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• • 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. JS - 051p Well History File Identifier 1 Organizing(done) Two-sided ❑ Rescan Needed RESCAN: OVERSIZED: NOTES: ,(Color Items: ❑ Maps: VV rayscale Items: ogs: ❑ Poor Quality Originals: ❑ Other: ❑ Other: BY: Maria Date: a /s/ ill P Project Proofing BY: W Date: Ilia-7pp/s//s/ Scanning Preparation j x 30 = 30 + a 3 = TOTAL PAGES 53 1 ' ,g,"7// 7 I Ls (Count does not include cover sheet) BY: Date: I /s/ Production Scanning f Stage 1 Page Count from Scanned File: 54 (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: YES NO BY: AM Date: ) // 7 /S. /s/ r14 f) 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 Michel Date: /s/ Final Page Count: Stage 1 + Stage 2: TOTAL PAGES: Scanning is complete at this point unless rescanning is required. 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H I- LO Ca >• CN W n > > o • O. 11:t D Y o Q o p v U Z d • co co � m o I a N 3 N m a• 2 o R U Q C7 t o 0 1111 X2653 7415096 I%%r 26 1 6 4 BAKER PRINT DISTRIBUTION LIST HUGHES Please sign and return one copy of this transmittal form to: COMPANY ConocoPhillips Baker Hughes INTEQ DATA LOGGED (mandatory) 795 East 94th Avenue g/31/201 WELL NAME 2H-14A; 14AL1 Anchorage,Alaska 99515 K BENDER (mandatory) FIELD Kuparuk River Unit to acknowledge receipt of this data. - (mandatory) COUNTY North Slope Borough LOG TYPE LWD-Coil (mandatory) (mandatory) STATE Alaska BH DISTRICT Alaska (mandatory) (mandatory) LOG DATE: July 18,2015 TODAYS DATE: 21-Aug-15 (mandatory) DISTRIBUTION LIST AUTHORIZED BY: Patrick Rider EMAIL: 1trick.rider bakerhughes.co (mandatory) HAS CLIENT BEEN INVOICED FOR ADDITIONAL PRINTS? No COMPANY FIELD FINAL CD Final CD ADDRESS(FEDEX WILL NOT DELIVER TO P.O.BOX) LOGS LOGS (digital/image) Surveys (Final Surveys) PERSON ATTENTION #OF PRINTS #Uh PF(IN I S #OF COPIES #OF COPIES#OF COPIES 4 4 4 4 4 4 4 1 ConocoPhillips Alaska Inc. _ Attn:Ricky Elgaricio IR G J V E 6 ATO 3-344 700 G Street is v'7 26 Anchorage,AK 99510 e� !y- 2 BP Exploration(Alaska)Inc. I 1 ` 0,�j `„c; I 1 'Petrotechnical Data Center,LR2-1 900 E.Benson Blvd. Anchorage,Alaska 99508 Attn:Dodie Stinson .. 3 Chevron/KRU Rep I 1 I I I �- I c I i, Attn:Glenn Frederick �, P.O.Box 196247 . Anchorage,AK 99519 AUG 26 Z U LI 4 State of Alaska -AOGCC 1 I 1 I 2 AGOG 1 :Attn:Makana Bender 1333 W.7th Ave,Suite 100 (Anchorage,Alaska 99501 1 5 DNR-Division of Oil&Gas *** I I I 1 Attn:Sean Clifton 550 West 7th Avenue,Suite 802 Anchorage,Alaska 99501 ***Stamp"confidential"on all material deliver to DNR I TOTALS FOR THIS PAGE: 0 3 4 4 4 0 TOTALS FOR ALL PAGES: 0 3 4 4 4 0 LO CI C) tD c0 y III N MI I `U2 41 m Ct mom c.0 ,INc LCA C) Et C t (123 O o_ as o w W W a i— ,, 0_ L Z s _c (1) 0 a = li o a) co _ V O > a M = .- 0 V •-c2N OC L O Y J N � N 0 = , _ V O a a - r co 0 V Y Y N 10 m O N • I IN I Z 4 4to m LO 7 hi§§ ` _1 inj s 2 N. \ /\ \ Z° CV CV 0 CO CO 2 � ] R R 0) \ o0 ] C 0 t2 ( CV CV CV % - < 3 / \ u CO # O. j Q Q a \ \ \ \ ! \ \ ) { / \ { ( .g :572, ES o � st sr mf \ � ` � £ a 5 ƒ \ \ / § A _ T ] ( \ \ ` V, « \ / k 3 3 A LD O t (o 2 j / / LU & 3f \ Z ƒ 0 $ § _ _co cn - - 0 > ) I / j « 2 a 2 2 © co- CD co d I > k ] \ | | q & - # 2 CD \ u 2 $ _ i CO CO _ ` k 9 E R ) \ To 2 2 a a 111- ; f £ ^ 2 G $ 2 2 a o > » co t .Co - z w & £ COco 0 to t E U) » CO- \ .2 } . liZ — } } U \ 0 § 0 \ -T. cf. \ \ a (N CS k _0 _0 _0Cli .0 <cl- < \ \ { « CO \ \ \ \ ® � « ƒ ) ƒ% & sr } } \ ll iJ co ! § jco , sr 9 @ \ zm \ } VI o � � D z < " � � \ 2 j \ \ ¥ - CL R q Q » < G \ \ \2Q > 0 § al k E \ u .. & @ § . • 2 { m o iti 2 k C / / / ri \ j } § \ \ k / co \ ) k � � \ \ : \ U u 0. 33 0 0. 2 0 2 ■ ■ o ■ o « > > @ • • ...„ 4- IA a W - in a= o m 0 c (/) o (i) m a. o c a O Q i Y U co E as Z O F T N CO M CO M CO CO M M M M 0) M M CO CO M CO CO CO CO CO CO M CO CO CO M CO CO w 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 (O p .O- O Or (N N O 2 M O N 0O ,-O CN O 0) M O M N 00) N V N snN. 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TH L N r0 V N N UO) m � m N N O � N O rts $ 2 8 mNmMN N orn m mmmm $ mro p J i Vco7 M N z,-; V m m O m m m m n m O m { m O co8 N. o o O 0 0 N M U) O rV ` _ O O O N m N N 1 D W n On 8 N (NO N 2 r (? c i N (V c N (V N N N N N N c N N N T Z 3 ( t — m - M CO N a7 (p m 0) r n m N- CO m 0 m M N (M M. V 0) o 1- m N (O rN- f- N N m CO CO r p O NI. O 5.• N O 0 0 O O O O 0 0 0 O 0 0 µ (o us (6 CO CO CO m CO CO CO CO (0 CO CO CO (0 (0 m m O N (� (rh M mV m m2 °,2888 m nn m m o m m. M N O) (0 (p U) O O N N M U) ( co O O N Q g r n r CO m CO CO m m m m CO CO CO m N- N- n n F p U 7 U) (O co- V) co- (O (D co- U) UJ 6 co- (O (o CO U) UJ m m C U) { W 2 •,.., n m m N M m M N N M M h V m m (n 4' `411 fQ r VO U) NN 6 (N c O U) O oi 4 O O N N M 2 N Q — N N N N N M M L n d •Y Y J J Q u2 2 Q Q O co UM UN N . C d a VO N N N N N N O N 0) O u) h 0) Oo O O FOa = III CE"' mmO) mmmmm0) mmmmmmmmmmU Y Y N N N M 0 O mO V m u) m N M N M N- V M0 O u (O V (n CO U) U) CO.. x- CO CO N V N V N m N. U) 0 UU) UUUUO Nj VuUU) Un uNO NO C . W▪ . m N N N O M M Mm 6 V Vm 8 m m^ co .— 0 _ T O O O J O O O O O O O O O O O O 8 O O 0 p `O ,ti U) U) y U U a in S "S o (0 (� 1 • • r' , RECEIVED • STATE OF ALASKA • AUG 18 7015 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND 110G -1a.Well Status: Oil ❑ Gas❑ SPLUG LJ Other ❑ Abandoned ❑ Suspended❑ 1 b.Well Class: 20AAC 25.105 20AAC 25.115 Development ❑ Exploratory ❑ GINJ ❑ WINJ ❑ WAG❑ - WDSPL❑ No.of Completions: Service [7] , Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Susp.,or 14. Permit to Drill Number/ Sundry: ConocoPhillips Alaska, Inc. . Aband.: '7/19/2015 215-096 3.Address: 7. Date Spudded: 15.API Number: P. O. Box 100360 Anchorage,AK 99510 ' 7/17/2015 50-103-20036-60 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 110'FSL,654'FEL, Sec.26,T11N, R8E, UM '7/18/2015 KRU 2H-14AL1 • Top of Productive Interval: 9. KB(ft above MSL): -125' 17. Field/Pool(s): 1291'FSL, 1044'FWL,Sec.35,T11N, R8E, UM GL(ft above MSL): ,30' Kupuruk River Field/Kuparuk River Oil Poo• Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 2454'FNL,824'FWL, Sec. 35,T11N, R8E, UM 10650'MD/6173'TVD ADL 25587 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 497745 y- 5948973 Zone- 4 n •10650'MD!6173'TVD ALK 2673 TPI: x- 494166 y- 5944876 Zone- 4- 12. SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 493945 y- 5946411 Zone- 4 no SSSV 2754'MD/2445'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) +9216'MD/6136'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 30" 110' 30" 110' 24" 172 sx Cold Set II 9.625" 36# J-55 30" 2839' 30" 2497' 12.25" 980 sx AS III,440 sx Class G 7" 26# J-55 29' 8843' 29" 6354' 8.5" 400 sx Class G,250 sx AS I 4.5" 11.6# L-80 8317' 8716' 5970' 6259' 6.125" 23 bbls Class G 2.375" 4.6# L-80 8517' 10650' 6113' 6173' 3" slotted liner 24. Open to production or injection? Yes ❑ No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 3.5" 8232' 8317'MD/5970'TVD, slotted liner from 8517'-10650'MD/6113'-6173'TVD 8239'MD/5914'TVD 26.ACID, FRACTURE, CEMENT SQUEEZE, ETC. I k Was hydraulic fracturing used during completion? Yes❑ No 0 I ,}12 0 Per 20 AAC 25.283(i)(2)attach electronic and printed information l . , DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED `� ////� t none 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 8/7!2015 water injector Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: Test Period Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 24-Hour Rate -0. Form 10-407 Revised 5/2015 V7L 9/Z//.5 CO TINyy��E QUI PAGE 2 RBDMS'ViHUU L J 2015 Submit ORIGINIAL only. X70-7 I `€{3�5X 28.CORE DATA Conventional Core 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 2754' 2445' Attach separate pages to this form, if needed,and submit detailed test information, including reports,per 20 AAC 25.071. Kuparuk A3 9402' 6166' Formation at total depth: Kuparuk A3 " 31. List of Attachments: Summary of Daily Operations,schematic,directional survey Information to be attached includes, but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey, core analysis, paleontological report, production or well test results,per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Jason Burke @ 265-6097 Email: Jason.Burke(a cop.com Printed Name: Dan Ven s Title: CTD Supervising Engineer Signature: i Phone: 263-4372 Date: 8 /7- jS 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 lb: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension, or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Pursuant to 20 AAC 25.071,submit detailed descriptions, core chips, photographs,and all subsequent laboratory analytical results, including, but not limited to:porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including, but not limited to:core analysis,paleontological report,production or well test results. Form 10-407 Revised 5/2015 Submit ORIGINAL Only ! • 11D 1j 11 11 N- 11 2 D 11 2 11 @r` 0 2 i; I-0) Zip b co II ;o© 11 V' O 1' N m 1 m .-"— 41 1, m N H j 11 2 2 2 m 11 II 1.m p 0071 n 1 U). t0 co a co C 2 M C 1( v j m'- 'v m '2 m 11 N E Lo 0 d cl W 7, 2 M hi O N a.N-.7gD t N\ ;..-p m o,D E way 03� v!m C 11 N D D _C 01°3t l0 N D ONO N V U y 1 a 1 Wo a_E m mm o my x m 11 0 m Oros o °mil m 085: S I '.. J c0 U 00N Q 00-- "LI Y N E Z�m ## C La X W m mal U c003,0- o1X (0N in — I, (V N Z N N O) 0) NN N t N fV i .....m-. Y Y Y _ M M M mmm th co m m m V // ii I03 Ii v II II L. 1110 111 -� I e� L,.. I1A ' \ ' �1 p 4a� .:;; .. :.:ism..:.:::..,:.:...:.:;:.:.:.:.:.:.:.:...:.::.:... ,.�'f el -0 u (fj ñ 7 €\c '-_ ♦^ lj ■ . :moi u) n �� 3k. J n r :.. ..�.. ` U ; ..... \./ ,..:: :..L:.`.:t...v)..L.f.Li.'.f:'.`.' :::•'C• .. w.:.:. *` .: ::..: ...:t:.4ri.,Y.}.{:'ii.} .,�..3`... ,11,„ ! 1,,,, 1.1.1 ' I111111 I IIII UO !Hifi OD b v N D o alptrir 0 14 O N N N go ,/(v1 a .0 V-1 N Y D N mp1 N� N N -03 D ,a AO N "9cLc? ;12 4t coN N' NO. ® _� coo m°i N� .Q O�o3 NM N i..0003 #p Int CM 0.N- C N� 0-OD CO" � o 013) T "oco 0 l0.- Q00 'O g N (D� M C1N sig Oa ¢Oo 283 v Q)N rm CJ oD ~ Q� v �„ KUP INJ110 2H-14ALI ConocoPhiHlips OR`t m Well Attributes Max Angle&MD TD Alaska,Inc. Wellbore API/UWI Field Name Wellbore Status Intl(°) MD((IKO) Act Btu,(ftKB) c„,,,,elaDflltlip5 501032003660 KUPARUK RIVER UNIT INJ 101.46 8,875.49 10650.0 ••• Continent H25(ppm) Date Annotation End Date KB-Grd(1t) Rig Release Date 2H-14ALI 8,42015 2'0304 PM SSSV:LOCKED OUT 63 12/30/2012 Last WO: 34.51 7/18/1984 Verticel schenrauc(aclua0 Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag: Rev Reason:ADD SIDETRACK,ADD LATERAL smsmith 8/6/2015 HANGER,23.7- (off sidetrack A) Casing Strings Casing Description OD(In) ID(In) Top(500) Set Depth(ftKB) Set Depth(TVD)...WULen(I...Grade Top Thread ALI LINER 2 318 1.920 8,516,5 10,650.0 6,172.6 4.60 L-80 ST-L r Liner Details Nominal ID Top(ftKB) Top(TVD)(ftKB) Top Incl(°) hem Des I Com (In) .11 } 8,516.5 6.112.8 43 73 DEPLOY J BAKER SHORTY DEPLOYMENT SLEEVE 1 900 V° Perforations&Slots Shot 4 Dons Top(TVD) Bin(TVD) (shots/f Top(ftKB) B[m(ftKB) (ftKB) (ftKB) Zone Oate 1) Type Com 8.517.4 10,649.6 6,113.4 6,172.6 A-3,2H-14 7:18;2015 SLOTS Slotted Liner -_.A-/CONDUCTOR,30.0-1100A A-e' r,"°-°'-‘3--.'" Notes:General&Safety Entl Datc Annotation NOTE: SURFACE;30.1-2,838.5-• • i DEPLOY VLV.3.505.6 4u GAS LIFT,8,154.0 LOCATOR.8.209.7 -[0, SEAL ASSY;8,2107-, i [1 PER:8,215.5 1 1 1 PACKER.8,238.6 au a' 94 I NIPPLE;8,284.0 1oh NB Ii LOCATOR:8,3243 mow SEAL ASSY;8,325.4 1 -11 47;11 ill Q \a IPERF 8.460 0-8 476 0- 'el t �A 1,1 IPERF:8.508.0-8.519.0- Al. ,h tai In.' : LINER-R WE 2015'.8,316.9- 87160 PRODUCTION;28.6-8.842.4 SLOTS;8,517 410.649 0 -. AL1 LINER;8,516.5-10,650.0 2H-14 PRE-RIG WELL WORK • DATE SUMMARY • 5/18/2015 SET& PULLED 2.79" CATCHER @ 8284' RKB. PULLED SOV, SET DV @ 8154' RKB. MIT IA 2500 PSI, GOOD. DRIFTED TBG TO 8497'SLM w/2.63"x 17'WHIPSTOCK DUMMY. TAGGED FILL @ 8505'SLM. READY FOR FCO. 6/7/2015 Perform FCO with 3.80" undereamer in the 4.5" liner down to the Landing Collar @ 8,601' CTMD. Made several up and down passes throughout liner until returns cleaned up. Wellbore filled with seawater and freeze protect diesel. Well now ready for SLB E-Line (whipstock). ***Job in progress*** 6/8/2015 TAGGED TD @ 8605' SLM; DRIFTED DOWN TO 8619' RKB WITH 2 5/8" DUMMY WHIPSTOCK. IN PROGRESS (READY FOR E-LINE WHIPSTOCK). 6/12/2015 SET WHIPSTOCK TOP OF TRAY AT 8530'. WHIPSTOCK ORIENTATION 4.5 DEGREES RIGHT OF HIGH SIDE. 2 RA TAGS LOCATED AT 8537'. BOTTOM OF WS AT 8543'. CORRELATED TO K1 MARKER AT 8351'AND SLB CBL LOG DATED 7/30/84. JEWELRY LOG RUN FROM TD TO 8000'. JOB COMPLETE 6/16/2015 (PRE-CTD) : DDT SV, MV, SSV(PASSED), PT SV, MV,SSV(PASSED). • Conoco Phillips Time Log & Summary IVel!view LVeb Repotting Report Well Name: 2H-14 Rig Name: NABORS CDR2-AC Job Type: DRILLING SIDETRACK Rig Accept: 7/9/2015 12:00:00 AM Rig Release: 7/20/2015 12:00:00 AM Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07/08/2015 24 hr Summary Finished reel swap. Moved rig&shop from 2F-18 to 2H-14. Move over well, rig up equipment. 06:00 10:30 4.50 0 0 MIRU MOVE RURD P MIRU CDR2,trucks on location, rig down subs,move off well, install jeeps,pre-move meeting with personnel 10:30 15:30 5.00 0 MIRU MOVE MOB P Mobilize off 3F-pad.Travel to 2H-14 15:30 20:30 5.00 MIRU MOVE MOB P Arrive on 2H-pad. Pad really soft. Spot up&move over the well. Have to utilize cat to pull out of soft gravel. Have tool house bring out grader to work pad. 20:30 00:00 3.50 MIRU MOVE RURD P Rig spotted in&sat down. Begin rigging up equip. 37/09/2015 Complete initial BOPE test, state witnessed by Chuck Shieve. PT inner reel valve, hardline to tiger tank& PDL's. Install coil connector. 00:00 01:00 1.00 0 0 MIRU WHDBO NUND P Nipple up Stack **Note: Rig accepted at 0:00 hours 01:00 01:30 0.50 0 0 MIRU WHDBO RURD P Continue fill reel with water, prep to start BOP test. Call State for witness. 01:30 13:30 12.00 0 0 MIRU WHDBO BOPE P BOPE test,witnessed by Chuck Shelve. Low test 250 psi, high test 3,500 psi, annular test 2,500 psi. 13:30 14:30 1.00 0 0 MIRU WHDBO RGRP T Change out B4 HCR valve. 14:30 20:30 6.00 0 0 MIRU WHDBO PRTS P Fill coil with seawater,test inner reel iron and packoff, PDL, and tiger tank line. 20:30 22:30 2.00 0 0 MIRU WHDBO MPSP P Cocduct TGSM. RU BPV luicator, pull TWC. Lay down equip. 22:30 00:00 1.50 0 SLOT WELLPF CTOP P Conduct PJSM. Cut a couple feet of coil, pull out eline. MWD test E-line, install coil connector. Pull test&PT. 07/10/2015 Tagged TOWS @ 8530'. Milled window&TD rathole @ 8555. Back reamed window&dry drifted clean. POOH&lay down BHA#1. 00:00 01:00 1.00 0 0 SLOT WELLPF CTOP P Continue installing CTC&Eline termination. 01:00 01:30 0.50 0 0 SLOT WELLPF SFTY P Conduct pre-spud with all on the rig. 01:30 02:00 0.50 0 0 SLOT WELLPF CTOP P Pump 1 coil volume foward. 02:00 03:45 1.75 0 76 PROD1 WHPST PULD P Shut the ordit valve.watch for no flow, good to go. Conduct TGSM for picking up BHA#1. Pick up BHA#1 Stab on. Re-open orbit valve. xao.1taia Time Logs • Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 03:45 06:00 2.25 76 8,365 PROD1 WHPST TRIP P RIH VV/window milling BHA. Inspected saddle clamps and pillow blocks and inner reel iron on newly installed reel at 300'and 1000'. At 1,100'LOTO reel and checked torque on bolts and repositioned chain guard. 06:00 06:15 0.25 8,365 8,398 PROD1 WHPST DLOG P Log K1 for+1.0 ft correction 06:15 07:00 0.75 8,398 8,502 SLOT WHPST CIRC P Displace well over to 9.4 ppg FloPro milling fluid, PUW 28k 07:00 07:15 0.25 8,502 8,532 PROD1 WHPST TRIP P RIH, dry tag TOWS at 8,530', PUW 32k 07:15 11:00 3.75 8,532 8,535 PROD1 WHPST WPST P Mill window, 1.55 bpm @ 3,367 psi FS, BHP 3650 psi,WHP 0, IA 925, OA 40 11:00 16:30 5.50 8,535 8,541 PROD1 WHPST WPST P Continue milling window, at midpoint, bled IA from 1500 psi to 263 psi. 1.55 bpm @ 3,367 psi FS, BHP 3650 psi,WHP 0, IA 779, OA 18 16:30 18:00 1.50 8,541 8,555 PROD1 WHPST WPST P Drill rate hole 1.55 bpm @ 3,367 psi FS, BHP 3665,WHP 0, IA 833, OA 20 18:00 20:00 2.00 8,555 8,555 PROD1 WHPST WPST P Back ream window several times. Dry drifted good, pump 5X5. 20:00 22:00 2.00 8,555 100 PROD1 WHPST TRIP P POOH 22:00 00:00 2.00 100 0 PROD1 WHPST PULD P OOH. Close orbit valve. Bleed well to 0. monitor while conducting pre-job. Lay down window milling BHA. )7/11/2015 Drill build section from 8555'to 8675'. POOH due to BHI tool failure to change BHA. RIH w/new BHA& continue drilling build section from 8675'. Trouble time: BHI 6 hours for tool failure. : Nabors 5.75 hours for shaker motor failure. 00:00 01:00 1.00 0 0 PROD1 WHPST RURD P Change out bails.The set needs to be sent to tubo-scope. 01:00 02:45 1.75 0 72 PROD1 DRILL PULD P Conduct PJSM. Pick-up build BHA. 02:45 04:30 1.75 72 8,360 PROD1 DRILL TRIP P RIH W/build BHA 04:30 05:00 0.50 8,360 8,400 PROD1 DRILL DLOG P Tie into K-1. Counter was 40' off. Clean up counter wheel&re-try.Tie in for a-12.5'coreection. 05:00 05:15 0.25 8,400 8,555 PROD1 DRILL TRIP P RIH, PUW 30k 05:15 08:00 2.75 8,555 8,670 PROD1 DRILL DRLG P Drill build section as per plan. 1.50 bpm @ 3,505 psi FS, BHP 3,847, WHP 100, IA 740, OA 20. 08:00 08:15 0.25 8,670 8,360 PROD1 DRILL TRIP P PUH to log K1 and RA marker 08:15 08:30 0.25 8,360 8,570 PROD1 DRILL DLOG P Log K1 for no correction and log RA marker. RA marker at 8,536.5' 08:30 08:45 0.25 8,570 8,670 PROD1 DRILL TRIP P RIH 08:45 09:00 0.25 8,670 8,675 PROD1 DRILL DRLG P Drill build section as per plan. 1.50 bpm @ 3485 psi FS, BHP 3838, WHP 100, IA 720, OA 20 Page 2 of 8 • • Time Logs • • Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 09:00 11:00 2.00 8,675 72 PROD1 DRILL TRIP T POOH due to tool failure/failed DGS -magnetic section of directional package. Close Baker orbit valve, and conduct no flow check. 11:00 11:45 0.75 72 0 PROD1 DRILL PULD T L/D BHA#2 11:45 12:45 1.00 0 72 PROD1 DRILL PULD T MU BHA#3, surface test, and open Baker orbit valve. 12:45 14:45 2.00 72 8,360 PROD1 DRILL TRIP T RIH with BHA#3 14:45 15:00 0.25 8,360 8,383 PROD1 DRILL DLOG T Log K1 and tie in for a-7.5 ft correction **Note: BHI downtime ended, total downtime 6 hours 15:00 20:45 5.75 8,383 8,383 PROD1 DRILL TRIP T Shale shaker motor failure. Motor coming from Prudhoe **Note: Nabors downtime total of 5.75 hours 20:45 21:00 0.25 8,383 8,675 PROD1 DRILL TRIP P Shaker fixed. Pumps up. RIH 21:00 00:00 3.00 8,675 8,768 PROD1 DRILL DRLG P 1.41 BPM @ 3325 psi FS. Drill ahead 1.41 BPM @ 3446 psi, BHP 3831, ROP 40. ECD 12.13 07/12/2015 TD build section @ 8815'. Drilled ahead from 8815'to 9576'. 00:00 01:30 1.50 8,768 8,815 PROD1 DRILL DRLG P @ 8768', continue drilling ahead 1.40 BPM @ 3396 psi, ROP of 37.TD build @ 8815'. 01:30 03:00 1.50 8,815 72 PROD1 DRILL TRIP P POOH to surface. 03:00 05:00 2.00 72 0 PROD1 DRILL PULD P Tag up, pumps off. 560 psi on well head&falling. Close orbit valve. Bleed off well head from 297 psi to 0 psi. Conduct pre-job. Lay down build BHA. 05:00 05:30 0.50 0 72 PROD1 DRILL PULD P Conduct PJSM. Pick-up BHA#4 05:30 07:30 2.00 72 8,360 PROD1 DRILL TRIP P RIH,with Lateral Drilling BHA,open EDC, pumping min rate. 07:30 07:45 0.25 8,360 8,360 PROD1 DRILL DLOG P Tie into the K1 correction of minus 7.0'. 07:45 08:00 0.25 8,360 8,815 PROD1 DRILL TRIP P Continue RIH to bottom. 08:00 13:30 5.50 8,815 9,111 PROD1 DRILL DRLG P BOBD 1.46 bpm at 3606 psi, BHP 3867,WHP 64, IA 684, OA 14 13:30 13:45 0.25 9,111 8,581 PROD1 DRILL WPRT P Wiper trip, PUW34k 13:45 14:00 0.25 8,581 9,111 PROD1 DRILL WPRT P RBIH 14:00 18:30 4.50 9,111 9,266 PROD1 DRILL DRLG P BOBD 1.38 bpm at 3480 psi, BHP 3808,WHP 25, IA 880, OA 20 18:30 20:30 2.00 9,266 9,415 PROD1 DRILL DRLG P Start mud swap 9.1 ppg, Continue drilling ahead. Get mud all around, 1.50 bpm @ 3339 psi/3834 BHP. Holding choke pressure now, 350 WHP. 20:30 21:15 0.75 9,415 9,415 PROD1 DRILL WPRT P Wiper, 30k off btm. Page 3 of 8 Time Logs • • Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 21:15 00:00 2.75 9,415 9,576 PROD1 DRILL DRLG P @ 9415, Drill ahead 1.50 BPM @ 3358 psi, 3854 BHP 37/13/2015 Drill ahead in A lateral from 9676'to 10372' 00:00 02:15 2.25 9,576 9,715 PROD1 DRILL DRLG P Continue drilling ahead to 9715' 02:15 03:15 1.00 9,715 9,715 PROD1 DRILL WPRT P Tie in wiper,28k off btm.Tie in for a +4.5'correction. RIH to bottom. 03:15 10:00 6.75 9,715 9,997 PROD1 DRILL DRLG P Drill ahead 1.50 BPM @ 3550 psi 3873 BHP 10:00 10:15 0.25 9,997 8,900 PROD1 DRILL WPRT P Wiper trip PUW 29.5k 10:15 10:45 0.50 8,900 9,997 PROD1 DRILL WPRT P RIH,wiper trip clean 10:45 16:15 5.50 9,997 10,162 PROD1 DRILL DRLG P BOBD 1.60 bpm @ 3800 psi FS, BHP 3910 psi,WHP 180, IA 933, OA 22. Bled IA to 540 psi 16:15 16:45 0.50 10,162 9,200 PROD1 DRILL WPRT P Wiper trip PUW 30k, early wiper trip due to low ROP and surface weight 16:45 17:15 0.50 9,200 10,162 PROD1 DRILL WPRT P RIH,wiper trip clean. Pump 10 x10 sweep 17:15 22:00 4.75 10,162 10,360 PROD1 DRILL DRLG P BOBD 1.55 bpm 3,700 psi FS, BHP 3875,WHP 200, IA 520, OA 22 22:00 23:40 1.67 10,360 10,360 PROD1 DRILL WPRT P Decision made to do a 200'wiper. Wiper trip(tie in),26k off BTM,Tie in for a+2.5'correction. RBIH 23:40 23:59 0.33 10,360 10,372 PROD1 DRILL DRLG P Back on BTM, drill ahead 1.45 BPM @ 3522 psi,3906 BHP 37 ROP, 12.25 ECD 07/14/2015 Drill Ahead A Lateral 10372 to 11052 00:00 04:00 4.00 10,372 10,560 PROD1 DRILL DRLG P Continue drilling ahead. 1.43 BPM @ 3619 psi, ROP 42, 3921 BHP 04:00 05:00 1.00 10,560 10,560 PROD1 DRILL WPRT P Wiper,26k off btm 05:00 09:15 4.25 10,560 10,805 PROD1 DRILL DRLG P BOBD 1.50 bpm 3400 psi FS, BHP 3935 psi,WHP 225 09:15 09:45 0.50 10,805 9,529 PROD1 DRILL WPRT P Wiper trip, PUW27k 09:45 10:15 0.50 9,529 10,805 PROD1 DRILL WPRT P RBIH, perform mud swap, new mud at bit 10,805' 10:15 16:21 6.10 10,805 10,908 PROD1 DRILL DRLG P BOBD 1.47 bpm 3350 psi FS, BHP 3915,WHP 315, IA 550, OA 22 16:21 16:39 0.30 10,908 10,908 PROD1 DRILL WPRT P Stacking, Hard to get drilling, Pull wiper to 10695, PUW=31.5k 16:39 18:15 1.60 10,908 10,912 PROD1 DRILL DRLG P 10908', Drill, 1.4 BPM @ 3315 PSI FS, BHP=4000 18:15 20:09 1.90 10,912 10,912 PROD1 DRILL WPRT P 10912', Drill,Wiper to window with tie in. +3.5'correction, PUW=27K 20:09 23:27 3.30 10,912 11,052 PROD1 DRILL DRLG P 10912', Drill, 1.4 BPM @ 3315 PSI FS, BHP=3950 23:27 00:00 0.55 11,052 10,226 PROD1 DRILL WPRT P 11052', Running low on push,-8K, Pull wiper to 9500', PUW=27K 37/15/2015 Drilled A lateral to TD @ 11478. Pumped sweeps. Tie in for+2.5'. RIH and confirm TD @ 11478. Pump beaded liner pill. Trip out for liner 00:00 00:18 0.30 10,226 11,052 PROD1 DRILL WPRT P Continue wiper from 11052 00:18 03:36 3.30 11,052 11,164 PROD1 DRILL DRLG P 11052', Driull, 1.41 BPM @ 3425 PSI FS, BHP=3970 Page 4 of 8 Time Logs • • Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 03:36 03:54 0.30 11,164 11,164 PROD1 DRILL WPRT P 11164 Wiper to 10730. Low surface weight, PUW=36K 03:54 15:45 11.85 11,164 11,306 PROD1 DRILL DRLG P 11164', Drill, 1.39 BPM @ 3425PS1 FS, BHP=3945, Low surface weight with poor transfer to bit. Problems getting it to drill, RIW=6K 15:45 16:51 1.10 11,306 8,555 PROD1 DRILL WPRT P Wiper trip, PUW 28K 16:51 17:00 0.15 8,555 8,575 PROD1 DRILL DLOG P Tie in at RA tag for a+2.0 ft correction 17:00 17:54 0.90 8,575 11,306 PROD1 DRILL WPRT P RIH 17:54 18:54 1.00 11,306 11,375 PROD1 DRILL DRLG P 11306', Drill, 1.42 BPM @ 3490 PSI FS, BHP=4005, RIW=-2K with 2.1K DHWOB 18:54 19:06 0.20 11,375 11,375 PROD1 DRILL WPRT P BHA wiper, stacked out, PUW=30K 19:06 21:24 2.30 11,375 11,478 PROD1 DRILL DRLG P 11375', Drill, 1.39 BPM @ 3450 PSI FS, BHP=4025 21:24 22:12 0.80 11,478 11,478 PROD1 DRILL WPRT P BHA Wiper,work pipe cann't make hole. Pump sweeps while attempting to drill, Call TD 11478'when sweeps reach BHA 22:12 00:00 1.80 11,478 10,328 PROD1 DRILL WPRT P 11478', Call TD,Chase sweeps to window and tie in for+2.5'correction, RBIH 07/16/2015 M/U and run A Liner, 11478 to 9218'with anchored liner top billet 00:00 00:30 0.50 10,328 11,478 PROD1 DRILL WPRT P Tag TD @ 11478 00:30 04:42 4.20 11,478 86 PROD1 DRILL TRIP P Trip out laying in beaded liner running pill, Paint EOP flags at 9100', & 6100'. Reduce speed pulling out due to hot pillow block bearing on reel, >200°. 04:42 06:24 1.70 86 0 PROD1 DRILL PULD P At surface, Close Orbit valve and flow check well for 5 Min. PJSM, Unstab and lay down BHA#4 06:24 09:45 3.35 0 2,263 COMPZ CASING PUTB P PJSM, Pick up A lateral liner assembly, 73 joints of 2 3/8'slotted liner with shorty deployment sleeve 09:45 10:45 1.00 2,263 2,263 COMPZ CASING PULD P MU BHA#5 to A lateral liner, surface test,and open orbit valve 10:45 13:30 2.75 2,263 11,478 COMPZ CASING RUNL P RIH with A lateral liner assembly to EOP flag at 6,100',-12.87 ft. correction, continue to RIH PUW 28.5K 13:30 14:00 0.50 11,478 8,335 COMPZ CASING TRIP P Release from liner, reset counters, and POOH, PUW prior to liner release 32.2K, PUW post liner release 25.6K, 14:00 14:15 0.25 8,335 8,363 COMPZ CASING DLOG P Log GR tie-in for a+7.5 ft. correction 14:15 15:30 1.25 8,363 44 COMPZ CASING TRIP P POOH, paint EOP flag at 8,300' 15:30 16:18 0.80 44 44 COMPZ CASING OWFF T Function orbit valve closed with WHP 706 psi. Monitor well for no flow, Flow check doesn't look good, Function valve open WHP 606 psi. 16:18 17:06 0.80 44 3,483 COMPZ CASING TRIP T RBIH to flush orbit valve __m_ _ Page 5 of 8 Time Logs • • Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07/16/2015 24hrSummary M/U and run A Liner, 11478 to 9218'with anchored liner top billet 17:06 17:36 0.50 3,483 3,529 COMPZ CASING CIRC T Circ flush accross orbit valve Pick up above valve 17:36 18:18 0.70 3,529 3,447 COMPZ CASING OWFF T Close orbit valve and monitor-looks good 18:18 19:06 0.80 3,447 55 COMPZ CASING TRIP T Trip out keeping hole full 19:06 19:42 0.60 55 55 COMPZ CASING OWFF P At surface, PJSM, Flow check well 19:42 20:00 0.30 55 0 COMPZ CASING PULD P Break off injector and lay down BHA #5 20:00 20:24 0.40 0 0 COMPZ CASING BOPE P Perform Bi weekly BOPE function test 20:24 21:36 1.20 0 103 COMPZ CASING PULD P Make up BHA#6, Ported bullnose, 1 Jt slotted liner, OH anchor, aluminum billet. M/U to coiltrack and surface test tool. EDC Open, Pressure up well and open Orbit valve 21:36 23:24 1.80 103 8,400 COMPZ CASING TRIP P RIH, EDC open, Pumping min rate 23:24 23:42 0.30 8,400 8,424 COMPZ CASING DLOG P Tie into K1 for-9.5'correction, PUW=27K, Close EDC 23:42 00:00 0.30 8,424 8,651 COMPZ CASING TRIP P Continue in hole, No pumping.verify depth running past RA marker. No correction 37/17/2015 Set anchored billet @ 9258, TOB=9217, Kick off and drill build/turn to 9475, Drill lateral to 9775' 00:00 00:18 0.30 8,651 9,258 COMPZ CASING TRIP P Continue in hole, set down on liner lower segment @ 9258 00:18 02:06 1.80 9,258 65 COMPZ CASING TRIP P Orient to 150R pumps on see tool shift @ 4800 PSI, Set down 3K. Trip out of hole, Slow down accross orbit valve to flush.TOLTB @ 9217' 02:06 02:36 0.50 65 65 COMPZ CASING OWFF P At surface, Close orbit valve. monitor for flow, PJSM 02:36 03:06 0.50 65 0 COMPZ CASING PULD P Unstab injector, Lay down BHA#6 03:06 04:00 0.90 0 72 PROD2 STK PULD P P/U BHA#7, Build section BHA with 1.2°motor and RR HYC Bi-center, Make up injector and surface test. Pressure up well and open orbit valve. 04:00 05:30 1.50 72 8,370 PROD2 STK TRIP P RIH, EDC closed 05:30 05:45 0.25 8,370 8,389 PROD2 STK DLOG P Tie in to K1 for a-10.0'correction 05:45 06:30 0.75 8,389 9,217 PROD2 STK TRIP P RIH and dry tag billet at 9,217' 06:30 08:15 1.75 9,217 9,218 PROD2 STK KOST P Time drill off billet, 1.45 bpm 3440 psi FS, BHP 3805,WHP 150, IA 220, OA 14 08:15 09:30 1.25 9,218 9,260 PROD2 DRILL DRLG P Drilling formation, 1.45 bpm 3440 psi FS, BHP 3810,WHP 150, IA 225, OA 14 09:30 09:45 0.25 9,260 9,260 PROD2 DRILL TRIP P Dry drift billet,dry drift clean, PUW 27.5K 09:45 13:00 3.25 9,260 9,475 PROD2 DRILL DRLG P BOBD 1.45 bpm 3450 psi FS, BHP 3860,WHP 170, IA 280, OA 15 13:00 13:30 0.50 9,475 8,494 PROD2 DRILL TRIP P 9475 ft, land build section, POOH Page 6 of 8 Time Logs • • Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 13:30 15:00 1.50 8,494 700 PROD2 DRILL TRIP P Open EDC, Continue POOH,flush orbit valve with jog. 15:00 16:00 1.00 700 72 PROD2 DRILL TRIP P At 700'a slug of aluminum plug choked,the orbit valve was cycled closed, blew down choke. Jog in hole to 1,000',to clean hole and choke of aluminum, POOH to surface. 16:00 16:15 0.25 72 72 PROD2 DRILL TRIP P PJSM and monitor well for no flow check 16:15 17:15 1.00 72 0 PROD2 DRILL PULD P LD build section BHA 17:15 17:45 0.50 0 72 PROD2 DRILL PULD P M/U BHA#8 with.6°motor and new Hycalog bit, M/U to coil and surface test. Pressure up well and open orbit valve 17:45 19:21 1.60 72 8,370 PROD2 DRILL TRIP P Trip in hole 19:21 19:27 0.10 8,370 8,392 PROD2 DRILL DLOG P Log K1 for-8.5'correction, PUW=24K 19:27 20:09 0.70 8,392 9,476 PROD2 DRILL TRIP P Continue in hole, Clean pass through window and billet 20:09 23:51 3.70 9,476 9,775 PROD2 DRILL DRLG P 9476', Drill, 1.47 BPM @ 3570 PSI FS, BHP=3830 23:51 00:00 0.15 9,775 9,775 PROD2 DRILL WPRT P 9775',Wiper trip to 8770', PUW=29K 07/18/2015 TD AU lateral, Condition hole. M/U completion, Non ported bullnose,69 Jts slotted liner 00:00 00:54 0.90 9,775 9,775 PROD2 DRILL WPRT P Continue wiper trip from 9775 to 8770' 00:54 04:30 3.60 9,775 10,075 PROD2 DRILL DRLG P 9775', Drill, 1.44 BPM @ 3450 PSI FS, BHP=3850 04:30 05:15 0.75 10,075 10,075 PROD2 DRILL WPRT P Wiper trip to 9,225', PUW=27K 05:15 08:30 3.25 10,075 10,375 PROD2 DRILL DRLG P BOBD, 1.45 bpm @ 3500 PSI FS, BHP 3880 08:30 09:15 0.75 10,375 8,560 PROD2 DRILL WPRT P Wiper trip, PUW 30K 09:15 09:30 0.25 8,560 8,575 PROD2 DRILL DLOG P Log RA fora+4.0'correction 09:30 10:00 0.50 8,575 10,375 PROD2 DRILL WPRT P RIH 10:00 13:15 3.25 10,375 10,650 PROD2 DRILL DRLG P BOBD, 1.50 @ 3550 psi FS, BHP 3830,WHP 160, IA 550, OA 20 Perform mud swap, new mud at the bit @ 10,403' "*Note: System 2 1,832'Drilled, 0.85% DS,33K LSRV 13:15 14:30 1.25 10,650 8,555 PROD2 DRILL WPRT P Pumped 10 x 10 sweeps and chase to the window 14:30 14:45 0.25 8,555 8,575 PROD2 DRILL DLOG P Log RA for+ 1.0 ft.correction 14:45 15:30 0.75 8,575 10,650 PROD2 DRILL WPRT P RIH to confirm TD @ 10,650' ° 15:30 20:00 4.50 10,650 63 PROD2 DRILL TRIP P Lay in beaded liner running pill while POOH, Paint EOP flag @ 6300' 20:00 20:24 0.40 63 0 PROD2 DRILL PULD P At surface,close orbit valve, Good flow check lay down BHA#8 20:24 20:48 0.40 0 0 COMPZ CASING PUTB P PJSM, R/U floor to run liner, PJSM to run liner Page 7 of 8 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 20:48 23:36 2.80 0 2,133 COMPZ CASING PUTB P P/U BHA#9 with non ported bullnose, 69 jts sloted liner,shorty deployment sleeve. Perform BOP drill at joint 11 in hole. 3:30Min. 23:36 00:00 0.40 2,133 2,178 COMPZ CASING PULD P PJSM, P/U Coil track, M/U to liner and stab on injector 07/19/2015 Run AL1 completion 10650 to 8516, Roll well to seawater. Freeze protect to 2500'. Set BPV. Leave orbit valve open, RDMO 00:00 00:30 0.50 2,178 2,177 COMPZ CASING PULD P Surface test tool, Open deployment rams, Pressure up well, open orbit valve 00:30 02:18 1.80 2,177 8,492 COMPZ CASING TRIP P RIH BHA#9, EDC closed 02:18 02:24 0.10 8,492 8,477 COMPZ CASING DLOG P Correct and 6300'EOP flag for-14.5', PUW=26K 02:24 03:00 0.60 8,477 10,470 COMPZ CASING TRIP P Continue in hole,clean trip past window and billet 03:00 03:06 0.10 10,470 10,488 COMPZ CASING DLOG P Log K1 for+4.5'correction 03:06 03:18 0.20 10,488 8,516 COMPZ CASING TRIP P Continue in hole, Tag bottom at 10650'. PUW=29K, Pumps on 1.5 BPM @ 3720, PUW=24K, Liner released, BOL=10650, TOL=8516, PUH and reset counters. 03:18 06:27 3.15 8,516 32 COMPZ CASING DISP P POOH while displacing well to seawater, function close orbit valve, flow check and freeze protect from 2,500' 06:27 06:57 0.50 32 0 COMPZ CASING PULD P LD liner running assebly BHA#9 06:57 11:15 4.30 0 0 DEMOB WHDBO RURD P Flush and blow down coil, pin injector,chain CT reel, and follow rig move check list. 11:15 13:00 1.75 0 0 DEMOB WHDBO MPSP P RU FMC lubricator, pressure test, set BPV, and RD FMC lubricator 13:00 14:00 1.00 0 0 DEMOB WHDBO RURD P Blow down surface lines, bleed koomey, and disconnect putz 14:00 15:00 1.00 0 0 DEMOB WHDBO NUND P Nipple down BOPE and check tree bolts. Did not find any loose tree bolts. FTP=863 psi 15:00 00:00 9.00 0 0 DEMOB WHDBO RURD P Continue RDMO CDR2 to 30-08 **Note: Rig released at 0:00 hours Page 8 of 8 • • amp W �_ o wo 04_ m N 0- I Ci C s. r O 0- CO 0 CD W OC a >, tf)a 0 z > U � a = •> O > _ •— O V E N _ O .wto C OYY : N N c O O 2 2 4 . N U 0 a a r (l3 W 0 Y Y N 10 m -- N • • 1110 iii � c. IV WNL "' so M 14u1 tea � o : A o 0 Co F- i-...- (15 . > ❑ N N Co d - y w h I� E IQ LLO v 1414,', U o Os iOO df71 O O O a Z N cN NNn rt > I i 01 J i a ' c 3 a0 0 0 CO co J 0 U ' C) ° a, Q ..... O CO0. Iii V V N N 44 O d O co 3 7 O O O > E tri tri > N CV Cg ( a F- E 0• .- oo 0 - o o) mm' h > N N FC Q i N• U i (� 1 9 (n U, J ca,, U = = U N > > U 3 0 t U a >� O O O I. W Nr Q y (n > 01CI s i W 1.;-,- -v, _ N > w y a 2 D D rn v o. oo N c ° Lci CI a Ce C m V N ZA .. ❑ ° N C Al V l0 N 2 > a c c°i m c'� ( m c 0 L +.. o w ` w o ui E a Cl.. (0 0❑ A EY 2 r m y • c (n g (0 >> 0 2 m J F. 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N V 0 U v a in o co �+ — ,-- — RECEIVED • JUL 27 Z015 Letter of Transmittal Nag AOGCC BAKER Date: DATA LOGGED July 24, 2015 M BgENDER HUGHES To: From: Makana Bender Yosha Ragbirsingh/Michael Soper AOGCC Baker Hughes INTEQ 333 West 7th Ave, Suite 100 795 East 94th Avenue Anchorage, Alaska 99501 Anchorage, Alaska 99515 Please find enclosed the directional survey data for the following well(s): 3F-18APB1 1 5 ci 6 9 2 6 0 7 3 3F-18A 21 508 26 072 3F-18AL1 21 5090 26 074 3F-18AL2 21 5091 26 075 2H-14A 21 5094 26 076 Q2H-14AL1 21 5096 26 077 (6) 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. Michael Soper, Baker Hughes, Project Engineer Michael.Soper@BakerHughes.com Yosha Ragbirsingh, Baker Hughes, Survey Manager Yosha.Ragbirsingh@BakerHughes.com 0 0 i _. vCo 9 _ � _ " CD0 o r1 N CD Nrx- x- o z o . 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V OD a) (n N W 0 W a) m co W W m A J CO (p n CD A A O _ a v n m N A C - < I cra O 0 GD a : a Z N U N N N (P CP N N N N (n a) (n ((pn (yn ((pn N Nc. o, Z 0 O m .OA1 W m W W O) O1 T N _(Ai) _(Ai) _(AT p S 0 g < cp A W W (J IJ 8 IJ IV 8 (n -� O O O O O (D (D aJ a M W ), `G U) O O ,(AO 8 ,0D O N W A A W N (Wn W c, O N W CO }p 4 S • A (n O W 'co A O •Co -+ •0 (n •OD W W CD0) CO N O - O 4 1 ��[ O 3 Z J (n CO O N V m A 0 N W J W Ut A CO d) L2 (') Cl) A 4,P(E ,.......11,:,:'-.--_;_F-75-4---z4,1,,,,5 m . „,-ft - A AA A A A A A (AD (A A A AD AD AD xprt) C g f; C H,-17.3-,V-7-IES-,,,,,,,,,Ci.rA VA)W V)W WA W w WWmWmmWWWW W W w a ` O �- �W i0 i0 -co m 0m ID aD co m m co W J J JV J D 0 N2 2 (N A N co O O 8 m m N O V J NNN N m AO -+ 3AA NOOa) N •N -' OW OV O Nd N VN n0N(n O• UV (An �� //��O 0 N D W 3 (2 I6 o N 0; 0, 0 : O O (O O) (O (O 0 W O (p N a) (O 0D O co J C : N O O O W O -- -. N W V1 N O 0 N 0 O C C ii, `. M N N_ - -NN N N NN W W W ,., N N N NN NN O wCiA.. 4>NN� NOVWmV(O A(p OWW WNN 1 D N n O N CO O CO CO J A OD jN if: n OD N (O D 0aW A OD Aw AO > 0W wW AQu04. T coO d) A coce,O O co V e •-DK 3 3 3 gKg 3 3 3 3 3 3 KZ 3 3 co o 0 0 v d o o v o v o m W W W co co co co W w c.) 40 w co co W W cum p O S Z O 3 m w (. IiiiI - co Pi , OF Thp s THE STATE • • Alaska Oil and Gas p1 Conservation Commission l`•le =�=- -_ y_= 333 West Seventh Avenue _ � GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 oFALASY*e Q' Fax: 907.276.7542 www.aogcc.alaska.gov D. Venhaus CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2H-14AL1 ConocoPhillips Alaska, Inc. Permit No: 215-096 Surface Location: 110' FSL, 654' FEL, SEC. 26, T11N, RO8E, UM Bottomhole Location: 2475' FSL, 651' FWL, SEC. 35, T11N, RO8E, UM Dear Mr. Venhaus: Enclosed is the approved application for permit to redrill the above referenced service well. The permit is for a new wellbore segment of existing well Permit No. 215-094, API No. 50-103- 20036-01-00. 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, Z/1 Daniel T. Seamount, Jr. r � Commissioner DATED this 1 v day of June, 2015. • F . • STATE OF ALASKA JUN 0 5 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION b�,��,6 PERMIT TO DRILL AOG CC ( 20 AAC 25.005 1 a.Type of Work: 1 b.Proposed Well Class: Development-Oil ❑ Service-Winj ❑ Single Zone ❑✓ . 1c.Specify if well is proposed for: Drill ❑ . Lateral Q Stratigraphic Test❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone❑ Coalbed Gas ❑ Gas Hydrates❑ Redrill ❑ Reentry❑ Exploratory ❑ Service-WAG 0' Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: a Blanket Li Single Well 11.Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59-52-180 ' KRU 2H-14AL1 P 3.Address: 6.Proposed Depth: 12. Field/Pool(s): P.O.Box 100360 Anchorage,AK 99510-0360 MD: 10300' ' TVD: 6060' • Kuparuk River Field , 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Surface: 110'FSL,654'FEL,Sec.26,T11N, RO8E, UM- ADL 25587, Kuparuk River Oil Pool Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1287'FSL, 1041'FWL,Sec.35,T11N, RO8E,UM 2673 7/1/2015 Total Depth: 9.Acres in Property: 14.Distance to 2475'FSL,651'FWL,Sec.35,T11N,RO8E, UM • 2560 • Nearest Property: 17394 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: , 125 feet 15.Distance to Nearest Well Open Surface:x- 497745 y- 5948973 Zone- 4 , GL Elevation above MSL: .30 feet to Same Pool: 2H-13,1360 16.Deviated wells: Kickoff depth: -8950 ft. 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: , 93° deg Downhole:3835 psig• Surface:3219 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 1775' 8525' 5998' 10300' 6060' 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 ND(ft): Junk(measured) 8873 6377 none 8716 6354 none Casing Length Size Cement Volume MD TVD Conductor/Structural 80' 16" 172 sx CS II 110' 110' Surface 2809' 9.625" 980 sx AS III,440 sx CI G 2839 2497' Production 8814' 7" 400 sx CI G,250 sx AS I 8842' 6354' Scab Liner 340' 4.5" none 8716' 6259' Perforation Depth MD(ft): Perforation Depth TVD(ft): perfs cemented off perfs cemented off 20.Attachments: Property Plat❑ BOP Sketch❑ Drilling Prograrr Q Time v.Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch❑ Seabed Report El 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 Ja e @ 265-6097 Email Jason.Burkeacop.com Printed Name . Venhaus Title CTD Engineering Supervisor Signature /PI— - Phone:263-4372 Date —5-/5 Commission Use Only Permit to Drill^ API Number: Permit Approval( //��(i, See cover letter Number: p2'V 09 (_ 50- '133+ Q 0036—60— CAI Date: l p f(V' i5 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: Other: 8 pyo ft f fo 35 U S 1 leis rrq'd: Yes 2 No J Mud log req'd: Yes❑ No EK/ trh 0 yv/a rP re re PI le 1---t1-sI'-Z 2S geasures: Yes No LI Directional svy req'd: Yes ✓� No❑ Spacing exception req'd: Yes ❑ No I Inclination-only svy req'd: Yes❑ No[� / APPROVED BY THE l 2 )0' Approved by: COMMISSIONER COMMISSION Date: (` Y Form 10-401 (Revised 10/2012) D ririz�is}(r ilia Arm the date of approval(20 AAC 5�f G Ails- a • • ConocoPhillips Alaska P.O.BOX 100360 ANCHORAGE,ALASKA 99510-0360 June 4,2015,2015 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 2H-14 using the coiled tubing drilling rig, Nabors CDR2-AC. CTD operations are scheduled to begin in July 2015. The objective will be to drill laterals KRU 2H-14A and 2H-14AL1 targeting the Kuparuk A-sand. The original perforations have been cemented off and the wells current status is listed as suspended(as per sundry#314-604). An application to abandon the KRU 2H-14 will be included. Attached to this application are the following documents:. — 10-401 Applications for 2H-14A&2H-14AL1 — Detailed Summary of Operations — Directional Plans for 2H-14A&2H-14AL1 — Proposed CTD Schematic — 10-403 Sundry Application to Abandon KRU 2H-14(184-195) If you have any questions or require additional information please contact me at 907-265-6097. Sincerely, 4111 Jason Burke ConocoPhillips Alaska Coiled Tubing Drilling Engineer • • $ALA�XA Kuparuk `f HAQpF Laterals iAL 2H-1 L1 I); Can° 'lipt Application for Permit to Drill Document 4.AC 1. Well Name and Classification 2 (Requirements of 20 AAC 25.005(f)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 4 (Requirements of 20 AAC 25.005(c)(13)) 4 Summary of Operations 4 Pressure Deployment of BHA 5 Liner Running 6 14. Disposal of Drilling Mud and Cuttings 6 (Requirements of 20 AAC 25.005(c)(14)) 6 15. Directional Plans for Intentionally Deviated Wells 6 (Requirements of 20 AAC 25.050(b)) 6 16. Quarter Mile Injection Review (for injection wells only) 7 (Requirements of 20 AAC 25.402) 7 17. Attachments 7 Attachment 1: Directional Plans for 2H-14A&ALA 7 Attachment 2: Current Well Schematic for 2H-14 7 Attachment 3: Proposed Well Schematic for 2H-14A&AL1 7 Page 1 of 7 6/3/2015 • S PTD Application: 2H-14A & AL1 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 2H-14A&AL1. Laterals will be classified as "Service—WAG Injection"well. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) This lateral will target the A3&A4 sand packages in the Kuparuk reservoir. See the attached 10-401 form for surface and subsurface coordinates of the 2H-14A&AL1. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005(c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR2-AC. BOP equipment is as required per 20 AAC 25.036, for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3500 psi. Using the maximum formation pressure in the area of 3835 psi in the 2H-13, the maximum potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 3219 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 2H-14 in December 2014 indicated a reservoir pressure of 3715 psi or 11.6 ppg equivalent mud weight. The maximum down hole pressure in the 2H-14 pattern is at 2H-13 with 3835 psi. It is not expected that reservoir pressure as high as 2H-13 will be encountered while drilling the 2H-14A & AL1 because we are staying 960 ft from the well. Using the 2H-13 pressure as the maximum possible, the maximum possible surface pressure, assuming a gas gradient of 0.1 psi/ft,would be 3219 psi. Potential Gas Zones (Requirements of 20 AAC 25.005(c)(4)(b)) No specific gas zones will be drilled; gas injection has been performed on the 2H pad, so cuttings will be monitored for entrained gas. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005(c)(4)(c)) The largest, expected risk of hole problems in the 2H-14 laterals will be the possibility of a high pressure differential when we cross a N-S fault, drilling from an 11.6 ppg block into possibly a 8.3 ppg block. Managed pressure drilling will be used to reduce this risk. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) N/A for this thru-tubing drilling operation. According to 20 AAC 25.030(f), thru-tubing drilling operations need not perform additional formation integrity tests. Page 2 of 7 6/3/2015 S • PTD Application: 2H-14A &AL1 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 2%", 4.7#, L 80, ST-L slotted liner; 2H-14A 8950' 11400' 6027' 6005' with an aluminum billet on top. 2%", 4.7#, L 80, ST-L slotted liner; 2H-14AL1 8525' 10300' 5998' 6060' with a shorty deployment sleeve. Existing Casing/Liner Information Category OD Weight Grade Conn. Top MD Btm Top Btm Burst Collapse (ppf) MD TVD TVD psi psi Conductor 16" 62.5 H-40 Welded 30' 110' 0' 110' 1640 630 Surface 9-5/8" 36 J-55 BTC 30' 2839' 0' 2497' 3520 2020 Casing 7" 26 L-80 TCII 29' 8842' 0' 6354' 7240 5410 Liner 4 %" 11.6 L-80 BTCM 8317' 8716' 5970' 6259' 7780 6360 Tubing 3 %2" 9.3 L-80 EUE 8Rd 24' 8232' 0' 5910' 6990 7400 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 Flo-Pro mud (9.1 ppg) — Drilling operations: Chloride-based Flo-Pro mud (9.1 ppg)✓ This mud weight will not hydrostatically overbalance the reservoir pressure. — Completion operations: 2H-14 contains a new style deployment valve. This valve will allow the deployment of tool strings and liner without pumping kill weight fluid. However, in the case the valve will not hold, BHA's will be deployed using standard pressure deployments and the well will be loaded with 12.0 ppg NaBr completion fluid in order to provide formation over-balance while running completions. — Emergency Kill Weight fluid: Two wellbore volumes of 12.9 ppg kill weight fluid will be stored at .— drillsite 18 in the Kuparuk field, and is accessible for trucking to the rig during CTD operations. 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 Page 3 of 7 6/3/2015 • • PTD Application: 2H-14A & AL1 promotes wellbore stability, particularly in shale sections, while at the same time providing an overbalance on the reservoir. Through experience with drilling CTD laterals in the Kuparuk sands, 11.8 ppg has been identified as the minimum EMW to ensure stability of shale sections. Since this well is proposed as an infield development candidate in an actively water flooded field, expected reservoir pressures can be difficult to estimate. In this case, however, a constant BHP of 11.8 ppg will be initially targeted at the window based on the recent static bottom-hole pressure and the fault blocks being drilled into. 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 2H-14 Window(8530' MD, 6123' TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A-sand Formation Pressure (11.6 ppg) 3693 psi 3693 psi Mud Hydrostatic(9.1 ppg) 2897 psi 2897 psi Annular friction (i.e. ECD, 0.090 psi/ft) 768 psi 0 psi Mud+ ECD Combined 3665 psi 2897 psi (no choke pressure) (underbalanced (underbalanced —28 psi) —796 psi) Target BHP at Window(11.8 ppg) 3757 psi 3757 psi Choke Pressure Required to Maintain Target BHP 92 psi 860 psi 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 AA C 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. 13. Proposed Drilling Program (Requirements of 20 AA C 25.005(c)(13)) Summary of Operations Background KRU 2H-14 is a dual lateral well that is being converted from a producer to an injector. A recent RWO was performed to swap tubing,cement a 4-1/2" scab liner in place and install a down hole deployment valve. Page 4 of 7 6/3/2015 • • PTD Application: 2H-14A & AL1 The objective of this well is to drill 2 laterals on either side of a N-S fault to provide support to the 2H-10, 2M-22 and the 2M-24. 2H-14A will kick off in the A4 sand at 8530'MD via a 2 string cemented window exit,then land in the A3 sand. From there the plan is to turn north and invert into the A4 pay, cross fault#1 into the lower A3 and geo-steer in the A3 pay until a TD of 11,400' MD. The lateral will be completed with 2-3/8" slotted liner with an aluminum billet to a depth of 8950'MD. 2H-14AL1 will kick off the billet at 8950'MD in the A4 pay on the east side of fault#1. The plan is to drop inot the A3 pay and geo-steer to the north drilling to a TD of 10,300'MD. The lateral will be completed with 2-3/8" slotted liner ran back into the parent well bore to a depth of 8525'MD. Pre-CTD Work • Coil:Perform FCO of old mud left over from RWO • E-line: Set a 4'/2"thru-tubing whip-stock at 8530' MD and 0° HS Rig Work 1. MIRU Nabors CDR2-AC rig using 2%"coil tubing. NU 7-1/16"BOPE,test. 2. 2H-14A Lateral(A4 sand-Northwest) i. Mill 2.80"window at 8530' MD ii. Drill 2.70"x 3.00"bi-center lateral to TD of 11300' MD iii. Run 2%"slotted liner with an aluminum billet from TD up to 8950' MD 3. 2H-14AL1 Lateral(A3 sand-North) i. Kick off the billet at 8950' MD ii. Drill 2.70"x 3.00"bi-center lateral to TD of 10300' MD iii. Run 2%"slotted liner with shorty deployment sleeve from TD up to 8325' MD 4. Freeze protect the well. Set BPV,ND BOPE. RDMO Nabors CRD2-AC. Post-Rig Work 1. Pull BPV 2. Obtain static BHP. 3. Flow back(less than 30 days) 4. Perform AOGCC witnessed MIT-IA 5. Put back on injection Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure, so installed in this well is a down hole deployment valve. This valve, when closed using hydraulic control lines from surface, isolates the well pressure and allows long BHA's to be deployed/un-deployed without killing the well. If the deployment valve fails, operations will continue using the standard pressure deployment process. A system of double swab valves on the Christmas tree, double deployment rams, double check valves and double Page 5 of 7 6/3/2015 • • PTD Application: 2H-14A & AL1 ball valves in the BHA, and a slick-line lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slickline. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment, the steps listed above are observed, only in reverse. Liner Running 2,44- 14- - 4- The 2 has a new down hole deployment valve installed. It will serve to deploy liners into the newly drilled laterals. If the valve fails the laterals will be displaced to an overbalancing fluid (12.0 ppg 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(measured to KPA boundary at closest point) Lateral Name Distance 2H-14A 17394' 2H-14AL1 17394' Page 6 of 7 6/3/2015 • • PTD Application: 2H-14A & AL1 — Distance to Nearest Well within Pool (measured to offset well) Lateral Name Distance Well 2H-14A 960' 2H-13 2H-14AL1 1360' 211-13 16. Quarter Mile Injection Review (for injection wells only) (Requirements of 20 AAC 25.402) 2H-14A is within %4-mile of the 2H-13 well 2H-14(mother bore) Injector • The well is completed with 3.5" 9.3#L-80 tubing, 4.5" 11.6#L-80 liner and 7"26#J-55 casing. The last MIT-IA was completed on 5/18/15 and passed at 2500 psi. • Recently worked over and new 4 1/2" liner was ran in hole and cemented in place with 23 bbl of Class"G" cement. This well will be classified as abandoned when we drill the 2H-14A. • Classified as a"Normal Well" • C-sand perforations (cemented): 8460'-8475' MD • A-sand perforations(cemented):A5: 8508'-8519', A4: 8530'—8563' &A3: 8588'—8614' MD • Packer is located at 8238' MD (222'above C-sand)variance was granted by AOGCC on 1/21/15 (attached). Packer was set high to isolate a casing leak 8297'—8319' MD. • 3 1/2" Baker Orbit deployment valve at 3505' MD • The well is being converted from a producer into an injector. The CBL data shows a very good bond in the 7"casing from 8350'—8450', and appears to be adequate above that based on the CBL from 7/30/1984 2H-13 (injector), —960' away from 2H-14A lateral to northeast • The 2H-13 is currently injecting into the Kuparuk A&C-sand intervals. • Currently a waivered well for TxIA communication and is currently a water only injector • Well head pressure is monitored daily as per waiver • Completed with 7", 26#, J-55 casing • C-sand perforations: C4: 7466'—7469' MD • A-sand perforations:A5: 7510'—7515' MD,A4: 7528'—7555' MD &A3: 7591'—7597' MD • Packer at 7387' MD, which is less than 200'from the perforations • The cement bond log shows adequate cement as per original injection order • Last state witnessed MIT-IA on 5/11/08 17. Attachments Attachment 1: Directional Plans for 2H-14A &AL1 Attachment 2: Current Well Schematic for 2H-14 Attachment 3: Proposed Well Schematic for 2H-14A &AL1 Attachment 4: 10-403 to abandon 2H-14 Page 7 of 7 6/3/2015 • • II II II CO it 0 11 , 0 0 y I� bo 0 0 11 coorn a 1-2-2, II ' 3 -m (O 30u ) v 11 i ©r *) I 1 m h _j O a I 2 0 co Q`/�-,O II I N F-;LO (O ‘ v a) II II d 20 C II O 0 0 N F--i 1 1 (n r in F I I v a N m �- II '10t m N 2 co c co M — II -.., w m o 'E m m 11 M O > O. T C I\ II 00 co d O rs \ II 03 .. m °' © E o) rnm E `m E ;I Z. 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O NOLuN U O a\ I, cr 0 n "O N � i w U 0 _ mO dQ 0 '-)g Y o J W ca p_c0 C 't - N m _� (00 O)� N N y_ O70 O) 1�co c� c ch a I" w cn "0 m N O .c/ T 'O. a a.- c0 CO Q N -O (O,- CO' 0,- COr C O Uc0 yO N �© d N i�CO N� a r`� ¢m 0 CD Fa Um .:k'f0) s^* `� KUP PROD • 2H-14 ConOCOPh1Ihp5 - Well Attributes Max Angle&MD TD Alaska Inc Wellbore API/UWI Field Name Wellbore Status Incl C) MD(ftKB) Act Btm(ftKB) Cnnbd PblBjn, 501032003600 KUPARUK RIVER UNIT PROD 54.38 3,000.00 8,873.0 ••• ^. Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date 20-14,5/23/2015 612:46 PM SSSV:LOCKED OUT 63 12/30/2012 Last WO: 12/25/2015 34.51 7/18/1984 venlozl schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag:SLM 8,505.0 5/18/2015 Rev Reason:GLV 0/0,TAG lehallf 5/23/2015 HANGER;237 Casing Strings Casing Description OD(in) ID(In) Top(ftKB) Set Depth(ftKB) Set Depth(N0)...Wt/Len(I...Grade Top Thread CONDUCTOR 16 15.062 30.0 110.0 110.0 62.50 H-40 WELDED Casing Description 'OD(in) ID(In) Top(ftKB) Set Depth(ftKB) -Set Depth(ND)...WULen(I...Grade Top Thread SURFACE 95/8 8.921 30.0 2,838.9 2,497.2 36.00 J-55 BTC Casing Description 01)(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread PRODUCTION 7 6.276 28.6 8,842.4 6,353.8 26.00 J-55 BTC Casing Description OD(in) ID(in) Top(ftKB) Set Depth MKS) Set Depth(TVD)...Wt/Len(I...Grade Top Thread aW1'LINER-RWO 2015 41/2 4.000 8,316.9 8,716.0 6,259.4 11.60 L-80 BTCM Liner Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl C) Item Des Com (in) 8,316.9 5,969.9 44.72 PACKER BAKER ZXP LINER TOP PACKER 4.330 -A.A."CONDUCTOR;30.0-110.0•• �„� 8,336.5 5,983.8' 44.64 HANGER BAKER FLEX LOCK LINER HANGER ' 4.240 8,352.4 5,995.1 44.58 SBE 80-40 SBE 4.000 Tubing Strings Tubing Description String Ma...ID)/n) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection TUBING-UPPER- 31/2 2.992 23.7 8,232.4 5,910.1 9.30 L-80 EUE 8Rd RWO 2015 SURFACE;30.1-2838.9-.a Completion Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(9) Item Des Com (In) 23.7 23.7 0.00 HANGER FMC GEN V HANGER 2.992 DEPLOY VLV;3,505.6 iimi 3,505.6 2,891.7 52.77 DEPLOY VLV BAKER ORBIT DEPLOYMENT VALVE 2.910 8,209.7 5,894.1 45.40 LOCATOR BAKER GBH-22 LOCATOR SUB 2.992 8,210.7 5,894.8 45.40 SEAL ASSY BAKER 80-40 SEAL ASSEMBLY 2.992 Tubing Description String Ma...ID(In) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection TUBING-LOWER- 3 1/2 2.992 8,215.5 8,367.0 6,005.5 9.30 L-80 EUE 8rd Mod GAS LIFT;6154.0 RWO 2015 Completion Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Mei C) Item Des Com (in) 8,215.5 5,898.2 45.36 PBR 80-40 PBR(20') 4.000 -- 8,238.6 5,914.4 45.20 PACKER BAKER 4702 FHL PACKER 2.950 LOCATOR;8,209.7 a; 8,284.0 5,946.5 44.89 NIPPLE HSE 2.813"'X'NIPPLE 2.813 la: SEAL Asst;9,210.7 1 8,324.3 5,975.1 44.69 LOCATOR 80-40 GBH-22 LOCATOR SUB 2.980 PBR;9,215.5 ! 8,325.51 5,975.91 44.681 SEAL ASSY 180-40 GBH-22 SEAL ASSEMBLY 1 2.992 PACKER;5238.6Perforations&Slots Zmuciziz9 Shot Dens Top(ND) Btm(ND) (shots/f Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Com 8,460.0 8,476.0 6,072.1 6,083.6 C-4,UNIT B, 4/18/1985 12.0 IPERF 120 deg.Ph;5"Baker 2H-14 Tubing Cony Mk NIPPLE;8284.0 8,50$.0 8,519.0 6,106.6 6,114.5 A-5,2H-14 4/22/1985 4.0 IPERF 90 deg.Ph;2 118" Illt EnerJet 8,530.0 8,563.0 6,122.5 6,146.5 A-4,2H-14 4/22/1985 4.0 IPERF 90 deg.Ph;21/8" EnerJet 8,588.0 8,614.0 6,164.7 6,183.8 A-3,2H-14 4/22/1985 4.0 IPERF 90 deg.Ph;2 1/8" EnerJet Cement Squeezes LOCATOR;8,324.3 I-, Top(TVD) Btm(TVD) -IB Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Des Start Date Com ' ' 8,336.5 8,842.0 5,983.8 6,353.5"4 1/2"liner 1/19/2015 Pump 15 bbls of Mud Push II Followed by 23 bbls of 1 `t Class""0""15.8 lb/gal cement.Flush lines.Drop Dart SEAL ASSY;8,325.4 z.p- &pump 5 bbls fresh wtr.Displace w/53.5 bbls of mud. z it Total displacement=58.5 bbls.Pressure up&bump plug with 2500 psi.Plug down at 05:46 hrs.S/O w/ 45K&set slips. .1.iMandrel Inserts 1 9t ati 1 on Top(ND) Valve Latch Port Size TRO Run N Top(ftKB) (ftKB) Make Model OD(in) Sew Type Type (in) (psi) Run Date Com IPERF;8.460.0-8,476.0- : �: 1 8,154.0 5,855.1 CAMCO MMG 11/2 GAS LIFT DMY RKP 5/18/2015 DCR- 1 -• :. Notes:General&Safety IPERF;8,508.0-8,519.0- 4' End Date _ Annotation ',0 - 10/27/2010 NOTE:View Schematic w/Alaska Schematic9.0 IPERF;8,530.0.8,563.0 9 - A, IPERF,8,588.0-8,614 0 Q LINER-RWO 2015;8,316.9- 8,716.0 ; 10 r r 'N PRODUCTION;28.6-8,842.4 • ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 2H Pad 2H-14 2H-14AL1 Plan: 2H-14AL1 wp07 Standard Planning Report 29 May, 2015 Irde1ti BAKER HUGHES • •• rsai ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference:'� p' Well 2H-14 Company:,14.E < ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2H-14 @ 125.00usft(2H-14) Site: Kuparuk 2H Pad North Reference: True Well: 2H-14 Survey Calculation Method: Minimum Curvature Wellbore: 2H-14AL1 Design: 2H-14AL1_wp07 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 2H Pad Site Position: Northing: 5,948,973.20 usft Latitude: 70°16'18.548 N From: Map Easting: 498,414.90 usft Longitude: 150°0'46.152 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: -0.01 ° Well 2H-14 Well Position +NI-S 0.00 usft Northing: 5,948,973.05 usft Latitude: 70°16'18.545 N +E1-W 0.00 usft Easting: 497,745.06 usft Longitude: 150°1'5.655 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 2H-14AL1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°l 11 (nT) BGGM2014 8/1/2015 18.60 80.85 57,543 Design 2H-14AL1_wp07 Audit Notes: Version: Phase: PLAN Tie On Depth: 8,950.00 Vertical Section: Depth From(TVD) +N/-S +EI-W Direction (usft) (usft) (usft) (°)', 0.00 0.00 0.00 233.73 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (°) (°) (usft) (usft) (usft) „ (°/100ft) (°/100ft) (°/100ft) (°) Target 8,950.00 93.34 311.43 6,027.13 -4,121.07 -3,907.30 0.00 0.00 0.00 0.00 9,040.00 83.00 302.73 6,030.01 -4,066.95 -3,978.88 15.00 -11.49 -9.66 220.00 9,210.00 83.68 328.40 6,050.07 -3,947.40 -4,096.06 15.00 0.40 15.10 90.00 9,280.00 90.05 336.77 6,053.90 -3,885.43 -4,128.19 15.00 9.09 11.96 53.00 9,480.00 90.54 6.76 6,052.86 -3,689.75 -4,156.51 15.00 0.25 15.00 89.00 9,650.00 89.20 32.23 6,053.26 -3,530.82 -4,100.24 15.00 -0.79 14.98 93.00 9,950.00 89.43 347.23 6,057.05 -3,242.69 -4,050.85 15.00 0.08 -15.00 270.00 10,300.00 89.65 39.73 6,060.06 -2,914.13 -3,972.10 15.00 0.06 15.00 90.00 5/29/2015 11:37:05AM Page 2 COMPASS 5000.1 Build 61 11, • ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 2H-14 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2H-14 @ 125.00usft(2H-14) Site: Kuparuk 2H Pad North Reference: True Well: 2H-14 Survey Calculation Method: Minimum Curvature Wellbore: 2H-14AL1 Design: 2 H-14A L 1_wp07 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) (°) (0) (usft) (usft) (usft) (usft) (°/100ft) (°) (usft) (usft) 8,950.00 93.34 311.43 6,027.13 -4,121.07 -3,907.30 5,588.12 0.00 0.00 5,944,853.56 493,836.92 TIP/KOP 9,000.00 87.59 306.61 6,026.73 -4,089.62 -3,946.11 5,600.82 15.00 -140.00 5,944,885.02 493,798.11 9,040.00 83.00 302.73 6,030.01 -4,066.95 -3,978.88 5,613.83 15.00 -140.04 5,944,907.70 493,765.36 Start 15 dls 9,100.00 83.08 311.80 6,037.30 -4,030.92 -4,026.23 5,630.69 15.00 90.00 5,944,943.74 493,718.02 9,200.00 83.60 326.89 6,048.96 -3,955.79 -4,090.74 5,638.27 15.00 88.90 5,945,018.88 493,653.54 9,210.00 83.68 328.40 6,050.07 -3,947.40 -4,096.06 5,637.59 15.00 87.14 5,945,027.28 493,648.22 3 9,280.00 90.05 336.77 6,053.90 -3,885.43 -4,128.19 5,626.84 15.00 53.00 5,945,089.25 493,616.12 4 9,300.00 90.10 339.77 6,053.88 -3,866.85 -4,135.59 5,621.82 15.00 89.00 5,945,107.82 493,608.72 9,400.00 90.35 354.76 6,053.48 -3,769.59 -4,157.57 5,582.01 15.00 89.00 5,945,205.08 493,586.77 9,480.00 90.54 6.76 6,052.86 -3,689.75 -4,156.51 5,533.92 15.00 89.06 5,945,284.92 493,587.86 5 9,500.00 90.38 9.76 6,052.70 -3,669.96 -4,153.63 5,519.89 15.00 93.00 5,945,304.70 493,590.74 9,600.00 89.59 24.74 6,052.73 -3,574.73 -4,124.07 5,439.72 15.00 93.02 5,945,399.91 493,620.34 9,650.00 89.20 32.23 6,053.26 -3,530.82 -4,100.24 5,394.54 15.00 93.02 5,945,443.82 493,644.17 6 9,700.00 89.20 24.73 6,053.96 -3,486.90 -4,076.42 5,349.35 15.00 -90.00 5,945,487.72 493,668.01 9,800.00 89.26 9.73 6,055.31 -3,391.67 -4,046.89 5,269.21 15.00 -89.89 5,945,582.93 493,697.56 9,900.00 89.36 354.73 6,056.52 -3,292.04 -4,043.01 5,207.15 15.00 -89.69 5,945,682.55 493,701.47 9,950.00 89.43 347.23 6,057.05 -3,242.69 -4,050.85 5,184.28 15.00 -89.51 5,945,731.89 493,693.64 7 10,000.00 89.44 354.73 6,057.54 -3,193.35 -4,058.68 5,161.41 15.00 90.00 5,945,781.24 493,685.82 10,100.00 89.47 9.73 6,058.50 -3,093.72 -4,054.81 5,099.35 15.00 89.93 5,945,880.86 493,689.73 10,200.00 89.55 24.73 6,059.36 -2,998.48 -4,025.28 5,019.20 15.00 89.78 5,945,976.08 493,719.28 10,300.00 89.65 39.73 6,060.06 -2,914.13 -3,972.10 4,926.43 15.00 89.65 5,946,060.40 493,772.48 Planned TD at 10300.00 5/29/2015 11:37:05AM Page 3 COMPASS 5000.1 Build 61 • • ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 2H-14 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2H-14 @ 125.00usft(2H-14) Site: Kuparuk 2H Pad North Reference: True Well: 2H-14 Survey Calculation Method: Minimum Curvature Wellbore: 2H-14AL1 Design: 2H-14AL1_wp07 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting -Shape (°) (1 (usft) (usft) (usft) (usft) (usft) Latitude Longitude 2H-14AL1 CTD Polygon 0.00 0.00 0.00 -2,410.981,135,915.30 5,946,222.00 1,633,546.00 70°1'57.877 N 140°54'29.290 W -plan misses target center by 1139839.81 usft at 8950.00usft MD(6027.13 TVD,-4121.07 N,-3907.30 E) -Polygon Point 1 0.00 0.00 0.00 5,946,222.00 1,633,546.00 Point2 0.00 -346.83 570.18 5,945,875.03 1,634,116.02 Point3 0.00 -1,082.99 338.41 5,945,139.02 1,633,884.05 Point 4 0.00 -1,330.91 628.53 5,944,891.03 1,634,174.07 Point5 0.00 -2,075.01 570.78 5,944,147.03 1,634,116.10 Point6 0.00 -1,331.23 -289.56 5,944,890.99 1,633,256.07 Point 7 0.00 0.00 0.00 5,946,222.00 1,633,546.00 2H-14AL1_T01 0.00 0.00 6,049.00 -3,864.081,136,055.75 5,944,769.00 1,633,686.00 70°1'43.560 N 140°54'31.522 W -plan misses target center by 1139963.07usft at 8950.00usft MD(6027.13 TVD,-4121.07 N,-3907.30 E) -Point 2H-14A CTD Polygon 0.00 0.00 0.00 -1,543.061,135,349.98 5,947,090.00 1,632,981.00 70°2'7.133 N 140°54'41.639 W -plan misses target center by 1139276.14usft at 8950.00usft MD(6027.13 TVD,-4121.07 N,-3907.30 E) -Polygon Point 1 0.00 0.00 0.00 5,947,090.00 1,632,981.00 Point2 0.00 -24.75 730.08 5,947,065.03 1,633,711.00 Point3 0.00 -1,396.98 457.54 5,945,693.02 1,633,438.08 Point 4 0.00 -2,223.80 1,201.90 5,944,866.06 1,634,182.11 Point5 0.00 -2,942.90 1,136.15 5,944,147.05 1,634,116.15 Point6 0.00 -2,108.16 151.75 5,944,982.01 1,633,132.10 Point? 0.00 0.00 0.00 5,947,090.00 1,632,981.00 2H-14AL1_T02 0.00 0.00 6,053.00 -3,647.081,135,987.68 5,944,986.00 1,633,618.00 70°1'45.767 N 140°54'32.527 W -plan misses target center by 1139895.07usft at 8950.00usft MD(6027.13 TVD,-4121.07 N,-3907.30 E) -Point 2H-14A_Fault1 0.00 0.00 0.00 -3,233.11 1,135,744.53 5,945,400.00 1,633,375.00 70°1'50.143 N 140°54'37.663 W -plan misses target center by 1139668.11 usft at 8950.00usft MD(6027.13 TVD,-4121.07 N,-3907.30 E) -Rectangle(sides W500.00 H1.00 D0.00) 2H-14AL1_T03 0.00 0.00 6,060.00 -2,821.941,136,174.45 5,945,811.00 1,633,805.00 70°1'53.507 N 140°54'23.687 W -plan misses target center by 1140082.48usft at 8950.00usft MD(6027.13 TVD,-4121.07 N,-3907.30 E) -Point 2H-14A_Fault2b 0.00 0.00 0.00 -3,818.071,136,057.73 5,944,815.00 1,633,688.00 70°1'44.004 N 140°54'31.269 W -plan misses target center by 1139981.00usft at 8950.00usft MD(6027.13 TVD,-4121.07 N,-3907.30 E) -Rectangle(sides W500.00 H1.00 D0.00) 2H-14A_Fault2a 0.00 0.00 0.00 -4,114.981,136,466.86 5,944,518.00 1,634,097.00 70°1'40.522 N 140°54'20.917 W -plan misses target center by 1140390.09usft at 8950.00usft MD(6027.13 TVD,-4121.07 N,-3907.30 E) -Rectangle(sides W500.00 H1.00 D0.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 10,300.00 6,060.06 2 3/8" 2.375 3.000 5/29/2015 11:37.05AM Page 4 COMPASS 5000.1 Build 61 • ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 2H-14 Company: ConocoPhillips(Alaska)Inc.-Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2H-14 @ 125.00usft(2H-14) Site: Kuparuk 2H Pad North Reference: True Well: 2H-14 Survey Calculation Method: Minimum Curvature Wellbore: 2H-14AL1 Design: 2H-14AL1_wp07 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-5 +El-W (usftj (usft) (usft) (usft) Comment 8,950.00 6,027.13 -4,121.07 -3,907.30 TIP/KOP 9,040.00 6,030.01 -4,066.95 -3,978.88 Start 15 dls 9,210.00 6,050.07 -3,947.40 -4,096.06 3 9,280.00 6,053.90 -3,885.43 -4,128.19 4 9,480.00 6,052.86 -3,689.75 -4,156.51 5 9,650.00 6,053.26 -3,530.82 -4,100.24 6 9,950.00 6,057.05 -3,242.69 -4,050.85 7 10,300.00 6,060.06 -2,914.13 -3,972.10 Planned TD at 10300.00 5/29/2015 11:37:05AM Page 5 COMPASS 5000.1 Build 61 • • ConocoPhillips ConocoPhillips (Alaska) Inc. -Ku p2 Kuparuk River Unit Kuparuk 2H Pad 2H-14 2H-14AL1 2H-14AL1_wp07 Travelling Cylinder Report 29 May, 2015 nat Yf } BAKER HUGHES • Baker Hughes INTEQ • ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips(Alaska)Inc.-Kup2 Local Co-ordinate Reference: Well 2H-14 Project: Kuparuk River Unit TVD Reference: 2H-14©125.00usft(2H-14) Reference Site: Kuparuk 2H Pad MD Reference: 2H-14 @ 125.00usft(2H-14) Site Error: 0.O0usft North Reference: True Reference Well: 2H-14 Survey Calculation Method: Minimum Curvature Well Error: 0.00usft Output errors are at 1.00 sigma Reference Wellbore 2H-14AL1 Database: OAKEDMP2 Reference Design: 2H-14AL1_wp07 Offset TVD Reference: Offset Datum Reference 2H-14AL1_wp07 Filter type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 8,950.00 to 10,300.O0usft Scan Method: Tray.Cylinder North Results Limited by: Maximum center-center distance of 1,217.50usft Error Surface: Elliptical Conic Survey Tool Program Date 5/29/2015 From To (usft) (usft) Survey(Wellbore) Tool Name Description 200.00 8,500.00 2H-14(2H-14) GCT-MS Schlumberger GCT multishot 8,500.00 8,950.00 2H-14A_wp06(2H-14A) MWD MWD-Standard 8,950.00 10,300.00 2H-14AL1_wp07(2H-14AL1) MWD MWD-Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") ("), 10,300.00 6,185.06 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 2H Pad 2H-14-2H-14-21-1-14 9,789.42 7,600.00 1,127.69 21.54 1,112.58 Pass-Major Risk 2H-14-2H-14A-2H-14A_wp06 8,950.00 8,950.00 0.00 0.37 -0.22 FAIL-Major Risk CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 5/29/2015 11:03:23AM Page 2 of 6 COMPASS 5000.1 Build 65 • • I 1 o I iA !m la ! 0 ._ ..4M I .._ ._._.. .............. . 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These materials may be found in the original hard file or check the parent folder to view it in digital format. • • TRANSMITTAL LETTER CHECKLIST WELL NAME: K2(A. 02 14'-110.1-1 PTD: 0Ur'0�I Development /Service Exploratory Stratigraphic Test Non-Conventional FIELD: t14. /�r�/ POOL: IZyo,r1,4 ?I /4 rr XW( %\/6,i- 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. o21S'09Y , API No. 50-1D3 - a003(9 -01 - o0. ►/ (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 0 • 1i❑ y C. O) Q oD N y a a) o of m a � c m ; , � QLU' a Li rr = O' '0 a 023: p0,, w c � O c. N : E 0pf p o • ca y : 0) O O. 7 L co a > , ; 3' CiCo f . �' y _.0 a. oy o o, c 3,a ). co ca J O, _ C' a). a �� W to �� W, W ."ct ' O � U) �p� ao. a CV J_ I- 0: v. 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