' (18.5' Rig + 7.3' of ice) rkb/md/tvd. Wait on cement (WOC) per direction of HES cement supervisor. CC- CAELU S Energy Alaska Plug #4: Surface Casing - 10-3/4" 45.5# L80 BTC Suface Casing Plug (Intermediate Casing Not Set Well Input Data Surface Casing ID in 9.95 Bottom of Plug ft 200 PTA Plug Length in 11.75" Casing ft 200 Top of Plug ft 0 Excess 0% Capacity Output Data Surface Casing Capacity Data bbls/If 0.0962 Surface Casing Capacity Data w/ Excess bbls/If 0.0962 Cement Slurry Input Data Plug Slurry Cement Slurry Type Perm C Downhole Slurry Density 15.60 Downhole Slurry Yield cuft/sk 0.96 Mix Water al/sk 3.81 Volume Output Requirements Total Plug Cement Volume bbls 19.2 Total Plug Cement Volume Required sacks 113.00 Cement Mix Water Volume Required bbls 10.3 Wash -Up Volume bbls 50 Total Water Volume per Job bbls 61.0 10. RIH with 9-7/8" GX-CIX mill tooth bit„DC,HWDP. Drill top 20 ft. of 200ft Permafrost "C” cement plug or ( rkb = 20' + 18.5' rig + 7.3' to mud line (25.8') =45.8') 10 CE CAELU S Encro, Alaska Procedure: CT -1 10 % & 16 casing cut & retreive Mechanical: Casing data: • 16" 155# @ 1 10'This has a .938 Wall Thickness ( Cemented ) • 10-3/4" 45.5# L-80 BTC @ 2,566 MD' (10 3/4x 16" are cemented) • Two sets of Multi String cutter blades (knife size: 8-1/4") to initially cut the 10 3/4 surface casing. Trip to change blades, and then cut the 16 " conductor casing will be required. Work string: 5" 19.5# X 4-1/2 IF Drill Pipe for the bigger size casing strings Objective Step #1 : Cut the 10-3/4" surface casing @ 15' below mud line Step #2: Cut the 16" conductor casing @ 15' below mud line Step #3 : Retrieve 16" conductor casing, 10-3/4" surface casing & CT -1 cellar box 1. PU mill tooth 9-7/8" GX-C1X mill tooth bit/HWDP. Drill, dress off top 20 ft. of 200 ft. Permafrost "C" cement plug. 2. To cut the 10 3/ " casing pick up the following assembly: • 8 1/4" OD Multi -String Cutter w/MM Knives w/ 6 5/8 Reg Conn. • 9 1/2" OD Fixed Blade Stabilizer w/6 5/8 Reg Conn. • Workstring 3. RIH and position Multi Sting cutter at 15 ft. below mud line elevation ( rkb = 15' + 18.5' rig + 7.3' to mudline (25.8') =40.8'). Commence circulation to extend multi string cutters (8-1/4" knife size). Commence workstring rotation to begin 10-3/4" surface casing cut. a. Observe circulation pressure, torque as string cutters engage casing. 4. Cut 10-3/4" surface casing. Observe pressure drop as Multi String cutters complete cut through 10-3/4" casing wall thickness. (Pressure drop range : 200-400 psi) 5. Continue casing cutting mechanics (hydraulics, rotary) to provide "window' in 10-3/4" surface casing for 16" conductor casing knives assembly. 11 CE CAELU S FnerRy Alaska 6. POOH for "new" set of 8-1/4" casing cutting knives for cutting the 16" conductor casing. 7. Trip in hole with Work -string. Lower cutting assembly carefully thru BOP's. Record pick- up, slack -off and free rotating weights and slack -off weights. Begin Rotation with top -drive and apply pump pressure to open knives and cut the 16"" casing a. Observe pressure differential as deployed casing cutting knives locate into section window created during the surface 10-3/4" casing cutting operation. b. Observe the 8-1/4" Multi String cutter assembly "take weight" as deployed casing cutting knives locate on the bottom of the 10-3/4" section window. 8. Cut 16" conductor casing. A complete cut will be signaled by the cutter as a loss of pressure and an increase in pump strokes and reduction in torque. 9. POOH and L/D 8-1/4" Multi String cutter assembly. 10. N/D Arctic Fox bell nipple/flow line and Shaffer 11" 5M BOPE. 11.N/D FMC Gen. V Well Head to expose the 10-3/4" mandrel hanger/landing ring assembly. 12. Drop slings and shackles through Arctic Fox rotary. Tie onto CT -1 cellar box gusset plates welded to the 16" conductor. PU on cellar box, surface casing & conductor casing assembly. 13. Confirm cellar box, surface casing and conductor casing is free. 14. Complete the RD of the Arctic Fox drilling rig. Move the Arctic Fox off of the CT -1 well location. 15. Mobilize Cruz crane and excavator to CT -1. Use crane and or excavator tie -on to the slings/shackles/pad eyes securing the CT -1 cellar box, 10-3/4 surface and conductor casing. 16. Extract CT -1 cellar box, conductor and surface casing strings. Arrange logistics plan for the transport of the CT -1 cellar box, conductor and surface casing strings back to 2P pad for disposal. In the event that a "Spear" assembly is required. Pick up the following BHA to pull the 10-3/4 X 16" casing stub. Record the pick up and slack off weights. Engage cut casing and pull same free. POOH and lay down casing • 10 3/ "Bowen Casing Spear Packoff w/ 4'/2 IF BxP • Spear Gr. 103/445.5# Min — 9.876 Nom - 10.029 Max — 10.192 • 101/4 " Bowen Casing Spear w/ 4'h BxP • 5' Spear Casing Extension w/ 4'/2 IF BxP • 11-1/2" OD Spear Stop Sub w/ 4'/2 IF BxP • Lubricated Bumper Jar w/ 4'/2 IF BxP • Crossover Sub WS B x 4'/2 IF P • Workstring 12 Annulus Disposal Transmittal Form - CT -1 AOGCC Regulations. 20 AAC 25.080 (b) 1 Designation of the well or wells to receive drilling wastes: CT -1 2 The depth to the base of freshwater aquifers and permafrost, if No Aquifers / Base Permafrost = +/- 934'MD/TVD resent. 3 A stratigraphic description of the interval exposed to the open From the 10-3/4" shoe to the cement top all that is open is annulus and other information sufficient to support a interbedded claystone, siltstone and shale with occasional commission finding that the waste will be confined and will minor non -hydrocarbon bearing sands. not come to the surface or contaminate freshwater. 4 A list of all publicly recorded wells within one-quarter mile There are no other wells or water wells within I mile. and all publicly recorded water wells within one mile of the well to receive drilling waste. 5 Identify the types and maximum volume of waste to be Types of waste may be drilling mud, drilling cuttings, reserve disposed of and the estimated density of the waste slurry. pit fluids, cement -contaminated drilling mud, completion fluids, diesel, formation fluids associated with the act of drilling a well, drill rig wash fluids, domestic waste water, any added water needed to facilitate pumping of drilling mud or drilling cuttings, and any other fluids associated with drilling a well. Densities range from diesel to 12#/gal. Maximum volume to be pumped is 35,000 bbls 6 A description of any waste sought to be determined as drilling Cement rinsate waste under (h)(3) of this section. 7 An estimate of maximum anticipated pressure at the outer Maximum anticipated pressure at the outer casing shoe during casing shoe during annular disposal operations and disposal operations is 2,049 psi. See attached calculation calculations showing how this value was determined. page. 8 Details that show the shoe of the outer casing is set below the See attached: cementing reports, LOT / FIT reports and base of any freshwater aquifer and permafrost, if present, and casing reports. cemented with sufficient cement to provide zone isolation: 9 Details that show the inner and outer casing strings have See attached casing summary sheet and calculation pages. sufficient strength in collapse and burst to withstand antici ated t3ressure of disposal operations: 10 The downhole pressure obtained during a formation integrity See attached LOT/FIT report. test conducted below the outer casing shoe. 11 Identification of the hydrocarbon zones, if any above the N/A depth to which the inner casing is cemented. 12 The duration of the disposal operation, not to exceed 90 days. N/A 13 Whether drilling waste has previously been disposed of in the N/A annular space of the well and, if so, a summary of the dates o the disposal operations, the volumes of waste disposed of, and the wells where the drilling waste was generated. 14 The well(s) where the drilling waste to be disposed of was or CT -1 will be generated. 15 If the operator proposes not to comply with a limitation N/A established in (d) of this section, an explanation of why com liance would be imprudent. 16 Any additional data required by the commission to confirm N/A 1 containment of drilling waste. CT -1 Surface Injection Pressures with gauge at disposal wellhead and using annulus friction of 50 MW (m) Injection Pressure (psi) MW ( )(psi) Injection Pressure MW ( ) Injection Pressure (psi) 6.8 1,212 8.8 951 10.8 690 6.9 19199 8.9 938 10.9 676 7.0 1386 9.0 924 11.0 663 7.1 11172 9.1 911 11.1 650 7.2 15159 9.2 898 11.2 637 7.3 11146 9.3 885 11.3 624 7.4 15133 9.4 872 11.4 611 7.5 15120 9.5 859 11.5 598 7.6 15107 9.6 846 11.6 585 7.7 1,094 9.7 833 11.7 572 7.8 1,081 9.8 820 11.8 559 7.9 1,068 9.9 807 11.9 546 8.0 15055 10.0 794 12.0 533 8.1 19042 10.1 781 12.1 520 8.2 15029 10.2 768 12.2 507 8.3 15016 10.3 755 12.3 494 8.4 11003 10.4 742 12.4 481 8.5 990 10.5 729 12.5 468 8.6 977 10.6 716 12.6 455 8.7 964 10.7 703 12.7 442 Well CT -1 Date 2/15/2016 CASING/TUBING DESCRIPTION ENTER VALUES in the YELLOW CELLS Vim. 1.0-t.'05 Collapse Bursting Size Wt. Grade PSI PSI Surf.1 10.750 45.500 L 80 1 2470.00 5210.00 Next String 1 7.625 29.700 L 80 4790.00 6890.00 Tubingl 3.500 Fluid in Tubing/Casing Annulu Gas Surface Casin TVD2510 ft Drilled Mud Weight 9.8 ppg Pore Pressure @ Shoe 0.447 psi/ft (suggest fresh water gradient) Shoe FIT/LOT 15.7 ppg Annuluar FIT/LOT 15.3 ppg Pburst @ 85% 4,429 Max Injected MW 12 ppg Max Surface Pressure 1,500 psi Distance from Pump to Well 350 ft Diameter of Pump Line 1.75 inches Estimated TOC 4,680 MD ft Estimated TOC 4,546 TVD ft Gas/Fluid Gradient in tubing/casing annulu 0.1 psi/ft Header Pressure (for wells on gas lift) 0 psi Pcollapse @ 85% 4,072 (suggest 0.06 - 0.07 psi/ft) Well CT -1 Date 2/15/2016 Mw Pressure Calculations for Annular Disposal (for submital with Annular Disposal Application) String Assumptions 10.75 in Maximum injection pressure of 1,500 psi Maximum density of the injection fluid is 12.0 ppg _ Pore pressure at the 9 5/8" casing shoe is 0.447 psi/ft Gas/Fluid Gradient in tubing/casing annulus 0.1 psi/ft Header Pressure (for wells on gas lift) 0 psi 2,510 TVD TOC Est. @ 4,680' MD \ 4,546' TVD 3.5 "Tubing 6,650 TVD Pburst85% — PHydrostatic + PApplied " PF 4,429 = ( 2,510 * 0.052 * MW.., MWmax = 31 ppg vmim 1,040-05 + 1500 - ( 0.4472 * 2.510 ) Surface Casing String Size 10.75 in Weight 45.5 ppf Grade L 80 Pburst700% 5,210 psi Pburst85 % 4,429 psi Depth of Shoe 2,510 it FIT/LOT @ Shoe 15.7 ppg or 2,049 psi FIT/LOT for Annulus 15.3 ppg Max Surf. Pressure 1,500 psi Maximum Fluid Density avoid Collapse of 2nd Casing String Pcollapse85% — PHydrostatic + PApplied' PGasGradient - PHeader 4,072 =( 4,546 * 0.052 * MWmax )+ ##### - ( 0.1000 * 4,546 ) - 0 MW... — 12.5 ppg 2nd Casing String Size 7.625 in Weight 29.7 ppf Grade L 80 Pcollapsel00% 4,790 psi Pcollapse85% 4,072 psi Top of Cement 4,546 ft Gas Gradient 0.1 psi/ft Max Surf. Pressure 1,500 psi Header Press 0 psi Pmax allowable = Shoe TVD Depth *.052 * Shoe FTT/LOT Pmax allowable = ( 2,510 * .052 * 15.7 ) Pmax allowable = 2,049 psi This is the value for the Injection Permit "Maximum Anticipated Pressure at Shoe". Schwartz, Guy L (DOA) From: Quick, Michael J (DOA) Sent: Wednesday, February 17, 2016 1:35 PM To: Tom Brassfield; Schwartz, Guy L (DOA) Cc: Walter Quay; Mike Cook; Tulimaniq Drilling; Regg, James B (DOA) Subject: RE: CT -1 (PTD 215-208) P&A Update on surface casing shoe plug Tom — As discussed, your plan forward below is acceptable. Please keep us posted on the forward progress. Michael Quick Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7`h Avenue Anchorage, AK 99501 (907) 793-1231 (phone) (907) 276-7542 (fax) mike.ouick aPalaska.gov 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 Mike Quick at 907-793-1231 or mike.auick@alaska.gov. From: Tom Brassfield [mailto:Tom.Brassfield@caelusenergy.com] Sent: Wednesday, February 17, 2016 11:29 AM To: Schwartz, Guy L (DOA); Quick, Michael ] (DOA) Cc: Walter Quay; Mike Cook; Tulimaniq Drilling Subject: CT -1 (PTD 215-208) P&A Update on surface casing shoe plug Guy, summary of the last 24 hrs +/- and proposed way forward: • Attempted 2ntl 1500 psi pressure test at 1500 hrs +/- (2/16) -no good. • PU EZSV bridge plug and set at 2000'+/- MD. Attempted 1500 psi PT- no good. • POOH and PU RTTS. Set (560' +/- MD) below TAM port collar at 481'+/- MD. • Tested below retainer to 1500 psi- good 30 minute test. • Tested backside -failed. • PU to above port collar at 444'+/- MD- good 10 minute test. Proposed way forward • PU EZSV bridge plug and set below port collar at approx.. 546' +/- MD. • Lay 2 balanced plugs to surface- approx. 300' each. • WOC and tag TOC approx.. 20' to 25' below mudline. • Proceed with cutting 10-3/4" & 16" casings per approved AOGCC procedures. Prepare to move Rig to CT -2. Guy/ Mike, will call to discuss! Thanks, Tom From: Schwartz, Guy L (DOA) [mailto:guv schwartz(&alaska.aov] Sent: Tuesday, February 16, 2016 3:44 PM To: Tom Brassfield; Quick, Michael J (DOA) Cc: Walter Quay; Mike Cook; Tulimaniq Drilling Subject: RE: CT -1 (PTD 215-208) P&A Update on surface casing shoe plug Tom, You proposal as written below is acceptable. If retainer does not hold pressure after WOC then you are authorized to set another plug at 2000 ft and repeat the pressure test to 1500 psi. Regards, 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 on 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 1 or (Cuv schwartz@oloska aov(. From: Tom Brassfield [mailto:Tom Brassfield(&Caeluseneray.com] Sent: Tuesday, February 16, 2016 2:52 PM To: Schwartz, Guy L (DOA); Quick, Michael J (DOA) cc: Walter Quay; Mike Cook; Tulimaniq Drilling Subject: CT -1 P&A Update on surface casing shoe plug Mike/Guy, per our phone conversation regarding the CT -1 P&A: • EZSV was set at approx.. 2476' MD and weight tested. • Squeezed 100 bbls +/- slurry below, unstung and dropped 100' or 10 bbls of slurry on top. • Pulled up hole and attempted to pressure test to 1500 psi +/-. • Pressure held for approx.. 10 minutes and then bled -off to 250 psi and held. Proposed way forward: • Wait on cement to about 5 PM and perform 1500 psi pressure test. • If it holds, come up hole and set surface EZSV and set 200' +/- cement surface plug. • If it does not hold, PU bridge plug and set at 2000' +/- MD. Pressure test to 1500 psi +/-. Proceed ahead with surface cement plug. Thanks, Tom 343-2115 980-5646 cell Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. Statement of Confidentiality: This message may contain information that is privileged or confidential. if you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. THE STATE °fALASKA. GOVERNOR BILL WALKER Walter Quay Senior Staff Drilling Engineer Caelus Energy Alaska Smith Bay, LLC 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503 Re: Exploration Field, Exploration Pool, CT -1 Permit to Drill Number: 215-208 Sundry Number: 316-109 Dear Mr. Quay: Z�5-2a`6 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.claska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. DATED thisq"day of February, 2016. Sincerely, oeri- 7 4- Cathy P. ster Chair RBDMS w FrQ n 9 2016 RECEIVED STATE OF ALASKA FEB 0 S 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 280 20 AAC 25. Abandon 0 Plug Perforations ❑ Fracture stimulate ❑ Repair Well ❑ Operations shutdown ❑ 1. Type of Request: Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 4. Current Well Class: 5. Permit to Drill Number. 2. Operator Name: Caelus Energy Alaska Smith Bay, LLC Exploratory El • Development ❑ 215-208 3. Address: ❑ 6. API Number. Sfra[igraphic ❑ Service 3700 Centerpoint Drive, Suite 500, Anchorage AK 99503 50-879-20021-00 8, Well Name and Number. 7. If perforating: What Regulation or Conservation Order governs well spacing in this pool? Alk CT -1 Will planned perforations require a spacing exception? Yes ❑ No ❑� 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 392275 1 Exploration 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft�' ffective Depth MD: Effective Depth ND: MPSP (psi): Plugs (MDi'. Junk (MD): �O�r (203.71y Casing Length Size MD ND Burst Collapse Structural Conductor 110' 16" 151 ppf X-65 128.5' 128.5' na na Surface 2532.5' 10-3/4" 45.5 ppf L80 2551' 2510' 5210 2470 Intermediate Production Liner Perforation Depth MD (ft): D (ft): Perforatio!PIWellbore Tubing Size: Tubing Grade: Tubing MD (ft): na na na na na Packers and SSSV Type: Packers and SSSV MD (ft) and ND (ft): na na 12. Attachments: Proposal Summary schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑✓ - Stratigraphic ❑ Development ❑ Service ❑ 14. Estimated Date for 2/10/2016 15. Well Status after proposed work: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ Commencing Operations: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Date: 16. Verbal Approval: ❑ Op Shutdown ❑ Abandoned Q Commission Representative: GINJ 17. 1 hereby certify that the foregoing is true and the procedure approved Tom Brassfield herein will not be deviated from without prior written approval. Contact Email tom brassfleldOgaelusenergy corn Printed Name Wal r Ou y 343-2129 Title Senior Staff D Engr 0,2(0-8/2016 Signature Phone ate !�f/ COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity iYl BOP Test ® Mechanical Integrity Test ❑ Location Clearance 5 +�-+�+,-�--- Z�� L Other: T� Post Initial Injection MIT Req'd? Yes ❑ No ❑ Yes No Subsequent Form Required: Spacing Exception Required? ❑ APPROVEDBY Approved by: COMMISSIONER THE COMMISSION Date: Z - — VOL Submit Form and �(� 5 / Form 10-403 ievised 11/20150 R�°@ titAl[ Valid for 12 ��sf�C h Lite of FEB g l�p - Attachments in Duplicate Z�9,1 IM111111. RECEIVED ME CAELUS FEB 0 0 2016 Energy Alaska A0GW Caelus Energy Alaska Smith Bay, LLC 3700 Centerpoint Drive, Anchorage, AK 99503 Tel: (907) 277-2700 Fax: (907) 343-2190 Ms. Cathy Foerster, Chair 02/08/2016 Alaska Oil and Gas Conservation Commission 601 West 5`11 Ave. Suite 505 Anchorage, Alaska. 99501 RE: Plug & Abandonment Sundry for CT -1 CONFIDENTIAL PTD# 215-208 API# 50-879-20021-00 Dear: Ms. Foerster, Caelus Energy Alaska Smith Bay, LLC submits for AOGCC review, a 10-403 Application For Sundry Approval to P&A the CT -1 Smith Bay wellbore. An AOGCC 10-403AD Sundry Approval form will also be submitted to the AOGCC to support the fluids disposal effort before completing the CT -1 P&A. Pertinent information attached to this application includes the following documentation: • 10-403 Sundry Well schematic • P&A procedures • Mud Log to 6645' MD/6518' TVD The following are Caelus Energy Alaska Smith Bay, LLC designated contacts for reporting responsibilities to the Commission: 1) Completion Report Walter Quay (20 AAC 25.070) (907) 343-2129 2) Geologic Data and Logs Paul Daggett (20 AAC 25.071) (907) 343-2134 If you have any questions or require additional information, please contact Walter Quay at (907) 343-2129 (Ofc), (907) 230-3961 (Mob), or Vern Johnson at (907) 343-2111 (Ofc), (907) 575- 9430 (Mob) e-mail: vem.iohnson@caelusenergy.co Sincerely✓� Walter Quay- Senior St ff D ' ing Engineer cc: Michael Hopkinson, Vern Johnson, Mike Cook, Tom Brassfield CT -1 :Well File C�ELLJ'.*4 Energy Alaska ProspeQ Name Tulimaniq Principal Engineer: Water Quay Well Type Exploration/"(� ration Producer Well ClassiNro / CT Drilling Dontractorodq: Doyon Grilling/Arctic Pox Ice oad thickness fft.l: 8.0 ft Zone of Interest /Primry aTorok TIIT Raul, saw. (reference: M: 23.4 ft. Zone of Interest/Secondary Ell..... Plug & Abandonment AFE DRILL EVAL as TE15167 DAYS arm-ba62 Smith Bay , w� nmaa pre em'..pn Lm6 mimaFWa ESD ..a. North Slope, Alaska pews Lops Bm 'no Israel, Cut ii :� I6 inx36&es, CaMxtw W 0e alperM WNI Hase:FMC Ge:.V 11" NONE NONE pemwfrvst 0 0 16'Rltrl {":: _ 4" OepOi (RNM:IIO R. m80 R, ceWw keISO 5X 41'{/-tkb :' a.. Iro IW Spend Mae SGrt� WBnWD/MO :e E35V 0 225 M1b ie BCi 493/PoInnC MW: 9.5 qR rcn Top Gas Hydrate TAM Rated Collor Wsiast -mass spec stab,Rty gene 828 828 0sea R. md/tud Base Pemuhmt 929 929 7 Bow GU XybaW 164E 1638 t TO SGNIiry Eons 15 Do Leas Ismene: PSI ,ma,mY Freaw Proltttian: M,IGR/Res TOC: O MROC: 2066 ft. Mmll 7-5/1rY 10-3/4"(Oleeel) XBAT/xCAL Suirl. cisim, Heel lQ7M. 253VWD/MlOND Em5s: 25M6/ . 103/4'45.50 talft L40 SEC ... V.as Ta6Gmom MP#32426 unw"ca0 TOC 2065ft ESV 024]6 `y' ID:9..SV�Dn W:. 11 D951b; 15.8 Aj0 mm ECCess: 40% 10.3 VOw1 2551 2510 TOP #224]6 13-1/2" Mudla991n9 Immusuiax MUG LykpNTM(LOT): MadOppym: H—huk Tapaet 2861 2811 3% XWBOF 499/PINA 14.00 pp mm,(evpmada MaNxm ExprogDST MW: Se 10,2 IN tL Gasiact-moa sqa (Cee69enry)/CM0. potential BASF#5:35011 )-Ts(-�-kA.Ai.. suMIWt: R[srnnna MIST Op. Xale Antt aeaulas ^�-1r "t flaJJ oriemaOm soMe Injec4un interval d'nPasal ,.:J i. 1 Trak 563 9915 4]]9 Tap P149#4050 FHI/Ds1 Tarok 503 TT Sawm-a-MDT Top Tufimamu Fan 5180 5041 Tulimaa Fan `020 Formation Evaluation Top Cenral 5313 sin Co1N2mu:w: Immary ObjeNa Fees -m- XL-Rmk Top tome 968 5628 TOP #1:5450 core-120 Tamk/Tullm1mq Lae TUYmamq Fm 5950 5810 ROPE:Tmok/Tukmmu Fon VSP Top MR2 2 MWD/LWD: 6-3/sEUMe Gmbe -Cased H0M Laos dr/GR/Re/PWD/Den CCL/GR/4L NeutromporaYly m elm of well test TW LN 6940] 6]00+/- 6-3/O XMT XIcaOQ 2 ] 6-3fr XCAL 6.3/4"MRIL Wad Tend Delab Open Hada 6-3/4"Gamma IDs I (TD) ]000'+/- 1 69]3+- &12'0]000'+- 8-12" Mudla991n9 Panama;Express/DSI Gsrtaa-mass aper Elleamerian Section -Not Drilled pa inclWM- reasonless, ]4]I 7331 pE%/OSI coIW PEUM Ta, 51:ub6k 7621 I40 Oipok Smk MWD/LWD: MSU -ar-XL-Ronk 4-3/4-Tdpe Combe Top lriaMk $161 8021 Dir/GR/Ra/PWD/Den Neutron-pamsh, Top LUWr® 8363 8222 4d1V XBAT VSP 43/4"XCAL Tao NWkph 8521 Sul 43/4" Geotme Boxman 0691 8541 ID 8]81 8641 Max. Wellbore Deviation OpECIUMS, a Pro 1 r wkc— m11 Is Well Total Depth (TD) 8781 ft. and / 8641 ft. had ]orals Surface Location (HAD 27 LEON ZONE 5-masers) X:452075 Y: M38579 Surface Location (Govt. Sect. Line) 2149 FAIL,1724 ML T17N RO9W Sect 17 BHL(NAV 27 MM WNE 5-mws) X:452082 Y: 7858884 BML (Govt Sect. Line) 4132 PSL, 3552 FEL T17H R09W Sect 17 Projection Methal NAD27/ZONES/UTM-mnature Rev 3 CE CAELU S Energy Alaska CT -1 DRAFT Plug & Abandon Conductor & Surface Casing Retrieval 1619x 10-3/4" Caelus Energy Alaska, Smith Bay LLC Exploration Test Well Smith Say, North Slope, Alaska Modirted by TJB 02/08/2016 1 CE CAELU S EnerPy Alaska Well Name: I CT -1 Drill & Evaluate Summary Type of Well: I Exploration Test Well / North Slope Surface Location: 2149' FNL. 1724' FWL. Section 17 T17N R09W UM Target Formation: 4132' FSL. 3552' FEL. Section 17 T17N R09W UM Total Depth 4132' FSL. 3552' FEL. Section 17 T17N R09W UM AFE Number: 1150036 Spud Date: Jan. 19 , 2016 Rig: I Doyon Drilling : Arctic Fox Total Operating days to Drill 67 & Evaluate: MD: 667906 ft TVD: 666506 ft Max Inc: 17. KOP: 1000 KBE-GIL 18.5 PAD -AMS 4.9 ft Well Design conventional, slimhole, etc.: I Directional "S" Profile Objective: Primary: Drill & Evaluate Torok/Tulimaniq Fan (8-1/2" intermediate hole sect.) Secondary : Evaluate Ellesmerian Formation(s) (6-3/4" production hole sect.) Drilling Fluid Program: Surface Hole Section : 13-1/2" Polymer/BDF 499 Density (ppg) Funnel Vis PV YP pH I API Filtrate LG Solids 9.5-9.8 125-70 10-30 30-35 9.0-10 1 <9 <13% Intermediate Hole Section : 8-1/2" Hole Section Opening : 9-7/8" 3% KCL/BDF 499/EZ MUD DP PHPA Density (ppg) PV YP HTHP CI-(mg/I) API Filtrate LG Solids 9.6-10.2 8-20 15-25 NA I <15K 1 <6 1 <6% K CC- CAELU S Energy Alaska Formation Markers: CT- 1 Formation Est. Formation Tops TVDss) Actual MD/TVD (Feet) Prospective Hydrocarbon Bearing Top Gas Hydrate Stability 805' Casing Test Pressure 10-3/4" 45.5# L80 BTC 3000 psi Base of Permafrost 906' Planned BOP Test Pressure Rams test to 250 psi/5,000 psi. BGHS (Base Gas Hydrate Stability) 1615' Casing Test Pressure 3500 psi Nanushuk Topset 2788' Torok SB 3 4756' Top Tulimaniq Fan 5018' Top Central Channel 5150' Top Lobe 3 5605' Base Tulimaniq Fan 5787' Top HRZ 6560' LCU/Kingak 6677' ? Top Sag River 7308' NA Top Shublik 7460' NA Top Ivishak 7998' NA Top Lisburne 8199' NA Top Kekiktuk 8358' NA Top Basement 8518' NA TD 8618' NA Well Control - BOPE Surface Interval : 13-1/2" 21 '/4" x 2M Hydril MSP Annular Preventer Maximum Anticipated BHP 1263 psi (9.6 Ib/gal @ 2530 -ft TVD) Maximum Surface Pressure 985 psi (0.11 psi/ft gas gradient to surface) Casing Test Pressure 10-3/4" 45.5# L80 BTC 3000 psi Planned Drilling Fluid polymer/BDF 499 Intermediate Interval: 11" x 5K Annular BOP. 11" x 5K Double Ram BOP 11" x Initial Wellbore: 8-1/2" Single Ram BOP w/ 2-7/8" x 5" VBR's v Hole Opening : 9-7/8" Maximum Anticipated BHP 3458 -psi (10.0 Ib/gal @ 6650 -ft TVD) Maximum Surface Pressure 2726 psi (0.11 psi/ft gas gradient to surface) Planned BOP Test Pressure Rams test to 250 psi/5,000 psi. Annular test to 250 psi/2,500 psi Casing Test Pressure 3500 psi 7-5/8" 29.7# L80 BTC 3 CE CAELU S FnP[L,, Alaska I Planned Drilling Fluid 13% KCL/BDF 499/EZ MUD DP PHPA I Production Interval: 6-3/4" 11" x 5K Annular BOP 11" x 5K Double Ram BOP 11"x 5K Single Ram BOP w/ 2-7/8" x 5" VBR's Maximum Anticipated BHP 4583 -psi (10.2 Ib/gal @ 8641 ft TVD) Maximum Surface Pressure 3633 psi (0.11 psi/ft gas gradient to surface) Planned BOP Test Pressure Rams: test to 250 psi/5,000 psi. Annular: test to 250 psi/2,500 psi Planned Drilling Fluid 3% KCL/BDF 499/EZ MUD DP PHPA Kick Tolerance/Integrity Testing Kick Tolerance / Integrity Testing Summary Table Exp Casing set / Interval Maximum Influx Mud Weight Pore Min LOT / FIT Volume (bbls) Press Surface : 10-3/4" Diverter 9.5 — 9.8 ppg 1263 12.0 ppg (LOT) 2566/2530 ft. and/tvd Intermediate: 7-5/8" 9.6 — 10.2 ppg 3458 12.5 ppg (FIT) 6790/6650 ft. and/tvd Open Hole : 6-3/4"10.0 — 10.2 ppg 4583 8781/8641 ft. and/tvd NOTE: All LOT / FIT will be taken with a minimum of 20 -ft and a maximum of 50 -ft of new hole drilled outside of the previous casing string 51 CE C4ELU S Energy Alaska CT- #1 — Plug & Abandonment Conductor (16") x Surface Casing (10-3/4") Cut & Retrieve Pre Job Planning • Check all Safety procedures of Doyon Arctic Fox rig operations. • Upon arriving on the Rig Site, Check with the Drilling Foreman or Company Representative to verify Plug & Abandonment and casing cut & pul work scope objectives. • Verify adequate HES cementing P&A blends (sxs) and mix water (bbls) at the appropriate temperature is staged at the CT -1 well site. • Confirm the collection, handling and disposal of cement rinsate and wash-up fluids for each P&A plug. • Check all tools sent in baskets to insure all tools arrived at the CT -1 location. • Measure lengths, OD's and ID's of all P&A and Baker Hughes casing cut & pull equipment • Verify Drill Collars, Heavy Weight Drill Pipe, 5" drill pipe and Weatherford - NOV Grand Prideco 2-7/8",10.4#, HT 2-7/8" PAC work string connections to insure all X -over subs are on location. Weatherford : 2-7/8" Drill Pipe Package Quantity Description 30 2-7/8" 10.4# S-135 D/P 2-7/8" HT PAC approx.: 930 ft. 10 2-7/8 HT PAC D/P LIFT NUBBINS 1 YT ELEVATOR DRESSED 2-7/8" 1 2-7/8" D/P SLIPS 1 XO, NC50 X2-7/8 HT PAC BXP 1 2-7/8" HT PAC MULE SHOE • Ensure that the CT -1 Cellar box annuli/outer shell is being heated with blower air to assist with retrieval. • The AOGCC requires a 48 hour advance notice prior to the commencing of well plugging operations. k,,> v ar>PrM N ' tNo_m6 PreoCEt>,A Le Plug and Abandonment Procedure 1. Pick up and stand back 30 jts of Weathearford 2-7/8" 10.4# S-135 D/P 2-7/8" HT PAC (approx.: 930 ft) , 5" 19.5# S-135 NC -50 drill pipe to reach TD. uz'-e St,rwrp. 2. Ensure the Shaffer 11"X5M BOPE is configured with VBR/pipe rams to seal against below rotary tubular sizes: 5" HWDP/DP. 2-7/8" DP. 5 CE CAELU S Energy Alaska 3. Plan is to pump 4-500' balanced cement plugs from TD back to 5000' +/- MD. Annular fluid disposal will be into open hole from the 10-3/4" shoe to 5000'. The targeted zones are at 2570', 2650', and 2960' MD. MU BHA # PA100: RIH to Plug #1 bottom setting depth at TD or approximately 7000 ft.+/- md. Displace balanced cement plug 49 bbls from 7000 ft. and to 6500 ft. md. POOH to 6500 ft. and or TOC. Halliburton may want to pump a 18.5 +/- bbl spacer in front with 1.5 bbl spacer behind. Circulate bottoms -up and prepare to set plug #2. 4. Repeat plug placement for plugs #2, #3, and #4. 5. Wait on cement (WOC) at 3000' +/- ft. and as directed by Halliburton cementing field supervisor until Plug #4 has developed sufficient compressive strength to allow for a confirmation "tag" of*(o 15 kips. RIH and tag top of Plug#4 at 5000' 5000' +/- MD Note top of cement for Plug #4 on HES Job log. �on;N 1NSPELCO2 -M V�+�TI�ESST�t%. MuS, C%rt(kX%.AlL VJAEIJ-rA&&%NG. 4066,-, tNai✓s c( tvi'1'n e5S Plugs #1, #2, #3, and #4: TD to approx.. 5000' MD Intermediate Open Hole PTA Plug (Intermediate Casing Not Set) Well Input Data Hole Size in 8.5 Bottom of Plug ft 7000,6500,600 5500 PTA Plug Length ft 500/plug Top of Plug ft 6500,6000,5500,5000 % Excess 40% Capacity Output Data Open Hole Capacity Data bbls/If 0.0702 Open Hole Capacity Data w/ Excess bbls/If 0.0983 Spacer & Cement Slurry Input Data Spacer Spacer Type Tuned III Spacer Density 10.5 Mix Water al/bbl 37.56 Spacer Volume bbls 20 Bottom of Spacer ft 6500 Top of Spacer ft 6296 Plug Slurry Cement Slurry Type PTA & Int Blend Downhole Slurry Density 15.80 Downhole Slura Yield cuft/sk 1.15 Mix Water al/sk 4.96 Volume Output Requirements A :))k ) 1 OV- N CC- CAELU S Fnnrnv Alaska Spacer Volume Required bbls 20.0 Total Plug Cement Volume bbls 49.1 Total Plug Cement Volume Required sacks 240.00 Cement Mix Water Volume Required bbls 28.3 Spacer Mix Water Requirement bbls 17.9 Wash -Up Volume bbls 50 Total Water Volume per Job bbis 97.0 C11= NOTE: Final P&A procedures need to be approved by the AOGCC as well as the Sundry for fluids disposal into the Nanushuk interval from 2960' to 2980' MD. Once TOC has been confirmed at 5000' +/- pull BHA # PA100 to 3000' +/- or across the bottom injection zone, close the annular or pipe rams and prepare to pump down the backside i.e. "annular disposal". Guiders for disposal are: • Perform open hole LOT procedure similar to the surface casing shoe L procedure. See attachment. • Attempt to keep su a pressure plus fluid density below the 1 . ppg EMW (LOT) at the surface casing shoe. Ca lated maximum anticipated pre re at shoe is 2049 psi. It may be necessary to exceed this pre ure to establish injectio nto the zones. • Notify Anchorage of the results beforeesiartinOuids disposal. • Once a rate is established flush the ckside 200 bbls +/- water and begin annular disposal of fluids. o Surface pressure pl he hydrostatic weight of t disposal fluid should not exceed the 2049 psi. o Monitor de y of the fluids being pumped downhole. Adj rates and pressures o K5015 record of volumes, fluid densities, and surface pump pressur for AOGCC eporting AWNu_AR ��twsR� tiNo� SEPAtfn.Y Svr+OJt4 POOH hole with BHA # PA100. Stand back 30 jts of Weathearford 2-7/8" 10.4# S-135 D/P 2-7/8" HT PAC (approx.: 930 ft.). 7 CE CAELU S Enerey Alaska 7. PU Halliburton 10-3/4" 45.5# EZSV and RIH on 5" 19.5#/ft S135 NC50 DP to setting depth at 2476 ft. and (75ft. above 10-3/4" surface casing shoe @ 2551 ft. md). Set EZSV at 2476 ft. md. ✓ 8. Displace Plug #5 below EZSV at 2476 ft. md. Calculated cement volume is to 3500' MD. ✓ +�• too bbl czne. -r ca,WCs-C Plug #5: Surface Casing - 10-3/4" 45.5# L80 BTC (below shoe) Surface Casing/Intermediate Open Hole PTA Plug Intermediate Casing Not Set Well Input Data Hole Size in 8.5 Hole Size in 9.875 Surface Casing ID in 9.95 Bottom of Plug ft 3500 PTA Plug Length in 8.5" Hole Section ft 929 PTA Plug Length in 9.875" Hole Section ft 20 PTA Plug Length in 10.75" Casing ft 75 Depth of EZSV ft 2476 Top of Plug ft 2476 % Excess 40% Capacity Output Data Open Hole Capacity Data - 8.5" bbls/If 0.0702 Open Hole Capacity Data - 8.5" w/ Excess bbls/If 0.0983 Open Hole Capacity Data - 9.875" bbls/If 0.0947 Open Hole Capacity Data - 9.875" w/ Excess bbls/If 0.1326 Surface Casing Capacity Data bbls/If 0.0962 Spacer & Cement Slurry Input Data Spacer Spacer Type Tuned III Spacer Density 10.5 Mix Water al/bbl 37.56 Spacer Volume bbls 20 Plug Slurry Cement Slurry Type PTA & Int Blend Downhole Slurry Density 15.80 Downhole Slurry Yield cuft/sk 1.15 Mix Water al/sk 4.96 Volume Output Requirements 0 oV- CE CAELU S EnerRv Alaska Spacer Volume Required bbls 20.0 Total Plug Cement Volume bbls 101.1 Total Plug Cement Volume Required sacks 494.00 Cement Mix Water Volume Required bbls 58.3 Spacer Mix Water Requirement bbls 17.9 Wash -Up Volume bbls 50 Total Water Volume per Job bbls 127.0 i v 9. Release from EZSV at 2476 w/5" 19.5#/ft S135 NC50 DP. Displace Plug #6 (100 ft.) on top of EZSV. POOH to 2200'+/ -MD. Pressure test cement plug #6 to 1500 psig. POOH. Plug #6: Surface Casing - 10-3/4" 45.5# L80 BTC (top EZSV) Suface Casing Plug Intermediate Casing Not Set Well Input Data Surface Casing ID in 9.95 Bottom of Plug ft 2476 PTA Plug Length in 11.75" Casing ft 100 Top of Plug ft 2376 % Excess 0% Capacity Output Data Surface Casing Capacity Data bbls/If 0.0962 Surface Casing Capacity Data w/ Excessbbls/If 0.0962 Spacer & Cement Slurry Input Data Spacer Spacer Ta Water Spacer Density 8.33 Spacer Volume bbls 20 Plug Slurry Cement Slurry Type PTA & Int Blend Downhole Slurry Density 15.80 Downhole Slurry Yield cuftlsk 1.15 Mix Water al/sk 4.96 Volume Output Requirements Spacer Volume Required bbls 20.0 Total Plug Cement Volume bbls 9.6 Total Plu Cement Volume Re uired sacks 47.00 Cement Mix Water Volume Re ired bbls 5.6 E v M CE CAELU S Enerev Alaska Spacer Mix Water Requirement bbls 20.0 Wash -Up Volume bbls 50 Total Water Volume per Job bbls 76.0 10. PU Halliburton 10-3/4" 45.5# EZSV converted to bridge plug. RIH and set a 225 ft. and (rkb). Release from EZSV at 225 ft. and and displace cement Plug #7 from 225 and rkb to mud line elevation at 26.5' (18.5' Rig + 8' of ice) rkb/md/tvd. Ideally would like to displace cement to 25' below mudline so a drill out would not be required. Pick up 4" wash tool and circulate down to 51.5' RKB. IAG -VOL FOM SNeFp�ck P�Ub P2w2 to CAS%aG CUTOFF, Plug #7: Surface Casing - 10-314" 45.5# L80 BTC Nor FY kNSPevmm W tTIJESS k ACS ? C.ASt1JG Suface Casing Plug Intermediate Casing Not Set Well Input Data Surface Casing ID in 9.95 Bottom of Plug ft 200 PTA Plug Length in 11.75" Casing ft 200 Top of Plug ft 0 Excess ° Capacity Output Data Surface Casing Capacity Data bbls/If 0.0962 Surface Casing Capacity Data wl Excess bbls/If 0.0962 Cement Slurry Input Data Plug Slurry Cement Slurry Type Perm C Downhole Slugy Density 15.60 Downhole Slurry Yield cuft/sk 0.96 Mix Water al/sk 3.81 Volume Output Requirements Total Plug Cement Volume bbls 19.2 Total Plug Cement Volume Required sacks 113.00 Cement Mix Water Volume Required bbls 10.3 Wash -Up Volume bbls 50 Total Water Volume per Job bbls 61.0 10 Cir LiFg:-. J MW ✓ 01r% 11 CC- CAELU S nnr v Alaska if requird RIH with 9-7/8" GX-CIX mill tooth bit„DC,HWDP. Drill top 25 +/- ft. of 200ft Permafrost "C” cement plug or ( rkb = 25' + 18.5' rig +8' to mud line (26.5') =51.5') Procedure: CT -1 10 % & 16 casing cut & retreive Mechanical: Casing data: 16"151# @ 110' This has a.938 Wall Thickness ( Cemented ) 10-3/4" 45.5# L-80 BTC @ 2,551 MD' (10'/4 x 16" are cemented) Two sets of Multi String cutter blades (knife size: 8-1/4") to initially cut the 10'/ surface casing. Trip to change blades, and then cut the 16 " conductor casing will be required. Work string: 5" 19.5# X 4-1/2 IF Drill Pipe for the bigger size casing strings Objective Step #1 : Cut the 10-3/4" surface casing @ 15' below mud line Step #2: Cut the 16" conductor casing @ 15' below mud line Step #3 : Retrieve 16" conductor casing, 10-3/4" surface casing & CT -1 cellar box 1. PU mill tooth 9-7/8" GX-C1X mill tooth bit/HWDP. Drill, dress off top 20 ft. of 200 ft. Permafrost "C" cement plug if required. 2. To cut the 10 3/ " casing pick up the following assembly: 8 1/4" OD Multi -String Cutter w/MM Knives w/ 6 5/8 Reg Conn. 9 1/2" OD Fixed Blade Stabilizer w/6 5/8 Reg Conn. Workstring 3. RIH and position Multi Sting cutter at 15 ft. below mud line elevation ( rkb = 15' + 18.5' rig + 8' to mudline (265) =415). Commence circulation to extend multi string cutters (8-1/4" knife size). Commence workstring rotation to begin 10-3/4" surface casing cut. a. Observe circulation pressure, torque as string cutters engage casing. 4. Cut 10-3/4" surface casing. Observe pressure drop as Multi String cutters complete cut through 10-3/4" casing wall thickness. (Pressure drop range : 200-400 psi) 5. Continue casing cutting mechanics (hydraulics, rotary) to provide "window" in 10-3/4" surface casing for 16" conductor casing knives assembly. 6. POOH for "new" set of 8-1/4" casing cutting knives for cutting the 16" conductor casing. 11 CE CAELU S Enemy Alaska 7. Trip in hole with Work -string. Lower cutting assembly carefully thru BOP's. Record pick- up, slack -off and free rotating weights and slack -off weights. Begin Rotation with top -drive and apply pump pressure to open knives and cut the 16"" casing a. Observe pressure differential as deployed casing cutting knives locate into section window created during the surface 10-3/4" casing cutting operation. b. Observe the 8-1/4" Multi String cutter assembly "take weight" as deployed casing cutting knives locate on the bottom of the 10-3/4" section window. 8. Cut 16" conductor casing. A complete cut will be signaled by the cutter as a loss of pressure and an increase in pump strokes and reduction in torque. 9. POOH and L/D 8-1/4" Multi String cutter assembly. 10. N/D Arctic Fox bell nipple/flow line and Shaffer 11" 5M BOPE. 11. N/D FMC Gen. V Well Head to expose the 10-3/4" mandrel hanger/landing ring assembly. 12. Drop slings and shackles through Arctic Fox rotary. Tie onto CT -1 cellar box gusset plates welded to the 16" conductor. PU on cellar box, surface casing & conductor casing assembly. 13. Confirm cellar box, surface casing and conductor casing is free. 14.Complete the RD of the Arctic Fox drilling rig. Move the Arctic Fox off of the CT -1 well location. ator tie -on to 15.Mslings/shackles/padieyee Cruz crane s securriiingtthe or tCT--1 cellar Use crane surface and vcondu for casing. stics an for 16. Exract oflthe llCTb1 cellar box, conductor and surface rcas ng Arrange alck to 21 t P pad for disposal. NOTE: Strap cut casing strings and note on morning report. Take pictures for AOGCC summary Sundry. Sug.,T sMpv. o< e ��`S'O` : Pv* cr. TO A`�GC�' In the event that a "Spear" assembly is required. Pick up the following BHA to pull the 10-3/4 X 16" casing stub. Record the pick up and slack off weights. Engage cut casing and pull same free. POOH and lay down casing • 10 % " Bowen Casing Spear Packoff w/ 4'/2 IF BxP • Spear Gr. 10'/ 45.5# Min — 9.876 Nom - 10.029 Max — 10.192 10 3/4 " Bowen Casing Spear w/ 4'/z BxP 5' Spear Casing Extension w/ 4'/2 IF BxP 11-1/2" OD Spear Stop Sub w/ 4'/2 IF BxP Lubricated Bumper Jar w/ 4'/2 IF BxP Crossover Sub WS B x 4'/2 IF P Workstring 12 215 Z©'� Regg, James B (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, February 03, 2016 2:01 PM To: Walter Quay Cc: Regg, James B (DOA); Quick, Michael J (DOA); Vern Johnson; Tulimaniq Drilling Subject: RE: 215-208 Caelus CT -1 BOP Test Walter, You have approval to extend BOP testing until BHA is out of well. If there are further delays in POOH w/ BHA past tomorrow notify the commission. As we discussed let AOGCC know your immediate plans for the well as soon as possible. We will need a sundry application for Annular disposal operations or P &A activities. You might also forward the latest OH logs to Patricia so we can start looking at them before the weekend. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may Contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guv schwartz@aloska.aov). From: Walter Quay(mailto:Walter.OuavCobcaelusenergy.com) Sent: Wednesday, February 03, 2016 12:09 PM To: Schwartz, Guy L (DOA) Cc: Regg, James B (DOA); Quick, Michael J (DOA); Vern Johnson; Tulimaniq Drilling Subject: 215-208 Caelus CT -1 BOP Test Guy, As per our conversation, we were on schedule to be out of the hole and testing the BOP today. Caelus Drilling Supervisor, Jack Keener sent in the Notification Request on Monday, February 1't, expecting the test to start today. See the attached e-mail of this and the response from Louis Grimaldi. As per the email, Jack and Louis talked last night, with Louis verbally waving witness of the upcoming BOP Test. We have had a couple of delays. We had a washout in the drillpipe delaying us 4 hours and -18 hours of time spent running the GeoTap IDS downhole pressure and sampling tool in this exploration well. The present forecast has the BOP test starting tomorrow midday. We request an extension of the BOP test and will proceed with the BOP test as soon as we are out of the hole. Walter Quay Senior Staff Drilling Engineer Caelus Energy Alaska, LLC 3700 Centerpoint Dr, Ste 500, Anchorage, AK 99503 Direct (907) 343-2129 1 Cell (907)230-3961 wa Iter.guav@CaelusEnerey.com Schwartz, Guy L (DOA) From: Walter Quay <Walter.Quay@caelusenergy.com> Sent: Friday, January 29, 2016 3:45 PM To: Schwartz, Guy L (DOA) Cc: Vern Johnson; Tom Brassfield Subject: 215-208 Caelus CT -1 Jan 23-29 Caelus Energy Alaska Smith Bay, LLC Well CT -1 AOGCC Weekly Report Permit to Drill # 215-208 API# 50-879-20021-00 SHL: 3129' FNL, 3556' FEL, Sec. 17, T37N, R9W, LIM Project status ending week of: 01/29/2016 • Made wiper trip back to TD, circulated and condition mud, POOH and LD BHA. • Ran 10-3/4" 45.5 ppf L-80 casing to 2551' MD/2510' TVD, C&C mud. • RU and run the stab -in cementing string, cemented the 10-3/4" surface casing with 258 bbls of 10.7 ppg lead slurry followed by 48.4 bbl of 15.8 bbis tail slurry. Bumped plug, floats held with approx. 115 bbls of slurry back to surface, no losses during the job. • ND Diverter system, NU FMC wellhead and BOP stack. • Tested BOP stack per approved PTD- test witnessed by AOGCC inspector. • PU 9-7/8" clean-out BHA, RIH to FC, C&C mud, tested casing to 3000 psi- good test. Finish drilling shoe track and 20' of new hole to 2584'MD/2541' TVD. • C&C mud, RU and performed LOT to 15.7 ppg EMW. • POOH with clean-out BHA, PU 8-1/2" rotary steerable drilling assy with MWD/LWD tools. RIH. Current activity- drilling ahead at 2615' +/- MD. Walter Quay Senior Staff Drilling Engineer Caelus Energy Alaska, LLC 3700 Centerpoint Dr, Ste 500, Anchorage, AK 99503 Direct (907) 343-2129 1 Cell (907)230-3961 wafter quay@CaelusEnergy.com Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. CASING AND LEAK -OFF FRACTURE TESTS Well Name. Csg Size/Wt/Grade: Date: 1/28�/ZO_ 1� 10.75 L80 45.5 Csg Setting Depth: Supervisor: Keener/Ross 2S48 _ TMD --- Mud Weight: z�TVD 9 5 PP9 LOT= Leakoff pressure = 820 15.71 ppg Psi Pumped- Fluid PuHole Depth = 1.3 — Bbls 2585� and Volume Back = Estimated Pum ----- 1 , bbls PUMP Output: 0.100 Barrels/Stroke CASING TEST DATA Enter Strokes Hern Enter pressure LEAK -OFF DATA Enter Strokes Here Enter Pressure l tLFAKAFf DATA tCASING TEST DATA 1000 1900 1800 3700 3800 3500 3400 3300 3200 3100 3000 2900 2800 2700 2600 -- 2500 2400 2300 2200 2100 2000 1900 1800 —-- 1700 - 1600 1500 1400 1300 1200 1100 1000 -- 900 800 700 600 500 400 300 — 200 — 100 0 25 3 10 15 20 Time (Minutes) Schwartz Guy L (DOA) From: Walter Quay <Walter.Quay@caelusenergy.com> Sent: Friday, January 22, 2016 11:35 AM To: Schwartz, Guy L (DOA) Cc: Tom Brassfield; Vern Johnson Subject: 215-208 Caelus CT -1 Jan 15-22 Caelus Energy Alaska Smith Bay, LLC Well CT -1 AOGCC Weekly Report Permit to Drill # 215-208 API# 50-879-20021-00 SHL: 3129' FNL, 3556' FEL, Sec. 17, T17N, R9W, UM Project status ending week of 1/22/2016 • Finished construction of the CT -1 ice island on 01/06/16 to a freeboard depth of approx. 5.5'. Total ice thickness to mudline ranging from 7' to 7.5'. • Drilled 24" conductor hole to 62', hit water, RU hammer drill and drove 16" 151 ppf conductor to 110'. • Cemented upper 24" x 16" conductor with 43.3 bbls of slurry. Set cellar box. • Finish installing FMC landing ring on 01/11/16. • RU Arctic Fox from 01/11/2016 to 01/19/16. • Performed diverter function test on 01/18/16- witnessed by AOGCC rep. • Spud CT -1 at 2030 hrs 01/19/16. • Drilled 13-1/2" hole to surface casing TD of 2564'MD/2522' TVD Current activity- making wiper trip and prep to run and cement 10-3/4" surface casing. Walter Quay Senior Staff Drilling Engineer Caelus Energy Alaska, LLC 3700 Centerpoint Dr, Ste 500, Anchorage, AK 99503 Direct (907) 343-2129 1 Cell (907)230-3961 walter.quav(@CaelusEnergy.com Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. THE STATE GOVERNOR BILL WALKER Mike Hopkinson Senior Vice President Caelus Energy Alaska Smith Bay, LLC 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503 Alaska Coil and Gas Conservation Commission Re: Exploration Field, Exploration Pool, CT -I Caelus Energy Alaska Smith Bay, LLC Permit No: 215-208 Surface Location: 2149' FNL, 1724' FWL, SEC. 17, R9W, UM Bottomhole Location: 4132' FSL, 3552' FEL, SEC. 17, T17N, R9W, UM Dear Mr. Hopkinson: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Pax: 907.276.7542 Www. oogcc.aloska. gov Enclosed is the approved application for permit to drill the above referenced exploration well. All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. 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 approvals 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. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the AOGCC's internal use. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P Foerster Chair JL DATED this 22 day of December, 2015. e2% STATE OF ALASKA ALI A OIL AND GAS CONSERVATION COMM )N PERMIT TO DRILL 2n AGc 7a nn, RECEIVED DEC 0 2 2015 la. Type of Work: 11b. Proposed Well Class: Exploratory -Gas ❑ Service- WAG ❑ Service -Disp1a ❑ Specify well is p fy � if proposed for: Drill 21 ° Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj ❑ Single Zone Coalbed Gas ❑ Gas Hydrates ❑ ReddN ❑ Reentry ❑ Exploratory- Oil Q • Development - Gas ❑ Service- Supply ❑ Multiple Zone Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket O . Sngle Well ❑ 11. Well Name and Number: Caelus Energy Alaska Smith Bay, LLC Bond No. SUR0025190 , CT -1 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3700 Centerpoint Drive, Suite 500, Anchorage, AK 99503 MD: 8781 TVD: 8641 Exploration - 4a. Location of Well (Govemmental Section): 7. Property Designation (Lease Number): Surface: 2149' FNL 1724' FWL Sec 17 T17N. R09W. UM. • ADL 392275 ✓ Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 4132' FSL 3552' FEL Sec 17 T17N. R09W. UM. LAS29943 2/1/2016 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4132' FSL 3552' FEL Sec 17 T17N. R09W. UM. 1536. 0.4 miles 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): • 23 feet 15. Distance to Nearest Well Open Surface: x-463002 y-6152707 Zme- 5 C1 Elevation above MSL (ft): • 4.5 feet to Same Pool: N/A 16. Deviated wells: Kickoff depth: 1000 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 17.5 degrees Downhole: 4624 Surface: 3665 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 24" 16" 84# X-56 Welded 80 22 22 102 102 Auger (24" Hole Diam.)/368 sm. 15.6 ppg 13-1/2" 10-3/4" 45.5# L-80 BTC 2546 20 20 2566 2530 Lead: 415 sm 10.9 ppg Tail: 264 sm 15.8 ppg ? 9-7/8" 7-5/8" 29.7# L-80 BTC 6772 18.5 18.5 6790 6650 1st site: 215 an 15.8 ppg 2nd stage: 400 sm 15.8 ppg -1/ _ - _ - __-. 1,710 4, 1:, S -o 47 i 81, v r 19. PRESENT WELL CONDITION SUMMARY (To be completed for Reddll and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Property Plat Q BOP Sketch Drilling Program Q Time v. Depth Plot Q Shallow Hazard Analysis0 Diverter Sketch Seabed Report Q Drilling Fluid Program ❑� 20 AAC 25.050 requirements0 21. Verbal Approval: Commission Representative: Date 2 -Dec -15 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be Mike Cook (907) 343-2135 deviated from without prior written approval. Contact mi ke.cook(d), Gael use n era v. com Email Printed Name Michael Hopkinson Title Senior Vice President /I Signature Phone (907) 646-9315 Date 2 -Dec -15 Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: 5- 50- $ -aQQa - - Date: p� 15 requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coal methane, gas hydrates, a gas contained in s les: Other: .. �D0 a yrs i SOP T�5I- Samples req'd: Yes Nlo ❑ Mud log req'd: V NOD (" / 'C HzS measures: Yes [� M1❑/ Directional svy req'd: Yes No❑ - -7 IF �SP C e..nSpacing exception req'd: Yes ElM11� Inclination -only svy req'd: YesO �/.t /LVVV Post initialinjection MIT req'd: Yes❑ No❑ .cX6a 111 'S'Tr� / 6�/,✓tiQiv5 £ U� (�J�iZ) cc-cr Cll APPROVED ✓�(/r/�--� BY Submit in Donn and Approve" 1 -qo1 w� V201� Thls ermit is vol I ( ) p of ap@UM1IAB)Qd. OS(g)) �),¢i� errts in Du licate ��¢ /z -Lr rs v I N 1 v 1 i •I 1` 7'KA Iiqlujjz) �/�y C AE LU Energy Alaska Caelus Energy Alaska Smith Bay, LLC 3700 Centerpoint Drive, Anchorage, AK 99503 Tel: (907) 277-2700 Fax: (907) 343-2190 Ms. Cathy Foerster, Chair RECEIVED Alaska Oil and Gas Conservation Commission 601 West 5`h Ave. Suite 505 DEC 0 2 2015 Anchorage, Alaska. 99501 AOGCC RE: Application for Permit to Drill: CT -1 Dear: Ms. Foerster, Caelus Energy Alaska Smith Bay, LLC submits for AOGCC review, the requisite Permit to Drill (Form: 10-401) in support of the CT -1 exploration test well to be drilled and evaluated, near - shore in Smith Bay, Alaska (ADL 392275), in the upcoming winter exploration season of 2015- 2016. Pre -positioning of CT -1 program critical loads via barging from West Dock to Point Lonely was completed in September 2015. The pre -positioned inventory includes : drill rig, camp(s) infrastructure, well construction tangible & intangible products, service company equipment and ice road, ice island building equipment. A snow trail pre -packing campaign is currently ongoing with approved tundra travel equipment to establish a logistics supply route from Pt. Lonely to Lake 654 — a distance of approximately 23 miles. The assembly of camps, fuel storage containment & tankage will be followed by the construction of an ice runway and the CT -1 ice pad (500 ft. diameter) to be positioned approximately 0.4 miles from the shore line of Smith Bay. Concurrently, a snow trail will be pre - packed (140 miles) originating from Drillsite 2P in Kuparuk to Lake 654 with an anticipated completion date of mid-January 2016. Caelus Energy Alaska Smith Bay, LLC will utilize the Doyon Drilling Arctic Fox drill rig to drill and evaluate the CT -1 exploration test well. The estimated spud date is February 1", 2016. The well geologic objectives are to obtain L/MWD and E -line logging information through the Torok formation — the primary zone of interest, while drilling the intermediate 9-7/8" hole section. Formation evaluation contingencies such as obtaining cores and flow testing the Torok formation could potentially be performed should reservoir properties merit and sufficient operating days remain. As a geologic secondary objective, the CT -1 wellbore is planned to be deepened after running and cementing intermediate 7-5/8" casing at the base of the LCU. A 6-3/4" production hole section will be drilled to evaluate potential Ellesmerian stratagraphic units. UIC Class lI fluids generated from CT -1 well construction activities are intended to be disposed of via annular injection or open hole displacement prior to the plug and abandonment of the CT - 1 wellbore.'An AOGCC 10-403 Sundry Approval form will be submitted to the AOGCC to support the fluids disposal effort. CT -I Exploration Test Well AOGCC - Permit to Drill i Page 2 of 2 At the end of the 2016 exploration drilling season, the rig and associated equipment will be de- mobilized back to Deadhorse, AK. Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following documentation: 1) Form 10-401 Application for Permit to Drill 2) Tulimaniq I Proposed Wellbore Diagram 3) Drilling Time vs. Depth Plot 4) A survey plat showing the surface location of the well 5) Proposed Drilling Program and Geological Prognosis 6) Seismic and Offset Well Shallow Hazards Analyses ** 7) Drilling Area Risks Discussion 8) Casing Cementing Design 9) Casing Properties and Design Factors 10) Fracture and Temperature Gradient Curves 11) Diagrams and Descriptions of the BOP Equipment to be Used 12) Summary Directional Program Fugro GeoConsulting, Inc. has completed their Shallow Hazards Assessment for the CT -I well. A copy of the Final version of the shallow hazards and pore pressure assessment will be made available to the AOGCC upon receipt from Fugro GeoConsulting,Inc. Caelus Natural Resources Alaska, LLC does not anticipate the presence of H2S in the formations to be encountered in this well. However, H2S monitoring equipment will be functioning on the rig at all times during drilling and completion operations. The following are Caelus Natural Resources Alaska, LLC designated contacts for reporting responsibilities to the Commission: 1) Completion Report Walter Quay (20 AAC 25.070) (907) 343-2129 2) Geologic Data and Logs Paul Daggett (20 AAC 25.071) (907) 343-2134 If you have any questions or require additional information, please contact Walter Quay at (907) 343-2129 (Ofc), (907) 230-3961 (Mob), or Vern Johnson at (907) 343-2111 (Ofc), (907) 575- 9430 (Mob) e-mail: vem johnson@caeluseneryg com Since Attachments : AOGCC Form 1041 Permit Information per 20 AAC 25.005 (a) and (c) cc: Michael Hopkinson, Walter Quay, Vern Johnson, Mike Cook, Tom Brassfreld CT -1 : Well File C/�ELLJ'� Energy Alaska Principal Engineer: Walter Quay Tulimanig prospect Name Tulima Drilling Cantrector/Rig: Doyon Drilling/Arctic Fox ationpand Well Type Well Classification Producer C T � Ridd.( efthicknv n(Rca :MSL)23. R. Interdict /Primary Torok Zone of Intere 1 ME DRILL, EVAL. & TEST 57 DAYS Zoneof Interest/Secondary Ellecanerian Wor"AhM Smith Bay ,q,pgDx (.Sp,°9FF6 ....'elrd MFD °w`wD mvD Wince ...mXWFNea r04,.lrOX North Slope, Alaska MD '> i lain Mlbfix-% 67206Wen Head : WC Gen, v It- 24 OmIM1 (RKM:IWR CM'OUROr to Ed Wooed W 805K NONE NONE PttmMmet 0 0 ft. hewn re ead elm. SpW Had: 3NW:%5-10 999/PoNmc ,06:9.5-100 fl MUGbgTng: IW 100 SbKOl00 RTWIMD Cda Top Gas Hydrate 0500"`ean ®SOORand/lvd Saudi may spec Shelter IDm 828 828 aaw Permah°rt 929 929 Bow Gm"rM 1642 1638 Sbkill" bene Lead Lemont Pemiarrun Ft.. Protroth) : TOC: o,BOC: 2065 ft. Annuli ] 5/8"z 100.3/4' (need) vir/GR/Ru/%BAT Cednen 2330' cemfty: OGS AN, a 10-3/4" 45.50 ba ft L-80 M race ... t: lard Ya N: V. Pd ounce,Zm W TOC: 20668 Dreal a'.ortm:9n5' M: Asdee:MMe 15.8 IN Exca:40% vb 10-314' Casing 2565 2530 13-1 2" Intermedlab HAA 3% KC48DF 499/PHPA NW: 9.6 Lyk N Tut . (expected) 19.06 a'g Wuiv. (apcted) Mudbgging MudbDwnp: Nanuvhuk Tepeat 2861 2811 -1 r 10.2 pp9 Platform ExPrw/0SI ' \D MI rte l GUFact-mw spec (Cnxiden potential Annularanne oa M:Rtuanna,ht cr Open intar.al Eads «rens<IDn sDnx GOiddl mOc°tonleld le ands R. 114 68en0 Torok 58 3 4915 9719 W t Od:15.8 Mg ss . S Rment EtteC% . FMI/D51 m F°rma°on EvalmDon SatuMDT Saturn—MUTTOP Too TuNmanq Fan 5180 5041 Cantlnomq: Carnal $313 5173 - o Can-II0'Tnro4/Tulimnnq Fri., OMecGw ,SCT-°ry%l-0.wk To P Lobe3 57M 5628 ROPE: Torok/TWimanio Fm aselim BTuana Fan 5950 5810 2M. Stage - o Top HRZ 6723 6583 MWD/LWD:6-3/V s4aW Hole Lngc ES Cent. diaR tukq: Ed. Stage: Triple cambe D/665n'TOO TCC: 590 OLM/6100 EMD DOIGR/Ru/FWD/Oaro CCL/GR/CBL to"Fer" Denser: 1518 IN n."Ex.-ParuRy n exntafeall tat 11;n— e:r"Wo Con. U. 5E% 6-3/4-XIAT Let 5d3e mry 63/4"XCAL VSp on. 675'. 6-3/4"AFR at eaten TO . 6d/4'Geobp5D5 ]-5/a'Cuin9 6]90 6650 prndudbn MW'. 3% Foundation lnte9nry Tu[ Muell"ging rep LOU 6MO 6700 KCLODF 499/NPA MW: 10.0- 14 WIN Nue'_(tou'Oed) PNtbm Expmfl DSl l. 10.2 IIN Giulia. -muvpec 4 Orn caliperIncluded- T. Sm RWs 7471 7331 AMER collar Tap SM1Wlik 762I 7983 cape Sonic MWW1.W0: 4-3/4' Anal -0a, XL-Ract Triple talnbn Top lvubek 8161 8023 DD/GR/Raa7PWD/Dem exzz N.O. -PamRy ' rm lYhmna 8363 4-3/4"XIAT 4-3/4" %CAL V ToO Rek46d 8521 8381 Ba.ema,t FEEL 8541 6 TD 8701 8641 ax. We re U"—. tion Dr ne 5 P I s9au. Well Total Depth (TD) 8781 R and / 8641 R. tvd sea uxi-m�s.ex. M.x. Surface Location(MAD n 11714 ZONE s-metre)%: 452075 Y:7858S19 Surface Location (Govt. Seel. Line) 2149 FNL, 1724 MLT17N R09W Sect. 17 wmmanm . ce ee- BottomHole Location(NnD 27 u1M ZONE S. ANN: 452082 0906 BotteLocation (Govt Sect Line) F543552 FEL]TI]8N Sect 1] Nm AD27/Z0NE 5, MM Rion Projection Method R., 2 CE CAELU S 3nern,y Alaska 0 10 0 Install 16" Conductor, 1000 Commission Camp Arctic Fox - Drilling. Rig 2000 3000 4000 E V 5000 6000 R RU -Cement 7-5/8" Int. CsR. 7000 P 8000 9000 10000 Caelus Energy Alaska CT -1 Exploration Test - Smith Bay, Alaska 20 30 40 �/ � •e�ei� n .. ne _LI w/ L -M W D RU E -Line - Run FE Logs P&A Prod. Hole Section so Z9 NOTES 1. SECTION UNE AND LOCATION DATA PER BLM—ALASKA. N _ 2. VICINITY MAP SHORELINE LOCATION AND APRO% DISTANCE TO SHORELINE DERIVED FROM GOGGLE EARTH, 2013 IMAGERY. GRAPHIC SCALE 0 1000 2000 4000 LEGEND (IN FEET ) ® CONDUCTOR SURFACE LOCATON 1 inch - 2000ft. JT17'N R4W > (� CT -1 ( y I a �V y I I i VICINITY MAP I' 2 M', _ES 7 8 i 9 SMITH BAY T- --. -- APPROXIMATE SHORE LINE PROPOSED j' CT -1 18 17 16 LOCATED WTHIN PROTRACTED SECTION 17, T. 17 N., R. 9 W., UMIAT MERIDIAN, ALASKA WELL NAD27 I GEODETIC NAD27 GEODETIC SECTION NO. ZONE 5 -US FT I ZONE 5 -METERS INAD27 POStTION(DMS) POST TION(D.DD) OFFSETS Y=6,152,707.05 N=7,858,579.36 70'49'41.48230" 70.828189529' 2,149' FNL CT -1 IX= 463.001.98 E=452,075.43 154'78'27.24814" 154.307568927' 1,724' FWL L,Y�L! L V J G,E[xEP. AAM CT -1 D, R: fRB15 DFRIIIS M 00 01—PROPOSED WELL LOCATION SH.Cx- b®�� -§ LOCATED WITHIN PROTRACTED T a t 1' - z000' SECTION 17, T17N, R9W, U.M. CE CAt: LU S Energy Alaska CT -1 Caelus Energy Alaska, Smith Bay LLC Exploration Test Well Smith Bay, North Slope, Alaska Drill & Test: 54 days. Drilling Rig: Doyon Arctic Fox Proposed Spud Date: February 1st, 2016 Surface Location: 2149' FNL. 1724' FWL. Sec 17. T17N. R09W. UM. Caelus Energy Alaska Smith Bay, LLC Sr. Drilling Engineer Prepared by: Caelus Energy Alaska Smith Bay, LLC Drilling Superintendent Reviewed by: 1 Caelus Energy Alaska Smith Bay, LLC VP Operations Approved by: Caelus Energy Alaska Smith Bay, LLC VP Exploration Approved by: CE CAELU S Energy Alaska Well Name: CT -1 Drill & Evaluate Summary Twe of Well: I Exploration Test Well / North Slope Surface Location: 2149' FNL. 1724' FWL. Section 17 T17N R09W UM Target Formation: 4132' FSL. 3552' FEL. Section 17 T17N R09W UM Total Depth 4132' FSL. 3552' FEL. Section 17 T17N R09W UM AFE Number: NENS-TU 08-13 Estimated Spud Feb 1st, 2016 Date: Rig: Doyon Drillin : Arctic Fox Total Operating days to Drill 57 & Evaluate: MD: 867811 TVD: 866K11 ft Max Inc: 17 KOP: 1000 PAD -AMS 4.5 ftft Well Design conventional, slimhole, etc.: I Directional "S" Profile Objective: Primary: Drill & Evaluate Torok/Tulimaniq Fan (9-7/8" intermediate hole sect.) Secondary: Evaluate Ellesmerian Formations 6-3/4" production hole sect. nrillinn Fli irl Proaram: 13-112 in Surface Hole Fluid Properties: 3% KCL/Polymer/BDF 499 Density(ppg) Funnel Vis PV YP pH API Filtrate LG Solids 9.5-10.0 /1 125 -70 1 10-30 1 30-35 9.0 — 10 <9 <13% 9-7/8 in Intermediate Hole Fluid Properties: 3% KCL/BDF 499/EZ MUD DP PHPA Density (ppg) PV YP HTHP CI-(mg/I) API Filtrate LG Solids 9.6-10.2 8-20 15-25 1 NA <15K <6 <6% 6-3/4 in Production Hole Fluid Properties: 3% KCL/BDF 499/EZ MUD DP PHPA Density (ppg) PV MP HTHP Cl-(mg/1) API Filtrate LG Solids 10.0 —10.2 8-20 1 15-25 1 NA <15K <6 <6% 2 CE CAELU S Energy Alaska Waste Disposal: RCRA Exempt - Class II Wastes Drilling Fluids: Option #1: Store on site (BSS Tank Farm). Annular inject: 10-3/4" x 7-5/8" annuli or open hole displacement. Option #2: Transport to an approved G & I facility for disposal. Drill Cuttings disposal: Option #1: Freeze on site. Transport to an approved G & I facility for disposal. Waste Disposal: RCRA Exempt - Class I Wastes Option #1: Transport to BP's Pad 3 facility at Prudhoe Bay or beneficial re -use, where possible. Casing/Tubing Program Hole Size Csg / Tbg O.D. Wt/Ft Grade Conn Length Top MD / TVDrkb Bottom MD / TVDrkb 24 in 16 in 84# L-80 Welded 80 ft 22 ft/22 ft 102 ft /102 ft 13-1/2 in 10-3/4 in 45.5# L-80 BTC 2,546 ft 20 ft / 20 ft 2,566/2,530 ft 9 -7/8 -in 7-5/8in 29.7# L-80 BTC 6772 ft 18.5 ft/ 18.5 ft 6790/6650 ft Tail Class 'G'. Density: 15.8 ppg. Yield: 1.15 cu ft/sk. (10-3/4' Mix Water: 5.0 gal/sk. -- shoe to 500 ft. above Volume to be pumped = C64-sxs//54 bbls cement II-rO ram: 7-5/8" 29.7 ppf L-80 BTC Casing Size: 10-3/4" 45.5 ppf L-80 BTC / 5" dp Inner String/ TAM collar @ 500 Basis for ft. and/tvd Type: Surface Casing to 2,566/2,530 ft MD/TVD Basis for - 80 ft shoe track Calculation: - 250% OH excess used in permafrost to --960' and 40% OH excess below permafrost. Cement Volume. - Cement must return to surface Cement Volume: Spacer 10 bbls water (to test lines) + 50 bbls Tuned Spacer III at 10.5 ppg Lead Permafrost "U. Density: 10.9 ppg. Yield: 4.15 cu ft/sk. (Surface to Mix Water: 19.25 gal/sk. 2066 ft. md) Volume to be pumped = 15 s/306 bbls. Tail Class 'G'. Density: 15.8 ppg. Yield: 1.15 cu ft/sk. (10-3/4' Mix Water: 5.0 gal/sk. -- shoe to 500 ft. above Volume to be pumped = C64-sxs//54 bbls shoe depth 2566 ft. BHST -70 deg F at 2530 feet TVD (off set well data - Aklaq #6) Casing Size: 7-5/8" 29.7 ppf L-80 BTC Type: Intermediate Casing: 6790/6650 ft MD/TVD BKB Basis for 2 Stage through ES Cementer positionedat -6100' ( 150 ft. and below Calculation: Base Tulimaniq Fan). 80 ft shoe track. Estimate 50% excess in open hole. / Top of cement (TOC) to be at 4680 ft MD BKB - 500 ft above ✓ estimated top of the Torok Tulimaniq Fan. Cement Volume. Spacer 110 bbls water test lines). 40 bbls - Tuned Spacer III at 3 CE CAELU S Enerev Alaska Cement Volume: Spacer 10 bbls water (test lines). 40 bbls — Tuned Spacer III at Stage 1. • Mudlogging 10.5 ppg. • L/MWD Slurry HALCEM. Density: 15.8 ppg. Yield: 1.15 cu sk. (6790 ft.(to Water: 5.0 gal/sk. TOC at —6100' md. = ES cementer 9-7/8" —6100 ft.) 7-5/8" shoe position = 150 ft. below base Tulimaniq Fan. • Mud Logging: GasFact/mass spec: 2,566/2530 ft MD/TVD — to Volume to be pumped: 21 s/44 bbls • L/MWD ES cementer • E -Line Cement Volume: Spacer 40 bbls — Tuned Spacer III at 10.5 ppg Stage 2. o FMI/DSI/ Saturn or MDT o MSCT or XL -Rock Slurry HALCEM. Density: 15.8 ppg. Yield: 1.1cu ft/sk. assn h . to Mix Water: 5.0 gal/sk. Volume from 61 00'to 4680'- 1420 Interval: 6790/6650 ft MD/TVD — 8781/8641 ft MD/TVD ES cementer linear ft of coverage. to 500 ft. Volume to be pumped: 400 sxs/82 bbls 8781/8641 ft MD/TVD above T. • LWD: Directional/GR/PWD/Res/Density/Neutron Porosity • E -Line Fan. o E -Line: PEX/DSI/Dipole Sonic/MSCT or XL -Rock Tem —150 de F @ 7000 feet TVD offset well data — Akla #6 Evaluation Program Surface Hole: 13-1/2" Interval: 100 ft MD/TVD — 2,566/2530 ft MD/TVD • Mudlogging: GasFact/mass spec: 100 ft-2,566/2530ft. MD/TVD • Mudlogging . LWD: Directional/GR/Res • L/MWD • E -Line Intermediate Hole : Interval: 2,566/2530 ft MD/TVD — 6790/6650 ft MD/TVD 9-7/8" • Mud Logging: GasFact/mass spec: 2,566/2530 ft MD/TVD — • Mudlogging 6790/6650 ft MD/TVD • L/MWD • LWD: Directional/GR/PWD/Res/Density/Neutron Porosity • E -Line o XBAT/XCAL/AFR/GEO-TAP IDS • E -Line: PEX/DSI-RTScanner o FMI/DSI/ Saturn or MDT o MSCT or XL -Rock o Well Test = CCL/GR/CBL o VSP at section TD Production Hole: Interval: 6790/6650 ft MD/TVD — 8781/8641 ft MD/TVD 6-3/4" • Mud Logging: GasFact/mass spec: 6790/6650 ft MD/TVD — • Mudlogging 8781/8641 ft MD/TVD • L/MWD • LWD: Directional/GR/PWD/Res/Density/Neutron Porosity • E -Line o XBAT/XCAL o E -Line: PEX/DSI/Dipole Sonic/MSCT or XL -Rock o VSP N CE CAELU S Energy Ataska Recommended Bit Program BHA Hole Size Depth (MD) Bit Type Nozzle #100 13-1/2" 0 to 2566 HTC: MXC-1 -Tooth Bit 3-15 & BGHS (Base Gas Hydrate Stability) IADC Code -1-1-7 1-10 #200 9-7/8" 2,566 ft to +/-6,790 ft Security : Fixed Cutter TBD Torok SB 3 4756' +/-100' (IADC Code: M323 Top Tulimaniq Fan #300 6-3/4" 6,790 ft to 8,781 ft Hycalog : Fixed Cutter TBD +/-100' Yes Top Lobe 3 (IADC Code: TBE)) +/-100' Formation Markers: CT- 1 Formation Est. Formation Tops TVDss Uncertainty Feet Prospective Hydrocarbon Bearing Top Gas Hydrate Stability 805' No Base of Permafrost 906' BGHS (Base Gas Hydrate Stability) 1615' +/-100' No Nanushuk Topset 2788' +/-100' No Torok SB 3 4756' +/-100' Yes Top Tulimaniq Fan 5018' +/-100' Yes Top Central Channel 5150' +/-100' Yes Top Lobe 3 5605' +/-100' Yes Base Tulimaniq Fan 5787' +/-100' Yes Top HRZ 6560' +/-100' Yes LCU 6677' NA Yes Top Sag River 7308' +/-100' Yes Top Shublik 7460' +/-100' Yes Top Ivishak 7998' +/-100' Yes Top Lisburne 8199' +/-100' Yes Top Kekiktuk 8358' +/-100' Yes Top Basement 8518' +/-100' No TD 8718' NA No 5 CC- CQELU S Energy Alaska Well Control - BOPE Surface Interval : 13-112" 21 '/" x 2M Hydril MSP Annular Preventer Maximum Anticipated BHP 1263 psi (9.6 Ib/gal @ 2530 -ft TVD) Maximum Surface Pressure 985 psi 0.11 psi/ft gas gradient to surface) Casing Test Pressure 10-3/4" 45.5# L80 BTC 3000 psi Planned Drilling Fluid 3% KCL/Polymer/BDF 499 Intermediate Interval: 9-7/8" 11" x 5K Annular BOP. 11" x 5K Double Ram BOP 11" x Maximum Anticipated BHP Single Ram BOP w/ 2-7/8" x 5" VBR's Maximum Anticipated BHP 3458 -psi (10.0 Ib/gal @ 6650 -ft TVD) Maximum Surface Pressure 2726 psi (0.11 psi/ft gas gradient to surface) Planned BOP Test Pressure Rams test to 250 psi/5,000 psi. Min LOT / FIT Annular test to 250 psi/2,500 psi Casing Test Pressure 3700 psi '� wu 4,1(- 4) 35a 7-5/8" 29.7# L80 BTC Planned Drilling Fluid 3% KCL/BDF 499/EZ MUD DP /_-7-> Production Interval: 6-314" 11" x 5K Annular BOP 11" x 5K Double Ram BOP 11" x 5K Single Ram BOP w/ 2-7/8" x 5" VBR's Maximum Anticipated BHP 4583 -psi (10.2 Ib/gal @ 8641 ft TVD) Maximum Surface Pressure 3633 psi (0.11 psi/ft gas gradient to surface) Planned BOP Test Pressure Rams: test to 250 psi/5,000 psi. Annular: test to 250 psi/2,500 psi Planned Drilling Fluid 3% KCL/BDF 499/EZ MUD DP PHPA Kirk Tnlerance/Intearity Testina Kick Tolerance / Integrity Testing Summary Table Exp Casing set / Interval Maximum Influx Volume (bbls) Mud Weight Pore Min LOT / FIT Press Surface: 10-3./4" @ 2566/25301263 Diverter 9.5 — 10.00 ppg 12.0 ppg (LOT) ft. and/tvd Intermediate: 7-5/8" @ 44 9.6 — 10.2 ppg 3458 12.5 ppg (FIT) 6790/6650 ft. and/tvd Open Hole: 6-3/4" @ 8781/8641 64 10.0 — 10.2 ppg 4583 ft. and/tvd NOTE: All LOT / FIT will be taken with a minimum of 20 -ft and a maximum of 50 -ft of new hole drilled outside of the previous casing string n CAt: LU S Energy Alaska CT #1 - Summary Well Plan : Drill, Evaluate & Test 1. Pre -install 16" 84# X-56 ERW conductor to approximately 80' below pad elevation and a 6.5' deep cellar designed to keep cellar fluids from thawing the ice island by circulating cold air around it. Move in rig and rig up over conductor. 2. Notify thQ AOG C WAhin 48 hou[5 Df intent to perform diverter function test and drills and commence drilling operations. 3. Diverter riser assembly should be made to length according to diverter space out schematic. Ensure that the 13-1/2" bit and the fluted 10-3/4" mandrel hanger will pass through the drilling riser and bell nipple. 4. Conduct specific tour safety meetings with each crew on the potential of gas hydrates or shallow gas and the handling of same. Stress the importance of adhering to required minimum mud weight versus depth as the surface hole is drilled. 5. Pick up and stand back 2,000' of 5" 19.5# S-135 NC -50 drill pipe and 500' of 5" HWDP. 4" DP will be used for the final 6-3/4" production hole section. 6. Ensure that pipe rams are available for the following pipe sizes: 7-5/8" casing, 5" DP/liner, 4-1/2" tubing, 4-1/2" tubing, 2-7/8" tubing and 4" drill pipe. 7. Install a 21 '/4" x 2000 psi annular diverter with 16" diverter line. Function test diverter and valve to verify correct sequence of operation and record on IADC drilling report. Fill diverter & riser with V2 water to check for leaks. Send completed Diverter Test form to AOGCC as specified on the form. Q jHold a diverter drill prior to drilling surface hole. RU 4" gate valves and Cam lock fittings on the tZ conductor for cement returns and to use for access with top job pipe if this becomes necessary. he ace is 8. A conventional spud mudwith 900'initial TVD/MD (estimated ed base permud weight, lmafrost) and be used on theld at that hweight hor will increase to 10.0 ppg y - , higher, until hole section TD. 9. PU 13-1/2" bit, spud and drill surface hole with DP/HWDP down to approx. 300' with reduced drilling parameters. 10. POH and MU BHA #100 including MWD/LWD tools. Shallow test the BHA below the rotary table. Log and survey the hole already drilled. RIH. 11. Gradually increase drilling parameters once all the BHA is below the conductor shoe. Do not allow the hole deviation to exceed 5 degrees from vertical. 12. Drill 13-1/2" hole vertically to KOP at 1000 ft. tvd/md. as per the directional plan and mud plan to interval TD and/tvd. Controlling ROP may be necessary to prevent packing off, lost circulation or flow over the top of the bell nipple. Be alert at all times for the possibility of encountering shallow gas and react per diverter procedure. 7 C. CAELU S Energy Ataska 13. Actual 13-1/2" surface hole sectionTD will be based on ROP, MWD and mud logging data so as to place the shoe in minimum 50' shale section, if possible. The well site Geologist will assist in picking casing point. 14. Make short trips as required, circulate and condition mud and POH. Download LWD data and, if possible, rack back BHA #100. Move efficiently toward running surface 10-3/4" 45.5# L-80 BTC casing, as hole conditions can deteriorate with time. The surface hole BHA #100 can be laid down after cementing 10-3/4" casing. 15. Rig up casing running equipment and top drive mounted Volant casing running tool. 16. Rijn 10-3/4" 45.5# L-80 BTC casing, with float shoe and Davis Lynch inner string type float collar, monitoring returns and filling casing with Volant tool. A TAM collar will be installed in the 10-3/4" casing at +/-500' to be used in case a second stage cement job is required. 17. RIH with stab -in tool on 5" drillpipe and cement 10-3/4" casing to surface as per plan, using the inner string oc through 5" drillpipe. Notify AOGCC if cement does not reach surface. Perform second stage cementing through the TAM collar, if there are no primary lstage cement returns to surface. f" 18. If cement returns come to surface as planned, on the primary cement job, POH with stab -in sub while LD 5" DP. Start cleaning pits to accept new3% KCL/BDF 499/EZ MUD DID. Leave one pit with spud mud for drilling out the shoe track. 19. Nipple down the 21 '/4" 2M diverter. 20. Make up and install FMC 11" x 5M multi -bowl wellhead and 11" x 5M BOP stack. 21. PU singles of 5" 19.5# S-135 NC -50 DP to reach intermediate TD at —7170/7030 and/tvd . If not previously done, LD the surface hole BHA. 22. Notify AOGCC a minimum of 48 hours prior to testing BOPE. Test BOPE to 250 psi low and 5 000 _ psi high except annular preventer to be tested to 250/2,5944zsj. (See Permit to Drill for reference). IV Note: BOP tests are required every 7 days on exploration drilling projects. Each low and high V1 pressure test to be held for a minimum of 5 minutes. 23. MU BHA# 200: 8-1/2" rotary steerable (Geo -Pilot 7600 EDL) directional BHA with LWD tools (Dir/DGR/EW R/Density/Neutron Porosity) and shallow test tools. A Well Commander circulating sub will be run in the BHA in the event of lost circulation. Spud mud will be used to drill out the shoe track. Test casing to 3000 psi for 30 minutes, making sure to chart the test. Drill shoe track to 10' above the shoe. 24. Switch out to intermediate 3% KCL/BDF 499/EZ MUD DP per mud program. 25. Drill out shoe track, clean out rat hole and drill 20' of new hole. yD I�0- 26. Perform LOT. Record the results on the Morning Report and in the IADC report. Note: Acceptable LOT is 12.0 ppq or higher.. It is recommended that the cement unit or rig test pump be used to perform the LOT for better control of pump rate. Send in LOT results to Anchorage office for flk forwarding to the AOGCC for reference in upcoming annular disposal operations. \z 10 CAELU S Energy Alaska 27. Drill 8-1/2" hole per Sperry directional plan (CT -1 wp06) with BHA #200 (rotary steerable) assembly to 7-5/8 29.7# L-80 BTC casing point at 6790/6650 ft. and/tvd. 28. Control penetration rates and circulate for samples as required, according to Caelus Energy Alaska mud logging requirements. The well site geologist will be responsible for formation top picks in consultation with Anchorage based personnel. 29. Circulate and condition mud and POH w/ BHA#200 for open hole logs. 30. RU & Perform open hole E -line logging as follows: - Run #1: PEX/DSI, Tri -axial Resistivity, CMR Plus. - Run #2: Spectral Gamma Ray, Sonic Scanner, FMI. - Run #3: MDT (single probe + Saturn probe) MDT -IFA for fluid analysis (DP conveyed). - Run #4: 1-1/2" x 3" Rotary side wall cores. - Run #5: VSP 31. MU BHA#300 - RIH with 9-7/8" hole opener assembly. Open 8-1/2" intermediate hole section from surface casing shoe depth (2566 ft. and ) to intermediate hole section TD @ 6790 ft. md. POOH while L/D 5" 19.50 S-135 NC -50 DP. 32. Prepare to run 7-5/8" 29.7 L-80 BTC casing. Change top rams to 7-5/8" casing rams, install a 7- 5/8" test joint and test the rams to 30 3 5, 00 psi. RU casing running equipment including Volant tool. �ot� 33. Run 7-5/8" 29.7# L-80 BTC casing and cement per HES cementing program (2 stages). Stage 1: through the float shoe with (215 sxs) 15.8 ppg HALCEM Premium cement. Stage 2: through an ES cementer at 6100' with (400 sxs) 15.8 ppg HALCEM Premium cement, to bring cement to 500' above the top Torok Tulimaniq Fan. TOC to be approx 4680'MD. 34. Install the 7-5/8" pack -off in the wellhead and test to 5000 psi. 35. Rig up and test the BOPE to 250 psi/5000 psi, except annular to 250/2500 psi. Notify AOGCC inspector (659-3607) at leastrs ahead of test. W. 37 38. q b [w> Install bowl protector. Establish an injection rate and pump into 7-5/8" x 10-3/4" annulus. Pump approx 50 bbls mud to ensure the annulus is open. Notify the Anchorage drilling superintendent if the annulus will not take fluid. Do not exceed 3800 psi (80% of 7-5/8" casing collapse), if attempting to pressure up and clear the annulus. After cement has fully cured, step rate injectivity tests will be performed down the 10-3/4" x 7-5/8" annulus and recorded to verify the well can be used for annular disposal of drilling mud. Prepare to use the annulus for subsequent annular disposal operations. 39. PU BHA #400: 6-3/4" drilling assembly including a Well Commander circulating sub for lost circulation and 4" DP to reach the final hole TD at +/- 8781/8641' MD/TVD. RIH. Clean out 7-5/8" casing to -5' above float collar, leaving 80' shoe track intact. 0 CAELU S Energy Alaska 40. Close the upper pipe rams and test the casing to 4000 psi for 30 minutes and record the test on a chart. 41. Drill shoe track to 20' above the casing shoe. Condition existing 3% KCL/BDF 499/EZ MUD DP PHPA mud from intermediate hole and adjust weight to 10 ppg. Drill out the shoe track and 20' new hole. Perform FIT looking for 12.5 ppa EMW as a minimum. Note: Density of drilling fluid will be adjusted up as needed for pore pressure control and for hole stability. MW is expected to be —10.2 ppg by the end of the hole section. 42. Drill the 6-3/4" (BHA#400) hole section to a total depth of +/- 8781/8641 ft. and/tvd as defined by geologists at the rig site and in Anchorage. The well will penetrate basement to provide sufficient rat hole for logging purposes (+/-100 feet). Perform wiper trip to 7-5/8" shoe, if needed. 43. POH and stand back BHA #400. 44. RU and perform open hole E -line logging as follows: - Run #1: PEX/DSI/4 arm caliper KJ - Run #2: MSCT-or-XL-Rock - Run #3: VSP (to be determined) 45. After E -line work is complete The open hole section will be abandoned as follows: Set a cement retainer on DP, 100' inside the 7-5/8" casing shoe and downsqueeze sufficient cement volume equivalent to the open hole volume from TD up to the retainer. Lay a 50' cement plug on to of the retainer. hh� 46. Well Testing: Torok Scope I�vd The primary Torok testing objective is to obtain representative formation fluid samples from the prospective interval if fluid samples are not acquired during drilling (Geotap IDS) or wireline / operations (modular dynamic tester). Due to time and operational restrictions extended production testing is not planned. The test will be performed in cemented 7-5/8" casing with 4-1/2" tubing including a packer with Tubing Conveyed Perforating Guns (TCP) using extreme overbalanced with nitrogen to provide stimulation to create micro fractures for improved inflow from the anticipated laminated reservoir. Perforating guns will be dropped to provide a clear path for production from the perforations and to enable deployment of downhole fluid sampling tools. The well will be produced to a three-phase separator to clean-up phase and to capture produced oil, water and gas samples from the separator and downhole. Gas will be flared and liquids will be stored in a tank farm on the drilling island. Post testing, all produced fluids will be either pumped back into the formation or trucked off site before the well bore is abandoned." 47. NotifyAOGCC of intent to abandon well at least 24 hours in advance. A detailed procedure will be issued by the Caelus Energy Alaska Anchorage office following consultation with the AOGCC. 10 C CAELUS Energ%x Alaska Offset Well Operational Summaries Summary of findinas There was little evidence of gas in any of the surface holes examined. Drew Pt #1, drilled in 1978, reported 120 units of gas at a depth of 2008' TVD/MD with a MW of 9.5 ppg. The MW was increased to 9.8 ppg. No other influxes in surface holes were reported. Mud weights in surface holes varied from 8.9 to 10.3 ppg. One well (South Simpson Test Well #1 drilled in 1977), experienced trouble in cementing 13 3/8" casing to surface primarily due to lost circulation encountered when drilling the surface hole starting at 950' TVD/MD. Surface hole casing setting depths varied from —1,430' TVD/MD (Puviaq #1 drilled in 2003) to —2670' ft MD/TVD (East Simpson Test Well #1 drilled in 1979). The typical surface casing setting depth for all the offsets studied was around 2650' TVD/MD. South Simpson #1 experienced lost circulation in the 13'/2" hole section at 5279', 5965' in the Torok and at 7020' TVD/MD in the Kingak. No apparent hole problems or well control issues were caused by these events. East Simpson Test Well #1 drilled in 1979, reported lost circulation at 5699' and 6270' TVD/MD in the Torok. East Simpson Test Well #2, drilled in 1980, recorded a gas spike of 280 units at 5764' MD, in the Torok. This well also reported the well flowing after POH with a core barrel from 7197' TVD/MD at the base of the Ivishak/Top Lisburne formations. MW was raised from 9.3 to 9.8 ppg and no further problems were noted. Aklaa #6 (207-009) drilled by FEX in 2007 to a depth of 7280' MD/7235' TVD. - 16" conductor set at 80' BGL - 12-1/4" hole drilled to 21 01'with 10.0-10.3 ppg mud weights - 9-5/8" set at 2072' and cemented with 136 bbls lead slurry and 41 bbls tail slurry. No mention in reports of cement to surface. - Drill 8-1/2" hole to 7280' with 9.6-10.0 ppg mud weights - 7" casing stuck off bottom with shoe at —7045'. Cemented with 23 bbls 15.8 ppg Class G slurry. Followed by second stage with 60 bbls cement pumped and displaced with significant losses. - There were no apparent problems drilling the 12-1/4" surface hole to 2101' MD. Upon drill out below the surface shoe, a 16 ppg FIT was obtained. Losses were experienced starting at 6490' and increasing to 170 bbls/hr by 6529'. Total losses of 728 bbls were reported. The loss zone appeared to be the base of the Torok formation. - Total losses were experienced in the 8-1/2" hole at 6532' with a core barrel in the hole, again in the Torok. Additional losses occurred at 7153' in the Kugrua formation. Some tight hole and sloughing were reported from 7300' to 6573'. This appeared to be happening in the Torok and HRZ. Aklaq #2 (205-180) drilled by FEX in 2006 - Experienced partial lost circulation in the 12-1/4" surface hole in the Nanushuk at 2312' TVD/MD. - 16" conductor set at 115' BGL - 12-1/4" hole drilled to 2435' with 9.3 ppg mud weight - 9-5/8" casing set at 2418' and cemented with 203 bbl Permafrost lead and 41 bbls Class G tail. 80 bbls cement returns to surface. - Drill 8-1/2" hole to 7585' with 9.4-10.7 ppg mud weights - 7" casing shoe at 7565' cemented with 45.5 bbls 15.8 ppg Class G lead and second stage with 45 bbls 15.8 ppg premium Class G slurry. Severe losses during second stage. -An FIT of 16 ppg was obtained after drilling out the 9-5/8" shoe at 2418' TVD/MD. -When drilling 8-1/2" hole at 6480'-6670' MD the well was "breathing" a volume of 90 barrels in the Torok formation. -There were significant lost circulation and stuck pipe events further down the hole in the Miluveach and Kugrua formations but these formations will not be present at the Tulimaniq location. Puviaq #1 (202-248) drilled by ConocoPhillips in 2003 to a depth of 7900 ft TVD/MD. -20" conductor set at 82' BGL. -16" hole drilled to 1430' TVD/MD with mud weight of 10.1 ppg. -13-3/8" casing set at 1423' TVD/MD and cemented with 149 bbls lead and 49 bbls tail slurry with cement returns to surface but volume inconclusive. FIT to 16.0 ppg. -12-1/4" hole drilled to 3175' TVD/MD with mud weight of 9.6-9.9 ppg with 170 units of gas reported after short trip at TD. -9-5/8" casing set at 3167' TVD/MD and cemented with 45 bbls 15.8 ppg Class G cement Note: The above casing design was run to facilitate annular disposal early in the well. FIT to 16.2 ppg EMW. -8'/z' hole drilled and cored to 7900' TVD/MD with mud weight of 9.5-9.7 ppg. Run logs. -7" casing set at 7891' TVD/MD and cemented with 92 bbls 15.8 ppg Class G cement. -The well was then completed with 3'/z" tubing. East Simpson Test Well #2 (100-203) drilled by Husky Oil in 1980 to a depth of 7505'. -20" conductor set at -75' BGL. -12'/4" pilot hole drilled with 9.4-9.9 ppg mud weight to 2650' TVD/MD. Hole opened up to 17'/2" with 9.8-10.3 ppg MW. -13-3/8" casing set at 2635' TVD/MD and cemented with 2742 sx 15.6 ppg cement. Got back 50 bbls cement to surface. 12.0 ppg FIT after drilling out. -12'/4" hole drilled and cored to 6450' TVD/MD with one gas show of 280 units at 5764' (Torok) with a 9.9 ppq MW. -9-5/8" casing set at 6427' and cemented with 206 bbls Class G cement. 12.0 ppg FIT after drilling out. -8 %" hole drilled & cored to 7197' with 9.3 ppg mud. Observed flow when RIH with DST tools after POH with core bbl. Increase MW to 9.8 ppq. Re -run DST tools and perform test over the interval 7152'-7197' TVD/MD. This yielded a FSP of 3752 psi at 7176' TVD/MD. (10.05 ppg pore pressure). -Drill and core to TD at 7505' TVD/MD with MW of 9.8-10.0 ppg. East Simpson Test Well #1 (100-201) drilled by Husky Oil in 1979 to 7739'. -20" conductor set at —70' BGL. -17'/2' hole drilled to 2670' TVD/MD with 9.5-10.1 ppg mud weight. -13-3/8" casing set at 2661' TVD/MD and cemented with 528 bbls 14.5-15.1 ppg cement. Full returns and got 14.5 ppg cement to surface but no volume mentioned. -12.0 ppg FIT after drill out. -12'/" hole drilled and cored to 7186' TVD/MD with lost circulation reported at 5699' and 6270' MD/TVD (Torok). Mud weight 10.8 to 10.4 ppg. -Ran logs and side wall cores. Lost 70 bbls mud on check trip before POH for casing with 10.7 ppq MW. -9-5/8" casing set at 7167' TVD/MD and cemented with 1000 sx Class G cement at 15.6 to 16 ppg. 11.9 ppg FIT after drilling out. -8 Y2' hole drilled and cored to 7739' TVD/MD with mud weight of 10.5-10.6 ppg. -Ran OH logs and sidewall cores. Drew Point #1 (100-198) was drilled by Husky Oil in 1978 to 7946 ft TVD/MD. -20" Conductor set at 80' BGL. -17-1/2" hole drilled to 2668' TVD/MD with 8.9-10.2 ppg mud weight. 120 units of gas was reported at —2000' with a 9.5 ppg mud weight. This was subsequently increased to 9.8 ppg and no further gas was reported. Ran OH logs. -13-3/8" casing set at 2661' TVD/MD. Cemented with 3800 sx Arcticset cement at 15.0 ppg. Got back 14.5 ppg cement to surface with no returned cement volume mentioned. Drilled out and conducted FIT to 11.1 ppg EMW. -12-1/4" hole drilled and cored to 5922' TVD/MD. Ran DST over the interval 5850'-5922' TVD/MD in the Torok. This yielded a FSIP of 2226 psi and only a slight blow, with no fluids found in the sample chamber (7.3 ppg pore pressure). Drilling continued to a TD of 6895' TVD/MD and logs were run. -9-5/8" casing set at 6834' TVD/MD and finally squeeze cemented through the shoe with 200 sx Class G cement, after a failed primary cement job. CBL log run after squeezing the shoe confirmed good cement. FIT to 11.35 ppg was performed after drilling out. -8'/2' hole drilled and cored to a TD of 7946' TVD/MD. Ran a second DST over the interval 7472-7572' TVD/MD in the Shublik yielding a FSP of 3796 psi (9.8 ppg pore pressure) and a third DST over the interval 7765'-7821' TVD/MD in the Ivishak yielding a FSP of 3891 psi (9.64 ppg pore pressure). Neither DST recovered any hydrocarbons. OH logs were run and the well was abandoned. South Simpson Test Well #10 00-197) drilled by Husky in 1977 to a depth of 8795' TVD/MD. -30" conductor set at —80' BGL. -17-1/2" hole drilled to 510' TVD/MD and opened up to 26" with mud weight of 8.4-10.2 ppg- -20" casing set at 495' TVD/MD and cemented with 1200 sx of slurry at 15.0-15.2 ppg with cement returns to surface but volume inconclusive. -18-1/2" hole drilled to 2215' TVD/MD with mud weight of 9.1-10.2 ppg. The well lost circulation at 950' and 1280' TVD/MD and again after drilling to TD at 2215' TVD/MD. Various LCM pills were spotted and the losses were reduced considerably but the well still took 4 bbls of fluid when E line logging the hole section. -16" casing set at 2125' TVD/MD and cemented with 2000 sx 15.2 ppg Arcticset II cement. Lost returns during the last 250 sx pumped Performed top lob through 1" pipe down to a depth of 360' and pumped 300 sx Arcticset II but no mention of cement returns to surface were made. -13-1/2" hole drilled to TD of 7209' TVD/MD with lost circulation occurring at 5279' TVD/MD (Torok) with 10.3 ppq mud weight (lost 220 bbls, spotted LCM pill and got back 150 bbls mud when drilling ahead). Lost circulation occurred again at 5965' TVD/MD (Torok) with a 10.3 ppq mud weight (lost 439 bbls mud and spotted LCM pill to regain circulation). A third lost circulation event occurred at 7020' TVD/MD (Kingak) with a 10.6 ppq mud weight (lost 50 bbls mud and spotted LCM pill to regain circulation). At TD, open hole logs were run. -10 %" casing set at 7125' TVD/MD and cemented with 1000 sx Class G cement (no cement weight recorded but noted full returns during cement job. FIT to 11.9 ppg. -8-1/2" hole drilled and cored to TD at 8795' TVD/MD with mud weight of 10.2-10.5 ppg. This hole section penetrated the Sag R, Shublik, Ivishak and Endicott formations and reached TD in the Pre -Mississippian argillite. There is no indication from well records that any well control or other problems resulted from having all these formations simultaneously exposed in the open hole. Run OH logs and abandon the open hole with cement and a cement retainer. -Perforate the 10 %" casing across the interval 6522-6568' TVD/MD (Kingak). Run DST tools and reported flowing gas at 75 MCFD and a pore pressure of 8.53 ppg EMW. -A second DST for the perforated interval 6183'-6241' TVD/MD (Torok) showed a light blow with samples containing gas cut mud with a sheen of oil and a pore pressure of 2.3 ppg EMW. -A third DST for the interval 5807'-5946' TVD/MD (Torok) yielded only a trace of gas and a pore pressure of 6.3 ppg EMW. The well was then abandoned. CC� CAELUS Energy Alaska CT -1 DRILLING RISKS The histories of offsetting, previously drilled wells were closely examined to identify drilling risks and potential problems in the Tulimaniq #1 well. The offsetting wells examined are: South Simpson Test Well #1 (100-197) Drew Point #1 (100-198) East Simpson Test Well #1 (100-201) East Simpson Test Well #2 (100-203) Puviaq #1 (202-248) Aklaq #2 (205-180) Aklaq #6 (207-009) Based on the problems found in the drilling records for these wells, the identified drilling risks for Tulimaniq #1 are divided into Moderate Probability and Low Probability categories as discussed below. Moderate Probability No Cement to Surface When Cementing Surface Casing All but one of the offsetting wells brought cement to surface during the primary cementing job on the surface casing. One well (South Simpson #1) suffered lost circulation while drilling the 17-1/2" surface hole at 950' and again at 1280'. Spotting and circulating LCM pills regained circulation according to well documentation. Circulation was again lost during the 13-3/8" surface primary cement job and a top job using 1" pipe to a depth of 360 feet to pump additional cement to surface was required. One well (Aklaq 6) made no mention of cement returns to surface in morning reports nor mention of any remedial action taken. C' D /3 -oo Cement volumes used on all these wells, including top jobs, varied significantly from the Z _, volume calculated for an in -gauge hole. It has long been known that excessive circulation, multiple trips and elevated mud temperatures can lead to dramatic hole enlargement in the permafrost interval. An examination of the time interval between spud and pumping surface casing cement reveals a roughly linear relationship between that time and the amount of excess cement each well requires (i.e. the longer the hole is open, the higher the percent excess cement is required). The excess cement planned to be pumped in the Tulimaniq #1 well is based on the anticipated number of days between spud and pumping cement. However, the volume will be adjusted before cementing to take into account the actual open hole time. For further assurance that cement will be brought to surface, the surface casing of Tulimaniq #1 will contain a port collar placed at ±500' for use if the primary cement job fails to reach the surface. Lost Circulation Four of the offset wells (South Simpson #1, East Simpson #1, Aklaq #2 and Aklaq #6) experienced loss of circulation or breathing at depths between 5279' and 7020' in the Torok, below the surface casing. Mud weights being used at these times was between 9.6 and 10.8 ppg. In the most severe of the lost circulation events in the lower Torok, over 700 bbls of mud was lost before regaining full circulation. To minimize this as a potential problem, the planned mud weight curve will be adhered to unless hole conditions dictate otherwise. In addition, lost circulation materials will be on location at all times during drilling operations. One lost circulation event in Aklaq #6 occurred with a core barrel in the hole when coring the Kugrua formation at 7624' MD and this appeared to lead to some hole instability issues. However, Tulimaniq #1 will not penetrate the Kugrua formation. Lost circulation is the most likely event that will be encountered when drilling Tulimaniq #1 and the Torok may well be the main culprit. Low Probability Shale Instability One well (Drew Point #1) reported wellbore instability in what may be the Kingak. There are known wellbore instability problems associated with the HRZ and Kingak shales in wells drilled across the developed North Slope. Some of the factors contributing to hole instability in these shales are insufficient mud weight, wellbore azimuth and high deviation. Generally, the Kingak shales exhibit higher risk and severity than the shallower HRZ. Published studies of these two troublesome shales include stability diagrams that relate hole angle, azimuth and optimum mud weight for keeping the shales as stable as possible. Tulimaniq #1 will be vertical, so mud weight and fluid loss of the drilling mud are the only controllable variables. The planned mud weights of 10.0 to 10.6 ppg, recommended as optimal by the HRZ and Kingak stability charts, will be used. Gas Hydrates Methane hydrates within the permafrost interval have been encountered in various locations across the North Slope where they can be troublesome, reducing hydrostatic columns and inducing well kicks. Hydrates were not recorded in any of the wells offsetting the Tulimaniq #1 location and is not expected in the well to be drilled there. However, there remains a remote possibility of encountering hydrates and caution will be exercised. Hydrogen Sulfide Hydrogen sulfide was not encountered in any offset wells to Tulimaniq #1 and is not expected in this well. H2S procedures and continuous monitoring will be in place and followed during drilling operations. Casing Shoe Leak Off Test Procedure: 1. After testing BOPE, pick up the drilling assembly and RIH to the float collar. Circulate to consistent mud weight and rheology. 2. Shut in with the pipe rams and test the casing to the required test pressure. Record the volume of mud required and the corresponding pressures in 'X bbl increments. When the design pressure is reached shut in the well and record the shut in pressure for 30 minutes. 3. Bleed off pressure while taking returns to a calibrated tank and record volume recovered. 4. Drill out the shoe track. Drill 20 ft of new hole and circulate the hole clean with consistent mud weight in/out. Pull up into the casing shoe. 5. Perform a Leak Off Test (or Formation Integrity Test): • Calculate the required test pressure to reach leak off (or formation integrity test limit) with the actual mud weight and the estimated fracture EMW. • Plot the casing test data and the calculated leak off on appropriate scale coordinate paper. As a guide, use the data from the casing test to determine the approximate volume of mud required to reach the calculated LOT/FIT. • Shut the well in. R/U the test pump. • Bring the pump on line at 0.25 — 0.50 bpm. Maintain a constant rate. • Record the pressure for every %of a bbl pumped. • Continue pumping until the pressure vs. volume curve breaks over indicating leak off. Note: For FIT, do not take to leak off • Discontinue pumping and shut in the well. Record the shut in pressure in 1 minute increments for 10 minutes or until pressure shows stabilization. • Bleed off the pressure and record the volume of mud recovered. • Plot the data to determine the LOT/FIT pressure at the shoe as EMW. • Submit the test results to the Caelus Energy LLC drilling engineer for distribution as required. 3u F44 Surface Casing - Both Wells Conductor / CSG Ann. Well Input Data CSG I OH Permafrost I Surface Casing OD (in) 10 75 Surface Casing Weight 4lft 45.5 Surface Casing ID in 9.95 Surface Casing Setting Depth (ft) 2566 Previous Casing Casing OD (in) 16 Previous Casing Weight Iblft 84 Previous Casing Casing 10 (in) 15.01 Previous Casing Setting Depth (ft) 100 innerstring DP OD (in) 5 Innersting DP Weght(Ih/ft) 19.5 Trimming DP ID (in) 4.276 Hole Size (in) 13.5 Base of Permahost (ft) 980 Top of Lead Cement (ft) 0 Top of Tail Cement (ft) 2066 Length of Tail Cement (ft) 500 Shoe Joint Length (ft) 85 %Excess in Permafrost 250% % Excess Below Permahost 40% Capacity Output Data 40 Hdex Csg Annular Capacity Data bbls4 0.0648 Csg x Csg Annular Capacity total sl1) 0.1066 Casing Capacity Data (bbIM9 0.09112 Innersiring Capacity Data(bilxAq 0.0178 Spacer & Cement Slurry Input Data 1.15 Spacer 5.05 Spacer Type Spacer Spacer Density (pplD 1 10.5 Spacer Volume (bible) 50 Lead Slurry 215 Cement Stu T e Permafrost Surface Sluor, Density 10.90 Downhole Slurry Density (pool 11.23 Downhole Slurry Yield (cultists) 4.15 Mix Water(gaVsk) 19.24 Tail Slur 50 Cement Slurry Type Surf Tail Downhole Slurry Density (pP9) 15.80 Downhole Slurry Yie1tl cuftlsk 1.15 Mix Water(gallsk) 5.05 Volume Output Requirements Spacer Volume Required (tools) 50 InnerStrina Displacement bola 45 Lead Cement Calculated Volume R ulretl bbis 306 Lead Cement- Additional Volume bola 0 Tonal Lead Cement Volume (bola) 306 Total Lead Cement Volume on loc sacks 415 Total Tail Cement Volume bob 54 Total Tail Cement Volume Required sacks 264 Cement Mix Water Volume Required able 222 Waxh,Up Volume bbl 5p Total Water Volume per Job 322 Caell Energy Alaska - Smith Bay CT -1 : Casing Cement Design 100 ft, MD Coodudor5hoe I I I 1 960 ft, MD r Base permafrost 1 2066 ft, MD 1 Top of Tail 1 I I i Surface Casino Calculations Conductor / CSG Ann. 10.68 bbl CSG I OH Permafrost I = I 194.99 bbl CSG / OH Sub. Perm. 1 100.31 bbl Shue Track 8.17 bbl Drill PI a 44.07 bbl Total Lead bbl 358.19 bbl Intermediate Casing Multiple Stage Cement Job Sm e 1 CSG 1 OH Well Input Data bbl Intermediate Casing OD In 7.625 Intermediate Casing Weight #/it 29.7 Intiontroate Casing IO (in) 6.875 Intermediate Casing Setting Depth (ft) 6790 Multiple Stage Cementer Depth 11 6100 Top of Cement Stage 1(ft) 6100 Top of Cement Stage 2 (ft) 4680 Length of Cement Stage 1 (ft) 890 Length of Cement Stage 2 (ft) 1420 Hole Size lin) 9.875 Shoe Track Length (ft) 85 % Excess 50% Capacity Output Data Annular Capacity Data (bblsl8) 0.0382 Casing Capacity Data (bblslif) 0.0459 Spacer & Cement Slurry Input Data Spacer Spacer Type Tuned 111 Spacer Density(ppg) 10.5 Stage 1 Spacer Volume tools 40 Stage 2 Spacer Volume (tools) 40 Cement Slurry Cement Slurry Type PTA &Int Blend Downhole Slurry Density(ppg) 15.80 Downhole Slurry Yield(WfU5k) 1.15 Mix Water(gal/sk) 5.05 Volume Output Requirements Spacer Volume Required (bola) 80.0 Stage 1 Cement Volume Required (bible) 44.0 Stage l Cement Volume Required sacks 215 Stage 2 Cement Volume Re ulretl bbis 82.0 Stage Cement Volume Required (sacks) 400 Total Cement Volume Required(bbls) 126.0 Total Cement Volume Required (sacks) 615 Cement Mix Water Volume Required able 74.0 Wssh4 ;, Volume (bbl) 50 Total Water Volume per Job 204.0 � 3634 It. MD Top of 5pacer 4680 ft, MD TopTop of Tulimaniq Fan I I Ti, I 6723 ft, MD I Top HIM I I 1 1 6705 ft, MD I Baffle Adapter 1 Joint 2 j 6750 ft, MD Float Collar m ntt I 1 Intermediate Casino Calculations Sm e 1 CSG 1 OH = 40.0 bbl Sm e15M1oe Traek 4.0 bbl Stage 1 Total - 44.0 bbl Stage 2 CSG I OH 82 0 bbl Stage 2 Shoe Track - 0.0 bbl Sterna 2 Total - 82.0 bol CCAELUS Energy Alaska CT -1 Casing Design Verification Planned Casing Program The well will be drilled directionally to a TD of +/- 8781' MD (8641' TVD) to evaluate the Torok, Sag R, Shublik, Ivishak and Lisburne/Kekiktuk formations. After logging, the well will be plugged and abandoned. API Casing Design Factors Design factors are essentially "safety factors" that allow the design of safe, reliable, casing strings. Each operator may have his own set of design factors based on his experience and the condition of the pipe. Here we use the following design factors: Tensile Joint Strength: Nt = 1.8 Collapse (from external pressure): Nc = 0.8 or 80% Burst (from internal pressure): Ni = 0.8 or 80% The pore pressures used in these calculations are in part derived from the record of mud weights used to drill the offset wells. Maximum pore pressure, based on mud weights used in the intermediate holes of offset wells, is indicated to be 9.7 to 10.0 ppg, possibly in the HRZ — Kingak interval. The highest pore pressure in the 6-3/4" hole section is based on DST data from East Simpson Well #2 that yielded a pressure of 3752 psi at 7176' TVD/MD which is 10.05 ` ppg• 16" 10-3/4" 7-5/8" Depth (MD) 80' 2,566' 6,790' Depth (TVD) 80' 2,530' 6,650' Hole Size Driven 13-1/2" 9-7/8" Weight (ppf) 84# 45.5# 29.7# Grade H-40 L-80 L-80 Connection weld BTC BTC Nominal ID (in) 15.25" 9.95" 6.875" The well will be drilled directionally to a TD of +/- 8781' MD (8641' TVD) to evaluate the Torok, Sag R, Shublik, Ivishak and Lisburne/Kekiktuk formations. After logging, the well will be plugged and abandoned. API Casing Design Factors Design factors are essentially "safety factors" that allow the design of safe, reliable, casing strings. Each operator may have his own set of design factors based on his experience and the condition of the pipe. Here we use the following design factors: Tensile Joint Strength: Nt = 1.8 Collapse (from external pressure): Nc = 0.8 or 80% Burst (from internal pressure): Ni = 0.8 or 80% The pore pressures used in these calculations are in part derived from the record of mud weights used to drill the offset wells. Maximum pore pressure, based on mud weights used in the intermediate holes of offset wells, is indicated to be 9.7 to 10.0 ppg, possibly in the HRZ — Kingak interval. The highest pore pressure in the 6-3/4" hole section is based on DST data from East Simpson Well #2 that yielded a pressure of 3752 psi at 7176' TVD/MD which is 10.05 ` ppg• Design Factor Calculations Tensile Requirements The calculations will use the buoyed weight of each casing string plus an overpull of 100,000 lbs. 10-3/4" 45.5# L-80 BTC Surface Casing Buoyed weight of 2500' of casing = 2500 x 45.5 x 0.847 (buoyancy factor for 10 ppg mud) + 100,000 lbs (overpull safety factor) = 196,300 lbs Tensile Yield for casing = 1,040,000 lbs Safety Factor = 1040000/196300 = 5.3 vs a target of 1.8 or greater 7-5/8" 29.7# L-80 BTC Intermediate Casing Buoyed weight of 6790' of casing = 6790 x 29.7 x 0.847 (buoyancy factor for 10 ppg mud) + 100,000 (overpull safety factor) = 270,808 lbs Tensile Yield for casing = 683,000 lbs Safety Factor = 683000/270808 k = 2.52 vs a target of 1.8 or greater Burst Requirements Use maximum anticipated surface pressure (MASP) for each casing string. For each casing string, MASP is the formation pressure at the next casing point less a gas column to surface. 10-3/4" 45.5# L-80 BTC Surface Casing: Burst Rating = 5,210psi MASP at 9-7/8" hole section TD of 6,790'/6650 MD/-lVD (Intermediate casing): MASP = 6650'x ((10.0 ppg x 0.052)-0.1 psi/ft) = 2,793 psi DFb = Max Anticipated Surf Pressure / Burst Rating of Casing =2,793 psi / 5,210 psi =0.53 or 53% vs a target of less than 0.8 or 80% of burst rating �,�c 7-5/8" 29.7# L-80 B'i.. Intermediate Casing: Burst Rating = 6890 psi MASP at 6-3/4" hole section TD of 8781/8641MD/TVD: MASP = 8,641'x ((10.0 ppg x 0.052)-0.1 psi/ft) =3,629 psi z,Ic DFb = Max Anticipated Surface Pressure / Burst Rating of Casing 3629 psi / 6890 psi =0.53 or 53% vs a target of less than 0.8 or 80% of bursfrating—�� 3629 psi is also only 73% of the pressure rating of the 5000 psi BOP system that will be installed on the well. Collapse Requirements Use an external pressure consisting of formation pore pressure at the casing shoe and an internal pressure of a gas column to surface. 10-3/4" 45.5# L-80 BTC Surface Casing: Collapse Rating = 2470 psi External pore pressure Internal pressure w/ gas only Collapse Pressure =9.6 x 0.052 x 2,550' =1,250 psi =0.1 x 2,500' =250 psi =1,250 psi – 250 psi = 1,000 psi DFc = 10-3/4" collapse pressure /collapse rating 1000 psi / 2470 =0.40 or 40% vs a target of less than 0.8 or o o co apse rating 7-5/8" 29.7# L-80 BTC -M Intermediate Casing: Collapse Rating = 4790 psi External pore pressure =10.0 x 0.052 x 6,650' =3,458 psi Internal pressure w/ gas only =0.1 x 6,650' = 665 psi Collapse Pressure =3,458 psi –665 psi =2793 psi DFc = collapse pressure / collapse rating ,793 psi /4,790 psi 611 =0.58 or 58% vs a target of less than 0.8 or 800/6 of collapse rating M 2000 M 6000 x 0 8000 r c v O i[GIQ�Ti 12000 14000 16000 Tulimaniq Drilling Project Pressure Depth Plot Pressure Profile From Offset Wells Aklaq Area o v s 190. > v > 000 000 0000 0000 2000 A000 Pressure(PSIA) 20 PPg 's 00 O Aklag2 - -- r: South Simpson Caribou x Ikpikpuk HP@6ppg • HP@8ppg HP@10ppg HP@12ppg - HP@14ppg HP@16ppg • HP@18ppg • HP@20ppg aklag2MW South Simpson MW Ikpikpuk MW Puviaq MW o Topagoruk MW Tulimaniq Drilling Project Temperature Depth Plot Temperature Profile From Offset Wells Aklaq Area Temperature (deg F) -20 80 180 280 380 200 400 600 x ❑ F 800 a m 1000 1200 1400 1600 deg F/100 ft 480 ♦ Caribou Ikpikpuk Puviaq Puviaq thermal gradient x Topagoruk • thermal grad @ 1.4 deg F/ft • thermal grad @ 1.6 deg/100ft thermal grad @ 1.8 deg F/100ft - thermal grad @ 2 deg F/100ft • thermal grad -@ 2.2. deg F/100ft Tulimaniq Drilling Project Seismic Derived Pore Pressures Sampled from locations at Aklaq #2 & Aklaqyaaq #1 lidnivol Timwl T4,," fm56iMwVMJ jJ Ulm IM Ugan Ti4 w i r,'- to 13J v. PPG PIN Preaded)lore I4es5we Normal CalylMtion Tr"A Liles I3W W It to '0 fi 411U 01 :oi w 1131 ya PK CASING ORE IrIRON CONNEX TEST EQUIP. PLACE HOLDER (cuttings Pit) PIPE STORAGE TANK FARM 24'-6.9" SHOP RIG FUEL \ TANK SPILL CONNEX Well Center is 53' west from center of Pad. TEST EQUIPMENT eusH HYD. HOUS IrIRON CONNEX TEST EQUIP. PLACE HOLDER (cuttings Pit) PIPE STORAGE TANK FARM 24'-6.9" SHOP RIG FUEL \ TANK SPILL CONNEX Well Center is 53' west from center of Pad. DIVERTER LINE RUN 100'+ BEYOND SUBSTRUCTURE. OR AT LEAST 75' BEYOND NEAREST IGNITION POINT L T-0" VDYON DRILL M me In(ormMion contalnetl In bis tl2win9 is iM1elolM property o(Doyon Ortlling Inc. AnY reDrotluc0on In whole or peR wiNout Ne express wrlLLen consent of Doyon Drilllnp Iric. Is proMbfletl. 0YUJ09 NTS r r oD`I s9meixene AicM1c Fox 21}' 2000 psi Divetler Assembly G¢n@ral L¢ypul 1 VALVE LEOENO M' sono psi spuppR wmurx om ° 2 3 4 5 6 7 1 BYPASS s000m Tw/%wcrn aonou� 11' SWO P9 91MLq IM vwaz[ GT[ Px� w,u� s._ USLINDRAMS A UMU ATOR CONTROL TECHNOLOGY INC ® D O ® 6 STATION TRIP K P MP 1/208 VAC, 20 HP MR PUMP: 2/40:1, 80PM, 3,000 PSI ® D 0 Ind, FLUID RFS RVOIR• 165 GALLON O o0 s Iro' saoo psl NCR vuvx ® 0 D O O OO O O � 1/e•Iv%uPvEE o3nSoWM wGsR ®fQ OO Is" GPJ IME M SWR MIMM ACCUMULATOR MANIFOLD 10 BOTTLES, 11 GALLONS EACH OO I OO f4' IM Py NRq. OV61RY XMR GlE V.LLK I NITROGEN BACKUP REMOTE PANEL IN AOCHOus I I i,� sf Ip zwo P9 xroRR eov/oAmRR 90TH Fc 4 BOTTLES �fRsn mm us sTUMlfo as/R.wcm mneu wcACE OM1 R1FR lboyan I ARCM FOX 1-srp 60P SYSTEM AND CONTROL ° I -Z w sRnmA pm > 1 37 Too_ OINT � m i 13.50 1-0110.36 --I COMBINATION LOWFP BOW TFS- PLUG AND PACKOFF RUNNING TOOL `TO 010.35 V 1EN V H ICIEV ALASKA RENTAL WELLHEAD OPTION 16 X 10 3/4 X 7 5/8 POP888-0005 1 LANDING RING 2 P164819 CASING HEAD ASSEMBLY 3 13-300-718 TBC MD ASSY 4 P172126 CSC HGR ASSY 5 12-150-017 I PACKOFF A55Y 6 P184011 j 10 3/4 C-21 HGR 7 1166636 BELL NIPPLE 8 12-093-113 7 5/8 C-21 HGR 9 P168324 CSG MANDREL HGH. LANDING RING 37 Too_ OINT � m i 13.50 1-0110.36 --I COMBINATION LOWFP BOW TFS- PLUG AND PACKOFF RUNNING TOOL `TO 010.35 V 1EN V H ICIEV ALASKA RENTAL WELLHEAD OPTION 16 X 10 3/4 X 7 5/8 4< 11-5K THROUGH BORE SYSTEM SURFACE WELLHEAD LAYOUT BASIC WELLHEAD CAELUS ENERGY SERVICES ALASKA J. ARREOLA I M.BROWN 105 -27 -HI F 19309 REF: DM IGOCOP60 TOOL JO INTI LONE BOWL PpOTECTOfl FOR 10 3/4 Lp51NL 1 PP 1663Bi I LANA INE JOINT —010.78— 5.00 11.97 17. 09 I L � I PRIVATE AND CONFIDENTIAL �1078� 09.37 810.82 SHORT BOWL PROTECTOR COMP NATION IIPPFR BOW] T 5/8 CASING HANGERylacrn ro •K mtmm'. uo FOR 7 5/B CAS NG TEST PWC ANO R AND R TOOL <S.- &1"_479 BONL PROTECTOR RUNNING 700E 51.211_123 a� 2s15g9 4< 11-5K THROUGH BORE SYSTEM SURFACE WELLHEAD LAYOUT BASIC WELLHEAD CAELUS ENERGY SERVICES ALASKA J. ARREOLA I M.BROWN 105 -27 -HI F 19309 REF: DM IGOCOP60 JI'AKITA JV TO FAIRS TO F IRS MATERIAL LIST Item Description A 3-1116" 10M Remote Operated Hydraulic Choke B 3-1l8" 6M Adjustable Choke 1 2-1116" 5M Manual Gate Valve 2.14 3-118" 5M Manual Gate Valve 1 LEDGEND 1 White Handle Valves Normally Open Red Handle Valves Normally Closed FROM gap STACK Caelus Energy Alaska Smith Bay Tulimaniq CT -1 CT -1 Plan: CT -1 wp07 Standard Proposal Report 23 November, 2015 HALLIBURTON Sperry Drilling Services C CAELUS NALLIBURTON +NlS III Ener Alaska Spanny Drilling 000 000 Energy ' - - - -- CASING DETAILS Northing 615270706 INFILL Comma can., 46300199 DETAILS: CT -1 Loci) 450 Lannert, Loo nude 70.8281895614 -154.30]5688623 COMPANY DETARS. Caelus Energy Alaska REFERENCE INFORMATION Ca Winne MB) ReRrmKe WllU-1, Tme NOM ventral ri-I Rern vm 18.5'+4.5' @ 23.00mft tache Foe) Mounted aemm aerm<me: 18.5'+ 4.5'� 20.Oemt(Arntic Foe) Calmltlum Midland: Minimum Cen'tlum Project: Smith Bay TVD TVDSS MO Size Name Calculad Mem d Mi - umCumamre Site: Tulimani Q 2530.00 2507.00 2566.56 10-314 665000 6627.00 6790.16 7518 10 3l4" 7 SIB' a Syne. ISCWSA Seen Muchood, True CylinderNonh Well: CT -1 0 -- -- _ Erm 8 rf EI'pnc.l Conic Wellbore: 8641.00 8618.00 8781.16 &814 6 3/4" ON Wi meg Method. Rules Bund CT•1 Plan: CT -1 wI FORMATION TOP DETAILS 750 ---- - -F- -- ---- 'i --- TVDPath TVDMPalh MDP th Formation SECTION DETAILS - 2811.00 2788.00 2861.19 Nanushuk Topset - - -Start Build 1.50 5041.00 5018.00 5181.16 5810.00 5787.00 5950.16 T Tul. Fan Base Tul. Fan 1 6583.00 6560.00 6723.16 T HRZ Sec MD Inc Azi TVD TVDSS -W-S +EI -W DLe TFace VSec Target - 6700.00 6677.00 6840.16 LCU 1 18.50 0.00 0.00 18.50 4.50 0.00 0.00 0.0� 0.00 D.00 1500 _ 7331.00 7308.00 7471.16 T Sag River 2 1000.00 0.00 0.00 1000.00 977.00 0.00 0.00 0.00 0.00 0.00 8541.00 8518.00 8681.16 Basement 3 2166.41 17.50 0.00 2148.37 2125.37 176.71 0.00 1.50 0.00 176.71 4 4610.95 17.50 0.00 4479.81 4456.81 911.64 0.00 0.00 O.DO 911.64 5 5194.16 0.00 0.00 5054.00 5031.00 1000.00 0.00 3.00 180.00 1000.00 6 8781.16 0.00 e00 8641 00 8616.00 1000.00 0.00 0.00 0.00 1000.00 CTI BHL v2 - - Start 2444.54 hold at 2166.41 MD 2250 - - Displacemem of PHIL to target = 0' -10 3/4" �- 3000 Nanushuk Topset 1200 - 6314"OR rS m p : 1080 Inn Ora vo _ _75/8 -- t 0 3750 9641 _, 960- $ Start Drop -3.00 1 _ _ _ - C1-1 Q4500 ayo7 _ 40- 840- - szsD T Tul. Fan - - Stan 3587.00 hold at 5194.16 MD '. 720 - ',, Base Tul. Fan CD - ~.__ 6000 - ___ _ _ ___. ___. __. 600 80 480- 6750- 6750 _ _. ,.. ',, - LCU o rn 360-_ •___ ',__. _... TSag River -- Ip 14^ 7500 ,. '.. 240 - - - 8250 - - Basement - - -- 6 3/4" OH - 120 _�.. _.,.... CTI BHL v2 - - _ _ TD at 8781.16 9000_ 0 Displacement of BHL to target = 0 li -1000 -500 0 500 1000 1500 2000 2500 3000 -600 490 -360 -240 -120 0 120 240 360 480 600 Vertical Section at 0.00° (1000 usfUin) West( -)(East(+) (300 usWin) Database: EDMPrd Company: Caelus Energy Alaska Project: Smith Bay Site: Tulimaniq Well: CT -1 Wellbore: CT -1 Design: CT -1 wp07 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well CT -1 TVD Reference: 18.5'+4.5' @ 23.00usft (Arctic Fox) MD Reference: 18.5' +4.5' @ 23.00usft (Arctic Fox) North Reference: True Survey Calculation Method: Minimum Curvature Project Smith Bay Map System: US Stale Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 05 Using geodetic scale factor Site Tulimaniq CT -1 Dogleg Build Site Position: Northing: 6,152,707.06 usft Latitude: 70.8281895710 From: Map Easting: 463,001.99 usft Longitude: -154.3075688250 Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -0.29 ° 463,001.99 usft Longitude: Position Uncertainty usft Well CT -1 Dogleg Build Turn Measured Well Position +N/ -S 0.00 usft Northing: 6,152,707.06 usft Latitude; Azimuth +E/ -W 0.00 usft Easting: 463,001.99 usft Longitude: Position Uncertainty usft 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 70.8281895614 -154.3075688623 4.50 usft Wellbore CT -1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength 1°I 1°I InTI IGRF2010 8/11/2015 17.55 80.86 57,626 Design CT -1 wp07 Audit Notes: Version: Phase: Vertical Section: Depth From (TVD) (usft) 18.50 Plan Sections Dogleg Build Turn Measured +N/.S +E/ -W Vertical TVD Depth Inclination Azimuth Depth System (usft) (1 (1) (usft) usft 18.50 0.00 0.00 18.50 -4.50 1,000.00 0.00 0.00 1,000.00 977.00 2,166.41 17.50 0.00 2,148.37 2,125.37 4,610.95 17.50 0.00 4,479.81 4,456.81 5,194.16 0.00 0.00 5,054.00 5,031.00 8,781.16 0.00 0.00 8,641.00 8.618.00 PLAN Tie On Depth: 18.50 +N/ -S +E/ -W Direction (usft) (usft) V) 0.00 0.00 0.00 11123/2015 3: 59:22PM Page 2 COMPASS 5000.1 Build 58 Dogleg Build Turn +N/.S +E/ -W Rate Rate Rate Tool Face (usft) (usft) ("1100usft) ("1100usft) ('1100usft) (1) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 176.71 0.00 1.50 1.50 0.00 0.00 911.64 0.00 0.00 0.00 0.00 0.00 1,000.00 0.00 3.00 -3.00 0.00 180.00 1,000.00 0.00 0.00 0.00 0.00 0.00 11123/2015 3: 59:22PM Page 2 COMPASS 5000.1 Build 58 Halliburton HALLI B r Standard Proposal Report Database: EDMPrd Local Co-ordinate Reference: Well CT -1 Company: Caelus Energy Alaska TVD Reference: 18.5'+ 4.5'@ 23,00usft(Arctic Fox) Project: Smith Bay MD Reference: 18.5'+4.5' @ 23.00usft (Amtic Fox) Site: Tulimaniq North Reference: True Well: CT -1 Survey Calculation Method: Minimum Curvature Wellbore: CT -1 Depth Inclination Azimuth Design: CT -1 wp07 +NI -S +El -W Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI -S +El -W Northing Easting DLS Vert Section (usft) O V) (usft) usft (usft) (usft) (usft) (usft) -4.50 18.50 0.00 0.00 18.50 -4.50 0.00 0.00 6,152,707.06 463,001.99 0.00 0.00 100.00 0.00 0.00 100.00 77.00 0.00 000 6,152,707.06 463,001.99 0.00 0.00 200.00 0.00 0.00 200.00 177.00 0.00 0.00 6,152,707.06 463,001.99 0.00 0.00 300.00 0.00 0.00 300.00 277.00 0.00 0.00 6,152,707.06 463,001.99 0.00 0.00 400.00 0.00 0.00 400.00 377.00 0.00 0.00 6,152,707.06 463,001.99 0.00 0.00 500.00 0.00 0.00 500.00 477.00 0.00 0.00 6,152,707.06 463,001.99 0.00 0.00 600.00 0.00 0.00 600.00 577.00 0.00 0.00 6,152,707.06 463,001.99 0.00 0.00 700.00 0.00 0.00 700.00 677.00 0.00 0.00 6,152,707.06 463,001.99 0.00 0.00 800.00 0.00 0.00 800.00 777.00 0.00 0.00 6,152,707.06 463,001.99 0.00 0.00 900.00 0.00 0.00 900.00 877.00 0.00 0.00 6,152,707.06 463,001.99 0.00 0.00 1,000.00 0.00 0.00 1,000.00 977.00 0.00 D.00 6,152,707.06 463,001.99 0.00 0.00 Start Build 1.50 1,100.00 1.50 0.00 1,099.99 1,076.99 1.31 0.00 6,152,708.37 463,001.99 1.50 1.31 1,200.00 3.00 0.00 1,199.91 1,176.91 5.23 0.00 6,152,712.29 463,002.01 1.50 5.23 1,300.00 4.50 0.00 1,299.69 1,276.69 11.77 0.00 6,152,718.83 463,002.05 1.50 11.77 1,400.00 6.00 0.00 1,399.27 1,376.27 20.92 0.00 6,152,727.98 463,002.09 1.50 20.92 1,500.00 7.50 0.00 1,498.57 1,475.57 32.68 0.00 6,152,739.73 463,002.15 1.50 32.68 1,600.00 9.00 0.00 1,597.54 1,574.54 47.03 0.00 6,152,754.08 463,002.22 1.50 47.03 1,700.00 10.50 0.00 1,696.09 1,673.09 63.96 0.00 6,152,771.01 463,002.31 1.50 63.96 1,800.00 12.00 0.00 1,794.16 1,771.16 83.47 0.00 6,152,790.52 463,002.41 1.50 83.47 1,900.00 13.50 0.00 1,891.70 1,868.70 105.54 0.00 6,152,812.58 463,002.52 1.50 105.54 2,000.00 15.00 0.00 1,988.62 1,965.62 130.15 0.00 6,152,837.20 463,002.65 1.50 130.15 2,100.00 16.50 0.00 2,084.86 2,061.86 157.30 0.00 6,152,864.34 463,002.78 1.50 157.30 2,166.41 17.50 0.00 2,148.37 2,125.37 176.71 0.00 6,152,883.75 463,002.88 1.50 176.71 Start 2444.54 hold at 2166,41 MD 2,200.00 17.50 0.00 2,180.40 2,157.40 186.81 0.00 6,152,893.85 463,002.93 0.00 186.81 2,300.00 17.50 0.00 2,275.78 2,252.78 216.87 0.00 6,152,923.91 463,003.09 0.00 216.87 2,400.00 17.50 0.00 2,371.15 2,348.15 246.94 0.00 6,152,953.97 463,003.24 0.00 246.94 2,500.00 17.50 0.00 2,466.52 2,443.52 277.00 0.00 6,152,984.03 463,003.39 0.00 277.00 2,566.56 17.50 0.00 2,530.00 2,507.00 297.01 0.00 6,153,004.04 463,003.49 0.00 297.01 10 314" 2600.00 17.50 0.00 2,561.90 2,538.90 307.07 0.00 6,153,014.09 463,003.54 0.00 307.07 2,700.00 17.50 0.00 2,657.27 2,634.27 337.13 0.00 6,153,044.15 463,003.69 0.00 337.13 2,800.00 17.50 0.00 2,752.64 2,729.64 367.20 0.00 6,153,074.21 463,003.85 0.00 367.20 2,861.19 17.50 0.00 2,811.00 2,788.00 385.59 0.00 6,153,092.60 463,003.94 0.00 385.59 Nanushuk Topset 2,900.00 17.50 0.00 2,848.02 2,825.02 397.26 0.00 6,153,104.27 463,004.00 0.00 397.26 3,000.00 17.50 0.00 2,943.39 2,920.39 427.32 0.00 6,153,134.33 463,004.15 0.00 427.32 3,100.00 17.50 0.00 3,038.77 3,015.77 457.39 0.00 6,153,164.39 463,004.30 0.00 457.39 3,200.00 17.50 0.00 3,134.14 3,111.14 487.45 0.00 6,153,194.45 463,004.46 0.00 487.45 3,300.00 17.50 0.00 3,229.51 3,206.51 517.52 0.00 6,153,224.52 463,004.61 0.00 517.52 3,400.00 17.50 0.00 3,324.89 3,301.89 547.58 0.00 6,153,254.58 463,004.76 0.00 547.58 3,500.00 17.50 0.00 3,420.26 3,397.26 577.64 0.00 6,153,284.64 463,004.91 0.00 577.64 3,600.00 17.50 0.00 3,515.63 3,492.63 607.71 0.00 6,153,314.70 463,005.07 0.00 607.71 3,700.00 17.50 0.00 3,611.01 3,588.01 637.77 0.00 6,153,344.76 463,005.22 0.00 637.77 11123/2015 3:59:22PM Page 3 COMPASS 5000.1 Build 58 Halliburton u+ ' - _I r ` - , .. I ��,'.:. Standard Proposal Report Database: EDMPrd Local Co-ordinate Reference: Well CT -1 Company: Caelus Energy Alaska TVD Reference: 18.5' +4.5' @ 23.00usft (Arctic Fox) Project: Smith Bay MD Reference: 18.5'+4.5' @ 23.00usft (Arctic Fox) Site: Tulimaniq North Reference: True Well: CT -1 Survey Calculation Method: Minimum Curvature Wellbore: CT -1 Depth Inclination Design: CT -1 wp07 TVDss +N/ -S Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E1 -W Northing Easting DLS Vert Section (usft) (1) (1 (usft) usft lush) (usft) (usft) (usft) 3,683.38 3,800.00 17.50 0.00 3,706.38 3683.38 667.84 000 6,153,374.82 463,005.37 0.00 667.84 3,900.00 17.50 0.00 3801.76 3,778.76 697.90 0.00 6,153,404.88 463,005.52 0.00 697.90 4,000.00 17.50 0.00 3,897.13 3,874.13 727.97 0.00 6,153,434.94 463,005.68 0.00 727.97 4,100.00 17.50 0.00 3,992.50 3,969.50 758.03 0.00 6,153,465.00 463,005.83 0.00 756.03 4,200.00 17.50 0.00 4,087.88 4,064.88 788.09 0.00 6,153,495.06 463,005.98 0.00 788.09 4,300.00 17.50 0.00 4,183.25 4,160.25 818.16 0.00 6,153,525.12 463,006.13 0.00 818.16 4,400.00 17.50 0.00 4,278.62 4,255.62 848.22 0.00 6,153,555.19 463,006.29 0.00 848.22 4,500.00 17.50 0.00 4,374.00 4,351.00 878.29 0.00 6,153,585.25 463,006.44 0.00 878.29 4,600.00 17.50 0.00 4,469.37 4,446.37 908.35 0.00 6,153,615.31 463,006.59 0.00 908.35 4,610.95 17.50 0.00 4,479.81 4,456.81 911.64 0.00 6,153,618.60 463,006.61 0.00 911.64 Start Drop .3.00 4,700.00 14.82 0.00 4,565.34 4,542.34 936.43 0.00 6,153,643.38 463,006.73 3.00 936.43 4,800.00 11.82 0.00 4,662.64 4.639.64 959.47 0.00 6,153,666.42 463,006.85 3.00 959.47 4,900.00 8.82 0.00 4,761.00 4,738.00 977.39 0.00 6,153,684.34 463,006.94 3.00 977.39 5,000.00 5.82 0.00 4,860.18 4,837.18 990.14 0.00 6,153,697.09 463,007.01 3.00 990.14 5,100.00 2.82 0.00 4,959.88 4,936.88 997.68 0.00 6,153,704.62 463,007.04 3.00 997.68 5,181.16 0.39 0.00 5,041.00 5,018.00 999.96 6.00 6,153,706.90 463,007.06 3.00 999.96 T Tul. Fan 5,194.16 0.00 0.00 5,054.00 5,031.00 1,000.00 0.00 6,153,706.95 463,007.06 3.00 1,000.00 Start 3587.00 hold at 5194.16 MD 5,200.00 0.00 0.00 5,059.84 5,036.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 5,300.00 0.00 0.00 5,159.84 5.136.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 5,400.00 0.00 0.00 5,259.84 5,236.84 1.000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 5,500.00 0.00 0.00 5,359.94 5,336.84 1,000.00 0.00 6.153,706.95 463,007.06 0.00 1,000.00 5,600.00 0.00 0.00 5,459.84 5,436.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 5,700.00 0.00 0.00 5,559.84 5,536.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 5,800.00 0.00 0.00 5,659.84 5,636.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 5,900.00 0.00 0.00 5,759.84 5,736.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 5,950.16 0.00 0.00 5,810.00 5,787.00 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 Base TUL Fan 6,000.00 0.00 0.00 5,859.84 5,836.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 6,100.00 0.00 0.00 5,959.84 5,936.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 6,200.00 0.00 0.00 6,059.84 6,036.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 6,300.00 0.00 0.00 6,159.84 6.136.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 6,400.00 0.00 0.00 6,259.84 6,236.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 6,500.00 0.00 0.00 6,359.84 6,336.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 6,600.00 0.00 0.00 6,459.84 6,436.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 6,700.00 0.00 0.00 6,559.84 6,536.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 6,723.16 0.00 0.00 6,583.00 6,560.00 1,000.00 6.06 6,153,706.95 463,007.06 0.00 1,000.00 THR2 6,790.16 0.00 0.00 6,650.00 6,627.00 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 7 618^ 6,800.00 0.00 0.00 6,659.84 6,636.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 6,840.16 0.00 0.00 6,700.00 6,677.00 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 LCU 1112312015 3:59:22PM Page 4 COMPASS 5000.1 Build 58 Halliburton Standard Proposal Report Database: EDMPrd Local Co-ordinate Reference: Well CT -1 Company: Caelus Energy Alaska TVD Reference: 18.5'+ 4.5'@ 23.00usft(Arctic Fox) Project: Smith Bay MD Reference: 18.5'+4,5' @ 23.00usft (Arctic Fox) Site: Tulimanki North Reference: True Well: CT -1 Survey Calculation Method: Minimum Curvature Wellbore: CT -1 Design: CT -1 wp07 j Planned Survey --_-� Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Basting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 6,736.84 6,900.00 0.00 0.00 6,759.84 6,736.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1000.00 7,000.00 0.00 0.00 6,859.84 6,836.84 1,00000 0.00 6,153,706.95 463,007.06 0.00 1,000.00 7,100.00 0.00 0.00 6,959.84 6,936.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 7,200.00 0.00 0.00 7,059.84 7,036.84 1,000.00 0.00 6,153,706.95 463,007.06 D.00 1,000.00 7,300.00 0.00 0.00 7,159.84 7,136.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 7,400.00 0.00 0.00 7,259.84 7,236.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 7,471.16 0.00 0.00 7,331.00 7,308.00 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 T Sag River 7,500.00 0.00 0.00 7,359.84 7,336.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 7,600.00 0.00 0.00 7,459.84 7,436.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 7,700.00 0.00 0.00 7,559.84 7,536.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 7,800.00 0.00 0.00 7,659.84 7,636.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 7,900.00 0.00 0.00 7,759.84 7,736.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 8,000.00 0.00 0.00 7,859.84 7,836.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 8,100.00 0.00 0.00 7,959.84 7,936.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 8,200.00 0.00 0.00 8,059.84 8,036.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 8,300.00 0.00 0.00 8,159.84 8,136.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 8,400.00 0.00 0.00 8,259.84 8,236.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 8,500.00 0.00 0.00 8,359.84 8,336.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 8,600.00 0.00 0.00 8,459.84 8,436.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 8,681.16 0.00 0.00 8,541.00 8,518.00 1,000.00 0.00 6,153.706.95 463,007.06 0.00 1,000.00 Basement 8,700.00 0.00 0.00 8,559.84 8,536.84 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 8,781.16 0.00 0.00 8,641.00 8,618.00 1,000.00 0.00 6,153,706.95 463,007.06 0.00 1,000.00 TO at 8781.16.6 3/4" OH Targets Target Name -hitimiss target Dip Angle Dip on. TVD +N/ -S +E/ -W Northing Easting - Shape (°) C) (usft) (usft) (usft) (usft) (usft) CTI DHLQ 0.00 0.00 8,641.00 1,000.00 0.00 6,153,706.95 463,007.06 - plan hits target center - Circle (radius 250.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (1) 1"1 2,566.56 2,530.00 10 3/4' 10-3/4 13-1/2 6,790.16 6,650.00 7 5/8" 7-5/8 9-7/8 8,781.16 8,641.00 6 3/4" OH 6-3/4 6-3/4 11/232015 3:59:22PM Page 5 COMPASS 5000.1 Build 58 HALLIBURTON Database: EDMPrd Company: Caelus Energy Alaska Project: Smith Bay Site: Tulimaniq Well: CT -1 Wellbore: CT -1 Design: CT -1 wp07 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well CT -1 4.5'@ 23.00usft (Arctic Fox) 18.5' + 4.5'@ 23.00usft (Arctic Fox) True Minimum Curvature 1123/2015 3:59.22PM Page 6 COMPASS 5000.1 Build 58 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (1) C) 8,681.16 8,541.00 Basement 0.00 5,950.16 5,810.00 Base Tul. Fan 0,00 7,471.16 7,331.00 T Sag River 0.00 5,181.16 5,041.00 TTul. Fan 0.00 2,861.19 2,811.00 Nanushuk Topset 0.00 6,840.16 6,700.00 LCU 0.00 6,723.16 6,583.00 THRZ 0.00 Plan Annotations - -� Measured Vertical Local Coordinates Depth Depth +NI -S +E/ -W (usR) (usft) (usft) (usft) Comment 1,000.00 1,000.00 0.00 0.00 Start Build 1.50 2,166.41 2,148.37 176.71 0.00 Start 2444.54 hold at 2166.41 MD 4,610.95 4,479.81 911.64 0.00 Start Drop -3.00 5,194.16 5,054.00 1,000.00 0.00 Start 3587.00 hold at 5194.16 MD 8,781.16 8,641.00 1,000.00 0.00 TO at 8781.16 1123/2015 3:59.22PM Page 6 COMPASS 5000.1 Build 58 Caelus Energy Alaska Smith Bay Tulimaniq CT -1 CT -1 CT -1 wp07 Anticollision Summary Report 23 November, 2015 no 0 ISO Azimuth from North 101 vs Centre to Centre Separation X100 usMinj REFERENCE INFORMATION Co-ordinateNIE Reference: Well CT -1, True North Vertical( D Reference: 18.5'+4.5'23.00usa(Arctic Fox) Secdon (VS Reference: Slot - (0.00 N, O.00E) Measured Dem Reference: 18.5'+4.5 @ 23.00usn (Arctic Fox) Calculation Method: Minimum Curvature NAD 27 ASP Zone 5 : WELL Ground Levet: 4.50 .W -S +E/ -W Northing Seeing Latiltude Longitude 0.00 0.00 6152707.06 463001.99 70.8281895614 -154.3075688623 Error System: ISCWSA Scan Method : Trev. Cylinder North Error Surface: Elliptical Conic Warning Mathod, Rules Based 270 ANTI -COLLISION SETTINGS Interpolation Method: MD, interval: 25.00 Depth Range From: 18.50 To 8781.16 Centre Distance: 1086.27 Plan: CT -1 wp07 180 Azimuth from North °1 vs Centre to Centre Separation 120 usfuml SECTION DETAILS Sec MD Inc Azi TVD TVDSS +N/ -S +E/ -W DL eg TFace VSec Target 1 18.50 0.00 0.00 18.50 4.50 0.00 0.00 0.00 0.00 0.00 2 1000.00 0.00 0.00 1000.00 977.00 0.00 0.00 0.00 0.00 0.00 3 2166.41 17.50 0.00 2148.37 2125.37 176.71 0.00 1.50 0.00 176.71 4 4610.95 17.50 0.00 4479.81 4456.81 911.64 0.00 0.00 0.00 911.64 5 5194.16 0.00 0.00 5054.00 5031.00 1000.00 0.00 3.00 180.00 1000.00 Tulimarvg Fan Top 6 8781.16 0.00 0.00 8641.00 8618.00 1000.00 0.00 0.00 0.00 1000.00 CTi BHL J2 SURVEY PROGRAM Date: 2015-11-23TM 00:00 Validated Yes Version: Depth From Depth To SuiveylPlan Tool 18.50 2567.00 CT -1 W07 (CT -1) MWD+SC 2567.00 6790.00 CT -1 wp07 ((CT -1) MWD+SC 6790.00 8781.16 CT -1 vFO7 (CT -1) MWD>SC no 0 ISO Azimuth from North 101 vs Centre to Centre Separation X100 usMinj REFERENCE INFORMATION Co-ordinateNIE Reference: Well CT -1, True North Vertical( D Reference: 18.5'+4.5'23.00usa(Arctic Fox) Secdon (VS Reference: Slot - (0.00 N, O.00E) Measured Dem Reference: 18.5'+4.5 @ 23.00usn (Arctic Fox) Calculation Method: Minimum Curvature NAD 27 ASP Zone 5 : WELL Ground Levet: 4.50 .W -S +E/ -W Northing Seeing Latiltude Longitude 0.00 0.00 6152707.06 463001.99 70.8281895614 -154.3075688623 Error System: ISCWSA Scan Method : Trev. Cylinder North Error Surface: Elliptical Conic Warning Mathod, Rules Based 270 ANTI -COLLISION SETTINGS Interpolation Method: MD, interval: 25.00 Depth Range From: 18.50 To 8781.16 Centre Distance: 1086.27 Plan: CT -1 wp07 180 Azimuth from North °1 vs Centre to Centre Separation 120 usfuml SECTION DETAILS Sec MD Inc Azi TVD TVDSS +N/ -S +E/ -W DL eg TFace VSec Target 1 18.50 0.00 0.00 18.50 4.50 0.00 0.00 0.00 0.00 0.00 2 1000.00 0.00 0.00 1000.00 977.00 0.00 0.00 0.00 0.00 0.00 3 2166.41 17.50 0.00 2148.37 2125.37 176.71 0.00 1.50 0.00 176.71 4 4610.95 17.50 0.00 4479.81 4456.81 911.64 0.00 0.00 0.00 911.64 5 5194.16 0.00 0.00 5054.00 5031.00 1000.00 0.00 3.00 180.00 1000.00 Tulimarvg Fan Top 6 8781.16 0.00 0.00 8641.00 8618.00 1000.00 0.00 0.00 0.00 1000.00 CTi BHL J2 Halliburton Anticollision Report Company: Caelus Energy Alaska Local Coordinate Reference: Project: Smith Bay TVD Reference: Reference Site: Tulimaniq MD Reference: Site Error: 0.00usft North Reference: Reference Well: CT -1 Survey Calculation Method: Well Error: 0.0ousft Output errors are at Reference Wellbore CT -1 Database: Reference Design: CT -1 wp07 Offset TVD Reference: Well CT -1 18.5' + 4.5'@ 23.00usft (Arctic Fox) 18.5' + 4.5'@ 23.O0usft (Arctic Fox) True Minimum Curvature 2.00 sigma EDMPrd Offset Datum Reference CT -1 wP07 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: Unlimited Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,076.27usft Error Surface: Elliptical Conic Survey Tool Program Date 11/23/2015 From To (usft) (usft) Survey (Wellbore) Tool Name Description 18.50 2,567.00 CT -1 wp07 (CT -1) MWD+SC Fixed.v2:standard dec & axial correction 2,567.00 6,790.00 CT -1 wp07(CT-1) MWD -SC Fixed. v2: standard dec& axial correction 6,790.00 8781.16 CT -1 wp07 (CT -1) MWD+SC Fixedv2' standard use & axial correction Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) Tutimaniq No Offset Wells in Area---- 23.00 20.50 0.01 1.06 -1.06 Major Risk 1112312015 4:07..58PM Page 2 of 3 COMPASS 5000.1 Build 58 FUGRO GEOCONSULTING INC. Shallow Hazards Assessment Proposed CT -1 Well Smith Bay, Alaska 8 October 2015 Fugro Project No.: 27.1501-2886 CAELUS Energy Inc., NORDAQ Energy Inc. ca CAELUS Energy LLC-+-wsxucx xno s+.wsrart nut.x M M ?GRO '� CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA Report No. 27.1501-2686 8 October 2015 CAELUS Energy Inc. 8401 North Central Expy. Dallas, TX 75225 Attention: Mr. Kenny Goh SHALLOW HAZARDS ASSESSMENT PROPOSED CT -1 WELL SMITH BAY, ALASKA ?own 6100 Hillcroft (77081) P.O. Box 740010 Houston, TX 77274 Phone: 713-369-5600 Fax: 713-778-6816 Fugro GeoConsulting, Inc. (FGCI) is pleased to present to CAELUS the following shallow hazards and pore pressure assessment for the proposed CT -1 well, near shore in Smith Bay, Alaska. The report describes the shallow geologic and pressure conditions that may influence exploratory well drilling in the study area. This work was performed under a Master Service Agreement between CAELUS Energy, Inc. and Fugro GeoConsulting, Inc, dated 21 August 2014. We appreciate the opportunity to work with you on this project and look forward to continuing as your shallow hazard and geotechnical consultants. Please call us if you have any questions or if we can be of further assistance. Sincerely, FUGRO GEOCONSULTING, INC. Yosmel Sanchez, Ph.D. Senior Geoscientist v Stephen Varnell, P.G. (TX, CA), C.E.G. (CA) Deputy Geoscience Department Manager / Consultant Copies submitted: (1 digital) 00-41� Aurelian C. Trandafir, Ph.D., P.E. Deputy Quantitative Geohazards Manager / Consultant A member of the Fugro group of companies with offices throughout the world. Geology License #11337 t; I AURELIAN 52 GRO CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY. ALASKA EXECUTIVE SUMMARY The following report assesses the shallow geologic conditions that might affect petroleum exploration in State Lease Block 523 and portions of the surrounding area. The report specifically assesses shallow geologic conditions that could affect exploratory drilling operations at the proposed CT -1 well to a subsurface depth of about 4,003 ft (TVDss) and pore pressure prediction to a depth of 9,000 ft (TVDss), The study area is located on State lands, outside the north -central part of the NPR -A, and along the Alaskan Beaufort Sea coast. CT -1 is near the outer Ikpikpuk River Delta in the southern part of Smith Bay and about 60 miles east-southeast of Barrow, AK. Conditions in the proposed CT -1 well appear to be generally favorable for exploratory drilling. There are several offset wells in the area, which penetrated similar tophole conditions without significant problems. Some of the fundamental aspects covered in the study are summarized below. 1. Permafrost. The base of the ice bearing permafrost (0 °C) at the proposed CT -1 is probably about 906 ft TVDss. The top of permafrost probably drops off sharply seaward in Smith Bay, but may still be present in the upper 100 feet of sediment. The delta distributary channels, thermokarst lakes, possible submerged shoals, submerged thermokarst lakes, and a changing shoreline may produce local variations in the permafrost. The relatively warm river water undoubtedly contributes to permafrost degradation from the top down, but some degradation also occurs from below. 2. Gas Hydrates. The BGHS is about 1,615 ft TVDss in the CT -1 area and gas hydrates are possible between that depth and the top of gas hydrate stability at about 805 ft TVDss. Throughout most of the tophole section, gas hydrates in high concentrations or as massive layers are not likely because most of the stratigraphic section is fine-grained and there is a general lack of anomalous seismic response. Minor localized amounts of hydrate may still be present in the form of disseminated small crystals, nodules, and fillings in lenses and partings. There is slightly greater potential for hydrate accumulations near the base of the BGHS where coarser -grained siltstone and sandstone appear more likely. 3. Shallow Gas. The potential for encountering shallow gas ranges from negligible to low at the proposed CT -1 drill site. There is no clear acoustic evidence for shallow gas at the proposed wellsite; however, there is some potential for encountering free gas, trapped beneath the base of gas hydrate stability (BGHS), about 2.8 miles southeast of the proposed wellsite. Shallow gas problems were not encountered in the surrounding offset wells. Gas shows while drilling were mostly found in the deeper section. Minor gas was encountered within the permafrost at Puviaq #1, which is 9.3 miles south- southwest of the proposed CT -1 wellsite. These shallow gas releases were probably from pore -space hydrates within ice -bonded permafrost and are not significant. 4. Stratigraphy. Northeast -dipping siltstones, sandstones, and shales of the Albian-Cenomanian Nanushuk Group and the Albian Torok Formation comprise the bulk of the tophole section (-4,000 ft). Based on the offset wells, these strata can also include coals and carbonaceous shales. Shallow non - marine to marginal marine sandstones are most likely in the Nanushuk. A few hundred feet of silty claystones and shales of the Seabee Formation may overlie the Nanushuk. Quaternary sifts, sands, and clays of the Gubik Formation in turn overlie these strata. 5. There are no shallow faults in the study area. 6. No significant overpressure has been identified in the analyzed offset wells near the CT -1 prospect. Our calculations do not anticipate significant overpressure at the CT -1 location where the greatest values are assessed near the transition of the Kingak Formation and the Sag River Sandstone to the base of the Shublik Formation reaching a maximum of 10.0 ppg. 7. No other geologic conditions were identified from the 3D seismic data that would be expected to impact drilling operations. Report No. 27.1501-2886 Page i of 40 GRO CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY. ALASKA CONTENTS 1. INTRODUCTION......................................................................................................................................5 1.1 Purpose and Scope..................................................................................................................................5 24 1.2 Data Used................................................................................................................................................5 1.3 Project Participants..................................................................................................................................7 2. GEOLOGIC SETTING.............................................................................................................................8 2.1 Permafrost................................................................................................................................................8 .......... 34 2.2 Hydrates...................................................................................................................................................9 2.3 Regional Geologic and Structural Setting..............................................................................................10 36 2.4 Stratigraphy............................................................................................................................................10 3. SHALLOW GEOLOGIC CONDITIONS NEAR THE PROPOSED CT -1 WELLSITE ............................16 3.1 Stratigraphy............................................................................................................................................16 3.2 Permafrost..............................................................................................................................................17 3.3 Gas Hydrates and Free -Phase Gas.......................................................................................................17 3.3.1 Gas Hydrates..........................................................................................................................18 3.3.2 Free -Phase Gas......................................................................................................................19 3.4 Other Conditions....................................................................................................................................20 4. SHALLOW GEOLOGIC CONDITIONS AND PORE PRESSURE ASSESSMENT FOR PROPOSED 7. REFERENCES ....................................... Report No. 27.1501-2886 Page 2 of 40 CT -1 WELL............................................................................................................................................24 4.1 Introduction............................................................................................................................................. 24 4.2 Site Specific Shallow Geologic Conditions and Tophole Prognosis Chart ............................................24 4.3 Methodology...........................................................................................................................................27 4.4 Post -drill Offset Well Summaries...........................................................................................................28 4.5 Pore Pressure Assessment for the proposed CT -1 Well, Observations and Recommendations .......... 34 5. WELLSITE SUMMARY..........................................................................................................................36 5.1 Introduction............................................................................................................................................. 36 5.2 Location and Description........................................................................................................................36 6. RESULTS AND RECOMMENDATIONS...............................................................................................38 7. REFERENCES ....................................... Report No. 27.1501-2886 Page 2 of 40 CAELUS ENERGY, INC. Blau SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA APPENDICES APPENDIX A 1 INTERPRETATION AND MAPPING PROCEDURES 1 A.1 INTRODUCTION 2 A.2 DATA ACQUISITION AND PROCESSING 2 A.3 BASE MAP (CHART 1) 4 A.4 STRUCTURE MAPS, HORIZONS 2 AND 4 (CHARTS 2 AND 3) 4 A.5 FIGURES AND SEISMIC DATA EXAMPLES 4 A.6 ASSESSING SHALLOW GAS POTENTIAL 5 A.7 ASSESSING HYDRATE POTENTIAL 5 LIST OF TABLES Table1. Proposed CT -1 Well Location..........................................................................................................................5 LIST OF FIGURES Figure 1.1. Study area and proposed location of the CT -1 prospect. Although Tulimaniq #1 is drill -pending, its location is shown for reference. Figure 2-1. Map showing the depth to the base of permafrost in a broad area including Smith Bay (modified from Collet, 1993). Spot depths are from wells accessed through the Alaska - AGMC Website, Formation top downloads, AOGCC, (2010). Image from Landsat7 Global Imagery Mosaic. Figure 2-2. Map showing the depth of the base of gas hydrate stability in a broad area including Smith Bay (modified from Lewis and Collett, 2013). Image from Landsat7 Global Imagery Mosaic. Figure 2-3. Base map with orientation of seismic lines presented in this report. Figure 2-4. Arbitrary regional line between East Simpson Test Well #1, the proposed CT -1 well and Drew Point #1 showing regional geologic conditions. Figure 2-5. Arbitrary line across Puviaq #1 and proposed CT -1 well location showing regional geologic conditions. Figure 2-6. Arbitrary line across Aklaq #6 and proposed CT -1 well location showing geologic conditions. Figure 2-7. Channel features and amplitude anomalies corresponding to the Torok clinoforms. Figure 3-1. Crossline 308 showing shallow geologic conditions near the proposed CT -1 wellsite. Figure 3-2. Vatmin volume attribute extraction from 20 ms above to 20 ms below Horizon 1. The relatively high negative amplitudes appear to represent the trough lobes of a strong peak -over -trough, positive polarity reflection at the depth of Horizon 1. Signal strength is amplified along the trend of the delta front, which may reflect a shallow, unfrozen sediment zone above the permafrost and below the shore -fast ice. Figure 3-3. Identified amplitude anomalies in the shallow section. Figure 3-4. Amplitude anomalies near the base of gas hydrate stability. Figure 3-5. Analysis of amplitude anomalies in the upper Torok Formation near Horizons 3 and 4. Report No. 27.1501-2886 Page 3 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA ?GR13 Figure 4-1. Relative location of offset wells used for the tophole prognosis chart and pore pressure assessment with respect to the CT -1 proposed location. Figure 4-2. Arbitrary seismic line along the proposed CT -1 well trajectory. Figure 4-3. Tophole prognosis chart. Figure 4-4. Post -drill pore pressure analysis for Aklaq # 2 well. The dots in the gamma ray chart correspond to points of significant gas shows. Figure 4-5. Post -drill pore pressure analysis for the Puviaq #1 well. Figure 4-6. Post -drill pore pressure analysis for the Drew Point #1 well. The red line on the travel time curve corresponds to the assumed normal compaction trend. Figure 4-7. Post -drill pore pressure analysis for the East Simpson Test Well #1. The red line on the travel time curve corresponds to the assumed normal compaction trend. Figure 4-8. Post -drill pore pressure analysis for the South Simpson Test Well #1. The red line on the travel time curve corresponds to the assumed normal compaction trend. Figure 4-9. Integrated pore pressure prediction for the CT -1 prospect. Chart 1. Navigation Post -Plot, CT -1 Prospect Blocks 518-525, 533-534 and 538. Chart 2. Structure Horizon 2. Chart 3. Structure Horizon 4. Report No. 27.1501-2886 Page 4 of 40 GRO CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA INTRODUCTION 1.1 Purpose and Scope The purpose of this study is to identify significant shallow geologic features or conditions that may impact exploratory drilling at the proposed CT -1 wellsite. The study area is located on State lands, outside the north -central part of the NPR -A, and along the Alaskan Beaufort Sea coast. The proposed CT -1 location is on the outer Ikpikpuk River Delta, about 60 miles east-southeast of Barrow, Alaska, and in the southern part of Smith Bay (Chart 1). Roughly one third of the study area in the southwest is onshore and the rest in the shallow waters of Smith Bay. The proposed CT -1 wellsite is in State Lease Block 523 and about 2,000 ft from the shifting deltaic shoreline. Water depth is estimated to be —5 ft below surface at the proposed CT -1 location. Table 1. Proposed CT -1 Well Location The scope of this study consists of interpretation, mapping, and assessment based primarily upon a project -specific 3D seismic data volume covering State Lease Block 523 and surrounding areas along Smith Bay. The subsurface depth limit of investigation for the geohazards study is about 4,003 ft TVDss. Section 5 provides the integrated pore pressure prediction for the CT -1 prospect along with specific details of the data used, techniques, graphs, conclusions, and recommendations. The subsurface depth limit for the comprehensive pore pressure assessment is 9,000 ft TVDss. 1.2 Data Used Fugro GeoConsulting, Inc, (FGCI) based this assessment primarily on 49 sq. mi. of three-dimensional seismic data provided by CAELUS (Chart 1). FairfieldNodal in Houston, Texas processed these data specifically for geohazards evaluation of the study area and they provide an excellent resource for the analysis of potential drilling hazards. FairfieldNodal provided RMS and interval velocity data along with the following, project -specific 3D data volumes at 2 -millisecond sample intervals and 110 -ft inline/crossline spacing: • Raw NMO Stack • Enhanced NMO Stack • Post Stack Migration CAELUS provided the following velocity function for sediment column time to depth conversion: Depth in feet = 915.6462617512 + 3056.24765254*t (t = two-way travel time to the mapped horizon in seconds). CAELUS also provided a 606 sq. mi. Post Stack Time Migration volume at a 4 -millisecond sample interval and 110 -ft inline/crossline spacing. These data were primarily used for offset well correlation; however, comparisons of the near, mid, and far offset stacks were used for lithology and amplitude analysis. Report No. 27.1501-2886 Page 5 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA CAELUS provided drilling reports and logs for several existing wells that fall within the 3D data coverage area. Information for additional offset wells and core tests used for this study were accessed online through the Geologic Materials Center, Alaska DNR, Division of Geological and Geophysical Surveys. The regional geologic assessment also incorporates readily available maps and publications from the U.S. Geological Survey, the Alaska Department of Natural Resources, the Alaska Oil and Gas Conservation Commission (AOGCC, 2014), and published peer-reviewed journal articles. References for the publicly available resources, which are available on the internet, are listed at the end of this report. xm Feel 6238700 N 1 GRID East Simpson Test Well NORTH East Simpson Test Well South Simpson Test Well #1 E Topagoruk Test Well #1 9 Proposed CT -1 well, surface location Primary offset wells - used in study • Secondary offset wells and core tests used in alsET A Image from Landsat7 F671 Global Imagery Mosaic n- 'ION (FAST - GAINED) scr -&m Ca.rnl #1 Figure 1-1. Study area and proposed location of the CT -1 prospect. Although Tulimaniq #1 is drill - pending, its location is shown for reference. Report No. 27.1501-2886 Page 6 of 40 CAELUS ENERGY, INC. SRO SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA 1.3 Project Participants NORDAQ Energy, Inc. (NORDAQ) and CAELUS Energy, Inc. (CAELUS) contracted Fugro GeoConsulting, Inc. (FGCI) to provide geophysical and geohazards interpretation, mapping, and report preparation services. Mr Michael Kucera, Senior Consultant, loaded the survey data to the workstations, provided technical assistance as required, and was responsible for data management services. Gregory J. Nash, M.S., P.G., Senior Consultant, performed geophysical data interpretation in the studied area. Mr Yosmel Sanchez, Senior Geoscientist, completed the pore pressure assessment and associated text and graphics. Mr Joshua Kelly, Geoscientist, updated the graphs corresponding to the CT -1 location while Mr. Sean Garner, FGCI, developed the charts and GIS database. Mr Steve Varnell, M.S., P.G., and Mr Aurelian C. Trandafir Ph.D., P.E. reviewed the final report and contributed to its final form and content. Mr Kenny Goh is CAELUS point of contact with FGCI. Report No. 27.1501-2886 Page 7 of 40 GR® CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA 2. GEOLOGIC SETTING 2.1 Permafrost The base of permafrost (0 °C) at the proposed CT -1 is probably about 1,000 ft TVDss (USGS, 2013), Figure 2-1. A rough estimate of the base of Ice -Bearing permafrost, based on offset wells is probably closer to 900 ft TVDss (Figures 2-4, 2-5, and 2-6). The general model for the inner continental shelf is that a thick permafrost layer developed during the last ice age when sea level was lower and the modern shelf was subaerially exposed. Subsequent sea level rise allows the year-round circulation of relatively warm seawater over the Pleistocene permafrost in water depths greater than about 6 ft. The relatively warm water degrades the permafrost from the top down, but some degradation also occurs from below. The gross permafrost model for Smith Bay is a seaward -thinning permafrost wedge. Actual permafrost distribution and thickness is undoubtedly far more complex. The delta distributary channels, thermokarst lakes, possible submerged shoals, submerged thermokarst lakes, and a changing shoreline may produce local variations in the permafrost. The top of permafrost probably drops off sharply seaward in Smith Bay, but may still be present in the upper 100 feet of sediment. Offshore wells and boreholes in the Canadian Beaufort have encountered permafrost to depths greater than 600 m (-1969 ft). Figure 2-1. Map showing the depth to the base of permafrost in a broad area including Smith Bay (modified from Collet, 1993). Spot depths are from wells accessed through the Alaska - AGMC Website, Formation top downloads, AOGCC, (2010). Image from Landsat7 Global Imagery Mosaic. Report No. 27.1501-2886 Page 8 of 40 CAELUS ENERGY, INC. ORD SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA 2.2 Hydrates Arctic gas hydrate occurrences have been identified in sand -rich units deposited in near -shore and onshore environments. Collett et al., (2011) postulate that these Arctic hydrates were originally free -gas accumulations that became trapped as hydrates during the last glacial period as sea level, atmospheric temperatures, and subsurface temperatures dropped. The existence of gas hydrates in the shallow section is a potential drilling concern primarily because the base of gas hydrate stability (BGHS) can act as a physical barrier impeding vertical migration of free - phase gas resulting in accumulations of free -phase gas immediately below the BGHS. Recent reports from the Qugruk #2 blowout appear to confirm this potential drilling concern (AOGCC, 2014). The apparent association of the BGHS with the blowout at Qugruk #2 was considered in this assessment along with various other possible hydrate -drilling concerns identified at the Cirque -1 well (Figure 2-2). Destabilizing massive hydrate accumulations may cause uncontrolled gas releases during drilling (including blowouts), collapsed casings, and gas leakage to the surface outside of the casing (Yakushev and Collett, 1992; Collett, 1993; and Collett and Dallimore, 2002). The blowout at the Cirque -1 originated with a shallow gas zone beneath the BGHS. Dissociation of a thick gas -hydrate -bearing interval above the gas zone contributed to the problem and it appears that the attempts to control the well enhanced the dissociation of the hydrates (AOGCC, 1992 and Collett and Dallimore, 2002). However, none of these conditions materialized in the numerous surrounding offset wells near the study area (Figure 2-2). Collett and Dallimore (2002) present the straightforward drilling programs to mitigate hydrate -related drilling and production problems. Figure 2-2. Map showing the depth of the base of gas hydrate stability in a broad area including Smith Bay (modified from Lewis and Collett, 2013). Image from Landsat7 Global Imagery Mosaic. Report No. 27.1501-2886 Page 9 of 40 CAELUS ENERGY, INC. GRU SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA 2.3 Regional Geologic and Structural Setting The study area is located in the southern part of Smith Bay, offshore the north -central part of the National Petroleum Reserve -Alaska (Chart 1). Smith Bay overlies the northern part of the Colville Foreland Basin near the westward extension of the Barrow Arch. The Jurassic Colville Basin, which is part of the foreland basin north of the Brooks Range, is mostly filled with Early Cretaceous through Tertiary siliciclastic sediments derived from the ancestral Brooks Range (Houseknecht, 2014). The Colville Basin had a relatively stable tectonic history during the Cretaceous with a slow and constant rate of subsidence (Bird, 2001). Clastic sediments steadily filled the basin during the Cretaceous through present with only short-term local variations in sedimentation rates (Bird, 2001). The orientation of the Cretaceous -Tertiary clinoforms indicates that basin fill generally progressed from west to east during this period (Lewis and Collett, 2013). In the regional study area, the clinoforms of the Torok and Nanushuk Formations are part of a large northeasterly prograding, Aptian to Cenomanian sequence (Lewis and Collett, 2013). The overall structure of the tophole section conforms to this northeasterly -dipping basin fill. 2.4 Stratigraphy Although there appear to be potential discrepancies among the various lithological descriptions of the numerous offset wells and test cores, all these data have been reviewed and revised by numerous geologists and published by the USGS and by the ADGGS. The following relies mainly on those published reports, but also upon the original well logs and lithological descriptions. Siltstones, sandstones, and shales of the Albian-Cenomanian Nanushuk Group and the Albian Torok Formation comprise the bulk of the tophole section (-4,000 ft). The Torok and Nanushuk represent the coeval lower and upper parts of a prograding clastic wedge (Mull et al., 2003). The available seismic data and in particular the seismic profiles represented by the seismic lines shown in Figure 2-3, reveal very clear patterns of these prograding Cretaceous clinoforms (Figures 24, 2-5, and 2-6). The slope to shelf claystones and siltstones of the Torok Formation coarsen upward into the interbedded shallow marine and nonmarine sandstone and shale of the Nanushuk Formation (Lewis and Collett, 2013). The Nanushuk is a sand -prone section and the Torok is a silt -prone section. Based on the offset wells, these strata include coals and carbonaceous shales. The Torok Formation primarily accumulated in delta slope and basin -floor fan settings. The Torok foreset reflectors in the study area show clear evidence of channeling and slumping (Figure 2-7). The Nanushuk Group accumulated in shallow deltaic and fluvial settings. The seismic data suggest that onlapping high stand wedges may contribute to high -amplitude topset reflectors in the study area. The Nanushuk appears to subcrop at shallow depths at the East Simpson Test Well #1, Puviaq #1, and Aklaq #6, which are generally northwest and southwest of the study area (Figures 2-4, 2-5, and 2-6). Colville shale and Colville Sandstone overlie the Top Nanushuk, which is reported to be at 1,230 ft TVD at Drew Point #1 to the northeast (Figure 2-4). Shallow Colville sandstone was also recorded at the East Simpson Test Well #1 (Figure 2-4). Report No. 27.1501-2886 Page 10 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA ?K;R93 Mull et al., (2003) have suggested abandoning the Colville Group in favor of the "more readily mappable' Seabee, Tuluvak, Schrader Bluff, and Prince Creek Formations. The Colville strata in the regional study area probably consist of marginal -marine, Upper Cretaceous Seabee and Tuluvak Formations. There are probably a few hundred feet of silty claystones and shales of the Seabee Formation at the proposed wellsite. The shallow, poorly -indurated sandstone at Drew Point #1 is the Tuluvak Formation (AOGCC, 2010), but it does not extend into the study area based on the structural configuration of the shallow section (Figure 2-4). The youngest strata in the Smith Bay area consist of Quaternary silts, sands, and clays of the Gubik Formation. They were deposited in a near -shore marine environment and probably represent all the Pleistocene and part of the Pliocene. Based on the nearby offset wells, these thin, surficial, unconsolidated sediments unconformably overlie poorly -indurated shale of the Upper Cretaceous Seabee Formation. XIY: Feet 6228700 6208700 6188700 6168700 6148700 6128700 6108700 6088700 1489900150990015299001549900156990015899001609900162990016499001669900 G . East Simpson Test Well #1 Drew Point #1 South Simpson Test Well #1 CT -1 Aklaq #6 Puviaq #1 C -t Aklaq #2* A -A. Arbitrary line displayed on Figure 2-4. C -C: Arbitrary line displayed on Figure 2-6. B -B: Arbitrary line displayed on Figure 2-5. Inline 257 and crossline 308, displayed on Figures 2-7 and 3-1, respectively. Figure 2-3. Base map with orientation of seismic lines presented in this report. Report No. 27.1501-2886 Page 11 of 40 0 z 0 N N 0 N rn NORTHWEST SOUTHEAST NORTHWEST WELLSITE STUDY AREA NORTHEAST East Simpson Test Well #1 CT -1 Drew Point #1 Offset tft): 0.000 0.500 u REDACTED M. GUN 3/2/2020 Figure 2-4. Arbitrary regional line between East Simpson Test Well #1, the proposed CT -1 well and Drew Point #1 showing regional geologic conditions. cost 3=D =r - C ao0rn jam . ZZ M z G) (Dn A< ;1; 0 D to Z Dn (n to M rn Cn 3 M z M O O rn M 0 0 c til M Q Puviaq #1 SOUTH-SOUTHWEST- 48627 ft Offset (ft): 20000 30000 40000 50000 60000 70000 0.000 39 Nanushul WELLSITE STUDY AREA CT -1 NORTH-NORTHEAST 1 80000 90000 100000 110000 • 10,000 ft '...,4IZON ,41._$}� ;6 K,�yti"ryrz.�i•��;. '- ..''i 4 `s.. ..> •1' �:•. _' ... S"S..I._ dor-x'F ::... 1.•,. REDACTED 3=D q>m =Ir—C as0(7 < z > >m DDG) (A ,'D < 0— in z NO m m NU) 9 m z M. Guhl 3/2/2020 Figure 2-6. Arbitrary line across Puwaq #1 and proposed CT -1 well location snowing regional geologic conaitions. 0 0 A O Aklaq #6 CT -1 N N n SOUTH-SOUTHWEST55741ft 3 NORTH-NORTHEAST = D Offset (ft):0 10000 0000 30000 40000 50000 60000 70000 ( 80000 90000 100000 110000 W O y 0.000 j * m 10.000 ft Z ....w�e:'.iwa ♦ .�T..` "-i� yf' a+. +. J ��.-n~+9 D rN M .,',�.w�,•,a,�� +ip�,r�"' 1 'i i. _ 505 1 ORIZON 1 �> • A>`�H, i"r` y A < ��84 " GIPS!.. - '88 BIP.i•1' 'y"^�`� 3' D D Z Base Permafrost T"�"+_^� ..,�,,,��` •Y ,N` y ~ ! 3 ORIZON 2ty.K,>df m 448 G' r+t+wr."yC"BGHS` i ° 4+"'.-fyA �f (f)"c"�,_-. ..'1483° ar ! u'-> - Ul 0.500--�+.:�;, ".."-- Z FD "- ` 2444—x --HORIZON 3 41 y�. . y 4 0 N -O t •D m'~3153' orok 9 1.000 ... _ _. .�.:.. .,... REDACTED M. Guhl 3/2/2020 Figure 2-6. Arbitrary line across Aklaq #6 and proposed CT -1 well location showing geologic conditions. E! 0 channels of mmimlon elmsba v ehce pt 1%mv (eta. below Horizon mese Iebiailybaa channels increase In sloe with depth w11¢te they wn areMualty be delineated,,,wilt ve andi vanane anabNe mn 1. neew twdr ape). rner pereelry appear b be shale Hasa. but slrc axle Sand! layers. tpomb m reaoMe, ere pride. Octad "o D CT�t sore t DWLp <bhda ROIRRWEBT ; soixhm A0T Ps 1 A 9$ ti-�--x—eMe.tran I 1 l =1-- 4-13, u 11 mow_ 1s• CTED uhl3/2/2020 ---- _taflasd6elwaentbrizorodand s. Nora: Images M1om PoalSlaakAllondbn.Enh.hoodhill �0 Propoeed Ch1 well, eudac. I.i,e,on [gTI Passible large-ecalarotetlonal slumps (kfl) N_ it ' ' GRINORTH , } DIP of mmknum elmlleMy silo. 131 nor (1,300 flt below Hendon a. A seam d distinct rorllre9sl-IeMlrg charred, bland the DrogladM Meadels. The 1hannel3 display $ome of the highest regalia ampOtudes in the eludy area tul . dpM). Iargo-sae, mdmvest-wwheest Irendirg slump fealmesareclearly evldbtin the dower forret elate. Figure 2-7. Channel features and amplitude anomalies corresponding to the Torok clinoforms. 3=D -i D m = r C 03 0 V3 >:Em ZZ DNm rM N < �Eft z N N M ur N 3 M z v O 'U O V3 M 0 0 4 JC C m r r 40 V a. n .roo woo rseo 3 vatmla ablated. m tbrde e,tractlon hom 180 ma to 3110 rte below woe nlorizon a (eta It to 1,311011 bebw Horizon <r The ralidbady Mph m0ative amplitude. may ba eadl.be of hob gee In Doterllelry eaNy channel deposits. Attemathaly, may may simply Indicate el Ithobpc boundaries glory the chamsi marpitw aas.aeted xfth the Ilodepeadiono .mot«ceM abate. The turbidity -flow channel., IMm-s1oDe channela, and sial features ledlea s that the 05na" fur.eh ere broadly sodded by mem wasdrg prove... Them teal. helped to bund the Vopredlrg Chneftems mH show that masa wabi mMributod to the h.imved miyallon ad the mnpleadat The magnitude m the pa ltafloml f¢Iwas that orteced the dlrofem foresed, remalre ureeneln. However. them images luustmte that theaedate candenrwete relatively one, .leen. DIP of mmknum elmlleMy silo. 131 nor (1,300 flt below Hendon a. A seam d distinct rorllre9sl-IeMlrg charred, bland the DrogladM Meadels. The 1hannel3 display $ome of the highest regalia ampOtudes in the eludy area tul . dpM). Iargo-sae, mdmvest-wwheest Irendirg slump fealmesareclearly evldbtin the dower forret elate. Figure 2-7. Channel features and amplitude anomalies corresponding to the Torok clinoforms. 3=D -i D m = r C 03 0 V3 >:Em ZZ DNm rM N < �Eft z N N M ur N 3 M z v O 'U O V3 M 0 0 4 JC C m r r 40 V II[a 113117 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA 3. SHALLOW GEOLOGIC CONDITIONS NEAR THE PROPOSED CT -1 WELLSITE 3.1 Stratigraphy The overall structure of the tophole section conforms to the northeasterly -dipping sediment consisting mostly of clastic Cretaceous sediments. The structure maps for Horizon 2 and Horizon 4 display those trends (Charts 2 and 3). Interbedded shallow marine and nonmarine sandstone and shale of the Nanushuk Formation comprise most of the 4,000 -ft thick tophole section. The lower part of the tophole section includes more steeply -dipping clinoforms of the Torok Formation, which include mostly outer shelf and slope claystones and siltstones. CT -1 SOUTHWEST * NORTHEAST Onset (it): 0 10000 120000 30000 40000 aHonzon 2 4 _1 E 0.500 —m � Horizon 3 Horizon -" 777 t REDACTED M. GUM 3/2/2020 .p...- - .. v. v....n..v ___ .......... o........ yw,Vyw w„VluvnJ Ilea, MV P1UPU OU l 1-1 WCHbILU. Surface to Horizon 1 (Unit 1). We estimate that there is probably about a 100 -ft to 250 -ft thick section of surficial Quaternary sifts, sands, and clays. Thicknesses are likely to be variable beneath the Ikpikpuk River Delta. Across most of the study area, seismic correlations to East Simpson Test Well #1 and Drew Point #1 suggest these sediments unconformably overlie a few hundred feet of poorly -indurated siltstone and silty claystones of the Seabee Formation. Thin sandstone interbeds are possible in this section. A Nanushuk unconformity appears to form the base of the section. Report No. 27.1501-2886 Page 16 of 40 Horizon 1 �' _ a �. Z:;y.�TonM Gas Hybale Statin: Baca lmeoannq Ge�malrz aHonzon 2 4 _1 E 0.500 —m � Horizon 3 Horizon -" 777 t REDACTED M. GUM 3/2/2020 .p...- - .. v. v....n..v ___ .......... o........ yw,Vyw w„VluvnJ Ilea, MV P1UPU OU l 1-1 WCHbILU. Surface to Horizon 1 (Unit 1). We estimate that there is probably about a 100 -ft to 250 -ft thick section of surficial Quaternary sifts, sands, and clays. Thicknesses are likely to be variable beneath the Ikpikpuk River Delta. Across most of the study area, seismic correlations to East Simpson Test Well #1 and Drew Point #1 suggest these sediments unconformably overlie a few hundred feet of poorly -indurated siltstone and silty claystones of the Seabee Formation. Thin sandstone interbeds are possible in this section. A Nanushuk unconformity appears to form the base of the section. Report No. 27.1501-2886 Page 16 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA _P[aR1311 Horizon 1 to Horizon 3 (Units 2 and 3). Horizon 1 was the shallowest mappable horizon in the study area and it generally appears to correlate to the top of the Nanushuk Group (Figures 2-4, 2-6, 3-1, 3-3, 3-4, and 3-5). The Albian-Cenomanian Nanushuk Group consists mostly of siltstones, sandstones, and shales with some carbonaceous shale and coal. Horizon 2 was picked because it was easily mapped, but it also appears to mark the top of a relatively sand -rich section. Horizon 3 to Horizon 4 (Unit 4). Horizon 3 was mapped near the base of the Nanushuk Group; however, correlations to the surrounding formation top picks in offset wells remain uncertain (Figures 2-4, 2-5, and 2-6). Unit 4 consists of mostly siltstone and shale topset beds. These topsets mark the top of the northeast-prograding foreset beds (Figures 2-4, 2-7, 3-1, 3-3, 3-4, and 3-5). Horizon 4 to Depth Limit of Investigation (Unit 5). The depth limit of this investigation is 1 second (-4,003 ft TVDss). Unit 5 consists of the prograding Cretaceous clinoforms of the Torok Formation containing mostly siltstone and shale, but channel sandstones are likely in the lower few hundred feet (Figure 2-6). 3.2 Permafrost The base of permafrost is consistently about 1,000 ft TVDss in the surrounding onshore offset wells and projected to be about 1,200 ft TVDss in the outer part of Smith Bay (Figures 2-1, 2-3, 2-4, and 2-5). The base of the ice bearing permafrost is however estimated at —906 ft TVDss at the proposed CT -1 location. There is no hard data available concerning the top of permafrost and internal structures, which are undoubtedly far more complex. We do know that the relatively warm seawater degrades the permafrost from the top down, but some degradation also occurs from below. For purposes of this assessment, we had to adopt the simple model of a seaward -thinning permafrost wedge. The permafrost model assumes that the top of permafrost probably drops off sharply seaward in Smith Bay, but may still be present in the upper 100 feet of sediment. However, the delta and distributary channels, submerged thermokarst lakes, possible submerged shoals, and a changing shoreline undoubtedly produce significant local variations in the permafrost. There are numerous active thermokarst lakes in the Smith Bay area (Figure 1-1) and those lakes, as well as the recently drained lakes, probably have a substantial thaw bulb of low-velocity material under them. Rising sea levels have submerged many thermokarst lakes and formed small bays and inlets. Smith Bay may include numerous submerged thermokarst lakes that produce similar low-velocity zones. The distributary channels also produce thaw bulbs. The year-round flow of relatively warm water from the delta distributary channels may produce the most significant permafrost degradation in the study area. Shifting channels produce both vertical and lateral variations in permafrost distribution in the shallow section. The shifting coastline and channels probably produce zones and layers of thawing and refreezing. 3.3 Gas Hydrates and Free -Phase Gas The identification of possible gas accumulations and hydrate layers were a principle concern of this study. We ran multiple attribute searches, at 100 millisecond intervals, and on the multiple data volumes in Report No. 27.1501-2886 Page 17 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA ?[aR0 attempts to identify the shallow gas and hydrates within the 7-mi2 study area. We extended several attribute searches to the surrounding offset wells for comparison. We found no geophysical evidence to delineate the BGHS. Tighter and overlapping attribute search windows were run at the reported depth of the BGHS (-1,600 ft TVDss). We found only limited evidence for potential gas (elevated amplitudes with potential trapping mechanisms) away from the proposed CT -1 wellsite (Figures 3-3, 3-4, and 3-5). However, we found no other direct hydrocarbon indicators (DHIs) e.g., phase reversals, velocity pull - downs, and flat spots are difficult to assess in many areas due to the lack of reflection continuity. In addition, none of the numerous surrounding offset wells reported significant gas shows in the tophole section. 3.3.1 Gas Hydrates The gas hydrate stability zone is calculated to be from about 805 ft to 1,615 ft TVDss in the CT -1 area (Collet et al., 2008; Lewis and Collett, 2013), Figure 3-2. The base of ice -bonded permafrost is estimated to be about 906 ft TVDss (USGS, 2013). There is some potential for ice -bonded, pore -space hydrates within that 100 -ft overlap and within the overlying ice -bonded permafrost to about 400 ft TVDss based on calculations from Dallimore and Collett (1995). The tophole strata within the gas hydrate stability zone are mostly fine-grained sedimentary rocks where minor amounts of hydrate may be present in the form of disseminated small crystals, nodules, and fillings in lenses and partings. The potentially sand -rich strata, beneath Horizon 2, have greater potential for significant hydrate accumulations (Figure 3-3). Surface to Horizon 1. Amplitudes between the surface and Horizon 1 are variable. There are strong peak -over -trough, positive polarity reflections, above the zone of gas hydrate stability, but within the permafrost. These reflections are associated with Horizon 1 and they are very unlikely to reflect free - phase gas or significant hydrate (Figures 3-1 and 3-2). Unconformities can also produce strong peak - over -trough signatures and Horizon 1 probably represents a major transgressive marine flooding surface at the top of the Nanushuk Group (Mull at al., 2003). The arcuate, northwest -southeast trend of bright amplitudes also appears to conform more to the delta -front morphology than it does to stratigraphic trends (Figure 3-2). Seismic velocities in permafrost are primarily controlled by ice content rather than lithology (Ramachandran et al., 2011). A sub -ice unfrozen zone surrounding the delta front or variations in ice content are more likely to produce the sharp contrast at Horizon 1. Horizon 1 to Horizon 2. No anomalous, negative or positive, amplitude responses were identified in this low- to moderate -amplitude section. Hydrates may be present in the form of disseminated small crystals, nodules, and fillings in lenses and partings, but significant accumulations are not likely. Horizon 2 to BGHS. Seismic amplitudes range from moderate to high where Horizon 2 is above the BGHS (Figures 3-1, 3-3, 3-4, and 3-5). There is slightly greater potential for hydrate accumulations between Horizon 2 and the BGHS because the interval appears sandy. In some areas, there is also a very tentative stratigraphic correlation to negative high -amplitude reflectors below the BGHS on the eastern side of the study area (Figures 3-3 and 3-4). Report No. 27.1501-2886 Page 18 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA k6M1 N o a000 eaoo ,z000 RNORTH �Wt Y q,l yt sn tow f Proposed CTANL we0, v surfacelocation '550, Stmeture contours in feet on Horizon 1, Shoreline possible Nanushuk 4 HIGH Notes: 1. Images from PostStack-Migration-EnhancedNMO 2. $.soot Permafrostand ease of Gas Hydrate Stability from USGS Open File Report99-015 and USGS Scientific Investigations Report 2019--5050, respectively. Figure 3-2. Vatmin volume attribute extraction from 20 ms above to 20 ms below Horizon 1. The relatively high negative amplitudes appear to represent the trough lobes of a strong peak -over -trough, positive polarity reflection at the depth of Horizon 1. Signal strength is amplified along the trend of the delta front, which may reflect a shallow, unfrozen sediment zone above the permafrost and below the shore -fast ice. 3.3.2 Free -Phase Gas The potential for encountering shallow gas ranges from negligible to low in the tophole section for the study area. Shallow gas problems were not encountered in the surrounding offset wells, which penetrated nearly identical stratigraphy to the depth of this study. There is slightly greater potential for gas beneath the BGHS and in stratigraphically favorable conditions, but away from the proposed wellsite. BGHS to Horizon 3. The decreasing amplitude with depth within this interval probably corresponds to decreasing sand content. There is an area of anomalous, negative high -amplitudes on the southeastern side of the study area, but at least 1.8 miles southeast of the proposed wellsite (Figures 3-3 and 3-4). There may be free -phase gas trapped beneath the BGHS in this area. However, a detailed analysis of this area did not reveal any of the classic juxtaposed leading -peak event above the BGHS with leading -trough events below the BGHS (high to low velocity change) that would be indicative of free gas. In addition, the area of elevated amplitudes does not conform to the northeast -dipping stratigraphic trend and there were no other direct hydrocarbon indicators (DHIs) e.g., phase reversals, velocity pull -downs, and flat spots. Report No. 27.1501-2886 Page 19 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA ?ORB However, free gas is still possible in this area below the BGHS because the anomalous strata appear to be sand rich and because the BGHS provides an efficient trapping mechanism. Horizon 3 to Horizon 4. No amplitude anomalies were identified in this stratigraphic section. The moderate- to high -amplitude basal portion of this topset section is well bedded with most of the seismic energy in peak reflectors. Onlapping high -stand wedges may cause the slightly brighter amplitudes in the northeast, but there is no acoustic evidence for gas accumulations. Sharp lithological boundaries, thin -bed tuning effects, and unconformities probably produce most of the high -amplitude peak -trough reflections that are common in the topsets between Horizons 3 and 4. Horizon 4 to Depth Limit of Investigation (Unit 5). The section generally consists of siltstone and shale with low- to moderate -amplitude reflectors. However, thin sandstone layers are possible and Houseknecht (2014) suggests that these clinoforms may have served as migration pathways from the Lower Cretaceous gamma -ray zone (GRZ) source rocks in other areas. There is a small area of anomalous negative amplitudes below Horizon 4 and about 2 miles northeast of the proposed wellsite (Figure 3-5). Based solely on the amplitudes and potential stratigraphic trapping mechanism, free gas, trapped beneath the topset beds, may cause this anomalous area. Alternatively, the high amplitudes may represent relative increases in sand content and not free gas. There were no other direct hydrocarbon indicators (DHIs) e.g., phase reversals, velocity pull -downs, flat spots, and frequency loss in this area. 3.4 Other Conditions We found no evidence for other site conditions that would adversely affect exploratory drilling operations. Report No. 27.1501-2886 Page 20 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA -r 1311111113 Oesel lhl 0006NORTHWEST a1 T 0 10000 20000 30000 60000 SOUTHEAST Umt1 ; Top I gas hr`d ate i z H an 1— Unif 2 ♦ A; W ti �. 1n,\ r ( _..: . vM beano-pdrmafr Horizon 2 roat'`�y{ � _ _ � �J'.aF�+ 0500 Unit r 4 ' �+ TROUGH.OVER-PEAK - FUnit 4���� !s " Horizon 4, 0eadm,trough events below Ne BGHS (high to low vebctly change) may Indicate tree -phase gas, in silty to sandy strata, batted beneath the 8GHS. 3 anels Chn These latemlly-extensive, negative amplitude anomalies do not continue updip F Unit F` )` above the eGMS, which somewhat supports the potentlel for gas. These j 1 continue updip the area of the proposed wellsi where Me positive polarity lana _ ! -a O reflections (A80VE) have some potential br hydrate (your. However,)doesthe 1000 ,a .--„-„.�,.. ! a�l� area of levatetl negative am It Des al ihrs depth Fi depth e 9 _ _Pio G ( gore 12) does not REDACTED M. Guhl 3/2/2020 Figure 3-3. Identified amplitude anomalies in the shallow section. Report No. 27.1501-2886 Page 21 of 40 m * to U)n a C14o - Ir woo rtooe 1 n m Z Often (11) 0 10000 * 20000 30000 40000GRID = r C O yV 0000 NORTHWEST SOUTHEAST NORTH W O:o D`tm Z six •, �—���� _, z s. — D n -_ .. duration 2 T_ F'�'•��' EnractbnlMemal � y q M•- •••� ,..EIx ~--_ %•v -taw - q,�:. m Los ..� o s d N m = ProposdeCT.- NL wall, r- rL m race r vmmin volume admbute osspo cdon from 40 rrs mous to 40 me below In. repMed head of gad hydrate r rtffillky (BONS). The relatively high negative amplitudes In the east am generally below the reported depth of the BGHS for thls eA etlmn metanalL However.. datallad analysis of this ems did out reveal any of the classic )uMeposed leamnMpeak ever) above the BGHS with leading -trough everts below the BGHS (high to II vamoity charge)that.i,kbe NdlcM.ofkedgas. Insomuch Ins area of elevated ampliWtled rices rotcoKorm mIM1e REDACTED ronheast-tippng dretigrepnic moot and sinulady elevated amplitudes are common In this area belwoen Homans 2 and 4. These elevated amplitudes on the daemon vide of Smith Bay may added lamml velocity charges in me shallow permafrod section. However, free gas is still possible in this area be. Ine BGHS, Note.: 1. lmagdefrom POdStackWigrdion-Enha ced O 2. Base of Pammfroct and Base of Gas Hydrae SlabgOy from I Open File Report 99-015 and USGS Selen Me lnveeigMiane Report 2013-5050, mopedlvely. M. GUN 3/2/2020 Figure 3-4. Amplitude anomalies near the base of gas hydrate stability. m �N N O O O My ;x> z =iDm F- r' Z = r C cT1 W O Ug V ? N ..v. =Z ORsat(IU: o i laced 20000 wood f ; . wad sand 1. y � M m S g.OUTWE HST 1WRTMEAST Gain r G) bXTH N to AmplRuda try Eelope daplay showing 4INon 1t reflection immid th and soman The mfleaors T\ gobaby represent the combined resporse of .:. — ..I - _ seveml interfaces, however we of the energy M '• ' I . • ~ - la In the peak reftichn n the basset beds a . ` , ,:yl y t - Homan 4, whereas may energy s concentrated ✓ .ste�a� (n In the tough reflector in the fooset hotly below Y^� m _ Isms S 1 PPmmaforl HMxpn d. t` 40 m N d Sharp Indo cru bourNtles ihably eduo. s 4 enacts end urcoMONtl.a probably produce most of the m comm sada the ekarougn w �'�Y _ " m redviamba that are common n aha tarsals 4 Z =15% nX 4SUNgtY between Honrorn ]artl 4. - w+' \a 1 � ..,,� 1 � � :o" Proposetl CT-i ! � E`;'- j -tea �L 4 O F _ 1 i-••_. y i•� ♦ tow O IN]ETA m Extraction� —.. d F HwH IEDACTED Vitamin volutre itMbet. exbaalpn from bliadmn 4 to toe me below Ibrl... 4 (-400 It below Horhon 4) ahowNg on area eT elevated negative emdRedes ber ealh lapsed bed.. The relatively Ngh negative empli,udas may be indicative of from gas trapped beneath (000 beds. Amplitude aromefies in the in the upper -1.000 R of pogradimq c6rofomm beds are new in the sNdy scone_ Tha section generally cormdsts of si94gre and net.. However. thin candatone layers are possible and HouseknecN, (2016) suggests that these c4ndlomme may have served as migration pathways from GR source ocka in other areas. However, the high sm Ndudes probably represent relative Ir amosas in sand content and not free gas. Them were no other direct hydrocarbon Indicators(OHIs) ag, Mase reversals, velocity pYLdowra, flat arms, and frequency lass in are area. M. Guhl 3/2/2020 Figure 3-5. Analysis of amplitude anomalies in the upper Torok Formation near Horizons 3 and 4. m w o o O �GR® CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA 4. SHALLOW GEOLOGIC CONDITIONS AND PORE PRESSURE ASSESSMENT FOR PROPOSED CT -1 WELL 4.1 4.2 Introduction At the request of CAELUS, FGCI has undertaken a review of the available information, including offset well data (Figure 4-1), seismic correlations, and amplitude analysis to produce a site specific tophole prognosis chart and pore pressure (PP) assessment for the CT -1 prospect. X/Y: Feet 6188700 6163700 1484900 1509900 1534900 1559900 1584900 1609900 1634900 1659900 East Simpson Test Well #1 South Simpson Test Well #1 0 6138700 a I 6113700 6088700 Aklaq #2 0 6063700-,—.- Aklaq #6 0 Drew Point #1 0 CT -1 • Study Area Puviaq #1 0 Figure 4-1. Relative location of offset wells used for the tophole prognosis chart and pore pressure assessment with respect to the CT -1 proposed location. FGCI has reviewed available log data and post -drill documents summarizing well -drilling operations and well events for six offset wells in the vicinity of the CT -1 prospect (Figure 4-1). The wells reviewed include: Aklaq #2; Aklaq #6 (although PP chart not included because is very similar to Aklaq #2); Puviaq #1; Drew Point #1; East Simpson #1; and South Simpson Test Well #1. Review summaries of documented well events while drilling are included in Section 4.4. Site Specific Shallow Geologic Conditions and Tophole Prognosis Chart On the basis of the seismic interpretation performed and supporting information from offset wells, shallow geologic conditions at the proposed CT -1 location are assessed as favorable for drilling operations. The proposed CT -1 well is planned with a deviated trajectory that will intersect Horizons 1 to 4 in the shallow section to a depth limit of investigation of 4,003 ft TVDss (Figures 4-2 and 4-3). Report No. 27.1501-2886 Page 24 of 40 Alp CAELUS ENERGY, INC. ORD SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA The amplitude extractions performed suggest that areas of higher potential for shallow gas accumulations are more than 10,000 ft away from the proposed CT -1 location (Figures 2-7 and 3-3). Discrete amplitude anomalies identified within 20 mili-seconds above and below Horizon 1 and within a radius of 100 ft from the proposed surface location are interpreted to be the result of non-uniform sediment conditions within the permafrost and the surface ice cover (Figure 3-2). Gas accumulations, if present within this interval, are considered small and low pressured. The interval comprised by Horizon 4 above and Horizon 5 below, contains isolated amplitude anomalies that are more than 200 ft away from the proposed CT -1 wellbore (Figure 2-7). This sequence contains channel features and prograding structures that suggest high sedimentation rates at time of deposition, however relative dating assigns an early Cretaceous age for this sequence (Mull at al., 2003) which also suggests that if overpressure conditions were generated as the result of undercompaction, such pressures have been likely released through geologic time. A detailed lithological description of the sedimentary sequences intersected by the proposed CT -1 borehole as well as the assessed potential for shallow hazards are presented on Figure 4-3 in the tophole prognosis chart for planning of drilling operations. Offs N 3 M-1 PEAK REDACTED M. Guhl 3/2/2020 ORO CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -I WELL SMITH BAY, ALASKA Ala DEPTHS ASSESSMENTS X=1603017.574 Y-0524211.111 HORIZON S INFERRED LITHOLOGY AND TYrt THICKNESS D TVD FEET TAD FEET Hlgbly unllkety Fmeewe INSETSEISMIC PROFILE REPRESENTS SEQUENCE CONDITIONS BSS (FEU)Mpgibk: AN ANBITRARY NE ALONG THE WELL PATH DESIGNATIONS U ML ass (.0 Lew: Unlitaly presence rPeedP.m.;n,Itihi on ma S PROPOSED CT -1 WELLSITE N Probebm meoemtltivleb SHALLOW HYDRATE OTHER Several feet of surBcial Ikpikpuk River clays and sits at 1000 2000 3000 400C the sea floor. GAS BEARING CONDITIONS PRESENCE SANDS 0.000 ( SEAFLOOR 0 5 0.002 - is" CAUSING POINT 10010 250 It of paodY-soded day, sill and sand. ' 483 REFERTO Mostly poody4nduraled siltstone and silty claystone with some NOTE 1 1 !PTERR,11E. sandstone interbeds. HORIZON 1 �_. 483 488 0.153 ...... " iOP OF CASNYDRATE �'"^�"^^mem- 800 SOS 0.245 STABILITY BASE OF ICE Interbedded shale and siltslone with thin sandstone and 901 906 0.273 767 BEARING PERMAFROST coal layers. HYDRATES HORIZONY w 1250 1255 0.369 m LU BASE STABILITY Mostly sandstone with siltslone, dayslone, and Coal layers. 1610 1615 0.464 OFGAS HYDRATES 0.500 - - -1 w_ 1219 REFER TO _... — - NOTE 2 F Mostly claystone with siltslone and some sandstone and shale 3-� interbeds. HORIZON 3 O — 10314" CAUSING POINT 2460 2504 2485 2509 0.671 0.682 433 HORIZON 4 • - 2893 2898 0.770 _, ,1 Mostly siltslone and shale. ' -- REFER TO 1105 NOTE 3 Siltslone and shale with disconfinuous channel sandstones. _., DEPTH LIMIT OF 3998 4003 1.000 INVESTIGATION 740 4738 4743 1.153 HORIZONS 1. Th.. in p..In Internal mlmr gas m rM pmmnwath Eaae4 en repom matter Ptabli kl. Notes 3. Them m some pmmBml for gas trapped ber-am Na ar elgm M1ytlnm smWlay; Iwwwaq tllan is no daYeamml[eNtlen[e for gas al maOepID. 4. Them Is some potantlal for gas trapped benwlM1 mpsH wnflnln8 am. a. oma M Pamw/roal and Beae oI Ges Hy4ram SIabIIHy frml USGS Opan FIm RapM 9Sd15 anal Uafia SabntlM Invaatlgatlor,f Report 201]-5058, respatllvely. ACTED TOPHOLE PROGNOSIS CHART, PROPOSED CT -1 WELLSITE M. Guhl 3/2/2020 �GRO CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA 4.3 Methodology FGCI conducted a post -drill pore pressure analysis for each of the offset wells reviewed and the corresponding results are included in Figures 4-4 through 4-8. The pore pressure prediction for the CT -1 prospect was carried out mainly on the basis of offset well data and well events which offer a more reliable foundation to evaluate pore pressure and geohazards in the area. Estimation of the pore pressure was also performed using Eaton's empirical method (Eaton, 1975) which applies the following equation: PPG = OBG — [OBG-PPGhYd] - f where: PPG= in-situ pore pressure gradient (or formation pressure gradient); OBG = overburden pressure gradient (i.e., total vertical stress); PPGhyd = hydrostatic pore pressure gradient, and V = empirical correlation parameter that depends on the type of data used in pore pressure evaluation (e.g., drilling parameters, resistivity, velocity, etc.). The overburden gradient was calculated from the density logs for East Simpson #1, South Simpson #1, and Drew Point #1 for which log density data were available; whereas the hydrostatic pressure gradient in this case was considered to be 0.44 psi/ft. In the case of the CT -1 prospect, the empirical correlation parameter Pwas defined as the quotient to the third power of the interval seismic velocity and the normal velocity which provided consistent results compared to what was expected based on pore pressure trends generated for offset wells: where: P = (Vint -seismic /Vnormal)3 Vint -seismic= interval velocity (provided by NordAq for Tulimaniq #1) Wormal = normal velocity in the shales corresponding to the investigated area. The normal velocity (Wormal) was calculated using the available log data from which a normal linear compaction trend (based on transit time) was generated for each well and a subsequent compaction trend assumed for the CT -1 location. Estimation of the fracture gradient for offset wells is based on available LOT or FIT data as well as calculations using the equation below (Eaton, 1969): where: FG = PPG+ (OBG - PPG) x u /(1 - u) FG = fracture gradient u = Poisson's ratio (estimated from offset well data and literature) Report No. 27.1501-2886 Page 27 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA ?IMIR0 In addition to the calculated FG, an adjusted FG curve is also provided based on observations from well events documented in offset well logs and daily drilling reports (DDR). The integrated pore pressure prediction for the CT -1 prospect is presented in Figure 4-9. Estimation of the pore pressure gradient uncertainty was performed using the information available for offset wells and the corresponding pore pressure calculations. The uncertainty was determined as the mean value of the maximum and minimum difference between pore pressures generated from well events and calculated from Eaton's method at same discrete depths. 4.4 Post -drill Offset Well Summaries Aklaq #6: ■ Tight hole encountered at 3749 ft MD. ■ 1170 units of gas at 4723 ft MD. ■ 1140 units of gas from 4874-4935 ft MD. ■ 1140 units of gas from 5970-6000 It MD. ■ Frequent connection gas from 6529 It to 6968 ft MD ranging from 319-836 units. ■ Casing point (7 -inch) at 7050 It MD. ■ Loss of returns at 7125 ft MD with 10.05 ppg mud weight (MW). ■ Regain returns at 7163 ft MD with 9.9 ppg MW. Report No. 27.1501-2886 Page 28 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA Aklaq #2: ■ Gas zone from 2593-2621 ft MD with up to 1510 units. at Connection gas from 2593 to 3535 ft MD. ■ From 4990 It to 5140 ft MD up to 1441 u of gas. is From 6054-6061 ft MD gas sand. is From 6160-6172 It MD gas sand. is From 6188-6198 It MD gas sand. ■ Partial circulation losses at 7624 ft MD. is Lost well in the interval from 7200 ft to 7680 TVD. Cut drill -line and performed sidetrack. ■ Losing mud and gas peaking at 8300 ft MD. 0 Aklaq 42 Post -Drill Pressure Analysis 16... Adjusted FGA OBG 1000 Calc.J 2000 9 5187 3000 � o MW' t 4000 c n 0 _. 5000 PPG from I events well 6000 0 KGP 0 7000 '� 77 e' 8000 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Pressure Gradient(ppg) Torok. Formation HRZ Shale IiiiiiiiiiiiiiKupamh tcu BCU Kugrua Kul, n,3 Tip The original wellbore was lost during reaming operations as a result of the collapse of the Milluveach Shale section between the LCU & BCU. _P 11311141113 Neutron porosity Gamma ray (API) 0 50 too 0 200 400 600 Figure 4-4. Post -drill pore pressure analysis for Aklaq # 2 well. The dots in the gamma ray chart correspond to points of significant gas shows. Report No. 27.1501-2886 Page 29 of 40 i6"ill CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA Puviaq #1: ■ Shallow gas identified in the shallow section. Traces of methane were measured from 200 ft MD with a peak at —550 ft MD. ■ MDT data provide a more accurate pore pressure profile for the well. ■ Possible occurrence of methane hydrates around the base of permafrost indicated in the pre -drill report. Puviaq #1 Post -Drill Pressure Analysis 0 1000 2000 3000 x i s CL p 4000 5000 7000 2160 Quaternary Torok Formation HRZ Shale LCU Simpson Intv. Kingak, TiR Tight hole while POOH The shallow section in the Puviaq 1 well contains methane gas. Traces of methane were first identified at 200 ft MD (-143 ft TVDSS). The higher amount of methane was encountered at 550 It MD. Overburden and fracture gradient were estimated using pre -drill and post -drill data. Logs not available. Figure 4-5. Post -drill pore pressure analysis for the Puviaq #1 well. ICT ., Report No. 27.1501-2886 Page 30 of 40 20 �<. Estimated OBG /\ ... _._.-. 133/8., Adjusted FG MW ( Ill C 1 71.' I -;ir� 9 5/8" li t PPG based on MDT and well events 1 7 I ..:.. 7,. A 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Pressure Gradient(ppg) Quaternary Torok Formation HRZ Shale LCU Simpson Intv. Kingak, TiR Tight hole while POOH The shallow section in the Puviaq 1 well contains methane gas. Traces of methane were first identified at 200 ft MD (-143 ft TVDSS). The higher amount of methane was encountered at 550 It MD. Overburden and fracture gradient were estimated using pre -drill and post -drill data. Logs not available. Figure 4-5. Post -drill pore pressure analysis for the Puviaq #1 well. ICT ., Report No. 27.1501-2886 Page 30 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY. ALASKA ?13RID Drew Paint #1: is At 2008 ft TVDss reading of 120 units of gas. is At 6867 ftTVDss the borehole was caving in. ■ Possible overpressure may have existed at the Base of the Torok Formation and in Pebble Shale Zone. Pressure calculation in the interval is not consistent with the drilling record of the well. Drew Point #1 Post -Drill Pressure Analysis 0 20" ` OBG Cala FG 1000 H �l 2000 C r I3 3%8A / Mw , �I r 3000 4 f'. Adjusted FG x G 4000 1 o a 1� 5000 PPG based on 'I well events o 6000 0 to 9 5 o As 7000 ° 6000 8 9 10 11 12 13 14 15 16 17 18 19 20 Pressure Gradient(ppg) Travel Time tpsRt) Gamma Ray (API) 0 50 100 150 200 0 100 200 300 I bile snare K ngak,Fm Sag R vet Saner. au m. Iwsn Mm: a..vmn a RT., Figure 4-6. Post -drill pore pressure analysis for the Drew Point #1 well. The red line on the travel time curve corresponds to the assumed normal compaction trend. Report No. 27.1501-2886 Page 31 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY. ALASKA ?URD East Simpson Test Well #1: ■ Tight hole encountered from 5150 It to 5325 ft MD of a bit trip. ■ Pressured shale reported at 5365 ft MD. ■ Water wet sand encountered in the Torok Fm. may contain partially overpressured fluids. ■ Lost returns at 5699 ft MD with a MW of 10.8 ppg. ■ Lost returns at 5782 ft MD with 10.8 ppg. ■ Lost partial returns at 5945 ft MD with 10.7 ppg. ■ Lost partial returns at 6270 ft MD with 10.3 ppg East Simpson #1 Post -Drill Pressure Analysis 0- ..` 20^A Adjusted . Adjusted FG 1000 2000 F7 13 31l rCaIc FG 3000 w PP from 00R& ,� I 4000 well events tB ' �i f r L n 5000 I 1 17 l i. 6000 9 5ra.. 7000 -J� L i 8000 8 9 10 11 12 13 14 15 16 17 18 19 20 Pressure Gradient(ppg) Quaternary a, F Shu r Torok Formation Travel time (pSfft) Gamma Ray e 100 Zoe o 1G0 200 N� TMWNIY � CT -1 Figure 4-7. Post -drill pore pressure analysis for the East Simpson Test Well #1. The red line on the travel time curve corresponds to the assumed normal compaction trend. Report No. 27.1501-2886 Page 32 of 40 I �GRO CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA South Simpson Test Well #1: in Partial circulation was lost from 796 to 950 ft MD. in Circulation losses at 2175 ft MD while conditioning for logging and setting rasing. in After pumping 1750 sacks of cement, returns were lost while cementing the 16" casing. in Lost circulation at 5279 ft MD and 5965 ft MD, respectively. in Tight hole from 5960 to 6445 ft MD while POOH. in Higher PP at 5990-6000 ft MD because of increment in the gas units (1280). in Gas reading of 1536 units registered from 6520 to 6700 ft MD suggesting an increase in pore pressure. The decrease in mud weight is attributed to increased gas concentration. ■ Lost circulation at 7020 ft MD. 0 1000 2000 3000 4000 x t y 5000 0 6000 7000 8000 9000 South Simpson #1 Post -Drill Pressure Analysis Travel Time (pstR) Gamma Ray (APQ 0 100 200 0 100 200 FG 20 '. 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Pressure Gradient(ppg) Torok Formation Pebble Shale Wngak Fm. Sag Rmer Sahel, Shulh k Fm. lvishak Fm. T©.;Argillije SWM Simps�N1155m T.1 Figure 4-8. Post -drill pore pressure analysis for the South Simpson Test Well #1. The red line on the travel time curve corresponds to the assumed normal compaction trend. Report No. 27.1501-2886 Page 33 of 40 Adjusted FG' v o 1 OBG 16. t" Calc FG (PPG from i well events �J ,+ e i o X11.. in 3:4 lt: r {}i o 0 0 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Pressure Gradient(ppg) Torok Formation Pebble Shale Wngak Fm. Sag Rmer Sahel, Shulh k Fm. lvishak Fm. T©.;Argillije SWM Simps�N1155m T.1 Figure 4-8. Post -drill pore pressure analysis for the South Simpson Test Well #1. The red line on the travel time curve corresponds to the assumed normal compaction trend. Report No. 27.1501-2886 Page 33 of 40 CAELUS ENERGY, INC. ORD SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA 4.5 Pore Pressure Assessment for the proposed CT -1 Well, Observations and Recommendations ■ The presence of gas hydrates within the permafrost, although not identified in offset wells, cannot be ruled out. ■ Pore pressure calculations suggest a gradual increase from -4000 ft to -7800 ft up to -10 ppg (Figure 4-9; uncertainty not considered). ■ On the basis of offset well events, the risk of circulation losses increases near the base of the Torok Formation at -7000 ft (Figure 4-9). ■ Within the Sag River Sandstone the difference in hydraulic head in the deepest part of the basin with respect to the CT -1 location accounts for -0.5 ppg overpressure (Figure 4-9) which supports an estimation of the PP of -10 ppg. 0 Pre -Drill Pore Pressure Analysis CT 1 Location 11 a I ts•" FOe� 1000 i'li t i b , I Tentative EMW y,;' ► Illi 2000 r Calc. PPG " ,i t� j '- Cala FG 10 3/4'7 II 3000�a + I � 1• , FG with lower m 4000 ' uncertainty ' I F 5000 ` ' PPG uncertainty `\ based on offset well observations T 6000..-. .I. � o-�:� -I I i �b 7000 o..7 5/87 Zone of possible o � circulation losses '4 y I ' andfor overpressure o , 8000 f 0 Illi 5 A I f 4 9000 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Pressure Gradient (ppg) Quaternary N Figure 4-9. Integrated pore pressure prediction for the CT -1 prospect. Torok Formation Fan Deposits HRZ Shale 1Tdp'L I Krtg Fm ag _ er Sandstone, r'M. ' Shubllk Fmr7 Ivlshak Fm. The comprehensive pore pressure assessment conducted by FGCI in the CT -1 area reveals the following results: 1. No significant overpressure has been identified in the analyzed offset wells in the vicinity of the CT -1 prospect. A maximum pore pressure value of 10.3 ppg was estimated for the South Simpson Test Report No. 27.1501-2886 Page 34 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA ?GRO Well #1 within the Kingak Formation. The evaluation relies on the occurrence of a maximum of 1536 units of gas with a mud weight of 10.3 ppg from —6600 ft to —6900 ft MD (Figure 4-8). With that exception, pore pressure generally stays below 10 ppg in all analyzed wells. 2. As for the offset wells, FGCI calculations do not anticipate significant overpressure at the CT -1 location where the maximum estimated value is 10.0 ppg near the transition between the Kingak Formation and the Sag River Sandstone. 3. Circulation losses occurred in Aklaq #2, Aklaq #6, East Simpson Test Well #1, and South Simpson Test Well #1 and the potential for circulation losses exists at the CT -1, particularly at the base of the Torok Formation. 4. The presence of gas hydrates within the permafrost, although not identified in offset wells, cannot be ruled out. FGCI recommends: 1. Include in the well plan proper procedures to handle the possible occurrence of gas hydrates within the permafrost and discuss them with the drilling crew before well spud. 2. Design a mud plan according to the pressure analysis developed for the CT -1 prospect. 3. Fugro recommends testing the formation pressure after setting the 7 5/8 -inch casing and before increasing mud weight at —7000 ft TVDss in order to mitigate the risk of circulation losses. 4. If gas content and/or connection gas increases, a heavier mud may be required. A tight mud weight window is anticipated from —6600 ft TVDss to well TD, thus the mud weight program may require real time adjustments at the driller's discretion. 5. The execution of a robust well surveillance plan based on MWD\LWD, gas content and cuttings inspection is highly recommended in order to anticipate possible well events. Report No. 27.1501-2886 Page 35 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA 5. WELLSITE SUMMARY 5.1 Introduction ?ORD Various tophole drilling considerations are discussed and assessed in this section. Figure 4-9 (Section 4) shows the integrated pore pressure prediction for the CT -1 prospect. Figure 4-3 shows the Tophole Prognosis Chart for CT -1 and graphically displays an assessment of shallow gas and other drilling hazards. The tophole strata that will be penetrated at CT -1 are generally similar to those penetrated at several offset wells. Consequently, tophole-drilling histories at these offset wells should generally be representative of conditions that will be encountered at CT -1, and summaries of some well histories were used in making the assessments given here. The important difference is that all of the offset wells were located onshore. CT -1 is in Smith Bay and water depth at well location is estimated to be -5 ft. Shallow permafrost conditions and the associated seismic velocities remain uncertain. 5.2 Location and Description Prnn orl CTA Wall I nratinn NAD 1983 State Plane Alaska 5 ft X = 1603017.574 Latitude: 70.82780008° N Y = 6152421.111 Longitude: 154.31091077° W 16" -Casing Installation. There are probably several feet of unfrozen, modern clays and silts at the seafloor. The underlying sediment is probably over -consolidated and poorly -sorted clay, silt, and sand and probably less than 200 -ft thick. These sediments are also likely to be unfrozen to the depth of the casing point at 100 TVDss. However, the depth to the top of permafrost is uncertain, as is the thickness of over - consolidated sediment. We anticipate soft rock (poorly -indurated) siltstones and claystones beneath the over -consolidated sediments, which are more likely to contain ice -bonded permafrost. The poorly -indurated rocks are probably less than a few hundred feet thick and they overlie mostly siltstones and shales to about 1,260 ft TVDss. The base of ice -bearing permafrost is estimated to be about 906 ft (AOGCC, 2010). There are minor amounts of methane gas in the form of hydrates within the ice -bonded permafrost zone. Degradation of the permafrost and hydrate during drilling may release minor amounts of gas, but we do not anticipate any significant gas accumulations within the overall permafrost zone (0 °C) to about 1,000 ft TVDss. The gas hydrate stability zone is from about 805 to 1,615 ft TVDss. Hydrates were not observed in the offset wells, which penetrated nearly identical strata. However, minor amounts of hydrate may be present throughout this zone. There is slightly greater potential for hydrate accumulations near the base of the hydrate stability zone at about 1,615 ft TVDss because the strata are interpreted to be sandy; however, there was no geophysical evidence for massive hydrates at these depths. The risk for encountering significant hydrate accumulations is considered low. Report No. 27.1501-2886 Page 36 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA _r G"13 There is also a low risk for encountering significant free -phase gas in the potentially sandy strata beneath the base of gas hydrate stability at about 1,615 ft TVDss. We did not identify any geophysical evidence for gas at these depths, but there is still some limited risk because the base of gas hydrate stability has the potential to trap the upward migration of gas in permeable beds. 10 -314" -Casing Point. There does not appear to be any risk of encountering hydrates or gas at the planned casing point depth. The strata probably consist of siltstones and shales with possible thin sand beds. There is again some risk of encountering gas shows in the interpreted channel sands near the base of this investigation at about 4003 ft TVDss. We do not anticipate significant overpressure in the CT -1 location where the maximum estimated value is of 10.0 ppg near the transition of the Kingak Formation and the Sag River Sandstone -7,000 ft to 8,000 ft TVDss. There is some potential for circulation loss near the base of the Torok Formation (-6,600 ft TVDss) based on circulation losses reported in Aklaq #2, Aklaq #6, East Simpson Test Well #1, and South Simpson Test Well #1. Report No. 27.1501-2886 Page 37 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA 6. RESULTS AND RECOMMENDATIONS ?CORD 1. Conditions in the proposed CT -1 7 -mil study area generally appear to be favorable for exploratory drilling. 2. There is some limited potential for shallow gas, away from the proposed drill site. An accumulation of free -phase gas, in sand -rich strata, beneath the BGHS, may cause the area of acoustic anomalies about 1.8 miles southeast of the proposed wellsite. Gas, stratigraphically-trapped beneath topset beds, may cause the area of bright amplitudes about 2 miles north of the proposed wellsite. 3. Any information obtained during the drilling concerning the top and distribution of permafrost in Smith Bay would be useful to future permafrost modeling efforts should exploration continue in this area. 4. The potential for the possible occurrence of gas hydrates within the permafrost and in the possible sandstone interval just above the BGHS should be considered in the drilling plan. 5. The limited potential for gas trapped beneath the BGHS should be considered in the drilling plan. 6. The execution of a robust well surveillance plan based on MWD\LWD, along with gas content and cuttings inspection is highly recommended in order to possibly anticipate well events. 7. Include in the well plan proper procedures to handle the possible occurrence of gas hydrates within the permafrost and discuss them with the drilling crew before well spud. 8. Design a mud plan according to the pressure analysis developed for the CT -1 prospect. 9. Fugro recommends testing the formation pressure after setting the 7 5/8 -inch casing and before increasing mud weight at —7000 ft TVDss in order to mitigate the risk of circulation losses. 10. If gas content and/or connection gas increases, a heavier mud may be required. A tight mud weight window is anticipated from —6600 ft TVDss to well TD, thus the mud weight program may require real time adjustments at the driller's discretion. 11. No other geologic conditions were identified from the 3D seismic data that would be expected to impact drilling operations in the tophole section. Report No. 27.1501-2886 Page 38 of 40 CAELUS ENERGY, INC. Glen SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA Alaska Oil and Gas Conservation Commission, 1992. Summary of the Cirque -1 blowout of February 12, 1992, public record letter from D.J. Ruckel, ARCO Alaska, to D. Johnston, State of Alaska Oil and Gas Conservation, Commissioner, Anchorage, Alaska, 32 p. Alaska Oil and Gas Conservation Commission, 2010. Alaska Geologic Materials Center Formation Tops, On-line Inventory, State of Alaska Department of Natural Resources, Division of Geological and Geophysical Surveys, accessed December 2014 http://dggs.alaska.gov/gmc/inventory.php Alaska Oil and Gas Conservation Commission, 2014. Repsol; Cugruk 2 Well Control Incident Report for the AOGCC Permit to Drill 211-167, 327 p. Bird, K.J., 2001. Framework geology, petroleum systems, and play concepts of the National Petroleum Reserve — Alaska, in Houseknecht, D.W. (editor), 2001, NPRA CORE WORKSHOP — Petroleum Plays and Systems in the National Petroleum Reserve—Alaska: SEPM Core Workshop No. 21, p. 5-17. Collett, T.S., 1993. Natural gas hydrates of the Prudhoe Bay and Kuparuk River area, North Slope, Alaska: American Association of Petroleum Geologists Bulletin, v. 77, no. 5, p. 793-812. Collett, T.S., Agana, W.F., Lee, M.W., Zyrianova, M.V., Bird, K.J., Charpentier, T.C., Houseknect, D.W., Klett, T.R., Pollastro, R.M., and Schenk, C.J., 2008. Assessment of gas hydrate resources on the North Slope, Alaska, 2008: U.S. Geological Survey Fact Sheet 2008-3070, 4 p. Collett, T.S., and Dallimore, S.R., 2002. Detailed analysis of gas hydrate induced drilling and production hazards: Proceedings of the Fourth International Conference on Gas Hydrates, Yokohama, Japan, May 19-23, p. 47-52. Collett, T.S., Lee, M.W., Agana, W.F., Miller, J.J., Lewis, K.A., Zyrianova, M.V., Boswell, Ray, and Inks, T.L., 2011. Permafrost -associated natural gas hydrate occurrences on the Alaska North Slope: Journal of Marine and Petroleum Geology, v. 28, p. 279-294. Dallimore S. R. and Collett T. S., 1995. Intrapermafrost gas hydrates from a deep core hole in the Mackenzie Delta, Northwest Territories, Canada, Geology; June 1995; v. 23, no. 6; p. 527-530. Eaton, B.A., 1969. Fracture gradient prediction and its application in oilfield operations. Journal of Petroleum Technology 21 (10), 1353-1360. Eaton, B.A., 1975. The equation for geopressure prediction from well logs. Society of Petroleum Engineers of AIME. Paper SPE 5544.Hill, P., Dallimore, S., and Taylor, A. T., 2011, Importance of Sea -Level Controlled Depositional Architecture to the Understanding of Permafrost and Gas Hydrates on High Latitude Shelves, Search and Discovery Article #80124, 27 pp. Houseknecht, David W., 2014. Brookian Stratigraphic Plays in the National Petroleum Reserve — Alaska (NPRA): U.S. Geological Survey Open -File Report 03-039, U.S. Geological Survey Reston, Virginia 20192 [http://pubs.usgs.gov/of/2003/ofO3-039/text.htm]. Lewis, K. L., and Collett, T. S., 2013. Brookian Sequence Well Log Correlation Sections and Occurrence of Gas Hydrates, North-Central North Slope, Alaska, Scientific Investigations Report 2013-5050, U.S. Department of the Interior, U.S. Geological Survey, 23 p. Mull, C.G., Houseknecht, D.W., and Bird, K.J., 2003. Revised Cretaceous and Tertiary stratigraphic nomenclature in the Colville basin, Northern Alaska: U.S. Geological Survey Professional Paper 1673, 51 p. Report No. 27.1501-2886 Page 39 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY. ALASKA _P1MR0 Ramachandran, K., Bellefleur, G., Brent, T, Riedel,M., and Dallimore, S., 2011. Case History, Imaging permafrost velocity structure using high resolution 3D seismic tomography , Geophysics. Vol. 76, No. 5 (September -October 2011); P. 8187—B198 USGS, 2013. Department of the Interior U.S. Geological Survey, Selected Data from Eleven Wildcat Wells in the National Petroleum Reserve in Alaska, USGS Open File Report 99-015 Page Last Modified: Thr Jan 10 23:13 EST 2013 http://pubs.usgs.gov/of/1999/ofr-99-0015[WorkShop.htm Yakushev, V. S., and Collett, T. S., 1992. Gas hydrates in arctic regions: Risk to drilling and production: International Offshore and Polar Engineering Conference, 2nd, San Francisco, California, Proceedings, p. 669-673. Report No. 27.1501-2886 Page 40 of 40 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA. CHARTS 536 535 532 533 637 638 ti 521 526 625 44 CT -1 523 + + 531 628 527 + + + talo ' SMITH BAY + 534 529 530 510 8 522 519 + I U/624� + NAVIGATION POST -PLOT CT -1 PROSPECT SLOCXSE'..E...C. BM TSFA OFFSHORRAIASKS CAELM ENERGY CX l 536 535 532 531 528 527 E E SMITH SAY cRlo NORTH 533 537 538 «, 534 529 530 F E ♦ hh - « 4y hh he 521 520 « 18 526 525 `, . F � 523 522 519 h.n ♦ F 7 s 524 ♦ ♦ ♦ 9 ♦ /.. .. ♦. O r �wMw ❑ W.. INTERPRETIMWORMPTION i e STRUCTURE HORIZON 2 CRI PROSPECT RLocRs siesx.sxuxAxo sa sr. sEa OFFSMOflEPLPSFP OFFGADGEAIAG CAEL SENERGY ART2 536 535 532 531 528 527 iR GRID ♦ SMITH BAY NORTH 533 537 538 k .„� 534 529 530 i R �a 621 4 ,., ' sgo e 526 525 CTl ' 0 523 >., 522 - f 519 E g` _ ♦ �' g ♦ +P 524 x J 3� f _F ♦ • r p� ♦ B ♦ . . E g. � ❑ umm y, �w®wuv�mv INT�EsRPRET^YE INFORMATION v STRUCTURE HORIZON 4 EA PROSPECT BLOCKS S135b, SlldN.W O5N SMOFFSHOC1NRESKE OFFSXORE.IIASIU EAELUS ENERGY CH4RT3 ' vv� �e CAELUS ENERGY, INC. GRU SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY. ALASKA APPENDIX A INTERPRETATION AND MAPPING PROCEDURES Appendix A Page 1 of 5 CAELUS ENERGY, INC. GRD SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA A.1 INTRODUCTION The charts, figures, and profiles presented in this report primarily reflect the interpretation of 3D seismic data supplemented by well logs. The following appendix describes the interpretive procedures used to produce the illustrative charts and figures accompanying the text portion of this report. Metadata for all of the charts described below are included with the ArcGIS database provided with this report. A.2 DATA ACQUISITION AND PROCESSING These data were shot with Vibroseis on a 110 ft by 110 ft grid. These data were originally processed in 2008. They were reprocessed from the original field tapes in 2014 to refine detail in shallow structures and to preserve seismic amplitudes for use in shallow hazard analysis. Figure A-1 — Input Area CDP Fold (0-80) Figure A-2 — Output Area CDP Fold (0-80) Processing outline for Hazards data: 1. Data Input a. SEG -D shot gathers b. Constrain input area to 7x7 sq. miles centered on primary target 2. Geometry Merge a. Merge geometry with traces b. Convert coordinates to NAD 83 Alaska State Plane Zone 5 3. Refraction Statics a. Refraction statics were computed using a deeper reflector to eliminate permafrost interference which are known to exist as deep as 1000 ft. in the area b. First breaks were auto picked and then hand -edited c. Offsets between 12200 —17800 ft. were used as branch points d. Data were processed at a 40 ft. datum with a replacement velocity of 6000 fl/s 4. Pre-Decon Wavelet Processing a. True Amplitude Recovery b. Shot domain, frequency dependent diversity scaling Appendix A Page 2 of 5 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY, ALASKA c. Surface consistent amplitude compensation 5. Surface Consistent Deconvolution a. 240ms operator spiking decon b. Shot and Receiver terms decomposed and applied 6. Velocity Analysis 1 (1 mi Interval) 7. Mute Analysis a. Initial mute evaluated and updated as necessary 8. Surface Consistent Residual Statics 1 a. Final statics constrained to ±24 ms, with majority of statics between ±8 ms 9. Velocity Analysis 2 (1/2 mi Interval) 10. Surface Consistent Residual Statics 2 a. Final statics constrained to ±24 ms, with majority of statics between ±2 ms 11. Post-Decon Wavelet Processing a. Shot domain frequency -dependent diversity scaling (FDDS) b. Offset domain frequency -dependent diversity scaling (FDDS) 12. Surface Consistent Amplitude Compensation a. Decomposed and applied to shots and receivers 13. CDP Trim Statics a. Final statics constrained to ± 10ms 14. Post Stack Enhancements a. Spectral whitening b. F-XY decon filter c. Footprint attenuation d. FK model and subtract 15. FD Post Stack Migration ?GRO Refraction statics and surface consistent residual statics were used to remove most of the distortion from short wavelength permafrost thickness variations. The refraction statics used the very far offsets to see below the permafrost. Subsurface depths in this report are calculated based on a polynomial velocity function, provided by NordAq for the nearby Tulimaniq #1 prospect and applied to CT -1 based on the surrounding offset wells, seismic velocity, and permafrost modeling. The average acoustic velocity below the surface is calculated as follows: Depth in feet = 915.64626175*t2 + 3056.24765254*t (t = Two-way travel time to the mapped horizon in seconds). Appendix A Page 3 of 5 CAELUS ENERGY, INC. SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY. ALASKA A.3 A.4 A.5 TWO-WAY TIME ILIO➢ o 1�Em15"mRonixl Well -�-nummm9lm. +3•e s.3ml[va —poly.fiuYm[nq 11111 y =O.OW91565x2+3 0.56247651 Wlaam Fu mkWm rom, I>mw am. 4 Tumwmy lFne VMm. mm, 118 315 1008 455 1350 15 3860305 wa4 4 .11, 4u axis I.A 5632 IL83 6934 3501 803.0 81 033.3 5485 13316 355 11434 e)IB tsee.o 7941 18830 ]MO W Rio ;1153 115,E M15 Mmm1e V[IxIN Amman fiem FSWIeM Tuor[y 4n[ VeN[[ItlrytM1 Vanletl Npt 1, we 1. wa4 4 5W oss.] 4. 1w1e Bw 3.1 )w 2eze 1 ew 3511.5 Bw 011 INp +w+e Io wxz2 U aw 8z33 IM Ma ss Re3a W 3113.1 1. 10.12].3 31w 2 11]x88 Figure A-3 Time vs. depth velocity functions. BASE MAP (CHART 1) [BIRO Vx[[m FmmtWn M1[m Eu181mpeon Tut W[II1 T—Y time Vanletl Npt 1, we 1. 1160 5W A00 WO 3115 ae 1sw MIA 051 < z0A ]840 3100 0330 +w+e .1a wt5 53 aw e 1 1 52b A 145]4 0040 1510.4 ]424 1500.0 ]592 11230 RBB .1.11 Fun[tl[n Iw iuIMm19+n1. Tma, m. m.m. d.I,1 .,a t9w I.. e+ o 55 B5w +sego ]sw Chart 1 shows the entire CT -1 prospect area at a scale of 1:24,000. The survey lines shown on Chart 1 were generated from world coordinates supplied by FairfieldNodal. Representative inlines and crosslines are displayed on Chart 1 to aid in referencing geologic and stratigraphic conditions identified from the 3D seismic data volume. STRUCTURE MAPS, HORIZONS 2 AND 4 (CHARTS 2 AND 3) The structure values were calculated by converting the subsurface times to depth using the following velocity function. Depth = 915.64626175*T2 + 3056.24765254*T (T = two-way travel time to the mapped horizon in seconds). FIGURES AND SEISMIC DATA EXAMPLES The data examples were selected from the 3D seismic data volume and various graphics programs to illustrate particular geologic conditions and stratigraphy that are discussed in this report. The seismic data examples were exported from the seismic workstation for set-up and annotation in PowerPoint and in the CorelDraw graphics -editing program. Appendix A Page 4 of 5 CAELUS ENERGY, INC. SRO SHALLOW HAZARDS ASSESSMENT, PROPOSED CT -1 WELL SMITH BAY. ALASKA A.6 ASSESSING SHALLOW GAS POTENTIAL High -amplitude anomalies were auto -picked by the Vatmin, Vatmax, and Vatrms attribute searches. A baseline criterion for the values of the amplitudes was then selected by comparing the computed results with a vertical section in amplitude envelope or reflection strength display. The envelope is independent of the phase and it relates directly to the acoustic impedance contrasts. It may represent the individual interface contrast or, more likely, the combined response of several interfaces, depending on the seismic bandwidth. The amplitude envelope is a physical attribute that can be used as an effective discriminator for the following characteristics: • acoustic impedance contrast or reflectivity, • bright spots, • possible gas accumulation, • sequence boundaries, • thin -bed tuning effects, • unconformities, • major changes of lithology, • major changes in depositional environment, • spatial correlation to porosity, and other lithologic variations. The above criterion was used to distinguish gassy sediments from other conditions in the high -amplitude, low -impedance anomalies as follows: • Negligible: Unlikely to encounter shallow gas due to the stratigraphic and structural framework of the zone. No anomalous amplitudes are present and no hydrocarbon indicators have been identified. • Low: Potential for minor amounts of near -normally pressured solution gas in sands. • Moderate: Increased potential for encountering near -normally pressured solution gas. High amplitudes with trough -peak reflection character. There are no other direct hydrocarbon indicators; however, the stratigraphic and structural framework may be suitable for the presence of shallow gas. • High: Stratigraphic and structural framework is ideal for shallow gas accumulation. There are high amplitude anomalies or "bright spots" with trough -peak reflection character and other direct hydrocarbon indicators. Stratigraphic and structural framework favorable for trapping gas. A.7 ASSESSING HYDRATE POTENTIAL High -amplitude anomalies were identified with the Vatmax attribute searches to identify strong peak -over - trough, positive polarity reflections; however this signal is not alone diagnostic of hydrate in sands. Very shallow water sands also produce peak -over -trough signatures as do many unconformities. To avoid ambiguity with the identification of hydrate -bearing sands, identification was based on the following criteria: • The estimated depth of the BGHS. • Strong amplitudes consistent with zones of elevated acoustic velocity and peak -trough reflection paring above the BGHS. • Juxtaposed leading -peak event above the BGHS with leading -trough events below the BGHS. Appendix A Page 5 of 5 TRANSMITTAL LETTER CHECKLIST WELL NAME: (27-1—t PTD: oC /S- acsB Development _ Service 41 Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: ( POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- _ function (If last two digits Production should continue to be reported as a of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50-_- -� from records, data and logs acquired for well (name onpermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where sam les are fust 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 YYGLL rtKIVII l L HtUKLIJ 1 rieia a roof _ _ _ _ Well Name: CT 1 _-_ _ProgramXP _— _.. Well bore seg PTD#: 2152080 Company CAELUS ENERGY A]AS)SA_SMITH BAY LLC _ Initial Class/rype _EXP / PEND GeoArea B80 Unit On/Off Shore On— Annular Dispos: Administration 1 Permit fee attached NA 2 Lease number appropriate .. ... . ..... . . . . . . . . . . _ ... Yes _ _ ADL0392275, entire wellbore. 3 Unique well name and number - - Yes CT -1 4 Well located in a defined pool .. . . . . . .. . . . ...... . . . . .. ......... No.. - Exploratory well - 5 Well located proper distance from drilling unitboundary- - - . ....... . . . . . . .. Yes .. _ 6 Well located proper distance from other wells _ _ ....... Yes _ _ _ First well to be drilled within -Sec 17, T1 7N, R9W, U.M. 7 Sufficient acreage available in drilling unit. _ Yes 8 If deviated, is wellbore platincluded_ .. _ _ _ .. .. _ _ _ ... Yes 9 Operator only affected parry.. - ..... - ........ - ......... Yes - _ Wellbore, will be. more than 500' from lease boundary, 10 Operator has. appropriate bond in force _ _ _ _ _ _ _ _ .... - Yes 11 Permit can be issued without conservation order.. _ _ _ .. _ ... _ Yes Appr Date 12 Permit can be issued without administrative. approval ... _ _ ...... Yes PKB 12/16/2015 13 Can permit be approved before 15 -day wait _ _ _ Yes 14 Well located within area andstrataauthorized by Injection Order # (put 10# in, comments). (For NA I15 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 A$31 A5.030(t. AUZA-D) NA 18 Conductor string provided _ - _ - - - _ - - - - - Yes 16" conductor to be set at,102 ft Engineering 19 Surface casing protects oll.known USDWs _ _ .. _ _ _ .. _ NA- _ _ _ No aquifers ,. Offshore and permafrost area. -(A miles offshore) 20 CMT vol adequate to circulate on conductor & surf csg _ _ _ _ _ _ _ Yes - - 10 3/4 surface casing will be fully cemented _ Using stab in collar... - 21 CMT vol adequate to tie-in long string to surf csg.... _ _ ...... _ _ _ _ .. No. _ .. May use well for Annular disposal.. Permit required 22 CMT will cover -all known. productive horizons.... _ Yes 23 Casing designs adequate for C, T, B.& permafrost. _ - _ - - - - _ - - _ - _ Yes .. _ _ _ _ . BTC calcs provided.. All good by industry accepted standards. 24 Adequate tankage. or reserve pit _ ... _ _ .. _ _ _ _ . Yes _ _ _ _ Rig has steel pits,. Waste will. be.disposed as per PTD. Cuttings.transported to Pbay.... _ 25 If. a. re -drill, has. a 10-403 for abandonment been approved _ NA - _ Exploration well, - - - - - - - - - --- - - - - - - 26 Adequate wellbore separationproposed_ _ _ _ _ _ _ _ .. Yes .... _ no other wells in area. Well is near vertical.... ..... _ 27 If.diverter required, does if meet regulations. _ ... _ _ _ Yes _ Arctic Fox has IT diverter.. Layout of line on ice pad. is provided... Appr Date 28 Drilling fluid program schematic & equip list. adequate - _ - - .... - - Yes _ .. _ Max formation pressure = 4624 psi ( 10.3 ppg EMW) will drill well with 10-10.3 ppg mud as needed.. GLS 12/21/2015 29 BOPES,. do they meet regulation _ _ _ ... _ _ _ Yes _ Arctic. Fox has 5000 psi 11". BOPE slack.- 3 ram and 1 annular. 30 BOPE. press rating appropriate, lest to (put psig in comments)............ _ _ . Yes _ _ _ .. MASP = 3665 -psi ( will test. ROPE to 5000 psi.. Annular to 2500 psi)- - - '31 Choke manifold complies w/API. RP -53 (May 84)- _ ........ _ ....... Yes 32 Work will occur without operation shutdown ....... . . . ... . . . . ... . . . .. Yes _ . Separate sundry required for Annular disposal -and P& A of well. _ - 33 Is presence of H2S gas- probable - - - _ .... _ _ _ _ _ - - - - - No _ _ H2$ not expected but is exploration well requires safeguards._ 34 Mechanical_ condition of wells within AOR verified (For service well only) - _ _ .. _ NA- 35 Permit can be issued w/o hydrogen. sulfide measures - .. _ - - - _ _ - - _ _ _ No measuredrequired.. _ _ Exploratory well. H2$ measured required... Geology 36 - Data.presented on potential overpressure zones _ Yes Max expected reservoir is _ _ p _ p _ ppg EMW; will he.drilled -using 9.5 to 10.2 ppg mud.. Date 37 Seismic analysis of shallow gas -zones-- - - - - - - - - - - - - - - - - - - - - - - _ _ - - Yes .. _ _ _ _ _ Seismic analysis indicates no anomalous amplitudes that maybe associated withshallowgas. - No near surface PKB PKB 12/16/2015 38 Seabed condition survey -(if off -shote) _ . _ . _ _ _ ... _ _ _ .. - _ - _ NA _ _ _ . faults; 3 exploratory wells Win 10 miles.- Well to be drilled from bottom founded icepad offshore Smith Bay. 39 Contact name/phone for weekly, Progress reports [exploratory only) . . . . . .... . . . ... Yes - - - - , . _ Mike Cook (907) 343-2135. Geologic Engineering Public Exploration well in Smith Bay. Sundry required for A/D and well testing operations. GIs Commissioner: Date: Commissioner: Date Commissioner Date BSS 'z�2Z1r Company Caelus Energy Alaska Well CT- 1 Section 8.5 Rig Arctic Fox Field Wild Cat Borough North Slope Alaska Country USA Report by WL: A Shetty/ P Trofimoff/ L Mejia PTS:A Shende Reviewed by WL Domain: H Dumont, G Garcia Logging Date 12-Feb-2016 Report Date 19-Feb-2016 Run Number R1D3 Job Number PTS: DS-2016-06293 Modular Formation Dynamics Tester Data Evaluation Report CT-1 2 1 EXECUTIVE SUMMARY ............................................................................................................................................................. 6 2 INTERPRETATION SUMMARY ................................................................................................................................................... 8 2.1 INTRODUCTION .................................................................................................................................................................................. 8 2.2 COMMENTS ...................................................................................................................................................................................... 8 2.3 SUMMARY ANALYSIS ........................................................................................................................................................................... 8 2.4 CONCLUSION & RECOMMENDATION ...................................................................................................................................................... 8 2.5 CONTACTS ........................................................................................................................................................................................ 8 2.6 PRESSURE VERSUS DEPTH OVERVIEW ..................................................................................................................................................... 9 3 FLUID AND SAMPLING SUMMARY .......................................................................................................................................... 12 3.1 SAMPLING AND FLUIDS PROFILING SUMMARY TABLE .............................................................................................................................. 12 3.2 FLUIDS ANALYSIS RESULTS TABLE ........................................................................................................................................................ 13 4 FLUID GRADIENTS .................................................................................................................................................................. 16 5 PRESSURE RESULTS ................................................................................................................................................................ 18 5.1 PRETEST SUMMARY TABLE ................................................................................................................................................................. 18 5.1.1 Formation Pressure Quality Grading Description ................................................................................................................. 18 5.2 TEST POINT TABLE ............................................................................................................................................................................ 19 6 PRESSURE VS. DEPTH VIEWS .................................................................................................................................................. 22 6.1 DEPTH OVERVIEW BY QUALITY ........................................................................................................................................................... 22 7 DOWNHOLE FLUID ANALYSIS AND SAMPLING........................................................................................................................ 24 7.1 R1D3 – FILE 12 – 5676.02 FT MD ................................................................................................................................................... 24 7.1.1 Standard Cross Plot ............................................................................................................................................................... 25 7.1.2 IFA_1 Composition, GOR and Fluorescence Cross Plot .......................................................................................................... 26 7.1.3 IFA_1 Density-Viscosity Cross Plot ........................................................................................................................................ 27 8 DFA PREDICTOR – RESERVOIR CONNECTIVITY ANALYSIS (SUGGESTED AS PART OF COMPLETE REPORT) ............................... 30 9 WELL AND JOB DATA .............................................................................................................................................................. 34 9.1 WELL HEADER ................................................................................................................................................................................. 34 9.1.1 Well Header Table ................................................................................................................................................................. 35 9.2 TOOL STRING .................................................................................................................................................................................. 37 9.3 WELL SURVEY TABLE ........................................................................................................................................................................ 40 10 LITERATURE ............................................................................................................................................................................ 45 10.1 EXCESS PRESSURE ......................................................................................................................................................................... 45 10.1.1 Excess Pressure Example.................................................................................................................................................... 46 10.2 INSITU FLUID ANALYZER ................................................................................................................................................................. 47 CT-1 3 DISCLAIMER ANY INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES, OR RECOMMENDATION FURNISHED WITH THE SERVICES OR OTHERWISE COMMUNICATED BY SCHLUMBERGER TO CUSTOMER AT ANY TIME IN CONNECTION WITH THE SERVICES ARE OPINIONS BASED ON INFERENCES FROM MEASUREMENTS, EMPIRICAL RELATIONSHIPS AND/OR ASSUMPTIONS, WHICH INFERENCES, EMPIRICAL RELATIONSHIPS AND/OR ASSUMPTIONS ARE NOT INFALLIBLE, AND WITH RESPECT TO WHICH PR OFESSIONALS IN THE INDUSTRY MAY DIFFER. ACCORDINGLY, SCHLUMBERGER CANNOT AND DOES NOT WARRANT THE ACCURACY, CORRECTNESS OR COMPLETENESS OF ANY SUCH INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES OR RECOMMENDATION. CUSTOMER ACKNOWLEDGES THAT IT IS ACCEPTING THE SERVICES "AS IS", THAT SCHLUMBERGER MAKES NO REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, OF ANY KIND OR DESCRIPTION IN RESPECT THERETO. SPECIFICALLY, CUSTOMER ACKNOWLEDGES THAT SCHLUMBERGER DOES NOT WARRANT THAT ANY INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES, OR RECOMMENDATION IS FIT FOR A PARTICULAR PURPOSE, INCLUDING BUT NOT LIMITED TO COMPLIANCE WITH ANY GOVERNMENT REQUEST OR REGULATORY REQUIREMENT. CUSTOMER FURTHER ACKNOWLEDGES THAT SUCH SERVICES ARE DELIVERED WITH THE EXPLICIT UNDERSTANDING AND AGREEMENT THAT ANY ACTION TAKEN BASED ON THE SERVICES RECEIVED SHALL BE AT ITS OWN RISK AND RESPONSIBILITY AND NO CLAIM SHALL BE MADE AGAINST SCHLUMBERGER AS A CONSEQUENCE THEREOF. CT-1 4 This page left intentionally blank CT-1 5 Section 1 Executive Summary CT-1 6 1 Executive Summary This report presents the evaluation and interpretation of the MDT pressure and sampling data from the well CT-1, for the 8.5” section, acquired on 12th Feb 2016. An InSitu Fluid Analyzer (IFA) was used for downhole fluid analysis (DFA). A Saturn 3D Radial Probe and an Extra Large Diameter (XLD) probe were used for acquiring pressures and samples. 9 pressure stations were attempted in this section resulting in 3 low quality pressures and 6 tight/dry tests. The formation had very low mobility as observed from the high number of tight tests. Also, in the three stations where valid pressure response was seen, the mobility was so low that the pressures did not stabilize (as shown below) and are possibly highly supercharged. Thus, the confidence in the pressure values is low One DFA station was performed at 5676.02 ft MD and 2 non-compensated (450 cc MPSR) samples were collected. Sampling was terminated because of the low mobility and the sample contamination might be high. IFA identified the fluid to be primarily water. However, some hydrocarbons were also seen. The acquisition of pressures and samples at that low mobility was possible, because Saturn 3D radial probe was used. Thus, the MDT acquisition program resulted in 3 low quality pressures in a low mobility formation and 2 samples, which were predominantly water. Since the formation has low mobility, MDT could be used to perform mini-frac tests to understand the geomechanical properties of the formation and evaluate well stimulation scenarios, in future sections or offset wells. CT-1 7 Section 2 Interpretation Summary CT-1 8 2 Interpretation Summary 2.1 Introduction This report describes the results and analysis of MDT field recorded data carried out on 12-Feb- 2016 in the well CT-1 that includes pressure pretest LQC and analysis as well as Downhole Fluid Analysis (DFA). A total of 9 pressure stations were attempted in this well, giving 3 low quality pressures and 6 tight/ dry tests. A sampling and DFA station was also performed, identifying a fluid which is primarily water and 2 MPSR samples were collected 2.2 Comments MDT Run 1 Descent 3 was performed on 12-Feb-2016 in 8.5” section, drilled with 9.7 lbm/gal W BM mud. An IFA was used for downhole fluid analysis. An Extra Large Diameter probe and a Saturn 3D Radial probe, were used to get pressures and samples. The MDT stations were processed with InSitu Pro 2015.1.0 to get the most representative formation pressure and mobility in each station. TVD depths were calculated from directional survey dated 6-Feb-2016 2.3 Summary Analysis The pressure versus depth views contained in section 6 give an overview of the pressure and sampling acquisition. 9 pressure stations were attempted in this section resulting in 3 low quality pressures and 6 tight/dry tests. The formation had very low mobility as observed from the high number of tight tests. Also, in t he three stations where valid pressure response was seen, the mobility was so low that the pressures did not stabilize and are possibly highly supercharged. Thus, the confidence in the pressure values is low. Pressures were in the range 2771- 2800 psia and mobility was in the range 0.04- 0.14 mD/cP. One DFA station was performed at 5676.02 ft MD and 2 450 cc MPSR samples were collected. Sampling was terminated because of the low mobility and the sample contamination might be high. IFA identified the fluid to be primarily water. However, some gas was also seen as tiny bubbles (1-2% volumetrically). The acquisition of pressures and samples at that low mobility was possible, because Saturn 3D radial probe was used. Based on resistivity of 0.063 ohmm as measured by IFA, the salinity and density could be estimated to be 58700 ppm and 1.02 g/cc, respectively. This density was also observed by DV-Rod viscometer. 2.4 Conclusion & Recommendation Thus, the MDT acquisition program resulted in 3 low quality pressures from 9 pressure stations and 2 MPSR samples from 1 sampling station, in a low mobility formation using Saturn 3D Radial probe. IFA identified the fluid primarily as water. Since the formation has low mobility, it might be important to understand the geomechanical properties like the stress distribution, closing pressures, etc. to evaluate well stimulation scenarios. MDT could be used to perform mini -frac tests to understand these properties. 2.5 Contacts Please contact Aniket Shende for any information or queries related to this report: E-mail: AShende@slb.com Phone: +1 281 285 1503 For more details see: Section 3 – Fluid and Sampling Summary Section 4 – Fluid Gradients Section 5 – Pressure Results Section 6 - Pressure vs. Depth Views Section 7 – Downhole Fluid Analysis and Sampling Section 8 – DFA Predictor – Connectivity Analysis Section 9 – Well and Job Data Section 10 – Literature CT-1 9 2.6 Pressure versus Depth Overview CT-1 10 This page left intentionally blank CT-1 11 Section 3 Fluid and Sampling Summary CT-1 12 3 Fluid and Sampling Summary 3.1 Sampling and Fluids Profiling Summary Table No. Run No. File No. Date Time MD (ft) TVD (ft) Type Bottle Module Bottle Serial No. Bottle Type Bottle Volume cc Closing Pressure Flowline Temperature (degF) Pump Time (s) Pump Volume (cm3) Fluid 1 R1D3 12 2/6/2016 13:59:04 AM 5676.02 5549.27 Sampling MS1_B4 30281 MPSR 450 cc 450 6404.78 146.37 5991.0 20068.34 Water 2 R1D3 12 2/6/2016 13:59:04 AM 5676.02 5549.27 Sampling MS1_B3 968 MPSR 450 cc 450 6408.74 146.38 6044.4 20256.48 Water CT-1 13 3.2 Fluids Analysis Results Table Run No. File No. MD (ft) TVD (ft) TVDss (ft) C1 (wt%) C2 (wt%) C3-C5 (wt%) DV-Rod Dens. (g/cm3) Contamination (%) Water Frac. Fluid Comment R1D3 12 5676.02 5549.27 -5523.27 1.02 0.95 Water Sample is predominantly R1D3 12 5676.02 5549.27 -5523.27 88.34 6.68 4.98 Gas Same sample as above had small bubbles of gas *DV-rod measurements taken at flowing temperature and pressure. CT-1 14 This page left intentionally blank CT-1 15 Section 4 Fluid Gradients CT-1 16 4 Fluid Gradients DV-Rod Density Summary Well Name Gradient Top TVD Bottom TVD Top TVDSS Bottom TVDSS Density Color Gradient Comments Density Statistical Error Density Theoretical Error R2 Chi2 Probability STD Contact Depth Contact Depth SS Contact Comments Contact Statistical Error Contact Theoretical Error psi/ft ft ft ft ft g/cc lbm/gal lbm/gal psi ft ft ft ft CT-1 5549.27 5549.27 -5523.27 -5523.27 1.02 DV-Rod Dens. Mud Gradient Summary Well Name Gradient Top TVD Bottom TVD Top TVDSS Bottom TVDSS Density Color Gradient Comments Density Statistical Error Density Theoretical Error R2 STD Primary Gauge Repeatability psi/ft ft ft ft ft lbm/gal lbm/gal lbm/gal psi psi CT-1 0.519 5518.6 6336.09 -5492.6 -6310.09 9.994 Mud Before 0.024 0.034 0.99999 0.5 SRQP 0.3 CT-1 0.516 5516.43 6329.58 -5490.43 -6303.58 9.947 Mud After 0.552 0.05 0.9984 7.27 SRQP 0.3 Fluids Type Definition Density From (lbm/gal) Density To (lbm/gal) Gradient From (psi/ft) Gradient To (psi/ft) Color Probable Fluid Type Less 0.0000 Less 0.0000 Negative Gradient 0.0000 4.8145 0.0000 0.2500 Gas 4.8145 7.9924 0.2500 0.4150 Oil 7.9924 9.7833 0.4150 0.5080 Water 9.7833 15.5575 0.5080 0.8078 Mud 15.5575 Higher 0.8078 Higher Invalid CT-1 17 Section 5 Pressure Results CT-1 18 5 Pressure Results 5.1 Pretest Summary Table CT-1 Total Pretest Type Volumetric Drawdown Pretest 9 Pretest Status Valid Test 3 Tight Test 5 Dry Test 1 Gauge PQQP1 3 SRQP 7 Runs Color R1D3 (06-Feb-2016) 9 Formation Pressure Quality Color NA 6 Low 3 Drawdown Mobility Quality Color NA 6 Low 3 5.1.1 Formation Pressure Quality Grading Description Quality Color Description Examples NA No Formation Pressure No Seal or Lost Seal High Good Formation Pressure Build Up – Stabilized Medium Fair Data, Near Formation Pressure Building – Close to being Stabilized Low Questionable Formation Pressure Building – Not close to being Stabilized CT-1 19 5.2 Test Point Table Fil e No . Te st No. Run Probe MD Probe TVD TVD Subsea Pretest Status Pretest Type Comments Formati on Pres. Last BU Pres. Equiv. Formati on Density DD Mobili ty Pres. Varia nce 60 Sec Slope ft ft ft psi psi ppg mD/c P psi psi/min 3 3 R1D3 5663.46 5536.71 -5510.71 Valid Test Volumetric Drawdown Successive pretests stabilizing at lower pressures, indicating supercharging 2771.82 2771.82 9.595 0.14 0.00 0.060 4 5 R1D3 5667.89 5541.15 -5515.15 Tight Test Volumetric Drawdown Tight Test 2812.21 0.00 -0.231 5 8 R1D3 5674.87 5548.12 -5522.12 Tight Test Volumetric Drawdown Tight Test 2886.54 0.00 0.019 6 0 R1D3 5676.33 5549.59 -5523.59 Dry Test Volumetric Drawdown Dry Test 2458.09 1.16 -5.793 7 0 R1D3 6385.47 6258.72 -6232.72 Valid Test Volumetric Drawdown Pretest building up and supercharged, but not stabilized 2800.62 2800.62 8.577 0.04 0.08 4.349 8 0 R1D3 6436.51 6309.75 -6283.75 Tight Test Volumetric Drawdown Tight Test 3027.20 0.05 8.134 9 0 R1D3 6110.64 5983.89 -5957.89 Tight Test Volumetric Drawdown Tight Test 2885.84 0.16 19.628 10 0 R1D3 5957.50 5830.75 -5804.75 Valid Test Volumetric Drawdown Pretest building up supercharged 2793.71 2793.71 9.183 0.04 0.08 12.981 11 0 R1D3 5763.48 5636.73 -5610.73 Tight Test Volumetric Drawdown Tight Test 2856.26 0.01 0.678 12 R1D3 5676.02 5549.27 -5523.27 Volumetric Drawdown Only sampling, no pretest CT-1 20 File No. Test No. Run No. Mud Pres. Before Equiv. Mud Density Mud Pres. After Pretest Volume Pretest Duration Pretest Flowrate Gauge Type Packer/Probe Type Date Time Temp. After Well Deviation psi lbm/gal psi cm3 s cm3/s degF deg 3 3 R1D3 2881.92 9.978 2880.52 3.30 5.1 0.65 PQQP1 XLarge- Diameter 2/6/2016 5:07:15 AM 139.26 0.19 4 5 R1D3 2883.35 9.975 2882.90 3.24 7.5 0.43 PQQP1 XLarge- Diameter 2/6/2016 5:08:26 AM 139.10 0.19 5 8 R1D3 2886.82 9.974 2886.82 1.76 3.0 0.59 PQQP1 XLarge- Diameter 2/6/2016 5:48:54 AM 139.21 0.19 6 0 R1D3 2887.57 9.974 2902.62 238.47 63.0 3.79 SRQP OPN-7-AA Saturn 2/6/2016 6:54:28 AM 140.41 0.19 7 0 R1D3 3255.12 9.976 3268.37 612.54 334.8 1.83 SRQP OPN-7-AA Saturn 2/6/2016 9:13:05 AM 154.48 0.06 8 0 R1D3 3282.90 9.980 3283.25 82.34 12.9 6.38 SRQP OPN-7-AA Saturn 2/6/2016 10:48:35 AM 156.44 0.13 9 0 R1D3 3113.15 9.977 3115.66 108.75 32.4 3.36 SRQP OPN-7-AA Saturn 2/6/2016 11:51:10 AM 154.71 0.37 10 0 R1D3 3034.36 9.979 3034.10 131.94 34.5 3.82 SRQP OPN-7-AA Saturn 2/6/2016 12:28:26 AM 150.81 0.32 11 0 R1D3 2932.92 9.975 2933.82 56.43 17.7 3.19 SRQP OPN-7-AA Saturn 2/6/2016 13:03:25 AM 146.13 0.24 12 R1D3 2887.75 389.02 SRQP OPN-7-AA Saturn 2/6/2016 13:59:04 AM 142.39 0.19 CT-1 21 Section 6 Pressure vs. Depth Views CT-1 22 6 Pressure vs. Depth Views 6.1 Depth Overview by Quality CT-1 23 Section 7 Downhole Fluid Analysis and Sampling CT-1 24 7 Downhole Fluid Analysis and Sampling 7.1 R1D3 – File 12 – 5676.02 ft MD Downhole Fluid Analysis Display R1D3 File 12 5676.02 ft MD, 5549.27 ft TVD Fluid Identification and Sampling IFA indicated water Two (2) 450 cc MPSR captured CT-1 25 7.1.1 Standard Cross Plot CT-1 26 7.1.2 IFA_1 Composition, GOR and Fluorescence Cross Plot CT-1 27 7.1.3 IFA_1 Density-Viscosity Cross Plot CT-1 28 This page left intentionally blank CT-1 29 Section 8 DFA Predictor – Reservoir Connectivity Analysis CT-1 30 8 DFA Predictor – Reservoir Connectivity Analysis (Suggested as part of complete report) DFA data can be used to investigate fluid equilibrium, reservoir connectivity and reservoir fluid geodynamics process. Some aspects it may involve are: 1. Analyze available DFA data (previous wells vs. new well data), 2. Integrate DFA into geological models (reservoir, field and basin scale), 3. Predict DFA logs at any location in the field, and 4. Compare the predictions with the DFA measurements in newly drilled wells to validate the fluid and geologic model. With real time DFA log analysis, a common feature in toda y’s logging environment, model discrepancies uncovered by a mismatch with DFA measurements can be investigated during the wireline formation evaluation program. This workflow can be implemented during exploration, appraisal and development. Both the geolog y and the fluids in the model are compared to the real reservoir and fluid properties, and if needed, both models could be updated. This is a new way to bring value by taking advantage of DFA to guide not only sample acquisition but fluid data acquisition in general to help unravel reservoir architecture. DFA fluid mapping could be complementary to lab geochemistry studies and analyses of field pressure gradients, or as in the case study, it may tap into more advantageous and previously unnoticed reservoir features [1, 2, 3]. MDT DFA Optical Density Spectrum for different stations (left) and Optical Density Gradient graph (right) to support Compartm ent / Fluid Equilibrium Studies [2] DFA Supporting Compartment / Fluid Equilibrium Studies [2] CT-1 31 Reservoir Fluid Geodynamics [1] [1] O.C. Mullins S.S. Betancourt, M.E. Cribbs, J.L. Creek, B.A. Andrews, F. Dubost, L. Venkataramanan, The colloidal structure of crude oil and the structure of reservoirs, Energy & Fuels, 21, 2785-2794, (2007) [2] S.S. Betancourt, F.X. Dubost, O.C. Mullins, M.E. Cribbs, J.L. Creek, S.G. Mathews, Predicting Downhole Fluid Analysis Logs to Investigate Reservoir Connectivity, SPE IPTC 11488, Dubai, UAE, (2007) [3] Vinay K. Mishra, Jesus A. Cañas, Soraya S. Betancourt , Hadrien Dumont, Li Chen, Nivash Hingoo, Julian Y. Zuo, Oliver C. Mullins et al, DFA Connectivity Advisor: A New Workflow to Use Measured and Modeled Fluid Gradients for Analysis of Reservoir Connectivity, OTC, Houston, TX, 5-8 May 2014 CT-1 32 This page left intentionally blank CT-1 33 Section 10 Well and Job Data CT-1 34 9 Well and Job Data 9.1 Well Header CT-1 35 9.1.1 Well Header Table Borehole Size/Casing/Tubing Record Bit Bit Size (in) 8.5 Bottom Driller (ft) 6644.5 Bottom Logger (ft) 6638 Casing Size (in) 10.75 Weight (lbm/ft) 45.5 Inner Diameter (in) 9.95 Grade N/A Top Driller Top Logger (ft) 0 Bottom Driller (ft) 2551 Bottom Logger (ft) 2545 Comments Operational Run Summary Parameter (Unit) R1D3 Date Log Started 06-Feb-2016 Time Log Started 02:24:00 Date Log Finished 06-Feb-2016 Time Log Finished 03:54:00 Top Log Interval (ft) 5644 Bottom Log Interval (ft) 6418 Total Depth (ft) 6544.5 Max Hole Deviation (deg) 16.18 Azimuth of Max Deviation (deg) 0.62 Bit Size (in) 8.5 Logging Unit Number COSU-AA-E 7206 Logging Unit Location Prudhoe bay Recorded By A. Shetty / P. Trofimoff / L. Mejia Witnessed By M. Deakin Service Order Number DITD-00009 Comments Borehole Fluids Parameter (Unit) R1D3 Type Fluid Fresh Water Max Recorded Temperature (degF) 159 Source of Sample Active Tank Salinity (ppm) 29150 Density (lbm/gal) 9.7 Viscosity (s) 44 Fluid Loss (cm3) 5.8 pH 10 Date/Time Circulation Stopped 03-Feb-2016 22:52:00 CT-1 36 Date Logger on Bottom 06-Feb-2016 Time Logger on Bottom 03:54:00 Source Rmf Pressed Source Rmc Pressed Rm@Meas Temp (ohm.m@degF ) 0.17@64.7 Rmf@Meas Temp (ohm.m@degF) 0.2@58.5 Rmc@Meas Temp (ohm.m@degF) 0.42@63.2 Rm @ BHT Rmf @ BHT Rmc @ BHT Comments Depth Summary Depth Control Parameters R1D3 Rig Type Land Rig Depth Measured Device R1D3 Type IDW -JB Serial Number Wheel Correction 1 -4 Wheel Correction 2 -3 Tension Device R1D3 Type TD-K Serial Number Logging Cable R1D3 Type 7-50KA-US- SSC Serial Number Logging Cable Length (ft) 20500 Comments Remarks Run Name R1D3 Remark Line 1 Wireline conveyed using Tuffline 7-50KA-US-SCC U714006. Remark Line 2 Remark Line 3 Remark Line 4 Remark Line 5 Remark Line 6 Remark Line 7 Remark Line 8 Tool run as per toolsketch. Remark Line 9 Two samples taken at 5657.5 ft MD. Remark Line 10 Ten pressure/sampling points attempted, tight formation all over the test interval. Remark Line 11 Fluid moved from tight formtion sucessfully with Saturn probe Remark Line 12 Remark Line 13 Remark Line 14 Remark Line 15 Remark Line 16 Remark Line 17 Comments CT-1 37 9.2 Tool String CT-1 38 CT-1 39 CT-1 40 9.3 Well Survey Table -1000 -800 -600 -400 -200 0 200 400 600 800 1000 -1000 -800 -600 -400 -200 0 200 400 600 800 1000 Survey Top View View Azimuth: 90 S <----> N (ft)W <----> E (ft) 7000 6000 5000 4000 3000 2000 1000 0 -3000 -2000 -1000 0 1000 2000 3000 Survey Side View View Azimuth: 90 TVD (ft)ft CT-1 41 # MD (ft) Incl (deg) Azim (deg) TVD (ft) North (ft) East (ft) Dep.Azim. (deg) Dog Leg Sev. (deg/100ft) 1 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 3 253.21 0.23 149.88 253.21 -0.44 0.26 149.88 0.09 4 302.31 0.19 193.31 302.31 -0.6 0.29 154.68 0.33 5 368.52 0.39 225.46 368.52 -0.87 0.1 173.44 0.38 6 423.26 0.53 212.06 423.26 -1.21 -0.17 187.85 0.32 7 529.44 0.45 207.72 529.43 -2 -0.62 197.28 0.08 8 555.09 0.32 197.42 555.08 -2.16 -0.69 197.74 0.57 9 616.77 0.32 284.3 616.76 -2.28 -0.91 201.74 0.71 10 712.59 1.46 349.98 712.57 -1.01 -1.38 233.79 1.42 11 744.46 2.07 349.2 744.42 -0.05 -1.56 268.33 1.92 12 807.31 2.27 349.19 807.23 2.29 -2.01 318.82 0.32 13 870.75 3.33 355.09 870.59 5.36 -2.4 335.9 1.73 14 933.84 4.07 0.78 933.55 9.43 -2.52 345.01 1.31 15 996.51 4.99 1.37 996.02 14.38 -2.43 350.41 1.47 16 1060.27 5.7 1.09 1059.51 20.31 -2.3 353.53 1.11 17 1123.6 6.94 1.37 1122.45 27.28 -2.15 355.49 1.96 18 1186.53 7.98 359.95 1184.85 35.45 -2.06 356.67 1.68 19 1249.98 8.69 359.87 1247.63 44.65 -2.08 357.33 1.12 20 1312.43 9.58 0 1309.28 54.56 -2.09 357.81 1.43 21 1376.21 10.36 0.26 1372.1 65.61 -2.06 358.2 1.22 22 1438.47 10.84 2.82 1433.3 77.05 -1.75 358.7 1.08 23 1501.87 11.78 2.93 1495.47 89.47 -1.13 359.28 1.48 24 1564.55 12.34 3.24 1556.76 102.55 -0.42 359.76 0.9 25 1626.81 12.99 2.05 1617.51 116.18 0.21 0.1 1.12 26 1690.19 13.71 359.27 1679.17 130.81 0.36 0.16 1.52 27 1749.63 13.62 359 1736.93 144.85 0.15 0.06 0.19 28 1816.84 14.24 358.64 1802.17 161.03 -0.18 359.94 0.93 29 1880.33 14.25 358.59 1863.7 176.65 -0.56 359.82 0.02 30 1943.07 14.86 358.93 1924.43 192.41 -0.9 359.73 0.98 31 2006.37 15.09 358.61 1985.58 208.76 -1.25 359.66 0.39 32 2069.67 15.53 358.33 2046.63 225.47 -1.7 359.57 0.7 33 2132.89 15.51 358.34 2107.55 242.38 -2.19 359.48 0.03 34 2196.24 15.94 359.22 2168.53 259.54 -2.55 359.44 0.78 35 2259.81 15.87 359.27 2229.66 276.96 -2.78 359.42 0.11 36 2322.96 15.66 0.53 2290.44 294.12 -2.81 359.45 0.64 37 2385.69 16.26 0.25 2350.75 311.37 -2.7 359.5 0.96 38 2435.49 16.18 0.62 2398.57 325.28 -2.59 359.54 0.26 39 2520.78 15.95 0.38 2480.53 348.88 -2.39 359.61 0.28 40 2599.16 16.13 359.83 2555.86 370.54 -2.35 359.64 0.3 41 2661.81 15.82 359.72 2616.09 387.78 -2.41 359.64 0.5 42 2724.39 15.57 359.37 2676.33 404.71 -2.55 359.64 0.43 43 2787.4 15.65 358.33 2737.02 421.66 -2.89 359.61 0.46 44 2843.82 15.56 357.18 2791.36 436.82 -3.48 359.54 0.57 45 2912.21 16.02 356.03 2857.17 455.4 -4.59 359.42 0.81 46 2975.92 16.16 353.73 2918.38 472.98 -6.16 359.25 1.02 47 3028.04 16.1 354.35 2968.45 487.38 -7.67 359.1 0.35 48 3102.95 15.7 356.58 3040.5 507.84 -9.29 358.95 0.97 CT-1 42 # MD (ft) Incl (deg) Azim (deg) TVD (ft) North (ft) East (ft) Dep.Azim. (deg) Dog Leg Sev. (deg/100ft) 49 3166.9 15.7 358.42 3102.06 525.12 -10.05 358.9 0.78 50 3230.68 15.78 359 3163.45 542.42 -10.44 358.9 0.28 51 3293.25 15.76 1.06 3223.66 559.42 -10.43 358.93 0.9 52 3356.15 16.02 1.01 3284.16 576.64 -10.12 358.99 0.41 53 3418.59 16 1.13 3344.18 593.86 -9.8 359.05 0.06 54 3481.5 16.08 2.22 3404.64 611.23 -9.29 359.13 0.5 55 3545.73 15.77 4.24 3466.41 628.83 -8.3 359.24 0.99 56 3609.59 15.7 4.85 3527.87 646.09 -6.93 359.39 0.28 57 3671.02 15.69 3.87 3587.01 662.66 -5.66 359.51 0.43 58 3734.69 15.83 4.43 3648.29 679.91 -4.41 359.63 0.32 59 3797.66 15.97 5.13 3708.85 697.1 -2.97 359.76 0.38 60 3860.9 15.92 5.17 3769.66 714.4 -1.41 359.89 0.08 61 3924.04 15.72 2.5 3830.41 731.57 -0.26 359.98 1.2 62 3986.97 15.89 358.79 3890.96 748.7 -0.07 359.99 1.63 63 4050.4 15.82 359.16 3951.98 766.03 -0.38 359.97 0.19 64 4112.77 15.66 358.82 4012.01 782.94 -0.68 359.95 0.3 65 4177.14 15.83 359.33 4073.96 800.41 -0.96 359.93 0.34 66 4239.64 15.76 1.47 4134.1 817.42 -0.84 359.94 0.94 67 4301.44 15.77 1.82 4193.58 834.2 -0.36 359.98 0.15 68 4365.81 15.7 1.72 4255.53 851.65 0.18 0.01 0.12 69 4427.87 15.79 1.29 4315.27 868.48 0.62 0.04 0.24 70 4491.86 15.98 0.85 4376.81 886 0.95 0.06 0.35 71 4554.88 15.68 2.49 4437.44 903.18 1.45 0.09 0.85 72 4617.88 14.31 2.13 4498.3 919.46 2.11 0.13 2.18 73 4678.5 13.28 2.04 4557.17 933.91 2.63 0.16 1.7 74 4744.48 11.92 0.16 4621.56 948.3 2.92 0.18 2.15 75 4805.59 10.18 358.21 4681.53 960.01 2.77 0.17 2.91 76 4870.43 8.89 358.18 4745.47 970.74 2.43 0.14 1.99 77 4931.72 7.28 356.21 4806.15 979.35 2.02 0.12 2.67 78 4995.39 6.29 353.54 4869.38 986.84 1.37 0.08 1.63 79 5053.65 5.67 352.16 4927.32 992.86 0.61 0.04 1.09 80 5124.03 4.51 349.14 4997.42 999.03 -0.38 359.98 1.69 81 5186.59 2.2 348.45 5059.87 1002.62 -1.09 359.94 3.69 82 5248.66 0.62 334.11 5121.92 1004.09 -1.47 359.92 2.59 83 5311.81 0.2 351.15 5185.07 1004.5 -1.64 359.91 0.69 84 5375.68 0.13 242.94 5248.94 1004.58 -1.72 359.9 0.42 85 5438.7 0.22 200.5 5311.96 1004.44 -1.83 359.9 0.24 86 5498.97 0.18 134.09 5372.23 1004.26 -1.8 359.9 0.37 87 5562.1 0.13 91.18 5435.36 1004.19 -1.65 359.91 0.19 88 5623.43 0.22 44.42 5496.69 1004.27 -1.5 359.91 0.26 89 5688.56 0.19 9.81 5561.82 1004.47 -1.4 359.92 0.19 90 5746.14 0.24 13.52 5619.4 1004.68 -1.35 359.92 0.09 91 5811.21 0.31 312.65 5684.46 1004.93 -1.45 359.92 0.44 92 5880.07 0.63 192.75 5753.32 1004.69 -1.67 359.9 1.2 93 5942.15 0.39 148.08 5815.4 1004.18 -1.63 359.91 0.72 94 6005.35 0.26 123.16 5878.6 1003.92 -1.4 359.92 0.3 95 6069.42 0.27 352.61 5942.67 1003.99 -1.3 359.93 0.75 96 6132.2 0.38 303.45 6005.45 1004.25 -1.49 359.91 0.46 97 6195.05 0.4 248.75 6068.3 1004.28 -1.87 359.89 0.57 CT-1 43 # MD (ft) Incl (deg) Azim (deg) TVD (ft) North (ft) East (ft) Dep.Azim. (deg) Dog Leg Sev. (deg/100ft) 98 6253.77 0.26 239.25 6127.02 1004.14 -2.17 359.88 0.26 99 6317.21 0.12 254.64 6190.46 1004.05 -2.36 359.87 0.23 100 6382.55 0.06 66.7 6255.8 1004.05 -2.4 359.86 0.27 101 6439.4 0.13 166.13 6312.65 1003.99 -2.35 359.87 0.27 102 6511.66 0.18 130.48 6384.91 1003.84 -2.25 359.87 0.15 103 6644.5 0.18 130.48 6517.75 1003.57 -1.93 359.89 0 CT-1 44 Section 10 Literature CT-1 45 10 Literature 10.1 Excess Pressure Excess Pressure is used in this report to show small changes in the pressure regime and to indicate a density or fluid change. The Excess pressure is generated by subtracting the expected pressure from the fluid weight from the total measured pressure and the remaining pressure is the difference. If the pressures are of high quality and the fluid in the pore space has not changed then the Excess Pressures should fall along a vertical line i.e. have the same excess pressure value. If the Excess Pressures deviates from the vertical line or from a consistent value this could indicate a pressure regime change, fluid density change, unstable pressures or supercharging. To get the Excess Pressure a high quality pressure is picked as the total pressure and the gradient is used to get a fluid density for computing the Excess Pressure. At the pressure datum the Excess Pressure will be 0. So when the Excess pressure is plotted any good pressures that don’t have the same fluid density will be shifted off the zero line. The following low resistivity example demonstrates the use of Excess Pressure. Here test 2 was used as the pressure datum and the Gas gradient of 0.174 psi/ft was used as the fluid density to compute Excess Pressure. Tests 2 through 11 line up well on zero and tests 13 through 19 make a new diagonal line off the zero line. In this case this shows the pressures are good values and there is a fluid change around 11694 ft. The LFA analysis and the standard pressure gradient also support the fluid change, or Gas Oil contact. If the pressures were not stable or supercharged they would not of fit on a line and would of indicated poor quality pressures. A change in pressure regime due to a barrier would be indicated by a discrete excess pressure shift. Reference: Alton Brown: “Improved interpretation of wireline pressure data” , AAPG Bulletin v. 87 no.2 (February 2003) CT-1 46 10.1.1 Excess Pressure Example CT-1 47 10.2 InSitu Fluid Analyzer Quantitative fluid measurements at reservoir conditions, in real time InSitu Fluid Analyzer Quantitative fluid measurements at reservoir conditions, in real time CT-1 48 Applications Quantified fluid measurements that were previously unachievable from wireline logs or laboratory analysis are now possible downhole and in real time. By investigating fluids at their source, you gain a d e e p e r i ns i g h t to f lui d c o mpos iti on a n d d is tr i bu t i on, t o i mp r o v e y o u r unders t a ndin g of t he re ser v o ir . Appli ca t io n s:  R e se rvo i r f lu id c h a rac t er iza t i on  I den tif ic a t io n o f co mp a r tments an d l a te r a l s ea l in g b ou nd ar ies. Q u an tif ica tion o f co m pos i t io na l gradin g  Strat egy dev e lo p m e n t fo r c o r ros io n a nd sca le  S a m p le a ssu r a n ce : si n gl e p has e an d pur i ty R e se rvo i r s im u la t ion (E O S mo de lin g)  I m p ro v e d -a c c u r a c y  Determ ina t i on o f p rete s t g rad ien ts an d f lu id contac ts. As p h al ten e g ra d ien t d e t e r m inat ion  D i ffe r en t ia t io n o f b io genic a nd the rm o g en ic dry gas  I den tif ic a t io n o f vo la t ile o il an d g as c on de nsa te  Determ ina t i on o f g a s /o i l rati o (GO R ) and co n d ensa te /gas ra t io (C GR) CT-1 49 Module Fluorescence detect or Pressure and t em perat ur e gauge Density sensor Flowline R esistivit y sensor Filter array spec t rom eter G rati ng spectrom et er InSitu F l ui d An al y ze r s e rvi c e i ntegrat e s m ulti ple I nSi t u Famil y re se rvoi r f lui d m e asu rem e nt s an d sen so rs. Fluid Profiling analysis of InSitu Family DFA measurements gives further insight to reservoir fluid distribution and variation. Characterization of the fluid system is extended from a single well to multiple-well (field-based) applications, such as quantifying compositional gradients and identifying zonal connectivity. 1. Dual Spectrometers for Enhanced Accurac y The foundation of DFA is optical absorption spectroscopy. The InSitu Composition hydrocarbon fluid composition measurement introduces the first downhole deployment of a laboratory-grade “grating spectrometer” in addition to the conventional filter array spectrometer. This technical innovation expands the accuracy and detail of the compositional information, resulting in quantifiable fluid data. The filter array spectrometer measures wavelengths in the visible to near - infrared (Vis-NIR) range from 400 to 2,100 nm across 20 channels that indicate the color and molecular vibration absorptions of the reservoir fluid and also show the main absorption peaks of water and CO2. The grating spectrometer has 16 channels focused on the 1,600 - to 1,800- nm range, where reservoir fluid has characteristic absorptions that reflect molecular structure. The dual-spectrometer measurements together with real-time calibration (performed downhole every 1 second) and improved compositional algorithms significantly improve the accuracy and repeatability of quantitative reservoir fluid analysis. It is this improved accuracy that enables Fluid Profiling comparison of fluid properties between wells, making field-wide DFA characterization a new critical tool for reservoir studies. CT-1 50 The wavelength ranges of the filter array and grating optical spectrometers are optimized for the detection and analysis of hydrocarbon and CO2 components in crude oil and natural gas, as well as for the determination of water content and pH. The measurem ent of optical density (OD) is simply the base-10 logarithm of the ratio of incident light to the transmitted light through a cross-section of reservoir fluid in the flowline. OD is presented as a dimensionless unit, whereby one OD absorbance unit implies a 10-fold reduction in light intensity. For example, OD = 0 means 100% of light is transmitted, OD = 1 indicates 10% light is transmitted, and OD = 2 means 1% light is transmitted. The measurements are conducted across the entire frequency spectrum of light in the Vis-NIR range. 2. InSitu Composition Measurement The Vis-NIR spectrum measured by the two InSitu Composition spectrometers is used for the analysis of fluid hydrocarbon composition, GOR, CO2, water content, and mud filtrate contamination. In addition to the improved measurement capabilities of the dual spectrometers, the compositional analysis is refined with an algorithm developed from Beer -Lambert’s law, which indicates that the optical absorption of a component is proportional to its concentratio n. Thus the spectrum of a live oil is a weighted sum of the absorptions of its individual components. The significant variation of the C6+ group in live oil is also accounted for in the algorithm. The C6+ group is the main component of stock-tank oil, and the detailed spectrum of the grating spectrometer in the 1,600- to 1,800-nm range was used to characterize stock-tank oil on the basis of wax and branched-alkane content. From this data, the fluid composition analysis corrects for spectrum variation. An independent determination of ethane (C2) is now possible for the first time owing to the increased resolution of the grating spectrometer together with advanced deconvolution. This extra detail in analyzing light -end hydrocarbon components is critical for productivity analysis and economic assessment. The ratio of C1/C2 can also help determine whether the hydrocarbon source is biogenic or thermogenic. From the composition, the gas/oil ratio (GOR) and condensate/gas ratio (CGR) are determined from the vaporizations of the hydrocarbon and CO2 components at standard conditions for flashing a live fluid. CT-1 51 3. InSitu GOR From t he enhanced co mposit ion measurement, the gas/oil ratio (GOR) and condensate/gas rat io (CGR) are det ermined fro m the vaporizations o f the hydrocarbon and CO2 components at standard condit io ns fo r flashing a live fluid. This new implementation provides greater range and increased accuracy over the measurement offered in previous generat ion tools (LFA live fluid analyzer and CFA compo sit ional fluid analyzer). Results can now be entered into reservo ir simulat ion mode ls wit h confidence. 4. InSitu CO2 Measureme nt Carbon d io xide is present in the fluids of many reservo irs and must be accurately accounted for when deve loping hydrocarbon reserves. Howe ver, reliable quant ificat ion of CO2 fro m reservo ir fluid samp les can be difficu lt , especially if there is water in the collected samples, because CO2 easily reacts wit h wat er, whether from mud filtrate contaminat ion or formatio n water. The measurement of CO2 co ntent by the InS itu Fluid Analyzer system is perfor med with the filter arra y spect rometer. A dedicated channel to the CO2 absorption peak is co mplemented with dual base line channels above and below that subtract out the over lapping spectrum of hydro-carbon and small amount s of water. The new channels and enhanced algorithm make it possible to plot the CO2 content in real t ime, together with upper and lower accuracy tolerances on the measurement. This give s increased confidence in the measurement accuracy under different environments. CT-1 52 5. InSitu Color Measurement Wit h optical f ilt er s improved for high-temperature performance, the InSitu Color reservoir fluid colo r mea sureme nt uses the extended measurement range of the 20-channel filter array spectro meter to determine fluid color. The reliabilit y o f the measurement is supported by cont inuous real-t ime aut o- calibrat ion, applicat ion of a contaminat ion algorithm that uses all the spect ro meter channe ls, and a coated- window detection flag for enhanced QC. The color measurement supports fluid ident ificat ion, determinat ion of asphaltene gradients, and pH measurement. 6. InSitu Density Measure ment Measuring densit y downho le at reservoir condit ions provides numerous advantages over surface mea surement s, especially for determining pressure gradients in thin beds or carbonate transit io n zones. This rea l-t ime measurement directly yields the slope of the pressure gradient for the ident if icat ion of f lu id contacts. The InS itu Densit y reser vo ir fluid densit y measurement is based on t he reso nance character ist ics of a vibrat ing sensor that oscillates in two perpendicular modes within t he flu id. Simple physical models describe the resonance frequency and qualit y factor of the sensor in relat ion to the fluid densit y. Dual-mode oscillat ion is superior to other resonant t echnique s be cause it minimizes the effects of pressure and temperature on the senso r t hrough commo n mo de reject ion, which further improves the accuracy o f the measure ment. The InSitu Densit y measurement is made under flowing condit io ns, and the resonato r is resist ive to corrosive fluids. 7. InSitu fluorescence Measurement The InS it u Fluo rescence reservo ir fluid fluorescence measurement detects free gas bubbles and ret rograde co ndensate liqu id dropout for single-phase assurance while conduct ing DFA and sampling. Fluid t ype is also ident ified. The result ing fluid phase informat ion is especially useful for defin ing the difference between retrograde condensates and vo lat ile oils, which can have similar GORs and live-o il densit ies. Because the fluorescence measurement is also sensit ive to liqu id precip it at io n in a co ndensate gas when the flowing pressure falls below the dewpo int, it can be used to monitor phase separation in real time to ensure the collect ion of representative single-pha se sa mples. CT-1 53 Dua l f luor esc enc e de tector Gas de tec t or Li gh t so urce Sap p h ir e p r i s m Flowline Downho le reflectio n a nd dual fluorescence measurements provide assurance that the reservo ir flu id is in single phase before DFA and sampling. 8. InSitu pH Measure ment The format io n water pH is a key parameter in water chemistr y, used for calculat ing the corro sion a nd scaling potential of the water, under-standing reservo ir connectivit y and transit ion zones, determining the co mpat ibilit y o f inject ion water and for mat ion water, and designat ing opt ima l salinit y a nd pH windows for polymer and gel inject ions. Obtaining high-qualit y DFA and samples o f format io n water relies on tracking mud filtrate contamination by dist inguishing bet ween fo r mat ion water and mud filtrate in real time. Water pH is measured wit h the InS itu pH reservoir fluid pH measurement by injecting dye into the fo r mat ion fluid be ing pumped through the InS itu Fluid Analyzer flowline. The pH is calcu lat ed with 0.1- unit accuracy from the relevant visible wavelengths of the dye signal me asured by a n o pt ical fluid analyzer. Making the measurement at reservoir condit io ns avo ids the irreversible pH change s that occur when samples are brought to the surface, as acid gases and salts co me out of solut ion wit h reduced temperature and pressure and routine laboratory flashing of t he sa mp le. InS it u pH senso r measures fluids across the entire flowline cross sect ion, which makes it more robust than potentio metric methods of measurement, which are compromised when oil and mud foul elect ro de surfaces. Direct pH measurements with dye also avo id the limitations of resist ivit y measurement in mo nitoring contaminat ion, which requires a sufficient resist ivit y contrast bet ween t he filtrate and for mat ion water. CT-1 54 InS itu pH measureme nt of pH = 3 indicated high CO2 that was missed in laboratory analys is conducted after the sample was flashed. W ith knowledge of the actual CO2 content, the operator could minimize su bsequent corrosion and scaling problems. CT-1 55 9. Flowline Resistivity Measurement The flowline resist ivit y se nsor uses the same proven techno logy emplo yed in Schlumberger format io n test ing tools. W it h the resistivit y sensor included in the DFA assembly, it is possible to monitor resist ivit y during dual-packer sampling operations in W BM. 10. Flowline Pressure and T emperature Measurements The high-reso lut io n pressure and temperature sensors used in Schlumberger format ion testing too ls a re also inco rporated in the InS itu Fluid Analyzer ser vice. Direct measurement of pressure and temperature is esse nt ia l to ident ify the posit ion in the PVT envelo pe where the other fluid pro pertie s, such as densit y, are measured, especially when the sensors are placed downstream of the flo wline pump. The DFA measurements within the flowline can then be accurately translated ba ck to virg inal reservo ir condit ions by emplo ying well-known equation-of-state (EOS) algorithms. 11. Sampling Quality Control Wit h InS itu Fa mily me asure ments, the reservo ir fluid is analyzed before samples are collected, which subst ant ia lly improves the qualit y of the fluid samples. The sampling process is optimized in terms of where and when to sample and how many samples to collect. In addit ion, the pressure senso r pro vides an accurate record of over pressuring the sample contents before the sampling chamber is clo sed. The compre hensive InS itu Pro real-time qualit y control and interpretation software depth view co mbine s the results of pressure and fluids analysis from mult iple data CT-1 56 sources. 12. Chain of Custody DFA also provide s a co nvenient technique for establishing a chain of custody for fluid samp le s. Differences between analyt ical data acquired downho le and that from corresponding samples in the laboratory are a strong indicat ion that the laboratory sample may ha ve bee n co mpro mised. 13. Fluid Profiling Fluid Pro filing charact erizat io n provides the distribut ion of fluid properties across the reservo ir, beyo nd what a t radit ional sampling program can achieve. The quant ified accuracy o f the InSitu Family mea surements expands DFA applicat ion from a single well to mult iple-well analysis, defining reservo ir architecture across the ent ire field. Quantificat ion of the variation of fluid propert ies at higher reso lut io n than conventional sampling and analysis is key to identifying and different iat ing composit ional grading, fluid contacts, and reservo ir compart ments. 14. InSitu Fluid Analyzer Mechanical Specifications Tem pera tu r e r a ti n g, deg F 350 [175] Pressure rat ing, p si [MP a ] 25,000 [170] Diame te r , in [cm ] 5 [12.7] Length , ft [m] 10.43 [3.18] Weight , l b m [k g] 368 [167] CT-1 57 Thank you for calling Schlumberger Company Caelus Energy Alaska Well CT- 1 Section 8.5 Rig Arctic Fox Field Wild Cat Borough North Slope Alaska Country USA Report by WL: A Shetty/ P Trofimoff/ L Mejia PTS:A Shende Reviewed by WL Domain: H Dumont, G Garcia Logging Date 12-Feb-2016 Report Date 19-Feb-2016 Run Number R1D3 Job Number PTS: DS-2016-06293 Modular Formation Dynamics Tester Pressure Time plots CT-1 3 DISCLAIMER ANY INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES, OR RECOMMENDATION FURNISHED WITH THE SERVICES OR OTHERWISE COMMUNICATED BY SCHLUMBERGER TO CUSTOMER AT ANY TIME IN CONNECTION WITH THE SERVICES ARE OPINIONS BASED ON INFERENCES FROM MEASUREMENTS, EMPIRICAL RELATIONSHIPS AND/OR ASSUMPTIONS, WHICH INFERENCES, EMPIRICAL RELATIONSHIPS AND/OR ASSUMPTIONS ARE NOT INFALLIBLE, AND WITH RESPECT TO WHICH PR OFESSIONALS IN THE INDUSTRY MAY DIFFER. ACCORDINGLY, SCHLUMBERGER CANNOT AND DOES NOT WARRANT THE ACCURACY, CORRECTNESS OR COMPLETENESS OF ANY SUCH INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES OR RECOMMENDATION. CUSTOMER ACKNOWLEDGES THAT IT IS ACCEPTING THE SERVICES "AS IS", THAT SCHLUMBERGER MAKES NO REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, OF ANY KIND OR DESCRIPTION IN RESPECT THERETO. SPECIFICALLY, CUSTOMER ACKNOWLEDGES THAT SCHLUMBERGER DOES NOT WARRANT THAT ANY INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES, OR RECOMMENDATION IS FIT FOR A PARTICULAR PURPOSE, INCLUDING BUT NOT LIMITED TO COMPLIANCE WITH ANY GOVERNMENT REQUEST OR REGULATORY REQUIREMENT. CUSTOMER FURTHER ACKNOWLEDGES THAT SUCH SERVICES ARE DELIVERED WITH THE EXPLICIT UNDERSTANDING AND AGREEMENT THAT ANY ACTION TAKEN BASED ON THE SERVICES RECEIVED SHALL BE AT ITS OWN RISK AND RESPONSIBILITY AND NO CLAIM SHALL BE MADE AGAINST SCHLUMBERGER AS A CONSEQUENCE THEREOF. Pressure vs. Time PlotRun No:R1D3 Test No:3 Probe MD:5663.46ft Probe TVD:5536.71ft6-Feb-2016Caelus Energy AlaskaWild CatConPr_R04_Sta003_MDT_EDTACT-1Mud Before(2881.92psi)Start Drawdown(2756.76psi)Start Buildup(1281.94psi)Last Buildup(2771.82psi)Mud After(2880.52psi)psic/min degFcm3 psiETIM (s)050010001500200025003000350015002000250030000100020009095100105110115120051015202770278027902800SRQP(psi), MRSR Quartz Gauge PressurePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line PressureHMS1(c/min), MRHY 1 Motor SpeedPQQT1(degF), MRPQ 1 Quartz Gauge TemperaturePQPTV1(cm3), MRPQ 1 Pretest VolumePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line Pressure Tool Type: MDT Pretest Type: Volumetric Drawdown Pretest Pretest Status: Valid Test Packer/Probe Type: XLarge-Diameter probe Primary Gauge: PQQP1 Formation Pressure: 2771.82 (psi) Last Read Buildup Pressure : 2771.82 (psi) Drawdown Mobility: 0.14 (mD/cP) Mud Pressure Before: 2881.92 (psi) Mud Pressure After: 2880.52 (psi) Temperature Before: 141.39 (degF) Temperature After: 139.26 (degF) Pretest Rate: 0.65 (cm3/s) Pretest Volume: 3.3 (cm3) Comments: Successive pretests stabilizing at lower pressures, indicating supercharging Flow Regime ID PlotRun No:R1D3 Test No:3 Probe MD:5663.46ft Probe TVD:5536.71ft Delta Time100101102103110210310410Spherical Derivative(psis)Radial Derivative(psi) Spherical Specialized PlotSpherical Time Function1.00.5-0.014001600180020002200240026002800Spherical Pressure(psi) Last Buildup Pressure: 2771.82 (psi) Extrapolated Pressure: Buildup Mobility: Spherical Slope: Radial Specialized PlotRadial Time Function1.00.5-0.014001600180020002200240026002800Radial Pressure(psi) Actual Spherical Slope on Spherical Derivative: Ideal Slope: 0 Actual Spherical Slope on Radial Derivative: Ideal Slope: -0.5 Actual Radial Slope on Spherical Derivative: Ideal Slope: 0.5 Last Buildup Pressure: 2771.82 (psi) Extrapolated Pressure: Actual Radial Slope on Radial Derivative: Ideal Slope: 0 Horizontal Mobility Thickness: Radial Slope: Pressure vs. Time PlotRun No:R1D3 Test No:5 Probe MD:5667.89ft Probe TVD:5541.15ft6-Feb-2016Caelus Energy AlaskaWild CatConPr_R04_Sta004_MDT_EDTACT-1Mud Before(2883.35psi)Start Drawdown(2810.62psi)Start Buildup(1902.33psi)Last Buildup(2812.21psi)Mud After(2882.9psi)psic/min degFcm3 psiETIM (s)0200400600800100012001400160020002200240026002800300001000200012012212412612813005101520281028202830SRQP(psi), MRSR Quartz Gauge PressurePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line PressureHMS1(c/min), MRHY 1 Motor SpeedPQQT1(degF), MRPQ 1 Quartz Gauge TemperaturePQPTV1(cm3), MRPQ 1 Pretest VolumePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line Pressure Tool Type: MDT Pretest Type: Volumetric Drawdown Pretest Pretest Status: Tight Test Packer/Probe Type: XLarge-Diameter probe Primary Gauge: PQQP1 Formation Pressure: Last Read Buildup Pressure : 2812.21 (psi) Drawdown Mobility: Mud Pressure Before: 2883.35 (psi) Mud Pressure After: 2882.9 (psi) Temperature Before: 139.19 (degF) Temperature After: 139.1 (degF) Pretest Rate: 0.43 (cm3/s) Pretest Volume: 3.24 (cm3) Comments: Tight Test Flow Regime ID PlotRun No:R1D3 Test No:5 Probe MD:5667.89ft Probe TVD:5541.15ft Delta Time100101102103110210310410Spherical Derivative(psis)Radial Derivative(psi) Spherical Specialized PlotSpherical Time Function1-020002200240026002800Spherical Pressure(psi) Last Buildup Pressure: 2812.21 (psi) Extrapolated Pressure: Buildup Mobility: Spherical Slope: Radial Specialized PlotRadial Time Function1.00.5-0.020002200240026002800Radial Pressure(psi) Actual Spherical Slope on Spherical Derivative: Ideal Slope: 0 Actual Spherical Slope on Radial Derivative: Ideal Slope: -0.5 Actual Radial Slope on Spherical Derivative: Ideal Slope: 0.5 Last Buildup Pressure: 2812.21 (psi) Extrapolated Pressure: Actual Radial Slope on Radial Derivative: Ideal Slope: 0 Horizontal Mobility Thickness: Radial Slope: Pressure vs. Time PlotRun No:R1D3 Test No:8 Probe MD:5674.87ft Probe TVD:5548.12ft6-Feb-2016Caelus Energy AlaskaWild CatConPr_R04_Sta005_MDT_EDTACT-1Mud Before(2886.82psi)Start Drawdown(2591.63psi)Start Buildup(1792.27psi)Last Buildup(2886.54psi)Mud After(2886.82psi)psic/min degFcm3 psiETIM (s)050010001500200025003000350018002000220024002600280001000200013213313413513613713813905101520259025922594SRQP(psi), MRSR Quartz Gauge PressurePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line PressureHMS1(c/min), MRHY 1 Motor SpeedPQQT1(degF), MRPQ 1 Quartz Gauge TemperaturePQPTV1(cm3), MRPQ 1 Pretest VolumePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line Pressure Tool Type: MDT Pretest Type: Volumetric Drawdown Pretest Pretest Status: Tight Test Packer/Probe Type: XLarge-Diameter probe Primary Gauge: PQQP1 Formation Pressure: Last Read Buildup Pressure : 2886.54 (psi) Drawdown Mobility: Mud Pressure Before: 2886.82 (psi) Mud Pressure After: 2886.82 (psi) Temperature Before: 139.03 (degF) Temperature After: 139.21 (degF) Pretest Rate: 0.59 (cm3/s) Pretest Volume: 1.76 (cm3) Comments: Tight Test Flow Regime ID PlotRun No:R1D3 Test No:8 Probe MD:5674.87ft Probe TVD:5548.12ft Delta Time100101102103110210310410510610710810Spherical Derivative(psis)Radial Derivative(psi) Spherical Specialized PlotSpherical Time Function1.00.5-0.0180020002200240026002800Spherical Pressure(psi) Last Buildup Pressure: 2886.54 (psi) Extrapolated Pressure: Buildup Mobility: Spherical Slope: Radial Specialized PlotRadial Time Function1.00.5-0.0180020002200240026002800Radial Pressure(psi) Actual Spherical Slope on Spherical Derivative: Ideal Slope: 0 Actual Spherical Slope on Radial Derivative: Ideal Slope: -0.5 Actual Radial Slope on Spherical Derivative: Ideal Slope: 0.5 Last Buildup Pressure: 2886.54 (psi) Extrapolated Pressure: Actual Radial Slope on Radial Derivative: Ideal Slope: 0 Horizontal Mobility Thickness: Radial Slope: Pressure vs. Time PlotRun No:R1D3 Test No:0 Packer Interval MD:5676.02 - 5676.64ft Packer Interval TVD:5549.28 - 5549.9ft6-Feb-2016Caelus Energy AlaskaWild CatConPr_R04_Sta006_MDT_EDTACT-1Mud Before(2887.57psi)Start Drawdown(2969.91psi)Start Buildup(1391.08psi)Last Buildup(2458.09psi)Mud After(2902.62psi)psic/min degFcm3 psiETIM (s)01000200030004000500060007000500100015002000250030000500100015001301351401451505101520100020003000SRQP(psi), MRSR Quartz Gauge PressurePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line PressureHMS1(c/min), MRHY 1 Motor SpeedSRQT(degF), MRSR Quartz Gauge TemperaturePQPTV1(cm3), MRPQ 1 Pretest VolumeSRQP(psi), MRSR Quartz Gauge Pressure Tool Type: MDT Pretest Type: Volumetric Drawdown Pretest Pretest Status: Dry Test Packer/Probe Type: OPN-7-AA Saturn Primary Gauge: SRQP Formation Pressure: Last Read Buildup Pressure : 2458.09 (psi) Drawdown Mobility: Mud Pressure Before: 2887.57 (psi) Mud Pressure After: 2902.62 (psi) Temperature Before: 138.38 (degF) Temperature After: 140.41 (degF) Pretest Rate: 3.79 (cm3/s) Pretest Volume: 238.47 (cm3) Comments: Dry test Flow Regime ID PlotRun No:R1D3 Test No:0 Probe MD:5676.33ft Probe TVD:5549.59ft Delta Time100101102110210310410Spherical Derivative(psis)Radial Derivative(psi) Spherical Specialized PlotSpherical Time Function1-0140016001800200022002400Spherical Pressure(psi) Last Buildup Pressure: 2458.09 (psi) Extrapolated Pressure: Buildup Mobility: Spherical Slope: Radial Specialized PlotRadial Time Function21-0140016001800200022002400Radial Pressure(psi) Actual Spherical Slope on Spherical Derivative: Ideal Slope: 0 Actual Spherical Slope on Radial Derivative: Ideal Slope: -0.5 Actual Radial Slope on Spherical Derivative: Ideal Slope: 0.5 Last Buildup Pressure: 2458.09 (psi) Extrapolated Pressure: Actual Radial Slope on Radial Derivative: Ideal Slope: 0 Horizontal Mobility Thickness: Radial Slope: Pressure vs. Time PlotRun No:R1D3 Test No:0 Packer Interval MD:6385.16 - 6385.78ft Packer Interval TVD:6258.41 - 6259.03ft6-Feb-2016Caelus Energy AlaskaWild CatConPr_R04_Sta007_MDT_EDTACT-1Mud Before(3255.12psi)Start Drawdown(2641.64psi)Start Buildup(410.29psi)Last Buildup(2800.62psi)Mud After(3268.37psi)psic/min degFcm3 psiETIM (s)05001000150020002500300035004000450050005500050010001500200025003000350001401451501551605101520100020003000SRQP(psi), MRSR Quartz Gauge PressurePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line PressureHMS1(c/min), MRHY 1 Motor SpeedSRQT(degF), MRSR Quartz Gauge TemperaturePQPTV1(cm3), MRPQ 1 Pretest VolumeSRQP(psi), MRSR Quartz Gauge Pressure Tool Type: MDT Pretest Type: Volumetric Drawdown Pretest Pretest Status: Valid Test Packer/Probe Type: OPN-7-AA Saturn Primary Gauge: SRQP Formation Pressure: 2800.62 (psi) Last Read Buildup Pressure : 2800.62 (psi) Drawdown Mobility: 0.04 (mD/cP) Mud Pressure Before: 3255.12 (psi) Mud Pressure After: 3268.37 (psi) Temperature Before: 145.85 (degF) Temperature After: 154.48 (degF) Pretest Rate: 1.83 (cm3/s) Pretest Volume: 612.54 (cm3) Comments: Pretest building up and supercharged, but not stablized Flow Regime ID PlotRun No:R1D3 Test No:0 Probe MD:6385.47ft Probe TVD:6258.72ft Delta Time100101102103010110210310410Spherical Derivative(psis)Radial Derivative(psi) Spherical Specialized PlotSpherical Time Function1-05001000150020002500Spherical Pressure(psi) Last Buildup Pressure: 2800.62 (psi) Extrapolated Pressure: Buildup Mobility: Spherical Slope: Radial Specialized PlotRadial Time Function321-05001000150020002500Radial Pressure(psi) Actual Spherical Slope on Spherical Derivative: Ideal Slope: 0 Actual Spherical Slope on Radial Derivative: Ideal Slope: -0.5 Actual Radial Slope on Spherical Derivative: Ideal Slope: 0.5 Last Buildup Pressure: 2800.62 (psi) Extrapolated Pressure: Actual Radial Slope on Radial Derivative: Ideal Slope: 0 Horizontal Mobility Thickness: Radial Slope: Pressure vs. Time PlotRun No:R1D3 Test No:0 Packer Interval MD:6436.2 - 6436.82ft Packer Interval TVD:6309.45 - 6310.06ft6-Feb-2016Caelus Energy AlaskaWild CatConPr_R04_Sta008_MDT_EDTACT-1Mud Before(3282.9psi)Start Drawdown(3263.6psi)Start Buildup(651.05psi)Last Buildup(3027.2psi)Mud After(3283.24psi)psic/min degFcm3 psiETIM (s)050010001500200025005001000150020002500300035000500100015001401451501551605101520100020003000SRQP(psi), MRSR Quartz Gauge PressurePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line PressureHMS1(c/min), MRHY 1 Motor SpeedSRQT(degF), MRSR Quartz Gauge TemperaturePQPTV1(cm3), MRPQ 1 Pretest VolumeSRQP(psi), MRSR Quartz Gauge Pressure Tool Type: MDT Pretest Type: Volumetric Drawdown Pretest Pretest Status: Tight Test Packer/Probe Type: OPN-7-AA Saturn Primary Gauge: SRQP Formation Pressure: Last Read Buildup Pressure : 3027.2 (psi) Drawdown Mobility: Mud Pressure Before: 3282.9 (psi) Mud Pressure After: 3283.25 (psi) Temperature Before: 154.83 (degF) Temperature After: 156.44 (degF) Pretest Rate: 6.38 (cm3/s) Pretest Volume: 82.34 (cm3) Comments: Tight Test Flow Regime ID PlotRun No:R1D3 Test No:0 Probe MD:6436.51ft Probe TVD:6309.75ft Delta Time100101102103110210310410510610Spherical Derivative(psis)Radial Derivative(psi) Spherical Specialized PlotSpherical Time Function1-010001500200025003000Spherical Pressure(psi) Last Buildup Pressure: 3027.2 (psi) Extrapolated Pressure: Buildup Mobility: Spherical Slope: Radial Specialized PlotRadial Time Function1-010001500200025003000Radial Pressure(psi) Actual Spherical Slope on Spherical Derivative: Ideal Slope: 0 Actual Spherical Slope on Radial Derivative: Ideal Slope: -0.5 Actual Radial Slope on Spherical Derivative: Ideal Slope: 0.5 Last Buildup Pressure: 3027.2 (psi) Extrapolated Pressure: Actual Radial Slope on Radial Derivative: Ideal Slope: 0 Horizontal Mobility Thickness: Radial Slope: Pressure vs. Time PlotRun No:R1D3 Test No:0 Packer Interval MD:6110.33 - 6110.95ft Packer Interval TVD:5983.58 - 5984.2ft6-Feb-2016Caelus Energy AlaskaWild CatConPr_R04_Sta009_MDT_EDTACT-1Mud Before(3113.15psi)Start Drawdown(3195.2psi)Start Buildup(1775.49psi)Last Buildup(2885.84psi)Mud After(3115.66psi)psic/min degFcm3 psiETIM (s)0200400600800100012005001000150020002500300035000500100015001401451501551605101520100020003000SRQP(psi), MRSR Quartz Gauge PressurePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line PressureHMS1(c/min), MRHY 1 Motor SpeedSRQT(degF), MRSR Quartz Gauge TemperaturePQPTV1(cm3), MRPQ 1 Pretest VolumeSRQP(psi), MRSR Quartz Gauge Pressure Tool Type: MDT Pretest Type: Volumetric Drawdown Pretest Pretest Status: Tight Test Packer/Probe Type: OPN-7-AA Saturn Primary Gauge: SRQP Formation Pressure: Last Read Buildup Pressure : 2885.84 (psi) Drawdown Mobility: Mud Pressure Before: 3113.15 (psi) Mud Pressure After: 3115.66 (psi) Temperature Before: 156.24 (degF) Temperature After: 154.71 (degF) Pretest Rate: 3.36 (cm3/s) Pretest Volume: 108.75 (cm3) Comments: Tight Test Flow Regime ID PlotRun No:R1D3 Test No:0 Probe MD:6110.64ft Probe TVD:5983.89ft Delta Time100101102110210310410Spherical Derivative(psis)Radial Derivative(psi) Spherical Specialized PlotSpherical Time Function1-0180020002200240026002800Spherical Pressure(psi) Last Buildup Pressure: 2885.84 (psi) Extrapolated Pressure: Buildup Mobility: Spherical Slope: Radial Specialized PlotRadial Time Function21-0180020002200240026002800Radial Pressure(psi) Actual Spherical Slope on Spherical Derivative: Ideal Slope: 0 Actual Spherical Slope on Radial Derivative: Ideal Slope: -0.5 Actual Radial Slope on Spherical Derivative: Ideal Slope: 0.5 Last Buildup Pressure: 2885.84 (psi) Extrapolated Pressure: Actual Radial Slope on Radial Derivative: Ideal Slope: 0 Horizontal Mobility Thickness: Radial Slope: Pressure vs. Time PlotRun No:R1D3 Test No:0 Packer Interval MD:5957.19 - 5957.81ft Packer Interval TVD:5830.44 - 5831.06ft6-Feb-2016Caelus Energy AlaskaWild CatConPr_R04_Sta010_MDT_EDTACT-1Mud Before(3034.36psi)Start Drawdown(3042.74psi)Start Buildup(1043.01psi)Last Buildup(2793.71psi)Mud After(3034.1psi)psic/min degFcm3 psiETIM (s)020040060080010001200140016001000150020002500300035000500100015001401451501551605101520100020003000SRQP(psi), MRSR Quartz Gauge PressurePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line PressureHMS1(c/min), MRHY 1 Motor SpeedSRQT(degF), MRSR Quartz Gauge TemperaturePQPTV1(cm3), MRPQ 1 Pretest VolumeSRQP(psi), MRSR Quartz Gauge Pressure Tool Type: MDT Pretest Type: Volumetric Drawdown Pretest Pretest Status: Valid Test Packer/Probe Type: OPN-7-AA Saturn Primary Gauge: SRQP Formation Pressure: 2793.71 (psi) Last Read Buildup Pressure : 2793.71 (psi) Drawdown Mobility: 0.04 (mD/cP) Mud Pressure Before: 3034.36 (psi) Mud Pressure After: 3034.1 (psi) Temperature Before: 153.19 (degF) Temperature After: 150.81 (degF) Pretest Rate: 3.82 (cm3/s) Pretest Volume: 131.94 (cm3) Comments: Pretest building up supercharged Flow Regime ID PlotRun No:R1D3 Test No:0 Probe MD:5957.5ft Probe TVD:5830.75ft Delta Time100101102110210310410510Spherical Derivative(psis)Radial Derivative(psi) Spherical Specialized PlotSpherical Time Function1-01000150020002500Spherical Pressure(psi) Last Buildup Pressure: 2793.71 (psi) Extrapolated Pressure: Buildup Mobility: Spherical Slope: Radial Specialized PlotRadial Time Function21-01000150020002500Radial Pressure(psi) Actual Spherical Slope on Spherical Derivative: Ideal Slope: 0 Actual Spherical Slope on Radial Derivative: Ideal Slope: -0.5 Actual Radial Slope on Spherical Derivative: Ideal Slope: 0.5 Last Buildup Pressure: 2793.71 (psi) Extrapolated Pressure: Actual Radial Slope on Radial Derivative: Ideal Slope: 0 Horizontal Mobility Thickness: Radial Slope: Pressure vs. Time PlotRun No:R1D3 Test No:0 Packer Interval MD:5763.17 - 5763.79ft Packer Interval TVD:5636.42 - 5637.04ft6-Feb-2016Caelus Energy AlaskaWild CatConPr_R04_Sta011_MDT_EDTACT-1Mud Before(2932.92psi)Start Drawdown(3017.31psi)Start Buildup(1351.14psi)Last Buildup(2856.26psi)Mud After(2933.82psi)psic/min degFcm3 psiETIM (s)050010001500200025001500200025003000050010001401451501551605101520280028502900SRQP(psi), MRSR Quartz Gauge PressurePQQP1(psi), MRPQ 1 Quartz Gauge Pressure, Sample Line PressureHMS1(c/min), MRHY 1 Motor SpeedSRQT(degF), MRSR Quartz Gauge TemperaturePQPTV1(cm3), MRPQ 1 Pretest VolumeSRQP(psi), MRSR Quartz Gauge Pressure Tool Type: MDT Pretest Type: Volumetric Drawdown Pretest Pretest Status: Tight Test Packer/Probe Type: OPN-7-AA Saturn Primary Gauge: SRQP Formation Pressure: Last Read Buildup Pressure : 2856.26 (psi) Drawdown Mobility: Mud Pressure Before: 2932.92 (psi) Mud Pressure After: 2933.82 (psi) Temperature Before: 150 (degF) Temperature After: 146.13 (degF) Pretest Rate: 3.19 (cm3/s) Pretest Volume: 56.43 (cm3) Comments: Flow Regime ID PlotRun No:R1D3 Test No:0 Probe MD:5763.48ft Probe TVD:5636.73ft Delta Time100101102103210310410510Spherical Derivative(psis)Radial Derivative(psi) Spherical Specialized PlotSpherical Time Function1-014001600180020002200240026002800Spherical Pressure(psi) Last Buildup Pressure: 2856.26 (psi) Extrapolated Pressure: Buildup Mobility: Spherical Slope: Radial Specialized PlotRadial Time Function1-014001600180020002200240026002800Radial Pressure(psi) Actual Spherical Slope on Spherical Derivative: Ideal Slope: 0 Actual Spherical Slope on Radial Derivative: Ideal Slope: -0.5 Actual Radial Slope on Spherical Derivative: Ideal Slope: 0.5 Last Buildup Pressure: 2856.26 (psi) Extrapolated Pressure: Actual Radial Slope on Radial Derivative: Ideal Slope: 0 Horizontal Mobility Thickness: Radial Slope: Technical Report Title Date Client: Caelus Energy Alaska, Smith Bay LLC Field: Wildcat Exploration Rig: Doyon Arctic Fox Date: February 19, 2016 Surface Data Logging End of Well Report CT-1 TABLE OF CONTENTS 1. General Information 2. Daily Summary 3. Days vs. Depth 4. After Action Review 5. Formation Tops 6. Show Reports 7. Mud Record 8. Bit Record 9. Morning Reports 10. Survey Report Digital Data to include: Final Log Files Final End of Well Report Final LAS Exports Halliburton Log Viewer EMF Log Viewer GENERAL WELL INFORMATION Company: Caelus Energy Alaska Smith Bay, LLC Rig: Doyon Arctic Fox Well: CT-1 Field: Wildcat Exploration Borough: North Slope Borough State: Alaska Country: United States API Number: 50-879-20021-00-00 Sperry Job Number: AK-XX-0903061217 Job Start Date: 13 Jan 2016 Spud Date: 19 Jan 2016 Total Depth: 7070’ MD, 6954’ TVD North Reference: True Declination: 16.314° Dip Angle: 80.89° Total Field Strength: 57487 nT Date Of Magnetic Data: 20 January 2016 Wellhead Coordinates N: North 70° 49’ 41.480” Wellhead Coordinates W: West 154° 18’ 27.258“ Drill Floor Elevation 18.5’ Ground Elevation: 4.9’ Permanent Datum: Mean Sea Level SDL Engineers: Jeremy Tiegs, Ashley Wilderom, Doug Acker, Jacob Robertson, Leigh Ann Rasher SDL Sample Catchers: Kyle Blazian, Enoc Velez Martinez, Autumn Gould, Michael LaDouceur Company Geologist: Zach Beekman, Jeff McBeth, Michael Watt, Joanne Schwetz Company Representatives: Mike Thornton, Jack Keener, Wade Frame, Mike Ross SSDS Unit Number: 121 DAILY SUMMARY 01/19/2016 SDL rigged up on location. Wait on the unit to warm up before rigging up. Pipe shed was loaded with drill pipe and heavy weight drill pipe. Began rigging up and ran gas line to the unit. Rigged up network connections with MWD and WITS to Totco and then the well was spudded and drilled ahead to 253’ MD. 01/20/2016 Continued to drill ahead from 253’ MD to 315’ MD and then pulled out of the hole to surface to break down bit and sub. Made up BHA #1 as per Sperry directional service; ran in the hole to 300’ MD and conducted a shallow pulse test. Tagged the bottom at 310’ MD and then continued drilling the surface section to 1295’ MD. Gas: The max gas was 32 units at 646’ MD and the average drilling background gas was 8 units. Fluids: There was 0 barrels of polymer based mud lost down hole. Geology: Alternating samples of sandstone that vary in levels of clay content. One type of sandstone is fine grained well sorted and is dominantly unconsolidated clear to white grains. The other commonly seen sandstone is moderately consolidated and is much more opaque and dark brown to tan in color. It contains much less quartz and higher amounts of feldspars and lithics. These much coarser grained cuttings have are blocky and more angular grains. When large amounts of clay have been observed they are hygroturgid and in very rare cases are they cryptoturgid. And break in an amorphous or plastic manner. Organics and carbonaceous material can be seen throughout most samples and in a rare case the sample at 750' MD had a small amount bluish residual fluorescence. 01/21/2016 Drilled ahead from 1295' MD to 2443' MD; back reaming a full stand before every connection. Gas: The max gas was 40 units at 2324’ MD and the average drilling background gas was 12 units. Fluids: There was 0 barrels of polymer based mud lost down hole. Geology: Lithology seen today was dominated by clay content. Varying amounts of sandstone were present until around 1900' MD and then the clay became +90% of the sample. Carbonaceous material was present until 1500' MD after which no particles were fluorescing. Clays were swelling mostly in an irregular manner but from 1700'-1900' MD cryptofissile swelling was seen. Reaction to hydrochloric acid was seen in few samples randomly throughout the drilling today. Silt content also varied throughout the samples that were +90% clay. 01/22/2016 Drilled from 2,436' MD TD at 2,564' MD and pumped a high vis sweep (bottoms up calculated strokes was 6545) that had no significant increase in cuttings. Continued pumping until 1.5 bottoms up and then pulled out of the hole to 2,118' MD. Back reamed and circulated out of hole to surface and rigged up to run in the hole. The CVE was turned off due to clay balls packing off the flow line. Gas: The max gas was 24 units at 2523’ MD and the average drilling background gas was 18 units. Fluids: There was 0 barrels of polymer based mud lost down hole. Geology: From 2440’ MD to TD the cuttings were all clay. The last 60' had cryptofissile swelling and at the very end rare pieces of chert were seen. 01/23/2016 Ran into the hole from surface to 2,564' MD and then circulated 1.5 bottoms up to clean the hole. Pumped a 20 barrel dry job and then pulled out of the hole from 2,564' MD to surface. Racked back 5" HWDP and laid down BHA #1. Rigged up to run 10.75" casing. Gas: The max gas was 6 units and the average circulating background gas was 2 units. Fluids: There was 0 barrels of polymer based mud lost down hole. 01/24/2016 Troubleshot Volant casing tools and then made up shoe joint and float collar. Ran in the hole with 10-3/4" surface casing from surface to 2,547' MD and then circulated 2 bottoms up. Rigged up to run 5" DP and preparing to conduct a cement job. Gas: The max gas was 4 units and the average circulating background gas was 2 units. Fluids: There was 0 barrels of polymer based mud lost down hole. 01/25/2016 Pumped a 230 barrel lead cement job and a 48.4 barrel tail cement job with 42 barrels displaced with fresh water and bumped plug. Picked up out of hole and laid down landing joint. Nipple down the catch can and diverter system. Gas: The max gas was 4 units and the average circulating background gas was 2 units. Fluids: There was 0 barrels of polymer based mud lost down hole. 01/26/2016 Nipple up blowout preventer and the mud pits 1,2,3,6 and rock washer pit were cleaned. BOPE rigged up and Pit 6 was filled with water to prepare to batch up mud. Gas: The max gas was 4 units and the average circulating background gas was 2 units. Fluids: There was 0 barrels of polymer based mud lost down hole. 01/27/2016 Blowout preventer test equipment rigged up and picked up 74 joints of 5” DP. Rig tested Blowout preventer equipment and picked up bottom hole assembly to drill out shoe track. Performed a gas bag test with 10% Methane gas at shaker and received 968 units back. Gas gear calibrated and began tripping in hole. Gas: Performed a gas bag test with 10% Methane and received 968 units back. Zero unit’s gas all day since we are in closed hole. Fluids: There was 0 barrels of polymer based mud lost down hole. 01/28/2016 Tripped in the hole and drilled out the shoe track to 2585’ MD. The rig performed a Leak off test and pumped a dry job. Picked up out of hole and layed down BHA #2. Picked up BHA #3. Gas: Max gas of 8 units and an average gas of 4 units Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 01/29/2016 Made up BHA #3, tripped in the hole and began drilling ahead in Intermediate Section at 13:20. Optimize CVE at 2890' to 3050' MD; CVE is operating at 100% efficiency. We are currently drilling ahead in the formation at 3046' MD with formation gas of 8 units. Gas: Max gas of 16 units and an average gas of 4 units Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 01/30/2016 Drilled ahead in the intermediate section from 3,049’ MD to 4,233’ MD. Mass spectrometer went offline at 07:47/ 3,440’ MD and came back online at 08:27/ 3,485’ MD. Isotube samples were collected during the machine’s downtime at 08:04/ 3,464’ MD and 08:22/ 3,476’ MD. Attempted to switch to the Legacy trap while assessing CVE from 18:30 to 19:00 and 20:00 to 20:30. Noted trace appearance of C-2 at 4,037’ MD. Mudlogger notified geologist and collected isotube. Gas: Max gas of 40 units and an average gas of 15 units Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 01/31/2016 Drilled ahead in the intermediate section from 4,233' to 5,193' MD. Mass Spectrometer underwent routine maintenance and was calibrated prior to the 5,100' section at 19:48. Currently drilling ahead with the last sample 70% Claystone and 30% Silt. Background gas was around 25 units.. Gas: Max gas of 44 units and an average gas of 14 units Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/1/2016 Drilled ahead in the intermediate section from 5,193' to 5,415' MD. Drill pipe washed out and TOOH to 4,718' MD. Rigged in the hole to continue drilling. Gas spiked at 5,667' MD to 795 units. The Legacy gas trap was swapped out for the CVE moments before the gas spiked. The last sample consisted of 70% Claystone and 30% Sandstone. Currently we are in the process of running the GEOTAP with a hole depth of 5,934' MD Gas: Max gas of 795 units and an average gas of 73 units Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/2/2016 Continued drilling ahead from 5,934' MD to 6, 304’ MD. Conducted GEOTAP operations and continued drilling ahead to 6, 570’ MD. Max gas was 446 units at 6,438' MD. The last sample at 6,550' MD consisted of 90% Claystone and 10% Siltstone with a current background gas of 45 units Gas: Max gas of 446 units and an average gas of 57 units Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/03/2016 Continued to drill ahead to 6645’ MD and perform GeoTap logs. Begin to short trip and encounter a tight spot at 3135’ MD. Reamed to the shoe and pumped out of hole to surface. Trip in hole to 6521’ MD, ream to bottom, circulate bottoms up and pump dry job. Begin to pull out of the hole at a depth of 6059’ MD as of midnight. Gas: Max gas of 371 units at 6614’ MD and an average gas of 48 units. The max trip gas was 116 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. Geology: Samples consisted of 40% to 70% grey to brown, sub blocky, soft, non-swelling Claystone with 30% clear to translucent to brown, round, unconsolidated Siltstone and 60% grey to brown, firm to hard, angular to sub angular, fissile to platy, organic Shale. 02/04/2016 Pull out of hole from 6059’ MD and lay down BHA #3. Rig up and test BOPE’s. Pick up open hole wireline tools with wireline BHA. Preparing to run in hole with wireline tools as of midnight. SDL crew clean CVE gas equipment. Gas: The max trip gas was 6 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/05/2016 Run in hole with wireline tools and perform wireline logging run #1. Lay down run #1 tools and pick up wireline run #2 tools. Run in hole with wireline tools and perform wire line logging run #2. Lay down wireline tools as of midnight. Gas: The max trip gas was 5 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/06/2016 Perform wireline logging run #3 and lay down wireline tools. Begin to pick up tools for wireline run #4. Gas: The max trip gas was 3 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/07/2016 Perform wireline logging run #4 and lay down tools. Pick up BHA #4 and run in hole. Cut and slip drill line as of midnight. SDL crew calibrated THA using 10.030%, 20.029% and 98.986% C1 and gas chromatograph with low calibration cocktail gas. Gas: The max trip gas was 4 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/08/2016 Continue to cut and slip drill line. Run in hole to 660’ MD and wash in hole to 6600’ MD and begin to log from 6600’ MD to 6645’ MD. Drill ahead from 6645’ MD to 7070’ MD. Circulate and condition mud and perform short trip to 6449’ MD. Trip back to bottom, pump bottoms up sweep and circulate hole clean. Begin to pull out of hole as of midnight. Gas: Max gas of 240 units at 6690’ MD and an average gas of 45 units. The max trip gas was 29 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. Geology: Samples consisted of 60% to 70% dark grey to brown, firm to hard, unconsolidated Siltstone with minor Sandstone, Shale and Claystone from 6645’ MD to 6720’ MD. 50% to 75% dark grey to brown, firm to hard, dark black micro laminations, platy texture Shale with 25% to 40% Siltstone and minor Sandstone from 6720’ MD to 6900’ MD. 10% to 60% translucent to transparent to milky white, firm to soft, fine to very fine grain, well sorted, sub round, weakly to moderately cemented, non-calcareous Sandstone and 30% to 80% light brown to light grey, firm to soft, unconsolidated Siltstone with minor Shale and Claystone from 6900’ MD to 7070’ MD. 02/09/2016 Continue to pull out of hole and lay down BHA #4. Rig up wireline and perform wireline logging run. Gas: The max trip gas was 4 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/10/2016 Complete wireline looging and rig down wireline equipment. Perform rig maintenance and run in hole to 6943’ MD with 2-7/8” pipe. Wash down to 7069’ MD and pump cement plug. Pull out of hole to 6501’ MD and circulate. Pump second cement plug, pull out of the hole to 5996’ MD and circulate. Gas: The max trip gas was 47 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/11/2016 Circulate wiper ball and pump cement plug. Pull out of hole to 5492’ MD, circulate wiper ball and pump cement plug. Pull out of hole to 3850’ MD, pump wiper ball and pump dry job. Pull out of hole from 3850’ MD to 2100’ MD. Continue to pull out of the hole sideways and lay down stands. Monitor well and lay down drill pipe. Perform maintenance, rig up testing equipment and test BOPEs. Gas: The max trip gas was 14 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/12/2016 Finish testing BOPEs and rig down testing equipment. Make up BHA and run in hole to top of cement at 4732’ MD. Pull out of hole to 3036’ MD and circulate mud clean. Run in hole to 4701’ MD and wash down to top of plug and set 15K on cement. Pull out of hole to 3028’ MD, circulate and condition mud. Rig up injection equipment and begin to inject waste. Gas: The max trip gas was 34 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/13/2016 Continue injection operations. Phase III conditions stand down and monitor well. Gas: The max trip gas was 3 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 02/14/2016 Phase III conditions stand down, continue to wait on weather and monitor well. Pull out of hole and lay down 82 joints of drill pipe. Run in hole to 3072’ MD and condition mud before injection. Gas: The max trip gas was 4 units. Fluids: There was 6.4 barrels of 3% KCL based mud lost down hole. 02/15/2016 Inject second load of waste. Perform rig maintenance and pull out of the hole from 3072’ MD to 2505’ MD to lay down pipe. Circulate bottoms up at 2505’ MD and monitor well. Gas: The max trip gas was 71 units. Fluids: There was 0 barrels of 3% KCL based mud lost down hole. 0 1000 2000 3000 4000 5000 6000 7000 8000 0 5 10 15 20 25 30 35Measured Depth Rig Days Actual Actual WELL NAME: CT-1 OPERATOR: Caelus Energy Alaska, Smith Bay LLC MUD CO: Halliburton - Baroid RIG: Doyon Arctic Fox SPERRY JOB: AK-XX-0903061217 Days vs. Depth 13 Jan 2016 Sperry SDL Arrived on Location LOCATION: Wildcat Exploration AREA: North Slope Borough STATE: Alaska SPUD: 19-Jan-2016 TD: 8-Feb-2016 Commenced 13.5" Surface Hole Section On Bot: 17:47 19 Jan 2016 TD Surface Hole Section 2564' MD, 2522' TVD Off Bot: 02:41 22 Jan 2016 Landed 10.75" Casing 2547' MD, 2505' TVD 24 Jan 2016 Commenced 8.5" Intermediate Hole Section On Bot: 10:45 28 Jan 2016 POOH to P/U BHA #3 Off Bot: 11:50 28 Jan 2016 On Bot: 13:10 29 Jan 2016 POOH for wireline logging Off Bot: 02:32 03 Feb 2016 On Bot: 06:40 08 Feb 2016 TD Intermediate Section 7070' MD, 6954' TVD Off Bot: 17:05 08 Feb 2016 WELL NAME:LOCATION: OPERATOR:AREA: SPERRY JOB:STATE: RIG:HOLE SECTION: EMPLOYEE NAME:DATE: Sperry Drilling Confidential Document v 3.0 Difficulties experienced: We had issues with the CVE and flow line packing off when drilling through the heavy clays. The Mass Spectrometer was having issues with moisture build up, which required switching to the backup machine so the main machine good dry out. We also had a few connectivity issues with WITS which caused gaps in data. Recommendations: A back up gas trap was installed in case the CVE had to be taken from the flow line to be cleaned to avoid lost data. The driller also suggested blowing down the flow line at every connection to alleviate the clay build up. The flow path to the Mass Spectrometer was adjusted to flow through a regulator and drop out jar resolving the moisture build up. Innovations and/or cost savings: N/A What went as, or better than, planned: The sample catchers collected the required samples including the increased frequency required during zones of interest. We had no networking issues with town and no HSE incidents. Communications between the rig and the mudloggers was great and pit volumes were tracked accurately. CT-1 Caelus Energy Alaska, Smith Bay LLC AK-XX-0903061217 Doyon Arctic Fox Jacob Robertson Wildcat Exploration North Slope Borough Alaska Surface / Intermediate 13-Feb-2016 Surface Data Logging After Action Review Surface Data Logging WELL NAME:CT-1 LOCATION:Wildcat Exploration OPERATOR:Caelus Energy Alaska, Smith Bay LLC AREA:North Slope Borough MUD CO:Halliburton - Bariod STATE:Alaska RIG:Doyon Arctic Fox SPUD:19-Jan-2016 SPERRY JOB:AK-XX-0903061217 TD:8-Feb-2016 Marker MD TVD TVDSS Torok SB1 2,941.0 2,895.0 2,861.0 Torok SB2 4,221.0 4,127.0 4,093.0 Torok SB3 4,904.0 4,790.0 4,756.0 Top Tulimaniq Fan 5,313.0 5,197.0 5,163.0 Top Tulimaniq Central Channel 5,424.0 5,308.0 5,274.0 Top Tulimaniq Lobe 3 5,783.0 5,667.0 5,633.0 Base Tulimaniq Fan 5,994.0 5,878.0 5,844.0 Top HRZ 6,717.0 6,601.0 6,567.0 LCU 6,917.0 6,800.0 6,766.0 Top J2 6,948.0 6,832.0 6,798.0 TD 7,070.0 6,954.0 6,920.0 Formation Tops Well Name:Depth (MD)#to ft Location:(TVD)#to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: Depth ft C1 C1 C1 C1 . C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 - =C1/C2 = C2 - =C1/C3 = C3 - =C1/C4 = C4 - =C1/C5 = C5 - = Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 - =C1/C2 = C2 - =C1/C3 = C3 - =C1/C4 = C4 - =C1/C5 = C5 - = Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft C1 C1 C1 C1 . C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 - =C1/C2 = C2 - =C1/C3 = C3 =C1/C4 = C4 - =C1/C5 = C5 - = Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 - =C1/C2 = C2 - =C1/C3 = C3 - =C1/C4 = C4 - =C1/C5 = C5 - = Production Analysis x Gas Oil Water Non-Producible Hydrocarbons 75 83 -8 432 560 -128 471 212 257 -45 2649 20000 47595 68790 -21195 66 882 1203 -321 166 4 5730 Gas Units 436 Mud Chlorides (mg/L) = 205 257 -52 -634 72 33 39 805 1203 -398 164 409 560 -151 476 5704 Gas Units 346 Mud Chlorides (mg/L) =20000 44053 68790 -24737 62 83 0 83 3 Hydrocarbon Ratios 560 12 548 273 257 10 247 813 68790 1291 67499 57 1203 18 1185 123 5694 Gas Units 571 Mud Chlorides (mg/L) =20000 2 0 0 0 10 18 -8 0 18 95 -77 78 12 40 -28 273 1291 3471 -2180 28 1 Hydrocarbon Ratios 5631 Gas Units 23 Mud Chlorides (mg/L) =20000 N/A Oil Show Rating Free Oil in Mud N/A Color N/A Color Cut Color N/A Intensity N/A Color N/A Intensity N/A Color N/A Residual Flourescence N/A Amount N/A Distribution N/A Intensity N/A Color Stain Amount N/A Type N/A Amount Cuttings Analysis: Odor None Fluorescence Cut Fluorescence Residual Cut Paul Daggett 8-Feb-16 Interpretation: The production of this zone is deemed to be Gas based upon gas chromatograph data. Samples consisted of clr-wh-trnsl-trnsp, vf-f gr, md-w srt, sb ang-sb rnd, sli calc Sandstone. No show or fluorescence seen in samples from these intervals. Show Report Report # 1 CT-1 / Tulimaniq 5630 5730 Smith Bay 5503 5603 Caelus Energy Alaska Leigh Ann Rasher Top Tulimaniq Lobe 3 Oil Gas NPH NPH NPH Oil Gas NPH Oil Gas NPH NPH NPH Oil Gas NPH Oil Gas NPH NPH NPH Oil Gas NPH 1 10 100 1000 Oil Gas NPH NPH 1 10 100 1000 NPH Oil Gas NPH Well Name:Depth (MD)to ft Location:(TVD)to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 =C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Show Report Report # 2 CT-1 / Tulimaniq 5900 6000 Smith Bay 5816 5916 Caelus Energy Alaska Leigh Ann Rasher Top Tulimaniq Lobe 3 Paul Daggett 8-Feb-16 Interpretation: The production of this zone is deemed to be Gas based upon gas chromatograph data. Samples consisted of lt brn-clr-wh-trnsl-trnsp, vf-f gr, md-w srt, sb ang-sb rnd, sli calc Sandstone. No show or fluorescence seen in samples from these intervals. Cuttings Analysis: Odor None Fluorescence Cut Fluorescence Residual Cut N/A Color N/A Intensity N/A Color N/A Residual Flourescence N/A Amount N/A Distribution N/A Intensity N/A Color Stain Amount N/A Type N/A Amount N/A Oil Show Rating Free Oil in Mud N/A Color N/A Color Cut Color N/A Intensity 33396 1291 32105 59 1 Hydrocarbon Ratios 5901 Gas Units 352 Mud Chlorides (mg/L) =20000 107 10 97 1107 562 18 544 143 236 12 224 331 2 29 0 29 31020 1291 29729 58 527 18 509 132 5921 Gas Units 362 Mud Chlorides (mg/L) =20000 Hydrocarbon Ratios 237 12 225 297 110 10 100 929 20000 26892 3562 23330 67 32 0 32 3 445 97 348 169 189 51 138 382 5943 Gas Units 278 Mud Chlorides (mg/L) = 4 5981 Gas Units 93 Mud Chlorides (mg/L) = 88 27 61 1228 19 0 19 20000 8532 3562 4970 101 146 97 49 382 2 0 2 64 51 13 1243 31 27 4 2485 Oil Gas NPH NPH NPH Oil Gas NPH Oil Gas NPH NPH NPH Oil Gas NPH Oil Gas NPH NPH NPH Oil Gas NPH 1 10 100 1000 Oil Gas NPH NPH 1 10 100 1000 NPH Oil Gas NPH Well Name:Depth (MD)to ft Location:(TVD)to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 =C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Show Report Report # 3 CT-1 / Tulimaniq 6350 6450 Smith Bay 6266 6366 Caelus Energy Alaska Leigh Ann Rasher Base Tulimaniq Fan Paul Daggett 8-Feb-16 Interpretation: The production of this zone is deemed to be Gas based upon gas chromatograph data. Samples consisted of lt brn-gry, uncons Siltstone and gry-dk gry, blky-sb blky, non-swlg, non-calc Claystone. No show or fluorescence seen in samples from these intervals. Cuttings Analysis: Odor None Fluorescence Cut Fluorescence Residual Cut N/A Color N/A Intensity N/A Color N/A Residual Flourescence N/A Amount N/A Distribution N/A Intensity N/A Color Stain Amount N/A Type N/A Amount N/A Oil Show Rating Free Oil in Mud N/A Color N/A Color Cut Color N/A Intensity 16436 3038 13398 37 1 Hydrocarbon Ratios 6366 Gas Units 136 Mud Chlorides (mg/L) =20000 135 36 99 447 440 76 364 56 303 64 239 135 2 30 0 30 24064 3038 21026 42 582 76 506 59 6388 Gas Units 200 Mud Chlorides (mg/L) =20000 Hydrocarbon Ratios 420 64 356 138 188 36 152 412 20000 47045 4427 42618 41 51 0 51 3 1259 224 1035 49 1093 222 871 109 6416 Gas Units 414 Mud Chlorides (mg/L) = 4 6438 Gas Units 446 Mud Chlorides (mg/L) = 528 138 390 349 144 22 122 20000 48859 4427 44432 40 1345 224 1121 47 164 53 111 1177 222 955 101 576 138 438 400 Oil Gas NPH NPH NPH Oil Gas NPH Oil Gas NPH NPH NPH Oil Gas NPH Oil Gas NPH NPH NPH Oil Gas NPH 1 10 100 1000 Oil Gas NPH NPH 1 10 100 1000 NPH Oil Gas NPH Well Name:Depth (MD)to ft Location:(TVD)to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 =C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis x Gas Oil Water Non-Producible Hydrocarbons 312 0 312 1530 16 1514 35 912 14 898 101 20500 33192 1764 31428 24 1343 22 1321 21 4 6613 Gas Units 371 Mud Chlorides (mg/L) = 204 14 190 134 70 0 70 388 22 366 26 372 16 356 49 6593 Gas Units 105 Mud Chlorides (mg/L) =20500 11127 1764 9363 26 43 41 2 3 Hydrocarbon Ratios 249 137 112 66 143 97 46 1514 5435 2408 3027 21 262 116 146 27 6575 Gas Units 55 Mud Chlorides (mg/L) =20500 2 109 41 68 314 97 217 159 633 116 517 25 576 137 439 50 13196 2408 10788 21 1 Hydrocarbon Ratios 6551 Gas Units 146 Mud Chlorides (mg/L) =20500 N/A Oil Show Rating Free Oil in Mud N/A Color N/A Color Cut Color N/A Intensity N/A Color N/A Intensity N/A Color N/A Residual Flourescence N/A Amount N/A Distribution N/A Intensity N/A Color Stain Amount N/A Type N/A Amount Cuttings Analysis: Odor None Fluorescence Cut Fluorescence Residual Cut Paul Daggett 8-Feb-16 Interpretation: The production of this zone is deemed to be Gas based upon gas chromatograph data. Samples consisted of gry-dk gry, blky, non-swlg, non-calc Claystone, gry-brn, frm-hd, fis Shale and clr-trnsl-brn, uncons Siltstone. No show or fluorescence seen in samples from these intervals. Show Report Report # 4 CT-1 / Tulimaniq 6550 6620 Smith Bay 6466 6536 Caelus Energy Alaska Leigh Ann Rasher Base Tulimaniq Fan Oil Gas NPH NPH NPH Oil Gas NPH Oil Gas NPH NPH NPH Oil Gas NPH Oil Gas NPH NPH NPH Oil Gas NPH 1 10 100 1000 Oil Gas NPH NPH 1 10 100 1000 NPH Oil Gas NPH Well Name:Depth (MD)#to ft Location:(TVD)#to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: None Depth ft C1 C1 C1 C1 . C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 - =C1/C2 = C2 - =C1/C3 = C3 - =C1/C4 = C4 - =C1/C5 = C5 - = Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 - =C1/C2 = C2 - =C1/C3 = C3 - =C1/C4 = C4 - =C1/C5 = C5 - = Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft C1 C1 C1 C1 . C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 - =C1/C2 = C2 - =C1/C3 = C3 =C1/C4 = C4 - =C1/C5 = C5 - = Production Analysis x Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 - =C1/C2 = C2 - =C1/C3 = C3 - =C1/C4 = C4 - =C1/C5 = C5 - = Production Analysis x Gas Oil Water Non-Producible Hydrocarbons 76 35 41 418 165 253 40 231 98 133 131 8385 3009 5376 20 432 160 272 21 4 6755 Gas Units 137 Mud Chlorides (mg/L) = 245 98 147 259 65 16 49 714 160 554 31 576 165 411 86 6740 Gas Units 152 Mud Chlorides (mg/L) = 15687 3009 12678 23 92 0 92 3 Hydrocarbon Ratios 765 73 692 54 341 37 304 177 18838 2538 16300 21 876 93 783 24 6730 Gas Units 220 Mud Chlorides (mg/L) = 2 210 0 210 657 37 620 86 934 93 841 17 1128 73 1055 29 20553 2538 18015 21 1 Hydrocarbon Ratios 6690 Gas Units 240 Mud Chlorides (mg/L) = N/A Oil Show Rating Poor Free Oil in Mud N/A Color No Vis Cut Color Cut Color Dull Yellow Intensity N/A Color N/A Intensity Weak Color Mod Milky Wh Residual Flourescence None Amount None Distribution Spoty Intensity Very Slow Color Stain Amount Type Crush Cut Amount Cuttings Analysis: Odor None Fluorescence Cut Fluorescence Residual Cut Paul Daggett 8-Feb-16 Interpretation: The production of this zone is deemed to be Gas based upon gas chromatograph data. Samples consisted of clr-wh-trnsl-trnsp, vf-f gr, md-w srt qrtz, siliceous cmtn w/ clay matrix, 15% drk blk lith grns, sb ang-sb rnd Sandstone Show Report Report # 5 CT-1 / Tulimaniq 6680 6760 Smith Bay 6606 6755 Caelus Energy Alaska Leigh Ann Rasher HRZ Oil Gas NPH NPH NPH Oil Gas NPH Oil Gas NPH NPH NPH Oil Gas NPH Oil Gas NPH NPH NPH Oil Gas NPH 1 10 100 1000 Oil Gas NPH NPH 1 10 100 1000 NPH Oil Gas NPH CT-1 Caelus Energy Alaska, Smith Bay LLC Halliburton - Baroid Doyon Arctic Fox AK-XX-0903061217 Date Depth Wt Vis PV YP Gels Filt R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Sd Pm pH MBT Pf/Mf Chlor Hard ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%%ppb Eqv mg/l Ca++ 19-Jan 160 9.55 62 13 33 19/24/25 -59/46/40/33/20/18 -----9.6 ----Spud Well / Drilling Ahead 20-Jan 1266 9.75 62 11 29 15/20/23 10.0 51/40/35/28/15/13 1/0 6.3 0.0/93.2 0.75 0.75 9.5 1.0 0.50/1.80 4000 560 Drilling Ahead 21-Jan 2390 9.70 50 12 30 14/17/20 10.0 54/42/36/28/14/12 1/0 7.2 0.0/92.5 1.50 1.50 9.8 3.0 0.80/1.20 2500 280 Drilling Ahead 22-Jan 2564 9.80 65 10 32 14/17/20 10.0 52/42/32/23/12/10 1/0 8.2 0.0/91.5 0.50 1.50 10.0 5.5 0.90/1.80 3200 720 TD Surface / Short Trip / MADPass 23-Jan 2564 9.80 63 15 22 14/17/20 10.2 52/37/32/23/12/10 1/0 7.7 0.0/92.0 0.50 1.50 10.0 5.0 0.80/1.80 2700 560 MAD Pass / L/D BHA / R/U Casing 24-Jan 2564 9.80 64 13 28 12/17/18 9.9 54/41/34/22/12/10 1/0 7.7 0.0/92.0 0.50 1.40 10.0 5.0 0.80/1.90 2800 520 Run Casing / R/U to cement 25-Jan 2564 9.80 66 14 27 13/17/18 10.0 55/41/34/23/12/10 1/0 7.7 0.0/92.0 0.25 1.50 10.0 5.0 0.80/1.80 2600 520 Pumped cement job/ N/D diverter 26-Jan 2564 9.80 60 12 24 12/14/15 10.0 48/36/30/23/12/10 1/0 7.7 0.0/92.0 0.25 1.50 10.0 5.0 0.80/1.80 2400 520 RU BOP, Cleaned pits & mix new mud 27-Jan 2564 9.80 63 12 23 11/13/15 10.4 47/35/28/22/11/9 1/0 7.7 0.0/92.0 0.20 1.80 10.0 5.0 0.90/2.00 2400 520 R/U BHA and TIH to drill out shoe 28-Jan 2584 9.50 63 15 20 8/12/13 5.9 50/35/29/22/8/7 1/1 5.2 0.0/93.5 -0.60 10.0 -0.50/1.60 1500 200 Making up BHA Date Depth Wt Vis PV YP Gels Filt R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Sd Pm pH MBT Pf/Mf Chlor Hard ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%%ppb Eqv mg/l Ca++ 29-Jan 2993 9.55 50 13 22 8/11/13 6.0 48/35/29/21/8/7 1/1 5.3 0.0/93.0 0.25 0.55 9.7 1.0 0.35/1.20 20500 200 Drilling Intermediate Section 30-Jan 4185 9.70 50 13 20 8/12/15 5.5 46/33/28/20/8/6 1/1 6.2 0.0/92.1 0.10 0.20 9.5 5.0 0.20/1.20 21000 80 Drilling Intermediate Section 31-Jan 5152 9.65 50 11 18 6/9/11 11.8 40/29/24/17/6/5 1/2 6.1 0.5/91.8 0.05 0.30 9.7 6.8 0.38/0.80 20000 80 Drilling Intermediate Section 1-Feb 5934 9.70 46 12 18 6/13/16 5.8 42/30/25/19/6/5 1/2 6.4 0.3/91.8 0.05 0.25 9.6 7.3 0.25/1.20 20000 120 Drilling Intermediate Section 2-Feb 6519 9.65 43 10 20 6/9/13 5.8 40/30/24/18/6/5 1/2 6.5 0.1/91.8 0.05 0.35 9.6 7.2 0.2/1.20 20500 120 Drilling Intermediate Section 3-Feb 6645 9.85 49 12 18 6/10/15 5.6 42/30/24/18/6/5 1/2 7.4 0.1/90.9 0.05 0.42 10.2 7.5 0.25/0.95 21000 80 POOH 4-Feb 6645 9.75 47 10 18 6/10/13 5.8 38/28/23/17/6/5 1/2 7.0 0.1/91.3 0.05 0.40 10.1 7.5 0.25/0.95 20000 80 RIH Wireline 5-Feb 6645 9.80 47 10 17 6/10/13 5.8 37/27/22/16/6/5 1/2 7.0 0.1/91.3 0.05 0.40 10.1 7.5 0.25/0.95 20500 80 Wireline Logging 6-Feb 6645 9.75 56 9 16 5/8/11 5.6 34/25/21/16/5/4 1/2 6.8 0.1/91.6 0.05 0.50 10.0 7.5 0.30/0.95 19000 80 Wireline Logging 7-Feb 6645 9.75 56 10 17 6/9/12 5.6 37/27/21/16/6/5 1/2 6.7 0.1/91.5 0.05 0.50 10.2 7.5 0.30/0.95 21000 80 Slip and cut drill line 8-Feb 7070 10.10 42 12 18 6/9/13 5.6 42/30/26/19/7/6 1/2 7.9 0.1/90.4 0.05 0.55 10.3 7.5 0.35/1.00 20500 80 POOH 9-Feb 7070 10.10 47 12 18 6/9/13 5.8 42/30/26/19/6/5 1/2 7.9 0.1/90.4 0.05 0.40 9.8 7.5 0.30/1.05 20500 80 Wireline Logging 10-Feb 7070 10.10 42 11 19 6/9/13 6.0 41/30/26/19/6/5 1/2 7.9 0.1/90.4 0.05 0.40 10.0 7.5 0.35/1.05 20000 80 Pump Cement Plug 11-Feb 7070 10.20 47 12 20 6/9/12 8.2 44/32/27/20/7/6 1/2 8.4 0.1/90.1 0.05 0.50 10.4 7.5 0.35/1.05 18000 1600 R/U to RIH 12-Feb 7070 10.20 50 11 23 6/10/14 9.0 45/34/27/20/7/6 1/2 8.4 0.1/90.1 0.05 0.50 10.5 7.5 0.35/1.05 18000 1600 Injecting Waste 13-Feb 7070 10.20 54 12 22 6/10/14 9.0 46/34/27/20/7/6 1/2 8.4 0.1/90.1 0.05 0.45 10.3 7.5 0.30/1.00 18000 1600 Phase 3 Stand Down 14-Feb 7070 10.10 49 12 22 6/9/14 9.0 46/34/28/21/7/6 1/2 8.1 0.1/90.4 0.05 0.55 10.6 7.5 0.40/1.15 18000 1600 Circulating 15-Feb 7070 9.80 52 ----------10.3 ----Monitor well Casing Record WELL NAME:LOCATION:Wildcat Exploration OPERATOR:AREA:North Slope Borough MUD CO:STATE:Alaska RIG:SPUD:19-Jan-2016 SPERRY JOB:TD:8-Feb-2016 Remarks 16" Conductor @ 110' MD, 110'TVD 10.75" Casing @ 2547' MD, 2505'TVD Surface Section - Spud Mud / Polymer - BDF 499 Intermediate Section - EZ Mud / 3% KCl - BDF499 Remarks Water and Oil Based Mud Record BHA#SDL RUN #Bit #Bit Type Bit Size Depth In Depth Out Footage Bit Hours TFA AVG ROP WOB (max) RPM (max) SPP (max) FLOW GPM (max)Bit Grade Comments 1 100 1 Baker Hughes VM-1 13.50 110 2564 2484 33.47 0.856 72.0 20 70 1700 610 2-1-WT-M-E-I-NO-TD Surface Section TD 2 200 2 Baker Hughes GX CIX 9.882 2564 2584 20 7.17 1.0707 50.0 15 100 485 550 1-1-NO-A-E-I-NO-BHA Surface/Intermediate - Clean out Run 3 300 3 NOV SK616M J2D 8.50 2584 6645 4061 109.91 0.759 58.0 18 140 2320 550 0-1-WT-G-X-I-NO-TD Intermediate Section 4 400 4 NOV SK616M J2D 8.50 6645 7070 425 15.41 0.759 58.0 14 120 2100 550 1-3-BT-G-X-I-CT-TD Intermediate Section TD Alaska RIG:Doyon Arctic Fox SPUD:19-Jan-2016 WELL NAME:CT-1 LOCATION:Wildcat Exploration OPERATOR:Caelus Energy Alaska, Smith Bay LLC AREA:North Slope Borough MUD CO: SPERRY JOB:AK-XX-0903061217 TD:8-Feb-2016 Halliburton - Baroid STATE:Bit Record . . * 24 hr Recap: pH (907)375-7571Unit Phone: Bit TypeBit # SDL crew set up Mass Spectrometer, Total Gas Analyzer, Gas Chromatograph, Isotube, IsoJars, and sample Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l - 0 19-Jan-2016 11:59 PM Current Pump & Flow Data: 54 Max ROP ROP (ft/hr) 4.23 @ Mud Data Depth Morning Report Report # 1 Customer: Well: Area: Location: Rig: CT-1 / Tulimaniq Caelus Energy Alaska North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Arctic Fox Report For: Condition - Grade Out -1 - 13.250 - Baker / VM-1 - Size Fluid Gain / Loss (24 hours): 0 bbls 100% Gas In Air=10,000 Units0Connection - 18 Tools Directional / EWR / XBAT API FL Chromatograph (ppm) -0' - WOB -- Avg Min Comments RPM ECD (ppg) ml/30min 1Background (max)Trip Average N/A Mud Type Lst 60 - Type - ---- Depth in / out YP (lb/100ft2) - 000 00 CementCht Silt C-4i C-4n - 24 hr Max Weight 0 Hours C-3 -40 Ss (ppb Eq) C-1 C-5i AK-AM-0903061217 - - Drilling Ahead - Surface PV - Footage - M. Thornton / W. Frane ShClyst - - TuffGvlCoal cP - - - Gas Summary 0 13 18 (current) Avg to0' Yesterday's Depth: Current Depth: 24 Hour Progress: 161.8 Flow In (gpm) Flow In (spm) 110' 253' 143' Max @ ft Current 187'83.4 Date: Time: bottles. Spud the well and drilled to 253' MD. 4 in 1 251'Minimum Depth C-5n 253' 57.4 C-2 5 SPP (psi) Gallons/stroke TFA Depth -- MBT 253' 0.8560 0 14 0 Siltst 787 184 Units* Casing Summary Lithology (%) 0 - 17 0 15 Jeremy Tiegs Maximum Report By:Logging Engineers:Ashley Wilderom / Jeremy Tiegs Set AtSize Grade (max)(current) 12 0 Cly 58 - . . * 24 hr Recap: Cly 3708 - 16.00'' (max)(current) 2 0 0 Jeremy Tiegs Maximum Report By:Logging Engineers:Ashley Wilderom / Jeremy Tiegs 0 - 1431 184 0 Set At 84.0 in cP 0 0 Siltst Units* Casing Summary Lithology (%) Size Depth -- MBT 1295' 0.8560 343'Minimum 57.4 C-2 32 Fluid Gain / Loss (24 hours): 0 bbls sub. Made up BHA #1 as per Sperry directional service; ran in the hole to 300’ MD and conducted a shallow pulse test. Tagged the 8 Alternating samples of sandstone that vary in levels of clay content. One type of sandstone is fine grained well sorted and is opaque and dark brown to tan in color. It contains much less quartz and higher amounts of feldspars and lithics. These much dominantly unconsolidated clear to white grains. The other commonly seen sandstone is moderately consolidated and is much more 0 Flow In (spm) Time: 0 253' 1295' 1042' Yesterday's Depth: Current Depth: 24 Hour Progress: 647'130.2 Date: 280.7 Flow In (gpm) Max @ ft SPP (psi) 0 (current) Depth 646' - C-5n M. Thornton / W. Frane ShClyst -- Tuff Footage - TFA (ppb Eq) C-1 C-5i AK-AM-0903061217 Drilling Ahead - Surface PV - - C-3 -40 Gas Summary Ss GvlCoal 0 --- Weight L-80 Grade 0 000 C-4i C-4n 0 Depth in / out YP (lb/100ft2) - Lst 60 - Cement 00 -- Cht Silt Chromatograph (ppm) -80' Average N/A8Background (max)Trip - WOB Conductor Comments RPM Type Hours 100% Gas In Air=10,000 Units0Connection - 0 blueish residual fluorescence. carbonaceous material can be seen throughout most samples and in a rare case the sample at 750' MD had a small amount observed they are hygroturgid and in very rare cases are they cryptoturgid. And break in a amorphous or plastic manner. Organics and coarser grained cuttings have are blocky and more anglular grains. When laqrge amounts of clay have been Cuttings Lithology: bottom at 310’ MD and then continued drilling the surface section to 1295’ MD. 110' -1 - 13.250 - Baker / VM-1 -- 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke 787 253' Depth Morning Report Report # 2 Customer: Well: Area: Location: Directional / EWR / XBAT - Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 20-Jan-2016 11:59 PM Current Pump & Flow Data: 1337 Max 0 - Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907)375-7571Unit Phone: Bit TypeBit # Continued to drill ahead from 253’ MD to 315’ MD and then pulled out of the hole to surface to break down bit and Size - . . * 24 hr Recap: (907)375-7571Unit Phone: Bit TypeBit # Drilled ahead from 1295' MD to 2443' MD back reaming a full stand before every connection. Size - Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 2500.00 Condition - Grade Out 0 21-Jan-2016 11:59 PM Current Pump & Flow Data: 1588 Max 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 1295' Depth Morning Report Report # 3 Customer: Well: Area: Location: Directional / EWR / XBAT -- North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke 614 10.0 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type Cuttings Lithology: 110' -1 7.2 13.250 9.80 Baker / VM-1 9.70 became +90% of the sample. Carbonaceous material was present until 1500' MD after which no particles were fluorescing. Lithologies seen today were dominated by clay content. Varying amounts of sandstone were present until ~1900' MD and then the clay 100% Gas In Air=10,000 Units0Connection - 0 WOB Conductor Comments RPM Type Hours 17Background (max)Trip Average N/A Polymer2390' Cht Silt Chromatograph (ppm) -80' - Cement 00 Depth in / out YP (lb/100ft2) 9.80 Lst -- 0 000 C-4i C-4n 0 --- Weight L-80 Grade C-3 -100 Gas Summary Ss GvlCoal 0 (ppb Eq) C-1 C-5i AK-AM-0903061217 Drilling Ahead - Surface PV - 12 Footage - TFA 30 C-5n M. Thornton / W. Frane ShClyst -- Tuff 0 (current) Depth 2324' 1370'84.2 Date: 288.2 Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 0 1295' 2443' 1148' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls 12 Clays were swelling mostly in an irregular manner but from 1700'-1900' MD cryptofissile swelling was seen. Reaction to HCl clay. was seen in few samples randomly throughout the drilling today. Silt content also varied throughout the samples that were +90% 3 1669'Minimum 64.8 C-2 40 Depth 3.050 MBT 2443' 0.8560 220 0 Set At 84.0 in cP 0 00 2557 0 Jeremy Tiegs Maximum Report By:Logging Engineers:Ashley Wilderom / Jeremy Tiegs (max)(current) 0 0 - Siltst Cly 6445 - 16.00'' Units* Casing Summary Lithology (%) Size . . * 24 hr Recap: (907)375-7571Unit Phone: Bit TypeBit # Drilled from 2,436' MD TD at 2,564' MD and pumped a high vis sweep (bottoms up calculated strokes was 6545) Size - Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 3200.00 Condition - Grade Out 0 22-Jan-2016 11:59 PM Current Pump & Flow Data: - Max 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2443' Depth Morning Report Report # 4 Customer: Well: Area: Location: Directional / EWR / XBAT -- North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 10.0 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type Back reamed and circulated out of hole to surface and rigged up to run in the hole. The CVE was turned off due to clay balls packing 110' -1 8.2 13.250 9.80 Baker / VM-1 9.80 off the flow line. 100% Gas In Air=10,000 Units-Connection - 0 WOB Conductor Comments RPM Type Hours -Background (max)Trip Average - Polymer2390' Cht Silt Chromatograph (ppm) -80' - Cement 00 Depth in / out YP (lb/100ft2) 10.00 Lst -- 0 000 C-4i C-4n 0 --- Weight L-80 Grade C-3 -100 Gas Summary Ss GvlCoal 0 (ppb Eq) C-1 C-5i AK-AM-0903061217 Tripping in Hole PV - 10 Footage - TFA 32 C-5n M. Thornton / W. Frane ShClyst -- Tuff 0 (current) Depth 2523' 2559'54.7 Date: 91.7 Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 0 2443' 2564' 121' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls that had no significant increase in cuttings. Continued pumping until 1.5 bottoms up and then pulled out of the hole to 2,118' MD. 18 From 2440" to TD the cuttings were all clay. The last 60' had cryptofissile swelling and at the very end rare pieces of chert were seen. Lithology Cuttings: 7 2492'Minimum - C-2 24 Depth 5.565 MBT 2564' 0.8560 - 0 Set At 84.0 in cP 0 00 2865 0 Jeremy Tiegs Maximum Report By:Logging Engineers:Ashley Wilderom / Jeremy Tiegs (max)(current) 0 0 - Siltst Cly 3245 - 16.00'' Units* Casing Summary Lithology (%) Size . . * 24 hr Recap: Cly 35 - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) 0 0 - Siltst 0 Jeremy Tiegs Maximum Report By:Logging Engineers:Ashley Wilderom / Jeremy Tiegs 0 14 - 0 Set At 84.0 in cP 0 0 Depth 5.063 MBT - 0.8560 -Minimum - C-2 6 Fluid Gain / Loss (24 hours): 0 bbls dry job and then pulled out of the hole from 2,564' MD to surface. Racked back 5" HWDP and laid down BHA #1. Rigged up to run 2 0 Flow In (spm) Time: 0 2564' 2564' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: -- Date: - Flow In (gpm) Max @ ft SPP (psi) 0 (current) Depth - 22 C-5n J. Keener / W. Frane ShClyst -- Tuff Footage - TFA (ppb Eq) C-1 C-5i AK-AM-0903061217 Running 10.75" Casing PV - 15 C-3 -- Gas Summary Ss GvlCoal 0 --- Weight L-80 Grade 0 000 C-4i C-4n 0 Depth in / out YP (lb/100ft2) 10.00 Lst -- Cement 00 Polymer2564' Cht Silt Chromatograph (ppm) -80' 2564' Average --Background (max)Trip WOB Conductor Comments RPM Type Hours 100% Gas In Air=10,000 Units-Connection - 0 10.75" casing. 110' -1 7.7 13.250 9.80 Baker / VM-1 9.80 10.2 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - - Depth Morning Report Report # 5 Customer: Well: Area: Location: -- Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 23-Jan-2016 11:59 PM Current Pump & Flow Data: - Max 0 2700.00 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907)375-7571Unit Phone: Bit TypeBit # Ran into the hole from surface to 2,564' MD and then circulated 1.5 bottoms up to clean the hole. Pumped a 20 barrel Size - . . * 24 hr Recap: (907)375-7571Unit Phone: Bit TypeBit # Troubleshot Volant casing tools and then made up shoe joint and float collar. Ran in the hole with 10-3/4" surface Size - Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 2800.00 Condition - Grade Out 0 24-Jan-2016 11:59 PM Current Pump & Flow Data: - Max 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current - Depth Morning Report Report # 6 Customer: Well: Area: Location: --- North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 9.9 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type 110' -1 7.7 13.250 9.80 Baker / VM-1 9.80 100% Gas In Air=10,000 Units-Connection - 0 WOB Conductor Comments RPM Type Hours -Background (max)Trip Average - Polymer2564' Cht Silt Chromatograph (ppm) -80' 2564' Cement 00 Depth in / out YP (lb/100ft2) 10.00 Lst -- 0 000 C-4i C-4n 0 --- Weight L-80 Grade C-3 -- Gas Summary Ss GvlCoal 0 (ppb Eq) C-1 C-5i AK-AM-0903061217 Rigging up Cement Equipment PV - 13 Footage - TFA 28 C-5n J. Keener / W. Frane ShClyst -- Tuff 0 (current) Depth - -- Date: - Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 0 2564' 2564' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls casing from surface to 2,547' MD and then circulated 2 bottoms up. Rigged up to run 5" DP and preparing to conduct a cement job. 2 0 -Minimum - C-2 4 Depth 5.064 MBT - 0.8560 - 0 Set At 84.0 in cP 0 00 14 0 Jeremy Tiegs Maximum Report By:Logging Engineers:Ashley Wilderom / Jeremy Tiegs (max)(current) 0 0 - Siltst Cly 34 - 16.00'' Units* Casing Summary Lithology (%) Size . . * 24 hr Recap: (907)375-7571Unit Phone: Bit TypeBit # Pumped a 230 bbls lead cement job and a 48.4 bbls tail cement job with 42 bbls fresh water and bumped plug. Size 70.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 2600.00 Condition - Grade Out 0 25-Jan-2016 11:59 PM Current Pump & Flow Data: - Max 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current - Depth Morning Report Report # 7 Customer: Well: Area: Location: --- North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 10.0 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type 2547' 110' 2-1-WT-M-E-I-NO-TD1 7.7 13.250 9.80 Baker / VM-1 9.80 100% Gas In Air=10,000 Units-Connection - 0 WOB Conductor Comments RPM Type Hours -Background (max) Trip Average - Polymer2564' Cht Silt Chromatograph (ppm) 20.080' 2564' Cement 00 Depth in / out YP (lb/100ft2) 10.00 Lst - - 0 000 C-4i C-4n 0 - - - 45.5 Weight L-80 Grade C-3 -- Gas Summary Ss GvlCoal 5 (ppb Eq) C-1 C-5i AK-AM-0903061217 N/D diverter PV 2564' 14 Footage 33.47 TFA 27 C-5n J. Keener / W. Frane ShClyst - - Tuff 0 (current) Depth - -- Date: - Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 0 2564' 2564' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls POOH and laid down landing joint.. Currently nipple down catch can and diverter system. 2 0 -Minimum - C-2 4 Depth 5.066 L-80 MBT - 0.8560 10.75'' - 0 Set At 84.0 in cP 0 00 13 0 Jacob Robertson Maximum Report By:Logging Engineers:Ashley Wilderom / Jacob Robertson (max)(current) Surface 0 0 - Siltst Cly 43 - 16.00'' Units* Casing Summary Lithology (%) Size . . * 24 hr Recap: Cly 25 - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface 0 0 - Siltst 0 Jacob Robertson Maximum Report By:Logging Engineers:Ashley Wilderom / Jacob Robertson 0 11 - 0 Set At 84.0 in cP 0 0 Depth 5.060 L-80 MBT - 0.8560 10.75'' -Minimum - C-2 4 Fluid Gain / Loss (24 hours): 0 bbls prepared to batch up mud. 2 0 Flow In (spm) Time: 0 2564' 2564' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: -- Date: - Flow In (gpm) Max @ ft SPP (psi) 0 (current) Depth - 24 C-5n J. Keener / W. Frane ShClyst - - Tuff Footage 33.47 TFA (ppb Eq) C-1 C-5i AK-AM-0903061217 R/U BOP PV 2564' 12 C-3 -- Gas Summary Ss GvlCoal 0 - - - 45.5 Weight L-80 Grade 0 000 C-4i C-4n 0 Depth in / out YP (lb/100ft2) 10.00 Lst - - Cement 00 Polymer2564' Cht Silt Chromatograph (ppm) 20.080' 2564' Average --Background (max) Trip WOB Conductor Comments RPM Type Hours 100% Gas In Air=10,000 Units-Connection - 0 2547' 110' 2-1-WT-M-E-I-NO-TD1 7.7 13.250 9.80 Baker / VM-1 9.80 10.0 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - - Depth Morning Report Report # 8 Customer: Well: Area: Location: -- Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 26-Jan-2016 11:59 PM Current Pump & Flow Data: - Max 0 2400.00 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907)375-7571Unit Phone: Bit TypeBit # Nipple up BOPE. Cleaned mud pits 1,2,3,6 and rock washer pit. Rigged up BOPE. Filled Pit 6 with water and Size 70.0 . . * 24 hr Recap: (907)375-7571Unit Phone: Bit TypeBit # R/U BOPE test equipment. Picked up 74 joints of 5" DP and racked back in derrick. Rig tested BOPE. P/U BHA to drill Size 70.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 2400.00 Condition - Grade Out 0 27-Jan-2016 11:59 PM Current Pump & Flow Data: - Max - 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current - Depth Morning Report Report # 9 Customer: Well: Area: Location: --- North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 10.4 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type 2547' 110' 2-1-WT-M-E-I-NO-TD1 7.7 13.250 9.80 Baker / VM-1 9.80 100% Gas In Air=10,000 Units-Connection - 0 WOB Conductor Comments RPM 2564' Type - Hours -Background (max) Trip Average - Polymer2564' Cht Silt Chromatograph (ppm) - 20.080' Baker/ GX CIX 2564' Cement 00 2 Depth in / out YP (lb/100ft2) 10.00 Lst - - 0 000 C-4i C-4n 0 - - - 45.5 Weight L-80 Grade C-3 -- Gas Summary Ss GvlCoal 0 (ppb Eq) C-1 C-5i AK-AM-0903061217 TIH PV 2564' 12 9.882 1.071 Footage - - 33.47 TFA 23 - C-5n J. Keener / M. Ross ShClyst - - Tuff 0 (current) Depth - -- Date: - Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 0 2564' 2564' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls out shoe track. Ran bag test with 10% Methane gas at shaker and received 968 units back. Gas gear calibrated. Prepared to TIH. 0 0 -Minimum - C-2 0 Depth 5.063 L-80 MBT - 0.8560 10.75'' - 0 Set At 84.0 in cP 0 00 0 0 Jacob Robertson Maximum Report By:Logging Engineers:Ashley Wilderom / Jacob Robertson (max)(current) Surface 0 0 - Siltst Cly 0 - 16.00'' Units* Casing Summary Lithology (%) Size . . * 24 hr Recap: 100 1-1-NO-A-E-I-NO-BHA2Baker/ GX CIX 9.882 1.071 7.17 2564' 2584' Cly 1227 - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface 0 0 - Siltst 0 Jacob Robertson Maximum Report By:Logging Engineers:Ashley Wilderom / Jacob Robertson 0 12 - 0 Set At 84.0 in cP 0 0 Depth -63 L-80 MBT - 0.8560 10.75'' -Minimum N/A C-2 8 Fluid Gain / Loss (24 hours): 0 bbls Currently making up BHA #3. 1 0 Flow In (spm) Time: 0 2564' 2584' 20' Yesterday's Depth: Current Depth: 24 Hour Progress: 2572'- Date: 68.0 Flow In (gpm) Max @ ft SPP (psi) 0 (current) Depth 2568' 20 - C-5n J. Keener / M. Ross ShClyst - - Tuff 8.5 0.759 Footage - - 33.47 TFA 20' (ppb Eq) C-1 C-5i AK-AM-0903061217 M/U BHA #3 PV 2564' 15 C-3 -- Gas Summary Ss GvlCoal 0 - - 90 45.5 Weight L-80 Grade 0 000 C-4i C-4n 0 3 Depth in / out YP (lb/100ft2) 10.00 Lst - - Cement 00 3% KCL2584' Cht Silt Chromatograph (ppm) - 20.080' NOV/ SK616M J2D 2564' Average 3-Background (max) Trip WOB Conductor Comments RPM 2584' Type - Hours 15 100% Gas In Air=10,000 Units-Connection 10 0 2547' 110' 2-1-WT-M-E-I-NO-TD1 5.2 13.250 9.50 Baker / VM-1 9.50 5.9 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - - Depth Morning Report Report # 10 Customer: Well: Area: Location: -- Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 28-Jan-2016 11:59 PM Current Pump & Flow Data: - Max - 0 15000.00 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907)375-7571Unit Phone: Bit TypeBit # TIH and drilled out shoe track to 2585' MD. Rig performed LOT test and pumped a dry job. POOH and L/D BHA #2. Size 70.0 . . * 24 hr Recap: (907)375-7571Unit Phone: Bit TypeBit # M/U BHA #3 and TIH. Began drilling ahead in the intermediate section at 13:20. Optimize CVE at 2890' to 3050' MD. Size 70.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 20500.00 Condition - Grade Out 0 29-Jan-2016 11:59 PM Current Pump & Flow Data: 1750 Max - 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2585' Depth Morning Report Report # 11 Customer: Well: Area: Location: DGR, EWR-P4, ELD, XBAT, Geo-Pilot, PWD, ALD, CTN 7.229.91 North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke 522 6.0 95% Rig Activity: 10.67 Arctic Fox Report For: Tools ml/30minMud Type 2547' 110' 2-1-WT-M-E-I-NO-TD1 5.3 13.250 9.55 Baker / VM-1 9.55 100% Gas In Air=10,000 Units-Connection 100 0 WOB Conductor Comments RPM 2584' Type - Hours 15 5Background (max) Trip Average 1 3% KCL2993' Cht Silt Chromatograph (ppm) - 20.080' NOV/ SK616M J2D 2564' Cement 00 3 Depth in / out YP (lb/100ft2) 9.70 Lst - - 0 000 C-4i C-4n 0 - - - 45.5 Weight L-80 Grade C-3 -- Gas Summary Ss GvlCoal 0 (ppb Eq) C-1 C-5i AK-AM-0903061217 Drilling Ahead PV 2564' 13 8.5 0.759 Footage - - 33.47 TFA 20' 22 - C-5n J. Keener / M. Ross ShClyst - - Tuff 0 (current) Depth 2752' 2987'71.4 Date: 145.0 Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 0 2585' 3047' 462' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls CVE is operating at 100% efficiency. We are currently drilling ahead in the formation at 3046' MD with formation gas of 8 units. 4 0 -Minimum 101.0 C-2 16 Depth 0.350 L-80 MBT 3047' 0.8560 10.75'' 187 0 Set At 84.0 in cP 0 00 41 0 Jacob Robertson Maximum Report By:Logging Engineers:Ashley Wilderom / Jacob Robertson (max)(current) Surface 0 0 - Siltst Cly 1377 - 16.00'' Units* Casing Summary Lithology (%) Size 100 1-1-NO-A-E-I-NO-BHA2Baker/ GX CIX 9.882 1.071 7.17 2564' 2584' . . * 24 hr Recap: 100 1-1-NO-A-E-I-NO-BHA2Baker/ GX CIX 9.882 1.071 7.17 2564' 2584' Cly 3792 - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface 0 0 - Siltst 0 Jacob Robertson Maximum Report By:Logging Engineers:Ashley Wilderom / Jacob Robertson 0 1529 194 0 Set At 84.0 in cP 0 0 Depth 5.050 L-80 MBT 4233' 0.8560 10.75'' -Minimum 34.0 C-2 40 Fluid Gain / Loss (24 hours): 0 bbls and was brought back online at 08:27/3,485' MD. Isotube samples were collected during the machine's downtime at 08:04/ 15 0 Flow In (spm) Time: 0 3047' 4233' 1186' Yesterday's Depth: Current Depth: 24 Hour Progress: 3617'78.0 Date: 152.0 Flow In (gpm) Max @ ft SPP (psi) 0 (current) Depth 3418' 20 - C-5n J. Keener / M. Ross ShClyst - - Tuff 8.5 0.759 Footage - - 33.47 TFA 20' (ppb Eq) C-1 C-5i AK-AM-0903061217 Drilling Ahead PV 2564' 13 C-3 -- Gas Summary Ss GvlCoal 0 - - - 45.5 Weight L-80 Grade 0 000 C-4i C-4n 0 3 Depth in / out YP (lb/100ft2) 9.50 Lst - - Cement 00 3% KCL4185' Cht Silt Chromatograph (ppm) - 20.080' NOV/ SK616M J2D 2564' Average -2Background (max) Trip WOB Conductor Comments RPM 2584' Type - Hours 15 100% Gas In Air=10,000 Units-Connection 100 0 20:30. Noted trace appearance of C-2 at 4,037’ MD. Notified geologist and collected isotube. 3464' MD and 08:22 / 3476’ MD. Attempted to switched to the legacy trap while assessing CVE from 18:30 to 19:00 and 20:00 to 2547' 110' 2-1-WT-M-E-I-NO-TD1 6.2 13.250 9.70 Baker / VM-1 9.70 5.5 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke 522 2585' Depth Morning Report Report # 12 Customer: Well: Area: Location: DGR, EWR-P4, ELD, XBAT, Geo-Pilot, PWD, ALD, CTN - Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 30-Jan-2016 11:59 PM Current Pump & Flow Data: 1990 Max - 0 21000.00 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907)375-7571Unit Phone: Bit TypeBit # Drilled ahead in the intermediate section from 3,049' to 4,233' Mass Spectrometer went offline at 07:47/3,440' MD Size 70.0 . . * 24 hr Recap: (907)375-7571Unit Phone: Bit TypeBit # Drilled ahead in the intermediate section from 4,233' to 5,193' MD. Mass Spectrometer underwent routine Size 70.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 20000.00 Condition - Grade Out 0 31-Jan-2016 11:59 PM Current Pump & Flow Data: 1990 Max - 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2585' Depth Morning Report Report # 13 Customer: Well: Area: Location: DGR, EWR-P4, ELD, XBAT, Geo-Pilot, PWD, ALD, CTN 10.2810.54 North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke 522 5.2 95% Rig Activity: 10.86 Arctic Fox Report For: Tools ml/30minMud Type and 30% Silt. Background gas is currently around 25 units. 2547' 110' 2-1-WT-M-E-I-NO-TD1 6.1 13.250 9.65 Baker / VM-1 9.65 100% Gas In Air=10,000 Units-Connection 70 4 WOB Conductor Comments RPM 2584' Type - Hours 15 2Background (max) Trip Average - 3% KCL5152' Cht Silt Chromatograph (ppm) - 20.080' NOV/ SK616M J2D 2564' Cement 00 3 Depth in / out YP (lb/100ft2) 9.70 Lst - - 0 000 C-4i C-4n 11 - - - 45.5 Weight L-80 Grade C-3 -- Gas Summary Ss GvlCoal 0 (ppb Eq) C-1 C-5i AK-AM-0903061217 Drilling Ahead PV 2564' 11 8.5 0.759 Footage - - 33.47 TFA 20' 18 - C-5n J. Keener / M. Ross ShClyst - - Tuff 0 (current) Depth 4564' 4311'54.0 Date: 149.0 Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 0 4233' 5193' 960' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls maintenance and was calibrated prior to the 5,100' section at 19:48. Currently drilling ahead with the last sample 70% Claystone 14 0 -Minimum 61.0 C-2 44 Depth 6.850 L-80 MBT 5193' 0.8560 10.75'' 194 0 Set At 84.0 in cP 0 00 1402 0 Jacob Robertson Maximum Report By:Logging Engineers:Ashley Wilderom / Jacob Robertson (max)(current) Surface 22 0 - Siltst Cly 4552 30 16.00'' Units* Casing Summary Lithology (%) Size 100 1-1-NO-A-E-I-NO-BHA2Baker/ GX CIX 9.882 1.071 7.17 2564' 2584' . . * 24 hr Recap: 100 1-1-NO-A-E-I-NO-BHA2Baker/ GX CIX 9.882 1.071 7.17 2564' 2584' Cly 85761 - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface 1166 11 - Siltst 16 Jacob Robertson Maximum Report By:Logging Engineers:Ashley Wilderom / Jacob Robertson 460 7570 194 28 Set At 84.0 in cP 71 0 Depth 7.346 L-80 MBT 5934' 0.8560 10.75'' 5500'Minimum - C-2 795 Fluid Gain / Loss (24 hours): 0 bbls RIH to continue drilling. Gas spiked at 5,667' to 795 units. The Legacy gas trap was swapped out for the CVE moments before 73 4 Flow In (spm) Time: 5 5193' 5934' 741' Yesterday's Depth: Current Depth: 24 Hour Progress: 5260'53.0 Date: 160.0 Flow In (gpm) Max @ ft SPP (psi) 28 (current) Depth 5667' 18 - C-5n J. Keener / M. Ross ShClyst - - Tuff 8.5 0.759 Footage - - 33.47 TFA 20' (ppb Eq) C-1 C-5i AK-AM-0903061217 Preparing GEOTAP tool PV 2564' 12 C-3 -- Gas Summary Ss GvlCoal 95 - - - 45.5 Weight L-80 Grade 22 000 C-4i C-4n 196 3 Depth in / out YP (lb/100ft2) 9.60 Lst 30 - Cement 1549 3% KCL5934' Cht Silt Chromatograph (ppm) - 20.080' NOV/ SK616M J2D 2564' Average 296Background (max) Trip WOB Conductor Comments RPM 2584' Type - Hours 15 100% Gas In Air=10,000 Units89Connection 70 446 GEOTAP with a hole depth of 5,934' MD. the gas spike. The last sample consisted of 70% Claystone and 30% Sandstone. Currently we are in the process of running the 2547' 110' 2-1-WT-M-E-I-NO-TD1 6.4 13.250 9.70 Baker / VM-1 9.70 5.8 95% Rig Activity: 10.58 Arctic Fox Report For: Tools ml/30minMud Type 10.39 North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke 522 2585' Depth Morning Report Report # 14 Customer: Well: Area: Location: DGR, EWR-P4, ELD, XBAT, Geo-Pilot, PWD, ALD, CTN 9.96 Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 1-Feb-2016 11:59 PM Current Pump & Flow Data: 1990 Max - 123 20000.00 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907)375-7571Unit Phone: Bit TypeBit # Drilled ahead in the intermediate section from 5,193' to 5,415' MD. Drill pipe washed out and TOOH to 4,718' MD. Size 70.0 . . * 24 hr Recap: (907)375-7571Unit Phone: Bit TypeBit # Continued drilling ahead from 5,934' MD to 6, 304' MD. Conducted GEOTAP operations and continued drilling ahead Size 70.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 20500.00 Condition - Grade Out 255 2-Feb-2016 11:59 PM Current Pump & Flow Data: 2100 Max - 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2585' Depth Morning Report Report # 15 Customer: Well: Area: Location: DGR, EWR-P4, ELD, XBAT, Geo-Pilot, PWD, ALD, CTN 10.0010.29 North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke 530 5.8 95% Rig Activity: 10.46 Arctic Fox Report For: Tools ml/30minMud Type background gas of 45 units. 2547' 110' 2-1-WT-M-E-I-NO-TD1 6.5 13.250 9.65 Baker / VM-1 9.65 100% Gas In Air=10,000 Units162Connection 90 1177 WOB Conductor Comments RPM 2584' Type - Hours 15 45Background (max) Trip Average 14 3% KCL5934' Cht Silt Chromatograph (ppm) - 20.080' NOV/ SK616M J2D 2564' Cement 2931 3 Depth in / out YP (lb/100ft2) 9.60 Lst - - 30 000 C-4i C-4n 268 - - - 45.5 Weight L-80 Grade C-3 -- Gas Summary Ss GvlCoal 338 (ppb Eq) C-1 C-5i AK-AM-0903061217 Drilling Ahead PV 2564' 10 8.5 0.759 Footage - - 33.47 TFA 20' 20 - C-5n J. Keener / M. Ross ShClyst - - Tuff 97 (current) Depth 6438' 6268'61.0 Date: 125.0 Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 367 5934' 6550' 616' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls to 6,550' MD. Max gas was 446 units at 6,438' MD. The last sample at 6,550' MD was 90% Claystone 10% Siltstone with a current 57 8 6556'Minimum 66.0 C-2 446 Depth 7.243 L-80 MBT 6550' 0.8560 10.75'' 190 42 Set At 84.0 in cP 237 688025 5737 67 Jacob Robertson Maximum Report By:Logging Engineers:Douglas Acker / Jacob Robertson (max)(current) Surface 1345 380 10 Siltst Cly 48859 - 16.00'' Units* Casing Summary Lithology (%) Size 100 1-1-NO-A-E-I-NO-BHA2Baker/ GX CIX 9.882 1.071 7.17 2564' 2584' . . * 24 hr Recap: 100 1-1-NO-A-E-I-NO-BHA2Baker/ GX CIX 9.882 1.071 7.17 2564' 2584' Cly 33905 - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface 1357 39 - Siltst 129 Jacob Robertson Maximum Report By:Logging Engineers:Douglas Acker / Jacob Robertson 769 4814 199 31 Set At 84.0 in cP 345 13 Depth 7.549 L-80 MBT 6645' 0.8560 10.75'' 6556'Minimum N/A C-2 371 Fluid Gain / Loss (24 hours): 0 bbls to the shoe and pumped to surface. TIH to 6,521' MD and reamed to bottom. Max trip gas was 116 units. Circulated bottomes up 48 7 Flow In (spm) Time: 54 6570' 6645' 75' Yesterday's Depth: Current Depth: 24 Hour Progress: 6578'62.0 Date: 82.0 Flow In (gpm) Max @ ft SPP (psi) 192 (current) Depth 6614' 18 - C-5n J. Keener / M. Ross ShClyst - - Tuff 8.5 0.759 Footage - - 33.47 TFA 20' (ppb Eq) C-1 C-5i AK-AM-0903061217 POOH PV 2564' 12 C-3 6040 Gas Summary Ss GvlCoal 589 - - - 45.5 Weight L-80 Grade 22 0290 C-4i C-4n 205 3 Depth in / out YP (lb/100ft2) 10.2` Lst - - Cement 2184 3% KCL6645' Cht Silt Chromatograph (ppm) - 20.080' NOV/ SK616M J2D 2564' Average 116-Background (max) Trip WOB Conductor Comments RPM 2584' Type - Hours 15 100% Gas In Air=10,000 Units-Connection - 1559 and pumped dry job. Currently POOH with a bit depth of 6,059' MD. 2547' 110' 2-1-WT-M-E-I-NO-TD1 7.4 13.250 9.85 Baker / VM-1 9.85 5.6 95% Rig Activity: 10.56 Arctic Fox Report For: Tools ml/30minMud Type 10.27 North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke 555 2585' Depth Morning Report Report # 16 Customer: Well: Area: Location: DGR, EWR-P4, ELD, XBAT, Geo-Pilot, PWD, ALD, CTN 10.16 Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 3-Feb-2016 11:59 PM Current Pump & Flow Data: 167 Max - 203 21000.00 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907)375-7571Unit Phone: Bit TypeBit # Drilled ahead to 6,645' MD and ran GEOTAP logs. Ran a short trip and encountered tight spot at 3,135' MD. Reamed Size 70.0 . . * 24 hr Recap: (907)375-7571Unit Phone: Bit TypeBit # POOH from 6,069' MD and L/D BHA. R/U and tested BOPE's. P/U open hole wireline tools and RIH with wireline BHA Size 70.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 20000.00 Condition - Grade Out - 4-Feb-2016 11:59 PM Current Pump & Flow Data: - Max 0-1-WT-G-X-I-NO-TD 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2585' Depth Morning Report Report # 17 Customer: Well: Area: Location: DGR, EWR-P4, ELD, XBAT, Geo-Pilot, PWD, ALD, CTN -- North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 5.8 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type 2547' 110' 2-1-WT-M-E-I-NO-TD1 7.4 13.250 9.75 Baker / VM-1 9.75 100% Gas In Air=10,000 Units-Connection - - WOB Conductor Comments RPM 2584' Type 113 Hours 15 -Background (max) Trip Average 6 3% KCL6645' Cht Silt Chromatograph (ppm) 10 20.080' NOV/ SK616M J2D 2564' Cement -- 3 Depth in / out YP (lb/100ft2) 10.10 Lst - - - --- C-4i C-4n - - - - 45.5 Weight L-80 Grade C-3 6040 Gas Summary Ss GvlCoal - (ppb Eq) C-1 C-5i AK-AM-0903061217 R/U Wireline PV 2564' 10 8.5 0.759 Footage 109.91 4061' 33.47 TFA 20' 18 6645' C-5n J. Keener / M. Ross ShClyst - - Tuff - (current) Depth - -- Date: - Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: - 6645' 6645' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls CVE optimized and cleaned. Currently preparing to RIH with wireline. - --Minimum - C-2 - Depth 7.547 L-80 MBT 6645' 0.8560 10.75'' - - Set At 84.0 in cP - -- - - Jacob Robertson Maximum Report By:Logging Engineers:Douglas Acker / Jacob Robertson (max)(current) Surface - - - Siltst Cly - - 16.00'' Units* Casing Summary Lithology (%) Size 100 1-1-NO-A-E-I-NO-BHA2Baker/ GX CIX 9.882 1.071 7.17 2564' 2584' . . * 24 hr Recap: 100 1-1-NO-A-E-I-NO-BHA2Baker/ GX CIX 9.882 1.071 7.17 2564'2584' Cly - - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface - - - Siltst - Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher - - - - Set At 84.0 in cP - - Depth 7.547 L-80 MBT 6645' 0.8560 10.75'' -Minimum - C-2 - Fluid Gain / Loss (24 hours): 0 bbls L/D wireline tools as of midnight. SDL crew change out. - - Flow In (spm) Time: - 6645' 6645' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: -- Date: - Flow In (gpm) Max @ ft SPP (psi) - (current) Depth - 17 6645' C-5n J. Keener / M. Ross ShClyst -- Tuff 8.5 0.759 Footage 109.91 4061' 33.47 TFA 20' (ppb Eq) C-1 C-5i AK-AM-0903061217 Perform Wireline PV 2564' 10 C-3 -- Gas Summary Ss GvlCoal - --- 45.5 Weight L-80 Grade - --- C-4i C-4n - 3 Depth in / out YP (lb/100ft2) 10.10 Lst -- Cement -- 3% KCL6645' Cht Silt Chromatograph (ppm) 10 20.080' NOV/ SK616M J2D 2564' Average 5-Background (max)Trip WOB Conductor Comments RPM 2584' Type 113 Hours 15 100% Gas In Air=10,000 Units-Connection - - 2547' 110' 2-1-WT-M-E-I-NO-TD1 7.0 13.250 9.80 Baker / VM-1 9.80 5.8 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 2585' Depth Morning Report Report # 18 Customer: Well: Area: Location: DGR, EWR-P4, ELD, XBAT, Geo-Pilot, PWD, ALD, CTN - Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 5-Feb-2016 11:59 PM Current Pump & Flow Data: - Max 0-1-WT-G-X-I-NO-TD - 20500.00 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907)375-7571Unit Phone: Bit TypeBit # RIH w/ wireline tools & perform wireline run #1. L/D run #1 tools, P/U run #2 tools & RIH. Perform wireline run #2. Size 70.0 . . * 24 hr Recap: (907)375-7571Unit Phone: Bit TypeBit # Perform wireline run #3. L/D wireline tools & P/U wireline tools for run #4. Size 70.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 19000.00 Condition - Grade Out - 6-Feb-2016 11:59 PM Current Pump & Flow Data: - Max 0-1-WT-G-X-I-NO-TD Conductor 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2585' Depth Morning Report Report # 19 Customer: Well: Area: Location: DGR, EWR-P4, ELD, XBAT, Geo-Pilot, PWD, ALD, CTN -- North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 5.6 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type 2547' 110' 2-1-WT-M-E-I-NO-TD1 6.8 13.500 9.75 Baker / VM-1 9.75 100% Gas In Air=10,000 Units-Connection - - WOB Conductor Comments Surface RPM 2584' Type 113 Hours 15 -Background (max)Trip Average 3 3% KCL6645' Cht Silt Chromatograph (ppm) 10 20.080' NOV/ SK616M J2D 2564' Cement -- 3 Depth in / out YP (lb/100ft2) 10.00 Lst -- - --- C-4i C-4n - --- 45.5 Weight L-80 Grade C-3 -- Gas Summary Ss GvlCoal - (ppb Eq) C-1 C-5i AK-AM-0903061217 Perform Wireline PV 2564' 9 8.5 0.759 Footage 109.91 4061' 33.47 TFA 20' 16 6645' C-5n J. Keener / M. Ross ShClyst -- Tuff - (current) Depth - -- Date: - Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: - 6645' 6645' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls - --Minimum - C-2 - Depth 7.556 L-80 MBT 6645' 0.8560 10.75'' - - Set At 84.0 in cP - -- - - Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher (max)(current) Surface - - - Siltst Cly - - 16.00'' Units* Casing Summary Lithology (%) Size 100 1-1-NO-A-E-I-NO-BHA2Baker/ GX CIX 9.882 1.071 7.17 2564'2584' . . * 24 hr Recap: 113 0-1-WT-G-X-I-NO-TD3NOV/ SK616M J2D 8.5 0.759 109.91 2584' 6645' Cly - - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface - - - Siltst - Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher - - - - Set At 84.0 in cP - - Depth 7.556 L-80 MBT 6645' 1.0707 10.75'' -Minimum - C-2 - Fluid Gain / Loss (24 hours): 0 bbls 20.029% & 98.986% C1 & GC w/ low cal cocktail gas. - - Flow In (spm) Time: - 6645' 6645' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: -- Date: - Flow In (gpm) Max @ ft SPP (psi) - (current) Depth - 17 C-5n J. Keener / M. Ross ShClyst -- Tuff 8.5 0.759 Footage 7.17 TFA 4061' (ppb Eq) C-1 C-5i AK-AM-0903061217 Cut & slip PV 20' 10 C-3 -- Gas Summary Ss GvlCoal - --- 45.5 Weight L-80 Grade - --- C-4i C-4n - 4 Depth in / out YP (lb/100ft2) 10.20 Lst -- Cement -- 3% KCL6645' Cht Silt Chromatograph (ppm) 15.02564' NOV SK616M J2D PDC 2584' Average 4-Background (max)Trip WOB Conductor Comments Surface RPM 6645' Type Hours 10 100% Gas In Air=10,000 Units-Connection - - 2547' 110' 1-1-NO-A-E-I-NO-BHA2 6.7 9.882 9.75 Baker/ GX CIX 9.75 5.6 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 2585' Depth Morning Report Report # 20 Customer: Well: Area: Location: DGR, EWR-P4, XBAT, DM, HCIM, PWD, ALD, CTN - Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 7-Feb-2016 11:59 PM Current Pump & Flow Data: - Max Conductor - 21000.00 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907) 375-7571Unit Phone: Bit TypeBit # Perform wireline run #4 & L/D tools. P/U BHA #4 & RIH. Cut & slip drill line. SDL calibrate THA using 10.030%, Size 100.0 . . * 24 hr Recap: (907) 375-7571Unit Phone: Bit TypeBit # Cont to cut & slip drill line. RIH to 6600' MD & wash in hole & log f/ 6600' MD to 6645' MD. Drill ahead f/ 6645' MD to Size 100.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 20500 Condition - Grade Out 309 8-Feb-2016 11:59 PM Current Pump & Flow Data: - Max Conductor 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2585' Depth Morning Report Report # 21 Customer: Well: Area: Location: DGR, EWR-P4, XBAT, DM, HCIM, PWD, ALD, CTN 10.5410.58 North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 5.6 95% Rig Activity: 10.69 Arctic Fox Report For: Tools ml/30minMud Type POOH. Max gas observed while drilling was 240u @ 6690' MD associated with Sst. Samples consisted of 60%-70% Sltst w/ minor 2547' 110' 1-1-NO-A-E-I-NO-BHA2 7.9 9.882 10.10 Baker/ GX CIX 10.10 30%-80% Sltst w/ minor Sh & Clyst f/ 6900' MD to 7070' MD. Sst, Sh & Clyst f/ 6645' MD to 6720' MD, 50%-75% Sh w/ 25%-40% Sltst & minor Sst f/ 6720' MD to 6900' MD and 10%-60% Sst & 100% Gas In Air=10,000 Units-Connection 5 1279 WOB Conductor Comments Surface RPM 6645' Type Hours 10 -Background (max)Trip Average 28 3% KCL7070' Cht Silt Chromatograph (ppm) 15.02564' NOV SK616M J2D PDC 2584' Cement 31145 4 Depth in / out YP (lb/100ft2) 10.30 Lst 10 - 36 000 C-4i C-4n 315 --- 45.5 Weight L-80 Grade C-3 5- Gas Summary Ss GvlCoal 537 (ppb Eq) C-1 C-5i AK-AM-0903061217 POOH PV 20' 12 8.5 0.759 Footage 425' 7.17 TFA 4061' 18 7070' C-5n J. Keener / M. Ross ShClyst -- Tuff 135 (current) Depth 6690' 6669'68.1 Date: 169.2 Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 6 6645' 7070' 425' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls 7070' MD. Circ & cond mud, begin short trip f/ 7070' MD to 6449' MD. Trip back to bottom, pump bus & cir hole clean. Begin to 45 4 6853'Minimum - C-2 240 Depth 7.542 L-80 MBT 6645' 1.0707 10.75'' - 46 Set At 84.0 in cP 225 0125 4709 119 Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher (max)(current) Surface 1055 0 80 Siltst Cly 22953 - 16.00'' Units* Casing Summary Lithology (%) Size 113 0-1-WT-G-X-I-NO-TD3NOV/ SK616M J2D 8.5 0.759 109.91 2584' 6645' . . * 24 hr Recap: 113 0-1-WT-G-X-I-NO-TD3NOV/ SK616M J2D 8.5 0.759 109.91 2584' 6645' Cly 0 - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface 0 0 - Siltst 0 Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher 0 0 - 0 Set At 84.0 in cP 0 0 Depth 7.547 L-80 MBT 7070' 1.0707 10.75'' -Minimum - C-2 - Fluid Gain / Loss (24 hours): 0 bbls - - Flow In (spm) Time: 0 7070' 7070' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: -- Date: - Flow In (gpm) Max @ ft SPP (psi) 0 (current) Depth - 18 7070' C-5n J. Keener / M. Ross ShClyst -- Tuff 8.5 0.759 Footage 425' 7.17 TFA 4061' (ppb Eq) C-1 C-5i AK-AM-0903061217 Wireline logging PV 20' 12 C-3 -- Gas Summary Ss GvlCoal 0 --- 45.5 Weight L-80 Grade 0 000 C-4i C-4n 0 4 Depth in / out YP (lb/100ft2) 9.80 Lst -- Cement 00 3% KCL7070' Cht Silt Chromatograph (ppm) 15.02564' NOV SK616M J2D PDC 2584' Average 4-Background (max)Trip WOB Conductor Comments Surface RPM 6645' Type Hours 10 100% Gas In Air=10,000 Units-Connection - 0 2547' 110' 1-1-NO-A-E-I-NO-BHA2 7.9 9.882 10.10 Baker/ GX CIX 10.10 5.8 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 6645' Depth Morning Report Report # 22 Customer: Well: Area: Location: DGR, EWR-P4, XBAT, DM, HCIM, PWD, ALD, CTN - Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 9-Feb-2016 11:59 PM Current Pump & Flow Data: - Max Conductor 0 20500 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907) 375-7571Unit Phone: Bit TypeBit # Cont to POOH & L/D BHA #4. R/U wireline & perform wireline logging. Size 100.0 . . * 24 hr Recap: (907) 375-7571Unit Phone: Bit TypeBit # Complete wireline logging & R/D wireline equip. Perform rig maintenance & RIH to 6943' MD w/ 2-7/8" pipe. Wash Size 100.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 20500 Condition - Grade Out 0 10-Feb-2016 11:59 PM Current Pump & Flow Data: - Max 1-3-BT-G-X-I-CT-TD Conductor 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 6645' Depth Morning Report Report # 23 Customer: Well: Area: Location: DGR, EWR-P4, XBAT, DM, HCIM, PWD, ALD, CTN -- North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 5.8 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type 2547' 110' 1-1-NO-A-E-I-NO-BHA2 7.9 9.882 10.10 Baker/ GX CIX 10.10 100% Gas In Air=10,000 Units-Connection - 0 WOB Conductor Comments Surface RPM 6645' Type 120 Hours 10 -Background (max) Trip Average 47 3% KCL7070' Cht Silt Chromatograph (ppm) 14 15.02564' NOV SK616M J2D PDC 2584' Cement 00 4 Depth in / out YP (lb/100ft2) 9.80 Lst -- 0 000 C-4i C-4n 0 --- 45.5 Weight L-80 Grade C-3 -- Gas Summary Ss GvlCoal 0 (ppb Eq) C-1 C-5i AK-AM-0903061217 Plug & abandon PV 20' 12 8.5 0.759 Footage 15.41 425' 7.17 TFA 4061' 18 7070' C-5n J. Keener / M. Ross ShClyst -- Tuff 0 (current) Depth - -- Date: - Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 0 7070' 7070' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls down to 7069' MD & pump cmt plug. POOH to 6501' MD & circ. Pump 2nd cmt plug, POOH to 5996' MD & circ. - --Minimum - C-2 - Depth 7.547 L-80 MBT 7070' 1.0707 10.75'' - 0 Set At 84.0 in cP 0 00 0 0 Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher (max)(current) Surface 0 0 - Siltst Cly 0 - 16.00'' Units* Casing Summary Lithology (%) Size 113 0-1-WT-G-X-I-NO-TD3NOV/ SK616M J2D 8.5 0.759 109.91 2584' 6645' . . * 24 hr Recap: 113 0-1-WT-G-X-I-NO-TD3NOV/ SK616M J2D 8.5 0.759 109.91 2584' 6645' Cly 0 - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface 0 0 - Siltst 0 Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher 0 0 - 0 Set At 84.0 in cP 0 0 Depth 7.547 L-80 MBT 7070' 1.0707 10.75'' -Minimum - C-2 - Fluid Gain / Loss (24 hours): 0 bbls wiper ball & pump dry job. POOH f/ 3850' MD to 2100' MD. Cont to POOH sideways & L/D stnds. Monitor well & L/D DP. Perform - - Flow In (spm) Time: 0 7070' 7070' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: -- Date: - Flow In (gpm) Max @ ft SPP (psi) 0 (current) Depth - 20 7070' C-5n J. Keener / M. Ross ShClyst -- Tuff 8.5 0.759 Footage 15.41 425' 7.17 TFA 4061' (ppb Eq) C-1 C-5i AK-AM-0903061217 Testing BOPE PV 20' 12 C-3 -- Gas Summary Ss GvlCoal 0 --- 45.5 Weight L-80 Grade 0 000 C-4i C-4n 0 4 Depth in / out YP (lb/100ft2) 10.40 Lst -- Cement 00 3% KCL7070' Cht Silt Chromatograph (ppm) 14 15.02564' NOV SK616M J2D PDC 2584' Average 14-Background (max)Trip WOB Conductor Comments Surface RPM 6645' Type 120 Hours 10 100% Gas In Air=10,000 Units-Connection - 0 rig maintainence and R/U testing equip. Test BOPE. SDL crew clean gas equip. 2547' 110' 1-1-NO-A-E-I-NO-BHA2 8.4 9.882 10.20 Baker/ GX CIX 10.20 8.2 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 6645' Depth Morning Report Report # 24 Customer: Well: Area: Location: DGR, EWR-P4, XBAT, DM, HCIM, PWD, ALD, CTN - Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 11-Feb-2016 11:59 PM Current Pump & Flow Data: - Max 1-3-BT-G-X-I-CT-TD Conductor 0 18000 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907) 375-7571Unit Phone: Bit TypeBit # Circ wiper ball & pump cmt plug. POOH to 5492' MD circ wiper ball & pump cmt plug. POOH to 3850' MD, pump Size 100.0 . . * 24 hr Recap: (907) 375-7571Unit Phone: Bit TypeBit # Finish testing BOPEs. M/U BHA & RIH t/ TOC @ 4732' MD. POOH to 3036' MD & circ mud clean. RIH to 4701' MD & Size 100.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 18000 Condition - Grade Out 0 12-Feb-2016 11:59 PM Current Pump & Flow Data: - Max 1-3-BT-G-X-I-CT-TD Conductor 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current Depth Morning Report Report # 25 Customer: Well: Area: Location: --- North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 9.0 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type 2547' 110' 1-1-NO-A-E-I-NO-BHA2 8.4 9.882 10.20 Baker/ GX CIX 10.20 100% Gas In Air=10,000 Units-Connection - 0 WOB Conductor Comments Surface RPM 6645' Type 120 Hours 10 -Background (max)Trip Average 34 3% KCL7070' Cht Silt Chromatograph (ppm) 14 15.02564' NOV SK616M J2D PDC 2584' Cement 00 4 Depth in / out YP (lb/100ft2) 10.50 Lst -- 0 000 C-4i C-4n 0 --- 45.5 Weight L-80 Grade C-3 -- Gas Summary Ss GvlCoal 0 (ppb Eq) C-1 C-5i AK-AM-0903061217 Waste injection PV 20' 12 8.5 0.759 Footage 15.41 425' 7.17 TFA 4061' 22 7070' C-5n J. Keener / M. Ross ShClyst -- Tuff 0 (current) Depth - -- Date: - Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 0 7070' 7070' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 0 bbls wash down to top of plug, set 15K on cmt. POOH to 3028' MD, circ & cond mud. R/U injection equip & inject mud. - --Minimum - C-2 - Depth 7.548 L-80 MBT 1.0707 10.75'' - 0 Set At 84.0 in cP 0 00 0 0 Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher (max)(current) Surface 0 0 - Siltst Cly 0 - 16.00'' Units* Casing Summary Lithology (%) Size 113 0-1-WT-G-X-I-NO-TD3NOV/ SK616M J2D 8.5 0.759 109.91 2584' 6645' . . * 24 hr Recap: 113 0-1-WT-G-X-I-NO-TD3NOV/ SK616M J2D 8.5 0.759 109.91 2584' 6645' Cly 0 - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface 0 0 - Siltst 0 Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher 0 0 - 0 Set At 84.0 in cP 0 0 Depth 7.554 L-80 MBT 1.0707 10.75'' -Minimum - C-2 - Fluid Gain / Loss (24 hours): 0 bbls - - Flow In (spm) Time: 0 7070' 7070' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: -- Date: - Flow In (gpm) Max @ ft SPP (psi) 0 (current) Depth - 22 7070' C-5n J. Keener / M. Ross ShClyst -- Tuff 8.5 0.759 Footage 15.41 425' 7.17 TFA 4061' (ppb Eq) C-1 C-5i AK-AM-0903061217 Wait on weather PV 20' 12 C-3 -- Gas Summary Ss GvlCoal 0 --- 45.5 Weight L-80 Grade 0 000 C-4i C-4n 0 4 Depth in / out YP (lb/100ft2) 10.30 Lst -- Cement 00 3% KCL7070' Cht Silt Chromatograph (ppm) 14 15.02564' NOV SK616M J2D PDC 2584' Average 3-Background (max)Trip WOB Conductor Comments Surface RPM 6645' Type 120 Hours 10 100% Gas In Air=10,000 Units-Connection - 0 2547' 110' 1-1-NO-A-E-I-NO-BHA2 8.4 9.882 10.20 Baker/ GX CIX 10.20 9.0 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - Depth Morning Report Report # 26 Customer: Well: Area: Location: -- Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 13-Feb-2016 11:59 PM Current Pump & Flow Data: - Max 1-3-BT-G-X-I-CT-TD Conductor 0 18000 Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907) 375-7571Unit Phone: Bit TypeBit # Cont injection operations. Phase III conditions, monitor well. Size 100.0 . . * 24 hr Recap: (907) 375-7571Unit Phone: Bit TypeBit # Phase III conditions, continue to wait on weather. POOH & L/D 82 jts of DP. RIH to 3072' MD. Condition mud before Size 100.0 Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides 18000 Condition - Grade Out 0 14-Feb-2016 11:59 PM Current Pump & Flow Data: - Max 1-3-BT-G-X-I-CT-TD Conductor 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current Depth Morning Report Report # 27 Customer: Well: Area: Location: --- North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - 9.0 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type 2547' 110' 1-1-NO-A-E-I-NO-BHA2 8.1 9.882 10.10 Baker/ GX CIX 10.10 100% Gas In Air=10,000 Units-Connection - 0 WOB Conductor Comments Surface RPM 6645' Type 120 Hours 10 -Background (max)Trip Average 4 3% KCL7070' Cht Silt Chromatograph (ppm) 14 15.02564' NOV SK616M J2D PDC 2584' Cement 00 4 Depth in / out YP (lb/100ft2) 10.60 Lst -- 0 000 C-4i C-4n 0 --- 45.5 Weight L-80 Grade C-3 -- Gas Summary Ss GvlCoal 0 (ppb Eq) C-1 C-5i AK-AM-0903061217 Condition mud PV 20' 12 8.5 0.759 Footage 15.41 425' 7.17 TFA 4061' 22 7070' C-5n J. Keener / M. Ross ShClyst -- Tuff 0 (current) Depth - -- Date: - Flow In (gpm) Max @ ft SPP (psi) Flow In (spm) Time: 0 7070' 7070' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: Fluid Gain / Loss (24 hours): 6.4 bbls injection. - --Minimum - C-2 - Depth 7.549 L-80 MBT 1.0707 10.75'' - 0 Set At 84.0 in cP 0 00 0 0 Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher (max)(current) Surface 0 0 - Siltst Cly 0 - 16.00'' Units* Casing Summary Lithology (%) Size 113 0-1-WT-G-X-I-NO-TD3NOV/ SK616M J2D 8.5 0.759 109.91 2584' 6645' . . * 24 hr Recap: 113 0-1-WT-G-X-I-NO-TD3NOV/ SK616M J2D 8.5 0.759 109.91 2584' 6645' Cly 0 - 16.00'' Units* Casing Summary Lithology (%) Size (max)(current) Surface 0 0 - Siltst 0 Leigh Ann Rasher Maximum Report By:Logging Engineers:Douglas Acker / Leigh Ann Rasher 0 0 - 0 Set At 84.0 in cP 0 0 Depth -52 L-80 MBT 1.0707 10.75'' -Minimum - C-2 - Fluid Gain / Loss (24 hours): 0 bbls 2505' MD and monitor well. - - Flow In (spm) Time: 0 7070' 7070' 0' Yesterday's Depth: Current Depth: 24 Hour Progress: -- Date: - Flow In (gpm) Max @ ft SPP (psi) 0 (current) Depth - - 7070' C-5n M. Thornton / R.Wimmer ShClyst -- Tuff 8.5 0.759 Footage 15.41 425' 7.17 TFA 4061' (ppb Eq) C-1 C-5i AK-AM-0903061217 Monitoring Well PV 20' - C-3 -- Gas Summary Ss GvlCoal 0 --- 45.5 Weight L-80 Grade 0 000 C-4i C-4n 0 4 Depth in / out YP (lb/100ft2) 10.30 Lst -- Cement 00 3% KCL7070' Cht Silt Chromatograph (ppm) 14 15.02564' NOV SK616M J2D PDC 2584' Average 71-Background (max) Trip WOB Conductor Comments Surface RPM 6645' Type 120 Hours 10 100% Gas In Air=10,000 Units-Connection - 0 2547' 110' 1-1-NO-A-E-I-NO-BHA2 - 9.882 9.80 Baker/ GX CIX 9.80 - 95% Rig Activity: - Arctic Fox Report For: Tools ml/30minMud Type - North Slope Borough Smith Bay / Point Lonely Job No.: Daily Charges: Total Charges: MWD Summary 24 hr Max Gallons/stroke - Depth Morning Report Report # 28 Customer: Well: Area: Location: -- Rig: CT-1 / Tulimaniq Caelus Energy Alaska ROP ROP (ft/hr) Avg Current 2.79 @ Mud Data API FL Avg MinECD (ppg) pH mg/l to 15-Feb-2016 11:59 PM Current Pump & Flow Data: - Max 1-3-BT-G-X-I-CT-TD Conductor 0 - Condition - Grade Out Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides (907) 375-7571Unit Phone: Bit TypeBit # Inject 2nd load of waste. Perform rig maintenance and POOH f/ 3072' MD to 2505' MD to L/D pipe. Circulate B/U @ Size 100.0              ! 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Company: Caelus Energy Alaska, Smith Bay LLC Well: CT #1 API: 50-879-20021-00-00 Field: Wildcat Exploration Rig: Doyon Arctic Fox Country: USA Analyst: Mathew D. Rowe Date: 02/16/2016 Mass Spectrometry Gas Analysis Studio GasFact End of Well Report 1I GasFact End of Well Report Date Disclaimer Halliburton Energy Services (HES) will use its best efforts to furnish customers with accurate information and interpretations that are part of, and incident to, the services provided. However, HES cannot and does not warrant the accuracy or correctness of such information and interpretations. Under no circumstances should any such information or i nterpretation be relied upon as the sole basis for any drilling, completion, production, or financial decision or any procedure involving any risk to the safety of any drilling venture, drilling rig or its crew or any other third party. The Customer has full responsibility for all drilling, completion and production operation. HES makes no representations or warranties, either expressed or implied, including, but not limited to, the implied warranties of merchantability or fitness for a particular purpose, with respect to the services rendered. In no event will HES be liable for failure to obtain any particular results or for any damages, including, but not limited to, indirect, special or consequential damages, resulting from the use of any information or interpretation provided by HES. 2I GasFact End of Well Report Table of Contents Table of Figures 3 Executive Summary. 5 Methodology. 6 Zone A: 4,240’ – 4,380’ MD 7 Zone B: 5,660’ – 5,790’ MD 12 Zone C: 5,870’ – 5,955’ MD 17 Zone D: 6,300’– 6,460’ MD 22 Zone E: 6,610’– 6,620’ MD 27 3I GasFact End of Well Report Table of Figures Zone A Figure 1.A Pixler Plot 8 Figure 1.B Cross plot of Gas Chromatography propane to methane vs propane to ethane. 8 Figure 1.C Compositional ternary plot using ethane, propane, and normal butane. 8 Figure 1.D Cross plot of Gas Chromatography iso-pentane to normal pentane vs iso-butane to normal butane. 8 Figure 2.A Ternary plot of Mass Spectroscopy sulfur dioxide (MS Sulfur_3) vs benzene (MS Soluble2) vs sulfur oxide (MS Sulfur_2). 10 Figure 2.B Ternary plot of Mass Spectroscopy ethane vs propane vs the sum of butane, pentane and hexane. 10 Figure 2.C Ternary plot of Mass Spectroscopy toluene (MS Soluble3) to benzene (MS Soluble2) to hexane. 10 Figure 2.D Cross plot of Mass Spectroscopy hexane to benzene (MS Soluble2) vs hexane to toluene (MS Soluble3). 10 Zone B Figure 3.A Pixler Plot 13 Figure 3.B Cross plot of Gas Chromatography propane to methane vs propane to ethane. 13 Figure 3.C Compositional ternary plot using ethane, propane, and normal butane. 13 Figure 3.D Cross plot of Gas Chromatography iso-pentane to normal pentane vs iso-butane to normal butane. 13 Figure 4.A Ternary plot of Mass Spectroscopy sulfur dioxide (MS Sulfur_3) vs benzene (MS Soluble2) vs sulfur oxide (MS Sulfur_2). 15 Figure 4.B Ternary plot of Mass Spectroscopy ethane vs propane vs the sum of butane, pentane and hexane. 15 Figure 4.C Ternary plot of Mass Spectroscopy toluene (MS Soluble3) to benzene (MS Soluble2) to hexane. 15 Figure 4.D Cross plot of Mass Spectroscopy hexane to benzene (MS Soluble2) vs hexane to toluene (MS Soluble3). 15 Zone C Figure 5.A Pixler Plot 18 Figure 5.B Cross plot of Gas Chromatography propane to methane vs propane to ethane. 18 Figure 5.C Compositional ternary plot using ethane, propane, and normal butane. 18 Figure 5.D Cross plot of Gas Chromatography iso-pentane to normal pentane vs iso-butane to normal butane. 18 Figure 6.A Ternary plot of Mass Spectroscopy sulfur dioxide (MS Sulfur_3) vs benzene (MS Soluble2) vs sulfur oxide (MS Sulfur_2). 20 Figure 6.B Ternary plot of Mass Spectroscopy ethane vs propane vs the sum of butane, pentane and hexane. 20 4I GasFact End of Well Report Figure 6.C Ternary plot of Mass Spectroscopy toluene (MS Soluble3) to benzene (MS Soluble2) to hexane. 20 Figure 6.D Cross plot of Mass Spectroscopy hexane to benzene (MS Soluble2) vs hexane to toluene (MS Soluble3). 20 Zone D Figure 7.A Pixler Plot 23 Figure 7.B Cross plot of Gas Chromatography propane to methane vs propane to ethane. 23 Figure 7.C Compositional ternary plot using ethane, propane, and normal butane. 23 Figure 7.D Cross plot of Gas Chromatography iso-pentane to normal pentane vs iso-butane to normal butane. 23 Figure 8.A Ternary plot of Mass Spectroscopy sulfur dioxide (MS Sulfur_3) vs benzene (MS Soluble2) vs sulfur oxide (MS Sulfur_2). 25 Figure 8.B Ternary plot of Mass Spectroscopy ethane vs propane vs the sum of butane, pentane and hexane. 25 Figure 8.C Ternary plot of Mass Spectroscopy toluene (MS Soluble3) to benzene (MS Soluble2) to hexane. 25 Figure 8.D Cross plot of Mass Spectroscopy hexane to benzene (MS Soluble2) vs hexane to toluene (MS Soluble3). 25 Zone E Figure 9.A Pixler Plot 28 Figure 9.B Cross plot of Gas Chromatography propane to methane vs propane to ethane. 28 Figure 9.C Compositional ternary plot using ethane, propane, and normal butane. 28 Figure 9.D Cross plot of Gas Chromatography iso-pentane to normal pentane vs iso-butane to normal butane. 28 Figure 10.A Ternary plot of Mass Spectroscopy sulfur dioxide (MS Sulfur_3) vs benzene (MS Soluble2) vs sulfur oxide (MS Sulfur_2). 30 Figure 10.B Ternary plot of Mass Spectroscopy ethane vs propane vs the sum of butane, pentane and hexane. 30 Figure 10.C Ternary plot of Mass Spectroscopy toluene (MS Soluble3) to benzene (MS Soluble2) to hexane. 30 Figure 10.D Cross plot of Mass Spectroscopy hexane to benzene (MS Soluble2) vs hexane to toluene (MS Soluble3). 30 5I GasFact End of Well Report Executive Summary. Five major zones were identified for further analysis. Zone A is a barrier with increases in porosity and/or permeability and increased heavier hydrocarbon species after the barrier. Zone B has indications of a hydrocarbon gas associated with a liquid hydrocarbon. Zone C and Zone B appear to have relatively the same gas finger print. Heavier gas is being recycled during these zones making it appear that there is gradation, which is false. Zone D has increased indications of gas hydrocarbons associated with liquid hydrocarbons with a different gas finger print than Zone B and C. Zone E is a possible fault zone or some other geological zone with increased permeability and/or porosity. The fluid in Zone E has strong indications of liquid hydrocarbons present. 6I GasFact End of Well Report Methodology. The gas out data is presented for discussion from a constant volume extractor. Gas out data does not account for recycled gas. 7I GasFact End of Well Report Zone A: 4,240’ – 4,380’ MD Zone A Discussion: The zone is a barrier. There are indications of increased permeability and/or porosity after the barrier. The fluid also has indications of increased of heavier hydrocarbons present. 8I GasFact End of Well Report Figure 1.A Pixler Plot Figure 1.B Cross plot of Gas Chromatography propane to methane vs propane to ethane. Figure 1.C Compositional ternary plot using ethane, propane, and normal butane. Figure 1.D Cross plot of Gas Chromatography iso-pentane to normal pentane vs iso-butane to normal butane. A B C D 9I GasFact End of Well Report Figure 1.A Discussion: Pixler plots are used as initial indicators of possible non-productive, gas or oil formational fluid. The gas chromatograph data shown in this pixler plot shows the zone to be in a non-productive zone. There is a slight noticeable shift in the data around 4240’ MD. A slight increase in formation porosity and /or permeability was detected. Figure 1.B Discussion: This figure is used to determine if there are sub-zones to the main zone. There appears to be sub- zones within this zone that may be due to changes in porosity and/or permeability. The data does shift on the same trend at 4240’ MD. Figure 1.C Discussion: The compositional ternary plot indicates whether a fluid is productive gas/liquid or non- productive hydrocarbon. The zone is in the non-productive hydrocarbon area of the plot. The data does shift towards C3 at 4240’ MD. Figure 1.D Discussion: This figure is used to determine if the formation fluid has experienced biodegradation based on iso/normal ratios and to determine if there are sub-zones in the main zone. No interpretation can be made from this plot. 10I GasFact End of Well Report Figure 2.A Ternary plot of Mass Spectroscopy sulfur dioxide (MS Sulfur_3) vs benzene (MS Soluble2) vs sulfur oxide (MS Sulfur_2). Figure 2.B Ternary plot of Mass Spectroscopy ethane vs propane vs the sum of butane, pentane and hexane. Figure 2.C Ternary plot of Mass Spectroscopy toluene (MS Soluble3) to benzene (MS Soluble2) to hexane. Figure 2.D Cross plot of Mass Spectroscopy hexane to benzene (MS Soluble2) vs hexane to toluene (MS Soluble3). A B C D 11I GasFact End of Well Report Figure 2.A Discussion: The examination of sulfur dioxide, sulfur oxide, and benzene is to determine if biodegradation has occurred and to help identify gas and liquid formational fluid. High sulfur was encountered throughout the well. This could be attributed to either the originating kerogen type or bacterial degradation. There is a shift in the data away from benzene towards sulfur dioxide at 4240’ MD. There is an increase in gases present at this point and the formational fluid has increased sulfur due to possible biogenic degradation. Figure 2.B Discussion: The figure is the mass spectroscopy equivalent of the compositional ternary plot. Significant increase in relative C2 indicating a dryer gas that is exhibiting biodegradation indicators. Figure 2.C Discussion: The toluene, benzene and hexane ternary allows for the examination of the interaction between chemical species with varying affinities for aqueous and non-aqueous phases. Relative low values of benzene, toluene and hexane make interpretation ambiguous. There does appear to be an increase in hexane in the data after 4240’ MD that indicates increased liquid hydrocarbon indicators that are in contact or were in contact with water due to the maintained value of benzene. Figure 2.D Discussion: The figure is to determine if there are multiple formational fluids present or a gradation of formational fluids present. The shift in data around 4240’ MD does support a shift in the formational fluids. Hexane spikes relative to toluene, which indicates liquid hydrocarbons, but the lack of change in hexane to benzene ratio is indicative of liquid water contact with liquid hydrocarbons. 12I GasFact End of Well Report Zone B: 5,660’ – 5,790’ MD Zone B Discussion: The zone appears to have increasing indicators of gas hydrocarbons associated with liquid hydrocarbons. The gas chromatograph’s limited detection does not pick up the indicators of liquid hydrocarbons, but the mass spectrometer does. The formation also has indications of biodegradation at some point. 13I GasFact End of Well Report Figure 3.A Pixler Plot Figure 3.B Cross plot of Gas Chromatography propane to methane vs propane to ethane. Figure 3.C Compositional ternary plot using ethane, propane, and normal butane. Figure 3.D Cross plot of Gas Chromatography iso-pentane to normal pentane vs iso-butane to normal butane. A B C D 14I GasFact End of Well Report Figure 3.A Discussion: Pixler plots are used as initial indicators of possible non-productive, gas or oil formational fluid. The pixler plot indicates increasing weight of hydrocarbons at the bottom of the section. The increase at the bottom of the section is most likely due to recycled gas giving a false indication of gradation. The Pixler plot falls short in the interpretation side due to the lack of heavier hydrocarbon analysis. Figure 3.B Discussion: This figure is used to determine if there are sub-zones to the main zone. Plot indicates increasing concentration of heavier hydrocarbons with depth. There is a shift in the data with depth indicating increasing C2 and C3, which could be attributed to recycled gas. The shift in data can be mainly attributed to increasing heavy hydrocarbons. The data has shifted to suggest a liquid hydrocarbon could be in place. Figure 3.C Discussion: The compositional ternary plot indicates whether a fluid is productive gas/liquid or non- productive hydrocarbon. The shift in data from favoring C2 towards C3 and C4 is indicative of increasing liquid component. There may be associated liquid phase in the deeper part of the section. Recycled gas is making the formation gas appear heavier than it should. Figure 3.D Discussion: This figure is used to determine if the formation fluid has experienced biodegradation based on iso/normal ratios and to determine if there are sub-zones in the main zone. The zone appears to trend towards less biodegradation with depth, which is unexpected. The shift may be due to recycled gases. 15I GasFact End of Well Report Figure 4.A Ternary plot of Mass Spectroscopy sulfur dioxide (MS Sulfur_3) vs benzene (MS Soluble2) vs sulfur oxide (MS Sulfur_2). Figure 4.B Ternary plot of Mass Spectroscopy ethane vs propane vs the sum of butane, pentane and hexane. Figure 4.C Ternary plot of Mass Spectroscopy toluene (MS Soluble3) to benzene (MS Soluble2) to hexane. Figure 4.D Cross plot of Mass Spectroscopy hexane to benzene (MS Soluble2) vs hexane to toluene (MS Soluble3). A B C D 16I GasFact End of Well Report Figure 4.A Discussion: The examination of sulfur dioxide, sulfur oxide, and benzene is to determine if biodegradation has occurred and to help identify gas and liquid formational fluid. The plot indicates that biodegradation may have occurred in this zone and trends towards less biodegradation with depth due to building recycled gas. Figure 4.B Discussion: The figure is the mass spectroscopy equivalent of the compositional ternary plot. The zone has an increase in heavier components with depth. Some of the increase can be attributed to recycled gas, but the majority of it can be attributed to increasing heavier hydrocarbon species. The increasing heavier hydrocarbon species does indicate a possible liquid phase is in place. Figure 4.C Discussion: The toluene, benzene and hexane ternary allows for the examination of the interaction between chemical species with varying affinities for aqueous and non-aqueous phases. The zone is dominated by hexane, which favors the possibility of liquid phase in place. Figure 4.D Discussion: The figure is to determine if there are multiple formational fluids present or a gradation of formational fluids present. The zone appears to be a single zone with high indicators of liquid hydrocarbons. 17I GasFact End of Well Report Zone C: 5,870’ – 5,955’ MD Zone C Discussion: The zone appears to have the same relative finger print as the zone above. The formational fluid appears to have gas hydrocarbons associated with a liquid hydrocarbon. The zone has experienced biodgradation. 18I GasFact End of Well Report Figure 5.A Pixler Plot Figure 5.B Cross plot of Gas Chromatography propane to methane vs propane to ethane. Figure 5.C Compositional ternary plot using ethane, propane, and normal butane. Figure 5.D Cross plot of Gas Chromatography iso-pentane to normal pentane vs iso-butane to normal butane. A B C D 19I GasFact End of Well Report Figure 5.A Discussion: Pixler plots are used as initial indicators of possible non-productive, gas or oil formational fluid. The Pixler plot indicates a trend from a possible producible gas hydrocarbon to a non-productive hydrocarbon. The bias of the extractor is indicated by the elevated Pixler plot. The relative values of the Pixler in this zone match the zone above. The two fluids may be related. Other plots indicate possible liquid state present or residual of liquid state present. Figure 5.B Discussion: This figure is used to determine if there are sub-zones to the main zone. The zone appears to have two sub-zones. The upper part of the zone is dominated by a gas that has possible indications of a limited associated liquid phase. The bottom zone does indicate the lack of a heavier phase, but it is limited due to the lack of heavier hydrocarbon detection by GC. Figure 5.C Discussion: The compositional ternary plot indicates whether a fluid is productive gas/liquid or non- productive hydrocarbon. The zone is in the gas dominated part of the compositional ternary plot. The main part of the zone does indicate a shift towards liquid hydrocarbons. Figure 5.D Discussion: This figure is used to determine if the formation fluid has experienced biodegradation based on iso/normal ratios and to determine if there are sub-zones in the main zone. The elevated iso/normal ratios indicate that at some point the fluid experienced significant biodegradation. 20I GasFact End of Well Report Figure 6.A Ternary plot of Mass Spectroscopy sulfur dioxide (MS Sulfur_3) vs benzene (MS Soluble2) vs sulfur oxide (MS Sulfur_2). Figure 6.B Ternary plot of Mass Spectroscopy ethane vs propane vs the sum of butane, pentane and hexane. Figure 6.C Ternary plot of Mass Spectroscopy toluene (MS Soluble3) to benzene (MS Soluble2) to hexane. Figure 6.D Cross plot of Mass Spectroscopy hexane to benzene (MS Soluble2) vs hexane to toluene (MS Soluble3). A B C D 21I GasFact End of Well Report Figure 6.A Discussion: The examination of sulfur dioxide, sulfur oxide, and benzene is to determine if biodegradation has occurred and to help identify gas and liquid formational fluid. The plot indicates that biodegradation may have occurred in this zone and trends towards less biodegradation with depth as benzene is recycled. Figure 6.B Discussion: The figure is the mass spectroscopy equivalent of the compositional ternary plot. The zone has an increase in lighter components with depth indicating a movement away from a liquid phase as the zone is exited. Figure 6.C Discussion: The toluene, benzene and hexane ternary allows for the examination of the interaction between chemical species with varying affinities for aqueous and non-aqueous phases. The system is dominated by hexane with reducing hexane relative to benzene and toluene as recycled gas increases. This is indicative of moving away from a gas associated with a liquid. Figure 6.D Discussion: The figure is to determine if there are multiple formational fluids present or a gradation of formational fluids present. The zone appears to be a single zone with high indicators of liquid hydrocarbons. 22I GasFact End of Well Report Zone D: 6,300’– 6,460’ MD Zone D Discussion: The zone has indications of a gas hydrocarbon present with an associated liquid. The zone also exhibits some indicators of reduced permeability and/or porosity. The fluid has been biodegraded. 23I GasFact End of Well Report Figure 7.A Pixler Plot Figure 7.B Cross plot of Gas Chromatography propane to methane vs propane to ethane. Figure 7.C Compositional ternary plot using ethane, propane, and normal butane. Figure 7.D Cross plot of Gas Chromatography iso-pentane to normal pentane vs iso-butane to normal butane. A B C D 24I GasFact End of Well Report Figure 7.A Discussion: Pixler plots are used as initial indicators of possible non-productive, gas or oil formational fluid. The data trends into the productive gas zone with a high slope from C1/C4 to C1/C5, which could indicate either dry gas or lack of permeability in zone. The fluid does appear to be related throughout the zone. Figure 7.B Discussion: This figure is used to determine if there are sub-zones to the main zone. At minimum, two zones are indicated with the upper zone having fewer indicators of liquid hydrocarbons and the bottom zone having increased indicators. Recycled gas may be influencing the results. Figure 7.C Discussion: The compositional ternary plot indicates whether a fluid is productive gas/liquid or non- productive hydrocarbon. The location of the data does indicate a liquid hydrocarbon may be present. The increasing trend towards C3 and nC4 is most likely due to recycled gas. Figure 7.D Discussion: This figure is used to determine if the formation fluid has experienced biodegradation based on iso/normal ratios and to determine if there are sub-zones in the main zone. The fluid has indications of biodegradation due to the data approaching 1. Normal hydrocarbons are consumed first in biodegradation with iso hydrocarbons experiencing less biodegradation. 25I GasFact End of Well Report Figure 8.A Ternary plot of Mass Spectroscopy sulfur dioxide (MS Sulfur_3) vs benzene (MS Soluble2) vs sulfur oxide (MS Sulfur_2). Figure 8.B Ternary plot of Mass Spectroscopy ethane vs propane vs the sum of butane, pentane and hexane. Figure 8.C Ternary plot of Mass Spectroscopy toluene (MS Soluble3) to benzene (MS Soluble2) to hexane. Figure 8.D Cross plot of Mass Spectroscopy hexane to benzene (MS Soluble2) vs hexane to toluene (MS Soluble3). A B C D 26I GasFact End of Well Report Figure 8.A Discussion: The examination of sulfur dioxide, sulfur oxide, and benzene is to determine if biodegradation has occurred and to help identify gas and liquid formational fluid. The plot indicates that biodegradation may have occurred in this zone and trends towards less biodegradation with depth as benzene is recycled. Figure 8.B Discussion: The figure is the mass spectroscopy equivalent of the compositional ternary plot. The zone has increased indicators for liquid hydrocarbons with depth, which is primarily contributed to recycled gas. Figure 8.C Discussion: The toluene, benzene and hexane ternary allows for the examination of the interaction between chemical species with varying affinities for aqueous and non-aqueous phases. The system is dominated by hexane with reducing hexane relative to benzene and toluene as recycled gas increases. This is indicative of moving away from a gas associated with a liquid. Figure 8.D Discussion: The figure is to determine if there are multiple formational fluids present or a gradation of formational fluids present. The zone appears to be a single zone with high indicators of liquid hydrocarbons. 27I GasFact End of Well Report Zone E: 6,610’– 6,620’ MD Zone E Discussion: The zone was analyzed due to indications of possible faulting with a fluid that was dominated by liquid hydrocarbon indicators. The small depth range of the zone indicates a brief geological event that could be faulting or a thin bed with high permeability with both options having a fluid with strong indications of liquid hydrocarbons present. 28I GasFact End of Well Report Figure 9.A Pixler Plot Figure 9.B Cross plot of Gas Chromatography propane to methane vs propane to ethane. Figure 9.C Compositional ternary plot using ethane, propane, and normal butane. Figure 9.D Cross plot of Gas Chromatography iso-pentane to normal pentane vs iso-butane to normal butane. A B C D 29I GasFact End of Well Report Figure 9.A Discussion: Pixler plots are used as initial indicators of possible non-productive, gas or oil formational fluid. The data indicates a possible producible gas for a very brief formation. This may be due to a fault or some other brief geological occurance. Figure 9.B Discussion: This figure is used to determine if there are sub-zones to the main zone. There is a single zone. Figure 9.C Discussion: The compositional ternary plot indicates whether a fluid is productive gas/liquid or non- productive hydrocarbon. The fluid has indications of possible liquid hydrocarbons. Figure 9.D Discussion: This figure is used to determine if the formation fluid has experienced biodegradation based on iso/normal ratios and to determine if there are sub-zones in the main zone. The zone has experienced biodegradation of fluid. 30I GasFact End of Well Report Figure 10.A Ternary plot of Mass Spectroscopy sulfur dioxide (MS Sulfur_3) vs benzene (MS Soluble2) vs sulfur oxide (MS Sulfur_2). Figure 10.B Ternary plot of Mass Spectroscopy ethane vs propane vs the sum of butane, pentane and hexane. Figure 10.C Ternary plot of Mass Spectroscopy toluene (MS Soluble3) to benzene (MS Soluble2) to hexane. Figure 10.D Cross plot of Mass Spectroscopy hexane to benzene (MS Soluble2) vs hexane to toluene (MS Soluble3). A B C D 31I GasFact End of Well Report Figure 10.A Discussion: The examination of sulfur dioxide, sulfur oxide, and benzene is to determine if biodegradation has occurred and to help identify gas and liquid formational fluid. The zone is dominated by benzene, which is significantly different than the zones above. Figure 10.B Discussion: The figure is the mass spectroscopy equivalent of the compositional ternary plot. The zone has greater indicators of liquid hydrocarbon than the other zones. Figure 10.C Discussion: The toluene, benzene and hexane ternary allows for the examination of the interaction between chemical species with varying affinities for aqueous and non-aqueous phases. The zone is dominated by liquid hydrocarbon indicators. Figure 10.D Discussion: The figure is to determine if there are multiple formational fluids present or a gradation of formational fluids present. Single zone present. 32I GasFact End of Well Report Any questions/comments or changes you would like to make to the logs and/or summary, Please do not hesitate to call or email. E-mail: Mathew.Rowe@Halliburton.com Office: 281-871-6127 Cell: 337-356-6594 Thank you for your business. Technical Report Title www.halliburton.com HO7736 © 2013 Halliburton. All Rights Reserved. Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. Formation Testing Analysis  Report    Client: Caelus Energy Alaska  Well: CT‐1  Field: Smith Bay  Rig: Arctic Fox  Country: USA    8 ½” Open Hole  (MWD run 0300)        Logging  February 2nd to 3rd, 2016  Formation &  Reservoir  Solutions (FRS)  Prepared by:  Franck Michel    Reviewed by:  Jerry House      Date:  Version 2, February 9th, 2016  Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 2 Table of Contents Table of Contents ............................................................................................................................ 2  Overview ......................................................................................................................................... 4  Log Header ...................................................................................................................................... 7  Tool String Diagram ....................................................................................................................... 8  Units and Parameters .................................................................................................................... 10  Test Summary ............................................................................................................................... 11  Plots............................................................................................................................................... 13  Test No. 1.0; MD: 5666.94 ft; TVD: 5540.20 ft _ Pressure / Time plot .................................. 13  Test No. 2.0; MD: 5669.88 ft; TVD: 5543.14 ft _ Pressure / Time plot .................................. 14  Test No. 2.1; MD: 5669.88 ft; TVD: 5543.14 ft _ Exact Pressure / Time plot ........................ 15  Test No. 3.0; MD: 5664.72 ft; TVD: 5537.98 ft _ Pressure / Time plot .................................. 16  Test No. 3.1; MD: 5664.72 ft; TVD: 5537.98 ft _ Exact Pressure / Time plot ........................ 17  Test No. 4.0; MD: 5940.45 ft; TVD: 5813.70 ft _ Pressure / Time plot .................................. 18  Test No. 5.0; MD: 5939.79 ft; TVD: 5813.04 ft _ Pressure / Time plot .................................. 19  Test No. 6.0; MD: 5766.03 ft; TVD: 5639.29 ft _ Pressure / Time plot .................................. 20  Test No. 7.0; MD: 5766.44 ft; TVD: 5639.70 ft _ Pressure / Time plot .................................. 21  Test No. 8.0; MD: 6436.83 ft; TVD: 6310.07 ft _ Pressure / Time plot .................................. 22  Test No. 9.0; MD: 6435.31 ft; TVD: 6308.56 ft _ Pressure / Time plot .................................. 23  Test No. 10.0; MD: 6386.34 ft; TVD: 6259.59 ft _ Pressure / Time plot ................................ 24  Test No. 10.1; MD: 6386.34 ft; TVD: 6259.59 ft _ Exact Pressure / Time plot ...................... 25  Test No. 11.0; MD: 6385.88 ft; TVD: 6259.13 ft _ Pressure / Time plot ................................ 26  Test No. 11.1; MD: 6385.88 ft; TVD: 6259.13 ft _ Exact Pressure / Time plot ...................... 27  Test No. 12.0; MD: 6386.93 ft; TVD: 6260.17 ft _ Pressure / Time plot ................................ 28  Test No. 12.1; MD: 6386.93 ft; TVD: 6260.17 ft _ Exact Pressure / Time plot ...................... 29  Appendix A – Field FTWD Data Sheet (Real-time results) ......................................................... 30  Disclaimer ..................................................................................................................................... 31  Drawdown Buildup Analysis ........................................................................................................ 32  Exact Mobility Analysis ........................................................................................................... 32  Test Quality Parameters ............................................................................................................ 34  Automatic Test Comments ....................................................................................................... 35  Dual Probe Anisotropy Analysis (Vertical Interference Testing) ............................................. 36  Anisotropy Dip-angle Corrections ........................................................................................ 36  Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 3 Flow Rate Determination .......................................................................................................... 37  Automatic Flow Rate Option ................................................................................................ 37  Manual Flow Rate Option ..................................................................................................... 37  Manual Volume Option ........................................................................................................ 37  RTS Mobility Drawdown and Buildup Calculation Summary ................................................. 38  Table 1 PTA Spherical Flow Regime Calculations (Typical Physical Units) ..................... 38  Table 2 PTA Radial Flow Regime Calculations (Typical Physical Units) ........................... 38  Table 3 PTA Variables & Constants Using Internal Program (Typical Physical Units) ..... 39  Table 4 PTA Spherical Flow Regime Calculations (SI Units) ............................................. 40  Table 5 PTA Radial Flow Regime Calculations (SI Units) .................................................. 40  Table 6 PTA Variables & Constants Using Internal Program SI Units ................................ 41  RTS Theory References ............................................................................................................ 42  Basic Tool Theory......................................................................................................................... 45  Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 4 Overview At the request of Caelus Energy Alaska, the GeoTap IDS tool was run in the CT-1 well, Smith Bay field, USA in a 8 ½” hole for formation pressures, establishes gradients in various formations and collect formation fluid samples. The pressure transient analysis is presented in the report. For each test, the first plot shows the whole test from the beginning when the pad is set against the borehole wall to the retraction of the pad upon completion of the test. The second plot shows a zoomed-in view of the sub-test that was selected for determination of pressure and mobility (when applicable), which normally is the last sub-test of a pre-test. The FTWD test depth reported in this report for each test is referenced to the drilling LWD log. Log correlation passes were performed to adjust the depth to the drilling log prior to positioning the GeoTap IDS probe at a requested station. Each pre-test was performed with a drawdown rate of either 1 or 0.5 cc/sec for a volume of 10 cc for each sub-test, followed by a variable buildup time up to 224 sec. The drawdown volumes were confirmed with Halliburton’s Reservoir Testing Studio (RTS) application after having selected the beginning and end of the pre-test intervals. During the GeoTap IDS run (MWD Run 0300), 12 pad sets were attempted. The pre- tests’ classification is as follows.  9 ‘Dry/Tight Test’  3 ‘Unstable Buildup’ Surface communication with the GeoTap IDS was enabled by “downlinking”; commands were transmitted in the drill-pipe mud from the Geospan rig floor skid system. Real-time test data was sent by mud Pulse Modulation protocol. GeoTap IDS real-time test results collected at the well-site in the ‘FTWD Data Sheet’ table are presented in this report in Appendix A. Transient analysis was performed on all the drawdowns of each test during the data analysis. In this report the transient analysis is only presented for the best-quality drawdown of each pre-test. The results presented are using high resolution memory data (5 data points per second). Mobility values are calculated for the build-up assuming a spherical flow model. Those results are presented in the table at the base of each transient graph (Mexact) and in the Pressure Transient Analysis Summary. Note that compressibility (Ct) figures shown in the table below the transient graphs are not used in the drawdown or build-up mobility calculations. Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 5 Only one pumpout was initiated which took place following the pre-test #10. Pump rate was established at 0.5 cc/sec. Fluid density readings indicated only mud filtrate. Although the pump out rate was set at 0.5 cc/sec, the rate at which fluid moved was much slower. The pump drew pressure down to almost atmospheric pressure and it appears that gas was being broken out due to this low pressure. No formation fluid sample was collected during this pump out. Pumpout real-time monitoring data Pumpout memory data Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 6 The following pictures are of the GeoTap IDS pad post-run 0300. Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 7 Log Header Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 8 Tool String Diagram MWD run 0300, BHA components: MWD run 0300, GeoTap IDS Tool Information: Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 9 Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 10 Units and Parameters The following units and parameters were used. Units: Length ft and in Pressure psia Temperature degree F Mud Weight ppg Volume cc Rate cc/sec Parameters applicable to 6 ¾” GeoTap IDS tool size: Snorkel radius 0.596 inches Flowline Volume 46 - 51 cc (for pretest) Test Summary PRESSURE TEST SUMMARY Test Identification Hydrostatic Pres. Eq. Mud Wt. Test Pressures - Temperatures Test Times Remarks Test No. File No. MD (ft) TVD (ft) Phyds1 (psia) Phyds2 (psia) EqFmMw (lbs/gal) EqBhMw (lbs/gal) Psdd (psia) Pedd (psia) Pstop (psia) dPob (psia) Temp (degF) dTdd (sec) dTbu (sec) 1.0 320-1.0 5666.94 5540.20 2984.47 2984.44 10.36 Dry/Tight Test 2.0 320-2.0 5669.88 5543.14 2982.16 2983.00 10.20 10.35 Dry/Tight Test 2.1 320-2.1 5669.88 5543.14 2982.16 2983.00 10.20 10.35 2893.44 91.92 2939.50 43.50 121.86 10.20 473.80 Dry/Tight Test 3.0 320-3.0 5664.72 5537.98 2973.15 2972.38 10.17 10.32 Unstable Buildup 3.1 320-3.1 5664.72 5537.98 2973.15 2972.38 10.17 10.32 2876.12 100.61 2927.61 44.77 120.68 20.20 1081.60 Unstable Buildup 4.0 320-4.0 5940.45 5813.70 3081.96 3081.83 10.19 Dry/Tight Test 5.0 320-5.0 5939.79 5813.04 3083.37 3083.59 10.20 Dry/Tight Test 6.0 320-6.0 5766.03 5639.29 2999.70 2991.15 10.20 Dry/Tight Test 7.0 320-7.0 5766.44 5639.70 2983.01 2982.79 10.17 Dry/Tight Test 8.0 320-8.0 6436.83 6310.07 3356.57 3356.50 10.23 Dry/Tight Test 9.0 320-9.0 6435.31 6308.56 3356.50 3356.32 10.23 Dry/Tight Test 10.0 320-10.0 6386.34 6259.58 3332.86 3333.03 9.76 10.24 Dry/Tight Test 10.1 320-10.1 6386.34 6259.58 3332.86 3333.03 9.89 10.24 2632.62 114.60 3219.93 113.10 125.95 20.42 1207.57 Dry/Tight Test 11.0 320-11.0 6385.88 6259.13 3328.50 3331.17 9.31 10.23 Unstable Buildup 11.1 320-11.1 6385.88 6259.13 3328.50 3331.17 9.77 10.23 2341.61 136.68 3178.65 152.51 125.76 20.00 575.90 Unstable Buildup 12.0 320-12.0 6386.93 6260.17 3330.75 3332.22 8.08 10.24 Unstable Buildup 12.1 320-12.1 6386.93 6260.17 3330.75 3332.22 9.77 10.24 1003.96 95.23 3180.09 152.13 125.58 20.00 700.60 Unstable Buildup Legend: Phyds1: Initial Hydrostatic Pressure Phyds2: Final Hydrostatic Pressure EqFmMw:Equivalent Formation Mud Weight (Pstop / (TVD * Constant)) EqBhMw: Equivalent Borehole Mud Weight (Phyds2 / (TVD * Constant)) Psdd: Initial Drawdown Pressure Pedd: Final Drawdown or End Drawdown Pressure Pstop: Final Buildup Pressure Temp: Final Temperature dTdd= Tedd-Tsdd: Tedd - End of Drawdown Time; Tsdd - Initial Drawdown Time dTbu=Tstop - Tedd:Buildup Time, Tedd - End of Drawdown Time, Tstop - Final Buildup Time dPob= Phyds2 - Pstop: Over Balance Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 12 PRESSURE TRANSIENT SUMMARY Test Identification Buildup Stability PTA Pressure PTA Mobilities Remarks Test No. File No. MD (ft) TVD (ft) Pumps (on/off) Exposure (min) Stability (psia/min) Stability (degF/min) Pexact (psia) Pstdev (psia) Mexact (md/cp) Msdd (md/cp) 1.0 320-1.0 5666.94 5540.20 Dry/Tight Test 2.0 320-2.0 5669.88 5543.14 Dry/Tight Test 2.1 320-2.1 5669.88 5543.14 On 657.36 23.519 -0.003 2939.66 27.43 0.128 0.678 Dry/Tight Test 3.0 320-3.0 5664.72 5537.98 Unstable Buildup 3.1 320-3.1 5664.72 5537.98 On 748.98 11.326 -0.036 2927.61 5.55 0.093 0.355 Unstable Buildup 4.0 320-4.0 5940.45 5813.70 Dry/Tight Test 5.0 320-5.0 5939.79 5813.04 Dry/Tight Test 6.0 320-6.0 5766.03 5639.29 Dry/Tight Test 7.0 320-7.0 5766.44 5639.70 Dry/Tight Test 8.0 320-8.0 6436.83 6310.07 Dry/Tight Test 9.0 320-9.0 6435.31 6308.56 Dry/Tight Test 10.0 320-10.0 6386.34 6259.58 Dry/Tight Test 10.1 320-10.1 6386.34 6259.58 On 585.59 4.008 -0.049 3223.18 131.04 0.034 0.310 Dry/Tight Test 11.0 320-11.0 6385.88 6259.13 Unstable Buildup 11.1 320-11.1 6385.88 6259.13 On 694.15 20.973 -0.047 3341.21 644.85 0.030 0.321 Unstable Buildup 12.0 320-12.0 6386.93 6260.17 Unstable Buildup 12.1 320-12.1 6386.93 6260.17 On 725.24 17.028 -0.038 3400.98 837.37 0.023 0.326 Unstable Buildup Legend: Pexact: Projected formation pressure based on exact model. Pstdev: Standard deviation of actual pressures from exact model Mexact: Spherical Mobility based on exact model Msdd: Spherical Drawdown Mobility Plots Test No. 1.0; MD: 5666.94 ft; TVD: 5540.20 ft _ Pressure / Time plot GeoTap Pretest File # 320-1.0 Date: 02-Feb-16 01:06:45 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 5666.94 2984.47 2984.44 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 0.00 0.00 0.60 0.15 2.80e-008 46.00 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 14 Test No. 2.0; MD: 5669.88 ft; TVD: 5543.14 ft _ Pressure / Time plot GeoTap Pretest File # 320-2.0 Date: 02-Feb-16 01:40:40 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 5669.88 2982.16 2983.00 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.57 0.87 0.60 0.15 1.40e-005 46.00 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 15 Test No. 2.1; MD: 5669.88 ft; TVD: 5543.14 ft _ Exact Pressure / Time plot GeoTap Pretest File # 320-2.1 Date: 02-Feb-16 01:40:40 EXACT PRESSURE / TIME PLOT SUMMARY MD (ft) TVD (ft) Pedd (psia) Pstop (psia) Pexact (psia) Mexact(md/cp) 5669.88 5543.14 91.92 2939.50 2939.66 0.128 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.36 0.92 0.60 0.15 7.61e-006 46.00 TEST CONDITIONS & STATUS +/- stdev (psia) Stability (psia/min) Stability (degF/min) Pump Status Exposure Time (min). Tool Face (deg). 27.43 23.52 -0.00 On 657.36 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 16 Test No. 3.0; MD: 5664.72 ft; TVD: 5537.98 ft _ Pressure / Time plot GeoTap Pretest File # 320-3.0 Date: 02-Feb-16 03:06:02 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 5664.72 2973.15 2972.38 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.34 0.46 0.60 0.15 1.02e-005 46.00 REMARKS Unstable Buildup Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 17 Test No. 3.1; MD: 5664.72 ft; TVD: 5537.98 ft _ Exact Pressure / Time plot GeoTap Pretest File # 320-3.1 Date: 02-Feb-16 03:06:02 EXACT PRESSURE / TIME PLOT SUMMARY MD (ft) TVD (ft) Pedd (psia) Pstop (psia) Pexact (psia) Mexact(md/cp) 5664.72 5537.98 100.61 2927.61 2927.61 0.093 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.65 0.48 0.60 0.15 5.55e-006 46.00 TEST CONDITIONS & STATUS +/- stdev (psia) Stability (psia/min) Stability (degF/min) Pump Status Exposure Time (min). Tool Face (deg). 5.55 11.33 -0.04 On 748.98 REMARKS Unstable Buildup Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 18 Test No. 4.0; MD: 5940.45 ft; TVD: 5813.70 ft _ Pressure / Time plot GeoTap Pretest File # 320-4.0 Date: 02-Feb-16 15:03:55 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 5940.45 3081.96 3081.83 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.25 0.45 0.60 0.15 9.49e-006 46.00 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 19 Test No. 5.0; MD: 5939.79 ft; TVD: 5813.04 ft _ Pressure / Time plot GeoTap Pretest File # 320-5.0 Date: 02-Feb-16 15:33:34 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 5939.79 3083.37 3083.59 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.67 0.45 0.60 0.15 1.18e-005 46.00 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 20 Test No. 6.0; MD: 5766.03 ft; TVD: 5639.29 ft _ Pressure / Time plot GeoTap Pretest File # 320-6.0 Date: 02-Feb-16 16:36:19 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 5766.03 2999.70 2991.15 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.46 0.40 0.60 0.15 1.02e-005 46.00 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 21 Test No. 7.0; MD: 5766.44 ft; TVD: 5639.70 ft _ Pressure / Time plot GeoTap Pretest File # 320-7.0 Date: 02-Feb-16 16:57:25 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 5766.44 2983.01 2982.79 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.85 0.43 0.60 0.15 1.24e-005 46.00 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 22 Test No. 8.0; MD: 6436.83 ft; TVD: 6310.07 ft _ Pressure / Time plot GeoTap Pretest File # 320-8.0 Date: 03-Feb-16 04:14:48 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 6436.83 3356.57 3356.50 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.20 0.47 0.60 0.15 1.08e-005 46.00 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 23 Test No. 9.0; MD: 6435.31 ft; TVD: 6308.56 ft _ Pressure / Time plot GeoTap Pretest File # 320-9.0 Date: 03-Feb-16 04:40:36 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 6435.31 3356.50 3356.32 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.47 0.47 0.60 0.15 1.09e-005 46.00 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 24 Test No. 10.0; MD: 6386.34 ft; TVD: 6259.59 ft _ Pressure / Time plot GeoTap Pretest File # 320-10.0 Date: 03-Feb-16 05:29:31 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 6386.34 3332.86 3333.03 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.35 0.43 0.60 0.15 1.15e-005 46.00 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 25 Test No. 10.1; MD: 6386.34 ft; TVD: 6259.59 ft _ Exact Pressure / Time plot GeoTap Pretest File # 320-10.1 Date: 03-Feb-16 05:29:31 EXACT PRESSURE / TIME PLOT SUMMARY MD (ft) TVD (ft) Pedd (psia) Pstop (psia) Pexact (psia) Mexact(md/cp) 6386.34 6259.59 114.60 3219.93 3223.18 0.034 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.35 0.46 0.60 0.15 8.34e-006 46.00 TEST CONDITIONS & STATUS +/- stdev (psia) Stability (psia/min) Stability (degF/min) Pump Status Exposure Time (min). Tool Face (deg). 131.04 4.01 -0.05 On 585.59 REMARKS Dry/Tight Test Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 26 Test No. 11.0; MD: 6385.88 ft; TVD: 6259.13 ft _ Pressure / Time plot GeoTap Pretest File # 320-11.0 Date: 03-Feb-16 07:17:45 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 6385.88 3328.50 3331.17 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.24 0.46 0.60 0.15 9.08e-006 46.00 REMARKS Unstable Buildup Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 27 Test No. 11.1; MD: 6385.88 ft; TVD: 6259.13 ft _ Exact Pressure / Time plot GeoTap Pretest File # 320-11.1 Date: 03-Feb-16 07:17:45 EXACT PRESSURE / TIME PLOT SUMMARY MD (ft) TVD (ft) Pedd (psia) Pstop (psia) Pexact (psia) Mexact(md/cp) 6385.88 6259.13 136.68 3178.65 3341.21 0.030 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.28 0.46 0.60 0.15 1.03e-005 46.00 TEST CONDITIONS & STATUS +/- stdev (psia) Stability (psia/min) Stability (degF/min) Pump Status Exposure Time (min). Tool Face (deg). 644.85 20.97 -0.05 On 694.15 REMARKS Unstable Buildup Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 28 Test No. 12.0; MD: 6386.93 ft; TVD: 6260.17 ft _ Pressure / Time plot GeoTap Pretest File # 320-12.0 Date: 03-Feb-16 07:49:34 PRESSURE/TIME PLOT SUMMARY Depth Hydrostatic Pretest Pressures Pretest Times Mobility MD (ft) Phyds1 (psia) Phyds2 (psia) Psdd (psia) Pedd (psia) Pstop (psia) Tsdd (sec) Tedd (sec) Tstop (sec) Mdd (md/cp) 6386.93 3330.75 3332.22 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.80 0.40 0.60 0.15 9.44e-006 46.00 REMARKS Unstable Buildup Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 29 Test No. 12.1; MD: 6386.93 ft; TVD: 6260.17 ft _ Exact Pressure / Time plot GeoTap Pretest File # 320-12.1 Date: 03-Feb-16 07:49:34 EXACT PRESSURE / TIME PLOT SUMMARY MD (ft) TVD (ft) Pedd (psia) Pstop (psia) Pexact (psia) Mexact(md/cp) 6386.93 6260.17 95.23 3180.09 3400.98 0.023 CONSTANTS - SPHERICAL FLOW Volume (cc) Rate (cc/sec). Rsnorkel (in) Porosity (fraction) Ct (1/psia) Flow-line Storage (cc) 9.56 0.48 0.60 0.15 3.21e-005 46.00 TEST CONDITIONS & STATUS +/- stdev (psia) Stability (psia/min) Stability (degF/min) Pump Status Exposure Time (min). Tool Face (deg). 837.37 17.03 -0.04 On 725.24 REMARKS Unstable Buildup Appendix A – Field FTWD Data Sheet (Real-time results) MWD Run 0300 Disclaimer DATA, RECOMMENDATIONS, INTERPRETATIONS LIMITATIONS Because of the uncertainty of variable well conditions the necessity of relying on facts and supporting services furnished by others, Halliburton IS UNABLE TO GUARANTEE THE EFFECTIVENESS OF THE PRODUCTS, SUPPLIES OR MATERIALS, NOR THE RESULTS OF ANY TREATMENT OR SERVICE, NOR THE ACCURACY OF ANY CHART INTERPRETATION, RESEARCH ANALYSIS, JOB RECOMMENDATION OR OTHER DATA FURNISHED BY Halliburton. Halliburton personnel will use their best efforts in gathering such information and their best judgment in interpreting it, but Customer agrees that Halliburton shall not be liable for and Customer SHALL RELEASE, DEFEND AND INDEMNIFY Halliburton against any damages or liability arising from the use of such information even if such damages are contributed to or caused by the negligence, fault or strict liability of Halliburton. Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 32 Drawdown Buildup Analysis During the pretest a small amount of fluid is withdrawn from the formation through the snorkel and into the tool at a known rate. This causes the pressure pulse called a pretest drawdown. The combination off low rate and snorkel D determines an effective range of operation. The maximum drawdown pressure pulse can be determined from the well-known spherical flow equation where Pdd is the final drawdown pressure differential at time t=.       fp pdd dd kr q = P  2696,14 Where: Pdd ............................................................................. drawdown differential pressure (psi) qo .............................................................................................. drawdown flow rate (cc/sec) ks ................................................................................ formation spherical permeability(md)  ....................................................................................................................... viscosity (cp) rp ................................................................................................................ probe radius(cm) p .................................................................................... probe flow coefficient (1.37to0.95) With a 0.10cc/sec to 1.5cc/sec drawdown flow rate and a 1.0cm probe employed, it is possible to test formations ranging from 1000 to 0.5 md with pressure differentials ranging from 2 to 5000 psi. Exact Mobility Analysis By analyzing the drawdown curve and the build-up curve it is possible to calculate the mobility of the formation. The mobility is defined as the permeability divided by the viscosity (md/cp). Therefore if the viscosity of the fluid being drawn is known, it is also possible to determine the formation permeability. The fluid being drawn into the pretest is normally assumed to be the mud filtrate so if the mud type is known it is possible to estimate the filtrate viscosity. The two methods of determining the mobility are shown by the two equations below. First is the drawdown mobility Mdd that uses the drawdown pressure differential (i.e.,Pdd=Pstop-Pdd_end) and is the most common method used in the industry. It is normally referred to as the steady-state spherical method. The second is the exact spherical mobility Mexact that typically uses the buildup curve. A simplified form of the exact method is shown in Figure-1 which is an exponential with a magnitude of  (pressure, psi) and a time constant of (sec). Both the drawdown and buildup curves can be analyzed but normally the buildup is used. The curve fit parameters alpha  and beta  are used to determine the mobility. Generally these Mdd and Mexact are very similar except in low mobility zones where the mobility is < 1 md/cp. In this case the Exact method yields the most accurate estimate of Mobility. Mdd=            p p dd o rP q  2 696,14 Drawdown spherical mobility (md/cp) Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 33 Mexact=                pt p po er q 12 696,14 Exact spherical mobility (md/cp) Where: tp ................................................................. draw down production time(tdd_end-tdd_start ,sec)  ...................................................................................... Exact curve fit time constant (sec)  ................................................................................ Exact curve fit build up constant (psi) Pressure (psi)Time (sec)tstop Q tdd_end tdd TPdd_end t = T – tdd_end tdd_start  t fbu eP(t)P  * Pdd_start Pdd=Pstop-Pdd_end Pstop Phyds Fig–1 Buildup function where formation pressure (Pf*), Alpha ( ) and beta () are determined from the Exact curve fit and Pf* is normally reported a PExaxt. Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 34 Test Quality Parameters There are two different measurements of test quality. The first is called the sigma which is a measure of how closely the data conforms to the Exact model and is reported in ± pressure units (normally psi). The sigma is determined by calculating the standard deviation of the data from the theoretical curve as follows.  )1( )()(p)( 2   n iPi=P bu bu ........... standard deviation ± pressure units (normally psi) Where: Pbu ........................................................... buildup pressure from Exact curve fit (see Fig. 1) p(i) ............................................................................................. measured buildup pressures i ............................................................................................................... index of data point n .................................................................................. total number of pressure points used The second method of measuring the test quality is the pressure and temperature stability. The “Pressure Stability” and “Temperature Stability are determined using a linear regression over the time period specified (i.e., default of 30 sec) and reported for each selected stop pressure. The stability can be either positive or negative. The stability period can be modified if desired in RTS. The source data for this derivative is the pressure gauge selected by the engineer for formation pressure which is normally the Quartz gauge closest to the probe. There are some exceptions to the stability period during buildups which are outlined below. 1. Start of buildup continue stability calculation until the buildup time reaches the stability period (i.e., 30 default). 2. Reset stability period to 1/3 of the buildup time (10 seconds default). 3. As the buildup progresses increase the stability period using 1/3 of the buildup time until the specified stability time is reached (30 sec default). Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 35 Automatic Test Comments Automatic test comments are generated based on the sigma quality parameter and the logic below. Test are classified by types and are normally Type A, B, C, and D. Any test that is not Type A, B, C or D is type F. The logic below determines the test type automatically but as explained below the RTS analysis can always override these comments and classify the tests as he sees fit. If Abs(Pstop - Phyd2) < 50 psi: “Potential Mud set” elseif Pstop < 1000 psi and alpha > 30 sec: “Dry/Tight test” elseif Pstop < 750 psi, “Dry/Tight test” elseif sigma <= 0.1: “Excellent Buildup Stability” (Type A) elseif sigma <= 1.0: “Good Buildup Stability” (Type B) elseif sigma <= 10.0: “Fair Buildup Stability” (Type C) elseif sigma > 10.00 and beta > 500 and alpha > 30: “Low Perm, still building” else: “Unstable Buildup (Type D)” The RTS analysts can override these comments based on his discretion, but if the key words Excellent, Good, Fair or Unstable are used the test comments the type associated with these key words used to apply the test type. The color coding to the test types are as follows. Type A Green Type B Orange Type C Pink Type D Red Type F Black Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 36 Dual Probe Anisotropy Analysis (Vertical Interference Testing) When one of the probes is isolated it may be possible to determine the horizontal permeability and anisotropy from the isolated (observation) probe that is spaced at a vertical distance from the source probe (lv) Mh_exact=       v pt v vo v el Q  12 1696,14 Exact Horizontal Mobility (md/cp) 3 _ _      exacth exacts exacth v exact M M k k Exact anisotropy Anisotropy Dip-angle Corrections The calculation for anisotropy assumes the bedding plane is oriented relative to the borehole. The correction chart shown below can be used to find the anisotropy when the relative dip angle is known. Entering the chart from the left hand side with the real-time anisotropy and following one of the lines to the right determines the correction with increasing dip-angle. For example, using a real-time anisotropy of 10 and with a dip-angle of 700 the corrected anisotropy is slightly less than 0.1. This would be the case of a nearly horizontal well. Notice that as the dip-angle approaches 450 the lines converge. This means that measurements taken close to a 450 dip-angle are not very sensitive to anisotropy. 0.00001 0.0001 0.001 0.01 0.1 1 10 100 1000 0 102030405060708090 Dip Angle (deg)Anisotropy (kv/kh)300 100 30 10 1 0.1 0.01 0.001 0.0001 0.00001 Real-Time Anisotropy Fig. 2 Anisotropy Dip-angle Correction Chart. Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 37 Flow Rate Determination There are three methods of determining the drawdown (and pumping) flow rates which can be selected in the Job Parameters. In the newer tools the flow rate is measured and the “Automatic Method” is the preferred default. In older tools the flow rate or test volume can be specified but the values must be entered manually. With any of these three options it is rare that the volumes and rates exactly match that specified by the engineer since there is variability in the actual execution of a pretest and the rates and volume in RTS are determined from actual events and measured data. Automatic Flow Rate Option The automatic flow rate option determines rate from the measured rate curve(s) directly. For pretesting the averaged rate between the selected starting and ending times of the drawdown is used (i.e., Tstard_dd and Tend_dd). It is possible to select a Tend_dd that may not fall within the drawdown period and still estimate the mobility using the averaged rate for the drawdown period chosen. When this happens the simulated drawdown curve is turned off. For both pumping and pretesting the rate should be determined from the active rate curves. Since some tools like the RDT can have more than one pretest module or pump the total average from all the rate curves are used to for the “Automatic Rate” calculation. Then the volume for the drawdown is determined by using this averaged rate times the drawdown time (i.e., AvgRate/(Tend_dd-Tstart_dd)). However, the time used to average should not exceed 30 minutes which would apply to pumpouts or miniDST testing and it is desirable to determine the rate just prior to the buildup. In this case the averaged rate would be from Tdd-30 minutes to Tdd. Also, rates less than 0.02 cc/sec from Meas PT Rate are filtered out (set to 0 values) and rates less than 0.1 cc/sec for Pump Rates are set to 0 before averaging. Manual Flow Rate Option With this option selection in the Job Parameters the rate is fixed to the value entered. The volume of the pretest is determined by multiplying this rate time the drawdown time period selected (i.e., Tstard_dd and Tend_dd). Manual Volume Option With this option selection in the Job Parameters the volume is fixed to the value entered. The rate of the pretest is determined by dividing this volume by the drawdown time period selected (i.e., Tstard_dd and Tend_dd). Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 38 RTS Mobility Drawdown and Buildup Calculation Summary Table 1 PTA Spherical Flow Regime Calculations (Typical Physical Units) Mdd=         p p dd o rP q  2 696,14 ........................................ Drawdown Mobility, Pressure/Time Plot (md/cp) Ms_exact=               pt p po er Q 12 696,14 ........................... Exact Mobility, Pressure/Time Plot (md/cp) Mloglog= 5.1 1 5.2 5.1 4 696,14            dt dpt cV fo  ....................................... FasTest Mobility, Log-Log Plot (md/cp) Mfast= 5.1 1 5.1 4 696,14          fast fo m cV  ............................................. FasTest Mobility, FasTest Plot (md/cp) Msphere= 5.1 1 4 696,14          sphere fo m cq  .................................................. Spherical Mobility, FastPlot (md/cp) Table 2 PTA Radial Flow Regime Calculations (Typical Physical Units) Mdd=                  p wf o dd dd o t rc q hPLambertWhP q 2 4 696,14   ...................... Drawdown Mobility (md/cp) Mloglog=               dt dpth V eLog o 2)(4 696,14  ................................................ FasTest Mobility, Log-Log Plot (md) Mfast=         fast o mh V eLog)(4 696,14  .......................................................... FasTest Mobility, FasTest Plot (md) Mradial=            radial o mh q eLog)(4 696,14  ................................................................ Radial Mobility, FastPlot (md) Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 39 Table 3 PTA Variables & Constants Using Internal Program (Typical Physical Units) qo ................................................................................................................. drawdown flow rate (cc/sec) Vo ........................................................................................................................... drawdown volume(cc) Vs ................................................................................................................................ storage volume(cc)  ................................................................................................................................................... porosity  ........................................................................................................................................... viscosity(cp) cf ..................................................................................................................... fluid compressibility(1/psi) Pdd .................................................................................................. drawdown differential pressure(psi) p ........................................................................................................ prove flow coefficient (1.37to0.95) rp .................................................................................................................................... probe radius(cm) rw .............................................................................................................................. wellbore radius(cm) h ..................................................................................................................................... zone height (cm) T .............................................................................................................................. actual testtime(T,sec) t ..................................................................................................... shut in or buildup time ((tdd_end-T,sec) t’ ......................................................................................... production or drawdown time (tdd_start-T,sec) tp ..................................................................... production or drawdown time period (tdd_end-tdd_start,sec) dp/dt ................................................................................. Log-Log Plot buildup time derivative(psi/sec) mfast .............................................................................................................................. FasTest Plot slope msphere ........................................................................................................................ Spherical Plot slope mradial ............................................................................................................................. Radial Plot slope  ................................................................................................................ Exact Plot time constant (sec)  .................................................................................................................. Exact curve fit constant (psi)  ............................................................................................................................ Eulier’sconstant (1.78) Log(e) ........................................................................................ logbase10conversionconstant (0.43429) Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 40 Table 4 PTA Spherical Flow Regime Calculations (SI Units) Mdd=         p p dd o rP q  2 1013 ........................................... Drawdown Mobility, Pressure/Time Plot (md/cp) Ms_exact=               pt p po er Q 12 1013 .............................. Exact Mobility, Pressure/Time Plot (md/cp) Mloglog= 5.1 1 5.2 5.1 4 1013            dt dpt cV fo ........................................... FasTest Mobility, Log-Log Plot (md/cp) Mfast= 5.1 1 5.1 4 1013          fast fo m cV  ................................................. FasTest Mobility ,FasTest Plot (md/cp) Msphere= 5.1 1 4 1013          sphere fo m cq  ...................................................... Spherical Mobility, FastPlot (md/cp) Table 5 PTA Radial Flow Regime Calculations (SI Units) Mdd=                 p wf o dd dd o t rc q hPLambertWhP q 2 4 1013   ......................... Draw down Mobility (md/cp) Mloglog=            dt dpth Vo 24 1013  .......................................................... FasTest Mobility, Log-Log Plot (md) Mfast=        fast o mh V 4 1013 ................................................................... FasTest Mobility, FasTest Plot (md) Mradial=         radial o mh q eLog)(4 1013  ........................................................... Radial Mobility, FastPlot (md) Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 41 Table 6 PTA Variables & Constants Using Internal Program SI Units qo ................................................................................................................. drawdown flow rate(m2/sec) Vo .......................................................................................................................... drawdown volume(m2) Vs ............................................................................................................................... storage volume(m2)  ................................................................................................................................................... porosity  ................................................................................................................................. viscosity (cp, Pa-s) cf ..................................................................................................................... fluid compressibility(1/Pa) Pdd .................................................................................................. drawdown differential pressure(Pa) p ........................................................................................................ prove flow coefficient (1.37to0.95) rp ...................................................................................................................................... probe radius(m) rw ................................................................................................................................ wellbore radius(m) h ....................................................................................................................................... zone height (m) T ............................................................................................................................ actual test time (T,sec) t ....................................................................................................... shutin or buildup time((tdd_end-T,sec) t’ .......................................................................................... production or drawdown time(tdd_start-T,sec) tp ...................................................................... production or drawdown time period(tdd_end-tdd_start,sec) dp/dt ................................................................................. Log-Log Plot buildup time derivative(Pa/sec) mfast .............................................................................................................................. FasTest Plot slope msphere ........................................................................................................................ Spherical Plot slope mradial ............................................................................................................................. Radial Plot slope  ................................................................................................................ Exact Plot time constant (sec)  .................................................................................................................. Exact curve fit constant (Pa)  ........................................................................................................................... Eulier’s constant (1.78) Log(e) ..................................................................................... logbase 10 conversion constant (0.43429) Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 42 RTS Theory References An Integrated Approach to Reservoir Connectivity and Fluid Contact Estimates by Applying Statistical Analysis Methods to Pressure Gradients, SPWLA 2007_HH paper presented at the 48th Annual Logging Symposium, June 3 - 6, 2007 , Austin, Texas. Formation Pressure Testing in the Dynamic Drilling Environment, SPE 112816 presentation was an SPE Distinguished Lecture during 2006-2007. Formation Testing and Sampling Using an Oval Pad in Al Hamd Field, Egypt, SPE 102366 presented at the SPE Annual Technical Conference and Exhibition, 24-27 September 2006, San Antonio, Texas, USA. Formation Tester While Drilling Experience in Caspian Development Projects, SPE 96719 paper presented at the SPE Annual Technical Conference and Exhibition, 9-12 October 2005, Dallas, Texas. Experience Using the First Commercial Pad and Probe Style Formation Tester While Drilling Service Has Led To Value Creation at the Valhall Flank Development, SPE 92712 paper presented at the SPE/IADC Drilling Conference, 23-25 February 2005, Amsterdam, Netherlands The Influence of Water-Base Mud Properties and Petrophysical Parameters on Mudcake Growth, Filtrate Invasion, and Formation Pressure, Petrophysics Volume 46, Number 1, January - February, 2005. Formation Tester Immiscible and Miscible Flow Modeling for Job Planning Applications, SPWLA 2005-L paper presented at the SPWLA 46th Annual Logging Symposium, 2005 Results of Laboratory Experiments to Simulate the Downhole Environment of Formation Testing While Drilling. SPWLA 2005R paper was presented at the SPWLA 45th Annual Logging Symposium held in Noordwijk, The Netherlands, June 6–9, 2004. Formation Testing In The Dynamic Drilling Environment, SPWLA 2005N paper was presented at the SPWLA 45th Annual Logging Symposium held in Noordwijk, The Netherlands, June 6–9, 2004. Formation Pressure Testing In the Dynamic Drilling Environment. SPE 87090 was presentated at the IADC/SPE Drilling Conference held in Dallas, Texas, U.S.A., 2–4 March 2004. Formation Testing While Drilling, a New Era in Formation Testing. SPE 84087 was presentated at the 2003 SPE Annual Technical Conference and Exhibition held in Denver, Colorado, USA, 5-8 October 2003. Formation Testing While Drilling, a New Technique for Acquiring Pressure Data, Paper presented at the SPE Nigerian Annual International Conference and Exhibition 4-8 August 2003. A New Inversion Technique Determines In-Situ Relative Permeabilities And Capillary Pressure Parameters From Pumpout Wireline Formation Tester Data, Spwla Forty-Fourth Annual Logging Symposium, Galveston, Texas, June 22-25, 2003. Performance Optimization of Perforated Completions Using a New 3D Finite-Element Wellbore Inflow Model and Artificial Neural Network, ExiPet Petroleum Congress, held in Veracruz, Mexico, February 16 - 18, 2003. Well Test Analysis Review, and Future Development, ExiPet Petroleum Congress, held in Veracruz, Mexico, February 16 - 18, 2003. Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 43 Sample Quality Prediction with Integrated Oil and Water-based Mud Invasion Modeling, SPE paper 77964 presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition held in Melbourne, Australia, 8–10 October 2002. Inversion of Multi-Phase Petrophysical Properties Using Pumpout Sampling Data Acquired with a Wireline Formation Tester, SPE paper 77345 presented at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, 29 September–2 October 2002. Multiple Factors that Influence Wireline Formation Tester Pressure Measurements and Fluid Contact Estimates, SPE paper 71566 presented at the 2001 SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, 30 September–3 October 2001. New Wireline Formation Testing Tool with Advanced Sampling Technology, SPE paper 71317, SPE Reservoir Evaluation and Engineering Journal, April 2001. Testing of Gas Condensate Reservoirs — Sampling, Test Design and Analysis, SPE paper 68668 presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition held in Jakarta, Indonesia, 17–19 April 2001. Advanced Dual Probe Formation Tester with Transient, Harmonic, and Pulsed Time-Delay Testing Methods Determines Permeability, Skin, and Anisotropy, SPE paper 64650 presented at the SPE International Oil and Gas Conference and Exhibition in China held in Beijing, China, 7–10 November 2000 Advanced Permeability and Anisotropy Measurements While Testing and Sampling in Real-time Using a Dual Probe Formation Tester, SPE paper 62919 presented at the 2000 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, 1–4 October 2000. New Dual-Probe Wireline Formation Testing and Sampling Tool Enables Real-Time Permeability and Anisotropy Measurements, SPE paper 59701 presented at the SPE Permian Basin Oil and Gas Recovery Conference held in Midland, Texas, 21–23 March 2000. New Wireline Formation Testing Tool with Advanced Sampling Technology, SPE paper 56711 presented at the 1999 SPE Annual Technical Conference and Exhibition, Houston, Texas, 3–6 October 1999 Exact Spherical Flow Solution with Storage for Early-Time Test Interpretation, SPE Journal of Petroleum Technology, Nov. 1998 New Exact Spherical Flow Solution with Storage and Skin for Early-Time Interpretation, with Applications to Wireline Formation and Early-Evaluation Drillstem Testing, SPE Paper No. 49140, 1998 SPE Annual Technical Conference and Exhibition, New Orleans, La., Sept. 1998 New Exact Spherical Flow Solution for Early-Time Well Test Interpretation with Applications to Wireline Formation Testing and Early-Evaluation Drillstem Testing, SPE Paper No. 39915, SPE Rocky Mountain Regional Meeting/Low Permeability Reservoirs Symposium, Denver, Co., April 1998 New Exact Spherical Flow Solution for Early-Time Well Test Interpretation with Applications to Wireline Formation Testing and Early-Evaluation Drillstem Testing, SPE Paper No. 39768, SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, March 1998 Pressure Test Validity Shown by Comparing Field Tests and Simulations, Part II: Formation Pressure Test Tools, Oil & Gas Journal, Jan. 12, 1998 Testing System Combines Advantages of Wireline and Drillstem Testers, Part I: Formation Pressure Test Tools, Oil & Gas Journal, Jan. 5, 1998 Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 44 Low Permeability Interpretation Using a New Wireline Formation Tester ‘Tight Zone’ Pressure Transient Analysis, SPWLA 94 III Paper, presented at the 35th Annual Symposium in Tulsa, Oklahoma, June (1994). Real Time Pressure Transient Analysis Methods Applied to Wireline Formation Test Data, SPE paper 28449, presented at the 69th Annual Technical Conference of SPE in New Orleans, La., Sep. 25-28, 1994. Interpretation of Wireline Formation Tester Pressure Response, Mud Super-charging and Mud Invasion Effects, SPWLA 92 HH Paper, presented at the 33rd Annual Symposium in Oklahoma City, Oklahoma, June (1992). Improved Models for Interpreting the Pressure Response of Formation Testers, SPE paper 22754, presented at the 66th SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 1991 Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 45 Basic Tool Theory The GeoTap Service The objective of the GeoTap tool development was to provide a robust repeatable formation pressure measurement in a LWD tool contained in a single collar. While several original approaches have been considered for FTWD tools, the GeoTap tool resembles a conventional WFT adapted to a drill collar. The GeoTap tool design is similar to many probe style wireline tools, where a donut shaped rubber pad forms a seal around a metal snorkel. When this probe configuration is pressed against the wellbore the snorkel penetrates the mudcake and contacts the formation to make the pressure measurement. The GeoTap tool collar has been integrated into the real-time Sperry-Sun Measurement and Logging While Drilling (M/LWD) system. Tools are available in 4 ¾”, 6 ¾”, 8”, and 9 ½” tool size. The GeoTap tool can be used to take pressure measurements in boreholes from 5 ¾” – 18”. Wherever possible, proven downhole M/LWD components were used. This includes using a field-proven Quartz Gauge with accompanying electronics. In this case, the Sperry Pressure While Drilling (PWD™) gauge section is used that has been in service for more than three years. The use of the PWD electronics provided a reliable memory and communications (GeoSpan™) system to operate and control the GeoTap tool downhole. Further considerations were made in designing the tool to ensure that it was compatible with ongoing drilling operations and yet simple enough to maintain at the well site. The tool is capable of operating while the rig pumps are active (i.e., pumps on) with no apparent detrimental effect on the data quality. Having the pump on is a preferred mode of operation because it reduces the potential of differential sticking and keeps the wellbore and mud system conditioned. Operation of GeoTap Tool The GeoTap tool can be run as a typical tool section and uses existing Sperry-Sun M/LWD technology. This enables it to be deployed with other M/LWD tools and use the same data uplink and downlink capabilities. Most of the runs to date have been with the GeoTap tool in combination with several other LWD sensors including BAT™ Sonic, MRIL-WD™ magnetic resonance and GEOPILOT™ rotary steerable system. The GeoTap tool operation is pre- programmed with a timed sequence of events. The time to operate has been kept to a minimum such that (at circa 7 minutes from start to finish) it is analogous to making a slow connection. The timed events can be altered by sending a downlink signal to the tool so that it can adapt to changing formation conditions. When an initialization downlink command is sent to the tool to start the sequence, the sequence will continue unless the tool detects a system error. If an error is detected or system power is lost the probe is automatically retracted. As a fail-safe mechanism, there is a hydraulic accumulator in the tool that maintains a reserve of hydraulic fluid at system pressure to automatically retract the probe in the event of a power loss. Furthermore, the probe can be sheared with a 100,000 pound force if the accumulator loses pressure. With the tool positioned on depth (determined from the real-time responses from the M/LWD tool string) the downlink command is issued from the surface to initiate the test. The downlink is achieved by using the GeoSpan™ technology and the Insite™ software package. This allows the operator at the surface to transmit through the mud column down to the M/LWD tool. The pressure signal from the surface is received and decoded by the PWD pressure sensor (located Formation and Reservoir Solutions (FRS) GoM 3950 Interwood S. Pkwy, Houston, TX 77032-3873 9 February 2016 Confidential Page 46 within the GeoTap tool) and the arming instruction is confirmed by sending a command back to the surface. On receipt of the downhole confirmation, a second pressure signal is sent by the surface GeoSpan to start the execution of the pressure test in pumps on mode. If it is desired to perform the pressure test with pumps off (as when a PDM motor is a part of the BHA), then the pressure test sequence starts as soon as circulation stops (a short delay can be applied in advance of the probe setting). Pressure data are actually recorded from a pair of pressure transducers located within the tool. The GeoTap tool’s primary pressure transducer is the annular PWD quartz transducer. A strain gauge transducer is also available with both gauges recording at a 5Hz sampling rate. Once the test sequence is completed the probe is retracted, additional data are transmitted and drilling can continue. Real-time data transmission can occur concurrently with the pressure test sequence if the pumps are on while testing. If the “pumps off” mode is selected the data transmission occurs immediately after the sequence has ended The complete set of pressure data is stored in the tool memory and is downloaded at the surface when the tool is retrieved. It was recognized early in the tool development that just transmitting pressures was not sufficient to evaluate the pressure test data quality. For this reason the additional parameters were added to the data transmission so that the drawdown and buildup data could be characterized as curves that reflect the full data set recorded downhole. Notice that the Pstop and Pfu pressures are transmitted with 0.1psi and 8 psi resolution respectivly. Comparing these two pressures gives the operator an immediate indication of the stability of the buildup. The other parameters are described in further detail under the topic of real-time data transmission. Real-Time data Transmission: The “pumps-on telemetry” protocols are ideal for the GeoTap real-time data transfer. The GeoTap tool fully emulates the “PWD” annular pressure-while-drilling measurement whilst not activated for a test. However, on command from the surface, an “equalizer” valve closes to isolate the gauge manifold from the annulus and the “pre-scripted” pressure test sequence runs automatically. The PWD/FTWD duality (where by the pressure data is written in parallel to both the PWD annular and FTWD test records) and pumps-on operation means that the pressure test transient is available as a fast updating (~ every 8 second) “annular pressure only” PWD data stream (with 1 psi resolution) during the test for “visual QC” , along side the “downhole processed” analysis of the pressure transient : In effect, during a test, the HCIM controller interrupted the routine / continuous FE data and switched to transmitting only the pressure transient data. This “visual” presentation parallels the downhole data regression and transmitted FTWD data results: Phyd1 and Phyd2, the drawdown start and the stop pressures and the “shut-in” pressure at the end of the build-up period. Apart from the shut-in / stop pressure, which has 0.1 psi coded resolution, the other pressures have a data compression applied which is ±8psi. The pretest rate, volume and build up time can be changed during the FT test if the previous build up time is long enough (≥96 seconds).