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211-154
Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. fl_j 1 - 15 =1 Well History File Identifier Organizing (done) ❑ Two-sided ❑ Rescan Needed RE AN: OVERSIZED: NOTES: Maps: C or Items: ❑ Grayscale Items: ❑ Logs: ❑ Poor Quality Originals: ❑ Other: ❑ Other: BY: Ma '�ria Date: p�9 /s/ P 1 Project Proofing BY: ri—A aria Date: 719.,? / /s/ (Y.P Scanning Preparation x 30i + = TOTAL PAGES ac �] (Count does not include cover sheet) BY: Maria Date: i JJ o`9 /L�,- /s/ Production Scanning Stage 1 Page Count from Scanned File: (Count does include cover heet 9► ) Page Count Matches Number in Scanning Preparation:aration: YES NO BY: de) Date:7 / 1 a9 /4 /s/r ` I Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Stage 2 Additional Well Reports: YES NO TOTAL PAGES: Digital version appended by: Meredith Michal Date: /s/ Final Page Count: Stage 1 + Stage 2: TOTAL PAGES: Scanning is complete at this point unless rescanning is required. ReScanned BY: Maria Date: /s/ Comments about this file: Quality Checked 7/8/2014 Well History File Cover Page_20140708.doc a 9 0 N < < < N Z Z Z a- o T c Z C >- >- ).- .' N 76 r) U 641 2 N c0 L co co 5 >- N 0 a N a 2 co >, O) Q — Z Z a ° o t L a co w? U d m 0 as o 2 0 U C II t d2 c ur U W 0 0 c co Z ° E m Z Z Q E Y N a Y .) ° E �° o U E >- >- r rN < -J U CO N _ a 1° °' 2 ° ` a Oa c -o o,.. a mm J U @ ? m N = 0 cu - O Li U cc 00 re -0 ii E _. N W Z v p) N a) U U O U d E Z ° a y iUvwQ N o o —I a c m = a N v E0Jo O 5 2 = o U UU 4c^L c ZI 5 t i E rN °2 oN wO op a a) r E a U =' U I m Z m o J ~ m zO c ° >- >- >- E - to Q c V a. N a a f° N �� a2 E ZJ _co w o) C C i0 Z c co m CL J N ° h- E n NC �_ _ ) d 5 ( m co c Q D v c o c Q a --- a• a) ZI - aO Q Z aEo >U DU o 0 20E m z = 2 a) a) Q E m `o Z CL z at -Jo m w o) E > > } o 0 • z o .. t E 0 0 Q t c a°i 'a3 E w E a O 2 OZ O 2 W 0 Z Cl) 0 .� ° t i- ,-- H ° .. a y Ce o E = 60 Q ° E E E z m w Y 1 w o' C z Z OLL to Z O m U 0 c a +. C —En 1 H c Z c N o aus ° a OLL y py ` Q o o Q ° 0 ...7.. 1 ° U r O) 2 '., .0 J — a) d U CC dr—— y J 0 a 0 o d 0. w E SV1 E • 0 u' 1- a 76 a)2 S. u o a°i O o �a°i o a o 13 Joy 3 Z 0 a 0 O 0 CL U o 0 0 N r .41. N r 0 'rte >, O zI c;, ti N m 0 o a 0 o i C ' z E. a CC U w Zto _ ww�� till ca o La_ a NI 11 O co d a J U J W a IX U 1 W Z V U Z t Q V. 0 J °. raa a ° U C C o L .t1 N Oa c E 1 N 9 o 4. m N J t a R a N Z Mg , .g W ce, m co a a �.. itik. Q = c E 1 Q o a Z o ,' E z _ , pi Q_ X o a ad N a) CL N cU w 1Id E o II E a 2 O scmialE Tr [ic OEL L - O SEAN PARNELL,GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 COMMISSIONCONSERVATION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 L. Gantt CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, 2K-08BL1-01 ConocoPhillips Alaska, Inc. Permit No: 211-154 Surface Location: 121' FSL, 94' FEL, SEC. 2, T1ON, R8E, UM Bottomhole Location: 693' FSL, 1403' FWL, SEC. 3, T1ON, R8E, 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 2K-08B, Permit No 211- 152, API 50-103-20111-02. 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, 4 / Daniel T. Seamount, Jr. it-- Chair DATED this day of November, 2011. cc: Department of Fish & Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) STATE OF ALASKA ECEIV � ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL NOV : 7 ?PP 20 AAC 25.005 la.Type of Work: 1 lb.Proposed Well Class: Development-Oil ❑✓ i Service-Winj ❑ Single ZonrAMRacUibeiffi l jgtorl )i]i$ 11 Drill 0 Re-drill ❑✓ Stratigraphic Test ❑ Development-Gas ElService-Supply 0 Multiple Zone Ell•Coalbed .Gas Hydrates Re-entry ❑ Exploratory ❑ Service-WAG CI Service-Disp ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: U Blanket ❑Single Well 11.Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59-52-180 2K-08BL1-01 - 3.Address: 6.Proposed Depth: 12. Field/Pool(s): P P 0(S): P.O.Box 100360 Anchorage,AK 99510-0360 MD: 12145' • TVDSS: 6029' • Kuparuk River Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Surface: 121'FSL,94'FEL,Sec.2,T1ON, RO8E, UM • ADL 25588,•25589 ' Kuparuk River Oil Pool • Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 718'FSL, 1933'FEL,Sec.3,T1ON,RO8E, UM I 2674,2675 12/27/2011 Total Depth: 9.Acres in Property: 14.Distance to 693'FSL, 1403'FWL,Sec.3,T1ON,RO8E,UM 2560 Nearest Property: >15000' 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: /146.5 feet 15.Distance to Nearest Well Open Surface:x- 498310 • y- 5938425 • Zone- 4 GL Elevation above MSL:/f�• feet to Same Pool: 2K-13A,1700' 16.Deviated wlI : Kickoff depth: 10100ft. 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 101.5° deg Downhole:4492 psig . Surface:3875 psig • 18.Casing Program: Specifications Top - Setting Depth -Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade _ Coupling Length MD TVDSS MD TVDSS (including stage data) 3" 2.375" 4.7# L-80 ST-L 2505' 9640' 6026' 12145' 6029' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured) Effective Depth MD(ft): Effective Depth TVD(ft): Junk(measured) 9441' 6098' 7452' 9441' 6098' none Casing Length Size Cement Volume MD TVD Conductor/Structural 74' 16" 115' 115' Surface 3729' 9.625" 2133 sx AS III,595 sx CI G 3770' 2905' Intermediate Production 7393' 7" 230 sx Class G 7434' 5227' Liner 2222' 4.5" 35 bbls Class G 9441' 6098' Perforation Depth MD(ft): Perforation Depth TVD(ft): none none 20.Attachments: Property Plat❑ BOP Sketch E Drilling Program❑✓ Time v.Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report El Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements ❑✓ 21.Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact Gary Eller @ 263-4172 $___ Printed Name L. Gantt Title CTD Engineering Supervisor SignatureC. Phon 263-4021 Date(N nba,\_ . ' 11A( f(//6 III /r Commission Use Only Permit to Drill API Number:_ Permit Approval See cover letter Number: /� -❑�/"/-6- (--a) Date: 0.-"D I 11 q1 for other requirements Conditions of approval: If box i checked,well may not be used to explore for,test,or produce coalbed met anile,gas hydrates,or gas contained in shales: N �:L{,Spa p3;, O P fes & Samples req'd: Yes ❑ o Mud log req'd: Yes ❑ No [/ Other: .os� Ay w -Twe E' H2S measures: Yes [ No ❑ Directional svy req'd: Yes [� No ❑ cti) APPROVED BY THE COMMISSION //73d/if DATE `Jr ( ,COMMISSION I a 1 Form 10-401 (Revised 7/2009) This permit is valid for24&tenths rohn°th2 of approval(20 AAC 25.005(9)) Submit in Duplicate 6.i //•Z1.4 f / ill(( �U s , s ConocoPhillip Alaska P.O.BOX 100360 p, ANCHORAGE,ALASKA 99510-0360f �� $ ;� ) ?MI' November 16, 2011 14/26 a Ol!&Gas cOps, • t.wir;q},.._ �9PFCIIOPrigo Commissioner-State of Alaska Alaska Oil &Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits Permit to Drill applications for three coiled tubing drilling (CTD) laterals out of Kuparuk well 2K-08A(PTD#211-049) using the Nabors CDR2-AC coiled tubing drilling rig. The objective is to drill one cased and cemented sidetrack and two producing A-sand laterals: 2K-08B, 2K-08BL1, and 2K-08BL1-01. Work is scheduled to begin in December 2011. Also included is the sundry application for abandoning the cased portion of 2K-08A below the proposed sidetrack point of 2K-08B. ConocoPhillips requests a variance from the plugging requirements of 20 AAC 25.112(c)(1). There are no perforations in 2K-08A nor does the proposed plugged interval penetrate any permeable formations, so the proposal meets the overall objective of preventing migration of fluids to other hydrocarbon zones or freshwater. Attached to this application are the following documents that explain the proposed job operations: — Permit to Drill Application Forms for 2K-08B, 2K-08BL1, &2K-08BL1-01 — Proposed &Current Wellbore Schematic — BOP Schematic for'bighole' CTD operations and running 3%" liner — BOP Schematic for`slimhole' CTD operations and running 2%" liner — Drilling Program Summary — Directional Plans — 10-403 application for plugging the existing 2K-08A wellbore If you have any questions or require additional information please contact me at my office 907-263-4172. Sincerely, GaryEII ConocoPhi ups Alaska Coiled Tubing Drilling Engineer KRU 2K-08B, BL1, & BL1-01 — Coiled Tubing Drilling Summary of Operations: Well KRU 2K-08A is a suspended well equipped with 4%"tubing and 4'/2"production liner. In June 2011, it was TD'd and cased in the Kalubik shale short of the originally targeted Kuparuk C and A sands. A CTD sidetrack out of the 4%"liner will be drilled and cased across the Kuparuk C and A sands. Two A-sand CTD horizontal laterals will then exit this cased section and be drilled west to increase reservoir exposure. Initially the BOPE for Nabors CDR2-AC will be equipped for`bighole' CTD operations(i.e. 3"BHA). Our first operation will be to drill cement out of the 4%"shoe track from 9348' to 9440' MD. The 2K-08B sidetrack will ultimately exit the 4%" liner at 9425' MD from a mechanical whipstock,rendering the cased interval below 9425' effectively abandoned in 2K-08A. ConocoPhillips requests a variance from the requirements of 20 AAC 25.112(c)(1)to abandon 2K-08A in this manner. After setting the whipstock and milling a window in the 4'/2"liner,we will drill through the Kalubik shale and the C-sand into the A-sand with a 4'/8"bi-center bit to a depth of 9780' MD. We will then run 580' of 31/4",6.6 ppf,L-80 liner with TC-II connections from 9200' to 9780'. The 31/4"liner will be cemented in place with 7 bbl of 15.8 ppg cement,which will isolate the Kuparuk sands and the Kalubik shale behind pipe. After reconfiguring our BOPE for slimhole operations(i.e.2%"BHA),we will set a whipstock in the 31/4" liner at 9650' MD and then make a window exit at that depth. The 2K-08BL1 lateral will be drilled with a 3"bi- center bit targeting the A4 sand west of 2K-08B with a 2920' lateral. The lateral will be completed with 2%" slotted liner to the TD of 12,570' MD with an aluminum billet at 10,100' MD. The 2K-08BL1-01 lateral will kick off from the aluminum billet at 10,100' MD and will likewise target the A4 sand west of 2K-08B well with a 2045' lateral. The hole will be completed with a 2%" slotted liner to the TD . of 12,145' MD with the liner top inside the 31/4" liner at 9640' MD. After completing the 2K-08BL1-01 lateral,as a contingency we will possibly run a 31/4"x 4'h" liner-top packer at 9200' top rovide further isolation to the C-sand formation that is behind the 3'/4"cemented liner. The decision to run a liner-top packer will be based upon the thickness and reservoir quality that we find in the C- sand as well as success of the 31/4" liner cement job. Drilling Program - 20 AAC 25.005(c)(13) Pre-CTD Work 1. Positive pressure and drawdown tests on master valve&swab valve 2. Prep site for Nabors CDR2-AC, including setting BPV Rig Work 1. MIRU Nabors CDR2-AC rig using 2%"coiled tubing. NU 7-1/16"BOPE,test. BOPE will be configured for`bighole' CTD operations. 2. 2K-08B Sidetrack(Intermediate Hole Section) a. Drill out the 4'/2"shoe track to a depth of 9440'. b. Set whipstock in 4%" liner at 9425' MD c. Mill 3.80"window with high-side orientation at 9425' MD d. Drill 3.70"x 4'/8"bi-center lateral to TD of 9780' MD e. Lay in over-balanced fluid prior to running liner f. Run 31/4"blank liner with TC-II connections from TD up to 9200'inside the 4'/2"liner g. Cement 31/4"liner in place with 7 bbl of 15.8 ppg cement using 2%e-coil Page 2 of 6 p �, November 16,2011, FINAL 4M KRU 2K-08B, BL1, & BL1-01 — Coiled Tubing Drilling 3. 2K-08BL1 Lateral(A4 sand,west) a. Swap from 2%"to 2"e-coiled tubing. Reconfigure BOPE for slimhole drilling; retest BOPE as needed. b. Set a monobore whipstock in the 31/4"liner at 9650' MD c. Mill 2.74"window with high-side orientation at 9650' MD d. Drill 2.70"x 3"bi-center lateral to TD of 12,570' MD e. Lay in over-balanced fluid prior to running liner f. Run 2%"slotted liner with an aluminum billet from TD up to 10,100' MD 4. 2K-08BL1-01 Lateral(A4 sand,west) a. Kick off of the aluminum billet at 10,100' MD b. Drill 2.70"x 3"bi-center lateral to TD of 12,145' MD c. Lay in over-balanced fluid prior to running liner d. Run 2%"slotted liner from TD up to 9640' MD,up inside the 31/4"liner 41")- 5. OPTIONAL: Run 31/4"x 41/4"liner-top packer at 9200' to ensure isolation of the C-sand efP 6. Freeze protect. Set BPV,ND BOPE. RDMO Nabors CRD2-AC. Post-Rig Work 1. Pull BPV 2. Obtain static BHP 3. Put well on production Directional - 20 AAC 25.005(c)(2) & 20 AAC 25.005(d) • See attached directional plans: 1. 2K-08B,plan#6 2. 2K-08BL1,plan#7 3. 2K-08BL1-01, plan#6 • • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. . • 2K-08B CTD laterals: >15,000' to property line, 1700' to the 2K-13 CTD laterals ' Casing Program 20 AAC 25.005(c)(6) • 2K-08B: 3%", 6.6#,L-80,TC-II solid liner from 9200' to 9780' MD o Annular capacity(gauge hole)of the—580' of 31/4"liner is 3.3 bbl. o Proposed 7 bbl cement volume provides>100%excess cement compared to gauge hole • 2K-08BL1: 23/",4.7#,L-80, ST-L slotted/solid liner from 10,100' MD to 12,570' MD • 2K-08BL1-01: 2%",4.7#,L-80, ST-L slotted/solid liner from 9640' MD to 12,145' MD - Existing Casing/Liner Information: s >> Surface: 9/8 ,J-55, 36 ppf Burst 3520 psi Collapse 2020 psi Production: 7",J-55,26 ppf Burst 4980 psi Collapse 4320 psi Liner: 4'/2",L-80, 12.6 ppf Burst 8430 psi Collapse 7500 psi Page 3 of 6 November 16,2011, FINAL KRU 2K-08B, BL1, & BL1-01 — Coiled Tubing Drilling Reservoir Pressure - 20 AAC 25.005(c)(4)(A) • Well 2K-08A does not penetrate the Kuparuk sands so there is no formation pressure measurement available in the immediate vicinity of the planned 2K-08B. The best indication of expected formation pressure was provided by the initial pressure measurement in the 2K-13A sidetrack in June 2011, 1700' to the south. It measured A-sand reservoir pressure of 3799 psi at 9050' MD, 6090' TVD,corresponding to 12.0 ppg EMW. This well has been on pre-production for the last several months, so we expect formation pressure in the vicinity of 2K-08B to now be 3500 psi or 11.0 ppg. We have little data on the differential pressure between the A-sand and the C-sand formations, but we generally expect pressures to be similar. We expect to encounter similar pressure as laterals are drilled away from the mother well. • Maximum potential formation pressure in 2K-08B is based on the 2M-14 injection well to the northwest, which in 2007 had measured formation pressure of 4527 psi at 6200 TVD for a pressure gradient of 14.0 . ppg. In 2K-08B this gradient equates to a maximum potential formation pressure of 4492 psi(6171' TVD) and a maximum potential surface pressure of 3875 psi assuming a gas gradient to surface. Mud Program -20 AAC 25.005(c)(8) • Will use formate-based fluids(10.5 ppg planned, 10.0— 11.0 ppg possible)for milling operations and drilling the 2K-08B interval with the bighole CoilTrak assembly. We will use bromide-based Flo-Pro . mud(10.5 ppg planned, 10.0— 11.0 ppg possible)for drilling operations in the subsequent slimhole horizontal laterals. • In all laterals we will have to lay in weighted completion fluid to over-balance formation pressure prior to running 31/4" solid liner and 2%" slotted liner. The weight of the completion fluid is typically planned to match or slightly exceed the pressure held at the window during MPD operations. This targeted pressure at the window is as much based on hole stability considerations as it is over-balancing formation pressure. In 2K-08B (bighole, intermediate hole section)we plan to use 12.5 ppg fluid but it could be increased to • as much as 13.0 ppg. In the 2K-08BL1 and 2K-08BL1-01 slimhole laterals we plan to use 11.8 ppg fluid • but it could be increased to 13.0 ppg if needed. Managed Pressure Drilling: Managed pressure drilling(MPD)techniques will be employed to provide constant bottom hole pressure by . using drilling fluid hydrostatic pressure in combination with annular friction and applied surface pressure. A hydraulic choke for regulating surface pressure is installed between the BOPE choke manifold and the mud pits, independent of the BOPE choke. A minimum, constant over-balancing pressure is targeted at the window based on shale stability concerns and is adjusted as necessary based on reservoir pressure encountered during the drilling operation. Pressure at the 2K-08B Window(9425' MD, 5944' SSTVD, 6091' TVD) Using MPD—2'/8" Coiled Tubing Pumps On (2.3 bpm) Pumps Off A&C-sand Formation Pressure (11.0 ppg) 3484 psi 3484 psi Mud Hydrostatic(10.5 ppg planned) 3326 psi 3326 psi Annular friction (i.e. ECD, 0.06 psi/ft) 566 psi 0 psi Mud + ECD Combined 3892 psi 3326 psi (no choke pressure) (overbalanced (underbalanced —410 psi) —160 psi) Target BHP at Window(12.5 ppg) 3959 psi 3959 psi Choke Pressure Required to Maintain 70 psi 630 psi Target BHP Page 4 of 6 Q R I G I A L November 16,2011, FINAL KRU 2K-08B, BL1, & BL1-01 —Coiled Tubing Drilling Pressure at the 2K-08BL1 Window(9650' MD,6025' SSTVD, 6172'TVD) Using MPD-2" Coiled Tubing Pumps On (1.5 bpm) Pumps Off A-sand Formation Pressure(11.0 ppg) 3530 psi 3530 psi Mud Hydrostatic(10.5 ppg planned) 3370 psi 3370 psi Annular friction (i.e. ECD, 0.035 psi/ft) 338 psi 0 psi Mud + ECD Combined 3708 psi 3370 psi (no choke pressure) (overbalanced (underbalanced -180 psi) -160 psi) Target BHP at Window(11.8 ppg) 3787 psi 3787 psi Choke Pressure Required to Maintain 70 psi 420 psi Target BHP BOPE - 20 AAC 25.005(c)(3) • Two well bore volumes of emergency kill-weight fluid will be available to the rig during drilling operations. The emergency 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. • Two BOP diagrams are attached. o The 2K-08B sidetrack will be drilled, cased, and cemented using 23/8"coiled tubing. BOPE configuration for the `bighole BHA' will be used during these operations. We will begin drilling operations on 2K-08B using this BOPE configuration. The variable bore rams(25/8"to 3'/2"range) will provide secondary well control while running 31/4" liner. o The `slimhole BHA' BOPE configuration will be used for all remaining operations,which consists of drilling and lining the 2K-08BL1 and 2K-08BL1-01 laterals. These operations will be conducted with 2"coiled tubing. We will switch to this BOP configuration prior to running a whipstock inside the 31/4"cemented liner. The 2%"rams will provide secondary well control while running 2%" liner. • Pipe rams,blind rams and the CT pack off will be pressure tested to 250 psi and to 4500 psi. The maximum potential surface pressure in 2K-08A is 3875 psi assuming a gas gradient to surface. • The annular preventer will be tested to 250 psi and 2500 psi. Liner Running: • Since there is no SSSV,the 2K-08A CTD laterals will have to be displaced to an overbalancing fluid prior to running liner. See the"Mud Program" section for details. • While running 31/4"solid liner, a floor valve with appropriate threads will be on the rig floor. The variable bore rams(2%"to 3'/2"range)will provide secondary well control while running 31/4" liner. • While running 2%" slotted liner, a joint of 2%"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 2%"rams will provide secondary well control while running 2%" liner. Pressure Deployment of BHA: Double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA,and a slickline lubricator are used to deploy and undeploy the BHA under pressure. The BHA is too long to simply isolate by closing the double swab valves on the Christmas tree, so the BHA has to be lubricated under pressure. The pressure control equipment listed 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. The reverse is used for BHA undeployment. Page 5 of 6 ORIGINALNovember 16, 2011, FINAL KRU 2K-08B, BL1, & BL1-01 — Coiled Tubing Drilling • 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, external pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. Drilling Hazards - 20 AAC 25.005(c)(4)(B) & 20 AAC 25.005(c)(4)(C) • One significant drilling hazard in 2K-08A is uncertainty of formation pressure in the A-sand. The expected formation pressure is—3500 psi(i.e. 10.9 ppg), although there are offset wells that range from 14.0 ppg to 8.0 ppg. The A-sand horizontal laterals are targeting a relatively isolated and undeveloped fault block, increasing the degree of uncertainty. Use of Managed Pressure Drilling(MPD)techniques will mitigate the risk. We have also shut in those offset wells with the most extreme pressure differentials to allow formation pressure to better equalize. • Shale stability is the major concern of the 2K-08B sidetrack. We will cut—35' TVD of Kalubik shale after exiting the 4'/2" liner. We will mitigate the potential for hole collapse by cutting this shale at 70° - inclination or less and by ma+intaining a minimum 12.5 ppg ECD. In addition,we'll minimize exposure time by drilling as short an interval as possible and quickly running 31/4"liner across this shale. • Well 2K-08A has no measured H2S since it is a suspended well that does not penetrate the Kuparuk sands. Well 2K-07 is located 25' to the right side and 2K-09 is 25' to the left side of the 2K-08A surface location. Well 2K-07 has 38 ppm H2S and 2K-09 has 40 ppm H2S as of October 2011. The maximum H2S level on the pad is 63 ppm from well 2K-21A(October 2011). All H25 monitoring equipment will be operational. Waste Disposal - 20 AAC 25.005(c)(14) • 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. Page 6 of 6November 16,2011, FINAL 3T • i _.a [I. CD 11 Cl.) cn .Q cn II o va E 0 al Q) Cl) i =. > o o Uo N N 0 7a _ct N 0� Q ra ., 'Ur V •� s V (� 11 V J L n ti ti N 9` I' 3 = _ CO JU : � M• I 0 LLu) IIiIt CO NC 0 tl c :`"=._-ce Q' U u _ nu a u` 0 il 1:3 'n ,i w D 1HE r- l 4 W Nabors CDR-2AC Kuparuk Managed Pressure Coil Tubing Drilling BOP Configuration for 2" Coil Tubing Ti Lubricator Riser Annular Blind Blind/Shear 2" Pipe/Slipl ► (CT)L Pump into Lubricator \/I above BHA rams - l>` 1 r r Choke 1 2-3/8" Pipe/Slip(BHA) Choke Equalize Manifold 2-3/8" Pipe/ II Slip(BHA) Kill ►;O<J L><>< L 0 i 1 r Blind/Shear 2"Pipe/Slip(CT) -i r Choke 2 i Swab Valves L Wing Valves '4-41i41 NI Tree Flow Cross Surface Safety Valve BOPE: 7-1/16", 5M psi, TOT Choke Line: 2-1/16", 5M psi X Master Valve Kill Line: 2-1/16", 5M psi Equalizing Lines: 2-1/16", 5M psi Choke Manifold: 3-1/8", 5M psi Riser: 7-1/16", 5M psi, C062 Union t . U ' i <, 0 z (..1 b ip — h NN a) N- ic) (o `t d o -0 O O O D o Cc) N O Cr) N O (6 p N N O I- .G I- 'c :04. ti J m JO .- co o I. oo 0 co c[iO Eto CDr N O N MO to_ Ot` in cY \ Y(0 m ^ N to II O N N N NfII _Q' d0co O O W O� O - M JN 3.(off OM J N C) 3 y ti _ Naok �j - ao `p o m tN m M v U O X W U (6 NCD Y � a) o p dm 010 mo p � n LO cU md N O Q N 'O Q'm - CL0 c O NX d 0 X v2 PaOOJti W m m o 0 3 . a 0_ 0- � a p ° O C 43 ii o 0 3 � rn E _ I 'Co ° o u . c`% 3 to V c� 3 m 13) ‘\ \i CI U I II: a/ I77�77� 1 A�1 O O \\ 0 aN O 0 m M C a. I / \ c3 ,:1- = Y7U N CO � Q o [o - ED_ N ',:-=!, V to cy, co COI 2 LO r O .a J 22-4 N 4- Xk 19 2 p 1 co 1- Li" - cng m2 o -J - E o c.irn N to ` M .- V N Q N (o n 3 N N- _C \ N .- co CA co v 3 v r- 0 RIGINIAL ConocoPhi ps Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 2K Pad 2K-08 2K-08BL1-01 Plan: 2K-08BL1-01_wp06 Standard Planning Report 02 November, 2011 ISOM BAKER HUGHES OIflGJNAL 1.7' ConocoPhillips or its affiliates Ird' ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 2K-08 Company: ConocoPhillips(Alaska)Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2K-08A(D141)@ 146.508(D141 (28+118.5)) Site: Kuparuk 2K Pad North Reference: True Well: 2K-08 Survey Calculation Method: Minimum Curvature Wellbore: 2K-08BL1-01 Design: 2K-08BL1-01_wp06 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 Site Kuparuk 2K Pad Site Position: Northing: 5,938,600.18ft Latitude: 70°14'36.519 N From: Map Easting: 498,310.17ft Longitude: 150°0'49.133 W Position Uncertainty: 0.00 ft Slot Radius: " Grid Convergence: -0.01 ° Well 2K-08 Well Position +NI-S 0.00 ft Northing: 5,938,425.30 ft Latitude: 70° 14'34.799 N +E/-W 0.00 ft Easting: 498,310.18 ft Longitude: 150°0'49.132 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 118.50ft Wellbore 2K-08BL1-01 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2011 12/10/2011 16.33 79.81 57,353 'Design 2K-08BL1-01_wp06 Audit Notes: Version: Phase: PLAN Tie On Depth: 10,100.00 Vertical Section: Depth From(TVD) +N/-5 +E/-W Direction (ft) (ft) (ft) (°) -118.50 0.00 0.00 265.00 Plan Sections Measured ND Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (ft) (0) (°) (ft) (ft) (ft) (°/100ft) (°/100ft) (°/100ft) (°) Target 10,100.00 93.51 231.98 6,045.90 599.72 -7,119.49 0.00 0.00 0.00 0.00 10,180.00 101.51 231.98 6,035.46 550.91 -7,181.92 10.00 10.00 0.00 0.00 10,380.00 91.14 249.21 6,013.30 454.08 -7,354.34 10.00 -5.18 8.62 120.00 10,480.00 91.12 259.21 6,011.32 426.92 -7,450.43 10.00 -0.02 10.00 90.00 10,580.00 91.10 269.22 6,009.37 416.85 -7,549.78 10.00 -0.02 10.00 90.00 10,880.00 90.96 299.22 6,003.85 489.69 -7,837.23 10.00 -0.05 10.00 90.00 11,280.00 90.73 259.22 5,997.70 552.46 -8,224.04 10.00 -0.06 -10.00 270.00 11,630.00 86.94 294.02 6,005.05 592.11 -8,566.26 10.00 -1.08 9.94 96.40 12,145.00 88.09 242.48 6,029.02 576.86 -9,063.29 10.00 0.22 -10.01 270.00 11/2/2011 1:57:02PM Page 2 COMPASS 2003.16 Build 69 IGNr '« k , ..'t. t ConocoPhillips or its affiliates Iran ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 2K-08 Company: ConocoPhillips(Alaska)Inc. ND Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2K-08A(D141)@ 146.50ft(D141 (28+118.5)) Site: Kuparuk 2K Pad North Reference: True Well: 2K-08 Survey Calculation Method: Minimum Curvature Wellbore: 2 K-08BL 1-01 Design: 2K-08BL1-01_wp06 Planned Survey Measured ND Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/_W Section Rate Azimuth Northing Easting (ft) (0) (0) (ft) (ft) (ft) (ft) (°/100ft) (°) (ft) (ft) 10,100.00 . 93.51 231.98 6,045.90 599.72 -7,119.49 7,040.13 0.00 0.00 5,939,026.56 491,191.54 TIP/KOP 10,180.00 101.51 231.98 6,035.46 550.91 -7,181.92 7,106.58 10.00 0.00 5,938,977.76 491,129.10 2 10,200.00 100.50 233.74 6,031.64 539.06 -7,197.57 7,123.20 10.00 120.00 5,938,965.91 491,113.45 10,300.00 95.35 242.40 6,017.83 486.78 -7,281.54 7,211.41 10.00 120.34 5,938,913.66 491,029.47 10,380.00 91.14 249.21 6,013.30 454.08 -7,354.34 7,286.78 10.00 121.53 5,938,880.99 490,956.67 3 10,400.00 91.14 251.21 6,012.90 447.31 -7,373.16 7,306.12 10.00 90.00 5,938,874.22 490,937.86 10,480.00 91.12 259.21 6,011.32 426.92 -7,450.43 7,384.87 10.00 90.04 5,938,853.84 490,860.59 4 10,500.00 91.12 261.21 6,010.93 423.52 -7,470.14 7,404.80 10.00 90.00 5,938,850.45 490,840.89 10,580.00 91.10 269.22 6,009.37 416.85 -7,549.78 7,484.72 10.00 90.04 5,938,843.80 490,761.25 5 10,600.00 91.10 271.22 6,008.99 416.93 -7,569.77 7,504.63 10.00 90.00 5,938,843.88 490,741.26 10,700.00 91.08 281.22 6,007.08 427.74 -7,669.04 7,602.58 10.00 90.04 5,938,854.72 490,642.00 10,800.00 91.02 291.22 6,005.24 455.63 -7,764.92 7,695.66 10.00 90.23 5,938,882.63 490,546.14 10,880.00 90.96 299.22 6,003.85 489.69 -7,837.23 7,764.72 10.00 90.41 5,938,916.70 490,473.85 6 10,900.00 90.96 297.22 6,003.52 499.14 -7,854.84 7,781.45 10.00 -90.00 5,938,926.15 490,456.23 1 11,000.00 90.94 287.22 6,001.86 536.91 -7,947.29 7,870.25 10.00 -90.03 5,938,963.93 490,363.81 11,100.00 90.89 277.22 6,000.27 558.04 -8,044.89 7,965.64 10.00 -90.20 5,938,985.09 490,266.22 11,200.00 90.81 267.22 5,998.78 561.91 -8,144.67 8,064.71 10.00 -90.36 5,938,988.97 490,166.45 11,280.00 90.73 259.22 5,997.70 552.46 -8,224.04 8,144.60 10.00 -90.51 5,938,979.55 490,087.08 7 11,300.00 90.51 261.20 5,997.49 549.06 -8,243.75 8,164.53 10.00 96.40 5,938,976.16 490,067.38 11,400.00 89.39 271.14 5,997.57 542.40 -8,343.40 8,264.38 10.00 96.42 5,938,969.51 489,967.74 11,500.00 88.29 281.08 5,999.61 553.03 -8,442.68 8,362.36 10.00 96.41 5,938,980.17 489,868.46 11,600.00 87.24 291.04 6,003.52 580.63 -8,538.59 8,455.49 10.00 96.21 5,939,007.79 489,772.58 11,630.00 86.94 294.02 6,005.05 592.11 -8,566.26 8,482.06 10.00 95.82 5,939,019.27 489,744.91 8 11,700.00 86.96 287.01 6,008.78 616.60 -8,631.68 8,545.10 10.00 -90.00 5,939,043.77 489,679.50 11,800.00 87.07 277.00 6,014.00 637.35 -8,729.24 8,640.47 10.00 -89.63 5,939,064.54 489,581.96 11,900.00 87.27 266.99 6,018.95 640.82 -8,828.93 8,739.48 10.00 -89.10 5,939,068.03 489,482.28 1 12,000.00 87.55 256.98 6,023.48 626.91 -8,927.72 8,839.11 10.00 -88.61 5,939,054.15 489,383.49 1 12,100.00 87.91 246.98 6,027.45 596.05 -9,022.63 8,936.34 10.00 -88.15 5,939,023.31 489,288.59 12,145.00 • 88.09 242.48 6,029.02 • 576.86, -9,063.29 _ 8,978.52 10.00 -87.76 5,939,004.13 489,247.93 I TD 1 1/2/2011 1:57:02PM Page 3 COMPASS 2003.16 Build 69 ConocoPhillips or its affiliates ConocoPhillips Planning Report BAKER, Alaska HUGHES Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 2K-08 Company: ConocoPhillips(Alaska)Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 2K-08A(D141)@ 146.50ft(D141 (28+118.5)) Site: Kuparuk 2K Pad North Reference: True Well: 2K-08 Survey Calculation Method: Minimum Curvature Wellbore: 2K-08BL1-01 Design: 2K-08BL1-01_wp06 Targets Target Name -hit/miss target Dip Angle Dip Dir. ND +N/-S +E/-W Northing Easting -Shape (0) (°) (ft) (ft) (ft) (ft) (ft) Latitude Longitude 2K-08BL1-01_Polygoi 0.00 0.00 0.00 822.79 -9,238.30 5,939,250.08 489,072.99 700 14'42.836 N 150°5 17.740 W -plan misses target center by 6034.66ft at 12000.00ft MD(6023.48 ND,626.91 N,-8927.72 E) -Polygon Point 1 0.00 822.79 -9,238.30 5,939,250.08 489,072.99 Point 2 0.00 403.74 -9,282.19 5,938,831.08 489,029.01 Point 3 0.00 349.32 -7,122.96 5,938,776.18 491,188.01 Point4 0.00 734.37 -7,112.06 5,939,161.19 491,198.99 Point 5 0.00 822.79 -9,238.30 5,939,250.08 489,072.99 2K-08BL1-01_T2 0.00 0.00 5,998.00 554.98 -8,247.12 5,938,982.07 490,064.01 70°14'40.213 N 150°4'48.912 W -plan misses target center by 6.40ft at 11302.98ft MD(5997.46 ND,548.62 N,-8246.69 E) -Point 2K-08BL1-01_T1 0.00 0.00 6,051.00 563.21 -7,111.98 5,938,990.05 491,199.03 70°14'40.305 N 150°4'15.909 W -plan misses target center by 33.98ft at 10115.78ft MD(6044.72 ND,590.03 N,-7131.89 E) -Point 2K-08BL1-01_T3 0.00 0.00 6,029.00 561.81 -9,060.22 5,938,989.08 489,250.99 70°14'40.271 N 150°5 12.553 W -plan misses target center by 15.36ft at 12145.00ft MD(6029.02 ND,576.86 N,-9063.29 E) -Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (") (") 3,763.50 2,751.86 9 5/8" 9-5/8 12-1/4 7,512.17 5,121.79 7"TOW 7 8-1/2 9,444.00 5,952.34 4-1/2" 4-1/2 4-1/2 12,145.00 6,029.02 2-3/8" 2-3/8 3 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (ft) (ft) (ft) (ft) Comment 10,100.00 6,045.90 599.72 -7,119.49 TIP/KOP 10,180.00 6,035.46 550.91 -7,181.92 2 10,380.00 6,013.30 454.08 -7,354.34 3 10,480.00 6,011.32 426.92 -7,450.43 4 10,580.00 6,009.37 416.85 -7,549.78 5 10,880.00 6,003.85 489.69 -7,837.23 6 11,280.00 5,997.70 552.46 -8,224.04 7 11,630.00 6,005.05 592.11 -8,566.26 8 12,145.00 6,029.02 576.86 -9,063.29 TD 11/2/2011 1:57:02PM Pag(t 4 `, COMPASS 2003.16 Build 69 1 a s f t a ConocoPhillips ConocoPhillips (Alaska) Inc. -Ku p2 Kuparuk River Unit Kuparuk 2K Pad 2K-08 2K-08BL1-01 2K-08BL1-01_wp06 Travelling Cylinder Report 02 November, 2011 ru BAKER HUGHES ConocoPhillips or its affiliates IC ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips(Alaska)Inc.-Kup2 Local Co-ordinate Reference: Well 2K-08 Project: Kuparuk River Unit TVD Reference: 2K-08A(D141)@ 146.50ft(D141 (28+118.5)) Reference Site: Kuparuk 2K Pad MD Reference: 2K-08A(D141)@ 146.50ft(D141 (28+118.5)) Site Error: 0.00ft North Reference: True Reference Well: 2K-08 Survey Calculation Method: Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore 2K-08BL1-01 Database: EDM Alaska Prod v16 Reference Design: 2K-08BL1-01_wp06 Offset TVD Reference: Offset Datum Reference 2K-08BL1-01_wp06 Filter type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of refer( Interpolation Method: MD Interval 25.00ft Error Model: ISCWSA Depth Range: 10,100.00 to 12,145.00ft Scan Method: Tray.Cylinder North Results Limited by: Maximum center-center distance of 1,411.70ft Error Surface: Elliptical Conic Survey Tool Program Date 11/2/2011 From To (ft) (ft) Survey(Wellbore) Tool Name Description 32.50 7,432.50 2K-08 GyroData(2K-08) GYD-CT-CMS Gyrodata cont.casing m/s 7,434.17 7,669.77 2K-08A MWD(R500)(2K-08APB2) MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC 7,720.17 9,403.48 2K-08A(R1000)(2K-08A) MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC 9,403.48 9,650.00 2K-08B_wp06(2K-08B) MWD MWD-Standard 9,650.00 10,100.00 2K-08BL1_07(2K-08BL1) MWD MWD-Standard 10,100.00 12,145.00 2K-08BL1-01_wp06(2K-08BL1-01) MWD MWD-Standard r Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name n n 9,444.00 6,098.84 4-1/2" 4-1/2 4-1/2 12,145.00 6,175.52 2-3/8" 2-3/8 3 I 3,763.50 2,898.36 9 5/8" 9-5/8 12-1/4 7,512.17 5,268.29 7"TOW 7 8-1/2 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 2K Pad 2K-08-2K-08BL1 -2K-08BL1_07 10,124.98 10,125.00 0.60 1.47 -0.43 FAIL-Major Risk 2K-13-2K-13-2K-13 Out of range 2K-13-2K-13A-2K-13A Out of range 2K-13-2K-13AL1 -2K-13AL1 Out of range 2K-13-2K-13AL2-2K-13AL2 Out of range 2K-28-2K-28AL1 -2K-28AL1_wp03 Out of range Kuparuk 2M Pad 2M-09-2M-09-2M-09 11,850.00 12,177.00 490.09 318.42 178.62 Pass-Major Risk CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 11/2;2011 9:09:05AM Page 2 of 7 COMPASS 2003.16 Build 69 ConocoPhillips or its affiliates Fr ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips(Alaska)Inc.-Kup2 Local Co-ordinate Reference: Well 2K-08 Project: Kuparuk River Unit TVD Reference: 2K-08A(D141)@ 146.50ft(D141 (28+118.5)) Reference Site: Kuparuk 2K Pad MD Reference: 2K-08A(D141)@ 146.50ft(D141 (28+118.5)) Site Error: 0.00ft North Reference: True Reference Well: 2K-08 Survey Calculation Method: Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore 2K-08BL1-01 Database: EDM Alaska Prod v16 Reference Design: 2K-08BL1-01_wp06 Offset TVD Reference: Offset Datum Reference Depths are relative to 2K-08A(D141)@ 146.50ft(D141 (28-Coordinates are relative to:2K-08 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:-0.02° t I Ladder Plot 1 1 I 1 400 ' 1 I I I I 1 1 I I I 1 I I I 1 1 1 I I I 1 1 1 I I 1 I I I 1 I I 1 1 I I I I 1 050 ' t I I I I I 1 I I I 1 [6 1 I 1 1 1 1 I I 1 ca la_ J J _ _ __J J _i __ __ J___ _ a, I I I I I cr) 1 1 I 1 1 . 1 1 1 1 I I I 1 1 a,, 700 * 1 1 I 1 1 I I I t I O 1 1 1 1 I I I 1 1 {� C 1 I I I I OP al 1 I I 1 1 U 1 1 I 1 1 1 I 1 I 350 ' I 1 I 1 i 1 I I 1 � ? i I I I 1 `I 1 I I I I , 1 I I I 1 1 1 1 I I I I 0 1 1 0 2000 4000 6000 8000 10000 12000 M easured Depth LEGEND --A-.-2K-08.2K-03BL1.2K-08BL1 07V0 —9-- 2M-09,2M-09,2M-09 V1 CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 11/2/2011 9:09:05AM Page 7 of 7 COMPASS 2003,16 Build 69 ORIGIN!. L -8 I o. SCO _ _ as N- 1 gi 1 8 a :� --_4_ -II II i I a 8 1 -8 e ri o 8 :. baa + A .a o w 3 SO Ed m 0 W klitl GO � 8 7— j 8 _M. 1 I -o_1_ N Ng —4,--'6----47---1---0' j — .,,,,.4"-- I 1— I I —I - so" `✓ r r-J. ui p I °� o 0 p r rr r-.-. r' rr-rm r o a d 8 0 -o b d o 8 o R. b O0 I �-._o CD W >d so h M O T M h 0 (14/1J oc l)(+)1[11oN/(-)q1nos I 2t N m 0 a 1 o O W V 1 n N ' v7-iiEl s¢ & O y O O V z ra > z z 2,1_ o Q QH N ro Q us co r-.co 1-- -O h r 1 ` p gR,S4 Lo N�O�Qr ��pr NOD � _� O'-NMQ r- T' O en C c- 7-0 0 = O 0 D O 8888Q$ O O O O j M o Y Y J 2 _, aa0 8 8'888888888 1 p L - _ > >YN z J000666600pY Ywwo — - ,� _ �' m cs o33v E2.f,E. gyt/.t..' 2o1 04 NrSQ N WOi ry�2–rr QI,, o a3r mJd + mo "�J N o r ^r ir. b5 m m J C. o o ? Q E o � e� . 8 3 os w v c S- v (7W m p i MO �Oo". MMc . . 04 N �$ .171 MMjp _0D 0D G '4228 2R NN�Np fl f4 �C 1 ! N'' . b V�' �y NNNNN �NN aZM UUMaw Ui G I ''0YOO ©©888 I , IE ./.V ' 00 8888$8$88 88 8 8 $Qtly b . b . 8 ' n• . _ soso ooTh . e .o vo 0 0 2 a ffiv r N 04 e OR ibINAL iana-i eag ueayu (u/k) SL) u1daQ rea!lizA OTU j TRANSMITTAL LETTER CHECKLIST J WELL NAME C / �— 1 1_ l/ j PTD# 2- 1 1 567 Development Service Exploratory Stratigraphic Test Non-Conventional Well pry FIELD: r---k'"lamK2/(-5' �( POOL: kt(r-i-ti4 i u_"-'"_ C) Circle Appropriate Letter/ Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well l( ,2__e- r� ���// (If last two digits in Permit No. 211 152-, API No. 50-/ 13- 2 - �, / API number are --7 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 target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: 1/11/2008 0a - a o a 0 . r . co m - 3 p o pvo C.0 13 p a 3 Nisi.CO CD -.O 7 0 -L cn.o -, p N) p CO -s O o A ofY Oao y (O 0) (b d 7 co) 7 0 N N N co A (p O O O W W W W C.) W C.) CO CO G) N N N N N N N N.) N.) N — — CO 00 J 6) 01 A C.) N 0 A (O co V O OC A W N -, O CO Co -I O of A W N -� O co co O (J7 A W N -, co v /+7j'7' 0 cn cn 0 -v K F * C� co co 0 �. 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