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Home My WebLink About209-133 • • 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. cO _9 - 153 Well History File Identifier Organizing (done) ❑ Two -sided III I111111 1 ❑ Rescan Needed 1111111 RES N DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ Maps: Greyscale Items: ( Rtt i fther, No/Type: c., N I. ❑ Other Items Scannable by g a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: n BY: Maria Date: c. . p 1 /s/ 11.1 Project Proofing I 111111 UM BY: AD Date: �ah. . 3 II /s/ lir Scanning Preparation ' x 30 = 3 0 + / 9 = TOTAL PAGES 1-1-9' (Count does not include cover sheet) BY: Date: `' /s/ Production Scanning III IIIIF II III Stage 1 Page Count from Scanned File: 50 (Count does include cover sheet) Page Count Matches Number in Scanning Pre aration: L/ YES NO BY: Date: 0,3 f ' /s/ im1 Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. 11 1111111 I ill ReScanned III 1 BY: Maria Date: /s/ Comments about this file: Quality Checked III 1 10/6/2005 Well History File Cover Page.doc DATA SUBMITTAL COMPLIANCE REPORT 2/17/2011 Permit to Drill 2091330 Well Name /No. KUPARUK RIV UNIT 1B- 17L2 -01 Operator CONOCOPHILLIPS ALASKA INC API No. 50- 029 - 22461 -62-00 MD 9520 TVD 6455 Completion Date 12/22/2009 Completion Status 1 -OIL Current Status 1 -OIL UIC N REQUIRED INFORMATION ---- Mud Log No Samples No Directional Survey Yes w DATA INFORMATION • Types Electric or Other Logs Run: GR / RES (data taken from Logs Portion of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med /Frmt Number lame Scale Media No Start Stop CH Received Comments D C Lis 19322 / Induction /Resistivity 6725 9520 Open 2/6/2010 EWR logs in PDF, TIFF and CGM graphics og Induction /Resistivity 2 Col 6903 9520 Open 2/6/2010 MD MPR, GR 'Cog Induction /Resistivity 5 Col 6903 9520 Open 2/6/2010 MD MPR, GR ti:ig Induction /Resistivity 5 Col 6903 9520 Open 2/6/2010 TVD MPR, GR D C Lis 19325 eduction /Resistivity 6725 8919 Open 2/6/2010 PB1 EWR logs in PDF, TIFF and CGM graphics t Induction /Resistivity 2 Col 6903 8919 Open 2/6/2010 PB1 MD MPR, GR Induction /Resistivity 5 Col 6903 8919 Open 2/6/2010 PB1 MD MPR, GR Induction /Resistivity 5 Col 6903 8919 Open 2/6/2010 PB1 TVD MPR, GR // Directional Survey 6898 9320 Open ilk 1..t6 C Asc Directional Survey 6898 9320 Open t Directional Survey 6898 8775 Open PB1 C Asc Directional Survey 6898 8775 Open PB1 Well Cores /Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments DATA SUBMITTAL COMPLIANCE REPORT 2/17/2011 Permit to Drill 2091330 Well Name /No. KUPARUK RIV UNIT 1B- 17L2 -01 Operator CONOCOPHILLIPS ALASKA INC API No. 50- 029 - 22461 -62 -00 MD 9520 TVD 6455 Completion Date 12/22/2009 Completion Status 1 -OIL Current Status 1 -OIL UIC N ADDITIONAL INFORMATION Well Cored? Y Daily History Received? (j/ N Chips Received? Y / t`L_- Formation Tops 0 N Analysis Y / N .- Received? Comments: Compliance Reviewed By: : a ..__ Date: 0 r; le out/ • 1 • Conoco Phillips Alaska RECIPIENTS No other distribution is allowed without OH FINAL OH FINAL written approval from ConocoPhillips Image files and/or Digital Data contact: Lisa Wright, 907 263 -4823 hardcopy prints ConocoPhillips Alaska, Inc. 1 Hardcopy Print NSK Wells Aide, NSK 69 ATTN: MAIL ROOM 700 G Street, Anchorage, AK 99501 AOGCC 1 Hardcopy Print, Christine Mahnken 1 Graphic image file 1 Disk * / 333 West 7th Ave, Suite 100 in lieu of sepia ** Electronic Anchorage, Alaska 99501 CGM / TIFF LIS BP 1 Hardcopy Print, Petrotechnical Data Center, MB33 1 Graphic image file 1 Disk * / David Douglas in lieu of sepia ** Electronic P.O. Box 196612 CGM / TIFF LIS Anchorage, Alaska 99519 -6612 CHEVRON /KRU REP 1 Hardcopy Print, Glenn Fredrick 1 Graphic image file 1 Disk * / P.O.Box 196247 in lieu of sepia ** Electronic Anchorage, Alaska 99519 CGM / TIFF LIS • Brandon Tucker, NRT State of Alaska; DNR, Div. of Oil and Gas 1 Disk * / 550 W. 7th Ave, Suite 800 Electronic Anchorage, Alaska 99501 -3510 LIS Dog — �3 / WO a09 --/3 l 9 30 3 009 —(33 1� 32y 1 1B -17 L1, L2, an L2 -01TD Sidetracks Last update= 1230 /091JWLt 2o - r 33 i 4" Camco TRDP -4A @ 1896' MD 16" 62# H 40 shoe 4" 11# J -55 BTC Mod tubing (surface - 3554' MD) @ 121' MD 3 -1/2" 9.3# J -55 EUE 8rd AB -Mod Tubing (3554' - 6276' MD) 3 -1/2" 9.2# J -55 SPCLN BTC -Mod Tubing (6276' - 6743' MD) 5 ", 18 #, L -80, LTC, R -3 Class A (6305' - 7477' MD) Camco MMG gas lift mandrels @ 2403', 3590', 4496', 5308', 5904', & 6197' MD 9 -5/8" 40# J -55 shoe @ 4241' MD Baker 80 -40 PBR (10' length with 3" ID seal bore) Baker 7" x 3 -1/2" HB retrievable packer @ 6259' MD 7" 26# L -80 shoe @ — 3 -1/2" Camco D landing nipple @ 6274' MD (2.75" min ID) 6629' MD r L2 (in C3 /C4 sands- north fault block), TD @ 9320' MD 3" borehole, Slotted liner (2 -3/8 ", 4.6 #, L -80 ST -L) Deployment sleeve at 8097' MD; Bottom of shoe at 9204' MD Tubing Tail @ 6743' MD ...,■1.. L2 -01 (in Cl sand -north fault block), TD @ 9520' MD C -sand perfs a Deployment Sleeve 6693' MD 6907' - 6967' MD -_-_- - Anchor billet at 2 -3/8" Slotted liner 6994' -6789' MD _ 8060' MD / 2 -3/8" Blank liner 6789' -7113' D E / 2 -3/8" Slotted liner 7113' -9244 M ' MD 3 -1/2 x 5" Baker Gen 2 flow / R &R Indexing Guide 9224' -9245' MD by whipstock @ 6904' MD \ 2 -3/8" Blank liner 9245' -9247' MD Guide Shoe top at 9247' MD, bottom at 9248' MD 3 -1/2 x 5" Baker Gen 2 flow- / \ — _ by whipstock @ 6990' MD \ Anchor billet at �� 8200' MD � \ \ L2 -01 PB1 (in Cl sand- north /) C -sand perfs \ fault block), TD @ 8918' MD, 7013' - 7053' MD Z_ ___: unlined 5" 18.0# L -80 shoe — — }� @ 7477' MD ......■ L1 (in C1 sand- south fault block), TD @ 8975' MD Deployment Sleeve 6969' MD 2 -3/8" Slotted liner 6979' -7065' MD 2 -3/8" Blank liner 7065' -7338' MD 2 -3/8" Slotted liner 7338' -7871' MD 2 -3/8" Blank liner 7871' -8120' MD 2 -3/8" Slotted liner 8120' -8244' MD 2 -3/8" Blank liner 8244' -8431' MD 2 -3/8" Slotted liner 8431' -8620' MD 0 -Ring Sub 8620' -8621' MD 2 -3/8" Solid liner 8621' -8653' MD Guide Shoe top at 8653' MD, bottom at 8654' MD ► KtutfvED STATE OF ALASKA !A.N 2 G 2010 ALASKA OIL AND GAS CONSERVATION COMMISSION Alaska Oil & G Commission WELL COMPLETION OR RECOMPLETION REPORT ANI la. Well Status: Oil 0 Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development 0 Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No. of Completions: Service ❑ Stratigraphic Test El 2. Operator Name: 5. Date Comp., Susp., 12. Permit to Drill Number: ConocoPhillips Alaska, Inc. or Aband.: December 22, 2009 209 - 133 / 3. Address: 6. Date Spudded: 13. API Number: P. O. Box 100360, Anchorage, AK 99510 - 0360 December 15, 2009 50 029 - 22461 - 62 ' 4a. Location of Well (Govemmental Section): 7. Date TD Reached: 14. Well Name and Number. Surface: 502' FNL, 154' FEL, Sec. 9, T11 N, R10E, UM December 21, 2009 1B • Top of Productive Horizon: 8. KB (ft above MSL): 102' RKB 15. Field /Pool(s): 1663' FNL, 1652' FWL, Sec. 10, T11 N, R10E, UM GL (ft above MSL): 61' AMSL Kuparuk River Field Total Depth: 9. Plug Back Depth (MD + TVD): 1667' FNL, 2512' FEL, Sec. 10, T11 N, R10E, UM 9254' MD / 6416' TVD Kuparuk River Oil Pool 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x 550285 y 5969647 Zone 4 9520' MD / 6455' TVD ADL 25648 TPI: x - 552101.6 y - 5968498 Zone 4 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x 553218 y - 5968502 Zone 4 1896' MD / 1896' TVD 466 18. Directional Survey: Yes 0 No ❑ 19. Water Depth, if Offshore: 20. Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) 1700' MD / 1700' TVD 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): 22. Re drill /Lateral Top Window MD/TVD GR/Res 8198' MD / 6414' TVD 23. CASING, LINER AND CEMENTING RECORD . SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT CEMENTING RECORD CASING SIZE WT. PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE PULLED 16" 62.5# H-40 Surf. 120' Surf. 120' 24" 205 sx AS1 9.625" 40# J -55 Surf. 4241' Surf. 4178' 12.25" 950 sx AS III, 400 sx CI G 7" 26# L -80 Surf. 6629' Surf. 6188' 8.5" 225 sx Class G 5" 18# L -80 6298' 7477' 5915' 6936' 6.125" 160 sx Class G 2.375" 4.6# L -80 6701' 9254' 6248' 6416' 3" Slotted liner 24. Open to production or injection? Yes Q No ❑ If Yes, list each 25. TUBING RECORD Interval open (MD +TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET ( MD/TVD) none 6260' MD / 5883' TVD alternating solid /slotted liner 6701' - 6796' MD 6248' - 6328' TVD 32 spf 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 7119' - 9251' MD 6498' - 6416' TVD 32 spf DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED na PRODUCTION TEST Da First Production Method of Operation (Flowing, gas lift, etc.) December 27, 2009 gas lift oil Date of Test Hours Tested Production for OIL - BBL GAS - MCF WATER - BBL CHOKE SIZE GAS - OIL RATIO 1/1/2010 24 hours Test Period - 927 1641 2621 176 Bean 2747 Flow Tubing Casing Pressure Calculated OIL -BBL GAS -MCF WATER -BBL OIL GRAVITY - API (corr) Press. 213 psi 962 24 -Hour Rate -> 927 1641 2621 23 deg. 28. CORE DATA Conventional Core(s) Acquired? Yes ❑ No 0 Sidewall Cores Acquired? Yes ❑ No El If Yes to either question, list formations and intervals cored (MD +TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (Submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. NONE . ONE .T I Form 10 -40A 1 �1 09 JAN 2 7 2010 1,41 CONTINUED ON REVERSE Submit original my 6 • • 28. GEOLOGIC MARKERS (List all formations and markers encountered): 29. FORMATION TESTS NAME MD TVD Well tested? ❑ Yes El No If yes, list intervals and formations tested, Permafrost - Top ground surface ground surface briefly summarizing test results. Attach separate sheets to this form, if Permafrost - Bottom 1700' 1700' needed, and submit detailed test information per 20 AAC 25.071. Top C1 8495' 6409' Top C1 8867' 6400' Top C1 9368' 6417' Top B 9477' 6441' N/A 1 B- 17L2 -01 PB1 Total depth 8919' 6406' Formation at total depth: Kuparuk B 30. LIST OF ATTACHMENTS Summary of Daily Operations, schematic, directional survey 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Jill Long © 263 - 4093 O'!a.5IIo Printed N e V. C i e Title: Alaska Wells Manager VZ-.512-6/6 Signature Phone 265 -6306 Date Sharon Allsup -Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases 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. Item 1 a: Classification of Service wells: Gas injection, water injection, Water - Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. 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 4b: TPI (Top of Producing Interval). Item 8: 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 13: The API number reported to AOGCC must be 14 digits (ex: 50- 029 - 20123- 00 -00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: 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 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut -in, or Other (explain). Item 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a list of intervals tested and the corresponding formation, and a brief summary of this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 12/2009 e KUP 0 1B- 17L2 -01 ConocoPhillips 1 7 . \ Well Attributes Max Angle & MD TD a. too Wellbore APYUWI Field Name Well Status Incl ( °) MD (ftK8) Act Btm (ftKB) 500292246162 KUPARUK RIVER UNIT "Well 103.09 7,195 41 9,520.0 'Comment H2S (PPM{ Date Annotation E (ft) Rig Release Date '° . SSSV TRDP 75 8/18/2008 Annotation WO: 1 .. nd Date KB - 01 _ 4/5/1994 Annotation I'Depth(ftKB) ,End Date Annotation Last Mod ... End Date Last Tag- i j Rev Reason: GLV 0/0, QC SIDETRACKS Imosbor 1/4/2010 Casio Strin s Casing Description String 0 ... Sfr g ID ... Top (ftK8) Set Depth (f... Set Depth (TVD) String Wt... String ... String Top Thrd " ' ' LINER L2-01 - S/T off 2 3 1 995 6,693.0 9,248.0 6,416 4 4 60 L -80 STL ' main wellbore HANGER, 41 ; "n. � ' ` <; Liner Details 'To Depth ' (TVD) Top Inc! Nomi... Top(ftKB) (ftK ( °) Item Description Comment ID (in) I 6,693.0 6,241.3 34.20 DEPLOY 2.7" GS Deplyment Sleeve 1.995 CONDUCTOR . 9,244 _ - -- 42121 . 9,244.0 6,416 4 89 87 GUIDE R &R Indexing Guide LINER 1.995 Other In Hole (Wireline retrievable plugs, valves pumps, fish, etc.) Top Depth SAFETY VLV, (TVD) Top Inc! 1,096 Top (ttK8) (ftK8) (°) Description Comment Run Date ID (in) 8,060 6,391.5 89.62 ANC IIOR ANCHOR BILLET TO L2 12/14/2009 1.000 1111 ,_. BILLL I GAS LIFT, Perforations & Slots - - - -- - Shot 2,404 Top (RKB) Top (TVD) Min (TVD) Dens T etm (ftK8 (RKB (1866) Zone Date _ - �.e° Type Comment I,'; 6,701 6,796 6,247.9 6,328.3 C -1, 1B -17L1 12/21/2009 32.0 SLOTS Alternating solid /slotted pipe - 0.125 "x2.5" i 4 circumferential adjacent rows, 3" centers staggered 18 deg, 3' non - slotted ends GAS 3,590 - 7,119 9,251 6,497.9 6.416 4.0 -1, 18-171.2-01 12/21/2009 32.0 SLOTS Alternating solid /slotted pipe - 0.125'x2.5" @ 4 circumferential adjacent rows, 3" centers staggered 18 deg, 3' non - slotted ends N otes: General $ Safet >7 L SURFACE, En d . Da _ _ _ Annotation 41 - 4,241 __ - '� 12/22/2009 NOTE: MULTI-LATERAL WELL CTD 1B -17L1, 1B -17L2, 16- 17L2 -01 GAS LIFT,_ '" 1/4/2010 NOTE VIEW SCHEMATICw /Alaska SchemaSc9.0 4:496 .w°,,,,.., GAS LIFT, 5,308 �.. IF GAS LIFT, I 5,904 __....___... III GAS LIFT, 6,197 at ir PBR, 6,246 -' i PACKER,6,259 "''': .._ NIPPLE,6,274 , 1 ; C PRODUCTION,_ 31 -6,629 S05, 6,742 a WHIPSTOCK_ �.. 6,904 WINDOW L2 -01, 6,900-6,910 IPERF, 6,907 -6,967 WHIPSTOCK, 6,980 WINDOW L1, 6,990 -7,000 SLOTS, 6.966 -7.080 7,013 -7,033 IPERF, 7,013 -7,053 `. RPERF, I 7033 -7,053 - LINER, ,< TO (1x,47), Mandrel Details TO 118 -v ), 7,500 - Top Depth Top - -- Pod (TVD) Incl OD Valve Latch Ed. TRO Run 6.969 -8.654 �- " • MKS) () Make Model (in Sere Type T (n) Stn T�{ft/C6) ) YP TM. (Psi) Run Date Can... 1 2,403.5 2.402.0 3.16 CAMCO KBUG 1 GAS LIFT GLV BK 0.000 1,342.0 12/25/2009 2 3,589.5 3,581 0 13.54 CAMCO KBUG 1 GAS LIFT GLV BK 0.188 1,366.0 12/25/2009 . _ 3 4,496.3 4,395.8 31.68ICAMCO KBUG 1 GAS LIFT OV BK 0.250 0.0 12/25/2009 4 5,307.5 5,088.5 32.87 CAMCO KBUG 1 GAS LIFT DMY BK 0 000 0.0 1214/2008 5 5,904.2 5,586 .3 33.29 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 4/15/2000 6 6,196.7 5,830.8 33.84 CAMCO MMM 1 1/2 GAS LIFT DMY RK 0.000 0.0 11/13/2009 I d { • 1B-17 Well Events Summary DATE SUMMARY • 11/8/09 (PRE CTD) T & IC POT's - PASSED. MITOA - PASSED. PT /DD MV WF SV SSV - PASSED. DD SSSV - PASSED. 11/11/09 LOGGED CALIPER SURVEY f/ 7110' TO 6226' RKB. RECOVERED GOOD DATA. IN PROGRESS. 11/12/09 SET CAT SV IN D NIPPLE @ 6274' RKB. PULLED GLVs @ 2403' & 4496' RKB; SET DVs @ SAME. PULLED OV © 6197' RKB. READY FOR CIRC OUT. IN PROGRESS. 11/13/09 CIRCULATED 200 BBL DSL TO PROD. SET DV @ 6197' RKB. MITIA 2500 PSI, PASSED. PULLED CAT SV © 6274' RKB. IN PROGRESS. 11/14/09 MEASURED BHP @ 6950' RKB: 2036 PSI. READY FOR E /L. 11/17/09 DRIFT FOR SETTING TOOL & WHIPSTOCK TO 7050' SLM W/ SETTING TOOL DRIFT ASSY (2.74" CENT, 3' OF 1.875" WB & 2.74" X 3' CENT, OAL =7.5') & DMY WHIPSTOP DRIFT ASSY (2.65" X 9', 1.85" X 1', 2.62" X 9', OAL =18'), NO PROBLEMS. JOB COMPLETE 11/23/09 SET BAKER THRU- TUBING GEN II 2.625" WHIPSTOCK USING DPU -i. TOP OF WHIPSTOCK AT 6980' WITH WHIPSTOCK TRAY 15 DEG RIGHT OF HIGHSIDE LOOKING DOWNHOLE. TWO Co60 RA BEADS PLACED IN WHIPSTOCK AT 6987.5'. WHIPSTOCK SCHEMATIC IN WELLVIEW ATTACHMENTS. 11/25/09 ATTEMPTED TO BLEED T ABOVE SSSV UNABLE TO BLEED TO 0 PSI APPEARS SSSV NOT HOLDING POTENTIALLY DUE TO LOW T PRESSURE 12/24/09 GAUGE TBG 2.78" TO 6274' RKB. MEASURED BHP @ 6650' RKB (2565 PSI) & GRADIENT @ 6525' RKB (2507 PSI) SET CATCHER @ 6274' RKB. PULLED DMY VLV's © 4496 & 3590' RKB. IN PROGRESS. 12/25/09 PULLED DV @ 2403' RKB. SET 1/4" OV @ 4496. SET GLVS @ 3590' & 2403' RKB. PULLED CATCHER @ 6274' RKB. TEST TBG BELOW GLM @ 4496' RKB W/ D &D HF, GOOD. COMPLETE. I S Time Logs . Date From To Dur S. Depth E. Depth Phase Code Subcode, T Comment 16:57 17:27 0.50 0 0 COMPZ CASING PUTB P PU liner string 17:27 17:42 0.25 0 0 COMPZ CASING SFTY P Hold Safety Drill, taking a kick while running liner 17:42 18:12 0.50 0 0 COMPZ CASING SFTY P Crew Change, Hold PJSM running liner 18:12 19:21 1.15 0 0 COMPZ CASING PULD P Continue running liner 19:21 19:36 0.25 0 0 COMPZ CASING SFTY P PJSM, PU deployment sleeve, coiltrack. MU to CT 19:36 20:36 1.00 0 0 COMPZ CASING PULD P MU deployment sleeve, coiltrack to CT 20:36 22:18 1.70 0 6,800 COMPZ CASING RUNL P RIH, pumping minimum rate 22:18 22:54 0.60 6,800 7,820 COMPZ CASING RUNL P Offline with pumps, closed EDC. Record up and down weights. RIH =14K, PUW =26K RIH through window 20FPM, Increasing to 50 FPM running liner to bottom 22:54 23:24 0.50 7,820 9,185 COMPZ CASING RUNL P Slow down to 2.5 FPM to tie in depth with Gamma. Stacking weight. PUH 29K PUW. RIH to bottom. 12K =RIW, 3K WOB, pumping .2 BPM in, 883 CTP. 23:24 23:33 0.15 9,185 7,994 COMPZ CASING RUNL P Tag 9185' MD, -16K CTW. 7K WOB. Online with pumps max rate. 1.56 BPM 3300psi CTP, PUH releasing from liner. 23K PUW. Liner released. Stop at 9100' subtracting liner from bit depth. Corrected depth= 7994.47' 23:33 00:00 0.45 7,994 6,895 COMPZ CASING RUNL P POOH 40 FPM .7 BPMin, .07 BPM out, to window. Tie in to RA marker 12/14/2009 Set billet with OH anchor on depth. POOH Perform full BOP test, waived by the state. 10hr BOP test. RIH to sidetrack off billet L2 -01 with 1.2 AKO. 00:00 02:30 2.50 6,895 0 COMPZ CASING RUNL P Tie in RA marker. +19' correction. Places bottom of liner 9204'. TOL= 8098.5'. POOH. 02:30 02:45 0.25 0 0 COMPZ CASING SFTY P At surface, Hold PJSM LD BOT tools, PU /MU BHA 02:45 04:30 1.75 0 0 PROD3 DRILL PULD P LD /PU /MU tools. 04:30 06:36 2.10 0 6,760 PROD3 DRILL TRIP P Open EDC, pumping minimum rate RIH 06:36 06:48 0.20 6,760 6,780 PROD3 DRILL DLOG P Tie in, +17', close EDC and continue RIH 06:48 07:18 0.50 6,780 8,093 PROD3 DRILL TRIP P Continue RIH '07:18 07:30 0.20 8,093 8,090 PROD3 DRILL WPST P Tag liner top at 8092' with 2.5K WOB, 27K PUW, 15K RIW. Set down 200 WOB at 8090', pump .25 BPM, anchor set at 3900 CTP. 26K PUW 07:30 09:00 1.50 8,090 0 PROD3 DRILL TRIP P POOH, .3 BPM at 50 FPM in open hole, .6 BPM at 100 FPM in cased hole. Page 16 of 27 S • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 09:00 09:36 0.60 0 0 PROD3 DRILL PULD P Flow check, Lay down BHA 09:36 10:30 0.90 0 0 PROD3 DRILL BOPE P Flush stack, displace coil to fresh water, grease tree 10:30 20:30 10.00 0 0 PROD3 DRILL BOPE P Test BOP's and tree valves, inner reel valve and stripper. BOP test 10 hrs. 20:30 21:30 1.00 0 0 PROD3 DRILL BOPE P RD test joint, Clean up floor. Displace CT to mud, change stripper, install check valves 21:30 22:30 1.00 0 0 PROD3 DRILL PULD P . PU /MU BHA #13 22:30 23:45 1.25 0 6,756 PROD3 DRILL TRIP P RIH with BHA #13, 1.2 AKO, with HCC, Q cutters 23:45 00:00 0.25 6,756 6,800 PROD3 DRILL DLOG P Tie in depth with gamma, +17 correction. Close EDC , RIH 12/15/2009 Kick off billet from 8063 - 8067', continue drilling ahead. Drilled into B sand @ 8330', Tight spots during wiper trips from 8340 - 8380'. Increase claygaurd in mud. Continue drilling ahead. 00:00 00:30 0.50 6,800 8,000 PROD3 DRILL TRIP P RIH through window, looked good. Online with pumps 1.45 BPM in, 1.06 BPM out. 13K RIW. 00:30 00:45 0.25 8,000 8,000 PROD3 DRILL TRIP P Weight check, RIW 13K, PUW 25K, RIH for dry tag. Bypass Micro Motion 00:45 01:15 0.50 8,000 8,063 PROD3 DRILL TRIP P Dry tag 8064'. PU 28K PUW. Online with pumps 1.4 BPM in, 1 BPM out, 2370 CTP, 325 diff psi off bottom. PUH 80' , 5 FPM troughing. RIH 10 FPM to 8062. RIH, /minute. 01:15 02:15 1.00 8,063 8,063 PROD3 STK KOST P Start time drilling .05'/ 2 minutes. .14 -.25K WOB. 1.4 BPM in, 1 BPM out, 2430 CTP. 340 diff 02:15 03:00 0.75 8,064 8,064 PROD3 STK KOST P Good amount of aluminum in returns. Continue time drilling .05'/ 2 minutes with .9-1K WOB, 12K CTW, 1.4 BPM, 2433 CTP, 363 diff. 03:00 03:21 0.35 8,064 8,065 PROD3 STK KOST P Time drilling .1'/ 2 minutes. .5-1K WOB 12.5K CTW. 1.4 BPM in, 2450 CTP, 394 diff. 03:21 03:42 0.35 8,065 8,067 PROD3 STK KOST P Auto drill 3 FPH, .1 - .3 WOB, 12.5K CTW. 1.4 BPM in, 2330 CTP, 316 diff 03:42 03:57 0.25 8,067 8,067 PROD3 STK KOST P Auto drill 4 FPH, .1 - .5 WOB, 11.5 CTW. 1.4 BPM in, 2350 CTP, 03:57 04:15 0.30 8,067 8,070 PROD3 STK KOST P Auto drill 10 FPH 04:15 04:33 0.30 8,070 8,080 PROD3 STK KOST P Drilling ahead, holding back at 20 FPH, 11K surface wt., 200 WOB, 30-40 psi motor work, Increase ROP to 60 FPH. 04:33 05:06 0.55 8,080 8,080 PROD3 STK KOST P . Ream across billet at +/- 30 Deg. Drift past billet clean. Page 17of27 110 Ask- Time Logs Date From To Dur S. Depth E. Depth Phase Code '` Subcode T Comment 05:06 08:00 2.90 8,080 8,210 PROD3 DRILL DRLG P ' Drilling ahead, 1.4 BPM, 1.0 BPM returns, 2400 CTP, 3270 BHP, 11K RIW, , 1 -3K WOB, 200 - 300 psi motor work, Limiting ROP to 100 FPH. Hitting hard streaks where ROP drops to <20 and surface weight stacks out to - 10K. This was also seen coming up through C2. 08:00 09:30 1.50 8,210 8,210 PROD3 DRILL WPRT P Wiper trip to window. Stacked out with motor work at 8190 while RIH, worked past and backreamed, cleaned up. 09:30 12:30 3.00 8,210 8,360 PROD3 DRILL DRLG P Drilling ahead, 1.4 BPM, 1.0 BPM returns, 2400 CTP, 3280 BHP, 12K RIW, , 1 -3K WOB, 200 - 300 psi motor work, Limiting ROP to 100 FPH. Hitting hard streaks where ROP drops to < 20 and surface weight stacks out to - 10K. 12:30 14:15 1.75 8,360 8,360 PROD3 DRILL WPRT P Wiper trip back to window. -3 to -4K CTW while drilling. Current mud system- 1% low torq, 0 776. Increase 776 to 1% 14:15 14:30 0.25 8,346 8,360 PROD3 DRILL WPRT P Stacked out, 8346' -8355' TF change in this section, PUH with over pulls. Work pipe up and down through area. 14:30 17:12 2.70 8,360 8,510 PROD3 DRILL DRLG P Drilling ahead, 1.4 BPM, 1.19 BPM returns, 2400 CTP on bottom, 2750 off bottom, 3314 BHP, 12K RIW, , 1 -3K WOB, 200 - 300 psi motor work, Limiting ROP to 100 FPH. Hitting hard streaks where ROP drops to < 20 and surface weight stacks out to - 10K. 17:12 20:12 3.00 8,510 6,903 PROD3 DRILL WPRT P Wiper trip to window with Tie in. CT weight 30.5K, slight overpull @ 8352' to 35K, worked area and continue with wiper. Plus 4 ft correction. 20:12 22:12 2.00 6,903 8,510 PROD3 DRILL WPRT P RIH started stacking weight 30 left & pulled heavy @ 8345'. Work area a numerous times, loss of returns when stacking out & playing with pump rates. Increase claygaurd in mud system. Tried numerous times with wiping low side on P /U. Did a 300 ft wiper, and keep working through, made it to TD. Wipe up high side to ensure bad spot is clean, motor work and drag at 8340'. 22:12 00:00 1.80 8,510 8,580 PROD3 DRILL DRLG P BOBD - CT weight 1k, 1.5 bpm, circ 3000 psi, BHP 3415, ECD 10.4, ROP 55, WOB 1.9. Page 18 of 27 I Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 12/16/2009 24 hr Summary Continue drilling ahead, work through tight spots while tripping @ 8350 & 8550. POOH to P/U agitator due to weight transfer on bottom . 00:00 02:30 2.50 8,580 8,660 PROD3 DRILL DRLG P Continue drilling ahead. CT weight - 6K, 1.45 bpm, cric press. 3000psi, BHP 3410, WOB 2.8, ROP 30 fph. Pumping 5 bbls sweeps every 75'. 02:30 05:12 2.70 8,660 8,660 PROD3 DRILL WPRT P Wiper trip, P/U weight 30K off bottom, chasing 5 bbls sweep out. Troubled area of 8350 looked cleaner, trouble spot now at 8550' while RIH. Begin working through it with toolface and playing with the pump rates. Pump 5 bbl sweep on bottom. 05:12 07:09 1.95 8,660 8,738 PROD3 DRILL DRLG P BOBD - CT weight - 7K, WOB 1.1, 1.45 bpm - 3000psi, BHP 3450, ROP 50 fph. 07:09 07:15 0.10 8,738 8,738 PROD3 DRILL WPRT P BHA wiper, 30K PUW. 07:15 08:45 1.50 8,738 8,810 PROD3 DRILL DRLG P Continue drilling ahead. CT weight - 6K to -18K, 1.45 bpm in, 1.14 out. 3000 CTP. BHP 3410, WOB .5 - 2.8K, ROP 30 -80 fph. Pump sweeps to help stacking, increase active system to 2% low torq, 2% 776. 08:45 11:15 2.50 8,810 8,810 PROD3 DRILL WPRT P Wiper trip back to window, 38K PUW, Set down weight 8350' - 8370'. PU to work areas in B formation. 11:15 14:30 3.25 8,810 8,918 PROD3 DRILL DRLG P Continue drilling ahead. CT weight - 6K to -18K, 1.45 bpm in, 1.14 out. 3000 CTP. BHP 3410, WOB .5 - 1.2K, ROP 20 -80 fph. Pump sweeps as needed. Stacking wieght, Trouble keeping WOB. PUH doing BHA wipers trying to get good weight transfer. Continued stacking problems 14:30 18:00 3.50 8,918 81 PROD3 DRILL TRIP P POOH to pick up Agitator 18:00 20:30 2.50 0 78 PROD3 DRILL PULD P CT @ surface, monitor well for flow. Looks good. Pre job meeting, lay down BHA & inspected bit. 1 Cutter has fallen off, P/U re -run Razor bit and agitator with 38 hrs. Clean injector gripper blocks and grease injector head. 20:30 00:00 3.50 78 8,190 PROD3 DRILL TRIP P Test agitator at surface, RIH pumping 1 bpm. Tie in with correction +17 ft. Continue RIH 12/17/2009 RIH had problems in B sands @ 8345' & 8525'. Sticking BHA & loss circulation. POOH & set OH Billet @ 8200. RIH with 1.4 AKO and Cheetah, KO billet @ 8199'. Page 19 of 27 i Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 00:00 01:24 1.40 8,190 8,390 PROD3 DRILL TRIP T Continue RIH and working through tight spots starting @ 8340', work the BHA in hole down to 8390, P/U and wip through area, starting to pull heavy @ 8370'. Pumping 1.3 bpm, looks like packing off, losing returns. Slowly started getting returns back, moving pipe slowly up to 8330' getting better ruturns and weight is pulling close to normal. 32K. Injector slipping © 38K with 2000 psi traction pressure applied. 01:24 02:48 1.40 8,390 8,530 PROD3 DRILL TRIP T Wipe up to 8000', Pump 5 bbl pill, RIH and try again. Tagged up @ 8330' and started working in cautiously, good returns to surface. Worked down to 8530, started to lose returns. P/U and try to circ out again. Pulled free with 43K, while getting better returns after working CT. BHA sticking. 02:48 03:48 1.00 8,530 7,100 PROD3 DRILL WPRT T Wiper up through bad section while discuss forward step with town. 03:48 06:00 2.20 6,900 0 PROD3 DRILL WPRT T POOH for sidetrack. 06:00 06:30 0.50 0 0 PROD3 DRILL SFTY T At surface. Crew change /PJSM 06:30 07:30 1.00 0 0 PROD3 DRILL PULD T LD BHA. 07:30 08:30 1.00 0 0 PROD3 DRILL SVRG T Service injector head, Clean gripper blocks, inspect chains and traction system. 08:30 09:45 1.25 0 0 PROD3 STK PULD T MU BHA #15 09:45 11:30 1.75 0 6,740 PROD3 STK TRIP T RIH 11:30 11:45 0.25 6,740 6,757 PROD3 STK DLOG T Tie in depth to gamma, +17 correction 11:45 12:15 0.50 6,757 8,211 PROD3 STK WPST T Weight check 27K PUW, 15K RIW. Set Billet on OH anchor, 8211.1'. Anchor set at 4100 psi CTP. -11K WOB. PUH 27K. 12:15 14:15 2.00 8,211 0 PROD3 STK TRIP T POOH 14:15 14:30 0.25 0 0 PROD3 STK SFTY T At surface, monitor well for flow. Hold PJSM 14:30 15:42 1.20 0 0 PROD3 DRILL PULD T LD BHA #15, PU BHA #16 15:42 17:03 1.35 0 6,740 PROD3 DRILL TRIP T RIH, EDC open. .26 BPM in 17:03 17:21 0.30 6,740 8,188 PROD3 DRILL DLOG T Tie in depth to gamma, Correction +17 Page 20 of 27 • Time Logs Date From . To Dur S. Depth E. Depth Phase Code `+ Subcode T Comment 17:21 20:21 3.00 8,188 8,199 PROD3 STK KOST T RIH and tag TOB @ 8188'. 12' ft early, retag begin KOB. Had two stalls 1 ft into drilling. Notice no Al. in returns, looking back we are on a ledge 8188 & 8193' , Work BHA down by cleaning ledges and ream down to top of billet.(8199). Back ream above area to smooth out 30 left Pulled heavy @ 8170'. RIH was clean. 20:21 00:00 3.65 8,199 8,222 PROD3 STK KOST T Start KOB - 8198'. Good motor work @ 8199', time drilled and @ 8201' the drilling changed, WOB dropped off & CT weight came back. No Al. billet returns to surface. Increased speed @ 8203' to 10 fph, 8208' increase to 20 fph to 8214, drill © 50 fph to 8222', P/U and back ream.(30 left & right) RIH & dry run looked good. 12/18/2009 Kick off top of Billet @ 8200', continue drilling ahead. Total losses 330 bbls for past 24 hours. 00:00 00:36 0.60 8,222 8,235 PROD3 STK KOST T Backreamed KO area, (45 left & right) RIh & dry tag, looks good. Continue drilling ahead, no Al samples in returns, most likely slipt downhole. Call town & continue drilling ahead. Gamma indicates we are in good sand. 00:36 01:36 1.00 8,235 8,290 PROD3 DRILL DRLG T Drilling ahead - CT weight 11K, 1.44 bpm, 2700psi, BHP 3370, WOB 1.3K, ROP 80 fph. 01:36 02:12 0.60 8,290 8,290 PROD3 DRILL WPRT T Quick Wiper trip for DD to work out survey and directional data. CT weight 26K off bottom. Pulled up 8100', everything looked clean. 02:12 03:12 1.00 8,290 8,370 PROD3 DRILL DRLG T BOBD - Ct weight 5K, 1.43 bpm, 2700psi, BHP 3370, WOB 1.6, ROP 80 fph. 03:12 05:27 2.25 8,370 8,370 PROD3 DRILL WPRT T Wiper trip - tie in. CT weight off bottom 28K. +1 ft correction, billet areas looked clean. Set down 8195' PUH, RIH 30L, Slide through 05:27 06:18 0.85 8,370 8,410 PROD3 DRILL DRLG T Drill Ahead 1.4 BPM in, 1.13 out, 2590 CTP, 3300 BHP, .5 -2K WOB, 10 -80 FPH. Drilling through hard stringers 06:18 06:24 0.10 8,410 8,410 PROD3 DRILL WPRT T BHA wiper, sticky. 40K CTW 06:24 08:51 2.45 8,410 8,520 PROD3 DRILL DRLG T Drill Ahead 1.4 BPM in, 1.13 out, 2590 CTP, 3300 BHP, .5 -2K WOB, 10 -80 FPH. Drilling through hard stringers 08:51 10:51 2.00 8,520 8,520 PROD3 DRILL W PRT T Wiper Trip back to window. 25K CTW, Did not tag up. Page 21 of 27 Time Logs Date ! From To Dur S. Depth E. Depth Phase Code Subcode T Comment 10:51 12:21 1.50 8,520 8,629 PROD3 DRILL DRLG T Drill Ahead 1.4 BPM in, 1.13 out, 2750 CTP, 3300 BHP, .5 -2K WOB, 10-80 FPH. Drilling through hard stringers. Slowly increase Low Torq to 3% 12:21 12:27 0.10 8,629 8,629 PROD3 DRILL WPRT T BHA Wiper, Weight transfer issues 30K PUW 12:27 13:03 0.60 8,629 8,670 PROD3 DRILL DRLG T Drill Ahead 1.4 BPM in, 1.14 out, 2790 CTP, 3390 BHP, 1 -2.5K WOB, 10-80 FPH. Drilling through hard stringers. Good weight transfer to bit 13:03 15:33 2.50 8,670 8,670 PROD3 DRILL WPRT T Wiper trip to window, 29K, Over pull 40K @ 8645', RIH, PUH 40K Pull free 3% Low Torq around in active system -230pm 15:33 18:33 3.00 8,670 8,825 PROD3 DRILL DRLG T Drill Ahead 1.4BPM in, 1.13 out 18:33 21:33 3.00 8,825 8,825 PROD3 DRILL WPRT T Wiper trip P/U weight off bottom 30K slight overpull's with toolface changes in tight formation. Tie in. + 4.5 correction. 21:33 23:03 1.50 8,825 8,917 PROD3 DRILL DRLG T BOBD - CT weight 6K, 1.40 bpm 1.0 returns, 2700 psi, BHP 3370, ROP 70, WOB 1.2 23:03 00:00 0.95 8,917 8,935 PROD3 DRILL DRLG P Continue drilling ahead, crossing a fault or hard section. CT weight -15K, WOB .4, 100ft wiper to try help the weight transfer. Weight improved continue drilling ahead. 12/19/2009 Drill down to 9210', WOB dropped off, P/U CT & stuck at BHA (differential & mechanical) not cuttings. Continue to work on stuck BHA, finally popped free while spotting 20 bbls of slick diesel. Max. pull 63K during operations. Wiper trip + 6.5' tie in & clean up into cased hole. ( total losses 350 bbls to well & 387 bbls overall including tiger tank displacement). 00:00 03:00 3.00 8,935 8,970 PROD3 DRILL DRLG P Drilling ahead, Ct weight -5K, WOB 1.3, 1.43 BPM with 1 bpm returns, circ press 2700psi, BHP 3370, ROP 30. hard drilling again @ 8950'. Slow ROP 4- 5 fph, CT weight - 18K. Broke through long hard spot, @ 8965'. Good ROP 60 fph, CT weight 5K. 03:00 05 :30 2.50 8,970 8,970 PROD3 DRILL WPRT P Wiper trip, P/U weight 28K off bottom. Looked clean through billets. 05:30 08:42 3.20 8,970 9,120 PROD3 DRILL DRLG P Drill ahead 1.37 BPM in, 1 BPM out, 2443 CTP, -3 to -16K CTW, .7 -2K WOB, 3310 BHP, 0 WHP. Drilling through hard stringers. Good weight - transfer, Mud system =3% 776, 2.5% Low Torq. 08:42 11:24 2.70 9,120 9,120 PROD3 DRILL WPRT P Wiper trip to window 28K PUW. Page 22 of 27 1 Time Logs Date From To Dur . S. Depth E. Depth Phase Code ' Subcode T Comment 11:24 11:36 0.20 8,763 9,120 PROD3 DRILL WPRT P Tag with 40R TF, hole was drilled at 90L. TF change in this area. PUH, 38K PUW, RIH 12K, slip through with correct TF. Back ream 10' above with 180 deg TF. RIH Slip through. RIH. Tag 8994'. PUH 38K with 40R TF, 38K PUW, RIH 90R TF, slip through. RIH 11:36 13:00 1.40 9,120 9,210 PROD3 DRILL DRLG P Drill Ahead 1.4 BPM in, 1.02 BPM out, 2625 CTP, 80 FPH, 1.2K WOB, 3330 BHP, 3K CTW. 13:00 13:15 0.25 9,210 9,210 PROD3 DRILL DRLG T Lose weight on bit, surface weight stacking, PU for BHA wiper, 45K CTW. RIH -14 X 4. STUCK. RIH to neutral weight. Mix up a high vis, lube pill. PJSM, Stuck pipe, discuss staying clear of CT and Reel, pulling heavy weights. 13:15 14:00 0.75 9,210 9,210 PROD3 DRILL DRLG T PUH 50K, No luck, RIH to neutral weight. Offline with pumps 5 minutes. PUH 50K, still stuck No pumps, 8.65 ECD, 2809 BHP 14:00 14:21 0.35 9,210 9,210 PROD3 DRILL DRLG T Pump high vis/lube pill (6.5% lube, 65K LSRV) 10bbrls. 1.4 BPM in, 1.08 BPM out. Order out LRS with Deisel. 14:21 15:00 0.65 9,210 9,210 PROD3 DRILL DRLG T 5 bbrls out bit. Offline with pumps, Try to pull free, 50K PUW. Stuck PU 55K pumps off, X 5. Still stuck. 15:00 16:00 1.00 9,210 9,210 PROD3 DRILL DRLG T Pump 10 bbrls pill, 6% low torq. 1.49 BPM in, 1.11, 2885psi CTP 3K CTW, 0 WHP, 3368 BHP, 10.2 ECD Call for Super Slick Deisel 16 :00 16:27 0.45 9,210 9,210 PROD3 DRILL DRLG T Offline with pumps 5bbrls pill out of bit. Let soak, Try to pull free 60K No luck LRS on location, Hold PJSM, LRS rig up to cement line. 16:27 16:57 0.50 9,210 9,210 PROD3 DRILL DRLG T LRS rigged up and psi tested. Online pumping 10 bbrls deisel. 1.5 BPM, 1.05 out. 2733 CTP, Swap to active mud system chasing deisel down to bit. Page 23 of 27 Time Logs Date From To Dur S. Depth E. Depth Phase Code ° ` Subcode T Comment 16:57 17:09 0.20 9,210 9,210 PROD3 DRILL CIRC T 9 bbrls of deisel out bit, Offline with pumps, try to pull free. 55K PUW. Stuck. Slack off to neutral weight let deisel soak. 17:09 18:09 1.00 9,210 9,210 PROD3 DRILL DRLG T Work pipe up and down trying to pull free, 55K . STUCK. RIH. 32 cycles to this point. 18:09 19:33 1.40 9,210 9,210 PROD3 DRILL CIRC T Crew change, check valve alignment, let the CT relax in nuetral for 30 minutes. Tried 4 times -10K to +50K, no luck with 13.5' of stretch. Start circulating 10 bbl diesel pill out of well. Set up for SD down CT. 19:33 20:15 0.70 9,210 9,210 PROD3 DRILL CIRC T Swap to tiger tank for returns, only saw 2 -3 bbls of desiel with the lightest density of 7.8# . Conitnue circulating drill mud to clean up well. Tried pulling CT total 10 times since tower change at different rates & weights. Max pull 59K. Pre -job meeting with LRS. 20:15 21:03 0.80 9,210 9,210 PROD3 DRILL CIRC T Start pumping 20 bbls of SD down CT string, followed by drill mud. Start working string when diesel in CT and around nozzle. Popped free on 4th pull @ 62K. had 9 bbls out nozzle, and 11 inside CT. Noticed an extra 150 # of pull on BHA while working the string when diesel was working around the string. 21:03 23:33 2.50 9,210 6,300 PROD3 DRILL WPRT P Total of 15 cycles on pipe since 18:00 hrs. Inspected CT 100 ft off bottom, looked good. Wiper trip to discuss next steps and condition hole. CT weight 28K. CT pipe visually inspected and looked good. No weight changes @ billets, Sent 30 bbls to Tiger tank, clean mud back inside. 23:33 00:00 0.45 6,300 6,900 PROD3 DRILL WPRT P Pull up into cased hole, circulate B/U to clear any cuttings (if any) and inspect injector in case of damage due to stuck pipe. Tie in +6.5 ft correction. 12/20/2009 Drilled ahead slowly, sticking & irratict drilling to 9355'. Crossed fault @ 9310'. POOH to P/U agitator. Q cutters damaged on bit. RIH with BHA # 17. difficult time getting to bottom (last 50 ft). (total bbls lost - 360/24hr) 00:00 02:30 2.50 6,900 9,020 PROD3 DRILL WPRT P RIH from window, + 6.5 ft correction to pip tag. Tagging up @ 8191' (ledges above billet), tried 4 times. Stopped pump rate while attempting. had to set down lightly, then kick pump off /on to pop by it (Toolface 30 degrees left) RIH down to 8220' P/U and backream from 8197 to 8185'.RIH was clean with a little bump. Page 24 of 27 • Time Logs Date From To Dur S. Depth E. Depth Phase Code . `> Subcode T Comment 02:30 03:00 0.50 9,020 9,210 PROD3 DRILL WPRT P Weight check P/U weight 30K @ 9000', Continue RIH. P /U- 9100' 30K, 9190' 30K, 9208' 31K, little pull WOB. Light motor work RIH from 9193', start drilling from 9206'. 03:00 03:24 0.40 9,210 9,242 PROD3 DRILL DRLG P Drilling ahead - CT weight 6K, 1.47 bpm -1.07 returns, WOB .5, Circ press. 2700psi, BHP 3370, ROP - 100 fph. Holding back the reins. 75 Right, holding 90 degrees. 03:24 04:24 1.00 9,242 9,308 PROD3 DRILL DRLG P P/U for weight check 32K, come up 200 ft. Clean - loses are 1/2 bpm. Drilling ahead - CT weight 5K, WOB .5, ROP 90 fph, BHP 3350, 1.45 bpm @ 2700 psi. Drill 50ft - 100ft wiper 32K off bottom. Hit hard spot @ 9308'. WOB & CT weight started dropping off. 04:24 05:06 0.70 9,308 9,315 PROD3 DRILL DRLG P P/U weight - overpull of 42K, but came free & pulled normal. Wiper up 300 ft. Drill ahead - WOB .8, CT weight -12K, 1.5 bpm, returns 1.0, BHP 3350. ROP 40 fph. 05:06 06:36 1.50 9,315 9,336 PROD3 DRILL DRLG P P/U off bottom due to pump problem, lost prime. Weight was clean, swap pumps, small over pull @ 9270'. Clean up area, start drilling again. 06:36 08:18 1.70 9,336 9,342 PROD3 DRILL DRLG P Drilling ahead - CT weight -14K, 1.5 bpm - 1.07 returns, WOB .5, Circ press. 2800psi, BHP 3370, ROP - 10 -20 FPH. Increase Low Torq to 4 %, 776 currently at 2 %, Pump 10 bbrls 65 LSRV, 6% lube pill 08:18 09:00 0.70 9,342 9,346 PROD3 DRILL DRLG P PU 40K, weight check. RIH drill ahead -17K surface weight, .8 WOB, 1.5 BPM in, 1.16 out, 2800 CTP, 3300 BHP. 09:00 12:30 3.50 9,346 9,346 PROD3 DRILL WPRT P Wiper trip back to window. 30K PUW. 12:30 13:30 1.00 9,346 9,355 PROD3 DRILL DRLG P Drill Ahead, hard stringers, Weight transfer not good. Numerous overpulls. differential sticking issues and not being able to slide keeping WOB. 35 -50K PUW, -17K Drilling surface weight. 13:30 16:45 3.25 9,355 0 PROD3 DRILL WPRT P POOH for Agitator 16:45 16:54 0.15 0 0 PROD3 DRILL SFTY P At surface, Hold PJSM 16:54 18:54 2.00 0 90 PROD3 DRILL PULD P LD BHA # 16 & PU BHA # 17, 1.1 AKO, Agitator and razor bit. 18:54 20:18 1.40 90 90 PROD3 DRILL CTOP P Service CT injector. Pressure test CT connector low /high - looked good. 20:18 23:18 3.00 90 8,191 PROD3 DRILL TRIP P RIH, tie in +17', no issues through window or build. Page 25 of 27 Time Logs Date From To , Dur S. Depth E. Depth Phase Code Subcode T Comment 23:18 23:36 0.30 8,191 9,300 PROD3 DRILL TRIP P Tagged ledge @ 8191' @ 30 left. P/U and come offline on pumps, tagged again. Rolled pumps and slid through. Continue RIH, smooth all the way to TD. Weight check @ 9300' 32K . 23:36 00:00 0.40 9,300 9,337 PROD3 DRILL TRIP P tagging up with good motor work @ 9317', P/U weight 42K, steady drag @ 36K, cleaned up @ 9290'. Rlh cleaner until 9337'. Motor work. 12/21/2009 Drill ahead to TD of 9520', Lay in Liner beads and POOH. Monitor well, LD BHA # 17, P/U Liner assembly with a indexing guide shoe, 1.5 bent sub & R & R indexing shoe. 00:00 00:30 0.50 9,337 9,355 PROD3 DRILL TRIP P Continue working down to 9350', Motor work and slight over pull's past 50 ft. P/U weight off bottom - 38K. 00:30 01:30 1.00 9,355 9,399 PROD3 DRILL DRLG P BOBD - CT weight -5K, WOB 1.3, Circ press 3060, 1.45 bpm, 1.0 returns, ROP 60, BHP 3321. 01:30 02:30 1.00 9,399 9,417 PROD3 DRILL DRLG P P/U ROP slowed down, weight dropped off. P/U weight 46K, RIH, P/U weight 38K pulled free. Wipe 100'. BOBD - slow hard drilling with good weight transfer. 02:30 03:30 1.00 9,417 9,477 PROD3 DRILL DRLG P Broke through - CT weight -12K, WOB 1.8, ROP 70 - 90, 1.47 bpm, 1.10 returns, BHP 3350. P/U weight 38K. Geo's not sure what formation yet. 03:30 04:30 1.00 9,477 9,490 PROD3 DRILL DRLG P CT weight -15K, WOB 1.1, 1.48 bpm, 1.1 returns, Circ press 3200, BHP 3360, ROP 10 - 20 fph, Geo's feel maybe top of C1 now & maybe another 100ft to drill or less? 04:30 08:00 3.50 9,490 9,490 PROD3 DRILL WPRT P Wiper trip to window, P/U weight 38K off bottom. Clean up hole for weight transfer and better ROP. Light tag at 8190' with no pumps. Kick pumps on slip through. 08:00 09:00 1.00 9,490 9,520 PROD3 DRILL DRLG P Drill Ahead 1.4BPM in, 1.08 BPM out. 3100 CTP, -12K surface weight, 1 -1.5K WOB, 3350 BHP. 20 -30 FPH 09:00 11:30 2.50 9,520 9,520 PROD3 DRILL WPRT P TD, Wiper trip to window, Tie in with RA marker +4 correction 11:30 12:00 0.50 9,520 9,520 PROD3 DRILL WPRT P Perform Static BHP test. 2740psi. 12:00 14:00 2.00 9,520 9,520 PROD3 DRILL WPRT P RIH. 8190' set down 5K. Slip through RIH to 9490' 14:00 16:00 2.00 9,520 9,520 PROD3 DRILL WPRT P POOH laying Alpine beads 16:00 18:00 2.00 9,520 9,520 PROD3 DRILL WPRT P POOH, Paint EOP flags at 6769', 100 ' off bottom and 4202' and 100' from entering OH, EOP 18:00 19:30 1.50 9,520 0 PROD3 DRILL PULD P Crew change. Flo -check well. Lay down BHA # 17. razor bit had damaged & chipped cutters. Page 26 of 27 i • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 19:30 20:30 1.00 0 0 COMPZ CASING PULD P Prep the rig floor & liner runnning equipment. Inspect Top drive and test teh R & R indexing tool. Worked well. 20:30 21:00 0.50 0 0 COMPZ CASING SFTY P Safety meeting and safety joint drill prior to P/U liner 21:00 00:00 3.00 0 1,700 COMPZ CASING PUTB P Start P/U liner assembly with R & R indexing sub, 1.5 bent sub & indexing guide shoe. 12/22/2009 Release from liner, Freeze Protect well RDMO RIG RELEASE 24:00 00:00 02:00 2.00 1,700 2,600 COMPZ CASING PUTB P Complete running liner. Total weight 10K. Clean up rig floor and put away liner running tools. Took less than 1/2 bbl to fill hole. 02:00 03:00 1.00 2,600 2,600 COMPZ CASING CTOP P P/U BHA assembly and make up injector. 03:00 04:15 1.25 2,600 6,790 COMPZ CASING RUNL P RIH pumping. 3 bpm through EDC. 04:15 05:15 1.00 6,790 8,190 COMPZ CASING RUNL P Tie in to EOP flag, +12' correction RIH to TD 05:15 05:30 0.25 8,190 9,234 COMPZ CASING RUNL P Tag PUH orienting R & R tool x 3. Continue RIH 05:30 06:00 0.50 9,234 9,234 COMPZ CASING RUNL P Tag 9234'. Unable to PUH 66K. RIH -20K, X 10. EDC not closing 100 %. Calibrate EDC. Now closed 100 %. 06:00 06:15 0.25 9,234 9,234 COMPZ CASING SFTY P Crew change, PJSM 06:15 06:30 0.25 9,234 9,234 COMPZ CASING CIRC P Pump off GS, Releasing from Liner. 06 :30 08:00 1.50 9,234 8,400 COMPZ CASING RUNL T Standby 08:00 08:30 0.50 8,400 8,340 COMPZ CASING DLOG P Tie in Depth 08:30 09:00 0.50 5,630 5,630 COMPZ CASING DLOG P PUH to continue Tie in, -1 correction, Remove Liner length and correct depth 09:00 09:30 0.50 5,630 6,650 COMPZ CASING TRIP P RIH 50' above TOL., Liner Top at 6693'. 09:30 10:00 0.50 6,650 6,650 COMPZ CASING CIRC P Swap hole over to Seawater, good returns to surface, POOH. Start pumping diesel to freeze protect well. 10:00 12:00 2.00 0 0 COMPZ CASING TRIP P POOH freeze protecting well. CT @ surface, Flow -check well at surface. 12:00 12:30 0.50 0 0 COMPZ CASING PULD P lay Down BHA 12:30 15:00 2.50 0 0 DEMOB WHDBO CIRC P Flush stack with Sea - water then blow down with air. Fill stack with methanol prior to setting BPV. 15:00 17:30 2.50 0 0 DEMOB WHDBO NUND P Setting BPV 17:30 20:30 3.00 0 0 DEMOB WHDBO CTOP P Blow down coil to pits via gravity line 20:30 00:00 3.50 0 0 DEMOB WHDBO NUND P Finish Pits, Nipple down BOP equip, General Rig Down. RIG RELEASE 24:00 HOURS Page 27 of 27 c Alaska ConocoPhillips(Alaska) Inc. • Kuparuk River Unit Kuparuk 1B Pad 1B-17L2-01 500292246162 Baker Hughes INTEQ I Definitive Survey Report BAKE 28 December, 2009 _w- ConocoPhillips no oPh dl h 5 Definitive Survey Report HUGHES Alaska Company: ConocoPhillips(Alaska) Inc. Local Co- ordinate Reference: 1B - 17 Project: Kuparuk River Unit ND Reference: 1B-17 @ 102.00ft (1B-17) Site: Kuparuk 1B Pad MD Reference: 1B @ 102.00ft (1B Well: 1B-17 North Reference: TRUE Wetlbore: 1B-17 Survey Calculation! Method' Minimum Curvature Design: 1B -17 Database:; EDM Alaska Prod v16 Survey Map Map Vertical MD inc Azi T17Ct TVDSS +NI -S ¢S /-W Florthing Eastirfg D Section Survey Tool Name A nnotation (ft) () ( °) (ft) ( (ft) (ft) (ft) (ft) (11 00) (ft) • 8,190.65 75.22 49.98 6,412.49 6,310.49 - 1,165.67 1,803.14 5,968,493.70 552,096.11 16.00 2,106.45 MWD(3) TIP 1B - 17L2 - 01PB1 8,200.00 76.60 51.33 6,414.77 6,312.77 - 1,159.92 1,810.15 5,968,499.49 552,103.08 20.35 2,110.83 MWD (4) KOP 8,230.17 83.41 41.18 6,420.02 6,318.02 - 1,139.40 1,831.56 5,968,520.16 552,124.34 40.07 2,123.13 MWD (4) 8,250.18 88.13 38.33 6,421.49 6,319.49 - 1,124.06 1,844.31 5,968,535.58 552,137.00 27.53 2,129.30 MWD (4) 8,280.21 91.14 32.77 6,421.68 6,319.68 - 1,099.64 1,861.76 5,968,560.11 552,154.28 21.05 2,136.48 MWD (4) 8,310.15 91.50 25.64 6,420.99 6,318.99 - 1,073.53 1,876.36 5,968,586.31 552,168.70 23.84 2,140.38 MWD (4) 8,340.44 91.04 30.61 6,420.32 6,318.32 - 1,046.83 1,890.63 5,968,613.11 552,182.79 16.47 2,143.76 MWD (4) 8,374.96 90.46 38.23 6,419.87 6,317.87 - 1,018.38 1,910.13 5,968,641.68 552,202.09 22.14 2,151.35 MWD (4) 8,405.02 92.98 40.54 6,418.97 6,316.97 - 995.16 1,929.19 5,968,665.03 552,221.00 11.37 2,160.47 MWD (4) 8,43507 96.51 45.25 6,416.48 6,314.48 - 973.23 1,949.56 5,968,687.10 552,241.22 19;54 2,171.29 MWD(4) 8,465.23 96.73 51.29 6,413.00 6,311.00 - 953.29 1,971.91 5,968,707.17 552,263.43 19.91 2,184.67 MWD (4) 8,495.50 98.46 58.25 6,408.99 6,306.99 - 935.99 1,996.40 5,968,724.64 552,287.80 23.50 2,201.03 MWD (4) 8,525.30 98.16 64.32 6,404.68 6,302.68 - 921.83 2,022.25 5,968,738.97 552,313.55 20.18 2,219.80 MWD (4) 8,560.29 95.81 69.95 6,400.42 6,298.42 - 908.35 2,054.23 5,968,752.66 552,345.45 17.32 2,244.53 MWD (4) 8,589.75 95.50 76.55 6,397.52 6,295.52 - 899.91 2,082.29 5,968,761.30 552,373.44 22.32 2,267.48 MWD (4) 8,620.24 95.13 83.24 6,394.69 6,292.69 - 894.58 2,112.16 5,968,766.82 552,403.27 21.88 2,293.26 MWD (4) 8,650.33 94.39 90.65 6,392.19 6,290.19 - 892.99 2,142.08 5,968,768.61 552,433.18 24.66 2,320.47 MWD (4) 8,680.25 93.29 96.54 6,390.18 6,288.19 - 894.86 2,171.87 5,968,766.94 552,462.97 19.98 2,348.83 MWD (4) • 8,710.25 90.40 102.24 6,389.22 6,287.22 - 899.75 2,201.43 5,968,762.25 552,492.57 21.29 2,378.11 MWD (4) 8,740.35 88.01 107.56 6,389.64 6,287.64 - 907.49 2,230.50 5,968,754.71 552,521.69 19.37 2,407.98 MWD (4) 8,770.32 84.62 108.07 6,391.56 6,289.56 - 916.63 2,258.97 5,968,745.75 552,550.22 11.44 2,437.81 MWD (4) 8,800.33 84.74 102.02 6,394.35 6,292.35 - 924.39 2,287.82 5,968,738.20 552,579.11 20.08 2,467.48 MWD (4) 8,830.15 83.94 95.88 6,397.29 6,295.29 - 929.00 2,317.12 5,968,733.78 552,608,43 20.66 2,496.40 MWD (4) 8,850.20 84.22 91.80 6,399.36 6,297.36 - 930.34 2,337.01 5,968,732.58 552,628.34 20.29 2,515.38 MWD (4) 8 85.48 87.52 6,402.04 6,300.04 - 930.16 2,366.74 5,968,732.95 552,658.06 14.89 2,542.94 MWD (4) 8,910.29 85.97 81.95 6,404.30 6,302.30 - 927.39 '2,396.75 5,968,735.92 552,688.05 18.45 2,569.79 MWD (4) 8,940.61 84.06 87.77 6,406.93 6,304.93 - 924.69 2,426.82 5,968,738.83 552,718.09 20.13 2,596,73 MWD (4) 8 84.46 93.79 6,409.90 6,307.90 - 925.09 2,456.24 5,968,738.62 552,747.52 20.29 2,624.21 MWD (4) 9,000.23 85.36 99.49 6,412.56 6,310.56 - 928.55 2,485.94 5,968,735.36 552,777.24 19.14 2,653.08 MWD (4) 9,030.58 86.19 105.48 6,414.80 6,312.80 - 935.09 2,515.48 5,968,729.02 552,806.81 19.87 2,682.95 MWD (4) 12/28/2009 11:29 :32AM Page 3 COMPASS 2003.16 Build 69 VP ConocoPhillips IA Cat Definitive Survey Report NUS Alaska Company: ConocoPhillips(Alaska) Inc. Local Co-ordinate Reference: 1B-17 Project: Kuparuk River Unit TVD Reference: 13-17 @ 102.00ft (1B-17) Site: Kuparuk 1B Pad MD Reference: 1B-17 @ 102.00ft (1B-17) Well: 1B-17 North Reference: i TRUE Wellbore: 1B-17 Survey Calculation Method: Minimum Curvature Design: 1B-17 Database: EDM Alaska Prod v16 Survey Map ;Vial) ,,,, MD Inc Afii TVD TVDSS +Nf -S +E /-W Nortliin Eastin S n Sectio (ft) ( °) (a) (ft) (ft) (ft) (ft) (ft) g (ft) ( Wk (ft) S urvey Tool Name Annotation 9,060.41 87.54 112.31 6,416.43 6,314.43 - 944.73 2,543.64 5,968,719.57 552,835.04 23.31 2,712.68 MWD (4) 9,090.19 89.14 106.91 6,417.30 6,315.30 - 954.71 2,571.67 5,968,709.77 552,863.13 18.90 2,742.41 MWD (4) 9,125.07 90.31 100.15 6,417.46 6,315.46 - 962.87 2,605.56 5,968,701.85 552,897.07 19.67 2,776.92 MWD (4) 9,160.23 90.71 95.74 6,417.15 6,315.15 - 967.73 2,640.37 5,968,697.22 552,931.91 12.59 2,811.06 MWD (4) 9,190.20 90.12 102.14 6,416.93 6,314.93 - 972.38 2,669.96 5,968,692.77 552,961.53 21.44 2,840.27 MWD (4) 9,220.20 91.04 108.67 6,416.63 6,314.63 - 980.35 2,698.87 5,968,685.00 552,990.49 21.98 2,870.07 MWD (4) 9,250.20 89.79 115.33 6,416.41 6,314.41 - 991.58 2,726.67 5,968,673.95 553,018.36 22.59 2,900.05 MWD (4) 9,280.09 89.42 121.21 6,416.62 6,314.62 - 1,005.73 2,752.98 5,968,659.98 553,044.76 19.71 2,929.73 MWD (4) 9,310.17 89.88 128.70 6,416.80 6,314.80 - 1,022.95. 2,777.62 5,968,642.93 553,069.51 24.95 2,958.99 MWD (4) 9,340.14 90..58 133.08 6,416.68 6,314.68 -1,042.56 2,800.27 5,968,623.47 553,092:29 14.80 2,987.29 MWD (4 9,372.88 85.21 133.89 6,417.88 6,315.88! -1,065.07 2,824.00 - 5,968,601.12 553,116.17 16.59 3,017.66 MWD :(4) 9,400.38 81.65 133.85 6,421.03 6,319.03 - 1,084.00 2,843.69 5,968,582.33 553,135.98 12.95 3,042.96 MWD (4) 9,432.85 76.18 134.51 6,427.27 6,325.27 - 1,106.20 2,866.53 5,968,560.29 553,158.97 16.96 3,072.39 MWD (4) 9,460.13 70.76 135.13 6,435.03 6,333.03 - 1,124.62 2,885.08 5,968,541.99 553,177.64 19.99 3,096.44 MWD (4) 9,520.00 70.76 135.13 6,454.76 6,352.76 - 1,164.68 2,924.96 5,968,502.20 553,217.78 0.00 3,148.31 PROJECTED to TD • 12/28/2009 11:29:32AM Page 4 COMPASS 2003.16 Build 69 Conoco Phillips Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 1B Pad 1 B- 17L2 -01PB1 500292246170 Baker Hughes ITE • Definitive Survey Report HUGHES 28 December, 2009 ConocoPhillips BAKER rtOCOPh I��hpS Definitive Survey Report A HUGINES laska Company: ConocoPhillips(Alaska) Inc. Local Co-ordinate Reference: 1B-17 Project: Kuparuk River Unit TVD Reference: 1B-17 @ 102.00ft (1B Site: Kuparuk 1B Pad MD Reference: 1B-17 @ 102.00ft (1B Well: 1B-17 North Reference: TRUE Weltbore: 1B-17 Survey Calculation Method: Minimum Curvature Design: 1B - Database: EDM Alaska Prod v16 Survey Map Map Ver#iaai MD Inc: Azi 'ND TVDSS +NI -S +E /-W Northing Easting °DLS vectlan Survey Tool Name Annotation (ft) ( °) ( °) (ft) (ft) (ft) (ft) (ft) (ft) ( 1'100') (ft) 8,042.50 88.37 34.59 6,391.06 6,289.06 - 1,276.27 1,708.68 5,968,382.47 552,002.40 13.62 2,057.91 MWD (2) TIP 1B -17L2 • 8,063.00 89.01 31.63 6,391.53 6,289.53 - 1,259.11 1,719.88 5,968,399.71 552,013.48 14.77 2,062.02 MWD (3) KOP 8,090.68 83.38 36.74 6,393.37 6,291.37 - 1,236.28 1,735.38 5,968,422.64 552,028.83 27.44 2,068.06 MWD (3) Interpolated AZI 8,125.52 80.06 43.27 6,398.39 6,296.39 - 1,209.88 1,757.52 5,968,449.18 552,050.79 20.85 2,078,96 MWD (3) 8,160.79 77.15 45.48 6,405.36 6,303.36 - 1,185.17 1,781.70 5,968,474.05 552,074.79 10.29 2,092.38 MWD (3) 8,190.65 75.22 49.98 6,412.49 6,310.49 - 1,165.67 1,803.14 5,968,493.70 552,096.11 16.00 2,105.17 MWD (3) 8,225.86 80.44 54.99 6,419.92 6,317.92 - 1,144.73 1,830.43 5,968,514.81 552,123.25 20.32 2,122.87 MWD (3) 8,255.40 82.33 54.80 6,424.34 6,322.34 - 1,127.94 1,854.33 5,968,531.76 552,147.03 6.43 2,138.93 MWD (3) 8,292.35 81.09 47.20 6,429:68 6,327.68 - 1,104.95 1,882.72 5,968:554.94 552,175.27 20.63- 2,156.90 MWD (3) 8,320:30 82.86 43.07 6,433.58 6,331.58 1,085.43 1,902.33: 5,968,574.59 552,194.75 15.94 2,167.97 MWD (3) 8,350.49 84.44 37.98 6,436.92 6,334.92 - 1,062.63 1,921.82 5,968,597.52 552,214.08 17.55 2,177.73 MWD (3) 8,380.47 86.50 41.83 6,439.29 6,337.29 - 1,039.71 1,940.99 5,968,620.56 552,233.09 14.53 2,187.15 MWD (3) 8,410.68 87.42 46.64 6,440.89 6,338.89 - 1,018.10 1,962.03 5,968,642.31 552,253.98 16.19 2,198.79 MWD (3) 8,445.37 87.54 52.40 6,442.42 6,340.42 - 995.61 1,988.38 5,968,664.97 552,280.18 16.59 2,215.04 MWD (3) 8,472.36 88.43 56.97 6,443.37 6,341.37 - 980.02 2,010.38 5,968,680.71 552,302.08 17.24 2,229.79 MWD (3) 8,505.38 87.42 62.18 6,444.57 6,342.57 - 963.32 2,038.82 5,968,697.60 552,330.41 16.06 2,250.11 MWD (3) 8,535.46 90.37 65.36 6,445.15 6,343.15 - 950.03 2,065.79 5,968,711.07 552,357.28 14.42 2,270.32 MWD (3) 8,565.44 94.43 68.02 6,443.89 6,341.89 - 938.18 2,093.29 5,968,723.10 552,384.70 16.18 2,291.55 MWD (3) 8,595.21 97.89 71.08 6,440.70 6,338.70 - 927.84 2,121.02 5,968,733.63 552,412.35 15.48 2,313.54 MWD (3) 8,625.33 97.36 75.45 6,436.70 6,334.70 - 919.25 2,149.60 5,968,742.41 552,440.87 14.49 2,336.97 MWD (3) 8,655.18 97.08 80.94 6,432.94 6,330.94 - 913.19 2,178.58 5,968,748.66 552,469.81 18.27 2,361.70 MWD (3) 8,685.27 94.80 85.47 6,429.83 6,327.83 - 909.65 2,208.29 5,968,752.39 552,499.49 16.78 2,388.04 MWD (3) 8,720.38 94.77 91.45 6,426.90 6,324.90 - 908.71 2,243.24 5,968,753.57 552,534.44 16.97 2,420.21 MWD (3) 8,750.38 96.40 94.93 6,423.98 6,321.98 - 910.37 2,273.05 5,968,752.11 552,564.25 12.76 2,448.55 MWD (3) 8,785.31 95.94 102.57 6,420.22 6,318.22 - 915.65 2,307.35 5,968,747.06 552,598.58 21.79 2,482.39 MWD (3) 8,820.29 96.31 109.66 6,416.48 6,314.48 - 925.30 2,340.74 5,968,737.64 552,632.03 20.18 2,516.99 MWD (3) 8,850.29 96.46 114.10 6,413.14 6,311.14 - 936.41 2,368.40 5,968,726.72 552,659.76 14.72 2,546.80 MWD (3) 8,880.08 95.51 109.13 6,410.03 6,308.03 - 947.32 2,395.93 5,968,715.99 552,687.37 16.90 2,576.41 MWD (3) 8,919.00 95.51 109.13 6,406.30 6,304.30 - 960.01 2,432.54 5,968,703.54 552,724.05 0.00 2,615.12 PROJECTED to TD 12/28/2009 11:32 :18AM Page 3 COMPASS 2003,16 Build 69 I Page 1 of 2 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Thursday, December 17, 2009 1:28 PM To: 'Long, Jill W Subject: RE: 1B-17 L2 -01 PB1 (PTD 209 -132) (PTD 209 -133) Jill, Thanks.. .that prints out fine. Thankyou for the update on the drilling status. You are correct in the PB API number and designation. Let me know of any other departures from the PTD that come up as the well progresses. Regards, Guy Schwartz Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Long, Jill W [mailto:JiII.W.Long @conocophillips.com] Sent: Thursday, December 17, 2009 1:01 PM To: Schwartz, Guy L (DOA) Subject: RE: 1B -17 L2 -01 PB1 I think that happened because I sent it as a picture. Here it is in pdf form. Let me know if this doesn't come through. Jill Long ConocoPhillips Alaska Office: 907 - 263 -4093 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz @alaska.gov] Sent: Thursday, December 17, 2009 11:32 AM To: Long, .3111W Subject: RE: 1B -17 L2 -01 PB1 Jill, Can you send me the diagram as a separate attachment.. can't get it to print right. Guy Schwartz Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) 12/17/2009 • Page 2 of 2 From: Long, Jill W [ mailto: Jill.W.Long @conocophillips.com] Sent: Thursday, December 17, 2009 10:44 AM To: Schwartz, Guy L (DOA) Subject: 1B -17 L2 -01 PB1 Guy, As a follow -up to our phone conversation earlier, here is an email notification that we are proceeding with a sidetrack out of the 1B-17 L2 -01 lateral. Attached is a cross - section view which will help describe the situation. The 1B-17 L2 lateral was completed on 12/13/09 and an anchor billet set above the L2 liner at 8063' MD. The sidetrack off of the anchored billet was completed early 12/15/09 and drilling began. The C1 sands are the target of the L2 -01 lateral, however the thickness of the C1 was much thinner than expected. This resulted in drilling into the B sand (as you can see on the cross section). We were hopeful that we could manage the B sand, and did so until early this morning after POOH to pick up an agitator. On the trip back in we encountered significant problems getting through the B sand beginning at 8350' MD. Because of the risk involved with managing the B as well as the low probability that liner could be run through the B, the team decided to sidetrack out of the L2 -01 lateral. The portion of the L2 -01 lateral that was drilled will not be lined and not considered productive. Thus, it will be called the 1B-17 L2 -01 PB1. The kickoff for the new L2 -01 lateral will be at 8200' MD. Please let me know what additional information you need or if this is sufficient. Thanks, Jill Long ConocoPhillips Alaska Drilling and Wells Office: 907 - 263 -4093 Cell: 907 - 240 -6574 Fax: 918- 662 -6330 12/17/2009 ,_ . ,., -- o - surveys 1 G - I LL - U1 LL -U1 Well Plank .Parent Well 1G -1 / C = ®iis C D ' R Well 1B-1 - L2 and L2 -01 1 ieasu ed Depth Profile ----- 1B-17 L2 surreys Top C4 Top C3 — Mid C3 Marker Top C2 Top Cl (non -pay) Structural Cross- Section Interpretation Top Cl Pay Top B '''Faults , i Polygon ; Targets • picks 6175 -' i. f _ _ . _ _ 1 ____ -. __ __ - _ _ __ f _ _ i __ ______ -_ ___ -_ ___ - f __ T __ T ------ f __ _ f 1 - - -- Fault N 3 _ North , -- - -- -- --4--i East East -r - -; � � __ __�_ f __.__�____ f __ r __ __.�___ __ T r __ T __ _ __ __r__i f __T__i f , • - DT5 ' • -6200 1B -17 36 ss D" - -�- � 1B -17 L2 ' " 432 'MD152 "- -6225 - ' Parent Well , t' - __ ___ __ __ __ ------ f __ __, r , r -'r i-.- i_ _ _- - __ r __ i_ __ _ _r__ ___ .� __ __ __ __ __i ---- f __ __i ------ f __ __l ------ f __. __ _1 ------ , , . , r __ ___ 0250 1B -17 L2 -01 KOP L ` (J'ss 1 ' 8053'MDI -524 IYaii , -5275 - : : : : El A.V.i ,--* • ' ^ : : __ __ f __ T __ ___,__,___ __,___,___ __ ------ f __ __ ______ _ _ _ ___ ______ __ i i 1B -17 L2 KOP 1B -17 L2 -01 KOP : 5300 - 1B -17 5903'MDl- 6319'ss �� i 8200' MD ' ' ' ' ' ' ' ' 532 0 .. � r � X3.1 y l' B -17 L2- O1 -PB1 _ nr 'gift _ v _ - 44,.., l apppr 89 191M-6304'S . - ----. =7. 11 11.111_ , _ •._ . _ ; . _ H !i i . - : , _.-.;,,,Asi D Ilikonsiiii M KAM ' : : , i No d ,. i i 14%11 -5350 - 1 irr. a tctil r r Fault A 1B -17 L2 -01 _E_ - _ _ - 1TDTS Well Plan S - - - - , -6375 _ _4_- 4_ 4__ ___-_ __ ------ f ____ _ f ___ ------ r __ T ____ _f _ ___ r__i__ --- ------ r __r__T 1111 . :::: '" DTE ' __4_- ..:___ _ f __ __,______ __,_ r ---- i - __ __ __,___ f ____ f __ r __ r __ r ------ f __ __ ...4.__ .; __ ____ _ _. -_- __. __4._ __ __ __-, ------ r__ __-, ------ r ---- -,__ _ __ _f __ r - _ T __ _____ __r r r -,__ ---r-4--4-- ___ __ __i ------ f __ -6450 - -6475 • • . . . 6700 6900 7100 7300 7500 7700 7900 8100 8300 8500 8700 8900 9100 9300 9500 9700 Vertical Exaggeration: - 4.8 x Measured Depth 1 s ( ` i k ¢ r 'I I f SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS aka 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMIIIISSION j ANCHORAGE, ALASKA 99501 -3539 t' PHONE (907) 279 -1433 a FAX (907) 276 -7542 Mr. V. Cawvey Wells Manager ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, Kuparuk River Oil Pool, 1B- 17L2 -01 ConocoPhillips Alaska, Inc. Permit No: 209 -133 Surface Location: 502' FNL, 154' FEL, Sec. 9, Ti 1 N, R 10E, UM Bottomhole Location: 1835' FNL, 2857' FWL, Sec. 10, Ti 1N, R10E, UM Dear Mr. Cawvey: 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 KRU 1B -17, Permit No. 1940450, API No. 50- 029 - 22461 -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 Commission 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 Commission 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 a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). Sincerely, 0 Daniel T. Seamount, Jr. / Chair DATED this (p day of November, 2009 cc: Department of Fish $s Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. ► RECEIVED 0 • STATE OF ALASKA OCT 2 8 2009 ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL Alaska Gil & Gas Cons. Commission 20 AAC 25.005 Anchorage 1 a. Type of Work: 1 b. Current Well Class: Exploratory ❑ Development Oil Q • 1c. Specify if well is proposed for: Drill ❑ Re -drill El Stratigraphic Test ❑ Service ❑ Development Gas ,1 Coalbed Methane ❑ Gas Hydrates ❑ Re -entry ❑ Multiple Zone❑ Single Zone jY L '1 Shale Gas ❑ 2. Operator Name: 5. Bond: LJ Blanket ❑ Single Well 11. Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59 - 52 - 180 1B ' 3. Address: 6. Proposed Depth: 12. Field /Pool(s): P.O. Box 100360 Anchorage, AK 99510 - 0360 MD: 9650' • TVD: 6376' • Kuparuk River Field • 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 502' FNL, 154' FEL, Sec. 9, T11N, R10E, UM • ADL 25648 . Kuparuk River Oil Pool • Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1671' FNL, 1754' FWL, Sec. 10, T11N, R10E, UM 466 12/1/2009 Total Depth: 9. Acres in Property: 14. Distance to 1835' FNL, 2857' FWL, Sec. 10, T11N, R10E, UM 2560 Nearest Property: 19350' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: . 102 fee 15. Distance to Nearest Well Open Surface: x - 550285 • y - 5969647 • Zone 4 KB Elevation above GL: 6f ��eet o Same Pool: 1B -08AL1 , 1645' • 16. Deviated wells: Kickoff depth: 8300. ft. 17. Maximum Anticipated Pressures in psig (see 20 MC 25.035) Maximum Hole Angle: 94° d Downhole: 2113 psig . Surface: 1457 psig • 18. Casing Program Specifications Setting Depth Quantity of Cement Size Top Bottom c. f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2 - 3/8" 4.7# L - 80 ST - L 2740' 6910' 6326' 9650' 6376' 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) 7500' 6957' 7392' 6857' Casing Length Size Cement Volume MD TVD Conductor /Structural 80' 16" 205 sx AS 1 120' 120' Surface 4200' 9 -5/8" 950 sx AS III, 400 sx CI G 4241' 4178' Intermediate Production 6588' 7" 225 sx Class G 6629' 6188' Liner 1184' 5" 160 sx Class G 7477' 6936' Perforation Depth MD (ft): Perforation Depth TVD (ft): 6907'- 6967', 7013' -7053' 6425'- 6478', 6518' -6553' 20. Attachments: Filing Fee ❑ BOP Sketch 0 Drilling Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Property Plat ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program gi 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact J. Long @ 263 - 4093 / .1,c i 0 la.111)1 Printed Name V. Cawvey Title Wells Manager C 1 Signature 2 Phone p;* . 6,364c, Date lo/- / ©, Commission Use Only Permit to Drill API Number: Permit Approv 0 /// See cover letter Number: 2r4/3 C 50- 1 ct`-2 2— / 6 2— I Date: j/ / /if £ for other requirements Conditions of approval : If box is checked, - well may not be used to explore for, test, or produce coalbed me ane, gas hydrates, or gas contained in shales: 3560 p "- L3iP rr r Samples req'd: Yes ❑ No Mud log req'd: Yes ❑ No Other: 2 �� ,L Anh + vlci r H2S measures: Yes Er' No ❑ Directional svy req'd: Yes [► No ❑ -q03 re8ctc.rt-X ,--c9 coK'er k - °� j_ 1 `c1 r. ! � APPROVED BY THE COMMISSION 6 D A TE: i , • , ° ' , / � COMMISSIONER Form 1 -401 (Revised 1/2009) � .� it L `� Duplicate • • C onoc�Philii ps Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 1B Pad 1B-17 1B-17 L2 -01 Plan: Plan 4, 1B-17 L2 -01 Standard Planning Report 19 October, 2009 FS. BAKER HUGHES ORIGINAL ConocoPhillips ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co- ordlnate Reference: Well 1 B - 17 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project::; Kuparuk River Unit MD Reference: ._ 1B-17 (a) 102.00ft (1B-17) Site: Kuparuk 1B Pad North Reference: - True . Weil: 1 B - 17 Survey Calculation Method: Minimum Curvature Wellborn: 1 B -17 L2 Design: Plan 4, 1B-17 L2 -01 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 1B Pad Site Position: Northing: 5,969,646.72ft Latitude: 70° 19' 40.290 N From: Map Easting: 549,457.39ft Longitude: 149° 35' 56.057 W Position Uncertainty: 0.00 ft Slot Radius: " Grid Convergence: 0.38 ° Well 1 B -17 Well Position +N / - 0.00 ft Northing: 5,969,647.14 ft • Latitude: 70° 19' 40.240 N +E/ - 0.00 ft Easting: 550,285.37 ft . Longitude: 149° 35' 31.884 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 61.00ft . Wellbore 1B-17 L2 -01 Magnetics Model Name Sample Date Declination Dip Angle Field Strength r) (0) (nT) BGGM2009 12/2/2009 17.45 79.81 57,361 Design Plan 4, 1 B -17 L2 -01 Audit Notes: Version: Phase: PLAN Tie On Depth: 8,300.00 Vertical Section: Depth From (TVD) +W-S +E/ -W Direction (ft) (ft) (ft) C) - 61.00 0.00 0.00 98.00 Plan, Sections Measured TVD Below Dogleg Build Turn Depth _ Inclination Azimuth System +r4/-S +E/ -W Rate Rate Rate TFO (ft) O (0) (ft). (ft) (ft) ( ( ° /100ft) ( ° /100ft) ( Target 8,300.00 95.65 34.02 6,293.21 - 1,169.40 1,909.88 0.00 0.00 0.00 0.00 8,453.00 65.54 39.59 6,317.95 - 1,049.79 1,998.97 20.00 -19.68 3.64 170.00 8,493.00 72.16 44.40 6,332.38 - 1,022.11 2,023.94 20.00 16.57 12.03 35.00 8,568.00 84.16 53.62 6,347.77 - 974.20 2,079.27 20.00 16.00 12.29 38.00 8,668.00 85.20 73.68 6,357.13 - 930.25 2,168.03 20.00 1.04 20.06 88.00 8,788.00 86.83 97.68 6,365.60 - 921.33 2,286.52 20.00 1.36 20.00 87.00 8,873.00 90.16 114.36 6,367.84 - 944.71 2,367.89 20.00 3.92 19.62 79.00 9,028.00 94.25 145.12 6,361.72 - 1,042.48 2,485.57 20.00 2.64 19.84 82.00 9,178.00 90.20 115.37 6,355.77 - 1,138.17 2,598.70 20.00 -2.70 -19.84 263.00 9,228.00 86.95 105.90 6,357.01 - 1,155.77 2,645.42 20.00 -6.49 -18.93 251.00 9,318.00 86.79 123.93 6,361.96 - 1,193.47 2,726.58 20.00 -0.18 20.03 91.00 9,388.00 87.37 137.94 6,365.54 - 1,239.16 2,779.26 20.00 0.83 20.01 88.00 9,650.00 88.40 85.51 6,375.95 - 1,332.67 3,014.08 20.00 0.39 -20.01 270.00 10/19/2009 2 :50 :05PM Page 2 COMPASS 2003.16 Build 69 ORIG11'-\.!C\L ConocoPhillips mai Conoco Phillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co- ordinate Reference:. Well 1 B - 17 Company ConocoPhillips(Alaska) Inc. . Reference: Mean Sea Level Project Kuparuk River Unit MD Reference: 1 B -17 © 102.00ft (1 B-17) Site: Kuparuk 1B Pad North Reference: True Well: _ = 1B -17 Survey Calculation Method: Minimum Curvature Wellbore: ' 1B L2 - 01 Design: Plan 4, 18 - 17 L2 - 01 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map DOPE Inclination ' Azimuth System +WS +E/ -W Section Rate Azimuth Northing Easting (ft ( ° I , (ft) (ft) (ft) (ft) ('MOOR) rj (ft) 8,300.00 95.65 34.02 6,293.21. - 1,169.40 1,909.88 2,054.04 0.00 0.00 5,968,490.68 552,202.86 TIP / KOP 1B L2 8,400.00 75.96 37.53 6,300.49 - 1,088.87 1,967.85 2,100.24 20.00 170.00 5,968,571.59 552,260.28 8,453.00 65.54 39.59 6,317.95 - 1,049.79 1,998.97 2,125.62 20.00 169.74 5,968,610.88 552,291.14 2 8,493.00 72.16 44.40 6,332.38 - 1,022.11 2,023.94 2,146.49 20.00 35.00 5,968,638.72 552,315.92 3 8,500.00 73.27 45.30 6,334.46 - 1,017.37 2,028.65 2,150.50 20.00 38.00 5,968,643.49 552,320.60 8,568.00 84.16 53.62 6,347.77 - 974.20 2,079.27 2,194.62 20.00 37.73 5,968,686.99 552,370.92 4 8,600.00 84.42 60.05 6,350.95 - 956.79 2,105.91 2,218.57 20.00 88.00 5,968,704.57 552,397.44 8,668.00 85.20 73.68 6,357.13 - 930.25 2,168.03 2,276.40 20.00 87.36 5,968,731.53 552,459.38 5 8,700.00 85.56 80.09 6,359.71 - 923.02 2,199.08 2,306.14 20.00 87.00 5,968,738.97 552,490.37 8,788.00 86.83 97.68 6,365.60 - 921.33 2,286.52 2,392.49 20.00 86.48 5,968,741.24 552,577.79 6 8,800.00 87.29 100.04 6,366.21 - 923.18 2,298.36 2,404.48 20.00 79.00 5,968,739.47 552,589.64 8,873.00 90.16 114.36 6,367.84 - 944.71 2,367.89 2,476.32 20.00 78.88 5,968,718.41 552,659.31 7 8,900.00 90.91 119.71 6,367.58 - 956.98 2,391.93 2,501.84 20.00 82.00 5,968,706.30 552,683.431 9,000.00 93.57 139.55 6,363.63 - 1,020.38 2,468.50 2,586.49 20.00 82.05 5,968,643.43 552,760.42 9,028.00 94.25 145.12 6,361.72 - 1,042.48 2,485.57 2,606.46 20.00 82.83 5,968,621.44 552,777.63 8 9,100.00 92.38 130.82 6,357.53 - 1,095.73 2,533.57 2,661.41 20.00 -97.00 5,968,568.52 552,825.98 .I 9,178.00 90.20 115.37 6,355.77 - 1,138.17 2,598.70 2,731.81 20.00 -97.83 5,968,526.52 552,891.391 9 9,200.00 88.76 111.21 6,355.97 - 1,146.87 2,618.90 2,753.03 20.00 - 109.00 5,968,517.96 552,911.64 9,228.00 86.95 105.90 6,357.01 - 1,155.77 2,645.42 2,780.52 20.00 - 108.96 5,968,509.24 552,938.22 10 9,300.00 86.80 120.33 6,360.96 - 1,183.91 2,711.36 2,849.75 20.00 91.00 5,968,481.54 553,004.34 9,318.00 86.79 123.93 6,361.96 - 1,193.47 2,726.58 2,866.14 20.00 90.21 5,968,472.08 553,019.6211 11 9,388.00 87.37 137.94 6,365.54 - 1,239.16 2,779.26 2,924.67 20.00 88.00 5,968,426.75 553,072.60 1 12 9,400.00 87.37 135.54 6,366.09 -1,247.89 2,787.47 2,934.02 20.00 -90.00 5,968,418.08 553,080.87 9,500.00 87.57 115.52 6,370.55 - 1,305.64 2,868.37 3,022.16 20.00 -89.89 5,968,360.87 553,162.141 9,600.00 88.06 95.51 6,374.40 - 1,332.23 2,964.17 3,120.73 20.00 -89.00 5,968,334.93 553,258.111 • 9,650.00 88.40 85.51 6,375.95 - - 1,332.67 3,014.08 3,170.22 20.00 -88.23 5,968,334.83 553,308.02 TD 1 10/19/2009 2 :50:05PM Page 3 COMPASS 2003.16 Build 69 ConocoPhillips • ConocoPhillips Planning Report BAKER Alaska Database: EDM Alaska Prod v16 Local Co- ordinate Reference: Well 1 B -17 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project Kuparuk River Unit MD Reference: 1 B -17 @ 102.00ft (1B-17) Site: Kuparuk 1B Pad North Reference: True Well: 1 B - 17 Survey Calculation Method: Minimum Curvature Wellbore: 1 B -17 L2 -01 Design: Plan 4, 1B-17L2-01 Targets Target Name , - hfUmiss target Dip Angle Dip Dir. TVD +14/-S +E/-W Northing Easting - Shape ( ) (°) (ft) (ft) (ft) (ft) (ft) Latitud L g ft u d e 1B -17 L2 -01 t1.4 0.00 0.00 6,332.00 - 1,007.17 1,990.37 5,968,653.43 552,282.25 70°19' 30.332 N 149° 34' 33.788 W - plan misses target center by 34.78ft at 8482.23ft MD (6328.92 TVD, - 1029.47 N, 2016.88 E) - Point 1B -17 L2 -01 Polygon 0.00 0.00 0.00 - 1,579.63 860.41 5,968,073.46 551,156.27 70° 19' 24.704 N 149° 35' 6.771 W - plan misses target center by 6393.29ft at 8300.00ft MD (6293.21 TVD, - 1169.40 N, 1909.88 E) - Polygon Point 1 0.00 - 1,579.63 860.41 5,968,073.46 551,156.27 Point 2 0.00 - 1,912.63 1,005.21 5,967,741.47 551,303.28 Point 3 0.00 - 1,802.14 1,534.01 5,967,855.49 551,831.28 Point 4 0.00 - 1,732.50 1,740.50 5,967,926.51 552,037.27 Point 5 0.00 - 1,450.78 1,938.40 5,968,209.52 552,233.26 Point 6 0.00 - 1,217.34 2,026.96 5,968,443.53 552,320.25 Point 7 0.00 - 1,098.91 2,114.76 5,968,562.53 552,407.24 Point 8 0.00 - 1,077.53 2,207.91 5,968,584.53 552,500.24 Point 9 0.00 - 1,116.55 2,359.67 5,968,546.53 552,652.24 Point 10 0.00 - 1,254.44 2,641.79 5,968,410.55 552,935.25 Point 11 0.00 - 1,381.91 3,010.98 5,968,285.57 553,305.25 Point 12 0.00 - 1,382.60 3,114.99 5,968,285.58 553,409.26 Point 13 0.00 - 1,170.94 3,170.40 5,968,497.58 553,463.24 Point 14 0.00 - 1,148.29 3,072.54 5,968,519.57 553,365.24 Point 15 0.00 - 945.25 2,768.86 5,968,720.55 553,060.24 Point 16 0.00 - 796.03 2,437.81 5,968,867.54 552,728.23 Point 17 0.00 - 782.39 2,040.85 5,968,878.52 552,331.22 Point 18 0.00 - 1,031.36 1,882.18 5,968,628.51 552,174.24 Point 19 0.00 - 1,150.72 1,783.37 5,968,508.51 552,076.24 Point20 0.00 - 1,373.16 1,694.88 5,968,285.50 551,989.25 Point21 0.00 - 1,551.82 1,491.67 5,968,105.50 551,787.26 Point 22 0.00 - 1,625.70 1,170.14 5,968,029.47 551,466.27 Point 23 0.00 - 1,515.13 936.85 5,968,138.47 551,232.26 Point 24 0.00 - 1,579.63 860.41 5,968,073.46 551,156.27 1B-17 L2 -01 t4.4 0.00 0.00 6,362.00 - 1,198.09 2,719.16 5,968,467.42 553,012.24 70°19' 28.452 N 149° 34' 12.517 W - plan misses target center by 7.95ft at 9314.18ft MD (6361.75 TVD, - 1191.36 N, 2723.40 E) - Point 1B -17 L2 -01 Fault 3 0.00 0.00 0.00 - 1,148.77 1,036.32 5,968,505.45 551,329.27 70° 19' 28.941 N 149° 35' 1.636 W - plan misses target center by 6353.58ft at 8300.00ft MD (6293.21 TVD, - 1169.40 N, 1909.88 E) - Polygon Point 1 0.00 - 1,148.77 1,036.32 5,968,505.45 551,329.27 Point 2 0.00 - 1,388.40 1,577.79 5,968,269.47 551,872.28 Point 3 0.00 - 1,376.05 1,825.90 5,968,283.49 552,120.27 Point 4 0.00 - 1,370.07 1,978.96 5,968,290.49 552,273.28 Point 5 0.00 - 1,706.72 3,123.86 5,967,961.55 553,420.30 Point 6 0.00 - 1,370.07 1,978.96 5,968,290.49 552,273.28 Point 7 0.00 - 1,376.05 1,825.90 5,968,283.49 552,120.27 Point 8 0.00 - 1,388.40 1,577.79 5,968,269.47 551,872.28 1B-17 L2 -01 t2.4 0.00 0.00 6,368.00 - 956.69 2,365.75 5,968,706.42 552,657.24 70° 19' 30.827 N 149° 34' 22.830 W - plan misses target center by 11.79ft at 8876.54ft MD (6367.83 TVD, - 946.19 N, 2371.10 E) - Point 1B-17 L2 -01 Fault 4 0.00 0.00 0.00 - 881.55 2,643.28 5,968,783.41 552,934.24 70° 19' 31.565 N 149° 34' 14.729 W - plan misses target center by 6339.98ft at 8400.00ft MD (6300.49 TVD, - 1088.87 N, 1967.85 E) - Polygon Point 1 0.00 - 881.55 2,643.28 5,968,783.41 552,934.24 Point 2 0.00 - 1,067.59 2,646.04 5,968,597.41 552,938.25 Point 3 0.00 - 1,277.64 2,649.65 5,968,387.41 552,943.26 Point 4 0.00 - 1,067.59 2,646.04 5,968,597.41 552,938.25 1 10/19/2009 2:50:05PM Pagp,4 r COMPASS 2003.16 Build 69 ikjii4‘ it- • ConocoPhillips la a ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co- ordinate Reference: Well 1 B - 17 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project Kuparuk River Unit. MD Reference: 1 B -17 © 102.00ft(1 B -17) Site: Kuparuk 1B Pad North Reference: True Well: 1B - 17 Survey, Calculation Method: Minimum Curvature Wellborn: 1 B - 17 L2 - 01 Design: Plan 4, 1B-17 L2 -01 1B -17 L2 -01 t5.4 0.00 0.00 6,376.00 - 1,324.99 3,000.34 5,968,342.42 553,294.23 70° 19' 27.203 N 149° 34' 4.312 W - plan misses target center by 8.44ft at 9636.19ft MD (6375.55 TVD, - 1333.42 N, 3000.29 E) - Point 1B -17 L2 -01 t3.4 0.00 0.00 6,356.00 - 1,134.25 2,594.58 5,968,530.42 552,887.24 70° 19' 29.080 N 149° 34' 16.153 W - plan misses target center by 1.75ft at 9172.38ft MD (6355.80 TVD, - 1135.71 N, 2593.65 E) - Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name ( ") ( ") 9,650.00 6,375.95 2 - 3/8" 2 - 3/8 3 Plan Annotations Measured Vertical Local Coordinates Depth Depth +W-$ +EI W (ft) (ft) (ft) (ft) Comment 8,300.00 6,293.21 -1,169.40 1,909.88 TIP / KOP 1B-17 L2 8,453.00 6,317.95 - 1,049.79 1,998.97 2 8,493.00 6,332.38 - 1,022.11 2,023.94 3 8,568.00 6,347.77 - 974.20 2,079.27 4 8,668.00 6,357.13 - 930.25 2,168.03 5 8,788.00 6,365.60 - 921.33 2,286.52 6 8,873.00 6,367.84 - 944.71 2,367.89 7 9,028.00 6,361.72 - 1,042.48 2,485.57 8 9,178.00 6,355.77 - 1,138.17 2,598.70 9 9,228.00 6,357.01 - 1,155.77 2,645.42 10 9,318.00 6,361.96 - 1,193.47 2,726.58 11 9,388.00 6,365.54 - 1,239.16 2,779.26 12 9,650.00 6,375.95 - 1,332.67 3,014.08 TD 10/19/2009 2:50.05PM Page 5 COMPASS 2003.16 Build 69 0 R r% t, 1 Project: Kuparuk River Unit A�m to T Norm WELLBORE DETAILS: 1B-17 L2 -01 REFERENCE INFORMATION �-^ Megneg N nn 21.98 Site: Kuparuk 18 Pad Coordinate WE Reference Well 16-17, True North ,. Magnetic Fiats Parent Wellbore: 1B - 17 L2 ( ) " " Well:. 1 B - strength 57x49. Vertical (ND) Reference: Mean Sea Level BAKER T ie on M 8 300.00 /��/1 1 Wellboro: 16-17 L2 -01 Dip Angle 8085° Section Depth Reference: 1B -17 102. Reference: Slot - (0.00N, 005 Measured D (1 �Q V W � 1'.� Plan: Plan 4, 18 - 17 L2 - 01 (1B 17/18 - 17 L2 - 01) Moe IraBCCM2 epth 008 (18 -17) 14 I4ES Calculation Method. Minimum Curvature -200 _ __. ___.. - 300 - ',., WELL DETAILS: 1B -17 Ground Level: 61.00 -400 +N/-S +E / -W Northing Easting Latittude Longitude Slot 0.00 0.00 5969847.14 550285.37 70° 19' 40.240 N 149° 35' 31.884 W -500. SECTION DETAILS ANNOTATIONS _600 - . Sec MD Inc Azi TVDSS +NI -S +E/ -W DLeg TFace VSec Target Annotation 1 8300.00 95.65 34.02 6293.21 - 1169.40 1909.88 0.00 0.00 2054.04 TIP / KOP 1B-17 L2 700 2 8453.00 65.54 39.59 6317.95 - 1049.79 1998.97 20.00 170.00 2125.62 2 3 8493.00 72.16 44.40 6332.38 - 1022.11 2023.94 20.00 35.00 2146.49 3 4 8568.00 84.16 53.62 6347.77 - 974.20 2079.27 20.00 38.00 2194.62 4 -800- - s, 6 5 8668.00 85.20 73.68 6357.13 - 930.25 2168.03 20.00 88.00 2276.40 5 6 8788.00 86.83 97.68 6365.60 -921.33 2286.52 20.00 87.00 2392.49 6 c -900- q 7 8873.00 90.16 114.36 6367.84 - 944.71 2367.89 20.00 79.00 2476.32 7 8 9028.00 94.25 145.12 6361.72 - 1042.48 2485.57 20.00 82.00 2606.46 8 . + / 9 9178.00 90.20 115.37 6355.77 - 1138.17 2598.70 20.00 263.00 2731.81 9 8 10 9228.00 86.95 105.90 6357.01 - 1155.77 2645.42 20.00 251.00 2780.52 10 4 i; i .: ., :'. 11 9318.00 86.79 123.93 6361.96 - 1193.47 2726.58 20.00 91.00 2866.14 11 p -1 100- ik 12 9388.00 87.37 137.94 6365.54 - 1239.16 2779.26 20.00 88.00 2924.67 12 13 9650.00 88.40 85.51 6375.95 - 1332.67 3014.08 20.00 270.00 3170.22 TD - 1200 „-.r : 1 o 1 poe>ssrsok 0 -1400 / TIP / KOP 1B -17 L2 _1500_ 1B- 17/16 -17 L2.01 ft, -1600 _. _ _... -1700 IB ]7/]B -17 LI 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 West( -) /East( +) (100 ft /in) 6050 6100 , C 6150 w 6200_ tn TIP / KOP IB -17 L2 ,4 6250_ - ' = -' ` d 6300 ... - J 2 .. 3 _.. .... _ _.... - . m - + 4 10 1B- 17/1B -17 L2-01 V » c 6350 -. 6 7 8 F 11 12 s' t ill q TD � � 6400 10- ..17/1B -17 LI 6450 ,,.., 6500 ,, 6550 ! !, I. _. �._ -.. -� 1800 1850 1900 1950 2000 2050 2100 2150 2200 2250 2300 2350 2400 2450 2500 2550 2600 2650 2700 2750 2800 2850 2900 2950 3000 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 Vertical Section at 98.00° (50 ft/in) . ConocoPhillips RECEIVED Alaska P.O. BOX 100360 ®C T 2 8 2009 ANCHORAGE, ALASKA 99510 -0360 October 27, 2009 AI flit s Cons® Co 'seen Anchorage 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 three lateral sidetracks out of Kuparuk Well 1 B -17 (PTD# 194 -045) using the coiled tubing drilling rig, Nabors CDR2 -AC. Work is scheduled to begin on 1B-17 as early as December 2009. The CTD objective is to drill three lateral sidetracks (1B-17 L1, 1B-17 L2, and 1B-17 L2 -01) targeting the C1 & C3 /C4 sands across faults into unsupported areas. The well will be pre - produced for approximately 6 months and then converted to injection service. Because the conversion will not occur immediately, these permit to drill applications are for production service. In preparation for the conversion, however, the following work has already been done to identify any issues that need to be addressed before proceeding with the sidetracks. — The Quarter Mile Injection Review is included in this packet. — The cement bond log was sent to Guy Schwartz (AOGCC) on Friday, October 23, for review. Attached to this application are the following documents that explain the proposed job operations: — Permit to Drill Application Forms for 1B-17L1, 1B-17 L2, and 1B-17L2-01 — Proposed Schematic — BOP Schematic — Detailed Summary of Operations — Directional Plans If you have any questions or require additional information please contact me at 907 - 263 -4093. Sincerely, Jill L•l � Coiled Tubing Drilling Engineer Permmto Drill Summary of Opel KRU 1B-17 L1, 1B-17 L2, and 1B-17 L2 -01 Lateral Coiled Tubing Drilling Overview: Well 1B -17 is a C -sand producing, single completion well equipped with 4" tubing (from surface to 3554' MD), 3.5" tubing (from 3554' to 6743' MD), and a 5" production liner (from 6305' to 7477' MD). The upper completion consists of a 3.5" TRDP -4A surface controlled subsurface safety valve, six gas lift mandrels, and a 3.5" D nipple in the tubing tail. The existing perforations in the 1B-17 completion will remain open after the three proposed CTD laterals are drilled and completed. CTD will mill the first 5" window by kicking off of the 3.5" x 5" flow- through whipstock set pre -rig at — 6980'. The first lateral, 1B -17 L1, will land in the B5 shale and then invert upward to intersect the C1. Drilling will continue, crosscutting up through the C1 until reaching the target top of C1 pay. After reaching the target, drilling will turn downwards, crosscuting towards the base of the C1 sands until TD ( -8975' MD). The 1995' lateral will be drilled with a 2.70" x 3" bi- center bit on 2" e coil, as will all the subsequent laterals. The completion will consist of a 2 slotted liner (8 slots per foot) across the C1 pay; the B5 shale section will be covered with 2 solid liner. The liner top will be placed inside the tubing, just above the whipstock. After the 1B-17 L1 lateral is complete, the second 3.5" x 5" flow- through whipstock will be set inside the 5" liner at —6906' MD. The second window will then be milled by kicking off the whipstock. Drilling of the 1B-17 L2 lateral then begin, landing in the upper C1 and inverting up to crosscut the C3 /C4 prior to crossing Fault #3. After crossing Fault #3, the well path is planned to invert up through the C2 and intersect the C3 /C4 pay to crest 5' below the top of the C4. Drilling with then turn downwards, crosscutting to the base of the C3 and reaching TD at —9600'. The completion will consist of a 2 slotted liner (8 slots per foot) from TD to —8300' where an openhole anchored billet will be set for kicking off the next lateral. The 1B-17 L2 -01 lateral will exit (low -side) off the anchored billet set in the L2 lateral at —8300' MD' The kickoff will take place in the C2 and the well will then be directed down into the C1 sands, inverting up to the top of the C1 pay. After the target is reached, the well will be drilled down, crosscutting to the base of the C1 to TD at —9650' MD. The completion will consist of 2 slotted liner from TD to up across the junction with the 1B-17 L2 lateral. The completion will then continue with blank liner being placed across the C2 sands and finishing with slotted liner to just outside the window. A liner deployment sleeve will be on top of the liner to facilitate re -entry. The upper whipstock will be left in the well for access to the 1B-17 L2 -01 lateral post rig. The drill -in fluid will be Flo-Pro xanthan -based polymer with potassium chloride. The managed pressure drilling - technique will be applied to manage bottom hole pressure, thereby minimizing hole stability problem. Page 1 of 5 Q R I G 1 N L 10/27/2009 Permit to Drill Summary of Ope1'llfions Cont. KRU 117 L1, 1B -17 L2, & 1B -17 L2 -01 Operational Outline Pre -Rig Work 1. Tag fill and obtain a SBHP survey 2. Set lower whipstock (NOTE: kickoff point target depth is 6980') 3. Prepare wellsite for rig arrival Rig Work 1. MIRU Nabors CDR2 -AC rig using 2" coil tubing. NU BOPE and test. 2. Window Milling- Mill 2.74" window at 6980' 3. 1B-17 L1 Lateral a. Drill 2.70" x 3" bi- center lateral to the south at a TD of 8975' MD b. Run the 2005' of 2%" slotted liner from TD to —6970' (just above the whipstock). Blank liner will be placed across the B5 sands. 4. Window Milling a. Set the second 3.5" x 5" Flow- through Whipstock at —6906' MD b. Mill 2.74" window off this whipstock 5. 1B-17 L2 Lateral a. Drill 2.70" x 3" bi- center lateral to the north at a TD of 9600' MD b. Run the 1300' of 2 slotted liner from TD to 8300'. An aluminum billet will be placed at 8300'. 6. 1B-17 L2 -01 Lateral a. Kick off of the open -hole anchored aluminum billet at 8300' MD. b. Drill 2.70" x 3" bi- center lateral to the north at a TD of 9650' MD c. Run the —2740' of 2%" slotted liner from TD to just outside of the window (-6910' MD). Blank liner will be placed across the C2 sands. 7. Freeze protect. ND BOPE. RDMO Nabors CRD2 -AC. Post -Rig Work 1. Obtain SBHP 2. Flowback to tanks for well cleanup 3. Begin production Page 2 of 5 ORIGINAL 10/27/2009 Permit to Drill Summary of OpIkons Cont. KRU 017 L1, 1B -17 L2, & 1B -17 L2 -01 Mud Program • Chloride -based Biozan brine (8.6 ppg) for milling operations, and chloride -based Flo -Pro mud (8.6 ppg) for drilling operations. • There is a SCSSV installed in 1B-17 which should be able to be used during running the 2 %" slotted liner of the completion. This will eliminate the need for kill weight fluid during running of the completion. Disposal: • No annular injection on this well. • Class I I liquids to KRU 1R Pad Class II disposal well • Class II drill solids to Grind & Inject at PBU Drill site 4 • Class I wastes will go to Pad 3 for disposal. New Completion Details: Lateral Name Liner Liner Liner Liner Liner Details Top Btm Top Btm MD MD SSTVD SSTVD 1 B -17 L1 6970 8975 6380 6408 2'/ ", 4.7 #, L -80, ST -L slotted liner across pay sand, blank liner across B5. 2W, 4.7 #, L -80, ST -L slotted. Anchored 1 B -17 L2 8300 9600 6293 6298 billet set on top. 1 B -17 L2 -01 6910 9650 6326 6376 2%", 4.7 #, L -80, ST -L slotted across pay sand, blank across C2 sands. Existing Completion Details: Category OD Weight Grade Connection Top Btm Top Btm Burst Collapse (ppf) MD MD TVD TVD psi psi Conductor 16" 62 H-40 Welded 0 120 0 120 1640 630 Surface 9 5 / 40 J -55 BTC 0 4241 0 4178 3950 2570 Casing 7" 26 L -80 BTC Mod 0 6629 0 6188 7240 5410 Liner 5 " 18.0 L -80 LTC R -3 6293 7477 5911 6936 10140 10490 Tubing 4 " 11 J -55 BTC Mod 0 3554 0 3547 6300 6590 Tubing 3'/z " 9.3 J -55 ABM -EUE 3554 6743 3547 6283 6990 7400 Well Control: • Two well bore volumes of KWF will be available to the rig during drilling operations. The kill weight fluid may or may not be stored onsite, but if it is stored offsite it will be in the Kuparuk Field within a short drive to the rig. • BOP diagram is attached for operations with 2" coil tubing. • Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3500 psi. Maximum potential surface pressure is 1457 psi assuming a gas gradient to surface based on the most recent bottom hole pressure measurement which was 2113 psi at 6417' TVDss on April 7, 2009. An updated SBHP reading is planned prior to rig arrival. • The annular preventer will be tested to 250 psi and 2500 psi. Page 3 of 5 ORIGINAL 10/27/2009 Permit to Drill Summary of OpIkons Cont. KRU 117 L1, 1B -17 L2, & 1B -17 L2 -01 Directional: • See attached directional plans. • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. • Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 1B-17 L1 19800' 1B-17 L2 19300' 1B-17 L2 -01 19350' • Distance to Nearest Well within Pool (toe measured to offset well) Lateral Name Distance Offset Well 1B-17 L1 1905' 1B-07 1B-17 L2 1605' 1 B -08AL1 1B-17 L2 -01 1645' 1 B -08AL1 Logging MWD directional, resistivity, and gamma ray will be run over the entire open -hole sections. Hazards • The most recent H reading on 1B-17 was taken on 08/06/09 and read 30 ppm. All H monitoring equipment will be operational while drilling the 1 B -17 laterals. • Siderite is possible in upper C1 sand. • Higher than expected water saturations may be encountered. If this is the case in any lateral, TD may be called earlier than the planned TD. Quarter Mile Injection Review There are no existing wellbores within a quarter mile of the planned 1B-17 laterals. The closest existing wellbores for each of the planned lateral well paths are as follows: 1B-17 L1 The well with the closest proximity to any point in the 1B-17 L1 planned wellbore trajectory is 1B-18. The closest distance between 1B-18 and 1B-17 L1 is 1455 ft. 1B-18 is a single Kuparuk producer with perforations in the A4, C1, C2, C3 and C4 sands. 1B-17 L2 The well with the closest proximity to any point in the 1B-17 L2 planned wellbore trajectory is 1B-18. The closest distance between 1B-18 and 1B-17 L2 is 1455 ft. 1B-18 is a single Kuparuk producer with perforations in the A4, C1, C2, C3 and C4 sands. 1B-17 L2 -01 The well with the closest proximity to any point in the 1B-17 L2 -01 planned wellbore trajectory is 1B-08. The closest distance between 1B-08 and 1B-17 L2 -01 is 1645 ft. 1B-08 is a multi - lateral injector with two laterals in the C3 /C4 and C1 sands. Motherbore perforations exist in the C3 and C4 sands and are open to injection. Page 4 of 5 !''"1 ?`1 f (NMA 10/27/2009 Permit to Drill Summary of ()pitons Cont. KRU •17 L1, 1B -17 L2, & 1B -17 L2 -01 Managed Pressure Drilling Managed pressure drilling (MPD) techniques will be employed to provide constant bottom hole pressure by using 8.6 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allows for the use of Tess expensive drilling fluid and minimizes fluid losses and /or fracturing at the end of the long well bores. A hydraulic choke for regulating surface pressure is located between the BOPE choke manifold and the mud pits, and will be independent of the BOPE choke. Using this technique will require deployment of the BHA with trapped wellhead pressure. Pressure deployment of the 2%" BHA will be accomplished utilizing the 2%" pipe rams and slip rams. Well 1 B -17 has a SCSSV, so the well should not have to be loaded with overbalanced fluid prior to running the completions. Operating parameters and fluid densities will be adjusted based on real -time bottom hole pressure measurements while drilling and shale behavior. The following charts show the different pressure parameters in both "pumps on" and "pumps off' conditions. Reservoir pressure at the KOP is currently estimated to be 2,096 psi (6980' MD/ 6387' TVD). Milling and Drilling Conditions Pumps On Pumps off Mud weight 8.6 ppg 8.6 ppg Hydrostatic 2856 psi 2856 psi Annular Friction 628 psi 0 psi Surface Choke 0 psi 0 psi TOTAL 3484 psi 2856 psi EMW 10.5 ppg 8.6 ppg *Assume annular friction is 90 psi /1000 ft at 1.5 bpm Reservoir Pressure Wells 1B-03, 1B-18, and 1B-06 are the closest offset wells in the C -sand intervals. They are also the target producing wells for the CTD injection patterns. The most recent static bottom hole pressure readings in each well are as follows: Well name Pressure (psi) SSTVD of Est. Measured Date EMW (ppg) 1B-03 2310 6280 3/10/2007 7.1 1B-18 2450 6350 8/23/2007 7.4 1B-06 2265 6365 3/12/2007 6.8 Page 5 of 5 ORIGINAL 10/27/2009 1 B -17 Proposed CTD Sidetrack Last update= 10/07109 (JWL) . 3 -1/2" Camco TRDP-4A @ 1896' MD mum w . 4" 11# J -55 BTC Mod tubing (surface - 3554' MD) 16" 62# H 40 shoe 3 -1/2" 9.3# J -55 EUE 8rd AB -Mod Tubing (3554' - 6276' MD) @ 121' MD V.W. 3 -1/2" 9.2# J -55 SPCLN BTC -Mod Tubing (6276' - 6743' MD) 5 ", 18 #, L -80, LTC, R -3 Class A (6305' - 7477' MD) "' Camco MMG gas lift mandrels @ 2403', 3590', 4496', 5308', 5904', & 6197' MD 9-5/8" 40# J -55 MN shoe @ 4241' MD r - Baker 80 -40 PBR (10' length with 3" ID seal bore) 1 Baker 7" x 3 -1/2" HB retrievable packer @ 6259' MD 7" 26# L-80 shoe —....... -� 3 -1/2" Camco D landing nipple @ 6274' MD (2.75" min ID) @ 6629' MD G) Tubing Tail @ 6743' MD , 3 -1/2 x 5" Baker Gen 2 flow -by whipstock C - sand perfs @ 6906' MD, leave for access post - rig 6907' - 6967' MD - --- �'"' _ Anchor billet at 8300' MD L2 lateral in C3 /C4 sands (north fault block), TD @ 9,600' MD \ 3" borehole, Slotted liner (2 -3/8 ", 4.6 #, L -80 ST -L) • \ \ ~ ____ — _ — _ — _ — ›) ) � 3 -1/2 x 5" Baker Gen 2 flow- \ oil 1 by whipstock @ 6980' MD — — --- — — — C perfs r \ L2 -01 lateral in C1 sand (north fault block), TD @ 9,650' MD /// 7013' - 7053' MD .7 3" borehole, Slotted liner from TD to across junction (2 -3/8 ", 4.6 #, L -80 ST -L), Blank liner across C2, Slotted liner up to outside the window 5" 18.0# L - 80 shoe — — — ' __ — — — — 1 @ 7477' MD L1 lateral in C1 sand (south fault block), TD @ 8,975' MD ✓♦� 3" borehole, Slotted liner across pay (2 -3/8 ", 4.6 #, L -80 ST -L) Blank liner will be placed across B5 • • Nabors CDR -2AC Kuparuk Managed Pressure Coil Tubing Drilling BOP Configuration for 2" Coil Tubing 7 Lubricator ( I 1 Riser � Annular/ Blind / Shear 2" Pipe / Slip (CT) Pump into Lubricator �� 1 above BHA rams r L r Choke 1 2 -3/8" Pipe / Slip (BHA) r Choke Equalize' Manifold 2 -3/8" Pipe / Slip (BHA) T 1 Kill • > �\� C > <�� I ,, 1 1 �'' 1 Blind / Shear 2" Pipe / Slip (CT) -I Choke 2 Swab Valves 7 Wing Valves J I Tree Flow Cross 1 1 ,At, Surface Safety Valve BOPE: 7- 1/16", 5M psi, TOT Choke Line: 2- 1/16 ", 5M psi Master Valve Kill Line: 2- 1/16 ", 5M psi A Equalizing Lines: 2- 1/16 ", 5M psi Choke Manifold: 3 -1/8 ", 5M psi Riser: 7- 1/16", 5M psi, C062 Union OR IGINAL > r -2 - C 1 -1' , X _2000 � � j� -4 O 0 D of i -200 .- 1 10 �. 0 �/V'J V V - 02 i ) ' � 4 ') I - AIL ) '' `0030001 ? r 40i) C '' -Ct-klzi A L:6 1 i dilfe 19 X l i 1 _________ , --- _3 li } .4 I— r, F '` IL: � ' ( `L' �, �� I -200qi. 1 ' • y ii nIDID , _Ati I' -2000/7 1 i � � �� _ 2ooa 200 , W S ' • _ r ' (I 4 'IL 2000 I44. . • ., I �IIIIIII '30170 0 .3- -50'0 ' 000 - 7. t " . 4 '0 r • Q I ° 5 o111 ` � _soa_ o MoD - , 1� � ''e 1 B -17 3 1 000 tk _ [ � -� a :ii5 1 B -17 2 01 i a - �;,_ /11101°- On y 1 -•: lies within th AOR 100 1 4000 �' 17 L1 within he uparuk Riv i Pool ` 1 B • 4000 moo/ o ° 5[10 _ i A -5000 40 1 18 �, I -4000 0 i ' 1 B-17L -0 ell course lie -301 l0 -5000 f 1 6,250' TVDsu •. ea � 8 • ' gie , f : C PF -01 A /,, Q 1 B-1 5AL2 Tract ID 13 •U-3 -6-23 -026648 I 1 -50D0 1 B -04 4 r 0 '0011 /06 KRU 1 B - 17L2 - 01 Area of Review / 0 1 � 7 1 Well course tick marks are in intervals of 100' TVDsubsea / 1 E -168 sFD 11/3/2009 f • • TRANSMITTAL LETTER CHECKLIST WELL NAME /6 — / 7 PTD# 6 0, l( CO-74- t- ' G L� Gc f &> L�j� 7 (� d�n 4 7 5 t� ,z) V Development Service Exploratory Stratigraphic Test Non- Conventional Well eo FIELD: K—G (; ,-G< Kic —�� POOL: (1 t �c E. �/r / c^),) Circle Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK ADD -ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well /mil ( lg / 7 (If last two digits in Permit No. /9 /s , API No. so-6 7j*- 2_2 - . API number are between 60 -69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(D, all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non - Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: 1/11/2008 -11111111.1®11 Field & Pool KUPARUK RIVER - 490000 Well Name: _ KUPARUK RIV UNIT 1B- 17L2 -01 _ Program DEV Well bore seg tg PTD#: 2091330 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 On /Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes Entire horizontal lateral wellbore will lie within ADL 25648 3 Unique well name and number Yes 4 Well located in a defined pool Yes Kuparuk River Oil Pool, govemed by Conservation Order No. 432C 5 Well located proper distance from drilling unit boundary Yes Conservation Order No. 432C contains no spacing restrictions with respect to drilling unit 6 Well located proper distance from other wells Yes boundaries and no interwell spacing restrictions. Wellbore will be more than 3 -1/2 miles 7 Sufficient acreage available in drilling unit Yes from an external property line where ownership or landownership changes. 8 If deviated, is wellbore plat included Yes 9 Operator only affected party - - Yes 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval - Yes SFD 11/3/2009 13 Can permit be approved before 15 -day wait Yes 14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For Yes • 15 All wells within 1/4 mile area of review identified (For service well only) Yes - KRU 1B-08 16 Pre - produced injector: duration of pre production less than 3 months (For service well only) Yes Spoke wellbore - well will be produced for —6 months, then converted to injection. 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A -D) NA 18 Conductor string provided NA Conductor set in 1 B -17 Engineering 19 Surface casing protects all known USDWS NA Surface casing set in 1B -17 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing cemented to GL in 1 B -17 21 CMT vol adequate to tie -in long string to surf csg NA Production casing set in 1 B -17 22 CMT will cover all known productive horizons No OH slotted liner completion 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankageor reserve pit Yes Rig equipped with steel pits. All waste to approved disposal wells. 25 If a re- drill, has a 10 -403 for abandonment been approved NA Using flowthrough whipstocks to allow 1 B -17 (motherbore) to flow after Laterals are drilled. - 26 Adequate wellbore separation proposed Yes Proximity analysis perfromed. No issues. 27 If diverter required, does it meet regulations NA Wellhead already in place. BOP stack installed. Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pressure = 2113 psi (6.3 ppg) .. Drilling with 8.6 ppg mud ( using MPD technique) - - - GLS 11/4/2009 29 BOPEs,do they meet regulation Yes - - 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP= 1457 psi. Will test BOP to 3500 psi 31 Choke manifold complies w /API RP -53 (May 84) Yes • 32 Work will occur without operation shutdown Yes - - 33 Is presence of H2S gas probable Yes H2S reported on 1B pad. Rig has sensors and alarms. 34 Mechanical condition of wells within AOR verified For service well only) Yes Well plan is to convert to injector after 6 month ofpre- production. AOR complete. 35 Permit can be issued w/o hydrogen sulfide measures No 1B-17 measured 30 ppm H2S on 8/6/09; measures required. Geology 36 Data presented on potential overpressure zones Yes Expected reservoirpressure is 6.3 ppg EMW; will be drilled with 8.6 ppg mud using Managed Appr Date 37 Seismic analysis of shallow gas zones NA Pressure Drilling techniques. SFD 11/3/2009 38 Seabed condition survey (if off_ - shore) NA 39 Contact name /phone for weekly progress reports [exploratory only] NA Geologic Engineering P • ' Spoke wellbore. Will be pre - produced for about 6 months prior to conversion to injector. Commissioner: Date: Commissioner: Date o ner Date //- 6 -61 / //-Z -- Op