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Home My WebLink About210-110 • • 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. caqL0 - 1 L Q Well History File Identifier Organizing (done) ❑ Two -sided 11111111111111 ill ❑ Rescan Needed 1111111111 1111111 R E AN DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ Maps: ❑ Greyscale Items: ❑ Other, No/Type: ❑ Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: BY: ig Date: 1 �, a, /s/ u • Project Proofing IH Hilililull 11111 BY: Maria Date: 1 /s/ P Scanning Preparation x 30 = + = TOTAL PAGES l 9 BY: (Count does not include cover sheet) O Date: • g / Production Scanning 111111111111111111 Stage 1 Page Count from Scanned File: a. 0 (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ✓ YES NO BY: ( Maria ) Date: 10.,/a7/// /s/ v vi F Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: Is/ Scanning is complete at this point unless rescanning is required. 111 11111111111 11111 ReScanned 1 11111 BY: Maria Date: /s/ Comments about this file: Quality Checked IllhIIIIIIIlIIIllII 12/22/2011 Well History File Cover Page.doc DATA SUBMITTAL COMPLIANCE REPORT 11/1/2011 Permit to Drill 2101100 Well Name /No. KUPARUK RIV UNIT 3N- 16AL1 -03XX Operator CONOCOPHILLIPS ALASKA INC API No. 50- 029 - 21593 -63-00 MD TVD Completion Date Completion Status Current atus CANC 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 / 9 9 9 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: exo.c.e (I a lee 04- Compliance Reviewed By: t443 Date: 1 Ide d i ) I. • • • J. L. Cawvey Alaska Wells Manager Drilling & Wells P. 0. Box 100360 Anchorage, AK 99510 -0360 ConocoPh i I I i ps Phone: 907 - 265 -6306 September 30, 2010 RECEIVED Commissioner D. Seamount f1('T u 0 2010 State of Alaska Alaska Oil & Gas Conservation Commission ��) "�os.0>r:siorz 333 West 7 Avenue Suite 100 Apch Ta Anchorage, Alaska 99501 Subject: Cancellation of Permits to Drill #210 -109 (3N- 16AL1 -02) and #210 -110 (3N- 16AL1 -03) Dear Commissioner: ConocoPhillips Alaska, Inc. requests the cancellation of two Permits to Drill #210- ✓ 109 for well 3N- 16AL1 -02 and #210 -110 for well 3N- 16AL1 -03. We will not be drilling these wells. If you have any questions regarding this matter, please contact J. Gary Eller at 263- 4172. Sincerely, Z . L. Cawvey RBDMS OCT 08 Alaska Wells Manager CPAI Wells JLC /JGE /skad • • SI:Y[1'E al PALASIn, SEAN PARNELL, GOVERNOR ALASKA. OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 V. Cawvey Alaska Wells Manager ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 -0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, 3N- 16AL1 -03 ConocoPhillips Alaska, Inc. Permit No: 210 -110 Surface Location: 1561' FSL, 30' FEL, SEC. 29, T13N, R9E, UM Bottomhole Location: 1142' FNL, 946' FEL, SEC. 33, T13N, R9E, UM Dear Mr. Cawvey: Enclosed is the approved application for permit to redrill the above referenced service well. The permit is for a new wellbore segment of existing well KRU 3N -16A, Permit No 210- 049, API 50- 209 - 21593 -01. 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. Sincerely, Daniel T. Seamount, Jr. Chair DATED this • day of August, 2010. cc: Department of Fish & Game, Habitat Section w/o encl. (via e -mail) Department of Environmental Conservation w/o encl. (via e -mail) • , *- ,,,.,".4"..., v 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION \ 1.I1. PERMIT TO DRILL Ainka Ut 61 On Cent C 'i issinli 20 AAC 25.005 Att;)Cim; §r;ifi0 la. Type of Work: • lb. Proposed Well Class: Development - Oil ❑ Service - Winj is • Single Zone 0 • lc. Specify if well is proposed for: Drill ❑ Re -drill IO Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Re -entry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: U Blanket U Single Well 11. Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59 - 52 - 180 • 3N 16AL1 - 03 • 3. Address: 6. Proposed Depth: 12. Field /Pool(s): P.O. Box 100360 Anchorage, AK 99510 - 0360 MD: 9388' • TVD: 6439' • Kuparuk River Field 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 1561' FSL, 30' FEL, Sec. 29, T13N, R9E, UM ' ADL 25521, 25520 • Kuparuk River Oil Pool • Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 650' FNL, 1699' FEL, Sec. 33, T13N, R9E, UM 2556, 2557 9/3/2010 Total Depth: 9. Acres in Property: 14. Distance to 1142' FNL, 946' FEL, Sec. 33, T13N, R9E, UM 2560 Nearest Property: 8800 • 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: • 60 feet 15. Distance to Nearest Well Open Surface: x - 518371 ' y - 6013799 ' Zone 4 GL Elevation above MSL: • 34 feet to Same Pool: 3N -19 , 1600' 16. Deviated wells: Kickoff depth: 8440 • ft. 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 99.9° deg Downhole: 3283 psig . Surface: 2663 psig . 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7# L - 80 ST - L 1223' 8165' 6400' 9388' 6439' slotted / solid liner 19 I 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) 8190 6478 4900' 8157 6453 Casing Length Size Cement Volume MD TVD Conductor /Structural 78' 16" 249 sx CS II 115' 115' Surface 4760' 9.625" 1350 sx AS III, 350 sx Class G 4797' 3638' Intermediate Production 4963' 7" 300 sx Class G, 175 sx AS I 5000' 3752' Liner 3524' 3.5" 600 sx Class G 8190' 6478' Perforation Depth MD (ft): Perforation Depth TVD (ft): none none 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Program 0 Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program is 20 AAC 25.050 requirements IN 21. Verbal Approval: Commission Representative: Date: �• 22. I hereby certify that the foregoing is true and correct. Contact Gary Eller @ 263 - 4172 Printed Name V. Cawvey Title Alaska Wells Manager Signature ► �/� Phon 265-6306 Date g1/01,0 � 4till a∎ 1Q, full ■TVelitNeti Commission Use Only Permit to Drill API Number: t' Permit Approval See cover letter / [I '`r�t Number: 21 C) l / c 50- 1--�1 - 21'J -/ - -�� tii)Date: for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed t thane, gas hydrates, or gas contained in shales: Z .4( -3 10 i. 130e A j Sf 4- S amples req'd: Yes El No L r J� Mud log req'd: Yes ❑ No [/ Other: 1 ' - ZS0C1 ps 1 4,,,, �a- je5 p "' 2S measures: Yes [1 No ❑ Directional svy req'd: Yes [/7 No ❑ f-}GQ t( Lyt;N ; S+ ,r1Ci..4 - -- AP,Oro rid G& -re.!/' L _ret 6L, cG r', n ,, r . l .e e mCe s. /J - rt vn.._ tvt-t �A t%i `tc di 1 ..,../ / 4'6 z z -( ! ~tI ! (eq `mi p � APPROVED BY TIRE COMMISSION r/ t7 / D ATE:..- �� I ii• OMMISSIONER Form 10-401 (Revised 7/2009) This permit is val i f r i, fio 494(1 1e1f I (20 AAC 25.005(g)) Submi� �n plicate - /3 -/v x.13 !� • • KRU 3N- 16AL1, AL1 -01, AL1 -02, AL1 -03 — Coiled Tubing Drilling Summary of Operations: Well 3N -16A is a recent rotary sidetrack equipped with 3 tubing and 3 production liner. Well 3N -16A has not been perforated — it was drilled to the top of the A -sand and cased/cemented in anticipation of future CTD operations. Four proposed A -sand CTD laterals will access an area that is without injection support for improved sweep efficiency and reserve recovery. Prior to drilling the 3N -16A CTD sidetracks, service coiled tubing will drill out the shoe track of the 31/2" production liner. Well 3N -16A has already passed an MIT -IA and MIT -T, and has had a cement bond log run confirming excellent cement. Please note that the packer placement in well 3N -16A is not as prescribed in 20 - AAC 25.412(b): it is substantially more than 200' away from the planned kick -off point for the CTD laterals. Administrative approval is requested to allow water injection into the 3N -16A laterals given the existing packer placement. The 3N -16AL1 lateral will exit the 3%2" liner via a mechanical whipstock at 8170' MD. The lateral will target the A2 sand northeast of the existing well with a 1423' lateral. The hole will be completed with a 2 slotted liner to the TD of 9593' MD with a liner top aluminum billet at 8785' MD. The 3N- 16AL1 -01 lateral will kick off from the aluminum billet at 8785' MD and will target the A3 sand northeast of the existing well with a 940' lateral. The hole will be completed with a 2%" slotted liner to the TD of 9725' MD with a liner top aluminum billet at 8240' MD. The 3N- 16AL1- 02 lateral will kick off from the aluminum billet at 8240' MD will target the A2 sand southeast of the existing well with a 1099' lateral. The hole will be completed with a 2%" slotted liner to the TD of 9339' MD with a liner top aluminum billet at 8440' MD. The 3N -16AL 1 -03 lateral will kick off from the aluminum billet at 8440' MD and will target the A3 sand southeast of the existing well with a 948' lateral. The hole will be completed with a 2%" slotted liner to the TD of 9388' MD with the final liner top located just inside the 31/2" liner at 8165' MD. CTD Drill and Complete 3N -16A Laterals: August 2010 Pre -Rig Work 1. Positive pressure and drawdown tests on master valve & swab valve 2. MIT -IA, MIT -T, MIT -OA.. 3. MIRU coiled tubing. Drill out the 3'/2" liner shoe from 8157' to 8190' using a 2.80" mill 4. PU under - reamer dressed for 31/4", ", 9.3 ppf tubing. Under -ream cement sheath in liner shoe. 5. Prep site for Nabors CDR2 -AC, including setting BPV Rig Work 1. MIRU Nabors CDR2 -AC rig using 2" coil tubing. NU 7 -1/16" BOPE, test. 2. 3N -16AL1 Lateral (A2 sand, northeast) a. Set a mechanical whipstock in the 3%2" liner at 8170' b. Mill a 2.80" window in the 31/2" liner at 8170' c. Drill 2.70" x 3" bi- center lateral to TD of 9593' MD d. Run 2%" slotted liner with an aluminum liner -top billet from TD up to 8785' 3. 3N- 16AL1 -01 Lateral (A3 sand, northeast) a. Kick off of the aluminum billet at 8785' MD b. Drill 2.70" x 3" bi- center lateral to TD of 9725' MD c. Run 2%" slotted liner with an aluminum liner -top billet from TD up to 8240' Page 2 of 6 ORIGINAL August 10, 2010, FINAL • KRU 3N- 16AL1, AL1 -01, AL1 -02, AL1 -03 — Coiled Tubing Drilling 4. 3N- 16AL1 -02 Lateral (A2 sand, southeast) a. Kick off of the aluminum billet at 8240' MD b. Drill 2.70" x 3" bi- center lateral to TD of 9339' MD c. Run 2%" slotted liner with an aluminum liner -top billet from TD up to 8440' 5. 3N- 16AL1 -03 Lateral (A3 sand, southeast) a. Kick off of the aluminum billet at 8440' MD b. Drill 2.70" x 3" bi- center lateral to TD of 9388' MD ° c. Run 2%" slotted liner from TD up to 8165' MD, up inside the 31/2" liner 6. Freeze protect. ND BOPE. RDMO Nabors CRD2 -AC. (W Post -Rig Work 1. Pull BPV 2. Obtain static BHP 3. Run GLVs 4. Flow back well for clean up prior to putting on injection 5. Conduct MIT -IA 6. Put well on injection Mud Program: • Will use chloride -based Biozan brine or used drilling mud (8.6 ppg) for milling operations, and chloride - based Flo -Pro mud (8.6 ppg) for drilling operations. The SCSSV installed in 3N -16A should allow us to deploy 2%" slotted liner without having to kill the well. 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: • 3N- 16AL1: 2% ", 4.7 #, L -80, ST -L slotted /solid liner from 8785' MD to 9593' MD • 3N- 16AL1 -01: 2% ", 4.7 #, L -80, ST -L slotted /solid liner from 8240' MD to 9725' MD • 3N- 16AL1 -02: 2% ", 4.7 #, L -80, ST -L slotted /solid liner from 8440' MD to 9339' MD • 3N- 16AL1 -03: 2% ", 4.7 #, L -80, ST -L slotted /solid liner from 8165' MD to 9388' 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 Liner" 3 ", L -80, 9.3 ppf Burst 10,160 psi Collapse 10,530 psi Logging • MWD directional, resistivity, and gamma ray will be run over the entire open hole section. Reservoir Pressure • There have not been any pressure surveys taken in 3N -16A since it has never been perforated. Recent pressure surveys in the target fault block indicate very low bottom hole pressure. A survey in 3N -19 measured A -sand reservoir pressure of 1252 psi at 6346' SSTVD, corresponding to 3.8 ppg EMW. The last pressure survey in 3N -15 measured pressure of 1001 psi at 6400' SSTVD, corresponding to 3.0 ppg. We generally expect to encounter similar pressure as the laterals are drilled away from the mother well. Page 3 of 6 Ord GINAL August 10, 2010, FINAL • KRU 3N- 16AL1, AL1 -01, AL1 -02, AL1 -03 — Coiled Tubing Drilling Well Control: • Two well bore volumes ( -170 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 3500 psi. Maximum potential surface pressure in 3N -16A is 2663 psi assuming a gas gradient to surface and maximum potential formation pressure. Maximum potential formation pressure is based on the original pressure measured in well 3N -19, which is 3283 psi at 6200 SSTVD (i.e. 10.2 ppg) in February 2002. • The annular preventer will be tested to 250 psi and 2500 psi. Directional: • See attached directional plans: 1. 3N- 16AL1, plan #4 2. 3N- 16AL1 -01, plan #5 3. 3N- 16AL1 -02, plan #6 4. 3N- 16AL1 -03, plan #5 • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. • 3N -16A northeastern CTD laterals (AL1 & AL1-01): —8130' to property line, —1350' to well 3N -15 • 3N -16A southeastern CTD laterals (AL1 -02 & AL1-03): —8800' to property line, 1600' from well 3N -19 Hazards • Lost circulation is a major concern in 3N -16A because of the very low reservoir pressure in the A -sand. Losses will be tolerated as best as is possible, but if it becomes impossible to drill ahead then we'll complete the well with slotted liner across whatever hole has been drilled. We could then return to drill the remaining laterals after the well has been on injection for a significant period of time. • Shale stability is a potential problem, particularly in the build section where the A5 shale will be encountered. Will mitigate potential sloughing problems by cutting this interval at less than 70° hole angle. • There has been no injection into the target fault block nor has the 3N drilisite ever been equipped to inject MI gas. Therefore, it is unlikely that an influx could yield significant quantities of gas. • Well 3N -16A has no measured H since it has not been perforated or produced since being sidetracked in July 2010. Prior to being sidetracked well 3N -16 had 140 ppm measured H as of 12/15/08. Well 3N -15 is located 25' to the right side and 3N -17 is 25' to the left side of the 3N -16A surface location. Well 3N -15 has 150 ppm H and 3N -17 has 120 ppm H both being measured in Nov -09. The maximum H level on the pad is 220 ppm from well 3N -01 (12/11/09). All H monitoring equipment will be operational. Page 4 of 6 R G1 ° August 10, 2010, FINAL • • KRU 3N- 16AL1, AL1 -01, AL1 -02, AL1 -03 — Coiled Tubing Drilling Managed Pressure Drilling Managed pressure drilling (MPD) techniques will be employed to provide constant bottom hole pressure by using 8.6 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also 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 isolation during deployment and not as a stripper. The SCSSV in well 3N -16A will enable us to deploy slotted liner without having to kill the well. Operating parameters and fluid densities will be adjusted based on real -time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected at TD: • Expected reservoir pressure is 1200 psi at 8170' MD (6403' SSTVD), or 3.6 ppg EMW. • Expected annular friction losses while circulating: 819 psi (assuming annular friction of 100 psi/1000 ft due to the 3 tubing) • Planned mud density of 8.6 ppg equates to 2870 psi hydrostatic bottom hole pressure at 6403' SSTVD • While circulating 8.6 ppg mud, bottom hole circulating pressure is estimated to be 3689 psi or 11.1 ppg EMW without holding any additional surface pressure. This is sufficient to overbalance expected formation pressure in 3N -16A. If increased formation pressure is encountered, mud weight or choke pressure will be increased to maintain overbalance. Additional choke pressure or increased mud weight may also be employed for improved borehole stability, but not necessarily for well control. • When circulation is stopped, —820 psi of surface pressure would have to be applied to maintain the same borehole pressure as during drilling operations. Quarter -Mile Injection Review The following wells lie within one - quarter mile of the proposed 3N -16A CTD laterals. • 3N -16 (plugged & sidetracked) — Plugged A -sand and C -sand perfs in April/May 2010 in anticipation of a rotary sidetrack. Placed a total of 30 bbl of class `G' cement and achieved 1500 psi squeeze pressure. • 3N -16A (suspended injector and motherbore of the CTD laterals). This well was recently TD'd and cased down to 8190' MD, 6478' TVD which is in the B -sand above the target horizon of these CTD laterals. The cement bond log of 7/22/2010 shows generally excellent cement across the 3%2" liner up to 5564' MD. A liner -top packer at 4666' MD ties the 3%2" liner into the 7" casing. The well has already passed a MIT -IA (7/11/10) and State - witnessed MIT -T (8/7/10). The passing MIT -T confirms liner integrity between the top of cement at 5564' and the liner -top packer at 4666'. Please note that ConocoPhillips requests administrative approval to allow waterflood injection into 3N -16A even though the packer is more than 200' away from the kick -off point as per 20 AAC 25.412(b). • 3N-16A-PB1 — Drilled from 4950' to 8260' MD (6478' TVD). It was TD'd in the B -sand above the target injection horizon of these CTD laterals. The borehole was abandoned due to shales falling apart. Ultimately stuck 51/2" liner in this borehole from 5328' — 7528'. A cement retainer was set inside the 51/2" liner at 5360' MD. It is highly likely that sloughing shales will have packed off against the 5%2" liner, preventing fluid migration uphole to other hydrocarbon bearing intervals. Page 5 of 6 l € (° t, I It, August 10, 2010, FINAL t\ • • KRU 3N- 16AL1, AL1 -01, AL1 -02, AL1 -03 -- Coiled Tubing Drilling • 3N- 16A -PB2 — Accidentally sidetracked from the 3N- 16A -PB 1 wellbore at 7740' MD and drilled to 7833' MD (6249' TVD) before confirming accidental departure. It was TD'd in the D -shale above the target injection horizon of these CTD laterals. The 51/2" liner that got stuck in the 3N-15A-PB1 borehole straddled the sidetrack point of this plugback, so likewise it should provide isolation to uphole intervals. Also, since this plugback was TD'd 214' vertically above the proposed kickoff depth of the 3N -16A CTD laterals there should be no opportunity for direct communication with the CTD laterals. • 3N- 16A -PB3 — Sidetracked from the 3N- 16A -PB1 borehole from 5195' to 8180' MD (6472' TVD). It was TD'd in the B -sand above the target injection horizon of these CTD laterals. Abandoned due to shales falling apart. Placed a 36 bbl cement plug from 6600' — 7600' MD. Also set a cement retainer inside the 7" casing at 4900' MD, and squeeze 51 bbl of cement through this retainer. • 3N -14A — Sidetracked from the 3N -14 wellbore in October/November 2007 and drilled to 8220' MD (6647' TVD). This well is a producing single completion in the Kuparuk A -sand. The Kuparuk sands are isolated by cemented 3 liner. • 3N-14A-PB1 — Hole was drilled to 7768' MD, 6232' TVD in October 2007. The 5%2 liner became stuck at 4310' to 7274'. A stinger was used to spot a 21.4 bbl cement plug on top of the stuck liner in order to isolate the plugback and kickoff the 3N -14A borehole. Since this plugback was TD'd 231' vertically above the proposed kickoff depth of the 3N -16A CTD laterals there should be no opportunity for direct communication with the CTD laterals. • 3N -15 — This well is a producing single completion in the Kuparuk A -sand. It is isolated by cemented 7" casing across the Kuparuk sands. Page 6 of 6 August 10, 2010, FINAL n R r m KUP • 3N -16A Conoco M 1 � Well Attributes Max Angle & MD 1 TD ' ellbore API /UWI Field None (Well Status 'nci(`) IMD (ftKB) Act Btm (ftKB) 500292159301 � W. KUPARUK RIVER UNIT PROD 56.10 4,69229 8190.0 Comment H2S (pp m) D to Annotation End Date KB - Grd (ft) Rig Release Date "' SSSV: 1 RDP i 140 1 12/15/2008 Last WO: 7/3/2010 I 39.49 5/20/1986 Sc�na AatueE Annotation Depth (ftKB) End Date Annotation Lest Mod ... End Date Last Tag: SL/1 8,143.0 7/13/2010 Rev Reason: WORKOVER, SIDETRACK Imosbor ,_ 7/14/2010 Casinq Strings HANGER, 23 - -- ' v '''13.1, P Casing Description String 0... String ID.. Top (ftKB) Set Depth (f... Set Depth (ND) String Wt... Siring ... String Top Thrd a - . CONDUCTOR 16 15062 37 0 115.0 115 0 62.50 H WELDED gym,` �_ _ _ — _ _ — _ — 1 Casing Description String 0... Str ID . T op (ftKB) S D (f... S D (ND) Str g Wt... String ... String Top Thrd SURFACE 9 5/8 8.765 37.0 4,797.5 3635.1 36.00 J -55 BTC Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd WINDOW 8 6.500 4,872.0 4,882.0 3,681.4 .__ I : Casing Description String 0... String ID ... Top (ftKB) Set Depth (f.. Set Depth (TVD) ... String Wt... String ... String Top Thrd PRODUCTION post 7 6.151 36.8 5,000.0 3,751.5 26.00 J -55 BTC (Sidetrack Casing Description String 0... String ID _Top (ftKB) Set Depth (f... Set Depth (ND) String Wt... String ... String Top Thrd LINER 3 12 ; 2 -992 4,665.8 8,190 0 1 930 L-80 IBT -Mod ft Liner Details 'Top Depth (TVD) Top Intl CONDUCTOR,! Top (00(B) 0 ") (`) Item Description Comment ID (in) 37 - 115 4,665.8 3,561.5 56.06 PACKER BAKER C -2 ZXP LINER TOP PACKER 5.250 r 4,686.1 3,572.8 56.09 HANGER BAKER FLEXLOCK LINER HANGER 4.400 a t 4,695.9 3,577.9 55.77 PBR SBE 2.950 4,716.2 3,589.4 55.80 XO BUSHING CROSSOVER BUSHING 2.992 SAFETY VLV,_ 2,103 4,725.0 3,594.3 55.81 NIPPLE HES'X' NIPPLE 2.813 8 156.8 6,453.6 453. 4 97 COLLAR BAKER LANDING COLLAR 2.950 8 159 2 6 455 4 42 97 COLLAR 2.992 ' Tubing Descri ption String 0 String S rig ID.. Top -�- String - -.__. - Tubing Strin s op (ftKB) Set Depth (f Set Depth (ND) Wt... String ... (String Top Thrd el TUBING 31/2 ___ - 2992 I 23 -3 1 4,717.4 I 3,590 1 _._ . 9 30_ t L-80 1 EUE8r4ABMOD_ GAS LIFT, _ Completion Details 3,034 Top Depth (TVD) Top Incl 1 Top (MB) OMB) (`) Item Description Comment ID (in) _ 23.3 23.3 -0.01 HANGER FMC 3 -1/2" Gen IV Tubing Hanger 3.500 ` 2,102.6 1,991.7 39.01 SAFETY VLV CAMCO TRMAXX -CMT SCSSV w/ 2.813" X profile 2.812 4,679.9 3,569.4 56.08 LOCATOR Locator NO_GO 2.992 4,695.8 3,577.9 55.77 SEAL ASSY Baker 80-40 Bonded Seal Assembly 2.890 GAS LIFT 4,594 Notes: General & Safety -- -' — End Date Annotation 7/3/2010 NOTE: WELL SIDETRACKED & NEW TUBING COMPETION SET, PRE -CTD MULTI -LAT DRILL 7/14/2010 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 7/14/2010 NOTE: ****TUBING COMPLETION DEPTHS NOT CONFIRMED ** I , 1 LOCATOR, �s 4.680 I 1 1 SEAL ASSY. L- 4.696 - - - _ !ei 1 i I F r i SURFACE, , 37 -4,797 WINDOW 'A', __. 4,872 -4,682 -. -.... _. _. _. 'Mandrel Details_ -___ Top Depth Top Port PRODUCTION (TVD) Incl 01) Valve Latch Size TRO Run - post Sidetrack, —_ —_. -___ _ Stn To. ', B (ftKB) (1 Make Model (in) Seri Type Type (in) (pa0 Run Date Com... 37 - 5,000 IN 3,033.6 2,607.2 ME CAMCO KBG -2 -9 1 GAS LIFT DMY BK -5 0.000 0.0 5/30/2010 © 4593.7 3,521.2 mia CAMCO KBMG 1 GAS LIFT DMY BKS 0.000 0.0 7/11/2010 ■ I1 1 I LINER, 4,888 -8,190 TD (3N -16A), _ 9.190 .. - - - ORIGI Last Updated: 9- Aug -10 3N -16A Proposed CTD Sidetrack 3 -1/2" Camco SSSV @ 2103' MD (2.813" X- profile) 3 -112" 9.3# L -80 EUE 8rd Tubing to surface C 1■ 3 -1/2" Camco KBG2 -9 gas lift mandrel @ 3034' 3 -1/2" Camco KBMG gas lift mandrel @ 4594' Baker 80 -40 seal assembly at 4696' ,, V Muleshoe @ XXXX' C) 9 -518" 40# J -55 shoe • @4803'MD 3.112" Production Liner ' „ N N 3 -1/2” x 7" ZXP liner top packer @ 4666" MD ,, „,,,,,„. 3 -1/2” x 7" liner hanger @ 4686' MD G , / 3 -1/2" PBR @' MD • / 3 -1/2" X- nipple @ 4725 MD (2.813" min ID) 7" TOW @ 4882 MD :' . AL1 -01 TD @ 9725' MD KOP @ 8170' MD I Billet at 8240' iefr Baker 3 -1/2" monobore WS _ / AU TD @ 9593' MD 3 -1/2 ", 9.3 ppf, L -80 Liner Billet at 8785' • Shoe @ 8190' MD '" -- --------------- \ AL1-02 TD @ 9339' MD ----- - Billet at 8440' I AL1 -03 TD @ 9388' MD --- Liner top at 8165' • Conoco Phillips Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit - Kuparuk 3N Pad 3N-16 3N-16AL1-03 Plan: 3N-16AL1-03_wp05 Standard Planning Report 09 August, 2010 FARM BAKER HUGHES r i 4 L.; L • • ConocoPhillips rsai Conoco. hillips Planning Report BAKER Alaska HUGHES '� Con c Phia s Inc. TVD Reference Mean Sea Level D atabase to Reference Well 3N -16 Company � - Cono p ( ) � � �� vel Projec f g Kuparuk River Unit MD Reference a 3N 16A (di 60.28ft (D16 (34.1+ 26.18)) ,Site. ki. Kuparuk 3N Pad litirtft Reference True Well - 3N -16 Survey Caltalation Method: Curvature Wellbore f 3N- 16AL1 -03 D 1- 03_wp05 esign _ 3N-16AL1-03_wp05 : Project a Kuparuk River Unit Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor ( Kuparuk 3N I Ku Pad . Site Site Position: Northing: 6,013,799.17ft Latitude: 70° 26' 55.957 N From: Map Easting: 517,946.19ft Longitude: 149° 51' 12.938 W Position Uncertainty: 0.00 ft Slot Radius: " Grid Convergence: 0.14 ° Well _ 3N -16 Well Position +N / -S 0.00 ft Northing: 6,013,799.25ft Latitude: 70° 26' 55.947 N +E/ -W 0.00 ft Easting: 518,370.74 ft Longitude: 149° 51' 0.470 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 34.10ft Wellbore 3N- 16AL1 -03 Magnetics Model Name Sample Date - Declination Dip Angle Field Strength (1 r) (nT) BGGM2009 8/6/2010 17.08 79.87 57,396 Design 3N- 16AL1 -03 wp05 Audit Notes: Version: Phase: PLAN Tie On Depth: 8,440.00 Vertical Section: Depth From +NI-S- + E/-W Direction (R) (ft) (ft) r) = - -34.10 0.00 0.00 123.00 Plan Sections . . Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth - S ystem +N/-S +E/ W Rate Rate . - Rate TFO (ft) (") (°) _ (ft) (ft) (ft) (° /100ft) (1100ft} _ (1100ft) - (') Target 8,440.00 89.52 121.98 6,475.70 - 2,209.47 3,617.10 0.00 0.00 0.00 0.00 8,520.00 99.90 115.92 6,469.13 - 2,248.02 3,686.72 15.00 12.97 -7.57 330.00 8,650.00 96.02 96.62 6,450.95 - 2,283.81 3,809.71 15.00 -2.98 -14.85 260.00 8,750.00 90.76 110.70 6,445.00 - 2,307.34 3,906.43 15.00 -5.26 14.08 110.00 8,860.00 95.50 126.53 6,438.96 - 2,359.73 4,002.53 15.00 4.30 14.40 73.00 8,988.69 90.00 108.00 6,432.73 - 2,418.30 4,116.26 15.00 -4.27 -14.40 - 105.95 9,188.69 88.75 137.98 6,434.97 - 2,525.94 4,282.10 15.00 -0.62 14.99 92.50 9,388.00 88.92 167.88 6,439.12 - 2,701.37 4,371.77 15.00 0.08 15.00 90.00 8/9/2010 3:45:31 PM Page 2 COMPASS 2003.16 Build 69 0 n t, 1 , 1 • Conoco Phillips • C Fris onocoPhi lips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local :Co - ordinate Reference; Well 3N -16 C :c ConocoPhillips(Alaska) Inc. TVD,Reference Mean Sea Level Proje Kuparuk River Unit MD Reference ' 3N -16A @ 60.28ft (D16 (34.1+ 26.18)) Site:' '! , f Kuparuk 3N Pad North Reference True Weil `'; f, 3N -16 Survey -- Calculation Method:- Minimum Curvature Wellbore: 3N- 16AL1 -03 Design 3N- 16AL1- 03_wp05 Planned;Surveif Measured. TVD BeloNr Verticat; Dogleg Toolface `- Map Map - Depth , Inclination Azimuth ,,, System +N/�S +E/ WJ Section - Rate. Azimuth`. _ No Existing 8,440.00 89.52 121.98 6,475.70 - 2,209.47 3,617.10 4,236.92 0.00 0.00 6,011,598.93 521,992.91 TIP / KOP 8,500.00 97.31 117.46 6,472.12 - 2,239.14 3,669.06 4,296.65 15.00 -30.00 6,011,569.39 522,044.94 8,520.00 99.90 115.92 6,469.13 - 2,248.02 3,686.72 4,316.30 15.00 -30.27 6,011,560.55 522,062.63 2 8,600.00 97.62 104.00 6,456.90 - 2,274.93 3,760.90 4,393.18 15.00 - 100.00 6,011,533.82 522,136.86 8,650.00 96.02 96.62 6,450.95 - 2,283.81 3,809.71 4,438.94 15.00 - 101.82 6,011,525.07 522,185.69 � 3 8,700.00 93.42 103.68 6,446.83 - 2,292.59 3,858.73 4,484.83 15.00 110.00 6,011,516.41 522,234.72 8,750.00 90.76 110.70 6,445.00 - 2,307.34 3,906.43 4,532.87 15.00 110.58 6,011,501.77 522,282.45 4 0 8,800.00 92.95 117.88 6,443.38 - 2,327.88 3,951.94 4,582.24 15.00 73.00 6,011,481.35 522,328.02 8,860.00 95.50 126.53 6,438.96 - 2,359.73 4,002.53 4,642.00 15.00 73.23 6,011,449.62 522,378.67 5 8,900.00 93.82 120.75 6,435.70 - 2,381.81 4,035.70 4,681.85 15.00 - 105.95 6,011,427.63 522,411.90 8,988.69 90.00 108.00 6,432.73 - 2,418.30 4,116.26 4,769.29 15.00 - 106.42 6,011,391.35 522,492.54 6 1 9,000.00 89.93 109.70 6,432.74 - 2,421.95 4,126.97 4,780.26 15.00 92.50 6,011,387.72 522,503.25 9,100.00 89.28 124.68 6,433.44 - 2,467.51 4,215.66 4,879.46 15.00 92.50 6,011,342.38 522,592.05 9,188.69 88.75 137.98 6,434.97 - 2,525.94 4,282.10 4,967.00 15.00 92.39 6,011,284.12 522,658.63 7 9,200.00 88.75 139.67 6,435.21 - 2,534.45 4,289.55 4,977.88 15.00 90.00 6,011,275.63 522,666.10 9,300.00 88.80 154.68 6,437.36 - 2,618.23 4,343.59 5,068.83 15.00 89.96 6,011,192.00 522,720.34 9,388.00 88.92 167.88 6,439.12 - 2,701.37 4,371.77 5,137.74 15.00 89.64 6,011,108.93 522,748.72 TD Casing Points - - . r Measured Vertical, - Casing.. Hole Depth Depth Diameter= D iamete r (ft) (ft) Name t ") r) 4,789.28 3,570.19 9 5/8" 9 -5/8 12 -1/4 4,882.00 3,622.05 7" TOW 7 8 -1/2 9,388.00 6,439.12 2 3/8" 2 -3/8 3 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S: +E/ W ( ft) (ft) (ft) (ft) -' _ Comment 8,440.00 6,475.70 - 2,209.47 3,617.10 TIP / KOP 8,520.00 6,469.13 - 2,248.02 3,686.72 2 8,650.00 6,450.95 - 2,283.81 3,809.71 3 8,750.00 6,445.00 - 2,307.34 3,906.43 4 8,860.00 6,438.96 - 2,359.73 4,002.53 5 8,988.69 6,432.73 - 2,418.30 4,116.26 6 9,188.69 6,434.97 - 2,525.94 4,282.10 7 9,388.00 6,439.12 - 2,701.37 4,371.77 TD 8/9/2010 3:45:31 PM Page 3 COMPASS 2003.16 Build 69 0 r? 1 r, 1 P4,,, 1„ I\ ; 1 \ t C 1 ','' :i ; ', . Aamre.to Tn.NoM WELLBORE DETAILS: 3N- 16AL1 -03 REFERENCEINFORMATION �+" Project: Kuparuk River Unit Magnetic North 21.57 Site: Kuparuk3N Pad Co (NE) Reference: INe113N - 16, True North Magnetic d Parent Wellbore: 3N- 16AL1 -02 ' Well: 3N -16 shenon 5 76745en T ie on MD: 8440.00 Vertical (TVD) Reference: Mean Sea Level BAKER �+ Wellbore: 3N- 16AL1-03 Dry Angie e0. Sec on(VS)Reerence: Sbt- (O.00N,O.00E) Co MVt OCCri��'ll��lp5 Plan: 3N- 16AL1 -03 wp115(3N- 16/3N- 16AL1.03) Date: �'D1 M easured Depth Reference: 3N•16A@60.28it(D16 (34.1 +26.18)) Calculation Method: Minimum Curvature HUGHES -1920- - ° - - 31V- 16/3N- 16AL1 -01 / .\- Io; +NV- I6_I1 WELL DETAILS: 3N -18 -1980- - - - - Ground Level: 34.10 / / ON/-S +E/ -W Northing Easting Latittude Longitude Slot -2040- - - - - / - - - - - _- - - - -- - - 0.00 0.00 6013799.25 518370.74 70° 26' 55.947 N 149° 51' 0.470 W , -2100 / - - -- - _- - - . -- - -- - - SECTION DETAILS ANNOTATIONS / - Sec MD Inc Azi TVD +N/-S +E/-W DLeg TFace VSec Target Annotation -2160- . ' 1 8440.00 89.52 121.98 6475.70 - 2209.47 3617.10 0.00 0.00 4236.92 TIP I KOP 2 8520.00 99.90 115.92 6469.13 - 2248.02 3686.72 15.00 330.00 4316.30 2 -2220- - - 3 8650.00 96.02 96.62 6450.95 - 2283.81 3809.71 15.00 260.00 4438.94 3 TIP /KO' 4 8750.00 90.76 110.70 6445.00 - 2307.34 3906.43 15.00 110.00 453287 4 zzao- 5 8860.00 95.50 126.53 6438.96 - 2359.73 4002.53 15.00 73.00 4642.00 5 2 6 8988.69 90.00 108.00 6432.73 - 2418.30 411626 15.00 - 105.95 4769.29 6 p 1N- 16 /3N- 16APB 7 9188.69 88.75 137.98 6434.97 -2525.94 4282.10 15.00 92.50 4967.00 7 X2340- I - - - 8 9388.00 88.92 167.88 6439.12 - 2701.37 437177 15.00 90.00 513774 TD �' _... + + + • ?goo- - 0 -2460- - + - - y -2520 - 3N- 16RN -16• 1 -02 iv-, _ -. -2580 I -2640- -- - + t ", --- -- " -� r -2700 - - ' -- - - - - - \\ - m= ',.ci -2760- '- - - - . - 3N- 16/3N- 16ALI -03 3N- 16/3N -I6 -2820- - - - - x� >" ..n 3420 3480 3540 3600 3660 3720 3780 3840 3900 3960 4020 4080 4140 4200 4260 4320 4380 4440 4500 + West(- )/East( +) (60 ft/in) 6200- N. - - : - ! \ - - -- 6250_ \ \� ' 6300__. - N -- - 34- 16 /3N- I6APB3 3N- 16/3N- 16AL1 -01' III 6350 , - .i - -. I - - -- WI : N- I6r3N- IOAPBI I ' � � - 6400- t . ; / - -..- _ _ ._ _ _ _ _- _ _ 3V -Ir i \.Ic \l 1 3N- 16/3I�; 16AL1 -03 .13 3N- 16/3N -16A- . r _ \ d 6450 - C -° - __ TD - -- -- - Q _ -. - - r - is • - , - _ : 'b I 5 6 7 p 9 ) 6500 - - - - - - - 3 - T I P / 2 6550- -- • - -- 3N-16/3N-16A111-02 ',\ a) . : . , H 6600- -- - - - - - 6650 - - - - : - - - - 3N- 16/3N -16 6700 - - - - _ -- .- - - 3600 3650 3700 3750 3800 3850 3900 3950 4000 4050 4100 4150 4200 4250 4300 4350 4400 4450 4500 4550 4600 4650 4700 4750 4800 4850 4900 4950 5000 5050 5100 5150 5200 5250 5300 5350 5400 5450 5500 rt Vertical Section at 123.00° (50 ft/in) AzirrahnloTrue N WELLBORE DETAILS: 3N- 16AL1-02 REFERENCE INFORMATION r- Project: Kuparuk River Unit Megrexrm;m.21.S3 Site: Kuparuk 3N Pad C°orrinale (WE) Reference Well 3N True North Magnetic 57 FWn Parent Tie on M r D : : 8 82 00 vertical 1 Well: BAKEIR Conoc- Well: SN -16 se.nalh:ero7aaidT Tieon MD: �)Relerence: 3W16AQ60.286(D16 (34.1 +26,16)) Wellbore: 3N k d at BG M2039 Seclwn(VS) Reference: Slot - (O.00N, 0.00E) 8 �� P Ian:3N - 16AL1.02 wp06(3N 16/3N 16AL1 - 02) ° MeasuedDeplhRefeence. 3W16AQ60.28ft(D16 ■��Irr Calculation Method: Minimum Curvature n r S -300 -( _ I - ;N -14 N -14 --- - - r0) _ 3N- 1 ;N_I? - -- - - --- -- - -- -- - - '- -- - -- c -451 .. r ., ,e - . - 1 - - - -601 -- - . - - --- - - - -- - - 750 , N-14.N-14.11131 - - , , ∎N- 14,3N -14A -901 \ - _ ' - r - ■ - I . - - - - -1050 \ - - - - - -1200 - - - -1350 , \ \ - - -- -- -1500 /- ",\ - , 1 1 7 . 1 - _ - - - - -_ - -_ -_— �.. __.,..- -1650 - - -'- - - - - - - - - - - - - - ' • � � [iE 0 �0 1 . =1- - - - - - - - - . i. ti �..,., .�;a, v -2250 .. - 1 z O -2400 F. e 1 ; - . - - ' ' ` :N - J' N }B1 a '7' - 2550 _ - - ' a.. - _ 3N Y 9 . - 2700 - - \ :N- 1(+,+N -II AI I.tII - • O - - - _- -- -2850 • - - - - - - - . - - - - - - - - - 6` s ,.:.u,er.l, 1000- .\ ` r. / - - - -- -- - i - 3150- . - - -- - - - - -- - - - -- ' - -- ----- - - -- -'- - -3300- - -3450- , - - - -',. -3600- - - - - - - -3750- - - -3900- \� , - - -' N. �-1' IN.ii ;.1 4050- N N 4200- - - - - . - - - - - - - - � - - 1N-It,vN -in `II -I>, ,1-1-11, 3N 1911N - 19 \ T.) ,II ' '.1 i 4350- --- _ . - -- - - - - _ 1350 1500 1650 1800 1950 2100 2250 2400 2550 2700 2850 3000 3150 3300 3450 3600 3750 3900 4050 4200 4350 4500 4650 4800 4950 5100 5250 5400 5550 5700 5850 6000 6150 6300 6450 6600 6750 6900 3N -16A @ 60.28ft (D16 (34.1+ 26.18)) West( -) /East( +) (150 ft /in) S Nabors CDR -2AC Kuparuk Managed Pressure Coil Tubing Drilling BOP Configuration for 2" Coil Tubing Lubricator Riser Annular/ Blind / Shear 2" Pipe / Slip (CT) Pump into Lubricator above BHA rams r Choke 1 2 -3/8" Pipe / Slip (BHA) ' Choke Equalize Manifold 2 -3/8" Pipe / Slip (BHA) �} J L • L Kill _ i i W - 1 1 Blind / Shear 2" Pipe / Slip (CT) Choke 2 :Swab Valves . ► Wing Valves ' � � ;��14 Tree Flow Cross Surface Safety Valve BOPE: 7- 1/16 ", 5M psi, TOT Choke Line: 2- 1/16 ", 5M psi Master Valve Kill Line: 2- 1/16 ", 5M psi Equalizing Lines: 2- 1/16 ", 5M psi Choke Manifold: 3 -1/8 ", 5M psi Riser: 7- 1/16 ", 5M psi, CO62 Union p C; t\I I )4. n r E a • TRANSMITTAL LETTER CHECKLIST WELL NAME 3A 1('A s PTD# 2__/ L- / C -� Development t./ Service Exploratory Stratigraphic Test Non - Conventional Well FIELD: r e �. POOL: Ktre---y (/ � ( /C L - 1 oo / � t fS rr �—f 1 I Circle Appropriate Letter I 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 P(i2r= E c A �- l - 4 (If last two digits in Permit No. 2_ /Lry(`yt�`{ j , API No. 50- e� 1 - 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 thro h 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 1 Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK RIV UNIT 3N- 16AL1 -03 Program SER Well bore seg 0 PTD#: 2101100 Company CONOCOPHILLIPS ALASKA INC Initial Class /Type SER / PEND - GeoArea 890 _- Unit 11160 On /Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes Surf loc in ADL 025521; kick -off point, top prod interval and TD in ADL 025520. 3 Unique well name and number Yes 4 Well located in a defined pool Yes Kuparuk River Oil Pool, governed by Conservation Order No. 432C 5 Well located proper distance from drilling unit boundary Yes Conservation Order No. 432C contains no spacing restrictions with respect to drilling unit 6 Well located proper distance from other wells Yes boundaries and no interwell spacing restrictions. Wellbore will be more than 1 mile 7 Sufficient acreage available in drilling unit Yes from an external property line where ownership or landownership changes. 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15 -day wait Yes SFD 8/13/2010 114 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For Yes Area Injection Order No. 2B • 15 All wells within 1/4 mile area of review identified (For service well only) Yes 3N -16, 3N -16A, 3N- 16APB1, 3N- 16APB2, 3N- 16APB3, 3N -14A, 3N- 14APB1 I16 Pre - produced injector: duration of pre - production less than 3 months (For service well only) No 17 Nonconven. gas conforms to AS31.05.030Q.1.A),(j.2.A -D) NA 18 Conductor string provided NA Conductor sest in 3N-16A Engineering 119 Surface casing protects all known USDWs NA Surface casing set in 3N -16A 1 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing cemented in 3N -16A 21 CMT vol adequate to tie -in long string to surf csg NA Production casing set in 3N-16A 22 CMT will cover all known productive horizons No slotted liner planned for laterals. 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel pits. 1 25 If a re- drill, has a 10 -403 for abandonment been approved NA 3N -16A is a topset 3 1/2" liner to set up for CTD laterals. 26 Adequate wellbore separation proposed Yes Proximity analysis performed. No issues. 27 If diverter required, does it meet regulations NA Wellhead in place. BOP to be placed on top of production tree. Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pressure = 3283 psi ( 10.2 ppg EMW) Will drill with 8.6 ppg mud and use MPD technique. GLS 8/13/2010 29 BOPEs, do they meet regulation Yes ( most likely BHP will be lower based on offset pressures) 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP = 2663 psi Will test BOP to 3500 psi 31 Choke manifold complies w/API RP -53 (May 84) Yes • 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable Yes H2S on 3N pad. Rig has sensors and alarms. '34 Mechanical condition of wells within AOR verified (For service well only) Yes AOR completed. 3N- 16APB1 has liner stuck inside... Likey shale sloughing will block fluid migration. 135 Permit can be issued w/o hydrogen sulfide measures No Original well 3N -16 measured 140 ppm H2S in Dec. 2008; measures required. Geology 36 Data presented on potential overpressure zones Yes Expected reservoir pressure is about 3.0 to 3.8 ppg EMW; will be drilled using 8.6 ppg mud and Managed Appr Date 37 Seismic analysis of shallow gas zones NA Pressure Drilling Technique using a coiled- tubing rig to manage the wellbore. SFD 8/13/2010 38 Seabed condition survey (if off - shore) NA 39 Contact name /phone for weekly progress reports [exploratory only] NA Geologic Engineering Public Commissioner: Date: Date ate Comm' oner Date 2 (,0 8/77(0 � � �'/ — 1 o