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DATA SUBMITTAL COMPLIANCE REPORT 7/1/2019 Permit to Drill 2161260 Well Name/No. HANSEN H-04 MD 20867 TVD 7127 Completion Date 3/22/2019 REQUIRED INFORMATION , V pod t�N Mud Log , 7 O DATA INFORMATION J List of Logs Obtained: GR/Res/DEN/Neu/PWD rvvuAl. Well Log Information: Log/ Electr Operator Bluecrest Alaska Operating LLC API No. 50-231.20064-00-00 Completion Status 1 -OIL Current Status 1 -OIL UIC No Samples P16 ✓^'l Dp Directional Survey Yesz 1 Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data (from Master Well Data/Logs) Interval CHI Start Stop CH Received Comments 10 20950 5/10/2019 _•�n Electronic Data Set, Filename: H04_Main.las Vvt&6 U 5/10/2019 Electronic File: Hansen H04 AM Report Nabors 12-26-2018.pdf 5/10/2019 Electronic File: Hansen H04 AM Report Nabors 12-27-2018.pdf 5/10/2019 Electronic File: Hansen H04 AM Report Nabors 12-28-2018.pdf 5/10/2019 Electronic File: Hansen H04 AM Report Nabors 12-29-2018.pdf 5/10/2019 Electronic File: Hansen H04 AM Report Nabors 12-30-2018.pdf 5/10/2019 Electronic File: Hansen H04 AM Report Nabors 12-31-2018.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-01-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-02-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-03-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-04-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-05-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-06-2019.pdf AOG('CPage 1 or9 Monday, July I, 2019 DATA SUBMITTAL COMPLIANCE REPORT 7/1/2019 Permit to Drill 2181260 Well Name/No. HANSEN H-04 Operator Bluecrest Alaska Operating LLC API No. 50-231-20064-00-00 MD 20867 TVD 7127 Completion Date 3/22/2019 Completion Status 1 -011 - ED -OILED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data AOGCC Page 2 of Current Status 1-0I1- UIC No 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-07-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-08-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-09-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-10-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-11-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-12-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-13-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-14-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-15-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-16-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-17-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-18-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-19-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-20-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-21-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-22-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-23-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-24-2019.pdf Monday, July I, 2019 DATA SUBMITTAL COMPLIANCE REPORT 7/1/2019 Permit to Drill 2181260 Well Name/No. HANSEN H-04 Operator Bluecrest Alaska Operating LLC API No. 50-231-20064-00-00 MD 20867 TVD 7127 Completion Date 3/22/2019 Completion Status 1-0I1. ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data AOGCC Page 3 of 9 Current Status 1-0I1. UIC No 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-25-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-26-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-27-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-28-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-29-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-30-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 01-31-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-01-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-02-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-03-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-04-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-05-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-06-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-07-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-08-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-09-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-10-2019.pdf 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-11-2019.pdf Monday. July 1. 2019 DATA SUBMITTAL COMPLIANCE REPORT 7/1/2019 Permit to Drill 2181260 Well Name/No. HANSEN H-04 Operator Bluecrest Alaska Operating LLC API No. 50-231-20064-00-00 MD 20867 TVD 7127 Completion Date 3/22/2019 Completion Status 1-0I1- Current Status 1-0I1- UIC No ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-12-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-13-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-14-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-15-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-16-2019.1>df ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-17-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-18-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-19-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-20.2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-21-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-22-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-23-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-24-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-25-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-26-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-27-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 02-28-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-01-2019.pdf AOGCC Page 4 of 9 Monday, July I, 2019 DATA SUBMITTAL COMPLIANCE REPORT 7/1/2019 Permit to Drill 2181260 Well Name/No. HANSEN H-04 Operator Bluecrest Alaska Operating LLC API No. 50-231-20064-00-00 MD 20867 TVD 7127 Completion Date 3/22/2019 Completion Status 1-0I1- Current Status 1-0I1 UIC No ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-02-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-03-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-04-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-05-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-06-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-07-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-08-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-09-2019.1>df ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-10-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-11-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-12-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-13-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-14-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: Hansen H04 Nabors AM Report 03-15-2019.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: H04-Main.dbf ED C 30739 Digital Data 5/10/2019 Electronic File: h04-main.hdr ED C 30739 Digital Data 5/10/2019 Electronic File: H04-Main.mdx ED C 30739 Digital Data 5/10/2019 Electronic File: h04-mainr-dbf ED C 30739 Digital Data 5/10/2019 Electronic File: h04-mainr.mdx ED C 30739 Digital Data 5/10/2019 Electronic File: H04-Main_SCL.DBF ED C 30739 Digital Data 5/10/2019 Electronic File: H04 -Main SCL.MDX AOGCC Page 5 of 9 Monday, July I, 2019 DATA SUBMITTAL COMPLIANCE REPORT 7/1/2019 Permit to Drill 2181260 Well Name/No. HANSEN H-04 Operator Bluecrest Alaska Operating LLC API No. 50-231-20064-00-00 MD 20867 TVD 7127 Completion Date 3/22/2019 Completion Status 1-0IL Current Status 1-0I1- UIC No ED C 30739 Digital Data 5/10/2019 Electronic File: H04-MAIN_tvd.dbf ED C 30739 Digital Data 5/10/2019 Electronic File: H04-MAIN_tvd.mdx ED C 30739 Digital Data 5/10/2019 Electronic File: BLUE CREST ENERGY H-04 FINAL REPORT.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: H04-MAIN—Drilling Dynamics Log MD.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: H04-MAIN_Formation Log MD.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: H04-MAIN—Gas Ratio Log MD.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: H04-MAIN_LWD Combo Log MD.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: H04-MAIN—Drilling Dynamics Log MD.tif ED C 30739 Digital Data 5/10/2019 Electronic File: H04-MAIN_Formation Log MD.tif ED C 30739 Digital Data 5/10/2019 Electronic File: H04-MAIN_Gas Ratio Log MD.tif ED C 30739 Digital Data 5/10/2019 Electronic File: H04-MAIN_LWO Combo Log MD.tif ED C 30739 Digital Data 5/10/2019 Electronic File: H04 -Main Show Report #1 14747- 14800.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: H04 -Main Show Report #1 14747- 14800.xism ED C 30739 Digital Data 5/10/2019 Electronic File: H04 -Main Show Report #10 18732-19220.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: H04 -Main Show Report #10 18732-19220.xism ED C 30739 Digital Data 5/10/2019 Electronic File: H04 -Main Show Report #11 19800-20148.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: H04 -Main Show Report #11 19800-20148.xism ED C 30739 Digital Data 5/10/2019 Electronic File: H04 -Main Show Report #12 20460-20830.pdf ED C 30739 Digital Data 5/10/2019 Electronic File: H04 -Main Show Report #12 20460-20830.xism ED C 30739 Digital Data 5/10/2019 Electronic File: H04 -Main Show Report #2 14838- 14870.pdf AOGCC Page 6 of 9 Monday, July I, 2019 DATA SUBMITTAL COMPLIANCE REPORT 7/1/2019 Permit to Drill 2181260 Well Name/No. HANSEN H-04 Operator Bluecrest Alaska Operating LLC API No. 50-231-20064-00-00 MD 20867 TVD 7127 Completion Date 3/22/2019 Completion Status 1 -011 - -OILED ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data ED C 30739 Digital Data Log C 30739 Log Header Scans 0 0 ED C 30908 Digital Data 15354 20832 ED C 30908 Digital Data 310 20868 ED C 30908 Digital Data Current Status 1-0I1- UIC No 5/10/2019 Electronic File: H04 -Main Show Report #2 14838- AOGCC Page 7 of 9 Monday, July 1, 2019 14870.xism 5/10/2019 Electronic File: H04 -Main Show Report #3 14925- 15007.pdf 5/10/2019 Electronic File: H04 -Main Show Report #3 14925- 15007.xism 5/10/2019 Electronic File: H04 -Main Show Report #4 15020- 15075.pdf 5/10/2019 Electronic File: H04 -Main Show Report #4 15020- 15075.xlsm 5/10/2019 Electronic File: H04 -Main Show Report #5 15135- 15213.pdf 5/10/2019 Electronic File: H04 -Main Show Report #5 15135- 15213.x1sm 5/10/2019 Electronic File: H04 -Main Show Report #6 15490- 15710.pdf 5/10/2019 Electronic File: H04 -Main Show Report #6 15490- 15710.x1sm 5/10/2019 Electronic File: H04 -Main Show Report #7 16313- 16866.pdf 5/10/2019 Electronic File: H04 -Main Show Report #7 16313- 16866.x1sm 5/10/2019 Electronic File: H04 -Main Show Report #8 17750- 18320.pdf 5/10/2019 Electronic File: H04 -Main Show Report #8 17750- 18320.xism 5/10/2019 Electronic File: H04 -Main Show Report #9 18345- 18692.pdf 5/10/2019 Electronic File: H04 -Main Show Report #9 18345- 18692.x1sm 2181260 HANSEN H-04 LOG HEADERS 6/24/2019 Electronic Data Set, Filename: BlueCrest_H04- Main _EcoSoope Images_ RM_LAS.Ias 6/24/2019 Electronic Data Set, Filename: BlueCrest_H04- Main_EcoScope_ RM_LAS.Ias 6/24/2019 Electronic File: Folder info.txt AOGCC Page 7 of 9 Monday, July 1, 2019 DATA SUBMITTAL COMPLIANCE REPORT 7/1/2019 Permit to Drill 2181260 Well NamelNo. HANSEN H-04 Operator Bluecrest Alaska Operating LLC API No. 50-231-20064-00-00 MD 20867 TVD 7127 Completion Date 3/22/2019 Completion Status 1-0I1- Current Status 1-0I1- UIC No ED C 30908 Digital Data 6/24/2019 Electronic File: BlueCrest_H04-Main_EcoScope Completion Date: 3/22/2019 Images_RM_DLIS.dlis ED C 30908 Digital Data 6/24/2019 Electronic File: BlueCrest_1-104- Monday, July 1, 2019 Main_EcoScope_RM_D1-I S.dlis ED C 30908 Digital Data 6/24/2019 Electronic File: BlueCrest_1-104- Main_EcoScope_2in_ RM_0-20867ftM D. Pdf ED C 30908 Digital Data 6/24/2019 Electronic File: BlueCrest H04- Main_E coScope_2in_RM_I nvertTVD. Pdf ED C 30908 Digital Data 6/24/2019 Electronic File: BlueCrest H04- Main _EcoScope_5in_R M_0-20867ftMD. Pdf ED C 30908 Digital Data 6/24/2019 Electronic File: BlueCrest H04- Main_EcoScope_5in_RM_I nvertT V D. pdf ED C 30908 Digital Data 6/24/2019 Electronic File: BlueCrest_H04- Main EcoScope_Image_5in_RM_0- 20867ftMD.Pdf ED C 30908 Digital Data 6/24/2019 Electronic File: H04—Surveys to surface_final.pdf ED C 30908 Digital Data 6/24/2019 Electronic File: H04—Surveys to surface_final.xlsx Log C 30908 Log Header Scans 0 0 2181260 HANSEN H-04 LOG HEADERS ED C 30908 Digital Data H04 ASP Final Survey PDF ED C 30908 Digital Data H04 ASP Final Survey Excel Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments Cuttings 5810 20867 3/26/2019 1703 INFORMATION RECEIVED Completion Report Y Directional / Inclination Data DY Mud Logs, Image Files, Digital Data(' NA Core Chips Y /l A Production Test Informatio Y NA Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files © Core Photographs Y /l/NH i Geologic Markers/Tops O Daily Operations Summary Cuttings Samples oY /NA Laboratory Analyses Y /� COMPLIANCE HISTORY Completion Date: 3/22/2019 AOGCC Page 8 of 9 Monday, July 1, 2019 DATA SUBMITTAL COMPLIANCE REPORT 7/1/2019 Permit to Drill 2161260 Well NamelNo. HANSEN H-04 Operator Bluecrest Alaska Operating LLC MD 20867 TVD 7127 Completion Date 3/22/2019 Completion Status 1-0I1 Current Status 1-011- Release -OIL Release Date: 11/19/2018 Description Date Comments Comments: Compliance Reviewed By: I y API No. 50.231-20064.00-00 UIC No Date: 7/1 I 1 ( I AOG('(' Page 0 M 9 Monday. July 1. 2019 21 81 21 RECEE V, Fr -o 50908' JU"J 26 2r; 2 18 126 Schlumberger -Private Ilue est Energy 21812 30739 BlueCrest Alaska Operating LLC 3301 CStreet, Suite 202 Anchorage, AK 99503 Tet: (907) 754-9550 fi� v : C �V D Fax: (907) 677-0204 MAY 10 2019 Transmittal AOCCC -----H! Today's Date 5/10/2019 Transmtttal #2019 08 .. .. ... ..... _._. To: Ms. Meredith Guhl From: Andrew Buchanan CD's contain the Final Well Data for H04: Final Well Data for Well H04 Main Final Well Data for Well H04 1-01 Final Well Data for Well H04 L02 Final Well Data for Well H04 L03 Final Well Data for Well H04 L04 Final Well Data for Well H04 L05 Final Well Data for Well H04 L06 Final Well Data for Well H04 L07 Regards Andrew Buchanan BlueCrest Energy STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 0 9 ?^1n WELL COMPLETION OR RECOMPLETION REPORT ANA(DO&t. 1a. Well Status: Oil Q Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development 21 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: BlueCrest Alaska Operating LLC Comp: 3/22/2019 218.126 ' 3. Address: 7. Date Spudded: 15. API Number: 3301 "C" Street, Suite 202, Anchorage, AK 99503 12/27/2018 50-231-2006400-00 4a. Location of Well (Governmental Section): 8. Date TO Reached: 16. Well Name and Number: Surface: 2089' FSL, 1541' FEL, Sec 2, T4S, R15W, SM 2/20/2019 • H04 Top of Productive Interval: 9. Ref Elevations: KB: 180.5 17. Field / Pool(s): 318' FSL, 3275' FEL, Sec 33, T3S, R15W, SM GL:145.8 BF:141.4 , Hansen,Undefined Cosmopolitan Oil Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 3158' FSL, 2634' FEL, Sec 32, T3S, R15W, SM 20864' MD / 7127' TVD • Fee Hansen,ADL18790,ADL 384403 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: • 19. DNR Approval Number: Surface: x- 168804 y- 2144597.65 • Zone- 4 20867' MD / 7127' TVD LOCI 14007 TPI: x- 156626.45 y- 2148387.65 Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 152064.83 y- 2151357.51 Zone- 4 488' MD / 488' TVD N/A 5. Directional or Inclination Survey: Yes L41 (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/rVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) 15,479' MD / 7077' TVD KOP 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 ALL LOGS WERE SLB LWD: GR-Res--Den-Neu-PWD Final Mudlogging Report / Mud Log / Lithology Log (Nabors-CanRig) Formation Log / LWD Combo Log / Gas Ratio Log / Drilling Dynamics Log 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT GRADE HOLE SIZE CEMENTING RECORD CASING FT TOP BOTTOM TOP BOTTOM PULLED 20 0.500" wall A525 41 115.5 41 115.5 Driven N/A - Rotary Drilled/Driven N/A 13.375 72 L-80 40.5 5800 40.5 3593 17.5" 787 bbls Lead / 176 bbls Tail N/A 9.625 47 P-110 37.8 15406 37.8 7055 12.25" 139 bbls 15.8 ppg G -Tail N/A 4.5 15.2 P-110 15211 20864 6988 7127 8.5" Slotted Liner - no cement N/A 3.5 9.3 L80 10.61 15246 10.61 6988 N/A Production Tubing String N/A 24. Open to production or injection? Yes Q No ❑ 25. TUBING RECORD If Yes, list each interval open (MDfrVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MDrrVD) Size and Number; Date Perfd): 3.5" 15246' MD 15211' MD / 6988' TVD Well completed with 4-1/2" slotted liner in mainbore; see attached lower liner tally for set depths and details. There are no perforations since a slotted liner 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. was run in the well. Slotted liner in mainbore top is at 15211' MD (6988' TVD) Was hydraulic fracturing used during completion? Yes No � and bottom is at 20864' MD (7127' TVD). Production from fishbone laterals drains into slotted liner in mainbore.COMPLETION Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED DATE N/A N/A Z Zo,, VERIFj D 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): 3/25/2019 as lifted 3/2512019 Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 12 hours Test Period 1200 (op1300 j 19' $ 37 500 Flow Tubing Casinq Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 1575 24 -Hour Rate 1200 0 15 27 Form 10-407 Revised 5/2017 0 S _/� q e03)713 ON PAGE 2 IMS -146o/ MAY 0 9 2019 Submit ORIGIN`AA,L onV 28. CORE DATA Conventional Co. _,$): Yes ❑ No Sidewall Cores: . as ❑ No Q If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. N/A 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD - TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Beluga 2330 2159 Upper Tyonek A 5510 3489 Attach separate pages to this form, if needed, and submit detailed test Lower Tyonek 13024 6201 information, including reports, per 20 AAC 25.071. Starichkof 15342 7034 Hemlock 16786 7126 TPI (matches 4a & 4b) 15,406 7,055 BPI (TD) 20,867 7,127 TPI is also 9-5/8" shoe for H04 mainbore Formation at total depth: IStarichkof 31. List of Attachments: Operations Summary, Actual Wellbore Diagram, List of Formation Tops, Mud Wt vs. Depth Data, Final Definitive Directional Surveys, Slotted Liner String Tally (4-1/2"), Tubing String Tally (3-1/2"), Wellhead & Tree Schematic, Pressure Test Results Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Andrew Buchanan Contact Name: Tom McKay Authorized Title: Vice Preside task perations Contact Email: tom.mckay bluecrestenerov corn Authorized /Q Contact Phone: 907-754-9566 Signature: S^ 7-! / 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 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only nue Enedrgy 3301 C Street, Suite 202, Anchorage, AK 99503 Thomas McKay, PE Phone: (907)754-9566 Email: tom.mckay@bluecrestenergy.com April 9, 2019 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Cosmopolitan Project RE: Well Completion Report Form 10-407: Horizontal / Multilateral "Fishbone" Production Well H04 Rev 1 PTD No. 218-126 API No. 50-231-20064-00-00 Dear Commissioners, BlueCrest Alaska Operating LLC hereby submits a completed Form 10-407 Well Completion Report with Attachments for the onshore horizontal / multilateral production well H04 Rev 1. This well was drilled and completed using BlueCrest Rig #1. The well is currently undergoing an extended flow test on gas lift after installing the 4-1/2" slotted liner completion. Note that the flow test results, etc., as per AOGCC request, will be covered under a subsequent 10-407 package, along with other required well production tests and reports. Please find attached for the review of the Commission, the completed Form 10-407, and the information required by 20 ACC 25.070 for this wellbore, covering the drilling and completion of the "fishbone" multilateral, and the running of the upper 3-1/2" tubing string. If you have any questions or require further information, please do not hesitate to contact Tom McKay at 907-754-9566 (office phone). Sincerely, 4 Larry Burgess Alaska Manager BlueCrest Energy Alaska nue Energy H04 Rev 1 — Mainbore Form 10-407 Well Completion Report List of Attachments Cosmopolitan Project AOGCC Item No. Description A Cover Letter w/ Attachment Headers 1 AOGCC Form 10-407 Well Completion Report (2 pages) 2 Operations Summary (Daily Running Summary / Recap) 3 (2) Actual Wellbore Schematics (as Completed) 4 Detailed List of Formation Tops / Geologic Markers (Box 29) 5 Mud Weight vs Depth Data 6 Definitive Wellbore Survey (Directional Survey) x 8 files total 7 13-3/8" Surface Casing Tally & Details 8 13-3/8" Surface Casing Cementing Recap 9 9-5/8" Intermediate Casing Tally & Details 10 9-5/8" Intermediate Casing Cementing Recap 11 Lower Lateral Completion Slotted Liner Tally Sheet 4-1/2" 12 Tubing Completion String Tally Sheet 3-1/2" 13 Wellhead & Tree Schematic (at the time of this 10-407) 14 Pressure Tests & FIT's on 13-3/8" & 9-5/8" Casings; Liner; Tubing; Tree 15 H04 Rev 1 Conductor Slot As -Built - REVISED COORDINATES H-04 As Built Schematic 4-3-2019 26" Hole 20" 0.50" Wall A252 Conductor @ +/. 18T MD / TVD @ 488' MD Rig 1 RKB: 34.65' H -16A Elevation: 145.8' KB to MSL: 180.46' 17'/2" Hole — 13-3/8"72#L-80 BTC Casing @ +/_ 4195' MD - 3-'/2" 9.3# LA0 Tubing GLM 3 wl IPO Valve @ 4,696 MD, 3,197' TVD XNIPPW2@ 5,097-MD,3,340'WD GLM 2 wl IPO Valve @ 10.661' MD, 5,346' WD 12.'/." Hole L-01 L -O2 L-03 L.oe 9-5/8" 53.5# P-110 Casin KOP 10,OW MD 9 KOP 16.860' MD KOP 17,690 -MD KOP 18,6.0' MO NOP 19.220 ' MD L L -OT TO 172N'MD TO 18230 MD TO 10,017'MD TO 20,BB6'MO TO 28,735•MO KOP 20.OM'MD KOP 20.920 -MD 15,406MD +1. 7,055'TVD 21 TO SB'MD TO 21,888'MD X NIPPIe 1 (� 1 1 14A58'MD, 6,717'WD � .� Koi 1 TO DCIN Chemical Infection Sub @ 13,596' 110,6,409'WD GLM 1 w/ 1/4' orifice Valve @ 14,288' MD, 6,656' WD ..tor Seal Assembly @ 15.207' MD SGM W DH Gauge @ 15,116'MD,6,952'WD 8 1/2" Hole 4'/2" 15.2# LA0 TSH -563 Slotted / Blank Liner lae st / En&U iq-0,( MD PkA / .0 lZC X 2 _ MO WtV Flor Joint A.-.bi, P -Pa ed By D. Ross 4319 T. McKay, 22March2019 H04 Lower Lateral ACTUAL Completion with Slotted Liner in 20" Conductor to beset @82' Mainbore and Seven (7) Open Hole BGL Fishbone Ribs Ilu est 13-3/8" 72# L80 Energy BTC @ 5800' MD 3-Yz" 9.3# IBT-MOD Production Tubing Fishbone ribs are 8-%" open holes spaced approx every 800' with 4-Yz" slotted liner run in the mainbore after the seven ribs were drilled; ribs were drilled in order from LOl to L07 using open hole sidetracks to initiate each rib; ribs penetrate all layers of Starichkof and Hemlock pay sands 4-%" x 9-5/8" L 2 L03 L04 L05 L06 L07 Liner Hanger & \ Liner Top Packer v� M � 9-5/8" 47.0# P110 H563 @ 15406' MD 4-Yzz" 15.2# H563 Slotted Liner @ 20867' MD H-04 Formation Tops SSTVD MD TVD H-04 Add-180.5' NAhrti'6,o C-- Beluga -1978.18 2330 2158.68 I Upper Tyonek A -3308.35 5510 3488.85 Lower Tyonek -6020.31 13024 6200.81 Starichkof -6853.97 15342 7034.47 Hemlock -6945.3 16786 7125.8 H-04-LO1 Starichkof -6631.02 17158 6811.52 H-04-LO2 Hemlock -6904.77 17179 7085.27 Starichkof -6544.78 18186 6725.28 H-04-LO3 Hemlock -6832.52 18287 7013.02 H-04-LO4 Hemlock -6800.62 19146 6981.12 Starichkof -6485.96 19922 6666.46 H-04-LO5 Hemlock -6791.27 20028 6971.77 Starichkof -6510.86 20697 6691.36 H-04-LO6 Hemlock -6823.52 20671 7004.02 Starichkof -6569.83 21320 6750.33 H-04-LO7 Hemlock -6885.62 21308 7066.12 Starichkof -6651.92 21932 6832.42 WELL #4 - REV 01 N.A.D.83 N: 2144356.97 E: 1308831.26 LAT: 59'51'27.32"N LON: 151'48'13.78"W N.A.D.27 N: 2144597.86 E: 168803.61 LAT: 59'51'29.48"N LON: 151'46'06.03"W 1541' F.E.L. 2089' F.S.L. TOP OF CONDUCTOR PLANT: 98.43' NAVD88:146.13' GROUND (PAD) ELEVATION PLANT: 97.5' NAVD 88: 145.2' 4.75' J WELL #4 REV 01 NOTE: 1. STATE PLANE AND GEOGRAPHIC COORDINATES ARE ALASKA STATE PLANE, ZONE 4, N.A.0.83 AND AND N.A.D.27 AS LABELED. 2. COORDINATES ESTABLISHED FROM STATIC GPS OBSERVATIONS. 3. ALL DISTANCES SHOWN ARE GROUND. 4. THE NGS COORDINATE CONVERSION AND TRANSFORMATION TOOL (NCAT) WAS USED FOR NAD83(2011) TO NAD 27 CONVERSIONS, 5. TOP OF CONDUCTOR ELEVATION WAS AS -BUILT AT THE FIRST CUTOFF, APPROXIMATELY AT PAD LEVEL. - AS BURT CONDUCTOR LOCATION I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY DONE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DIMENSIONS AND OTHER DETAILS PER THIS REVISION ARE CORRECT AS OF DECEMBER 19, 2018. W1 "K x N 45 Rt SW SEC 2 c^ 9 n 4 srw,v, z ti °a O W 2 w. aox o T4S R15W SEC i THIS SURVEY "�. . T4s R15W SEC 11 wa 151 — V VICINITY MAP I" = 1/2 MILE N a 5 10 ( IN FEET ) 1 inch = 10 ft. F, ��E OF . 4 111 -,, •....... 9SFf�4 ' 9 i �i *:'49 " *'s ... ... ..................� i �-JACOB GERONDALE-�o� �ij'r�,'•. LS -117`8 ,•'��`"- it 7111 10 t��tt�� lI �� •"��Or` AS BUILT SURVEY BLUECREST ENERGY WELL #4 - REV 01 WITHIN SECTION 2 T4S R15W S.M., AK. HOF BURY & ASSOCIATES, INC. veyors - Engineers - Planners REET, ANCHORAGE, ALASKA 272-5451 :12 21 18 STAKED:12 17 18 16-014-1 AS BUILT:12 21 2018OR POINT I RECERT: WellView° Well Name: HO4 BC - Daily Recap Well Name H04 APUUWI 50-231-20064-00-00 Sudara Legal Location 2173' FSL, 1552' FEL, Sect, T4S, R15W SM 77 218-126 Spud Date Rig Release Date Ground Elevation (it) kt33m ird Dista Well Subtype 12/27/201816:30 145.20 34.45 Prod ucer-Horizontal-Multilateral Daily Operations Start Date 12/14/2018 End Date Spud Date 12/27/2018 Total Number of Reports 96.0 Total Depth m Wellbone (ffKS) 120,867.00 survey Data MD (ftKB) Ind I') Aum (') TVD (ftKe) VS (ft) NS (ft) EW (ft) 1 DSS ("/10011) Date 20,779.52 90.48 301.89 7,127.42 17,706.05 6,291.78 -18,812.63 0.45 2/19/2019 20,820.0089.80 301.94 7,127.32 17,746.51 6,313.18 I -16,846.99 1.68 - 2/19/2019 20,867.00 89.00 302.00 7,127.81 17,793.48 6.338.07 -16,886.86 1.71 2/19/2019 Rigs Contiador Rig Number BC Rig 1 Daily Operations Rpt# Start Date End Date Summary 12/14/2018 12/15/2018 - Remove Stairway from Mud pits to Rig floor with Crane- - Lift Suit rase - Layed down felt and Herculite in from of Pits and set next set of mats with crane - Installed Skid Rams on Backyard Rails and connected hoses - Turned around skid on rig skid rams - Chained up remaining stairs around dg - Removed clamps and Hammer seal on flow line - Disconnected Transfer line between Reserve pits and Rig pits - _ Connected controls that skid the Backyard - Removed benning in front of suitcase - Removed Storm clamps - Secured all looses objects around rig - Checked under Backyard for any obstructions - Cleaned out Cellar Box for H16A 2.0 12/15/2018 12/16/2018 - Blow Down Water Lines to dg - Remove feet from Pipe shed elevators - Remove snow and ice from matting boards and Skid beams - Lost Power to Camp, offices, and Production facility @ 00:10 Hrs - Power back on 02:30 Hrs - PJSM with crews and Skid Rig 20'towards H04 - Move Drilling Line spool between pinning skid beams - Lay out Felt and Herculite - Move mats, cross beams, and Skid rails form back yard to front yard and connected with crane and loader assist - Skidded rig 20'towards H04 - Leapfrog skid rails, mats, and cross sections from back to front yard - Removed sections of burming from old containment - Top off all equipment with fuel - Lay out next section of felt 30'x 100' in from of backyard - Welded next 1 00' x 100' section of Herculite - Skid Rig 20'towards H04 3.0 12/16/2018 12/17/2018 - PJSM - Skidi ing Rip to H04 - Lay out Felt and Herculite for the Skid - Move Skid rails, Mats, and Cross races,atin place with Crane and Loader assist - Disconnect Power to Water Tanks, Fuel Tanks, and Reserve Pits to Continue Skidding - Skid 20'towards H04 - Skidding psi on Front Yard1000 psi and Back Yard 1600 psi - Continue Skidding to H04 Using Cruz Crane and Loaders to assist in Moving Mats, Skid Beams, & Cross Beams - Fabricated Longer Water Hoses and add extra Fuel Hoses To keep rig fueled and water for Boiler Condensate tanks -Wired in Magtec Generator to run Fuel and Water Pumps - Laying out Felt and Herculite as we skid to H04 - Moved Mats, Skid Beams, and Cross Sections form back of the rig to the front and assembled with Crane and Loader assists - Rolled out Felt for second 1 00' x 100' of Herculite in front of Backyard - Skid Rig 20'towards H04 - skidding pressure on front yard 1000 psi and Backyard pressure 1650 psi - laid down fell in front of Backyard and seam taped final 100' x 100' section of HerculRe to previous section to be unfolded as rig is skidded forward - Moving Mats, Cross sections, and skid beams from back of Rig to front - Determined Rig was 8.5" West of Well Center @ 11 0'from H04 - Skidding Operations Halted - Change Liners in mud pumps from 6" to 6.5" - Placed new hopper line in Reserve Pits - Removed Liner and Fell in Back yard 4.0 12/17/2018 12/18/2018 - PJSM - Changing Liners in Mud Pumps from 6" to 6.5" - Inspecting Valves and seats - Installing new hopper and plumbing in Reserve Pits - Fabricated new fuel and water lines - Ran steam lines to Rig water tanks and monitored temperature - Changed O -rings in Hydraulic piping connections 5.0 12/18/2018 12/19/2018 - PJSM -Assemble Mud Pumps back together after changing Pistons and liners to 6.5" - Clean out Trip Tank with Mag Tech Vacuum Truck - Continuously sweeping snow from new Herculite for Rig Move - Thawing out Cellar H04 and pumping out water - Connect Steam to Reserve Pits for heat - Inspect Drawworks Chains - Paint new hopper lines in Reserve Pits - Complete Mud Pumps Liner and Piston change to 6.5" - Change out suction valves in charge pump room - Serviced Drawworks, Low Clutch, High dutch, Iron Roughneck, and - - TDS - Complete Mud Pumps fluid end inspection - Replaced 8" butterfly valve in Pump Room - Removed old Felt, Herculite, and burming in back of Rig - Disassembled from set of Front yard Skid Rails, Cross Members, and Mats - Rolled back Felt and HerculRe to have access for setting of 20" Conductor and cellar for H03 - - Replace bad butterfly valves in mud pits - Moving spill connex and other equipment to make room for final Rig position on H03 - Monitoring and filling Boiler Hot Wells, Rig Fuel, and Boiler Fuel throughout the day 6.0 12/19/2018 12/20/2018 - PJSM - Inspect and change out bad valves in pit system - Blow down Top Drive - Snow and ice removal in problem areas - Measure Office building and Toilets and stake off area for moving - Notify and showed Production of items need to a remove from H1 in order to make final approach on H03 - Clean new cellar box _ - - for welder to cut hole for 20" Conductor - Inventory and organize Rig floor tools and equipment - Fill Boiler and Generator day tanks with fuel - Drain charge pumps - Relocate Miscellaneous equipment from East side - of Camp to ready location for moving- Weld down hatch covers in pits - Uncover ends of service pipe line for electrician - Change pop off settings in pumps to 3750 psi - Repaired steam leaks in heaters around Rig - Replaced butterfly valves on suctions # 3 & # 5 in Pits - Checked Hydraulic lines on skate in Pipe shed for - leaks - Cleaned and organized pipe shed - Greased Slew bearing on Top Drive - Checked torque on Drawworks tie down bolts - Moving miscellaneous equipment form South end to staging area behind main camp in preparation for office move and final position of rig on H03 www.peloton.com Page 1110 Report Printed: 3/20/2019 WellView' Well Name: H04 BC - Daily Recap Daily Operations Rpt# Smrt Dam End Date Summary 7.0 12/20/2018 12/21/2018 - Housekeeping and Maintenance around the Rig - Change out bad valves in Mud Pits - Prep office for moving to new area - Assist mechanic in adjusting counter balance on Top Drive - Motorman and Mechanic fabricating new fuel return lines from dg to tank - Monitor temperature on rig water tanks - Fuel rig and boilers - Fill Boiler hot wells with water - Assist in splitting office complex for moving - Remove snow and ice in problem areas - Jack up office complex and split - Move office traitors to new position East end of the rig with Loader - Line up traitors and push together- Level up traitors - Drill Anchors in the ground for trailor tie downs - Bolt together traitors - Connect power - Install trim, transitions strips, and ceiling tiles - Simops operations, Kraxberger completed drilling 20" conductor to 75' TD - Install weather stripping between office buildings - Changing out bad valves in pits - Install hercufite around 12/21/2018 12/22/2018 air compressors - Place cellar box over Well H03 and mark for excavator - Grease Drawworks traction motors - Clean bottom of ST -100 and install centering plate - Dug hole for Cellar box H03 - Install Box and level - Fill in around box and move excess gravel - Assist with office wiring and install ceiling tiles - Rolled Felt and Herculite out in front of Front yard and Back Yard - Install Mals, skid beams, and cross sections Front yard - Skid Rig 20'towards H03 - Move skid beams, mats, and cross sections from back of rig to front and Install - Roll out felt and herculite in front of Back Yard - PJSM - Move skid beams, cross sections, and mats from North end of Rig and assemble on South end - 12/22/2018 12/23/2018 - Skid Rig and Back yard 20' South towards H03 - Disassemble skid beams, cross sections, and mats from North end of Rig and assemble on South end of Front Yard - Back blade South end of Back Yard to level location - Assemble skid beams and cross braces on South end of Back yard - Production removed XO flange and Temp sensors from H01 wellhead - Skid Rig and Back yard 16' South towards H03 - Stop and remove Tree Cap from H01 - Skid remaining 4' of last 20' sections - Disassemble skid beams, cross braces, and mats from North end of Front and Back yard and move and assemble on south end - Skid Rig and Back Yard 20' South towards H03 - Disassemble skid beams, cross sections, and mats from North end and move and assemble on South end of Front and Back yards - Skid 20' South towards H03 - Disassemble skid beams, cross braces, and mats from North end and move and assemble on South end of Front and Back Yard - Skid Rig and Back Yard 20' South towards H03 - Stopped at H04 with plum bob and checked alignment - Center line is 12" to the West - disassemble skid beams, cross sections, on the North end of Front and Back Yard - Lay out Felt South of Front Yard and piece Herculite together 10.0 12/23/2018 12/24/2018 - Move mats, skid beams, and cross braces with crane and loader from back of rig to the front and pin in place - Add Herculite and tape together - Move Cruz crane from West side of Rig to the East - Skid rig 14' to Well H03 Center line (Good) - Retract skidding cylinders - Set stairways around rig - Install storm clamps - Cut 20" Conductor 71"from Ground level - Modify flow line - Cut off 10", remove jet nipple and patched - Remove skid rams and bases from Back Yard to make room for Magtech's dragon wagons at cuttings box - Remove skid bases and placed drilling line spool and stairway with crane North end of Front yard - Received water in pits and began mixing spud mud - Replaced bell housing on HPU Pump B in cellar - Made fuel, water, steam, and air hoses to and from reserve side of Rig - Installed stairway in cellar to mezzanine - Cleaned up old berming, herculite,and felt North side of Rig - Remove skidding controls and hoses from Back yard and boxed up - Berming aorund Mud Pits 11.0 12/24/2018 12/25/2018 - Install walkways under Rig - Install pins and feet on pipe elevators - Mixing spud mud - Working on Benning around Rig - Working on steam, water, fuel, and air lines to/from reserve pits - Complete changing bell housing for HPU pump 2 - Mount new socket on NE side of dog house for RigMinder comms to office - Get measurements for Riser Space Out - change out O -rings on hydraulic manifold on rig floor - Weld on 4" & 6" nipples on Conductor - Set starter head, make up and test to 250 psi with Vetco - Changed out rubbers in - dresser sleeve and installed flowline in sleeve and flow box with crane assistance - Install brackets and gas buster hose to flowline - Install chain and guard on drilling line spool - Ran electrical lines from reserve side - - - through service pipe line - Continue making hoses to plumb into service pipe line - Staged service company units in position to be connected with power - Gather risers and prepare for nipple up 12.0 12/25/2018 12/26/2018 - PJSM - Berming around Rig - Install dragon heater and boxes South of Back Yard - Nipple up adaptor spool and well head - Install riser and make up hammer seals on top and bottom - Change oil in Agitators - Repair steam leaks throughout the Rig - Working on water lines - Berming around the rig - Run wires for RigMinder comms for office - Dress shakers with API 140 mesh screens - Welder welding on gussets for Conductor - Torqued up bottom flange on surface riser - Completed berming - Picked up excess herculite and felt that was trimmed off while berming - Completed dressing shakers with API 140 screens - Built 446 bbls spud mud, Total mud 1446 bbts - Continue plumbing service lines from reserve to Rig - Replacing ' 1a% W leaking steam hoses around the Rig - Layed out SLB tools for measuring and strapping - Layed down from rig floor short riser - Installed mouse holes - Connected pipe racks to pipe shed elevators - Loaded pipe shed with XT -54 drill pipe - Changed out grabber bodies on ST -100 - Mechanic working on dragon fire heater 13.0 12/26/2018 12/27/2018 Pick up and stand back 60 stands of XT 54 drill pipe. Rabbit with 3.625" teflon drift. Hook up all service lines from rig to reserve module. Wrap lines with re -enforced visqueen. Hook up electrical lines to reserve module. - Weld 45° 4" nipples onto conductor for surface cement job. Load shed with 14 HWDP joints. 12/27/2018 12/28/2018 Thaw out service lines from rig to reserve pit module. Pick up 2 stands of HWDP. Make up BHA#1. 17.5" bit/ bit sub XO to 5Y:" XT 54 DP. Pre spud meeting. Fill all lines and conductor. check for leaks. Spud well @ 1630 hrs. Drill to 308' to allow room for BHA#2. Pump out of the hole. 12/28/2018 12/29/2018 Drill rat hole from 267' to 310'. 750 GPM, 60 RPM, 8k WOB, Heavy chattering from cobbles and boulders. Formation changed to sand and clay @ 277'. MW= 8.8 PPG, VIS 135. BROOH two stands. Lay down bit, bit sub, XO. Service rig and lop drive. Pick up BHA#2 with crane assist. Unseated riser with stabilizer. Reset same. Complete BHA pickup. Tag bottom and begin Directional drilling, kick off @ 370'. Drill from 310'to 758' MD. 16.0 12/29/2018 12/30/2018 Directional drill 17''N' surface hole from 758' to 1768'. Back ream one stand out, to change out saver sub. Continue drilling from 1768' to 2430' MD. Building inclination to 45". www.peloton.com Page 2110 Report Printed: 312 012 01 9 WellView` Well Name: H04 BC - Daily Recap Daily Operations Rpt N SFmt Date End Dale Summary 17.0 12/30/2018 12/31/2018 Directional drill 17%" surface hole with rotary steerable Powerdrive. From 2430' to 3860' MD. 975 GPM, 140 RPM, 20k TQ, 2270 PSI PP. 30k WOB. Ream each stand. 18.0 12/31/2018 1/1/2019 Directional drill 17%1' surface hole with rotary steerable Powerdrive. From 3860' MD to 4910' MD. 975 GPM, 140 RPM, 20k TO, 2400 PSI PP. 30k WOB. Add 14 BPH water, blending in 50 BPH new mud. Ream each stand. 19.0 1/1/2019 1/2120191 Directional drill 17%1' surface hole with rotary steerable Powerdrive. From 4910' MD to 5810'. 975 GPM. 150 RPM, 20k TQ, 2600 PSI PP. 30k WOB. Add 14 BPH water, blending in 50 BPH new mud periodically. Ream each stand. Shoe to be set 80' MD below Upper Tyonek Coal #4, in a claystone. 20.0 1/2/2019 1/3/2019 Circulate and condition mud system. Lower MW from 10.7 PPG to 10.3 PPG, lower vis from 236 to 100.CBU 3x's. BROOH from 5810' MD to surface. Lay down BHA#2 with crane assist. 21.0 1/3/2019 1/4/2019 Safely retrieved all BHA components from 17%1' bit run to 5810. Clean and clear rig floor. Rig up to run casing. Repair damaged wire on pipe skate. Begin running casing to joint #4. Cross threaded connection between #3 & #4. Repair pin end on #4, remove collar from joint #3. (Heat and break out with rig tongs, Baker Loc'ed) 22.0 1/4/2019 1/5/2019 Run surface casing ( 13 3/8" L80 72# BTC) from joint #1 to Joint # 108. 4390'. 23.0 1/5/2019 1/6/2019 Continued to run 13 3/8" 72oof L-80 BTC casing to Sano'. IJD the CRT and R/U a circulating swedge and circulate a B/U. RID the circulating swedge and R/U the cement head and load bottom plug#1. R/U spider elevators. While continued to circulate and condition mud to 10.tppg and 33 vis Gear the rig floor of casing running tools. Cemented the 13 3/8" casing. 24.0 1/6/2019 1/7/201 Rig displaced 836.6 BELS 10.1 PPG spud mud. Bumped the top plug on strokes. Held 1250 PSI/ 500 PSI - over for 5 mins. Bled off. Floats held. Pull landing joint. Nipple down riser and well head adapter. Nipple up 31e MB222 wellhead. Test lower void to 2000 PSI for 15 mins. Verified by CoMan.Measure and cut a section of \12 herculite for spill containment in cellar, prepare for OBM. Level ground around cellar with pea gravel for secure footing. Begin to nipple up BOPE. Install adapter flange 13 5/8" 5k to 10k spool. Set stack on top. 25.0 1/7/2019 1/8/2019 Nipple up ROPE. Cameron 10k Stack. Change out mud pump liners from 6.5" to 6". Perform 16 BBL top job with SLB cementers. Conduct initial BOPE test with AOGCC Inspector. 26.0 1/8/2019 1/9/2019 Rig down test equipment. Rig down test joint, break off dart and FOSV valves. Continue to dean pits. Steam off XT 54 FOSV, and dart valves. Troubleshoot top drive counter balance system with Mechanic. Picked up 10 foot pup and a single to measure alignment issue of top drive. Centered top drive with'come-a-long'to measure offset distance. Lay down pipe. Remove off driller side torque rail. Lay down on rig floor. Remove lower trolley from top drive. Set on rig floor, mount new teflon shims. SIMOPS: Derrick man working on changing all three pumps over to 6" self adjusting ceramic liners. Pit watcher cleaning pits with Magtec. 27.0 1/9/2019 1/10/2019 - PJSM - Replaced shims and worn teflon pads from the trolley travel area - Simops: Cleaning mud pits - Removed end caps from suction line and dean out - Transfer 9.8 ppg OBM to reserve pits from tank farm - Complete sealing cellar area with herculite - Strap drill pipe to be picked up - Cleaning around rig - Spot Bulk Mixer around Reserve Pit area - Installed Dolly back onto Top Drive with new shims and teflon - Trouble shoot Top Drive Counter Balance - Checked Counter Balance Nitrogen level - Picked up 1 joint XT -54 and 10' pup and checked alignment on Top Drive - Installed Mouse Holes - Changed out Rig Tong heads - Secured BOP stack with chains and binders - Weighted up OBM in Reserve Pits to 10.5 ppg - Completed cleaning suction lines and installed end caps - Gathered equipment for picking up BHA - Elevators on Top Drive stopped functioning - Replace Ates valve - Pick up and make up BHA # 3, clean out assembly, and RIH picking up 5.5" XT -54 drill pipe 28.0 1/10/2019 1/11/2019 - PJSM - RIH with clean out assembly picking up 5.5" XT -54 drill pipe F/ 1,513'T/2,440' Drift each joint - RE - aligned Top Drive dolly Rails to make up saver sub into pipe at rotary table to fill pipe - Made up TDS into string and filled pipe - RIH with clean out assembly picking up 5.5" XT -54 drill pipe F/ 2,240'T/ 5,700', tagged up - Filled pipe every 20 stands - Circulated mud system until even mud weight in and out - Attempted 600 gpm - Mud too thick for flow line and shakers - Reduced pump rate to 300 gpm and circulated to improve circulating rate - 50% Flow rate -work string 5' to 10' while rotating - 60/RPM - 550 PSI - 145k/ Rot Wt - Circulate and condition mud while reciprocating pipe until trough and flow line could handle 500 gpm and mud weight the same in and out - Rigged up to Pressure test casing pumping down drill string and kill line - Break circulation down drill string and kill line - Close upper pipe rams and pump 5 bpm until 3000 psi - Total strokes 111 and 12.5 bblsum ed - Held 3000 psi for 30 minutes - Good test - Bled off pressure through super choke back to pits - 15.5 bbls returned - Blow down choke manifold and took SCRs - Drilling cement, float Collar and shoe track F/ 5,700'to 5,800' 75/RPM - 450/gpm - 790/psi - WOB/15-25k - Torque/10-20k - Rot Wt/ 150k - PU/WT 200k - Flow line began plugging up with thick returns - Picked up off bottom and reduced pump rate to 100 gpm with 475 psi and 100% flow line flow - Staged up to 400 gpm with 400 psi _ while rotating and reciprocating pipe - PIU Wt 200k - S/O Wt 120k - Rot WV 150k - Torquell 0-1 5k - 60/RPM 29.0 1/11/2019 1/1212019 Circulated and conditioned mud for displacing the well to MOBM. Displaced the well to 10.5ppg MOBM. POOH and rack back the BHA. Cleaned the rig floor. Pulled the wear bushing and ran the test plug. Made up test assembly - Filled BOP stack and choke manifold with water - attempted to fill TO hose, froze up - Thaw out hose - Tested BOPE and choke manifold to 250 psi low/ 3500 psi high for 5 minutes - Test alarms, PVT High/Low, Flow paddle alarm - Accumulator draw down test - Remove test joint and attempted to test blinds - choke hose frozen - Remove hose from BOP and thaw with steam - Change out wash packing to mechanical. Installed new motor on centrifuge pump.. www.peloton.com Page 3110 Report Printed: 3/20/2019 WeliView Well Name: H04 BC - Daily Recap Daily Operations Rpt# Stan Data End Date Summery 30.0 1/12/2019 1/13/2019 Thawed out the frozen choke hose. Installed the replacement valves for the top drive compensator. Installed the new motor for the centrifuge supply pump. Thawed out the frozen test pump. Removed the Tesco wash pipe and installed the Dublin mechanical wash pipe. Completed the BOPE test. Trouble shot the Rigminder " system and it began to work again. Drained the BOP stack and blew down all I Ines used for testing BOPE - Drained the test pump - Cleared the floor of test equipment and hoses - Cleaned out the flow box - Pulled the riser and replace O-ring in the upper hammer seal and gelled up around the top of the riser - Removed test plug - Picked up and made up 9 518" casing hanger and landing joint - Made dummy run and set hanger into wellhead - tagged @ 38'- Pulled hanger out of BOP, broke out hanger from landing joint and layed down with crane assist - Installed wear bushing and ran in lock downs with Vetco - Layed down test joint - Layed down Flex collars, Jars, and excess HWDP from derrick - Picked up new set of Jars with crane assist 31.0 1/13/2019 1/14/2019__ - PJSM - Layed down excess HWDP from the derrick with crane assist - Picked up BHA #4 Steerable assembly as per Directional Driller instructions with crane assist to 341'- Ran in hole with BHA #4 picking up 150 joints XT -54 drill pipe - Drifted each joint - Filled pipe every 20 stands - Performed shallow test on smart tools @ 2,400' and calibrated lock height - Checked smart tools again @ 4,094' as per DO with 700/gpm and 1350/psi - Monitored well on Trip tank - Continued RIH from derrick F/ 5,024'T/ 5,685'- Broke circulation and Took SCRs - Re,rn d Ft R5' fhm, h FI ,r GOUF @ c 748' n.._ gh _w ackio-Shoe.@5,&DD'_WItIL 750Igpm, 1650/psi, and 8OIRPM - Drilled Shoe @ 5,800', cleaned out rat hole, and drilled 20' of new hole to 5,830'- WOB/10-25k - 10-20k/Torque - 750/gpm - 1660/psi - Circulated and conditioned mud while reciprocating pipe until mud weight was 10.5 ppg in and out - Pulled inside casing to 5,774' for FIT - Broke circulation down the drill string and kill line - Performed FIT with 5 spm until pressure reached 520 psi on choke - EMW 13.2 -Held for 10 minutes mon' -pressure dropped to 380 psi - Pumped 2.8 bls and bled back 2.2 bbls - Blew down all lines used for testing - Lined manifold and BOP back up for drilling - Lubricated Rig - Stopped hydraulic leak on Top Drive - Drilled 12.25 hole F/ 5,830' T/ 5,963' as per DO & K&M parameters wfh20-25kNVOB - 120/RPM - 15-20k/Torque - 900Igpm - 2460/psi 32.0 1/14/2019 1/15/2019 - PJSM - Drilled 12.25" hole F/ 5,963' T/ 7,123' as per DO & K&M Parameters - 950-1000Igpm - 2940/psi - 140IRPM - 20-22k/Torque on bottom - 8k/Torque off bottom - 25-30 k/ WOB - P/U WT 185k - S/O WT 145k - ROT/ WT 165k - Max gas 410 units - ECD 11.2 ppg - Continued Drilling as per DO & K&M parameters F/7,125' T 8,590' - 980/gpm - 3100Ipsi - 25-30kNVOB - 25-32k/Torque on bottom - 18-24 k/Torque off bottom - P/U Wt 220k - S/O Wt 130k - ROTNVT 165k - Max gas 322 units - ECD 11.24 ppg - Took SCRs @ 7,653' MD & 4,624' TVD with 10.6 ppg - Serviced Top Drive, Drawworks, and Blocks 33.0 1/15/2019 1/16/2019 - PJSM - Drilled 12.25" hole F/ 8,590'T/ 10,000' as per DO & K&M Parameters - 985/gpm - 3290/psi - WOB/25-35k - RPMI140-160 - 20-24k/Torque on bottom - 8-10k/Torque off bottom - P/U Wt 245k - S/O Wt 145k - Rot Wt 190k - Max gas 600 units - ECD 11.22 ppg - Adding LVT @ 7bbl/hr- Serviced Rig - Drilled FI10,000' T/ 11,031' as per DO & K&M Parameters - Control drilled F 10,200'T/ 10,400'@ 100 FT/HR due to building mud in active pits - Drilled F/ 10,850'T/ 11,031'@ 200 FT/HT due to G&I unable to keep up with cuttings disposal - 990/gpm - 3820/psi - WOBI1 O -25k - RPMI140/160 - 18-22klrorque on bottom - 1 OkfTorque off bottom - P/U Wt 255k - S/O Wt 135k - Rot Wt 195k - Max gas 498 units - ECD 11.28 - Obtained Scrs - Serviced Top Drive and blocks, Monitored well on Trip tank- well static 34.0 1/16/2019 1117/2019 -Drilled FI 11,03V T 11,783' as per DO & K&M Parameters - 1000/gpm - 3730/psi - WOBI30k - RPM/160 - 20klTorque - P/U Wt 260k - 8/0 Wt 160k - Rot Wt 200k - Max gas 900 units - ECD 11.18 ppg - Lubricate Rig - Drilled F/ 11,783'T/ 12,346' as per DO & K&M parameters - 1000 gpm - 3950/psi - WOM/15-25k - RPM/140 -160 - 20-26k/Torque on bottom - 12klrorque off bottom - P/U Wt 285k - S/O Wt 140k - Rot WV 205k - Max gas 348 units - ECD 11.11 ppg - Changed pop off valve on #3 mud pump- Circulated and reciprocated pipe while working on pump - 750/gpm - 2425/psi 35.0 1/17/2019 1/18/2019 - Replace pop off #3 mud pump - Drilled F/12,790' T/ 13,698" as per DO & K&M parameters - 1000/gpm - 4100/psi - RPM/160 - 23k/Torque on bottom - WOB/25-30 - Rol Wt 220k - P/U Wt 310k - S/O Wt 135k - Max gas 349 units - ECD 11.02 - Serviced rig while taking SCRs - Power outage - Drilled F/13,698'TI 14,394' as per DO & K&M Parameters - 1000/gpm - 4136Ipjsi - WOB/2D-30k - RPM/140-160 - 20-28k/Torque on bottom - 16-18k1Torque off bottom - Max gas 106 units - ECD 11.12 ppg - Serviced Top Drive, Drawworks, Blocks, Crown, & ST -100 36.0 1118/2019 1/19/2019 - Drilled FI 14,394'T/ 14,974' as per DO & K&M parameters - 1000/gpm - 42201 psi - WOB/30k - RPM/140- 160 - 30k/Torque - P/U Wt 315k - S/O Wt 155k - Rot WU230k - Max gas 250 units - ECD 11.02 ppg - Drilled F/ 14,974' T/ 14,420' (TD) as per DD & K&M Parameters - 1000Igpm - 4290Ipsi - WOB/15-30k - RPMI140- 160 - 22-26k/Torque on bottom - 16k/Torque off bottom - P/U Wt 310k - S/O Wt 150k - Rot Wt 230k - Max gas 191 units - ECD 11.01 ppg - Began clean up cycle as per K&M instructions with minimum of 3 x bottoms up and rack back 1 stand each bottoms up - Had issues breaking 1st stand with saver sub - Slacked off to rotary table and broke saver sub with rotary locked - Pulled stand @ 10FT/Min and racked back - Performed clean up cycle as per K&M Parameters reaming @ 140 RPM & reciprocating pipe F/15,348' to 15,257' 37.0 1/19/2019 1/20/2019 - Performed dean up cycle as per K&M Instructions - Rotate and reciprocate pipe - 140/RPM - 18k/Torque - Serviced rig and obtained SCRs - Blew down TO and changed out saver sub while monitoring well on Trip tank, 3.5 bbl/hr losses - Back reamed out of hole F/ 15,348' T/15,060' @ 5 Ft/Min - 1000/gpm - 4350Ipsi - 140/RPM - 18k/Torque - Changed swab in #3 Mud pump, circulated and reciprocated pipe while working on pump with 700Igpm, 2360/psi, 120/RPM - Back reamed out of hole F/15,D60' T/14,720' @ 15 FUMin - 1000/gpm - 4375/psi - 140/RPM - 18k/Torque - 600 psi pressure loss, trouble shoot and change suction valve in #3 pump - circulated and reciprocated pipe while working on pump - 700/gpm - 2360/psi - Back reamed F/ 14,720'T/ 11,219 as per K&M instructions - Back reamed @ 5,10, 15 Ft/Min depending on ECDs and hole - 1000/gpm - 3800/psi - 14-18k/Torque - Rot Wt 190k - Max gas 397 units - ECDs 11.02-11.10 ppg www.peloton.com Page 4110 Report Printed: 3/20/2019 WellView° Well Name: H04 BC - Daily Recap Daily Operations Rpt# Start Date End Dale Summary 38.0 1/20/2019 1721/2619 - Back ream out of hole F/11,219' T! 8,400' as per K&M instructions - 1000/gpm - 3500/psi - RPm/140 - Max gas 285 units - 110-150 back ground gas - Back ream one stand slowly to allow shakers to clean up F/ 8,400' T 8,310'- Continue back reaming F/ 8.310'; T/ 6,700' as per D&M instructions - 1000/gpm - 3250/psi - RPM/140 - 12k/torque - ECD 11.06 - Max gas 183 units - Started packing off @ 6,633' - Slacked off to 6,702'and worked pipe @ 2 FVMin until shakers cleaned up - Back reamed out of hole F/6,612' T/ 5,920' @ 5 -15 FVMin as hole dictated - 1000/gpm - 4250/psi - RPM/140 - 7-10krrorque - String Wt 150k - Max gas 183 units - ECD 10.91 ppg - Stopped @ 5,920' and took strings Wts, P/U Wt 170k - SIO Wt 130k - Rot Wt 150k - Began pulling BHA through shoe @ 100/gpm & 180/psi F/5,920' T/ 5,818'- Hole packed off with 20k overfull and pressured up to 570 psi - Stopped pump and slacked string to 5,950'- Circulated and reciprocated pipe F/5,950' T/5,910 @ 1000/gpm - 2800/psi - Pulled BHA into casing F/5,910' T/ 5,778' no problems - -' Performed clean up cycles 39.0 1/21/2019 1/22/2019 - Performed dean up cycle, rack back one stand each bottoms up to 5,305'- 1000 gpm - 2750 psi - 120 RPM - 8k Torque -Flow checked 15 minutes - Blew down mud line and top drive -Fill trip tank -Clean rig floor - Cut and slip 110' of drilling line - Monitor well on Trip tank - 1/2 bb./hr losses - Service rig - Pumped dry job, blow down lines and TO - POOH on elevators F/ 5305'T/ 3,863'- Observedl Ok overpull and trending upwards to 20k @ 3,900'- Make up top drive and RIH to 3,995'- upon establishing circulation,observed packoff - Worked pipe and established full circulation and rotary - Reamed into hole T/ 4,182'- Back reamed out of hole F/ 4,182' T/ 1,837'@ 20 FVMin as per K&M instructions - 1000 gpm - 1800 psi - RPM 120 - String Wt 1301k - Circulate and reciprocate pipe F/ 1,837'T/ 1,746'@ 5 FVMin - 1000 gpm - 2000 psi - 120 RPM - 4k Torque - Circulated bottoms up x 6 - Back reamed F/ 1,746'T/996' @ 20 FVMin 1000 gpm - 1800 psi - RPM 120 - POOH on elevators to 340'- PJSM - Lay down BHA with crane assist - Monitor well on trip tank 40.0 1/22/2019 1/23/2019 - Lay down BHA with crane assist - Clear floor of all BHA tools and equipment - Bring casing tools and equipment to rig floor with crane - Monitor well on Trip tank - Drain stack, closed blinds and changed top rams to 9 5/8", changed wash pipe to Chevron style - Monitored well on Trip tank - Make up test joint, xo, and wear bushing running tool and retrieved wear bushing - Set test plug, filled stack and lines with water and tested rams 205/3500 for 5 minutes - Rigged down test equipment, removed test joint and plug - Changed out drilling bales and elevators to casing bales and elevators - Safely meeting with crews - Run 9 5/8" casing with Volant tool - Tanana inspecting threads and GBR confirming torque with torque graph - Filling pipe on the fly and topping off every 20 joints 41.0 1/23/2019 1/24/2019 Run 9.625" 47# P110 HYD 563 casing. From joint #62 to # 256. Filling each joint, top off every 20 joints. Good metal displacement. 42.0 1/24/2019 1/25/2019 Run 9.625" 47# P110 HYD 563 casin . From joint #256 to # 338. Filling each joint, top off every 20 joints. Good metal displacement. an anger on depth. Shoe @ 15406'. Circulate and condition mud system, wellbore. Rig up cementers. MU plug launcher and hardline, SLB loaded lines with 5 bbls water and checked for leaks. SLB pressure tested lines at 300 low 3500 high, good tests. Dropped first plug. Rig pumped 98 bbls 13 ppg MudPush II at 4 bpm and shut down. SLB dropped 2nd bottom Plu antl um ed 139.3 bbls (678 sx) 15.8 ppg Class G cement at 3.5 bpm.SLB dropped top plug, then displaced with 10 bbls weer. rM_rIlrpumped 10 BBLS 13 v1 ppg MP2 with no fiber @ 4 BPM 400 psi, followed by 1105 BBLS 10.5 PPG OBM. Slowed to 3 bpm with 40 bbl to go. (Rig pumped 12,068 strokes) Pumped half the shoe track. Did not bump the plug. Held 400 psi (FCP of 580 psi) for 5 minutes, bled off and floats held. Bled back 1/4 bbl into trash can on rig floor. Mix water temp at 70 deg. Pumped 50% excess . Did not attempt to reciprocate the string.CIP at 21:54 hrs, 01-24-2019. RD and released Schlumberger. 43.0 1/25/2019 1/26/2019 Lay down landing joint. Change out casing bales and elevators to drilling bales and elevators. P/U a stand, make up running tool to pack off. Set pack off in well head profile. LLDS. Test to 5000, 10 mins. good. Strap _ & tally 210 JTS 5" XT50 DP with pre-instaled W WT super sliders, pick up via mousehole and stand back. Cleaning pits, transfer 891 BBLS 10.5 ppg OBM to mud plant for centrifuging and storage in uprights 14,16,20. Change out casing rams to VBR's in upper pipe ram. - 1/26/2019 1/27/2019 Change out top pipe rams to VBR's (3.5" x 5.5"). Change out washpipe on top drive from Chevron style to Mechanical. Clean pits in active system and reserve module. Rig up to test BOPE. Test with State witness. One fail/pass, miscellaneous sensor went flat. Rig down test equipment. PJSM: P/U BHA#5 with Cruz crane assist. 45.0 1/27/2019 1/28`2019 TIH with BHA#5 to 2530' MD. Test MWD tools. TIP to 8765' MD. crew change. TIH to 15209'. Tag up on \� cement stringers. Stage pumps up to 465 GPM, 2400 PSI, Ream down to 15283'. One joint above float collar. Circulate and condition to achieve even MW in/out, Rio up test casing to 3500 PSI 30 mins Charted. Begin drilling shoe track. 46.0 1/28/2019 1/29/2019 Drill shoe track, and clean out to TO of 12%." hole. 15420'. CBU. Clean pits 1,5. Displace out 10.5 ppg OBM with 9.4 ppg MOBM. Clean pits, build volume. Drill 20 feet of fnew hole. CBU. Perform FIT to 13.5 PPG EMW. Build volume. 47.0 1/29/2019 1/30/2019 Build volume of 9.4 ppg CaCO3. Build base mud in Mud plant, ship to reserve module, add Megamul emulsifier, w,WglZt up to 9.4 ppg, ship 280 BBLS to active. Fill shaker pits. Drill 8W hole from 15440' to 16,828' MDCLOV 48.0 1/30/2019 1/31/2019 Directional do BIA" production hole L01 from 16,828' to 17,200. BROOK Install 48 NRDPP on stands 166 to 181. Open hole idetrack L01 back into Mother bore @ 16,060' drill 90° tangent to 16,455' MD. 49.0 1/31/2019 2/1/2019 Directional aril LO rom 16,455'to 18,230'. 515 GPM, 2700 PP, 251k TO, 160 RPM, 280k Up WL 120k Dn Wt, 200k Rot VVI7I 1.9 ECD, 9.5 PPG MW. www.poloton.com Page 5110 ReportPrinted: 3/20/2019 WeliView` Well Name: H04 BC - Daily Recap Daily Operations Rpt a Stan Data End Date Summary 50.0 2/1/2019 2/2/2019 BROOH to 16840'. Trench from 16840'to 16860'. Drill from 16860'to 17620'. Begin drillinL03 17620'. Drill L03 to 17,957' MD. 51.0 2/2/2019 2/3/2019 Directional drill 8'/:" hole with rotary steerable system from 17957' to 19,017'. Lost 15 BBLS in 4 mins, 225 BPH. Slowed pumps down. Staged pumps back to 400 GPM. 25 BPH loss rate. Pump 50 BBLS LCM, 30#/BBL, slowed losses to 12 BPH. BROOH to 18,625'. Placing NRDPP on each stand coming out. 52.0 2/3/2019 2/4/2019 Service Rig. BROOH from 18625' to 17,31V MD. Repair top drive, cylinder on compensator. Pumping 350 GPM, well static. Complete repairjob. BROOH from 17,310'to 15,354' MD. Inside casing. 53.0 2/4/2019 2/5/2019 BROOH from 15354' to 14849'. Aftemnpt to puff on elevators from 14849 to 14655, drag increased 35k, would not break over. Continue BROOH from 14,655'to 8100' MD. Good hole fill. Well static. Some of the XT54 will have to be laid down. 54.0 2/512019 2/6/2019 BROOH from 8100* To 7081. POOH on elevators to the BHA. Lay down BHA with crane assist. clear and clean rig floor, adjust Baylor brake, hang two SLR's in derrick. TIH w/ 25 stds. 5" DP, Prepare to come out side ways. Worn hard banding. 55.0 2/6/2019 2/7/2019 - PJSM - Lay down 5" DP - assist W WT with removal of NRDPPs on each joint, clean each joint with passing of sponge ball with Magtec Vac assist - Repair alignment of pipe skate and beaver slide with shims - Lay down 5" DP(total 75 jnts), Monitor well on trip tank - Remove XOs from TD, change inserts on elevators to 5.5" - RIH with 51 stands of 5.5" DP - Service Rig - POOH laying down 153 joints of 5.5" DP cleaning pipe in pipe shed with sponge ball with Magtec Vac Truck assist - RIH with 41 Stands 5.5" DP from derrick - POOH 11 Stands inspecting with Premium - Continue POOH laying down 5.5" DP and cleaning in pipe shed with sponge and Magtec Vac Truck assistance 56.0 2/7/2019 2/8/2019 - PJSM - POOH and layed down 71 joints of 5.5" XT -54 DP(total 249 XT -54 UD). - Washed each joint in mouse hole and cleaned inside of joints with sponge ball using Magtec Vac Truck in pipe shed - Cleaned rig floor - Prepared lest tools, removed wear bushing, and installed test plug - Tested BOPE with 5" & 5.5" DP 250/3500 psi low/high for 5 minutes - Performed accumulator draw down test and check Nitrogen x 6 bottles @ 2400 psi - Removed test plug and installed wear bushing, layed down test equipment - Placed tree into cellar with crane - PJSM with crane crew and picked up BHA #6 to 161'- Cleaned rig floor and readied tools for picking up 5" XT -50 DP - RIH picking up (75) joints of 5" XT -50 DP to 2,530' monitoring well on trip tank - Filled pipe every 20 stands - ( Performed shallow test with Directional tools @ 1,774', good test) - Serviced rig - RIH with 5" XT -50 DP from derrick removing NRDPPs to 2,721' monitoring well on Trip tank 57.0 2/8/2019 2/9/2019 - PJSM - RIH with 5" XT50 DP from derrick removing all NRDPPs from each stand F/ 2,721' TI 6,800', monitoring displacement on trip tank and filling every 20 stands - Service Rig - C/O elevator inserts to 5.5" and RIH picking up 5.5" HT -55 DP from pipe shed F/ 6,800'T/ 13,624', drifting each joint - Monitor well on trip tank and filling pipe every 20 stands ( NRDPPs were installed before picking up DP on pipe racks and pipe shed as per pre -job plan of placement depths) - RIH picking up (36) joints of5.5" XT -54 F/ 13,624' T/ 14,755' monitoring well on trip tank - Fill pipe every 20 stands - RIH with 5.5" XT -54 DP from derrick F/ 14,755'T/ 15,315' monitoring displacement on trip tank - Circulate and condition until Mud Wt infout the same, 9.5 ppg - Hang blocks - Slip and cut drilling line 58.0 2/9/2019 2/10/2019 - Repaired hydraulic line cutter - Monitored well on trip tank - Cut and slipped 100' of drilling line - Tightened deadman clamp, installed drawworks guard, installed SLM hook load sensor - Calibrated Rigminder block height and observed starting wrap on drum was not properly seated - Unpooled wraps on drum and respooled OK - Calibrated Rigminder block height and SLIM hook load sensor - Monitored well on trip tank - Performed Mad Pass and confirmed depth correlation to be correct and all smart tools functioning properly - RIH F/ 15,472' T/ 17,570'- Filled pipe every 10 stands - SOW 135k - Circulated and conditioned mud while reciprocating and rotating pipe F/ 17,570' T/ 17,650' with 400/gpm - 1900/psi - 22-28k torque - Trenching F/ 17,670 T/ 17,690' - Kick o0 and time drilling F/ 17,690'T/ 17,716'- Drilling L04 F/ 17,716'T/ 17,865' as per DO parame rs 59.0- -d 2/10/2019 2/1112019 - DrillinL04 l 17,865' T/ 19,635' as per Directional Driller and K&M parameters - 160/RPM - 470/440/gpm - 2300122 si - WOB/10/25k - 24-26k/Torque - P/U Wt 310k - S/O Wl 135k - Rot Wt 210k ECD 11.58 ppg - - Max gas 255 units Take SCRs every 500' drilled, serviced rig while performing SCRs _ 2/1112019 2/1212019 - Drilled L04 F/ 19,635'T/ 20,094' (TD) as per Directional Driller & K&M parameters with 450/gpm - 2100/psi - WOB/10-12k - 160/RPM - 26k/Torque - P/U Wt 3DOk - Rot Wt 210k - ECD 11.65 ppg - Max gas 126 units - Picked up off bottom, stopped rotary, recycled pumps, and took final survey - BROOH F/20,094' T/ 18,320' as per K&M parameters with 430/gpm - 2100/psi - 160/RPM - 24klforque (5 ft/min F/ 20,094'T/19,918'& 15 ft/min F/ 19,918' T/ 18,320') - Reamed F/ 18,320'T/18,420'- Trenching F/ 18,420' T/ 18,4 dh 160/RPM - 24kITorque - 450/gpm - 2150/psi - 0-8k/WOB - ECD 11.26 ppg - Time drilling for sidetrac LO5 118,440' T/ 18,454'- continue drilling original hole F/ 18,454'T/ 18,550' as per DD & K&M parameters W 160/RPM - 24 -28klrorque - 450/gpm - 2150Ipsi - 15/23kIWOB - ECD 11.44 ECD - PIU Wt 330k - S/O 135k - Rot Wt 218k 61.0 2/12/2019 2/13/2019 - Drilled ahead in L05 FI 18,550'T/ 19,071' as per DO & K&M parameters - 180/RPM - 24-26k/Torque - 440/gpm - 2150/psi - WOB/10-15k - P/U Wt 330k - SIO Wt 135k - Rot Wt 215k - ECD 11.55 - Max gas 200 units - Changed oil and fitters in lube oil pump on Top Drive - Drilled F/ 19,071' T/ 19,888' as per DO & K&M parameters - 180IRPM - 24-28k/Torque - 440/gpm - 2200/psi - WPB/10-15k - P/U Wt 310k - Rot Wt 215k - ECD 11.71 ppg - Max gas 258 units - Mud Wt in 9.2 ppg - Mud Wt out 9.3 ppg ( The LOS build section started @ 19,197' with 3°/100' build rate) 62.0 2113/2019 2/14/2019 - Drilled L05 F/ 19,888' T/ 20,664" as per DD & K&M parameters - 180/RPM -74--28k/Torque - 430Igpm - - --- 2230/psi - WOB/10-15k - P/U Wt 320k -ROT Wt 2081k -Max gas 193 units - 11.80 - Changed lube oil pump discharge filter - Drilled L05 F/ 20,664'T/ 20,735' (TD) as per DO & K&M parameters - 180/RPM - - ' 26k/Torque - 440/gpm - 2250/psi - WOB/8-14k - PIU Wt 305k - Rot Wt 2081k - ECD 11.84 ppg - Max gas 193 - - units - BROOH F/ 20,735 T/ 19,541' as per K&M parameters - RPM/150 - 24-26k/torque - 440/gpm - 2200/psi - ( Pulled T/ 19,440'@ 3 ft/Min & pulled T/ 19,541 @ 10 ft/Min) - Inspect NRDDPs while coming out of hole www.peloton.com Page 6/10 Report Printed: 3/2012019 WellView Well Name: H04 BC - Daily Recap Daily Operations Rpt# Stan Data End Date Summary 63.0 2/14/2019 2/15/2019 - BROOH F/ 19,541'T/ 19,163' as per K&M parameters - 140-150/RPM - 26k/Torque - 440/gpm - 2200/psi - Rotating P/U Wt 200k - Adding 8.0 ppg pre mix mud into system to maintain 9.2 ppg - Blow down TO and rig up to circulate @ 2001gpm with FOSV & side entry sub - Remove wash pipe and change out upper quill seals, change oil and filters and install new wash pipe - R/D circulating assembly, establish circulation and rotary, work pipe 60'- R/U circulating assembly and circulate @ 200/gpm - Change out saver sub - Rig Service - / circulating assembly 64.0 2/15/2019 2/16/2019 - Drilling O6 / 19,513' TI 20,855' as per DD & K&M parameters - 170-190/RPM - 24-28k/Torque - 440- 450/gpm - 25/psi - WOB - 10-15k - P/U Wt 330k - Rot Wt 205k - ECD 11.76 ppg - Max gas 181 units - Took SCRs every 500' 65.0 2/16/2019 2/17/2019 -Drilled LO6 F/ 20,855' T/ 21,358' (TD) as per DO & K&M parameters 0 RPM/190 - 26klforque - 450/gpm - 2445/psi - WOB/10-15k - P/U Wt 325k - Rot Wt 210k - ECD 12.8 ppg - Max gas 135 units - BROOH F/ 21,358' 7/21,172' @ 3 ft/min & F/ 21,172'T/ 19,917' @ 15 fUmin - 160/RPM - 440/gpm - 2400/psi - Ream back to 20,009'- Flushed Top Drive gear box with HD32, Drain, and changed suction screen and discharge filter- Filled with 75W-90 new oil - Cleaned washpipe and lubricated quill seals - Circulated @ 200/gpm while servicing - Reamed down F/ 20,009'T/ 20,018'- Trenched F/ 20,018'T/ 20,038' as per DO parameters - 440/gpm - 2200/psi - 160/RP Time drilled F/ 20,038'T/ 20,050' - WOB/15k - 160/RPM - 26k/Torque - 440/gpm - 2200/psi - Drillin L07 / 20,050' T/ 20,060' - 160/RPM - 26-28k/Torque - WOBI15k - 440/gpm - 2200/psi - P/U Wt 325k - Rot 210k - ECD 11.34 ppg - Pumps shut down, Picked up off bottom, cycled pumps, found plugged jet, alternated parameters and cleared bit 66.0 2/17/2019 2/18/2019 - Drilled L07 FI 20,067'T/ 20,394' as per DD & K&M parameters - 190/RPM - 24k/Torque - 450/gpm - 2330/psi - WOB/15k - P/U Wt 315k - Rot Wt 210k - ECD 11.68 ppg - Max gas 62 units - Low lube oil psi shut down TO - Changed discharge filter & serviced rig while circulating @ 200 gpm - Drilled L07 FI 20,394' T/ 20,760' as per Dd & K&M parameters - 190/RPM - 26k/torque - 450/gpm - 2350/psi - WOB/10-16k - P/U Wt 325k - ROT Wt 210k - ECD 11.7 ppg - Max gas 154 units - Took SCRs every 500' drilled - Drained oil out of TD, Replaced lube oil pump and filters, filled with new 75W-90 oil & circulating @ 200/gpm - Serviced rig - Drilled L07 F/ 20,760' jT/ 20,872' as per DO & K&M parameters - 190/RPM - 23-26k/Torque - WOB/10-17k - 450/gpm - 2400/psi - P/U Wt 320k - Rot Wt 210k - ECD 11.63 ppg - Max gas 122 units 67.0 2/18/2019 2/19/2019 - Drilled L07 F/ 20,872' T/ 21,148' as per DO & K&M parameters - 190/RPM - 24k/Torque - WOB/15-30k - 460-475/gpm - 2425/2625/psi - P/U Wt 335k - Rot Wt 220k - ECD 11.82 ppg - Max gas 117 units - TDS shut down due to low oil pressure - Stand back one stand and drain oil in TO - checked lube oil flow sensor - Filled with new oil and changed filters - Drilled L07 F/ 21,148' TI 21,260' as per DD & K&M parameters - 190IRPM - 27k/Torque - WOB/15-22K - 475/gpm - 2650/psi - P/U Wt 340k - Rot Wt 230k - ECD 11.94 ppg - - Max gas 116 units - Drilled L07 F/ 21,148' T/ 21,830' as per DD & K&M parameters - 190/RPM - 24- 26k/Torque - WOB/15-20k - 475/gpm - 2600 psi - P/U Wt 335k - Rot Wt 205k - ECD 12.11 - Max gas 127 units - Took SCRs every 500' drilled. 68.0 - 2/19/2019 2/20/2019 - Drilled L07 F/ 21,830' (TD) as per DO & K&M parameters - 160/RPM - 24-26kfrorque - WOB/12-20k - 465/gpm - 26501psi - P/U Wt 345k - Rot Wt 210k - Max gas 70 units - ECD 12.11 ppg - Took surveys and SCRs - BROOH L07 F/ 21,966'T/ 20,758 as per K&M parameters - 160/RPM - 28k/Torque - 465/gpm - 2650/psi - Service Rig - Establish parameters and begin Trenching as per DO FI 20,800'T/ 20,820' as per DO parameters - 150/RPM - 24k/Torque - 465/gpm - 2525/psi - Tir5is.QVIIlng F/ 20,820'T/ 20,834' as per DD Parameters- 150/RPM - 24kfrorque - 465/gpm - 2525/psi - DrillinLO F/ 20,834' T/ 20,853' as per DD & K&M parameters - 180/RPM - 26kfTorque - WOB/15k - 465/gpm psi - P/U Wt 330k - Rot Wt 205k - ECD 11.67 ppg - Take SCRS - Top Drive shutting down - Change Flow paddle on TO lube system & circulate @ 200/gpm - Drilling L08 FI 20,853'T/ 20,867' as per DO & K&M parameters - 180/RPM - 26kfrorque - WOB/15k - 465/gpm - 2500/jpsi - P/U Wt 330k - Rot Wt 205k - TDS continued shutting down - Switched spare wires in service loop - Serviced Rig - TDS persisted to shut down - TO L08 was called @ 20,867'- Changed oil and filters on TDS and BROOH F/20,867' TI 20,830' @ 1 1/2 fvmin circulating bottoms up each stand reamed - 160/RPM - 29k/Torque - 465/gpm - 26001psi - BR P/U Wt 210k - ECD 11.65 ppg 69.0 2/20/2019 2121/2019 TO of H04 Mother bore @ 20867'. BROOH from 20830' to 20385'. 470 GPM, 150 RPM, 29k TQ, 15 to 207min. slight pack off seen @ 20385'. Drop back in 10 feel, pulled slower, and it cleaned up. BROOH from 20385'to 17,105' MD. Maintain 470 GPM, 160 RPM, 22k TO. Encountered minor cuttings beds from 17,556' to 17,105'. Shakers unloaded. 100% increase in cuttings load seen on shakers. 70.0 2/21/2019 2/22/2019 BROOH from 17,105'to 15,658'. Varying pulling speeds with downhole conditions. Full drilling parameters. CBU two stands below shoe from 15,668 to 15,595'. Pulled into casing with no rotary. No drag seen. Back ream out 3 stands into the casing from 15,408 to 15,130. Monitor well, static. Make up Halliburton storm packer and hang string off 65 feet from floor. Rig up and test ROPE. Witness waived by AOGCC. 71.0 2/22/2019 2/23/2019 Complete Koomey draw down test. Blow down choke manifold. Rig down test equipment. Drain stack Pull - - test plug. Set wear ring. Retrieve storm packer. Rig up filter cart, and pump TO gear oil through for one hour. (New filters were dirty after job). RID cart. BROOH from 15,128' to 10,060' MD. Monitor well on active pit system. Good hole fill. 72.0 2/23/2019 2/2412019 Continue to BROOH from 10,060'to stand #11. 1203' b8 depth. CBU. Monitor well. Static. Drop Gyro. POOH on elevators to 634' MD. 73.0 2/24/2019 212512019 Trip out of hole on elevators. Gyro surveys recorded each stand to shrink the ellipse of uncertainly or future well planning. Lay down BHA#6. Bit grade 2 -3 -BT -A -X -1 -CT -TD. Clean and clear rig floor of BHA components. Prepare to run 4%" liner. Load pipe shed with hanger and PBR with crane. Set GBR power tongs and graphing system on floor. Rig up. Remove drilling bales and elevators. Install casing bales and elevators. Install HT55 saver sub. Pick up first joint and baker loc silver Bullert shoe. Run 145 joints of 414" P110 HYD 563 15.2# liner. AVG torque=8200 itAns. Remove rasing bales and elevators. Install drilling bales and elevators. Pick up hanger/PBR,XO. Make up to casing string. Mix up 5 gallons of "palmix", pour into top of hanger, lel set up for 20 mins. Trip in hole to 5686.22' (Length of liner and running tools). www.peloton.com Page 7110 ReportPrinted: 3/20/2019 WeliView Well Name: HO4 BC - Daily Recap Daily Operations Rpt n Stan Date End DateSummary 74.0 2/25/2019 2/26/2019 RIH on elevators with 5A" DP. 5672' of 41A" liner. From 5688' to 15,300'. Removing all super sliders. Drifitng each stand. Record up down weights, and rotating weight. Trip into the open hole, 307min to 17,205' MD. Entered 1-01. Stack weight out. Pump out of the lateral to 16,644', 120 GPM, 450 PP, 290k Up. 75.0 9 2/2612019 2/27/2019 Continue to pump out from 16,644'to 15,892'. Shuffle pipe in derrick to allow the Driller to use derrick S camera. Observed that top drive main seal on pipe handler was leaking, Pump/ream past 1-01 exit point, (15,894' to 16,113) 120 GPM, 20 RPM. No hole drag observed. TIH 6 stands to 16,738'. Pump/ream past depth of L02 exit point. ( 16,738' to 16,925'). TIH on elevators. Tagged TO of LOt a second time @ 17200'. Pump out of the hole for a clean out run to 14,670'. Continue to pump out of the hole 120 GPM, 270 PP. to _ 12,518. Change saver sub to HT55. Pump out of the hole to 9645' MD. 76.0 2/27/2019 2/28/2019 Continue to pump out of the hole w/ 120 GPM, 175 PP from 9645' to 9362'. Change out grabber dies in R. Pump out to 5686'. Lay down hanger assembly and PBR. Inspect partly disassembled top drive blower motor. Discover two fan blade fins missing, unable to retrieve with magnet tool.POOH laying down liner. d Vacuuming wiper ball through all blank joints, wrapping each slotted joint with shrink wrap. AVG break out 14 torque=7500 f tabs. Monitor well on trip tank. Achieving calculated hole fill each 15 joints. Lay out liner in running order. Lay down 75 joints. One joint damaged. 77.0 - 2/28/2019 3/1/2019 Trip out of the hole, lay down 145 joints of 4Y2" P110 HYD 563 15.2# liner and hanger. Prepare to pick up BHA#7 clean out assembly. Fly old hanger out of pipeshed with crane. Dis-assemble top drive. Expose blower motor, remove radiator, fan cover, electrical cover. Search for two missing fins from squirrel cage fan. Filler TO gear oil through fitter cart. Electrician continue to work on lop drive blower motor, able to retrieve one fin. Mechanic relieved Electrician and continued the work. Remove second fin. SIMOPS: clean clear rig floor, steam MOBM in pits, steam brine in reserve module. Assist welder in shop. 78.0 3/1/2019 3/2/2019 Slip and cut 100' of drilling line. Service draw works, check torque on bolts under draw works. Good. Calibrate block height. Drain gear oil from top drive main gear box. Pin point leak source. The rig has the correct replacement flanged seal in stock. Install new rig floor Rig Minder screen. Replace leaking hose in ST100. Drain mud leg in poor boy. Remove drilling bales and elevators. SIMOPS: Inventory XO's in connex. Clean off BOPE. Repair heaters in the cellar. Maintain active MOBM and brine in reserve pits @ 90°. Monitor well on TT. Close blinds. Fill hole every 6 hours. Wait on top drive Techs and parts. 79.0 3/212019 3/312019 Clean and clear rig floor for top drive work. Blow down choke manifold to poor boy. Blow down top drive. SIMOPS: Wash BOPE in cellar, replace valves in pits. Extend exhaust stack to pit room rig vacuum system.Assist welder. Monitor well on TT. still taking % bbllhr average. Tesco hand arrived @ noon. Assist Tech in tearing down top drive. Complete tear down, swap out Flanged Seals. top drive was re -assembled to the rotary bushing. Test ran. Good. Continue to put the top drive back together. 80.0 3/3/2019 3/4/2019 Re- assemble lower top drive section with Tesco Technician and Mechanic. Service mechanical wash pipe. Remove HT55 saver sub. Install XT54 saver sub. Change out grabber dies on top drive. Mount drilling bales and elevators. Install new mechanical wash pipe. Install new blower motor fan, guards. Safety wire tie all bolts on top drive. Function robotics and blower motor. All tests good. Monitor well on TT. Fill every 6 hours. Hole took 2 bbls in 12 hours. Pre Job safety meeting with crane crew / DD. Pick up BHA#7 clean out assembly. TIH 15 stands of HT55. Pump, test MWD. POOH to lay down 32 joints of HT55 for hard banding. Single in with 31 joints of good HT55. Run 4 stands of DP to 1556'. 81.0 3/4/2019 3/5/2019 Trip in the hole with HT55 DP from 1560'to 4990'. Started with 213 joints in derrick. Laid down 95, picked up 44 new joints of HT55. 54 stands in tally. Crossover to 5" XT50 DP. Manage 5" DP. Lay down 154 joints, keep 56 joints. 82.0 3/5/2019 3/6/2019 Continue drill pipe management. Premium Inspector on the rig floor removing all worn joints from the tally. Lay down joints of XT50 from 6077'to 7086'. total laid down 154. Pick up 133 joints of newly hard banded XT50. 189 total in the new tally. Manage XT54 OF. Lay down 72 joints. Strap and tally 99 joints of XT54. Single in with 80 joints to 14,920' MD. 83.0 3/6/2019 3/7/2019 - Single in hole with XT -54 DP F/ 14,920'T/ 15,046' -M1U TO and stage up pumps to 400/gpm - Rotate pipe 20/RPM and reciprocated pipe F/ 15,042'T/ 14,955' looking for leaks on TD, minor leaks - Changed out ODS tugger line - Blow down TO - Picked up remaining 18 joints of XT -45 with single joint elevators and racked back in derrick - Monitored well on TT - Made up RTTS on string and RIH to under wellhead and hung off drill string- Drained stack, removed wear bushing, installed test plug - Made up test assembly and performed shell test, good test - Tested BOPE with 3.5" & 5" test joints with AOGCC witness Austin McCleod - Blind rams test failed due to #3 CMV - Repaired CMV #3 and tested Blinds with AOGCC witness - All test good - Rigged down test assembly and test plug and installed wear bushing - Made up RTTS running tool and retrieved RTTS and drill string - Layed down RTTS tools - RIH to shoe - staged up pumps to 400/gpm &1,575/psi - no losses Exited through shoe and reamed to 15,591'- Correlated depth of shoe using MWD tools, OK - Circulated and conditioned mud while reciprocating pipe - Monitored TO for leaks www.peloton.com Page 8110 Report Printed: 3/2012019 WellView Well Name: H04 BC - Daily Recap Daily Operations Rpt # Start Date End Dale Summary 84.0 3/7/2019 3/8/2019 - Reamed F/ 15,594'T/16,040'- 450/gpm - 120/RPM - 23-28k/Torque - Max speed 30 ft/min - Steer bit to low side and pass X 3 F/ 16,040'T/ 16,077' as per plan - Ream tercel reamers F/ 16,115' T/ 16,192' - BR T/ 16,050' - With bit to high side passed through junction to ensure remain in mother bore - Test successful - TIH on elevators F/ 16,262' 7/16,354' - Removed ODS line guide from drilling line due to sheared roller- TIH on elevators F/ 16,354'T/ 16,840'- Ream L03 junction X 2 F/16,840' T/ 16,890' on low side orientation - Continue reaming with tercel reamers X 2 F/ 16,915' T/ 16,992' - 450/gpm - 1985/pjsi - 140/RPM - 26- 28k/torque - Rot Wt 205k - RIH on elevators F/ 16,992'T/ 17,650'- Remove NRDPPs while running in hole - Reaming Junction L04 with bit on low side X 2 F/ 17,670'T/ 17,710'- Continue reaming with tercel reamers X 2 F/ 17,745' T/ 17,822'- 450/gpm - 2100/psi - 140/RPM - 22-36k/torque - Rot Wt 200k - RIH on elevators F/ 17,822' T1 18,420'- Remove NRDPPs while tripping in hole - With bit on low side, ream X 2 L05 junction F/18,420' T/ 18,460'- Continue reaming junction with tercels F/ 18,495' T/ 18,572'- 450/gpm - 2100/psi - 140/RPM - 22-36k/Torque - Rot Wt 200k - Serviced rig and circulated @ 260/gpm with 900/psi while - removing drilling line guide from derrick - RIH on elevators F/ 18,572'T/ 19,200'- Remove NRDPPs while RIH - Reamed LO6 junction with bit on low side F/19,200' T/ 19,240'@ 450/gpm - 2130/psi - 140/RPM - 22- 36k/Torque - Rot Wt 200k - RIH to 19,260' - .. 3/812019 3/9/2019 Reamed into the hole 19,260'to 19,275'. Worked both tercell reamers across the L06 junction X2 19,275'to 19,352'. Serviced the TD and acquired slow pump rates. RIH on elevators 19,352' to 20,018'. Reamed the L07 junction with the bit X2 20,018'to 20,058'. Reamed the Tercel reamers across the L07 junction X2 20,093'to 20,170'. Continued to ream into the hole 20,170' to 20,780' and dressed the L08 junction X2 20,780'to 20,820'. Continued to ream down and tag bottom 20,867'. Began cleanup cycles 20,867' to 20,388'. The grabber dies failed at 20,388' while backing out the top drive. While attempting to ream back down into the hole to get the top drive at floor level the pump pressure increased and the top drive stalled. Rotation and circulation were reestablished and the stand was worked from 20,388'to 20,480' until it cleaned up(had partial packoffs and erratic torque at 20,411' and 20,403'). The top drive was brought to floor level and the grabber dies were changed. Back Reamed out of the hole F/ 20,480'T/ 18,420'@ 5-15 ft/min as hole dictated. 450/gpm - 2200/psi - 150/RPM - 28k/JTorque - Rot Wt 190k. Worked down through L07 & L06 junctions, no issues to remain in mother bore - 86.0 3/9/2019 3/10/2019 Checked bolts on top drive rails OK. BROOH 18,420'to 18,141'. Troubleshot top drive brake problem and had to change out the encoder while circulating at 18,141'. B/R one stand 18,141' to 18,044'.Toubleshot the rigminder system while rotating and reciprocating at 18,044' to 17,950'. Installed the drawworks fast line guide while troubleshot the rigminder. BROOH 17,950' to 15,535'. Verify high side pass on L04, L03, and L02 junctions, OK. Pumping out of hole F/ 15,535'to 15,323'@ 5-10 ft/min. No overpull observed while pulling BHA through the shoe. Flow checked well @ shoe, Static. Performed clean up cycle by BROOH @ 1.5 it/min X 3 bottoms up F/ 15,323'to 15,136' 450GPM/2000PSI 15ORPM 20-38k TO. Serviced Rig. 87.0 3110/2019 3/11/2019 Pumped out of the hole 13,166' to 11,298'. Changed out equipment to pump out 5" XT -50 DP. Monitored the well on trip lank, static. Pumped out of the hole 11,298' to 9583'. Performed clean up cycles while B/R out 9583' to 9394'. POOH on elevators 9394' to 8919'. Hole did not take any displacement. Checked flow, static. Pumped out of the hole 8919'to 5218' SLM. Changed elevators to 5.5". Pulled one stand of HT -55 and observed swabbing. Change saver sub from XT -50 to HT -55. Pumped out of hole F/5218' T/ 2138' 1 OOGPM/350PSI PUW 160k. SLM. Monitor well on active system. Good displacement 88.0 3/11/2019 3112/2019 Pumped out of the hole 2138' to 1850'. Circulated B1U X —2while POOH 1850' to 1752'. POOH on elevators 1752'to 118'. UD BHA#7 with crane assist. Loaded the pipe shed with the liner hanger and 4.5" liner. Blew down the topdrive and cleared rig floor of equipment. R/U to run the 4.5" liner. P/U the flex shoe and loaded the bottom 6' pup with 1 s barite. Test the casing tongs on joint#2. Trouble shoot the casing tongs and changed out the load cell and power unit. Tested the tongs OK. Ran 4 1/2" slotted liner with Tenaris inspecting treads and torque tum on each connection to 5615' ( every other joint slotted with the last 5 joints solid to be in the lap). Monitored the well on the trip tank. Good displacement. Removed the casing bails and elevators and installed the drilling bails and elevators. Picked up the PBR and Hanger and made up same. Made up the Hanger assembly to the Liner string. Added Pal mix as per SLB. Picked up first stand of HT -55 DP and drifted. Made up to Liner string and RIH to 5752'. Monitored well on TT. Broke circulation to ensure Hanger assembly was clear with 2.5 bbls/min 10OPSI PUW 125K SOW 115K. Serviced Drawworks, Top Drive, Blocks, & ST -100. Monitored well on trip lank while servicing rig. Static 89.0 3/12/2019 3/13/2019 Ran 4.5" Liner on 5.5" HT -55 DP F/ 5752' to 10,870'. Drift each stand. PUW 125K SOW 115K. Monitored well on Trip lank. BOP Drill. changed saver sub from HT -55 to XT -54, monitored well on TT. Picked up 15 joints of 5.5" XT -54 DP and RIH to 11,388'. Drifted each joint and monitored well on trip tank. RIH with Liner on 5.5" XT -54 DP from derrick F/ 11,388' to 15,372' drifting each stand. Parameters before exiting shoe, 85GPM/475PSI, PUW 265K SOW 150K ROW 200K 1 ORPM 16-18K Torque. Pump dry job and RIH with Liner to 20,379'@ 30-60 ft/min SOW 150K Monitor well on TT. Reamed Liner to bottom F/ 20,379' to 20,867' with 15RPM/28-30K Torque Tagged bottom with 10K. Picked up to 310K plus 2'. Set slips and drop 1.5" ball. Pumped ball down with 3.5 BPM 850/psi for 3400 stks. Slowed pump to 2 BPM with 577/psi. Observed ball hit seat and pressured up to 750 psi and then bled quickly off with pump running. Attempted this several times without success. Bring on pumps to 750/9pm & 3600 psi in attempt to set hanger. No success www.peloton.com Page 9/10 ReportPrinted: 3/20/2019 WellView' Well Name: H04 BC - Daily Recap Daily Operations Rpt # Start Date Ertl Date Summary 90.0 3/13/2019 3/14/2019 Set hanger mechanically using secondary procedure. Picked up string to 360K and slacked off to 220K. Applied 4 rounds of left hand torque and locked in with 15K. Worked torque downhole. Repeated this process X 2 and observed packer set @ 100K down weight. Picked up to 220K and rotated and verified packer set and Drill sting released. Lined up down the backside with annular closed and tested packer. Leaked. Slacked off and stacked weight to 98K and picked up to 220K. Tested packer to 2350 psi for 15 minutes. Good test.Picked up string to 15,288' and CBU @ 450/GPM/1325PSI. PJSM and displaced the 9.4 ppg MOBM from the hole to 9.2 ppg Brine. Flushed TT line and cleaned TT, 2 X suction pits, troughs, and - shakers. String was u -tubing. Mixed and pumped 9.9 ppg slug and POOH laying down 5.5" DP F/ 15,288'to 6437'. Flushed each joint with fresh water. Monitored well on Trip tank. Serviced Rig ( Blocks, crown, TDS, drawworks, and ST -100) 91, 3/14/2019 3/15/2019 POOH laying down 5.5" DP from 6437' to 40'. Pulled liner running tool to surface, inspected, and layed down. Change elevator inserts and continue to lay down XT -50 DP from the derrick via mousehole. Monitor well on Trip tank. Cleaned Rig Floor. Drained BOP. Removed wear bushing. Made up Tubing hanger to Landing joint and made a dummy run. Verified placement. Layed down hanger and landing joint. Removed drilling bails and elevators. Installed tubing bails and elevators. Rigged up GBR tong and equipment. Rigged up Schlumberger control line sheaves and spools. Load pipe shed with tubing and jewelry. Held pre job meeting with all parties involved with running the production tubing. 92 3/15/2019 3/16/2019 PJSM on running upper completion. Make up seal assembly, locator sub, 1 joint of TSH 511, & XO to the tubing IBT thread. 40' hole depth. Trip in hole using single joint elevators from 40'to 129'. Install Standard gauge mandrel, down hole pressureltemp. Hook up I -wire and test to 5000 psi for 15 minutes. Test good. Trip in hole to joint # 8. Rig Floor hydraulic supply manifold block with the line directly to the tugger to hoist singles off the pipe skate to the mouse hole. By passed the block with direct line to the tugger. Ran upper completion 3 1/2" 9.3# L-80 IBT-M from 343' to 10,356'. Installed Cannon clamps on each joint for the control lines. Torque on tubing was to the diamond 2200-2400 ft/lbs. Inspected each joint to ensure the seal ring was installed correctly. Monitored well on trip tank. Good displacement. After running Landing X nipple, filled tubing on the run and topped off each 15 joints. 93.0 3/16/2019 3/17/2019 RIH with 3 1/2" upper completion 9.3# IST L-80 from 10,356' to 15,271' using Run -N -Seal dope. AVG torque 2400 ft/lbs. Installed Cannon camps on each joint. Slack off with 10k down weight @ liner top. 27.5' of compression. Calculated space out required. Layed down 71.22' of tubing. Made up 3 x pup joints, 7.67', 9.67', 9.81'. place joint # 452 on top. Hanger was observed to be machined for a 12.6 ISM pup. Pup on hanger was 15.6 lbs/ft. Broke hanger off and picked up back up hanger. Layed down pups that were picked up and recalculated space out. Picked up joint # 526, 28.60 and one 1.8' pup. Ran 71.55' of tubing back into hole. Terminate 2 x control lines in hanger on rig floor. SLB & GE working in conjunction. PUW 155K SOW 100K. Landed tubing with 15K on seal assembly. Clear rig floor of GBR & Schlumberger tools and equipment. Rigged up for completion testing on annulus and down the tubing. Test the lines to 3000 psi. While testing through the annulus observed a pressure loss @ 500 psi. Continued with test to 1700 psi for 10 minutes. Test charted. Good test. Confirmed the shear valve was leaking by pumping down the annulus and getting returns through the tubing. Closed SCSSSV and pumped down annulus to 1500 psi for 10 minutes. Good test, charted. 94.0 3/17/2019 3/18/2019 Conduct equalization test of SSSV with 1500 PSI. Good. Pull landing joint. Install TWC. Break down testing equipment. Remove Schlumberger equipment from rig floor, GBR equipment, Well head equipment. Clean flow box. Wash stack. Pump deep clean with fresh water through 3 mud pumps, choke, kill line, manifolds, L/D riser. Lay down both mouse holes. Power down accumulator. Cleaned and inspected BOP and rams & greased. Tighten all ram doors. Remove choke & Kill lines. Disconnect koomey hoses. Remove bolts from BOP to Adaptor spool. Set BOP on pedestal and secure. 95.0 3/18/2019 3/19/2019 Remove starter head from the cellar. Position tree over well. BOP secured with chains and BOP hoist. Clean up cellar area. simops: Cleaning in the active and reserve pits. Pickle mud pump # 3. SLB ran I -wire and control lines through the tubing head bonnet. Nippled up tree to wellhead. SLB terminated tech wire and control lines.. Tested control line to 5000 psi. Verified by CoMan. Connected TECH wire to controller, bad test, switched to different controller, tested conductivity. Good test. GE tested void to 5000 psi. Good test. Rigged up and tested tree with water to 350 psi low for 10 minutes and 5000 psi high for 10 minutes. Good test. Witnessed by CoMan and charted. Removed tree cap and removed TWC. Secure tree. Cleaned up all testing equipment. PJSM - Rigged up Pollard wireline on ODS. Hung sheaves on TO with cabled harness. SLB opened SCSSSV and locked open with needle valve. Run #1 to retrieve the plug in top nipple. Unsuccessful. Run #2 retrieve prong in top nipple. Run #s 3 & 4 unsuccessful to remove dummy valve from GLM #1. Run #5 retrieved dummy valve in GLM #1. run #6 was successful in setting valve in GLM #1. RIH with 3" GS to 5125' and pulled plug. change out tool string to 15'x 2" stem. RIH with 3 1/2" OM -1 with JOS to 14,326' WL depth to latch onto valve in GLM # 3. POOH without valve. Pollard shut down operations until tomorrow. Simops: various projects for warm stack. 96.0 3/19/2019 3/20/2019 Remove drilling XOs and subs from the rig floor. Transport to Premium for inspection. Remove pipe rack _ mats and boards and clean. Remove check valve from the trip tank discharge line. Flushed shaker pit centrifugal pumps. Greased MP fluid end parts. Remove IA ported flange and store on rig floor. Clean and - organize dog houses. Wash trip tank. Stage production pre -built piping and headers by H04 well head. Open gas buster and U-tube to drain. Open degasser inspection cover. Remove MP #3 bleeder valve, washed body. Simops: Pollard slick line returned to work @ 06:30 hrs. First two runs unsuccessful. 3rd run caught the dummy valve in GLM #3 @ 14,297'. Run #4 was unsuccessful installing valve in GLM #3. Run #5 was successful installing valve in GLM #3 @ 14,297'. Rigged down Pollard wire line. Slipped 11 wraps on drawworks to lay down Top Drive. www.peloton.com Page 10/10 ReportPrinted: 3/20/2019 L 0 Y N N Otl mC d0 q N N o Z�rdry ^m'0 f ioj `0 - 8orc���gRnlii�873 h Ua W q Qp Om Or OnQP fly A^w m Amm10- 2- $ q wm� N (y N N f g nn r �n mmr`u� 'a m N� mNm tl 8 '6 tlmtlmm mrrn "Io gPtl �j$$j •m n mo a���o{ umrlNm ..ON I w S wmmmw mSSSm mmw 8`m..,; w',w $mmmw Em ww d _ NNNNN NmNN N__N h__hN NY1m'wN _NNN _N Nh' o° n cr;� "Emme mumsn 8`°i' emmmp �+o meCm wtlAm m'I Smq m" Ian 2 W0 OmPtl �mr °N-tl Nm mmm0� d�-V %n ONNV OOI . 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Q.� 00 p $mN v mq�� pG p E N jtm�l �OwbO r�OV� p F ui v2 �cnm �: ==SSfib5555 Vy1 NYY N{{��IpNM nnnn LL yN�N {N ��4QQa366�Q�Q� nnnr Q W E S nmmm� mer - oe�0�00 j wnrreRo 0p<rNip y W�mtp C n p l70�pi� /O 0mbm b Np f rMON0l700rb N v o gSRR�m�eSw� ` _mmS N�?anwN E R$88s mm RRR g a wenn oN �no"�'Iw. Co O Z Or N1�00�p�gRR O y C° bNNm i ---------- Ommmm wmmw � 6 K Q N i U N mvNi,<�� F Rmo�O� g of oIr wRRRR RRN N yO O Q N Z � O s Z n N m og o R U F NN C O Only Enter Red 13 318' surface casino Casing ID 12.347 Casing O.D.: 133/8 Weight per Foot 72 Grade: L-80 Threads BTC RUN TA" DIST. JT. N0, On, sla. i cunni Blue Crest H04 0.7482 inches Block Wt: 72,000 ppf Mud Wt. 9.8 Will: Ave TO= Foreman: lb& TA" DIST. JT. N0, On, sla. i cunni Blue Crest H04 Run date: SHOE 2.00 RKB TO sea level = 179.65' Will: Pad Grade height= 145.20' lb& RKB to Load shoulder. 40.48 ppg Top of 13.375" casing o4048 4352 Casing wl sopa bod, Casing shoe Q MD = 5,645 1 bbl Shoe depth TD= 5,645.18 2 TO of 17.5' hole, MD 5,580.28 72,122 lb SHOE 2.00 5,643.18 2.00 Bulinus 0.00 0bbl 74,56516 1 1 41.52 5,601.86 4352 Casing wl sopa bod, twbaawr 6.45 1 bbl 77.198 lb 2 2 41.38 5,580.28 84.90 Casing wl wild boo wrbolawr 12.58 2bbl 77.321 lb 3 Float 2.OD 1 5,558.28 86.90 Hoa talar 12.87 2bb1 79,83316 4 3 41.03 1 5,517.25 127.93 Casing wl sopa bodylurbolator 18.95 3bbl 82,439 lb 5 4 42.56 5,474.69 170.49 Casco wr solid body babolatar 25.26 4 bbl 84,97416 8 5 41.47 5,433.28 211.90 Casino wl sam bod, wrbomtor 31.39 6bbl 87,514 11, 7 6 41.48 5,391.80 253.38 Casing wl said turholator 37.54 7bb1 90.036 lb 8 7 47.79 5,350.61 294.57 Casco ad. Idbanlybirb.law, 43.64 8 bbl 92,55416 9 8 41.13 5,309.48 335.70 tui solid body turboiator 49.73 9bbl 95,088 lb 10 9 41.39 5,26809 377.09 -Casm, tasm whonaboa wrbomtor 55.87 10 bill 97,53310 11 10 39.93 5,228.16 417.02 casin wl wldb wrbolator 61.78 11 bbl 10D,0751b 12 11 41.51 5,186.65 458.53 Casing wl said boalv turbui•wr 67.93 12 bbl 102,66416 13 12 42.29 5.144.36 500.82 Casing w/solid badly turboiator 74.20 13 bbl 105,24516 14 13 42.18 5,102.20 542.98 Cast whollabod wrbolwtor 80.44 14 bM 107,838 lb 15 14 42.35 5,059.85 585.33 Cosin wlsam Imodyflabolift, 86.72 15 bbd 110,33016 16 15 40.70 5,019.15 626.03 Coln wt sam bad, botanists, 92.75 16 bbl 112,92316 17 le 42.34 4,976.81 668.37 Casin w wind body wrbaaor 99.02 18 bbl 115,51816 18 77 42.35 1 4,934.46 710.72 cash else m body wrbolator 105.29 19 bbl 118,110 lb 19 78 42.38 4892,08 753.10 Casing whond body wrmietor 111.57 20 bbl 120.698 lb 20 19 42.26 4,849.82 795.36 Co.[., w/wlid body wrbaator 11783 21 bbl 123,01716 21 20 37.78 4,812.04 833.14 Casiu9w1whil bad, wroomor 12343 22 bbl 125,605 Ib 22 21 42.36 4,769.68 875.50 Casing w1wild both, wrbolator 129.71 23 bbl 128.187 lb 23 22 42.18 4,727.50 917.68 1 Casing wlsolla body wroaatw 135.96 24 bbl 130,74716 24 23 41.81 4,685.69 959.49 Casino w/ solid body turbaatw 142.15 25 bbl 133,205 lb 25 24 40.15 4,645.54 999.64 Cases wl sono body wrbolator 148.10 26 bbl 135.760 lb 26 25 41.73 4,603.81 1,041.37 Coln w/ solid body turboiator 154.28 27 bbl 738,27916 27 26 40.16 4,563.85 7,081.53Cum wreogab wrbolwar 160.23 28 bbl 140.8D3 lb 28 27 42.19 4,521.46 1,123.72 Coal., whoga body wrbol•.r 166.48 29 bbl 143,399 lb 29 28 42.41 4,479.05 1,166.13 Casing vol solid body turboiator 172.76 31 bbl 145.99516 30 29 42.40 4,436.65 1,208.53 Casing W/ solid banN, turboiator 178.05 32 bbl 148.5261b 31 30 41.33 4,395.32 1,249.86 Casing wl solid bod, turboiator 185.17 33 bbl 157,11016 1 32 31 1 42.21 4,353.11 1,292.07 Casino wham body wmaawr 191.42 34 bbl 153,614 lb 33 32 4089 1 4,312.22 1,332.98 Casco s) solid body wrboiawr 197.48 35 bbl 156.202 lb 34 33 42.28 1 4,269.94 1,375.24 Casing w/sola badv baloWawr 203.74 36 bill 758,76116 35 34 41.79 4,228.75 1,417.03 Casing wl said body wrbotatur 209.94 37 bbl 161,219 lb 36 35 40.15 4,188.00 1,457.18 Casing tui wild body wrbolator 215.88 38 bbl 163,719 Ib 37 36 40.83 4,147.17 1,498.01 costo W1 wild body turbolatp221.93 39 bbl 166.309 lb 38 37 42.30 4,704.87 1,540.31I casing Wl solid body turbaate. 228.20 40 bbl 168.887 lb 39 38 42.10 4,062.77 1,582.47 Casing wl solid boa turbolater 234.44 41 bbl 171,478 lb 40 38 42.32 4,02045 1,624.73 Caenwt solid bo turboiator 240.71 43 ON 174,04916 41 40 41.99 3,978.46 1,666.72 1 Cum adwild body wrbobtor 246.93 44 bbl 176,603 lb 42 41 41.71 3,936.75 1,708.43 1 Casing wham body tunadwe 253.11 45 bbl 179,197 lb 43 42 42.37 3,894.38 1,750.80 Casing W/ said body wmoiawr 259,38 46 bill 181,782 lb 44 43 42.22 3.852.16 1,793.02 Cum Wl solid back, wrbaewr 265.64 47 bbl 184.381 lb 45 44 42.45 3.809.71 1,835.47 Cuing w/ solid turboiator 271.93 48 bbl 186,96916 46 45 42.26 3.767.45 1,877.73 Casin an sale usaakor 278.19 49 bbl 189,566 lb 47 46 4242 3.725.03 1,920.15 Casingwl sato wrbolator 284.47 50 bbl 192,012 lb 48 47 39.95 3,685.08 1,960.10 case sal wild wrbolaor 290.39 51 bbl 194,610 lb 49 48 42.43 3,642.65 2,00253 Casing wl said turbadir 296.68 52 bbl 197.2D5 lb 50 49 42.39 3,600.26 2,044.92 Cuing wt solid annotator 302.96 54 lobi 199,796 lb 51 50 42.31 3.557.95 2,087.23 Casin wlsou wrbolator 309.23 55 bbl 202.388 lb 52 51 42.34 3.515.61 2,129.57 Casinowlsolla wrbolator 315150 56 bbl 204,943 lb 53 52 41.73 3,473.88 2,171.30 Casco add sold bad tarbelator 321.68 57 bbl 207,416 lb 54 53 40.39 3,43349 2,211.69 casco wl solid bo wrbaator 327.67 58 lobi 209,902 lb 55 54 40.60 3.392.89 2,252.29 casing wt sale turbaator 333.68 59 bbl 212,42116 56 55 41.14 3.351.75 2,293.43 casing wt sesta wrholatm 339.78 60 bbl 214,992 lb 57 56 42.00 3.309.75 2,335.43 Casing whale turlwlatar 346.00 61 bbl 217,50016 56 57 40.95 3,268.80 2,376.38 Casingw/salla wrbaawr 352.07 62 bbl 219,989 lb 59 58 40.65 3,228.15 2.417.03 Cut whale wdWator 358.09 63 bbl 222,49616 60 59 40.95 3,787.20 2,457.98 Casing wl wild turlwlawr 364.15 64 bbl 224,97516 61 80 40.49 3.146.71 24488.47 atm wl solid wrbolator 370.15 65 bbl 227,827 Ib 62 87 43.21 3.103.50 2,547.68 deco ad wild wrbolator 376.55 67 bbl 230.196 lb 63 62 42.06 3,061.44 2,583.74 Casin lid sone boa wrbolator 382.79 68 bill 232.595 lb 64 63 39.19 3.022.25 2,622.93 casing w/wfid lanch, wroaatar 388.59 69 bbl 235,062 lb 65 64 40.28 2,981.97 2.663.27 w.m .1 wild wrbolator 70 bbl 237,36116 66 65 37.55 2,944.42 2,700.76 Casingwt said im wrbolator 71 bbl 239,817 lb 67 66 40.11 2,904.31 2,740.87 Casingwl sam turbolawr 72 bbl 242,21016 68 67 39.09 2,865.22 2,779.86 Casingwhom turbaawr 73 bbl 244,679 lb 69 68 40.32 2,824.90 2,820.28 asin whom wrbolator 3 74 bW 247.298 lb 70 69 42.78 2,782.12 2,863.06 CasingWl wiia turblawr 7 V44322.80 75 bbl 249,85716 71 70 47.79 2,740.33 2,904.85 Casingwl sold indicator 76 bbl 252,461 lb 72 71 42.53 2,697.80 2,947.38 Casingwlsaia turbobtur 77 bbl 264,999 lb 73 72 41.45 2,856.35 2,988.83 Casio ad solid wrbolator 78 bbl 257,28816 74 73 37.39 2,878.96 3,026.22 tui w/aolm wrbaator 79 bbl 259,74416 75 74 40,12 2,578.84 3068.34 taw wham wrbdator 80 bill 262,330 ib 76 75 42.23 2,538.67 3,108.57 Corn wlwald turbaator 460.54 81 bbl 264,72716 77 78 38.75 2,497.46 3,147.72 Cum wt wild wrbolator 466.34 83 bbl 1 of 2 pages Only Enter Red 78 RKB TO Sea level= 179.65' Pad Gnh, HggM= Blue Crest H04 13 318" surface casirog Top of 13.375" casing = 40.48 Casing shoe @ MD = 5,645 Casing 10 12.347 TD of 17.5" hole, MD - 5,655 0.1482 bbYft Casing O.D.: 13318 inches Block Wt: 72,OOD lbs. WagMPar Foo: 72 ppf Mud Wt. 9.8 ppg Grade: L-80 80 Ave TQ= 3,315.15 Threads BTC 491.15 Foreman: 277.390lb 82 81 RUN TALLY 3,354.54 DIST. turbolator 496.98 88 bM279.785lb Jr. NO. 83 82 A40.192,211.33 Safirdallsi.irt MMft On Pigs LENGTH FI RNB TML Lnarth Run date: 78 RKB TO Sea level= 179.65' Pad Gnh, HggM= 145.20' RKB to Loan sboyidar = 40.48 Top of 13.375" casing = 40.48 Casing shoe @ MD = 5,645 Shoe depth TD= 5,645.18 TD of 17.5" hole, MD - 5,655 DETAILS 267.213 lb 78 77 2,456.85 3,188.33 Casio Wt soca wrbolator 472.36 84 bbl 269,781 lb 79 78 2,414.92 3,230.26 Casln wlsona anonald« 478.57 85 bbl 272,406 lb 80 79 2,372.04 3,273.14 Casio vel sola wrboler 484.92 86 bbl 274,978lb 81 80 2,330.03 3,315.15 Casco w/adle wma.tor 491.15 87 bill 277.390lb 82 81 2,290.64 3,354.54 Casco vel solid turbolator 496.98 88 bM279.785lb 83 82 A40.192,211.33 2,251.52 3,393.66 Cann vel soul turbolator 50278 89 bill 282,24616 84 83 2,211.33 3.433.85 Casio vel sale wrbolmor 50873 90 bbl 284.574 lb 85 84 2,173.31 3,471.87 cadn vel solid inrboldar 514.36 91 bbl 287,193 lb 86 85 2,130.53 3.514.65 Coln vel sola wrbolsior 520.70 92 bbl 289.68116 87 86 2,089.90 3,555.28 Casio vel sale boo turbolator 526.72 93 bbl 292,110111 88 87 2,050.22 3,594.96 teem vel sand boi wrbdstor 532.60 94 bill 294,623 lb 89 88 41.03 2,009.19 3,635.99 Casino wlsona turml.wr 538.68 1 95 bill 297,184 lb 90 89 41.84 1,967.35 3,677,83 Co.[.,w/vena bo turbolator 544.88 96 bbl 299,58116 91 90 39.15 1,928.20 3,716.98 Cuin vel soils wrboW« 550.68 97 bbl 302,040 lb 92 91 40.15 1,888.05 3,75713 CUIn wl.oim turbolator 556.63 98 bbl 304.485 lb 93 92 39.94 1,848.11 3,797.07 Cam vel sand wrbaator 562.54 100 bbl 306.952 lb 94 93 40.29 1,807.82 3,837.36 Casio vel sale wrlolator 568.51 101 bbl 309.385 lb 95 94 39.74 1,768.08 3,877.10 team w/sora turbolator 574.40 102 bbl 311.849 lb 96 95 40.25 1,727.83 3.917.35 Casio vel sold turbolator 580.36 103 bbl 314,40116 97 96 41.68 1,686.15 3,959.03 Casco vel solid wmolator 586.54 104 bill 316,842 lb 98 97 39.86 1,646.29 3.998.89 Casing vel solid bnboator 592.44 105 bbl 319.437 lb 99 98 42.39 1,603.90 4,041.28 C.I.wl.oea bo baa olmor 598.72 1 U bbl d2_5907 lb 100 99 40.33 1,563.57 4,081.61 CaW. wlsoea bo turbolator 604.70 107 bbl 324.192 lb 101 100 37.33 1,526.24 4,118.94 Casing Wt solid bo nowagur 610.23 108 bbl 326,667 lb 102 101 40.41 1,485.83 4,159.35 Casco vel sons boa turbolator 616.22 109 bol 328.925 lb 103 102 36.88 1,448.95 4,196.23 Casio Wt solid body turbolator 621.68 110bbl 331,240 lb 104 103 37.82 1,411.13 4,234.05 Casio wlsolhl turbolator 627.28 111 bol 333,807 lb 105 104 41.92 1,369.21 4,275.97 Casino .1 ..ad wmolator 633.49 112 bbl 336,274111 106 105 40.30 1.328.91 4,316.27 Casio vel solid be turbolator 63946 113 bbl 338,843 lb 107 106 41.95 1,286.96 4,358.22 Casino.1 sold wdnolow 645.68 114 bbl 341.338 lb 108 107 40.76 1,246.20 4,398.98 Casio vel sopa turbolivor 651.72 115 bbl 343.873 11, 109 108 41.40 1,204.80 4,440.38 Casio vel solid body turbolator 657.85 116 bill 346,37416 110 109 40.85 1,163.95 4,481.23 Casio vel sena boa wmolator 663.90 117 bill 348.822 lb 111 110 39.97 1,123.98 4,521.20 Casing vel sand ashr turbolator 669.82 119 bbl 351,382 lb 112 111 41.82 1,082.16 4,563.02 Casing w/sand liandir wrholaor 676.02 120 bbl 353,76116 113 112 38.85 1,043.31 4,601.87 Casio vel solid wrbolmor 681.78 121 bbl 356,10316 114 113 38.25 1,005.06 4,640.12 Casio wt sono wmosior 687.44 122 bbl 358,38316 115 114 37.24 967.82 4,677.36 Coln wlsolld boa wmolator 692.98 123 bbl 360,879 lb 116 115 40.77 927.05 4,718.13 Coln wt sonab wrbdxor 699.0D 124 bbl 363,404111 117 116 41.24 885.81 4,759.37 Casio Wt solid turbinator 705.11 125 bill 365,862 lb 118 117 40.14 845.67 4,799.51 Coal vel said bo verbalist., 711.06 126 bbl 368,330 lb 119 118 40.31 805.36 4,839.82 Casio Wt sold brrbolat« 717.03 127 bbl 370,813 lb 120 119 40.55 764.81 4,880.37 Coal.Winans! b,* wrbolatar 723.04 128 bbl 373,343 lb 121 120 41.32 723.49 4,921.69 Casio vel said boa turbolator 729.16 129 bill 375,816 lb 122 121 40.39 683.10 4,962.08 CUIn vel said boa turbolator 735.14 130 bill 378.301 lb 123 122 40.59 642.51 5,002.67 Casino vel solid Indio turbolator 741.16 131 bbl 380,862 lb 124 123 41.83 600.68 5,044.50 Casing w/sMid W turbolator 747.35 132 bbl 383,011 lb 125 124 35.10 565.58 5,079.60 c..ln w/solid turban« 752.55 133 bbl 385,329 lb 126 125 37.86 52L72 5,117.46 Casing wt moa toody wrbewer 758.16 134 bbl 387,776 lb 127 126 39.97 487.75 5,157.43 Cooling wlsona body wmolator 764.08 135661 390,237 lb 128 127 40.18 447.57 5.197.61 Casing vel sola bi wmdnor 770.04 136 bbl 392458111 129 128 36.28 411.29 5,233.89 Coding vel solid wmdaor 775.41 137 bbl 394,906111 130 129 39.98 371.31 5,273.87 1 Casino vel said body turbolator 781.33 138 bbl 397.4112 lb 131 130 42.08 329.23 5,315.95 Casino w/amid verbom« 787.57 139 bbl 399,934 lb 132 131 40.05 289.18 5,356.00 Ca.w w/smm bo turbolator 793.50 140 bbl 402,391 lb 133 132 40.13 249,05 5,396.13 CUm w/wind boa turboa[or 799.45 141 bbl 404,901 lb 134 133 40.98 20807 5.437.11 CUM .'sold boa turbolator 805.52 143 bbl 407,32316 135 134 39.56 168.51 5,476.67 Casio vel solid boa turbolator 811.38 144 bbl 409,978 lb 136 135 43.37 125.14 5,520.04 Casio wt solid turbolator 817.80 145 bbl 412,367111 137 136 39.01 86.13 5,559.05 Cosi vel sono enbuln« 823.58 146 bbl 414,8511b 138 137 40.57 45.56 5,599.62 Cann wlsola wmolator 829.59 147 bbl 415,15316 139 4.94 40.62 5,604.56 Pup Joint, B a P 830.33 147 bbl 415,16216 140 0.14 40.48 5.604.70 Nezzz tz zre• Hanger 830.35 147 bbl 417,64016 141 40.48 0.00 5,645.18 RKB W load sbonder 836.34 148 bbl 72,00016 0.00 110 bbl 2 of 2 pages Only Enter Red Blue Crest H04 Run date: 1-24-,S $18" Intermedlate cast r RKB TO ana—l= 179.65' Casing ID 8.681 0.0732 bbM RW Or.& Kae.= 145.20' Casing O.D.: 95/8 inches Block WC 72,000 Ibs. RKa ro Lo.e unwmu- 37.80 waen, p. Fw 47 ppf Mud Wt. 10.6DDB Top of 9.625- Casing 37.80 Grade: Pilo Aye TO= Casing shoe @MD= 15,406 Threads iydril 563 Foreman: Shoe depth TD= 15,406.50 RUN TALLY OST. TD of 12.114" hole, MD = 15,420 46. 46. 45.41 46.11 46.21 1 of 4 pages Only Enter Red 88 88 Blue Crest H04 98" Intermediate cash 4,000.60 292.99 BB bbl Cesmg ID 8.681 69 bbl 0.0732 bbVB Casing O.D.: 9518 inches Block Wt: 72,000 lbs. Waenl R=Froe 47 opt Mud Wt. 10.6 ppg Grade: Pilo 73 bbl Ave T0= 11 08].58 4,318.92 316.30 Threads iydril 563 Foreman: 75 Db1 245,759 to 97 97 10 995.69 4.410.81 323.03 RUN 1A4.1.r 2107. 76 bbl 249.33216 99 99 10 905.00 4 501.50 329.67 JT NO 251,15616 100 100 10858.70 4547.60 333.06 Strina W.I he 252,9]816 101 101 10812.45 4594.05 336.45 Fr RKe 254,786 lb 102 102 Run date: 1-2,.d RKelosea Noa1= 179.65 14520 RKR.e Load.naulda.= 37.90 Top of 9.625"casing = 37.00 Casing shoe @MD= 15,106 Shoe depth To- 15,406.50 TD of 12.114"hole, MD= 15,420 229.599 88 88 44.87 48.33 40.58 45.23 46.18 45.04 46.05 44.91 48.21 45.88 44.41 46.28 46.3 46.25 45.92 44.99 46.24 46.4 45.85 4378 46.15 46.26 45.34 45.33 46.25 45.07 46.24 46.19 45.44 44.36 46.19 45.22 45.19 46.3 46.34 45.46 45.81 45.84 43.01 46.08 46.28 45.04 46.38 45.21 46.28 43.75 46.2 45.55 46.25 45.56 46.46 46.2 44.32 46.24 44.74 45.56 45.74 45.24 46.2 45.49 46.26 46.45 45.07 46.26 46.4 46.24 46.27 45.87 46.14 46.22 43.29 45.9 45.76 46.13 41.63 44.6 46.4 46.3 42.27 44.36 46.26 48.14 46.36 44.61 45.81 46.24 45.75 43.59 11,405.90 4,000.60 292.99 BB bbl 2314241e 89 89 11359.5] 4048.93 296.38 69 bbl 233,181 lb 90 90 11,314.99 4091.51 29965 70 bell 234962 lb 91 91 1126976 413674 302.96 71 bbl 2367821b 92 92 11,223.56 4,18292 306.34 72 bbl 238,556 lb 93 93 11,178.54 4,227.96 309.64 72 bbl 240370 Ib 94 94 11,132.49 4,274.01 31391 73 bbl 24213916 95 95 11 08].58 4,318.92 316.30 74 bbl 243,95916 98 96 11041.37 4,365.13 319.68 75 Db1 245,759 to 97 97 10 995.69 4.410.81 323.03 75 Dbl 247.508 lb 98 98 10951,28 41455.22 326.28 76 bbl 249.33216 99 99 10 905.00 4 501.50 329.67 77 bbl 251,15616 100 100 10858.70 4547.60 333.06 78 bill 252,9]816 101 101 10812.45 4594.05 336.45 79 b01 254,786 lb 102 102 10766.53 4839.97 339.81 79 Db1 256,559 Ib 103 103 10721.54 4684.96 343.11 80 bbl 258,380 lb 104 104 10,675.30 4]31.20 346.49 81 bbl 26020816 105 105 10,628.90 4777.60 349.89 82 bbl 262014 lb 106 106 10.583.05 4,823.45 353.25 83 boll 263,739 lb 107 107 10,539.27 4,867.23 356.46 83 bbl 265,510 lb 108 10844.95 10,494.32 4.912.18 359.75 84 boll 26732810 109 109 10,448.17 4,958.33 363.13 85 boll 269.150 11, 110 110 10601.91 5,004.59 366.52 86 bbl 270,936 lb 111 111 10356.5] 5049.93 36984 86 bbl 272,72216 112 112 10,311.24 5095.26 373.16 87 boll 274,544 lb 113 113 10264.99 5141.51 376.54 88 bbl 276,320 lb 114 114 10 19.92 5186.58 379.84 89 bbl 2]8,14116 115 115 10,173.68 5232.82 383.23 1 90 bbl 279.961 Ib 116 116 10,127.49 5,279.01 386.61 1 90 bbl 281,751 Ib 117 i1T 10,082.05 5324.45 389.94 91 bel 283,499 Ib 118 118 10,037.67 5368.83 393.19 92 bbl 285,319 lb 119 119 9,991.48 5415.02 396.57 93 Db1 287.100 lb 120 120 9.946.26 5460.24 399.89 93 bbl 28888016 121 121 9,901.07 5505.43 403.20 94 bbl 29070410 122 122 9,854.77 5,551.73 406.59 95 bbl 292.53D lb 123 123 9,808.43 5,598.07 409.96 96 bell 294,321 Ib 124 124 9,]629] 5,643.53 413.31 97 bbl 296,125 lb 125 125 9,717.16 5689.34 416.66 97 ON 297,931 lb 126 126 9,671.32 5,735.18 420.02 98 bbl 299,625 lb 127 127 9628.31 5778.19 423.17 99 boll 301,4411b 128 128 9,582.23 5824.27 42655 100 bbl 30326416 119 129 9535.95 5870.55 429.94 100 bbl 305, 038 Ib 130 130 9490.91 5915.59 433.23 101 bel 306,86510 131 131 9,444.53 5961.97 436.63 10201,1 308U ,6 132 132 9,399.32 6007.18 439.94 103 bbl 31046916 133 133 9.353.04 8053.46 443.33 1D4 bbl 31219316 134 134 9,30929 fi 09721 446.53 104 bbl 31401316 135 135 9263.09 6.143.41 449.92 105 bbl 31580716 136 136 9217.54 6,18896 453.25 106 bbl 317,629 lb 137 137 9,171.29 6,235.21 456.64 107001 3194241/, 138 138 9,125.73 628077 459.98 107 bbl 3212541b 139 139 9079.27 6327.23 463.38 1 108 bbl 323,07416 140 140 9,033.07 6,373.43 466.76 109 bbl 214,8201b 141 141 8,988.75 6417.75 470.01 110 bbl 326,6421b 142 142 8,942.51 6.463.99 473.40 111 bbl 328,404 lb 143 143 8897.77 8508.73 476.67 111001 330,199 lb 144 144 885221 6554.29 480.01 112 Db1 3320011b 145 145 8806.4] 6600.03 483.36 113 boll 333822 lb 146 146 8760.23 6,64627 486.75 114 bbl 335642 lb 147 147 8714.03 6692.47 490.13 115 bbl 337,4Z3,4 lb 148 148 8668.54 6.737.96 493.46 115 bell 339,257 lb 149 149 8622.28 6,78422 496.85 116661 M1,087 W 150 150 8,575.83 6830.67 500.25 117 bbl 342.862 lb 151 151 8530.76 687574 503.55 118 bbl 344,68516 152 152 8484.50 6.922.00 506.94 1 118 bbl 346,512 Ib 153 153 8438.10 6.968.40 1 510.34 119 bbl 348.334 lb 154 154 8391.86 7014.64 513.72 120 bbl 350,157 lb 155 155 8.345.59 7.060.91 517.11 121 bbl 351,964 lb 156 156 8,299.72 7.106.78 520.47 122 bbl 35378116 157 157 8253.58 7,152.92 523.85 122 bbl 355602 lb 158 158 8,207.36 7,199.14 527.24 123 boll 357308 to 159 159 8,1640] 7,242.43 530.41 124 boll 359.116 lb 160 160 8118.1] 7,288.33 533.77 125 bbl 360,918 Ib 161 161 8072.41 7,334.09 537.12 125bbl 362,736 11, 162 162 8026.28 7380.22 540.50 12601,1 364,376 lb 163 163 7,984.65 7421.85 543.55 127 bbl 366,133 lb 164 164 7940.05 7466.45 546.81 128 bbl W7,960 10 165 165 7,893.65 7,512.85 55021 129 bbl 369,784 lb 166 166 T 84].35 7,559.15 553.60 129 bbl 371,450 lb 167 167 7,805.08 7,601 42 556.70 130 bbl 37319716 168 168 7,760.72 ],645.78 559.95 131 DM 37501916 169 169 7,714.46 7,69204 563.33 132 DDI 376,837 lb 170 17O 7668.32 7]38.18 588.71 132 boll 378.663 In 171 171 7,621.96 T ]84.54 570.11 133 bbl 380.421 16 1 2 172 7 577.35 7,829.15 573.37 134 boll 382,225 lb 173 173 746530 7,874.96 576.73 1351,61 384047Ie il4 174 7485.30 7921.20 580.12 136 b01 38589916 175 175 7439.55 1966.95 583.47 136 bbl 387 S661b 176 176 7 395.98 8,010.M 586.66 137 bbl 2 of 4 pages Only Enter Red Blue Crest H04 Run date: 1-24.19 518" Intermin lab cash axe 10 sea level= 179.65' Casing ID 8.681 0.0732 b005 Pad cme aalelde 14520- CasingO.D.: 9518 inches Block Wt: 72,000 Ihs. Rxaml,wd.xoom.r• 37,00 Wagntw root 47 ppf Mud Wt. 10.6 ppg Top of 9.625" casing= 3790 Glade: Pilo Ave TO= Casing an" @MD= 15,406 Threads dydril 563 Foreman: Shoe depth TD= 15p06.50 Rua TALLY MST. TD of 12.114" hole, MD = 15 420 44.51 45.81 45.11 46.21 45.91 45.81 3 of 4 pages Only Enter Red Blue Crest H04 Run Cab: 142 19 518" Inbrmedlate 4asir RRe To s.. kv 1. 179.65' Casing ID 8.681 0.0732 tp08 faapme.R.Iele. 145.20 - Casing O.D.: 9518 inures Block Wt: 72,000 Ihs, Raamta.esxovle.,, 37.50 WN.hl w Foot 47 ppf Mud Wt 10.6 ppg Top of 9.625 easing= 37.80 Grad. Pilo Ave TO= Casing shoe@MDv 17406 Threads 4ytln1583 Foreman: Shag depth TD= 15,406.50 RUR TALLY 03T TD of 12.114" hole, MO = 15,420 45.61 46.08 45.91 46. 45. 46. 46. 46.11 46, 46.2 4 of 4 pages Only Enter Red 4.5" L iner Casing ID 3.826 Casing O.D.: 4 1/2" Weight per Foot: 15.2 Grade: Pilo Threads iydril563 RUN Strina Welahl sof its inches Block Wt: ppf Mud Wt. Foreman: TALLY JT. NO. On Plea, .Inint Ipnnlh Blue Crest H04 0.0149 bbl/ft 72,000 lbs. 9.4 ppg Ave TQ= 8,200.00' Lawson / Ashley DIST. 15210.85 FI RKn Tnr 1 ....H. Run date: 3.11.19 1 RKB TO Sea level = 179.65' Centralizers = 8.125' Pad Grade Height = 145.20' RKB to Load shoulder = 37.80 0bbl Overlap= 198.12 Top of Liner 15210.85 0 bbl Casing shoe @ MD = 15,406 1 bbl Shoe depth TD= 20,864.00 1 bbl TD of 8 1/2" hole, MD = 20,867 nerwu c 72,292 Ib 1 FS 22.43 38.54 39.49 37.84 38.98 38.29 39.66 38.65 38.66 38.8 39.17 38.06 38.95 38.36 38.8 38.98 38.97 38.65 38.49 38.66 38.98 38.54 39 38.56 38.65 38.55 38.97 37.18 38.41 38.96 36.75 38.54 38.65 38.52 38.75 38.54 38.65 38.54 38.98 38.53 39.13 38.98 38.79 38.98 38.98 38.8 40.27 38.54 38.78 37.99 39.13 20,841.57 22.43 Guidel.12'/Pup6.1'IFlex7.44'IPup6.09'/XO1.7' 0.00 0bbl 72,794 Ib 2 2 20,803.03 60.97 Blank no centralizer 0.91 0 bbl 73,308 Ib 3 3 20,763.54 100.46 Slotted/ no centralizer 1.50 1 bbl 73,800 Ib 4 4 20,725.70 138.30 Blank I Spiral Centralizer 2.06 1 bbl 74,308 Ib 5 5 20,686.72 177.28 Slotted/Spiral Centralizer 2.65 1 bbl 74,806 Ib 6 6 20,648.43 215.57 Blank I Spiral Centralizer 3.22 1 bbl 75,323 Ib 7 7 20,608.77 255.23 Slolted/Spiral Centralizer 3.81 1 bbl 75,826 Ib 8 8 20,570.12 293.88 Blank / Spiral Centralizer 4.38 2 bbl 76,329 lb 9 9 20,531.46 332.54 Slotted/Spiral Centralizer 4.96 2 bbl 76,834 Ib 10 10 20,492.66 371.34 Blank I Spiral Centralizer 5.54 2 bbl 77,344 Ib 11 11 20,453.49 410.51 Slotted/Spiral Centralizer 6.12 2 bbl 77,840 Ib 12 12 20,415.43 448.57 Blank / Spiral Centralizer 6.69 2 bbl 78,347 Ib 13 13 20,376.48 487.52 Slotted/Spiral Centralizer 7.27 3 bbl 78,846 Ib 14 14 20,338.12 525.88 Blank I Spiral Centralizer 7.85 3 bbl 79,351 Ib 15 15 20,299.32 564.68 SlottedlSpiral Centralizer 8.43 3 bbl 79,859 Ib 16 16 20,260.34 603.66 Blank I Spiral Centralizer 9.01 3 bbl 80,366 Ib 17 17 20,221.37 642.63 Sloped/Spiral Centralizer 9.59 4 bbl 80,869 Ib 18 18 20,182.72 681.28 Blank / Spiral Centralizer 10.16 4 bbl 81,370 Ib 19 19 20,144.23 719.77 Slotted/Spiral Centralizer 10.74 4 bbl 81,874 Ib 20 20 20,105.57 758.43 Blank I Spiral Centralizer 11.32 4 bbl 82,381 Ib 21 21 20,066.59 797.41 Slotted/Spiral Centralizer 11.90 4 bbl 82,883 Ib 22 22 20,028.05 835.95 Blank I Spiral Centralizer 12.47 5 bbl 83,391 Ib 23 23 19,989.05 874.95 Slotted/Spiral Centralizer 13.05 5 bbl 83,893 Ib 24 24 19,950.49 913.51 Blank I Spiral Centralizer 13.63 5 bbl 84,396 Ib 25 1 25 19,911.84 952.16 Slotted/Spiral Centralizer 14.21 5 bbl 84,898 Ib 26 26 19,873.29 990.71 Blank I Spiral Centralizer 14.78 5 bbl 85,405 Ib 27 27 19,834.32 1,029.68 Slotted/Spiral Centralizer 15.36 6 bbl 85,889 Ib 28 28 19,797.14 1,066.86 Blank I Spiral Centralizer 15.92 6 bbl 86,389 Ib 29 29 19,758.73 1,105.27 Slotted/Spiral Centralizer 16.49 6 bbl 86,896 Ib 30 30 19,719.77 1,144.23 Blank / Spiral Centralizer 17.07 6 bbl 87,375 lb 31 31 19,683.02 1,180.98 Slotted/Spiral Centralizer 17.62 7 bbl 87,876 Ib 32 32 19,644.48 1,219.52 Blank I Spiral Centralizer 18.20 7 bbl 88,380 Ib 33 33 19,605.83 1,258.17 Slotted/Spiral Centralizer 18.77 7 bbl 88,881 Ib 34 34 19,567.31 1,296.69 Blank I Spiral Centralizer 19.35 7 bbl 89,386 Ib 35 35 19,528.56 1,335.44 Slotted/Spiral Centralizer 19.92 7 bbl 89,887 Ib 36 36 19,490.02 1,373.98 Blank I Spiral Centralizer 20.50 8 bbl 90,391 Ib 37 37 19,451.37 1,412.63 Slotted/Spiral Centralizer 21.08 8 bbl 90,892 Ib 38 38 19,412.83 1,451.17 Blank I Spiral Centralizer 21.65 8 bbl 91,400 lb 39 39 19,373.85 1,490.15 Slotted/Spiral Centralizer 22.23 8bbl 91,901 Ib 40 40 19,335.32 1,528.68 Blank/ Spiral Centralizer 22.81 8bbl 92,411 Ib 41 41 19,296.19 1,567.81 Slotted/Spiral Centralizer 23.39 9 bbl 92,918 Ib 42 42 19,257.21 1,606.79 Blank I Spiral Centralizer 23.97 9 bbl 93,423 Ib 43 43 19,218.42 1,645.58 Slotted/Spiral Centralizer 24.55 9 bbl 93,931 Ib 44 44 19,179.44 1,684.56 Blank I Spiral Centralizer 25.13 9bbl 94,438 Ib 45 45 19,140.46 1,723.54 Slotted/Spiral Centralizer 25.72 10 bbl 94,943 Ib 46 46 19,101.66 1,762.34 Blank I Spiral Centralizer 26.29 10 bbl 95,468 lb 47 47 19,061.39 1,802.61 Slotted/Spiral Centralizer 26.89 10 bbl 95,969 Ib 48 48 19,022.85 1,841.15 Blank I Spiral Centralizer 27.47 10 bbl 96,474 Ib 49 49 18,984.07 1,879.93 Slotted/Spiral Centralizer 28.05 10 bbl 96,969 lb 50 50 18,946.08 1,917.92 Blank/Spiral Centralizer 28.62 11 bbl 97,478 lb 51 51 18,906.95 1,957.05 Slotted/Spiral Centralizer 29.20 11 bbl 1 of 3 pages Only Enter Red 4.5" L iner Casing ID 3.826 Casing O.D.: 4 1/2" Weight per Foot: 15.2 Grade: Pilo Threads -lydril563 RUN Strinn Wninht i!M i." Blue Crest H04 Run date: 3.11.19 52 0.0149 bbl/ft inches Block Wt: 72,000 lbs. ppf Mud Wt. 9.4 ppg Casing shoe @ MD = 15,406 Ave TQ= 8,200.00' 20,864.00 Foreman: Lawson / Ashley TALLY 12 bbl DIST. 18,680.25 2,183.75 Slotted/Spiral Centralizer 32.58 JT. NO. 100,969 Ib 58 58 18,638.81 2,225.19 Blank I Spiral Centralizer 33.20 12 bbl nn Pion Wn . I. -.h n own 101,983 Ib 60 60 Run date: 3.11.19 52 RKB TO Sea level = 179.65' Centralizers = 8.125" Pad Grade Height = 145.20' RKB to Load shoulder = 37.80 ......... 11 bbl Overlap= 198.12 Top of Liner 15210.85 11 bbl Casing shoe @ MD = 15,406 11 bbl Shoe depth TD= 20,864.00 12 bbl TD of 8 1/2" hole, MD = 20,867 97,980 lb 52 52 38.57 35.66 38.19 39.25 38.97 36.06 41.44 39.4 38.53 38.99 38.07 38.98 38.54 39.13 41.55 38.66 38.97 38.66 38.97 39.18 39.56 38.52 38.8 1 38.99 39.29 38.97 38.98 38.99 38.96 37.96 38.59 38.54 39.14 39.57 38.96 39.13 38.99 38.96 38.54 38.99 36.39 41 38.53 40.15 38.55 39.92 38.53 39.09 38.55 39.55 40.13 18,868.38 1,995.62 Blank/Spiral Centralizer 29.77 ......... 11 bbl 98,444 Ib 53 53 18,832.72 2,031.28 Slotted/Spiral Centralizer 30.31 11 bbl 98,942 Ib 54 54 18,794.53 2,069.47 Blank I Spiral Centralizer 30.88 11 bbl 99,453 lb 55 55 18,755.28 2,108.72 Slotted/Spiral Centralizer 31.46 12 bbl 99,960 Ib 56 56 18,716.31 2,147.69 Blank I Spiral Centralizer 32.04 12 bbl 100,429 Ib 57 57 18,680.25 2,183.75 Slotted/Spiral Centralizer 32.58 12 bbl 100,969 Ib 58 58 18,638.81 2,225.19 Blank I Spiral Centralizer 33.20 12 bbl 101,482 Ib 59 59 18,599.41 2,264.59 Slotted/Spiral Centralizer 33.79 13 bbi 101,983 Ib 60 60 18,560.88 2,303.12 Blank I Spiral Centralizer 34.36 13 bbl 102,491 Ib 61 61 18,521.89 2,342.11 SlottedlSpiral Centralizer 34.94 13 bbl 102,987 Ib 62 62 18,483.82 2,380.18 Blank I Spiral Centralizer 35.51 13 bbl 103,494 Ib 63 63 18,444.84 2,419.16 Slotted/Spiral Centralizer 36.09 13 bbl 103,996 Ib 64 64 18,406.30 2,457.70 Blank / Spiral Centralizer 36.67 14 bbl 104,505 Ib 65 65 18,367.17 2,496.83 SlottedlSpiral Centralizer 37.25 14 bbl 105,046 Ib 66 66 18,325.62 2,538.38 Blank I Spiral Centralizer 37.87 14 bbi 105,550 Ib 67 67 18,286.96 2,577.04 Slotted/Spiral Centralizer 38.45 14 bbl 106,057 Ib 68 68 18,247.99 2,616.01 Blank / Spiral Centralizer 39.03 14 bbl 106,560 Ib 69 69 18,209.33 2,654.67 SlottedlSpiral Centralizer 39.61 15 bbl 107,067 Ib 70 70 18,170.36 2,693.64 Blank/ Spiral Centralizer 40.19 15 bbl 107,578 Ib 71 71 18,131.18 2,732.82 Slotted/Spiral Centralizer 40.77 15 bbl 108,093 Ib 72 72 18,091.62 2,772.38 Blank I Spiral Centralizer 41.36 15 bbl 108,594 Ib 73 73 18,053.10 2,810.90 Slotted/Spiral Centralizer 41.94 16 bbl 109,099 Ib 74 74 18,014.30 2,849.70 Blank I Spiral Centralizer 42.52 16 bbl 109,607 Ib 75 1 75 17,975.31 2,888.69 Slotted/Spiral Centralizer 43.10 16 bbl 110,118 Ib 76 76 17,936.02 2,927.98 Blank I Spiral Centralizer 43.69 16 bbl 110,626 Ib 77 77 17,897.05 2,966.95 Slotted/Spiral Centralizer 44.27 16 bbl 111,133 Ib 78 78 17,858.07 3,005.93 Blank/Spiral Centralizer 44.85 17bbl 111,641 Ib 79 79 17,819.08 3,044.92 Slotted/Spiral Centralizer 45.43 17 bbl 112,148 Ib 80 80 17,780.12 3,083.88 Blank I Spiral Centralizer 46.01 17 bbl 112,642 Ib 81 81 17,742.16 3,121.84 Slotted/Spiral Centralizer 46.58 17 bbl 113,144 Ib 82 82 17,703.57 3,160.43 Blank lSpiral Centralizer 47.15 17 bbl 113,646 Ib 83 83 17,665.03 3,198.97 Slotted/Spiral Centralizer 47.73 18 bbl 114,156 Ib 84 84 17,625.89 3,238.11 Blank lSpiral Centralizer 48.31 18 bbl 114,671 Ib 85 85 17,586.32 3,277.68 Slotted/Spiral Centralizer 48.90 18 bbl 115,178 Ib 86 86 17,547.36 3,316.64 Blank I Spiral Centralizer 49.48 18 bbl 115,688 Ib 87 87 17,508.23 3,355.77 Slotted/Spiral Centralizer 50.07 19 bbl 116,195 Ib 88 88 17,469.24 3,394.76 Blank / Spiral Centralizer 50.65 19 bbl 116,702 Ib 89 89 17,430.28 3,433.72 Slotted/Spiral Centralizer 51.23 19 bbl 117,204 Ib 90 90 17,391.74 3,472.26 Blank / Spiral Centralizer 51.81 19 bbl 117,712 Ib 91 91 17,352.75 3,511.25 Slotted/Spiral Centralizer 52.39 19 bbl 118,185 Ib 92 92 17,316.36 3,547.64 Blank lSpiral Centralizer 52.93 20 bbl 118,719 Ib 93 93 17,275.36 3,588.64 Slotted/Spiral Centralizer 53.54 20 bbl 119,221 Ib 94 94 17,236.83 3,627.17 Blank I Spiral Centralizer 54.12 20 bbl 119,743 Ib 95 95 17,196.68 3,667.32 Slotted/Spiral Centralizer 54.72 20 bbl 120,245 Ib 96 96 17,158.13 3,705.87 Blank I Spiral Centralizer 55.29 21 bbl 120,765 lb 97 97 17,118.21 3,745.79 Slotted/Spiral centralizer55.89 21 bbl 121,267 Ib 98 98 17,079.68 3,784.32 Blank lSpiral Centralizer 56.46 21 bbl 121,776 lb 99 99 17,040.59 3,823.41 SlottedlSpiral Centralizer 57.05 21 bbl 122,277 Ib 100 100 17,002.04 3,861.96 Blank lSpiral Centralizer 57.62 21 bbl 122,792 Ib 101 101 16,962.49 3,901.51 'Otte SpCentralizer 58.21 22 bbl 123,315 Ib 102 102 16,922.36 3,941.64 Blank I Spiral Centralizer 58.81 22 bbl 2 of 3 pages Only Enter Red 4.5" L iner Casing ID 3.826 Casing O.D.: 41/21, Weight per Foot: 15.2 Grade: Pilo Threads -lydril563 RUN Strinn Wwinht 8nf he Blue Crest H04 Run date: 3.11.19 103 0.0149 bbl/ft inches Block Wt: 72,000 lbs. ppf Mud Wt. 9.4 ppg Casing shoe @ MD = 15,406 Ave TQ= 8,200.00' 20,864.00 Foreman: Lawson / Ashley TALLY 23 bbl DIST. 16,685.86 4,178.14 Blank / Spiral Centralizer 62.34 JT. NO. 126,903 Ib 109 109 16,646.74 4,217.26 Slotted/Spiral Centralizer 62.92 23 bbl nn pin" i.,i". ie",..h 24 bbl 127,918 Ib 111 111 Run date: 3.11.19 103 RKB TO Sea level = 179.65' Centralizers = 8.125" Pad Grade Height = 145.20' RKB to Load shoulder = 37.80 rmporcuivw 22 bbi Overlap= 198.12 Top of Liner 15210.85 22 bbl Casing shoe @ MD = 15,406 22 bbl Shoe depth TD= 20,864.00 23 bbl TD of 8 1/2" hole, MD = 20,867 123,826 Ib 103 103 39.29 39.87 38.97 40.14 38.95 39.28 39.12 38.97 38.98 38.98 38.96 38.94 38.98 39.64 37.82 40.66 38.84 39.13 38.7 38.58 39.52 38.98 38.79 38.54 38.55 1 39.09 36.69 38.95 36.3 40.25 39.14 38.18 38.16 38.46 39.43 39.32 38.99 38.99 39.13 39.13 38.16 38.98 38.57 1.3 17.1 23.011 16,883.07 3,980.93 Slotted/Spiral Centralizer 59.40 rmporcuivw 22 bbi 124,345 Ib 104 104 16,843.20 4,020.80 Blank / Spiral Centralizer 59.99 22 bbl 124,853 Ib 105 105 16,804.23 4,059.77 Slotted/Spiral Centralizer 60.57 22 bbl 125,375 Ib 106 106 16,764.09 4,099.91 Blank I Spiral Centralizer 61.17 23 bbl 125,882 Ib 107 107 16,725.14 4,138.86 Slotted/Spiral Centralizer 61.75 23 bbl 126,394 Ib 108 108 16,685.86 4,178.14 Blank / Spiral Centralizer 62.34 23 bbl 126,903 Ib 109 109 16,646.74 4,217.26 Slotted/Spiral Centralizer 62.92 23 bbl 127,410 Ib 110 110 16,607.77 4,256.23 Blank i Spiral Centralizer 63.50 24 bbl 127,918 Ib 111 111 16,568.79 4,295.21 Slotted/Spiral Centralizer 64.08 24 bbl 128,425 Ib 112 112 16,529.81 4,334.19 Blank / Spiral Centralizer 64.67 24 bbl 128,932 ib 113 113 16,490.85 4,373.15 Slotted/Spiral Centralizer 65.25 24 bbl 129,439 Ib 114 114 16,451.91 4,412.09 Blank / Spiral Centralizer 65.83 24 bbl 129,947 Ib 115 115 16,412.93 4,451.07 Slotted/Spiral Centralizer 66.41 25 bbl 130,463 Ib 116 116 16,373.29 4,490.71 Blank / Spiral Centralizer 67.00 25 bbl 130,955 Ib 117 117 16,335.47 4,528.53 Slotted/Spiral Centralizer 67.57 25 bbl 131,485 Ib 118 118 16,294.81 4,569.19 Blank / Spiral Centralizer 68.17 25 bbl 131,990 Ib 119 119 16,255.97 4,608.03 Slotted/Spiral Centralizer 68.75 25 bbl 132,500 Ib 120 120 16,216.84 4,647.16 Blank/ Spiral Centralizer 69.34 26 bbl 133,003 Ib 121 121 16,178.14 4,685.86 Siotted/Sphal Centralizer 69.91 26 bbl 133,506 Ib 122 122 16,139.56 4,724.44 Blank I Spiral Centralizer 70.49 26 bbl 134,020 Ib 123 123 16,100.04 4,763.96 Slotted/Spiral Centralizer 71.08 26 bbl 134,528 Ib 124 124 16,061.06 4,802.94 Blank / Spiral Centralizer 71.66 27 bbl 135,033 Ib 125 125 16,022.27 4,841.73 Slotted/Spiral Centralizer 72.24 27 bbl 135,534 ib 126 126 15,983.73 4,880.27 Blank / Spiral Centralizer 72.81 27 bbl 136,036 Ib 127 127 15,945.18 4,918.82 SlottedlSpiral Centralizer 73.39 27 bbl 136,545 Ib 128 1 128 15,906.09 4,957.91 Blank / Spiral Centralizer 73.97 27 bbl 137,023 Ib 129 129 15,869.40 4,994.60 Slotted/Spiral Centralizer 74.52 28 bbl 137,530 Ib 130 130 15,830.45 5,033.55 Blank / Spiral Centralizer 75.10 28 bbl 138,002 Ib 131 131 15,794.15 5,069.85 SlottedlSpiral Centralizer 75.64 28 bbl 138,526 Ib 132 132 15,753.90 5,110.10 Blank/Spiral Centralizer 76.24 28 bbl 139,036 Ib 133 133 15,714.76 5,149.24 Slotted/Spiral Centralizer 76.83 28 bbl 139,533 Ib 134 134 15,676.58 5,187.42 Blank I Spiral Centralizer 77.40 29 bbl 140,030 Ib 135 135 15,638.42 5,225.58 Slotted/Spiral Centralizer 77.97 29 bbl 140,531 Ib 136 136 15,599.96 5,264.04 Blank/Spiral Centralizer 78.54 29 bbl 141,044 Ib 137 137 15,560.53 5,303.47 Slotted/Spiral Centralizer 79.13 29 bbl 141,556 Ib 138 138 15,521.21 5,342.79 Blank I Spiral Centralizer 79.71 30 bbl 142,063 Ib 139 139 15,482.22 5,381.78 Slotted/Spiral Centralizer 80.30 30 bbl 142,571 ib 140 140 15,443.23 5,420.77 Blank / Spiral Centralizer 80.88 30 bbl 143,080 Ib 141 141 15,404.10 5,459.90 Solid 81.46 30 bbl 143,590 Ib 142 142 15,364.97 5,499.03 Solid 82.05 30 bbl 144,087 Ib 143 143 15,326.81 5,537.19 Solid 82.61 31 bbl 144,594 lb 144 144 15,287.83 5,576.17 solid 83.20 31 bbl 145,096 Ib 145 145 15,249.26 5,614.74 Solid 83.77 31 bbl 145,113 lb 146 15,247.96 5,616.04 xO 83.79 31 bbl 145,3361b 147 15,230.86 5,633.14 PBR 84.05 31 bbl 145,6351b 148 15,207.851 5,656.15 1 Liner Hanger 84.39 1 31 bbl 3 of 3 pages WellView Well Name: H04 Cement Surface Casing Cement APIIUWI 50-231-20064-00-00 Surface Legal Location 2nr sSL. 1552 FEL, s.r2. T+s. R15N Field Name Hansen License# 218-126 SfateiProvince AK Well Configuration Type Fish bone Ground Elevation (R) 145.20 Casing Flange Elevation (R) 139.17 KB -Ground Distance (R) 34.45 KB -Casing Flange Distance(R) . 40.48 Spud Date 12/27/2018 16:30 Rig Release Date Surface casing Cement, Casing, 1/4/2019 18:48 Type Casing I Cementing Start Date 1/4/2019 Cementing End Dale 1/5/2019 WellboreString Original Hole 13 3/8" surface casing, 5,799.6ftKB Cementing Company Dowell Schlumberger Evaluation MethotlCement Returns to Surface Evaluation Results 200 BBLS cement to surface Comment 1, 40.0-4,799.0ftKB Top Depth (RKB) 40.0 Bottom Depth (RKB) 4,799.0 Full Return? Yes Vol Cement Ret (bbl) 0.0 Top Plug? No Bottom Plug? Yes miles Pump Rate (bbVmin) 4 Final Pump Rate (bbVmin) 4 Avg Pump Rate (bbVmin) 4 Final Pump Pressure (poi) 200.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (RKB) Tag Method Depth Ptug DrIled Out To (R(B) Drill Out Diameter (in) Dnll Out Date Lead Fluid Type Lead Fluid Desaiption 13# lead cement Amount (sacks) 2,160 Class A Volume Pumped (bbl) 787.0 Estimated Top (MB) 40.0 Estimated Bottom Depth (RKB) 4,799.0 Percent Excess Pumped (%) 32.0 Yield (Repack) 1.95 Mm H2o Radio (gal/sack) 10.67 Free Water (%) Density (IbNgal) 13.00 Plastic Viscosity (CP) Thickening Time (hp 1st Compressive Strength (psi) Cement Fluid Additives Add Type Corm anti foam D47 0.05 2, 4,799.0-5,799.OftKB Top Depth (flKB) 4,799.0 Bottom Depth (RKB) 5,799.0 Full Return? Yes Vol Cement Ret (bbI) 200.0 Top Plug? lYes Bottom Plug? No Initial Pump Rate (bbVmin) 3 Final Pump Rate (bbVmin) 3 Avg Pump Rate (bbVmin) 3 Final Pump Pressure (psi) 750.0 Plug Bump Pressure (psi) 1,250.0 Pipe Reciprocated' No Reciprocation Stroke Length (ft) Reciprocator, Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (RKB) Tag Method Depth Plug Dried Out To (RKB) DMI Out Diameter (in) Drill Out Date Tail Fluid Type Tail Fluid Description Tail cement Amount (sacks) 818 Class G Volume Pumped (bbl) 176.0 Estimated Top (RKB) 4,799.0 Estimated Bottom Depth (RKB) TPercent 5,799.0 132.0 Excess Pumped (%) Yield (W/sack) 1.16 Mot H2O Ratio (gal/sack) 5.12 Free Water (%) Density(lb/gap Plastic Viscosity(cP) Thickening Time (m) tat Compressive Strength (psi) Cement Fluid Additives Add Type Card Low temp retarder Anti foam D177 D47 0.005 0.02 I _ __ -__-"-._--..- Page t/1 ReportPrinted: 3/14/2019 WeliViewe Well Name: HO4 Cement �3/g `t j Surface top job APINWI 50-231-20064-00-00 Surface Legal Location z+ra rst. ssz rat. sxz. res, R,aw... Field Name Hansen L¢ensez 218-126 StatelProvince AK Well configuration Type Fish bone Ground Elevation (fl) 145.20 Casing Flange Elevation (fl) 139.17 K&Grcuntl Distance (ftJ 34.45 KB -Casing Flange Distance (ft) 40.48 Spud Date 12/27/201816:30 Fog Release Date Surface top job, Casing, 1/7/2079 11:24 Type Casing Cementing Start Date 117/2019 Cementing Entl Date 1/712019 We11Dore original Hole Shing 13 316" surface casing, 5,799.60KB Cementing Company Dowell Schlumberger Evaluation McUwO velums to surface Cement Evaluation Results 2 BBLS back to the cellar Comment The original cement job settled down 60 feet in the conductor 6 to 7 hours after bumping the plug. fop 60 feet down from load shoulder. Brought cement to surface. pumped 16 BBLS 15.8 PPG class G cement. Tagged cement 1, 40.0.700.ORK8 Top Deptl, (NKa) 40.0 Bottom Depth (flKB) 100.0 Full Return? No Vol Cement Rel (bhp 1.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbgmin) 1 Final Pump Rale (bbNnin) 1 Avg Pump Rate (bblhnin) t Final Pump Pressure (psi) 10.0 Plug Bump Pressure (psi) Pipe Retiprocatetl? No Redprocation Stroke Length (N) Radprece4on Rate (spm) Pipe Rcletetl? No Pipe RPM (rpm) Tagged Depth (flKB) Tag Methotl Depth Plug Drllletl Out To (flKB) Dell Out Diameter (in) Drill Out Date Tail Fluid Type Tail Fluid Description Gass G tail cement Amount (sacks) 75 Class G Volume Pumpetl (bM) 16.0 Estimated Top (flKB) 40.0 Estimated Bottom Depth (flKB) 100.0 Percent Excess Pumped (%) 0.0 Yield (R/satic) 1.16 Mix H20 Ratio (gaUsack) 5.12 Free Water I°o) Density (Ib/gep Plastic viscosity (CP) Tbidening Time (hr) tat Compressive Strength (psi) Cement Fluid Additives type Conc Add ' age 1/[ ReportPrinted: 311412019 type Conc WellViewe Well Name: H04 Cement (- 4 1 Intermediate single stage job APIA/WI Surtaca Le gal Location Field Name ❑censett Shde/Province Well Configuration Type 50-231-20064-00-00 z,7r vsL:, ru., sem, Ue asw_. Hansen 218-126 AK Fish bone ro Elevation (R) Casing Flange Elavaiion (R) rice (R) KBCasing Flange Distance (R) ASpua Date Rig Release Data 145.20 139.17 40.48 12/27/2018 16:30 Intermediate single stage job, Casing, 1/241201917:45 Type Cementing Start Data CamerRing End Date Wellbore Stang Casing 1/24/2019 1/24/2019 Original Hole 9 5/8" Intermediate, 15,406.1ftKB cementing Company I Evaluation Method Cement Evaluation Results Dowell Schlumberger Calculations Did not bump the plug, pumped half of the shoe track. Floats held. 100% returns. Comment Intermediate:1104. Blue Crest. 1.24.2019 9.625" 47# cemented in 12.25" hole. MU plug launcher and hardline, SLB loaded lines with 5 bbls water and checked for leaks. SLB pressure tested lines at 300 low 3500 high, good tests. Dropped first plug. Rig pumped 98 bbls 13 ppg MudPush II at 4 bpm and shut down. SLB dropped 2nd bottom plug and pumped 139.3 bbls (678 sx) 15.8 ppg Class G cement at 3.5 bpm.SLB dropped top plug, then displaced with 10 bbls water. The rig pumped 10 BBLS 13 ppg MP2 with no fiber @ 4 BPM 400 psi, followed by 1105 BBLS 10.5 PPG OBM. Slowed to 3 bpm with 40 bbl to go. Pumped half the shoe track. Did not bump the plug. Held 400 psi (FCP of 580 psi) for 5 minutes, bled off and floats held. Bled back 1/4 bbl into trash can on rig floor. Mix water temp at 70 deg. Pumped 50% excess. Did not attempt to reciprocate the string.CIP at 21:54 hrs, 01-24-2019. RD and released Schlumberger. 1, 13,907.0-15,406.01tK6 Top Depth (RKB) Bottom Depth (RKB) Full Return? Vol Cement Ret (bbl) Top Plug? Bottom Plug? 13,907.0 15,406.0 Yes 0.0 Yes Yes InNal Pump Rate (bbVmin) Final Pump Rate (bbgmin) Avg Pump Rate (bbgmin) Final Pump Pressure (psi) Plug Bump Pressure (pti) 4 3 4 580.0 0.0 Pipe Reciprocated? Reciprocation Stroke Length (R) Reciprocation Rete (Spm) Pipe Rotated? Pipe RPM (mm) No No Tagged Depth (fll(B) Tag Method Depth Plug Drilled Out To (RKB) Drill Out Diameter (in) Drill Out Date Tail Fluid Type Fluid Description u sacks) Class Volume Pumped (bbl) Tail 10.5 1678 G 139.3 Estimated Top (RKB) Estimated Bottom Depth (RKB)Pe t Excess Pumped (%) ie (IRsack) Ma H2O Ratio (gallsack) 13,907.0 15,406.0 .0 1.16) 5.12 Free Water (%) Density ([West) Plastic Viscosity (cP) N Ikkkening Time (hr) 1st Compressive Strength (psi) 15.80 5.20 Cement Fluid Additives Add Type Cone High Temp Retarder D177 0.035 Fluid Loss Control D255 0.4 Liquid Antifoam Agent D47 0.02 Cement Dispersant D65 0.3 Page 111 ReportPrinted: 3114/2019 nue est Energy Cosmopolitan Project Wellhead/Tree 10-401 APD Attachments Wellhead/Tree 6 > 1�llelz lA l l - Gator Crossover 15207.88 Joint Count Category Component Length Cum Length BTM I TOP OD ID Drift SLB_Equip Seal Assembly 5.28 5.28 15245.56 15240.28 4.75 3.755 3.68 SLG Equip 3-1/2 TSH -511 Jt 32.40 37.68 15240.28 15207.88 3.50 2.992 2.867 SLB Equip Locator5ub 1.31 38.99 15207.88 15206.57 8.50 2.992 2.867 SLB Equip Crossover 3-1/2"IBT-M Boxx ELIE Pin 1.81 40.80 15206.57 15204.76 4.25 2.99 2.87 1 Tubing_9.3ppf 1 32.99 73.79 15204.76 15171.77 3.50 2.992 2.867 2 Tubing_9.3ppf 2 32.92 106.71 15171.77 15138.85 3.50 2.992 2.867 SLB -Equip 3.5"SGM Bottom Pup (9.2# IBT-M BOX x9.2# IBT-M PIN) 14.71 121.42 15138.85 15124.14 4.27 2.992 2.867 SLB Equip 3.5" SGM Bottom XO Pup (9.3# 8RD-M BOX x IBT-M 9.3# PIN) 1.34 122.76 15124.14 15122.80 3.75 2.992 2.867 SLB Equi 3-1/2,9.30,SGM 6.51 129.27 15122.80 15116.29 5.12 2.918 2.867 SLB_Equip �, 3.5" SGM Top XO Pup (9.2# IBT-M BOX x 9.3# 8RD-M PIN) 1.55 130.82 15116.29 1 15114.74 3.75 2.992 2.867 3 51-13_Equip Tubing_9.3ppf 3.5" SGM Top Pup (9.2# IBT-M BOX x 9.2# IBT-M PIN) 3 14.74 33.04 145.56 178.60 15114.74 15100.00 15100.00 15066.96 4.27 3.50 2.992 2.992 2.867 2.867 4 Tubing_9.3ppf 4 33.05 211.65 15066.96 15033.91 3.50 2.992 2.867 5 Tubing 9.3ppf 5 32.90 244.55 15033.91 15001.01 3.50 2.992 2.867 6 Tubing_9.3ppf 6 32.98 277.53 15001.01 14968.03 3.50 2.992 2.867 7 Tubing_9.3ppf 7 32.81 310.34 14968.03 14935.22 3.50 2.992 2.867 8 Tubing_9.3ppf 8 32.97 343.31 14935.22 14902.25 3.50 2.992 2.867 9 Tubing_9.3ppf 9 32.85 376.16 14902.25 14869.40 3.50 2.992 2.867 10 Tubing_9.3ppf 10 33.00 409.16 14869.40 14836.40 3.50 2.992 2.867 11 Tubing_9.3ppf 11 32.89 442.05 14836.40 1 14803.51 3.50 2.992 2.867 12 Tubing_9.3ppf 12 32.82 474.87 14803.51 14770.69 3.50 2.992 2.867 13 Tubing_9.3ppf 13 33.02 507.89 14770.69 14737.67 3.50 2.992 2.867 14 Tubing_9.3ppf 14 32.88 540.77 14737.67 14704.79 3.50 2.992 2.867 15 Tubing_9.3ppf15 32.92 573.69 14704.79 14671.87 3.50 2.992 2.867 16 Tubing_9.3ppf 16 33.04 606.73 14671.87 14638.83 3.50 2.992 2.867 17 Tubing_9.3ppf 17 32.98 639.71 14638.83 14605.85 3.50 2.992 2.867 18 Tubing_9.3ppf 18 32.85 672.56 14605.85 14573.00 3.50 2.992 2.867 19 Tubmg_9.3ppf 19 33.06 705.62 14573.00 14539.94 3.50 1 2.992 2.867 20 Tubing_9.3ppf 20 32.64 738.26 14539.94 14507.30 3.50 1 2.992 2367 21 Tubing_9.3ppf 21 33.22 771.48 14507.30 1 14474.08 3.50 2.992 2.867 Equip 3.5' XS Bottom Pup (9.2# IBT-M BOX x IBT-M 9.3# PIRr 14.72 786.20 14474,081 14459.36 quip ip 31/2" Xl 2.813 X -LANDING NIPPLE#9.31BT-M BXP 3.S' XI TOP P. .9.2#1 L.-. 0%x9.2#IBT-M PIN) 1.48 14.74 787.68 802.42 14459.36 14457.88 14457.88 14443.14 4.26 4.26 2.813 2.992 2.808 2.808' 22 Tubing 9.3ppf 22 32.80 835.22 14443.14 14410.34 3.50 2.992 2.867 23 Tubing_9.3ppf 23 32.88 868.10 14410.34 14377.46 3.50 2.992 2.867 24 Tubing_9.3ppf 24 33.07 901.17 14377.46 14344.39 3.50 2.992 2.867 25 Tubing_9.3ppf 25 32.90 934.07 14344.39 14311.49 3.50 2.992 2.857 SLB Equip 3.5" GLMI Bottom Pup (9.2# IBT-M BOX x 18T -M 9.3# PIN) 14.70 948.77 14311.49 14296.79 4.25 2.992 2.867 SLB Equip GLMI, 3-1/2 MMG, W RK LATCH 1.5" DUMMY INSTALLED 8.82 957.59 14296.79 14287.97 5.97 2.92 2.867 SLB Equip 35'GLMl Top Pu f9.2#.IBT-MBOXx9.2#IBT-MPI% 1' 971.91 : 428 97 14273.65 4.27 2, 2.867 26 Tubing_9.3ppf 26 33.06 1004.97 14273.65 14240.59 3.50 2.992 2.867 27 Tubing_9.3ppf 27 33.02 1037.99 14240.59 14207.57 3.50 2.992 2.867 28 Tubing_9.3ppf 28 33.99 1071.98 14207.57 14173.58 3.50 2.992 2.867 29 Tubing_9.3ppf 29 33.04 1105.02 14173.58 14140.54 3.50 2.992 -27867- 30 Tubing_9.3ppf 30 32.86 1137.88 14140.54 14107.68 3.50 2.992 2.867 31 Tubing_9.3ppf 31 32.87 1170.75 14107.68 14074.81 3.50 2.992 2.867 32 Tubing_9.3ppf 32 33.06 1203.81 14074.81 14041.75 3.50 2.992 2.867 33 Tubing_9.3ppf 33 32.94 1236.75 14041.75 14008.81 3.50 2.992 2.867 34 Tubing_9.3ppf 34 33.03 1269.78 14008.81 13975.78 3.50 2.992 2.867 35 Tubing_9.3ppf 35 33.05 1302.83 13975.78 13942.73 3.50 2.992 2.867 36 Tubing_9.3ppf 36 32.83 1335.66 13942.73 13909.90 3.50 2.992 2.867 37 Tubing_9.3ppf 37 33.01 1368.67 13909.90 13876.89 3.50 2.992 2.867 38 Tubing_9.3ppf 38 32.88 1401.55 13876.89 13844.01 3.50 2.992 2.867 39 Tubing_9.3ppf 39 32.90 1434.45 13844.01 13811.11 3.50 2.992 2.867 40 Tubing_9.3ppf 40 33.06 1467.51 13811.11 13778.05 3.50 2.992 2.867 41 Tubing_9.3ppf 41 33.02 1500.53 13778.05 13745.03 3.50 2.992 2.867 42 Tubing_9.3ppf 42 33.00 1533.53 13745.03 13712.03 3.50 j 2.992 2.867 43 Tubing_9.3ppf 43 33.07 1566.60 13712.03 13678.96 3.50 2.992 1 2.867 44 Tubing_9.3ppf44 33.03 1599.63 13678.96 13645.93 3.50 2.992 2.867 45 Tubing_9.3ppf 45 33.01 1632.64 13645.93 13612.92 3.50 2.992 2.867 SLB_Equip 3.5' DCIN Bottom Pup (9.2# IBT-M BOX x IBT-M 9.3# PIN) 14.70 1647.34 13612.92 13598.22 4.27 2.992 2.867 SLB Equip 3-1/2,DCIN ASSEMBLY 1.86 1649.20 13598.22 13596.36 5.70 2.942 2.867 SLB Equip 3.5" DON Top Pup (9.2# IBT-M BOX x 9.2# IBT-M PIN) 14.72 1663.92 13596.36 13581.64 4.26 2.992 2.867 46 Tubing_9.3ppf 46 32.85 1696.77 13581.64 13548.79 3.50 2.992 2.867 47 Tubing 9.3ppf 47 32.87 1729.64 13548.79 13515.92 3.50 2.992 2.867 48 Tubing_9.3ppf 48 32.85 1762.49 13515.92 13483.07 1 3.50 2.992 2.867 49 Tubing_9.3ppf 49 33.01 1795.50 13483.07 13450.06 3.50 2.992 2.867 50 Tubing 9.3ppf 50 33.02 1828.52 13450.06 13417.04 3.50 2.992 2.867 51 Tubing_9.3ppf 51 32.88 1861.40 13417.04 13384.16 3.50 1 2.992 12.867 52 Tubing_9.3ppf52 32.48 1893.88 13384.16 13351.68 3.50 2.992 2.867 53 Tubing_9.3ppf 53 33.07 1926.95 13351.68 13318.61 3.50 2.992 2.867 54 Tubing_9.3ppf 54 32.98 1959.93 13318.61 13285.63 3.502.992 1 2.867 ator Crossover 1%7n7RM Joint Count Category Component Length Cum Length BTM -T-OP--OD ID Drift 55 Tubing_9.3ppf 55 32.84 1992.77 13285.63 13252.79 3.50 2.992 2.867 56 Tubing_9.3ppf 56 32.98 2025.75 13252.79 13219.81 3.50 2.992 2.867 57 Tubing_9.3ppf 57 33.06 2058.81 13219.81 13186.75 3.50 2.992 2.867 58 Tubing_9.3ppf 58 32.99 2091.80 13186.75 13153.76 3.50 2.992 2.867 59 Tubing_9.3ppf 59 33.00 2124.80 13153.76 13120.76 3.50 2.992 2.867 60 Tubing_9.3ppf 60 32.90 2157.70 13120.76 13087.86 3.50 2.992 2.867 61 Tubing_9.3ppf 61 33.01 2190.71 13087.86 13054.85 3.50 2.992 2.867 62 Tubing_9.3ppf 62 33.00 2223.71 13054.85 13021.85 3.50 2.992 2.867 63 ITubing 9.3ppf 63 32.96 2256.67 13021.85 12988.89 3.50 2.992 2.867 64 Tubing9,3ppf 64 32.92 2289.59 12988.89 12955.97 3.50 2.992 2.867 65 Tubing_9.3ppf 65 32.83 2322.42 12955.97 12923.14 3.50 2.992 2.867 66 Tubing_9.3ppf 66 32.82 2355.24 12923.14 12890.32 3.50 2.992 2.867 67 Tubing_9.3ppf 67 32.89 2388.13 12890.32 12857.43 3.50 2.992 2.867 68 Tubing_9.3ppf 68 32.55 2420.68 12857.43 12824.88 3.50 2.992 2.867 69 Tubi n 9.3ppf 69 32.62 2453.30 12824.88 12792.26 3.50 2.992 2.867 70 Tubing_9.3ppf 70 33.02 2486.32 12792.26 12759.24 3.50 2.992 2.867 71 Tubing 9.3ppf 71 32.91 2519.23 12759.24 12726.33 3.50 2.992 2.867 72 Tubing_9.3ppf 72 33.01 2552.24 12726.33 12693.32 3.50 1 2.992 2.867 73 Tubing 9.3ppf 73 32.84 2585.08 12693.32 1 12660.48 3.50 2.992 2.867 74 Tubing_9.3ppf 74 32.88 2617.96 12660.48 12627.60 3.50 2.992 2.867 75 Tubing_9.3ppf 75 33.00 2650.96 12627.60 12594.60 3.50 2.992 2.867 76 Tubing_9.3ppf 76 32.99 2683.95 12594.60 12561.61 3.50 2.992 2.867 77 Tubing_9.3ppf 77 32.44 2716.39 12561.61 12529.17 3.50 2.992 2.867 78 Tubing_9.3ppf 78 32.98 2749.37 12529.17 12496.19 3.50 2.992 2.867 79 Tubing_9.3ppf 79 32.90 2782.27 12496.19 12463.29 3.50 2.992 2.867 80 Tubing_9.3ppf 80 32.84 2815.11 12463.29 12430.45 3.50 2.992 2.867 81 Tubing_9.3ppf 81 32.82 2847.93 12430.45 12397.63 3.50 2.992 2.867 82 Tubing_9.3ppf 82 33.06 2880.99 12397.63 12364.57 3.50 2.992 2.867 83 Tubing_9.3ppf 83 32.97 2913.96 12364.57 12331.60 3.50 2.992 2.867 84 ITubina 9.3ppf 84 33.07 2947.03 12331.60 12298.53 3.50 2.992 2.867 85 Tubing_9.3ppf 85 33.00 2980.03 12298.53 12265.53 3.50 2.992 2.867 86 Tubing_9.3ppf 86 33.06 3013.09 12265.53 12232.47 3.50 2.992 2.867 87 Tubing_9.3ppf 87 32.82 3045.91 12232.47 12199.65 3.50 2.992 2.867 88 Tubing_9.3ppf 88 32.88 3078.79 12199.65 12166.77 3.50 2.992 2.867 89 Tubing_9.3ppf 89 32.99 3111.78 12166.77 12133.78 3.50 2.992 -T8-67- 90 Tubing 9.3ppf 90 32.97 3144.75 12133.78 12100.81 3.50 2.992 2.867 91 Tubing_9.3ppf 91 33.05 3177.80 12100.81 12067.76 3.50 1 2.992 2.867 92 Tubing_9.3ppf 92 32.97 3210.77 12067.76 12034.79 3.50 1 2.992 2.867 93 Tubing_9.3ppf 93 32.98 3243.75 12034.79 12001.81 3.50 1 2.992 2.867 94 Tubing_9.3ppf 94 33.05 3276.80 12001.81 11968.76 3.50 1 2.992 2.867 95 Tubing_9.3ppf 95 32.87 3309.67 11968.76 11935.89 3.50 2.992 2.867 96 Tubing_9.3ppf 96 33.09 3342.76 11935.89 11902.80 3.50 2.992 78-67- 97 Tubing_9.3ppf 97 32.88 3375.64 11902.80 11869.92 3.50 2.992 2.867 98 Tubing_9.3ppf 98 32.47 3408.11 11869.92 11837.45 3.50 2.992 2.867 99 Tubing_9.3ppf 99 33.13 3441.24 11837.45 11804.32 3.50 2.992 2.867 100 Tubing_9.3ppf 100 32.88 3474.12 11804.32 11771.44 3.50 2.992 2.867 101 Tubing_9.3ppf 101 32.98 3507.10 11771.44 11738.46 3.50 2.992 2.867 102 Tubing 9.3ppf 102 32.79 3539.89 11738.46 11705.67 3.50 2.992 2.867 103 Tubing_9.3ppf 103 32.85 3572.74 11705.67 11672.82 3.50 2.992 2.867 104[Tubing-9.3ppf 104 32.89 3605.63 11672.82 11639.93 3.50 2.992 2.867 105 Tubing_9.3ppf 105 33.04 3638.67 11639.93 11606.89 3.50 2.992 2.867 106 Tubing_9.3ppf 106 33.06 3671.73 11606.89 11573.83 3.50 2.992 2.867 107 Tubing_9.3ppf 107 33.08 3704.81 11573.83 11540.75 3.50 2.992 2.867 108 Tubing_9.3ppf 108 32.85 3737.66 11540.75 11507.90 3.50 2.992 2.867 109 Tubing_9.3ppf 109 32.88 3770.54 11507.90 11475.02 3.50 2.992 2.867 110 Tubing_9.3ppf 110 32.90 3803.44 11475.02 11442.12 3.50 2.992 2.867 111 Tubing_9.3ppf 111 33.00 3836.44 11442.12 11409.12 3.50 2.992 2.867 112 Tubing_9.3ppf 112 33.07 3869.51 11409.12 11376.05 3.50 2.992 2.867 113 Tubing_9.3ppf 113 33.06 3902.57 11376.05 11342.99 3.50 2.992 2.867 114 Tubing_9.3ppf 114 33.02 3935.59 11342.99 11309.97 3.50 2.992 2.867 115 Tubing_9.3ppf 115 33.04 3968.63 11309.97 11276.93 3.50 2.992 2.867 116 ITubing 9.3ppf 116 32.99 4001.62 11276.93 11243.94 3.50 2.992 2.867 117 ITubing_9.3ppf 117 33.04 4034.66 11243.94 11210.90 3.50 2.992 2.867 118 ITubing 9.3ppf118 33.00 4067.66 11210.90 11177.90 3.50 2.992 2.867 119 Tubing_9.3ppf 119 33.03 4100.69 11177.90 11144.87 3.50 2.992 2.867 120 Tubing_9.3ppf 120 32.99 4133.68 11144.87 11111.88 3.50 2.992 2.867 121 Tubing_9.3ppf 121 32.42 4166.10 11111.88 11079.46 3.50 2.992 2.867 122 Tubing 9.3ppf 122 33.01 4199.11 11079.46 11046.45 3.50 2.992 2.867 123 Tubing_9.3ppf 123 33.00 4232.11 11046.45 11013.45 3.50 2.992 2.867 124 Tubing_9.3ppf 124 32.78 4264.89 11013.45 10980.67 3.50 2.992 2.867 125 Tubing 125 32.74 4297.63 10980.67 30947.93 3.50 2.992 2.867 126 Tubing 9.3ppf 126 33.07 1 4330.70 10947.93 10914.86 3.50 2.992 2.867 I ..Gator Cro550Ver 15207.98 Joint Count Category Component Length Cum Length BTM TOP OD ID Drift 127 Tubing9.3pPf 127 33.06 4363.76 10914.86 10881.80 3.50 2.992 2.867 128 Tubing_9.3ppf 128 32.97 4396.73 10881.80 10848.83 3.50 2.992 2.867 129 Tubing9.3ppf 129 32.85 4429.58 10848.83 10815.98 3.50 2.992 2.867 130 Tubing_9.3ppf 130 32.98 4462.56 10815.98 10783.00 3.50 2.992 2.867 131 Tubing9.3ppf 131 32.84 4495.40 10783.00 10750.16 3.50 2.992 2.867 132 Tubing_9.3ppf 132 32.79 4528.19 10750.16 10717.37 3.50 2.992 2.867 133 Tubing_9.3ppf 133 32.48 4560.67 10717.37 10684.89 3.50 2.992 2.867 SLB _Equip SLB Equip 3.5"GLM2 Bottom Pup(9.2#IBT-M BOX IBT-M 9.3# PIN) _ GLM2, 3-1/2 MMG, W RK LATCH 1.1" OUMMV INSTAI.� . _ 81 4575.37 4584.18 10684.89 10670.19 10670.19 10661.3 .�_ 2.992 2.915 2.867 2.867 SLB Equip 3.5" GLM2 Top Pup (9.2#IBT-M BOX x 9.2# IBT-M PA 14.38 4598.56 10661.38 10647 4.26 2.992 2.867 134 Tubing_9.3ppf 134 33.03 4631.59 10647.00 10613.97 3.50 2.992 2.867 135 Tubing_9.3ppf 135 32.86 4664.45 10613.97 10581.11 3.50 2.992 2.867 136 Tubing_9.3ppf 136 32.66 4697.11 10581.11 10548.45 3.50 2.992 2.867 137 Tubing_9.3ppf 137 32.94 4730.05 10548.45 10515.51 3.50 2.992 2.867 138 Tubing_9.3pPf 138 32.98 4763.03 10515.51 10482.53 3.50 2.992 2.867 139 Tubing_9.3ppf 139 33.04 4796.07 10482.53 10449.49 3.50 2.992 2.867 140 Tubing_9.3ppf 140 33.02 4829.09 10449.49 10416.47 3.50 2.992 2.867 141 Tubing_9.3ppf 141 33.01 4862.10 10416.47 1 10383.46 3.50 2.992 2.867 142 Tubing_9.3ppf 142 32.73 4894.83 10383.46 10350.73 3.50 2.992 1 2.867 143 Tubing_9.3ppf 143 33.01 4927.84 10350.73 10317.72 3.50 2.992 2.867 144 Tubing_9.3ppf 144 33.06 4960.90 10317.72 10284.66 3.50 2.992 2.867 145 Tubing 9.3ppf 145 33.07 4993.97 10284.66 10251.59 3.50 2.992 2.867 146 Tubing 9.3ppf 146 33.05 5027.02 10251.59 10218.54 3.50 2.992 2.867 147 Tubing_9.3ppf 147 33.04 5060.06 10218.54 10185.50 3.50 2.992 2.867 148 Tubing_9.3ppf 148 32.94 5093.00 10185.50 10152.56 3.50 2.992 2.867 149 Tubing_9.3ppf 149 33.01 5126.01 10152.56 10119.55 3.50 2.992 2.867 150 Tubing_9.3ppf 150 32.94 5158.95 10119.55 10086.61 3.50 2.992 2.867 151 Tubing_9.3ppf 151 33.06 5192.01 10086.61 10053.55 3.50 2.992 2.867 152 Tubing9.3ppf 152 32.89 5224.90 10053.55 10020.66 3.50 2.992 2.867 153 Tubing_9.3ppf 153 32.97 5257.87 10020.661 9987.69 3.50 2.992 2.867 154 Tubing 9.3pPf 154 32.98 5290.85 9987.69 9954.71 3.50 2.992 2.867 155 Tubing_9.3ppf 155 33.02 5323.87 9954.71 9921.69 3.50 2.992 2.867 156 Tubing 9.3ppf 156 32.99 5356.86 9921.69 9888.70 3.50 2.992 2.867 157 Tubing_9.3ppf 157 32.92 5389.78 9888.70 9855.78 3.50 2.992 2.867 158 Tubing_9.3ppf 158 32.96 5422.74 9855.78 9822.82 3.50 2.992 2.867 159 Tubing_9.3ppf 159 32.88 5455.62 9822.82 9789.94 3.50 2.992 2.867 160 Tubing_9.3ppf 160 32.96 5488.58 9789.94 9756.98 3.50 2.992 2.867 161 Tubing_9.3ppf 161 33.00 5521.58 9756.98 9723.98 3.50 2.992 2.867 162 Tubing9.3p f 162 32.99 5554.57 9723.98 9690.99 3.50 2.992 2.867 163 Tubing9.3ppf 163 32.90 5587.47 9690.99 9658.09 3.50 1 2.992 2.867 164 Tubing_9.3ppf 164 32.87 5620.34 9658.09 9625.22 3.50 2.992 2.867 165 Tubing_9.3ppf 165 33.00 5653.34 9625.22 9592.22 3.50 2.992 2.867 166 Tubing_9.3ppf 166 33.01 5686.35 9592.22 9559.21 3.50 2.992 2.867 167 Tubing_9.3ppf 167 32.85 5719.20 9559.21 9526.36 3.50 2.992 2.867 168 Tubing_9.3ppf 168 33.07 5752.27 9526.36 9493.29 3.50 2.992 2.867 169 Tubing_9.3ppf 169 32.61 5784.88 9493.29 9460.68 3.50 2.992 2.867 170 Tubing_9.3ppf 170 32.88 5817.76 9460.68 9427.80 3.50 2.992 2.867 171 Tubing_9.3ppf 171 33.07 5850.83 9427.80 9394.73 3.50 2.992 2.867 172 Tubing_9.3ppf 172 32.98 5883.81 9394.73 9361.75 3.50 2.992 2.867 173 Tubing9.3ppf 173 32.96 5916.77 9361.75 9328.79 3.50 2.992 2.867 174 ITubing 9.3ppf174 32.83 5949.60 9328.79 9295.96 3.50 2.992 2.867 175 Tubing9.3cof 175 32.90 5982.50 9295.96 9263.06 3.50 2.992 2.867 176 Tubing_9.3pprf 176 32.98 6015.48 9263.06 9230.08 3.50 2.992 2.867 177 Tubing_9.3ppf 177 33.00 6048.48 9230.08 9197.08 3.50 2.992 2.867 178 Tubing_9.3ppf 178 32.83 6081.31 9197.08 9164.25 3.50 2.992 2.867 179 Tubing_9.3ppf 179 33.06 6114.37 9164.25 9131.19 3.50 2.992 2.867 180 Tubing93ppf 180 33.06 6147.43 9131.19 9098.13 3.50 2.992 2.867 181 Tubing_9.3ppf 181 32.81 6180.24 9098.13 9065.32 3.50 2.992 2.867 182 Tubing_9.3ppf 182 32.99 6213.23 9065.32 9032.33 3.50 2.992 2.867 183 Tubing_9.3ppf 183 33.00 6246.23 9032.33 8999.33 3.50 2.992 2.867 184 Tubing9.3ppf 184 32.97 627910 8999.33 8966.36 3.50 2.992 2.867 185 Tubing_9.3ppf 185 32.95 6312.15 8966.36 8933.41 3.50 2.992 2.867 186 Tubing_9.3ppf 186 32.99 6345.14 8933.41 8900.42 3.50 2.992 2.867 187 Tubing_9.3pPf 187 32.89 6378.02 8900.42 8867.54 3.50 2.992 2.867 188 Tubing_9.3ppf 188 32.97 6410.99 8867.54 8834.57 3.50 2.992 2.867 189 Tubing_9.3ppf 189 33.01 6444.00 8834.57 8801.56 3.50 2.992 2.867 190 Tubing_9.3ppf 190 32.64 6476.64 8801.56 8768.92 3.50 2.992 2.867 191 Tubing_9.3ppf 191 32.99 6509.63 8768.92 8735.93 3.50 2.992 2.867 192 Tubing_9.3ppf 192 32.93 6542.56 8735.93 8703.00 3.50 2.992 2.867 193 Tubing_9.3ppf 193 33.04 6575.60 8703.00 8669.96 3.50 2.992 2.867 194 Tubing9.3ppf 194 32.96 6608.56 8669.96 8637.00 3.50 2.992 2.867 i _JCetnf Crossover f 92W AA Joint Count Category Component Length Cum Length BTM TOP OD ID Drift 195 Tubing_9.3ppf 195 32.88 6641.44 8637.00 8604.12 3.50 2.992 2.867 196 Tubing_9.3ppf 196 32.84 6674.28 8604.12 8571.28 3.50 2.992 2.867 197 Tubing_9.3ppf 197 33.02 6707.30 8571.28 8538.26 3.50 2.992 2.867 198 Tubing_9.3ppf 198 32.86 6740.16 8538.26 8505.40 3.50 2.992 2.867 199 Tubing9.3ppf 199 33.05 6773.21 8505.40 8472.35 3.50 2.992 2.867 200 Tubing_9.3ppf 200 33.01 6806.22 8472.35 8439.34 3.50 2.992 2.867 201 Tubing_9.3ppf 201 32.99 6839.21 8439.34 8406.35 3.50 2.992 2.867 202 Tubing_9.3ppf 202 32.82 6872.03 8406.35 8373.53 3.50 2.992 2.867 203 Tubing_9.3ppf 203 32.95 6904.98 8373.53 8340.58 3.50 2.992 2.867 204 Tubing_9.3ppf 204 32.82 6937.80 8340.58 8307.76 3.50 2.992 2.867 205 Tubing_9.3ppf 205 32.87 6970.67 8307.76 8274.89 3.50 2.992 2.867 206 Tubing_9.3ppf 206 32.96 7003.63 8274.89 8241.93 3.50 2.992 2.867 207 Tubing_9.3ppf 207 32.97 7036.60 8241.93 8208.96 3.50 2.992 2.867 208 Tubing 9.3ppf 208 32.94 7069.54 8208.96 8176.02 3.50 2.992 2.867 209 Tubing 9.3ppf 209 32.93 7102.47 8176.02 8143.09 3.50 2.992 2.867 210 Tu6ing_9.3ppf 210 32.61 7135.08 8143.09 8110.48 3.50 2.992 2.867 211 Tubing_9.3ppf 211 32.83 7167.91 8110.48 8077.65 3.50 2.992 2.867 212 Tubing_9.3ppf 212 32.92 7200.83 8077.65 8044.73 3.50 2.992 2.867 213 Tubing_9.3ppf 213 32.82 7233.65 8044.73 8011.91 3.50 2.992 2.867 214 Tubing_9.3ppf 214 32.86 7266.51 8011.91 7979.05 3.50 2.992 2.867 215 Tubing_9.3ppf 215 32.96 7299.47 7979.05 7946.09 3.50 2.992 2.867 216 Tubing_9.3ppf 216 33.07 7332.54 7946.09 7913.02 3.50 2.992 2.867 217 Tubing_9.3ppf 217 32.99 7365.53 7913.02 7880.03 3.50 2.992 2.867 218 Tubing_9.3ppf 218 32.84 7398.37 7880.03 7847.19 3.50 2.992 2.867 219 Tubing_9.3ppf 219 32.90 7431.27 7847.19 7814.29 3.50 2.992 2.867 220 Tubing_9.3ppf 220 32.86 7464.13 7814.29 7781.43 3.50 2.992 2.867 221 Tubing_9.3ppf 221 33.03 7497.16 7781.43 7748.40 3.50 2.992 2.867 222 Tubing_9.3ppf 222 32.97 7530.13 7748.40 7715.43 3.50 2.992 2.867 223 Tubing_9.3ppf 223 33.04 7563.17 7715.43 7682.39 3.50 2.992 2.867 224 Tubing_9.3ppf 224 32.88 7596.05 7682.39 7649.51 3.50 2.992 2.867 225 Tubing_9.3ppf 225 32.98 7629.03 7649.51 7616.53 3.50 2.992 2.867 226 Tubing_9.3ppf 226 33.04 7662.07 7616.53 7583.49 3.50 2.992 2.867 227 Tubing_9.3ppf 227 32.98 7695.05 7583.49 7550.51 3.50 2.992 2.867 228 Tubing_9.3ppf 228 33.05 7728.10 7550.51 7517.46 3.50 2.992 -T8-67- .867229 229 Tubing_9.3ppf 229 33.04 7761.14 7517.46 7484.42 3.50 2.992 2.867 230 Tubing_9.3ppf 230 32.95 7794.09 7484.42 7451.47 3.50 2.992 2.867 231 ITubing_9.3ppf 231 33.04 7827.13 7451.47 7418.43 3.50 2.992 2.867 232 Tubing_9.3ppf 232 32.86 7859.99 7418.43 7385.57 3.50 2.992 2.867 233 Tubing_9.3ppf 233 33.00 7892.99 7385.57 7352.57 3.50 2.992 2.867 234 Tubing_9.3ppf 234 32.89 7925.88 7352.57 7319.68 3.50 2.992 2.867 235 Tubing_9.3ppf 235 32.96 7958.84 7319.68 7286.72 3.50 1 2.992 2.867 236 Tubing_9.3ppf 236 32.93 7991.77 7286.72 7253.79 3.50 2.992 2.867 237 Tubing_9.3ppf 237 32.95 8024.72 7253.79 7220.84 3.50 2.992 2.867 238 Tubing_9.3ppf 238 32.83 8057.55 7220.84 7188.01 3.50 2.992 2.867 239 Tubing_9.3ppf 239 32.86 8090.41 7188.01 7155.15 3.50 2.992 2.867 240 Tubing_9.3p f 240 33.01 8123.42 7155.15 7122.14 3.50 2.992 2.867 241 Tubing_9.3ppf 241 32.48 8155.90 7122.14 7089.66 3.50 2.992 2.867 242 Tubing_9.3ppf 242 32.98 8188.88 7089.66 7056.68 3.50 2.992 2.867 243 Tubing_9.3ppf 243 32.94 8221.82 7056.68 7023.74 3.50 2.992 2.867 244 Tubing_9.3ppf 244 32.53 8254.35 7023.74 6991.21 3.50 2.992 2.867 245 Tubing_9.3ppf 245 32.99 8287.34 6991.21 6958.22 3.50 1 2.992 2.867 246 Tubing_9.3ppf 246 32.90 8320.24 6958.22 6925.32 3.50 1 2.992 2.867 247 Tubing_9.3ppf 247 32.93 8353.17 6925.32 6892.39 3.50 2.992 2.867 248 Tubing_9.3ppf248 32.88 8386.05 6892.39 6859.51 3.50 2.992 2.867 249 Tubing_9.3ppf 249 33.08 8419.13 6859.51 6826.43 3.50 2.992 2.867 250 Tubing_9.3ppf 250 33.86 8452.99 6826.43 6792.57 3.50 2.992 2.867 251 Tubing_9.3ppf251 33.02 8486.01 6792.57 6759.55 3.50 2.992 2.867 252 Tubing_9.3ppf 252 32.99 8519.00 6759.55 6726.56 3.50 2.992 2.867 253 Tubing_9.3ppf 253 32.84 8551.84 6726.56 6693.72 3.50 2.992 2.867 254 Tubing_9.3ppf 254 32.99 8584.83 6693.72 6660.73 3.50 2.992 2.867 255 Tubing_9.3ppf 255 32.83 8617.66 6660.73 6627.90 3.50 2.992 2.867 256 Tubing_9.3ppf 256 32.96 8650.62 6627.90 6594.94 3.50 2.992 2.867 257 Tubing_9.3ppf 257 33.01 8683.63 6594.94 6561.93 3.50 2.992 2.867 258 Tubing_9.3ppf 258 33.04 8716.67 6561.93 6528.89 3.50 2.992 2.867 259 Tubing_9.3ppf 259 32.86 8749.53 6528.89 6496.03 3.50 2.992 2.867 260 Tubing_9.3ppf 260 32.91 8782.44 6496.03 6463.12 3.50 2.992 2.867 261 Tubing_9.3ppf 261 32.92 8815.36 6463.12 6430.20 3.50 2.992 2.867 262 Tubing_9.3ppf 262 33.02 8848.38 6430.20 6397.18 3.50 2.992 2.867 263 Tubing_9.3ppf 263 32.94 8881.32 6397.18 6364.24 3.50 2.992 2.867 264 Tubing_9.3ppf 264 32.99 8914.31 6364.24 6331.25 3.50 2.992 2.867 265 [Tu 265 265 33.02 8947.33 6331.25 6298.23 3.50 2.992 2.867 ocator Crossover 15207.88 Joint Count I Category Component Length Cum Length BTM TOP OD ID Drift 266 Tubing_9.3ppf 266 33.06 8980.39 6298.23 6265.17 3.50 2.992 2.867 267 Tubing_9.3ppf 267 33.05 9013.44 6265.17 6232.12 3.50 2.992 2.867 268 Tubing_9.3ppf 268 33.00 9046.44 6232.12 6199.12 3.50 2.992 2.867 269 Tubing_9.3ppf 269 32.85 9079.29 6199.12 6166.27 3.50 2.992 2.867 270 Tubing_9.3ppf 270 33.01 9112.30 6166.27 6133.26 3.50 2.992 2.867 271 Tubing_9.3ppf 271 32.98 9145.28 6133.26 6100.28 3.50 2.992 2.867 272 Tubing_9.3ppf 272 32.68 9177.96 6100.28 6067.60 3.50 2.992 2.867 273 Tubing_9.3ppf 273 33.05 9211.01 6067.60 6034.55 3.50 2.992 2.867 274 Tubing_93ppf 274 33.01 9244.02 6034.55 6001.54 3.50 1 2.992 2.867 275 Tubing_9.3ppf 275 32.26 9276.28 6001.54 5969.28 3.50 2.992 2.867 276 Tubing_9.3ppf 276 32.51 9308.79 5969.28 5936.77 3.50 2.992 2.867 277 Tubing_9.3ppf 277 32.90 9341.69 5936.77 5903.87 3.50 2.992 2.867 278 Tubing 9.3ppf 278 32.55 9374.24 5903.87 5871.32 3.50 2.992 2.867 279 Tubing_9.3ppf 279 32.91 9407.15 5871.32 5838.41 3.50 2.992 2.867 280 Tubing_9.3ppf 280 32.84 9439.99 5838.41 5805.57 3.50 2.992 2.867 281 Tubing_9.3ppf 281 32.99 9472.98 5805.57 5772.58 3.50 2.992 2.867 282 Tubing_9.3ppf 282 32.86 9505.84 5772.58 5739.72 3.50 2.992 2.867 283 Tubing_9.3ppf 283 32.88 9538.72 5739.72 5706.84 3.50 2.992 2.867 284 Tubing_9.3ppf 284 33.03 9571.75 5706.84 5673.81 3.50 1 2.992 2.867 285 Tubing_93ppf 285 33.06 9604.81 5673.81 5640.75 3.50 2.992 2.867 286 Tubing_9.3ppf 286 32.90 9637.71 5640.75 5607.85 3.50 2.992 2.867 287 Tubing 9.3ppf 287 33.02 9670.73 5607.85 5574.83 3.50 2.992 2.867 288 Tubing_9.3ppf 288 33.03 9703.76 5574.83 5541.80 3.50 2.992 2,367 289 Tubing_9.3ppf 289 32.95 9736.71 5541.80 5508.85 3.50 2.992 2.867 290 Tubing_9.3ppf 290 32.73 1 9769.44 5508.85 5476.12 3.50 2.992 2.867 291 Tubing_9.3ppf 291 33.02 9802.46 5476.12 5443.10 3.50 2.992 2.867 292 Tubing_9.3ppf 292 32.82 9835.28 5443.10 5410.28 3.50 2.992 2.867 293 Tubing_9.3ppf 293 33.17 9868.45 5410.28 5377.11 3.50 2.992 2.867 294 Tubing_9.3ppf 294 33.01 9901.46 5377.11 5344.10 3.50 2.992 2.867 295 Tubing_9.3ppf 295 33.02 9934.48 5344.10 5311.08 3.50 2.992 2.867 296 Tubing_9.3ppf 296 32.99 9967.47 5311.08 5278.09 3.50 2.992 2.867 297 Tubing_9.3ppf 297 33.07 10000.54 5278.09 5245.02 3.50 2.992 2.867 298 Tubing_9.3ppf 298 33.00 10033.54 5245.02 5212.02 3.50 2.992 2.867 299 Tubing_9.3ppf 299 32.90 10066.44 5212.02 5179.12 3.50 2.992 2.867 300 Tubing_9.3ppf 300 32.84 1 10099.28 5179.12 5146.28 3.50 2.992 2.867 301 TLPlug Installed 302 Tubing_9.3ppf SLB_Equip SLB Equip 51 -8 -Equip MIL Tubing_9.3ppf 301 3.5' X2 Bottom Pup (9.2# IST -M BOX x IBT-' 31/2" X2 2.813 X -LANDING NIPPLE IBT-M BX 3.5' X2 Top Pup (9.2# IBT-M BOX x 9.2# IBT-M P 302 32.86 1.48 14.71 32.00 10132.14 146.85 10148.33 10163.04 10195.04 5146.28 5113.42 5098.71 5097.23 5082.52 5113.42 5098.71 5097.23 5082.52 5050.52 3.50 4.26 4.27 4.26 3.50 2.992 2.992 2.813 2.992 _ 2.992 2.867 '. 2.867 303 Tubing9.3ppf 303 32.91 10227.95 5050.52 5017.61 3.50 2.992 2.867 304 Tubing_9.3ppf 304 32.89 10260.84 5017.61 4984.72 3.50 2.992 2.867 305 Tubing_9.3ppf 305 32.91 10293.75 4984.72 4951.81 3.50 2.992 2.867 306 Tubing_9.3ppf 306 32.85 10326.60 4951.81 4918.96 3.50 2.992 2.867 307 Tubing_9.3ppf 307 32.86 10359.46 4918.96 4886.10 3.50 2.992 2.867 308 Tubing9.3oof 308 33.03 10392.49 4886.10 1 4853.07 3.50 2.992 2.867 309 Tubing_9.3ppf 309 32.99 10425.48 4853.07 4820.08 3.50 2.992 2.867 310 Tubing_9.3ppf 310 33.02 10458.50 4820.08 4787.06 3.50 2.992 2.867 311 Tubing_9.3ppf 311 33.00 10491.50 4787.06 4754.06 3.50 2.992 2.867 312 Tubing_9.3ppf 312 32.67 10524.17 4754.06 4721.39 3.50 2.992 2.867 SLB Equip SLG Equip 3.5" GLM3 Bottom Pup (9.2# IBT-M BOX x IBT-M 9.3# PIN) GLM3, 3-1/2 MMG, 1.5' SOV " RKP latch 14.73 8.81 10538.90 10547.71 4721.39 4706.66 4706: 4697.85 - 4.25 - 5.97 , 19 2.867 2.867 SLB Equip 3.5" GLM3 Top Pup (9.2# IBT-M BOX x 9.2# IBT-M PIN) 14.72 10562.43 4697.85 4683.13 4.28 2.992 2.867 313 Tubing_9.3ppf 313 33.06 10595.49 4683.13 4650.07 3.50 2.992 2.867 314 Tubing9.3ppf 314 32.88 10628.37 4650.07 4617.19 3.50 2.992 2.867 315 Tubing_9.3ppf 315 33.04 10661.41 4617.19 4584.15 3.50 2.992 2.867 316 Tubing_9.3ppf 316 33.05 10694.46 4584.15 4551.10 3.50 2.992 2.867 317 Tubing_9.3ppf 317 33.06 10727.52 4551.10 4518.04 3.50 2.992 2.867 318 Tubing_9.3ppf 318 32.84 10760.36 4518.04 4485.20 3.50 2.992 2.867 319 Tubing_9.3ppf 319 33.07 10793.43 4485.20 4452.13 3.50 2.992 2.867 320 Tubing_9.3ppf 320 32.47 10825.90 4452.13 4419.66 3.50 2.992 2.867 321 Tubing_9.3ppf 321 33.03 10858.93 4419.66 4386.63 3.50 2.992 2.867 322 Tubing_9.3ppf 322 32.88 10891.81 4386.63 4353.75 3.50 2.992 2.867 323 Tubing_9.3ppf 323 32.78 10924.59 4353.75 4320.97 3.50 2.992 2.867 324 ITubing._9.3ppf 324 32.91 10957.50 4320.97 4288.06 3.50 2.992 2.867 325 Tubing9.3ppf 325 33.06 10990.56 4288.06 4255.00 3.50 2.992 2.867 326 Tubing_9.3ppf 326 33.00 11023.56 4255.00 4222.00 3.50 2.992 2.867 327 Tubing_9.3ppf 327 32.96 11056.52 4222.00 4189.04 3.50 2.992 2.867 328 Tubing 9.3ppf 328 33.06 11089.58 4189.04 4155.98 3.50 2.992 2.867 329 Tubing_9.3ppf 329 33.00 11122.58 4155.98 4122.98 3.50 2.992 2.867 330 Tubing 9.3ppf 330 33.07 11155.65 4122.98 4089.91 3.50 2.992 2.867 Ocat., C.o .mv r I OW Ra Joint Count Category Component Length Cum Length BTM TOP OD ID Drift 331 Tubing_9.3ppf 331 33.08 11188.73 4089.91 4056.83 3.50 2.992 2.867 332 Tubing_9.3ppf 332 33.07 11221.80 4056.83 4023.76 3.50 2.992 2.867 333 Tubing_9.3ppf 333 32.98 11254.78 4023.76 3990.78 3.50 2.992 2.867 334 Tubing_9.3ppf 334 33.01 11287.79 3990.78 3957.77 3.50 2.992 2.867 335 Tubing_9.3ppf 335 33.08 11320.87 3957.77 3924.69 3.50 2.992 2.867 336 Tubing_9.3ppf 336 32.98 11353.85 3924.69 3891.71 3.50 2.992 2.867 337 Tubing_9.3ppf 337 30.33 11384.18 3891.71 3861.38 3.50 2.992 2.867 338 Tubing_9.3ppf 338 33.53 11417.71 3861.38 3827.85 3.50 2.992 2.867 339 Tubing_9.3ppf 339 33.02 11450.73 3827.85 3794.83 3.50 2.992 2.867 340 Tubing_9.3ppf 340 33.07 11483.80 3794.83 3761.76 3.50 2.992 2.867 341 Tubing_9.3ppf 341 32.98 11516.78 3761.76 3728.78 3.50 2.992 2.867 342 Tubing_9.3ppf 342 33.01 11549.79 3728.78 3695.77 3.50 2.992 2.867 343 Tubing_9.3ppf 343 33.08 11582.87 3695.77 3662.69 3.50 2.992 2.867 344 Tubing_9.3ppf 344 32.48 11615.35 3662.69 3630.21 3.50 2.992 2.867 345 Tubing_9.3ppf 345 33.04 11648.39 3630.21 3597.17 3.50 2.992 2.867 346 Tubing_9.3ppf 346 32.93 11681.32 3597.17 3564.24 3.50 2.992 2.867 347 Tubing_9.3ppf 347 32.95 11714.27 3564.24 3531.29 3.50 2.992 2.867 348 Tubing_9.3ppf 348 33.02 11747.29 3531.29 3498.27 3.50 2.992 2.867 349 Tubing_9.3ppf 349 33.00 11780.29 3498.27 3465.27 3.50 2.992 2.867 350 Tubing_9.3ppf 350 32.88 11813.17 3465.27 3432.39 3.50 2.992 2.867 351 Tubing9.3ppf 351 33.01 11846.18 3432.39 3399.38 3.50 2.992 2.867 352 Tubing_9.3ppf 352 32.98 11879.16 3399.38 3366.40 3.50 2.992 2.867 353 Tubing_9.3ppf 353 33.00 11912.16 3366.40 3333.40 3.50 2.992 2.867 354 Tubing_9.3ppf 354 33.03 11945.19 3333.40 3300.37 3.50 2.992 2.867 355 Tubing_9.3ppf 355 33.05 11978.24 3300.37 3267.32 3.50 2.992 2.867 356 Tubing_9.3ppf 356 30.73 12008.97 3267.32 3236.59 3.50 2.992 2.867 357 Tubing_9.3ppf 357 33.06 12042.03 3236.59 3203.53 3.50 2.992 2.867 358 Tubing_9.3ppf 358 33.08 12075.11 3203.53 3170.45 3.50 1 2.992 2.867 359 Tubing_9.3ppf 359 32.99 12108.10 3170.45 3137.46 3.50 2.992 2.867 360 Tubing_9.3ppf 360 33.10 12141.20 3137.46 3104.36 3.50 2.992 2.867 361 Tubing_9.3ppf 361 32.95 12174.15 3104.36 3071.41 3.50 2.992 2.867 362 Tubing_9.3ppf 362 33.03 12207.18 3071.41 3038.38 3.50 2.992 2.867 363 Tubing_9.3ppf 363 33.01 12240.19 3038.38 3005.37 3.50 2.992 2.867 364 Tubing_9.3ppf 364 32.99 12273.18 3005.37 2972.38 3.50 2.992 2.867 365 Tubing_9.3ppf 365 32.85 12306.03 2972.38 2939.53 3.50 2.992 2.867 366 Tubing_9.3ppf 366 32.95 12338.98 2939.53 2906.58 3.50 2.992 2.867 367 Tubing 9.3ppf 367 32.88 12371.86 2906.58 2873.70 3.50 2.992 2.867 368 Tubing_9.3ppf 368 32.52 12404.38 2873.70 2841.18 3.50 1 2.992 2.867 369 Tubing_9.3ppf 369 32.87 12437.25 2841.18 2808.31 3.50 2.992 2.867 370 Tubing_9.3ppf 370 32.98 12470.23 2808.31 2775.33 3.50 2.992 2.867 371 Tubing_9.3ppf 371 33.05 12503.28 2775.33 2742.28 3.50 2.992 2.867 372 Tubing_9.3ppf 372 32.86 12536.14 2742.28 2709.42 3.50 2.992 2.867 373 Tubing_9.3ppf 373 32.90 12569.04 2709.42 2676.52 3.50 2.992 2.867 374 Tubing_9.3ppf 374 33.05 12602.09 2676.52 2643.47 3.50 2.992 2.867 375 Tubing_9.3ppf 375 32.89 12634.98 2643.47 2610.58 3.50 2.992 2.867 376 Tubing_9.3ppf 376 33.06 12668.04 2610.58 2577.52 3.50 2.992 2.867 377 Tubing_9.3ppf 377 32.60 12700.64 2577.52 2544.92 3.50 2.992 2.867 378 Tubing_9.3ppf 378 33.03 12733.67 2544.92 2511.89 3.50 2.992 2.867 379 Tubing_9.3ppf 379 33.04 12766.71 2511.89 2478.85 3.50 2.992 2.867 380 Tubing_9.3ppf 380 33.01 12799.72 2478.85 2445.84 3.50 2.992 2.867 381 Tubing_9.3ppf 381 33.02 12832.74 2445.84 2412.82 3.50 2.992 2.867 382 Tubing_9.3ppf 382 33.00 12865.74 2412.82 2379.82 3.50 2.992 2.867 383 Tubing_9.3ppf 383 32.53 12898.27 2379.82 2347.29 3.50 2.992 2.867 384 Tubing_9.3ppf 384 32.91 12931.18 2347.29 2314.38 3.50 2.992 2.867 385 Tubing_9.3ppf 385 33.02 12964.20 2314.38 2281.36 3.50 2.992 2.867 386 Tubing_9.3ppf 386 32.79 12996.99 2281.36 2248.57 3.50 2.992 2.867 387 Tubing_9.3ppf 387 32.54 13029.53 2248.57 2216.03 3.50 2.992 2.867 388 Tubing_9.3ppf 388 33.05 13062.58 2216.03 2182.98 3.50 2.992 2.867 389 Tubing_9.3ppf 389 33.08 13095.66 2182.98 2149.90 3.50 2.992 2.867 390 Tubing_9.3ppf 390 33.00 13128.66 2149.90 2116.90 3.50 2.992 2.867 391 Tubing_9.3ppf 391 33.11 13161.77 2116.90 2083.79 3.50 2.992 2.867 392 Tubing_9.3ppf 392 32.94 1 13194.71 2083.79 2050.85 3.50 2.992 2.867 393 Tubing_9.3ppf 393 32.85 1 13227.56 2050.85 2018.00 3.50 2.992 2.867 394 Tubing_9.3ppf 394 33.06 13260.62 2018.00 1984.94 3.50 2.992 2.867 395 Tubing_9.3ppf 395 32.88 13293.50 1984.94 1952.06 3.50 2.992 2.867 396 Tubing_9.3ppf 396 33.02 13326.52 1952.06 1919.04 3.50 2.992 2.867 397 Tubing_9.3ppf 397 32.91 13359.43 1919.04 1886.13 1 3.50 2.992 2.867 398 Tubing_9.3ppf 398 33.00 13392.43 1886.13 1853.13 3.50 2.992 12.867 399 Tubing_9.3ppf 399 33.05 13425.48 1853.13 1820.08 3.50 1 2.992 2.867 400 Tubing 9.3ppf 400 33.03 13458.51 1820.08 1787.05 3.50 2.992 2.867 401 Tubing9.3ppf 401 33.09 13491.60 1787.05 1753.96 3.50 2.992 2.867 Locator Crossover 152(1]99 Joint Count Category Component Length Cum Length BTM TOP OD ID Drift 402 Tubing_9.3ppf 402 33.06 13524.66 1753.96 1720.90 3.50 2.992 2.867 403 Tubing_9.3ppf 403 32.99 13557.65 1720.90 1687.91 3.50 2.992 2.867 404 Tubing_9.3ppf 404 33.01 13590.66 1687.91 1654.90 3.50 2.992 2.867 405 Tubing_9.3ppf 405 32.92 13623.58 1654.90 1621.98 3.50 2.992 2.867 406 Tubing_9.3ppf 406 33.06 13656.64 1621.98 1588.92 3.50 2.992 2.867 407 Tubing_9.3ppf 407 33.04 13689.68 1588.92 1555.88 3.50 2.992 2.867 408 Tubing_9.3ppf 408 32.67 13722.35 1555.88 1523.21 3.50 2.992 2.867 409 Tubing_9.3ppf 409 32.96 13755.31 1523.21 1490.25 3.50 2.992 2.867 410 Tubing_9.3ppf 410 32.99 13788.30 1490.25 1 1457.26 3.50 1 2.992 2.867 411 Tubing_9.3ppf 411 32.88 13821.18 1457.26 1424.38 3.50 2.992 2.867 412 Tubing_9.3ppf 412 32.95 13854.13 1424.38 1391.43 3.50 2.992 2.867 413 Tubing_9.3ppf 413 32.99 13887.12 1391.43 1358.44 3.50 2.992 2.867 414 Tubing_9.3ppf 414 33.01 13920.13 1358.44 1325.43 3.50 2.992 2.867 415 Tubing_9.3ppf 415 32.87 13953.00 1325.43 1292.56 3.50 2.992 2.867 416 Tubing_9.3ppf 416 32.67 13985.67 1292.56 1259.89 3.50 2.992 2.867 417 Tubing_9.3ppf 417 30.83 14016.50 1259.89 1229.06 3.50 2.992 2.867 418 Tubing_9.3ppf 418 33.00 14049.50 1229.06 1196.06 3.50 2.992 2.867 419 Tubing_9.3ppf 419 33.08 14082.58 1196.06 1162.98 3.50 2.992 2.867 420 Tubing_9.3ppf 420 33.00 14115.58 1162.98 1129.98 3.50 2.992 2.867 421 Tu6ing_9.3ppf421 32.99 14148.57 1129.98 1096.99 3.50 2.992 2.867 422 Tubing_9.3ppf 422 33.02 14181.59 1096.99 1063.97 3.50 2.992 2.867 423 Tubing_9.3ppf 423 33.06 14214.65 1063.97 1030.91 3.50 2.992 2.867 424 Tubing_9.3ppf 424 33.00 14247.65 1030.91 997.91 3.50 2.992 2.867 425 Tubing _9.3 pf 425 32.99 14280.64 997.91 964.92 3.50 2.992 2.867 426 Tubing_9.3ppf 426 33.00 14313.64 964.92 931.92 3.50 2.992 2.867 427 Tubing_9.3ppf 427 30.84 14344.48 931.92 901.08 3.50 2.992 2.867 428 Tubing_9.3ppf 428 32.93 14377.41 901.08 868.15 3.50 2.992 2.867 429 Tubing_9.3ppf 429 32.85 14410.26 1 868.15 835.30 3.50 2.992 12,8671 430 Tubing_9.3ppf 430 33.05 14443.31 1 835.30 802.25 3.50 2.992 2.867 431 Tubing_9.3ppf 431 33.00 14476.31 802.25 769.25 3.50 2.992 2.867 432 Tubing_9.3ppf 432 32.89 14509.20 769.25 736.36 3.50 2.992 2.867 433 Tubing 9.3ppf 433 33.04 14542.24 736.36 703.32 3.50 2.992 2.867 434 Tubing_9.3ppf 434 33.01 14575.25 703.32 670.31 3.50 2.992 2.867 435 Tubing_9.3ppf435 32.86 14608.11 670.31 637.45 3.50 2.992 2.867 436 Tubing_9.3ppf436 32.00 14640.11 637.45 605.45 3.50 2.992 2.867 437 Tubing_9.3ppf 437 33.05 14673.16 605.45 572.40 3.50 2.992 2.867 438 Tubing_9.3ppf 438 32.94 14706.10 572.40 539.46 3.50 2.992 2.867 439 Tubing_9.3ppf 439 32.86 14738.96 539.46 506.60 3.50 2.992 2.867 SLB Equip SLB Equip 3.5" TRMAXX Bottom Pup (9.2# IBT BOX x IBT-M 9.3 3-1/2 TRMAXX-5E, 2.812 X TYPE SSSV (9.2# IBT-M BxPrK 14.70 4.27 14753.66 14757.93 506.60 491.90 491.90 487.63 4.26 2.992 2.813 2.808 2.808 SLB Equip 3.5" TRMAXX Top Pup (9.2# IBT-M BOX x 9.2# IBT-M PIN) 14.73 14772.66 487.63 472.90 2.992 2.808 440 Tubing_9.31ppf 440 33.09 14805.75 472.90 439.81 3.50 2.992 2.867 441 ITubing_9.3ppf 441 33.04 14838.79 439.81 406.77 3.50 2.992 2.867 442 Tubing_9.3ppf 442 33.05 14871.84 406.77 373.72 3.50 2.992 2.867 443 Tubing9.3ppf 443 33.11 14904.95 373.72 340.61 3.50 2.992 2.867 444 Tubing_9.3ppf 444 33.04 14937.99 340.61 307.57 3.50 2.992 2.867 445 Tubing_9.3ppf445 32.88 14970.87 307.57 274.69 3.50 2.992 2.867 446 Tubing_9.3ppf 446 32.67 15003.54 274.69 242.02 3.50 2.992 2.867 447 Tubing_9.3ppf 447 33.00 15036.54 242.02 209.02 3.50 2.992 2.867 448 Tubing_9.3ppf 448 32.98 15069.52 209.02 176.04 3.50 2.992 2.867 449 Tubing_9.3ppf 449 33.03 15102.55 176.04 143.01 350 2.992 2.867 450 Tubing_9.3ppf 450 33.07 15135.62 143.01 109.94 3.50 2.992 2867 451 Tubing_9.3ppf 451 33.08 15168.70 109.94 76.86 3.50 2.992 2.867 Tubing_9.3ppf 452 32.90 15201.60 76.86 43.96 3.50 2.992 2.867 Tubing_9.3ppf 526 28.60 15230.20 43.96 15.36 3.50 2.992 2.867 Pups 1 1.80 15203.40 43.96 42.16 3.50 2.992 2.867 Pups HP 4.75 15234.95 15.36 10.61 4.50 3.958 3.833 Hanger 0.48 15235.43 10.61 10.13 RKS to LDS 35.87 Squat for 15k Ibf in Compression 25.26 ND H-16 MD H-12 ND H-12 ND H -16A ND H-04 GLM -1 6940 15312 6715 6823 6656 GLM -2 5500 11145 5506 5498 5348 GLM -3 3380 4131 3442 3311 3200 15 �0 PRESSURE INTEGRITY TEST Blue Crest Well Name: H04 Rig: Rig 1 Date: 1 1/10/2019 Volume Input Volume/Stroke P mp Rate: Drilling Supervisor: Rowland Lawson / T Ashleyl 1pump used: #1 Mud Pump Strokes W 0.0924 Bbls/Strk 'W 5.00 Strk/min Type ofTest: cgs ng Shoe rest LOT/Frr 'W Pumping down annulus and Casing Test Pressure Integrity Test Hole Size: 17-1/2" Casin Shoe DepthHole De th RKB-CHF: 34.6 Ft 580(; TD Ft -TVD 830.0 5TD 3603.0 TVD Casing Size and Description: 13-3/8" 5e3r/Ft L-80 BTC TIV Casina Test Pressure Inte rit Test Mud Weight: 1 8.3 ppg Mud Weight: 10.5 ppg Mud 10 min Gel: Lb/100 Ft2 Mud 10 min Gel: 13.0 Lb/100 Ft2 Test Pressure: 3000.0 psi Rotating Weight: 150.0 Lbs Rotating Weight: Lbs Blocks/Top Drive Weight: Lbs Blocks/Top Drive Weight: Lbs Desired PIT EMW: 13.0 ppg Estimates for Test: 10.2 bbls Estimates for Test: 467 psi 1.5 bbls W11 F'W EMW = Leak -off -Pressure +Mud Weight = 520 + 10.5 PIT 15 Second 0.052 x TVD 0.052 x 3593 Shut-in Pressure, psi EMW at 5800 Ft -MD 3593 Ft -TVD = 13.3 Fill in FIT Columns =_> Pumping Strks I psi I Shut-in Min psi Pum in Strks psi Shut-in Min psi 0 101 5 30 10 60 0 3220 5 7T210 10 3200 0 30 -5-8o 10 170 0.00 520 0.25 0.50 15 190 15 31901 15 270 1.00480 1.50 2.00 450 20 340 20 31801 20 360 25 490 25 3170 -25-450 30 660 30 31701 30 5201 2.50 351 830 1 3.00 440 40 990 45 1140 3.50 4.00 420 50 1300 4.50 55 1450 5.00 410 3500 Lost 50 psi during test, held 9 4% f t 30oa 2500 w j z000 N 1500 � a 1000 500 0 0 2 4 6 8 10 12 0 5 10 15 20 25 30 Barrels Shut -In time, Minutes CASING TEST BLEAK -OFF TEST O PIT Point Comments: 60 1600 5.50 65 1740 6.00 400 70 19006.50 75 2050 1 7.00 400 80 2200 1 7.50 85 2360 1 8.00 390 90 25101 1 8.50 95 26801 9.00 390 100 2820 9.50 10.00 0 105 2990 110 3150 113 3220 Volume S Volume L -Bled Back S Volume S Volume ark S 6� nvv ioolo.ri P. Summary OA r. JO �\ 30 S `SO Gn�C1�o�dn�. CHART NO NO 14P-6000 SHR/q/ �V 1ETEP. l \�.. . u Ft: pFF M U o SMART PJT ON M �1 7S LOICATION 1 ✓ REMAR�`.s 114 °Os OOD% ops / _. Ops? / j 005£ ppoQ /- _ ..,ry \ i -PO � � 25OV / r 1000 N � \ � 20 O 500 jC06 C6 os, 9v 04 Vs DlueUreSt 11-04. 9.13[5 rl 173G. I est Summary PRESSURE INTEGRITY TEST BlueCrest Energy Alaska Well Name: Hansen H-04 I Rig: Rig 1 1 Date: 1 1.28.2019 Volume In ut Volume/Stroke P mp Rate: Drilling Supervisor: Keener / Wall Pump used: #z Mud Pump ' Strokes 'W 0.0924 Bbls/Strk 'W 5.00 Strk/min Type of Test: Casing shoe rest LOT/FIT 'W Pumping down annulus and DP. Casing Test Pressure Integrity est Hole Size: 8-1/2" CasingShoe Depth Hole Depth Pum in Shut-in Pumping Shut-in RKB-CHF:l 34.7 Ft 15406.0 Ft -MD 7056.0 Ft -TVD I 15440.0 Ft -MD 7067.0 Ft -TVD Strks 0 psi 0 Min 0 psii 3570 Strks 0 psi 01 Min psi 0.00 1570 Casing Size and Description: 9-5/8" 40#/Ft L-80 BTC Casina Test Pressure lnt? rit Test 10 280 1 3550 5 200 0.25 1550 Mud Weight: 10.5 ppg Mud 10 min Gel: Lb/100 Ft2 Test Pressure: 3500.0 psi Rotating Weight: Lbs Blocks/Top Drive Weight: Lbs Estimates for Test: 15.1 bbls Mud Weight: 9.2 ppg Mud 10 min Gel: Lb/100 Ft2 Rotating Weight: Lbs Blocks/Top Drive Weight: Lbs Desired PIT EMW: 13.5 ppg Estimates for Test: 1578 psi 7.1 bbls 20 530 2 3550 10 340 0.50 1540 30 750 3 3540 15 450 1.00 1540 1.50 2.00 1540 40 970 4 3520 20 560 50 1170 5 3520 25 660 601 1370 6 35101 30 770 2.50 1530 701 15601 7 35101 35 870 3.00 1530 Casing Volume= 1168.1 bbi 1r Casing volume 1168.1 bbl EMW = Leak -off Pressure + Mud Weight = 1560 + PIT 15 Second 0.052 x TVD 0.052 x 7056 92 Shut-in Pressure, psi EMW at 15406 Ft -MD 7056 Ft -TVD = 13.5 ppg 1550 801 17701 90 1970 8 3510 9 3510 40 970 45 1090 3.50 1530 4.00 1530 100 2170 10 3505 50 11701 4.50 1530 110 2370 15 3505 55 12701 5.00 1530 4000 Lost 75 psi during test, o, 3500 3000 00- Lu 2500 U) 2000 U.1 IX 1500 1000 500 0 0 2 4 6 a 10 12 14 16 18 0 5 10 15 20 25 30 Barrels Shut -In time, Minutes �CASING TEST BLEAK -OFF TEST O PIT Point 120 2580 20 3500 60 13701 5.50 1520 130 2780 25 3500 65 14501 6.00 1520 140 2990 30 3495 70 15501 6.50 1510 150 3210 72 15701 7.00 1510 160 3400 17.50 1500 1701 35701 8.00 1500 8.50 1500 9.00 1490 9.50 1 "'1 10.00 1 Volume lgAmig Bois Volume --Bled Back S Volume S Volume S Comments: DlueUreSt 11-04. 9.13[5 rl 173G. I est Summary C-] louu L ` 1000 500 (Ay�p `v p0 p % y O hp cbc�NSP !-x 'f o O 41 1 Vil - G� P �Q ol� O 00 O 0 00 ��i Q dr 1PPS oo `�N �N mos►— ---- ``,_ coos , op ST 'w 55 _ — 60 `5500 000 4,500 JSOp _3ppo O° P 2000 4500 1000 —500 \ \ 5 AltT Qy�RT 0 00 Mp_5� oN4Rt o u N °O / VSs` rSSS Ol' ----2000 �- 1000 —500- 40 ct, t" h°° �NART No. ` fvrER M0 MP -6000 -INP, - CHAP pur av IUCA r/� rAKEN .....:. - REMARK SCE k:. sl, �F Tear. / r 00 Op0\ d O O Q pQ pOn . ON p \ per , sI, 6p/ 0P ------ _ SZ Winston, Hugh E (DOA) From: Dwight Warner <dwarner@bluecrestenergy.com> Sent: Friday, May 10, 2019 10:09 AM To: Winston, Hugh E (DOA) Subject: RE: 24 hour production rates Hansen H04 You are correct it should be 600 MCF not 600,000. Sorry about that it was reported in SCF not MSCF on the spreadsheets. Dwight From: Winston, Hugh E (DOA) <hugh.winston@alaska.gov> Sent: Friday, May 10, 2019 9:25 AM To: Dwight Warner <dwarner@bluecrestenergy.com> Subject: RE: 24 hour production rates Hansen H04 Thanks, also can you verify the number given for the Gas volume in box 27? This is measured in MCF correct? The number seems extraordinarily large. Huey From: Dwight Warner <dwarner(c@bluecrestenergv.com> Sent: Friday, May 10, 2019 8:58 AM To: Winston, Hugh E (DOA) <hugh.winston@alaska.gov> Subject: RE: 24 hour production rates Hansen H04 The test data was for 12 hours but the rates are in bbls/day. The average rate during the last test on 4/2 was 604 bopd. After flowing back the oil based mud the well was doing 800 bopd on 3/31. before we choked it back to keep it stable. Let me know if you have any other questions Dwight Warner Sr. Production Engineer BlueCrest Energy Inc 3301 C Street, Suite 202 Anchorage, AK 99503 DwarnerP bluecrestener¢y.com (w)907 -754 -9556(m)907 -440-0192(f)907-754-5997 Dwight H04 Rev 1 Actual Mud Weight vs. Depth Data Table Days Depth MW From MD ppg Operational Notes Spud 0 8.6 PU DP / Prepare BHA / fill conductor 0 267 8.8 Spud well / drill to 308' for RSS BHA 1 758 9.0 Drill to 310'/ TOH for RSS BHA / TIH & Drill 17-1/2" 2 2430 9.8 Drill 17-1/2" surface section / 68 deg angle 3 3860 10.2 Drill 17-1/2" surface section / 68 deg angle 4 4910 10.25 Drill 17-1/2" surface section / 69 deg angle 5 5810 10.45 Drill 17-1/2" surface section to 5810' MD / BROOH 6 5810 10.4 BROOH for casing / LD BHA / RU to run 13-3/8" 7 5810 10.2 Run 13-3/8" surface casing 8 5810 10.3 Run 13-3/8" surface casing 9 5810 10.0 Run & cement 13-3/8" surface casing 10 5810 10.0 Displace cement / bump plug / install starter head 11 5810 9.6 NU & test BOPE / clean pits / build OBM / top job 12 5810 9.6 Work on top drive / MU BHA #3 cleanout BHA / PU DP 13 5810 9.6 TD rail alignment / RIH w/ singles & cleanout BHA 14 5810 10.5 Test casing to 3K; drill out shoe track/ swap to OBM 15 5810 10.5 POOH for RSS BHA / Test BOPE 16 5810 10.5 Test BOPE / Dummy Run 9-5/8" Hgr / RIH w/ RSS BHA 17 5963 10.5 RIH / Drill out shoe / FIT 13.2 ppg / Drill ahead 18 8590 10.5 Drill intermediate section w/ RSS BHA 19 11031 10.55 Drill intermediate section w/ RSS BHA 20 12790 10.55 Drill intermediate section w/ RSS BHA 21 14394 10.6 Drill intermediate section w/ RSS BHA 22 15420 10.55 Drill intermediate section w/ RSS BHA to Csg Point 23 15420 10.55 Circ & Cond at TD / Backream out for Casing 24 15420 10.55 Backream out for Casing 25 15420 10.5 POOH for casing / LD BHA / Test csg rams / RU to run csg 26 15420 10.55 Run 9-5/8" casing 27 15420 10.5 Run 9-5/8" casing 28 15420 10.6 Run 9-5/8" casing; land at 15406' MD; cement same 29 15420 10.65 Cement 9-5/8" / clean pits / chg rams / MU drill pipe 30 15420 10.65 Test BOPE / MU BHA 5 for production section 31 15420 10.2 RIH / test csg to 3500 OK / clean out shoe track 32 15440 9.3 Swap mud systems / drill 20'/ run FIT to 13.5 ppg EMW 33 16828 9.4 Drill 8-1/2" section to 1-01 / TD in 1-01 lateral / BROOH 34 16445 9.4 Trench & timedrill to L02 lateral 35 18230 9.5 TD in L02 lateral / BROOH 36 17957 9.5 BROOH L02 / Trench - ST - Drill L03 37 19017 9.5 TD in L03 lateral / BROOH / spot LCM pill 38 19017 9.5 BROOH to inspect / change BHA / chk Super Sliders 39 19017 9.5 BROOH to inspect / change BHA / chk Super Sliders 40 19017 9.5 Inspect BHA / LDDP / remove worn out Super Sliders 41 19017 9.5 Manage drill pipe / test BOPE 42 19017 9.5 PU DP / MU BHA / RIH to drill L04 43 17690 9.55 RIH _.rc and condition mud / Prep to drill L04 44 17865 9.3 Trench & timedrill to L04 lateral / reduce MW 45 19635 9.2 Drill L04 lateral / seepage mud losses ongoing 46 20094 9.2 Finish & Backream L04 / Trench & drill L05 lateral 47 19888 9.25 Drill L05 lateral 48 20735 9.3 Drill LOS lateral / BROOH in LOS 49 19513 9.2 Drill L06 lateral 50 20855 9.2 Drill L06 lateral 51 21358 9.2 Finish L06 / BROOH / Trench & ST to L07 52 20872 9.2 Drill L07 lateral 53 21830 9.2 Drill L07 lateral 54 21966 9.2 Trench & ST to L08 / Drill L08 lateral partially / top drive issues / BROOH 55 20867 9.2 TD of L08 Mother Bore is 20867' MD / BROOH to shoe 56 20867 9.2 Hang Off & Test BOPE - 14 days/ BROOH 57 20867 9.2 BROOH 58 20867 9.2 BROOH / POOH on elevators 59 20867 9.2 LD BHA / MU 4-1/2" slotted liner/ RIH 60 20867 9.2 Run 4-1/2" slotted liner/ enter LO1 wrong lateral BROOH 61 20867 9.25 BROOH / Pump out with 4-1/2" slotted liner 62 20867 9.2 Lay down 4-1/2" liner 63 20867 9.2 Lay down 4-1/2" liner / Repair Top Drive 64 20867 9.3 Service rig / wait on Top Drive parts and Tech 65 20867 9.3 Tesco Tech arrived / tear down Top Drive / repair same 66 20867 9.3 Complete Top Drive repairs / MU Cleanout BHA -7 / RIH 67 20867 9.3 Manage drill pipe / RIH w/ cleanout BHA -7 68 20867 9.3 RIH w/ cleanout BHA -7 / hang off on RTTS packer at shoe 69 20867 9.25 Test BOPE / Release RTTS / Ream in hole clean out L01 junction 70 20867 9.25 Clean out open hole / dress junctions for liner / clean to TD 71 20867 9.3 BROOH and dress each junction area 72 20867 9.3 BROOH and dress each junction area / BR & Pump Out 73 20867 9.3 Pump out for liner 74 20867 9.4 LD Cleanout BHA/ MU 4-1/2" slotted liner/ RIH on 5-1/2" DP 75 20867 9.4 Run liner to TD / set hanger & packer / circ well to brine 76 20867 9.2 Circ Well to Completion Brine / POOH / LDDP 77 20867 9.25 LDDP / RU and run 3-1/2" tubing upper completion 78 20867 9.25 RIH w/ 3-1/2" tubing upper completion & accessories 79 20867 9.25 RIH w/ 3-1/2" tubing / land same / shear valve / test SSSV - OK 80 20867 9.25 LD landing joint / set TWC / clean BOP stack / remove BOP 81 20867 9.25 Remove adapter spool / NU & pressure test tree / Slickline work 82 20867 9.25 Turn well over to production / install GLV / cold stack rig 83 20867 9.25 Set Top Drive in shipping cradle / cold stack rig 84 lue est Energy Cosmopolitan Project BlueCrest H04 Rev 1 Lower Lateral AOGCC Form 10-407 Well Completion Report Package A TTA CHMENT 6 Definitive Directional Wellbore Survey H04 Fishbone Well Naming & Numbering Index Well Name PTD No. from AOGCC API No. from AOGCC Final TO (MD) Notes H04 Mainbore 218-126 50-231-20064-00-00 20867 Final completed wellbore with 4-1/2" slotted liner in 8-1/2" hole 1404-1-01 218-127 50-231-20064-60-00 17200 8-1/2" Open Hole completion 1-104-1-02 218-128 50-231-20064-61-00 18230 8-1/2" Open Hole completion 1404-1-03 218-129 50-231-20064-62-00 19017 8-1/2" Open Hole completion H04 -L04 218-130 50-231-20064-63-00 20094 8-1/2" Open Hole completion 1-104-1-05 218-131 50-231-20064-64-00 20735 8-1/2" Open Hole completion 1404-1-06 218-132 50-231-20064-65-00 21358 8-1/2" Open Hole completion 1-104-1-07 218-133 50-231-20064-66-00 21966 8-1/2" Open Hole completion KOP Planned Actual TD Actual Actual Lateral Footage Lateral Volume (bbls) H04 Mainbore 15479 20867 5388 378 LO1 16382 16060 17200 1140 80 L02 17180 16860 18230 1370 96 L03 17980 17690 19017 1327 93 L04 18780 18440 20094 1654 116 L05 19580 19220 20735 1515 106 L06 20382 20038 21358 1320 93 L07 21180 20820 21966 1146 80 Total 14860 1043 n N py Z d N K N m rP2 N M d N W LL M b N LL 00 V1 ei N N m .Ni N m K V m tYl M d N J W LL Q n Q LL b O1 m O O m N N n N ei v F N M U d N J LL N m M LL O N N O� N ro N N .y N N N F N M V d N J W LL N m M LL N n Q N N m N N m K N m r N M d N W LL m ao rl LL b OI W N n m .Ni N ry C V1 M r N M d N J W LL a a N LL Q ll1 N a0 a ry .N-1 N M G V1 m r N M d N J W LL W M N LL O pl n b Of N .Ni N m K N m r N m d N J W LL O N m LL 01 N b O Vf m rNi N m n N oo m N n o N N N N N N e'I Vl X b p o O n M ao eni m T OO m N tbD N '1 e4 ei N N N N O N N A V r r�P2 m M M m N M M M M m m V M V t! V V N V N V d V d N d N d N t%f � tdl LL LL W LL LL b_ LL LL N LL b LL Q Vl n N l0 N V1 M N O (O Q N M Ot M N � N m m m V1 a Vf 1l1 N N '1 N N d ,. LL LL LL N LL LL LL_ LL LL M Q vl �bO N Q w1 n .r M � M Vb 01 eQi H N N M N b Of (O N b W n n n b M O O1 op .y H DJ b M DJ m m m 0o a m m eQ1 N N eQi N eQY N eNi N eNi N H N eN4 N n N Z N N N M M .. Q o m � m vi vi Lq .+ lG n b tG ry w O b � V1 Q O �Qvl N •i e1 ei 'i e1 e1 '1 X O p O� T p O m N NO d 00 a` q Z 'i ei 'I rl 'I ei N N 6 d p 0 0 0 0 0 g o 'o 0 x x x x0 x x x x MEMORANDUM TO: Jim Regg P. I. Supervisor State of Alaska Alaska Oil and Gas Conservation Commission Q?� I *'I I� DATE: FROM: Matt Herrera SUBJECT: Petroleum Inspector 3/21/19 Flowback Unit SVS Hansen H-04 BlueCrest Energy PTD 2181260 - 3/21/19: Traveled to BlueCrest's Hansen Production Facility and met up with Jared Brake (Bluecrest) and Robert Hoff (Production Technology Services; PTS) to inspect the flowback system set up by PTS for well H-04. The drilling rig had just completed wellbore operations and turned well over to production operations. The H-04 well system (mother bore and 7 laterals) flow path is as follows: wellhead to the PTS test header, to a choke manifold, to an inline heater, then separation (3-phase); a process and instrument diagram is attached. API gravity for the produced oil is estimated at 24 degrees so heat will be essential for separation. Only 2 -phase separation will be utilized until wellbore fluids have been cleaned up. The water -oil mix will be flowed back to relief tanks for cleanup. Once it has been determined wellbore brine has been cleaned out, the 3-phase separator portion will be utilized (internal oil weir to separate Oil/Water with gas breakout flowing through a mist extractor to the sales gas meter and sales line. Separated oil will flow to storage tanks for eventual custody transfer measurement before loading for truck transport. The temporary production flowback system is equipped with manual emergency shutdown system (ESD) capability at the choke manifold area and next to the 3-phase separator. Actuation at the ESD panels will close the surface safety valve (SSV) at the well head. The SSV and subsurface safety valve (SSSV) will be tied in to a low- pressure pilot trip (actuated) system when the well has been put on permanent production. The PTS test separator is protected with pressure safety valve that relieves to the clean-up tank. Separated "dry" gas also has relief to a flare system installed if necessary, with the gas relief line equipped with a scrubber to mitigate the carryover of any liquids to the flare system. Attachments: Photos (7); P&ID for Temporary Flowback System 2019-0321 _Wel I_Test_Unit_Hansen_H-04_mh. docx Page 1 of 5 Temporary Production Photos by AOGCC Insp 3/21/2019 Flowback System — Hansen H-04 (PTD 2181260) ctor M. Herrera 2019-032 1_Well_Test_Unit_Hansen_H-04_mh.docx Page 2 of 5 Hansen H-04 production tree TIM.,, Ao K f' ELI' l� F- 1®� • rl '-1 FIs 2019-0321 Well_Test_Unit_Hansen_H-04_mh.docx Page 5 of 5 PTS ESD Station PTS ESD Control Panel a Daum Q-, Zm�w° I� I � � c I of m0303 L__ L _ J Zam e a a D m _ CD N B 9 m � C vm D(n ZO hued of W 4S3 wO4 3NIl ouvn 13Nd r laved of l# 4S3 wau 3NIl oiim 13Nd n o m � rn m � rn Z p a I 'JNI1531 SNOIlYJOTT' OIAd 143NJ 3°l8 007 SJLd A'OU 153l1� 3N18 Ned N W OS3 wW 3NI�VWf13Nd • �• �• �• 41083 ® ® '�W� NNVl l31l3tl tl3BSfltl�S $Vj t tt (#0091SNV) OININM 110 8 T Nt t uWWR�I MW14 13NVd a OS3 Sid f I I wol; eurl ollwoPfH • I I 4 I m 113M N �M /� I ASS � I w L - - --_-_-_-_-_-_-_-_-_-_-_-_-_-_- I ISd MB'H31V3H 3NIl z — w I I I I I . 0lO-ANVW 3NOHO 'dgiV3H NOlionOONd .s II I I I $ 1 -.j I I I 1 h° � �� -Siz c►�d H04 Weekly Operations Recap to AOGCC 13March2019 Report # 90 Period: 13 March 2019 to 19 March 2019 hanger mechanically using secondary procedure. Picked up string to 360K and slacked off to 220K. Applied 4 rounds of left hand torque and locked in with Worked torque downhole . Repeated this process X 2 arta observed packer set @ 100K down weight. Picked up to 220K and rotated and verified packer set Dnll sting released. Lined up down the backside with annular closed and tested packer. Leaked. Slacked off and stacked weight to 98K and picked up to K. Tested packer d 2350 psi or 15 minutes Good test.PKked up strung to 152838' a f CBU @ 450/GPMV1325PSI. PJSM and displaced the 9 4 peg MOSM I me hole to 92 ppg Bone. Flushed TT line and cleaned TT. 2 X suction qts. troughs, and shakers. String was u -tubing. Mixed and pumped 9 9 ppg slug and )H laying down 5.5' DP Fr 15,288' to 6437'. Flushed each pint Coo fresh water Monitored well on Trip tank Serviced Rig I Blocks. crown. TDS. drawivorks. 643T POOH Laying down 51/' DP Flush each Ipnt wvth fresh water. Lay down running tool and cross over Monitor well on Trip tank. Lay down 5" XT -50 DP from denirk usfg muse hole Rg up to n#1 upper completion. 14March2019 Report # 91 POOH laying down 5 5' DP from 643T to 40'. Pulled liner running tool to surfaceinspected, and layed down. Charge elevator inserts and contime to lay down XT-% OP from the derrick via mousehole. Mortnp well on Trip Lank Cleaned Rig Floor. Drained BOP. Removed wear bushing. Made up Tulzng hanger to Lalling joint and made a dummy run. Verified placement. Layed down hanger and landing Idnl. Removed Co ling pals and elevators. Installed tutting bails and elevators. Rigged up GBR tang and equipment Rigged up Schlumberger control line sheaves and spools. Load pipe shed with tubing and leweny. Held pre lob meeting with all parties evolved vnth tinning the production tuning. Pre-Jousafety meeting'wnn all involved with running the produc on string Cperarons roceron Make nn seal, PassemuN antl %Os. Run 2 Idris of tubing. Pick up the SGM and correct control line. Test l0 5000 psi. RIH picking up 3.5' production tubing. 15March2019 Report # 92 PJSM on running upper completion. Make up seal assembly, locator sub, 1 joint of TSH 511. 8 XO to the tubing IBT thread 40rale depth Trp in We using single pint elevators from 40' to 129' Insall Standard gauge manldrel. down hole pressurettemp. Hook up I-wtte and test to 5000 psi for 15 minutes. Test good. Trip in role to joint # 8. Rig Floor hydraulic supply manifold block with the lime directly to the lugger to hast singles Off rue pipe skate to it* mouse rade By passed the block wth direct line to the tugger. Ran upper Completion 3 112' 9.3# L-80 BT -M from 343' m 10,356'. Installed Cannon camps on each joint for the Con" lines. Torque on tubing was to the diamond 2200-2400 Mos. Inspected each joint to ensure the seal nog was installed comecey. Monitored well on nip arik Good displacement After running Landino X milefilled lubma on the run and topped off each 15 fonts. 3 12' Upper completion F/ 10,356' Ti 14 736' filling inside tubing every 15 joints. Make up SSS\' and connect control line and lest Continue TIH'NO on stung to N- 90' above top of seal bore. Record PU 8 SO weights. TIH slowly and enter the seal We Orel the Bator on the seal assembly tags On e ee-tack receptacle. Space out tuotng with pigs and make up tubing hanger and landing loot Paw through tris temtinanans for the TEC wre and 'control lines. Slack off and land tubing. Test the tubing hanger to 5000 psi for 10 minutes. Rig up to ire 9 588' casing valve Test lines to 3000 psi. Test and top of the production seals to 1700 psi on test chart. Fitt tubing and test robing to 2500 psi for 10 minutes. Bleed pressure to 0. Gose SCSSS%1 test anni to 1500 psi for 10 mimttesand confirm SCSSS%' S holding pressure from below on test chart. Perform an equalization test on the 16March2019 Report # 93 RIH with 3 12' upper completion 9.3# IBT L-80 from 10.356' t0 15271' using Run -N -Seal dope. AVG torque 2400 ftlos. Installed Cannon clamps on each joint Slack off with 10k down weight @liner cop. 27.5' of compression. Calculated space out repumred. Layed down 71 22' of tubing. Made up 3 r pup joints. 7 67'. 9.6T. 9.81'. place pint # 452 on top. Hanger was observed to be machined or a 12.6 Ism pup Pup on hanger was 15.61bstfl. Broke harger off and picked up back up hanger. Layed down pips mat were poked up and recalculated space our. Picked up jam # 526. 28.60 and one 1.8' pup Ran 71,55' of tubing back into hole. Tem -mate 2 r: =hot lines in hanger on rig floor. SLB 8 GE working in Conjunction PUW 155K SOW 100K. Larded tubing with 15K on sea assembly. Clear ng flop of GBR 8 Stmumberger loi and equipment Rigged up or completion testing on aroulus and down the tubing Test the Ines to 3000 psi. While testing through the annulus observed a pressure loss @ 500 psi. Continued with test to 1700 p5 for /0 minutes Test charted. COW test Confirmed the shear valve was leaking by pumping dawn the annulus and getting retums through the tubing Closed SCSSSV and pumped dovm annulus to 1500 psi for 10 minutes. Good test. charted. J'hAh SCSSSV dosed. test backside to 1500 psi for 10 minutesgaol test on chart Perform eguali? inn test on SCSSSV. by dawn landing loin. Insall 21va'y check valve. Rig down SL8 control lines and sheaves from demck. Lay down casing bales and elevators. Rig mown all testing equipment and roses. Flush BOP wdh flush tool Flush choke and kill line with fresh water Open Ram doors, clean BOP with HP wash down gun. Grease rams. Npple dawn BOP Nipple up Production Tree and test. Rig up slick line top loading plug acid chane out the SO and dummy valves to GLVs 17March2019 Report # 94 CaouCt eWali�don 1251 of SSSV With 1500 PSI. Good. Put lending lam. Install TWC. Break down testing equipment Remove SchNmberga egapniem troch ng floor. GBR equipment, Well head equipment. Clean flow box. Wash stark. Pump deep clean Wim fresh water through 3 mud pumps. Croke. kill line. manifolds. UD neer. Lay down both mouse holes. Power down accumulator. Cleared aro Inspected BOP aro rams & greased. Tighten all ram does. Remove choke & KN lines. Disconnect koomey, hoses_ Remove bots from BOP to Adapor spool. Set BOP on pedestal and secure. Nipple dowi aidaptn spool. Remove GE starter head and riser from cellar. Temtlrtate the TEC one and 1ryect0VCon#ml lines through the tubing head bornet. Splice, run, and connect the TEC one Nipple up production bee. test void. Test tree with ng test pump 250 Psi ow for 5 minutes and 5000 pet high for 10 minutes. Remove TWC. Rid up slick kre 18March2019 Report # 95 I— I Remove starter head ham the cellar. Position tree over well. BOP secured with chains and BOP horst Clean up cellar area. scoops: Cleaning in the active and reserve pits. Pickle mud pump # 3. SLB ran 1-wre and control Imes through the tubing head uonnel. Nippled up tree to welpteed. SLB terminated tech wire and controlknees.. Tested Control brie to 5000 psi. Verged by CoMat Connected TECH wire to rmtroller, bad test. Switched to different counter. tested conductivity. Good test. GE tested void to 5000 psi. Good test. Rigged up arra tested tree with water to 350 psi low or 10 minutes and 5000 Psi high for 10 minutes. Good test Witnessed by CoMan and chatted. Removed tree Cap and removed TW C. Secure tree. Geared up all testing egrxpmem. PJSM - Rigged up Pollard wrehm on ODS. Hung sheaves on TO with cabled harness. SLB opened SCSSSV and locked open with needle varve. Run #1 to retrieve me ping in top nipple. Unsuccessful. Rus 92 retrieve prong in top nipple. Run its 3 & 4 unsuccessful to remove dummy valve horn GLM #1. Run 05 retheved dummy valve in GLM #i. ran #6 was successful to selling valve n GLM #1. RIH with 3" GS to 5125' antl pulled plugchage out tool strip to 15' x 2' stem. RIH with 3 12" OM -1 with JOS to 14,326' WL depth to latch onto valve in GLM # 3. POOH without valve Pollard shut down operations unto 10010"M Siniops: various pmlects or warm stack. Tum over well to production. Prepare ng for warm stack. Cleaning pits, reserve one. clearing pipe racks on ng floor. Prepare to lay TDS 19March2019 Report # 96 Remove dnlhng %Os and subs hen the rig floa. Transport to Premium for nspeeWm. Remove pipe rack mats and boards and clean. Remove creck valve from the mp tank discharge line. Flushed shaker pn centrifugal pumps. Greased MP fluid end pans. Remove IA pored flange aro store on ng floor Clean aro orgy a dog houses. Wash trip tank. Stage production pre -built piping and headers by H04 well head. Open gas buster and U-tube W drain. Open degasses inspection cover. Remove MP #3 bleeder valve, wasned body Simcps: Pollard slick line returned to work @ 06:30 him First two runs unsuccesshll. 3rd nn caught the dummy valve in GLM #3 @ 14.297'. Run #4 was unsuccessful metalling valve in GLM #3. Run #5 was successful minding valve in GLM #3 @ 14.29T Ridded down Pollard wire line. Slipped 11 wraps on drawwwks to lay down Top Drive. line to lav down the Too Drive Preparing Top Drive to lay dove. Remove Saver sub. IBOPs. "S' Pipe. Rotary lose. Wash pipe. Drain al, Disconnect elecmpal service loops. disconnect counter balance hoses. Remove dolly. Poseon TO camer on ng floor with crane. Lay down Top Drive NOTE: THIS IS THE FINAL REPORT FOR THE H04 DRILLING & COMPLETION OPERATIONS TWM, 20 March 2019 3"IPPIN( 50% 1*t 2-Ig_'ty(Irl fill NABORS / CANAG RECEOVED MAR 2 6 2019 Well: H04: (Shipping Box #1 - 6 Dry Sample Boxes) Main, JV API: 50-231-20064-00-00 (Shipping Box #2 - 5 Dry Sample Boxes) Main, API: 50-231-20064-00-00 (Shipping Box #3- 7 Dry Sample Boxes) 1-01, 1-02, 1-03, 1-04, 1-05, 1-06, L07 API: 50-231-20064-60-00, 61-00, 62-00, 63-00, 64-00, 65-00, 66-00 TD: 2/19/2019 Set Type Frequency Interval (Feet/ MD) Operator: BSC Crest Alaska Operating 5810'- 20867' TD Date: 2/20/2019 Well Name: H04 - Main, L01, L02, L03, 1-04, 1-05, 1-06, 1-07 prepared By: Benjamin Handley/ Barbara Delaney Location: Kenai Peninsula Borough, Alaska Hansen Field Shipping: 333 W 7th Ave, Suite 100 Anchorage, AK 99501 Attn: Meredith Guhl (907)739-1235 Well: H04: (Shipping Box #1 - 6 Dry Sample Boxes) Main, JV API: 50-231-20064-00-00 (Shipping Box #2 - 5 Dry Sample Boxes) Main, API: 50-231-20064-00-00 (Shipping Box #3- 7 Dry Sample Boxes) 1-01, 1-02, 1-03, 1-04, 1-05, 1-06, L07 API: 50-231-20064-60-00, 61-00, 62-00, 63-00, 64-00, 65-00, 66-00 TD: 2/19/2019 Set Type Frequency Interval (Feet/ MD) Main (11 Boxes, 504 Envelopes) Washed and Dried 30' 5810'- 20867' TD 1-01 (1 BOX & 39 Envelopes) Washed and Dried 30' 16040'— 17200' TD L02 (1 BOX & 46 Envelopes) Washed and Dried 30' 16850'— 18230' TD L03 (1 BOX & 44 Envelopes) Washed and Dried 30' 17690'— 19017' TD L04 (1 BOX & 55 Envelopes) Washed and Dried 30' 18440'— 20094' TD L05 (1 BOX & 51 Envelopes) Washed and Dried 30' 19220'— 20735' TD L06 (1 BOX & 46 Envelopes) Washed and Dried 30' 19988'— 21358' TD L07 (1 BOX & 39 Envelopes) Washed and Dried 30' 20827'— 21966' TD Total Number of Dry Sample Boxes: 18 & Total Number of Envelopes: 824 Number of Dry Sample Boxes: 18 Packaged into 3 Large Shipping Boxes 'Shipping Box #1: H04 Main Well Bore (6 Dry Sample Boxes) r 6 Number of Envelopes: 283 5810• To ly 300 Shipping Box #2: H04 Main Well Bore (5 Dry Sample Boxes) Number of Envelopes: 221 Shipping Box #3: H04L01, H041-02, H041-03, H041-04, H041-05, H041-06, H041-07 (7 Dry Sample Boxes) Number of Envelopes: 320 BLUECREST RIG #11 JOB #: A1744 / WELL: H04 — Main, 1-01, L02, L03, L04, L05, L06, L07 i'�03 rwl 105 koro t� q0q ,-410 r -(2S(�, 4-4 2161 UO Regg, James B (DOA) From: Regg, James B (DOA) Sent: Tuesday, March 19, 2019 10:03 AM3ltglf T To: Dwight Warner; Alecia Wood �\ 6 Cc: larry.burgess@bluecrestenergy.com; FracOps; Schwartz, Guy L (DOA); DOA AOGCC Prudhoe Bay Subject: RE: SVS Test Within First 5 Days _ Waiver Request for H04 PTD 218-096 through 218-102 Thank you for the P&ID. Yesterday we received BlueCrest's notice for opportunity to inspect the PTS equipment as rigged up for Hansen H-04., scheduled for 3/21. An AOGCC Inspector will contact you about updates as you proceed. Just to be clear about AOGCC's expectations: A passing performance test of the well H-04 surface safety valve (SSV) or equivalent shutdown valve within the PTS equipment must be completed before commencing flow through the well test system (LPS trip; closure of SSV, and ability to hold pressure differential). Also, the well's SSSV must be function tested for AOGCC witness. Performance testing of the well's entire SVS (SSV, LIPS, SSSV) to satisfy the requirements of 20 AAC 25.265(h)(4) may be deferred up to 14 days after startup of flowback from well H-04. The well SVS must be made operable and performance tested after flowback operations are completed and the well is placed in production. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or iim.reee@alaska.eov. From: Dwight Warner <dwarner@bluecrestenergy.com> Sent: Monday, March 18, 2019 11:18 AM To: Regg, James B (DOA) <jim.regg@alaska.gov>; Alecia Wood <alecia.wood@bluecrestenergy.com> Cc: larry.burgess@bluecrestenergy.com; FracOps <fracops@bluecrestenergy.com>; Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe.bay@alaska.gov> Subject: RE: SVS Test Within First 5 Days _ Waiver Request for H04 PTD 218-096 through 218-102 Jim, My name is Dwight Warner and I am replacing Alecia as the Sr Production Engineer here at Bluecrest Energy. I am just getting up to speed so bear with me as I work with Alicia to get in a position where I will not need her help anymore. I am not sure if you remember but I did work with you years ago when I was the lead PE for GPMA and I am looking forward to working with you again. Sorry for the late notice as Alicia was Ll ying to take care of this but her computer has died. She is still trying to get it working but I wanted to at least give you the P&ID for PTS as we won't be using Expro on the new well as they have left the state. We have already functioned tested the SSSV as described below and will be ready to begin flowback later this week. Attached is the P&ID showing that we will be using the wellhead SSV by having a line run from PTS unit to the SSV panel. Operations will notify through the web page once we have a better idea what day we will be ready. Please give me a call or respond with any questions or additional information. Dwight Warner Sr. Production Engineer BlueCrest Energy Inc 3301 C Street, Suite 202 Anchorage, AK 99503 Dwarner@bluecrestenergv.com (w)907 -754 -9556(m)907 -440-0192(f)907-754-5997 From: Regg, James B (DOA) <iim.regg@alaska.gov> Sent: Thursday, December 06, 2018 10:58 AM To: Alecia Wood<alecia.woodCa@bluecrestenergy.com> Cc: larry.burgess@bluecrestenergy.com; 'FracOps' <fracops@bluecrestenergy.com>; Schwartz, Guy L (DOA) <guy.schwartzt@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.Prudhoe. bav@alaska.gov> Subject: RE: SVS Test Within First 5 Days _ Waiver Request for H16A PTD 218-096 through 218-102 Thank you for providing the Expro test system P&ID (Drawing # WT-XAK-20107) and the procedure for the well test emergency shut down system (ESD System Check). A passing performance test of the Expro SSV (P&ID Tag 20-XAK- 004) must be completed before commencing flow through the well test system (LPS trip; closure of SSV, and ability to hold pressure differential). Also, the well's SSSV must be function tested. Performance testing the well's normal SVS (including SSSV) may be deferred up to 14 days after startup of flowback from well H -16A. The well SVS must be made operable and performance tested after flowback operations are completed and the well is placed in service. BlueCrest must provide notice to AOGCC for the opportunity to inspect the Expro well test system when rigged up on H -16A and to witness the Expro SSV performance test. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or iim.reggOalaska.gov. Regg, James B (DOA) P�n z(t51 Z6c From: Dwight Warner <dwarner@bluecrestenergy.com> Sent: Monday, March 18, 2019 11:18 AM 1 To: Regg, James B (DOA); Alecia Wood Cc: larry.burgess@bluecrestenergy.com; FracOps; Schwartz, Guy L (DOA); DOA AOGCC Prudhoe Bay Subject: RE: SVS Test Within First 5 Days _ Waiver Request for H04 PTD 218-096 through 218-102 Attachments: Bluecrest-BCE P&ID REV04.pdf Jim, My name is Dwight Warner and I am replacing Alecia as the Sr Production Engineer here at Bluecrest Energy. I am just getting up to speed so bear with me as I work with Alicia to get in a position where I will not need her help anymore. am not sure if you remember but I did work with you years ago when I was the lead PE for GPMA and I am looking forward to working with you again. Sorry for the late notice as Alicia was trying to take care of this but her computer has died. She is still trying to get it working but I wanted to at least give you the P&ID for PTS as we won't be using Expro on the new well as they have left the state. We have already functioned tested the SSSV as described below and will be ready to begin flowback later this week. Attached is the P&ID showing that we will be using the wellhead SSV by having a line run from PTS unit to the SSV panel. Operations will notify through the web page once we have a better idea what day we will be ready. t Please give me a call or respond with any questions or additional information. Aka $Ie e ,^^ __ 1r �'S� Dwight Warner Sr. Production Engineer BlueCrest Energy Inc 3301 C Street, Suite 202 Anchorage, AK 99503 DwarnerP bluecrestenergv.com (w)907 -754 -9556(m)907 -440-0192(f)907-754-5997 From: Regg, James B (DOA) <iim.regg@alaska.gov> Sent: Thursday, December 06, 2018 10:58 AM To: Alecia Wood<alecia.wood@bluecrestenergy.com> Cc: larry.burgessc@bluecrestenergy.com; 'Fracops' <fracops@bluecrestenergy.com>; Schwartz, Guy L (DOA) <guv.schwartz@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.Prudhoe. bay@a laska.gov> Subject: RE: SVS Test Within First 5 Days _ Waiver Request for H16A PTD 218-096 through 218-102 Thank you for providing the Expro test system P&ID (Drawing p WT-XAK-20107) and the procedure for the well test emergency shut down system (ESD System Check). A passing performance test of the Expro SSV (P&ID Tag 20-XAK- 004) must be completed before commencing flow through the well test system (LIPS trip; closure of SSV, and ability to hold pressure differential). Also, the well's SSSV must be function tested. Performance testing the well's normal SVS (including SSSV) may be deferred up to 14 days after startup of flowback from well H -16A. The well SVS must be made operable and performance tested after flowback operations are completed and the well is placed in service. BlueCrest must provide notice to AOGCC for the opportunity to inspect the Expro well test system when rigged up on H -16A and to witness the Expro SSV performance test. Jim Regg Supervisor, Inspections AOGCC 333 W.71h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or iim.reee@alaska.gov. From: Alecia Wood<alecia.woodCa@bluecrestenergy.com> Sent: Tuesday, December 4, 2018 3:48 PM To: Regg, James B (DOA) <jim.regg@alaska.gov> Cc: larry.burgessCa@bluecrestenergy.com; TracOps' <fracops Ca) bluecrestenergv.com> Subject: RE: SVS Test Within First 5 Days _ Waiver Request for H16A PTD 218-096 through 218-102 Jim, Attached is the test procedure from Expro. We will pressure test the SSSV from below before the rig N/D the BOP and N/U the tree. They will test the self equalization of the valve, that it holds pressure from below and allow it to open. We can do a function test of the hydraulics after the rig releases it however without DP we will not be able to see if the valve is open/closed until we start the flowback and unload the kill weight fluid. Alecia From: Regg, James B (DOA) [mailto:jim.regg(cbalaska.00v] Sent: Wednesday, November 28, 2018 2:09 PM To: Alecia Wood Subject: RE: SVS Test Within First 5 Days _ Waiver Request for H16A PTD 218-096 through 218-102 Please provide the test procedure for the Expro well test unit's safety valve system (equivalent to well SSV). Will the SSSV be function tested as done with H-12? Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCQ, 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 forwaroirig it, and, so that the AGGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.rezeC@alaska.¢ov. From: Alecia Wood <alecia.wood@bluecrestenergy.com> Sent: Monday, November 26, 2018 2:30 PM To: Regg, James B (DOA) <lim.regg alaska.gov> Cc: 'Joshua Hall' <ioshua hall@bluecrestenerg _.com>;'FracOps' <fracops bluecrestenergy.com>;'Larry Burgess' <larry.burgess@bluecrestenergy.com> Subject: SVS Test Within First 5 Days _ Waiver Request for H16A PTD 218-096 through 218-102 Hi Jim, We are approximately two weeks out from bringing our new drill H16A online and are requesting a waiver of the SV5 test requirement within the first 5 days of production as we did with H12. We are planning to flow back through Expro (please see attached schematic of the equipment and ESD) to unload the brine and OBM to tanks while flowing the gas to the facility. The well will be completed with open hole laterals and a slotted liner in the main bore, we are requesting permission to continue flowing back the well while it is cleaning up which may take more than 5 days (Estimate 10-14 days?)to minimize water hammering. Once the fluids have cleaned up and the well stabilizes we will turn the well over to operations and submit our witness notification to test our SVS as soon as possible. Please let me know if you approve or have any questions or concerns. Thank you! Alecia Wood Alecia Wood Sr. Production Engineer BlueCrest Energy Inc 3301 C Street, Suite 202 Anchorage, AK 99503 Alecia.Wood@BlueCrestEnergy.com (w) 907-754-9556 (m) 907- 394-2485 (f) 907-754-5997 I46i 14-04 (per zte&t zbo ) 0' 150; i L _ _ J PRODUCTION HEATER v z IM c a n r e m M SSv I 3 I o I I N I I O WELL HI J L ICD LINE hom Pibtb Pawl From NroP�U nE PANEL WELL M Hydraulic Line from PTS ESD v z PANEL I c I D C IM I Z J3 o tank m N fa m v 21 0 m '1 600#) m gas ro Owe Iw BLUE. CREST ENERGY TZ BLUE CREST P&ID JMF _TI -1 s ALLOCATIONS TESTING MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg111�l DATE: January 8, 2019 P. I. Supervisor )< f `I 1 FROM: Brian Bixby Petroleum Inspector SUBJECT: Cement Top Job Hansen H-04 Blue Crest Energy PTD 2181260 01/07/19: 1 arrived at location and met up with Rowland Lawson (Drillsite Supervisor) and George Brewster (All American Toolpusher). We discussed the surface casing cement top job which will include tagging the top of cement and getting cement to surface. They used %" conduit threaded together and installed down the annulus between conductor and surface casing. The top of cement was tagged and 60 feet. The crews rigged up to the top of the conduit and pumped 16 bbls of 15.2 PPG cement until good 15.2 PPG cement was ' seen at surface. I witnessed weighing of 3 different samples of the cement returns — all 15.2 PPG. This was a successful cement top job. Attachments: none 2019-0107_Surface_Csg_Topjob_Hansen_H-04_bb.docx Page 1 of 1 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Larry Burgess Alaska Manager BlueCrest Alaska Operating, LLC 3301 C Street, Suite 202 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Hansen Field, Undefined Oil Pool, H04 BlueCrest Alaska Operating, LLC Permit to Drill Number: 218-126 revised Surface Location: 2089' FSL, 1541' FEL, SEC. 2, T4S, R15W, SM Bottomhole Location: 3847' FSL, 3680' FEL, SEC. 32, T3S, R15W, SM Dear Mr. Burgess: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .aogcc.olaska.gov Enclosed is the approved application for the permit to drill the above referenced development well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce is contingent upon issuance of a conservation order approving a spacing exception. BlueCrest Alaska Operating, LLC assumes the liability of any protest to the spacing exception that may occur. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Hollis S. French L Chair DATED this -2- , day of December, 2018. STATE OF ALASKA ALA % OIL AND GAS CONSERVATION COMMIS: J PERMIT TO DRILL 20 AAC 25.005 C�U('- 5 -1:-__b T& ►/vt (T- . Proposed Well Class: Exploratory - Gas ❑ Service - WAG [:]Service - Disp ❑ Ia. Type of Work:4xploratory ic. Specify if well is proposed for: Drill Lateral tratigraphic Test Q•Development - Oil ❑Service- Winj E]Single Zone 0' Coalbed Gas ❑Gas Hydrates Redrill Reentry -Oil Development - Gas Service -Supply ❑ Multiple Zone ❑ Geothermal F] Shale Gas 2. Operator Name: 5. Bond: Blanket . ❑ Single Well ❑ 11. Well Name and Number: BlueCrest Alaska Operating LLC Bond No. 5511251547 • H04 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3301 "C" Street, Suite 202, Anchorage, AK 99503 SL MD: 22,120' TVD: 7,062' Hansen, Undefined Oil Pool 4a. Location of Well (Governmental Section): AS -STAKED 7. Property Designation: Surface: 2089' FSL, 1541' FEL, Sec. 2, T4S, 1 7 4 SM ADL 18790, ADL 384403, Fee -Hansen Top of Productive Horizon: 9-5/8" Csg Point 8. DNR Approval Number: 13. Approximate Spud Date: 582' PSL, 3820' FEL, Sec. 33, T3S, R15W SM LOCI 14-007 12/23/2018 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 3846' FSL, 3681' FEL, Sec. 32, T3S, R1 5W SM 14423 543' (YO1664) 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (it): 179.72 15. Distance to Nearest Well Open Surface: x- 168804 y- 2144597.65 Zone- 4 GL / OF Elevation above MSL (ft): 145.1 Ito Same Pool: 2590'- H1AL1 16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 115 degrees Downhole: 3,549 psi • Surface: 2,842 psi (using 7,070' TVD) 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) Driven 20 0.5" wall A252 Welded 152 41 41 193 193 WA - Rotary Drilled / Driven 17.5 13.375 72 L-80 BTC 5581 40 40 5621 3530 Lead: 715 bbls, 12.0 ppg Tail: 167 bbls 15.8 ppg Class G 12.25 9.625 47 Pilo Hyd 563 15982 38 38 16020 7128 Tail: 132 bbls, 15.8 ppg Class G TOC: 14,520' MD / 6,740' TVD 8.5 4.5 15.2 Pilo Hyd 563 6000 15920 7125 22120 7062 Slotted Liner- No Cement; 100' lap 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD III): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): N/A Perforation Depth TVD (ft): N/A Hydraulic Fracture planned? Yes ❑ No Q 20. Attachments: Property Plat O BOP Sketch v Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program ,r 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Thomas McKay Authorized Name: Larry Burgess Contact Email: tom.mckavCa)bluecrestenerav cam Authorized Title: Alaska Manager Contact Phone: 907-754-9566 Authorized Signature: Date: 20 -Dec -18 Commission Use Only Permit to Drill API Number. Permit Approval See cover letter for other Number: ` 50-/--3 / -- z�/(,�� - ^(�C'j Date: requirements. Conditions of approval: If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: . 3.J�� 5 :' /�010 TtSt- Samples req'd: Yes ❑ No Mud log req'd: YesoHzS measures: Yes o Directional svy req' :�P"�� 'S acing exception Yes [JNo Inclination -only svy req'd: Fe �re/q'd: iim•'r3cct• 13 Q_ G, %� Post initial injection MIT req'd: Yes ENO �� iJe/ f. r Gtl�i i vt� �r e� Z v A 4L Z o a 356 h )&-- . APPROVED BY L I Approved by: t Z. COMMISSIONER THE COMMISSION Date: \ (v/ �1D Ls (Q, O' Form 10-401 Revised 5/2017/JX This permit is valid fog /� -R4 G IhNterai A Submit Form and proval per 20 AAC 25.005(9) Attachments in Duplicate fue st Energy 3301 C Street, Suite 202, Anchorage, AK 99503 Thomas W. McKay, P.E. Phone: (907) 754-9566 Email: tom.mckay@bluecrestenergy.com December 20, 2018 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Cosmopolitan Project RE: Application for Permit to Drill: Horizontal Production Well H04 Revision 1 Fishbone Producer H04 API No. 50-231-20064-00-00 H04 PTD No. 218-126 Form 10-401; Fishbone Multilateral Well Design Dear Commissioners, BlueCrest Alaska Operating LLC hereby applies for a Permit to Drill for the onshore horizontal production well H04 - Rev 1 — Fishbone Producer. This well will be drilled and completed using BlueCrest Rig #1. The expected spud date could be as early as 23 Dec 2018. H04 Rev 1 will be a multilateral producer, employing seven (7) "fishbone" style ribs drilled off the mainbore up into the full section of reservoir present on this Lease. The H04 Rev 1 well will be a grass roots producer drilled from the adjusted H03 slot. The H04 Fishbone Producer well will not be fracture stimulated but instead will rely on the seven (7) rib open hole wellbores to drain the hydrocarbon fluids, etc. into the main bore which will be cased with a 4-1/2" slotted liner. The well will be completed with 3-1/2" tubing and lifted using gas lift as needed. A Diverter Waiver was previously approved for the H04 well. Please find attached for the review of the Commission an updated Form 10-401, along with a recap explanation for the change in surface slot and well name. Please note that the eight (8) Spacing Exceptions for this H04 well have already been approved. Also note that seven (7) additional yet abbreviated APD packages have been submitted and approved for each well 'rib" numbered L01 through L07, which are proposed to be open hole sidetracks off the mainbore. As per AOGCC regulations, each rib requires its own unique name and APD. If you have any questions or require further information, please do not hesitate to contact Tom McKay at 907-754-9566 (office) or 907-350-9544 (cell). Sincerely, 4 Larry Burgess Alaska Manager 0 BlueCrest Alaska Operating LLC lye st Energy H04— Rev 1 BlueCrest H04 Rev 1 Fishbone APD Revised Package - Main Bore section Topic Cosmopolitan Project A Cover Letter/ Table of Contents B Explanation for Slot and Well Name Change C Revised Form 10-401 for H04 Rev 1 D H04 Rev 1 Legal Coordinates for Mainbore plus seven (7) laterals E H04 Rev 1 As -Staked Surface Slot Location in H03 Slot F Revised Cement Volume Calculations for Surface & Intermediate Casings G Revised Directional Plan for H04 Rev 1 H I H04 Rev 1 New Well Ria Elevation Form — to be submitted when ria is on slot I lue est Energy Cosmopolitan Project BlueCrest Well H04 (PTD 218-126); to be revised to H04 Rev 1: This recap explanation of the BlueCrest H04 well covers the period December 14 through December 18, 2018, and covers the sequential operations as follows: Release rig to H04 from H16A Release H16A well to Production Dept. and flowback H16A well to Expro Commence Rig Skidding Operation on rail system to H04 well, with 20" conductor previously installed With rig over / near Slot 10; discover that rig was drifting / creeping slightly in a westerly direction Creep rate was approx 1" per 20 feet; well row runs in an approximate north -south orientation Projected rig would "miss' center of H04 conductor by approx one foot_to the west__ Ceased moving rig any further; the cause of this creeping is not fully understood as of yet Decision made to set a new 20" conductor in the adjusted H03 slot; adjusted by surveyor's projection as to where rig would "land" at slot 3 after skidding Discussed matter with AOGCC (Guy Schwartz, 18Dec2018), and plan is to drill H04 Revision 1 well from H03 slot Operator has provided in this document package: cover letter with this explanation, new surface location, new as -staked Slot 3 surface location, revised Form 10-401, and revised directional plan using new surface slot for the H04 Rev 1 well. This morning (19 Dec), we are mobilizing Kraxberger to set a new conductor in the H03 slot, and preparing the rig to drill surface hole as it waits to skid to the H03 slot. PLEASE NOTE: As it stands now, we could be spudding the H04 Rev 1 well approximately 23-24 Dec 2018, but it is dependent on the rig and well center alignment V currently being resolved. \1 WELL #4 - REV 01 N.A.D.83 N: 2144356.76 E: 1308831.20 LAT: 59'51'27.32"N LON: 151'48'13.78"W N.A.D.27 N: 2144597.65 E: 168803.55 LAT: 59'51'29.48"N LON: 151'48'06.03"W 1541' F.E.L. 2089' F.S.L. GROUND (PAD) ELEVATION PLANT: 97.4' NAVD 88: 145.1' - 4.76' - �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� N T4S R15 SEC 2 C$ 0 T4S R15W q SEC t THIS SURVEY µi Y T4S R15W SEC 11 ur is1 VICINITY MAP a 5 10 ICS ( IN FEET ) 1 inch = 10 ft. _�P��••OF q��Slrh ��. •' �y SAA' i� J J JACOB GERONDALE;'moo S s'• LS -11758 tea_ AS STAKED SURVEY BLUECREST ENERGY WELL #4 - REV 01 WITHIN SECTION 2 T4S R15W S.M., AK. I LOUNSBURY & ASSOCIATES, INC. I Surveyors - Engineers - Planners 5300 A STREET, ANCHORAGE, ALASKA 272-5451 GRID: H04 Rev 1 Surface Casing - 13-3/8" REVISION 1 H04 Rev 1 Intermediate Casing - 9-5/8" REVISION 1 Cement Volume Calculations for APO Cement Volume Calculations for APD Planned Depth of 13-3/8" Shoe 5621 feet MD Planned Depth of 9-5/8" Shoe 16020 feet MD Top of Tail Cement by Design 4621 feet MD Top of Tail Cement by Design 14520 feet MD Length of Lead Cement 4621 feet MD Length of Tail Cement 1500 feet MD Length of Tail Cement 1000 feet MD Bit Size 17.5 inches Bit Size 12.25 inches Casing OD 13.375 inches Casing OD 9.625 inches Assumed Actual Average Hole Size 17.50 inches Assumed Actual Average Hole Size 12.25 inches Annular Volume Factor 0.1237 bbls/ft Annular Volume Factor 0.0558 bbls/ft Lead Cement Volume 572 bbls No Lead Cement Required Excess 25 Lead Excess Barrels 142.9 bbls Lead Cement Volume with Excess Added 714.6 bbls Lead Cement Density 12.0 ppg Lead Cement Yield 2.44 cubic feet / sack Tail Cement volume 124 bbls Tail Cement volume 84 bbis % Excess 25% % Excess 50% Tail Excess Barrels 30.9 bbis Tail Excess Barrels 41.8 bbis Tail Cement Volume with Excess Added 154.7 bbls iTail Cement Volume with Excess Added 125.5 bbis Tail Cement Density 15.8 ppg Tail Cement Density 15.8 ppg Tail Cement Yield 1.16 cubic feet sack Tail Cement Yield 1.16 cubic feet sack Casing ID 12.347 inches Casing ID 8.681 inches Casing Internal Volume Factor 0.1481 bbis/ft Casing Internal Volume Factor 0.0732 bbis/ft Shoe Track Length 80 feet Shoe Track Length 80 feet Shoe Track Tail Cement Volume 11.8 bbis Shoe Track Tail Cement Volume 5.9 bbis Total Lead Cement Volume in Barrels 714.6 bbis No Lead Cement Required Conversion Factor Barrels to Cubic Feet 5.615 cubic feet / barrel Total Lead Cement Volume in Cubic Feet 4012.8 cubic feet Total Tail Cement Volume in Barrels 166.5 bbis Total Tail Cement Volume in Barrels 131.4 bbis Conversion Factor Barrels to Cubic Feet 5.615 cubic feet/ barrel Conversion Factor Barrels to Cubic Feet 5.615 cubic feet / barrel Total Tail Cement Volume in Cubic Feet 934.9 cubic feet Total Tail Cement Volume in Cubic Feet 737.6 cubic feet Volume of Mud Push II Spacer at 11.0 ppg 80 bbls Volume of Mud Push II Spacer at 11.0 ppg 100 bbis Total Sacks of Lead Cement Required 1645 sacks Total Sacks of Tail Cement Required 636 sacks Total Sacks of Tail Cement Required 806 sacks N Energy H04 (P2) Proposal Geodetic Report (Def Plan( 1: BlueCreat Ixl Cwenowi to Unit turn l Sloc Caam inoitan Ped/H-04(3) VSEL Study Study bole: Hw'm"" F�sibilitY ay Name: W2312006 HU (P2) ey Date: December 19. M18 I AND I DDI I ERD Ratio: 1%.549' / 19452.44) It 16.9]5/ 2.]29 dirt. Rate.. grader; NA11,27 Alecks StalePlane, Zone 04 US Feet tion Let l Long: N 59' 51' 294844D', W 151.4W602930' ' tion Grid WE YM N 2144597.654 HUS, E 16411(03.236 NIS Grid Convergance Angle: -1.5582' Scale Factor: 100002404 Ion / Patch: 2.10.544.0 Vertical Section AtlmuM: VaNcal Section Origin: TVD Reference Datum: TVD Reference Elevetlao: Ground Elevation: Magoon. Daalinatian: Total Gravity Field Strength: Greatly Madel: Total Magnetic Field greater: Magnetic DIR Angle: Declination Data Magoagc Declination Mori Nang+ Reference: 300.000 -(True NOM) DODO R. 0.000 R Romry Tebb 179.820 it above MSL 145.17011 above MSL 14.474' t 601.2613m9n (9 80665 Saeed) DD% 52 nT .uo - n January 1)019 HDGM 20010 True 0.00000 ' - 14.x741 Cosmopolftan UnitlCosmoplitan PacKH15-P2\H15-P2\H75-P2 (Pi) Drilling Office 2.8.572.0 . Schlumberger -Private 12120/201810:57 AM Page i of MO Ixl Aalm True TVDSS TVU VSEL H9 EW TF OLS Exclusion Zona Hclealan tom GaoMag Th No("Sn E(US) Commanm (� (.( (.) (ft) (fl) (ft) (ft) (ft) (1 Difficulty (%180fl) DlMcolry lndaa Alert An9k (nT) (RUS) (US) RTE 000 0.00 0.00 -179.02 000 GO) 0.00 am 283M WA 0.00 1713 16223.15 2144597,65 16800324 10000 000 283.00 -79.02 100.00 0.00 0.00 0.00 283M 0.00 0.00 17.13 16223.34 2144597.65 16880324 200.00 000 283.00 20.10 200.00 000 0.00 0.00 283M 0.60 0.00 17.13 16223.52 214459765 16880324 WOOD 0.00 283.00 120.18 300.00 000 000 000 283M 0.00 0.00 1713 1622371 2144597.65 16880324 KW Cry 111M 400.00 000 28300 220.18 400.00 0.00 0.00 0.00 283M 0.00 0.00 17.13 1622389 2144597.65 16000324 500-00 1.00 28300 320.17 499.99 0103 020 485 283M 1.00 0.00 17.18 16271% 2140.59707 168802.39 Crv21100 600.00 200 28300 42014 599.96 3.34 019 3.40 283M 1.00 004 17.29 16374 2144598.53 160]99.86 700.00 4.00 283.00 520.% 69982 8.34 1.96 4.50 28W 2.00 154 17.60 16726,19 2144599.65 160794.79 Cry 2.51100 80000 6.00 283.00 619.61 79943 1668 392 -16.99 2,891 2.00 2.02 18.26 17264.73 2144602.04 160786.36 900.00 8.50 283.85 718.80 898.62 2677 6.87 49.26 20511 2.% 2.41 19.15 18067.77 2144605.32 160774.17 1000.00 1100 284.32 81735 91 45.013 11.00 45.68 1.5611 2.50 2.71 20,29 191D2A6 2144609.69 168757.07 110000 13.50 284.62 915.07 1094.89 85.49 16.30 ,76.21 1311 2.W 2.97 21.65 2032].45 2144615,75 168737.49 1200.00 16.00 284.82 1011.]] 1191.59 90.04 22,77 -90.80 IAR 2.W 3.10 23.20 21701.05 214462289 160713.06 1300.00 1849 284.97 1107.27 1207.09 11866 WAG -119.47 DM 2.50 336 24,89 2318].]8 2144631.29 168684.63 1400.00 2099 285.09 1201.38 1301.20 151.30 39.16 -152.10 0.84R 2.66 352 2870 24757.05 2144640.94 16865226 1500.00 23,49 285.18 129393 1473.75 187.89 49.04 -1(16.64 0.7611 2.50 3.67 28.61 26383.31 2144651.81 168616.00 160000 25.99 205.26 1304.74 1564.56 228.35 60.03 -229,02 0.698 2.W 3.80 W.W 2804539 2144883.89 168575.93 1700.00 2849 285.32 147364 165346 Me 73.10 -23.18 DIGR 2.50 392 32.65 29]25.]3 2144877.18 168532.12 180000 W.9t, 285.37 1560.46 174018 320.62 85.23 32101 0598 2.50 4.03 31]5 31409.66 2144691.59 16848485 1900.00 M49 28542 1615.03 1824.85 372.25 99.40 37345 D. 2.66 4.13 36.90 33084.81 2144707.15 168433.82 200000 35.99 285.46 1M7.20 1907.02 427.40 114.57 42.36 0.5111 2,66 4.22 39.011 3474061 2144M3.81 160379.12 200.00 W.49 265.50 1801 1986.62 485.99 130.72 485.70 04911 2.50 4.31 41.30 3636798 214474184 16832126 2200.00 40.99 285.53 1883.68 2063.50 54708 14782 -547.W 04611 21% 4,39 4354 3]9509] 244760.31 168260.15 230000 4349 285.56 1957.71 2137.66 812.98 185.81 4612,06 04411 2.50 4.47 45.66 66506.59 244766.08 16819590 2400.00 45.99 205.59 2028.73 200.55 861.15 184.]3 fi79.66 042R 2.50 4.55 48% 41066.82 2144800.81 168128.63 2660.00 4849 Mat 20%.61 22]6.43 752.26 20447 -7W.W OAR 2.50 4.62 50.38 42447.51 244822.47 16005048 2600.00 W." 285.63 216123 2341.05 826.18 225.02 424.07 0.398 2.50 4.60 52.69 4W3014 2144845.01 167905.57 2700.00 W49 285.65 2222.45 240217 902.76 246.31 -900.20 0.3811 2.50 4.75 55.01 4514829 21441168.39 16791005 280800 55.99 265.67 228 17 24W.99 War 268.66 -97882 03611 2.50 481 57.34 46397.53 2144892.% 16783206 290000 56.49 285.69 2334.28 2514.10 1063.35 291.11 -105918 0.3511 2.50 4.87 59.60 47574.24 2144917.49 16]751.]4 300000 60.99 265.71 2384.66 2564.40 1147.04 314,49 -1142.92 0.3511 2.50 493 82,03 48675.02 2144943.11 16766926 31DDD(, 63.49 285.]3 243123 2611.05 1232.80 38846 -128.10 0348 2.W 498 64.39 4%%.73 2144959.39 16]5841] 3200.00 65.99 285.74 273.89 260,71 1366.44 662.911 -1315.14 03311 266 5.04 66.75 50(06.79 2449%2 16749842 366000 6649 285]6 251257 2692.39 1409.81 360.01 -1403.89 032R 2.50 5.09 69.11 51492,51 2145023.71 167410.W EM Civ M14AS 68.85 285.76 251784 2697.66 1422.89 391.66 -141688 HS 2.50 5.09 Wall 51603.66 2146627.73 167W7.W 3400.00 60.05 285.76 254869 2720.51 1500.20 413.34 -1493.64 HIS 0.00 5.12 69.46 51609.89 2145051.47 16732.36 350G0G 66.85 285.76 2584.76 26450 1590.66 430.6] -1583.40 HIS 0.00 5.16 89.48 5161049 2146679.23 167232.32 WMA0 ( 1.85 285.76 2620.84 2066.66 1661.00 464.00 -1673.16 HS 0.00 5.19 69.46 51611.09 2145107.00 167143.20 3700.00 Wait 285]6 26%.91 2836.73 1771.40 489.31 -1762.92 HS 0100 5.22 6946 5161189 214513416 1670M 24 3800.00 68.85 28516 2692.98 2872.80 1%1.66 51487 -185280 HIS 0.00 5.24 69.46 5161238 2145162.53 16696520 3900.00 68.85 265.76 229.05 2900.07 1952.20 51000 -1942.44 HS 0.00 517 69.46 51612.88 2145190.29 166876.15 4000.00 68.85 28516 265.13 2944.95 2042.60 560.34 -2032.20 HIS 0.00 5.W 69.48 5161348 2145218.05 166]8]11 4100.00 6885 205.76 280120 2901.02 2133.01 590.67 -2121% HIS 0.00 532 69.46 516140] 2145245.02 16660.07 420000 68.85 285.76 2837.27 W17D9 22341 61600 -211.73 HIS 0.00 531 69.46 51614.6'7 2145273.158 166609.03 4300.00 Wm 28516 2873.W WW.17 2313.81 ( 1.33 -266148 HIS 0.00 S.W 89.46 5161537 2145W1.35 16651999 4400.00 68.85 2%.76 290942 W8914 2404.21 666.67 -2661.24 HIS 0.00 566 69.46 51615.86 2145329.11 166430.95 4500.00 68.65 285]6 294549 3125.31 2494.61 892.00 -2481.00 HIS 0.00 541 69.48 51616.46 2145356.88 166341.91 4600.00 W85 28516 2961.57 3161.39 28501 717.23 -2570.77 HIS 0.00 543 69.46 51817.06 214538464 166252.87 Cosmopolftan UnitlCosmoplitan PacKH15-P2\H15-P2\H75-P2 (Pi) Drilling Office 2.8.572.0 . Schlumberger -Private 12120/201810:57 AM Page i of Cammema MD Ua Incl (°) A71m True (°1 TVDSS (B) TVD (e) VSEL (a) NS (B) EW (N) TF (°I 0l5 curtyIonel Eaclualon Z. (°/1998) DN84uNy lnen FNH Enclunlen Zene Rn91e G1oM4p Th 07) NOMing (BUS) Eatlng (NUS) 4700.00 6885 28576 301].64 3197.46 2675.61 420 -2660,53 HS 0.00 5.45 6906 51617.65 2145412/5 166163.83 400000 6885 28596 3053.71 3233.53 2]65.62 768.0 -2]50.29 HS 0.00 547 69.46 51618.25 21454491]7 10104,79 4900.00 6885 28576 308978 326960 2856.22 793.33 -294005 HS 0.00 5.48 6946 51618.85 214546590 165895,75 5000.00 68.65 28516 3125.86 3305.60 2946.62 818.68 -2919.87 HS 0.00 5.50 69.6 51619.44 214549510 165896,71 5100.00 68.95 285.76 3161.93 3347,75 303502 843.99 -310.5] HS 0.00 5.52 51620.04 21455234] 165717.67 5200.00 68.85 285]6 3198.00 33]]82 312].42 88933 -3109.0 HS 0.0 5.53 046 69.46 5162064 2145551.23 165]1862 53W.00 68.85 285.76 3234.08 3413.90 321182 894.66 0199.09 HS 0.00 555 69.46 51621.83 2145578.9976 16562958 OM() 5400.00 68.85 285.76 3276M 3449.9] 3324.14 919.99 0288.85 HS 0.00 557 69.46 51621.93 2145616.]6 16554951 U99a-TYonek 55].61 60.65 20.76 32]850 3324.14 924.45 33"ft78.61 HS 0.00 557 046 214561265 165524.77 5500.00 68.85 285.76 33W221279 U8632 340604 3389.63 94532 0378.61 HS 0.00 559 69.46 $1622.42 51622.2 2145634,52 166451.50 001.36 68.65 285.76 334230 3522.12 3409.34 970.68 3460.37 HS 0.00 5.60 6946 5162302 210.5662.29 165362,46 13-YB'Caa 57W.00 67.65 2W.76 336000 3529.82 3507.34 9]50] 340]54 HS 0.00 560 046 51623.15 2145660.22 16534344 5700.00 68.85 285.76 3378.37 3550.19 357943 995.99 -3558.13 HS 0.00 5.81 5162361 21451]90.05 1652]342 MOM .85 285.76 3114.54 3594,28 366983 . 1021.32 364].89 HS 0.00 5.62 0.46 6946 5162421 2145717.82 16518438 5900.00 0.85 28576 3485.51 3630.33 3761.23 1048.95 3737.66 HS 0.00 5.64 6946 51624.81 2145705.50 16509534 8000.00 68.85 28516 3486.59 3666.41 3050.83 1071.99 -3927.12 HS 0.00 585 69.46 5162540 2145773.35 17513030 6100.00 68.85 28516 352286 3702.48 109532 3917.18 HS 000 5.66 69.46 5162600 2145611.11 16491526 6200.00 66 .65 28576 3558.]3 3]39.55 ." 4014121.44 1122.65 4008.94 HS 0.00 5.68 69.46 5162659 2145828.68 16482822 6300.00 68.05 28516 3594.81 377983 4121.8,1 1147.98 4096.70 HS 0.00 569 6946 51627.19 2145856.91 164]39.18 UTvonekD 631551 0.85 28576 360040 3780.22 4135.86 1/51.91 4110.62 HS 0.00 569 6946 5162727 214586895 1647253] 640000 68.85 28516 3630.00 3810.70 4212.24zlz.z4 1173.32 418646 HS 0.00 5.70 69.46 5162].]0 2145884.41 160650.13 6500.00 68.85 20516 3606.95 3946.77 4302.64 119885 4276.22 HS 0.00 5.71 6946 5162830 2145912.17 16456189 6600.00 6085 28516 3703.02 3902.84 4.04 1223.90 4365.98 HS 0.00 5.72 6946 51628.97 2145939.93 1644]2.05 6]00.00 68.85 28518 3739.10 3918.92 447340.4 124931 44;1574 HS 0.00 5.74 6946 51629.56 214596570 164393.01 6000.00 6995 20516 377517 3954.99 455,7.& 127465 454585 HS 0.00 5.75 69.46 51630.16 2145995.46 164293.97 6900.00 6885 205.76 01224 3991.6 4W.25 1299.98 ON 5.76 6946 51630.]5 2146023.23 164204.93 7000.00 69.95 205]6 380].32 402511 405.0 1325.31 4725.26 HS HS 0.00 577 69.46 51631.35 2146050.99 16411589 7100.00 68.85 285.]6 3893.39 4063.21 4945.05 1350.64 481,112 481079 HS 0.00 5.70 6946 5163194 2146178]8 164926.85 7200.00 68.85 285.]6 391946 4099.28 4935.45 1375.88 4904.55 HS 0.00 5.79 6946 5163254 2146108.52 163937.81 7300.00 68.85 28516 3955.54 413536 5025.95 1406,31 4994.31 HS OOU 5.80 6946 5163313 2146134.29 163848]] 7400.00 68.85 295.76 3991.61 4171.3 5116.25 1426.64 5074.0] HS 0.00 5.02 6946 51633.72 21461820.5 163]59.]3 750000 69.95 20516 4027.60 4207.50 5296.65 1457.98 -5173.0 HS 000 5.82 69.46 51634.32 2146189.82 16367089 7600.00 68.5 285.76 406375 4243.55 5297.06 14]].31 526359 HS 0.00 69.46 51634.91 2146215.50 16358185 7700.00 686 .65 285.76 4099.03 4279.65 5387.46 1502.84 -5353.35 HS 0.00 m 5.84 s 6946 51635.50 2146245.35 163492.60 7800.00 68.85 295.]6 413590 1315.79 507.86 152].9] -544311 HS 0.00 5.05 69.46 51636.10 2146273.11 16300356 7900.00 68.85 205.76 4151.97 435119 5568.26 1553.31 5532.87 HS 0.00 5.86 6946 51636.69 2146300.68 163314.52 8000.00 68.05 295,76 4208,05 1307.87 5657.66 1578.64 562283 HS 0.00 5.87 6946 51637.28 214632966 16312548 010000 68.85 28576 424412 4423.94 554906 1603.87 502.39 HS 0.00 5.07 69.46 51637.87 2146356.10 163136.44 820000 68.85 28576 4200.19 1160.01 5639.48 1829.30 5802.15 HS 0.00 5.09 NA6AG 51638.0] 2146391.17 1630/540 0300.00 60.05 28516 4316.27 4496.09 5929.87 ]664.64-5891.91 HS OW 5.89 W.46 69 51639.06 2146411.93 16295936 8000.00 285.76 4352.31 4532.16 601037 1679.97 5981.69 HS 0.00 5.90 6946 51639.65 2146439.70 162889.32 050900 68.95 Ras 205.76 4300.41 0560.23 611087 1705.30 5071.44 H$ 000 5.91 NA6A 5184014 2146465.46 162]0928 880000 68 .85 285.76 4424.40 4679.30 6201.07 1]30.63 5161.20 HS 0.00 5.92 W69.46 51640.04 2146495.23 16269224 8700.00 6885 28516 4460.66 4610.30 091A7 170.97 5250.96 HS 0.00 5.92 6946 51641.43 2146522.99 16260230 8000.00 69.05 20516 4496.63 487645 638187 1706,30 034012 HS 0.00 5.93 6946 51642.2 2146550]8 162513.16 8900.00 60.85 285.7 4532]0 4712.52 W]2.D 1006.63 5130.48 HS 0.00 5.94 69,46 51642.61 2146578.52 162424.11 900000 68.85 205.]66 456010 4747.60 656288 1831.96 552034 HS 0.00 5.95 6946 51643.20 2146606.29 162335.0] 910000 68.85 285.76 4604.85 4780.77 6653.08 1957.30 -6610.00 HS 0.00 5.95 69.47 5164319 2146634.0.5 162246.03 MOMWN 60.85 205.76 4640.92 482084 6]4348 1002.63 369976 HS 0.00 5.96 690 51641.30 214601.62 16215999 O00.00 93 60.05 285.76 4676.99 4856.81 6933.88 1907.96 -878952 HS O 5.97 694] 51644.98 2146699.58 161067.95 9400.00 60.05 205.76 4713.07 489289 692428 193329 087928 HS 000N 5.98 69.0 51645.57 2146717.31 161878,91 9500.0 6005 285.76 4749.74 4928.96 7014.68 1950.63-(1969V7057.W HS 0.0 5.98 6947 51646.16 2146772,46 161889.87 UTyOnekl 9598.57 29576 4785,21 4965.0 ]103.60 1983.96 -)067.0 NS 0.00 599 69,47 51646.]4 1146]]2.47 161800.83 970,00 085 60.05 205.76 09521 ]105.08 1903.96 -7058.81 HS 0.0 599 694] 5164615 2146772.87 161610.83 9700.00 60.05 205.76 4821.29 M1,111 5001.11 719549 200929 -]148.5] HS 0.00 6.00 6947 51647.34 2146800.64 16101.79 9900.00 60.05 20576 4057.36 5037.18 728589 2034.62 -023933 HS 0.0 6.00 69.0 51647.93 2146029/0 16162275 9900.00 68.85 295.76 4093.43 5103.25 737629 2059.96 -]320.09 HS 0.00 6.02 69.0 51640.52 2146856.17 161533.51 1000000 6605 205.76 4919.51 5109.33 746769 2085.29 -]41].85 HS 700 6.02 690 51649.71 2146983.93 161440.67 10100.00 6885 285.76 4965.68 5145.40 ]55].09 2110.62 -750 HS 080 602 69A7 51619]0 214691110 161355.83 10100.00 89.95 295.76 6001.65 5181.0 760.9 2135.95 -]5913]7,37 HS O.W 603 6947 51650.29 214041.16 161266,58 UTyonekJ 1020523 6885 28576 5037.72 5193!2 7737.8 2161,29 -]6029] HS 000 6.03 694] 51650.87 2146N7.23 161177,54 10300.00 60.05 205.76 503].]2 5217.54 ]737.89 218129 -]69].13 HS 0.00 6.04 6947 51650.87 214696123 1611]554 10100.00 6085 285.76 510,87 5253.62 7028.30 2196.92 -]]]6.09 HS 000 604 69.0 5102.05 214699499 161088.50 60.05 285.76 5109.87 528969 ]910.]0 2211.95 -7866.65 HS 0.0 6.05 69A] 51652.05 214]022]6 160999.46 IWW.00 10661.61 6085 285.76 5145.94 5325.79 8009.10 123129 -7956.41 HS O.W 605 690 51852.84 210050.52 160910.42 110W.W 5 28576 5182.01 5361.81 8089.0 2282,92 3046.1] HS OW 6.61 69.47 51653.23 214]0]828 160721.30 109W.W 0,80.05 28586 5218.09 09591 8199.90 2207.95 3135.83 HS 0. 6.07 680 51653.02 210130.05 160732.34 1.W 60.85 285.76 5251.16 5133.98 8200.30 231320 .225]0 HS O.W0 6.07 6947 51654.41 210133.81 160643.30 1100110W.61 60.85 28576 5261.24 W0.06NA3 03]0.]0 2330.92-(1315.46 HS 0.0 BW 69.47 51651. 210161.0 160564.26 11100.61 68.85 285.76 5326.31 55W61.13 8461.11 2363.95 -840522 HS 0.0 6.61 694] 51655.00 214]189.31 160165.12 61.61 112.85 0 285.76 5362.39 54 52.20 001.51 2309.20 -848488 HS 0.61 69.47 51656.17 21021].11 160376.18 11".11".00 80.85 285.76 530.45 557827 0641.91 2414.61 -850484 HS 061 60 661 79.0 5160,76 210244.85 160287.19 114W.W 0.85 285.76 5431.0 01/35 9732.31 2439.95 0674.0 HS 0.0) 6.10 6947 51657.34 2147279.64 160198.09 116W.W 68.85 285.76 550.60 56042 882211 2485.28 -8764.26 HS O.W 6.11 69,47 5165593 210300.10 160109.05 117W.W 0.85 28576 5506.65 08649 091311 2490.61 -8854.02 HS O.W 6.11 690 5160.52 2147n8.177W 161 11700.61 67.85 20.76 551255 5522.55 9003.51 25,1594 -8943.]0 HS OW 6.12 690 51659.10 210355.93 6197 1599308] 11800.61 0.05 285.56 5578.82 570.80 9093.92 251120 -903354 H6 0.0 6.12 6947 51659.69 2147383.70 1599593 Cosmopolitan Unit\Cosmopllfan Pad\Hl5-P2NHl5-P2\H15-P2 (Pi) Drilling Office 2.8.572.0 . Schlumberger -Private 12/20/2018 10:57 AM Page 2 of 5 LommaMs MD Incl Azlm T. NO6$ NO VSEL HS EW TF onal Exclusion Zone Exclusion Zona GaoMe9 TR N.ftFnq E IN 19 1'1 (N Ifll Ifl) IRI (ftl (7 0DLS0) culty 1 (°110081 olMoulH lmllz Alan An9N (nTl IRU91 MUng ust IeU31 11900.00 68.85 205.76 5614.09 5794.71 9184,32 2566.61 -9121M HS 0.00 6.13 6947 5160.27 2147411.46 159752.89 1200000 68.85 285.76 5650.96 5030.78 927412 2591.94 -921306 HS 000 6.13 6947 51660,86 2147439.23 15966385 121WW 60.05 285.76 5687.01 5366.86 9365.12 2617.27 -9302.83 HS 000 6.14 69.47 51661.45 2147466.99 15957481 122W.W 60.85 28516 5723.11 590293 94M5 2642.61 -9392.59 HS 000 6.14 6847 5166203 214749415 15946577 1230.0 6885 285.76 5759.18 5939.00 954512 2667.94 -9402.35 HS 0.0 6.15 6947 51662.62 214752252 159395.73 124W.N 60.85 285.76 5795.26 5975% 9636.9 2693.27 -9572.11 HS 0.00 6.15 6947 51663.20 2147550.20 159307.69 12500.0 60.05 28576 5031.33 01115 972673 2710.60 -9661.87 HS 0.00 6.16 6947 51663.79 2147578.05 159218,65 1200.0 60.85 285.76 56740 6147.22 9817.13 2743.94 -9751.63 HS OM 6.16 6947 51664.37 2147605.31 159129.61 127000 60.05 285.76 590348 6063.30 990253 2769.27 -9841$9 HS OM 6.17 fi9A7 5104.95 214763.0 15940.% 1200.0 60.05 285.76 039.55 611937 999.93 2794.60 .9931.15 HS 000 6.17 69.47 5105.54 214766t4 t0%1.52 Lower rla 12094.67 68.85 28576 5973.70 6153.52 108352 2818.58 -101613 HS 0.00 6.18 6947 510aW 214707.0 158867.23 1200.0 68.85 28576 5975.62 6155.44 10000.33 2819.93 -1090.91 HS OM 6.18 fi9A7 516%.12 2147639.11 150862.48 13000.0 6885 28576 W11.0 619151 1017073 2045.27 -10110.67 HS 0.00 6.18 69.47 510671 2147716.87 10773.44 13100,0 0.85 28516 641" 6227,59 10269.13 290.60 490043 HS O,W 6.19 69.47 51667.29 2147744.64 158634.40 132W.W MA5 285.76 6003.84 6263.66 10359.54 2895.93 -1990.19 HS 000 6.19 6947 51%7.87 2147772AO 156595.38 t33W.W 0,85 2016 6119.91 6299.73 1449.% 291.26 40319.96 HS 000 6.20 6947 51660.45 2147000.17 15806.32 L Tyonek0 1338170 0.85 285.76 8142.20 922.02 IMOa79 293692 -1435.41 HS 0.00 620 0.47 5108.81 210817,32 158451.31 13400M 68.35 285.76 6155.99 6335.81 10540.34 246.60 -1469Y2 HS 0.00 6.20 0.47 5109.4 214797.93 153417.28 135OW 0.0 2016 619.06 6371.88 1MM.74 291.93 -10559.40 HS 0.00 6.20 69.47 5160.9 2147855.69 150328.24 13600.0 68.85 20.76 6228.13 007.95 0721.14 2%126 -10649.24 HS 0.00 6.21 69.47 51670.20 214703.46 158239.20 L TyonekC 13619.59 085 285,76 623520 4f502 10738.85 302.23 -10668,82 HS 0.0 621 69.47 51870.32 214780.0 f5921.75 137W.W 6685 285.76 626421 6444.0 10011.4 3022.0 -10739.0 HS OW 621 0.47 51670.78 214%1112 1581WA6 13800.0 085 20.76 630.28 400.10 1001.4 30293 -10828.76 HS OW 622 0.47 51671.37 2147930.99 15061.12 1390000 085 285.76 6336.35 6516.17 10992.35 337126 -1018.9 HS 0.00 612 047 5167t% 214796615 1579729 14000.0 Wa5 28576 6372.42 6552.24 1109]5 3%8.59 -1103.23 HS OW 613 69.8 5167253 2147994.52 15788303 L TyonekD 140961 065 28576 075.80 WW72 1101.46 3101.03 -11016.93 HS 0.00 623 WAS 516720 214799.19 15794.45 14100.00 68.85 28576 6408.W 608.32 11173.15 3123.93 -1108.4 HS OM 6.23 8948 51673.11 21489228 157793.99 1420000 6885 285.76 6444.57 694.39 1120.55 314916 -111810 HS OW 623 6948 5167369 214WW.05 157704.95 14300.0 68.85 28576 648064 6660.46 11353.95 31740 -11271% HS O0 624 69.48 51674.27 2148077.81 157615A1 1440.0 66.85 235.76 6516.72 6896.51 11444.35 3199.92 -1130732 HS OM 6.24 6948 5194.35 214810.0 157526.87 14500.0 0.85 28516 655279 6732.61 1153475 M2516 -11457.08 HS OW 625 WAS 5167543 2148133.31 157437.83 L TyonekE 1409.57 W85 26076 80510 67M 92 1161573 32295 410149 HS 0.N 625 046 5187595 21481021 157358.9 11600,0 68.85 28516 WIN 670.0 1162116 9N,W -1154685 HS 0.0 6.25 6948 51676.01 2143161.11 15734819 14700.0 68.85 285.76 694.93 60415 1171556 3275.92 -11636.61 HS OM 825 6948 51676.59 214810.87 157259.75 1400.0 68.35 205.76 666101 64083 11805.96 330125 -11726.37 HS OW 626 6948 51677.17 2148216.4 157170.71 14900.0 68.85 205.76 6697.00 076.W 11896.36 3326.0 -11816.13 HS 0.0 6.26 69.48 5167715 2148244.40 157081.9 15MOM 6885 205.76 6733.15 01297 1198676 3351.92 -11905.89 HS OW 827 NA8 51678.32 214822.16 156992.63 SIa kofco Mkr 1508928 6685 28576 965W 044.62 1206657 337428 -119M13 HS OW a2 W46 516780 2149%W 156914.02 151N,N 6685 285.76 676923 649.05 12077.16 M7715 -11995.65 HS 0.N 6.27 69,48 51670.90 2148299.93 1000.59 SIs kof 15164.24 6865 28576 6792.40 6972.22 1213524 33052 -12053.31 HS 0.0 82 048 51679.27 214831777 15604639 Cry WOO 1510.0 68.85 205.76 679306 6972.0 12136.90 3393.99 4204.96 MAM 0.0 6.2 69.48 5167928 2143318.28 15684415 152000 69.69 286.30 68059 OWN 1219.69 34977 -1208545 34.91R 3.0 6.28 70.09 51082.9 21483288 1%814.51 S1ml WF 15207.32 609 2869 6807.69 W87,49 12174.37 34N 72 -12092.4 34.888 3.00 6.20 70.22 5192528 2148330.01 156807.96 15300.0 72.16 200.19 037.75 7017.57 1220.87 3130.06 -129567 %9R 3.60 630 71.91 52452.83 214830.42 156725.00 Sta kofE 130.81 72.18 20.20 030.0 7017.9 1220.62 3431.10 -1217640 34.31R 360 6.30 71.92 52457.27 2148i0W 10724.36 Stm kofD 15382.42 74.21 2894 081.0 74142 12"7,29 340.44 -122030 33,9R 3.00 6.32 7343 5289022 214838601 1505118 140.0 U.4 269.94 6aesm 746.14 1233.96 319.17 .1220.23 33.82R IN 633 73.76 52979.10 2148392.13 156635.40 15500.0 77.14 291.0 090.69 790.51 12449.60 3496.61 -12356.89 331R 300 6.35 75.fi3 53157.37 21442907 15651512 SfriSWA 155550 70.52 2920 002.30 708242 120299 351687 -124074 33.2R 3N 6.36 7a69 000.37 214840W 1564%43 &1 MkofC 1556625 78.87 29277 694.0 70412 125130 3521.10 -124169 33.17R 300 836 7689 0745.35 2/48/5518 15486.42 IMOK) W N.65 20.33 6910.81 709083 1246.79 3534.0 -1240.30 WMR IN 6.37 77.54 5300.87 214468.99 1561%.28 Sferl WB 1569342 82.0 24.37 025.70 71ea52 f2WOW 3571.75 -12W1.% 32,81R 360 639 79.33 $4229% 214808.93 15373.16 1570000 3.9 294.98 6926.61 71MA3 1205.01 3574.49 -1253146 MAR IN 6.39 7946 54252.9 2148511.4 156367.32 15800.00 4.69 2%.61 6938.4 7117.86 127",, W17.n -12626.69 32.61R 3.00 641 81,0 51583.42 2140557.48 156278.10 1590000 8712 296.23 6M5W 712491 12813.71 303.66 -12715.42 325R 3.00 B43 83.36 54813.20 210605.01 10191.85 1600000 89.75 2%,4 647.73 7127.55 12M365 3712.10 -1289.81 9.46R IN 645 85.32 51999.% 21405609 156105.81 EMCm 1600972 WM 300.0 84175 7127.57 12953.37 3717.03 -12811.24 HS 3.00 6A5 85.51 501409 214066117 1%097.52 9-&WcSg 1601972 WM 30.0 694775 7127.9 1M3,W 3722.0 -12819% HS 0.00 6.45 Tamat 0.51 SW14,M 21/886100 15089.0 cr W1W 1603972 WM MM 6947.75 7127.57 1293,37 3732.0 -123122 19R 0.00 6.45 85.51 5501471 214897,47 1%071.96 KOP Cry W100 16125.00 951 300.34 694586 712563 13068.62 3"4.87 -129109 LS 3.00 6.47 985 55114.95 214M2.W 1%999A4 16200.00 9104 30034 6943.53 7123.% 13143.58 381274 -1295.9 LS 2.00 6A0 0.41 5507560 2148761.91 15W35aO Cry VIM 1974.9 89.54 30.34 694315 7122.97 13218,0 3050.0 -13402 91.97R 2.00 649 497 497172 2140001.50 155072.19 163000 899 3084 694336 712118 13143.58 3363.34 -13061.86 91.97R 2.00 6.60 84.3 549%.14 21488144 155050.90 1400.00 MAS 3024 6944,25 71209 13313.52 3916.09 -13146.81 91958 200 6.51 4.19 51900.17 2140869.0 1%767.48 End Cry 1466.53 89.41 MC17 6944.92 712174 1MW.91 395281 -13202.28 HS 2.00 6M 8377 548%.31 2148908.10 15713.03 165400 89At 304.17 694526 71250 13443.30 3971.61 -13229.9 HS 0.00 6.9 83.77 54858.31 2148927.65 15568586 16600% 89.41 30417 6946.30 7126.12 135130 402777 -13312.70 HS 0.0 an 3." 48%A3 2148906.4 15%403 16700.00 89At 304.17 6947.M 712.16 1364276 40"93 93395.44 HS 0.00 6.0 83.77 4858.52 214041.43 15552350 Cry VIM 16776.08 89.41 304.17 6940.12 7127.4 1371863 4126.66 -134%.38 GGAL OM 6.54 3." 43059 214%88.85 15546174 16 WW 8973 303.53 6940.30 7128.12 13742% 4139.98 -13478.25 63.0% 3.0 6.4 426 5490182 2149102.71 155442.24 Cry WIM 16819.79 90.00 303.0 6940.35 7128.17 13762.25 4160.4 -IM4.79 1.6L 3N 6.54 4.67 54945.53 2149114.01 1554260 KOPCr VIM 1690.00 9241 39.93 6946.67 7126.49 1342.33 4194A7 4420 LS 3.N 6.% 960 55108.42 214915946 15530.93 17000.00 9041 30293 6944.21 7124.0 1342.9 4248.82 -134597 LS 2.00 6.57 0.% 5498071 2149216.9 1597154 Cosmopolitan Unit\Cosmoplitan Pad\H75-P2\H75-P2\H15-P2 (Pi) Drilling Office 2.8.572.0 Schlumberger -Private 12/20/2018 10:57 AM Page 3 of 5 Cosmopolitan Unit\Cosmoplitan PaMH15-P2\H15-P2\H15-P2 (P1) Drilling Office 2.8.572.0 SChIUmbergef-Private 12/20/2018 10:57 AM Page 4 of 5 NO M) ADm True TVOSS TVD VSEC NS EW TF OLS DlrecDanal Eacluelon Zeile Excluslon Zona GeoNa9Th NorNhg EasUng Canme Ift) 1°I f9 Ifl1 181 Ifll In) Ifll 1'1 ('110081 010cully lndrt Alert ,4718171 lw (717) (ODS) (WS) Crv21100 17049.92 89.41 302.93 6944.30 7124.12 13992.02 427596 -13687.87 73951- 2.00 658 84.12 U893 B7 2149244.34 155236.39 EMC, 17083.57 8959 30229 6944.59 712441 14025.63 4294.09 -13716.21 HE 200 6.58 84.48 54928.35 2149263.24 155208.55 17100.00 8959 302.29 6944.71 7124.53 14042.05 43M.87 -13730.10 HS 0.00 658 84.48 5492837 2149272.39 155194.91 17200.00 89.59 30229 6945.42 712524 14141.97 4356.28 -13814.64 IS 0.00 659 84.40 54928.44 2149328.08 155111.85 1730000 89.59 302.29 6946.13 7125.95 14241.89 4409.69 -13699.18 HS 0.00 660 84.48 5492852 2149303.77 155M879 17400.00 89.59 302.29 6946.84 7126,66 UU1.80 4463.11 -13983.71 IS 0.00 660 84.48 51928.60 214943947 15494574 1750000 89.59 302.29 6947.55 7127.37 144418 4516.52 -14068.25 HS 0.00 661 84.40 5492867 2149495.16 15186268 17600.00 89.59 302.29 6948.26 7120.00 14541.64 4569.93 -14152.79 HS 0.00 6.61 84.40 51928.74 2149550.05 154779.63 Crv&100 1760628 89.59 3M.29 6948.30 7120.12 14547.91 4573.28 -14158.09 9.51R 0.00 661 84.48 51928]5 2149554.35 15477442 Cry W1W 1762003 90.00 302.35 694835 7120.17 14561.65 4580.64 -1410.71 021R 3.00 661 8485 54961.98 214952.M 154763.00 KOPCry WOO 1770900 0267 30235 694628 7126.10 14650.52 4628.24 -14244.84 LS 300 6.63 87,41 55128.16 2149611.64 151689.19 17800.00 90.85 32.36 6943.48 7123.30 1041.39 4676.92 -14321.67 LS 2.00 664 8567 5502666 2149662.40 15461311 Cry 21100 17858.32 89.68 30235 694321 712303 14799.66 4708.14 -10.370.93 165.98R 2.00 6.65 84.55 5193415 2149694.95 154565.32 EndCm 17866.19 89.53 302.40 694327 7123.09 1460).52 01236 -14377.58 HB 200 6.66 84.39 51920.16 2149699.34 15455819 17900.00 89.53 302.40 694355 712337 14841.30 4)30.0 -14406.12 HS 000 665 84.39 51920.18 214971623 154530.75 18000.00 8953 30240 694437 7124.19 1494121 4784.06 -14490.55 HS 000 6.66 84.39 5492825 2149774.09 16444)81 18100.00 89.53 32.40 6945.19 7125.01 15041.12 4637,64 -14574.98 HS 000 6.66 84.39 54920.33 2149829.95 15136487 18200.00 8953 30240 694601 7125.83 15141.03 4891.22 -1465940 HE 000 6.67 84.39 M92040 2149805.01 151281.92 - 1830000 89.53 302.40 694683 7126.65 IM40.94 4944.81 -104383 HS 800 667 84.39 5492046 214994167 154198.98 18400.00 89.53 302.40 694]65 7127,47 153W.85 4998.39 -142826 HS 0.00 6.68 84.39 54920.0 2149997.53 164116.64 Crv31100 18404.83 89.53 3MA0 694769 7127.51 1534.5.67 5000.98 -14832.34 466R 800 668 U39 54920.54 21.4000.23 154112.03 Cry 31100 18420.55 90.00 32.44 6947,75 7127.57 1536130 5009.41 -14845.61 0I 300 6.68 84.2 5196035 2150009.02 154099.00 KOP Cry 2/100 18509.00 92.65 W244 694570 7125.52 15449]2 5056.80 -1492023 LS 3.00 6.89 87.38 55126.82 2150058.46 154025.69 18600.00 90.83 30244 694293 7122.75 15540.59 510563 -14996.98 LS 2.00 6.71 8563 55024.30 2150109.33 153950.29 Crv211W 16650.32 896] 30244 694268 MUM 15598.85 5136.92 -15046.20 161.17R 200 6]1 84.51 54931.73 2150141.94 153901.94 End Cry 18668.56 890 302.51 694276 7122.58 15609.09 5142.42 -15054.84 HS 2.00 6.71 64.31 54912.54 210147.60 15389345 1870000 89,47 302.51 6943.04 7122.86 1564049 515932 -15081.35 HE 0.00 6.72 84.31 54912.56 2150165.29 153867,41 10000.00 89.47 30251 694396 7123.78 1574039 21306 -15165.68 HE 0.00 6.72 84.31 6491263 215221.30 153704.58 18900.00 89.47 302.51 6944.88 7124.70 15840.29 266.80 -1525000 HS 000 6.73 8431 64912.69 21502)7.32 153701]5 1900000 89.0 302.51 6945.80 7125.2 15940.19 5320.55 -1533433 HE 800 673 84.31 54912.76 2150333.34 153610.91 19100.00 89.47 302.51 6946.72 7126.64 1604009 W7429 -1511865 HS 0.00 874 84.31 54912.82 2150389.36 153O600 19200.00 89.47 302.51 6947.64 7127.46 1613999 512804 -1550298 HE 0.00 6.74 84.31 6491288 2150445.38 153453.24 Cry 31100 1922.06 8947 32.51 694767 7127.49 1614284 6429.57 -1550539 1191- 0.00 674 84.31 64912.88 2150446.98 15346087 Cry 3110 19220.00 90.00 30240 6947.75 7127.57 16160.77 5439.20 4520.53 0.11R 300 674 84.85 54961.72 2150157,02 153436.00 KOP C. 2/100 19309.00 9265 302.41 6945.71 7125.53 1248.86 U8645 -15594.97 LS 3.00 6.76 87,38 55120.34 21W506.27 153362.87 19400.00 9083 MA1 6942.96 71n.78 1633974 5535.19 -15671.76 LS 300 6.77 85.63 5W1730 2150557.08 153207.43 Cry 211W 19458.32 89.66 302.41 694271 7122.53 I63%.W 558644 -1572100 168.73R 2.00 6.77 84.51 54926.24 2150509.06 153239.06 End Cm 19467.64 8948 302.44 694278 7122.W 16407.31 5571.44 -15728.86 HS 2W 670 8433 54907.86 2150594.87 15231.33 1WO.W 89.48 302.44 694308 7122." 1643964 558880 -1575fi.17 HS OW 6]0 84.33 64907.88 215061297 153204.51 196O.W 89.48 302.44 6943.99 7123.81 16539.55 5642.44 -15840.56 HE OW 678 84.33 54907.94 2150668.89 153121.60 197W.W 89.48 302.44 6944.90 7124.72 1609.45 569608 -1692495 HE 0.00 879 04.2 5492.99 2150724.50 153030]0 19800.64 8948 3WA4 6945.2 7125.64 16739.36 5749.72 -1600934 H3 O.W 6.79 8433 54908.05 2150780.72 15295500 19 W.W 8948 302.44 694613 7126.55 16839.26 5803.36 -16093.73 HS 0.00 664 84.2 54648.11 2150836.64 152072.90 ZOOOO.W 89.48 30244 6947.64 712746 16939.17 5857.01 -16178.12 HS O.W 664 8433 64908.16 2150892.56 15270999 Cry&100 20643.05 89A0 302.44 6947.67 7127.49 1694222 058-64 -16180.70 1.251- 0.00 6.64 84.33 64908,16 2150894.26 152707.47 Cry WOO 2W20.W 64.00 302.43 6947.75 7127.57 169065 W68.00 -16195.42 0.05E 3.W 6.64 8484 64964.12 2150904.02 15277300 - KOP Crv211W 2MW.W 92.66 3MA3 6945.70 7125.2 1704804 6915.44 -16270.10 LS 3.W 62 87.39 55127.64 2150953.47 152699.64 20200.64 90.84 302.43 6942.93 712275 17138.91 596421 -16346.87 1-S 2.W 883 85.65 552539 2151W4.2 152624.22 Cry 21100 2020.32 09.67 30243 6942.67 712249 17197.18 5995.49 -16396.09 176438 2W 6.83 8453 54933.06 2151036.92 152575.86 End Cry 20264.30 89.47 32.44 6W.75 7122.57 17207.14 WW.84 -16404.61 HS 2 D 6.83 8433 54914.87 215104249 152567.59 20300.00 047 302.44 6943.04 7122.0 17238.82 W17.84 -16431.27 HS O.W 6.84 84.33 54914.89 215106022 IU541.31 20400.64 64.47 32.44 8943.97 7123.79 17338.72 0771.48 -16515.86 HS O.W 6.84 84.33 56914.94 2151116.14 164458.41 2050D.W 89.0 302.44 6944.89 7124.71 17438.63 6125.12 -16600.05 HS 864 6.84 84.33 54914.99 215117205 152375.W 20WO.W 89.47 30244 6945.2 7125.64 175380 6178.76 -16681.44 HS 864 6.85 8433 5491504 2151227.97 1522M.W 20700.64 89.47 302.44 8966.74 7126M 17638.44 622.40 -16768.84 HS O.W 6.85 84.33 54915.09 215128388 12209.69 CryM00 2079722 89.0 302.44 6947.64 7127.46 17735.57 284.55 -16650.08 N68 O.W 6.86 84.33 54915.13 215133825 12129.09 20800.W 0.53 302.39 6947,67 7127.49 177M 34 628604 -16853.23 39.68L 3W 6.86 MA1 6422.36 2151339.80 152126.79 Cry W100 2020.19 90.00 3M.W 694775 7127.57 17758.52 6296.80 -16870.2 1.51R 3.64 608 84.97 54971.95 2151351.02 152110.00 KOP Cry 211W 209M.W 92.66 3M.07 694569 7125.51 17847.24 6343.89 -16945.57 LS 3.W 687 87.50 55132.31 215140.14 15203605 21000.00 90.84 302.07 6962.90 7122.72 17938.13 6392.18 -17022.65 LS 2.W 6.80 8576 5503343 2151450.51 151964.32 Cry&100 210.58.2 89.66 302.07 694264 7122.46 1799641 603.14 .17072.07 110.631R 2W 6.89 8464 54943.19 2151482.81 151911.76 End Cry 21088.27 89.0 302.63 694286 712268 18026.34 6439.17 -17097.37 HS 2W 6.89 84.28 56909.71 21514992 151886.90 21100.W 89.47 3M.W 694297 712279 10050.06 6445.49 -17107,25 H3 BW 689 84.28 64M.72 2151506.11 151877.20 21200.64 89.47 3263 6943.90 712312 18137.95 6499.41 -17191.46 HS O.W 6.90 84.28 54909]6 215156230 151794.40 213W.W 89.47 30263 6944.84 712466 18237.84 6553.33 -17275.67 HS 864 6.90 8428 %99.81 215161849 151711.76 214W.W 89.47 302.63 6915.)7 712559 18337.73 6W7,25 -1730.80 HS 864 691 8418 54909.85 2151674.68 151629.05 21500.00 89.47 32.2 6946]0 7126.52 18437,62 601.17 -17444.10 HS am 6.91 84.28 54909.09 215173087 151546.33 21664.00 0947 302.63 6947.63 712745 18537.51 671509 -17528.31 HS 864 6.91 8428 5496493 2151787.64 151463.61 Cosmopolitan Unit\Cosmoplitan PaMH15-P2\H15-P2\H15-P2 (P1) Drilling Office 2.8.572.0 SChIUmbergef-Private 12/20/2018 10:57 AM Page 4 of 5 Survey Eno, Model: ISCWSA Rev 0 --- 3D 95.000% Confidence 2.7955 sigma Survey Prag,am: 0.000 ND Incl Arlm True NpSS TVD VSEL NS EW TF OLS Dimclional Excluelon Zona Excluelon Zona GBOMag TI NortM1ing Ei48ag Comments In) 1°I 1°I Ifll in) (ft) Iftl Ifll 1°) 1°no9fl1 DiMwM md.z Alen Aad sry (0) Iftus) Inu51 Cat 3.1/100 21604.03 09.47 302.63 6947.67 T127.49 18547.53 6717,26 -17531.70 3291- ow 6.91 8428 54909.93 215478932 151460.28 Cm 31/100 21621.29 90100 302.60 6947.75 7127.57 18558.77 6726.56 47546.24 1.111. 3.10 6.92 8480 54957,70 2151799.02 151446.00 20109.000 21700.00 92.44 302.55 694607 712589 18637.38 6768.93 -17612.55 1.11L 3.10 6.93 87.16 56116.71 215184318 151380.87 0.600 21800.00 9554 30209 6939.12 7118.94 18737,03 6822.56 -17696.65 1.111 3.10 6.94 89.85 5518430 2151899.OT 151298.25 21900.00 98.64 302.43 6926.78 7106.60 10836.16 687582 -17790.37 1.12L 3.10 6.95 86.86 5510127 2151954.59 151218.01 2200000 101,74 302.37 6909.09 7080.91 18934.49 6928.55 -17863.46 1.13L 3.10 697 83.86 54867.90 2152009.56 15113138 End Cry 22036.20 10286 302.35 6901.38 7001.20 18969.83 690.48 -17893.34 IS 3.10 6.97 82]8 5474651 2152029.30 151105.03 2210000 102.86 302.35 6887.18 706200 19031.97 6980.76 -17945.80 HS 000 697 82]0 54746.30 2152063.99 151053.40 TD 22120.27 • 102.86 302.35 6082.67 7062.49 . 1905172 699134 -17962.50 000 898 82.78 54746.23 215260502 15103100' Survey Eno, Model: ISCWSA Rev 0 --- 3D 95.000% Confidence 2.7955 sigma Survey Prag,am: 0.000 5620.000 1/100.000 16.000 13.375 SLB_MWD+GMAG 1104-1-01/1104101(1`3) MO." 7120.000 1/100.000 12.250 9.625 SLB MWD+SAG 1104L01/R04 01(P3) 5620.000 16015.000 1/100.000 12.250 9625 SLB-MWD+GMAC HW101I H0 01(P3) 16015.000 16125060 1/100.000 8.500 0.000 SLB_MWD+SAG 114 01 I 1104101 (P3) 16015.000 16125.000 11100000 8500 0.000 SLB MWO+GMAG HO 01 11404-101 (Pal 16125.000 16900.060 11100000 8500 0.000 SLB MMD+GMAG 140Y1.02/1104-1-02(1`2) 16900.060 17709.000 111W.000 8.500 0.000 SLB 6KVD+GMAG H0 1-0311104-L03(P2) 17709.000 18509.000 1/100.000 8.500 01000 SLB_MWD+GMAG H(WL04I H04-LN(P2) 10509000 19309000 1/100.000 8.500 0.000 SLB_MWD+GMAG 1104-1-05/1104105(1`2) 19309000 20109.000 1/100060 8.500 0000 SLB_MWD+GMAG 1104106/110K06(P2) 20109.600 20909000 1/100.000 8.500 0000 SLB MWD+GMAG 1-04107/ 11047.07(1`2) 20909.000 22120.272 1/100.000 0.600 5,500 SW MWD+GMAG H04I H04(P2) Cosmopolitan UnitlCosmoplitan Pad\H15-P2\H15-P2\H15-P2 (P1) Drilling Office 2.8.572.0 .Schlumberger -Private 12/20/201810:57 AM Page 5 of Vertical Section Plane (0.00 ft N, 0.00 ft Q 0 300.00° Vertical Section (ft) 16000 16500 17000 17500 19000 16500 19000 19500 5500 ----- ------ --------------- -- ----- -- ----- - - - --- - --- ------ 6000 . __._._._._._._._._._.._._._.__._.__._._._._.r._._._._._._._._._._._.__._._._._._._._._._._._.._._._.------- .__._._._._._.__._._._._.-------- ._._._._._.__._. i 6500 ------_-- ------ --------------------- ._--- L------- ................ ';............. ....... ._._._._.-................. ._._._._._._._._._._._._.._._._._._._._....... _.!._._._._.____. 7�G---------- '----- --- ------._----'--'-- -------v-------'--- '+---------------------------------- OYW .T.------------ -------------------------- ------------- .........- ----------- ............._._._._._._._._._._._.__._._._._._._._. Schlumberger -Private VHnedl XQld d%dde @Aokk. o.ddRfl•doo.oa• Vertical Sedron (k) WEST (R) FAST XMYTbog<fAtivdte H04 (132) Anti -Collision Summary Report MMyals Data-24Hr Time: December 19. M18-14:34 Analysts Me186M: 3D Least Dywee 011enc BloeCrest RaHreece Trajectory: H04(Pi (Def Plan) Field: cosmopolitan One Ni lwarmil: EN, 10.0 Measured Dean, (0) Structure: Gumopolitas No Rule SN: OW AneWHI Slanted 8002 x5.115.2 Slid: 1406(3) Min Pb: All tory minima lndkaled. Wall: H04(ten, 1) Vernon l Petal 2.10.516.0 Borellola: Ip4 games. I Pro)M: IwylmeMrlllilgC00k Inst Scan MO Range: 20909.008 -22=271 Tralsotow Error Modal: ISCiti" 95.000% Con9cence 2.7955 sigma. W si"I For ORsat Trajection. summary OIMM Selectbn cmeda We0neae OUMrce scan: Reablded MNin53130,n8 Seleclian (Alen: VeMbas Sulve,- DOfinswe Mom- Definirao wrois mases defimlrva plena -All Non -OM Surveys when no UelSweey is sM in a boodatle - MI NOi Plans Man no Def -Plan Is cel in a ber some O jvt Trajectory SeerNlon Allow Bap controlling Ref..i FIJIL.1Alert Slrtua FcMAS h EOU R t4a h D. h w Fact Rule MD(ft) TVD h ANrt mi. Miller I Major Maar 140x07 gi(Deftem) - - FeII Myer. 0.00 30282 30229 -30202 4101 OSF 50 2090900 7125.51 OSF.500 OSFa1.50 OSF,TW Enter Major 000 16201 108.63 -1.0,1 e.11 OSF1.50 2091000 712546 MInR98F 96.60 14621 40 m d]]5 100 OSF150 21"0.00 7125.96 OSF11,W Ext Major 137.75 140.0 43.97 -2.30 'A0 Oili 21580.60 ]12].08 OSF>1.W E. Miner 30828 13150 216.]1 171.29 339 OSF1EO 22120.37 7062.49 TO H04106 (n) (Def Men) 7 - Wem0g Abd 13962 10T. 6x 236 OSF1 S0 2090000 ]12551 OSF-600 EExit Ake 436_WJ.% 436.55 13296 3255 333 fid 696 OSF150 2169000 712633 OSf>500 Exit Alan 825.05 91.]8 763.61 73339 11fi5 Cirri To 2212027 ]082.49 TO Haran MA (Def Sunay) WwnYp AWt 1339.00 ]8001 91200 548.99 2.54 OSF1.50 2090900 7125.51 Osi Enkr. Alai 1330S5 ]88.70 804.62 511. 2.53 OSF1,50 2100.00 7122.71 Mln%bSF 1329.52 787.92 803.91 54100 253 011i 21020.0 7122.0 MIrR-.AOF 132912 7 747 803.81 541.05 2.53 Oili 21000 7122." MINPTUEOU 1328.14 783.84 805.25 Wad 2.54 091 21090.0 7122.70 Efiria 1 16]8.52 58232 1299.0 111120 4M OSF1.0 22120.27 70911 Tp H04105(P2)(Oef Plan)"""-' Pap 533.>6 12960 648.00 603.3fi 632 Cirri xx ti m900 712551 MinPu 14092 9515 162708 139577 23.]9 OSF150 22t. 27 ]092.49 TO 1104iO4(1`2)(Dal Man) Pays 1088.88 87 20 1030.33 1301,86 18.88 OSF1.50 20om 00 112551 Min%e 2212.32 99.19 214578 2113.12 33.95 OBF150 2212037 736249 TO HO4L03da)(Def Pim) Pau 18388 9206 17]1.35 1760.81 3003 OSF150 20909.00 712551 Miens 300007 10266 293134 2897.44 44.35 OSF150 2212027 7062 49 TO H04{p2 (p2)(Oel Plen) pass 2889.0 98.98 2602fifi 257008 6093 OSF150 2009.00 712551 MinRe 3853.61 10543 378292 374818 5565 OSE150 22120.27 7062A9 TO Hansen afA1.1(0N Survey) Pap 29111 ]53.81 248441 22'43 5. O6F1.50 2100.00 7127A5 MinF1U8F 2885.19 ]52.05 249293 223233 SAS 0511.0 21750.00 7123.08 MInR4AOP 2984.97 ]51. &9W To 2232.36 5m OBF1.50 21710.0 7120]8 MINPT�0.EOU 29829] 75329 24W.45 2229.0 59 OSF1.0 7.43000 T0257 Mi 298278 754.51 229" 2229.28 5& 0150 22120.27 7062.49 MinPle H16IDerSarm) Pap 311260 289.20 291953 292348 18.19 OSF1.m 20090 712551 Mini 311377 29384 Ni 282013 1595 01 21040.0 7122A1 MinPoCICi 311116 Nate 290005 28o6.m 1539 OSF1.50 2160.30 712005 MinFlLlt1 311123 304.41 10198 2800.02 1519 MI'l Ed 2168.0 7126.33 MINPT 6EOU Uhlumeami-Pi Rh1um8e10ervPMme 311137 W4,M 290]. 2006.] 15.3] OBF150 21500.00 ]12852 MIhPt A P 311594 30660 2809.9 MPH 15.19 CS SO 217W,W ]12509 Mln%-PROP 313 . 323. 2911.11 2006.4] IL54 0SF1.W 22110. 7N4.78 MINPTOEOU 312056 324.80 n14,121 MMMI U OSF1A 221.2] 7062.49 Min%a Heneen#1(DOf S.ry ,) PBN 3203]0 59224 280055 2fi11 d6 B.1S OSF1.W .909.00 7125.61 Min%S 403301 4.W 3]27]5 357531 1]22 MF1.W 2212027 706249 TO N18A (DB! SYrveY) Pa. 3229. 89786 30]090 2.177 1631 OSF150 22010.00 ]00685 MIn%-0101 323015 290.42 293175 16.29 OSF150 220MOD ]067W MINPT-0.EOV 3230.15 296.40 MW 091 39AN 2931]5 16. 05F150 2212.00 Mm%Pt ADI 383026 29952 303094 2931]6 1670 OSFI50 2.262] 7W249 ].2879 SF Min%0.3F N16MLW (Oef Suety) Po. 323225 294.60 302552 2.164 1851 OSF1.50 217W.00 ]125.A MmPLCICt 323325 A9 M 3V3551 293764 1651 OSF1.50 21710.00 7125.. MIn%c 3232.59 291.89 325.60 2987. 16. OSFI50 21]]000 712159 MinNI SF 3239. 295.97 342.02 294369 16 C] OSF1.W 22.0.00 ]075. MinPt-PSF 3241. 296.15 344.14 294575 1647 OSFIA 2212027 ].849 TO H16A{OS (Oef Survey P. 3230]1 201,14 34].19 2951.93 1fi.BB OSF1.A 222.00 ]12551 Min%5 324011 2.15 189 OSF150 210.00 ]122.]2 MnMt 33. 2236 A.23 30'87.. A.44 1614 OSF1.50 2120000 7124.47 SF Min%OSF 1 ]]15.55 2]00] 310]4 W97.68 3W].fi8 10.12 OSF159 22120.27 >062.49 TO H18LL06(Dat Survey) P. 288- 3054.W 2859.02 1615 OSF1W 21010W 7122.59 MinPI tCI a23474] TL07.15 2W.15 AMA 2857.00 1804 OSFIM 21250.10 7124.19 MnPlLt01 V47.27 280.4 3532 2058]] 16.02 03'1.50 21310870 ]124.]5 MINPT-0 OU M47.42RW.W 35331 74 2858] 1801 (A 21380872 ]125M MmPt-C,. W4G.D2 N1.31 353. 2858.]1 16.]8 0SF1.W 2142D.W ]125.]] MIn%-0�ADP 3224.40 215.1] 34682 28182] 18.40 OSF1.A 21TN.W ]12159 MIn%-03F 32..00 2M.91 346870 29!808 1619 OSF1.W 210W.W ]1184 MInR4 3243.92M.81 340.30 284811 16.W OSF1.W 2101O.W 71 TO MINPFbEOU 324324 295.82 346. 292422 1651 OSFI.W 21830.2 ]116.. MhPtL I 3255.. 8184 36..16 .0320 1670 OSF1.W nlM27 702.49 TO H16P01(Oef Survay) PoW 33]186 35989 321]4 29121] 8780 OSF1A 2029.00 ]125.51 mmFta 300040 36.13 3595.99 2442] 1856 OSFI50 2212027 70W 49 TO H16A14 (Oe( Survey) PBW 32]72 3182 364.03 295904 1545 OSF150 2090900 ]12551 MIn%s 363752 28081 N`A.tt 358.89 19.51 OSF150 221202] ]05249 TO HIM-LO(Def Survey) Peas 34849] 28872 32]21] 31]625 1006 OSF1W ADAM 7125.51 Min%s 44042 2422] 3]859 3]96.15 25.11 OSFt W 12212(1.2] ]082.49 TO H412 (P3)Mal Man) - Pett ]590.02 1.92 3828.13 3491.2 52.55 OSF1.W ANN 712551 Min%e 479345 100.01 47W,N 445.37 87.20 OSF1W 2212027 72349 TO 416A102(O Survey) 301589 247 92 345.29 3302.9] 2339 OSF1.3 2028W 712551 MmFts 461112 20525 .7396 440607 AM 05 A 2212027 7062.49 TD H12 (Del SYrvOy) Pa. 1044.02 29140 364943 3753. 264 03F150 .29D0 7125.51 MIn%-0101 4044.07 29148 304942 3]524 204 OSF1.W 209300 712461 MINPT-0EOU 402410 291.52 34943 3752.58 2087 OSF1.4 1240.2 712423 Min%.PADP 4048.10 .42 3851.0 374.81 A'" 0SF1.4 2134.2 7125.12 MINPTPEOV 4010.23 299.3! 3M1. 37W Mn 03F1.W 213W.2 712521 MInR-0 DP 4495] .4.2 M5291 3]550 .. OSF1.50 21470.. 712024 Min%OSF 4054.61 297.8 .554 3756.4 2047 0SF1.W 217W.2 71232 MINPT-0.EOU 40.W 29824 .556]3756. ROA' 08F150 21790.00 ]119.80 Mnm-0 DP 405521 3021 3854]4 37552 2032 OS . 1219..00 ]D%S3 Min% -0101 405544 M1. .403 ]752.0 20. OSFI.. 22120.27 722.49 MIn%a H12 06 (OOf Survey) Pale Rh1um8e10ervPMme scnwmee.9e.-Pmae bM 03 291W 3419.43 3]58.83 209 CGF1.W 10900.00 712551 Mln%LMt 4314.0] M."3848.42 3]SR59 20.M OOF1.50 2081003 1124A1 MINPTOEOU 409.10 29152 A3 3]58.59 20.0] O IM 2094000 7124.M Mln%.O'ADP IM].M 293 3&51) 3]:N.2 Mn CWIM 2127000 ]124.38 MlnP 405192 2852 3&54. 3]58.10 20.81 OSF1A0 2153000 )126.00 MlnPO 435)22 2819 3058, 3]59. 20.52 OSFIM 21780.60 )122.3] Min%-0.AOP 3.23 385].)5 37W.W Mm O IM 21M,W 7096.0.3 Min%CtCI 005827 3W 3851. 3]5].81 20.33 OSF1.50 219WW ]090.82 MINPTbEOU 4W3.33 300.]3 385].1 3]5]. 2032 OSF1. 2201000 7MM Mln%-0.AOP 405945 3006) 3850.80 3)58.]8 20.31 OSFfW 22120.27 7W249 MinPI-O-SF H12 L06(Oaf Survry) Few 405119 187 4 380230 J7W. 21. OSF1.50 20963.00 112551 Min%e 40]40) 288. 390.49 3]84.1 2115 OSFIM 211W.W Tlm,m MlnP 43]3. 290.]0 3075.42 377fi 02 20.M OGF1.W 215b.0 7126M MinmL1Ct 407; 59 339.11 3815.& 3733.45 18.11 OBF1.W 81810.00 ]11].95 Min%85F 40]169 M. 3915.50 3]3320 1818 OBF1.W R18W 00 7112.18 MnRt p b71W 337.. w5W 3]3321 1612 OSF150 215]0.00 ]110.48 MINPTOEOU 10]1.02 W7,72 3865.55 37wm 18.13 OSFfW 218.00 )1080) MhR1 t 40)6.47 33 97 385216 3740.. 18.25 MF150 2212027 1.243 TO X11{04 (CelBurvryl Pass 4066.08 28B.W 391240 31)6.1 21.11 OSF150 MM9.W )12551 MinFa IWfOR RW.gi %]).16 3)8072 21.10 MOIm 21043.. ]122.41 Min%G3F 41..36 331. 3880.12 3))).98 18.85 0SF1.W 21M.W ]12].15 Min%a 418415 323. 3981. 30..27 1913 OSF1 W 22120.27 7.2.49 TO X12103 IONS~ Poss 411464 .945 39..01 JW510 2006 OSF1.50 20.9.. 712551 Min% -M 4116. 326.1 39-.19 3791.18 16. OSF1.M 20843.. 712423 MIND O. EOU 4110.11 327.41 3.0.51 381.0 1692 OBF1.W 2WW.m 71.!.48 On%s 4m JW.25 41W.13 4.9.34 21.73 03F1.W 221..27 ]m2A9 TO H12-L02(WSumy) - - Paw 42IB dd 303]8 4046fif 1915. 2105 OSF150 20W9.00 7125.51 Min%a 472632 270.73 454550 4455.59 2828 OSF150 22120.27 706243 TO H16A1011Defsurvayl Pm 441522 20901 4P556 420622 31.W OSFtM 2090900 712551 Min%5 5300.92 173.94 5192. 5134.. 4603 OSF1. 2212027 706249 TO Su"Y) pssy .25M 211,)9 443329 44133 33.04 OSFt. 21050,. 7122.42 Min%QSF 461698 211.. 447535 4405.. 3303 OSFIW 211M.W 7123.. Mln%OSF 40..47 210.. .BBW 43..92 1111 OSF1.W 21410.W ]125.89 Mln%.0.ADP 40095) 210.61 .88.49 ]3178.92 JJ.12 OSFI.W R1120.W 7125.] MIND O. EOU OBWR 210.5] .BB.W 43%A6 33.12 OSF1.% 214MM 7125.87 Min%-C1Ct 466115 205.91 45.3.34 44.34 .26 03F1.. 2212027 7062.49 TO H12{01(NI 5u.y) Pew 46224 289.62 ...BI 435243 $$m OSF156 26909.00 7125.51 Mln%s 5434.42 23409 5140.03 501033 34.13 OSF150 2212027 706249 TO H14PB1(Oaf Su -y) Pep 467914 M. .92, 44002 2525 OSF1.W 2909W 712551 Mln%a 46%.01 2..W .9689 .0052 24.33 OSFIW 21810W 7110m MIn%.CtCI 4.124 292.65 .95 E9 439039 24.11 03Fl. 2$12027 7.249 Mina H14PB3(De15urvey) Peas 47&.% 271] 4599.51 450.2 25.. OSFi- WWB.W )12551 Minft 47M 71 2W. 4601 J] 4.6.1 W.88 OSF1.W X .W 71Y1.W MOM 0.792. 2ml. 4W2W 4.].33 2529 OSF1.W 214b.W 71n.M MIn%'Otp ]91 2M.. 4588.9 4W3.00 W.03 OSFI.`W 21710.W 1143.. 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WRP 25925 MAI 28385 M.H 239.83 MMS =10.93(68) MOO 220.93 MlnPU 25930 3281 283.83 228.49 31].83 MMS =10.93(68) 240.00 240.93 MINP]QEW 266.51 3201 2 283.1 5).8] IMS W(-) 900,93 93).& MlnF 20fi.5d 32.01 293. 293.)3 5)2] IMS 10.0 920.00 937.W MINMT W 3M D5 3281 314.72 .2.25 35.5 WS=1093(68) 1063]5 MnR F 7.85 O1.P M.31 MAD 184 OSFIM 4 w 432040 347.75 Mln%A$F 032$ am )8].93 783.0J01 O5F1.W 4681).00 31W24 MlnlF $F 802.51 6951 816.01 M.30 OSF1.W 4810.00 324190 MlnP F 135675 1..68 1274.61 1R34D0 WFt,M 2120.00 4 OA2 Mln F 1475.91 102.3) 14%,31 13)3.51 OSF1.W )20.00 4268.8 MlnP F 1535.15 100.39 1464.] 1428.68 WFM S20.W 4393.08 Min!N 3F 15]18) 19323 1583.50 1930.45 05F1.W 821093 448382 MlnP F 2681,29 246.]8 238.94 293581 0SF1.W 18310.93 S10.M MlnP F 3037.69 262.]) 2868.85 2]84.92 WF1.W 1582000 7119M MlnP F 309485 255.20 2924.49 2839.26 WF1.W 16600.93 ]000.)O MM%ASF 3104.10 M. 2968 2W,01 1.0 OSFIM 10990.5 6919.93 M(N") OU 3104.12 2931,18 MD, 2.3.A11.1 O5F1.W 18910.93 6894.41 Mlnl63103.65 260.81 2932A5 284564 O3F1,50 Immoo 6860.83 MM%-0SF 3106.30 2M.94 M4' 20413] OSF1.W 1)1205 6641m Min%ASF 312225 3&30 294553 285] OSF1.W 1]41401 6]12 5] Mln%-0SF X16A.M( NSA,n,) P. 20o.08 3281 258.5 22127 WA MAD =10.0Im) Om O.S 3-tays MOD 3281 26868 22127 13923014 IMS =1000(.) 3465 3466 WRP 25925 32.1 RM.BS 226. 2..83 MMS=10.93(68) 220.93 220,83 Min%p 2.. mz 283.93 228.08 27.m 8345.10.93 (m) 240.0 240.00 MINP)UFOU 268.51 32.1 2 283.)1 5).8] IMS=10.00(.) DOOM m).& Min%s 286 32.1 293. Y53.]3 5).2] MM5. 10,93(68) 9]0.93 68].60 MINP bE00 325.5 32.81 3148 222 35. MA5. 10 DO(m) 183.ao 14T3.]5 MinPbaSF 1485 81.n 73.35 M.1 1 OSFi W 4M.00 MS.m WR trSF 832.68 0.81 ]81.% M.0 10 OSF1.W 483.00 3193b Mlnl40 F W2,51 0.16 818.4 )m, 18. OSF1.W 4840.93 3R4).M MM%-0SF 13M.]5 122.81 124.60 1231.14 16.]3 OSF150 ]120.00 QMA2 MMPIASF 1439.M 68.)3 132,14 1339. 721. OSFIM 7M.00 .18.0 Min%ASF 1475.91 102.2) 140138 137 21. OBF1,M 220,00 426086 Mln!N SF 1568.68 10.28 1M4.14 1429D 2, 04F1.m S20BD 4368.8 mhm% F 15]3.4 102.11 1500M low 21. OSF150 510,00 .6302 MM%-0SF 282.83 2M.89 2712N 2632 I8. 05F1.W 1485.93 6802.47 Mln%ASF 311305 259.80 2938. 2083. I8. OSF1.W 15820D0 71190 Syyp 3168.T 258.97 2 2688 16832 OSFt50 Imm ]105.]5 MInl0.A 318.81 293.19 2989D2 291283 t8. 0SF1.W IWOGM ]S].W MM% F 3185.71 281A3 6810.0 2924 18. WFIM 185mm MT. MIIp1pgF M9.83 25.05 3031 242. 18.M WFIM 16980.5 6912.42 Mn%a 3218.68 20.5 ]03623 29838.3 1189 OSFI M 1710.5 600237 Mln%-0.AOP 3219.N 273403036.]4 294591 112 0SF1.W 1)3..5 6745.15 mll P) W 321983 2]3]0 303616 2945. 1)]0 O8F1W M7000 6]31,94 Mln%A-MP 31RO.09 2]4.15 3037 93 MID 1].. OSF1.W 1741401 6812.52 MWF HISA(WSrveY) 3281 2885 22.22 WP MRD-10OD 0,5 OS Suftm MOD 3281 283.68 221.28 139230.]4 MAD =10.Oo(m) &.OD WRPRS.m 2M35 3281 20. 22883 239.M MMD. 10.5(m) 283.00 OD in% MiEw 293.30 32.01 283. 226.9 21).00 DAD =10.5 (m) 240,5 =MODAo 2830.00 MINP]-0EW YM1lumbeq-PrWn, kMUN a ,Nn z88.51 VAI 283.38 MIT 5]A] MA8=10=(m) 9X80 95]84 MMpM MN M.81L-.a 253.]3 57.P MPS=10.0 (m) 970.0 WIN MINff-0 )U 325.05 32A1 314.n M2 n MP8=18X(m) Imm 14]3]5 min I p ]8185 61.]1 723.35 703.1 18. OSFIN 4320N 30X.30 A.mI F 03388 8881 ]0]W MN 10.90 O5F1,50 40 M 310.24 MMP F 88251 0,16 B18A5 M. 18. OSF1,X 4NO.N 3NI.98 Myq F 1358.5 12281 1274.0 12.".14 16.23 OSF1,X 7620.N MM.42 MnR-0 F 143960 98.73 1322.74 13%.05 218 OSF1,X 2530.00 4218.32 mliil 9F IMAM 102.V 1407.38 137365 21 OSF1,X 77=N 42N." MIn!1 SF 153515 5820 1484.14 142987 218 WFIN NNN 4 .011 MlnP F 1573.82 108.11 15".50 14NN 218 MF1,X MON "X82 Minl WSF 2872.52 3M.N 2]1224 M2N 180 WFIN 1480." 0082A7 MI R-PSF 3113.0 M. -039.9 2863. Is. WFIN IMON 7118.0 MnpM 31M.]] 20.98 2%5 29".81 1Od2 MFIM 10330.3 7105.25 MnR-0.AOP 31MAI 2X.18 2999" 291262 IB30 OSF1,X 183MN ]MIN MInR1 SF 315.)1 261M 301098 29210 18.33 OSF1N 165X,N MS].M MInPl4sF 32"69 28], 30312 294254 180 OSF1,X INN.N 7312-02 Min% 321895 27059 30M 23 2N63fi 17.73 OSF1.X 1721ON M2.32 MMp4App 321934 27340 30M.I5 29]594 11.72 NF1W 1540." 6245.15 MINP2OEOU 3219.5 2]3]0 XM39 21N5. 1].]0 OSF160 173M.N 8231.& Mnp1pPDp 3220" 274.14 3070 29459 O. OSF150 1]414.01 6712M MinR-0 F urvreY _ _.. ��.. _ ._. �._____�.._.__-_ _-._.. Pan 2".00 3281 2. ll 22]2] NM MAS =1TIM (m) 0m 0m Suda- 2X.OB 25.25 3281 2.36 22727 13923674 3281 25895 226.44 23983 MAS =16N(m) MAS =1000(m) M65 2200 34.65 22000 WRP Minft MM 208.51 3RA1 32,81 258.5 280 236.49 253.]1 217N 528] MAS = ION (ml MAS - ION(m) MN MO.N 24ON 952,& MINK#W Min% 2N. 3281 2N.N 25373 57.22 MA8=10.0 (m) MN .2.0 MINP]4EW 32505 32.81 314.]2 293. 1 1355 SHS -10.11 ) 160,0 145.]5 Ml.P F T04.M 81.72 ]23.35 M31 10 OSF1.X 4320." 3MM Min! 5 F 032.5 5.81 78]-08 ]73.0I O6F1.X 4WN 31N24 MmRP F 882.51 0.16 816-04 ]93 OSF1.X 4024." 3&]89 MinNg F 1350]5 I=A, 12]05 1234.14 OSF1.X TIMN AlmA2 MlnR-0.SF 14%,M ".23 1372.74 13396 O3F1.0 M)N 421032 MInPIgSF 1475.91 102.2] 140]38 13]3.6 OSFlm 7773." 4255 M, RP F 1535.35 1".28 1401.14 14280OSF1W X20." 43955 MnPT-0 F 1573.82 10.11 1X050 14114.OSF160 010.N 4483.5 MlnPt S25M.0 239.3 2]1224 2632OSF160 148X.m 8X2.4] MinPl-0 3113.45 M 2939.92 2853 BSFIN INNN ]1185 MInN. 3152] 259] 2",. 209. 18A2 OSF1,X 183t6N ]1".M 6pnp,O,AOP 31]241 2X.19 Mii 02 291262 1836 OSF1,X 15X00 TN],X Mln!( F 31.71 281.M 3010.96 29248 18. WF1.X 185X." MT." MinR1 SF 32".0 28]. .3122 2942. 100 MF1.X 1""W 012V MIn% 3218.. 273,0 3036.23 29483 12.0 WF1,X 5012 MinP14AOP 321034 27340 303674 294591 1>T2 WF1.X j"iTN 1]340= 8M13 MINT{IEOU 321958 VITO 31,,. 2945, 1T.N OSF1,50 1]320= 873194 Mine DP 3220.09 274.15 3037Po 2.5. I7.M p3F1.X 1741401 671257 MinmbSF N18(ONO~ Poa MN 3281 258.5 22727 NIA 545=t0 N(m) ON ON sn1 . 260" 25925 32.81 MN 2212] 130M74 32.81 25 m 228u 839.83 MAS =1080(m) MAS=10N(m) 34.M MN 3465 220= WNP Mln%a 259.30 288.51 32.et 32.81 2M." 2X. 226.49 20.71 21110 57.73 MAS=ITIM(m) MM=ION(m) 240m MN 240.= 957, MINPT4EOU MM 2.., 32.81 RX 25,73 5727 Mp0- ION (m) 9]0.= 90].0 MINTOEOU 32505 32.81 314.72 292. 35. Mp0-N.N(m) ISN.= 1473.75 MmPl45F ],.85 BIT ]23.31 M3A6 188 OSF1.50 4320,= 30X60 MInF F 83288 MIN 78793 773,0 1898 WF1.50 48X." 3190.24 MinP1 SF 0561 0.21 816,01 793.30 1898 OSFI.X 4810.N 324786 Miii"` SF 13X.5 123.5 12]4.61 12,00 16.72 OBF1,X 71ON 405-02 MinF :F 1475.91 52.37 14".31 137354 21. OSF1.X 772ON 425.5 MinlI SF Imm 1".39 14,.07 1430.96 31. OSFI,X NNN 4]95.0 Nnl4O F 15735 10.23 1NTM) 14,,45 2181 WF1,X .t0.m Mw.m Nnml F 2"1.5 248.5 258, 20.01 1]. WF1.X 1=1Om 0165 MInR MF 3"7.0 M.77 Min 2],92 10. WFIN 1M20.= 7119.0 MinNl .F NNn5 31,.10 2..Y0 292449 283976 2. 2830. 28u.01 1798 WFIN WFIN 10XON IMN,m M11.73 8843.04 MInNI F MINPT EOU 31NA7 2..18 2830. 2,3. 17.98 WF1,X 18910" X,41 MInROAOp 31.85 2581 203245 2,5. 179 WF1.50 1735." ONN MInR-6SF 31" MN 2934" R,2.3T 179 OSFI,X 1712O.m 0,1." MInM-0.SF kMUN a ,Nn SCM1lum0e9lr9nvale 312225 264.50 2W 53 E85].W= 06F150 1741401 6]12.5] Mln%-OAF HIBA102(DO Sumy) 260.08 3281 25885 22727 NA WS 1000(m) OPo 060 Sunece 26008 3f 01 25885 227.27 130230.]4 MFS=10.00(m) 34.65 31.65 WRP E%25 3291 25895 226.44 21.83 MFS=1000 (m( 2ffiW 220,00 Mins 259M MAI 29689 228.49 21198 MOS -10.00(m) 24010 24010 MINP]-0£W 28051 MA1 241.36 253.]1 5].8] WA=10.WDO MAN 95]." M10% 28854 3281 200. 25373 5]2] WS=10.00(m) MAD 96]A4 MINn-OEOU 32515 32.81 314.17 20.26 MAS=10.00(m) 150DA0 141375 Mln% F 78415 el." ]23,35 M13 18 05F1.50 4MDA0 3000.38 MlnP F BUN 88.01 ]0],98 3',A05 10. WF1.% 4680.00 31M24 Min% -03F ANSI W.18 81814 18. O8F1.% 4040.00 3243,96 WRF 4356.15 U2.61 1274.00 1234.1 185! OSF1.W 7120.W 4070,42 Mln%-0SF 1438.50 00.73 1312.74 IMM 21.8 mF150 I'MON 4218.32 N`I-0 F 1475.91 IM27 140738 1373. 21.8 03F150 372D.W 428&00 MWiPtp F 1535.35 10AN 1484.14 1429.07 219 OSF1.W WW.W 4396N MlM•1.O.gF 1513A7 1"11 150&50 IM4.56 21.0 0SFIA0 8210.00 4 .w MInp1.pSF 201252 239.0 2712.24 =.59 1&0 0SF1.50 1400000 80287 S9n%-0SF 311345 200. nae.92 M. t& 09F1.W 1MAIDD 7119.0 MlnM 3168.7] 258.00 2995.80 MKAW 1042 OSF1.W 18330,00 7100.75 W0,Q Dp 317201 I60.19 2999.02 2912A 18 0BF1.W 16300.00 ]00].00 Mln%-O8F 310571 281.0 3010.98 29240 1& WIN IOWA= ]157.]8 Mln%-0SF 309.59 MA 3IXN 200254 16.= OSF1.50 1000010 5912V MinMs 8218.95 ml.w 3082 29c63 1]00 OSF1.W 1121019 8802.1 Min%hNDP 3219.31 M. 3030.7 291594 17.M OSF1.W 1)340.00 8]45.15 MIN11OEOU 3219W 273.70 W367 2945. 17.70 0SF1.0 837000 673194 WOnI4ADP 322009 2]4.15 303700 29459 17.0 OSF1.50 1741401 8]12.57 Mln%-0.5F H18A4A7(WSUMY) P. 200.= 250.85 227.27 W4 =10.00(m) 0= O." 5uWRP 200." MAI 25805 1]1730.)4 WA M08=10.00(.) 30.0 14.0 200.26 MAI 38.81 2%.95 228.44 U6.. 23913 FMS=10.Po (m) 200.00 2M.= Min%e n% 21.M 3281 2%.09 228 d9 21718 FMS=10.00(.) 240.00 240.= MINPF EW 286.51 38.81 20038 E53.71 5]A]=10.00(.) WS WN 07M M11%e 286.14 32.01 m" 20.]3 5127 MAS -10.00(.) 810.= BW.W MIN"EOU 3250 MAI 314.72 292. 35.5 MAS =10.W(m) 15000 14]3]5 WWIF MIN 61.12 723.35 M3.10 180 WIN 43RO.W 3000]0 Mln%-0SF 020 =.0 787.98 70, AZ WIN 4890.00 31M24 ..R-0SF MAI %.18 816,04 MM AA WIN 4&O.W 324200 On% -ASF 1356.75 122.81 1274.00 1234.14 16.73 =FIM 712DM 4070,Q Mln%-0SF 1439.50 99.73 133214 IMAM 21.6 WIN ]SMAS 421832 MmR% F 1475.91 IN 27 1407. 1373. 21.6 OSF150 ]]20.00 4208.0 Mln%bBF IMAM 1W20 1414,14 ICZ07 21.0] 0SFIA0 SOROAO 43&5.% Min%b5F 1573.67 1(.11 1000.% 1464.% 21A 0SF1.W 8210,00 44%.62 MIn%.OSF 2832M 239,0 271224 26U.5 -g 180 OSFI.W 146W.W WMA7 MMR'OSF 311345 2%, N.'NA3 EAUAfi 18, 0BF1.W 15820.00 7119.0 Mp1%e 910011 200.00 17"5.60 290001 18Q 03F190 1%30.00 71.75 Mn%A 3172.81 200.18 2993.02 2812 Ism WIN 16MOM MIN Mln%-0SF 310.71 261.82 3010.98 2924 19, OSF1.W 1656100 ]057.78 Min%-0AF 3019.59 M.051 M1.31 2912 5d 8.m WIN 1%W00 012.Q M Py 3218.95 270.00 3036 RBI6. 12% DANN 11710.00 %0247 MlNt APAP 3219.& VA 3036,7 291594 17.17 DARN 17MM 0]4515 MINPt' 3219.00 211.]0 MIS UO 1].711 DANN IMION on".Mlffi OOP MMN 21414 3037W 2945. 17. 08FI.W 1]]101 BH25] Mln%ASF S.O.ka151e1e I NO S..O Pb 13ER0.40 3211 13227.15 13195.W WF MVS=IoN(m) 0DO ON suf- 1322&13 MAI 13228.0 1319532 OITO.36 WS=10.=(ml 34.0 UN WRP 132P 3281 13225,51 13195. 16E(.33 INS -10.00 eO 250.= mm MInPM 1319773 32.81 131028 131"92 117405 MAB-10.W(m) 910.00 905,51 hfl. 9F 13088.29 MAI 1WI128 I30N48 01.59 MPA. 10.W(m) 11MIA0 130050 MlmP F 12821.% 3].( U7WA7 127".5 530 i1 0SF1.50 1900.00 1SSA78 MIOIOSF 11395.82 49.31 113229 1IM0.51 36103 DARN 3810.0 288723 Wn%-0AF 9030.51 ",09 Am. 9764V 2335E DSFI.% 6%O.W 350.8] MIR -0 F W45.66 WAl MWTIr 8565. 18930 OSFI.W 7120.00 40I0.Q 3yn%e SCM1lum0e9lr9nvale St81um0er6er-Prl a ]336.0] Btb 118.738 ]251. 1M pE OSF1S0 5500.00 48>fiA5 Mln%USF 5346,]8 129.561 52M 521]. 04.& OSF1.50 11800,00 5]58306 Mln%USF 438180 16].15 tMs. 4256.N .16.02 4IW.71 35. 415115 4855 OSFI.W OSFI.5D 14550.00 15130.00 8750.05 6958.07 Mln%.0.SF Min%CICt 43250 203.08 41".69 614235 32.11 OSF1.W 16019.]2 )1215] Min%USF 4318.]0 200.92 4184,46 411]&4 3241 CSF, 1626000 711281 mirft. OP 4318.06 63185] 200.76 200,58 g186M 418449 411],8] 32.43 4117" 32200 OSFIM OGF150 10300A 10330.0) 711002 ]105.]5 MINPT-0 W WRn Clct 440420 19398 4271.20 420523 33.37 as" SO 1741401 5]125] TO cmmu9olun. stile 1(Ogl s-2) Pena 1023006 18230203062 1 182 3281 18228.74 92.81 10026.)1 52.01 18228 1019765 WA 1810].82®00 18197.81 WA MAS=1000 (m) MA6=10.00(IS MAS = ISM SS) 000 20." 30.00 0.00 p." 30,00 Suil-o MlnlF SF Mln, TbEOU 18230.62 18045.62 3281 32&1 1022871 1803740 1819781 WA 18012.81 288811 MAS = lobo (.) MAS= MOD sn) MIS 1500." US 1473.75 Will, MInP F 13004.00 84.30 13559.48 1353962 342 J2 OSF1.50 ]12).03 tl]pAE MlriPq 10]75." BR." 1001).72 108022a 213. OSFIA0 10030.00 5336.59 Mn% -0.5F 7�.D2 815513 158.01 2D1.99 ]]]3.77 7]24.01 80.]0 OSF150 OSF.50 14790.00 17414.01 S837M 6712.51 Mln%USF Minta 8018.71 "54.18 47,5] 13220.0 MAI 1)216.313181.8 S 16290.10 MAS=10.00(1) 250." M,W Min% 13190.31 32.01 1307.80 1315). 11]3. MAS=10W(m) 910.00 008.51 Mln%.6SF 13000.00 32.01 13DM.72 13048 82649 MAS=1.7.00lm) 13".W 1362.50 Mln%4SF 1281414 37.10 2760.98 12]77.MUMS OSF150 198)2030 10".78 MM%-0SF 11380.49 49,30 11354&0 113"11 OSF1.50 3840m 250].25 MMPUSF "23.39 60.16 00]828 9]5]. OSF1 W 5880.00 3551.03 MN% F 863800 W. "",51 855]. OSF1.50 7120.00 4070.60 Mintat 7)2984 SIM ]2]878 ]249. OSF1.50 8800,00 4676.]1 MnP SF 534200 12983 5253.00 5212.1 OSF1.W 11800.00 5750.04 MnPI430048 10].20 425101 4193.2] OSF1.50 14550.00 6751,18 MI.K"F 4348.1 43H.W 195.27 199,74 4215.60 4211.01 4150&0 33.57 414109 32. CSF150 OSF150 15120.00 15500.- 8956,00 7.77)&0 MMP6fACt Mln%-03F 433].]4 10003 4304.00 616871 326 OSF1.W 15750.- )11281 Mine F 4319.55 N18.1D ISSAS 1"61 418.25 MUM 4120.1 92.87 4118.28 3259 OSF1.. OSF150 103"30) 1034DM ]110.0] 710160 Mnfl SF B9nRI 4318.14 1".91 1189./8 4118.23 32.58 OSF1 W 183-.- ]00].46 MINPT-0£W 4318.18 1"&5 4184.10 4118.12 12.5] OSFI W 18]]11.- M95,W Mln%712004 431085 20360 4210.69 4143.1] 33.18 OSFI W 1698).00 8095." Min% -0 -SF 44)420 179.115 4264.46 422515 37.12 OSF,. 17411,19 671257 TO C.-,IIImn SIe101(W -- S-Y) P8" 15223.19 1622311 1022110 M81 15221.21 3E 11 1822118 3281 182211 10190.36 WA 16190.36[ WP 18100,35 WA MA5=10 OD (m) Mp5 =10 W (m) MAs=1000(50) 000 20M 30,00 00) 20- 30.00 SYNBC9 Mln%-0. F mlNP EW 16723.16 18038.18 Mist 10221.18 18120.35 NIA 32&1 1-".- 100)5, 2721]8 MAS=10.00(m) MAS^10.00(.) 34,50 I. SO SIM 1473.75 WRP MnP F 1%9).]9 05. 13552. 135)2)2 33856 OSF1.50 112(1.00 4070.00 MlnPb lo7111.58 031010712710807 213.52 .4 CSFi.10 10830.00 5336." MlnP F ]8]8.00 150.20 ml A] )]562. 0081 OSF150 14790.- 6837,77 Min%OSF 642026 6156.12 195.]8 18]93 82$& 0333,4 51 C -11- OSF1.SO 18900 W 1741119 BSS5. 671257 MirAM MInF1g .2S 11[ 5M 181 61'.1 C.MoNlun SWW Doer surveyl P. 1822819 18223.16 18323.16 3281 1822121 3281 16221.10 U,81= 1619038 WA 1619).36 151.35 WA MAS =10001.) MAS=10)0(50) MA3=1000(.) 000 2oss WAS 0.00 20W 30.00 Su.. Min%OSF MINPTOEW 1R23,16 18038.16 32.01 78321.18 18120135 WA 56281 18]39.50 1.053 2721.7 MAS =10.00(1) MAS- 10.-150) 34.65 1560.00 N.05 103.75 WRP MIn%.00.SF 1359)]9 ..0 13%279 1)5)2]2 338. OSF1.. )13800 470A0 Mln%e 1770.50 WAS 171209 106874 21352 OSF1.5D 10630,00 5336." MInR�O-SF ITS&W 15620 )771.4] 7722,65 061 OSFtSD 14]9020) 683).7] Min%USF 0129201".] 8150.72 1793 8296 6233 sA9 OSFIM OSF1.50 16980.00 041119 6895." 712.51 Min%g Min%s -26.11 5.760.18 5150 St81um0er6er-Prl a H04 (P2) Anti -Collision Summary Report Analysis Dale-24hr Time: December 19, 2018-14:37 Analysis Method: Normal Plane Client: BlueCrest Reference Trajectory: HIM (P2)(Def Plan) Fleld: Cosmopolitan Unit Depth Intervil: Every 10.00 Measured Depth (ft) Structure: Cosmopolitan Pad Rule Set: DSM AntiCollision Standard 5002 v5.1/5.2 Slot: H."3) Min Pts: All local minima indicated. Wall: H041. 1) Version l Patch: 2.10.544.0 Borehole: H04 Database 1 Project: localhoetcrilling-Cock Inlet Scan MD Range: 20909.00ft- 22120.2M T[electory Error Model, ISCWSA03-D 95.000%C denoe2.7955sgma,forsubjactwell.For OSset Trejechwhis Summery ORaet Selection Criteria Wellhead distance scan: Restricted within 63130.]] It Selection filters: Definitive Surveys -Defini6Ve Plana- Definitive surveys exclude definNve plans - All Non -Def Surveys when no Def -Survey is set in a borehole- Ali Non -Def Plans when no Def -Plan is eel in a borehole Onset Trajeenwy Separatha AIIow I Sep. Controlling R.1larence Tralectair, RIA Level Alert Status Ct-ct MAS EOU fl Dear. k Fact Rule MD TVD ffQ Alert Minor Major Maar maim 11 4 0](P2)(Def Plan) Fee Major 000 30282 ===9 20229 302.82 -0.01 OSF1.50 20909.00 ]125.51 OSF�5.00 OSF<1.50 OSFa1.00 Enter Major 0.00 162.10 -10847 162.10 -0.01 OSF1.50 2091000 712546 MinPls 0.19 162.6-108.6 A62.49 -0.01 0SF1.50 20930.00 7124.61 MINPTOEOU 0.42 162.98 -108. -182. -0.01 OSF1.W 20939.99 7124.23 MInPt-O-ADP 111.46 168.30-1.16 58.85 0.99 OSF1.50 21466.02 ]126.20 OSFa1.00 Exit Major 169.01 169.26 5536 -0.25 1.50 OSF1.50 21604.54 ]12].49 OSP150 Fitt Minor 301.91 155.78 19765 148.14 2.92 OSF1.W 22055.49 AO6.91 TO H04-L06(P21(Def Plan) Were, Ala# 210.41 16196 102.03 98 d5 195 OSF1.50 2090900 712551 OSPoSW Enter Alart 432 79 168.19 320.23 264.50 3.88 0SF150 213]31] 7125.34 TO Hansenit1A(Def Survey) WarrIm Ale# 139629 777.44 8]76] 618.85 270 OSF150 2090900 7125.51 OSF<SOO Ether Alert 132814 78377 805.30 5463] 2.51 OSF150 21090.94 ]122.]1 MinPle Htnrun#1AL1(DO Survayl Paha 300834 741.16 2513.90 2267.1 6. OSF1.so 2107176 7122.54 MinPt -SF 298279 7M 241 247963 222&551 59,11 OSF1.50 22120.27 7D62.49 MinFte H16(Del Survey) Pare R3112,8 290.36 2918.95 282249 16.13 OSF1.50 20W9Do 7125.51 MinPILtQ 3113] 293.47 2917.79 2820.29 15.98 OSF1,W 21032.71 ]122.43 MhPt-08A 3113.78 M.gql OSF1.W 21052.40 7122.43 MINPs 311116 304.23 2908.01 2806.92 15.38 OSF1.59 210.52.55 7126.08 MinPt-CIIX 3111.68 305.78 2907.50 2005.90 15.31 OSF1.W 21502.55 7126.% MINK01.1 3115.03 310.54 MB441 2805291 15.09 OSF1.59 21651.9 7127.33 MlnPt}ADP 3131.23 32].0 291286 28".1el 14,401 OSF1.W 22120.27 706249 Mioft H16A (Def Survey) Fess 324116 20870 3048.35 2952. 16. OSF1.W 21050.04 712242 MhPt-0SF 3229.88 297.88 3030.97 2932.0 16.31 OSF1.50 22013.36 7086.15 MInPt- 3230.16 M,69[:2 2931.48 16.27 O.9F1 50 22090.75 7069,06 MINPT43.EOU 323040 29900 3030]4 2931,401 16,251 OSF1.50 22120.27 706249 MinPle H16A-LO7(DO Survey) Pass 324116 288.70 3046.36 2952.46 1689 OSF1.50 21050D4 7122.42 MInPtOSF Schlumberger -Private Schlumberger Private 3232.25 294.58 3035.53 293].68 16.51 OSF150 21899.80 7126.9 Mint- CI 3232.38 294.90 3035.43 2937,45 16.49 OSF1.% 21]29]8 7124.39 MINPT4 EOU 3232.61 295.01 3035."L 2937.44 16.49 OSF1.W 299.75 ]123.]8 mfalm ADP 3245.49 298.92 3045.0 2948.5] 18.33 OSFI.W 22120.27 702.0 MhPt4 SF HlmA 05(Wsurvey) Pass 323904 287.% 304].05 2951% 1695 OSFL50 2091482 7125.24 Mine 3243.05 288.86 3050.14 2954.1 16.0 OSF150 2105]93 712246 MIOPI -0 -SF 3245.61 28940 3052.35 2956.21 16.8] OSF150 2119192 7123.65 MinPI-O-SF H16A-L9(Def Survey) p866 324].4 26848 305483 2959.01 16.94 OSF1.50 21009.42 712280 MinPt-0ICt 324758 280.89 3054.68 2958.8 ifi.91 OSF1.50 21057.32 712245 Min%s 3241.1 290.11 305342 2957,04 16.84 OSF1.50 21246.38 7124.16 M'mPl-CICt 3247.44 2098. 3053.12 295646 79 OSF1.50 21332.72 7124.% MINPT4 EOU 3243.84 295.58 304646 294826 16.51 OSF1.50 21833.92 7115.35 Min% H12-1-06(Def Survey) Pa. 4044.04 29148 3849.39 3752.55 2008 OSF1.50 20911.24 712540 MInPt-CtOt 4044.10 291833849.35 3752.46 2087 OSF1.50 20930.85 ]124.5] MINPT-0-EOU 4011.22 291.]9 3849.371 3]52.43 2066 OSF1.W 20950.48 7123.66 MInRI DP 1045.02 292.53 9W.483]5329 2081 OSF1.W 21046.63 7122.42 MI,R1 F 4047.83 293.83 3851.6 .7754.00F-20.73 OSF1.W 2128].64 7124.% MinPI-0-ADP 4051.]4 295.62 3854.20 375592 20.61 OSF1.W 21464.35 ]126.3] Min!R-0IQ 4051.76 295.91 3054.1 J>55. 20.60 OSF1.% 21493.28 7128.46 W% 4058. 30020 3857.77 3750.03 20.34 OSF1.W 219%.98M97.36 MlnPt-OICI 409.31 39.0 385].62 3]5].78 20.32 Wl.W 2197.47 7089.43 MINPTO{OU 40046 300.]4305]64 3]5].] 20.30 OSF150 22018.27 7085.11 MmPt-0-ADP 4060.47 30186 385903 3758.80 20,251 OSF150 22120.27 706249 Mine -O -SF H12(Del Survey) Pass 4014.04 29148 3849.39 3752.55 20.88 OSF1.50 20911.24 7125.40 WnPtG 4044.10 291.63 3649.35 3]5248 20.87 OSF1.W 299.85 7124.57 MINPT-0EOU 4064.22 281.79 3849.37 3752.43 20.0 OSF1.W 29W.18 ]123.68 M11�PI4 DP 4045.82 292.0 385048 37532 20.41 OSF1.W 21018.0 ]12'1.42 WnPt4 F 4048.17 291,4 38515 3]53]4 20.89 O F1.W 21337.0 7125.01 MINPThEOU 4018.23 294.51 3051 3]53] 290 OSF1.W 2131].83 ]125.10 mmpt43.A0P 4051.]4 M.34385551 37W39 20.45 OSF1.W 2963.81 7122.9 MINPTOEOU 4055.21 39.18 3854.76 375502 20.33 OSF1.50 2107.0 797.8 MInPt4AC1 4055.45 W1,741 3853,991 3753 91 2022 OSF1.50 22120.27 708249 MinNs H13.05(Del Survey) Pan 40fifi 39 291.7 7775 3)]4.6 2098. OSF1.50 2091]W 7125.11 Min% 4074.32 292.9 3878]3 3781.43 20.9 OSFI.W 21055.81 7122.9 MmPtO F 4074.3 292.67 3678.68 3781.63 2095 OSF1.W 21094.9 T122J4 MlnP143I0 40]360 296.81 387540 3]]6.79 20.65 OSF150 21544.% 7126.9 MmPt-0tCt 40]102 337.74 386553 3].7328 18.1.7 OSF150 21888.87 7108.W MinPts H12 -L04 (Del Survey) 4066.71 291.60 38]3. 3].4.11 2100 OSF150 20909.00 7125.51 MinPls 407847 2927139300 3785]6 20.9 OSF150 21043.95 7122.41 MinPI-0-SF 4089.32 334.52 3885.9 375480 18.39 OSF1.50 21194.68 ]123.6] MinPle C....,lltan State 1 (Def lowIr Surrey) Pam 461O.W 210.68 448941 43W 82 33.11 OSF1,50 21431,90 7125.88 MmPt-0-SF 460952 210.56 4466.51 439896 33.13 OSF1,50 2143241 7125.89 MinMs 5108.87191.4 5200.5 521]41 42.7 OSF1,50 22035.22 791.42 MinPls 5106.6 191.45 5280.60 5217.42 42.79 OSF1.50 22038.67 701.10 MinPt-CCI 589.20 187.48 5401.50 5419.73 45.31 OSFI.50 22120.27 TU62.49 TD H14PB1 (Oef Surrey) Pan688163 280.79 4494.11 4400. 25.09 OSF1.50 209900 7125.51 MInPs Schlumberger Private SIMO Rd Stale i (Def Survey) Pass H16A-1-01 (Def Survey) Pass H12-102(Def Survey) Peu Schlumberger-PUvate 4687.00 202.09 449062 4404.9 25.01 OSF1.W 21057.08 7122.45 MInRt F 4886.81 281. 449836 0404.] 25.02 OSF1.W 210/9.52 7122.80 Minis FE4886.81 281.84 4498.39 4404.)] 25.03 OSF1.W 21092.91 ]122]2 MmPt-0t01 4880.61 290.15 4496.65 4400.45 24.33 0SF1.W 21878.14 )109.]5 Mint -0t 4691.24 292.84 "95,6811 4398.39 24.11 0SF150 2212027 708249 WPM H14PB3(Def Survey) 4)BB.iJ 267] 4600.8 450).39 2567 OSF1.W 2091 ].1B 7125.14 Pa. 4)6763 28198 4602.31 4508.65 26,6A OSF1.W 21050.31 7122.42 Min%s MlnPt4 F 4]90. 281.83 4672.42 4508.81 25.58 OSF1.W 21088.24 ]122.]6 MIMI-0 4]92. 285.2] <602.05 4W7.29 25.28 OSF1.W 21444.47 ]128.00 MInmI 4]91. 288.03 4596.67 4502.99 25.03 OSF1.W 21710.2 7125.42 MhPt-0 4791.14 288. 4598. 4 2W 25.01 OSF1.W 2938.71 )123.]8 MINPT-0-E0U 4791.23288.44 4567.81 4672.) 25.00 OSF1.W 21]49.44 7123.13 MInPt-0ADP 480191 339 201 4575.25 4462511 21.29 OSFt50 22081.56 ]0]1.11 AmPls H14(DOSurv.Y) Pau 4080.68 281.69 4)02.56 460899 26.13 OSF1.50 20912.03 ]125.3] MInRs 409269 282.99 4]03)0 4609.70 26.021 OSF1.50 21055.11 7122.44 WnPt-OSF 4892.% 282.7 4]03] 480976 26.04 OSF1.W 21081.23 ]122.62 MINPT-O-EOU 48925 282.76 4]03]2 4609.79 28.04 OSF1.W 21082.37 ]122.]2 MhPt-0t 4892.73 282.95 4]03.) 46091 26.02 OSF1.W 21112.34 7122.91 MMRADP 4893.83 284.10 4]00.1 4609) 25.92 OSF1.W 21231.% ]124.2 MinPt-0-ADP 489896 208. 4)05.) 460963 25.48 OSF1.W 21]4].25 ]12328 MINPT-0{OU 4900.80 291.8 4706.1 4fi69.32 25.30 O9F1.W 21919.69 )098.48 MlnPt D -ADP 4900.6 29333 4]04] 460].34 25.14 OSF150 22120.27 706249 MinPls H16A.LO4(DO Survey) Peu 104-105(P2)(DOf P64n) Pass 116PB1(DWSurvey) Pae. H04104(P2)(DO Plan) 0046 1412i01(Def Svrvey) Pass H04-LO1(P3)(Oef Plan) Pess 116A-1-03(Def Survey) Pae. H12-102 (DO Surrey) Pass HIM. 01 (DO Surrey) Pa. Hansen #1 (def Survey) Pass H04-L02(P2)(DO Plan) Pas H12 -L03 (DINSu..y) Pess H14PB2(D.f Survey) Pas¢ 116A-1-02(l)d Survey) Pass 104-L03(P2)(DO Plan) Pass SIMO Rd Stale i (Def Survey) Pass H16A-1-01 (Def Survey) Pass H12-102(Def Survey) Peu Schlumberger-PUvate Schlumberger-PrWaae 471677 284 94 452648 4431.83r 24.91 OSF150 21459.94 6892.57 Min%OSF H14P83 (Def Survey) Pus 4]65.29 272.00 458364 4493.3 2637 OSF1.50 1994069 7126.92 Min%-O03t 4785.30 2]2.08 456359 4493.22 26.36 OSF1.50 19950.69 ]12].01 MINPT-0-EOU 4765.37 272.16 4583.60 6493.21 28.35 OSF1.50 18960.89 7127.10 MInPI-0-ADP 4]6].38 274.0 4584.3 4493.30 26.18 OSF1.50 20214.74 7117.70 MINPT-0-EOU 4M.32 2]52 4564. 1 4493.03 26.07 OSF1.% 20373.19 708.5.10 MINPT-0.EOU 4785.39 275.35 4584. "93.021 26.W OSF1.W 20363.59 ]083.16 WN -0 -ADP 6806.20 284.76 4616.03 4521,"l 25.40 OSF1.W 21459.96 8692.57 Mn%-0SF H14(Def Survey) Pas, 48]903 288.5 4889. 46104 27.35 OSF1.50 19310.85 712545 MlnPIs 46859 278.54 4698.93 460741 2640 OSF1.W 20642.4 ]02].32 MI RP Q 4886.1 279.52 4 .33 406A8 26.31 WF1.50 20]54.85 6988.19 MInmCct 4886.09 2M.r 4899.25 4806.32 26.28 OSF1.0 20781.93 6977.78 MINPT-0-EOU 4886.16 279.85 QM.261 4606 301 26.28 0SF4.50 20790.95 6874.26 MRn ADP 4912.2 28571 4721.21 4626301 25 B] OSF1.50 21459.94 8682.57 Min% -0 -SF Hi6A-1-01(DO Survey) Pass HIM-L02(Def Survey) Pass Sla4chkd State 1(DO Survey) Pass H12-LOI(Dsf Survey) Pass Hensen #1 (DHSurvey) Pass H0 1-01(P3)(Def Plan) Pass H06 W P2)(DO Plan) Pass 104-L03(P2)(Def Plan) Pass H14P82(Daf Survey) Pass 6]83.10 2]1.]1 4W1.71 4491.47 26.39 OSF1.50 19962.15 6965.48 Min%O10 4]83.18 2]1.]84581.6] 4491,40 26.38 OSF1.W 19971.43 6961.95 MINPT-0 00 4]83.25 271.85 4581.69 d491A0 26.3] OSF1.W 9960 1.8] 69]8.39 Min% -0 -ADP 4797.% 278.16 4611.89 4518 W 25.86 OSF1.W 207]7.90 8662.5] MOR-0SF H14(Def3urvey) 48]712 267r69 4698.33 43943 27,42 OSF150 1918365 712731 Min%-CICt Pass 48]].15 26776 4698.32 4609.39 2]42 OSF1.50 1919363 712740 MINPT-0-EOU 48.21 287.83 4698.33 460a.Wl 27,41 0SF1.50 19203.37 7127A9 Mln%-0ADP =1275.62 4]04.85 4613.33 26.71 0SF1.W 2029].]9 6845.59 Mbl%�1 4889.00 275. 4704.]1 661308 26.67 OSF1.50 2351.91 8622.71 MINPT4 EOU 4889.3 270.02 473.73 4613.0 26.68 OSF1.50 20380.93 018.0 Min% -0 -ADP 4901.25 2]9.22 4714.77 462203 26.42 OSF1.50 M777.90 6842.57 MmPt4 F H16A-1-01(DO Surrey) Pees H0 1-02 (P2) (Def Pan) Pass Slaechkof State 1(DO Survey) Pass HO4-L01(P3)(Def Plan) Pass Survey) Pass 0044.1 27468 3860.97 3]69.]4 22,16 OSF150 1794165 712371 MIO%-0ICt Schlumberger-PrWaae Schlumberger -Private 4044.42 V4.713860At 3]69.]1 22.16 OSF1.W 17951.84 ]123.]9 MINnT EOU 4W," 2)4.)4 3860.96 3]69.] 22.18 OSF1.50 1]981.84 ]123.8) MMR -0 -ADP 4043.90 275.33 30D.0 3)68.61 22.11 OSF1.W 18141.81 7125.35 MInNIL 404395 275. 3880. 3]68.58 22.10 OSF1.50 18151.81 7125.43 MM%g 4040. 276.98 385588 3]83.89 21.% OSF1.0 18590.00 7119.33 MInR1 Q 4"0.87 276.9 3855.88 3'83.88 21.% OSF1.50 1880012 7119.08 Mln%e FE!;M 278,80 384).)1 3755.11 21.P OSF1.50 19031.93 )029.80 Min� 4033.91278.89r 3617.69 3755.06 21.77 OSF1.W 19053.41 ]023.6) MINPT- OU 4033.88 27593 304].]1 3)55.0 21.77 OSF1.W 1%62.W ]020.88 MmR% ADP 4033.86 279.67 3017.10 3750.21 2171 OSF1.W 19205.21 a%8.0 Mi R% n 41133.% 279.373"7.W 3)5414 21.70 OSF1.W 19222.W 6%i.W MINPT4 OU 4033.96 29.0 3817.08 3754.12 21.69 OSF1.W 19239.66 6854.59 Min%-0ADP 4003.73 281.48 3M.74 3762.24 21.6 OSF1.W 100.65 6805.43 Min%ASF 406320 28333 3873.98 37]9.87r---21 5-8 OSF150 20048.90 8812.57 Mine -O -SF H12-LO4 (Def Survey) Pass 4044.41 2]066 388097 3]69]3 22.16 OSF1.W 1]941.85 ]123.]1 WR -Mt 4044.42 274.71 3860.9 376911 22.16 OSF1.W 17951.81 )123]9 MINPT OU 404444 2]4.]4 38609 37691 22.16 OSF1.W tl%1.07 7123.87 MMR -ADP 4063. 275.33 385005 3768.60 22.10 OSF1.W 18141.81 7125.35 Min%-01Ot 4043.95 2]5.3 3860 3]60.5 22.10 OSF1.W 18151.81 7125.8 Nn%s 2)6.90 385580 3763.88 21.% OSF1.W 18596.00 7119.33 MMMn 404087 2MAM 21.% OSF1.W 1800]2 7119.08 ".% 4033.91 278.W 380.71 3755.10 21.77 OSF1.W 1%".% 7029.60 MInMI t 403394 278. 389). 3]55.05 21.77 OSF1.W 1%WA1 7023.67 MINK-EOU 403399 278.93 380.]0 3755. 21.76 OSF1.50 19062.60 7020.68 MnN-0. P 4033.88 279.67 380.10 3754.23 21.71 OSF1.W 19205.21 6888.63 WnMdd 4033.90 279.P 380.06 3754.13 21.]0 O6F1.5D 19222.50 8%1.07 MINT EOU 4033.90 279.86 380.08 3754.12 21.69 O.SF1.50 19238.86 054.0 Min% -D -ADP 4049.46 281.90 3861.19 3M7.W 2162 OSF1.W 198".W 670.W MmN% F 4076.02 283.70 3886.56 3792.32 2162 OSF1.W 2008.% 6612.57 MIn F H12i01 (Oef 3urveY) 4060.6 274.2 3877.4 378641l 22.29 OSF1.W 1]]0990 7126.10 Pass Min%s 4064.84 2)4.5] 3801.47 3)90.2) 22.28 OSF1.W 178"." 7123.24 MInPt-0SF 4013.njj 319.0 38W.081 3)23.95 1904 OSF1.W 18)6{.64 7096.62 M'rn%s H14PB2(Dai Survey) Pass 45538] 25991 438026 4293.96 26.38 OSF1.50 1813975 7125.33 Min%-CIC1 455369 260.01 438021 429388 26.37 OSF150 1815973 7125.50 4553.93 260.05 438022 4293.8 26.36 OSF1.0 1810.72 7125.0 MINP7-0-EOU MinPt-O-ADP 4559.28 28234384.0 4296.95 26.17 O8F1.W 18626.90 7116.43 MINPTOEOU 4559.31 26237 43M 0611 42969 26.16 OSF1.W 1037.13 7115.30 Min% -O -ADP 4574.16 380,Ml 4320 271 4193 831 18.081 OSF1.50 19190.04 074.85 Min%s H14P91(Nf Survey) '_' "W'"'- 4707. 258. 4535.2 4449. 27.41 OSF1.W 1]]13.36 ]12590 Pess M' ft 46]L6 2644] 4495." 407.21 26.59 OSF1.50 1888064 ]0]242 Min%LICI Bit.ti 2024 4493.35 440493 WAl OSF150 19154.18 698951 Wm% 871.28 268.54 4493.25 4101.73 28.30 OSF1.W 19190.38 6072.0 MINPT-0-EOU M71 A3 265P 4493.ni 4104Jli 26.36 OSF1.W 19219.92 6982,71 WMP ADP 4702.98 271.81 452145 4431.17 W.Ni O F150 20048.0 01257 Min% -0 -SF H14PB3 (Def Survey) Pam a4)65. 258.4 4592.83 40101 27.76 OSF1.W 1]]12.28 7125.95 Mine 064.]3 20.57 45%.69 45".16 27.53 OSF1.W 1810.61 ]125]9 Minm� 081.84 20.93 45%.W 4503.91 27.49 OSF1.W 18261.38 7128.35 MINPT,P OU 0".91 261.0 45%.5 ±503 Bg 27.48 OSF1.W 1089.17 7126.0 Min% -0 -ADP 089. 263.13 4593.97 406.59 27.29 OSFi.W 1B .W 719.35 MinRp 00.)6 263.2 4583. 450651 27.28 OSF150 ls7 ." 71%.42 MINPT OU 089.80 26330 4593.94 4508.5 2727 OSP150 18)15.2) 71".87 MInM1 DP 07368 270.61 4593.12 4503.24 28.55 OSF150 19850.42 W".78 Min%4LCI 4773.88 270.8 893.11 450321 26.% OSF150 190347 8890.95 MMPM Schlumberger -Private Schlumberger -Private 478182 27190 4600.22 4509.91 26.4) OSF1.50 20048.90 661257 MN%43SF Htd(Def Survey) Pass 4875 651 2600 4707.97 4615.6 28.23 OSF150 1]]16.44 )125]6 MlnPis 4883.92 262.27 4]08]4 4621.65 2803 OSF1.50 1823780 7126.14 MIOPILYCt 4683.94 262.32 4]08.]3 462162 20.03 OSF1.50 18247.77 ]126.22 MINPT-0-EOU 488399 268.37 4]08]5 4fi21 fit 26.02 O.4F1.50 18257.74 7128.30 bpnm-. Dp 48]6.3 26].3) 469].]9 460900 27.45 OSFt50 19176.92 89]9.]4 MInPtIX 4878.30 287.43 469] 7] 4608.95 27.45 OSF1.50 19188.21 8876.14 MINPT4 EOU 4876.43 287.49 489]7] 0808.94 27.44 OSF1.W 19195.48 6978.51 MlnN ADP 4908.01 273.01 4]23.8 4833.01 27.05 OSFt.W 20634.88 881852 MINPT-0-EOU 4908.10 273.10 4721TOU4633.0 2].04 OSFI.W 20048.90 6612.57 Min%s StanchkMSUte 1(Oef&u 1w, _ - r.. ) Pass nMm 118.12 ]838.39 ]]99.43 101.58 OSF1.50 1925349 6948.80 Minft ]91].55 118.11 7838,40 ]]99.44 101.59 OSF1.50 19255.54 6947.93 MinPl tCt 8542.]9 113.95 M6642 8428.84 113.66 OSF1.50 19596.60 6802.92 TD H04-L01 (P3)(WMan) Pass Survey) Pass 404358 275.2= 3768.35 22.11 OSFt.W 1813000 706049 WNPT-0-EW 404356 2]5.15 3859.60 3768.41 22.12 OSF1.W 18150.00 ID Al MInPI-C4Ct 404492 871.01 3859.92 3]6].9 21.9 OSFt.W 18410.00 8987.11 MMR-0SF 4043% 2]8.85 385819 3]8].30 22.00 OSFt.W 1MMM 6933.]5 MhMP DP 4043.91 2]6.60 3659.16 3]6].31 82.00 OSFt.W 10500.00 8929.52 MINPT-0-EOU 40438 2]6.50 3059.22 3]6].36 RR.Ot OSF1.50 18520.00 6921.07 Min%4ACt 4046.50 277.d8 3861.28 3M.12r 21.95 0SF1.50 18710.00 684018 Min%-0SF 4045.38 271.38 3861.1 3]69. 2185 OSF1.50 18760.00 8019.65 MinRs 40463 2]].36 3861.13 3769.01 21% OSF1.50 18))0.00 8015.43 sfinm Ot 4057.80 2]].16 3872.78 3706.72 22_.Oj OSF1.50 19220.00 6825.26 Min%-0SF 4050.91 277.13 387382 3781 77 2204 OSF1.50 19248.82 6813.11 TD SMEchkef State 1(Def Survey) Pass 433399 191.83 4205.]5 4142.18 34.0) OSF1.50 16900.00 712649 Mln%5 510007 14970 4999.86 4950.29 51.43 OSFI,50 19248.62 661317 TD H14PB2(Def Survey) 458]]0 255.12 439]2 4312.5 26. OSF1.50 1890000 ]126.49 Pass Min%s 4566.11 258.164393.66 430].95 26.6 OSFt.W 1]39000 7126.59 Min%-0SF 4555.31 259.82 4381.88 4295.6264 OSF1.W 1]900.06 ]10].89 Min%OSF 0551.11 259.65 4380.67 4294,46 26.41 OSF1.W 18090.00 M70.64 WnPt.CICt 4554.12 259.771 4MO.601 429435 26.39 OSF1.W 18130.00 1006.49 4554.14 251.78 4380.81 4294.3 263 OSFS.W 181401M 7067.M Min%e Mln%-0SF 4554.34 261.34 4309.]] d303.00 2829 OSF1.W 1065080 0006.14 MinR4 F 456].32 282.25 44121 4325.0 2633 OSFLW 19130,0 6663.6 Min%-0-ADP 4592.80 M.UqL_4M,1qL 4301.2 2370 OSFt.W 19248.62 M13.17 68n%s H14PB1(Dd Survey) Pass 4688. 255.16 451841 4433. 276 OSF160 1690000 712649 489394 2M.1 4522.6 443]80 27.59 OSF1.50 1)16000 7125.09 M'InPls MINPLO-EOU 4694.05 258.27 4522. 4437.7 27.56 MF1.50 17190.00 ]125.1] Mlnm ADP 4894.8 257.8 452288 4437. 27.47 OSFS.W 17330.00 7126.16 Minft 409477 257.25 4522.94 443752 VA OSF1.50 17380.00 7128.51 MinP1 F dM5.59 283.93 450931 442166 28.72 OSF1.50 18510.00 6925.30 Min%-0SF 466229 283.52 4508.28 "18 77 26.75 OSF1.W 18700.00 6845.01 WR-0-ADP 4602.2] M.Ml 4MI81 4410.]7 2615 OSFt.W 18710,0 8 .78 MINPT-O-EOU 0682.28 MA 4506.28 4418.70 2675 OSF1.W 18720,0 8838.56 Min%-01Ct 4695.10 Zfid.25 4518.80 4430.0 2675 OSFt.W 19230,0 M21.04 MInPt-0SF 469577 260.28 4519.25 443146 2675 OSFt.W 19240.62 6613.7 TD H14PB3(Def Survey) Peva Schlumberger -Private Schlumberger-%ivate 4]0.5.48 254.121 45]5.]4 4491361 28.11 OSF1.W 18900.00 7128.49 Mins 4]5].83 2W15 OSF1.W 17220.00 712538 Min%y 4]59.1] 258.32 4587% 4502.8 279 OBF1.W 17320.00 7126.09 MInPt- F 47611 257.03 4M1.fi 408.3 2290 OSF1.50 17500.W 7127.37 wrtP 4763.80 257.W OSF1.50 175W.00 712732 Mine 4766.13 260.58 4592.09 4505.5 2]. OSF1.50 18040.0 7002.10 Min!N DSF 4765.02 260A3 OSF1.50 18170.00 7049.53 MIMM 4]65.0 280.42 459106 4W4.W 2].54 OSF1.50 1811M.00 7008.88 MinP1-OIO1 4785.73 260.82 459185 4M5.11 27. OSF1.50 18320.00 7001.33 Min%-0SF 4]]2.13 2M.81 458].8 4511.32 2].54 OSF1.W 1857800 6099.94 Min% -0 -ADP 4774.67 282.28 4599.49 4512.3 27.0 OSF1.W 19700.W 8005.01 MmR% F 0790.51 261.98 4823.53 4538. 27.5 OSF1.W 19220.00 682528 Minfn 8F 4M0.53 262.01 4625.53 453!1.53 2].58 OSF1.W 19248.62 11813.17 TO H14(OWSumy) Pass 4808.32 253421 4679.051 4594.81 2880 OSF1.50 16900.0 712649 Mln%5 4853.55 200. 402..7 459].21 28.50 OSF1.% 169W.W 7124.25 Mln%5 48M.0 257.1 4602.9 059].54 28.42 OSF1.W 1700.00 7124.22 MINPT-0£OU 4854.78 25724 4602.9 4597, 2841 OSF1.% 1]0]0.00 7124.30 Mln%-0-ADP 4655.24 257.68 4883.1 4597.59 288 OSF1.W 17110.W 1924.0 WnP 4885.73 257. 489344 480]]9 28.40 OSF1.W 17400.W 7127.30 Min% 4888.28 258.12 M 5.85 4610.13 28,3911 OSF1.W 17580.00 7127.93 Min% -048F 4875.86 250. 470294 46170 20..70 OSF1.50 17M.M 7121.47 min% 4871.14 259.43 4703.66 461].]1 20.3 OSF1.50 17840.00 7115.52 Min% -0$F 4681.14 200. 4]07.1 462011 20.21 OSF1.W 1790.00 7092.5 Mi.m 4886.21 28244 4708.12 4622.07 200 OSF1.W 18170.00 7049.53 Min%-0SF 4884.07 282. 4]09.01 4621.98 20.05 OSF1.W 18210.0 7037..4 mfn 4884.0 262.0 4709.02 4621.90 28.05 OSF1.W 18220.00 ]034.]0 MinNO t 4888.09 2626 F 47068 4623.4 28.01 OSFI.W 18410.00 6987.11 Min% 4886.73 28388 4]ID.4 482286 2]. OSF1.W 18560.0 8904.17 Mine 4886.] 263,N 471049 462286 27.88 OSF1.W 185]000 6099.90 MInPt-0IOt 4880.8 285. 471131 462301 2]68 OSF1.W 18860.0 6735.14 Min%a 4888.90 26589 4]11.31 4623. 27.0 OSF1.50 18970.0 6]30.91 Min!N-0ADP 4889.6] 26599 4]1201 4623.68 2].67 OSF1.M 100.0 6600.20 Minl -0SF 4892.85 265.91 4715.25 462694 27.70 OSF1.W 19248.62 6613.17 TO Sunmy) v�` Pass 5134.2) 207.0 4993.92 4926.33 3]94 0SF1.W 19246.62 8613.17 Min%s 2821.15 231.33 2664.60 2588.8 18.1 OSF1.W 14312.W 6(185.01 Wi SF 290.23 248.11 2736.49 MU 12 L 17.81 OSF1.W 14557.28 670.27 MORF 3153.31 280.55 297661 2888 75 V. OSF1.50 1%10.M 7118.82 MlnR1 SF 3219.52 273. 30368 2945.6] 1769 OSF1.W 1730739 6741.W MINPT-0-EOU 3219.85 274.25 3038.69 294560 1].67 OSF1.W 17374.34 6730.03 MinP14AOP 3220.4 274.78 035.93 29656 17. OSF1.5O 17410.31 6714.20 Min%ASF 3220.51 26402 .7044.17 2956.49 18.M OSFi.% 1741401 671257 TO H16A-105(Oef Survey) Pa65 28808 3281 258.85 22].2] WA MAS =10.00 (m) 000 000 Surtace 259.25 32.81 2W.96 228.44 240.]8 MAS =10.00 (m) 219.35 219.35 Mi.ft 2M.W 32.81 258.89 228.09 21].80 MAS =10.W (m) 239.M 239.34 MINPTOEOU 288.5 32.81 2M MJ1 50.13 MAS=10.00 (m) 955.72 953.63 Min% 288.53 32.81 280.M 253.72 57.0 MAS =10.W (m) 966.08 983.83 MINPTBEOU 325.70 32.81 315.37 M,w 35. MAS =10.00(.) 1491.14 1485.82 Min%-0SF 751.50 60.07 711.10 WI.Q 19. OSF1.50 4177.70 309.05 MhRP F W170 68.61 817.61 M.w 19.1 OSF1.50 4781.78 3219.74 MmR% F %916 Win] 823.35 WO.67 19.1 OSF1.W 0791.16 32M.M MmN% F 1050.81 83.60 1W232 975.21 19..9 OSF1.0 W19.05 352928 Min%-0SF 1384.89 125.37 130.]5 1259.32 16.]0 OSF1.W 7114.41 408.41 Min%-0SF 1088.02 102.20 1389.0 136582 211 OSF1.M 7536.19 4220.% MhNP F 1520.35 105.78 1449.0 1414.58 21.]6] OSF1.W ]]W.04 0312.42 Min%4"F 2012.19 233.57 26M.14 257861 18.1 OSF1.M 14274.38 6651.22 Min!N SF 2821.15 234.33 2680.80 20682 18.1 OSF1.W 14312.W 6685.01 WnNI F Schlumberger-%ivate 54 Iumbeqerv9RvaM M2.23 24841 2]36.49 26U.1 1]61 OSFi.W 14557.28 6753.27 Minmb 310.31 284.55 2976.01 2000.7 1).89 OSFLW 15810.59 7118.82 MlnlPSF 3219.52 273.8 WW6 290.5.6] 1)69 0.4F1.W 1730.39 674L90 MINK) OU 3219.85 274.25 3036.09® 17.67 OSF1.W 1)3]4.34 6730.03 Min% -0 -ADP 3220.44 2]4)8 303693 294566 1].84 OSF1.5O 1741031 6714.20 MIM+b0.SF 3220.51 264.02 3044.9 2958.49 18.36 OSF1.50 17414.01 6]125] TD H18ML0 (Def 8urvay) Pose 26088 32.81 25005 22]2] NIA MAS =1080 (m) 000 0.00 SURace 259.25 32.81 256% 226.4 240.78 MAS=1000 (m) 21935 219.35 Min% 25930 32.81 256.69 22649 217.88 MAS=1000 (m) 239.34 239.34 MINPT-0-EOU 32.81 280.38 253.)1 5&13 MAS=10.00(.) 955.72 953.63 Min%t 286.53 32.01 280. 253.)2 57.0 MAS =10.00 (m) 968.08 %3.03 MINPT-O-EOU 325.70 32.81 315.37 292. 35.08 MAS=10.00 (m) 1491.14 1465.82 MInN1 F 751.50 60.07 711.10 691.4 19. OSF1.50 4177.70 3009.05 MM%43SF 063.70 68.61 817.61 )95. 19.1 OSF1.50 4]61.]0 3219.74 MIMR4 F 869.76 69.08 823.35 000.6 O5F1.5O 4791.16 3230.34 MmR% F 1058.81 03.80 1002.]2 9]5.21 OSF1.W 5619.85 3529.28 Min!R�3F 1384.69 125.37 1300]5 1259.32 OSF1.W ]114.41 408&41 Min%438F 1468.02 102.20 13%.53 1365. OSF1.W )538.19 4220.58 Mi.Rl F 1520.35 105.)8 416.70 1449.40 1414. OSF1.W ])90.84 4312.42 MInR1 F 2012.19 233.5] 2656.14 25]8.61 OSF1.W 142)4.67 601.22 WRP F 2821.15 234.33 2 .W 2586.8 OSF1.W W12.W 8885.01 Min!N 1 F 2902.23 248.11 2]36.49 2854.1O5F1.W 1455).20 6TW.2T WR% F 3153.31 264.55 29]6.61 288&] OSF1.W 1010.1 7118.82 WnRI F 3219.52 2]3.8 3038.8 29456] 1)69 OSF1.W 1]34].38 6]41.90 MINIT4 EOU 3219.85 274.25 3038.89 284589 17.67 OSF1.W 1]3)4.34 6730.03 Min%-0-AOP 322044 2]4.)8 3036.93 2945861]. OSF1.1 17410.31 671020 MMM% F 322951 264.02 3044.17 2956.49 18.36 OSFl.50 17414.01 6)12.5] TD H16A-L04 (DefSurvey) Poet 260.00 32.81 258.85 22).2] WA MAS =10.67 (m) 0.00 0.00 SURace 267. 32.81 255.96 22649 240.70 MA6=1O.W(m) 219.35 219.35 Mint 259.30 32.81 25689 226.49 217.80 MAS=1080 (m) 239.34 239.34 MINK -0 OU 28fi.52 3Z.Bi 280. 253.]1 50.13 MAS=10.67 (m) 9".M 9".fi3 MMPb: 286.53 32.81 200.39 253.]2 57A9 MAS =1O.W(m) 967.00 963.83 MINPT43-EOU 32570 3281 315.37 292.89 350 MAS =10.67 (m) 101.14 1465.62 M.R-0 F ]51.67 60.07 711.10 691.43 19.08 OSF1.W 412.0 3008.05 MInR1 F 863.0 60.61 017.61 ?Wog 19.1 OSF1.W 461]8 3219.74 Min%-0SF 569.76 6900 823.35 800.67 19.16 OSF1.5O 491.16 3230.34 Min!N SF 1067.81 83.0 1002.72 975.21 19.2 OSF1.W W19.85 3529.20 WNn F 1389.89 125.37 1300.]5 1259.32 16.70 OSF1.W 7114.41 401.41 MinN4 F 1460.02 102.20 1399." 130.82 21.7fi OSF1.50 7536.19 420.W MmN% F 1520.35 105.78 1149.48 1414. 21. OSF1.50 ]]0.84 4312.42 MhN% F 2812.19 233.57 2 .14 2578.61 18.1 OSF1.5O 14274.38 151.22 Min% -044F 2821.15 234.33 261M.60 2506.8 18.1 OSF1.50 14312.60 6685.01 MmR% F 2902.23 248.11 2]36.49 MM.12 17,61 OSF1.W 14W).28 6)0.2) Min% -0 -SF 31".31 284.55 0)6.61 2888.7 1]. OSF1.W 15810.1 7118.1 MIMRQ F 3219.52 2M. 3038.8 294567 17.69 OSF1.W 937.W 6741.90 MINPT#W 3219.1 2]4.25 3 .6929456 L 1).6] OSF1.W ]2324.36 6/30.03 Min% -0 -ADP 3220.64 2]4.]0 3"8.93 2945.66 1).1 OSF1.W 17410.31 6714.20 WRF 3220.51 264.02 3044.17 29M 49 1036 OSF1.5D 17414.01 6)12.5) TD H16A-101 (Def Survey) Pots 260.08 3281 258.85 22)2) WA MAS =10.67 (m) 0.00 0.00 SURace 21.2 32.81 2W.% 226.N 240.76 MAS =10.00 (m) 219.35 219.35 M111% 2130 32.81 2W.W 226.49 217.88 MAS =1O.W (m) 239.34 239.34 MINPT43-EOU 21.5 3281 M.341 25311 50.13 MAS =1080 (m) 05.2 953.63 M10% 288." 32.81 20.34 253.72 57.49 MAS =1O.W (m) 986.08 863." MINK) OU 325]0 32.81 31537 292.8 J5. MAS =1O.W(m) 1491.14 1465.62 Mlr IO F 751.50 W.O] 711.10 691,431 19.0 OSF1.W 49).0 309.05 MInP14)44F 00.0 0.61 017.61 795.0 19.1 O.9F1.W 461]8 3219.4 MInRI F 80.]6 1.0 023.35 WO,67F---19-1Q OSF1.W 491.16 3230.36 W %43SF 54 Iumbeqerv9RvaM Schlumberger-PrWWe 1058.81 03.60 1002.72 97521 = 19216]0 OSF1.8 5819.85 3528.28 MIBR' F 1384.69 125.37 1300]5 1259.32 0$F1.50 7114.41 4068A1 MhPI4 F 1468.02 102.20 1399.53 136561 21.7(1 OSF1.8 ]536.19 4220.58 MInRt-0 F 1520.35 105.8 1419.48 1414. 21.] OSF1.50 ]]90.84 4312./2 MMmI F 2812.19 233.57 2853.14 2578.61 16.1 OSF1.8 ]42]4.38 6651.22 MMR/ F 2821.15 234.33 2884.60 2506.02 10.1 OSF1.8 14312.8 6665.01 8nR-0 F 2902.23 240.11 2736.49 2654.12 17.61 OSF1.8 14557.28 6]53.2] MInR1 F 3153.31 264.5529]661 28887 1]. OSF1.8 15810.59 7118.82 MmNP F 3225.07 2751 3041.32 29499 1]. OSF1.50 1]414.01 6]12.5] MInP1-O-SF Pao H16A-L07 (Det Survey) 260.08 32.01 250.85 22].2] NIA MAS =10.00 (m) 000 0.00 $mh4ce 259.25 3201 256.96 226.44 240]8 MAS=1000 (m) 219.35 219.35 MlnP 259.30 32.81 25609 22(1.49 21] 88 MAS =10.00 (m) 239.34 239.34 MINPT4EOU 28(1.5 U. 280. 253)1 50.13 1M3=10.00 (m) 955.72 953.63 MInft 286.53 32.81 280. 253]2 5]49 MAS =IOM (m) 986.08 96183 MINK -0 OU M.70 MAI 315.37 292.8 35. MAS=1080(.) 1191.14 1465.82 MInR1 F 751.50 80.0] 711.10 691.4 19.0 OSF160 4172.]0 3009.5 MMR/ F 063.]0 68.61 817.61 ]9509 iB.t OSF180 4761]8 3219.]4 MInP14 F 869.]6 69.08 823.35 800. 19.1 OSF1.50 4791.16 3230.34 MMPI -0 F 1058.81 83.60 1002.]2 9]5.21 19.2 OSF1 SO 5619.85 3529.28 MhRM F 1381.69 125.37 138.75 1259.32 16.70 O$F1.W 7114A1 4W8Al MhR-0 F 1468.02 102.20 1399.53 1365.8 21. OSF1.50 7536.19 4220.56 Min%435F 1520.35 105.]] 1449.48 1414.58 21.7 OSF1.SD ]]90.84 4312.42 MhIR-0 F 2812.19 233.57 2656.15 25]8.62 18.1 OSF1.8 142]4.36 66.51.22 WIR�F 2821.15 234.32 266480 258(1.82 18.1 O$F1.50 14312.60 6865.01 MInM1 F 2902.23 248.10 2706A9 26561 17.61 OSF1.50 14557.28 6]53.2] MhPt4 F 3153.31 264.55 29'!8.61 2888. 17. OSF1.8 15810.59 7118.82 MInR1 F 3219.52 273. 3036.6 2945.6] 17.69 OSFI.50 17347.39 8741.90 MINPT43-EOU 3219.85 274.25 MW 69L_12jEtlj 1767 OSF1.50 1]374.34 6730.03 MMPI- DP 3220.41 274.78 3036.93 2945.80 1].64 OSF1.50 17410.31 (1]14.20 MMR/ F 3220.51 M4.02 3044.17 298A9 18.36 OSF1.8 1741401 6]125] TD T Peee Sla6chkof Slate 1(00 Survey) 1322)8 32.81 13225] 13195. 1571271 "S 10.00 (m) 256.82 25682 MinP6 1322847 32.01 13220.93 13195.66 209524 MAS-10.DD (m) 380.81 380.81 MINPT-O-EOU 13228.57 32.81 1322098 1319 761L 2076.06 MAS=10.8 (m) 48.05 408.05 M,nRt F 1322850 3281 13220. 13195.69 2065.8 MA6=10.00(.) 416.01 416.81 MINPT4 EOU 13228.3 KS 13222. 131955 2880.33 WS 10.00 (m) 443.08 443.08 MlnP 4346.6 195.36 4216.03 415127 33.55 QSF1.50 15128.25 695824 MinPl CtCt 434664 195.3 4216.0 4151. 33.54 OSF1.60 15131.87 6980.54 Wft 434]! 19].10 421536 4150.03 33.26 OSF1.50 15255.44 ID .51 MInPt-0 4347.21 19].3 4215. 414982 33.21 OSF1.50 16276.46 ]010.25 MINPT4 W 434].32 19].53 4215.20 4149 ]9 33.10 OSF1.50 1528651 7013.41 MlWtI ADP 4363.15 199.(1] 4229.68 4163.48 32. OSF1.50 15488.82 ]8].96 MInP40SF 6383.91 160.(10 8276.50 6223.31 W. OSF1.50 16099.9] 7128.63 MMPI -0 -SF 432445 201.42 418111 4123.4 32.37 OSF1.50 18270.26 7113.80 MlWtM F 4318.94 28.8 4104.8 4118.118 32.42 OSF1.8 16298.53 7110.21 MI^ft 4318.57 M.591 4184,491 4117.98 32A6 OSF1.50 16328.82 7105.92 Minft 4710.10 174.28 4583.56 4535.82 4078 (MF1.50 17414.01 6]12.5] TD Pose Surve ) 18230.04 3281 18226.27 1619].23 9856.31 MA$=10.W (m) 394.]9 394.]9 M'^� 18230.04 32.8118226.25 1819723 972823 MAS=10.8 (m) 402.8 4028 MINPT-O£OU 18230.34 32.81 18226,49 18197. 9401.46 MAS=10.81.) 431.44 431.64 MInR1 F 1823287 32.81 18220.30 18189. 9870.6 MMS: 10.W(m) 5W.28 58.27 MhRP SF 1823616 32.81 10232.30 18203. 9401.5 hWS=10.W(m) 87.57 87.54 MMRF 13220. 32.81 13218.41 13107. 1581717 MAS=10.00(.) 254.25 254.25 MMPN 13221.8 32.811321380 13188.28 210815 MAS =IOM (m) 378.24 318.24 MINPT4 OU 13221.27 32.81 1321370 13188.46 2082. MAS =10.00 (m) 401.54 401.54 MhPl43 F 13221.12 32.81 13213.61 13188.31 2103.36 MMS=10.00(.) 419.05 419.05 MINK] -EOU Schlumberger-PrWWe Schlumberger-PrivMe P"s 32.81 1321¢9 13100.21 2]28.85 MAS =10.0(.) 445.32 145.31 MlnP 525843 FROM tn.40 5137.55 WM.03 44.90 0SF1.W 14Wl.W 8901.50 MlnPl. t 5256.43 in.513].52 50)8. 40.8 OSF1.W 14334.90 8902.59 Min% 5386]6 10.1 52]3.fi 5217.6 400 OSF1.W 18853.5970n.26 Mint 5056]1 175. 4939.5 40014 43,5 OSF1.W 18853.83 70".25 Mine 6483.77 155.32 6379.90 632845 6301 OSF1.W 16654.15 Mn.n Min%ASF 5910.0150.0 5804.3 5)51.96 SBA OSF1.W 16854.85 ]0]7.25 MinPb 5684.83 180. 557718 5523.85 53.2 MF 50 1MS.0 707).25 Min%m 4455.83 189. 4329.2 4266. 35.4 OSF1.W 1055.44 7077.25 Min% 442497 190.94 4297,34 4234.02 34.9 O51P1.50 18888.39 7077.25 Min%A4F "26.98 191.04 42 9.28 423593 34.93 OSF1.W 190.43 707.25 Min%ASF 190. 0292.4 4229.3 3501 OSF1.W 1806.88 Mn.25 Mln%s 4418.25 190.33 4291.04 4227.9 349 OSF1.W 16657.21 Mn.25 Mint "18.0 10.39 4291 ]3 4228.591® OSF1.W 1685].]3 Mn.25 WPIASF 530. 167. 520492 5229.4 48.82 OSF1.W 105].39 Mn.25 Min% 6076.7 1W.7 59)2.fi1 5921.01® OSF1.W 18859.14 M77M Min %s 4550.] 186.4 "2608 438425O5F1.W 1685].4)MInP6 515).0 1)1.92 5042.08 4985.10 452 OSF1.W 1057.0 7077.25 Min%s 481).01 177. 469). 463841 40.5 0SF1.W 1885).85 )0)].25 mlM 4)]2.1 1W.7 4651.31 4591.39 39.8 OSF1.W 1080.2 Mn.25 Mh1Pbi 0960.) 175. 4851.32 4)93.10 42.66 OSF1.W 16858.05 Mn.25 Mins 40].31 1]].11 4)08.91 4)3020 41 ]8 OSF1.W 100.30 70n.25 Min% 6801.41 14].]8 6)0256 665363 894 OSF1.50 18658.]3 ]0]).25 Mins 6518.] 1W.2 641022 6360.46 65.4 OSF1.50 18660.0] 70)).25 MinPts 75W. 100.2 ]496.51]4W. 81] OSF1.W 1W59.0 7077.25 Min%s 7928.80 137.0 7836.70 n9t15 87.01 OSF1.50 16661.0 ]0]7.25 TD )257.1 143. ]155. ]107. 77.3 OSF1.W 1801.41 7077.25 M.% Onsrn.,.'tan sure i (DO Survey) 18222. 32.81 18218.918189] 1111320 MAS =10W(m) 392.22 392.22 MinPl 1822255 3Z81L_jUl8,9A 1810.74 1001.89 MRS =10.W 1m) 4N.W 404.00 MINPT0.EOU 10222.86 32.81 18219.25 181W.0,91 10]3]. MRS =10.0 (m) 432.M 432.78 Min%ASF 4720.0 4578.0 4WB43 33]1 MF1.0 21657.85 7077.25 Min% '211.60r 4720.04211.K 0578.02 450842 33.70 0SF1.W 21657.89 7077.25 Mln%A-RDP 4721.31 211.74 15]9.61 45057 33.89 OSF1.W 21850.07 Mn.25 Min%ASF 477121 211.73 4573.51 450947 33.69 OSF1.W 21850.07 Mn.25 TD 5124. 204.1 4987.69 4920.18 37.94 OSF1.W 21855.88 Mn.25 Wft Schlumberger-PrivMe P"s Traveling Cylinder Plot NODo R,padn ula ws d D& on On,m d m St Dlm,ns00 SIMimr Rmk2 AmnCdulswn rW, ua,tl DbM AnFCollnbn Sl,nd,etl 5002 rS.1R 2 28( 270 201 North 350 10 TRAVELING CYLINDER PLOT Gant 8j.cn.11 Fi,M C,amdpald,n Unn SI nt COSmOPOlkan Pad Well H01(.v1) Bor,hdl, H04 D,ce 10-D 2018 Schlumberger -Private 90 100 HNNSEN H-04 (Revisea) Permit 218-126 Coordinate Conversion Check (NAD 27 Lat/Long to NAD 27 ASP) onvertfrom: • LLh SPC UTM XYZ Enter tat -ion in decimal degrees -, Lat+ 59.8581888889 ; Lon -151.8016750000 Q or degrees -minutes -seconds Lat N 59-51-29.48000 " Lon W 151-48-06.03000 or drag map marker to a location of interest Ellipsoid Height (m) Input datum NAD27 I Output datum NA027 Don't see a datum in the list? Click here to team more. )vented coordinates will be in output datum. rport Results to , I*, x UTM (m) LLh 5 SPC Srcl-at 59.8581888889 Zone AK 4-5004 010210"80 N595129 48000 Scale factor DestLat 59.8581888889 Northing (m) 653,674.537 N595129.48000 Northing 2,14,597210 Siglat A 000000 (usft) (aresec) Northing (ift) 2,144,601.499 Srcl-on -151.8016750000 Easting (m) 51,451.315 W1514806.03000 Easting 168,803-188 � DestLon -151.8016750000 (usft) W1514806.03000 Easting (ift) 168,803 526 Siglon . 10 000000 (aresec) Convergence -01332949 (dms) SrcEht NIA 1,,,1 Scale factor 1.00002484 UTM (m) Zone 5 Northing 6,636 018 378 Easting 567,125-819 Convergence 010210"80 (dms) Scale factor 0.99965522 Combined N/A factor USNG Leaflet i Sources XYZ (m) X NDA Y NDA Z N/A USNG 5VNG6712536018 AOGCC December 21, 2018 TRANSMITTAL LETTER CHE/CKLIST WELL NAME:��— PTD: Development Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: 41 / POOL: W, Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50 -- (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - from records, data and logs acquired for well name on ermit . ` The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Comnanv 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 er Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool HANSEN, HANSEN UNDEF OIL-290100 Well Name: HANSEN H-04 Program DEV Well bore seg PTD#:2181260 Company BLUECREST ALASKA OPERATING LLC Initial Class/Type —L1_EY_!_P_END —GeoArea .820 Unit 1Q370 On/Off Shore On Annular Disposal Administration 17 Nonconven, gas conforms to AS31,05,030(j 1.A),0,2.A-D) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA 1 Pernitfee attached- - - - - - - - - - - - - - - - - - .......... - - - - - - - NA - - - - - - - - - - - - - - - - - - - - - - - - - - - 2 Lease number appropriate - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - Yes Surface Location Jies within Fee-Hansen;.Portion of Well Pesses.Thru. ADL0018790; 3 Unique well name and number ... -Yes - - - TO lies in ADL0384403. - - - - - - - 4 Well located in a-defined pool - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - No - - - Hansen Undefined Oil Pool- - - - - - - 5 - Well located proper distance from drilling unit boundary . . . . .... . .. . . . . . . .. . ... Yes - - - ......... .. - - - - _ .. - ........ . 6 Well located proper distance_ from other wells- - - - - - - - - - - - - - - - - - - - - - - - - - - - No - - _ - _ SPACING EXCEPTION REQUIRED, HANSEN, HANSEN UNDEF OIL-290100, governed by statewide spacing re 7 Sufficient acreage available in drilling unit- - . Yes As planned, this well does NOT conform with statewide spacing requirements....... - - 8 If deviated, is wellbore plat included - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - Yes - - - SPACING EXCEPTION REQUIRED: Well lies within same govemmental.quarter section as Hansen-1A, - 9 Operator only affected party- - - - - - - - - - - - - - - - - - - - - - - - - - - - - --- - - - - - Yes- 10 Operator has. appropriate bond in force . . . . . . . . . . . . . . . ................ Yes ...... - - - - - - - - - - - - - - - - - - - - - - - - Appr Date 11 Permit can be issued without conservation order - - - - - - - - - - - - - - - - - - - - No.... - - - - SPACING EXCEPTION REQUIRED: Well lies within same governmental.quarter section as Hansen 1A. - 12 Permit coon be issued without administrative approval - - - ............... - - Yes SFD 12/21/2018 13 Can permit be approved before 15-day. wait.... - - _ - _ - - - - - - - - 14 Well located within area and strata authorized by. Injection Order # (put 10# in- comments) (For - NA . . . . . . . . ............... . 15 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 .................. . . . ............... 18 Conductor stringprovided. . . . . . . . .................. . . . . . . . . . . . . . Yes - - - - - - - 20" conductor driven to 193 ft. (moved to slot Hr03-due to rig issues . . Engineering 19 Surface casing. protects all known USDW6 - - - ---- - - - - - - - - - - - - - - - - - - - Yes - - 13.3/8" surface casing will be. set at 3530 ft TVD 20 CMT vol. adequale.to circulate on conductor & surf csg . . . .................... Yes 21 CMT vol adequate to tie-in long string to surf osg --- - - - - - - - - - - - - - - - - - - - - - No - - 9 5/8". will have 1000 ft of cement 22 C.MT will cover all known productive horizons- - - - - -------- - - - - - - - - - - - - - - - Yes - - Drilling lateral spokes... will-be lett-OH.. 23 Casing designs adequate for. C, T, B &_permafrost - - - - - - - - .... - ... - Yes BTC tale provided. 24 Adequate tankage. or reserve pit - - _ - - - - - - - - - Yes Rig has steel pits— all waste transported. to approved disposal well.... . 25 If a-re-drill, has a 10-403 for abandonment been approved - - - - - - - - - NA- 26 Adequate wellbore separation proposed - . . . . . . ....... Yes - - _ - No issues with close crossing. 27 If diverter required, does it meet regulations--- - - - - - - - - - - - - - - - - - - - - - NA...... - Diyeter waived per 20 AAC 25.035 (h)(2). Appr Date 28 Drilling fluid program schematic & equip list adequate - - ... - - - - Yes - - Max formation pressure = 3549 psi (9.66 ppg EMW) willdrill with 10.5 ppg mud... GLS 12/2172018 29 BOPEs, do they meet. regulation - - - - - - - - - - - - - - - - - - - - - - - - Yes 30 BOPE.press rating appropriate; test to _(put psig in comments)- .. .. - .. Yes .. MASP = 2842 psi ( will test BOPE to 3500 psi) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 31 Chokemanifoldcomplies w/API. RP-53 (May 84)- - - - - - - - - - - - - - - - Yes- 32 Work will occur without operation shutdown_ - - - - ... - - - - - Yes 33 is presence of 1-12S gas probable _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ______ - No 1-12S not expected 34 Mechanical condition of wells within AOR verified (Forservicewell only) - NA 35 Permit can be issued w/o hydrogensulfidemeasures Yes H2S not observed in nearby. Hansen wells. Rig has sensorsand alarms, - .............. . Geology 36 Data. presented on potential overpressure zones- ........ Yes - - _ Horizontal well targeting Starichkof sand and Hemlock. Planned mud weights in conjunction with - - - - Appr Date 37 Seismic analysis of shallow gas. zones - . . . . . . . . . . . . . . ......... NA..... - - _ Managed PressureDrillingtechnique appear adequate to controlmaximumanticipateddownhole SFD 12/21/2018 38 Seabed condition survay.(if off-shore) . . . . . . . . . . . . . .................... NA. - pressure of 9.66 ppg• which is based on MDT measurements of reservoirpressure in nearby well 39 Contact name/phone for weekly.progress reports. [exploratory only] - _ _ NA Geologic Engineering Pu� REVISED APPLICATION: Due to rig move problem that required setting of a new conductor. approx 20ft away from original SHL Commissioner: Date: Commissioner: Date Co is er Date SFD 12/21/2018 Mainbore will have slotted liner. The lateral up dip spokes Wil be left OH. GIs DTS r (� THE STATE °fALASKA GOVERNOR BILL WALKER Larry Burgess Alaska Manager BlueCrest Alaska Operating, LLC 3301 C Street, Suite 202 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Hansen Field, Undefined Oil Pool, H04 BlueCrest Alaska Operating, LLC Permit to Drill Number: 218-126 Surface Location: 2173' FSL, 1552' FEL, SEC. 2, T4S, R15W, SM Bottomhole Location: 3847' FSL, 3680' FEL, SEC. 32, T3S, R15W, SM Dear Mr. Burgess: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the permit to drill the above referenced development well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce is contingent upon issuance of a conservation order approving a spacing exception. BlueCrest Alaska Operating, LLC assumes the liability of any protest to the spacing exception that may occur. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Hollis S. French Chair {l DATED this I" day of November, 2018. STATE OF ALASKA AL .CA OIL AND GAS CONSERVATION COMMISoiON h j PERMIT TO DRILL 20 AAC 25.005 ^'. P,'0 7^- -- '- 1 ' 1 a. Type of Work: i b. Proposed Well Class: - as ❑Service - WAG ❑ Service -Disp ❑ tc. Specifyf - is pbse-oF Drill •Q Lateral tratigraphic Test Development -Oil ❑Service -Winj ❑ Single Zone Q Coalbed Gas ❑GasHydrates Redrill Reentry ploratory - Oil Development -Gas Service - Supply ❑ Multiple Zone ❑ Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket , O Single Well ❑ 11. Well Name and Number: BlueCrest Alaska Operating LLC Bond No. 5511251547" H04 - 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3301 "C" Street, Suite 202, Anchorage, AK 99503 MD: 22,122' TVD: 7,063' Hansen, Undefined Oil Pool - 4a. Location of Well (Governmental Section): 7. Property Designation: - Surface: 2173' FSL, 1552' FEL, Sec. 2, T4S, R1 5W SM ADL 18790, ADL 384403, Fee -Hansen ' Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 350' FSL, 3337' FEL, Sec. 33, T3S, RI 5W SM LOCI 14-007 11/15/2018 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 3847' FSL, 3680' FEL, Sec. 32, T3S, R1 5W SM 14423 543' (YO1664) 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 180.5 15. Distance to Nearest Well Open Surface: x-168813. y- 2144623.035 • Zone- 4 GL / BF Elevation above MSL (ft): 145.25 to Same Pool: 2590'- H1ALi 16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 115 degrees Downhole: 3,549 psi • Surface: 2,842 psi '(using 7,070' TVD) 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) Driven 20 0.5" wall A252 Welded 152 41 41 193 193 N/A - Rotary Drilled / Driven 17.6 13.375 72 L-80 BTC 5583 40 40 5623 3531 Lead: 715 bbls, 12.0 ppg Tail: 167 bbls 15.8 ppg Class G 12.25 9.625 47 Pilo Hyd 563 15443 38 38 15481 7067 Tail: 132 bbls, 15.8 ppg Class G TOC: 13,981' MD / 6,546' TVD 8.5 4.5 1 15.2 Pilo Hyd 563 6741 15381 7042 22122 • 7063 Slotted Liner- No Cement; 100' lap 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): N/A Perforation Depth TVD (ft): N/A Hydraulic Fracture planned? Yes ❑ No 2] 20. Attachments: Property Plat ❑' BOP Sketch v Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverts, Sketch Seabed Report Drilling Fluid Program ,r 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Thomas McKay Authorized Name: Larry Burgess Contact Email: tom.mckav(dbluecrestenergy.com Authorized Title: Alaska Manager Contact Phone: 907-754-9566 Authorized Signature:Date: 11 -Oct -18 Commission Use Only Permit to Drill 'rj API Number: Permit Approval f See cover letter for other Number: Zl 50-'y3 - b'(� "(..moi'-G� Date: 11 requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: -Af 3 500 1051 11610 . / CJ Samples req'd: Yes ❑ No Mud log req'd: Yes 1E -120 11 '' ,, JJ� �-- H,S measures: Yes ❑ o Directional svy req' .Yes sti't' � W� apjil Spacing exception req'd: Yes [v�No ❑ Inclination -only svy req'd: Yes ❑Jo Ee t,/Q� '1? ✓� (,V Lt�lk1 _ j% ZU f�AC, Z,7 C) 3'j 01 x 2� Post initial injection MIT req'd: Yes ❑Jo , APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 1 , i tn' iQ-J I D I G� I Submit Form and �rm 10-001 Revised 5/2017 This permit is v li 4 f t e of approval per 20 AAC 25.005(8) Aaachment in Dupkcate e 0an lNeSr Energy 3301 C Street, Suite 202, Anchorage, AK 99503 Thomas W. McKay, P. E. Phone: (907) 754-9566 Email: tom.mckay@bluecrestenergy.com October 11. 2018 Alaska Oil and Gas Conservation Commission 333 West 7'h Avenue, Suite 100 Anchorage, Alaska 99501 Cosmopolitan Project RE: Application for Permit to Drill: Horizontal Production Well H04 – Fishbone Producer Form 10-401; Fishbone Multilateral Well Design Dear Commissioners, BlueCrest Alaska Operating LLC hereby applies for a Permit to Drill for the onshore horizontal production well H04 – Fishbone Producer. This well will be drilled and completed using BlueCrest Rig #1. The planned spud date could be as early as 15 Nov 2018. H04 will be a multilateral producer, employing seven (7) "fishbone" style ribs drilled off the mainbore up into the full section of reservoir present on this Lease. The H04 well will be a grass roots producer drilled from the H04 slot. The H04 Fishbone Producer well will not be fracture stimulated but instead will rely on the seven (7) rib wellbores to drain the hydrocarbon fluids, etc. into the main bore which will be cased with a 4-1/2" slotted liner. The well will be completed with 3-1/2" tubing and lifted using gas lift as needed. A Diverter Waiver will be requested under a different cover letter for well H04. Please find attached for the review of the Commission form 10-401, and the information required by 20 ACC 25.005 for this well. Please note that the eight (8) Spacing Exceptions for this H04 well have already been submitted. Also note that seven (7) additional yet abbreviated APD packages will be submitted for each well 'rib" numbered L01 through L07, which are proposed to be open hole sidetracks off the mainbore. As per AOGCC regulations, each rib requires its own unique name and APD. If you have any questions or require further information, please do not hesitate to contact Tom McKay at 907-754-9566 (office) or 907-350-9544 (cell). Sincerer 4".1— Larry Burgess 0 Alaska Manager BlueCrest Alaska Operating LLC fue st / Energy Cosmopolitan Project H04 BlueCrest H04 Fishbone APD Package - Main Bore + Fishbone Lower Laterals Section Topic A Cover Letter B APD Table of Contents C Form 10-401 1 Well Name 2 Location Summary 3 BOPE Information 4-a Drilling Hazards Information 4-b Pressure Model Plot 4-c Drilling Hazards Summary 5 LOT/FIT Procedure 6 Casing & Cementing Program 7 Diverter System Information 8 Drilling Fluid Program 9 Abnormally Pressured Formation Information 10 Seismic Analysis 11 Seabed Condition Analysis 12 Evidence of Bonding 13 Proposed Drilling Program 14 Discussion of Mud & Cuttings Disposal and Annular Disposal 15 Attachments 15-1 Drilling Procedure - Proposed Drilling Program 15-1a Wellbore Schematic - Cross Sectional Color View 15-1b Wellbore Schematic - Excel Section Review 15-1c Wellbore Schematic - Visio Version 15-2 Directional Plan 15-3 Casing Design & Cement Volume Calculations 15-4 Formation Integrity & LOT Procedures 15-5 BOP & Choke Manifold Configuration 15-6 Wellhead & Tree Configuration 15-7 Diverter Configuration & Schematics 15-8 H04 Lease Map 15-9 H04 As -Built Surface Slot Location 15-10 H04 New Well Rig Elevation Form Well Identifier Surface X Y Depth MD Legal Coordinates H04 (Pl) Surface Location 168812.804 2144623.035 2173' FSL, 1552' FEL, Sec. 2, T4S, R15W SM H04 (Pl) SCP 165349.46 2145687.06 -3353.43 5623.05 3143' FSL, 5044' FEL, Sec. 2, T4S, R15W SM H04 (131) ICP (Top of Production) 156564.79 2148421.8 -6889.98 15481 350' FSL, 3337' FEL, Sec. 33, T3S, R15W SM H04 (Pl) TD 151037.26 2152075.44 -6886.54 22122.01 3847' FSL, 3680' FEL, Sec. 32, T3S, R15W SM H04 -L01 (Pl) KOP (Top of Production) 156089.35 2148667.44 -6951.6 16021.46 583' FSL, 3819' FEL, Sec. 33, T3S, R15W SM H04 -L01 (P1) TD 155000.35 2149401.42 -6536.55 17413.75 1286' FSL, 4928' FEL, Sec. 33, T3S, R15W SM H04 -L02 (P1) KOP (Top of Production) 155462.09 2149089.34 -6951.32 16777.86 987' FSL, 4458' FEL, Sec. 33, T3S, R15W SM H04 -L02 (Pl) TD 154213.31 2149933.44 -6466.66 18379.17 1796' FSL, 447' FEL, Sec. 32, T3S, R15W SM H04 -L03 (P1) KOP (Top of Production) 154774.06 2149555.27 -6951.58 17608.87 1433' FSL, 5158' FEL, Sec. 33, T3S, R15W SM H04 -L03 (Pl) TD 153496.35 2150416.47 -6436.55 19250.37 2258' FSL, 1177' FEL, Sec. 32, T3S, R15W SM H04-1-04 (Pl) KOP (Top of Production) 154113.81 2149999.68 -6951.51 18404.82 1859' FSL, 548' FEL, Sec. 32, T3S, R15W SM 1-104-1-04 (P1) TD 152833.34 2150864.47 -6436.55 20050.65 2687' FSL, 1852' FEL, Sec. 32, T3S, R15W SM H04-1-05 (P1) KOP (Top of Production) 153450.87 2150447.6 -6951.55 19204.9712288' FSL, 1223' FEL, Sec. 32, T3S, R15W SM H04-LO5 (Pl) TD 152223.29 2151275.44 -6466.63 20779.6513081' FSL, 2473' FEL, Sec. 32, T3S, R15W SM H04 -L06 (Pl) KOP (Top of Production) 152787.44 2150894.87 -6951.55 20005.16 2716' FSL, 1899' FEL, Sec. 32, T3S, R15W SM H04 -L06 (P1) TD 151648.29 2151662.49 -6516.66 21461.68 3451' FSL, 3058' FEL, Sec. 32, T3S, R15W SM H04 -L07 (P1) KOP (Top of Production) 152129.131 2151338.82 -6951.54 20799.25 3141' FSL, 2569' FEL, Sec. 32, T3S, RiSW SM H04-1-07 (Pl) JTD 151145.251 2152002.44 -6606.64 22048.92 3777' FSL, 3570' FEL, Sec. 32, T3S, R15W SM Wellbore Nearest Producing Well Distance To Nearest Producer (ft) Nearest Property Line Distance (ft) H04 Hansen 1AL1 2590 Y01664 543 H04-L01 Hansen 1AL1 2590 Y01664 4866 H04-L02 Hansen 1AL1 2590 Y01664 4010 H04-L03 Hansen lAL1 2647 Y01664 3216 H04-L04 Hansen 1AL1 2842 Y01664 2493 H04-L05 Hansen 1ALl 2964 Y01664 1831 H04-L06 Hansen 1AL1 2955 Y01664 1209 H04-L07 Hansen 1AL1 2951 Y01664 660 lust Energy Application for Permit to Drill Document Cosmopolitan Project H04 10-401 APD Discussion Sections Horizontal Multilateral Producer H04 — Mainbore Horizontal Table of Contents 1. Well Name...................................................................................................................3 Requirements of 20AAC25.005 (f)..............................................................................................................3 2. Location Summary........................................................................................................3 Requirements of 20 AAC 25.005(c)(2).......................................................................................................... 3 Requirements of 20 AAC 25.050(b).............................................................................................................. 3 3. Blowout Prevention Equipment Information..................................................................4 Requirements of 20 AAC 25.005(c)(3).......................................................................................................... 4 4. Drilling Hazards Information.........................................................................................4 Requirements of 20AAC25.005 (c)(4).........................................................................................................4 DrillingHazards Summary:..................................................................................................................... 6 S. Procedure for Conducting Formation Integrity Tests.......................................................7 Requirements of 20AAC25.005 (c)(5)......................................................................................................... 7 6. Casing and Cementing Program.....................................................................................7 Requirements of 20 AAC 25.005(c)(6).......................................................................................................... 7 7. Diverter System Information .........................................................................................7 Requirements of 20 AAC 25.005(c)(7).......................................................................................................... 7 8. Drilling Fluid Program...................................................................................................8 Requirements of 20 AAC 25.005(c)(8).......................................................................................................... 8 9. Abnormally Pressured Formation Information................................................................8 Requirements of 20AAC25.005 (c)(9)......................................................................................................... 8 10. Seismic Analysis...........................................................................................................8 Requirements of 20AAC25.005 (c)(10).......................................................................................................8 11. Seabed Condition Analysis............................................................................................8 Requirements of 20AAC25.005 (c)(11)....................................................................................................... 8 12. Evidence of Bonding.....................................................................................................9 Requirements of 20AAC25.005 (c)(12)....................................................................................................... 9 13. Proposed Drilling Program............................................................................................9 Requirements of 20AAC25.005 (c)(13)....................................................................................................... 9 1IPage H04 10-401 APD Discussion Sections IueNest Energy Cosmopolitan Project H04 10-401 APD Discussion Sections 14. Discussion of Mud and Cuttings Disposal and Annular Disposal.......................................9 Requirements of 20AAC25.005(c)(14) .......................................................................................................9 15. Attachments................................................................................ Attachment Drilling Procedure.......................................................................... Attachment 2 Directional Plan............................................................................. Attachment 3 Casing Design Calculations............................................................. Attachment 4 formation Integrity And Leak Off Test Procedure .............................. Attachment 5 BOP & Choke Manifold Configuration .............................................. Attachment 6 Wellhead & Tree Configuration....................................................... Attachment 7 Diverter Schematics....................................................................... Attachment8 Lease Map............................................................................................. Attachment 9 As -Built Slot Survey................................................................................ A+rh—...• 1n IA/ell rio....11— C..r... ................................9 ....................................... 9 ....................................... 9 ....................................... 9 ....................................... 9 0 ....................................... 9 ....................................... 9 .......................................... 9 .......................................... 9 .......................................... 9 21 Page H0410-401 APD Discussion Sections nue Energy Cosmopolitan Project H0410-401 APD Discussion Sections 1. Well Name Requirements of 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(6). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. Well Name: H04 To include the main bore and lower lateral drilling and completion only. NOTE: This well will be proposed as a "fishbone" design with a mainbore named as H04, and seven (7) open hole "barefoot" laterals drilled by open hole sidetrack from the mainbore to be named as: 1-104-1-01, 1-104-1-02, 1-104-1-03, H04 - L04, 1-104-1-05, H04-1-06, and H04 -L07. The seven (7) laterals or "ribs" will be drilled upward into all the Hemlock and Starichkof reservoir layers at an inclination of 115 degrees, and each will have its own APD package to be submitted. This particular package (1-104) is for the mainbore H04 drilling and completion operations. 2. Location Summary Requirements of 20 AAC 25.005(c)(2) An application for a Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission and identified in the application: (2) a plat identifying the property and the property's owners and showing (A)the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines. (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth; (D) other information required by 20 AA 25.050(6); Location at Top of Productive Interval Location at Surface 2173' FSL, 1552' FEL, Sec. 02, T4S, R15W SM Measured Depth, RKB: 15,481' ASP Zone 4 NAD 17 Coordinates Northing: 2,144,623.035' Easting: 168,812.804' RKB Elevation 180.50'AMSL - Pad Elevation 145.25'AMSL Location at Top of Productive Interval 350' FSL, 3337' FEL, Sec. 33, T3S, R1SW SM ASPZone4 NAD27Coordmotes Northing: 2,148,421.8' Easting: 156,564.79' Measured Depth, RKB: 15,481' Total Vertical Depth, RKB: 7,067' Total Vertical Depth, 55: 6,886' Location at Total Depth 3847' FSL, 3680' FEL, Sec. 32, T35, R15W SM ASP Zone 4 NAD 17 Coordinates Northing: 2,152,075.44' Easting: 151,037.26' Measured Depth, RKB: 22,122' Total Vertical Depth, RKB: 7,063' Total Vertical Depth, 55: 6,883' Requirements of20AAC25.050(b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well, Please see Attachment 2: Directional Plan Please see Attachments 7-8: Diverter Schematics / Lease Map (1) for all wells within 200 feet of the proposed wellbore (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The Applicant is the only affected owner. 31Page 1404 10-401 APD Discussion Sections lust Energy Cosmopolitan Project H04 10-401 APD Discussion Sections 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) An application for o Permit to Drill mus( be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (3) a diagram and description of the blowout prevention equipment (HOPE) as required by 20AAC 25.035, 20AAC25.036, or 20AAC 25.037, as applicable, Please see Attachment 5: BOP & Choke Manifold Configuration 4. Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) An application /oi a Permit to Drill muss be oc omponied by each of the following items, except for an item already on file with the commission and identified in the application: (4) information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a methane gradient, The expected reservoir pressure in the Starichkof / Hemlock Sands is 0.472 psi/ft, or 9.07 ppg EMW at 6,951' TVDss taken per MDT's on Cosmopolitan 1. The maximum known pressure in the upper Kenai sands is 9.66 ppg @ 3,841' TVDs! per MDT's taken on Cosmopolitan 1. To be conservative, the highest pressure gradient of 9.66 ppg or 0.502 psi/ft will be used to determine MPSP at the production interval of 6,900' TVDss. The maximum potential surface pressure (MPSP) based on the above maximum pressure gradient, a methane gradient (0.10), and the planned vertical depth of the Starichkof / Hemlock formation is:\ MPSP=(6,900TVDss) (0.502 - 0.1 psi/ft) r- 11A j\ =2,774 psi L(I PPS MPSP=(7,070TVD)(0.502-0.1psi/ft) =2,842 psi (using TVD instead of TVDss for this calculation) MAX BHP=(7,070TVD) (0.502 psi/ft) =3,549 psi (using TVD instead of TVDss for this calculation) ✓ (B) data on potential gas zones, The Sterling, Beluga and Tyonek sands within the Kenai group have been known to contain gas. The intermediate section will be drilled with a minimum mud weight of 10.5 ppg, the maximum known pressure through these sections is 9.66 ppg @ 3,841' TVDss per MDT's taken on Cosmopolitan 1. ,/ (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking, Please see the Drilling Hazards Overview below. 4lPage H04 10-401 APD Discussion Sections 1ue est Energy W$ txI M 4000 N N t] ,C p 5000 • 1_1 1 V16011a Cosmopolitan Project H0410-401 APD Discussion Sections Pressure Model (EMW) Upper Tyonek, 3292.44 Lower Tyonek, 6059.01 Starichkof, 6874.84 Hemlock, 6902.77 8 9 10 11 12 13 14 15 16 17 18 19 20 EMW (PPG) —Lithostatic Stress • MDT Data— Frac Gradient—Moving Average—Planned Mud Weight 51Page H04 10-401 APD Discussion Sections nue st i Energy Drilling Hazards Summary: 17-%" Hole Section / 13-'/a" Casing Cosmopolitan Project H0410-401 APD Discussion Sections Event Risk Level Mitigation Strategy Maintain planned mud parameters, Increase mud weight, use Clay Balling Low weighted sweeps, reduce fluid viscosity, control ROP. Abnormal Pressure in Low Diverter drills, increased mud weight. Surface Formations Reduced trip speeds, mud properties, proper hole filling, real time Directional Control Low BHA design, on -sight geologic review, avoid "drilling the line". Directional Control Low Reduced pump rates, mud rheology, lost circulation material, use Lost Circulation Low of low density cement slurries, control running speeds. 12-%" Hole Section / 9 -fie" Casing Event Risk Level Mitigation Strategy Reduced pump rates, reduced trip speeds, real time equivalent Lost Circulation Low circulating density (ECD) monitoring, mud rheology, Pre -planned LCM pills, lost circulation material. Hole swabbing on Reduced trip speeds, mud properties, proper hole filling, real time trips Low equivalent circulating density (ECD) monitoring, weighted sweeps. Directional Control Low Increased mud density and fluid composition according to plan, Sloughing Coals, Low controlled trip speeds, ECD monitoring, optimized hydraulics for Tight Hole hole cleaning. Abnormal Reservoir Low Well control drills, increased mud weight. Pressure Low practices, mud scavengers. H2S drills, detection systems, alarms, standard well control Hydrogen Sulfide Gas Low practices, mud scavengers. 8-%" Hole Section / 5-%" Slotted Liner Event Risk Level Mitigation Strategy Fluid density according to plan, reduced pump rates, reduced trip Lost Circulation Low speeds, real time equivalent circulating density (ECD) monitoring, mud rheology, lost circulation material. Hole swabbing on Reduced trip speeds, mud properties, proper hole filling, real time trips Low equivalent circulating density (ECD) monitoring, weighted sweeps. Directional Control Low BHA design, on -sight geologic review. Abnormal Reservoir Low Well control drills, increased mud weight. Pressure HZS drills, detection systems, alarms, standard well control Hydrogen Sulfide Gas Low practices, mud scavengers. 6 1 P a g a H0410-401 APD Discussion Sections lNest Energy Cosmopolitan Project H0410-401 APD Discussion Sections 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) An application fora Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission and identified in the application: (5) a description of the procedure for conducting formation integrity tests, as required under 20AAC 25.030(f); Please see Attachment 4: Formation Integrity and Leak Off Test Procedure 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An application for a Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission and identified in the application: (6) a complete proposed casing and cementing program as required by 10 AAC 25.030, and a description of any slotted liner pre -perforated liner, or screen to be installed; Casing and Cementing Program See also Attachment 4: Cement Volume Calculation Summary Csg/Tbg Hole size Weight Grade Conn Length Top MD/TVD Btm MD/7VD Cement Program OD (in/ (in/ Ilb/h) (�/ Ift) Ift) 20" N/A '5001 A525 Weld 152' - 41'/41' 193'/193'- N/A Wal 5,623'/ - 882 TOTAL BBLS 13-3/8' 17-1/2" 72 L-80 BTC 5,583' 40'/40' 3,531' LEAD: 572 bbls 12.00 ppg Kenai Lead "G" TAIL: 167 bbls 15.8 ppg Class 9-5/8" 12-1/4" 47 P-110 Hydri1563 15,443' 38'/38' 15,481'/, 132 TOTALBBIS "G" 7,067' TAIL: 132 bbls 15.8 ppg Class TOC: 13,981' MD/ 6,546' TVD No cement required 4-1/2" 8-1/2" 15.2 P-110 Hydril 563 6,741' 15,381'/ 22,122'/ , Slotted liner completion 7,042' 7,063' 100' liner lap Please see Attachment 3: Casing Design Calculations NOTE: Due to the high inclination at the 9-5/8" intermediate shoe, a tractor would be required to run a CBL/USIT log on this shoe. In addition, since the H04 well is not to be hydraulically fracture stimulated, it is requested that the AOGCC G— waive the CBL /USIT requirement on the 9-5/8" cement job on the H04 well. 7. Diverter System Information L )AWOL Requirements of 20 AAC25.005(c)(7) �✓ An application for a Permit to Drill must be accompanied by each ofth following items, except for an item already on file with the commission and identified in the application: (7) a diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC25.035(h)(1); Please see Attachment 5: BOP and Choke Manifold Configuration. NOTE: A request and justification to waive the requirement for a diverter system while drilling the H04 surface section will be submitted under a separate cover letter. 71Paga H0410-401 APD Discussion Sections t31ueC.fest Energy Cosmopolitan Project H0410-401 APD Discussion Sections 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8) An application for a Pen, t to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application.: (8) a drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. Drilling will be done with drilling fluids having the following properties over the listed intervals in the following Table. NOTE: the base case drilling fluid program is to drill the surface section with a fresh water conventional barite based system. The intermediate section will be drilled with a oil based conventional barite mud system. However, based on the results seen in the H14 and H12 flowback production test histories, it is planned to drill the H04 production section using a solids free oil based mud system with no barite, using only salt and calcium carbonate for weighting and bridging material, in order to minimize near wellbore formation damage in the reservoir section. Since the well design does not allow for any type of well stimulation or acid clean up after completion, it is vital for well productivity to drill the reservoir with as light a mud weight as possible, and with as few solids as possible, in an effort to minimize formation damage. Parameter Surface Intermediate Production Type W BM OEM OEM Name Spud Mud Versa Pro VersaPro Density(ppg) 9.8 10.5 8.8-9.7 ' `'E• Oil: Water Ratio N/A 80:20 75:25 6/3 RPM 17-20 12-14 8-10 PV (lbs/100ft') <28 <28 API Fluid Loss (cc/30min) NC HTHP Fluid Loss (cc/30min) <5.0 <5.0 Electric Stability (mlVolts) >600 >600 pH 8.5-9.5 Chlorides <2,000 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application; (9) for an exploratory or strotigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); Not applicable: Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis Requirements of 20 AAC25.005 (c)(10) An application for a Permit to Drill must be accompanied by each of the following items, except Jor on item already on file with the commission and identified in the application: (10) for an exploratory or stratigrophic test well, a seismic refraction or reflection analysis as required by 10 AAC 25.061(a); Not applicable: Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (I1) for a well drilled from an offshore platform, mobile bottom -founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(6); Not applicable: Application is not for an offshore well. 8lPage H0410-401 APD Discussion Sections J' nue est Energy Cosmopolitan Project H0410-401 APD Discussion Sections 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (12) evidence showing that the requirements of 20 AAC 25.015 (Bonding)hove been met; Evidence of bonding for BlueCrest Alaska Operating LLC is on file with the Commission. 13. Proposed Drilling Program Requirements of 20 AAC 25.005 (c)(13) A copy of the proposed drilling program, the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 10 AAC 25.283(m); to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting an Application for Sundry Approvals (Form 10- 403) b403) with the information required under 20 AAC 15.180 and 20 AAC 15.283, (13) a copy of the proposed drilling program,- Please rogram; Please refer to Attachment 1—Drilling Procedure. Note: The H04 well will NOT be hydraulically stimulated. . 14. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) An application for o Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (14) a general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well.; Solid and liquid wastes generated during the drilling process will be disposed of at Hilcorp Alaska, LLC's Kenai Gas Field (KFG) Grind & Injection (G&I) Facility or AIMM Technologies' (hydrokinetics) facility in Kenai. Dried water base cuttings from the surface section are planned to be properly disposed of in a local landfill after being tested using the filter paint test. No annular disposal is planned for this well. 15. Attachments Attachment 1 Drilling Procedure with Wellbore Schematics Attachment 2 Directional Plan Attachment 3 Casing Design and Cement Volume Calculations Attachment 4 Formation Integrity And Leak Off Test Procedure Attachment 5 BOP & Choke Manifold Configuration Attachment 6 Wellhead & Tree Configuration Attachment 7 Diverter Schematics Attachment 8 Lease Map Attachment 9 As Built Slot Survey Attachment 10 New Well Elevation Form 9 1 P a g a H0410-401 APD Discussion Sections D(UENest Energy Attachment 1 Cosmopolitan Project H0410-401 Fishbone APD Attachments H0410-401 Fishbone APD Attachments BlueCrest Energy H04 MAINBORE & FISHBONE LOWER LATERAL Drilling and Completion DRAFT Well Plan Tom McKay Tom.mckay@BiueCrestEnergy.com David Ross david.ross@BlueCrestEnergy.com IueC.lest Energy Table of Contents Cosmopolitan Project H04_ Well Plan WellPlan Summary..........................................................................................................................3 General................................................................................................................................................................... 4 Signageand Documentation.................................................................................................................................................4 Close Approach and Offset Well Interception Risks.............................................................................................................4 Survey Program & Procedures..............................................................................................................................................4 Casing/Liner/Tubing/DP/HWDP Drifts..................................................................................................................................5 PipeDope..............................................................................................................................................................................5 ProjectOverview..............................................................................................................................6 Structure................................................................................................................................................................ 6 Stratigraphy........................................................................................................................................................... 6 WellOverview.................................................................................................................................. 8 WellSchematic...................................................................................................................................................... 9 SectionReview.....................................................................................................................................................10 GeologicHazards.................................................................................................................................................11 Pre -Rig Operations..........................................................................................................................12 Conductor/ Cellar Installation (pending operation)............................................................................................13 Operations..........................................................................................................................................................................13 MI R U.............................................................................................................................................. 14 MIRUOperations................................................................................................................................................. 15 DiverterInstallation.............................................................................................................................................15 (NOTE: A Diverter Waiver has been requested from the AOGCC)...............................................................15 Drilling............................................................................................................................................16 Surface................................................................................................................................................................. 17 GeneralNotes.....................................................................................................................................................................17 Drilling Procedure (17-1/2" Surface Section)......................................................................................................................18 CasingProgram...................................................................................................................................................................19 CasingRunning Notes.........................................................................................................................................................19 RunningProcedure............................................................................................................................................................. 20 CentralizerPlacement.........................................................................................................................................................20 0)Page H04_ Well Plan for APD Package � r � lueC.'iest Cosmopolitan Project Energy HO4 Well Plan Cementing...........................................................................................................................................................................22 CementingNotes................................................................................................................................................................22 CementingProcedure.........................................................................................................................................................22 Intermediate........................................................................................................................................................ 24 Overview............................................................................................................................................................................. 24 GeneralNotes.....................................................................................................................................................................24 Drill Out Procedure (13-3/8" Casing)..................................................................................................................................25 Drilling Procedure (12-1/4" Section)...................................................................................................................................26 CasingProgram...............................................:...................................................................................................................28 CasingRunning Notes.........................................................................................................................................................28 CasingRunning Order.........................................................................................................................................................29 CentralizerPlacement.........................................................................................................................................................29 Pre-Run...............................................................................................................................................................................29 RunningProcedure.............................................................................................................................................................31 Cementing........................................................................................................................................................................... 32 CementingNotes................................................................................................................................................................32 CementingProcedure.........................................................................................................................................................32 Priorto Lifting The BOP Stack.............................................................................................................................................33 While Lifting the BOP Stack and Setting the Emergency Slips............................................................................................33 Overview............................................................................................................................................................................. 34 GeneralNotes.....................................................................................................................................................................34 DrillOut Procedure.............................................................................................................................................................35 RSS BHA & Procedure for Drilling 8-1/2" Production Section: ............................................................................................ 36 Completion: Lower Lateral.............................................................................................................. 39 SlottedLiner Run(5-1/2")....................................................................................................................................40 Overview............................................................................................................................................................................. 40 GeneralNotes.....................................................................................................................................................................40 Liner Running Order (subject to change when run in well)................................................................................................42 ConnectionSpecifications...................................................................................................................................................43 5-1/2" Slotted Liner Running: ............................................................................................................................................. 44 Example Liner Running Parameters....................................................................................................................................45 Mechanical Releasing the Liner Running Tool - Example...................................................................................................46 UpperCompletion.......................................................................................................................... 48 3-1/2" Production Tubing String..........................................................................................................................49 1(Page H04_ Well Plan for APD Package nue st Energy Overview ......................... Cosmopolitan Project H04_ Well Plan ..................................... 49 TubingString Running Sequence........................................................................................................................................49 21 Page H04_ Well Plan for APD Package IueC fest Energy Well Plan Summary Rig BlueCrest Rig #1 Well Type Multilateral Fishbone Design Producer Well Design 13-3/8" Surface x 9-5/8" Intermediate x 4-1/2" Slotted Liner Lower 4-1/2" 15.2# P110 H563 Slotted Liner Lateral Completion Upper N/A Design Lateral Tubing String 3-1/2" 9.3# L80 IBT-MOD Production Tubing String AFE TBD PTD Lower Lateral TBA by AOGCC API # TBA by AOGCC PTD Upper Lateral Will be issued later under a subsequent APD API # Will be issued later under a subsequent APD Cosmopolitan Project H04_ Well Plan 31 Page H04_ Well Plan for APD Package lue st Cosmopolitan Project Energy H04_ Well Plan General Signage and Documentation 1. Ensure that all well signage is on location and displayed properly. Well Sign • "On Diverter" Signage (unless Diverter Waiver request is approved by AOGCC) 2. Ensure the following documents are stored TOGETHER in the company man's office: • Application for Permit to Drill (APD 10-401) 4 Display in Dog House as well; include H04 mainbore APD plus seven (7) rib lateral APD's • Onshore ODPCP • SPCC Plan • Air Permit • FAA obstruction determination • Lease Operations Plan LO/CI 14-007 Close Approach and Offset Well Interception Risks It is important to stay as close as practical to the planned directional program. The directional program and a summary of close approaches can be found in the attachments. These close approaches will be in conformance with the minimum well separation criteria detailed by the Drilling Anti -Collision Analysis and Close Approach Guidelines. It is the responsibility of the Directional Driller and the Drilling Supervisor to ensure that the directional plan is executed as planned, that the position of the well as it is drilled is monitored on an anti - collision diagram and that no tolerance line for close approach wells is crossed. It is important that the well bore remains close to the planned well path as any major deviations from the profile may adversely affect the ability to drill future wells and still adhere to the current close crossing guidelines. Survey Program & Procedures Take MWD surveys as frequently as needed, but no less than every 100 ft. Carefully review the anticipated close crossings with existing wellbores and future well paths. Make sure that directional drillers are aware of all drilling close crossing issues, hard lines and no-go lines. If a no-go or hard line has been or will be crossed, stop drilling immediately and contact the Drilling Superintendent to discuss options. NOTE: 1. Directional Drillers are to be continuously monitoring upcoming potential crossings. 2. It is the Directional Drillers responsibility to keep the drilling team aware of any and all potential issues concerning anti -collision issues. 41 Page H04_ Well Plan for APD Package lust Cosmopolitan Project Energy H04 Well Plan Casing/Liner/Tubing/DP/HWDP Drifts Ensure the following drifts are on location and stored properly, in one spot, on the rig. Casing 12.250" Nylon Solid Casing 8.500" Nylon Solid Liner 3.701" Nylon Solid Tubing 2.867" Nylon Solid Drill Pipe 3.750" Nylon Solid Drill Pipe 3.875" Steel Hollow Drill Pipe 3.875" Steel Hollow HWDP 3.000" Steel Hollow Pipe Dope Ensure that the following pipe dopes are on location upon rig up. 1. Drill Pipe/ HWDP ZN-50 -> *All XT-## Drill Pipe and HWDP Connections 2. API Casing Threads: Jet Lube Run and Seal Arctic 4 Surface Casing: 72# L80 Buttress Casing Only Shipped from the mill with Kendex Storage Compound on the pin end, wipe this off thoroughly prior to applying Just Lube Run and Seal Arctic 3. Hydril Threads: Jet Lube Seal Guard ECF -> All Hydril Casing, Liner and Tubing Threads • Hydril connections are shipped with Jet Lube Seal Guard ECF already applied and are "Rig Ready". • Wipe the box ends down with a clean cloth prior to running. 51 Page H04_ Well Plan for APD Package IueC.fest Energy Project Overview Structure Cosmopolitan Project H04_ Well Plan The Hansen Field (hereinafter referred to as Cosmopolitan or Cosmopolitan project) structure is a NE/SW doubly plunging asymmetric anticline bounded along its west flank by a high angle reverse fault that strikes parallel to the structural axis. Associated tear faults with normal throw cut the northern and southern portions of the feature and one smaller fault was found in the Cosmopolitan State #1. This structure, which is four and one-half miles by 2 miles in size, has approximately 600 feet of vertical closure over an area of over 6,000 acres at the Starichkof sand (Lower Tyonek sandstone just above the Hemlock Conglomerate). Structural control includes six wellbores, (three of these are vertical and penetrate the entire geological section on the structure and three are extended reach wells drilled from the Hansen shore -side drilling pad) 3D seismic acquired by Pioneer Resources in 2005, dip meter data in two of the vertical wells, and migrated 2D high resolution seismic data acquired by GeoTek Alaska, Inc. in 2013. 3D seismic data was used to tie all of the wells to generate several levels of structure maps (see the following discussion on seismic data and interpretation). Although there is a .3 to .5 second seafloor reverberation on the 3D data, the shallow high resolution Geo -Hazard 2D seismic shows that the structure is typical of parallel folding. Stratigraphy Approximately 8,600 feet of Tertiary age Kenai Group non -marine sedimentary rocks are present at Cosmopolitan. The Kenai Group is represented here by approximately 1,000 feet of the Beluga Formation (USGS unpublished data) characterized by thin bedded sandstones, coals, siltstone and silty shale intervals that were deposited in a braided stream environment. Based on estimates from seismic data and log correlation approximately 1,050 feet of Beluga was penetrated in the Starichkof State Unit #1 well, about 500 feet was present in the Starichkof State #1 and it appears to be missing in the Cosmopolitan State #1 well. The difference in thickness in the Beluga across the Cosmopolitan structure is related to erosion and does not represent depositional thinning. The overlying Sterling Formation is not present and has also been removed by erosion. Unconformity underlying the Beluga sequence is 5,945 feet of Miocene age Tyonek Formation, a basin wide series of fluvial conglomerate, conglomeratic sandstone, sandstone, coal, siltstone and shale which represent deposition in meandering streams, associated fluvial sediments and lacustrine environments. It is a major producer of both biogenic natural gas and thermogenic oil throughout the basin and is charged with gas and oil at Cosmopolitan. BlueCrest Energy, Inc. has informally divided the Tyonek into an upper section that contains gas productive sandstones and a lower interval that is predominately oil prone. The two zones are separated by a laterally correlative shale section that is easily recognized in all of the existing wells. The lowest section of the Lower Tyonek, from 6,742 to 7,104 feet MD has been referred to as the "Starichkof" sand by Conoco/Phillips, Pioneer Resources and by BlueCrest Energy, Inc. and is the oil discovery zone found in 1967 by Pennzoil in their Starichkof State #1 well. Immediately underlying the Starichkof sand (Lower Tyonek) is the Oligocene Hemlock Conglomerate. It was drill stem tested in the Starichkof State #1 well and recovered brackish water from two separate intervals beneath the 6 1 P a g e H04_ Well Plan for APD Package IueC.iest Energy Cosmopolitan Project H04_ Well Plan oil/water contact at approximately -7030 ft. Conoco/Phillips tested water free oil in higher structural positions in both the Hansen 1 and Hansen 1A wells. The Hemlock generally consists of medium to coarse grained, thick bedded sandstone with substantial conglomeratic beds and lenses. In the Starichkof State #1 well it is 485 feet thick, and in the Cosmopolitan State #1 it is 500 feet thick. Underlying the Hemlock is the Paleocene to Eocene age West Foreland Formation, a 1,155 feet thick sequence of volcanic tuffs and volcanoclastic sandstone and siltstone devoid of oil or gas shows and without reservoir quality rocks. The West Foreland unconformably overlies the Upper Cretaceous marine Matanuska Formation that is at least 3,339 feet of shale containing an abundance of Inoceramus shell fragments. 71 Page H04_ Well Plan for APD Package lust Energy Well Overview Cosmopolitan Project H04_ Well Plan Well Schematic Section Review Geologic Hazards 81 Page H04_ Well Plan for APD Package lue est Energy Well Schematic r Cosmopolitan Project H04_ Well Plan d � M� m Q 11 r 9 1 P a g e H04_ Well Plan for APD Package 0 C a c m C r Cosmopolitan Project H04_ Well Plan d � M� m Q 11 r 9 1 P a g e H04_ Well Plan for APD Package lust Cosmopolitan Project Energy Hoo Well Plan Section Review Last Updated: TVM. 03 Oct 2018 HO4 Fishbone Production Well (Main Bore I Lower Lateral I Slarichkof f Hemlock Primary Target) '193' MDITVD Orilkdin Bit: 17-V2" POC Bit OEM MWD: Telescope 6.112" Un -cemented 3.112" Production Tubing to Surface LVD: GeoSpheie Open Hole ; Slotted Liner 12.0 ppg Lead RSS: PDX6 GLM's I SSSV I OH Gauges I CI L�Un-Cemented Slotted Liner Completion Max Ind 104 deg Bit: 12-V4" PDC 715 bbls WBM MWD: PowerPulse OEM RSS: Xceed 675 12-14" 25/Excess 9.8-10.0 ppg Sp LVD: arcVISION (GRIRES) 17-172" —_—__----___ TOC @ 13.981'MD Top of Tail 4,623' M Open Hole 15.8 ppg Class G Tail '1� 15.8 ppg Class 15o��f' 167 bbls 50% Excess 25% Excess Incl GS di Bit: 8.112" POC RSS: Xceed 675 i OEM MWD: Telescope 6.112" Un -cemented 3.112" Production Tubing to Surface LVD: GeoSpheie Open Hole ; Slotted Liner adnVISION No Frac's ( I 4-112"15.2111 P110 H593 Slotted Liner GLM's I SSSV I OH Gauges I CI L�Un-Cemented Slotted Liner Completion Max Ind 104 deg Bit: 12-V4" PDC OEM RSS: Xceed 675 12-14" 10.5 ppg VersaPro MWD PowerPulse Open Hole —_—__----___ TOC @ 13.981'MD LVD: dreVISION(GRiRES) '1� 15.8 ppg Class 15o��f' 132 bb1s 50% Excess fo Liner Hgr h Liner Top Packer Incl 77 deg Bit: 8.112" POC RSS: Xceed 675 i OEM MWD: Telescope 6.112" Un -cemented 8.6.9.7 ppg VersaP LVD: GeoSpheie Open Hole ; Slotted Liner adnVISION No Frac's ( I 4-112"15.2111 P110 H593 Slotted Liner L�Un-Cemented Slotted Liner Completion Max Ind 104 deg 101Page H04_ Well Plan for APD Package Iue, Nest Energy Geologic Hazards 17-%" Hole Section 13-%" Casing Cosmopolitan Project H04_ Well Plan Event Risk Level Mitigation Strategy Clay Balling Maintain planned mud parameters, Increase mud weight, use Lost Circulation Low weighted sweeps, reduce fluid viscosity, control ROP. Abnormal Pressure in Low Diverter drills, increased mud weight. Surface Formations Reduced trip speeds, mud properties, proper hole filling, real Directional Control ✓it- BHA design, on -sight geologic review, avoid "drilling the line". trips Reduced pump rates, mud rheology, lost circulation material, use Lost Circulation Low of low density cement slurries, control running speeds. 12-Y" Hole Section / 9-Y" Casing Event Risk Level Mitigation Strategy Reduced pump rates, reduced trip speeds, real time equivalent Lost Circulation Low circulating density (ECD) monitoring, mud rheology, Pre -planned LCM pills, lost circulation material. Hole swabbing on Reduced trip speeds, mud properties, proper hole filling, real Low time equivalent circulating density (ECD) monitoring, weighted trips sweeps. Directional Control Low Increased mud density and fluid composition according to plan, Sloughing Coals, Low controlled trip speeds, ECD monitoring, optimized hydraulics for Tight Hole hole cleaning. Abnormal Reservoir Low Well control drills, increased mud weight. Pressure practices, mud scavengers. Hydrogen Sulfide Gas Low HZS drills, detection systems, alarms, standard well control practices, mud scavengers. 8-%" Hole Section / 4-%" Slotted Liner Event Risk Level Mitigation Strategy Fluid density according to plan, reduced pump rates, reduced trip Lost Circulation Low speeds, real time equivalent circulating density (ECD) monitoring, mud rheology, lost circulation material. Hole swabbing on Reduced trip speeds, mud properties, proper hole filling, real Low time equivalent circulating density (ECD) monitoring, weighted trips sweeps. Directional Control Low BHA design, on -sight geologic review. Abnormal Reservoir Low Well control drills, increased mud weight. Pressure Hydrogen Sulfide Gas Low HzS drills, detection systems, alarms, standard well control practices, mud scavengers. 111 Page H04_ Well Plan for APD Package nue esr Energy Pre -Rig Operations Cosmopolitan Project H04_ Well Plan Conductor & Cellar Installation 121Page Fa G4_ Wel Plan for APD Package lu6 eCiest Energy Conductor/ Cellar Installation (will be completed for H04 slot) Operations Cosmopolitan Project H04_ Well Plan 1. 20" Conductor will be preset via Kraxberger Drilling via theirdual rotary drillin ri to a depth of 152' BGL Conductor Pipe: 20", 0.500" Wall, A252 ERW Welde • The conductor is NOT cemented to surface • Cut off at 1' above ground level 2. Confirm that the identification markings on the conductor match the planned surface location with the "as - built survey." If identification markings are not present on the conductor, contact the Drilling Supt. prior to moving the rig onto the well. • Each conductor is to be marked with a common pad elevation survey mark by the surveyors. Surveyors to also mark each conductor with a degree of angle to set each tree. 3. A 10' x 10' x 8' well cellar was installed and the 20" conductor cutoff 60" below ground level. • The additional stick up is to allow GE Oil & Gas to make a clean cut on the conductor prior to installing the 20" landing ring 4 Final top of conductor to be 71-1/4" BGL. ✓ • Verify that the access ladder is located to the South. • Ensure the conductor plate is installed and welded around the 20" conductor. 4. Verify that two 3" threaded nipples have been welded on the conductor on opposite sides. Include ball valves and Cam -Lock male fittings on each nipple. Ensure threaded ball valves can be installed without running into the OD of the diverter head. Nipples are to be used as follows: • Assist in washing out surface casing hanger on cement jobs • Take returns to Vac trucks while cementing • Provide access to annulus for top job through small diameter tubing If these valves are not currently installed contact GE Oil & Gas Representative to have them installed • Kevin Krause — Lead Service Manager • Kevin. Kra use@ge.com -> Cell: 907-398-9995 131 Page H04_ Well Plan for APD Package lueC.iest Cosmopolitan Project Energy H04 Well Plan MIRU MIRU Operations Diverter Installation 141Page 11,V Vise ; Plan for APD Package nue st Energy Cosmopolitan Project H04_ Well Plan MIRU Operations 1. MIRU BlueCrest #1 over preinstalled 20" conductor casing set at -152' BGL. 2. Move in and rig up. Record move distance and rig floor distance to pad and sea level in Daily Report and on IADC reports. • Ensure all concerned parties (Directional Drillers, MWD Operators, and Geologists) are using the same rig floor elevation. 3. Post drilling permit in the rig office and company office. Diverter Installation (NOTE: A Diverter Waiver has been requested from the AOGCC) /�/S/hl� 1. Secure 13-3/8" landing ring on 20" conductor with lock down screws. • 20" Landing Ring ID: 17.62" 2. Nipple up VetcoGray starter head and test the lower seals. • DO NOT Exceed 500 psi. 3. Install 21-1/4"x 2000 psi diverter and riser equipment with 18" outlet line. • Ensure diverter is run in accordance with the specified diverter diagrams attached. • The 18" line extends straight out 80 feet from well center. 4. Place slop tank under the end of the diverter line. 5. Function test the diverter to verify the valve on the diverter line opens BEFORE the annular fully closes. • Give AOGCC 48-hour notice to witness test. • The diverter control system must open the side outlet valve and close the diverter element within 45 seconds for this size of diverter. • Fill diverter & riser with water to check for leaks. 4 Record on IADC drilling report. -> Hold diverter and rig abandonment drill prior to drilling surface hole. 6. Make sure the 3" outlets on the 20" conductor have valves and connections for taking mud returns. Diverter lines to be as straight as possible. • Ensure "Warning Zone - ON DIVERTER" and rig well signs are spotted correctly on location. 151Page H04_ Well Plan for APD Package lye st Energy Drilling Cosmopolitan Project H04_ Well Plan Surface Intermediate Production 161 Page H04_ Well Plan for APD Package llue est Energy Surface Overview Cosmopolitan Project H04_ Well Plan 17.5 13.375 9.8-10.0 Spud Mud RSS PDC 5,623' 3,531' 690 Fluids Gel Spud Mud 9.8-10.0 r 150' 5,623' 14-17 NC <2,000 8.5-9.5 *Allow fluid to weight up naturally — Do not exceed 10.0 ppg BNA Min Max RSS 8.25" PD X6 PowerPulse GR/Res 600 1200 Bit Smith PDC MSi 619 6 x 12, 3 x 13 1.052 General Notes • Prior to spud, a safety meeting will be held with the rig crews to discuss open hole drilling procedures. Suggested topics include: o Conductor broaching operations and contingencies o Well control procedures and rig evacuation procedures o Flow rates and hole cleaning • The area around the conductor should be continuously monitored during drilling, circulating, and cementing operations. o If broaching occurs, stop drilling immediately. Contact the AOGCC field inspector and the Drilling Superintendent to inform them of the broach. • Efforts should be made to minimize high doglegs in surface hole. o Inform the Drilling Engineer of any doglegs over 5 degrees per hundred. • Ported float valves are required in all hole sections. • Conduct 13-3/8" Casing dummy run prior to drilling out conductor. 171 Page H04_ Well Plan for APD Package luel.fest Energy Drilling Procedure (17-1/2" Surface Section) 1. Ensure 13-3/8" Casing dummy run has been conducted prior to drilling out conductor. 2. Pickup and drift all DP, HWDP, and DC's for surface section to confirm free of debris. 3. PU BHA • Bit: 17 %" Smith PDC Re -Run from H14 and H12 4 TFA: 1.052 (3 x 18, 1 x 20) --> PD1100X6 4. Directionally drill 17-1/2" surface hole: Drilling Parameters: --> Flow Rate: 850+ GPM 4 Rotary: 120+ RPM Cosmopolitan Project H04_ Well Plan • Lower flow rates of 450-600 GPM will help avoid anti -collision boundaries by minimizing hole washout and optimize dog leg capability in the build section. Keep in mind that lower flow rates below the tool threshold may pose difficulty steering. A backup motor is on location in the event that steering becomes an issue. • Avoid anti -collision boundaries • Take MWD surveys as frequently as needed. Carefully review the anticipated close crossings with existing wellbores. Make sure that directional drillers are aware of all drilling close crossing issues, hardlines and no-go lines. If a no-go or hardline has been or will be crossed, stop drilling immediately and contact the Drilling Engineer to discuss options. 5. Hole conditions will always determine final mud properties. 6. Surface casing point: • Land in good shale found between 3,115'- 3,350' TVDss. • Circulate bottom hole samples to verify shale, confirm with wellsite geologist. • DO NOT set in coal, if coal is encountered drill another 20' MD. Drill the hole to fit casing, if possible, to reduce pup joints in the string. Leave approx 10' rathole. 7. Circulate the hole clean per K&M and POOH on elevators. 8. If BROOH is required, contact Drilling Engineer prior to commencing: • Circulate until shakers are clean per K&M. Backream one (1) stand per bottoms up very slowly. -> 900+ GPM 4 120+ RPM • BROOH at full drilling parameters, 3-5 min per stand. NOTE: • Backreaming speed will be dictated by hole conditions. Consult with K&M prior to increasing pulling speed. • Decrease backreaming speed as torque and pump pressure dictate. • Once backreaming in the open hole has been started, DO NOT stop backreaming until the HWDP. • DO NOT attempt to pull out on elevators once backreaming has started. 9. If shakers/mud return system becomes overloaded and flow rate is cut to handle the issue, DO NOT continue to backream until the parameters are brought back to full backreaming rate. 10. Once the HWDP is reached, circulate until hole is clean per K&M 11. Pull and lay down BHA. 181 Page H04_ Well Plan for APD Package lutf e('iesr Energy 12. Perform a dummy hanger run before running casing, if not already conducted. Casing Program Cosmopolitan Project H04_ Well Plan 13.375 12.347 72 L-80 BTC 12.25 2,670 5,380 1,661,000 Connection Make Up Operational Limit in. in. in. ft -lbs. 14.375 12.335 10.825 Casing Running Notes ft -lbs. ft -lbs. ft -lbs. ft -lbs. Average 10 to the Diamond Perform dummy run prior to running casing, if not already conducted. • Surface casing will be set on mandrel hanger. • Any packing off while running casing, should be treated as a very serious problem if major returns are lost. o It is preferable to pull casing out until circulation can be re-established rather than risk not getting cement to surface. Contact the Drilling Superintendent if the casing packs off high for discussion of the options. • Have Vetco representative verify the correct casing hanger is on location prior to running surface casing. • Torque values for the BTC casing are determined at the rig by making up the connection to the make-up mark (base of triangle). Record torque values for the first 10 connections made up in this manner and average. This average will be used as the make-up torque for the remainder of the string. • Utilize Volant Casing Running tool for make-up and fill up. 191 Page H04_ Well Plan for APD Package lNesr Energy Cosmopolitan Project H04_ Well Plan Running Procedure 1. Inspect and drift all surface casing to 12.25". 2. While RIH with the Casing: Obtain SO Weights per K&M every joint DO NOT take PU weights IF IT IS NECESSARY TO PICK UP THE STRING ENSURE THAT THE PUMPS ARE ON TO REDUCE SWAB LOADS 3. Run the surface casing as follows: Float shoe BakerLok 2joints 13-3/8" 72# L-80 BTC casing BakerLok Float Collar BakerLok 13-3/8" 72# L-80 BTC casing 13-3/8" 72# L-80 BTC casing to hanger VetcoGray 13-3/8" mandrel hanger 13-3/8" landing joint Centralizer Placement +/-18 13-3/8" x 17-1/2" VariForm Weatherford 201 Page H04_, Well Plan for APD Package nue est Energy 13-3/8" x 17-1/2" VariForm Centralizer 1. One (1) — 5' Above Float Shoe 2. One (1) — 8' Above Float Shoe 3. No Centralization on 2"d Joint 4. One (1) —10' Above the Float Collar 5. From 3`d Joint Through Tail Slurry (500') o One (1) Each per Joint o Center of Joint 6. Two (2) — Center of Joint Inside Conductor ALL CENTRALIZERS TO BE RUN ON STOP COLLARS 4) T Cosmopolitan Project H04_ Well Plan 211 Page H04_ Well Plan for APD Package lue est Cosmopolitan Project Energy H04 Well Plan Cementing Mud Push II 80 bbl. Density: 11.0 ppg N/A 17-1/2" 13-3/8" Kenai Surface Lead 715 bbl. ✓ Density: 12.03ppg 25% Yield: 2.44 ft /sk Kenai Suface Tail 167 bbl. ✓ Density: 15.8ppg 25% Top of Tail @ 4,623 MD Yield: 1.22 ft3/sk Cementing Notes • Obtain and review the Test Report from the cementing lab on the job blend prior to pumping the cement. DO NOT pump cement if there are any doubts as to cement quality, quantities, pumping times, or thickening times. • Ensure that enough cement retarder is built to keep cement from setting up prior to disposal. • OUTLINE CEMENTING TRUCKS NEEDED, TYPE OF RETARDER, ETC... Cementing Procedure 1. After reaching bottom, rig up and circulate with casing on bottom at 5 bpm, if possible, without losing returns. Reduce mud viscosity prior to pumping cement if necessary. • To help ensure good cement to surface after running the casing, and if practical for existing hole conditions, condition mud to YP < 20 Ib/100ft' prior to cementing the casing but after the casing is on bottom. Have adequate supply of cold water on hand to ensure the desired rheologies can be achieved. 2. Rig up to cement and pressure test cement lines. 3. Pump Mud Push Spacer. Shut down and drop bottom plug. 4. Pump cement job per the Schlumberger cementing plan. Cement volumes are based on 10% excess since too much cement was pumped on the H16 and H14 surface casing cement jobs. 5. Report the number of bbls of cement returned to surface: • Task one person to be in charge of monitoring for cement returns and volume of cement returns • Recommend that a dye or small amount of cello -flake be added to the wash or spacer to give an indication of top of cement. 6. Drop top plug after the tail slurry. 7. Pump displacement at 8.5 bpm maximum. 8. Drop circulation rate 3 BPM for last 20 bbls of displacement prior to bumping plug. 9. Pump until the plug bumps and then pressure up to 500 psi above Final Circulating Pressure (FCP) to ensure the plug has landed. If floats do not hold, maintain FCP on casing and shut in cement head for a minimum of 6 hours before rechecking. • Do not over displace the cement (Pump NO MORE than y2 the shoe joint volume). • Watch for signs of packing -off during pumping operations and closely monitor the cellar area for mud or cement returns around the conductor. 221 Page H04_ Well Plan for APD Package nue st Energy Cosmopolitan Project H04_ Well Plan AOGCC and Drilling Superintendent must be contacted prior to beginning a top job using 1" pipe. Do not proceed with top job without AOGCC approval. 7 • Establish circulation and continue until pumping secondary cement job through 1" pipe. • Pump top cement job until cement is seen at surface. • Cut off and leave 1" pipe in well. 30. Drain and wash cement from riser. Nipple down riser and flush all lines. 11. Nipple up Vetco Gray Well Head, orienting the well head valves as indicated on the conductor markings. • If there is any doubt about the proper orientation, call the Drilling Superintendent. • Ensure that the seal between the casing hanger and well head is tested to 5,000 psi for 10 minutes. • Measure the distance from the rig floor to the top flange of the well head and record on the [ADC and Daily Report. Complete the Rig Elevation Record, send to Drilling Engineer, and place it in the electronic well folder. 12. Nipple up the 13-5/8" 10M BOP stack, and test per the AOGCC Permit to Drill (attached). • Notify AOGCC 24 hours prior to performing BOP test. • Do not test BOPE against casing. • Test rams and choke manifold components to 3500 psi high / 250 psi low • Test annular preventer to 2500 psi high / 250 psi low —> PERMIT TO DRILL BOP testing frequency: Every 14 days unless noted otherwise by AOGCC ✓ 231 Page H04_ Well Plan for APD Package due est Energy Intermediate Overview Cosmopolitan Project H04_ Well Plan 12.25 9.625 RSS PDC ACTIMUL RD 10.50 15,481' 7,067' 77° • Mud Fluid Type Weigh From To ACTIMUL RD 10.50 5,623' 15,481' 13-15 Nominal Type Size RSS 8.25" Make PD Xceed PDC ml/30 min <5 ��IMIIIIIII Min Telescope arcVISION ' 600 X716 10 x 14 80:20 mlvolts >600 Max 1200 1.503 General Notes Shallow test MWD tools.' • Monitor hole conditions carefully. Be alert for early signs of lost circulation and differential sticking. If any of these problems are observed immediately notify the Drilling Supervisor or Toolpusher (attempt to keep the pipe moving and circulation established). • If cavings are noted at surface pictures shall be taken to clearly identify cavings structure and geometry. • Ensure that all team members are communicating with each other on any observed drilling trends and that everyone understands the potential risks. Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand or coal sections for any extended period of time. • Keep shut down times to a minimum during connections. • Swab / Surge: Make "easy on, easy off' slips a standard practice Ensure the Top Drive Torque Limit is set below the lowest make up torque in the string. Do not run the risk of further make up downhole while drilling. Contact the Drilling Engineer prior to commencing back reaming at any point while drilling the well. 241 Page H04_ Well Plan for APD Package lueC.fest Cosmopolitan Project Energy H04 Well Plan Drill Out Procedure (13-3/8" Casing) 13. Install wear bushing 14. Pick up and drift all DP, HWDP, and DC's for surface section to confirm free of debris. 15. PU drill out BHA • Bit: 12-1/4" Mill Tooth • TFA: 0.994 (4 x 18) • Dumb Iron Assembly 4 NOTE: Discuss with Office omitting this step and drill out with C bit and BHA to be used to drill the 12-1/4" section. �1111 16. TIH to top of float equipment and pressure test surface casing to 3,09"si for 30 min. Chart and record same. • Plot casing pressure test on LOT form and submit to Drilling Engineer • Verify the test indicates a linear line and there is no air entrained in the mud. Repeat casing pressure test if needed to achieve a linear line plot. 17. Drill out float collar and shoe. • Take note of any green cement or lack of necessary WOB to drill out shoe track. • If no cement or green cement is encountered DO NOT drill out the shoe. 4 Call drilling superintendent prior to continuing operations. 18. Clean out rat hole and POOH on elevators & LD drill out BHA. 19. PU Drilling BHA • 12-1/4" X716 PDC • TFA: 1.503 (10 x 14) • PD Xceed RSS BHA 20. Shallow test MWD/LWD tools. RIH to TD. 21. Displace new hole to 10.50 ppg VersaPro OBM. 22. Drill 20' of new formation, below the rat hole, with VersaPro OBM. Circulate OBM until hole clean and balanced. NOTE: discuss with office the option to conduct the FIT before swapping to the OBM. 23. POOH to surface casing shoe and perform FIT per AOGCC requirements following the attached LOT procedure: l Required FIT: 13.00` p)_MW 4 Recorded LOT/FIT pressures shall follow the format below: I. EMW = Ps"'fa" + MW 0.052•(TVD) II. 13.0 ppg EMW FIT/LOT w/459 psi and 10.5 ppg MW @ 3,531' TVD -> Offset Hansen 1: 13.00 ppg EMW FIT w/ 540 psi and 9.9 ppg MW @ 3,349' TVD • All data shall be recorded on the provided "BlueCrest Casing/FIT/LOT Form". • Pressure test is to be taken to leak off but not to exceed 1,000 psi surface pressure. • If LOT is below 13.00 ppg EMW, contact Drilling Superintended prior to drilling ahead. • NOTE: casing pressure test linear line and FIT pressure test line should be closely parallel to each other. • NOTE: Notify AOGCC if any aspect of the FIT is considered to be unusual or not as expected. 251 Page H04_ Well Plan for APD Package IueC.iesr Energy Cosmopolitan Project H04- Well Plan Drilling Procedure (12-1/4" Section) 1. Directionally drill intermediate hole: • Drilling Parameters: -> Flow Rate: 900+ GPM 4 Rotary: 120+ RPM • PU and Slack -off Weights will be taken EVERY stand Per K&M • Follow Recommended Connection Practices • Avoid anti -collision boundaries • Take MWD surveys as frequently as needed maintaining at least 1 survey per stand. Carefully review the anticipated close crossings with existing wellbores. Make sure that directional drillers are aware of all drilling close crossing issues, hardlines and no-go lines. 4 If a no-go or hardline has been or will be crossed, stop drilling immediately and contact the Drilling Superintendent to discuss options. NOTE: COAL DRILLING PRACTICES • Drill coal seams slowly to avoid allowing large chunks from entering the wellbore • Monitor ROP, torque and pump pressure for signs of drilling into a new seam. o Coals tend to drill fast with low WOB and low torque o Torque spikes may indicate sticking pipe and the bit o Drill 1'-3', pick up off bottom above coal o Circulate/rotate above the coal before continuing to drill o Continue drilling at 2'-5' intervals, pulling above to circulate • Use ECD management techniques to minimize cycling the formation o Use high angle tripping practices (STOP, DROP & ROLL) to avoid packing off o Slowly bring pumps on after connections or breaking circulation. Rotate first to break gel strength. Stage into the hold to shear gels. Control trip speeds to manage surge/swab loads. o Maintain "thin" low end rheology and gels o DO NOT PUMP SWEEPS o DO NOT CONDUCT WIPER TRIPS • Maintain a broad particle size distribution (PSD) of bridging agents in the mud o Increasing mud weight will prevent coals from destabilizing, but only if the mud is able to seal the fractures. Stop, Drop & Roll • Stop - When coming out of the hole if overpull is encountered DO NOT KICK PUMPS ON! • Drop - Run back into the hole 3-5 stands or area where the pipe was last free. • Roll - Initiate rotation and bring the pump up slowly to full circulating rate. Clean the hole at full rotary and circulating rate prior to commencing tripping operations. • CHECK -Pullback through area of overpull & monitor PU weight. 261 Page H04_ Well Plan for APD Package IueC fest Energy Cosmopolitan Project H04_ Well Plan 2. Intermediate casing point: • Land within the Starichkof Sand, as directed and confirmed by Operations Geologist. TD will be a minimum of 400' past the base of the shale marker (Top of Starichkof) 4 This well may be sidetracked in the future, enough room needs to be made for the rathole ("'15'), liner overlap (^'150') and whipstock offset (^'150') while remaining below the coal above the Starichkof. 3. Circulate until shakers are clean per K&M. Backream one (1) stand per bottoms up very slowly while circulating clean at full drilling parameters. 4 900+GPM 4 120+ RPM 4. Attempt to POOH on elevators. 5. If tight hole is encountered, TIH 3 stands and circulate shakers clean. Attempt to trip back through depth of tight hole: • If tight hole is still encountered, ream the section clean, and confirm it is free of obstruction prior to continuing to POOH. • If area is free continue to POOH on elevators making sure monitor drag trends for signs of excessive over pull. 6. If the hole is swabbing or reoccurring issues are encountered while POOH, BROOH to the surface casing shoe. • Contact Drilling Engineer prior to commencing back reaming operations at any point in the well • BROOH at full drilling parameters 4 900+ GPM 4 120+ RPM NOTE: • Backreaming speed will be dictated by hole conditions. Consult with K&M prior to increasing pulling speed. • Decrease backreaming speed as torque and pump pressure dictate. • Once backreaming in the open hole has been started, DO NOT stop backreaming until the surface casing shoe. DO NOT attempt to pull out on elevators once backreaming has started until the shoe has been reached and sufficiently cleaned. • If shakers/mud return system becomes overloaded and flow rate needs to be reduced, DO NOT continue to BROOH until the parameters are brought back to full backreaming rate. 7. Circulate the hole clean per K&M 8. POOH on elevators. 9. Pull and lay down BHA. 10. Perform a dummy hanger run before running casing, if not already completed. i v 271 Page H04_ Well Plan for APD Package due est Energy Casing Program Cosmopolitan Project H04_ Well Plan in. 9.625 in. lbs. -- 8.681 47 P-110 in. psi H563 8.525 5,300 psi lbs. 9,440 1 1,493,( Pipe Connection I Make Up ational Limit Ibl in. in. in. ft -lbs. ft-Ibs. ft -lbs. ft -lbs. ft -lbs. 47 10.625 8.681 9.25 13,200 15,800 23,000 69,000 103,000 Casing Running Notes • Perform dummy run prior to running casing o A slick landing joint will be utilized. • Intermediate casing will be landed on emergency casing slips. o Verify the modified wear ring is installed prior to running casing. • Have Vetco representative verify the correct emergency slips are on location prior to running in the hole. • Utilize Volant CRTi Tool for running, fill up and circulation. • Have a spare shoe track on location prior to running casing. • Ensure the casing run is modeled with actual wellbore conditions (i.e. actual survey, active mud weights, depths, etc...) • Surge modeling shall be agreed upon by K&M and Drilling Engineer to determine safe running speeds to prevent/ minimize potential losses. • Have an assortment of 9-%" pup joints available for space out when setting casing on depth • Ensure that a copy of the LWD logs with details of known tight spots, problem areas, doglegs, KOP's, and a theoretical drag chart with potential decision points identified for the casing run, is available on the rig floor. 281 Page H04_ Well Plan for APD Package nue est Energy Casing Running Order Float shoe 2 joints 9-5/8" 47# P-110 Hydril 563 Casing Float Collar 9-5/8" 47# P-110 Hydril 563 Casing to surface 9-5/8" landing joint Centralizer Placement Cosmopolitan Project H04_ Well Plan Bakerlok Bakerlok Bakerlok Take note that this is 47# P-110 Hydril 563 Slick landing joint +/-38 9-5/8" x 12" VariForm Weatherford Pre -Run 1. Confirm 12" OD (slightly less than 12-1/4" gauge hole) Weatherford Variform centralizers are on location and attached to pipe prior to loading the in the shed. 2. Inspect and drift all surface casing to 8.500". • This is to be done AFTER centralizers are crimped to casing. --) The crimping tool can affect the inner diameter. 3. Pull wear bushing. Install test plug. Then install 9-5/8" casing rams and test same. Pull test plug. 4. Install modified wear ring. • To protect hangers if casing needs to be rotated while running. • Wear bushing is short enough to not extend past studs when the wellhead is broken when emergency slips are set. • ID should be the same as the actual drilling wear bushing. 5. Perform dummy run with 9-5/8" slick landing joint, confirm and record length to break. • Casing will be set on emergency slips. _� 6. Ensure a spare float shoe and collar made up with centralizers is on location as backup. 7. Ensure the 9-5/8" floor valve or "kill sub", comprised of a TIW valve crossed over to 9-5/8" Hydril 563 is on the rig floor. Function valve and leave in the open position. 291 Page H04_ Well Plan for APD Package lye st Energy 9-5/8" x 12" Weatherford Variform Centralizer 1. One (1) — 5' Above Float Shoe o Floating between stop collar and float shoe 2. No Centralization on 2'd Joint 3. One (1) —10' Above the Float Collar o Floating Between Stop Collar and Float Collar 4. From 3rd Joint Through Top of Cement o One (1) Each per Joint 0 o Crimped +/- 3' From Pin End ALL CENTRALIZERS WITH STOP RING +/- 3' FROM PIN END UNLESS STATED OTHERWISE Cosmopolitan Project H04_ Well Plan 301 Page H04_ Well Plan for APD Package lueC,lest Energy Cosmopolitan Project H04_ Well Plan Running Procedure 1. Bring Volant CRTi Tool to the rig floor and rig up same. 2. Pickup the shoe track and makeup by hand using chain tongs until enough weight is in the slips to prevent cross threading. • The shoe track is to be BakerLok'd • Inspect the float valves as the shoe track is picked up 3. Run the shoe track into the well and confirm the floats are holding negative pressure. 4. Run the first 10 joints using chain tongs. 5. Continue running in the hole utilizing the Volant CRTi Tool. While TIH with Casing: • Fill every joint. • Obtain SO Weights Every Joint per K&M • DO NOT take PU weights. DO NOT POOH without the pumps on. • This data shall be plotted against theoretical curves in real-time to determine SO friction factors (SOFF's) and allow pro -active decisions to be made. • If there are distinct divergences from theoretical lines or changes in the friction factor, an attempt should be made to document the causes (e.g. ledges, change in formation, doglegs, etc.) • If the casing will not pass an obstruction, rotation should be discussed in an attempt to work the string down o DO NOT attempt to rotate the casing until the expected torque values are modeled to determine is casing rotation is possible as the string will be full. Contact Drilling Engineer immediately if problems are encountered while TIH. 6. Prepare to land the casing on bottom • Ensure adequate rathole is allowed below shoe and free pickup weight of casing is observed. • 10' rathole 7. Makeup slick Landing Joint 8. Open 350 ton air slips and slide them out of the way. 9. Slack off and land casing using the hand slips. • Leave 4'-5' of casing stick up above hand slips. • Use rotary hand slips and bushings type: Bushings API #2 and Slips CMS XL. • Take care to ensure that there are no couplings across the casing rams once the casing is on depth. 10. Break circulation at Y2 bpm assessing losses if any, this will allow any "clabbered up" or cold mud to be circulated out prior to stepping up the rate. 11. After at''/= bpm without any issues/ losses, then step up the rate gradually to 8 bpm. • If losses are encountered contact the Drilling Engineer immediately. 12. CBU 3.5 (estimate Final YP < 20) • If needed, circulate and thin mud to properties slightly as outlined in CemCADE and Mud plan summary prior to pumping cement. 311Page H04_ Well Plan for APD Package nue / &68Y Cosmopolitan Project H04_ Well Plan NOTE: As a reminder, the following aspects of the cement job will be "different" than a normal job: • The casing will not be reciprocated or rotated once at TD. • After cementing the casing, the pipe will be pulled into tension and then landed using the mandrel hanger. Cementing Mud Push II 100 bbl. Density: 11.8 ppg N/A 12-1/4" 9-5/8" Class "G"— Density: 15.8 ppg Top of Cement @ 13,981' MD 132 bbl. Yield: 1.16 ft3/sk 50% Cementing Notes • Obtain and review the UCA Compressive Strength Test Report on the job blend from the cementing lab at least 24 hours prior to pumping the cement. DO NOT pump cement if there are any doubts as to cement quality, quantities, pumping times, or thickening times. • DO NOT over displace more than half the shoe track volume if plugs do not bump on strokes. • Perform rig pump efficiency check prior to pumping and displacing cement. • Check cement calculations with SLB and Drilling Engineer. Cementing Procedure 1. Rig up to cement and pressure test cement lines per Schlumberger. 2. Pump Mud Push Spacer. Shut down and drop bottom plug. 3. Pump cement job per the attached Schlumberger cementing plan. • Cement volumes are based on 50% excess and at least 500' TVD above the intermediate casing shoe. 4. Drop top plug and cleanup on top. • Ensure to capture cleanup volumes when calculating necessary displacement volumes. 5. Pump displacement at 8.0 bpm maximum. • Drop circulation rate to 3 BPM for last 20 bbls of displacement prior to bumping plug. 6. Bump plugs and pressure up to 500 psi above Final Circulating Pressure (FCP) to ensure the plug has landed. • If floats do not hold, maintain FCP on casing and shut in cement head for a minimum of 6 hours before rechecking. • Do not over displace 4 Pump NO MORE than Y2 the shoe track volume if plugs do not bump on calculated strokes. 7. Wait on cement to setup per Schlumberger UCA minimum required compressive strength time requirement prior to nippling down BOPE and setting emergency slips. • 500 psi compressive strength minimum. 321Page H04_ Well Plan for APD Package lue est Energy Cosmopolitan Project H04_ Well Plan Prior to Lifting The BOP Stack 1. P/U 1 stand of 5" drill pipe make up 8' pup and floor valve (closed). Run stand inside casing all the way down to the elevators, this will displace the mud from the casing down to the wellhead then pull the stand and rack it back. This allows for a "dry" casing cut saving time and eliminating having to clean mud out of the well bay. 2. Remove the flow line and choke & kill lines. 3. Radio communication is required for those in the cellar and on the rig floor. • Also ensure that radio channel is clear to only those involved in the cellar, rig floor, and sub -base. 4. Ensure that Vetco Gray/ and one floor hand is in the cellar with a radio prior to lifting the stack to measure amount of travel to provide enough room to install the emergency slips and casing cutting tool. While Lifting the BOP Stack and Setting the Emergency Slips (optional step if casing is stuck off the intended setting depth using the mandrel hanger) 1. Upon lifting the Stack and multi -bowl: DO NOT LOWER THE STACK FOR ANY REASON UNTIL ALL PARTIES ARE NOTIFIED PRIOR TO LOWERING THE STACK. • Caution: When the stack is raised, the casing and multi -bowl can become un -centralized and if lowered the multi -bowl seal area can become compromised 2. Confirm with Vetco Gray hand in the cellar that there is enough room to set the emergency slips. 3. Set emergency slips with casing in Tension • Pull approximately 100K over string block weight and set emergency slips. • Slack off and allow casing weight to be transferred to the slips. • Record weight transferred to the slips on Daily Report. 4. Prior to cutting the casing ENSURE THAT ALL WEIGHT IS SLACKED OFF. 5. Once the slips are set and the casing is cut be sure that there is radio communication between those in the cellar and rig floor prior to pulling the casing in the event that the stack has to be slightly lowered. 6. Remove and lay down the cut casing 7. Install Vetco Gray Packoff assembly. 8. Re -Install the Vetco Gray Multibowl and BOP's with RCD • Test wellhead connection to 5000 psi • Radio communication is necessary for all parties involved when lowering the stack 9. Pressure test pack off per Vetco Gray. • Do not exceed 80% of intermediate casing collapse • Record test on IADC report and Daily Report 10. Install rams and test per the AOGCC Permit to Drill (attached) • Test rams and choke manifold components to 3500 psi high / 250 psi low • Test annular preventer to 2500 psi high / 250 psi low • Do not test BOPE against casing. • Notify AOGCC 24 hours prior to performing BOP test. -> PERMIT TO DRILL requires BOP testing frequency every 14 days unless notified otherwise by AOGCC 11. Install wear bushing. 12. Clean mud pits in preparation to receive production OBM. 331 Page H04_ Well Plan for APD Package lue est Energy Production — Lower Lateral Overview Cosmopolitan Project H04_ Well Plan 8.50 4.5 RSS PDC ACTIMUL RD 8.8-9.4 22,122' 7,063' 115° Fluids LI© ppg ACTIMUL RD 8.8-9.4 15,481' 22,122' 7-11 From To RSS 6.75" Xceed675 Smith PDC General Notes ml/30 min % mlVolts <5.0 80:20 >600 ' Min Max Telescope/ GeoSphere/ 300 PWD/ MVC EcoScope XS616 7 x 12 0.773 • A combination string of 5-1/2" and 5" drill pipe will be utilized. • The 9-5/8" Intermediate String will NOT require a CBL as per AOGCC Regulations prior to drilling out since no hydraulic fracturing is planned for this well. OV— C6La,c'—' � • Shallow test MWD tools. • Monitor hole conditions carefully. Be alert for early signs of lost circulation and differential sticking. If any of these problems are observed immediately notify the Drilling Supervisor or Toolpusher (attempt to keep the pipe moving and circulation established). • If cavings are noted at surface, pictures shall be taken to clearly identify cavings structure and geometry. • Ensure that all team members are communicating with each other on any observed drilling trends and that everyone understands the potential risks. Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand or coal sections for any extended period of time. • Keep shut down times to a minimum during connections. • Swab / Surge: Make "easy on, easy off" slips a standard practice • Ensure the Top Drive Torque Limit is set below the lowest make up torque in the string. Do not run the risk of further make up downhole while drilling. 341 Page H04_ Well Plan for APD Package nue est Energy Cosmopolitan Project H04_ Well Plan Cement Bond Log (NOT REQUIRED BY REGULATION UNLESS WELL IS TO BE FRAC'D) L 9 e r- rr b;J A C) c? « J -,L- �. f an 1. Rig up Schlumberger wireline and cement evaluation t1ol with tractor assist highly likely J 2. Trip in the hole per Schlumberger requirements • Acquire CBL per Schlumberger (tractor assist to get log to TD will likely be required) 3. POOH and download the data for processing. Notify Drilling Engineer as soon as tools are on the bank to expedite future drill out. Drill Out Procedure 4. Install wear bushing 5. Pick up and drift all DP, HWDP, and DC's for surface section to confirm free of debris. 6. PLI drill out BHA Bit: 8-1/2" XR+ • TFA: 0.994 (4 x 18) • Dumb Iron Assembly NOTE: discuss with office the option of omitting this step and drilling out with the PDC and RSS BHA. 7. TIH on 5" XT50 and 5-1/2" XT54 Drill Pipe. 8. TIH to top of float equipment and pressure test intermediate casing to 3,500 psi for 30 min. Chart and record same. • Plot casing pressure test on LOT form and submit to Drilling Engineer • Verify the test indicates a linear line and there is no air entrained in the mud. Repeat casing pressure test if needed to obtain a linear line plot. 9. Bleed off pressure. 10. Drill out float collar and shoe. • Take note of any green cement or lack of necessary WOB to drill out shoe track. • If no cement or green cement is encountered DO NOT drill out the shoe. 4 Call Drilling Superintendent prior to continuing operations. 11. Clean out rat hole and POOH on elevators & LD drill out BHA. 12. PLI Drilling BHA Bit: 8-1/2" Z716 PDC 4 TFA: 0.773 (7 x 12) 4 PD Xceed 900 RSS BHA 13. TIH to TD on 5" XT50 and 5-1/2" XT54 Drill Pipe. 14. Displace to new 9.5 ppg VersaPro OBM. 15. Drill 20' of new formation, below the rat hole. 16. POOH to intermediate casing shoe and perform FIT per AOGCC requirements following the attached LOT procedure. • Required FIT: 13.50 ppg EMW 4 Recorded LOT/FIT pressures shall follow the format below: I. EMW = PSur(ace+ MW 0.052•(TVD) II. 13.5 ppg EMW FIT/LOT w/ 1,470 psi and 9.5 ppg MW @ 7,067' TVD 4 Offset Hansen 1: 12.80 ppg EMW FIT (Depth, MW and pressure not recorded) 351Page H04_ Well Plan for APD Package nue st Cosmopolitan Project Energy H04 Well Plan • All data shall be recorded on the provided "BlueCrest Casing/FIT/LOT Form". • If LOT is below 12.50 ppg EMW, contact Drilling Superintendent prior to drilling ahead. RSS BHA & Procedure for Drilling 8-1/2" Production Section: 3. PU Rotary Steerable Drilling BHA Bit: 8-1/2" XS616 PDC 4 TFA: 0.773 (7 x 12) --> PD Xceed 900 RSS BHA with EcoScope LWD 4. TIH on 5-1/2" XT54 x 5" XT50 DP to 9-5/8" shoe depth; circulate bottoms up. 5. Wash down to previous TD. 6. Directionally drill production hole: • Drilling Parameters: 4 Flow Rate: +500 GPM --> Rotary: +120 RPM • PU and Slack -off Weights will be taken EVERY stand Per K&M • Avoid anti -collision boundaries • Take MWD surveys as frequently as needed. Carefully review the anticipated close crossings with existing wellbores. Make sure that directional drillers are aware of all drilling close crossing issues, hardlines and no-go lines. If a no-go or hardline has been or will be crossed, stop drilling immediately and contact the Drilling Superintendent to discuss options. 7. The seven (7) ribs of the fishbone production section will be drilled in the following sequence using a 8.8- 9.4 ppg low solids CaCO3 OBM starting mud weight with no barite: ' o Drill the first fishbone rib '1O3" up into the Hemlock and Starichkof pay sands at 115 degrees inclination, as per the APD and directional plan for H12 -1_O3. o Circulate the rib clean, and backream L01 rib back to mainbore. ` d - A r o Once back in the mainbore, pull out to a open hole sidetrack depth as directed by the Operations Geologist. o Sidetrack the mainbore to the low side and drill ahead to the kickoff point for the L02 rib. o Repeat the procedure above to drill the L02 rib, and the subsequent ribs L03, L04, LOS, LOIS, and L07. o The last rib could be designated as L08 which will simply be a continuation to TD of the mainbore to be drilled under the H04 APD. o NOTE: more than one bit run is expected to be required to drill the multiple ribs, and the two-week AOGCC BOP test frequency will also need to be incorporated into the Daily Operations Plan. o Drill the H04 mainbore to TD, and circulate the well clean. o Backream to the 9-5/8" shoe. o Cap well with 9.5 ppg to 10.2 ppg weighted OBM depending on the actual reservoir pressure and well balance point that is encoun ered. o POOH and lay down BHA. Rig up to run 4-1/2" slotted liner lower completion. o Rig up and run 4-1/2" slotted liner with Volant Hydroform rigid blade centralizers crimped on at one per joint, and run in to 9-5/8" shoe. 361 Page H04_ Well Plan for APD Package lue est j Energy Cosmopolitan Project H04_ Well Plan NOTE: • Backreaming speed will be dictated by hole conditions. Consult with K&M prior to increasing pulling speed. • Decrease backreaming speed as torque and pump pressure dictate. • Once backreaming in the open hole has been started, DO NOT stop backreaming until inside the intermediate casing shoe. • DO NOT attempt to pull out on elevators once backreaming has started until the shoe has been reached and sufficiently cleaned. • If shakers/mud return system becomes overloaded and flow rate needs to be reduced, DO NOT continue to BROOH until the parameters are brought back to full backreaming rate. 8. Drop 2" hollow DP rabbit once bit is above the 9-5/8" intermediate shoe, POOH on elevators taking SLM and LD BHA. Ensure a wireline tail longer than the longest stand is attached. NOTE: Hard Banding • AT NO TIME SHOULD THE TRIP OUT OF THE HOLE BE CONDUCTED WITHOUT TAKING PROPER RECORDS ON STRING LOCATION OF WORN DP HARD BANDING. • ADDITIONALLY, BE SURE TO TRACK TOTAL ROTATING HOURS, BOTH DRILLING AND BROOH, OF ALL TRIPS TO ATTEMPT TO MAKE A CORRELATION BETWEEN HARD BANDING WEAR AND DP REVOLUTIONS • Take note of any joints that show hard banding wear, using the attached hard banding check sheet provided. • It is imperative that we track where in the string we are seeing the most hard band wear for future planning purposes. 371 Page H04_ Well Plan for APD Package nue st Energy Production Section Drilling BHA (SLB example from H12): Cosmopolitan Project H04_ Well Plan 381 Page H04_ Well Plan for APD Package nue st Energy Cosmopolitan Project H04_ Well Plan Completion: Lower Lateral Lower Lateral - Liner Run 391 Page H04_ Well Plan for APD Package lue est Energy Slotted Liner Run (4-1/2") Overview Cosmopolitan Project H04_ Well Plan 8.500 4.500 RSS PDC ACTIMUL RD 9.50 22,122' 7,063' 115.00' in. in. lbs. 4.500 3.826 15.2 in. P-110 H563 in. 3.701 psi 14,340 psi 13,460 Connection I Make Up I Operational Limit in. in. I ft -lbs. ft -lbs. ft -lbs. ft -lbs. ft -lbs. 3.826 4.093 5,100 6,100 8,900 I 8,900 26,000 General Notes PJSM: Include all company, rig and service personnel. • Discuss: • Dropped objects • Trapped pressure • Handling of the non-standard length equipment about to be handled. -�> Anyone may stop the job for HSE issues. Well Control: Discuss with ODE prior to liner running operation. • Ensure VBR's installed will cover 4-1/2" liner and 5" x 5-1/2" DP. Pressure requirements: • HES and Baker must agree that pressure setting requirements and limitations are understood and compatible. Liner String: • The majority of the liner will consist of 4-1/2" 15.2# P-110 H563 pipe with slots cut in every other joint. • This will be crossed over to a 23' Seal Bore Receptacle, a 7-5/8" x 9-5/8" liner hanger/ liner top packer and then RIH on 5-1/2" drill pipe as required. Liner Top Packer is Barrier Between Open Hole and 9-5/8" Casing • The liner top packer will be a primary barrier between production hole and intermediate casing. 401 Page H04_ Well Plan for APD Package nue st Energy Operational Specifics Cosmopolitan Project H04_ Well Plan 17. Drift all liner and completion equipment prior to RIH. (Service Company Reps to be present) 18. Hydril-563 lift nubbins will be required to pick-up the liner. 19. Follow GBR rep and Tenaris HYD 563 running procedures and recommendations. 20. Use Jet Lube Seal Guard ECF on HYD 563 Connections. 21. Utilize GBR/torque turn equipment w/record provided to BlueCrest rep at end of liner installation. 22. RIH speed: • Not to exceed 60'/min. 23. Circulation pressure: • Not to exceed 2,000 psi (liner hanger pinned to 2600 psi) 24. Circulation rate: • Not to exceed 5 bbl/min 411 Page H04_ Well Plan for APD Package lue est Energy Liner Running Order (subject to change when run in well) Guide Shoe Linerjoint(s) as required Landing Collar 1 Linerjoint(s) as required Landing Collar 2 Slotted Linerjoint(s) as required 4.5" 15.2# H 563 Pin x 7.0" 29# Vam Top HT Box XO 5.75" ID Seal Bore Receptacle (230' length) 7.0" 29# Vam Top HT Pin x Pin 7.625" 29.7# Vam Top HT Box x 7" 29# Vam Top HT Box XO 7.625" x 9-5/8" Hydraulic set liner hanger 7.625" 29.7# Vam Top HT Pin x Pin 7.625" x 9-5/8" liner top packer w/ 10' tie -back sleeve 7.625" 29.7# H 563 Liner Running Tool - Rotational Capability Mandatory Drill Pipe 15.2 P-110 H-563 Baker -Lock 15.2 P-110 H-563 15.2 P-110 H-563 Baker -Lock 15.2 P-110 H-563 15.2 P-110 H-563 Baker -Lock 15.2 P-110 H-563 15.2/29 4145 H-563 23 P-110 29.7/29 P-110 29 7 140 KSI 125 KSI Cosmopolitan Project H04_ Well Plan Vam Top HT Vam Top HT Vam "'100' Liner Lap Top HT 450,000# Tensile 26 125 KSI Vam 460,000# Tensile Top HT Torque Same as 7" H563 below P-110 IF 595,000# Tensile 40,000 ft. lbs. Torque To surface 421 Page / H04_ Well Plan for APD Package lue st Cosmopolitan Project Energy H04 Well Plan Connection Specifications - psi psi Ibf. In ft -lbs. Min: 5100 100% 14,340 13,460 485,000 3.826 Optimum: 6100 Max: 8900 80% 11,472 10,768 388,000 3.701 Make Up Loss: 4.093" drift Min: 16,300 100% 9,110 12,750 1,056,000 6.184 Optimum: 18,300 Max: 19,900 80% 7,288 10,200 844,800 6.059 Make Up Loss: 4.776" drift 100% 5,670 10,760 1,068,000 6.809 80% 4,536 8,608 854,400 6.750 drift Min: 18,600 Optimum: 20,600 Max: 22,600 Make Up Loss: 4.050" 431 Page H04_ Well Plan for APD Package nue est Cosmopolitan Project Energy H04 Well Plan 4-1/2" Slotted Liner Running: 25. Centralization: • One 4-1/2" x 8-1/4" Volant crimped on centralizer per joint. 26. Baker -lock the shoe joints. 27. K&M/SLB will provide "Broomstick" T&D chart. Pay attention to weight loss trends and FF trends. If weight losses do not follow expected FF trends from last BHA trips stop and circulate as necessary. 28. Rotation will be required to run liner to TD. 29. Follow Service Company equipment limitation recommendations. 30. Keep liner full. Fill every 5-10 joints while running. 31. Monitor pick-up and slack -off weights while running. Record PU and SO weights. Maximum pull is 80% of pipe yield or 80% of the weakest component of the LH assembly. 32. MU Liner hanger and liner top packer. Fill tieback extension with XanPlex gel and wait 30 minutes for thickening (can be mixed ahead of time). Run in one stand and circulate at least one liner volume. 33. Break circulation after liner is fully made up and note weight of liner in mud. 34. RIH with liner on drill pipe no faster than 1-1/2 minute per stand (60 ft/min). Watch displacement carefully and adjust running speed accordingly. • Screw into every 5 stands and fill pipe while lowering to the floor. Slowly in and out of slips. 35. Record hanging weight. Record SO weights every joint/ stand. Take PU and ROB weights every 10 joints/Stands. Record ROB weight prior to exiting the shoe and lock in cased hole friction factors. 36. Maximum pull at the liner top is limited to 80% of the weakest yield point in the string. 37. Break circulation every thousand feet and maintain good hole conditions. 38. Check hole displacement while RIH. 39. Monitor fluid returns and adjust running speed as required to minimize/eliminate losses. DO NOT exceed 60'/min. 40. Control running speed as hole conditions dictate to reduce pressure surges to the formation. 41. At +/- 45' above the 9-5/8" shoe, circulate 1-1/2 drill pipe and liner volumes, check and report the Pickup and Slack off string weights. DO NOT exceed 60%-70% of nominal liner hanger actuation pressure while circulating. 42. Establish rotating parameters above window and every 2000' while running to open hole. 43. Confirm torque specifications prior to rotating. DO NOT exceed the torque specifications for the weakest liner component. 44. Slack off slowly out of the 9-5/8" casing shoe looking for any abnormal resistance. 45. Continue in the hole looking for set down at the main wellbore liner hanger/packer setting depth. 46. Tag up on bottom and pull back up to position the shoe 2' off bottom. 47. Stage pump rates up slowly while remaining below 60%-70% of nominal hanger setting pressure. Circulate a minimum of one bottoms up at the desired cementing rate while limiting rate/pressure to avoid shearing hanger or initiating losses. • Consult with Liner Hanger Representative if elevated pressures are observed. 441 Page H04_ Well Plan for APD Package lue est Energy Setting the Liner Hanger Cosmopolitan Project H04_ Well Plan 48. Displace the hanger setting ball, slowing pump rate as directed by the service supervisor and bump the ball or plug and pressure up as required by liner procedure to set the liner hanger (typically 15% above nominal setting pressure). 49. Slack off total liner weight plus 50k downhole to confirm hanger set. Setting the Liner Top Packer 50. Pressure up per service company procedure to 4200 psi to release the Running Tool from the liner. • If the liner running tool cannot be pulled after hydraulic release sequence, the following mechanical back up release procedure should be followed. This requires left hand torque to shear a set of shear pins in the housing. With the running tool in the neutral position apply sufficient left hand torque to shear the secondary release pins. Work string up and down as necessary to get torque down to running tool. Apply secondary set down weight at the tool to shear secondary release mechanism. Rotate back to the right and apply 15k ft -Ib to ensure Drill Pipe did not back off during the releasing sequence. Pick up to release the running tool. 51. Bleed pressure to zero. 52. Pick up as directed by liner hanger service supervisor to expose Packer Setting Dogs, rotate at 15 to 20 RPM, and slack off to set liner top packer with 60K lbs at the liner top. 53. Pressure up drill pipe to 500 psi and pick up to remove the RS pack off bushing from the RS nipple. Bump up pressure as required to maintain 500 psi DPP while moving pipe until the pressure drops rapidly, indicating the pack off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at the liner top). 54. Immediately with the loss of pressure and before DPP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 55. Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and reverse circulate the well clean. 56. POH and inspect and LD liner running tools. If Dog Sub was used, check shear indication to confirm setting force applied downhole. Example Liner Running Parameters 451 Page H(Y Plan for APD Package lye est Energy Setting the Liner Top Packer and Releasing Running Tool - Example Cosmopolitan Project H04_ Well Plan Mechanical Releasing the Liner Running Tool - Example 461 Page H04_ Well Plan for APD Package uue st Energy Polish Mill Run & Brine Displacement Cosmopolitan Project H04_ Well Plan (Note: this is an optional step, and the brine displacement could be conducted after setting and releasing from the liner hanger) 57. P/U Polish Mill BHA and TIH on 5-1/2" DP to 30" above the top of 7.625" tie -back extension. 58. Obtain pick-up and slack -off weights before entering the tie -back extension. 59. Establish a circulation rate of +/- 1 BPM and slowly run in the hole while rotating at +/- 30 RPMs. 60. Observe pressure increase when the BHA enters the 5.75" ID, 23' polished bore receptacle located directly below the liner hanger. Mark the drill pipe. 61. Shut down the pumps and proceed to polish the PBR while rotating at +/-30 RPM until the BHA No Go is at the lower crossover. 62. Pull up out of the PBR to 5' above the tie -back extension and proceed to circulate the 9.7 ppg OBM in the casing with 9.5 ppg KCI/NaCL brine as per the fluid displacement procedure. 63. Flow check the well. 64. POOH managing drill pipe as required. 65. Lay down polish mill assembly and prepare to run upper completion. 471 Page H04_ Well Plan for APD Package lue est Energy Upper Completion Cosmopolitan Project H04_ Well Plan Production Tubing & Jewelry (3-1/2") 481 Page H04_ Well Plan for APD Package nue st Energy 3-1/2" Production Tubing String Overview in. 3.500 Connection Make Up psi 10,540 Cosmopolitan Project H04_ Well Plan psi lbs. 10,160 207,000 Operational Limit in. in. in. ft -lbs. ft -lbs. ft -lbs. ft -lbs. ft -lbs. TBD TBD TBD TBD TBD TBD I TBD TBD Tubing String Running Sequence NOTE: Final completion program may be adjusted based on actual well conditions and log results that are encountered, and would be detailed in a subsequent Completion Sundry Notice Form 403 to be filed. 66. Tally and Drift 3-1/2" 9.3# L80 IBT-MOD tubing string in pipe shed. Drift to 2.867". 67. Pull wear bushing and wash tubing hanger setting and sealing area as required. . 68. Make dummy run w/tubing hanger. 69. PU 20' 3-1/2" Seal Stack and associated equipment. 70. PU and RIH with production tubing string. 71. Keep hole full of 9.5 ppg kill weight brine. 72. Use Best of Life 2000 NM as per TSA recommendations. 73. Include three (3) gas lift mandrels, one (1) SSSV, one (1) set of real time readout downhole temperature and pressure gauges, and one (1) downhole chemical injection mandrel. 74. RIH to 100' above packer setting depth as per tally and slow running speed. 75. Run cables and lines through penetrations in tubing hanger. 76. RIH to packer setting depth. 77. Set packer and pressure test same. 78. Slack off weight per tubing movement calculation to be provided. 79. Measure for space out and PU as required to lay down top joint. 80. Pup up and crossover from 3-1/2" to 4-1/2" as required 1 joint below tubing hanger point. 81. MU tubing hanger. 82. Land tubing. jUJ 83. Install TWC and observe well for flow. 84. Test packoff. I c' 85. Connect control line for SSSV to surface system. 86. Connect line for downhole chemical injection. 87. Connect I -wire for downhole pressure and temperature data transmission. 88. Drain BOP stack. Nipple down rig BOP Stack and place on stump. 491Page H04_ Well Plan for APD Package nue est Energy 89. Nipple up 4-1/2" 5K production tree and pressure test same to 5,000 psi. 90. Pull TWC. 91. Function test SSSV. 92. Complete handover form and turn well operation over the Production Operators. 93. Open wing valve and route production to plant. 94. Observe and record flow rate data for unassisted flow if possible. 95. Initiate gas lift operation to observe assisted flow back. 96. Produce well as directed using gas lift to kick the well off. 2 Soy / Gta�Lj Cosmopolitan Project H04_ Well Plan A rr- Irk 5 501 Page H04_ Well Plan for APD Package 2400 3200 4000 4800 77 5800 8400 7200 8000 8800 9800 10400 11200 nv+ nnmu-a. 0#0 0 500 1000 1500 2000 25008US scare Dare 1:12500 10/104018 112500 E Last Updated: TWM, 09 Oct 2018 H04 Fishbone Production Well (Main Bore / Lower Lateral / Starichkof / Hemlock Primary Target) —193' MD/TVD Drilled In 20" 0.500" Wall A252 ERW Cement Mud/Deviation Bit: 17-1/2" PDC Bit 12.0 ppg Lead RSS: PDX6 715 bbis WBM MWD: PowerPulse 25% Excess 9.8-10.0 ppg Spud Mud LWD: arcVISION(GR/RES) 17-1/2" Top of Tail 4,623'MD Open Hole 15.8 ppg Class G Tail 167 bbis 25% Excess Ind 69 deg 5,623' MD / 3,531' TVD 13-3/8" 72# N80 BTC Azim 286 deg 3-1/2" Production Tubing to Surface GLM's / SSSV / DH Gauges / CIM Bit: 12-1/4" PDC OBM RSS: Xceed 675 12-1/4" 10.5 ppg VersaPro MWD: PowerPulse Open Hole TOC @ 13,981' MD LWD: arcVISION (GR/RES) 15.8 ppg Class G 132 bbis 50% Excess Liner Hgr & Liner Top Packer Incl 77 deg 15,481' MD / 7,067' TVD (Lower Lat) I I I 9-5/8" 47# P110 H563 I Azim 291 deg Bit: 8-1/2" PDC RSS: Xceed 675 OBM MWD: Telescope 8-1/2' I I Un-cemented 8.8-9.7 ppg VersaPro LWD: GeoSphere Open Hole I I Slotted Liner adnVISION i No Feat's 4-1/2" 15.2# P110 H563 Slotted Liner JUn-Cemented Slotted Liner Completion Max Incl 115 deg 22.122' MD / 7.063' TVD Total Depth in Mainbore Azim 302.4 deg T. McKay, 285ept2018 H04 Lower Lateral Completion with 20" Conductor Slotted Liner in Mainbore and Seven to be set @ 152' BGL (7) Open Hole Fishbone Ribs 13-3/8" 72# L80 BTC @ 5623' MD 3-%" 9.3# IBT-MOD Production Tubing 4-Y2" x 9-5/8" Liner Hanger & Liner Top Packer 9-5/8" 47.0/53.5# N80/P110 H563 @ 15481' MD Iue est Energy Fishbone ribs are 8-%" open holes spaced approx every 800' with 4-%" slotted liner run in the mainbore after the seven ribs are drilled; ribs are drilled in order from L01 to L07 using open hole sidetracks to initiate each rib; ribs penetrate all layers of Starichkof and Hemlock pay sands L01 L02 L03 L04 LOS LO6 L07 M 4-M" 15.2# H563 Slotted Liner @ 22122' MD tflueNest Energy Attachment 2 Cosmopolitan Project H0410-401 Fishbone APD Attachments H0410-401 Fishbone APD Attachments ��St H04 (P1) Proposal Geodetic Report Energy (Def Plan) 4: BlueCrect Vertical Section Irdp : 291GOD °(Two NoM) ND55 Cooner,roln Unit Van' at Section 0Wgld7 NS Pure Islut Cosmopolinn Ped/H-04 TVD Zol n, ce Depend Rotary TabeOR Eachialon ions ` study TVD eon It �p MSL bole: H04 "127 F" Ground Elevation:t 1452500 R above MSL (ft) 50231.ty, Magnetic Declination: 14510' ry Name: H04 (P1) Total Gravity Field Strength: 1001.261 sin, (9.80665 Based) ey Dad: Sepkmber 24, 2018 Gravity Model: DO% I AND I DDI I ERD Rago: 156509'/19453912 R/6976/2.]29 Tadd Magnetic Field Strength: 55089.1]9 nT dlnate Reference Syadm: NAD27 Al.k. State Plane, Zone W, US Feel Magnetic Dip Angle: 12.814' tion Lat I Lou,: N 59' 51' 29.13663', W 151° 48' 5.85554' Declination Dale: December 01. 2018 tion Grid WE YM: N 2144623035 fIUS. E 10812 804 fti Magnetic Dsclbmtlon Model: HOGM 2018 Grid Cnver,enca Angle: .1.5502' Nortll Reference: True North Sole Fatlpr: t 00002464 Grid Convergence Used 0.0000' Ion I Petcb: 210 544 0 Total Corr Mao NoM-oTrus Noah: 14,5103- Cosmopolitan Unit\Cosmoplitan Pa&H15-P2\H75-P2\H75-P2 (P7) Drilling Office 2.8.572.0 . Schlumberger -Private 10/9/2018 2:33 PM Page 1 of 5 MD Intl grim True ND55 NO VSEC NS EW 1F OILS Olrectiontl Exclaalen Zane Eachialon ions GBOMa, Th NOMln9 Eeeting Commend (ft) 1'1 (ry (ft) (0) (N) B) (R) (ry ('IIM) Difficulty Index uen Angle InT) (Nus) Vi RTE 000 000 0.00 -180.50 0.00 0.00 000 000 283M N/A 0.00 17.13 16222.56 2144623.04 16801280 100.00 0.00 28300 410.50 10000 0.00 0.00 0.00 283M 000 0.00 17.13 16222.76 2144623.04 168812.80 200.00 000 283.00 19.50 20000 000 000 0.00 283M 0.00 O.OD 17.13 1622285 214462304 16001280 300.00 0.00 283.00 119.50 300.00 0.00 0.00 000 283" 0,00 000 11.13 16223.13 214482304 16881280 Cry 11100 400.00 000 283.00 219.50 400.00 00 0.00 000 283M 000 0.00 17.13 1622332 2144623.04 160012.00 500.(10 1.00 283.00 31949 499.99 0.66 020 -OA5 2WIJ 180 000 17.18 107`3.61 2144623.25 16081196 Cry 21100 600.0 2.00 283.00 41946 599.96 3.46 0.79 3.40 2WM 1.00 ON 17.29 1075.31 2144623.91 168809.43 700.00 4.00 28380 51932 699.82 8." 1.96 4.50 283M 2.00 1.54 17.67 16728.04 2144625.23 160004.36 Cry 25/100 80.00 6.00 283.00 61893 79943 17.27 3.92 -1699 2.16R 200 202 18.26 17267.79 2144627.42 16679592 90.0 60 20.82 718.12 898.62 29.78 6.86 -29.26 1.95R 2.50 201 19.15 18076.92 2144630.69 16070314 1000.0 11.0 284.26 81667 997.17 46.56 1008 45.68 1.51R 2.50 2.71 20.30 19117.41 2144635.25 168767.44 110.0 13.0 28455 914.39 lose 9 67.0 16.26 38.22 12411 250 2.97 21.67 2034681 2144641.09 166747.04 120.0 WOO 284.74 101109 1191.59 9295 22.70 -90.05 1.05R 2.50 3.18 23.22 21724.07 2144648.19 168722.60 1300,0 160 284.89 11059 128709 122,42 W20 -119.51 091R 2.50 3.36 24.91 2321396 2144856.55 160694.16 140.0 20.99 285.0 1200.70 1301.20 156.01 30.99 -152.14 0.81R 250 3.52 26.73 2478577 2144666.15 160661]7 1500.0 23.49 28OW 129325 1473.75 193.66 41102 -in 70 072R 250 3.67 28.64 2641CO5 2144676.96 168625.50 160.0 25" 285.16 1384.06 1564.56 235.30 59.73 -229.11 0.66R 2.50 3.80 30.63 28077,70 2144688.90 16858540 170.00 28.49 285.22 147296 165346 280.84 7113 -27328 061R 2.50 392 32.66 29759.22 2144702.17 160541.57 180.0 30.99 28527 155918 1740.28 330.19 04.77 321.15 00R 2.50 4.03 34.79 31"COO 2144716.51 168494.07 1900.0 33.49 285.31 164435 1824.85 383.28 98.84 -372.61 0.52R 2.0 4.13 36.94 33119.71 21447`31.97 168443.02 2001 35.99 285.35 1726.51 10701 439.99 113.91 42TW 0.498 2.50 4.22 3912 34775.83 2144748.53 168388.49 210.00 38.49 285.39 1806.11 1906.61 500.21 129.95 48592 OAR 2.50 4.31 41.34 3fi40328 2144766.15 10330.59 -- 220.0 40.99 28542 188300 203.50 56o" 146.93 -547.55 0"R 2.0 439 43.56 37994.16 214084.60 16826944 2300.00 4349 28544 1957.02 2137.52 630.74 164.81 412.35 OA2R 2.50 4,47 4504 39541.50 2144804.44 160205.15 24000 45.99 28547 2020.04 2208.54 700.80 103.57 080.19 OAR 250 4.55 48.12 41039.09 2144825.04 168137.04 2500.00 48.49 205.49 2095a2 2276.42 773.88 20.17 -750.95 GUR 2.0 402 50.42 42401.38 2144846.56 168067.64 2600.00 Was 285.52 2160.54 2%1.04 849.84 223.57 ,42448 0.3/11 2.0 4,68 52.73 43863.38 2144868.95 167994.69 2700.00 WA9 205.54 2221.76 240226 920.51 244.73 -900.65 03611 2.0 415 55.05 45100.57 2144892.17 167919.12 2000.00 0.99 285.55 227948 2459.98 1009.02 266.61 -979.32 0.358 2.50 Cal 57.39 4642803 2144916.19 167841011 2900.00 WAS 285.57 233359 2514.0 1093.0 289.18 -1060.32 0.34R 2.50 4.87 59.73 47604.46 2144940.94 1677W.71 3000.00 SOA9 285.59 2303.97 2564.47 1179.51 312.37 -1143.52 0.WR 2.50 4.93 62.08 40704.05 2144966.40 1676711.17 310000 6349 20501 243D.54 2611.04 120.61 336.17 -1220.75 OUR 250 498 64.43 4972455 2144992.50 16759362 320000 65.99 2850 247320 2653.70 1357.64 360.50 -1315.85 OUR 2.50 504 0.79 50663.19 2145019.20 167507.22 330.00 68.49 205.64 2511.00 2692.38 1449,45 385.34 -1404.65 0.318 2.50 5.09 69.16 51517AS 2145046" 167419.12 End Civ 3314.37 (ROO 28564 2517.11 2697.61 1462.78 380.95 -1417.54 HS ZOO 5.09 69.50 51833.10 2145050.40 167406.33 34000 68.85 28564 2540.00 2720.50 1542.29 410.46 -1494." HS 0.00 5.12 69.0 51633.69 2145074.01 167330.04 3W0.00 6885 285.64 2584.00 2764.58 IM14 43582 -1584.26 IS 0.00 SAO 0.50 5163429 214510156 167240.94 3600.00 6885 28564 2620A5 2000.65 1728.00 460.76 -1674.07 IS 000 5.19 0.50 51634.89 2145129.16 167151.84 3700.00 085 28564 2656.23 2836.73 1820.06 485.90 -1763.00 H6 000 5.22 0.W 51635.49 2145156.73 167062/4 380.00 68.85 285.64 2692.31 2872.81 1913.72 51104 -1053.70 HS 0.0 5.24 69.50 51636.08 2145184.30 166973.65 3900.00 6885 28564 2720.30 206.88 200&57 536.18 -1943.51 HS 0.00 $27 69.50 51636.68 2145211.88 166884.55 4000.00 6885 205.64 2764.46 2944.96 2099.43 581.32 -2033.32 IS DW 5.30 6950 51637.28 2145239.45 1079545 4100.00 68.85 285.64 2600.54 2981.04 2192.29 586.46 -2123.14 HS DOO 532 69.50 51637.87 214526702 16670.35 420000 68A5 285.64 2836.61 3017.11 2205.15 611.60 -2212.95 NS 0.00 5.34 69.50 51630.47 2145294.59 1601725 4W000 68.85 205.64 2072.69 3053.19 2370.00 638.74 -2302.77 IS 0.00 536 6950 51639.07 2145322.17 165528.15 440000 68.85 205.64 2900.77 300.27 247086 661,818 -2392.58 HS 0.00 5.39 69.50 51639.66 2145319.74 166439.05 4W000 68.85 28564 2944.64 3125.34 256312 0702 -248299 IS 0.00 5.41 69W 51"0.26 214537731 166349.95 4600.00 68.85 28664 2960.92 3161A2 26%58 712.16 -257221 HS 000 5.43 0.50 51"0.86 2145404.89 16060.66 Cosmopolitan Unit\Cosmoplitan Pa&H15-P2\H75-P2\H75-P2 (P7) Drilling Office 2.8.572.0 . Schlumberger -Private 10/9/2018 2:33 PM Page 1 of 5 Cosmopolitan Unit\Cosmoplitan PadN15-P2\H75-P2\H15-P2 (P1) Dniling OMI;e 2.8.572.0 Schlumberger -Private 10/9/2018 2:33 PM Page 2 of 5 ND Incl A7)m True rvoss WD VSEL NS EW TF 025 Enclualon Zone Exclusion Zone GecMag Th NeHMnB EUUnp comm.M. Ifl) 1°) (% Ifl) (4) (ft) IR) (ft) (% Difficulty Index (me17R1 Dlmcully Inde: Alert A"al• Pt (or) IRuS) (1645) 4700.00 WM 285.64 W1100 3197.50 2749.43 737.W -266202 HS 000 5.45 69.50 5164145 2145432.46 166171 16 480000 685 28564 3053.07 3233.57 284229 762." -2751.83 HS 0.00 5.47 69.50 51642.05 2145460.03 166082.66 490000 64.5 285.64 3089.15 3269.65 2935.15 787.57 -2841.65 HS 0.00 548 69.50 51642.64 2145487.61 165)9356 5000.00 88.85 285.64 312523 3305.73 3028.00 81211 -2931.46 HS 000 5.50 69.50 51643.24 2145515.18 16004.46 5100.00 6885 285.64 3161.30 334180 3120.86 837.85 -3021.27 HS 0.00 5.52 69.50 5164384 2145542/5 16501538 520000 68.85 285.64 3197.38 337788 321372 06299 -3111.09 HS 000 553 69.50 51644.43 2145570.33 16572626 5300.00 045 285.64 323346 341396 3306.58 888.13 1200.90 HS 0.00 5.55 69.64 51645.03 214559790 165637.16 510000 68.85 285.64 3269.53 3450.03 WW43 91327 1290.71 HS 0.00 557 0.50 5164562 2145625.47 165548.06 Unn T.ek 541931 0185 28564 327650 3457.00 341737 918.13 330..06 HS 0.00 557 69.50 5184574 2145&30.60 Imam 500000 68.85 285.64 330561 3486.11 3492.29 93041 -3300.53 HS 000 SM 69.50 5164622 2145653.05 165458.97 560000 68.85 285.64 3341.69 3522.19 3585.15 963.55 -3470.34 HS 0.00 5.60 69.50 5164682 2145680.62 165369.87 13116-ce9 562305 W85 28564 WN100 3530.50 3606.55 90..35 3491.04 HS 0.00 580 law 5164695 2145686.97 165349.33 SMO.W 6885 28564 337716 3550.26 3678.01 988.69 1560.16 HS 000 5.61 89.% 51647." 2145708.19 165200]7 SWO.W 68.85 285.64 341384 3594.34 3770.86 1013.03 3649.97 HS 0.00 5.62 69.50 51648.01 2145735/7 165191.67 5964.00 68.85 285.64 3149.92 3630.42 386312 1038.97 -373918 HS 000 5.64 69.50 51648.60 2145763.34 165102.57 600000 085 285.64 3485.99 3666.49 3956.5 1064.11 -3829.60 HS 000 5.5 69.50 51649.20 2145790.91 16501347 6100.00 68.85 285.64 352207 3702.57 404944 1089.25 3919.41 HS 000 566 69.50 51649.79 2145818.49 164924.37 6200.00 68.85 Max 355815 3730.65 414229 1114.39 400922 HS 000 5.0 69.50 51650.39 2145646.64 16403527 6300.00 WA5 285.64 3594.22 377472 4235.15 1139.53 409904 HS 000 5.69 69.50 51650.% 210.5873.63 164746.18 U Tronek0 6317.13 69.85 28564 3600.40 3780.90 4251.05 114364 4114.42 HS 000 66 6950 51651.08 214078.35 1803092 64W.W 5.5 285.64 363030 3010.00 4328.01 1164.67 418885 HS 000 510 Saw 51651.56 2145901.20 164657,08 650000 5.85 265.64 366637 3848.87 4420.67 1189.81 4278.66 HS 000 5.71 69.50 51652.17 2145928]0 164567.98 660000 68.85 285.64 3702.45 3802.95 451312 1214.95 4368.48 HS 0.00 512 69.50 51652.76 2145956.35 16408.88 670000 68.85 285.64 3738.53 391903 4606.58 124009 4458.29 HS 0.00 5.74 69.50 51653.36 2145903.92 164389/8 680000 60.85 285.64 3774.60 3955.10 4699.44 126523 4548.10 HS 000 575 69.51 51653." 21AW11.50 16430068 690000 0.85 285.64 3810.68 3991.18 09230 1290.37 463192 HIS 0.00 5.76 69.51 51654.55 2146039.07 164211.58 7000.00 68.85 285.64 354676 4027.26 4885.15 1315.51 48773 HS 0.00 5.9 69.51 5105.14 2146066.64 164122A8 71W.W 60.85 205.64 3882.83 4063.33 4970.01 1340.65 4817.54 HS 000 5.78 69.51 51655.73 214609412 16403339 7200.64 50.85 285.64 3918.91 409941 WMA7 1365]9 490136 HS O W 5.79 69.51 51656.33 2146121.79 16364429 73W.W 6885 285.64 395499 4135.49 5163.73 1390.93 4997.17 HS O.W 5.0 69.51 51656.92 2146149.36 163855.19 74W.W 6085 285.64 3991.06 4171.56 5256.50 1416.07 3646.99 HS O.W 5.81 6951 5167.52 2146176.94 1637660 7564.64 60.85 285.64 407.14 420764 5349." 144121 517660 HS OW 5.82 69.51 51656.11 2146204.51 163676.0 76W.W 68.85 285.64 406322 424372 5"2.30 1466.35 -5266.61 HS O.W 5.83 6951 516M.70 2146232.08 16358189 7700.W 68.85 205.64 4099.29 4279)9 5535.16 149149 3356.43 HS OW 5.84 69.51 51659.30 2146259.88 163498.79 7800.64 68.85 205.64 413537 431587 582&01 151662 541624 H6 O.W 5.85 69.51 516590 2146207.23 163409.69 7WO.W 68.85 205.64 4171.45 4351.95 5720.87 1541.76 3586.05 HS O.W 5.86 69.51 5166448 2146314.80 16332060 8000.00 68.85 285.64 420.52 438802 5013.73 IN&W -5625.87 HS O.W 5.87 69.51 51661.07 2146342.30 163231.64 810000 68.65 205.64 4343.64 4424.10 006.50 1592.04 571588 HS O.W 587 69.51 51661.67 2146369.95 16314240 8200.00 68.85 2B5.64 499.60 4460.18 590" 1617.18 580.5.49 HS 0 W 5.88 69.51 51662.26 2146397.52 163053.30 8300.64 68.85 285.64 4315.75 4496.25 W92.W 1642.32 5895.31 HS O.W 589 6951 51662.85 2146425.09 162964.20 840000 6885 285.64 4351.83 4532.33 6105.16 1667.46 5985.12 H9 0.W 5.90 69.51 51663.44 2146452.67 162875.10 8WO.00 68.05 285.64 4307.91 4%8." 698.01 1692.60 6m4.93 H6 O.W 5.91 6951 51664.04 2146480.24 162786.00 BOOM 68.85 205.64 4423.90 4604.48 6370.87 1717.74 416415 HS 0.0 5.92 6951 51664.63 214607.01 1626%.W 8700.00 68.85 285.64 446).% 4640.56 6463.73 17288 £254.56 HS O.W 5.92 69.51 5164522 2146535.39 16260181 88W.00 68.85 285.64 4496.14 4676.64 6556.59 1768.02 634236 HS O.W 5.93 69.51 5164581 2146562.96 162518.71 8900.W 6885 285.64 4532.21 471211 6649." 1MA6 -6634.19 HS OW 594 69.51 51664.40 2146564.53 862429.61 U TyonekH 899819 0M 28564 4588W 474&W 8741.55 181810 6523.28 HS 0.0 695 0.51 51668.0 946617.06 162341.23 WOO.W 68.85 285.64 4560.29 4748.79 6742.30 1810.30 6524.64 HS 0.00 5.95 69.51 51666.99 2146618.11 162340.51 9100.00 68.85 285.64 4604.37 06487 6035.16 1843.44 6813.82 HS 0.00 5.95 6951 51667.58 2146645.68 162251.41 9200.00 6885 205.64 4640." 4820.94 6928.02 1086.58 670.63 HS 0.00 596 6951 51666.17 214667325 162162.31 5W.00 68.85 285.64 4676.52 485702 7020.87 18W.72 6764.44 HS 0.00 597 6951 51660.77 214670083 16207321 940000 6885 205.64 012.64 4893.10 7113.73 1910.86 $8&9.28 HS 0.0 5.90 6951 61664.36 214672840 161986.11 9500.00 68.85 205.64 048.67 4929.17 720.59 19".W 6973.07 HS O.W 5.98 69.51 51664.95 2146755.97 161895.01 U Tyonek1 959986 88.85 28564 084.70 496520 720.31 190.10 -7M..76 HS am 699 69.51 51670.54 2146783.51 161864.04 960000 68.85 205.64 084.75 4%5.25 7299AS 1969.14 4062.88 HS 0.00 599 69.51 51670.64 946783.55 16180.592 9700.00 68.85 285.64 482083 5001.33 739230 1996.28 -7152.70 HS O.W 800 0.51 51671.13 2146811.12 161716.82 9864.00 68.85 28&61 48%.90 W37.40 7405.16 2019.42 -7242.51 HIS 0.00 600 69.51 51671.72 214683889 161627/2 990090 6885 285.64 469298 W73A8 757802 20".56 -7332.32 HS 0.00 6.01 69.51 51672.31 214066.27 161538.62 10000.00 6885 285.64 4929.06 5109.56 7670.88 20070 4422.14 HS 0.00 (I.02 6951 51672.64 2146493.84 161449.52 10164.00 68.85 285.64 4965.13 5145.0 776313 2094.84 -7511.95 HS 0.00 6.02 69.51 5167348 214692141 161364.42 1020000 6885 285.64 W0121 5181.71 785859 2119.98 46116 HS 0.00 6.03 6951 51674.07 2146948.W 161271.32 U Tvm J 10207.45 W85 286& 5003.64 5184.40 7803.51 2121.85 -0608.46 HS ON 664 6.51 511574.12 94051.04 161264.64 103W.W 085 28&" 5037.29 5217.79 794945 2145.12 -701.58 HS 0.00 6.04 69.51 51674.66 2146976.56 161182.22 164W.00 u85 28564 W73.W 5253.% 804231 2170.26 -7761.39 HS 0.00 6.04 6951 5167525 210()4.13 16103.13 10500.64 68.85 28564 5109" 5289.94 8135.16 2195.40 -7071.21 HS O.W 6.05 6.51 51675.64 214701.70 1610174.03 106M 00 0.85 Mae 5145.52 5326.02 822802 2220.54 -7961,0 HS OW 6.05 0.61 51676.43 210059.28 1091093 1070000 6885 285.64 5181.59 5362.09 832088 2245.88 Mows* HS 000 6% 0.51 516)102 210086.5 16402583 1000.00 64.5 285.64 521167 5398.17 641373 2270.81 6140.65 HS am 607 %.51 5167161 2147114.42 16073613 109W.W 68.5 28564 5253.75 5434.25 85%.59 229595 623046 HS On 6.07 69.51 51678.19 2147142.64 1W647.63 11000.00 64.5 28564 528982 500.32 850.45 2321.09 632027 HS 0.00 &% 6.51 51678.78 214710.57 160558.53 111W.W 5.65 285.64 5325.90 55%.40 860.31 234623 6410.09 HS O.W 6.0 69.51 51679.37 2147197.14 16046943 11200.W 0.65 285.64 538198 554248 875.16 2371.37 6499.64 HS O.W 60 0.51 51679.96 2147224/2 160300.34 11300.64 64.5 285.64 539805 5570.55 518.02 2396.51 658971 HS 000 60 69.51 51680.56 214nU.29 16029124 1140.0 MRS 25.64 5434.13 5614.63 8970.5 2421.65 6679.5 HS Ow 6.10 69.51 5151.13 214799.% 16002.14 11500.64 66.85 25.64 5470.21 5650.71 9063.74 2446.79 6769.34 HS O.W 6.11 69.51 5101.72 2147307." 160113.04 11600.0 64.05 25.64 5506.28 5606.70 9158.59 2471 93 6859.15 HS OM 6.11 6.51 51682.30 2147335.01 16002394 1170.0 68.85 25.64 5642.36 5722.06 049.45 2497.07 6948.97 HS 0.0 6.12 69.51 51882.89 2147362.50 1093484 Cosmopolitan Unit\Cosmoplitan PadN15-P2\H75-P2\H15-P2 (P1) Dniling OMI;e 2.8.572.0 Schlumberger -Private 10/9/2018 2:33 PM Page 2 of 5 Commaras MO (ftl cl In17 Azlm Tr (°) 0 NDSB (%) ND 1ft1 VSEL Ifll RS (fl) IyVI (%) TF l°) DLS DlreallonN Exclusion Z. lM (°I100fl) Dcufty Index AIaM1 ExNuslon20 M%rre la GaoM a9 TB (sT) NoM1Mn9 (ftU5) E(WS) IffllS) 1160.50 6085 28564 5578.44 5758.94 9342.31 2522.21 -9038.78 "a 000 6.12 Mal 5168348 2147390.16 159815.74 11900.0 80.85 28564 5614.51 579501 8435.17 2517.35 -9128.59 HE 000 6.13 69.51 516M 214741713 159756.64 12000.00 68.85 285.64 586.59 5031.09 9520.02 2572.49 9218.41 HE 000 6.13 Mal 51684.65 2147445.30 159667.55 121W.W 60.85 285.64 588887 5867.17 9620.88 2507.0 -MOM HS 0.00 6.14 69.M S1M5.23 2147472.07 159578.45 122W.0 68.85 285.64 572274 590324 9713.74 2622.77 -939804 HE O.W 614 69.52 51685.82 214750045 159489.35 123WOD 60.85 285.64 5758.82 5939.32 W6M 2647.91 948785 HS O.W 6.15 69.52 51686.40 2147528.02 159400.25 124W.W 60.85 285.64 5794.90 5975.40 9899.45 2671M -9577.66 HS 000 6.15 69.52 51fi96.M 2147555.59 159311.15 12500.50 0.85 2&5.64 5830.97 6011.47 9992.31 2690.19 -9667,48 HE O.W 6.16 69.52 5160757 2147583.17 159222.05 12600.50 60.85 285.64 M67.05 6047.55 15085.7 2721M 9757.29 HS ow 6.16 69.52 51fiM.16 2147610.74 159132.95 12700.W 60.85 285.64 5503.13 600363 10178.0 2740.47 -9847.10 HE 0.00 6.17 6.52 51688.74 2147638.31 15504305 12850.0 0.85 285.64 639.20 6119.70 1070.88 2773.61 -9936.92 HS O.W 6.17 69M 5168932 2147665.6 158954.75 Lawny Tyon 126582 Man 28564 5973.70 8154.20 1036.87 2797.65 -10022.80 HS 0.00 6.10 daw 5166.88 21476225 15M69.56 12900.50 6.85 285.64 507520 6155.78 103614 2790.75 -1002613 HS 0.00 648 6.52 51689.91 214769346 1086566 13000.50 6.85 2M.64 60M36 6191.86 10456.60 2823.89 -10116.54 HS O.W 6.18 6.52 51690.49 214"2103 150776.56 131W.W 0.85 285.64 647.43 6227.93 10549.46 2049.03 -10206.36 HE 0.00 6.19 6.52 51691.] 214"48.61 15MB7.46 IMM.M 010 Mad 6083.51 6264.01 1042.31 2074.17 -10296.7 H8 000 6.19 6.52 51691.86 2147"6.18 158598.36 13300.50 0.85 285.64 6119.59 6300.m 10735.17 2099.31 -10305.90 HS 000 620 69.52 51692.24 2147803.75 15869.26 L Tyonaka 1336.68 6.85 28584 6142.20 622.70 10793.37 291506 -10442.28 HS 050 620 6.52 51692.6 2147821.04 15645341 13400.00 68.0 285,6,1 610,66 636.16 1082803 2924.45 -10475.6 HS 000 620 6952 5169282 2147831.33 150420.16 13500.50 68.85 285.64 6191.74 672.24 10920.89 2909.6 -10565.61 HS 600 620 6952 51693AO 2147058.W 158331.06 136000 68.85 285.64 6227.82 6408.32 1101374 2974.73 -106,43 HS 0.00 6.21 69M 5169399 2147886.47 15641.96 L Tyonn C 136046 6.85 28584 63520 8415.70 1102.75 2979.67 -106736 HS ON 621 6.52 51894I1 214762.11 158223.73 13M.M 6.85 28564 6263A9 6444.39 1110680 2999.06 -1074524 HS 000 6.21 69.52 51694.57 2147914.05 158152.87 13800.00 68.85 28564 6299A7 646.47 11199.46 3025.50 -1003505 HS 000 622 6952 5169515 2147941.6 15663]7 1360.50 6885 28564 6MOAS 6516.55 1129231 3050.14 -10924.07 HE 800 622 69.52 5169573 2147M9.19 157974.67 14000.00 6.85 285.64 6372.12 6552.62 11385.17 307520 -11014.68 HS 0.00 623 69.52 51696.31 214766.76 157885.57 L Tyodn D 14010,47 6.85 28564 0756 6556.40 11394.89 3077.82 -11024.0 HS O.W 623 6.52 5169637 214799965 15787824 14100.00 6885 285.64 6408.20 65010 11478.3 3150.42 -1110449 HS OM 6.23 69.52 5169.09 2148024.34 15"96.47 14200.00 6.85 28564 6444.28 662478 11570.89 3125.56 .11184.31 HE 0.00 613 69.52 5169747 214801.91 15"7.37 14300.00 6.85 285.64 6480.35 6660.85 1166374 315010 41284.12 HS 0.00 624 69.52 51698.05 2148079.48 15761827 14400.00 6885 285M 6516.43 6606.0 11756.60 3175.04 -11373.93 HS 000 624 69.52 51698.63 214817.06 157529.17 1450000 6.85 28564 6552.51 733.01 11849.46 3250.98 -11463.75 HS 0.00 625 69.52 5169921 2148134.63 1574400 L TyonakE 146034 Man 285" 658510 676.6 1103.35 3223.6 41544.89 HS 0.0 625 6952 516974 214816.54 15736.6 146WA0 68.85 28&64 6588.58 6769.08 11942.32 3226.12 -11553.56 HS 000 625 6952 51699.79 214816220 1736.% 14700.50 6.85 2M64 6624.66 6805.16 12035.7 3251.26 .1103.37 HS Om 6.25 6952 517W.37 2140189.78 157261.88 14800.00 68.85 285.64 6660.74 6841.24 12120.03 3276.40 -11733.19 HS Om 626 6952 517M.95 2148217, 15710.78 14900.00 6885 285.64 6696.01 6".31 12220.89 3301.54 -1163.W HS O.M 826 6852 51701.53 214644.92 1570M.6 15500.00 60.05 285.0 6732.09 6913.39 1231375 3326.60 -1191281 HE OW 827 69.52 5170.11 214672.6 1664.0 Sfamhkof Coal 1508950 68.85 28584 76500 694550 1239&39 3349.0 -1199275 HS O.W 627 k4kr 6.52 51702.62 2148287.04 15691528 1510000 68.85 20564 6760.97 694947 12406.60 3351.82 -12502.63 HS Om 6.27 6952 51702.6 2146350.7 156M548 SWMkof 1516495 M85 28584 6792.40 672.85 1246692 33615 -1206.97 HS 0.0 a27 6.52 51703.0 2148317.98 1564781 Cry 311m 15165.56 68.85 28564 792.6 673.12 1246740 3368.30 -12061.51 35.37R O.W 6.27 69.7 51703.06 2148310.15 1684707 15200.00 6910 28828 6804.01 6985.31 12499.57 0".16 -12092.8 35.14R 3.50 6.28 70.14 5167.44 2140327.84 156816.35 SlanahkofF 1520.09 89.89 28&42 667.6 688.10 12507.13 3379.29 -126916 3&WR 3.W 6.28 7028 51954.78 2148330.17 156869.13 1000.00 72.16 20009 6837.40 707.98 12593.06 3185.06 -1216.76 X.SSR 3.50 630 71.95 52474.04 21403M.21 1572686 Sfa°lchWE 1601.6 7220 285.12 Maw 7018W 1259546 34056 -12184.29 34618 3.0 a6 71.98 52483.26 21483615 156M535 Sfatla WD 1683.40 74.23 26.56 061.6 7042.10 12673.0 300.85 -122M.32 34.128 3.50 6.32 73.40 52913.41 214838602 156652.0 15400.0 74.0 288.85 6866.05 7046.0 12689.6 3136.24 -12273.37 X.04R 3.50 6.33 73.79 52996.6 2148391.82 10637.13 9-518' IX81.W 7666 291.25 686.14 706&64 127M.0 34M.79 -1234884 01R 3.50 &34 7630 038555 2148421.36 156564.44 15550.50 77.13 291.57 00.44 7070.94 1276.58 3170.55 -12364.7 0.62R 3.W 6.35 75.66 53171.6 2148420.50 156547.40 SfarichkofA 1555625 78.54 292.53 602.30 70080 12841.56 3491.19 -1241503 0.42R 3.50 6.36 7672 5371847 21484M.6f 15649701 Slmfchkac 1567.48 78.82 292.72 604.6 70MW 12852.55 349542 -12425.16 U39R 3.50 636 760 670.17 214MM 11 15648&99 1560.W 79.6 29326 6910.58 7091.00 12884.49 357.90 -12454.6 M20R 3.W 6.37 7755 53894.6 2148460.39 15645791 Sfaic WS 15684.79 8201 294.84 62570 710620 1297792 3546.04 -12540.6 330R 3.50 8.39 78.37 54244.86 21485083 15071M 157W.0 82.14 294.92 692642 7106.92 12903.0 351821 -12WM n02R 3.50 6.39 7947 5426.61 214851113 15636891 1560.W 84.6 296.7 6937.91 7118.41 1307.96 361.36 -126X.19 32.038 3.W 6.41 81.40 5150.17 2148556.70 15620085 159W.W 07.19 298.19 6945.01 7125.51 13181.18 363723 -1272215 32.72R 3.W 6.43 0334 54821.16 214864.96 1619337 16000.0 09.71 Mal W7.72 7128.22 1329.16 3685.69 -12810.17 KE7R 3.W 6.45 05.M 55007.M 21465518 15610730 End Cm 1611.46 90.00 3W.W 6917.75 7128.25 13291.48 3691.41 -1260.11 HE 3.W 6.45 05.52 5625.04 21486117 15667.52 C,Tlw 1602146 90.00 3W.W 6947]5 712825 1330136 36%.41 -1268.77 7a2R O.W 645 0552 5625.05 214867.00 16089.00 16100.50 92.34 350.31 6946.15 7126.65 1337887 3YM.85 -126%.6 762R 3.W 6.47 87,68 5514791 214708.27 16022.21 KOPCn2l100 16120.W 9293 30.39 6945.23 7125.73 13398.59 374594 -12913W LS 3.W 6.47 8022 55166.6 2148718.84 1600525 1700.50 91.33 350.39 6W2.26 712216 1%7746 3786.39 -12902.85 LS 2W 6.48 86.69 55101.24 214761.14 155937,42 Cry 211M 16270.0 89.93 350.39 6941.49 7121.99 13518.51 382180 -1304323 101.438 2W 6.49 05.35 55011.47 2148790.10 15578.02 16500.0 09.01 W0.98 611.56 7122.06 13576.09 367.11 -1369.0 101.438 250 6.% 0&7 X988.91 2148814.19 155852.65 16400.50 8941 306.94 694223 712213 1374.25 3890.04 -1310.86 101A2R 200 6.51 0413 54%449 21086941 15576928 End Cry 16456,04 0919 304.04 6942.91 712341 13728.96 3WOM -132W.59 HS 200 6.52 83.62 51851.10 214601.58 10723.41 16%0.00 09.19 304.04 6943.53 7124.03 13"118 394556 -13237.50 HE 0m 6.52 03.62 51851.14 2148927.17 15567.7 160000 09.19 304.04 6944.94 7125.44 1386.20 4WIM -13319.88 HS OW 6.53 8362 51851.24 2148905.38 15696.36 1670000 09.19 301.04 6946.35 7126.05 1396.61 4M7.5D -1310.73 HS O.W 6.53 83.62 X851.33 2149043.58 15,25.0 Cry 31100 1777.6 09.19 304.04 6947.44 7127.94 140@.28 41W.90 -1347.10 W.19L 0.50 6.94 83.6 54851.40 214%80.00 156461.89 1660.50 89.6 303.51 6476 7128.10 14964.04 411339 -13185.0 52.10 3.W 6.94 84.16 5490750 2149101.70 15X4369 Cry MW 1621.m 90.0 W3.W 6X7.75 712015 148509 412520 -13503.6 18L 3.W 6.55 X.60 5,t956.02 2149114W 15X26.W KOP Cry 21150 169W.W 92.35 30.93 6846.14 7126.64 1416183 4167.88 9356947 LS 3.W 6.56 86a6 55115.0 2149150.46 1,381.38 Cosmopol%an Unit\Cosmoplitan Pad\H75-P2\H15-P2\H15?2 (Pi) Drilling Office 2.8.572.0 . Schlumberger -Private 10/9/2018 2:33 PM Page 3 of 5 Cosmopolitan Unit\Cosmoplttan Pad\H75-P2\H15-P2\H75-P2 (P1) Drilling Office 2.8.572.0 . Schlumberger -Private 10/9/2018 2:33 PM Page 4 of 5 MO Incl kdrn True Wass TVD VSEL N6 EW TF DLS DIr Uonal Excluelon Zone Exeluelae2oee O o",,,Tll N"HKin9 Eae1M9 Commerce (N) (7 CI (R) (el (n) On (10 ('1 1'116681 OlNwuKy Index Awn A"?� (nT) (Nus) must 11000.00 90.35 30293 694318 712428 14259.63 4222.23 -13853.37 LS 2.00 6.57 8504 54906.91 214921507 155278.90 Cry WOO 1785000 89.35 30293 6943.91 7124.41 14300.55 4249.42 -13895.33 61.61L 200 6.58 84.08 54099.28 214924338 155237.11 End Cr, 17065.00 8962 30229 6944.22 1124.12 14312.03 4288.28 43124.81 HS 200 6.59 84.52 54941.13 2149263.04 155200.02 17100.00 89.62 302.29 6944.32 712482 14351.51 427639 -13737.50 HS 000 6.59 84.52 54941.14 214927139 155196.36 17200.00 09.62 302.29 6844.89 7125.49 14455.61 4329.71 -13822.03 HS 0.00 6.59 8452 5494122 2149327.09 155113.30 17300.00 89.62 302.29 6945.65 7126]5 14553.67 4383.12 -13906.57 HS 0.00 660 84.52 51911.29 2149302.10 155030.25 1740000 89.62 302.29 6916.32 712682 14651.13 4436.53 -13991.11 HS 0.00 6N 84.52 54941.37 2149438.48 1%97.19 17500.00 89.62 302.29 6946.90 M7,48 14749.00 4489.95 -14075.64 HS 0.00 6.61 8452 5494144 2149494.17 154864.14 17600.00 09.62 302.29 697.65 7128.15 1407.06 4543.36 -14160.18 HS 0.00 6.61 8452 54941,51 2149549.87 16781.06 Cry 31100 17600.07 89.62 302.29 6947.71 7128.21 14056.56 4548.10 -14167.60 IoWR 000 6.61 (AN 5494152 214955481 15773.71 Crv&1W 17621,77 90.00 302.35 697,75 7128.25 14069.21 4555.00 -14178.58 0.21R 3.00 6a2 8487 54912.44 214956200 15763.00 1770000 92.35 302.36 6946.15 7126.65 14945.89 4596.86 -174464 021R 3.00 6.63 87.12 55123.99 2149605.64 154698.10 KOP C, W100 17710.00 92.65 302.36 6945.71 712631 14955.68 4602.20 -14253.00 LS 300 6.63 87,40 55137,23 2149611.21 154889.81 17800.00 9085 302.36 6942.97 7123.47 15043.87 4650.35 -14329.06 LS 2.00 6fi4 85.68 55036.81 2149661.41 154615.16 Cr,211W 17060.00 09.65 302.36 6942.11 7123.21 15102.69 4 Alr -1431974 16731R 2.00 6.65 84.53 54942.10 2149694.90 154565.30 End Cry 17060.10 89.48 MAO 6942.78 712328 15111.22 4607.13 -14307.09 HS 2.00 685 84.35 54925.90 2149699.75 154556.16 17900.00 89.48 302.40 6943.06 712356 15141.90 4703.90 -14413.52 HS 0.00 6aS 8135 54925.92 214971724 154532.20 18000.00 8948 MAO 6943.90 7124.48 15239.93 4757.40 -14491.94 HS 0.00 666 84.35 54926.00 214977310 _ 154449.26 18100.00 89.48 MAO 6944.09 7125.39 15337.95 4B11.M -14502.37 HS 0.00 666 84.35 54926.07 214982896 154366.M 18200.00 8948 302.40 6945.00 7126.30 15435.97 4864.65 -14666.00 HS 0.00 667 84.35 54926.14 214988482 154283.31 18300.00 MAO 30240 6946.11 7127.21 15533.99 491823 -1475123 HS 0.00 667 84.35 54926.21 214994080 154200.43 18400.00 89.48 302.40 6947,63 7128.13 15632.02 4971.92 -14835,65 HS 000 6.68 84.35 54926.28 21499%.54 154117.49 c,w1W 18404.82 WAS 302.40 6947.67 7128.17 IMM74 491440 -14039.72 4.19R 000 6a8 8135 54926.29 2149993.23 15411349 Cry 3%00 1842230 90.00 30244 6947.75 7128.25 15653.01 4903.77 -14054.48 OAR 300 6.68 8465 54970.82 215000900 154099.00 1850000 92.33 30244 6946.17 7126.67 15730.01 502544 -14920.03 OAR 300 689 BLOB 55122.47 215005244 154034.60 KOP Cry 1,100 1851000 WM 30244 6945]4 7126.24 15739.80 5030.80 449287 LS 300 6.70 87.37 55135.09 215Wm03 158726.82 188W.00 WA3 30240 694302 7123.52 15827.97 5079.06 -15004.38 LS 200 611 85.64 5503445 2150108.33 15395114 Cry MOD 18660.87 No 30240 694228 7123.28 15886.77 5111.25 -1505501 155998 200 671 84.49 54939.07 2153141.89 153902.87 End Crv, 18068.05 8948 302.51 6942.04 7123.34 15894.66 5115.57 -15061,00 HS 200 6.72 84.33 54924.12 215014639 153095.33 1870087 89.48 30251 694313 7123.63 1592597 51K.74 -1500]5 HS 000 622 84.33 54924.14 21MI64.29 163080.06 188W.W 89.48 30251 694003 712453 16023.95 510649 4517307 HS 000 6.72 84.33 54924.20 21W220.31 153786.03 18900.87 8948 302.51 6944.93 7125.43 18121.94 5240.23 -1525740 HS 0.00 673 80.33 M924.27 21M276.m 153703.19 190W.W 89.48 302.51 694583 7126.33 16219.92 5293.97 -15341]2 HS 000 6.73 84.33 51924.33 2150332.35 15362036 19100.00 8948 302.51 694613 7127.23 16317.91 537.72 -15426.05 HS 0.00 6.74 84.33 54924.39 2150388.36 153531.52 19200.87 89.48 302.51 6947.0 7128.13 16115.89 5871A6 -15510.37 HS 0.00 6.74 04.33 54924.46 21W444.38 153454.69 Crv3n00 1920497 8948 302.51 694781 7128.17 1642076 5404.13 .1551456 12131, 0.00 674 8493 51924.46 2150447.16 153450.57 Cry 31100 1922255 WM 30240 6947.75 7128.25 1643793 5413.57 4552940 0.11R 300 6.74 84.86 51972.19 215045787 153436.87 19387.87 9232 30240 6946.18 1126.60 16513.89 54MM -15594]7 0.11R 3.00 6.76 870 5512293 2150500.25 153371.70 KOP CN 21100 1931087 92.62 MAO 6945.75 1126.25 1652369 5460.41 -15603.21 Ls 3M 6.76 67.30 5513631 215050584 153363.49 19400.00 90.82 MAO 6943.04 1123.54 16611.86 MOM -15679.16 LS 2.87 8.77 8565 55035.87 2150556.09 153200.80 Cry 1,100 19460.00 89.62 =AD 6942.81 7123.31 16670.68 5540.77 -15729.81 1658 2.00 6.78 84.87 51939.83 21WM9.61 153239.12 End Cry 19467.W 89.49 3M.44 694286 1123.36 16677.57 5544.54 45735.75 HS 2.87 6.78 84.36 UW689 21W593,M 153233.29 19500.00 8949 =Ad 6943.16 7123.66 1670908 558223 -15763.57 HS OW 6.78 84.36 51926.70 215061198 15320595 19600.00 89.49 302.44 694405 7124.55 1680789 5615.87 -15847.87 HS 0.00 6.78 00.36 51926.76 2150667.89 153123.05 19700.00 89.49 392.44 694495 7125.45 16905.87 M69.51 -1593235 HS 000 619 mm 51926.82 2150723.81 153040.15 198W.W 89.49 30244 6945.84 712694 11003.91 572315 -16016.74 HS 000 6.19 04.36 54926.88 2150119.73 15295725 19900M 88.49 302.44 694613 712723 1710192 5776.79 -16101.13 HS 0.87 6.87 04.36 $192893 2187035.65 152874.31 20000.00 89.49 3M.44 697.63 7120.13 17199.93 5830.43 -16165.52 HS 0.00 600 04.36 54926.99 2150891.56 152791.44 Cry 31100 20005.16 89.49 3M.44 697.67 7128.17 11704.90 5833.20 -16189.88 1.28 0.00 660 04.36 54926.99 2150094.45 152787.16 Cry 31100 28722.24 WM 392.43 6947.75 712825 10921.73 584236 4620429 O.ML 387 6.80 84.85 51971.80 2150904.00 15277387 20100.00 92.33 3M 43 6946.17 712667 11291.92 SKWM -16269.91 O.WL 3.00 6.82 81.09 5512326 215094746 15270851 KOP CN 211W 20110.00 9263 3M.43 6945.73 712623 17307.71 5889.41 -16278.34 LS 3.00 6.82 87.38 55136.62 215095304 t527W26 20287.00 W.83 3M.43 6943.01 712351 1739589 5931.64 -1635127 LS 200 6.83 85.66 55035.55 2151003.33 152625.67 Cry 211M 2MWM 0963 3M.43 694251 7123.27 174M 70 596982 -16404.91 175AR 2.87 6.03 84.87 5494041 2151036.87 152575.92 EndC, 20961.63 0940 3M." 694283 712333 17462.18 Ssn.91 -16111.35 HS 200 6.03 8435 5492643 2151041.13 152569.59 20387.00 8940 =A4 6943.12 7123.62 1749390 599127 -16438.67 HS 0.0 6.04 8435 5492645 2151059.23 152512.75 20400.87 89AS MAI 6944.03 7124.53 1759191 8744.91 -16623.06 HS 000 6.04 04.35 54926.50 2151115.15 162459.85 20WO.W WAS =A4 6844.93 712543 17689.92 0098.55 -16VrrA5 HS 0.00 604 8426 54926.0 2151171.87 152376.95 20600.87 89.48 302.44 6945.04 7126.31 17787.93 6152.19 -16691.84 HS 0.00 685 84.38 M926.60 215122696 152294.04 207W.00 8948 =A4 884815 7127.25 17885.94 8205.83 -16116.24 HS 0.00 8.05 0435 54926.65 2151262.89 152211.14 Cry 31187 20799.25 89.48 30244 6947.65 7128.15 17983.21 6259.06 -1685999 40.26L 0.00 686 8436 54926.69 2151338.39 152128.86 20800M 89,W MA3 6947.65 7128.15 17983.95 6259.47 .1686063 4026L 3.00 686 84.38 54928.65 2151338.01 15212823 Cry 31187 2002193 WOO 302.00 69715 712835 18005.46 6271.16 -16079.19 1.5R 3.00 6.86 SIM 54982AO 2151M1.0 16211000 20900 00 9234 302.06 6946.16 7126.66 18082M 6312.55 -16945.35 1.518 3.00 6.87 8721 55120.71 2151394.18 157044.99 KOP Cry &100 20910.00 92.64 872.07 6MS,72 7126.22 18091 87 6317.86 -16953.82 LS 300 6A7 8749 5514142 2151399.71 152036.67 210W.W Wed 302.07 6942.99 712349 1818015 6365.62 -17030.04 LS 2.00 6.88 M.1 55043.59 2151449.53 151961.76 Orvw1w 2106087 8964 30207 6942.73 7123.23 1023903 6391.7 .1700089 106.26R 2.00 6.89 84.62 5495061 2151487.75 151911.87 End Cry 21089.22 8948 W2.fi3 697.96 7123.46 18267,68 6413.11 -17105.57 HS 200 689 84.30 M92135 21514W 05 151807.56 Cosmopolitan Unit\Cosmoplttan Pad\H75-P2\H15-P2\H75-P2 (P1) Drilling Office 2.8.572.0 . Schlumberger -Private 10/9/2018 2:33 PM Page 4 of 5 Cosmopolitan Unit\Cosmoplitan Pad\H75-P2\H15-P2\H15-P2 (P1) Drilling Office 2.8.572.0 . Schlumberger -Private 10/9/2018 2:33 PM Page 5 of 5 MD Incl Azim True NDSB ND VSEL NS EW TF BLS DlrecBorwl Exclusion Zona h,luslmn Zam GeoMap TB NaNInB exams, BemmeMa /ftl 17 19 IN (fl) IM1I Ifl I M1 I I I100fl DliBcu InMa Ahrt (°I I' I gv A"e� InTI (flus) (11118) MIS) 2110000 89.40 302.63 6943.06 712356 18278.24 "low -17114.65 HS 0.00 6.89 84M 5492136 2151505.11 151818.64 21200.00 89.48 302.63 6943.97 712407 18376.18 8472.84 -17198.86 HS 0.00 6.90 84.30 54921AO 2151581.30 151795.92 21MM 0948 302.63 6914.08 7125.39 18474.12 6526.76 -1M83.06 HS 0.00 6.90 8430 54921.44 2151617.49 151713.20 2140.0 8948 3D2.63 690.5.79 712629 1857207 6580.68 -17351.29 HS 0.00 6.91 84.30 54921.49 215167388 151630.48 2150000 8948 302.63 6946.70 7127,20 10870.01 6634.60 -17451.50 HS 0.00 6.91 84,30 54921.53 2151729.88 151547.77 21600.00 89.48 302.63 6947.62 7128.12 18767.95 6688.52 -17535 M HS 0.00 6.92 8430 5492157 2151706.07 151465.05 Civ 3.11100 21606.14 89AS 302.63 6947.67 7128.17 18773.96 6691.83 -17540.88 3.331. 0.00 6.92 84.30 54921.57 2151789.52 151459.97 Civ 3.11100 21623.02 90.00 302.60 6947]5 712835 18790.50 8700.93 -17555.11 1.111. 3.10 6.92 8481 54968.9 2151799.00 151446.00 21700.00 92.39 302.55 6946.15 712665 10865.89 5142.36 -17619.95 1.11L 3.10 6.93 87,12 55124.27 215184248 151382.30 2180000 85.48 302.49 693929 711979 10963.63 6796.00 -9704.06 1.11L 3.10 6.80 89.89 55193.93 2151898.08 151299.68 21900.00 9858 302.43 6927.04 710) 54 19060.89 694826 .1M07.79 1.12L 3.10 6.95 8690 55112.94 2151953.61 151217.43 22000.00 101.68 302.37 009.45 7089.95 19157,37 6902.00 -17870.89 1.13- 3.10 6.97 83.90 54881.58 2152008.59 151135.79 EsdC, 22037.94 102.86 302.35 6901.30 708188 19193.72 6921.85 -17902.21 HS 3.10 6.97 82.77 54754.62 2152029.28 15110503 22100.00 102.86 30285 6BB7.67 7068.07 1925304 6954.22 -17953.32 HS 0.00 6.97 82.77 54754.41 2152063.03 151054.81 TD MUM 102.86 302.35 688267 706117. 19274.40 6965.70 -17871.45 0.00 6.98 82,7 54754.33 215207500 15103700 Sury Error Mods: ISCWSA Rw 0'--3d 95.000% Confidence 2.7955 sigma Survey Program: Descrip0on part MD From MD To EOU Fre, Hoh Slxe Casing Diameter Expected Max Su" Tool type Emshola I Suiv I 0.000 1500.000 1/10.000 17500 13.375 SLB -MWD -STD 1104-1-01/1104--01(Pt) 2 0000 5623048 WIMO0 9.500 13.375 SLBMWDeGMAG 1104-101/1104--01(Pt) 2 5623048 7050.000 11100.000 122% 9.625 SLB_MWOSTB H04-LO1 11104101 (P1) 3 5623.048 15481000 11100000 12250 9.625 SLB_MWD.GIMG H04.101 11104101 Sal) 3 15481.000 16120000 11100000 8.500 0,000 SLB_MWDSTD 1104-LOI I1104i01(PI) 4 IM81000 16120.000 11100000 8.500 0000 SIB MWDeGMAG 1104-1.0111104-1.01 (PI) 4 16120.000 16900.000 1/10000 8.500 0.000 SLB_MWD•GMAG HM-LO2/HO4-LO2(Pt) 4 16900.000 17710000 11100000 0.600 0.00 SLB MWD4G5MG 1404-1.0311104-I.03(Pi) 4 17710.000 18510.00 1/100.00 8.500 0.00 SLB_MWD4GMAG 1104-1.04/1104--041P1) 4 10510.000 19310.00 11100000 8.500 0000 SLB_MWD•GMAG H04-1-05/1104-1-05(PI) 4 19310.000 20110.000 111M." 8.500 0.000 SLB_MWD4GWG 1104-106/1104--061P11 4 20110.000 20910.000 11100.000 6.00 0.00 SLB_MWD4GMAG H04-LO71 H04-L07(Pt) 4 20910.000 22122.010 11100000 0.500 5.500 SLB_MWD+GMAG H04/H04(P1) Cosmopolitan Unit\Cosmoplitan Pad\H75-P2\H15-P2\H15-P2 (P1) Drilling Office 2.8.572.0 . Schlumberger -Private 10/9/2018 2:33 PM Page 5 of 5 V.00 ft N. G." %ane (P.00 k N. 0.00 R E) O 291.00• Vertical Section (N) ve Ocal $ on Nane (0.00 k N. 0.00 R p ® 291.00• Vertical Section (k) WEST (k) EAST WEST (k) EAST S[blumberpe Prime H04 (P1) Anti -Collision Summary Report Analysis Dats-24hr Time: September 25,2018-15:38 Analysis Method: Normal Plane Client: BlueCrest Reference Trajectory: H04 (P1) (Def Plan) Field: Cosmopolitan Unit Depth Interval: Every 10.00 Measured Depth (ft) Structure: Cosmopolitan Pad Rule Set: DSM AntiCollision Standard 5002 v5.115.2 Slot: H-04 Min Pts: All local minima indicated. Well: H04 Version / Patch: 2.10.544.0 Borehole: H04 Database 1 Project: localhost\dnlling-Cook Inlet Scan MD Range: 20910.00ft-22122.018 Traiectory Error Model: ISCWSAO 3-D 95.000% Confidence 2.7955 sigma, for subject well. For Offset Trajectories Summary Offset Selection Criteria Wellhead distance scan: Restricted within 63132.51 ft Selection fillets: Definitive Surveys - Definitive Plans- Definitive surveys exclude definitive plans - All Non -Def Surveys when no DefSurvey is set in a borehole - All Non -Def Plans when aro Def -Plan Is sal in a borehole Offset TrajectorySe Allow Sep. Controlling Reference TrajectoryRisk Level Alert Statue Ct-Ct fi MAS ftaration EOU k Dev. k Fact. Rule F MD (ft)TWD ft Alert Minor mador F major Major H00.L07 (P1) (Def Man) Fail Major 0.00 298.03 -199.12 -298.03 -0.01 0SF180 20910.00 7126.22 OSF<500 OSF<1.50 0SF<1.00 Enter Major 004 159.33 -10660 159.28 -001 OSF1,50 2092000 7125.78 MInPt-OSF 0.17 159.6 -10867L -0oi OSF1.50 20930.00 7125.37 MINPr-O-EOU =159.44 0.39 159.90 -10664 159.51 -0.01 CSF1.50 20940.00 7125.00 Minlot-0-ADP 10.44 165.37 -3.23 -57.93 0.97 OSF1.50 21456]5 7128.81 OSF>100 Exit Major 164.12 166.45 52.72 -2.34 1.48 CSF1.50 21595.59 7128.08 OSF>1.50 Exit Minor 301.91 154.29 198.62 147.62 2.95 OSF1.50 22057.23 7077.59 TD H00.1_06 (P1) (Def Plan) Weming Alert 210.14 158 NJ 103.74 51 191 1.99 0SF1.50 20910.00 7126.22 OSF<5.00 Enter Alen 43283 165.26 322.21 26].5] 395 OSF1.50 21375.00 7126.06 TD Hansen #tA (Def Survey) Warning Alen 1400.42 778.74 882.26 62367 2.71 OSF1.50 20914.53 712802 0SF<5.00 Enter Alen 1334.09 783.021 811.75 55.07 2.58 OSF1.W 21092.27 7123.49 Min%s Hansen #tAL1 (Def Survey) Pass 3014.23 740.52 2520.20 2273.70 6.111 OSF1.50 21069.54 7123.30 MInPI-O-SF 3000.36 750.33LL 2499.7 2250.0 6.00 OSF1.50 21477.40 7127.00 MinPts 2966]0 75372 2485891 2234.97 5.95 OSF1.50 22122.01 7063.17 Min%. H16(Def Survey) Pass R3118.68 288.25 2926.18 2830.43 16.28 OSF1.50 20910.00 7126.22 MinM-CtCI 3119.59 291.42 2924.98 2828.17 16.11 OSF1,50 21032.95 712319 MinM.CtCt 3119.60 291.9 2924.64 2827.85 16.0 WF1.50 21052.64 7123.20 Min% 3118.99 302.47 2915.02 2814.52 15.50 OSF1.50 21452.88 71211.78 MinPt-CtCt 3117.51 304.05 2914.48 2813.46 15.43 OSF1.50 21502.88 7127.23 MINK-O-EOU 3121.67 West 2915.!gJ 2812.7 15.20 OSF1.50 21851.43 ]128.03 MIePt-O-ADP 3137.09 325] 2919. 2811.321114.48 OSF180 22122.01 ]063.1] MinPt. H16A-L07(P3)(Diff Plan) Pass 323360 319,251 W20.4411 291435 15.24 OSF1,50 20910.00 7126.22 MinPts 3235.84 320.48 3021.68 2915.36 15.1 OSF1.W 21055.97 7123.21 Minh-OSF 3239.10 328.223021.2 291288 14.93 OSF1.50 21886.19 7127.75 MINPT-O-EOU 3241,81 329.44 3021.86 2912.37 14.80 OSF1.W 21865.86 ]098.55 MinPt-O-ADP 3243.58 331.12 3022.51 2912461 14.73 OSF1.50 22122.01 7063.17 MvPt-0-SF H16A(P3)(Def Plan) Pas. 3233.60 31925 3020.4 2914.35 15.24 OSF1.50 20910.00 7126.22 MinMx 3235.84 32048 3021.88 2915.36 15.19 OSF1,50 21055.97 7123.21 MInPt-O-SF Rhlumberter-Private Schlumbeger-Private 3239.10 $28.23021.29 2912.68 14.93 OSF1.50 21668.19 7127.75 MINPT-0-EOU 3242.25 330.18 3021.W 2912PAL 14.77 OSF1.50 22048.]] 7079.47 WPI -O -ADP 3243.09 330.97 3022.11 2912.12 14.]4 OSF1.50 22122.01 7063.17 MmPt-O-SF H16A-WS(P3)(Def Plan) Pass 3233.61 319.31 3020.41 2914.30 15.23 OSF1.50 20910.00 712622 MlnPts 3236.14 320.67 3022.03 291547 1518H OSF1.50 21055.11 7123.21 MinPI-O-SF 3236.84 321.14 WMA 2915.7 15.16 OSF1.W 21155.49 7124.06 MlnPI-O-ADP 325264 32].75 3033.81 2924891 14.93 OSF1.W 21845.00 711494 MinPI.O-SF H16A-L05(P3)(Df Plan) Pass 3242.]5 319.30 3029.58 2923.45 15.28 OSF1.W 20910.00 712622 MlnPN 3251.31 320.56 3037.27 29M.75L_15,261 OSF1.W 21052.51 7123.20 MmPt-O F 3257.21 321.12 3042.80 2936.09 15.2fi OSF1.W 21184.135 7124.33 MhPt-O-SF H12-LO6(Def Survey) Pass 4049.85 289.35 3856.62 3760.50 21.06 OSF1.50 20910.00 7126.22 MinPt-=t 4049.97 289.613856.57 3760.36 21.04 OSF150 20940.90 7124.96 MINPT-O-EOU 4050.04 289.69 3858.59 3]60.35 24.04 OSF1.W 20950.71 7124.83 MinPI-O-ADP 4051.85 290.55 385]83 3761.31 2096 OSF1.W 21058.68 7123.23 Minpl-0-SF 4051.82 290.36 3857.92 376146 2100 OSF1.60 21098.19 7123.54 Minpt- t 4053.75 292.00 38581 3]61]5 20.89 OSF1.W 21278.17 7125.18 WR-O-AOP 409.5] 29402 3861.23 3763.55 20.78 OSF1.W 21484.69 7127.07 MinPt- Ct 4057.59 294.12 3881.1 3]63.4] 20.76 OSF1.50 21493.80 7127.15 MIOPIS 4084.08 296.66 3884.62 3765.40 20.47 OSF1.50 21958.25 7W8.W MInmI tCt 4064.21 299.1 3864.4 3765.06 20.44 OSF1.50 22008.15 7088.28 MINPT-O-EM 4064.29 299.24 3W 471 3765.05 20.44 OSF1.50 22018.56 7086.10 MinPt.O-ADP 4066.34 300.23 3865.85 3]66.11 20.36 OSF1.50 22122.01 7063.17 WnPt-O-SF H12 (Dal Survey) Pass 4049.85 289.35 3856.62 376050 2106 OSF1.50 20910.00 7126.22 MmPl-CtCt 4049.97 289.81 3856.57 320940.90M OSF1.50 20940.90 7124.96 MINP74}EOU 4115004 289.69 385&591 3760.35 2104 OSF1.60 20950.71 7124.83 MMR -O -ADP 4051.85 290.56 3857.83 3761.311 OSF1.50 21058.89 7123.23 MmPt-O-SF 4051.8 290.36 385792 3761.46 21.00 OSF1.50 21098.19 7123.54 MInPt-CICI 4054.00 2925 38586 3764.45 20.85 OSF1.50 21338.17 7125.73 MINPT-O-EOU 4054.15 292]3 38586 3]fi1.42 2084 OSF1.50 21358.17 7125.91 MlnPt43-ADP 40W 63 M,80LM862,4H 3763.83 2059 OSF1.50 21773.98 7122.09 MINPT-O-EOU 40610 298.64 3861.61 376239 2046 OSF1.50 21958.02 7097.98 MinR.CtM 4061.28 300241 OSF1.50 2212201 7063.17 MinPts H12-L05(Def Survey) Pass 407167 289.52 38]8.33 3]82.15 2116 OSF1.50 2091000 7126.22 MmPls 40W14 290.84 3885.92 3789.30 21.11 OSF1.50 21056.04 712321 Min%-OSF 40801 290.65 3886.03 3]89.48 21.12 OSF1.50 21095.29 7123.51 MinPt-CtQ 407941 295.05 3882.39 3784.37 20.80 OSF1.W 21544.90 ]12]61 MInPl.=t 496.63 33OXI M52.251 37Q,461 18,2311 OSF1.W 2188683 7109.46 MinPts H42{04 (Def Survey) - .1h, 40]4.54 289.50 3881.21 3785.04 21.18 OSF1.50 20910.00 ]126.22 MlnPls 408595 290.78 3891.77 3795.17 21.14 OSF1.50 21059.51 7123.23 MinPt-O-SF 4085.91 290.58 389187 3795.34 21.16 OSF1.W 21097.65 7123.54 mhm-CICS 4095.11 332,811 OSF1.W 21195.12 7124.42 MinPts Survey) Pass 1]0.8 6665.18 86280 60.3] OSF1.50 21386.33 ]126.1] MinPls 540888 189.83 528L86 52190 43.1] OSF1.W 22036.95 7082.10 Minft 5408.8 189.83 5281.67 5219.05 43.17 OSF1.50 22038.41 ]061.]8 MinPt-CICI 5804.34 188.03 5479.67 541832 45.66 OSF1.W 22120.87 7063.42 TD 4610.51 208.17 4471.07 4402.34r 33.53 OSF1.W 21433.64 7126.60 MhPt-O-SF 4809.53 208.0544]0.17 4401.48 3354 OSFt.W 21434.13 ]128.80 MinPle 6814.00 189.91 8]000 8844.0 60.85 OSFtW 21739.14 7124.60 MinPls Schlumbeger-Private H14PB1 (DO Survey) Pass 4687]4 278,671 4W1.631 4409.07 25.32 OSF1.50 20918.15 712686 MinPls 4692.83 2]9.96 4W5.86 "12.8711 25.2AI OSF1.50 21057.34 7123.22 Min% -0 -SF R WA5 279.7 4W5.81 4412.68 25.24 OSF1.50 21082.18 7123.10 Min%s 4892. 279.74 4505.62 4412.70 25.24 OSF1.50 21093.24 7123.W Min%-C(Ct 48964 28852 450377 4407.92 2449 OSF1.50 21878.55 7110.52 MmPt- tCt 4697.06 2913 4502.50 "06.721 2426 OSF150 22122.01 ]063.1] Min%s H14PB3 (DO Survey) Pass 4]93.84 278.6 460T8] 4515.3 2591 OSF1.50 20910.00 7126.22 Minpis 4796.64 279.93 4609.70 4516.71 25.]9 OSF1.50 21058.]8 ]123.23 Min%-OSF 4796.49 279.78L_1609 " 45167 25.80 OSF1.50 210]81] 7123.35 Ms% 07984 2]9.]3 4609.65 4516.74 25.81 OSF1.50 21086.59 7123.53 Min%-CICt 0798.0 283.39 4809.15 4515.01 25.8 OSF1.W 21444.82 712610 Min%-CIQ 479686 286.30 460566 4510.56 25.21 OSF1.0 21710.77 7126.17 Min%-CiQ 4796.97 286.824805.5 4510.35 25.19 OSF1.W 21740.07 7124.55 MINPT-O-EOU 4]97.08 288.73 450.5.5 451033 25.18 OSFi.W 21]49.80 7123.90 Min% -0 -ADP 4W7.54 337.89 458195 4489.85 21.0 OSF1.0 22081.91 7072.09 Min%s H14(Def Survey) Pass 4896.46 27947 4709.82 4016.98 26.37 OSF1.50 20910.00 7126.22 MinPts 4897.53 280.24 4710.37 4617.2L 28.30 OSF1.50 20988.51 712368 Min% -0 -ADP 4898.51 280.87 4]1094461].65 28.2 OSF1.50 21055.33 7123.21 Min%-0SF 4898.39 280.8 4]10. 4617.70 26.28 OSF1.50 21083.63 7123.41 MINPT-0EOU 4898. 280.67 4710.95 4817)2 26.27 OSF1.50 21092.73 7123.49 Min%-CtCt 4898.56 280.87 4710.98 461].] 26.25 OSF1.50 21112.69 7123.67 Min% -0 -ADP 4899.76 282.20 4711.31 4617.5 26.13 OSF1.50 21242.27 7124.85 Min% -0 -ADP 490486 287.73 4]12.71 4617.13 25.65 OSF1.W 21]5].40 7123.37 MINPT-0-EOU 49964 291.84 4]11.60 4614641 25,301 OSF1.60 22122.01 ]063.1] MmPls 1164-1-01(PI)(D6f Plan) Pass Hi BA-L04(P3)(DO Plan) Pass H04-102(P1)(DO Plan) Pass Hanson #1(DO Sun ) Pass H12-1011(DO Survey) Pass H12 -L03 (Oef Survey) Pass H16PB1(Def Surrey) Pass 1-104�104(PI)(Def Plan) Pass H14PB2(DO Survey) Pass H16A4.01(P3)(00 Plan) Pass 1-104-1-05 (P1) (DO Plan) Pass H1M-1-02(P3) (DO Plan) Pass H04-L03(Pi)(DO Plan) Pass HI6 1-03 (P3) (DO Plan) Pass H12-L02(DO Survey) Pass 5shlunnbergerPrivate Offset Trajectory Allow I Sap. I Controlling Alert 11041.06 (P1) (Def Plan) 1104-1-07 (P1) Anti -Collision Summary Report Analysis Data24hr Time: September 25, 2018-15:27 Analysis Method: Normal Plane Client: BlueCrest Reference Trajectory: 1104-L07(PI)(Def Plan) Field: Cosmopolitan Unit Depth Interval: Every 10.00 Measured Depth (8) Structure: Cosmopolitan Pad Rule Set: D&M AntiCollision Standard 5002 v5A15.2 Slot: 11414 Min Pts: All local minima indicated. Well: H04 Version I Patch: 2.10.544.0 Borehole: 1104-1.07 Database l Project: Iocalhostiddlling-Cook Inlet Sean MD Range: 20110.00%- 22048.92% Enter Major Trajectory Error Model: ISCWSA0 3-D 95.000% Confidence 2.7955 sigma, for subject well. For -103.27 -154.wl 41.01 OSF1.50 Offset Trajectories Summary 712579 Offset Selection Cntena MrP1-0-SF 0.17 Wellhead distance scan: Restricted within 63059.41 ft 154.44 41.01 Selection filters: Definitive Surveys - Definitive Plans- Definitive surveys exclude definitive plans 7125.39 MINPT-O-EOU -All Non -Def Surveys when no Def -Survey is set in a borehole - All Non -Def Plans when no Def -Plan is set in a borehole 0.39 Offset Trajectory Allow I Sap. I Controlling Alert 11041.06 (P1) (Def Plan) Fail Major 0.00 291.3] -194.88 -0.01 OSF1.50 20110.00 7126.23 OSF<500 OSF<L50 OSF11.00 Enter Major 0.04 154.33 -103.27 -154.wl 41.01 OSF1.50 2012000 712579 MrP1-0-SF 0.17 154.61 -103.3 154.44 41.01 OSF1.50 2013000 7125.39 MINPT-O-EOU 0.39 154.89 -103.30 -_1MA 41.01 OSF1.50 20140.00 7125.01 MinN-O-ADP 107.41 160.85 41.12 43.24 1.00 OSF1.50 20656]] 7126.86 OSF>1.00 Exit Major 15096 161.48 51.88 -1.52 1.49 OSF1.5D 20786.50 7128.03 OSF>1.50 Exit Minor 333.40 139.10 240.24 194.30 3.61 OSF1.50 21511.45 7005.17 TD H04L05(P1)(Dar Plan) -_-- - -- - - - Warning Alert 21006 154201 106,831 55861 205 OSF1.50 20110.00 7126.23 OSF�5.00 Enter Alen 483.85 160.96 376.10 322.89 4.53 OSF1.50 20581.37 7127.08 TD Hansa. #1A (Def Survey) Warning Alen 1728.42 ]62.12 1220.01 966.30 3.40 OSF1.50 20118.79 7125.84 OSF<5.00 Enter Alen 1333.90 783751 811.07 550 151 2.55 OSF1.50 21083.72 7110.34 MmPts Hanson #1AL1(Del Survey) HE3015.85 72101 2534.83 2294. 6.28 OSF1.50 20110.00 7126.23 Peas Minns 30151 726.21 253065 2288.93 8.23 OSF1.50 20400.09 712453 MInR-01Ct 3015.50 ]2].42 2530.21 L 2288.0 6.22 OSF1.W 20479.29 7125.25 MINPT4 EOU 3016.02 728.08 2530.30 228]. 8.22 OSF1.50 20518.98 7125.61 MinPI-O-ADP 2955.10 759.90 2448.50 2195]0 5.84 OSF1.50 22048.92 6783.25 Min%9 H18 (Del Survey) Pass M311]21 283.58 2927.83 283363 16.54 OSF1.Ed 20742.57 7127.63 Min%-CtCt 3118.52 300.30 2918.00 2818.22 15.62 OSF1.W 21372.66 7049.42 Minpt-CiCt 3119.06 303.29 2915.54 2815.77 15.47 OSF1.50 21489.61 7019.52 MINPT- EOU 3119.56 303.89 2916.84 2815.6] 15.44 OSF1.W 21488.57 7013.12 MinPt-O-ADP 3153.07 323.23 293726 2829.84 1467 OSF1.50 2204146 6786.39 MinPt-03F Hi BA -LW (P3)(Oef Plan) Pass 3224.]3 312. 3016.37 291269 15.55 OSF1.50 20110.00 7126.23 M'oRs 323181 318.20 3019 35LL ZL13 61JL 15.28 OSF1,50 20807.62 7128.21 MinN-0-ADP 3252.08 329.39 3032.16 292269 14.85 OSF1.50 22048.92 6783.25 Mirpt-O-SF HIM(P3)(Def Flan) 3224.73 312.04 3016.3] 2912.69 15.55 OSF1.50 20110.00 7126.23 Pass MinPts 3231.81 318.20 3019.35 2913.61 15.28 OSF1.W 20807.82 7128.21 Minn -O -ADP 325742 328.97 3037.77 2928A]iJ 14.89 OSF1.50 22048.92 6783,25 MrR-0-SF 1-1164-1-06(P3)(Def Pbn) Pass Schlumberger -Private Hit -L03 (Def Survey) 4059201 3224.]3 312.04 3016.37 2912.69 15.55 OSF1.50 20110.00 7126.23 283.46 3231.81 318.21 3019.35 2913.61 15.28 OSF1.50 20807.62 7128.21 329.30 3241.30 32].]4 3022.4 2913.56 14.87 OSF1.50 21881.17 6854.04 H16A-105(P3)(Daf Plan) 4059.32 282.93 38]0.3] 31]6.3 3224.]0 312.0] 3016.36 29126] 15.54 OSF1.50 20110.00 7126.23 21.32 325391 320.97 3039.60 2932.93 15,251 OSF1.50 21250.09 7080.48 H16Ai04 (P3) (Def Plan) 20667.92 7128.96 408].90 287.75;:38]5]51 21.27 OSF1.50 20895.35 3233.49 312.04 3025.13 2921.46 15.59 OSF1.50 2011000 7126.23 7062.83 3250.89 314.23 3041.08 2938.88 15,W1 OSF1.50 20416.04 ]124.6] 4611.15 3254.38 314.55 3044.33 2939.81 15.58 OSF1.50 20488.55 7125.13 H12-LOS(Def Survey) 208.25 44]1.]0 4402.95 33.52 OSF1.50 21439.82 7029.20 4]99.12 403643 283.19 3849.31 3755.24 21.46 OSF1.50 20175.60 ]123.9] 403845 283.263849.2 3]55.19 2145 OSF1.50 20185.41 ]123.]6 4038.51 283.34 3849.29 3]55.1 21.45 OSF1.50 201913.80 7123.56 405500 336.63 3830.25 3]18.3] 18.12 OSF1.50 2197340 6815.12 H12 -LOG (Def Survey) 4038.43 283.20 3849.30 3755.23 2146 OSF1.50 20175.60 ]123.9] 4038.45 283.26[:] 84918 3155.18 21.45 OSF1.50 20185.41 ]123.]6 4038.51 20.35 3849281 3755,161 21.45 OSF1.50 20188.80 7123.56 40498 289.12 385615 376010 21.08 OSF1.50 20878.89 ]12].40 4049.95 289.61 385655 3760.34 21.04 OSF1.50 20944.38 7124.33 4050.09 289.78 385658 3760.32 21.03 OSF1.50 20966.12 7122.81 4058.5 293.8 3862,291L_37".67 20.78 OSF1.50 21490.68 701240 405859 29394 3862.30 3]64.6 20.78 OSF1.50 21501.10 7008.80 4063.55 298.22 3864.41 3765.33 20.50 OSF1.50 21995.93 6805.61 4083.60 298.39 316521 20.49 OSF1.50 22015.81 670.22 4083.74 298.57 3864.3] 3]85.1] 20.48 OSF1.50 22035.70 8788.83 4063.88 298.69 3884.43 3765.19 20,47 OSF1.50 22048.92 6783.25 H12(Def Survey) 4038.43 283.20 384930 375523 21.46 OSF150 20175.60 7123.91 403845 283.28 3849.28 3755.18 21.45 OSF1.50 20185.41 1123.76 403851 283.35 384928 3]55.18 21.45 OSF1.50 20196.80 1123.58 0049.82 289.12 3856.75 3180.10 21.08 OSF1.60 20878.89 ]12].40 4049.95 289.61 3856.55 3160.34 21.04 OSF1.50 20944.38 1124.33 4050.09 289.78 3856581 21.03 OSF1.50 20966.12 712281 4073.14 29850 38]3.82 3774,641 M,531 OSF1.50 2204892 6783,25 Hit -L03 (Def Survey) 4059201 282.75 38]0.36) 3]]6.441 21.80 OSF1.50 2011000 1126.23 400.00 283.46 30]]0 3]83.54 21.5 OSF1.50 20201.31 712349 4098.76 329.30 3878.90 316046 18,721 OSF1.50 20489.27 1125.34 H12 -L04 (Def Suney) 4059.32 282.93 38]0.3] 31]6.3 21.59 OSF1.50 20114.56 7126.03 406260 281.13 3875.85 3180.47 21.32 OSF1.50 2082201 1128.54 406]]1 28].5 3815]0 3780.19 21.29 OSF1.50 20667.92 7128.96 408].90 287.75;:38]5]51 21.27 OSF1.50 20895.35 1127.21 4090.05 M.691 3887.92 3157.35 1B."I OSF1.50 21323.34 7062.83 Surrey) 4611.15 208.24 44]1.61 4402.91 33.52 OSF1.50 2143298 7031.36 4611.20 208.25 44]1.]0 4402.95 33.52 OSF1.50 21439.82 7029.20 4]99.12 202.74 4663.30 4596.38 35.84 OSF1,50 22048.92 6183.25 H14P131(Def Survey) 475 17 2]0]1 4494.36 4404.45 25.99 475.32 271.59 4493.93 440373 2591 075.49 2]2.04493.] 4403.42 25.87 4676.18 273.87L 4493.27 4402.31 25.70 46]6.59 2]4.36 4493.36 4402.23 25.66 OSF1.50 20110.00 112623 OSF1.50 2021745 7123.31 OSF1.60 20218.50 712343 OSF1.50 20468.20 1125.15 OSF1.50 20518.01 7125.60 Schlumberger -Private MinPts MlnPI-O-ADP Mine Pass MinPis MinPI-O-SF Pass Min% MmPt43 F TD Pass MInR-=t MINPT-0{01J MmPt-O-AOP Mins Pass MinR-CtCt MINPT4 EOU Min%-OADP MinPt-=t MINPT-0{01J MInP1-O-AOP Minft Minh -O -ADP MinPtCtlu MINPT- EOU MhPt-OADP Min% -O -SF Pass MInm-CLCt MINPT-O-EOU MmPt- Mla Min!N- VM MINPT-O-EOU MlnPl-O-ADP Min% -O -SF Pass MInNs MmPt-O-SF MinNs Pass MlnPts MmPtCta MINPT-O-EOU Min!N-0 DP Min% Pass MmRs M'mPI-O-SF TD Pass Mink-CtCI MmPt4tC1 MINPT-O-EOU MINPT-O-EOU Min% -O -ADP H14PB3 (Def Survey) H14 (Def Survey) H16A-L01(P3)(Del Plan) Hansen #1 (Def Survey) W0 L04(Pi)(Def Plan) Survey) H12-1,01 (Dal Survey) H16A-102(P3)(Daf Mn) H12 -L02 (Def Survey) H16A-L03(P3)(Oaf Plan) H14PB2 (Def Surrey) H16PB1 (Def Survey) M0 1-01 (P1) (Def Plan) H04-L03(PI)(Def Pian) M0 1-02 (P1) (Def Plan) H 1BA-L01(P3)(00 Plan) H04-L02(P1)(Def Plan) Survey) Hl4PB2(Def Survey) H04L01(P1) (Def Plan) 4]02.58 285.39 4511.99 4417.19 24.80 4702.M 285.7 4511.8] 4416.95 24.77 4703.56 286,84 4512.00 4418.] 24.68 4710.43 289.60 451],03 4420.82 24.48 27063 4]]3.13 271.21 4]]3.33 271.47 4774.72 272.66 4798.63 282.77 4]98.8] 283.51 4799.05 285.27 4799.10 285.42 4799.16 265.51 4817.80 336A4 4502.13 4515.36 4513,78 26,54 26.49 26.4] 26.36 25.54 25.47 25.32 25.30 OSF1.50 2182264 6982.90 OSF1.50 21658.48 8948.02 OSF1.50 21]6].33 690268 OSF1.50 22048.92 6763.25 OSF1.50 20110.00 7126.23 OSF150 20174.55 7124.00 OSF1.50 20203.14 7123.47 OSF1.50 20WIN 7123.99 OSF1.50 21401.18 7041.12 OSF1.50 21479.41 701823 OSF1.50 21855.71 6949.19 OSF1.50 21670.28 8943.04 OSF1.50 218]8.]8 6939.45 OSF1.50 22035.26 6789.01 4893.53 2]6.0] 4709.15 4617.46 2666 OSF1.50 20588.49 ]12622 4693.] 2]].61 4708.35 4616.14 26.53 OSF1.50 20746.48 7127.67 4893.90 2]8.004708.24 4815.90 26.49 OSF1.50 20786.45 7128.03 4894.08 278.20 4706.28 4815.86 26.48 OSF1.50 2D602.02 ]128.1] 4897.39 280.2 4]10.22 4817.12 26.30 OSF1.5D 21004.90 7119,50 4897.72 280.65 4710.29 L==48117LO=6=126.26 OSFI.SD 21050.44 7114,60 4916.47 290.14 472271 4626 321 25.50 OSF150 22048.92 678325 Schlumberger -Private MInPI-QCt MINPT43-EOU MmRP ADP MmPt-OSF Pass Minks MINPT-O-EOU Min% -D -ADP MinPt-O-ADP MinPt-CtQ MINP7-O-EOU MmPt4 tQ MINPI-O-EOU Min% -O -ADP Mine Pass MInP1-=t MlnPI-QCt MINPT-O{OU MInPI-O-ADP MINPT-O-EOU MhPt-0-ADP Min% -O -SF Pass Pass Pass Pass Pass Pass Pass Pass Pass Pass Pass Pass Pass Pass Pass Pass Pass Pass Traveling Cylinder Plot NOGC Region nine as baud On Cxemed EOU Ddmdumn nfMinor 2 i A.CoxMan ruN uaed'. DO.M AnlColesldn Standard 5002 rQ tl! 3 281 27D FF[ North 350 D 10 TRAVELING CYLINDER PLOT client S..Coal F.W CeamopoOen Unn SVuqure Cefinep0laen Ped Wex H0e Borehole H04 Deb 24-S.,201S Method: Schlumberger -Private BO 00 IueC,fest Energy Attachi Cosmopolitan Project H0410-401 Fishbone APD Attachments H0410-401 Fishbone APD Attachments IuS eCiesr Energy Cosmopolitan Project MASP & Casing Design H04 Fishbone Well; Maximum Anticipated Surface Pressure (MASP): N 17.5" Hole Section it LI -- This hole section will be drilled with a divertero' nly, no BOPE. While MASP will equal the formation pore pressure at the surface casing shoe depth of 3,350' TVDss less a gas gradient to the surface, it cannot be shut in, only diverted. However, since no shallow gas in the surface section has been encountered in the first two offset wells on the pad (1-114 and H16), as well as the recently drilled H12, a diverter waiver for H04 has been requested. Offset well information indicates that the pore pressure at 3,350' TVDss will be a maximum of 9.0 ppg (0.468 psi/ft). Calculation for MASP (17.5" hole) = (3,350') x (0.468-0.10) =1,233 psi. 12.25" Hole Section The MASP for 12.25" hole section will be the formation pore pressure (less a full gas column to the surface) at 15,022' MD/ 6,900' TVDss Offset well information indicates that pore pressure at 6,900' TVDss will be a maximum of 9.66 ppg (0.502 psi/ft). Calculation for MASP (12.25" hole) = (6,900') x (0.502-0.10) = 2,776 psi. 8.5" Hole Section The MASP for the 8.5" hole section will be the formation pore pressure (less a full gas column to the surface) at 22,122' MD/ 6,883' TVDss. Offset well information indicates that pore pressure at 6,900' TVDss will be a maximum of 9.0 ppg (0.468 psi/ft). Calculation for MASP (8.5" hole) = (6,883') x (0.468 - 0.10) = 2,533 psi. With MASP in the 8.5" open hole section calculated to be 2,533 psi, the 5,000 psi BOPE system to be used will be adequate. 10-401 APD Attachments MASP & Casing Design lue est Energy Casing Design Verification: H04 Planned Casing program: Cosmopolitan Project MASP & Casing Design 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 operator's recommended design factors. Design Factors: Tensile Joint Strength: Nt = 1.8 SF Collapse (from external pressure): Nc= 1.125 SF Burst (from internal pressure): Ni = 1.25 SF The pore pressures and fracture gradients used here are those derived from studies of offsetting Cosmopolitan 1, Hansen 1 and Hansen 1A. 10-401 APD Attachments MASP & Casing Design 13.375" 9.625" Surface Casing Intermediate Casing Depth (MD) 5,623' 15,481' Depth (TVDss) 3,531' 7,067' Hole size 17.5" 12.25" Weight (ppf) 72 47 Grade L-80 P-110 Connection BTC Hydril563 Nominal ID (in) 12.347" 8.681" 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 operator's recommended design factors. Design Factors: Tensile Joint Strength: Nt = 1.8 SF Collapse (from external pressure): Nc= 1.125 SF Burst (from internal pressure): Ni = 1.25 SF The pore pressures and fracture gradients used here are those derived from studies of offsetting Cosmopolitan 1, Hansen 1 and Hansen 1A. 10-401 APD Attachments MASP & Casing Design lust Energy Cosmopolitan Project MASP & Casing Design H04 Casing Design Factor Calculations: Burst Requirements Use maximum anticipated surface pressures (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. 13.375", 72#, L-80, BTC Surface Casing: MASP at 12.25" hole section TVDss of 6,886': MASP = (6,886') x ((10.5 ppg x 0.052)-0.10 psi/ft) = 3,071 psi (burst stress) DFBur,t = burst strength / burst stress = 5,380psi / 3,071 psi =_.1-3-5 vs minimum SF of 1.25. 9.625", 47#, P-110, Hydril 563 Intermediate Casing: MASP at 8.5" hole section TVDss of 6,883': MASP = (6,883') ((10.0 ppg x 0.052)-0.10 psi/ft) =2,891 psi (burst stress) DFB„r,t = burst strength / burst stress = 9,440 psi / 2,891 psi = 3.27 vs minimum SF of 1.25. 10-401 APD Attachments MASP & Casing Design DI yeN sr Energy Collapse Requirements Cosmopolitan Project MASP & Casing Design Use an external pressure consisting of the formation pore pressure at the casing shoe and an internal pressure of a gas column to surface. 13.375", 72#, L-80, BTC Surface Casing: External pore pressure = 9.0 x 0.052 x 3,350' = 1,568 psi Internal pressure w/gas only = 0.10 x 3,350'= 335 psi Collapse stress = 1,568 psi - 335 psi = 1,233 psi. DFcollapse = collapse rating / collapse stress = 2,670 / 1,233 = 2.17 vs minimum SF of 1.125. 9.625", 47#, P-110, Hvdril 563 Intermediate9.625", 47#, P-110, 563 Intermediate Casing: External pore pressure Internal pressure w/gas only = 9.66 x 0.052 x 6,886' = 3,459 psi = 0.10 x 6,886'= 689 psi Collapse stress = 3,459 psi — 689 psi = 2,770 psi DFc"iiapse = collapse rating/collapse stress = 5,300 psi/ 2,770 psi = 1.91 vs minimum SF of 1.125. 10-401 APD Attachments MASP & Casing Design nue est Energy Axial Requirements 13.375", 72#, L-80, BTC Surface Casing: Weight in air = 5,623'x 72 Ib/ft Pipe weight in mud = Pipe wt (in air) x Buoyancy Factor (BF) BF for 9.6 ppg mud = (65.5-9.6)/ 65.5 Pipe weight in mud = 404,856 lbs x 0.8534 = 404,856 lbs. = 0.8534 = 345,504 lbs. Cosmopolitan Project MASP & Casing Design DFAmIl = body tensile strength / buoyed wt. = 1,661,000 lbs. / 345,504 lbs. = 4.81 vs minimum SF of 1.8. 9.625", 47#, P-110, Hydril 563 Intermediate Casing: Weight in air = (15,481'x 47 Ib/ft) = 727,607 lbs. Pipe weight in mud = Pipe wt. (in air) x Buoyancy Factor (BF) BF for 10.5 ppg mud = (65.5-10.5) / 65.5 = 0.8397 Pipe weight in fluid = 727,607 lbs. x 0.8397 = 610,972 lbs. DFA,iII =joint tensile strength/ buoyed wt = 1,493,000 lbs. /610,972 lbs. = 2.44 vs minimum SF of 1.8. 10-401 APD Attachments MASP & Casing Design nue est Energy Cosmopolitan Project MASP & Casing Design H04 Fishbone Well; Maximum Anticipated Surface Pressure (MASP): 17.5" Hole Section This hole section will be drilled with a diverter only, no BOPE. While MASP will equal the formation pore pressure at the surface casing shoe depth of 3,350' TVDss less a gas gradient to the surface, it cannot be shut in, only diverted. However, since no shallow gas in the surface section has been encountered in the first two offset wells on the pad (H14 and H16), as well as the recently drilled H12, a diverter waiver for 04 has been requested. Offset well information indicates that the pore pressure at 3,350' TVDss will be imum of 9.0 ppg (0.468 psi/ft). Calculation for MASP (17.5" hole) = (3,350') x (0.468-0.10) = 1,233 psi. 12.25" Hole Section The MASP for 12.25" hole section will be the formation pore 15,022' MD/ 6,900' TVDss Offset well information indicates that pore pressure at psi/ft). Calculation for MASP (12.25" hole) = (6,900') x 8.5" Hole Section The MASP for the 8.5" hole section will be the at 22,122' MD/ 6,883' TVDss. Offset well information indicates that psi/ft). (less a full gas column to the surface) at will be a maximum of 9.66 ppg (0.502 = 2,776 psi. n pore pressure (less a full gas column to the surface) at 6,900' TVDss will be a maximum of 9.0 ppg (0.468 Calculation for MASP (8.5" hole) = (083') x (0.468 - 0.10) = 2,533 psi. With MASP in the 8.5" open hole ection calculated to be 2,533 psi, the 5,000 psi BOPE system to be used will be adequate. 10-401 APD Attachments MASP & Casing Design Y P V o h o a v v v v v x w wu v v v h H H m L H w N a h u a a a ¢ Ju c a a a 0 0 a n .a lmn .+ o In In In m v e m In m toti N o m a m w o b W 00 0 N N N Ill m N '-I m m m N .y O M I�11 tmvl .Ni ^� � N O VOI C N ei lD O M l0 m .-i IO .r .r •� m .-+ .y m �+ vi n O O a O a d w N N 3u (O d tp M yl d d V E m V U d d Ol c O C m O x Y C O c U _J E `1 E V1 d o .� '3 d c '3 3 J E vu m�E aLL E v wc �' >, V c H 10 L E u io o o ww w w a y j a u .� E > m> D> c J E E w E o E o v_ F ¢ ov c c c c `w Y F Y v u c u > U d '" d d d y u V 'm,� O_ 'm O u O O v a E E E E= m m a y m d O V W V V V C pp N N J x C C y y J m> m J N N m m L O O O O O O V ¢¢ Z H e\' P r �- r P H V VL ut � Z H V H > 1- Y vmi N a a 0 0 0 v v v v a v L L L a �n vl in yo a L '� '� a s '^ a a U u v v d U�dl C c_ c a a a a n J a a a a J a v a 1] J J a J J L Ip Ip a a y y a y y a In N m m m o Vl Ill o n ry o 0 0 o O V m n M N n N O m O 1l1 V1 VI U1 m O YI w m N ti n N N 1� to O N V1 m m v a p a v a N 3 v VI d m 3 V 10 7 J m d P N O d X y p E c U c m U U c m O w O 'd C O C y O: \ O N W V d Nv n v e E E d m o m '3 v J J E E '^ E p1 p1 m m E v > E vl E v v 2 E >m> om > o > �uu a N .m-Ia v v a m 2 > u J a a d o u v o �' o i v w 2 c 9 i o w c 0 c m E L E -o u m E > m> o i o o d v _= E u E d y d a J H V O v m- J m > N> 0 Y d m d li v E Ili E cJ o 0 d V O > O- d_ U d J m F u ¢ O C d N C d C d C d C m C C C d J Y u V C V U C u G o N N o `o o a? E ,d, E E E v N v v v o_ m m° A -°- u u J C y L L N m d U d W V V V d d x d d d m m F F J d J H y �- d h N ul d o m m in c N J a x a a a a V K w u U U c '.n c '.n d v>> 'y m Gy m v �. m w m m m m x w=__ O O c c S V 2 O� F J J m U¢¢ J o J J J J F e F U V Vl V1 H u H F V Hj 1> f f lue est Energy Attachmen Cosmopolitan Project H0410-401 Fishbone APD Attachments H04 10-401 Fishbone APD Attachments nue Energy BlueCrest LOT/FIT Procedure Cosmopolitan Project LOT/FIT Procedure 1. Drill out the shoe track and clean out any rat hole from the previous hole section below the shoe. From this depth, drill an additional 20 ft (minimum) to 50 ft (maximum) of new hole. 2. Circulate the wellbore clean and ensure MW in= MW out. Record this value. Lineup one mud pump on the kill line. Isolate the other pump(s). 3. Turn on the pump to flood the kill line and to ensure the hole is full and that no air is present in the circulating system. 4. While pumping, ensure that the pump pressure gauge and the gauge on the chart recorder are reading the same pressure. 5. Shutdown the pump, position a tool joint at the rig floor and close the upper pipe rams. 6. Bring the mud pump online slowly at % -'/: bbl per minute and watch for pressure to start increasing. 7. Verify no fluid is leaking past the closed pipe rams. Record the pressure from the chart recorder vs strokes pumped every 2 or 3 strokes pumped. The pressure should increase in a linear fashion vs strokes (Volume) pumped. 8. To perform a LOT (Leak -off Test), continue pumping and recording pressure vs strokes until the pressure deviates from a straight line trend. Obtain two additional readings to confirm this deviation from linearity. 9. Shut down the pump and continue to record pressure vs time, initially every 30 seconds for 2 minutes and then every minute for an additional 8 minutes. 10. Plot the points for the pressure build up vs volume pumped on one chart and the pressure drop vs time on a second chart. 11. By looking at the chart of pressure vs volume pumped, the leak -off pressure is the point at which the curve deviates from a straight line trend. 12. Use the formula: MW + Pressureyeak off MWEquivaient = TVDShoe x 0.052 13. Report using the format below: • XX.XX ppg EMW FIT/LOTw/ XXX psi and XX.XX ppg MW @ X,XXX' TVD 14. The FIT follows the same operational steps as previously described, except that the pressure is increased to a pre -determined value previously calculated, where the plot of pressure vs volume pumped does not deviate from a straight line. Using the same formula, the FlTvalue is obtained. If, however, deviation from a straight line does occur, do not keep pumping. The leak off pressure has been reached and additional pumping may cause the formation to break down. 15. The final step is to bleed off the pressure from the test and measure the volume of fluid returned to a small pit such as the trip tank or small pill pit. Depending on well design and depth, this volume bled back could be small — maybe no more than 1 bbl. 10-401 APD Attachments LOT/FIT Procedure tSlueNest Energy Attachment Cosmopolitan Project H0410-401 Fishbone APD Attachments H0410-401 Fishbone APD Attachments !ue st Energy Cosmopolitan Project BOP & Choke Manifold Configuration i 5K# WI H tOK 49 3/32- 0 0 /32"0TT0 FLANGE (U M 66 5/8" I o CL a�D ¢! a N 27 3/4" 0 41 11/16" a% ) ° 13 5/8"X10K# CAMERON BOP STACK BLUECREST ENERGY 13 5/8 -MON CA OWN BOP STACK Y-� - —6 ma Of JK VM IML W01 Pro - - - -- 1 6 l6 av rW - uw w rri Fa :B5K7g02 2 10-401 APD Attachments BOP & Choke Manifold Configuration nue est Energy Cosmopolitan Project BOP & Choke Manifold Configuration 10-401 APD Attachments BOP & Choke Manifold Configuration z I U lb ay 3534_' J o� W MR Y B � y i 'ow O 3 I O m a 4 w z Y y O I o d x I 1 z M � z — , ¢ ai3 0-, a o w yQW S N 10-401 APD Attachments BOP & Choke Manifold Configuration nue est Energy Diverter 'OPE PORT a LL a CLOSING PORT J. G FLANGED - M AS CAST - N - - Cosmopolitan Project BOP & Choke Manifold Configuration ILAS ST m a P m AS CAST + _ i_ K - CLF AMP L ASCAST -- .{ HUB Nominal Dimensions—Inches—with 2000 psi Bottom Connections A B Hub 16 51 I C ., O 12Y: E F 231102 G H J K GV%, 27% 46% L 51% M N 0 $814 52% 150 P Rio 52W 1w,6MEMO LHub 54Hub Ya 5044 .. 12V2 23% 5n 91'4 Vis 2741 Nominal Dimensions—inches—with 3000 psi Bottom Connections A B CD E F G M J K L M N O P 17 FMA 1 54Hub Ya 5044 .. 12V2 23% 5n 91'4 Vis 2741 4514 51* 5844 52% 50 Hi 10-401 APD Attachments BOP & Choke Manifold Configuration IueC.fest Energy Attach Cosmopolitan Project H0410-401 Fishbone APD Attachments H0410-401 Fishbone APD Attachments ? A' /< -21, S x Z/1 r, �0 L SWDd Aid uoj@wo0 d0H anon au11 9�oy0 y10 L SWDd O.F8' uoaauau0 y0l SWDd g uoaauau0 Aq aolnuuy u 011DWGgDS �1004S dO8 ['ON 0121 ,10213N3 1S32103mo Sanlon II!� NOt a)IoyO algD}sn(pD IDnuDry „9L/L £ bl N01 a>1o40 0pnoiD6H OOVMS ,9L/L £ £L SAIDA p10;!uow S-Ij uaawDO NO L ,.91/ L £ Qt SAIDA pIO;Iuow Sj j uwawo0 y01 .91/L £ I t aAIDA p1O;!uDw S'Id u0Jaw00 NO „9L%L £ Ot aAIDA pl0}!u0w SIA uOJaw00 N0 ,9L/I. £ O6 SAIDA pl0}!uow Slj u0jawD0 mo I. „9L/L £ O SAIDA pl0}!uow S -U DaawDO NOL „91/L 9 LO SAIDA plo;!u0w S -U UWSWDO NOl .9L/L £ O OAIOA piO}!UDw S -LA uOJawDO NOL „9l/L £ O aAIDA pp;!uDw Sl_i uOJawDO NOt .91/L £ O aAIDA plO}!uow S -IJ uwawo0 N01 „91/1. £ £O aAIDA pID}IUDw S13 uOJawDO NOL „91/t £ ZO aAIDA uO!}DIOS! a6nob S -I3 u010wDO NOL „9l/L Z lO z �'`Q�U Ol na%l� l� 5i! tt 4 j4=v7I°7�7 l 014DWayOS PIOJ!uoW OJOLAO L'ON 0PJ kOdIN13 iS:i(1oiin-i8 Ilue lest Energy Cosmopolitan Project Wellhead/Tree ♦ us6 sago rx I I 1 . i loss• • vus,ouo lsl • as xl W/M:ar S(W. PxN 631' ♦ F lN- sssro s,uao vv .:!1!' i Jtl ull M-0 1 u Sw SAW PSI 1 Ij .••- 15R•PKRCYI j..�_i 52'CSG H6x L r6.05' d i 11.5'b•SA99P11 i MWCMl MNIYfN i i j — DMI, sr ®Gl'.ld 6 G6 — ue-rrraror KILLNEAO assn son •-1 `e :s Jwwm--- IIG Manllf•l MW9Cr9 954•ODC56---- 10-401 APD Attachments Wellhead/Tree IueNest Energy Attachmen Cosmopolitan Project H0410-401 Fishbone APD Attachments H0410-401 Fishbone APD Attachments BlueCrest Rig 1 Diverter Line Routing Options While Working on H04 Well Slot Attachment 15-7 to APD Form 401 Package H04 Diverter Routing Options (if waiver is not granted) y U U 7 T 7 7 7 - 7 Truck & loader access From this end only U \ Diverter line orientation B and outlet options A Diverter line is 18" in ID / surface hole bit size is 17-1/2" / Line length 80' minimum Line would use 45 deg elbows to enable routing to SW corner of pad Line would be raised using pipe stands or buried, or combination of both No truck / loader access On this end of rig L. . r,, c� U UU U U T T l T U \ Diverter line orientation B and outlet options A Diverter line is 18" in ID / surface hole bit size is 17-1/2" / Line length 80' minimum Line would use 45 deg elbows to enable routing to SW corner of pad Line would be raised using pipe stands or buried, or combination of both AOGCC Diverter Regs • (c) Except as provided in (d) and (h) of this section, a high capacity flow diverter system must be installed to provide safety for personnel and equipment before rotary rig drilling is performed below a well's structural or conductor casing, unless the casing is equipped with BOPE conforming with (e) of this section. The following provisions apply to a diverter system: • (1) the diverter system must consist of a remotely operated annular pack - off device, a full -opening vent line valve, and a diverter vent line with a diameter • (A) of at least 16 inches, unless a smaller diameter is approved by the commission to account for smaller hole size, geological conditions, rig layout, or surface facility constraints; and • (B) at least as large as the diameter of the hole to be drilled, unless a pilot hole with a diameter no larger than that of the vent line is drilled first; the commission will waive the requirement of this paragraph if the operator demonstrates, based on drilling experience in the near vicinity, that drilling a pilot hole would not be necessary for safety; • (2) the diverter system must be assembled as follows: • (A) the diverter vent line outlet must be located below the annular pack -off, either as an integral part of the annular pack -off device or as a vent -line outlet spool immediately below it; • (B) the actuating mechanism for the vent line valve must be integrated with the actuating mechanism for the annular pack -off device in a fail-safe manner so that the vent line valve automatically opens before full closure of the annular pack -off; AOG CC Dive rte r Regs • (C) the vent line must extend to a point at least 75 feet • (i) away from a potential source of ignition; and • (ii) beyond the drill rig substructure, or to a point within the reserve pit and at least 50 feet beyond the drill rig substructure; • (D) the vent line must be as straight as possible, secured to prevent movement, and designed to avoid freeze-up; • (E) the vent line may be secured to the rig and with portable cradle supports, but may not be attached to flowlines, cable trays, or other processing equipment; • (F) all turns with a bend radius less than 20 times the inside diameter of the vent line must be targeted; • (G) all valves must be full -opening; • (3) a clearly marked "warning zone" must be established on each side and ahead of the vent line tip, and the following restrictions must be in effect within the warning zone, beginning with the function test of the diverter system immediately before drilling operations begin and ending with diverter system rig -down: • (A) a prohibition on vehicle parking; • (B) a prohibition on ignition sources or running equipment; • (C) a prohibition on staged equipment or materials; • (D) the restriction of traffic to essential foot or vehicle traffic only; • (4) the commission will, in its discretion, inspect the diverter system for compliance with the requirements of this subsection and require the operator to test the system to ensure proper operation. lue est Energy Attachment 8: Cosmopolitan Project H0410-401 Fishbone APD Attachments H0410-401 Fishbone APD Attachments E41 Tis. I �O Hansen 1A ' SEC. T35. R1N1 H-1 H04 with 1000' Radius Around Production Section H04 Surface Location (NAD 27) Northing: 2,144,623.03', Easting 168,812.80' 2173' FSL, 1552' FEL, Sec. 2, T4S, R15W SM Surface Casing Point Northing: 2,145,687.06', Easting 165,349.46' 3,143' FSL, 5,044' FEL, Sec. 2, T4S, R15W SM Intermediate Casing Point (Top of Production) Northing: 2,148,421.8', Easting: 156,564.79' 350' FSL, 3,337' FEL, Sec. 33, T3S, R15W SM Total Depth Northing: 2,152,075.44, Easting: 151,037.26' 3,84T FSL, 3,680' FEL, Sec. 32, T3S, R15W SM ADL38440 SEC 28. T3S. R:SW. SM 9V{pf 511 'SH: 33. n SEC 4. T4S, R15W. SM Cosmopolitan Unit Development Date 26/09/2018 Company BlueCrest Energy ADL39190 Confidential NOP. T3S. R15W. SM SEC 26. T38, R15W, E 34 T3S R15W PM ADL18790 SEC 3.T45.R15W.SM 0 1000 2000 3000 4000 5000ftUS 1:30000 SEC 35, T35, R15W. SEC 36. PETRU. lNest Energy r Attachment • ductor Slot Survey Cosmopolitan Project H0410-401 Fishbone APD Attachments H04 10-401 Fishbone APD Attachments NOTE: The 20" Conductor and Surface Slot Location as -built schematic for H04, to be prepared by Lounsbury Surveyors, will be provided to include in this APD package when the 20" is set and the as -built schematic is completed. lflueNest Energy Attachm Cosmopolitan Project H0410-401 Fishbone APD Attachments H0410-401 Fishbone APD Attachments NOTE: The New Well Elevation Form for H04, to be prepared by SLB Directional Drillers, will be provided to include in this APD package when the BlueCrest Rig 1 is on the H04 well, actual elevation measurements can be taken, and the surface slot as -built schematic has been completed. l'NeSt Energy Cosmopolitan Project 3301 C Street, Suite 202, Anchorage, AK 99503 Thomas W. McKay, P.E. Phone: (907)754-9566 Email: tom.mckay@bluecrestenergy.com ''` '0111E October 17, 2018 a :,... &� i7 'as ra.�, Alaska Oil and Gas Conservation Commission 333 West 7°i Avenue, Suite 100 OCT 17 2018 Anchorage, Alaska 99501 �` RE: Application for Permit to Drill: Horizontal Production Well H04 °0 °- (� C Request for Diverter Variance as per 20 AAC 25.035 (h)(2) Dear Commissioners, BlueCrest Alaska Operating LLC, under a separate cover, hereby applies for a Permit to Drill for the onshore horizontal production well H04. This well will be drilled and completed using BlueCrest Rig #1. The planned spud date could be as early as 15 November 2018. In addition, under this cover, BlueCrest Alaska Operating LLC hereby applies for a diverter waiver for the H04 well to be drilled from the Hansen / Cosmopolitan Project drill site north of Anchor Point, Alaska. This waiver is requested under 20 AAC 25.035 (h)(2) of the AOGCC Regulations. Based on the lack of shallow gas observed in the offset wells (H-1, H16, H14, and H12) in the immediate vicinity of the H04 surface location, BlueCrest requests a variance from the AOGCC to waive the requirement for a diverter on the surface section of this H04 well, as the presence of shallow gas has been proven to be non- existent on the initial drilling operations in the near vicinity of this drilling location, as per 20 AAC 25.035 (h)(2). Four (4) wells have been drilled from this drilling pad adjacent to the H04 surface slot, those being H1, H12, H14 and H16 (aka Hansen 02), and all these wells did not penetrate or expose any recordable volumes of shallow gas in the surface section. It should be noted that the H04 surface slot is only forty (40) feet away from the H1 well which was drilled from the H06 slot (see attached well row schematic). Attached are several documents supporting this position, listed as follows: Attachment 1 Diverter Waiver Summary Attachment 2 Diverter Waiver Exhibits Attachment 3 Well Data File Attachment 4 Surface Casing Points Section 2, US, R15W Attachment 5 Pattern Within ADL 18790 Attachment 6 Development Pattern Map Attahcment 7 Mudlogs on File at AOGCC for: Cosmopolitan State 1 BlueCrest H12 BlueCrest H14 BlueCrest H16 Hansen 1 BlueCrest can provides these mudlog files on a disk or flash drive if needed by AOGCC staff. If you have any questions or require further information, please do not hesitate to contact Tom McKay at 907-754-9566 (office) or 907-350-9544 (cell). Geologic related questions can be addressed to Andrew Buchanan at 907-754-9563 (office). Sincerel4t-/ 4�_6� Larry Burgess Alaska Manager BlueCrest Alaska Operating LLC H04 Diverter Waiver Discussion Surface Section There have been four (4) wells drilled from the Hansen Drilling and Production Pad; the Hansen 1, H12, H16 and H14. The surface sections these wells and all future development wells are completely contained within Section 2, Township 4 S, Range 15 W, SM. The four (4) wells successfully drilled the surface sections of the wells with no evidence of gas accumulations or over pressure. The wells were drilled with spud mud ranging from 9.0-10.0 ppg. All future development wells are being planned with the surface casing shoe set at similar depth as the H14 and H12 wells within the same stratigraphic interval. The Formations penetrated are the overlying surface sediments, Beluga and Upper Tyonek Formations. Lithology The surface sediments consist of sand, gravel, silt and occasional clays. The Beluga Formation is made up of thin bedded sandstones, coals, siltstones and silty shale intervals deposited in a braided stream environment. The Upper Tyonek Formation consists of fluvial conglomerate, conglomeratic sandstone, sandstone, siltstone and shale deposited in meandering streams, associated fluvial sediments and lacustrine environments. Shallow Hydrocarbon Accumulations There is no evidence of any significant accumulations of hydrocarbons in the shallow sands of Hansen Drill Pad location. No oil or gas accumulations were encountered in the shallow sands of Hansen 1 well drilled from the Hansen drill pad. Mudlogs from the Hansen 1, H12, H16 and H14 wells showed the presence of minor gas associated with the degassing of coals as they were circulated out of the well, the maximum reading for Hansen 1 was 1083 units at -3,010' TVDSS; 70 units at -2702' TVDSS in the H16 well 194 units at -2704' TVDSS in the H14 well. Once the coal cuttings were circulated out of the hole, the ditch gas readings returned to background levels. Well Cosmopolitan 1 Hansen 1 H16 H14 H12 Surface Casing Shoe MD 2033' 5176' 4147' 4217' 4177' Max Ditch Gas 214 Units @ 689' TVDSS 1083 Units @ -3010 NDSS 70 Units @ 2702' TVDSS 194 Units @ 2704' NDSS 343 Units @ 4101' MD Formations Surface sediments, Beluga, U. Tyonek Surface sediments, Beluga, U. Tyonek Surface sediments, Beluga, U. Tyonek Surface sediments, Beluga, U. Tyonek Surface sediments, Beluga, U. Tyonek Uthologies Conglomerate, Sands, Sandstone, Siltstone, Clay, Shale, Volcanics, Coal Conglomerate, Sands, Sandstone, Siltstone, Clay, Shale, Volcanics, Coal Conglomerate, Sands, Sandstone, Slltstone, Clay, Shale, Volcanics, Coal Conglomerate, Sands, Sandstone, Siltstone, Clay, Shale, Volcanic, Coal Conglomerate, Sands, Sandstone, Siltstone, Clay, Shale, Volcanics, Coal �1 Cosmopolitan Unit Development Pattern Date 07/062017 Company 1 BlueCrest Energy SE SEC SEC SEC 7 Cosmopolitan Unit Development Pattern Date 07/062017 COtmany 81ueCrest Energy 0 2000 4000 6000 8000 100001NS 1:48000 Rig Positioned on H04 Well Slot No truck / loader access N cn oo n t0- 4f7 -d-„? O m 6 � o O b b On this end of rig S i 2 i T 2 i=== i x x= S Y M i i Z w V) M/ j / Diverter line is 18" in ID / surface hole bit size is 17-1/2" Line would use 45 deg elbows to enable routing to SW corner of pad Line would be raised using pipe stands or buried, or combination of both AOGCC PTD No. 218-126 Coordinate Check 16 October 2018 INPUT Geographic, NAD27 Hansen H-04 Latitude: 59 51 29.73683 Longitude: 151 48 05.85554 OUTPUT State Plane, NAD27 5004 -Alaska 4, U.S. Feet 1A NorthingfY: 2144 62 3.036 EastinglX: 168812.804 Convergence: -1 33 29.34454 Scale Factor: 1.000024835 Remark: Corpscon v6.0.1, U.S. Army Corps of Engineers TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: Z l Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: V /psi <--e- k - POOL: /if G &-f r / Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. _'API No. 50- - (� (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool HANSEN, HANSEN UNDEF OIL - 290100 PTD#:2181260 Company BLUECREST ALASKA OPERATING LLC Initial Class/Type Well Name: HANSEN H-04 Program DEV Well bore seg ❑ DEV/ PEND GeoArea 820 Unit 10370 On/Off Shore On _ Annular Disposal ❑ Administration 17 Nonconven, gas conforms to AS31,05,030(j.t.A),Q,2.A-D) .......................NA - - - - .......................... _ ................... _ ... Commission r: Date C� ��/9 1 Permit fee attached NA I� ��� 2 Lease number appropriate . . . .... . . . . ...... . .. . . . . . . _ _ _ _ Yes _ _ _ _ Surface Location lies within. Fee-Hansen;, Portion of Well Passes.Thru. AD40018790; 3 Unique well name and number ... . ......... . . ........ Yes .... _ TO liesjn AD40384403. 4 Well located in.a defined pool_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___ No ...... Hansen Undefined Oil Pool_ 5 Well located proper distance from drilling unit boundary_ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 6 Well located proper distance from other wells_ _ _ _ _ . . . . . . . . . ... . ... . ....No... _ _ .. SPACING EXCEPTION REQUIRED, HANSEN,. HANSEN _UNDEF.OIL -290100, governed by statewide spacing r 7 Sufficient acreage available in. drilling unit _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ As planned, this well does NOT conform with statewide spacing requirements.... 8 If deviated, is wellbore plat. included ..... . ............................. Yes .. SPACING EXCEPTION REQUIRED: Well lies within some governmental quarter section as Hansen 1A. 9 Operator only affected part _ _ _ . .... . .......... . Yes 10 Operator has. appropriate bond in force _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes Appr Date 11 Permit can be issued without conservation order. _ _ _ No _ SPACING EXCEPTION REQUIRED: Well lies within same governmental. quarter section as Hansen.1A.. _ 12 Permit can be issued without administrative approval _ _ _ _ Yes SFD 10/17/2018 13 Can permit be approved before 15-day wait _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 14 Well located within area and strata authorized by Injection Order # (put. 10# in comments) (For NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _____________ 15 All wells. within 1/4mile 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 ...... _ _ _ ..... _ 18 Conductor string. provided ..... _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ 20" conductor driven to 193 ft. Engineering 19 Surface casing protects all known U$DWs _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ 13 3/8" surface casing will be. set at 3530 ft TVD 20 CMT vol adequate to circulate on conductor & surf.csg .. ........ Yes ........... .. .... .. ......... . 21 CMT vol adequate to tie-in long string to surf csg_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No.... _ _ _ _ 9 5/8" will have 1000 ft of cement 22 CMT will cover all known_ productive horizons _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ Drilling lateral spokes... will be left OH.. 23 Casing designs adequate for C, T, B R. permafrost_ _ . _ ................ Yes .. _ 13TC calc provided. 24 Adequate. tankage or reserve pit _ _ _ _ _ _ _ _ _ _ ..... - Yes _ . Rig has steel pits.... all.. waste transported. to approved disposal well. _ 25 If a_re-drill, has a 10-403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA 26 Adequate wellbore separation proposed. _ _ .. _ Yes _ _ No issues with close crossing... 27 If.diverter required, does it meet. regulations _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___________ NA _ ... Diyeter waived per 20 PAC 25.035 (h)(2).. Appr Date 28 Drilling fluid_ program schematic.$ equip list adequate _ _ _ _ _ _ _ _ _ . Yes Max formation pressure = 3549 psi (9,66 ppg EMW) will drill with 10.5 ppg mud GLS 10/31/2018 29 BOPEs, do they meet regulation .... _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - 30 ROPE press rating appropriate; test to (put psig in comments). ................. Yes _ _ _ MASP .= 2842. psi (will. test BOPE to 3500 psi) .............. ... 31 Choke manifold complies w/API RP-53 (May 84)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Yes ... 32 Work will occur without operation shutdown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 33 Is presence of H2S gas probable .. .. _ _ No... _ _ _ _ _ H2$ not expected .... _ 34 .Mechanieal.condition of wells within AOR verified (For service well only) ...... . . . . . . .. NA _ . - - - - - - _ . _ .. _ --- ._35 35 Permit can be issued w/o hydrogen_ sulfide measures _ ................... Yes ..... H2S not observed in nearby Hansen wells..Rig has sensors and alarms, Geology 36 Data presented on potential overpressure zones. _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ Horizontal well targeting Starichk_of sand and Hemlock. Planned mud weights in oonjunction with. _ Appr Date 37 Seismic analysis of shallow gas zones.... .. _ .. _ _ _ _ _ _ _ _ _ _ _ _ NA _ Managed Pressure. Drilling technique appear adequate to control. maximum anticipated. downhole SFD 10/16/2018 38 Seabed condition survey (if off-shore) .............................. . . NA _ _ _ pressure of 9.66 ppg, which is based on MDT measurements of reservoir pressure in. nearby well, 39 Contact name/phone for weekly progress reports [exploratory only] _ _ _ NA Geologic Engineering Mainbore will have slotted liner. The lateral up dip spokes will be left OH. GIs Commissioner: Date: (�� Commission r: Date C� ��/9 ommissi � Date AIS I� ��� I' IC�tPI
