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215-053
Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. vg,_JS_ - Q5 3 Well History File Identifier Organizing (done) ❑ Two-sided ❑ Rescan Needed RES N: OVERSIZED: NOTES: Colo Items: ❑ Maps: rayscale Items: ogs: ❑ Poor Quality Originals: ❑ Other: ❑ Other: BY: CP Date: V/C2///J /s/ mf Project Proofing BY: 40, Date: q Al IS /s/ idA Scanning Preparation c x 30 = tO 0 + �3 = TOTAL PAGES 3 (Count does not include cover sheet) r4 BY: Maria Date: 51g,1 /„S--- /s/ Production Scanning Stage 1 Page Count from Scanned File: gI" (Count does include cov sheet) Page Count Matches Number in Scanning Preparation:)/S' YES NO BY: CP Date: Cr/a r /s/ VIVt P Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Stage 2 Additional Well Reports: YES NO TOTAL PAGES: Digital version appended by: Meredith Michal Date: /s/ Final Page Count: Stage 1 + Stage 2: TOTAL PAGES: Scanning is complete at this point unless rescanning is required. ReScanned BY: Maria Date: /s/ Comments about this file: Quality Checked 7/8/2014 Well History File Cover Page_20140708.doc o kn o • E o c rq •0 .N o C7 E E CO • c G O \ .. < N 0 • 0 • 0 0 J a p e) 0 ml 2 0(14 0 < aT) aT)co Q Q J o c a s c o j } @ I- I- N > > o o c c to c c CO co in 0 • In In a) In In N N it lL U) LL W - R as o 0 0 ai ai ai 0 0 z (Liz E 2 2 F 2 2 F F- 6 Z @ CO CO 0 W W @ N 0 0 N 0 0 _QI F- a mI > _ Q @ N CT m O @ LL it W co W < W U) UD m W W m C I m O O O Y O O O O O O @ —- N 0 N N N Q U) N N N N N N N N &) Q C H@ Z @ @ y < d V 0 O C N Q f0 i6 @ a) N N a i6 w a) a) a) N a) a) a) @ Z d 0 1 O Il E, u n Ow Il u LL U. E Il U. 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D a) w c - CD .a) a7 C/� m y v a) A a p c co p To • a) Q c E as O Ti l'15 0 cn Z O ti .c 0 e O U T E co ca U Z CO N CO 00 l4 N 10 0 3 r O O O O O ami I c Q N co co I w :a ;a :o a I O Z I m m cm rn m rn la p p p p p J E p c O >' CO O F On0 On0 W Ono 0�0 W C > m E W E a O a) WO W dN INN N N N N N o a N re c ` I N > EOZ m ayi w7,5 I 4t cc C Ci Cs/ l Z O O N0° U y U U U U U Q O8 Q O p = t .2- C C U 0 £ o a) E 0 ,-,re O E o aU Eo E E O 0 ° w rn - LL 2 °a UJ W W W J i 0 a 0 0 U a 0 0 , RLCEIVED STATE OF ALASKA JUN 16 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND 1 C la.Well Status: Oil D. Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20AAC 25.105 20AAC 25.110 Development Q • Exploratory ❑ GINJ ❑ WINJ D WAGE 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.: • 5/21/2015 215-053' 3.Address: 7. Date Spudded: 15.API Number: P.O. Box 100360,Anchorage,AK 99501 • 5/19/2015 50-103-20070-60 • 4a.Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 252'FSL,556'FWL,Sec. 1,T11N, R8E, UM ' • 5/20/2015 , KRU 2T-08AL1 , Top of Productive Interval: 9. KB(ft above MSL): 117' 17. Field/Pool(s): /3111-1-29-3'FSL,4.2651 FEL,Sec. 1,T11N, RO8E, UM lA4u/ "F'I�,M„1 GL(ft above MSL): 37' Kuparuk River Field I Kuparuk River Oil Pool ' Total Depth: 1610110. Plug Back Depth MD/TVD: 18. Property Designation: 504'FSL, 829'FEL,Sec. 1,T11N, R8E, UM 8252'MD/5857'TVD' ADL 25569 • 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 498945 ' y- 5970233 • Zone- 4 •8252'MD/5857'TVD . 2667 TPI: x- X35'02502 y- 5911291 Zone- 4 12. SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 502839 ' y- 5970485 .. Zone- 4 nipple @ 501'MD/501'TVD 2140'MD/2121'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) . 7333'MD/5831'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 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT. PULLED 16" 62.5# H-40 37' 115' 37' 115' 24" 234 sx CS II 9.625" 36# J-55 34' 2977' 34' 2798' 12.25" 685 sx AS III,315 sx Class G 7" 26# J-55 1985' 7600' 1975' 6126' 8.5" 300 sx Class G, 175 sx AS I 2.375" 4.6# L-80 7084' 8252' 5726' 5857' 3" slotted liner 24.Open to production or injection? Yes Q 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" 7091' 6995'MD/5658'TVD slotted liner from 7084'-8252'MD 5726'-5857'TVD 4 jcs$i-' lid 6 26.ACID, FRACTURE,CEMENT SQUEEZE,ETC. + Was hydraulic fracturing used during completion? Yes El No ❑ �� Per 20 AAC 25.283(i)(2)attach electronic and printed information "4 . DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED cement plug @ 7200' 16.5 ppg cement cement squeeze 7060-7200 16 bbls of 16.5 ppg Class G 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 6/2/2015 Gas Lift Oil Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 6/15/2015 20 hours Test Period 735 1832 1622 124 1793 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 9R1 1103 24-Hour Rate •=.6. 802 2264 1910 24 Form 0-407 Revised /2015 v T-� 1 /8 /`c CONTIN�IED ON PAGE 2 A Submit ORIGINIAL only_ ` ` .'sr//� RBDM /IAUG 1 7 1015 f_, 28.CORE DATA Conventional Cork 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 ❑ No ❑� Permafrost-Top surface surface If yes, list intervals and formations tested,briefly summarizing test results. Permafrost-Base 2140' 2121' Attach separate pages to this form, if needed,and submit detailed test information, including reports,per 20 AAC 25.071. Kuparuk A3 7333' 5831' Kuparuk A3 7890' 5840' Kuparuk A3 7922' 5840' Formation at total depth: Kuparuk A3 31. List of Attachments: Daily Operations Summary,schematic,final 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: Ron Phillips @ 265-6312 Email: Ron.L.Phillipsconocophillips.com Printed Name: Dan Venhaus Title: CTU Engineering Supervisor Signature: Phone: 263-4372 Date: — 4S 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 la: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated.Each segregated pool is a completion. Item 1 b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing 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 , - ,„ KUP PROD 2T-08AL1 ConocoPhillips 'Well Attributes Max Angle&MD TD Alaska Inc 3Wellbore API/UWI Field Name Wellbore Status ncl(°) MD(ftKB) Act Btm(ftKB) cmocoanlalps'-a' 501032007060 KUPARUK RIVER UNIT PROD 90.77 7,395.47 11,000.0 ... Comment H2S(ppm) Data Annotation End Date KB-Grd(ft) Rig Release Date 2T-08AL1,616/2015 30229 PM SSSV:NIPPLE 25 11/1/2014 Last WO: 40.10 7/22/1986 Verbcal schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag:TDL 7,066.0 4/23/2015 Rev Reason:ADD SIDETRACK,ADD LATERAL smsmith 5/22/2015 HANGER;283Ve. Ll(off main wellbore),ADD PERF/CEMENT,GL Casing Strings .J Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... Wt/Len(I...Grade Top Thread 11 LINER 2 3/8 1 992 7,084 1 8.262 0 5,857.3 4.60 L-80 ST-L . . ,,. � ;. ,p4,,Liner Details Nominal ID -M/CONDUCTOR;37.0-115.0• , Top(ftKB) Top(TVD)(ftKB) Top Incl(1 Item Des Com (in) 7,084.1 5,725.6 40.52 DEPLOY BAKER SHORTY DEPLOYMENT SLEEVE 1.000 • NIPPLE;501.4 Perforations&Slots Shot Dens Top(TVD) Ban(TVD) (shots/f Top(fIKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Corn I;: 7,084.9 8,251.6 5,726.3 5,857.2 A-3,2T-08 5/20/2015 SLOTS Slotted Liner Notes:General&Safety PRODUCTION TIEBACK- _ 9, End Date Annotation 2013;33.6-1,985.0 NOTE: GAS LIFT;2,694.0ar SURFACE;33.6-2,976.8 Al is GAS LIFT;4,498.9 , GAS LIFT;5,629.1 GAS LIFT;6,360.3 rk GAS LIFT;6,909.4 SEAL ASSY;6,965.0 PBR;6,972.9 PACKER;6,995.3 r. V 9' !v Ped;7,070.0-7,072.0—r Y • A v NIPPLE,7,078.3 4. 9 '' 4 r A ;$— WLEG;7,089.7 — v_.. 9 r —9 v- -0 r— WHIPSTOCK-MONOBORE; « _ 7,124.0 0 r— ,4 r r WHIPSTOCK-MONOBORE; 7,140.0 Ped;7,142.0-7,152.0— ' :---- 0 — r PRODUCTION;1,985.0-7,600.01 a c SLOTS;7,084.9-8,251.6 SLOTS;7,344.0-8,930.4 LINER;7,084.1-8,252.0 _ t SLOTS;8,931.6-10,991.6 LINER;7,334.9-10,992.0 I 2T-08 EOW CTD Schematic Modified by RLP 5-29-15 DS-nipple at 501'MD(2.875"min ID,No-Go) II3-1/2",9.3#,L-80,EUE 8rd Mod Tubing to surface 16",62.5#, H-40 h.. .........._ shoe at 115'MD 3-1/2"Camco MMG gas lift mandrels at 2694',4499',5629',6360',& 6909'RKB (6926'PDC) 9-5/8",36#,J-55 _ shoe at 2977'MD !'-_; -- I.' Baker Locator at 6965'RKB (6982'PDC) Ii Baker 3-1/2"80-40 PBR at 6973'RKB (6990'PDC) Baker FHL packer 6995'RKB (7012'PDC) 1111tlf DS-nipple at 7078'RKB (7095'PDC) (2.813"min ID, No-Go) ... ._ 3-1/2"tubing tail at 7091'RKB (7108'PDC) I ! 2T-08AL1 south,TD at 8252' KOP @ 7124'MD Liner top at 7084'MD ` KOP @ 7140'MD \ ---------------- A-sand perfs(sgz'd) _ 7188'-7192'MD I 7202'-7228'MD 2T-08A south,TD at 10,991' Billet @ 7,333' 7",26#casing at 7600'MD 0'-1985': L-80,TC-II 1985-7600': J-55, BTC -MIllme.._ TT-08 WELL WORK SUMMARY DATE SUMMARY PRE-RIG WELL WORK 3/14/2015 SET 2.81"C-LOCK W/FLOW THRU SUB SOFTSET& DUAL SPARTEK GAUGES (OAL=81") @ 7078' RKB.LEFT WELL SI FOR 10 DAY BUILD UP.RETURN LATER.IN PROGRESS 3/25/2015 PULLED 2.81" C LOCK WITH GAUGES @ 7078' RKB. FINAL BHP: 2525 PSI. SET 2.81" CSA-2 PLUG & BAITED PULLING TOOL @ SAME. PULLED GLVs @ 6360', 5629' RKB. SET DV @ 6360' RKB. IN PROGRESS. 3/26/2015 PULLED GLVs @ 4499'&2694' RKB. SET DVs @ 5629', 4499' &2694' RKB. DDT CONFIRMED PLUG INTEGRITY. PULLED OV @ 6909' RKB. LOADED TBG/ IA WITH INHIB SW& DSL. IN PROGRESS. 3/27/2015 CMIT TBG x IA 2500 PSI, GOOD. SET DV @ 6909' RKB. MIT IA 2000 PSI, GOOD. PULLED 2.81" CSA-2 PLUG @ 7078' RKB. READY FOR INJECTIVITY TEST. 4/3/2015 Displaced tubing with 70 bbls seawater. Established injectivity test @ 0.5 bpm @ 450 psi and 1.0 bpm @ 850 psi w/SW. Freeze protected well w/20 diesel. See WSR for details. Note: Unable to perform 0.25 bpm test, minimum rate with pump=0.5 bpm. 4/14/2015 CORRELATED TO HALLIBURTON JEWELRY LOG DATED 8-JAN-2015. PERFORATED 7070'-7072'WITH 2"3SPF MILLENIUM BIG HOLE CHARGES. PERFORATED 7142'- 7152'WITH 2"6 SPF MILLENIUM DEEP PENETRATING CHARGES. 4/16/2015 RAN BAKER NIPPLE LOCATOR FOR 2.81" NIPPLE AND FLAGGED PIPE AT 7093.3' CTMD. PUMPED 21 BBLS OF 16.5 PPG CEMENT. LAYED IN CEMENT FROM 7340' CTMD TO TUBING TAIL AT 7107'CTMD (CORRECTED) GETTING 1:1 RETURNS. ONCE INSIDE THE TUBING WELL WENT ON VAC, LOST ALL RETURNS. ATTEMPTED TO HESSITATE 3 TIMES AND WAS ABLE TO WORK PRESSURE SLOWLY TO 780 PSI, BUT WOULD NOT HOLD. CONTAMINATE CEMENT DOWN TO 7200' CTMD. IN PROGRESS. 4/20/2015 MIXED AND PUMPED 16 BBLS OF 16.5 PPG CEMENT. LAYED IN 1:1 FROM 7190'AND PULLED TO SAFETY AT 5550' CTMD. SQUEEZED 5.5 BBLS OF CEMENT TO FORMATION BEFORE REACHING 1200 PSI SQUEEZE PRESSURE. CONTAMINATED CEMENT LEAVING TOC AT 7060' CTMD. TRAPPED 600 PSI ON TUBING. READY FOR SLICKLINE TAG IN 72 HOURS. 4/23/2015 TAGGED TOC @ EST. 7066' RKB. MIT TBG 2000 PSI, PASSED. READY FOR DHD. 4/24/2015 (PRE-CTD): TREE VALVE TEST, DDT MV(PASSED), DDT SSV(PASSED), DDT SV (PASSED), PP MV(PASSED), PP SSV(PASSED), PP SV(PASSED). ConocoPhillips Time Log & Summary Wel!view Web Reporting Report Well Name: 2T-08 Rig Name: NABORS CDR2-AC Job Type: DRILLING SIDETRACK Rig Accept: 5/8/2015 3:02:00 PM Rig Release: 5/21/2015 3:00:00 PM Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 35/08/2015 24 hr Summary Move from 2K-15 to 2T-08. Spot rig modules. MIRU CDR2 on 21-08. Rig accept @ 15:00.Start initial BOPE test,in progress. 00:00 01:30 1.50 0 0 MIRU MOVE MOB P Move shop to 2T pad, continue rig down off 2K-15. 01:30 02:00 0.50 0 0 MIRU MOVE SFTY P Safety meeting with PEAK trucks. 02:00 05:30 3.50 0 0 MIRU MOVE MOB P Demob Pits and sub off well, move to 2T pad. 05:30 06:30 1.00 0 0 MIRU MOVE RURD P Arrive on location, PJSM, Prep well for rig,deep cellar due to pad buildup. 06:30 10:00 3.50 0 0 MIRU MOVE MOB P Spot drill sub and pits. 10:00 15:00 5.00 0 0 MIRU MOVE RURD P Hook up interconnect, hook up steam lines, rig up stairs and walkways,check tree flange bolts on very crooked tree(30 min), NU BOP, recheck flange bolts(30 min)add extra riser,safe out rig, hook up remote ESD in ops cab to 21-201 and 2T-39,wells are online and at 12.5-ft centers. NOTE:Accept Rig at 15:00 15:00 00:00 9.00 0 0 MIRU WHDBO BOPE P Start BOPE test,test pressure 3500 psi, annular preventer 2500 psi, witness waived by Lou Grimaldi. 05/09/2015 Complete initial BOPE test, pull BPV. Drill cement pilot hole to 7,170', back ream transition area. POOH w/ BHA#1, flow check at surface, no flow. 00:00 03:00 3.00 0 0 MIRU WHDBO BOPE P Complete initial BOPE test. Test waived by Lou Grimadi(AOGCC) 03:00 05:00 2.00 0 0 MIRU WHDBO PRTS P Load coil,test inner reel iron and pack-offs, re-test blind rams, good test. 05:00 07:00 2.00 0 0 MIRU WHDBO MPSP P PJSM. Rig-up FMC Lubricator, pull BPV, LD FMC lubricator 07:00 09:00 2.00 0 0 MIRU WHDBO PRTS P PJSM-Pressure test PDL's,TT line, valve check list, pre floor for drilling operations. 09:00 10:18 1.30 0 62 SLOT WELLPF PULD P PJSM-MU BHA#1, cement pilot hole assembly, 0.9 AKO motor and 2.80"no-go D331 mill, install checks, MU to CoilTrak,surface test. 10:18 11:45 1.46 62 7,066 SLOT WELLPF TRIP P RIH with BHA#1 11:45 12:07 0.38 6,890 7,061 SLOT WELLPF DLOG P Tie in to K1 marker at 7120': +14' correction. Page 1 0111 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 12:07 13:05 0.97 7,061 7,061 SLOT WELLPF DISP P Swap well to 9.8 ppg FloPro mud (leftover from 2K-15). 13:05 13:14 0.16 7,061 7,061 SLOT WELLPF CIRC P Swapped from taking returns to tiger tank to inside and gas was present in returns. Swap back to tiger tank and circulate-15 bbls of 9.8 ppg mud. 13:14 17:41 4.45 7,061 7,170 PROD1 RPEQP1MILL P Close EDC, PUW 30k Ib. RBIH to dry tag at 7086'. PU,pumps online at 1.45 BPM, pump pressure 3600 psi. Begin seeing motor work at-7085.6'. Milling ahead- 1.45 BPM, pump pressure 4000 psi, ROP 18-20 ft/hr. Stall at 7094.5', PUW 26k. Stall at 7108.02', PUW 27k. WOB increase at-7117'indicates possible casing contact point. PU to above TOC, PUW from 7135.82'=26k. 17:41 21:56 4.25 7,170 7,170 PROD1 RPEQP1 REAM P Dry drift set down 1K @ 7,119'. Dress transition area, make several back reaming passes at 180 deg ROHS, improvement, .4 K set down at 7,119'. No improvement last two passes. Call town,try 20 deg ROHS back reaming passes, still seeing .4K @ 7,119',when mill contacts casing. 21:56 22:17 0.35 7,170 7,030 PROD1 RPEQP1DLOG P POOH, Tie-in to K1 for+1' correction. 22:17 23:27 1.18 7,030 96 PROD1 RPEQP1TRIP P POOH w/BHA#1 23:27 23:57 0.50 96 96 PROD1 RPEQP1OWFF P Flow check, no flow. 35/10/2015 Run PDS caliper survey, caliper results indicate good pilot hole. Run BHA#4 whipstock. Set TOWS 7140'. Run BHA#5 window milling assembly.Time drill from 7140'to 7142'at 1 fph. In progress. 00:00 01:00 1.00 96 0 PROD1 RPEQP1PULD P PJSM. LD BHA#1, install nozzle. 01:00 02:00 1.00 0 0 PROD1 RPEQP1CIRC P PJSM.Jet BOP stack, remove nozzle. 02:00 03:30 1.50 0 73 PROD1 RPEQP1PULD P PJSM. PU/MU BHA#2, Caliper assembly,test MWD tools. 03:30 05:30 2.00 73 7,160 PROD1 RPEQPI DLOG P RIH w/BHA#2,tie-in at K1 marker for a+15.5'correction. RIH. 05:30 06:40 1.18 7,160 6,260 PROD1 RPEQP1 DLOG P Arrive at 7160'and wait on caliper fingers to open. Fingers programmed to open at 06:22. Log up hole at 50 fpm until fingers close at 06:40. POOH at-100 fpm. 06:40 07:49 1.15 6,260 71 PROD1 RPEQP1TRIP P POOH at-100 fpm. 07:49 08:19 0.50 71 71 PROD1 RPEQP1 OWFF P Tools at surface. Perform no flow test. PJSM for laying down tools on a dead well. 08:19 08:44 0.43 71 0 PROD1 RPEQP1PULD P LD BHA#2. Page 2 of 11 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 08:44 09:14 0.50 0 71 PROD1 RPEQPI PULD P PJSM for MU dummy drift. MU BHA #3:whipstock dummy drift. Good surface test. 09:14 10:44 1.50 71 7,057 PROD1 RPEQP1TRIP P RIH with dummy drift. 10:44 10:56 0.20 7,057 7,057 PROD1 RPEQPI DLOG P Tie in at K1 marker for a+13.5' correction. PUW @ 7057'=30k lb. 10:56 11:08 0.20 7,057 7,165 PROD1 RPEQP1TRIP P Dry drift cement pilot hole area at —11 fpm. No weight fluctuations. 11:08 12:14 1.10 7,165 71 PROD1 RPEQP1TRIP P POOH 12:14 12:41 0.45 71 71 PROD1 RPEQPI OWFF P On surface, no flow, PJSM-laying down BHA 12:41 13:02 0.35 71 0 PROD1 RPEQP1PULD P LD BHA#3 13:02 13:41 0.65 0 74 PROD1 RPEQPI PULD P PJSM-MU BHA#4, OH anchor whipstock assembly. 13:41 15:18 1.63 74 7,020 PROD1 RPEQP1TRIP P RIH with BHA#4 15:18 15:27 0.15 7,020 7,020 PROD1 RPEQP1DLOG P Tie in at K1 marker fora+14' correction. 15:27 15:57 0.50 7,020 7,151 PROD1 RPEQP1WPST P RIH to 7150.53'. Close EDC, bring pumps online, see circulating pressure spike,set down slightly, no downhole movement, PU, and PUW is normal.TOWS 7140', BOWS 7150.53',set 0 degrees of high side. 15:57 17:15 1.30 7,151 74 PROD1 RPEQP1TRIP P POOH 17:15 17:45 0.50 74 74 PROD1 RPEQPI OWFF P On surface,flow check. 17:45 19:18 1.55 74 74 PROD1 WHPST PULD P PJSM. LD BHA#4. PJSM. MU BHA#5 19:18 21:06 1.80 74 7,141 PROD1 WHPST TRIP P RIH w/Window milling assembly, tie-in to K1 for+14.5'correction, continue in hole. Dry tag depth @ 7,140.8 21:06 23:57 2.86 7,140 7,142 PROD1 WHPST WPST P Start timing milling whipstock as per well plan @ 1 fph. 1.40 BPM @ 3,650 PSI, BHP=3,435 PSI, CTW=8.5K,WOB=1.5K. 05/11/2015 Time mill window exit to 7,147'. Mill rathole to 7,161, before formation sand in returns decreased to 10%, stopped milling rathole. Back ream window,some motor work from 7,141'to 7,145', make additional back ream passes at 30 L/R. Dry drift clean. POOH to make caliper run. Run PDS caliper survey from 7,160'to 6,260'@ 50 fpm. POOH, LD BHA#6, check data,send data to processing.Wait on caliper data and plan forward. 00:00 05:00 5.00 7,142 7,147 PROD1 WHPST WPST P Time mill window at 1 fph. 05:00 07:54 2.90 7,147 7,161 PROD1 WHPST WPST P Continue milling window 1 and 2 fph per plan 1.4 bpm at 3,491 psi, BHP 3,448 psi,WOB 1.9k, CWT 8.3k. 7,148.6 pick up ROP, mill ahead 1.4 bpm at 3,535 psi, BHP 3,449 psi, WOB .8k, CWT 8k. 20%formation sand in returns. 7,156.1-ft, stall, PUW 35k, mill ahead 1.41 bpm at 3,437 psi, BHP 3,450 psi,WOB.4k, CWT 9.5k. 10% sand in returns. L�_ Page 3 of 11 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07:54 10:00 2.10 7,161 7,161 PROD1 WHPST REAM P 7,161-ft, Back ream window,0°with some motor work and-2k WOB 7,145 to 7,141-ft, RBIH,some motor work,WOB 1.9k, confer with town, back ream 30L/30R,dry drift window 0°HS to 7,160-ft.Open EDC 10:00 11:39 1.65 7,161 74 PROD1 WHPST TRIP P POOH with BHA#5 11:39 12:09 0.50 74 74 PROD1 WHPST OWFF P On surface,flow check. PJS-LD BHA 12:09 13:00 0.85 74 0 PROD1 WHPST PULD P LD BHA#5, both mills 2.79"no-go,a little wear on mill side, pics in folder. 13:00 14:27 1.45 0 72 PROD1 WHPST PULD T PDS caliper rep onsite, program tool. PJSM-MU BHA#6 PDS memory caliper assembly, surface test. 14:27 16:51 2.40 72 7,160 PROD1 WHPST TRIP T RIH with BHA#6 EDC closed,tie in to K1 for plus 15-ft correction, continue in hole. 16:51 17:30 0.65 7,160 6,260 PROD1 WHPST DLOG T Arrive at 7160'and wait on caliper fingers to open. Fingers programmed to be fully open at 17:12. Log up hole at 50 fpm until fingers close at 17:30. 17:30 18:30 1.00 6,260 72 PROD1 WHPST TRIP T POOH at—100 fpm. 18:30 19:00 0.50 72 72 PROD1 WHPST OWFF T No flow check 19:00 20:00 1.00 72 0 PROD1 WHPST PULD T PJSM. LD BHA#6, check caliper for data, good data, send to Houston. 20:00 00:00 4.00 0 0 PROD1 WHPST WAIT T Wait on data from Houston and plan forward. Held Pre-spud. It l000ks like we milled off left side of whipstock tray. Continue to wait on town for plan forward. 05/12/2015 Set 3-1/2"monobore XL whipstock:TOWS 7124'at 0 degrees high side.Swap mud to new 9.3 ppg PowerPro system. Run LIB to verify whipstock orientation. Begin milling at 7124.28'at 10 degrees LOHS. 00:00 00:45 0.75 0 0 PROD1 WHPST WAIT T Hold conference call with town on plan forward. Decide to run second whipstock,TOW @ 00:45 04:15 3.50 0 0 PROD1 WHPST WAIT T Call Baker for second whipstock, wait for whipstock arrival. 04:15 05:09 0.90 0 74 PROD1 WHPST PULD T Baker arrived on location. PJSM. MU BHA#7 05:09 07:27 2.30 74 7,135 PROD1 WHPST TRIP T RIH w/3.5" Baker Monobore XL whipstock with OH anchor, upper slip aligned 0 degree highside tray. Tie in to K1 for plus 13.5-ft correction, PUW 30k,continue in hole. 07:27 07:42 0.25 7,135 7,060 PROD1 WHPST WPST T 7,134.53-ft, On depth with whipstock, PU to neutral, release off whipstock at 3,800 psi,stack 5k, PUW 30k,TOWS 7,124-ft, PUH to 7,060-ft 07:42 08:51 1.15 7,060 7,060 PROD1 WHPST DISP T 7,060-ft, Swap mud over to 9.3 ppg PwrPro. 08:51 10:06 1.25 7,060 74 PROD1 WHPST TRIP T POOH with BHA#7 10:06 10:36 0.50 74 74 PROD1 WHPST OWFF T On surface, flow check. PJSM-LD BHA. Page 4of11 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 10:36 11:45 1.15 74 58 PROD1 WHPST PULD T LD BHA#7. PJSM-MU BHA#8, 2.48"OD LIB assembly 11:45 13:24 1.65 58 7,125 PROD1 WHPST TRIP T RIH with BHA#8,tie in at K1 for plus 13.5-ft correction, PUW 28k, continue in hole 13:24 14:33 1.15 7,125 58 PROD1 WHPST TRIP T 7,124.73-ft,Tag up, see 3.2k DHWOB, POOH, PUW 28k, clean. 14:33 15:03 0.50 58 58 PROD1 WHPST OWFF T On surface,flow check. PJSM-LD BHA. 15:03 15:54 0.85 58 73 PROD1 WHPST PULD T LD BHA#8, LIB pics(pre run&post run)put in S: drive folder. PJSM-MU BHA#9 window milling assembly#2, 0.6°motor with 2.80"DSM 15:54 17:23 1.49 73 7,061 PROD1 WHPST TRIP T RIH with BHA#9,tie in to K1 for +13.5'correction 17:23 22:30 5.13 7,061 6,753 PROD1 WHPST WAIT T PUH,discuss plan forward with town. 22:30 22:52 0.37 6,753 7,124 PROD1 WHPST TRIP T Decison made to mill with BHA#9. RIH to dry tag at 7124.28'. PU, pumps online, RIH. 22:52 23:58 1.11 7,124 7,125 PROD1 WHPST WPST T Milling from 7124.28'to 7125.36'. In progress. 35/13/2015 Mill casing window(TOW 7124', BOW 7129.6')and rathole to 7124'. Drill build section. In progress. 00:00 03:00 3.00 7,125 7,129 PROD1 WHPST WPST T Milling from 7125.36'to 7129.4' 03:00 04:00 1.00 7,129 7,131 PROD1 WHPST WPST T OBM at 7129.4ft, 1.47 bpm at 2941 psi, BHP 3265,WHP 0, IA 363, OA 0, DHWOB 1.4k, ROP 1.9 fph 04:00 08:30 4.50 7,131 7,145 PROD1 WHPST WPST T Milling rat hole, 1.44 bpm at 3154 psi, BHP 3270,WHP 0, IA 402, OA 0, DHWOB 2.7k, ROP 3.6 fph. Note: Choke cleaned out, heavy shale. 08:30 09:45 1.25 7,145 7,145 PROD1 WHPST REAM T 7,145-ft, TD rathole, back ream window 10°LOHS,20° R/40°L passes, Dry drift window, clean. 09:45 11:00 1.25 7,145 73 PROD1 WHPST TRIP T POOH for build drilling assembly, open EDC,jog at 1,800-ft,choke plugging with shale. 11:00 12:39 1.65 73 0 PROD1 WHPST PULD T PJSM-Un-deploy/LD BHA#9,2.79" no-go on both mills. 12:39 14:15 1.60 0 63 PROD1 DRILL PULD P PJSM-MU build section BHA#10, 2.3°AKO motor with HCC Bi-center bit, Deploy,make up to CoilTrak, surface test. 14:15 15:30 1.25 63 7,010 PROD1 DRILL TRIP P RIH with BHA#10 15:30 15:45 0.25 7,010 7,040 PROD1 DRILL DLOG P Tie in to K1 for plus 14-ft correction, PUW 23k 15:45 15:54 0.15 7,040 7,145 PROD1 DRILL TRIP P Continue in hole,clean through window 15:54 17:15 1.35 7,145 7,215 PROD1 DRILL DRLG P 7,145-ft, OBD 1.5 bpm at 3,380 psi, BHP 3,421 psi,WHP 96, IA 231, OA 0 17:15 17:30 0.25 7,215 7,020 PROD1 DRILL WPRT P 7,215-ft, PUH to log RA, PUW 24, Page 5 of 11 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 17:30 17:45 0.25 7,020 7,020 PROD1 DRILL DLOG P Tie into the K1 marker correction of 0.0ft 17:45 18:00 0.25 7,020 7,215 PROD1 DRILL WPRT P RBIH to bottom, RIW 14k 18:00 00:00 6.00 7,215 7,300 PROD1 DRILL DRLG P BOBD 1.42 bpm at 3050 psi, BHP 3485,WHP 111, IA 368, OA 0, getting high DGLS,control drill to minimize DGLS. 35/14/2015 TD build section at 7300'. Drill lateral from 7300'to 8366'. In progress. 00:00 01:36 1.60 7,300 78 PROD1 DRILL TRIP P TD build section early due to high 50°DGLS 01:36 03:27 1.85 78 0 PROD1 DRILL PULD P Tools at surface. PJSM. Pressure undeploy BHA#10(build section assembly). 03:27 04:36 1.15 0 81 PROD1 DRILL PULD P PJSM. MU and pressure deploy BHA #11:2 3/8"0.5 degree AKO X-treme motor and 2.7"x3"Hycalog bi-center bit. 04:36 06:12 1.60 81 7,010 PROD1 DRILL TRIP P RIH with BHA#11 06:12 06:33 0.35 7,010 7,300 PROD1 DRILL DLOG P Tie in to K1 for plus 13.5-ft correction, PUW 24k, RBIH. 06:33 09:54 3.35 7,300 7,580 PROD1 DRILL DRLG P 7,300-ft, OBD 1.5 bpm at 3530 psi, BHP 3,480 psi,WHP 119, IA 288, OA 0. 09:54 10:36 0.70 7,580 7,140 PROD1 DRILL DLOG P Wiper up hole with MADD pass to 7,140-ft, PUW 25k, 10:36 14:54 4.30 7,140 7,880 PROD1 DRILL DRLG P 7,580-ft, OBD 1.5 bpm at 3,529 psi, BHP 3,514 psi,WHP 120, IA 495, OA O. 14:54 15:18 0.40 7,880 7,150 PROD1 DRILL WPRT P Wiper up hole, PUW 26K. 15:18 15:42 0.40 7,150 7,880 PROD1 DRILL WPRT P Wiper back in hole, RIW 11K. 15:42 20:13 4.52 7,880 8,180 PROD1 DRILL DRLG P 7,880-ft, OBD 1.5 bpm at 3,528 psi, BHP 3,512 psi,WHP 46 psi, IA 622 psi,OA 0 psi. Drill to 8180.05'. 20:13 20:46 0.55 8,180 7,145 PROD1 DRILL WPRT P Wiper up hole from 8180.05'to 7145', PUW 27.5k 20:46 20:55 0.15 7,145 7,169 PROD1 DRILL DLOG P Tie in at RA marker at 7130'for a +1.5'correction. 20:55 21:20 0.42 7,169 8,180 PROD1 DRILL WPRT P Wiper back in hole from 7169'to bottom, RIW 11.5k 21:20 23:59 2.66 8,180 8,366 PROD1 DRILL DRLG P BOBD(8180.05')1.5 bpm at 3481 psi, BHP 3520 psi,WHP 14 psi, IA 688 psi, OA 0 psi. Fault encountered at 8312'. 05/15/2015 Drill A lateral from 8366'to 9627'. In progress. 00:00 01:27 1.45 8,366 8,480 PROD1 DRILL DRLG P OBD at 8366'. 1.5 bpm at 3380 psi, BHP 3567,WHP 25, IA 728, OA 0 01:27 01:54 0.45 8,480 7,319 PROD1 DRILL WPRT P Wiper trip from 8480'to 7319', PUW 27.5k 01:54 02:21 0.45 7,319 8,480 PROD1 DRILL WPRT P RBIH from 7319 to bottom, RIW 10.1k Page 6 of 11 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 02:21 09:09 6.80 8,480 8,780 PROD1 DRILL DRLG P BOBD at 8480'. 1.5 bpm at 3585 psi, BHP 3531,WHP 4, IA 753,OA 0. Stall at 8643'.slow drilling through Anchorite. 09:09 09:39 0.50 8,780 7,580 PROD1 DRILL WPRT P Wiper up hole, PUW 25k 09:39 10:06 0.45 7,580 8,780 PROD1 DRILL WPRT P Wiper back in hole, RIW 11k. 10:06 14:12 4.10 8,780 9,080 PROD1 DRILL DRLG P 8,780-ft, OBD 1.5 bpm at 3,380 psi, BHP 3,585 psi,WHP 63, IA 317, OA 0. Mud swap Note: New mud at bit at 8,818-ft. 1,694-ft drilled w/0.8%solids. 14:12 15:03 0.85 9,080 7,145 PROD1 DRILL WPRT P Wiper up hole for tie in, PUW 27k 15:03 15:12 0.15 7,145 7,170 PROD1 DRILL DLOG P Log RA marker for plus 2.0-ft correction, PUW 27k 15:12 15:51 0.65 7,170 9,080 PROD1 DRILL WPRT P Wiper in hole, RIW 10k. 15:51 19:42 3.86 9,080 9,380 PROD1 DRILL DRLG P 9,080-ft, OBD 1.5 bpm at 3,397 psi, BHP 3,592 psi,WHP 131, IA 255, OA O. 19:42 20:17 0.59 9,380 9,380 PROD1 DRILL WPRT P Wiper trip from 9380'to 8580'then back to bottom. 20:17 23:59 3.70 9,380 9,627 PROD1 DRILL DRLG P BOBD at 9,380'. 1.5 bpm at 3370 psi, BHP 3620,WHP 95, IA 346, OA 0.AT 9627'at misdnight. 05/16/2015 Drill A lateral from 9627'to 10,535'. In progress. 00:00 00:51 0.85 9,627 9,680 PROD1 DRILL DRLG P At 9627', OBD. 1.5 bpm at 3312 psi, BHP 3652 psi,WHP 74, IA 409, OA 0 00:51 01:42 0.85 9,680 9,680 PROD1 DRILL WPRT P Wiper trip from 9680'to 8680'then back to bottom. 01:42 07:33 5.85 9,680 9,980 PROD1 DRILL DRLG P BOBD. 1.5 bpm at 3400 psi, BHP 3640 psi,WHP 48 psi, IA 437, OA 0 07:33 08:48 1.25 9,980 7,145 PROD1 DRILL WPRT P Wiper trip for tie in, PUW 27k. 08:48 08:57 0.15 7,145 7,170 PROD1 DRILL DLOG P Log RA marker for plus 3.0-ft correction. 08:57 09:57 1.00 7,170 9,980 PROD1 DRILL WPRT P Wiper in hole, RIW 10k 09:57 14:54 4.95 9,980 10,280 PROD1 DRILL DRLG P 9,980-ft, OBD 1.5 bpm at 3,420 psi, BHP 3631 psi,WHP 16, CWT 2k, WOB 1.65k, IA 467, OA 0. 14:54 16:03 1.15 10,280 10,280 PROD1 DRILL WPRT P Wiper trip up hole to 8,700-ft, PUW 27.5k. RBIH, RIW 7k 16:03 21:33 5.50 10,280 10,535 PROD1 DRILL DRLG P 10,280-ft, OBD 1.5 bpm at 3,378 psi, BHP 3,668 psi,WHP 0,CWT 1.8k,WOB 1.4k, ROP 50 fpm, IA 531, OA 0 21:33 22:33 1.00 10,535 7,300 PROD1 DRILL WPRT P 10535ft, pump 5x5 sweep,Wiper up hole to 7300ft, PUW 30k 22:33 23:52 1.32 7,300 10,535 PROD1 DRILL WPRT P 7300ft,Wiper back in hole. RIW 9k 23:52 23:59 0.13 10,535 10,535 PROD1 DRILL DRLG P BOBD. 1.5 bpm at 3210 psi, BHP 3770 psi,WHP 43, IA 447, OA 0 05/17/2015 Drill A lateral from 10,535'to 10990'. Page 7 of 11 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 00:00 01:20 1.34 10,535 10,542 PROD1 DRILL DRLG P BOBD. 1.5 bpm at 3210 psi, BHP 3770 psi,WHP 43, IA 447,OA 0. Not making much hole,time for agitator. 01:20 04:00 2.68 10,542 84 PROD1 DRILL TRIP P POOH. New mud to the bit at 10,535'. 04:00 05:28 1.48 84 0 PROD1 DRILL PULD P Tools at surface. PJSM. Pressure undeploy BHA#11 (drilling assembly). Bit condition 1-1-BT-N-X-I-NO-BHA 05:28 06:13 0.75 0 0 PROD1 DRILL BOPE P Crew change out, PJSM-Function test BOPs. 06:13 08:43 2.50 0 78 PROD1 DRILL PULD P PJSM-MU and pressure deploy BHA #12(drilling assembly with agitator) .5 AKO motor with HYC Bi-center bit, change out checks,surface test, PJSM-change out pack-offs. 08:43 10:37 1.90 78 7,030 PROD1 DRILL TRIP P RIH with BHA#12, 10:37 10:46 0.15 7,030 7,065 PROD1 DRILL DLOG P Tie into the K1 correction of plus 16.5 ft. 10:46 12:04 1.30 7,065 10,539 PROD1 DRILL TRIP P Continue RIH with BHA#12 12:04 16:55 4.85 10,539 10,840 PROD1 DRILL DRLG P 10,539-ft, OBD 1.40 bpm at 3,592 psi, BHP 3,693 psi,WHP 106, IA 232, OA 0 16:55 17:22 0.45 10,840 9,800 PROD1 DRILL WPRT P Wiper trip up hole, PUW 28k. 17:22 17:46 0.40 9,800 10,840 PROD1 DRILL WPRT P Wiper in hole, RIW 7k. 17:46 21:28 3.70 10,840 10,990 PROD1 DRILL DRLG P 10,840-ft, OBD 1.4 bpm at 3,795 psi, BHP 3,688 psi,WHP 16, IA 417, OA 0. 21:28 23:58 2.50 10,990 78 PROD1 DRILL WPRT P TD A lateral at 10990', pump 10 x10 sweep,perform wiper to the swab valves. 35/18/2015 Run A lateral lower completion(bull nose,65 jts 2-3/8"slotted liner, shorty deployment sleeve)to 10,992'.MU A lateral upper completion. 00:00 00:30 0.50 78 78 PROD1 DRILL CTOP P Tighten reel chain, Reset counters to zero 00:30 01:45 1.25 78 7,040 PROD1 DRILL WPRT P RBIH,to tie in depth. 01:45 02:00 0.25 7,040 7,040 PROD1 DRILL DLOG P Tie into the K1 marker correction of plus 13ft. 02:00 03:30 1.50 7,040 10,991 PROD1 DRILL WPRT P Line up orienter for passing through window, continue RIH to confirm TD. 03:30 06:54 3.40 10,991 78 PROD1 DRILL DISP P Confirm TD, 10991',displace well to 11.4 ppg completion fluid. 06:54 07:24 0.50 100 100 PROD1 DRILL OWFF P On Surface, Flow check, PJSM-LD BHA. 07:24 08:24 1.00 100 0 PROD1 DRILL PULD P LD BHA#12, check coil 20-ft above CTC, Bit condition 1-1-BT-N-X-I-BU-TD 08:24 09:24 1.00 0 0 COMPZ CASING RURD P PJSM-Prep floors for liner run, inspect top drive. Note:Test joit disconnect inspected by BOT TT rep. Brent Lane. 09:24 13:21 3.95 0 2,061 COMPZ CASING PUTB P PJSM-MU bull nose,65 jts of 2 3/8" slotted,shorty deployment sleeve. Page 8 of 11 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 13:21 13:57 0.60 2,061 2,106 COMPZ CASING PULD P PJSM-MU BHA#13 on A lateral lower liner assembly, MU to CoilTrak,surface test. 13:57 17:12 3.25 2,106 10,992 COMPZ CASING RUNL P RIH with A lateral lower liner on BHA #13,tie in at flag for 10.5-ft correction,continue in hole, correction at K1 plus 2.5-ft, continue in hole. 17:12 17:24 0.20 10,992 10,992 COMPZ CASING RUNL P 10,992-ft, PUW 35k, release of liner at 1.38 bpm, PUW 25.5k, reset counters. 17:24 19:45 2.35 10,992 45 COMPZ CASING TRIP P POOH 19:45 20:15 0.50 45 45 COMPZ CASING OWFF P Tools at surface. No flow test. 20:15 20:45 0.50 45 0 COMPZ CASING PULD P PJSM for LD BHA#13(lower A lateral liner running assembly). LD BHA#13. 20:45 00:00 3.25 0 1,640 COMPZ CASING PUTB P PJSM for MU upper A lateral liner. MU ported bull nose,53 jts 2 3/8", 4.6#, L-80, STL slotted liner, aluminum liner top billet. (BHA#14) Liner weight=6k lb. 05/19/2015 Finished completion on A lateral, Kicked off of billet at 7333', Drilled ALA lateral from 7333'to 7940' 00:00 02:30 2.50 1,640 8,590 COMPZ CASING RUNL P RIH with BHA#14 02:30 02:43 0.22 8,590 8,629 COMPZ CASING DLOG P Tie in to K1 for+12.5'correction. 02:43 03:02 0.33 8,629 8,929 COMPZ CASING RUNL P RIH. Tag top of lower liner at 8930', PUW @ 8930'=30k, RBIH, pump online at 1.44 bpm, release liner, on bottom. 03:02 04:32 1.50 8,929 44 COMPZ CASING TRIP P POOH 04:32 05:02 0.50 44 44 COMPZ CASING SFTY P PJSM,check well for flow 05:02 05:41 0.65 44 0 COMPZ CASING PULD P LD Liner running BHA#14 05:41 06:59 1.30 0 72 PROD2 STK PULD P MU BHA#15 kick off/drilling assembly, 0.9 AKO motor and HYC used Bi-center bit, MU to CoilTrak, surface test 06:59 08:29 1.50 72 7,030 PROD2 STK TRIP P RIH with BHA#15 08:29 08:41 0.20 7,030 7,070 PROD2 STK DLOG P Tie in at K1 for plus 13-ft correction, PUW 28k 08:41 09:41 1.00 7,070 6,943 PROD2 STK DISP P Displace hole to 9.3 ppg drilling fluid. 09:41 10:11 0.50 6,943 7,333 PROD2 STK TRIP P Trip in to dry tag billet 7333, PUH, PUW=26K 10:11 12:23 2.20 7,333 7,336 PROD2 STK MILL P Time mill off liner top billet, 1.4 BPM @ 3160 PSI FS, BHP=3460 12:23 13:29 1.10 7,336 7,380 PROD2 DRILL DRLG P Drill ahead, 10-20 FPH, 1.4 BPM @ 3084 PSI FS 13:29 13:41 0.20 7,380 7,380 PROD2 DRILL WPRT P PUH to dry drift billet,observed small overpull, -700LBs coming up, clean RIH, PUW=26K, 13:41 17:26 3.75 7,380 7,640 PROD2 DRILL DRLG P 7380', drill ahead, 1.4 BPM @ 3060 PSI FS, BHP=3495, RIW=9.9K Page 9 of 11 Time Logs 9 Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 17:26 18:26 1.00 7,640 7,640 PROD2 DRILL WPRT P 7640',Wiper up hole to 7170', PUW 26k 18:26 23:26 5.00 7,640 7,940 PROD2 DRILL DRLG P 7640', BOBD 1.4 bpm at 3110 psi, BHP 3570,WHP 25, IA 137, OA 0 23:26 23:52 0.44 7,940 7,160 PROD2 DRILL WPRT P 7940',Wiper up hole PUW 25 23:52 23:58 0.11 7,160 7,358 PROD2 DRILL WPRT P 7160',Wiper back in hole RIW 11 05/20/2015 TD well 8252',displaced well to 11.4 ppg completion fluid, MU 37 jts of slotted liner, Started RIH 00:00 00:15 0.25 7,358 7,940 PROD2 DRILL WPRT P 7358', Continue wiper in hole back to bottom. RIW 11k 00:15 08:27 8.20 7,940 8,251 PROD2 DRILL DRLG P 7940', BOBD 1.40 bpm at 3100 psi, BHP 3521,WHP 0, IA 152, OA 0 08:27 10:27 2.00 8,251 83 PROD2 DRILL WPRT P 8,251',TD AL1 lateral, pump 10x10 sweep,perform wiper to the swab valves, PUW 26K. 10:27 11:48 1.35 83 7,035 PROD2 DRILL WPRT P 83.2', RIH to tie in depth 11:48 12:00 0.20 7,035 7,059 PROD2 DRILL DLOG P Tie into K1 marker for plus 13.5 ft. correction,WT check 25.5K 12:00 12:42 0.70 7,059 8,252 PROD2 DRILL WPRT P RIH to confirm TD, RIW 12:42 13:24 0.70 8,252 8,252 PROD2 DRILL TRIP P Tag TD @ 8252 Punp Beaded liner running pill 13:24 15:30 2.10 8,252 89 PROD2 DRILL TRIP P POOH laying in beaded liner running pill, Paint EOP flags @ 6900'and 5800' 15:30 16:00 0.50 89 89 PROD2 DRILL OWFF P Perform 30 Min no flo, PJSM lay down BHA#15 16:00 17:30 1.50 89 0 PROD2 DRILL PULD P Lay down BHA#15-Prep floor to run liner, Inspect top drive 17:30 19:15 1.75 0 0 PROD2 DRILL SFTY P I believe survey discussion with town team. 19:15 22:15 3.00 0 1,168 COMPZ CASING PUTB P PJSM, MU liner assembly 22:15 23:15 1.00 1,168 1,212 COMPZ DRILL PUTB P PJSM, MU BHI tools to liner 23:15 00:00 0.75 1,212 5,172 COMPZ DRILL RUNL P RIH,with AU liner assembly with 37 jts of slotted liner with shorty deployment sleeve. 05/21/2015 Release AU Liner @ 8252,TOL=7084', Roll well to seawater, Freeze protect from 2500', RDMO, Rig Release 15:00 00:00 00:24 0.40 5,172 7,000 COMPZ CASING RUNL P Continue RIH,with liner assembly 00:24 00:39 0.25 7,000 7,000 COMPZ CASING RUNL P Correction at 5800' EOP flag of plus 12.0'. PUW 29k 00:39 01:24 0.75 7,000 8,252 COMPZ CASING RUNL P Continue RIH with liner to bottom. 01:24 01:39 0.25 8,252 8,252 COMPZ CASING TRIP P 8252', Released liner on bottom 8252', leaving the TOL @ 7084.05' 01:39 03:39 2.00 8,252 2,500 COMPZ CASING DISP P POOH,displacing well to seawater. 03:39 04:57 1.30 2,500 0 DEMOB WHDBO FRZP P PJSM, RU Little Red, PT line 3500 psi, freeze protect well from 2500'to surface. 04:57 05:57 1.00 0 0 DEMOB WHDBO PULD P PJSM, Undeploy BHA 05:57 06:27 0.50 0 0 DEMOB WHDBO PULD P Crew change,Valve check list ____ __. _._�_.__ Page 10 of 11 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 06:27 08:03 1.60 0 0 DEMOB WHDBO PULD P PJSM, PUD BHA#16 and lay down 08:03 10:03 2.00 0 0 DEMOB WHDBO CIRC P PJSM, Pull floats from UQC install nozzle. Stab on well. Pump pre flush, 30 BBI inhibitor, and flush 10:03 11:39 1.60 0 0 DEMOB WHDBO MPSP P PJSM, R/U Lubricator, Set BPV, WHP=600PSI 11:39 15:00 3.35 0 DEMOB WHDBO NUND P PJSM, Nipple down stack, check stack bolts-found 7 on tree that needed tightening. Tightened all, RDMO, Rig release @ 15:00 Page 11 of 11 2T-08 WELL WORK SUMMARY DATE SUMMARY POST-RIG WELL WORK 5/25/2015 MADE MULTIPLE MAGNET RUNS TO LINER TOP @ 7078' RKB. RECOVERED REAMINGS & CHUNKS OF METAL. MEASURED BHP @ 7075' RKB: 2936 PSI. SET CATCHER ON LINER TOP @ 7084' RKB. PULLED DV @ 5629' RKB. IN PROGRESS. 5/26/2015 PULLED DV'S @ 4499' &2694' RKB; SET OV @ 5629' RKB. SET GLV's @ 4499' &2694' RKB; (OBTAIN GOOD DDT ON IA) PULLED CATCHER @ 7084' RKB. JOB COMPLETE f ip W wile `M2 4Z m N I C) C CU 0 0- CU 0 a) W Q F- A 0. V) z > •— 0 i - •— — .- _ s .- - - co .C^ C 0) u C > a c = • 0 0 N ti — 4-1 in Y �C L O C = N N C N 02 2 C a ci V O O � a9 � Ca W i C� Y � N � m0 N I. 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LO \ o - <V ° U C \ �• � � CA 43 2 N 4° ° ^ \ /f�2 & ) A 2 2 Guhl, Meredith D (DOA) From: Allsup-Drake, Sharon K <Sharon.K.Allsup-Drake@conocophillips.com> Sent: Wednesday, September 09, 2015 8:42 AM To: Guhl, Meredith D (DOA) Cc: Phillips, Ron L Subject: FW: KRU 2T-08A Ll, PTD 215-053, TPI state plane coordinates Meredith — The x,y coordinates for TPI on 2T-08AL1, at a depth of 7333', is 502502, 5971291. The Legal description would be 1311' FSL, 1166' FEL, Sec. 1, T11N, R8E, UM. Do you want me to send a corrected 10- 407 to you? Thank you, Sharon From: Phillips, Ron L Sent: Friday, September 04, 2015 12:04 PM To: Allsup-Drake, Sharon K Cc: Eller, 3 Gary Subject: RE: KRU 2T-08A L1, PTD 215-053, TPI state plane coordinates Sharon, The 2T-08AL1 kicked off in the A3 pay therefore the top of this lateral is in the TPI for this lateral (7333'MD). Can you recalculate the X,Y coordinates in NAD 27 for box 4b on the 10-407 for 2T-08AL1 and let the AOGCC(Meredith Guhl at meredith.guhl@alaska.gov or 793-1235) know the correct X,Y? I will be going on vacation for 3 weeks starting today. If you need our help on any of this can you please contact Gary Eller. Thanks, Ron L. Phillips Senior CTD Engineer ConocoPhillips Alaska Phone 265-6312 Cell 317-5092 From: Guhl, Meredith D (DOA) [mailto:meredith.guhl@alaska.gov] Sent: Wednesday, September 02, 2015 10:29 AM To: Phillips, Ron L Cc: Bettis, Patricia K (DOA) Subject: [EXTERNAL]KRU 2T-08A L1, PTD 215-053, TPI state plane coordinates Ron, Two questions regarding the listed Top of Productive Interval on the 10-407 form for KRU 2T-08A L1, PTD 215-053. 1. Please re-supply the TPI coordinates listed in box 4b in State Base Plane Coordinates, NAD 27.The coordinates supplied do not agree with our calculations. 2. Please provide the depth of the top of the productive interval. It appears to be the same depth as the kick off point. 1 Please respond via email and I will update the 10-407 form by hand as needed. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave,Suite 100,Anchorage,AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. 2 215053 215052 \ 25873 25872 BAKER PRINT DISTRIBUTION LIST HUGHES Please sign and return one copy of this transmittal form to: COMPANY ConocoPhillips Baker Hughes INTEQ COVED (mandatory) 795 East 94th Avenue DATA LOGGED co/45/2015 WELL NAME 2T-08A,I2T-08AL1 Anchorage,Alaska 99515 M.K.BENDER UN 0 3 2015 (mandatory) JJ FIELD Kuparuk River Unit to acknowledge receipt of this data. A^^CC (mandatory) 1l� COUNTY North Slope Borough LOG TYPE LWD-Coil (mandatory) (mandatory) STATE Alaska BH DISTRICT Alaska (mandatory) i a ndate, LOG DATE: May 22,2015 TODAYS DATE: 1-Jun-15 (mandator DISTRIBUTION LIST AUTHORIZED BY: Paula Lacey EMAIL: paula.lacey(ftakerhughes.com mandatory) HAS CLIENT BEEN INVOICED FOR ADDITIONAL PRINTS? No COMPANY CD (digital/image) FIELD FINAL Final Final ADDRESS(FEDEX WILL NOT DELIVER TO P.O.BOX) LOGS LOGS Survey/Logs Surveys PERSON ATTENTION J� #OF PRINTS #OF PRINTS #OF COPIES #OF PRINTS v V V �7 1 ConocoPhillips Alaska Inc. 1 Karen Hipsher/Lynn Hallford NSK 69 700 G Street Anchorage,AK 99510 2 BP Exploration(Alaska)Inc. 1 1 Petrotechnical Data Center,LR2-1 900 E.Benson Blvd. Anchorage,Alaska 99508 Attn:Analisa Steger 3 Chevron/KRU Rep I 1 1 Attn:Glenn Frederick P.O.Box 196247 Anchorage,AK 99519 4 State of Alaska -AOGCC I 1 I 1 Attn:Makana Bender 333 W.7th Ave,Suite 100 Anchorage,Alaska 99501 5 DNR-Division of Oil&Gas *** I 1 I I Attn:James Hyun 550 West 7th Avenue,Suite 802 Anchorage,Alaska 99501 � ***Stamp"confidential"on all material deliver to DNR TOTALS FOR THIS PAGE: 0 4 4 0 0 0 TOTALS FOR ALL PAGES: 0 4 4 0 0 0 Letter of Transmittal Date: RECEIVED BAKER DATA LOGGED May 22, 2015 MAY 2 6 2015 MK t NDki HUGHESAoricto 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): 2T-08A Z1 5052 25848 2T-08A1.1 2 1 5 0 5 3 2 5 8 4 9 • (2) 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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N: N: N� N. ri N: 00 00 OD co o co- - a d ,Q CI) d U £ 'o m m m 0 0 a `CO 3 0 U) to W I m kIll` O SI Lo c 4 w N 0 C o Q d E o R I- Z o O 0 0 W i- I- y th W U) a Ca- 4-v 2 10g O N CO0 CO y E -, ig N N 0 1- 1- �N. X 2 I o 3 0 ., O O 0 o m m to - 0) 0 UJ J 0 0 N- N- j 01 00 _ _ U ) o /� (� E w I- © V 0 07 V lJ Q Q N N CO CO O O N V N j W C m c N N H W c w IC(V N 0 O O WN I O yq$ a 9 I";:::- 8 0) oC # V 02T21..1.: C 3'A QNt 0 0) 2 C 0 rnCO Ct Z N 'r C o j O C V d O) 4E 9 a co w r2 C o >W w Ce N N >00 0 TS CI C4 f a�. se' o E $ m m g M M o p 2 Z N 0 W ✓ m ✓ N O N N E N N N r r r N tor- o 2 .M V r r ,.O N N 1,-- N Ll Y 0 E 0) U)) 00 0 v m N C 1 N0 (0 '� N co Q Cm 0 D a Q o^ CO m W M a a a in d a' N 8 2 2 a s 0 <0 N O O O N N C a s o -- (0 m S U Y Y N N N m . \\ O M O ON O coO /� N co L c d y N N U a g _ o c a V CO CO E °' m W 2 a o ao ` U) `S o m' N tO tiof Ty �w �\�/j,:s), THE STATE Alaska Oil and Gas � �- �;�, of/�A�\ j\ SIKj\ Conservation Commission • i i -_=_ 333 West Seventh Avenue ion'-.44;4:i GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 *' Main: 907.279 1433 OF ALAS1 Fax: 907.276 7542 www,aogcc.alaska goy D. Venhaus CTD Supervising Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2T-08AL 1 ConocoPhillips Alaska, Inc. Permit No: 215-053 (Revised) Surface Location: 252' FSL, 556' FWL, SEC. 1, T11N, R8E, UM Bottomhole Location: 524' FSL, 844' FEL, SEC. 1, Ti 1N, R8E, UM Dear Mr. Venhaus: Enclosed is the approved application for permit to drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 215-052, API No. 50-103- 20070-01-00. 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, 116-.1 Cathy P. Foerster , Chair — DATED this 28 day of May, 2015. • RECEIVED STATE OF ALASKA - MAY 1 8 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL AOGCC 20 AAC 25.005 1 a Type of Work . 1 b Proposed Well Class. Development-Oil Q• Service-Winj ❑ Single Zone ❑✓ 1 c Specify if well is proposed for Drill ❑ Lateral C Stratigraphic Test❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone❑ Coalbed Gas ❑ Gas Hydrates❑ Redhill ❑ Reentry LI Exploratory ❑ Service-WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2 Operator Name 5 Bond: , U Blanket U Single Well 11.Well Name and Number. ConocoPhillips Alaska, Inc. Bond No. , 59-52-180 KRU 2T-08AL1 • 3 Address: 6 Proposed Depth 12.Field/Pool(s): P.O. Box 100360 Anchorage,AK 99510-0360 MD:8245' • TVD: 5723' . Kuparuk River Field 4a Location of Well(Governmental Section): 7.Property Designation(Lease Number)- Surface:252'FSL,556'FWL, Sec. 1,T11N,R8E,UM • ADL 25569 Kuparuk River Oil Pool - Top of Productive Horizon. 8.Land Use Permit 13.Approximate Spud Date 1324'FSL, 1190'FEL,Sec. 1,T11N, R8E, UM 2667 5/19/2015 Total Depth 9 Acres in Property. 14 Distance to 524'FSL,844'FEL,Sec. 1,T11N, R8E, UM 2560 Nearest Property 4770 4b Location of Well(State Base Plane Coordinates-NAD 27) 10.KB Elevation above MSL • 117 feet 15 Distance to Nearest Well Open Surface:x- 498945 • y- 5970233 • Zone- 4 GL Elevation above MSL. • 82 feet to Same Pool. 2T-13,361 16 Deviated wells Kickoff depth 7 355 ft. -17.Maximum Anticipated Pressures in psig(see 20 AAC 25 035) Maximum Hole Angle 90° deg Downhole:3142 psig . Surface:2573 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 1162' 7083' 5709' 8245' 5723' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft) Total Depth TVD(ft). Plugs(measured) Effective Depth MD(ft) Effective Depth TVD(ft) Junk(measured) 7676 6186 none 7513 6057 none Casing Length Size Cement Volume MD TVD Conductor/Structural 78' 16" 234 sx CS II 115' 115' Surface 2943' 9 625" 685 sx AS III,315 sx Cl G, 2977' 2798' 100 sx AS I Intermediate Production 5615' 7" 300 sx CI G, 175 sx AS I 7600' 6126' Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 7188-7192, 7202-7206, 7208-7228 5805-5808, 5815-5819, 5820-5835 20 Attachments: Property Plat ❑ BOP Sketch❑ Drilling Prograrr O Time v Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements Q 21.Verbal Approval Commission Representative re r b a l appro v-et 1' l"/G for/ LU tpp Date y/' I\j„� 2 22 I hereby certify that the foregoing is true and correct Contact Ron Phillips @ 265-63 ?..&) Email Ron.L.Phillips@cop.com Printed Name D. Ven us Title CTU Engineering Supervisor Signature f1 �,wv �/ ���— Phone:263-4372 Date 5 I\%I\S Commission Use Only Permit to Drill / API Number Permit Approval See cover letter Number:2 t -o53 r<v6tcl 50-\o3-2.0 0 1 0- to 0 -te 0 Date. - 12...3/20t5 for other requirements Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed me hane,gas hydrates,or gas contained in shales: II Other. Oa P 7`i�5 f fa Soo /�5 Samples req'd: Yes No Mud log req'd: Yes❑ No[� 4rz�vla_r --V« fry /1-,s'f- H2S measures: Yes NoDirectional svy req'd: Yes No r 5 Spacing exception req'd: Yes ❑ No U Inclination-only svy req'd: Yes❑ No Rr {ten APPROVED BY THE p Approved by / COMMISSIONER COMMISSION Date S- C-O '(.5.- Form � Form 10-401 a/e( vised 10/2012) Th i i v i ftMooshm the date of approval(20 AAC 25.005(g))- 5�/Sf// � �� /'� _.S- 1777. .,/C' 4 ConocoPhilli s RECEIVED p Alaska MAY 18 2015 P.O. BOX 100360 AOGCC ANCHORAGE,ALASKA 99510-0360 AOGCC 18, 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 permit to drill the second 2T-08A lateral (2T- 08AL1) to the south instead of to the north as permitted using the coiled tubing drilling rig, Nabors CDR2-AC. CTD operations are scheduled to begin May 19, 2015. The objective will be the same as the original objective (to the north) to target the Kuparuk A3 pay in the same fault block as the parent well 2T-08. The 2T-08AL1 lateral will drill south staying -20' TVD over the 2T-08A lateral, but remain in the A3 pay as originally planned. / Now that we have drilled the 2T-08A lateral to the south we know the formation dip, location and throw of the faults to the south better than to the north. This information will help us drill horizontal in the 25' thick Kuparuk • A3 pay. Attached to this application are the following documents: - 10-401 Application for 2T-08AL1 - Detailed Summary of Operations - Directional Plan for 2T-08AL1 - Proposed CTD Schematic If you have any questions or require additional information please contact me at 907-265-6312. Sincerely, j113./Y.4. Ron Phillips ConocoPhillips Alaska Coiled Tubing Drilling Engineer Kuparuk CTD Laterals NABOfl'ALASKA 2T-08A & 2T-08AL1 CLLR °°`°P"'P Application for Permit to Drill Document 2nC 1. Well Name and Classification 2 (Requirements of 20 AAC 25.005(t)and 20 AAC 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 3 (Requirements of 20 AAC 25.005(c)(6)) 3 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 AAC 25.005(c)(9)) 4 10. Seismic Analysis 4 (Requirements of 20 AAC 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 7 14. Disposal of Drilling Mud and Cuttings 7 (Requirements of 20 AAC 25.005(c)(14)) 7 15. Directional Plans for Intentionally Deviated Wells 7 (Requirements of 20 AAC 25.050(b)) 7 16. Attachments 7 Attachment 1: Directional Plans for 2T 08A&2T 08AL1 2T-08AL1 7 Attachment 2: Current Well Schematic for 2T-08 7 Attachment 3: Proposed Well Schematic for 2T-08A CTD Laterals 7 Page 1 of 7 March 9,May 17, 2015. PTD Application: 2T-08A & 2T-OoiL1 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 2T-08A & 2T-08AL1. All laterals will be classified as "Development— Oil" wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) Both laterals will target the A3 sand package in the Kuparuk reservoir. See the attached 10-401 form for surface and subsurface coordinates of the 2T-08A &2T-08AL1. 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 3500 psi. Using the maximum formation pressure in the area of 3142 psi in well 2T-09, the maximum potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 2573 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)) A static bottom hole pressure of 2T-08 in Dec 2014 indicated a reservoir pressure of 2430 psi @ 5806' TVD or 8.0 ppg EMW. The highest pressure in an offset well is at the 2T-09 injector to the east with 3142 psi @ 5695' TVD or 10.6 ppg EMW. Using the 2T-09 pressure as the maximum possible, the maximum possible surface pressure,assuming a gas gradient of 0.1 psi/ft, would be 2573 psi. - The 2T-05 well had 15.7 ppg EMW (4703 psi @ 5770' TVD) back in May 2009 but the 2T-09 drilled within 89' of it and is only seeing 10.6 ppg EMW(3142 psi @ 5695' TVD) in October 2014. Well 2T-06 to the north recently measured the A-sand formation pressure at 5.4 ppg EMW(1653 psi @ 5838' TVD) in August 2014 and all the other surrounding pressures are between 8.7 ppg and 10.6 ppg EMW in the A-sand formation. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) No specific gas zones will be drilled but both the 2T and 2U pads have injected gas. There is a distinct potential • that free gas could be associated with any formation influx. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005(c)(4)(c)) An expected risk of 2T-08 is the hole stability through the A6, A5 &A4 basal shales. We will use MPD techniques to target a constant 11.4 ppg formation pressure while drilling and completing all laterals. There is a . risk of differential sticking since we're drilling into areas of reduced formation pressure. There are limited backup window exit locations in 2T-08. 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. Page 2 of 7 March 0, May 17, 2015 PTD Application: 2T-08A & 2T-Ob,-L1 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Lateral Liner Top Liner Btm Liner Top Liner Btm Liner Details Name MD MD TVDSS TVDSS 2T-08A 7200' 11000' 5573' 5721' 2%", 4.7#, L-80, ST-L slotted liner; with aluminum billet 3 ni _■ - .- 2T�,- ^�T 7083' 8300' 5608' 5588' - - deployment sleevc 2%", 4.7#, L-80, ST-L slotted liner with 2T-08AL1 7083' 8245' 5709' 5723' deployment sleeve Existing Casing/Liner Information Category OD Weight Grade Connection Top Btm Top Btm Burst Collapse (ppf) MD MD TVD TVD psi psi Conductor 16" 62.50 H-40 Welded 0' 115' 0' 115' 1640 630 Surface 9-5/8" 36.0 J-55 BTC 0' 2977' 0' 2798' 3520 2020 Casing 7" 26 J-55 BTC 0' 7600' 0' 6126' 4980 4320 Tubing 3 '/z" 9.3 L-80 EUE-MOD 0' 7091' 0' 5731' 10160 10530 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 PowerVis mud (9.3 ppg) - Drilling operations: Chloride-based PowerVis mud (9.3 ppg). This mud weight should hydrostatically overbalance reservoir pressure. However, if increased formation pressure is encountered then overbalanced conditions will be maintained using MPD practices described below. - Completion operations: 2T-08 does not contain a subsurface safety valve (SSSV). The well will be • loaded with 11.4 ppg NaCl/NaBr completion fluid in order to provide formation over-balance while running completions. - Kill Weight fluid: Two wellbore volumes of 12.9 ppg kill weight fluid will be stored at drillsite 1B in the Kuparuk field, and is accessible for trucking to the rig during CTD operations. Page 3 of 7 March-9, May 17, 2015 PTD Application: 2T-08A & 2T-ObML1 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, 11.4 ppg has been identified as the minimum EMW to ensure stability of shale sections. 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 2T-08 Window (7140' MD, 5768' TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A-sand Formation Pressure (8.0 ppg) 2399 psi 2399psi Mud Hydrostatic (9.3 ppg) 2789 psi 2789 psi Annular friction (i.e. ECD, 0.070 psi/ft) 500 psi 0 psi Mud + ECD Combined 3289 psi 2789 psi (no choke pressure) (overbalanced (overbalanced —890 psi) —390 psi) Target BHP at Window(11.4 ppg) 3419 psi 3419 psi Choke Pressure Required to Maintain 130 psi 630 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 March 9, May 17, 2015 PTD Application: 2T-08A & 2T-ObiL1 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well 2T-08 was a Kuparuk A-sand producer(development)well equipped with 31/2"tubing and 7" production casing. Two laterals from well 2T-08 will be drilled,one to the south(2T-08A)to augment A- sand production from the suspended 2T-13 and one to th?„oerth(2T-08AL1). CTD operations will target the A3 sand. ` a Well 2T-08 was completed into the Kuparuk A-sand interval in 1986 as a single completion. A RWO was performed Feb 2013 replacing the 3-1/2"completion,replacing the top 1985' of 7"casing and cementing the 7"x 9-5/8"annulus up to surface. Prior to CTD operations,the existing A-sand perfs in will be squeezed with cement to provide a means to kick out of the 7"casing. ConocoPhillips has submitted at 10-403 sundry application for a variance from the requirements of 20 AAC 25.112(c)(1)to plug the A-sand perfs in this manner. Immediately prior to cementing the A-sand perfs the tubing tail will be perforated. Both of these operations are needed to prepare the well for CTD operations. After plugging off the existing A-sand perfs with cement pre-rig,the Nabors CDR2-AC drilling rig will drill a pilot hole to 7170' and set a whipstock in the 2.80"pilot hole at the planned kickoff point. Both laterals will exit through the 7"casing at 7140' MD and will target the A3 sand. Both laterals will be . completed with 2W slotted liner from TD with the final liner top located inside the 31/4"tubing. Pre-CTD Work 1. Slickline: Dummy all GLVs. 2. E-line: Shoot 2' of holes in the 31/2"tubing tail at 7053' MD. 3. Coil: Cement squeeze the A-sand perfs bringing cement up into the tubing tail. 4. Slickline: Drift tubing,tag top of cement and pressure test. 5. 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. 2T-08A Sidetrack(A3 sand -south) a. Drill 2.80"high-side pilot hole through cement to 7170' MD b. Caliper pilot hole c. Set whipstock at 7140' MD d. Mill 2.80"window at 7140' MD e. Drill 3-1/4"bi-center lateral to TD of 11,000' MD f. Run 23/8"slotted liner with an aluminum billet from TD up to 7,200' 7,305' MD Page 5 of 7 March 9, May 17, 2015 PTD Application: 2T-08A & 2T-Ob,-L1 3. 2T-08AL1 Lateral (A3 sand—north south) a. Kick off of the aluminum billet at 77280' 7,305' MD • b. Drill 3-1/4"bi-center lateral to TD of 8,300' 8,245' MD • c. Run 2%" slotted liner from TD up to 7083' MD, inside the 3'/2"tubing tail 4. Freeze protect. Set BPV,ND ROPE. RDMO Nabors CRD2-AC. Post-Rig Work 1. Pull BPV 2. Obtain static BHP. Install GLV's. 3. Return to production Pressure Deployment of BHA The planned bottomhole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. Because of this, MPD operations require the BHA to be lubricated under pressure using 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 slickline lubricator. 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. Page 6 of 7 March 9, May 17, 2015 PTD Application: 2T-08A & 2T-OoML1 Liner Running — The 2T-08 CTD laterals will be displaced to an overbalancing fluid (11.4 ppg NaCI/NaBr) prior to running liner. See the"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). 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 openhole section. — Distance to Nearest Property Line and nearest well in the same pool. Distance Distance to . to Sidetrack 11%."- iie Unit Nearest Name 2 ,�a �iiN ; 4 Boundary, ` Wed Nearest Well 2T-08A 03 4,770' 361' 2T-13 2T 08AL1 05 2,620' 1250' 2T-06 2T-08AL1 07 4,770' 361' 2T-13 16. Attachments Attachment 1: Directional Plans for 2T 08A & 2T 08AL 1 2T-08AL 1 Attachment 2: Current Well Schematic for 2T-08 Attachment 3: Proposed Well Schematic for 2T-08A CTD Laterals Page 7 of 7 March 0, May 17, 2015 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2T Pad 2T-08 2T-08AL1 -, lit Plan: 2T-08AL1_wp_07 .' Standard Planning Report 18 May, 2015 BAKER HUGHES 4110 ConocoPhillips Planning Report BAKER HUGHES 1r EDM Alaska Sandbox ailmate References Well 2T-08 Eompany ConocoPhillips(Alaska)Inc -Kup2 T1efappee Mean Sea Level ro ect Kuparuk River Unit Mit . 2T-08 @ 117 OOusft(2T-08) Kuparuk 2T Pad Klorifi a ra True • I N: 21-08 '"Surve Ga cuWbon Method: Minimum Curvature - ri; 2T-08AL1 v® 2T-08AL1_wp_07 . rr�ject Kuparuk River Unit North Slope Alaska United States a� s . ,.4..':,...,. ,..,,ori: .�,m._.,..,-& ,...z s..P...1 W.4 aaaa.a s ....,,,.., 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 2T Pad Site Position: Northing: 5,970,382.43 usft Latitude: 70°19'49.129 N From: Map Easting: 498,944.93 usft Longitude: 150 0'30.807 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: -0.01 ° Well Position +NI-S 0.00 usft Northing: 5,970,232.63 usft • Latitude: 70°19'47.655 N +Ei-W 0.00 usft Easting: 498,944.96 usft Longitude: 150°0'30.806 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft iWeflbd4me 2T-08AL1 /44g°/-!:3,7)4' �� 11A e ti ,, z'' pectination y '-k' Str' 80."89 57,554 BGGM2014 6/1/2015 18.71 ,. •. a. taieslg e , 2T-08AL1 wp 07 ▪.m'�2 .°4 4 4'4'2%2,".•,,m7,,,,,7,,,n44.2,4.,.,, _,,4 ,„':,24444484844444.44444414n.4,".:'•.: w,,.,„ .-4,..„..wt@"�&,EaB�?4412 ," '%41.1:�s✓..',,,, „n_„..., Audit Notes: Version: Phase: PLAN Tie On Depth: 7,305.28 ife cat Senn: Depth From:(TVD)" 1 +E/W Direction ` .IfRii:'44 s usft $ • ,)e °�* a ( ), qft (usft) �� h . 0.00 0.00 0.00 180.00 ▪la , o rNerls 4, t 7t Below xa L}4 I �� i ifird g�� 111 1 K'( ,-y 3 ; ,, a ilk System" +N/-S +EI W q 0 „r k Ff� 4,i. x '��\ } , 51st) (usft) (us• 7 (t ''E (art OOft� (/1IInft) 7,305.28 79.18 119.75 5,708.88 1,073.00 3,533.61 0.00 0.00 0.00 0.00 7,335.00 80.75 122.69 5,714.06 1,057.83 3,558.63 11.08 5.28 9.89 61.79 7,415.00 90.35 122.69 5,720.26 1,014.80 3,625.68 12.00 12.00 0.00 0.00 7,485.00 90.35 131.09 5,719.84 972.82 3,681.61 12.00 -0.01 .12.00 90.00 7,720.00 90.45 159.29 5,718.18 781.82 3,814.41 12.00 0.04 12.00 89.70 7,800.0,0 89.94 168.88 5,717.91 704.98 3,836.32 12.00 -0.63 11.98 93.00 7,900.00 89.21 156.90 5,718.65 609.58 3,865.69 12.00 -0.73 -11.98 266.50 8,050.00 89.25 174.90 5,720.67 464.71 3,902.08 12.00 0.03 12.00 90.00 8,245.00 89.31 198.30 5,723.14 272.36 3,879.82 12.00 0.03 12.00 90.00 COMPASS 5000.1 Build 61 5/18/2015 8:52:21AM Page 2 ConocoPhilliPs Planning Report R HUGHES , �r . EDM Alaska Sandbox s -, _ e -- -e , Well 2T-D8 L : Cono..7,"Phillips(Alaska)Inc.-Kup2 : A ° , ;A Mean Sea Level Kuparuk Unit 2T-08 @ 117 00usft(2T-08) fir,Kuparuk River Pad ,d mance '* True e11 2T-D8ey `lau hod Minimum Curvature o�,r 2T-OSAL1' Li wp_07 t'? x" - lu:�• �a _� r" ,.,. «: �-.....& .ar....a, u.� . �`e..�� :K,.� �.d. .. 4a' fF u.,cu.»,,.aIt, x.�-«a 1' c .'�.z .s. .. ,. • s :x", "_:n �4,. xae:a.a<:� s.�,, : :r.' u;. . '''',1: ...,,,,,,,,,,,,„,,..,,,..v...,-, ,Tanned 9uf "ANItaS amu , NIa' qr g incl,- a:- n Azt 7,305.28 79.18 119.75 5,708.88 1,073.00 3,533.61 1,073.00 0.00 0.00 5,971,305.02 502,478.36 TIP 7,335.00 80.75 122.69 5,714.06 1,057.83 3,558.63 -1,057.83 11.08 61.79 5,971,289.85 502,503.38 KOP 7.400.00 88.55 122.69 5,720.12 1,022.90 3,613.05 1,022.90 12.00 0.00 5,971,254.92 502,557.80 7,415.00 90.35 122.69 5,720.26 1,014.80 3,625.68 -1,014.80 12.00 0.00 5,971,246.82 502,570.42 3 7,485.00 90.35 131.09 5,719.84 972.82 3,681.61 -972.82 12.00 90.00 5,971,204.83 502,626.34 4 7,500.00 90.36 132.89 5,719.74 962.78 3,692.76 -962.78 12.00 89.70 5,971,194.80 502,637.49 7,600.00 90.41 144.89 5,719.08 887.58 3,758.39 -887.58 12.00 89.71 5,971,119.59 502,703.10 7,700.00 90.44 156.89 5,718.33 800.37 3,806.95 800.37 12.00 89.79 5,971,032.39 502,751.64 7,720.00 90.45 159.29 5,718.18 781.82 3,814.41 781.82 12.00 89.88 5,971,013.83 502,759.10 5 7,600.00 89.94 168.88 5,717.91 704.98 3,836.32 -704.98 12.00 93.00 5,970,937.00 502,781.00 6 7,900.00 89.21 156.90 5,718.65 609.58 3,865.69 609.58 12.00 -93.50 5,970,841.60 502,810.35 Z , 8,000.00 89.23 168.90 5,720.01 514.18 3,895.04 514.18 12.00 90.00 5,970,746.21 502,839.68 8,050.00 89.25 174.90 5,720.67 464.71 3,902.08 -464.71 12.00 89.84 5,970,696.74 502,846.71 8 8,100.00 89.26 160.90 5,721.32 414.77 3,903.91 414.77 12.00 90.00 5,970,646.81 502,848.54: 8,200.00 89.29 192.90 5,722.59 315.68 3,891.91 315.68 12.00 89.92 5,970,547.74 502,836.53 8,245.00 89.31 198.30 5,723.14 • 272.36 3,879.82 -272.36 12.00 89.77 5,970,504.42 502,824.43 TD V 511812015 8:52:21AM Page 3 COMPASS 5000.1 Build 61 ConocoPhillips Planning Report BAKER HUGHES. Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 2T-08 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2T-08 @ 117.00usft(2T-08) Site: Kuparuk 2T Pad North Reference: True Well: 2T-08 Survey Calculation Method: Minimum Curvature Wellbore: 2T-08AL1 Design: 2T-08AL1_wp_07 Targets Target Name -hit/misstarget Dip Angle Dip.Di TVDr tNI-S +E!-W Northing Fasting -Shape (°) sft} (usft) (usft) (usft) Latitude Longitude 2T-08AL1 TGT2 5-16-18 0.00 0.00 5,720.00 477.291,144,029.39 5,970,549.00 1,642,860.00 70°5'40.437 N 140°48'19.485 W -plan misses target center by 1140125.48usft at 8100.00usft MD(5721.32 TVD,414.77 N,3903.91 E) -Point • 2T-08AL1 TGT1 5-16-18 0.00 0.00 5,723.00 182.26 1,144,027.43 5,970,254.00 1,642,858.00 70°5'37.575 N 140°48'20.821 W -plan misses target center by 1140123.54usft at 8100.00usft MD(5721.32 TVD,414.77 N,3903.91 E) -Point 2T-08AL1_T04 0.00 0.00 5,682.00 1,654.38 1,143,796.20 5,971,726.00 1,642,627.00 70°5'52.209 N 140°48'21.020 W -plan misses target center by 1139892.96usft at 8100.00usft MD(5721.32 TVD,414.77 N,3903.91 E) -Point 2T-08AL1_T05 0.00 0.00 5,705.00 2,021.41 1,143,744.14 5,972,093.00 1,642,575.00 70°5'55.850 N 140°48'20.910 W -plan misses target center by 1139841.36usft at 8100.00usft MD(5721.32 TVD,414.77 N,3903.91 E) -Point 2T-08A Polygon 0.00 0.00 0.00 1,205.301,143,518.23 5,971,277.00 1,642,349.00 70°5'48.260 N 140°48'30.890 W -plan misses target center by 1139628.96usft at 8100.00usft MD(5721.32 TVD,414.77 N,3903.91 E) -Polygon Point 1 0.00 0.00 0.00 5,971,277.00 1,642,349.00 Point 0.00 -479.07 -89.92 5,970,797.99 1,642,259.02 Point3 0.00 -535.03 146.12 5,970,742.00 1,642,495.03 Point4 0.00 -1,285.08 230.27 5,969,992.02 1,642,579.07 Point 5 0.00 -2,090.24 -144.61 5,969,186.99 1,642,204.11 Point6 0.00 -3,146.43 -603.46 5,968,130.97 1,641,745.16 Point7 0.00 -3,771.54 -853.36 5,967,505.96 1,641,495.19 Point 8 0.00 -4,035.46 -283.25 5,967,241.98 1,642,085.21 Point9 0.00 -2,896.26 132.57 5,968,381.01 1,642,481.15 Point 10 0.00 -2,076.09 632.46 5,969,201.03 1,642,981.10 Point 11 0.00 -1,353.98 813.34 5,969,923.04 1,643,162.07 Point 12 0.00 -631.90 855.21 5,970,645.04 1,643,204.04 Point 13 0.00 -131.89 646.09 5,971,145.03 1,642,995.01 Point 14 0.00 49.07 327.02 5,971,326.02 1,642,675.99 Point 15 0.00 0.00 0.00 5,971,277.00 1,642,349.00 2T-08AL1_T03 0.00 0.00 5,692.00 1,349.341,143,727.23 5,971,421.00 1,642,558.00 70°5'49.350 N 140°48'24.310 W -plan misses target center by 1139823.71 usft at 8100.00usft MD(5721.32 TVD,414.77 N,3903.91 E) -Point 2T-08AL1 Polygon 0.00 0.00 0.00 733.24 1,143,428.29 5,970,805.00 1,642,259.00 70°5'43.810 N 140°48'35.502 W -plan misses target center by 1139538.79usft at 8100.00usft MD(5721.32 TVD,414.77 N,3903.91 E) -Polygon Point 1 0.00 0.00 0.00 5,970,805.00 1,642,259.00 Point2 0.00 -110.94 375.06 - 5,970,694.02 1,642,634.01 Point 3 0.00 97.13 618.04 5,970,902.03 1,642,876.99. Point4 0.00 555.18 666.96 5,971,360.03 1,642,925.97 Point 5 0.00 1,097.23 652.85 5,971,902.03 1,642,911.94 Point 6 0.00 1,403.26 603.79 5,972,208.03 1,642,862.93 Point 7 0.00 1,555.27 576.76 5,972,360.03 1,642,835.92 Point 8 0.00 1,542.17 69.71 5,972,347.01 1,642,328.92 Point 9 0.00 1,035.13 124.81 5,971,840.01 1,642,383.94 Point 10 0.00 653.09- 124.89 5,971,458.01 1,642,383.97 Point 11 0.00 0.00 0.00 5,970,805.00 1,642,259.00 2T-08AL1 TGT4 5-16-15 0.00' 0.00 5,720.00 877.31 1,143,823.31 5,970,949.00 1,642,654.00 70°5'44.625 N 140°48'23.621 W -plan misses target center by 1139919.49usft at 8100.00usft MD(5721.32 TVD,414.77 N,3903.91 E) • -Point 2T-08AL1_TO2 • 0.00 • 0.00 5,705.00 • 1,170.311,143,682.25 5,971,242.00 1,642,513.00 70°5'47.678 N 140°48'26.368 W -plan misses target center by 1139778.80usft at 8100.00usft MD(5721.32 TVD,414.77 N,3903.91 E) -Point 5/18/2015 8:52:21AM Page 4 COMPASS 5000.1 Build 61 Fa' ConocoPhillips Planning Report BAKER HUGHES Database , EDM Alaska Sandbox Well 2T-08 "Company 4-,: I.,/ . a ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk.River Unit Kuparuk 2T Pad 2T-08 2T-08AL1 2T-08AL1_wp_07 b Travelling Cylinder Report 16May, 2015 `a A///,—,- t 04-'. k: 1 m I z F i z BAKER ' R HUGHES INTEQ „a 11110 `IP' 'Sill BAKER ConocoPhillips Travelling Cylinder Report HUGHES FES INTEQ Company 0 ConocoPhillips(Alaska)Inc.-Kup2 Local Co ordmat� iefe nae ir;Well 2T-08 Project Kuparuk River Unit TVD Reference f 'Mean Sea Level Reference-Site:," Kuparuk 2T Pad .MD Reference: ''t,',. 2T-08 @ 117.00usft(2T-08) Site:Errar 0:00usft North Reference: True Reference:Well " 2T-08 Survey Calculation Meth'• Minimum Curvature Well,Error ` ', 0.00usft Output errors are at ',1.00 sigma Referenca.Welllrore 2T-08AL1 Database: :''EDM Alaska Prod ReferenceD srge:f 2T-08AL1 wp_07 Offset TVD Reference 'Offset Datum Reference,,,,,-;,,-----'„w 2T-08AL1 wp 07 ..a,.'3...n', a.s�d.47�^4,-„:«,.tu.,aue -' .,`__,_ ” r.. >:... ..._..., 5 ,�.»..,..s Filter type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 7,305.28 to 8,245.00usft Scan Method: Tray.Cylinder North Results Limited by: Maximum center-center distance of 1,012.80usft Error Surface: Elliptical Conic "•- „ �. � � ,. ..-'�' ;' ua• Y h Survey Tool Program l,, From To - (usft) (usft) Suroey€(Wellliare} Nam'' .iotY 200.00 7,100.00 2T-08 ATDB(2T-08) BOSS-GYRO Sperry-Sun BOSS gyro multishot 7,124.00 7,305.28 2T-08A(2T-08A) MWD MWD-Standard 7,305.28 8,245.00 2T-08AL1_wp_07(2T-0BAL1) MWD MWD-Standard Casing Points Measured Vertical Casing . "Hole.; Depth Depth Diameter `'. .Diameter . ., ., (usft)- _ (usft) �, - Name �F_s ... , ,•„ :. O t 7 . 2,976.00 2,680.83 9 5/8” 9-5/8 12-1/4 700.00 582.97 7" 7 8-1/2 8,300.00 - 2 3/8" 2-3/8 3 m Reference Offset Centre to No-Go Allowable Measured Measured Centre Distance,:,' 'Deviation. Warnrmj lt;Site Name f Depth Depth Distance (usft) from Plan" i, elfrsel>firei fWelludre , i n* usft usft usft usft Kuparuk 2T Pad 2T-08-2T-08-2T-08 7,305.28 7,400.00 154.15 9.98 145.00 Pass-Major Risk 2T-08-2T-08A-2T-08A 7,325.00 7,325.00 0.00 0.28 -0.26 FAIL-Minor 1/10 CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 5/16/2015 5:38:27PM Page 2 of 5 COMPASS 5000.1 Build 61 isin 1.-- BAKER a ConocoPhillips Travelling Cylinder Report NUBS INTEQ ,.,,.....5:,;;;;; it'd Campany xhYF, ConocoPhillips(Alaska)Inc.-Kup2 Local: x .1_ 6 5 m Ire ii F Y 4s a _ 4' 6 t,n m W 4. Fz �v 2 ~m2IA ei▪i E 4 N " 212:1u k, W Q N No0 -C .. .... Vl oN a as n o -. m o s m - (nil'1Tsn 06)(+)41JoNNU(-)Limos 0 __ 3 a I1.1yt 8 Q) - it 21:g I 0 • • 0_ 0 a 1- ,NO NDN%,01 cO A .. • t, _ • m GJ a 1 '000~1 Nz -rN _ _ ( , LOa1100>0000000 C7 a, .�cD is O.r•o r..'�O 1noo -. t 1 O J N- LL 0 0 0)c')c0 0 0 � C. j F- - I- CO 0)CO 01 N Q)07 .. .... - ,.. .. ... '4' p1 F KN N O JO OS 000000 N ...... - .._. ...... 1 clacl N- ,O.-CM N N N N N N. -... - dCe eN MN.-.-NO>NN. _ >>1=1n - <OCOCO(O<M COON • YY 1,v red '�y,'Jri ER u-i�-r 2R 22 6?! :: .: CO +fj ER Nap M COOco 0,ti �`j,. co os , 3Er w' a 3"m _J W om<,NN m onLen,-,, r H v ZrM.��rN-m�a1`rN ,y O 0.0.01 P2 n-CO. .cN 0 `'' a ' N r,p W [�l)CO 232 ,-rnccO c<O, ,M Q1M 0 Vp Q1cO r.NO<'1 M1 rti ur+ �, r,r, j L 0-j .,cO,C,1 l0 u, I[1,O,O zO -t[10)010107 N000 { 11 ^ ,_ Q,-CD COO N CO O)0)M d) O)N N O)N CO O 06. I 1,1 CL VN.,In In., 4?,-- - C.-h-c.,n'1 V',"NN M - 0~)N00100)0NCNTO) - , O. W O + ONu-i 00^ti0griO 8pNQQp805 $* r n n n v n n r ,n v $ V rMrM 1711'Nfe N2N N cl) o (6 N M ,co r Noy (ui�sn 5£) gi.doa IIDI�an°niFi i • KUP PROD 2T-08 ConocoPhillips F Well Attributes Max Angle&MD TD Alaska.Inc. Wellbore API/UWI Field Name Wellbore Status rax (°) MD(ftKB) Act Btm(ftKB) Cmna;ndlt,p, 501032007000 KUPARUK RIVER UNIT PROD 48.25 3,000.00 7,676.0 Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date 2T-08.2/10/20143:23:19 PM SSSV:Flapper Locked Out Last WO: 2/6/2013 40.10 7/22/1986 - Vertical schematic(actual) - - _ Annotation 'Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag:TOC 7,080.0 1262011 Rev Reason: REMOVE CEMENT DISPLAY hipshkf 2/9/2014 .............................HANGER:283 -r �i FROM 1-26-11 L' Casing Strings Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(WD)...WtlLen(I...Grade Top Thread --At CONDUCTOR 16 15.062 37.0 115.0 115.0 62.58 H-40 WELDED ', Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(WD)... Wt/Len(I...'Grade Top Thread 1 N SURFACE 95/8 8.765 33.6 2,976.8 2,798.4 36.00 J-55 'BUTT Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... WtlLen(I...Grade Top Thread Production 2013 Tie-back 7 6276 33.6 1,985.0 1,975.3 26.00 L-80 TC-II "A.A/CONDUCTOR;37.0-115.0• '�r r Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... Wt/Len(I...Grade Top Thread PRODUCTION 7 6.276 1,985.0 7,6000 6,125.8 26.00 J-55 BUTT ® Tubing Strings Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection NIPPLE 501.4 MB TUBING WO 31/2 2.992 28.3 7,091.0 5,730.9 9.30 L-80 EUE-ABM Completion Details • Nominal ID Top(ftKB) Top(WD)(ftKB) Top Incl(°) Item Des Com (in) 28.3 28.3 0.10 HANGER TUBING HANGER 7"X 3-1/2"McEvoy Type DP-1-D-S-3 2.992 at 501.4 501.4 0.67 NIPPLE CAMCO DS NIPPLE w/2.875"PROFILE 2.875 6,965.0 5,635.1 40.57 SEAL ASSY BAKER LOCATOR SEAL ASSEMBLY w/21.74-ft of seals 2.970 P,oaop000 2013 Ge-Sack.33 6- spaced out 7-ft 1 985 0 6,972.9 5,641.1 40.56 PBR BAKER 80-40 PBR 2.990 6,995.3 5,658.1 40.53 PACKER BAKER FHL PRODUCTION PACKER w/4.13-ft Pup 2.940 7,078.3 5,721.3 40.52 NIPPLE CAMCO 2.812"DS NIPPLE 2.812 GAS LIFT;2.694.0 7,089.7 5,729.9 40.52 WLEG 3 1/2"WLEG 2.950 Perforations&Slots Shot Dens . ; Top(TVD) Btm(WD) (shotsM Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Corn 7,188.0 7,192.0 5,804.8 5,807.8 A-3,2T-08 3/3/2013 5.0 RPERF 60°Ph,Millenium 7,188.0 7,192.0 5,804.8 5,807.8 A-4,2T-08 10/14/1986 1.0 CMT 90 deg.Ph;4"HyperJet SURFACE:33.62,97fi8- SQZ II 7,202.0 7,206.0 5,815.4 5,818.5 A-3,21-05 10/14/1986 1.0 CMT 90 deg.Ph;4"HyperJet SQZ II GAS LIFT;A498.9 _ 7,202.0 7,206.0 5,815.4 5,818.5 A-3,2T-08 3/3/2013 5.0 RPERF 60°Ph,Millenium 7208.0 7,228.0 5,820.0 5,835.3 A-3,2T-08 10/14/1986 4.0 CMT 90 deg.Ph;4"HyperJet SQZ II 7,208.0 7,228.0 5,820.0 5,835.3 A-3,2T-08 3/32013 5.0 RPERF 60°Ph,Millenium Cement Squeezes Top ITV()) Btm(TVD) GAS LIFT;5,629.1 :: Top(ftKB) atm(ftKB) (ftKB) (ftKB) Des Start Date Com 7,080.0° 7,229.0° 5,722.5° 5,836.1"CMT PLUG 1/26/2011 'PUMPED&SQUEEZED 10 BBLS OF CLASS G CEMENT ACROSS PERFS;TOC @ 7080' Mandrel Inserts St atl C • on Top(TVD) • Valve Latch Port Sian TRO Run 0 GAS LFT 6.350 3 r; No Top(ftKB) (ftKB) Make Model OD(in) Sew Type Type (in) (psi) Run Date m 1 2,694.0 2,596.0 Camco MMG 11/2 GAS LIFT GLV 'RK 0.188 1,230.0 3/11/2013 2 4,498.9 3,838.7 Camco MMG ' 1 12 GAS LIFT GLV RK 0.188 1,224.0 3/11/2013 3 5,629.1 4,644.4 Camco MMG 1 12 GAS LIFT 'GLV RK 0.188 1,212.0 3/11/2013 4 6,360.3 5,179.2 Camco MMG 11/2 GAS LIFT GLV RK 0.188 1,202.0 3/11/2013 5 6,909.4 5,592.9 Camco MMG 1 1/2 GAS LIFT OV RK 0.188 0.0 3/11/2013 GAS LIFT.6 909 4 Notes:General&Safety End Date Annotation 12/1/2010 NOTE:VIEW SCHEMATIC w/Alaska Schematic9.0 SEAL ASSY;6,965.0 . . PBR;6,9729 PACKER;6.995.3 I • NIPPLE;7,078.3 WLEG;7,089.7 CMT SOZ;7,188.0-7,192.0-\ RPERF;7,188.0-7,192.0 CMT SO2;7,202.0-7,206.0 RPERF;7,2060-7.228 0 CMT SO2;7,276.0-7,228.0, I PRODUCTION:1,985.67,600.0 A N. 05 / � � \ [ / � 5 � \ \ Coo / � ® ¢ % 2 2 \ co ) _® ® A .9 CC ,__°- G \ e G00. § ) 5 / f 0 7 / 7 j \ , oo ? CC - - ? co O . Co9 0a \ . / \ § § �\ \ (N § @ ± 0 -0 ) 0 \ / � / % \ O = 2 * ) _ ( 0 Co E e S » \ \ II ',:, , iI w oo 4•Oa) O gS / 4m 2 S \ \ 2 ED to- \ \ -0 \ \ I % °° ' : 2 f »2 o / ¢ {y 2 = s = \ j ' j A =- taco2 e 3 0 iNi ) ) ) • 7 § & C/ $ csi ,- 0 \ 6 o A co 03 2 2 §& 0' A Z _ 2 / ;© � §, 0 L r/ .ii}\ I ....., : » ,.. v . : } .. 2 w . . } § \ £ § II \ < @ u CI) O I _ U 2 §// . IL 2 I e erm ■ % b a00 /00 li 00\ 3- - 0.C. \\ \/ / / \/§ ) 0 0. %= 2m 0 o S- / -'0 Y Y c m\G 9 co ° Co ` \\ 52 4R/ / .. . E _, , I . 1.1...ilir: _ c, „p I- --rc- r Q � O -o = : - O CD a. -. Z - 3 F ® _.. 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I s4....t, , . .;.:--'177:71,F.iii:ii,,,,,0777: :7175:7.7.7:1V.!:?.U:.!::.i:1;i:i:.i . --- 'eO V` •, I 11 ,4 CC I ) ! 1 i. I E Ore c) )� ( I l l l l l l l l l l l l l l i l l l I l l i l + l i l l l l l l l I l l i i l l l + c �n o kr) o v> o kr) o �n o �n o �n r o N N O N N O N t- oo O N �c �o �c r r r r o0 00 00 0 0, N If) CD kr) �n �n S S � in ConocoPhiili 2T-08A State Plane View ra +2T-08A Surveys Well Plan 04 Parent Well 2T-08—Drillers Polygon Faults 5971500 — 4 _ _ 2K-15L1 KOP 5971035'N/1642358'E 5971000 — D _ Fault#1 -8'DTE , air. Ozc 5970500 Parent Well - 2T-08 1.3. Fault#2 - -25'DTS a — ; D 5970000 —— ,• bk _ I. i_ _ ;• • 0 5969500 — : — I: ke.0000010. " Fault'A' - - 4, -18'DTSE i'4 U Fault'B' e. .0 -? DTSE 5969000 — ..• ....._ io I Fracture - - - X99 -_ a Fault'C '� -4'DTS - f tt 5968500 — - Well Plan 04 5968000 — 5967500 — 5967000 I I 1 I i 1 I 1 i I I I i , t 1 1641000 1641500 1642000 1642500 1643000 1643500 Easting Loepp, Victoria T (DOA) From: Loepp,Victoria T (DOA) Sent: Monday, May 18, 2015 2:37 PM To: 'Eller,J Gary' Subject: RE: KRU 2T-08AL1 (PTD#215-053) Bottomhole Location -Verbal Approval Gary, Verbal approval is granted to proceed with work under the revised PTD 215-053 for KRU 2T-08AL1. 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.Loepp(c alaska.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.Loepo@alaska.gov From: Eller, J Gary [mailto:J.Gary.Eller@conocophillips.com] Sent: Monday, May 18, 2015 9:15 AM To: Loepp, Victoria T(DOA) Cc: Schwartz, Guy L(DOA); Venhaus, Dan E; Phillips, Ron L Subject: FW: KRU 2T-08AL1 (PTD #215-053) Bottomhole Location Victoria—Good morning. We have decided that we would like to pursue the revision to the 2T-08AL1 lateral (PTD#215- 053) as per the e-mail I sent you Friday. ConocoPhillips is preparing the written PTD required for this revision, and we expect to have it in your hands within the next couple of hours. ConocoPhillips requests expedited approval of this PTD revision—by early this evening, the drilling rig will be standing by waiting on permission to proceed with drilling 2T- 08A11. Please let me know if you have any questions. -Gary Eller From: Eller, 3 Gary Sent: Friday, May 15, 2015 9:25 AM To: victoria.loepp@alaska.gov Cc: Phillips, Ron L; Venhaus, Dan E; Goyette, Jennifer A Subject: KRU 2T-08AL1 (PTD #215-053) Bottomhole Location 1 Victoria—Greetings! I wanted to make you aware of a discussion we're having regarding the bottomhole location of the planned 2T-08AL1 lateral (PTD#215-053). The whole purpose of the AL1 lateral was to contact A3-sand pay that would replace the production from the original 2T-08 wellbore, which had to be cemented up in order for us to accomplish our CTD sidetrack. Up until now, we believed that going north was the best way to encounter sufficient A3 pay without encountering significant faulting &geologic complexity. We're presently drilling the 2T-08A sidetrack (PTD#215-052), and early in the lateral we are seeing much less faulting and geologic complexity than we anticipated. As shown on the map below, it has us contemplating whether it would be better to point the AU lateral south instead of north. It would be an easier kickoff and have less geologic uncertainty than steering north, but it would also require a revision to the PTD. This is still in the discussion phase at this point, but I just wanted to alert you to the possibility that we may want to make this change to the AL1 lateral. We still have a long way to go in drilling the 2T-08A, so we should not have to deal with this before Monday. But I just wanted to let you know what we're thinking so you're not caught unaware if we come to you next week asking for this change. Please contact me if you have any questions. «OLE Object: Picture (Device Independent Bitmap)» J. Gary Eller Wells Engineer ConocoPhillips - Alaska work: 907-263-4172 cell: 907-529-1979 Approved well path for 2T-08AL 1 Possible revised location for 2T-08AL1 lateral??? 2 pTO 2i5- -615-3 Loepp, Victoria T (DOA) From: Eller, J Gary <J.Gary.Eller@conocophillips.com> Sent: Friday, May 15, 2015 9:25 AM To: Loepp, Victoria T (DOA) Cc: Phillips, Ron L;Venhaus, Dan E; Goyette, Jennifer A Subject: KRU 2T-08AL1 (PTD#215-053) Bottomhole Location Follow Up Flag: Follow up Flag Status: Flagged Victoria—Greetings! I wanted to make you aware of a discussion we're having regarding the bottomhole location of the planned 2T-08AL1 lateral (PTD#215-053). The whole purpose of the AL1 lateral was to contact A3-sand pay that would replace the production from the original 2T-08 wellbore, which had to be cemented up in order for us to accomplish our CTD sidetrack. Up until now, we believed that going north was the best way to encounter sufficient A3 pay without encountering significant faulting &geologic complexity. We're presently drilling the 2T-08A sidetrack (PTD#215-052), and early in the lateral we are seeing much less faulting and geologic complexity than we anticipated. As shown on the map below, it has us contemplating whether it would be better to point the AL1 lateral south instead of north. It would be an easier kickoff and have less geologic uncertainty than steering north, but it would also require a revision to the PTD. This is still in the discussion phase at this point, but I just wanted to alert you to the possibility that we may want to make this change to the ALA lateral. We still have a long way to go in drilling the 2T-08A, so we should not have to deal with this before Monday. But I just wanted to let you know what we're thinking so you're not caught unaware if we come to you next week asking for this change. Please contact me if you have any questions. 1 _ / , . /f t —___ Approved well path for ' 1 2T-08AL 1 - I r' , __ ; -4 - -, -k,--:T-0$27-48 -.`•v 14 Possible revised location for 2T-08AL1 lateral??? __._; I _______________,....„„ir.,---- , i ,1 ,i,..... f :t I .- ;iy:n --- -it I ff N4: 2T-08 2T-08A _ . :7•17 'T•.. 3. Gary Eller Wells Engineer ConocoPhillips - Alaska work: 907-263-4172 cell: 907-529-1979 2 TRANSMITTAL LETTER CHECKLIST WELL NAME: 5e'&/ 1 l l Di T/ // L / (a ti“2 PTD: �--/ S — Development _Service Exploratory Stratigraphic Test Non-Conventional FIELD: kirt---1 /etv14 POOL: ktye:LA Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit / LATERAL No. 7-/S-UST-, API No. 50-/C.t3- 2>7[) -C.)/ 60. - ;! (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 fJi m OO , a) • • • • a. • . , . , , N C c ,. • , . , . . . • , • . , , COZ c , , , , , , , , , -2,0. 5 gpm,, , o.c, , •> C, p' 0 , a , . . , as. rn Lu u) E O O O @ f6 N' :L' y' a .y o' •N o v, \ o d' a �' , , , , , , , , , , ._ , , .o; 0, ;c. '3. co `. o 0 _� .0 3. U. ,.. , , > 5 •, , as , , , , , , . �, m, , aN), 3' cr 3, �. 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'jJr #k a o c a J o a sLIJ V ,r Fs Q a M liCl a s Q a 0 of - Alaska Oil and Gas �w\�\�y7,�s THE STATE ofALAsKA Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 GOVERNOR BILL WALKER 9 Main: 907.279.1433 ALAS' Fax: 907 276.7542 www.aogcc alaska.gov D. Venhaus CTD Supervising Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2T-08AL1 ConocoPhillips Alaska, Inc. Permit No: 215-053 Surface Location: 252' FSL, 556' FWL, SEC. 1, T11N, R8E, UM Bottomhole Location: 2367' FSL, 1124' FEL, SEC. 1, Ti 1N, R8E, 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. 215-053, API No. 50-103- 20070-01-00. 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, f2e-t Cathy P. oerster Chair DATED this day of March, 2015. .ECEWED STATE OF ALASKA MAR 13 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL AOGCC 20 AAC 25.005 la.Type of Work lb Proposed Well Class Development-Oil Q Service-Winj ❑ Single Zone 2, ic.Specify if well is proposed for Drill ❑ ` Lateral 0 Stratigraphic Test❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone❑ Coalbed Gas ❑ Gas Hydrates❑ Redrill ❑ Reentry E Exploratory ❑ Service-WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name. 5. Bond: • 0 Blanket U Single Well 11.Well Name and Number. ConocoPhillips Alaska, Inc.- Bond No. 59-52-180 . KRU 2T-08AL1 ' 3 Address 6.Proposed Depth. 12.Field/Pool(s): P.O. Box 100360 Anchorage,AK 99510-0360 MD:8300'• ND: 5705' Kuparuk River Field • 4a Location of Well(Governmental Section) 7.Property Designation(Lease Number): Surface:252'FSL,556'FWL,Sec. 1,T11N,R8E, UM ' ADL 25569 . Kuparuk River Oil Pool . Top of Productive Horizon 8 Land Use Permit 13.Approximate Spud Date 1297'FSL, 1356'FEL,Sec. 1,T11N, R8E, UM 2667 5/1/2015 Total Depth 9.Acres in Property: 14.Distance to 2367'FSL, 1124'FEL,Sec. 1,T11N, R8E, UM 2560 - Nearest Property 2620 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL , 117 feet 15.Distance to Nearest Well Open Surface:x- 498945 y- 5970233 Zone- 4. GL Elevation above MSL: , 82 feet to Same Pool. 2T-06,1250 16.Deviated wells Kickoff depth: . 7200 ft. 17.Maximum Anticipated Pressures in psig(see 20 AAC 25 035) Maximum Hole Angle: • 94° deg Downhole:3142 psig . Surface:2573 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 1217' 7083' 5620' 8300' 5705' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft) Plugs(measured) Effective Depth MD(ft): Effective Depth TVD(ft): Junk(measured) 7676 6186 none 7513 6057 none Casing Length Size Cement Volume MD TVD Conductor/Structural 78' 16" 234 sx CS II 115' 115' Surface 2943' 9.625" 685 sx AS III,315 sx CI G, 2977' 2798' 100 sx AS I Intermediate Production 5615' 7" 300 sx CI G, 175 sx AS I 7600' 6126' Liner Perforation Depth MD(ft): Perforation Depth ND(ft): 7188-7192, 7202-7206, 7208-7228 5805-5808, 5815-5819, 5820-5835 20.Attachments Property Plat❑ BOP Sketch❑ Drilling Prograrr ❑✓ Time v Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25 050 requirements Q 21.Verbal Approval: Commission Representative Date: 22 I hereby certify that the foregoing is true and correct Contact Ron Phillips @ 265-6312 Email Ron.L.Phillips@cop.com Printed Name __, D. Venhaus Title CTU Engineering Supe o Signature Phone:263-4372 Date .3 —12- 15 Commission Use Only Permit to Drill API Number: 1 Permit Approval I See cover letter Number c2 IS- o 3 50- 103-0200 7C-(o-bO Date: � 1 16 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. CP Other: Samples req'd. Yes , No 1,1-Mud log req'd: Yes❑ No Z 1� I-775/-- /-c 3j C 5 r Gp ` � c * , _.f�tf s7`�L / `, p 6-* c" r�. fl5 H2S measures: Yes y Alts 1 - \ nal svy req'd: Yes Z No❑ 1-6; 25-6 ��S Spacing exception req'd: Yes ❑ No Inclination-only svy req'd: Yes El No[r APPROVEBBY4}1£` Approved byP)1P-€.„--2-2C74,----COMMISSIONER COMMISSION Date:3- �(S Form 10-401 (Rev ed 10/2012) T rs a the date of approval(20 AAC 25.005 ) ysis ii'r4 13 vrl3//q/iS ��`� 'lotimAhtflom RECEIVED ConocoPhillips MAR 13 2015 Alaska AOGCC P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 March 9, 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 applications for permits to drill a dual-lateral out of the Kuparuk Well 2T-08 using the coiled tubing drilling rig, Nabors CDR2-AC. CTD operations are scheduled to begin in May 2015. The objective will be to drill laterals KRU 2T-08A&2T- 08AL1 targeting the Kuparuk A3-sand. A separate sundry application is attached to plug the KRU 2T-08 (186- 189) perfs to allow these laterals to be drilled. As detailed in the attachments, ConocoPhillips requests a variance from the requirements of 20 AAC 25.112(c)(1) to plug the A-sand perfs in 2T-08. Attached to this application are the following documents: — 10-401 Applications for 2T-08A&2T-08AL1 — Detailed Summary of Operations — Directional Plans for 2T-08A&2T-08AL1 — Proposed CTD Schematic — 10-403 Application to Abandon KRU 2T-08 (186-189) — Operations Summary in support of the 10-403 application If you have any questions or require additional information please contact me at 907-265-6312. Sincerely, Ron Phillips ConocoPhillips Alaska Coiled Tubing Drilling Engineer Kuparuk CTD Laterals NABORS ALASKA I' 2T-08A & 2T-O8ALI °co`mApplication for Permit to Drill Document 2AC 1. Well Name and Classification 2 (Requirements of 20 AAC 25.005(0 and 20 AAC 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 3 (Requirements of 20 AAC 25.005(c)(6)) 3 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 AAC 25.005(c)(9)) 4 10. Seismic Analysis 4 (Requirements of 20 AAC 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 7 14. Disposal of Drilling Mud and Cuttings 7 (Requirements of 20 AAC 25.005(c)(14)) 7 15. Directional Plans for Intentionally Deviated Wells 7 (Requirements of 20 AAC 25.050(b)) 7 16. Attachments 7 Attachment 1: Directional Plans for 2T-08A&2T-08AL1 7 Attachment 2: Current Well Schematic for 21-08 7 Attachment 3: Proposed Well Schematic for 2T-08A CTD Laterals 7 Page 1 of 7 March 9,2015 PTD Application: 2T-08A & 2T-08AL1 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 2T-08A & 2T-08AL1. All laterals will be classified as "Development— Oil'wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) Both laterals will target the A3 sand package in the Kuparuk reservoir. See the attached 10-401 form for surface and subsurface coordinates of the 2T-08A&2T-08AL1. 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 3500 psi. Using the maximum formation pressure in the area of 3142 psi in well 2T-09, the maximum potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 2573 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)) A static bottom hole pressure of 2T-08 in Dec 2014 indicated a reservoir pressure of 2430 psi @ 5806' TVD or 8.0 ppg EMW. The highest pressure in an offset well is at the 2T-09 injector to the east with 3142 psi @ 5695' TVD or 10.6 ppg EMW. Using the 21-09 pressure as the maximum possible, the maximum possible surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 2573 psi. The 2T-05 well had 15.7 ppg EMW(4703 psi @ 5770' TVD) back in May 2009 but the 2T-09 drilled within 89' of it and is only seeing 10.6 ppg EMW(3142 psi @ 5695' TVD) in October 2014. Well 2T-06 to the north recently measured the A-sand formation pressure at 5.4 ppg EMW(1653 psi @ 5838' TVD) in August 2014 and all the other surrounding pressures are between 8.7 ppg and 10.6 ppg EMW in the A-sand formation. Potential Gas Zones (Requirements of 20 AAC 25.005(c)(4)(b)) No specific gas zones will be drilled but both the 2T and 2U pads have injected gas. There is a distinct potential that free gas could be associated with any formation influx. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) An expected risk of 2T-08 is the hole stability through the A6, A5 &A4 basal shales. We will use MPD techniques to target a constant 11.4 ppg formation pressure while drilling and completing all laterals. There is a risk of differential sticking since we're drilling into areas of reduced formation pressure. There are limited backup window exit locations in 2T-08. 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(t), thru-tubing drilling operations need not perform additional formation integrity tests. Page 2 of 7 March 9, 2015 • PTD Application: 2T-08A & 2T-08AL1 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Lateral Liner Top Liner Btm Liner Top Liner Btm Liner Details Name MD MD TVDSS TVDSS 2T-08A 7200' 11000' 5573' 5721' 2%", 4.7#, L-80, ST-L slotted liner; with aluminum billet 2T-08ALI 7083' 8300' 5608' 5588' 2%", 4.7#, L-80, ST-L slotted liner with deployment sleeve Existing Casing/Liner Information Category OD Weight Grade Connection Top Btm Top Btm Burst Collapse (ppf) MD MD TVD TVD psi psi Conductor 16" 62.50 H-40 Welded 0' 115' 0' 115' 1640 630 Surface 9-5/8" 36.0 J-55 BTC 0' 2977' 0' 2798' 3520 2020 Casing 7" 26 J-55 BTC 0' 7600' 0' 6126' 4980 4320 Tubing 3 1/2" 9.3 L-80 EUE-MOD 0' 7091' 0' 5731' 10160 10530 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 PowerVis mud (9.3 ppg) — Drilling operations: Chloride-based PowerVis mud (9.3 ppg). This mud weight should hydrostatically overbalance reservoir pressure. However, if increased formation pressure is encountered then overbalanced conditions will be maintained using MPD practices described below. — Completion operations: 2T-08 does not contain a subsurface safety valve (SSSV). The well will be loaded with 11.4 ppg NaCI/NaBr completion fluid in order to provide formation over-balance while running completions. — Kill Weight fluid: Two wellbore volumes of 12.9 ppg kill weight fluid will be stored at drillsite 1B in the Kuparuk field, and is accessible for trucking to the rig during CTD operations. Page 3 of 7 March 9,2015 PTD Application: 2T-08A & 2T-UESAL1 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, 11.4 ppg has been identified as the minimum EMW to ensure stability of shale sections. 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 2T-08 Window(7140' MD,5768'TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A-sand Formation Pressure (8.0 ppg) 2399 psi 2399psi Mud Hydrostatic(9.3 ppg) 2789 psi 2789 psi Annular friction (i.e. ECD, 0.070 psi/ft) 500 psi 0 psi Mud + ECD Combined 3289 psi 2789 psi (no choke pressure) (overbalanced (overbalanced —890 psi) —390 psi) Target BHP at Window(11.4 ppg) 3419 psi 3419 psi Choke Pressure Required to Maintain 130 psi 630 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 March 9,2015 PTD Application: 2T-08A & 2T-08AL1 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well 2T-08 was a Kuparuk A-sand producer(development)well equipped with 31/2"tubing and 7" production casing. Two laterals from well 2T-08 will be drilled,one to the south(2T-08A)to augment A- sand production from the suspended 2T-13 and one to the north(2T-08AL1). CTD operations will target the A3 sand. Well 2T-08 was completed into the Kuparuk A-sand interval in 1986 as a single completion. A RWO was performed Feb 2013 replacing the 3-1/2"completion,replacing the top 1985' of 7"casing and cementing the 7"x 9-5/8"annulus up to surface. Prior to CTD operations,the existing A-sand perfs in will be squeezed with cement to provide a means to kick out of the 7"casing. ConocoPhillips has submitted at 10-403 sundry application for a variance from the requirements of 20 AAC 25.112(c)(1)to plug the A-sand perfs in this manner. Immediately prior to cementing the A-sand perfs the tubing tail will be perforated. Both of these operations are needed to prepare the well for CTD operations. After plugging off the existing A-sand perfs with cement pre-rig,the Nabors CDR2-AC drilling rig will drill a pilot hole to 7170' and set a whipstock in the 2.80"pilot hole at the planned kickoff point. Both laterals will exit through the 7"casing at 7140' MD and will target the A3 sand. Both laterals will be completed with 2%" slotted liner from TD with the final liner top located inside the 31/2"tubing. Pre-CTD Work 1. Slickline: Dummy all GLVs. 2. E-line: Shoot 2' of holes in the 3%2"tubing tail at 7053' MD. 3. Coil: Cement squeeze the A-sand perfs bringing cement up into the tubing tail. 4. Slickline:Drift tubing,tag top of cement and pressure test. 5. 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. 2T-08A Sidetrack(A3 sand-south) a. Drill 2.80"high-side pilot hole through cement to 7170' MD b. Caliper pilot hole c. Set whipstock at 7140' MD d. Mill 2.80"window at 7140' MD e. Drill 3-1/4"bi-center lateral to TD of 11,000'MD f. Run 2%"slotted liner with an aluminum billet from TD up to 7,200' MD PTD Application: 2T-08A & 2T-08AL1 3. 2T-08AL1 Lateral(A3 sand - north) a. Kick off of the aluminum billet at 7,200' MD b. Drill 3-1/4"bi-center lateral to TD of 8,300' MD c. Run 2%" slotted liner from TD up to 7083' MD, inside the 3'/z"tubing tail 4. Freeze protect. Set BPV,ND BOPE. RDMO Nabors CRD2-AC. Post-Rig Work 1. Pull BPV 2. Obtain static BHP. Install GLV's. 3. Return to production Pressure Deployment of BHA The planned bottomhole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. Because of this, MPD operations require the BHA to be lubricated under pressure using 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 slickline lubricator. 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. Pana Fi of 7 FAarrh Q 71-195 PTD Application: 2T-08A & 2T-OoAL1 Liner Running — The 2T-08 CTD laterals will be displaced to an overbalancing fluid (11.4 ppg NaCI/NaBr) prior to running liner. See the "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). 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 openhole section. / — Distance to Nearest Property Line and nearest well in the same pool. Distance Distance to to Sidetrack Directional Unit Nearest Name Plan Boundary Well Nearest Well 2T-08A 03 4,770' 361' 2T-13 2T-08AL1 05 2,620' 1250' 2T-06 16. Attachments Attachment 1: Directional Plans for 2T-08A & 2T-08AL 1 Attachment 2: Current Well Schematic for 2T-08 Attachment 3: Proposed Well Schematic for 2T-08A CTD Laterals Page 7 of 7 March 9, 2015 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2T Pad 2T-08 2T-08AL1 Plan: 2T-08AL1_wp05 Standard Planning Report 05 March, 2015 rain BAKER HUGHES ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 2T-08 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2T-08 @ 117.00usft(2T-08) Site: Kuparuk 2T Pad North Reference: True Well: 2T-08 Survey Calculation Method: Minimum Curvature Wellbore: 2T-08AL1 Design: 2T-08AL1_wp05 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 2T Pad Site Position: Northing: 5,970,382.43 usft Latitude: 70°19'49.129 N From: Map Easting: 498,944.93 usft Longitude: 150°0'30.807 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: -0.01 ° Well 21-08 Well Position +N/-S 0.00 usft Northing: 5,970,232.63 usft Latitude: 70°19'47.655 N +E/-W 0.00 usft Easting: 498,944.96 usft Longitude: 150°0'30.806 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 2T-08AL1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (0) (0) (nT) BGGM2014 6/1/2015 18.71 80.89 57,554 Design 2T-08AL1_wp05 Audit Notes: Version: Phase: PLAN Tie On Depth: 7,200 00 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (0) r 0.00 0.00 0.00 0.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (0) (0) (usft) (usft) (usft) (°/100ft) (°/100ft) (0/100ft) (0) Target 7,200.00 62.17 63.18 5,689.82 1,077.51 3,430.40 0.00 0.00 0.00 0.00 7,270.00 87.47 43.54 5,708.17 1,117.85 3,483.45 45.00 36.15 -28.06 320.00 7,340.00 93.04 12.52 5,707.85 1,178.86 3,515.93 45.00 7.95 -44.31 280.00 7,410.00 93.71 7.66 5,703.73 1,247.64 3,528.17 7.00 0.96 -6.95 278.00 7,555.00 93.65 17.83 5,694.39 1,388.59 3,560.04 7.00 -0.04 7.01 90.00 7,640.00 91.70 12.20 5,690.42 1,470.56 3,582.02 7.00 -2.30 -6.62 251.00 7,730.00 91.69 18.50 5,687.75 1,557.27 3,605.83 7.00 -0.01 7.00 90.00 7,835.00 92.32 11.18 5,684.07 1,658.63 3,632.69 7.00 0.60 -6.98 275.00 7,940.00 89.20 4.52 5,682.68 1,762.57 3,647.01 7.00 -2.97 -6.34 245.00 8,300.00 83.78 339.85 5,705.06 2,115.69 3,598.76 7.00 -1.51 -6.85 257.00 3/5/2015 9.33.25AM Page 2 COMPASS 5000.1 Build 61 ConocoPhilhps Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 2T-08 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2T-08©117.00usft(2T-08) Site: Kuparuk 2T Pad North Reference: True Well: 21-08 Survey Calculation Method: Minimum Curvature Wellbore: 2T-08AL1 Design: 2T-08AL1_wp05 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) 7,200.00 62.17 63.18 5,689.82 1,077.51 3,430.40 1,077.51 0.00 0.00 5,971,309.55 502,375.17 TIP/KOP 7,270.00 87.47 43.54 5,708.17 1,117.85 3,483.45 1,117.85 45.00 -40.00 5,971,349.88 502,428.22 Start 45 dls 7,300.00 89.86 30.24 5,708.87 1,141.78 3,501.41 1,141.78 45.00 -80.00 5,971,373.80 502,446.18 7,340.00 93.04 12.52 5,707.85 1,178.86 3,515.93 1,178.86 45.00 -79.69 5,971,410.88 502,460.71 End 45 dls,Start 7 dls 7,400.00 93.62 8.35 5,704.36 1,237.76 3,526.78 1,237.76 7.00 -82.00 5,971,469.77 502,471.56 7,410.00 93.71 7.66 5,703.73 1,247.64 3,528.17 1,247.64 7.00 -82.24 5,971,479.65 502,472.95 7,430.00 93.71 9.06 5,702.43 1,267.38 3,531.07 1,267.38 7.00 90.00 5,971,499.39 502,475.86 4 7,500.00 93.69 13.97 5,697.91 1,335.81 3,545.01 1,335.81 7.00 90.09 5,971,567.81 502,489.80 7,530.00 93.67 16.07 5,695.99 1,364.72 3,552.77 1,364.72 7.00 90.41 5,971,596.72 502,497.57 5 7,555.00 93.65 17.83 5,694.39 1,388.59 3,560.04 1,388.59 7.00 90.54 5,971,620.58 502,504.84 7,600.00 92.62 14.85 5,691.93 1,431.70 3,572.68 1,431.70 7.00 -109.00 5,971,663.69 502,517.48 7,615.00 92.28 13.85 5,691.28 1,446.22 3,576.39 1,446.22 7.00 -109.16 5,971,678.20 502,521.20 6 7,640.00 91.70 12.20 5,690.42 1,470.56 3,582.02 1,470.56 7.00 -109.21 5,971,702.54 502,526.83 7,700.00 91.70 16.40 5,688.64 1,528.66 3,596.84 1,528.66 7.00 90.00 5,971,760.63 502,541.65 7,715.00 91.69 17.45 5,688.19 1,543.01 3,601.20 1,543.01 7.00 90.12 5,971,774.98 502,546.02 7 7,730.00 91.69 18.50 5,687.75 1,557.27 3,605.83 1,557.27 7.00 90.16 5,971,789.24 502,550.65 7,800.00 92.11 13.62 5,685.43 1,624.48 3,625.18 1,624.48 7.00 -85.00 5,971,856.44 502,570.00 7,820.00 92.23 12.22 5,684.67 1,643.96 3,629.65 1,643.96 7.00 -85.16 5,971,875.91 502,574.48 8 7,835.00 92.32 11.18 5,684.07 1,658.63 3,632.69 1,658.63 7.00 -85.22 5,971,890.59 502,577.52 7,900.00 90.39 7.05 5,682.54 1,722.78 3,642.97 1,722.78 7.00 -115.00 5,971,954.72 502,587.81 7,925.00 89.65 5.47 5,682.53 1,747.63 3,645.70 1,747.63 7.00 -115.10 5,971,979.57 502,590.54 9 7,940.00 89.20 4.52 5,682.68 1,762.57 3,647.01 1,762.57 7.00 -115.10 5,971,994.51 502,591.85 8,000.00 88.26 0.42 5,684.01 1,822.49 3,649.59 1,822.49 7.00 -103.00 5,972,054.42 502,594.44 8,100.00 86.71 353.59 5,688.41 1,922.19 3,644.38 1,922.19 7.00 -102.91 5,972,154.12 502,589.24 8,200.00 85.21 346.73 5,695.46 2,020.42 3,627.35 2,020.42 7.00 -102.61 5,972,252.33 502,572.23 8,300.00 83.78 339.85 5,705.06 2,115.69 3,598.76 2,115.69 7.00 -102.13 5,972,347.61 502,543.66 Planned TD at 8300.00 3/5/2015 9:33:25AM Page 3 COMPASS 5000.1 Build 61 ConocoPhillips ConocoPhillips (Alaska) Inc. -Ku p2 Kuparuk River Unit Kuparuk 2T Pad 2T-08 2T-08AL1 2T-08AL1_wp05 Travelling Cylinder Report 04 March, 2015 BAKER HUGHES 11.-- Baker Hughes INTEQ FG" ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips(Alaska)Inc.-Kup2 Local Co-ordinate Reference: Well 2T-08 Project: Kuparuk River Unit TVD Reference: 2T-08 @ 117.00usft(2T-08) Reference Site: Kuparuk 2T Pad MD Reference: 2T-08 @ 117.O0usft(2T-08) Site Error: 0.00usft North Reference: True Reference Well: 2T-08 Survey Calculation Method: Minimum Curvature Well Error: 0.Oousft Output errors are at 1.00 sigma Reference Wellbore 2T-O8AL1 Database: OAKEDMP2 Reference Design: 2T-08AL1_wp05 Offset TVD Reference: Offset Datum Reference 2T-08AL1_wp05 Filter type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 7,200.00 to 8,300.O0usft Scan Method: Tray.Cylinder North Results Limited by: Maximum center-center distance of 1,018.30usft Error Surface: Elliptical Conic Survey Tool Program Date 3/4/2015 From To (usft) (usft) Survey(Wellbore) Tool Name Description 200.00 7,100.00 2T-08 ATDB(2T-08) BOSS-GYRO Sperry-Sun BOSS gyro multishot 7,100.00 7,200.00 2T-08A_wp03(2T-08A) MWD MWD-Standard 7,200.00 8,300.00 2T-08AL1_wp05(2T-08AL1) MWD MWD-Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 8,300.00 5,822.06 2 3/8" 2-3/8 3 Summary Reference Offset Centre to No-Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well-Wellbore-Design (usft) (usft) (usft) (usft) Kuparuk 2T Pad 2T 08 2T 08 2T 08 7,218.51 7,225.00 19.83 6.04 14.71 Pass-Major Risk 2T-08-2T-08A-21-08A_wp03 7,200.00 7,200.00 0.00 0.27 -0.22 FAIL-Major Risk CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 3/4/2015 4:50.46PM Page 2 of 5 COMPASS 5000.1 Build 65 • r o NO N W 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PTD: CJS-0S3 /Development _Service _Exploratory _Stratigraphic Test _Non-Conventional FIELD: Il � ,/� h POOL:{J� ��n < d p�i L/e� ) /��\��u Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit / LATERAL No. a 1 S 05)- , API No. 50- 10 3 - O p O -0 I - a b . (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. 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