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Home My WebLink About210-014 • IR Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. Q £ Q - Q Lt/ - Well History Fite Identifier Organizing (done) Two -sided III II11III IIII ❑ Rescan Needed 1 11111 I 11111 R CAN DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ Maps: 'Greyscale Items: ❑ Other, No/Type: ❑ Other Items Scannable by a Large Scanner Poor Quality Originals: \ C OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: BY: ( — M a r i a . . . ) Date: 1430/11 /s/ r ip _.,,,m......,_ Project Proofing 111111111 11111 BY: Maria Date: j a /s/ VY , _ Scanning Preparation F x 30 = 3 0 + I ` I = TO PAGES - !� 3Q (Count doe no t i ncl ude cover shee_) tv in BY: 4 Maria Date: t O� `� /s/ Production Scanning I 1111111111111111 Stage 1 Page Count from Scanned File: L -V5 (Count does include cove sheet) Pa a Count Matches Number in Scanning Preparation: YES NO BY: Maria Date: 0/ � 3 © '1 Is/ p I Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: Is/ Scanning is complete at this point unless rescanning is required. I I 111111 IIII ReScanned I I BY: Maria Date: /s/ Comments about this file: Quality Checked III IIIIIIIllIIIIII 12/22/2011 Well History File Cover Page.doc DATA SUBMITTAL COMPLIANCE REPORT 10/20/2011 Permit to Drill 2100140 Well Name /No. KUPARUK RIV UNIT 1E -15AL1 Operator CONOCOPHILLIPS ALASKA INC API No. 50- 029 - 20769 -60 -00 MD 8812 TVD 6347 Completion Date 4/20/2010 Completion Status 1WINJ Current Status WAGIN �''UIC Y REQUIRED INFORMATION / _. Mud Log No Samples No Directional Surveiy Yes DATA INFORMATION Types Electric or Other Logs Run: GR / RES (data taken from Logs Portion of Master Well Data Maint Well Log Information: • Log/ Electr Data Digital Dataset Log Log Run Interval OH / Tye Med /Frmt Number Name Scale Media No Start Stop CH Received Comments ED C Lis 19775 "Induction /Resistivity 7362 8812 Open 6/17/2010 EWR OH LIS plus PDF, CGM, and TIFF og Induction /Resistivity 2 Col 7632 8812 Open 6/17/2010 MD MPR, GR og Induction /Resistivity 5 Col 7632 8812 Open 6/17/2010 MD MPR, GR Log Induction /Resistivity 5 Col 7632 8812 Open 6/17/2010 TVD MPR, GR D C Directional Survey 8300 8812 Open Rpt Directional Survey 8300 8812 Open Well Cores /Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments • ADDITIONAL INFORMATION Well Cored? Y /6 Daily History Received? l.9 N Chips Received? .- Formation Tops -6/ N Analysis '4711 Comments: Compliance Reviewed By: __ —_ Date: O _061, t - STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION • REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Abandon r Repair well r Plug Perforations r Stimulate r Other © PROD to WAG Alter Casing r Pull Tubing r Perforate 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: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development r Exploratory r 210 -014 3. Address: 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 Stratigraphic [' Service ❑ 50- 029 - 20769 -60 7. Property Designation: 8. Well Name and Number: ADL 25651 1 E -15AL1 9. Field /Pool(s): Kuparuk River Field / Kuparuk Oil Pool 10. Present Well Condition Summary: Total Depth measured 8812 feet Plugs (measured) None true vertical 6347 feet Junk (measured) None Effective Depth measured 8810 feet Packer (measured) 7322, 7663 true vertical 6347 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 AL1 1189 2.625 8812 6347 0 0 Perforation depth: Measured depth: Slots: 8062 - 8811 True Vertical Depth: 6405 -6347 Tubing (size, grade, MD, and TVD) 3.5, J -55, 7682 MD, 6340 TVD RECEIVED V E Packers & SSSV (type, MD, and TVD) PACKER - BAKER FHL PACKER • eirta and 6066 TVD l'i 3 0 2010 PACKER - BAKER FB -1 PACKER @ 7663 MD and 6330 TVD SAFETY VLV - CAMCO TRDP -1A @ 1878 MD and 1878 TVD maikrs ag• 11. Stimulation or cement squeeze summary: Ax Intervals treated (measured): 1 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 I 15. Well Status after work: Oil r Gas r WDSPL r Daily Report of Well Operations x GSTOR r WAG pi 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: 310 -310 Contact Bob Christensen /Darrell Humphrey Printed Name , • .e ■ Ch ; t:d sen Title Production Engineering Specialist Signature i Phone: 659 -7535 Date c::?/ ? 821 n Tr 1 U RB MS sEP 3.0 7 6- 7.5e, z (m��`� . Form 10-404 Revised 7/2009 Submit Original Only 1 E -15AL1 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 09/20/10 IPRE STATE WITNESSED MIT -IA ( PASSED) 09 /21 /10ISTATE WITNESSED ( JOHN CRISP) MIT -IA ( PASSED ). ,, 45 "4s i KUP 1 E -15AL1 ) ConocoPhillips s , Well Attributes Max Angle & MD TD Wellbore APIIUWI Field Name Well Status Inci (°) MD MB) Act Btm (91168) ConomPw(hps 500292076960 KUPARUK RIVER UNIT INJ 101.98 8,480.31 8,812.0 Comment 825 (ppm) Date Annotation End Date KB -Ord (ft) Rig Release Date -- Well Config 1E- 154L1,9/620104. 1853 PM - 1 Schematic Last WO: 40.71 8/4/1982 Schematc - Actual Annotation Depth (ItKB) End Date Annotation Last Mod ... End Date Last Tag: SLM Rev Reason: GLV C/O Imosbor 9/6/2010 Casing Strings Casing Description String 0... Stri ID ... Top (1t68) Set D (5... Set Depth ( TVD) ... String Wt... String ... String Top Thrd Liner AL1 2 3/8 J 1 .995 I 7 ,623. 4 I 8,812.0 I 6,347.1 I 4.60 I L -80 1 STL Liner Details Top Depth (TVD) Top Inc! Nomi... Top (96(8) (RKB) ( °) Item Description Comment ID (in) CONDUCTOR, 112 7,623.4 6,302.4 33.91 DEPLOY Deployment Sleeve Baker 1.000 32 - SAFETY VLV, Perforations & Slots 1,979 Shot Top (TVD) Btm (TVD) Dens Top (11(B) Btm (RKB) IRKS) (MO) Zone Date (eh... Type Comment GAS LIFT, 8,062 8,811 6,404.6 6,347.1 A-4, 1E-15 3/24/2010 32.0 Slots Alternating solid /slotted pipe - 1,949 0.125 "x2.5" @ 4 circumferential • adjacent rows, 3" centers staggered SURFACE, II 18 deg, 3' non - slotted ends 30.2,193 055 LIFT Notes: General & Safety 3,690 a End Date Annotation 4/20/2010 NOTE: SIDETRACKw /LATERALS 1E -15A, 15AL1, 15AL2, 15AL2 -01 4/20/2010 NOTE: VIEW SCHEMATIC w /PJaska Schematic9.0 GAS LIFT. 5,219 GAS LIFT, I 6,256 L GAS LIFT, 6,291 C GAS LIFT. 7,272 ■ 564, 7,307 . PACKER, 7.322 INJECTION, 7,359 INJECTION, 7,425 IPERFS, 7,47&7,554 - APERF, a 7,550.7,554 RE WHIPSTOCK, 7,557 WINDOW AL2 -01, 7,555 -7,565 .. INJECTION, 7,592 APERF, 7,618-7,638 WHIPSTOCK, I 7,631 WINDOW ALI, 7,633 -7641 Mandrel Details Top Depth Top Port LOCATOR, (TVD) Inc( OD Valve Latch Size TRO Run 78 ma Stn To ltXB) (BBB) 1') Make Model (m) Sery Type Type (in) (psi) Run Dab Com... PACKER 7,663 - P( - 1' 1,948.5 1,948.4 1.46 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 8/312010 I■ 2 3,690.5 3,504.9 46.84 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 8/31/2010 NIPPLE, 7,676 I Rj 3 5,218.8 4,525.2 45.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 I. 4 6,255.6 5,252.2 43.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 5 6,291.2 5,277.8 43.53 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 SOS, 7,682 6 7,271.9 6,027.0 37.97 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 PRODUCTION, 7 7,359.0 6,095.5 38.22 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 30 Sbb. . . 8 7,425.4 6,147.7 38.44 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 8,082 Una/ AL1, 9 7,592.1 6,278.3 38.42 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 7.6238,612 TD (1E-15AL1), 6,612 • • sliAlr[E AIAEKKA 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. P.O. Box 100360 J 0 Anchorage, AK 99510 Re: Kuparuk River Field, Kuparuk Oil Pool, 1 E -1 SAL 1 Sundry Number: 310 -310 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 ? / day of September, 2010. Encl. . STATE OF ALASKA U "q W , o ALASKA OIL AND GAS CONSERVATION COMMISSION 'W . (6 'yo APPLICATION FOR SUNDRY APPROVALS CI 20 AAC 25.280 1. Type of Request: Abandon r Plug for Redrill [ j Perforate New Pool r Repair w ell ❑ Change Approved Program r Suspend r Rug Perforations r Perforate r Pull Tubing in Time Extension r Operational Shutdow n r Re -enter Susp. Well f Stimulate r . Alter casing [? Other:PROD to WINJ D • 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development n • Exploratory r 210 -014 . 3. Address: Stratigraphic ❑ Service r 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50- 029 - 20769 -60 • 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 n 1 E -15AL1 • 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): 8812 • 6347 - 8810' 6347' none none Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 16 112' 112' SURFACE 2163 10.75 2193' 2193' WINDOW AL1 8 8 7641' 6316' PRODUCTION 8296 7 8326' 6392' LINER AL1 1189 2.625 8812' 6347' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8062 -8811 6406 -6347 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= 6330 12. Attachments: Description Sunmary of Proposal n 13. Well Class after proposed work: Detailed Operations Program r BOP Sketch r Exploratory r Development r Service pl • 14. Estimated Date for Commencing Operations: 15. Well Status after proposed work: 6/22/2010 Oil r Gas r WDSPL r Suspended r 16. Verbal Approval: Date: WINJ r r GINJ r WAG r Abandoned 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 Phone: 659 -7535 Date Ct • Cc, tO Commission Use Only Sundry Number: 31O_3, 0 Conditions of approval: Notify Commission so that a representative may witness Plug Integrity r BOP Test r Mechanical Integrity Test (Location Clearance r RECOVED Other. SEP 1 7 2010 Subsequent Form Required: / D _ 4 c-/ asks ei & Gx Cat. Sian ��, / f Anchorage �i APPROVED BY )/ 2 I' �) V Approved by: 4 ,� C OM M ISSIONER THE COMMISSION Date: / ( / Form 10 -403 Revised 1/ 0`C0 5EP At l ' F 4 ?Jo 'd Submit in Duplicat � • • 1 E -15AL1 • 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 rye- producinginiec1r 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/0= 1600/0/330: Start T/I/0= 1600/3000/360: 15min. reading T/I/0= 1600/2910/360: 30min. reading T/I/0= 1600/2890/360 • KUP 1E-15AL1 COIIOCOPhi hips > °. Well Attributes 'Max Angle & MO TO - Alaska, Inc. Weubore APIIUWI Field Name Well Status Ina (1 MD MB) Act Btm (RKB) 500292076960 KUPARUK RIVER UNIT INJ 101.98 8,480.31 8,812.0 .,° Comment H2S (ppm) Date Annotation End Date KB-Grd (R) Rig Release Date Well CPnrw:- fE- 16AL7,gB2010 SSSV: TRDP Last WO: 40.71 8/4/1982 ScMnraae- JYe+al Annotation Depth (ftKB) End Date Annotation Last Mod ... 'End Date - Last Tag: SLM _ Rev Reason: GLV C/O - (mosbor _ 9/6/2010 . • - - - -� -- Casing Strings Casing Description String 0... String ID ... Top (RK8) Set Depth (6... Set Depth (TVO) ... String Wt... String ... String Top Thrd LinerAL1 23/8 1.995 7,623.4 8,812.0 6,347.1 4.60 L -80 STL ■ Liner Details Top Depth (TM (T Top Inc! Nom /... CONDUCTOR, Top (RKB) (RKB) ( °) Ism Description 1 Comment ID (in) 32 - t1z 7,623.4 6,302.4 33.91 DEPLOY Deployment Sleeve Baker 1.000 SAFETY 1,678 VLV, Perforations & Slots Shot I Top(TVD( atm(TVD) Dens Top (RKB) Btm (RKB) (RKB) (RKB) Zone Date (eh... Type Comment GAS 1s4s LIFT, I 8,062 8,811 6,404.6 6,347.1 A -4, 1E -15 3/24/2010 32.0 Slots Alternating solid /slotted pipe - 0.125"x2.5" @ 4 circumferential adjacent rows, 3" centers staggered 18 de SURFACE, 3D -2,193 g, 3' non - slotted ends GAS LIFT, Notes: General & Safety 3,690 a End Date Annotation II 4/20/2010 NOTE: SIDETRACKw /LATERALS 1E -15A, 15AL1, 15AL2, 15AL2 -01 4/20/2010 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 GAS LIFT, 5,219 L a 5A0 6 ,25 8,258 f GAS LIFT, • 6,291 GAS - , I 1) . 2 A . 7,27 /f P69, 7,307 10 Q < X , __EI PACKER, 7,322 " C I INJECTION, . 7,359 iti 1 INJECTION,.. 7,425 aK a a . PERFS, - 7 47 APERF, J 7,550 -7,554 WHIPSTOCK, 7,557 - WINDOW AL2 -01, 7,556 -7,565 ■ , i a ' INJECTION 7,59 1 APERF, 7,616-7,638 , WHIPSTOCK, • 7,631 WINDOW ALI, 7,533 -7,641 L ndrel Details O C ATOR, Top Depth Top Port 7,662 �� (TVD) Inc! OD Valve Latch Size TRO Run + PACKER, 7,663 "..∎ '_ Stn Top (66813) (RK8) (1 Make Model (In) Sent Type Type (in) (PM) Run Date Cont..._ r 1 1,948.5 1,948.4 1.46 CAMCO KBUG 1 GAS LIFT DMY - BK 0.000 0.0 8/31/2010 2 3,690.5 3,504.9 46.84 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 8/31/2010 NIPPLE, 7,676 - l t�, 3 5,218.8 4,525.2 45.86 CAMCO KBUG 1 GAS LIFT DMY 8K 0.000 0.0 6/5/1990 II 4 6,255.6 5,252.2 43.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 5 6,291.2 5,277.8 43.53 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 SOS, 7,682 E. 6 7,271.9 6,027.0 37.97 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 PRODUCTION, 7 7,359.0 6,095.5 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 30.8,410 Slots, , 8 7,425.4 6,147.7 38.44 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 8,062 - 8,611 Liner AL1, 9 7,592.1 6,278.3 38.42 CAMCO KBUG 1 INJ DMY - BK 0.000 0.0 7/20/1993 7,623-6812 _ 70 (1 E- 15AL1), -\ 8,612 • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Abandon Re air well pi WINJ to PROD r p r Plug Perforations r Stimulate r Other Alter Casing r Pull Tubing r Perforate 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: N. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development r i Exploratory r 210 -014 3. Address: `6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 Stratigraphic r Service r 50- 029 - 20769 -60 7. Property Designation: 8. Well Name and Number: ADL 25651 1 E - 15AL1 9. Field /Pool(s): Kuparuk River Field / Kuparuk Oil Pool 10. Present Well Condition Summary: Total Depth measured 8812 feet Plugs (measured) none true vertical 6347 feet Junk (measured) none Effective Depth measured 8810 feet Packer (measured) 7307, 7322, 7663 true vertical 6347 feet (true vertucal) 6055, 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 AL1 8 8 7641 6316 0 0 PRODUCTION 8296 7 8326 6392 0 0 LINER AL1 1189 2.625 8812 6347 0 0 0 0 0 Perforation depth: Measured depth: 8062 -8811 True Vertical Depth: 6406 -6347 Tubing (size, grade, MD, and TVD) 3.5, J -55, 7682 MD, 6340 TVD RECEIVED VED Packers & SSSV (type, MD, and TVD) PBR - BAKER PBR @ 7307 MD and 6055 TVD I U 2010 PACKER - BAKER FHL PACKER @ 7322 MD and 6066 TVD PACKER - BAKER FB -1 PACKER @ 7663 MD and 6330 TVD Alaska 0!I has CMS. Commission Anchorage 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 479 1100 2020 Subsequent to operation 229 151 1805 914 145 13. Attachments )+4. Well Class after proposed work: Copies of Logs and Surveys run Exploratory r Development G Service N tk. Well Status after work: Oil p Gas r WDSPL r Daily Report of Well Operations X GSTOR r WAG rj GASINJ r WINJ ra 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 0 .....L.......4?\,..nui MOMS JUN Z4 Form 10-404 Revised 7/2009 f'"` 7 7 1 " Submit Original Only • . t 1 E -15AL1 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 F I I 1 I I I I I I I I i I I I I • vs.-- KUP • 1E -15AL1 V ConocoPhillips s Well Attributes Max Angle & MD TD A1dS14•1 1iK Wel!bore API /UWI Field Name Well Status Inc! ( °) MD (RKB) Act Btn! (RKB) ta„x,P,il1ips 500292076960 KUPARUK RIVER UNIT INJ 101.98 8,480.31 8,812.0 Comment R2S (ppm) Date Annotation End Date KB.Grd (ft) Rig Release Date Well Cones. - IE- 15AL1, 4/2520108.0.27 AM - SSSV: TRDP Last WO: 40.71 8/4/1982 Schematic - Acluel Annotation Depth IRKB) 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 ... Top (MB) Set Depth (e... Set Depth (TVO) ... String Wt... String ... String Top Thrd Liner ALt I 23/8 I 1.995 7,623.4 I 8,812.0 I 6,347.1 l 4.60 I L -80 I STL Liner D etails Top Depth (TVD) Top Inc! Noml... Top (RKB) (RNB) ( °) Item Descripton Comment ID (In) coNOU Z 7,623.4 6,302.4 33.91 DEPLOY Deployment Sleeve Baker 1.000 • SAFETY VLV, Perforations & Slots 1,878 `� De ot Top (TVD) Btm (TVD) Dens Top MB) Btm (RKB) (RKB) (RKB) Zone Date lob... Type Comment GAS LIFT, 8,062 8,811 6,404.6 6,347.1 A-4, 1E-15 3/24/2010 32.0 Slots Alternating solid/slottedpipe - t 949 0.125 "x2.5" @ 4 circumferential adjacent rows, 3" centers staggered SURFACE, 18 deg, 3' non - slotted ends 30 -2,193 cASUFr, Notes: General & Safety S WO End Date Annotation 4/20/2010 NOTE: SIDETRACK w/LATERALS 1E -15A, 15AL1, 15AL2, 15AL2 -01 4/20/2010 NOTE: VIEW SCHEMATIC w /Alaska Schemadc9.0 GAS LIFT, 5,219 GAS LIFT, . 256 e,zs6 Z GAS LIFT. 6,291 GAS LIFT, 7,272 ' 1 2 1:— 780, 7.307 PACKER, 7,322 INJECTION, _ I 7.359 i INJECTION, 1 S 7,425 IPERFS, 7,478 -7,554 F APERF, 6 7,550.7,554 — L___1 WHIPSTOCK, WINDO X WINDOW AL2 -01, 7,558- 7.56.5 INJECTION, I 7,592 L APERF, 7,618 -7,638 , WHIPSTOCK. 4 7,631 WINDOW AL1, • \ 7,833 -7,641 Mandrel Details LOCATOR, Top Depth Top Port 7,562 e (TVD) Inc! OD Valve Latch Site TRO Run PACKER, 7,663 Stn Top (RKB) IRKS/ (% Make Model (In) Sere Type Type lint (psi) Run Dab Cons... 1 1,948.5 1,948.4 1.46 CAMCO KBUG GAS LIFT GLV BK 0.188 1,346.0 4/24/2010 2 3,690.5 3,504.9 46.84 CAMCO KBUG 1 GAS LIFT OV BK 0.250 0.0 4/24/2010 NIPPLE, 7,676 3 5,218.8 4,525.2 45.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 4 6,255.6 5,252.2 43.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 5 6,291.2 5,277.8 43.53 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 IlL SOS, 7.6132 6 7,271.9 6,027.0 37.97 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 PRODUCTION, 7 7,359.0 6,095.5 38.22 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 ' 30.8,410 Sidle, , , 8 7,425.4 6,147.7 38.44 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 8,!x12-8,811 Liner ur 9 7,592.1 6,278.3 38.42 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 7,6235,812 TD (1 E- 75AL1), 8,812 - ill\i/itEr'1.- i .'--E ,:,/i. ,,-ireiku REN- - ER RAK Company 9i)17 HUGHES ,IIINi i. 7 , , H / q ‘', ' rut ft rios.,'; 7 i.9414,411 , I C Alaska, Inc. Distribution ,, '•",..f7'.:1,',17..,7,,3 st:N.,:ir_'''-,1 Well Name Data Distri , H Area*** , ,',,,,),,,,•'''' , , :1,,. , ,,,..•,,i8)..:1.,,.,..i„....;,,,,,,1 Kupar Ar a , ,,,,, i1 ,. ,, ) , r t ' ' ,,,,,,,•{7,:i-.1''','`..,.: y' ,;,,', Date 6/9/2010 OH H AL Dig ital ,i, 1,, .: , ; , .:. ,, i ,, , . , i. I , , • ' ' 1,:,,,, it ', , , '. -,,:,,,,,:',,,i'l,,,,, n.,,,,,f,,,i',:ez:,7,..:;.c,',\,i,,,,,,,!,,,17,,I,..:,,,,,,::ki:::'!..,,,',I.,;,,.4;:,,,,t:',11.1,::,4:911,,,i3; ConocoPhillips Con°c° P ''' .. '' , .. ,,, I, ,, • ., .,,, ,,,'' ' ,, -,‘,„•.1,:iri'...i•••,,,,r6it,1„,,,•,-0,4,, t i ,, ,. • , Airnlaagsekla G1-netsateDrig i, „t.1,1;,li,,IiI, RECIPIENTS other distribution ophilliPs . , ,'',, ',.), , , , , ',I" i'.)t•,,. ,i'-,..;=.',',,r, ,,,,,04,T,';`,,1 approval from Conoc .4823 i . ,. written aggro tribution is allowed withou ,, ,,, OH FINAL , 1 '' h a r d :0 1 P e Y s p a r n i d/or contact Wr ight Conoco. A h i L is i i l s l u ip a p s W D A r r l e a k s e ka, Inc , Sharon , 1 Hardcopy Print I CDoninliong Tech ATO-1530 w co e p K - 0M NS . I mAii_ RO ATTN. I 700 G Street Ima 1 Di _ - - - - , ' Graphic Ima Electronic i , 1 File t LIS Anchorage, AK : CGM / TIFF ConocoPhillips 1 i' E )1'1'.■ l'' ' A Inc Ricky Elgarico - _ . , , to i ' . ' ' . t Y . ,•reli'iii,, , , 9 ' l i i ,, ,,,. ,,,,Eo,i. 7_ 1 .111 k*/ 1 Hardcopy Pgrint, -I "is - Anchorage, AK 99504 ftp. ' in - Li 1. i „ „ - ' ! 1 Graphic ima_a fi le . //b2bftp.conocophillips.com AOGCC t ' ' ,' ' ', Electronic . 1. ken il I CGM / TIFF s Print, ; . , ' 1 Hardcopy file k*/ Christine Mahn ken Graphic image 333 W e Alaska 9 ' 1 Grap .a„,, Electronic Anchorage, West 7th Ave, Suite 100 n lieu of sepia** „ BP 1 CGM/TIFF LIS Print, Disk*/ David Hardcopy • . 1 Har 196612 ci 6612 P.O. Box 196612 9951-- Graphic I I 1 GraP ** Electronic e Anchorage, Alas 1 l' u of sepia Anchor i in .ie /KRU REP /TIFF LIS CHEVRON I CGM / T ' Glenn Fredrick ', 1 pis .*/ t , k Box 196247 99519 . image file 1 Dis , I ,•,., AP.n°c•horag.re'cAkleasr,kNaRT ; of Oil and Gas 1 Brandon f State of Alaska; sDuNitRe,8D0i0 Electronic Div. - 0 LIS DS ' 550 W. 7th Ave, Alaska 99501-351 , , ,., , 4 Anchorage' Foreman TOTAL s g Enginee i , n p ts Hardcopy • ri Page 1 of 4 RECEIVED • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 1 9 2010 WELL COMPLETION OR RECOMPLETION REPOUM la. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended 0 1b. Well Class 20AAC 25.105 20AAC 25.110 Development f Exploratory ❑ GINJ ❑ WINJ 0 WAG ❑ WDSPL ❑ No. of Completions: Service El Stratigraphic Test Ell 2. Operator Name: 5. Date Comp., Susp., 12. Permit to Drill Number: ConocoPhillips Alaska, Inc. or Aband.: April 20, 2010 210 - 014 / 3. Address: 6. Date Spudded: 13. API Number: P. O. Box 100360, Anchorage, AK 99510 - 0360 March 23, 2010 50 029 - 20769 - 60 4a. Location of Well (Govemmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 444' FSL, 814' FEL, Sec. 16, T11 N, R10E, UM March 24, 2010 1E Top of Productive Horizon: 8. KB (ft above MSL): 105.7 RKB 15. Field /Pool(s): 2042' FSL, 907' FWL, Sec. 16, T11 N, R10E, UM GL (ft above MSL): 41' AMSL Kuparuk River Field Total Depth: 9. Plug Back Depth (MD + TVD): 2305' FSL, 734' FWL, Sec. 16, T11 N, R10E, UM 8810' MD / 6347' 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 8812' MD / 6347' TVD ADL 25651 TPI: x - 546138 y - 5961605 Zone 4 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x 545962 y - 5961867 Zone 4 SSSV @ 1878' MD / 1878' TVD 469 18. Directional Survey: Yes EI 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 8326' MD / 6392' TVD 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT CEMENTING RECORD CASING SIZE WT. PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE PULLED 16" 62.5# H -40 Surf. 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 7623' 8812' 6302' 6347' 3" slotted liner 24. Open to production or injection? Yes • 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 8062' -8811' MD 7663' MD / 6331' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 5 4, EilON 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 Ei 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 RBDMS MAY 19 10'0 • Z- ( 6 06/34 • • 28. GEOLOGIC MARKERS (List all formations and markers encountered): 29. FORMATION TESTS NAME MD TVD Well tested? ❑ Yes 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 A4 /Base A5 8490' 6365' Kuparuk A5 8812' 6347' 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: Gary Eller @ 263 - 4172 Printed N.' Ca Title: Alaska Wells Manager p Signature ,_ „/ Phone 265 - 6306 Date 1t1J0 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 11., j KUP S 1 E -15AL1 ConocoPhiltips n Well Attributes Max Angle & MD TO ACaska I Wellbore APUUWI Field Name Well Status Inc! ( °) MD (ftKB) Act Bin, (ftKB) i ,, hp , 500292076960 KUPARUK RIVER UNIT :INJ 8,812.0 Comment H2S (ppm) Date Annotation End Date KB - Grd (ft) Rig Release Date ... wen coot) 1E- 15nL,az1f20s:11 PM SSSV: TRDP Last WO: 40.71 8/4/1982 Stlum Apual10 3;o - Annotation Depth (ftKB) End Date Annotation !Last M d ... End Date Last Tag: SLM, I I Rev Reason: SIDETRACK w /LATERALS Imosbor 4/20/2010 Casing Strings , Casing Description String 0... I String ID ... Top (ftKB) Set Depth (t... Set Depth (ND) ... String Wt...IStr ng ... {String Top Thrd Liner AL1 23/8 '. 1.995 7,623.4 8,812.0 4.60 1 L-80 I STL Liner Details Top Depth _. ' P10) Nomi... (ND) Top Inc! CONDUCTOR, Top (ftKB) ( ( °) Item De ption Comment ID (n) i 32 - 112 7,623 4 DEPLOY ''. 1.000 SAFETY YIN, Perforations & Slots Deployment Sleeve Baker 1,878 Shot I • .. Top (TVD) Btm (TVD) I Dens Date Top (ftKB) B1m (ftK61 (ftKB) (ftKB) Zone (sh °- Type Comment GAS LIFT,__ 8,062 8,811 A 1E 3/24/2010 32.0 Slots Alternating solid/slottedpipe - 1,949 0.125"k2.5" @ 4 circumferential adjacent rows, 3" centers staggered SURFACE, 18 deg, 3' non - slotted ends 30 - 2,193 _ ° -a, '*,-' a ..--• 1 GAS LIFT '�' .,�,-., 3,690 End Date Annotation c ill : .{ 4/20/2010 NOTE: SIDETRACK w /LATERALS 1E-15A, 15AL1, 15AL2, 15AL2 -01 4/20/2010 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 GAS LIFT, 5,219 GAS LIFT, 6,256 GAS LIFT, _ �- Y 6,291 4 GAS LIFT 7,272 PBR, 7,307 - I • .. -_.,t PACKER, 7,322 INJECTION, 7,359 p INJECTION,_ _.. r 7,425 IPERFS, 7 478 -7,550 ERF, 7,550 -7,554 '., IIM s WHIPSTOCK, 7,557 WINDOW AL2.01, 7,558 -7,565 14. INJECTION, 7,592 it A APERF, 7,618 -7,838 II I. WHIPSTOCK, 7,631 WINDOW AL1, a 7,633 -7,641 Mandrel Details 1 1 Top Depth Top Sort LOCATOR, M To ftKg (TVD) Inc! CAMCO OD Valve Latch Size TRO Run 7962 PACKER, 7,663 ti p ( (HKB) 11 Make Model (in) Sery Type Type (in) (psi) Ran Date Coin... NIPPLE, 7,676 - Stn A o 948 5 KBUG 1 GAS LIFT DMY We 0.000 0.0 6!5/1990 2 3,690.5 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 - l 3 5,218.8 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 4 6,255.6 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 5 6,291.2 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 SOS, 7,682 L 6 7,271.9 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 PRODUCTION, 7 7,359.0 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 30 8,4101 Slob, . 8 7,425.4 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 8,062 - 8,811 ' -- - _ Liner AL1, ^' 9 7,592.1 CAMCO KBUG 1 INJ DMY OK 0.000 0.0 72011993 7,623 -8,812 - - - TD (1 E- 15AL1), 8,812 • 1E-15 CTD Sidetrack - Final Last Updated: 21- Apr -10 3 -1/2" Camco TRDP -1A nipple @ 1878' MD MIN 3 -1/2" 9.3# K -55 EUE 8rd Tubing to surface t 3 -1/2" Camco KBUG gas lift mandrels @ 1948', 3690', 5218', 6256', 7271' E. 16" 65# H -40 shoe MI @ 112' MD Baker 3 -1/2" PBR @ 7307' MD MI Baker FHL packer @ 7321' MD • lift , 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) lw ;• , l Baker FB -1 packer @ 7663' MD w/ Baker SBE - � 3 -1/2" Camco D landing nipple @ 7676' MD (2.75" min ID, No -Go) 1 ■■ 3 -1/2" tubing tail @ 7682' MD C -sand perfs 7478' - 7554' MD Sqz perfs (2/14/10) WNW AL2 -01, TD = 9765' AL2, TD = 10,085' 7550' - 7554' CBL 2 -3/8" liner 7542' -9765' 2 -3/8" liner 7690' - 10,058' w 7618' - 7638' CBL Deployment sleeve at 7542' Billet at 7690' AL2 -PB3, TD = 9710' Unintended sidetrack at /� _::_ _::_ 7855' KOP #2 at 7557' MD ______ ________ KOP #1 at 7631' MD I AL2 -PB2, TD = 10,135' µ ------ - - -, -- -• - - -- 2 -3/8 8200'-10,135 liner �� _- Billet at 8200' Baker flow- by �� whipstocks lo /ii. AL2 PB1 TD 9835' • ,, ' --- ------ - -- --- .-- 2 -3/8" liner 8864' -9835' ,, . -------- ..- Billet at 8855' A -sand perfs 7716' - I \ 2------- J AL1 Lateral, TD = 8812' 7796 = I MD (plugged) — / _ _ 2 -3/8" liner 7623' - 8812' —_ _ _ _ — Liner top at 7623' A Sidetrack, TD = 9800' CIBP at 7656' ELM 2 -3/8" liner 8323' - 9794' 7" 26# K -55 shoe @ Billet at 8323' 8410' MD (7674' MD, 2/13/10) . . . - Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 13:48 14:54 1.10 7,600 1,700 PROD1 DRILL TRIP P Continue circulating flo -pro while POOH, Paint flag at 6132' EOP Flag. 14:54 16:06 1.20 1,700 7,600 PROD1 DRILL TRIP T Attempt to close SSSV. Well continued to flow at < 0.1 BPM after 5 minutes. Pressure back up, open SSSV and RIH to circulate in KWF 16:06 17:54 1.80 7,600 0 PROD1 DRILL TRIP T Lay in 12.0 NaBr KWF from window to surface 17:54 18:30 0.60 0 0 PROD1 DRILL SFTY P Monitor for no -flow while doing crew changeout., PJSM Pulling BHA out of dead well and running liner 18:30 19:30 1.00 0 0 PROD1 DRILL PULD P Lay down BHA # 7 19:30 19:45 0.25 0 0 PROD1 DRILL BOPE P P/U Test joint and function test BOPE 19:45 23:00 3.25 0 1,515 COMPZ CASING PUTB P Prep Floor and run 45 Joints of liner and aluminum billet with GS profile, Surface test tool 23:00 00:00 1.00 1,515 4,800 COMPZ CASING RUNL P RIH with BHA #8 03/23/2010 Ran Liner in A lateral from 9790 to 8326'. KO Top of Billet @ 8326' - drill to TD of AL1 Lateral to 8810'. 00:00 01:00 1.00 4,800 7,647 COMPZ CASING RUNL P Continue in well with "A" lateral liner 01:00 01:45 0.75 7,647 9,794 COMPZ CASING RUNL P Correct @ 6132' EOP flag. -13', continue in well PUW =33, 01:45 01:57 0.20 9,790 9,790 COMPZ CASING RUNL P Tag and set down @ 9797, PUW =35K @ 9790 Repeat and confirm Pump 1.3 @ 3900, Pick up 23k Released from liner Line up to pump across top, Start out of well 01:57 02:15 0.30 9,790 9,100 COMPZ CASING RUNL P POOH 02:15 02:30 0.25 9,100 7,648 COMPZ CASING DLOG P 9100' (No correction after setting liner) log down to RA Marker, +4' correction Liner at 9794 corrected, TOL @ 8323.25 Reset bit depth to 7647.53, Bottom of GS. Current tool string 44.6 02:30 04:30 2.00 7,648 0 COMPZ CASING TRIP P POOH 04:30 05:00 0.50 0 0 COMPZ CASING PULD P Lay down liner running BHA 05:00 06:00 1.00 0 72 PROD2 STK PULD P PU drilling BHA for AL1 06:00 07:30 1.50 72 7,614 PROD2 STK TRIP P RIH 07:30 08:30 1.00 7,614 7,614 PROD2 STK DISP P Circulate out KWF 08:30 08:42 0.20 7,614 7,670 PROD2 STK DLOG P Tie in, -10' 08:42 08:57 0.25 7,670 8,326 PROD2 STK TRIP P RIH to tag billet 08:57 11:27 2.50 8,326 8,329 PROD2 STK KOST P 8326', Dry tag billit 1.43 BPM @ 3900 FS Started milling off billit Page 8 of 35 • • Time Logs . Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 11:27 11:57 0.50 8,329 8,350 PROD2 DRILL DRLG P 8329', Drill Ahead 15 FPH to 8330 then drill ahead to 8350 @ 30FPH Back ream up through kick off area then pass through not pumping. 11:57 14:42 2.75 8,350 8,505 PROD2 DRILL DRLG P 8350 Drill ahead 1.45BPM @ 4000 PSI FS BHP =4120 EDC =12.6 1.5k WOB, RIW =10k 14:42 15:42 1.00 8,505 8,505 PROD2 DRILL WPRT P 8505', Wiper to window 1.45 BPM @4100 FS PUW =28K, BHP =4080 Slight bobble (200Ibs DH) running in past billit, nothing on way up 15:42 18:42 3.00 8,505 8,655 PROD2 DRILL DRLG P 8505' Drill Ahead 1.45BPM @ 4050 FS 1.4K WOB 8.8K RIW BHP =4110 18:42 20:42 2.00 8,655 8,655 PROD2 DRILL WPRT P Wiper trip - P/U weight off bottom 28K. had problems @ 7926' & 7930' RIH. Stacked weight, slid through with lower pump rate. 20:42 23:00 2.30 8,655 8,810 PROD2 DRILL DRLG P Drilling ahead - 1.30 bpm, circ 4200 psi, BHP 4100, ECD 12.7, WOB 2k, ROP 60. Pump a low visc pill 10 bbls to lower circ pressure - continue drilling ahead. 23:00 00:00 1.00 8,810 8,810 PROD2 DRILL WPRT P TD lateral - P/U weight 29K, pump visc pill & Wiper trip. 03/24/2010 Pump KWF, Run liner in AL1 Lat from 8810 - 7623'. P/U Whipstock and set 180 lowside TOWS 7557'. P/U Milling BHA with centralizer. 00:00 02:00 2.00 8,812 8,812 PROD2 DRILL WPRT P Final wiper trip - noticed overpull @ 7840' while wiping. Tie in +3 ft correction. Mix up Liner pill. RIH tag bottom @ 8812' 02:00 04:30 2.50 8,812 71 PROD2 DRILL TRIP P P/U and start pumping 12 bbl liner pill. Flag EOP @ 7479' & 6367'. Pump KWF from window to surface. 04:30 05:00 0.50 71 0 PROD2 DRILL PULD P CT @ surface, flow check for 15 minutes & TBTfor laying down BHA. Lay down BHA. 05:00 06:00 1.00 0 0 COMPZ CASING SFTY P Prep rig floor for P/U liner. Safety joint drill. 06:00 09:30 3.50 0 1,232 COMPZ CASING PUTB P Crew change, PJSM, P/U Liner, Perform Safety joint drill with day crew 09:30 11:30 2.00 1,232 7,611 COMPZ CASING RUNL P RIH with Liner 11:30 12:00 0.50 7,611 8,812 COMPZ CASING RUNL P At 6367 Flag, correct -11.7, close- EDC PUW =30K, 12:00 12:06 0.10 8,812 8,555 COMPZ CASING RUNL P 8812, Set down with liner, PUW =35K, Roll pumps 1.3 BPM @ 4000PSI PUW= 24K, Released from liner, Start out of well Page 9 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 12:06 12:18 0.20 8,555 8,565 COMPZ CASING DLOG P Log tie in, Correct +2', Remove liner length from counters Bottom of liner @ 8812 corrected, TOL @ 7623.47 12:18 13:54 1.60 8,565 0 COMPZ CASING TRIP P POOH 13:54 14:36 0.70 0 0 COMPZ CASING PULD P At surface, PJSM to remove BHA from dead well Monitor well for flow, Pull liner running tools from well 14:36 15:42 1.10 0 0 PROD3 RPEQPI PULD P M/U Whipstock and coil track, Surface test tool and make up injector 15:42 18:30 2.80 0 7,567 PROD3 RPEQP1TRIP P RIH with 3.5" Whipstock. Tie in -10 ft correction. P/U weight 27K. Close EDC. RIH slowly to setting depth. TOWS 7557' BOWS 7566'.7' 180 lowside. 18:30 20:00 1.50 7,567 54 PROD3 RPEQP1TRIP P Start pumping KWF down CT- pressure up to 4300 psi, Set - sat down 5K looked good. P/U weight 25K, start pumping KWF down CT while POOH. 20:00 21:00 1.00 54 0 PROD3 RPEQPI PULD P CT @ surface, flo- check. Safety meeting for BHA handling. Lay down BHA. change out pack off. 21:00 22:00 1.00 0 70 PROD3 WHPST PULD P P/U BHA # 12 window milling BHA with centrilizer & 10 ft vibration sub. 22:00 00:00 2.00 70 7,450 PROD3 WHPST TRIP P RIH and swap fluid to flo -pro on bottom. Tie in - 10ft. 03/25/2010 Mill LS window from 7557' - 7575' TOWS 7557' BOWS - 7565'. P/U 2.5 AKO build BHA. 00:00 03:00 3.00 7,558 7,560 PROD3 WHPST MILL P Dry tag @ 7558', P/U and slowly RIH with pumps @ 1.45 bpm. free spin 3950, lightly tag @ 7557.8'. Start milling window. Seeing metal returns 1.5' ft into window. WOB 1.4, Ct weight 12K, 1.45 bpm, 4100 psi. 03:00 05:00 2.00 7,560 7,561 PROD3 WHPST MILL P Continue Milling - WOB 1.8, CT weight 12K, 1.45 bpm, 4100psi, good metal returns over shaker. Continue time drilling. 05:00 11:00 6.00 7,561 7,565 PROD3 WHPST MILL P Weight dropped off WOB @ 7560.5' Start to auto drill .8 fph with WOB .8K. CT weight 12K. 1.45 bpm @ 3900 psi. 11:00 14:00 3.00 7,565 7,570 PROD3 WHPST MILL P 7564.7, Lost WOB and Differential pressure. Bottom of window 6.9' Window. Continue to time drill to 12' past TOWS 14:00 14:30 0.50 7,570 7,575 PROD3 WHPST MILL P 12' Below pinch point, Drill formation 14:30 15:30 1.00 7,575 7,575 PROD3 WHPST REAM P Drilled formation, Start dressing / back reaming, Made two down reaming passes then go through dry, Looks good 15:30 17:00 1.50 7,575 70 PROD3 WHPST TRIP P POOH following pressure schedule Page 10 of 35 ConoccPhilli s p Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 1E Pad 1 E -15AL1 50- 029 - 20769 -60 Baker Hughes INTEQ V • Definitive Survey Report BAKER Y p HUGHES 21 April, 2010 ^ ~ C��»hiUKi�� . ~_m�"��v�o " ov"o Oe�n�vaSunxoyRepod HUGHES Alaska Company: Inc. Local Co-ordinate Reference: 1s Project: Kuparuk River Unit TVmRef"m,nnw: 1E-1n@ 105.70n(1s-15) Site: Kuparuk 1E Pad MD Reference: 1s'15 @105.70o(1s'15) |weU: 1e'15 North Reference: TRUE ! / weUuo,e: 1s'15 Survey Calculation Method: Minimum Curvature Design: 1E-15 Database: EDM Prod wwi en� w� Alaska -�_ _- _______'___ ____ -_. __- -_-__--_______ --__ -- '---� '__ _ -___-_--_-_ - - ___'____-'__�__--_____ ___ '__-__-_______. 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 o* Using geodetic factor cm, � �� L-______—_-__-_ '--------------- '� �� - -' -'- - — -' - - -'--'�---'--� -�- -'--�--------�-------- ----------- -----' -------- -------- --| �� Well 1s-15 Well Position +NI-S 0.00 ft Northing: 5.960.029.95n Latitude: 70° 18'5.686 w +E/ 0.00 ft Easting: 549710.0*n Longitude: 149° 35'50.538 vv Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00 ft _ / xxwxuon, 1s'15Au Magnetics Model Name Sample Date Declination Dip Angle Field Strength ! (*) ( (nT) ! BGGM2009 3o5/2010 17.33 79.80 57,371 | � - : Design --- - 1 E-15*u - - - '- - '--'-- - - ' -- - -- '-' - ' '-- - -- - ' / | Audit Notes: � Version: 1.0 Phase: ACTUAL Tie On Depth: 8,300.48 Vertical Depth From +mmS +E/-W Direction �� (ft) (ft) (ft) 7> ��y 105.70 0.00 0.00 296.49 _�I Survey Program note From To Survey Survey (ft) (ft) wwnm»(Wwxunre) Tool Name Description Start Date End Date 200.00 7,600.00 1E-15 (1E-15) FINDER-MS SDC Finder multisho 8m5/2000 7,632/0 8.300.48 1E-15A (1E-15A) MWD MWD - Standard 3n8/2010 3/21o010 | 8.326.00 8.760.24 1s'15«u(1s'15Au) mvvo MWD - Standard 3o4/2010 3/2*/2010 | ---_I 4/21/2010 10:50:10AM Page 2 COMPASS 2003.16 Build 69 r ConocoPhillips M' ConocoPhilli 5 BAKER Definitive Survey Report HUGHES Alaska i Company: ConocoPhillips(Alaska) Inc. Local Co- ordinate Reference: 1 E - 15 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: 1 E - 15 North Reference: TRUE Wellbore: 1E Survey Calculation Method: Minimum Curvature ■ Design: 1E-15 Database: EDM Alaska Prod v16 Survey Map Map MD Inc AzI TVD TVDSS 0411-S +E/-W Northing East ng DLS Sect on Survey Tool Name Annotation (ft) ( °) ( °) (ft) (ft) (ft) (ft) (ft) (ft) ( /100') (ft) • 8,300.48 90.74 1.60 6,392.14 6,286.44 1,412.74 - 3,555.29 5,961,419.01 546,145.83 23.71 3,812.18 MWD (2) TIP 1E 8,326.00 89.85 5.85 6,392.01 6,286.31 1,438.20 - 3,553.63 5,961,444.47 546,147.32 17.01 3,822.05 MWD (3) KOP 8,368.26 99.40 1.18 6,388.60 6,282.90 1,480.19 - 3,551.04 5,961,486.47 546,149.63 25.13 3,838.46 MWD (3) 8,400.51 101.49 359.01 6,382.76 6,277.06 1,511.90 - 3,550.98 5,961,518.18 546,149.48 9.26 3,852.55 MWD (3) 8,430.50 101.27 356.02 6,376.84 6,271.14 1,541.27 - 3,552.26 5,961,547.53 546,148.01 9.80 3,866.79 MWD (3) 8,460.24 101.86 351.32 6,370.87 6,265.17 1,570.22 - 3,555.47 5,961,576.46 546,144.61 15.61 3,882.58 MWD (3) 8,480.32 101.98 347.63 6,366.72 6,261.02 1,589.53 - 3,559.06 5,961,595.75 546,140.89 17.99 3,894.40 MWD (3) 8,520.57 100.22 341.49 6,358.97 6,253.27 1,627.58 - 3,569.57 5,961,633.72 546,130.13 15.59 3,920.78 MWD (3) 8,550.53 96.21 338.09 6,354.69 6,248.99 1,655.39 - 3,579.82 5,961,661.46 546,119.70 17.47 3,942.36 MWD (3) 8,580.45 93.57 333.47 6,352.13 6,246.43 1,682.57 - 3,592.04 5,961,688.56 546,107.29 17.73 3,965.42 MWD (3) 8,610.37 89.11 329.14 6,351.43 6,245.73 1,708.80 - 3,606.40 5,961,714.68 546,092.77 20.77 3,989.97 MWD (3) 8,640.34 89.17 323.80 6,351.88 6,246.18 1,733.77 - 3,622.95 5,961,739.54 546,076.06 17.82 4,015.92 MWD (3) 8,670.34 90.37 319.11 6,352.00 6,246.31 1,757.22 - 3,641.63 5,961,762.87 546,057.21 16.14 4,043.10 MWD (3) 8,700.38 91.78 315.28 6,351.44 6,245.74 1,779.25 - 3,662.04 5,961,784.77 546,036.67 13.58 4,071.19 MWD (3) 8,730.35 92.73 314.89 6,350.26 6,244.56 1,800.46 - 3,683.18 5,961,805.83 546,015.39 3.43 4,099.58 MWD (3) 8,760.24 92.12 319.96 6,349.00 6,243.30 1,822.44 - 3,703.38 5,961,827.68 545,995.04 17.07 4,127.46 MWD (3) 8,812.00 92.12 319.96 6,347.08 6,241.38 1,862.04 - 3,736.66 5,961,867.05 545,961.51 0.00 4,174.90 PROJECTED to TD III 1 4/21/2010 10:50: LOAM Page 3 COMPASS 2003.16 Build 69 • iii / Y \ J SEAN PARNELL, GOVERNOR S A ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 ! PHONE (907) 279 -1433 d 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, 1 E -15AL 1 ConocoPhillips Alaska Inc. Permit No: 210 -014 Surface Location: 443' FSL, 815' FEL, SEC. 16, Ti 1 N, R 10E, UM Bottomhole Location: 2375' FSL, 927' FWL, SEC. 16, 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 Kuparuk River Unit 1E-15A, 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). j1 wie . Norm.. Com , issi. er 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) . RECEI V • • 4111 STATE OF ALASKA JAN 2 6 2010 ALASKA OIL AND GAS CONSERVATION COMMISSION Alaska Oil & Gas Cens. Commission PERMIT TO DRILL Anchorage 20 AAC 25.005 la. Type of Work: . lb. Proposed Well Class: Development - Oil ❑ Service - Winj gi • Single Zone • ' l c. Specify if well is proposed for: Drill ❑ Re -drill 0 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 - 15AL1 • 3. Address: 6. Proposed Depth: 12. Field /Pool(s): P.O. Box 100360 Anchorage, AK 99510 - 0360 MD: 8830' • TVD: 6240' • Kuparuk River Field 4a. Location of Well (Govemmental 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: 1329' FSL, 1222' FWL, Sec. 16, T11 N, R10E, UM 469 3/20/2010 Total Depth: 9. Acres in Property: 14. Distance to 2375' FSL, 927' FWL, Sec. 16, T11 N, R10E, UM 2560 Nearest Property: 26100' 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: 1 E -11 & 1 E -13 @ 1015' , 16. Deviated wells: Kickoff depth: 8400 • ft. 17. Maximum Anticipated Pressures in psig (see 20 AAC 25 035) Maximum Hole Angle: 105° 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 1200' 7630' 6204' 8830' 6240' slotted liner i I I 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 0 Drilling Program gi Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements EI 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact J. G. Eller @ 263 Printed Name V. Cawvey Title Alaska Wells Manager Signature 7v Phon 265-6306 Date V Commission Use Only Permit to Drill API Num : Permit Approval I See cover letter Number: CDC) / `r 50 -(�2! �- G 7> 767- 6c ° ( , I Date: ,7/570 for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbe methane, gas hydrates, or gas contained in shales: Er ." 5600 Ps i80 P .-- 7 1 — Samples req'd: Yes ❑ No E Mud log req'd: Yes El No g Other: 4, z5-06 p s` Ahhw(,"r 7,7 H2Smeasures: Yes �No I♦ Dire ona svy req'd: Yes u No ❑ ® C�...,� d % IT-1A .A., F - • ROVED BY THE COMMISSION DATE: 4-.5"-lo / , COMMISSIONER Form 10 (Revised 7/2009) This permit is valid oOr 2RoIttGoJn d 4 approval (20 AA .005(g)) ubmit in Duplicate • • RECEIVED JAN 2 6 2010 Conoco Phillips p Alaska oil & Gas cons. Commission Alaska Anchorage P.O. BOX 100360 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 1E-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 1 E -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. Sincerely, % --. 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 tubing at the first kickoff point. The 1E -15A sidetrack will make a 2- string exit through the 3 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'/2" tubing. It will target the A4 sand southeast of the existing well with a 2593' lateral. The hole will be completed with a 2 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'/2" tubing at 7550' MD. CTD Drill and Complete 1E -15: March/April 2010 Pre -Rig 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 ORIGINAL January 25, 2010, FINAL • • KRU 1E-15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Rig Wo 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. °`t 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. 1E -15AL1 Lateral (A4/5 sand, northwest) i5 a. Kick off of the aluminum billet at 8400' MD P11) 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. 1 E -15AL2 Lateral (A4 sand, southeast) a. Set 3'/2" monobore whipstock in 3'h" 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. 1 E- 15AL2 -01 Lateral (A4/5 sand, southeast) a. Kick off of the aluminum billet at 8500' MD b. Drill 2.70" x 3" bi- center lateral to TD of 10,075' MD. 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 11 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: 103/4", 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 D A N E L 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. • Page 4 of 5 Dpi G \ ec I f l 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 3 » of the 2%" BHA will be accomplished utilizing the 2 /8 pipe rams and slip p g p p p 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) Page5of5 G i i January 25, 2010, FINAL ,.. KU P 1 E -15 Conn Rhilli V vtac (s A l �'' Inc, .,,c : 4 Walther* AMAMI (Field Name Well Status I I () MD NtKB) Act Blm (MB) ,,,,.11111bs rl 500292076900 KUPARUK RIVER UNIT INJECTING 49.62 L 3,800.00 8,435.0 = ,_ Comment ti25 (pp...) Date Annotation End Date KB-Gld Ng Rig Release Date ". SSSV: TRDP 1 0 8/18/2008 Last WO [ 11/5/1984 40.71 8/4/1982 wet co tl -�.,i :1 t « A tat n _ Depth ( BK B) End Dat d Dat a _...__ - ' jf411 og�pl - .. . .., Annotation Last Mod By End DM. Last Tag: SLM 7.848.0 1 6/13/2009 I Rev Reason: SET STRADDLE PATCH tip(w) 7/8 /2009 tasInc v Stnncl - ., 4 - z ,< ,- A- �, String OD String 10 Set Depth Set De ( TVD) String Wt String s,n Cag Description (in) -__ (in) T.. BKB (SKB) (ftKB) (Ibs/N) Grade String Top Thrd ii CONDUCTOR 1 1 CONDUCTOR 16 15.060 32.0 112.0 11 2.0 65.00 11 112 .... SURFACE 10 3/4 9.794 0.0 2,193.0 2,192.8 45.50 K-55 SAFETY VLV, PRODUCTION 7 8 151 0.0 8,410.0 6 9162 26.00 K-55 1,876 GAS LIFT, _ `^ String OD String ID Set Depth Set Depth (710) String Wt String , 1,948 Tubing Description ( Oft) Top (IIKB) (RKB) (rtKB) (Ibsff) Grade String Top Thrd TUBING 31/2 2.992 0.0 7,682.0 6348 6 9.20 J BTC IPC SURFACE, r fiail l Hole A'nt'i ieiryW -t 1m Run. =t et[Sev ble= Fis .eta) �c Top Depth GAS LIFT, (TVD) Top Inc! 3,890 _p (ftKB) MKB) r) D.dripd. Co Run Date ID (In) 1,878 1,877.9 1.69 SAFETY bLV Camco TROP- 1A-ENC - -- - 11/5/1984 2.813 1,948 1,947.9 1.46 GAS LIFT CAMCO/KBUG/1/DMY / /// Comment STA 1 6/5/1990 2.875 GAS LIFT, 5 3,690 3,504.6 46.83 GAS LIFT CAMCO /KBUG /1/DMY / / / /Comment STA 2 ---s 6/5/1990 2.875 1 . 5,218 4.524.6 45.86 GAS LIFT CAMCOIKBLIG/1/DMY / /// Comment STA 3 6/5/1990 2.875 GAS LIFT, _ 6,256 5,252.5 43.86 GAS LIFT CAMCO /KBUG/1/DMY / /// Comment STA 4 11/5/1984 2.875 6256 -- - . illr., 6,291 5,277.7 43.53 GAS LIFT CAMCO/KBUG /1 /DMY / /// Comment STA 5 • 6/3/1990 2.875 GAS LIFT �,,, 7,271 6,026.3 37.97 GAS LIFT CAMCO/KBUG/1/DMY //// Comment STA 6 • 6/5/1990 2.875 6291 7,307 6,054.7 38.07 PBR Baker PBR 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 _ 1N 7 ,271 " -. r __ _ - 7,425 6,147,4 38.44JECTION 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 2.8T OAL 7/6/2009 1.750 PBR, 7307 (GOOD TEST TO 2500#) 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 6,2782 3842 INJECTION CAMCO /KBUG /1/DMY / /// Comment CLOSED STA 9 7/20/1993 2.875 7,602 6,286.4 38.89 PACKER PATCH: LOWER WEATHERFORD ER PACKER 2.8T OAL 7/3/2009 1.750 INJECTION. - -- - - -. ..... ,.._�. 7.354 - 7 , 6 63 6,333.8 38.78 PACKER Baker 'FB•1'PACKER 11/5/1984 4.000 t 7,676 6,344.0 38.76 NIPPLE Camco V Nipple NO GO 11/5/1984 2.750 IwECrION - __ 7,682 6 38.75 SOS . _...._._ Baker ._MW .. - .. 11/5/1984 2.992 7,425 7,682 6,348.6 38.75 TTL 11/5/1984 2.992 `Ci 7,884 6,506.5 38.52 FISH VANN GUN LOST DOWNHOLE 8/12/1993 8/12/1993 0.000 IPERFS. .ss,- ,, �+ e a = . 'a. ?a,, etr '' ,K" vk 1.478 - 7,554 ._-7 ` " a ` v9x n -~ - "' .i Te m .'_ ` - L., N }s' , S - P $cs w � t _ 5:.: -, �`�-s� r. :' - si�.r ...n... '.?i3� .�.x _ ..�.. Shot Top (TVD) Btm (TVD) Dens PACKER, 7,575 -- -�� Top (/8 B) Bfm (ftKB) MKS) NOM) _ Zone Date _(.1,-,--_ Type -�.. Comment 7,478 7,554 6,188.9 6,248.5 C4, C-3, C-1, 8/12/1982 12.0 IPERFS GEO VANN GUNS PATCH, 7,578 1 UNIT B, 1 E -15 INJECTION, 7,716 7,725 6,375.2 6,382.2 A -5, 1E -15 8/12/1993 4.0 RPERF 2.5' Titan Hollow Cartier guns, 180 7,592 deg phase, 96 deg CCW orient 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 6,383.1 A -5, A-4, 1E -15 11/5/1984 12.0 RPERF SCHLUMBERGER GUNS W 7,742 7,769 6,395.5 6,416.6 A 1E-15 8/12/1993 - 4.0 RPERF 2.5' Titan Hollow Carrier guns, 180 deg phase, 96 deg CCW orient PACKER. 7,663 7,749 7,776 6,401.0 6,422.0 A4, 1E -15 8/12/1982 ^ 12.0 IPERFS GEO VANN GUNS 7,756 7,783 6,406.4 6,427.5 A4, 1E -15 11/5/1984 12.0 RPERF SCHLUMBERGER GUNS NIPPLE,7,676 -- 7,775 7,782 6,421.3 6,428.7 A4, 1E - 15 8/12/1993 4.0 RPERF 2.5 Follow Canier guns, 180 deg phase, 96 deg CCW orient BOS7,682 7,782 7,789 6,426.7 6,432.2 A-4, 1E -15 8/12/1982 12.0 IPERFS GEO VANN GUNS Ta, 7sa� 7,789 7,796 6,432.2 6,4371 A-4, 1E -15 11/5 /1984 120 APERF SCHLUMBERGER GUNS $t e atanet► ts ? : ;,� .., _ . , ,...�. ., 4=„ J., v. . ,. , .. . RPERF. ' is 8016001 7,716-7725 I' - 1 Min Top MM Bhn Top Depth Depth Depth Depth (TVD) (TVD) MG) (BKB) OMB) 8148)_ Type Date Comment IPERFS. _ 1 7,716.0 7,796.0 6,375.2 6,437.7 A -SAND 8/19/1993 E -FRAC, PUMP 193,397# BEHIND 7,723 - 7,732 a ': RE -FRAC t 7 730.0 7,796.0 6 386 1 6,43 7 FRAC 12/17/1984 - 7.730 -7.739 � .Note/ General B - Safety . .. F n .. - ",. ), ,. T`- ,..� .. _"a, , ll `r 5. End Date Annotation RPERF 5/24/2009 NOTE: C - SAND LEAK FOUND Q 7596' ELMD AROUND GLM #9 7,742 -7,769 _ ,. A-SAND RE -FRAC, - 7,716 IPERFS, 7,749 - 7,776 11 FRAC, 7,730 RPERF, 7,7567,783 RPERF, 7,775 -7,782 - - . , IPERFS, .: i - _ ' 7,782 -7,789 APERF, - 7,789 -7,798 FISH, 7,884 Q RI PRODUCT ._ !GINA ._ v ............_..,.. 6,410 10, 8ION. 1E-15 Proposed CTD Sidetrack Last Updated; 21- Jan -10 3 -1/2" Camco TRDP -1A nipple @ 1878' MD Ii` 3 -1/2" 9.3# K -55 EUE 8rd Tubing to surface MI r 3 -1/2" Camco KBUG gas lift mandrels @ 1948', 3690', 5218', 6256', 7271' 16" 65# H -40 shoe 1 12' MD MO @ Baker 3 -1/2" PBR @ 7307' MD F Baker FHL packer @ 7321' MD 3 -1/2" Camco KBUG injection mandrels @ 7354', 7425', 10 -3/4" 45.5# K -55 shoe @ 2193 MD ■ Carbide blast rings 7446' - 7552' (7452' -7538' CBL) t ry ,l Baker FB -1 packer @ 7575' MD w/ Baker SBE • IM ,. _ 3 -1/2" Camco D landing nipple @ 7676' MD (2.75" min ID, No -Go) 1 3 -1/2 " tubing tail @ 7682' MD C -sand perfs 7478' f,' ' "' Top of cement at injection CD 7554' MD mandrel #8 for C -sand perfs AL2 -01 Lateral (A5 sand, southeast) (..M , NN TD 10075' K OP #2 at 7557` MD w N \ Liner top at 7550' K€TP #1 at 7635' MD '" - Baker flow-by monobore — — whipstocks Y ; % - - 7 TD Lateral 10150 (A4 sand, southeast) --� r e — _ _ _ _ _ _ - - Billet at 8500' Glr. __ AL1 Lateral (A5 sand, northwest) viiiiiiiiiiaiiiia l I � _ ' is A -sand perfs 7716' - CI _ TD = 8830 / / Liner top at 7630' 7796' MD (plugged) — _ /_ A Sidetrack (A4 /A5 sand, Northwest) 7" 26# K 55 shoe @ - CIBP at 7679 MD , i T t1, + s „f � 4 4 � 1`' t TD = 9525' 8410' MD �� „;' "'s" Billet of 8400' 0 • Nabors CDR -2AC Kuparuk Managed Pressure Coil Tubing Drilling BOP Configuration for 2" Coil Tubing Lubricator Riser \ Annular / Blind / Shear 2" Pipe / Slip (CT) Pump into Lubricator MJ lb.- � •■ above BHA rams 1/ P ' 1 Choke 1 2 -3/8" Pipe /Slip (BHA) 1' Choke ' Equalize Manifold 2 -3/8" Pipe / Slip (BHA) ' J L Kill � i • J • _ _ MI Blind / Shear 1 2" Pipe / Slip (CT) IN 11 Choke 2 11 . Sw ab Valves a Wing Valves 0 ®N 1 ejA 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 • • Nov Conoco Phillips Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 1E Pad 1E -15 1 E -15AL1 Plan: 1 E -15AL1 wp03 Standard Planning Report 13 January, 2010 BAKER HUGHES ORIGIN , s L k .a yy Iaa -. a II i ' . ConocoPhillips ill Conoco 1 p Planning Report BAKER Aiaska 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: 1E-15AL1 Design: 1 E- 15AL1_wp03 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 1E Pad 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 -15AL1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength ( (1 VT) BGGM2009 3/25/2010 17.33 79.80 57,371 Design 1E -15AL1 wp03 Audit Notes: Version: Phase: PLAN Tie On Depth: 8,400.00 i Vertical Section: Depth From (TVD) +N/-5 +E/ -W Dire ction (ft) (ft) (ft) (°) 0.00 0.00 0.00 298.60 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (ft) (1 (°) - (ft) (ft) (ft) (1100ft) (°/100ft) ( ° /'t00ft) ( °) Target 8,400.00 94.98 354.12 6,290.52 1,508.94 - 3,566.28 0.00 0.00 0.00 0.00 8,435.00 101.18 355.23 6,285.60 1,543.43 - 3,569.50 18.00 17.72 3.18 10.00 8,465.00 105.30 358.83 6,278.73 1,572.58 - 3,571.01 18.00 13.71 11.99 40.00 8,495.00 104.29 4.32 6,271.06 1,601.56 - 3,570.22 18.00 -3.35 18.29 100.00 8,525.00 101.16 8.82 6,264.45 1,630.62 - 3,566.86 18.00 -10.46 15.02 125.00 8,555.00 97.31 12.67 6,259.64 1,659.70 - 3,561.34 18.00 -12.80 12.82 135.00 8,630.00 95.95 359.15 6,250.94 1,733.62 - 3,553.69 18.00 -1.82 -18.03 265.00 8,705.00 93.46 12.47 6,244.76 1,807.81 - 3,546.13 18.00 -3.31 17.75 100.00 8,830.00 90.53 350.14 6,240.34 1,931.90 - 3,543.33 18.00 -2.35 -17.86 263.00 1/13/2010 7 :48:02AM Page 2 COMPASS 2003.16 Build 69 O R! GN • ConocoPhilli s • NM Conoco itltps 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 -15AL 1 Design: 1 E- 15AL1_wp03 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System + N /_ + Ej W Section Rate - Azimuth - Northing Easting (ft) (°) . ( °) (ft) (ft) (ft) (ft) ( °IlOOft) (°) (ft) (ft) • 8,400.00 94.98 354.12 6,290.52 1,508.94 - 3,566.28 3,853.45 0.00 0.00 5,961,515.12 546,134.20 TIP / KOP 8,435.00 101.18 355.23 6,285.60 1,543.43 - 3,569.50 3,872.78 18.00 10.00 5,961,549.58 546,130.76 2 8,465.00 105.30 358.83 6,278.73 1,572.58 - 3,571.01 3,888.07 18.00 40.00 5,961,578.72 546,129.05 3 8,495.00 104.29 4.32 6,271.06 1,601.56 - 3,570.22 3,901.24 18.00 100.00 5,961,607.70 546,129.66 4 8,500.00 103.77 5.08 6,269.85 1,606.39 - 3,569.82 3,903.21 18.00 125.00 5,961,612.54 546,130.02 8,525.00 101.16 8.82 6,264.45 1,630.62 - 3,566.86 3,912.21 18.00 125.18 5,961,636.78 546,132.82 5 8,555.00 97.31 12.67 6,259.64 1,659.70 - 3,561.34 3,921.27 18.00 135.00 5,961,665.89 546,138.15 6 8,600.00 96.54 4.55 6,254.20 1,703.83 - 3,554.66 3,936.53 18.00 -95.00 5,961,710.06 546,144.54 8,630.00 95.95 359.15 6,250.94 1,733.62 - 3,553.69 3,949.95 18.00 -95.98 5,961,739.86 546,145.30 7 8,700.00 93.64 11.58 6,245.06 1,802.93 - 3,547.17 3,977.40 18.00 100.00 5,961,809.20 546,151.36 8,705.00 93.46 12.47 6,244.76 1,807.81 - 3,546.13 3,978.83 18.00 101.04 5,961,814.08 546,152.37 8 8,800.00 91.26 355.49 6,240.81 1,902.15 - 3,539.58 4,018.23 18.00 -97.00 5,961,908.45 546,158.30 • 8,830.00 90.53 350.14 •6,240.34 1,931.90 - 3,543.33 4,035.77 18.00 -97.71 5,961,938.18 546,154.35 TD Targets Target Name - hittmiss target Dip Angle Dip Dir. TVD +N/-S +E/ -W Northing Easting - Shape (1 ( °) (ft) (ft) (ft) (ft) (ft) Latitude Longitude 1E -15A, AL1 Polygon 0.00 0.00 0.00 767.57 - 3,282.05 5,960,775.72 546,423.30 70° 18' 13.228 N 149° 37 26.237 W - plan misses target center by 6329.05ft at 8555.00ft MD (6259.64 TVD, 1659.70 N, - 3561.34 E) - Polygon Point 1 0.00 767.57 - 3,282.05 5,960,775.72 546,423.30 Point 2 0.00 980.13 - 3,515.68 5,960,986.71 546,188.29 Point 3 0.00 1,674.76 - 3,751.15 5,961,679.70 545,948.25 Point 4 0.00 2,453.17 - 4,257.10 5,962,454.67 545,437.21 Point 5 0.00 2,827.35 - 4,125.63 5,962,829.67 545,566.19 Point 6 0.00 2,767.11 - 3,784.98 5,962,771.69 545,907.20 Point 7 0.00 2,438.78 - 3,893.15 5,962,442.69 545,801.22 Point 8 0.00 2,003.05 - 3,637.98 5,962,008.70 546,059.24 Point 9 0.00 2,190.91 - 3,612.75 5,962,196.70 546,083.22 Point 10 0.00 2,142.09 - 3,337.03 5,962,149.71 546,359.23 Point 11 0.00 1,484.55 - 3,418.36 5,961,491.71 546,282.26 Point 12 0.00 878.80 - 3,163.31 5,960,887.72 546,541.29 Point 13 0.00 767.57 - 3,282.05 5,960,775.72 546,423.30 1 E -15AL1 t1.3 0.00 0.00 6,251.00 1,737.47 - 3,553.66 5,961,743.70 546,145.31 70° 18' 22.766 N 149° 37 34.170 W - plan hits target center - Point 1E -15AL1 t2.3 0.00 0.00 6,239.00 1,941.46 - 3,549.31 5,961,947.70 546,148.31 70° 18' 24.772 N 149° 37' 34.046 W - plan misses target center by 11.36ft at 8830.00ft MD (6240.34 TVD, 1931.00 N, - 3543.33 E) - Circle (radius 1,350.00) 1113/2010 7:48:02AM J �s''� j ��^'� Page 3 r COMPASS 2003.16 Build 69 7 ' t'"S, r i N ; � � 3a Azimuths to True North WELLBORE DETAILS: 1E -15AL1 REFERENCE INFORMATION r- Project: Ku paru k River Unit M gne I Ft83• IF/Skill Site: Kuparuk 18 Pad Co-ordinate Reference: Well 1E- 15, True North M gs n on MD Parent W: 1E-15A 0 IKE ConocoPhillips Well: 1E-15 saengmaeeszisr Tie on MD: 8400.00 Vertical (TVD) Reference: Mean Sea Level a 9, Section S Reference: Slot• 000N, 0.00E ellbore: 1E -15A /1 De1e3/231nW Measured Depth Reference: 1E- 1501057011 (1E -15) E Plan: 1E•15AL1_wp03(1E- 151E- 15AL1) M �° Calculaton Method: Minimum Curvature HUGHES 2250- " 1E- 15.11; 15.A WELL DETAILS: 1E•15 2200 .,. -.- 1 Ground Level: 0.00 2151 - +N /•S +E / -W Northing Easting Latiftude Longitude Slot 0.00 0.00 5960029.95 549710.04 70° 18' 5.686 N 149° 35 50.538 W 2100- _- -{ - c - -_._. _ -- -: .__. SECTION DETAILS ANNOTATIONS \ 1 Sec MD Inc Azi TVDSS +N( -S +E / -W DLeg TFace VSec Target Annotation 2050 I 1 8400.00 94.98 354.12 6290.52 1508.94 - 3566.28 0.00 0.00 3853.45 TIP / KOP 2 8435.00 101.18 35523 6285.60 1543.43 - 3569.50 18.00 10.00 3872.78 2 2000 � 3 8465.00 105.30 358.83 6278.73 1572.58 •3571.01 18.00 4000 3888.07 3 4 8495.00 10429 4.32 6271.06 1601.56 - 357022 18.00 100.00 390124 4 TD +- -- -- -- -- - - - - - -- - -_ ___-- --- ------ - -- --- j 5 8525.00 101.16 8.82 6264.45 1630.62 - 3566.86 18.00 125.00 3912.21 5 < 1950 <. i 6 8555.00 97.31 12.67 6259.64 1659.70 -3561.34 18.00 135.00 3921.27 6 0 - - t} ., 1E 1511E 1 7 8630.00 95.95 359.15 625094 1733.62 -3553.69 18.00 265.00 3949.95 7 x1900 - - -- L _ -._ 8 8705.00 93.46 12.47 6244.76 1807.81 - 3546.13 18.00 100.00 3978.83 8 .. { i 9 :i30.00 90.53 350.14 6240.34 1931.90 - 3543.33 18.00 263.00 4035.77 TD + 1 I '41850:- i- - -- .___ - - __.... -- : -- • ■ O Z 1800 . - - - -- - - - -_. _.... _..__- __,._ Z1750 - 5 3 1700 - -- - - - T - ., ', +41 1650- -- - 1 - -- - - - - -- , WAIN, 1600,. ' _...- -- - 4-. -.. _.- -- - -- i '" 15541 ....- --- . --- - - - _ . _ _ - -_ _. '-- .__- __ - - -- - -- - - -' -- ---__ i __ TIP /KOP - - 1500 -- - - 1 - -- - - - -. - _-- -- __..._..._ i. - 4 050 -4000 -3950 -3900 -3850 -3800 -3750 -3700 -3650 -3600 -3550 -3500 -3450 -3400 -3350 -3300 -3250 -3200 -3150 West(- )/East( +) (50 ft/in) 6220 - - - - -_.-- - -- - - -- -- - -- - -- - - - -- - - - - -- - -- - - - - - -- -- - ----- - - - - -- 1 1 6�3o- Ali 6_4o-4 { -- -- l -- �. m L., 0 6 - - _ . _.____ -. -. _._ -_ -- -- - - - -- ----- - - - -- - - - - -- . ._._.. -• _ - -- -- - - - - - - - - - - - -- ,-, 6 1E 5/1E 15AL1 ' Y 6260:- - ; I 1 { - { 4 N d ' i i Q 6270 U 6280- - - -- - - -T - - - -- -- - --- - -- - - - - - -- _... - -- -_- - ---_ -_ -- -- -- -- - �- - -- - - - -- -- • m TIP /KOP „__..(1.) 6290- -._- _ _. -__ - ___ ___ ' • 6300-' - ___- __ - -_. -_- - --- - 6310 -.._- _ 1 !-- ------ { - I 15A _. � - I { -- - - - - -- - .___.- - - 6320 - -- -- 1 -- - - - - -- -_ -.- -- --- 3790 3800 3810 3820 3830 3840 3850 3860 3870 3880 3890 3900 3910 3920 3930 3940 3950 3960 3970 3980 3990 4000 4010 4020 4030 4040 4050 4060 4070 4080 4090 4100 4110 4120 4130 4140 4150 4160 4170 Vertical Section at 298.60° (10 ft/in) i AvmtAhsmTeu9NMh WELLBORE DETAILS: 1E -15A REFERENCE INFORMATION Project: Ku pare k River Unit MegneacNOtlh41.e3° Milli Site: Kuparuk 1E Pad M�nebcE etl Parent Wellbore: 1E -15 Co- ordinate (NE) Reference: Well 1E- 15, True North Well: 1E•15 54m s M20:T Tie on MD: 7600.00 Vertical V) Reference 1E-15 5 105.70f1 (1E-15) ConocoPhilltps Wellbore: 1E - 15A fl /25/2076 Section n VS)Reterence: Sbt•(O.O0NON, 0. O.00E) PIan: 1E 1511E - 15A) Measured Depth Reference: 1E•155105.7011 (1E -15) Calculation Method: Minimum Curvature HUGHES i 44001 - - _ -- _ 420(! - -- -_-. .- .._... « _ I - : , — --- ----- — -- - - - - -- 3800- -_ 36110 -- 1!'111 10 -_.. _ -- —__ 3400-.1 _ __ :. _ - ! - _. \ 340 \ __ _. . _._. -_ . 3200 j 1 _._ _. _..... _. - _ - - -- -- - ._ - -- -.. .. -- - --_._ <n__.. ..._._ _ - _. - . - - . __._.-- --- - --- - - - - -- -- 111111 �. 2800- -- - - - -- - -- - --- - - --- -___ -__ -- - -- - -- •P--/ 2600 I -. 1E.15: IF 15A ', • ( x nr, ' _._ M O 2400- - -__.__ - _ _- — — ___ _ - _— -_. - .. _ _.. -___ _- _ -_ _ _____ - . _.__ _ _— -•� 4 — ' — - 2000 — �( — t I 0 1F-14 .F -l7 IEl 1E -.4 't ..+ 1801 {_ -.. . -... \ -._ _...... 140 \ -- - -- -- . , 1200 " -- --- -- - - -- :. 1000; j ____ ,_ x _ ___.— - —__ __— - .` ' 1 - 14 6,0 400 — .- — -- — 1 X00 0 ~ -200 } -- (- - � . _ - -// � - — - 600 - : ) j i='� r ; 1E 41'70 I 1' i N ' ` 1 -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 @ 105.7011 (1 E -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, - 4001' 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, - 4144' 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 perfd 7110'- 7192', A -sand perfd 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 31/2" (9.3 ppf, L -80) x 51/2" (15.5 ppf, L -80) tapered production casing on 3- 22 -96. Included 20 centralizers on the 31/2" portion and 12 centralizers on the 51/2" 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. • r a 3'/" sealbore at the 3'/" x A -sand perf d 9124'-9198'. There is no packer installed, but there is 2 51/2" crossover at 8772'. The 31/2" 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 1 E -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 perfd 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 perfd 6660'- 6724', A -sand perfd 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 1 E -16 is currently on long term shut in due to flowline problems. 4. KRU 1E - 17 (injector, — 4286' away) • Completed with 7 ", 26 #, K -55 casing on 8- 24 -82. Included 12 B &W Turbo -fin centralizers on the bottom 11 + tail "G" cement. Reciprocated joints. Cemented with 340 sacks of lead 310 sacks of to J p 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 peed 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 perfd 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 Atlnudwbr Nord, WELLBORE DETAILS: 1E -15AL2 REFERENCEINFORMATION �' Project: Kuperuk River Unit WoedeNoM 21.80 Site: Kuparuk 1E Pad CaorGmate(WE) Reference: Wel 1E -15, True North 1a�emrrotl P aren t on 15 00, BAKE �Or10C0 Wen: 1E -15 sr rpns atio nr Tie MD: MD: 7500,00 Vertical (TM Reference: tE•15@105.708(tE -15) �y�, + Wdlbore: 1E -15AL2 Dip Anpe.8084• Section (VS) Reference: Slot -(0.008,0.00E) 11��1�5 — PIan:1E - 15AL2 wp05(tE 15/1E 15AL2( — e� 7° Meaeue4 Depth h tE- 15 HUGRES Celouladonlalion Met Method: od: Minimum Curvature 2 6 - - - - - - - 1E- 12/1E42AL1 - - - - - 1L15 /IE -15A 24001 - - _ - _ - 6366 1 F a2/1E712 �� app . h t. 2200- - - - - - - ' - " - - - - - h ,. io . - - n> IE -IS %IE -BALI 2 000- - - - - - - - - f0.tb 1800_ - ■ - - - - - 1E - 102,13 L.,tcral / 1600- - - - - - - - - - - - - \ / 1400- - -- - - - - - - - - - ' / 1200 - - - - - - \ - - - - - 1000- - - - - - - - - \ M e - - - - - - - k �. ^, - - - - - a ,poi, u. -, i I I -'11I `� 800- - - - - - - - - - - - - - - - „'ps. .---, IE- IYIE -12AL 2 / O 200- - - - - -- - - - P - - _ r o -- / _ V \ - .. . . Al0 .., 411 - - - - - - -- - - - \ , -800 -- -- - - -- - - - - - e (�� / / \ \ \ _I000 -- - - -- - - - - - - - " - - - l � \ \i r 1E- IS /IE- 15AL2.01 f \ \ -1200 - IE- IS /1E -15AL2 ' \ \ -M00 - - - - - - -- - - - - - - / - - - - I - - - \ \ d1 2(1E - 02 � _1600 - - - - - - - - - - - - - - - - - - - - I - - - - _\ _ . -1800 _ - - - - - - - - - - - - IL -30. I1? -3u / IE- 1 -17 _ h -2000 - - - - - - - - - - - - ?. .-" - - /, ' -- - - - . i -22'1 - -- - - I 1E- 34/1E 434 -2.11 - - - - - - _ - - - - - -- - - - - - - - - - - . I I - 2600 - - -- - - - - - - - - - - - - - - - - -- - - - - - - - { IE- 31 /IE. -31PR1 -6400 - 6200 -6000 -5800 -5600 -5400 -5200 - 5000 -4800 -4600 -441)0 -4200 -4000 -3800 -3600 -3400 -3200 -3000 -2800 -2400 -2200 -200 800 -1600 -1400 -1200 -1000 -800 -600 -400 r TM 00 -200 0 200 400 600 800 1000 WPat(_l/East( +) (200 ft/in) . Azimuths b True North WELLBORE DETAILS: 1E-15A REFERENCE INFORMATION Project: Kuparuk Myer Unit Magnate North 21,83* MAI Site: Kuparuk 1E Pad Magnetic P Parent Wafture: 1E-15 Co-ordinate (NIE) Reference: Wel 1E-15, True North ell Well: 1E Streng8:57857.18a Tie on MD: 7600.00 Vertical (NO) Reference: 1E-15 @ 105.70ft (1E-15) BAKER . ConocoPhillips Wafture: 1E-15A Plan: 1E-15A wp03(1E-15/1E-15A) _ NAV., 80.84 Oaer 325/2010 Model: SGG.M2009 section (vS) Reference: Slot - (0.00N, 0.00E) Measured Depth Reference: 1E-ag 15 105.70ft (1E-15) Calculation Method: Minimum Curvature IFIUGHIES _._ 4800 _ . . 4600 - . . . . . 4400- - . 4200 _ - - 4000-- _ . ___ _ 38 _ -tr '- 3600 tE-II/tE . . . . , • . 3400 - .0 i -,,,II - - - - • if.'" q 3200 - - - - \ ,,, 3000 - - '.-. . 2800 .5 2.$11 _ ._ \'') a ,,...1„1„...,,_ i _ 0. 2400- . . 1E-15/1E-15A" /P . 1 ...,..., I + - .....e. \ , Fli ip-ioilF-tv .,,,,,, 1E /1E ,..-... I . '41600- . • cn 1400- • ... . _ \ N. \ \ I .,• .... . \ i ---- 1000- - - . . --I __ . . _ ".. ,_ , \ \ i i . •--- . .. IN ' , •;.-' 1E 800- -- - ...--- 1E ;, , N IE-12/1E-12AL,2 , . 400 . . -_____. / - ' — --__ - - . ----____ ---.. .. - . ..-------- ' -- 20 , __---= -- 0- - - . . . i - - . - . ,i: - / - , -,- ,, I----- ----____ \ / -----• - 0 - IF-m/1E4m -204 -- . - - . _ _----- , \,, , _ -------- -401 - .. - " - . _ --------- .. -- . \ - - 1E46/1 E-11; -601 i . . a•) --- i ,, .. ,•ii 11.-151E-15A1.2-01 . 1E-34/1E-3 4 ' -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 1 200 0 — 200 400 600 1E-15 @ 105.206 (1E-15) West(-)/East(+) (200 ft/in) • • TRANSMITTAL LETTER CHECKLIST WELL NAME KUPARUK RIVER UNIT 1E -15AL1 PTD# 2100140 Development X Service Exploratory Stratigraphic Test Non - Conventional Well KUPARUK KUPARUK RIVER OIL FIELD: POOL: ooL: 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(f), 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 x Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK RIV UNIT 1E -15AL1 Program SER Well bore seg 0 PTD#: 2100140 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 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. 17 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes i9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes 1 11 Permit can be issued without conservation order Yes Appr Date 1 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 # (putIO# in comments) (For Yes Area Injection Order No. 2B le '15 All wells within 1/4 mile area of review identified (For service well only) Yes KRU 1E -11, KRU 1E -13 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. 1 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 1 E -15 1 22 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 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 and MPD GLS 1/28/2010 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 • 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 complete for area impacted by lateral. 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 reservoir pressure is 11.5 ppg EMW; however, 1 E -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 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 Engineering Public A -sand lateral injector to improve sweep efficiency. Commissioner: Date: Commissioner: Date Commissioner Date ?° Z- _S--/0