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HomeMy WebLinkAbout210-016 • • Image Project Weil 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 b direct inspection of the file. o - DJ Well History File Identifier Organizing (done) Two -sided III 11111111 III 11111 ❑ Rescan Needed II 111111 RE AN DIGITAL DATA OVERSIZED (Scannable) olor Items: ❑ Diskettes, No. ❑ Maps: Greyscale Items: ❑Other, No/Type: ❑ Other Items Scannable by a Large Scanner Poor Quality Originals: OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: BY: Date: c 9.12--g/ll /s/ P Project Proofing 11111111111 I III / BY: Maria Date: ' �. � U 1 /sl MP Scanning Preparation c L x 30 = (0 + 7 = TOTAL PAGES 6 7 (Count does not include cover sheet) t/yj� BY: ` f Mari Date: / A gg p ( /s/ r Y Production Scanning 111111111111111 Stage 1 Page Count from Scanned File: 10 U (Count does include cover et) Number in Scanning Preparation: YES Page Count Matches g NO p _ BY: Date: 19#, r 1 /s/ I. p Sta 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. A11111111111 ReScanned I 1 BY: Maria Date: /s/ Comments about this file: Quality Checked III IIIIII III (111111 12/22/2011 Well History File Cover Page.doc DATA SUBMITTAL COMPLIANCE REPORT 10/20/2011 Permit to Drill 2100160 Well Name /No. KUPARUK RIV UNIT 1E- 15AL2 -01 Operator CONOCOPHILLIPS ALASKA INC API No. 50- 029 - 20769 -62 -00 MD 9765 TVD 6365 Completion Date 4/20/2010 Completion Status 1WINJ Current Status WAGIN UIC Y REQUIRED INFORMATION Mud Log No Samples No Directional Survey DATA INFORMATION Types Electric or Other Logs Run: gr / res (data taken from Logs Portion of Master Well Data Maint Well Log Information: III Log/ Electr Data Digital Dataset Log Log Run Interval OH / Tye Med /Frmt Number Name Scale Media No Start Stop CH Received Comments ED C Lis 19777 kee Notes 7363 9766 Open 6/17/2010 EWR LIS plus PDF, CGM, and TIFF Graphics g Induction /Resistivity 2 Col 7689 9765 Open 6/17/2010 MD MPR, GR og Induction /Resistivity 5 Col 7689 9765 Open 6/17/2010 MD MPR, GR Log Induction /Resistivity 5 Col 7689 9765 Open 6/17/2010 TVD MPR, GR C Asc Directional Survey 7680 9765 Open ..Rpt Directional Survey 7680 9765 Open Well Cores /Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments • ADDITIONAL INFORMATION Well Cored? Y 1k$ Daily History Received? N Chips Received? -/-id' Formation Tops N Analysis 1 Received? Comments: _IL Compliance Reviewed By: _ Date: A.0 1 6 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMIS* REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Abandon r Repair w ell r Rug Perforations r Stimulate f Other © PROD to WAG Alter Casing r Rill Tubing r ; Fbrforate New Fool r Waiver r Time Extension r Change Approved Program r Operat. Shutdow n r Perforate rj Re -enter Suspended Well r 2. Operator Name: - 4. Current Well Status: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development gz Exploratory r 210 -016 3. Address: 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 Stratigraphic Service ❑ 50 029 - 20769 - 62 7. Property Designation: 8. Well Name and Number: ADL 25651 1 E - 15AL2 - 9. Field /Pool(s): Kuparuk River Field / Kuparuk Oil Pool 10. Present Well Condition Summary: Total Depth measured 9765 feet Plugs (measured) None true vertical 6365 feet Junk (measured) None Effective Depth measured 9765 feet Packer (measured) 7322, 7663 true vertical 6365 feet (true vertucal) 6066, 6330 Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 16 112 112 0 0 SURFACE 2163 10.75 2193 2193 0 0 WINDOW AL2 -01 7 8 7565 6151 0 0 WINDOW AL1 8 8 7641 6316 0 0 PRODUCTION 8380 7 8410 6916 0 0 LINER AL2 -01 2223 2.625 9765 6365 0 0 Perforation depth: Measured depth: Slots: 7543 - 7609; 7668 - 9764 True Vertical Depth: 6340 - 6296; 6352 - 6366 Tubing (size, grade, MD, and TVD) 3.5, J - 55, 7682 MD, 6340 TVD NE Packers & SSSV (type, MD, and TVD) PACKER - BAKER FHL PACKER nd 6066 TVD SEP 3 0 2010 PACKER - BAKER FB - 1 PACKER 63 MD and 6330 TVD „ �Il SAFETY VLV - CAMCO TRDP -1A @ 1878 MD and 1878 TVD Mesta ' 11. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil - Bbl Gas - Mcf Water - Bbl Casing Pressure Tubing Pressure Prior to well operation 231 462 1107 850 194 Subsequent to operation 1877 700 73 13. Attachments 14. Well Class after proposed work: Copies of Logs and Surveys run Exploratory r Development r Service FA 15. Well Status after work: Oil r Gas r WDSPL r Daily Report of Well Operations x GSTOR r WAG r GASINJ r WIND r SPLUG r 16. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 310 -308 Contact Bob Christensen /Darrell Humphrey Printed Name / R %be ,,.� hristen-- n Title Production Engineering Specialist Signature 1 - -- Phone: 659 -7535 Date 9 / a2 0 n RBDMS SEP 3 0 5.30. /4 o � �n Form 10 -404 Revised 7/2009 Submit •r gi Inal • y • 1 E- 15AL2 -01 DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 08/29/10 TAGGED LINER TOP @ 7546' SLM. MEASURED SBHP @ 7400' RKB (2215 PSI) & GRADIENT @ 7273' RKB (2211 PSI) SET SS CATCHER @ 3825' RKB. PULLED GLV @ 1948' RKB & OV @ 3690' RKB. IN PROGRESS. 08/31/10 SET DV @ 1948' RKB. PULL CATCHER @ 3825' SLM (PACKED W/ SCALE) BULLHEAD 125 BBLS DIESEL DN IA. SET DMY © 3690' RKB. MITIA 3000 PSI (PASS) COMPLETE. 09 /13 /10ICommenced Water Injection Service 09 /20 /10IPRE STATE WITNESSED MIT -IA ( PASSED) 09 /21 /10ISTATE WITNESSED ( JOHN CRISP) MIT -IA ( PASSED ). t 4* KUP 1E-15AL2-01 Conoc ° Well Attributes Max Angle & MD TD Alaska, Inc Wellbore API /UWI Field Name Well Status Inc' (') MD (18(6) Act Btm (61(8) - uuPlieps 500292076962 KUPARUK RIVER UNIT INJ 104.05 6110.73 9,765.0 Comment H2S (ppm) Date Annotation End Date K8-Ord (R) Rig Release Date Well Confi9. - 1E- 15AL2 -01, 9.620104.20.18 PM SSSV: TRDP Last WO: 40.71 8/4/1982 Schematic - Actual Annotation Depth (fb(B) End Date Annotation Last Mod ... End Date Last Tag: SLM Rev Reason: GLV C/O Imosbor 9/6/2010 Casing Strings Caning Description String 0... String ID ... Top (ftl(8) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd Liner AL2 -01 (off 25/8 1.995 7,542.4 9,765.0 4.60 L -80 STL main wellbore) Liner Details Top Depth CONDUCTOR, (TVD) Top Inc! Nomi... 32112 Top (ftKB) (RKS) (°) Item Description Comment ID (in) 7,542.4 6,239.4 38.42 DEPLOY Deployment Sleeve Baker 1.995 SAFETY VLV, _ o 1 Perforations & Slots 1 . Shot Top (TVD) Btnn (T110) Dens GAS LIFT, Top (61(8) Btm (61(8) Irma) (81(8) Zane Date (sh... Type Comment 1.949 7,543 7,609 6,239.8 6,295.9 A-4, 1E-15 4/19/2010 32.0 Slots Altemating solid/slotted pipe - 0.125"x2.5" @ 4 circumferential SURFACE, adjacent rows, 3" centers staggered 30 2,193 II 18 deg, 3' non - slotted ends GAS LIFT, 7,668 9,764 6,352.0 6,365.5 4/19/2010 ' 32.0 Slots Alternating solid /slotted pipe - 3690 �• 0.125'x2.5" @ 4 circumferential a adjacent rows, 3" centers staggered 18 deg, 3' non - slotted ends GAS LIFT, s ,2,9 ilrEt Notes: General & Safety End Date Annotation GAS LIFT,, 4/20/2010 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 6,256 — 4/20/2010 NOTE: SIDETRACK w/LATERALS 1E -15A 15AL1, 15AL2, 15AL2 -01 GAS LIFT, 6,291 E GAS LIFT. 2 M 7272 EI P8R, 7,307 — ` PACKER, 7,322 INJECTION, 7.359 IR INJECTION, 7,425 IPERFS, li 7,4787554 a 1 • APERF. I 7,550 -7554 Mt • WHIPSTOCK, 7,557 WINDOW AL2 -01, 7,558 -7,565 Slots, ■, 75437,609 OF INJECTION t - 7 592 MI APERF, 7,618 - 7,638 = - WHIPSTOCK, I 7,631 WINDOW AL1, 7,6337,641 l Mandrel Details — II LOCATOR, Top Depth Top Port 7662 . (TVD) Inc' OD Valve Latch Size TRO Run PACKER, 7,%3 ,:J lid Stn Top (IIKB) (RK ('1 Make Model On) Sere Type Type (In) (psi) Run Date Conn... 1 1,948.5 1,948.4 1.46 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 8/31/2010 Al 5 2 3,690.5 3,504.9 46.84 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 8/31/2010 I 11: 3 5,218.8 4,525.2 45.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 NIPPLE, 7,678 4 6,255.6 5,252.2 43.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 SOS, 7,682 5 6,291.2 5,277.8 43.53 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 PRODUCTION, 6 7,271.9 6,027.0 37.97 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 30 - 8.410 -\ � .. Slots, le 7,359.0 6,095.5 38.22 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 Liner AL2 - 01 (off main 8 7,425.4 6,147.7 38.44 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 ° 7 7,542 - 99,765 65 9 7,592.1 6,278.3 38.42 CAMCO KBUG 1 INJ DMY ' BK 0.000 0.0 7/20/1993 TO (1E-15AL2-01), 765 9,765 4 ' • . ELLs sifor[E ® SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Darrell R. Humphrey Production Engineering Specialist ConocoPhillips Alaska, Inc. 0 01 ( P.O. Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, Kuparuk Oil Pool, 1E-15AL2-01 Sundry Number: 310 -308 Dear Mr. Humphrey: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Chair DATED this Z I day of September, 2010. Encl. G R v 1 * - �1 • STATE OF ALASKA q '1")' 0/ b ALASKA OIL AND GAS CONSERVATION COMMISSIO APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request Abandon r Rug for Redrill r Perforate New Pool r Repair w ell r Change Approved Program r Suspend ❑ Rug Perforations r Perforate r Pull Tubing r Time Extension r Operational Shutdow n f ; Re -enter Susp. Well [ j Stimulate ❑ Alter casing r Other:PROD to WINJ n • 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development C . Exploratory r 210 -016 • 3. Address: Stratigraphic r Service r 6. API Number. P. O. Box 100360, Anchorage, Alaska 99510 50- 029 - 20769 -62 • 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line 8. Well Name and Number. where ownership or landownership changes: Spacing Exception Required? Yes r No p1 1E- 15AL2 -01 • 9. Property Designation: 10. Field / Pool(s): ADL 25651 • Kuparuk River Field / Kuparuk Oil Pool • 11. PRESENT WELL CONDITION SUMMARY Total depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9765 . 6365 i 9765' 6365' none none Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 16 112' 112' SURFACE 2163 10.75 2193' 2193' WINDOW AL2 -01 7 8 7565' 6257' PRODUCTION 7660 7 7690' 6371' LINER AL2 -01 2223 2.625 9765' 6365' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 7543 -7609 7668 -9764 3.5 J - 7682 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft) PBR - BAKER PBR MD= 7307 TVD= 6055 PACKER - BAKER FHL PACKER MD= 7322 TVD= 6066 PACKER - BAKER FB -1 PACKER MD= 7663 TVD= 6347 SOS - BAKER SHEAR OUT SUB MD= 7682 TVD= 6364 12. Attachments: Description Summary of Roposal r 13. Well Class after proposed work: Detailed Operations Program [j BOP Sketch Exploratory r Development Service R 14. Estimated Date for Commencing Operations: 15. Well Status after proposed work: 6/22/2010 Oil r Gas r WDSPL r Suspended f 16. Verbal Approval: Date: WINJ p • GINJ r WAG r Abandoned r Commission Representative: GSTOR r SPLUG r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Bob Christensen /Darrell Humphrey Printed Name Darrell R. Humphrey Title: Production Engineering Specialist Signature z,,, i V,, Phone: 659 -7535 Date C' . IS / 0 Commission Use Only Sundry Number - 3I 0 Conditions of approval: Notify Commission so that a representative may witness J Plug Integrity r BOP Test r Mechanical Integrity Test Location Clearance r' PCE . ' Other: SEP 1 7 2010 Alma ON & in Cent COMMiSsion Subsequent Form Required: / a . y ci Anchorage l • - APPROVED BY q I Z I / /Q Approved by: i . ✓ COMMISSIONER THE COMMISSION Date: SEP 21 /a) '2- Form 10 -403 Revised 1/2010 � ° I �, 1 Z6 /v Submif in D I,a}, • . 1 E- 15AL2 -01 DESCRIPTION SUMMARY OF PROPOSAL ConocoPhillips Alaska Inc. requests approval to convert KRU Well 1E -15 from Oil Production service to Water Injection service.Well 1E -15A CTD was completed in the Kuparuk formation on April 23, 2010 as a preroducing injector with initial production commencing on May 31, 2010. Conversion to Injection service is required due to potential reservoir depletion. Well 1E -15A injection will provide pressure support to offset producers 1E -12, 1F -06, 1F -14 and 1F -19. The 16" Conductor was cemented with 326sx of AS II. The 10 -3/4" Surface casing (2193' and / 2193' tvd) was cemented with 1025sx AS III and 250sx AS II. The 7" Production casing (8410' and / 6916' tvd) was cemented with 605 sx Class "G ". The top of the Kuparuk B1 was found at 7665' and / 6331' tvd. The top of the Kuparuk A6 was found at 7738' and / 6364' tvd. The top of the Kuparuk A5 was found at 7763' and / 6375' tvd. The top of the Kuparuk A4 was found at 9322' and / 6365' tvd. The USIT CBL performed on March 11, 2010 indicates good continuous formation quality bond from 7460' and (6175' tvd) to 7580' and (6269' tvd). The injection tubing/casing annulus is isolated via Baker FHL Packer 6.151" OD x 2.94" ID located @ 7322 and / 6066' tvd. An MIT -IA was last performed on 8/31/10; MITIA 3000 psi, 15 minutes, Passed. MITIA 3000 PSI (PASS) COMPLETE. Initial T/I/O= 1600/0/330: Start T/I/O= 1600/3000/360: 15min. reading T/I/O= 1600/2910/360: 30min. reading T/I/O= 1600/2890/360 • ao _ Ire- • KUP • 1 E- 15AL2 -01 ConocoPhillips ' Well Attributes Max Angle & MD TD • Alaska InC Wellbore API /UWI Field Name Well Status Incl (•) MD (ftKB) Act Btm (ftKB) c,or,aor1„Il,ps 500292076962 KUPARUK RIVER UNIT INJ 104.05 8,110.73 9,765.0 .. Comment H2S (ppm) Date Annotation End Date KB (ft) Rig Release Date Well Collin:- 1E - 15AL2 - 09: 45 AM — SSSV:TRDP Last WO: 40.71 8/4/1982 Schematic - Actual Annotation Depth (ftKB) End Date Annotation Last Mod ... End Date Last Tag: SLM Rev Reason: GLV C/O Imosbor 4/25/2010 Casing Strings Casing Description String 0... String ID _IT op (ftKB) Set Depth (f... Set Depth (TVD) ... String. String ... String Top Thrd r[ Liner AL2 -01 (off 25/8 1.995 7 9 4 .60 L - STL ( main wellbore) I _ Liner Details Top Depth CONDUCTOR, (TVD) Top Inc' Nomi... 32-112 Top (ftKB) (ftKB) (1 item Description Comment ID (in) 7,542.4 6,239.4 38.42 DEPLOY Deployment Sleeve Baker 1.995 SAFETY VLV, o 1,875 Perforations & Slots Shot Top (TVD) Btm (TVD) Dens GAS LIFT, i Top (ftKB) Btm(ftKB) (848) MU) Zone Date (oh... Type Comment 1.949 ,, 7,543 7,609 6,239.8 6,295.9 A -4, 1E -15 4/19/2010 32.0 Slots Altemating solid /slotted pipe - 0.125 "x2.5" @ 4 circumferential SURFACE, adjacent rows, 3" centers staggered 30 - 2,193 18 deg, 3' non - slotted ends GAS LIFT, 7,668 9,764 6,352.0 6,365.5 4/19/2010 32.0 Slots Altemating solid /slotted pipe - 3,690 _ .. I l adjacent rows, 3" centers staggered GAS LIFT, 18 deg, 3' non - slotted ends 5,219 R Notes: General & Safety End Date Annotation GAS LIFT, 4/20/2010 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 6 ' 4/20/2010 NOTE: SIDETRACK w /LATERALS 1E-15A, 15AL1, 15AL2, 15AL2 -01 sr GAS LIFT, 6,291 GAS LIFT, 7,272 PBR, 7,307 PACKER, 7,322 INJECTION, i 7,359 1 INJECTION. F 7,425 } T PERFS 7,475 -7,554 !c 1 ate APERF, I 7,550 -7,554 =_ WHIPSTOCK, 7,557 WINDOW AL2 -01, 7,558-7,565 Skits, 7,543 7,6W INJECTION, M 7,592 - In APERF, 1 7,618-7,638 WHIPSTOCK, i 7,631 1 i I WIN ,641 # 7,6337,641 Mandrel Details Top Depth Top Port JII LOCATOR, (TVD) Intl OD Valve Latch Size TRO Run PACKER, 7,663 ` Stn Top ((tl(8) (ftKB) e) Make Model (in) Sery Type Type (in) (psi) Run Date Com... 1 1,948.5 1,948.4 1.46 CAMCO KBUG 1 GAS LIFT GLV BK 0.188 1,346.0 4/24/2010 :7 M r 2 3,690.5 3,504.9 46.84 CAMCO KBUG 1 GAS LIFT OV BK 0.250 0.0 4242010 II II 3 5,218.8 4,525.2 45.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 NIPPLE, 7,678 a. 4 6,255.6 5,252.2 43.86 CAMCO KBUG - 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 SOS, 7,682 5 6,291.2 5,277.8 43.53 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 PRODUCTION, 6 7,271.9 6,027.0 37.97 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 308,410 Slots, I. 7,668 7 7,359.0 6,095.5 38.22 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 Liner f mai n 8 7,425.4 6,147.7 38.44 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 w 05 main 7,542 V765 9 7,592.1 6,278.3 38.42 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 720/1993 TD (1E.15AL2 -01), 9,765 • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Abandon r Repair w ell r Plug Fbrforations r Stimulate r Other r WINJ to PROD Alter Casing r Pull Tubing r Fbrforate New Pool r Waiver r Time Extension r Change Approved Program r Operat. Shutdow n r Perforate r Re -enter Suspended Well r 2. Operator Name: 4. Current Well Status: B. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development r Exploratory r 210 -016 3. Address: ‘6. API Number: P. 0. Box 100360, Anchorage, Alaska 99510 Stratigraphic r Service I� 50 - 029 - 20769 - 7. Property Designatioq: 8. Well Name and Number: ADL 25651 1 E- 15AL2 -01 9. Field /Pool(s): `, Kuparuk River Field / Kuparuk Oil Pool 10. Present Well Condition Summary: Total Depth measured 9765 feet Plugs (measured) none true vertical 6365 feet Junk (measured) none Effective Depth measured 9765 feet Packer (measured) 7307, 7322, 7663, 7682 true vertical 6365 feet (true vertucal) 6055, 6066, 6347, 6364 Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 16 112 112 0 0 SURFACE 2163 10.75 2193 2193 0 0 WINDOW AL2 -01 7 8 7565 6257 0 0 PRODUCTION 7660 7 7690 6371 0 0 LINER AL2 -01 (0 2223 2.625 9765 6365 0 0 0 0 0 Perforation depth: Measured depth: 7543 -7609 True Vertical Depth: 7668 -9764 Tubing (size, grade, MD, and TVD) 3.5, J -55, 7682 MD, 6364 TVD Packers & SSSV e, MD, and TVD) RECEIVED (tYp ) PBR -BAKER PBR @ 7307 MD and 6055 TVD PACKER - BAKER FHL PACKER @ 7322 MD and 6066 TVD ION 2 4 2010 PACKER - BAKER FB - 1 PACKER @ 7663 MD and 6347 TVD SOS - BAKER SHEAR OUT SUB @ 7682 MD and 6364 TVD 4laska 0:1 & , C n;. C4f11fftjSSjOt 11. Stimulation or cement squeeze summary: lltlirir3qe Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil - Bbl Gas - Mcf Water - Bbl Casing Pressure Tubing Pressure Prior to well operation 479 1100 2020 Subsequent to operation 229 151 1805 914 145 13. Attachments ht. Well Class after proposed work: Copies of Logs and Surveys run Exploratory r Development r Service r ` t5. Well Status after work: 011 p Gas r WDSPL r Daily Report of Well Operations GSTOR r WAG r GASINJ r WINJ r SPLUG r 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt N/A Contact Bob Christensen /Darrell Humphrey Printed Name Darrell R. Humphrey Title Production Engineering Specialist Signature Phone: 659 -7535 Date a. ` p RB fv' 10 Form 10-404 Revised 7/2009 D JLIN Z 4 7-7_ Submit Original Only f • • ,r 1 E- 15AL2 -01 DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 05/31/10 Well currently being pre- produced to improve injection quality post CTD sidetrack operations. Put on production at 0732 hours. Well being gas lifted from 1E-31 @ 926 psi, 1000 MSCFD I I I I I 1 i. ` KUP • 1E- 15AL2 -01 Conoco Phillips 0 Well Attributes Max Angle & MD TD A!.t,i..1 II I, Welibore API /UWI Field Name Well Status Inc' (•) MD (568) Act Btm (RKB) LonocoR•Wpf 500292076962 KUPARUK RIVER UNIT INJ 104.05 8,110.73 9,765.0 Comment H2S (ppm) Date Annotation End Dab 6813rd (R) Rig Release Date "' _SSSV: TRDP Last WO: 40.71 8/4/1982 Well Conag. - 1E- 15AL2 -0,, 4252010809'. 45 AM - Schematc -Actual Annotation Depth (ftKB) End Data Annotation Last Mod ... End Date Last Tag: SLM I I Rev Reason: GLV C/O I Imosbor 4/25/2010 - -- - - Casing Strings Casing Description String 0... String ID... Top (f8(8) Set Depth (f... Set Depth (TVD)... String Wt... String... String Top Thrd Liner AL2 -01 (off 25/8 1.995 7,542.4 9,765.0 4.60 L-80 STL • main wellbore) Mil Liner Details Top Depth CONDUCTOR, (TVO) Top Inci Nom'... 32.112 107 (..) (568) (•) Item Description Comment ID (in) P 7,542.4 6,239.4 38.42 DEPLOY P erforations & Slots Deployment Sleeve Baker 1.995 III SAFETY VLV, ,,676 Dent Top (TVD) 8tm (TVD) Shot GAS LIFT. Top (RKB) Btm (568) (R613) (RKB) Zone Dab ICh... Type Comment _ 1.949 7,543 7,609 6,239.8 6,295.9 A-4, 1 E -15 4/19/2010 32.0 Slots Alternating solid/slotted pipe - I 0.125 "x2.5" @ 4 circumferential SURFACE, adjacent rows, 3" centers staggered 30.2193 18 deg, 3' non - slotted ends GAS LIFT, 7,668 9,764 6,352.0 6,365.5 4/19/2010 32.0 Slots Alternating solid/slotted pipe - 3,690 —_. 0.125 "x2.5" @ 4 circumferential adjacent rows, 3" centers staggered 18 deg, 3' non - slotted ends GAS LIFT, 5,219 Notes: General & Safety End Date Annotation GAS LIFT, _ _ • 4/20/2010 NOTE: VIEW SCHEMATIC w /Aaska Schematic9.0 e 4/20/2010 NOTE: SIDETRACK wMTERALS 1E -15A, 15AL1, 15AL2, 15AL2 -01 - - - -- GAS LIFT. ,251 8.291 IML in GAS LIFT, ,272 7 272 PBR, 7,307 PACKER, 7,322 INJECTION, 7,359 INJECTION, 7425 IPERFS, 7,476 -7,554 l t 8 APERF, 7.550 -7, 554 S WHIPSTOCK, 7557 — N WINDOW AL2 -01, 7,558-7,565 7,ob, 7,5435,809 INJECTION, 7,592 N, i APERF, 1 7,6167,68 WHIPSTOCK, !' « 7.61 WINDOW AL1, 7,633-7,641 ! Mandrel Details Top Depth Top Port LOCATOR, (TVD) Intl OD Valve Latch Sic. TRO Run 7,662 _ PACKER, 766 J E ` Ma Top ((8(8) 1569) (") Make Model ('n) Sery Type ((Pe (In) (psi) Run Date Com... 1 1,948.5 1,948.4 1.46 CAMCO KBUG 1 GAS LIFT GLV BK 0.188 1,346.0 4/24/2010 51 - r 2 3,690.5 3,504.9 46.84 CAMCO KBUG 1 GAS LIFT OV BK 0.250 0.0 4/24/2010 i 3 5,218.8 4,525.2 45.86 CAMCO KBUG 1 GAS LIFT OMY BK 0.000 0.0 6/5/1990 NIPPLE, 7676 4 6,255.6 5,252.2 43.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 SOS, 7,662 5 6,291.2 5,277.8 43.53 CAMCO KBUG 1 GAS UFT DMY BK 0.000 0.0 6/3/1990 PRODUCTION, 6 7,271.9 6,027.0 37.97 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 30-8,410 Sbb, -\ 7.668 7 7,359.0 6,095.5 38.22 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 Liner AL2 (off mT O 1 7,425.4 6,147.738.44 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 118ors) 7, 9 7,592.1 6,278.3 38.42 CAMCO KBUG 1 INJ OMY BK 0.000 0.0 7/20/1993 5428,785 TO 11E-15AL2-01), 9,7 5 9,735 RECEIVEll 6)10 Vali III Company ConocoPhillips, Alaska, Inc. �l1- JLJ1v 1 7 2010 BAKER Well Name 1 E- 15AL2 -01 Gas HUGHES /9=3" a� Date 6/9/2010 TE ConocoPhillips Alaska Greater Kuparuk Area*** Data Distribution RECIPIENTS ` 1 �= a No other distribution is allowed without t r. t t. , s e> OH FINAL OH FINAL ' rip -1, 0 At • i written approval from ConocoPhillips Image files andlor Digital Data i �. 'L." I contact: Lisa Wright, 907 263 -4823 hardcopy prints , ConocoPhillips Alaska, Inc. C ,1 4; r • Sharon Alisup -Drake i • Drilling Tech, ATO-1530 ConocoPhillips Alaska, Inc. i 1 Hardcopy Print , r° ' ,.)' "; NSK Wells Aide, NSK 69 . 9 'F t 101,1 ATTN: MAIL ROOM 700 G Street,' Anchorage, AK 99501 ConocoPhillips Alaska, Inc. i Ricky Elgarico 1 Graphic Image 1 Disk * / - ! .. _ _ ■ e Z.1 File * * / * ** Electronic 1 791 -G -- Street, CGM / TIFF LIS ftp: / /b2bftp.conocophillips.com * * ** 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 i CGM / TIFF LIS Aft BP i 1 Hardcopy Print, ` .' •. imp Petrotechnical Data Center, MB33 1 Graphic image file 1 Disk`/ ' ' ' • David Douglas in lieu of sepia ** Electronic i , , ' - 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 ; , - j t`'" "'" 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 DS Engineer / Rig Foreman ' TOTAL Hardco.y Prints 4 Page 1 of 4 RECEIVED • STATE OF ALASKA • 9 7010 ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 1 2 WELL COMPLETION OR RECOMPLETION REPi 1a. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended L 1b. WellAttlelne 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory ❑ GINJ ❑ WINJ El WAG ❑ WDSPL ❑ No. of Completions: Service El Stratigraphic Test ❑ 2. Operator Name: 5. Date Comp., Susp., 12. Permit to Drill Number: ConocoPhillips Alaska, Inc. or Aband.: April 20, 2010 210 - 016 / 3. Address: 6. Date Spudded: 13. API Number: P. O. Box 100360, Anchorage, AK 99510 - 0360 April 14, 2010 50 029 - 20769 - 62 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 444' FSL, 814' FEL, Sec. 16, T11 N, R10E, UM April 19, 2010 1E Top of Productive Horizon: 8. KB (ft above MSL): 105.7' RKB 15. Field /Pool(s): 897' FSL, 1326' FWL, Sec. 16, T11 N, R10E, UM GL (ft above MSL): 41' AMSL Kuparuk River Field Total Depth: 9. Plug Back Depth (MD + TVD): 442' FNL, 2152' FWL, Sec. 21, T11 N, R10E, UM 9765' MD / 6365 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 549710 y - 5960030 Zone 4 9765' MD / 6365' TVD ADL 25651 TPI: x - 546567 y - 5960462 Zone 4 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x 547404 y - 5959129 Zone 4 SSSV @ 1878' MD / 1878' TVD 469 18. Directional Survey: Yes El 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) 1450' 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 7689' MD / 6370' TVD 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT CASING SIZE WT. PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE CEMENTING RECORD PULLED 16" 62.5# H -40 Surf. 112' Surf. 112' 24" 326 sx AS II 10.75" 45.5# K -55 Surf. 2193' Surf. 2193' 13.5" 1025 sx AS III, 250 sx AS II 7" 26.0# K -55 Surf. 8410' Surf. 6916' 8.75" 605 sx Class G 2.375" 4.7# L -80 7542' 9765' 6240' 6365' 3" slotted liner 24. Open to production or injection? Yes 0 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) 3.5" 7682' 7321' MD / 6066' TVD alternating solid / slotted liner from 7543' -7609' MD 7663' MD / 6331' TVD alternating solid / slotted liner from 7668' -9764' MD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. s `'" i DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) flowback in progress Date of Test Hours Tested Production for OIL -BBL GAS -MCF WATER -BBL CHOKE SIZE GAS - OIL RATIO Test Period - -> Flow Tubing Casing Pressure Calculated OIL -BBL GAS -MCF WATER -BBL OIL GRAVITY - API (corr) Press. psi 24 -Hour Rate -> 28. CORE DATA Conventional Core(s) Acquired? Yes ❑ No 0 Sidewall Cores Acquired? Yes ❑ No Q 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 Form 10 -407 Revised 12/2009 CONTINUED ON REVERSE Submit original only • 4 6- .1111.. Mil 1ii 40 RBDMS MAY 1 9 ZO O - -1 u % i 6 6 �/G G Ai 28. GEOLOGIC MARKERS (List all formations and mark ncountered): 29. • FORMATION TESTS NAME MD TVD Well tested? ❑ Yes 0 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 3398' 3291' needed, and submit detailed test information per 20 AAC 25.071. Top A5 7690' 6370' Top A4 7712' 6389' Top A4 (inverted) 8164' 6379' N/A Formation at total depth: Kuparuk A4 /A5 30. LIST OF ATTACHMENTS Summary of Daily Operations, final directional survey, schematic 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: ary Eller @ 263 - 4172 Printed Na e V. awv Title: Alaska Wells Manager LL ���/ Signature ,:.� _. Phone 265 - 6306 Date J ' I 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 la: 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 KUP • 1 E- 15AL2 -01 Con©c©Phillips Well Attributes Max Angle & MD TD Wellbore API /UWI Field Name Well Status Inc! (") MD (ftKB) Act Btm (ftKB) I 5002920 /6962 KUPARUK RIVER UNIT ( INJ 9765 0 CanItis 1 Comment H2S (ppm) Date Annotation L End Date � KB Grd (ft) Rig Release Date SSSV. TEMP _ , Last WO: 40.71 8/4/1982 I Well CO 1E 15AL8-01, 421200 24]'.50 PM _ - _- — _ Scrt ma Actval_ Annotation Depth (f188) ( End Date Annotation Last Mod ... End Date Last Tag- SLM '. Rev Reason: SIDETRACK w /LATERALS Imosbor 4/20/2010 t! :, Casing Strings ,, !Casing Description String 0... String ID ... Top (ftKB) Set Depth (f_. Set Depth (TVD) . String Wt... String String Top Thrd Liner AL2 -01 (off 2 5/8 1 995 7,542 4 9,765.0 4.60 L-80 STL (main wellbore) l .. ■ I Liner Details Top Depth CONDUCTOR, _- (TVD) Top lncl Nomi... 32- 112 Top (ftKB) (10(8) /') Item Description Comment ID (in) 7,5424. DEPLOY Deployment Sleeve Baker 1.995 SAFETY VLV, .. - 1.878 Perforations & Slots Shot T op (TVD) Btm (TVD) - Dens GAS LIFT, T•• ftKB BtalyBOR (ftKB) (ftKB) Zone Date (eh. Type Comment 1.949 7,543 7,609 A-4, 1E-15 4/19/2010 32.0 Slots Alternating solid/slotted pipe - 0.125 "x2.5" @ 4 circumferential SURFACE, adjacent rows, 3" centers staggered 30 - 2,193 18 deg, 3' non - slotted ends GAS LIFT, 7,668 9,764 4/19/2010 32.0 Slots Alternating solid/slotted pipe - 3,690 0.125 "x2.5" @ 4 circumferential ,.. adjacent rows, 3" centers staggered ... - 18 deg, 3' non - slotted ends GAS LIFT, __ � 5.219 r... ` „' Notes: General & Safety End Date Annotation GAS LIFT, 4/20/2010 NOTE VIEW SCHEMATIC w /Alaska Schematic90 6,256 _ _ __ 4/20/20 NOTE SIDETRACK w /LATERALS 1E -15A, 15AL1, 15AL, 15AL2 -01 (2 pg schematic) GAS LIFT, 6,291 it GAS LIFT, 7,272 PBR, 7,307 f PACKER, 7,322 -- INJECTION, 7,359 -.. ._ It INJECTION, - .. 7,425 IPERFS, 7,478 -7,554 I _, APERF, 7,550 7,554 WHIPSTOCK, 7.557 �_ WINDOW M.2 -01, -- --• 7,558-7,565 51ots..- 7,543 -7,609 INJECTION, ®. 7,592 i It ■ APERF, 7,618 - 7,638 WHIPSTOCK,_ 7,631 WINDOW AL1, 1 7,633 -7,641 Mandrel Details` LOCATOR, >!� r T Depth Top port r 7,662 - �' (i '� (ND) Incl 00 Valve Latch SW TRO Run Stn Top (ftKB) (ftKB) (1 Make Model n) Sery TYPe Type (in) 0199 Run Date Com... PACKER, 7,663 1 1,948.5 CAMCO KBUG 1 GAS LIFT DMY Dk 0.000 0.0 6/5/1990 m -21 et'e... 2 3,690.5 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 3 5,218.8 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 NIPPLE, 7 ,676 . ° 4 6,255.6 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 Sce 7682 . ,. 5 6,291.2 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 30 8,4110 0 PRODUCTION, 6 7,271.9 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 flu 7,668 7 7,359.0 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 Liner AL2 91 W i (oft main — 481 8 7,425.4 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 l 7,5429, a°9 ,765 \ 76 5 \ 9 7,592.1 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 TO (1 E- 15412 -01), 9,765 1E-15 CTD Sidetrack - Final Last Updated: 21- Apr -10 3 -1/2" Camco TRDP -1A nipple @ 1878' MD lila 3 -1/2" 9.3# K -55 EUE 8rd Tubing to surface k- .,,, 3 -1/2" Camco KBUG gas lift mandrels @ 1948', 3690', 5218', 6256', 7271' 16" 65# H -40 shoe = @ 112' MD Baker 3 -1/2" PBR @ 7307' MD Baker FHL packer @ 7321' MD 3 -1/2" Camco KBUG injection mandrels @ 7354', 7425', 7592' • 10 -3/4" 45.5# K -55 shoe @ 2193 MD ■ Carbide blast rings 7446' - 7552' (745Z-7538' CBL) Baker FB -1 packer @ 7663' MD w/ Baker SBE 3 -1/2" Camco D landing nipple @ 7676' MD (2.75" min ID, No -Go) 3 -1/2" tubing tail @ 7682' MD C -sand perfs 7478' - 7554' MD ~ Sqz perfs (2/14/10) M _w � AL2 -01, TD = 9765' AL2, TD = 10,085' 7550' - 7554' CBL 2 -3/8" liner 7542' -9765' 2 -3/8" liner 7690'- 10,058' • 7618' - 7638' CBL NAM Deployment sleeve at 7542' Billet at 7690' AL2 -PB3, TD = 9710' Unintended sidetrack at KOP #2 at 7557' MD = a %/� .......... ... _... 7855' KOP #1 at 7631' MD AL2 -PB2, TD = 10,135' 2 -3/8" liner 8200'- 10,135' Baker flow -by monobore °�� Billet at 8200' whipstocks % /i AL2 -PB1, TD _ - 9835' 4'-9835' 8" 88 - �— 2 Bille3!t at liner 88556 ' A -sand perfs 7716' - I_� ._. / / J AL1 Lateral, TD = 8812' 7796' MD (plugged) — / / (-- 2 -3/8" liner 7623' - 8812' — —_ _ — _ — _ ) Liner top at 7623' A Sidetrack, TD = 9800' 7" 26# K -55 shoe CIBP at 7656' ELM 2 -3/8" liner 8323' - 9794' @ (7674' MD, 2/13/10) Billet at 8323' 8410' MD 1 ConochiIIips Alaska ConocoPhillips(Alaska) Inc. • Kuparuk River Unit Kuparuk 1E Pad 1 E- 15AL2 -01 50- 029 - 20769 -62 Baker Hughes INTEQ Viii/ B • AKER Definitive Survey Report HUGHES 21 April, 2010 vr- Conoco Phillips 13 Conoco Phillips Definitive Survey Report BAKER HUGHES Alaska I Company: ConocoPhillips(Alaska) Inc. Local Co-ordinate Reference: 1E Project: Kuparuk River Unit wo Reference: 1E-15 @ 105.70ft (1E-15) I Site: Kuparuk 1E Pad MD Reference: 1E-15 @ 105.70ft (1E-15) I Well: 1E North Reference: TRUE Wellbore: 1E Survey Calculation Method: Minimum Curvature I Design: 1E-15 Database: EDM Alaska Prod v16 Project Kuparuk River Unit Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level 1 Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point I Map Zone: Alaska Zone 04 Using geodetic scale factor I Well 1E-15 SI I Well Position +N/ 0.00 ft Northing: 5,960,029.95ft Latitude: 70° 18' 5.686 N +E/ 0.00 ft Easting: 549,710.04ft Longitude: 149° 35' 50.538 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00 ft Wellbore 1E 1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength el CI (nT) BGGM2009 3/25/2010 17.33 79.80 57,371 - _ — Design 1E-15AL2-01 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 7,680.36 Vertical Section: Depth From (TVD) +N/-$ +E/-W Direction (ft) (ft) (ft) C) 1 • 105.70 0.00 0.00 249.03 — –. 1 Survey Program Date From To Survey Survey (ft) (ft) Survey (Wellbore) Tool Name Description Start Date End Date 200.00 7,500.00 1E-15 (1E-15) FINDER-MS SDC Finder multishot 8/25/2000 7,557.00 7,680.36 1E-15AL2-PB1 (1E-15AL2-PB1) MWD MWD - Standard 3/26/2010 3/29/2010 7,689.00 9,725.48 1E-15Al2-01 (1E-15AL2-01) MWD MWD - Standard 4/15/2010 4/19/2010 _ - _.... 4/21/2010 10:56:34AM Page 2 COMPASS 2003.16 Build 69 - p ConocoPhillips fril ConocoPhillips Definitive Survey Report is HUGHES Alaska I Company: ConocoPhillips(Alaska) Inc. Local Co- ordinate Reference: 1E I Project: Kuparuk River Unit TVD Reference: 1E-15 @ 105.70ft (1E-15) I Site: Kuparuk 1E Pad MD Reference: 1E-15 @ 105.70ft (1E-15) Well: 1 E - 15 North Reference: TRUE Wellbore: 1E Survey Calculation Method: Minimum Curvature i Design: 1E Database: EDM Alaska Prod v16 i Survey I MD Inc Azi TVD TVDSS +141/-S +E/.W Map Map DLS Vertical (ft) (1 (*) (ft) (ft) (ft) (ft) Northing Easting moo') Section Survey Tool Name Annotation • 7,680.36 28.50 195.31 6,362.98 6,257.28 860.91 -3,240.29 5,960,869.32 546,464.45 46.22 2,717.73 MWD (2) TIP 1E 7,689.00 31.96 192.03 6,370.44 6,264.74 856.68 - 3,241.31 5,960,865.09 546,463.45 44.37 2,720.19 MWD (3) KOP; Top AL Billet 7,720.24 44.77 202.41 6,394.91 6,289.21 838.33 - 3,247.25 5,960,846.70 546,457.63 45.77 2,732.32 MWD (3) 7,750.18 60.58 203.68 6,413.01 6,307.31 816.50 - 3,256.57 5,960,824.81 546,448.46 52.91 2,748.82 MWD (3) 7,780.17 76.40 203.36 6,423.97 6,318.27 791.00 - 3,267.67 5,960,799.24 546,437.53 52.76 2,768.31 MWD (3) 7,810.17 90.49 197.56 6,427.39 6,321.69 763.15 - 3,278.03 5,960,771.32 546,427.35 50.72 2,787.96 MWD (3) 7,840.07 92.95 181.49 6,426.49 6,320.79 733.77 - 3,282.96 5,960,741.92 546,422.61 54.34 2,803.07 MWD (3) ( 7,870.58 94.03 167.27 6,424.62 6,318.92 703.55 - 3,279.99 5,960,711.71 546,425.78 46.65 2,811.11 MWD (3) 7,900.35 92.49 160.54 6,422.92 6,317.22 675.01 - 3,271.76 5,960,683.23 546,434.21 23.15 2,813.63 MWD (3) 7,930.52 95.13 156.86 6,420.92 6,315.22 646.97 - 3,260.83 5,960,655.27 546,445.32 14.99 2,813.46 MWD (3) 7,960.77 96.99 151.49 6,417.72 6,312.02 619.90 - 3,247.73 5,960,628.29 546,458.60 18.69 2,810.91 MWD (3) 7,990.54 98.04 146.30 6,413.83 6,308.13 594.64 - 3,232.49 5,960,603.13 546,474.00 17.64 2,805.72 MWD (3) 8,020.35 98.79 140.55 6,409.46 6,303.76 570.96 - 3,214.93 5,960,579.58 546,491.72 19.25 2,797.79 MWD (3) 8,050.76 101.50 139.78 6,404.10 6,298.40 547.98 - 3,195.75 5,960,556.72 546,511.04 9.25 2,788.11 MWD (3) 8,080.53 102.63 145.07 6,397.88 6,292.18 524.92 - 3,178.01 5,960,533.78 546,528.94 17.79 2,779.79 MWD (3) 8,110.72 104.05 150.64 6,390.91 6,285.21 500.06 - 3,162.38 5,960,509.03 546,544.73 18.56 2,774.09 MWD (3) 8,140.18 102.98 155.49 6,384.02 6,278.32 474.53 - 3,149.41 5,960,483.59 546,557.86 16.41 2,771.12 MWD (3) 8,170.38 101.43 160.03 6,377.63 6,271.93 447.22 - 3,138.25 5,960,456.35 546,569.21 15.56 2,770.47 MWD (3) I! 8,200.44 97.35 163.84 6,372.73 6,267.03 419.03 - 3,129.06 5,960,428.23 546,578.58 18.45 2,771.97 MWD (3) • 8,230.45 92.70 168.40 6,370.10 6,264.40 390.02 - 3,121.90 5,960,399.27 546,585.94 21.66 2,775.66 MWD (3) 8,260.33 92.36 170.82 6,368.78 6,263.08 360.66 - 3,116.51 5,960,369.95 546,591.51 8.17 2,781.14 MWD (3) 8,290.40 90.92 167.16 6,367.92 6,262.22 331.17 - 3,110.77 5,960,340.50 546,597.45 13.07 2,786.33 MWD (3) 8,320.70 92.15 163.05 6,367.10 6,261.40 301.90 - 3,102.99 5,960,311.29 546,605.42 14.15 2,789.54 MWD (3) 8,350.46 90.09 158.07 6,366.52 6,260.82 273.85 - 3,093.09 5,960,283.31 546,615.51 18.11 2,790.33 MWD (3) 8,380.28 93.44 155.36 6,365.60 6,259.90 246.48 - 3,081.31 5,960,256.02 546,627.47 14.45 2,789.12 MWD (3) 8,410.56 93.47 151.64 6,363.78 6,258.08 219.44 - 3,067.83 5,960,229.07 546,641.13 12.26 2,786.21 MWD (3) 8,440.65 93.29 147.79 6,362.00 6,256.30 193.50 - 3,052.68 5,960,203.24 546,656.44 12.79 2,781.35 MWD (3) 8,470.62 93.69 144.30 6,360.18 6,254.48 168.69 - 3,035.98 5,960,178.54 546,673.31 11.70 2,774.62 MWD (3) 8,500.66 93.47 140.68 6,358.30 6,252.60 144.92 - 3,017.72 5,960,154.88 546,691.72 12.05 2,766.09 MWD (3) 8,530.63 91.35 139.65 6,357.04 6,251.34 121.92 - 2,998.54 5,960,132.02 546,711.05 7.86 2,756.40 MWD (3) 4/21/2010 10:56:34AM Page 3 COMPASS 2003.16 Build 69 Conoco Phillips Rae Conoco Phillips Definitive Survey Report BAKER HUGHES Alaska Company: ConocoPhillips(Alaska) Inc. Local Co-ordinate Reference: 1E Project: Kuparuk River Unit TVD Reference: 1E-15 © 105.70ft (1E-15) Site: Kuparuk 1E Pad MD Reference: 1E-15 © 105.70ft (1E-15) Well: 1E North Reference: TRUE Wellbore: 1E Survey Calculation Method: Minimum Curvature Design: 1E Database: EDM Alaska Prod v16 Survey Map Vertical MD Inc Azi TVD TVDSS +N/-S +EJ-W DLS N o I n g Easting Section Survey Tool Name Annotation 8,560.62 90.15 141.72 6,356.65 6,250.95 98.72 -2,979.54 5,960,108.95 546,730.20 7.98 2,746.96 MWD (3) • 8,590.52 88.43 141.88 6,357.02 6,251.32 75.23 -2,961.06 5,960,085.58 546,748.84 5.78 2,738.11 MWD (3) 8,620.59 89.63 145.31 6,357.53 6,251.83 51.04 -2,943.22 5,960,061.51 546,766.84 12.08 2,730.10 MWD (3) 8,650.51 92.43 148.79 6,356.99 6,251.29 25.94 -2,926.95 5,960,036.52 546,783.27 14.93 2,723.89 MWD (3) • 8,680.62 92.18 152.43 6,355.78 6,250.08 -0.27 -2,912.19 5,960,010.41 546,798.20 12.11 2,719.49 MWD (3) 8,710.49 91.07 155.93 6,354.93 6,249.23 -27.14 -2,899.18 5,959,983.63 546,811.38 12.29 2,716.96 MWD (3) 8,740.51 89.14 157.22 6,354.88 6,249.18 -54.69 -2,887.25 5,959,956.17 546,823.49 7.73 2,715.67 MWD (3) 8,775.50 86.47 158.42 6,356.22 6,250.52 -87.06 -2,874.05 5,959,923.89 546,836.91 8.36 2,714.93 MWD (3) 8,805.60 85.82 155.32 6,358.24 6,252.54 -114.67 -2,862.26 5,959,896.35 546,848.88 10.50 2,713.80 MWD (3) 8,835.62 87.61 152.06 6,359.96 6,254.26 -141.53 -2,848.97 5,959,869.58 546,862.34 12.37 2,711.00 MWD (3) 8,865.48 88.68 148.66 6,360.93 6,255.23 -167.47 -2,834.22 5,959,843.75 546,877.27 11.93 2,706.50 MWD (3) 8,900.52 90.92 146.79 6,361.05 6,255.35 -197.09 -2,815.51 5,959,814.25 546,896.17 8.33 2,699.63 MWD (3) 8,930.60 91.51 143.97 6,360.41 6,254.71 -221.84 -2,798.43 5,959,789.62 546,913.42 9.58 2,692.53 MWD (3) 8,960.35 92.06 141.67 6,359.49 6,253.79 -245.53 -2,780.46 5,959,766.06 546,931.54 7.95 2,684.23 MWD (3) 8,990.37 91.97 137.69 6,358.43 6,252.73 -268.40 -2,761.05 5,959,743.32 546,951.10 13.25 2,674.29 MWD (3) i 9,020.50 92.73 134.59 6,357.20 6,251.50 -290.10 -2,740.19 5,959,721.75 546,972.09 10.58 2,662.58 MWD (3) 9,050.57 89.54 131.95 6,356.60 6,250.90 -310.70 -2,718.31 5,959,701.30 546,994.11 13.77 2,649.51 MWD (3) 1 9,080.32 90.34 135.61 6,356.63 6,250.93 -331.28 -2,696.83 5,959,680.86 547,015.72 12.59 2,636.82 MWD (3) 9,110.36 91.26 138.35 6,356.21 6,250.51 -353.24 -2,676.34 5,959,659.04 547,036.36 9.62 2,625.55 MWD (3) 4111 9,140.18 89.26 141.26 6,356.08 6,250.38 -376.02 -2,657.10 5,959,636.40 547,055.75 11.84 2,615.73 MWD (3) 9,170.33 86.68 143.25 6,357.14 6,251.44 -399.84 -2,638.65 5,959,612.70 547,074.35 10.80 2,607.03 MWD (3) 9,200.53 84.99 145.83 6,359.34 6,253.64 -424.37 -2,621.18 5,959,588.29 547,091.98 10.19 2,599.49 MWD (3) 9,230.49 85.14 149.31 6,361.92 6,256.22 -449.56 -2,605.18 5,959,563.21 547,108.15 11.58 2,593.56 MWD (3) 9,260.53 85.45 152.97 6,364.38 6,258.68 -475.78 -2,590.73 5,959,537.09 547,122.77 12.19 2,589.45 MWD (3) 9,295.51 85.91 157.31 6,367.02 6,261.32 -507.42 -2,576.07 5,959,505.55 547,137.63 12.44 2,587.08 MWD (3) 9,325.73 87.45 160.89 6,368.77 6,263.07 -535.60 -2,565.31 5,959,477.45 547,148.58 12.88 2,587.12 MWD (3) 9,355.67 87.42 162.53 6,370.11 6,264.41 -563.99 -2,555.92 5,959,449.11 547,158.15 5.47 2,588.51 MWD (3) 9,390.96 86.71 157.59 6,371.92 6,266.22 -597.11 -2,543.91 5,959,416.08 547,170.38 14.12 2,589.14 MWD (3) 9,420.64 87.21 154.08 6,373.49 6,267.79 -624.15 -2,531.78 5,959,389.12 547,182.69 11.93 2,587.49 MWD (3) ' 9,450.51 88.74 151.39 6,374.55 6,268.85 -650.68 -2,518.10 5,959,362.69 547,196.54 10.36 2,584.21 MWD (3) 9,480.48 88.93 148.25 6,375.16 6,269.46 -676.58 -2,503.04 5,959,336.89 547,211.77 10.49 2,579.42 MWD (3) 4/21/2010 1056:34AM Page 4 COMPASS 2003.16 Build 69 ConocoPhillips ConocoPhillips Definitive Survey Report HUGHES Alaska Company: ConocoPhillips(Alaska) Inc. Local Co- ordinate Reference: 1 E - 15 Project: Kuparuk River Unit TVD Reference: 1E-15 @ 105.70ft (1E-15) I Site: Kuparuk 1E Pad MD Reference: 1E-15 @ 105.70ft (1E-15) i Well: 1E North Reference: TRUE j Weilbore: 1E Survey Calculation Method: Minimum Curvature Design: 1E-15 Database: EDM Alaska Prod v16 I Survey - - -- - _ _ �� -.- -- -- i I t MD Inc Azi TVD TVDSS +141/-S +EI W Map Map DES Vertical Northing Easting (.1100') Section Survey Tool Name Annotation (ft) (1 (1 (ft) (ft) (ft) (ft) (ft) (ft) (ft) 9,510.61 89.69 143.92 6,375.52 6,269.82 - 701.58 - 2,486.24 5,959,312.01 547,228.74 14.59 2,572.67 MWD (3) • 9,540.46 90.74 140.73 6,375.41 6,269.71 - 725.20 - 2,467.99 5,959,288.51 547,247.14 11.25 2,564.08 MWD (3) 9,570.54 92.30 137.90 6,374.61 6,268.91 - 748.00 - 2,448.40 5,959,265.84 547,266.88 10.74 2,553.94 MWD (3) 9,600.45 94.52 134.90 6,372.83 6,267.13 - 769.62 - 2,427.81 5,959,244.36 547,287.61 12.46 2,542.45 MWD (3) 9,630.75 93.78 133.36 6,370.64 6,264.94 - 790.66 - 2,406.12 5,959,223.47 547,309.44 5.63 2,529.73 MWD (3) 9,660.71 92.76 131.57 6,368.93 6,263.23 - 810.85 - 2,384.06 5,959,203.42 547,331.63 6.87 2,516.35 MWD (3) 9,690.48 92.92 135.07 6,367.45 6,261.75 - 831.25 - 2,362.43 5,959,183.17 547,353.39 11.75 2,503.45 MWD (3) 9,725.48 91.14 137.68 6,366.21 6,260.51 - 856.56 - 2,338.30 5,959,158.02 547,377.69 9.02 2,489.98 MWD (3) 9,765.00 91.14 137.68 6,365.43 6,259.73 - 885.78 - 2,311.69 5,959,128.98 547,404.48 0.00 2,475.59 PROJECTED to TD • 4/21/2010 10:56:34AM Page 5 COMPASS 2003.16 Build 69 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 06:03 08:48 2.75 10,085 0 PROD6 DRILL WPRT T Tag TD 10085'. POOH laying in Liner pill with Alpine beads chasing with KWF 08:48 09:03 0.25 0 0 PROD6 DRILL OWFF T Check for flow, Hold PJSM 09:03 10:03 1.00 0 0 PROD6 DRILL PULD T Looks good LD BHA - 10:03 13:33 3.50 0 2,400 COMPZ CASING PUTB T Safety meeting - P/U liner - safety joint drill 4 stands in 2 min. 45 secs. P/U 73 joints of liner in total. 13:33 14:33 1.00 2,400 2,400 COMPZ CASING PULD T P/U Coiltrak BHA - set in rams & strip over injector. 14:33 16:33 2.00 2,400 10,058 COMPZ CASING RUNL T RIH pumping . 3 bpm. Correct @ flag depth EOP. BHI depth + 4.5 ft. P/U weight 27K. above window. smooth through window. CT weight 13K RIH down to 10068' P/U 10 ft, Ct weight 35K.Set depth 10058' bottom & Liner top - 7701' 16:33 17:03 0.50 10,058 7,564 COMPZ CASING DLOG T P/U pump rate to 1.3 bpm, pressure 4200 psi, P/U and release off liner. _ CTT weight 23K. Stop pumping - POOH to RA tag for tie. Correction depth +1 ft. Liner top @ 7701'. Correct BHA depth. 17:03 18:33 1.50 7,564 0 COMPZ CASING TRIP T POOH - pumping KWF 18:33 18:51 0.30 0 0 COMPZ CASING SFTY T PJSM / Monitor well for flow. Well is dead 18:51 19:45 0.90 0 0 COMPZ CASING PULD T Pull off well and lay down BHA 27. 19:45 00:00 4.25 0 PROD7 STK BOPE T Begin Bi Weekly full BOPE witnes waived by Jeff Jones. AOGC 04/14/2010 Complete Full BOPE test. Set Anchored Billit @ 7701, P/U drill by BHA. Time mill off billit, drill build 00:00 04:45 4.75 0 0 PROD7 STK BOPE T Continue testing BOPE Witness waived by Jeff Jones AOGC. Test completed @ 0400, Install Checks back in UQC, Roll Coil back to KWF, Remove injector from well 04:45 06:45 2.00 0 73 PROD7 STK PULD T PJSM, M/U anchored billit BHA and Coil Trak BHA #28 06:45 08:45 2.00 73 7,700 PROD7 STK TRIP T RIH with EDC open pumping .3bpm. Tie in with +2 ft correction. Stop pumping and close the EDC. RIH through window. weight check © 7695' - 26K. Orientate HS. Tag TOL @ 7700' - TOB @ 7689'. P/U neutral weight and bring pumps online. Anchor set at 3500 psi. POOH to window. 08:45 10:45 2.00 7,700 0 PROD7 STK TRIP T POOH pumping KWF. 10:45 11:45 1.00 0 0 PROD7 STK PULD T Lay down Billet BHA & P/U Build BHA with 2.5 AKO. Billet setting tool looked good, all parts intact. Page 27 of 35 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 11:45 15:00 3.25 0 7,688 PROD7 STK TRIP T RIH pumping with EDC open. Swap well over to flow pro on bottom.Close EDC - RIH through window. 15:00 18:30 3.50 7,688 7,698 PROD7 STK KOST T Dry Tag TOB @ 7688.8' P/U weigth 26K, start pumping 1.4 bpm. 3700psi, BHP 4000, ECD 12.4, CT weight 7K, WOB .6 - milling lfph from 7688.4'. Stall @ 7888.7' P/U and start again. 18:30 18:45 0.25 7,698 7,700 PROD7 STK KOST T Going to 20 Ft/Hr, Pull up past billit. Looks good Drill to 7700. Wipe up to window 23 K PUW, 1.4 BPM @ 3940 FS 18:45 19:45 1.00 7,700 7,520 PROD7 STK WPRT T 7520, Pulled up through window, open EDC, circulate while waiting on well plan 11 19:45 20:00 0.25 7,520 7,700 PROD7 STK WPRT T Close EDC, RIH to drill build 20:00 21:27 1.45 7,700 7,752 PROD7 DRILL DRLG T 7700, Drill ahead RIW =12k 1.4 BPM @ 3848 PSI FS BHP =4006 21:27 23:27 2.00 7,752 7,810 PROD7 DRILL DRLG T 7752, Taking losses 1.49 in .5 BPM Out P/U off bottom and confirm rates, Annular dropped 175 PSI Go back to bottom and drill, Losses steadiliy improving BHP =3825 23:27 23:42 0.25 7,810 7,818 PROD7 DRILL DRLG T 7810, Losses have healed to 1.1 BPM out, 1.49 In BHP =3990, ECD =12.1 Slow ratty drilling, ROP = 5 to 15 FPH 7.2K RIW, 3k DH WOB 23:42 00:00 0.30 7,818 7,818 PROD7 DRILL DRLG T Midnight depth 7818 Landed @ 7810 TVD= 6321.69 1.8' high of plan, Continue to turn. Avg DLS 50.5 Loss rate @ .25 BBI /Min 04/15/2010 Complete build /turn section @7864. Drill intermidiate section to 8227 00:00 02:00 2.00 7,818 7,864 PROD7 DRILL DRLG T Drill by section landed with turn 1.44 BPM @ 3820 PSI FS 1.15 BPM Returns BHP =3980, ECD =12.12 02:00 02:09 0.15 7,864 7,500 PROD7 DRILL TRIP T Trip out of well 02:09 02:30 0.35 7,500 7,500 PROD7 DRILL TRIP T Stop above window, Trap 700 PSI, Shut down pump to open EDC Well taking fluid @ 550 PSI WHP. Shut in well and monitor for static BHP Stactic pressure @ window 3690 02:30 03:30 1.00 7,500 0 PROD7 DRILL TRIP T Trip out of well 03:30 03:45 0.25 0 0 PROD7 DRILL TRIP T At surface, Close EDC Page 28 of 35 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T ' Comment 03:45 04:45 1.00 0 0 PROD7 DRILL PULD T PJSM to pressure undeploy. Unable to maintain 700 PSI WHP. Well static @ 425. Will start MPL @ 500 PSI Lost 10 BBIs on trip out 04:45 07:15 2.50 0 72 PROD7 DRILL PULD T Load Motor in well. Make up pre loaded BHA - crew change and complete deploying BHA with 1.3 AKO 07:15 10:03 2.80 72 7,864 PROD7 DRILL TRIP T RIH holding MP schedule, pumping .8 bpm through open EDC. Tie in +2 ft correction, Close EDC RIh through window to TD 10:03 12:33 2.50 7,864 8,015 PROD7 DRILL DRLG T Drilling ahead - 1.40 bpm, 3800 psi, BHP 3996psi, ECD 12.2, ROP 65, WOB 1.8, Ct weight 7800, rate out 1.2. 12:33 13:15 0.70 8,015 8,015 PROD7 DRILL WPRT T Wiper trip - Ct weight 26K off bottom. Losing roughlyt 16 bbls an hour. 13:15 15:15 2.00 8,015 8,165 PROD7 DRILL DRLG T Drilling ahead - 1.40 bpm, 4000psi, BHP 4050, ECD 12.4, ROP 60, WOB 2.5, Ct weight 5K, Rate out 1.25 bpm. Losses are down to 10 -12 bbls hour. 15:15 17:00 1.75 8,165 8,165 PROD7 DRILL WPRT T Wiper trip Mad pass with Tie in. P/U weight 25K. 17:00 19:30 2.50 8,165 8,227 PROD7 DRILL DRLG T 8165', Drill ahead 1.40 BPM @ 4100 PSI FS RIW =6.6 DH WOB =1.5K BHP =4086 19:30 21:30 2.00 8,227 0 PROD7 DRILL TRIP T 8227, TD Intermediate build, POOH PUW =30K 21:30 00:00 2.50 0 0 PROD7 DRILL PULD T PJSM, Lay down BHA #30, P/U BHA #31 Surface test tool, 04/16/2010 M/U .9 Degree motor, Found debrie in injector sump during service. Observed dimples on coil while RIH. POOH to replace skates 00:00 00:27 0.45 0 0 PROD7 DRILL PULD T M/U and test tool BHA #31 with 0.9 degree motor 00:27 02:27 2.00 0 7,590 PROD7 DRILL TRIP T RIH 02:27 02:33 0.10 7,590 7,604 PROD7 DRILL DLOG T Log Gamma Tie in for a +1 foot correction, RIH 02:33 02:48 0.25 7,604 8,227 PROD7 DRILL TRIP T RIH to Drill, Set down at 8178 (tool face change) P/U and rih 02:48 04:01 1.23 8,227 8,300 PROD7 DRILL DRLG T 8227', Drill Ahead 1.43 BPM @ 3840 FS BHP =4150 RIW =7.7K with 1.6K WOB 04:01 06:25 2.40 8,300 8,379 PROD7 DRILL DRLG T 8300' Drilling Lost 10 BBIs since midnight No new pipe markings while on bottom drilling. Page 29 of 35 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 06:25 07:25 1.00 8,379 8,379 PROD7 DRILL WPRT T Wiper trip - 26K off bottom. Watch for pipe markings and they start @ 8215 - Markings Indicates obstructions was in the chains POOH during yesterday's trip to surface. 8215' is BHA depth minus BHA = 8143' EOP. 07:25 09:25 2.00 8,530 8,530 PROD7 DRILL DRLG T Drilling ahead - 1.35 bpm, BHP 4100, ECD 12.6, ROP 80, WOB 2.5, CT weight 1K, Out rate 1.20 09:25 12:25 3.00 8,530 71 PROD7 DRILL TRIP T Wiper trip - P/U weight 27K. Saw a slight weight bobble @ 8215' at surface. Decision made to POOH and change skates on injector head. Stopped and measured depth of inditations..065" POOH following Manged pressure schedule. 12:25 13:59 1.57 71 0 PROD7 DRILL PULD T CT @ surface - Safety meeting & Start undpleoying BHA. Lay down Motor & bit. Set up on Managed Pressure for Pipe stabbing. keeping 550 psi on WHP injecting roughly 2 -3 bbl /hour. 13:59 15:59 2.00 0 0 PROD7 DRILL RGRP T Pre job for cutting CT and unstabbing pipe. Unstab coil and secure to reel 15:59 17:59 2.00 0 0 PROD7 DRILL RGRP T PJSM Remove stripper from injector 17:59 19:59 2.00 0 0 PROD7 DRILL RGRP T PJSM Remove railings and guards from Injector. Inspect gripper block and chains for debrie 19:59 22:29 2.50 0 0 PROD7 DRILL RGRP T Remove Goosneck tilt cylinder, roll chains out, remove skates 22:29 23:59 1.50 0 0 PROD7 DRILL RGRP T Clean injector sump, Inspect injector for foreign objects Prep for skate instal - Total 24 Hr Fluid loss 61 BBIs 04/17/2010 Complete injector skate chage out. Perform slack mgmt. RIH and drill 00:00 01:30 1.50 0 0 PROD7 DRILL RGRP T Skates installed Check gooseneck rollers and lubricate. Continue to pump down MPL. 01:30 03:30 2.00 0 0 PROD7 DRILL RGRP T Install stuffing box, inspect stuffing box brass 03:30 04:30 1.00 0 0 PROD7 DRILL RGRP T PJSM, Rig up and stab coil into injector 04:30 05:00 0.50 0 0 PROD7 DRILL RGRP T PJSM, Install new packoffs, seal end of eline, Reverse circulate water into coil 05:00 07:30 2.50 0 0 PROD7 DRILL SLPC T Perform slack mngt - Cut 10 ft of coil off. 7 ft to find the cable. 07:30 10:00 2.50 0 0 PROD7 DRILL RGRP T Re -head CT connector, pressure & pull test. Continue pumping down MPL. injecting 2 bbl /hour @ 550 psi. 10:00 12:00 2.00 0 0 PROD7 DRILL RGRP T Begin Deploying BHA (same BHA as last run). Page 30 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 12:00 13:15 1.25 0 7,400 PROD7 DRILL TRIP T Start RIH, check SSSV & pressure guages. RIH 200 ft. Stop - problems with choke sequence. 13:15 13:30 0.25 7,400 7,413 PROD7 DRILL DLOG T Perform TIE -In log from 7398' do To 7410.39. + 3' Correction. Corrected depth = 7413.39. PUH 100' to check Injector & Coil tubing for marks or damage. 13:30 13:45 0.25 7,413 7,313 PROD7 DRILL TRIP T PUH 100' to check Injector & Coil Tubing for marks or Damage before going thru Window. 13:45 14:15 0.50 7,313 8,171 PROD7 DRILL TRIP T Stop & Trap 500 psi and Close EDC. Continue Tripping in hole thru Window. Inspecting pipe while RIH. 14:15 15:45 1.50 8,171 8,150 PROD7 DRILL CIRC T Tagged up @ 8171', WOB 3.5K, P/U weight 35K, backed pump rate down. RIH, orient TF, RIH 15 fpm, tagged @ 8159', P/U 100ft. RIH to 8158' tagged up, WOB 2K, P/U 60 ft. RIH 125right, made it to 8161' tag up. RIH down to 8150' slow speed to 7 fpm, slow pump rate to .8 bpm, and try to steer through. Made it to 8181' P/U pulled heavy. Slack off, ciculate to get 1:1. Continue working pipe with pump rates and slower POOH speeds. 15:45 16:27 0.70 8,150 8,180 PROD7 DRILL WPRT T Popped free increase pump rate to 1.3. Wipe up to window. Looks like clay returns over shaker. Pump low /high pill to get @ nozzle on bottom. 16:27 17:27 1.00 8,180 8,180 PROD7 DRILL WPRT T 8155' Light tag, P/U - lower pump rate - RIH to 8160' - P/U light over pull 31K, Increase pump rate to 1.4 while BHA wiper - RIH 8170' - P/U 31K BHA wipe, RIH to 8180' - Drag @ 37K for 15ft- BHA wiper. RIH to 8170' Clean P/U wipe up to 7720' - Add drill zone to low visc sweep - RIH for another bite while mixing up sweep. 17:27 18:15 0.80 8,180 8,200 PROD7 DRILL WPRT T RIH down to 8190' @ 1 bpm. Looked clean in /out. P/U weight 27K Wiper to 8100'. RIH to 8200'. Stacked @ 8196' P/U 29K to 8100'. RIH to 8200'. Wiper up to 7720' for hand -over and sweep is ready to pump. 18:15 20:00 1.75 8,200 8,531 PROD7 DRILL WPRT T Pump sweep - RIH. Tag @ 8199 twice, Reduce rate to .5 BPM RIH clean to 8146. PUH @ 5 FPM slight motor work @ 8198 & 8188. Turn around @ 8180 at full pump rate. Stack out @ 8260, 8294, 8324, 8390, Pump sweep and pull back up to 8380. Worked all areas where set down Page 31 of 35 • Time Logs Date From . To Dur S. Depth E. Depth Phase Code Subcode . T Comment 20:00 21:45 1.75 8,531 8,670 PROD7 DRILL DRLG T 8531', Drill ahead 1.33 BPM @ 3835 PSI FS RIW =2.5, DHWOB =1.9 BHP =4040 21:45 23:15 1.50 8,670 8,670 PROD7 DRILL WPRT T 8670, Sweeps coming out of bit, wipe to 7695 PUW =28k, Overpull with motor work @8150 Bobble @8199 going in. Full pump rate going in 23:15 00:00 0.75 8,670 8,726 PROD7 DRILL DRLG T 8670', Drill Ahead 1.35 BPM @ 3610 PSI FS Lost 99 BBIs to formation 04/18/2010 Drilled from 8958 to 9555 00:00 01:12 1.20 8,726 8,815 PROD7 DRILL DRLG T Drilling Ahead 1.35 BPM @ 3610 PSI FS 01:12 02:45 1.55 8,815 8,815 PROD7 DRILL WPRT T 8815 Wiper to window, with low high sweep PUW =30K 1.37 BPM @ 3720 BHP =4039 Motorwork 8182 & 8141 with light overpulls Clean run in at full pump rate 02:45 04:45 2.00 8,815 8,958 PROD7 DRILL DRLG T 8815, Drill Ahead 1.35@ 3670PSI FS RIW =6.7K with 1.6K DH WOB, BHP =4090 ROP 75 FPH 04:45 05:45 1.00 8,958 7,580 PROD7 DRILL WPRT T 8958 Wiper to window with 5 & 5 low high sweep 1.34 BHP @3630 PSI FS BHP =4103 Light motor work 8181 -8142 PUH and 8145 -8190 RIH 05:45 07:00 1.25 7,580 8,958 PROD7 DRILL DLOG T Tie in to RA Tag. -.5 ft correction. Continue Back down to last drill depth. 07:00 08:45 1.75 8,958 9,050 PROD7 DRILL DRLG T 8959, Drill Ahead 1.35 bpm @ 3940 psi BHP =4168 psi RIW= 6.6K w/1.68k DH WOB ROP= 38 - 50 fph 08:45 09:30 0.75 9,050 9,110 PROD7 DRILL DRLG T Pick -up and made tool face change. Up Wt =27k. Continue w/ drilling operation. 09:30 11:48 2.30 9,110 9,110 PROD7 DRILL WPRT T 9110 Wiper to Window. PUW =29k 1.36 bpm @ 3730 psi BHP =4173 / Seen small overpull 8150' 11:48 14:03 2.25 9,110 9,161 PROD7 DRILL DRLG T 9110 Drill Ahead 1.4bpm @ 4028 psi RIH Wt= 9k WOB While Drilling= 1.78k ROB =65 -80 fph. Seen no problems while Tripping In Hole. Page 32 of 35 • I Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 14:03 14:33 0.50 9,161 9,215 PROD7 DRILL DRLG T Drilling Break Around 9161' ROP Down from 76 fph to 33 fph. 1.4 bpm @ 4075 psi WOB =1.6k to 1.9k Possible Fault area. 14:33 14:48 0.25 9,215 9,215 PROD7 DRILL WPRT T BHA Wiper Trip across slow drilling area from 9158' - 9215' Up Wt =28k 1.4 bpm / 3988 psi 4192 psi BHP 14:48 15:48 1.00 9,215 9,260 PROD7 DRILL DRLG T BHA Wiper Trip Look Good. 9215 Drill Ahead. 1.4 bpm @ 4040 psi ROP down to 10 - 15 W /2.4k WOB 15:48 18:03 2.25 9,260 9,260 PROD7 DRILL WPRT T 9260' Wiper To Window, W/ 10 & 10 low -high sweep PUW =28.5k 1.41 bpm @ 3875 psi BHP =4144 Seen slight over -pull again 8150' 18:03 19:33 1.50 9,260 9,408 PROD7 DRILL DRLG T 9260' Drill Ahead 1.32 BPM @ 3770 PSI FS BHP =4264 19:33 22:03 2.50 9,408 9,408 PROD7 DRILL WPRT T 9408, wiper to window with lo high sweep and tie in PUW =32k Clean trip up, Set down @ 8202, tool face change, went right through Correct -2 at RA Tag 22:03 23:48 1.75 9,408 9,555 PROD7 DRILL DRLG T 9408 Drill Ahead 1.35 BPM @ 3750 PSI FS RIW = -8k, DHWOB= 2K 23:48 00:00 0.20 9,555 9,550 PROD7 DRILL WPRT T 9555 Wiper to Billit with sweeps PUW =32K 04/19/2010 TD AL2 -01 Lateral @ 9765 M/U and Run liner to 9765, TOL =7542, Roll well to Seawater, F/P from 2100' 00:00 01:30 1.50 9,555 9,555 PROD7 DRILL WPRT T Contine on wiper from 9555 Motor work @ 8140 on way up Set down @ 8202, Adj. TF and clean pass through 01:30 03:30 2.00 9,555 9,705 PROD7 DRILL DRLG T 9555, Drill Ahead 1.3 BPM @ 3980FS RIW = -4K, 2K WOB BHP =4216 Swap to new mud 3% Clay Guard 2011' on system 03:30 05:15 1.75 9,705 9,705 PROD7 DRILL WPRT T Wiper trip to Billit PUW =30K 05:15 06:00 0.75 9,705 9,765 PROD7 DRILL DRLG T Continue drilling down to TD @ 9765' RIW= -3.6k 1.35 bpm / 3930 psi BHP =4182 psi 06:00 07:45 1.75 9,765 7,580 PROD7 DRILL WPRT T Wiper Trip To Window w/5 & 10 low - high sweep. Up Wt =30k 1.4 bpm @ 3882 psi. Motor Work @ 8185' & 8148' and slight over pull. Page 33 of 35 • Time Logs Date From To Dur S. Depth . E. Depth Phase Code Subcode T Comment 07:45 08:00 0.25 7,580 7,601 PROD7 DRILL DLOG P Tie -In with GR from 7580' to 7602.27'. Had -1 correction. New Corrected depth= 7601.27' 08:00 09:15 1.25 7,601 9,765 PROD7 DRILL TRIP P Continue in hole to TD Maintaining MB. RIH Wt= 11k 1.3 bpm @ 3670 psi. BHP =4022 psi. 09:15 10:30 1.25 9,765 9,765 PROD7 DRILL DISP P RIH to TD @ 9765'. Liner Pill @ Bit. PUH Laying in 1 for 1 pumping @ .45 bpm @ 50 fpm follow MPS UP WT =32k CTP =2225 psi. BHP =3905 psi 10:30 11:00 0.50 9,765 7,472 PROD7 DRILL DISP P Stop & Paint Flag @ 7472'. Continue to PUH Laying in 12.0 ppg KWF 1 for 1. Up Wt =20k CTP= 2200psi @ 1.1 bpm 11:00 11:45 0.75 7,472 5,272 PROD7 DRILL DISP P Stop & Paint Flag @ 5272'. Continue to POOH laying in 12.0ppg KWF @ for 1 Up Wt =15k CTP =2344 @ 1.1 bpm. 11:45 12:00 0.25 5,272 0 PROD7 DRILL OWFF P OOH With KWF @ surface. Observe Well for flow. 12:00 12:15 0.25 0 0 PROD7 DRILL SFTY P Hold PJSM on removing Drilling BHA. No Flow On Well 12:15 13:45 1.50 0 0 PROD7 DRILL PULD P Start Removing BHA from well. 13:45 18:45 5.00 0 0 COMPZ CASING PUTB P Held PJSM. Start Picking Up 2 3/8" • Liner 18:45 19:09 0.40 0 0 COMPZ CASING PULD P PU coil track, M/U to liner, stab on well and surface test tool 19:09 20:35 1.44 0 2,267 COMPZ CASING RUNL P RIH with liner 20:35 20:47 0.20 2,267 7,466 COMPZ CASING DLOG P Tie into flag for +6' correction Wt Chk 27K, RIH 20:47 23:02 2.25 7,466 9,765 COMPZ CASING RUNL P Tag bottom, PUW =42K, Set liner back on bottom Pump 1.3 BPM @ 4168 Pull up to 24K liner released Pull up 20' Pump 5 BBL hi vis spacer followed by seawater 23:02 23:32 0.50 9,765 9,585 COMPZ CASING DLOG P 9739 tie into formation -1 foot correction 23:32 23:59 0.46 9,585 4,000 COMPZ CASING TRIP P POOH Line up little LRS to freeze protect coil from 2100' 04/20/2010 FP well, set BPV, Rig Down. Rig released at 18:00. 00:00 01:30 1.50 4,000 0 COMPZ CASING TRIP P Continue tripping out of well, Freeze protect from 2100' 01:30 02:00 0.50 0 0 COMPZ CASING SFTY P OOH.Spaceout, PJSM 02:00 03:45 1.75 0 0 COMPZ CASING PULD P UnDeploy BHA #33 03:45 04:00 0.25 0 0 DEMOB WHDBO SFTY P PJSM On Steps for Setting BPV. Page 34 of 35 • • s 0[F AILEKKA SEAN PARNELL, GOVERNOR c ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVA1`ION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Mr. Von Cawvey Alaska Wells Manager ConocoPhillips Alaska Inc. P.O. Box 100360 Anchorage, Alaska 99510 -0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, 1E- 15AL2 -01 ConocoPhillips Alaska Inc. Permit No: 210 -016 Surface Location: 443' FSL, 815' FEL, SEC. 16, T11N, R10E, UM Bottomhole Location: 437' FNL, 2142' FWL, SEC. 21, T11N, R10E, UM Dear Mr. Cawvey: Enclosed is the approved application for permit to re -drill the above referenced service well. The permit is for a new wellbore segment of existing well KRU 1E -015A, Permit No. 210 -013, API No. 50- 029 - 20769- 01 -00. Injection 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, D aniel T. Seamount Chair DATED this C Sday of April, 2010 cc: Department of Fish & Game, Habitat Section w/o encl. (via e -mail) Department of Environmental Conservation w/o encl. (via e -mail) RECEIVES J STATE OF ALASKA . �e yr APR 1 3 2010 ALASKA OIL AND GAS CONSERVATION COMMISSION ®, ^ PERMIT TO DRILL J '� a{& SCons,COMMISslrn 20 AAC 25.005 la. Type of Work: A lb. Pr Well Class: Development - Oil ❑ Service - Winj Q • Single Zone El . lc. Specify if well is proposed for: Drill ❑ Re -drill El Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Re -entry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: U Blanket U Single Well 11. Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59 - 52 - 180 . 1 E 15AL2 - 01 • 3. Address: 6. Proposed Depth: 12. Field /Pool(s): P.O. Box 100360 Anchorage, AK 99510 - 0360 MD: 9783' • TVD: 6263' • Kuparuk River Field 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 443' FSL, 815' FEL, Sec. 16, T11 N, R10E, UM ` ADL 25651. Kuparuk River Oil Pool • Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1300' FSL, 1226' FWL, Sec. 16, T11 N, R10E, UM 469 4/14/2010 • Total Depth: 9. Acres in Property: 14. Distance to 437' FNL, 2142' FWL, Sec. 21, T11 N, R10E, UM 2560 Nearest Property: 24400' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: + 102 feet 15. Distance to Nearest Well Open Surface: x - 549710 • y - 5960030 • Zone 4 GL Elevation above MSL: • 41 feet to Same Pool: 1E-16 @ 675' , 16. Deviated wells: Kickoff depth: 7690 .ft. 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 101.6° deg Downhole: 4895 psig • Surface: 4264 psig • 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7# L - 80 ST - L 2233' 7550' 6245' 9783' 6263' 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) 8435' 6936' 8323' 6848' 7884' Casing Length Size Cement Volume MD TVD Conductor /Structural 112' 16" 326 sx AS 1 112' 112' Surface 2155' 10.75" 1025 sx AS Ill, 250 sx AS II 2193' 2193' Intermediate Production 8376' 7" 605 sx Class G 8410' 6916' Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 7478'- 7554', 7716'- 7739', 7742' -7796' 6190'- 6249', 6375'- 6393', 6396' -6438' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date: 4 0 22. I hereby certify that the foregoing is true and correct. Contact J. G. Eller @ 263 - 4172 hS Printed Name V. Cawvey Title Alaska Wells Manager V Signature Phon 265 Date I I � Commission Use Only Permit to Drill API umb ' Permit Appro I See cover letter Number: 2 /*C__) /�j 50- �� f j - 6 _ �(7 F' 2 "� Date: a ' 0 for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coal d methane, gas hydrates, or gas contained in shales: ©-- *-50� psi. 6 ke OP i Imo" — Samples req'd: Yes ❑ No Mud log req'd: Yes ❑ No Er Other: r Z Sao r S ` d 7; /'- ch . )-12S measures: Yes [' No ❑ Directional svy 4- regq'd: Yes 1 .e N 0 i 1 I J M (T { 0 !"[ OLr, /L 6U4-1',..4A_ Ofer i G-cc 41,-, w; -. Ala ZS - 4-1 m APPROVED BY THE COMMISSION DATE: �� , COMMISSIONER r Form 10 - 401 (Revised 7/2009) This permit is valid for 24 no tps'rgmtbe date of approval (20 AAC 25.005(9)) Submit in Duplicate �, 0_ yl. �S t o „„ .e44 _cis y / . iv • ConocoPhill Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 1E Pad 1E-15 1 E- 15AL2 -01 Plan: 1 E- 15AL2- 01 Standard Planning Report 13 April, 2010 BAKER HUGHES ConocoPhillips rate ConocoPhtlhhps Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co- ordinate Reference: Well 1 E -15 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project Kuparuk River Unit MD Reference: 1E-15 © 105.70ft (1E-15) Site: Kuparuk 1E Pad North Reference: True Well: 1E-15 Survey Calculation Method:. Minimum Curvature Wellbore: 1 E- 15AL2 -01 Design: 1 E- 15AL2 -01 _wp10 Project Kuparuk River Unit 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 1 E Pad 1 Site Position: Northing: 5,959,760.24ft Latitude: 70° 18' 3.022 N From: Map Easting: 549,889.51 ft Longitude: 149° 35' 45.358 W Position Uncertainty: 0.00 ft Slot Radius: " Grid Convergence: 0.38 ° Well - 1E-15 Well Position +N /-S 0.00 ft Northing: 5,960,029.95 ft • Latitude: 70° 18' 5.686 N +E / -W 0.00 ft Easting: 549,710.04 ft • Longitude: 149° 35' 50.538 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00ft Wellbore 1 E- 15AL2 -01 Magnetics Model Name Sample Date Declination Dip Angle Field Strength ( r) - (n • ) BGGM2009 3/25/2010 17.33 79.80 57,371 Design 1E- 15AL2 -01 wp10 Audit Notes: Version: Phase: PLAN Tie On Depth: 7,680.36 Vertical Section: Depth From (TVD) +N/ +E/ Direction (ft) (ft) (ff) ( 0.00 0.00 0.00 150.00 4/13/2010 12 :16 :52PM Page 2 COMPASS 2003.16 Build 69 i ti ;mi R �.. ConocoPhillips Fer Al ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co- ordinate Reference: Well 1 E - 15 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project Kuparuk River Unit MD Reference: 1E-15 © 105.70ft (1E-15) Site: Kuparuk 1E Pad North Reference: True Well: 1 E - 15 Survey Calculation Method: - Minimum Curvature Wellbore: 1 E - 15AL2 - 01 Design: 1 E 15AL2 01_wp10 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N /-S +E/-W Rate Rate Rate TFO (ft) ( (°) (ft) (ft) (ft) 0100ft) ( °/100ft) (1100ft) (°) Target 7,680.36 28.50 195.31 6,257.28 860.91 - 3,240.29 0.00 0.00 0.00 0.00 7,690.00 32.37 191.69 6,265.59 856.16 - 3,241.42 44.41 40.15 -37.55 -26.93 7,715.00 43.13 200.44 6,285.34 841.54 - 3,245.77 48.00 43.06 34.98 30.00 7,812.64 90.00 200.44 6,323.10 759.92 - 3,276.19 48.00 48.00 0.00 0.00 7,892.64 94.96 162.31 6,319.50 681.51 - 3,278.11 48.00 6.20 -47.66 278.00 8,042.64 94.96 135.20 6,306.29 554.95 - 3,201.34 18.00 0.00 -18.07 271.20 8,140.00 98.33 152.52 6,294.93 477.20 - 3,144.50 18.00 3.46 17.79 78.00 8,240.00 101.62 170.50 6,277.48 384.23 - 3,113.33 18.00 3.29 17.97 78.00 8,420.00 89.45 140.26 6,259.74 223.78 - 3,039.26 18.00 -6.76 -16.80 250.00 8,505.00 89.47 124.96 6,260.54 166.41 - 2,976.89 18.00 0.02 -18.00 270.00 8,625.00 90.25 146.55 6,260.84 80.95 - 2,893.66 18.00 0.64 17.99 88.00 8,805.00 92.35 178.89 6,256.65 -88.59 - 2,840.89 18.00 1.17 17.97 86.00 8,875.00 89.27 166.67 6,255.65 - 157.89 - 2,832.11 18.00 -4.40 -17.46 256.00 9,080.00 89.42 129.77 6,258.08 - 329.14 - 2,726.01 18.00 0.07 -18.00 270.00 9,110.00 89.42 124.37 6,258.38 - 347.22 - 2,702.08 18.00 0.01 -18.00 270.00 9,360.00 89.24 169.37 6,261.47 - 551.22 - 2,568.94 18.00 -0.07 18.00 90.50 9,460.00 83.20 152.37 6,268.11 - 645.11 - 2,536.42 18.00 -6.03 -17.00 250.00 9,538.00 90.11 140.12 6,272.67 - 709.67 - 2,493.23 18.00 8.86 -15.71 299.00 9,633.00 94.19 123.49 6,269.08 - 772.73 - 2,422.74 18.00 4.29 -17.50 284.00 9,783.00 90.39 150.25 6,262.98 - 881.14 - 2,321.26 18.00 -2.53 17.84 97.40 I I 4/13/2010 12:16:52PM Page 3 COMPASS 2003.16 Build 69 0 r) 1 i 'I ,` i. ConocoPhillips raPd1 COn©CQPht11rp5 Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co- ordinate Reference: Well 1 E - 15 Company: ConocoPhillips(Alaska) Inc. ND Reference: Mean Sea Level Project: _ - Kuparuk River Unit MD Reference: 1E-15 @ 105.70ft (1E-15) Site: Kuparuk 1 E Pad North Reference: True Well:. 1 E - 15 Survey Calculation Method: Minimum Curvature Wellbore: 1 E - 15AL2 - 01 Design: 1 E 15AL2 - 01 _wp10 Planned Survey I Measured TVD Below Vertical Dogleg Toolface Map Map Depth inclination Azimuth System +Ni-S +EI -W Section Rate Azimuth Northing Easting (ft) ( °) ( (ft) (ft) (ft) (ft) ( ( (ft) (ft) 7,680.36 28.50 195.31 6,257.28 860.91 - 3,240.29 - 2,365.71 0.00 0.00 5,960,869.32 546,464.45 ' TIP 7,690.00 . 32.37 191.69 6,265.59 856.16 - 3,241.42 - 2,362.16 44.41 - 26.93 5,960,864.56 546,463.35 KOP 7,700.00 36.60 195.71 6,273.83 850.67 - 3,242.77 - 2,358.08 48.00 30.00 5,960,859.06 546,462.03 7,715.00 43.13 200.44 6,285.34 841.54 - 3,245.77 - 2,351.68 48.00 26.68 5,960,849.92 546,459.09 3 7,800.00 83.93 200.44 6,322.43 771.74 - 3,271.78 - 2,304.24 48.00 0.00 5,960,779.95 546,433.54 7,812.64 90.00 200.44 6,323.10 759.92 - 3,276.19 - 2,296.20 48.00 0.00 5,960,768.10 546,429.22 4 7,892.64 94.96 162.31 6,319.50 681.51 - 3,278.11 - 2,229.26 48.00 - 82.00 5,960,689.70 546,427.81 End of DLS 48 7,900.00 94.99 160.98 6,318.86 674.55 - 3,275.80 - 2,222.08 18.00 -88.80 5,960,682.75 546,430.16 8,000.00 95.08 142.91 6,310.02 587.01 - 3,229.15 - 2,122.94 18.00 -88.92 5,960,595.53 546,477.39 8,042.64 94.96 135.20 6,306.29 554.95 - 3,201.34 - 2,081.27 18.00 -90.51 5,960,563.66 546,505.41 6 8,100.00 97.02 145.38 6,300.28 511.13 - 3,164.93 - 2,025.12 18.00 78.00 5,960,520.08 546,542.10 8,140.00 98.33 152.52 6,294.93 477.20 - 3,144.50 - 1,985.51 18.00 79.06 5,960,486.29 546,562.76 7 ' 8,200.00 100.42 163.26 6,285.13 422.44 - 3,122.24 - 1,926.97 18.00 78.00 5,960,431.69 546,585.38 8,240.00 101.62 170.50 6,277.48 384.23 - 3,113.33 - 1,889.42 18.00 79.75 5,960,393.54 546,594.54 8 8,300.00 97.76 160.26 6,267.36 327.10 - 3,098.39 - 1,832.48 18.00 - 110.00 5,960,336.52 546,609.85 8,400.00 90.86 143.58 6,259.80 239.52 - 3,051.59 - 1,733.23 18.00 - 111.73 5,960,249.26 546,657.23 8,420.00 89.45 140.26 6,259.74 223.78 - 3,039.26 - 1,713.43 18.00 - 112.99 5,960,233.60 546,669.66 9 8,500.00 89.47 125.86 6,260.50 169.30 - 2,980.97 - 1,637.10 18.00 -90.00 5,960,179.51 546,728.31 8,505.00 89.47 124.96 6,260.54 166.41 - 2,976.89 - 1,632.56 18.00 -89.86 5,960,176.64 546,732.40 10 8,600.00 90.09 142.05 6,260.91 101.25 - 2,908.24 - 1,541.81 18.00 88.00 5,960,111.95 546,801.47 8,625.00 90.25 146.55 6,260.84 80.95 - 2,893.66 - 1,516.94 18.00 87.93 5,960,091.75 546,816.19 11 8,700.00 91.17 160.02 6,259.90 14.12 - 2,860.02 - 1,442.24 18.00 86.00 5,960,025.15 546,850.27 8,800.00 92.30 177.99 6,256.85 -83.60 - 2,841.03 - 1,348.12 18.00 86.17 5,959,927.57 546,869.90 ' 8,805.00 92.35 178.89 6,256.65 -88.59 - 2,840.89 - 1,343.73 18.00 86.72 5,959,922.58 546,870.07 12 8,875.00 89.27 166.67 6,255.65 - 157.89 - 2,832.11 - 1,279.32 18.00 - 104.00 5,959,853.35 546,879.31 13 I 8,900.00 89.27 162.17 6,255.97 - 181.96 - 2,825.40 - 1,255.12 18.00 -90.00 5,959,829.32 546,886.18 9,000.00 89.33 144.17 6,257.20 - 270.82 - 2,780.45 - 1,155.69 18.00 -89.94 5,959,740.77 546,931.71 9,080.00 89.42 129.77 6,258.08 - 329.14 - 2,726.01 - 1,077.96 18.00 -89.72 5,959,682.81 546,986.53 14 9,100.00 89.42 126.17 6,258.28 - 341.44 - 2,710.24 - 1,059.42 18.00 -90.00 5,959,670.62 547,002.38 9,110.00 89.42 124.37 6,258.38 - 347.22 - 2,702.08 - 1,050.34 18.00 -89.96 5,959,664.90 547,010.581 15 9,200.00 89.30 140.57 6,259.39 - 407.78 - 2,635.92 - 964.81 18.00 90.50 5,959,604.78 547,077.14 9,300.00 89.24 158.57 6,260.67 - 493.64 - 2,585.48 - 865.24 18.00 90.32 5,959,519.27 547,128.14 9,360.00 89.24 169.37 6,261.47 - 551.22 - 2,568.94 - 807.10 18.00 90.09 5,959,461.81 547,145.06 16 9,400.00 86.79 162.60 6,262.86 - 589.98 - 2,559.26 - 768.70 18.00 - 110.00 5,959,423.11 547,154.99 9,460.00 83.20 152.37 6,268.11 - 645.11 - 2,536.42 - 709.53 18.00 - 109.76 5,959,368.14 547,178.19 17 I 4/13/2010 12:16:52PM Page 4 COMPASS 2003.16 Build 69 ConocoPhillips la '° ConocoPhillips Planning Report BAKER Alaska HUGHES Database: ,- _ EDM Alaska Prod v16 Local Co- ordinate Reference: Well 1 E - 15 Company: ' _ ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project 3 Kuparuk River Unit MD Reference: 1 E -15 © 105.70ft (1 E -15) Site: Kuparuk 1 E Pad North Reference: True Well: 1 E - 15 Survey Calculation Method: Minimum Curvature Wellbore: 1 E - 15AL2 - 01 Design: 1 E 15AL2 01_wp10 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/S +E/ W Section Rate Azimuth Northing Fasting ( (°) (°) (ft) (ft) (ft) (ft) ( 1100ft) (°) (ft) (ft) 9,500.00 86.73 146.06 6,271.62 - 679.32 - 2,516.03 - 669.71 18.00 -61.00 5,959,334.07 547,198.80 9,538.00 90.11 140.12 6,272.67 - 709.67 - 2,493.23 - 632.02 18.00 -60.45 5,959,303.87 547,221.80 18 9,600.00 92.79 129.28 6,271.09 - 753.20 - 2,449.25 - 572.33 18.00 -76.00 5,959,260.64 547,266.07 9,633.00 94.19 123.49 6,269.08 - 772.73 - 2,422.74 - 542.17 18.00 -76.28 5,959,241.28 547,292.70 19 9,700.00 92.55 135.46 6,265.13 - 815.18 - 2,371.22 - 479.64 18.00 97.40 5,959,199.18 547,344.50 j 9,783.00 , 90.39 150.25 6,262.98 • - 881.14 - 2,321.26 - 397.55 18.00 98.11 5,959,133.56 547,394.881 TD I 4/13/2010 12:16:52PM (�Pfgs.S 1 i A COMPASS 2003.16 Build 69 e ,,, • = ' 1 t = •• ■ , \ I., ,, Oman to Two North WELLBORE DETAILS: 1E- 15AL2 -01 REFERENCE INFORMATION - Project: KuparukRiverUnit Magnetic Nonh'21.83 Site: Kuparuk 1E Pad Coordinate (NIE) Reference Well 1E - 15, True North Magnetic Field Parent Wellbore: 1E- 15AL2 -PB1 Well: 1E -15 Strength Wh ( ND ) Reference. Me Se L BAKER Illliii�lry, "' Ti on MD 7680 Rf Y KI A f �i Wellbore: 1E•15AL2 - DP Angle: 8 or Section (VS) Reference: Slot- (0.00N, 0.00E) Conoc4PN11��Ips PIan:1E 15AL2 - wp10(1E•15l1E 15AL2 - 01) M Measured Depth Reference 1E- 15@105.708(1E -15) Calculation Method: Minimum Curvature HUG Y ■LS 1F- 15!1E -ISALI - 1000 ,' KOP TIP WELL DETAILS: 1E -15 Ground Level: 0.00 800 - +N / -S +FJ -W Northing Easting Latittude Longitude Slot End ofDLS 48_ 0.00 - 0.00 5960029.95 549710.04 70° 16' 5.686 N 149° 35 50.538 V4 600 ' SECTION DETAILS ANNOTATIONS + 400 6 � Sec MD Inc Azi TVDSS 4)/ -eFJ - W DLeg TFace VSec Target Annotation 7 ' 1 7680.36 28.50 195.31 6257.28 860.91 - 3240.29 0.00 0.00 - 2365.71 TIP 200 - $ - - - • - 2 7690.00 32.37 191.69 6265.59 856.16 - 3241.42 44.41 -26.93 - 2362.16 KOP 9 3 7715.00 43.13 200.44 6285.34 841.54 -3245.77 48.00 30.00 - 2351.68 3 a - 4 7812.64 90.00 200.44 6323.10 759.92 -3276.19 48.00 0.00 - 2296.20 4 0 1 ° , 5 7892.64 94.96 162.31 6319.50 681.51 - 3278.11 48.00 278.00 -2229.26 End of DLS 48 H . 6 8042.64 94.96 13520 6306.29 554.95 - 3201.34 18.00 27120 - 208127 6 0 - 200 - 12 b, 7 8140.00 98.33 152.52 6294.93 477.20 -3144.50 18.00 78.00 -1985.51 7 13 8 8240.00 101.62 170.50 6277.48 384.23 -3113.33 18.00 78.00 - 1889.42 8 9 8420.00 89.45 140.26 6259.74 223.78 303926 18.00 250.00 - 1713.43 9 + - 400 14 ' 1 10 8505.00 89.47 124.96 6260.54 166.41 - 2976.89 18.00 270.00 - 1632.56 10 .Z 15 - 600 11 8625.00 90.25 146.55 6260.84 80.95 - 2893.66 18.00 88.00 - 1516.94 11 c 12 8805.00 92.35 178.89 6256.65 -8859 - 2840.89 18.00 86.00 - 1343.73 12 17 13 8875.00 89.27 166.67 6255.65 - 157.89 - 2832.11 18.00 256.00 - 1279.32 13 ^ _800- - 14 9080.00 89.42 129.77 6258.08 -329.14 - 2726.01 18.00 270.00 - 1077.96 14 `. - 18 - - 1, 15 9110.00 89.42 124.37 6258.38 -34722 - 2702.08 18.00 270.00 - 1050.34 15 ....a 19 - - ID - - 16 9360.00 8924 169.37 6261.47 - 551.22 - 2568.94 18.00 90.50 - 807.10 16 p - l000 - - \_ _ _ 1E 15/1E -15AL2 - PB1 17 9460.00 83.20 152.37 6268.11 - 645.11 - 2536.42 18.00 250.00 - 709.53 17 rn 1E 15 /1E 15AL2 - 01 18 9538.00 90.11 140.12 6272.67 - 709.67 - 2493.23 18.00 299.00 -632.02 18 - 1200- - 19 9633.00 94.19 123.49 6269.08 - 772.73 -2422.74 18.00 284.00 - 542.17 19 - = 20 9783.00 90.39 15025 6262.98 - 881.14 - 232126 18.00 97.40 -397.55 TD 10-15/IF -1 CAI 2 - PB2 - - ---- --- --- -- -1400- m -1600 ) -1800- -4400 - 4200 -4000 -3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 6000- West( -) /East( +) (200 ft/in) -� ' . 6060 r -: 6120-- - - - . - - III 6180 TIP - - - - - . 6240- i KOP 8 9 10 11 12 13 14 15 16 17 1g 19 .3 End ofDLS48 6 7 - TD 1E- 15/1E-1<AL2 -1'B2 - . -- l' 6300- < 4 . - - -_ - - -- ` Q m 1 IE- 15/1E- 15AL2 -01 II- <lh -i AI .: 6360 - Trd arei U rn 1E- 15/1E -15AL2 -PBI '- m 6420- N m y 6480- - P. Ir-^ 6540- . 6600- 6660- - - - -2400 -2340 -2280 -2220 2160 -2100 -2040 -1980 -1920 1860 -1800 -1740 1680 -1620 -1560 -1500 -1440 -1380 -1320 -1260 -1200 -1140 1080 -1020 -960 -900 -840 -780 -720 -660 -600 - 540 -480 -420 -360 -300 -240 -180 -120 Vertical Section at 150.00° (60 ft /in) kinuthsto Tom North WELLBORE DETAILS: 1E- 15AL2 -01 REFERENCE INFORMATION �°"' h:57 Well: 1E -15 Sbengl66 Project: Kuparuk River Unit Mverehc Nodh:21.ea" Site: Kuparuk 1 E Pad Msg Coor6nate (N/E) Reference Well 1E-15, True North 57 Field 1n Parent i r 7 680 36 2 -P61 „ 04 Tie e o On n MD: 7680.36 Vertlwl(ND) Reference 1E-15S105.70fl(1E -15) BAKER Conac • WeUtwre: 1E- 15AL2 -01 DpArgk saw Section (VS) Reference Slot - (O.00N, 0.00E) oPh� dkps Plan: 1E- 15AL2 -01 wp10(1E- 15/1E- 15AL2 -01) g 0 Measured Depth Reference: 1E- 15 @105,70fl (1E -15) HUGHES Calculation Method: Minimum Curvature 5 ' - 671 : 15 /1E -15A 11 12111"- l2l -I -0I 11-1: 1]' -111 I / 2600 6790, 1E -12/1E -121 IPDI 2400 - - - 11 1- , l - - - /'tea `I: 12lll� 1_'1.2 -OIPH1 2200_ - - • - \ - r � 1 �� - - - - - - - - -_ - - - \ of 2000- 1800 ` -J -ll -I ELI \.� - IL- ln2 /kt- l.uirr,�l 1600 \ 1400 • 1200 ' 1000 / -.004 r '� 1E 800- • l( "/0, - - , • i"� 600 -\ \ \\\ 17,1 a 400 ------ --.,_ -. . \ 0 N 200 . 1 0- - -- - - - - -- \+ . \ — a!1 } ur, -200- \ / y \ I -1 c.;11 .1„ 1E- 15/1E -1 01 _ iAL2 - i -800- _ \ ' - � 1, - / r \ III -1000 • 1E- 15 /1E- 15AL2 -}B1 _ \' - • / \ F.''i4 \ , -1200- r - / -1400- • I1 - 15,11-- 15A1.2 -t'1;2 \ -1600- - - - - - / I.u2Ill - n2 " -1800- / , \ -2000- • - �, -` - 't• 2200- - 2400 I} ;a /u: i4 i -2600 IE - 04 /1E - 04 / I1. 71 /IL :IP15I -6400 -6200 -6000 -5800 -5600 -5400 -5200 -5000 - 4800 - 4600 -4400 - 4200 -4000 - 0 000 -3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -]800 -1600 -1400 -1200 -1000 800 - 600 -400 200 400 600 800 1000 1E-15 It 105.706 (1E-15) West(- )/East( +) (200 ft/in) 1E-15 Proposed CTD Sidetrack Last Updated: 13-Apr-10 3-1/2" Camco TRDP-1A nipple @ 1878 MD MEM ligam- 3-1/2" 9.3# K-55 EUE 8rd Tubing to surface Milo- 3-1/2" Camco KBUG gas lift mandrels @ 1948', 3690', 5218', 6256', 7271' 16" 65# H-40 shoet....• MI ______ @ 112' MD 1910.51- 1111111 Baker 3-1/2" PBR @ 7307' MD D.- Baker FHL packer @ 7321' MD • Mill MO' 3-1/2" Camco KBUG injection mandrels @ 7354', 7425', 7592' 10-3/4" 45.5# K-55 .....,„,..„, shoe @ 2193 MD . ■ Carbide blast rings 7446' - 7552' (7452-7538' CBL) Baker FB-1 packer @ 7663' MD w/ Baker SBE 1: ....,_ 3-1/2" Camco D landing nipple @ 7676' MD (2.75" min ID, No Go) 3-1/2" tubing tail @ 7682' MD C-sand perfs ■..1 CO 7478' - 7554' MD Sqz perfs (2/14/10) -, ....,. ,,,,',;•-..,^.- ' A, , AL2-01, TD = 9783' AL2, TD = 10,085' , 27550' - 7554' CBL :-a-' ; I M ' 2-3/8" liner 7550-9783' 2-3/8" liner 7690-10,058' 3 . ,, ..,.., Billet at 7690' AL2-PB3, TD = 9710' ' - ' ,", s - z-, ...— 7618 7638 CBL Unintended sidetrack at 7855 a) -, . ......... .......... --------- KOP #2 at 7557' MD --------------- ' _...- ----------------------------- — „ , .--- .-- -- AL2-PB2, TD = 10,135' ..-.-- KOP #1 at 7631' MD -- .----- .--- . ... .------...---- 2-3/8" liner 8200'-10,135 Baker flow-by monobore Billet at 8200 ' >I II v,,N. -,.-,. .....---.......--- . -N. .......-- ...- ....---- ...---- .--- ____----- „----. ' whipstocks z:','%; .. „,, ..- ..--- r ---- .. .. „•,.•. ....• -------- _ ... ,<A--_____________________:____________:::_) AL2-PB1, TD = 9835 ' 2-3/8" liner 8864'-9835' -- --------- --' Billet at 8855' 1 7:-------- I — — — — — imumw V V AL1 Lateral, TD = 8812' 7796' MD (plugged) .ii■iii - - - • -......., _ < 7 - - 2-3/8" liner 7623' - 8810' , ,....:..... .. Sidetrack, TD = 9800' 7" 26# K-55 shoe @ ' CIBP at 7656' ELM 2-3/8" liner 8326' - 9790' 8410' MD (7674' MD, 2/13/10) Billet at 8326 ......■ 11111■- • • RECEIVED ✓ APR 1 3 2010 ConocoPhillips Alaska Alaska Oil & Gas Gons. COITIMISSIOn P.O. BOX 100360 Anchorage ANCHORAGE, ALASKA 99510 -0360 April 13, 2010 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 a revision to the drilling application for Kuparuk 1 E- 15AL2 -01 (210- 016). The revision is necessary due to the kick -off point being moved more than 500' away from the original approved plan due to hole problems. The formation objective is the same as the original AL2 -01 lateral proposal . and the new TD is within 500' of what was originally proposed. This revision to the AL2 -01 lateral will not affect the quarter -mile injection review that was previously submitted. I understand that the well name (i.e. 1 E- 15AL2- 01) and API number (i.e. 50- 029 - 20769 -62) shall remain the same as was originally approved in PTD #210 -016. Attached to this application are the following documents that explain the proposed job operations: — Proposed Wellbore Schematic (updated) — Directional Plan Proposed operations are shown in blue in the enclosed wellbore schematic and summary of operations. If you have any questions or require additional information please contact me at my office 907 - 263 -4172. incerely, Gary Iler ConocoPhillips Alaska Coiled Tubing Drilling Engineer Page 1 of 2 4 • • Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, April 13, 2010 8:21 AM To: 'Eller, J Gary' Subject: RE: KRU 1 E -15AL2 (210 -015) & AL2 -01 (210 -016) Changes Gary, A new PTD will be needed for 1 E- 15AL2 -01. A revision of the existing PTD can be issued.... Submit the new directional and any other changes to the existing PTD and we will re -issue it. (will have the same PTD # and API #) Sounds like you will not need the BOP variance based on our phone conversation this morning. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From Eller, 3 Gary [ mailto :iGary.Eller @conocophillips.com] Sent: Monday, April 12, 2010 11:41 AM To: Schwartz, Guy L (DOA) Cc: Gantt, Lamar L Subject: KRU 1E -15AL2 (210 -015) & AL2 -01 (210 -016) Changes Guy — As we discussed over the phone, we've had an eventful weekend out at Nabors CDR2 while drilling Kuparuk laterals from the 1E-15 motherbore. I have attached two cross section diagrams — one dated April 9 and the other dated April 12. On the cross - section of April 9, we had already drilled and Tined laterals as follows: Lateral Drilled Lined AL2 7557' — 9835' 8855' — 9835' AL2 -01 8855' — 10,135' 8200' — 10,135' AL2 -02 8200' — 9710' n/a The AL2 -02 lateral only needed to be drilled another 100' or so to reach TD. We pulled up for a short trip, but when we went back down we found that we were unable to get past 7855'. We tried to get past this spot with 3 more assemblies with no success. Ultimately we tried drilling through this 'blockage' at 7855' in the hopes of intersecting the hole we had already drilled, but unfortunately that was not successful. Instead, we accidentally sidetracked at 7855' and since then we have been drilling ahead. One of the outcomes of this unplanned sidetrack is that the laterals listed above will now all become plugbacks as they are not cased to the parent wel(bore and are considered unlikely to remain open. So here are the revised lateral names as shown on the April 12 cross - section: Old Name New Name AL2 AL2 -PB1 AL2 -01 AL2 -PB2 AL2 -02 AL2 -PB3 The hole that we are currently drilling, shown on the April 12 cross- section as blue dots & line, is now the 1 E- 15AL2 lateral. No change is required to drilling permit 210 -015 for this AL2 lateral. However, the next lateral that we plan to drill (AL2 -01, 210 -016) will need to change. The approved kick -off point in the PTD was 8500' MD, but 4/13/2010 Page 2 of 2 i • we would like to move that kick -off point to 7700' MD. That will allow us to put liner across this problem interval so we don't lose the AL2 lateral that we're currently drilling. Although this moves the kick -off point 700' from the original plan, the proposed bottom -hole location and the proposed objective formation remain unchanged. Therefore, ConocoPhillips believes that a new drilling permit is not required as per 20 AAC 25.015(b)(1), and that a simple e-mail notification of the change is adequate. Please let me know if you concur. ConocoPhillips has one other request of the Commission. We anticipate reaching TD of the AL2 lateral tomorrow morning (April 13), and we are due for a bi- weekly BOP test that same day. Given the potential for a repeat of the hole problem at 7855', ConocoPhillips requests from the Commission that we be allowed one extra day to run liner into the AL2 lateral prior to conducting our BOP test. My fear is that the hole could collapse at -7855' during the time we're out of the hole for a BOP test, jeopardizing the AL2 lateral and ultimately wasting resources of the State. Following the BOP test we will resume drilling operations on the 1 E- 15AL2 -01 lateral. Thanks, and please contact me if we need to discuss this further. J. Gary Eller Wells Engineer ConocoPhillips - Alaska work: 907 - 263 -4172 cell: 907 - 529 -1979 fax: 907-265-1535 4/13/2010 • TRANSMITTAL LLETTER CHECKLIST NAME K/7 � / - ' 'j ( -' ` J PTD# ? - / ( 0 / ' () - _ Development t Service Exploratory Stratigraphic Test Non - Conventional Well FIELD: ( � � � - POOL: � /,�l-c . i/_ Per ( ) i /�( (1.19 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 rjew wellbore segment of existing well (If last two digits in API No permit (J No. Ca / API number are -�. o, / f C (J 50- - 1 between 60 -69) ion should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(0, 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 i- - * . Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 - _ -- Well Name: KUPARUK RIV UNIT 1E- 15AL2 -01 -__ Program SER - - Well bore seg PTD#: 2100160 Company CONOCOPHILLIPS ALASKA INC -_- Initial Class /Type SER / 1WINJ GeoArea 890 Unit 11160 -_- On /Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes Top prod interval and TD in ADL 25651 3 Unique well name and number Yes Kuparuk River Oil Pool, governed by Conservation Order No. 432C 4 Well located in a defined pool Yes Conservation Order No. 432C contains no spacing restrictions with respect to drilling unit 5 Well located proper distance from drilling unit boundary Yes boundaries and no interwell spacing restrictions. Wellbore will be more than 5 miles 6 Well located proper distance from other wells Yes from an external property line where ownership or landownership changes. 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 1 9 Operator only affected party Yes 1 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 4/14/2010 1 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 Area Injection Order No. 2B 1 15 All wells within 1/4 mile area of review identified (For service well only) Yes KRU 1E- 01PB1, KRU 1E -06, KRU 1E -16, KRU 1E-17, KRU 1E -30 16 Pre - produced injector: duration of pre production less than 3 months (For service well only) No Well will be flowed back for cleanup only. 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 E -15 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in 1E-15 1 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing cemented in 1E -15 21 CMT vol adequate to tie -in long string to surf csg NA Production casing set in 1E-15 22 CMT will cover all known productive horizons No OH slotted liner planned 23 Casing designs adequate for C, T, B & permafrost Yes (Revision for PTD needed since Kickoff pt. moved >500' ) 24 Adequate tankage or 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 Yes 310 -023 26 Adequate wellbore separation proposed Yes Proximity analysis performed . No issues. 27 If diverter required, does it meet regulations NA Wellhead in Place. BOP installed on tree. Appr 1 Date 28 Drilling fluid program schematic & equip list adequate Yes Max fm pressure= 4895 psi (14.9 ppg) Expected pressure is 11.5 ppg . Will drill with 10 ppg mud and MPD GLS 4/15/2010 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP= 4264 psi Will test BOP to 5000 psi • 1 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 on 1E pad. Rig has sensors and alarms. 34 Mechanical condition of wells within AOR verified (For service well only) Yes AOR completed. No issues. All wells cemented across Kuparuk zone. 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 1E pad are H2S- bearing. H2S measures required. Geology 36 Data presented on potential overpressure zones Yes Expected reservoirpressure is 11.5 ppg EMW; however, 1E -15 was an injector, so pressures Appr Date 37 Seismic analysis of shallow gas zones NA encountered may reach 15.1 ppg. Will be drilled using 10.0 ppg mud and managed pressure SFD 4/14/2010 38 Seabed condition survey (if off - shore) NA drilling technique to keep ECD at about 12.4 ppg. Hazards program notes potential for 39 Contact name /phone for weekly progress reports [exploratory only] NA encountering high- pressure (15+ ppg) stringers while drilling. Mitigation measures discussed. r Geologic Engineering Public RE -ISSUE due to change in program caused by hole problems. KOP raised from 8500' to 7700' MD and landing point moved Commissioner: Date: Commissioner: Date Date ate >500' from originally permitted location. BHL is within 500' of originally permitted location. A5 -sand spoke injector to improve fL/S ,Iv JKN sweep efficiency. 0 II -3; „ � ' a , , a L f SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Mr. Von Cawvey Alaska Wells Manager ConocoPhillips Alaska Inc. P.O. Box 100360 Anchorage, Alaska 99510 -0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, 1E- 15AL2 -01 ConocoPhillips Alaska Inc. Permit No: 210 -016 Surface Location: 443' FSL, 815' FEL, SEC. 16, T11N, R10E, UM Bottomhole Location: 664' FNL, 2201' FWL, SEC. 21, Ti 1N, R10E, UM Dear Mr. Cawvey: Enclosed is the approved application for permit to re -drill the above referenced service well. The permit is for a new wellbore segment of existing well Kuparuk River Unit 1E- 015A, Permit No. 2100130, API No. 50- 029 - 20769- 01 -00. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the 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 inspe • at (907) 659 -3607 (pager). Si 1 .oh or, .. C • issi • er ONC, DATED this day of February, 2010 cc: Department of Fish & Game, Habitat Section w/o encl. (via e -mail) Department of Environmental Conservation w/o encl. (via e -mail) RECEIVED STATE OF ALASKA JAN 2 6 2010 ALASKA OIL AND GAS CONSERVATION COMMISSION Alaska ®t! 8t Gas Cons. Comm ission PERMIT TO DRILL Anchorage 20 AAC 25.005 la. Type of Work: . 1 b. Proposed Well Class: Development - Oil ❑ Service - Winj 0 . Single Zone Q • 1 c. Specify if well is proposed for: Drill ❑ Re -drill Q Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Re -entry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: U Blanket U Single Well 11. Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59 - 52 - 180 • 1 E 15AL2 - 01 3. Address: 6. Proposed Depth: 12. Field /Pool(s): P.O. Box 100360 Anchorage, AK 99510 - 0360 MD: 10075 " TVD: 6290' Kuparuk River Field 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 443' FSL, 815' FEL, Sec. 16, T11N, R10E, UM • ADL 25651 . Kuparuk River Oil Pool Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1329' FSL, 1222' FWL, Sec. 16, T11N, R10E, UM 469 3/30/2010 Total Depth: 9. Acres in Property: 14. Distance to 664' FNL, 2201' FWL, Sec. 21, T11N, R10E, UM 2560 Nearest Property: 24400' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 102 feet 15. Distance to Nearest Well Open Surface: x - 549710 • y - 5960030 Zone 4 GL Elevation above MSL: 41 feet to Same Pool: 1E-16 @ 675' , 16. Deviated wells: Kickoff depth: 8500 1 ft. 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 104° d Downhole: 4895 psig Surface: 4264 psig 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7# L - 80 ST - L 2525 7550' 6245' 10075' 6290' 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) 8435' 6936' 8323' 6848' 7884' Casing Length Size Cement Volume MD TVD Conductor /Structural 112' 16" 326 sx AS 1 112' 112' Surface 2155' 10.75" 1025 sx AS III, 250 sx AS II 2193' 2193' Intermediate Production 8376' 7" 605 sx Class G 8410' 6916' Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 7478'- 7554', 7716'- 7739', 7742' -7796' 6190'- 6249', 6375'- 6393', 6396' -6438' 20. Attachments: Property Plat ❑ BOP Sketch Q Drilling Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements Q 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact J. G. Eller @ 263 - 4172 \ Printed Name Title Ala ska Wells Manager Cawve er g Signature t, . Phon 265 - 6306 Date 1/7zd Jc) Commission Use Only Permit to Drill API Num er: Permit Approval See cover letter Number: 21 C- / /II 50 - ?0 - 2-6>7‘; [.- C.r_..JI Date: 8/6 for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: -4 5000 p sc /° Bo /Z., /- Samples req'd: Yes ❑ No [(2 Mud log req'd: Yes ❑ No [J/ Other: • tc z /0 s L Ay n . -' r 7 H2S measures: Yes [E/No ❑ ectional svy req'd: Yes g No ❑ /, 41 [_ t-4-. < c ") -, M IT -'A at. f'fe, Fat.) b .�- k X + ; r' - C Qp er&)(i o i 4.c c. o e .... rs A l o ►. digr APPROVED BY THE COMMISSION DATE: a •' ' 0 gliOf , COMMISSIONER Form 10 (Revised 7/2009) This permit is vali fo i s t>4 c o if approval (20 C 25.005(g)) Submit in Duplicate • • RECEIVED Conoco Phillips JAN 2 6 2010 Alaska Alaska OBI & 0!3 Cent Commission P.O. BOX 100360 Anrherne ANCHORAGE, ALASKA 99510 -0360 January 25, 2010 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 permit to drill applications for four lateral sidetracks out of Kuparuk ' Well 1E-15 (PTD# 182 -102) using the coiled tubing drilling rig, Nabors CDR2 -AC. Work is scheduled to begin on 1E-15 in late March 2010. The CTD objective is to drill four A -sand lateral sidetracks (1E-15A, 1 E- 15AL1, 1 E- 15AL2, and 1 E- 15AL2 -01). The original wellbore perforations will be plugged with cement and a bridge plug prior to CTD operations (Sundry application is attached). Attached to this application are the following documents that explain the proposed job operations: - Permit to Drill Application Forms for 1E-15A, 1 E- 15AL1, 1 E- 15AL2, 1 E- 15AL2 -01 - Proposed & Current Wellbore Schematic - BOP Schematic - Detailed Summary of Operations - Directional Plans - Sundry application for plugging the KRU 1E-15 motherbore If you have any questions or require additional information please contact me at my office 907 - 263 -4172. 99ncerely, Gary Eller ConocoPh s Alaska Coiled Tubing Drilling Engineer • • KRU 1E -15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Summary of Operations: Well 1E -15 is a Kuparuk A -sand and C -sand injection well equipped with 3'/2" tubing x 7" casing. Four proposed A -sand CTD laterals will improve sweep efficiency and reserve recovery. Prior to drilling, the existing C -sand in 1E -15 will be squeezed with cement and the A -Sand perfs will be plugged with a bridge plug. After squeezing the existing C -sand perfs with cement, a mechanical whipstock will be placed in the 3'/2" tubing at the first kickoff point. The 1E -15A sidetrack will make a 2- string exit through the 3%2" tubing and 7" casing at 7635' MD. It will target the A4/5 sand northwest of the existing well with an 1890' lateral. The hole will be completed with a 2 slotted liner to the TD of 9525' MD with a liner top aluminum billet at 8400' MD. The 1E -15AL1 lateral will kick off from the aluminum billet at 8400' MD and will also target the A4/5 sand northwest of the existing well with a 430' lateral. The hole will be completed with a 2%" slotted liner to the TD of 8830' MD with the final liner top located just inside the 3'/2" tubing at 7630' MD. The 1E -15AL2 lateral will make another 2- string exit through the 3%2" tubing and 7" casing at 7557' MD via a second mechanical whipstock placed in the 3 tubing. It will target the A4 sand southeast of the existing well with a 2593' lateral. The hole will be completed with a 2W slotted liner to the TD of 10,150' MD with a liner top aluminum billet at 8500' MD. The 1E- 15AL2 -01 lateral will kick off from the aluminum billet at 8500' MD and will target the A4/5 sand . southeast of the existing well with a 1575' lateral. The hole will be completed with a 2 slotted liner to the TD of 10,075' MD with the final liner top located just inside the 3'h" tubing at 7550' MD. CTD Drill and Complete 1E -15: March /April 2010 Pre -Rie Work 1. Test packoffs — T & IC. 2. Positive pressure and drawdown tests on MV, SV, & SSSV. 3. DGLV's, load tbg & IA. MIT -IA. MIT -OA. 4. Obtain updated static BHP on A -sand & C -Sand 5. Pull tubing patch isolating injection mandrel at 7592' 6. Dummy injection mandrels at 7354' & 7452' 7. Set 3'/2" CIBP at 7679' MD to plug off A -sand perfs 8. Shoot squeeze perfs thru the 3'/2" tubing and 7" casing at 7630' & 7552' ELM 9. Lay in cement on top of CIBP isolating A -sand. Squeeze the C -sand perfs with cement. 10. RU slickline. Tag cement top. Pressure test cement squeeze. 11. Drill out cement from the 3'/2" tubing to 7665' using special clearance bi- center bit 12. Run whipstock dummy 13. Set monobore whipstock at 7635' MD with high -side orientation. 14. Prep site for Nabors CDR2 -AC. Page 2 of 5 1 l A i A January 25, 2010, FINAL • • KRU 1E -15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Rig Work 1. MIRU Nabors CDR2 -AC rig using 2" coil tubing. NU 7- 1/16" BOPE, test. 2. 1E -15A Lateral (A4/5 sand, northwest) a. Mill 2.74" 2- string window with high -side orientation at 7635' MD. b. Drill 2.70" x 3" bi- center lateral to TD of 9525' MD. c. Run 2%" slotted liner with an aluminum liner -top billet from TD up to 8400' 3. 1 E -15AL 1 Lateral (A4/5 sand, northwest) a. Kick off of the aluminum billet at 8400' MD b. Drill 2.70" x 3" bi- center lateral to TD of 8830' MD. c. Run 2 slotted liner from TD up to 7630' MD, up inside the 7" casing 4. 1E -15AL2 Lateral (A4 sand, southeast) a. Set 3'A" monobore whipstock in 3'/2" tubing at 7557' MD with low -side orientation. b. Mill 2.74" 2- string window with low -side orientation at 7557' MD. c. Drill 2.70" x 3" bi- center lateral to TD of 10,150' MD. d. Run 2 slotted liner with an aluminum liner -top billet from TD up to 8500' 5. 1E- 15AL2 -01 Lateral (A4/5 sand, southeast) a. Kick off of the aluminum billet at 8500' MD Lca--) b. Drill 2.70" x 3" bi- center lateral to TD of 10,075' MD. p . T-0 c. Run 2 slotted liner from TD up to 7550' MD, up inside the 3'/2" tubing 6. Freeze protect. ND BOPE. RDMO Nabors CRD2 -AC. Post -Rig Work 1. Obtain static BHP 2. Run GLVs 3. Flow back well to tanks or to the system for clean up prior to putting on injection 4. Conduct MIT -IA 5. Put well on injection Mud Program: • Will use chloride -based Biozan brine or used drilling mud (8.6 ppg) for milling operations, and chloride - based Flo -Pro mud ( -10.0 ppg) for drilling operations. There is a SCSSV installed in 1E -15, so we should not have to kill the well to deploy 2 slotted liner. Disposal: • No annular injection on this well. • Class II 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. Casing Program: • 1E -15A: 2 ", 4.7 #, L -80, ST -L slotted /solid liner from 8400' MD to 9525' MD • 1E- 15AL1: 2 ", 4.7 #, L -80, ST -L slotted /solid liner from 7630' MD to 8830' MD • 1E- 15AL2: 2 ", 4.7 #, L -80, ST -L slotted/solid liner from 8500' MD to 10,150' MD • 1E- 15AL2 -01: 2 ", 4.7 #, L -80, ST -L slotted/solid liner from 7550' MD to 10,075' MD Existing Casing/Liner Information Surface: 10 ", K -55, 45.5 ppf Burst 3580 psi; Collapse 2090 psi Production: 7 ", K -55, 26 ppf Burst 4980 psi; Collapse 4320 psi Page 3 of 5 O � ,' J January 25, 2010, FINAL KRU 1E -15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Well Control: • Two well bore volumes ( -180 bbl) 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 5000 psi. Maximum potential surface pressure in 1E -15 is 4264 psi assuming a gas gradient to surface and maximum potential formation pressure. Maximum potential formation pressure is based on the highest recent measured bottom hole pressure in the vicinity, which is 4895 psi at 7633' MD, 6310 TVD (i.e. 14.9 ppg) from 1E -15 > itself in late November 2009. Since that time, the A -sand has been allowed to crossflow to the lower - pressure C -sand, so the formation pressure in the A -sand is now reduced. • The annular preventer will be tested to 250 psi and 2500 psi. Directional: • See attached directional plans: 1. 1E -15A, plan #3 2. 1E- 15AL1, plan #3 3. 1E- 15AL2, plan #5 4. 1E- 15AL2 -01, plan #5 • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. • 1E -15 CTD northwestern laterals (A & AL1): —26,100' to property line, —1015' to wells 1E -11 & 1E -13 • 1E -15 CTD southeastern laterals (AL2 & AL2 -01): —24,400' to property line, —675' from well 1E -16 , Logging • MWD directional, resistivity, and gamma ray will be run over the entire open hole section. Reservoir Pressure • The most recent static BHP survey in well 1E -15 was taken January 2010 after allowing the A -sand to cross flow to the lower pressure C -sand for a month. The 72 -hour buildup measured reservoir pressure of 3719 psi at 6238' SSTVD, corresponding to 11.5 ppg EMW. We generally expect to encounter decreasing pressure as the laterals are drilled away from the mother well due to offset producing wells. Hazards • Lost circulation is usually not particularly troublesome in the A -sand, but it is a possibility in 1E -15 since , we expect to encounter decreasing formation pressure as the laterals are drilled away from the mother well. • Over - pressured zones are a potential hazard in 1E -15. Even though cross flow to the C -sand has significantly reduced A -sand pressure in the 1E -15 wellbore to 11.5 ppg, there is opportunity to encounter high - pressure stringers (up to 15.0 ppg) while drilling. With 10.0 ppg mud and expected • formation pressure, no choke pressure is needed to maintain well control. If high pressure formations are encountered, a combination of mud weight and /or choke could be needed to maintain well control. Use of the SSSV to deploy slotted liner should eliminate the need to spot heavy kill weight fluid, but if the SSSV fails then completion fluids in excess of 13.0 ppg will be needed to kill the well. • Shale stability is a potential problem, particularly in the build section where the A6 sand will be encountered. Will mitigate potential sloughing problems by cutting this interval at less than 70° hole angle, and by holding a constant pressure on the formation throughout drilling operations. • Well 1E -15 has no measured H since it is an injection well. Well 1E -31 is located 105' to the right side and 1E -16 is 120' to the left side of the 1E -15 surface location. 1E -16 has no measured H since it also is an injection well. Well 1E -31 has 60 ppm H as measured on 8/6/09. The maximum H level on the pad is 130 ppm from well 1E -24A (8/6/09). All H monitoring equipment will be operational. ' Ai Page 4 of 5 [' January 25, 2010, FINAL • • KRU 1E-15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Managed Pressure Drilling Managed pressure drilling (MPD) techniques will be employed to provide constant bottom hole pressure by using 10.0 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 allow use of less 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 installed between the BOPE choke manifold and the mud pits, and is independent of the BOPE choke. Using this technique will require deployment of the BHA under trapped wellhead pressure. Pressure deployment of the 2%" BHA will be accomplished utilizing the 2%" pipe rams and slip rams. The annular preventer will act as a secondary containment during deployment and not as a stripper. Well 1E -15 has a SCSSV, so the well should not have to be killed prior to running slotted liner. Operating parameters and fluid densities will be adjusted based on real -time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected at TD: • Expected reservoir pressure is 3711 psi at 7635' MD (6206' SSTVD), or 11.5 ppg EMW. • Expected annular friction losses while circulating: 763 psi (assuming annular friction of 100 psi /1000 ft due to the 3'/2" tubing) • Planned mud density of 10.0 ppg equates to 3227 psi hydrostatic bottom hole pressure at 6206' SSTVD • While circulating 10.0 ppg mud, bottom hole circulating pressure is estimated to be 3990 psi or 12.4 ppg EMW without holding any additional surface pressure. This is sufficient to overbalance expected formation pressure in 1E -15. If increased formation pressure is encountered, mud weight or choke pressure will be increased to maintain overbalance. • When circulation is stopped, —760 psi of surface pressure shall have to be applied to maintain the same borehole pressure as during drilling operations. Quarter -Mile Injection Review The following wells lie within one - quarter mile of the proposed 1E -15 CTD laterals. A detailed review will be made of each of these wells separately and subsequently to the submission of the drilling permits. • 1E -15 motherbore (injector) • 1E -15 CTD northwestern laterals (A & AL1): • 1E -11 (injector) • 1E -13 (injector) • 1F-19 (producer) • 1E -15 CTD southeastern laterals (AL2 & AL2 -01): • 1E -06 (producer) • 1E -14 (producer) • 1E -16 (injector) • 1E-17 (injector) • 1E -30 (injector) Page 5 of 5 1 I ft January 25, 2010, FINAL I -_ II I KUP 1E 15 ConocoPhi lips We717Attnlwt s - -r lHaxatigie`& MD TQ = „ a Wellbore API /UWI IF Id Name IW II Status Inel () I MD (ftKB) Ad Earn (MB) Alaska, Inc. Lorwc C ant 500292076900 KUPARUK RIVER UNIT INJECTING 49.62 LL 3,800.00 8,435.0 c111t1 ip 25 ( Q - Da_ b Annotation End -- _ liat - ,;. Date 11__ d te KB.G d (ft) Rig Release "' ;; ;1, - ,7$�7/@�2QOJt 10.3_4:gE 7d4 _, SSSV: TRDP _ ( _ 0 ..` 8/18/2008 Last WO: 11!5/1984_ wW" Con�g;.. 40.71 8/4/1982 S4lpata/7 PL:.::. „ -. - ,,,, - A obtion Depth (ftKB) End Data = Annotation Last Mod By End Date Last Tag: SLM 7,848 6113/2009 Rev Reason: SET STRADDLE PATCH triplwj 7/8/2009 easind`Strinas n ,, .,, r v : 4 - -r4 g7e- -� : w .' i _- , Str ng OD String ID Set D pth Sat Depth (110) String Wt strbg C si Desi p tion f n) l 9) Top (ftKB) (ftKB) (ftKB) (Ibs7R) Grade String Top Thrd :LS 112 CON DUCTOng cr R 16 19 .060 32.0 112.0 112.0 65.00 H-40 CONDUCTOR, 112 - .,. -^ _. -4646 -__ SURFACE 103/4 5794 0.0 2,193.0 2,192.8 45.50 K-55 SAFETY vLV, _ PRODUCTION 7 6.1 0.0 8,410.0 6 9162 26.00K-55 1,878 r T. . .'+c ,, tIliS S , _ ,.y . ._` , P TvbiM� Stun GAS LIFT, Str g OD String ID Set Depth Set Depth (TVO) String Wt String 1.948 Tubing Desch tion On) (1) Top (ftKB) MKS) (ftKB) (hbslft) Grade String Top Thad 11.1 TUBING 3 1/2 992 0 0 7 682 0 6348 6 920 .2 55 BTC IPC SURFACE, A� he min llole"( 4 11 -J il 7 u rg R urt & i st4et c :Y- r. , x :? 2,199 Top Depth GASLIFT, MD) Top loci 3,690 Top (ttKB) (ftKB) (1 .,_ Descripiilen Comment Run Dab 113 (in) 1,878 1,877.9 1.69 SAFETY ILV Camco TRDP- 1A -ENC 11/5/1984 2.813 GAS LIFT, 1,948 1,947.9 1.46 GAS LIFT CAMCO /KBUG /1/DMY / / / / Comment STA 6/5/1990 2.875 5,216 3,690 3,504.6 46.83 GAS LIFT CAMCO/KBUG /1/DMY / / / /Comment: STA 2 6/5/1990 2.875 _._...._._ ---....__. ..,_....,_... 5,218 4,524.6 45.86 GAS LIFT CAMCO /KBUG /1/DMY /// /Coment: STA3 6/5/1990 2.875 GAS LIFT, 6,256 6,256 5,252.5 43.86 GAS LIFT CAMCO /KBUG/t/DMY / /// Comment: STA 4 11/5/1984 2.875 - V „. _..� 6,291 5,277.7 43.53 GAS LIFT CAMCO /KBUG /1/DMY / /// Cont: STA 5 6/3/1990 2.875 ii 7,271 6,026.3 37.97 GAS LIFT CAMCO /KBUG /1/DMY /! // Comment: STA 6 6/5/1990 2.875 GAS LIFT. 6$91 - 7,307 6,054.7 38.07 PBR J Baker PBR __, ,4466_ 11/5/1984 3.000 7,321 6,065.7 38.11 PACKER Baker 'FHL' PACKER 11/5/1984 3.000 GAS LIFT, 7,354 6,091.6 38.20 INJECTION CAMCO /KBUG /1 /DMY / /// Comment CLOSED STA 7 7/20/1993 2.875 ll 7,425 6,147.4 38.44 INJECTION CAMCO /KBUG /1 /DMY //// Comment CLOSED STA 8 7/20/1993 2.875 7,575 6,264.9 38.42 PACKER PATCH: UPPER WEATHERFORD ER PACKER 2.87" OAL 7/6/2009 1.750 PBR, 7,307 - ,- (GOOD TEST TO 2500#) 1 iii 7,578 6,267.0 38.42 PATCH PATCH: SPACER PIPE, SNAP LATCH, SEAL ASSY OAL 7/6/2009 1.750 22.22" OAL (25.09" BETWEEN ELEMENTS) PACKER, 7,321 7,592 6,278.2 38.42 INJECTNN CAMCO /KBUG /1/DMY / /// Comment: CLOSED STA 9 7/20/1993 2.875 ji 7,602 6,286.4 38.89 PACKER PATCH: LOWER WEATHERFORD ER PACKER 2.87" OAL 7/3/2009 1.750 INJECTION, 7,663 6,333.8 38.78 PACKER Baker'FB -1' PACKER .......... .. ......___..._ ._. 11/5/1984 4.000 7.354 _4664. '4444. �.. 6664... 7,676 6,344.0 38.76 NIPPLE Camco '0' Nipple NO GO 11/5/1984 2.750 7,682 6,348.6 38.75 SOS Baker 11/5/1984 2.992 INJECTION, _.. 7.425 7,682 6,348.6 38.75 TTL 11/5/1984 2.992 7,884 6,506.5 38.52 FISH VANN GUN LOST DOWNHOLE 8/12/1993 8/12/1993 0.000 IPERFS. i uw .t ts' ^Xa."` x+ s ,� . o , 4°V i*g 4 �i .n 4:g a 'tF t 7a7e 7ss, - Pe lo ;& S * } :ks r, . s s A-..,., w r ` Y z �a -: I Snot Top (TVD) She CND) Dens _ PACKER, 7,575 -��'- Tpp ftKB) Btm (69(8) ( B) (ft Top - Zone Date _ (sh - -„ - Type. ,. - - „ _ Comment 7,478 7,554 6,188.9 6,246.5 C C - 3, C 8/12/1982 12.0 IPERFS GEO VANN GUNS - a' UNIT B, 1E -15 PATCH. JEC a INJECTION. 2haoll deg g TION. ON. 7,716 7,725 6,375.2 6,3f81" 2. 2 A -5, 1E -15 8/12/1993 4.0 RPERF 2.5.5 T' Titan ne, Hollow Cagier guns, 180 7,723 7,732 6,380.6 6,387.7 A -5, 1E -15 8/12/1982 12.0 IPERFS GEO VANN GUNS PACKER, 7,602 7,730 7,739 6,386.1 6,393.1 A-5, A4, 1E -15 11/5/1984 12.0 RPERF SCHLUMBERGER GUNS -. .iiiiii 7,742 7,769 6,395.5 6,416.6 A-4, 1E-15 8/12/1993 4.0 RPERF 2S" Titan Hollow Carver guns, 180 deg phase, 96 deg CCW orient PACKER, 7.663 . ' - -- P - - 7 ,749 7,776 6,401.0 6,422.0 A4, 1E -15 8!12/1982 12.0 IPER GEO VANN GUNS It 7,756 7,783 6,406.4 6,427.5 A ..12.0 RPERF SC LBERGER GUNS 7,785 4, 1E -15 11/5/1984 12 SCHLUMBERGER NIPPLE, 7,676 7,775 7,782 6,421.3 6,426.7 A4, 1E -15 8/12/1993 4.0 RPERF FS 2.5" Titan Holow Carrier guns, 180 deg phase, 96 deg CCW orient SOS, 7,662 7,782 7,789 6,426.7 6 43 !.2 A-4, 1E-15 8/12/1982 12.0 IPERFS GEO VANN GUNS 171. 7,682 ... 7,789 7,796 6,432.2 6,437.7 A4, 1E -15 11/5/1984 12.0 APERF SCHLUMBERGER GUNS Sflriiulatians'8 7ieatril2rtti§a � � :� 4 _' . � � x416.: � Bottom RPERF, I' - _ , Min Top Mas Btm Top Depth Depth 7,718 -7,725 6,' 1 . �' -.. I Depth Depth (TVD) (TVD) (MB) MKS) (ftKB) (1888) ___ Type Date _ Comment IPERFS,_ I 7,716.0 7 6,375.2 6,437.7 A - SAND 8/19/1993 A4/A5 SAND RE - FRAC, PUMP 193,397# BEHIND 7.723 . - - RE -FRAC PIPE j - - - 7,730.0 7,796.0 6,386.1 641 .7 FRAC 12/17/1984 A SAND FRAC RPERF. 11 • , 7,730 -7,739 - r t N es':`General:V , 4 ._- _ _ _ _ k � ,; : ,,.. 4 6646 , _ , .i. n , End Date Annotation RPERF, 5/24/2009 NOTE: C LEAK: FOUND @ 7596' ELMD AROUND GLM #9 7.742 -7.768 i1 _ )-, - 4'666"_. ._ - 6446..- -4 4„. .._ -. _ _ A-SAND RE -FRAC, 7,716 IPERFS, 7,749 - 7,776 - FRAC, 7,730 ' ,■� - RPERF, 'M: , 7,756 -7,783 RPERF, ii - t 7,775 -7,782 - 1 I IPERFS. , 7,782 -7,789 - _ APERF, 1' 7,789 -7,796 _ FISH, 7,884 • PRODUCTION. - . .. - 8,410 \ TD, 8435 - , `''' - ' A \ \ _ . .d.., . ,. .. .. . - . 4 464 -- 6664.. `�! • 1 E -15 Proposed CTD Sidetrack Last Updated: 21- Jan -10 3 -1/2 Camco TRDP -1A nipple @ 1878' MD -.n 3 -1/2" 9.3# K -55 EUE 8rd Tubing to surface 3 -1/2" Camco KBUG gas lift mandrels @ 1948', 3690', 5218', 6256', 7271' 16" 65# H -40 shoe @ 112' MD ! " Baker 3 -1/2" PBR @ 7307' MD ;, �w ; - Baker FHL packer @ 7321' MD 3 -1/2" Camco KBUG injection mandrels @ 7354', 7425',.7592' 10 -314" 45.5# K -55 shoe @ 2193 MD ■ Carbide ker FB -1 blast rinpacker gs 7446' 7552MD w/ ' (7452Ba` er 7538SBE ' CBL) k • �1;� Ba R VOLMATV _ 3 -1/2" Camco D landing nipple @ 7676' MD (2.75" min ID, No -Go) 3 -1/2 " tubing tail @ 7682' MD IF C -sand perfs 7478' ti4'. Top of cement at injection 7554' MD mandrel #8 for C -sand perfs \ �_ - ,.„,,,.,..,-M, AL2-01 Lateral (A5 sand, southeast) — V ,N TD = 10075' Liner top at 7550' fKOP #2 at 7557` MD . • KOP #1 at 7635' MD Wimil, — - - - Baker flow -by monobore _ — — — AL2 Lateral (A4 sand, southeast) whipstocks w ' �►�. / / TD = 1 ,0150 ' — Z _ _ — — _ Billet at 8500' e eaa`aa ,� ,- AL1 Lateral (A5 sand, northwest) TD = 8830' 4 A -sand perfs 7716' - : I Liner top at 7630' 7796' MD (plugged) . <.rs. _ -` A Sidetrack (A4 /A5 sand, Northwest) CIBP at 7679' MD TD = 9525' 7" 26# K -55 shoe @ ,' `„ `, -„ , ,. ,, , Billet at 8400' 8410' MD ...■1 1111■_ • • Nabors CDR -2AC Kuparuk Managed Pressure Coil Tubing Drilling BOP Configuration for 2" Coil Tubing Lubricator tom] Riser Annular/ Blind / Shear 2" Pipe / Slip (CT) Pump into Lubricator J L • ■■■ IN above BHA rams ■ ■ i 1 r -- � r Choke 1 'I 2-3/8" Pipe / Slip (BHA) It Choke Equalize Manifold '� 2 -3/8" Pipe / Slip (BHA) IN \ Kill ► / / a l\ ® - w ® •_ l r 1 Blind / Shear 2 "Pipe / Slip (CT) 0 11 Choke 2 11 I Valves IF Wing Valves C1 C-4 Tree Flow Cross 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 Equalizing Lines: 2- 1/16 ", 5M psi Choke Manifold: 3 -1/8 ", 5M psi Riser: 7- 1/16 ", 5M psi, C062 Union ORIGINAL • ConocoPhilli. s Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 1E Pad 1E -15 1 E- 15AL2 -01 Plan: 1 E- 15AL2- 01 Standard Planning Report 13 January, 2010 BAKER HUGHES R C; ,%,"\ ISM r.' . , ConocoPhillips ISM ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 1 E -15 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 1E -15 @ 105.70ft (1E -15) Site: Kuparuk 1 E Pad North Reference: True Well: 1E-15 Survey Calculation Method: Minimum Curvature Wellbore: 1 E- 15AL2 -01 Design: 1 E- 15AL2- 01_wp05.1 Project Kuparuk River Unit 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 I Site Kuparuk 1E Pad Site Position: Northing: 5,959„ r60.24ft Latitude: 70° 18' 3.022 N From: Map Easting: 549,889.51 ft Longitude: 149° 35' 45.358 W Position Uncertainty: 0.00 ft Slot Radius: " Grid Convergence: 0.38 ° Well 1E-15 Well Position +N / -5 0.00 ft Northing: 5,960,029.95 ft Latitude: 70° 18' 5.686 N +E/ -W 0.00 ft Easting: 549,710.04 ft Longitude: 149° 35' 50.538 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00 ft Wellbore 1 E- 15AL2 -01 Magnetics Model Name Sample Date Declination Dip Angle Field Strength ( °) (°) (nT) BGGM2009 3/25/2010 17.33 79.80 57,371 Design 1 E- 15AL2- 01_wp05.1 Audit Notes: Version: Phase: PLAN Tie On Depth: 8,500.00 Vertical Section: Depth From (ND) +N / -S +E/ -W Direction (ft) (ft) (ft) - ( 0.00 0.00 0.00 149.00 1/13/2010 7:55:49AM Page 2 COMPASS 2003.16 Build 69 0 R 1 ,3! ,r. r ✓ ConocoPhillips Van ConocoPhillips Planning Report RAKER Adask HUGHES Database: EDM Alaska Prod v16 Local Co.oudlnate Reference: Well 1 E -15 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project Kuparuk River Unit MD Reference: 1E -15 @ 105.70ft (1E -15) Site Kuparuk 1E Pad North Reference: True Well: 1 E -15 Survey Calculation Method: Minimum Curvature Wellbore: 1E-15AL2-01 Design: 1 E- 15AL2- 01_wp05.1 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +Nl-S +E/-W Rate Rate. Rate TFO (ft) (1 (°) (ft) (ft) (ft) (1100ft) eflOOft) ( °1100ft) ( °) Target 8,500.00 93.02 141.23 6,276.21 225.21 - 3,032.10 0.00 0.00 0.00 0.00 8,530.00 98.42 141.23 6,273.22 201.95 - 3,013.42 18.00 18.00 0.00 0.00 8,560.00 103.09 144.00 6,267.62 178.54 - 2,995.52 18.00 15.55 9.23 30.00 8,590.00 104.43 149.38 6,260.48 154.20 - 2,979.52 18.00 4.47 17.95 75.00 8,620.00 101.68 154.16 6,253.70 128.46 - 2,965.71 18.00 -9.15 15.91 120.00 8,650.00 96.60 156.01 6,248.93 101.61 - 2,953.24 18.00 -16.93 6.19 160.00 8,680.00 93.80 151.38 6,246.21 74.84 - 2,940.01 18.00 -9.33 -15.46 239.00 8,755.00 91.38 138.08 6,242.81 13.82 - 2,896.83 18.00 -3.23 -17.73 260.00 8,830.00 90.64 124.60 6,241.48 -35.60 - 2,840.66 18.00 -0.98 -17.98 267.00 9,030.00 90.52 160.60 6,239.38 - 191.88 - 2,721.18 18.00 -0.06 18.00 90.00 9,130.00 90.03 142.61 6,238.90 - 279.48 - 2,673.82 18.00 -0.49 -17.99 268.50 9,205.00 87.71 129.31 6,240.39 - 333.26 - 2,621.82 18.00 -3.10 -17.74 260.00 9,330.00 85.21 151.71 6,248.22 - 428.89 - 2,542.96 18.00 -2.00 17.92 97.00 9,430.00 83.90 169.75 6,257.79 - 522.46 - 2,510.23 18.00 -1.31 18.03 95.00 9,580.00 83.66 142.58 6,274.36 - 657.56 - 2,450.55 18.00 -0.16 -18.11 268.00 9,730.00 88.85 169.15 6,284.34 - 792.92 - 2,390.02 18.00 3.46 17.71 80.00 9,880.00 88.97 142.14 6,287.25 - 928.28 - 2,328.74 18.00 0.08 -18.00 270.00 10,075.00 89.16 177.25 6,290.53 - 1,108.29 - 2,262.14 18.00 0.10 18.00 90.00 1/13/2010 7:55;49AM Page 3 COMPASS 2003.16 Build 69 r I t , , 1.-' ConocoPhillips • VAIN ConocoPhillips Planning Report HUGHES Database: EDM Alaska Prod v16 Local Cc-ordinate Reference: Well 1E -15 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD, Reference: 1E -15 @ 105.70ft (1E -15) Site: Kuparuk 1E Pad North Reference: True Well 1E-15 Survey Calculation Method: Minimum Curvature Welibore: 1E-15AL2-01 Design: 1 E- 15AL2- 01_wp05.1 I Planned Survey I Measured TVD Below. Vertical Dogleg _ Toolface Map Map Depth Inclination Azimuth System +1'1/-S +E! W Section Rate Azimuth Northing Easting (ft) (Y) (0) (ft) (ft) (ft) (ft) (1100ft) (°) (ft) (ft) . 8,500.00 93.02 141.23 6,276.21 225.21 - 3,032.10 - 1,754.69 0.00 0.00 5,960,235.08 546,676.81 TIP! KOP 1E -15AL2 8,530.00 98.42 141.23 6,273.22 201.95 - 3,013.42 - 1,725.13 18.00 0.00 5,960,211.94 546,695.65 2 8,560.00 103.09 144.00 6,267.62 178.54 - 2,995.52 - 1,695.85 18.00 30.00 5,960,188.65 546,713.69 3 8,590.00 104.43 149.38 6,260.48 154.20 - 2,979.52 - 1,666.75 18.00 75.00 5,960,164.42 546,729.85 4 8,600.00 103.52 150.99 6,258.07 145.78 - 2,974.70 - 1,657.04 18.00 120.00 5,960,156.04 546,734.73 8,620.00 101.68 154.16 6,253.70 128.46 - 2,965.71 - 1,637.57 18.00 120.39 5,960,138.78 546,743.83 5 8,650.00 96.60 156.01 6,248.93 101.61 - 2,953.24 - 1,608.13 18.00 160.00 5,960,112.01 546,756.48 6 8,680.00 93.80 151.38 6,246.21 74.84 - 2,940.01 - 1,578.36 18.00 - 121.00 5,960,085.33 546,769.89 7 8,700.00 93.17 147.83 6,245.00 57.62 - 2,929.91 - 1,558.40 18.00 - 100.00 5,960,068.18 546,780.10 8,755.00 91.38 138.08 6,242.81 13.82 - 2,896.83 - 1,503.82 18.00 - 100.22 5,960,024.60 546,813.46 8 8,800.00 90.94 129.99 6,241.89 -17.43 - 2,864.52 - 1,460.39 18.00 -93.00 5,959,993.57 546,845.98 8,830.00 90.64 124.60 6,241.48 -35.60 - 2,840.66 - 1,432.53 18.00 -93.16 5,959,975.56 546,869.95 9 8,900.00 90.63 137.20 6,240.70 -81.34 - 2,787.86 - 1,366.14 18.00 90.00 5,959,930.18 546,923.05 9,000.00 90.55 155.20 6,239.67 - 164.09 - 2,732.47 - 1,266.67 18.00 90.14 5,959,847.80 546,978.99 9,030.00 90.52 160.60 6,239.38 - 191.88 - 2,721.18 - 1,237.04 18.00 90.33 5,959,820.10 546,990.45 10 9,100.00 90.18 148.01 6,238.96 - 254.82 - 2,690.89 - 1,167.49 18.00 -91.50 5,959,757.35 547,021.15 9,130.00 90.03 142.61 6,238.90 - 279.48 - 2,673.82 - 1,137.56 18.00 -91.58 5,959,732.81 547,038.38 11 9,200.00 87.86 130.19 6,240.20 - 330.06 - 2,625.66 - 1,069.39 18.00 - 100.00 5,959,682.55 547,086.88 9,205.00 87.71 129.31 6,240.39 - 333.26 - 2,621.82 - 1,064.68 18.00 -99.77 5,959,679.39 547,090.74 12 9,300.00 85.75 146.32 6,245.85 - 403.26 - 2,558.35 - 971.98 18.00 97.00 5,959,609.81 547,154.66 9,330.00 85.21 151.71 6,248.22 - 428.89 - 2,542.96 - 942.09 18.00 96.02 5,959,584.28 547,170.22 13 9,400.00 84.23 164.33 6,254.69 - 493.39 - 2,516.92 - 873.39 18.00 95.00 5,959,519.96 547,196.68 9,430.00 83.90 169.75 6,257.79 - 522.46 - 2,510.23 - 845.03 18.00 93.83 5,959,490.94 547,203.57 14 9,500.00 83.61 157.07 6,265.44 - 589.01 - 2,490.40 - 777.77 18.00 -92.00 5,959,424.53 547,223.83 9,580.00 83.66 142.58 6,274.36 - 657.56 - 2,450.55 - 698.49 18.00 -90.62 5,959,356.26 547,264.13 15 9,600.00 84.29 146.15 6,276.46 - 673.72 - 2,438.97 - 678.67 18.00 80.00 5,959,340.17 547,275.82 9,700.00 87.75 163.86 6,283.45 - 763.77 - 2,397.02 - 579.87 18.00 79.63 5,959,250.41 547,318.36 9,730.00 88.85 169.15 6,284.34 - 792.92 - 2,390.02 - 551.29 18.00 78.39 5,959,221.31 547,325.55 16 9,800.00 88.88 156.54 6,285.74 - 859.66 - 2,369.42 - 483.47 18.00 -90.00 5,959,154.72 547,346.59 9,880.00 88.97 142.14 6,287.25 - 928.28 - 2,328.74 - 403.70 18.00 -89.75 5,959,086.37 547,387.71 17 9,900.00 88.98 145.74 6,287.61 - 944.45 - 2,316.98 - 383.78 18.00 90.00 5,959,070.29 547,399.59 10,000.00 89.05 163.75 6,289.35 - 1,034.50 - 2,274.49 - 284.71 18.00 89.94 5,958,980.52 547,442.66 10,075.00 . 89.16 177.25 6,290.53 .-1,108.29 - 2,262.14 - 215.09 18.00 89.62 5,958,906.82 547,455.50 TD 1/13/2010 7 :55:49AM _ Pagg,4 COMPASS 2003.16 Build 69 Magn¢boNoueNdtn WELLBORE DETAILS: 1E- 15AL2.01 REFERENCE INFORMATION ►'- Project: Kuparuk 1E Pad MnaanexNwn:at.ea� Site: Kuparuk 1E Pad Co- ordinate(WE) Reference: Well IE•15, True 90,10 Meansaraa Parent Wellbore: 8 5 0 15AL2 Well: 1 E - sventtmax Vertical QVD) Reference: Mean Sea Level Tie on MD: 8500.00 C Wellbore: IE - 15AL2 - aPnnaa.ao.ea• Section (VS) Reference' Slot- (O.00N, O.00E) 4Q� ©C0�'Fl���t�75 i Dale Measured Depth Reference: 1E- 155105.7011 (1E•15) ���1 6 I _ PIan:1E 15AL2.01_wp05.1(1E 1511E 15AL2 - 01) MOM Calculation Method Minimum Curvature I 45 - -_. - -.0 - 4 - ±- -- - ----- :` - - -- _ - . - l TIP /KOPIE -15AL2 WELL DETAILS. 1E -15 301 - -__ Ground Level: 0.00 2- - +N / -S u-E1 -W Northing Easting Latiltude Longitude Slot 3- - - - - p 0.00 0.00 5960029.95 549710.04 70° 18' 5.686 N 149° 35' 50.538 W 150 4 _ - - _ , - - -- -- - - SECTION DETAILS ANNOTATIONS 5 1 7 Sec MD Inc Azi TVDSS +N( -S +EI.W DLeg TFace VSec Target Annotation 8 1 8500.00 93.02 14123 627621 225.21 - 3032.10 0.00 0.00 -1754.69 TIP IKOPIE -15AL2 - 151 - 9 2 8530.00 98.42 141.23 6273.22 201.95 - 3013.42 18.00 0.00 - 1725.13 2 - - - 3 8560.00 103.09 144.00 6267.62 178.54 -2995.52 18.00 30.00 - 1695.85 3 - - 10 4 8590.00 104.43 149.38 6260.48 154.20 - 2979.52 18.00 75.00 - 1666.75 4 11 , 5 8620.00 101.68 154.16 6253.70 128.46 - 2965.71 18.00 120.00 - 1637.57 5 0 -4- _, - - -- 12 - - 6 8650.00 96.60 156.01 6248.93 101.61 - 295324 18.00 160.00 - 1608.13 6 ,r) 7 8680.00 93.80 151.38 624625 74.84 2940.01 58.00 239.00 -1578.36 7 13 • 8 8755.00 91.38 138.08 6242.81 13.82 - 2896.83 18.00 260.00 - 1503.82 8 ^ - 600 14 r 9 8830.00 90.64 124.60 6241.48 -35.60 - 2840.66 18.00 267.00 -1432.53 9 + - 10 9030.00 90.52 160.60 6239.38 191.1' : 2721.18 18.00 90.00 -1237.04 10 -75 15 1 ► 1 1 9130.00 90.03 142.61 6238.90 •279.48 - 2673.82 18.00 268.50 - 1137.56 11 p - 12 9205.00 87.71 129.31 6240.39 - 33326 - 2621.82 18.00 260.00 - 1064.68 12 16' 13 9330.00 85.21 151.71 624822 - 428.89 - 2542.96 18.00 97.00 - 942.09 13 1 - 91 - 14 9430.00 8390 169.75 6257.79 - 522.46 - 251023 18.00 9500 - 845.03 14 ` - - 15 9580.00 83.66 142.58 6274.36 657.56 -2450.55 .� i 17" 55 18.00 268.00 -698.49 15 1051 - I 16 9730.00 88.85 169.15 6284.34 - 792.92 - 2390.02 18.00 80.00 - 551.29 16 0 1 17 9880.00 88.97 142.14 628725 -928.28 -2328.74 18.00 270.00 -403.70 17 .... 18 10075.00 89.16 177.25 6290.53 - 1108.29 - 2262.14 18.00 90.00 •215.09 TD - 1200 i , ,. li 1 E-1 11E•15AL2 i -135 _._ - i - -- - +. E - - -- ■ - 1500 -- - -- i -- -- - -- ' -- - _. - - -- 1 I 1 / - 3900 - 3750 -3600 -3450 -3300 -3150 -3000 -2850 -2700 -2550 -2400 -2250 -2100 •1950 -1800 -1650 -1500 -1350 -1200 6000 _._ West(- )/Bast( +) (150 ft/in) i 6os ,._. 11 1-: i [ • i I I 1 61001 - + { 0 1 1111 6150 . 4 I TIP/KOP 1E-15A \ 1- -( _ j I 1 (x_ 3 N J 62511 - -- -', \\�` -_i.. ) f - _ . _ $ - - _... - 4 . -- - -- -- __ ]]] ` IE 15 1E-15 L2-01 - 5 U 6300 1 -._- _....- _._ _ -._-• +- __ - a..r ----------- - - - 11.") m M 6350 t --- -_.. - -.. -- - -- -, t - _ L - - __ 11 } StI - 1- ._ - • 6400 - - } - -- _ . - - -- - -. I • 6450- - _ 6500 L___ i ■ , - I 6550 -. . • 1 . 1 1..•. . !.. . I I -1850 -1800 -1750 -1700 -1650 -1600 -1550 -1500 -1450 -1400 -I350 -1300 -1250 -1200 -1150 -1100 -1050 -1000 -950 -900 -850 -800 -750 -700 -650 -600 -550 -500 -450 -400 -350 -300 -250 -200 -150 -100 -50 0 50 Vertical Section at 149.00 (50 ft/in) Avmltsb7m6Noth WELLBORE DETAILS: 1E -15AL2 REFERENCE INFORMATION Project: Kuparuk River Unit MegnekNOM:21 1,4 iT Site: Kuparuk 1 E Pad Magnexrteld Parent Wellbore: 1E -15 Co- ordinate (NEE) Reference: Well 1E- 15, True North Well: 1E -15 scengd,.sra7nsn7 Tie on MD: 7500.00 V ec 5 105.7011(1 )Reference:tE-75 E1E•15) BAKEIR HUGHES Wellbore: 1E -15AL2 P lan:1E- 15AL2_wp05(1E- 15/10- 15AL2) n*57657156 euion ( VS ) Reference: Slob (5 0N.O.0 /� { �� 3RS201U Mme,eccM2roa S Measured Depth Reference. 1E- 15 @105.7011(IE•15) 4� rL 'fC Calculation Method: Minimum Curvature 11!1217 &12A11 —_ -- 67,, ..400 -,' I 1 ",,.. ° 6400 _... _ 2200,1 l Ik 15.1E 15A1.1 .,DOD - -. � 1800- -- ------ - _._ - -- - - - -- - - - - -- - - - --- --- - - - -_- _. ___.__._ - _ .[. ,n.. 11:r_�Krs ` 16346 I 16(10: -.. - .. __ -. _._._.... 1400(!_... , i £ - - F 1200 f — boo- c -,. 80o- , > >O'' 600 / w 400- / C> / Z -zoo-1 X y -400-' - -- - -- - -_ .:. — - - - -- - - - -- ,j „' -1: i''f — \- coo- -_ — - I/ \ \ \ • -1000 / I ..:tJ -ti; -12007 _____. ___.__ _ —_ .. — IL 15111..I. . .,N• __. - 140011 :.... -.... - -_.... ____. -._ - _. - -_- _.... ; i i - 160(:1.. _.... _._._... __. . -_.. -. 1$O(: i - 22(1( :. 1E-34 11 3 - 2400 -I 1 - 26001. _... 1 004110 -0{- C : t .L -? PR1 A -6400 -6200 -6000 -5800 -5600 -5400 -5200 -5000 -4800 -4600 -4400 -4200 -4000 -3800 -3600 -3400 -3200 -3000 - 2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 400 600 800 1000 1E-15 @ 105.70ft (1E-15) West( - )/East( +) (200 ft/in) • • Quarter -Mile Injection Review KRU 1E -15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Wells Within 1/4 -Mile of 1E -15 Northwestern Laterals (A & AL1) 1. KRU 1E -15 (motherbore injector) • Completed with 7 ", 26 #, K -55 casing on 7- 31 -82. Included 23 B &W Turbo -fin centralizers. Cemented with 280 sacks of lead + 325 sacks of tail "G" cement. Reciprocated casing for most of the job. No mention in cementing reports of lost returns. • C -sand perf'd 7478'- 7554', A -sand perf'd 7716'- 7796'. The tubing tail is at 7682' MD and the upper packer is at 7321'. The CBL of 7 -1 -82 shows very good cement around the C -sand but generally poor cement around the A -sand, although there is cement isolation between the two intervals. There is no reason to expect injection out of zone. • Well 1E -15 is currently shut -in awaiting sundry approval to plug the A -sand and C -sand perfs. 2. KRU 1E - 11 (injector, 1001' away) • Completed with 7 ", 26#, K -55 casing on 5 -4 -82. Target TOC = 6708' MD. Casing became stuck 13' off bottom while attempting to reciprocate casing prior to cement job. Lost full returns when casing got stuck. Cemented with 475 sacks of lead + 600 sacks of tail "G" cement with no returns during the cement job. • The CBL of 5 -5 -82 shows very poor cement around both the Kuparuk C -sand and A -sand. • Following the CBL of 5 -5 -82, they perforated at 7674' (i.e. above the C -sand) and performed a squeeze with 41 bbl "G" cement through a retainer to 1400 psi. Drilled out cement and retainer the following day and tested the squeeze perfs to 1000 psi. • On 10 -17 -84 performed additional squeeze work at 7910' (i.e. above the A -sand perfs) using 200 sacks of 15.9 ppg "G" cement. No bond log was run to assess the success of the squeeze. • 1E -11 was pre - produced in the C/A sands from April 1982 to May 1996, and was converted to injection in May 1996. The A sand was frac'd two different times -- in 1985 and 1991. Both were gelled water frac's. The C sand was never frac'd. The most recent IPROF (May 2007) showed 71% C -sand and 29% A -sand injection. Significant A to C sand crossflow was detected into the injection mandrels at 7577' and 7643' MD. • Present completion: C -sand perf d 7708'- 7794', A -sand perf'd 7996'- 8076'. The tubing tail is at 7955' MD and the uppermost packer is at 7491'. Well 1E -11 has been shut in since 2007 due to flowline problems but in 2009 it was put back on miscible gas injection, and water injection is expected to resume in 2011. 3. KRU 1E - 13 (injector, — 1144' away) • Completed with 7 ", 26 #, K -55 & L -80 casing on 7 -1 -82. Included 14 B &W Turbo -fin centralizers. Cemented with 564 sacks of lead + 670 sacks of tail "G" cement. Reciprocated casing for most of the job. No mention in cementing reports of lost returns. • C -sand perf d 71 10'- 7192', A -sand perf d 7345'- 7416'. The tubing tail is at 7055' MD and the only packer is at 6976'. The CBL of 7 -1 -82 shows good cement around both the C -sand and A- sand perfs. There is no reason to expect injection out of zone. Well 1E -13 is currently on long term shut in due to flowline problems. Page 1 of 3 February 5, 2010, FINAL • • Quarter -Mile Injection Review KRU 1E-15A, AL1, AL2, AL2-01 — Coiled Tubing Drilling 4. KRU 1F -19 (producer, —1103' away) • Completed with 3'/2" (9.3 ppf, L -80) x 5'/2" (15.5 ppf, L -80) tapered production casing on 3- 22 -96. Included 20 centralizers on the 3%" portion and 12 centralizers on the 5'/2" portion. Cemented with 230 sacks "G" cement. Calculated TOC was 7114' MD. Reciprocated casing until 20 bbl cement had turned the corner. Poor returns during cementing, but noted a 400 psi increase in pump pressure as cement moved uphole. • A -sand pert d 9124' - 9198'. There is no packer installed, but there is a 3'/2" sealbore at the 3'/2" x 5%2" crossover at 8772'. The 3'/2" tubing seals stab into this sealbore. The CBL of 4 -12 -96 shows excellent cement adjacent to the A -sand perfs. Well 1F -19 is actively producing from the A -sand. Wells Within 1/4 -Mile of 1E -15 Southeastern Laterals (AL2 & AL2 -01): 1. KRU 1E -06 (producer, —938' away) • Completed with 9% ", 47 #, L -80 casing on 9 -7 -80. No casing detail available. Cemented in 2 stages: first stage out the shoe and the second stage through a DV collar at 7127' MD. Cemented via the shoe with 300 sacks (stage #1) and via the DV collar with 900 sacks (stage #2) of "G" cement. There were no returns during the second stage of cementing through the DV collar. Drilled ahead to 9847' MD, but later the open hole and a portion of the cased hole was plugged back in stages to 7400'. • The CBL of 9 -20 -80 only logged down to 7124' MD, but it shows very poor quality cement across both the C -sand and A -sand perfs. • In December 1984 performed a cement squeeze at 6760' MD (i.e. below the C -sand perfs) through a retainer with 100 sacks of "G" cement ( -80 sacks behind pipe). Achieved a squeeze pressure of 3000 psi. No bond log was run to assess the success of the squeeze, nor did they pressure test the squeeze after drilling out. • The most recent PPROF in 1E-06 was obtained in March 2009. It showed 79% C -sand to 21% A- sand production contributions. No crossflow was detected. Both the A and C sand have been frac'd in this well. The A -sand was a gelled water batch frac in 1985, and the C -sand was frac'd with 71,000 lbs in 1988. • Present completion: C -sand perf'd 6648'- 6710', A -sand perf d 6838'- 6900'. Tubing tail is at 6801' MD, and the uppermost packer is at 6538'. Well 1E -06 is presently shut in due to low productivity, but it is expected to benefit from injection into the 1E -15 CTD laterals. 2. KRU 1E - 14 (producer, — 1430' away) • Completed with 7 ", 26 #, K -55 casing on 7- 16 -82. Included 12 B &W Turbo -fin centralizers on bottom 12 joints, plus 8 more uphole. Cemented with 350 sacks of lead + 425 sacks of tail "G" cement. Reciprocated casing for entire job and maintained full returns. • C -sand perf'd 6660'- 6724', A -sand pert d 6853'- 6888'. The tubing tail is at 6803' MD, and the upper packer is at 6430'. The CBL of 7 -17 -82 shows adequate cement across the C -sand perfs and excellent cement across the A -sand perfs. Another CBL run on 5 -4 -83 only logged down to 6620' and does not add anything significant to this assessment. Well 1E -14 is currently on long term shut in due to flowline problems. Page 2 of 3 February 5, 2010, FINAL • • Quarter -Mile Injection Review KRU 1E -15A, AL1, AL2, AL2-01 — Coiled Tubing Drilling 3. KRU 1E -16 (injector, -646' away) • Completed with 7 ", 26 #, K -55 casing on 8- 13 -82. Included 13 B &W centralizers on bottom 12 joints. Cemented with 355 sacks of lead + 300 sacks of tail "G" cement. Reciprocated casing for most of job, but casing was stuck high for a little while. Maintained full returns entire job. • C -sand perf d 7193'- 7256', A -sand perf'd 7396'- 7454'. The tubing tail is at 7319' MD, and the upper packer is at 7043'. The CBL of 8 -13 -82 shows excellent cement throughout the entire Kuparuk sand interval. There is no reason to expect injection out of zone. Well 1E -16 is currently on long term shut in due to flowline problems. 4. KRU 1E - 17 (injector, 1286' away) • Completed with 7 ", 26 #, K -55 casing on 8- 24 -82. Included 12 B &W Turbo -fin centralizers on the bottom 11 joints. Cemented with 340 sacks of lead + 310 sacks of tail "G" cement. Reciprocated casing for most of job. No mention made of losses or of the quality of returns during cementing. • C -sand perf'd 7373'- 7441', A -sand perfd 7587'- 7636'. The tubing tail is at 7523' MD, and the upper packer is at 7230'. The CBL of 8 -24 -82 shows excellent cement across the C -sand and A- sand perforated interval. There is no reason to expect injection out of zone. Well 1E -17 is currently on long term shut in due to flowline problems. 5. KRU 1E - 30 (injector, — 797' away) • Completed with 7 ", 26 #, K -55 casing on 9- 12 -82. Included 10 B &W Turbo -fin centralizers on the bottom 12 joints, plus 8 more uphole. Cemented with 300 sacks of lead + 350 sacks of tail "G" cement. Reciprocated casing for entire job and maintained good returns. • C -sand perfd 6792'- 6847', A -sand perf d 6991'- 7042'. The tubing tail is at 6909' MD, and the upper packer is at 6630'. The CBL of 9 -11 -82 shows excellent cement around both the C -sand and A -sand perfs. There is no reason to expect injection out of zone. Well 1E -30 is currently on long term shut in due to flowline problems. Page 3 of 3 February 5, 2010, FINAL - -� - Adn.aver. ara WELLBORE DETAILS: 1E -15AL2 REFERENCE INFORMATION Project: Kuperuk RiverUmt Magneto NoM:21,V Site: Kuparuk 1E Pad Co- ordinate (NIE) Reference: Wet 1E -15, True North Vaal xa 7 n Parent i on MD: 7 5 0. V .7011(1E -f BAKER �.� Well: 1E -15 eeeng/+.5785/.fenr Tre OnMD: 7500.00 R 1E -15 � 105 '� Wellbore: 1E•16AL2 DipAnple Section (VS)Reference: Slot - (0.00N,0.00E) 2rePato C0I"10C0P11iiIp5 PIan :1E - 15AL2 wpO5(1E 15/15 15AL2j Measued Depth Reference: 1E- 15 @ic6J0f (1E-15) HUGHES L_ __ -_-_"- - Cdculation Method. Minimum Curvahue 1E- 12 /1E -11ALI 2600 - - - - - - _ - - _ - - __ - - - - - - - 1E 15 /IE - 15A_ 2400 - -- - - - __ - - - - 636 - - - - - - - - - - - - - _ - - - - - IE- 1211E -12_F. s c - 6400 2200 - - - - - - - - - - • . .. - - __,,,,e , - - - - - - - - b•u 1 F- 15 -1 5AL I 211! - - -- - - - - - - - - - - - - __ _ - - _ - _ r 31( 1800 - - - - - - - - - - - - \ - - - -" 1E 102/B Latc6d / I \ 1600 - - _- - - - - - -- -_ - - - - -.,,, - - - -_ - -- - !- 1400 -- - - - - - -- - - - - - - - - - - - - - - - - - - -- - - - - r 1200 - - 1000: - - - - - - - - - - - - - e - - - - - - - , "' - - - - -- - 800 - -- - - - - -- -- - - 'tea - - - - - - - - . - - - \ „,-,0. % ^ - - - - - - - - 12- 1211E- 12A1 -2 - - - 600 - - -' -- - - - - - - -_ / _ 400] -- - - / - - 4 % 1 O 200-, - - - - - -- - - -_ _- - - ._ - - - — - - - r , \ ,--../ 0_. / - --4' \ ._. ____ . .0 - - - - 411, i Emit i E.,v, j -200 -- - - - - - - - - - - - -- - .. - - - - - - - - : 0 - - - - - -- - - - - - - - ' � J _ ��- - -- ,i 0 .11 - - - - - _ _ I lk _ . _..------ i z i \ \ ...- ' - \ i - _ _ - - 1E ]'r1E 15AL2.Ol j i - . - - - _ \ \ -1200 - - - - _ - - - - - - - - - -- IE 15/1E «, / - f 1 - I12/1E -02 - - — - - - - - / - - i " - - - - - -1800 - - - - -. -- -- - - - - - � - - 16-311/16-3 - - - - - j - - - - 1E-1 3 -2000 - - - - - _ . - - - - . - - 3r � - - - - - 1,a -- - - - - - - - - - - -22" - - __ _ - - - i - \ IE 3.0E - 34 - 2400 - - - - - - - - _ - - - - - - - - - - - - - - - - - - - - - 1E tE 31/1F:31FE1 - 6400 - 6200 - 6000 -5800 -5600 -5400 -5200 -5000 - 4800 -4600 -4400 - 4200 -4000 -3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1600 -1400 -1200 -1000 -800 - 600 -400 -200 0 200 400 600 800 1000 Wes gt(- '/East( +) (200 ft/in) Project: Kuparuk River Unit ' . Allmfflyst4TrusNorh VVELLBORE DETAILS: 1E-15A MapnelieNcoth.21.8.1' REFERENCEINFORMATION lakl Site: Kuparuk 1E Pad xt.gmecnal Parent Wellbore: 1E Co-ordinate (N/E) Reference: Wel 1E-15, True North Well: 1E-15 SfinplIv57857.18nT Tie on MD: 7600.00 Vertical (ND) Reference: 1E-15(g 105.7 flE-15) BAKER - CortocoPhillips _ Wellbore: 1E-16A Plan: E-15A_wp03 CAPA,01..80.84. Oldr3/25/2010 Modet 2= Section (VS) Reference: Slot - (0.00N, 0.00E) Measured Depth Reference: 1E 05 1.7011(1E-15) Calculation Method: Minimum Curvature HUGHES _ 1 _ 1 1E15A) W _- 4800- - _ . _ _ _ . _ . _ _ _ _ _ _ _ . _ _ _ 4200- . _ ' _ . 4000 _ . _ _ _ 3800- - - - - - - ( 1E - 3600- . - 3400- - - - - • Ir.- - IF-12-1[_' _ 3200 - - ow l . _ _ . . _ _ _ ■O'' _ . - -- \ • , \ \ \\, ,vo _ _ 3 - - - -,....- 2800 -- \ \ \ \ - - 2400 \ e , E1E-71_ C 2400 - -- -- - . _ _ _ 1E-15/1E-15A 1E-1 - " . \ - - - _ , ,.....,,, 0 11 1 1.63 0 " 1F 1E /1E 1800 - ..--, 1600 -- „-----e-, - - 1 c:9 /- - -‘" 1201 - - - ," ' . . ,, - - ''< ' \ 1000 - _ . --- " t - --- - ...-- ...-----'-' 4 , , 1E-102/44-L.teral / 800 1E-14/1E-14 --- c '69 .Zk, .; . , ■ ., , . ,..-,, ,..," c .,,, ■ , ,,,, - ,.„,„.._ ' ' ,, , '-'-_ / "---. 1 , - - - 1E-12/1E-E2AL2 -''', - --''-'-- . / . -/--- , ' ....„„ N i .--- ■ , -..„ `, , , -------__ 40 I . / --.______ . -,,,,: \ -_____. -_____ ' 1 -:-.<:- / 200- $ _ - ------.__:. ---.--.. - \ / / ' ' ,.< .. .,.. 0- - N . ' ''', ----- '----------------,_ —4 \ 7 ' -200- - -.. -- .. 1E416/1E-04, _. if,-1E-0 \ _------ ,. . - - - - - . - - — -- - . _------- - ------- \ i _ _ — \ - _ . ' _----_ — — --- IE-In/IE-16 .,------ , _.-------- , ■ -02:1E-9.1 ____---- - 600 - . - _ _ __ _ _ , - ---- - - - \ - 4:: , . 1E -6800 -6600 -6400 -6200 -6000 -5800 -5600 -5400 -5200 -5000 -4800 -4600 -4400 -4200 -4000 -3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 400 600 1E-15 t 105.7011(1E-15) West(-)/East(+) (200 ft/in) • TRANSMITTAL LETTER CHECKLIST WELL NAME KUPARUK RIVER UNIT 1E- 15AL2 -01 PTD# 2100160 Development X Service Exploratory Stratigraphic Test Non - Conventional Well FIELD: KUPARUK POOL: KUPARUK RIVER OIL RIVER POOL 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 KUPARUK RIVER UNIT 1E -15A, Permit No. X (If last two digits in 2100130, API No. 50 -029- 20769- 01 -00. Injection should API number are continue to be reported as a function of the original API number between 60 -69) stated above. PILOT HOLE In accordance with 20 AAC 25.005(0, 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 , '; Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK RIV Program IV UNIT 1E- 15AL2 -01 P - -- SER - -- Well bore seg D PTD #:2100160 Company CONOCOPHILLIPS ALASKA INC Initial Class /Type SER / PEND _GeoArea 890 Unit 11160 On /Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes Top prod interval and TD in ADL 25651 3 Unique well name and number Yes Kuparuk River Oil Pool, governed by Conservation Order No. 432C 4 Well located in a defined pool Yes Conservation Order No. 432C contains no spacing restrictions with respect to drilling unit 1 5 Well located proper distance from drilling unit boundary Yes boundaries and no interwell spacing restrictions. Wellbore will be more than 5 miles 6 Well located proper distance from other wells Yes from an external property line where ownership or landownership changes. 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes 1 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 13 Can permit be approved before 15 -day wait Yes SFD 1/27/2010 14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For Yes Area Injection Order No. 2B • 1 15 All wells within 1/4 mile area of review identified (For service well only) Yes KRU 1E- 01PB1, KRU 1E -06, KRU 1E -16, KRU 1E -17, KRU 1E -30 16 Pre- produced injector: duration of pre- production less than 3 months (For service well only) No Well will be flowed back for cleanup only. 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 E -15 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in 1E -15 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing cemented in 1E -15 21 CMT vol adequate to tie -in long string to surf csg NA Production casing set in 1E-15 122 CMT will cover all known productive horizons No OH slotted liner planned 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or 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 Yes 310 -023 1 26 Adequate wellbore separation proposed Yes Proximity analysis performed . No issues. 27 If diverter required, does it meet regulations NA Wellhead in Place. BOP installed on tree. Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max fm pressure= 4895 psi (14.9 ppg) Expected pressure is 11.5 ppg . Will drill with 10 ppg mud and MPD GLS 2/5/2010 ' BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP= 4264 psi Will test BOP to 5000 psi 1111 1 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 on 1E pad. Rig has sensors and alarms. 34 Mechanical condition of wells within AOR verified (For service well only) Yes AOR completed. No issues. All wells cemented across Kuparuk zone. 135 Permit can be issued w/o hydrogen sulfide measures No Wells on 1E pad are H2S-bearing. H2S measures required. Geology 36 Data presented on potential overpressure zones Yes Expected reservoir pressure is 11.5 ppg EMW; however, 1E -15 was an injector, so pressures Appr Date 37 Seismic analysis of shallow gas zones NA encountered may reach 15.1 ppg. Will be drilled using 10.0 ppg mud and managed pressure I SFD 1/27/2010 , 38 Seabed condition survey (if off - shore) NA drilling technique to keep ECD at about 12.4 ppg. Hazards program notes potential for 39 Contact name /phone for weekly progress reports [exploratory only] NA encountering high - pressure (15+ ppg) stringers while drilling. Mitigation measures discussed. Geologic Date: Engineering Date Public Date A5 -sand spoke injector to improve sweep efficiency. Commissioner: Coy 'ssioner:. Commissioner S ig z -s - -ic