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M 0 `M` r O O M J a Q a LL 0 r M H If) 5 z o G/ N W re I re � to a Q a c - Y o Y a l►0 0 z d inco• 10ti p �. o F i I' 3 N N d re 0 0 I c U .2 �a U a C7 • a 0 O a 2 c.) • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: Oil ❑.,E. Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended lb.Well Class: 20AAC 25.105 20AAC 25.110 Development ❑ ' Exploratory ❑ GINJ ❑ WINJ ❑ WAG❑ WDSPL❑ No.of Completions: Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6. Date Comp., Susp.,or 14. Permit to Drill Number/ Sundry: ConocoPhillips Alaska, Inc. Aband.: •8/5/2015 215-107 - 3.Address: 7. Date Spudded: 15.API Number: P. 0. Box 100360,Anchorage,AK 99501 •7/31/2015 50-029-21828-63 • 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 876'FNL, 1929'FWL,Sec.22,T13N, R9E, UM •8/2/2015 KRU 30-08L1-03 Top of Productive Interval: 9. KB(ft above MSL): 58' 17. Field/Pool(s): 1304'FSL, 1896'FWL,Sec. 15,T13N, R9E, UM GL(ft above MSL): 33' Kuparuk River Field/Kuparuk River Oil Poo Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 1799'FNL, 841'FEL, Sec. 16,T13N, R9E, UM 11000'MD/6655'TVD ADL 25513 • 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 525566 y- 6021944 Zone- 4 .11001'MD/6655'TVD ALK 2554 TPI: x- 525521 y- 6024123 Zone- 4 12. SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 522773 y- 6026290 Zone- 4 2002'MD/2002'TVD 1604'MD/1604'TVD 5. Directional or Inclination Survey: Yes - (attached) No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 na (ft MSL) . 7790'MD/6708'TVD 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion, suspension,or abandonment,whichever occurs first.Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance,dipmeter,formation tester,temperature,cement evaluation, casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary GR/Res RECEIVEL SEP 032015 23. CASING, LINER AND CEMENTING RECORD 'OGCC WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASINGGRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT PULLED 16" 62.5# H-40 35' 110' 35' 110' 24" 164 sx AS II 10.75" 45.5# J-55 35' 2619' 35' 2619' 12.25" 1300 sx AS III,225 sx AS II 7" 26" J-55 33' 7746' 33' 6915' 8.5" 400 sx TLW,200 sx Class G,225 sx AS I 2.375" 4.6# L-80 7411' 11000' 6652' 6655' 3" slotted liner 24.Open to production or injection? Yes ❑ No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 3.5" 7137'/7435' 5424'MD/6136'TVD and slotted liner from 7411'-11000'MD 6652'-6655'TVD 7189'MD/6479'TVD 26.ACID, FRACTURE,CEMENT SQUEEZE, ETC. '• ev Was hydraulic fracturing used during completion? Yes n No ❑ Per 20 AAC 25.283(i)(2)attach electronic and printed information I t'��� DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED -:Sr.j' .�... ...-.:...I none 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 8/17/2015 gas lift oil Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 8/17/2015 19 hours Test Period -* 1901 1622 3015 176 Bean 853 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 233 138 24-Hour Rate .-6. 1639 1199 2423 21 Form 10-407 Revise 5/ 015 CONTINUED ON PAGE 2 Submit ORIGINIAL only 7/�/� vr� ill /� 9���� BQI SEP 0 4 201 � r 11111 28. CORE DATA Conventional Co. Yes ❑ No ❑ Sidewall Cores: ❑ No ❑✓ 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. NONE 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes El No Permafrost-Top surface surface If yes, list intervals and formations tested, briefly summarizing test results. Permafrost-Base 1604' 1604' Attach separate pages to this form, if needed,and submit detailed test information, including reports,per 20 AAC 25.071. Kuparuk Al 7790' 6708' Kuparuk A2 7852' 6703' Kuparuk A3 8448' 6708' NONE Kuparuk A2 8615' 6653' Kuparuk A3 8746' 6645' Kuparuk A2 9484' 6636' Kuparuk A3 9625' 6631' Kuparuk A2 10841' 6644' Formation at total depth: Kuparuk A2 • 31. List of Attachments: Summary of Daily Operations,schematic,directional survey 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. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Cody Pohler Email: Cody.Pohler(C7cop.com (.) I7 Printed Name: Dan Venhaus Title: CTD Engineering Supervisor Signature: Phone: 263-4372 Date: -2-/5 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 1 a: 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 lb: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results, including,but not limited to: porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including, but not limited to:core analysis,paleontological report, production or well test results. Form 10-407 Revised 5/2015 Submit ORIGINAL Only 41 KUP PROD • 30-08 ConocoPhillips NIA Well Attributes Max Angle&MD TD Alaska,Inc. Wellbore API/DWI Field Name Wellbore Status Ind(°) MD(ftKB) Act Bim(ftKB) OmocoPtem,. 500292182800 KUPARUK RIVER UNIT PROD 42.82 4,800.00 7,770.0 °°° Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date 30-08,8/1720152'30:47 PM SSSV:TRDP Last WO: 6/16/2015 33.98 7/20/1988 Vertical schematic actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date ---, - -- ---- --. - .... - --- Last Tag:SLM 7,414.0 4/5/2015 Rev Reason:ADD LATERALS L1(off main smsmith 8/10/2015 HANGER;33.0 -#41�` wellbore),L1-03,&L1-04,PULL PLUG,GLV C/O Casing Strings ��/. "ni CasingDescriptionOD(in) ID(in) Top(ftKB) SetDepth(ftKB) SotDepth(ND)..WVLen(I...Grade Top Thread 1CONDUCTOR 16 15.062 35.0 110.0 110.0 62.50 H-40 Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread SURFACE 10 3/4 9.794 35.0 2,619.0 2,618.8 45.50 J-55 BTC Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread L1 WINDOW 7 7,417.0 7,425.0 6,662.8 CONDUCTOR;35.0.110.0 Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread PRODUCTION 7 6.276 33.0 7,746.3 6,915.4 26.00 J-55 BTC SSSV;2,001.0 '11$. Tubing Strings Tubing Description String Ma...'ID(in) 'Top(ftKB) I Set Depth(ft..1Set Depth(ND)(...I Wt(lb/ft) 'Grade 'Top Connection TUBING-UPPER- 31/2 2.992 33.0 7,137.21 6,438.8 9.30 L-80 EUE 8rd Mod WO 2015 Completion Details GAS LIFT;2,497.1 4 Nominal ID _ Top(ftKB) Top(TVD)(ftKB) Top Inct(°) Item Des Com (in) 33.0 33.0 0.32 HANGER CAMERON GEN IV TUBING HANGER 2.950 I I 2,001.8 2,001.6 0.55 SSSV CAMCO CMT-5-SR W/X PROFILE 2.813 7,117.5 6,423.6 39.40 LOCATOR BAKER GBH-22 LOCATOR SUB 3.000 SURFACE;35.0-2,619.0 7,118.0 6,424.0 39.39 SEAL ASSY BAKER 80-40 GBH-22 SEAL ASSEMBLY 3.000 - Tubing Description (String Ma...I ID(in) (Top(ftKB) I Set Depth(ft...1Set Depth(TVD)(...I Wt(Ib/ft) (Grade 'Top Connection GAS LIFT;3,719.2 j, 4 TUBING-SCAB 51/2 4.950 5,423.8 7,208.2 6,493.8 15.50 L-80 BTCM LINER-WO 2015 Completion Details Nominal ID Top(ftKB) Top(TVD)(ftKB) Top Ind(*) Item Des Com (in) GAS LIFT;4,782.9 5,423.8 5,136.4 41.83 PACKER BAKER HRD-E ZXPN LINER TOP PACKER 4.890 5,439.3 5,148.0 41.77 HANGER BAKER HMC LINER HANGER 4.860 5,448.3 5,154.6 41.74 Liner Liner,5-1/2",15.56,L-80,BTCM-SCC,Box x Pin 4.950 GAS LIFT;5,374.6 7,122.7 6,427.6 39.38 XO Reducing Crossover,5-1/2"BTC Box x 5"BTC Box 4.380 7,125.0 6,429.4 39.38 SBE BAKER 80-40 SEAL BORE EXTENSION 4.000 7,143.5 6,443.7 39.34 XO Reducing Crossover,5"BTC Box x 3-1/2"EUE 8rd Pin 2.980 PACKER;5,423.8 - = 7,1$6.7 6,477.2 39.26 LOCATOR BAKER GBH-22 LOCAT03R-1 R SUB 2.990 HANGER;5,439.3 7,187.2 6,477.5 39.26 SEAL ASSY BAKER 80-40 GBH-22 SEAL ASSEMBLY 2.990 Liner;5,448.3 Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection I � TUBING-LOWER- 51/2 5.012 7,189.3 7,435.0 6,670.6 14.00 J-55 STC GAS LIFT;6,561.3 WO 2015 Completion Details liii Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (in) GAS LIFT;7,063.1 7,189.3 6,479.2 39.25 PACKER BAKER F-1 PRODUCTION PACKER 4.000 7,192.6 6,481.7 39.24 SBE BAKER 80-40 SEAL BORE EXTENSION 3.990 7,212.0 6,496.7 39.19 XO Reducing Crossover,4-3/4"Stub Acme Box x 3-1/2"EUE 8rd Pin 2.930 LOCATOR;7,117.5 7,292.1 6,558.9 38.95 Coupling Coupling,3-1/2"EUE 8rd Mod Box x Box 2.992 Liner-Pup;7,114.8 7,292.6 6,559.3 38.95 NIPPLE HALLIBURTON X NIPPLE 2.813 xo Reducing;7,122.6 P_1 7,345.7 6,600.6 38.67 Ported Ported Crossover,3-1/2"EUE 8rd Mod Box x 5-1/2"STC 2.992 SEAL ASSY;7,118.0 I� SBE;7,125.0 Crossover Pin AYE 1116 7,346.7 6,601.4 38.67 WEARSOX 6"OD Wearsox,5-1/2",14#,J-55,STC Box x Pin 5.012 XO Reducing;7,143.5 '_ ® Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) Top(TVD) Top Incl Top(ftKB) (ftKB) ("I Des Com Run Date ID(in) LOCATOR;7,188.7 7,415.0 6,654.9 38.36 WHIPSTOCK BAKER GEN II WHIPSTOCK 7/16/2015 :a 7,583.0 6,786.8 38.20 FISH 8'Metal Strip From Perf Gun;Left in Hole 6/6/1989 PACKER;7,189.3 SEAL ASSY;7,1E721V'' F Perforations&Slots SBE;7,192.6 10/7 Shot Dens Top(ND) Btm(ND) (shots/f Top(ftKB) ,Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Com 7,416.0 7,432.0 6,655.7 6,668.3 A-3,30-08 6/6/1989 12.0 APERF 2 1/8"EnerJet;60 deg. phasing l 7,439.0 7,462.0 6,673.7 6,691.8 A-2,30-08 6/6/1989 12.0 APERF 2 1/8"EnerJet;60 deg. NIPPLE;7,292.6 phasing Mandrel Inserts st mi Top(TVD) Valve Latch Port Size TRO Run WEARSOX;7,348.6 N Top(ftKB) (ftKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com CAMCO 0.156 • 8/12/2015 a 2 3,719 2 3,718,0 CAMCO 0.15618/12/2015 CAMCO 0.18818/12/2015 I 4 5,374.6 5,099.8 CAMCO KBMG 5.55 GAS LIFT OV BK 0.188 0.0 W12/2015 WHIPSTOCK;7,415.0 -.1 CAMCO DMY DK 1.000 0.0 6/25/2015 APERF;7,418.0-7,432.01 - 1 L1 WINDOW 7,417.0-7,425.9 ,II i 6 7,063.1 6,381.6 CAMCO KBG-2- 4.851 GAS LIFT DMY DK 1.000 0.0 6/25/2015 . - 9 Notes:General&Safety APERF;7,439.0-7,462.0 End Date Annotation 7/10/1994 NOTE:WAIVERED WELL:IA x OA COMMUNICATION (PERF;7,478.0-7,498.0- 2/28/2010 NOTE:View Schematic w/Alaska Schemtic9.0 7/21/2015 NOTE:Upper tubing is 3 1/2"9.3#L-80 EUE 8rd Mod to 5381'MD XO to 31/2"9.3#L-80 IBTM to 7137' FISH;7,583.0 NOTE:Lower tubing is 3 1/2"9.3#L-80 from 7189'-7345',XO to 5 1/2"14#J-55 from 7345'-7435' Iii I PRODUCTION;33.0-7,740.3 SLOTS;7,411.4-10,990.0 L1-03 LATERAL LINER;7,410.5 -11,000.0- r KUP PROD • 30-08L1-03 ConocoPhillips I ` Well Attributes Max Angle&MD TD Ad--k4l,inc Wellbore API/UWI Field Name Wellbore Status -.ncl 7) MD(ftKB) Act Min(ftKB) 0,,,,,,„,.„4",„1„. 500292182863 KUPARUK RIVER UNIT PROD 100.50 7,880.51 ... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date 30-08L1-03,8/17/201523050 PM SSSV:TRDP Last WO: 6/16/2015 33.98 7/20/1988 Verteal schematic(ac/cal) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag: Rev Reason:ADD LATERALS L1(off main smsmith 8/10/2015 wellbore)L1-03,&L1-04,PULL PLUG,GLV C/O lit 1 11 1 r, Casing Strings I( Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I..Grade Top Thread � i t L1-03 LATERAL LINER 2 3/8 1.992 7,410.5 11000 0 6,654.9 4.60 L-80 STL r Liner.Details Nominal ID Top(ftKB) Top(TVD)(ftKB) Tap Incl(°) Item Des Com (in) CONDUCTOR;35.0-110 a !'% 7, &410.5 6 651 4 38 36 DEPLOY BAKER SHORTY DEPLOYMENT SLEEVE 1.000 j� Perforations Slots I S900,2,001.8 1 Shot Dens Top(TVD) Btm(TVD) (shots/f Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Com 7,411.4 10,999.6 6,652.1 6,654.9 A-1,30-08 8/2120)5 SLOTS Slotted Liner GAS LIFT 2497.1 - Notes:General&Safety End Date Annotation NOTE: SURFACE:350-2,6190 J` MI GAS LIFT:3,719 2 GAS LIFT;4 782 9 all GAS LIFT;5,374.6 111 1111 PACKER;5423.8 HANGER;5439 3 I I Liner;6,448 3 GAS LIFT,6,561 3 I GAS LIFT'.7,063.1 f' I LOCATOR:7,117 5 IIIIIP Liner-Pup's 7,114 8 g' XO Reducing',7,122.6MI - SEAL ASSY;77:1112861,19. 9,-we SBE; dtc 90 Reducing',7,143 5 LOCATOR;7,186 7 i r1 PACKER',71893 SEAL ASSY,7,187.2. SBE;71926 g. 9 E NIPPLE;7,292.6 I W EARSOX;7,346.6 I. WHIPSTOCK;7,4150 ( APERF',7,416.0-7,432 0 L1 WINDOW;7417.0-7,4250 L'^ :i APERF',7,439.0-7,4620-_ IPERF',7,476.0-7,4960-_ FISH;7,5830 - i PRODUCTION;33.0-7,746.3- SLOTS;7 411 4-10,999 6 L1-03 LATERAL LINER;7,410.5 -11 000 0 30-08 PRE AND POST RIG WELL WORK SUMMARY DATE SUMMARY • • PRE-RIG WELL WORK 7/16/2015 SET BAKER GEN II WHIPSTOCK CORRELATED TO GEARHART CEMENT BOND LOG DATED 8/1/88. TOP OF WHIPSTOCK SET AT 7415' ORIENTATION 3 DEGREES ROHS. BOTTOM OF WHIPSTOCK AT 7428'. 2 PIP TAGS AT 7422.3'. FOUND 5 1/2" COLLARS AT 7394'AND 7438' (3' DEEPER THAN ANTICIPATED). JOB COMPLETE POST-RIG WELL WORK 8/4/2015 *** CDR-2 RIG JOB*** DRIFTED TBG TO 2.85"TO SSSV @ 2002'RKB AND SET 2.81"XX PLUG @ SAME. COMPLETE. 8/12/2015 PULLED 2.81"XX PLUG @ 2002' RKB. GAUGED TBG TO 2.77"TO LINER @ 7410' RKB. MEASURED BHP @ SAME:4064 PSI. SET CATCHER @ 5499'SLM. PULLED DV&SET OV @ 5375' RKB. PULLED DV&SET GLV @ 4783' RKB. IN PROGRESS. 8/13/2015 PULLED DVs, SET GLVs @ 3719'&2497' RKB. BLED IA PRESSURE TO CONFIRM INTEGRITY. PULLED CATCHER @ 5499' SLM. COMPLETE. 8/18/2015 (WC): MITOA(PASSED TO 1800 PSI). • • ConocoPhiIIips Time Log & Summary WelIview Web Reporting Report Well Name: 30-08 Rig Name: NABORS CDR2-AC Job Type: DRILLING SIDETRACK Rig Accept: 7/20/2015 8:00:00 PM Rig Release: 8/5/2015 12:00:00 PM Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07/20/2015 24 hr Summary Move to 30, MIRU,Accept rig @ 20:00, Start BOPE Test,Test witness waived by Johnny Hill,AOGCC 00:00 14:30 14.50 0 0 MIRU MOVE MOB P Move CDR2 to 30 pad 14:30 17:00 2.50 0 0 MIRU MOVE MOB P Arrive on 30 pad, Remove jeeps, Status well, Spot rig 17:00 20:00 3.00 0 0 MIRU MOVE RURD P MIRU, follow rig up checklist 20:00 22:42 2.70 0 0 MIRU WHDBO NUND P Nipple up stack,swap out risers ***RIG ACCEPT""*20:00 22:42 00:00 1.30 0 0 MIRU WHDBO BOPE P Start full initial BOPE Test,Witness waived by Johnny Hill,AOGCC 07/21/2015 Complete BOPE test, PT PDL&TT Line, M/U BHA#1, RIH 00:00 09:48 9.80 0 0 MIRU WHDBO BOPE P Continue BOPE Test 09:48 11:24 1.60 0 0 MIRU WHDBO MPSP P PJSM. RU and pull BPV. LD FMC equipment. Several tour groups today! 11:24 13:24 2.00 0 0 MIRU WHDBO PRTS P PJSM. PT PDL's and TT line. Install checks, perform valve check list. Finish with tour groups. 13:24 15:39 2.25 0 73 PROD1 WHPST PULD P PJSM. PJSM. MU BHA#1. PD BHA #1 15:39 17:33 1.90 73 7,040 PROD1 WHPST TRIP P RIH w/window milling assembly, pumping at minimum rate, .6 AKO motor. 17:33 17:51 0.30 7,040 7,103 PROD1 WHPST DLOG P Log K1 for-9'correction 17:51 18:03 0.20 7,103 7,418 PROD1 WHPST TRIP P Continue in well, Dry tag whipstock @ 7418 18:03 23:15 5.20 7,418 7,410 PROD1 WHPST CIRC P PUH, PUW=30K, Circ hole to 9.1 used flow pro, Losses greater then 1 BPM , M/UI High vis pill 100K LSRV, pump 25 BBIs and squeeze.Able to get annular to—3900 PSI.Start to circulate, Unable to ge annular to 4K without losses more then.5BPM. Add more vis to second 25 BBIs, —130K LSRV and pump at higher rate and squeeze in. Loss tate 12 BPH with—3900 Annular. 23:15 00:00 0.75 7,410 7,418 PROD1 WHPST WPST P Close EDC, RIH to mill window, Call initial pinch point @ 7417.9, 1.6 BPM @ 3378PS1 FS, BHP=3875, 1.4BPM Returns, Midnight depth 7418.4 37/22/2015 Complete milling window&rathole to 7440. Trip out and P/U build section BHA, RIH&Drill Page 1 of 11 Time Logs • • Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 00:00 12:09 12.15 7,418 7,440 PROD1 WHPST WPST P Continue to mill single run dual string exit window as per well plan, midpoint @ 7,423', open choke @ 07:15, reduced ECD to 10.8, losses reduced from .2 to.05 bpm. Complete window milling @ 7,430'. Drill rathole to 7,440'. 12:09 14:09 2.00 7,440 7,440 PROD1 WHPST REAM P Ream/Dress window as per well plan, dry drift window,drift clean. 14:09 16:12 2.05 7,440 64 PROD1 WHPST TRIP P POOH w/milling assembly, lay in 25 bbl hi vis pill. 16:12 17:54 1.70 64 66 PROD1 WHPST PULD P On surface. PJSM. PUD BHA#1, LD BHA. Both mills out @ 2,79 No-Go 17:54 18:18 0.40 0 0 PROD1 DRILL SFTY P Crew change,Valve checklist 18:18 18:48 0.50 0 0 PROD1 DRILL PRTS P Pressure test ODS PDL for RSM pre load, Good test 18:48 20:30 1.70 0 72 PROD1 DRILL PULD P PJSM, M/U and pick up BHA#2, Build section BHA with 2.2+AKO motor and re run HCC bi center. Make up to coil and surface test tool 20:30 22:18 1.80 72 7,060 PROD1 DRILL TRIP P RIH, EDC open, pumping min rate 22:18 22:36 0.30 7,060 7,085 PROD1 DRILL DLOG P Log K1, On first pass set down @ 7079, PUH and relog at 90R TF, Set down again. Shut EDC and roll pump @ min rate. Log down, go past and call correction-9' 22:36 22:54 0.30 7,085 7,441 PROD1 DRILL TRIP P Continue trip in hole, clean pass through window 22:54 00:00 1.10 7,441 7,482 PROD1 DRILL DRLG P 7441', Drill, 1.48 BPM @ 3050 PSI FS, BHP=3771, New 9.4PPG mud @ bit 7468 37/23/2015 TD Build section ti 7610, M/U RSM lateral BHA drill 7610 to 8260'Lost 150 BBIs/24Hrs 00:00 04:06 4.10 7,482 7,610 PROD1 DRILL DRLG P Continue drilling build section, 1.46 BPM @ 3200 PSI FS, BHP=3920 04:06 06:03 1.95 7,610 73 PROD1 DRILL TRIP P 7610', Call EOB,Trip out for lateral BHA,Avg DLS=46, PUW=29K, Attempt to open EDC 7364 received motor fault due to hall sensor failure. Rolled pumps still closed. Decide to leave EDC alone,Trip out 06:03 07:33 1.50 73 0 PROD1 DRILL PULD P Made two attempts to perform closure test on SSSV, unsuccessful. PJSM. PUD BHA#2, LD BHA. 07:33 09:33 2.00 0 70 PROD1 DRILL PULD P PJSM. MU/PU BHA#3 09:33 11:51 2.30 70 7,610 PROD1 DRILL TRIP P RIH w/L1 lateral drilling assembly, tie-in to K1 for-9'correction, log RA @ 7,421.5',tight spot @ 7,468'. 11:51 16:51 5.00 7,610 7,910 PROD1 DRILL DRLG P Drill ahead L1 lateral: 1.48 BPM @ 3,630 PSI, BHP=4025 PSI, CTW=11 K,WOB=1.8K, ROP=60. Ankerite @ 7,890'. 16:51 17:24 0.55 7,910 7,910 PROD1 DRILL WPRT P Wiper to window, PUW=25K, RBIH. Page 2of11 Time Logs • 4111 Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 17:24 20:06 2.70 7,910 8,108 PROD1 DRILL DRLG P 7910', Drill, 1.5 BPM @ 3200PSI FS, BHP=4050, RIW=9.9K, DHWOB=2.4K 20:06 21:36 1.50 8,108 8,108 PROD1 DRILL WPRT P 8108',Wiper trip to 7380 while sorting out aired up mud/pump problems 21:36 23:24 1.80 8,108 8,260 PROD1 DRILL DRLG P 8108 Drill, 1.55 BPM©3350 PSI FS, BHP=4020 23:24 00:00 0.60 8,260 8,260 PROD1 DRILL WPRT P Wiper trip to 7420. PUW=26K 07/24/2015 Drilled L1 lateral 8910 to 9244, Swapped mud, Lost 119 last 24 Hrs 00:00 00:06 0.10 8,260 8,260 PROD1 DRILL WPRT P Complete wiper trip from 8260 00:06 01:30 1.40 8,260 8,335 PROD1 DRILL DRLG P 8260', Drill, 1.52 BPM©3530 PSI FS, BHP=4045 01:30 03:12 1.70 8,335 8,392 PROD1 DRILL DRLG P Continue upward cutting through A1/A2 interface>150 API. Lower ROP 03:12 03:18 0.10 8,392 8,392 PROD1 DRILL WPRT P Stall out @ 8392, PUW=26K, PUH and restart 03:18 08:15 4.95 8,392 8,610 PROD1 DRILL DRLG P 8392', Drill 1.55 BPM @ 3630 PSI FS, BHP=4169 08:15 09:24 1.15 8,610 8,610 PROD1 DRILL WPRT P Wiper for tie-in, PUW=26K,tie-in for +2'correction, RBIH. 09:24 12:54 3.50 8,610 8,734 PROD1 DRILL DRLG P Drill ahead: 1.46 BPM @ 3,660 PSI, BHP=4,140 PSI, CTW=11.3K, WOB=1K, ROP=75. 12:54 14:06 1.20 8,734 8,734 PROD1 DRILL WPRT P Wiper to 8395', PUW=24K swapping pumps 14:06 19:42 5.60 8,734 8,960 PROD1 DRILL DRLG P 8734', Drill, 1.57 BPM @ 3660PS1 FS, BHP=4200, New mud @ bit @8768' 19:42 20:36 0.90 8,960 8,960 PROD1 DRILL WPRT P 8960',Wiper to 7960, PUW=27K 20:36 00:00 3.40 8,960 9,244 PROD1 DRILL DRLG P 8960', Drill, 1.51 BPM @ 3500 PSI FS, BHP=4240 37/25/2015 Drill 9244 to 10221, Lost 96BBIs 9.4PPG FloPro 00:00 01:00 1.00 9,244 9,310 PROD1 DRILL DRLG P Drilling Ahead, 1.51 BPM @ 3510 PSI FS, BHA=4230 01:00 02:00 1.00 9,310 9,310 PROD1 DRILL WPRT P Wiper to 8110, PUW=28K 02:00 05:57 3.95 9,310 9,660 PROD1 DRILL DRLG P 9310', Drill 1.51 BPM @ 3510 PSI FS, BHP=4250 05:57 08:06 2.15 9,660 9,660 PROD1 DRILL WPRT P Wiper for tie-in, PUW=28.5K, +3.5' correction, RBIH. 08:06 13:00 4.90 9,660 10,010 PROD1 DRILL DRLG P Drill ahead: 1.50 BPM @ 3,660 PSI, BHP=4,295 PSI, CTW=7.5K, WOB=1.2K, ROP=70. 13:00 14:15 1.25 10,010 10,010 PROD1 DRILL WPRT P Wiper trip, PUW=27K, RBIH. 14:15 18:00 3.75 10,010 10,108 PROD1 DRILL DRLG P Drill ahead: 1.49 BPM @ 3,845 PSI, BHP=4,325 PSI, CTW=5.5K, WOB=1.5K, ROP=85.Ankerite @ 10,100', ROP=4. 18:00 00:00 6.00 10,108 10,221 PROD1 DRILL DRLG P Crew change/Valve checklist, very low ROP could be Ankorite 07/26/2015 Drilled 10,221 to 10,984'.Trip out to replace failed RSM �_ Page 3 of 11 Time Logs • Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 00:00 02:00 2.00 10,221 10,350 PROD1 DRILL DRLG P Drilling, 1.50BPM @ 3612PSI FS, BHP=4370 02:00 04:12 2.20 10,350 59 PROD1 DRILL TRIP T RSM not responding to commands, PUH slowing while waiting on sweeps already pumped for planned 10,360'wiper trip. Continue to trouble shoot tool. No good getting responce.Trip out.Jet slow past SSSV 04:12 05:12 1.00 59 59 PROD1 DRILL OTHR T At surface, Dump SSSV, bled down to 400PSI from 836. S/I and pressure rose right back up. Fail.Tag-up, space out. 05:12 07:12 2.00 59 0 PROD1 DRILL PULD T PJSM. PUD BHA#3, LD BHA, change-out RSM,some bit damage, pictures in S drive folder. Rig maintenance. 07:12 09:03 1.85 0 66 PROD1 DRILL PULD T PJSM. PU/PD BHA#4 09:03 14:03 5.00 66 10,350 PROD1 DRILL TRIP T RIH w/RSM drilling assembly,tie-in for-9'correction, continue in hole.At 10,150'took another gas/crude influx,took returns to tiger tank, troubleshoot choke issues, choke issue resolved.Took 90 bbls gas cut fluid to tiger tank,gas/crude circulated out. Start pumping new mud at bit 10,377'. CALLED 8 HRS NPT BHI 14:03 18:09 4.10 10,350 10,710 PROD1 DRILL DRLG P Drill ahead: 1.50 BPM @ 3,820 PSI, BHP=4,360 PSI, CTW=3.5K, WOB=2.4K, ROP=85. 18:09 18:57 0.80 10,710 10,710 PROD1 DRILL WPRT P Wiper trip to 9710', PUW=27K 18:57 00:00 5.05 10,710 10,984 PROD1 DRILL DRLG P 10710', Drill, 1.5 BPM @ 3820 PSI FS, BHP=4365 37/27/2015 TD well @ 11,000, Condition hole and run L1 liner 10455 to 8232 00:00 00:42 0.70 10,984 11,000 PROD1 DRILL DRLG P Drill, 1.5 BPM @ 3820 PSI FS, BHP=4412 00:42 03:30 2.80 11,000 69 PROD1 DRILL WPRT P Sweeps coming out, Call TD @11,000',wiper trip to swab, PUW=26K, Open EDC @ 7400' 03:30 03:36 0.10 57 69 PROD1 DRILL WPRT P At surface, Clean counters, reset counters 03:36 04:30 0.90 69 PROD1 DRILL WPRT P Trip back in to confirm depth&pump liner running pill 04:30 04:42 0.20 7,065 7,094 PROD1 DRILL DLOG P Log K1 for-9'correction 04:42 06:39 1.95 7,094 11,000 PROD1 DRILL WPRT P Continue in hole, stack weight @ 8,330,saw some motor work.At 10,515'had to take returns to TT, minimal gas influx.Tag TD @ 11,000'. 06:39 09:45 3.10 11,000 81 PROD1 DRILL TRIP P POOH, laying in liner pill 48 bbls, 12.0 ppg completion fluid. Paint EOP flags @ 9,400'and 5,800'. Continue OOH. Page 4 of 11 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 09:45 10:24 0.65 81 81 PROD1 DRILL OWFF P Monitor well for flow 10:24 10:54 0.50 81 0 PROD1 DRILL PULD P PJSM. LD BHA#4. 10:54 11:54 1.00 0 0 COMPZ CASING WAIT P Waiting on new liner running plan forward. Load @ tally 55 extra joints. 11:54 15:42 3.80 0 2,223 COMPZ CASING PUTB P PJSM. MU 86 jts slotted liner.At 56 jts appear trickle over over stack had increased,stab safety joint,monitor well 30 minutes, no pressure. Decide to continue,71 jts in suspend picking up more due to trickling again. 15:42 16:42 1.00 2,223 2,267 COMPZ CASING PULD P M/U Coil trac to liner, M/U to injector and surface test, Strip on well, Tag stripper and set depth 16:42 18:30 1.80 2,267 8,081 COMPZ CASING TRIP P RIH with BHA#5, Non ported bullnose, 71Jts slotted liner,and shorty deployment sleeve 18:30 18:36 0.10 8,081 8,068 COMPZ CASING DLOG P Stop and correct to EOP flag for-13' 18:36 18:54 0.30 8,068 9,265 COMPZ CASING TRIP P Continue trip in, see small bobble in 8330 area. Nothing significant 18:54 19:00 0.10 9,265 9,291 COMPZ CASING DLOG P Log K1 for+3.Total overall correction -10' 19:00 19:42 0.70 9,291 10,455 COMPZ CASING TRIP P Continue in hole, Stop at 10455, PUW=28K, DHWOB=-4.5K. Back on depth pump off liner, 1.4 BPM @ 4075, PUW=28K, DHWOB=-.8, PUH and remove liner length from counters,-2223.17 19:42 20:12 0.50 8,214 7,048 COMPZ CASING TRIP P Trip out to above window pumping across the top 20:12 21:06 0.90 7,048 7,048 COMPZ CASING PRTS P Stop, Line up and pump down coil, Shut in well for 30 Min static. After 30 min annulas @ 4097, WHP=48PS1 21:06 22:54 1.80 7,048 35 COMPZ CASING TRIP P POOH BHA#5 22:54 00:00 1.10 35 COMPZ CASING PULD P PJSM, PUD BHA#5 07/28/2015 Undeployed BHA#5. Funtion test BOPE.Test 2 3/8"rams. Ran OH anchored billet to top of liner at 8,232-ft. Kick off billet at 8,220-ft. Drill ahead L1-04 lateral to 8,765-ft. 00:00 01:24 1.40 0 0 COMPZ CASING PULD P Continue PUD BHA#5, Lay down string 01:24 02:42 1.30 0 0 COMPZ CASING BOPE P Perform bi-weekly BOPE function test-Test and chart 2 3/8 deployment rams 02:42 04:51 2.15 0 73 COMPZ CASING PULD P PJSM, M/U and PD BHA#6 anchored aluminum billet 04:51 07:24 2.55 73 8,232 COMPZ CASING TRIP P Trip in with Anchored Billet, EDC open, Pumping min rate,tie-in to K1 for-9.5'correction, continue in hole, PUW=26K,tag up on TOL @ 8,232', orient for LS kick-off. Pressure up, release from billet, TOB @ 8,220'. 07:24 08:33 1.15 8,232 8,232 COMPZ CASING CIRC P PUH slowly, pump spacer, followed by 9.4 ppg mud. 1___ __ Page 5 of 11 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 08:33 10:09 1.60 8,232 66 COMPZ CASING TRIP P POOH w/BHA#6 10:09 11:15 1.10 66 0 COMPZ CASING PULD P PJSM. PUD BHA#6, LD BHA. 11:15 13:06 1.85 0 72 PROD2 STK PULD P PJSM. MU/PD BHA#7 13:06 15:18 2.20 72 8,221 PROD2 STK TRIP P RIH w/Drilling assembly 0.5 AKO motor, RR HYC bit,tie-in for-9' correction,continue in hole,dry tag billet @ 8,221'. 15:18 16:21 1.05 8,221 8,223 PROD2 STK KOST P Start milling off billet at 1 fph, 1.50 BPM @ 3,790 psi, BHP=4,270 psi, CTW=12.5K,WOB=1.2K.Off billet. 16:21 17:06 0.75 8,223 8,261 PROD2 DRILL DRLG P Drill ahead L1-04 lateral: 1.50 BPM @ 3,810 PSI, BHP=4,265 PSI, CTW=12K,WOB=1.3K, ROP=70. Dry drift billet, clean. 17:06 20:33 3.45 8,261 8,570 PROD2 DRILL DRLG P 8,261-ft, OBD 1.5 bpm at 3,926 psi, BHA4,281 psi, CTW 11.1k,WOB 1.6k, ROP 75. 20:33 21:24 0.85 8,570 8,570 PROD2 DRILL WPRT P Wiper trip up hole to 7,770-ft, PUW 27k, RBIH 21:24 00:00 2.60 8,570 8,765 PROD2 DRILL DRLG P 8,570-ft, BOBD 1.5 bpm @ 3,845, BHP 4,279 psi, CTW 10.5k,WOB 1.4k, ROP 65. 37/29/2015 Drill ahead 8,765-ft to 9,448-ft. Perform wiper to swab. Confirm TD at 9,446-ft. Lay in 12.3 ppg Formate beaded liner running pill. MU L1-04 liner. 00:00 01:48 1.80 8,765 8,920 PROD2 DRILL DRLG P Drill ahead 1.5 bpm at 3,874 psi, BHP 4,289 psi, CTW 10.4k,WOB 1.95k, ROP 85 01:48 02:48 1.00 8,920 8,920 PROD2 DRILL WPRT P Wiper trip up hole to 7,820-ft, PUW 27k, RBIH, RIW 13.5k 02:48 08:48 6.00 8,920 9,270 PROD2 DRILL DRLG P 8,920-ft, BOBD 1.5 bpm at 3,869 psi, BHP 4,282 psi, CTW 9.6k,WOB 2k, ROP 45, 08:48 10:51 2.05 9,270 9,270 PROD2 DRILL WPRT P Wiper for tie-in/jet tail pipe, PUW=26K, +2'corection,jet big tail pipe at max rate. RBIH. 10:51 13:21 2.50 9,270 9,449 PROD2 DRILL DRLG P Drill ahead 1.49 bpm at 4,050 psi, BHP 4,374 psi, CTW 7.4k,WOB 2.5k, ROP 80. Called TD @ 9,450'. Pump 10 X 10 to/hi vis sweeps. 13:21 15:45 2.40 9,449 73 PROD2 DRILL WPRT P Wiper to swab,chase sweeps,tag up, reset depth. 15:45 17:00 1.25 73 7,070 PROD2 DRILL TRIP P RBIH for corrected TD. 17:00 17:15 0.25 7,070 7,100 PROD2 DRILL DLOG P Tie in to K1 for minus 9-ft correction, PUW 24k, Close EDC 17:15 18:18 1.05 7,100 9,446 PROD2 DRILL TRIP P RIH, Stack down 3x at 7,426-ft, bottom of window, roll pump and pass through, continue in hole, confirm TD at 9,446-ft. 18:18 21:33 3.25 9,446 72 PROD2 DRILL DISP P POOH laying in 12.3 ppg Formate beaded liner running pill, completion fluid to surface, paint EOP flags at 7,600-ft and 5,600-ft. 21:33 22:03 0.50 72 72 PROD2 DRILL OWFF P On surface, monitor well for flow, PJSM. __o__n Page 6of11 Time Logs Date From To Dur S. Depth E. Death Phase Code Subcode T Comment 22:03 23:03 1.00 72 0 PROD2 DRILL PULD P Lay down BHA#7, bit condition 4-2-BT-N-X-I-BU-TD, check pipe, .126 flat spot 5-ft above CTC. 23:03 00:00 0.95 0 312 COMPZ CASING PUTB P PJSM-prep floors for running liner. MU bull nose, 52 jts slotted and shorty deployment sleeve. 37/30/2015 Ran L1-04 liner from 9,421-ft to 7,802-ft. Ran OH anchored billet to top of liner at 7,802-ft. Roll hole to 9.4 ppg drilling mud. 00:00 01:45 1.75 312 1,619 COMPZ CASING PUTB P Continue of MU L1-04 liner completion. 01:45 02:54 1.15 1,619 1,663 COMPZ CASING PULD P PJSM-MU BHA#8 to liner completion, MU to CoilTrak, Surface test. 02:54 03:36 0.70 1,663 4,153 COMPZ CASING RUNL P RIH with BHA#8, lost communication with tool. 03:36 04:18 0.70 4,153 4,153 COMPZ CASING EQRP T Attempt to re-establish commuinication with CoilTrac tools, no joy. 04:18 04:57 0.65 4,153 1,663 COMPZ CASING TRIP T POOH pumping over top to troubleshoot BHI CoilTrak tool failure. 04:57 05:27 0.50 1,663 1,663 COMPZ CASING OWFF T On surface, monitor well for flow, PJSM. 05:27 09:27 4.00 1,663 1,663 COMPZ CASING EQRP T Troubleshoot lost communication issue. Change collector box and BHI tool string. 09:27 10:12 0.75 1,663 1,663 COMPZ CASING PULD T MU new BHA to liner assembly, surface test tool. 10:12 11:00 0.80 1,663 4,153 COMPZ CASING RUNL T RIH w/lower liner assembly 11:00 12:51 1.85 4,153 9,421 COMPZ CASING RUNL P Continue in hole with liner assembly, tie-in EOP flag for-10.5'correction, also K1 for no correction. Set depth PUW=33K,set depth 9,421', release from liner,TOL depth @ 7,802', PUW=25K. PUH, reset depth. 12:51 14:12 1.35 9,421 56 COMPZ CASING TRIP P POOH for anchored billet. 14:12 14:42 0.50 56 56 COMPZ CASING OWFF P Monitor for flow 14:42 15:36 0.90 56 73 COMPZ CASING PULD P PJSM. LD BHA#9. PJSM. MU BH#10 15:36 17:51 2.25 73 7,802 COMPZ CASING TRIP P RIH w/Anchored billet,tie-in for of minus 10-ft correction at K1, PUW 26k, RBIH, no problem thru window, tag up on top of liner at 7,802-ft,set single slip 30° HS, release off at 3,600 psi,top of billet at 7,790-ft. 17:51 19:15 1.40 7,802 56 COMPZ CASING TRIP P POOH for drilling assembly 19:15 19:45 0.50 56 56 COMPZ CASING OWFF P On surface, monitor for flow. PJSM 19:45 20:39 0.90 56 0 COMPZ CASING PULD P LD BHA#10, check pipe, .124" measured flat spot 5-ft above CTC. 20:39 21:39 1.00 0 72 PROD3 STK PULD P PJSM-MU BHA#11, change out checks, MU to CoilTrac,surface test. Page 7 of 11 Time Logs • Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 21:39 00:00 2.35 72 7,790 PROD3 STK TRIP P RIH w/Drilling assembly 0.5 AKO motor, new HYC bit,tie-in for minus 9-ft correction,continue in hole, PUW above window 27k,stack 4k at 7,426-ft 2x, roll pump minimum rate to pass thru,dry tag billet at 7,790-ft, PUW 27k. 37/31/2015 Kick off billet at 7,790-ft. Drill L1-03 lateral from 7,792-ft to 9,280-ft 00:00 01:00 1.00 7,790 7,790 PROD3 STK DISP P Roll hole to 9.4 ppg FloPro. 01:00 02:42 1.70 7,790 7,792 PROD3 STK KOST P Start milling off billet at 1 fph, 1.50 bpm at 3,853 psi, BHP 4,214 psi, CWT 12.7k,WOB 1.25k. Off billet. 02:42 04:21 1.65 7,792 7,840 PROD3 DRILL DRLG P Drill ahead L1-03 lateral 1.50 bpm at 3,869 psi, BHP 4,219 psi, CWT 12.3k,WOB 1.6k, ROP 45. Dry drift billet, clean. 04:21 09:33 5.20 7,840 8,140 PROD3 DRILL DRLG P 7,840-ft OBD 1.5 bpm at 3,642 psi, BHP 4,220 psi, CWT 12k,WOB 1.4k, ROP 55. NOTE: New mud at bit at 7,850-ft. 09:33 10:12 0.65 8,140 8,140 PROD3 DRILL WPRT P Wiper trip, PUW=25K, RBIH. 10:12 13:18 3.10 8,140 8,490 PROD3 DRILL DRLG P Drill ahead: 1.69 BPM @ 4,195 PSI, BHP=4,265 PSI, CTW=11.8K, WOB=1.4, ROP=110. 13:18 14:06 0.80 8,490 8,490 PROD3 DRILL WPRT P Wiper trip, PUW=26K, RBIH. 14:06 17:42 3.60 8,490 8,840 PROD3 DRILL DRLG P Drill ahead: 1.69 BPM @ 4,185 PSI, BHP=4,290 PSI, CTW=10.8K, WOB=1.3, ROP=70. 17:42 18:30 0.80 8,840 7,437 PROD3 DRILL WPRT P Wiper trip for tie in, PUW 27k. 18:30 18:39 0.15 7,437 7,462 PROD3 DRILL DLOG P Tie at RA for plus 2.5-ft correction. 18:39 19:12 0.55 7,462 8,840 PROD3 DRILL WPRT P Wiper in hole, RIW 14k. 19:12 22:12 3.00 8,840 9,190 PROD3 DRILL DRLG P 8,840-ft, OBD 1.70 bpm at 4,220 psi, BHP 4,300 psi, CWT 9.5k,WOB 1.0k, ROP 110, IA 480, OA 554 22:12 23:00 0.80 9,190 9,190 PROD3 DRILL WPRT P Wiper up hole to 8,190-ft, PUW 27k, RBIH, RIW 10.5k. 23:00 00:00 1.00 9,190 9,280 PROD3 DRILL DRLG P 9,190-ft, OBD 1.70 bpm at 4,233 psi, BHP 4,333 psi, CWT 9.2k,WOB 1.4k, ROP 70 08/01/2015 Drill L1-03 lateral from 9,280-ft to 10,725-ft 00:00 04:36 4.60 9,280 9,540 PROD3 DRILL DRLG P 9,280-ft, OBD 1.70 bpm at 4,233 psi, BHP 4,333 psi, CWT 8.4k,WOB 1.8k, ROP 70 NOTE: Mud Swap-New mud at bit at 9,511-ft. 04:36 05:27 0.85 9,540 9,540 PROD3 DRILL WPRT P Wiper up hole to 8,540-ft, PUW 27k, RBIH, RIW 10.2k. 05:27 10:18 4.85 9,540 9,890 PROD3 DRILL DRLG P 9,540-ft, OBD 1.70 bpm at 4,000 psi, BHP 4,325 psi, CWT 9.1k,WOB 1.0k, ROP 70, IA 625, OA 613 _. _ Page 8 of 11 Time Logs 11111 S Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 10:18 12:21 2.05 9,890 9,890 PROD3 DRILL WPRT P Wiper trip for tie-in, PUW=26K,tie-in to RA correction+2', RBIH. 12:21 14:51 2.50 9,890 10,225 PROD3 DRILL DRLG P Drill ahead: 1.70 BPM @ 4,185 PSI, BHP=4,365 PSI, CTW=7.4K, WOB=1K, ROP=130. 14:51 16:06 1.25 10,225 10,225 PROD3 DRILL WPRT P Wiper trip, PUW=26K, RBIH. 16:06 20:12 4.10 10,225 10,570 PROD3 DRILL DRLG P Drill ahead: 1.69 BPM @ 4,250 PSI, BHP=4,405 PSI, CTW=5.1K, WOB=1.2K, ROP=110. 20:12 21:30 1.30 10,570 10,570 PROD3 DRILL WPRT P Wiper up hole to 9,000-ft, PUW 26k, RBIH. 21:30 00:00 2.50 10,570 10,725 PROD3 DRILL DRLG P 10,570-ft, OBD 1.70 bpm at 4,272 psi, BHP 4,430 psi, CWT 2.0k,WOB 1.0k, ROP 120, IA 444, OA 388 38/02/2015 Drill L1-03 lateral from 10,725-ft to TD at 11,000-ft. Perform wiper to swab, Confirm TD at 11,000-ft. Lay in 12.3 ppg Formate beaded liner running pill. 00:00 02:21 2.35 10,725 10,781 PROD3 DRILL DRLG P 10,725-ft, OBD 1.7 bpm at 4,380 psi, BHP 4,404 psi, CWT-8k,WOB 1.4k, ROP 70, Pump 5x5 sweep 02:21 03:57 1.60 10,781 7,435 PROD3 DRILL WPRT P Wiper trip for tie-in, PUW 27k 03:57 04:06 0.15 7,435 7,465 PROD3 DRILL DLOG P Tie-in to RA correction for plus 2.5-ft 04:06 04:42 0.60 7,465 7,435 PROD3 DRILL WPRT P Open EDC(at 7,410-ft inside BTP), on line 1.95 bpm at 3,875 psi, BHP 4,210 psi, PU jetting 5.5 BTP to 7,435-ft, RBIH 10-ft to surge BTP, close EDC. 04:42 06:00 1.30 7,435 10,781 PROD3 DRILL WPRT P Wiper in hole. 06:00 13:15 7.25 10,781 11,000 PROD3 DRILL DRLG P Drill ahead: 1.70 BPM @ 4,125 PSI, BHP=4,490 PSI, CTW=3.5K, WOB=1.3K, ROP=50.At 10,805' had decrease pump rate to 1.48 BPM. Mutiple 500'wiper trips to regain,push/WOB, many restarts. TD @ 11,000', pump 10 X 10 bbl to/hi vis sweeps. 13:15 16:15 3.00 11,000 66 PROD3 DRILL WPRT P Wiper trip to swab @ 1.70 BPM. Hole clean,tag up, reset depth. 16:15 18:30 2.25 66 11,000 PROD3 DRILL TRIP P RBIH for corrected TD, plus9-ft correction at K1, RIH,Stack at 7,418-ft(top of window) PU and ran through window no problem, continue in hole,confirm corrected TD at 11,000-ft, PUW 26k. 18:30 23:30 5.00 11,000 72 PROD3 DRILL DISP P POOH laying in 12.3 ppg Formate beaded liner running pill,completion fluid to surface, paint EOP flags at 7,300-ft and 3,700-ft. 23:30 00:00 0.50 72 72 PROD3 DRILL OWFF P On surface, monitor well for flow. PJSM 08/03/2015 Ran L1-03 completion to 10,100-ft,work to 11,000-ft,top of liner at 7,410-ft.Wait on seawater truck to get around rig move. 00:00 01:00 1.00 72 0 PROD3 DRILL PULD P LD BHA#11, Bit condition 1-1-WT-A-X-I-BU-TD,flat spot 5-ft above CTC at.117". Page 9 of 11 Time Logs • i Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 01:00 01:45 0.75 0 0 COMPZ CASING PUTB P Prep floors for liner run, check pack offs, inspect injector and top drive. 01:45 07:45 6.00 0 3,590 COMPZ CASING PUTB P PJSM-MU bullnose, 115 jts of 2 3/8" slotted, shorty deployment sleeve. 07:45 08:51 1.10 3,590 3,634 COMPZ CASING PULD P PJSM. MU BHA#12.Change-out pack-off in stripper. 08:51 12:03 3.20 3,634 10,182 COMPZ CASING RUNL P RIH w/liner assembly, tie-in to EOP flag for-10.5'correction, PUW=28.5K. Liner started stacking @ 10,127'work pipe 40 times,work to 10.182'. 12:03 13:30 1.45 10,182 10,500 COMPZ CASING RUNL P Start circulating at min rate,then work pipe,work liner to to 10,500'. 13:30 16:30 3.00 10,500 10,840 COMPZ CASING RUNL P Continue this process working liner downhole 16:30 20:30 4.00 10,840 11,000 COMPZ CASING RUNL P Continue this process working liner to set depth. 20:30 20:36 0.10 11,000 7,395 COMPZ CASING RUNL P 11,000-ft, on depth, release off liner 1.3 bpm at 3,666 psi, PUW 26k. 20:36 23:30 2.90 7,395 7,395 COMPZ CASING CIRC T 7,395-ft, Standby and monitor well, waiting for seawater truck and LRS to get around Nabors 9ES moving from 3K pad towards CPF-3 on mats. Trucks onsite at 22:15. PJSM-bring on seawater. 23:30 00:00 0.50 7,395 7,395 COMPZ CASING DISP P PJSM-Displace well to seawater. X8/04/2015 Displace well to seawater. Freeze Protect from 2,500-ft.Attempted set BPV but cut seals on the plug. Brushed profile but had same result on BPV. Rig up slickline to set plug in SSSV nipple. 00:00 01:21 1.35 7,395 7,395 COMPZ CASING DISP P Continue displacing well to seawater. 01:21 02:21 1.00 7,395 2,500 COMPZ CASING TRIP P POOH-PJSM with LRS, P/T lines and equipment. 02:21 04:15 1.90 2,500 45 COMPZ CASING FRZP P Freeze protect from 2,500-ft. 04:15 06:00 1.75 45 0 COMPZ CASING PULD P PJSM-Undeploy and LD BHA#12 06:00 07:45 1.75 0 0 DEMOB WHDBO MPSP P Flush stack with seawater 07:45 10:30 2.75 0 0 DEMOB WHDBO MPSP P PJSM-Load FMC equipment and set BPV. BPV failed pressure test, pull BPV, replaced 0-ring and set BPV. Pressure test failed 2nd attempt. 10:30 14:45 4.25 0 0 DEMOB WHDBO MPSP T Discuss plan forward with town 14:45 15:30 0.75 0 0 DEMOB WHDBO MPSP T LD FMC PDL, Load rig PDL to conduct brush and flush 15:30 17:00 1.50 0 0 DEMOB WHDBO MPSP T Brush and flush H profile to remove debri to set BPV 17:00 18:00 1.00 0 0 DEMOB WHDBO MPSP T Load FMC equipment, PT,and set BPV. Still leaking, pooh with same cut seal. 18:00 19:30 1.50 0 0 DEMOB WHDBO MPSP T Call out slickline 19:30 20:00 0.50 0 0 DEMOB WHDBO SFTY T Slickline on location. Conduct PJSM in the dog house. Rig up slickline. 20:00 00:00 4.00 0 0 DEMOB WHDBO MPSP T Rig up slickline. Note: had to re-spot the unit twice to get wire lined up through beaver slide. Page 10of11 Time Logs • • Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 08/05/2015 24 hr Summary 00:00 00:30 0.50 0 0 DEMOB WHDBO MPSP T Continue rigging up slickline. 00:30 02:30 2.00 0 0 DEMOB WHDBO MPSP T 1. Pt slickline lubicator to 2500 psi. open up. RIH with plug drift&2.25" magnet.to SSSV nipple @ 2002' RKB. pooh with no metal junk. 2. RIH with 2.81"XX plug,set in SSSV X nipple @ 2002' RKB with 1300 psi on WH.Attempt pt to 2500 psi, lost pressure due to suspected surface valve leak. Bleed TBG down to 0 psi, held 0 psi for 15 minutes. 02:30 03:45 1.25 0 0 DEMOB WHDBO MPSP T Conduct PJSM. RD slickline. 03:45 06:00 2.25 0 0 DEMOB WHDBO RURD P Stop trouble time. Flush stack& surface line with inhibited FW,clean pits. 06:00 09:30 3.50 0 0 DEMOB WHDBO RURD P Blow down coil and surface lines, clean out rotary table sump,floor and cellar 09:30 10:30 1.00 0 0 DEMOB WHDBO NUND P Nipple down BOPE Note: **SITP 1,400 psi 10:30 11:00 0.50 0 0 DEMOB WHDBO NUND P Check tree bolts Note: **2 bolts below the master valve were loose 11:00 12:00 1.00 0 0 DEMOB WHDBO RURD P Complete rig move checklist Note: **Rig released at 12:00 hrs Page 11 of 11 • . IT 0 0 Iii Ni.._i. z o n o gs Lraw O CC N 0- I C i CU 0 cn 0 co 0 aw — W a I— ,, Q u)a. w ._ a. _ _ . .MINIM s = - Cl) Al O MCE a "a M 0 > V O a Lo Ot/ 00 = • -1 N C O - 4. 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OC) M M M M M CO M CO CO M CO CO CO CO co M > M M .2 2 O O ^ y y J J aco 00 00 M O O) N r N- an co N co co N 0 co d O O 0 N N (O N a) m O co CO V CO N M V N N O = = O O O 22 5-- O 0w m rof� O O LU 0 1 m m 8 O O m aoN U Y Y co co co Z _ a N O N N CO CO O CO V CO (O V (O O (O N V 0 N f� CO O N. (O V V CO M N CO CO CO N. 0 U .- O O O O O O O CV O O O O O O ON N- C 4..:, . i ❑ N N 0 (W(1 O V N` O M (O 0) N (O a0 V O 0 (O (O N.0 N) N- I) CO CO CO 01 0) CO 0 COC V O 0 T rG O O O O O O O O O O O O O O O O O r U 0 •O °r' N G) N N ✓ a` in 0 m' • 21 51 08 > 1 1 7 107 115104 26 1 7 2 6 1 26 q 70 VAN PRINT DISTRIBUTION LIST BAKER HUGHES Please sign and return one copy of this transmittal form to: COMPANY ConocoPhillips Baker Hughes INTEQ D6Ta LOGGED (mandatory) 795 East 94th Avenue /\ /2015 WELL NAME 30-08L1;08L1-03;08L1-04 Anchorage,Alaska 99515 M.K.BENDER (mandatory) FIELD Kuparuk River Unit to acknowledge receipt of this data. 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N V n 0 0 0 0 0 0 0 ( 0 0 0 0 0 0 ( !n c N.wN M 2 Q CO O M nO O) N go' W W Q 8 O 1 Cra .. 0 >, 2 7o Ooo000 0 oOoO ci Oo ✓ .C2 ca CO °' Na) r. N«, N a) U a t_ O 7 co ..,..._...,.......$ ro 0 0 !RECEIVED S AUG 0 5 2015 Letter of Transmittal BAKER Date: DATA LOGGEDAugust 4, 2015 ,:fik BENDER HUGHES To: From: Makana Bender Yosha Ragbirsingh/Michael Soper AOGCC Baker Hughes INTEQ 333 West 7th Ave, Suite 100 795 East 94th Avenue Anchorage, Alaska 99501 Anchorage, Alaska 99515 Please find enclosed the directional survey data for the following well(s): 30-08L1 2 � � g I Q � 8 12 6 0 91 2 30 -08L1-04 30-08L1-03 2 1 5 1 0 7 2 6 0 9 3 Permitted, never drilled: 30-08L1-01 30-08L1-02 (3) Total prints Enclosed for each well(s): 1 hardcopy print of directional survey reports (NAD27) 1 compact disk containing electronic survey files Note: Please feel free to send us an email in place of return mail. 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OF ❑ N N N (0 0 0 0 n r N- r W M M C N U 0 = T E ` O O O Ci O O O O O O O O O O O CJ T o ✓ £O C Y ° (i' 0 ') U d 05 S �S ❑ co v • • tiOF 741 1111 • THE STATEAlaska Oil and Gas 1 of Conservation Commission � z-==_ 333 West Seventh Avenue r�r- I GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 Op, ALASFax: 907.276 7542 www.aogcc.alaska.gov D. Venhaus CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 30-08L1-03 ConocoPhillips Alaska, Inc. Permit No: 215-107 Surface Location: 876' FNL, 1929' FWL, SEC. 22, T13N, RO9E, UM Bottomhole Location: 1795' FNL, 810' FEL, SEC. 16, T13N, R9E, UM Dear Mr. Venhaus: Enclosed is the approved application for permit to re-drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 188-064, API No. 50-029- 21828-00-00. Production should continue to be reported as a function of the original API number stated above. 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, Cathy P. 'oerster Chair DATED this day of June, 2015. • • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION JUN 18 2015 PERMIT TO DRILL �OG� 20 AAC 25.005 la.Type of Work: lb Proposed Well Class: Development-Oil ❑✓ • Service-Winj ❑ Single Zone o 1c.Specify if well is proposed for: Drill ❑ . Lateral El Stratigraphic Test ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone❑ Coalbed Gas ❑ Gas Hydrates❑ Redrill ❑ Reentry❑ Exploratory ❑ Service-WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: s U Blanket U Single Well 11.Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59-52-180• KRU 30-08L1-03 3.Address: 6.Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage,AK 99510-0360 MD: 11000' % TVD: 6584' • Kuparuk River Field ' 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Surface:876'FNL, 1929'FWL,Sec.22,T13N, RO9E, UM ADL 25513 Kuparuk River Oil Pool . Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1566'FSL, 1772'FWL,Sec. 15,T13N, R9E, UM 2554 8/1/2015 Total Depth: 9.Acres in Property: 14.Distance to 1795'FNL,810'FEL,Sec. 16,T13N, R9E, UM ^ 2560 ' Nearest Property: 3805 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: - 58 feet 15.Distance to Nearest Well Open Surface:x- 525566 y- 6021944 Zone- 4•• GL Elevation above MSL: . 33 feet to Same Pool: 30-01 ,792 16.Deviated wells: Kickoff depth: , 8100 ft. 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: -103.5° deg Downhole:4822 psig , Surface:4153 psig 18.Casing Program: Specifications Top - Setting Depth -Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7# L-80 ST-L 3250' 7750' 6651' 11000' 6584' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured) Effective Depth MD(ft): Effective Depth TVD(ft): Junk(measured) 7770' 6934' none 7663' 6849' 7583' Casing Length Size Cement Volume MD TVD Conductor/Structural 75' 16" 164 sx AS II 110' 110' Surface 2584' 10.75 1300 sx AS III,225 sx AS II, 2619 2619' Production 7713' 7" 400 sx TLW,200 sx CI G, 7746' 6915' 225 sx AS I Perforation Depth MD(ft): Perforation Depth TVD(ft): 7416-7432,7439-7462,7476-7496 6656-6668,6673-6692,6703-6719 20.Attachments: Property Plat❑ BOP Sketch❑ Drilling Program Q Time v.Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Program ❑ 20 AAC 25.050 requirements ❑ 21.Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact Cody Pohler @ 265-6435 Email Cody.J.Pohler(a7icop.com Printed Name . Venhau Title CTD Engineering Supervisor CJ? 0/f7// Signature 2�.r/ti ..,--1. — Phone:263-4372 Date ‘— /7— /S Commission Use Only Permit to Drill 1 API Number: Permit Approval See See cover letter Number: /S— yo7- 50- O9-� igz?-(-Ool Date: 1//( r' ft#5 for other requirements Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed m thane,gas hydrates,or gas contained in shales: ❑1 Other:DOR 1Y5/- li-0 4 5 OOp 5 / Samples req'd: Yes ❑ No V Mud log req'd: Yes❑ No[' -iel v7 ti/a►'pr-r-vev1!`Cr firs t- to 25LY�SIJf2S measures: Yes [Zr No Directional svy req'd: Yes] No E1 Spacing exception req'd: Yes ❑ No Inclination-only svy req'd: Yes❑ No Z APPROVED BY THE /' r Approved by: . / �' COMMISSIONER Date:L 6 -3 / 5 Form 10-401 (R: ised 10/2012 This permit is valid for 24 months from t o�a iI 2 05(g)) j{"*O 2/I /S- yr-L 6/x3/45 • • RECEIVED ConocoPhillips JUN 18 2015 Alaska P.O. BOX 100360 AOGGC ANCHORAGE,ALASKA 99510-0360 June 5, 2015 Commissioner- State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits an application for permits to drill a penta-lateral out of the Kuparuk Well 30-08 using the coiled tubing drilling rig, Nabors CDR2-AC. The work is scheduled to begin August 2015. The CTD objective will be to drill five laterals (30-08L1, 30-08L1- 01, 30-08L1-02, 30-08L1-03, 30-08L1-04), targeting the A sand intervals. Note the current A sand perforations are still open below the whipstock. Attached to this application are the following documents: — Permit to Drill Application Form 10-401 for 30-08L1, 30-08L1-01, 30-08L1-02, 30-08L1-03, 30-08L1- 04 — Detailed Summary of Operations — Directional Plans — Proposed Schematic If you have any questions or require additional information please contact me at 907-265-6435. Sincerely, ,--� Cody Pohler Coiled Tubing Drilling Engineer • • Kuparuk CTD Laterals NA80N5 ALASKA 30-08L1, 30-08L1-01, 30-08L1-02, 30-08L1-03 , & 30-08L1-04 21AC Application for Permit to Drill Document 1. Well Name and Classification 2 (Requirements of 20 AAC 25.005(f)and 20 MC 25.005(b)) 2 2. Location Summary 2 (Requirements of 20 AAC 25.005(c)(2)) 2 3. Blowout Prevention Equipment Information 2 (Requirements of 20 AAC 25.005(c)(3)) 2 4. Drilling Hazards Information and Reservoir Pressure 2 (Requirements of 20 AAC 25.005(c)(4)) 2 5. Procedure for Conducting Formation Integrity tests 2 (Requirements of 20 AAC 25.005(c)(5)) 2 6. Casing and Cementing Program 2 (Requirements of 20 AAC 25.005(c)(6)) 2 7. Diverter System Information 3 (Requirements of 20 AAC 25.005(c)(7)) 3 8. Drilling Fluids Program 3 (Requirements of 20 AAC 25.005(c)(8)) 3 9. Abnormally Pressured Formation Information 4 (Requirements of 20 MC 25.005(c)(9)) 4. 10. Seismic Analysis 4 (Requirements of 20 MC 25.005(c)(10)) 4 11. Seabed Condition Analysis 4 (Requirements of 20 AAC 25.005(c)(11)) 4 12. Evidence of Bonding 4 (Requirements of 20 AAC 25.005(c)(12)) 4 13. Proposed Drilling Program 5 (Requirements of 20 AAC 25.005(c)(13)) 5 Summary of Operations 5 Pressure Deployment of BHA 6 Liner Running 6 14. Disposal of Drilling Mud and Cuttings 6 (Requirements of 20 AAC 25.005(c)(14)) 6 15. Directional Plans for Intentionally Deviated Wells 7 (Requirements of 20 AAC 25.050(b)) 7 16. Attachments 7 Attachment 1: Directional Plans for 30-08L1, L1-01, L1-02, L1-03, L1-04 7 Attachment 2: Current Well Schematic for 30-08 7 Attachment 3: Proposed Well Schematic for 30-08L1, L1-01, L1-02, L1-03, L1-04 7 Page 1 of 7 6/17/2015 • • PTD Application: 30-08L1, L1-01, L1-02, L1-03, L1-04 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) The proposed laterals described in this document are 30-08L1, 30-08L1-01, 30-08L1-02, 30-08L1-03 & 30- 08L1-04. All laterals will be classified as "Development—Oil" wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 form for surface and subsurface coordinates of the 30-08L1, 30-08L1-01, 30-08L1-02, 30-08L1-03 & 30-08L1-04. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR2-AC. BOP equipment is as required per 20 AAC 25.036, for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4500 psi. Using the maximum formation pressure in the area of 4822 psi in 30-05, the maximum potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 4153 psi. See the"Drilling Hazards Information and Reservoir Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2500 psi. 4. Drilling Hazards Information and Reservoir Pressure (Requirements of 20 AAC 25.005(c)(4)) Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005(c)(4)(a)) The equivalent mud weight as of May 31, 2015 in 30-08 was 10.4 ppg. An updated pressure survey will be obtained on the Kuparuk A-sand only before Coiled Tubing Drilling operations begin. The maximum downhole pressure in the 30-08 pattern is to the north with the 30-05 injector at 4822 psi (13.9 ppg EMW) dating May 2015. Well 30-05 has a high throughput with pressure expected to drop to a target of 12.5 ppg. Our pressure management plan called to shut-in the well within 6 months prior to the spud of 30-08; it is currently offline. As the laterals are drilled we approach 30-01. Well 30-01 has a pressure of 3679 (10.6 ppg EMW) and is planned for CTD sidetrack additionally. Potential Gas Zones (Requirements of 20 AAC 25.005(c)(4)(b)) Well 30-07 to the east injected lean gas (2014) and well 30-05 to the north injected MI (2013) however all planned laterals are to the northwest; no specific gas zones are expected to be drilled. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005(c)(4)(c)) The largest, expected risk of hole problems in the 30-08 laterals will be shale instability across the faults, managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossing. Along with shale instability as mentioned above the higher pressure risk will also be taken into consideration for potential hole problems.Again MPD will be used to mitigate the high pressure risk. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) N/A for this thru-tubing drilling operation. According to 20 AAC 25.030(f), thru-tubing drilling operations need not perform additional formation integrity tests. 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) Page 2 of 7 6/17/2015 • • PTD Application: 30-08L1, L1-01, L1-02, L1-03, L1-04 New Completion Details Lateral Liner Top Liner Btm Liner Top Liner Btm Liner Details Name MD MD TVDSS TVDSS 30-08L1 9,750' 11,000' 6,598' 6,641' 2%', 4.7#, L 80, ST-L slotted liner, aluminum billet on top 30-08L1-01 8,900' 11,050' 6,598' 6,608' 2%', 4.7#, L-80, ST-L slotted liner; aluminum billet on top 30-08L1-02 8,100' 9,670' 6,636' 6,634' 2W, 4.7#, L-80, ST-L slotted liner; aluminum billet on top 30-08L1-03 7,750' 11,000' 6,651' 6,584' 2%', 4.7#, L-80, ST-L slotted liner; aluminum billet on top 30-08L1-04 7,410' 9,170' 6,592' 6,555' 2%', 4.7#, L-80, ST-L slotted liner; deployment sleeve on top Existing Casing/Liner Information Category OD Weight Grade Connection Top Btm Top Btm Burst Collapse (ppf) MD MD TVD TVD psi psi Conductor 16" 62.5 H-40 Welded 36' 110' 31' 110' 1,640 630 Surface 10-3/4" 45.5 J-55 BTC 35' 2,619' 35' 2,618' 3,520 2,020 Production 7" 26.0 J-55 BTC 33' 7,746' 33' 6,915' 4,980 4330 Tubing* 3-1/2" 9.3 L-80 EUE 33' 7,349' 33' 6,603' 10,160 10,530 Tubing Tail* 5-1/2" 14 H-40 STC 7351' 7,435' 6,604' 6,670' 3,110 2,610 *Rig workover proposed depths 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) N/A for this thru-tubing drilling operation. Nabors CDR2-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a diverter system is not required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System Diagram of Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System - Window milling operations: Chloride-based FloVis mud (9.8 ppg) - Drilling operations: Chloride-based FloVis mud (9.8 ppg). While this mud weight may not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. - Completion operations: Well 30-08 contains a sub-surface safety valve allowing deployment of tool strings and liner without pumping kill weight fluid. If the valve does not hold, BHA's will be deployed using standard pressure deployments and the well will be loaded with 12.0 ppg NaBr completion fluid in order to provide formation over-balance while running completions. - Emergency Kill Weight fluid: Two well bore volumes (-195 bbl) of 13.0 ppg Formate emergency kill weight fluid will be within a short drive to the rig during drilling operations. Page 3 of 7 6/17/2015 • • PTD Application: 30-08L1, L1-01, L1-02, L1-03, L1-04 Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole formation throughout the coiled tubing drilling (CTD) process. Maintaining a constant BHP promotes wellbore stability, particularly in shale sections, while at the same time providing an overbalance on the reservoir. Through experience with drilling CTD laterals in the Kuparuk sands, 11.8 ppg has been identified as the minimum EMW to ensure stability of shale sections. Since this well is kicking out into the A3 sand turning northwest in Al pay, we plan to hold 11.8 ppg at the window for stability. The constant BHP target will be adjusted to maintain overbalanced conditions if increased reservoir pressure is encountered during drilling. The constant BHP target will be maintained utilizing the surface choke. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Pressure at the 30-08 Window (7,415' MD, 6,650' TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A-sand Formation Pressure (10 ppg) 3473 psi 3473 psi Mud Hydrostatic (9.4 ppg) 3251 psi 3251 psi Annular friction (i.e. ECD, 0.090 psi/ft) 667 psi 0 psi Mud + ECD Combined 3918 psi 3251 psi (no choke pressure) (overbalanced (underbalanced —445 psi) - 222 psi) Target BHF at Window(11.8 ppg) 4083 psi 4083 psi Choke Pressure Required to Maintain 165 psi 832 psi Target BHP 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005(c)(9)) N/A-Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005(c)(10)) N/A-Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A-Application is not for an exploratory or stratigraphic test well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. Page 4 of 7 6/17/2015 • • PTD Application: 30-08L1, L1-01, L1-02, L1-03, L1-04 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well 30-08 is a Kuparuk A-sand injection well equipped with 3'/2"tubing and 7"production casing. The rig work-over this June will replace the existing tubing and packers with new 3-1/2"tubing with a 5-1/2" "Big Tail Pipe"completion. Five laterals will be drilled to the north west of the parent well with the laterals targeting the different A sand lobes.These laterals will access reserves in the adjacent fault blocks targeting the A3,A2,and Al sands. A mechanical whip-stock will be set inside the 5 ''A"big tail pipe at the planned kick off point of 7,415' MD. The 30-08L1 lateral will exit through the big tail pipe at 7,415'MD and TD at 11,000' MD. Ll lateral will be completed with 2 3/8"slotted liner from TD up to 9,750' MD with an aluminum billet for kicking off the 30-08L1-01 lateral. The 30-08L1-01 will drill to a TD of 11,050' MD,with the liner top at 8,900' MD. The 30-08L1-02 will drill to a TD of 9,670' MD,with the liner top at 8,100' MD. The 30- 08L1-03 will drill to a TD of 11,000' MD,with the liner top at 7,750' MD.The 30-08L1-04 will drill to a TD of 9,170' MD,with the liner top at 7,410 MD;just above the whipstock. Pre-CTD Work 1. RU Slickline:Pull sheared SOV,dummy all gas lift valves,obtain a KRU A-sand SBHP,and conduct a dummy whipstock drift. 2. RU E-line: Set Baker Hughes 3-1/2"x 5-1/2"Thru-Tubing Whipstock. 3. Prep site for Nabors CDR2-AC, including setting BPV. Rig Work 1. MIRU Nabors CDR2-AC rig using 2"coil tubing. NU 7-1/16"BOPE,test. 2. 30-08L1 Lateral(Al sand to north west) a. Mill 2.80"window at 7,415' MD. b. Drill 3"bi-center lateral to TD of 11,000' MD. c. Run 2%"slotted liner with an aluminum billet from TD up to 9,750' MD. 3. 30-08L1-01 Lateral(A2 sand) a. Kick off of the aluminum billet at 9,750' MD. b. Drill 3"bi-center lateral to TD of 11,050' MD. c. Run 2%"slotted liner from TD up to 8,900' MD 4. 30-08L1-02 Lateral(Al sand) a. Kick off of the aluminum billet at 8,900' MD. b. Drill 3"bi-center lateral to TD of 9,670' MD. c. Run 2%"slotted liner from TD up to 8,100' MD 5. 30-08L1-03 Lateral(A2 sand)7 a. Kick off of the aluminum billet at 8,100' MD. b. Drill 3"bi-center lateral to TD of 11,000' MD. c. Run 2%"slotted liner from TD up to 7,750' MD 6. 30-08L1-04 Lateral(A3 sand) a. Kick off of the aluminum billet at 7,750' MD. b. Drill 3"bi-center lateral to TD of 9,170' MD. c. Run 2%"slotted liner from TD up to 7,410' MD, above the whipstock. Page 5 of 7 6/17/2015 • i PTD Application: 30-08L1, L1-01, L1-02, L1-03, L1-04 7. Freeze protect. Set BPV,ND BOPE. RDMO Nabors CRD2-AC. Post-Rig Work 1. Pull BPV. 2. Install GLV's. Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure, so installed in this well is a sub-surface safety valve. This valve, when closed using hydraulic control lines from surface, isolates the well pressure and allows long BHA's to be deployed/un-deployed without killing the well. If the sub-surface safety valve fails, operations will continue using the standard pressure deployment process. A system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slick-line lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slickline. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. • — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment, the steps listed above are observed, only in reverse. Liner Running — The 30-08 well has a sub-surface safety valve installed. It will serve to deploy liners into the newly drilled laterals. If the valve fails the laterals will be displaced to an overbalancing fluid (12 ppg NaBr) prior to running liner. See"Drilling Fluids" section for more details. — While running 2%" slotted liner, a joint of 2%" non-slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2%" rams will provide secondary well control while running 2%" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1R-18 or 1B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). Page 6 of 7 6/17/2015 i i PTD Application: 30-08L1, L1-01, L1-02, L1-03, L1-04 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) — The Applicant is the only affected owner. — Please see Attachment 1: Directional Plan — Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. — MWD directional, resistivity, and gamma ray will be run over the entire open hole section. — Distance to Nearest Property Line (measured to KPA boundary at closest point) Lite a Ptance 30-08L1 3382' 30-08L1-01 5730' 30-08L1-02 4472' 30-08L1-03 3805' 30-08L1-04 3506' — Distance to Nearest Well within Pool Lateral NaraUOIfarce Well :, 1 30-08L1 921' 30-01 30-08L1-01 752' 30-01 30-08L1-02 1872' 30-01 30-08L1-03 792' 30-01 30-08L1-04 3506' 30-05 16. Attachments Attachment 1: Directional Plans for 30-08L1, L1-01, L1-02, L1-03, L1-04 Attachment 2: Current Well Schematic for 30-08 Attachment 3: Proposed Well Schematic for 30-08L1, L1-01, L1-02, L1-03, L1-04 Page 7 of 7 6/17/2015 • • 0 o 2 2 o o in o 0 _ 11 II ❑ N O :r., ~20 o0 Mo"o a;00 p oarc 1--1o O` OM N R MN0] J -p OI co CV — II N a C- L a Q m!w Ov41 11 I1 COu, m II = a) ii II II U) II J I 41 C 0 U J O O p O a) o 2 > E 0 c° II _ 0 L U a ❑.N 2 C m it ❑ C 0 7Q C �� J te IoI O) _ c - O II' II ai p]- - ^c_ O cv 3- a) O O ~� Lo"QV) COO N ap`� r N p C O) 01. H C 00 C c D p� N❑ II co 2 f _O II tI N= N � c N S 2 p _ S II 0 m 0 II o� 78 H T0U. a H CO ao > -o m 1 a`�0M❑ o_ - 7:0 rn Nm ) v�� C N io up '- w cp� 7 • Up 0)c dr O • t o U w E a m `°09 i v°' n. r;cv v = =o2ED =o 03 o 1 O\= U) W N ° W3:J C \ C N 2 Q F-0. (J p0 00 N MN m Xo o a 0 .2 t co c� o ill-0 V O c Q001,e0 M < , 0cv O oU� E m `m Er a _lm � 1" co w N o * E m - '2 N > N C 'E 0 (6 N N N J I- co CY ,_ C o 0 O-N ✓ ) F-Ird2 o rn U , c __ N u_ o X M E2 o c7 m m o a) .ik,:ii:1 CV N p \\ N N O` N- N N Uc. 0 O.O m z Xa u��(n fn0 - �� 0 o o-. m U C) M IV M UJ M in 2 7.,0 O O in d 0 ;N 8 O O_X O N N � y y O V .; N .O N U f�Nx i 0 —czo>c)< i cts d 0 iiii:/ / X d c.- 5o ilk a -m 00 a) �isi Q 3� N� 0 O1 C V N ui C 't N N 0 O OIIp L0 C O c0 Y2 w0O N nVV� N (h O -m _ ,_ "w a�^^ t _2 O)N 2� 0.., (.0(O(0 �i 0 NT� r) 0 0"a C)V,.� '� CO," N y� D Na O.N Qhl�l� V O (I3 TO SON �� CO co Ne} 43/AN M tLn UCO C)h c N�. - N- in X04. • • ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 30 Pad 30-08 30-08L1-03 Plan: 30-08L1-03_wp04 Standard Planning Report 01 April, 2015 latU BAKER HUGHES • • -,e-' Vaal ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 30-08 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-08 @ 58.00usft(30-08) Site: Kuparuk 30 Pad North Reference: True Well: 30-08 Survey Calculation Method: Minimum Curvature Wellbore: r 30-08L1-03 Design: 30-08L1-03_wp04 Project Kuparuk River Unit,North Slope Alaska,United States Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk 30 Pad Site Position: Northing: 6,022,094.67 usft Latitude: 70°28'17.333 N From: Map Easting: 525,478.25 usft Longitude: 149°47'30.897 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.20° Well 30-08 Well Position +N/-S 0.00 usft Northing: 6,021,943.75 usft Latitude: 70°28'15.845 N +E1-W 0.00 usft Easting: 525,566.00 usft Longitude: 149°47'28.332 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 30-08L1-03 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nfl BGGM2014 7/1/2015 18.78 81.01 57,569 Design 30-08L1-03_wp04 Audit Notes: Version: Phase: PLAN Tie On Depth: 8,100.00 Vertical Section: Depth From(TVD) +N/-S +EI-W Direction (usft) (usft)', (usft) (°) 0.00 0.00 0.00 315.00 4/1/2015 10:06:19AM Page 2 COMPASS 5000.1 Build 61 I • ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 30-08 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-08 @ 58.00usft(30-08) Site: Kuparuk 30 Pad North Reference: True Well: 30-08 Survey Calculation Method: Minimum Curvature Wellbore: 30-08L1-03 Design: 30-08L1-03_wp04 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +El-W Rate Rate Rate TFO (usft) (°) (°) (usft) (usft) (usft) (°1100ft) (°1100ft) (°/100ft) (°) Target 8,100.00 93.01 304.71 6,636.38 2,622.58 -459.23 0.00 0.00 0.00 0.00 8,250.00 103.51 304.71 6,614.85 2,706.99 -581.09 7.00 7.00 0.00 0.00 8,350.00 96.51 304.71 6,597.47 2,763.02 -662.00 7.00 -7.00 0.00 180.00 8,450.00 92.47 298.97 6,589.63 2,815.57 -746.64 7.00 -4.04 -5.73 235.00 8,650.00 89.99 312.76 6,585.31 2,932.43 -908.28 7.00 -1.24 6.89 100.00 8,800.00 95.22 303.64 6,578.47 3,024.98 -1,025.86 7.00 3.49 -6.08 300.00 8,910.00 88.55 299.79 6,574.85 3,082.73 -1,119.32 7.00 -6.07 -3.49 210.00 9,015.00 86.66 292.68 6,579.25 3,129.08 -1,213.35 7.00 -1.80 -6.77 255.00 9,170.00 92.11 302.07 6,580.92 3,200.25 -1,350.77 7.00 3.51 6.06 60.00 9,460.00 89.90 322.26 6,575.80 3,393.89 -1,564.56 7.00 -0.76 6.96 96.00 9,710.00 92.90 305.01 6,569.65 3,565.69 -1,744.73 7.00 1.20 -6.90 280.00 9,810.00 96.89 299.24 6,561.12 3,618.65 -1,829.05 7.00 3.99 -5.77 305.00 9,910.00 89.89 299.24 6,555.21 3,667.37 -1,916.10 7.00 -7.00 0.00 180.00 10,030.00 89.02 307.59 6,556.36 3,733.39 -2,016.17 7.00 -0.73 6.96 96.00 10,150.00 89.03 299.19 6,558.41 3,799.37 -2,116.26 7.00 0.01 -7.00 270.00 10,250.00 89.03 306.19 6,560.11 3,853.34 -2,200.36 7.00 0.01 7.00 90.00 10,350.00 86.09 312.55 6,564.37 3,916.67 -2,277.55 7.00 -2.95 6.36 115.00 10,500.00 85.61 323.06 6,575.26 4,027.35 -2,377.89 7.00 -0.32 7.01 93.00 10,600.00 89.12 317.01 6,579.86 4,103.86 -2,442.02 7.00 3.52 -6.06 300.00 10,800.00 89.15 303.00 6,582.88 4,232.09 -2,594.82 7.00 0.01 -7.00 270.00 11,000.00 90.38 316.95 6,583.70 4,360.27 -2,747.70 7.00 0.62 6.97 85.00 4/1/2015 10.06.19AM Page 3 COMPASS 5000.1 Build 61 • • ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 30-08 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-08 @ 58.00usft(30-08) Site: Kuparuk 30 Pad North Reference: True Well: 30-08 Survey Calculation Method: Minimum Curvature Wellbore: 30-08L1-03 Design: 30-08L1-03_wp04 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (0) (0) (usft) (usft) (usft) f (usft) (°/100ft) (°) (usft) (usft) 8,100.00 93.01 304.71 6,636.38 2,622.58 -459.23 2,179.17 0.00 0.00 6,024,564.48 525,097.81 TIP/KOP 8,200.00 100.01 304.71 6,625.04 2,679.12 -540.86 2,276.87 7.00 0.00 6,024,620.73 525,016.00 8,250.00 103.51 304.71 6,614.85 2,706.99 -581.09 2,325.02 7.00 0.00 6,024,648.46 524,975.67 Start 7 dls 8,300.00 100.01 304.71 6,604.66 2,734.85 -621.33 2,373.18 7.00 -180.00 6,024,676.18 524,935.34 8,350.00 96.51 304.71 6,597.47 2,763.02 -662.00 2,421.86 7.00 -180.00 6,024,704.21 524,894.58 3 8,400.00 94.50 301.83 6,592.67 2,790.32 -703.61 2,470.58 7.00 -125.00 6,024,731.36 524,852.89 8,450.00 92.47 298.97 6,589.63 2,815.57 -746.64 2,518.87 7.00 -125.28 6,024,756.46 524,809.76 4 8,500.00 91.86 302.42 6,587.74 2,841.07 -789.60 2,567.27 7.00 100.00 6,024,781.81 524,766.73 8,600.00 90.62 309.31 6,585.58 2,899.61 -870.57 2,665.92 7.00 100.13 6,024,840.07 524,685.56 8,650.00 89.99 312.76 6,585.31 2,932.43 -908.28 2,715.79 7.00 100.28 6,024,872.75 524,647.75 5 8,700.00 91.74 309.72 6,584.55 2,965.38 -945.87 2,765.67 7.00 -60.00 6,024,905.57 524,610.05 8,800.00 95.22 303.64 6,578.47 3,024.98 -1,025.86 2,864.38 7.00 -60.05 6,024,964.89 524,529.86 6 8,900.00 89.15 300.14 6,574.65 3,077.73 -1,110.66 2,961.64 7.00 -150.00 6,025,017.34 524,444.89 8,910.00 88.55 299.79 6,574.85 3,082.73 -1,119.32 2,971.29 7.00 -150.13 6,025,022.31 524,436.21 7 9,000.00 86.93 293.70 6,578.41 3,123.18 -1,199.58 3,056.66 7.00 -105.00 6,025,062.48 524,355.82 9,015.00 86.66 292.68 6,579.25 3,129.08 -1,213.35 3,070.56 7.00 -104.76 6,025,068.33 524,342.03 8 9,100.00 89.65 297.83 6,581.99 3,165.32 -1,290.15 3,150.49 7.00 60.00 6,025,104.30 524,265.12 9,170.00 92.11 302.07 6,580.92 3,200.25 -1,350.77 3,218.06 7.00 59.83 6,025,139.03 524,204.38 9 9,200.00 91.89 304.16 6,579.88 3,216.63 -1,375.88 3,247.40 7.00 96.00 6,025,155.32 524,179.22 9,300.00 91.13 311.12 6,577.24 3,277.65 -1,454.99 3,346.48 7.00 96.07 6,025,216.06 524,099.91 9,400.00 90.36 318.08 6,575.93 3,347.82 -1,526.13 3,446.41 7.00 96.26 6,025,285.98 524,028.53 9,460.00 89.90 322.26 6,575.80 3,393.89 -1,564.56 3,506.15 7.00 96.35 6,025,331.91 523,989.95 10 9,500.00 90.38 319.50 6,575.70 3,424.91 -1,589.79 3,545.93 7.00 -80.00 6,025,362.84 523,964.61 9,600.00 91.59 312.60 6,573.97 3,496.86 -1,659.14 3,645.84 7.00 -80.01 6,025,434.54 523,895.03 9,700.00 92.78 305.70 6,570.15 3,559.91 -1,736.58 3,745.18 7.00 -80.13 6,025,497.32 523,817.38 9,710.00 92.90 305.01 6,569.65 3,565.69 -1,744.73 3,755.03 7.00 -80.39 6,025,503.07 523,809.21 11 9,800.00 96.49 299.82 6,562.28 3,613.75 -1,820.41 3,842.53 7.00 -55.00 6,025,550.87 523,733.37 9,810.00 96.89 299.24 6,561.12 3,618.65 -1,829.05 3,852.10 7.00 -55.43 6,025,555.73 523,724.72 12 9,900.00 90.59 299.24 6,555.25 3,662.49 -1,907.38 3,938.49 7.00 -180.00 6,025,599.30 523,646.25 9,910.00 89.89 299.24 6,555.21 3,667.37 -1,916.10 3,948.11 7.00 -180.00 6,025,604.16 523,637.50 13 10,000.00 89.23 305.50 6,555.90 3,715.53 -1,992.08 4,035.89 7.00 96.00 6,025,652.05 523,561.37 10,030.00 89.02 307.59 6,556.36 3,733.39 -2,016.17 4,065.56 7.00 95.95 6,025,669.83 523,537.22 14 10,100.00 89.02 302.69 6,557.56 3,773.67 -2,073.39 4,134.49 7.00 -90.00 6,025,709.90 523,479.87 10,150.00 89.03 299.19 6,558.41 3,799.37 -2,116.26 4,182.98 7.00 -89.92 6,025,735.45 523,436.91 15 10,200.00 89.03 302.69 6,559.26 3,825.07 -2,159.13 4,231.47 7.00 90.00 6,025,761.00 523,393.96 10,250.00 89.03 306.19 6,560.11 3,853.34 -2,200.36 4,280.61 7.00 89.94 6,025,789.12 523,352.64 16 4/1/2015 10:06:19AM Page 4 COMPASS 5000.1 Build 61 • • ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 30-08 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-08 @ 58.00usft(30-08) Site: Kuparuk 30 Pad North Reference: True Well: 30-08 Survey Calculation Method: Minimum Curvature Wellbore: 30-08L1-03 Design: 30-08L1-03_wp04 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (`) (°) (usft) (usft) (usft) (usft) (°/100ft) (°) (usft) (usft) 10,300.00 87.56 309.37 6,561.59 3,883.95 -2,239.85 4,330.18 7.00 115.00 6,025,819.60 523,313.04 10,350.00 86.09 312.55 6,564.37 3,916.67 -2,277.55 4,379.97 7.00 114.91 6,025,852.18 523,275.24 17 10,400.00 85.91 316.05 6,567.85 3,951.50 -2,313.24 4,429.84 7.00 93.00 6,025,886.89 523,239.43 10,500.00 85.61 323.06 6,575.26 4,027.35 -2,377.89 4,529.19 7.00 92.76 6,025,962.51 523,174.53 18 10,600.00 89.12 317.01 6,579.86 4,103.86 -2,442.02 4,628.63 7.00 -60.00 6,026,038.79 523,110.14 19 10,700.00 89.13 310.00 6,581.38 4,172.65 -2,514.50 4,728.53 7.00 -90.00 6,026,107.32 523,037.44 10,800.00 89.15 303.00 6,582.88 4,232.09 -2,594.82 4,827.36 7.00 -89.89 6,026,166.49 522,956.92 20 10,900.00 89.77 309.98 6,583.83 4,291.52 -2,675.16 4,926.19 7.00 85.00 6,026,225.63 522,876.38 11,000.00 90.38 316.95 6,583.70 4,360.27 -2,747.70 5,026.09 7.00 84.93 6,026,294.12 522,803.62 Planned TD at 11000.00 4/1/2015 10.06.19AM Page 5 COMPASS 5000.1 Build 61 • S ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 30-08 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-08 @ 58.00usft(30-08) Site: Kuparuk 30 Pad North Reference: True Well: 30-08 Survey Calculation Method: Minimum Curvature Wellbore: 30-08L1-03 Design: 30-08L1-03_wp04 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/-S +EI-W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) Latitude Longitude 30-08L1-03_TO1 0.00 0.00 6,632.00 -1,512.721,139,636.64 6,024,345.00 1,665,088.00 70°13'49.308 N 140°33'46.967 W -plan misses target center by 1140103.38usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Point 30-08L1_Fault4 0.00 0.00 0.00 -615.481,138,428.60 6,025,238.00 1,663,877.00 70°13'59.810 N 140°34'17.680 W -plan misses target center by 1138911.77usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Rectangle(sides W365.00 H1.00 D0.00) 30-08L1-03_T08 0.00 0.00 6,560.00 -318.801,137,948.57 6,025,533.00 1,663,396.00 70°14'3.402 N 140°34'30.148 W -plan misses target center by 1138411.60usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Point 30-08L1-03_T03 0.00 0.00 6,585.00 -1,230.291,139,227.57 6,024,626.00 1,664,678.00 70°13'52.657 N 140°33'57.460 W -plan misses target center by 1139693.32usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Point 30-08L1-03_T05 0.00 0.00 6,581.00 -958.721,138,779.46 6,024,896.00 1,664,229.00 70°13'55.958 N 140°34'9.121 W -plan misses target center by 1139244.32usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Point 30-08L1-03_302 0.00 0.00 6,594.00 -1,379.041,139,442.08 6,024,478.00 1,664,893.00 70°13'50.895 N 140°33'51.960 W -plan misses target center by 1139908.34usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Point 30-08L1_Fault3 0.00 0.00 0.00 -955.71 1,138,776.47 6,024,899.00 1,664,226.00 70°13'55.991 N 140°34'9.193 W -plan misses target center by 1139260.65usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Rectangle(sides W370.00 H1.00 D0.00) 30-08L1-03_T04 0.00 0.00 6,575.00 -1,086.581,139,026.04 6,024,769.00 1,664,476.00 70°13'54.351 N 140°34'2.609 W -plan misses target center by 1139491.32usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Point 30-08L1_Fault5 0.00 0.00 0.00 -295.811,137,953.65 6,025,556.00 1,663,401.00 70°14'3.617 N 140°34'29.902 W -plan misses target center by 1138435.96usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Rectangle(sides W375.00 H1.00 D0.00) 30-08L1-03_T09 0.00 0.00 6,584.00 196.181,137,389.28 6,026,046.00 1,662,835.00 70°14'9.230 N 140°34'43.936 W -plan misses target center by 1137851.10usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Point 30-08 CTD Polygon 0.00 0.00 0.00 -2,183.521,140,139.39 6,023,676.00 1,665,593.00 70°13'42.050 N 140°33'35.492 W -plan misses target center by 1140628.06usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Polygon Point 1 0.00 0.00 0.00 6,023,676.00 1,665,593.00 Point 2 0.00 374.09 279.29 6,024,051.01 1,665,870.98 Point 3 0.00 1,267.73 -1,064.82 6,024,939.94 1,664,523.94 Point4 0.00 2,062.29 -2,090.24 6,025,730.89 1,663,495.90 Point5 0.00 2,634.88 -2,838.39 6,026,300.86 1,662,745.86 Point6 0.00 2,301.27 -2,964.53 6,025,966.85 1,662,620.88 Point7 0.00 1,758.01 -2,313.30 6,025,425.88 1,663,273.91 Point8 0.00 1,381.24 -1,800.52 6,025,050.91 1,663,787.93 Point9 0.00 1,116.13 -1,482.38 6,024,786.92 1,664,106.94 Point 10 0.00 753.26 -941.55 6,024,425.95 1,664,648.96 Point 11 0.00 557.21 -636.18 6,024,230.97 1,664,954.97 Point 12 0.00 292.20 -346.05 6,023,966.98 1,665,245.98 Point 13 0.00 0.00 0.00 6,023,676.00 1,665,593.00 30-08L1_Fault1 0.00 0.00 0.00 -1,516.731,139,640.63 6,024,341.00 1,665,092.00 70°13'49.263 N 140°33'46.870 W -plan misses target center by 1140126.69usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Rectangle(sides W363.00 H1.00 D0.00) 30-08L1_Fault2 0.00 0.00 0.00 -1,247.251,139,217.51 6,024,609.00 1,664,668.00 70°13'52.507 N 140°33'57.822 W -plan misses target center by 1139702.64usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Rectangle(sides W360.00 H1.00 D0.00) 4/1/2015 10:06:19AM Page 6 COMPASS 5000.1 Build 61 • • ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 30-08 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-08 @ 58.00usft(30-08) Site: Kuparuk 30 Pad North Reference: True Well: 30-08 Survey Calculation Method: Minimum Curvature Wellbore: 30-08L1-03 Design: 30-08L1-03_wp04 30-08L1-03_T06 0.00 0.00 6,572.00 -625.481,138,428.56 6,025,228.00 1,663,877.00 70°13'59.713 N 140°34'17.724 W -plan misses target center by 1138892.43usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Point 30-08L1-03_T07 0.00 0.00 6,555.00 -500.781,138,229.97 6,025,352.00 1,663,678.00 70°14'1.218 N 140°34'22.874 W -plan misses target center by 1138693.49usft at 8100.00usft MD(6636.38 TVD,2622.58 N,-459.23 E) -Point Casing Points Measured Vertical r.` _ Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 11,000.00 6,583.70 2-3/8" 2.375 3.000 Plan Annotations "°,/moi i Measured Vertical Local Coordinates + o Depth Depth +N/-S +E/-W _"' ,' r,, '�i1"' 3$ Xg (usft) (usft) (usft) (usft) Comment 's, Fr 8,100.00 6,636.38 2,622.58 -459.23 TIP/KOP 8,250.00 6,614.85 2,706.99 -581.09 Start 7 dls 8,350.00 6,597.47 2,763.02 -662.00 3 8,450.00 6,589.63 2,815.57 -746.64 4 8,650.00 6,585.31 2,932.43 -908.28 5 8,800.00 6,578.47 3,024.98 -1,025.86 6 8,910.00 6,574.85 3,082.73 -1,119.32 7 9,015.00 6,579.25 3,129.08 -1,213.35 8 9,170.00 6,580.92 3,200.25 -1,350.77 9 9,460.00 6,575.80 3,393.89 -1,564.56 10 9,710.00 6,569.65 3,565.69 -1,744.73 11 9,810.00 6,561.12 3,618.65 -1,829.05 12 9,910.00 6,555.21 3,667.37 -1,916.10 13 10,030.00 6,556.36 3,733.39 -2,016.17 14 10,150.00 6,558.41 3,799.37 -2,116.26 15 10,250.00 6,560.11 3,853.34 -2,200.36 16 10,350.00 6,564.37 3,916.67 -2,277.55 17 10,500.00 6,575.26 4,027.35 -2,377.89 18 10,600.00 6,579.86 4,103.86 -2,442.02 19 10,800.00 6,582.88 4,232.09 -2,594.82 20 11,000.00 6,583.70 4,360.27 -2,747.70 Planned TD at 11000.00 4/1/2015 10:06.19AM Page 7 COMPASS 5000.1 Build 61 ! 0 0 ` cg r c .... 0 �i g p 4= I — i1 i 0 �O CO N m` O N N 40 11 f O tel. a S O - o v m ',,. a .o h 0 wl ' ±: li ti p'�,: e j 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We primarily rely on choke adjustment which is almost instantaneous and mud weight secondarily. Many of our wells are designed with an underbalanced mud in combination with annular friction and choke to maintain overbalance and well control as already outlined in the verbiage and table on page 4 of the permit. As an example, the 30-08 permit application pg.4 table notes expected choke pressures in order to maintain 11.8 ppg EMW. These choke pressures would increase another^'450 psi, should 13.4 ppg pressure be encountered and there were no changes to mud weight. This surface pressure change is well within the capability of our surface equipment. To switch from drilling mode to completion requires utilizing mud hydrostatic as the primary for overbalance. We would achieve this by adding solid weighting material to 13.0 ppg brine for pressures over 13.0 ppg. We try to avoid this since the solids inhibit weight transfer. We therefore target expected reservoir pressures below 13.0 ppg with pressure management plans on all our candidates. I hope this helps answers your questions. I am curious as to why this particular well is garnering attention when it's not technically different from many of our wells. Please call me if you need more clarification. Thanks, Dan Venhaus CTD Engineering Supervisor-Alaska Cell 907-230-0188 Office 907-263-4372 From: Pohler, Cody J Sent: Wednesday, June 24, 2015 10:03 AM To: Ohlinger, James J; Eller, J Gary; Venhaus, Dan E Subject: FW: KRU 30-08L1, 30-08L1-01, 30-08L1-02, 30-08L1-03, 30-08L1-04(PTDs 215-104,-105,-106,0 108) Her response below From: Loepp, Victoria T(DOA) [mailto:victoria.loeppCa alaska.gov] Sent: Wednesday, June 24, 2015 9:57 AM 1 To: Pohler, Cody J Subject: [EXTERNAL]RE: KRU 30-08L1, 30-08L1-01, 30-08L1-02, 30-08L1-03, 30-08L1-04(PTDs 215-104,-105,-106,- 107,-108) Cody, If 13.4 to 13.9 ppg formation pressure is encountered, can overbalance be maintained through choke adjustment and changes in mud weight? Could you please outline the calculation in a summary table. Thanx, Victoria From: Pohler, Cody J [mailto:Cody.J.Pohler@conocophillips.com] Sent: Tuesday, June 23, 2015 3:18 PM To: Loepp, Victoria T(DOA) Cc: Venhaus, Dan E; Ohlinger, James J; Eller, J Gary Subject: RE: KRU 30-08L1, 30-08L1-01, 30-08L1-02, 30-08L1-03, 30-08L1-04(PTDs 215-104,-105,-106,0 108) Victoria, With a maximum downhole pressure in the 30-08 pattern of 4822 psi(13.9 ppg EMW) is 13.0 ppg KWF nearby adequate? For Kuparuk CTD operations, it is fairly common and expected to encounter formation pressures significantly lower than the maximum pressure in the area.This is due to the faulting and/or drilling distance from the high- pressure injectors. In well 30-08, as in many cases, the well path is towards development well 30-01 (10.6 ppg formation pressure, Feb 2015), and maintains 1600' standoff from the injector 30-05.Therefore we do not anticipate to encounter formation pressures above 12.0 ppg. Please explain how this high pressure risk will be mitigated if encountered? As per standard CTD operations, we will use MPD practices of increasing the choke pressure and possibly the mud weight to maintain overbalance.The completion phase would then require adding weighting material to the 13.0 ppg killweight fluid to run liner. Will another pressure be obtained in 30-05 before drilling? Yes, our expectation is that 30-05 will have declined to at least 13.4 ppg by 30-08 spud date. One, if not several more, formation pressure measurements will be obtained by that time. Is the Baker whipstock flow through? There is substantial area for flow around the Baker 5%2" through-tubing whipstock, so the perforations in the 30- 08 completion will continue to produce after the CTD laterals are drilled and completed. Thanks, Cody From: Loepp, Victoria T (DOA) [mailto:victoria.loer @alaska.gov] Sent: Monday, June 22, 2015 3:01 PM To: Pohler, Cody J 2 Subject: [EXTERNAL]KRU 30-08L1 )-08L1-01, 30-08L1-02, 30-08L1-03, 30-11-04(PTDs 215-104,-105,-106, 108) Cody, With a maximum downhole pressure in the 30-08 pattern of 4822 psi(13.9 ppg EMW) is 13.0 ppg KWF nearby adequate? Please explain how this high pressure risk will be mitigated if encountered?Will another pressure be obtained in 30-05 before drilling? Is the Baker whipstock flow through? Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil&Gas Conservation Commission 333 W.7th Ave,Ste 100 Anchorage,AK 99501 Work: (907)793-1247 Victoria.Loerux talaska.gov CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Victoria Loepp at(907)793-1247 or Victoria.Loepp@alaska.gov 3 • • OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. • • TRANSMITTAL LETTER CHECKLIST WELL NAME: /< U'_. 3 d- -o3 PTD: als-- /0 Development Service _Exploratory Stratigraphic Test _Non-Conventional FIELD: /41141/414 ! AJ- POOL: I ( /ZVIA-- / J/ 31 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 v LATERAL No. PSS-0(02-1 , API No. 50-O2 - alug -Oct - CSO. (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 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 6 • ❑i ❑ N 0) O a) n V) N a) 0 vi, o@ a), , , O , • c co. Q ° , ,, a co 0 ej . 0 Lu c c6 L' �, • Oc a). a, E O CO, o' m ° p. 0) ar a o) 3' os ._ C O, C) 0�, o. ao o. N °, CO E. co pj� a) 7• � > a '. IH 3 o O c, °�' t ami `o Op M. 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