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202-225
MEMORANDUM- State .,aSka Alaska Oil and Gas Conservation Commission TO: Randy Ruedrich ~ Commissioner DATE: April 8, 2003 THRU: Maunder/Regg P.I. Supervisor ~\~ '0V:;\ù/ SUBJECT: Plug & Abandonement Ivik #1 Pioneer Natural Resouces Exploration . ·etD~· FROM: Lou Grimaldi Petroleum Inspector CONFIDENTIAL Section: 6 Lease No.: 389950 Operator Rep.: Township: 13N Drilling Rig: Nabors 27E Range: 8E Rig Elevation: Meridian: Umiat Total Depth: 6950 CasinglTubing Data: Conductor: 0.0. Shoe@ Surface: 0.0. Shoe@ Intermediate: 0.0. Shoe@ Production: 0.0. Shoe@ Liner: 0.0. Shoe@ Tubing: 0.0. Tail@ Casing Removal: ft. Casing Cut@ ft. Casing Cut@ ft. Casing Cut@ ft. Casing Cut@ ft. Casing Cut@ ft. Casing Cut@ Feet Feet Feet Feet Feet Feet Type PluQ (bottom up) Founded on Bottom of Cement Pluggina Data: Top of Cmnt Depth Verified? Mud Weight above plug Pressure Test Applied Annulus Balanced 3113 Surface Visual N/A No Type Plug Founded on: Verified? Open Hole: Bottom Drillpipe tag Perforation: Bridge plug Wireline tag SCI\NNEO JUN 1 ..i 20GB Annulus: Balanced C.T. Tag Casing Stub: Retainer Surface: ~~ cef-i I arrived location and stood-by while slickline finished rigging down from the well. The cßri( was circulated down the tubing and back up the 3 1/2 x 7 5/8 liner and up through the 13318 surface casing. Cement was circulated to surface, returns were visible in the slop tank. I witnessed a weight on the cement returns of 15.5+ with a good clean consistency. Gary Goerfich (Company rep.) went out of his way to accommodate my request for a sample. I left location at this time and requested to be called when the surface casing is cut and pulled. Distribution: orig - Well File c - Operator c - DNRlDOG c - Database c - Rpt File c - Inspector Rev.:5/28/00 by LR.G. P&A Ivik #1 04-08-03 LG.xls 5/5/2003 . . MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs _lnserts\Microfilm _ Marker.doc DATA SUBMITTAL COMPLIANCE REPORT 5/9/2005 Permit to Drill 2022250 Well Name/No. IVIK 1 5/1 IÁ¿ ).f·7~h^à ~3 Operator PIONEER NATURAL RESOURCES US API No. 50-703-20436-00-00 MD 6943'-- TVD 6942..; Completion Date 4/9/2003 ..- UIC N Current Status P&A Completion Status P&A REQUIRED INFORMATION Mud Log Yes Samples No Directional surv~ _Ye0 DATA INFORMATION Types Electric or Other Logs Run: LWD:GRlRes/CNUFDC. E-Line: GRlRes/FDC/CNLCaIIDSUCMRlFMI Well Log Information: (data taken from Logs Portion of Master Well Data Maint) Log/ Electr Data Digital Dataset Log Log Run Interval OH/ Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments 4-RPt ..-ßeP"ort: Final Well R 0 0 Case 6/17/2003 Final Well Report w/logs in ¡ Well History file. téD C Las 12029 Induction/Resistivity 25 100 6945 Case 6/17/2003 Wireline, Resistivity, Neutron, Density, Porosity, Gamma Ray, Caliper ~ C Las 12029 Induction/Resistivity 25 175 6943 Case 6/17/2003 Resistivity, Neutron, I Density, Porosity, Gamma Ray, Caliper ~ C Las 12029 Neutron 25 175 6943 Case 6/17/2003 Resistivity, Neutron, Density, Porosity, Gamma Ray, Caliper .....ro C Las 12029 Density 25 175 6943 Case 6/17/2003 Resistivity, Neutron, Density, Porosity, Gamma Ray, Caliper ~ C Las 12029 Caliper log 25 175 6943 Case 6/17/2003 Resistivity, Neutron, Density, Porosity, Gamma Ray, Caliper It9 12029 Mud Log 2 Col 175 6943 Case 6/17/2003 Logs are with Final Well Report in Well file. ¡~ 12029 Lithology 2 Col 175 6943 Case 6/17/2003 Logs are with Final Well I Report in Well file. ! I 12029 See Notes 2 Col 175 6943 Case 6/17/2003 Drilling Dynamics Log. 1·J.eg Logs are with Final Well Report in Well file. ¡l§P C Las 12029 Directional Survey 175 6943 Case 6/17/2003 Resistivity, Neutron, i Density, Porosity, Gamma I Ray, Caliper I ¥og 12029 Induction/Resistivity 25 Blu 175 6943 Case 6/17/2003 Resistivity, Neutron, i Density, Porosity, Gamma ! Ray, Caliper ~- --- ~ DATA SUBMITTAL COMPLIANCE REPORT 5/9/2005 Permit to Drill 2022250 Well Name/No. IVIK1 Operator PIONEER NATURAL RESOURCES US API No. 50-703-20436-00-00 MD 6943 TVD 6942 Completion Date 4/9/2003 Completion Status P&A Current Status P&A UIC N ~' &'2029 See Notes 2 Col 175 6943 Case 6/17/2003 DML-MWD Combo Log. . g Logs are with Final Well i c Report in Well file. )," Log 4'2029 Caliper log 25 Blu 175 6943 Case 6/17/2003 Resistivity, Neutron, Density, Porosity, Gamma Ray, Caliper V[og .:r2029 Density 25 Blu 175 6943 Case 6/17/2003 Resistivity, Neutron, ! Density, Porosity, Gamma I Ray, Caliper i 46- C Asc \....12090 Dip 6557 2871 Open 5/27/2003 .~ I n090 iSD-: C Asc Dip 6871 4119 Open 5/27/2003 !9Ð C Pds ,A2090 Formation Micro 1m a 6188 6873 Open 5/27/2003 Formation Micro Imager /. fCóg Pds Formation Micro Ima 25 Col 4145 6907 Open 5/27/2003 Fullbore Micro Imager Tool '~ C Pds A'2090 Computer Log 25 4800 6600 Open 5/27/2003 CMR DMRP Processed ~. Magnetic Resonance 25 Col 2870 6907 Open 5/27/2003 Combinable Magnetic Log Resonance ÉÔ C Pds 42090 Formation Micro Ima 5506 5189 Open 5/27/2003 Formation Micro Imager "ÉD C Pds "'-;2090 Formation Micro Ima 4824 5507 Open 5/27/2003 Formation Micro Imager ..£D C Pds ~090 Formation Micro 1m a 4143 4825 Open 5/27/2003 Formation Micro Imager EEY C Pds ..-12090 Formation Micro Ima 5 4143 6873 Open 5/27/2003 Formation Micro Imager ED C Pds 12õ91 Induction/Resistivity 25 2992 6907 Open 5/27/2003 Resisitivity Log - AIT - Platform Express I~ I nd uction/Resistivity 25 Col 2992 6907 Open 5/27/2003 Resisitivity Log - AIT - Platform Express .- ED-----ê Pds 12091 Caliper log 2 2992 6907 Open 5/27/2003 Caliper Log - Platform Express Leg- Caliper log 2 Col 2992 6907 Open 5/27/2003 Caliper Log - Platform Express ED C Pds 12091 See Notes 25 2992 6907 Open 5/27/2003 Triple Combo Log - Platform Express J&g- See Notes 25 Col 2992 6907 Open 5/27/2003 Triple Combo Log - Platform Express '?l-/ C Pds 12091 See Notes 5265 6542 Open 5/27/2003 Mechanical Sidewall Coring Tool L,.gg-- See Notes Col 5265 6542 Open 5/27/2003 Mechanical Sidewall Coring Tool DATA SUBMITTAL COMPLIANCE REPORT 5/9/2005 Permit to Drill 2022250 Well Name/No. IVIK1 Operator PIONEER NATURAL RESOURCES US API No. 50-703-20436-00-00 MD 6943 TVD 6942 Completion Date 4/9/2003 Completion Status P&A Current Status P&A UIC N i ErtJ- C Pds 12091 Sonic 5 90 6907 Open 5/27/2003 Dipole Sonic Imaging Tool I BCR, Lower Dipole I [ ~nic H-og 5 Col 90 6907 Open 5/27/2003 Dipole Sonic Imaging Tool I BCR, Lower Dipole ! .+eo C Pds 120'9"1 Sonic 25 90 6907 Open 5/27/2003 Dipole Sonic Imaging Tool DSI P&S Mode i -Šonic i tcig 25 Col 90 6907 Open 5/27/2003 Dipole Sonic Imaging Tool I DSI P&S Mode I ~t See-Notes 5432 6542 Open 5/4/2005 CoreLab Core Analysis .~ .~ J ¡ Lo~ -sõíílc 25 Col 90 6907 Open 5/27/2003 Dipole Sonic Imaging Tool I DSI P&S Mode I ! Ep.---'-é Pds 12091 Density 25 2992 6875 Open 5/27/2003 Density/Neutron Log - I Platform Express ! L-eg-- ,.t>ensity 25 Col 2992 6875 Open 5/27/2003 . Density/Neutron Log - I Platform Express ~-- C Lis ,.A2œ2 See Notes Open 5/27/2003 Field data for Formation Micro Imager (FMI) and Dipole Sonic Imager (DSI) logged in open hole. This is the main log file and is in DLlS format. ~. C Pds ......-12093 Cement Evaluation 5 4100 6820 Case 5/27/2003 Cement Bond Log I SCMT/PSP i ,¡...bog Cement Evaluation 5 Col 4100 6820 Case 5/27/2003 Cement Bond Log I SCMT/PSP i lED C Pds ).2G93 SeismicNelocity 5 250 6850 Open 5/27/2003 Verticle Seismic Profile - ~_. .~ I Check Shot - Monitor Log 1 J-Log &eismicNelocity 5 Co I 250 6850 Open 5/27/2003 Verticle Seismic Profile - '! Check Shot - Monitor Log i SD---- C Pds 1-2B94 Formation Tester 5 4700 6551 Open 5/27/2003 Modular Dynamic Tester- MDT - Pretests and Samples ! C;g- ..Formation Tester 5 Col 4700 6551 Open 5/27/2003 Modular Dynamic Tester- I MDT - Pretests and i _ Samples ~.- C Lis 12~Lis Verification 4700 6551 Open 5/27/2003 Modular Dynamic Tester - I MDT - Pretests and i . Samples i~D Las ~per log BS 0 0 I I Permit to Drill 2022250 MD 6943 TVD 6942 Well Cores/Samples Information: Name I Cuttings L_ ADDITIONAL INFORMATION Well Cored? ~ N Chips Received? ~ Analysis Received? ð/N Comments: Compliance Reviewed By: DATA SUBMITTAL COMPLIANCE REPORT 5/9/2005 Well Name/No. IVIK 1 Operator PIONEER NATURAL RESOURCES US API No. 50-703-20436-00-00 Completion Date 4/9/2003 þ Completion Status P&A I ntelVa I Start Stop 180 6943 Sent Received Daily History Received? Formation Tops Current Status P&A Sample Set Number Comments 1118 ThIN ~N Date: UIC N ~' q (V~ ~S-- ~. ) ) Letter of Transß1ittal Date: May 4, 2005 FROM Kevin Schmidt Pioneer Natural Resources 700 G Street, Suite 600 Anchorage, AK 99501 TO Howard D. Okland Petroleum Geologist Assistant Alaska Oil & Gas Conservation Commission 333 W. ih Avenue., Suite 100 Anchorage, AK 99501 o Letter x Report D Agreement INFORMATION TRANSMITTED o Maps o Other: DETAil QTY 2 Core Analysis Reports DESCRIPTION v Core Analysis Reports for Oooguruk & Ivik#1 Received by: LL. ðJLJ Date: °1 N, Æ (J [ S·- Please sign and return one copy to Pioneer Natural Resources, Inc., ATTN: Kevin Schmidt 700 G Street Suite 600, Anchorage AK 99508 907-343-2190 fax FL' (t. ~ D?.. - ,:z ;}. ) ) r \ PIONEER NMURAL RESOURCES CANADA INC. DATA . TRANSMITTAL II DATE: June 10, 2003 TO: Alaska Oil & Gas Conservation Commission 333 W. - 7th Ave., Suite 100 Anchorage, AK 95501 Attention: Lisa M. Weepie FROM: Kevin Schmidt Natchiq #1 50-703-20438 ~s: (2 copies) Multiple Propagation Resistivity Caliper Corrected Neutron ~.... . Optimized Density Gamma Ray, Caliper Log ~oé).1 V@ B(1 copy) þ.Fmãí Well Report (1 copy) Ooogaruk #1 50·703·20437 ()09 - dd(¡J ~s: (1 copy) ..-.. ~ ~ ~ Multiple Propagation Resistivity Gamma Ray RWD Log ~~g.R (1 copy) ¿.)2ínal Well Report (1 copy) Ivik#1 50-703-20436 ~ f)O'd ~f)CJ5 ~: (1 copy) Multiple Propagation Resistivity Caliper Corrected Neutron ~ Optimized Density Gamma Ray, Caliper Log I ó(::ð ;æ~' (1 copy) vFinal Well Report (1 copy) ENCLOSED IS THE FOLLlNG INFORMATION: ~_d)d-1- dUCT 0 ~~!!::CE'\/ED 11~1"",,,, JUN 1 ¡:' 2003 ,4JaSt~a \}.~ ¿~ Gss CC;¡r, CQmmi3áoo þ,mi'hOf~"e SENT BY: Melany Larsen, Phone: (403) 231-3222 Administrative Assistant, Engineerinq 2900. 255 - 5 AVENUE SW. CALC;ARY, AL.BERTA T2P 3GG . BUSINE.SS ((¡03) 231-3100 . I:AX ((¡03) 7.G9-9(¡97 One copy of this transmittal is kept on file for our reference. ) Schlumberger DCS i-Reservoir, Data and Consulting Services 3940 Arctic Blvd., Suite 300 Anchorage, Alaska 99503-5711 Company: ,,<l Alr,':::J '~)1 A.~~) I ,"'" I -, ) ,~""y;t- :J ("-> /" ,~I,tl' It'"'' \ ,..j,::>..3 ¿:.r" / I / l/ .-.. r~- ¡Ü I ;- Location: Attention: /../)" ¿;";ç i'-?;'.r,::: ~,> \. ~; tt,.;..~ /r" r ~. ¿;;/ ':.) ;:1 'I /~Ö ,I \;o""~1 Date: Jctilumþerger N~ 2797 ·-..,..·..·--;íj/:i" /1 F ,l,.....,t--<.", , I .f. /""/ ( i "....,..' "'] .-., ._> i, ~I ¿ì11 ..::..' "'''''''.., .. :p-, ._ 2., ¡/ I l:: '/1 t' ,.., . Y . ' ' :. 0' ,,: I, l '/.. 1>' 1(,:..··(' d"!'¡. 1/) Ii' I Serv'lces', / ';'À)/o¡c.çJ,e)/!"I'-"C If( t'\ ,/t:: I! -' l L..J;';'I{ ,..J Is . ',f ", 'I I /1 _,"' I . /' /< !f., ervlces. '¿. . I t' ¡J.r, /,,117 ) ."..... ,/ ,''/~- r J, ,<,I' I /},..("\ J :, ml..:...." ,\J ~ L -, ',...a. ~I¡ it::II./,/ l;:~;t(It.,,:~,¡v /iV)'t:: ("O'}It,I?¡ c'/? ,i.'¡,rt.i'c '"..1)(" !,I,S. 1'1,· ,(,.¡4--r :JJ'é:t.~)n-,~.. { i' iJL ., ¡ I f· , N¡ )0...,"1'- ;;.1.,).,/) {$)tl I] ~c.l i¡ l. t::á 1\:' '1- {J ') Ì)' )< L/ ., r' ¡'..}:..¡ /F..,. rl ~.' 'ì '.,. .I I ," '-'" , '" .$ e.. () /.5 /it~,~\:;." No. of Boxes: / j'<ri~^,No, of Boxes: Well Name: Job No: '''J "] '" 1 C ,ç"'{,) ,,:¿ G~I I \ 'Ä:Adä'l T a~~s: ,,:~~.$~~I'~' ..' \'i.:\ Welf(Natne: :'~:~'I'¡' S el'Vi ces : "':";:r'iit: ',¡~~<~ \ --' - No. of Boxes~·"" ,/ .. i.;~:b ~.9: ,,' . ~~:\.:~I ,/. .~r;' 'Adâ'l Tapes: !:", Well Name: Services: No, of Boxes:. Job No: Add'l Tapes: Schlumberger Courier: : 4;::::;) '. :/.- ""I;~::::'::i? '''~ ··'-'..'4.'W'....~................ Date Delivered: '" " b 09-89 W~Name: . Job N,.ó: Ad,~/i Tapes: Well Name: Services: ':'.":; r\1.'6. of Boxes: ',(.~~r¡....·ilJ'1fì, " , Job No: ~dd'l Tapes: \'1 "\ ''Ii'' ~ W~II Name: \; serVfees: ~ '. No. of Boxes: Job No: Add<1 Tapes: RECE,VFn MAY 27 2003 Alaska on & Gt1~ Con6. CommiUan Anchorage <~~ . ,-~;1 .;;-' ,,/L__ , Received By: \ . ') ) BUSINESS DEVELOPMENT J. Patrick Foley Alaska Land & Negotiations Consultant (907) 264-6750 . (907) 830-0999 mobile PIONEER NATURAL RESOURCES ALASKA, INC. April 23, 2003 Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501-33539 HAND DELIVERED Subject: Ivik # lWell Reports and Information Permit No. 202-225 Harrison Bay, North Slope, Alaska Dear Commissioners, LV;¡¿' ~þ Pioneer Natural Resources Alaska, Inc. has completed operations on the,,..Qo.ogtm:rl( #1 well. The well was plugged and abandoned on April 9, 2003. The following forms, reports and information are enclosed with this transmittal: 1. Well Completion Report Form 10-407 2. Wellbore diagram showing Final Status 3. Survey Listing 4. Final Well / Event Summary (Drilling) 5. Final Well / Event Summary (Completion) 6. Operations Summary Report (Drilling) 7. Operations Summary Report (Completion) 8. Conductor As-Built Drawing The information transmitted herewith is CONFIDENTIAL. We respectfully request that this material be maintained as CONFIDENTIAL in accordance with the provisions of 20 AAC 25.537(d) and the current practices of the Commission. Additional geologic data and logs required by 20 AAC 25.071 will be delivered under separate transmittal in the near future. Best regards, ~~~~?~ RECEIVED APR 2 3 2003 Cc: Mr. Dave Braddock - Pioneer Natural Resources USA, Inc. Mr. Rusty Cooper - Pioneer Natural Resources Alaska, Inc. Mr. Ed Kerr - Armstrong Alaska, Inc. Alaska Oil & Gas Cons. Commission Anchorage 310 "K" STREET, SUITE 200, ANCHORAGE, ALASKA 99501 . . FAX (907) 264-6743 ) ) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of well Classification of Service Well Oil 0 Gas 0 Suspended 0 Abandoned 0 Service 0 ..~.,. ,..~....,.'. ~~...ìio1¡«I.. ...,'.".'..:.'". 2. Name of Operator ~~~\' ., t~:·(~~· Pioneer Natural Resourses . '.,. · ~ '.,. 3, ~~~re;Street, Suite 200;Anehorage, AK 99501 '!~~ 4. location of well at surface {;?~,~'?:'.~~,f.~"(.Ìl¿::r~~~,f 1349.8' FSL & 536.9' FWL of Sec 6 T13N R8E UM 1 1i(>,::):,:;¡Ji'i ¡ ~ r'l {';, "I'·' ~:: ~ At Top Producing Interval ;! ¿i"" , ", . j 1:;~i;;p~ 500' FWL of See 6 T13N RaE UM at 6410' MD I V~R~;;È~'2! v:,t 3 1345.3' FSL & 535.6' FWL of Sec 6 T13N R8E UM at 6943' MD t.::::~l?,:,;,:.:.:.:J 5. Elevation in feet (indicate KB, DF, etc.) 6. lease Designation and Serial No. 51 feet 389950 I 12. Date Spudded 13. Date 1.D. Reached 14. Date Comp., Susp. Or Aband. February 25, 2003 March 5, 2003 April 9, 2003 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 6943' MD I 6941.8' TVD 30' below the mud line YES 0 No 0 22. Type Electric or Other logs Run LWD: GR/Res/CNLlFDC. E-Line: GR/Res/FDC/CNLCal/DSLlCMR/FMI/MDT/SWC 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM Surface 171' Surface 2998' 2835' 4310' 4310' 6943' 7. Permit Number 202-225 8. API Number 50-703-20436 9. Unit or lease Name Ivik 10. Well Number 1 11. Field and Pool Exploration 15. Water Depth, if offshore (P&A'd) 10.5' feet MSL 20. Depth where SSSV set Pulled 16. No. of Completions 1 21. Thickness of Permafrost N/A feet MD CASING SIZE 13-3/8" 7-5/8" 5-1/2" 3-1/2" W1. PER FT. 68# 29.7# 17# 9.2# GRADE K-55 L-80 L-80 L-80 HOLE SIZE N/A 9-7/8" 6-3/4" 6-3/4" CEMENTING RECORD Drive Pipe 451 sx ASL & 130 sx G AMOUNT PUllED 50' 59' 85 sx G lead (13 ppg) & 463 sx G "Expanding" Cmt 3-1/2" TUBING RECORD DEPTH SET (MD) 4310' PACKER SET (MD) CSR at 4310' 24. Perforations open to Production (MD + TVD of Top and Bottom and interval, size and number) 25. SIZE * Plugged & Abandoned all perforations after test with EZSV at 6375' MD and 25' of cement. 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 6410' - 6478' 28,325# 20/40 Carbo Lite 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) N/A Plugged & Abandoned after flow test: no artificial lift. Date ofTest Hours Tested Production for Oll-BBl GAS-MCF WATER-BBl CHOKE SIZE GAS-Oil RATIO 4/1/2003 48 Test Period> 2000 600 N/A 1/2" Flow Tubing Casing Pressure Calculated Oll-BBl GAS-MCF WATER-BBl Oil GRAVITY - API (corr) Press. 310 psi 350 psi 24-Hour Rate> 1000 300 N/A 20° API 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. 6100 - 6102' - SS, mod. well cemnted, oil-saturated 6102 - 6144 - sh, dk brown, indurated RECEIVED APR 2 3 2003 Alaska Oil & Gas Cons. Commission Anchorage G,f- Submit in duplicate flJ[)WiS BF L APR 3 0 1003 CONTIt)m;~NAL Form 10-407 Rev. 7-1-80 ) 29. 30. ) GEOLOGIC MARKERS FORMATION TESTS MEAS.DEPTH TRUE VERT. DEPTH Include interval tested, pressure data, all fluids recovered and gravity. GOR, and time of each phase. NAME Top I Middle Brookian Top I HRZ Base I HRZ Top I Torok Top I Kuparuk C Top I Nuiqsit 4409' 5843' 5961' 5220' 6095' 6396' 4408' 5842' 5960' 5219' 6094' 6395' RECEIVED APR 2 3 2003 Alaska Oil & Gas Cons Comm' . . ,ss,oo Anchorage 31. LIST OF ATTACHMENTS 32. I hereby certify that the following is true and correct to the best of my knowledge. Signed ~~;7< Title For Ken Sheffield. President Date 0~ 3 Prepared by Paul Rauf 263-4990. INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 (' (( & ~ ,. [ore Lab RESERVOIR DPTIMIZATIDN Petroleum Services Division Core Laboratories Canada, Ltd. 2810 - 12 Street N.E. Calgary, Alberta, Canada T2E 7P7 Tel: (403) 250-4000 Fax: (403) 250-5120 www.corelab.com 2003 05 28 Pioneer Natural Resources Canada Inc. 2900,255 - 5th Ave. SW Calgary, Alberta T2P 3G6 Attention: Mr. Kevin Schmidt Subject: IVIK #1 THETIS ISLAND Our File Number: 52131-03-0173 Rotary sidewall coring equipment and 100/0 kcl polymer base mud were used to core the subject well. The samples were labeled at the well site and transported to our Calgary laboratory for analysis. 1. Conventional, Plug Type analysis Sixty samples (25.4 mm diameter) were cleaned in a vapour phase extractor using toluene and dried in a gravity oven. Analysis includes porosity by Boyle's Law technique using helium as the gaseous medium and horizontal permeability to air. Thank you for the opportunity to be of service. Yours truly, CORE LABORATORIES CANADA, LTD. '. '\ David J. Brooks Supervisor, Routine Rock Properties DJB/jw enclosures .-!.: :¡ ~ .~ if \ ..--.. CORE ANALYSIS REPORT FOR PIONEER NATURAL RESOURCES CANADA INC. IVIK #1 THETIS ISLAND 1450' FSL & 500' FWL THETIS ISLAND, ALASKA --" These analyses, oplnlons or interpretations are based on observations and materials supplied by the client to whom; and for whose exclusive and confidential use; this report is made. The interpretations or opinions expressed represent the best judgment of Core Laboratories (all errors and omissions excepted); but Core Laboratories and its officers and employees, assume no responsibility and make no warranty or representations, as to the productivity, proper operations, or profitableness of any oil, gas or mineral well or formation in connection with which such report is used or relied upon. ~ ~ \ ~ ~ ..r<, CORE LABORATORIES Company PIONEER NATURAL RESOURCES CANADA INC. Field THETIS ISLAND File No.: 52131-03-0173 Well IVIK #1 THETIS ISLAND Formation . Date . 2003-03-28 . . Location 1450' FSL & 500' FWL Coring Equip.: ROTARY SIDEWALL Analysts: DJB Province ALASKA Coring Fluid Core Dia: COR E A N A L Y S I S RES U L T S SAMPLE DEPTH PERMEABILITY POROSITY GRAIN DESCRIPTION NUMBER (MAXI~UM) (HELIUM) DENSITY .~ Kalr ft md % gmjcc 60 5265.0 140. 27. 1 2.67 ss vf f 59 5266.0 18.5 22 . 1 2.67 ss vf f 58 5277.0 20. 1 21.5 2.67 ss vf f 57 5278.0 52.9 24.6 2.66 ss vf f 56 5279.0 18.0 25.4 2.66 ss vf f 55 5295.0 9.67 19 .3 2.69 S5 vf f dol 54 5296.0 2.28 21.8 2.80 ss vf f 53 5297.0 5.80 19.5 2.67 ss vf f 52 5310.0 4.83 19.2 2.69 ss vf f 51 5320.0 26.9 22.2 2.67 ss vf f 50 5321.0 31. 1 22.5 2.66 ss vf f 49 5322.0 0.71 12.2 2.79 ss vf f dol 1 am 48 5362.0 24. 1 21 .8 2.68 S5 vf f 47 5378.0 23.7 23.2 2.67 S5 vf f 46 5379.0 45.3 23. 1 2.67 ss vf f .~ \ 45 5389.0 15.2 21 . 2 2.68 ss vf f 44 5392.0 36.5 23.0 2.67 ss vf f 43 5393.0 15 . 4 2 1 . 1 2.67 ss vf f 42 5395.0 2.90 16 . 4 2.70 ss vf f dol 41 5397.0 7.75 19.8 2.70 ss vf f dol 40 5398.0 16.8 2 1 . 1 2.67 ss vf f 39 5406.0 10.4 21.3 2.64 S5 vf f 38 5412.0 0.80 16 . 6 2.69 ss vf slty 37 5416.0 2 . 10 17. 7 2.67 ss vf flam 36 5418.0 10.4 20.8 2.67 ss vf flam 35 5424.0 3.79 18.3 2.68 S5 vf flam 34 5425.0 1.06 17.0 2.69 ss vf f calc 1 - 1 CORE LABORATORIES Company Well PIONEER NATURAL RESOURCES CANADA INC. IVIK #1 THETIS ISLAND Field Formation THETIS ISLAND File No.: 52131-03-0173 Date 2003-03-28 COR E A N A L Y S I S RES U L T S SAMPLE DEPTH PERMEABILITY POROSITY GRAIN DESCRIPTION NUMBER (MAXI~UM) (HELIUM) DENSITY Kalr ft rod % gmjcc 33 5432.0 27.4 22.3 2.66 vf f -,. ss 32 5443.0 1 2 . 2 20.7 2.67 ss vf f 31 5446.0 5.09 17.8 2.68 ss vf f 30 6095.0 0.24 1 1 . 2 2.69 ss vf anhy 29 6096.0 o . 15 9 . 3 2.71 ss vf f glauc 28 6097.0 0.01 0.5 3 . 1 7 dol i ppv sid 27 6098.0 0.56 12 . 3 2.73 ss vf f m glauc 26 6099.0 0.34 1 5 . 1 2.70 ss vf f m glauc 25 6403.0 0.86 12 . 7 2.67 ss vf f 24 6412.0 1 5 . 1 18.6 2.63 ss vf f 23 6415.0 2.04 14 . 1 2.66 ss vf f 22 6417.0 4.89 14.6 2.65 ss vf f 21 6439.0 <.01 0.5 3.28 dol i sid 20 6441.0 6.69 14.5 2.74 ss vf f dol 19 6443.0 1 2 . 1 15.9 2.65 ss vf f 18 6445.0 35.5 17. 9 2.66 ss vf f 17 6447.0 9.24 15.8 2.66 ss vf f --.., 16 6449.0 4.65 14.8 2.92 ss vf f sid 15 6451.0 16.6 16.7 2.66 ss vf flam 14 6453.0 0.01 3.2 3.26 dol i ppv sid calc 13 6455.0 100. 19 . 6 2.66 ss vf flam 12 6457.0 4.73 15.5 2.66 ss vf flam 1 1 6459.0 58.0 16 . 1 2.66 ss vf flam 10 6461.0 5.22 15.2 2.66 ss vf flam 9 6465.0 <.01 12 . 7 3.24 dol i sid 1 am 8 6469.0 5.22 16 . 1 2.64 ss vf f carb lam 7 6470.0 28.4 18.6 2.64 ss vf f carb lam 6 6475.0 12.3 16.6 2.63 ss vf f carb lam 5 6476.0 6.70 15 . 4 2.65 ss vf f 1 - 2 CORE LABORATORIES Company PIONEER NATURAL RESOURCES CANADA INC. Field THETIS ISLAND Fi 1 e No.: 52131-03-0173 Well IVIK #1 THETIS ISLAND Formation Date 2003-03-28 COR E A N A L Y S I S RES U L T S SAMPLE DEPTH PERMEABILITY POROSITY GRAIN DESCRIPTION NUMBER (MAXI~UM) (HELIUM) DENSITY Kalr ft md % gmjcc 4 6477.0 15 . 0 1 7 . 7 2.66 vf f ~ 55 3 6486.0 25.0 19 . 1 2.63 55 vf f carb 2 6530.0 0.58 10.4 2.70 55 vf f dol lam 1 6542.0 0.97 12.8 2.70 55 vf f dol 1 am r~.. 1 - 3 A (Prefix A) Horizontal matrix permeability measured by pressure decay profile permeametry through a probe tip due to induced fractures Removed for advanced core analysis Anhydrite Argillaceous Appears similar to Bitumen = Break Coarse Calcite (calcareous) Carbonaceous Cobble Conglomerate Chert Coal/coal inclusion = Coquina = Dolomite Fine Full diameter analysis including three directional permeabilities, porosity and densities = Fossil (fossiliferous) Fracture (undifferentiated) Friable = Glauconite (glauconitic) Granule Gypsum Halite (salt) Horizontal fracture Intercrystalline Inner Full Diameter (Full diameter sample is drilled from the bulk portion of the core in the vertical direction for permeability and porosity measurements) ACA anhy arg AST bit bk c calc carb cbl cgl cht coal coq dol f FD foss frac fri glauc grnl gyp hal hfrac i IFD incl lam Is Iv m mi mv NA NP NR OB 001 pbl PFD ppv PR PSA PSP pyr pyrbit ru SA sdy SEM sh shy sid sltst slty SP .... . . .. - ....- -. '. <. '\~,*œ\~:(:: .:. r':;¿'jj}~~i:::V "': :. 4:}~..' . ... ....... . ., . .. . . ',." ",. . ........ ..... , ~.~.~ C·· ....:... .': :···:.·.·L·;:··:···· :I:J'.':"~... . ..gr:l:!::.:. iJ!..: . "PETTi {f ttUH .s=rllVU::ES CODE KEY - DESCRIPTIONS = Inclusions Laminae (laminated) Limestone Large vug = Medium Mud invaded Medium vug Not analyzed by request No permeability measurement possible due to poor sample quality Not received Overburden sample (permeability and porosity measured at net overburden stress) Oolitic Pebble - Preliminary Full Diameter sample Pinpoint vug = Preserved for future studies Particle size analysis Preliminary Small Plug sample Pyrite (pyritic) Pyrobitumen = Rubble Sieve analysis Sandy Scanning electron microscope analysis = Shale Moderately shaly (20% - 40%) Siderite Siltstone Silty Small plug (sample drilled from core in maximum horizontal direction and parallel to bedding plane where possible) permeability porosity, and grain density are measured SPH SPP SPT ss ssdy sshy sty sulf sv TEe TS uncons vc vf vfrac VIS VOS vshy VSP vug ws XRD 10240 Humidity analysis of small plug sample at 60 degrees Celsius and 50 % relative humidty Small plug from preserved section of the core Small Plug used for tracer analysis Sandstone Slightly sandy «20%) Slightly shaly «20%) Stylolite (ic) Sulphur Small vug Thermal Extraction Chromatography to determine oil richness Thin section Unconsolidated Very coarse Very fine Vertical fracture Viscosity of oil measured Vertical overburden sample (vertical permeability measured at net overburden stress) Very shaly (>40%) Vertical small plug drilled from whole core to measure vertical permeability (and occasionally porosity) Vuggy (vuggular) Water sand X-ray diffraction Perm unavailable due to broken core = Permeability >10 Darcies, (maximum routine permeability measurement) ~'. .-.- , PIONEER N A TU RAL RESO U RCES 2835 ' 2998' 4310' '- I . I I 6943' :..~ ) I I I I I I I I I I I I I I I I I I ~: I I I ) I vik #1 Final Status I · Cut & pulled tubing at 85' MD · Cut & pulled 7-5/8" CSG at 45' below pad level = 18' below mud line. · Cut & pulled 13-3/8" CSG at 42' below pad level = 15' below mud line. · Cemented with 600 sx Arcticset Cement,130 sx of G and 140 sx of Arcticset Cement through the sliding sleeve at 3113'. /' · Circulated excess cement through the "RP" shear valve at 92'. · Solid Cement Plug: 3113' to 92' MD TOC (IA) = 30' below the mud line. /'" TOC (OA) = 29' below the mud line 7-5/8",29.7#, L-80, BTC-M 3-1/2" Sliding Sleeve at 3113' (120' below the shoe) 2.81" "X" nipple at 4275' 1 0.0 ppg LSND drilling mud / _____,.. ~..... .. I EZSV set at 6375' wi 25' of cement on xr--: top: PBTD = 6350'. Tested to 2000 psi . . ~: Perforations: 6410' - 6478' 3-1/2" Liner Tail ) ) #1 Ivik #1, Beaufort Sea Exploration,North Slope, Alaska SURVEY LISTING Page 1 Well bore: Ivik #1 Wellpath: MWD <0-6943'> Date Printed: 10-Apr-2003 r'¡. BAKER HUGHES INTEQ Well bore Name Ivik #1 -'~-"-------'---'-~-' ...._.________.________.__._._______. Createc;L___.___.___..___.___________._________.___.._________.____ Last Revised ...... ... _.__ ___________.______._ _________ _._._____________Jº_~J'.1ªr:~º_º_~ ... __.____._ ... .___.__...._____ _______._. __...______ JJl:IYL~!:~-º 03_____________ ..--,--.-.--.--..-.-..- Well Name Ivik #1 .------,,---_.. .-'"-.--,.,.--., -.-.-.--- ,.-.-----,.---,. ------.--...-"----- Government 10 50-703-20436 ~. ."".-----"--.-- ,-,_._.._-._--~,.. -.-..---.--------- ---.__.._--_._-~--,------_..~_._"~_._-- -,.._--,_.,..,._----- Last Revised _______.___ 10-Mar-2003 - _..__._----.-.-_._.~_.._-,,_..._.._-,._-_._-_.,-.~"-._.--.-.--.- _._-----_.----_.._~ -_._---------- Slot -_._--,~-----------_._--~._---~_._._-~-_.._,- -~ª-!!!~----------..-- . _..____.9J'1(t_"'A-º[tbj.Dg_____.ºrtçL~ªª!!Qg_.____._..bª!itude____...______.______._._____~-º!l9J.!!dº_~___.____.______._.__!iºt!.l:L__._..____ _~ª_§.t____.._._.__.__ _§Jgt~t______._u_._____d_ 60~~~_~º~~00Q__~ 761.89.8000 N70 30 22.5706 W150 1 Uª-~Qª?'Iº~QQt'_!_._________._Qd..ººI;___d_U._____._ "---_._----~--_.""-,_.._,------- -~-----_._._-----,-._-_._._._. --,..-.__.~._----_...~._..._,._--------_._,-_.._,._,.-,._-----_.__.,'-_..__.__._--_....,-~ Installation _Nª!!!§}____._______.._._....__......_.______.___. ._Easti ng_______.___.._.____._ _~_º__r!_hLIJ_g_.___.______._____ç...9o~º-§~~m Na r1}~_____._______.._._._._________.N-º.ctb_,l\Jjg.Dæ~_r1J.__ Ivik #1 476789.8000 6034820.3000 AK-4 on NORTH AMERICAN DATUM True .. ._u __._____.________.____.._ 1-ª~.L~La!lJrn - - -~~..-......_----~,..-,'--- __~. _.'_..,.__ ,._·~'___.n___"_._~_.__ _ _ _,..._._._."____,_,..._ __.,_ _ .______ _.____._____._~____._.". ,____"._,__..___. _._._..__.__. _". _,.____",._______ ,__,.___.___._,___~_".. _... _.._n ..____.______...._..._.".,_._ __ ___._________ ._ _________. "'__._..._._... Field _N arn~ .... ...___._________.__...._~ªgilJ.~________._.___.___Nº.rthIng.__.._ ___________º-oord SY..§Jª-OL N a me ___._____.__._..____.___.__.____. North AI ig n me nt.._ Beaufort Sea Exploration 481458.3800 6028077.2700 AK-4 on NORTH AMERICAN DATUM True -----.---..-.---..--.----.--.----..--.-----.--...-.. -.-.. -... .-..---______... .._.__.__. _________ _ J..ª-~_?_...9Ji_tl!.!TL.h___.._ ....__..__.._._.__.._.__...__.__ .__ --.-.--".-.--------,..------ ---~--_..._"-_._-~-- ~---_.,_.~-_.,. Created By For SKIP COYNER by Tom Jones ,-.- .----- -- ------...----------------- --- -., ----------------,.....-..-----. -- -. ----- .-- All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVO's are from Rig ( Nabors 27E 49.0ft above Mean Sea Level) Vertical Section is from O.OON O.OOE on azimuth 161.30 degrees Bottom hole distance is 111.17 Feet on azimuth 161.30 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ) ) ~~i:~¿~:: ""~', -··~.i #1 Ivik #1, Beaufort Sea Exploration,North Slope, Alaska SURVEY LISTING Page 2 Wellbore: Ivik #1 Wellpath: MWD <0-6943'> Date Printed: 10-Apr-2003 r'¡. BAKER HUGHES INTEQ k___.._._______"____.__,..._.__.,..____~__,_~,_ -.,--...-.------...-- Comments .." ---..- ..".... - ".-- _._.,._._--~-_._---_.._._- ._--_._-----_..._._--~._.-.'--,_._--_.,-_...,-,-_.- .'----,-..------.------"..---...,---..--..-.---. -.--~..~"_._,,-_. All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Nabors 27E 49.0ft above Mean Sea Level) Vertical Section is from O.OON O.OOE on azimuth 161.30 degrees Bottom hole distance is 111.17 Feet on azimuth 161.30 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ) ) #1 Ivik #1, Beaufort Sea Exploration,North Slope, Alaska SURVEY LISTING Page 3 Wellbore: Ivik #1 Wellpath: MWD <0-6943'> Date Printed: 10-Apr-2003 r&i. BAKER HUGHES INTEQ Wellpath Report MD[ft] Inc[deg] -"'------_.~_.~._-~ North[ft] East[ft] Dogleg Vertical ____.___._____._____.________._______________________ _ü;L~.gL19-ºft] S ecti on [ft] . _._ __ ... _______º_~ºº_________._____Q_'g_º_ ____ _.. _________ _.QJ)Q .._._______ __ u_._o~g-º _ ____._____Q_'~Qt·J__________.__.__Q_~ºº_~__ .___________. __º~º_Q_._____.._.______.._º. OQ__ . ___ __ .___.__.f.t4ª·_º_~__ ..________________.t~5 ______...__tº~_'.LCL________.____4.4JJJ?1.__.________ 5.42S 1.69E ._._____u_.___.____9-=ª~________. 5.68 731.33 _______.__._.__-.1g"L _______.____151 .03 731 .20 ________.____11.: 5 ~~__.__.__.__.__...4 .27 ~_.___.__.__..___.____QJ~_.._____._._._ 12.33 _..___J_ºQ_~.}J___._ .__._____._u.__.L_~ª_.. ......__._ __t~_º~I§.__._._..___._lQQ~t§.L___..___._____"_:L~4§_ ____._._.____ 7.04 E ____.__.____...__.._._º~Q5 18.59 1284.93 0.77 155.01 1284.68 21.85S 9.08E 0.20 23.61 _._____~____".._______...._~,,__,._.,," ____..______ __.·___m_..____·,_.,____,____..______. _.__ _ _ -'..._____,___._._.____ _____,_,._._,__.____..___~ __._..._. ,....._".___..._____._.__.___,.._..._ "._._.__.m_.,,____.,"__'_ _,_______ 1§º~J1_._n____ u __Q.:.Q7_ _.____ . . ..1§~ .2~____.. ___.1.9_ºªJtT_ __ _ ... __ _~§-,--Qª~_______.1.Q&t~. ________...__Q_...Q1________.__._1Z_...W_ ___1ª-~_~,-ª_1._ __ _ _~__ _ _Q.86 _ ______IQJH _._~__._ 1853.55 25. 88S ..__.___.____ _Jll§g._________n___9...:ª_ª_ __...._.__.___.__78. 7~_ ________._g.13 -ª-'-~4_._ _._n_____ ... .___O~§~t.__. ... .u. ___l~_:~I_._.____.n___~..t~.~-=.º_~__u.___ ____._ . ..~~ . 8º_~._ .._...__._____...16 . z.g~._..._n__.__._....__-ºJ..:t__ ____.___..._._..?8 . 8.9_. .. .... __._.._~~~_;t~Z.~L..._n_.__ .. __..nº~ª4.__.__________.~07_~ª.1___ . .....__.__~4_?~·4q_....____.._ ____._g.º-J.I§____ 17.66E 0.29 ___.._.._~~~§_Q_. 2707.04 1.05 180.53 2706.70 28.50S 17.25E 0.27 32.53 ___._,___ "__'_''''__'n....'_·___''''_ __.__..._______ __ , .._ _" _._.____,~.".____...___,__,_.,_ _ _ __ ___.__.._..._,,,_....."_____.____.,,_._,_. ____.."_..._,"________._______ _~._.,_,_____,_. .._ ._.__~...________ _~'____..__._____._~__~._._.__.____._._.. 2960.11 1.21 186.78 2959.73 33.48S 16.91E 0.08 37.13 - .- -.. .._--_.,--",.._,---..._---_....., - ,,- -- - - -----,-- --...---,-- '-..-- - - .-.....-.---.---,,--.-.,,-------...--,- .. ---,- .--..."........---.-..-,.-.-,--- - --'.". .--- - -.-._- . 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LL_._ 50. 66S_________u...1Z~Iª_~ _ .. .Q.]§_ ..._§-ª-,_E?Z_ __ ..u ___4.9~_ª_:~E?_ 1 .46 __ m_m1ºZ~ ªI__u_ _4Q~_gj!Q____ __ _§Z_,4J~L __ . __J~Jº~___ ___º_~º§ _ __ _un. 13_º_:§.Q_ __4_ª_QI·I~______.__ _. .. __L§ª...__~__m153_,g§._____ ._4~QºJ~Jt___ ._J:t4_,4~§___. _ ._~.L97~._ 0.14.___ 67.98 4590.75 1 . 52 ..____u_J.§.~§1_____..____.4.§_ª~.:.ªiL_..____ ___.I1J._ª-~___ ______ _._._._~.5. 28~.___.__ .___.º-...Q~_. _____ ._____._Z§~§~_. 4ªIZ:I4... _ .... _._..1 .J.I_ ._ ____..JL~LQQ_____________ 48 7-º_~ªº.____. __.___.uZr.4_~_~__ .____.._.._gZ'-20 E____ ...... ._________Q~§__._.__ __ .... .___.ª_~j)-º_ . _._._§J§~:Iº-_. . __L~§__..._____ 153.07 5161.74 ._.._-ªª.:~§§__._ ._.._____~ª.:Zªg_ ........._ .__.__.___g~~J _____ªªJ_ª_ 544.tª1__ _ . J_JQ_.____ J59.~~_§ ..__§..41Q~_ªº __.__._.___ªª.82S____._.___..___~L~_º-E_ __ ._.QJL________ ... _____ª-4J4_ _. . _~Z~4:~_~_ __ u_º'-~Z_ .. ___.1.§4A~L_____n__qI4__ªJ_Q_________.__ 93.53S 33.16E ..____.____g~_ª._._________...ª_~.~~~__ ________J?_Q12. 913__.__.___.. ..___.____º~§.ª_____. __ .u. _Hº.:.ª§___ _. ___..__--º-Q_19..:ª~_____.__._ 96. 84§__ ..___n..... __.____ª.§J..4E__.__ _. ._.____.._______QJ__º_ .___.._....._J..9-ª.:Q<2_ _ _ __ __J?~~ª=~4__ ______ __. ___._.__Q:.§_~_ ..._.____ _ ___J.4.º-:L?_...__...__.._ 6292. 0ª__________ª_9. OZ§L_...___.._..__â.ª]~~ _._..___________.. 0.02 1 05.63 ._ ___.§§Zl~~_ 0.71 195.31_____..__§§'?13.76 lQJ~~_1§_ _.___.__ª?-=Q]~_. . ._gJ.~.m____. .__tQªAg_ _ºª-º~~Qª._____ .. ____Q.§Q_.___ ._u~Q~_~~~________§ª§J_·ª~___ _..LQ1'-69§._m____m__ª§:.~_ªS .u ___º~Qª._ . m.11Q~LL _ . ____º-ª-4_~~ºº_____________u___º:þ_Q_____ .. ._.u__._~~~Qg_____.§~~J .81 1 05.30S___._______ª-5.64~..________.______º~Qº_________.J1.1-,--1Z_ Dir[deg] TVD[ft] All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Nabors 27E 49.0ft above Mean Sea Level) Vertical Section is from O.OON O.OOE on azimuth 161.30 degrees Bottom hole distance is 111.17 Feet on azimuth 161.30 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated -.--.-,.--.----- All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Nabors 27E 49.0ft above Mean Sea Level) Vertical Section is from O.OON O.OOE on azimuth 161.30 degrees Bottom hole distance is 111.17 Feet on azimuth 161.30 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ..--_. ---.-.-....-.----,--.----------"-.-- -.--..-...---,-,----..------- --_._._-~~_..- ------". "..-.. "-"'--" --..-......-----.------ .-.. - - ,,_.._~._-_._-_.._.__._--_.__..~.._--- 13 3/8in Conductor . - -,,--......-..-..-. --...----....-,--.- 7 5/8in 0.00 Ç~.lD_g__.__. __________.__.__ ~. 1/~in~.ir1§!r._ . ___ . .__ . º_~Q_º ___ 35.64E Ivik #1 0.00 105.30S 6941.81 6943.00 O.OOE O.OON "-...---..------.-".-..,.. '-'--~-_. ._----,-"""~---~.- ..- ~. ------.-. -- --~''''''-,_... .-.-----.---.-..-.-.-"" --~-..-. -,-, -.,---..---. - -------.-- '-"- _._._~.._,,--- --'-- .-...----.---.,-....-. ._._-_.__.~._._----,,-,---_._.. 16.82E Ivik #1 2995.61 2996.00 O.OOE O.OON 0.00 34.24S , ._,,-_._-"'-_...._~._- __~ª§_lllQ§_________..________.____._.__.._________.____._________.._____.__.__..._________.__.__.__.______.._________._____._ Name Top Top Top Top Shoe Shoe Shoe Shoe Wellbore .._. Jy1.ºlft1.____._. IVº-[fU___ ___ .~ºr.tl}mL__~ª§.~Lftl______J~1PlftL____TY_ºID1__..___~_º_rtO.Lf!L.__.. J;ª~JmL__ ...__ .______ ._...___,_ 0.00 0.00 O.OON O.OOE 171.00 171.00 0.79S 0.25E Ivik #1 _._~.~..,-_._-----_.,-_._-- --_.~_."._._-_._------_..,- .... -.-.-.---.-------. ",...- .._._.._---------_._,_.._---_.._--_._..__._._---~. .~-_.-_..._,-_.__._-_._- ..-~._.__. - -,. ---_.__._..-._.._,--~- ---,-.-_._-~,------_._-"--_.._._.._._-. Hole Sections -- .._---- Diameter Start Start Start Start End End End Start Wellbore lLol___.__. ._.________ M D[ft] .IVºlf!L__.____N.9-"!blf!L__.J~ª§![ftL.....__M_ºID]______.I~Lº1m.__..__N orth [ft] _ ____ê.~![ftl__________________________ 1Z..1./_~_ __________º_~ºº__ __ O. ºº_ __._..__º&QJ~L .._._..__º~ºº_I;_ _._... .J]J.~º-º__..___._J..zt~_ºº.. .._____º]J!§_____J~.~.~§g_. JY!K.ifL.n._.____________ 9 7/8 171.00 171.00 ____....Q]9$__.__.___Qg§~__...~.º_~Q~_ºº______._~_º_t9_~_º-º____.___ 34. 76S ..._._..16.78_1;_. Ivik #1________.___.______ 63/4 3020.00 3019.60 34.76S 16.78E 6943.00 6941.81 105.30S 35.64E Ivik #1 -..----- ~.__._"-,,..._--- ------,------_._------------ .. '--'-. --.... ,,_.._--~.~--_..-..._--_._. ---....... ---"'- Comments M!?lf!l____.___.. _IY-º1f!L_______~Qr:tt!If!L.___._ East[ft] ____ Com ment ...--ª~1_~~ºº___..9_ª41AH~____..._.......tQ§~ª0~..___ ...__ªº-~ªA~__E[QJ§!.ç!.~º__ºªt~L:J\,j_º_~_~B_YE'[______ "~i. BAKER HUGHIS INTEQ SURVEY LISTING Page 4 Well bore: Ivik #1 Well path: MWD <0-6943'> Date Printed: 10-Apr-2003 #1 Ivik #1, Beaufort Sea Exploration,North Slope, Alaska ) ) J.,¡¡r:Ì":\' It·,.. r::Y(~. ',:." J. ììJ.'~,¡, ,'PIt ',;!i',{1 ..~ ~ 't . PIONEER . "" ~ 'i.it.:~i,;:~,:·:~r~::,~i';·~:i~;;.t:·~ '\. legal Well Name: IVIK #1 Common Well Name: IVIK #1 Event Name: ORIG DRilLING DATE' TMD 2/2412003 (ft) 212512003 (ft) 212612003 2,246.0 (ft) 2127/2003 3,020.0 (ft) 212812003 3,020.0 (ft) 3/112003 3,020.0 (ft) 31212003 4,960.0 (ft) 3/3/2003 6,100.0 (ft) 3/412003 6,143.0 (ft) 3/512003 6,905.0 (ft) 3/612003 6,943.0 (ft) 317/2003 6,943.0 (ft) 3/8/2003 6,943.0 (ft) 31912003 6,943.0 (ft) 3/1012003 6,943.0 (ft) 3/1112003 6,943.0 (ft) 3/12/2003 6,943.0 (ft) 3/1312003 6,943.0 (ft) 3/1412003 6,943.0 (ft) 3/15/2003 6,943.0 (ft) 3/16/2003 6,943.0 (ft) ) ) . . " ,',.' ':' . '. ,'.", ," " . . . ., . p,···.ïQNEeRNATURAL··~eSOu.RèE. s· . ,,' '. . ::'f=i~.I""eU/I;\,~l)t ·SU.n.~_ry· . ' . . . Page t of.t Start Date: 2/3/2003 , 24 HOUR. SUMMARY . ,. . End Date: 3/12/2003 FINISHED RURT. TESTED BOP'S & DIVERTER SYSTEM. FINISHED PRE-ACCEPTANCE WORK. PU DP & BHA. CLEANED OUT CONDUCTOR WITH PDM. SPUD WELL AT 09:15 2/25102. DRILLED SURFACE HOLE DRGL. 9-71f!l' eSG. HOLE & CONDo HOLE FOR CSG. & POOH & RIG UP TO RUN CSG. & RUN CSG. RUN & CMT. CSG & TEST BOP's TEST BOP/lD BHA #1 &PU BHA #2 & RIHrrEST CSG/PERFORM LEAK OFF TEST MOSTLY DRLG DRLG TO CORE POINT & PREP MUD FOR CORE BARREL & TRIP FOR COREBBL. CORE #1 CORE POOH AND LAY DOWN CORE BARREL AND RUN BHA # 4 RR#2 & DRILL FINISH HOLElCOND FOR LOGS/POOH/RUN LOGS E-LlNE EVALUATION: TRIPPLE COMBO, DSVFMI, VSP, MDT. RAM DP CONVEYED MDT TOOL. RIH WITH SIDEWALL CORE TOOL. TEST BOP AND CIRCULATE HOLE CLEAN CIRC & COND HOLE. W/O ROAD REPAIR. POOH. STARTED RUNNING liNER. RAN AND CEMENTED TAPERED LINER RAN 3-1/2 COMPLETION TUBING, DISPLACE TBG TO DIESEL, TEST TBG & lA, NlD BOP STACK NlU TREE, TEST SAME, RELEASE RIG TO MOVE TO OOGURUK MOVE 27E & SUPPORT EQUIPMENT TO OOOGURUK #1. MOVE 27E & SUPPORT EQUIPMENT TO OOOGURUK#1. MOVE 27E & SUPPORT EQUIPMENT TO OOOGURUK #1. Printed: 411012003 11:16:41 AM Legal Well Name: IVIK #1 Common Well Name: IVIK #1 Event Name: ORIG COMPLETION DATE. ·TMD 3/17/2003 (ft) 3/18/2003 (ft) 3/19/2003 (ft) 3120/2003 (ft) 3/21/2003 (ft) 3/2212003 (ft) 3/2312003 (ft) 3/24/2003 (ft) 3/2512003 (ft) 3f.æ/2003 00 3/27/2003 (ft) 3/28/2003 (ft) ~/2OO3 00 3/30/2003 (ft) 3/3112003 (ft) 4/1/2003 (ft) 4/212003 (ft) 4/3/2003 (ft) 4/4/2003 (ft) 4/512003 (ft) 4/6/2003 (ft) ~/2003 (ft) 4/8/2003 (ft) 4/9/2003 (ft) 4/10/2003 (ft) Æ;";~:-;'" ti~~ ' \~t . .. PIONEElt " . ~t'~';~:(~~~~~::'·'~~~'¡i::í,~;-;:.:rt ) ) . . . ,',' , .', " . . " . '., , , . :, . \ . .' " ". . " ". " .' ' ... PI.ON~E;ßNATU~L~ESOPRCE$· Final·W~U Il;vt)nt \$~mmary. . . Page 1.Qf 1. Start Date: 2/3/2003 24 HOURS\.IMMARY End Date: 4/9/2003 Rig Up Test Equipment FINISHED RIG UP BOND LOG AND PERF SHUT IN - WAITING ON ORDERS. PUMPED INTO PERFS WI DIESEL, JETTED TUBING DRY W/NITROGEN. SHUT IN FOR 24 HOURS. SHUT IN FOR BUILD UP. SITP = 464 PSI SHUT IN FOR BHP BUILD UP. SHUT IN FOR BHP BUILD UP. RIU SLU. PULLED BHP BOMBS. DUMMIED OFF GLM FOR FRAC JOB. OPENNED WELL TO FLOW. MADE 16 BBL OF DIESEUOIL & DIED. SIaN. FRAC. FLOW BACK & TEST WELL. SET PRESSURE GAUGE FOR PBU, OPEN WELL FOR FLOW FLOW TESTS FROM 0600 TO 1030. WAITED ON VAC TRUCKS OFFLOADED PRODUCT FROM HOLDING TANKS. MONITOR PSIG & TEMP. PULLED &, DOWN LOADED BOMBS. RE-RAN BOMBS OPENED FOR FLOW TEST FLOWED WELL 24 HOURS: 1000 BOPD, 300 MCFPD, FTP = 290 PSI FLOW TESTED WELL UNTIL 9:00 PM. SI FOR BHP BUILD UP TEST. SI. DE-MOB TESTERS. SI SI FOR BHP BUILD UP TEST. SI UNTIL 9:00 PM. PUMPED MEOH & HOT DIESEL. RETRIEVED BHP BOMBS. PLUGGED PERFS W/EZSV + CMT. PLUGGED BACK TO 92' RKB PER PROGRAM. wac. CUT & PULLED TBG. TRIED TO CHEMICALLY CUT 7-5/8": NEGATIVE. CUT & PULLED THE 7-518" & 13-3/8". REMOVED & BACKFILLED THE CELLAR. PrintBd: 411012003 11:01:29 AM ) ') ~.~-~ ,)~",. . \.. ,'f:~ \~,\ '~.~: , :", , '. ". . " '. . '. " . ..... . " ,.:"', PIONi:ERNA TURAL.RESOU:RCES . .' ,': :,.", ,":: '. . :".',", . . ',' ",,' ':" '(.',", " ",'," ',-",'" .: ,,:, ',,:, ". '., '," :Op_rå~iþl1.iS·ummarY~@port· ..' " " ..', " . : . . ,'. " ,'. \ ' ' .. : . Pag~.1. .of. 5 ". "PIONEEll ~::;;.'I:~,;'_,'jj¡,·~' '~·:i"i¡!~~:~:i!.::~:i;·t. Legal Well Name: IVI K #1 Common Well Name: IVIK #1 Spud Date: 2/25/2003 Event Name: ORIG DRilliNG Start: 2/3/2003 End: 3/12/2003 Contractor Name: NABORS DRilliNG Rig Release: 3/12/2003 Group: Rig Name: NABORS DRilliNG Rig Number: 27E " '. . ", " . . . '. Sub· . . . , , , ..Date :.. From'~To . Hours Code Code Phase . . D~scri.ption ·of ·Ope~at,lon.s 212412003 06:00 - 03:00 21.00 002 MIRU FINISHED MI/RU NABORS RIG 27E WITH SATELITE CAMP & BALL MILL: MADE FINAL INSPECTIONS & PRE-COMMISSIONING TESTS. VECO DROVE 13-318" CONDUCTOR TO 172' RT ON 2/17-18/03. VETCO NU MULTI-BOWL WELLHEAD ON 2/18/03 ICE ISLAND COMPLETED ON 2/19/03 MU/RU MAIN RIG MODULE WITH DERRICK UP ON 2/19/03. MI/RU REMAINING RIG MODULES & BALL MILL 2/20-21/03. MI/RU EPOCH (mudloggers) 7 BAKER-INTEQ SKIDS MI/RU SA TELlTE COMMUNICATIONS, INSTALL PHONES. ETC 2/21-23/03. RU CANRIG TOP DRIVE & TEST SAME. NU 13-518" BOP's & TEST SAME TO 3500 PSI (pre-acceptance test). NU DIVERTER SYSTEM & FUNCTION TEST SAME (witnessed by AOGCC). FINISHED LAYING 16" DIVERTER LINE PER AOGCC REGULATIONS. 03:00 - 06:00 3.00 011 CSGSUR RIG ACCEPTED AT 03:00 2/24/03. PU 30 3-1/Z' DP & BHA. OFFLOAD SPUD MUD FROM BAROID PLANT. PREPARE TO SPUD. 2/2512003 06:00 - 00:00 18.00 011 CSGSUR CONTINUED P/U 3-1/2" DP (90 JNTS TOTAL), 3-112" HWDP (29 JNTS TOTAL), 6-1/Z' DC (9 JNTS TOTAL) & 4-3/4" DC (9 JNTS TOTAL). 00:00 - 01 :00 1.00 018 501 CSGSUR REPAIRED WEIGHT INDICATOR. 01 :00 - 02:30 1.50 011 512 CSGSUR PICKED UP 12-1/4" BIT TO CLEAN OUT CONDUCTOR - WOULD NOT PASS THROUGH DSA. LD 12-1/4" BIT. 02:30 - 03:30 1.00 011 CSGSUR SET WEAR BUSHING. DISCOVERED 1/2 BBL SPILL FROM MUD PITS IN CONTAINMENT (HIGH LEVEL LEAK IN PIT WALL) EQUALIZED MUD TO ANOTHER PIT TO LOWER THE LEVEl. CALLED ACS. 03:30 - 06:00 2.50 011 CSGSUR PICKED UP 9-7/8" BIT ON PDM. CLEANED OUT CONDUCTOR TO MAKE ENOUGH RAT HOLE TO PICK UP MWD/lWD TOOLS. 2/2612003 06:00 - 09:00 3.00 009 CSGSUR CLEANED OUT 13-318" CONDUCTOR & P/U MWD/LWD TOOLS. PREPARED TO DRILL AHEAD. LWD = GRlRES. 09:00 - 10:00 1.00 006 CSGSUR SPUDDED WELL AT 09:15 ON 2125103. DRILLED TO 305' WITH BAKER PDM, MWD & LWD ON HWDP. 10:00 - 13:00 3.00 011 CSGSUR RE-CONFIGURED BHA (SWAPPED OUT HWDP WITH DC'S). 13:00 - 16:00 3.00 006 CSGSUR DRILLED AHEAD WITH TOP DRIVE, BAKER PDM, MWD & LWD. 15 BPM 1400 PSI 16:00 - 17:00 1.00 018 501 CSGSUR REPAIRED HYD'L OIL FILTER LEAK ON TOP DRIVE (BLOWN SEAL). 17:00 - 23:00 6.00 006 CSGSUR DRILLED AHEAD WITH BAKER PDM, MWD & LWD. 9.2 PPG KCUPOl YMER MUD. TALLIED 7-518" SURFACE CASING IN THE PIPE SHED. 23:00 - 00:00 1.00 006 CSGSUR CONTROL DRILLED WHILE WAITING ON PEAK VAC TRUCKS: BALL MILL FULl. TURN AROUND TIME ON PEAK VAC TRUCK #1 WAS OVER 7 HOURS ON A 40 MILE HAUL TO KRU 1 R-18 DISPOSAL WELL. PEAK VAC TRUCK #2 TOOK OVER 3 HOURS TO ARRIVE FROM DEADHORSE. 00:00 - 06:00 6.00 006 CSGSUR DRILLED AHEAD WITH BAKER PDM, MWD & LWD. 9.2 PPG KCUPOL YMER MUD. CONTINUED CONTROL DRILLING AS NABORS BALL MILL NOT KEEPING UP. 2l'Z712OO3 06:00 - 11:30 5.50 006 CSGSUR CONT. DRLG. 9-7/8" SURFACE HOLE to 3020' T.D. 11:30 -13:00 1.50 010 CSGSUR CIRC. RUN CARBIDE FLAG. Printed: 01110/2003 11:15:42 AM ) ') ~~!"~ ' "'" ' " ........ ~:I ................. ·rI9~~~~NAIY~R~~9H~R~~..........··..····..·· ... ,,~\tRtf.'~~~l~~" '., ',:;OP~tåtions,:Su~~~!Y~~PºIt"," legal Well Name: IVIK#1 Common Well Name: IVIK #1 Event Name: ORIG DRilLING Contractor Name: NABORS DRILLING Rig Name: NABORS DRILLING , , ,Sub, "',D~te' From ~To ' Hours, '¢9d~, Code "'Phase 2127/2003 13:00 -17:00 4.00 013 CSGSUR 17:00 ·18:00 1.00 010 CSGSUR 18:00 . 01 :00 7.00 012 CSGSUR 01 :00 - 02:00 1.00 028 CSGSUR 02:00 - 05:00 3.00 028 CSGSUR 05:00 - 06:00 1.00 028 CSGSUR 212812003 06:00 - 11 :30 5.50 028 CSGSUR 11:30-16:00 4.50 026 CSGSUR 3/1/2003 16:00 - 18:30 2.50 028 CSGSUR 18:30 . 21:00 2.50 004 CSGSUR 21 :00 - 22:00 1.00 031 CSGSUR 22:00 - 22:30 0.50 031 CSGSUR 22:30 - 02:00 3.50 031 PROLN1 02:00 - 06:00 4.00 004 PROLN1 06:00 - 08:00 2.00 021 PROLN1 08:00-10:30 2.50 016 512 PROLN1 10:30-11:30 1.00 018 512 PROLN1 11 :30 - 14:00 2.50 015 PROLN1 14:00 - 21 :00 7.00 015 PROLN1 21 :00 - 23:30 2.50 011 PROLN1 23:30 - 00:00 0.50 010 PROLN1 00:00 - 02:00 2.00 017 PROLN1 02:00 - 03:30 1.50 031 PROLN1 03:30 - 04:30 1.00 022 PROLN1 04:30 - 05:00 0.50 006 PROLN1 05:00 - 05:30 0.50 010 PROLN1 05:30 - 06:00 0.50 022 PROLN1 06:00 - 22:30 16.50 006 PROD1 22:30 - 23:30 1.00 018 PROD1 23:30 - 00:00 0.50 010 PROD1 00:00 - 02:00 2.00 012 PROD1 02:00 - 03:00 1.00 016 PROD1 03:00 - 05:00 2.00 011 PROD1 05:00 - 06:00 1.00 006 PROD1 06:00 - 18:00 12.00 006 PROLN1 18:00 - 19:00 1.00 010 PROLN1 19:00 - 21 :00 2.00 013 PROLN1 21 :00 - 22:00 1.00 010 PROLN1 3/2/2003 31312003 " , . . . '" '. , , ., ':,P~ge ~Qf5 Start: 213/2003 Rig Release: 3/12/2003 Rig Number: 27E Spud Date: 2125/2003 End: 3/12/2003 Group: , . . . , ,",' ,,'-.' , .' . " . "', [)escri~ionof Oper~tions, SHORT TRIP 20 STDS. WASH & REAM FI2808' TO 3020' CIRC. RECIP PIPE & CONDo MUD POOH & LAY DN BHA RIG UP VETCO GREY HANGER LANDING JT. & RUN IN HOLE TO ENSURE ALL OK RIG UP NABORS CSG. TOOLS MU SHOE & FLOAT COLLAR & 2-JTS. CSG. & CIRC. TO ENSURE FLOATS OK RUN 7 518" CASING RUN 72 JTS. OF 7..s18" 29.7# L-80 BTC & WASH FROM 2976 TO 2998' CIRC & PREP. & CEMENT WITH 5 BBL H2O & 45 BBL. CW100 & 50 BBL. MUD PUSH @ 10.5 PPG. & 351 BBL(451 SACKS) OF LEAD 10.7 PPG. & 30 BBL (130 ax) CLASS G + 0.5% CaCI2 MIXED AT 15.8 PPG, DISPLACE WITH 20 BBL. H2O & PUT IN PLACE WITH 114 BBL. MUD BUMPED PLUG & FLOATS HELD. RIG DOWN CSG. TOOLS & LANDING JT. & CHANGE OUT ELEVATOR' BAILS. SET 7..s18" PACKOFF & TEST TO 5000 PSI. RUN & OPEN TAM PORT COLLAR & CIRC ANNULUS CLEAN. CIRC 7-518" X 13--3/8" ANNNULUS WITH CACL2 & 2 PERCENT METHANOL. FOR FREEZE PROTECTION CLOSE PORT COLLAR & TEST. REMOVE EXCESS EQUIPMENT FROM WORK AREA. TEST BOP EQUIPMENT TO 250 LOW & 3500 HIGH (TEST WITNESSED BY JOHN CHRISTMAN WITH AOGC. TEST BOP'S TO 250 LOW & 3500 HIGH WITNESSED BY AOGC JOHN CRISP REPAIR TOP DRIVE REPAIR IRON ROUGHNECK & LAYING DN JARS ETC. LAY DN BHA#1 MAKING UP BHA #2 (HAD PROBLEMS LOADING THE SOURCE IN MWD & LWD. TRIPPING IN HOLE TAG CMT.@ 2884' PICK UP TOP DRIVE &CIRC. CUT & SLIP DRLG. LINE DRLG OUT FLOAT COLLAR @ 2996' TO 2968 RIG UP & TEST CSG. TO 3500 PSI. OK DRLG. CIRC & CONDITION MUD FOR L.O.T. PERFORM LEAK OFF BROKE @ 16.4 EMW. STABILIZE @ 12.4 PPG. EMW. DRILLING &&4" HOLE, BACKREAM TIGHT HOLE AT 3821' LOST POWER TO TOP DRIVE, BLEW LUBE PUMP FILTER SEAL WHEN POWER TURNED BACK ON PUMPED SWEEP, PREP FOR SHORT TRIP TOH TO 2306' REPAIR AND SERVICE TOP DRIVE PU 21 JTS DRILL PIPE AND TIH, NO PROBLEMS DRilLING 6-314" HOLE CMS . DRLG. 6.75"' HOLE TO at!JOI! POINT. 'It/JØ CIRCULATE & CONDITION MUD FOR CORE BBL SHORT TRIP 20 STOS. NO PROBLEMS CIRC & CONDITION MUD FOR CORE BBL Printed: 411012003 11:15:42 AM . &1. ~:M:\ .,1,', ,. . !·~~i.j.. ,~~"" PIONEER' ." !i'ji';"::;;~::~'~'''F~j{~''',?~;~:i:'~ ' ) ) . . " : "" " '. ", ", ',', "', ':" ..,,' .,' ~ > ~ . ,,'.' .. .,,':' '. \:, .... ~ " , .' ·i:PIONE.ER·:NATP~~:RI;SQURCES . , ",," ," .:,"":,".:...:::'," '. ".' ',:', ' "", '" '. ", ':"..' ", .:',' Qp.erä~i()I1$$I.Î.Ó1l'11alY~~p()rt . .p~ge ·301.5 Legal Well Name: IVIK #1 Common Well Name: IVIK #1 Event Name: ORIG DRilliNG Contractor Name: NABORS DRilLING Rig Name: NABORS DRilLING ·Sub. ....... Date ". From-To HoufS.Cpde Code Phase. 313/2003 3/~2003 3/5/2003 31612003 3fl12OO3 3/8/2003 319/2003 22:00 - 01:00 01 :00 - 03:30 03:30 - 05:30 05:30 - 06:00 06:00 - 08:30 08:30 ~ 06:00 06:00 - 08:00 08:00 - 09:00 09:00 - 10:30 10:30-11:00 11:00 -12:00 12:00 - 19:00 19:00 - 20:30 20:30 - 03:00 03:00 - 04:30 04:30 - 06:00 06:00 - 06:30 06:30 - 07:30 07:30 - 08:30 08:30 - 09:30 09:30 - 17:30 17:30 ~ 00:30 00:30 - 06:00 06:00 - 07:30 07:30 - 12:00 12:00 - 14:30 14:30 - 20:30 20:30 - 21 :30 21 :30 - 02:00 02:00 - 05:30 05:30 - 06:00 06:00 - 01:00 01 :00 - 06:00 06:00 - 13:30 13:30 ~ 19:00 19:00 - 20:00 20:00 - 00:00 00:00 - 06:00 3.00 012 2.50 015 2.00 029 0.50 029 2.50 029 21.50 029 2.00 029 1.00 029 1.50 029 0.50 018 1.00 016 7.00 011 1.50 210 6.50 006 1.50 018 1.50 006 0.50 006 1.00 010 1.00 013 1.00 010 8.00 012 7.00 019 5.50 019 1.50 210 512 4.50 210 2.50 210 6.00 011 1.00 210 4.50 011 3.50 210 0.50 011 19.00 210 5.00 210 7.50 210 5.50 021 1.00 006 4.00 009 6.00 009 510 EVAL 510 EVAL PROlN1 PROlN1 PROLN1 PROlN1 PROlN1 PROlN1 PROlN1 PROlN1 PROLN1 PROLN1 PROLN1 PROlN1 PROLN1 PROLN1 PROLN1 PROLN1 PROLN1 PROLN1 PROlN1 PROlN1 PROLN1 PROLN1 PROLN1 EVAL EVAL EVAL EVAL EVAL EVAL EVAL EVAl EVAl EVAl EVAL EVAL EVAL Start: 213/2003 Rig Release: 3/12/2003 Rig Number: 27E Spud Date: 2/25/2003 End: 3/12/2003 Group: '. '" ' .' . , .. . DeScriptioQðf Qperatio,ns . POOH TO BHA #2 HANDLE BHA #2 DOWNLOAD SOURSE ETC MU CORE BBL. BHA #3 TRIP IN HOLE WITH CORE BARREL #1 CONTINUE TO TRIP IN HOLE WITH BHA #3 CORE BARREL ASSY.#1 7 WASH & REAM F/6OOO' TO 6100' CORING CORE #1 POOH TO BHA #3 WITH CORE BBL. ASSY. STAND BACK BHA #3 LAY DN CORE #1 & CORE BARREL (FULL RECOVERY) REPAIR DRIP PAN UNDER ROTARY TABLE SERVICE TOP DRIVE TIH WITH BHA #4 RR #2 TO 5991' LOGGING MAD PASS F/5991' TO 6143' DRLG F/6143' TO 6754' REPLACE O-RING ON STAND PIPE, & TEST SAME DRLG F/6754' TO 6900' DRLG F/6900' TO 6943' CIRC & CONDITION FOR LOGS SHORT TRIP TO CORE PT. 6100' CIRC & CONDITON FOR LOGS MONITOR WELL & POOH FOR lOGS RUN #1 LOG /CMT/PLATFORM EXPRESS/AIT-H F/6901' TO 3000' RUN #2 LOG FMIIDSI FROM 6901' TO SURFACE. FINISHED RUNNING E-lINE TRIPPLE-COMBO. DEPTH SCHLUMBERGER~6901' RAN DSIIFMI (SONIC) LOGS. RAN VSP CHECK SHOTS. RD E-LlNE. RE-ARRANGED PIPE IN THE DERRICK PU 9 JTS DP. RABBIT NEW DP & HWDP. P/U MDT TOOL & CHECK SAME. RIH TO THE SHOE WITH MDT TOOL. CIRCULATE AT THE SHOE WHILE HANGING SCHLUMBERGER'S SHEAVE IN THE DERRICK FOR WIRELlNE (MDT) WET CONNECT. RIH TO 4035' BREAK CIRCULATION. P/U SIDE DOOR SUB. RIH WITH E-LlNE AND LATCH UP ON MDT TOOL. TEST MDT TOOL: OK RIH. TOOK MDT PRESSURE READINGS: 5265',5277',531(1,5320', 5362',5378',5393',5406',5425' AND 5443' (TOROK). RIH WITH DP CONVEYED MDT TOOL TO 6400'. SCHLUMBERGER RAN DP CONVEYED MDT TOOL. TOOK A TOTAL OF 20 PRESSURE SETS AND 8 SAMPLE SETS. BHP IN NUIQSIT IS A 9.8 PPG EMW ZONE: 3272 PSI @ 641'Z MDfTVD. BHP IN TOROK IS AN 8.5 PPG EMW ZONE; 2307 PSI @ 5277.5'. POOH. UD MDT TOOL. RIH WITH MFCT TOOL TO COLLECT SIDEWALL CORES. TEST BOP. TEST PRESURE RAMS 25013500, ANNULAR 25013500, VALVES 25013500. RIG DOWN TESTING EQUIPMENT, BLOW DOWN CHOKE & KILL LINE P/U BHA & TIH FIDERRICK T/SHOE, BREAK CIRC CO NT. RIH T6796 CONT. CIRC. WAITING FOR ACCESS TO PAD Pñnæd: 411012003 11:15:42 AM ) ) ~::"~i-~ (.¡;:3 ' ¥~~ . . /PI.ONEEIt .. . . .,' ~~'~~'~;,~;~',';~~:I'~~ ~'!r~~':':µ~~,.:::'t " '. ,"', .. ". '. " ,'. '," , " " . . .' .':':.,', ~, , ': : : ", .' , . . .. . ,'" . . ,.'" . . .', . . :~IQNEE,~NÄTURA,L~E~?lJ~ÇES · .... ()pera~iqns .Sumrn-:rv·lieport . .' ': . , , .' . . . ' " . . .. ... Pag.e~ of 5 COMP CIRCULATED & CONDITIONED MUD. MUD LOOKS GOOD - NO HOLE PROBLEMS. CIRCULATED WAITING ON A BY-PASS ROAD AROUND NORDIC 3 FOR WATER TRUCK ACCESS AND EVAC (IF NEEDED). SPOT HI-VIS PILL ON BOTTOM. POOH. UD EXCESS PIPE. RACKED BACK 3000' IN THE DERRICK REPAIRED PIPE SKATE. FINISHED UD BHA, ETC. CLEARED THE FLOOR FOR LINER JOB. PJSM. RlU TUBING TOOLS. P/U & RACKED BACK 45 JOINTS OF 3-1/2" TUBING FOR INNER STRING CEMENT JOB. MlU SHOE JOINTS WITH: SET SHOE, 2 JTS, FC, JNT, LC. P/U 3-1/2" LINER & INSTALLED TURBOLATORS ACROSS PAY ZONES. P/U TAIL STRINGS 3.5 TUBING. RIH CHANGE OUT CSG. EQUIP FJ3.5 TO 5.5 RIH W5.S LINER C/O ELEVATORS & POWER TONGS F/5-1/Z' T13-1I2" TUBING ELEVATORS & TONGS, RIH F/DERRICKS 3-112" INNER STRING SPACE OUT INNER STRING & SWAP JT. #130(30.79) TO #13(28.05) C/03-1/Z' TUBING ELEVATORS TI3-1/Z' D.P. ELEVATORS/ PIU HANGER C/O 3-1/Z' POWER TONGS T/5-1/2" POWER TONGS MlU HANGER TO 5-112" RIH W/1 ST STD DRILL PIPE & MIU CMT HEAD TO TOP SINGLE, C/O ELEV. T/S" TlPICK UP CMT HEAD, SET CMT HEAD & SINGLE ON SKATE, C/O ELEV. TI3-1/Z' PROLN1 RIH LINER ON 3-112" D.P. 60'/ MIN T/6943' NO PROBLEMS PROLN1 PIU CMT HEAD & RIU TO CIRC. PROLN1 CIRC @ 45 STRKS :: 1030 PSI CBU. PUMPED 10 BBL CW-1OO, 40 BBL MUD PUSH - 30 BBL OF 13lB LEAD, 99BBL OF 15.8 TAIL, DROPPED DP WIPER PLUG & DISPLACED WI53,4 BBLS OF 9.8 BRINE, BUMP PLUG AND PRESSURED TO 4100 PSI, FINAL PRESURE 1100 PSI @2.5 BPM. TEST CMT LINES T/4600 PSI, PUMP 10 BLS CW-100, 40 BBLS MUD PUSH, 30 BBLS LEAD CMT, 99 BBLS TAIL CMT, DROP DART & BUMP WI53.4 BBLS. CJ.P. @22:57 THURS, SET HANGER & PACKER, TOP OF LlNER@2835, SHOE @ 6941, RELEASED FRM LINER & CIRC. BOTTOMS UP AND GOT 10 BBL CMT BACK MONITOR WELL FI30 MIN AND CLEAR FLOOR LD/ CMT HEAD FINISH UP CLEANING POSSUM BELLY, MUD THROUGH TO CIRC CLEAN BRINE POOH W/LlNER RUNNIGN TOL & 3.5 INNER STRING STD BACK RIU WIREUNE RIH W2.75 DRIFT W/GAUGE RING STOPPED Q 2842 WOULD NOT GO POH WJWIRELlNE DROPPED OFF 2.75 GAUGE RING RIH WI 2.7'5' DRIFT TO 6849 TAGGED UP POH RID WIRELlNE Legal Well Name: IVIK #1 Common Well Name: IVIK #1 Event Name: ORIG DRILLING Contractor Name: NABORS DRILLING Rig Name: NABORS DRILLING " . ..:..", .', :'Sub', . Dàte :F..om ~ To Hou~·Cøde Codø Ph~se. . 3/1012003 06:00 - 10:30 4.50 010 10:30 - 13:30 3.00 012 CaMP 13:30 - 16:00 2.50 018 501 COMP 16:00 - 21 :00 5.00 012 COMP 21 :00 - 00:00 3.00 '028 CaMP 00:00 - 06:00 6.00 028 COMP 3/11/2003 06:00 - 08:00 2.00 028 PROLN1 08:00 - 09:00 1.00 028 PROLN1 09:00 - 12:00 3.00 028 PROLN1 12:00 - 14:00 2.00 028 PROLN1 14:00 - 15:00 1.00 028 PROLN1 15:00 - 15:30 0.50 028 PROLN1 15:30 - 16:00 0.50 028 PROLN1 16:00 - 17:00 1.00 028 PROLN1 17:00 -19:00 19:00 - 19:30 19:30 - 21 :30 2.00 028 0.50 028 2.00 028 21 :30 - 23:30 2.00 028 PROLN1 23:30 - 01 :00 1.50 028 PROLN1 01 :00 - 02:00 1.00 028 PROLN1 02:00 - 03:00 1.00 028 PROLN1 03:00 - 06:00 3.00 028 PROLN1 3/12/2003 06:00 - 08:30 2.50 206 PROLN1 08:30 - 10:30 2.00 206 PROLN1 10:30-11:00 11:00 -12:00 0.50 206 1.00 206 PROLN1 PULL WEAR BUSHING PROLN1 RID LOWER IBOP ON TOP DRIVE BE ABLE TO INSTALL SAFETY VALVE ON TUBING RUN. PROLN1 RIH W/3-1/Z' 9.2# IBT TUBING & TAG W/JT# 222 31' IN 12:00 ~ 18:00 6.00 206 Start: 2/3/2003 Rig Release: 3/12/2003 Rig Number: 27E Spud Date: 2/25/2003 End: 3/12/2003 Group: . .. . .. D~scnþtionof()peration$·: > , ," . Pñnted: 411012003 11:15:42 AM ') ) 1~"'~;-Ì\ ~~\,,:~t . ; II '¿Wi -"';;:':""~ .. .. PIONEER " : ' '~~"~~\'1.:.#~~::' '~~l'I~Vi¡:2~~,~~I\\~ . " ' " ',', ~ . . , . . : ". 'I . ' " " , " . :.. .': . .,' . ...... . . '. . . " .. , .. , ' . .. ::·PIONEER'NATURALRESOÜRCES", . . ., ·':'0. :. P.' '·~ralti'()Os"Sll~:lnélrY,~. e. p<>. rt " . ", " ,". " , <"Page ~·,of,S Legal Well Name: IVIK#1 Common Well Name: IVIK#1 Spud Date: 2/25/2003 Event Name: ORIG DRILLING Start: 2/3/2003 End: 3/12/2003 Contractor Name: NABORS DRILLING Rig Release: 3/12/2003 Group: Rig Name: NABORS DRILLING Rig Number: 27E . , ' , Sub . ,,',', ··Dätø' Fr9m .; To , Hours' . Code·' Code' Phase ']~~scl'ipti(jn ofÓperatiøn~ .'. ., 3/1212003 18:00 - 19:00 1.00 206 PROLN1 STRING IN & SPACE OUT TUBING. SET 10 K& PRESS ANNULUS T/5OO PSI GOOD, BLEED PSI & P/U 5' & RE-TEST SEAL ASSEMBLY, INTEGRITY GOOD 19:00 - 20:00 1.00 206 PROLN1 RID SPACE OUT JTS, MIU 2 PUP JTS (2.67 & 9.89), GlMlSSSV 20:00 - 20:30 0.50 206 PROLN1 RIU & TEST CONTROL LINE TI5,OOO PSI 20:30 - 21 :30 1.00 206 PROLN1 C/O ELEVATORS TI3-1/2" D.P. & MlU XlO'S TO LANDING JT & P/U TUBING HANGER 21 :30 - 22:30 1.00 206 PROLN1 HOOK UP SSSV CONTROL LINES T/HANGER & TEST LINES T/5,OOO PSI 22:30 - 23:00 0.50 206 PROLN1 TEST SEAL ASSEMBLY FIPROPER SPACEOUT PRIOR T/FREEZE PROTECT T/2000PSI - GOOD, P/U 2C1 TO PUMP FREEZE PROTECTION AROUND 23:00 - 23:30 0.50 206 PROLN1 PUMP DIESEL TO FILL LINES THEN PSI TEST LINES T/3,ooo PSI- GOOD, PUMP 44 BBLS DIESEL TO DISPLACE TUBING, PSlm550, STING IN SEAL ASSEML Y & BLEED PSI DOWN TIZERO, LAND HANGER 23:30 ~ 00:00 0.50 206 PROLN1 LOCK DOWN HANGER, PRESSURE TEST TUBING TI3,ooo PSI HOLD F/30 MIN. 00:00 - 02:00 2.00 206 PROLN1 BLEED DOWN TBG PRESSURE TO 2000 PSI. RIU AND TEST 3 1/2" x 75/8" ANN TO 3500 PSI FOR 30 MIN. BLEAD DOWN TBG AND ANNULUS PRESSURES. CLEAR LINES. CLOSE SSSV. 02:00 ~ 02:30 0.50 206 PROLN1 BACK OUT & LAY DOWN LANDING JT. 02:30 - 03:00 0.50 206 PROLN1 SET BPV 03:00 ~ 06:00 3.00 206 PROLN1 N/D BOPE, REMOVE RISER, BELL NIPPLE, CHOKE & KILL LINE, HOOK UP BRIDGE CRANE, PREPARE TO SET BACK BOP STACK 3/13/2003 06:00 ~ 09:00 3.00 022 COMP N/U ADAPTER FLANGE AND TREE 09:00 ~ 10:30 1.50 022 COMP TEST ADAPTER FLANGE AND TBG HGR. TO 5000 PSI, HOLD FOR 10 MIN, OK PRESSURE TEST TREE TO 4000 PSI HOLD FOR 10 MIN, OK, FUNCTION TEST SSSV, CLOSE SAME 10:30 - 12:00 1.50 022 COMP CLEAR FLOOR OF COMPLETION EQUIPMENT, SECURE WELLHEAD AND TREE. RELEASE RIG FROM OPERATION ON IVIK #1. 12:00 - 15:00 3.00 022 COMP BLOW DOWN H20, DISSCONNECT LINES BEìWEEN COMPLEXS, PREP CELLAR FOR RIG MOVE 15:00 - 18:00 3.00 022 COMP RIG DOWN BERMS, GERONIMO LINE, MOVE CUTTINGS TANK 18:00 - 21:00 3.00 022 COMP LOAD PIPE SHED WIMISC. PARTS, CENTER UP TOP DRIVE, C/O CMT LINE 21 :00 - 00:00 3.00 022 COMP BLOW DOWN STEAM, PULL SKATE RAIL INTO CATTLE CHUTE, PREP BOARDS FOR RIG MOVE, UNPLUG ROOM, SCOPE UP CATTLE CHUTE EXTENSION 3/1412003 06:00 - 06:00 24.00 002 MIRU MlU CAMP, RIG, TELECOM, ETC TO OOOGURUK .r Printed: 411012003 11:15:42 AM ) dF"': jj~~ I', ~i?~,1{, ~ ... ,,' PIONEER. " '. '.:~,·;~,:~.;;;~n¡:~··~~~,'~f¿',,;:~~~:{·~ ') , , , ' . . . . ' . Pag~, t9f~ " '" . ',.,.," . . . ,,'., . .',:. '" :." ',', ,',' " . ',' , , 'PIO,N,EERNATURALRE$()URQES::"" . .. .ó~~Utjh~áuml1l~..y:Be~~rt ... . legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: "", Pate IVIK #1 IVIK #1 ORIG COMPLETION NABORS DRilLING NABORS DRilLING , ,', ," ,'\$uÞ FrolJ1~ Tef Hoµ,rs :C()de, Code, 3/1712003 06:00 - 06:00 24,00 003 311812003 06:00 - 06:00 24.00 003 3/19/2003 08:00 - 19:00 11.00 211 19:00 - 21 :30 2.50 202 3120/2003 06:00 - 06:00 24.00 202 3/21/2003 06:00 -18:00 12.00 207 Start: 213/2003 Rig Release: 3/12/2003 Rig Number: 27E Spud Date: 2/25/2003 End: 4/9/2003 Group: Pha~: . ',' ',' , ." , :,", . " ,', ',", . " ",-De~criptlèm,(jf O¡jeratiqns MIRU Rig Up Testers MIRU FINISH RIG UP TESTERS, FLUSH LINES AND PRESSURE TEST 3500 PSI COMP WO SCHLUM, SHOWED UP WITHOUT MAST UNIT, WO MAST UNIT, RAN CCLlSCMT TO 6840' LOGGERS PBTD, LOG UP TO 6500' AND TOOL FAILED, POOH AND CHANGE OUT TOOLS, LOG INTERVAL 6820 - 4100', GOOD BOND OVER PERF INTERVAL, RD SCHLUM LOGGERS COMP RU SCHLUM CTU, PREP FOR PERF IN A.M. TEST 3/18/03 RIU SCHLUMBERGER E-UNE. RAN SCMT LOG FROM 6840' ·4100'. GOOD CEMENT ACROSS NUIQSIT SAND ZONE, RIO SCHLUMBERGER. 3/19/03 RIU SCHLUMBERGER CTU. RIH WITH MEMORY LOG ON 1.5" COILED TUBING. FLAGGED COIL & LOGGED 6600' - 6400'. POOH & PROCESSED LOG. ADJUSTED SPACE OUT TO CORRELATE WITH E-LlNE lOG. P/U 2.5" TCP GUNS. RIH ON COILED TUBING. SPACED OUT GUNS PER PROGRAM. DROPPED 0.5" BALL. PRESSURED UP ON COILED TUBING TO FIRE TCP GUNS: 6410' - 6422' (6 SPF) 6436' - 6462' (6 SPF) 6468' - 6470' (6 SPF) 6474' - 6478' (6 SPF) PULLED UP 200' & OBSERVED WELL. NO FLOW. NO PRESSURE INCREASE. DROPPED BACK DOWN TO PERFORATING DEPTH FOR SAFETY. PRESSURED UP ON PERFORATIONS TO 2500 PSI- VERY LITTLE BLEED OFF. PRESSURED UP ON PERFORATIONS TO 3000 PSI- PRESSURE BROKE TO 2500 PSI. PUMPED INTO PERFORATIONS 5 BBL OF DIESEL TO CONFIRM PERFORATIONS, ETC. BLED OFF PRESSURE. DROPPED DOWN BELOW "X" NIPPLE. DROPPED 0.75" BALL & RELEASED TCP GUNS - FELL TO BOTTOM. POOH WITH COILED TUBING. SECURED CTU FOR THE NIGHT. RlU SLICK LINE. RIH & SET BHP GUAGES IN "X" NIPPLE AT 6885'. POOH. RID SLU. SECURED WELL. SION. TEST SITP THIS AM = 10 PSI. OPENED WELL TO FLOW· BLED TO 0 PSI: NO RECOVERY. TUBING FULL OF DIESEL RlU NH B & R" AND PUMPED 30 BBL OF DIESEL INTO PERFORATIONS: 2.5 BPM AT 3000 PSI 20 BBL 3.2 BPM AT 3300 PSI 10 BBL ISDP 2350 PSI 10 MIN SIP 2050 PSI Printed: 411012003 11:08:16AM ) ) . . , . . . .., . '" . ,". '. ,', " , ,',' . ,'. "." ' '. \:' ~åg~2.~f 5. ~'~~ . i', ' ;~ .':~ 1;#1 :-. -~~i PIONEElt ~'~"'~~1,¡,"1'~~;~'~:~~'~:~~~":1~:«" ............. ... ..p'QN'EERNÅ~~F~ÅL~E~oJkcE$ .................... ·····9~~h~;~~~m.~~~~rt ................ Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: IVIK #1 IVIK#1 ORIG COMPLETION NABORS DRILLING NABORS DRilLING ·.:.oète· '. r=rom~To l-Ì~u~:'Cod~ .~~be . . ·Þhase. 3/21/2003 06:00 ~ 18:00 12.00 207 TEST 18:00 - 06:00 12.00 216 TEST 3IZ2J2003 06:00 - 06:00 24.00 216 TEST 3123J2OO3 06:00 - 06:00 24.00 216 TEST 312412003 06:00 - 06:00 24.00 216 TEST 312512003 06:00 - 06:00 24.00 208 TEST 3/2612003 06:00 - 06:00 24.00 207 TEST 3/27/2003 06:00 - 06:00 24.00 207 TEST 3/28/2003 07:00 - 14:00 7.00 205 TEST 14:00 - 14:20 0.33 205 TEST 14:20 -16:34 2.23 205 TEST 16:34 - 16:48 0.23 205 TEST 16:48 - 19:00 2.20 205 TEST 19:00 - 20:10 1.17 207 TEST 20:10 - 06:00 9.83 207 TEST 312912003 06:00 - 15:00 9.00 207 TEST Spud Date: 2/2512003 End: 4/9/2003 Group: Start: 2/3/2003 Rig Release: 3/12/2003 Rig Number: 27E ", ".:De~cripti()~l ot:ôpe,' ratiò~S" ' . " " . , RlU CTU & NITROGEN PUMPER. RIH WITH COILED TUBING TO 6400' DISPLACING THE TUBING WITH NITROGEN WHILE RIH. JETTED THE TUBING DRY AT 6400'. RECOVERED 90 BBL OF DIESEL == 55 BBL OF TUBING VOLUME + 35 BBl OF COIL VOLUME. NO INFLUX FROM THE FORMATION EXCEPT THAT THE FINAL FLUID SAMPLES WERE BLACK DIESEL WITH ASP HAL TINE ODOR. DIESEL PUMPED WAS 41 GRAVITY API @ 60 DEGREES. THE FINAL SAMPLES WERE 39.6 GRAVITY API @ 60 DEGREES. RID CTU & NITROGEN PUMPER. LEFT WELL OPEN TO THE TANKS. LACK 30 BBL OF DIESEL TO RECOVER (FROM PUMP IN TEST ABOVE). LEFT WELL OPEN TO THE TANKS. NO FLOW. FTP = 0 PSI. WAITING ON ORDERS. SHUT IN FOR BUILD UP. WOO. FINAL SITP = 85 PSI. SHUT IN FOR BUILD UP. SITP= 464 PSI SHUT IN WIO FRAC JOB. SITp· 771 PSI. RlU HES SLU. PULLED BHP BOMBS. DUMMIED OFF GLM. PREPARED FOR FRAC JOB. SITP = 881 PSI. OPEN NED WELL UP TO FLOW LINE. MADE 16 BBLS OF DIESEUOIL & DIED. SHUT IN. WAITING ON FRAC JOB. MOVED IN DOWELL FRAC EQUIPMENT FOR FRAC JOB. RIG UP SLB FRAC CREW AND SUPPORT EQUIPMENT. TRANSFER AND GEL FLUIDS. QA/QC FRAC FLUIDS. PRESSURE TEST LINES TO 8000 PSI DIAGNOSTIC PUMP INS, STEP RATE, STEP DOWN AND DATA FRAC PUMP FRAC JOB. FRAC'D JURASSIC FORMATION WITH 200 BBLS OF YF-125LG FLUID AT AN INJECTION RATE OF 20 BPM PLACING 30,000 LBS 20/40 CARBOLlTE PROPPANT IN FORMATION. TREATMENT WAS FLUSHED TO TOP PERF WITH 55 BBLS. FLUSH INCLUDED -35 BBLS OF DIESEL. WELL SHUT-IN RIG DOWN SLB AND SUPPORT EQUIPMENT. TURN OVER TO NTS TESTING FOR FLOWBACK START FLOW TEST @ -20:10. APPROX. 70 BBLS RETURNED. SAMPLES CONTAIN GEL AND PROPPANT NTS FLOW TEST WELL RAutomated Data Entry, Inlet Samp 0.5% W/C, No Solids Divert To Tank Three Automated Data Entry, Divert to Tank #6 Automated Data Enby,Correded API 2O.7,Divert to Tank #1 Automated Data Enby,DJvert to Tank #2 Gas Gravity .659 Automated Data Entry, Divert to Tank #3 Begin Injecting Defoamer at Well Head Automated Data Entry, Divert To Tank One Printød: 4110/2003 11:08:16 AM ') ) , . \, . ",' . . . . '.' .:p~Qe30f 5 . .'. ···...:þ10NF~R,NÁTUFiAL:RE~QURCt:S,':,' .. .... .... '9PIi~~6$~ufu~a~~~PÅI·t ... ... Legal Well Name: IVIK#1 Common Well Name: IVIK #1 Event Name: ORIG COMPLETION Contractor Name: NABORS DRILLING Rig Name: NABORS DRILLING "Date: '·.Fro~-ro' :}I~ul$ qÓde'~:e ::PhS$6, . 3/29/2003 06:00 - 15:00 9.00 207 15:00 - 06:00 15.00 207 3I3OJ2003 06:00 ~ 10:30 4.50 207 10:30 - 06:00 19.50 3131/2003 06:00 ~ 06:00 24.00 216 41112003 06:00 - 10:00 4.00 216 10:00 - 21 :00 11.00 206 21 :00 - 06:00 9.00 216 4/212003 06:00 - 06:00 24.00 216 41312003 06:00 - 21 :00 15.00 216 Start: 213/2003 Rig Release: 3112/2003 Rig Number: 27E Spud Date: 2125/2003 End: 4/9/2003 Group: , ". ":D~~CriPtjQnOf Ó~ratiòris , . ' TEST Automated Data Entry, Divert To Tank Two Divert To Tank Two Automated Data Entry, Up Choke To 44. Divert To Tank Three Corrected Oil API 20.3 Automated Data Enby, Divert To Tank One, Haliburton On Loe. Rig Up Slick Une Automated Data Entry" 5/1 Well For Haliburton Divert To Tank Two TEST RIU HALLIBURTON SLICKLINE , FOUND PROPPANT, RAN GUAGE RING 0 5936'. SET BOTTOM HOLE PRESSURE BOMB AND XNIPPLE AT 4310'. RIG DOWN HALLIBURTON AND OPEN WELL FOR FLOW. OVERNIGHT FLOW RATE @13OOBBL. RUNNING OUT OF TANK ROOM. RECOVERY TO DATE 1711 BBL. TEST Automated Data Entry By-pass Sand Control Unit to Heater Open to Low Oil Scrubber Automated Data Entry Automated Data Entry start Injecting De-Foamer Automated Data Entry SII Defoamer Injection Automated Data Enby, SII Well At Wing,BloWing Down Blow Down Complete,Monltloring Well Head psi, Waiting On Fluid Transport TEST WELL SHUT IN @10:3O. PRESURE 617 PSI. WAITING ON TRUCKS TO REMOVE CRUDE FROM HOLDING TANKS. TEST WELL SHUT IN. OFFLOADED 1200 TO 1400 BBl OF PRODUCT TO FLUID TRUCKS. MONITORED PSIG AND TEMP. CURRENTLY PSIG @689. TEST SHUT IN FOR BHP BUILD UP. HAULED ALL PRODUCED Oil TO CPF-3. TEST RIU SLlCKLINE UNTI. RIH & TAGGED FilL 10 FT ABOVE GUAGES. POOH. RIH WITH BAILER & BAILED CARBO LITE DOWN TO TOP OF GUAGES. POOH. RIH & RETRIEVED GUAGES. DOWNLOADED BHP DATA. RE-SET GUAGES. RIH & HUNG GUAGES IN THE X NIPPLE AT 4300 FT. RID SLICK LINE. TEST OPENED WELL TO THE TEST UNIT ON A 32/64 INCH POSITIVE CHOKE: FLOWING 1000 BOPD, GRAVITY = 20. 300 MCFPD, FTP = 280 PSI. TEST FLOW TESTED THE WELL ON A 32164 INCH POSITIVE CHOKE: 1000 BOPD. 300 MCFPD, FTP == 290 PSI. 1/2 % BS&W. WELL LOADED UP & TRIED TO DIE A FEW TIMES BUT IT UNLOADED A SLUG OF FLUID THEN RETURNED TO NORMAL. WE HAD TO REMOVE CARBOLlTE FROM THE SEPARATOR SEVERAL TIMES DURING THE DAY. TEST FLOW TESTED WELL AS BEFORE: 800-1000 BOPD. 300 MCFPD, STP = 290 PSI, 1/2 % BS&W. 51 AT 9:00 PM AT END OF 48 HR FLOW TEST. TOTAL OIL HAULED TO CPF-3 ::I 3828.48 BBL Printed: 411012003 11:08:16 AM ) ,.(~'(-~,!""" t:: " ""'~låNEE:~,~ATUM,L:R~~OlJRÇES ,,' /Þ~~fåti~n~,S~Jr¡~~~fiè~rt··.. .. "", ' ,"':'" ;' " . . . ""., ".Pe.~bripti()~' Of,()perati()n~ SHUT WELL IN FOR BUILD UP. FLUSHED & CLEANED FLOW LINES, ETC. PREPARING FOR DE-MOB. SI FOR BHP BUILD UP TEST. DE-MOBILIZED NTS TEST EQUIPMENT. SHUT IN FOR BHP BUILD UP TEST. SI FOR BHP BUILD UP TEST. FINISHED SI BHP TEST: 95 HRS (DAYLIGHT SAVINGS TIME). FINAL SITP = 480 PSI. RIU SLICK LINE. RIH WITH 2.05" GUAGE RING: HIT HYDRATE PLUG AT 42' FROM PAD LEVEL. RAN A 2.63" GUAGE RING & HIT IN THE SAME SPOT. RAN A 2.25" GUAGE RING WITH THE SAME RESULTS. BLED DRY GAS GAS FROM THE TREElTUBING: NO CHANGE IN SITP. CALLED OUT HOT OIL TRUCK + METHANOL TO THAW OUT HYDRATE PLUG. WAITED ON HOT OILER. RlU TO WELLHEAD. PUMPED 3 BBL OF METHANOL & 9 BBL OF HOT DIESEL. FINAL SITP 500 PSI. RlU SLICK LINE. RAN 2.25" GR TO T/BHP BOMBS: OK RAN RETRIEVING TOOL. CAUGHT & RELEASED BHP BOMBS. RIH TO 5300' FOR A GRADIENT STOP. RIH TO T/PERFS TO CHECK TUBING: OK MADE FINAL GRADIENT STOP AT 6300'. POOH WITH BHP BOMBS. FINISHED POOH WITH BHP BOMBS. PULLED DUMMY VALVE FROM GLM. SET "Rp· SHEAR VALVE IN GLM (1600 PSI SHEAR). RID SLICK LINE UNIT. BULLHEADED 100 BBL OF 10 PPG MUD TO FLUSH/DISPLACE THE TUBING AND LOWER LINER: WELL DEAD. RIU SCHLUMBERGER. RAN & SET EZSV IN THE 3.5" LINER AY' 6375' RKB. PULLED UP & THEN TAGGED EZSV TO VERIFY SETTING DEPTH: OK POOH. PRESSURE TESTED THE EZSV TO 2000 PSI FOR 30 MINUTES ~~ . SCHLUMBERGER DUMPED 25' OF CEMENT ON THE EZSV (2 / RUNS). RID E-LlNE. RlU HALLIBURTON SLICK LINE. RIH & OPENNED THE SLIDING SLEEVE AT 3112' RKB. PUMPED THROUGH SLIDING SLEEVE TO CONFIRM IT IS OPEN. SET OTIS "PUMP THROUGH VALVE" IN THE "X" PROFILE IN THE SLIDING SLEEVE. RID SLICK LINE. TESTED THE VALVE THROUGH THE IA TO 500 PSI: OK ABAND RlU DOWELL. TESTED LINES. PUMPED ABANDONMENT PLUG FROM 3113'TO SURFACEAT3 BPMAS FOllOWS: ,PIONEElt '. ,;:}?~;;:~ lï·~"':¡"~'~~:·~":'Wi~::~;); Legal Well Name: IVIK #1 Common Well Name: IVIK #1 Event Name: ORIG COMPLETION Contractor Name: NABORS DRILLING Rig Name: NABORS DRILLING , . ., , Sub' Date 'F~om-To , Houl$ ,C()de , Code" ' P~a~e, ' 41312003 21:00 - 06:00 9.00 216 TEST 4/412003 06:00 - 06:00 24.00 216 TEST 4/5/2003 06:00 - 06:00 24.00 216 TEST 4/612003 06:00 - 06:00 24.00 216 TEST 417/2003 06:00 - 21 :00 15.00 216 TEST 21 :00 - 23:00 2.00 031 ABAND 23:00 - 03:30 4.50 031 ABAND 03:30 - 06:00 2.50 031 ABAND 4/812003 06:00 - 08:00 2.00 030 ABAND 08:00 - 09:00 1.00 030 ABAND 09:00 - 14:30 5.50 019 ABAND 14:30 - 15:30 1.00 030 ABAND 15:30 - 20:30 5.00 030 ABAND 20:30 - 23:30 3.00 030 ABAND 23:30 - 02:30 3.00 026 ) . ,~ ' , . '. '. . . , ,.' , , , . . ,..pag~·~ .of 5 Start: 2/3/2003 Rig Release: 3/12/2003 Rig Number: 27E Spud Date: 2/25/2003 End: 4/9/2003 Group: 10 BBl FRESH WATER SPACER 90 BBl (600 SX) ARCTICSET CEMENT AT 15.7 PPG 20 BBl (130 SX) CLASS "G" CEMENT AT 15.8 PPG 20 BBl (140 SX) ARCTICSET CEMENT AT 15.7 PPG 1 BBl FRESH WATER TO CLEAR THE SURFACE LINES. CIP AT 01:15AM. GOOD CEMENT RETURNS TO SURFACE. WITNESSED BY LOU GRIBAlDI AOGCC. PRESSURED UP THE IA TO 2200 PSI & SHEARED THE "RP" SHEAR VALVE. CIRCULATED THE ANNULUS & TUBING CLEAN WITH HOT , Printed: 4111112003 11:08:16 AM ) ) .,,' " .' ',", .,' , , , , , , . , . , :,,~åg~ 5,of5 ,,_i-¡:.., ,~ , ~IO,Ni=~RNATU~L.RI;Sqq~Ç'ES" ,.' , ',()pøré1ti():nf5,SUmmaìy':~pport: i,'.' , 'PIONEER' " ': ~ 1:)\\~~~.':i-;':~;:~~~~:"~¡'~:~::'~~:':'·~'1. Legal Well Name: IVIK #1 Common Well Name: IVIK #1 Event Name: ORIG COMPLETION Contractor Name: NABORS DRILLING Rig Name: NABORS DRILLING ,Sub "D~lte 'From-To' H()~rs:Code ,Cöde'Pha$e, Spud Date: 2/25/2003 End: 4/9/2003 Group: Start: 2/3/2003 Rig Release: 3/12/2003 Rig Number: 27E " '. . b~~~riptioo,'ofop~r~ti,on$, ". ' , ' .' '., WATER THROUGH THE GLM AT 92' RKB. RID DOWELL & HB&R. WOC. WAITING ON CEMENT. WOC. WAITING ON SCHLUMBERGER. PJSM. RlU SCHLUMBERGER E-LINE. TAGGED CEMENT IN GLM AT 95' RKB (6C1 BELOW PAD LEVEL). CUT 3-1/2" TUBING BETWEEN THE SSSV AND THE GLM WITH A CHEMICAL CUTTER. POOH. MOVED BACK AWAY FROM THE TREE. NID TREE & REMOVED SAME. BACKED OUT LDS's. PULLED TUBING HANGER, TUBING AND SSSV. LATCHED ONTO CASING PACKOFF & PULLED SAME. RE-HEADED SCHLUMBERGER'S LINE THROUGH VETCO CROSSOVER & HGR RUNNING TOOL. SCHLUMBERGER'S CABLE HEAD ADAPTOR DID NOT FIT THE 6--3/8" CHEMICAL CUTTER. CALLED DEAD HORSE & FOUND THE CORRECT PART. WAITED ON NEW CABLE HEAD ADAPTOR. MADE UP CHEMICAL CUTTER. RIH & SPACED OUT SO' BELOW PAD LEVEL. ATTEMPTED TO CUT THE CASING: POOH MOVED SCHLUMBERGER OUT OF THE WAY TRIED TO PULL THE 7-5/8- CASING AND HANGER WITH A CRANE: NO MOVEMENT. APPARENTLY NOT CUT COMPLETELY. ORDERRED A MECHANICAL CUTTER FOR 7-5/f!' CASING AS A BACK UP PLAN. MADE UP SECOND CHEMICAL CUTTER. ATTEMPTED TO CUT THE CASING AT 40' BELOW GROUND LEVEL: FIRED BUT DID NOT CUT. RID E-LlNE. SHUT DOWN. WAITING FOR CASING CUTTER, HOT WATER & RESTING PERSONNEL. PICK UP 5-314- CASING CUTTER ON 3-112" DP. PIU POWER SWIVEL WITH THE CRANE. RlU HB&R TO PUMP HOT WATER. R/U 2 APC VAC TRUCKS TO CAPTURE RETURNS. CUT THE 7-518" CASING AT 45' BELOW PAD LEVEL (18' BELOW THE MUD LINE). I UD CASING JOINT, PUP's & HGR. PULL & UD WELLHEAD ASSEMBLY. PICK UP 8-114" CASING CUTTER ON 3-1/2" DP. PIU POWER SWIVEL WITH THE CRANE. RIU HB&R TO PUMP HOT WATER. R1U 2 APC VAC TRUCKS TO CAPTURE RETURNS. CUT THE 13-318" CASING AT 42' BELOW PAD LEVEL (15' BELOW THE MUD LINE). UD CASING JOINT. RID POWER SWIVEL, ETC. DE--MOB REMAINING EQUIPMENT & SATELlTE CAMP. SCRAPED & CLEANED UP THE ICE PAD. DUG OUT CELLAR PIPE & BACKFILLED THE HOLE WITH CLEAN ICE CHIPS. ABAND 41812003 23:30 - 02:30 3.00 026 3.SO 027 7.00 027 2.00 030 ABAND ABAND ABAND 02:30 - 06:00 06:00 - 13:00 13:00 - 15:00 419/2003 15:00 - 16:00 1.00 030 ABAND ABAND 16:00 - 20:00 4.00 030 ABAND 20:00 - 21 :30 1.50 030 ABAND 21 :30 - 22:30 1.00 030 ABAND 3.00 030 22:30 - 01 :30 ABAND 01 :30 - 06:00 4.50 3.00 030 ABAND 4110/2003 06:00 - 09:00 ABAND 09:00 - 12:00 3.00 030 12:00 - 06:00 18.00 030 ABAND FINAL REPORT. Printed: 411012003 11:08:16 AM 2/18/03 I DRAWING NO: I SHEET: I REV: 1 OF 1 0 CADD F1LE NO, LK601 D496 NSK 6.01-d496 Pioneer Natural Resources Alaska, Inc. IVIK #1 CONDUCTOR AS-BUILT ~6 -1217---^v I SURVEYOR'S CERTlFICA TE I HEREBY CERTIFY THA T I AM PROPERL Y REGISTERED AND LICENSED TO PRACTICE LAND SUR'ÆYlNG IN THE STA TE OF ALASKA AND THA T THIS PLA T REPRESENTS A SURVEY DONE BY ME OR UNDER MY DIRECT SUPERVISION AND THA T ALL DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF FEB 19, 2003. w 500' ." 1 I( ^v -IVIK No. ¿ a L() "<t ..- ~ ¿ ^"« I .,,, I 2!~ ~ J .",~ II iff r' <.)~ J~ .:t"; ','" !. ~I:~ I ",,' .".' Th tis Is ,,<. ",,', <". ,n! I . ! .,....··..·....-·-·-"-·-;bOGU R. U0..~~·~-·-'l--·--·--i--'.. ---.-·..·-1.'-..·--··,--····-···· j----¡- " ~ ~ t I 3>" I T ::N I ,. I ~ I "~~" I " L / I ¡ T13N I ¡ I cx.m I ¡ i, \ DOQ( ~'6 !~:i <1(. J i ? I 1 (" ¡ 5 ¡ :/TI:~~~;·~~¡-¡" ;-I:·" .~,~ ":~\ ·:.,---·:~-r>t~:~hl7!~1L1~r ..._~.._.._.............!.._." ..J............,'. .., ) 'if"' ~~ " I I ~ ~ J)I ~\.._.!:l~qL- ___.~~_1~~~~~_.~~ ._-=- I.~m_ ¡ ':&1 Q .¢' A I D5-;,w f: ~ ü, u--r ,1~1\ :¡ú t'J ¡ &- B'i'ò 1: r k ::~ ,2t~ .'íO Z~ ~DS-i . /. I ~ . -I \ ¡ I .' ",~,_...,., _ '~~ _ ~I . .: _ . ~L') ~rì -! ~ \ I.A ~~ VÆ:S1¡ SA ( 1& V I " '" ~ I ~~ " ...--;,3':0 ~'. ~~J. .~l· ,,~ r," 1~'>2! ~~ ~ ! \ q, U I T~"'3~ ~~ j, ~ OJ ì T12N \ 1 D5-JI I I (fo , ~o i WW \ t·:¡,Qj b ~I ! ~~' 'Q i'...,, .~1 ~..s>,.. 'M~h... ~--_.-1:._-j-'_._~. ~-_J-t:."'f. ~'"-""'1.." ~._~.~ <h ~~~ Q~3H ....., au \) \ \)~}-' :if" J 1 " D ~ L 'u.=; 0..:. ""---- '1 ¡ It I i\ . ! goO\, ~.r.. ~\ !~¡ DS-3A._ VICINITY MAP SCALE: 1 II = 2 MILES TOP OF ICE PAD 1. COORDINATES SHOWN ARE ALASKA STATE PLANE, ZONE 4, NAD 27. 2. GEOGRAPHIC COORDINATES ARE NAD 27. 3. ALL DISTANCES ARE TRUE. 4. BASIS OF LOCATION IS DRILL SITE 3R MONUMENTS. SET BY LHD & ASSOCIATES. 5. ELEVATIONS ARE DERIVED FROM LEICA HI-PRECISION GPS UNITS & ARE DEPENDENT ON GRA VIMETRJC GEOID MODELING. DATUM IS B.P.M.S.L NOTES: SCALE: 1" = 200' IVIK No. 1 LOCATED WITHIN PROTRACTED SEC. 6, T 13 N, & R 8 E, UMIAT MERIDIAN, 1450' F.S.L., 500' F. W.L. LA T = 70"30'22.571" N LONG = 150·11'23.589" W Y = 6,034,820.3' X = 476,789.8' ICE PAD ELEV.= 18.5' ADL 0389950 ~f N l' . RE;V DATE BY CK APP ') DESCRIPllON DESCRIPllON REV DATE BY APP ." ~Re: Pio~eer eyes slice of Slope ) ) Subject: Re: Pioneer eyes slice of Slope Date: Fri, 11 Apr 2003 09:28:38 -0700 From: Park.Chae@epamail.epa.gov To: Godsey.Cindi@epamail.epa.gov CC: Tom_Maunder@Admin.State.AK.US s=- '0-\~~\ 'dO'd-ddS Cindi, I spoke with Tom Maunder at the AOGCC about this company (Pioneer Natural Resources Co.) According to Tom, the drilling occurred without any discharge. All potential discharges were collected and disposed of in a nearby class 2 injection well. Without a discharge, NPDES would not apply, which explains why they are not covered by an NPDES permit. I want to let you know Cindi that I appreciate you taking the time to bring things like to my attention. Cindi Godsey/R 1 O/USEP AI To: Chae Park/R 1 O/USEP AlUS@EPA US@EPA cc: Sent by: Subject: Pioneer eyes slice of Slope Anchorage Daily News <adn@nandomedia.c om> 04/07/200301 :56 PM Please respond to Cindi Godsey The following adn.com article was sent by: Cindi Godsey (godsey.cindi@epa.gov) And Cindi Godsey had this to say: Chae, I saw this story and thought that these guys didn't have permit coverage under the Arctic GP and I am not sure how they could have drilled 3 wells from an ice island without discharging so thought you might want to look into it. Any comments on the North Slope GP?? --------------------------------------------------------------- Pioneer eyes slice of Slope OIL: Though exploration yields modest results, Dallas company plans another test. 1 of 2 4/11/20038:38 AM ~R~: Pio~eer eyes slice of Slope ) ) By WESLEY LOY, Anchorage Daily News Published: April 1 2003 A Dallas-based oil company on Monday announced mixed results from its first round of exploratory drilling on the North Slope. Pioneer Natural Resources Co. said all three wells it drilled in shallow water northwest of the Kuparuk oil field struck sandstone filled with oil but the sands were "too thin to be considered commercial." Pioneer added, however, that it found Jurassic rocks, which are deeper and older, and one well flowed at a sustained rate of 1 ,300 barrels of oil per day. The well will undergo a pressure buildup test to determine whether the find is worth developing, the company said. You can read the full story online at: http://www.adn.com/business/story/2872950p-2909203c.htm I --------------------------------------------------------------- This article is protected by copyright and should not be printed or distributed for anything except personal use. For information on reprinting this article or placing it on your Web site, please contact the Daily News marketing department at (907) 257-4429 or marketing@adn.com. 2 of 2 4/11/20038:38 AM ) ) BUSINESS DEVELOPMENT J. Patrick Foley Alaska Land & Negotiations Consultant (907) 264-6750 . (907) 830-0999 mobile PIONEER NATURAL RESOURCES ALASKA, INC. March 31, 2003 Mr. Randy Ruedrich, Commissioner Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501-33539 HAND DELIVERED Subject: I vik #1 Permit No. 202-225 API No. 50-703-20436 Form 10-403 Application for Sundry Approvals Harrison Bay, North Slope, Alaska /" Dear Mr. Ruedrich, Attached are duplicate original copies of form 10-403 Application for Sundry Approvals relative to the abandonment of the Ivik #1 Well and associated drawings and documentation. We continue to evaluate well's potential. At the present time the Ivik # 1 is shut-in for pressure buildup ancl,wî11\ be flowed again on a production test. We intend to commence plugging operations on or after v,J.) ~pn..l?i2003. ~.~ Sliõuld you have questions on the matter please call Skip Coyner at (907) 743 -0921. Please call me as soon as the form is approved and I will come over to pick it up. / Thank you. Best regards, ?:(9..ú';Z? J. Patrick Foley RECEi\lE[ MAR ~:j .' Cc: Ken Sheffield - Pioneer Natural Resources Alaska, Inc. Rusty Cooper - Pioneer Natural Resources Alaska, Inc :i.i-""'OI&~-- r '00'\&.: :' ~""'V" v.'," ".....,. \JIØ:v '\to.,''t;¡.,;t,,·.:''¡;~þ~~~,\:,.,I\.~;' AOC~~;;ê~ 310 "K" STREET, SUITE 200, ANCHORAGE, ALASKA 99501 . . FAX (907) 264-6743 ) ) kit ~>J {Jj'-i/3J STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION / APPLICATION FOR SUNDRY APPROVALS 3. Address Development _ Exploratory _X Stratigraphic _ Service Re-enter suspended well _ Other Time extension Stimulate Variance Perforate 6. Datum elevation (DF or KB feet) RKB = 51 feet 7. Unit or Property name 1. Type of request: Abandon _X Suspend_ Alter casing _ Repair well _ Change approved program _ Operational shutdown _ Plugging _ Pull tubing _ 5. Type of Well: 2. Name of Operator Pioneer Natural Resources Alaska 310 "K" Street, Suite 200 Anchorage, AK 99501 4. Location of well at surface 1450' FSL & 500' FWL of Sec 6 T13N R8E UM At top of productive interval 1350' FSL & 537' FWL of Sec 6 T13N R8E UM At effective depth Exploration 8. Well number ./ 1 9. Permit number / approval number ~ 202-225 /' 10. API number 50-703-20436 / 11. Field / Pool Exploration J:~\ \c... ti-..1... tt?rJ At total depth 1345' FSL & 538' FWL of See 6 T13N R8E UM 12. Present well condition summary / After testing, the tubing will be displaced by bullheading to the perforations with 10 ppg kill weight mud. A CIBP will be set at:!:. 6375' and 25 ft of cement will be dumped on the CIBP. The CIBP will be tested to 2000 psi. ~ Casing Length Size Cemented Measured Depth True vertical Depth Conductor 140' 13-3/8" Drive Pipe 172.5' 172.5' Surface Casing 2963' 7-5/8" 451 sx ArctiSet Lite, 130 sx G 2,993 2,993 Production Liner 1475' 5-1/2" lead: 85 sx G + 8% Gel 4310' 4310' (Tal ZXP @ 2835') 2633' 3-1 /2" Tail: 463 sx G - expanding cmt 6943' 6943' /. Perforation depth: measured 6410' - 6478' true vertical 6410' - 6478' Tubing (size, grade, and measured depth 3.5",9.2#, L-80, IBT @ 4307' Packers & SSSV (type & measured depth) CSR: 4290' - 4310', Halliburton "Wellstar" SSSV at 72' RKB ~ :~':~ ,?, 13. Attachments Description summary of proposal _X Detailed operations program _ BOP sketch Refer to attached morning drilling report for LOT test, surface cement details and casing detail sheets, schematic _ 14. Estimated date for commencing operation 15. Status of well classification as: April 5, 2003 16. If proposal was verbally approved Oil Gas Suspended _ Name of approver Date approved Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed <79....-7~,.. "'H,.... Title: President Ke~. Sheffield. Jr. "/ r I' j ",) FOR COMMISSION USE ONLY Conditions of approval: Notify Com~sion so representative may witness Plug integrity -l\ BOP Test _ location clearance _, ~ <:..::. . \. Mechanical Integrity Test _ . . ~equent form required 10- 4<0 \ ,,~~"'"\~~~,~c~,\,,((:.~~ ",\~~\~~cJ \>\~~ &~'-\f'''' Approved by order of the Commission ;J. - -7 ~ Commissioner APR 4 axO i G-NA~_ Questions: call Skip Coyner at 748-3689 Date y{~~ Approval no. .:< f""'} . ~ _ -X f-:J' / J L/' Date r:J r / :ý¿J;J Form 10-403 Rev 06/15/88 · RBOM~ RFI SUBMIT IN TRIPLICATE ) ) -:) 0 N ::::::~ NA TU PAL RB30U RCES Plugging Program Well Name: Days: AFE NO.: Ivi k #1 3-5 003592 Classification: API No.: AOGCC Permit: Exploration 50-703-20436 202-225 Estimated Start: April 5, 2003 Prepared By: S. Coyner HSE OBJECTIVES FOR WELL: 1. No Lost time Accidents. 2. No Spills. 3. No environmental damage Surface Location: North 6,034,820' East 476,790' 1450 ft FSL & 500 ft FWL of Section 6, T13N, R8E UM I AFE Number: I 003592 I I Estimated Start Date: 14/05/2003 I ./ I Testing Company: I NTS I Estimated Test days: \3 -5 ) ) Telephone Contacts: Anchorage Pgr No.: Name: Position: Home No.: Office No.: Cell No.: Home No.: Skip Coyner Drilling Supt. 622-0030 339-6269 748-3689 622-0030 Rusty Cooper Oper Mgr. 276-6000 264-6752 519-1214 * 208-3809* Pioneer NRA Office 264-6750 Kuparuk Security 659-7300 Kuparuk CPF-3 659-7401 Kuparuk Medical 659-7230 AOGCC North Slope 659-3607 (pgr) AOGCC Tom Maunder 279-1433 Casing & Tubing Program: (see attached well bore diagrams) Size & Type Top Bottom Length Hole Size Drift 13-3/8", 68#, J-55, PElS GL 172' 140' nla 12.259" 7-5/8",29.7#, L-80, STC-Mod Surf 2996' 2966' 9.875" 6.750" 5-1/2",17#, L-80, Hydril 511 2835' 4290' 1455' 6.750" 4.767" 3-1/2",9.2#, L-80, 1ST-Mod 4310' 6900' 2590' 6.750" 2.867" 3-1/2",9.2#, L-80, 1ST-Mod Surf 4297' 4267' nla 2.867" PLUG AND ABANDONMENT Notify AOGCC 24 Hrs before starting the plugging operation. 1. After testing is completed, RID NTS test equipment. R/U Slick Line. Pull the SHP bombs at 4300'. Set at 1500 psi "RP" shear valve in the GLM at 92'. RID SLU. Displace the tubing by bullheading ± 80 bbl of 10 ppg mud into the tubing and perforations. ../ 2. R/U E-Line. Set an EZSV at ± 6375'. Dump 25' of cement on the EZSV.-vf'est to 2000 psi. 3. R/U SLU, a squeeze manifold and a "tiger tank" as required. RIH with slick line and open the sliding sleeve. Establish circulation down the tubing taking returns from the IA into the tiger tank. RIH and set a Halliburton "Pump Thru Valve" (check valve) in the sliding sleeve upper profile (2.81" "X"). RD SLU. 4. Mix and pump a 125 bbl cement plug from 3113' to surface: · 1 0 bbl fresh water spacer · 80 bbl of ArcticSet cement · 25 bbl (120 sx) class "G" neat cement · 20 bbl of ArcticSet cement 5. You should have cement to surface at this point, if not, mix and pump ArcticSet cement until cement returns are seen. Displace with water to the tree (to clear the lines). Pressure up on the IA to open the RP shear valve (± 1500 psi). Reverse circulate the well with clean, hot water through the "RP" shear valve. WOC. Keep Dowell tied on to the well. Dispose of excess fluids properly. ) ) 6. RU E-Line with a crane. Use a riser and packoff as needed. Tag-test the cement plug. Pressure-test the cement plug to 1000 psi using a chart recorder. Circulate with hot (130° F) water through the GLM if needed: the chemical cutter needs ~ 70° F to function. Chemically cut the 3-1/2" tubing between the GLM and the SSSV (cut at ± 85' RKB). RO E- Line. Flow check for 1 hour. 7. NO the tree and return it to Vetco. Displace the hole with hot (130° F) water again. Using a pup joint and single joint elevators, pull the tubing hanger, tubing (± 40 ft) and SSSV with the crane (~ 1000 Ibs). Pull the casing hanger packoff. Send the tubing, hanger, pups, SSSV, etc to Deadhorse to be dis-assembled. You must complete step #8 before the well cools off below 70° F. 8. P/U the 7-5/8" Hanger running tool and X-O to 3-1/2" IF. N/U the E-Line packoff using the crane, single-joint elevator and chain tong. RU E-Line and crane. Chemically cut the 7-5/8" casing 10' to 20' below the mud line but above the port collar. RO E-Line. Use the crane to pull the 7-5/8" casing hanger and cut off joint (± 30 ft) (1000 Ibs). 9. NO the multi-bowl wellhead leaving only the 13-3/8" drive pipe. Chain off the cellar box. 10. Pick up a mechanical casing cutter, pup joint and power swivel with the crane. RU to circulate while sucking returns from the cellar. Anchor the power swivel torque arm to the crane or other fixed object. Cut the 13-3/8" drive pipe ± 5 ft below the mud line. Circulate hot seawater while cutting the casing. LO all tools. 11. Pull the 13-3/8" stub with the crane. Spot 10 sx of ArcticLite cement over the casing stubs. 12. Clean out the cellar and properly dispose of the waste. 13. Retrieve the cellar and close the hole with clean ice chips, etc. Prepared by: ---------------------- Skip Coyner NTS/Pioneer Attachments: . Wellbore diagrams 3-1/2" Liner Tail Perforations: 6410' - 6478' 2.81" "X" nipple at 4275' 5" x 4" CSR X-Q's 5-1/2", 17#, L-80, 511 Liner Baker 3-1/2" Sliding Sleeve at 3113' 7-5/8",29.7#, L-80, BTC-M Baker HMC & ZXP Ivik #1 Completion SSSV at 77' GLM at 92' ) I'·' . :>i , · I i, I : . I I I, I,,·' '.. I I;; ., I I I r I" r I. . I ' I' '" , I I 2835' I I I ., Î' ::,; 2993' fM.;":,:: f I:: I I I 4310' I 6950 ' ) PION EER NA TU RAL RESOU RCES ) I :1 PIONEER I:·' "1 1\· ".1 N ,A. TU RAL R830 U RCES 1 I 1 · ····..1 1 ,,'i.1 I: :"1 r:"'1 I" ',::1 1,/.' .... >1 I:: :,,1 1'.1 I ' ',I I .1 1 .,1 I '·1 1,:1 I J , 1 2835' ! '~ i4] 1<1 2993' ~.,:I..~ 1'1 I:i I '..., ~þ~: II . '····1 I "",' '..1 I . . I 1 I I' .:~I I I 4310' ¡,~~:¡ r: "..: -:·:::';·::::1 I }:?:\ì ::":-:'" :':":'}(?: I:·:,·::...:·.:.J I:·..: .:.:.,.:J I·. ,': .: .'._ I: .::.:: :._..1 I·: .. ". ::·1 t· _ ··:·:...:·~···:-:t r ::~~·:t;¡ I. 0) .::'. .~\... '. .'.:.:'~ ::..::..... ····.1 I:::·?::i·.:::.:;:~ 1.-·· ':'.::.:'.. ... . :::\::::0:1 1:>'::.:::.<:.:1 I·:······.·: ::·..i:::·:.... 6950' II·:.:,·::~.··...··,···~::::::-·:i ~':~'i ') SSSV at 77' GLM at 92' I vik #1 Completion Baker HMC & ZXP 7-5/8", 29.7#, L-80, BTC-M Baker 3-1/2" Sliding Sleeve at 3113' 5-1/2", 17#, L-80, 511 Liner 2.81" "X" nipple at 4275' 5" x 4" CSR X-Q's CIBP @ 6375' + 25' cement Perforations: 6410' - 6478' 3-1/2" Liner Tail PION EER NATURAL RESOURCES ) 2835 ' I I r:. I : I I I I 1 I .' .'..: ':~:,~ 'h' \" ...." ~,"""", 1 ,::::.: I' '. ::;::).:"::~. I: .{\·r:,:~; I'....::;: ".""A"· I "',":',:::'.'.::.:': ""....':'..',;.,:. I "':."::::.~'.~;': I , ~\\~ ~,:-:<,:::;~ ~ I ;:);::.,':::'. 1 '~..' ,0:'::..:: I;:~:::::::>;:: [< ~~ II:::: f;' I I, I I I I I . I 2993' 4250' I I ....J r·: , . ..] I . I I .... . .. 6950' :.....jj. ..~.: ) Ivik #1 Cement plug: 3100' to 80' MD SSSV at 77' GLM at 92' 7-5/8",29.7#, L-80, BTC-M 3-1/2" Sliding Sleeve at 3113' · Open the Sliding Sleeve · Set a check valve in the "X" profile · Displace the tbg & csg with ArcticSet I · Pressure up the IA to open the "RP" shear valve in the GLM at ± 90' · Circulate the csg & tbg clean using the GLM Perforations: 6410' - 6478' 3-1/2" Liner Tail PIONEER NA TU RAL RESOU RCES 2835' 1 1 I. ì 2993' 1111I::: 1 I I. I I I I I. I I 4250' : I:' I.: .. r·,.·.~::·:' r:.,:/~:: , I:.:·.·::::: I':: :>:: I:' I I I I I I I, I I I' 6950' ) Chemically Cut 3-1/2" & 7-5/8" ." . .........".. '. . I I ,'.. I '. I 1 .. ".·,1 '1 , I I .1 .,....,..,... ,,:...,....:.~.::...c.":'.:::,.,:" 1 ::..;.....:~:,: :' '.":",':":'.~':' ....:.:.>..:.:':' I ,.,,-......,,. :,,-.:"::':.: . ." 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I I"·' .',.' ...., I' ..jj¡j.......,:. ..J ,.'1 ..:.:~:I .:......:: ) I vik #1 Cut off tubing & casing · RID E-Line & tag the cement plug · Chemically cut the tubing below the SSSV · N/D the tree & pull 1 jt of tubing & SSSV · Chemically cut the casing below the mud line · Pull the casing stub 7-5/8",29.7#, L-80, BTC-M 3-1/2" Sliding Sleeve at 3113' 2.81" "X" nipple at 4275' Perforations: 6410' - 6478' 3-1/2" Liner Tail PION EER N,A, TURA.L RESOU RCES Hot Water in ) -) Ivik #1 Cut off Drive Pipe , · Mobilize a 40-Tone Crane. · Bring out Power Swivel & Casing Cutter already made up. · Lower the BHA into the casing & chain the casing to the swivel. · Pull 500# over & lock the crane. · Tie the stiff arm to the crane base. · Circulate hot seawater. · Suck up returns w/ vacuum trucks/super sucker. , Vac Truck Super Sucker 6 ft 72" Cellar '-----" ~;¡;¡;¡"""'"''''''''''''''''''''''''''''''''''''''''''''''''''''''·..·..·..·..·..·.....·..·..·..·..·..·..·······s¡â~···~il·..·..·..····..·.................. ~;¡;¡_................................................................................................................jl~I:'~..~~............................, !,IIII~IIIIIIII;III¡IIII!!¡~~!!!!I:!!:! .~,~~-,----;~ 5 3/4" C tter .----~--.---.-..-.--..,--.---------------...--..,.~.-----.---.---.-.-.-.- 1~~!¡l!~~~~~¡~~~~~~~~~~~~~~i~~~I~!¡!I!!!I¡!¡!I!!!!!!!!II¡~!!!!!!¡!!!!I!II!!~!~!I~!¡~:~ ------------------------------------------------------------- ------------------------,------------------------------------- --------------------------------------'-----------'.--'--------- -~-----~----------~------.--------,---,-------,---------~--------- -----------,-------------------------,--------------_.---------- ---------- ------------------------ -----.---. ------------------------- ¡~¡ii~¡~¡~¡~¡~¡~~:-:-~ ;~:~~~::~-~~::-:~~~~:_lî¡¡î¡¡î¡¡~iI!¡~¡¡¡!¡¡!¡¡¡~¡¡¡~¡¡¡~ : ~:-: -:-:-:~:-:-: -:-:-:~:-:-:- :-: - :~: -:~ :-:-:~ :-:~:~: - :~: _:¥O:~ :-: -:...: -:-: ~:~: - :-: ~:~::7:~:- :-: -: -:-: ~ ~:~ :-: - :~:-:-: - :-:- ::: ::::=:=:::::=::: -:::.::::: :=:: ::~ =:=:::=:::::=: =:=:=: =:=: =:=:=:= :-:::.::: :=:::-:::.: :=: ~ =:: :=: ::=:= ::~:=:: ::::::::::::::::::: = :=:::= :~;:.::::::::: ::: ::=:: :=: =: :: ::=:: :=:=:: :::=:: :=:::=: ::= -;:=::: =:=:: :-:::':: =:=: =:=::::: :::: =::: ::=::::::: =:::::: :::::::: - ... 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'.. -------------,------,---~------'--------_.,-- .. .. ... - .. .. .. - .. ... .. ... - - .. -- - .. .. ... - ... ... - ... - ... ... .. .. ... ... ... ... ... - ... - - ... .. ----_..._------....'--,-,---,-----,-----,----------,~ .. - ... ... .. .. '.. - .. .. .. - - '.. - ... - -' '- ....'- .. - ... .. .. '- ..... .. .;. ..'... .. ... - ..... '.. -'... ----'----------'-~----'------,--'---'----'-----'-- ... .., .. - .. ... .., - ... ...' .. - - .. - ... .. .. - ... ... - - -, ... -- .. ... - - - ... .. - .. - ... ... .. - ... ------------------------.----,----------.--- _.... .. - .. ... '- - .. ... .... - '.. .. '"- '- .. -'.. - ... ..'... .. ..... .. .. .. .. - ... .. .. ... - .. .. .. .. .. -----------------------.-------------,---- .. ... .. ... - - - -, - .. .. - .. ... - ... ... - ... ....... - '," -, -, - - .... .. .. ...' - .. ... - ... .. .. ..' -- - _.._.._-------_..._--------,-----------_...'--~,'-- ) ) PIONEER NATURAL RESOURces Weekly Operations Report I vik # 1 Permit No.: 202-225 February 28, 2003 · 13-3/8",68#, L-80 PIE conductor was driven by VECO to 140' below pad level = 172' DF. · 2/19/03: Vetco NU multi-bowl wellhead and diverter spool (pre-rig) · MI & RU Nabors 27E on Ivik #1. NU BOPE, diverter valve and diverter line. · 2/23/03: function tested diverter system: witnessed by Chuck Sheve wi AOGCC. · PIU drill pipe & BRA. · Spud Ivik #1 at 09:15 on 2/25103. · Drilled 9-7/8" hole to 3020' MD/TVD taking MWD surveys every 300 ft. Drift direction was SSE and maximum angle was 1.5°. The wellbore is > 500' FWL. · Conditioned the hole and set 7-5/8", 29.7#, L-80 BTC-Mod at 2998' MD/TVD. · 2127/03: Dowell cemented with 451 sx (351 bbl) of ArcticSet Lite followed by 142 sx (30 bbl) of class "G" + CaCho Displaced with drilling mud. Bumped the plug. Floats held. Circulated ± 75 bbl of cement to surface. · LID landingjoint. Set and tested Vetco casing packoff. · Opened Tam port collar at 72' MD/TVD. Circulated the 13-3/8" x 7-518" annulus clean and freeze protected same with CaCh brine. Note: 100' of cemented overlap. · NID Diverter line and NU blind flange on diverter spool. · 2/28/03: testing BOPE to 3500 psi as per the pennit: witnessed by John Christman. The plan forward is to drill out, run our LOT and drill ahead to the Kuparuk "c" core point at ± 6250' MD/TVD. We will cut a 60 ft core and then TD the well at ± 6950' MD/TVD. ACS is on or near location 24/7 observing and advising both the drilling operation and the on- going ice construction operation. We had one Yz bbl mud spill in containment that basically splashed over the top of the shaker pit. ACS was called and assisted with the clean up. No accidents or injuries. Skip Coyner NTS/Pioneer ) " Weekly Operations Report I vik # 1 Permit No.: 202-225 N ATU RÞ<.l REBO U R<:;:Ë8 March 7, 2003 · 7-5/8" surface casing set at 2996' MD/TVD. · Casing and BOPE tested to 3500 psi. Witnessed by John Christman. · Drilled out and perfonned LOT at 3020' MD/TVD. Broke at 16.4 ppg EMW. Pumped into fonnation at 12.4 ppg EMW. · Drilled 6-3/4" hole to 6100' MD/TVD. · Cored 6100' - 6144' MD/TVD. · Drilled to TD of 6950' MD/TVD. · Conditioned the hole. · RIU Schlumberger. Ran open hole logs. Current operation: running open hole logs: MDT. The plan forward is to finish logging, Test BOP's and RIH. We plan to condition the hole, run and cement the tapered liner per program followed by the completion tubing. No accidents or injuries. Skip Coyner NTS/Pioneer ) ) Weekly Operations Report I vik # 1 Permit No.: 202-225 N A TU PAL REBO IJ F<CËS March 21, 2003 · RD and MORT · RU test equipment. Tested lines. · RU Schlumberger E- Line and ran SCMT in the liner: good cement across the pay zone. · RU Schlumberger CTU. Ran memory correlation log. · Perforated the Nuiqsit sand with 2-1/2" TCP guns on coil: o 6410' - 6422' o 6436' - 6462' o 6468' - 6470' o 6474' - 6478' · No flow. Broke down perforations with 30 bbl of diesel. · Jetted the tubing down to the perforations with nitrogen. RID CTU. · No flow. SI WIO Frac job. No accidents or injuries. Skip Coyner NTS/Pioneer ) ) Weekly Operations Report I vik # 1 Permit No.: 202-225 April 4, 2003 · Flow tested the well through perforations in the Jurassic: 6410' - 78'. · Shut in 2 days for tank room: hauled oil to CPF-3. · Flowed well for official 48-hour test: hauled oil to CPF-3. · Shut in for 96-hour buildup which ends on 4/6/03. · RID NTS test unit and tank farm. No accidents or injuries. Skip Coyner NTS/Pioneer ) ) PIONEER NATUR.Ál RESOURCES Weekly Operations Report Ivik #1 ........o,_._._-_~ pemùtNO.:~ April 11, 2003 · Left well shut in for 96-hr BHP buildup test. · R/U slick line. Retrieved BHP bombs. Installed "RP" shear valve in the GLM at 92' RKB. · R/U E-Line. Set EZSV in 3-1/2" Liner at 6375' (35' above the perfs). · Tested EZSV to 2000 psi for 30 minutes: ok. · E- Line dumped 25' of cement on the EZSV: two runs. · R/U Slick line. Opened the sliding sleeve at 3113'. Set a check valve in the upper profile of the sliding sleeve. Pumped through the check valve: OK. Tested the check valve from below to 500 psi: OK. RID Slick line. · R/U Dowell. Mixed and plumped abandonment plug from the sliding sleeve to surface: · 10 bbl fresh water · 90 bbl of ArcticSet Cement mixed at 15.7 ppg · 20 bbl of class "G" cement mixed at 15.8 ppg · 25 bbl of ArcticSet cement mixed at 15.7 ppg · 2 bbl fresh water to clear the lines. o Witnessed by L. Grimaldi. Caught sample of cement returns at 15.5 ppg. · Pressured up on the IA and sheared the "RP" valve. Circulated the IA and tubing clean through the GLM at 92' RKB. RiD Dowell. · R/U E-Line. Tagged cement at 94' RKB. Tested to 1000 psi: OK. Cut the tubing at 85' RKB. N/D the tree. Pulled the tubing with a crane: OK. Attempted to cut the 7-5/8" casing twice with chemical cutters: Negative. RID E-Line. · PIU mechanical cutter and power swivel with a crane. Cut the 7-5/8" casing at 77' RKB. Pulled the casing with the crane: OK. N/D wellhead. · Cut the 13-3/8" casing with a mechanical cutter and power swivel at 72' RKB (15' below the mud line): OK. Pulled the 13-3/8" stub. · Pulled the cellar and backfilled with clean ice chips. · Scraped location and hauled off the dirty ice. · Final Report. No accidents or injuries. Skip Coyner NTS/Pioneer ) ~1~u~ (ill~ fÆ~~~[K\~ ) AI/A~KA OIL AND GAS CONSERVAnONCO~SSION Kenneth H. Sheffield, Jr. President Pioneer Natural Resources Alaska, Inc. 3900 "C" Street Ste 702 Anchorage Alaska 99518 ! / / / TONY KNOWLES, GOVERNOR 333 W. "fTH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Ivik #1 Pioneer Natural Resources Alaska, Inc. Permit No: 202-225 Surface Location: 1450' FSL & 500' FWL, Sec. 6, T13N, R8E, UM Bottomhole Location: 1450' FSL & 500' FWL, Sec. 6, T13N, R8E, UM Dear Mr. Sheffield: Enclosed is the approved application for permit to redrill the above referenced exploration well. This permit to redrill does not exempt you from obtaining additional permits or approvals 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. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the Commission's internal use. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. 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. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, ~ð"-~ Michael L. Bill Commissioner BY ORDER OF THE COMMISSION DATED this 3~day of December, 2002 cc: Department ofFish & Game, Habitat Section wlo encl. Department of Environmental Conservation wlo encl. !IJ6'A- l t/ z.!Ol- ) ) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of work: Drill 0 Redrill 0 Re-entry DDeepen D 2. Name of Operator Pioneer Natural Resources Alaska Inc. Development Oil D Multiple Zone D 10. Field and Pool 3. Address 3900 "C" Street, Ste 702, Anchorage, AK99518 4. Location of well at surface 1450' FSL & 500' FWL of Sec 6.T13N R8E UM At top of productive interval same At total depth same 12. Distance to nearest property line 500 feet 16. To be completed for deviated wells Kickoff depth: MD 18. Casing program size Hole Casing Weight 13-3/8" 72 9-718" 7-5/8" 29.7 6-3/4" 5-1/2" 17 3-1/2" 9.2 1b. Type of well. Exploratory 0 Stratigraphic Test D Service 0 Development Gas D Single Zone D 5. Datum elevation (DF or KB) 10.5' + 32.5' = 43 feet 6. Property Designation 389950 / 7. Unit or property Name 11. Type Bond (see 20 MC 25.0251) Ivik '/ Statewide 8. Well number Number 1 103655283 9. Approximate spud date/, Amount February 1,2003 $200,000 14. Number of acres in property 15. Proposed depth (MD and TVD) 2533 7500 ' MD / 7500 ' TVD 17. Anticipated pressure (see 20 MC 25.035 (e)(2)) Maximum surface 2850 psig At total depth (TVD) 3600 psig Setting Depth Exploration North 6,034,820' East 476,790' ~ 13. Distance to nearest well /' Arco, #1 Kalubik, > 10400 feet Maximum hole angle Specifications Grade Coupling L-80 PE~ L-80 BTC-Mod K-55 FJ L-80 BTC-Mod Top Bottom Quantity of Cement Length MD TVD MD TVD (include stage data) 80 32 32 112 112 Drive Pipe 3000 0 0 3000 3000 311 sx Permafrost L & 223 sx G /' 1400 2850 2850 4250 4250 294 sx of Premium-Microlite & 1 3250 4250 4250 7500 7500 351 sx Premium-Latex cement Total Depth: 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Plugs (measured) 20. Attachments Filing fee 0 Property Plat 0 BOP Sketch 0 Diverter Sketch 0 Drilling program 0 Drilling fluid program 0Time vs depth plot ßefraction analysis 0Seabed report 020 AAC 25.050 requirements 0 21. I hereby certify that the foreg , g is true and correct to the best of my knowledge For questions call Skip Coyner 339·6269 S & S;gned )(J!/.. .~.. _~/¡¡;: Title: President Date N # V 2-21 ;2tJO'2.,- Kenneth H. effie/d, Jr. Commission Use Only ~ Permit Number .. _ . --- I API numb~ "'/_ 'J /"1./ /;7/_" I Approval date I. 91· , -? M 0 See cover letter ;2(~)2-?7 ~ 50-7¿~") L..,L.,. 7"':;l~ (·b I'~ ~ U~ for other requirements Conditions of approval Samples required ~ Yes D No Mud log required ~ Yes U No Hydrogen sulfide measures D Yes ~ No Directional survey required ~ Yes D No Required working pressure for BOPE D2M; D 3M; D 5M; D 10M; D D Other: Tee",'+- !3.:J P E ~ '~ç 0 L? P ~ (.t ~ ORIGINAL SIGNED BY t.1 L. Dill Effective Depth: Casing Conductor Surface Production Length Perforation depth: Approved by Form 10-401 Rev. 12/1/85· measured true vertical feet feet measured true vertical feet feet Junk (measured) Size Cemented Measured depth True Vertical depth measured RECE1VED NOV 222002 mø on & Gas Cons. commission - Anchorage true vertical by order of Dare lR! % ,./ Commissioner the commission \ , '\ i \\ L \ I ~, Submit in triplicate ) ) Pioneer Natural Resources Alaska Inc Exploratory Drilling Program Well Name: Ivik #1 Classification: Exploration Rig Days: 15 ADL: 389950 Drill and Complete (Test & Abandon off Rig) / Estimated Spud: February 1, 2003 Prepared By: S. Coyner EXPLORA TION OBJECTIVES FOR WELL: 1. Drill the well through the Kuparuk "C" as directed. ~ 2. Run the completion as directed. MORT. 3. Peñorate and test the well. 4. After testing, plug back as required using E-Line, etc. 5. Properly plug and abandon - without the rig. " HSE OBJECTIVES FOR WELL: 1. No Lost time Accidents. 2. No Spills. 3. No environmental damage Ivik #1 Drilling Program Page 1 ) Well Name: .\) Ivik #1 Drill and Completion Plan Summary I Type of Well: Vertical 1 Drill, Case, Complete, Test and Abandon 14 Surface Location: North 6,034,820' East 476,790' 1450 ft FSL & 500 ft FWL of Section 6, T13N, R8E UM I AFE Number: I I Estimated Spud Date: 12/01/2003 / I Drilling Rig: I Nabors 27E /~ I I Estimated Rig days: 115 1 I Pad Elev: 110.5' I I RKB: 143.0' I I MD: \7,500' I I TVD: 17,500' \ I Proposed Well Design: I Slim Hole to minimize drilling waste -I -I I Objectives: Kuparuk Formation and Middle Brookian Formation -/,. Mud Proaram: (attached) Bit Proaram: Interval Size Type Footage Hours ROP RPM WOB Surf - 3,000' 9-7/8" 1-1-5 3000' 24 125 200/300 1 0-30 3000' - 7500' 6-3/4 PDC 4500' 36 125 200/300 5-15 Surveys & LWD: Directional Program: While Drilling: At Surface Casing Point: At TD: 9-7/8" Hole: MWD Surveys every 300' / 300' to 3000' MD 6-3/4" Hole: MWD Surveys every 300' - 3000' to 7500' MD (additional surveys to maintain the wellbore ~ 500 ft FWL) __ Drop a Magnetic Multi-Shot Survey Before POOH Drop a Magnetic Multi-Shot Survey Before POOH Ivik #1 Drilling Program Page 2 LOQQinQ ProQram: Suñace Hole: LWD: Open Hole: E-Line: LWD: Open Hole: E-Line (OH): Production Hole: E-Line (CH): ) MWD 1 GR 1 RES Mud Logging & Gas Detection Cased Hole GR MWD 1 GR 1 RES Mud Logging & Gas Detection G R/CN L/FDC/Sonic/Caliper MDT's, SWC's SCMT in the Liner (bond & correlation) Formation Markers: Formation Tops MD TVD Sagavanirtok 950' 950' Possible gas hydrates: 1100' to 1600' ¿:-- Ugnu 2400' 2400' Colville 2750' 2750' Middle Brookian 4250' 4250' Hydrocarbon Bearing, 9.0 ppg EMW Torok 5350' 5350' Hydrocarbon Bearing, 8.6 ppg EMW T/HRZ 5950' 5950' Kalubik 6120' 6120' T/Kuparuk 6200' 6200' Hydrocarbon Bearing, 9.6 ppg EMW Kuparuk "C" 6300' 6300' Hydrocarbon Bearing, 9.8 ppg EMW T/Miluveach 6400' 6400' Alpine Sand 6500' 6500' Hydrocarbon Bearing, 9.8 ppg EMW Jurassic Sands 6650' 6650' Hydrocarbon Bearing, 9.6 ppg EMW PTD 7500' 7500' Casing/Tubing Program: (see schematics) Hole Csg/Lnrl WtlFt Gr;de Conn Length Top Btm Size Tbg OD's ¡ MD/TVD MD/TVD Driven 13-3/8" 72.0# L-80 PE 80' 35' 115' 9-7/8" 7-5/8" 29.7# L-80 BTC-M 3000' 0' 3000' 6-3/4" 5-1/2" 17# K-55 511 1400' 2850' 4250' 3-1/2" 9.2# L-80 BTC-M 3250' 4250' 7500' Tubing 3-1/2" 9.2# L-80 BTC-M 4250' GL 4250' Ivik #1 Drilling Program Page 3 Integrity Testing: Test Point: Depth: .±. 3020' Test Type: Expected EMW ~ 13.4 ppg Surface Casing Shoe (20' below the shoe) LOT (based on offset data) 1. After NU & testing BOPE, RIH. Test the 7-5/8" casing to 3500 pSi~ Record the volume of mud required to pressure up to 500 psi, 1500 psi, 2500 psi and 3500 psi. 2. Drill out the shoe track. Drill 20 ft of new hole and circulate the hole clean with consistent mud weight in/out. Pull up into the casing shoe. 3. Perform a Leak Off Test: · Shut the well in. RU cement pump. · Record the fluid volume in the cement unit's tanks. / · The estimated Leak Off surface pressure with 9.5 ppg mud is = 608 psi. · As a guide, use the data from the casing test to determine the approximate volume of mud required to reach 608 psi on the LOT. · Bring the pump on line at 0.1 - 0.2 bpm & keep the rate constant. · Record the pressure for every tenth of a bbl pumped. · Continue pumping until the pressure breaks over plus 1 bbl. · Plot the data to determine the Leak off pressure at the shoe as EMW. · Repeat the test if needed. ) ) Cementina Proaram: (attached) Well Control: /,f Surface hole will be drilled with a diverter. The production hole will be drilled with well control equipment consisting of 5000 psi working pressure pipe rams(2), blind/shear rams, and annular preventer capable of handling maximum potential surface pressures. · Maximum anticipated BHP: 9.8 ppg EMW at 6300' = 3210 psi, Kuparuk "C" · Maximum surface pressure: 3210 psi - a full column of gas @ 0.10 psi/ft = 2585 psi · Planned BOP test pressure: /3500 psi (unless otherwise designated) Disposal: · Cuttings Handling: Cuttings generated from drilling operations will be ground on site using Nabors' ball mill. All drilling waste will be trucked to KRU disposal well 1 R-18 for underground injection subject to Ballot 260. · A cuttings bin fitted for use with Nabors rig #27E will be used as needed to catch and hold excess drilling waste until the ball mill and/or trucks can catch up. · In the event of an equipment failure, drilling waste will be trucked to Prudhoe Bay's G & I facility on 08-04 for disposal. H2S: H2S has not been seen/reported on any of the offset wells: Kalubik #1, Kalubik #2, // Kalubic #3, E. Harrison Bay #1 & Thetis Island #1. As a precaution, however, H2S monitors will be used at all times and 30-minute air packs will be available. Ivik #1 Drilling Program Page 4 DRILL AND COMPL~~ION PROCEDURE ) Pre-RiÇl Work: 1. The 13-3/8" non-insulated conductor will be driven to .± 115' RKB. 2. NU the multi-bowl casing head on the 13-3/8" conductor. 3. Spot and fill the reserve fuel tank with spill containment. 4. Spot and fill the reserve water tank with spill containment. 5. Stockpile mud and cement materials on/near location. 6. Stockpile casing and tubing on/near location. 7. Ensure communications are up and running. 8. Ensure the permits are in order. 9. Ensure all training requirements have been met. 10. Establish polar bear perimeter and watch. /' 11. Notify the AOGCC 24 hours prior to spud and BOP test. 12. Notify ACS prior to MIRT. DrillinÇl Hazzards: 1. The shallow hazard survey indicates the presents of no discernable hazards. In addition, none of the offset wells reported any hazardous conditions while drilling near surface. 2. Gas generated from drilling through "hydrates" is expected to be minimal. Again, offset / wells reported only minor volumes of gas while drilling the surface hole. The reduced hole size planned for this well with minimize the volume of gas generated while drilling. 3. Gumbo and other reactive formations constitute potential hazards from surface to TD. The planned use of inhibitive drilling fluid should minimize this problem, however, caution should }e used at all times because swabbing and packing off could occur at any depth. 4. No H2S is expected in this well, however, H2S monitors will be used at all times and the crews should be made ware of this potential hazard. 5. No abnormal pressure is expected based upon offset data. The maximum expected mud weight is 9.8 ppg, however, the crews should be alert to this potential hazard as well. BOP tests "kick drill" will be conducted in accordance with AOGCC regulations. 6. Lost circulation represents a potential hazard in this area. An adequate supply of LCM will be stockpiled on location for use if needed. The drilling fluid will be maintained to minimize ECD, surge and swab pressures. Lost circulation is considered to be a low potential hazard and little if any losses were reported on the offset wells. RiÇl Operations: 1. MIRU Drilling Rig, camp and ball mill with berms and herculite as required. 2. Take on water and mix spud mud. Make sure all solids control equipment is operating at capacity. Set the solids control van/skid (if used) and be sure it's operational. Set the cutting tank, etc. / 3. NU the BOP's on the wellhead with the diverter and diverter spool. RU the dJ>:erter lines (10" minimum) as per AOGCC regulations. Function test the diverter system. Use a test plug; test the rams, casing head and flanges to 2000 psi before the rig is accepted. 4. Clean out the 13-3/8" drive pipe. PU the 9-7/8" BHA with MWD/GR/RES and a performance (straight hole) motor. While drilling the surface hole, stop and circulate the Ivik #1 Drilling Program Page 5 hole clean at 1000' é.:) at 2000'. Try not to out drill the so) control equipment: control ./ drill if necessary. Record MWO surveys every 300 ft. Orill the surface hole to +1- 3000'. Drill the hole to fit the casing including 10-15' of rat hole. 5. At casing point, circulate the hole clean. Rotate the drill string at ~ 120 rpm to help clean the hole. Make a 20 stand wiper trip. Circulate bottoms up again. Orop a magnetic multi- shot and POOH. LD BHA. If t~ hole is "tight", pump out of the hole using the top drive. 6. NU and te~Sing rams. RU casing tools; Make up the "Combo Tool" on a stand of drill pipe and stand it back. Run and cement the 7-5/8",29.7# surface casing. A port collar will be run in the casing string one full joint below the mandrel hanger C±. 25' below the mud line). Use PDC drill-able float equipment and centralizers on every third joint to surface. Run a cement basket 1 joint below the port collar. Land the fluted hanger. 7. Circulate at least one full casing volume and adjust the rheology of the mud as needed. Pump a "marker pill" and record the pump strokes (bbls) shoe to surface. Calculate the annular volume and adjust the cement volume as required. Cement as per the attached program. Displace with drilling mud. Bump the plug with 1000 psi over final pump pressure. Record cement returns. 8. ND the cement head. RIH and open the port collar. Circulate the 13-3/8" x 7-518" annulus clean from the port collar to surface. Spot freeze protect fluid (brine & methanol) in the annulus. Close the port collar. LD the "combo tool" and landing joint. LD surface hole BHA components as necessary. 9. Orain and wash out the BOP stack. Set and test the 7-5/8" packoff. NO the diverter qnd diverter lines. NU the drilling riser. Test the BOPE to 250 psi and 3500 psi on chart. /' 10. MU 6-3/4" drilling assembly with MWD/GRlRES, and a performance motor with a 1° bend. RIH to the float collar. Test the 7-5/8" casing to 3500 psi. / 11. Orill out the shoe track and 20' of new formation. Oisplace the well with clean (low LGS 0/0) 9.5 ppg brine-based, drilling fluid (per attached program). ~II up into the shoe and perform a Leak Off Test. The expected LOT should be about 13.4 ppg based on offset data. a. Shut the well in. RU cement pump. b. Record the fluid volume in the cement unit's tanks. c. The estimated Leak Off surface pressure '!'lith 9.5 ppg mud is = 608 psi. d. As a guide, use the data from the casing test to determine the approximate volume of mud required to reach 608 psi on the LOT. e. Bring the pump on line at 0.1 - 0.2 bpm & keep the rate constant. f. Record the pressure for every tenth of a bbl pumped. g. Continue pumping until the pressure breaks over plus 1 bbl. /' h. Plot the data to determine the Leak off pressure at the shoe as EMW. i. Repeat the test if needed. /' 12. Orill the 6-3/4" hole to TO as directed using the performance motor and L WD tools. Adjust the mud weight as dictated by hole conditions. Survey every 300 ft as needed. Slide if needed to keep the wellbore at least 500 ft from. the west line. Stop and circulate bottoms up every 1000' rotating the drill pipe at ~ 100 rpm to aid hole cleaning. At T/HRZ, ensure the mud is conditioned to ± 10.0 ppg and short trip if needed. Test often for free potassium /' in the system which inhibits the reactive clays. Let the chloride content climb with additions of KCI: the salt increases the mud density without adding solids. 13. At TO, circulate and condition hole for logs, cores and RFT's. Make a 20-stand wiper trip and circulate bottoms up. Circulate and drop a magnetic multi-shot. POOH for logs. 14. RU E-Line, riser and packoff. Log the hole as directed: GRlCNUFDC/Sonic/Calip. RFT's and SWC's are expected. Run the SWC's last. Make a wiper trip between E-Line runs only if needed. RD E-Line. Load the liner in the pipe shed. Install turbolators, centralizers, etc. Ivik #1 Drilling Program Page 6 15. RIH with a bit and BH, ~eam any tight spots. Circulate bottL ) up at least twice/OOH. If the BOP's do not have the necessary ~R s, install and test 5-1/2" casing rams. 16. RU and run the 5-112" x 3-1/2" tapered liner, CSR, liner hanger, liner-top PKR and setting tools on drill pipe. The CSR is to be run ± 150' above the Middle Brookian test zone. Set the liner hanger ~ 150' above the 7-5/8" shoe. Circulate and set the liner hanger. Condition the mud prior to cementing the liner. 17. RU cementers. Mix and pump the liner cement job as programmed with the volume adjusted as per the caliper log. Displace with drilling mud. Bump the plug. Set the liner-top PKR and dis-engage from the liner. Circulate the hole clean. Test the liner top PKR beyond the 7-5/8" LOT using the pressure-volume data from the casing test as a guide. /' 18. Shut down the pumps and flow check the well for 30 minutes. LDDP and liner setting tools. RIH with a polish mill and 3-1/2", 9.2# L-80 BTC tubing on drill pipe from the derrick. Polish the CSR. Test the casing, liner top PKR and the liner to 3500 psi for 30 minutes on chart. Circulate the well clean. ~OOH. LDDP & BHA. Rack the tubing in the derrick. 19. RU and run the 3-1/2" completion tubing, CSR seal nipple, sliding sleeve, GLM (wI RP shear valve) and SSSV (see attached diagram). Tag the CSR and space out the tubing string. Displace the well with ± 100 bbl of "clean" KCI mud followed by a 10 bbl Hi-Vis spacer and ± 40 bbl of diesel. String into the CSR, land the hanger and RILDS. Test the IA to 3500 psi for 30 minutes on chart. Test the SSSV control lines to 5000 psi. 20. RU Slick Line unit. Drift the tubing and liner to PBTD as required. Pull the "lock out" sleeve from the SSSV. POOH and RD SLU. Close the SSSV. 21. Set a BPV in the tubing hanger. Wash out the BOP's and LD the I~mding joint. ND the BOP's. NU and test the upper tree assembly to 4000 psi with diesel!"Leave the tree freeze protected with diesel. Secure the well. 22. RD and MORT. / 23. Set the well house and prepare to test the well. Well Testina: 1. RU well test unit, storage ,tanks, SSSV control pump, flare stack, etc. Pull the BPV and open the SSSV. /' 2. RU E-Line with lubricator. Run a correlation log as follows: GRISCMT/CCL in)be lower (3- 1/2") portion of the liner. Perforate the test zone #1 as directed. RD E-Line. 3. Test the well as directed and in accordance with the applicable permits. Produced liquids are to be disposed of at KRU facilities subject to ballot 260. 4. After testing zone #1, spot kill weight mud across the perf~tions. RU E-Line. Set a CIBP / ~ 50 ft above the perforations. Test the CIBP to 1000 psi. Dump bail ~ 25 ft of cement on top of the CIBP. 5. Perforate the test zone #2 as directed. RD E-Line. 6. Test the well as directed and in accordance with the applicable permits. Produced liquids are to be disposed of at KRU facilities subject to ballot 260. 7. After testing zone #2, bullhead the tubing with kill weight mud~U E-Line. Set a CIBP ~ 50 ft above the zone #2 perforations. Test the CIBP to 1000 psi. Dump bail ~ 25 ft of cement on top of the CIBP. RD E-Line. Ivik #1 Drilling Program . Page 7 PLUG AND ABANDv~MENT ) 1. After testing and plugging back with E-Line, RU SLU, cementers and a "slop tank" as required and continue plugging the well. Open the sliding sleeve and establish circulation. Set a Halliburton "Pump Thru Valve" in the sliding ~ve profile. RD SLU. 2. RU a squeeze manifold. Mix and pump a 125 bbl cement plug: 3100' to MSL. Displace with water to the tree (clear the lines) and allow the plug to equalize. Pressure up on the IA to open the RP shear valve C±. 2500 psi) and then reverse circulate the well clean from that depth. Freeze protect. RD cementers. /' 3. RU E-Line with a crane. Use a riser and packoff as needed. Tag-test the cement plug. Pressure-test the plug as required. Circulate with hot water through the GLM. Chemically cut the 3-1/2" tubing between the GLM a~ the SSSV. RD E-Line. Flow check for 1 hour. 4. ND the tree and return it to the vendor. Using a short landing joint and elevators, pull the tubing hanger, tubing C±. 40 ft) and SSSV with the crane (~ 1000 Ibs). 5. NU a 7-5/8" pup joint and E-Line packoff. RD E-Line with a crane. Use a packoff. Chemically cut the 7-5/8" casing above the port cbllar. RD E-Line. Pull the casing hanger packoff. Use the crane to pull the 7-5/8" casing hanger and cut of!Joint C±. 30 ft) (1000 Ibs). 6. ND the multi-bowl wellhead leaving only the 13-3/8" drive pipe. / 7. Pick up a mechanical casing cutter, pup joint and power swivel with the crane. RU to circulate while sucking returns from the cellar. Anchor the power swivel torq~ arm to the crane or other fixed object. Cut the 13-3/8" drive pipe ± 5 ft below the mud. Circulate hot seawater while cutting the casing. LD all tools. 8. Pull the 13-3/~ub with the crane. Spot 5 sx of permafrost "L" cement over the casing stubs. RD. 9. Clean out the cellar and properly dispose of the waste. 1 O. Retrieve the cellar and close the hole with clean ice chips, etc. Prepared by: ~cftnr Senior Drilling Engineer Natchiq Technical Services Attachments: · Drill time graph · Wellbore diagrams · Offset mud weight graph · Offset LOT graph · Cement program · Drilling Fluid Program Ivik #1 Drilling Program Page 8 ') ) Ivi k #1 o 1000 2000 Set 7-5/8" Casing 3000 .t: ....., g. 4000 C 5000 6000 ,... 7000 \ Logs, RH's & SWC's 8000 o 5 10 Days 15 20 13-3/8" Drive Pipe 3000' I·',··'", .' .."~. I'··..··',· .'..'''. '.',;..~:':'''.' ...... .". "-..~ h·..·.' "'"".,,- ,"'.", r}'?; I·;::}: r):;::~; r:):; t·:::;:·:; ¡¡,I, ¡ ìr~:::~~ ~~!.m¡ """'"". t:,~~·:: t::?:/ I:.:-::::{; f'f~g f:{~; (}~ f~:{:i (}::{ Î:::'::S:; t~~m -:,:.:-::: ~', .,' '.~ ' 7500 ' ) ------ ') ,'";~I Pioneer Natur;~7;;~ees Alaska Ine ::<>:;:·::il Surface Casing & Production Hole ...., ,'. 'I ¡"¡;t~ :::\/1 :::\':J ;Y::}:I ~::{')I+- 9-7/8" Hole ::::-::',] ~?/) g}?:::1 ~:/:}I \:;/:,1 ::::\>:a /:.::::,:;a ~i,:~n~1 W::}il r~:Y:::1 "/::!:;:] ~::'/;::I ~::i~?} 7-5/8",29.7#, L-80, BTC-M ::-:::-::,:;1 Pi = 6,890 psi I: Pc = 4,790 psi Cement with 311 sx (230 bbl) of Permafrost "L" followed by 223 sx (46 bbl) of "G" + 2% CaC12, .--- 6-3/4" Hole ) 1;;~~¡t,···.'.:1 -: .~. ':'~.': :~<:, .: "",', n..:;;~ ~'...:,:,'..'.'...:.'.'...":.'.:.':, :::;::::::;:1 ~i'" ;:::::::\1 1::':\:,::; '~.}::j '.·è:'~l i;:':-:'I f-); ~{::::;:-] t:i':}i :'-:::;:::',':1 f::--::i §::;::::.. 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I·, . :~?\~. 4250' ~,¡, Ill] É:/t-:; ~}Y~n fvn n?~::Wi f?f}::; ~W:g:C:i f:·}::.:} F3WJ ü~:u~? :~:Xg~:~Î tmm~ ::::::~:)::::>d f{:-::\: :~::.'.~:':-:'::':.:'J f:::\>::: :~:~:~:???i f:~:::::::':::::: :):?:::.::J f:::~::::? :/'::::<~:j !.:.:.',.,:,:.:.;.:.:.:,:.:.:.:..:..:.:....:.. :.:, ~: >:::: i :::~: /. t :\/.;::':::j f::::::::(~ .:.:::.}};::. i:::~:::~~:-'?i:~: ":' '.,' '.: ": '." ë:??'::; H/.i§;: f:/:::'/::: ,::\:\;),:,) ('\):'::: {:~:>\)i f:-~':~::::::: ~:::::::\'::::::)i t<;:/::;:;:: ?:\.:::\.:::] t::/·::\ ::':':::':':"':'::'::,' 7500' :;IH~@im! ) Pioneer Natural Resources Alaska Inc I vik #1 Production Liner Cement the Liner with 294 sx (97 bbl) of Premium-Micro lite followed by 351 sx (73 bbl) of Premium-Latex LWL cement. Liner Hanger & Liner Top Packer 7-5/8",29.7#, L-80, BTC-M Pi = 6,890 psi Pc = 4,790 psi 5-1/2" x 4" CSR & 3-1/2" X-Q 5-1/2" x 3-1/2" Liner (top-down): · 7-5/8" x 5-1/2" Liner-Top Packer - 7-5/8" x 5-1/2" Liner Hanger -1400',5-1/2",17#, FJ Liner - 4.0" Bore CSR x 12 ft - X-Q to 3-1/2" BTC - 3250', 3-1/2", 9.2#, IBT-M Liner 3-1/2" Liner Tail ) I::::.·.·.:.~···.'·,· ;·:··:····:·::·',·:·,1 .\-.',' :...' :.,','-:', :::2:; '::'~'.,~:' ." . , . ., .. :: : :: ~ :: ~ ,". .": ~, ::: :::~:'; t<::/: I : -:/:.>:.:; I?::::~ ~::::\() 1::/'( :;'::',:,:::1 i.~:,~+: ~·~-(:I i::::>:::; ("":1 I:'::::'::': :,:::,:,:·1 (':X:i:: ::\?:':::::I t-:.'" ;':»:1 tx::::; :):;::'1 f:>,:~:: ;'::',}j f:</::; , . ·1 r?:::;:~ r_;.~i:./:I f:;:}i ;?:~;J t:;:: ~::::::':.j ¡::.::,:::::;:: :.;,..:_~.:.:.:.::.._'..:_...·:.:,..:.:.11 f;::):; (>}~ >:>.\1 t::i:::i ;::::::<-~:I t' :;:}):il 2850' I~rij ~ ~@,f; I·".,· ~ . ~:;:;H ;i.m¡ i,~;' '}! nil 3000' .:/tI ~m~il~ t· . '::~<\~I i;\¡:iJ., ~~;:i) fi~:: . 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') Pioneer Natural Resources Alaska Inc I vik #1 Completion Assembly: Test 1 Liner Hanger & Liner Top Packer 7-5/8",29.7#, L-80, BTC-M 3-1/2" Sliding Sleeve at 3100' 5-1/2" x 4" CSR & 3-1/2" X-O 3-1/2" Tubine: (Top-Down): · Mandrel Hanger wI control line ports · 30',3-1/2",9.2#, IBT-M Tubing · 3-1/2" x 5000 psi SSSV · Pup Joint x 10' · CAMCO MMG GLM wI RP shear valve · 3060',3-1/2", 9.2#, IBT -M Tubing · Baker 3-1/2" Sliding Sleeve wI 2.81 "X" profile · 1150',3-1/2",9.2#, IBT-M Tbg · CSR seal nipple Kuparuk "c" 3-1/2" Liner Tail ) Ic~;; ~¡~:I I~:)::::: ~i\:-:;,J f::X ~::~::':'(I f/:) <:-:::/,1 p;::} :\,:":::'::1 f:>::::; :r:'}::-!I in.:::::: ::':!:~<::I t?'> ::}:::'::~':I !;,:,',.,:.:.:;...,::...:,:.::,'.:,: ::;:::/::.- I .. >;::>:/::1 m:~,?:' (':':":'d h·::i?: ){}::I iVf:1 [;:.,!,:,:.'".:,:.;,.,:,:,:.i,:.',.11 f?~:~::' f:~\ :{}::Ù EW: ::::,~::'::'I {~;:::'::: ~~?~:~il i;X:!::; :::?:~:::J f::::f::: ::~::¿:~::I I' , . ~~F:::;I 2850' I~r,;:l¡ i ¡., :,:.;,·.:,:~.::.;.:'.~,;:,JI r:~r~:: :;,:, f'...... ,,',' :.,,:::; ';;',::i::,1 3000' I~\¡ ¡¡¡i. 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(:::::::::\::::: ::j:::\::::~::::~:i I:::;.:>:;:::::::: ::':~i>:J 7 500' :).taHX>Ali?:~ ) Pioneer Natural Resources Alaska Inc I vik #1 Abandon Test 1: Test Zone 2 Liner Hanger & Liner Top Packer 7-5/8",29.7#, L-80, BTC-M 3-1/2" Sliding Sleeve at 3100' 5-1/2" x 4" CSR & 3-1/2" X-Q Middle Brookian Kuparuk "c" 3-1/2" Liner Tail ) I:;.·..;,..;,;...... ..'.11.:,··.··.·.,.:1 ?~;~< <.~.~:~\<:. .,·c.·.. """"'. I"):'::: "::"'::~::a 1/ :'/,':1 1/:,:'..,: :-,:'::'1 ì':}): ::',1 f:/>:, ".·..:1 t-:.:):;:';::,J Ie,.::." ::;i":] f?:":~ :':,·,:,:'1 f,::,:·:<~~.1 f:··::"< :,:/::J r::-::.:::: /:::)J vJ,..;;; :::::::'':::1 I/::/~ :,;.:)): r}:~;.j }!:(:) f::::?:: ·;;-:':-}I w::::;~:' ::::.:;:\::.1 i(:::,::< . 1 2850' ~!¡¡t ~ i:,::,~,!.',j..!.: k·::<;::" t>::::::, };:::.: .,':<;~; :~/';::,J f~:\s: X~,\ ::::/~: :::/::.::::1 i\~t:S:... )::~.:~.;:::) 3000' ...;:~?:: ;::,\:~I (;::::< ::~X:~:i 1::Xf;: ~+;j {>? ' ' I ...., .Q.£. }}{:I :r:);~ r/I I:::;:?:: ~~:::::::i 1)\;: :::?}¡ [::::::::: ~;'~::I t\::: . 1 4250' :;~~\ ~~ I:}t:\ :;:{:U) I::~':'\:~:;: .' ,.,. ",' :?;::.~?;:~.:;:~ 1 ..-,'..' -zI : ." .1 I." '., .'.:J f":':', :':,~',"'.'¡ t~:·,~:è-:.:·> ' {':::::'::;':~J I:::'::??~:: Y:\:.':>::;J 1::::::/:::",\: .~:::::::':::::::I r-...:·::,:::,:: '.\:~::(:) I'::':,':':: '.: '::. );:::::: >::::. I'·::,':'.":':'" ~:?::<:::::::::t I····:···:·:::· ::::-;\::'}) 1::-:::::::: /:::::-::::.:::.( 1 :::':::,::~. :':'<.,: ~·I I::;::::;:.:::::' .... .,.. .~:/:>::/:-:. I::.·:,./:.~: ~;::?::::.'::::,i I:::;:::::::.:::':. .~:::~::':::'~/I 1'::::'::·:\. '::~':'::'::': i ~.,'.' ,.:....<~ r::/:::-:,.:::.':::: :::::;::::\:\t- I'::~'//:: {/?>·::'t 1:\/:\:;:: ::i:\) 7500' :···:.:Jit:\:::-·:··::)·~:itiq ~) Pioneer Natural Resources Alaska Inc I vik #1 Finish Testing: E-Line Plug Back Liner Hanger & Liner Top Packer 7-5/8",29.7#, L-80, BTC-M 3-1/2" Sliding Sleeve at 3100' 5-1/2" x 4" CSR & 3-1/2" X-Q Middle Brookian Kuparuk "c" 3-1/2" Liner Tail ) If;;; !...;1,':.:'...,1. ~ , ::"".:.:.'''',~ + 75' RKB ~~,,~::;~ þ ¡ ~~,'.;,~:':::::I f?':r: w:~d/~:::.::.::::.::::.:. D\n~ ~~':"':;,: 1 :'0::':' ~:::<?':::; ::'/:/:/:\ '):\}{. ::..,. 1 I.-. '. ~ \/~t: U·:\:::::.::: }::::(:? .: ,I I' '.: ~/)::\ ~X)::~:::\ ~/<:::'.::::: . .:':0,.:1 I.' ,<: ~)/\ {)(:~\ :?\)::\ :.:..-: " ~ 1 I:' ....,,: \:~;r):::\})? :;/t>::: :: '. ::1 I'· '.':': ff::r-:? \{:'/,,~,::: §?::.::{: :'~. '.:·1 f:·<:.:' :\\?? C/:?/ //~:) :\.::':::,1 1 '.: ::':~ :~/Ò\ t:\/::::: ~~}~~/2 :~:,·.·.',·:I r::.:::::;: t:rmm JmWB [WJ-;:@! :·':':::'·,i: L:··.':: m~m~ mmm mm~m f.:):,:: r,:·.::·:: '~/:}\ :\::}:\:~ }):\~~ ;'::::',.1 I' ",: '::0":'-:':::' :::::::::::::, c.:":::::::::: ::·':'1 f'o.\~ ~rNä n~%:~~ wmm~ ~":·:::·::.:I ¡:(¡ I jl~!¡;;; ,¡¡¡ 'ti:¡ 3000' ij¡¡,n¡;!;!n:¡;,!~¡ ro',) -? {\// ~~:~: ::}/I ¡;¡,¡¡¡ ¡g;~;¡ ~,¡~ (::>~ C) ;.';~ ¡III;: :@~ ~~m-: 4250' ~¡¡¡t 11m;: ~~{<~~ ¿~t/?J Üt< .:....,:,.....:.:. ~~:éX::J . F',:.:2I ~Hd ~/L/ ' 1+~:+::J f\:::::\ }}~~:}i f/:\?:::\?:}:::::t ())?: i??~::~::'::~f f\?:::::: X\:,:/:j f::::::~::::\ \/:::??i (/:??:? )::}/<i f:::,//::::: t\\/:\î r/::/).:> t~~:::::::~\t I}::':::>/:: '..,.. '.. ~:::::/:::/:j f:?:\/ ::·:·:·::·i."·:: \/:::::)t ~;¡;¡; ð1,,¡,¡,!:¡ t:\:::::::::::~ }::::;~::::<[ t/:Y:? /f:·::·?~· 7 500' :t.~Y:?n::}lUn ) Pioneer Natural Resources Alaska Inc I vik #1 Cement plug: 3100' to 75' MD 7-5/8",29.7#, L-80, BTC-M 3-1/2" Sliding Sleeve at 3100' Middle Brookian Ku paruk "c" 3-1/2" Liner Tail ) Chemical Cut 3-1/2" & 7-5/8" I :;::.:::::,(. -~;::'::::";;:: : ;:::.; :: .;(.:; '.:,~':: :: ~'.~ .: ~; ":(.;:: .: ~:;. :(,; ".,'" ,,".~ "."'. ", .... ."..".. .~. . ...... .,.,.,.".' ..~". .,.,.". ," ",' '0< '.' ".... ", "',' ",," ".' ~ :i,~,~~ :::,~: ::: ~ ~ : ~:,:~'~'~; ~~'\~,~'~ :::: ¿ :~: ~:',~::~: ~~:.::: ~:~,~; :.:.: ~.::~ :~.;: :::~';':'>:~:":~ :-~?<':~:.::.:,.:: .",.".~""." '~"'.. ",' ',. .,. '. ....."..". ~ %X~~i~ ¡:~~m~~~¡ ~mE~t~ .....,....... .......'...... .,,_........'... -,' .-....,. ......,..,. ..... '. '.' ,0",", ".' "." " . '.' . -. . o' ~. 0"' .' .' . . "0" - -" I' . . ::':. " :'.: .:',:.':,::<. .:::}...:::.) ··.·1 I '. .::-:':.':(::: ':(::,":-:':'..) ;:,:-,:;:-,:;. 1 1;:-:'::'; )::::::::~;y ,::::':::-::.:~/: \::.:/:::::: ':'::.' :..1 I'·:· . \\;;::<::: \:/::::~'(: //.(:::::: '.......·'·1 I·: .:: /:':'/).::< ::;':,:~::"/,: :(\">:\ .: . 1 i:--···· ;:::::::.:::-::::< :<:-:<:::>:: X/?/:: 1 ¡.--:" '.::.. \:\}}: ·t.::·\/ :/~?}\: :,..::-. 1 I".~: .... :':'.::,'::::::::::: :~::'/:>/: ::y,::,::,:::.:::.::~ :';'1 (.' .; ~)/:> :((//: :::<::~.::\' .1 (-:::'; :>\:::.~\: ::,~>::::::::"~: :(,?:':;?:~ , '-: J r::::::·· ·;\\:W J{mm: :~~{J>'\ }'..':,': r·~"···: ':. ::~~: :~:?:.::~:/:~: :~~: .' >:.~-:-.·l (:.. :-'::':'" ::::.: ::}::.::Y:/::Y ;.;.:': :'."::::,:1 3000' lè¡; nllifW¡~ ¡¡¡;il 1'\':::': .::::: :::::::;~\/ :\: '::~':',:i ¡~" ¡¡:~i:~ -ii"~,! !'II ~"I"I 4250' !¡!'l,t rlj',;! (m?:~ /~:~:~;j. ~¡¡¡¡t~¡ .~¡j¡¡;¡ ........... .. .":':' ~ ~\\( ~Y?::<-J t:\?:~ {::\//I f>:~::::::/ :::::::/:::::~:j r::::\~:;::::~ :::~//':n r/:~.~::::: ~:;:\:~'::::/, t:/:::<.:::: ~:~::::::\?::I (/::)} )??:/J 1:\<:>:::;:: \::::::~:::::j t/:(O::.;: :::::.(){j t<.:.::::\... .. ::;;:::;\::::j ~~(}m ':'~:~Œ\:}'i: :'. ~::::':~ r:,:-::.-.::-:~' , . . . I ()\) ~:A\::kì 1.::-::::// ::j\"<:'J 7 500' ::':·:a~r',x,:x..n: ') Pioneer Natural Resources Alaska Inc I vik #1 Cut off tubing & casing 7-5/8",29.7#, L-80, BTC-M 3-1/2" Sliding Sleeve at 3100' Middle Brookian Kuparuk "c" 3-1/2" Liner Tail 1000 2000 3000 4000 .c .... c.. CI) C 5000 6000 7000 8000 9000 ) ') Offset Mud Weight Om __+__ ___ m ---r-' ---~-mr-- mj___+imj--m___ m+mr----:mL m . - - ~ ....~: - - - - - - - ...... - .. - :-...... - - -;.. .. - ..!- - .. .. - .. -! - .. .. -!- - .. - : - - - -! - - - - - .. .... .... - - - - -:- - .. .. : - - -. .. - - -;- - - - : - - - _..- ::: ::1:: ::: ::::::r: ::t:::::: ::::::::~[n::: ::: :::r:i::--:::r::[ ::: :::: ::::1:::: ::: ::::::::t::: - ;;:::j:::r::;::::j::- -;:::;:::::::: ::: :::::::::;:::: ::::j::::;::: ::: ::: : ::r: ::: ::: ::T:: :- -;::: -:::- TJ: :1::: I:::::::: ::: :::r:l::: ::::I::T:: :: , , , , , , .--- ----t---- --- --------.---- - , , , , , , ---- ----1--- --- --------1---- - , , , , , , . -.. - - - - - - - - - - - - - - - - - - -.. -- -- , , .___ ___.1. __ _______.,____ _ _:m: :-::::::i::::;:::::::::::: ::: :~-K~i~b¡k-#~--- m __;m_ ___~----[----;ooo-j---ooo-- 000 ·......Kalubik #2 _¡m_ ---1----i---+-+ooo---- 000 -......Kalubik #3 : : : i -'-Harrison Bay -.- 3M-27 .....Thetis Island #1 " , " , ____ ___.1____1..___ ________1..___ _ _ " , " , " , · : L m - _ _ _ __ 000_:_ _ _ _ ~ _ ___ _ _ __:___.,. _+m:ooo_ I' . I . . ! !,! - - ~ - - .. .. .. - - - - - - .. ..:- .. - - ~ - - -. - - - -:- - .. .. ~ - - - ~ - - .. -:- - - - _~--m--- --- ooo-!----f---· ---+---f--+--+--- - ~ - - .. - -- .. - - - - .. - - -¡- - - - ~ - - - - - - --¡- - - - ~ - - - ~ -- - + - - .. : ,. I'.' , I I I I , , , I I I I I I I I I I I I I J._______ _w_ ____1____10_____.__1____1-___-+_.__1____ " 'I 1 I 1 1 ",, " , " - - - - - - - -. - - - - .,... - r - - -. - - - -,- - - - r - -.,.. - -,- - -- " ,',' , 1 t "" , , ,.. , , I --,---....--""-------- --- ----,----r---·----,----,.--·,----,---- , , , " 1 tit m - '---,- m -- -:- m'_ -i-- m'_ -i--.- n.m_ - m - -i- -, m_ m¡m_' --, m¡__ ::: ::TT:: ::::::r: ::: _- ::: ::TLtT:::: :::::r:y::::¡::::r:JJ:: ..' .'" II IIII 8 9 10 11 12 13 Mud Weight o 1000 2000 3000 .r:. .... g. 4000 C 5000 6000 7000 8000 10.0 sc 11.0 ') \ J Offset LOT's (Frac Gradient) . . . . .. . . . . . . . . . . . . . . . . . . . . . . . ~ . . \ 12.0 ! . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... . 113.41 II 13.0 14.0 16.0 17.0 15.0 EMW (ppg) 9/02 REV DATE BY CK APP DESCRIPTION REV DATE BY I. CK APP DESCRIPTjON ) ') 29 28 27 26 25 30 29 ~ 28 27 26 Thetis 15. 3:! 32 COOGARUK #1 0 33 34 35 36 31 32 33 35 IVIK No. 1 T14N T13N LOCA TED' WITHIN PROTRACTED 2 1 6 5 SEC. 6, T 13 N, & R 8 E, SITE~ ~IVIK #1 UMIA T MERIDIAN. 500' F.W.L, 1450' F.S.L. 10 11 12 7 9 10 11 LA T == 70·30'22.57" LONG = 150'11'23.58" Y = 6,034,820 15 14 13 18 17 16 15 14 X = 476,790 ~ o NA TCHIQ #1 "'> Z' ADL 0389950 -5'0 24 22 23 -? 19 20 21 22 23 <S>Q 0- &- N 27 26 25 30 2~ A) A) --.JCD 36 fTIfTI 31 32 SCALE: 1" = 200' ~ \ ¿ .À \\ ~\ ~ Ö\-- ~ ? ""0 L() '<; - ~6 ,2T7~ w Pioneer Natural Resources Alaska, Inc. ~~ \ \b \" 1 \ ~O'\~ ~()'()() ~.\ þ.1. ~\ \%\ CADD FilE NO. LK601 0476 I DRAWING NO: 11/22/02 VICINI TY MAP SCALE: 1" = 2 MILES NOTES: 1. COORDINATES SHOWN ARE ALASKA STATE PLANE ZONE 4, NAO 27. 2. GEOGRAPHIC COORDINATES ARE NAD 27. 3. ALL DISTANCES ARE TRUE. 4. ICE PAD IS ROTA TED 70' EAST FROM NORTH. IVIK #1 WELL AND ICE PAD PERMIT EXHIBIT I SHEET: 1 NSK 6.01-d476 I REV: OF 1 0 ') ) Pioneer Natural Resources Alaska Inc. Ivik :::1 Cement Recommendation 7.625" Surface Casing 5.5 / 3.5" Production Liner Prepared for: Skip Coyner November 19, 2002 Version 4.00 Prepared by: Eric Dompeling Halliburton Energy Services 6900 Arctic Blvd. Anchorage, Alaska 99518 907-275-2637 HALLIBURTON The Future Is Working Together. Ivik #1 Well Detail.doc ) ') HALLIBURTON Location :Section 6, T13N, R8E UM ENGINEER: Skip Coyner RIG: Nabors 27E Well Number: Ivik # 1 MSL : RKB: 43 ft Status: Grassroots DEPTH I MD I TVD I INFORMATION I HOLE I CASING I I MUD I CEMENT I WELL Conductor I~ill I!~II 115 115 ~~ Surface Casing ; )11,1 200% Excess above· I i - , ~~I _____f>_~r~9Jf~_~~_~_qº~__~_~º~___~~-------------------_ I~L______________________ ___________________________________________________ 40% Excess Below." ~~I 311 Sacks Permafrost L .1\1:1 \ I~ f! , I,~~¡ '1 ~: \~¡ , '-!! , :!Î _____T_q~_~fJ·_~~ _?l§9___?_~§Q.___ '.____________________ I. ~---------------------- .P_Q~~_____.RP9.____________________________________ i I 6.875" 10 223 Sacks G 2% CaCI 13-3/8" Driven I' ' , I Top of Liner 2850 2850 3000 3000 7 5/8" Size 97/8" 29.7#Wt. MW =9.6 70 BHST F.G.=12.5 ppg Production Liner 4.95" 10 Top of 3.5" 4250 4250 5.5"Size 17# Wt. 294 Sacks Microlite 3.5"Size Shoe Depth 7500 7500 6.75" 9.3#Wt.1 MW =10.2 Additional Information: Top of Tail @ 5800', Lead slurry to Top of Liner + 150 Ft. 110 BHST 30% Excess Top of Tail 5800 5800 Pore ppg 351 Sacks Super CBL 2.992" 10 190 BHST F.G.=16 ppg ) HALLIBURTON ) Cement Recommendation Surface Casing Well Conditions Casing Size & Wt. Hole Size MD TVD Top of Tail 7 5/8" 29.7# 9 7/8" 3,000' 3,000' 2,250' Volume Excess Mud Wt. BHST BHCT Previous Casing Depth 200% I 40% 9.6 ppg 70°F 50°F 110' Slurry Recommendation: Preflush I Spacer . :~_~.Þ~ìW ater, 75 bbl Alpha Spacer Lead Slurry: i/,·/'3~/~.§'~. (1,292 Ft3) PERMAFROST L .~ ,,\,~,,\,,..... i Tail Slurry: ·~,:>;'22~<g(s. ( 256 Ft3) Premium Cement, 2% Calcium Chloride (~""':;~:'¡:1)1i" ÌI'o(."~·· (230 bbl) (46 bbl) Density (ppg) Yield (cu ft / sk) 8.34 / 10.5 1.?.2_] (1..'·'4..1..~. .. /- .....~...::::."". 20.3 Tail Slurrv 15.8 ",.......""--'-'-"") ~/ 5.00 Spacer Lead Slurrv Water requirements (gal/sk) Fluid Loss (cc/30 min.) Free Water % Thickening Time Hr: min. 6:00+ 3:00 Compressive Strength - PSI 12 hr (est.) 24 hr (est.) (48 Hr.) 25 (72Hr.) 260 1650 1800 Volumes based on: Lead slurry: Top of Lead cement @ Surface 110 feet cased hole + 0% excess, 1390' open hole + 200% excess, 750' open hole + 40% excess. Top of Tail slurry 1000 feet above shoe@ 2,250' 750' calculated annulus volume +40% excess + 120 foot shoe joint. Tail slurry: Casin~ Equipment 1 ea. - 7 5/8" 29.7# Halliburton Super Seal II Float Shoe 1 ea. - 7 5/8" 29.7# Halliburton Super Seal II Float Collar 1 ea. - 7 5/8" 29.7# Top Plug 1 ea. - 7 5/8" 29.7# Bottom Plug Pioneer Natural Resources Alaska Inc Ivik #1 11/21/2002 ) HALLIBURTON ') Cement Recommendation Surface Casing Pumping Schedule Stage Liquid Number Description Density Rate Volume Tracer Shutdown lbl gal bpm bbl mm 1 Spud Mud 9.60 5.00 0.0 D 2 Water Spacer 8.34 5.00 20.0 D 3 D 3.00 4 Alpha Spacer 10.20 5.00 75.0 [gJ 5 Pennafrost L 10.70 8.00 230.0 D 6 Surface Tail 15.80 8.00 40.2 D 7 Surface Tail Shoe 15.80 8.00 5.5 D 8 D 3.00 9 Spud Mud 9.60 8.00 122.2 D 10 Spud Mud 9.60 2.00 10.0 D Stage Description Spud Mud Water Spacer Alpha Spacer Pennafrost L Surface Tail Surface Tail Shoe Spud Mud Spud Mud Time mm 1.20 4.20 8.20 22.82 27.82 29.70 39.08 51.58 56.66 56.66 60.29 70.29 77.44 79.94 80.04 ECD at Zone Fracture I Reservoir lbl gal 9.80 9.80 9.80 9.83 9.82 9.64 9.98 10.49 10.78 10.78 10.69 10.93 12.01 12.18 11.95 Critical Velocity - Fracture Zone Based on annular segment at 3000.0 Critical Rate ft Critical Velocity Critical Reynold's Number bpm 13.08 1.17 8.19 13 .40 19.34 19.34 13.08 13.08 ft/s 4.07 0.36 2.55 4.17 6.02 6.02 4.07 4.07 4004 5895 4401 4362 2383 2383 4004 4004 Time of Events S tarts Pumping Stage Enters Annulus 9.80 9.80 9.80 9.83 9.82 9.64 9.98 10.49 10.78 10.78 10.69 10.93 12.01 12.18 11.95 Water Spacer 3.00 min shutdown Alpha Spacer Pennafrost L Water Spacer Alpha Spacer Penna frost L Surface Tail Surface Tail Shoe 3.00 min shutdown Spud Mud Surface Tail Spud Mud Prior to plug landing Plug landed Pioneer Natural Resources Alaska Inc I vik # 1 11/21/2002 ) HALLIBURTON " Cement Recommendation Surface Casing IECD Pump Pressure 16 OptiC em Summary ECD at 3000 ft TVD, Pump Pressure, Pump Rate, and Density vs. Time Fluid Density Rate--··.·-··.···.·······-.·-----··.·····-.--·--··.-··.... 15- .-~~"-,~-----_..-.--- ~ 14- 13- "- ~', , I 70 cr o 10 30 20 7.625 in Surface Casing o OptiCem Pinal Densitv & Hvdrostatic Profile Annular FluidD'énsity vs. Measured Depth ----- 500- I 000- 1500- 2000- M=~~~ili (ft~ 3000- 3500 10 I 11 I I I 12 13 14 Density/Hydrostatic Gradient (lb/gal) I IS 7.625 in Surface Casing Pioneer Natural Resources Alaska Inc Ivik #1 700 -9 -8 -600 -7 -500 -6 -5 -400 -4 iate (bpm) -300 -3 Pump ?ressure (psi) -2 -200 -1 , I ' 80 100 90 -0 I C61HALlIBUR1ON OptiCmn v3.1.0 19·Nov·0211:0l 1- Density I - Hydrostatic Gradieq¡ 16 I 0 HALLIBURTON OpliCmn v3.I.U 19·Nov-U2 11:01 11/21/2002 ) HALLIBURTON TVD (¥i~o- I Pore Pressure Gradielll Minimum Hydrostatic Gradieul o ) Cement Recommendation Surface Casing OptiCem Downhole Pressure Profiles Minimum Hydrostatic Pressure and Maximum ECD Ys. TVD Fracture Gradienl Maximum EC[)----------- \ , I' 'I"" I ' 10.0 10.5 11.0 ECD (lb/gal) , I ' 11.5 1000- 2000- 4000- 5000 8.5 , I ' 9.0 , I ' 9.5 7.625 in Surface Casing OptiCem Circulating Pressure and Density at Fracture Zone. DowMole Annular Pressure and ECD YS. Time I Circulating Pressure Hydrostatic Pressure I 2000 Pressuf6òwsi) Fr;:.t~JJ,l1·~; J'.r....~),\~rç,l¡:::çJ~ ;~ .,~i,!1.Q, 1,( T\',Q 1900- 1800- 1700- 1500- ~ -(1) 1400 ,I, o G) , I I 20 , I ' 10 , I ' 30 w G)~ '1""11,,1'1 40 50 60 Time (min) @ I 9.0 90 , 1 70 I ' 80 7.625 in Surface Casing Pioneer Natural Resources Alaska Inc Ivik #1 ----I I ' 12.0 , I ' 12.5 13.0 I OHALLlBURTON OptiC~'n v3.I.O 19·Nov·02 11:01 -12.5 Fluids Pumped CD Water Spacer CD Shutdown @ Alpha Spacer (3) Permafrost L CD Surface Tail Ci) Surface Tail Shoe CD Shutdown CD Spud Mud @ Spud Mud -12.0 -11.5 ::-11.0 -10.5 = ECD (lb/gal) -10.0 -9.5 I «:) HALLIBURTON OptiCcm v3.1.0 19-Nov-0211:01 11/21/2002 ) HALLIBURTON Well Conditions Casing Size & Wt. Hole Size MD TVD TOC Slurry Recommendation: Preflush I Spacer Lead Slurry: Slurry: Density (ppg) Yield (cu ft I sk) ) 7 Cement Recommendation Production Liner 5.5" 17# I 3.5" 9.2# 6.75" 7,500' 7,500' 2,850' I 5,800' Volume Excess Mud Wt. BHST BHCT Previous Casing Depth Casing Size change @ 30% 10.2 ppg 190°F 130°F 3,000 ' 4,250' (3.5" to TD) 5 bbl water, 35 bbl Alpha Spacer , 29,~,iSks. (545 Ft3) Premium Cement + 15 LB/SK. Microlite, ,,>+- 0.2% CFR-3 (Friction Reducer), + 0.75% Halad 344 (Fluid Loss Additive), + 0.05 glsk D-Air-3 (Anti-foam), + HR-5 (Retarder) as required (97 bbl) ...-""--"\ ,Á51 JkS. (407 Ft3) Premium cemen.t+ 1 % Bentonite, + 2.0 G/SK. LATEX 2000, L ~% CFR-3 (Friction Reducer), + 0.36 glsk. 434B (Latex Stabilizer), +0.05 glsk D-Air-3 (Anti-foam), + HR-5 (Retarder) as required (72.6 bbl) Spacer Lead Slurrv Tail Slurrv 8.34 I 11 13.4 éP {2 .16 13.38 .11 <75 <75 0 0 >3:00 3:00 Water requirements (gal/sk) Fluid Loss (cc/30 min.) Thickening Time Hr: min. Free Water % Compressive Strength - PSI 12 hr (est.) 24 hr (est.) 350 @ 900P 625 @90 OP 1,440 @165 of > 1,000 @165 of >2,000 @ 1650P Volumes based on: Spacer I Pre-Flush: Volume based on 1,000 ft. of annular volume and lor 10 minutes contact time. Lead Slurry: 2,800 ft. Calculated open hole +30% excess, + 150' Liner Lap + 150' Excess (with 3.5" D.P. in Hole). Final Top of Cement at 2,850'MD / Tail Slurry: 1700 ft. calculated open hole volume,+ 30% Excess.+ 120 foot shoe joint. Top of Cement at 5,800' Casin~ Equipment 1 ea. - 3.5" 9.2# Halliburton Super Seal II Float Shoe 1 ea. - 3.5" 9.2# Halliburton Super Seal II Float Collar Pioneer Natural Resources Alaska Inc I vik # 1 11/21/2002 ) ) HALLIBURTOI\I 8 Cement Recommendation Production Liner Pumping Schedule Stage Liquid Number Description Density Rate Volume Tracer Shutdown lb/ gal bpm bbl min I LSND 10.00 6.00 0.0 D 2 Alpha Spacer 11.00 3.00 5.0 D 3 Shut Down Pressure Test D 3.00 4 Alpha Spacer 11. 00 3.00 20.0 D 5 Microlite Slurry 13 .40 6.00 97.0 D 6 Pt MC Super CBL 15.90 7.00 71.5 lZJ 7 Pt MC Super CBL 15.90 7.00 1.0 D 8 Shut Down Drop Top Dart D 3.00 9 LSND 10.00 7.00 54.2 D 10 LSND 10.00 3.00 25.0 D Critical Velocity - Fracture Zone Based on annular segment at 7500.0 ft Stage Description LSND Alpha Spacer Microlite Slurry Pt MC Super CBL LSND Time min 1.83 1.83 6.50 17.63 21.80 26.80 28.38 38.03 41.03 41.74 57.11 57.21 ECD at Zone Fracture I Reservoir lb/ gal 10.55 10.55 10.54 10.74 10.75 10.88 10.93 11.59 11.24 11.59 13.14 12.82 Critical Rate bpm 12.69 5.66 4.82 15.97 12.69 Critical Reynold's Number Critical Velocity fils 5.03 2.24 1.91 6.33 5.03 8950 5471 2013 2480 8950 Time of Events Stage S tarts Pumping Enters Annulus 10.55 10.55 10.54 10.74 10.75 10.88 10.93 11.59 11.24 11.59 13.14 12.82 Alpha Spacer 3.00 min shutdown Alpha Spacer Microlite Slurry Alpha Spacer Microlite Slurry Pt MC Super CBL 3.00 min shutdown Pt MC Super CBL LSND Prior to plug landing Plug landed Pioneer Natural Resources Alaska Inc I vik # 1 11/21/2002 HALLIBURTûÀ. -) 9 Cement Recommendation Production Liner IECD Pump Pressure OptiCem Summary ECD at 7500 ft TVD, Pump Pressure, Pump Rate, and Density YS. Time Fluid Density Rate 15- --7 I 2250 -8 :-2000 -7 :-1750 -6 16 14- :-1500 -5 13- :-1250 -4 12- :-1000 ~lte (bpm) 11 -750 : Pump :?ressure (psi) - -2 :-500 10- VD, ~e~ In (Ib/gaI) cp I I I I I I I f I I I 10 20 30 Time (min) :-250 -1 cr I 0 -0 50 60 3.5" / 5.5" Cement Production Liner I «:) HALLIBURTON OpliCcm v3.1.0 19·Nov·0211:13 o OptiCem Final Density & Hydrostatic Profile Annular Fluid bensity YS. Measured Depth 1- Density I - Hydrostatic Gradien, 1000- 2000- 3000- 7000- 4000- 5000- Measured "Jepth (ft) 6000- 8000 9 I 10 I I I I 11 12 13 14 Density/Hydrostatic Gradient (lb/gal) I 15 16 3.5" / 5.5" Cement Production Liner I 0 HALLIBURlON OpliCc'II1 v3.I.O 19·Nov·0211:13 Pioneer Natural Resources Alaska Inc Ivik #1 11/21/2002 HALLIBURTú~ 1 Pore Pressure Gradient Minimum Hydrostatic Gradieut 0- 1000- 2000- 3000- 4000- TVD @00- 6000- 7000- 8000 8 I 9 ") 10 Cement Recommendation Production Liner OptiCem Downhole Pressure Profiles Minimum Hydrostatic Pressure and Maximum ECD Ys. TVD Fracture Gradieul Maximum ECD -------1 I 14 I IS I 16 17 \", . ...""'~ I ~ HALLIBURTON OptiCcm v3,l.O 19-Nov-0211:13 OptiCem Circulating Pressure and Density at .Fracture Zone. Dowñhole Annular Pressure and ECD YS. Time I Circulating Pressure Hydrostatic Pressure I 7000 6500- l"I';I<:H\n.' .')l';>lIrC:!: (·1):1' .7~(I\I.n .1'\'1) 6000- 5500- 5000- P 450(}- .) ressure ŒSl 400~~ 3500- ~ 3000 - I, o CD CM I ' 10 I 10 I I I 11 12 13 ECD (lb/gal) 3.5" / 5.5" Cement Production Liner Fluids Pumped CD Alpha Spacer CD Shutdown CD Alpha Spacer W MicroLite SLurry CD MicroLite SLurry CD MicroLite SLurry CD Pt MC Super CBL CD Pt MC Super CBL GQ) Shutdown @ LSND -12 @ LSND ECD (lb/gal) -16 -14 (j) I ...~, 40 I 20 CD I , , I 30 Time (min) 3.5" I 5.5" Cement Production Liner Pioneer Natural Resources Alaska Inc -10 @ I -8 60 I 50 I 0 HALLIBURTON OptiCc,n v3.1.0 19-Nov-0211:13 Ivik #1 11/21/2002 General Discussion ) Pioneer Natural Resources Inc. Ivik #1 Drilling Fluids Program ) This exploration well will be drilled from an off-shore ice island west of Oliktok Point on the North Slope of Alaska. The well will be drilled as a "slim hole" to minimize waste. The well will be spudded with a 9-7/8" bit and drilled to the surface casing point of ± 3000' TMD where 7-5/8" casing will be run and cemented to surface. A 6-3/4" hole will then be drilled to a final well TD of ± 7500' TMD. At TD, a 5-1/2" x 3-1/2" tapered liner will be run and cemented. The targets for this well include the middle Brookian and Kuparuk sands with other possible oil bearing sands being present. An inhibited KCI/Polymer mud will be used to drill this well from spud to TD (no coring is planned for this well). As a general drilling fluids plan, spud the well with inhibited 9.0 ppg KCI/Polymer mud. The mud weight will then be held between 9.0-10.0 ppg to the surface casing point unless hole conditions dictate otherwise. Our primary focus for surface hole drilling operations will be adequate mud weight for well control and sufficient mud viscosity for hole cleaning. This spud mud is fOImulated with several mechanisms to provide effective wellbore stabilization and to . reduce drilling waste, Le., ionic inhibition (KCI), polymer encapsulation (PHP A) and anionic bonding (Clayseal). From the surface shoe to TD, the continued use of the inhibited KCI/Polymer mud is suggested with again the primary focus being to provide effective wellbore stabilization and the reduction of drilling waste. When drilling this interval of the well a certain amount of new mud will be required coming out of the surface casing to re-adjust the low gravity solids content to acceptable limits for continued drilling operations. The mud weight for this interval will range from 9.6 ppg at drill-out of the surface casing to 9.8 ppg by 4000' (middle Brookian target) and to 10-10.3 ppg by the top of the Kuparuk sands. This current mud plan would put the mud filtrate salinity in the 60K-90K ppm range for drilling the pay-zones. Formation Tops/Casin~ Program Formation BÆocene Sagavanirtok Ugnu Colville Mudstone 7-5/8" Surface Casing Middle Brookian HRZ Kalubik Kup "c" Miluveach Alpine Sand Jurassic Sand TD/Jurassic Shale Special Considerations TMD 900' 1000' 2200' 2700' 3000 ' 4300' 5900 ' 6100' 6250' 6400' 6450' 6550' 7500' Comments possible gas hydrates occasional "heavy oil" Expected LOT = 13.4 ppg EMW secondary target occasional shale instability occasional shale instability target sands occasional shale instability secondary target secondary target occasional shale instability Mud Wt 9.0-9.3 9.3-9.6 9.6-10.0 9.6-10.0 9.8-10.0 9.8-10.0 9.8-10.0 9.8-10.2 9.8-10.2 9.8-10.2 9.8-10.2 9.8-10.2 / 1. Maintain a sufficient quantity of Driltreat (lecithin) to accomplish a 2 ppb treatment in the event gas hydrates are noted. Ivik #1 Page 1 11/21/2002 ) ) 2. Lime and zinc carbonate should be on location for HzS contingency. 3. Maintain an adequate supply of barite to increase the mud weight by 1.5 ppg at all times. 4. Due to the remote nature of this location, maintain an adequate supply of LCM and the other mud additives, which may be required to support this drilling program. Surface Interval (9-7/8"" Hole to 3,,000' TVD/TMD) The surface interval of this well will be drilled with a KCl/Polymer mud as formulated below: 9.0 ppgFormulation Fresh Water KCl NaCl EZ Mud DP Clayseal P AC-L/R Barazan-D KOH Aldacide-G Baroid Baracor 700 .95 bbl 44 Ibs o .75 Ibs .84 gal .5 Ibs 1-2 Ibs .11bs .21bs o 1.0 (ionic inhibition) (polymer encapsulation) (anionic bonding) (API filtrate of6-12 cc's) (as required for an initial 35 YP) (pH = 8.5-9) (X-Cide 207 for rig maintenance) (as needed) (colTosion inhibitor) Spud the well with maximum flow rates (550-650 gpm assuming 9-7/8" hole w/3-l/2" drill pipe) to ensure good cuttings transport. Target an initial yP in the 45 range then adjust as dictated by the actual hole cleaning requirements of the well (minimum gravel is anticipated - mostly clays and sand). Reduce viscosity as allowed (previous wells in the area have TD'd the surface hole with a ± 25 YP). However, if hole cleaning appears to be inadequate, do not hesitate to quickly raise the viscosity as required. Polymer viscosity in the form of Barazan-D additions should be utilized to provide rheological support as needed. Utilize high viscosity sweeps to supplement the hole cleaning capabilities of the system. With an initial mud density of9.0 ppg, please note the other issues of concern as listed below: 1. Alert all members of the drilling team of the potential of encountering gas hydrates. 2. A mud weight of ± 9.6 ppg is cUlTently programmed for drilling the gas hydrate interval of the well, if encountered. Note: offset wells encountered only minimal gas hydrates. 3. If gas hydrates are encountered, treat the system with 2.0 ppb of Driltreat (Lecithin) and Yí% by volume BDF-263. Also, control drill if necessary. 4. Maintain the mud as cool as possible (under 50°F if possible). Efforts to keep the fluid cool include mudding up with cold water and diluting the mud with cold water. The Baroid mud plant in Prudhoe Bay can be utilized to supply the initial volume of fluid for the spud. Make every effort to maintain the system as clean as possible through the normal dilution process and maximization of solids control equipment application. As this mud will be formulated with soluble salts for the mud density requirement, the Baroid Solids Van should be considered for use to enhance/support the overall solids control efforts. Mud maintenance issues for this interval of the well are as follows: 1. If possible, use pre-mixed KCI water to maintain volume while drilling ahead. 2. Use PAC's for API filtration control. Target 6-12 cc's initially, dropping the fluid loss to the 6 cc range prior to running casing at the surface casing point. 3. Hold the pH in the 8.5 - 9.0 range with KOH. 4. By material balance, maintain the Clayseal concentration in the 2% by volume range. 5. By material balance, maintain the EZ Mud DP in the .75 - 1.0 ppb range. Ivik #1 Page 2 11/21/2002 ) ') 6. Control penetration rates based upon the ability of the surface system to process the drilling mud. Use as "fine mesh" shaker screens as possible. 7. Daily additions of X-Cide 207 are needed to control bacterial action. 8. Corrosion inhibitors should be run (1 ppb Baracor 700 / .5 ppb Barascav D). 9. Keep MBT as low as possible (generally <12 ppb). Heavy amounts of clay may be present below the permafrost that could require additions of ConDet and BDF-263 to reduce BRA balling and screen blinding. Sweeping the hole with high viscosity sweeps prior to the short trip at TD and again prior to coming out of the hole to run the surface casing is recommended. If possible, reduce the fluids rheology to <20 yP after the casing is on bottom prior to starting the cement job. Surface Hole Mud Properties (9-7/8") Mud Density Viscosity Properties (ppg) (sec/qt) Initial 9.0 80 - 120 Pinal 9.8-10.0 50 - 80 yP 35 - 45 15 - 30 PV 13 - 21 15 - 23 10 Second Gel 10 - 15 10 - 15 API FL (cc's/30 min) <15 6-8 Production Interval (6-3/4" Hole to @7500' TVD/TMD) Prior to drilling out the surface casing condition the spud mud to ± 9.6 ppg density with <4% LGS and an MBT of <6 ppb (a certain amount of new mud or brine additions could be considered in terms of re- adjusting the properties of the mud to insure a quality fluid for the initial drilling operations of the 6-3/4" hole). Increase the mud weight as needed with KCI so as to allow maximum application of centrifuge support to optimize solids control efforts. KCI will be used for ionic inhibition and for the basic density requirements of the system. CaC03 may be used as necessary. Initially, target a mud density of± 9.6 ppg with a yP in the 10 to 20 range and maintain until out of the sticky clays often found within this interval of the well. Then, adjust yP as required with Barazan-D polymer as needed for efficient hole cleaning. If screen blinding from heavy clays is a problem, use ConDet and BDF-263 treatments. Once through the sticky clays, increase the yP to the 15-25 range with Barazan-D to ensure good hole cleaning support. Flow rates of 250 - 275 GPM will provide an annular velocity of 200' /min which should suffice in this near vertical hole. Maintain the 9.6 ppg mud weight down to 4000'. Increase the density as needed (9.8 ppg) prior to drilling the middle Brookian target. Minimize LGS's through the constant/efficient use of solids control equipment and dilution as required. Below 4000', maintain the API filtrate :S 6 with PAC's. Use KCI brine for daily volume additions (the brine density should be based on the mud weight objectives at the time). Daily additions of X-Cide 207 should be made to control bacterial action. KOH should be used for pH control. Keep MBT as low as possible « 12 ppb), however, do not revert to "dump & dilute" practices unless absolutely necessary. Just above the HRZ, treat the mud with 4-6 ppb of Baranex to drop the 2000 F. HTHP to 10-12 cc's to provide effective wellbore stability through the lower portion of the well. And then at some point just above the Kuparuk D shale, increase the mud weight to 10.0 ppg (with KCI and/or CaC03 as allowed). Production Hole (6-3/4") Mud D. (p ) P rt· enslty pg rope les Initial 9.6 Final 9.8 - 10.3 yP 10-15 15 - 25 PV 6-12 15 - 25 10 Second Gel 2-5 2-6 API FL (cc's/30 min) 6-10 <6 PH 9-9.5 9.0 - 9.5 Ivik #1 Page 3 11/21/2002 .,.. .~..- - "~'<'¡"-"'" , ,... ~'I ·i . ,: .,," - ", I~' _ .', '~...~...' '"'-. !' 'I I, ':- ,'! " ,! ',I 'Ii': I , , 1;1 : II' Date: 6-8-00 Rev. ;~ Legend ~ White Handle Valves \~ Normally Open ~ Red Handle Valves Normally Closed ~iûll- . :':i'~!~~~"' ~~.¿ï~<lf,,:,,:.;~~~~~f~~j'}:t~~;:~~~ - ,_,~t""C__".~" ,.- !~~~d~ ~~~j~~~~~.:~~=1~ f atenal List ,,' ", ' ," ",' ,'" .'.'" " ' ' ",. " ' " -, - - ' · I :);; +:; ,;'<f.'~:~~~} ,", ,;'ð:'":/':. .~,',': F~,f1i,:; " " . :,' . ",),_.~:, "d ·::-jlt ,I".,:·,¡' ,T:'; l:" I . " ,I ,'j , J" I ,/ " Description 3-1/16" 1 0,000# Remote Hydraulic Operated Choke 3-1/16" 10,000# Adjustable Choke 4-1/16" 10,000# Manual Gate Valve 3-1/16" 1 0,000# Manual Gate Valve 2-1/16" 10,000# Manual Gate Valve " . <, '" I, I· t ' J' ',. I'·, . ,. f·, I ':"k::'-" .:, .': " .i.". . . I I, I" ,'.1 I, I' B,C 2,3,5,6 1,4,7-15 16 I:'·; I ' ¡', ," I I , A " . Item .. I, .....~.<t.~.~."'.. '-p. ~ .... "- .... - -'. .........~.. " ......... ...... ... .'. - \ _ r ._.~ .;. ,.-::---. -1"";-' .....":"" -,'-.-:-"'--:- _..-....-..,-:-'"r l...c~-=:":~·:.-:-~-:':7'~~~ì;"~:;:-:~~...7I(:T0·,-,,'·~-....~--r-~~1~:- ( ( ( { 2/t.U~U11' ; _-, DRAWN BY I Ci:EC1ŒD BY APPROVED BY TOE SCALE . i~,." 'E DWG. NO. NTS 1.__ JAN 91 I REV. ¡~.~ ;___E -..----..- ....--. -- i \ DB¡CRIPT1f\r.: DWB LA TOE LA DWfIi. APPR. ~ BY MTE GENERAL ISSUE 12/08/D1 E J.A. R.I<. 09/04/98 B TB 'N 02/21/97 C 07/27/9'ð B 09/01/93 RIG 27E BOP STACK AND SURFACE DIVERTER MODIAED DIVERTER SlZE;(1 Bi / CONFlGURA.1lON PROJEm C~GED· CLAMP CONNECnoN TO BOLTED FLANGE , . 11ß.E R~SED DIVERTER AS PER DeN '3 I GENERAL ISSUE RSB RSIJ N:.:~=~~~~~~DF Nabors Alaska Drilling Inl 2525 C street, Suite 20 AnchQrage, Alallca 9950~ 9D7-283-60oo flt~... -- .............c..r.-.r Oil & Gas, Inc. ··'¡::;:;<~t;W::';';i·,,·A '."~;"""~/')"....¡:"" . . "':!('<:\;;f~:,'·.I:\: \L~~;~'::(,:.",: ARMSTRONG ': }'¡~i~¡:~ ~:}~~~.... ". "flRB·la TECHNI!¢iL S~\ßVICES :."¡It......~w-.:.:..:1'~I(, OCTOBER 2002 Proposal for Arctic Drilling Rig with Crew II~ , r·.........~n:o......''''.,·....,~.....'...'.tL'L:~:''';:n'".:.n~.._.'.::;'·,r.....~..,,',··,,-,'":.-.!...., ..."- ,. ',0;-',"'":'-.'"' "':'C"I'..,".._-,..:.:::--=-. l I i I IJ I i L ......----16·-150# ru; ------+--~l-B----- ~4~~------- I ~- "-.~ ~~=TOR I I I I 2' o· _ I- ~""~~ SURFACE DIVERTER PIPING CONFIGURATION PlJ\N VIEW ',.....- -....'\ I ~ \ , '+, I I , , \ , \, , --suSSTRuctURE w~---'--.cElLAR 21 1/4" 2000# HYDRIL BOP /DIVERTER 25'-11- -~..-....-...._...._...._..,,-..-_...- -...-...--.-...-....-....-...-...- -....-....-....-...-...-....-...- -...-..-....-...-....-...-....- Î I I I BOL1ED FlANGE ADAPTER SPOOL - HUB x FlANGE , I SINGLE 13 S/B" 5000' HYDRll MPl BUND RAM BOLlED FlANGE 4" 5000' HCR VALVE .. 4" CHOKE UNE 4" 5000' GATE VALVE BOL1ED FlANGE SINGLE 13 SIB· 5000' HYDRll MPl PIPE RAM 1C5' BOl1ED FlANGE SINGLE 13 5/B" 5000' HYDRll MPl PIPE RAM BallED RANGE 13 5/B" 500D' HYDRll ANNULAR BOP + ( I ! .....-...---- ....... SURFACE DIVERTER CONFIGURATION ) 2' O· I io 3/1B"- I 2' '0· .... ~ 4' 4 '/2· ì.. J BOP STACK ELEVATION --- I 3/8.1------------------- -----I r · ,¡r ~------, i r L ~-------- I I I· 3/8",------------- -J ! l- => ~ r.,¡r . C---, I r-=- ; .1 ___~~OO~~~ V~~~ - - - \--- I ! I I~ _ q,_ II 3/8 r- 3" 5000' HeR VAlVE __+_~ " 10 5/B· _____~ \ _______ I ! ~ 3/8. --- 3.02. -J I . r ~UNE C ¡ r-=> r · ,¡r. ------=1' ! I. 3/8"~;¡r -------1---- 1'1 I ; ì CUS10MfR FURNISHED II III I L-=>. J 4' 3 7/8" I i ( 4l I ! r I I I I L I I I '\ ,r' '\ ) ') _ WELL SITE SURVEY SHALLOW DRILLING HAZARDS EVALUATION PROPOSED IVIK #1 ALASKA STATE LEASE ADL389950 HARRISON BAY, ALASKA Pursuant to 20 AAC 25.061 all available CDP geophysical, velocity, and proximal well data have been examined and evaluated for shallow intennediate depth drilling hazards. Interpretation of . these data suggests that no prohibitive condition exists at this location that could pose a potential /" shallow drilling hazard. The IV~ # 1 well will be drilled from an ice pad located approximately 3.5 miles south of Thetis Island. The island is located in shallow state waters approximately 8 miles west of Oliktok Point in the eastern portion of Harrison Bay. The proposed drillwell will be located 1450' NSL & 500' EWL of Section 6, Township 13 North by Range 8 East (70.506268 degrees latitude north by 150.189884 degrees longitude west). Geolot!Y , Throughout Quaternary and possibly late Tertiary time sedimentation in this region has been dominated by.the Colville River Delta. Thetis Island, located 3.5 miles to the north, is part of the Jones Island chain. These islands are the last reworked remnants of the drowned Pleistocene coastal plain. Superficial sediments include coarse sand, ,gravel, and boulder lag deposits of Quaternary age. The underlying Pleistocene ~ection, referred to onshore as the Gubik Fonnation, consists of . channelized marine and nonmarine muds, sands, gravels, and low grade coals. Locally the entire . Quaternary sequence is less than 900 'thick. Underlying the Gubik fonnation is the Sagavanirktok'Ponnation, w~ich ranges in age from 'Upper Cretaceous through Tertiary. The Sagavanirktok Formation consists of complexly interþedded ' marine and nonmarine shelf and delta plain deposits composed of sandstone, shale, and . conglomerate. Locally the Sagavanirktok Formation is approximately 3,000' thick and gently. dips to the northeast at 10 to 20. ' The lowermost Sagavanirktok Formation includes a sandstone sequence informally named the Ugnu and West Saksands. ,This Late Cretaceous to Early Tertiary sandstone sequence is approximately 1,000' thick. These sands 'bear heavy oil and natural gas in the Kuparuk River and Milne Point Units to the east and southeast. The Sagavanirktok Formation overlies the Schrader Bluff and Torok Formations. These fonnations collectively referred to as the Colville Group, include fluvial-deltaic sands/shales and marine prodelta deep-water shales. ,Locally the Colville Group is approximately 2,000' thick. Geophysics A Conoco/Phillips acquired 3-D seismic grid covering the proposed Ivik #1 and Western Geophysical acquired 2-D seismic reflection profiles proximal to the well location were analyzed for potential shallow and intennediate depth drilling hazards (see enclosed seismic/well base map); These same data were correlated with all publicly available shallow hole log data to produce an integrated shallow hazards assessment for the Ivik #1. Specifically as part of this ) ') ( analysis correlations have been made with the Kalubik # 1, Kalubik #,?, Palm 3 W -07, East Harrison Bay #1, West Sak #16 and the Thetis Island #1 welIs which directly offset and surround the Ivik #1 location. Illustrated inline 1466, crossline 809(both intersect the Ivik #1) and a reconstruction line that intersects the Kalubik # 1 well, the Ivik #1 location and Thetis Island #1 well are enclosed for your reference. An Ivik # 1 interval velocity/pressure profile exhibit, constructed by integrating all available offset logs, subsurface pressures and seismic data is also attached for reference. :potential Shallow Drillinl! Hazards Permafrost I Seismic reflection data in proximity to ,the Ivik #1 well show a unique response to the laterally varying permafrost thickness in the near subsurface from the mainland and across Harrison Bay. This response is manifest~d by high quality reflection continuity onshore where'permafrost thickness is at a maximum; in contrast to the shallow offshore areas of Harrisön :aay where reflection quality degrades laterally due to permafrost deterioration. This differential thinning is caused by the influx of relatively warm sea water since the latesfHolocene sea level transgression. Resultant permafrost thinning within Harrison Bay has been recorded to as little as 683 ft in the East Harrison Bay # 1 . well. The velocity effect seen in the seismic data is a pronolmced broad "puIl-down" of reflection time coinCident with the. coastline. Conversely seismic reflections show a uniform "pull-up" directly beneath the shoreline indicating permafrost thickening as you move back onshore, as evidenced by the 1563 ft thick permafrost layer in the West Sak #16 well. . Interpretation of all available seismic and well log data translates to an expected permafrost thickness- of 965 ft and an anticipated permafrost base at the Ivik # 1 location /" of approximately ~9 50ft to -1000 ft subsea. The nearest offset well, the East Harrison Bay #1 (2miles west northwest), base of permafrost is interpreted to be at -683 ft subsea. This well is the nearest direct offset and represents the best geographic analog for anticipated permafrost thickness and levels from an offshore ice pad. Shallow Gas/Oil Accumulations There is no geophysical evidence for any significant accumulations of shallow gas beneath the Ivik #1 location. No amplitude anomalies, velocity sag or frequency attenuation indicators are present from 3-D seismic cQvering the location. There is an interpreted gas hydrates layer beneath the. permafrost that has been penetrated by exploration wells surrounding the location. On mudlogs, elevated gas readings through C5 were recorded on the chromatograph, but gas amounts through the hydrates layer never reached levels in any of the offset wells that presented any drilling hazards in the operations of these wells. Specifically, the Kalubik #1 and East Harrison Bay #1 were both drilled in areas of indicated higher hydrates concentration from the 3-D (higher '/ amplitude response), but neither well encountered any significant amounts of gas or experienced any notable drilling operational issues. Hydrates thicknesses were interpreted in the Kalubik #1 (46Ò ft thick, hydrates base -1617 subsea) and Thetis Island # 1 (450 ft thick, base hydrates -1516 subsea) and should be present in the Ivik # 1 at a thickness of 605 ft and an interpreted base of hydrates at -1570 subsea. For the purposes of well planning a partial gas hydrates and free gas column was planned for in our well design and subsequent drilling operational plan development. Having noted the ') ') interpreted hydrates layer, there are no other velocity density indic~tors of any significant free gas beneath the well. Two minimal faults are revealed in the CDP reflection data within 2000 feet of the well; however they tenninate at a minimum depth of -6,000' subsea and are not the likely source for the shallow gas hydrates noted in the offset wells. However, CDP reflection data also reveal several listric normal faults southwest and northeast of this well. These faults are interpreted to extend into the shallow sedimentary section and are the most likely migration pathways for minor shallow gas/hydrates accumulations seen at the base of permafrost. Minor elevated background gas within the permafrost interval is anticipated and planned for in the proposed Ivik # 1 well. The Ugnu-West Sak sand interval is present in the East Harrison Bay #1 (2,220' to 3340' MD, -2187' to -3,307 subsea), Kalubik#1 (2220 to 2990 MD, -1881 to -2957 subsea), and Palm 3W-07 (2675 to 3265 MD, -2152 to -2425 subsea). Minor background gas and no oil shows are seen in association with these sands. This is consistent with the known limit of U gnu and West Sak oil bearing sands to southeast in the Kuparuk River Unit. This interval or its' equivalent, is anticipated to occur at a depth ranging from approximately -1900 to -3200 subsea in the Ivik well and any sands present will most likely be water bearing or contain only minor accumulations of solution gas. The previously referenced vertical pressure profile, which incorporates all pertinent engineering, geological and geophysical data, served as the basis for design and development of all operational and safety plans for the Iv~k # 1. well. Summary As a result of this shallow hazards interpretation, we have not identified from seismic or surrounding offset well data any conditions beneath the Ivik #1 location, which could pose a prohibitive shallow or intennediate depth drilling hazard to the planned drilling operations. A copy of all pertinent data to shallow geological and drilling safety conditions has been supplied to operations and engineering personnel in the preparation of the Ivik # 1 well design and operational plan. ~Ç¿;)~ / v (,., / ' ¥. X. Furin . /Vice President of Geoscience ,/ November 14, 2002 Well Site Survey Abnormal Forma¡ )ressure Evaluation State Lease ADL 389950 ) WELL SITE SURVEY ABNORMAL FORMATION PRESSURE EVALUATION IVIK #1 LOCATION ALASKA STATE LEASE ADL389950 HARRISON BAY, ALASKA Pursuant to 20AAC 25.033 (e) (1) available geophysical data and proximal offset well data have been examined and evaluated for potential overpressure strata. Examination and interpretation of these data suggest that formation pore pressure increases at a normal gr,adient with 'depth and abnormal formation pressure is not anticipated to the proposed total depth of 7500 ft. Reference is h~reby made to the proposed Ivik #1 seismic/well base map, 3-D seismic refl.ection profiles and the interval velocity/pressure gradient exhibit previously submitted to the DNR Oil and Gas Conservation Commission November 2002. The seismic/well base map highlights the area of 3-D coverage, 2-D coverage, attached reference seismic lines, the locations of all key offset wells proximal to the I vik # 1 well location. The referenced pressure/interval velocity exhibit integrates all available geologic, petrophysical, engineering and geophysical information used in our abnormal pressure analysis for the Ivik#l. The exhibit has two plots imbedded in it which display interval velocity and formation pressure on the corresponding "x" axis versus a common increasing depth scale on the "y" axis. Examination of all available velocity, density and pressure data show a general increase of interval velocity and pressure with depth to the limit of penetrated formations below 9800 ft ' within the area. Short discrete velocity reductions on an overall increasil1g trend are observed and are interpreted to represent local variations in formation density, velocity, and lithology. No correlative velocity reversal, "breakback", or "flattening" is observed that could be related to overpressure within any formations above the proposed total depth of7500 f1. This overpressure evaluation is supported by all seismic and offsetting exploratory well data. The key offset wells for planning purposes are highlighted on the aforementioned seismic/well base map. These wells are: Arco-Kalubik #1, Arco-Kalubik #3, Unocal-East Harrison Bay #1, Exxon-Thetis Island #1, Arca-Palm 3W-07, and Arco- West Sak #16. The total depth of these wells ranged from 6166 ft to 9809 ft TVD. All six of these wells were drilled with maximum mud weights ranging from 9.5 ppg to 10.6 ppg. As it is general practice to drill slightly overbalanced, in situ pore pressures are likely less. Bottom-hole formation pressure data collected in these wells from within the Ivishak and Lisboume Formations show a range of equivalent mud weights from 9.3 ppg to 9.6 ppg, which represent a normal pressure gradient to depths . greater than 8000'MD. 1 ! Well Site Survey Abnormal Forma. )ressure Evaluation State Lease ADi389950 ) In summary, abnormal formation pressure is not anticipated at the proposed Ivik #1. All operations and engineering personnel have been advised of these geological drilling safety conditions. ,." . 9-. . ~1~;' ~ !d: --'-" ë1~ (/ . M. . Furin . VICe President of Geoscience Armstrong Oil & Gas November 14, 2002 2 ) ) November 22, 2002 PIONEER NATURAL RESOURCES CANADA INC. Cammy Oechell Taylor Chairman Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Exploration Drilling Permits Ooogaruk #1, Ivik #1 and Natchiq #1 Dear Ms. Taylor Attached are our Permit To Drill applications for three planned exploration tests north of Oliktook Point in the Beaufort Sea. The proposed wells are: Ooogaruk #1 7500PTD in ADL 389954 Ivik #1 7500PTD in ADL 389950 Natchiq #1 7500PTD in ADL 389951 Enclosed with each application is the required $100.00 filing fee. Our intent is to have all permits approved and in hand before comn1encing the required contract awards. The State and North Slope Borough Consistency Determinations have been issued along with / all of the associated permits required in that public process. Should you or staff have any questions please contact Skip Coyner, Natchiq Technical Services at 907-339-6250, or Stu Gustafson at 206-972-1993. SiPCerelY~ j/~. 'J~"l/J // Llljl ..' ~/~ K eth H. Shef leld, Jr. r President Pioneer Natural Resources Alaska, Inc RECEIVED NOV 2 2 2002 , Alaska Oil & Gas Cons. Commission 2900,255 - 5 AVENUE SW, CALGARY, ALBERTA T2r~ 3G6 . BUSINESS (403) 231-3100 . FAX (403) 269-94~ Anchorage ) Attachments: Ooogaruk # 1 Application Package Ivik # 1 Application Package Natchiq #1 Application Package '.. .'. .-.. ..".. ..-...._ ..... .......-. ....-.....-..... ..... ....-.-.-..-.-.-".-.-.-...-.-...... ..... ...-.-.-.-.-..-..C-O:.~.:.-...-...,.. .... "".-".-.-".'.'''''''''''-.:.'.-.:0_. .... ....,.·.:.,.:.-.:00-.·.-.;.·.·.-... ..... ......-.-...,.-........,.-.,.:.-.,.:.. _ ...,.-.-..-.:.-.:....-.,..-.-.-.:.-.. ""I'- ....,.·.-.:.·.-.;00·.'..:.:..·.-.:.,.. .... .....:.:...'.:.-...,..,.....-..:.-.:.,.., _""', NORTHERN CONSULTING GROUP 2454 TELEQUANA DRIVE 243-7716 ANCHORAGE, AK 99517 [',}¡b1\fb\!E 0Tc¿r-e % IJ /tÛl f Q (?P1~ ftu# (4Ul ~ ~ .A I;JRkaUSA Federal Credit Union P.O. Box 196613 . Anchorage, AK 99519-6613 /. - fiJ¿fJ f) FOR l!JilL-toUr{ -!¡0!Jœ¡ I: 31 2 52? 2 0 2 . I: 8 0 III 8 2 ? 8 5 ~ III 2 II- 0328 89-720213252 It ß~. £l:L . c200 2- / I $ 100 ~~ " -(. ---. -~ ffI Tn~~~~¡~~-,ealures ~ DOLLARS ".'. .. .... ¡ íÛJ k~__~ : 0328 -' ........."..........,... ... ............-.-.'.-..-..-.. ...... ...-.,..-........-.....-.:...-.. .... ...:..,.-.-..:..:......:.-.:.:.:.,..,.,..: ..... ....:.-.:.:.:..-..:...:.,.:.~.-..-..,... ...... ·c...:o:.-.,.-.:ö:.-.-.,.:..:.:.,.." ..... ·...:..:.·.,.:--.-...:ù.:.-.:.-.,.,..· ...... .c.:-___:."·.-.:,,.-.:.:.".-.-.,..· ...... ".:.".-.-.:.-.·00'.".-.:.:.·."" -+- ."".:.:...-.:.._...:.,.-.:.,...:...: ...1 "- ) .~ TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERlP ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER ,-;- , k. ::#/ WELL NAME I. II" I 7n2-'-~~ PTD# CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) "CLUE" The permit is for a new wellbore segment of existing well Permit No, API No. Production should continue to be reported as a function· of the original API number stated above. HOLE In accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 70/80) from records, data and logs acquired for well (name on permit). PILOT (PH) SPACING EXCEPTION / DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. ¡r;..".,~:'~'I.,:. ...... ... ......... ...... ........ ..... lM:i.L":~ERMIT CHECKLIST FIELD & POOL COMPANY PIONEER WELL NAME Ivik#1 PROGRAM Exploritory (EXP) ~ Development (DEV) _ Redril---Êervice (SER) _Well bore seg _ Annular disposal para req GEOL AREA 890 UNIT No. Explor. ON/OFF SHORE Off 00000 - Exploratory Initial ClassfType EXP /1-0IL APPR SFD } 1. Permit fee attached ................................................................................................ 2. Lease number appropriate...... ......... ... ... ... ... ......... ......... ... ..................... ............ ...... 3. Unique well name and number ................................................................................. 4. Well located in a defined pool................................................................................... 5. Well located proper distance from drilling unit boundary ................................................. 6. Well located proper distance from other wells... ..................... ............ ...... ..................... DATE 7. Sufficient acreage available in drilling unit.................................................................... $. If deviated, is well bore plat included........................... .................. ... ...... ...... ...... ......... 11/27/2002 9. Operator only affected party..................................................................................... 10. Operator has appropriate bond in force ............ ...... ... ... ... ... ... ... ... ...... ... ... ... ...... ... ... ... 11. Permit can be issued without conservation order.................................... ...... ...... ...... ... 12. Permit can be issued without administrative approval........................... ............ ............ 13. Can permit be approved before 15-day wait......... ......... ......... ............ ... ......... ............ 14. Well located within area and strata authorized by Injection Order # 15. All wells witthin 1/4 mile area of review identified...... .................. ..................... ............ 16. Pre-produced injector: duration of pre-production less than 3 months.............................. 17. ACMP Finding of Consistency has been issued for this project........................... ............ ADMINISTRATION (For Service Well Only) (F or Service Well Only) (For Service Well Only) 18. Conductor string provided....................................................................................... 19. Surface casing protects all known USDWs ................................................................. 20. CMT vol adequate to circulate on conductor & surf csg ...... ... ... ... ......... ...... ................... 21. CMT vol adequate to tie-in long string to surf csg ......................................................... 22. CMT will cover all known productive horizons... ..................... .................. ...... ............. 23. Casing designs adequate for C, T, B & permafrost....................................................... 24. Adequate tankage or reserve pit.............................................................................. 25. If a re-drill, has a 10-403 for abandonment been approved ............................................ 26. Adequate wellbore separation proposed ............... ... ... ......... ...... ...... ... ............ ...... ..... 27. If diverter required, does it meet regulations.................. ........................... ...... ......... ... 28. Drilling fluid program schematic & equip list adequate............... ... ...... ............ .............. DATE 29. BOPEs, do they meet regulation ... ......... ... ...... ... ...... ......... ... ......... ...... ...... ... ... ... ... ... J j 1 j 30. BOPE press rating appropriate; test to ............... ...... ... 3500 psig ... ... ...... ......... ...... fy '-1 0 L.. 31. Choke manifold complies w/API RP-53 (May 84) ............ ......... ... ... ...... ............ ... ........ 32. Work will occur without operation shutdown ............... ......... ... ... .................. ...... .......... 33. Is presence of H2S gas probable ...... ... ... ...... ... ... ... ...... ............... ... ... ...... ...... ...... ..... (F or Service Well Only) 34. Mechanical condition of wells within AOR verified... ......... ............ ........................... ..... ENGINEERING APPR W,6A- GEOLOGY 35. 36. DATE 37. 38. 11/27/2002 39. Permit can be issued w/o hydrogen sulfide measures... ...... ...... ......... ........................... Data presented on potential overpressure zones......... ............ ... ...... ...... ...... ......... ... ... Seismic analysis of shallow gas zones ...... ... ...... ...... ... ...... ... ... ......... ... ... ... ... ......... .... Seabed condition survey (if off-shore) ...... ... ...... ...... ... ...... ...... ......... ......... ... ...... ... ..... Contact name/phone for weekly progress reports [exploratory only] .............................. A::: f GEOLOGY: ENGINERING: RES. ENGINERING: COMMISSION: RPC: TEM: JDH: COT: '2..1z.1 Oz- SFD:~ WGA: X MJW: DTS: I ~Þl./{)¡?/ MLB: /2../0 2-/ c.J 2.. Yes Yes Yes No Yes· Yes Yes NA Yes·' Yes Yes Yes Yes #0328: Northern Consulting Group Exploratory well * However, well is located exactly 500' from West line of Sec. 6, T13N, R8E, a boundary across which ownership changes. A spacing exception will not be needed unless the actual well location encroaches upon the 500' setback buffer. Operator plans to conduct directional surveys and directional drill as needed to honor the 500' buffer (Drilling and Completion Procedure, page 6). Not Applicable, vertical well. ** See note, above. " NA Not Applicable NA Not Applicable NA Not Applicable Yes ACMP Consistency Determination (AK 0208-010G) issued Nov 14, 2002. Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 13-3/8" @ 112'. Surface casing will be set at 3000' MD and TVD and cemented to surface. Well is 5 miles offshore within the Beaufort Sea. SFD Adequate excess planned. Nabors 27E. NA Not Applicable Max MW 10.3 ppg. MSP 2850 psi. ¡( ,. ~ No NA Not Applicable Yes No evidence of H2S in offset exploration wells. Yes Pressure grad. Approx. 0.45 psi/ft from surface to t/HRZ; expected to increase to 0.52 psilft from t/HRZ to TD based on well/seismic data. Yes Minor gas from hydrates expected from b/ Permafrost (1 000' MD/TVD) to 1600' MD/TVD. No other shallow hazards anticipated. NA Not Applicable: well to be drilled from ice island. Yes Skip Coyner, Senior Drilling Engineer, Natchiq Technical Services, 339-6269 Comments/Instructions Directional survey required to ensure that the well does not encroach on the 500' set-back buffer. Well will be mudlogged and gas detectors will be utilized to minimize gas hydrate hazards. ) Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding infonnation, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. ) ) -, U EPOCH ,j U \1 '¡.~ '~' AJasKs \.J¡; .;:: ;.:;,.:.~~:,.;C;'¡~:. CüfnmlS5tOO l;ndlorage JUN 1 7 2003 0) ~~~c· - E1\fED· ~ ~!,¡ ~~::c:.r.J: ' ~§ l"'.D'IIí\' .iIIÐI John Morris - Sr. Logging Geologist Fletcher England - Logging Geologist Barry Wright - Logging Geologist Paul Nielsen - Logging Geologist MARCH 6, 2003 FINAL WELL REPORT ) NORTH SLOPE BOROUGH, AK NORTHWEST KUPARUK PROSPECT WINTER 2003 EXPLORA TION PROGRAM IVIK #1 PIONEER NATURAL RESOURCES 8êJeJ-CJd5 · Pioneer Natural Resources - Ivik #1 ) TABLE OF CONTENTS Pioneer Natural Resources Ivik #1 Exploration - Northwest Kuparuk North Slope Borough, Alaska TABLE OF CONTENTS..................... ................. .............. ....... ..... ... ...... ...... ...... ....... ...... 2 WELL RESU ME.............................................................................................................. 3 WELL SU M MARY. ........... .................. ........ ............. ..... ..... ....... ..... ......... ...... ...... ......... .... 4 FORMATION TOPS.................................... .................................................. .................. 6 DAILY ACTIVITY SUM MARY ......................................................................................... 7 ) RIG TIM E DiSTRIBUTION....... ....................................................................................... 9 LITHOLOGY AND COM M ENTS ................................................................................... 11 SU RVEY IN FORMATION............................................................................................. 24 DAI L Y MUD PROPERTIES..... ..... ............ ........ .............. ... ....... ....... ...... ...... ......... .... .... 25 BIT RECORD................................................................................................................ 26 MORNING REPORTS.............. ........................ ............................... .APPENDIX 1 FI NAL LOGS................................................................................. .AP PEN DIX 2 ) [~ EPOCH 2 1.1 Pioneer Natural Resources - Ivik #1 ) Company: Well: Field: Region: Location: Coordinates: Elevation: County, State: API Index: Spud Date: Total Depth: Contractor: Company Representatives: ) RigfType: Epoch Logging Unit: Epoch Personnel: Company Geologists: Casing Data: Hole size: Mud Type: Logged Interval: Electric Logging Co: ) WELL RESUME Pioneer Natural Resources Ivik#1 Exploration North Slope, Alaska Offshore W of Oliktok Point and S-SW of Thetis Island Y=6,034,820 X=476,790 1450' FSL & 500' FWL of Sec. 6, T13N, R8E, Umiat Meridian Lat 70°30'22.57" Long 150°11 '23.58" RKB 50.0' Ice Pad ± 19.5' North Slope Borough, Alaska 50-703-20436 2/25/03 6943' MD Nabors Alaska Drilling, Inc. Larry Meyers Skip Coyner Nabors 27E, Land #14 John Morris Fletcher England Barry Wright Paul Nielsen Albert Wegelin Rick Geesaman Dick Owens 13 3/8" @ 172' (Conductor) 7 5/8" @ 2996' 9 7/8" to 3020' 6 %" to 6943' KCI Polymer spud to TO 175' to 6943' Schlumberger ~ EPOCH 3 · Pioneer Natural Resources - Ivik #1 WELL SUMMARY ) Pioneer Natural Resources spudded the Ivik #1 exploration well on February 25, 2003 with Nabors Alaska Oriiling, Inc. rig #27E. Ivik #1 is located offshore west of Oliktok Point and south-southwest of Thetis Island on the North Slope of Alaska. The well was drilled as a straight hole with a 9 7/8" bit to surface casing at 2996' MO and 6 %" hole size to TO at 6943' MD. Clays washing out were a minor problem before surface casing was set. No other significant drilling problems were encountered. The primary objective of this well was the Kuparuk "C" sands. Secondary objectives were Middle Brookian, Torok, and Nuiqsut Sand. A 44' core was cut from 6100' to 6144' MD. The Kuparuk C sand was present from 6100' to 6102.3' MO in the core. It was determined that the Kuparuk C sand began at 6098' MO, yielding a 4.3' interval total. It is moderately well cemented sandstone at the top of the cored interval, overlying 41.7' of shale in the remainder of the core. The sandstone is medium to coarse grained, s.lightly pebbly, and very glauconitic. It sharply overlies dark brown, well-indurated shale. ) The Middle Brookian did not yield any more than a trace of sand in cuttings samples, however, C 1 through C5 were present. The Torok target yielded high gas, but only trace sand and abundant siltstone. Maximum gas was 1681u at 5366' MO with the following chromotography in ppm: C1 253309, C217802, C3 8367, C4 3872, C52117. The first significant hydrocarbon show was encountered at 6098' to 6102.3' MD. This was a thin section of the Kuparuk "C" sands as noted above. Maximum gas was 117u at 6099' MO with the following chromotography in ppm: C1 19170, C2 968, C3 356, C4 156, C5 173. Samples yielded 100% bright yellow-gold sample fluorescence, instant bright light yellow cut fluorescence followed by fast streaming cut, pale straw visible cut, light brown residual ring, and moderate to strong bright yellow residual ring fluorescence. The second show was encountered at 6400' to 6480' MD in the Nuiqsut Sand. Maximum gas was 471 u at 6419' MO with the following chromotography in ppm: C175244, C25842, C31841, C41366, C5354. Samples yielded 1000k dull to moderately bright yellow-gold sample fluorescence, instant bright yellow-white cut fluorescence, pale straw visible cut. bright light yellow residual fluorescence, and fair petroleum odor from unwashed sample. ) The final shows were encountered at 6522' to 6556' MO in the Nechelik Sand. Maximum gas was 162u at 6555' MO with the following chromotography in ppm: C1 29494, C21516, C3833, C4 419, C5206. Samples yielded 20% light yellow-gold sample fluorescence, instant moderately bright light yellow cut fluorescence, and moderately bright light yellow residual cut fluorescence. There was no visible oil in samples, and no petroleum odor was noted. [~ EPOCH 4 ) . Pioneer Natural Resources - Ivik #1 The well reached a total depth of 6943' MD on March 5, 2003. Epoch Well Services provided RIGWA TCH 2000™ Drilling Monitoring services and DML TM Mudlogging Service. Hydrogen flame ionization (FID) Total Gas and (FID) Gas Chromatograph detectors were employed to detect and analyze formation gases. Constant mud gas was generated by Texaco's patented Quantitative Gas Measurement (QGMTM) electrically driven gas trap located at the shale shaker header box and extracted continuously from the trap to the unit by sample pumps. The gas trap was frequently cleaned and positioned to obtain optimum sampling! and the gas system was tested and calibrated on a regular basis. Cuttings samples were collected at regular 30' intervals, beginning at 175', as directed by Pioneer Natural Resource's sampling program. ) ) [~ EPOCH 5 · Pioneer Natural Resources - Ivik #1 FORMATION TOPS ) Marker MD INC AZ TVD TVDSS X Y +/- to PROG Sagavanirktok 930 1.30 155.10 929.9 878.9 -15.6 6.3 180 Ugnu 2025 0.70 72.90 2024.8 1973.8 -25.2 15.5 200 West Sak 2370 0.40 182.50 2369.8 2318.8 -25.3 17.8 255 Middle Brookian 4410 1.60 152.20 4409.3 4358.3 -66.9 23.0 60 Torok 5220 1.30 154.50 5219. 1 5168. 1 -84.5 29.4 100 HRZ 5850 0.80 148.29 5849.0 5798.0 -95.0 34.1 -100 Kalubik 5965 0.64 142.65 5964.0 5913.0 -96.0 34.9 -135 Put Mkr 6041 0.60 141.00 6040.0 5989.0 -97.1 35.3 TKUP 6098 0.60 142.30 6097.0 6046.0 -97.5 35.7 -142 LCU? 6160 0.60 143.70 6159.0 6108.0 -98.0 36.1 -200 Nuiqsut 6400 0.60 164.90 6399.0 6348.0 -1 00.0 37.2 -225 Nechelik 6496 0.70 181 .30 6495.0 6444.0 -101.1 37.3 ) ) [~ EPOCH 6 · Pioneer Natural Resources - Ivik #1 DAILY ACTIVITY SUMMARY ) 2/25/03 Pull wear bushing, service rig, pick up BHA, tag bottom at 105', clean to 175'. Pull out of hole, pick up BHA, spud at 09:00. Drill 175' to 509', circulate bottoms up. Pull 4 stands. Survey, change out elevators. Drill 509' to 610'. Service top drive. Drill 610' to 1535'. Circulate and condition mud. Drill 1535' to 1630'. 2/26/03 Drill from 1630' to 1800', circulate for ball mill. Drill from 1800' to 3020' surveying every 300'. Circulate at 3020' for short trip. POOH 3020' to 2766'. Back ream 2766' to 1630'. POOH 1630' to 1162', no problems. RI H 1162' to 2808'. Wash and ream 2808' to 3020'. Circulate and bring casing tools onto rig floor. POOH from 3020' to 1346', no problems. POOH. Stand back heavy weight drill pipe. Stand back 6 1/2" drill collars. Lay down BHA. Download MWD. ) 2/27/03 Circulate and condition mud for cement job. Cement casing. Rig down casing tools. RIH with pack-off and test to 5000 psi for 10 minutes. Pick up 4 3/4" drill collars and make up tam port collar running tool. Open port collar and circulate clean. Pump calcium chloride around port collar. Stand back drill collar. Lay down casing tools. 2/28/03 Nipple down diverter, nipple up BOP equipment. Test BOP equipment. Pick up BHA, pick up 3 1/2" drill pipe. RIH to casing shoe. Cut and slip drilling line. 3/01/03 Cut and slip drilling line. Drill float collar at 2914'. Wash to 2968'. Drill casing shoe at 2996'. Wash to 3020'. Drill to 3030'. Circulate bottoms up. Pull into casing and perform leak off test (16.4 ppg equivalent). Drill from 3030' to 3821', packing off on back ream. 3/02/03 Pull out of hole from 4925' to 2306', wet trip. Service top drive. Hang bell ringer. Pick up 21 joints of 3 1/2" drill pipe. Run into hole to 4925'. Trip gas 600 units. Drill 4925' to 5525'. Max gas 1700 units. Pack off at 500' and 5174'. Drill 5525' to 6100'. Max gas 1050 units. Circulate and condition mud, circulate sweep. Pull out of hole from 6100' to 4294', no problems. Run into hole from 4294' to 6100'. Wash and ream last stand, no problems. Circulate and condition mud, circulate sweep, spot pill on bottom. Pull out of hole from 6100' to 2779" no problems. Monitor well at casing shoe. ) ~ EPOCH 7 · Pioneer Natural Resources -Ivik #1 ) 3/03/03 Pull out of hole. Pick up coring assembly. Run into hole. Wash down one stand to 6100'. Circulate. Begin cutting Core #1. 3/04/03 Core to 6144'. Pull out of hole. Lay down core barrel. Pick up bit, and directional/logging tools. Surface test, upload MWD data. Run into hole. Circulate, perform measurement after drilling pass. Drill to 6470' 3/05/03 Drill to TD at 6943'. Pump sweep. Circulate hole clean. Wipe hole. Circulate hole clean. Pull out of hole. Rig up and run electric logs. ) .,) [j EPOCH 8 · Pioneer Natural Resources - Ivik #1 RIG TIME DISTRIBUTION Drill Circulate Trip Service Survey Casing & Core Ream Test Logging Repair Oth er Total Rig Cmting 02/25/03 1 1 1 10 0.5 0.5 1 24 02/26/03 1 1 2.5 9 2 24 02/27/03 3 1 1 1 9 24 02/28/03 7.5 5.5 1 1 24 03/01/03 17 1 6 24 03/02/03 13 2 8 1 24 03/03/03 8.5 15.5 24 03/04/03 4 0.5 6.5 13 24 03/05/03 6.5 6 6 5.5 24 Totals 62 15.5 50 2 0.5 11 22 2 5.5 5.5 1 39 216 ~ EPOCH 9 ~ '~ ---' II Pioneer Natural Resources - Ivik #1 Rig Time Distribution Casing & Cmting 5% Other 18% Repair 0% Ii Drill · Ci rculate DTrip o Rig Svc. · Survey iii Casing & CfT · Core DReam · Test · Logging o Repair II Other Test 3% Ream 1% Rig Svc. 1% Trip 23% U EPOCH 10 ~. '.--/ '-' II Pioneer Natural Resources - Ivik #1 ( LITHOLOGY AND COMMENTS 185' Clay Olive gray to dark greenish gray; very soft; thick; sticky; appears as amorphous lumps; dries to matte, earthy luster; moderately silty texture; non calcareous; scattered very fine sand grains; scattered to common organic material. 225' Sand/gravel Light gray to black, mod brown to dusky yellowish brown, becoming increasingly lighter colored with depth. Upper part is dominantly coarse to pebble size grains; angular to well rounded; poorly sorted; composed of 30% quartz and other siliceous minerals, 70% mafic and metamorphic minerals; trace clusters of microcrystalline pyrite; clay matrix. 280'Sand Light gray to white overall with slight salt and pepper appearance; clasts range from very fine lower to coarse upper, dominantly very fine to fine range; subangular to subround; mod sorted in the very to fine range; composed of 70% quartz, 30% metamorphic and volcanic lithics; silty matrix. 325' Clay Light gray with slight olive hues; very soft; thick to fluffy; pasty; mod to very adhesive; mostly as soft amorphous lumps; dries to earthy luster; mod silty texture; non calcareous; scattered to common black carbonaceous material; locally silty, scattered very fine sand grains. ( 370' Sand Light gray to white overall with salt and pepper appearance; clasts range from very fine lower to coarse upper, dominantly very fine to fine range; subangular to subround; mod sorted in the very to fine range; composed of 60% quartz, 40% metamorphic and volcanic lithics; silty, argillaceous matrix. 415' Clay Light gray with occasional brown hues; very soft; thick, fluffy, occasionally runny; mod to very adhesive; mostly as soft amorphous lumps; dries to earthy luster; very silty texture; non calcareous; scattered to common black carbonaceous material; locally common very fine to medium sand grains. 460' Sand Dominantly light gray overall; clasts range from very fine to coarse, dominantly fine grain; angular to rounded, dominantly subangular to subround; moderately sorted; composed of 70% quartz, 30% lithics; trace clusters of microxln pyrite; clay/silt matrix inferred. 500' Clay Light brownish gray to brownish gray with olive gray secondary hues; very soft; mushy to runny consistency; no noticeable fracture; amorphous cuttings habit; dull, earthy luster; clayey to gritty texture; non calcareous scattered to common black carbonaceous material; common very fine to medium sand grains. ( 550' Sand Light gray overall; common salt and pepper appearance; very fine to coarse lower; dominantly medium lower with trace of very coarse conglomerate grains subangular to subrounded; moderate sphericity overall; poor to fair sorting polished occasionally frosted texture; present as unconsolidated loose grains; approximately 50-70% quartz, 30-50% various dark gray to black lithic clasts, trace wood in samples; probable clayey matrix in part; non calcareous; no sample fluorescence. (j EPOCH 11 II Pioneer Natural Resources - Ivik #1 (" 620' Clay Light brownish gray to brownish gray with olive gray secondary hues; very soft; mushy to runny consistency; no noticeable fracture; amorphous cuttings habit; dull, earthy luster; clayey to gritty texture; non calcareous to trace very slight HCI reaction; scattered to common black carbonaceous material; common very fine to medium sand grains entrained in cuttings. 675' Siltstone Light brownish gray to brownish gray overall with occasional olive gray secondary hues; mostly loose clasts with mushy to stiff consistency; trace well indurated cuttings with very tough and crunchy tenacity; blocky to earthy fracture; tabular to blocky cuttings habit; dull, earthy luster; silty to slightly gritty texture; massive bedding; vigorous calcareous reaction on fresh surfaces. 735' Clay Light brownish gray to brownish gray with olive gray secondary hues; very soft; mushy to runny consistency; no noticeable fracture; amorphous cuttings habit; dull, earthy luster; clayey to gritty texture; non calcareous to trace very slight HCI reaction; scattered to common black carbonaceous material; common very fine to medium sand grains entrained in cuttings. 790' Clay Light brownish gray to brownish gray with olive gray secondary hues; very soft; mushy to runny consistency; no noticeable fracture; amorphous cuttings habit; dull, earthy luster; clayey to gritty texture; non calcareous to trace very slight HCI reaction; scattered to common black carbonaceous material; occasional very fine to fine sand grains entrained in cuttings. ( 845' Clay Light brownish gray to brownish gray with olive gray secondary hues; very soft; mushy to runny consistency; no noticeable fracture; amorphous cuttings habit; dull, earthy luster; clayey to gritty texture; non calcareous to trace very slight HCI reaction; scattered to common black carbonaceous material; occasional very fine to fine sand grains entrained in cuttings. 900' Clay Light brownish gray to brownish gray with olive gray secondary hues; very soft; mushy to runny consistency; no noticeable fracture; amorphous cuttings habit; dull, earthy luster; clayey to gritty texture; non calcareous to trace very slight HCI reaction; scattered to common black carbonaceous material; occasional very fine to fine sand grains entrained in cuttings. 955' Sand Medium gray overall; common salt and pepper appearance with a variety of colors ¡nlarger grains; very fine to pebble sized grains; subangular to rounded, most pebbles well rounded moderate sphericity overall with individual clasts of high sphericity; poor1y sorted; present as unconsolidated loose grains of quartz and a variety of chert, igneous and metamorphic lithics. 1010' Sand Medium gray overall; common salt and pepper appearance with a variety of colors in larger grains; very fine to pebble sized grains; subangular to rounded, most pebbles well rounded moderate sphericity overall with individual clasts of high sphericity; poor1y sorted; present as unconsolidated loose grains of quartz and a variety of chert, igneous and metamorphic lithics. 1065' Clay Light brownish gray to brownish gray with olive gray secondary hues; very soft; mushy to runny consistency; no noticeable fracture; amorphous cuttings habit; dull, earthy luster, clayey to gritty texture; non calcareous to trace very slight HCI reaction; scattered to common black carbonaceous material; common fine to medium sand grains entrained in cuttings. ( 1120' Sand Light gray overall; common salt and pepper appearance; very fine to very coarse; dominantly fine with continued trace of rounded pebble size grains subangular to subrounded; moderate sphericity overall; poor to fair sorting polished occasionally frosted texture; present as unconsolidated loose grains; approximately 50-70% quartz, 30-50% various dark gray to black [J EPOCH 12 · Pioneer Natural Resources - Ivik #1 lithic clasts, trace massive pyrite in samples; probable clayey matrix in part; non calcareous; no sample fluorescence. ( 1190' Clay Light brownish gray to brownish gray with olive gray secondary hues; very soft; mushy to pasty consistency; no noticeable fracture; amorphous cuttings habit; dull, earthy luster; clayey to gritty texture; non calcareous to trace very slight HCI reaction; scattered to common black carbonaceous material; common very fine to medium sand grains entrained in cuttings. 1245' Clay Light brownish gray to brownish gray with olive gray secondary hues; very soft; mushy to pasty consistency; no noticeable fracture; amorphous to blocky cuttings habit; dull earthy luster; clayey to gritty texture; non calcareous to trace very slight HCI reaction; scattered to common black carbonaceous material; common very fine to coarse sand grains entrained in cuttings. 1305' Sand Light gray overall; common salt and pepper appearance; very fine to very coarse; dominant fine upper with abundant rounded pebble size grains; subangular to subrounded; moderate sphericity overall; poor to fair sorting polished occasionally frosted texture; present as unconsolidated loose grains; approximately 50-70% quartz, 30-50% various dark gray to black lithic clasts and chert probable clay matrix in part; non calcareous; no sample fluorescence. 1370' Clay Light brownish gray to brownish gray with olive gray secondary hues; very soft; mushy to pasty consistency; no noticeable fracture; amorphous cuttings habit; dull, earthy luster; clayey to gritty texture; non calcareous to trace very slight HCI reaction; scattered to common black carbonaceous material; common very fine to medium sand grains entrained in cuttings. ( 1425' Sand Light gray to light brownish gray overall with individual translucent to clear grains of quartz and opaque lithic clasts yielding a common salt and pepper appearance; very fine to very coarse grain size with a dominant medium lower fraction; angular to subrounded; moderate to low sphericity; poor to fair sorting; chipped to frosted texture; present as unconsolidated loose grains; approximately 50-70% quartz and 30-50% gray to black lithic clasts and chert; probable grain support with clay matrix in part; non calcareous; continue trace to 10% pebble clasts increasing to 40% @ 1470'; no sample fluorescence. 1515' Clay Light brownish gray to brownish gray with occasional olive gray secondary hues; mushy to slightly finn consistency; earthy to blocky fracture when finn; blocky cuttings habit; dull, earthy luster; silty to gritty texture; massive structure; commonly contains grains of very fine to medium lower sand; commonly grading to siltstone in part; non calcareous. 1570' Clay Light brownish gray to brownish gray overall; mushy to slightly finn consistency; blocky cuttings habit; earthy to irregular fracture; dull, earthy luster; silty to gritty texture; commonly grading to siltstone in part. 1620' Sand/gravel Light gray to black, light to dark greenish gray, occasional yellow and brownish hues, clear and milky white; clasts range from very fine upper to pebbles; angular to well rounded; poorly sorted; dominantly grain size is coarse or larger; composed of 30% quartz and other siliceous minerals, 70% mafics and metamorphic lithics; traces of coal and other carbonaceous matter; loose in samples but clay/silt matrix inferred; no oil indicators. ( 1685' Clay Light gray with slight olive hues and brownish hues; very soft; thi'ck; fluffy to pasty consistency; sticky; moderately cohesive; matte, earthy luster when dry; gritty, silty texture; scattered to common black carbonaceous matter; occasionally has dull yellow mineral fluorescence. ~ EPOCH 13 IJ Pioneer Natural Resources -Ivik #1 ( 1730' Sandlgravel Light gray to black, light to dark greenish gray, scattered yellow and brownish hues, common clear and white; clasts range from very fine upper to pebbles; angular to well rounded; poorly sorted; dominantly grain size is coarse or larger; composed of 30% quartz and other siliceous minerals, 70% mafics and metamorphic lithics; traces of coal and other carbonaceous matter; loose in samples but clay/silt matrix inferred; trace amounts of dull yellow mineral fluorescence; no oil indicators present. 1805' Clay Light gray with slight olive hues and brownish hues; very soft; thick; fluffy to pasty consistency; sticky; moderately cohesive; matte, earthy luster when dry; gritty, silty texture; scattered to common black carbonaceous matter; occasionally has dull yellow mineral fluorescence. 1850' Sand/gravel Light gray to black, light to dark greenish gray, scattered yellow and brownish hues, common clear and white; clasts range from very fine upper to pebbles; angular to well rounded; poorly sorted; dominantly grain size is coarse or larger; composed of 30% quartz and other siliceous minerals, 70% mafics and metamorphic lithics; traces of coal and other carbonaceous matter; loose in samples but clay/silt matrix inferred; trace amounts of dull yellow mineral fluorescence; no oil indicators present. ( 1925' Siltstone Light to medium gray I medium brownish gray; very soft to soft; mushy to crumbly; irregular and occasionally subblocky cuttings; matte luster with common sparkles; gritty, grainy texture; non calcareous; argillaceous, grades to and is interbedded with claystone; common carbonaceous matter, traces of coal free in sample; trace amounts of dull yellow minera,1 fluorescence; 10caUy common very fine sand grains disseminated throughout. 2010' Sand/conglomerate Light gray to dark gray, black, white, clear; clasts range from very fine upper to pebbles; angular to rounded; common bit sheared grains; scattered pitted grains; poorly sorted; composed of 60% quartz and other siliceous minerals, 40% metamorphic lithics and mafic lithics; trace cluste'rs of microcrystalline pyrite; grains are loose in sample but probably have a clay/silt matrix in situ. 2070' Sand Medium gray overall; light to dark gray, clear, white, black, light to medium greenish gray; clasts range from fine lower to coarse upper, dominantly medium to coarse; angular to subround; moderately sorted in the medium to coarse range; composed of 60% quartz, 40% mafics and metamorphic lithics; appears clean in samples; estimated fair to good porosity and permeability; no oil indicators. 2130' Sand Continues as described above, becomes increasingly coarse with approximately 10 to 20% of the sample in the granule or larger (up to pebble size). 2160' Claystone Light to medium brownish gray, occasionally with slight olive hues; very soft: to soft; increasingly indurated with depth; now crumbly to mushy; irregular cuttings, rarely with subblocky habit; matte, earthy luster; smooth to moderately gritty texture; non calcareous; common black carbonaceous matter; occasional traces of dusky brown to lignite coal; locally silty, grading in part and interbedded with siltstone. ( 2220' Sand/conglomerate Medium gray to dark gray overall; grains are black, light to dark gray, clear, white, occasionally light to medium greenish gray; clasts range from fine lower to pebbles, dominantly medium to coarse grained; angular to well rounded with common bit sheared grains; poor sorting overall; mod sorted in the medium to coarse range; 50% quartz and other siliceous minerals; 50% mafics [j EPOCH 14 II Pioneer Natural Resources - Ivik #1 and metamorphic lithics; trace cluster of microxln pyrite; trace of clear mica flakes; grains are loose in sample, probably with a clay/ silt matrix in situ; no oil indicators. ( 2300' Sand/conglomerate Medium gray to dark gray overall; grains are black, light to dark gray, clear, white, occasionally light to medium greenish gray; clasts are fine to pebble size in total range; most are in the medium to coarse range; angular to rounded; common bit broken grains; poor sorting overall; mod sorted in the medium to coarse range; 50% quartz and other siliceous minerals; 50% mafics and metamorphic lithics; trace cluster of microxln pyrite; trace of clear mica flakes; grain size in general is increasing with depth. 2380' Sandlconglomerate Medium gray to dark gray overall; grains are black, light to dark gray, clear, white, occasionally light to medium greenish gray; clasts range from fine to pebble size; most commonly men to coarse; angular to rounded; common shards from bit action; poor sorting overall; mod sorted in the medium to coarse range; 50% quartz and other siliceous minerals; 50% mafics and metamorphic lithics; traces of pyrite and mica flakes; grain size continues to increase with depth. 2455' Siltstone Light gray to occasionally mod brownish gray; very soft to soft, rarely slightly firm; smaU amorphous or rarely subblocky cuttings; matte luster with scattered sparkles; gritty texture; non calcareous; locally common very fine to fine sand grains; scattered to common carbonaceous matter; occasionally appears darker brown and more organic; argillaceous--grades to and is interbedded with claystone. ( 2515' Claystone Light to medium brownish gray; very soft to soft; mushy to rarely crumbly; appears as amorphous clay lumps and as irregular poorly indurated cuttings; earthy luster; smooth to mod gritty texture; non calcareous; scattered to abundant black carbonaceous matter; silty in part; grades to and is interbedded with claystone; no oil indicators. 2570' Siltstone Light gray to occasionally mod brownish gray; very soft to soft, rarely slightly firm; smaU amorphous or rarely subblocky cuttings; matte luster with scattered sparkles; gritty texture; non calcareous; locally common very fine to fine sand grains; scattered to common carbonaceous matter; occasionally appears darker brown and more organic; abundant clay; grades to claystone. 2630' Claystone Light to medium brownish gray; very soft to soft; mushy to rarely orumbly; appears as amorphous clay lumps and as irregular poorty indurated cuttings; earthy luster; smooth to mod gritty texture; non calcareous; scattered to abundant black carbonaceous matter; silty in part; grades to and is interbedded with claystone; trace white clay mineral. 2685' Siltstone Light gray to occasionally mod brownish 'gray; very soft to soft, rarely slightly firm; smaJl amorphous or rarely subblocky cuttings; matte luster with scattered sparkles; gritty texture; non calcareous; locally common very fine to fine sand grains; scattered to common carbonaceous matter; occasionally appears darker brown and more organic; argillaceous--grades to and is interbedded with claystone. 2745' Claystone Light to medium brownish gray; very soft to soft; mushy to rarely crumbly; appea:rs as amorphous clay lumps and as irregular poorty indurated cuttings; earthy luster; smooth to mod gritty texture; non calcareous; scattered to abundant black carbonaceous matter; silty in part; grades to and is interbedded with claystone. ( 2800' Siltstone Light gray to occasionally mod brownish gray; very soft to soft, rarefy slightly firm; small amorphous or rarely subblocky cuttings; matte luster with scattered sparkles; gritty texture; non [:I EPOCH 15 ( II Pioneer Natural Resources - Ivik #1 calcareous; locally common very fine to fine sand grains; scattered to common carbonaceous matter; occasionally appears darker brown and more organic; argillaceous--grades to and is interbedded with claystone. 2860' Claystone Light to medium brownish gray; very soft to soft; mushy to crumbly; dominantly appears as amorphous clay lumps and as irregular poorly indurated cuttings; earthy luster; smooth to mod gritty texture; non calcareous; scattered to abundant black carbonaceous matter, silty in part; grades to and is interbedded with claystone; no oil indicators. 2915' Siltstone Light gray to occasionally mod brownish gray; very soft to soft, rarely slightly firm; small amorphous or rarely subblocky cuttings; matte luster with scattered sparkles; gritty texture; non calcareous; locally common very fine to fine sand grains; scattered to common carbonaceous matter; occasionally appears darker brown and more organic; argillaceous--grades to and is interbedded with claystone. 2975' Claystone Light to medium brownish gray; very soft to soft; mushy to crumbly; dominantly appears as amorphous clay lumps occasionally as irregular shaped poorly indurated cuttings; earthy luster; smooth to mod gritty texture; non calcareous; scattered to abundant black carbonaceous matter; silty in part; grades very argillaceous siltstone. 3050' Claystone Brownish gray, occasionally with slight olive hues; very soft to soft; crumbly; weak poorly indurated subblocky and irregularly shaped cuttings; earthy luster; smooth to slightly gritty texture; non calcareous; trace amounts of pale yellowish brown shell fragments; trace amounts of light gray clay mineral probably devitrified ash fall tuff. ( 3100' Siltstone Brownish gray, light gray, occasionally with slight olive hues; soft; crumbly; irregular cuttings with rounded edges; matte luster with scattered sparkles; gritty texture; non calcareous; argillaceous; grades to and is interbedded with claystone; scattered to common black specks and strea'ks; scattered micro fine mica disseminated throughout. 3155' Claystone Increase in olive fraction; continues mostly medium brownish gray; soft, rarely slightly firm; crumbly; tabular and subblocky cuttings; matte luster; smooth to slightly gritty texture; non calcareous; locally silty, grading in part to siltstone; scattered black carbonaceous specks; rare light gray specks of ashy appearing clay mineral. 3205' Tuff White to very light gray, occasionally with slight yellow and blue hues; 50ft; crumbly; slightly resinous luster; smooth to mod gritty texture; non calcareous; appears as clay mineral with scattered to common light to medium gray ashy streaks; scattered very fine glass shards; common black pinpoint specks; light yellow mineral fluorescence; no apparent oil indicators. 3260' Siltstone Brownish gray, light gray, occasionally with slight olive hues; soft; crumbly; irregular cuttings with rounded edges; matte luster with scattered sparkles; gritty texture; non calcareous; argillaceous; grades to and is interbedded with claystone; scattered to common black specks and streaks; scattered micro fine mica disseminated throughout. ( 3315' Claystone Medium brownish gray; decrease in olive fraction; continues soft, rarely slightly firm; crumbly; tabular and subblocky cuttings; matte luster; smooth to slightly gritty texture; non calcareous; locally silty, grading in part to siltstone; scattered black carbonaceous specks; occasionall'ight gray specks of ashy appearing clay mineral. U EPOCH 16 II Pioneer Natural Resources - Ivik #1 ( 3365' Tuff White to very light gray, occasionally with slight yellow and blue hues; soft; crumbly; slightly resinous luster; smooth to mod gritty texture; non calcareous; appears as clay mineral with scattered to common light to medium gray ashy streaks; scattered very fine glass shards; common black pinpoint specks; dull light yellow mineral fluorescence; no apparent oil indicators. 3420' Siltstone Light gray, medium brownish gray, occasionally with slight olive hues; soft to slightly firm; crumbly; subblocky and irregular habit; matte luster with scattered micro sparkles; non calcareous; com black specks; scattered micro mica flakes; argillaceous, grading to claystone; no oil indicators. 3465' Claystone Light to medium brownish gray; rarely with olive hues, occasionally reddish; soft, to occasionally slightly firm; crumbly; tabular and subblocky cuttings; matte luster; smooth to slightly gritty texture; non calcareous; locally silty, grading in part to siltstone; scattered black carbonaceous specks; occasional light gray specks of ashy appearing clay mineral. 3515' Siltstone Light gray to occasionally mod brownish gray; very soft to soft, rarely slightly firm; small amorphous or rarely subblocky cuttings; matte luster with scattered sparkles; gritty texture; non calcareous; locally common very fine to fine sand grains; scattered to common carbonaceous matter; occasionally appears darker brown and more organic; argillaceous; grades to and is interbedded with claystone. ( 3575' Claystone Brownish gray, occasionally with slight olive hues; very soft to soft; crumbly; weak poorly indurated subblocky and irregularly shaped cuttings; earthy luster; smooth to slightly gritty texture; non calcareous; trace amounts of pale yellowish brown shell fra'gments; trace amounts of light gray clay mineral probably devitrified ash fall tuff. 3625' Siltstone Brownish gray, light gray, occasionally with slight olive hues; soft; crumbly; irregular cuttings with rounded edges; matte luster with scattered sparkles; gritty texture; non calcareous; argillaceous; grades to and is interbedded with claystone; scattered to common black specks and streaks; scattered micro fine mica disseminated throughout. 3680' Claystone Light to medium brownish gray; rarely with olive hues, occasionally reddish; soft, to occasionally slightly firm; crumbly; tabular and subblocky cuttings; matte luster; smooth to slightly gritty texture; non calcareous; 10caUy silty, grading in part to siltstone; scattered black 'carbonaceous specks; occasional light gray specks of ashy appearing clay mineral. 3745' Siltstone Brownish gray to medium dark gray with olive gray secondary hues; crumbly to soft, occasionally firm; subblocky to earthy fracture; fracture; subblocky to irregular cuttings with common rounded edges; earthy to matte luster; gritty to silty texture; argillaceous; non calcareous; abundant scattered black specks and black streaks/microlaminae; scattered microfine micas; commonly grades to and is interbedded with claystone. ( 3810' Claystone Light brownish gray to brownish gray with common olive gray secondary hues; mushy to runny in samples, occasionally slightly firm; earthy to irregular fracture when firm; amorphous to subblocky cuttings with rounded edges; dull, earthy to slightly greasy luster; clayey to silty texture; massive bedding; non calcareous commonly 'grades to and is interbedded with siltstone; continue trace to 10% ashy material. [~ EPOCH 17 · Pioneer Natural Resources - Ivik #1 ( 3875' Siltstone Brownish gray to medium dark gray with olive gray secondary hues; crumbly to soft, occasionally firm; subblocky to earthy fracture; fracture; subblocky to irregular cuttings with common rounded edges; earthy to matte luster; gritty to silty texture; argillaceous; non calcareous; abundant scattered black specks and black streaks/microlaminae; scattered microfine micas; commonly grades to and is interbedded with claystone; trace fine sand grains in samples. 3945' Tuff White to very light gray, occasionally with slight yellowish and bluish hues; soft to crumbly, occasionally firm; slightly resinous to greasy luster; smooth, clayey to moderately gritty texture non calcareous; commonly interbedded with claystone or as clay mineral in claystone with scattered light to medium gray streaks; scattered very fine glass; common black specks; dull light yellow mineral fluorescence. 4010' Siltstone Brownish gray to medium dark gray with olive gray secondary hues; crumbly to soft, occasionally firm; subblocky to subplanar fracture; fracture; subblocky to subtabular cuttings with common rounded edges; earthy to matte luster; gritty to silty texture; argillaceous; non calcareous; abundant scattered black specks and black to brown microlaminae/streaks; scattered microfine micas; commonly grades to and interbedded with claystone rare trace of slightly firmer cuttings continue trace to 10% ash in samples. 4085' Claystone Light brownish gray to brownish gray with common olive gray secondary hues; mushy to runny in samples, occasionally slightly firm; earthy to irregular fracture when firm; amorphous to subblocky cuttings with rounded edges; dull, earthy to slightly greasy luster; clayey to silty texture; massive bedding; non calcareous commonly grades to and is interbedded with siltstone; continue trace to 10% ashy material. ( 4150' Tuff White to very light gray, occasionally with slight yellowish and bluish hues; soft to crumbly, occasionally firm; slightly resinous to greasy luster; smooth, clayey to moderately gritty texture non calcareous; commonly interbedded with claystone or as clay mineral in claystone with scattered light to medium gray streaks; scattered very fineg'lass; ,common black specks; trace dull light yellow mineral fluorescence. 4215' Claystone Light brownish gray to brownish gray with common olive gray secondary hues; mushy to runny in samples, occasionally slightly firm; earthy to irregular fracture when firm; amorphous to subblocky cuttings with rounded edges; dull, earthy to slightly greasy luster; clayey to silty texture; massive bedding with occasional microlaminae; commonly grades to siltstone in part; interbedded with very silty claystone and tuff; non calcareous continue trace dull yellow mineral fluorescence. 4290' Claystone Light brownish gray to brownish gray with common olive gray secondary hues; mushy to runny in samples, occasionally slightly firm; earthy to irregular fracture when firm; amorphous to subblocky cuttings with rounded edges; dull, earthy to slightly greasy luster; clayey to silty texture; massive bedding with occasional microlaminae; commonly grades to siltstone in part; interbedded with very silty claystone and tuff; non calcareous to moderate HCI reaction, especially on bluish, darker gray cuttings; continue trace dull yellow fluorescence. ( 4370' Siltstone Brownish gray to medium dark gray with olive gray secondary hues; crumbly to soft, occasionally firm; trace tough cuttings; subplanar to subblocky fracture; subblocky to subtabular cuttings with commonly rounded edges; earthy to matte luster; silty to smooth texture, slightly gritty in darker gray, tough cuttings; argillaceous; non calcareous; abundant scattered black specks and black to brown microlaminae/streaks; laminations better developed than above; scattered microfine micas; commonly grades to and interbedded with claystone continue trace to 10% ash in samples. U EPOCH 18 LI Pioneer Natural Resources - Ivik #1 (" 4455' Claystone Brownish gray to light brownish gray with common olive gray secondary hues; mushy to runny in samples, occasionally slightly firm; earthy to irregular fracture when firm; amorphous to subblocky cuttings with rounded edges; dull, earthy luster; clayey to silty texture; massive bedding with occasional microlaminae, especially when silty; commonly grades to siltstone in part; interbedded with very silty claystone; non calcareous to slight HCI reaction, especially on cuttings with ash; continue trace dull yellow mineral fluorescence. 4535' Tuff White to very light gray, occasionally with slight yellowish and bluish hues; soft to crumbly, occasionally firm; slightly resinous to greasy luster; smooth, clayey to moderately silty texture non calcareous; commonly interbedded with claystone or as clay mineral in claystone with scattered light to medium gray streaks; scattered very fine glass; common black specks; trace dull light yellow mineral fluorescence. 4600' Siltstone Brownish gray to medium dark gray with olive gray secondary hues; crumbly to soft, occasionally firm; trace tough cuttings; subplanar to subblocky fracture; subblocky to subplaty cuttings with . commonly rounded edges; earthy to matte luster; silty to smooth texture, trace slightly gritty cuttings; argillaceous; non to slight calcareous, especially when firm; abundant scattered black specks and black to brown microlaminae/streaks; continued better developed laminae with occasionally fissile cuttings; scattered microfine micas; commonly grades to and interbedded with claystone continue trace to 10% ash in samples; note rare trace of tough, translucent, amber- colored carbonate with vigorous HCI reaction and well-developed parallel crystal growth, possible fracture filling. ( \ 4715' Claystone Brownish gray to light brownish gray with common olive gray secondary hues; mushy to runny in samples, occasionally slightly firm; earthy to irregular fracture when firm; amorphous to subblocky cuttings with rounded edges; dull, earthy luster; clayey to silty texture; massive bedding with occasional microlaminae, especially when silty; commonly grades to siltstone in part; interbedded with very silty claystone; non calcareous to slight HCI reaction. 4785' Siltstone Brownish gray to medium dark gray with olive gray secondary hues; soft to firm, occasionally hard; trace brittle cuttings; subplanar to subblocky fracture; subblocky to subplaty cuttings with commonly rounded edges; earthy to matte luster, occasionally slightly vitreous on hard cuttings; silty texture with occasional gritty cuttings; continue argillaceous; non to slight calcareous, especially when associated with ash; continue abundant scattered black specks and black to brown microlaminae; occasional slightly fissile cuttings; scattered microfine micas; commonly grades to and is interbedded with claystone and ash; note trace firm cuttings with silty matrix, very fine to medium grains of pulverized quartz/silica, and blebs of white to beige ash; also note trace to 10% translucent white to grayish black very hard, brime chert; infer harder siltstone cuttings silicified; chert associated with slow ROP. 4930' Claystone Light to medium brownish gray, occasionally light to medium gray; very soft to soft; mushy; moderate to very soluble; common amorphous lumps; dries to earthy luster; smooth to slightly silty texture; non calcareous; common moderate to dark brown translucent organic appearing blebs; common black to dusky brownish black carbonaceous matter; scattered to common 'light gray ashy appearing tuff blebs; scattered to common amber colored translucent specks, possible mud additive 5000' Siltstone Light gray to white, light to medium brownish gray; soft to occasionally firm; mushy to crumbly; subtabular and subblocky cuttings; matte luster with scattered micro sparkles; non to rarely slightly calcareous; argillaceous, grades in part to claystone; locally common ashy blebs and streaks; scattered microfine mica; common black pinpoint carbonaceous specks [j EPOCH 19 II Pioneer Natural Resources - Ivik #1 (' 5055' Claystone Light to medium brownish gray, occasionally light to medium gray; very soft to soft; mushy; moderate to very soluble; common amorphous lumps; dries to earthy luster; smooth to slightly silty texture; non calcareous; common moderate to dark brown translucent organic appearing blebs; common black to dusky brownish black carbonaceous matter, scattered to common light gray ashy appearing tuff blebs; scattered to common amber colored translucent specks, possible mud additive 5140' Siltstone Light gray to white, light to medium brownish gray; soft to occasionally finn; mushy to rarely moderately brittle; subtabular and subblocky cuttings; matte luster with scattered micro sparkles; non to rarely slightly calcareous; argillaceous, grades in part to claystone; locally common ashy blebs and streaks; scattered microfine mica; common black pinpoint carbonaceous specks 5195' Claystone Light to medium brownish gray, occasionally light to medium gray; very soft; fluffy; moderate to very soluble; common amorphous lumps; dries to earthy luster; smooth to slightly silty texture; non calcareous; common moderate to dark brown translucent organic appearing blebs, possibly mud additive; common black specks of carbonaceous matter 5250' Siltstone Light to medium gray, light to medium brownish gray; soft to rarely slightly finn; small irregular and subblocky cuttings; matte luster with scattered to common micro sparkles; common carbonaceous specks; trace amounts of very fine sand disseminated throughout; occasionally appears ashy; 100% dull yellow to dull gold sample fluorescence; slow blooming moderate bright light yellow cut fluorescence; moderate bright light yellow residual cut fluorescence; no staining is visible on cuttings; no visible cut ring in white ( 5320' Claystone Light to medium brownish gray, occasionally light to medium gray; very soft; fluffy; moderate to very soluble; common amorphous lumps; dries to earthy luster; smooth to slightly silty texture; non calcareous; common moderate to dark brown translucent organic appearing blebs, possibly mud additive; common black specks of carbonaceous matter; show continues as above with unifonn fluorescence on both siltstone and claystone cuttings 5390' Siltstone Light to medium gray, light to medium brownish gray; soft to rarely slightly finn; small irregular and subblocky cuttings; matte luster with scattered to common micro sparkles; common carbonaceous specks; trace amounts of very fine sand disseminated throughout; occasionally appears ashy; 100% dull yellow to dull gold sample fluorescence; slow blooming moderate bright light yellow sample fluorescence; moderate bright light yellow residual cut fluorescence; no staining visible on cuttings; no visible cut ring in white light 5460' Claystone Brownish gray to light brownish gray with olive hues; soft to slightly finn; earthy to irregular fracture when finn; amorphous to subblocky cuttings habit; dull, earthy to slightly greasy luster, especially when ashy; clayey to silty texture; commonly grades to siltstone in part; infer interbedded with siltstone; non to very slightly calcareous; continue faint dull yellow sample fluorescence ( 5520' Siltstone Brownish gray to light brownish gray with yellowish brown secondary hues; crumbly to slightly finn; irregular to subblocky fracture, occasionally subplanar; irregular to subblocky cuttings habit; dull, earthy to occasional microsparkly luster; silty to gritty texture; massive to rare microlaminated bedding structure; abundant scattered pinpoint black specks and microm'icas; trace very fine to fine lower clear quartz sand grains; trace faint dull yellow sample fluorescence with rare cuttings fragments showing dull to light yellow fluorescence, slow to moderately fast milky yellow streaming yellow cut, no residuals [J EPOCH 20 ~ ImI Pioneer Natural Resources - Ivik #1 ( 5610' Claystone Brownish gray to light brownish gray with olive hues; soft to slightly finn; earthy to irregular fracture when finn; amorphous to subblocky cuttings habit; dull, earthy to slightly greasy luster, especially when ashy; clayey to silty texture; commonly grades to siltstone in part; infer interbedded with siltstone; non to very slightly calcareous; continue faint dull yellow sample fluorescence 5670' Siltstone Brownish gray to light brownish gray with yellowish brown secondary hues; crumbly to slightly finn; irregular to subblocky fracture, occasionally subplanar; irregular to subblocky cuttings habit; dull, earthy to occasional microsparkly luster; silty to gritty texture; massive to rare microlaminated bedding structure; abundant scattered pinpoint black specks and micromicas; trace very fine to fine lower clear quartz sand grains; trace faint dull yellow sample fluorescence with rare cuttings fragments showing dull to light yellow fluorescence, slow to moderately fast milky yellow streaming yellow cut; no residuals 5760' Claystone Brownish gray to light brownish gray with common olive gray secondary hues; mushy to runny in samples, occasionally slightly finn; earthy to irregular fracture when finn; amorphous to subblocky cuttings with rounded edges; dull, earthy luster; clayey to silty texture; massive bedding with occasional microlaminae, especially when silty; commonly grades to siltstone in part; interbedded with very silty claystone; non calcareous to slight HCI reaction ( 5830' Shale I silty shale Olive black to olive gray with dark. brown/gray secondary hues; crumbly to slightly firm fissile with planar to subplanar parting platy to blocky cuttings habit; earthy to microsparkly luster; matte to microsucrosic texture, especially on freshly parted surfaces; very thin, well developed microlaminations with abundant organic matter / residue oriented along bedding planes; microlaminae are commonly wavy and discontinuous; abundant microfine micas disseminated throughout and oriented along bedding planes; non calcareous; trace to none very faint dull yellow sample fluorescence 5920' Shale I silty shale Olive black to olive gray with dark brown/gray secondary hues; crumbly to slightly finn fissile with planar to subplanar parting platy to blocky cuttings habit; earthy to microsparkly luster; matte to microsucrosic texture, especially on freshly parted surfaces; very thin, well developed microlaminations with abundant organic matter / residue oriented along bedding planes; microlaminae are commonly wavy and discontinuous; abundant microfine micas disseminated throughout and oriented along bedding planes; non calcareous; note abundant ash and trace cuttings with visible contacts with white carbonate (vigorous HCI reaction) in sample from 5940', also trace to scattered fragments of green hued, finn cuttings 6030' Shale I silty shale Olive gray to brownish gray with increasing dusky yellowish brown and medium gray hues with depth; trace to 100/0 gray/bluish/ greenish ashy cuttings and interbeds; friable to soft with occasional finner gray cuttings; noticeably less fissile than above shales; subblocky to flaky cuttings habit with common rounded edges dull, earthy to microsparkly luster; silty to matte texture; microlaminate to massive observed structure; trace very fine to fine lower sand grains. ( 6100' Sandstone (6100'-6103') Brownish gray to brownish red overaU; mod hard; clast size from silt to very coarse upper; angular to well rounded; poorly sorted; quartz with abundant glauconite; clay matrix; matrix supported; slight calcareous; 100% bright yellow-gold sample fluorescence; instant bright light yellow cut fluorescence followed by fast streaming cut; pale straw visible cut; light brown residual ring; moderate to strong bright yellow residual ring fluorescence. [:I EPOCH 21 II Pioneer Natural Resources - Ivik #1 f 6160' Shale Dark yellowish brown to dusky yellowish brown with moderate brown and brownish gray secondary hues; very soft to crumbly; subplanar to earthy fracture on firmer cuttings; amorphous to subblocky cuttings habit with occasional splinters; microsparkly to dull, earthy luster; silty to microsucrosic texture; massive to microlaminated obseNed structure; abundant microfine micas and scattered pinpoint black specks; trace very fine to coarse loose sand grains in samples; trace to common massive pyrite cuttings; grades to siltstone in part; occasional ashy interbeds; no sample fluorescence. 6245' Shale Dark yellowish brown to dusky yellowish brown with mod yellowish brown and brownish gray secondary hues; very soft to crumbly; earthy to rare subplanar fracture on firmer cuttings; amorphous to subblocky cuttings habit with rounded edges; becoming more clayey with depth; dull, earthy to microsparkly luster; massive to rare microlaminated structure; continue abundant microfine micas and black specks; continue trace massive pyrite; grading to claystone and siltstone in part; continue occasional ashy interbeds; no sample fluorescence.. 6290' Sand (6290' - 6300') Clear to light gray overall; very fine to medium upper with rare coarse lower grains; subround to angular, occasional rounded; moderate to low sphericity; moderate sorting; polished to frosted surface texture; present as loose grains in samples; composed quartz grains with common glauconite; no sample fluorescence. 6370' Shale Dark yellowish brown to dusky yellowish brown with dark brownish gray secondary hues; very soft; crumbly; earthy fracture on few cuttings; subblocky habit; earthy luster; massive to occasional microlaminate structure; common microfine mica; trace pyrite; grades in part to claystone and siltstone. ( 6410'Sand Clear, frosted, milky white; clasts range from very fine lower to fine upper; subangular to well rounded; moderately well sorted; composed of predominantly quartz with scattered mafics and metamorphic lithics; appears consolidated as very fine sandstone with clay matrix; very slight calcareous; variable grain matrix supported in lower zone; 100% dull to mod bright yellow-gold sample fluorescence; instant bright yellow-white cut fluorescence; pale straw visible cut in white light; bright light yellow residual cut fluorescence; fair petroleum odor from unwashed sample. 6490' Claystone Light grayish brown to occasional pale yellowish brown; very soft; stiff to pasty, occasionally crumbly; dominantly appears as lumpy clay, occasionally as roughly formed subblocky cuttings with rounded edges; matte luster; smooth to mod gritty texture; non to very slight calcareous; common ashy appearing blebs and streaks; common black specks; no structure. 6540' Sandstone Light to mod brown, light to dark grayish green; friable; very fine lower to fine lower; subangular to rounded; mod sorted; clay matrix; very slight calcareous; brown fraction is dominantly quartz; green fraction with abundant glauconite; matrix supported; 20% light yellow-gold sample fluorescence; instant mod bright light yellow cut fluorescence; moderate bright light yellow residual cut fluorescence; no visible oil in sample; no petroleum odor. 6615' Claystone Moderate brown with slight yellowish hue, light to medium gray; very soft to soft; mushy to rarely crumbly; dominantly appears as amorphous clay with few roughly formed subblocky or subtabular cuttings; matte, earthy luster with scattered microsparkles; smooth to slightly silty texture; scat carbonaceous specks; scattered ashy streaks and blebs; trace sample fluorescence, probably cavings from up hole. [j EPOCH 22 (I Pioneer Natural Resources - Ivik #1 ( 6680' Shale Dark brownish gray; firm; mod brittle; subtabular and subblocky habit; matte to slight shiny luster; smooth to slightly grainy texture; non calcareous; scat thin lams of ashy appearing material; scattered silty lams; poor to mod fissility; no oil indicators. 6720' Claystone Significant color change from moderate brown to olive gray; very soft; thick; pasty; appears as amorphous lumps; dries to earthy luster; dominantly smooth, occasional slight silty texture; non calcareous; scattered lams of siltstone and shale; occasionally has an ashy appearance. 6765' Tuff White to very light gray; very soft to soft, rarely slightly firm; dull to slightly waxy luster dominantly smooth to occasionally mod gritty texture; mod to occasionally very calcareous; scat light to medium gray ashy streaks; scat to common glass shards; apparently thinly laminated with claystones; light yellow mineral fluorescence. 6815' Claystone Olive gray and moderate yellowish brown; very soft to soft; mushy, thick, pasty; appears as amorphous clay in samples; mod to very soluble; matte, earthy luster; smooth to slightly silty texture; non to slightly calcareous; locally silty, grades in part to siltstone. 6865' Shale Dark brownish gray; firm; mod brittle; subtabular and subblocky habit; matte to slight shiny luster; smooth to slightly grainy texture; non calcareous; scat thin lams of ashy appearing material; scattered silty lams; poor to mod fissility; no oil indicators. ( 6905' Claystone Olive gray and moderate yellowish brown; very soft to soft; mushy, thick, pasty; appears as amorphous clay in samples; mod to very soluble; matte, earthy luster; smooth to slightly silty texture; non to slightly calcareous; locally silty, grades in part to siltstone. ( [j EPOCH 23 · Pioneer Natural Resources - Ivik #1 SURVEY INFORMATION ( Measured Depth TVD Inclination Azimuth Coordinates Dog Leg Feet Feet Degrees Degrees N(+) S(-) E(+) W(-) Degreesl100' 449 448.64 1.45 162.70 -5.42 1.69 0.32 731 731.20 1.27 151.03 -11.57 4.27 0.12 1010 1009.51 1.33 156.75 -17.23 7.03 0.05 1285 1284.68 0.77 155.01 -21.84 9.08 0.20 1569 1568.87 0.67 154.25 -25.08 10.61 0.03 1854 1853.54 0.86 70.84 -25.88 13.35 0.36 2139 2139.03 0.56 74.27 -24.80 16.72 0.11 2424 2423.45 0.34 207.84 -25.18 17.66 0.29 2707 2706.71 1.05 180.53 -28.52 17.24 0.27 2960 2959.72 1.21 186.78 -33.48 16.90 0.08 3172 3171.65 1.37 180.48 -38.24 16.61 0.10 3457 3456.50 1.18 174.52 -44.56 16.86 0.08 3740 3739.11 1.32 169.76 -50.65 17.72 0.06 4024 4022.89 1.46 167.37 - 57.40 19.09 0.06 4307 4305.96 1.58 153.05 -64.40 21.65 0.14 4591 4589.88 1.52 150.61 -71.16 25.26 0.03 4878 4876.80 1.17 179.00 - 77.40 27.18 0.26 5163 5161.74 1.36 153.07 -83.3 2 28.76 0.21 ( 5442 5440.79 1.10 159.95 -88.80 31.18 0.11 5724 5723.10 0.97 154.46 -93.51 33.15 0.06 6012 6010.92 0.58 140.35 -96.84 35.13 0.15 6293 6292.08 0.55 146.72 -99.08 36.79 0.02 6578 6576.76 0.71 195.31 -101.94 37.07 0.19 6863 6861.89 0.50 209.92 -104.73 35.98 0.09 ( (J EPOCH 24 (I Pioneer Natural Resources - Ivik #1 DAILY MUD PROPERTIES Date Depth Weight FV PV YP Gels API FL Cake Solids OillWater Sand PH CI Ca 2/25/03 1571 9.3 55 12 29 11/14/0 8.4 1 9.7 0/87 1 9.0 43000 120 2/26/03 3020 9.45 44 11 23 6/9/0 7.2 1 4.1 0/91.5 .75 8.5 54000 200 2/27/03 3020 9.5 48 12 20 7/2/0 7.0 1 4.5 0/91 .5 8.0 55000 400 2/28/03 3020 9.6 46 9 16 6/8/0 5.8 1 3.7 0/90 .1 8.0 77000 360 3/01/03 4925 9.85 45 13 20 6/9/0 5.6 1 4.0 0/88 .1 8.8 97000 360 3/02/03 6100 10.0 42 13 17 6/14/0 4.6 1 4.7 0/86.5 .1 9.3 101000 120 3/03/03 6127 10.0 45 15 17 5/12/0 4.1 1 4.6 0/87 .1 9.1 102000 120 3/04/03 6377 10.0 44 13 17 5/9/0 4.3 1 4.6 0/87 .1 9.1 102000 140 3/05/03 6943 9.9 46 14 17 6/15/0 4.3 1 5.0 0/87.6 .1 9.0 91000 100 (J EPOCH 25 ~' <~ .~ II Pioneer Natural Resources - Ivik #1 BIT RECORD Bit Grading I 0 D L B G 0 R N U U 0 E A T E N T L C A U H A E E L A R G E S R R T I E R 0 C I N N R R H 0 G C 0 0 A N S H P W W R A U S S R L L E D Bit # Size Make Type SIN Jets Depth Depth Ftg Hrs Ave Ave Ave Flow In Out FUHr WOB RPM Rate (gpm) 1 9 7/8 HC MXC 5019229 1x12, 175 3020 2849 11.5 247.7 11.3 135 630 2 2 FC A E NO TD 1 3x16 2 6 3/4 HYCA DS69 202845 5*11 3020 6100 3080 19.1 161.3 6.6 100 307 0 0 NO A X NO TD FNP V 3 6% DRI CMM X 6100 6144 44 2 78 1 1 WT M X NO TD F 34 F 2R2 6 3/4 HYCA DS^( 202845 5*11 6144 6943 799 6.9 115.8 10 100 310 0 0 NO A X NO TD FNP V [~ EPOCH 26 '~ ~ '-- Daily Report Pioneer Natural Resources ( Ivik#1 REPORT FOR L. Meyer, S. Coyner DATE Feb 25,2003 TIME 24:00 CASING INFORMATION 133/8" 175' SURVEY DATA BIT INFORMATION NO. SIZE 1 9 7/8 TYPE HC MXC1 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.3 VIS FC SOL ( MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUlTlNG GAS METHANE(C·1 ) ETHANE (C·2) PROPANE(C.3) BUTANE (C·4) PENT ANE(C-S) HYDROCARBONSHO~ INTERVAL Page 1 of 1 DAILY WELLSITE REPORT [~ EPOCH DEPTH 1630 YESTERDAY 176 24 Hour Footage 1454 PRESENT OPERATlON= DRILLING DEPTH INCLINATION VERTICAL DEPTH AZIMUTH INTERVAL SIN JETS IN OUT FOOTAGE HOURS 5019228 1x12,3x16 175 5 HIGH LOW AVERAGE 2481.0 @ 400 18.8 @ 433 414.1 2320 @ 1326 1200 @ 509 1477.6 5 @ 423 1 @ 1344 1 135 @ 176 135 @ 1630 135.1 2253 @ 1603 191 @ 353 1556.8 DEPTH: 1630' 41 PV YP FL Gels SD OIL MBL pH REASON PULLED CONDITION T/B/C CURRENT A VG 624.1 1842.4 1 135 2190 ftIhr amps Klbs RPM psi CL- Ca+ CCI HIGH LOW AVERAGE 91 @ 1281 0 @ 1605 16.4 TRIP GAS= 0 0 @ 1630 0 @ 1630 0.0 WIPER GAS= 0 CHROMATOGRAPHY(ppm) SURVEY= 0 19762 @ 1281 0 @ 1605 3252.4 CONNECTION GAS HIGH= 0 @ @ AVG= 0 @ @ CURRENT 0 @ @ CURRENTBACKGROUN~AVG 15 @ @ No shows LITHOLOGYIREMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 40% SAND, 20% GRAVEL, 30% CLAY, 10% SILT DAILY AC1WliY Pull wear bushing, service rig, pick up BHA, tag bottom at 105', clean to 175'. Pull out of hole, pick up BHA, spud at 09:00. Drill 175' to 509', SUMMARY circulate bottoms up. Pull 4 stands. Survey, change out elevators. Drill 509' to 610', Service top drive. Drill 610' to 1535'. Circulate and condition mud. Drill 1535' to 1630', (Midnight depth.) Epoch Personel On Board= 4 Daily Cost $2385.00 (Including Rigwatch) Report by: John Morris ( file:! IC: \DML %20D AT A\PIONEER \AM%2 OREPOR TS\2003 0225, htm 3/13/03 Daily Report PIONEER NATURAL RESOURCES ( Ivik#1 Page 1 of 1 DAILY WELLSITE REPORT [~ EPllCH REPORT FOR L. MEYERS, S. COYNER DATE Feb 26,2003 TIME 24:00 CASING INFORMATION 133/8" @ 175' SURVEY DATA BIT INFORMATION NO. SIZE 1 9 7/8" TYPE HC MXC1 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.3 VIS FC SOL ( MOO SUMMARY INTERVAL TOOLS TO GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1 ) ETHANE (C-2) PROPANE(C-3) BUTANE(C-4) PENT ANE(C-S) HYDROCARBONSHO~ INTERVAL DEPTH 3020 YESTERDAY 1630 PRESENT OPERATlON= RIG UP CASING EQUIPMENT 24 Hour Footage 1390 DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 2960' 1.21 186.78 2959.72' INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLE D 2019228 1x12,3x16 175' 3020' 2845' 11.4 2-E-1 TD HIGH LOW AVERAGE CURRENT A VG 732.0 @ 2488 9.5 @ 1874 295.5 262.4 ftIhr 2365 @ 1992 285 @ 1912 1771.0 1757.9 amps 31 @ 2784 1 @ 2261 7.3 15.1 Klbs 135 @ 1630 135 @ 3020 135.1 135 RPM 3067 @ 2656 1844 @ 1721 2581.6 2790 psi DEPTH: 3020' 55 PV YP FL Gels CL- SD OIL MBl pH Ca+ CCI HIGH LOW AVERAGE 70 @ 1727 0 @ 1957 14.1 TRIP GAS= NJA @ @ WIPER GAS= NJA CHROMATOGRAPHY(ppm) SURVEY= 0 15687 @ 1727 30 @ 1957 2878.8 CONNECTION GAS HIGH= 0 0 @ 3020 0 @ 3020 0.0 AVG= 0 0 @ 3020 0 @ 3020 0.0 CURRENT 0 0 @ 3020 0 @ 3020 0.0 CURRENT BACKGROUND/AVG 14 0 @ 3020 0 @ 3020 0.0 NO SHOWS. LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 80% CLAYSTONE, 20% SILTSTONE Drill from 1630' to 1800', circulate for ball mill. Drill from 1800' to 3020' surveying every 300'. Circulate at 3020' for short trip. POOH 3020' to 2766'. Back ream 2766' to 1630'. POOH 1630' to 1162', no problems. RIH 1162' to 2808'. Wash and ream 2808' to 3020'. Circulate and bring casing toots onto rig floor. POOH from 3020' to 1346', no problems. POOH. Stand back heavy weight drill pipe. Stand back 6 1/2" drill collars. Lay down BHA. Download M\I\ID. Epoch Personel On Board= 4 Daily Cost $2960.00 ($2385.00 reported yesterday was an error.) Report by: John Morris DAILY ACTIVITY SUMMARY ( fil e:1 IC: \DML %20DA T A \PIONEER \AM%20REPOR TS\2003 0226. htm 3/13/03 Daily Report PIONEER NATURAL RESOURCES ( Ivik#1 Page 1 of 1 DAILY WELLSITE REPORT [1 EPl)CH REPORT FOR L. MEYERS, S. COYNER DATE Feb 27,2003 TIME 24:00 CASING INFORMATION 75/8" @ 2991' SURVEY DATA BIT INFORMATION NO. SIZE 1 97/800 TYPE HC MXC1 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.3 VIS FC SOL ( MWD SUMMARY INTERVAL TOOLS TO GAS SUMMARY(unìts) DITCH GAS CUTIING GAS METHANE(C-1 ) ETHANE(C-2) PROPANE(C-3) BUTANE (C-4) PENTANE(C-5) HYDROCARBONSHO~ INTERVAL LITHOLOGY PRESENT LITHOLOGY NO NEW HOLE DEPTH 3020 YESTERDAY 3020 PRESENT OPERATlON= TESTING BOP EQUIPMENT 24 Hour Footage 0 DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 2960' 1.21 186.78 2959.72' INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS TIBIC PULLE D 2019228 1x12,3x16 175' 3020 2845' 11.4 2-E-1 TD HIGH LOW AVERAGE CURRENT A VG @ @ ftIhr @ @ amps @ @ Klbs @ @ RPM @ @ psi DEPTH: 3020' 55 PV YP FL Gels CL- SD OIL MBL pH Ca+ CCI HIGH LOW AVERAGE @ @ @ @ CHROMATOGRAPHY(ppm) @ @ @ @ @ @ @ @ @ @ TRIP GAS= 10 WIPER GAS: N/A SURVEY= N/A CONNECTION GAS HIGH= N/A AVG= N/A CURRENT N/A CURRENT BACKGROUND/AVG 0 NO SHOWS. LITHOLOGY/REMARKS GAS DESCRIPTION DAILY ACTIVITY Circulate and condition mud for cement job. Cement casing. Rig down casing tools. RIH with pack-off and test to 5000 psi for 10 minutes. SUMMARY Pick up 4 3/400 drill collars and make up tam port collar running tool. Open port collar and circulate clean. Pump calcium chloride around port collar. Stand back drill collar. Lay dO\M1 casing tools. Epoch Personel On Board= 4 Daily Cost $2960.00 Report by: JOHN MORRIS ( fil e:1 IC: \DML %20DA T A\PIONEER \AM% 2 OREP OR TS\2003 0227. htm 3/13/03 Daily Report PIONEER NATURAL RESOURCES ( Ivik#1 REPORT FOR L. MEYERS, S. COYNER DATE Feb 28, 2003 TIME 24:00 CASING INFORMATION 75/8" @ 2991' SURVEY DATA BIT INFORMATION NO. SIZE TYPE 2 6.75 HYCA DS69FNPV DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.3 VIS FC SOL ( MWD SUMMARY INTERVAL TOOLS TO GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE (C-2) PROPANE(C-3) BUTANE (C-4) PENTANE(C-5) HYDROCARBONSHO~ INTERVAL LITHOLOGY PRESENT LITHOLOGY NO NEW HOLE. DAILY ACTIVITY SUMMARY DAILY WELLSITE REPORT DEPTH 3020 Page 1 of 1 [~ EPOCH PRESENT OPERATlON= CUT AND SLIP DRILLING LINE YESTERDAY 3020 24 Hour Footage 0 DEPTH 2960' INCLINATION 1.21 AZIMUTH 186.78 VERTICAL DEPTH 2959.72' HOURS o CONDITION T/B/C REASON PULLED SIN 202845 INTERVAL JETS IN OUT 5x11 3020' FOOTAGE o CURRENT AVG ftIh r amps Klbs RPM psi Gels pH CL- Ca+ CCI 55 HIGH LOW AVERAGE @ @ @ @ @ @ @ @ @ @ DEPTH: 3020 PV YP FL SD OIL MBL TRIP GAS= N/A WIPER GAS= N/A SURVEY= N/A CONNECTION GAS HIGH= N/A AVG= N/A CURRENT N/A CURRENT BACKGROUND/AVG 0 GAS DESCRIPTION HIGH LOW AVERAGE Nipple down diverter. nipple up BOP equipment.Test BOP equipment. Pick up BHA, pick up 3 1/2" drill pipe. RIH to casing shoe. Cut and slip drilling line. @ @ @ @ CHROMATOGRAPHY(ppm) @ @ @ @ @ @ @ @ @ @ NO NEW HOLE LITHOLOGY/REMARKS Epoch Personel On Board= 4 Daily Cost $2960.00 Report by: JOHN MORRIS ( fil e:IIC: \DML %20DA T A \PIONEER \AM%20REPOR TS\2003 0228. htm 3/13/03 Dai 1 y Report Pioneer Natural Resources (' Ivik#1 REPORT FOR L. Meyers, S. Coyner DATE Mar 01, 2003 TIME 24:00 CASING INFORMATION 75/8" @ 2996' SURVEY DATA BIT INFORMATION NO. SIZE 2 6.75" TYPE HYCA DS69FNPV DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.8 VIS FC SOL MWD SUMMARY INTERVAL TO ( TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-S) HYDROCARBONSHO~ INTERVAL Page 1 of 1 DAILY WELLSITE REPORT [~ EPOCH DEPTH 4925 YESTERDAY 3021 24 Hour Footage 1904 PRESENT OPERATlON= Short trip DEPTH INCLINATION AZIMUTH INTERVAL SIN JETS IN OUT FOOTAGE HOURS 202845 5X 11 3020 1905' 11.1 HIGH LOW AVERAGE 618.3 @ 3469 11.9 @ 4683 259.6 1757 @ 3021 461 @ 4045 896.0 18 @ 4681 1 @ 4713 3.0 100 @ 3021 100 @ 4925 100.1 2979 @ 4357 919 @ 3031 2104.8 DEPTH: 4925' 45 PV YP FL Gels SD OIL MBL pH VERTICAL DEPTH CONDITION T/B/C REASON PULLE D CURRENT A VG 177 .2 ftIhr 939.9 amps 9.5 Klbs 100 RPM 2704 psi CL- Ca+ CCI HIGH LOW AVERAGE 850 @ 4012 2 @ 3793 83.6 TRIP GAS= N/A @ @ WIPER GAS= N/A CHROMATOGRAPHY(ppm) SURVEY= N/A 76600 @ 4179 483 @ 3793 12342.4 CONNECTION GAS HI GH= 230 8300 @ 4012 1 @ 3072 602.1 AVG= 60 10030 @ 4012 1 @ 3206 386.8 CURRENT 15 7778 @ 4012 1 @ 3210 232.0 CURRENT BACKGROUND/AVG 35 5163 @ 4012 1 @ 4924 129,9 NO OIL SHOW. LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 90% CLAYSTONE, 10% SILTSTONE, TRACES OF VOLCANIC TUFF DAILY ACTIVITY Cut and slip drilling line, Drill float collar at 2914', Wash to 2968'. Drill casing shoe at 2996', Wash to 3020', Drill. to 3030', Ci.rculate bottoms SUMMARY up. Pull into casing and perform leak off test (16.4 ppg equivalent). Drill from 3030' to 3821', packing off on back ream, Epoch Personel On Board= 4 Daily Cost $2960.00 Report by: John Morris ( fil e:IIC: \DML %20D A TA \PIONEER \AM%20REPOR TS\2003 03 01 ,htm 3/13/03 Daily Report Page 1 of 1 Pioneer Natural Resources ( DAILY WELLSITE REPORT ~ EPOCH Ivik#1 REPORT FOR L. Meyers, S. Coyner DATE Mar 02, 2003 TIME 24:00 DEPTH 6100 YESTERDAY 4925 24 Hour Footage 1175 PRESENT OPERATlON= Trip out of hole. CASING INFORMATION 75/8" @ 2996' SURVEY DATA DEPTH 6012 INCLINATION 0.58 AZIMUTH 140.35 VERTICAL DEPTH 6012.92 BIT INFORMATION NO. SIZE 2 6 3/4" TYPE HYCA DS69FNPV SIN 202845 JETS 5x 11 INTERVAL IN OUT 3020 6100 FOOTAGE 3080 HOURS 19.9 CONDITION T/B/C REASON PULLED DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 10.0 FC HIGH LOW AVERAGE CURRENT A VG 546 @ 5250 19.9 @ 4943 177.2 61.6 953 @ 5911 60S @ 5130 906 901 17 @ 5489 1 @ 5251 617 2 100 @ 6100 100 @ 6100 100 100 3506 @ 5732 1970 @ 5251 2945 2864 DEPTH: 6100 42 PV YP FL Gels CL- SD OIL MBL pH Ca+ ftIhr amps Klbs RPM psi VIS SOL CCI ( MWD SUMMARY INTERVAL TOOLS TO GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1 ) ETHANE(C-2) PROPANE(C-3) BUTANE (C-4) PENT ANE(C-5) HYDROCARBON SHOWS INTERVAL 5245-5465 HIGH LOW AVERAGE 1681 @ 5366 11 @ 6095 312 TRIP GAS= N/A @ @ WIPER GAS= 890 CHROMATOGRAPHY(ppm) SURVEY= N/A 253309 @ 5366 1922 @ 6095 53815 CONNECTION GAS HIGH= 270 17802 @ 5366 92 @ 6095 2837 AVG= 165 8367 @ 5366 32 @ 6095 1049 CURRENT 270 3872 @ 5366 10 @ 5118 428 CURRENT BACKGROUND/AVG 60 2117 @ 5365 2 @ 5214 208 Oil show from 5245' to 5465'. LITHOLOGY/REMARKS GAS DESCRIPTION Siltstone with traces of Maximum = 1681 units. With 100% Dull yellow to dull gold sample fluor; slow blooming mod bright cut fluor; sand. heavy gases through mod bright light yellwo residual cut fluor; no staining visible on cuttings; no pentane. visible cut ring in white light. LITHOLOGY PRESENT LITHOLOGY 50% CLAYSTONE, 30% SILTSTONE, 10% SHALE, 10% VOLCANIC TUFF Pull out of hole from 4925' to 2306', wet trip. Service top drive. Hang bell ringer. Pick up 21 joints of 3 112" drill pipe. Run into hole to 4925'. Trip gas 600 units. Drill 4925' to 5525', Max gas 1700 units. Pack off at 500' and 5174'. Drill 5525' to 6100', Max gas 1050 units. Circulate and condition mud, circulate sweep. Pull out of hole from 6100' to 4294', no problems. Run into hole from 4294' to 6100'. Wash and ream last stand, no problems, Circulate and condition mud, circulate sweep, spot pill on bottom. Pull out of hole from 6100' to 2779', no problems. Monitor well at casing shoe. Epoch Personal On Board= 4 Daily Cost $2960.00 Report by: JOHN MORRIS DAILY ACTIVITY SUMMARY ( fil e:1 IC: \DML %20DA T A \PIONEER \AM%20REPOR TS\2003 03 02.htm 3/13/03 Daily Report Pioneer Natural Resources ( Ivik#1 REPORT FOR L. Meyers DATE Mar 03, 2003 TIME 24:00 CASING INFORMATION 75/8" @2996' SURVEY DATA BIT INFORMATION NO. SIZE 3 6.75 Page 1 of 1 DAILY WELLSITE REPORT [~ EPOCH DEPTH 6131 YESTERDAY 6100 PRESENT OPERATlON= Coring 24 Hour Footage 31 DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SIN INTERVAL IN OUT 6100 HOURS 14.7 CONDITION T/B/C REASON PULLED TYPE DRI CMMF34F (CORE) DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.95 VIS FC SOL M\I\ID SUMMARY INTERVAL TO ( TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1 ) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL JETS TFA 0.55 FOOTAGE 31 HIGH LOW AVERAGE CURRENT AVG 3 @ 6101 1.6 @ 6121 4.2 1.7 708 @ 6119 142 @ 6101 661.6 614.7 11 @ 6111 2 @ 6101 10.3 10.7 78 @ 6101 78 @ 6129 80.8 78 1115 @ 6128 663 @ 6101 1054.7 1106 DEPTH: 6131 45 PV YP FL Gels CL- SD OIL MBL pH Ca+ ftIhr amps Klbs RPM psi CCI HIGH LOW AVERAGE 48 @ 6102 4 @ 6125 11.4 TRIP GAS= 315 @ @ WIPER GAS= N/A CHROMATOGRAPHY(ppm) SURVEY= N/A 7955 @ 6102 770 @ 6122 1913.2 CONNECTION GAS HIGH= N/A 358 @ 6102 24 @ 6125 70.9 AVG= N/A 146 @ 6102 9 @ 6125 31.1 CURRENT N/A 67 @ 6102 5 @ 6125 15.4 CURRENT BACKGROUND/AVG 8 50 @ 6102 1 @ 6108 4.9 No oil show. LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 50% CLAYSTONE, 30% SILTSTONE, 10% SHALE, 10% VOLCANIC TUFF DAILY ACTIVITY SUMMARY Pull out of hole. Pick up coring assembly. Run into hole. Wash down one stand to 6100'. Circulate. Begin cutting core #1. Epoch Personel On Board= 4 Daily Cost $2960.00 Report by: JOHN MORRIS ( fil e:/ IC: \DML %20D A T A \PIONEER \AM%20REPOR TS\2003 03 03. htm 3/13/03 Daily Report (" Ivik#1 REPORT FOR L. MEYERS DATE Mar 04, 2003 TIME 24:00 CASING INFORMATION 75/8" @ 2996' SURVEY DATA BIT INFORMATION NO. SIZE TYPE 2R2 6.75 HYCA DS69FNPV DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 10.0 VIS FC SOL MWD SUMMARY INTERVAL TO ( TOOLS , GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1 ) ETHANE(C-2) PROPANE(C-3) BUTANE (C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL Page 1 of 1 DAILY WELLSITE REPORT [~ EPOC·H DEPTH 6470 YESTERDAY 6131 PRESENT OPERATlON= DRILLING 24 Hour Footage 339 DEPTH AZIMUTH VERTICAL DEPTH INCLINATION SIN 202845 INTERVAL JETS IN OUT 5X11 6144 CONDITION T/B/C REASON PULLED FOOTAGE HOURS HIGH LOW AVERAGE CURRENT A VG 276.5 @ 6188 1.8 @ 6131 117.9 161.8 1042 @ 6168 700 @ 6376 907.6 969.3 13 @ 6432 1 @ 6376 7.6 3.8 100 @ 6423 78 @ 6144 116.0 90 3331 @ 6168 1096 @ 6135 3103.1 3200 DEPTH: 6470' 43 PV YP FL Gels CL- SD OIL MBL pH Ca+ ftIhr amps Klbs RPM psi CCI HIGH AVERAGE 114.2 TRI·P GAS= 680 \MPER GAS= N/A SURVEY= N/A CONNECTION GAS HIGH= 45 AVG= 45 CURRENT 45 CURRENT BACKGROUND/AVG 66 483 LOW @ 6140 @ CHROMATOGRAPHY(ppm) @ 6463 284 @ 6140 @ 6427 9 @ 6140 @ 6451 3 @ 6140 @ 6451 1 @ 6140 @ 6451 1 @ 6353 21342.6 1294.8 477.1 261.3 80.2 @ 6451 @ 95116 7840 3164 1460 607 OIL SHOW 6099' TO 6103', 6405' TO 6470', LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 80% CLAYSTONE,10% SILTSTONE, 10% VOLCANIC TUFF DAILY ACTIVITY SUMMARY Complete core #1. Pull out of hole. Pick up drilling assembly drill from 6144' to 6470' Epoch Personel On Board= 4 Daily Cost $2960.00 Report by: John Morris ( fil e:/ /C: \DML %20D A T A \PIONEER \AM%20REPOR TS\2003 03 04. htm 3/13/03 Daily Report Pioneer Natural Resources ( Ivik#1 Page 1 of 1 DAILY WELLSITE REPORT [~ EPOCH REPORT FOR L. MEYERS, G. GORLICH DATE Mar 05,2003 TIME 24:00 CASING INFORMATION 7 5/8N @ 2996' SURVEY DATA BIT INFORMATION NO. SIZE 2R2 6.75" TYPE HYCA DS69FNPV DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 10.0 VIS FC SOL MWD SUMMARY INTERVAL TO ( TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE (C-2) PROPANE(C-3) BUT AN E (C-4) PENTANE(C-5) HYDROCARBONSHO~ INTERVAL DEPTH 6943 YESTERDAY 6470 PRESENT OPERATlON= Electric Logging 24 Hour Footage 473 DEPTH INCLINATION AZIMUTH SIN 202845 INTERVAL IN OUT 6144 6943 HOURS 6.9 FOOTAGE 799 JETS 5X11 HIGH LOW AVERAGE 293.1 @ 6487 29.6 @ 6517 163.8 1006 @ 6476 625 @ 6484 912.9 13 @ 6471 1 @ 6943 5.9 100 @ 6470 100 @ 6943 100.0 3736 @ 6764 2418 @ 6484 3358.5 DEPTH: 6943' 45 PV YP FL Gels SD OIL MBL pH VERTICAL DEPTH CONDITION REASON T/B/C PULLED O-X-IN TD CURRENT A VG 0 ftIhr 0 amps 0 Klbs 0 RPM 0 psi CL- Ca+ CCI HIGH LOW AVERAGE 649 @ 6475 20 @ 6916 79.3 TRIIP GAS= N/A @ @ WIPER GAS= 410 CHROMATOGRAPHY(ppm) SURVEY= N/A 95172 @ 6475 3978 @ 6766 13865.6 CONNECTION GAS HIGH= 100 5533 @ 6475 126 @ 6916 625.4 AVG= 75 2862 @ 6475 61 @ 6766 329.0 CURRENT 80 1278 @ 6475 24 @ 6927 161.8 CURRENT BACKGROUND/AVG 15 563 @ 6415 1 @ 6932 68.1 Oil show from 6470' to 6495'. Trace oil show 6527' to 6566'. LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY Claystone 70%. Shale 10%, Siltstone 10%, Tuff 10% DAILY ACTIVITY SUMMARY Drill to TD at 6943', pump sweep, circulate hole clean. Wipe hole, circulate hole clean, pull out of hole. Rig up and run electric logs. Epoch PersonelOnBoard= 4 Daily Cost $2960.00 Report by: John Morris ( fil e:1 IC: \DML %20DA T A \PIONEER \AM%20REPOR TS\2003 03 05 .htm 3/13/03 Daily Report Page 1 of 1 Pioneer Natural Resources ( DAILY WELLSITE REPORT [j EPOCH Ivik#1 REPORT FOR G. Goerlich DATE Mar 06, 2003 TIME 24:00 DEPTH 6943 YESTERDAY 6943 PRESENT OPERATION= Wireline logs. 24 Hour Footage 0 CASING INFORMATION 75/8" @ 2996' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA BIT INFORMATION NO. SIZE TYPE SIN INTERVAL JETS IN OUT FOOTAGE HOURS HIGH lOW AVERAGE @ @ @ @ @ @ @ @ @ @ DEPTH: 6943 14 YP 17 Fl 4.6 Gels .1 Oil 0 MBl 7.0 pH CONDITION T/B/C REASON PUllED DRilLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 10.0 VIS FC 1 SOL CURRENT AVG ftlhr amps Klbs RPM psi 42 PV 5.5 SD 5/12/0 8.9 CL- 92600 220 CCI Ca+ MOO SUMMARY INTERVAL TO TOOLS ( GAS SUMMARY(units) DITCH GAS CUTTING GAS HIGH LOW AVERAGE METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE (C-4) PENTANE(C-5) HYDROCARBONSHO~ INTERVAL @ @ @ @ CHROMATOGRAPHY(ppm) @ @ @ @ @ @ @ @ @ @ TRIP GAS= N/A WIPER GAS= N/A SURVEY= N/A CONNECTION GAS HIGH= N/A AVG= NAI CURRENT' N/A. CURRENTBACKGROUND/AVG~~ NO NEW HOLE MADE. LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY NO NEW HOLE MADE. DAILY ACTIVITY SUMMARY Run wireline logs, move pipe in derrick, pick up pipe from shed, pick up MDT tools and trip in on drill pipe, circulate at shoe and rig up wireline sheeve, continue in hole with wireline tools, circulate drill pipe volume and pick up side entry sub. Epoch Personel On Board= 4 Daily Cost $2960.00 Report by: John Morris ( file: I IC: \DML %20DAT A \PIONEER \AM%20REPOR TS\200303 06 .htm 3/13/03 FINAL LOGS FORMATION PARAMETERS SAMPLED:SAMPLING OPERATION PERSONNEL: Depth:5265.0 - 6475.0 ft MD Wellsite Client Rep.:Howard Anderson Pressure:2294 - 3292 psia Oilphase Personnel:Jennifer Harris Temperature:130 - 168 °F MDT Personnel:Dennis Weathers Scott Shier Date submitted: Approved by: Date: n/a 29 March 2003Water-based Mud System Synthetic Oil-based Mud System © 2002 Oilphase Sampling Services - Sampling Report (Rev NAM 02). The data in this report remains the property of the client and may not be disclosed or reproduced without the client permission. On-site fluid analysis measurements made in the field may be subject to further evaluation once a PVT study has been performed. BOROUGH: FIELD: WELL: DATE: RIG: North Slope Thetis Island IVIK #1 06 - 07 March 2003 Nabors 27 E Oilphase Sampling & Analysis Services c/o Schlumberger Gulf Coast Special Services 107 S. Concord Road, Building No. 1 Belle Chasse, Louisiana USA 70037 Tel: 504-394-2555 Fax: 504-398-7382 FROM RESERVOIR TO RESULTS. Pioneer Natural Resources Canada Field Operations Report Schlumberger Private Borough: Well: Installation: Client: Job #: Date: Pioneer Natural Resources 047 06 - 07 Mar 03 North Slope IVIK #1 Nabors 27 E © 2002 Oilphase Sampling Services - Sampling Report (Rev NAM 02). The data in this report remains the property of the client and may not be disclosed or reproduced without the client permission. On-site fluid analysis measurements made in the field may be subject to further evaluation once a PVT study has been performed. Summary …………………………………………………... 1 Sequence of Events ……………………………………….. 2 Offshore MDT Sample Listing ……………………………... 3 Table of Contents iiSchlumberger Private Borough: Well: Installation: Client: Job #: Date: Pioneer Natural Resources 047 06 - 07 Mar 03 North Slope IVIK #1 Nabors 27 E © 2002 Oilphase Sampling Services - Sampling Report (Rev NAM 02). The data in this report remains the property of the client and may not be disclosed or reproduced without the client permission. On-site fluid analysis measurements made in the field may be subject to further evaluation once a PVT study has been performed. On 07 March 03, Schlumberger Wireline ran their Formations Dynamics Tester into the well IVIK #1. The toolstring consisted of six 450 cc MPSRs. MPSR 1290 was filled in the Nuiqsuit/Nechelit sand at 6475.0 ft MD. MPSR 1292 was filled in the Torok sand at 5432.0 ft MD. MPSR 1294 was also filled in the Torok sand at 5378.1 ft MD. MPSRs 1295 and 1320 were filled in the Torok sand at 5265.0 ft MD. The MPSRs were heated to reservoir temperature for two hours and transferred into Conventional Sam ple Bottles (CSB). It was found that MPSR 1290 did not sample correctly and the small amount of dead oil inside the tool was put into a glass vial. All pressurized hydrocarbon samples and associated drilling fluid sample will be sent to the Oilphase-DBR PVT laboratory in Edmonton, Alberta, Canada. Summary Schlumberger Private 1 Borough: Well: Installation: Client: Job #: Date: Pioneer Natural Resources 047 06 - 07 Mar 03 North Slope IVIK #1 Nabors 27 E © 2002 Oilphase Sampling Services - Sampling Report (Rev NAM 02). The data in this report remains the property of the client and may not be disclosed or reproduced without the client permission. On-site fluid analysis measurements made in the field may be subject to further evaluation once a PVT study has been performed. DATE TIME EVENT 07 Mar 03 01:30 Commenced running tools in the hole 10:53 Sampled MPSR 1290 at 6475.0 ft MD 15:21 Sampled MPSR 1292 at 5432.0 ft MD 16:15 Sampled MPSR 1294 at 5378.1 ft MD 17:35 Sampled MPSR 1295 at 5265.0 ft MD 17:41 Sampled MPSR 1320 at 5265.0 ft MD 28 Mar 03 04:00 Obtained opening pressure on MPSR 1290 (0 psi @ 65 F) 04:15 Transferred 20 cc of fluid from MPSR 1290 into glass vial 04:30 Obtained opening pressure on MPSR 1292 (1,000 psi @ 65 F) 06:30 Commenced transfer of MPSR 1292 (6,000 psi @ 136F) 06:45 Completed transfer of MPSR 1292 into CSB 7724-QA 07:00 Obtained opening pressure on MPSR 1294 (900 psi @ 65 F) 09:00 Commenced transfer of MPSR 1294 (6,000 psi @ 135F) 09:15 Completed transfer of MPSR 1294 into CSB 7722-QA 09:15 Obtained opening pressure on MPSR 1295 (1,800 psi @ 64 F F) 11:15 Commenced transfer of MPSR 1295 (6000 psi @ 130 F) 11:30 Completed transfer of MPSR 1295 into CSB 7720-QA 11:45 Obtained opening pressure on 1320 (2,000 psi @ 64 F) 13:45 Commenced transfer of MPSR 1320 (6,000 psi @ 130 F) 14:00 Completed transfer of MPSR 1320 into CSB 7718-QA Sequence of Events Schlumberger Private 2 Offshore MDT Sample Listing Sample Sample Type Chamber Popening Trans. Cond.Final Pres.Shipping Cyl.Sample Comments No.Serial No.psig @ °F psig @ °F psig @ °F Serial No.Volume NUIQSUIT/NECHELIK SAND SAMPLES: OIL 6475.0 ft MD (TVD=6474.1'), 3292 psia @ 168 F POT =53 min, POV = 7.9 Gal, DP = 3092 psi * 1.01 450 cc MPSR MPSR 1290 0 @ 65 n/a n/a 20 cc glass vial 20 cc TOROK SAND SAMPLES: WATER 5432.0 ft MD (TVD=5431.1'), 2367 psia @ 136 F POT =36 min, POV = 5.3 Gal, DP = 817 psi * 1.02 450 cc MPSR MPSR 1292 1,000 @ 65 6,000 @ 136 0 @ 65 CSB 7724-QA 415 cc TOROK SAND SAMPLES: WATER 5378.1 ft MD (TVD=5377.3'), 2345 psia @ 135 F POT =40 min, POV = 3 Gal, DP = 1875 psi * 1.03 450 cc MPSR MPSR 1294 900 @ 65 6,000 @ 135 0 @ 65 CSB 7722-QA 420 cc TOROK SAND SAMPLES: WATER 5265.0 ft MD (TVD=5264.2'), 2294 psia @ 130 F POT =54 min, POV = 13.4 Gal, DP = 694 psi * 1.04 450 cc MPSR MPSR 1295 1,800 @ 64 6,000 @ 130 100 @ 64 CSB 7720-QA 420 cc 1.05 450 cc MPSR MPSR 1320 2,000 @ 64 6,000 @ 130 100 @ 64 CSB 7718-QA 420 cc DRILLING FLUID SAMPLES 1.06 Waterbase mud n/a n/a n/a n/a 1 Gal. Steel pail 1 Gal.From active pit. Sample Date & Time 07/Mar/03 15.21 07/Mar/03 16.15 07/Mar/03 12.00 07/Mar/03 10.53 07/Mar/03 17.41 07/Mar/03 17.35 Borough: Well: Installation: Client: Job #: Date: Pioneer Natural Resources 047 06 - 07 Mar 03 North Slope IVIK #1 Nabors 27 E Schlumberger Private 3 Reservoir Fluids R-05-393 January 13, 2006 PVT, EOR, & Flow Assurance Study Pioneer Natural Resources Alaska, Inc. Field: NW Kuparuk Well: Ivik Westport Technology Center International 6700 Portwest Drive Houston, Texas 77024 (713) 479-8400 (713) 864-9357 (fax) www.westport1.com Prepared for: Pioneer Natural Resources Alaska, Inc. SAP No. 3645740 Westport Technology Center International makes no representations or warranties, either expressed or implied, and specifically provides the results of this report "as is" based on the information provided by the client. Drilling Fluids Gas Hydrates Materials & Corrosion Reservoir Fluids Formation Characterization Well Productivity Flow Assurance January 13, 2006 Pioneer Natural Resources, Alaska, Inc. 700 G. Street, Suite 600 Anchorage, AK 99501 Attention: Mr. Greg Sanders Subject: PVT, EOR, & Flow Assurance Study Ivik Well NW Kuparuk Field North Slope, Alaska Westport File No. R-05-393 Dear Mr. Sanders, Samples of non-pressurized stock tank oil collected from the subject well were forwarded to our laboratory for preparation of a recombined reservoir fluid for Omni Laboratories use. A small volume of the prepared fluid was utilized for a black oil PVT study and investigation of the effects of proposed gas injection in the form of an enhanced oil recovery study. A portion of the stock tank oil was further utilized for flow assurance measurements. The results of these analyses are presented on the following pages. Thank you for the opportunity to perform this study for Pioneer Natural Resources, Inc. Should you have any questions or comments regarding these measurements, please do not hesitate to call at your earliest convenience. Sincerely, Karl Karnes for Deepak Gupta Senior Phase Behavior Specialist Intertek Westport Technology Center Cc: Mr. Paul Leonard Pioneer Natural Resources USA, Inc. 1400 Williams Square West 5205 N. O'Connor Blvd. Irving, TX 75039-3746 Pioneer Natural Resources Alaska, Inc. NW Kurparuk, Well: Ivik File No. R-05-393 Halliburton Energy Services Page ii Executive Summary Recombined Oil Preparation: Approximately 5 liter of centrifuged stock tank oil (STO) was provided to Westport for recombined oil preparation. Based on the Ivik separator gas compositions (Hycal Report No.: 2003-023), a solution gas mixture was synthesized. After compositional analysis of the STO, a measured mass of the STO was loaded in a 5 liter cylinder and heated to 168 °F. The synthesized solution gas then added to the STO till a bubblepoint of 1950 psia at 168 °F was achieved. Compositional Analysis: The composition of the recombined oil was determined by flashing a portion of live sample, using a zero psig flash method, and analyzing the evolved gas and its corresponding residual oil by gas chromatography methods. The flash apparatus consists of an intermediate glass tube, an electronic pressure valve, and a gas collection vessel. The apparatus is first evacuated; the glass tube is then isolated from the gas collection vessel and pressurized with helium to atmospheric conditions (14.7 psia and 70°F). As the live sample is slowly released into the glass tube the pressure valve continuously opens, releasing excess gas into the gas collection vessel, and closes, maintaining a pressure of 14.7 psia in the glass tube. The sampling is completed when the pressure in the gas collection vessel is also 14.7 psia. The collected gas and the residual liquid is then analyzed by a gas chromatography method through tridecanes plus (C13+) and hexatriacontanes plus (C36+), respectively. The density and the molecular weight of the residual oil are measured. Using the masses of the flash products and their associated compositions, the composition of the live fluid was mathematically determined. Constant Composition Expansion (CCE): CCE tests were conducted on the recombined oil at 168 °F. Prior to charging the sample in a visual cell, fluid density at charging conditions was measured using a Paar Densitometer. Based on the fluid density and volume charged to the visual cell, total mass of the charged fluid was calculated. A step-wise constant composition expansion of the fluid was then performed yielding saturation pressure, single-phase compressibility, single-phase density, relative volume, percent liquid phase, and Y-function below saturation pressure. Viscosity: A capillary viscometer was charged with the recombined oil and equilibrated at 4000 psia and 168 °F. A step-wise reduction in pressure with corresponding pressure drop measurements was performed at a fixed flow rate. Based on the capillary constant of the tube, viscosity of the oil was determined as a function of the pressure. Pioneer Natural Resources Alaska, Inc. NW Kurparuk, Well: Ivik File No. R-05-393 Halliburton Energy Services Page iii Executive Summary (Cont’d) Injection Gas Preparation: A synthetic injection gas was prepared from pure hydrocarbon components plus carbon dioxide to a composition forwarded from Pioneer. The targeted and measured compositions are presented herein. Solubility & Swelling Experiments: A predetermined volume of prepared reservoir fluid was charged to a windowed PVT cell and equilibrated at reservoir temperature. Successive additions injection gas was added to yield mixtures of 10, 20, 45, and 60 mol percent injection gas in reservoir fluid. Following preparation of each gas-oil mixture, a constant composition expansion experiment was performed to yield saturation pressure, fluid swelling, single-phase compressibility, and two-phase volumetrics. Additional measurements were performed to determine mixture composition (as described above) and single-phase fluid viscosity. During the course of these measurements and especially after disassembly of the PVT cell at the conclusion of testing, it was noticed that what appeared to be asphaltene particles were precipitating and adhering to the cell window and cell stirring mechanism (see picture). These observations were forwarded to a representative of Pioneer Natural Resources and it was decided to perform additional testing to investigate this phenomenon further. Asphaltene Experiments: A windowed PVT cell fitted with Westport Technology Center’s near infrared laser system for detecting solids in a pressurized fluid was charged with prepared reservoir fluid and equilibrated at reservoir temperature and a pressure above reservoir pressure. An isothermal pressure survey was performed while logging light transmittance through the depressurizing crude. (A sharp drop in light transmittance indicates asphaltene flocculation in a depressurizing fluid or wax formation in a cooling system. Gas or fluid addition can also de-stabilize asphaltenes causing flocculation which is seen as a reduction in light transmittance in our system.) The “virgin” reservoir fluid showed no indication of asphaltene flocculation during depressurization. The reduction of pressure yields a reduction in fluid density which in turn yields a slight increase in light transmittance as shown on page 48. Following the above experiment, the system was re-equilibrated at 4500 psia. While logging light transmittance, the injection gas was slowly added and mixed into solution in the reservoir fluid. After injecting only a small volume of gas (6.23 mol%), a sharp drop in transmittance occurred indicating asphaltene flocculation. The stirring mechanism was turned off and the transmittance increased as the asphaltenes micells precipitated. When the stirrer was turned back on, the transmittance again decreased as the particles were mixed back into suspension. This gas titration experiment was repeated at 3300 psia with similar results but requiring only 4.66 mol% gas injection to induce asphaltene flocculation. Pioneer Natural Resources Alaska, Inc. NW Kurparuk, Well: Ivik File No. R-05-393 Halliburton Energy Services Page iv Executive Summary (Cont’d) The flocculated crudes generated above at 4500 and 3300 psia were further examined at pressure and temperature in a high pressure microscope apparatus. Photographs of the fluids with suspended asphaltene particles were analyzed for particle size distribution. These data are presented on page 51. Wax Appearance Temperature: A small volume of stock tank oil was sealed into a capillary tube fitted on a microscope slide with a temperature sensing thermocouple. This assembly was installed on a cross-polar microscope for determination of wax appearance temperature. When cooled to the lowest temperature the apparatus to could achieve (-20°F), no wax crystals were seen to have formed. Stock Tank Oil / Brine Viscosity Measurements: A series of analyses were performed to establish the relationship of viscosity to brine water cut (percentage) and temperature. These tests were performed by mixing stock tank oil with a synthetic formation brine at concentrations of zero to one hundred percent in ten percent increments. The individual mixtures were analyzed at 35, 100, and 175°F with rotational viscometers. These viscosity data plotted in terms of both water cut and temperature can be found on pages 56 and 57. Emulsion Testing: Emulsion stability tests were performed again utilizing stock tank oil and a synthetic formation brine. Ten percent brine water cut through ninety percent in ten percent increments were mixed in graduated tubes and allowed to separate while being examined on a time basis (0 to 48 hours time lapse). This experiment was performed at temperatures of 35, 100, and 171°F. Percent separation and photographs were collected at periodic elapsed times. Deposition of Samples: Westport Technology Center’s policy is to retain samples for 30 days following the date of the final report. Following this time period and providing no additional analyses are requested, the samples can be stored at Westport’s facility at posted charges or shipped to a destination of the client’s choice. Unless instructions are forwarded, it will be assumed that the samples are to be dumped with the resulting fluid disposed of, again at posted charges. Pioneer Natural Resources Alaska, Inc. NW Kurparuk, Well: Ivik File No. R-05-393 Page Cover Letter.......................................................................................................... i Executive Summary..............................................................................................ii-iv Table of Contents................................................................................................. v Reservoir Fluid Preparation & Partial Black Oil Study As-Received Stock Tank Oil Composition......................................................... 1,2 Solution Gas Composition................................................................................. 3 Recombined Oil Composition............................................................................ 4,5 Constant Composition Expansion at 168 °F...................................................... 6-9 Viscosity at 168 °F............................................................................................. 10,11 Enhanced Oil Recovery Study Synthetic Injection Gas Composition................................................................. 12 Summary of Solubility & Swelling Tests Volumetrics..................................................................................................... 13,14 Viscosity..........................................................................................................15-17 Incremental Solubility & Swelling Data 10 mol% Injection Gas....................................................................................18-23 20 mol% Injection Gas....................................................................................24-29 30 mol% Injection Gas....................................................................................30-35 45 mol% Injection Gas....................................................................................36-41 60 mol% Injection Gas....................................................................................42-47 Asphaltene Investigation NIR Laser Scans.............................................................................................48-50 Asphaltene Particle Size Analysis.................................................................. 51-53 Database of Molecular Weights & Densities.........................................................54 Flow Assurance Study Wax Appearance Temperature..........................................................................55 Crude Viscosity as functions of Water Cut & Temperature............................... 56,57 Emulsion Testing Oil/Brine Separation at 35°F........................................................................... 58-66 Oil/Brine Separation at 100°F......................................................................... 67-75 Oil/Brine Separation at 171°F......................................................................... 76-84 Halliburton Energy Services Page v Table of Contents Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Cylinder Number: 478 Sample Type : Stock Tank Oil Wt% Mol% Molecular Weight Density gm/mol gm/cc N2 Nitrogen 0.000 0.000 28.013 0.809 CO2 Carbon Dioxide 0.000 0.000 44.010 0.801 H2S Hydrogen Sulfide 0.000 0.000 34.080 0.817 C1 Methane 0.000 0.000 16.043 0.300 C2 Ethane 0.001 0.010 30.070 0.356 C3 Propane 0.036 0.253 44.097 0.507 iC4 iso-Butane 0.042 0.224 58.123 0.563 nC4 n-Butane 0.156 0.831 58.123 0.584 iC5 iso-Pentane 0.171 0.733 72.150 0.624 nC5 n-Pentane 0.242 1.038 72.150 0.631 C6 Hexanes 0.622 2.292 84 0.685 C7 Heptanes 1.453 4.736 96 0.722 C8 Octanes 2.256 6.621 107 0.745 C9 Nonanes 2.327 5.951 121 0.764 C10 Decanes 2.442 5.640 134 0.778 C11 Undecanes 2.397 5.046 147 0.789 C12 Dodecanes 2.497 4.800 161 0.800 C13 Tridecanes 2.900 5.128 175 0.811 C14 Tetradecanes 2.984 4.860 190 0.822 C15 Pentadecanes 3.018 4.534 206 0.832 C16 Hexadecanes 2.745 3.827 222 0.839 C17 Heptadecanes 2.606 3.403 237 0.847 C18 Octadecanes 2.572 3.171 251 0.852 C19 Nonadecanes 2.428 2.857 263 0.857 C20 Eicosanes 2.384 2.683 275 0.862 C21 Henicosanes 2.226 2.367 291 0.867 C22 Docosanes 2.127 2.158 305 0.872 C23 Tricosanes 1.973 1.920 318 0.877 C24 Tetracosanes 1.825 1.706 331 0.881 C25 Pentacosanes 1.766 1.584 345 0.885 C26 Hexacosanes 1.674 1.443 359 0.889 C27 Heptacosanes 1.631 1.350 374 0.893 C28 Octacosanes 1.581 1.261 388 0.896 C29 Nonacosanes 1.593 1.226 402 0.899 C30 Triacontanes 1.428 1.062 416 0.902 C31 Hentriacontanes 1.351 0.972 430 0.906 C32 Dotriacontanes 1.203 0.838 444 0.909 C33 Tritriacontanes 1.222 0.826 458 0.912 C34 Tetratriacontanes 1.080 0.708 472 0.914 C35 Pentatriacontanes 1.067 0.679 486 0.917 C36+Hexatriacontanes plus 39.974 11.261 1099 1.079 100.000 100.000 Measured Fluid Properties: Density, gm/cc at 60°F 0.9361 Oil Gravity, °API at 60°F 19.5 Molecular Weight, gm/mol 309 Component Data Base Values Compositional Analysis of As-Received Stock Tank Oil By Gas Chromatography Method Halliburton Energy Services Page 1 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Cylinder Number: 478 Sample Type : Stock Tank Oil Molecular Weight Wt.% Mol.%gm/mol Selected Components, Isomers, & Cyclic Compounds(1) C7 Benzene 0.070 0.277 78.12 0.884 C8 Toluene 0.207 0.695 92.15 0.871 Hydrocarbon Plus (Cn+) Properties(2) C6+ Hexanes plus 99.352 96.911 317 0.938 C7+ Heptanes plus 98.730 94.620 323 0.940 C10+ Decanes plus 92.694 77.312 371 0.952 C11+ Undecanes plus 90.252 71.672 390 0.957 C15+ Pentadecanes plus 79.474 51.837 474 0.977 C20+ Eicosanes plus 66.105 34.046 601 1.004 C25+ Pentacosanes plus 55.570 23.212 741 1.029 C30+ Triacontanes plus 47.325 16.348 896 1.053 C36+ Hexatriacontanes plus 39.974 11.261 1099 1.079 (2) Calculated by summation of all compositional data. Elotution Time, Minutes (1) Isomers & cyclics included in pseudo-component compositions on previous page and below. Whole Oil Fingerprint By Capillary Gas Chromatography Composition Analysis (Cont'd) By Gas Chromatography Method STO Sample Density g/cc Component Proper Name Fraction Re s p o n s e , p A min01020304050 pA 0 50 100 150 200 250 300 350 FID2 B, (I:\HPCHEM\DATA\GC6\FEB1005\115221.D) E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 n C 1 0 n C 1 1 n C 1 2 n C 1 3 n C 1 4 n C 1 5 n C 1 6 n C 1 7 n C 1 8 n C 1 9 n C 2 0 n C 2 1 n C 2 2 n C 2 3 n C 2 4 n C 2 5 n C 2 6 n C 2 7 n C 2 8 n C 2 9 n C 3 0 n C 3 1 n C 3 2 n C 3 3 n C 3 4 n C 3 5 n C 3 6 n C 3 7 n C 3 8 min02.5 5 7.5 10 12.5 15 17.5 20 pA 0 100 200 300 400 FID2 B, (I:\HPCHEM\DATA\GC6\FEB1005\115221.D) E t h a n e P r o p a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 n C 1 0 n C 1 1 n C 1 2 Halliburton Energy Services Page 2 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Compositional Analysis of Synthesized Solution Gas N2 Nitrogen 0.642 CO2 Carbon Dioxide 1.265 H2S Hydrogen Sulfide 0.000 C1 Methane 83.171 C2 Ethane 6.670 C3 Propane 4.906 iC4 iso-Butane 0.939 nC4 n-Butane 1.813 iC5 iso-Pentane 0.302 nC5 n-Pentane 0.274 C6 Hexanes 0.018 C7 Heptanes 0.000 C8 Octanes 0.000 C9 Nonanes 0.000 C10 Decanes 0.000 C11 Undecanes 0.000 C12 Dodecanes 0.000 C13+Tridecanes plus 0.000 100.000 C6+Hexanes plus 0.018 C7+Heptanes plus 0.000 C10+Decanes plus 0.000 C7 Benzene* 0.000 C8 Toluene* 0.000 * Included in hydrocarbon fraction above. Gas Gravity (air = 1.000)0.700 Molecular Weight 20.280 Heating Value BTU/Ft3 (gross)1195.000 BTU/Ft3 (net)1083.000 Critical Temperature, °F -70.900 Critical Pressure, psia 666.100 Composition Mol.%Component Halliburton Energy Services Page 3 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Fluid Recombination to 1950 psia saturation pressure at 168 °F Rs Bo (air=1.000) g/mol g/cm³ Ä 4000 168 1.135 191.4 0.8631 14.696 psia 77 263 1.007 0.7284 299.7 0.9312 14.696 psia 60 265 1.000 0.9374 Ä sample charge conditions Oil Gravity at STP: 19.3 °API Standard Conditions (STP) : 14.696 psia & 60°F (1) Evolved Gas/Oil Ratio : Gas at STP per barrel of oil at specified pressure and temperature. (2) Oil Volume Factor : Volume at specified pressure and temperature per volume of residual oil at STP (3) Density of oil phase at specified pressure and temperature. Mol.% Wt.% Mol.% Wt.% Mol.% N2 Nitrogen 0.720 0.000 0.000 0.041 0.280 CO2 Carbon Dioxide 1.392 0.000 0.000 0.124 0.541 H2S Hydrogen Sulfide 0.000 0.000 0.000 0.000 0.000 C1 Methane 82.130 0.000 0.000 2.677 31.929 C2 Ethane 6.507 0.006 0.060 0.403 2.566 C3 Propane 4.664 0.050 0.340 0.466 2.021 iC4 iso-Butane 0.925 0.043 0.222 0.150 0.495 nC4 n-Butane 1.829 0.151 0.779 0.360 1.187 iC5 iso-Pentane 0.484 0.144 0.598 0.209 0.554 nC5 n-Pentane 0.488 0.206 0.856 0.269 0.713 C6 Hexanes 0.379 0.552 1.969 0.595 1.355 C7 Heptanes 0.327 1.404 4.432 1.409 2.841 C8 Octanes 0.136 2.267 6.444 2.201 3.994 C9 Nonanes 0.018 2.359 5.843 2.262 3.578 C10 Decanes 0.001 2.506 5.605 2.399 3.426 C11 Undecanes 0.000 2.472 5.040 2.366 3.080 C12 Dodecanes 0.000 2.528 4.706 2.419 2.876 C13 Tridecanes 0.000 3.029 5.187 2.899 3.170 C14 Tetradecanes 3.103 4.895 2.970 2.991 C15 Pentadecanes 3.057 4.447 2.926 2.718 C16 Hexadecanes 2.868 3.872 2.745 2.366 C17 Heptadecanes 2.704 3.419 2.588 2.090 C18 Octadecanes 2.644 3.157 2.530 1.929 C19 Nonadecanes 2.621 2.987 2.508 1.825 C20 Eicosanes 2.476 2.698 2.370 1.649 C21 Henicosanes 2.312 2.381 2.213 1.455 C22 Docosanes 2.138 2.101 2.046 1.284 C23 Tricosanes 2.015 1.899 1.928 1.161 C24 Tetracosanes 1.875 1.698 1.795 1.037 C25 Pentacosanes 1.784 1.550 1.707 0.947 C26 Hexacosanes 1.738 1.451 1.663 0.887 C27 Heptacosanes 1.691 1.355 1.618 0.828 C28 Octacosanes 1.670 1.290 1.598 0.788 C29 Nonacosanes 1.593 1.188 1.525 0.726 C30 Triacontanes 1.501 1.081 1.437 0.661 C31 Hentriacontanes 1.385 0.965 1.326 0.590 C32 Dotriacontanes 1.306 0.882 1.250 0.539 C33 Tritriacontanes 1.184 0.775 1.133 0.473 C34 Tetratriacontanes 1.140 0.724 1.091 0.442 C35 Pentatriacontanes 1.041 0.642 0.996 0.392 C36+Hexatriacontanes plus 38.437 12.464 36.787 7.617 100.000 100.000 100.000 100.000 100.000 Compositional Analysis By Zero Psig Flash Method Pressure psia Gas/Oil Ratio(1) Oil Molecular Weight Evolved Gas Gravity Oil Volume Factor(2) Temperature °F Component Total Fluid Single-Phase Fluid Density(3) Evolved Gas Residual Liquid Halliburton Energy Services Page 4 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Fluid Recombination to 1950 psia saturation pressure at 168 °F Wt.% Mol.% Selected Components, Isomers, & Cyclic Compounds(1) C7 Benzene 0.068 0.167 78.12 0.884 C8 Toluene 0.202 0.419 92.15 0.871 Hydrocarbon Plus (Cn+) Properties(2) C6+ Hexanes plus 95.301 59.715 305 0.939 C7+ Heptanes plus 94.706 58.360 311 0.941 C10+ Decanes plus 88.834 47.948 355 0.953 C11+ Undecanes plus 86.435 44.522 372 0.958 C15+ Pentadecanes plus 75.781 32.405 448 0.979 C20+ Eicosanes plus 62.483 21.477 557 1.008 C25+ Pentacosanes plus 52.132 14.891 670 1.035 C30+ Triacontanes plus 44.020 10.715 786 1.061 C36+ Hexatriacontanes plus 36.787 7.617 924 1.091 (2) Calculated by summation of all compositional data. SARA Analysis by Liquid Chromatography Fluid - Calculation Basis Saturates wt% Aromatics wt% Resins wt% Asphaltenes wt% Residual Oil - Pentanes Insolubles 30.95 38.67 18.19 12.19 Fraction Composition Analysis (Cont'd) By Zero Psig Flash Method Total Fluid Density g/cm3 Molecular Weight g/mol Component Proper Name Whole Oil Fingerprint By Capillary Gas Chromatography Elution Time, minutes (1) Isomers & cyclics included in pseudo-component compositions on previous page and below. Re s p o n s e , min010203040506070 pA 0 25 50 75 100 125 150 175 200 225 *FID1 A, (I:\HPCHEM\DATA\GC6\032805\117685.D - I:\HPCHEM\DATA\GC6\032805\117734.D) E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 n C 1 0 n C 1 1 n C 1 2 n C 1 3 n C 1 4 n C 1 5 n C 1 6 n C 1 7 n C 1 8 n C 1 9 n C 2 0 n C 2 1 n C 2 2 n C 2 3 n C 2 4 n C 2 5 n C 2 6 n C 2 7 n C 2 8 n C 2 9 n C 3 0 n C 3 1 n C 3 2 n C 3 3 n C 3 4 n C 3 5 min0246810 pA 0 25 50 75 100 125 150 175 200 225 *FID1 A, (I:\HPCHEM\DATA\GC6\032805\117685.D - I:\HPCHEM\DATA\GC6\032805\117734.D) E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 Halliburton Energy Services Page 5 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Pressure-Volume Relationship at 168 °F (Constant Composition Expansion) Sample Type: Recombined Oil Pressure Coefficient of "Y" Relative Liquid Fluid psia Compressibility Function(1)Volume Volume % (2)Density 10-6 (vol/vol) psi-1 (VPb=1.000) (VL/VT× 100) g/cm³ 4044 7.207 0.985 100.00 0.8633 3738 7.252 0.987 100.00 0.8614 3440 7.296 0.989 100.00 0.8595 3143 7.340 0.991 100.00 0.8576 2840 7.386 0.993 100.00 0.8557 2540 7.431 0.996 100.00 0.8538 2241 7.476 0.998 100.00 0.8519 2037 7.507 0.999 100.00 0.8506 Pb 1950 7.520 1.000 100.00 0.8501 1923 4.842 1.004 99.58 1829 4.728 1.014 98.39 1716 4.591 1.029 96.63 1608 4.461 1.048 94.74 1499 4.329 1.069 92.68 1386 4.192 1.097 90.09 1184 3.949 1.164 84.28 982 3.705 1.265 76.85 694 3.357 1.532 62.55 390 2.991 2.352 40.04 (1)Y = (P sat /P -1) / (V/V sat -1) (2)Volume of liquid phase per total sample volume, percent. Pr : Reservoir pressure Pb : Saturation pressure Halliburton Energy Services Page 6 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Si n g l e - P h a s e R e l a t i v e V o l u m e 0. 9 8 4 0. 9 8 6 0. 9 8 8 0. 9 9 0 0. 9 9 2 0. 9 9 4 0. 9 9 6 0. 9 9 8 1. 0 0 0 1. 0 0 2 15 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 Pr e s s u r e , p s i a R e l a t i v e V o l u m e , ( V / V s a t ) Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 7 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Y- f u n c t i o n 2. 5 0 3. 0 0 3. 5 0 4. 0 0 4. 5 0 5. 0 0 20 0 4 0 0 6 0 0 8 0 0 1 0 0 0 1 2 0 0 1 4 0 0 1 6 0 0 1 8 0 0 2 0 0 0 2 2 0 0 Pr e s s u r e , p s i a Y - f u n c t i o n Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 8 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Pe r c e n t L i q u i d 30 . 0 0 40 . 0 0 50 . 0 0 60 . 0 0 70 . 0 0 80 . 0 0 90 . 0 0 10 0 . 0 0 11 0 . 0 0 20 0 4 0 0 6 0 0 8 0 0 1 0 0 0 1 2 0 0 1 4 0 0 1 6 0 0 1 8 0 0 2 0 0 0 2 2 0 0 Pr e s s u r e , p s i a R e l a t i v e L i q u i d V o l u m e , ( V L / V T ) * 1 0 0 Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 9 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Viscosity at 168°F (by Capillary Viscometry) Sample Type: Fluid Recombination to 1950 psia Saturation Pressure at 168 °F Oil Viscosity psia cP 3991 6.72 2993 6.10 2496 5.80 2098 5.55 Pb 1950 5.46 1700 5.95 1401 6.64 1102 7.47 802 8.58 405 10.27 106 12.96 15 15.14 Pr : Reservoir pressure Pb : Bubblepoint pressure Pressure Halliburton Energy Services Page 10 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 V is c o s i t y a t 1 6 8 ° F Sa m p l e T y p e : F l u i d R e c o m b i n a t i o n t o 1 9 5 0 p s i a S a t u r a t i o n P r e s s u r e a t 1 6 8 ° F (b y C a p i l l a r y V i s c o m e t r y ) Si n g l e & T w o - P h a s e O i l V i s c o s i t y 4. 0 0 6. 0 0 8. 0 0 10 . 0 0 12 . 0 0 14 . 0 0 16 . 0 0 0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 Pr e s s u r e , p s i a O i l V i s c o s i t y , c P Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 11 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Compositional Analysis of Synthesized Injection Gas N2 Nitrogen 0.000 0.014 CO2 Carbon Dioxide 1.000 1.051 H2S Hydrogen Sulfide 0.000 0.000 C1 Methane 83.400 83.384 C2 Ethane 8.100 8.121 C3 Propane 4.400 4.355 iC4 iso-Butane 0.000 0.000 nC4 n-Butane 2.500 2.490 iC5 iso-Pentane 0.000 0.002 nC5 n-Pentane 0.500 0.484 C6 Hexanes 0.100 0.097 C7 Heptanes 0.000 0.002 C8 Octanes 0.000 0.000 C9 Nonanes 0.000 0.000 C10 Decanes 0.000 0.000 C11 Undecanes 0.000 0.000 C12 Dodecanes 0.000 0.000 C13+Tridecanes plus 0.000 0.000 100.000 100.000 C6+Hexanes plus 0.100 0.099 C7+Heptanes plus 0.000 0.002 C10+Decanes plus 0.000 0.000 C7 Benzene* 0.000 0.000 C8 Toluene* 0.000 0.000 * Included in hydrocarbon fraction above. Gas Gravity (air = 1.000)0.694 Molecular Weight 20.090 Heating Value BTU/Ft3 (gross)1201 BTU/Ft3 (net)1088 Critical Temperature, °F -71.0 Critical Pressure, psia 667.1 Targeted Composition Mol.% Component Measured Composition Mol.% Halliburton Energy Services Page 12 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Live Oil Cumulative Gas Added Mol % (Live Oil Basis) Mol % (Mixture Basis) Gas/Oil Ratio scf/bbl (A) Original 0.00 0.00 0 1950 1.000 0.8501 A 11.20 10.07 66 2349 1.031 0.8341 B 25.14 20.09 149 3057 1.063 0.8206 C 43.27 30.20 256 3875 1.098 0.8091 D 82.15 45.10 485 5564 1.165 0.7929 E 150.50 60.08 889 7973 1.338 0.7356 Standard Conditions = 14.696 psia and 60°F (A) Standard cubic feet of gas per barrel of original reservoir fluid at 1950 psia and 168°F. (B) Barrels of indicated mixture at saturation pressure per barrel of original reservoir fluid at 1950 psia and 168°F. (C) At saturation pressure of the mixture. Summary of Solubility & Swelling Tests at 168°F Injection Gas Added to Reservoir Fluid Density gm/cc (C) Swollen Volume (B) Mixture Saturation Pressure psia Summary of Solubility & Swelling 1800 2300 2800 3300 3800 4300 4800 5300 5800 6300 6800 7300 7800 8300 0 25 50 75 100 125 150 175 Cumulative Gas Added, mol% (Live Oil Basis) Sa t u r a t i o n P r e s s u r e , p s i a 1.0 1.1 1.1 1.2 1.2 1.3 1.3 1.4 1.4 0 200 400 600 800 1000 Cumulative Gas Added, scf/bbl Sw o l l e n V o l u m e , b b l / b b l Halliburton Energy Services Page 13 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 psia °F Rs Bo (air=1.000) g/mol g/cm³ cP 1950(5)168 1.152 191.4 0.8501 5.46 14.696 psia 77 263 1.007 0.728 299.7 0.9312 14.696 psia 60 265 1.000 0.9374 2349(5)168 1.191 177.4 0.8341 5.12 14.696 psia 77 331 1.007 0.743 303.6 0.9331 14.696 psia 60 333 1.000 0.9393 3057(5)168 1.232 159.2 0.8206 3.91 14.696 psia 75 438 1.006 0.740 309.3 0.9346 14.696 psia 60 441 1.000 0.9402 3875(5)168 1.274 141.3 0.8091 3.23 14.696 psia 76 567 1.006 0.717 313.4 0.9359 14.696 psia 60 570 1.000 0.9417 5564(5)168 1.357 112.0 0.7929 2.09 14.696 psia 73 865 1.005 0.725 305.2 0.9341 14.696 psia 60 869 1.000 0.9388 7973(5)168 1.598 81.2 0.7356 0.96 14.696 psia 76 1518 1.006 0.720 313.5 0.9298 14.696 psia 60 1528 1.000 0.9356 Standard Conditions (STP) : 14.696 psia & 60°F (1) Evolved Gas/Oil Ratio : Gas at STP per barrel of oil at specified pressure and temperature. (2) Oil Volume Factor : Volume at specified pressure and temperature per volume of residual oil at STP (3) Density of oil phase at specified pressure and temperature. (4) Viscosity of oil phase at specified pressure and temperature. (5) Saturation pressure of oil phase at specified temperature. Summary: SARA Analysis of Residual Liquid Phase (Pentane Insolubles) Fluid - Calculation Basis Saturates wt% Aromatics wt% Resins wt% Asphaltenes wt% Recombined Live Oil 30.95 38.67 18.19 12.19 10.07 Mole% Gas in Mixture 35.15 35.18 17.30 12.37 20.09 Mole% Gas in Mixture 34.74 35.62 17.08 12.56 30.20 Mole% Gas in Mixture 32.41 39.18 14.87 13.54 45.10 Mole% Gas in Mixture 34.32 36.03 17.00 12.65 60.08 Mole% Gas in Mixture 35.74 36.92 18.00 9.33 Summary: Fluid Density and Gas-Oil Ratio 60.08 Mole% Gas in Mixture 45.10 Mole% Gas in Mixture Recombined Live Oil 10.07 Mole% Gas in Mixture 20.09 Mole% Gas in Mixture 30.20 Mole% Gas in Mixture Single-Phase Fluid Viscosity(4) TemperaturePressure Single-Phase Fluid Density(3)Fluid Description Oil Molecular Weight Gas/Oil Ratio(1) Oil Volume Factor(2) Evolved Gas Gravity Halliburton Energy Services Page 14 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Single-Phase Oil & Mixture Viscosity at 168°F (by Capillary Viscometry) Sample Type: Recombined Oil + Injection Gas Mole% psia cP gm/cc 0.00 3991 6.723 0.8630 0.00 2993 6.105 0.8567 0.00 2496 5.803 0.8536 0.00 2098 5.553 0.8510 Pb 0.00 1950 5.463 0.8501 10.07 4985 6.638 0.8538 10.07 3985 6.042 0.8475 10.07 2981 5.492 0.8397 Pb 10.07 2349 5.122 0.8341 20.09 6988 5.599 0.8422 20.09 5490 4.933 0.8373 20.09 3982 4.318 0.8282 Pb 20.09 3057 3.915 0.8206 30.20 5986 3.794 0.8275 30.20 4978 3.510 0.8196 30.20 4482 3.398 0.8151 Pb 30.20 3875 3.228 0.8091 45.10 8981 2.628 0.8121 45.10 7986 2.462 0.8082 45.10 6984 2.313 0.8029 Pb 45.10 5564 2.086 0.7929 60.08 10986 1.120 0.7539 60.08 9983 1.071 0.7498 60.08 8985 1.015 0.7437 Pb 60.08 7973 0.963 0.7356 Pb : Bubblepoint pressure Pd : Dewpoint pressure Mixture Viscosity Injection Gas in Mixture Pressure Mixture Density Halliburton Energy Services Page 15 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + I n j e c t i o n G a s (b y C a p i l l a r y V i s c o m e t r y ) Vi s c o s i t y a t 1 6 8 ° F O i l - G a s M i x t u r e V i s c o s i t y 0. 0 0 0. 5 0 1. 0 0 1. 5 0 2. 0 0 2. 5 0 3. 0 0 3. 5 0 4. 0 0 4. 5 0 5. 0 0 5. 5 0 6. 0 0 6. 5 0 7. 0 0 10 0 0 2 0 0 0 3 0 0 0 4 0 0 0 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 1 0 0 0 0 1 1 0 0 0 Pr e s s u r e , p s i a O i l V i s c o s i t y , c P 0. 0 M o l e % G a s i n M i x t u r e 10 . 0 7 M o l e % G a s i n M i x t u r e 20 . 0 9 M o l e % G a s i n M i x t u r e 30 . 2 0 M o l e % G a s i n M i x t u r e 45 . 1 0 M o l e % G a s i n M i x t u r e 60 . 0 8 M o l e % G a s i n M i x t u r e H a l l i b u r t o n E n e r g y S e r v i c e s Page 16 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + I n j e c t i o n G a s (b y C a p i l l a r y V i s c o m e t r y ) Vi s c o s i t y a t 1 6 8 ° F Sa t u r a t e d O i l - G a s M i x t u r e V i s c o s i t y 0. 0 0 0. 5 0 1. 0 0 1. 5 0 2. 0 0 2. 5 0 3. 0 0 3. 5 0 4. 0 0 4. 5 0 5. 0 0 5. 5 0 6. 0 0 0 1 0 2 0 3 0 4 0 5 0 6 0 7 0 Mo l e % I n j e c t i o n G a s i n M i x t u r e O i l V i s c o s i t y a t S a t u r a t i o n P r e s s u r e , c P Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 17 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Oil + 10.07 Mole% Injection Gas in Mixture Rs Bo (air=1.000) g/mol g/cm³ Ä 7253 168 177.4 0.8628 14.696 psia 77 331 1.007 0.7431 303.6 0.9331 14.696 psia 60 333 1.000 0.9393 Ä sample charge conditions Oil Gravity at STP: 19.0 °API Standard Conditions (STP) : 14.696 psia & 60°F (1) Evolved Gas/Oil Ratio : Gas at STP per barrel of oil at specified pressure and temperature. (2) Oil Volume Factor : Volume at specified pressure and temperature per volume of residual oil at STP (3) Density of oil phase at specified pressure and temperature. Mol.% Wt.% Mol.% Wt.% Mol.% N2 Nitrogen 0.573 0.000 0.000 0.040 0.256 CO2 Carbon Dioxide 1.076 0.000 0.000 0.119 0.481 H2S Hydrogen Sulfide 0.000 0.000 0.000 0.000 0.000 C1 Methane 81.010 0.000 0.000 3.278 36.236 C2 Ethane 7.165 0.003 0.030 0.546 3.222 C3 Propane 4.951 0.029 0.200 0.578 2.325 iC4 iso-Butane 1.285 0.037 0.193 0.223 0.682 nC4 n-Butane 1.794 0.097 0.507 0.355 1.082 iC5 iso-Pentane 0.528 0.110 0.463 0.200 0.492 nC5 n-Pentane 0.583 0.177 0.745 0.273 0.672 C6 Hexanes 0.435 0.499 1.803 0.566 1.196 C7 Heptanes 0.383 1.314 4.200 1.338 2.499 C8 Octanes 0.168 2.204 6.344 2.132 3.585 C9 Nonanes 0.039 2.304 5.780 2.191 3.212 C10 Decanes 0.008 2.498 5.659 2.365 3.130 C11 Undecanes 0.002 2.453 5.065 2.320 2.800 C12 Dodecanes 0.000 2.547 4.802 2.408 2.653 C13 Tridecanes 0.000 3.041 5.275 2.876 2.914 C14 Tetradecanes 3.166 5.058 2.994 2.795 C15 Pentadecanes 3.052 4.497 2.886 2.485 C16 Hexadecanes 2.909 3.978 2.751 2.198 C17 Heptadecanes 2.690 3.445 2.544 1.904 C18 Octadecanes 2.711 3.279 2.564 1.811 C19 Nonadecanes 2.602 3.003 2.460 1.659 C20 Eicosanes 2.503 2.763 2.367 1.527 C21 Henicosanes 2.380 2.483 2.251 1.372 C22 Docosanes 2.132 2.122 2.016 1.172 C23 Tricosanes 2.036 1.943 1.925 1.074 C24 Tetracosanes 1.912 1.753 1.808 0.969 C25 Pentacosanes 1.820 1.601 1.721 0.885 C26 Hexacosanes 1.741 1.472 1.646 0.813 C27 Heptacosanes 1.730 1.404 1.636 0.776 C28 Octacosanes 1.650 1.291 1.560 0.713 C29 Nonacosanes 1.612 1.217 1.524 0.673 C30 Triacontanes 1.520 1.109 1.437 0.613 C31 Hentriacontanes 1.424 1.005 1.347 0.555 C32 Dotriacontanes 1.286 0.879 1.216 0.486 C33 Tritriacontanes 1.193 0.791 1.128 0.437 C34 Tetratriacontanes 1.157 0.744 1.094 0.411 C35 Pentatriacontanes 1.039 0.649 0.982 0.359 C36+Hexatriacontanes plus 38.422 12.448 36.332 6.878 100.000 100.000 100.000 100.000 100.000 Component Total Fluid Single-Phase Fluid Density(3) Evolved Gas Residual Liquid Compositional Analysis By Zero Psig Flash Method Pressure psia Gas/Oil Ratio(1) Oil Molecular Weight Evolved Gas Gravity Oil Volume Factor(2) Temperature °F Halliburton Energy Services Page 18 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Oil + 10.07 Mole% Injection Gas in Mixture Wt.% Mol.% Selected Components, Isomers, & Cyclic Compounds (1) C7 Benzene 0.063 0.143 78.12 0.884 C8 Toluene 0.193 0.372 92.15 0.871 Hydrocarbon Plus (Cn+) Properties(2) C6+ Hexanes plus 94.387 54.552 307 0.940 C7+ Heptanes plus 93.820 53.356 312 0.942 C10+ Decanes plus 88.159 44.060 355 0.954 C11+ Undecanes plus 85.794 40.930 372 0.959 C15+ Pentadecanes plus 75.196 29.768 448 0.980 C20+ Eicosanes plus 61.992 19.711 558 1.009 C25+ Pentacosanes plus 51.625 13.598 673 1.037 C30+ Triacontanes plus 43.537 9.738 793 1.063 C36+ Hexatriacontanes plus 36.332 6.878 937 1.094 (2) Calculated by summation of all compositional data. SARA Analysis by Liquid Chromatography Fluid - Calculation Basis Saturates wt% Aromatics wt% Resins wt% Asphaltenes wt% Residual Oil - Pentanes Insolubles 35.15 35.18 17.30 12.37 Whole Oil Fingerprint By Capillary Gas Chromatography Elution Time, minutes (1) Isomers & cyclics included in pseudo-component compositions on previous page and below. Fraction Composition Analysis (Cont'd) By Zero Psig Flash Method Total Fluid Density g/cm3 Molecular Weight g/mol Component Proper Name Re s p o n s e , min010203040506070 pA 0 50 100 150 200 *FID1 A, (I:\HPCHEM\DATA\GC6\060605\120541.D - I:\HPCHEM\DATA\GC6\060605\121382.D) E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 n C 1 0 n C 1 1 n C 1 2 n C 1 3 n C 1 4 n C 1 5 n C 1 6 n C 1 7 n C 1 8 n C 1 9 n C 2 0 n C 2 1 n C 2 2 n C 2 3 n C 2 4 n C 2 5 n C 2 6 n C 2 7 n C 2 8 n C 2 9 n C 3 0 n C 3 1 n C 3 2 n C 3 3 n C 3 4 n C 3 5 min0246810 pA 0 50 100 150 200 *FID1 A, (I:\HPCHEM\DATA\GC6\060605\120541.D - I:\HPCHEM\DATA\GC6\060605\121382.D E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 Halliburton Energy Services Page 19 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Pressure-Volume Relationship at 168 °F (Constant Composition Expansion) Sample Type: Recombined Oil + 10.07 Mole% Injection Gas in Mixture Pressure Coefficient of "Y" Relative Liquid Fluid psia Compressibility Function(1)Volume Volume % (2)Density 10-6 (vol/vol) psi-1 (VPb=1.000) (VL/VT× 100) g/cm³ 5051 6.437 0.977 100.00 0.8541 4849 6.782 0.978 100.00 0.8530 4650 7.125 0.979 100.00 0.8518 4451 7.468 0.981 100.00 0.8506 4250 7.815 0.982 100.00 0.8493 4051 8.162 0.984 100.00 0.8479 3851 8.512 0.985 100.00 0.8465 3649 8.867 0.987 100.00 0.8450 3448 9.223 0.989 100.00 0.8435 3250 9.575 0.991 100.00 0.8419 3050 9.933 0.993 100.00 0.8403 2850 10.291 0.995 100.00 0.8386 2649 10.655 0.997 100.00 0.8368 2450 11.017 0.999 100.00 0.8350 Pb 2349 11.202 1.000 100.00 0.8341 2286 4.725 1.006 98.97 2233 4.665 1.012 98.29 2175 4.600 1.018 97.44 2120 4.538 1.024 96.73 2045 4.453 1.034 95.59 1943 4.338 1.048 94.06 1844 4.228 1.065 92.38 1647 4.006 1.106 88.53 1448 3.782 1.165 83.46 1247 3.556 1.248 77.44 948 3.219 1.450 66.10 648 2.883 1.890 50.25 403 2.607 2.858 32.88 (1)Y = (P sat /P -1) / (V/V sat -1) (2)Volume of liquid phase per total sample volume, percent. Pr : Reservoir pressure Pb : Saturation pressure Halliburton Energy Services Page 20 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 1 0 . 0 7 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Si n g l e - P h a s e R e l a t i v e V o l u m e 0. 9 7 5 0. 9 8 0 0. 9 8 5 0. 9 9 0 0. 9 9 5 1. 0 0 0 1. 0 0 5 20 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 Pr e s s u r e , p s i a R e l a t i v e V o l u m e , ( V / V s a t ) Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 21 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 1 0 . 0 7 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Y- f u n c t i o n 2. 0 0 2. 5 0 3. 0 0 3. 5 0 4. 0 0 4. 5 0 5. 0 0 0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 Pr e s s u r e , p s i a Y - f u n c t i o n Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 22 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 1 0 . 0 7 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Pe r c e n t L i q u i d 30 . 0 0 40 . 0 0 50 . 0 0 60 . 0 0 70 . 0 0 80 . 0 0 90 . 0 0 10 0 . 0 0 11 0 . 0 0 0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 Pr e s s u r e , p s i a R e l a t i v e L i q u i d V o l u m e , ( V L / V T ) * 1 0 0 Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 23 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Oil + 20.09 Mole% Injection Gas in Mixture Rs Bo (air=1.000) g/mol g/cm³ Ä 8020 168 159.2 0.8433 14.696 psia 75 438 1.006 0.7401 309.3 0.9346 14.696 psia 60 441 1.000 0.9402 Ä sample charge conditions Oil Gravity at STP: 18.9 °API Standard Conditions (STP) : 14.696 psia & 60°F (1) Evolved Gas/Oil Ratio : Gas at STP per barrel of oil at specified pressure and temperature. (2) Oil Volume Factor : Volume at specified pressure and temperature per volume of residual oil at STP (3) Density of oil phase at specified pressure and temperature. Mol.% Wt.% Mol.% Wt.% Mol.% N2 Nitrogen 0.443 0.000 0.000 0.041 0.231 CO2 Carbon Dioxide 1.120 0.000 0.000 0.161 0.584 H2S Hydrogen Sulfide 0.000 0.000 0.000 0.000 0.000 C1 Methane 81.296 0.000 0.000 4.269 42.366 C2 Ethane 7.280 0.005 0.051 0.721 3.818 C3 Propane 4.791 0.024 0.168 0.714 2.577 iC4 iso-Butane 1.479 0.033 0.176 0.312 0.855 nC4 n-Butane 1.490 0.058 0.309 0.337 0.924 iC5 iso-Pentane 0.467 0.073 0.313 0.178 0.393 nC5 n-Pentane 0.572 0.133 0.570 0.259 0.571 C6 Hexanes 0.428 0.420 1.546 0.511 0.969 C7 Heptanes 0.385 1.195 3.890 1.236 2.071 C8 Octanes 0.178 2.121 6.216 2.037 3.074 C9 Nonanes 0.051 2.285 5.840 2.146 2.823 C10 Decanes 0.015 2.476 5.714 2.309 2.743 C11 Undecanes 0.004 2.426 5.104 2.257 2.445 C12 Dodecanes 0.001 2.556 4.910 2.377 2.351 C13 Tridecanes 0.000 3.045 5.381 2.831 2.576 C14 Tetradecanes 3.171 5.161 2.948 2.470 C15 Pentadecanes 3.044 4.570 2.830 2.187 C16 Hexadecanes 2.915 4.061 2.710 1.944 C17 Heptadecanes 2.702 3.526 2.512 1.688 C18 Octadecanes 2.680 3.302 2.492 1.580 C19 Nonadecanes 2.635 3.098 2.450 1.483 C20 Eicosanes 2.502 2.814 2.326 1.347 C21 Henicosanes 2.348 2.495 2.183 1.194 C22 Docosanes 2.163 2.193 2.011 1.050 C23 Tricosanes 2.074 2.017 1.928 0.965 C24 Tetracosanes 1.866 1.743 1.735 0.834 C25 Pentacosanes 1.812 1.624 1.685 0.777 C26 Hexacosanes 1.752 1.509 1.629 0.722 C27 Heptacosanes 1.699 1.405 1.580 0.672 C28 Octacosanes 1.655 1.319 1.539 0.631 C29 Nonacosanes 1.632 1.255 1.517 0.601 C30 Triacontanes 1.490 1.108 1.385 0.530 C31 Hentriacontanes 1.406 1.011 1.307 0.484 C32 Dotriacontanes 1.287 0.896 1.197 0.429 C33 Tritriacontanes 1.331 0.899 1.237 0.430 C34 Tetratriacontanes 1.116 0.731 1.038 0.350 C35 Pentatriacontanes 0.956 0.608 0.889 0.291 C36+Hexatriacontanes plus 38.914 12.466 36.178 5.967 100.000 100.000 100.000 100.000 100.000 Component Total Fluid Single-Phase Fluid Density(3) Evolved Gas Residual Liquid Compositional Analysis By Zero Psig Flash Method Pressure psia Gas/Oil Ratio(1) Oil Molecular Weight Evolved Gas Gravity Oil Volume Factor(2) Temperature °F Halliburton Energy Services Page 24 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Oil + 20.09 Mole% Injection Gas in Mixture Wt.% Mol.% Selected Components, Isomers, & Cyclic Compounds(1) C7 Benzene 0.057 0.116 78.12 0.884 C8 Toluene 0.176 0.304 92.15 0.871 Hydrocarbon Plus (Cn+) Properties(2) C6+ Hexanes plus 93.008 47.681 311 0.941 C7+ Heptanes plus 92.497 46.712 315 0.942 C10+ Decanes plus 87.078 38.744 358 0.954 C11+ Undecanes plus 84.769 36.000 375 0.958 C15+ Pentadecanes plus 74.356 26.159 453 0.980 C20+ Eicosanes plus 61.363 17.277 565 1.008 C25+ Pentacosanes plus 51.180 11.886 686 1.036 C30+ Triacontanes plus 43.231 8.482 812 1.062 C36+ Hexatriacontanes plus 36.178 5.967 965 1.092 (2) Calculated by summation of all compositional data. SARA Analysis by Liquid Chromatography Fluid - Calculation Basis Saturates wt% Aromatics wt% Resins wt% Asphaltenes wt% Residual Oil - Pentanes Insolubles 34.74 35.62 17.08 12.56 Whole Oil Fingerprint By Capillary Gas Chromatography Elution Time, minutes (1) Isomers & cyclics included in pseudo-component compositions on previous page and below. Fraction Composition Analysis (Cont'd) By Zero Psig Flash Method Total Fluid Density g/cm3 Molecular Weight g/mol Component Proper Name Re s p o n s e , min010203040506070 pA 0 50 100 150 200 *FID1 A, (I:\HPCHEM\DATA\GC6\053105\120536.D - I:\HPCHEM\DATA\GC6\053105\121006.D) E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 n C 1 0 n C 1 1 n C 1 2 n C 1 3 n C 1 4 n C 1 5 n C 1 6 n C 1 7 n C 1 8 n C 1 9 n C 2 0 n C 2 1 n C 2 2 n C 2 3 n C 2 4 n C 2 5 n C 2 6 n C 2 7 n C 2 8 n C 2 9 n C 3 0 n C 3 1 n C 3 2 n C 3 3 n C 3 4 n C 3 5 min0246810 pA 0 50 100 150 200 *FID1 A, (I:\HPCHEM\DATA\GC6\053105\120536.D - I:\HPCHEM\DATA\GC6\053105\121006.D) E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 Halliburton Energy Services Page 25 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Pressure-Volume Relationship at 168 °F (Constant Composition Expansion) Sample Type: Recombined Oil + 20.09 Mole% Injection Gas in Mixture Pressure Coefficient of "Y" Relative Liquid Fluid psia Compressibility Function(1)Volume Volume % (2)Density 10-6 (vol/vol) psi-1 (VPb=1.000) (VL/VT× 100) g/cm³ 5051 6.522 0.983 100.00 0.8351 4851 6.963 0.984 100.00 0.8339 4650 7.407 0.985 100.00 0.8327 4452 7.847 0.987 100.00 0.8315 4251 8.293 0.989 100.00 0.8301 4051 8.741 0.990 100.00 0.8287 3852 9.190 0.992 100.00 0.8273 3651 9.646 0.994 100.00 0.8257 3450 10.104 0.996 100.00 0.8240 3249 10.565 0.998 100.00 0.8223 Pb 3057 11.007 1.000 100.00 0.8206 3051 5.682 1.000 99.79 2977 5.601 1.004 99.09 2924 5.542 1.007 98.57 2869 5.480 1.011 98.15 2799 5.402 1.016 97.50 2699 5.290 1.025 96.40 2599 5.178 1.033 95.25 2449 5.011 1.049 93.41 2247 4.785 1.076 90.53 2048 4.562 1.108 87.49 1848 4.340 1.151 83.72 1548 4.005 1.243 76.80 1250 3.671 1.393 67.91 949 3.335 1.662 56.33 518 2.854 2.729 33.69 (1)Y = (P sat /P -1) / (V/V sat -1) (2)Volume of liquid phase per total sample volume, percent. Pr : Reservoir pressure Pb : Saturation pressure Halliburton Energy Services Page 26 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 2 0 . 0 9 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Si n g l e - P h a s e R e l a t i v e V o l u m e 0. 9 8 0 0. 9 8 2 0. 9 8 4 0. 9 8 6 0. 9 8 8 0. 9 9 0 0. 9 9 2 0. 9 9 4 0. 9 9 6 0. 9 9 8 1. 0 0 0 1. 0 0 2 25 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 Pr e s s u r e , p s i a R e l a t i v e V o l u m e , ( V / V s a t ) Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 27 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 2 0 . 0 9 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Y- f u n c t i o n 2. 5 0 3. 0 0 3. 5 0 4. 0 0 4. 5 0 5. 0 0 5. 5 0 6. 0 0 6. 5 0 0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 Pr e s s u r e , p s i a Y - f u n c t i o n Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 28 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 2 0 . 0 9 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Pe r c e n t L i q u i d 30 . 0 0 40 . 0 0 50 . 0 0 60 . 0 0 70 . 0 0 80 . 0 0 90 . 0 0 10 0 . 0 0 11 0 . 0 0 0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 Pr e s s u r e , p s i a R e l a t i v e L i q u i d V o l u m e , ( V L / V T ) * 1 0 0 Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 29 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Oil + 30.20 Mole% Injection Gas in Mixture Rs Bo (air=1.000) g/mol g/cm³ Ä 5007 168 141.3 0.8198 14.696 psia 76 567 1.006 0.7169 313.4 0.9359 14.696 psia 60 570 1.000 0.9417 Ä sample charge conditions Oil Gravity at STP: 18.6 °API Standard Conditions (STP) : 14.696 psia & 60°F (1) Evolved Gas/Oil Ratio : Gas at STP per barrel of oil at specified pressure and temperature. (2) Oil Volume Factor : Volume at specified pressure and temperature per volume of residual oil at STP (3) Density of oil phase at specified pressure and temperature. Mol.% Wt.% Mol.% Wt.% Mol.% N2 Nitrogen 0.379 0.000 0.000 0.044 0.223 CO2 Carbon Dioxide 1.110 0.000 0.000 0.203 0.653 H2S Hydrogen Sulfide 0.000 0.000 0.000 0.000 0.000 C1 Methane 82.007 0.000 0.000 5.477 48.234 C2 Ethane 7.555 0.000 0.000 0.946 4.443 C3 Propane 4.764 0.006 0.043 0.880 2.820 iC4 iso-Butane 1.690 0.017 0.092 0.424 1.032 nC4 n-Butane 1.269 0.026 0.140 0.331 0.804 iC5 iso-Pentane 0.418 0.046 0.200 0.168 0.328 nC5 n-Pentane 0.566 0.093 0.404 0.255 0.499 C6 Hexanes 0.153 0.340 1.269 0.365 0.615 C7 Heptanes 0.061 1.046 3.450 0.979 1.458 C8 Octanes 0.022 1.997 5.933 1.834 2.457 C9 Nonanes 0.004 2.238 5.797 2.047 2.390 C10 Decanes 0.002 2.467 5.770 2.255 2.377 C11 Undecanes 0.000 2.442 5.207 2.231 2.144 C12 Dodecanes 0.000 2.534 4.933 2.315 2.031 C13 Tridecanes 0.000 3.027 5.422 2.765 2.233 C14 Tetradecanes 3.147 5.191 2.875 2.138 C15 Pentadecanes 3.030 4.610 2.768 1.898 C16 Hexadecanes 2.881 4.068 2.632 1.675 C17 Heptadecanes 2.686 3.552 2.454 1.463 C18 Octadecanes 2.665 3.328 2.435 1.370 C19 Nonadecanes 2.601 3.100 2.376 1.276 C20 Eicosanes 2.475 2.821 2.261 1.162 C21 Henicosanes 2.364 2.546 2.160 1.049 C22 Docosanes 2.099 2.157 1.917 0.888 C23 Tricosanes 2.061 2.031 1.883 0.837 C24 Tetracosanes 1.869 1.770 1.707 0.729 C25 Pentacosanes 1.811 1.645 1.654 0.678 C26 Hexacosanes 1.716 1.498 1.568 0.617 C27 Heptacosanes 1.702 1.426 1.555 0.587 C28 Octacosanes 1.714 1.385 1.566 0.570 C29 Nonacosanes 1.566 1.221 1.431 0.503 C30 Triacontanes 1.485 1.119 1.357 0.461 C31 Hentriacontanes 1.416 1.032 1.294 0.425 C32 Dotriacontanes 1.275 0.900 1.165 0.371 C33 Tritriacontanes 1.235 0.845 1.128 0.348 C34 Tetratriacontanes 1.172 0.778 1.071 0.320 C35 Pentatriacontanes 1.086 0.700 0.992 0.288 C36+Hexatriacontanes plus 39.665 13.615 36.235 5.607 100.000 100.000 100.000 100.000 100.000 Component Total Fluid Single-Phase Fluid Density(3) Evolved Gas Residual Liquid Compositional Analysis By Zero Psig Flash Method Pressure psia Gas/Oil Ratio(1) Oil Molecular Weight Evolved Gas Gravity Oil Volume Factor(2) Temperature °F Halliburton Energy Services Page 30 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Oil + 30.20 Mole% Injection Gas in Mixture Wt.% Mol.% Selected Components, Isomers, & Cyclic Compounds(1) C7 Benzene 0.049 0.089 78.12 0.884 C8 Toluene 0.166 0.255 92.15 0.871 Hydrocarbon Plus (Cn+) Properties(2) C6+ Hexanes plus 91.272 40.964 315 0.942 C7+ Heptanes plus 90.907 40.349 318 0.943 C10+ Decanes plus 86.047 34.045 357 0.954 C11+ Undecanes plus 83.792 31.667 374 0.959 C15+ Pentadecanes plus 73.606 23.122 450 0.980 C20+ Eicosanes plus 60.942 15.439 558 1.008 C25+ Pentacosanes plus 51.014 10.775 669 1.034 C30+ Triacontanes plus 43.241 7.820 781 1.060 C36+ Hexatriacontanes plus 36.235 5.607 913 1.089 (2) Calculated by summation of all compositional data. SARA Analysis by Liquid Chromatography Fluid - Calculation Basis Saturates wt% Aromatics wt% Resins wt% Asphaltenes wt% Residual Oil - Pentanes Insolubles 32.41 39.18 14.87 13.54 Whole Oil Fingerprint By Capillary Gas Chromatography Elution Time, minutes (1) Isomers & cyclics included in pseudo-component compositions on previous page and below. Fraction Composition Analysis (Cont'd) By Zero Psig Flash Method Total Fluid Density g/cm3 Molecular Weight g/mol Component Proper Name Re s p o n s e , min010203040506070 pA 0 50 100 150 200 *FID1 A, (I:\HPCHEM\DATA\GC6\051605\120300.D - I:\HPCHEM\DATA\GC6\051605\120352.D E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 n C 1 0 n C 1 1 n C 1 2 n C 1 3 n C 1 4 n C 1 5 n C 1 6 n C 1 7 n C 1 8 n C 1 9 n C 2 0 n C 2 1 n C 2 2 n C 2 3 n C 2 4 n C 2 5 n C 2 6 n C 2 7 n C 2 8 n C 2 9 n C 3 0 n C 3 1 n C 3 2 n C 3 3 n C 3 4 n C 3 5 min0246810 pA 0 50 100 150 200 *FID1 A, (I:\HPCHEM\DATA\GC6\051605\120300.D - I:\HPCHEM\DATA\GC6\051605\120352.D) E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 Halliburton Energy Services Page 31 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Pressure-Volume Relationship at 168 °F (Constant Composition Expansion) Sample Type: Recombined Oil + 30.20 Mole% Injection Gas in Mixture Pressure Coefficient of "Y" Relative Liquid Fluid psia Compressibility Function(1)Volume Volume % (2)Density 10-6 (vol/vol) psi-1 (VPb=1.000) (VL/VT× 100) g/cm³ 5051 10.376 0.986 100.00 0.8202 4851 10.771 0.989 100.00 0.8185 4650 11.170 0.991 100.00 0.8167 4449 11.572 0.993 100.00 0.8148 4244 11.982 0.995 100.00 0.8128 4049 12.377 0.998 100.00 0.8109 3949 12.581 0.999 100.00 0.8099 Pb 3875 12.733 1.000 100.00 0.8091 3849 6.431 1.001 99.65 3798 6.377 1.003 99.21 3748 6.325 1.006 98.79 3698 6.273 1.008 98.35 3628 6.200 1.011 97.78 3549 6.118 1.015 97.16 3445 6.010 1.020 96.30 3347 5.908 1.027 95.48 3248 5.805 1.034 94.52 3149 5.701 1.041 93.59 3046 5.594 1.048 92.61 2948 5.493 1.057 91.66 2750 5.287 1.077 89.37 2547 5.075 1.100 86.79 2349 4.869 1.131 83.76 2049 4.557 1.193 78.77 1748 4.244 1.287 72.40 1447 3.931 1.427 64.86 1149 3.620 1.653 55.54 846 3.305 2.080 43.52 545 2.992 3.050 29.39 (1)Y = (P sat /P -1) / (V/V sat -1) (2)Volume of liquid phase per total sample volume, percent. Pr : Reservoir pressure Pb : Saturation pressure Halliburton Energy Services Page 32 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 3 0 . 2 0 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Si n g l e - P h a s e R e l a t i v e V o l u m e 0. 9 8 4 0. 9 8 6 0. 9 8 8 0. 9 9 0 0. 9 9 2 0. 9 9 4 0. 9 9 6 0. 9 9 8 1. 0 0 0 1. 0 0 2 35 0 0 3 7 0 0 3 9 0 0 4 1 0 0 4 3 0 0 4 5 0 0 4 7 0 0 4 9 0 0 5 1 0 0 5 3 0 0 5 5 0 0 Pr e s s u r e , p s i a R e l a t i v e V o l u m e , ( V / V s a t ) Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 33 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 3 0 . 2 0 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Y- f u n c t i o n 2. 5 0 3. 0 0 3. 5 0 4. 0 0 4. 5 0 5. 0 0 5. 5 0 6. 0 0 6. 5 0 7. 0 0 0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 Pr e s s u r e , p s i a Y - f u n c t i o n Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 34 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 3 0 . 2 0 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Pe r c e n t L i q u i d 20 . 0 0 30 . 0 0 40 . 0 0 50 . 0 0 60 . 0 0 70 . 0 0 80 . 0 0 90 . 0 0 10 0 . 0 0 11 0 . 0 0 0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 Pr e s s u r e , p s i a R e l a t i v e L i q u i d V o l u m e , ( V L / V T ) * 1 0 0 Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 35 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Oil + 45.10 Mole% Injection Gas in Mixture Rs Bo (air=1.000) g/mol g/cm³ Ä 9023 168 112.0 0.8122 14.696 psia 73 865 1.005 0.7252 305.2 0.9341 14.696 psia 60 869 1.000 0.9388 Ä sample charge conditions Oil Gravity at STP: 19.1 °API Standard Conditions (STP) : 14.696 psia & 60°F (1) Evolved Gas/Oil Ratio : Gas at STP per barrel of oil at specified pressure and temperature. (2) Oil Volume Factor : Volume at specified pressure and temperature per volume of residual oil at STP (3) Density of oil phase at specified pressure and temperature. Mol.% Wt.% Mol.% Wt.% Mol.% N2 Nitrogen 0.234 0.000 0.000 0.040 0.159 CO2 Carbon Dioxide 0.981 0.000 0.000 0.262 0.667 H2S Hydrogen Sulfide 0.000 0.000 0.000 0.000 0.000 C1 Methane 82.087 0.000 0.000 7.994 55.793 C2 Ethane 7.656 0.003 0.030 1.400 5.213 C3 Propane 4.579 0.026 0.180 1.248 3.170 iC4 iso-Butane 1.853 0.054 0.284 0.701 1.350 nC4 n-Butane 0.913 0.051 0.268 0.367 0.706 iC5 iso-Pentane 0.313 0.067 0.283 0.196 0.303 nC5 n-Pentane 0.519 0.164 0.694 0.370 0.575 C6 Hexanes 0.345 0.433 1.573 0.558 0.744 C7 Heptanes 0.324 1.203 3.865 1.244 1.466 C8 Octanes 0.152 2.122 6.141 1.955 2.075 C9 Nonanes 0.037 2.270 5.725 2.009 1.859 C10 Decanes 0.006 2.477 5.641 2.166 1.810 C11 Undecanes 0.001 2.439 5.063 2.128 1.621 C12 Dodecanes 0.000 2.534 4.803 2.210 1.537 C13 Tridecanes 0.000 3.022 5.270 2.636 1.687 C14 Tetradecanes 3.139 5.041 2.738 1.614 C15 Pentadecanes 3.007 4.454 2.623 1.426 C16 Hexadecanes 2.871 3.946 2.504 1.263 C17 Heptadecanes 2.654 3.417 2.315 1.094 C18 Octadecanes 2.652 3.224 2.313 1.032 C19 Nonadecanes 2.607 3.025 2.274 0.968 C20 Eicosanes 2.469 2.740 2.154 0.877 C21 Henicosanes 2.332 2.445 2.034 0.783 C22 Docosanes 2.124 2.125 1.853 0.680 C23 Tricosanes 2.015 1.934 1.758 0.619 C24 Tetracosanes 1.864 1.718 1.626 0.550 C25 Pentacosanes 1.786 1.580 1.558 0.506 C26 Hexacosanes 1.726 1.467 1.506 0.470 C27 Heptacosanes 1.716 1.400 1.497 0.448 C28 Octacosanes 1.629 1.281 1.421 0.410 C29 Nonacosanes 1.593 1.209 1.390 0.387 C30 Triacontanes 1.462 1.072 1.275 0.343 C31 Hentriacontanes 1.393 0.989 1.215 0.316 C32 Dotriacontanes 1.289 0.886 1.124 0.284 C33 Tritriacontanes 1.203 0.802 1.049 0.257 C34 Tetratriacontanes 1.121 0.725 0.978 0.232 C35 Pentatriacontanes 1.031 0.647 0.899 0.207 C36+Hexatriacontanes plus 39.452 14.054 34.413 4.498 100.000 100.000 100.000 100.000 100.000 Component Total Fluid Single-Phase Fluid Density(3) Evolved Gas Residual Liquid Compositional Analysis By Zero Psig Flash Method Pressure psia Gas/Oil Ratio(1) Oil Molecular Weight Evolved Gas Gravity Oil Volume Factor(2) Temperature °F Halliburton Energy Services Page 36 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Oil + 45.10 Mole% Injection Gas in Mixture Wt.% Mol.% Selected Components, Isomers, & Cyclic Compounds(1) C7 Benzene 0.058 0.083 78.12 0.884 C8 Toluene 0.177 0.216 92.15 0.871 Hydrocarbon Plus (Cn+) Properties(2) C6+ Hexanes plus 87.423 32.063 305 0.939 C7+ Heptanes plus 86.865 31.319 311 0.940 C10+ Decanes plus 81.657 25.918 353 0.952 C11+ Undecanes plus 79.491 24.108 369 0.957 C15+ Pentadecanes plus 69.779 17.649 443 0.978 C20+ Eicosanes plus 57.749 11.867 545 1.006 C25+ Pentacosanes plus 48.325 8.358 647 1.032 C30+ Triacontanes plus 40.954 6.137 747 1.057 C36+ Hexatriacontanes plus 34.413 4.498 857 1.085 (2) Calculated by summation of all compositional data. SARA Analysis by Liquid Chromatography Fluid - Calculation Basis Saturates wt% Aromatics wt% Resins wt% Asphaltenes wt% Residual Oil - Pentanes Insolubles 34.32 36.03 17.00 12.65 Whole Oil Fingerprint By Capillary Gas Chromatography Elution Time, minutes (1) Isomers & cyclics included in pseudo-component compositions on previous page and below. Fraction Composition Analysis (Cont'd) By Zero Psig Flash Method Total Fluid Density g/cm3 Molecular Weight g/mol Component Proper Name Re s p o n s e , min010203040506070 pA 0 50 100 150 200 *FID1 A, (I:\HPCHEM\DATA\GC6\053105\120531.D - I:\HPCHEM\DATA\GC6\053105\120744.D E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 n C 1 0 n C 1 1 n C 1 2 n C 1 3 n C 1 4 n C 1 5 n C 1 6 n C 1 7 n C 1 8 n C 1 9 n C 2 0 n C 2 1 n C 2 2 n C 2 3 n C 2 4 n C 2 5 n C 2 6 n C 2 7 n C 2 8 n C 2 9 n C 3 0 n C 3 1 n C 3 2 n C 3 3 n C 3 4 n C 3 5 min0246810 pA 0 50 100 150 200 *FID1 A, (I:\HPCHEM\DATA\GC6\053105\120531.D - I:\HPCHEM\DATA\GC6\053105\120744.D) E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 Halliburton Energy Services Page 37 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Pressure-Volume Relationship at 168 °F (Constant Composition Expansion) Sample Type: Recombined Oil + 45.10 Mole% Injection Gas in Mixture Pressure Coefficient of "Y" Relative Liquid Fluid psia Compressibility Function(1)Volume Volume % (2)Density 10-6 (vol/vol) psi-1 (VPb=1.000) (VL/VT× 100) g/cm³ 7452 6.632 0.984 100.00 0.8055 7253 6.988 0.986 100.00 0.8044 7047 7.358 0.987 100.00 0.8033 6850 7.713 0.989 100.00 0.8021 6650 8.075 0.990 100.00 0.8008 6453 8.434 0.992 100.00 0.7995 6250 8.805 0.993 100.00 0.7981 6050 9.173 0.995 100.00 0.7967 5850 9.541 0.997 100.00 0.7952 5649 9.915 0.999 100.00 0.7936 Pb 5564 10.074 1.000 100.00 0.7929 5472 8.185 1.002 98.82 5421 8.132 1.004 98.45 5368 8.077 1.005 98.24 5282 7.988 1.007 97.54 5177 7.879 1.011 96.96 5044 7.741 1.015 96.08 4847 7.537 1.021 94.97 4645 7.327 1.028 93.50 4452 7.127 1.036 92.30 4150 6.815 1.051 90.28 3848 6.502 1.070 87.86 3551 6.194 1.092 85.22 3249 5.881 1.122 82.11 2952 5.574 1.159 78.30 2647 5.257 1.208 74.65 2350 4.949 1.275 70.41 2049 4.637 1.368 64.95 1751 4.329 1.504 58.40 1451 4.018 1.709 51.01 1149 3.705 2.035 42.38 849 3.394 2.645 32.12 (1)Y = (P sat /P -1) / (V/V sat -1) (2)Volume of liquid phase per total sample volume, percent. Pr : Reservoir pressure Pb : Saturation pressure Halliburton Energy Services Page 38 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 4 5 . 1 0 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Si n g l e - P h a s e R e l a t i v e V o l u m e 0. 9 8 2 0. 9 8 4 0. 9 8 6 0. 9 8 8 0. 9 9 0 0. 9 9 2 0. 9 9 4 0. 9 9 6 0. 9 9 8 1. 0 0 0 1. 0 0 2 55 0 0 5 7 0 0 5 9 0 0 6 1 0 0 6 3 0 0 6 5 0 0 6 7 0 0 6 9 0 0 7 1 0 0 7 3 0 0 7 5 0 0 Pr e s s u r e , p s i a R e l a t i v e V o l u m e , ( V / V s a t ) Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 39 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 4 5 . 1 0 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Y- f u n c t i o n 2. 5 0 3. 5 0 4. 5 0 5. 5 0 6. 5 0 7. 5 0 8. 5 0 50 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 Pr e s s u r e , p s i a Y - f u n c t i o n Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 40 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 4 5 . 1 0 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Pe r c e n t L i q u i d 20 . 0 0 30 . 0 0 40 . 0 0 50 . 0 0 60 . 0 0 70 . 0 0 80 . 0 0 90 . 0 0 10 0 . 0 0 11 0 . 0 0 0 1 0 0 0 2 0 0 0 3 0 0 0 4 0 0 0 5 0 0 0 6 0 0 0 Pr e s s u r e , p s i a R e l a t i v e L i q u i d V o l u m e , ( V L / V T ) * 1 0 0 Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 41 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Oil + 60.08 Mole% Injection Gas in Mixture Rs Bo (air=1.000) g/mol g/cm³ Ä 10068 168 81.2 0.7502 14.696 psia 76 1518 1.006 0.7200 313.5 0.9298 14.696 psia 60 1528 1.000 0.9356 Ä sample charge conditions Oil Gravity at STP: 19.6 °API Standard Conditions (STP) : 14.696 psia & 60°F (1) Evolved Gas/Oil Ratio : Gas at STP per barrel of oil at specified pressure and temperature. (2) Oil Volume Factor : Volume at specified pressure and temperature per volume of residual oil at STP (3) Density of oil phase at specified pressure and temperature. Mol.% Wt.% Mol.% Wt.% Mol.% N2 Nitrogen 0.143 0.000 0.000 0.039 0.113 CO2 Carbon Dioxide 0.889 0.000 0.000 0.382 0.705 H2S Hydrogen Sulfide 0.000 0.000 0.000 0.000 0.000 C1 Methane 82.534 0.000 0.000 12.933 65.486 C2 Ethane 7.725 0.000 0.000 2.269 6.129 C3 Propane 4.459 0.007 0.050 1.926 3.548 iC4 iso-Butane 2.037 0.028 0.151 1.179 1.647 nC4 n-Butane 0.603 0.017 0.092 0.356 0.497 iC5 iso-Pentane 0.227 0.032 0.139 0.185 0.209 nC5 n-Pentane 0.516 0.106 0.461 0.448 0.504 C6 Hexanes 0.317 0.299 1.116 0.505 0.488 C7 Heptanes 0.324 0.975 3.216 1.089 0.931 C8 Octanes 0.169 1.955 5.811 1.741 1.341 C9 Nonanes 0.046 2.274 5.891 1.868 1.254 C10 Decanes 0.009 2.524 5.904 2.021 1.225 C11 Undecanes 0.002 2.510 5.352 2.001 1.106 C12 Dodecanes 0.000 2.618 5.097 2.084 1.051 C13 Tridecanes 0.000 3.130 5.606 2.491 1.156 C14 Tetradecanes 3.252 5.365 2.588 1.107 C15 Pentadecanes 3.134 4.769 2.495 0.984 C16 Hexadecanes 2.975 4.201 2.368 0.866 C17 Heptadecanes 2.774 3.669 2.208 0.757 C18 Octadecanes 2.745 3.428 2.185 0.707 C19 Nonadecanes 2.698 3.216 2.147 0.663 C20 Eicosanes 2.541 2.896 2.023 0.597 C21 Henicosanes 2.416 2.602 1.923 0.537 C22 Docosanes 2.218 2.279 1.765 0.470 C23 Tricosanes 2.093 2.063 1.666 0.426 C24 Tetracosanes 1.940 1.837 1.544 0.379 C25 Pentacosanes 1.857 1.687 1.478 0.348 C26 Hexacosanes 1.764 1.540 1.404 0.318 C27 Heptacosanes 1.785 1.496 1.421 0.309 C28 Octacosanes 1.689 1.364 1.344 0.281 C29 Nonacosanes 1.620 1.263 1.289 0.261 C30 Triacontanes 1.540 1.160 1.226 0.239 C31 Hentriacontanes 1.455 1.061 1.158 0.219 C32 Dotriacontanes 1.340 0.946 1.067 0.195 C33 Tritriacontanes 1.200 0.821 0.955 0.169 C34 Tetratriacontanes 1.198 0.796 0.954 0.164 C35 Pentatriacontanes 1.082 0.698 0.861 0.144 C36+Hexatriacontanes plus 38.209 11.958 30.412 2.467 100.000 100.000 100.000 100.000 100.000 Compositional Analysis By Zero Psig Flash Method Pressure psia Gas/Oil Ratio(1) Oil Molecular Weight Evolved Gas Gravity Oil Volume Factor(2) Temperature °F Component Total Fluid Single-Phase Fluid Density(3) Evolved Gas Residual Liquid Halliburton Energy Services Page 42 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Sample Type: Recombined Oil + 60.08 Mole% Injection Gas in Mixture Wt.% Mol.% Selected Components, Isomers, & Cyclic Compounds(1) C7 Benzene 0.048 0.050 78.12 0.884 C8 Toluene 0.155 0.137 92.15 0.871 Hydrocarbon Plus (Cn+) Properties(2) C6+ Hexanes plus 80.282 21.160 308 0.934 C7+ Heptanes plus 79.778 20.671 314 0.936 C10+ Decanes plus 75.079 17.146 356 0.947 C11+ Undecanes plus 73.058 15.920 373 0.952 C15+ Pentadecanes plus 63.893 11.500 451 0.972 C20+ Eicosanes plus 52.491 7.523 567 1.000 C25+ Pentacosanes plus 43.570 5.114 692 1.027 C30+ Triacontanes plus 36.633 3.597 827 1.052 C36+ Hexatriacontanes plus 30.412 2.467 1002 1.081 (2) Calculated by summation of all compositional data. SARA Analysis by Liquid Chromatography Fluid - Calculation Basis Saturates wt% Aromatics wt% Resins wt% Asphaltenes wt% Residual Oil - Pentanes Insolubles 35.74 36.92 18.00 9.33 Fraction Composition Analysis (Cont'd) By Zero Psig Flash Method Total Fluid Density g/cm3 Molecular Weight g/mol Component Proper Name Whole Oil Fingerprint By Capillary Gas Chromatography Elution Time, minutes (1) Isomers & cyclics included in pseudo-component compositions on previous page and below. Re s p o n s e , min010203040506070 pA 0 50 100 150 200 *FID1 A, (I:\HPCHEM\DATA\GC6\052305\120526.D - I:\HPCHEM\DATA\GC6\052305\120569.D) E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 n C 1 0 n C 1 1 n C 1 2 n C 1 3 n C 1 4 n C 1 5 n C 1 6 n C 1 7 n C 1 8 n C 1 9 n C 2 0 n C 2 1 n C 2 2 n C 2 3 n C 2 4 n C 2 5 n C 2 6 n C 2 7 n C 2 8 n C 2 9 n C 3 0 n C 3 1 n C 3 2 n C 3 3 n C 3 4 n C 3 5 min0246810 pA 0 50 100 150 200 *FID1 A, (I:\HPCHEM\DATA\GC6\052305\120526.D - I:\HPCHEM\DATA\GC6\052305\120569.D) E t h a n e P r o p a n e I s o b u t a n e N o r m a l B u t a n e I s o p e n t a n e N o r m a l P e n t a n e 1 - H e x e n e n C 6 B e n z e n e n C 7 T o l u e n e n C 8 n C 9 Halliburton Energy Services Page 43 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Pressure-Volume Relationship at 168 °F (Constant Composition Expansion) Sample Type: Recombined Oil + 60.08 Mole% Injection Gas in Mixture Pressure Coefficient of "Y" Relative Liquid Fluid psia Compressibility Function(1)Volume Volume % (2)Density 10-6 (vol/vol) psi-1 (VPb=1.000) (VL/VT× 100) g/cm³ 10070 6.582 0.980 100.00 0.7502 9858 7.137 0.982 100.00 0.7491 9657 7.665 0.984 100.00 0.7480 9450 8.212 0.985 100.00 0.7468 9254 8.732 0.987 100.00 0.7455 9051 9.274 0.989 100.00 0.7442 8847 9.821 0.990 100.00 0.7427 8652 10.347 0.992 100.00 0.7413 8450 10.893 0.994 100.00 0.7397 8253 11.431 0.997 100.00 0.7380 8051 11.987 0.999 100.00 0.7363 Pb 7973 12.204 1.000 100.00 0.7356 ** 7853 9.732 1.003 96.89 ** 7651 9.346 1.006 94.97 ** 7450 9.000 1.010 93.53 ** 7252 8.695 1.014 92.53 ** 7051 8.420 1.019 91.03 ** 6851 8.179 1.023 89.58 6651 7.967 1.027 87.88 6449 7.781 1.033 86.60 6155 7.552 1.041 85.24 5848 7.357 1.051 83.88 5550 7.197 1.062 82.66 5250 7.055 1.074 81.23 4953 6.923 1.088 79.77 4652 6.788 1.105 78.08 4353 6.646 1.126 76.07 4052 6.487 1.150 73.96 3752 6.308 1.179 71.30 3453 6.104 1.212 68.57 3150 5.870 1.260 65.54 2850 5.610 1.320 62.18 2551 5.322 1.402 58.10 2249 5.007 1.510 53.41 1950 4.676 1.661 48.20 1651 4.340 1.880 42.28 1349 4.012 2.218 35.56 1058 3.733 2.757 28.26 **: Gas-oil interface unclear with asphaltene particles sticking to piston. (1)Y = (P sat /P -1) / (V/V sat -1) (2)Volume of liquid phase per total sample volume, percent. Pr : Reservoir pressure Pb : Saturation pressure Halliburton Energy Services Page 44 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 6 0 . 0 8 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Si n g l e - P h a s e R e l a t i v e V o l u m e 0. 9 7 5 0. 9 8 0 0. 9 8 5 0. 9 9 0 0. 9 9 5 1. 0 0 0 1. 0 0 5 75 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 1 0 0 0 0 1 0 5 0 0 Pr e s s u r e , p s i a R e l a t i v e V o l u m e , ( V / V s a t ) Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 45 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 6 0 . 0 8 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Y- f u n c t i o n 3. 0 0 4. 0 0 5. 0 0 6. 0 0 7. 0 0 8. 0 0 9. 0 0 10 . 0 0 11 . 0 0 50 0 1 5 0 0 2 5 0 0 3 5 0 0 4 5 0 0 5 5 0 0 6 5 0 0 7 5 0 0 8 5 0 0 Pr e s s u r e , p s i a Y - f u n c t i o n Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 46 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l + 6 0 . 0 8 M o l e % I n j e c t i o n G a s i n M i x t u r e Pr e s s u r e - V o l u m e R e l a t i o n s h i p a t 1 6 8 ° F Pe r c e n t L i q u i d 20 . 0 0 30 . 0 0 40 . 0 0 50 . 0 0 60 . 0 0 70 . 0 0 80 . 0 0 90 . 0 0 10 0 . 0 0 11 0 . 0 0 50 0 1 5 0 0 2 5 0 0 3 5 0 0 4 5 0 0 5 5 0 0 6 5 0 0 7 5 0 0 8 5 0 0 Pr e s s u r e , p s i a R e l a t i v e L i q u i d V o l u m e , ( V L / V T ) * 1 0 0 Da t a C u r v e F i t Me a s u r e d D a t a P o i n t s H a l l i b u r t o n E n e r g y S e r v i c e s Page 47 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d O i l Pr e s s u r e V s . L a s e r D e t e c t o r R e l a t i o n s h i p a t 1 6 8 ° F 1. 6 0 1. 6 5 1. 7 0 1. 7 5 1. 8 0 1. 8 5 1. 9 0 19 0 0 2 1 0 0 2 3 0 0 2 5 0 0 2 7 0 0 2 9 0 0 3 1 0 0 Pr e s s u r e , p s i a L a s e r D e t e c t o r V o l t a g e , V o l t Me a s u r e d D a t a P o i n t s Pr e s s u r e d e c r e a s e d f r o m 3 1 0 0 p s i a t o 1 9 5 0 p s i a a t 2 p s i p e r m i n u t e r a t e . H a l l i b u r t o n E n e r g y S e r v i c e s Page 48 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d L i v e O i l As p h a l t e n e F l o c c u l a t i o n E x p e r i m e n t a t 4 5 0 0 p s i a & 1 6 8 ° F Re c o m b i n e d O i l T i t r a t i o n W i t h I n j e c t i o n G a s 0. 0 0. 1 0. 2 0. 3 0. 4 0. 5 0. 6 0. 7 0. 8 0. 9 1. 0 0. 0 5 0 . 0 1 0 0 . 0 1 5 0 . 0 2 0 0 . 0 2 5 0 . 0 3 0 0 . 0 3 5 0 . 0 4 0 0 . 0 El a p s e d T i m e , M i n u t e s N I R L a s e r T r a n s m i t t a n c e , v o l t s 0.000.200.400.600.801.001.20 Gas Injected, cc On s e t o f a s p h a l t e n e f l o c c u l a t i o n a t 0 . 2 0 7 c c g a s i n j e c t e d , o r a t Ga s I n j e c t i o n s t a r t e d a t 0 . 6 c c p e r h o u r Ga s I n j e c t i o n o f f , s t i r r e r o f f H a l l i b u r t o n E n e r g y S e r v i c e s Page 49 Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Sa m p l e T y p e : R e c o m b i n e d L i v e O i l Stirrer "ON" during entire Test As p h a l t e n e F l o c c u l a t i o n E x p e r i m e n t a t 3 3 0 0 p s i a & 1 6 8 ° F Re c o m b i n e d O i l T i t r a t i o n W i t h I n j e c t i o n G a s 0. 0 0. 5 1. 0 1. 5 2. 0 2. 5 3. 0 3. 5 10 0 2 0 0 3 0 0 4 0 0 5 0 0 6 0 0 7 0 0 8 0 0 9 0 0 1 0 0 0 El a p s e d T i m e , M i n u t e s N I R L a s e r T r a n s m i t t a n c e , v o l t s 0.000.020.040.060.080.100.120.140.160.180.20 Gas Injected, cc On s e t o f a s p h a l t e n e f l o c c u l a t i o n a t 0 1 8 c c o f i n j e c t e d g a s o r a t Ga s I n j e c t i o n s t a r t e d a t 0 . 1 3 c c p e r h o u r H a l l i b u r t o n E n e r g y S e r v i c e s Page 50 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Summary of Asphaltene Particle Size at 168°F Injection Gas Added to Reservoir Fluid Sample: Recombined Live Oil + Injection Gas Asphaltene Particle Size at 4500 psia, µm 7 8 9 10 11 12 13 14 15 16 17 18 Number of Particles 214230131011 Asphaltene Particle Size at 3300 psia, µm 7 9 11 13 15 17 19 21 23 25 27 29 Number of Particles 22 28 57 14 40101012 Summary of Particle Size Distribution 0 10 20 30 40 50 60 70 0 5 10 15 20 25 30Particle Size, µm Nu m b e r o f P a r t i c l e s Halliburton Energy Services Page 51 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Asphaltene Particle Imaging at 4500 psia at 168 °F Solids Precipitation Testing with Injection Gas Sample: Recombined Live Oil + Injection Gas Image: 4500 psia & 168°F Image: 4500 psia & 168°F Image: 4500 psia & 168°F Image: 4500 psia & 168°F Halliburton Energy Services Page 52 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Asphaltene Particle Imaging at 3300 psia at 168 °F Solids Precipitation Testing with Injection Gas Sample: Recombined Live Oil + Injection Gas Image: 3300 psia & 168°F Image: 3300 psia & 168°F Image: 3300 psia & 168°F Image: 3300 psia & 168°F Halliburton Energy Services Page 53 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 N2 Nitrogen 28.01 0.8086 H2S Hydrogen Sulfide 34.08 0.8006 CO2 Carbon Dioxide 44.01 0.8172 C1 Methane 16.04 0.2997 C2 Ethane 30.07 0.3562 C3 Propane 44.10 0.5070 iC4 iso-Butane 58.12 0.5629 nC4 n-Butane 58.12 0.5840 iC5 iso-Pentane 72.15 0.6244 nC5 n-Pentane 72.15 0.6311 C6 Hexanes 84 0.685 C7 Benzene*78.11 0.8836 C7 Heptanes 96 0.722 C8 Toluene*92.14 0.8710 C8 Octanes 107 0.745 C9 Nonanes 121 0.764 C10 Decanes 134 0.778 C11 Undecanes 147 0.789 C12 Dodecanes 161 0.800 C13 Tridecanes 175 0.811 C14 Tetradecanes 190 0.822 C15 Pentadecanes 206 0.832 C16 Hexadecanes 222 0.839 C17 Heptadecanes 237 0.847 C18 Octadecanes 251 0.852 C19 Nonadecanes 263 0.857 C20 Eicosanes 275 0.862 C21 Henicosanes 291 0.867 C22 Docosanes 305 0.872 C23 Tricosanes 318 0.877 C24 Tetracosanes 331 0.881 C25 Pentacosanes 345 0.885 C26 Hexacosanes 359 0.889 C27 Heptacosanes 374 0.893 C28 Octacosanes 388 0.896 C29 Nonacosanes 402 0.899 C30 Triacontanes 416 0.902 C31 Henitriacontanes 430 0.906 C32 Dotriacontanes 444 0.909 C33 Tritriacontanes 458 0.912 C34 Tetratriacontanes 472 0.914 C35 Pentatriacontanes 486 0.917 C36 Hexatriacontanes 500 0.919 Note: Values for C6 through C36 from Katz, Firoozabadi, et al. * Typtically included in hydrocarbon fraction calculation. Database of Molecular Weight & Density used for Compositional Calculations Component Molecular Weight gm/mol Density gm/cc Halliburton Energy Services Page 54 Sample: NW Kuparuk Date: 5/16/2005 WAT: >-19.8°F Power setting for Objective Lens is 20X. Determination of Wax Appearance Temperature Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 (°F) (°C) 142.2 61.2 Clear Field 109.9 43.3 Clear Field 102.0 38.9 Clear Field 93.6 34.2 Clear Field 85.8 29.9 Clear Field 76.6 24.8 Clear Field 70.0 21.1 Clear Field 59.5 15.3 Clear Field 52.5 11.4 Clear Field 43.0 6.1 Clear Field 37.9 3.3 Clear Field 29.3 -1.5 Clear Field 24.4 -4.2 Clear Field 18.3 -7.6 Clear Field 13.1 -10.5 Clear Field 7.2 -13.8 Clear Field 18.3 -7.6 Clear Field 13.1 -10.5 Clear Field 7.2 -13.8 Clear Field 3.9 -15.6 Clear Field -2.7 -19.3 Clear Field -8.5 -22.5 Clear Field -13.2 -25.1 Clear Field -19.8 -28.8 Clear Field Sample Temperature Observation Halliburton Energy Services Page 55 Viscometer Brookfield DV-11+ (LV, RV, & HB) Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Water 35°F, 100°F, 171°F, Cut 3.96 1/sec 238 1/sec 238 1/sec %c Pc Pc P 0 832 74.8 15.9 10 1227 114 23.1 20 1835 150 36.4 30 3627 235 47.5 40 6848 422 102 50 4107 751 173 60 2976 1313 488 70 3.00 937 326 80 2.52 1.47 149 90 2.47 1.17 1.68 100 1.71 0.72 0.35 Viscosity vs. Water Cut 0.1 1.0 10.0 100.0 1000.0 10000.0 0 20 40 60 80 100 120 Water Cut (%) V i s c o s i t y ( c P ) 171°F, 238 1/sec 100°F, 238 1/sec 35°F, 3.96 1/sec Halliburton Energy Services Page 56 Vi s c o m e t e r B r o o k f i e l d D V - 1 1 + ( L V , R V , & H B ) Pi o n e e r N a t u r a l R e s o u r c e s U S A , I n c . NW K u p a r u k , W e l l : I v i k Fi l e N o . R - 0 5 - 3 9 3 Te m p e r a t u r e S h e a r R a t e % W a t e r % W a t e r % W a t e r % W a t e r % W a t e r % W a t e r % W a t e r % W a t e r % W a t e r % W a t e r % W a t e r °F 1 / s e c 0 1 0 2 0 3 0 4 0 5 0 6 0 7 0 8 0 9 0 1 0 0 35 3 . 9 6 83 2 1 2 2 7 1 8 3 5 3 6 2 7 6 8 4 8 4 1 0 7 2 9 7 6 3 . 0 0 2 . 5 2 2 . 4 7 1 . 7 1 10 0 2 3 8 75 1 1 4 1 5 0 2 3 5 4 2 2 7 5 1 1 3 1 3 9 3 7 1 . 4 7 1 . 1 0 0 . 7 2 17 1 2 3 8 16 2 3 3 6 4 7 1 0 2 1 7 3 4 8 8 3 2 6 1 4 9 1 . 6 8 0 . 3 5 Vi s c o s i t y v s . T e m p e r a t u r e 0110 10 0 10 0 0 10 0 0 0 0 2 0 4 0 6 0 8 0 1 0 0 1 2 0 1 4 0 1 6 0 1 8 0 Te m p e r a t u r e ( ° F ) V i s c o s i t y ( c P ) % Water 0 % Water 10 % Water 20 % Water 30 % Water 40 % Water 50 % Water 60 % Water 70 % Water 80 % Water 90 % Water 100 H a l l i b u r t o n E n e r g y S e r v i c e s Page 57 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 35°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.0 0.0 100.0 0.0 5.15hr 0.0 0.0 100.0 0.0 24hr 0.0 0.0 100.0 0.0 48hr 0.0 0.0 100.0 0.0 10% WC Initial 5min 10min 30min 1hr 2hr 5.15hr 24hr 48hr Halliburton Energy Services Page 120 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 35°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.0 0.0 100.0 0.0 5.15hr 0.0 0.0 100.0 0.0 24hr 0.4 0.0 99.6 0.0 48hr 0.4 0.0 99.6 0.0 20% WC 1hr 2hr 5.15hr 24hr 48hr Initial 5min 10min 30min Halliburton Energy Services Page 121 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 35°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.4 0.0 99.6 0.0 5.15hr 0.4 0.0 99.6 0.0 24hr 0.4 0.0 99.6 0.0 48hr 0.4 0.0 99.6 0.0 30% WC Initial 5min 10min 30min 1hr 2hr 5.15hr 24hr 48hr Halliburton Energy Services Page 122 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 35°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 21.1 78.9 0.0 5 0.0 27.8 72.2 0.0 10 0.0 27.8 72.2 0.0 20 0.0 27.8 72.2 0.0 30 0.0 27.8 72.2 0.0 45 0.0 27.8 72.2 0.0 1hr 0.0 27.8 72.2 0.0 2hr 0.0 27.8 72.2 0.0 5.15hr 0.0 27.8 72.2 0.0 24hr 27.8 0.0 72.2 0.0 48hr 27.8 0.0 72.2 0.0 40% WC Initial 5min 10min 30min 1hr 2hr 5.15hr 24hr 48hr Halliburton Energy Services Page 123 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 35°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 28.1 71.9 0.0 10 0.0 28.1 71.9 0.0 20 0.0 38.5 61.5 0.0 30 0.0 38.5 61.5 0.0 45 0.0 38.5 61.5 0.0 1hr 0.0 38.5 61.5 0.0 2hr 0.0 38.5 61.5 0.0 5.15hr 0.0 38.5 61.5 0.0 24hr 38.5 0.0 61.5 0.0 48hr 38.5 0.0 61.5 0.0 50% WC Initial 5min 10min 30min 1hr 2hr 5.15hr 24hr 48hr Halliburton Energy Services Page 124 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 35°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 50.4 49.6 0.0 5 0.0 50.4 49.6 0.0 10 0.0 52.4 47.6 0.0 20 0.0 52.4 47.6 0.0 30 0.0 52.4 47.6 0.0 45 0.0 52.4 47.6 0.0 1hr 0.0 52.4 47.6 0.0 2hr 0.0 52.4 47.6 0.0 5.15hr 0.0 52.4 47.6 0.0 24hr 54.5 0.0 45.5 0.0 48hr 54.5 0.0 45.5 0.0 60% WC Initial 5min 10min 30min 1hr 2hr 5.15hr 24hr 48hr Halliburton Energy Services Page 125 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 35°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 51.0 49.0 0.0 5 0.0 51.0 49.0 0.0 10 0.0 51.0 49.0 0.0 20 0.0 51.0 49.0 0.0 30 0.0 51.0 49.0 0.0 45 0.0 51.0 49.0 0.0 1hr 0.0 51.0 46.9 0.0 2hr 0.0 44.9 46.9 0.0 5.15hr 65.3 0.0 34.7 0.0 24hr 67.3 0.0 32.7 0.0 48hr 67.3 0.0 32.7 0.0 70% WC Initial 5min 10min 30min 1hr 2hr 5.15hr 24hr 48hr Halliburton Energy Services Page 126 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 35°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 74.0 26.0 0.0 5 0.0 76.0 24.0 0.0 10 0.0 78.0 22.0 0.0 20 0.0 78.0 22.0 0.0 30 0.0 78.0 22.0 0.0 45 0.0 78.0 22.0 0.0 1hr 0.0 78.0 22.0 0.0 2hr 0.0 78.0 22.0 0.0 5.15hr 0.0 78.0 22.0 0.0 24hr 78.0 0.0 22.0 0.0 48hr 78.0 0.0 22.0 0.0 80% WC Initial 5min 10min 30min 1hr 2hr 5.15hr 24hr 48hr Halliburton Energy Services Page 127 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 35°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 89.0 11.0 0.0 5 0.0 89.0 11.0 0.0 10 0.0 89.0 11.0 0.0 20 0.0 89.0 11.0 0.0 30 0.0 89.0 11.0 0.0 45 0.0 89.0 11.0 0.0 1hr 0.0 89.0 11.0 0.0 2hr 0.0 89.0 11.0 0.0 5.15hr 0.0 89.0 11.0 0.0 24hr 89.0 0.0 11.0 0.0 48hr 89.0 0.0 11.0 0.0 90% WC Initial 5min 10min 30min 1hr 2hr 5.15hr 24hr 48hr Halliburton Energy Services Page 128 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 100°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.0 0.0 100.0 0.0 9hr 0.0 0.0 100.0 0.0 24hr 0.0 0.0 100.0 0.0 48hr 0.0 0.0 100.0 0.0 10% WC 1hr 2hr 9hr 24hr 48hr Initial 5min 10min 30min Halliburton Energy Services Page 138 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 100°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.0 0.0 100.0 0.0 9hr 0.0 0.0 100.0 0.0 24hr 0.0 0.0 100.0 0.0 48hr 0.0 0.0 100.0 0.0 20% WC 1hr 2hr 9hr 24hr 48hr Initial 5min 10min 30min Halliburton Energy Services Page 139 30% WC Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 100°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.0 0.0 100.0 0.0 9hr 0.0 0.0 100.0 0.0 24hr 0.0 0.0 100.0 0.0 48hr 0.0 0.0 100.0 0.0 30% WC 1hr 2hr 9hr 24hr 48hr Initial 5min 10min 30min Halliburton Energy Services Page 140 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 100°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.0 0.0 100.0 0.0 9hr 0.0 0.0 100.0 0.0 24hr 0.0 0.0 100.0 0.0 48hr 0.0 0.0 100.0 0.0 40% WC Initial 5min 10min 30min 1hr 2hr 9hr 24hr 48hr Halliburton Energy Services Page 141 Emulsion Testing- Water Breakout @ 100°F Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.2 0.0 99.8 0.0 2hr 0.2 0.0 99.8 0.0 9hr 0.2 0.0 99.8 0.0 24hr 0.2 0.0 99.8 0.0 48hr 0.2 0.0 99.8 0.0 50% WC 1hr 2hr 9hr 24hr 48hr Initial 5min 10min 30min Halliburton Energy Services Page 142 Emulsion Testing- Water Breakout @ 100°F Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.2 99.8 0.0 5 0.0 1.0 99.0 0.0 10 0.0 2.0 98.0 0.0 20 0.0 3.5 96.4 0.0 30 0.0 4.0 96.0 0.0 45 0.0 5.5 94.4 0.0 1hr 0.0 6.5 93.4 0.0 2hr 0.0 10.0 90.0 0.0 9hr 16.0 0.0 84.0 0.0 24hr 18.0 0.0 82.0 0.0 48hr 18.0 0.0 82.0 0.0 60% WC Initial 5min 10min 30min 1hr 2hr 9hr 24hr 48hr Halliburton Energy Services Page 143 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 100°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 38.6 61.4 0.0 5 0.0 40.6 59.4 0.0 10 0.0 40.6 59.4 0.0 20 0.0 42.6 57.4 0.0 30 0.0 42.6 57.4 0.0 45 0.0 42.6 57.4 0.0 1hr 0.0 42.6 57.4 0.0 2hr 0.0 42.6 57.4 0.0 9hr 42.6 0.0 57.4 0.0 24hr 42.6 0.0 57.4 0.0 48hr 42.6 0.0 57.4 0.0 70% WC Initial 5min 10min 30min 1hr 2hr 9hr 24hr 48hr Halliburton Energy Services Page 144 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 100°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 62.5 37.5 0.0 5 0.0 66.7 33.3 0.0 10 0.0 66.7 33.3 0.0 20 0.0 66.7 33.3 0.0 30 0.0 66.7 33.3 0.0 45 0.0 68.8 31.3 0.0 1hr 0.0 68.8 31.3 0.0 2hr 0.0 68.8 31.3 0.0 9hr 0.0 68.8 31.3 0.0 24hr 68.8 0.0 31.3 0.0 48hr 70.8 0.0 29.2 0.0 80% WC Initial 5min 10min 30min 1hr 2hr 9hr 24hr 48hr Halliburton Energy Services Page 145 Emulsion Testing- Water Breakout @ 100°F Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 86.0 14.0 0.0 5 0.0 86.0 14.0 0.0 10 0.0 86.0 14.0 0.0 20 0.0 86.0 14.0 0.0 30 0.0 86.0 14.0 0.0 45 0.0 86.0 14.0 0.0 1hr 0.0 86.0 14.0 0.0 2hr 0.0 86.0 14.0 0.0 9hr 0.0 86.0 14.0 0.0 24hr 86.0 0.0 14.0 0.0 48hr 86.0 0.0 14.0 0.0 90% WC 1hr 2hr 9hr 24hr 48hr Initial 5min 10min 30min Halliburton Energy Services Page 146 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 171°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.0 0.0 100.0 0.0 6.5hr 0.0 0.0 100.0 0.0 24hr 0.0 0.0 100.0 0.0 48hr 0.0 0.0 100.0 0.0 10% WC 2hr 6.5hr 24hr 48hr Initial 5min 30min 1hr Halliburton Energy Services Page 156 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 171°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.0 0.0 100.0 0.0 6.5hr 0.0 0.0 100.0 0.0 24hr 0.0 0.0 100.0 0.0 48hr 0.0 0.0 100.0 0.0 20% WC Initial 5min 30min 1hr 2hr 6.5hr 24hr 48hr Halliburton Energy Services Page 157 Emulsion Testing- Water Breakout @ 171°F Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.0 0.0 100.0 0.0 6.5hr 0.0 0.0 100.0 0.0 24hr 0.0 0.0 100.0 0.0 48hr 0.0 0.0 100.0 0.0 30% WC Initial 5min 30min 1hr 2hr 6.5hr 24hr 48hr Halliburton Energy Services Page 158 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 171°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.0 0.0 100.0 0.0 1hr 0.0 0.0 100.0 0.0 2hr 0.0 0.0 100.0 0.0 6.5hr 0.4 0.0 99.6 0.0 24hr 0.4 0.0 99.6 0.0 48hr 0.4 0.0 99.6 0.0 40% WC Initial 5min 30min 1hr 2hr 6.5hr 24hr 48hr Halliburton Energy Services Page 159 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 171°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.0 0.0 100.0 0.0 45 0.4 0.0 99.6 0.0 1hr 0.4 0.0 99.6 0.0 2hr 0.4 0.0 99.6 0.0 6.5hr 0.4 0.0 99.6 0.0 24hr 0.4 0.0 99.6 0.0 48hr 0.4 0.0 99.6 0.0 50% WC Initial 5min 30min 1hr 2hr 6.5hr 24hr 48hr Halliburton Energy Services Page 160 Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Emulsion Testing- Water Breakout @ 171°F Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.0 100.0 0.0 10 0.0 0.0 100.0 0.0 20 0.0 0.0 100.0 0.0 30 0.2 0.0 99.8 0.0 45 0.4 0.0 99.6 0.0 1hr 0.4 0.0 99.6 0.0 2hr 0.4 0.0 99.6 0.0 6.5hr 0.4 0.0 99.6 0.0 24hr 0.4 0.0 99.6 0.0 48hr 0.4 0.0 99.6 0.0 60% WC Initial 5min 30min 1hr 2hr 6.5hr 24hr 48hr Halliburton Energy Services Page 161 Emulsion Testing- Water Breakout @ 171°F Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 0.0 100.0 0.0 5 0.0 0.7 99.3 0.0 10 0.0 19.6 80.4 0.0 20 0.0 21.7 78.3 0.0 30 0.0 23.9 76.1 0.0 45 0.0 34.8 65.2 0.0 1hr 0.0 34.8 65.2 0.0 2hr 0.0 34.8 65.2 0.0 6.5hr 34.8 0.0 65.2 0.0 24hr 37.0 0.0 63.0 0.0 48hr 37.0 0.0 63.0 0.0 70% WC Initial 5min 30min 1hr 2hr 6.5hr 24hr 48hr Halliburton Energy Services Page 162 Emulsion Testing- Water Breakout @ 171°F Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 59.6 40.4 0.0 5 0.0 61.7 38.3 0.0 10 0.0 61.7 38.3 0.0 20 0.0 61.7 38.3 0.0 30 0.0 61.7 38.3 0.0 45 0.0 61.7 38.3 0.0 1hr 0.0 61.7 38.3 0.0 2hr 0.0 61.7 38.3 0.0 6.5hr 61.7 0.0 38.3 0.0 24hr 61.7 0.0 38.3 0.0 48hr 61.7 0.0 38.3 0.0 80% WC Initial 5min 30min 1hr 2hr 6.5hr 24hr 48hr Halliburton Energy Services Page 163 Emulsion Testing- Water Breakout @ 171°F Pioneer Natural Resources USA, Inc. NW Kuparuk, Well: Ivik File No. R-05-393 Elapsed Time Water Phase Water External Emulsion Phase Oil External Emulsion Phase Oil Phase (min) vol % vol % vol % vol % 2 0.0 48.0 52.0 0.0 5 0.0 48.0 52.0 0.0 10 0.0 80.0 20.0 0.0 20 0.0 84.0 16.0 0.0 30 0.0 84.0 16.0 0.0 45 0.0 84.0 16.0 0.0 1hr 0.0 84.0 16.0 0.0 2hr 0.0 84.0 16.0 0.0 6.5hr 84.0 0.0 16.0 0.0 24hr 84.0 0.0 16.0 0.0 48hr 86.0 0.0 14.0 0.0 90% WC Initial 5min 30min 1hr 2hr 6.5hr 24hr 48hr Halliburton Energy Services Page 164
