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213-027
213-027: The Current Well Status was changed to EXPIR on the effective date of 2/28/2015. This change was performed by user SEM. _7Y3-aZ7 Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Tuesday, April 08, 2014 11:20 AM To: Ferguson, Victoria L (DOA) Cc: Eller, J Gary (J.Gary. Eller@conocophillips.com); Roby, David S (DOA); Bettis, Patricia K (DOA); Hunt, Jennifer L (DOA) Subject: RE: 3Q-03(PTD 191-126); 3Q-03A(PTD 213-016); 3Q-03AL1(PTD 213-017); 3Q-03AL1-01(PTD 213-027) Victoria, To document this unusual situation, the following note and email messages have been placed in AOGCC's well history files for KRU 3Q-03 (PTD 191-126), 3Q-03A(PTD 213-016), 3Q-03AL1(PTD 213-017), and 3Q-03AL1-01(PTD 213-027) and in AOGCC's RBDMS database for each of these well branches. ConocoPhillips Alaska Inc. (ConocoPhillips) failed to notify the AOGCC before making a change to proposed plug-for- redrill operations in KRU 3Q-03 (PTD 191-126). Rather than plugging existing perforations in KRU 3Q-03 prior to redrilling the well, ConocoPhillips instead installed a flow -around whipstock. The result of this unapproved change is that the KRU 3Q-03A, 3Q-03AL1 and 3Q-03AL1-01 well branches are all improperly named and have been assigned incorrect API numbers. To change the names and API numbers for these well branches after -the -fact would be unduly confusing, so AOGCC has decided to administratively abandon KRU 3Q-03 (even though it is still contributing to production) and to report all future production from these well branches against KRU 3Q-03A, Permit Number 213-016, API Number 50-029-22221-01-00. Accordingly, the current status of KRU 3Q-03 has been changed in AOGCC's RBDMS database to Administratively Abandoned (Code ADMA) effective 4/8/2014 as documented in the attached email messages. Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 Fax: 907-276-7542 From: Ferguson, Victoria L (DOA) Sent: Tuesday, April 08, 2014 10:04 AM To: Roby, David S (DOA); Davies, Stephen F (DOA); Bettis, Patricia K (DOA) Cc: Eller, J Gary(J.Gary.EllerCa)conocophillips.com) Subject: FW: 3Q-03(PTD 191-126); 3Q-03A(PTD 213-016); 3Q-03AL1(PTD 213-017); 3Q-03AL1-01(PTD 213-027) This note is to document that we will administratively abandon well 3Q-03 and no production will be allocated to 3Q- 03. Instead production will be allocated to 3Q-03A. Please note that physically 3Q-03 is actually open to production. Please make a note in RBDMS. Victoria Ferguson Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave, Ste 100 Anchorage, AK 99501 Work: (907)793-1247 victoria.ferguson(a)alaska.gov From: Ferguson, Victoria L (DOA) Sent: Tuesday, April 08, 2014 9:21 AM To: Eller, J Gary (J.Gary. Eller(cbconocophill ips.com) Subject: 3Q-03(PTD 191-126); 3Q-03A(PTD 213-016); 3Q-03AL1(PTD 213-017); 3Q-03AL1-01(PTD 213-027) Gary, We have reviewed the following sundry/PTDs and work completed: 3Q-03 3Q-03 3Q-03A 2/8/13,1/17/14 3Q-03AL1 2/8/13,1/17/14 3Q-03AL1-01 2/28/13,1/17/14 plug for redrill workover to change completion/pkr drill lateral drill lateral drill lateral 191-126 191-126 213-016 213-017 213-027 313-042 no sundry required na 2/8/13 The scope of the plug for redrill on 3Q-03 changed from a plugging of the perforations to a flow around whipstock after the workover was completed. Prior to drilling 3Q-03A, a new sundry for 3Q-03 was required for the change in scope. Since 3Q-03 was planned to remain open to production, the numbering/names of the laterals would have changed. The change in whipstock type for 3Q-03 was not approved. The naming and numbering of the laterals will not change in our system. Continue to use the current naming/numbering. Notes will be made to each of the well files outlining the situation. This oversight causes difficulty with our record keeping system including the production reporting system and well files and should not be repeated. Victoria Victoria Ferguson Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave, Ste 100 Anchorage, AK 99501 Work: (907)793-1247 victoria.ferg uson(a)alaska.gov THE STATE J I / GOVI"R.NOR SF.ANI P.ARNEL_L Lamar Gantt CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, 3Q-03AL1-01 ConocoPhillips Alaska, Inc. Permit No: 213-027 (revised) Surface Location: 2211' FNL, 2328' FEL, SEC. 17, T13N, R09E, UM Bottomhole Location: 497' FSL, 466' FWL, SEC. 5, T13N, R09E, UM Dear Mr. Gantt: 333 We,t Sevenih Avenue Anchorage, Alaska 99501 3572 nin: 907.279.143.3 Enclosed is the approved application for permit to re -drill the above referenced development well. This permit supersedes and replaces the permit previously issued for this well dated February 28, 2013. The permit is for a new wellbore segment of existing well KRU 3Q-03A, Permit No 213-016, API 50-029-22221-01-00. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P. Foerster Chair DATED this // 7 a y of January, 2014. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: Drill ❑ . Lateral Redrill ❑ Reentry 1 b. Proposed Well Class: Development -Oil ❑✓ Service - Wini ❑ • Single Zone ❑ Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Coalbed Gas ❑ Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Bond: - Ll Blanket Single Well Bond No. 59-52-180 11. Well Name and Number: 3Q-03AL1-01 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 12259' • TVD: 6586' 12. Field/Pool(s): Kuparuk River Field Kuparuk River Oil Pool e 4a. Location of Well (Governmental Section): Surface: 2211' FNL, 2328' FEL, Sec. 17, T13N, R09E, UM Top of Productive Horizon: 1222' FNL, 1865' FWL, Sec. 8, T13N, R09E, UM Total Depth: 497' FSL, 466' FWL, Sec. 5, T13N, R09E, UM 7. Property Designation (Lease Number): ADL 355024, 25512, 373301 8. Land Use Permit: 2553, 4162 13. Approximate Spud Date: 1/31/2014 9. Acres in Property: 5021 - 14. Distance to Nearest Property: 4870 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 516008 y- 6025861 Zone- 4. 10. KB Elevation above MSL: - 63 feet GL Elevation above MSL: 21.7 feet 15. Distance to Nearest Well Open to Same Pool: 3R-18 , 2400' 16. Deviated wells: Kickoff depth: 9875 ft. Maximum Hole Angle: 93° deg 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 5039 psig . Surface: 4386 psig - 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks (including stage data) Hole Casing Weight Grade Coupling Length MD TVD MD TVD 3" 2.375" 4.7# L-80 ST-L 2789' 9470' 6532' 12259' 6586' Islotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 9640' Total Depth TVD (ft): 6758' Plugs (measured) none Effective Depth MD (ft): 9516 Effective Depth TVD (ft): 6664 Junk (measured) none Casing Length Size Cement Volume MD TVD Conductor/Structural 80' 16" 1875 sx Poleset 120' 120' Surface 5170' 9.625" 1240 sx PF E, 495 sx Cl G 5210' 3906' Intermediate Production 9573' 7" 212 sx Class G 9605' 6732' Liner Perforation Depth MD (ft): 9361-9401' Perforation Depth TVD (ft): 6548'-6578' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Prograrr ❑✓ Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑ 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: Date: h\yf 22. 1 hereby certify that the foregoing is true and correct. Contact J. Gary E / e4- r @ 263-4172 \�<_ Email JI.Gary.EllerWconocophillipAdom Printed Name Lamar Gantt Title CTD Engineering Supervisor Signature �,' `; Phone 263-4021 Date j y I` Commission Use Only Permit to Drill Number: QQ 1-3 API Number: 50- ((),Z` - 2aa I QU Permit Approval �y Date: X j 3 See cover letter for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce Coalbed methane, gas hydrates, or gas contained in shales: Other: Q O tn to -L 4 pO ©�S Samples req'd: Yes No ® Mud log req'd: Yes❑ No [0 ' 6 T `C7 H2S measures: Yes No Directional svy req'd: Yespn No❑ Spacing exception req'd: Yes ❑ No Inclination -only svy req'd: Yes ❑ No [�r PPROVED BYTHE / '7 Approved by: CO I S ®N2 � i QMMI$SION Date: Form 10-401 (Revisd 10/2012) This permit is v2trd fbr 24'm6n1hB fforh the date -of approval (20 AAC 25.005(g)) r/k6 //160 � VZ_ ,I--i/l lv1 l f j`/�� �x v' conocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 January 9, 2014 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: JAN 0 9 2u A®GVV ConocoPhillips Alaska, Inc. hereby submits revisions to the Permit to Drill (PTD) applications that were previously approved for KRU 3Q-03A, 3Q-03AL1, and 3Q-03AL1-01. The approved PTD numbers for these applications are 213-016, 213-017, and 213-027 respectively. CTD operations are now scheduled to begin January 31, 2014 using the Nabors CDR2-AC rig. The revisions are necessary because the completion of 3Q-03 changed significantly during a workover in September 2013, which will in turn significantly change the planned CTD completion of these laterals. The directional plans for these laterals have not significantly changed, nor has the estimate of maximum potential formation pressure. But the borehole size, completion liner size, BOP configuration, and expected formation pressure have all changed. Attached to this application are the following documents that explain the proposed job operations. — Drilling program summary - Revised Permit to Drill application forms for 3Q-03A, 3Q-03AL1, & 3Q-03AL1-01 — Directional plans for 3Q-03A, 3Q-03AL1, & 3Q-03AL1-01 — BOP schematic diagrams for bighole & slimhole CTD BHAs — Proposed wellbore schematic If you have any questions or require additional information please contact me at my office 907-263-4172. Sincere , r . ' J. Gar Eller Conoco PQllips Alas Coiled TubiAg Drilling Engineer Kuparuk CTD Sidetrack NABOBS ALAS" 3Q-03A, AL1, & AL1-01 Ci 01% Drilling Program Summary ZRt 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(t) and 20 AAC 25.005(b))................................................................................................................... 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2)).................................................................................................................................................. 2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 3 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 3 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7)).................................................................................................................................................. 3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9)).................................................................................................................................................. 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4 11. Seabed Condition Analysis............................................................................................................ 4 (Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................4 12. Evidence of Bonding...................................................................................................................... 5 (Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 5 13. Proposed Drilling Program............................................................................................................. 5 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 5 Summaryof Operations...................................................................................................................................................5 PressureDeployment of BHA..........................................................................................................................................6 LinerRunning...................................................................................................................................................................7 14. Disposal of Drilling Mud and Cuttings.......................................................................................... 7 (Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 7 15. Directional Plans for Intentionally Deviated Wells....................................................................... 7 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 7 Attachment 1: Directional Plans for 3Q-03A, 3Q-03AL1, & 3Q-03AL1-01.......................................................................7 Attachment 2: Current Well Schematic for 3Q-03...........................................................................................................7 Attachment 3: Proposed Well Schematic for 3Q-03 CTD Sidetrack................................................................................7 Page 1 of 7 Updated January 7, 2014 PTD Applications for KRU 3Q-03A, AL1 & AL1-01 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) KRU 3Q-03A, 3Q-03AL1, and 3Q-03AL1-01 are proposed CTD horizontal laterals from the 3Q-03 motherbore. They will all be classified as "Development - OX wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) The 3Q-03 laterals will target the Al sand in the Kuparuk reservoir. See the attached 10-401 form for surface and subsurface coordinates of the 3Q-03A sidetrack and the 3Q-03AL1 and 3Q-03AL1-01 laterals. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Two different BOP diagrams are attached for well 3Q-03 as required per 20 AAC 25.036 for thru-tubing drilling operations. — The first portion of the 3Q-03A sidetrack will be drilled and cased using 23/" coiled tubing. BOPE configuration for the `bighole BHA' will be used during these operations. The variable bore rams (2%" to 3%2" range) will provide secondary well control while running 3W slotted & blank liner. — The `slimhole BHA' BOPE configuration will be used for all remaining operations after running 3%4' liner. This is the configuration that will be used for the remainder of 3Q-03A and the entire AL1 and ALl-01 laterals. These operations will be conducted with 2" coiled tubing and we will switch to this BOP configuration prior to drilling out the 3%4" uncemented liner. The 2%" rams will provide secondary well control while running 23/" liner. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and 4800 psi. Using a maximum potential formation pressure of 5039 psi, the maximum potential surface pressure is 4386 psi assuming a gas gradient of 0.1 psi/ft. See the "Drilling Hazards Information and Reservoir Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2500 psi. 4. Drilling Hazards Information and Reservoir Pressure (Requirements of 20 AAC 25.005 (c)(4)) Reservoir Pressure and Maximum Downhole Pressure The most recent static BHP survey in 3Q-03 was taken December 16, 2013 showing a formation pressure of ✓3614 psi at 6574' TVD, or 10.6 ppg EMW. A better estimate of far -field pressure is provided by well 3Q-01, which has historically tracked 3Q-03 very closely. 3Q-01 currently shows the far -field pressure to be 12.0 ppg EMW, which is now considered the maximum pressure that we expect to encounter while drilling the 3Q-03 laterals. Maximum potential formation pressure is based on an injector to the south. 3Q-12 had a static bottomhole pressure of 4990 psi at 6479' TVD for a gradient of 14.8 ppg in December 2012. Since that time the pressure in the entire area has come down to an estimated 12.0 ppg EMW as evidenced in both 3Q-01 and 3Q-03, but the measurement in 3Q-12 represents a conservative maximum for the area. In 3Q-03 this gradient equates to a maximum potential formation pressure of 5039 psi (9353' MD, 6543' TVD) and a maximum potential surface pressure of 4386 psi assuming a gas gradient to surface. Potential Gas Zones No specific gas zones will be drilled, but 3Q pad is located in an area of active miscible gas injection. It is likely that an influx can produce a significant amount of gas. Potential Causes of Hole Problems The major expected downhole risk in the 3Q-03 laterals is hole stability due to inter -bedded shales in the A -sand, the underlying Miluveach shale, and the overlying D shale. We will mitigate hole instability by installing a 3%4" liner over the planned Miluveach crossing the 3Q-03A sidetrack, and subsequently drilling ahead with Page 2 of 7 0 NI A L Updated January 7, 2014 �4 PTD Applications for KRU 3Q-03A, AL1 & AL1-01 slimhole tools on 2" coiled tubing. Furthermore, we will maintain a minimum ECD target of 12.1 ppg EMW at the window as well as use mud additives that minimize chemical instability. A second downhole risk is having adequate weight transfer to drill to the planned TD of 13,805' MD in 3Q-03A. We will mitigate that risk by maintaining very low doglegs in the sidetrack and maintaining mud lubricity. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 3Q-03 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity test is not required. 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Sidetrack Liner Liner Liner Liner Name Top MD Btm Top Btm Liner Details MD SSTVD SSTVD 3Q-03A 9290' 12,300' 6431' 6477' 3%4", 6.6#, L-80, TC-II slotted & blank intermediate liner 3Q-03A slimhole 12,290' 13,805' 6477' 6496' 23/", 4.7#, L-80, ST-L slotted liner 3Q-03AL1 9875' 10,400' 6507' 6538' 23/", 4.7#, L-80, ST-L slotted liner with aluminum bilet 3Q-03AL1-01 9470' 12,259' 6532' 6586' 2'/", 4.7#, L-80, ST-L slotted liner up inside 3%4" liner Existing Casing/Liner Information Category OD Wt (ppf) Grade Cxn Top MD Btm MD Top TVD Btm TVD Burst psi Col. psi Conductor 16" 62 H-40 Welded 0' 121' 0' 115' n/a n/a Surface Csg 95/" 36 J-55 BTC 0' 5210' 0' 3903' 3520 2020 Prod Cs 7" 26 J-55 BTC 0' 9605' 0' 6729' 4980 4320 Tubing 4'/2" 12.6 L-80 IBT-Mod 0' 9297' 0' F6498' 8430 7500 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) Nabors CDR2-AC will be operating under 20 AAC 25.036 for thru-tubing drilling operations so no diverter system is required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System A diagram of the Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System — Window milling operations: Chloride -based Biozan brine or used dr.fling mud (-10.0 ppg) — Drilling operations: Chloride -based Flo -Pro Flo Vis mud (10.0 ppg). This mud weight alone will not hydrostatically overbalance formation pressure in the 3Q-03 motherbore, but overbalanced conditions will be maintained using MPD practices described below. — Completion operations: Well 3Q-03 is equipped with a subsurface safety valve (SSSV) at 1927' MD which we intend to use whenever possible to isolate formation pressure while picking up completion Page 3 of 7 Updated January 7, 2014 PTD Applications for KRU 3Q-03A, AL1 & AL1-01 liner. That will not be possible for some liners due to their length, so in those cases the well will be loaded with over -balancing completion fluid. We anticipate using 12.2 ppg completion fluid to provide over -balance while picking up these liners or as contingency if the SCSSV fails. — Emergency Kill Weight fluid: A full load (-270 bbl) of 12.2 ppg emergency kill weight fluid will be within a short drive of the rig during drilling operations. Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole formation throughout the coiled tubing drilling (CTD) process. Maintaining a constant BHP promotes wellbore stability, particularly in shale sections, while at the same time providing pressure over- balance to the formation. In the 3Q-03 laterals we will target a constant BHP of 12.1 ppg EMW at the window. 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. 3Q-03A Bighole Drilling (9353' MD, 6540' TVD, 6477' SSTVD) Usinq MPD Pumps On (1.5 bpm) Pumps Off A -sand Formation Pressure 12.0 4081 psi 4081 psi Mud Hydrostatic 10.0 3401 psi 3401 psi Annular friction i.e. ECD, 0.060 si/ft 561 psi 0 psi Mud + ECD Combined 3962 psi 3401 psi (no choke pressure) (underbalanced (underbalanced —120psi) —680psi) Target BHP at Window 12.1 ppg 4115 psi 4115 psi Choke Pressure Required to Maintain Target BHP 150 psi 720 psi 3Q-03A Slimhole Drilling (9353' MD, 6540' TVD, 6477' SSTVD) Using MPD Pumps On (1.5 b m) Pumps Off A -sand Formation Pressure (12.0 p 4081 psi 4081 psi Mud Hydrostatic 10.0 ppg) 3401 psi 3401 psi Annular friction (i.e. ECD, 0.045 psi/ft) 421 psi 0 psi Mud + ECD Combined 3822 psi 3401 psi (no choke pressure) (underbalanced (underbalanced —260 psi) —680psi) Target BHP at Window 12.1 ) 4115 psi 4115 psi Choke Pressure Required to Maintain 290 psi 720 psi Target BHP 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005(c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005(c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A - Application is not for an exploratory or stratigraphic test well. Page 4 of 7 ORI j„ I Updated January 7, 2014 PTD Applications for KRU 3Q-03A. AL1 & AL1-01 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Well KRU 3Q-03 was worked over in September 2013 during which they installed a 4'/2" completion with packer and SCSSV. The purpose of upsizing the completion to 4%" OD was to improve the prospects of CTD being able to successfully drill the 3Q-03A lateral by placing intermediate 3%" liner across the Miluveach shale prior to drilling to ultimate TD. The 3Q-03A sidetrack will be drilled west of 3Q-03 to increase reservoir exposure and improve waterflood sweep in the Al sand. It is intended to test the western extent of the Al sand at Kuparuk. Operations will begin with 2%" coiled tubing and the 'bighole' BHA for drilling 4.25" borehole. The BOP will be configured for the bighole BHA. We will set a whipstock and mill a 3.80" window at 9353' MD through the 7" casing. The 3Q-03A will be drilled with the bighole BHA west to—12,300' MD, which includes a lengthy crossing of the Miluveach shale. We will then run 3%" slotted & blank liner (uncemented) to cover up the Miluveach shale with the 3%" liner top being placed inside the 4'/" tailpipe at 9297' MD. We will then reconfigure for drilling 3" borehole using the 'slimhole' BHA and 2" coiled tubing. The BOP will likewise be re -configured and retested for our typical slimhole BHA. The remainder of the 3Q-03A will be drilled out of the 3%4" liner shoe to a planned TD of 13,805' MD, and it will be completed with 23/" slotted liner from TD to inside the 3%4" shoe at—12,300' MD. The 3Q-03AL1 lateral will be drilled north/west of 3Q-03 targeting the Al sand with an 1168' lateral. We will set a whipstock in the 3%" liner at 9477' MD and mill a window in the 3%4" liner. The AL1 lateral will be drilled to a.TD of 10,645' MD. A portion of this lateral will serve as a pilot hole to gauge the location and displacement of a major fault, and the borehole hole beyond the fault will not be completed. The hole will be completed with a 2'/" slotted liner to—10,400' MD with an aluminum billet placed at 9875' MD. The 3Q-03AL1-01 lateral will be drilled north/west of 3Q-03 targeting the Al sand with a 2384' lateral. After kicking off the aluminum billet at 9875' MD, the lateral will be drilled to a TD of 12,259' MD. The hole will be completed with a 23/" slotted liner to TD with the final liner top located inside the 3%4" liner at 9470' MD. Pre-CTD Work MIRU slickline. Dummy all GLMs. Actuate the SCSSV at 1927' to confirm that it is stroking properly. 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 configured for bighole operations, test. 2. 3Q-03A Bighole Sidetrack (Al sand, west) a. Set whipstock in 7" casing at 9353' MD b. Mill 3.80" window through 7" casing at 9353' MD c. Drill 3.70" x 4.25" bi-center sidetrack to—12,300' MD, crossing from the Miluveach shale back into the Al sand at—12,100' MD. d. Run 3%4" slotted & blank liner from TD up into the 4%" tubing tail at 9297'. The well will be loaded with over -balancing fluid to provide well control while picking up 3%4" liner. Page 5 of 7'� (7- Updated January 7, 2014 PTD Applications for KRU 3Q-03A, AL1 & AL1-01 3. 3Q-03A Slimhole Sidetrack (Al sand, west) a. Swap to 2" coiled tubing and the slimhole drilling BHA. Re -configure BOP for slimhole drilling and retest. b. Drill 2.70" x 3" bi-center sidetrack from the shoe of the 3%4" liner at—12,300' to a planned TD of 13,805' MD. c. Run 2'/" slotted liner from TD up into the shoe of the 3%4" liner at—12,300' MD'. The SCSSV at 1927' MD will be used to isolate the formation while picking up slotted liner. 4. 3Q-03AL1 Lateral (Al sand, north/west) a. Set whipstock in the 3%4" liner at 9477' MD b. Mill 2.74" window through 3%" liner at 9477' MD c. Drill 2.70" x 3" bi-center sidetrack to TD of 10,645' MD Run 2%" slotted liner with an aluminum billet from 10,400' up to 9875'. The borehole beyond —10,400' is a pilot hole through shale that will not be completed. The SCSSV at 1927' MD will be used to isolate the formation while picking up slotted liner. 5. 30-03AL1-01 Lateral (Al sand, north/west) a. Kick off from aluminum billet at 9875' b. Drill 2.70" x 3" bi-center sidetrack to TD of 12,259' MD c. Run 2%" slotted liner from TD up to 9470' inside the 3%" liner. The SCSSV at 1927' MD may be used to isolate the formation if the liner is run in two segments, but if the liner is run in a single piece then the well will be loaded with over -balancing fluid to provide well control.. 6. Freeze protect. 7. Set BPV, ND BOPE. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV 2. MIRU slickline. Install gas lift design. Perform static BHP survey. 3. Put well on production. Pressure Deployment of BHA The planned bottomhole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. Because of this, MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slickline lubricator. This pressure control equipment ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slickline. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment the steps listed above are conducted in reverse. Page 6 of 7 Iv` Updated January 7, 2014 PTD Applications for KRU 3Q-03A, AL1 & AL1-01 Liner Running — Well 3Q-03 is equipped with a SCSSV, so when the liner length is less than 1927' then the SCSSV will be used to isolate formation pressure while picking up liner. If the liner is longer than 1927' then fluid of sufficient density to over -balance the formation will be used to provide formation over -balance while picking up slotted liner. See the "Drilling Fluids" section for more details. — While running slotted liner, a joint of non -slotted tubing will be standing by for emergency deployment. This will be done both for 3%4" and 2'/" slotted liners. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run, The 23/" pipe rams provide secondary well control while running 23/" liner, and the VBRs provide secondary well control while running 3%4" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) — No annular injection on this well. — Class II liquids to KRU 1 R Pad Class If disposal well — Class II drill solids to Grind & Inject at PBU Drill site 4 — Class I wastes will go to Pad 3 for disposal. 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) — There are no other affected owners — Please see attached directional plans for each lateral. — Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. — MWD directional, resistivity, and gamma ray will be run over the entire openhole section. — Distance to nearest property line and nearest well in the same pool. Sidetrack Name Directional Plan Distance to Unit Boundary Distance to Nearest Well Nearest Well 3Q-03A 07 —6290' —2400' 3R-18 3Q-03AL1 05 —4870' —2400' 3R-18 3Q-03AL1-01 02 —4870' —2400' 3R-18 Attachment 1: Directional Plans for 3Q-03A, 3Q-03AL1, & 3Q-03AL1-01 Attachment 2: Current Well Schematic for 3Q-03 Attachment 3: Proposed Well Schematic for 3Q-03 CTD Sidetrack Page 7 of 7 Updated January 7, 2014 �W V U) LL U 11J N CL v O �n � m U ❑ cc U � N7 N LO CO (O V U) I` M N a c0 E y ca 07 U ca U O) (V Cd c� v cam Y m (V O ❑ N n_ (V O) CO Z; [0 Y O R' 0. Co aro E N tea` N N mm coca v N rn rn 7 s ❑ 0 rn N O O ccN C Q J ch O II � M (M F N O U N y 2 N p c = y0 H C O C j 'O ❑ .0 N N N O C C, C Q N y O m - o O II a ❑ — c M F- ch c F v rn u — I 1111 ill III � N o r ❑ g N N ❑ y Lo N ❑ to X O - N _� y O �:E 4k O_ Cn ❑ Y '' O a) 'ITc0 D_O (q N O M y @� = c0 �1 O L/ OLL - Cfl v bo N ❑ � Lo O> F Q N CO L c y cA L Nabors CDR-2AC, Well 3Q-03A Kuparuk Managed Pressure Coiled Tubing Drilling BOP Configuration for `Bighole' Ops: 2%" Coiled Tubing, 3" BHA, & 3%4" Liner Pump into Lubricator above BHA rams Kill Lubricator Riser nular Blind / Shear 23/" Pipe / Slip (CT) 3" Pipe / Slip (BHA) Variable rams (2%"-3%2") Blind / Shear 2%" Pipe / Slip (CT) Wing Valves Swab Valves Tree Flow Cross Equalize Surface Safety Valve Master Valve Choke 1 Choke Manifold Choke 2 BOPE: 7-1/16", 5M psi, TOT Choke Line: 2-1/16", 5M psi 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 ORIGINI %L— Pump into L above BR ME Nabors CDR2-AC Kuparuk Managed Pressure, Coiled Tubing Drilling Standard BOP Configuration for 2" Coiled Tubing & `Slimhole' BHA ORIGINAL ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 3Q Pad 3Q-03 3Q-03AL1-01 Plan: 3Q-03AL1-01 wp02 Standard Planning Report 08 January, 2014 a ppr-- BAKER NUGNES 0 R I G I N A 1,11 . Baker Hughes INTEQ WE.. ConocoPhillips Planning Report RAKER HUGHES Database: EDM Alaska Sandbox v16 Company: ConocwPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3Q Pad Well: 3Q-03 Wellbore: 3Q-03AL 1-01 Design: 3Q-03AL 1-01 _wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3Q-03 Mean Sea Level 3Q-03: @ 63.00ft (3Q-03) True Minimum Curvature 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 Site Kuparuk 3Q Pad Site Position: Northing: 6,025,873.15ft Latitude: 70° 28' 54.757 N From: Map Easting: 515,959.89ft Longitude: 149° 52' 10.513 W Position Uncertainty: 0.00 ft Slot Radius: 0,000 in Grid Convergence: 0.12 ° Well 3Q-03 Well Position +N/-S 0.00 ft Northing: 6,025,861.28 ft Latitude: 70° 28' 54.639 N +E/-W 0.00 ft Eastinq: 516,008.42 ft Longitude: 149° 52' 9.086 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 21.70 ft Wellbore 3Q-03AL1-01 Magnetics Model Name Sample Date Declination Dip Angle Field Strength BGGM2012 6/30/2013 15.48 80.01 57,373 Design 3Q-03AL1-01_wp02 Audit Notes: Version: Phase: PLAN Tie On Depth: 9,775.00 Vertical Section: Depth From (TVD) +N/-S +El-W Direction (ft) (ft) (ft) (I -21.70 0.00 0.00 315.00 Plan Sections Measured TVD Dogleg Build Turn Depth Inclination Azimuth Below +N/-S +E/-W Rate Rate Rate TFO (ft) (I (°) System (ft) (ft) (°/100ft (°/100ft) (°/100ft) (°) Target 9,775.00 87.18 7.76 6,504.72 6,567.34 -1,128.27 0.00 0.00 0.00 0.00 9.875.00 89.71 19.49 6,507.45 6,664.31 -1,104.76 12.00 2.53 11.73 78.02 10,000.00 80.20 16.37 6,518.42 6,782.62 -1,066.46 8.00 -7.60 -2.50 198.00 10,130.00 83.38 6.36 6,537.03 6,908.59 -1,041.18 8.00 2.44 -7.70 287.00 10,300.00 83.56 352.67 6,556.45 7,077.07 -1,042.61 8.00 0.11 -8.05 270.00 10,480.00 78.87 338,89 6,584.06 7,249.06 -1,086.05 8.00 -2.61 -7.65 250.00 10,605.00 86.58 345.31 6,599.90 7,366.92 -1,124.04 8.00 6.17 5.14 40.00 10,835.00 90.20 327.26 6,606.41 7,576.51 -1,216.13 8.00 1.57 -7.85 281.00 11,035.00 90.19 311.26 6,605.71 7,727.56 -1,346.22 8.00 0.00 -8.00 270.00 11,185.00 92.87 299.56 6,601.69 7,814.29 -1,468.20 8.00 1.78 -7.80 283.00 11,425.00 92.38 280.35 6,590.58 7.895.71 -1,692.50 8.00 -0.20 -8.01 269.00 11,675.00 91.21 260.37 6,582.66 7,897.25 -1,941.10 8.00 -0.47 -7.99 267.00 11,825.00 91.71 272.36 6,578.82 7,887.77 -2,090.48 8.00 0.33 8.00 87.50 12,075.00 88.54 292.11 6,578.28 7,940.50 -2,333.56 8.00 -1.27 7.90 99.00 12,200.00 86.32 282.35 6,583.90 7,977.45 -2,452.67 8.00 -1.77 -7.81 257.00 12,259.00 89.66 279.02 6,585.97 7,988.38 -2,510.59 8.00 5.66 -5.65 315.00 11812014 12:25:28PM Paqe 2 COMPASS 2003.16 Build 69 OkiGINAL Baker Hughes INTEQ FeA.. ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox v16 Local Co-ordinate Reference: Well 3Q-03 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 3Q-03: @ 63.00ft (3Q-03) Site: Kuparuk 3Q Pad North Reference: True Well; 3Q-03 Survey Calculation Method: Minimum Curvature Wel (bore: 3Q-03AL1-01 Design: 3Q-03AL1-01 wp02 Planned Survey Measured TVD Vertical Dogleg Toolface Map Map Depth Inclination Azimuth Below +N/-S +E/-W Section Rate Azimuth Northing Easting (ft) (°) (°) System (ft) (ft) (ft) (°/100ft) (°) (ft) (ft) 9,775.00 87.18 7.76 6,504.72 6,567.34 -1,128.27 5,441.62 0.00 0.00 6,032,425.52 514,866.13 TIP 9,800.00 87.80 10.69 6,505.82 6,591.99 -1,124.27 5,456.22 12.00 78.02 6.032,450.18 514,870.08 9,875.00 89.71 19.49 6,507.45 6,664.31 -1,104.76 5,493.57 12.00 77.89 6,032,522.53 514,889A3 KOP 9,900.00 87.81 18.87 6,507.99 6,687.92 -1,096.55 5,504.45 8.00 -162.00 6,032,546.15 514,897.59 10,000.00 80.20 16.37 6,518.42 6,782.62 -1,066.46 5,550.14 8.00 -161.99 6,032,640.92 514,927.48 Start 8 dIs 10,100.00 82.62 8.66 6,533.37 6,879.07 -1,045.07 5,603.22 8.00 -73.00 6,032,737.40 514,948.65 10,130.00 83.38 6.36 6,537.03 6,908.59 -1,041.18 5,621.34 8.00 -71.85 6,032,766.93 514,952.48 4 10,200.00 83.41 0.72 6,545.09 6,977.97 -1,036.89 5,667.36 8.00 -90.00 6,032,836.30 514,956.62 10,300.00 83.56 352.67 6,556.45 7,077.07 -1,042.61 5,741.48 8.00 -89.35 6,032,935.39 514,950.69 5 10,400.00 80.89 345.06 6,569.99 7,174.21 -1,061.71 5,823.67 8.00 -110.00 6,033,032.47 514,931.39 10,480.00 78.87 338.89 6,584.06 7,249.06 -1,086.05 5,893.81 8.00 -108.97 6,033,107.27 514,906.89 6 10,500.00 80.09 339.94 6,587.72 7,267.47 -1,092.96 5,911.72 8.00 40.00 6,033,125.66 514,899.93 10,600.00 86.27 345.06 6,599.59 7,362.10 -1,122.77 5.999.71 8.00 39.81 6,033,220.21 514,869.93 10,605.00 86.58 345.31 6,599.90 7,366.92 -1,124.04 6,004.02 8.00 39.20 6,033,225.03 514,868.64 7 10,700.00 88.06 337.85 6,604.35 7,456.89 -1,154.01 6,088.82 8.00 -79.00 6,033,314.93 514,838.49 10,800.00 89.64 330.01 6,606.36 7,546.62 -1,197.91 6,183.32 8.00 -78.65 6,033,404.56 514,794.39 10,835.00 90.20 327.26 6,606.41 7,576.51 -1,216.13 6,217.33 8.00 -78.49 6,033,434.40 514,776.11 8 10,900.00 90.20 322.06 6,606.18 7,629.51 -1,253.71 6,281.39 8.00 -90.00 6,033,487.32 514,738.42 11,000.00 90.20 314.06 6,605.83 7,703.84 -1,320.49 6,381.16 8.00 -90.02 6,033,561.49 514,671.49 11,035.00 90.19 311.26 6,605.71 7,727.56 -1,346.22 6,416.13 8.00 -90.05 6,033,585.15 514,645.71 9 11,100.00 91.36 306.20 6,604.83 7,768.20 -1,396.91 6,480.71 8.00 -77.00 6,033,625.69 514,594.94 11,185.00 92.87 299.56 6,601.69 7,814.29 -1,468.20 6,563.71 8.00 -77.07 6,033,671.61 514,523.56 10 11,200.00 92.85 298.36 6,600.94 7,821.54 -1,481.31 6,578.11 8.00 -91.00 6,033,678.84 514,510.43 11,300.00 92.67 290.35 6,596.11 7,862.70 -1,572.23 6,671.50 8.00 -91.06 6,033,719.80 514,419.43 11,400.00 92.45 282.35 6,591.64 7,890.80 -1,668.01 6,759.10 8.00 -91.45 6,033,747.68 514,323.60 11,425.00 92.38 280.35 6,590.58 7,895.71 -1,692.50 6,779.89 8.00 -91.80 6,033,752.55 514,299.10 11 11,500.00 92.06 274.35 6,587.68 7,905.29 -1,766.79 6,839.20 8.00 -93.00 6,033,761.96 514,224.80 11,600.00 91.59 266.36 6,584.49 7,905.91 -1,866.66 6,910.25 8.00 -93.23 6,033,762.37 514,124.94 11,675.00 91.21 260.37 6,582.66 7,897.25 -1,941.10 6,956.77 8.00 -93.49 6,033,753.55 514,050.52 12 11,700.00 91.30 262.37 6,582.11 7,893.50 -1,965.81 6,971.59 8.00 87.50 6,033,749.75 514,025.83 11,800.00 91.63 270.36 6,579.55 7,887.17 -2,065.50 7,037.60 8.00 87.54 6,033,743.20 513,926.16 11,825.00 91.71 272.36 6,578.82 7,887.77 -2,090.48 7,055.68 8.00 87.75 6,033,743.74 513,901.18 13 11,900.00 90.76 278.29 6,577.21 7,894.72 -2,165.10 7,113.37 8.00 99.00 6,033,750.54 513,826.55 12,000.00 89.49 286.19 6,576.99 7,915.91 -2,262.75 7,197.40 8.00 99.13 6,033,771.51 513,728.87 12,075.00 88.54 292.11 6,578.28 7,940.50 -2,333.56 7,264.85 8.00 99.14 6,033,795.94 513,658.02 14 12,100.00 88.09 290.16 6,579.02 7,949.51 -2,356.86 7,287.70 8.00 -103.00 6,033,804.90 513,634.69 12,200.00 86.32 282.35 6,583.90 7,977.45 -2,452.67 7,375.21 8.00 -102.94 6,033,832.64 513,538.84 15 11812014 12:25:28PM Paqe 3 COMPASS 2003.16 Build 69 ''``AL ✓ Baker Hughes INTEQ WGusI ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3Q Pad Well: 3Q-03 Wellbore: 3Q-03AL 1-01 Design: 3Q-03AL 1-01 _wp02 Planned Survey Measured TVD Depth Inclination Azimuth Below (ft) V) (1) System 12,259.00 89.66 279.02 6,585.97 TD at 12259.00 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3Q-03 Mean Sea Level 3Q-03 @ 63.00ft (3Q-03) True Minimum Curvature Vertical Dogleg Toolface Map Map +NI-S +E/-W Section Rate Azimuth Northing Easting (ft) (ft) (ft) (°/100ft) V) (ft) (ft) 7,988.38-2,510.59 7,423.90 8.00 -45.00 6,033,843.44 513,480.89 11812014 12:25:28PM Paqe 4 COMPASS 2003.16 Build 69 u6., Baker Hughes INTEQ MA.. ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3Q Pad Well: 3Q-03 Well bore: 3Q-03AL1-01 Design: 3Q-03AL1-01_wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Shape V) (I (ft) (ft) (ft) 3Q-03AL1-01_Fault4 0.00 0.00 0.00 5,094.731,138,704.35 plan hits target center Rectangle (sides W575.00 1-11.00 D0.00) 3Q-03AL1-01_T8 0.00 0.00 6,576.00 5,221.971,137,844.90 plan hits target center Point 3Q-03AL1-01_Fault2 0.00 0.00 0.00 4,375.471,139,099.90 plan hits target center Rectangle (sides W450.00 H1.00 D0.00) 3Q-03AL1-01_T1 0.00 0.00 6,537.00 4,187.281,139,046.80 plan hits target center Point Well 3Q-03 Mean Sea Level 3Q-03: @ 63.00ft (3Q-03) True Minimum Curvature Northing Easting (ft) (ft) Latitude Longitude 6,033,405.62 1,654,585.63 700 15' 33.110 N 140' 38' 7.664 W 6,033,531.00 1,653,726.00 70° 15' 35.621 N 140° 38' 31.787 W 6,032,687.28 1,654,982.69 70' 15' 25.540 N 140° 37' S9.466 W 6,032,499.00 1,654,930.00 70' 15' 23.793 N 140' 38' 1.818 W 3Q-03AL1-01 T4 0.00 0.00 6,607.00 4,841.581,138,940.20 6,033,153.00 1,654,822.00 70' 15' 30.302 N 140' 38' 2.004 W plan hits target center Point 3Q-03AL1-01_Fault5 0.00 0.00 0.00 5,199.441,138,226.16 plan hits target center Rectangle (sides W450.00 H1.00 D0.00) 3Q-03AL1-01_Fault3 0.00 0.00 0.00 4,660.501,139,019.77 plan hits target center Rectangle (sides W520.00 H1.00 D0.00) 3Q-03AL1-01_T6 0.00 0.00 6,597.00 5,148.341,138,598.82 plan hits target center Point 3Q-03AL1-01_T3 0.00 0.00 6,576.00 4,500.341,139,032.47 plan hits target center Point 6,033,509.29 1,654,107.27 70' 15' 34.837 N 140' 38' 20.936 W 6,032,972.11 1,654,901.95 700 15' 28.426 N 140' 38' 0.515 W 6,033,459.00 1,654,480.00 70' 15' 33.787 N 140' 38' 10.459 W 6,032,812.00 1,654,915.00 70' 15' 26.853 N 140' 38' 0.853 W 3Q-03AL1_Polygon 0.00 0.00 0.00 3,553.581,139,342.47 6,031,866.00 1,655,227.00 70' 15' 17.202 N 140' 37' 56.113 W plan hits target center Polygon Point 0.00 3,553.581,139,342.47 6,031,866.00 1,655,227.00 Point 0.00 4,785.701,139,345.06 6,033,098.00 1,655,226.94 Point 3 0.00 5,210.161,139,148.93 6,033,521.99 1,655,029.92 Point 0.00 5,442.181,138,674.37 6,033,752.97 1,654,554.90 Point 0.00 5,431.631,137,980.28 6,033,740.93 1,653,860.91 Point 0.00 5,467.351,137,638.32 6,033,775.91 1,653,518.91 Point 0.00 5,137.341,137,626.62 6,033,445.91 1,653,507.92 Point 8 0.00 4,933.561,138,465.28 6,033,243.95 1,654,346.93 Point 9 0.00 4,608.681,138,869.64 6,032,919.97 1,654,751.95 Point 10 0.00 3,478.431,138,936.27 6,031,789.98 1,654,821.00 Point 11 0.00 3,553.581,139,342.47 6,031,866.00 1,655,227.00 3Q-03AL1-01_T7 0.00 0.00 6,581.00 5,189.331,138,143.86 6,033,499.00 1,654,025.00 70° 15' 34.861 N 140° 38' 23.344 W plan hits target center Point 3Q-03A_Polygon 0.00 0.00 0.00 3,519.581,139,342.39 6,031,832.00 1,655,227.00 70° 15' 16.872 N 140° 37' 56.265 W plan hits target center - Polygon Point 1 0.00 3,519.581,139,342.39 6,031,832.00 1,655,227.00 Point 0.00 3,831.681,139,308.04 6,032,143.99 1,655,191.98 Point 0.00 4,157.201,138,602.65 6,032,467.96 1,654,485.96 Point 0.00 4,054.651,137,907.37 6,032,363.93 1,653,790.98 Point 5 0.00 4,126.531,137,016.43 6,032,433.88 1,652,899.97 11812014 12:25.28PM Pane 5 COMPASS 2003.16 Build 69 " � I P 1" 1 1\1 A L Baker Hughes INTEQ HL® ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox v16 Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3Q Pad Well: 3Q-03 W el I bo re: 3 Q-03AL 1-01 Design: 3Q-03AL1-01 wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 3Q-03 Mean Sea Level 3Q-03: @ 63.00ft (3Q-03) True Minimum Curvature Point 0.00 4,139.301,136,171.37 6,032,444.83 1,652,054.97 Point 0.00 3,956.961,134,897.86 6,032,259.77 1,650,781.98 Point 8 0.00 3,587.191,134,770.07 6,031,889.76 1,650,655.00 Point 0.00 3,630.861,135,881.27 6,031,935.82 1,651,765.99 Point 10 0.00 3,661.781,137,825.53 6,031,970.92 1,653,709.99 Point 11 0.00 3,659.861,138,740.62 6,031,970.97 1,654,624.99 Point 12 0.00 3,443.501,138,902.19 6,031,754.98 1,654,787.01 Point 13 0.00 3,519.581,139,342.39 6,031,832.00 1,655,227.00 3Q-03AL1-01_T5 0.00 0.00 6,606.00 5,049.981,138,762.63 6,033,361.00 1,654,644.00 70° 15' 32.589 N 140' 38' 6.187 W plan hits target center Point 3Q-03AL1-01_Fault6 0.00 0.00 0.00 5,229.941,137,832.32 6.033,538.94 1,653,713.40 70° 15' 35.717 N 14W 38' 32.113 W plan hits target center Rectangle (sides W360.00 H1.00 D0.00) 3Q-03AL1-01_Faultl 0.00 0.00 0.00 4,081.021,139,076.04 6,032,392.81 1,654,959.47 70' 15' 22.718 N 140' 38' 1.445 W plan hits target center Rectangle (sides W450.00 H1.00 D0.00) 3Q-03AL1-01_T9 0.00 0.00 6,585.00 5,282.421,137,642.01 6,033,591.00 1,653,523.00 70° 15' 36.509 N 14W 38' 37.348 W plan hits target center Point 3Q-03AL1-01_T10 0.00 0.00 6,579.00 5,284.861,137,434.00 6,033,593.00 1,653,315.00 70' 15' 36.842 N 140' 38' 43.311 W plan hits target center Point 3Q-03AL1-01_T2 0.00 0.00 6,563.00 4,425.331,139,035.31 6,032,737.00 1,654,918.00 70° 15' 26.120 N 140° 38' 1.102 W plan hits target center Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (in) (in) 120.00 57.00 16" 16.000 24.000 5,210.00 3,840.47 9 5/8" 9.625 12.250 12,259.00 6,585.97 2 3/8" 2.375 3.000 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (ft) (ft) (ft) (ft) Comment 9,775.00 6,504.72 6,567.34 -1,128.27 TIP 9,875.00 6,507.45 6,664.31 -1,104.76 KOP 10,000.00 6,518.42 6,782.62 -1,066.46 Start 8 dls 10,130.00 6,537.03 6,908.59 -1,041.18 4 10,300.00 6,556.45 7,077.07 -1,042.61 5 10,480.00 6,584.06 7,249.06 -1,086.05 6 10,605.00 6,599.90 7,366.92 -1,124.04 7 10,835.00 6,606.41 7,576.51 -1,216.13 8 11,035.00 6,605.71 7,727.56 -1,346.22 9 11,185.00 6,601.69 7,814.29 -1,468.20 10 11,425.00 6,590.58 7,895.71 -1,692.50 11 11,675.00 6,582.66 7,897.25 -1,941.10 12 11,825.00 6,578.82 7,887.77 -2,090.48 13 12,075.00 6,578.28 7,940.50 -2,333.56 14 12,200.00 6,583.90 7,977.45 -2,452.67 15 12,259.00 6,585.97 7,988.38 -2,510.59 TD at 12259.00 11812014 12:25.28PM Pape 6 COMPASS 2003.16 Build 69 n,�� ConocoPhillips ConocoPhillips (Alaska) Inc. -Ku p2 Kuparuk River Unit Kuparuk 3Q Pad 3Q-03 3Q-03AL1-01 3Q-03AL1-01_wp02 Travelling Cylinder Report 05 March, 2013 W, fAd'a"'-- I BAKER NUGHES ORIGINAL Baker Hughes /Gal ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3Q Pad Site Error. 0.00ft Reference Well: 3Q-03 Well Error: 0.00ft Reference Wellbore 3Q-03AL1-01 Reference Design: 3Q-03AL1-01_wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 3Q-03 3Q-03: @ 63.00ft (3Q-03) 3Q-03. @ 63.00ft (3Q-03) True Minimum Curvature 1.00 sigma EDM Alaska Prod v16 Offset Datum Reference 3Q-03AL1-01_wp02 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00ft Error Model: ISCWSA Depth Range: 9,775.00 to 12,259.00ft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,421.77ft Error Surface: Elliptical Conic Survey Tool Program Date 3/5/2013 From To (ft) (ft) Survey (Wellbore) Tool Name Description 50.00 9,350.00 3Q-03 GYD-CT-CMS (3Q-03) GYD-CT-CMS Gyrodata cont.casing m/s 9,350.00 9,477.00 3Q-03A_wp06 (3Q-03A) MWD MWD - Standard 9,477.00 9,775.00 3Q-03AL1_wp05 (3Q-03AL1) MWD MWD - Standard 9,775.00 12,259.00 3Q-03AL1-01_wp02 (3Q-03AL1-01) MWD MWD - Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name 120.00 120.00 16" 16 24 5,210.00 3,903.47 9 5/8" 9-5/8 12-1/4 12,240.00 6,648.68 2 3/8" 2-3/8 3 Summary Site Name Offset Well - Wellbore - Design Kuparuk 3Q Pad 3Q-03 - 3Q-03A - 3Q-03A_wp06 3Q-03 - 3Q-03AL1 - 3Q-03AL1_wp05 Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Depth Depth Distance (ft) from Plan (ft) (ft) (ft) (ft) 11,922.34 10,875.00 1,197.20 133.97 1,066.61 Pass - Major Risk 9,875.00 9,875.00 0.00 2.08 -1.55 FAIL - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 31512013 8:05:25AM Page 2 of 5 COMPASS 2003.16 Build RIGINIAL Baker Hughes Fel.. ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3Q Pad Site Error: O.00ft Reference Well: 3Q-03 Well Error: 0.00ft Reference Wellbore 3Q-03AL1-01 Reference Design: 3Q-03AL1-01_wp02 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 3Q-03 30-03: @ 63.00ft (3Q-03) 3Q-03: @ 63.00ft (310-03) True Minimum Curvature 1.00 sigma EDM Alaska Prod v16 Offset Datum Reference Depths are relative to 3Q-03: @ 63.00ft (3Q-03) Coordinates are relative to: 3Q-03 Offset Depths are relative to Offset Datum Coordinate System is US State Plane 1927, Alaska Zone 4 Central Meridian is 150' 0' 0.000 W ° Grid Convergence at Surface is: 0.120 Ladder Plot 1400 1050 0 `m W U) 700 U 0 a> C N U 350 0 0 2000 4000 6000 8000 10000 12000 Measured Depth LEGEND $ 3Q-03, 3Q-03A, 3Q-03A vvp06 VO -f— 3Q-03, 3Q-03AL1, 3Q-03AL1_vvp05 VO 11- I I I I I I I I I I I I 1 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I 1 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I 1 I I I I I I I I I I I I I I i I I I I I I I I I I I I I i I I I I I I I I I I I I I I I I I I I 1 I i I I I I I i I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I 1 I I I I I I I I 1 I I I I I I I I I INA CC -Min centre to center distance or covergent point, SF -min separation factor, ES -min ellipse separation 3/5/2013 8:05:25AM Page 5 of 5 COMPASS 2003.16 Build 69 Lug= `tgo sz 4 S J a a 4O J M 4 n o,"qry40 Y Yw$��a�''' N N 5 d 4 a �a 4 Q a ommmmmmmmmmmmmm loom■■■■■moo■■■■ 1■■■■m■■■mi■■■■■■ 1■■■��►a®A I8q l�i:��l�■ 1■ I■i�■�a■■■mI�■II � Imo 1� Imii��!i■■oi1�■■� 1■■� loom m■■■■III■■�I■■ 1m 4 0�� a m aIy Z�I w z$ w z p c o H v O Z m 5�ommNwN�wNNww N� Q000mmmmmmmmmmmmm .ome� 0 wmmm�n n�°r°rrtin�r N mmno cvn mmmrnrnrn m m m m m m m m m m m m m m m v ovornvrm°,n°.mc.�Nam �- �Nm gj c��N.'>,n mvmiN�m�nN��imm �0000000000000aoo �Wimo am Ui Ii omaIimo ---- gym-mom,--�����2� 0 R I G" I N A L Iana-1 eag UeGIN (U!/I3 OL) uld3a Inoivan an1Z Ln s a S 0 c a < / � @ ■ \ n F turvrv�)(,Ilr( 9mS ® L L A-L ' �, 179L 1L R �ZJHE'- ,C-Q,1. WELL NAI�,IE: -- lc�_3 C� �3 AL_ V [i�:��i��j�in��,t F'`ClCTi,: Check Box for Appropr-ia.e Letter / Paragraphs to i3e Included in T➢'ansmaitta Letter- CHEC'N OPTIONS TEXT FOR APPROVAL LETTER MULTI _ c �perinjt is for a new wellbore segment of exis1i112 WC11 Permit hh /ILA"I1:RAl. No. 51 -- (11 last two dlulls Production should continue to be reported as a function o the ortglllal in API number are All] number stated above. between 60-69) In accordance with 20 AAC 25.005(f). all records. data and locus acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - - ) from records, data and logs acquired for well (name onpermit). The pennit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this pen -nit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 5/2013 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 PTD#:2130270 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Administration 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes 3 Unique well name and number Yes 4 Well located in a defined pool Yes 5 Well located proper distance from drilling unit boundary Yes 6 Well located proper distance from other wells Yes 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes Appr Date 11 Permit can be issued without conservation order Yes PKB 1/13/2014 12 Permit can be issued without administrative approval Yes 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 Well Name: KUPARUK RIV UNIT 3Q-03AL1-01 Program DEV Well bore seg DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disoosal 18 Conductor string provided NA Engineering 19 Surface casing protects all known USDWs NA 20 CMT vol adequate to circulate on conductor & surf csg NA 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons No 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes VLF 1/16/2014 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes 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 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Geology 36 Data presented on potential overpressure zones Yes Appr Date 37 Seismic analysis of shallow gas zones NA PKB 1/13/2014 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA - - - ADL0025512 Surf loc; ADL0373301 Top Prod Interval; ADL0355024 TD KRU 3Q-03AL1-01 KUPARUK RIVER, KUPARUK RIV OIL - 490100; governed by Conservation Order No. 432C CO No. 432C contains no spacing restrictions with respect to drilling unit boundaries CO No. 432C has no interwell spacing restrictions Wellbore will be more than 500' from an external property line where ownership or landownership changes. Conductor set in KRU 3Q-03 Surface casing set in KRU 3Q-03 Surface casing fully cemented Productive interval will be completed with slotted liner Rig has steel pits. All waste to approved disposal wells Proximity analysis performed. Max expected formation pressur 5039 psi(EMW 14.8 ppg) Drill w/10 ppg and overbalance w/ MPD MPSP 4386 psi; will test _BOPs-to 4800psi H2S measures required Wells on 3Q-Pad are H2S bearing. H2S measures_ required. Expected reservoir pressure is 10.6 ppg EMW, will be drilled using 10.0_ppg mud and managed pressure drilling technique. Two wellbore volumes of 12_.2 ppg emergency -kill weight fluid will_ be available. Geologic Commissioner: Date: Engineering Commissioner: Date Pu Comm Date / e s y THE STATE Alaska ! `LU and Gas 01ALASKA C.Gnwrvaticon Oarnfcnllss�'Gli GOVERNOR SEAN PARNELL 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Lamar Gantt CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, 3Q-03AL1-01 ConocoPhillips Alaska, Inc. Permit No: 213-027 Surface Location: 2211' FNL, 2328' FEL, SEC. 17, T13N, R09E, UM Bottomhole Location: 507' FSL, 469' FWL, SEC. 5, T13N, R09E, UM Dear Mr. Gantt: 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 3Q-03A, Permit No 213-016, API 50-029-22221-01-00. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, icy-,-- Cathy P Foerster Chair DATED this Z& day of February, 2013. RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 FEB 2 12013 AGCG 1a. Type of Work: Drill ❑ Lateral Redrill ❑ Reentry ❑ 1 b Proposed Well Class: Development - Oil ❑ Service - Winj ❑ Single Zone ❑ Stratigraphic Test ❑ Development -Gas ❑ Service - Supply ❑ Multiple Zone ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ 1c. Specify if well is proposed for: Coalbed Gas ❑ Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Bond: ✓ Blanket Lj Single Well Bond No. 59-52-180 ' 11. Well Name and Number: 3Q-03AL1-01 ' 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 12240' • TVDSS: 6581' • 12. Field/Pool(s): Kuparuk River Field Kuparuk River Oil Pool • 4a. Location of Well (Governmental Section): Surface: 2211' FNL, 2328' FEL, Sec. 17, T13N, R09E, UM - Top of Productive Horizon: 1366' FNL, 1899' FWL, Sec. 8, T13N, R09E, UM Total Depth: 507' FSL, 469' FWL, Sec. 5, T13N, R09E, UM 7. Property Designation (Lease Number)' AFL 3 ADL 25512, 373301 ' ZZjVj3 8. Land Use Permit: 2553, 4162 13. Approximate Spud Date: 3/7/2013 9. Acres in Property: L '- 8 �u 4. Distance to Nearest Property: 4870 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 516008 y- 6025861 Zone- 4 10. KB Elevation above MSL: 63 feet GL Elevation above MSL: 21.7 feet 15. Distance to Nearest Well Open to Same Pool: 3R-18 , 2400' 16. Deviated wells: Kickoff depth: 9800 ft. Maximum Hole Angle: 93° deg 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 5039 psig - Surface: 4386 psig . 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks stage data Hole Casing Weight Grade Couolinq Len th MD TVDSS MD TVDSS(including 3" 2.375" 4.7# L-80 ST-L 2970' 9270' 12240' 6414' 6581' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 9640' Total Depth TVD (ft): 6758' Plugs (measured) none Effective Depth MD (ft): 9516 Effective Depth TVD (ft): 6664 Junk (measured) none Casing Length Size Cement Volume MD TVD Conductor/Structural 80' 161, 1875 sx Poleset 120' 120' Surface 5170' 9.625" 1240 sx PF E, 495 sx Cl G 5210' 3906' Intermediate Production 9573' T 212 sx Class G 9605' 6732' Liner Perforation Depth MD (ft): 9361-9401' VD Perforation Depth T(ft): 6548'-6578' 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Program u Time v. Depth Plot ❑ Shallow Hazard Analysis Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑ 20 AAC 25.050 requirements ❑✓ 21. Verbal Approval: Commission Representative: Date: 22. 1 hereby certify that the foregoing is true and correct. Contact J. Gary Eller @ 263-4172 't Email J.Gary. Eller(c�conocoohillios. om Printed Name Lamar Gantt Title CTD Engineering Supervisor Signature LC 1v�A Phone 263-4021 Date 2 26 Q Commission Use Only Permit to Drill Number: 3 API Number: 50- OZ9 _ �;Z.> _ �' _ d d Permit Approv Date: See cover letter for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: n � f� /L�GQ S f Samples req'd: Yes ❑ No � Mud log req'd: Yes❑ No 1� 7 H2S measures: Yes Z No r❑� Directional svy req'd: Yes M No ❑ Spacing exception req'd: Yes ❑ No L� Inclination -only svy req'd: Yes ❑ No 42 APPROVED BY THE LIC) -- Approved by: COMMISSIONER COMMISSION Date: 2- Form 10-401 (R�vised 10/2012) This permit is�Gfid4ot 24 months from the date of approval (20 AAC 25.005(g)) �'LF z/Z6/1`3 ConocoPs philli Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 19, 2013 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: RECEIVED FEB 2 12013 ConocoPhillips Alaska, Inc. hereby submits a Permit to Drill (PTD) application to drill and complete 3Q-03AL1-01 and an amended application to #213-017 for lateral 3Q-03AL1. CTD operations are now scheduled to begin March 7, 2013 using the Nabors CDR2-AC rig. The addition of the 3Q-03AL1-01 lateral and the amendment to 3Q-03AL1 were made in response to a change in plans regarding crossing of a major fault. The updated plan calls for drilling a portion of the 3Q-03AL1 as a `pilot hole' to gauge the throw and location of the fault, thus the planned total depth of the 3Q-03AL1 lateral has been shortened drastically. The 3Q-03AL1-01 is being added then to achieve the original objectives of the 3Q-03AL1 lateral, and in map -view it looks very similar to the original 3Q-03AL1 plan that was approved via PTD #213-017. An updated drilling summary plan is attached with new information displayed in blue font. One other item is updated in the attached drilling summary. An updated static pressure survey in well 3Q-03 was taken on February 13 which showed a significant increase over the pressure that was taken in December 2012. The updated summary reflects the change in fluid weights and target drilling pressures that will be required to over -balance this increased formation pressure. No change is needed to the planned BOP test pressure as this was conservatively based on the maximum potential formation pressure in the area. Attached to this application are the following documents that explain the proposed job operations. A BOP schematic for slimhole CTD operations from Nabors CDR2 is already on file with the Commission. — Drilling program summary (updates in blue font) — Amended Permit to Drill application form for 3Q-03AL1 — Permit to Drill application form for 3Q-03AL1-01 — Directional plans for 3Q-03AL1 (amended) and 3Q-093AL1-01 — Proposed wellbore schematic If you have any questions or require additional information please contact me at my office 907-263-4172. incer Y J. Ga Eller \, Conoco dips Xi a Coiled Tubing Drilling Engineer Kuparuk CTD Sidetrack NABORS ALASKA 3Q-03A, AL19 & AL1-01 CDR, Drilling Program Summary 2RC Updates are shown in blue font 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(o and 20 AAC 25.005(b)).................................................................................................................. 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2))................................................................................................................................................. 2 3. Blowout Prevention Equipment Information................................................................................ 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................ 2 4. Drilling Hazards Information and Reservoir Pressure................................................................. 2 (Requirements of 20AAC 25.005(c)(4))................................................................................................................................................ 2 5. Procedure for Conducting Formation Integrity tests................................................................... 3 (Requirements of 20 AAC 25.005(c) (5))................................................................................................................................................. 3 6. Casing and Cementing Program................................................................................................... 3 (Requirements of 20 AAC 25.005 c 6.................................................................. 3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7))................................................................................................................................................. 3 6. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005(c)(8))................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9))................................................................................................................................................. 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))............................................................................................................................................... 4 11. Seabed Condition Analysis............................................................................................................ 4 (Requirements of 20 AAC 25.005(c)(11))............................................................................................................................................... 4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005(c) (12))............................................................................................................................................... 4 13. Proposed Drilling Program............................................................................................................ 4 (Requirements of 20 AAC 25.005(c)(13))............................................................................................................................................... 4 Summaryof Operations.................................................................................................................................................. 4 PressureDeployment of BHA.......................................................................................................................................... 5 LinerRunning..................................................................................................................................................................6 14. Disposal of Drilling Mud and Cuttings.......................................................................................... 6 (Requirements of 20 AAC 25.005(c)(14))............................................................................................................................................... 6 15. Directional Plans for Intentionally Deviated Wells....................................................................... 6 (Requirements of 20 AAC 25.050(b))..................................................................................................................................................... 6 Attachment 1: Directional Plans for 3Q-03A, 3Q-03AL1 (amended), & 3Q-03AL1-01................................................... 6 Attachment 2: Current Well Schematic for 3Q-03.......................................................................................................... 6 Attachment 3: Proposed Well Schematic for 3Q-03 CTD Sidetrack (updated).............................................................. 6 Page 1 of 6 Updated February 19, 2013 PTD Applications fog .M 3Q-03A, AL1 & AL1-01 1. Well Name and Classification (Requirements of 20 AAC 25.005(1) and 20 AAC 25.005(b)) KRU 3Q-03A, 3Q-03AL1, and 3Q-03AL1-01 are proposed CTD horizontal laterals from the 3Q-03 motherbore. They will all be classified as "Development - OX wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) The 3Q-03 laterals will target the All sand in the Kuparuk reservoir. See the attached 10-401 form for surface and subsurface coordinates of the 3Q-03A sidetrack and the 3Q-03AL1 and 3Q-03AL1-01 laterals. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR2-AC. BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and 4800 psi. Using a maximum potential formation pressure of 5039 psi, the maximum potential surface pressure is 4386 psi assuming a gas gradient of 0.1 psi/ft. See the "Drilling Hazards Information and Reservoir Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2500 psi. 4. Drilling Hazards Information and Reservoir Pressure (Requirements of 20 AAC 25.005 (c)(4)) Reservoir Pressure and Maximum Downhole Pressure An updated static BHP survey was taken in 3Q-03 on February 13, 2013. That survey showed that formation pressure had increased to 4105 psi compared to 3759 psi in December 2012. It represents an increase in formation pressure from of 11.0 ppg to 12.1 ppg EMW due to continued injection into well 3Q-01. Well 3Q-01 was shut-in the day after that static pressure survey was made, and we anticipate the formation pressure around 3Q-03 to now stabilize. The increase to 12.1 ppg formation pressure has caused us to adjust our fluid weights and target drilling pressures, and those adjustments are included in this update. We plan to make one more static pressure measurement in 3Q-03 prior to plugging it with cement, and we will adjust fluid weights and target drilling pressures accordingly. Maximum potential formation pressure is based on two offset injectors. 3Q-01 is the closest offset injector to the south, but we're unable to obtain a bottomhole pressure measurement in it. Surface pressure measurements in 3Q-01 indicate a formation pressure of 4960 psi at 6544' TVD for a gradient of 14.6 ppg. 3Q-12 is the next injector south of 3Q-01, and a static bottomhole pressure survey in December 2012 shows a formation pressure of 4990 psi at 6479' TVD for a gradient of 14.8 ppg. Using the measurement taken in 3Q- 12, in 3Q-03 this equates to a maximum potential formation pressure of 5039 psi (9357' MD, 6543' TVD) and a maximum potential surface pressure of 4386 psi assuming a gas gradient to surface. Even with the static pressure increase observed in 3Q-03 these offset pressures still represent the highest potential formation pressure in the area, so no modification is needed to the planned BOP test pressure of 4800 psi. Potential Gas Zones No specific gas zones will be drilled, but 3Q pad is located in an area of active miscible gas injection. It is likely that an influx can produce a significant amount of gas. Potential Causes of Hole Problems The major expected downhole risk in the 3Q-03 laterals is hole stability due to interbedded shales in the A -sand, the underlying Miluveach shale, and the overlying D shale. We will mitigate hole instability by maintaining a minimum ECD target of 13.0 ppg EMW at the window while drilling the CTD sidetrack, as well as using mud additives that minimize chemical instability. A second downhole risk is having adequate weight transfer to drill to the planned TD of 13,850' MD in 3Q-03A. We will mitigate that risk by maintaining very low doglegs in the sidetrack and maintaining mud lubricity. Page 2 of 6 `9�. b" Updated February 19, 2013 PTD Applications fog �RU 3Q-03A, AL1 & AL1-01 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 3Q-03 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity test is not required. 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Sidetrack Liner Liner Liner Liner Name Top MD Btm Top Btm Liner Details MD SSTVD SSTVD 3Q-03A 9445' 13,850' 6532' 6474' 2%", 4.7#, L-80, ST-L slotted liner with aluminum billet 3Q-03AL1 9800' 10,400' 6506' 6538' 2%", 4.7#, L-80, ST-L slotted liner with aluminum bilet 3Q-03AL1-01 9270' 12,240' 6414' 6581' 2%", 4.7#, L-80, ST-L slotted liner up inside 3'/2" tubing tail Existing Casing/Liner Information Category OD Wt Grade Cxn Top MD Btm MD Top TVD Btm TVD Burst psi Col. psi Conductor 16" 62 H-40 Welded 0' 121' 0' 115' n/a n/a Surface Cs 9%" 36 J-55 BTC 0' 5210' 0' 3903' 3520 2020 Prod Cs 7" 26 J-55 BTC 0' 9605' 0' 6729' 4980 4320 Tubing 3'/2" 9.3 J-55 g d Mod 0' 9284' 0' 6488' 6990 7400 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) Nabors CDR2-AC will be operating under 20 AAC 25.036 for thru-tubing drilling operations so no diverter system is required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System A diagram of the Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System — Window milling operations: Chloride -based Biozan brine or used drilling mud (-10.0 ppg) — Drilling operations: Chloride -based Flo -Pro Flo Vis mud (10.0 ppg). This mud weight alone will not hydrostatically overbalance formation pressure in the 3Q-03 motherbore, but overbalanced conditions will be maintained using MPD practices described below. — Completion operations: Well 3Q-03 is equipped with a subsurface safety valve (SSSV) but it is not functioning. Therefore, the well will be loaded with over -balancing completion fluid while picking up jointed liner. We anticipate using 13.0 ppg completion fluid to provide over -balance while picking up liner. — Emergency Kill Weight fluid: Two well bore volumes (-240 bbl) of 13.1 ppg emergency kill weight fluid will be within a short drive of the rig during drilling operations. Page 3 of 6 ) 7) 1 r I Updated February 19, 2013 PTD Applications fok .%RU 3Q-03A, AL1 & AL1-01 Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole formation throughout the coiled tubing drilling (CTD) process. Maintaining a constant BHP promotes wellbore stability, particularly in shale sections, while at the same time providing pressure over- balance to the formation. In the 3Q-03 laterals we will target a constant BHP of 13.0 ppg EMW at the window. 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. Pressure at the 3Q-03A Window (9357' MD, 6543' TVD, 6480' SSTVD) Usinq MPD Pumps On (1.5 b m) Pumps Off A -sand Formation Pressure 12.1 4117 psi 4117 psi Mud Hydrostatic 10.0 3402 psi 3402 psi Annular friction i.e. ECD, 0.095 si/ft 889 psi 0 psi Mud + ECD Combined 4291 psi 3402 psi (no choke pressure) (overbalanced (underbalanced -170psi) -715psi) Target BHP at Window 13.0 4423 psi 4423 psi Choke Pressure Required to Maintain 130 psi 1020 psi Target BHP 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005(c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005(c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A - Application is not for an exploratory or stratigraphic test well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations In well KRU 3Q-03, the 7" casing below the 3%2" tubing tail will be filled with 17 ppg cement to facilitate a cement pilot exit of the 7" casing. This cement will also effectively plug the existing perfs in 3Q-03, but there is insufficient room to plug the perfs in accordance with 20 AAC 25.112 (c). ConocoPhillips requests a variance from 20 AAC 25.112 (c) to plug the perfs in 3Q-03 in this manner. The proposed plugging procedure meets the overall objective of this section, providing an equally effective plugging of the well to prevent migration of fluids to other hydrocarbon zones or freshwater. The 3Q-03A sidetrack will be drilled west of 3Q-03 to increase reservoir exposure and improve waterflood sweep in the Al sand. After milling a pilot hole in the cement inside the 7" casing, a whipstock will be set and a window milled at 9357' MD to exit the 7" casing. The sidetrack will target the Al sand west of the existing well with a 4493' lateral. The hole will be completed with a 23/" slotted liner to the TD of 13,850' MD with an aluminum billet placed at 9477' MD. Page 4 of 6 Updated February 19, 2013 PTD Applications foi ..RU 3Q-03A, AL1 & AL1-01 The 3Q-03AL1 lateral will be drilled north/west of 3Q-03 targeting the Al sand with a 1168' lateral. After kicking off the aluminum billet at 9477' MD, the lateral will be drilled to a TD of 10,645' MD. A portion of this lateral will serve as a pilot hole to gauge the location and displacement of a major fault, and the borehole hole beyond the fault will not be completed. The hole will be completed with a 2%" slotted liner to—10,400' MD with an aluminum billet placed at 9800' MD. The 3Q-03AL1-01 lateral will be drilled north/west of 3Q-03 targeting the Al sand with a 2440' lateral. After kicking off the aluminum billet at 9800' MD, the lateral will be drilled to a TD of 12,240' MD. The hole will be completed with a 23/" slotted liner to TD with the final liner top located inside the 3%2" tubing tail at 9270' MD. Pre-CTD Work 1. MIRU slickline. Dummy all GLMs. Run whipstock dummy inside 3%2" tubing. 2. MIRU e-line. Shoot circulating holes in the 3%2" tubing tail at 9273'. 3. MIRU coiled tubing. Mill out the 2.75" XN nipple at 9276' to 2.80" ID. 4. Lay in a 17 ppg cement plug inside the 7" casing from PBTD up to the circulating holes at 9273', squeezing off all existing perfs. Apply squeeze pressure. Wait on cement to set. 5. MIRU slickline. Tag top of cement and pressure test to 1500 psi. 6. 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. 3Q-03A Sidetrack (Al sand, west) a. Mill cement pilot hole inside 7" casing to 9387' MD b. Set whipstock in the cement pilot hole at 9357' MD c. Mill 2.80" window through 7" casing at 9357' MD d. Drill 2.70" x 3" bi-center sidetrack to TD of 13,850' MD e. Run 2%" slotted liner with an aluminum billet from TD up to 9445'. The well will be loaded with over -balancing fluid to provide well control while picking up slotted liner. 3. 3Q-03AL1 Lateral (Al sand, north/west) a. Kick off from aluminum billet at 9445' b. Drill 2.70" x 3" bi-center sidetrack to TD of 10,645' MD c. Run 2%" slotted liner with an aluminum billet from 10,400' up to 9800'. The well will be loaded with over -balancing fluid to provide well control while picking up slotted liner. 4. 3Q-03AL1-01 Lateral (Al sand, north/west) a. Kick off from aluminum billet at 9800' b. Drill 2.70" x 3" bi-center sidetrack to TD of 12,240' MD c. Run 2'/" slotted liner from TD up to 9270' inside the 3'/2" tubing tail. The well will be loaded with over -balancing fluid to provide well control while picking up slotted liner. 5. Freeze protect. 6. Set BPV, ND BOPE. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV 2. MIRU slickline. Install gas lift design. Perform static BHP survey. 3. Put well on production. Pressure Deployment of BHA The planned bottomhole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. Because of this, MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double Page 5 of 6 Updated February 19, 2013 PTD Applications for _ RU 3Q-03A. AL1 & AL1-01 ball valves in the BHA, and a slickline lubricator. This pressure control equipment ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. - Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. - Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slickline. - When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. - The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment the steps listed above are conducted in reverse. Liner Running - Well 3Q-03 is equipped with a non-functioning SSSV, so fluid of sufficient density to over -balance the formation will be used to provide formation over -balance while picking up slotted liner. See the "Drilling Fluids" section for more details. - While running 2%" slotted liner, a joint of 23/" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 23/" pipe rams provide secondary well control while running 23/" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AA 25.005(c)(14)) - No annular injection on this well. - Class II liquids to KRU 1 R 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. 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AA 25.050(b)) - There are no other affected owners - Please see attached directional plans for each lateral. - Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. - MWD directional, resistivity, and gamma ray will be run over the entire openhole section. - Distance to nearest property line and nearest well in the same pool. Sidetrack Name Directional Plan Distance to Unit Boundary Distance to Nearest Well Nearest Well 3Q-03A 05 -6290' -2400' 3R-18 3Q-03AL1 05 -4870' -2400' 3R-18 3Q-03AL1-01 01 -4870' -2400' 3R-18 Attachment 1: Directional Plans for 3Q-03A, 3Q-03AL1 (amended), & 3Q-03AL1-01 Attachment 2: Current Well Schematic for 3Q-03 Attachment 3: Proposed Well Schematic for 3Q-03 CTD Sidetrack (updated) Page 6 of 6 Updated February 19, 2013 Cl) ❑ ❑' N _ CD p O N J p_ M � O O it � Q C M F-J D) Cl) N Q W s 001 Q n I- cli ❑ V _ O LO OU7 CR con N Q — On ❑ co II N s U' ❑ ._C N co M❑ O O� M F--j NcG N 2i cO t In ❑ zor a0 rn O (O N V U@ �` C v [V 9 J O m E V Ol m ❑ N fm (rQj F.2L a m v Q C °' rn 1318 a Z Sao \\ Qa w (L mn, a)—° i to y a� .0 a U ' p (V O p C ❑ E E SEE coo rn t U Oi m O O a U LO N N W N 01 fV (V cV N E E N N m O L p 0 Cl) (1) 00 U U 01 'C O O-= n /ID C? / Cl) N E a) c a /a F-- Z WNW ❑ V a W IJ O O to u O❑ L L top y In Q N N C Cl) N OI N N U O� L E cl L N V -'�❑ U a � ❑ dCD co (D O [V o (iOnDN IN mpLoO H R i0 L r Cl) W @ � ConocoPhillips Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 3Q Pad 3Q-03 3Q-03AL1-01 Plan: 3Q-03AL1-01_wp01 Standard Planning Report 18 February, 2013 a PP-_ BAKER HUGHES ConocoPhillips Alaska Database: EDM Alaska Prod v16 Company: ConocoPhillips(Alaska) Inc. Project: Kuparuk River Unit Site: Kuparuk 3Q Pad Well: 3Q-03 Welibore: 3Q-03AL 1-01 Design: 3Q-03AL 1-01_wp01 Baker Hughes Planning Report Local Co-ordinate Reference: Well 3Q-03 TVD Reference: Mean Sea Level MD Reference: 3Q-03: @ 63.O0ft (3Q-03) North Reference: True Survey Calculation Method: Minimum Curvature Project Kuparuk River Unit Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor F/.RI BAKER HUGHES Site Kuparuk 3Q Pad Site Position: Northing: 6,025,873.14ft Latitude: 70° 28' 54.757 N From: Map Easting: 515,959.89ft Longitude: 149° 52' 10.513 W Position Uncertainty: 0.00 ft Slot Radius: Grid Convergence: 0.12 ° Well 3Q-03 Well Position +N/-S 0.00 ft Northing: 6,025,861.28 ft Latitude: 70° 28' 54.639 N +E/-W 0.00 ft Easting: 516,008.42 ft Longitude: 149° 52' 9.086 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 21.70 ft Welibore 3Q-03AL1-01 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (I (I (nT) BG G M2011 12/31 /2012 15.90 80.04 57,392 Design 3Q-03AL1-01_wp01 Audit Notes: Version: Phase: PLAN Tie On Depth: 9,800,00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (ft) (ft) (ft) (°) -21.70 0.00 0.00 315.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (ft) (°) (°) (ft) (ft) (ft) (°/100ft) (°1100ft) (°/100ft) (°) Target 9,800.00 87.81 10.69 6,505.82 6,591.99 -1,124.27 0.00 0.00 0.00 0.00 9,950.00 75.81 10.69 6,527.16 6,737.61 -1,096.77 8.00 -8.00 0.00 180.00 10,075.00 82.34 2.98 6,550.88 6,859.32 -1,082.27 8.00 5.23 -6.17 310.00 10,275.00 87.50 347.77 6,568.69 7,057.22 -1,098.39 8.00 2.58 -7.61 288.00 10,425.00 85.48 359.62 6,577.91 7,205.75 -1,114.82 8.00 -1.34 7.90 100.00 10,725.00 85.87 335.55 6,600.87 7,495.73 -1,178.66 8.00 0.13 -8.02 270.00 10,875.00 89.24 324.02 6,607.29 7,625.00 -1,253.94 8.00 2.25 -7.69 286.00 11,275.00 92.79 292.21 6,600.01 7,868.72 -1,564.48 8.00 0.89 -7.95 276.50 11,425.00 92.73 280.20 6,592.76 7,910.46 -1,708.08 8.00 -0.04 -8.01 270.00 11,675.00 91.54 260.22 6,583.34 7,911.35 -1,956.64 8.00 -0.48 -7.99 267.00 12,075.00 89.19 292.14 6,580.71 7,953.84 -2,349.16 8.00 -0.59 7.98 94.00 12,240.00 90.35 278.99 6,581.38 7,998.01 -2,507.75 8.00 0.70 -7.97 275.00 211812013 10:37.49PM Page 2 COMPASS 2003.16 Build 69 �' Baker Hughes WE as ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 3Q-03 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 3Q-03: @ 63.00ft (3Q-03) Site: Kuparuk 3Q Pad North Reference: True Well: 3Q-03 Survey Calculation Method: Minimum Curvature Wellbore: 3Q-03AL 1-01 Design: 3Q-03AL 1-01 _wp 01 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +NI-S +El-W Section Rate Azimuth Northing Easting (ft) 1°) (1) (ft) (ft) (ft) (ft) (°/100ft) (1) (ft) (ft) 9,800.00 87.81 10.69 6,505.82 6,591.99 -1,124.27 5,456.22 0.00 0.00 6,032,450.18 514,870.08 TIPIKOP 9,900.00 79.81 10.69 6,516.60 6,689.60 -1,105.84 5,512.21 8.00 -180.00 6,032,547.82 514,888.30 9,950.00 75.81 10.69 6,527.16 6,737.61 -1,096.77 5,539.74 8.00 -180.00 6,032,595.85 514,897.27 Start 8 DLS 10,000.00 78.40 7.57 6,538.32 6,785.72 -1,089.04 5,568.30 8.00 -50.00 6,032,643.97 514,904.89 10,075.00 82.34 2.98 6,550.88 6,859.32 -1,082.27 5,615.55 8.00 -49.30 6,032,717.57 514,911.50 3 10,100.00 82.96 1.06 6,554.07 6,884.10 -1,081.39 5,632.45 8.00 -72.00 6,032,742.35 514,912.32 10,200.00 85.52 353.45 6,564.12 6,983.40 -1,086.17 5,706.04 8.00 -71.75 6,032,841.63 514,907.33 10,275.00 87.50 347.77 6,568.69 7,057.22 -1,098.39 5,766.88 8.00 -70.99 6,032,915.41 514,894.96 4 10,300.00 87.15 349.74 6,569.86 7,081.71 -1,103.26 5,787.65 8.00 100.00 6,032,939.89 514,890.04 10,400.00 85.80 357.64 6,576.01 7,180.83 -1,114.22 5,865.49 8.00 99.91 6,033,038.98 514,878.86 10,425.00 85.48 359.62 6,577.91 7,205.75 -1,114.82 5,883.53 8.00 99.42 6,033,063.90 514,878.21 5 10,500.00 85.50 353.60 6,583.81 7,280.36 -1,119.23 5,939.41 8.00 -90.00 6,033,138.49 514,873.63 10,600.00 85.61 345.58 6,591.57 7,378.33 -1,137.23 6,021.42 8.00 -89.53 6,033,236.41 514,855.43 10,700.00 85.81 337.56 6,599.06 7,472.86 -1,168.74 6,110.53 8.00 -88.90 6,033,330.86 514,823.72 10,725.00 85.87 335.55 6,600.87 7,495.73 -1,178.66 6,133.72 8.00 -88.30 6,033,353.71 514,813.75 6 10,800.00 87.54 329.78 6,605.19 7,562.22 -1,213.02 6,205.03 8.00 -74.00 6,033,420.12 514,779.25 10,875.00 89.24 324.02 6,607.29 7,625.00 -1,253.94 6,278.36 8.00 -73.67 6,033,482.80 514,738.20 7 10,900.00 89.47 322.04 6,607.58 7,644.97 -1,268.98 6,303.11 8.00 -83.50 6,033,502.74 514,723.12 11,000.00 90.38 314.09 6,607.71 7,719.30 -1,335.75 6,402.89 8.00 -83.48 6,033,576.91 514,656.19 11,100.00 91.28 306.14 6,606.26 7,783.67 -1,412.16 6,502.43 8.00 -83.47 6,033,641.12 514,579.66 11,200.00 92.16 298.18 6,603.26 7,836.83 -1,496.71 6,599.81 8.00 -83.58 6,033,694.09 514,495.00 11,275.00 92.79 292.21 6,600.01 7,868.72 -1,564.48 6,670.28 8.00 -83.82 6,033,725.83 514,427.17 8 11,300.00 92.79 290.21 6,598.79 7,877.76 -1,587.75 6,693.12 8.00 -90.00 6,033,734.81 514,403.88 11,400.00 92.75 282.20 6,593.95 7,905.61 -1,683.59 6,780.59 8.00 -90.10 6,033,762.46 514,307.99 11,425.00 92.73 280.20 6,592.76 7,910.46 -1,708.08 6,801.34 8.00 -90.49 6,033,767.25 514,283.49 9 11,500.00 92.40 274.20 6,589.39 7,919.84 -1,782.38 6,860.51 8.00 -93.00 6,033,776.48 514,209.18 11,600.00 91.93 266.21 6,585.61 7,920.20 -1,882.23 6,931.36 8.00 -93.27 6,033,776.62 514,109.34 11,675.00 91.54 260.22 6,583.34 7,911.35 -1,956.64 6,977.72 8.00 -93.57 6,033,767.61 514,034.96 10 11,700.00 91.40 262.21 6,582.70 7,907.53 -1,981.33 6,992.48 8.00 94.00 6,033,763.74 514,010.27 11,800.00 90.82 270.20 6,580.75 7,900.92 -2,081.01 7,058.29 8.00 94.05 6,033,756.91 513,910.62 11,900.00 90.23 278.17 6,579.83 7,908.21 -2,180.66 7,133.91 8.00 94.21 6,033,763.99 513,810.96 12,000.00 89.63 286.15 6,579.94 7,929.26 -2,278.34 7,217.86 8.00 94.28 6,033,784.83 513,713.25 12,075.00 89.19 292.14 6,580.71 7,953.84 -2,349.16 7,285.32 8.00 94.27 6,033,809.26 513,642.39 11 12,100.00 89.37 290.14 6,581.03 7,962.86 -2,372.47 7,308.18 8.00 -85.00 6,033,818.22 513,619.06 12,200.00 90.07 282.17 6,581.52 7,990.67 -2,468.44 7,395.70 8.00 -84.97 6,033,845.82 513,523.04 12,240.00 90.35 278.99 6,581.38 7,998.01 -2,507.75 7,428.70 8.00 -84.94 6,033,853.08 513,483.71 TD at 12240.00 211812013 10:37:49PM Page 3 COMPASS 2003.16 Build 69 Baker Hughes ConocoPhillips Planning Report Alaska Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 3Q-03 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-03: @ 63.00ft (3Q-03) Site: Kuparuk 3Q Pad North Reference: True Well: 3Q-03 Survey Calculation Method: Minimum Curvature Wellbore: 30-03AL1-01 Design: 3Q-03AL1-01 _wp01 B►KER%s HUGHES Targets Target Name hit/miss target Dip Angle Dip Dir. 11VD +NI-S +EI-W Northing Easting Shape 111 (1) (ft) (ft) (ft) IN (ft) Latitude Longitude 3Q-03AL1_Polygon (cop 0.00 0.00 0.00 6,255.18 -799.64 6,032,114.10 515,195.40 70° 29' 56.157 N 149' 52' 32.626 W plan misses target center by 6522.61ft at 9800.00ft MD (6505.82 TVD, 6591.99 N,-1124.27 E) Polygon Point 1 0.00 6,255.18 -799.64 6,032,114.10 515,195.40 Point 0.00 7,487.30 -797.05 6,033,346.10 515,195.34 Point 3 0.00 7,911.76 -993.18 6,033,770.10 514,998.32 Point 0.00 8,143.78 -1,467.74 6,034,001.07 514,523.31 Point 5 0.00 8,133.23 -2,161.83 6,033,989.03 513,829.31 Point 0.00 8,168.95 -2,503.79 6,034,024.01 513,487.31 Point 7 0.00 7,838.94 -2,515.49 6.033,694.01 513,476.32 Point 0.00 7,635.16 -1,676.83 6,033,492.06 514,315.33 Point 0.00 7,310.28 -1,272.47 6,033,168.08 514,720.35 Point 10 0.00 6,180.03 -1,205.84 6,032,038.09 514,789.41 Point 11 0.00 6,255.18 -799.64 6,032,114.10 515,195.40 30-03AL1-01 T9 0.00 0.00 6,579.00 7,986.47 -2,707.99 6,033,841.11 513,283.52 70' 30' 13.179 N 149' 53' 28.824 W plan misses target center by 200.58ft at 12240.00ft MD (6581.38 TVD, 7998.01 N,-2507.75 E) Point 3Q-03AL1-01_T2 0.00 0.00 6,576.00 7,201.94 -1,109.60 6,033,060.10 514,883.44 70° 30' 5.468 N 149' 52' 41.755 W plan misses target center by 5.43ft at 10420.93ft MD (6577.59 TVD, 7201.69 N,-1114.78 E) Point 3Q-03AL1-01_T1 0.00 0.00 6,521.00 6.888.88 -1,095.28 6,032,747.10 514,898.43 70' 30' 2.389 N 149° 52' 41.332 W plan misses target center by 36.22ft at 10102.09ft MD (6554.33 TVD, 6886.17 N,-1081.36 E) Point 3Q-03AL1-01_Fault5 0.00 0.00 0.00 7,943.50-2,726.08 6,033,798.11 513,265.52 70' 30' 12.757 N 149° 53' 29.356 W plan misses target center by 6585.22ft at 12240.00ft MD (6581.38 TVD, 7998.01 N,-2507.75 E) Rectangle (sides W1,000.00 H1.00 D0.00) 3Q-03AL1-01_T8 0.00 0.00 6,585.00 7,984.02-2,499.98 6,033,839.10 513,491.52 70' 30' 13.156 N 149° 53' 22.699 W plan misses target center by 13.03ft at 12229.77ft MD (6581.43 TVD, 7996.34 N,-2497.67 E) Point 30-03AL1-01_Fault2 0.00 0.00 0.00 7,494.98-1,116.96 6,033,353.09 514,875.45 70° 30' 8.350 N 149' 52' 41.973 W plan misses target center by 6566.19ft at 9900.00ft MD (6516.60 TVD, 6689.60 N,-1105.84 E) Rectangle (sides W1,000.00 H1.00 D0.00) 3Q-03AL1-01_T4 0.00 0.00 6,606.00 7,751.57-1,379.42 6,033,609.09 514,612.47 70' 30' 10.873 N 149° 52' 49.702 W plan misses target center by 5.29ft at 11054.25ft MD (6607.12 TVD, 7755.54 N,-1376.10 E) Point 30-03AL1-01_T5 0.00 0.00 6,597.00 7,849.94-1,543.21 6,033,707.09 514,448.48 70' 30' 11.840 N 149' 52' 54.526 W plan misses target center by 9.83ft at 11247.91ft MD (6601.28 TVD, 7858.02 N,-1539.62 E) Point 3Q-03AL1-01_Fault3 0.00 0.00 0.00 7,873.96-2,014.19 6,033,730.10 513,977.49 70' 30' 12.075 N 149' 53' 8.394 W plan misses target center by 6581.15ft at 11800.00ft MD (6580.75 TVD, 7900.92 N,-2081.01 E) Rectangle (sides W1,000.00 H1.00 D0.00) 3Q-03AL1-01_T7 0.00 0.00 6,576.00 7,923.57-2,297.10 6,033,779.10 513,694.51 70' 30' 12.562 N 149' 53' 16.725 W plan misses target center by 11.61ft at 12015.82ft MD (6580.06 TVD, 7933.83 N,-2293.49 E) Point 3Q-03A_Polygon (copy) 0.00 0.00 0.00 6,221.18-799.71 6,032,080.10 515,195.40 700 29' 55.823 N 1490 52' 32.629 W plan misses target center by 6524.45ft at 9800.00ft MD (6505.82 TVD, 6591.99 N,-1124.27 E) Polygon Point 1 0.00 6,221.18-799.71 6,032,080.10 515,195.40 Point 2 0.00 6,533.28-834.06 6,032,392.10 515,160.39 Point 3 0.00 6,858.80-1,539.45 6,032,716.07 514,454.37 Point 4 0.00 6,756.25-2,234.73 6,032,612.03 513,759.38 Point 5 0.00 6,828.13-3,125.67 6,032,681.99 512,868.38 211812013 10:37:49PM Page 4 COMPASS 2003.16 Build 69 1 "' Baker Hughes /crag ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 3Q-03 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 3Q-03: @ 63.00ft (3Q-03) Site: Kuparuk 3Q Pad North Reference: True Well: 3Q-03 Survey Calculation Method: Minimum Curvature W e l l b o re: 3 Q-03AL 1-01 Design: 3Q-03AL1-01 _wp01 Point 0.00 6,840.90 -3,970.73 6,032,692.94 512,023.37 Point 7 0.00 6,658.56 -5,244.24 6,032,507.88 510,750.39 Point 0.00 6,288.79 -5,372.03 6,032,137.87 510,623.40 Point 0.00 6,332.46 -4,260.83 6,032,183.93 511,734.40 Point 10 0.00 6,363.38 -2,316.57 6,032,219.03 513,678.39 Point 11 0.00 6,361.46 -1,401.48 6,032,219.08 514,593.39 Point 12 0.00 6,145.10 -1,239.91 6,032,003.08 514,755.41 Point 13 0.00 6,221.18 -799.71 6,032,080.10 515,195.40 3Q-03AL1-01_Faultl 0.00 0.00 -63.00 7,038.75 -1,027.95 6,032,897.10 514,965.43 70° 30' 3.863 N 149° 52' 39.351 W plan misses target center by 6584.70ft at 9800.00ft MD (6505.82 TVD, 6591.99 N,-1124.27 E) Rectangle (sides W1,000.00 H1.00 D0.00) 3Q-03AL1-01_T3 0.00 0.00 6,607.00 7,543.17 -1,201.86 6,033,401.09 514,790.45 70' 30' 8.824 N 149' 52' 44.473 W plan misses target center by 2.88ft at 10778.08ft MD (6604.15 TVD, 7543.14 N,-1202.28 E) Point 3Q-03AL1-01_Fault4 0.00 0.00 0.00 7,960.96 -2,473.03 6,033,816.10 513,518.51 70' 30' 12.929 N 149' 53' 21.905 W plan misses target center by 6581.58ft at 12223.28ft MD (6581.46 TVD, 7995.21 N,-2491.27 E) Rectangle (sides W1,000.00 H1.00 D0.00) 3Q-03AL1-01_T6 0.00 0.00 6,581.00 7,890.92 -1,998.15 6,033,747.10 513,993.49 70' 30' 12.242 N 149° 53' 7.922 W plan misses target center by 14.49ft at 11717.92ft MD (6582.27 TVD, 7905.32 N,-1999.12 E) Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name 120.00 57.00 16" 16 24 5,210.00 3,840.47 9 5/8" 9-5/8 12-1/4 12,240.00 6,581.38 2 3/8" 2-3/8 3 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (ft) (ft) (ft) A Comment 9,800.00 6,505.82 6,591.99 -1,124.27 TIP/KOP 9,950.00 6,527.16 6,737.61 -1,096.77 Start 8 DLS 10,075.00 6,550.88 6,859.32 -1,082.27 3 10,275.00 6,568.69 7,057.22 -1,098.39 4 10,425.00 6,577.91 7,205.75 -1,114.82 5 10,725.00 6,600.87 7,495.73 -1,178.66 6 10,875.00 6,607.29 7,625.00 -1,253.94 7 11,275.00 6,600.01 7,868.72 -1,564.48 8 11,425.00 6,592.76 7,910.46 -1,708.08 9 11,675.00 6,583.34 7,911.35 -1,956.64 10 12,075.00 6,580.71 7,953.84 -2,349.16 11 12,240.00 6,581.38 7,998.01 -2,507.75 TD at 12240.00 211812013 10:37:49PM Page 5 COMPASS 2003.16 Build 69 ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 3Q Pad 3Q-03 3Q-03AL1-01 3Q-03AL1-01_wp01 Travelling Cylinder Report 18 February, 2013 WeAd BAKER HU6NE5 - Baker Hughes rigs ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 3Q Pad Site Error: 0.00ft Reference Well: 30-03 Well Error: 0.00ft Reference Wellbore 3Q-03AL1-01 Reference Design: 3Q-03AL1-01_wp01 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 3Q-03 3Q-03: @ 63.00ft (3Q-03) 3Q-03: @ 63.00ft (3Q-03) True Minimum Curvature 1.00 sigma EDM Alaska Prod v16 Offset Datum Reference 3Q-03AL1-01_wp01 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 2004 100/1000 of reference Interpolation Method: MD Interval 25.00ft Error Model: ISCWSA Depth Range: 9,800.00 to 12,240.00ft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,419.87ft Error Surface: Elliptical Conic Survey Tool Program Date 2/18/2013 From To (ft) (ft) Survey (Wellbore) Tool Name Description 50.00 9,350.00 3Q-03 GYD-CT-CMS (3Q-03) GYD-CT-CMS Gyrodata cont.casing m/s 9,350.00 9,477.00 30-03A_wp06 (3Q-03A) MWD MWD - Standard 9,477.00 9,800.00 3Q-03AL1_wp05 (3Q-03AL1) MWD MWD - Standard 9,800.00 12,240.00 3Q-03AL1-01_wp01 (30-03AL1-01) MWD MWD- Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (") (") 120.00 120.00 16" 16 24 5,210.00 3,903.47 9 5/8" 9-5/8 12-1/4 Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (ft) from Plan Offset Well - Wellbore - Design (ft) (ft) (ft) (ft) Kuparuk 3Q Pad 3Q-03 - 3Q-03A - 3Q-03A_wp06 11,950.00 10,925.00 1,213.95 140.55 1,076.52 Pass - Major Risk 3Q-03 - 3Q-03AL1 - 3Q-03AL1_wp05 9,824.97 9,825.00 0.86 1.10 -0.15 FAIL - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 211812013 7:04:50PM Page 2 of 5 COMPASS 2003.16 Build 69 ` Baker Hughes FUI ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 30 Pad Site Error: 0.00ft Reference Well: 3Q-03 Well Error: 0.00ft Reference Wellbore 3Q-03AL1-01 Reference Design: 3Q-03AL1-01_wp01 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset ND Reference: Well 3Q-03 3Q-03 @ 63.00ft (3Q-03) 3Q-03: @ 63.00ft (3Q-03) True Minimum Curvature 1.00 sigma EDM Alaska Prod v16 Offset Datum Reference Depths are relative to 3Q-03: @ 63.00ft (3Q-03) Coordinates are relative to: 3Q-03 Offset Depths are relative to Offset Datum Coordinate System is US State Plane 1927, Alaska Zone 4 Central Meridian is 150' 0' 0.000 W ° Grid Convergence at Surface is: 0.12' Ladder Plot 1400 1050 0 f6 d N in N a) 700 U 0 2 C (D U 350 0 0 2000 4000 6000 8000 10000 12000 Measured Depth LEGEND 3Q-03,3Q-03A,3Q-03A )Ap06V0 —$— 3Q-03,3Q703AL1,3Q-03AL1_wp05V0 I I I I I I I I I I I I I I I I I I I I I 1 I I I I I I 1 I I I I I I I 1 I I I I 1 I I I 1 I I I I I I i I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I 1 I I I I I I I I I I i i I I I I I I I I i I I I I I I I I I 1 I I I I I I I I I I I I I I I I I I I I I I I - I -- I I I I I I I I I I I I I I I I I I I I I I I I 1 I I I I I I I I I I I I 1 I I I I I CC -Min centre to center distance or covergent point, SF -min separation factor, ES -min ellipse separation 2/18/2013 7:04:50PM Page 5 of 5 COMPASS 2003.16 Build 69 f J a W � LU W = O W 3 H K c m � a s Big �8 � 8 �Y 4 � v J M �a 40 22M q o0 YYQ�� �r3o3� o� a 34 a 4 Q a 1■■■_■■■■ii�i�■�ir■�ii■ lid■■�i■I/■■ ■II ■I/r■■i 1 ■�■�ii■II ■�1 ■■(�■I/■1■■i ill■_�■■�_■■■■®III■NINE ■�■■I 1■I■MMEN■EM■ MEM I■■I 1M!■■i■■■■■NMEN1■■I ■.MM!"WI MMM■■■■EMEN1■■I 1■■■■■■■■■EMES1■■I 1■■■■■■■■■EEMMl■■I _.T.b....o....d....o....d....o.._ .b....o....b.. _. d...-.�_._ n(U!/u OM (+A)IO sA41-as y Oo r z a �Om Q F-NMaimm�mrn��� tic j mai ui <o .��mo��mmN ���6���888titi o�o1�0001� �—o �i7 c�gNNNNN�N 0 o m m m m m m �2$521�q 0 F m rnw m_mrng !cq mv�m ��mo�o�mm P.t2 0 8���oNo��B n m m Id m m m rn rn rn m m p 000000000000 � 000000000000 8$ %�3titi�3p- I rn.-N.nvu�m�mrn��� Jana-j eag ueaw (ut/U OL) u3d3Q jaatuaA anjl N TRANSMITTAL LETTER CHECKLIST WELL NAME A lRu- 3 C� - 0,S A L I- O I PTD# -� 13 0 2�- f' Development Service Exploratory Stratigraphic Test Non -Conventional Well FIELD: POOL: X"A J, r2l d6L- 14"oorw�' �2� ✓F s a ; Check Box for 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 last digits in well KAo' 3Q -03A , permit No. ),l 3 O %(o , API No. 50- 0 �- as az ) - o! -0(). (If two 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 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 tar et 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 ro ram. Rev: 9/09/2011 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK RIV UNIT 30-03AL1-01 Program DEV Well bore seg n PTD#: 2130270 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal U Administration 17 Nonconven. gas conforms to AS31.05.0300A.A),0.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025512 Surf loc; ADL0373301 Top Prod Interval; ADL0355024 TD 3 Unique well name and number Yes KRU 3Q-03AL1-01 4 Well located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100; governed by Conservation Order No. 432C 5 Well located proper distance from drilling unit boundary Yes CO No. 432C contains no spacing restrictions with respect to drilling unit boundaries 6 Well located proper distance from other wells Yes CO No. 432C has no interwell spacing restrictions 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes Wellbore will be more than 500' from an external property line where ownership or landownership changes. 10 Operator has appropriate bond in force Yes Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval Yes PKB 2/22/2013 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 18 Conductor string provided NA Conductor set in KRU 3Q-03 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in KRU 3Q-03 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing fully cemented 21 CMT vol-adequate to tie-in long string to surf csg NA 7" casing set 22 CMT will cover all known productive horizons No Productive interval will be completed with slotted liner 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel pits. All waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved Yes Sundry 313-042; cement squeeze perfs, set whipstock and mill window 26 Adequate wellbore separation proposed Yes Proximity analysis performed. 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max expected formation pressur 4105 psi(EMW 12.1 ppg) Drill w/10 ppg and MPD VLF 2/27/2013 29 BOPEs, do they meet regulation Yes 30 BOPE_press rating appropriate; test to _(put psig in comments) Yes MPSP 4386 psi; will test BOPs to 4800 _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 112S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 -- — - - ---- -- -- Permit can be issued w/o_ hydrogen sulfide measures No Wells on 3Q-Pad are H2S_ bearing. H2S measures required. Geology 36 Data presented on potential overpressure zones Yes Expected reservoir pressure is 12.1 ppg EMW; will be drilled using 10.0 ppg mud and managed pressure drilling Appr Date 37 Seismic analysis_ of shallow gas zones NA technique. Two wellbore volumes of 13.1 ppg emergency kill weight fluid will be available. PKB 2/22/2013 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports_ [exploratory only] NA_ - - Geologic Engineering u lic Date t Dae: Commissioner: � Coon r: Z-Z�3—lj sinner Date �r S --
