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Home My WebLink About209-123 i 0 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. c 2,0 9 - /_ c 3 Well History File Identifier Organizing (done) ❑ Two -sided 111 NIIII II III 1111 ❑ Rescan Needed 111 11111111! 111111 RESCAN DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ Maps: Greyscale Items: Y Pctile., ❑ Other, No/Type: ❑Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: BY: Maria Date: 4R / / /s/ N f Project Proofing 1111111111 I 11 I BY: Aga Date: al a L ! l /s/ I Scanning Preparation x 30 = + = TOTAL PAGES__ a (Count does not include cover sheet) 114 BY: An Date: a a 91/ / /s/ Production Scanning III IIIII 11111 II III Stage 1 Page Count from Scanned File: 1- (Count does include cover eet) Page Count Matches Number in Scanning Pre aration: YES NO BY: an Date: tl aq- ) 1 /s/ Io Stage 1 If NO in stage 1, page(s) discrepancie were ound: YES I NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. 111 VIII 1 I III ReScanned 111 11111 III!I 11111 BY: Maria Date: /s/ Comments about this file: Quality Checked III IIIIII III IIII III 10/6/2005 Well History File Cover Page.doc DATA SUBMITTAL COMPLIANCE REPORT 2/16/2011 Permit to Drill 2091230 Well Name /No. KUPARUK RIV UNIT 3I- 11L1 -02 Operator CONOCOPHILLIPS ALASKA INC API No. 50- 029 - 21932 -62 -00 MD TVD Completion Date Completion Status Current Status UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: (data taken from Logs Portion of Master Well Data Maint • Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med /Frmt Number Name Scale Media No Start Stop CH Received Comments Well Cores /Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? Y / N Daily History Received? Y / N Chips Received? Y / N Formation Tops Y / N Analysis Y / N Received? , 7� Comments: I // T' _ r �� V a uJ 1 ` "� Compliance Reviewed By: Date: llo RA, °` 4 , * 0 Page 1 of 1 • Schwartz, Guy L (DOA) From: Long, Jill W [ Jill.W.Long @conocophillips.com] Sent: Thursday, June 03, 2010 3:48 PM To: Schwartz, Guy L (DOA) Subject: Withdraw Drilling Permits #209 -1220 and #209 -1230 Guy - The purpose of this email is to formally request to withdraw drilling permits #209 -1220 and #209 -1230 that were approved for planned coiled tubing drilling (CTD) sidetracks from Kuparuk producing well 31 -11. In October 2009, Permit to Drill (PTD) applications were approved for three CTD sidetracks from 31 -11: 3I-11L1 (PTD# 209 - 1210), 3I- 11L1 -01 (PTD# 209 - 1220), and 3I- 11L1 -02 (PTD# 209- 1230). The objective of these sidetracks was to access unswept reserves in the Al, A2, and A3 sands south of 31 -11. Work on those sidetracks began January 24, 2010, with the arrival and rig up of CTD rig, Nabors CDR2. After drilling 3I-11L1 and running the liner from TD up to the planned kickoff point for 3I- 11L1 -01, the window became inaccessible. Without access to the window the only solution for meeting the objectives of the project was to mill a second window and resume drilling all three laterals from there. At that time however, there was a low supply of potassium formate on the slope which was needed for use as the overbalanced completion fluid. Therefore, CTD operations were suspended until the potassium formate supply was sufficient for completing all three sidetracks on 31 -11. Nabors CDR2 rigged down and moved off the well on February 14, 2010. After the rig moved off, the well was put on production. The tubing eventually plugged off with solids produced from the unlined, openhole section of 31 -11L1 and was shut -in. A fill cleanout was performed on April 22, 2010, and the well has remained shut -in since then awaiting future work. The plan forward for 31 -11 is to set a plug in the 3 -1/2" tubing above the previously drilled window and attempt the CTD sidetracks again from a second window. The plug will isolate the 31-11L1 lateral and prevent solids from plugging off production from the future CTD sidetracks. By plugging the 31 -11 L1 lateral, the 31 -11 parent welibore perforations will be isolated as well. The reservoir targets and objectives for the future CTD sidetracks have not changed, nor have the planned rig operations. The only difference in the drilling program is that the parent welibore perforations will no longer be open to production after drilling the laterals. Therefore, all three CTD sidetrack laterals will have different names (3I -11A, 31- 11AL1, 31- 11AL2) and require new drilling permits. Since the permitted laterals 3I- 11L1 -01 and 31 -11 L1 -02 were not drilled and are no longer planned, the drilling permits for those laterals will not be used. Therefore, please let this email serve as ConocoPhillips' request to withdraw drilling permits #209 -1220 and #209 -1230. If you have questions please let me know. Sundry and PTD applications for the future work described above are being prepared and will be submitted soon. Thank you, Jill Long ConocoPhillips Alaska Drilling and Wells Office: 907 - 263 -4093 Cell: 907 -230 -7550 Fax: 918- 662 -6330 9/22/2010 • Page l of 1 Schwartz, Guy L (DOA) 1 13 From: Ohlinger, James J [ James .J.Ohlinger @conocophillips.com] Sent: Monday, February 08, 2010 2:08 PM To: Schwartz, Guy L (DOA) Subject: 31 -11 Drilling KOP Attachments: 31- 11_AOGCC.ppt Guy — as we talked Friday, the KOPs have moved for the 2nd and 3rd lateral after drilling the 1St lateral. Attached is a schematic, and below are the details. Original KOP New KOP 3I -11L1: 209 -1210 A2 -Sand API: 50- 029 - 21932 -60 6408 6408 3I- 11L1 -01: 209 -1220 Al -Sand API: 50- 029 - 21932 -61 7400 7290 3I- 11L1 -02: 209 -1230 A3 -Sand API: 50- 029 - 21932 -62 7300 7550 fames Ohlinger CTD Engineer ConocoPhillips AK, Inc. 907 - 265 -1102 office 907 - 748 -1051 cell 2/8/2010 • • d '0, 1 t _ " F �t SEAN PARNELL, GOVERNOR jr . �. s . F u e..J 1_ 6-.� k . -) ) 1 ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMhIISSION f ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Mr. J. Cawvey Alaska Wells Manager ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 -0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, 3I- 11L1 -02 ConocoPhillips Alaska, Inc. Permit No: 209 -123 Surface Location: 147' FSL, 48' FEL, Sec. 36, T13N, R8E, UM Bottomhole Location: 2610' FNL, 2310' FEL, Sec. 6, T12N, R9E, UM Dear Mr. Cawvey: Enclosed is the approved application for permit to re -drill the above referenced development well. The permit is for a new welibore segment of existing well KRU 3I -11, Permit No. 1890350, API No. 50- 029 - 21932 -00. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). Sincerely, Cathy . Foerster Commissioner DATED this 0 day of October, 2009 cc: Department of Fish 86 Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: 1b. Current Well Class: Exploratory ❑ Development Oil 0 lc. Specify if well is proposed for: Drill El Re-drill El Stratigraphic Test ❑ Service ❑ �� Development Gas ❑ A oalbed Methane ❑ Gas Hydrates ❑ Re -entry ❑ Multiple Zon/}� Single Zone �? � t" Shale Gas 2. Operator Name: / L7 t 5. Bond: U Blanket U Single Well 11. Well Name and Number: ConocoPhillips Alaska, Inc. IV t: Bond No. 59 - 52 - 180. 3I • 3. Address: 6. Proposed Depth: 12. Field /Pool(s): P.O. Box 100360 Anchorage, AK 99510 - 0360 MD: 9100' • TVD: 6107 ° Kuparuk River Field 4a. Location of Well (Govemmental Section): 7. Property Designation: Surface: 147 FSL, 48' FEL, Sec. 36, T13N, R8E, UM • ADL 25523, 25631 ° Kuparuk River Oil Pool - Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1059' FNL, 1835' FEL, Sec. 6, T12N, R9E, UM 2559, 2564 11/1/2009 Total Depth: 9. Acres in Property: 14. Distance to 2610' FNL, 2310' FEL, Sec. 6, T12N, R9E, UM ' 2437 Nearest Property: 18560 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 76 feet 15. Distance to Nearest Well Open Surface: x - 507830 ° y - 6007088 , Zone 4 KB Elevation above GL: 16.5 feet to Same Pool: 31 -13 , 1500 • 16. Deviated wells: Kickoff depth: 7300 ' ft. 17. Maximum Anticipated Pressures in psig (see 20 MC 25.035) Maximum Hole Angle: 102° • d Downhole: 4452 psig . Surface: 3804 psig - 18. Casing Program Specifications Setting Depth Quantity of Cement Size Top Bottom c. f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7# L - 80 ST - L 2715' 6385' 6134' 9100' 6107' slotted / solid liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured) Effective Depth MD (ft): Effective Depth TVD (ft): Junk (measured) 6772' 6560' 6680' 6473' Casing Length Size Cement Volume MD TVD Conductor /Structural 116' 16" 250 sx CS 11 116' 116' ��'�� Surface 3348' 9 -5/8" 330 sx Class G, 3383' 383' Intermediate 544 sx AS III, 175 sx AS 1 Production 6728' 7" 250 sx Class G, 175 sx AS I 6762' OCT 0 9 2n09 6550' Liner Alaska Oa Sl G is Cons. Com icgfo Perforation Depth MD (ft): Perforation Depth TVD (ft): Anchorage 6437'- 6454', 6457'- 6486', 6494' -6503' 6245'- 6261', 6264'- 6291', 6298' -6306' 20. Attachments: Filing Fee ❑ BOP Sketch 0 Drilling Program 0 Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Property Plat ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements El 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact James Ohlinger @ 265 - 1102 O Q Printed Name J. Cawvey Title Alaska Wells Manager Signature •2, Phone s ,- Date / 9/ Commission Use Only I Permit to Drill / API Number: / . Permit Approv ///;;; See cover letter Number: 2. q / C G � 3 i 50- (7 2832 -C' Date: /v /-f a9 for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coa ed ane, gas hydrates, or gas contained in shales: g . .4.1,500 / Sc. /gd P - M,574. Samples req'd: Yes ❑ No L►g Mud log req'd: Yes ❑ No Other: H2S measures: Yes RI ❑ Directional svy req'd: Yes [t/ No ❑ 4(-- .Z 5c c psi. J�n+► 3 " C .....+, ) / a. 41--r 3I- // PrD i t(9 -03s ,re P6 r+ iP rt'r t q Q. SV, / � , A P ROVED BY THE COMMISSION I Q ' DATE: � A' ,COMMISSIONER Form 10 401 (Revised 1/2009) - / Submit in Duplicate !6. /3.0� �s� /4j f /6' ? • • Permit to Drill Summary of Operations KRU 31-11L1, 3I-11L1-01, & 3I-11L1-02 Laterals Coiled Tubing Drilling Overview: Well 31 -11 is a 3'/" tubing x 7" casing producer in the Kuparuk A -sand. Three proposed CTD laterals will access reserves in an unswept area to the south. The existing A -Sand perfs in 31 -11 will be unaffected by these CTD laterals - the kickoff point will be in the 3'/" straddle portion above the current completion. The 31-11L1 lateral will exit the 3'/" tubing and 7" casing at 6407' MD and will target the A2 sand s of the existing well with a 2743' lateral. The hole will be completed with a 23/4" slotte finer to the TD of 9150' MD with a liner top aluminum billet at 7400' MD. The 3I-11L1-01 lateral will kick off from the aluminum billet at 7400' MD and will target the Al sand south of the existing well with an 1800' lateral. The hole will be completed with a 2%" slotted liner to the TD of 9200' MD with a liner top aluminum billet at 7300' MD. P The 3I-11L1-02 lateral will kick off from the aluminum billet at 7300' MD and will target the A3 sand south of the • existing well with an 1800' lateral. The hole will be completed with a 2 %" slotted liner to the TD of 9100' MD with the final liner top located just inside the 3 tubing at 6385' MD. * Operational Outline Pre -Rig Work 1. Positive pressure and drawdown tests on MV, SV, and SSSV. 2. DGLV's, load tbg & IA. MIT -IA. MIT -OA. 3. Shoot tubing punches in 3 tubing at 6411' and 6213' MD. 4. Set plug between tubing punches. Pump down tubing through tubing punches to confirm communication across the 3%2" x 7" annulus. /O" y0` 5. RU a -line. Set composite bridge plug at 6417' MD (inside seal assembly). ni 6. RU CTU. Lay in cement plug. Objective is to anchor the 3'/" tubing inside the 7" casing at the ,,,,,t4;11,.% 4- wt sidetrack point. p c -03 7. RU slickline. Tag cement top. l � 8. Drill out cement and composite bridge plug. 3 J - I( Caliper survey 3'/" tubing where cement was drilled out. Run dummy whipstock on slickline. 10. RU a -line. Set 3'/" monobore, flow -by whipstock at 6407' MD..' 11. Prep site for Nabors CDR2 -AC. • .. R ig Work 1. MIRU Nabors CDR2 - AC rig using 2" coil tubing. NU 7 - 1/16" BOPE, test. 2. 3I-11L1 Lateral (A2 Sand) 5 a. Mill 2.74" 2- string window with high -side orientation at 6407' MD `' b. Drill 2.70" x 3" bi- center lateral in the A2 sand to TD of 9150' MD. Pr c. Kill well. Run 2 %" slotted liner with an aluminum liner -top billet from TD up to 7400' � 3 . 3I-11L1-01 Lateral (Al Sand) 490/-4" a. Kick off of the aluminum billet at 7400' MD b. Drill 2.70" x 3" bi- center lateral in the Al sand to TD of 9200' MD. c. Kill well. Run 2%" slotted liner with an aluminum liner -top billet from TD up to 7300' 4. 3I- 11L1 -02 Lateral (A3 Sand) a. Kick off of the aluminum billet at 7300' MD b. Drill 2.70" x 3" bi- center lateral in the A3 sand to TD of 9100' MD. c. Kill well. Run 2%" slotted liner from TD up to 6385' MD, into the 3'/" tubing 5. Freeze protect. ND BOPE. RDMO Nabors CRD2 -AC. Page 1 of 5 0 p 1' a 9/29/2009 c, Liu • Permit to Drill Summary of Operations Cont. KRU 3I -1 1 L1, 31-1 1 L1 -01, and 31-1 1 L1 -02 Post -Rig Work 1. Install GLV's 2. Obtain SBHP 3. Produce to system Mud Program: • Will use chloride -based Biozan brine (8.6 ppg) for milling operations, and chloride -based Flo -Pro mud ( -10.0 ppg) for drilling operations. There is a SSSV installed in 3I -11, so we should not have to kill the well to deploy 2%" slotted liner. Disposal: • No annular injection on this well. • Class II liquids to KRU 1R Pad Class II disposal well • Class II drill solids to Grind & Inject at PBU Drill site 4 • Class I wastes will go to Pad 3 for disposal. Casing Program: • 3I -11L1: 2% ", 4.7 #, L -80, ST -L slotted liner from 7400' MD to 9150' MD • 3I- 11L1 -01: 2% ", 4.7 #, L -80, ST -L slotted/solid liner from 7300' MD to 9200' MD • 3I- 11L1 -02: 2% ", 4.7 #, L -80, ST -L slotted/solid liner from 6397' MD to 9100' MD Existing Casing/Liner Information Surface: 9% ", J -55, 36 ppf Burst 3520 psi; Collapse 2020 psi Production: 7 ", J -55, 26 ppf Burst 4980 psi; Collapse 4320 psi Well Control: • Two well bore volumes ( -222 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 4500 psi. Maximum potential surface pressure in 3I -11 is 3804 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 4452 psi at 6244 TVD in offset injector 3I -13 measured August 2009. • Well 3I -13 had been shut -in several months when this survey was taken. • The annular preventer will be tested to 250 psi and 2500 psi. Directional: • See attached directional plans: 1. 3I -11L1, plan #6 2. 3I- 11L1 -01, plan #3 3. 3I- 11L1 -02, plan #3 • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. • All 31-11 CTD laterals: 18,560' to property line, —1500' from well 3I -13 Logging • MWD directional, resistivity, and gamma ray will be run over the entire open hole section. Page 2 of 5 9/29/2009 '1 • • Permit to Drill Summary of Operations Cont. KRU 31-11L1, 3I-11L1-01, and 3I-11L1-02 Reservoir Pressure • The most recent static BHP survey in well 31-11 was taken May 2009, which measured reservoir pressure of 4255 psi at 6469'MD, 6275' TVD, corresponding to 13.0 ppg EMW: Expect to encounter increasing pressure as the laterals are drilled away from the mother well due to anticipated interaction with injection well 31-13. 3I -13 has been shut in since September 2008 to allow the area to de- pressurize. The most recent pressure survey in 3113 showed 4452 psi at 6244 TVD (13.7 ppg EMW) as of August 2009. - Hazards • Lost circulation is not expected to be particularly troublesome. Expect to encounter increasing pressure as the laterals are drilled away from the mother well. • Over - pressured zones are a potential hazard in 31 -11. Even with 10.0 ppg mud, choke pressure will have to be maintained while drilling, both for maintaining well control and borehole stability. 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 A5 sand will be encountered. Will mitigate potential sloughing problems by cutting this interval at less than 60° hole angle, and by holding a constant ±13.2 ppg EMW on the formation throughout drilling operations. • Well 31 -11 has 150 ppm H as measured on 6/22/09. Well 31 -12 is located 25' to the left side and 3I -10 is 25' to the right side of the 31 -11 surface location. The 3I -12 has no measured H since it is an injector. The H measured in 3I -10 is 120 ppm (1/2/09). The maximum H level on the pad is 160 ppm from wells 3I -04 (12/17/08) and 3I -17 (1/10/09). All H monitoring equipment will be operational. Managed Pressure Drilling Managed pressure drilling (MPD) techniques will be employed to provide constant bottom hole pressure by . using 10.0 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allow use of less expensive drilling fluid and minimizes fluid losses and/or fracturing at the end of the long well bores. A hydraulic choke for regulating surface pressure is installed between the BOPE choke manifold and the mud pits, and is independent of the BOPE choke. Using this technique will require deployment of the BHA under trapped wellhead pressure. Pressure deployment of the 2%" BHA will be accomplished utilizing the 2%" pipe rams and slip rams. The annular preventer will act as a secondary containment during deployment and not as a stripper. Well 31-11 has a SSSV, 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: • Estimated reservoir pressure: 4203 psi at 6407' MD (6217' TVD), or 13.0 ppg EMW. • • Expected annular friction losses while circulating: 577 psi (assuming friction of 90 psi/1000 ft due to the 3'/2" tubing) • Planned mud density of 10.0 ppg equates to 3233 psi hydrostatic bottom hole pressure at 6217' TVD • While circulating 10.0 ppg mud, bottom hole circulating pressure is estimated to be 3810 psi or 11.8 ppg . EMW without holding any additional surface pressure. This alone is insufficient to overbalance expected formation pressure in 31 -11, so —450 psi choke pressure will be required while drilling to maintain overbalance. If increased formation pressure is encountered, mud weight or choke pressure will be increased to maintain overbalance. • When circulation is stopped, 1000 psi of surface pressure shall have to be applied to maintain the same borehole pressure as during drilling operations. Page 3 of 5 e 9/29/2009 31 -11 Proposed CTD Sidetrack Updated: 24-Sep-09 Camco TRMAXX -5E SSSV @ 2212 MD (2.813" min ID, X- profile) 3 -1/2 ", 9.3# L -80 EUE 8rd -Mod Tubing to surface 16" 62# H-40 shoe @116'MD 3 -1/2" Camco MMG gas lift mandrels (5) @ 2512', 3702', 4760', 5668', & 6074' 9 -5/8" 36# J -55 shoe @3383'MDT..01111 X' landing nipple @ 6123' MD (2.813" min ID) • Baker 3 -1/2" seal assembly 6131' - 6143' MD 80-40 PBR at 6132' - 6145' Baker KBH Anchor Seal Assy at 6145' MD - Baker SAB 40 -32 packer @ 6146' MD 'X' landing nipple @ 6156' MD (2.813" min ID) milmr i I ' u`ed 2 -3/8" liner top at -6390' MD '` 3.1/2" flow-by ; Holes shot in 3 -1/2" straddle at -6411' & 6213' MD monobore v f <- whipstock at 6407 > - s i MD Baker F1 permanent packer @ 6422' MD (e -line set) - 80-40 Sealbore extension (6425'- 6430') " 3 -1/2 'straddle 'D' landing nipple @ 6433' MD (2.750" min ID) L1 -02 TD @ 9100' ^^_°°' • cemented in place ri : (wp03, A3 sand) -: .::-„,, WLEG at 6438' MD t \ i ce/ /'/ / A sand pens \ ............ �/ -.4111111111 L1 TD @ 9150' A3: 6437' - 6454' -- — ` (wp06, A2 sand) A2: 6457' - 6486' A1: 6494' - 6503' 2 -3/8" slotted pipe Aluminum billets @ 7400' MD L1 -01 TD @ 9200' 7" 26# J -55 shoe and 7300 MD (WP03) (wp03, Al sand) @ 6550' MD ■ I KUP • 31-11 . 117rilrag ._ ,. ConocoPhilli - owes Weli`Attributes ; Max M &MD h''1 .. . Alaska, Wellborn APWWI Field Name Well Status Inci r) MD (ftKB) Act Btm (ftKB) ,,,, 500292193200 KUPARUKRIVERUNIT PROD 24.02 5,300.00 6,772.0 Ps Comment H2S (ppm) Date Annotation End Date KB-Grd (8) Rig Release Date ".. WniI Cona6 0 3411 BM 12008740 AM - - SSSV:TRDP 160 2/5/2008 Last WO: 6/1/2009 35.91 4/4/1989 d,ematb - Annotation Depth (RKB) End Date Annotation Last Mod By End Date Last Tag: SLM 6,516.0 6/6/2009 Rev Reason: Workover, GLV C/O, Tag Imosbor 6/10/2009 + isiii i , •s ,�, L Casing Description String 0... Stang ID -. Top (81(8) Set Depth (f... Set Depth (TVD)... String WL.. String... String Top Thrd CONDUCTOR 16 15.062 0.0 116.0 116.0 6250 H-40 HANGER, 31 Casing Description String 0... String ID _. Top RK8 Set Depth f Set De D String Wt,.. String String To ''= 9 P fl 9 Pl 1 Pti ••• Depth (TVD)... fl 9 -• fl P Thrd w , SURFACE 95/8 8.765 35.0 3,383.4 3,383.3 36.00 J -55 Casing Description String 0... String ID Top (611(8) Set Depth (f Set Depth (TVD) String Wt... String String Top Thrd i , -. PRODUCTION 7 6.151 33.0 6,761.5 6,550.2 26.00 J-55 TUbniq Str ing3 .y :' i Tubing Description String 0... String ID Top (611(8) Set Depth (f... Set Depth (TVD) ... String Wt... Stang String Top Thrd TUBING - Upper 312 2.992 31.0 6,143.0 5,974.1 9.30 L-80 EUE COmpletlon'Details ' +.. •. Top Depth CONDUCTOR, - :t . _ _ . _ _ _ 0.116 �. F (TVD) Top Incl Top (ftKB) (RR) ( °) Item Description Comment ID (in) 31.0 31.0 0.02 HANGER FMC 6" x 3 1/2' Gen IV Tubing Hanger w/ pup 2.992 sssv, 2,212 2,212.3 2,212.3 0.17 SSSV Camco 3 1/2" x 2.813" 9C Profile TRMAXX -5E SCSSV "LOCKED OPEN 2.813 w /6200 psi on control line" 6,123.0 5,955.7 23.60 NIPPLE Haliburton 312" x 2813 "'X' Nipple 2.813 I L 6,131.0 5,963.1 23.57 SEAL ASSY Baker 80-40 Seal Assembly (2 Space out) 3.000 Tubing Description String 0_. String ID _- Top (RKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd GAS LIFT, TUBING - Mid 312 2.992 6,133.6 6,429.0 6,238.1 9.30 L -80 EUE 2,512 - Section CorrtpJetion Details : r . Top Depth . a .. .. .. , . + (TVD) To In SURFACE 353,36 - Top (RKB) () ( °) Item Descriptlon Comment ID (IN �,°,°.;; 6 ,133.6 5,965.5 23.57 PBR Baker 80-40 PBR 3.000 `_ - 6,147.0 5,977.7 23.53 SEAL ASSY Baker KBH-22 80 -DA-40 Anchor Seal Assy 3.000 GAS LIFT, 6,147.9 5,978.6 23.53 PACKER Baker 84-SAB-40x32 Retainer Prod. Packer 3.250 3,702 6,152.8 5,983.1 23.51 XO Reducing X -over Sub, 4 1/2 LTC pin x 31/2 EUE pin 3.010 E. 6,157.8 5,987.6 23.50 NIPPLE Haliburton2.813 "'X' Nipple 2.813 6,421.3 6,231.0 22.77 SEAL ASSY Baker 80-40 GBH -22 Seal Assy w/Locator 3.000 r . Tubing Description String 0... String ID , . Top (RKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd GAS LIFT. _- PACKER ASSY I 5 I 4.000 I 6,422.1 6,438.0 I 6246.3 I I I ACME 4,760 Cfitnpletioti`Dttatls <, Top Depth (TV0) Top Incl T op (RKB) (RKB) ( °) Rem Description Comment ID (In) 6,422.1 6,231.8 22.76 PACKER Baker 85.40'F1' Permanent Production Packer 4.650 GAS LIFT, 6,425.4 6,234.8 22.69 SBE Baker 80-40 SBE (5 Long) w/ XO Sub 4.000 5,666 6,429.9 6,238.8 22.59 XO - Reducing X -Over Sub 5" BTC x 3.5" EUE 3.000 6,433.4 6,242.1 22.52 NIPPLE Camco 312 "x2.75" 'D' Nipple 2.750 ' 6,437.1 6,245.4 22.44 SOS ShearoutSubw /WLEG 3.000 Peffarati -- Slots . . GAS OF 6,074 _ Shot Top (TVD) Btm(TVD) Dens T op (ftKB) Bbn (RKB) (RKB) (81(8) Zone Date (aft.- Type Comment 6,437 6,454 6,245.4 6,261.0 A -3, 31 -11 3/6/1990 8.0 IPERF 2 1/8" Dyna Strip, 60 deg ph 6,457 6,486 6,263.7 6,290.6 A -2, 31 -11 5/18/1989 4.0 IPERF 4.5 "HSD Csg Gun, 90deg ph NIPPLE. 6,123 6,494 6,503 6,298.0 6,305.8 A -1, 31-11 3/6/1990 8.0 IPERF 21/8 Dyna Strip, 60 deg ph N otes:`Genetal'dr Sale tY :; ; •: End Date Annotation SEAL Assr, 6/10/2009 I NOTE: VIEW SCHEMATIC w /Alaska Schema(1c9.0 6,131 PBR, 6,134 SEAL ASSY, 1 ..- .: -:',G • 6,147 - PACKER, 6,146 1 NIPPLE, 6,156 PACKER, 6,422 SEAL ASSY, . 6,421 SBE, 6,425 M Details`:_ . Top Depth Top Port (TVD) Intl OD Valve Latch Site TRO Run Stn Top (RKB) . O r) Make Model (in) Sery Type Type (in) (Psi) Run Date Con,... 1 2,511.6 2,511.6 0.09 Camco MMG 1 12 GAS LIFT GLV RK 0.188 1,265.0 6/52009 NIPPLE. 6.433 2 3,702.1 3,701.9 3.84 Camco MMG 1 12 GAS LIFT GLV RK 0.188 1,261.0 6/5/2009 3 4,760.5 4,706.8 23.38 Camco MMG 1 12 GAS LIFT GLV RK 0.188 1,254.0 6/5/2009 ` " 4 5,667.8 5,538.4 23.61 Camco MMG 1 12 GAS LIFT GLV RK 0.188 1,245.0 6/5/2009 SOS,6.437 5 6,074.0 5,910.7 23.36 Camco MMG 1 12 GAS LIFT OV RK 0.188 0.0 6/5/2009 IPERF, 6,43743,454 IPERF, 6,457$466 IPERF. In 10 PRODU ON' `M,✓i � u f 7D, 6,772 - • • ConocoPhulhps Alaska ConocoPhillips(Alaska) Inc. 1 Kuparuk River Unit Kuparuk 31 Pad 31 -11 31- 11L1 -02 Plan: Plan 3, 3I- 11L1 -02 Standard Planning Report 02 October, 2009 NotIM BAKER HUGHES G 1NAL 0 • N•' ConocoPhillips IlE1111 ConOCoPhd11pS Planning Report BAKER Alaska IHYtENES Daitaba a EDM Alaska Prod v16 Local Co ordinate Refit nrr3 Well 31 -11 spa / CortocoPhillips(Alaska) Inc. TVD R rence Mean Sea Level - Projece Kuparuk River Unit MD ren+4 : 31 -11 @ 76.00ft (31 -11) Site Kuparuk 31 Pad North Reference; True Well 31 -11 S urvey Calcutiition Method , Minimum Curvature 4 11t te. "- 3I-11L1 -02 be elgn� = Pl 3 , 31 - 1 1 L1 - 02 Project: Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor ite ... Kuparuk 31 Pad Site Position: Northing: 6,007,285.49 ft Latitude: 70° 25' 52.059 N From: Map Easting: 508,056.44 ft Longitude: 149° 56' 3.597 W Position Uncertainty: 0.00 ft Slot Radius: " Grid Convergence: 0.06 ° vu� iNsH 31-11 Well Position +N /-S 0.00 ft Northing: 6,007,088.16 ft . Latitude: 70° 25' 50.121 N +E / -W 0.00 ft Easting: 507,830.23 ft , Longitude: 149° 56' 10.241 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00ft ' WCUbor '. ° 31-11L1-02 if gnettcs M (I a Sample D LtecHnatt D p A `. �d rg (' 11 -.{n BGGM2009 11/1/2009 17.31 79.84 57,357 tesign ; Plan 3, 31-11 L1 -02 i Audit Notes: Version: Phase: PLAN Tie On Depth: 7,300.00 ` . +N/$ 4-01 vv d Depth Fro tel: 0 ( . (ft)� � ( 0.00 0.00 0.00 207.76 P �e *s N iteas flured n Az `� # e Dogleg -- u1 I Tu eptl>i ' Inclll€ltlon imuth Stem +N/*S +E/ Ram Rate Tfrfr O ( .(a . ). (ft) ',(ft) (ft) :, (°l = (0r�t� -: ( °rl tft) = 'c T� 7,300.00 94.73 245.34 6,165.24 - 1,155.39 - 1,174.68 0.00 0.00 0.00 0.00 7,320.00 98.73 245.34 6,162.89 - 1,163.67 - 1,192.73 20.00 20.00 0.00 0.00 7,340.00 102.18 243.30 6,159.26 - 1,172.19 - 1,210.45 20.00 17.29 -10.22 330.00 7,360.00 101.46 239.28 6,155.17 - 1,181.59 - 1,227.62 20.00 -3.62 -20.10 260.00 7,410.00 101.40 233.16 6,145.25 - 1,208.83 - 1,268.33 12.00 -0.13 -12.24 270.00 7,485.00 92.40 233.16 6,136.25 - 1,253.43 - 1,327.86 12.00 -12.00 0.00 180.00 8,035.00 91.16 167.13 6,117.02 - 1,741.41 - 1,506.74 12.00 -0.23 -12.00 270.20 8,435.00 90.40 215.13 6,111.24 - 2,122.46 - 1,581.74 12.00 -0.19 12.00 90.50 8,785.00 90.30 173.13 6,108.99 - 2,454.32 - 1,665.28 12.00 -0.03 -12.00 270.00 9,100.00 90.24 210.93 6,107.46 - 2,756.84 - 1,729.76 12.00 -0.02 12.00 90.00 10/2/2009 3 :01 :25PM Page 2 COMPASS 2003.16 Build 69 .'' !- ', I . .t ''' ,,, ' lt I \..,,, iii 1 • • �-' ConocoPhillips nag CC Planning Report BAKER Alaska HUGHES 1 atabase* EDM Alaska Prod v16 Local c otxilnate Reiertertce' Well 31 -11 ' Company ConocoPhillips(Alaska) Inc. , , , „/VDRefeferfte,i Mean Sea Level Prdject Kuparuk River Unit MD Reference :, ° 31 -11 @ 76.00ft (31 -11) ! 1te Kuparuk 31 Pad North Raaerence . True Well 31 -11 Harveytieuln Minimum Cur vature i11IfI� 31-11L1-02 Plan 3, 31- 11L1 -02 P tah, . / led ' ' liertt�caF �trtll p Depth IncItn � u.'tA � Nl 1 t=W , : an 14 t> er it ... ... .. t" . .: y fi (ft) f t t� : , .. 7,300.00. 94.73 245.34 6,165.24 - 1,155.39 - 1,174.68 1,569.54 0.00 0.00 6,005,931.66 506,6 KOP 7,320.00 98.73 245.34 6,162.89 - 1,163.67 - 1,192.73 1,585.28 20.00 0.00 6,005,923.35 506,638.84 2 102.18 243.30 6,159.26 - 1,172.19 - 1,210.45 1,601.07 20.00 -30.00 6,005,914.82 506,621.13 3 7,360.00 101.46 239.28 6,155.17 - 1,181.59 - 1,227.62 1,617.38 20.00 - 100.00 6,005,905.40 506,603.98 End of 20 deg / 100 ft DLS 7,400.00 101.42 234.38 6,147.23 - 1,203.04 - 1,260.42 1,651.64 12.00 -90.00 6,005,883.92 506,571.20 7,410.00 101.40 233.16 6,145.25 - 1,208.83 - 1,268.33 1,660.45 12.00 -90.97 6,005,878.12 506,563.30 5 7,485.00 92.40 233.16 6,136.25 - 1,253.43 - 1,327.86 1,727.64 12.00 - 180.00 6,005,833.46 506,503.82 6 7,500.00 92.40 231.36 6,135.62 - 1,262.60 - 1,339.71 1,741.28 12.00 -89.80 6,005,824.28 506,491.98 7,600.00 92.38 219.35 6,131.44 - 1,332.69 - 1,410.66 1,836.35 12.00 -89.88 6,005,754.12 506,421.11 7,700.00 92.24 207.34 6,127.40 - 1,416.01 - 1,465.47 1,935.61 12.00 -90.38 6,005,670.75 506,366.39 7,800.00 92.02 195.33 6,123.67 - 1,508.92 - 1,501.76 2,034.73 12.00 -90.86 6,005,577.81 506,330.20 7,900.00 91.70 183.33 6,120.41 - 1,607.37 - 1,517.93 2,129.38 12.00 -91.31 6,005,479.36 506,314.14 8,000.00 91.31 171.33 6,117.78 - 1,707.04 - 1,513.28 2,215.41 12.00 -91.70 6,005,379.70 506,318.89 8,035.00 91.16 167.13 6,117.02 - 1,741.41 - 1,506.74 2,242.78 12.00 -92.02 6,005,345.34 506,325.46 7 8,100.00 91.08 174.93 6,115.75 - 1,805.55 - 1,496.62 2,294.83 12.00 90.50 6,005,281.22 506,335.65 8,200.00 90.92 186.93 6,114.00 - 1,905.34 - 1,498.25 2,383.89 12.00 90.65 6,005,181.44 506,334.13 8,300.00 90.72 198.93 6,112.57 - 2,002.62 - 1,520.59 2,480.37 12.00 90.86 6,005,084.15 506,311.90 8,400.00 90.49 210.93 6,111.51 - 2,093.13 - 1,562.67 2,580.06 12.00 91.03 6,004,993.60 506,269.92 8,435.00 90.40 215.13 6,111.24 - 2,122.46 - 1,581.74 2,614.90 12.00 91.16 6,004,964.25 506,250.88 8 90.40 207.33 6,110.78 - 2,178.00 - 1,615.41 2,679.73 12.00 -90.00 6,004,908.69 506,217.26 8,600.00 90.38 195.33 6,110.10 - 2,270.97 - 1,651.72 2,778.92 12.00 -90.05 6,004,815.68 506,181.06 8,700.00 90.34 183.33 6,109.47 - 2,369.47 - 1,667.91 2,873.62 12.00 -90.14 6,004,717.18 506,164.98 8,785.00 90.30 173.13 6,108.99 - 2,454.32 - 1,665.28 2,947.48 12.00 -90.21 6,004,632.34 506,167.69 9 8,800.00 90.30 174.93 6,108.91 - 2,469.23 - 1,663.73 2,959.95 12.00 90.00 6,004,617.43 506,169.26 8,900.00 90.29 186.93 6,108.40 - 2,569.04 - 1,665.35 3,049.02 12.00 90.01 6,004,517.63 506,167.75 9,000.00 90.27 198.93 6,107.91 - 2,666.32 - 1,687.68 3,145.51 12.00 90.07 6,004,420.34 506,145.51 ' 9,100.00 90.24 210.93 6,107.46 • - 2,756.84 - 1,729.76 3,245.21 12.00 90.13 6,004,329.79 506,103.54 TD at 9100.00 -2 318" 10/2/2009 3:01:25PM Page 3 COMPASS 2003.16 Build 69 • • ConocoPhillips ram C 0 n 0 COFiiillil3S Planning Report BAKER MUGHES Dat as EDM Alaska Prod v16 LocalCo ordl t Reihisrence. Well 31-1 co ai ConocoPhilli # as k s} I nc. }VD � Mean Sea Level Kuparuk River unit IND Fl eferencs: 31-11 © 76 00f (31-11) Kuparuk 31 Pad North Reference True 1 31 11 Sulnv catcri�orl metho Minimum Curvature 31-11L1-02 Plan 3 , 31 1iL1 -02 T ts ai t Name h angst t?ip Ares #bhp lair tVD Nt l w North#rng ; tt � ° e ) � e } ) (fit ..., �,.' t !g 31- 11L1 -02 t2.3 0.00 0.00 6,144.00 - 1,195.41 - 1,261.39 6,005,891.55 506,570.22 70° 25' 38.363 N 149° 56' 47.243 W - plan misses target center by 7.81 ft at 7397.34ft MD (6147.75 TVD, - 1201.52 N, - 1258.30 E) - Point 31 -11 L1 -02 t1.3 0.00 0.00 6,166.00 - 1,150.49 - 1,174.33 6,005,936.55 506,657.22 70° 25' 38.805 N 149° 56' 44.690 W - plan misses target center by 4.96ft at 7300.00ft MD (6165.24 TVD, - 1155.39 N, - 1174.68 E) - Point 31 -11 L1 -02 fault 3 0.00 0.00 0.00 - 2,354.42 - 1,338.63 6,004,732.57 506,494.20 70° 25' 26.964 N 149° 56' 49.503 W - plan misses target center by 6118.39ft at 8670.38ft MD (6109.65 TVD, - 2339.97 N, - 1665.27 E) - Polygon Point 1 0.00 - 2,354.42 - 1,338.63 6,004,732.57 506,494.20 Point2 0.00 - 2,275.07 - 1,684.59 6,004,811.55 506,148.19 Point 3 0.00 - 2,138.47 - 2,272.51 6,004,947.52 505,560.19 Point 4 0.00 - 2,275.07 - 1,684.59 6,004,811.55 506,148.19 31- 11L1 -02 t3.3 0.00 0.00 6,104.00 - 2,732.99 - 1,782.08 6,004,353.58 506,051.20 70° 25' 23.240 N 149° 57' 2.507 W - plan misses target center by 57.60ft at 9100.00ft MD (6107.46 TVD, - 2756.84 N, - 1729.76 E) - Point 31 -11 L1 -02 Polygon 0.00 0.00 0.00 - 992.55 - 1,112.16 6,006,094.55 506,719.23 70° 25' 40.358 N 149° 56' 42.867 W - plan misses target center by 6145.58ft at 7485.00ft MD (6136.25 TVD, - 1253.43 N, - 1327.86 E) - Polygon Point 1 0.00 - 992.55 - 1,112.16 6,006,094.55 506,719.23 Point 2 0.00 - 1,814.43 - 1,317.00 6,005,272.53 506,515.27 Point 3 0.00 - 3,253.19 - 1,698.47 6,003,833.52 506,135.35 Point4 0.00 - 3,065.74 - 2,129.33 6,004,020.50 505,704.33 Point 5 0.00 - 1,230.13 - 1,557.44 6,005,856.52 506,274.24 Point6 0.00 - 992.55 - 1,112.16 6,006,094.55 506,719.23 3I-11L1-02 fault 2 0.00 0.00 0.00 - 1,499.67 - 1,038.69 6,005,587.55 506,793.21 70° 25' 35.371 N 149° 56' 40.709 W - plan misses target center by 6139.70ft at 7976.44ft MD (6118.34 TVD, - 1683.68 N, - 1516.26 E) - Polygon Point 1 0.00 - 1,499.67 - 1,038.69 6,005,587.55 506,793.21 Point 2 0.00 - 705.96 - 664.86 6,006,381.58 507,166.17 Point 3 0.00 415.07 - 583.73 6,007,502.58 507,246.12 Point 4 0.00 - 705.96 - 664.86 6,006,381.58 507,166.17 31 -11 L1 -02 fault 1 0.00 0.00 0.00 - 809.13 - 546.91 6,006,278.54 507,284.22 70° 25' 42.163 N 149° 56' 26.285 W - plan misses target center by 6200.35ft at 7410.00ft MD (6145.25 TVD, - 1208.83 N, - 1268.33 E) - Polygon Point 1 0.00 - 809.13 - 546.91 6,006,278.54 507,284.22 Point 2 0.00 - 1,203.04 - 673.32 6,005,884.53 507,158.24 C as i ng . ; „ .r C asin g Hts ©eP#h Diameter 4 Lana r 9,100.00 6,107.46 2 3/8" 2 -3/8 3 10/2/2009 3:01:25PM Page 4 COMPASS 2003.16 Build 69 ORIGtN • • b-' ConocoPhillips I Ekilli C0noCoIullipS Planning Report BAKIR Alaska HUGHES Data�la EDM Alaska Prod v16 Local ^Co ordtn R rence , .s Well 31 -11 mpa« ConocoPhillips(Alaska) Inc. .TV Re� Mean Sea Level oj '� Kuparuk River Unit I D #eferenc s 31 -11 @ 76.00ft (31-11) Kuparuk 31 Pad f e e True 31-11 Survey! it on Method Minimu C llibore ,.. 31-11L1 -02 Plan 3 3 11, - 02 Pan A to lions M p t tra t V�a1 Locat C o o rdln 6a iS W (ft) ' 1or#"t nt 7,300.00 6,165.24 - 1,155.39 - 1,174.68 KOP 7,320.00 6,162.89 - 1,163.67 - 1,192.73 2 7,340.00 6,159.26 - 1,172.19 - 1,210.45 3 7,360.00 6,155.17 - 1,181.59 - 1,227.62 End of 20 deg / 100 ft DLS 7,410.00 6,145.25 - 1,208.83 - 1,268.33 5 7,485.00 6,136.25 - 1,253.43 - 1,327.86 6 8,035.00 6,117.02 - 1,741.41 - 1,506.74 7 8,435.00 6,111.24 - 2,122.46 - 1,581.74 8 8,785.00 6,108.99 - 2,454.32 - 1,665.28 9 9,100.00 6,107.46 - 2,756.84 - 1,729.76 TD at 9100.00 10/2,2009 3:01:25PM Page 5 g f t $ y, COMPASS 2003.16 Build 69 : , .4 - ,1 s y ; 1 1,,.. amT"eMorel WELLBORE DETAILS: 31- 11L1 -02 REFEtENCEINFORMA110N Project: Kuparuk RtuerUnit Mepee�rlomr: 7 ,� Site: Kuparuk3lPad Coodnate(NE) Reference: Well 31 -11, True Nall) �" Well: 31 ` •:eero Feld 500292193262 Vertical (ND) Reference: Mean Sea Level ell: .,, BAKER COf1000Phtllip5 vYellbore: 3I o c e:tvaa SedonVS)Relaece Slot - (6.9dN,6.00El Plan: Plan 3, 31.11 L1 -02 31.11l3F11L7 -02 Model: Dem:nn2ao5 Parent Wellbore: 31 -11 L1 Measured D Reference :31.11(+816.0011 (3410 ( ) ecr�.lzcor Tie on MD: 7300.00 E� Calculation Mehad: Mnimun Curvdve -400 1 . WELL DETAILS: 3411 Ground Level: 0.00 -600 +NI -S +E/ -W Northing Eaeting Latntude Longitude Slot 0.00 0.00 6007088.16 507830.23 70'25'50.121 N 149' 56'10.241W -800 y - 1- I 17iI -II SECTION DETAILS ANNOTATIONS -1 ' OndcT deg 1 IAA ft D c ■ • , ... •00 Sec MD Inc Azi ssTVD +N/-S +E / -W DLeg TFace VSec Target AmotaBan 1 7300.00 94.73 245.34 6165.24 - 1155.39 - 1174.68 0.00 0.00 1569.54 KOP -1200 1 - LP 2 7320.00 98.73 245.34 6162.89 - 1163.67 - 1192.73 20.00 0.00 1585.28 2 3 7340.00 102.18 243.30 6159.26 - 1172.19 - 1210.45 20.00 330.00 1601.07 3 4 7360.00 101.46 239.28 6155.17 - 1181.59 - 1227.62 20.00 260.00 1617.38 Endo(20deg /100ft DLS ---, 1 5 7410.00 101.40 233.16 6145.25 - 1208.83 - 1268.33 12.00 270.00 1660.45 5 , i 6 7485.00 92.40 233.16 6136.25 - 1253.43 - 1327.86 12.00 180.00 1727.64 6 0 -1600 7 8035.00 91.16 167.13 6117.02 - 1741.41 - 1506.74 12.00 270.20 2242.78 7 0 • 8 8435.00 90.40 215.13 6111.24 - 2122.46 - 1581.74 12.00 90.50 2614.90 8 - 1800 9 8785.00 90.30 173.13 6108.99 - 2454.32 - 1665.28 12.00 270.00 2947.48 9 10 9100.00 90.24 210.93 6107.46 - 2756.84 - 1729.76 12.00 90.00 3245.21 TDat9100.00 / -2000 o -2200 I 4 - 2400 1 . . .., p i , P -260( ;1 -1 I .11j, 1 - 31- n/31 -11 ".1.02 - 2800 19111 W 31- 11 /.1- 111.1.01' - -. -3000 i -3200 1 t - �a -3200 -3000 -28011 -2600 -2400 -2200 -2000 --1800 -1600 -1400 -1200 -1000 -81111 -600 -400 -200 0 200 400 i > 5610 ` West(- )/East( +) (200 ft/in) 5695 5780 A 5865 • 00 5950 Endo - 20 deb / 100 fl DLS Q, 5 6035 r 9 ILJO9fw. Al CD d KOP / 7 8 31- IIR.1.1 L1.02 3 t 2 3' 5 6 i n i y 6120 __-_. _ - --∎ 31- 1731 -1 L.1 t 2 6205 __-- -- d) 2 :1 -1131 IIL14 1 c) 6290 6375 ,-n 31 -11/3 -11 6545 510 595 680 765 850 935 1020 1105 1190 1275 1360 1445 1530 1615 1700 1785 1870 1955 2040 2125 2210 2295 2380 2465 2550 2635 2720 2805 2890 2975 3060 3145 3230 3315 3400 3485 3570 3655 3740 3825 Vertical Section at 207.76° (85 ft/in) Pro ct: Ku aruk River Unit ^' NO�m.n Si P 500292193262 WELLBORE DETAILS: 31-11L1 -02 REFERENCERFO MAION I Site: Kuparuk 3l Pad Coardr�elNtE)Relsrc ee WW1 3141, True NNorth lh FEIN eeaF a • Well: 31 -11 so-err= Ver9cal(IVD)Relwence: 31-11 676.001 (31 -11) BAKER c Wellbore: 31- 11L1 -02 ou�'9e. 79.8, Sedan (VS) Reference: Sbt- (0.00X, 0.00E) ConocoPh1 5 Plan: Plan 3,31 -11 L1 -02 31- 11131 -11 L1-02 o�ennrzoos Parent Wellbore: 31 -11L1 Measued Reference: 31 -11 �76.6a f31 -11) ( ) rtaet ec�+mo<• Tie on MD: 7300.00 Ceauktion Method Minimum Cweture 111/0111115 Alaska . ___ -1080- - ._, L ......_- i �� r r..rzr rr J ./ -1170 . rAi / / // 1260 / r -13511 ' -1530 I 't :o + • -1620 d- / -1710 1 \• -._/ j 19(X i ( �--'� � °V -la9e r / / p -1980 1 I 1 J 2070 i 1 -2160 �� z O ^ -2250 . . L ' -2340 % 0 -2430 i -2520 -2610 - i -2700 / ; • +' L / _2790 6 (Jh}IPl -1 ■ 1.02 \ , -2880 '111141/31-1 1 -01 -2970 , I -3060 . 6303 635J -3150 - to 645`1 -3240 31- 7/31-1:1 — — 650 31 -11 @.3939pft ;31 -11) 3!40 "I 16 , -3240 -3150 -3060 -2970 -2880 -2790 -2700 -2610 -2520 -2430 -2340 -2250 -2160 -2070 -1980 -1890 -1800 -1710 -1620 -1530 -1440 -1350 -1260 -1170 -1080 -990 -900 -810 -720 -630 — -540 -450 -180 -90 0 90 West( - )/East( +) (90 ft/in) 0 • Nabors CDR -2AC Kuparuk Managed Pressure Coil Tubing Drilling BOP Configuration for 2" Coil Tubing Lubricator ESSI Riser Annular/ Blind / Shear 2" Pipe / Slip (CT) Pump into Lubricator J L above BHA rams �p'� _ I Choke 1 2 -3/8" Pipe / Slip (BHA) ; Choke Equalize Manifold 2 -3/8" Pipe / Slip (BHA) p J L J L Kill 4� �Q ► 1 r Bl / Shear 2" Pipe / Slip (CT) Choke 2 Swab Valves Wing Valves ®® ∎ ®∎ Tree Flow Cross Surface Safety Valve BOPE: 7-1/16", 5M psi, TOT U Choke Line: 2- 1/16 ", 5M psi 9Q C 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 0 i 'N 1 U I i 's i"\ • TRANSMITT ALL LETTER CHECKLIST NAME / � '" � 3 / l Lt / -Z)2_ PTD# 7-9 / Z� `� /Development Service Exploratory Stratigraphic Test Non - Conventional Well FIELD: t �c—' Lc l�— POOL: t 7 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 1<2LE / / (If last two digits in permit No. /t310 ice-;; API No. 50 - - API number are between 60 -69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(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 WELL PERMIT CHECKLIST z Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK RIV UNIT 3I- 11L1 -02 _ Program D_ EV Well bore seg AZ PTD#: 2091230 Company CONOCOPHILLIPS ALASKA INC - Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 On /Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes Top prod interval and TD in ADL 025631 3 Unique well name and number Yes 4 Well located in a defined pool Yes Kuparuk, Kuparuk Oil Pool governed by CO 432C. 5 Well located proper distance from drilling unit boundary Yes No spacing restrictions with respect to drilling unitboundaries and no interwell 6 Well located proper distance from other wells Yes spacing restrictions. Wellbore will be more than 3 miles from the 7 Sufficient acreage available in drilling unit Yes external boundary of the KRU. 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes - 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes SFD 10/9/2009 13 Can permit be approved before 15 -day wait Yes • 14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre - produced injector: duration of pre production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.0306.1.A)42.A -D) NA 18 Conductor string provided NA Conductor set in 31 -11 _ Engineering 19 Surface casing protects all known USDWs NA Surface casing set in 31 -11 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing cemented in 31 -11 X 21 CMT vol adequate to tie -in long string to surf csg NA Production casing set in 31 -11 22 CMT will coverall knownproductive horizons No OH slotted liner laterals 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 NA will keep motherbore production. S/T just above A sand. 26 Adequate wellbore separation proposed Yes Closest wellbore is 31 -13 at 1500 ft. 27 If diverter required, does it meet regulations NA BOP stack already in place. Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max fm pressure 4255 psi(13 ppg) .. Will use MPD (managed pressure drilling) and 10 ppg mud GLS 10/13/2009 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP = 3804 psi .. Will test BOP's to 4500 psi III 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 31 pad. Rig has sensors and alarms. 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No No, parent wellbore measured 150 ppm H2S during 6/09. Geology 36 Data presented on potential overpressure zones Yes Expected reservoir pressure is 13.0 - 13.7 ppg EMW; will be drilled using 10.0 ppg mud and Appr Date 37 Seismic analysis of shallow gas zones NA managed pressure drilling techniques. SFD 10/9/2009 38 Seabed condition survey (if off NA 39 Contact name /phone for weekly progress reports [exploratory only] NA Geologic Engineering �. '� .ner Overpressure expected up to 13.7 ppg EMW. Wellbore will be drilled using 10.0 ppg mud managed and pressure drilling Commissioner: Date: Co missioner: Date 4= Date techniques to maintain overbalance. SFD 0 7//449, 1' / -of