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206-175
image jest V11ell Hiat~ry t=ile ®r age XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. - 1 ~~.~ Well History File Identifier Organizing (done) ^ Two-sided III II~I~I I~ III Il ill ^ Rescan Needed III II~III II II III IN RE CAN Color Items: ^ Greyscale Items: DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner ^ Poor Quality Originals: OVERSIZED (Non-Scannable) ^ Other: ^ Logs of various kinds: NOTES: ^ Other:: BY: Maria Date: ~ ~ ©~ ls/ Project Proofing III II~III IIIII II III BY: Maria Date: ~' (~ ~s~ Scanning Preparation x 30 = BY: Maria Date: F ~,/ Production Scanning + =TOTAL PAGES~~ (Count does not include cover sheet) /s/ Stage 7 Page Count from Scanned File: ~_ (Count does include cove sheet) Page Count Matches Number in Scan ing Preparation: YES NO BY: Maria Date ~ ~ ~ ~ ~s~ ~~ 1 Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: !s~ Scanning is complete at this point unless rescanning is required. II I II II II III ~ I I III ReScanned BY: Maria Comments about this file: Date: ~s~ Quality Checked III II~IIIIII+I'I~I) 10/6!2005 Well History File Cover Page.doc Page l of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday., January 09, 2009 9:11 AM To: Allsup-Drake, Sharon K Cc: Eller, J Gary; Venhaus, Dan E; Okland, Howard D (DOA) Subject: RE: 2D-05L1 (206-174) and 2D-05L1-01 (206-175) Sharon. et at. The permits automatically expire rn 2 years unless the operator requests tc~ cancel them earlier. It appears these 4aterals were permitted in (ale 2006 so they should nov~r be expired`_ The actual paperwork to revise tP~e entries in tE~e well lists. may not have been accor~pfished yet. Calt or message: with any questions. Torn: From: Allsup-Drake, Sharon K [maiito:Sharon.K.Allsup-Drake@conornphillips.com] Sent: Friday, January 09, 2009 9:05 AM To: Maunder, Thomas E (DOA) Cc: Eller, J Gary; Venhaus, Dan E Subject: 2D-05L1 and ZD-05L1-01 Tom - What is the process to formally cancel a permit to drill? There are 2 permits we submitted in 2006 for 2D-05L1 and 2D-05L1-01. Do these just automatically get cancelled if not drilled in 2 years or is there another process to cancel them? Thank you, Sharon 263-4612 ~ ~~ ~ ~~ ~ ~ ~i F ~ E~'nt,Yas u: ~~, ~~~~. ~ ~ ~~) 3/26/2009 ,.~~` ~-~ ~~;~ ~~ .~ ~~` ~, ~ :. ~ . ~; ~,~` ~~~ ` R~r r ~ ~ £~~ ~. ~?: MICROFILMED 6/30/2010 DO NOT PLACE ANY NEW MATERIAL. UNDER THIS PAGE C:\temp\Temporary Internet Files\OLK9\Microfilm_Marker.doc RE: 2D-OSLI and other segment • -._J Subject: RE: 2D-OSLI and other segment From: "Eller, J Gary" <J.Gaty.Eller@conocophillips.com> Date: Thu, 21 Dec ?006 11:48:05 -0900 ~ ~~ - ~'~ `~ To: Z~hc+m as 1~launt~er<torrt_rna~inclei~,'~r~<<clil~itt.state.ak.~i~-~ C'C: Ste~~e Day ies <steve_davies<<i~~idmin.state.al~.us>, Davc Rc~h~~ ~ da~~e robs "cia~l~uin.state.ak.u~ =, "Vunhaus, Dare L" ~ Din.E.Vcnh,ius~u;~conoco[~hillips.com=~~ Tom - The assessment that you and Steve made is correct: under the name convention that we have been employing, the proper name for this lateral would be 2D-05L1-O1. However, we at ConocoPhillips have conferred with our CTD counterparts at BP and have come to the conclusion that the existing naming convention of laterals is unwieldy and not beneficial. We propose a much simpler naming convention, specifically L1, L2, L3, etc for laterals regardless of their origination point. We are NOT proposing to change the naming convention for sidetracks; that convention would remain A, B, C, etc. For purposes of this discussion, the definition of a sidetrack is when the productive interval has been plugged back and we are replacing that wellbore. A lateral would be a borehole drilled from within productive intervals or while productive sands remain open in the wellbore. The existing naming convention gets particularly unwieldy as more lateral legs get drilled off of other laterals. For instance, if we drill an unplanned lateral off of the second lateral in 2D-05, the correct name of that lateral would become 2D-05L1-0101 using the existing naming convention. How much simpler to call it 2D-05L3! Since this L1-0101 lateral is drilled last, it will be completed all the way back to the original wellbore and the "spoke" becomes the final lined motherbore. The existing naming convention therefore only confuses the completion. Lastly, the API numbering system in BP and COP, to our. knowledge, has not been modified to include 13th & 14th placeholders to designate a lateral off a lateral, but only reflects the number of laterals. I want to emphasize that this is not a wild-eyed scenario, but a very real potential occurrence in the CTD arena. If you would like, we would be glad to set a time, along with BP representatives, to come over and discuss with you the naming convention for laterals. Thanks, and please let me know if you'd like to get together. Gary Eller CPAI CTD Engineer 907-263-4172 -----Original Message----- From: Thomas Maunder [rr~ai..l.tc; :ton: maunder ~~a.i~r:.i.rz .state . ak . i.:.s Sent: Monday, December 18, 2006 4:17 PM To: Eller, J Gary Cc: Steve Davies; Dave Roby Subject: 2D-05L1 and other segment Gary, I just finished reviewing the permit application for 2D-05L1. No problem here. However, it does not appear that the proposal to name the succeeding segment 2D-05 L2 is correct. The new segment originates from the L1 wellbore. According to the convention we have been employing, this segment is a "spoke" and the proper name is 2D-05L1-O1. Please check with your associates about this. Call or message with any questions. I'd look forward to a message back confirming the name. ,~,~~ ,~4,~„"I 1/10/2007 10:05 AM ------- Original Message -------- ~ ~ ~ i~ Subject:RE: 2D-OS Lateral Naming Date:Tue, 09 Jan 2007 16:38:59 -0900 From:Venhaus, Dan E <Dan.E.Venhaus@conocophillips.com> To:Thomas Maunder <tom maunder@admin.state.ak.us> CC:Eller, J Gary <J.Gary.Eller@conocophillips.com>, Gantt, Lamar L <lamar.gantt@bp.com>, Worthington, Aras J <Aras.Worthington@bp.com> Tom, We understand your intention to differentiate laterals that originate from the parent wellbore (L1, L2, etc.) from laterals that originate in the formation (L1-01, L2-01, etc.). We agree to the proposed naming of 2D-05L1-01. And for the sake of discussion, if we add an additional lateral (or "spike", as you reference below) to 2D-05L1-01, the naming convention wilt be 2D-05L1-02, not 2D-05L1-01-01. Thanks for your attention to this matter. Dan Venhaus Wells/CTD Engineer ConocoPhillips AK, Inc. 907-263-4372 office 907=230-0188 cell -----Original Message----- From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Tuesday, January 09, 2007 1:11 PM To: Venhaus, Dan E Cc: HubbleTL@BP.com; Eller, J Gary; Steve Davies Subject: Re: 2D-05 Lateral Naming Dan, Gary and Terrie, We have recently exchanged a couple of messages regarding lateral naming for the 2nd segment on 2D-OS and an additional segment in 1 C-Ol . In the convention presently used, a lateral is a well segment that is drilled from a parent wellbore. A parent wellbore has a "low number series" (00, O1, 02, etc) in the 1 lth and 12th position in the API number. A, B, C, etc is also added to the well name indicating a redrill. Laterals are sequentially named/numbered L1, L2, L3, etc. Laterals have a 60 series number in the 1 lth and 12th API position. When a well segment is drilled from a lateral, under the current convention this segment has been called a "spoke". The naming convention for spokes so far has been to add -O1, -02, etc to the L. The 60 series number is continued in the API number, although the sequential numbering of the spokes may not agree with the actual drilling sequence. It could be possible to continue segregating and naming additional "daughter segments" (we have found reference to "spikes") however that likely would add a lot of confusion and not have much value to either the state or operator. There is a somewhat similar precedent that is used in land descriptions (for example, "SE1/4, SW1/4, E1/2 Sec. 12", which is a very compact way of saying the Southeast I/4 of the Southwest 1/4 of the Eastern 1/2 of Section 12). This schema works well when describing portions of leases. Several messages have been exchanged on operations in the 1 C-O1 parent well with the 1 of 2 l /10/2007 8:50 AM segments considered spokes and the name L1-XX. Based on the recent message traffic and keeping with the convention, the 2nd segment planned for ZD-OS should be 2D-OSLI-O1. Please respond and let me know if you are in agreement with this assessment. It is recognized that there is benefit in attempting to minimize confusion as much as possible, but we don't believe this would be the case using just a lateral designation repeatedly for segments originating from a parent wellbore and others originating in the reservoir. Tom Maunder, PE AOGCC 2 of 2 I/10/2007 8:50 AM id-7~~~~~®ld l~®s7s7~®1® Gary Eller CT Drilling Engineer ConocoPhillips Alaska, Inc. PO Box 196612 Anchorage, AK 99519-6612 SARAH PALBN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kuparuk River Field, Kuparuk River Oil Pool, Kuparuk 2D-05L1-Ol ConocoPhillips Alaska, Inc. Permit No: 206-175 Surface Location: 188' FSL, 550' FEL, SEC. 23, T11N, R09E, UM Bottomhole Location: 4302' FSL, 801' FWL, SEC. 24, T11N, R09E, UM Dear Mr. Eller: Enclosed is the approved application for permit to redrill the above referenced development well. The permit is for a new wellbore segment of existing well KRU 2D-05, Permit No 184-126, API 50-029-2115-00. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commissio 's petroleum field inspector at (907) 659-3607 (pager). J DATED this ~® day of January, 2007 cc: Department of Fish 8~ Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALAS~IL AND GAS CONSERVATION COMMI ,. N i ICU PERMIT TO DRILL I~ECEIVEL~ DEC 1 2 2006 20 AAC 25.005 7~iasica Gil & Gas Cons. Commission 1 a. Type of work ^ Drill ®Redrill ^ Re-Entry 1 b. Current Well Class ^ Exploratory ^ Development Gas ^ Service ~ ^ Multiple Zone ^ Stratigraphic Test ®Development Oil ^ Single Zone 1 c. Specify if well is or: ^ Coalbed Metha~ne~s Hydrates ^ Shale Gas 2. Operator Name: Conoco Phillips Alaska Inc. 5. Bond: ®Blanket ^ Single Well Bond No. 59-52-180 11. Well Name and Number: Kuparuk 2D-05J,~-~,-'~ 3. Address: c/o P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Proposed Depth: MD 10825 ~ TVD 5951 ss 12. Field /Pool(s): Kuparuk River Unit /Kuparuk 4a. Location of Well (Governmental Section): Surface: 168' FSL 550' FEL SEC 23 T11 N R09E UM ~ 7. Property Designation: ADL 025653 River Pool ~~ , , . , , , Top of Productive Horizon: 3929' FSL, 1367' FWL, SEC. 24, T11N, R09E, UM 8. Land Use Permit: 13. Approximate Spud Date: January 10, 2007 Total Depth: 4302' FSL, 801' FWL, SEC. 24, T11N, R09E, UM 9. Acres in Property: 2560 14. Distance to Nearest Property: 23,500' 4b. Location of Well (State Base Plane Coordinates): Surface: x-529214 ~ y-5954367 ~ Zone-ASP4 10. KB Elevation (Height above GL): 126 feet 15. Distance to Nearest Well Within Pool: 2,000' 16. Deviated Wells: Kickoff Depth: 9300 ~ feet Maximum Hole An le: 97 de rees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 4500 ` Surface: 3892 18. Casin Pr ram: S fi` ' To - in th - m anft of C m nt c.f. or a ks Hole Casin Wei ht Grade Cou lin Len th MD TVD MD TVD includin sta a data 2.7" x 3" 2-3/8" 4.6# L-80 STL 3209' 7616' 5896 10825' 5951' Uncemented Slotted Liner 19. PRESE NT WELL CONDiTIQN SUMMARY (To be completed for Redrill and Re-entry Operations) Total Depth MD (ft): 7990 Total Depth TVD (ft): Plugs (measured): 6363 None Effective Depth MD (ft): 7802 Effective Depth TVD (ft): 6190 Junk (measured): None asing ' Length. ize ement olume MD D Conductor /Structural Surface 116' 16" 224 sx Coldset II 116' 116' Intermediate 3823' 9-5/8" 1075 sx Arcticset III 685 sx Class 'G' 382 ' 3159' Pr d i n 7971' 7" 625 x l ss 'G' 2 x AS I 7 71' 6345' Liner Liner 2D-05L1 1650' 2-3/8" Uncemented Slotted Liner 9300' - 10950' 8989' - 6011' Perforation Depth MD (ft): 7534' - 7742' Perforation Depth TVD (ft): 5949' - 6135' 20. Attachments ^ Filing Fee, $100 ®BOP Sketch ®Drilling Program ^ Time vs Depth Plot ^ Shallow Hazard Analysis ^ Property Plat ^ Diverter Sketch ^ Seabed Report ®Drilling Fluid Program ®20 AAC 25.050 Requirements 21. Verbal A proval: Commission Representative: Date: 22. I hereby 'fy that the foreg 'ng is true and correct. Contact Gary Eller, 529-1979 Printed N Gary Eller Title CT Drilling Engineer Prepared By Name/Number: Si nature Phone 529-1979 Date 12/~ (o(e Terrie Hubble, 564-4628 Commission Use Oni Permit To Drill Number: Z~ ~ ~7 I Number: 50-029-21157-61-00 Permit Approval Dat : - See cover letter for other r uir ment 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 shales: Samples Req'd: ^~ es o Mud Log Req'd: ^ Yes 1!7 No ff ~~~~y~ ~ 1 H2S Measures: [7 Yes N Directional Survey Req'd: [i~Yes ^ No Other: ~1~ ` ' 1 ~ ~.S~fs~.~ ; l~~v~~E~. Date !•~Q •~~ APPROVED BY THE COMMISSION ,COMMISSIONER Form 10-401 Revised 12/2005 ,~ Y s v ~ /~ Submit In Duplicate ~/ ,dp iz• i~ oG ~~ V ~.~-~~ KRU~-05L1 and 2D-05 Sidetrac Laterals Coiled Tubing Drilling ~~~ C~~~ ®~ ~~, ~~l Summary of Operations: '~ 1 A coiled tubing drilling unit will drill two laterals from injector KRU 2D-OS using the managed pressure drilling technique. These horizontal laterals will target Kuparuk A4 sand reserves for increased pattern throughput. The 2D-OSL1 will be a 3300' lateral drilled to the northwest, and the 2D-OSL2 will be a 1550' lateral kicked off from the 2D-OSL1 and drilled to the south. Both laterals will be pre-produced for a period of months prior to conversion to injection. _ 2D-OS CTD Drill and Complete Program: Planned for January 2007: Pre-CTD Prep Work 1. Positive pressure and drawdown tests on MV and SV. 2. Test Packoffs - T & IC. 3. MIT-IA, MIT-OA. 4. Slickline tag fill. Obtain static BHP on A sand alone. a. If A sand static BHP exceeds 4500 psi, allow A sand to crossflow to C sand perfs. Re- measure static BHP on A sand. 5. Pressure test tubing to confirm that the C sand straddle has integrity. a. If the C sand straddle does not test, locate the leak and attempt repairs. 6. E-line shoot tubing punches in 3'/z" tubing tail at 7617' MD. 7. Coil tubing lay in cement plug across existing A sand perfs up across tubing tail to 7613' MD. 8. Slickline drift and tag top of cement. 9. Pressure test cement plug. CTD Rig Work 1. MIRU Nordic Rig #2 using 2" coil tubing. NU 7-1/16" BOPE, test. 2. Mill cement ramp, 2.74" window, and 10' of open hole from 7655' MD. 3. Drill the 2D-OSL1 trunk lateral to the northwest with a 2.70" x 3" bi-center bit from the window at 7655' MD to TD of 10,950' MD targeting the Kuparuk A4 sand. 4. Complete the L1 lateral with 23/8" slotted liner from TD up X9300' MD. An aluminum billet will be run an (9300' for kickoff of the L2 lateral. 5. Mill off the aluminum billet at 9300' MD. (~ _~~, ~ 6. Drill the JChateral to the south with a 2.70" x 3" bi-center bit from 9300' to 10,_850' MD targeting Kuparuk A4 sands. - 'f • (~,~ 5 ~~cv-~ ~- 7. Complete the lateral with 23/8" slotted liner. The 23/8" liner will be run to TD, and the liner ~~ - G ~, top will be 10' inside the 3'/2" tubing tail at 7616' MD. 8. ND BOPE. RDMO Nordic 2. Post-CTD Rig Work 1. Run GLVs, obtain static BHP. Leave the C Sand perfs isolated for the time being. 2. Pre-produce the L1 and L2.laterals of 2D-O5. 3. Submit separate 10-403 to convert 2D-OS to injection when ready to do so: Mud Program• Will use chloride-based Biozan brine (10.0 ppg) for milling operations, and chloride-based Flo-Pro mud f (10.0 ppg) for drilling operations. Will have to kill the well to deploy 23/8" slotted liner since the SCSSV has been locked out. Page 1 of 3 December 7, 2006, FINAL _ ~.~ -~ KRU~D-05L1 an - d 2D 05,J~~''Sldetrack Laterals Coiled Tubing Drilling Disnosal• • No annular injection on this well • Class II liquids to KRU 1R Pad Class II disposal well • Class II drill solids to Grind & Inject at PBU Drill site 4 • Class I wastes will go to Pad 3 for disposal. Casing Pro~ram• • 2D-OSL1: 23/8", 4.6#, L-80, STL slotted liner from 9300' MD to 10,950' MD • 2D-OSL2: 23/8", 4.6#, L-80, STL slotted liner from 7616' MD to 10,850' MD Existing Casing/Liner Information Surface: 95/8", J-55, 36# Burst 3520 psi; Collapse 2020 psi. Production: 7", J-55, 26# Burst 4980 psi; Collapse 4320 psi Well Control: • Two well bore volumes 0190 bbl) of kill weight fluid will be available to the rig during drilling ° operations. The kill weight fluid may or may not be stored onsite, but if it is stored offsite it will be in the Kuparuk Field within a short drive to the rig. • BOP diagram is attached for operations with 2" coil tubing. • Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4000 psi. Maximum potential surface pressure is 3892 psi assuming a gas gradient to surface and maximum expected formation pressure (i.e. 4500 psi). • The annular preventer will be tested to 400 psi and 2500 psi. Directional• • See attached directional plans for 2D-OSL1 and 2D-OSL2. • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. ' • The nearest well to the 2D-OSL1 lateral is 2D-06 which is 1500' away. The nearest well to the 2D-OSL2 lateral is 2D-03 which is approximately 2000' away. The KRU boundary is 23,500' away. Lo~~ing• • MWD directional, resistivity, and gamma ray logs will be run over the entire open hole section in both laterals. Drilling Hazards: • Lost circulation is a risk due to fault crossings and lack of injection support into isolated fault blocks in the A sand. Expect to encounter reduced formation pressure as the laterals are drilled away from the motherbore. • The risk of encountering excess pressure while drilling a fault crossing is considered lo_w. Because 2D-OS is an injection well, the highest pressure we expect to encounter is immediately around the motherbore. Because 2D-OS has recently been on miscible gas injection, .any formation influx is likely to contain hydrocarbon gas. Y • The highest HZS reading on the 2D pad is 85 ppm as measured in the 2D-15 well. Well 2D-OS is an injection well so it has no associated HZS. We112D-06B is adjacent to 2D-OS and has 70 ppm HZS (10/17/06). All HZS monitoring equipment will be operational. - Page 2 of 3 December 7, 2006, FINAL KRU D-05L1 and 2D-05L2 Sidetrack Laterals Coiled Tubing Drilling Reservoir Pressure: • The most recent static BHP survey in we112D-OS was taken in August 2005 after the well had been shut- in for 12 days with both the A and C sands open. The measured reservoir pressure was 3812 psi at 7802' MD, 6190' TVD which corresponds to 11.8 ppg EMW. Separate A sand and C sand pressures will be obtained prior to drilling these CTD laterals. Since 2D-OS is an injection well, expect to encounter decreasing formation pressure as the laterals are drilled away from the mother well. Maximum expected -- pressure is 4500 psi in the A sand, which corresponds to an EMW of 14.2 ppg at 6078' TVD (top of AS perfs). Maximum potential surface pressure with gas (assume 0.1 psi/ft gradient) to surface is 3892 psi. Variance request: • ConocoPhillips requests a variance to 20 AAC 25.036(d)(4) regarding the requirement to function pressure test ram-type BOP equipment after using such for purposes other than well control. The variance will not apply when the use of ram-type BOP equipment inay have compromised their effectiveness, such as if the pipe rams are inadvertently closed on a tool joint during routine operations. While drilling the 2D-OS laterals it will be routine to close the 23/8" combi-rams (i.e. pipe/slip rams). These activities will not compromise the integrity of the BOP equipment. Managed Pressure Drilling: Managed pressure drilling (MPD) techniques will be employed to provide constant bottom hole pressure by using 10.0 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allow use of less expensive drilling fluid and minimizes fluid losses and/or fracturing at the end of the long well bores. A hydraulic choke for regulating surface pressure will be installed between the BOPS choke manifold and the mud pits, and will be independent of the BOPE choke. Using this technique will require deployment of the BHA under trapped wellhead pressure. Pressure deployment of the BHA will be accomplished utilizing the BOP pipe/slips (i.e. 23/8" rams, see attached BOP configuration). The annular preventer will act as a secondary containment during deployment and not as a stripper. We112D-OS is not equipped with a SCSSV, so the well will have to be killed prior to running 23/8" slotted liner. Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected at TD: • Estimated reservoir pressure: 3688 psi at 7650' MD (6053' TVD), or 11.7 ppg EMW. • Expected annular friction losses while circulating: 689 psi (assuming friction of 90 psi/1000 ft). • Planned mud density: 10.0 ppg equates to 3148 psi hydrostatic bottom hole pressure at 6053' TVD • While circulating 10.0 ppg fluid, bottom hole circulating pressure is estimated to be 3837 psi or 12.2 ppg EMW without holding any additional surface pressure. • When circulation is stopped, it is anticipated that an additional 54_0 psi of surface pressure shall have to be applied to balance reservoir pressure. Page 3 of 3 December 7, 2006, FINAL ~+~ ss (167o-1a OD:3.51 P (7366-73 OD:3.5 P (7379-73 OD:6.1 Inject MandrelNs (7418-74 Inject MandreWe (7485-74 Injec~ MandralNa (7587-7E F (7606-7E OD:6.1 (7621-7E OD:3.~ TUBI (0-7E OD:3.` ID:2 (7678-7E I (7700-7i • • KRU 2D-05 ConocoPhillips Alaska, Inc. 2D-05 API: 500292115700 Well T INJ An le TS: 28 d 7532 SSSV Type: TRDP Orig 9/20/1984 Angle @ TD: 23 deg @ 7990 sv Com letion: 1• ~ Annular Fluid: Last W/O: Rev Reason: C/O CVs ) Reference L Ref L Date: Last U ate: 10/27/2005 Last Ta : 7802 CTMD TD: 7990 ftK6 Last Ta Date: 8/7/2005 Max Hole An le: 47 d 3700 Casin Strin -ALL STRINGS Descri lion Size To Bottom TVD Wt Grade Thread CONDUCTOR 16.000 0 116 116 62.50 H-40 SUR. CASING 9.625 0 3823 3159 36.00 J-55 PROD. CASING 7.000 0 7971 6345 26.00 J-55 Tubin Strin -TUBING Size To Bottom ND Wt Grade Thread 3.500 0 7626 6031 9.30 J-55 EUE 8RD Perforations Summar Interval TVD Zone Status Ft SPF Date T e Comment 7534 - 7578 5949 - 5988 C-4,UNIT B 44 12 9/28/1984 IPERF Dresser Atlas 7678 - 7688 6078 - 6087 A-5 10 4 9/28/1984 IPERF Dresser Atlas 7700 - 7742 6097 - 6136 A-4 42 4 9/28/1984 IPERF Dresser Atlas Gas Lift MandrelsNalves St MD TVD Man Mfr Man Type V Mfr V Type V OD Latch Port TRO Date Run Vlv Cmnt 1 2074 1907 MMH FMHO DMY 1.0 BK-2 0.000 0 9/28/1994 2 4210 3427 MMH FMHO DMY 1.0 BK-2 0.000 0 9/28/1994 3 5722 4526 MMH FMHO DMY 1.0 BK-2 0.000 0 9/28/1994 4 6842 5376 MMH FMHO DMY 1.0 BK-2 0.000 0 9/28/1994 5 7319 5762 Otis HP Round DMY 1.5 RO 0.000 0 10/2/1989 j In'ection Mandrels/Valves 3R St MD TVD Man Man Type V Mfr V Type V OD Latch Port TRO Date Vlv ~7, Mfr Run Cmnt ~o) 6 7418 5847 MMH MMH FMHO HFCV 1.0 BK 0.188 0 10/22/200 O en 7 7485 5906 MMH MMH FMHO HFCV 1.0 BTM 0.188 0 0/22/200 O n 8 7587 5996 MMH MMH FMHO DMY 1.0 0.000 0 0/14/2 1 <R 1. LATCH BROKEN OFF WHEN ATTEMPT MADE TO PULL DMY 4/7/2001 30' it) Other lu s, a ui ., etc. -JEWELRY De th TVD T e Descri lion ID 1870 1751 SSSV Baker'FVL' Locked Out 7/26/94 2.810 7366 5802 PBR Baker 10 3.000 °n I 7379 5813 PKR Baker'FHL' h d set PERM 3.000 ve 6 7606 6013 PKR Baker'FB-1' 4.000 19. 7621 6027 NIP Camco'D' Ni le NO GO 2.750 7625 6030 SOS Baker 2.992 7626 6031 TTL 2.992 on Ive 7 36, ion I~B 8 98, KR 77, it) JIP 22, ~0) NG 26, D0, 32) 'erf 38) 'erf _. 12) I KRU 2D-05 CTD Sidetrack A4-sand Injector Completion Total Proposed Footage = 4850' G. 3-'/2' SSSV set at 1870' (locked out) F. 3-1/2" 9.3# J-55 EUE 8rd Mod tubing with 3-1/2" x 1" gas lift mandrels 9-5/8"~ shoe E. 3-'/z' x 7" packer at 7379' C-sand perfs D. 3-1/2" production mandrels C. 3-'/2' x 7" packer at 7606' Possible leak in production mandrel B. 3-'/z' nipple with 2.75" ID at 7621' at 7587' RKB A. 3-1/2" tubing tail at 7626' 2-3/8" liner top @ 7616' ....... ...... ement KOP at Window in T' 26# J55 7650' M D casing ................. Aluminum billet at 9300' MD A5 sand perfs 2D-05L1 north ~~ lateral, TD @ 10950' MD ...:..:..:::::::::..::::.... 2-3/8"slotted liner ~_________N__ A4 sand ~.~:.~:::::::::.~.~.~.~:::. ------------- perfs 2D-05L2 south "curl" lateral , TD @ 10850' MD 7" shoe ~':~:~: • • • by BP Alaska $ Baker Hughes INTEQ Planning Report >NTE Q Company: BPAmow Date: 11/28!2006 Time: 12:04:31 Page: i Field: Kuparuk Co-ordinate(NE) Reference: Well: 2D-05, True North . Site: KRU 2D Pad Vertical (TVD) Reference: 2 D-05 Orig Rig 126.0 Well: 2D-05 Section (VS) Reference: Well (O.OON,O.OOE,200. OOAzi) Weilpath: Plan 3, 2D-05L2 Survey CAlenlxtion Method: Minimum Curvature Db: Orade Fiehl: Kuparuk Map System:US State Plane Coordinate System 1927 Map Zoae: Alaska, Zone 4 Geo Datum: NAD27 (Clarke 1866) Coordinate System: Well Centre Sys Datoro: Mean Sea Level Geomagnetic Model: bgg m2006 Site: KRU 2D Pad UNITED STATES :North Slope Site Positioe: Northing: 5954200. 61 ft Latitude: 70 17 9.387 N From: Map Fasting: 529765. 39 ft Longitude: 149 45 32.755 W Position Uncertainty: 0.00 ft North Refereuce: True Ground Level: 0.00 ft Grid Convergeece: 0.23 deg Well: 2D-05 Slot Name: Well Position: +N/-S 168.83 ft Northing: 5954367 .24 ft latitude: 70 17 11.047 N +E/-W -550.66 ft Fasting : 529214 .12 ft ~ Longitude: 149 45 48.798 W Position Uncertainty: 0.00 ft Wellpath: Plan 3, 2D-05L2 Drilled From: Plan 3, 2D-05L1 Tie-ou Depth: 9300.00 ft Current Datum: 2D-05 Orig Rig Height 126 .00 ft Above System Datum: Mean Sea Level Magnetic Data: 11/28/2006 Declination: 23.60 deg Fiekl Strength: 57605 nT Mag Dip Angle: 80.80 deg Vertical Section: Depth From (TVD) +N/-S +E/-W Direction ft ft ft deg 126.00 0.00 0.00 200.00 Plan: Plan #3 Date Composed: 11!28/2006 copy Lamar's plan 3 Version: 3 Principal: Yes Tied-to: From: Definitive Path Targets Mxp Mxp <--- Latitude -> <- Longitude --> Name I)t!set•iptioa TVD +N/-S +EkW Nerthiag !Fasting Deg Min Sec Deg Min Sec Dip. Dir. ft' ft ft ft ft 2D-05L1 Polygon 126.00 3917.77 2164.33 5958293.00 531363.00 70 17 49.575 N 149 44 45.710 W -Polygon 1 126.00 3917.77 2164.33 5958293.00 531363.00 70 17 49.575 N 149 44 45.710 W -Polygon 2 126.00 4732.95 2397.52 5959109.00 531593.00 70 17 57.592 N 149 44 38.905 W -Polygon 3 126.00 5202.02 2136.31 5959577.00 531330.00 70 18 2.206 N 149 44 46.516 W -Polygon 4 126.00 5522.30 1814.52 5959896.00 531007.00 70 18 5.357 N 149 44 55.895 W -Polygon 5 126.00 6001.18 1601.36 5960374.00 530792.00 70 18 10.067 N 149 45 2.107 W -Polygon 6 126.00 6742.78 1210.20 5961114.00 530398.00 70 18 17.361 N 149 45 13.509 W -Polygon 7 126.00 6599.11 862.61 5960969.00 530051.00 70 18 15.949 N 149 45 23.645 W -Polygon 8 126.00 6330.53 1006.58 5960701.00 530196.00 70 18 13.307 N 149 45 19.448 W -Polygon 9 126.00 5637.31 1299.92 5960009.00 530492.00 70 18 6.489 N 149 45 10.898 W -Poygon 10 126.00 5086.63 1718.82 5959460.00 530913.00 70 18 1.072 N 149 44 58.688 W -Polygon 11 126.00 4837.46 2012.88 5959212.00 531208.00 70 17 58.621 N 149 44 50.117 W -Polygon 12 126.00 4500.41 2016.58 5958875.00 531213.00 70 17 55.306 N 149 44 50.012 W -Polygon 13 126.00 3994.78 1906.60 5958369.00 531105.00 70 17 50.333 N 149 44 53.222 W -Polygon 14 126.00 3917.77 2164.33 5958293.00 531363.00 70 17 49.575 N 149 44 45.710 W 2D-05L2 Polygon 126.00 5109.26 1812.92 5959483.00 531007.00 70 18 1.294 N 149 44 55.945 W -Polygon 1 126.00 5109.26 1812.92 5959483.00 531007.00 70 18 1.294 N 149 44 55.945 W -Poygon 2 126.00 5367.45 1771.92 5959741.00 530965.00 70 18 3.834 N 149 44 57.138 W -Polygon 3 126.00 5378.67 1457.93 5959751.00 530651.00 70 18 3.945 N 149 45 6.293 W -Polygon 4 126.00 5093.66 1194.79 5959465.00 530389.00 70 18 1.142 N 149 45 13.966 W -Polygon 5 126.00 4747.16 1057.43 5959118.00 530253.00 70 17 57.735 N 149 45 17.972 W -Polygon 6 126.00 4142.76 1144.09 5958514.00 530342.00 70 17 51.790 N 149 45 15.448 W -Poygon 7 126.00 4104.41 1489.98 5958477.00 530688.00 70 17 51.412 N 149 45 5.366 W -Polygon 8 126.00 4858.57 1469.91 5959231.00 530665.00 70 17 58.830 N 149 45 5.946 W -Polygon 9 126.00 5050.15 1583.66 5959423.00 530778.00 70 18 0.714 N 149 45 2.629 W -Polygon 10 126.00 5109.26 1812.92 5959483.00 531007.00 70 18 1.294 N 149 44 55.945 W • by BP Alaska ~ Baker Hughes INTEQ Planning Report >NTE Q Company: BP Amoco Date: 11!28/2006 Time: 12:04:31 Page: 2 Field: Kuparuk Co-ordinate(NE) Reference: WeII: 2D-05, True North Site: KRU 2D Pad Vertical (TVD) Reference 2D-05 Orig Rig 128.0 Well: 2D-05 Sectio n (VS) Reference. Well (O.OON,O.OOE,200.OOAzi) Weilpath: Plan 3, 2D-05 L2 Survey Calcalatioo Me[hod: Minimum Curvature Db: Orade Targets Map Map <-- Latitude -> <- Longitude -> Name Description TYD +1V!-S +FJ-W 1Yorthing Easting Deg Min Sec Deg Min Sec Dip. Dir. ft ft ft ft ft 2D-05L2 Target3 6077.00 4148.99 1343.14 5958521.00 530541.00 70 17 51.851 N 149 45 9.646 W 2D-05L2 Target2 6097.00 4725.55 1212.36 5959097.00 530408.00 70 17 57.522 N 149 45 13.455 W 2D-05L1 Targets 6106.00 5373.89 1659.93 5959747.00 530853.00 70 18 3.897 N 149 45 0.403 W 2D-05L1 Target4 6116.00 5156.08 1862.11 5959530.00 531056.00 70 18 1.755 N 149 44 54.511 W 2D-05L2 Targets 6116.00 5004.20 1312.46 5959376.00 530507.00 70 18 0.262 N 149 45 10.536 W 2D-05L1 Target6 6116.00 5695.44 1526.16 5960068.00 530718.00 70 18 7.060 N 149 45 4.301 W 2D-05L1 Target3 6126.00 4926.93 2150.25 5959302.00 531345.00 70 17 59.500 N 149 44 46.112 W 2D-05L1 Target! 6134.00 4243.80 2166.59 5958619.00 531364.00 70 17 52.782 N 149 44 45.641 W 2D-05L1 Target2 6136.00 4589.67 2208.94 5958965.00 531405.00 70 17 56.183 N 149 44 44.404 W 2D-05L1 Target? 6136.00 6D55.48 1265.54 5960427.00 530456.00 70 18 1 D.602 N 149 45 11.898 W 2D-05L1 Target9 6137.00 6600.37 1053.63 5960971.00 530242.00 70 18 15.961 N 149 45 18.075 W 2D-05L1 Target8 6139.00 6396.80 1195.85 5960768.00 530385.00 70 18 13.958 N 149 45 13.929 W Annotation MD TVD ft ft 9300.00 6115.30 KOP ~ 9310.00 6114.89 2 9330.00 6113.75 3 9380.00 6111.43 4 9455.00 6109.18 5 9505.00 6108.60 End of 25 Deg/100 DLS 9730.00 6112.69 7 9930.00 6116.02 8 10205.00 6097.29 9 1043D.00 6081.52 10 10825.00 6077.07 TD Plan Bettina Information MD' Inci Aaim TVD _' +N!-S +E/-W DLS Bnild Tnrn TFO Target ft deg deg ft ft ft deg/100ft deg/100ft deg/100ft deg 9300.00 91.48 309.67 6115.30 5184.94 1822.89 0.00 0.00 0.00 0.00 9310.00 93.25 307.90 6114.89 5191.20 1815.10 25.00 17.67 -17.70 315.00 9330.00 93.24 302.89 6113.75 5202.76 1798.83 25.00 -0.06 -25.04 270.00 9380.00 92.08 290.43 6111.43 5225.12 1754.28 25.00 -2.31 -24.92 265.00 9455.00 91.33 271.69 6109.18 5239.43 1681.04 25.00 -1.00 -24.99 268.00 9505.00 90.00 259.26 6108.60 5235.49 1631.29 25.00 -2.65 -24.86 264.00 9730.00 87.96 232.33 6112.69 5144.11 1428.00 12.00 -0.91 -11.97 265.50 9930.00 90.16 208.42 6116.02 4992.87 1299.42 12.00 1.10 -11.95 275.00 10205.00 97.44 176.14 6097.29 4728.57 1241.53 12.00 2.65 -11.74 283.50 10430.00 90.46 149.98 6081.52 4515.91 1306.53 12.00 -3.10 -11.63 256.20 10825.00 90.75 197.38 6077.07 4134.44 1348.78 12.00 0.07 12.00 89.40 by BP Alaska r Baker Hughes INTEQ Planning Report INTE Q Company: BP Amoco Date: 11/28/2006 Time: 12:04:31 Page: 3 i.Fie~: Kupatuk Co-ordinate(NE) Reference: Well: 20-05, True North Site: KRU 2D Pad Verflcal (TVD) Reference 20-05 Orig Rig 126.0 WeII: 2D-05 Sectioe (VS) Reference: Well (O.OON,O.OOE,200.OOAzi) We{{path: Plan 3, 2D-0512 Survey Calculation Method: Minimum Curvature Db: OraGe Survey MD' Incl Azim ft deg deg 9300.00 91.48 309.67 9310.00 93.25 307.90 9320.00 93.25 305.39 9330.00 93.24 302.89 9340.00 93.01 300.40 9360.00 92.56 295.41 9380.00 92.08 290.43 9400.00 91.90 285.43 9420.00 91.70 280.43 9440.00 91.49 275.43 9455.00 91.33 271.69 9460.00 91.19 270.44 9480.00 90.67 265.47 9500.00 90.13 260.50 9505.00 90.00 259.26 9525.00 89.81 256.86 9550.00 89.58 253.87 9575.00 89.34 250.88 9600.00 89.11 247.89 9625.00 88.88 244.90 9650.00 88.65 241.91 9675.00 88.43 238.91 9700.00 88.21 235.92 9725.00 88.00 232.93 9730.00 87.96 232.33 9750.00 88.17 229.93 9775.00 88.44 226.95 9800.00 88.71 223.96 9825.00 88.98 220.97 9850.00 89.26 217.98 9875.00 89.54 214.99 9900.00 89.83 212.01 9925.00 90.11 209.02 9930.00 90.16 208.42 9950.00 90.72 206.09 9975.00 91.42 203.17 10000.00 92.12 200.25 10025.00 92.81 197.33 10050.00 93.49 194.40 10075.00 94.16 191.47 10100.00 94.82 188.54 10125.00 95.47 185.60 10150.00 96.11 182.65 10175.00 96.72 179.70 10200.00 97.33 176.73 10205.00 97.44 176.14 10225.00 96.86 173.79 10250.00 96.13 170.87 10275.00 95.37 167.95 10300.00 94.60 165.04 10325.00 93.82 162.13 10350.00 93.03 159.23 10375.00 92.23 158.34 SS TVD' N/S E!W MapN ft ft ft ft, 5989.30 5184.94 1822.89 5959558.71 5988.89 5191.20 1815.10 5959564.93 5988.32 5197.16 1807.09 5959570.86 5987.75 5202.76 1798.83 5959576.43 5987.21 5208.00 1790.33 5959581.64 5986.24 5217.34 1772.68 5959590.91 5985.43 5225.12 1754.28 5959598.62 5984.73 5231.27 1735.27 5959604.70 5984.10 5235.74 1715.79 5959609.09 5983.55 5238.50 1696.00 5959611:77 5983.18 5239.43 1681.04 5959612.64 5983.07 5239.53 1676.04 5959612.72 5982.74 5238.81 1656.06 5959611.93 5982.60 5236.37 1636.22 5959609.41 5982.60 5235.49 1631.29 5959608.51 5982.63 5231.35 1611.73 5959604.30 5982.77 5225.04 1587.54 5959597.89 5983.00 5217.47 1563.72 5959590.23 5983.34 5208.67. 1540.32 5959581.34 5983.78 5198.66 1517.42 5959571.24 5984.32 5187.47 1495.08 5959559.97 5984.95 5175.13 1473.35 5959547.55 5985.69 5161.68 1452.29 5959534.01 5986.51 5147.14 1431.97 5959519.40 5986.69 5144.11 1428.00 5959516.35 5987.36 5131.57 1412.44 5959503.75 5988.11 5114.99 1393.74 5959487.10 5988.73 5097.46 1375.94 5959469.50 5989.23 5079.02 1359.06 5959451.00 5989.61 5059.73 1343.17 5959431.65 5989.88 5039.63 1328.31 5959411.50 5990.01 5018.79 1314.51 5959390.60 5990.03 4997.25 1301.82 5959369.02 5990.02 4992.87 1299.42 5959364.63 5989.86 4975.09 1290.26 5959346.81 5989.39 4952.37 1279.84 5959324.06 5988.62 4929.16 1270.60 5959300.81 5987.55 4905.52 1262.55 5959277.14 5986.17 4881.51 1255.73 5959253.11 5984.51 4857.20 1250.15 5959228.78 5982.55 4832.66 1245.82 5959204.22 5980.31 4807.95 1242.75 5959179.51 5977.78 4783.15 1240.96 5959154.70 5974.99 4758.31 1240.45 5959129.86 5971.93 4733.51 1241.23 5959105.07 5971.29 4728.57 1241.53 5959100.12 5968.80 4708.80 1243.28 5959080.37 5965.97 4684.19 1246.59 5959055.77 5963.47 4659.74 1251.16 5959031.34 5961.29 4635.52 1256.98 5959007.15 5959.46 4611.61 1264.02 5958983.27 5957.96 4588.06 1272.28 5958959.76 5956.81 4564.95 1281.72 5958936.68 MapE DIS VS TFO Tool ft deg/100ft ft deg 531016.68 0.00 -5495.71 0.00 MWD 531008.86 25.00 -5498.93 315.00 MWD 531000.83 25.00 -5501.79 270.00 MWD 530992.55 25.00 -5504.23 269.86 MWD 530984.03 25.00 -5506.24 265.00 MWD 530966.35 25.00 -5508.99 264.8& MWD 530947.92 25.00 -5510.01 264.62 MWD 530928.88 25.00 -5509.29 268.00 MWD 530909.39 25.00 -5506.83 267.83 MWD 530889.59 25.00 -5502.65 267.67 MWO 530874.62 25.00 -5498.40 267.53 MWD 530869.63 25.00 -5496.78 264.00 MWD 530849.65 25.00 -5489.28 263.97 MWD 530829.82 25.00 -5480.20 263.89 MWD 530824.90 25.00 -5477.69 263.86 MWD 530805.35 12.00 -5467.11 265.50 MWD 530781.20 12.00 -5452.90 265.50 MWD 530757.40 12.00 -5437.64 265.52 MWD 530734.05 12.00 -5421.37 265.55 MWD 530711.19 12.00 -5404.13 265.59 MWD 530688.89 12.00 -5385.98 265.64 MWD 530667.21 12.00 -5366.95 265.71 MWD 530646.21 12.00 -5347.10 265.78 MWD 530625.95 12.00 -5326.50 265.87 MWD 530621.99 12.00 -5322.29 265.97 MWD 530606.48 12.00 -5305.18 275.00 MWD 530587.85 12.00 -5283.21 275.08 MWD 530570.11 12.00 -5260.64 275.17 MWD 530553.31 12.00 -5237.55 275.24 MWD 530537.50 12.00 -5213.98 275.30 MWD 530522.71 12.00 -5190.01 275.35 MWD 530509.00 12.00 -5165.71 275.38 MWD 530496.39 12.00 -5141.13 275.40 MWD 530494.00 12.00 -5136.19 275.40 MWD 530484.91 12.00 -5116.35 283.50 MWD 530474.59 12.00 -5091.44 283.48 MWD 530465.44 12.00 -5066.47 283.43 MWD 530457.48 12.00 -5041.50 283.34 MWD 530450.75 12.00 -5016.60 283.21 MWD 530445.26 12.00 -4991.85 283.05 MWD 530441.03 12.00 -4967.31 282.86 MWD 530438.06 12.00 -4943.04 282.63 MWD 530436.37 12.00 -4919.12 282.36 MWD 530435.96 12.00 -4895.61 282.06 MWD 530436.83 12.00 -4872.57 281.73 MWD 530437.15 12.00 -4868.03 281.37 MWD 530438.97 12.00 -4850.05 256.20 MWD 530442.38 12.00 -4828.05 255.91 MWD 530447.05 12.00 -4806.64 255.58 MWD 530452.96 12.00 -4785.88 255.28 MWD 530460.09 12.00 -4765.82 255.03 MWD 530468.44 12.00 -4746.51 254.82 MWD 530477.97 12.00 -4728.02 254.64 MWD by BP Alaska f; Baker Hughes INTEQ Planning Report 1NTE Q Company: BP Amoco Date: 11/28!2008 Time: 12:04:31 Page: 4 Field: Kuparuk Co-ordinate(NE) Reference: Well: 2D-05, True North Site: KRU 2D Pad Vertical (TVD) Reference: 2D-05 Orig Rig 126.0 Well: 2D-05 Sectiou (VS) Reference: Well (O.OON,O.OOE,200.OOAzi) Wellpath: Plan 3, 2D-05t2 Surrey Gakulation Method: Minimum Curvature Db: Orade Survey MD ft 10400.00 10425.00 10430.00 10450.00 10475.00 10500.00 10525.00 10550.00 10575.00 10600.00 10625.00 10650.00 10675.00 10700.00 10725.00 10750.00 10775.00 10800.00 10825.00 91.43 90.62 90.46 90.49 90.52 90.54 90.57 90.60 90.62 90.64 90.66 90.68 90.70 90.71 90.72 90.73 90.74 90.75 90.75 Azim deg 153.45 150.56 149.98 152.38 155.38 158.38 161.38 164.38 167.38 170.38 173.38 176.38 179.38 182.38 185.38 188.38 191.38 194.38 197.38 SS TVD NJS-° E!!'V MapN ft tt ft R 5956.01 4542.32 1292.32 5958914.10 5955.57 4520.25 1304.05 5958892.08 5955.52 4515.91 1306.53 59588$7.75 5955.35 4498.39 1316.17 5958870.26 5955.13 4475.95 1327.18 5958847.87 5954.90 4452.96 1336.99 5958824.92 5954.66 4429.49 1345.59 5958801.48 5954.41 4405.60 1352.95 5958777.63 5954.14 4381.36 1359.04 5958753.41 5953.87 4356.83 1363.87 5958728.9f 5953.58 4332.09 1367.40 5958704.18 5953.29 4307.19 1369.63 5958679.29 5952.99 4282.21 1370.55 5958654.32 5952.68 4257.22 1370.17 5958629.33 5952.37 4232.28 1368.47 5958604.39 5952.05 4207.47 1365.48 5958579.56 5951.73 4182.84 1361.19 5958554.93 5951.40 4158.48 1355.62 5958530.54 5951.07 _ 4134.44 1348.78 5958506.48 htapE DCS VS TFO Tool ft deg/100ft ft deg 530488.66 12.00 -4710.39 254.51 MWD 530500.47 12.00 -4693.66 254.42 MWD 530502.97 12.00 -4690.43 254.37 MWD 530512.68 12.00 -4677.26 89.40 MWD 530523.77 12.00 -4659.94 89.42 MWD 530533.67 12.00 -4641.69 89.45 MWD 530542.36 12.00 -4622.58 89.47 MWD 530549.81 12.00 -4602.64 89.50 MWD 530556.00 12.00 -4581.95 89.53 MWD 530560.92 12.00 -4560.55 89.57 MWD 530564.54 12.00 -4538.51 89.60 MWD 530566.87 12.00 -4515.88 89.63 MWD 530567.89 12.00 -4492.72 89.67 MWD 530567.60 12.00 -4469.10 89.70 MWD 530566.01 12.00 -4445.09 89.74 MWD 530563.11 12.00 -4420.75 89.78 MWD 530558.92 12.00 -4396.14 89.82 MWD 530553.44 12.00 -4371.34 89.85 MWD 530546.69 12.00 -4346.41 89.89 2 3/8" • • a A i$ it ~ j - $ ~ ,.. 1 t~` ` t t $ Y 8 ~~! + i gg .i l + 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PLOT HOLE In accordance with ~0 .~=~C 23.003(t~, all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number r !, (30- - -~ from records, data and logsi 'acquired for well i SPACII_VG i The permit is approved subject to full compliance with 20 AAC EXCEPTION ?3.033. Approval to perforate and produce /inject is contingent !upon issuance of a conservation order approving a spacing ' exception. assumes the liability of any protest to the spacing exception that may occur. i DRY D[TCH A11 dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or -: from where samples are first caught and 10' sample intervals through target zones. I Please note the following special condition of this permit: ~' !Non-Conventional production or production testing of coal bed methane is not allowed ' GVell 'for (name of well until after jCompanv Name) has designed and implemented a water well testing program to provide baseline data ' on water quality and quantity. (Com anv Name} must contact the j Commission to obtain advance approval of such water we(( testing Rev: 1 25.06 C'}ody`transmiral checklist • • i1 m y ~ I rn o a~ o_ - i : II y y ~ ~ a~ o `m ~ ~ o , •N, a ~ ~ ° n c o c y : o' m ~o a: ~, a: aci c w, ~ m : c U' °o ~ ~, ~ ~ ~ ~ ~ m' ~ rn '~~ ~~ a ° ~ °, 3 c o. ~ r, ° 3 Z. m - a~ ~ O. ~: ~ a. c 'y a w U : Q ~ 3 m ~ ~,~ ~ o ~ ~ ~: 3 N M: L - , ~ o N -Q a~ _ ~ a ° E O o: ~, ° ~ a of ~ y. O n`. Q. a O. U 3 C' C' ~ 0 0. ° ~ ~ ~ ~ ~ ~ ~ ~ ~ N' ~ a: O. Y. ~ ~ y ~ ~ ~ N' 7. °s n. a o. o ~ ~' ~ 3. a a 3 °~ ~ '3 a o a, a~, ~ U7. 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