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Home My WebLink About209-122 • • 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. _ J,Q, Well History File Identifier Organizing (done) ❑ Two -sided III I 11111 ❑ Rescan Needed III 111111111 111111 RES N DIGITAL DATA OVERSIZED (Scannable) olor Items: ❑ Diskettes, No. ❑ Maps: p yscale Items: I I ❑ Other, No/Type: ❑ Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non- Scannable) ❑ Other: O Logs of various kinds: NOTES: ❑ Other:: BY: AM% Date: oi._ • /s/ 14 , Project Proofing 111 H 111111 111 BY: Maria Date: �� /s/ 4 • Scanning Preparation x 30 = + = TOTAL PAGES / / BY: Date: a a (Count does not include cover sheet) r1 l /s/ Production Scanning III IIilllIillhl 111 Stage 1 Page Count from Scanned File: cq © (Count does include cove heet) Page Count Matches Number in Scanning Prep ration: YES NO BY: C:Maria Date: I I /s/ oip Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. 111 111 Ill I I I I ReScanned 1111 lililill 11111 BY: Maria Date: /s/ Comments about this file: Quality Checked III 1 ill 10/6/2005 Well History File Cover Page.doc DATA SUBMITTAL COMPLIANCE REPORT 2/16/2011 Permit to Drill 2091220 Well Name /No. KUPARUK RIV UNIT 3I- 11L1 -01 Operator CONOCOPHILLIPS ALASKA INC API No. 50- 029 - 21932 -61 -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? Comments: ) e w4v ` f f l YAil 6.-1/0,c4 c4 v1 Compliance Reviewed By: Date: R` t 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), 31- 11L1 -01 (PTD# 209 - 1220), and 31- 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 31- 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 3I-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 31-11L1 lateral, the 31 -11 parent wellbore 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 wellbore perforations will no longer be open to production after drilling the laterals. Therefore, all three CTD sidetrack laterals will have different names (31 -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 1 of 1 Schwartz, Guy L (DOA) From: Ohlinger, James J [ James .J.Ohlinger @conocophillips.com] 0 c _ / Z Z 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 3.I -11L1: 209 -1210 A2 -Sand API: 50- 029 - 21932 -60 6408 6408 3I- 11L1 -02: 209 -1220 Al -Sand API: 50- 029 - 21932 -61 7400 7290 31- 11L1 -02: 209 -1230 A3 -Sand API: 50- 029 - 21932 -62 7300 7.550 I I fames Oh CTD Engineer ConocoPhillips AK, Inc. 907 - 265 -1102 office 907 - 748 -1051 cell 2/8/2010 411/ \v, 1 ( e c ( ,Y) SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 M 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 -01 ConocoPhillips Alaska, Inc. Permit No: 209 -122 Surface Location: 147' FSL, 48' FEL, Sec. 36, T13N, R8E, UM Bottomhole Location: 2558' FSL, 2353' 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 wellbore 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 ( ', Com issioner ' Aft-- DATED this /7- day of October, 2009 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. 4 I II a STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: , 1 b. Current Well Class: Exploratory ❑ Development Oil Q 1 c. Specify if well is proposed for: Drill ❑ Re -drill E Stratigraphic Test ❑ Service U Development Gas J Coalbed Methane ❑ Gas Hydrates ❑ Re -entry CI Zo - 4 t:� Single Zone E .' Shale Gas CI 2. Operator Name: lb. 5. Bond: U Blanket U Single Well 11. Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59 - 52 - 180 31 11L1 - 01 • 3. Address: 6. Proposed Depth: 12. Field /Pool(s): P.O. Box 100360 Anchorage, AK 99510 - 0360 MD: 9200' TVD: 6168' Kuparuk River Field 4a. Location of Well (Governmental 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 2558' FSL, 2353' 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: 7400 • ft. 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 92.6 . deg Downhole: 4452 psig • Surface: 3804 psig 18. Casing Program _ Size Setting Depth R "' Qntity of Cement Specifications Top Bottom '� ua Hole Casing Weight Grade Coupling Length MD TVD MD TVD incc u n s ) o cr 9 U (�3 Alaska Oil & G as C � SS 3" 2.375" 4.7# L -80 ST -L 1900' 7300' 6165' 9200' 6168' slotte Iid �RtR11S � rfCnOiage 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth ND (ft): Plugs (measured) Effective Depth MD (ft): Effective Depth ND (ft): Junk (measured) 6772' 6560' 6680' 6473' Casing Length Size Cement Volume MD TVD Conductor /Structural 116' 16" 250 sx CS II 116' 116' Surface 3348' 9 -5/8" 330 sx Class G, 3383' 3383' Intermediate 544 sx AS III, 175 sx AS I Production 6728' 7" 25o sx Class G, 175 sx AS I 6762' 6550' Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 6437'- 6454', 6457'- 6486', 6494' -6503' 6245'- 6261', 6264'- 6291', 6298' -6306' 20. Attachments: Filing Fee ❑ BOP Sketch Q Drilling Program El Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Property Plat ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program El 20 AAC 25.050 requirements U 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact James Ohlinger @ 265 '. Printed Name J. Cawvey Title Alaska Wells Manager O Signature Phone Date ta 1 v a / Commission Use Only Permit to Drill � API Number: G� / Permit Approv I See cover letter Number 1 / L+2,�/ 50- L ?- 2. ` (3Z fP I I Date: /0 i ie for other requirements Conditions of approval : If box is checked ..we may not be used to explore for, test, or produce coalbed rr'fe ane, gas hydrates, or gas contained in shales: A" 'y SO 6 / S.. BOP el lest— Samples req'd: Yes ❑ No Mud log req'd: Yes ❑ No []/ Other: H2S measures: Yes 2 No ❑ Directional svy req'd: Yes [v]( No ❑ r a l os,: /t n.. /c C ikz.- re ,rf pre,- .Le._11ui�q at-17 3 S - (P /�Y9 -a33 (J ✓ APPROVED BY THE COMMISSION DATE: /9 -1- , COMMISSIONER Form 10 -401 (Revised 1/2009) n [ ('' m in Duplicate 1 11 A 74 . • Permit to Drill Summary of Operations KRU 31 -11 L1, 31-11L1-01, & 31-11L1-02 Laterals Coiled Tubing Drilling Overview: Well 31 -11 is a 3W 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 3W straddle portion above the current completion. The 31-11L1 lateral will exit the 3W tubing and 7" casing at 6407' MD and will target the A2 sand south of the existing well with a 2743' lateral. The hole will be completed with a 2 %" slotted liner 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. 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 3W 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 3W tubing at 6411' and 6213' MD. 4. Set plug between tubing punches. Pump down tubing through tubing punches to confirm communication across the 3W x 7" annulus. 5. RU e-line. Set composite bridge plug at 6417' MD (inside seal assembly). , A . yap{ 6. RU CTU. Lay in cement plug. Objective is to anchor the 3W tubing inside the 7" casing at the � - 3 1 - I ( sidetrack point. eyaz r 7. RU slickline. Tag cement top. coi 3 � 8. Drill out cement and composite bridge plug. Prp 9. Caliper survey 3W tubing where cement was drilled out. Run dummy whipstock on slickline. 10. RU e-line. Set 3W monobore, flow -by whipstock at 6407' MD. 11. Prep site for Nabors CDR2 -AC. Rig Work 1. MIRU Nabors CDR2 -AC rig using 2" coil tubing. NU 7 -1/16" BOPE, test. 2. 31-11L1 Lateral (A2 Sand) 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. rib c. Kill well. Run 2 %" slotted liner with an aluminum liner -top billet from TD up to 7400' 3. 31- 11L1 -01 Lateral (Al Sand) 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. 31- 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 3W tubing 5. Freeze protect. ND BOPE. RDMO Nabors CRD2 -AC. Page 1 of 5 9/29/2009 L • Permit to Drill Summary of Operations Cont. KRU 3I -11 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 • 31- 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 31-13 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. 31 -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 3I -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 nrnrINAL • • Permit to Drill Summary of Operations Cont. KRU 3I -11L1, 31- 11L1 -01, and 3I- 11L1 -02 Reservoir Pressure • The most recent static BHP survey in well 3I -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. 31 -13 has been shut in since September 2008 to allow the area to de- pressurize. The most recent pressure survey in 3I -13 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 3I -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 AS 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 31 -10 is 25' to the right side of the 31 -11 surface location. The 31 -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 31 -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 3I -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 3V2" 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 9/29/2009 P RU3NAL 31 -11 Proposed CID Sidetrack 16" 62# H-40 shoe Cameo TRMAXX -5E SSSV (b 2212 MD (2.813" min ID, X- profile) 3 -112 ", 9.3# L -84 EUE 8rd -Mad Tubing to surface ; (116'MD — 1111 3 -1/2" Cameo MMG gas lift mandrels (5) t - 2512', 3707, 4760', 5668', & 6074' 9-5/8" 36# J -55 - shoe (4) 3383' MD . _ III ■ X' landing nipple (o,) 6123' MD (2.813" min ID) S Baker 3-1/2" seal assembly 6131' - 8143' MD • 1......... 80-40 PBR at 6132' - 6145' Baker KBH Anchor Seal Assy at 6145' MD 1 Baker SAB 40-32 packer @ 6146' MD � �� 'X' landing nipple @ 8156' MD (2.813' min ID) t s s ' 2 -3/8" liner top at -6390' MD �"�'-1/2" flow-by .. Holes shot in 3 -112" straddle at 6411' & 6213' MD � 'nonobore . H g " �4 vhipstock at 6407" el 4° ' N4 Baker Fl permanent packer @ 6422' MD (e -line set) "- ""'lUID t - 80-40 Sealbore extension (8426- 6430') 1!2" straddle IF 4 'D' landing nipple @ 6433' MD (2.750" min ID) L1 -02 TO @ 9100' merited in place -' (wp03, A3 sand) . I MEG @ 6438' MD — \ '- --� � , 1- A sand pens _ /', � ' -�'� _ __ "` L1 TD 9150' A3: 6437' - 6454' � ` `� - --- (wp08, A2 sand) i , A2: 6457' - 6486' ``- Al: 8494' - 6503' `...., } 2 -3/8" slotted pipe Aluminum billets @ 7400' MD L1 -01 TO @ 9200' ~ 7" 26# J-55 shoe and 7300 MD (WP03) (wp03, Al sand) „mai @ 6550' MD KUP 31-11 oPhilhps ? *W illfiliAttrlbutes. .: ..,; M ;.u" TD, ' Wellbore APIAIWI Field Name - - ' wail Status Intl (°) MD (11K Act Btm (ItikB • - �• 500292193200 KUPARUK RIVER UNIT PRO 24.02 5,300,00 6,7720 " Comment H2S (ppm) Date Annotation End Date KB-Grd (R) Rig Release Date Well 31-11. 6/11/2009 SSSV:TRDP 160 2/512008 Last WO: 6/12009 35.91 4/4/1989 • Schematic - Anklet 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 Gasify Strings 1 .: Casing Description String 0... String ID . Top (11KB) Set Depth (f.. Set Depth (TVD).. String Wt... String ... String Top Thrd CONDUCTOR 16 15.062 0.0 116.0 116.0 62.50 1-1-40 HANGER, 31 ill: Casing Description String 0... String ID _. Top (RKB) Set Depth (f... Set Depth (TVD)... String Wt... String -. String Top Thrd SURFACE 9 5 8.765 35.0 3,383.4 3,383.3 36.00 J -55 Cuing Description String 0... String ID Top (RKB) Set Depth (f Set Depth (ND) String Wt... String String Top Thrd ', PRODUCTION 7 6.151 33 0 6,761.5 6550 2 26.00 J-55 Tubing StrinSid . . . y Tubing Description String 0... String ID . Top (RKB) Set Depth (f .. Set Depth (ND) .. String Wt_. String _. String Top Thrd �. TUBING - Upper 312 2.992 31.0 6,143.0 5,974.1 9.30 L-80 EUE CONDUCTOR, Comn`Pletiitn •Details _ _ ` Y N' 0-17,6 Top Depth (ND) Top Intl Top (RKB) MB) (°) item Description Comment ID (in) ir. 31.0 31.0 0.02 HANGER FMC 6" it 3 12" Gen IV Tubing Hanger w/ pup 2.992 555V, 2,212 �A 2,212.3 2,2123 0.17 SSSV Camco 312" x 2813" 'X' Profile TRMAXX -5E SCSSV "LOCKED OPEN w /6200 psi on control line" 6,123.0 5,955.7 23.60 NIPPLE Hatiburton 31/2' it 2.813" 'X Nipple 2.813 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 (ND) ... 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 - I . Section etion Detail . _ Top Depth (TVO) Top Incl SURFACE, Top (RKB) (RKB) l °) item Description 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, 412' LTC pin x 312' EUE pin 3.010 6,157.8 5,987.6 23.50 NIPPLE Haliburton 2,813 "'X' Nipple 2.813 6,421.3 6,231.0 22.77 SEAL ASSY Baker 80-40 GBH -22 Seal Assy w/Locator 1000 Tubing Description String 0... String ID Top (RKB) Set Depth (f . Set Depth ( D) - String Wt.. String ., String Top Thrd GAS LIFT. PACKER ASSY I 5 I 4000 I 6,4221 16,438.0 I 6,24 N I I I ACME 4,760 _ _ CBmplattolt D1 a71s . Top Depth L. (NM Top Inc! Top (ItKB) (RKB) (°) Item 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 it 3.5" EUE 3.000 -' 6,433.4 6,242.1 2252 NIPPLE Camco 312" x2.75 "'D' Nipple 2.750 6,437.1 6,245.4 22.44 SOS ShearoutSubw /WLEG 3.000 ES Pe GAS LIFT. rfOratlons &' Sits _ o . = . . ; Shot 6,074 Top (ND) Btrn (ND) Dens F . Top (RKB) Btm (RKB) (ftKB) (RKB) Zone Date (oh- Type Comment 6,437 6,454 6,245.4 6,261.0 A -3, 31 -11 3/6/1990 8.0 IPERF 21/8" Dyna Strip, 60 deg ph 11 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" Dyne Strip, 60 deg ph Notes: _Geneia7 Safety:'' End Date Annotation SEAL ASSY, 6 /102009 I NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 6,131 PBR, 6,134 .. 1 .' S• . SEAL c 147 r 6,147 PACKER. 6,148 iliiiiiiIOT I ..: NIPPLE, 6,158 Miff PACKER, AS SEAL ASSY, 6,421 56E. 6.425 4' ti Mandrel Details'; . , Top Depth Top Port ( ND ) Intl OD Valve Latch Sloe TRO Run � . Stn Top (RKB) (RKB) (1 Make Model Ds) Sery Type Type Del (pcI) Run Date Corn... 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 1 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 6/52009 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, 6,437 -6,454 IPERF, 6,457 -6.486 IPERF, _II IN 6,484 -6.503 ,a�� PRODUCTION, 7 33-6,761 N e) a ! r - NAL N, 8,772 • • ConocoPhi Iii s Alaska KNIREER ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 31 Pad moms 31 -11 31-1 1L1 -01 pigigNER Plan: Plan 3, 31- 11L1 -01 Standard Planning Report 02 October, 2009 re BAKER HUGH EB OPIGINAL • • ConocoPhillips ConocoF)Iiillit Alas Ica Is Planning Report BAKER ES , Database EDM Alaska Prod v16 ` "Local Co�lnate Re erence ; Well 31 -11 atny ConocoPhillips(Alaska) Inc. "flfD, t ferren : Mean Sea Level project Kuparuk River Unit MD Reference; 31 -11 © 76.00ft (31 -11) Kuparuk 31 Pad 1°orltt R81ence True Wet1 ' -. 31 -11 4at'veyCalculationM‘'itc i Minimum Curvature Wettbofe , 31- 11L1 -01 124 Plan 3, 31- 11L1 -01 e Kuparuk River Unit, North Slope Alaska, United St 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 31 Pad Site Position: Northing: 6,007,285.49ft 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 ° Well 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: 0.00 ft elibo v P - 31-11L1-01 „ .. netics Model` N Sample „ Declin n: pDip ' 1, S eth ( BGGM2009 11/1/2009 17.31 79.84 57,357 Plan 3, 31 11 L1-01 Audit Notes: Version: Phase: PLAN Tie On Depth: 7,400.00 Vertical Section , ; Depth From {T1iD): , S - +EI -W Dire t _ . , { . ,, n, { �' ., 0.00 0.00 0.00 207.76 Plan Sections =lured in , i -; Dogleg Build Depth . tin l ti diikii h merit a tf-S +E/-VV Rata , Rate. ltd (1 {) , ; , '. , . (i) , , (#t) . (°f'l fi 10 ("!100 *4.010t 7,400.00 92.12 233.61 6,159.25 - 1,206.00 - 1,260.50 0.00 0.00 0.00 0.00 7,415.00 89.12 233.61 6,159.09 - 1,214.90 - 1,272.58 20.00 -20.00 0.00 180.00 7,435.00 85.36 232.24 6,160.05 - 1,226.94 - 1,288.51 20.00 -18.79 -6.86 200.00 7,685.00 85.98 202.16 6,179.37 - 1,423.23 - 1,437.45 12.00 0.25 -12.03 270.00 7,810.00 89.95 187.68 6,183.83 - 1,543.61 - 1,469.49 12.00 3.18 -11.58 285.00 8,060.00 92.45 217.58 6,178.47 - 1,771.69 - 1,564.54 12.00 1.00 11.96 85.00 8,435.00 92.44 172.54 6,161.57 - 2,124.20 - 1,659.39 12.00 0.00 -12.01 271.00 8,585.00 89.86 190.36 6,158.54 - 2,273.50 - 1,663.18 12.00 -1.72 11.88 98.00 8,735.00 88.94 208.34 6,160.12 - 2,414.44 - 1,712.66 12.00 -0.61 11.99 93.00 9,035.00 89.14 172.33 6,165.31 - 2,704.70 - 1,765.58 12.00 0.07 -12.00 270.00 9,200.00 89.19 192.13 6,167.73 - 2,868.74 - 1,771.97 12.00 0.03 12.00 90.00 10/2/2009 2 :57 :21 PM Page 2 COMPASS 2003.16 Build 69 ORIGINAL • • IV ConocoPhillips rams ConoccIFilillips Planning Report BAKER Database• , EOM Alaska Prod v16 � LocBai Coordinate hence Well 31 -11 : p n ConocoPhillips(Alaska) Inc. :TAD i�nce: Mean Sea; Level Pr , Kuparuk River Unit , °'MD t�ferenee ; ° 31 -11 @ 76.00ft (3I -11) Sit i e r ,,,_,,,, Kuparuk 31 Pad North RReferencrR' . True iii' 31 -11 SutMve catculte(iic�t ilMetod Minimum Curvature � fteo 3 1-111 - 1-01 DOsi Plan 3 31- 11L1 -01 Pianned,Surve Nt) Selovr ve 1 J Toolface "Depth Section AzimuSt ' North n �g inciinrn rnut� '0` �, .� � ( (ft} ( ° Il � ? (TM} O ,,,,o2,: ,: 7,400.00 • 92.12 233.61 6,159.25 - 1,206.00 - 1,260.50 1,654.30 0.00 0.00 6,005,880.95 506,571.12 KOP 7,415.00 89.12 233.61 6,159.09 - 1,214.90 - 1,272.58 1,667.80 20.00 - 180.00 6,005,872.04 506,559.06 2 7,435.00 85.36 232.24 6,160.05 - 1,226.94 - 1,288.51 1,685.88 20.00 - 160.00 6,005,859.99 506,543.14 End of 20 deg / 100 ft DLS 7,500.00 85.40 224.41 6,165.30 - 1,269.99 - 1,336.87 1,746.49 12.00 -90.00 6,005,816.90 506,494.83 7,600.00 85.63 212.38 6,173.14 - 1,347.98 - 1,398.66 1,844.29 12.00 -89.37 6,005,738.85 506,433.12 7,685.00 85.98 202.16 6,179.37 - 1,423.23 - 1,437.45 1,928.95 12.00 -88.42 6,005,663.56 506,394.42 4 7,700.00 86.45 200.41 6,180.36 - 1,437.18 - 1,442.88 1,943.82 12.00 -75.00 6,005,649.61 506,389.00 7,800.00 89.63 188.83 6,183.80 - 1,533.71 - 1,468.06 2,040.96 12.00 -74.88 6,005,553.06 506,363.93 7,810.00 89.95 187.68 6,183.83 - 1,543.61 - 1,469.49 2,050.39 12.00 -74.49 6,005,543.17 506,362.51 5 7,900.00 90.89 198.44 6,183.17 - 1,631.15 - 1,489.79 2,137.31 12.00 85.00 6,005,455.61 506,342.30 8,000.00 91.89 210.40 6,180.74 - 1,722.01 - 1,531.04 2,236.93 12.00 85.08 6,005,364.72 506,301.15 8,060.00 92.45 217.58 6,178.47 - 1,771.69 - 1,564.54 2,296.49 12.00 85.37 6,005,315.01 506,267.71 6 8,100.00 92.53 212.78 6,176.73 - 1,804.34 - 1,587.56 2,336.11 12.00 -89.00 6,005,282.33 506,244.73 8,200.00 92.64 200.77 6,172.20 - 1,893.37 - 1,632.47 2,435.81 12.00 -89.21 6,005,193.27 506,199.91 8,300.00 92.63 188.75 6,167.59 - 1,989.79 - 1,657.88 2,532.96 12.00 -89.75 6,005,096.83 506,174.61 8,400.00 92.51 176.74 6,163.09 - 2,089.39 - 1,662.66 2,623.33 12.00 -90.31 6,004,997.24 506,169.93 8,435.00 92.44 172.54 6,161.57 - 2,124.20 - 1,659.39 2,652.61 12.00 -90.85 6,004,962.44 506,173.24 8,500.0 0 91.34 180.26 6,159.43 - 2,188.98 - 1,655.32 2,708.04 12.00 98.00 6,004,897.66 506,177.38 8,585.00 89.86 190.36 6,158.54 - 2,273.50 - 1,663.18 2,786.49 12.00 98.26 6,004,813.14 506,169.61 8 8,600.00 89.77 192.16 6,158.58 - 2,288.21 - 1,666.10 2,800.87 12.00 93.00 6,004,798.43 506,166.70 8,700.00 89.15 204.14 6,159.54 - 2,383.06 - 1,697.19 2,899.28 12.00 92.99 6,004,703.56 506,135.71 8,735.00 88.94 208.34 6,160.12 - 2,414.44 - 1,712.66 2,934.26 12.00 92.88 6,004,672.16 506,120.28 9 8,800.00 88.95 200.53 6,161.32 - 2,473.57 - 1,739.52 2,999.09 12.00 -90.00 6,004,613.02 506,093.48 8,900.00 89.00 188.53 6,163.11 - 2,570.17 - 1,764.56 3,096.24 12.00 -89.86 6,004,516.39 506,068.54 9,000.00 89.10 176.53 6,164.77 - 2,669.88 - 1,768.97 3,186.53 12.00 -89.64 6,004,416.69 506,064.24 9,035.00 89.14 172.33 6,165.31 - 2,704.70 - 1,765.58 3,215.76 12.00 -89.44 6,004,381.88 506,067.67 10 89.15 180.13 6,166.28 - 2,769.50 - 1,761.31 3,271.11 12.00 90.00 6,004,317.09 506,072.01 9,200.00 89.19 192.13 6,167.73 • - 2,868.74 - 1,771.97 3,363.89 12.00 89.88 6,004,217.85 506,061.45 • TD at 9200.00 - 2 3/8" 10/2/2009 2:57:21PM Page 3 COMPASS 2003.16 Build 69 ..n, I 1 f _ ; -. 1 !\ AL .., . • • Conoco Phillips ConocoPliillips Planning Report BAKER Alastca HUGHES Database EDM Alaska Prod v16 :Local Cordtn eae Well 31-11 C npany; ConocoPhillips(Alaska) Inc. TYD,Referehc ew Mean Sea Level C roject Kuparuk River Unit MD. e r nce 31 -11 @ 76.00ft (31 -11) Stte Kuparuk 31 Pad ;:Narttk Reference' True 'Inlay; 31 -11 Survey,Calcu� ion Method ° Minimum Curvature VVeUttors 3i 11L1 - 01 04( Plan 3, 31-11L1-01 Targets Target Nam h target.: Di D b ar. T ` +N1 +El W No ire Earmuff (It) 3I-11L1-01 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 6170.10ft at 7415.00ft MD (6159.09 TVD, - 1214.90 N, - 1272.58 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- 11L1 -01 t1.3 0.00 0.00 6,159.00 - 1,198.41 - 1,261.39 6,005,888.55 506,570.22 70° 25' 38.334 N 149° 56' 47.243 W - plan misses target center by 7.65ft at 7400.00ft MD (6159.25 TVD, - 1206.00 N, - 1260.50 E) - Point 31-11L1-01 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 6167.61ft at 8585.00ft MD (6158.54 TVD, - 2273.50 N, - 1663.18 E) - Polygon Point 1 0.00 - 2,354.42 - 1,338.63 6,004,732.57 506,494.20 Point 2 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 3I-11L1-01 t3.3 0.00 0.00 6,155.00 - 2,266.03 - 1,703.57 6,004,820.57 506,129.21 70° 25' 27.833 N 149° 57' 0.208 W - plan misses target center by 41.37ft at 8581.33ft MD (6158.53 TVD, - 2269.89 N, - 1662.53 E) - Point 31- 11L1 -01 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 6213.14ft at 7400.00ft MD (6159.25 TVD, - 1206.00 N, - 1260.50 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 31- 11L1 -01 Polygon 0.00 0.00 0.00 - 1,084.50 - 1,164.26 6,006,002.55 506,667.22 70° 25' 39.454 N 149° 56' 44.395 W - plan misses target center by 6161.20ft at 7400.00ft MD (6159.25 TVD, - 1206.00 N, - 1260.50 E) - Polygon Point 1 0.00 - 1,084.50 - 1,164.26 6,006,002.55 506,667.22 Point 2 0.00 - 1,808.36 - 1,375.00 6,005,278.54 506,457.27 Point 3 0.00 - 3,247.15 - 1,731.48 6,003,839.52 506,102.33 Point 4 0.00 - 3,002.67 - 2,192.28 6,004,083.49 505,641.32 Point5 0.00 - 1,112.12 - 1,543.33 6,005,974.53 506,288.22 Point 6 0.00 - 1,084.50 - 1,164.26 6,006,002.55 506,667.22 31- 11L1 -01 t4.3 0.00 0.00 6,163.00 - 2,804.94 - 1,829.16 6,004,281.58 506,004.20 70° 25' 22.532 N 149° 57 3.887 W - plan misses target center by 76.62ft at 9100.00ft MD (6166.28 TVD, - 2769.50 N, - 1761.31 E) - Point 3I-11L1-01 t2.3 0.00 0.00 6,182.00 - 1,519.20 - 1,479.75 6,005,567.56 506,352.22 70° 25' 35.178 N 149° 56' 53.647 W - plan misses target center by 14.08ft at 7788.84ft MD (6183.69 TVD, - 1522.70 N, - 1466.22 E) - Point Casing Paints Measured V ert l �rt� Hod .: ; b D 11tYiett Nam• ° ;�" M; e 9,200.00 6,167.73 2 3/8" 2 -3/8 3 10/2/2009 2:57:21 PM Page 4 COMPASS 2003.16 Build 69 ORIGINAL S • Ns , , ConocoPhillips CO114COP II Planning Report BAKER HUGHES l alabasa EDM Alaska Prod v16 Local Co ortlinateRe#erO cet ;; Well 31 -11' P Y . ConocoPhillips(Alaska) Inc. o fence: > Mean Sea Level troj hr Kuparuk River Unit ; MD ft ra oe 31 -11 Q 76.00ft (31 -11) Kuparuk 31 Pad North R+Eeforence. ; True 31-11 -,Aurvey CaIcu onMetttod' Minimum Curvature 31-11L1-01 Plan 3, 31- 1131 -01 , Plan 3, 31- I >tannnattadtlr►s Ili asuiied Vertical < Local:C+berdina , i# }, ,, , , tit) Comment 7,400.00 6,159.25 - 1,206.00 -1,260.50 KOP 7,415.00 6,159.09 - 1,214.90 - 1,272.58 2 7,435.00 6,160.05 - 1226.94 - 1,288.51 End of 20 deg / 100 ft DLS 7,685.00 6,179.37 - 1,423.23 - 1,437.45 4 7,810.00 6,183.83 - 1,543.61 - 1,469.49 5 8,060.00 6,178.47 - 1,771.69 - 1,564.54 6 8,435.00 6,161.57 - 2,124.20 - 1,659.39 7 8,585.00 6,158.54 - 2,273.50 - 1,663.18 8 8,735.00 6,160.12 - 2,414.44 - 1,712.66 9 9,035.00 6,165.31 - 2,704.70 - 1,765.58 10 9,200.00 6,167.73 - 2,868.74 - 1,771.97 TD at 9200.00 10/2/2009 2:57:21 PM Page 5 COMPASS 2003.16 Build 69 RI G I ,t-/‘ Azimuths to Tn. Note, WELLBORE DETAILS: 31 -11 L1 -01 REFERENCEINFORMAT1ON �'- Project: Kuparuk River Unit NJ/wool/or-17.r �� Site: Kuparuk3lPad MayK+Feld 500292193261 Coadinde(6E )Reference: Well 31-11, True North Well: 31 -11 srengm:57 6.TenT Vertical(ND)Reference: Mean Sea Level BAKER Wellbore: 3I-11L1-01 00++reb:�a.e+° Reference Sbt IO.008, 0.00E) ConocoPhillips Plan: Plan 3, 31- 11L1 -01 31- 11131- 11L1 -01 c .,. :1 „ 1/20 ,, Parent Wellbore: 31 -11 L1 M�auedDephRefrene 31- 11676.008Cd -10 ( ) IAoCel:e[;C3.130fL Tie on MD: 7400.00 Section (VS) Method Muimum Curvatue HUGH ES -600 , WELL DETAILS: 31-11 -800 Ground Level: 0.00 31 11/31-11 411-S +E/ -W Northing Easting Latittude Longitude Slat -1000 0.00 0.00 6007088.16 507830.23 70 ° 25'50.121 N 149° 56'10.241 W KOP �-�, -1211 SECTION DETAILS ANNOTATIONS Endof20 deg - 100 ft Sec MD Inc Azi ssTVD +N /-S +EI -W DLeg TFace VSec Target Amofaoon - 1400 1 7400.00 92.12 233.61 6159.25 - 1206.00 - 1260.50 0.00 0.00 1654.30 KOP • 2 7415.00 89.12 233.61 6159.09 - 1214.90 -1272.58 20.00 180.00 1667.80 2 - 1600 3 7435.00 85.36 23224 6160.05 - 1226.94 - 1288.51 20.00 200.00 1685.88 Endof20deg /100ftDLS 4 7685.00 85.98 20216 6179.37 - 1423.23 - 1437.45 12.00 270.00 1928.95 4 5 7810.00 89.95 187.68 6183.83 - 1543.61 - 1469.49 12.00 285.00 2050.39 5 -1800 6 8060.00 92.45 217.58 6178.47 - 1771.69 - 1564.54 12.00 85.00 2296.49 6 7 8435.00 92.44 172.54 6161.57 - 2124.20 - 1659.39 12.00 271.00 2652.61 7 0 - 2000 • 8 8585.00 89.86 190.36 6158.54 - 2273.50 - 1663.18 12.00 98.00 2786.49 8 9 8735.00 88.94 208.34 6160.12 - 2414.44 -1712.66 12.00 93.00 2934.26 9 } _2200 10 9035.00 89.14 172.33 6165.31 - 2704.70 - 1765.58 12.00 270.00 3215.76 10 11 9200.00 89.19 192.13 6167.73 -2868.74 - 1771.97 12.00 90.00 3363.89 TDat9200.00 rd 0 -2400 . 2600' 31 -1,!31 -1111 10 31-11/!1- ILI -01 C/3 -2800 f TD at 920(1.00 -3000 �.�� -3200 an.. -3400-- -3400 - 2 -3,11 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 - 5670 \ West(- )/East( +) (200 ft/in) 5760 5850 - 5940 0 o 6030 31- 1/31 -IILI ON a 6120 f _- -. _. 0 i r �- 11-11/36-11L14 1 r fir �� - __. Q 6213 ■ r ' 71 rn KOP 0 4 5 'D at 9200.00 U EE 2 6300 t 6390 . of20 le¢/ 1C08 DL N E-■ 6480 6570 6660 360 450 540 630 720 810 900 990 1080 1170 1260 1350 1440 1530 1620 1710 1800 1890 1980 2070 2160 2250 2340 2430 2520 2610 2700 2790 2880 2970 3060 3150 3240 3330 3420 3510 3600 3690 3780 Vertical Section at 207.76° (90 ft/in) I AarmacteTn. Na* WELLBORE DETAILS: 31 -11 L1 -01 REFERENCE INFORMATION a� Project Kuparuk River Unit Wane. nam'. 17.30° Site: Kuparuk 31 Pad Magnetic fern 500292193261 Coordnate(WE) Reference: Well 31 -11, True North Fa/ill Well: 31 - Stennis 0735e]4eT Vertical (TVD) Reference: 31 -11 @ 76.000 (31.11) BAKER ConoeoPhilli S Wellbore: 31-11L1-01 ovAngle naa4° Se bn VS)Refxe Reference SkA - (O OON, O.00E) Plan: Plan 3, 31 -11 L1 -01 31- 11131- 11L1 -01 Date : 11/1/200S Parent Wellbore. 31 - L1 Measured Depth Reference: 3I -11 @ 76.008 (31 -11) ( ) 6tee[BGCfRaoS Tie on MD: 7400.00 Calculation Method Minimum Curvature HUGHES Alaska -935 - - - - / - - - / /] ■ - I 020 .< / i t - l Al - -1105 �� -II P -1275 -1360 f • -1445 31- 13N1 -13 . 1530 o ps -1615 - v c r o -1700 O -1785 C -1870 / i r rn -1955 M / WNW/NM. + -2040 �/ 1:: \...\_� '\ � - 2295 31- 1713 O ' 0;, -2380 / / -2465 /! • -2550 / -2635 /' � . - -2720 .r 11,1 111-1-- -2805 ' 4 i , -2890 ! � 9 -� /. -2975 . -3060 / . -3145 31 -11 @76. -11) '1-16/331.16 -3230 -3145 -3060 -2975 -2890 -2805 -2720 -2635 -2550 -2465 -2380 -2295 -2210 -2125 -2040 -1955 -1870 -1785 -1700 -1615 -1530 -1445 -1360 -1275 -1190 -1105 -1020 -935 -850 -765 -6680 -595 -510 -425 -340 -255 -170 -85 West( -) /East( +) (85 ft/in) 1 I TRANSMITTAL LETTER CHECKLIST (l WELL NAME E U. NO I" I f l l PTD# - [ / O Development Service Exploratory Stratigraphic Test Non - Conventional Well FIELD: L _ L ' / POOL: KLLL c__'1 , f 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 J/ .-L / / (If last two digits in Permit No. API No. 50-6Z ?- 2�,/` ? - - . API number are �� between 60 -69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(0, all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well . SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non - Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: 1/11/2008 Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK RIV UNIT 31- 11L1 -01 Program DEV Well bore seg V PTD #: 2091220 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 On /Off Shore On _ Annular Disposal 7; Administration 1 Permit fee attached NA 2 Lease number appropriate Yes Top prod interval and TD in ADL 25631 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 unit boundaries and no interwell 1 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 10# 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 AS31.05.030Q.1.A),(j,2.A -D) NA 18 Conductor string provided NA Conductor set in 31 -11 Engineering 19 Surface casing protects all known 1JSDWs NA Surface casing set In31 -11 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing cemented in 31 -11 21 CMT vol adequate to tie -in long string to surf csg NA Production casing set in 31 -11 22 CMT will cover all 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 Mainbore production.. S/T is just above A sand. 26 Adequate wellbore separation proposed Yes Closest wellbore is 31 -13. 1500 ft away. 27 Ifdiverter 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 EMW) Will use MPD (managed pressure drilling) and 10 ppg mud 29 BOPEs, meetregulation Yes GLS 10/13/2009 - y- 9 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP= 3804 psi. Will test BOP 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 No 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- shore) NA 39 Contact name /phone for weekly progress reports [exploratory only] NA Geologic Engineering Public Overpressure expected - up to 13.7 ppg EMW. Wellbore will be drilled using 10.0 ppg mud managed and pressure drilling Date: Date Date Commissioner: Commission : C , 4' - / DD i / /0 -w? "Dy