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Home My WebLink About209-051THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Steve Williams Asset Manager ExxonMobil Alaska Production, Inc. PO Box 196612 Anchorage, AK 99519-6601 Re: Point Thomson Field, Thomson Oil Pool, PTU 16 Permit to Drill Number: 209-015 Sundry Number: 320-031 Dear Mr. Williams: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such fiuther time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Q` Je my ice Ch ' /J DATED thisqday of January, 2020. 3BDMS tj JAN 3 12020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 JAN 2 1 202 07-S 11 Z_-7 Z c7 AOC -CC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate L1 Repair Well [ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate❑ Pull Tubing ❑ Chana Approved Program ❑ Plug for Redrill El Perforate New Pool ElRe-enterSusp Well El Alter Casing El Other: tY /= �Eel 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Numbeir 140 46=- ExxonMobil Alaska Production Inc. Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 209-015 ' 3. Address:6. API Number: PO Box 196601, Anchorage AK 99519-6601 50-089-20031-00 -00 APO 7. If perforating: S. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A PTU -16 Will planned perforations require a spacing exception? Yes ❑ No ❑ N a 9. Prrorperty DDeessignation (Lease Number): 7055 I 10. Field/Pool(s): ADL 4F571 Surface / ADL 47571BHL ' A D L. W:7- Point Thomson Unit/ Thomson Oil Pool 11. aR7✓`, PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 17,140' 13,165' 17,033' 13,078' 8190 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 156' 20" 156' 156' n/a n/a Surface 4,869' 13-3/8" 4,869' 4,484' 5,380psi 2,670psi Intermediate 13,552' 10-3/4" 13,552' 10,581' 11,640psi 9,294psi Tie -Back Liner 13,124' 8-5/8" 13,124' 10,282' 13,280psi 12,280psi Prod Liner 4,042' 7-5/8" 17,132' 13,159' 13,630psi 14,300psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 16.700'- 16,881' 12,810'- 12,955' 5-1/2" x 5" S13Cr-95 116,365'(5" seal assy) Packers and SSSV Type: 7-5/8" VCH Gravel Pack Packer Packers and SSSV MD (ft) and TVD (ft): GP Packer: 16,414' MD / 12,577' TVD 3-1/2" Realm 16.75K NE TR-SSSV SSSV: 5,732' MD / 5,093' TVD GP Sump Pkr: 16,889' MD / 12,961' TVD 12. Attachments: Proposal Summary Wellbore schematic � 13. Well Class after proposed work: Detailed Operations Program BOP Sketch ❑ Exploratory ❑ Strati ra hic g p ❑ Development ❑✓ Service ❑ 14. Estimated Date for 2/5/2020 15. Well Status after proposed work: Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without priorwritten approval. Authorized Name: Steve Williams Contact Name: Kenley Scarlett Authorized Title: Point Thomson Asset Manager Contact Email: kenlev.scarlettl Oexxonmobil com Contact Phone: (907)564-3606 Authorized Signature: Date: 1/20/2020 COMMISSION USE ONLY Conditions of approv . Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 3BDMS 1 JAN 312020 Post Initial Injection MIT Req'd? Yes ❑ No ❑�A• Spacing Exception Required? Yes No Subsequent Form Required: j ^' by F-1No APPROVED BY c Approved by: � COMMISSIONER THECOMMISSION Date: (J D �fc� �iseddz�(�� /ia v ° RIQ NAL Submit Form and Form 10-40 Ap ved application is valid for 12 months from the too appy va . Attachments in Duplica) a of/Tnl2p M Exxon Mobil Upstream Oil & Gas Company Post Office Box 196601 Anchorage, Alaska 99519 907 334-2908 Telephone 907 202-2728 Cell 1/20/2020 ER -2020 -OUT -24 Ms. Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Steve Williams Point Thomson Asset Manager RE: Sundry Form 10-403: Solvent Treatment on Gas Injector (PTD No. 209-015) Dear Commissioner Chmielowski, ExxonMobil hereby applies for sundry approval to complete a solvent treatment on the PTU -16 (PTD No. 209-015) gas injection well at Point Thomson. PTU -16 is one of two gas injection wells at Point Thomson that has seen a decline in injectivity. A solvent treatment is designed to dissolve potential fouling mechanisms such as lubrication oil that is introduced into the gas stream through processing. Attached is a Sundry Form 10-403 and approved procedure. If you have any questions please contact Kenley Scarlett at (907) 564-3606 or kenley.scariettl O_exxonmobil.com Sincerely, SLW:lo:ks For and On Behalf of ExxonMobil Alaska Production Inc. Attachment: Sundry Application Form 10-403 Xylene Treatment Procedure A Division of Exxon Mobil Corporation DocuSign Envelope ID: 437BC725-3047-42AA-AE5A-OEOEDOA59D49 E11W, o i l ExxonMobil Alaska Production Inc. Point Thomson PTU -16 (Gas Injector) Xylene Treatment POINT THOMSON 111.] OPERATIONS Prepared: us yned by: Production Engineer Date: January 14, 2020 S- --95E5147E K. Scarlett OocuBlgned by: Reviewed: LE (Y AS Field Superintendent VA1�Yt,ln, I,rbb�S January 14, 2020 Date: D. Croo s R.. Troup t Endorsed: DO S9n dhy: Operations Technical Manager �SaIrbSS Date: January 16, 2020 BfBBB 9 BBF A B L. Cross Approved: oocusianen ey: �� Wells Operations Superintendent J I Lya Date: January 17, 2020 X96 i8*I 669BE�6 1. Tupa Revision date: January 2020 Page 1 Rev: 10 DocuSign Envelope ID: 437BC725-3047-42AA-AE5A-OEOEDOA59D49 PTU -16 Xylene Chemical Treatment Procedure Obiectives `• Inject xylene chemical solvent downhole to remediate declining well infectivity. IMPORTANT: Follow SDS precautions for solvent handling, storage and usage. NOTE: The well will be shut in for approximately 12-18 hours for the chemical treatment. 1.0 Preliminary (Complete Well Handover Process) Step Action I Remarks Who 1.1 Transfer chemical into totes for easier loading onto the hot oil unit. NOTE: Ensure materials handling safeguards and controls identified in the risk screen are implemented during the chemical transfer. 1.2 Locate the hot oil unit no closer than 75' to the PTU -16 wellhouse on central pad, barricade off the area, bond and ground the unit. y 1.3 Stage chemical totes on an elevated platform in secondary containment near hot oil unit or crane supported. 1.4 Ensure that the hot oil unit pre -start checklist has been completed prior to use. NOTE: Ensure atleast one 30kg fire extinguisher compatible with the pumping fluid is available on the unit. 1.5 Confirm that all Xmas tree valves are in the CLOSED position, including the kill (off-flowline) side manual wing valve. I IMPORTANT: Two valves (barriers) are required from both the reservoir and facility (flowline) for rig up. 1.6 OPEN the crown valve to monitor the tree cap pressure gauge and confirm the SSV and lower master valves are holding pressure. NOTE: Complete this prior to rigging up hot oil as part of WIMS testing. 1.7 Make up 2" hard pipe from the hot oil unit to the Xmas tree off-flowline side wing valve using the 3" 15K x 2" 1502 pump in flange and a new BX -154 gasket. Include a to-torq valve and check valve in the rig up at the Xmas tree as an additional barrier. i IMPORTANT: Hard pipe (not flexible hose) must be used as pump pressures will exceed 5000psi; shut in wellhead pressure—8200psi. I IMPORTANT: A check valve must be installed at the wellhead upstream of the to-torq valve to prevent back flow from the well. NOTE: Raise the 2" hard pipe off the pad using wood blocks and position drip trays under all connections. Use whip checks across the union connections. 1.8 Pressure test the hard pipe with diesel from the hot oil unit to 500psi low / 10,000psi high against the closed Xmas tree valves for 5 / 10 minutes. Tests should show no signs of leaks to be accepted as a pass. 1.9 Confirm the well manual wing valve and SDV552001-03 remain CLOSED. 1.10 Confirm the SSSV is hel OPEN om the well HPU. Effective: January 2020 Page 2 Rev: 10 DocuSign Envelope ID: 437BC725-3047-42AA-AE5A-OEOEDOA59D49 2.0 Pump Chemical Treatment Step Action / Remarks Who 2.1 OPEN the Xmas tree lower master valve and SSV552001-02. 2.2 Pressure up the hard pipe from the hot oil unit to wellhead pressure, equalize across and open the manual kill valve. 2.3 Commence pumping chemical solvent, at maximum rate (0.5-0.7bpm) and inject the entire available volume —25bbls 2 �� 2.4 Shut down pump, line up and switch to diesel. Restart and pump approximately 5 bbl to displace surface lines and equipment. 2.5 CLOSE the manual kill side valve and lo-torq valve. Bleed down and suck back any residual line fluids to the hot oil tank. 2.6 Disconnect hard line from Xmas tree and rig down. NOTE: The 3" 15K x 2" 1502 pump in flange and to-torq valve with a bleed cap (i.e. min 2 valves, including wing) may remain on the Xmas tree temporarily while the chemical treatment is evaluated, in case additional treatments are required. 3.0 Evaluation & Injection Restart / ) Allow the chemical sufficient time (several hours, or as observed on the downhole gauge — ��/ engineering to advise) to migrate downhole across the completion screens. NOTE: A volume of 25bbls will provide a hydrostatic pressure of approx. 560psi over 1500' length in the wellbore. After displacing 60psi of gas the net reduction in downhole pressure will be—500psi. This data may (or may not) be useful in monitoring the chemical fluid level using the downhole pressure gauge. • Target a soak time of 6-8 hours once the chemical is estimated or observed to be across the completion screens. • Monitor annulus pressures continually during soak and restart to identify signs of communication. Gradually restart PTU -16 injection from minimum rates (<20MMscf/d) as directed by engineering to displace any residual chemical and confirm satisfactory injectivity remains post-treatment. o Start injection at 8500 psi surface pressure and monitor for rate/pressure changes Do not exceed 8700 psi surface pressure during first hour of restart • Ensure downhole pressure is below 10,200 psi during first hour o Maintain injection at <20mmscfd for 1 hour o Set compressor ramp rate to 0.1 psi/sec and ramp to full rate for approximately 1 day • Monitor surface and downhole pressures during ramp up • Maintain below 10,800 psi on the DHPG at all times o Return PTU -16 to standard flow split as desired by Operations (approx. 40-50% total flow) 1/! IMPORTANT: A gradual injection restart is required to avoid potentially surging the completion screens with fluid, or reaching maximum allowable injection pressure of 11,000psi downhole in the unlikely event that injectivity further declines after chemical treatment. errective:3anuary 1u20 Page 3 Rev: 10 56 /✓'.1yr DocuSign Envelope ID: 437BC725-3047-42AA-AE5A-OEOEDOA59D49 Associated P&IDs • USPT-WP-PDPID-040552-A01, P&ID PTU -16 Injection Well (Rev52 — Markup) Effective: January 2020 Page 4 Rev: 10 DOCUSign Envelope ID: 437BC725-3047-42AA-AE5A-0EOEDOA59D49 PTU -16 Wellhead IftII 1 i y .OS � 1 j.],_i/. ]-3/C 10, D-5/els.( ,N' 2971 C PTU -16 Wellbore Schematic Injection Header Effective: January 2020 Page 5 Rev: 10 DOCtlSign Envelope ID: 437BC725-3047-42AA-AE5A-OEOEDOA59D49 E'NonMobil Insulated Conductor 31"x20-XS6 r 156Tb. /. . "tT' anmauslfhn x�1. 6 9Ppg Isotherm Mousing piker sued Tubing O15psJ1 injected goy: Surface Casing; 1338" 72# L-60 VAM TOP KE.. Special ooft 4867 M074 484' TVO 758" tinertop 7 POR 13,090' MD 110.258' TVD Liter Tie -Back; 8-5A- 52# SW I10T VMA SFC 13-124' NO 110,282' TVD Intarmediafa Casing; 103'4" 71 1# P"110 VAM TOP KS 13 557 NO 110.581' TVD Expandable Casing; 8575' x 10314" SET 14,669' MD 111,274' TVD TOP Thoavoo 16 690 h1D, 12801' TVD Top Ped; % 700 MD, 12 810 TVD Base Per; 16881;p 129E TbD Ease Tnmfsm 17015 MD 13065 T.1. Production Liner T -51r Liner. 471# 13C,%95. FA 17.132 6D 113 157 TVD PTU -16 Current Schematic ALL DEPTHS APPROXIMATE Tubing Hanger 5' DCIM Inc 718 5' DOM Inc 718 .31:2"TR-SCSN Inc 716 55", 29.7d S73Cr95 Tubing 5.5" RPOG Inc 718 15" x 5" Tubing XO P, 23.28 S13Cr95 Tubing MD IW In, 5,640' 5.018' 45 5,661' 5.045 45 5.737 5.093' 45 12821' 10.069' 45 12,962 10,169' 46 AD" Sliding 6lal S13Cr110 16,21T 12.420' 31 .75"'X"Larding Hippie 16,307 12.564' 36 .al Assy Mute Shoe 10,466' 12,610' 36 mag Park Packer UAW 12.5TT 36 i 414 MD.r12 5TTrVD ud LossValse 16475 12.674' 36 i 471610112.624TVD 11.0#Bank Rise 16,503 17.650' 36 11.0# Wow Bank 18580 12.713' 36 .11.0#OpOpac Screen. Too 1665T 1?715' 36 ,1110#Op01eC Screen. Base 16,888 12.961' 36 sail Padc SOUP Pacimr 14888 12.961' 36 f of Shoe Track 17,037 13.078' 36 Wall 17,145 13.165' 35 Ettective: January 2020 Page 6 Rev: 10 T r 0 o N N ey m C � S a a rn rn N m m U N U m 9 G O C O C j L N y N N N N U ^ m m m m N N UI .a U O O s 9 E E c w T N E E C E C C C C O .O m c O _ O C C O `O E E E 3 3 E r m m - U - o E E E E j a in N m m m n N N o a C y m NC O N N O m L O N d N T N U .m X m O E E a "O E E o h m v c x x U z z F- H r c m = m Y Y Y Y Y Y Y YO Y a c o O p O O p O O p w p E u3i T m N -o a a Q a s E X o K m E mE 2 O U E U LL y LL O m N c m E N� Y N c m E a N N d T T O O OU � C O a N A U d C N O C W a w Of d y E y Y Y Y Y Y Y O Y Y O O O O O O O U N O O O ry X N O N O c N C L N m CO E E h � N C m a C NE ^ w C w O L O O O O m E 0 E m m c a OLU o y Y O N iL 7 Lu EY CL �G N= E U m II m E N U W Y Y m a b 11 O„ e np O U U U L O v EE o c a«oi O O T n - n X N C N n C E E O O O O N m N d U N U M N U U C C N m m Z v m m > ` O W � � a w O O O In N U) (n N Z Z Z W x U o N i� it 7 ao a0 01 M aDW �N N "2 N n m N V O U) N L N O O (fl O (O O N v T -E V m i > N m E n N C d U) U) 55 N O U O H �a N !dE m id)w E U a oE a z n a cD n r 0 o N ey m C � O O N C C � m L O � N ^ C E m 3 UI U O O N N T N m c c - p N m _ w m W n °? m L r r a in m c m m O t N N m L N d O T N X 7 m E o o h c c a c c m U C O T N N m C O U N N F- c o m c o C7 = Q rn aCD O O w ria E u3i T m N -o a a Q a s E X o K m mE 2 U E LL y LL O m N c m E N� Y N c E a N N d T T O O OU "NO C O a N C n N n C N O C W a Of d M 0 0 N S U N m a o U N E N O U O ry N O N O c N C L N m O E E C m a C NE ^ w w ry .Q v m E 0 m m c a OLU o y Y O N iL X Lu EY CL �G N= E U m II m E N U W Y Y m a b 11 O„ e np O m m m L O .N EE c a«oi O O T n - n X o v >@ 15 VI N m m U p« m 0 N 0 0 L C > U N O OLh U U C C N T'E 'E N CD C o � � a w ~ ~ • • ConocoPhi I I i ps September 22, 2009 Commissioner D. Seamount State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7t~ Avenue Suite 100 Anchorage, Alaska 99501 Subject: Cancellation Permit to Drill #209-051 (1Q-15L1-01) Dear Commissioner: ~ J. L. Cawvey Afaska Wells Manager Drilling & Wells P. O. Box 100360 Anchorage, AK ~J9510-0360 Phone: 907-265-6306 I~ECEIVED S E P 2 4 2009 Ale~ka Oil & Gas Cons. Con~i~~ior~ Anchorege ConocoPhiliips Alaska, Inc. requests the cancellation of a Permit to Drill #209-051 forwell 1Q-15L1-01. We will not be drilling this well. If you have any questions regarding this matter, please contact J. Gary Eller at 263- 4172. Sincerely, _ Z ~.•. . L. Cawvey Alaska Wells Manager CPAI Wells JLC/JGE/skad ~ ~ ~~~ _ f ' ~ a ' 4s;1 `V ~ r ' f r xq~"; ~`~~"' ~ ~ rs ~ ~ - k `~ ' ` ~ ~ ~ ` ~ ~ ~ ~ SARAH PALIN, GOVERNOR _ ~ ~ C ~ i i~, k i~ ~ ~~ e' i - . . ._, .. .. _. ~_ .~ . . G___ ~ ~ ,. ~ ~ ~~ ~~~ Q~j ~~ ~~ ~ 333 W. 7thAVENUE, SUITE 100 COI~SERQATIOl~T C01~1II~i15SIO1~T ~ ANCHORAGE, ALASKA 99501-3539 ~ PHONE (907) 279-1433 ' FAX (907) 276-7542 J. Gary Eller Wells Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, 1 Q-15L 1-O l We11 ConocoPhillips Alaska, Inc. Permit No: 209-051 Surface Location: 1087' FNL, 1834' FEL, Sec. 26, T12N, R9E, UM Bottomhole Location: 1871' FNL, 1717' FEL, Sec. 23, T12N, R9E, UM Dear Mr. Eller: Enclosed is the approved application foz- permit to redrill the above referenced development well. This permit t~ drill does nat 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 w-ithdraw the permit in the event it was erroneously issued. The permit is for a new wellbore segment of e~sting well KRU 1Q-15, Permit Number 185-046, API 029-2130$-00. Production should continue to be reported as a function of the original API numbez stated above. 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 ta comply with an applicable provisian 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 Cornmission's petroleum field inspector at (907) 659-3607 (pager). S' c ely, ,~ /~ athy oer ter ,S ~ Com issioner DATED this U day of May, 2009 cc: Department of Fish & Game, Habitat Section w/ o encl. Department of Environmental Conservation w/o encl. • • ~~~~~~~r~ ~G ~ STATE OF ALASKA '~ ~ ALASKA OIL AND GAS CONSERVATION COMMIS O ~~R ~~ Z(~Q~ ~~~ ~ PERMIT TO DRILL ,~~~ Zo aac Zs.oos Aiaska ~il & Gas Cons. Gommi~~ian 1a. Type of Work: Drill ~ Re-drill Q/ Re-entry ^ 1b. Current Well Class: 6cploratory ~ Development Oil Q/ . Stratigraphic Test ^ Service ^ Development Gas ~ Multiple Zone ^ Single Zone ~ 1c. Specity if well is . Coalbed Methane ^ Gas Hydrates ^ Shale Gas ^ 2. Operator Name: ConocoPhi~lips Alaska, Inc. 5. Bond: / Blanket Single Well Bond No. 59-52-180 ' 11. Well Name and Number: 1Q-15L1-01 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 11050' • ND: 6235' ~ 12. Field/P001(s): Kuparuk River Field , 4a. Location of Well (Governmental Section): Surface: 1087' FNL, 1834' FEL, Sec. 26, T12N, R9E, UM ' 7. Property Designation: ADL 25641, 25634 ' Kuparuk River Oil Pool , Top of Productive Horizon: 529' FNL, 1119' FEL, Sec. 23, T12N, R9E, UM ~ 8. Land Use Permit: ALK 2572, 2567 13. Approximate Spud Date: 7/3/2009 Total Depth: 1871' FNL, 1717' FEL, Sec. 23, T12N, R9E, UM 9. Acres in Property: 2560 14. Distance to Nearest Property: 19990' 4b. Location of Well (State Base Plane Coordinates): Surface: x- 527789 ~ y- 5984784 • Zone- 4 10. KB Elevation (Height above GL): J3' AMSL feet 15. Distance to Nearest Well within Pool: 1 Q-2oA , 1120' 16. Deviated wells: Kickoff depth: 9260 • ft. Maximum Hole Angle: 93° deg 17. Maximum Anticipated Pressures in psig (see 2o aaC 25.035) Downhole: 3644 psig • Surface: 3010 psig ~ 18. Casing Program eCiflCation S Setting Depth Quantity of Cement Size p s Top Bottom c. f. or sacks Hole Casing Weight Grade Coupling Length MD ND MD ND (including stage data) 3" 2-3/8" 4.7# L-80 ST-L 2585' 8465' 6300' 11050' 6235' slotted / solid liner 19 PRESENT WELL CONDiTION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): 8866' Total Depth ND (ft): 6558' Plugs (measured) Effective Depth MD (ft): 8770' Effective Depth ND (ft): 6497' Junk (measured) 8538' Casing Length Size Cement Volume MD TVD ConductoNStructural 102' 16" 240 sx C5 II 102' 102' Surface 4327' 9-5/8" 1200 sx CS lil, 400 sx CS1 4420' 3524' Intermediate Production 8767' 7" 35o sx Class G, 25o sx CS1 8860' 6556' Liner Perforation Depth MD (ft): 8260'-8285', 8394'-8404', 8552'-8626', 8654'-8660' Perforation Depth ND (ft): 6160'-6178', 6252'-6258', 6357'-6406', 6424'-6427' 20. Attachments: Filing Fee ~ BOP Sketch ~ Drilling ProgramQ Time v. Depth Plot ~ Shallow Hazard Analysis Property Plat ^ Diverter Sketch ^ Seabed Report ^ Drilling Fluid Program ~/ 20 AAC 25.050 requirements Q 21. Verbal Approval: Commission Representative: Date: 22. I hereby certi hat th regoing is true and co ct to the best of my knowledge. ContaCt J. Gary Eller @ 263-4172 Printed Name . G8ry EI Title Wells Engineer Signature Phone 2~'~~ (~~-~ ~ Date (~_ ~~ '~~~~ ~~~~ h r n All Ora Commission Use Only Permit to Drill Number: ~~ ~ -~? ej ~ I Number: 50- ~ ~~~ " ~ ~ ~~y~i " ~ ~ Permit Approval Date: Z ( See cover letter for other requirements Conditions of BpprOV81 : If box is checked, well may not be used to explore for, test, or produce coalbed m hane, gas hydrates, or gas contained in shales: ,~' o~.s~~M\nV~.vhC,~l~~~.v,~alCy~- Samples req'd: Yes ^ No ~ Mud log req'd: Yes ^ No [,~ Other: H2S measures: Yes []~ No ~ Dire ~onal svy req'd: Yes [~ No ^ 3Sc~. pQS\ C~st't,+~~ S ~t- l~P ~~~t~~~-a~ ~='1 ac~.yS v~~css~~crw~sE u.c~~~~ i APPROVED BY THE COMMISSION DATE: S ` , COMMISSIONER V t~ t k/ t t C o' 1 w ls Form 10-401 Revised 12/2005 Submit in Duplic te ,•~~/~./~ ~~.~.~ ~ ~ KRU 1Q-15L1, L1-01 - Coiled Tubing Drilling ~ Summarv of Operations: Well 1Q-15 is a 3'h" tubing x 7" casing selective producer in the Kuparuk A-sand. Two proposed CTD laterals will improve sweep efficiency and reserve recovery. Prior to drilling, the existing A-Sand perfs in 1Q-15 will be squeezed with cement to provide a means to kick out of the 7" casing and to change the existing reservoir sweep pattern. The existing selective C-sand perfs in 1Q-15 will remain unaffected. After plugging off the existing 1Q-15 perfs with cement, a pilot hole will be drilled through the cement to 8560' MD, and a mechanical whipstock will be placed in the pilot hole at the planned kickoff point. The 1Q-15L1 lateral will exit the 7" casing at 8520' MD and will target the A3 sand north of the existing welT with a 2839' undulating wellbore. The hole will be completed with a 23/8" slotted liner to the TD of 11,359' MD with a liner top aluminum billet at 9260' MD. The 1Q-15L1-O1 lateral will kick off from the aluminum billet at 9260' MD and will target the A3 sand south '~` of the existing well with a 1790' wellbore. The hole will be completed with a 23/g" slotted liner to the TD of , 11,050' MD with the final liner top located just inside the 3'/z" tubing tail at 8465' MD. CTD Drill and Comnlete 1Q-15 uro~ram: June/Julv 2009 Pre-Ri~ Work 1. Test packoffs - T& IC. 2. Positive pressure and drawdown tests on MV and SV. 3. DGLV's, load tbg & IA. MIT-IA. MIT-OA. 4. Obtain updated static BHP on A-sand 5. Caliper survey across 7" casing and 3'/2" tubing. 6. Shoot tubing punches in 3'h" tubing tail at 8470' MD. 7. RU CTU. Mill out the 2.75" D-nipple at 846T MD to 2.80" ID. 8. Plug the A-Sand perfs with cement up to 8470' MD. 9. RU slickline. Tag cement top. 10. Prep site for Nabors CDR2-AC. Ri~ Work 1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 1Q-15L1 Lateral (north) a. Dri112.80" high-side pilot hole through cement to 8560 MD'. b. Drift pilot hole with whipstock dummy. c. Set 3'/2" monobore whipstock at 8520' MD with high-side orientation. d. Mill 2.74" window with high-side orientation at 8520' MD e. Dri112.70" x 3" bi-center lateral to the north to TD of 11,359' MD. ~ £ Kill well. Run 23/8" slotted liner with an aluminum liner-top billet from TD up to 9260' . - - atera sout ) a. Kick off of the aluminum billet at 9260' MD b. Dri112.70" x 3" bi-center lateral to the south to TD of 11,050' MD. ' c. Kill well. Run 23/8" slotted liner from TD up to 8465' MD, into the 3'/2" tubing tail ~~~~~~~4. Freeze protect. ND BOPE. RDMO Nabors CRD2-AC. ~ ~(~. Post-Ri~ Work 1. Obtain static BHP 2. Run GLVs. 3. Return well to production. ~ Page 1 of 3 ~ ~~~~~~~~ April 15, 2009, FINAL a ~ KRU 1Q-15L1, L1-01 - Coiled Tubing Drilling Mud Program: • Will use chloride-based Biozan brine (8.6 ppg) for milling operations, and chloride-based Flo-Pro mud "(~9.5 ppg) for drilling operations. Since there is no SCSSV installed in 1Q-15, we will have to kill the well to deploy 23/8" slotted liner. Disposal: • No annular injection on this well. " • Class II liquids to KRU 1R Pad Class II disposal well • Class II drill solids to Grind & Inject at PBU Drill site 4 • Class I wastes will go to Pad 3 for disposal. Casing Program: • 1Q-15L1: 23/g", 4.7#, L-80, ST-L slotted liner from 9260' MD to 11,359' MD ~------~- • 1Q-15L1-Ol: 23/8", 4.7#, L-80, ST-L slotted/solid liner from 8465' MD to 11,050' MD Existing Casing/Liner Information Surface: 95/8", J-55, 40 ppf Burst 3950 psi; Collapse 2570 psi Production: 7", J-55, 26 ppf Burst 4980 psi; Collapse 4320 psi Well Control: • Two well bore volumes (~200 bbl) of KWF will be available to the rig during drilling operations. The kill weight fluid may or may not be stored onsite, but if it is stored offsite it will be in the Kuparuk Field within a short drive to the rig. • BOP diagram is attached for operations with 2" coil tubing. • Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3500 psi. Maximum potential surface pressure is 3010 psi assuming a gas gradient to surface and maximum potential formation pressure. Maximum potential formation pressure is based on the highest measured bottom hole pressure in the vicinity, which is 3644 psi in well 1Q-15 itself in July 2008~. Well 1Q-15 had been shut-in several months when this survey was taken. • The annular preventer will be tested to 250 psi and 2500 psi. Directional: • See attached directional plans: 1. 1Q-15L1, plan #5 2. 1Q-15L1-O1, plan #6 • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. • 1Q-15LL• 18,700' to property line, ~2150' from well 1Q-O1 • 1Q-15L1-O1: 19,990' to property line, ~1120' from well 1Q-20A ' Logging • MWD directional, resistivity, and gamma ray will be run over the entire open hole section. - Reservoir Pressure • The most recent static BHP survey in well 1Q-15 was taken September 2008. Virtually the same bottom hole pressure was recorded in July 2008, which measured reservoir pressure of 3644 psi at 8552'MD, 635T TVD, corresponding to ll.0 ppg EMW. This is the highest pressure measured in the area. Expect to encounter similar to decreasing pressure as the laterals are drilled away from the mother well. Page 2 of 3 ~~~~~`,~* April 15, 2009, FINAL tE L ~ ~ KRU 1Q-15L1, L1-01 - Coiled Tubing Drilling Hazards • Lost circulation is not expected to be particularly troublesome. Expect to encounter decreasing pressnre as the laterals are drilled away from the mother well. • Shale stability is a potential problem, particularly in the build section where the A6 sand will be ~ encountered. Will mitigate potential sloughing problems by cutting this interval at no greater than 70° hole angle, and by holding a constant f 12.0 ppg EMW on the formation throughout drilling operations. • Well 1Q-15 has 86 ppm HZS as measured on 6/20/04. Wells 1Q-20A is located IS' to the left and 1Q-14 is 50' to the right side ofthe 1Q-15 surface location. The 1Q-14 has no measured HZS since it is an injectar. The HZS measured in 1Q-20A is 20 ppm (7/2/07). The maximum HZS level on the 1Q pad is 250 ppm from well 1Q-23 (7/2/07). All HZS monitoring equipment will be operational. Managed Pressure Drilling Managed pressure drilling (MPD) techniques will be employed to provide constant bottom hole pressure by using 9.5 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 BOPE 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 23/8" BHA will be accomplished utilizing the 23/8" pipe rams and slip rams. The annular preventer will act as a secondary containment during deployment and not as a stripper. Well 1Q-15 does not have a SCSSV, so the well will have to be killed prior to running slotted liner. Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected at TD: • Estimated reservoir pressure: 3634 psi at 8520' MD (6336' TVD), or 11.0 ppg EMW. ~ • Expected annular friction losses while circulating: 767 psi (assuming friction of 90 psi/1000 ft due to the 3'/2" tubing) • Planned mud density of 9.5 ppg equates to 3130 psi hydrostatic bottom hole pressure at 6336' TVD • While circulating 9.5 ppg mud, bottom hole circulating pressure is estimated to be 3897 psi or 11.8 ppg EMW without holding any additional surface pressure. This is sufficient to overbalance formation pressure in 1Q-15. If increased formation pressure is encountered while drilling the A lateral or the ALl lateral, mud weight or choke pressure will be increased to maintain overbalance. • When circulation is stopped, ~770 psi of surface pressure shall have to be applied to maintain the same borehole pressure as during drilling operations. Page 3 of 3 April 15, 2009, FINAL ~~~ ~~~~~~~ 0 N V / .~...~ ~ ~ ~ 1 Q-15L1, L1-01 16" 62#t H-40 shoe 102' MD 9-5l8" 40# J-55 ~ shoe 4420 MD Squeeze perfs (6/14/85) 8170' - 8172' MD C-sand perfs = 8260' - 8285' MD ~ B-sand perfs 8394' - 8404' Proposed CTD Sidetrack 2-3/8" liner top @ 8465' RKB side 2.80" pilot hole at 8520' hole drilled to 8560' MD. A-sand perfs = 8552' -8626' M D 8654' - 8660' MD - 7" 26# J-55 shoe 8860' MD TD @ 11,050' MD 3" openhole, completed ith 2 ~~ 3/8" 4.6#/ft STL Bla iner from 8465' ro 8975' MD ~~ _ _ \ ~~~ Cement - - - - - - - - - t ta 8703' L Aluminum billet KOP @ 9260' MD 3" openhole, completed with 2 3/8" 4.6#/ft STL slotted liner beiow 8975' MD L1 north lateral TD @ 11,359' MD g @ as ~ RKB (7/23/08) Updated: 15-Apr-09 Baker FVL SSSV @ 1903' MD (IocKed out) 9.3# J-55 EUE 8rd Tubing to surtace Camco KBUG gas lift mandrels @ 2101', 4155', 5462', 6215', 7087', 7521' MD Merla TPDX gas lift mandrel @ 8114' MD 3-1/2" PBR @ 8156' MD FHL packer @ 8169' MD 1l2" Merla TPDX production mandrels @ 8249', 8319', 8429' MD Baker FB-1 packer @ 8449' MD Baker SBE @ 8452' MD Cement top at 3-1/2" Camco D landing nipple @ 8467' MD (2]5" min ID) tubin Nipple milled out to 2.80" ID ~ ~ g punches @ Tubing punches @ 8470' MD ~S ~ 8470' MD 3-1/2" tubing tail @ 8480' MD (8468' WLM) L1-01 south lateral • ~ ~ ~ s w ~~~~-~:~~~~~~~ ~ ~ ~~~~~~ ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 1Q Pad 1 Q-15 Plan 6, 1 Q-15L1-01 Plan: Plan 6 Standard Planning Report 15 April, 2009 .-- BAKER HLl~HE~ INTEQ ~~~~!!\~~ ~ ~ ' Baker Hughes saK R ~~~~~~~~~~~~~ Planning Report ~'~N~ ~~k~ 1NTEQ ~ • ~ ... ,. ~~~ Kuparuk River Unit ,...,.. .....~~ . ~~ . ;,i.: . :~ . . .,,,. ~:: ,,; ;, ,i/Hld/.//./p/,ti, ,,,........,,,..,, .. .:`~r"~?Y%H// , \~`.\\C ..... .\\`. ~ . /.,. ~..a. 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 Position: Northing: 5,984,677.62ft Latitude: 70° 22' 9.206 N From: Map Easting: 528,389.22ft Longitude: 149° 46' 9.484 W Position Uncertainty: 0.0 ft Slot Radius: " Grid Convergence: 0.22 ° Audit Notes: Version: Phase: PLAN Tie On Depth: 9,200.0 ~ OA 0.0 0.0 200.00 I ;,.; ... .. ... . .... „ „ »,v,, .r ,...., .. ,,,,,, ,,,~„ P'i~~'~4~Fisns. .... 9,200.0 91.44 306.40 6,288.0 5,721.6 9,260.0 90.74 312.38 6,286.8 5,759.7 9,280.0 95.44 310.66 6,285.8 5,772.9 9,300.0 98.64 306.79 6,283.3 5,785.3 9,380.0 85.63 291.56 6,280.3 5,824.0 9,430.0 85.73 279.02 6,284.1 5,837.2 9,460.0 86.99 271.61 6,286.0 5,839.9 9,510.0 92.30 260.29 6,286.3 5,836.4 9,680.0 92.71 217.75 6,278.5 5,751.0 9,786.0 93.09 230.48 6,273.1 5,675.2 10,057.0 93.14 197.91 6,258.0 5,454.4 10,134.5 93.15 207.23 6,253.7 5,383.0 10,483.5 93.35 165.28 6,233.0 5,044.4 10,829.5 88.21 206.50 6,228.1 4,707.7 11,050.0 88.18 180.02 6,235.2 4,495.1 904.6 0.00 0.00 0.00 0.00 858.3 10.03 -1.17 9.97 96.64 843.3 25.00 23.49 -8.58 340.00 827.9 25.00 16.00 -19.36 310.00 758.4 25.00 -16.26 -19.04 230.00 710.4 25.00 0.21 -25.07 270.00 680.6 25.00 4.21 -24.69 279.45 630.8 25.00 10.61 -22.64 295.00 488.5 25.00 0.24 -25.02 271.50 415.0 12.00 0.36 12.01 87.97 265.0 12.00 0.02 -12.02 271.00 235.3 12.00 0.01 12.02 89.69 198.2 12.00 0.06 -12.02 271.50 163.4 12.00 -1.48 11.91 96.50 113.3 12.00 -0.02 -12.01 269.50 4/15/2009 1:25: 41 PM Page 2 w~ ~~tl~~~~~~ COMPASS 2003.16 Build 42F Well Position +N/-S 0.0 ft Northing: 5,984,783.67ft Latitude: 70° 22' 10.271 N +E/-W 0.0 ft Easting: 527,788.50 ft Longitude: 149° 46' 27.046 W Position Uncertainty 0.0 ft Welihead Elevation: ft Ground Level: O.Oft ' ~ BakerHughes ~ ~~~~~~~~~~~~~ Planning Report AiaSka ~'°~. B 11LIEGEIES iNTEQ 9,200.0 91.44 306.40 6,288.0 5,721.6 904.6 -5,685.9 3.27 -92.68 5,990,508.02 528,671.78 TIP 9,260A 90.74 312.38 6,286.8 5,759.7 858.3 -5,705.8 10.03 96.64 5,990,545.90 528,625.31 K~P 9,280A 95.44 310.66 6,285.8 5,772.9 843.3 -5,713.2 25.00 -20.00 5,990,559.07 528,610.31 3 9,300.0 98.64 306.79 6,283.3 5,785.3 827.9 -5,719.5 25.00 -50.00 5,990,571.43 528,594.79 4 ` 9,380A 85.63 291.56 6,280.3 5,824A 758.4 -5,732.2 25.00 -130.00 5,990,609.90 528,525.18 5 9,400.0 85.64 286.54 6,281.9 5,830.5 739.5 -5,731.9 25.00 -90.00 5,990,616.34 528,506.32 9,430.0 85.73 279.02 6,284.1 5,837.2 710.4 -5,728.1 25.00 -89.62 5,990,622.84 528,477.14 6 ; 9,460.0 86.99 271.61 6,286.0 5,839.9 680.6 -5,720.5 25.00 -80.55 5,990,625.51 528,447.35 7 9,500.0 91.24 262.56 6,286.6 5,837.9 640.7 -5,705.0 25.00 -65.00 5,990,623.32 528,407.47 9,510.0 92.30 260.29 6,286.3 5,836.4 630.8 -5,700.2 25.00 -64.86 5,990,621.80 528,397.59 8 9,600A 92.70 237.77 6,282.3 5,804.4 547.4 -5,641.6 25.00 -88.50 5,990,589.53 528,314.30 9,680.0 92.71 217.75 6,278.5 5,751.0 488.5 -5,571.3 25.00 -89.50 5,990,535.87 528,255.64 End af 25 deg/10d' DLS 9,700.0 92.79 220.15 6,277.6 5,735.5 476.0 -5,552.4 12.00 87.97 5,990,520.29 528,243.14 9,786.0 93.09 230.48 6,273.1 5,675.2 415.0 -5,474.8 12.00 88.09 5,990,459.76 528,182.39 10 9,800A 93.12 228.80 6,272.4 5,666.1 404.3 -5,4627 12.00 -89.00 5,990,450.67 528,171.77 9,900.0 93.24 216.78 6,266.8 5,593.0 336.6 -5,370.8 12.00 -89.09 5,990,377.29 528,104.35 10,000.0 93.22 204.76 6,261.2 5,507.3 285.7 -5,272.9 12.00 -89.76 5,990,291.49 528,053.68 10,057.0 93.14 197.91 6,258.0 5,454.4 265.0 -5,216.0 12.00 -90.44 5,990,238.44 528,033.18 11 `` 10,100.0 93.16 203.08 6,255:6 5,414.2 249.9 -5,173.1 12.00 89.69 5,990,198.18 528,018.31 10,134.5 93.15 207.23 6,253.7 5,383.0 235.3 -5,138.8 12.00 89.97 5,990,166.96 528,003.78 12 10,200A 93.33 199.36 6,250.0 5,323.0 209.5 -5,073.6 12.00 -88.50 5,990,106.85 527,978.17 10,300.0 93.47 187.34 6,244.1 5,226.0 186.5 -4,974.6 12.00 -88.95 5,990,009.83 527,955.53 10,400.0 93.47 175.31 6,238.0 5,126.4 184.1 -4,880.2 12.00 -89.66 5,989,910.22 527,953.60 10,483.5 93.35 165.28 6,233.0 5,044.4 198.2 -4,807.9 12.00 -90.39 5,989,828.23 527,967.94 13 10,500.0 93.12 167.25 6,232.1 5,028.4 202.1 -4,794.2 12.00 96.50 5,989,812.24 527,971.91 10,600.0 91.68 179.17 6,227.9 4,929.3 213.9 -4,705.2 12.00 96.61 5,989,713.27 527,984.06 10,700.0 90.17 191.08 6,226.3 4,829.9 205.0 -4,608.7 12.00 97.11 5,989,613.84 527,975.51 10,800.0 88.65 202.98 6,227.3 4,734.5 175.7 -4,509.1 12.00 97.31 5,989,518.31 527,946.64 10,829.5 88.21 206.50 6,228.1 4,707.7 163.4 -4,479.7 12.00 97.18 5,989,491.49 527,934.40 14 10,900A 88.16 198.03 6,230.3 4,642.6 136.7 -4,409.3 12.00 -90.50 5,989,426.24 527,907.97 11,000.0 88:15 186.03 6,233.6 4,545.0 115.9 -4,310.5 12.00 -90.23 5,989,328.60 527,887.55 11,050A ` 88.18 180.02 6,235.2 ~ 4,495.1 113.3 -4,262.8 12.00 -89.84 5,989,278.71 527,885.10 TD - 2 3/8" 4/1 fi/2009 9:25:41 PM Page 3 COMPASS 2003. ?6 Build 42F 4.; .,~+" f~ ` ~ ~ t ~ i~ ~ 1Q-15L1-01 t3.6 0.00 0.00 6,233.0 5,044.5 198.6 - plan hits target - Point 1Q-15L1-01 t4.6 0.00 0.00 6,235.0 4,494.8 113.5 - plan hits target - Point 1Q-15L1-01 Polygon 0.00 0.00 0.0 5,762.5 762.3 - plan misses by 628 0.6ft at 9380.Oft MD (6280.3 ND, 5824.0 N, 758.4 E) - Polygon Point 1 0.0 5,762.5 762.3 Point 2 0.0 5,386.7 422.9 Point 3 0.0 4,420.9 330.4 Point 4 0.0 4,450.3 -57.6 Point 5 0.0 5,392.1 42.9 Point 6 0.0 5,795.4 234.4 Point 7 0.0 5,982.3 542.1 Point 8 0.0 5,762.5 762.3 1Q-15L1-01 Fault 1 0.00 0.00 0.0 5,754.8 151.2 - plan misses by 6265.2ft at 10181.Oft MD (6251.1 ND, 5340.7 N, 216.1 E) - Polygon Point 1 0.0 5,754.8 151.2 Point 2 0.0 5,698.7 441.0 Point 3 0.0 5,577.9 665.6 Point 4 0.0 5,698.7 441.0 1Q-1511-01 t2.6 0.00 0.00 6,258.0 5,454.3 265.1 - plan hits target - Point 1Q-15L1-01 t1.6 0.00 0.00 6,278.0 5,708.3 531.1 - plan misses by 59.8ft at 9686.4ft MD (6278:2 TVD, 5745.9 N, 484.6 E) - Point 1Q-15L1-01 Fault 2 0.00 0.00 0.0 5,405.2 14.9 - plan misses by 6246.1ftat 10469.5ft MD (6233.8 ND, 5058.0 N, 194.8 E) - Polygon Point 1 0.0 5,405.2 14.9 Point 2 0.0 5,429.4 255.0 Point 3 0.0 5,463.3 540.2 Point 4 0.0 5,429.4 255.0 5,989,828.40 527,968.33 70° 22' 59.883 N 149° 46' 21.233 W ~ 5,989,278.41 527,885.32 70° 22' 54.477 N 149° 46' 23.724 W ~ 5,990,548.37 528,529.36 70° 23' 6.944 N 149° 46' 4.729 W ~ 5,990,548 .37 528,529. 36 5,990,171 .35 528,191. 38 5,989,205 .35 528,102. 43 5,989,233 .33 527,714. 43 5,990,175 .33 527,811. 38 5,990,579 .35 528,001. 36 5,990,767 .36 528,308. 35 5,990,548 .37 528,529. 36 5,990,538.39 527,918.34 70° 23' 6.868 N 149° 46' 22.619 W I 5,990,538.39 527,918.34 5,990,483.40 528,208.35 5,990, 363.41 528,433.35 5,990,483.40 528,208.35 5,990,238.39 528,033.34 70° 23' 3.913 N 149° 46' 19.285 W 5,990,493.38 528,298.35 70° 23' 6.411 N 149° 46' 11.499 W 5,990,188.39 527,783.33 70° 23' 3.431 N 149° 46' 26.610 W ~ 5,990,188.39 527,783.33 5,990,213.40 528,023.33 5,990,248.42 528,308.33 5,990,213.40 528,023.33 4/15/2009 1:25:4?PM Page 4 COMPASS 2003.16 Build 42F OR~~INAL ~' , , ~ Baker Hughes ~ ~`~ s ~~ ~~~~~~1~~~~~~ Planning Report ~~~~ INTEQ ~° , ~ Baker Hughes ~ ~`~ s Nuci~Es ~t~1`1~-CC?~~'1~~~~~?'?5 Planning Report ~~k~ 1NTEQ 9,200.0 6,288.0 5,721.6 904.6 TIP 9,260.0 6,286.8 5,759.7 858.3 KOP 9,280.0 6,285.8 5,772.9 843.3 3 9,300.0 6,283.3 5,785.3 827.9 4 9,380.0 6,280.3 5,824.0 758.4 5 9,430.0 6,284.1 5,837.2 710.4 6 9,460.0 6,286.0 5,839.9 680.6 7 9,510.0 6,286.3 5,836.4 630.8 8 9,680.0 6,278.5 5,751.0 488.5 End of 25 deg/100' DLS 9,786.0 6,273.1 5,675.2 415.0 10 10,057.0 6,258.0 5,454.4 265.0 11 10,134.5 6,253.7 5,383.0 235.3 12 10,483.5 6,233.0 5,044.4 198.2 13 10,829.5 6,228.1 4,707.7 163.4 14 11,050.0 6,235.2 4,495.1 113.3 TD 4/1~2009 1:25:41PM Page 5 COMPASS 2003.16 Build 42F ~~~G~~~L ~Gonv~oP'hill~ps Pro)ect KuparukRiverUnk ~ * ~ ArknulhsbT .r~en WELLBORE DETAILS: Plan 6, 1415L1-0 REFERENCEINFORMATION M.~.u~r~o,m:zzia __ . Slte: Kuparuk 1 Q Pad ~ ~ ~ CaoNinate (wE) Referenca: wel t~15, True NoM M.y~u~~e 500292130861 . . Wep: 7Q-15 verocel se.npm: s~eeo.an (~) Reference: Maen Sea Level WaNbore: PIaK 6, 14-15U-01 . oiP aya: eo.as section (vs) Re~erence: sbt- (o.ooN, o.ooe o.a:e~i ParentWelibore: PIan5,1415L1 Meaeureaoe 5oN(7~~5) maetere~e: ~a~5~s2 Plan:Plan6 1Q-15/Plan$,1Q-15L1-01 I ~ . . p ..MotlN:USERPEFINE Tleon~.MD:~:9200.00 CelcJetion MeMod: Mimmum CwvaWre WELL DETAILS: 1~-75 Ground Level: 0.00 +WS +E/-W Northing Easting Latittude LongRude Slot 0.00 0.00 5984535.18 1667820.22 70° 22' 9212 N 749° 48' 38284 W SECTION DETNLS ANNOTATIONS Sec MD Inc Azi --- ssND -- - +NIS -._.__.. +EI W _......--- DLeg --- TFace VSec Targel Annotation 1 9200.00 91.44 306.40 6287.99 5721:60 904.62 0.00 0.00 ~6685.94 TIP 2 9260.00 90,74 312.38 8286.85 5759.65 85828 10.03 96:64 -5705,85 KOP 3 9280.00 95,44 310.66 6285.77 5772.89 843.33 25.00 340.00 5713.17 3 4 9300.00 98.64 306.79 6283.32 5785.30 827.85 25.00 310.00 5719.55 4 5 9380.00 85.63 291.56 6280.33 5824.04 758.38 25.00 230.00 5732:19 5 6 9430.00 85.73 279.02 6284.11 5637J6 710.39 25.00 270.00 ~728.10 6 7 9460.00 86.99 271.61 6286.02 5839.93 680.60 25.00 279.45 5720:52 7 8 9510.00 92.30 260.29 6286.33 5836.40 630.82 25.00 295:00 5700.18 8 9 9680.00 92.71 217.75 6278.53 5751.00 488.54 25.00 271,50 557126 End of 25 deg1100' DLS 10 9788:00 93.09 230.48 fi273.15 5675.15 415.00 12.00 87.97 5474.84 10 11 10057.00 93.14 197.91 6258.00 5454.36 264.96 12.00 271.00 5216.04 N 12 10134.50 93.15 207.23 8253.74 5382.98 235.29 12.00 89.69 5138,82 72 13 10483.50 93.35 165.28 6233.03 5044.36 798.18 12.00 271.50 -0807.93 13 14 10829.50 88.21 206.50 6228.11 4707.71 163.39 12.00 96.50 -4479.68 14 15 11050.00 88.18 180:02 6235.18 4495.10 11329 12.00 269.50 -0262.76 TD V / ...~ a~.... ~ ~ ~ Q w O ~ ~ .C O. _ ~ ~ ~ J N U %j ~i m , ~ N ~ H BAKER i~LIGNE~ u . i ...,C Vertical Section at 200.00° (50 ft/in) cv__.i ~m.__~i~. i,cn nr._~ ProJect: Kuparuk River Onlt ~ ~nramWn.mr N nn WELLBORE DETAILS Plan 8, 1Q-15L1-0 REFERENCEINFORMA71oN , ~n0pwm rrwm x~ ia ,r Site: KuparuklfiPad WeIL• 7Q-15 Coo~nele(WE)Refere~e: We17415,TiueNoM sw~y~m°s~eeoa~ 500292130861 i Venkai(ivD~Reference: t4t5~92.5on(7a.75) ' ~ ~~n~~.,,,,t31.,,~11~ ~ ~~1~~ ~~~ '~ Wellboro: ~PIan6.1Q-15L7-01 plan• Plan 6 14-75/Plan 6 7Q•15L7-01 ( ~ o~pr go:eo.es~.. . ~ Seaon~VS)Referenw: Sbt-(O.OON,O.OOEI I 0~ e~+~~ Parent Wellbore: Plan 5, 7Q-1511 (~~~paptl~Reference 7~.75~s2.5on(1~a5) , • Matlq: USER DEFINEDi ~ TI8 00 ~ MDi 9ZOO.OO ~ Cekulation Metlwd. Minimum Curvafure ~,,...J ~ ~ ~ ~ ~+ BAKER HuGNES 1N'l~N:(~ 1Q-15 @ 92.50ft(1Q-15) -Z250 -2100 -1950 -1800 -1650 -1500 -1350 -1200 -1050 -900 -750 -600 -450 -300 -150 0 I50 300 450 600 750 900 1050 1200 1350 t500 1650 I800 1950 2100 2250 2400 2550 2700 2850 3000 3150 3300 West(-)/East(+) (150 ft/in) ~C~~1C?+CC1~"1~~'~t ~5 FroJect: `Kuparuk River Unit Site: Kuparuk 7Q Pad Wall: 1Q-75 Wellbore: Plan 6, 7Q-75L1-01 Plan: Plan 8 (14-15/Plan 6,1Q-75L1-07) ANTFCOLLISION'~3ETTINGS COMPANY~-0ETAILS: ConocoPhiYfps (Alaska)'lrn Interpolatlon Method: MD, interval: 25.00 CelculaGon Method:~~Minimum Curvature Depth Range From: ~9150.00 To 11050.00 Error System: ISCWSA Resulls L(mited By: Centre Distance: 1295.60 ~ Scan Method:. Trev. Cylinder North Reference: Plan: Plan 6(1~-75IPIan 6, 7~-15L1-01) ~ Enor Surface:-FJlipiical Conic 0 -~- WELL DETAILS: iQ-05 ---~ 6round LavN: ---- 0. 00 •IUS +EI.W Norlhinp Easllnp LaUltud~ ~ LonpIWA~ Slo! ~ 0.00 0.00 - _-_-__.._ 5981335A8 ..__._ _ 7887820.22 _______ 70° 4Y' 9212 N 149' IB' 38ZB4 W ~ . . ~ . SECTION DETAILS ~ °- MD Inc Azi ~.ND ...+W-S +g.yy DLeg TFace VSec ~ Target 9200.00 ~ 91.44 306.40 6380.49 5721.60 904.82 0.00 0.00 5H85.84 9280.00 90.74 31238 8379.35 5759.65 858.28 70.03 98.84 5705.85 ~ . 9280,00 85.44 310.68 837827 5772.88 &t3:33 25.00 340.00 5713J7 9300.00 98.84 308.79 637582 5785.30 82Ti85 25.00 310.00 5718.55 9380.00 85.63 291.56 6372.83 5824~.04 759.38 25.00 230.00 5732J9 9430.00 65.73 279.02 8378~.81 5837..18 770.39 25.00 270.00 -5728.W ~ . 9480.00 88.99 271.87 6378.52~~ ~ 5839.93 680.80 ~ 25.00 279.45 5720.52 9570.00 92:30 26029~ 6378.82 5836A0'~ 630,82 25.00 295,00 5700,18 9680.00 92!77 217.75 6377.03 5751.00 488.54 25.00 271.W 5577.28~ ~ 9786.00 93.09 230A8~~ 6365~.85 ~ 5675.15 475.00 12.00 87.97~~474.84 70057.00 93.74 197.97 8350.50 5454.38 264.96 12.00 271.00 5218.04~ 10134.50 93.15 ~ ~ 20723 8348524 538298 23529 12~.00 88.89 -5138.82 ` 70483.50 93.35 16528 6325.53 ~ 6044.38 ~ 198.78 12.00 271.50 4807.93 10829.50 8821 206.50~ 632(1.87~ ~4707.71~ 183.39. 12.00 96.50 -0479.68 17050.00 88J8 780.02 ~. ~6327,88 4495.10 113.29 12.00 289.50 4282.78. SURVEY PROGRAM ~ ~ Date: 20090331T00:00:00 Valideted: Yes Versbn: DepM~Fmm DepthTo. Survey/%an Tod ~ 100.00 ~ 8500.00. 1f]-15 (1~-15) ~ GCT-MS 8500.00 9200.00 Plan 5(Plen 5, 1Q-75L1) MWD 9200.00 11050.00 Plan 6 Plen 6, ta-15L1-01 MWD LEGEND « 1Q-15, Plan 5, 1Q-15L1, Plan 5 VO ll~i 1 L' u Travelling Cylinder Azimuth (TFO+AZI) [°] vs Centre to Centre Separation [16 ft/in] • ~ Nabors CDR-2AC Kuparuk Managed Pressure Coil Tubing Drilling BOP Configuration for 2" Coil Tubing Pump into L~ above BH~ Kill ~~~~~~~~,j~~. ~ • TRANSMITTAL LETTER CHECKLIST _ WELL NAME _ l~~~'~ ~CL~ I ~~ ~ ! "~ I PTD# ~~.-~~ . _ ~'-',~ / i~ , Development Service Exploratory Stratigraphic Test Non-Conventional Well FIELD: POOL: Circle Appropriate Letter / Paragraphs to be Inciuded in Transmittal Letter CNECK ADD-ONS WHAT (OPTIONS) APPLIES TEXT FOR A,PPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing / well ~~~~1-( l _~ _ / ~ (If last two digits in , ~ t API number are Permit No.%~_,'~~., , qpi i•No. 50-~~ -~./ ~~~~ ;_~~ between 60-69) Production should continue to be reported as a function of the original API number stated above. PtLOT HOLE [n accordance with 20 AAC 25.005( fl, all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - -_) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / iniect 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 q(~ dry ditch sample sets submitted to the C i SAMPLE omm ssion must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals throu h tar et zones. Non-Conventional We~~ P(ease note the following special condition of this permit: production or production testing of coal bed methane is not allowed for (name of well) until after ~Comuanv Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. ~Companv Name) must contact the Commission to obtain advance a roval of h pp suc water well testing ro ram. 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