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200-153
• STATE OF ALASKA 0 MAY 10 2018 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT ANLU . OG C la.Well Status: Oil ❑ Gas❑ SPLUG ❑ Other ❑ Abandoned ❑✓ Suspended III lb.Well Class: 2O AC 25.105 20AAC 25.110 Development ❑✓ • Exploratory ❑ GINJ ❑ WINJ ❑ WAG❑ WDSPL❑ No.of Completions: 1 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6. Date Comp.,Susp.,or 14. Permit to Drill Number/ Sundry: COOK INLET ENERGY LLC Aband.: 9/6/2017 200-153/317-351 3.Address: 7. Date Spudded: 15.API Number: 601 W.5th AVE.SUITE 310,ANCHORAGE,AK,99501 10/16/2000 50-133-20496-00-00 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 3443'FNL, 1468'FWL,Sec.4,T7N, R14W,SM 12/4/2000 Kustatan Field#1 Top of Productive Interval: 9. Ref Elevations: KB: 17. Field/Pool(s): 3443'FNL, 1468'FWL,Sec.4,T7N, R14W, SM GL: n/a BF: Kustatan Field#1 Gas Pool Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 3443'FNL, 1468'FWL,Sec.4,T7N, R14W,SM surface ADL 387023 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 186839.181 r y- 2460784.001 - Zone- 4 , 12300'MD/12300'TVD n/a TPI: x- 186839.181 y- 2460784.001 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 186839.181 y- 2460784.001 Zone- 4 n/a n/a 5. Directional or Inclination Survey: Yes ❑ (attached) No ❑✓ 13.Water Depth,if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 n/a (ft MSL) n/a 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first.Types of logs to be listed include, but are not limited to: mud log,spontaneous pot:ntial, gamma ray,caliper,resistivity, porosity, magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary none KANN MAY 2:12018 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMQUNT CASING FT. GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 133# K-55 0 120 0 120 Driven n/a none 13 3/8" 68# K-55 0 1820 0 1820 17 1/2" surf. none 9 5/8" 47# L-80 0 6500 0 6500 12 1/4" 643 cuft none 7 5/8" 29.7# L-80 6312 12300 6312 12300 8 1/2" 678 cuft none 24.Open to production or injection? Yes ❑ No 0 . 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number; Date Perfd): 2 7/8" 5316'MD 3090', 5110',5291' 26.ACID, FRACTURE,CEMENT SQUEEZE, ETC. DATE Was hydraulic fracturing used during completion? Yes ❑ No ❑✓ q/0/11" Per 20 AAC 25.283(i)(2)attach electronic and printed information V RIFIED DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): n/a I Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Rati¢: Test Period Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 24-Hour Rate ..... Form 10-407 Revised 5/2017 [rt *,t ri P, I9ONTINUED ON PAGE 2 u 5 -lY-I Submit ORIGINIAL only/ • • 28.CORE DATA Conventional Core(s): Yes ❑ No ❑ Sidewall Cores: Yes ❑ No ❑ If Yes,list formations and intervals cored(MD/TVD,From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑ Permafrost-Top If yes,list intervals and formations tested,briefly summarizing test results. Permafrost-Base Attach separate pages to this form,if needed,and submit detailed tet Top of Productive Interval information,including reports,per 20 AAC 25.071. Formation at total depth: 31. List of Attachments: Summary of daily operations,wellbore schematic,photo of cut off,photo of welded abandonment marker,photo of backfill Information to be attached includes,but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis; paleontological report,production or well test results,per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Stephen Ratcliff Contact Name: Stephen Ratcliff Authorized Title: Drilling Manager Contact Email: sratcliff@glacieroil.com Authorized Contact Phone: 907-433-3808 Signature: Date: 5/10/2018 ` INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC,no matter when the analyses are conducted. Item 1a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated.Each segregated pool is a completion. Item 1b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing,Ground Level,and Base Flange elevations in feet above Mean Sea Level.Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 19: Report the Division of Oil&Gas/Division of Mining Land and Water:Plan of Operations(LO/Region YY-123),Land Use Permit(LAS 12845), and/or Easement(ADL 123456)number. Item 20: Report measured depth and true vertical thickness of permafrost.Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and,pursuant to AS 31.05.030,submit all electronic data and printed logs within 90',days of completion,suspension,or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26.(Submit a separate form for each additional interval to be separately produce , showing the data pertinent to such interval). Item 27: Method of Operation:Flowing,Gas Lift,Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results,including,but not limited to:porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including,but not limited to:core analysis,paleontological report,production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only • GLACIER May 10th, 2017 Mr. Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Well Completion Cook Inlet Energy, LLC: Kustatan Field #1 Permit to Drill NO: 200-153 API No: 50-133-20496-00-00 Dear Mr. French, Cook Inlet Energy(CIE)hereby submits a Well Completion Report for abandonment of Kustatan Field #1. The work performed was covered under Approved Sundry 317-351. If you have any questions, please contact me at(907) 433-3808. Sincerely, \\\\ Stephen Ratcliff Drilling Manager Cook Inlet Energy, LLC (a Glacier Oil & Gas Corp. owned company) 10-407 601 W.5th Avenue,Suite 310,Anchorage,AK 99501 (907)334-6745*(907)334-6735 fax • • Kustatan Field #1 Daily Operations Summary API: 50-133-20496-00-00 PTD#: 200-153 Date Activity 08 Aug 2017 RU Slickline and pressure test lubricator to 2000 psi. RIH with 2-7/8" GS to 208', tag fluid level, continue to RIH to 3035' WLM and latch jet pump. POH with jet pump.YRIH with 2.1" LIB and set down at 5268', marks on side of LIB. RIH with 1.5" LIB and 1.75" XO and set down at / 5275', similar marks on LIB. RIH with 2.3" GR to 3035', attempt to work past, no go–unable to reach XN-profile to set plug. Use spangs to pull free. RDe 09 Aug 2017 RU Slickline. RIH with 2 7/8" shifting tool and shift both sleeves closed at 3043' and 3136', POH. RD Slickline. 10 Aug 2017 Rig up and pump 1 gallon of cement down cjmical injection line. RUcementers on tubing and attempt to confirm injectivity through 1'1,1- sandscreen. Pump 8.33ppg water at 0.5bpm, max pressure 2000psi. Shutdown cementers. RU slickline. Pressure test lubricator to 3000psi. RIH with 2.1" Blind box to 5276' WLM, confirm hard bottom at same i depth as previous run. RIH with 1 9/16" tubing punch, 13 shots, 0 phase, to and attempt to mechanically fire–unsuccessful, POH. Rearm guns. RIH with 1 9/16" tubing punch, 13 shots, 0 phase, and attempt to mechanically fire–unsuccessful, POH. Safely disarm gun. RD Slickline. 11 Aug 2017 RU Cementers on OA 9-5 8"x 13-3 :" . • ). Confirm injectivity on OA by pumping 8.33 ppg water up to 3 bpm at 1000 psi. Standby OAk cementers. RU Eline. RIH with 1-9/16" tubing punch, 13 shots, 4 spf, 0 C l phase, and tag bottom at 5281.5' MD. Pull up and correlate, tubing /a punch at 5274'-5277' MD, POH. Confirm all shots fired. RD Eline. 5� Cementers mix and pump 115 bbls (544 sx) of 13.0 ppg cement down OA (9 5/8" x 13 3/8") at 3 bpm (PLUG #1). Wash up lines and swap hardline to tubing. Confirm injectivity by pumping 8.3 ppg water through tubing punch between packers at 5110' and 5291' MD at 2 bpm, 2615psi. Mix and pump 16.5 bbls (50 sx) of 13.0ppg cement down tubing and displace with 26.1 bbls of water at 2 bpm, 2450psi. Wash up lines and RD cementers. (PLUG #2) Calc TOC @ 4510' MD. 15 Aug 2017 RU cementers on 2-7/8" tubing and conduct in house pressure test to 1500 psi –good. 2I1 . 4 :� • • 16 Aug 2017 RU cementers on 2-7/8"tubing and pressure test surface lines. , TT- Pressure .� test tubing to 1650 psi for 30 mins and chart same - good. Pressure test witnessed b AO CG C Rep, Lou Laubenstein. RD cementers. RU Eline and shift sleeve at 3043' MD. RD Eline. 17 Aug 2017 RU cementers and pressure test surface lines. Tubing and IA =0 psi. Pump water at 4 bpm down tubing,through sliding sleeve at 3043', until returns confirmed after 15 bbls pumped at surface through IA (2- 7/8" x 9-5/8" annulus). Pump additional 5 bbls water confirming circulation. Mix and pump 15 bbls (46 sx) of 13.0 ppg cement at 3 bpm and displace with 16 bbls of water. CIP at 16:40. Wash up and RD cementers. (PLUG #3). 18 Aug 2017 RU Slickline and pressure test lubricator to 1500 psi. RIH with 2" BB and tag TOC in 2-7/8" tubing at 2673' MD, POH. RD Slickline. (Calc 200' cement on top of packer) 25 Aug 2017 RU cementers to IA (2-7/8 x 9-5/8" annulus) and pressure test surface lines. Conduct pressure test on IA to 1500 psi for 30 mins and chart same—good. RD cementers. 26 Aug 2017 RU Eline and pressure test lubricator. RIH with 1-9/16"tubing punch, 4 spf, 10 shots, 0 phase, and perforate from 592' —594.3' MD, good indication of fire, POH. Confirm all shots fired. RD Eline. RU Cementers and pressure test surface lines. Prep and mix 30 bbls Viscous polymer pill. Pump 1 bbls of water down tubing, taking returns through IA, confirm circulation. Pump 30 bbls of viscous pill and displace with 0.9 bbl water. Wash lines and RD cementers. 27 Aug 2017 RU Eline and pressure test lubricator. RIH with 1-9/16" tubing punch, 4 spf, 10 shots, 0 phase, and perforate from 208.7'—211' MD, good indication of fire, POH. Confirm all shots fired. RD Eline. RU cementers and pressure test surface lines. Pump 1 bbl water to confirm circulation. Mix and pump 59 bbls f238 sx) of 14.5 ppg cement until ,(44+), returns returns at 14.3 ppg cement. CIP at 17:00. Wash lines and RD cementers. (PLUG #4—surface/top plug). 28 Aug 2017 Begin excavation around cellar. Pull grating. 29 Aug 2017 Continue excavation. 1 Sept 2017 Continue excavation. 2 Sept 2017 Continue excavation. 3I ) �. • • 3 Sept 2017 Continue excavation. 4 Sept 2017 Continue excavation. Cut wellhead 50" below native soil/original ground level. Cement to cut in tubing, tubing x 9-5/8" annulus, and 13- 3/8" x 20" annulus. Cement 6ft down from cut in 9-5/8" x 13-3/8" annulus. 5 Sept 2017 Mix and cement 9-5/8" x 13-3/8" annulus with 2.6 cult of cement. Prep for plate weld. 6 Sept 2017 Receive verbal approval from AOGCC Rep, Jim Regg, to weld Abandonment plate on well. Provided photos of plate, cement at top, and depth of cut from original ground level. Weld Abandonment marker plate on well (final plate depth of 50" below original ground level/native soil). Send photo of welded plate to Jim Regg. Receive verbal approval from AOGCC Rep, Jim Regg, to back fill hole. 21 Nov 2017 Approval received from DEC to backfill hole. Delay for backfill due to weather/winter. 07 May 2018 Back fill hole and level area. 4 i ag e • 0 . - -;---' .-40,e ',:•-•-:-,,-00,:`'...*''''4..;;',.-vw':..Ltr.-:::41';- 7.-' .-.,,..".1r, li.,' _.:1-•:-''-:-.1:,.#,...*72.;r,''..-7...7.7.-4-7--. ,,,, _ - '---.4.,- '.'.: -'' •.,.." ... ' "•- '-". ; . - ; ../.. '-.' . .,•-' , -- 9,-*-4‘:,,,.-1 : -..---,..--.Z- ,..., : °,,,- .- ',•-•. - . .7. ,,,,L' .-°-. " - -4-- ; L .....- - - . , L--AL,1,;;.• ' - i° ,- .-. A L.; . ; - , t.-VZNAss ' - 3,---... - ' '' ...46....,...11..-- ' ....,. f'..... -... • ..4 :4.1'; ....t.' ,} ‘ „„. .///'„ . ...', ar\...,... , ..„..`, ,, 1:- '.,,,,,, -, . . ...7,t.......4. - ^:_ 11.".02,, '....- ,' 74-4 :::."?"--...,,1 ' ' ' ' ..- 4.0,2t .it -- •.. .%°...„. ...,....- • - ,r'..,::::4. 14111,0" '''--•"----- • . ''.42,,,". ."7-.,. ,,---./W-,,„„. . 410'.' -..*,e . ,., .,.*, 4. ' Yq4-. "A.:7417-L- L:-'b:-..'.7 44444''''''' ' e 3,4,5?,--4-: , '''''' - e. / . A I _..., •. - . 4,'''. . - 04 „: , r ' ---. g 'solo,-4 . . •..4v,,,. -. . :-. ••• \ . ... it:- ' '.' ..;,.',./'•-,- —., :-*" :!-.. , ' - 't..1,,, ' .. • .- . . . ,,,,..., ..•:-. '.:7„,'..-„,4,". " ', A7. .,.,..1". ,,, -, :1 7 ' ' ' 7 . 41i 4 Ai - Vi . , . . I-I' . Cv.r: it'''. ,, _ . %.1, < • -:-...' '''7*..- '. ,. .‘,7, 401,,fr "'•:' 1‘• : ; ',.i.' ., , . ';'-.'„._ 1$4,L ' L'..."44:. •- . °L , ,r , . ' .--., - t L . , , . . .. , * -11t$0 $ - 1 . ° . • • ' L',- -LL--,L,f°L.,- . _ 1-L°L ... ,.., .!'. '' '' ' - ' '„, , . ,' .44111161116'1141W'''';'.''''''l'_.„,r.,„''''''''''''4,,l':'•';'{'''..11.':::-.*:.:7'''-''''''''''''':1:' Tt. . . . , .. 1 , , t , . Kustatan Field#1 (API No: 50-133-20496-00-00/PTD: 200-153)—Cut at 51" below grade. 51Page • • LL +,• '" wfidr ,. t w it ; a � r .w Nay' If ,y A. t ly'it a .. �+. i� AFr r M y, f .. i ,rg r '. +yid'' " ta #tt W ° ch. ,- �' IX 'wt, ,� '' l� t 5 71 '' f ir a ia 4.r, € te . , w s s s.,,,„7. iI r , • i.yss ii!B.Y ,, w . , �' - { so ,24 Illnr. F r Kustatan Field#1 (API No: 50-133-20496-00-00/PTD: 200-153)—Cement to surface. Wage • • kr. fie " f rya } ' . ». "1. $x ` 47,6--',' :J 7 -:T. 11,, ,,,,..., fes. ._ .. .... . a irl'::; 4 s V e .jhbow + 4::p (:)C)..r....1 5 10.2 w ..4' K , , -,.„,,,:- ,....0„,„.',..,--;: , F... TA T-A r\I .,....,..,...---z. ir, , ....T. . E. L ii,..) , '' .2..... k _. , : ' ''' '''''''''..„-- ."..., , .:„ .,„ ,.. lb, . . ...: ., , pi , ,, .. , ,.. I' 4Q '' : . *x 5 - f -- ..t. .k z,4. " i 4 Xt. [ _ • i- h N ... i'l ' -.. i Kustatan Field#1 (API No: 50-133-20496-00-00/PTD: 200-153)—Welded Plate. 71 ., • • • -p�! • . .. 64:x... ., , ,,.:w ..„ ,.,,+atry ._ ,o..�ias...-k+r,e - � '^r+ � ,; " kW,Y. . "�� t ' y,„; `: _...t,'ws � ' r .. ycVit, . } . . wq' ". `w .tt ,.. - 1.00'. # ,"7 '14: -!4; ” .tiw _ if" ' y . y„r, '"4«..... ey _ h ` '4"."',,,,.j ..---.,4".--!`;;•',,'"` , • , b#;, ty aF "i,I -,..-i',. x%1 M„ y,,'''' �" itls � -{ . T 'IT'i',- of x I1 Y i.07. 'iit1 it • • # ir ' • t'� i >,r• • w .': 4 .. t s a. r "•4t;r a+ `� ; 1 `..1'4:+. !4., £' .' .-...--7-` '7 e. , • . '{'pec: .;,_&,,'-'.." � 1 ,+.�y iw_'�i„.. aJ sf ~r_ a"9.ty - ..- -` . "_ �4 �G' P y • .r �� Y f :""':.,":VM--�6 M Y i f s t Sk 4. Atikto, Y „,,,,,,,...,7-,.. # ”: t [ 'yr s„,,,, j '. - ••• �' �*,....i. ; /". t r P �r!,:._ :, . t - •4, . ..."4„,.44i ..0,.. . ,...4 .--.%..-. . It ,„ . .. . . _ . ,,...„ . ._.., ........, .... . ... 44 4 4 '•'',”, : 0) ' , ' IYi*P Y f x + P " ti Kustatan Field#1 (API No: 50-133-20496-00-00 /PTD: 200-153)—Backfilled and leveled area. 8 a KF#1 Final P&A Schematic Version: Final September 7,2017 GLACIER 1, ::-1.:,.: 'E t� 4---,..... 59 bbls of 14.5ppg cmt pumped down tbg/up annulus 20"Conductor I �Tubing punch @ 208'-211'MD ,: . Viscous Pill ; — Tubing punch @ 592-594'MD y _ 20" 133#K-55 120'MD , y ' Driven 120'TVD i• i• 0.25"Chemical injection line w/188 steel bands 116 bbls of 13.0ppg cement pumped down t^' 9-5/8"x 13-3/8"annulus � . 13 3/8" 68#K-55 1,820'MD 17-112"Hole a 12.415" BTC 1820'TVD Methanol Injection Mandrel @ 2980'MD •##' �r�-15 bbls of 13.0 ppg cmt pumped down tbg/up annulus 1e. TOC tagged @ 2673'MD WTFD"Hydrow 1"Hydraulic Set Retrievable Packer li \ID "ID 3.0"@ 3090'MD(30K straight pull release) ` X profile w/XO sliding sleeve-ID 2.313"@ 3043'MD X profile w/XO sliding sleeve-ID 2.313"@ 3136'MD CBL shows partially bonded cmt-3080'-3400' "— 2 7/8"6.5#N80 EUE Tubing-ID-2.441"@ 5297'MD WTFD"Hydrow@1"(Hydraulic Set Retrievable Packer . 16.5 bbls of 13.0 ppg cement pumped TOC CBL 5,000'MD • ID 3.0" 5110'MD(30K straight pull release) a ,.. .._.„. „....... .: . .,. : \__..,.\_....,..__,_______..__„ 768 of 4.5"Stratapac PMF 12/20 Sandscreen-ID 2.441" X-profile Nipple-ID 2.313"@ 5187'MD : @ 5193'MD FILit a WTFD"Arrowpak"Retrievable Seal bore Packer I - bing punch @ 5274'-5277 w/4.75"seal bore-ID 4.75"@ 5291'MD lam. (Packer seal bore not utilized,seals are stung into 3.25" " itN. Seals stabbed into PBR-ID 2.4"@ 5295'MD PBR below packer) % " 1 XN-Profile Nipple-ID 2.441"@ 313'ki.) A = End of tubing(shot off mid-joint)-ID 2.441"@ 5316'MD Cement on top of BP-TOC @ 6192'MD '+: " _ , ,.,,,, \"r ••`...eli "'e WTFD"Frac Guard"Composite BP @ 6220'MD '�� •,.f' - 3 " ' Fish-TCP pert gun-Length 71' is --,.w.. === 95/8" 47# L-80 6,500'MD Top of Liner @ 6,312'MD ID-8.681" BTC 6,500'ND 12 1/4"Hole ""`Tag fill @ 6312'MD(just before BP set in 2005) _ / CT Fish-Jet nozzle assy w/1.5"od CT(41ft)(2003) Cleanout w/CTU stopped @ 6754'(2003) Perforations Purpose MD Cmt Squeeze 3080'-3083' Packer @ 3090' Gas 3102'-3149' Gas 3265'-3283' Cmt Squeeze 3420'-3423' Packer @ 5110' Gas I 5204'-5260' TOC previously documented at 10,000'MD Packer @ 5291' Gas 5353'-5365' Gas 5370'-5380' Gas 5844'-5850' Bridge Plug @ 6220' Disposal 6270'-6304' Disposal 6344'-6475' Disposal 6750'-6800' " 7 5/8" 29.7#L-80 12,300'MD 8 1/2"Hole ID-X STL/FL4S 12,300'ND PBTD @ 12259'MD/12259'TVD • 0 Pt zoo r5. 0 Regg, James B (DOA) From: David Pascal <dpascal@glacieroil.com> ,� Sent: Thursday, May 3, 2018 1:17 PM 1ST Cy 713110 To: Regg, James B (DOA) 1( Cc: Leland Tate; Carlisle, Samantha J (DOA); Schwartz, Guy L (DOA); Stephen Ratcliff Subject: Re: Kustatan Field 1 Mr. Regg, During the P&A operation of KF-1, a legacy spill was discovered in Sep 17 around the well. Long story short, we had to work with ADEC on remediation work. Approval for backfill was granted on 21st Nov but by then everything got frozen. We are currently evacuating the pit of water (there is still a lot of ice) and will be proceeding with the backfill and hence the delay on the 10-407. We have been still reporting all `zeros' on the monthly production reports for KF-1. We will make sure that everything is satisfactory on the P&A from AOGCC's end Thank you for your patience in this matter Thanks and Regards David Pascal Production Manager 1 Glacier Oil and Gas Corporation 4L-44.-:,A04 Email:dpascal@glacieroil.com From: "Regg,James B (DOA)" <jim.regg(Walaska.gov> Date:Thursday, May 3, 2018 at 10:05 AM To: David Pascal <dpascal@glacieroil.com> Cc: Leland Tate<Itate@glacieroil.com>, "Carlisle, Samantha J (DOA)" <samantha.carlisle@alaska.gov>, "Schwartz, Guy L (DOA)" <guy.schwartz@alaska.gov> , Subject: Kustatan Field 1 AOGCC records show Kustatan Field 1 (PTD 2001530)was abandoned during August-September 2017 under approved Sundry 317-351 (copy of sundry attached). The required 10-407 is delinquent; it was due with 30 days of abandonment according to 20 AAC 25.070(3). Please submit not later than May 18, 2018. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 1 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg1-1 qt 7 DATE: 9/7/2017 P. I. Supervisor FROM: Matt Herrera SUBJECT: Surface Abandonment Petroleum Inspector Kustatan Field #1 - Cook Inlet Energy - PTD 2001530; Sundry 317-351] 9/7/2017: I flew out to Trading Bay Landing Strip and met up with Daniel Clark (CIE) and drove to Kustatan Field #1 location. My visit was to verify CIE's compliance with the marker plate and below-surface-grade requirements. It appeared as though the marker plate had already been welded to the casing stub. Top of the marker plate was verified at approximately 8-10 feet below grade. Information on the marker plate was correct as compared to the approved permit. Attachments: Photos (2) 501401) FEE 0 tia�1 2017-0907_Surface_Abandon KF-1 mh.docx Page 1 of 2 • • Surface Abandonment— Kustatan Field #1 (PTD 2001530) Photos by AOGCC Inspector M. Herrera 9/7/2017 r i , 'h: ✓ ,,_,,,,,,,,,,......,„,44,„' w m.:rt 4u#t °jif "LLQ'= a ,'" 1 'a,+�` ` -:',;it,,--,-;—`40:7"._ ,'' �t^ " 77- w t ?...x `' �J , '. I, • . ' 4. .!.....,:i.--;* i 4.1 fl 2017-0907 Surface Abandon KF-1 mh.docx Page 2 of 2 • • AOGCC Memorandum Date: 9/6/2017 To: Kustatan Field 1 (PTD 2001530) From: Jim Regg �1 7��''i 7 Supervisor, Petroleum Inspections Subject: Surface P&A Attached are photos provided by Cook Inlet Energy (CIE) documenting the surface abandonment of Kustatan Field#1. Photos show the correct cut-off depth below original ground level, cement to surface, the information included on the marker plate, and the marker plate welded onto the casing stub. 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' • - •• • .... ,•,- „,__- .. . .. . . • - - — . .::,. „ . , .. .. . -.-_ . , • . _• - -. --:---4*-0---- . ...., ... . _ ., •-- rz- --•—,, -- . ., . - . - , • , , . .. • "*-1*:-.-, -- ' - - ...- e • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission 1014117 TO: Jim Regg � DATE: 8/16/17 P. I. Supervisor 1 FROM: Lou Laubenstein SUBJECT: Abandonment Plug Verification Petroleum Inspector Kustatan Field #1 - Cook Inlet Energy PTD# 2001530;'Sundry 317-351 8/16/2017: I traveled to Kustatan Production Facility to witness a pressure test of a cement plug on the Kustatan Field #1 well. I arrived on location and went through a job walkdown with Mike Murray (Cook Inlet Energy). All paperwork and information was on location. This was a pressure test of plug #1 for 30 minutes at 1500psi. The plug is set from 5110-5291 ft isolating the lower set of perforations. The 30-minute pressure test passed. I have attached the test chart. Summary: I witnessed the successful test of a Kustatan Field #1 abandonment plug isolating the lower perforations. Attachment: Test Chart 2017-0816_Plug_Verification_KF-1_11.docx Page 1 of 2 • • S Abandonment Plug — Kustatan Field #1 (PTD 2001530) 8/16/2017 l 4 S tis T}: 1 Y `- x 4 f /f k� �,. /'i{ / \ f , /f 29 ,..;,,,,-r..; '� , / / /f/ �, �, : ‘. / i/ / y� t } I J i , /...4„. . i I ) 7 t 1 ; f '7 -; C7 i n o o t. _- #,_ 1 i 1 ; SG v N N 0 f.) A 1 • \\\ \\_, 1 \tt`i`\\ \ , , Y y: ti \! \\ �'. t -; '\.\\\ \\ \ \\.\ \:\\:\\::::-...=.'''.2-',.,,--,,, '2,/"(k,:c!.1_ .,',.,-_- t \\0 \ It 1 jS i L 1 P :ate, 2017-0816 Plug_Verification KF-1 11.docx Page 2 of 2 • • yoF ry • ��\��y�� THE STATE Alaska Oil and Gas ��•:'s�i��, fALASI`:A o Conservation Commission _:= --_�_ 333 West Seventh Avenue "411-.11-1711111*-C GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OF Q, Main: 907.279.1433 ALAS* Fax: 907.276.7542 www.aogcc.alaska.gov Conrad Perry Sr. Vice President scANNED A;l C 11 Z C I/ Cook Inlet Energy, LLC 601 W. 5th Ave., Ste. 310 Anchorage,AK 99501 Re: Kustatan Field,Kustatan Gas Pool,Kustatan Field 1 Permit to Drill Number: 200-153 Sundry Number: 317-351 Dear Mr. Perry: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy . Foerster Commissioner DATED this 3 a y of August, 2017. RBDMS [AAA - 9 2017 • RECsEl` • STATE OF ALASKA • ! JP( I ALASKA OIL AND GAS CONSERVATION COMMISSION JUL. 2 7 2 17 I APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AOGCC 1.Type of Request: Abandon E1. Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: COOK INLET ENERGY,LLC Exploratory ❑ Development E. 200-153 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: 601 W 5TH AVE#310,ANCHORAGE,AK 99501 50-133-20496-00-00 , 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No ❑., ,/ KUSTATAN FIELD#1 4 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 390368 c KUSTATAN FIELD#1 GAS POOL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 12300 , 12300 - , 6192 , 6192 1930 6220' 6192' Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 20" 120' 120' N/A N/A Surface 1820' 13 3/8" 1820' 1820' 3450 psi 1950 psi Intermediate 6500' 9 5/8" 6500' 6500' 6870 psi 4750 psi Production Liner 5988' 7 5/8" 12300' 12300' 6890 psi 4790 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): see attached , see attached 2 7/8"6.5# N80 5316' Packers and SSSV Type: Hydraulic set Retrievable packers x2 Packers and SSSV MD(ft)and TVD(ft): , 3090'MD/TVD;5110'MD/TVD Arrowpak retrievable sealbore packer • 5291'MD/TVD 12.Attachments: Proposal Summary in Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program ❑I BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 , Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 8/7/2017 Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended Cl 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Conrad Perry Contact Name: Amanda Dial Authorized Title: Sr.Vice P - .,-nt Contact Email: adial@glacieroil.com Contact Phone: 907-382-0124 Authorized Signature: 6�/ Date: COMMISSION?JSE O LY Conditions of approval: Notify Commis so tha presentative may witness Sundry Number: /j //' /� i` j Plug Integrity I BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance LIQ " `! rr / ^h Other: h_ ph,44/1. it., _,‘„„,,,„,,,,,,,4- C-4,5;,o , c_,..)---i6e 0_,...e ble,.e,0,,,,p /06.6_. Post Initial Injection MIT Req'd? Yes ❑ No ❑ '' n Spacing Exception Required? Yes ❑ No V Subsequent Form Required: /40-.y 7- RBDMS LvAUG - 9 2017 APPROVED BY Approved by: �/ COMMISSIONER THE COMMISSION Date: g- 3 - /7 ,47 46NAL76_,,,-/.7 Submit Farm and Form 10-403 Revised 4/2017 Approved application is valid r proval. Attachments in Duplicate . < • • GLACIER RECEIVED July 24th, 2017 JUL 2 7 2017 Mr. Hollis French, Chair AOGCC Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage,Alaska 99501 RE: Application for Sundry Cook Inlet Energy, LLC: Kustatan Field #1 (PTD 200-153) Dear Mr. French, Cook Inlet Energy, LLC, hereby applies for a Sundry for Kustatan Field #1 well located on ADL 390368, requesting to permanently abandon the well, leaving the tubing in place and completing the operations rigless. If you have any questions, please contact me at (907) 727-7404. Sincerely, Y Conrad P rry Sr. Vice President Cook Inlet Energy, LLC (a Glacier Oil & Gas wholly owned company) 601 W. 5th Avenue, Suite 310 Anchorage,AK 99501 1 • < • GLACIER 1. WELL NAME - Kustatan Field #1 Well Summary Current Status: Kustatan Field#1 is shut-in. All pressures are at 0 psi. Current Perforations: 3080'- 3083' (Cement Squeezed) 3102'- 3149' 3265'- 3283' 3420'- 3423' (Cement Squeezed) 5204'- 5260' 5353'- 5365' 5370'- 5380' 5844'- 5850' Perforations below bridge plug at 6220' MD 6270' - 6304' 6344'- 6475' 6750' - 6800' Scope of Work: • Check tubing and all annulus pressures. • Rig up slickline and test lubricator to 2000 psi. • Pull jet pump,close sliding sleeves. • Abandonment Plug#1: Set plug in XN nipple at 5313'. • Rig up cement unit,establish injection rate through sandscreen/tubing. • Abandonment Plug#2: Bullhead 14 bbls 12.5 ppg cement thru sandscreen (5193'-5269' MD) • Abandonment Plug#3: Bullhead 115 bbls 12.5 ppg cement down 13 3/8"x 9 5/8" annulus. • WOC. Pressure test tubing/cement to 1500 psi for 30 mins and chart same. • Open sliding sleeve at 3043'. Punch if needed. • Abandonment Plug#4:Circulate 15 bbls 12.5 ppg cement down tubing and up annulus,placing 200'cap on top of packer at 3090'. • Fill control line with cement to injection mandrel at 2980'. • WOC. Pressure test tubing/cement to 1500 psi for 30 mins and chart same. • Tubing punch at 200'. • Abandonment Plug#5:Circulate 10 bbls 12.5 ppg cement down tubing and up annulus,placing 200'cap at surface. • WOC.Check well dead on all valves. Remove tree.Recover cellar. • Cut casing 3'below original ground level.Weld on ID CAP. Backfill pad to grade. 2 • • GLACIER General Well Information: Reservoir Pressure/TVD: 2515 psi @ 5,850'TVD/5,850' MD MASP: 1930 psi Wellhead Type/Pressure Rating: Vetco Grey-5000 psi-Wellhead&Tree BOP Configuration: Lubricator Well Type: Gas Producer Estimated Start Date: August 7, 2017 Drilling Manager: Drilling Engineer: Production Manager: Conrad Perry Stephen Ratcliff David Kumar (907) 727-7404 (907) 433-3808 (907)433-3822 cperry@glacieroil.com sratcliff@glacieroil.com dkumar@glacieroil.com Program Note: Bridge plug set at 6220' MD is set 50 ft above the top of the perforated interval and has 28' of cement dump bailed on top. Prior to the bridge plug set in 2005, coil tubing was unable to pass 6754' MD due to fill and a final fill tag of 6312' was encountered prior to ending the cleanout operations. 1) Give 48-hour notice to AOGCC for plugging operations. 2) Check tubing and all annular pressures. 3) Rig up Slickline. Test lubricator to 2000 psi. 4) Pull jet pump from and close sliding sleeve at 3043'. Serb 5) Close sliding sleeve at 3,136'. ,--> t 1 -Z 6) Set Plug in 2 7/8" XN nipple at 5313'. 7) RD Slickline. 8) Rig up cement unit to tubing. Test lines to 2500 psi. 9) Establish injection rate with water through sand screen into perfs from 5204'-5260'. a. Monitor annulus pressures. 10) Pump 15 bbls of 12.5 ppg cement and displace with 27.5 bbls of water. a. Estimated TOC inside tubing-4500'. 11) Rig up cement unit to 13 3/8"x 9 5/8" annulus. est lines to 2500 psi. ($Zo's �5 t3k44f 12) Establish injection rate with water. Max allowable injection pressure is 1500 psi. = i° 13) Bullhead 115 bbls of 12.5 ppg cement down the 13 3/8" x 9 5/8"annulus. 14) Pump 1 gallon cement into chemical injection line. l`12t.. ' 15) WOC 16) Test tubing and cement plug to 1500 psi for 30 mins and chart same. . 17) Rig up slickline and open sliding sleeve at 3043'. I 7 me. j -L.h.-5,,�.. Zv� 3 • • • GLACIER a. Have Eline on standby to perf tubing, if needed. 18) RD slickline. 19) Establish circulation down tubing and up annulus. 20) Circulate 15 bbls cement down tubing and through sliding sleeve, capping packer at 3090' with 200' of cement, and displace with 16 bbls of water. a. Estimated TOC inside tubing—2770'. 1 ,F .. 'f 5��"`''_`''"'�� 21) WOC.Test tubing and cement plug to 1500 psi for 30 mins and chart same. / �s,.: 22) Rig up Eline and perforate tubing at 200'. ---', (7Ac rvc_ Z.7cw S'.1-tf- ... . 23) Establish circulation and pump cement+/-20 bbls until good returns to surface.' f 1I 24) Rig down cement unit. 25) WOC __ 26) Nipple down tree. 27) Dig out to 8' below original ground level. Ensure grade is sufficient to allow safe access for welder to cut casing. 28) Cut all casing strings 3' below original ground level. „ . ' '`�` 5 21 `�`��G //r-- YY f r' 29) Top off all annular space with cement if it is not to surface in all casing strings. U•Xi -S. p a. Take i ures of cement at surface in all strings. / 0 Install well cap as follows [Regulation 20 AAC 25.120]: (1) is constructed of steel that is at least 1/4 inch thick; (2) is welded to, and covers, the outermost casing string, including the conductor casing; (3) does not extend beyond the outermost casing string; and (4) contains the following information bead-welded directly to the marker plate: (A)The name of the operator that plugged and abandoned the well; (B)The number assigned by the commission to the Permit to Drill (Form 10-401)for the well under 20 AAC 25.040(b); (C)The name designated for the well by the operator under 20 AAC 25.005(f); (D)The API number for the well, with any suffix appended to the number under 20 AAC 25.005(f). -------M— -______ --N COOK-----M— COOK INLET ENERGY 200-153 KUSTATAN FIELD#1 x 50-133-20496-00 31) Take pictures of casing stubs with cement, welded cap, and final after grading pad. Submit to town for inclusion in final report. kF 2 d lep/s�- Pio 1,.CI',sn y Jit 2°(97 w�P �l P� �1, Cal Cvg • n, IfIget Ott el To y is /HCW, I"�1/i 1'4P Rr/&Ap Imre /odery re('rfurste rite wet/ 010/ I1`v//7 fit' to /rooe��04 4yr 7.4,' froi., r Uh l(ICCeriq itet �flbolvtt,o7 /lever exceed''3 /rte 30 / 7, T4/) Pvell 4of 4 readapt Tit g„of I 6,4 ill vSeiV i Ke__ ono/ sl&t ' Al.? 7/07 KF#1 Final Completion Schematic Version: Updated •• < Ili April 18,2017 GLACIER , <, 20"Conductor 20" 133#K-55 120'MD Driven 120'TVD 0.25"Chemical injection line w/188 steel bands } r-4 a. •` 13 3/8" 68#K-55 1,820'MD 17-1/2"Hole ,' I 12.415" BTC 1820'TVD ' jii, Methanol Injection Mandrel @ 2980'MD w %IR X profile wfXO sliding sleeve-ID 2.313"@ 3043'MD WTFD"Hydrow 1"Hydraulic Set Retrievable Packer . JE, T PIMP installed in Sliding Sleeve(2012) ID 3.0"@ 3090'MD(30K straight pull release) Mil = JI ., X profilew/XO sliding sleeve-ID 2.313"@ 3136'MD CBL shows partially bonded cmt-3080'-3400' _ " gm TOC(CBL)@ 5,000'MD ....x. Re sxw 2 7/8"6.5#N80 EUE Tubing-ID-2.441"@ 5297'MD WTFD"Hydrow 1"Hydraulic Set Retrieuabia Packet ID 3.0"@ 5110'MD(30K straight pull release) :`_---:,_,1: 7i 'X-profile Nipple-ID 2.313"@ 5187'MD i � 768 of 4.5"Stratapac PMF 12/20 Sandscreen-ID 2.441" @ 5193'MD WTFD'Arrowpak"Retrievable Seal bore Packer i w/4.75"seal bore-ID 4.75"@ 5291'MD !' Seals stabbed into PBR-ID 2.4"@ 5295'MD I.(Packer seal bore not utilized,seals are stung into 3.25" PBR below packer) „?; XN-Profile Nipple-ID 2.441”@ 5-310132 313'MD End of tubin shot off mid-oint I0 2.441" 5316'MD 9( j ) @ r" Cement on top of BP-TOC @6192'MD 3. �a�>:ce. xr +a, p gun 1 _ � Fish sh-TCP erf -Length 71' ' WTFD"Frac Guard"Composite BP @ 6220'MD ' "'a I ilt== 9 5/8" 47# L-80 6,500'MD Top of Liner @ 6,312'MD ID-8.681" BTC 6,500'ND 12 1/4"Hole .. ----- , ' KV Tag fill @ 6312'MD(just before BP set in 2005) CT Fish-Jet nozzle assy w/1.5"od CT(418)(2003) - Cleanout w/CTU stopped @ 6754'(2003) Perforations Purpose MD le /� Cmt Squeeze 3080'-3083' (/ Packer @ 3090' Gas 3102'-3149' • 0 5 g 7 614 f Gas 3265'-3283' Cmt Squeeze 3420'-3423' / j34 Ji ) Packer @ 5110' \ (j g Gas t 5204'-5260' + TOC previously`documented at 10,000'MD i Packer @ 5291' 4J Gas 5353'-5365' Gas 5370'-5380' ,Gas 5844'-5850' Bridge Plug @ 6220' Disposal 6270'-6304' Disposal 6344'-6475' Disposal 6750'-6800' ',t 7 5/8" 29.7#L-80 12,300'MD 8 1/2"Hole -' ID-X STL/FL4S 12,300'ND PBTD @ 12259'MD/12259'TVD KF#1 Proposed P&A Schematic Version: Planned • • July 18,2017 II1] IGLACIER 7 20"Conductor 20" 133#K-55 120'MD ''1 Driven 120'TVD ..., 1 : ,..... 0.25"Chemical injection line w/188 steel bands ;` ,, 13 3/8" 68#K-55 1,820'MD 17-1/2"Hole . 12.415" BTC 1820'TVD .oma.. Methanol Injection Mandrel @ 2980'MD 44. re is X profile w/XO sliding sleeve-ID 2.313"@ 3043'MD , im , WTFD"Hydrow 1"Hydraulic Set Retrievable Packer ID 3.0"@ 3090'MD(30K straight pull release) X profile w/XO sliding sleeve-ID 2.313"@ 3136'MD CBL shows partially bonded cmt-3080'-3400' """'3 M M TOC(CBL)@ 5,000'MD II" 2 7/8"6.5#N80 EUE Tubing-ID-2.441"©5297'MD WTFD"Hydrow 1"Hydraulic Set Retrievable Paacker7.4 . till ID 3.0"@ 5110'MD(30K straight pull release) ill ' ' ,,, , - X-profile Nipple-ID 2.313"@ 5187'MD bb s u M ' 76ft of 4.5"Stratapac PMF 12/20 Sandscreen-ID 2.441" @5193'MD WTFD"Arrowpak"Retrievable Seal bore Packer <- w/4.75"seal bore-ID 4.75" 5291'MD 7.' ." !,:li Seals stabbed into PBR-ID 2.4" 5295'MD (Packer seal bore not utilized,seals are stung into 3.25" f'?4,1 -. -. -• •ug set in XN-Nipple @ 5313'MD PBR below packer) 4y 4 XN-Profile Nipple-ID 2.441"@ 5313'MD End of tubing(shot off mid-joint)-ID 2.441"@ 5316'MD Cement on top of BP-TOC @ 6192'MD ,0.;' ,.`~ Fish-TCP pert gun-Length 71' WTFD"Frac Guard"Composite BP @ 6220'MD w - __ ,z.; •, - C - 11== 9 5/8" 47# L-80 6,500'MD Top of Liner @ 6,312'MD -1, ID-8.681" BTC 6,500'ND 12 1/4"Hole Tag fill @ 6312'MD(just before BP set in 2005) CT Fish-Jet nozzle assy w/1.5"od CT(41 ft)(2003) Cleanout w/CTU stopped @ 6754'(2003) Perforations Purpose MD Cmt Squeeze 3080'-3083' Packer @ 3090' Gas 3102'-3149' Gas 3265'-3283' Cmt Squeeze 3420'-3423' Packer @ 5110' Gas 15204'-5260' TOC previously documented at 10,000'MD Packer @ 5291' Gas 5353'-5365' Gas 5370'-5380' Gas 5844'-5850' Bridge Plug @ 6220' Disposal 6270'-6304' Disposal 6344'-6475' Disposal 6750'-6800' 7 5/8" 29.7#L-80 12,300'MD 8 1/2"Hole 3 ID-X STL/FL4S 12,300'TVD PBTD©12259'MD/12259'TVD d .Zoo- /S3 .st.„ /7,. • I'HESTA"1'E `enarim cn f Natural l (asout.( 1 -I "• OfA L A SKA '^+14 t ' « - ` (4)11;RNOIt 13I1,1. WALKER October 6,2016 Cook Inlet Energy,LLC SC M414 ��� 1 , ADL 390368 Attn:Tim Jones 601 W. 5th Ave.,Suite 310 Anchorage, AK 99501 SURRENDER OF LEASE The Division of Oil and Gas (Division) issued the above-referenced oil and gas lease effective October 1,2003. On September 15, 2016,Cook Inlet Energy, LLC submitted a written surrender for the lease in its entirety.In accordance with lease provisions and 11 AAC 82.635(b),a surrender takes effect on the date it is filed,subject to the continued obligation of the lessee and its surety to make payment of all accrued royalties and rentals and to place the surrendered land in condition satisfactory for abandonment. A person affected by this decision may appeal it,in accordance with 11 AAC 02.Any appeal must be received within 20 calendar days after the date of"issuance"of this decision, as defined in 11 AAC 02.040(c)and(d),and may be mailed or delivered to Commissioner,Department of Natural Resources, 550 West 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to 1-907-269- 8918; or sent by electronic mail to dnr.appeals®alaska.gov. This decision takes effect immediately. If no appeal is filed by the appeal deadline, this decision becomes a final administrative order and decision of the department on the 31st day after issuance. An eligible person must first appeal this decision in accordance with 11 AAC 02 before appealing this decision to Superior Court.A copy of 11 AAC 02 may be obtained from any regional information office of the Department of Natural Resources. Sincerely, James B.Beckham Acting Director • am /s3 From Davies, Stephen F (DOA) Date 4/18/2013 9:42:29 AM To Edmunds, David C (DNR) Cc McMains, Stephen E (DOA); Schwartz, Guy L (DOA); Bettis, Patricia K (DOA) Subject Lease ADL 390368 and Kustatan - KF #1 Aimage001.ipq(2 KB HTML) David, In follow-up to our telephone conversation, Kustatan Field#1 (KF#1) is a gas development well that last produced in November 2012. The well is currently considered to be shut-in. AOGCC Regulation 20 AAC 25.105(a) states: All wells that have been permitted on a property under 20 AAC 25.005 must be abandoned before expiration of the owner's rights in that property or if, after notice and hearing, the commission orders abandonment for safety reasons or because the operator has effectively abandoned operations prior to the expiration of the lease. If the owner is the landowner, all wells that have been permitted on a property by 20 AAC 25.005 must be abandoned within one year following permanent cessation of the operator's oil and gas activity within the field where the wells are located or according to an abandonment schedule approved by the commission, unless the wells are earlier abandoned for safety reasons. Cook Inlet Energy cannot simply relinquish lease ADL 390368. They must submit an Application for Sundry Approval to, and receive approval from,the AOGCC before work is begun to abandon the KF#1 well. See 20 AAC 25.105(e). Please remind Cook Inlet Energy to review regulation 20 AAC 25.105,which is available online at: http://doa.alaska.gov/ogc/Regulations/Reglndex.html. Please ask Cook Inlet Energy to contact the AOGCC if they have questions. Best Regards, Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) 1 0 Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. Q 00 - _I 3 Well History File Identifier Organizing (done) ❑ Two -sided 111 iIIIIJIIIi 11111 ❑ Rescan Needed 11! JIIIIJIJII 111111 RES N DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ ps: Greyscale Items: ❑ Other, No/Type: Other Items Scannable by ❑ Poor Quality Originals: a Large Scanner 6 LOG' OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: BY: ). Date: 1/10 / /s/ Project Proofing 111111111111111111 BY: (Mari Date: 1 / 10 ) 11 /s/ nif Scanning Preparation I c, x 30 = -3 100 + e2 1 1 - = TOTAL PAGES 7 :234_ I / ount does not include cover sheet) BY: Maria , Date: f /0 Is/ iii. Production Scanning III 1111111111 II III Stage 1 Page Count from Scanned F (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: OYES NO BY: Maria Date: 1/10/ 1 1 /s/ Kip Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. 1 III ReScanned 1111111111111111111 BY: Maria Date: Is/ Comments about this file: Quality Checked 111 I 10/6/2005 Weil History File Cover Page.doc . • • • RECEIVED Cook Inlet Energy_ JAN 18 2013 AOGCC January 17, 2013 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7 Ave., Suite 100 ad b I 5.3 Anchorage, Alaska 99501 RE: KF #1 (PTD 2001530) Sundry Report of Operations Sundry No: 312 -013 Dear Commissioner Foerster, Cook Inlet Energy submits an updated 10 -407 form for the report of sundry well operations for the KF#1 in the Kustatan field of Cook Inlet. Attached please find a completed Form 10 -407 for the work with the requested well testing data. If you have any questions or require additional information, please contact me at (907) 433 -3804. Sincerely, Cook Inlet Energy SCANNED MAR 13 2013 Davi all, CEO Attachments: Form 10 -407 Well Completion Report 601 West 5 Avenue, Suite 310, Anchorage, Alaska 99501 Phone (907) 334 -6745 STATE OF ALASKA • . AL. OIL AND GAS CONSERVATION COINASION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas 151 ,. SPLUG ❑ Other ❑ Abandoned ❑ Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Q • Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No. of Completions: Service ❑ Stratigraphic Test ❑ 2. Operator Name: 5. Date Comp., Susp., or 12. Permit to Drill Number: COOK INLET ENERGY, LLC Aband.: 200 -153 ' 3. Address: 6. Date Spudded: 13. API Number: 601 W 5TH AVE #310 ANCHORAGE, ALASKA 99501 N/A 50- 133 - 20496 -00 • 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 3,443' FNL, 1,468 FWL Sect. 4 T7N, R14W SM N/A KUSTATAN FIELD #1 Top of Productive Horizon: 8. KB (ft above MSL): 260 • 15. Field /Pool(s): GL (ft above MSL): 230- KUSTATAN FIELD #1 GAS POOL Total Depth: 9. Plug Back Depth(MD +TVD): 6,192'MD/6,192TVD 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 186839.181 y- 2460784.001 Zone- 12,300' MD /12,300TVD ADL 387023 • TPI: x- y- Zone- 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x- y- Zone- N/A N/A 18. Directional Survey: Yes Ei No ❑ 19. Water Depth, if Offshore: 20. Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) N/A 21. Logs Obtained (List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re -drill /Lateral Top Window MD/TVD: CBL 4-9 -2012 from 3386' to 2300' N/A 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 133# K -55 120' 120' Driven N/A NONE 13 3/8" 68# k -55 1820' 1820' 17- 1/2" SURF NONE 9 5/8" 47# L -80 6500' 6500' 12 1/4" 643 Cu Ft NONE 7 5/8" 29.7# L -80 12300' 6,312' 12300' 8 1/2" 678 Cu Ft. NONE 24. Open to production or injection? Yes 0 No ❑ 25. TUBING RECORD If Yes, list each interval open (MD +TVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MD/TVD) Size and Number): 2 7/8" L -80 6.5# EUE 5,297'MD/TVD 3089'MD/TVD New Perforations: 3102'= 3115' =13' 3115'- 3125' =10' 3125'- 3135' =10' 109' MD/TVD 5291'MD/TV 3135'= 3149' =14' 3265'- 3283' =18' 3 3/8" guns, 6 SPF 60* phase 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. OPEN Perforations: 5204'- 5225' =21' 5225'- 5246' =21' 5246'- 5260' =14' Was hydraulic fracturing used during completion? Yes LJ No Ei Squeeze perfs 3420'-3423' and 3080'-3083' DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 3080' - 3083' MD/TVD Pumped total 20 bbl preflush Mud Clean with 4 %KCL at 3420' - 3423' MD/TVD 8.53ppg. Followed by 26 bbl Class G +,1% R3 +.2 %CD32 +.4 %FL62 +.05 %ASA301 +1 GAL /100SX, FP6L+ 43.9% Fresh Water. 126 SXS @15.8 ppg Final squeeze pressure 1460 psi at 1 bbl /min PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): 5/4/2012 Swabbina Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 5/4/2012 8 Test Period 0 0.06 MMcf /d Unknown 10 N/A Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 10 -150 PSI 0 24 -Hour Rate ...p 0 0.32 Unknown N/A 28. CORE DATA Conventional Core(s) Acquired? Yes ❑ No El Sidewall Cores Acquired? Yes ❑ No 0 If Yes to either question, list formations and intervals cored (MD +TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. RBDMS JAN 3 0 2013 Form 10 -407 Revised 10/2012 CONTINUED ON REVERSE 7z . I it original only 2- . 0 } ��-\ri9- • • 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? ❑ Yes No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if Permafrost - Top needed, and submit detailed test information per 20 AAC 25.071. Permafrost - Base Formation at total depth: 31. List of Attachments: Completion diagram, wellbore schematic 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Courtney Rust 907 -433 -3809 Email: courtney.rust ©cookinlet.net Printed Name: David Hall Title: CEO Signature: /e Phone: 907 -433 -3804 Date: 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. Submit a well schematic diagram with each 10 -407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1b: Classification of Service wells: Gas Injection, Water Injection, Water - Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50- 029 - 20123- 00 -00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. 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 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut -in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 MC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 MC 25.071. Form 10 -407 Revised 10/2012 Cook Inlet Energy !< 1- We-// F7o w re S7 3 - 4/— /7 Clock Choke Wellhead Wellhead Inner Outer Separator Separator 011terenlbl Orifice Gas Gas Total Water Water Sediment Water Sediment Sediment time Comments Setting Temp Press Annulus Annulus Press Temp Press Plea Rate Gum Fluid Gain Cum Cut Chlorides Gain Cum hhlmm (le/ ° 'F psl(g) psi(g) psl(g) p.pg) 'F Inch HuG In. /MN MMef bbls bbgiu tibia % bblihr bbl 4 SD 15" y7 Soo --- to 390 Y,To S•o W' .do /o f -- l t Y 31 Co 3 Cb G 4' .G tr ,oSq /0 t6 ` It ys 3 — fa 35 Vie Z. i .for 103E , 2. yy 3 30 - � 0 3 Yv Yz. 1.0 .a .o4t I05'0 -- /t y2. 30o - fo Soo Y/ 2.Z. It 697 l /0 — IL I Q 295 - _re 2qs yo Z•1 •• .092 • if to = !z yz Leo - f0 2.7f Yo 2 .3 to .043 35 /i /7 z. So - so 2 $' , 9/ 1.5 «. •0Gq I( yo i y7 7i4 - co 25o q /•N it _ 467 it y“ t o if$ 2 to • Sfl 2 2 S Y3 0.8 rr , oft 12.05 to t2._ lob - f 2-D1 Yz 0.$ t. . °V7 1 z3o -- to 11 1 9f — s.0 le y t O. g it ofr /300 — ( 5:e , /7, - 11I 'ii o. ) ►t "'re 030 to sy 1112. -- e I so NZ '1,Z it •ost - - i 1N0 _ t 5 ( $4 — ;, Izo j/2. I. 7 " .ofo Pt 30 to 5 /2f - Co gs y ( I.I at ,0 VI I tsars to 5 IC - so Co y/ f, (, i1 ,o$ rf 10 4g IL — S0 Sit, 'It S.Sy I tr • 16.4 /0 , 9 r/o - 3 /0 y2 3.q I t ,ose (Cc — 51 w II • l _ Cook Inlet Energy November 14, 2012 !, Ms. Cathy Foerster, Chair v ED Alaska Oil and Gas Conservation Commission NO V 14 2012 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 AOGCC RE: KF #1 Production through the annulus Dear Commissioner Foerster, Cook Inlet Energy would like to apologize for the oversight of failing to notify AOGCC of attempting to test de- watering the Kustatan Field #1 (KF #1, PTD 2001530) well in the Kustatan Field of Cook Inlet by jet pump through the annulus. After the completion of the work -over from Sundry No 312 -013, Cook Inlet Energy attempted to de -water the well from zones 5,204' — 5,260', 5,353' - 5,365' and 5,370' — 5,380' MD by swabbing the well. After swabbing the well for a period of time, CIE tested to see if a jet pump would be a more effective testing solution. The sliding sleeves in the well allowed for a jet pump to be installed to de -water the well and test for gas production. It was brought to Cook Inlet Energy's attention on 11/9/12 that approval was necessary and the well was shut -in at 12:30pm on 11/9/12 due to the submittal of KF #1 SSV test results on 11/8/12. The SSV Test was performed on 10/26/12. CIE has discontinued the use of the jet pump. CIE would like to continue to de -water the well through swabbing operations. If you have any questions or require additional information, please contact me at (907) 433 -3804. Sincerely, Cook Inlet Energy David Hall, CEO 601 West 5th Avenue, Suite 310, Anchorage, Alaska 99501 Phone (907) 334 -6745 ► • • RECEWED Cook Inlet Energy NOV 1 S am AOGCC November 13, 2012 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission SCANNEU APR 1 3 333 West 7 Ave., Suite 100 Anchorage, Alaska 99501 RE: KF #1 (PTD 2001530) Sundry Report of Operations Sundry No: 312 -013 Dear Commissioner Foerster, Cook Inlet Energy submits a report of sundry well operations for the KF#1 in the Kustatan field of Cook Inlet. The work performed included additional perforations from 3,102' — 3,149' and 3,265' — 3,283' and re- perforation from 5,204' — 5,260' including screen installation. Attached please find a completed Form 10 -407 for the work, summary of well operations and the current wellbore schematic for Sundry 312 -013. If you have any questions or require additional information, please contact me at (907) 433 -3804. Sincerely, Cook Inlet Energy David Hall, CEO Attachments: Form 10 -407 Well Completion Report Summary Operations Report Current Wellbore Schematic 601 West 5 Avenue, Suite 310, Anchorage, Alaska 99501 Phone (907) 334 -6745 STATE OF ALASKA ALAPA OIL AND GAS CONSERVATION COM SION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la. Well Status: Oil 17] Gas 0 • SPLUG ❑ Other ❑ Abandoned 111 Suspended0 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development el • Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No. of Completions: Service ❑ Stratigraphic Test ❑ 2. Operator Name: 5. Date Comp., Susp., or 12. Permit to Drill Number: COOK INLET ENERGY, LLC Aband.: 4/21/2012 200 -153 • 312 -013 3. Address: 6. Date Spudded: 13. API Number: 601 W 5TH AVE #310 ANCHORAGE, ALASKA 99501 N/A 50 -133- 20496 -00 • 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 3,443' FNL, 1,468 FWL Sect. 4 T7N, R14W SM N/A KUSTATAN FIELD #1 . Top of Productive Horizon: 8. KB (ft above MSL): 260 15. Field /Pool(s): GL (ft above MSL): 230 KUSTATAN FIELD #1 GAS POOL • Total Depth: 9. Plug Back Depth(MD +TVD): 6,192'MD/6,192'TVD 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 186839.181 • y- 2460784.001 . Zone- 12,300' MD /12,300'TVD • ADL 387023 • TPI: x- y- Zone- 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x- y- Zone- N/A N/A 18. Directional Survey: Yes U No ❑ 19. Water Depth, if Offshore: 20. Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) N/A 21. Logs Obtained (List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re- drill /Lateral Top Window MD/TVD: CBL 4-9 -2012 from 3386' to 2300' N/A 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 133# K -55 120' 120' Driven N/A NONE 13 3/8" 68# k -55 1820' 1820' 17- 1/2" SURF NONE 9 5/8" 47# L -80 6500' 6500' 12 1/4" 643 Cu Ft NONE 7 5/8" 29.7# L -80 6,312' 12300' 6,312' 12300' 8 1/2" 678 Cu Ft. NONE 24. Open to production or injection? Yes 0 No ❑ 25. TUBING RECORD If Yes, list each interval open (MD +TVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MD/TVD) Size and Number): 2 7/8" L -80 6.5# EUE 5,297'MD/TVD 3089'MD/TVD New Perforations: 3102'= 3115' =13' 3115'- 3125' =10' 3125'- 3135' =10' 109' MD/TVD 5291'MD/TV 3135'= 3149' =14' 3265'- 3283' =18' 3 3/8" guns, 6 SPF 60* phase 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. OPEN Perforations: 5204'- 5225' =21' 5225'- 5246' =21' 5246'- 5260' =14' W as hydraulic fracturing used during completion? Yes U No IN Squeeze perfs 3420'-3423' and 3080' -3083' RECEIVED DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED N 1 Zd �2 3080' - 3083' MD/TVD Pum total 20 bbl preflush Mud Clean with 4 %KCL at 3420' - 3423' MD/TVD 8.53ppg. Followed by 26 bbl Class G +.1% R3 +,2 %CD32 +,4%FL62 +.05 %ASA301 +1 GAL /100SX, AOGCC FP6L+ 43.9% Fresh Water. 126 SXS @15.8 ppg Final squeeze pressure 1460 psi at 1 bbl /min PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): Swabbing. well is still beina tested. 9/2012 production was 20 MCF Date of Test: Hours Tested: Production for Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Test Period ...■lo. open Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 24 -Hour Rate .4. 28. CORE DATA Conventional Core(s) Acquired? Yes ❑ No 0 Sidewall Cores Acquired? Yes ❑ No El If Yes to either question, list formations and intervals cored (MD +TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. Form 10-407 Revised 10/2012 CONTINUED ON REVERSE Submit on al only 2 . 2-?. /Z '" (%/3/ 42_ ' •4' • 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? ❑ Yes 0 No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if Permafrost - Top needed, and submit detailed test information per 20 AAC 25.071. Permafrost - Base Formation at total depth: 31. List of Attachments: Completion diagram, wellbore schematic 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Email: Printed Name: v /d 1://446- Title: p ` Signature: 1 Phone: lJ �- ,1d 0 r Date: /��J/ 20 Z INSTRUCTIONS eral: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10 -407 well completion report and 10 -404 well sundry report when the downhole well design is changed. Item 1b: Classification of Service wells: Gas Injection, Water Injection, Water - Altemating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50- 029 - 20123- 00 -00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. 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 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut -in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10 -407 Revised 10/2012 • • Table of Contents Current Wellbore Diagram 4 Current Completion Diagram 5 p �' Daily Report Summary 6 3IPage lir . • Kustatan Field #1 Current We |bore Diagram 11 -13 -12 KB=30' § 20 "133 K-55 Al20' MD Lev Methanol Injection . 13 3/8" 68# K 55 BTC A 1820' MD Mandrel p 2980' M D 4 ¥ • 7 27/8`&5 L-80 EUE Tubing Sliding Sleeve c 3O y ��� /�� S •f :'''..% % 95/8 "RmMe Retrievable Packer @ 3089' MD Sliding Slee 7 A 3135' 7 q % 95/8 "Retrievable Packer @ 5109' MD Stratapac Screens across per! 5193' and 5231' • v ¥ 2 7/8" XN Nipple @ 5187' MD 9 5/8" Black cat Pack r@ 5291' MD V Plug @ 5385' ƒ k � ;, « Bridge mug @ 6192' MD Squeeze P A. 308' r Top of 7 5/8 " Liner @ 6312' MD 3420 % New Gas P A: ' ; ' 9 5/8 "47 b8 BTC @ 6500 ' MD 3102s3115 3115 312eWE 3125'-3135'=10' ; A 3135'=3149'=14' 3265'-3283'=18' 7 4 PBD @ 6743' MD (8/14/03 CTU) 5204'-5225'=21' 5225'-5246'=21' 5246'-5260'=14' . . Existing Gas P A: % r. 5353-5365=12' 5370-5380 do ' ; 54-580%& • % k k % Disposal Perf : >7 .. 6270-6304' MD % 75/8 "2.7 L-80 STDFL S @12,300' MD 6312-6475' MD 6750-6800' MD COMPANY: Wet Energy LLC SING TUBING I WELL NAME: tan #1 SIZE: 9 5/8" 2 7/8" FIELD: Kustatan WEIGHT: 47# 6.4# COUNTY: GRADE: N -80 STATE: AK THREAD: EUE 10 DATE 4/16/2012 DEPTH: 5297.63' MAX. O.D. MIN. I.D. LENGTH DEPTH - I ITEM DESCRIPTION INCHES INCHES FEET FEET 1 KB 13 2 Tubing Hanger 0.83 12.37 3 2 7/8" N -80 EUE tubing joint 3.688 2.441 31.36 13.2 4 2 7/8" N -80 EUE tubing pup 3.688 2.441 6.26 44.56 .EI 5 2 7/8" N -80 EUE tubing pup 3.688 2.441 6.33 50.82 16 000 • ± 6 2 7/8" N -80 EUE tubing pup 3.688 2.441 6.3 57.15 7 2 7/8" N -80 EUE tubing pup 3.688 2.441 8.16 63.45 1 8 90- joints 2 7/8" N -80 EUE tubing 3.688 2.441 2809.84 71.61 El 9 2 7/8" N -80 EUE tubing pup 3.688 2.441 4.2 2881.45 III 10 Nova Technology chemical injection mandrel 4.463 2.441 4.27 2885.65 11 2 7/8" N -80 EUE tubing pup 3.688 2.441 4.2 2889.92 12 2 7/8" N -80 EUE tubing pup 3.688 2.441 10.25 2894.12 13 2 7/8" N -80 EUE tubing pup 3.688 2.441 10.17 2904.37 M "i 14 4- joints 2 7/8" N -80 EUE tubing 3.688 2.441 124.49 2914.54 M. 15 2 7/8" N -80 EUE tubing pup 3.688 2.441 4.17 3039.03 21 7- 16 2 7/8" EUE x 2.313 X profile WXO sliding sleeve 3.688 2.313 3.09 3043.2 17 2 7/8" N -80 EUE tubing pup 3.688 2.441 4.2 3046.29 • 18 2 7/8" N -80 EUE tubing joint 3.688 2.441 31.37 3050.49 19 2 7/8" N -80 EUE tubing pup 3.688 2.441 6.3 3081.86 !� 20 4 1/2" EUE pin x 2 7/8" EUE box x -over 4.76 2.441 1.76 3088.16 M 21 Weatherford " Hydrow 1" hydraulic set retrievable packer 8.25 3 9.75 3089.92 I 22 set up for 30,000f straight pull release 4 1/2" EUE box x 2 7/8" EUE pin x -over 5.57 2.441 0.82 3099.67 23 2 7/8" N -80 EUE tubing joint 3.688 2.441 31.35 3100.49 24 2 7/8" N -80 EUE tubing pup 3.688 2.441 4.14 3131.84 25 2 7/8" EUE x 2,313 X profile WXO sliding sleeve 3.688 2.313 3.09 3135.98 .� 26 2 7/8" N -80 EUE tubing pup 3.688 2.441 4.14 3139.07 25 oao ± 2 7 2 7/8" N -80 EUE tubing pup 3.688 2.441 8.14 3143.21 28 2 7/8" N -80 EUE tubing pup 3.688 2.441 10.21 3151.35 El 29 62 joints 2 7/8" N -80 EUE tubing 3.688 2.441 1940.45 3161.56 ■ 111 � 30 2 7/8" N -80 EUE tubing pup 3.688 2.441 6.17 5102.01 31 4 1/2" EUE pin x 2 7/8" EUE box x -over 4.76 2.441 1.76 5108.18 Mt- :5 32 Weatherford " Hydrow 1" hydraulic set retrievable packer 8.25 3 9.75 5109.94 a 32 . I set up for 30,000# straight pull release 33 4 1/2" EUE box x 2 7/8" EUE pin x -over 5.57 2.441 0.82 5119.69 • �l 34 2- 2 7/8" N -80 EUE tubing joints 3.688 2.441 3.688 2.441 62.77 5120.51 rJ , 35 2 7/8" N -80 EUE tubing pup 4.13 5183.28 To 36 2 7/8" EUE x 2.313" X- profile nipple 3.688 2.313 0.8 5187.41 • I 1 I 1 37 2 7/8" N -80 EUE tubing pup 3.688 2.441 4.15 5188.21 38 2 7/8" EUE pin x 4 1/2" BTC x -over 4.5 2.441 1.3 5192.36 39 4 1/2" Stratapac PMF 12/20 sandscreeen 5 2.441 38.13 5193.66 36 40 4 1/2" Stratapac PMF 12/20 sandscreeen 5 2.441 38.13 5231,79 41 2 7/8" EUE pin x 4 1/2" BTC x -over 4.5 2.441 1.3 5269.92 42 2 7/8" N -80 EUE tubing pup 3.688 2.441 8.25 5271.22 111 1 43 2 7/8" N -80 EUE tubing pup 3.688 2.441 8.11 5279.47 MI 1 44 Fluted centralizer sub 2 7/8" EUE 8.38 2.441 0.76 5287.58 45 2 7/8" N -80 EUE tubing pup 3.688 2.441 1.9 5288.34 39 1 46 Fluted centralizer sub 2 7/8" EUE x Stub Acme 8.38 2.441 0.76 5290.24 47 Stub Acme spacer tube 3.2 2.4 4.6 5291 ■ 48 2- 1' molded seal units to fit 3.25" PBR 3.375 2.4 1.66 5295.6 o 49 1/2 Mule shoe 3.2 2.4 0.37 5297.26 40 0 End of Tubing 5297.63 0 0 Note: All depths are based on the fluted centralizer locating to the top of the existing Blackcat packer in 44 the hole. Top of packer depth is 5291' as per Don Jones. Packer integrity test was inconclusive due to open squeeze perfs above top packer. Squeeze perfs: 3080' -3083' 188- stainless steel bands in hole for 46 injection line. Up wght: 41K Dwn wght: 38k. Packers are 30,000# over straight pull release. PREPARED BY: Jason House OFICE: 307 - 362 -1883 FAX: 307 - 362 -7677 I PREPARED FOR: OFFICE: FAX: Don Jones 907 - 776 -7105 48 WEATHERFORD COMPLETION SYSTEMS • ' Weatherford® OFFICE: (303) 893 -0287 FAX : (303) 893 -0288 Completion Systems 410 17TH. STREET SUITE 250, DENVER, COLORADO 80202 • • Kustatan Field #1 Daily Drilling Report Summary 3/26/2012 Safety meeting. Repair annular preventer with new element and hand from Control Technologies. 3/27/12 Test annular, witnessed by L. Grimaldi with AOGCC. LD test equipment. Pull two way check. Set BPV. Commission pit system and prep for operations. Received approval from J. Regg with AOGCC to begin operations. 3/28/12 Commission pit and pumps. Prep for operations. Rig down test joint. Set up wire line unit. MU lubricator and test to 500 psi. Tool up. Crew up. Shift open sliding sleeve at 5143'. Multiple runs. Made fluid tag run, fluid apparently at surface. RD. Pump into tubing to confirm fluid level. The well is static with fluid level at surface. Test 2 7/8x 9 5/8" annulus to 1500psi. Good Test. The annulus is fluid packed, did not take any volume. RD from testing. Prep rig for pulling pipe. 3/29/12 Work 2 7/8" tubing completion string in attempt to free 9 5/8" Hydro 1 packer and pull seal assy from lower production packer PBR. Not successful. Check tubing flow /pressure. 65 psi, monitor well. RU Pollard e line, RIH with CCL, tag bottom at 5314' WLM= prong /plug depth. POH, rig down e line unit. RU Pollard slickline unit. RIH with sliding sleeve shifting tool to close sleeve at 5145'. Made several attempts before sleeve shifted close successfully. POH and R /D. Rig up to and pressure testing tubing string to 300 psi, pressure held, sleeve confirmed closed. After attempting to pull completion string free, R/U Pollard eline, conduct a PJSM before M/U 2 1/8" jet cutter. 3/30/12 Make Completion string tubing cut at 5277' (wlm) =top tubing pup joint below 2 7/8" blast joints, POH, attempted to pull string free with 112K lbs (no, go). RIH w /3' tubing punch= 12 1 A" holes at 5160' to 5163' (wlm). POH. Confirm tubing holes by breaking circulation. RIH w 1.68" radial cutting torch assy to 5158' =cut top of 1St full joint below sliding sleeve. POH, R /D. pulled on completion tubing string, observed pulling pipe free at 55,0001bs, stabilized at 35,0001bs. Monitor well for gas migration and fluid level. Begin rig up to lay down completion string while monitoring well. P0H laying down completion string, cutting bands, and spooling up methanol injection SST. Tubing displacement =15 joints= 1.0 bbl. POH to injection mandrel, remove SST from sub and lay down. R/D Pollard spooler unit and derrick sheave. Continue P011 laying down 2 7/8" completion string. • • 3/31/12 Continue POH laying down 2 7/8" completion string w radial torch cut made at 5158' (wlm), lay down end of completion string with sliding sleeve, pup jt and 5.63' piece of cut off tubing joint =25' of joint body looking up in well. R/D Pollard Spool Unit and secure. Bring sheave down from derrick. R/D tongs, remove completion equipment /tubing from cat walk, pipe racks. Lay out, strap /number 2 7/8" SLH90ST drill i e. Clean/organize ri floor. La out out /strap Fishing BHA. Set pp rig Lay / p g wear bushings, monitor well, stabilized. Begin pickup fishing tool assy drill pipe work string, each joint. g� joint. Continue RIH with Baker Fish tool Assy #1. 20' from top of fish, record up and down weights: 55K up, 51K Down. Rotating weight 53K. Rig up to Circulate Bottoms up (CBU). Mud pump #1 and #2 idle at 26 spm @350- 400psi at 45spm= 1200 psi =4 BPM. Continue CBU =3880 total strokes at 2900 stks observed 11 ppm H2S in Mud pits, checked with portable calibrated gas detector. Zero H2S but read 11 ppm CO. Observed gas readings dropping off to zero ppm after 25 min of circulating slowly. Continue CBU, clean up cuttings, small amount of sand /silt. Pick up Kelly joints and work over fish (TOF= 5155' MD) after several attempts to engage the fish with overshot. Begin jarring on fish with 22K lbs overpull while pumping at 4 bpm. Increase to 30K lbs overpull. Fish appears to be free, with initial 10K lbs overpull, circulate 2 back -to -back 26 bbl HI VIS Pill (barazan D) while working string continually. Mix and spot HI VIS PILL on outside of fish and fishing tool BHA. Shut down pumps R/D Kelly pups and circulating rigging, POH "slowly" with est. 2 K lbs over normal string weight. Monitor /record hole volume. 4/2/12 POH with Baker fishing tool assy and Fish #1: 25' of 2 7/8" tubing body, pup joint, "Y" block, gun assy (along side tubing string blast joints), pup joint 2 blast joints, observed on pup joint below blast joints jet cutter did not make complete penetration and entire fluted centralizing subs, seal assy and mule shoe retrieved, used crane to pull last 76' of "Y' block strings out of hole. Lay down on walk and make service breaks on overshot. Strap all perf gun assy and completion string assy. Prep rig floor and pipe racks to p/u mill, scraper assy caliper and strap same. Pick Up and RIH with BHA. Begin RIH and drill pipe to 5186', check up weight= 58K lbs, 51K lbs down. Total pit volume= 207 bbls plus 19.7 llbs in trip tank. • • 4/3/12 Continue in the hole, encountered tight spot at 5235' (perfs) pick up set off jars to free work string, attempt to work string through tight spot, no go. Rig Up to circulate HI VIS Pill 2' above tight spot and work pipe at tight spot. After several attempts to go past tight spot, POH 5' above spot and continue circ out HI VIS pill. Pump HI VIS pill back to surface, fill trip tank and begin POH, monitor well displacement. Continue POH. Lay down Baker Mill 9 5/8" scraper BHA. Organize racks, cat walk and rig floor. Prep to conduct weekly BOPE test. Make up test jt. Pull wear bushing. Set test plug, rig up pressure recorder, make up pump in sub onto test jt. Make up test hose, fill stack, BOPE. Conduct full weekly BOPE test Annual bag: 250 -1500 psi, test blinds, pipe rams, HCR, manual choke & kill line valves, all 12 choke manifold valves from 250 -3000 psi koomey time /performance tests. Total pit volume =185 bbls plus 5 bbl in trip tank. 4/4/12 Rig down BOPE testing equipment, clear catwalk, and rig floor. Strap /Caliper M/U Halliburton 9 5/8" retrievable bridge plug to be run on drill collars and work string. Conduct a PJSM with IDA, CIE, WOT, and Halliburton reps. Begin picking up and M/U RBP BHA. Had difficulty torqueing up 4 1/2" connection. RIH on 5 -3 1/8" spiral drill collars and workover drill pipe to 3450'. Set retrievable bridge plug at 3450' lay down 1 single joint. R/U and test RBP, 9 5/8" casing to 1500 psi hold for 20 minutes test on pressure recorder, R/D test equipment. POH with RBP setting tool, monitor and record drill pipe displacement. Lay Down BHA, set wear ring. IDA drilling crew, greased up rig and checked all fluid levels. 4/5/12 Make up 12 bailer runs leaving 19' of 20 -40 frac sand on top of RBP tagged at 3450'. Top of sand at 3431'. Perforate for squeeze with 12 shots from 3420' to 3423' 90 degree phasing. Well static after shots fired. Make several attempts to circulate down the 9 5/8" csg looking for returns from the 9 5/8" x 13 3/8" annulus. Maximum pressure applied 550 psi. Unable to establish circulation. Perforate for squeeze with 12 shots from 3080' to 3083' 90 degree phasing. Well static after shots fired. Rig down Pollard E line. Rick up 9 5/8" Halliburton Fast Drill retainer. RIH. All shots fired on perforation runs. Total pit volume= 185 bbls plus 5 bbls in trip. 4/6/12 RIH with Halliburton Fast Drill retainer to 3380'. Check circulation through retainer - good. Unable to get retainer to set at 3380'. Pull up 30' to 3350', retainer will not set. POH. Check retainer. Found setting mechanism locked up. Replace bow springs. Made repairs. RIH with Halliburton Fast drill retainer to 3380'. Conducted valve drill while tripping. Wear ring in place. • • 4/7/12 Circulate through retainer. Good Test. et Halliburton Fast drill retainer at 3380'. Establish circulation into lower squeeze perfs at 3420' -3423' and back into IA from upper squeeze perfs at 3080'- 3083'. Pump rate 2.5 bbl /min at 900psi. Circulated 11 bbls. Mix preflush, test lines and pump 11 bbls of preflush. Stop pump when no returns observed. Set aside cement pumping equipment and rig up on Rig #34 circulating system. Check OA at the surface for communication. OA at surface remains static. Obtain good circulating condition with 2.5 bbls /min at 250 -450 psi. Circulate area to be squeezed for more than one hour while getting ready to pump cement. Test lines and finish pumping 6 bbls of preflush. Pump cement. Displace. Cement in place at 14:30. Pull 300' up hole and pump wiper dart through drill pipe. Q .� Pump slug. CBU. POH. BHA Change. Pumped total 20 bbl preflush Mud Clean with 4 %KCL at 8.53ppg. Followed by 26 e bbl Class G +.1% R3 +.2 %CD32 +.4 %FL62 +.05 %ASA301 +1 GAL /100SX, FP6L+ (I' 43.9% Fresh Water. 126 SXS @15.8 ppg Final squeeze pressure 1460 psi at 1 bbl /min 4/8/12 BHA Change. Level Derrick. RIH with 8.5" bit. R/U to drill @3000'. RIH to 3070'. Saftey meeting. Record slow pump rates. Wash from 3070' to top of cement at 3355'. Did not see cement at top squeeze perfs at 3080'- 3083'. Drill cement from 3355' to Halliburton Retainer at 3380'. Drill retainer. Drill cement from 3384' to 3386'. , v/,, 4/9/12 Drilling on Cement and remains of retainer at 3386'. POH. Condition of bit is good. Run CBL on pollard e line from 3386' to 2300'. Cement bond log is acceptable. Weekly BOP test. AOGCC waived witness. Rig Service. 4/10/12 Fly in 7 ea 4 3 /4" drill collars, jars, and handling tools on skyvan aircraft. Strap & MU BHA. RIH with 8.5" bit. es 4/11/12 RIH with 8.5" BIT # RR1. Tag CMT at 3386'. Tool change. Rig to drill. Drill CMT from 3386' to 3428'. Cleared up after 3428'. Wash from 3428' to 3440'. Removed 9' of sand from above RBP. CIRC bottoms up. Caught sand sample. RBP has about 10' of sand left on top of it. POH. LD BHA & bit. Pick up Halliburton's overshot and RIH to retrieve bridge plug. 4/12/12 Tagged sand, circulate down to RBP, remove sand. Release RBP and CBU observed small amounts of gas on Bottoms up. Check well, static, POH. Lay down Halliburton 9 5/8" RBP and retrieving tool assy. Strap /caliper bullnose mill 9 5/8" csg, scraper assy. Pick up assy. Had difficulty making up BHA connections. RIH with csg scraper assy and 2 7/8" drill pipe. Conducted pit drill. • • 4/13/12 RIH t/5265', rig down bails and elevators. P/U Kelly joint, wash down to 5291' slightly tag (top of 9 5/8" Arrowpak permanent packer. Slowly work pipe while circulating hole clean. During trip in hole work on cleaning pits, separating high vis sweeps from production water. Circulate well clean, while working workover string. Begin cleaning pits: pump free standing workover fluid (produced water) from pits to vac truck, work Pe i P periodically. eriodicall . Filled 2- 25 bbl Tanks a lot tanks, and 3 -15 bbl tanks a lot tanks with sludge & polymer sweep material total of 260 bbl of production water "workover fluid" transferred from mud pits to wmac. 4/14/12 Finished cleaning mud pits. Prep to take on clean produced water into pits. Label cutting boxes with Hi VIS sweep material /sand, spot pipe racks in place, off load ast of vac truck fluid. Begin receiving clean produced water into mud pits /mixing KCL material to achieved 2% KCL workover fluid at 8.6 ppg. Begin displacing well taking return to trip tank, trip tank pump transferring to 114 bbl open tp R -4 tank, vac trucking from tank to WMAC observed KCL fluid back to surface, shut down pumps and monitor well. Begin receiving clean produced water and mix up 240 bbl of KCL workover fluid at 2% this will allow us enough volume for pipe displacement to POH and manageable volume in pits. Well taking 2 bbl /day average. Total of 450 bbl of produced water transferred into mud pits before displacing old workover fluid from well. Total of 380 bbl est of old workover fluid displaced from well into vac truck. Total of 250 bbl est of produced water transferred into Mud pits to allow us to POH and have excess in pits. 4/15/12 Mix 250 bbl of KCL workover fluid. Prep rig floor and begin POH with 9 5/8" csg scrapper assy. Lay down bullnose mill 9 5/8" csg scraper. Organize rig floor, nipple down flow nipple, nipple up pollard shooting flange. PJSM with Pollard perf crew, IDA, and CIE reps. R/U pollard lubricator and equipment, record hole volume. RIH with GR tool, log from 5277' to 2800' for base line before Perf runs (will not use GR when reperfing 5200' zone) and show 9 5/8" csg. Collars for completion packer sets. POH, lay down tools. RIH with 1St gun run and perforate from 5260' to 5246' =14' (monitor well pressures and hole volumes on each run). RIH w 2nd gun run and perforate from 5246' to 5225' =21. Work on wireline, observed broken stand on wireline that had birds nested into lubricator. Lay down and cut wireline, restring and rehead tools. Total pit volume =177 bbls. Conducted well control drill while POH. PWS using 3 3/8" guns, 6 SPF 60* phase, est .44" holes in csg, est penetration= 36 " -40 ". • • • 4/16/12 Make repairs to wireline rehead line and tools. RIH with 3rd gun run and perforate from 5225' to 5204' =21'. RIH with 4th gun run and perforate from 3283' to 3265' =18', observed at surface that bottom 4' did not detonate. Making run #5 while building a 4' gun to reshoot. As of 0600 hrs no hole volume, gas detection or well head pressure changes observed. 5th gun run perforations from 3149' to 3135' =14'. RIH with 4' gun reshoot and perforated from 3283' to 3279' =4'. Zero psi on well, hole volume dropping slowly added 9 bbls KCL workover fluid. RIH w 6th gun run and perforate form 3135' to 3125' =10', POH, and R/D e line to side, lay down perf crew while testing BOPE. Hole took 14 bbl. Pull wear ring, conduct BOPE tst, 250 psi and 3000 psi on BOPE stack, choke manifold, kill and choke line valveing. 250 -1500 psi on annular bag. Test all rig monitoring systems including gas /H2S alarms, etc. Install wear ring and nipple up shooting flange /lubricator. Added 20 bbl to hole between 1530 and 2400 hrs. AOGCC waived witnessing weekly BOPE test. Added 65 bbls of Produced water to mud pits and mix KCL. Total pit volume= 156 bbl at 2400 hrs. Between perfs pull up 20' after shots made and observe well pressures for 20 minutes, when out of hole check volumes and record. Total KCL workover fluid added to well from 2400 to 2400hr =59 bbl. PWS using 3 3/8" guns, 6 SPF 60* phase, est .44" holes in csg, est penetration= 36 " -40 ". 4/17/12 RIH PWS, RIH with gun run #7 and perforate from 3125' to 3115' =10' observe well, no pressure on well, POH, RIH with final gun run #8, tag bottom at 5291', top of 9 5/8" Arrowpak pkr. Pull up hole perforate from 3115' to 3102' =13' observed well for pressure. POH. R/D PWS E line equip and nippled down shooting flange and nipple up flow nipple, flow line and trip tank hose. M/U stinger 9 5/8" csg scrapper bha. RIH with 2 7/8" work string, monitoring /recording proper pipe displacement while RIH to 5286' =5' above perm packer. CBU. Begin washing down inside 9 5/8" arrow pak packer PBR assy with 15' stinger. Had difficulty getting muleshoe on stinger inside of top packer, applied 500 lbs +/- and rotate slowly, observed stinger had slipped into top of packer. Note: Tagged top of packer at 5291' and found fill at 5292'. Up weight 61K down weight 59K. Total pit volume 116 bbls at 2400 hrs. Total excess KCL workover fluid added to well from 2400 to 2400 hrs = 46 bbl. Cumulative total= 105 bbl. • • 4/18/12 Continue washing inside of arrow pak packer PBR assy, taking weight, reciprocating work string, worked stinger to 5303' =bottom of PBR. Pump barazan D weep (HI VIS) observed returns of scale, cement, and some sand. Slug pipe string with 30 gallons of bleach to dissolve Hi VIS sweep residue, pump complete circulation back to surface. Prep to POH, L/D 2 7/8" drill place on trailers with BHA, take time to break out baker tools from Weatherford's. Pull wear ring, organize rig floor, clear floor of XO, etc palletize. Load pipe racks with 2 7/8" completion tubing. Strap tubing, redress seal assy, load sand screens on catwalk, PJSM with IDA weatherford, H &H and CIE reps, go over figures for completion string spacing out of components At report time: completion string up weight 25K, down weight 24K. Total pit volume =95 bbl at 2400 hrs. Total excess KCL workover fluid added to well from 2400 to 2400 hrs =23 bbl cumulative total= 128 bbl. 4/19/12 Run 66 jts between bottom of 9 5/8" Hydrow 1 packer and bottom sliding sleeve. Make up sliding sleeve, pup joints and top 9 5/8" weatherford Hydrow 1 packer, RIH, making up injection mandrel and Y4 SST. Continue RIH securing SST with band material, 2 bands per joint. Land seal assy into arrow pak PBR assy, space out w pup joints. R/U and CBU with seal assy and tubing hanger with in 10' of being set on bottom. Total of 188 bands in hole to secure SST injection line. Completion string compression on arrow pak packer with seal assy =15K lbs. Completion string up weight= 31K down weight =38K. Total pit volume =75 bbl at 2400 hrs. Excess KCL workover fluid loss to well from 2400 to 2400 hrs = 15bbl. Cumulative total fluid loss =143 bbl. • 4/20/12 CBU, observed little thread dope and fines over shakers. Pump 2 -drums of PKR fluid. Baker corrosion inhibitor 606W chased with 5 bbl of diesel do 2 7/8" x 9 5/8" annulus. Pull tubing hanger to floor, make up SST through hanger, test connections for leaks. Land seal ass and tbg hanger with 15K lbs compression. Run in tbg Y g g P hanger lockdowns and burst SST injection line disk at 5000 psi. Rig up and RIH with pollard slickline and set plug /prong in "X" nipple to hydraulically set both 9 5/8" Hydrow 1 packers. RU to pump down completion string to set both weatherford packers, slowly pressure up to 1500 psi in 500 psi increments at 2000 psi observed positive shifting /setting of both packers at surface. Continue pressuring up to 2500 psi and hold for 20 minutes before bleeding off. R/U to test 2 7/8" x 9 5/8" annulus, set up chart pressure recorder, pressure up to 800 psi slowly with mud pump. Shut in mud pump and begin pumping with test pump to achieve 1000 psi, not successful. Made many attempts to pressure up to 1000 psi, changed /simplified the plumbing on annulus to test pump (no test). Rig Up Pollards slickline, RIH to confirm both sliding sleeves are closed, R /D. Continue with attempts to pressure up annulus, no eo - v ' success. Fill suction pit with produced water, pressure up on annulus monitoring 3 0 and recording pressure observed on completion string, 2 7/8" x 9 5/8" annulus and 9 5/8 "x 13 3/8" annulus. With 1000 psi on inner annulus observed zero pressure on outer 9 5/8" x 13 3/8" annulus and zero pressure on tubing. Shut in all isolation valves. Observed pressure drop from 1000 psi to 500 psi in 1 minute, then slowly bled off from 500 to 220 psi in 10 minus, achieved static pressure of 180 to 150 psi in 20 mins. Conducted this pressure test 3 times with similar results. Confer with AOGCC, received word form Guy Swartz to proceed with final steps to complete well and rig down. He requested we monitor. both annulus pressures daily R/U Pollards ILA slickline, RIH and retrieve prong and plug at 5185', rig down. Note: pumped est 1 . 0 ,85` bbl of fluid to pressure up at 2 7/8 "x 9 5/8" annulus from zero to 1000 psi each 3 a4P - attempted pressure test. 4/21/12 Finish R/D Pollard Wireline after retrieving Prong /plug. Vetco gray installed BPV in top of tubing hanger. Begin nippling down BOPE. IDA crew set production tree, witness by vetco gray rep, nipple up and test void /hanger and upper neck to 5000psi for 15 min. Good test. Fill production tree with diesel and pressure test tree to 5000 psi for 15 min. Good test. Released rig at noon. • • Page 1 of 1 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Saturday, April 21, 2012 12:07 PM rm. 2_0 53 To: David Hall Cc: WMRU Drilling Foreman; David Hall; Courtney Rust; Conrad Perry Subject: Re: KF1 annulus David, Approved to move off as per our phone call. Chart tubing test if have not done so already . Guy DEL MAY 2 3 L2 Sent from my iPhone On Apr 21, 2012, at 8:02 AM, "David Hall" <David.Hall@cookinlet.net> wrote: Guy, Thanks for calling me back so late in the evening, as we discussed the inability to hold 1,000 psi on KF1 annulus as shown in the WO procedure. After conducting a series of test, it is believed that the packers, sliding sleeves and tubing are properly set and mechanically sound. The upper cement squeeze shot is at 3080 -3083 and the top packer is set slightly below the top cement squeeze shot at 3096. Although the cement bond log showed sufficient coverage over this interval, we believe the reason we cannot hold 1000 psi on the annulus is due to the upper cement squeeze shot at 3080 -3083 is allowing leakage. As we discussed and with your concurrence, we plan to rig -down Rig -34 followed by testing and putting the well online. Regards, David David Hall, CEO Cook Inlet Energy 601 W. 5th Avenue, Suite 301 Anchorage, Alaska 99501 Office ph: 907 -433 -3804 Mobil ph: 907 - 317 -8239 <PastedGraphic- 1.tifff 4/23/2012 • • Regg, James B (DOA) P ZOo /5 From: Regg, James B (DOA) Sent: Tuesday, March 27, 2012 5:08 PM ; 6/1 31271, L To: WMRU Drilling Foreman; 'David Hall' Cc: DOA AOGCC Prudhoe Bay; Schwartz, Guy L (DOA) Subject: RE: Rig #34 KF -1 well, CIE BOP Notification We have received the information requested. You may proceed with workover ops on Kustatan Field Well #1 (PTD 2001530). Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 -793 -1236 From: WMRU Drilling Foreman [mailto: drilling .foreman(acookinlet.net] Sent: Tuesday, March 27, 2012 4 :42 PM To: Regg, James B (DOA) Cc: DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Subject: FW: Rig #34 KF -1 well, CIE BOP Notification a � � €?h'' Jim, We have completed repairs to our annular preventer and tested the new element to 250 psi low & 1500 psi high as witnessed by Mr. Lou Grimaldi. With this initial test being complete and no other rig issues noted may we proceed with the workover on KF #1 well? Regards, Mike Murray From: WMRU Drilling Foreman [ mailto: drilling.foreman@cookinlet.net] Sent: Wednesday, March 21, 2012 11:53 AM To: 'Regg, James B (DOA)' Cc: 'DOA AOGCC Prudhoe Bay' Subject: Rig #34 KF -1 well, CIE BOP Notification Jim, At this time we would like to submit our 48 hr notice for a Rig #34 BOPE test and a follow up walk through of the Rig itself. Let us know from which direction an Inspector would be coming from and we will make Flight arraignments for them from Anchorage or North Kenai. Best Regards, Don Jones Cook Inlet Energy, LLC Drilling Logistic Coordinators Don Jones and Mike Murray Office # 907 - 776 -7141 Cell # 907 - 529 -9786 Fax # 907 - 776 -7148 drilling.foreman @cookinlet.net 1 • • Page 1 of 1 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, March 20, 2012 8:29 AM To: 'Courtney Rust' Cc: David Halt' Subject: RE: Beluga perf unload (PTD 200 -153) Courtney, The Beluga perf interval may be unloaded to prevent formation damage as per your request below but cannot be flow tested until a spacing exemption has been approved. This modification to the Sundry 312- 013 is approved. Regards, Guy Schwartz t,M ) MAR 0 Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Courtney Rust [ mailto :courtney.rust @cookinlet.net] Sent: Monday, March 19, 2012 5:09 PM To: Schwartz, Guy L (DOA) Subject: Perf dean off. Guy, Cook Inlet Energy requests to clean the water off the Beluga perforations zone 3102' -3150' and 3260'- 3285' while waiting on the exemption as stipulated in the Kustatan field #1 Sundry 312 -013. We are concerned that leaving the drilling fluid across the perforations listed above may damage the formations if left for an extended period of time. In order to ensure compliance with the sundry Cook Inlet Energy proposes to set a plug isolating the Tyonek formation and open the sliding sleeve for the Beluga zone, and clean up the Beluga formation then close the sliding sleeve for the Beluga until necessary permits are in place. Cook Inlet Energy expects the Beluga formation to be open for no more than one hour for this cleanup. Sincerely, Courtney Rust - - -- - - - -- - - -- - - -- x 3/20/2012 • • Cook Inlet Energy March 14, 2012, Mr. Dan Seamount, Chair Alaska Oil and Gas Conservation Commission 333 West 7 Ave., Suite 100 Anchorage, Alaska 99501 FT Re: Clean Off Request S S Dear Mr. Seamount, Cook Inlet Energy requests to clean the water off the Beluga perforations zone 3102' -3150' and 3260' -3285' while waiting on the exemption as stipulated in the Kustatan Field #1 Sundry 312- 013. We are concerned that leaving the drilling fluid across the perforations listed above may damage the formations if left for an extended period of time. In order to ensure compliance with the sundry Cook Inlet Energy proposes to set a plug isolating the Tyonek formation and open the sliding sleeve for the Beluga zone, and clean up the Beluga formation then close the sliding sleeve for the Beluga until necessary permits are in place. Cook Inlet Energy expects the Beluga formation to be open for no more than one hour for this cleanup. If you have any questions, please contact me at (907)- 433 -3804. Sincerely, David Hall CEO — Cook Inlet Energy 601 W. 5 Avenue, Suite 310, Anchorage, AK 99501 (907) 334 -6745 * (907) 334 -6735 fax • r - r72 L SEAN PARNELL, GOVERNOR UU L ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COM IISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 David Hall CEO Cook Inlet Energy ` e. _- /�� 601 West 5th Avenue, Suite 310 Anchorage, AK 99501 Re: Kustatan Field, Kustatan Gas Pool, Kustatan Field #1 Sundry Number: 312 -013 Dear Mr. Hall: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. Before startup of workover activities (wellbore entry), a rig inspection and BOPE test must be completed and any identified deficiencies resolved to AOGCC's satisfaction. This Application for Sundry Approval is approved subject to full compliance with 20 AAC 25.055 and Conservation Order No. 566 (CO 566). Approval to test or produce any interval other than the Kustatan Field #1 Gas Pool as defined in CO 566 is contingent upon issuance of a conservation order approving a spacing exception. Cook Inlet Energy assumes the liability of any protest to the spacing exception that may occur. Additionally, in accordance with 20 AAC 24.215(b) production from multiple pools, whether they be formally defined or not, cannot be commingled in the wellbore of the Kustatan Field No. 1 well (PTD 200 -153) without an order from the AOGCC authorizing such commingling. In order to issue such an order the AOGCC must, after receiving an application from the operator and providing notice of opportunity for public comment and hearing, determine that waste will not occur and that production can be properly allocated to the pools. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. e . : oner DATED this / day of March, 2012. Encl. • • Fisher, Samantha J (DOA) From: Foerster, Catherine P (DOA) Sent: Thursday, March 08, 2012 3:46 PM To: Fisher, Samantha J (DOA) Subject: Re: Kustatan Field #1 Approve Sent from my iPhone On Mar 8, 2012, at 7:31 PM, "Fisher, Samantha J (DOA)" <samantha.fisher©alaska.gov> wrote: > Please approve. I made the changes to the letter that were requested. > Thanks, > Samantha Fisher, Executive Secretary II > Alaska Oil and Gas Conservation Commission > (907)793 -1223 > <S45C- 212030816230.pdf> 1 • w" � D STATE OF ALASKA JAN 1 0 nit ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS # . 'a?. s; ` i,,;61, ;.'x is. ° °C ' 20 AAC 25.280 r'kft s,,, 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool 0 • Repair Well Ei . Change Approved Program El • Suspend ❑ Plug Perforations ❑ Perforate IS • Pull Tubing El ' Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Install sand control screen El , 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Cook Inlet Energy Development El , Exploratory ❑ 200 -153 ' 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 601 W 5th Avenue, Suite 310, Anchorage, AK 99501 50- 133 - 20496 -00 - 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No 0 Kustatan Field #1 9. Property Designation (Lease Number): 1g 10. Field / Pool(s): ADL 3 fC ).- -C s '' • /'' ' /7"..- Kustatan Field #1 Gas Pool - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): 'Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12,300 ' 12,300 6192' 6192' Bridge Plug @ 6192' None Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 20" 120' 120' N/A N/A Surface 1,820' 13 3/8" 1,820' 1,820' 3,450 psi 1,950 psi Intermediate 6,500' 9 5/8" 6,500' 6,500' 6,870 psi 4,750 psi Production Liner 5,988' 7 5/8" 12,300' 12,300' 6,890 psi 4,790 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 3102%3150'; 3260'3285' 3102'4150'; 3260'4285' 2 7/8 ", 6.5# L-80 5344 5204'5260'; 5353'5365' 5204'5260'; 5353'5365' 5370'-5380' 5370'-5380' Packers and SSSV Type: Packer: 9 -5/8" packer #1 w /sealbore Packers and SSSV MD (ft) and TVD (ft): Packer #1 @ 5291'MD/TVD 9 -5/8" packer #2 Packer #2 @ 5097'MD /TVD 9 -5/8" weatherford packer #3 Packer #3 @ 3020'MD/TVD 12. Attachments: Description Summary of Proposal El 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development 0 Service ❑ 1 14. Estimated Date for 1/11/2012 15. Well Status after proposed work: Commencing Operations: Oil ❑ Gas El WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact David Hall 433-3804 Printed Name David Hall Title CEO Signature Phone 907-433-3804 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: (3 12 - 0■ Plug Integrity ❑ BOP Test [ Mechanical Integrity Test ❑ Location Clearance ❑ Other: "4 3 QO 0 e se, e v p 1 'e_ s �.� / i+ it Spitc..t�v�, exG � 1. Jest- / e/ c. p�T / I 4 CJ Subsequent Form Required: `U O y I APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: a. 7.. /2 ©9 �� p 428 v Q+ �Z ORIGINA. iG �!`� _ 1 ; ��RDd11 Re O2012 II / G � g Submit in Duplicate .� F • _$ Cook Inlet Energy January 9, 2012 Mr. Dan Seamount, Chair JJ Alaska Oil and Gas Conservation Commission lr ? (' 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 oat., RE: KF #1 Additional Perforations and Screen Installation Dear Commissioner Seamount, ), / r sz.;)rz(s- Cook Inlet Energy would like approval to change the approved Sundry 311 -267 to include adding perforations at 3,102'- 3150'MD and 3260'- 3285'MD on the KF #1 in the Kustatan Field of Cook Inlet in order to test and produce from Beluga sands. The work performed will be also include the re- perforation and screen installation from approved Sundry 311 -267. The general work procedure is attached. The estimated date for commencement of this work is January 13, 2012 Attached please find a completed Form 10 -403 for the work, an outline of the procedure, a current wellbore schematic, a proposed wellbore schematic, Sundry 311 -267. If you have any questions, please contact me at (907) 334 -6745. Sincerely, , Cook In et Energy David Hall, CEO Attachments: 10 -403 Application for Sundry Approvals Outline Procedure Current Wellbore Schematic Proposed Wellbore Schematic Approved Sundry 311 -267 601 West 5th Avenue, Suite 310, Anchorage, Alaska 99501 Phone (907) 334 -6745 • • ADDITIONAL TEXT FOR APPROVAL LETTER This sundry is approved subject to full compliance with 20 AAC 25.055. Approval to test or produce is contingent upon issuance of a conservation order approving a spacing exception. Cook Inlet Energy assumes the liability of any protest to the spacing exception that may occur. This sundry is approved subject to full compliance with 20 AAC 25.215. _ _ ! °z/ C 1 .0' • Cook Inlet Energy, LLC. — Kustatan Field No. 1 (KF1) Add Perfs and Install Sand Screen Across Upper Tyonek A Sand; Perforate & test Beluga Sands 3102' — 3150' and 3260' — 3285' Summary Procedure Current Status, Background S©/ c2-1 I.ti /2- This well is currently shut -in. It is completed as a single selective with packers at 5168' and 5.2.a.r.. The well has multiple perforated gas intervals in the Tyonek A and Tyonek B zones: Upper zone of 5204' — 5260', and lower zones at 5353' — 5365', 5370' — 5380', 5844' — 5850'. The upper zone was completed behind tubing of a selective single. On a short and inconclusive test on October 25, 2005, the zone produced 35 bbls of water with fine sand on a 6 hour well test. Following the test, the zone was isolated with a sliding sleeve, and the lower zone was opened for flow. The lower zone tested at commercial rates and produced for several years with cumulative production of approximately .3 BCF. Recently, the well was re- entered and the sliding sleeve opened to allow flow from the upper zone. On a re -test of this zone, it produced considerable amount of fine sand, with a strong blow of gas. Obiective The upper 5204' -5260' zone is believed to be a viable target, but it needs to be recompleted to prevent the flow of sand. The Weatherford Stratapac tubing deployed sand screen has been identified as the best and most cost effective option for accessing this zone with sand control. The plan is to pull the upper completion, re- perforate the 5204' -5260' zone, and install sand screens across the zone so that � adequate drawdown can be applied to the reservoir, without flowing sand and plugging the tubing. The completion will look similar to a selective single completion, but without the ability to isolate the upper zone. A nipple profile in the lower tailpipe will allow the lower zone to be isolated in the future if necessary. In_addition to the above objective of perforating 5204 -5260 and installing Stratapac over same; plan �/ calls to perforate & test Beluga zones 3102'- 3150', 3260'- 3285. Due to no cement over interval, a � cement squeeze is planed on same. l� C 004 Equipment Mobilization, Checklist of Equipment 1. Prepare location to accept rig and equipment 2. Prepare Rig No. 34 to conduct workover operations 3. Notify contractors and prepare for mobilization of the following equipment: a. Pollard slickline unit b. E -line unit for perforating the tubing, and re- perforating the Upper Tyonek zone c. Vacuum Truck with 8.5 ppg produced water d. Weatherford completion equipment including plug, screens, packer, etc. per completion procedure e. Have BJ cement equipment on location f. Mud equipment, rain for rent tanks (210 bbl) on location •r. • • Pre -Rig Operations 1. Bleed down pressure from the annulus. On January 9 the annulus was reported to have 0 pressure; the tubing showed 85 psi. 2. Remove the flow lines from the tree and the wellhead. 3. MIRU Rig 34 with minimal crews. Spot equipment. Celt Le 4. Rig up Pollard Slick Line. Set an equalizing plug in the WXN nipple at 5318' in the tubin tail below " the lower packer, to isolate the lower zone. Rig down slickline -- �ir s /C .f '` - 5. Fill well with 8.5 ppg produced water to kill it. ( ? / - 1 - 4 ,)_ .��. SS 6. Test annulus to 1500 psi. ✓ 0 << cc°s ���, 7. RIH with sliding sleeve shifting tool and shift the sliding sleeve at 5150' to the open position to expose the upper zone to the tubing. POOH with slickline. RD slickline unit. 8. Monitor wellhead pressure; make sure the well is dead and not drinking fluid too fast. 9. Install 2 -1/2" "H" BPV in the tubing hanger with Vetco Gray. 10. With rig fully installed and tested, call for an AOGCC rig inspection and have an inspector on location to inspect the rig. Rig Operations HS IN" �" + L � . / ? 3 6'3 ��, 6 °. �' l 11. Notify AOGCC of upcoming BOPE test. — (7 WI / s � 12. Check for pressure under BPV. Fill with 8.5 brine as needed. 13. Nipple down the production tree and NU the BOP stack as follows, bottom to top: • 11" 5 ksi X 11" 3 ksi DSA bolted to 11" 5ksi Tubinghead Flange • 11" 3 ksi mud cross with choke and kill line • 11" 3 ksi double BOP stack with 2 -7/8" pipe rams, blind -shear rams, and annular 14. Check for pressure under BPV. Pull the BPV and set a two -way check valve in the tubing hanger profile. Pre -Test the BOPE to 3000 psi per AOGCC regulations and make sure all leaks are identified and fixed. L y i6ao 14s;, Top DiewvE 15. Call for AOGCC inspection. Conduct a full BOPE test of the stack and BOP equipment per AOGCC regulations. Pull two -way check and prepare for workover. 16. Rig up Pollard E -line unit and RIH with a tubing punch and punch a hole just above the upper packer / at approximately 5050' (packer set at 5097' MD). 17. Establish circulation with 8.5 ppg produced water and circulate all gas out of the well (formation pressures at 5353' was 23)Apsi equal to 8 3 ppg) Be prepared for OBM returns. T K (A c-t "` 18. Confirm the well is dead. Latch onto 2 -7/8" L -80 tubing hanger with a landing joint. Note: The tubing hanger has a 3.160" MCA box looking up, with 2 -7/8" 8rd threads on bottom. ., L - " 19. The upper packer, a Weatherford Hydrow 1, releases with a straight pull up, with approximately = lySK 30,000# of pull to release the packer, do not exceed 80% of tubing rating or 80 % of derrick (100,000 1/). The lower seal assembly is not latched into the packer. It is likely that the seal assembly is sanded into the lower packer and will require some effort to pull free. Note: See Attachments 1 and 2 for schematic of current completion. Note: In the event the seal assembly is completely sanded in and cannot be pulled free, RIH with chemical cutter and cut the tubing just below the upper packer. The upper packer can be pulled free and an added step with fishing tools and jars will be required to pull the middle completion and seal • assembly free from the lower packer. Have overshot and fishing jars on location in the event that the seal assembly is sanded in and must be jarred free with a workstring run. 20. With hanger out of tubing head, and with the annular and pipe rams in a position to close around the tubing if need be, circulate the hole clean and monitor fluid losses and background gas. If well is flowing while gas is expanding, close annular and circulate through the choke. Report gas and fluid losses and circulate until the well is stable and dead. If losses are relatively small, proceed with POOH, filling the hole periodically with additional produced water. If the fluid Toss rate is too high to keep up with for the duration of the workover, mix a 40 -bbl HEC pill, and circulate it down the tubing to the end of seal assembly while taking whatever returns up the annulus. When the HEC pill reaches the perfs, the fluid loss rate should decrease to an acceptable rate. 21. Disconnect 1/4" methanol injection line and prepare to spool the line for re -use. Plan to re -use clamps if in acceptable condition. POOH with 2 -7/8" tubing, Hydrow I packer, Y- block, blast joints, spent TC guns, centralizer, and seal assembly. Monitor well for fluid losses while pulling out. Break every joint and laydown the tubing on the pipe racks. Clean and inspect the threads to make certain the tubing can be re -run back in the hole. Laydown the packer, spent guns, and assorted jewelry. Note: upper zone had significant sand production, be aware of possible trapped pressure. 22. Have Vetco Gray inspect the tree and hanger, and redress the hanger if necessary. Have Weatherford inspect the Hydrow I packer and redress it if it appears the packer can be re -used. If not, run a new packer and plan to redress old one at a later date. Inspect the injection mandrel. Change out the valve and rerun the mandrel if it looks to be acceptable. Have a new mandrel on location in case the old one is not re- useable. 23. Set wear bushing. 24. MU a BHA as follows: • 8 -1/2 rockbit /44, t. I''` • 9 -5/8" casing scraper • 4 -3/4" DCs • Drilling jars 25. RIH on 2 -7/8" Weatherford workstring with SL H90 HT connections. Run scraper through the upper perfs and to just above the lower packer. Gently tag the lower packer and circulate any sand or fill that is on top of the bottom packer. Circulate the well with clean 8.5 ppg produced water. Use Flowzan sweeps as necessary if significant sand fill is tagged. Reverse circulate as necessary. 26. Monitor well for any changes in flow or losses. If losses persist, spot an HEC pill across the open (upper) zone. 27. POOH. LD workstring. Pull wearbushing. IV 28. Rig up eLine and set Halliburton 9 5/8" retrievable bridge plug at 3,450'. Test casing to 1500 psi to �✓ ensure plug is set. ` (2,1, 9, . l - 29. Dump bail 20' of sand on top of bridge plug. 3I ' 30. Perforate casing at 3,420' for circulation squeeze. 4 shots 90 degree phasing. W 31. Attempt to establish circulation up annulus. If circulation is established: 1L Z ,_" 17g a) Pick up work string and set cement retainer at 3380'. Establish circulation with 8.5 ppg brine. l QI J b) Mix and pump spacer and approximately 65 bbls cement (1000' of annulus with 15% ll excess)Cement Blend and spacer TBD. `I Z `' o ` I & c) Displace cement through retainer leaving one bbl cement in work string. Record final circulation pressures. d) Unsting from cement retainer, pick up 20' and reverse clean. POH. e) MU a BHA as follows: • • • i) 8 -1/2" rockbit ii) 9 -5/8" casing scraper iii) 4 -3/4" DCs iv) Drilling jars f) Clean out cement and retainer then wash to top of retrievable bridge plug. g) Proceed to step 32 -- ? 'mot /� 5 ? If circulation is not established: ( ` a) Perforate casing at 3,090' for circulation squeeze, 4 shots at 90 degree phasing. b) Pick up work string and set cement retainer at 3380'. Establish circulation with 8.5 ppg brine. c) Mix and pump spacer and approximately 20 bbls cement (20% excess)Cement Blend and spacer TBD. d) Displace cement through retainer leaving one bbl cement in work string. Record final circulation pressures. e) Unsting from cement retainer, pick up 20' and circulate clean. POH. f) MU a BHA as follows: v) 8 -1/2" rockbit vi) 9 -5/8" casing scraper -� OA (-c o I' 0 vii) 4 -3/4" DCs viii) Drilling jars g) Clean out cement and retainer then washing to top of retrievable bridge plug. ) Proceed to step 32 32. Recover retrievable bridge plug. 33. Conduct CBL. �--! 4'>'s,,s �oc �.ms. Fe- n /° `^ 7 34. RU Pollard E -line unit for re- perforating. MU 2 runs totaling 56' of casing guns and re- perforate the interval from 5204' to 5260' based on a CCL tie -in to the GR of Platform Express (GR /AIL /Den /Neu) logging run of 3- Nov -2000. Before detonating the first gun run, tag the bottom packer to get ann E- line depth of the packer. Before detonating the last gun run, lower the guns to tag the bottom Q v { packer. Note if fill was tagged. Finish perforating zone, POOH and lay down spent guns. Note: The (-6 zone at 5204' — 5260' MD is known to produce fine sand, so the objective is to perforate slightly i\` overbalance to prevent sand from sticking the guns. If it appears that sand flowed into the wellbore, MU slickline and RIH and tag and /or bail any fill and /or perf debris on top of the plug in the tubing tail and confirm that the PBR can accept seals. If fill is noted up to and including the seal bore receptacle and bailing is expected to take too long, PU o ? the workstring with the casing scraper and a short ( +/- 10') stinger of 1 -1/4" tubing with a mule ° shoe cut on bottom and RIH. Gently wash the stinger into the tubing tail to circulate out any fill so seal assembly can seat in the receptacle. POOH. 35. MU casing guns and perforate the interval from 3102' to 3150' and from 3260'to 3285' based on a CCL /gamma ray tie -in to the GR of Platform Express (GR /AIL /Den /Neu) logging run of 3- Nov -2000. Before detonating the first gun run, tag the bottom packer to get an E -line depth of the packer. Z Befo detonating the last gun run, lower the guns to tag the bottom packer. Note if fill was tagged. Finish perforating zone, POOH and lay down spent guns. 36. MU BHA as follows: i) 8 -1/2" rockbit ii) 9 -5/8" casing scraper iii) 4 -3/4" DCs iv) Drilling jars 37. Make clean out run to 5150'. Circulate bottoms up if possible. • • 38. MU and RIH with new seal assembly, sand screens, and 2 9 5/8" Weatherford straddle packers as follows, bottom to top: 0 ■ 2 each, 1 ft. seal units with bonded seals to fit inside 3.250" PBR of Arrow Pak packer • Seal Assembly Spacer tube, Size 3.25" with Stub Acme Pin X Pin • Fluted Seal Assy and Centralizer Sub with Stub Acme Box down and 2 -7/8" EUE 8rd Box up • 2 ft. pup - 2 -7/8" EUE 8rd Pin X Pin, N -80 • Fluted Centralizer Sub with 2 -7/8" EUE 8rd Box X Box • 2 each, 10 ft. pups - 2 -7/8" EUE 8rd Pin X 2 -7/8" 8rd Box, N -80 • "'1 ft. Crossover pup - 2 -7/8" EUE 8rd Pin X 4 -1/2" 11.6# BTC Box • Sand Screen - 2 joints (Range III, "'39' per joint) of 4 -1/2" Stratapac PMF 12/20 screen • - 1 ft. crossover P - 4 -1/2" 11.641 BTC pin X 2 -7/8" EUE 8rd Box )( • Weatherford WX landing nipple with 2 each, +/- 4 ft. 2 -7/8" EUE 8rd pups installed on each end r� • 2 joints of 2 -7/8" EUE 8rd N -80 tubing (or 1 joint and a 10' pup to space upper packer properly) • Crossover sub with 2 -7/8" EUE 8rd Pin X 3 -1/2" EUE 8rd Box . Weatherford Hydrow I Hydraulic Set Retrievable Packer. Packer to set at +/- 5130' (but not in a casing connection). • Crossover sub with 3 -1/2" EUE 8rd Pin X 2 -7/8" EUE 8rd Box • One each 10 ft. handling pup on top of packer - 2 -7/8" EUE 8rd Pin X 2 -7/8" 8rd Box, N -80 • 2 -7/8" EUE 8rd N -80 tubing to space out top packer at 3,020' 5 5 •„Weatherford sliding sleeve with 2 each, 4 ft. 2 -7/8" EUE 8rd pups installed on each end NOTE: Place one joint below packer at 3020'. Check if Weatherford has another sliding sleeve for 2956'. p01-• eatherford Hydrow I Hydraulic Set Retrievable Packer. Packer to set at +/- 3020' (but not in a 11 7asing connection). • Crossover sub with 3 -1/2" EUE 8rd Pin X 2 -7/8" EUE 8rd Box • One each 10 ft. handling pup on top of packer - 2-7/8" EUE 8rd Pin X 2-7/8" 8rd Box, N -80 • Weatherford sliding sleeve with 2 each, 4 ft. 2 -7/8" EUE 8rd pups installed on each end - ` a `� r " ' 1 • Two (2) Joints of 2 -7/8" EUE 8rd N -80 tubing • New Mandrel @ 2896', Nova Chemical Injection Mandrel • +/ -95 joints of 2 -7/8" EUE 8rd N -80 tubing with 3/8" stainless steel tubing from Injection mandrel at approximately 2896 ". <-16 Note: The tubing and pups below the packer should be spaced so that the packer is set in the middle of a full joint of 9 -5/8" casing. Collars will have been located with the CCL log of the perforating run from above. If need be, install a 10' pup in addition to, or in replacement of, one of the 2 joints of 2 -7/8" tubing below the packer. 39. Sting into the seal bore assembly of the bottom packer. Observe string weight Toss and note lengths required of pup joints. Pull up to the rig floor, laydown a joint of tubing and space out with pups as necessary. MU tubing hanger with methanol injection line penetration. Connect the injection line and pressure test connections and line. (...) 40. Stab seal assembly into the lower packer and set the upper packer as follows: • With landing joint made up to tubing hanger, lower seal assembly to within 10 feet of Seal Bore packer. Circulate packer fluid with corrosion inhibitor and 5 bbls ( of diesel for freeze protect down backside to the depth of the upper packer. • • • Lower the assembly to sting seals into packer and land tubing hanger with weight on lower packer, run in with lockdown studs per Vetco Gray. S j_ • Rig up Slick line to set plug in X nipple below the upper packer. 'pol 71. • Pressure up to 2000 psi against X plug in 500 psi increments to set the uppicr packers Hold and chart pressure as required. Pressure test the annulus and packer to 1000 psi for 30 min. Record the pressure test on a chart. - SS core_ e----. 41. Set BPV. ND BOP and NU X -mas tree. Pull BPV and install two -way check. Pressure test the tree to 3000 psi. 42. RD and release rig. Testing Operations 43. Connect flowline to the tree to flow test the well to a test vessel. 44. RU Pollard wireline with sliding sleeve shifting tool. RIH and shift the sliding sleeve at +1-5040' to ? the open position. Circulate packer fluid around that is treated with corrosion inhibitor. Leave a Ir ' 50' diesel cap in the annulus for freeze protection. Close s lid ng.sleeve, prare om floe e ll. ( �* —> t Q �. 45. RIH with swab cups on braided line. Swab the well and flow the well. Flow for at ast Thhours to clean up well and confirm production of gas and /or water. If well is flowing water, flow at least 4 tubing volumes of water to unload the tubing and near the the wellbore. Note gas production rate and whether gas rate is climbing or dropping. 46. Confer with Anchorage office on whether well can be flowed to the plant. Attachments: 1) Current Welbore Schematic 2) Current Completion Schematic, Weatherford 3) Proposed Welbore Schematic • Attachment 1 — Current Wcgb0T Schematic Kustatan Field #1 c,„),,,,,t Single Selective Completion KB -11.l#. •4 2013■ K-55 ©120' MD .. Methanol Injection 133/8"68■6 55 e c #1&oMD Mandrel \ « 7 ¥ : ( ._ / 4- / ) # > ¥ & ' ���° 0 a 31#& " 7 !ze 3Z4o - 2782 "Em B«EUETubing % & 3 9� ' e• « / � k •4 2782 "XNi le 2 5024' MD \ • \ • 2782 "Sldng Sleeve # 5143' MD % f gsaz "� a« & «s7uD 587P Gm on YB«knf185 \ 55 $ 7o278Z "�a Joints 5192' « _ • E \ 958Z " � a« ms al Bore & 5291' MD 91' /4'� \ \ �� l 278 "XN kppea 531E MD / S � P Gun assembly starts &5344 \ 41' ¢ \ & New Gas � A: 2 22\ \ - ' Bridge Plug & 6192' MD 52043 »o MD11 E ® k 5353-5365' MD $� 77 �pof 758Z " Liner © 6312' MD 5370-5380' MD { &, '41% » � Bull mm ©53 5' 7 'i 95 /8 "4 ■ L-80 e c a 6500' MD Disposal P %: k k 6270-834' MD " a s72s75MD $ f D#BkI MDA140z3c U) 6750-6800' MD • / / • • • • / • • • \ / \ 7 % 758Z "2.7#b«sLFL4S ©G,30oMD • • Attachment 2 - Current Completion, Weatherford Schematic IW Forest 011 Corporation ku4atan Facility 41 Vka _ Prepared For: Nor. 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I.10 474" •..14.0 0799154 092.49 14 4 1 1,125 1.273 001 3011.47 371116 I � . 7,94 4\..1 Cw.4440w104 01061n IN s 246 " 099 440'1 1,074 0.210 2,29 1102,26 5401.41 1 *04*, 461.949444 1236' 564400,, 44444.63099 046. 19# 1 0401 44094 1M10w 1a 115 \1 YIN NPA 1. 3' .,'0 . t t PM 40,1 9,697 2,41! ..30 4746,91 3103,44 Q i 164.1 1,069 2.441 11.36 1104.04 9110.61 I 4___ IM 0.o1.49'•a. 161, ••14 401911.' 9" 6 4411 0.940 VIII 1.660 2.203 11.110 3119451 5119.91 - C ,I../7 -- 717947454779 350 9 5. 4 ■ 7 119wW1 9 yp 4 .Mur 2 . • . .14 2.113' led ion 444 1.164•4194.510 199514 1.646 2.441 1.33 9119.32 0321.04 ; !' 4415641 45.11 9.546 6 .11601.4,740 2,440 2,2) 3121.09 3,923,29 - ,, 159166•66 196,91644 66IM 9 1.410 1.1.1 134 4124.29 4126.96 N.b.44.tn. Ohba. 1 orw1 1.991 1.441 20,00 942694 5146.94 I' 4- 240 Nip 1711" • MI 11 1, 041! 11411611423'3 .4 1 4.13 3344.94 2392.07 - 1 . Nor 1M11/M90 Nrd 6x1101. 234 40,04 5442.07 {104,14 ' . - .. { F L .. 1.5046 r . 421'.414 149N411�1Pf 31.W'Pa"w ln. 6611601.4,623 s% 1,41 4194.11 33.34 2' 4 r ' I. ( .16.9.#4 199144.. 19911 119 0.4t 6.99 00'I 1 4411 9.250 v{ 447 4220,00 6224.17 , 915999 / YN d' t 990.990 Pwe 110,299 Nn 1110 F • • Attachment 3 — Proposed Completion Kustatan Field #1 Proposed Wellbore Diagram KB =11.1 ft. +f Kv 20" 133# K -55 @120' MD Methanol Injection . :!y ' 13 3/8" 68# K -55 BTC @ 1820' MD Mandrel @ 2896' MD j ® • Sliding Sleeve @+ 2956' ® • • 9 5/8" Weatherford Packer @ 3020' MD New Gas Perfs 2 7/8" 6.5# L - 80 EUE Tubing ✓ 3102' -3150' MD 3260' -3285' MD Sliding Sleeve @+ 5050' ; ;1. i' • ;v w 9 5/8" Packer @ 5097' MD Sliding Sleeve @+ 5110' I ■ I ::. Sand Screened Perfs @ 5204' —5260' ve 9 5/8" Packer w/Seal Bore 5291' MD 2 7/8" XN Nipple @ 5315' MD � • ". r, �v w � Existing Gas Perfs: la f 5353 -5365' MD 5370 -5380' MD y t.:. Bridge Plug @ 6192' MD .Z` ii . :� Top of 7 5/8" Liner @ 6312' MD •., ,.,:.. 9 5/8" 47# L -80 BTC @ 6500' MD Disposal Perfs: .. %; 6270 -6304' MD •% z 6312 -6475' MD � PBD @ 6743' MD (8/14/03 CTU) 6750-6800' MD •• • Z v • • • • • ' :� %`�`�`� ,:,- , • 7 5/8" 29.7# L -80 STUFL4S @12,300' MD • l - Internal Memo 4 e ( Date From To: 1 /,,2y / /z � • c"to iti',v Ett y !Hatt /1 .0v_ ` KAz -z-it Hest Power /4ev 4 Kitty • z - I.s6 %A A+oi VA ; 000 iRc J u I�os E PuiyP ,/✓ Su d - flo.ty r CLcoA Velta Bti. ✓u y ` o'' '`er /!. Fu, -v & 2,£ WORK .5112.1d44-- 134 +C C i� Nor 3 .: l S�,San»f I tex Sr%7Na Pmt /�9/Jiv�F ,7filvd WIC f �!/ i4ia //A Fat r, ,' III • • 120113_ NOTE_ KF - ]Sundr Application .Approval_Condition.txt Text that must be inserted into the approval letter for this sundry application: This Application for Sundry Approval is approved subject to full compliance with 20 AAC 25.055 and Conservation Order No. 566 (CO 566) . Approval to test or produce any interval other than the Kustatan Field #1 Gas Pool as defined in CO 566 is contingent upon issuance of a conservation order approving a spacing exception. Cook Inlet Energy assumes the liability of any protest to the spacing exception that may occur. )T Page 1 • Page 1 of 1 Schwartz, Guy L (DOA) 20 _ From: David Hall [david.hall @cookinlet.netj Sent: Wednesday, March 07, 2012 3:41 PM To: Schwartz, Guy L (DOA) Cc: Barbara Kruk Subject: CIE SUNDRY retraction Guy, As we discussed, CIE request SUNDRY 311 -267 be retracted. Thank you, • David -� DMA 1 2 AO L David Hall, CEO 2 Cook Inlet Energy 601 W. 5th Avenue, Suite 301 Anchorage, Alaska 99501 Office ph: 907 - 433 -3804 Mobil ph: 907- 317 -8239 x 3/7/2012 • • Page 1 of 1 • Schwartz, Guy L (DOA) From: David Hall [david.hall @cookinlet.net] Sent: Friday, January 20, 2012 11:16 AM To: Schwartz, Guy L (DOA) Cc: Regg, James B (DOA); Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Barbara Kruk Subject: Re: KF #1 (PTD 200 -153) RWO sundry review Attachments: KF #1 TOC.pdf; ATT3737480.htm; kustatan time structure map..pdf; ATT3737481.htm; KF #1 Flowtest 11- 14- 05.xls; ATT3737482.htm; PastedGraphic- 1.tiff; ATT3737483.htm Guy, Here is my response to your questions, 1) Correct, the anticipated MASP for the workover is 1781. It is based on the 5313' MD Tyonek formation of 2316 psi using a .1 psi.ft gradient to surface as supported by the attached. The Beluga formation pressure is expected to be less than 5313' MD Tyonek formation. 2) 80 psi on the tubing and 0 psi on the 9 5/8" x 13 3/8 ". 3) We sent the CBL, see the attached calculations that shows the TOC of 4442'. In a related email from you having received the CBL you ask about our assessment of 2120' -2320' MD, our assessment is that it shows great perms and porosity but appears wet as indicated by the neutron log. 4) No, The current BHP for the 5313 zone is anticipated to be less than 8.5 ppg. We do not want to have fluid on the Beluga zone and are killing the well above it. 5) We lan to utilize the gas buster through the choke. P 9 9 6) You are correct, we will remove step 44. Also, on a different note related to the spacing exception issue, see the attached time structure map indicating drainage only on our lease. We plan to contour a map along with isopach for sand to come up with a map showing compresshive reservoir. In accordance with Alaska Statutes AS 20AC25.537(b), we request that confidentiality by extended to the attached 3102 Gas sand time structure map. Please let me know if you have any other questions. Regards, David IVIAT- a2 1, 1/23/2012 • Page 1 of 2 �I Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, January 13, 2012 9:59 AM To: 'David Hall' Cc: Regg, James B (DOA); Maunder, Thomas E (DOA); Davies, Stephen F (DOA) Subject: RE: KF #1 (PTD 200 -153) RWO sundry review David, Here are my comments and questions for the RWO procedure for KF #1: 1) What is the MASP (max anticipated surface pressure) for the well workover ? You list a formation pressure for the Tyonek (5313' md) at 2316 psi. This computes to a MASP of 1781 psi using a .1 psi /ft gradient to surface. Do you have any estimates for the Beluga formation pressure and what is your basis for the pressure? 2) What are the current tubing and annulus pressures? ... the 9 5/8" X 13 3/8" annulus? 3) Do you have the original CBL data available for our review? What is the current TOC in the 9 5/8" X 13 3/8" annulus? (Your well schematic shows cement to the surface shoe). Are there other zones that may need cement coverage below your proposed circulation point of 3420' md? 4) Step 4 has you setting a plug in the tubing but not testing it.... Step 5 has you killing the well with 8.5 ppg fluid. Are these steps swapped ?? 5) In Step 24 you are cleaning out fill by circulating and reversing out. What will be your flow path for the fluids at the surface? There likely will be gas entrained in the returns... 6) At step 44 you mention circulating packer fluid around after you have set the packers. It appears you have already done this in step 40. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: David Hall [mailto:david.hall @cookinlet.net] Sent: Thursday, January 12, 2012 6:16 PM To: Schwartz, Guy L (DOA) Cc: Regg, James B (DOA); Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Foerster, Catherine P (DOA); Roby, David S (DOA); DOA AOGCC Prudhoe Bay; Barbara Kruk; WMRU Drilling Foreman Subject: Re: KF #1 (PTD 200 -153) Guy, Thank you for the quick response. I understand the need to wait to rig up the BOP equipment until the below issues are resolved. I will attempt to address the items below, 1) Will wait for response. 2) Please let us know if we can provide addition information to help clarify. 3) We do not plan to co- mingle the three different zones at this time but if the need ever arises we would then submit the necessary co- mingling application. The proposed completion is designed as such. 1/23/2012 1 Page 2 of 2 • 4) We have addressed the rig shortcomings identified by the AOGCC inspector on Dec 24th and was under the understanding that the AOGCC inspector would verify satisfactory completion of those items at time of BOP witness /inspection. We are more than happy to coordinate a followup rig inspection before the BOP witness /inspection at AOGCC's convenience. Regards, David David Hall, CEO Cook Inlet Energy 601 W. 5th Avenue, Suite 301 Anchorage, Alaska 99501 Office ph: 907 - 433 -3804 Mobil ph: 907 - 317 -8239 Cook Inlet Energy_. On Jan 12, 2012, at 4:43 PM, Schwartz, Guy L (DOA) wrote: David, We are currently working through several issues regarding the upcoming RWO on KF #1. I will list them below: 1) Spacing issue is being handled but will take a few days to get an opinion from legal. 2) The Sundry RWO procedure itself needs some clarification. I will send you a list of my questions Friday morning. 3) Co- mingling the well is being handled by Dave Roby. You can theoretically complete the work to open the Beluga but can't actually flow both zones until the Conservation Order is approved. 4) The Rig itself (Rig 34) has several shortcomings regarding certifications and equipment specifications. Jim Regg is drafting an email to send you detailing all the items he still needs to approve the rig. The last rig inspection done on Dec 24th has many items that needed addressing. So in short, we can't allow you to pull the tree off and riq up BOP equipment until these issues are resolved. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) 1/23/2012 ' hook Inlet Energy ED JAN 1 y 2Lliz January 12, 2012 Alaska Oil & Gas Cons. Commission Anchorage Commissioner John Norman Alaska Oil & Gas Conservation Commission 333 West 7 Ave., Suite 100 Anchorage, Alaska 99501 Re: Request to Approve Amendments to Sundry 311 -267 Allowing Testing of New Zones in Kustatan Field No. 1 Gas Well -b zoo- J ° ems w = r,ti • d Dear Commissioner Norman: ' ` "�` t� Cook Inlet Energy, LLC (CIE) operates a small gas field on the West Foreland known as the Kustatan Field. This field is located within oil and gas lease number ADL 390368 and produced through a single well, Kustatan Field No. 1 (KF #1). This well has an existing spacing exception but CIE wishes to obtain approval of amendments to Sundry 311 -267 allowing it to test new zones within the well. These new zones would be tested for a period not greater than 180 days. CIE would then determine the extent of the drainage area and present the results to share this information with the adjacent lessee and the Alaska Division of Oil and Gas and then decide whether the appropriate action would be to file for a spacing exception or a unit prior to the commencement of commercial production. This well was originally drilled by Forcenergy, Inc. in 2000 as an oil exploration well, but did not encounter commercial quantities of oil and was subsequently recompleted as a Class II injection well in 2003. The well was recompleted again in 2005 as a gas well with perforations between 5,385' - 5,367' MD and 5367' - 5,352' MD. However, this well's bottomhole location is was found to be approximately 1,468 feet from the lease boundary with oil and gas lease ADL 391100 and therefore the conversion of KF #1 to a gas well created a violation of 20 AAC 25.055(a)(2), which requires that the wellbore of a natural gas well may be opened for testing or production within 1,500 feet of a property line only if the owner is the same and the landowner is / the same on both sides of the line. Forest Oil applied for, and received a spacing exception for this well, with consent of the adjacent landowners, as Conservation Order 566 on August 25, 2006. However, this order limited the exception to the defined depth interval between 5,385' and 5,352' MD. The wellbore experienced problems in 2010, ultimately leading to a cessation of production on December 27, 2010. Over the past year CIE has made several attempts to return the well to production. CIE has now successfully mobilized a drilling rig to the well and intended to begin a workover that would include reperforating existing zones as well as opening and testing new potentially productive zones at 3,102' - 3,150', 3,260' - 3,285', 5,204' - 5260' MD. The Commission approved Sundry 311 -267 for this work, which included the addition of perforations at 5,204' - 5260' MD. CIE filed a request January 9, 2012 to amend Sundry 311- 601 W 5 Ave., Suite 310, Anchorage, AK 99501 • • 267 to include the new perforations at 3,102' — 3,150' MD and 3,260' — 3,285' MD. CIE was under the mistaken understanding that this workover would not require a new spacing exception, until it was pointed out to us by Mr. Steve Davies of your staff that Order 566 limited the spacing exception to specific zones. The subsurface estate under both ADL 391100 and ADL 390368 is owned and leased by the State of Alaska under identical terms. ADL 391100 is currently leased to Apache Alaska Corporation (Apache), which has provided the attached letter of non - objection. Apache understands and supports our proposed activities. Upon completion and testing of this well CIE will share the information with Apache and mutually decide whether it would be proper to apply for a new spacing exception for the new interval prior to the commencement of commercial production. We understand the intent of 20 AAC 25(a)(2) is ultimately to protect a lessee from suffering harm by having natural gas drained from their lease by an adjacent lessee. However, our proposed plan can only benefit our adjacent lessee. Given the small size of this field, it is unlikely that it would be economic to drill a new well further away from the lease boundary. And CIE at this point believes that testing the new zones will help us to determine if it would be appropriate to seek a spacing exception for any or all of the new zones. At the very least CIE would encounter significant increased costs if it were unable to move forward with the workover in a timely manner, and at worst would find ADL 390368 terminated prematurely, as it is currently past its primary term. We therefore believe that it is in the best interest of all parties for CIE to move forward expeditiously with the workover and testing of this well, and we respectfully request that the Commission approve the amendment to Sundry 311 -267 allowing us to do so, subject to the conditions proposed in this letter. We would further request that the Commission review this request expeditiously so that if a spacing exception will be required prior to our commencement of work on this well, we would have as much notice as possible. If you have • s y questions or require any additional information, please contact our CEO, David Hall at 317 L 39. Si erely JR Wilcox President Cook Inlet E ergy, LLC Attachment: Apache Alaska Corporation Letter of Non - Objection CIE request to amend Sundry 311 -267 Conservation Order 566 II • • Cook Inlet Energy_ January 10, 2012 Apache Alaska Corporation Attn: Paul Abokhair Anchorage, Alaska Re: Letter of Non - Objection for Recompletion of the Kustatan Field No. 1 Gas Well Dear Paul: Cook Inlet Energy, LLC (CIE) has plans to recomplete our Kustatan Field No. 1 (KF #1) gas well on our Kustatan oil and gas lease, lease number ADL 390368. This well's bottom hole location is approximately 1,464 feet from the lease boundary with Apache Alaska Corporation's (Apache) oil and gas lease ADL 391100. CIE's predecessor in interest, Forest Oil Corporation (FOC), originally drilled the KF #1 well as an oil well, and met the spacing and pooling requirements as such. The well was subsequently converted to a disposal well and then to a gas well. FOC received a spacing exception from AOGCC for the Kustatan Field #1 Gas Pool, which is within the interval of 5,352' to 5,385' measured depth. CIE plans to recomplete the well and test additional gas intervals at 3102'- 3150', 3260'- 3285'and 5204' - 5260'. The KF #1 well bottom hole location is Tess than the 1,500' spacing required by 20 AAC 25.055. This letter of non - objection as verification that Apache, as the adjacent leaseholder, does not object to CIE recompleting the KF #1 well and testing additional gas intervals. We believe it is in Apache's best interest to allow CIE to recomplete and test the KF #1 well. Upon successful work -over and well test, CIE will determine the extent of the drainage area and present the results to Apache. By signing below, Apache hereby provides its non - objection pursuant to the conditions listed below: 1. Recompletion of the KF #1 well will not involve drilling any sidetracks or changing the path of the current wellbore. 2. Apache will not give up any rights to any gas that may be in communication across lease boundaries in any additional zone tested during the recompletion of the KF #1 well. t6 601 W 5 Ave., Suite 310, Anchorage, AK 99501 • • Letter of Non - Objection Recompletion of the KF #1 Gas Well January 10, 2012 Page 2 of 2 By this letter, Apache hereby agrees to and accepts the provisions set forth above. Sincerely, David Hall CEO Cook Inlet Energy, LLC Attachment: Wellbore Chart with Measurement to Lease Boundary Apache Alaska Corporation Non - Objection Date: / 'L- s 'U ' Double cfidc on an existing nter to change its prapaties. o . ' LMds: o English Metric I Digi� , I se Map _ � - .., Distance Told l Save ( �. ❑ igil II - i . ', .. ' Q p i .." 0 ®= S picE et ®0 Fet 1481882 1461882 I Pose I — -- - -_ ---- ____ -_. Mis* D.277 Q277 r l Ho I� • a f Ac eA9 e ADL -3 1(OQ I • _ E-- 1 ---- -,d ,:,. Culture: FST Leases_Apri5jt11 j, I r 37204, Y.246081270 Feet, Let:60'43'20.84548 ", Long.151'4526.06814 ", Edit Culture: Fulers li b ,:. .., ...:. - FOREST biL eoR'. � ; . Page 6 of ?v' Operat Summary / Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contract9r Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number. 160 Ike . .Fr om To H C1 Phase D of Op e r ations dub cede 11/4/2000 11:00 - 14:00 3.00 14 E DRLINI Break and lay down lower IBOP valve from top drive. p 14:00 - 15:00 1.00 12 A DRLIN1 Rig up to run 9 5/8" casing. Pick up Lafluer tool. /// ��� J 15:00 - 16:00 1.00 12 A DRLINI Rig up bales, elevators and slips. 16:00 - 17:00 1.00 12 A DRLIN1 Rig up stabbing board. Rig up air line for slips. tor/ 17:00 - 17:30 0.50 12 A DRLIN1 PJSM 17:30 - 18:00 0.50 12 A DRLIN1 Make up shoeand Moat collar. 18:00 - 02:30 8.50 12 A DRLIN1 Run 282 its. 9 5/8" csg. 02:30 - 04:00 1.50 12 C DRLIN1 +arc. @ 6496' 04:00 - 05:00 1.00 12 A DRLINI Break out and lay down Lafluer head. Blow down top drive.Make up landing joint, cement head and hose. 05:00 - 05:30 0.50 12 C DRLIN1 Break circulation and tag bottom @ 6500' while circulating.PJSM 05:30 - 06:00 0.50 12 DRLIN1 Test cant lines to 3000PSI. OK 11/5/2000 06:00 - 08:00 2.00 12 C CSGIN1 : Drop plug, 5 bbl. MESAH2O, kick out plug. Stop and reload head. Pump 43 bbl. MCS -A H2O, 72.5 bbl. lead slurry @ 12.5 ppg., 42.3 bbl. tail slurry 15.8 ppg. Drop plug 5 bbl. H2O, switch over to rig pumps. stop reciprocating casing @ 3500 strokes, bump plug @ 3970 strokes. 08:00 - 12:00 4.00 14 B CSGIN1 Pull cement hoses and drain. Prepare BOPs to pick up to set casing slips. Remove flow lines, hook up cable and cable clamp BOP linter. 12:00 - 13:00 1.00 14 B CSGINI PJSM Lift stack with rig hydraulics. 13:00 - 13:30 0.50 CSGIN1 Set casing slips with 115000 #. 13:30 - 14:00 0.50 14 B CSGINI Cut hole in 95/8" casing, drain and rough cut. 14:00 - 16:30 2.50 14 B CSGINI Let down stack, take off cement head. Rig down hydraulic lift system. Lay down 95/8" cut off.Lay down elevators. 16:30 - 17:00 0.50 14 B . CSGI Start finish cut on 9 5/8" casing. 17:00 - 21:00 4.00 14 CSGIN Pick up Vetco Gray tubing spool, fill with packing. test to 3800 PSI. Test OK. 21:00 - 01:00 4.00 14 B CSG/ 1 Nipple up BOP, tubing spool, change lower rams to 5 ". Nipple up flow line. Hook up turnbuckles. 01:00 - 05:00 4.00 15 A CSG 1 Pick up test joint and test plug. Test choke manifold, upper and lower IBOP valves. Test floor valves, choke and kill line valves. Test top, bottom and blind rams - 250/4000 PSI. test hydril- 25013000 PSI. Set wear bushing, lay down test joint. 05:00 - 06:00 1.00 14 E CSG 1 Install drip pans under rotary table. 11/6/2000 06:00 - 09:30 3.50 14 B DRLI 1 Finish installing drip pans, hoses. Clean cellar and sub base. 09:30 - 12:30 3.00 06. J DRLI RIH with 12 1/4" BHA and lay down same. 12:30 - 16:30 4.00 06 A DRLI Pick up 8 1/2" BHA. 16:30 - 18:00 1.50 06 A DRLI RIH to 2031'. 18:00 - 18:30 0.50 05 1 DRLI Break circulation 1 2031'. 18:30 -19:30 1.00 06 IA DRLI RIH to 3906'. 19:30 - 20:30 1.00 05 11 DRLI Break circulation @ 39'. 20:30 - 22:00 1.50 06 A DRLI RIH, tagged float collar @ 6418.6'. 22:00 - 22:30 0.50 05 1 DRLIN Break circulation © 6418, CBU. 22:30 - 23:00 0.50 09 DRLIN Slip 100' of drilling line. 23:00 - 06:00 7.00 08 E DRLIN . Prepare to lawdelVR"l015drive. Lay down bales and elevators and rpaawE1 wer IBOP.Move block hanging line. Remove kelly hose and lower hose. Lay down stabbing board. Install transport pins. Fold derrick board up. Close storm doors in board. Drain oil from top drive. Pin erection rigging to blocks and latch rigging to torque guide clamps. Release tension in torque cables. Tuen power off and disconnect electric and hydraulic cables. Unlatch from harpoon. Lay down beaver slide. Remove windwalls. 11/7/2000 06:00 - 07:00 1.00 01 A DRLIN2 Lower grasshopper on Can -Rig top drive and spool up electric cables and hydraulic hoses. Printed: 2122/2001 2:56:23 PM • • Page 1 of 1 Maunder, Thomas E (DOA) From: Regg, James B (DOA) Sent: Thursday, December 08, 2011 3:59 PM To: WMRU Drilling Foreman Cc: DOA AOGCC Prudhoe Bay; Maunder, Thomas E (DOA) aQO =- \S 3 Subject: RE: Miller Rig # 34 inspection. Attachments: AOGCC Rig Inspections Focus 11- 19- 10.pdf Before commencing work, the following schematics will need to be provided to facilitate the AOGCC rig inspection (include dimensions and pressure ratings for equipment as appropriate): - Blowout Prevention Stack - Diverter (if applicable) - Diverter Vent Line (if applicable) - Choke Manifold - Choke and Kill Lines - Accumulator System - Piping schematics for Rig's Fluid Flow and Hydraulic Controls - General Rig Equipment Layouts Attached please find a document outlinin s of focus for AOGCC's rig inspection. Once received, I will arrange for an Inspector to visit the rig at KF #1 (PTD 2001530 .J Jim Regg AOGCC " `i `t 333 W.7th Avenue, Suite 100 „ 1 }Y Anchorage, AK 99501 907- 793 -1236 • From: WMRU Drilling Foreman [mailto: drilling.foreman ©cookinlet.net] Sent: Tuesday, December 06, 2011 7:23 AM To: Regg, James B (DOA) Cc: DOA AOGCC Prudhoe Bay Subject: Miller Rig # 34 inspection. Jim, We are nearing the end of construction and in about a week will be ready to address the work on our KF #1 well. The AOGCC is welcome to inspect our rig at anytime, we have flights daily. Please advise, thank you, Mike Murray Cook Inlet Energy, LLC Drilling Logistic Coordinators Don Jones and Mike Murray Office # 907 - 776 -7141 Cell # 907 - 529 -9786 Fax # 907 - 776 -7148 drilling.foreman@cookinlet.net 12/9/2011 • . AOGCC Rig Inspections Focus Schematics Requested (prior to conducting inspection): - Blowout Prevention Stack - Diverter - Diverter Vent Line - Choke Manifold - Choke and Kill Lines - Accumulator System - Piping schematics for Rig's Fluid Flow and Hydraulic Controls P g g Y - General Rig Equipment Layouts Applicable Regulations: http: / /doa.alaska.gov /ogc /Regulations /RegIndex.html 20 AAC 25.005: Permit to Drill [MASP addressed in 25.005(c)(4)] 20 AAC 25.033: Primary Well Control — Drilling Fluid System 20 AAC 25.035: Secondary Well Control for Drilling — BOPE & Diverter 20 AAC 25.036: Secondary Well Control for Through- Tubing Drilling — BOPE 20 AAC 25.065: H 20 AAC 25.066: Gas Detection 20 AAC 25.280: Workover Operations 20 AAC 25.285: Secondary Well Control for Tubing Workovers — BOPE 20 AAC 25.286: Secondary Well Control for Workstring Service — BOPE 20 AAC 25.527: General Well Control Requirements Guidance Bulletins Related to Rigs: http:// doa. alaska. gov /ogc/bulletins/bulletindex.html # 7 -001: Kill Line # 8 -001: Gas Detector Alarms # 10 -001: Test Witness Notification # 10 -003: Reporting Use of BOPE to Prevent Flow of Fluids from Well Rig Inspection Focus: Diverter Diverter Vent Line BOP Stack Choke Manifold Choke and Kill Lines Accumulator System (Primary and Back -ups) Mud -Gas Separator BOPE Control Panels Mud System (Mud Logging; Conditioning Equipment; Testing; Communications) Gas Detection and Alarms Top Drive/ Rotary Condition of Drawworks, Rig Engines Structural Certifications for Derrick • TfAITE aksK,A\ SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMNIISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 David Hall CEO Cook Inlet Energy 601 W. 5th Ave., Ste. 310 ® (J— 1 . 3 Anchorage, AK 99501 Re: Kustatan Field, Kustatan Gas Pool, Kustatan Field #1 Sundry Number: 311 -267 Dear Mr. Hall: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerel 0 0 o 4. n • mis 'oner DATED this v day of September, 2011. Encl. II • • Cook Inlet Energy_ RECEIV AUG 3() �aikaUfia6�C� August 30, 2011 ort � SSiOA Mr. Dan Seamount, Chair Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue, Suite 100 Anchorage, Alaska 99501 -3539 Re: KF #1 Re- perforation and Screen Installation Dear Mr. Seamount, Cook Inlet Energy plans to re- perforate two intervals in KF #1 in the Kustatan Field of Cook Inlet in order to enhance gas production from the upper Tyonek sands. We also plan to install a sand control screen across the upper interval to minimize sand production from this zone. The workover will be performed using our Rig 34. A general work procedure is attached. The estimated date for commencement of this work is September 6, 2011. Attached please find a completed Form 10 -403 for the work, an outline procedure, a current welibore schematic and a proposed post - workover wellbore schematic. If you have any questions, please contact me at 433 -3804. Sincerely, f 2r1 vid Hall, CEO, Cook Inlet Energy Attachments: 10 -403 Application for Sundry Approvals Outline Procedure Current Wellbore Schematic Proposed Wellbore Schematic (A/4 h um u STATE OF ALASKA c'i,l^' ECEIV : ALASKA OIL AND GAS CONSERVATION COMMISSION '4' „AVali G 3, 0 21117 APPLICATION FOR SUNDRY APPROVALS Alaska 20 AAC 25.280 {cs QH & Gat Cam. � 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 ` ChangemiNstel4gEogram ❑ Suspend ❑ Plug Perforations ❑ Perforate 0 , Pull Tubing 0 . Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Install sand control screen 0 • 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Cook Inlet Energy Development 0 - Exploratory ❑ 200 -153 . 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 601 W 5th Avenue, Suite 310, Anchorage, AK 99501 50- 133 - 20496 -00 . 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: r i / ,'<e› Spacing Exception Required? Yes ❑ No El Kustatan Fac #1 ' �� ifl�y 9. Property Designation (Lease Number): I 10. Field /Pool(s): f ADL 387023 Kustatan Field' _ 0 i 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12,300 12,300 6192' 6192' Bridge Plug @ 6192' None Casing Length Size MD / TVD Burst Collapse Structural Conductor 120' 20" 120' 120' N/A N/A Surface 1,820' 13 3/8" 1,820' 1,820' 3450 psi 1,950 psi Intermediate 6,500' 9 5/8" 6,500' 6,500' 6,870 psi 4,750 psi Production Liner 5,988' 7 5/8" 12,300' 12,300' 6,890 psi 4,790 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 5204'-5260' 5204' -5260' 2 7/8 ", 6.5# L-80 5344 5353'5365' 5353' -5365' 5370' -5380' 5370' -5380' Packers and SSSV Type: Packer: 9-5/8" packer # 1 w /sealbore Packers and SSSV MD (ft) and TVD (ft): Packer # 1 @ 5291' MD/TVD 9-5/8" packer #2 Packer # 2 @ 5097' MD /TVD 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development 0 ' Service ❑ 14. Estimated Date for ,6/2 11 15. Well Status after proposed work: Commencing Operations: .1 Oil ❑ Gas El - WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Natasha Sachivichik 264 -6116 Printed Name David Hall Title g/3 f / CEO Signature `L✓ v Phone / Date .L J� 907-433-3804 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 51 1 'a Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: - c 'O P E fO ;ODO FL. Subsequent Form Required: t — L-( 0 LI. 7 / APPROVED BY Approved by: OMMISSIONER THE COMMISSION Date: �• 2.. / / ir Form 10-403 Revised 1/2010 1 R 1 G 1 N L RBDMS SEP 0 7 2111 S i., it in Duplicate .^ ' ` • . Kustatan Field #1 Single Selective Completion 11/22/05 KB =11.1f. A rl ' ' :::,....4 ' 20" 133 K-55 @120' MD Methanol Injection �`13 68# BTC @ 1 0' MD Mandrel @ 2980' MD • +41 3/8" K 5 8 v v • •# At ¥ • 2 7/8" 6.5# L-80 EUE Tubing A • se % . 2RmX Nipple @502'MD * 2»Fg@mgSleee@5143' MD g&mPackrA5g29D 5'TCP Gun on Y Block @ 5,185' 7'2 7/8" Blast Joints @ 5192' v ...dm P. � � g&y Packer wSelBore ASgt MD 2»yXN Nipple @515' MD - 41' TCP Gun assembly starts @ 5344' 4 , , i.;...; Bridge Plug @ (192' M D New Gas P: 5 0 -5260' MD : 4 5353-5365' M D ! ® e At ir Top of 7 5/8" Liner @ 6312' MD 5370-5380' MD 2 r 46.. 9 5/8" 47# L-80 BTC A 6500' MD aspsmPrf: k 6270-6304' M D • 6312-6475' MD 4 PBD @ 6743' MD(Za14/03CTU) 6750-6800' MD \ 4 . ( • • 4 i 4 � V Al / V AV 7&8" 2.7 L-80 STUFL S @12,300' MD 1 1 • 0 Kustatan Field #1 Proposed Welibore Diagram KB =11.1ft. ✓ 20" 133# K-55 912E MD \ Methanol Injection • 13 3/8" 68# K 55 BTC @ 1820' MD Mandrel @ 2980' M D ; • v v. s. 2 7/8" 6.5# L-80 EUE Tubing s. v. v. ~ • v Sliding Sleeve @ ±05' : g @y Packer g5gfMD g di nR Sleeve y ± 1 m' \ S net Screened Per g 520 '— 5260' a A , 9 &m Packer w Se (Bore @ 5291' MD A : 22mXN Nipple A5]EMD Existing Gas Perf : � � 5353-5365' MD v 5370-538 0' MD 4+0 � �� Bridge Plug @ 6192' MD p $. 7 Top of 7 5/8" Liner @ 6312' MD a I ; • 9 5/8" 47# L-80 BTC @ 6500' MD • Dis�smPrf: i 6270-6304' MD % 8312747E MD PBD @ 6743' MD ( /14 /03 CTU) 6750-6800' M D r •` ' 41 A ¥ 4 : q $ K� k 7 5/8" 29.7# L-80 STDFL S @12,300' MD • • Cook Inlet Energy_ Kustatan Field #1 Re- perforation, Sand Control Screen Installation and Re- completion Summary Procedure Project outline: Kustatan facility # 1 well is currently shut -in. The well contains the following un- isolated gas production perforations: 5185' — 5192', 5204' — 5260', 5353' — 5365', 5370' — 5380'. The top interval produced fine sand causing major tubing sanding problems. The deepest perforated interval did not show any flow ,— during testing. Currently, the well is shut -in with back - pressure on well to control sand influx. The current plan is to pull the existing completion, re- perforate the intervals listed above, install a sand control screen across the sand producing interval and install a new completion. Pre -Rig Operation 1. Mobilize personnel and equipment necessary for pre -rig operation. 2. Rig up wireline and run with a tubing punch and punch a hole just above the upper packer (packer set at 5097' MD). 3. Establish circulation with 8.9 ppg produced water and circulate all gas out of the well (formation pressure at 5353' is 2316 psi, equal to 8.32 ppg). 4. Monitor wellhead pressure; ensure well is dead. 5. Install BPV in the tubing hanger. 6. Remove the flow lines from the well head. Rig Operation 7. Rig up Rig #34 over the well. Nipple down the production tree. 8. Notify AOGCC of upcoming BOPE test. • • Cook Inlet Energy_ 9. Nipple up 11 "5M x 11" 3M DSA, 11" 3M mud cross and 11' 3M OP stack (annular, blind rams, 2 -7/8" pipe rams). Pull the BPV and set a two way check valve. Call AOGCC inspector to witness BOP test. Test BOP's to 3000 psi. After testing BOP pull the two way check valve. 10. Latch onto 2 -7/8" L -80 tubing hanger. Apply straight pull. Monitor upper packer release. Apply additional pull to release seal assembly. 11. POOH with 2 7/8 "tubing, Hydrow 1 packer and seal assembly. Monitor well for fluid losses while pulling out. L/D tubing and packer. 12. Retrieve the lower packer (set at - 5291' MD) using a retrieving tool operated by applying 2,000 to 3,000 lbs. down force on packer to latch the retrieving tool into the packer. Then pull slight tension and rotate to the right approximately 8 turns to release the packer. 13. POOH with the lower packer, L/D same. 14. Monitor fluid losses. If the fluid loss rate is too high to keep up with for the length of the work over, mix and place a 40 -bbl HEC pill. 15. Set wear bushing. 16. Run a 9 -5/8" scraper to 6192' MD (bridge plug). Circulate the well clean. POH. 17. Rig up wireline and re- perforate the existing perforated intervals. 18. Run and set the lower part of the completion (tubing tail, XN- nipple, lower packer) on wireline. Set the packer at 5291'. 19. The zone at 5204' — 5260' MD Run and set a retrievable casing screen across the perforated interval 5204' — 5260' plus 10 ft on either side. 20. M/U and run new 9 5/8" upper - packer completion as follows: • Seal assembly • Bottom sliding sleeve • Cook Inlet Energy_ • Top 9 -5/8" packer • Top sliding sleeve • 2 -7/8" tubing • 2 7/8" Chemical injection mandrel and %" stainless steel tubing. 21. Circulate packer fluid from top of the bottom 9 -5/8" packer to tubing hanger. 22. Sting the seal assembly into the bottom packer. Observe string weight loss. 23. Space out and install tubing hanger. Pressure test and terminate the chemical injection line at the tubing hanger. Set the top 9 -5/8" top packer at calculated depth and land the tubing / hanger. 24. Run in the lock down studs and pressure test the tubing hanger seals with Vetco Gray. 25. Pumping on back side, pressure test upper packer to 1000 psi for 30 minutes. Record the test on a chart. 26. Test 2 -7/8" tubing to 3000 psi against the tubing plug set earlier. 27. Install BPV and ND BOPE. 28. NU production tree. 29. Pull BPV. Install 2 -way check into the tubing hanger. Pressure test the tree to 3000 psi. 30. Remove 2 -way check valve. Install BPV. 31. Release rig. STATE OF ALASKA • ALASKA OI AND GAS CONSERVATION COMMISSION. REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Li Repair Well Li Plug Perforations Lf Stimulate Lf Other L] Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate 0 Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Cook Inlet Energ Development 111 Exploratory ❑ 200 -153 3. Address: Stratigraphic Service ❑ 6. API Number: 50- 133 - 20496 -00 - ala 7. Property Designation (Lease Number): 8. Well Name and Number: ADL 387023 • Kustatan Field # 1 9. Field /Pool(s): P/ Kustatan Field ( & s split 10. Present Well Condition Summary: Total Depth measured 12,300 feet Plugs measured 6,192 feet true vertical 12,300 feet Junk measured None feet Effective Depth measured 6,192 feet Packer measured 5,291 & 5,097 feet true vertical 6,192 feet true vertical 5,291 & 5,097 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 20" 120' 120' N/A N/A Surface 1,820' 13 -3/8" 1,820' 1,820' 3,450' 1,950' Intermediate 6,500' 9 -5/8" 6,500' 6,500' 6,850' 4,750' Production Liner 5,988' 7 -5/8" 12,300 12,300 6,890' 4,790' Perforation depth Measured depth 5204' - 5260' ; 5353' - 5365' ; 5370' 5380'; 5844' - 5850' True Vertical depth 5204' -5260' ; 5353' -5365' ; 537V-5380'; 5844' -5850' Tubing (size, grade, measured and true vertical depth) 2 -7/8 ", 6.5# L -80 5,344' 5,344' Packers and SSSV (type, measured and true vertical depth) 9 -5/8" Packer #1 9 -5/8" Packer #2 5,291' & 5,097' MD 5,291' & 5,097' TVD 11. Stimulation or cement squeeze summary: ;1-- . y t Intervals treated (measured): Treatment descriptions including volumes used and final pressure: ' 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl CaSirig Pressure Tubing Pressure Prior to well operation: 0 0 0 0 0 Subsequent to operation: 0 0 0 0 0 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run Exploratory Development El " Service ❑ Stratigraphic ❑ Daily Report of Well Operations 15. Well Status after work: Oil ❑ Gas IO r WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 311 -121 Contact David Hall Printed Name David Hall Title CEO q Signature „.,,,..-2 . e Phone 907- 334 -6745 Date p ,j A.) a/ ! BBDMS AUG 0 8 20 l Form 10 -404 Revised 10/2010 Submit Original Only • • • KF #1 WORKOVER April 25, 2011 Operations Summary 1. RU e -line, RIH w/ tbg cutter, shot off tubing tail /TCP gun assembly at 5,330', POH. 2. RIH w/ perf gun on e-line, perforated the interval 5,844' — 5,850', POH. 3. Attempted to flow well — no flow. 4. Shut in and secured well. 5. RD/M0 all equipment. • • Kustatan Field #1 Wellbore Diagram May 2011 KB =11.1 ft. N ✓ 20 "133 #K55 @120' MD Methanol Injection 13 3/8" 68# K -55 BTC @ 1820' MD • Mandrel @ 2980' MD 0. 0 .• 2 7/8" 6.5# L -80 EUE Tubing 0 0 2 7/8" X Nipple @ 5024' MD . . r 4 : 9 5/8" Packer @ 5097' MD 2 7/8" Sliding Sleeve @ 5143' MD . i• 56' TCP Gun on Y Block @ 5,185' _____ • 70' 2 7/8" Blast Joints @ 5192' �`' L'... iS : 9 5/8" Packer w /Seal Bore @ 5291' MD 2 7/8" XN Nipple @ 5315' MD = ; Existing Gas Perfs: AZ P ` 5204 -5260' MD 5353 -5365' MD . K 5370 -5380' MD Bridge Plug @ 6192' MD ��— ', 5844- 5850' MD Top of 7 5/8" Liner @ 6312' MD Bull Plug @ 5385' ;•` 9 5/8" 47# L -80 BTC @ 6500' MD Disposal Perfs: �• 6270 -6304' MD `. 6312-6475' MD w; PBD @ 6743' MD (8/14/03 CTU) 6750-6800' MD a �v • Li i • %- %- %� %. -' %. 7 5/8" 29.7# L -80 STUFL4S @12,300' MD • Cook Inlet Energy_ s : v..Jn q :n 4 , . „ i . , T « #d►}. ttttElSS1p►� rP> August 4, 2011 Mr. Dan Seamount, Chair Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue, Suite 100 Anchorage, Alaska 99501 -3539 Re: Sundry Report of operations Kustatan Field #1 Additional Perforations Sundry # 311 -121 Dear Mr. Seamount, Cook Inlet Energy submits a report of sundry well operations for the Kustatan Field #1 in the Kustatan Field of Cook Inlet. The work performed included perforation of additional gas zone at 5844'- 5850'. Attached please find a completed Form 10 -404 for the work, a summary of well operations and the current wellbore schematic, If you have any questions, please contact me at 334 -6745. Sincerely, % / ja David Hall, CEO, Cook Inlet Energy Attachments: 10 -404 Report of Sundry Well Operations Summary operations report Current Wellbore Schematic • • Cook Inlet Energy_ July 19, 2011 * r:° Mr. Dan Seamount, Chairman n +° °- I ' Alaska Oil and Gas Conservation Commission `; 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 g t ; (fi •• g r4A RE: Report of Sundry Well Operations Cook Inlet Energy: Kustatan Facility # 1 (KF #1) Permit to Drill No: 200 -153 API No: 50 -133- 20496 -00 � • AU L 1 6 WI Dear Mr. Seamount, Cook Inlet Energy is submitting the Sundry Well Operations Report for the work performed on KF #1 well located in Kustan Filed, Cook Inlet The objective of the operation was to cleanout wellbore sand influx to 5,320'. After a few unsuccessful attempts at KF #1, Cook Inlet energy decided to recomplete the well. Currently the well is shut in and pending on the new recompletion program. Please find enclosed the following documents for your files: • Completed Report of Sundry Well Operations (10 -404) • Wellbore diagram • Summary Report of Operations If you have any questions or require additional information, please contact me at: (907) 317 -8239 or N. Sachivichik at (907) 264 6116 Sincerely, P .. j Cook Inlet Energy David Hall, CEO cc: N. Sachivichik - SolstenXP . y STATE OF ALASKA ALASKA. AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Li Repair Well U Plug Perforations Li Stimulate U Other U Coil Tubing Cleanout Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Cook Inlet Energ Development EI Exploratory ❑ • 200 -153 3. Address: Stratigraphic Service ❑ 6. API Number: .a 50- 133 - 20496 -00 *0 7. Property Designation (Lease Number): .. 8. Well Name and Number: ADL 387023 '� � .. Kustatan Facility # 1 9. Field /Pool(s): G " Kustatan Field . IBS 7A .) (/1 1 - Q 10. Present Well Con n Summary: Total Depth measured 12,300 feet Plugs measured 6,192 feet true vertical 12,300 feet Junk measured None feet Effective Depth measured 6,192 feet Packer measured 5,291' & 5,097' feet true vertical 6,192 feet true vertical 5,291' & 5,097' feet Casing Length Size MD TVD Burst Collapse Structural r Conductor 120' 20" 120' 120' N/A N/A Surface 1,820' 13 -318" 1,820' 1,820' 3,450' 1,950' Intermediate 6,500' 9 -5/8" 6,500' 6,500' 6,850' 4,750' Production Liner 5,988' 7 -5/8" 12,300 12,300 6,890' 4,790' Perforation depth Measured depth 5204' -5260' ; 5353' -5365' ; 5370' -5380' feet True Vertical depth 5204' -5260' ; 5353' -5365' ; 5370' -5380' feet Tubing (size, grade, measured and true vertical depth) 2 -7/8 ", 6.5# L -80 5,344' 5,344' Packers and SSSV (type, measured and true vertical depth) 9 -5/8" Packer #1 9 -5 /8" Packer #2 5,291' & 5,097' 5,291' & 5,097' RFC L.. . I , 11. Stimulation or cement squeeze summary: 4 , 0... Intervals treated (measured): , .L4 'Ili Treatment descriptions including volumes used and final pressure: t ,,_:., .. „ 11::13. i> :!9+ . t.; !g, LMifi. �.tiri1liSSIOn 12. Representative Daily Average Productiorx or'Cjata Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 0 Subsequent to operation: 0 0 0 0 0 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run Exploratory Development Ei Service ❑ Stratigraphic ❑ Daily Report of Well Operations 15. Well Status after work: Oil ❑ Gas isi WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 1 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry umber or N/A if C.O. Exempt: 3 ( ` ._ � Contact Natasha Sachivichik 264 -6116 N Printed Name David Hall Title CEO Signature Phone 907 - 334 -6745 Date '2_/ Form 10 -404 Revised 10/2010 RB©MS At 2 0 Submit Original Only • 0 Kustatan Field #1 Current We\bore Diagram KB=I1.lft. a G . . . 20 133# K-55 @120 MD • Methanol Injection 13 3/8" 68# K 55 BTC @ 1820' MD Mandrel © 2980' MD LI. 2 7/8" 6.5# L-80 EUE Tubing k a • 22ƒX Nipple @50¢UD 2»ƒ &ghgSev @5143' MD • \ g &ƒPcer ASOg29D 56' TCP Gun on Y Block @ 5,185' < 70228 Blast Joints @ 519' ■■ 9@y Packer wSel Bore A591' MD - k 27/8 XN Nipple @ 531E MD . 23 41' TCP Gun ass mbly starts @ 5344' '� % Bridge pug @ 6192' M D New Gas Perfs: 5204-5260' MD # 535333E MD �� Top of 7 5/8" Liner @ 6312' MD 5370-5380' MD ;>::',': ; Bull mug © 5385' 9 5/8" 47# L-80 BTC @ 6500' MD P. Disposal Pe rf: 6270-6304' MD a 4 8312347E MD 0,0 PBD @ 87 3' MD (8/14/03 CTU) 6750-6800' MD % a • p. . ; ' % . ,% K k 7 5/8" 29.7# L-80 STL/FL4 S @12,300' MD • KF #1 WORKOVER April, 2011 Operations Summary RIH w/ slickline, set plug in XN nipple at 5,315', POH. RIH, opened sliding sleeve at 5,143', POH. Opened well to production, produced fine sand, sanded up tubing. Shut in. Holding back - pressure on well to control sand influx, RIH w/ slickline and closed sliding sleeve at 5,143', POH. RU CTU, RIH and cleaned out fill to plug at 5,315', POH. RIH w/ slickline, pull plug from XN nipple at 5,315', POH, RD slickline. RU e -line, RIH w/ tbg cutter, shot off tubing tail /TCP gun assy at 5,330', POH. • - - • t' 'H. Attempted to flow well — no flow. Shut in and secured well. RD/M0 all equipment. Af. - 19 114 t aLAa-kt. " 2c0 -13-5 a ) Gook Inlet Energy_ July 7, 2011 R f E U L., ii ;,=(w Daniel S. Sullivan, Commissioner Department of Natural Resources E ii+ik, & tov Cm*. t liI►IIiSSion 550 West 7 Avenue, Suite 1400 APlc fer qe Anchorage, Alaska 995Q1 -3650 Re: Withdrawal of Request for Suspension of Operation Included in Cook Inlet Energy's Letter dated June 27, 2011 Commissioner Sullivan: On June 27, 2011, Cook Inlet Energy, LLC ( "CIE ") informed you of its continuing diligent efforts to reestablish production from its KF #1 well in the Kustatan Field on State of Alaska Oil and Gas Lease ADL 390368. Also included in that letter was a request for approval of a Suspension of Operations under 11 AAC 82.670. CIE respectfully withdraws its request for a Suspension of Operations. CIE has scheduled a meeting with Division of Oil & Gas staff on July 7 to present information on its past reworking operations and its continuing plans and efforts to reestablish production. CIE is confident that the Division of Oil & Gas will agree that CIE's past and ongoing efforts meet the extension provisions contained in paragraph 4.(c)(2) of the lease. Si cerel, ?.: `iM .1y I 2, 2i'ii J Wilco President Cc: William Barron, Director, Alaska Division of Oil & Gas Wendy Woolf, Petroleum Land Manager, Alaska Division of Oil & Gas Dan Seamount, Chair, Alaska Oil & Gas Conservation Commission 601 W. 5 Avenue, Suite 310, Anchorage, AK 99501 (907) 334 -6745 * (907) 334 -6735 fax 1 • • . C ook Inlet Energy_ Cr June 27, 2011 EA/ED dI ih° :C:ne) Daniel S. Sullivan, Commissioner �_ Department of Natural Resources ; , �tfrlttliSS�O 7th .iPti��fh�5 550 West 7 Avenue, Suite 1400 Anchorage, Alaska 99501-3650 Re: Notice of Continuing Diligent Reworking Operations on the KF #1 Well, Kustatan Field (ADL 390368) and Request for a Suspension of Operations for Same Commissioner Sullivan: 3\06" 1 g3 Cook Inlet Energy, LLC ( "CIE ") wishes to inform you that it is continuing its diligent efforts to reestablish production from its KF #1 well in the Kustatan Field on State of Alaska Oil and Gas Lease ADL 390368. The last sustained production from the well/lease was on December 27, 2010, with some limited production over a three day period in mid -May. CIE continues to have problems with uncontrolled sand intrusion into the wellbore preventing the reestablishment of continuous production. Mechanical interventions conducted on the well to date have been unsuccessful. CIE is currently investigating the feasibility of deploying new sand - control treatments which could restore the well to production. CIE is also reviewing well logs and identifying new zones that could be brought into production with the benefit of new sand control technologies. CIE therefore respectfully requests a Suspension of Operations under 11 AAC 82.670 of 90 days, effective June 27, 2011, to allow it to continue its efforts to address the sand problem and reestablish production. A 90 day suspension, and the six month period permitted under the lease to restart operations following the termination of the suspension, will result in this acreage still being available for the 2012 Cook Inlet Areawide Lease Sale should no solution be found or the solution found be determined to be uneconomic. CIE has scheduled a meeting with Division of Oil & Gas staff on June 29 to present information on its past reworking operations and its continuing plans and efforts to reestablish production. Should you have any questions in regards to this request, please contact Pirtle Bates at ,irtle.bat cookinlet.net or 433 -3801. Sin. -rely,' F ,,.. JUN 3 0 2011 JRWi o President 601 W. 5 Avenue, Suite 310, Anchorage, AK 99501 (907) 334 -6745 * (907) 334 -6735 fax Cook Inlet Energy, LLC 4 of Reworking operations and Request for Suspen•of Operations — ADL 390368 June 27, 2011 Page 2 of 2 Cc: William Barron, Director, Alaska Division of Oil & Gas Wendy Woolf, Petroleum Land Manager, Alaska Division of Oil & Gas Dan Seamount, Chair, Alaska Oil & Gas Conservation Commission • [E A[LtisE,[- SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276-7542 June 24, 2011 Mr. David Hall Cook Inlet Energy 601 West 5 Avenue Anchorage, AK 99501 orDJU+ Re: Safety Valve System Testing Dear Mr. Hall: The Alaska Oil and Gas Conservation Commission (Commission) finalized and readopted revisions to well safety valve system (SVS) regulations — 20 AAC 25.265 — that became effective on December 3, 2010. In conjunction with those regulations, the Commission also published Industry Guidance Bulletin 10 -004 ( "Safety Valve Systems ") dated December 16, 2010. Weblinks to both documents were provided to Cook Inlet Energy (CIE) on December 30, 2010 by electronic mail with a request to establish a single - point -of- contact and to identify for the Commission the months CIE intends to test its well SVS. A response was requested by January 21, 2011. A second reminder was provided to CIE on February 11, 2011. CIE has not responded to the Commission's request. A review of Commission production records indicates the following CIE wells have produced during the first six months of the effective date of the readopted SVS regulations and therefore the SVS should have been tested not later than June 3, 2011: - West McArthur River Unit 1A (PTD 1951180) - West McArthur River Unit 2A (PTD 1931550) - West McArthur River Unit 5 (PTD 1980470) - West McArthur River Unit 6 (PTD 200107) - Kustatan Field 1 (PTD 200153 - West Forelan The Commission requests the following not later than July 8, 2011: 1) SVS tests performed on the above - listed wells since December 3, 2010; the Commission provided CIE the proper SVS test report forms by electronic mail dated June 1, 2011; 2) CIE's schedule for testing wells in the West McArthur River, West Foreland, Kustatan, and Redoubt fields; 3) CIE single - point -of- contact for SVS matters. Mr. David Hall • • June 24, 2011 Page 2 of 2 You are reminded that a functional SVS must be installed, maintained and tested as described in 20 AAC 25.265 for all completed wells except water source wells, disposal injectors, observation wells, and those wells that are isolated from the flowline. Performance testing of the well SVS must be conducted semi - annually. Depending on well location, the Commission must be notified at least 24 to 48 hours prior to testing for an opportunity to witness those tests. Failure to comply with the SVS test requirements may result in the Commission pursuing enforcement action. Please direct any questions regarding SVS testing requirements to Jim Regg at 907 - 793 -1236. Sincerely, (14 A t ;t&e49z..e._._____ Cathy P Foerster Commissioner • • LAMA SEAN PARNELL, GOVERNOR Q ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276-7542 David Hall S CEO c 9 \ 00 Cook Inlet Energy 601 W 5th Avenue, Suite 310 Anchorage, AK 99501 Re: Kustatan Field, Kustatan Gas Pool, Kustatan Field #1 Sundry Number: 311 -121 Dear Mr. Hall: A teltia Hall APR 1 3 2.0 Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holida weekend. ( 4 , ,,/ r DATED this I(/ day of April, 2011. Encl. • • Cook Inlet Energy_ RECE, VED APR 12 2u April 11, 2011 ska & 6a. Cans. Corn* Mr. Dan Seamount, Chair . -t�?t grNle Skin Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue, Suite 100 Anchorage, Alaska 99501 -3539 Re: KF #1 Additional perforation and gravel pack screen installation Dear Mr. Seamount, Cook Inlet Energy plans to add perforations at 5844' -5850' on KF #1 in the Kustatan Field of Cook Inlet in order to enhance gas production from the upper Tyonek sands and / to install a gravel pack screen across the sliding sleeve at 5143' to minimize sand production from this zone. Both operations will be performed using an e-line unit. The general work procedure is attached. The estimated date for commencement of this work is April 3 011. Attached p lease find a completed F orm 10 -403 for t he w ork, a n out line pr ocedure, a current wellbore schematic, a proposed wellbore schematic. If you have any questions, please contact me at 334 - 6745. Sincerely, /owe . ",/ il etei/e t David Hall, CEO, Cook Inlet Energy Attachments: 10 -403 Application for Sundry Approvals Outline Procedure Current Wellbore Schematic Proposed Wellbore Schematic . RECEIVE • STATE OF ALASKA 4-12 ,1( 1 ALASKA OIL AND GAS CONSERVATION COMMISSION Wash & Sas Cans. COUrlisSgq APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 I °ncror ge 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate el • Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Install gravel pack screen 0- 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Cook Inlet Energy Development 0 • Exploratory E 200 -153 • 3. Address: Stratigraphic ❑ Service 6. API Number: 601 W 5th Avenue, Suite 310, Anchorage, AK 99501 50- 133 - 20496 -00 • 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: pi /a- Spacing Exception Required? Yes ❑ No 0 i Kustatan F ' y am • ( #1 `/• •// 9. Property Designation (Lease Number): 1 10. Field /Pool s): ADL 387023 • kihr! ustatan Field „L 6 A 1 r • a •// 11. PRESENT WELL CONDITION SUMMA Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12,300 ' 12,300 . 6192' 6192' Bridge Plug @ 6192' None Casing Length Size MD / TVD Burst Collapse Structural Conductor 120' 20" 120' 120' N/A N/A Surface 1,820' 13 3/8" 1,820' 1,820' 3450 psi 1,950 psi Intermediate 6,500' 9 5/8" 6,500' 6,500' 6,870 psi 4,750 psi Production Liner 5,988' 75/8" 12,300' 12,300' 6,890 psi 4,790 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 5204' -5260' 5204' -5260' 2 7/8 ", 6.5# L-80 5344 5353' -5365' 5353' -5365' i 5370' -5380' 5370' -5380' Packers and SSSV Type: Packer: 9 -5/8" packer # 1 w /sealbore Packers and SSSV MD (ft) and TVD (ft): Packer # 1 @ 5291' MD/TVD 9 -5/8" packer #2 Packer # 2 @ 5097' MD/TVD 12. Attachments: Description Summary of Proposal 1i 13. Well Class after proposed work: Detailed Operations Program ❑ BOP S ❑ Exploratory El Development 1l Service El 14. Estimated Date for 4 3/ 11 15. Well Status after proposed work: Commencing Operations: ., Oil ❑ Gas 0 WDSPL ❑ Suspended El 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Natasha Sachivichik 264 -6116 Printed Name David Hall Title CEO Signature .. t � ( J I Phone Date s #.( 44 /e 907- 334 -6745 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31 1- \ (� Ql Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: 1, t 7 i . i APPROVED BY / Approved by: e OMMISSIONER THE COMMISSION Date: 4 7. Form 10 -403 Revised 1/2010 Submit in Duplicate RBDMS APR 1 1011 IVA R I G I A sz , L' // • • -=-, ate., Cook Inlet Energy Kustatan Field #1 Additional Perforations and Gravel Pack Screen Summary Procedure 1. Mobilize a -line unit to Kustatan Field -1 well 2. Check for pressure on the wellhead. 3. Rig up the a -line equipment. 4. Run in hole with perf guns. Correlate, tie -in, perforate 8'- interval at 5844' - 5850' MD /TVD. • 5. POOH with guns. 6. Pick up wireline- deployable gravel pack screen and run to 5143'. The screen will be set across the sliding sleeve. Install the screen according to Weatherford procedure. 7. POOH with a -line. 8. Rig down a -line equipment. 9. Install production tree. Turn over well to production crew. . • • • Kustatan Field #1 Current Wellbore Diagram KB =11.1 ft. r v'∎ 20" 133# K -55 @120' MD 4. + ,. Methanol Injection `? " 13 3/8" 68# K -55 BTC @ 1820' MD Mandrel @ 2980' MD 41 Pk+ + i 2 7/8" 6.5# L -80 EUE Tubing +* + 4* + +41 EN + 2 7/8" X Nipple © 5024' MD P +* I 0 + 9 5/8" Packer @ 5097' MD 2 7/8" Sliding Sleeve @ 5143' MD I+; PI + 56' TCP Gun on Y Block @ 5,185' +1 Pk 70' 2 7/8" Blast Joints @ 5192' +- 1 + � * 9 5/8" Packer w /Seal Bore © 5291' MD 2 7/8" XN Nipple © 5315' MD " j + 41' TCP Gun assembly starts @ 5344' N+ ;k+ - New Gas Perfs: *� —� N. Bridge Plug @ 192�11D L__ 5204 -5260' MD * .1%:. 5353 -5365' MD + Top of 7 5/8" Liner @ 6312' MD 5370 -5380' MD *'4 *�; *0 ' +,+ + + Bull Plug @ 5385' {* * _ ` 9 5/8" 47# L -80 BTC @ 6500' MD Disposal Perfs: 6270 -6304' MD 6312 -6475' MD + PBD @ 6743' MD (8/14/03 CTU) 6750 -6800' Lie ++► iie + v e ++ An A n + v .4 .4 t : .r1: 7 5/8" 29.7# L -80 STL /FL4S @12,300' MD I • Ku\ƒatan Field #1 Proposed Weilbore Diagram KB= 11.If. st . 20" 133# K-55 @120' MD lit Methanol | %edbn ® 13 &ƒ88 K-55 BTC A 182E MD Mandrel @ 298E MD oi +4 k 27 8" 6.5# L80EUE Tubing - +4 titv 7/8" X 0 2 9 5/8" Packer g 5097' MD 27ƒSdingSleee @514$9D 56' TCP Gun on Y Block g 5,185' _____ . 70' 2 7/8" Blast Joints @ 5192' „ Pmp sed Sands men A 544$ y D ( ! 111 sliding sleeve oi 0, I 9 &ƒ Packer w Se* Bore p 5291' MD 27/8 XN Nipple g 5315 MD NE Existing GasPerf: 41' TCP Gun assembly starts @ 5344' ,;,.. II 0 5204 -5 BC MD t 5353-538£ MD / Proposed Pew A 58 4' -5 50' MD g 5370-5380' MD » s Bridge Plug @ 6192' MD Top of 7 5/8" Liner @ 6312' MD 7 F Bull Plug @ 5385' 9 5/8" 47# L-80 BTC @ 6500' MD A ce Disposal Perf : 6270-6304' M D « 6312-6475' MD 1 E PBD A 6743' MD (8/14/03 CTU) 6750- 6800'M O ¥ e +1 ee + e + e ¥ e ke � � + ¥ : 75/8" 29.7 #L80 STL/FL S @12,3O0' MD • • s ozic SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMAIISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 David Hall CEO Cook Inlet Energy 601 W 5th Avenue, Suite 310 AANNED FEB 6 1 2011 Anchorage, AK 99501 Re: Kustatan Field, Kustatan Gas Pool, Kustatan Facility #1 Sundry Number: 311 -022 Dear Mr. Hall: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. Please be reminded of the pressure monitoring and data reporting requirements of Conservation Order No. 566, which is attached. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. . cere 4d Nor mi ioner DATED this / day of February, 2011. Encl. i VOA • 2v1 + " t,t t (zocc STATE OF ALASKA W ALASKA OIL AND GAS CONSERVATION COMMISSION IAN 2 7 2011 APPLICATION FOR SUNDRY APPROVALS A �^f (pp gay chi+ n 5,n 1 a G5.$ { . �,"W. @yiSS101, 20 AAC 25.280 y F"�" 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 Chattfttorawl Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Coiled Tubing cleanout 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Cook Inlet Energy Development 0 Exploratory ❑ 200 -153 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 601 W 5th Avenue, Suite 310, Anchorage, AK 99501 50- 133 - 20496 -00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No 0 Kustatan Facility #1 9. Property Designation (Lease Number): 1 10. Field/Pool(s): ADL 387023 f t4±at.C/.N. Kustatan Field .. Cpt.s w4A 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12,300 12,300 6192' 6192' Bridge Plug @ 6192' None Casing Length Size MD / TVD Burst Collapse Structural Conductor 120' 20" 120' 120' N/A N/A Surface 1,820' 13 3/8" 1,820' 1,820' 3450 psi 1,950 psi Intermediate 6,500' 9 5/8" 6,500' 6,500' 6,870 psi 4,750 psi Production Liner 5,988' 7 5/8" 12,300' 12,300' 6,890 psi 4,790 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 5204' -5260' / 5204' -5260' 2 7/8 ", 6.5# / L -80 5344 5353' -5365' 5353' -5365' 5370' -5380' 5370' -5380' Packers and SSSV Type: Packer: 9 -5/8" packer # 1 w /sealbore Packers and SSSV MD (ft) and TVD (ft): Packer # 1 it 5291' MD/TVD / 9 -5/8" packer #2 Packer # 2 © 5097' MD/TVD 12. Attachments: Description Summary of Proposal - 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch [l 7 . Exploratory ❑ Development 0 Service ❑ 14. Estimated Date for 2/1 /201 15. Well Status after proposed work: Commencing Operations: Oil ❑ Gas 0 WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Natasha Sachivichik 264 -6116 Printed Name David Hall Title � — 2 _ Z `< CEO Signature C / Phone Date ,./ ,��/ 907- 334 -6745 COMMISSION USE ONLY `� Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 311- ()p- Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: I p ..- (40 , % APPROVED BY Approved by: Ir( Cs MISSI — O,NER THE C M ISSION Date: 01r / fff��� DAM FED a Z Form 10 -403 Revised 1/2010 O l J 1 G 1 NA i i t 7n Duplicate • • Baker Hughes/BJ Services Coiled Tubing Services Kenai, AK Cook Inlet Energy West McArthur Field Kustatan #1 Obiective Cleanout wellbore sand influx to 5320' while using motor and 2.35" OD mill and open 2.31" ID profiles @ X- nipple (5024') and sliding sleeve (5143'). After cleanout and profile opening slickline unit will remove prong & plug assembly and then well will be jetted to production using CTU nitrogen lift. Procedure DAY 1 1. MIRU BJCT. Rig up WH Assembly (WHA). WHA will consist of 2- 9/16 ", 5M X 3- 1/16", 10M Spool, 3- 1/16 ", 10M Flow Cross and 3- 1/16 ", 10M Quad BOP. 2. Spot supply and flow back tanks as needed within bermed containment. 3. Load supply tank to 95% capacity with 3% KC1 solution (10.5 lbs KC1 /1 BBL H20). Vac Truck will be utilized to blend KC1 solution. Vac Truck will bring on water to 90% of maximum load capacity. Then vac truck to suction appropriate amount of KC1 from open bags per salt/water ratio as listed. Load will then be blown back and forth between supply tank and vac truck 2 — 3 times. Repeat as needed to fill supply tank to 95% capacity. 4. Spot Combo -Pump 5. Spot filtration skid inside bermed containment between supply tank and flow back tank. Insure bag filters are installed in all filter pods. Tie flow back tank to spare combo -pump centrifugal pump (C -pump) suction side using 3" cam lock hoses. Tie discharge side of C -pump to filtration skid using 3" cam lock hoses and then complete system by running 3" cam lock hoses to supply tank fill line connection. 6. Rig Combo -pump to CTU and WH kill line. Rig in pumping and flow back iron as needed. 7. Pickup(PU) injector and make up 1 -1/4" external CT connector. 8. Pull test CT connector to 10,000 lbs. 9. Load CT w/ fluid. Pressure test CT connector to 3500 psi. 10. Install pig catcher. Nipple up injector to WHA. 11. Pressure test pumping iron, choke manifold and flow back iron (200 psi/3000 psi). Pressure test BOP (200 psi/4500 psi) 12. Load pig in CT. Circulate pig to pig catcher taking returns to flow back tank. 13. Remove injector from WHA. Remove pig catcher and pig. Install X -over and jetting nozzle. 14. Nipple injector back to WHA. • • 15. Pump BB TO Nominal of 50/50 methanol -water blend to CT. Purge CT w/ N2 taking f ui returns to flow back tank. 16. Remove injector from WHA. 17. Chain 4nd secure injector. 18. Top ofuid supply tank w/ 3% KCL water to 95% tank capacity. 19. Secure well site. DAY 2 20. Pickup injector & lubricator as needed to cover BHA. 21. Make up milling BHA. Tool string will consist of 1 -1/4" external connector, 1" MT box X 1 -1/2" MT pin X -over, 2 -1/8" BOT DFCV, BOSS, Circ Sub, Jars, PDM & 2.35" Step Mill. 22. Nipple up Injector and lubricator to WHA. 23. Load CT with fluid. Pressure test WHA (200 psi/3000psi). 24. RIH @ 50 FPM pumping minimum rate fluids to suspected top of fill @ 4550'. BE AWARE OF MILL OD = 2.35" CLOSE TOLERANCE TO 2 -7/8 ", 6.5 PPF TUBULAR NOMINAL DRIFT ID = 2.347 ". DO NOT STAY IN ANY TIGHT SPOTS TRYING TO WORK THROUGH PRIOR TO REACHING TOP OF FILL WITHOUT CONSULTING AND NOTIFYING COOK INLET ENERGY(CIE) COMPANY REP. Establish full returns at surface before proceeding to Step 24. 25. PU 10' and increase pump rate to 1.5 BPM (2 -1/8" PDM Max Rate = 1.75 BPM). RIH @ 15 FPM washing /milling fill. Wash/mill fill in 50' sweeps maintaining 15 FPM RIH & POOH. 26. After establishing top of X- nipple profile @ 5024' complete a 75' sweep prior to proceeding with profile milling. 27. Time mill 2.31" ID profile. 28. With profile opened to 2.35" and verified by CT movement & weight gauge perform 4 complete sweeps of 10' across profile @ maximum of 5 FPM before proceeding forward with fill removal. 29. Repeat Step 24 to top of Sliding Sleeve(SS) @ 5143'. 30. Repeat Step 25 @ 5143'. 31. Repeat Step 26 @ 5143'. 32. Repeat Step 27 @ 5143' after CT movement & weight gauge verify upper and lower SS profiles have been opened to 2.35 ". 33. Repeat Step 24 for 20' below SS lower profile. 34. Circulate all fill to surface while maintaining 1.5 BPM pump rate while making 100' sweeps @ 5 FPM. Circulate minimum of 1 bottoms up (19.4 BBL) but DO NOT stop circulating & sweeping until surface returns are clean of solids. 35. POOH @ 15 FPM & 1.5 BPM to 5000' 36. Stop fluid pump and increase POOH rate to 50 BPM. POOH to surface. IF TEMPERATURES ARE A CONCERN FOR CT FREEZING POOH PUMPING MIN RATE FLUIDS. 37. With CT @ surface shut in WH @ master valve. Loaded column of fluid in well = / 2300 psi @ 5143'. • • • 38. Pump 2 BBL of 50/50 methanol -water and follow w/ N2 to purge /freeze protect CT. Rig down injector /lubricator. Lay down BHA & lubricator. 39. Set down injector and chain and secure. 40. Secure well site. Turn over well to CIE and Pollard for SS manipulation run. DAY 3 1. Pickup injector & lubricator as needed to cover BHA. 2. Make up washing BHA. Tool string will consist of 1 -1/4" external CT connector, 1" MT BOX X 1 -1/2" MT Pin X -over, BOT 2 -1/8" DFCV, BOSS, Circ Sub, PDM and 3' of Wash Over Shoe w/ internal indicator pin. 3. Nipple up Injector and lubricator to WHA. 4. Load CT with fluid. Pressure test WHA (200 psi/3000psi). 5. RIH @ 50 FPM pumping minimum rate fluids to 4550'. 6. Increase fluid rate to 1.25 BPM and wash to top of prong @ 5315' @ 25 FPM. 7. PU 5' and circulate bottoms up until returns at surface are clean. 8. Stop fluid pump and POOH 100 BPM. POOH to surface. IF TEMPERATURES ARE A CONCERN FOR CT FREEZING POOH PUMPING MIN RATE FLUIDS. 9. Pump 2 BBL of 50/50 methanol -water and follow w/ N2 to purge /freeze protect CT. Rig down injector /lubricator. VERIFY THAT INTERNAL INDICATOR PIN IN WASHOVER SHOE IS BENT. BENT PIN VERIFIES THAT WASHOVER SHOE CLEANED OVER PRONG TOP. Lay down BHA & lubricator. 10. Set down injector and chain and secure. 11. Turn over well to CIE & Pollard for prong & plug pull operations. 12. Pickup injector & lubricator as needed to cover BHA. 13. Make up jetting BHA. Toolstring will consist of 1 -1/4" external CT connector, 1" MT BOX X 1.125" SA Pin X- over,1 -3/4 " DFCV, BOSS & Jetting Nozzle. 14. Nipple up Injector and lubricator to WHA. 15. Load CT with fluid. Pressure test WHA (200 psi/3000psi). 16. RIH @ 50 FPM pumping minimum rate fluids to 4550'. 17. Open WHA and RIH @ 75 FPM pumping min rate fluids to 4550' 18. Increase fluid rate to 1.25 BPM and wash to Ported Sub @ 5320' @ 25 FPM. 19. Circulate one bottoms up. 20. Start N2 @ 250 SCFM and jet well dry. Keep CT moving via 200' sweeps, @ 10 FPM, while jetting to insure CT remains free. 21. Jet well until production comes on. Adjust N2 rate as needed to carry fluids while allowing well to flow to surface. 22. With WHP increasing stop N2 & sweeps and POOH. 23. Shut in WH @ master valve. . 24. RDMO. , , • 0 Kustatan Field #1 Current WChhore Diagram KB =11.lf . 20" 133 # K-55 @120' MD ? Methanol Injection ~ 13 3/2 68# K-55 BTC @ 1820' MD Mandrel o adel»29E MD . o v k r o o 22m 6.5 #D8 EUE Tubing / I .0 o : " k y 22mX Nipple #50$9O 222 SahgSleee@514'MD 9 »mPakr#509'MD 56' TCP Gun on Y Block » 5,48E : / 7'2 28" Blast Joints » 5192' + ME . g@mPakrwSemB?g591' MD � ::, 22yXN Nipple ©5315' MD : 41' TCP Gun assembly stars! » 5344' % : New Gas Perfs: q Bridge Plug © 6192' MD 5204-5260' M D 5353-5365' MD 4 ¢ Top of 7@mbnE»612' MD 5370-5380' MD q 7t: ' `* Bull Plug a 5385' ; ~ 9 5/8" 47# 68 BTC » 6500' M D Disposal Perfs: k 6270-6304' MD A 6312-6475' MD A PBD 46 4' MD (8/14/03 CTU) 6750-6800' MD • 4 o. % . • ¥ k • ^ 7&»29.7 #5,8 STRFL S @12,300' MD • • , ' ` ` • 0 Kustatan Field #1 Proposed Weil O e Diagram KB =11.lf . « 20" 133# K-55 @12 'M D . Methanol Injection . 13 3/8" 68# K 55 BTC @ 18 0' MD Mandrel @ 298 E MD f • « • 22m ES #DaoEUE Tubing k $ : 7 $ g@mPakr@509'MD 56' TCP Gun on Y Block @ 5,185' / 7'2 28" Blast Joints @ 5192' 2 Ell 9RmPakrwSemB?g52gfMD ¥ ; . 22yXN Nipple »5315' MD - � +sr 41' TCP Gun assembly starts 5344' # 5 4' � • ƒ '.� / Bridge mug » 6192' MD New Gas Persl: : s 5204-5260' M D #. 5353-5365' MD Top of 7 5/8" Liner » 6312' MD 5370-5380' MD Nk 4,- • . » Bull Plug % 5385' v 9 5/8" 47# L-80 BTC a 6500' M D Disposal Perls: k 6270-6304' M D & 6312-6475' MD ` % PBD A 6743' MD (8/14/03 CTU) • 6750-6800' MD % • . • . • . • / . & o. / • 75/8" 2$7 L-80STRFL S @12,300' MD STATE OF ALASKA 9 1 u ALASKA OIL A ND GAS C ONSERVAT1 0 0 N COMMISSION APPLICATION FOR SUN APPROVALS 20 AAC 25.280 1 1. Type of Request: Abandon 111 Plug for Re ❑ Perf orate New Po ol Repair Well Q Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate El Tubing ❑ Time Extension 111 Operations Shutdown ID Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Coiled Tubing cleanout . 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Cook Inlet Energy Development g 1F 4 Exploratory ❑ 200 -153 3. Address: Stratigraphic ❑ Service ,0-- 6. API Nu 'ber: 601 W 5th Avenue, Suite 310, Anchorage, AK 99501 50- 133 - 20496 -00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No 0 K -tatan Facility #1 9. Property Designation (Lease Number): 1 10. Field / Pool(s): ADL 387023 l l(sa5tai rug,, I Kustatan Field 1 ai w6k 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plus (measured): Junk (measured): 12,300 •- 12,300 • 12,259 12,259 ( None None Casing Length Size MD ' ( Burst Collapse Structural Conductor 120' 20" 120' 120' N/A N/A Surface 1,820' 13 3/8" 1,820' 1,820' 3450 psi 1,950 psi Intermediate 6,500' 9 5/8" 6,500' 6,500' 6,870 psi 4,750 psi Production /"7 Liner 5,988' 75/8" 12,300' \) 12,300' 6,890 psi 4,790 psi Perforatio pth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 1 ,480' - 13,050 9,4 = 9,599' 1/2" L-80 12,445' Packers and SSSV Type: Pack : TIW Type SSBB, SSSV: None ers and SSSV MD (ft) and TVD (ft): Packer .10 12;41'5' 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development E Service ❑ 14. Estimated Date for 4/24/2010 , 15. Well Status after proposed work: Commencing Operations: j > Oil 0 Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to e best of my knowledge. Contact Natasha Sachivichik 264 -6116 Printed Name David Hall Title / r .2�- / 1 CEO Signature / / I ne Date j ee 907 - 334 -6745 COMMISSION USE ONLY Conditions of approval: Notify Commission that a representative may witness Sundry Number: V'' 4)4Q Plug Integrity ❑ BOP T -.t ❑ Mechanical Integrity Test ❑ Location Clearance ❑ r., rz, i 't, ,' Other: JAN 2 i 2.011 .1.14Ae gig _. GiZfi& C'': 7 , .SSIOn Subsequent Form R wired: 'rnc oik,ge / '' APPROVED BY Approved,,by: COMMISSIONER THE COMMISSION Date: Form 10 -403 Revised 1/2010 0 R I G I NA S ubmit in Duplicate `} Cook Inlet Energy RECEIV IAN 2 5 2011 !1 ito '* 'GPS Cons. Co "G'i1ission January 24, 2011 Inrfiorhge Mr. Dan Seamount, Chair Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue, Suite 100 Anchorage, Alaska 99501 -3539 Re: KF #1 Coiled Tubing Cleanout Dear Mr. Seamount, Cook Inlet Energy proposes to work over Well KF #1 in the Kustatan Field of Cook Inlet in order to resume gas production from the upper Tyonek sands. The work to be performed will include coiled tubing cleanout of wellbore sand influx to 5320', milling out and open 2.31" ID profiles at X- nipple (5024') and sliding sleeve (5143'). After cleanout and profile opening slickline unit will remove prong & plug assembly and then well will be jetted to production using CTU nitrogen lift. The detailed work procedure is attached. The estimated date for commencement of this work is February 1, 2011. Attached please find a completed Form 10 -403 for the work, an outline procedure, a current wellbore schematic, a proposed wellbore schematic. If you have any questions, please contact me at 334 -6745. Sincerely, David Hall, CEO, Cook Inlet Energy Attachments: 10 -403 Application for Sundry Approvals Outline Procedure Current Wellbore Schematic Proposed Wellbore Schematic P • From: Saltmarsh, Arthur C (DOA) Sent: Monday, March 09, 2009 11:08 AM To: Maunder, Thomas E (DOA); Seamount, Dan T (DOA); Davies, Stephen F (DOA); Roby, David S (DOA); McMains, Stephen E (DOA); Williamson, Mary 3 (DOA); Regg, James B (DOA); Fleckenstein, Robert 3 (DOA); Colombie, Jody 3 (DOA); Gary Carlson; Norman, John K (DOA); Foerster, Catherine P (DOA); Laasch, Linda K (DOA); longmereftverizon.net Subject: FW: Pacific Energy files chapter -11, it's official!!! FYI. PACIFIC ENERGY RESOURCES LTD. ;;;A,dt ME.1 M. - :', ?Kg 111 West Ocean Blvd., Suite 1240 Long Beach, California 90802 Telephone: (562) 628 -1526; Fax: (562) 628 -1536 Files for Chapter 11 to Facilitate a Restructuring LONG BEACH, CALIFORNIA, Monday, March 9, 2009 - - Pacific Energy Resources Ltd. (the "Company ")(TSX:PFE) announces today that it and its wholly owned subsidiaries have filed voluntary petitions for reorganization under . Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware. The filing was precipitated by the dramatic decrease in the market price of oil over the past five months. Combined with the Company's pre- existing level of debt related to past acquisitions and poor capital market conditions, the Company's liquidity and cash flow is insufficient to operate its business and invest in its oil producing assets to increase production. Faced with these constraints, the Company and its subsidiaries filed petitions for reorganization under chapter 11 to facilitate access to an immediate source of liquidity as it works to restructure its debt. In connection with the filing, the Company is seeking customary authority from the Bankruptcy Court that will enable it to continue operating its business in the ordinary course of business. The requested approvals include requests for the authority to make wage and salary payments and continue various benefits for employees. In addition, the Company has negotiated a commitment for $40 million in debtor -in- possession ( "DIP ") financing. The DIP facility wraps and replaces two of the Company's three asset -based credit facilities and is being provided by the lenders of the two credit facilities that are being replaced. Upon Court approval, the DIP financing combined with the Company's operating revenue will provide sufficient liquidity to fund working capital, meet ongoing obligations and ensure that normal operations continue without interruption during its restructuring. About Pacific Energy Resources Pacific Energy Resources Ltd. is an oil and gas exploration and production company based in Long Beach, California, U.S.A. Additional information relating to the Company may be found on SEDAR at www.sedar.com. The Company's web site is www.PacEnergy.com. ON BEHALF OF THE BOARD OF DIRECTORS • PACIFIC ENERGY RESOURCES LTD. Pacific Energy Resources Ltd. David Hall 310 K. Street, Suite 700 Alaska Operations Manager Anchorage, AK 99507 Main: 907 - 868 -2133 Office: 907 - 258 -8600 Cell: 907 -317 -8239 Fax: 907- 258 -8601 dmhall@pacenergy.com pacenergy.com www.pacenergv.com ill • �. < , , SARAH PALIN, GOVERNOR i DEPARTMENT OF NATURAL RESOURCES 550 WEST 7 AVENUE, SUITE 800 ANCHORAGE, ALASKA 99501 -3560 DIVISION OF OIL AND GAS PHONE: (907) 269 -8800 FAX: (907) 269 -8938 CERTIFIED MAIL RETURN RECEIPT REQUESTED January 7, 2008 Darren Katie Pacific Energy Alaska Operating, LLC RECEIVED 111 West Ocean Blvd., Suite 1240 Long Beach, CA 90802 JAN 1 0 2008 RE: ... -A , 39036:8. Thii d Pl of Develo menl>Appr4ued ' --- rAinkal$4 Dear Darren, Anchorage On November 20, 2007, the Division of Oil and Gas (Division) received the proposed Third Lease Plan of Development (Third POD) for ADL 390368, submitted by Forest Oil Corporation. The proposed development plan is to produce all recoverable gas from the Kustatan Field #1 well and then convert the well back to a Class II waste disposal well, DOO - ■ 53 The Division fords the Third POD protects the public interest. I approve the proposed 3 POD for ADL 390368 for the period November 21, 2007 through November 20, 2008. Under Paragraph 10 of the lease, the Fourth POD for ADL 390368 will be due in this office on or before November 20, 2008. A person affected by this decision may appeal it, in accordance with 11 AAC 02. Any appeal must be received within 20 calendar days after the date of "issuance" of this decision, as defined in 11 AAC 02.040 (c) and (d), and may be mailed or delivered to Thomas E. Irwin, Commissioner, Department of Natural Resources, 550 W. 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to 1- 907 - 269 -8918; or sent by electronic mail to dnr.appeals(a),alaska.gov. This decision takes effect immediately. If no appeal is filed by the appeal deadline, this decision becomes a final administrative order and decision of the department on the 31st day after issuance. An eligible person must first appeal this decision in accordance with 11 AAC 02 before appealing this decision to Superior Court. A copy of 11 AAC 02 may be obtained from any regional information office of the Department of Natural Resources. Sincerely, Kevin R. Banks Acting Director cc: John K. Norman, AOGCC Nan Thompson, DOG Cammy Taylor, DOG Julie Houle, DOG Laura Silliphant, DOG Jack Hartz, DOG "Develop, Conserve, and Enhance Natural Resources for Present and Future Alaskans." __ • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage Alaska 99501 -3539 Re: Forest Oil Corporation, as Operator of ) Kustatan Field No.1 Well; Spacing and ) Pooling Requirements Enforcement Action ) AOGCC Order No. 44 October 9, 2006 DECISION AND ORDER p D b -* I* 3 On September 18, 2006, the Alaska Oil and Gas Conservation Commission ( "Commission ") issued a Notice of Proposed Enforcement Action ( "Notice ") under 20 AAC 25.535(b), finding that Forest Oil Corporation ( "Forest ") apparently violated statewide spacing and pooling requirements by completing the Kustatan Field No. 1 Well ( "KF #1") as a gas well and beginning regular production from this well. The Notice proposed assessing Forest with civil penalties for both violations. Forest did not respond in writing to this proposed enforcement action within the time period stipulated in 20 AAC 25.535(c) and therefore is considered to have accepted the proposed Commission action. A. Summary of Proposed Enforcement Action In its Notice, the Commission identified two apparent violations by Forest, specifically failure to comply with 20 AAC 25.055(a)(2) and 20 AAC 25.055(b). The violations consisted of Forest's completion of the KF #1 gas well within 1,500 feet of a property line where ownership changes and subsequent regular gas production from a property smaller than a governmental section without prior approval from the Commission. The Commission proposed the following civil penalties under AS 31.05.150(a): Other Order 44 • • October 9, 2006 Page2of4 (1) $100 per day for each of 101 days for violating 20 AAC25.055 (a)(2) from November 14, 2005, through February 22, 2006, inclusive; and (2) $100 per day for each of 94 days for violating 20 AAC 25.055(b) from November 21, 2005, through February 22, 2006, inclusive. The combined civil penalties proposed by the Commission total $19,500. B. Spacing and Pooling Requirements Pursuant to its statutory authority under AS 31.05.030, the Commission has adopted regulations concerning well spacing and pooling requirements to prevent waste and protect correlative rights. In absence of a Commission order an operator may not complete or produce a well in a manner that violates these regulatory requirements. C. Violation On February 22, 2006, the Commission became aware that Forest had completed the KF #1 well as a gas well on November 14, 2005, and that Forest had commenced regular production from this well on November 21, 2005, without a Commission order authorizing such actions. D. Corrective Actions In its letter dated February 23, 2006, the Commission ordered Forest to shut in the KF #1 well immediately. Forest complied with this order on or about February 23, 2006. By application dated February 24, 2006, Forest asked the Commission to waive the requirements of 20 AAC 25.055(a)(2) and 25.055(b) to allow them to return the well to regular production. After receiving written notice of non - objection from all affected landowners, the Commission issued an interim order on March 17, 2006, authorizing Forest to return the well to production. On Other Order 44 • ° October 9, 2006 Page 3 of 4 August 24, 2006, the Commission issued Conservation Order No. 566, granting Forest's requested exceptions to Commission regulations and establishing pool rules for the Kustatan Field #1 Gas Pool. E. Findings and Conclusions For the reasons stated above, the Commission finds that Forest violated statewide spacing and pooling requirements, and concludes that the proposed civil penalties are an appropriate penalty for these actions and a deterrent to future violations of Commission regulations and orders. In this matter, the Commission has assessed less than the maximum civil penalties allowed by AS 31.05.150(a), because (1) there is no evidence which would indicate that Forest acted in bad faith, and, (2) Forest's regulatory violations did not cause injury to the public. NOW THEREFORE IT IS ORDERED THAT: Within 30 days from the date of this Decision and Order, Forest shall pay to the Commission a civil penalty in the amount of Nineteen Thousand Five Hundred Dollars ($19,500). Done at Anchorage, Alaska this 9 day of October 2006 d OLI, 44 . F an Chai . � � A : � - a Oil • - s Conservati e • Commission • aniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission Cathy P. Foe ster, Commissioner Alaska Oil and Gas Conservation Commission R ¢ Forest OiI Corporation Alaska Division ,g ib 310 K Street, Suite 700 o i Anchorage, Alaska 99501 Phone: (907) 258 -8600 Fax: (907) 258 -8601 DATA TRANSMITTAL Date: July 26, 2006 To: AOGCC From: Diane Provost for Paul Winslow ATTN: Steve Davies, Petroleum Geol Forest OiI Corporation 333 W Seventh Ave, Ste 100 310 K Street, Suite 700 Anchorage, AK 99501 Anchorage, AK 99501 Phone: 907- 793 -1224 Phone: 907 -868 -2161 FAX 907 - 258 -8601 KUSTATAN FIELD #1 API: 50- 133- 20496-00 -00 PERMIT: 200-153 Quantity Description Depth 1 Dipole Shear Sonic Array Induction Tool Gamma Ray, Caliper 6508 -1820 1 Array Induction, Density Neutron, Gamma Ray, Caliper, Platform Express 6508 -1820 To acknowledge receipt, please return a signed copy to Forest Oil Corporation at the above address Received By: t . Returned to Forest Oil �I / / Date n I •ccepted By: (�/6/�(-� l 2Oo — /5 Subject: Forest's Requested Confidentiality for Information from Public Domain Wells From: Stephen Davies <steve_davies @admin.state.ak.us> Date: Thu, 06 Jul 2006 15:50:31 -0800 To: JDArlington@forestoil.com BCC: Camille 0 Taylor <cammy_taylor@law.state.ak.us >, John Norman <john norman @admin.state.ak.us >, Daniel Seamount <dan seamount @admin.state.ak.us >, Cathy P Foerster <cathy foerster @admin.state.ak.us> Jim, Could you handle this inquiry, or pass it along to someone who can? Attached are transmittal letters submitted by Forest for information from the West Foreland 1 and Kustatan Field 1 wells. Each of these transmittal letters contains a statement requesting, under statute AS 31.05.035, that confidentiality be extended to all information listed on each transmittal. Neither of these wells are confidential. In order for the Commission to come to a decision concerning the confidentiality of Forest's submittals, the Commission requires a detailed justification for each item as to why it should be considered confidential under AS 31.05.035. Could you please provide these justifications? Sincerely, Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission 907 - 793 -1224 Steve Davies Content -Type: application/pdf 060706 Forest Transmittal_Letters.pdf Content- Encoding: base64 Forest Kustan #1 (200 -153) Subject: Forest Kustan #1 (200 -153) From: Thomas Maunder <tom_maunder@admin.state.ak.us> Date: Tue, 31 Jan 2006 15:24:27 -0900 To: Steve Davies <stevedavies@admin.state.ak.us> Since Forest requested confidentiality for the information submitted for the WMcRU 4D workover, I looked at the other wells that over there that Forest had worked over in 2005. In the Kustatan #1 LF file, there are a number of pages stamped confidential and on the transmittal sheet (page 29) Forest requests confidentiality for essentially everything they submitted similar to WMcRU 4D. I checked the new report for W. Foreland #1 161 -049) and I didn't find a transmittal sheet, although I will go back and look further. This is something we should probably discuss and notify Forest that confidentiality is not something ordinarily granted for new wellwork on a well that has already been released. I did talk to Rob and sent a message to Ted Kramer about the WMcRU 4D. What are your thoughts ?? Tom 1 of 1 7/5/2006 10:37 AM X t L } a ` ;.. as a l 1 LJ I i ( t.- ' 1 ) FRANK H. 1 ii SKI, GOVERNOR % ALASKA OIL AND GAS i ' 333 W. 7'H AVENUE, SUITE 100 CONSERVATION COMMISSION / ANCHORAGE, ALASKA 99501 -3539 / PHONE (907) 279 -1433 FAX (907) 276 -7542 February 23, 2006 Certified Mail Return Receipt Requested 7004 1160 0001 3621 2400 Mr. Leonard Gurule Senior Vice President Forest Oil Corporation 310 K Street, Suite 700 Anchorage, AK 99501 Re: Notice of Violation of Well Spacing and Pooling Requirements Kustatan Field No. 1 Dear Mr. Gurule: It has come to the attention of the Alaska Oil and Gas Conservation Commission ( "Commission ") that Forest Oil Corporation's ( "Forest ") operations at the Kustatan Field No. 1 gas production well ( "KF #1") do not comply with state regulations. The regulations require that Forest shut the well in immediately and not return it to production until such time as Forest has submitted a request for a spacing exception and that request has been approved by the Commission. Pertinent regulations and Forest's non - compliance are discussed below. Regulation 20 AAC 25.055(a)(2) Forest recompleted KF #1 as a gas well on November 14, 2005. Regulation 20 AAC 25.055(a)(2) requires well bores open to test or regular production for gas be located more than 1,500 feet from the nearest property line, unless the owner is the same and the landowner is the same on both sides of the property line. KF #1 is a vertical well that is located 1,468 feet from the west line and 3,443 feet from the north line of Section 4, T7N, R14W, Seward Meridian ( "Section 4 "). Unleased acreage lies less than 1,500 feet to the west, in adjacent Section 5, T7N, R14W, Seward Meridian. When Forest filed the Sundry Application for recompleting KF #1 as a gas well, Forest failed to notify the Commission that this recompletion required a spacing exception because of the adjacent, unleased acreage. Forest, as operator, is responsible for identifying the need for a spacing exception and for requesting such exception. Shut -in and Spacing Option Requirement Kustatan Field No. 1 February 23, 2006 Page 2 of 3 Regulation 20 AAC 25.055(b) Well KF #1 does not comply with two aspects of this regulation, which states: "a well may not... begin regular production of gas from a property that is smaller than the governmental section upon which the well is located, unless the interests of the persons owning the drilling rights in and the right to share in the production from the... section... have been pooled under AS 31.05.100." 1. Commission records indicate KF #1 produced gas for 10 days during November 2005, and then continuously during December 2005 and January 2006. By the end of January 2006, cumulative gas production from KF #1 exceeded 90 million cubic feet. It is our understanding that Forest has characterized this produced gas to the State of Alaska's Department of Natural Resources ( "AKDNR ") as being test production rather than regular production. It is also our understanding that gas produced from KF #1 is being utilized as fuel gas for a turbine or turbines in Forest's Kustatan Facility. Alaska Statute 31.05.170(14) defines regular production as: "...continuing production of oil or gas from a well into production facilities and transportation to market, but does not include short term testing, evaluation, or experimental pilot production activities that have been approved by permit or order of the commission." Continuous gas production for more than two months totaling more than 90 million cubic feet surpasses any reasonable notion of short-term testing or evaluation. Transportation of the gas produced from KF #1 to Forest's Kustatan Facility and use of that gas to supplant turbine fuel obtained from other sources constitutes market use rather than flow testing of the well for reservoir evaluation. Therefore, the Commission considers KF #1 to be in "regular production" of gas. 2. KF #1 is located within State of Alaska Lease ADL 390368, which occupies the southern two - thirds of Section 4. The northern one -third of Section 4 is depicted on AKDNR status plats having Cook Inlet Region Corporation as the landowner. It is our understanding that Forest does not have a pooling agreement in place for this section. Accordingly, Forest's production from KF #1 does not comply with the pooling requirement of Regulation 20 AAC 25.055(b). Because of the number and seriousness of these violations, the Commission may decide to fine Forest up to $5000 per day per violation for every day of non - compliance. Further, since the regulations require that Forest shut the KF #1 well in immediately and not return it to production until such time as Forest has submitted a request for a spacing exception and that request has been approved by the Commission, continuing to produce after receipt of this letter may constitute a willful violation of law pursuant to AS 31.05.150(b). Shut -in and Spacing liktion Requirement Kustatan Field No. 1 � ' February 23, 2006 Page 3 of 3 As provided by 20 AAC 25.535(c), within 15 days after receipt of this notification Forest may file with the Commission a written response that concurs in whole or in part with the proposed action described herein, requests informal review, or requests a hearing under 20 AAC 25.540. A request for hearing or informal review will not however eliminate the requirement that you immediately suspend the regular production of gas from this well. a , . Orman Chairman • o R E Forest Oil Corporation Alaska Division 2 6 200 19 ° uas Cons. Ti 16 310 K Street, Suite 700 0 i Anchorage, Alaska 99501 Anchorage Phone: (907) 258 -8600 Fax: (907) 258 -8601 DATA TRANSMITTAL Date: December 6, 2005 To: Howard Oakland From: Barbara Kruk for Paul Winslow AOGCC Forest Oil Corporation 333 W. 7th Ave, Suite 100 310 K Street, Suite 700 Anchorage, AK 99501 Anchorage, AK 99501 Phone: (907) 279 -1433 Phone: (907) 868 - 2113 FAX: (907) 258 - 8601 TRANSMITTAL DESCRIPTION Well data for Kustatan Field #1, API #50 - 133 - 20496 -00 In accordance with Alaska Statutes AS 31.05.035, we request that confidentiality be extended to all of the following information. /2 Printouts Well Completion or Recompletion Report & Log dated 11/22/2005 - 3 pages (AOGCC form 10 -407) /l- Printout Summary Report of Daily Re- completion Drilling Reports - 3 pages /1- Printout Geologic Markers List - 1 page -1- Printout Oil & Gas Shows List - 1 page ,i1- Printout Summary Report and Results of each Test - 9 pages , 1- Printout PVT Analysis - 1 page .4 Printout Pressure Build Up data - 5 pages A - Printouts Gas Well Open Flow Potential Test Report - 4 pages ( AOGCC form 10 -421) V- CD Pressure Build Up data - 1 File; Format: Excel 4 1 3) Q a,. Please sign belo to acknowledge receipt. Received B '- Da*" 4)' ( Returned to Forest Oil Date Accepted By: Date Modified:12 /6/2005 Transmittals _AOGCC.xls /KF1_AOGCC_12_6_05 Date Prepared: 12/6/00 r 3 �i l•` _ RECEIVE[ ' STATE OF ALASKA ALAS AND GAS CONSERVATION COMMIS DEC 2 6 2005 WELL COMPLETION OR RECOMPLETION REPORT ANDi Gas Cons. 1,u4i iai la. Well Status: Oil Gas is Plugged ❑ Abandoned ❑ Suspended ❑ WAG ❑ lb. Well Class: AncttoTage 20Anc 25.105 2OE AC 25. 110 Development ❑ Exploratory ILI GINJ WINJ❑ WDSPL No. of Completions Other Service ❑ Stratigraphic Test ❑ 2. Operator Name: 5. Date Comp., Susp., 9r j 12. Permit to Drill Number: 2e Forest Oil Corporation Aband.: ;, l j.9 a { 200 -153 ' 3. Address: 6. Date Spudded: / G/ , 13. API Number: 1 31 OK Street, Suite 700, Anchorage, Alaska 99501 October 16, 2000 t 50- 133 - 20496 -00 4a. Location of Well (Govemmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 3,443' FNL, 1,468 FWL Sect. 4, T7N, R14W SM ' December 4, 2000 Kustatan Field # 1 Top of Productive Horizon: 8. KB Elevation (ft): 15. Field /Pool(s): 260 Total Depth: 9. Plug Back Depth(MD +TVD): Kustatan Field Same 6,220' 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 186839.181 y- 2460784.001 Zone- 12,300' TPI: x- y- Zone- 11. Depth Where SSSV Set: 17. Land Use Permit: Total Depth: x- y- Zone- N/A 18. Directional Survey: Yes ❑ No si 19. Water Depth, if Offshore: 20. Thickness of Permafrost: N/A feet MSL N/A 21. Logs Run: Zone was shot off of a mud log. 22. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT PULLED 20" 133 # K -55 Surf. 120' Same Driven N/A None 13 -3/8" 68# K -55 Surf. 1820' Same 17 -1/2" Surf. None 9 -5/8" 47 # L -80 Surf. 6500' Same 12 -1/4" 643 Cu. Ft. None 7 -5/8" 29.7 # L -80 6,312' 12,300' Same 8 -1/2" 678 Cu. Ft. None 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none "): SIZE DEPTH SET (MD) PACKER SET (MD) 5,353 - 5,365' MD =TVD, 5,370 - 5,380' MD =TVD 2 -7/8" 5,097' 5,097' c.uvit ie d y l , Single Selective 5,291' t ,—C l ICN ; , 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. €g /s1�t # ^fir w4t - " - , , �/ 7 a 4 DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED "�° € N/A iFif l t 26. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): November 14, 2005 Flowing Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 11/14/2005 1/24/1900 Test Period . N/A 1,508 0 (21- 33)/64 N/A Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (Gorr): Press. 1,475 24 -Hour Rate ...+ N/A 1,508 0 N/A 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none ". Lithology - Sandstone, light grey, fine to coursegrained, dominantly medium - grained, angular to rounded, dominantly sub - angular, 70% quartz, 30 %lithlic fragments. Sandstone is interbedded with tuffaceous claystone and minor amounts of coal. Porosity - Average 24% Interpreted from logs. Fractures - None Apparent. Shows- Gas shows on mud log, No oil shows. No core chips. IBS BFI. JAN 0 5 2006 Form 10 -407 Revised 12/2003 fl D I i '7 1 1 ANLINUED ON REVERSE r 8. GEOLOGIC MARKER. 29. ORMATION TESTS NAME M TVD Include and briefly sumIllirze test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state Beluga 3,380 3,380 "None ". Tyonek 4,462 4,462 Tested 5204' - 5,260'. Zone tested wet. Recovered 35 bbls of water with no GO Zone 10,532 10,524 shows of gas. Isolated zone behind sliding sleeve and shot the bottom G Zone 11,031 11,022 zone. Test# 2 Hemlock 11,468 11,458 Pererated 5,353 - 5380'. This zone is open and producing. West Foreland 12,016 12,005 30. List of Attachments: Well bore schematic 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Printed Name: Ted Kramer Title: Production , Manager l Signature: / 4 2 — � Phone: ?l! Y " 2 - 7 3 Date: it/ �2.. atc 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. Submit a well schematic diagram with each 10 -407 well completion report and 10 -404 well sundry report when the downhole well design is changed. Item la: Classification of Service wells: Gas Injection, Water Injection, Water - Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50- 029 - 20123- 00 -00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut -in, or Other (explain). Item 27: If no cores taken, indicate "none ". Item 29: List all test information. If none, state "None ". Form 10 -407 Revised 12/2003 w ® • • Kustatan Field #1 Single Selective Completion 11/22/05 KB=!l.lft. :; RRO N . 2 "13 #K5 @120' MD ¥ . : Methanol Injection ' 13 3/8 68# K5 BTC @ 1820' MD Mandrel g28'MD # �« .. 29a 6.5# L-80 EUE Tubing ✓ 298XNippleg52'MD 5/8" , , g&aPceg59 MD 288 Sliding Sleeve @514'MD 4 56' TCP Gun on Y Block @ 5,18' : :EMI 7'2 7/8 Blast Joints @ 5192' • 9 5/8" Packer w/ Se|Bore@591' MD 2 7/8 XN Nipple @ 5315' MD 41' TCP Gun as s mblystars! @ 5344' New Gas Pew : Bridge Rug p 6192' M D 5204-5260' M D 5353-5365' MD L Al Top of 7&8 Liner @612' MD 5370-5380' MD . w« ` Bull Plug g58' r 95/8" 4 #L8 BTC A60'MD r Disposal Perfs : 0 6270-6304' MD 6312-6475' MD n PBD g64'MD( /81 +0 CTU) 6750-6800' MD , ' ` a , " . 1 '75/ƒ2.7 L-80 STLFL S @12,300' MD • 1 cc DEC2 66 2005 Kustatan Field #1 Anchorage Daily Re- Completion Report Summary 10 -7 -05 Begin to rig up Nabors #26 rig. 10 -8 -05 Continue rigging up Nabors #26 rig. 10 -9 -05 Telescope derrick and set four 21,000# anchors. 10 -10 -05 Finish rigging up and setting anchors. Test BOPs, rams, hydrill, and blind rams. 10 -11 -05 Finish testing BOPs, rams, and hydrill. R/U tubing tongs & pulled 2 -way check. Pulled hanger loose, released downhole anchor, pulled seals out of packer, and picked up hanger to rig floor. Fill hole with water and circulate out 35 bbls of oil. 10 -12 -05 POOH with anchor and seal assembly. M/U subs and set wear bushings. R/D 2 -7/8" handling tools & R/U handling tools for 4 -3/4" drill collars. P/U retrieving tool, jars and drill collars. Tripping in hole with packer retrieving tool. 10 -13 -05 Finish POOH. Latched onto packer @ 6161' and pulled loose. After allowing packer to relax, slowly POOH. 10 -14 -05 Finish POOH w/ packer and lay down. Trip in hole w/ bit, scraper, & 2- 7/8" tubing. Tag TOL @ 6312'. Service rig. 10 -15 -05 POOH w/ bit & scraper. R/U E -line, pick up composite bridge plug. TIH and tag TOL @ 6312'. Pull up and set BP at 6220'. POOH & R/D E -line. Dump 85 gal of cement on top of BP (est. TOC @ 6192'). 10 -16 -05 Finish R/D slickline, blow down choke and kill line with air. Flush lines in pits & fill same with field water to mix KC1. TIH w/ bit & scraper. Displace hole with 3% KC1 water & corrosion inhibitor (8.5 # fluid). POOH & L/D 2 -7/8" tbg. 10 -17 -05 Finish L/D tbg, drill collars, bit & scraper. R/U Schlumberger E -line, P/U TCP guns & packer assembly. Tied in with gamma ray log and set packer @ 5294'. TCP guns @ 5353' -5365' and 5370' - 5380'. POOH and R/D E- line. P/U seals, Y -block assembly, and guns. TIH w/ BHA & 2 -7/8" production tubing. 1 �o�• I)'3 iSik_ • CONFIDENTIAL 10 -18 -05 M/U Nova chemical injection mandrel & test to 6500 psi for 15 min. Finish RIH w/ production tubing. Tag seals in lower packer at 5294', P/U, spaced out & M/U hanger. Hooked injection line to hanger. Land Hanger and test backside to 300 psi w/ tbg open. Seals tested ok. Pulled seals out of packer and displaced tbg w/ 30 bbls of diesel & 3 bbls on backside for freeze protection. Land hanger and R/D circulating lines. R/U slickline & TIH w/ 2.31" BX plug. Note: Received approval to not test BOPs from Jim Regg @ 09:30 10- 17 -05. 10 -19 -05 TIH w/ prong and set in BX plug @ 5024'. Test tbg to 1500 psi — OK. POOH w/ prong & pulled BX plug. TIH & set BX plug @ 5142' in sliding sleeve. Pressure up to 1700 psi and set hydro 1 packer at 5097'. Pulled BX plug. TIH w/ shifting tool and open sliding sleeve at 5142'. Tested backside to 300 psi to test top pkr with tbg open - OK. Closed sliding sleeve and POOH. R/D slickline & set BPV. N/D 11" BOPs. N/U VETCO 2- 9/16" 5M tree. Tested void to 5000 psi. Pulled BPV & installed 2 -way check. R/U test pump, tested tree to 250 psi low and 5000 psi high. R/D test lines. Release Nabors #26 rig from Kustatan Field #1. KF #1 Testing 10 -24 -05 RIH w/ slickline to open sliding sleeve @ 5142'. Flow Test #1: Pressure up on tbg to fire upper TCP guns (5,204' — 5,260'). Swab on well. 10 -26 -05 Continue to swab on well. Total recovery = 35 bbls. End Flow test #1 and RIH w/ slickline to close sliding sleeve. RIH with prong to pull BX plug & tag fill on top of plug. Rig up bailer on slickline and bail sand from on top of BX plug. Bailed for several days and were unsuccessful in clearing debris from on top of the BX plug. 11 -7 -05 Rig up coiled tubing unit to cleanout the fill on top of BX plug in bottom X Nipple. Coil tubing successful in removing fill. 11 -14 -05 Sliding sleeve @ 5142' is closed, isolating the lower TCP guns from the upper perforations. Pulled BX plug from XN nipple at 5315'. Flow Test E-- #2: Drop bar to fire lower TCP guns (5,353' - 5,365' & 5,370' - 5,380'). Opened the well up through test separator for cleanup flow. 11 -15 -05 Continue cleanup flow for total duration of approximately 8 hours. Set choke setting to 25/64" adj and flow well for 3.75 hrs. Increase choke setting to 27/64" adj. and flow well for 3.0 hrs. Increase choke setting to 29/64" adj. and flow for 3.0 hours. Increase choke setting to 33/64" adj. and flow for final 3.0 hrs. Shut -in well for extended buildup. 2 • • Choke Gas Rate Tubing Pressure (1/64 ") (Mscf/d) fpsig) 25 1,618 1,520 27 2,044 1,400 29 2,312 1,300 CONFIDEWTII\L 33 2,638 1,150 ' 11 -16 -05 Well shut -in for PBU. 11 -17 -05 End PBU at 16:45. 3 • • 12/5/2005 Kustatan Field #1, API# 50- 133 - 20496 -00 Geologic Markers CONFIDENTIAL Name Measured Depth TVD Beluga 3,380' 3,380' Tyonek 4,462' 4,462' GO -Zone 10,532' 10,524' G -Zone 11,031' 11,022' Hemlock 11,468' 11,458' West Foreland 12,016' 12,005' )vb _ls'3 F'��. • 1 12/5/2005 Kustatan Field #1, API# 50- 133 - 20496 -00 Oil and Gas Shows CO N FI DENTIAL Name Measured Depth TVD Tyonek 5,204' - 5,260' 5,204' - 5,260' Flow Test #1 Tyonek 5,353' - 5,365' 5,353' - 5,365' Flow Test #2 Tyonek 5,370' - 5,380' 5,370' - 5,380' Flow Test #2 2.0Q -1c S FLT... KF #1 - Gas Analysis (5,353' - 5 MD) w1 {L}t:fcat' 1 ! t. - )at_a tor E(& Cl1andl er Enc� ,13 j 1 jj � � j Diode 292 13'17. dialyze T tt L.imc Nov , 1( 05 10.06 C:�1 'i brat ion # .. 2 T E;i :1 1,oc tir n Nc . ' 170 2 Sta 1'ai&.l .._s S :ra Ycd + Wet rialysis • Ni' �- 13'1'j R..De .ia.* C _M ** 110Ienv ETTTA R . Y . w Mechan 99.1 3 1004. 0.! 495 7, 467 9.96 72 0.5399 Zr tlzallc '� , 1 } . � 0.0015 0.038, 3 .141 2.51 0.0015 F __ �ry}e 0 023 0'._ 0.00()3 0,0062 0.022 0,5x5 O.' 0K,3 ( C6 1 ) C 005 0, 28 0. 00f32 0. 002 0 0 , i7 O. r. O C: 2 Mui:3ture C.°CO 0,00 0.0000 -- 1.744 0.68 0.C10 1�T_t:rcgen 0 413 (). IJ ].00 D -- 0.411 0.00 0.0040 C . 217_ (),.., :) - () t)'3 3 - ) 0.213 0.00 O . (:'D.3: TL 100,00 :007.S 0.5588 (., 100.00 990.9 0.5599 * Lxxcorzect.ed for c impres- iii =i at 50.0F & 14 .:'301:'SIA . * ; L iquid Volume re.porrEri ,tt 60.0F . .' `andard / D y An 1y b a y j tec Wet 1 psis • hmo.1 JIasu' = 1 . : 4 16.216 Reiait t.ve 1]c =_tit = Q .559 C -55 Co preEKa. -_1' -t1 �+ e or = p . �? Q 9 7 Ee in :I uc = 4.,,...,__. Ltu /1}. 31:3 3 � lki F. � I u e - 1009 , 6 B.7t;,lCF' 993 .0 3t'a /CF Llbs0. Gas T)ertglty = 42. 0319 1bal,f 'OCF 42 .9207 1} Ln 1000CF +abbe de = 1327 .34 › Ur -norr al:I -7eri " ; - D Last C` 1 ►� -h lgas of ;J.Y5 btu /'�T� ,T rt.14 05 1 : 0 CIS+ te r, TJpi1a.- : GFA. 22 1 9C• . C f 3'_'�' /CF 505 S _ 7.".o GaL !3. G4 2 50, anci C 1olo . I . 9 . C0 , w Forest OiI Corporation 0, Kustatan Field #1 CONFJDENW • Tyonek Testing Summary • 0 G w 49 E Kustatan Field #1 Tyonek Te Program � g o � , Performed Two (2) Production Flow Tests: • 1. Tyonek Flow Test #1 (Upper Zone) CONFIDENTIAL • Perforations: 5,204' — 5,260' MD • Tested Wet • Recovered 35 bbls of water w/ no show of Gas 2. Tyonek Flow Test #2 (Lower Zone) • Perforations: 5,353' — 5,365' and 5,370' — 5,380' MD • • Multi -rate Flow Test, followed by extended Buildup • Flowed gas at a rate as high as 2.7 MMcf/d • Separator Gas Sample Collected O A Tyonek FIow Test #1 (Upper Zone) 1. Tyonek Flow Test #1 (Upper Zone) • Perforations: 5,204' - 5,260' MD • • Test start date: 10/24/05 '- • Zone tested wet • Recovered 35 bbls of water w/ no show of gas • Recovered -60 feet of fill (sand, perf debris, etc.) from on top of lower BX plug • No samples gathered • Isolated the perforations after testing by closing the sliding • sleeve at 5,142 MD (single selective completion string). "O R EJ`. - I 4� MIN INN= IJ;�;��r• " . ,t r �.v r ,r , 5 II - � � � • ' 5 ' o Kustatan Field No.1 - Logging Run 1 'FPTH i510G. 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Vie IMI � ■ ■ ■1� �1■ 7 7 , ill 5 I ' i.___ c 7 7 71 ,, ; k ii .z •' „ ,,..,. ,_.....,,,,_ = r-rir�; sure /Te :I r e. r� p19 , , .., _ ,,, Kustatan Field #1 CONFIDENTIAL Multi -rate Flow Test (11- 14 -05) 2,400.0 - I — 120.0 • Bottom -Hole Pressure - k Temperature _ • 2,200.0 = 110.0 ill 1 2,000.0 i 100.0 y Q - LL N 1,800.0 — — . f 90.0 v m • L • . a> _ _ ca = 1,600.0 • 80.0 Q - • • E w 1 - o • m - 1,400.0 70.0 1,200.0 60.0 Perforations: 5,353' - 5,365' MD 5,370' - 5,380' MD \ . 1,000.0 , 50.0 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 Time (hours) gf FT #2: P & G . Rate P J o , ) 4 .. - a ' a. Kustatan Field #1 LUNFIDE TIAL Multi -rate Flow Test (11- 14 -05) 2,500.0 3,000 2,800 2,600 • 2,200.0 ■� ii 2,400 k Bottom -Hole Pressure 2,200 Gas Flow Rate 2,000 y a .a Il i; m 1,900.0 1,800 g 1, N 600 fn a L m 1,400 0 _ L E 1,600.0 1 ,200 R C9 o m 1,000 • 800 1,300.0 I 600 400 Perforations: 5,353' - 5,365' MD 200 5,370' - 5,380' MD 1,000.0 ' , , , , , , , , ,.., , , , 1 , , , 1 1 1 , , , 1 , , , , , , 0 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 Time (hours) I 1 FT#2 Fl Summary Company: Forest Oil Corporation Well Name: Kustatan Field #1 r,°'3 Formation: Tyonek A Perforations: 5,353' - 5,365' & 5,370' - 5,380' MD • Test Date: 11/14-15/05 "Delta Time" Start Time: 19:17:53 Delta Average Time Time Gas Rate (hrs) (hrs) (Mcf /d) Comments: 0.0000 Start of Flow 2.4519 2.4519 466 5.2019 2.7500 1,124 6.2019 1.0000 2,143 11.0050 4.8031 2,581 14.7647 3.7597 1,618 Step #1 17.7947 3.0300 2,044 Step #2 20.7897 2.9950 2,312 Step #3 23.7872 2.9975 2,650 Step #4 69.4294 45.6422 0 PBU Company: Forest Oil Corporation Well Name: Kustatan Field #1 Formation: Tyonek A Perforations: 5,353' - 5,365' & 5,370' - 5,380' MD Gauge Start Date: 11/14/2005 Gauge Start Time: 16:07:02 Time Temp. Pressure Date Clock Time (hrs) (deg F) (psia) yyyy /mm /dd hh:mm:ss Comments: 0.0003 45.31 18.41 11/14/2005 16:07:04 0.0056 45.24 18.41 11/14/2005 16:07:23 0.0106 45.17 18.39 11/14/2005 16:07:41 0.0206 45.06 18.39 11/14/2005 16:08:17 0.0306 44.94 18.45 11/14/2005 16:08:53 h. 1, 0.0406 44.78 18.59 11/14/2005 16:09:29 0.0506 44.50 18.69 11/14/2005 16:10:05 0.0606 44.11 18.86 11/14/2005 16:10:41 Excet File; KF #1 Ftowtest 11 - 14`05:xis 0.0706 43.68 18.97 11/14/2005 16:11:17 - Raw Pressure & Temperature Data 0.0806 43.25 19.03 11/14/2005 16:11:53 Page 1 of 295 0.0906 42.82 19.05 11/14/2005 16:12:29 0.1006 42.41 19.05 11/14/2005 16:13:05 0.1106 42.01 19.05 11/14/2005 16:13:41 0.1206 41.62 19.04 11/14/2005 16:14:17 0.1306 41.25 19.05 11/14/2005 16:14:53 0.1406 40.89 19.03 11/14/2005 16:15:29 0.1506 40.56 18.99 11/14/2005 16:16:05 0.1606 40.26 19.17 11/14/2005 16:16:41 0.1656 40.13 34.86 11/14/2005 16:16:59 0.1706 40.01 130.34 11/14/2005 16:17:17 0.1756 39.93 179.80 11/14/2005 16:17:35 0.1806 39.89 207.90 11/14/2005 16:17:53 0.1856 39.88 224.81 11/14/2005 16:18:11 0.1906 39.91 232.28 11/14/2005 16:18:29 0.1956 39.95 235.44 11/14/2005 16:18:47 0.2006 39.99 237.28 11/14/2005 16:19:05 0.2056 40.05 238.54 11/14/2005 16:19:23 0.2106 40.11 239.64 11/14/2005 16:19:41 0.2156 40.17 240.46 11/14/2005 16:19:59 0.2206 40.24 240.97 11/14/2005 16:20:17 0.2256 40.30 241.44 11/14/2005 16:20:35 0.2306 40.37 241.90 11/14/2005 16:20:53 0.2356 40.43 242.27 11/14/2005 16:21:11 0.2406 40.49 242.51 11/14/2005 16:21:29 0.2456 40.56 242.69 11/14/2005 16:21:47 0.2506 40.62 242.85 11/14/2005 16:22:05 0.2556 40.68 242.98 11/14/2005 16:22:23 0.2606 40.74 243.10 11/14/2005 16:22:41 0.2656 40.79 243.20 11/14/2005 16:22:59 0.2706 40.85 243.28 11/14/2005 16:23:17 0.2756 40.90 252.32 11/14/2005 16:23:35 0.2806 40.96 262.67 11/14/2005 16:23:53 �.Or- I5 -1 • Company: Forest Oil Corporation Well Name: Kustatan Field #1 E # (jI r't ? ' 1 Formation: Tyonek A ; : ` s f 4 . 4 ; e •x Perforations: 5,353' - 5,365' & 5,370' - 5,380' MD Test Date: 11/14 -15/05 Delta Delta Daniels Meter Tubing Casing Surface Time Time Daniels Choke Pressure Temp. Gas Rate WHP Pressure Choke Date: Time (hrs) (hrs) Meter (64th) (psia) (F) (Mcf /d) (psia) (psia) (64th) Comments: 11/14/2005 19:00 2.8825 14.7 92 0 220 0 19:15 3.1325 14.7 93 0 150 0 19:17 3.1806 0.0000 14.7 93 Start of Flow 19:30 3.3825 0.2019 14.7 94 335 0 19:45 3.6325 0.4519 14.7 98 440 0 20:00 3.8825 0.7019 17.7 120 710 0 22 20:15 4.1325 0.9519 17.9 120 940 0 23 20:30 4.3825 1.2019 55.3 120 1150 0 23 20:45 4.6325 1.4519 230 114 1565 0 24 21:00 4.8825 1.7019 642 80 1372 0 19 21:15 5.1325 1.9519 3" 38 593 79 410 1268 0 21 21:30 5.3825 2.2019 3" 38 592 81 457 1345 0 21 21:45 5.6325 2.4519 2" 42 599 79 530 1506 0 23 22:00 5.8825 2.7019 2" 44 654 81 1004 1460 0 23 22:15 6.1325 2.9519 2" 44 639 79 993 1485 50 23 22:30 6.3825 3.2019 2" 45 540 75 1080 1517 50 23 22:45 6.6325 3.4519 2" 45 588 76 1093 1545 50 23 23:00 6.8825 3.7019 2" 47 502 74 1114 1590 50 25 23:15 7.1325 3.9519 2" 47 508 77 1111 1560 65 26 23:30 7.3825 4.2019 2" 48 517 78 1244 1500 65 28 23:45 7.6325 4.4519 3" 47 524 73 1256 1500 65 28 11/15/2005 0:00 7.8825 4.7019 3" 47 566 78 1143 1508 65 28 0:15 8.1325 4.9519 3" 50 457 69 1280 1536 65 30 0:30 8.3825 5.2019 3" 50 376 70 1045 1640 30 0:45 8.6325 5.4519 3" 60 549 69 1942 1325 75 30 1:00 8.8825 5.7019 3" 50 657 70 1932 1500 75 29 1:15 9.1325 5.9519 3" 55 702 67 2380 1257 75 31 1:30 9.3825 6.2019 3" 55 691 68 2317 1230 75 31 1:45 9.6325 6.4519 3" 61 659 65 2686 1162 75 33 2:00 9.8825 6.7019 3" 61 623 67 2555 1150 100 33 2:15 10.1325 6.9519 3" 55 711 71 2402 1177 100 33 2:30 10.3825 7.2019 3" 56 729 68 2519 1170 100 33 2:45 10.6325 7.4519 3" 55 721 67 2536 1140 100 33 3:00 10.8825 7.7019 3" 55 722 68 2535 1160 100 33 3:15 11.1325 7.9519 3" 55 723 68 2540 1160 100 33 3:30 11.3825 8.2019 3" 55 720 68 2529 1160 100 33 3:45 11.6325 8.4519 3" 55 712 68 2490 1190 100 33 4:00 11.8825 8.7019 3" 55 702 68 2460 1210 100 33 4:15 12.1325 8.9519 3" 56 660 67 2316 1160 100 34 4:30 12.3825 9.2019 3" 56 685 67 2745 1120 100 34 4:45 12.6325 9.4519 3" 56 700 67 2808 1100 100 34 5:00 12.8825 9.7019 3" 55 703 68 2650 1100 100 33 5:15 13.1325 9.9519 3" 55 705 68 2668 1105 100 33 5:30 13.3825 10.2019 3" 55 707 68 2669 1125 100 33 5:45 13.6325 10.4519 3" 55 712 68 2682 1120 100 33 6:00 13.8825 10.7019 3" 55 704 68 2659 1128 100 33 6:15 14.1325 10.9519 3" 6:30 14.3825 11.2019 3" 6:45 14.6325 11.4519 3" 50 679 70 1800 1400 100 • • Delta Delta Daniels Meter Tubing Casing Surface Time Time Daniels Choke Pressure Temp. Gas Rate WHP Pressure Choke Date: Time (hrs) (hrs) Meter (64th) (psia) (F) (Mcf /d) (psia) (psia) (64th) Comments: 7:00 14.8825 11.7019 3" 48 683 68 1580 1475 100 25 7:15 15.1325 11.9519 3" 48 689 70 1596 1500 100 25 7:30 15.3825 12.2019 3" 48 694 70 1608 1505 100 25 7:45 15.6325 12.4519 3" 48 697 70 1616 1520 100 25 8:00 15.8825 12.7019 3" 48 699 71 1623 1520 100 25 8:15 16.1325 12.9519 3" 48 700 71 1627 1520 100 25 Step #1 8:30 16.3825 13.2019 3" 48 699 71 1622 1550 100 25 Ave = 1618 Mcf /d 8:45 16.6325 13.4519 3" 48 698 71 1617 1550 100 25 9:00 16.8825 13.7019 3" 48 702 71 1624 1540 100 25 9:15 17.1325 13.9519 3" 48 702 71 1630 1540 100 25 9:30 17.3825 14.2019 3" 48 702 71 1625 1540 100 25 9:45 17.6325 14.4519 3" 48 702 71 1622 1520 100 25 10:00 17.8825 14.7019 3" 48 702 72 1646 1520 110 25 10:15 18.1325 14.9519 3" 50 696 69 2103 1430 110 27 10:30 18.3825 15.2019 3" 50 697 70 2064 1420 110 27 10:45 18.6325 15.4519 3" 50 697 69 2061 1410 110 27 11:00 18.8825 15.7019 3" 50 696 69 2054 1410 110 27 11:15 19.1325 15.9519 3" 50 702 69 2048 1410 110 27 11:30 19.3825 16.2019 3" 50 703 69 2033 1400 110 27 Step #2 11:45 19.6325 16.4519 3" 50 703 69 2039 1410 110 27 Ave = 2044 Mcf /d 12:00 19.8825 16.7019 3" 50 702 69 2030 1400 110 27 12:15 20.1325 16.9519 3" 50 701 69 2035 1400 110 27 12:30 20.3825 17.2019 3" 50 701 69 2024 1400 110 27 12:45 20.6325 17.4519 3" 50 701 69 2019 1400 110 27 13:00 20.8825 17.7019 3" 50 700 69 2018 1400 110 27 13:15 21.1325 17.9519 3" 54 700 67 2330 1320 100 29 13:30 21.3825 18.2019 3" 54 696 67 2304 1310 100 29 13:45 21.6325 18.4519 3" 54 698 67 2311 1310 100 29 14:00 21.8825 18.7019 3" 54 697 68 2309 1300 100 29 14:15 22.1325 18.9519 3" 54 699 67 2328 1300 125 29 14:30 22.3825 19.2019 3" 54 698 68 2320 1300 120 29 Step #3 14:45 22.6325 19.4519 3" 54 698 68 2315 1300 125 29 Ave = 2312 Mcf /d 15:00 22.8825 19.7019 3" 54 697 68 2305 1300 110 29 15:15 23.1325 19.9519 3" 54 696 68 2311 1290 125 29 15:30 23.3825 20.2019 3" 54 697 67 2307 1290 125 29 15:45 23.6325 20.4519 3" 54 697 68 2302 1300 125 29 16:00 23.8825 20.7019 3" 54 695 67 2307 1300 140 29 16:15 24.1325 20.9519 3" 56 714 65 2780 1175 125 33 16:30 24.3825 21.2019 3" 56 687 66 2680 1150 140 33 16:45 24.6325 21.4519 3" 56 683 67 2660 1150 150 33 17:00 24.8825 21.7019 3" 56 681 66 2643 1150 150 33 17:15 25.1325 21.9519 3" 56 680 66 2635 1150 150 33 17:30 25.3825 22.2019 3" 56 679 67 2625 1150 130 33 Step #4 17:45 25.6325 22.4519 3" 56 680 67 2632 1150 140 33 Ave = 2638 Mcf /d 18:00 25.8825 22.7019 3" 56 679 67 2620 1150 130 33 18:15 26.1325 22.9519 3" 56 679 67 2627 1150 130 33 18:30 26.3825 23.2019 3" 56 678 67 2635 1150 140 33 18:45 26.6325 23.4519 3" 56 679 67 2626 1150 140 33 19:05 26.9678 23.7872 3" 56 676 67 2632 1140 140 33 19:05 26.9681 23.7875 3" 0 Start PBU @ 19:05:07 19:30 27.3825 24.2019 3" 0 19:45 27.6325 24.4519 3" 0 20:00 27.8825 24.7019 3" 0 r T fi s COI F- I DENTI AI Kustatan Field # Multi-rate ) ate Flow Test 11 -14 -05 2,400.0 — -. • Bottom -Hole Pressure . Ternnerati!re 2,200.0 • i::::: u) - on d ,_, CI_ = • G1 • L = 1,600.0 80.0 � E o o •r m • 1,400.0 . 70 • r I 1,200.0 1 60.0 1 Perforations: 5,353' - 5,365' MD 5,370' - 5,380' MD 1,000.0 50.0 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 Time (hours) Y`� P Kustatan Field #1 � . � IT � _ Multi -rate Flow Test (11- 14 -05) 2,500.0 — 1 3,000 2,800 - 2,600 2,200.0 d. 2,400 • . _ � "._ Gas Bottom Flow Hole Rate Pressure — 2,200 R — 2,000 C. ii L 1,900.0 1,800 _ — 1,600 w L Q. m - 1,400 0 0 LL. x E 1,600.0 - -- 1,200 o 0 m _ — 1, 000 — 800 • 1,300.0 600 — 400 _ Perforations: 5,353' - 5,365' MD — 200 5,370' - 5,380' MD - 1,000.0 0 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 Time (hours) vt STATE OF ALASKA A ALAS IL AND GAS CONSERVATION COMMIAN GAS WELL OPEN FLOW POTENTIAL TEST REPORT la. Test: U Initial LJ Annual a Special lb. Type Test: [J Stabilized U Non Stabilized U Multipoint Multi -Rate Flow Test #2 - Conducted 11 -14 -05 ❑ Constant Time ❑ Isochronal ❑ Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Forest Oil Corporation Re- Completed 11/19/05 200 -153 3. Address: 6. Date TD Reached: 12. API Number: 310 K Street, Suite 700, Anchorage, AK 99501 12/4/2000 50- 133 - 20496 -00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 3,443' FNL Sec. 4, T7N, R14W SM 260' Kustatan Field #1 Top of Productive Horizon: 8. Plug Back Depth(MD +TVD): 14. Field /Pool(s): 6,220' Kustatan Field / Total Depth: 9. Total Depth (MD + TVD): 12,300' 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 186839.181 y- 2460784.001 Zone- 4 Kustatan Field TPI: x- y- Zone- 16. Type of Completion (Describe): Total Depth: x- y- Zone- DST #1 using 2 -7/8" Tubing 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 7 -5/8" 29.7 6.875 12,300 5,353' to 5,365' MD 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 5,370' to 5,380' MD 2 -7/8" 6.5 2.441 5,291 20. Packer set at ft: 21. GOR cf /bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 9,291 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): El Tubing ❑ Casing 104 F° 2316 psia @ Datum 5353' TVD psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO % N2: % H2S: Prover: Meter Run: Taps: 5,353 0.56 0.22 0.42 0 26. FLOW DATA TUBING DATA CASING DATA Prover Choke BH Pressure Diff. BH Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice psia Hw F psig F psig F Hr. Size (in.) Size (in.) 1. X 25/64 1799.8 97.9 1520 71 100 3.8 2. X 27/64 1646.3 96.2 1400 69 110 3.0 3. X 29/64 1506.9 93.7 1300 68 125 3.0 4. X 33/64 1340.8 90.1 1150 67 140 3.0 5. X Basic Coefficient Flow Temp. Super Comp. Rate of Flow I h wPm No. (24 -Hour) Pressure Gravity Factor Pm Factor F Factor Q Mcfd Fb or Fp Ft g Fpv 1 1618 2 2044 3 2312 4 2638 5. Temperature for Separator for Flowing No. Pr T Tr z Gas Fluid Gg G 1. 2. 3. Critical Pressure 4. Critical Temperature 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SIDE Submit in Duplicate Pc Pc P 2,316 pf2 5,363,856 No. Pt Pt Pc2-Pt2 Pw Pw Pc Ps Ps Pf -Ps 1. 1520 2,310,400 1,800 3,239,280 2,124,576 2. 1400 1,960,000 1,646 2,710,304 2,653,552 3. 1300 1,690,000 1,507 2,270,748 3,093,108 4. 1150 1,322,500 1340.8 1,797,745 3,566,111 5. 25. AOF (Mcfd) 3,892 Mcf /d n 0.939 Remarks: See attached KF #1 AOF spreadsheet and plot 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Ctr Title J-s. Date 11 30 - 0S - DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ 4 hwPm Fp Basic critical flow prover or positive choke factor Mcfd /psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor = dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air= 1.000), dimensionless Gg Specific gravity of separator gas (air= 1.00), dimensionless GOR Gas -oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back - pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut -in wellhead pressure, psia Pf Shut -in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 • • Kustatan Field #1 Multi -Rate Flow Test Perfs: 5,353' - 5,365' & 5,370' - 5,380' MD (11 -14 -2005) COMFU]ENTI\L Surface Gas BH Flowing BH Shut -in Choke Flowrate Pressure Pressure Size Q Ps Pf DD (Pf ^2 -Ps ^2) AOF (1/64 ") (Mscf /d) (psia) (psia) ( %) (psia ^2 x 10e3) n (Msc/d) 25 1,618 1,799.8 2,316 22.3 2,125 0.939 3,861 27 2,044 1,646.3 2,316 28.9 2,653 0.939 3,959 29 2,312 1,506.9 2,316 34.9 3,093 0.939 3,878 33 2,638 1,340.8 2,316 42.1 3,566 0.939 3,871 Ave 3,892 AOF I 3,892 I 0.0 2,316 100.0 5,364 From AOF Plot: From Form 10 -421: y = 0.8079 *x ^1.0646 AOF = Q*[Pf ^2 /(Pf ^2- Ps ^2)] ^n (Pf ^2 -Ps ^2) = 0.8079 *Q ^1.0646 (Pf ^2) = 0.8079 *AOF ^1.0646 AOF = [(Pf ^2)/0.8079] ^(1/1.0646) a = 0.8079 b = 1.0646 KUSTATAN FIELD #1 - AOF Plot Multi -Rate Flow Test (11/14/05) 10,000 - - - - -- Multi -Rate Flow Test (11/14/05) 4 . 1 1 —Least Squares Best Fit 1 •- , T -, , • , 1 C'T \ : o FBHP = 0.0 psia 1 1 K 1 I . . w N < 1 C6 y 1 I , N 1 CA y = 0.8079x'. 1 N R = 0.9969 1 < 1 a 1 1 Theoretical Absolute • 1 Open Flow (AOF) I = 3.89 MMscf /d 1 1/ 1 1 1,000 1 I . ' ' 1 I ' 1,000 10,000 GAS RATE (Mscf /d) • S 701E F LniE„\ I a FRANK H. MURKOWSKI, GOVERNOR ALASKA OIL AND GAS 333 W. 7T" AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Paula Inman 1 Alaska Production Engineer Forest Oil Corporation 310 K Street, Suite 700 Anchorage, Alaska 99501 Re: Kustatan Facility #1 Sundry Number: 305 -145 Dear Ms Inman: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. Please provide at least twenty -four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decisio ► o Superior Court unless rehearing has been requested. o - n ► man ' airman DATED this da Y of June, 2005 Encl. • O R £ s F O R E S T O I L _ C O R P O R A T I O N 19 �y 16 370 C7r95 eet • C�� 700 lJ CD ildoxarie, 2 /a,1 /ca 99501 (907) ?.58 -8600 • 907) 258 -8601 () June 8, 2005 Mr. John Norman, Chair AI �' 005 Alaska Oil and Gas Conservation Commission ,:t:, I,o,.. s,„- -- 333 W. 7 Avenue, Suite 100 Anchorage, Alaska 99501 -3539 Re: KF #1 Re- completion e' Dear Mr. Norman, Forest Oil proposes to work over Well KF #1 in the Kustatan Field of Cook Inlet to convert it from a Class II disposal well to a single selective gas producer in the upper Tyonek sands. The work to be performed is outlined in the attached summary procedure. The estimated date for commencement of this work is July 1, 2005. Attached please find a completed Form 10 -403 for the work, an outline procedure, a current wellbore schematic, a proposed wellbore schematic and a BOP configuration diagram for the workover unit to be used. If you have any questions, please contact me at 868 -2135. Sincerely, / Paula Inman Alaska Production Engineer Forest Oil Corporation Attachments: 10 -403 Application for Sundry Approvals Outline Procedure Current Wellbore Schematic Proposed Wellbore Schematic 11" 5M BOP Schematic i 1 .6 6,L) - 6's 4 STATE OF ALASKA � ALIPA OIL AND GAS CONSERVATION COMM 'SION.S g'' , A ID; APPLICATION FOR SUNDRY APPROVAL �' 20 AAC 25.280 - -41 tr /00 1. Type of Request: Abandon U Suspend Li] Operational shutdown LJ Perforate Lit Waiver Other Li Alter casing ❑ Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extensibir ❑ ,,,, Change approved program ❑ Pull Tubing El Perforate New Pool ❑ Re -enter Suspended Well '`Q , *% 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Forest Oil Corporation Development ❑ Exploratory ❑ 200-153 3. Address: Stratigraphic ❑ Service 0 6. API Number: 310 K Street, Suite 700, Anchorage, AK 99501 50- 133 - 20496 -00 7. KB Elevation (ft): 9. Well Name and Number: 260' MSL Kustatan Facility #1 8. Property Designation: 10. Field /Pools(s): ADL 387023 Kustatan Field 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12,300 12,300 12,259 12,259 None None Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 20" 120' 120' N/A N/A Surface 1,820' 13 3/8" 1,820' 1,820' 3450 psi 1,950 psi Intermediate 6,500' 9 5/8" 6,500' 6,500' 6,870 psi 4,750 psi Production Liner 5,988' 7 5/8" 12,300' 12,300' 6,890 psi 4,790 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Sheet See Attached Sheet 2 -7/8" 6.4#, L -80 6,216' Packers and SSSV Type: Baker 190-40 9 5/8" SC2 / No SSSV Packers and SSSV MD (ft): Packer at 6,161' 12. Attachments: Description Summary of Proposal U 13. Well Class after proposed work: f� 4 Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Developmen El Serv - 0 J3 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 7/1/2005 Oil ❑ Gas El Plugged ❑ Abandoned ❑ 16. Verbal Approval: Date: WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Title aInman Alaska Prod ction Engineer Signature ne (907) 868 -2135 Date 6, -c COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: (,, .- / 1 Plug Integrity 1].., BOP Test VI. Mechanical Integrity Test ❑ Location Clearance ❑ t- r, 15r ( ss.,x--� ms , V -s \c� bq- ccaca he kv sz -S i•Ar Other: �j Subsequent Fo ' 4 34r � S BFL JUN 3 0 2005 � / APPROVED BY Approved b VP 41 10, COMMISSIONER THE COMMISSION Date: 5 _ c Form 10 -403 Revised 11/2004 Submit in Duplicate • • • Kustatan Field el . Completed „.. . ,• A/ ) ,, [ i 27,4 °4 _4+ 4z46 12,0' MO .4 - 7 0774 4 % 7 # , t r. 4(,. 4 Cif* 3700r C22 )476”, b is s , .44044744M444,44444,4, 4, , �P '1 \ 5 e , ,. .1 gib: 1024 40 MA ,CV Est 6,7W X0 4,1 72 10' 21474740 0172 At , 3 ;' , -d , ' .g 2 276: 6 2724, " 's -T° o till' N L $. 410 470 i ':,, ovei l * / 10 x' a / 3, g. T WM 040 20 /0 sni 1 SAO • • Kustatan Facility #1 Alternative Single Selective Completion 4/6/05 20" 133# K -55 @120' MD 4. Methanol Injection \ 13 3/8" 68# K -55 BTC @ 1820' MD Mandrel @ 3000' MD MI 2 7/8" 6.5# L-80 EUE Tubing 4 I Top of cement 4600' MD 2 7/8" X Nipple @ 5070' MD +4 I gs. 9 5/8" Packer @ 5100' MD 2 7/8" Sliding Sleeve @ 5160' MD II ' 70' 2 7/8" Blast Joints @ 5194' EN ' 56' TCP Gun on Y Block N J , 9 5/8" Packer w /Seal Bore @ 5290' MD 2 7/8" XN Nipple @ 5325' MD 27' TCP Gun r New Gas Perfs: ; v',. 5204 -5260' MD v 5353-5365' MD Bridge Plug @ 6220' MD 5370 -5380' MD Top of 7 5/8" Liner @ 6312' MD / ' Fill @ 6312' MD (11/19/04 WL Tag) Disposal Perfs: ; ���� t 9 5/8" 47# L -80 BTC @ 6500' MD 6270 -6304' MD ,f 6312 -6475' MD ' ' 1'BD @ 6743' MD (8/14/03 CTU) 6750-6800' MD . k */ % / . ' .c"- , • •. ; 1 + i t r I \ 7 5/8" 29.7# L -80 STL /FL4S @12,300' MD / —05 91 • • Kustatan Facility #1 Alternative Single Selective Completion 4/6/05 \.ice . ■ � 20" 133# K -55 @120' MD Methanol Injection ." ■ � 13 3/8" 68# K -55 BTC @ 1820' MD Mandrel @ 3000' MD ��w ' � se 2 7/8" 6.5# L -80 EUE Tubing J , J � !: � ( v st.) ytc c..edQ.D. 2 7/8" X Nipple @ 5070' MD J % \J, , e.i 9 5/8" Packer @ 5100' MD 2 7/8" Sliding Sleeve @ 5160' MDR: 70' 2 7/8" Blast Joints @ 5194' Z 56' TCP Gun on Y Block , 9 5/8" P cker w /Seal Bore @ 5290' MD 2 7/8" XN Nipple @ 5325' MD e —, 27' TCP Gun , New Gas Perfs: : 5204 -5260' MD �w 11.1 "" --- _ I .. . 5353 -5365' MD .> Bridge Plug @ 6220' MD 5370 -5380' MD '' ' *''* I'11, 4 0 . ‹.; Top of 7 5/8" Liner @ 6312' MD K v Fill @ 6312' MD (11/19/04 WL Tag) Disposal Perfs: .., , \,, ° ` 6270 -6304' MD J� 9 5/8" 47# L -80 BTC @ 6500' MD • 6312 -6475' MD PBD © 6743' MD (8/14/03 CTU) 6750 -6800' MD -- 4 4, ,-- II 4 e• 4 e• 4 0 f • 4 « e• • . A I « . e• 4 `.�•i• 4 e• 4 « 4 `i• ce e • ice e • / �:s e • \ ✓� e • / ;4 e • / e• ya. 7 5/8" 29.7# L -80 STL /FL4S @12,300' MD • FOREST OIL CORPORATION Kustatan Facility #1 Workover Summary- 5/5/05 Current Status: Class II Disposal well for Kustotan Facility, well is currently on standby. Wireline tools tagged fill (or liner top) at 6312' MD on 11/19/04. Straight hole. Objective: Recomplete well as single selective gas producer in upper Tyonek sand at 5204 -5260' MD (straddle zone) and 5353 -5365' and 5370 -5380' MD (lower zone). Maintain flexibility to convert back to disposal well later below base of fresh water zone at 6150' MD (DIO 26.003). Injection Log 4/14/03 showed SBHP of 3064 psi, 128 deg F at 6851' MD with zero pressure at surface. The upper zone Tyonek gas pressure is estimated at 2500 psi, 127 deg F based on regional trend data. The annulus fluid is inhibited produced water with a 5 BBL diesel cap. 1. Bleed pressure off all annulus strings. Pump diesel into annulus valves to ensure communication path is open. 2. Set 2 %2" `H' BPV in Tubing Hanger 3. MIRU Nabors Pulling Unit 4. Nipple down injection tree. 5. Nipple up 11" 5M BOPs and test to 3,000 psi. BOPs will consist of a double ram and an annular preventer. The rams will be set up with blinds on top and pipe rams on the bottom. 6. Remove BPV 7. Latch onto 2 7/8" tubing hanger (Note: Tubing hanger has 3.160 MCA Box Top, 2 7/8" 8rd Box Bottom). Release Model E -22 Anchor at 6160' MD with right hand rotation. Tubing needs 5k to 8k pull at anchor to release. POOH with tubing/E -22 Anchor and lay down tubing. Note: Need to have wireline unit/chemical cutter available in case anchor does not release and tubing has to be cut; also need tubing overshot/oil jar fishing tools to be available 8. Tubing Hanger & Tree to be inspected/redressed by Vetco Gray. Hanger and tubing head adaptor need to be modified to accept methanol injection line. 9. RIH with SC -2 Packer Retrieving tool and latch into Baker Model SC2 -PAH Retrievable Packer at 6161' MD and retrieve packer. r-ft fop 10. RIH with 8 1/2" bit and casing scraper to top of 7 5/8" liner lap at 6312' MD. F ��3 Circulate hole clean and change over to 3% KCL completion fluid; POOH. 11. RU electric line unit; RIH and set 9 5/8" Composite Bridge Plug at 6220' MD -roa�a �� �z (Note: Bridge Plug should be set no higher than 6220' per AOGCC abandonment cgsteNNAAS h :6 requirements of setting plug within 50' of top of perfs at 6270'). Test Bridge Plug CSP, V ) o , to 1600 #. Note: AOGCC may require 7 ' cement to be paced on top of Bridge ! Mt VrtclortsesPlug. v <Q s� s v\ � it cVc-)- r \ - .O r►.Z nJ 12. Pick u p 27' TCP gun assembly (for interval 5353-5365' & 5370 -5380' MD), 2 C c ' 7/8" tubing tail with WL Entry Guide and XN nipple one tubing joint below Seal *A- tom. Bore and make up on 9 5/8" X 2 7/8" Packer w /Seal Bore. RIH on Electric Line. {mooz)tvu` c r.,., ti\ Tie in TCP gun on depth at 5353 -5365' & 5370 -5380' MD. Set Packer at 5290' tt i \\l \ c-2. `if) MD. ,11 f'C " Created by Eric Skaalure Page 1 of 3 Z: \FEPSI\Bpenrose\Projects\Forest Oil\KF #1 Workover\KF #1WOSSsum0505.doc • • FOREST OIL CORPORATION Kustatan Facility #1 Workover Summary- 5/5/05 14. Pick up Packer Seal Assembly, 2 7/8" tubing, 2 7/8" Blast Joints, Ported Y Block w /TCP Gun (for interval 5204 -5260' MD), 2 7/8" Sliding Sleeve 1 joint below packer, and upper 9 5/8" Packer to be set at 5100' MD. Ensure space -out of TCP guns is correct in relationship to final setting depth of Lower Packer. 15. Install X Nipple on 2 7/8" tubing 1 joint above Packer Seal Assembly, Methanol Injection Mandrel Sub w /check valves at 3000' and run 1/4" Methanol Injection line to surface. 16. Make up tubing hanger with Methanol injection line penetration; connect methanol injection line and pressure test connections and line 17. Circulate tubing to diesel (31 bbls, to provide drawdown for perforating) and Freeze protect annulus 18. Stab Seal Assembly into lower Packer. Pressure up on annulus to ensure seals are engaged. 19. Land tubing hanger. 20. RU Slickline to set Equalizing Plug in X nipple above upper packer at 5100'; pressure test tubing; retrieve Equalizing Plug 21. RU Slickline to set Equalizing Plug in X nipple in Sliding Sleeve below upper packer at 5100' 22. Set upper Packer at 5100' MD. 23. Retrieve Equalizing Plug in X nipple in Sliding Sleeve below upper packer at 5100' MD 24. Set BPV in Tubing Hanger 25. Nipple down BOPE's and nipple up tree; pressure test to 5000# 26. Rig down Nabors Pulling Unit 27. Pull BPV. 28. Set up piping and choke manifold for cleanup flow. Set up Forest Oil portable test separator, gas flare line, and portable tank for flowback liquids. 29. RU Slickline to set Equalizing Plug in XN nipple below lower Packer at 5290' MD (Note: Run extended Equalizing Prong fishing neck to allow for peforation debris around top of plug) 30. Shift Sliding Sleeve in straddled interval to Open position 31. Activate TCP gun firing head through Y Block to perforate upper perf interval 5204 -5260' MD by pressuring up on tubing; flow well for cleanup. Monitor for water production. Well may need to be swabbed in to initiate flow, or if significant water is produced, a coiled tubing nitrogen lift may be required to ensure cleanup. Note: If well produces water, collect 3 water samples (1 liter each) in lined containers for laboratory compositional analysis. Test Choride content on -site to establish if chorides are greater than or less than 10,000 ppm. 32. If well produces water with minimal gas after cleanup flow, shut in well and skip to Step 34 33. If zone produces gas, shut -in well. RU slickline to hang off downhole shut -in tool & pressure /temp memory gages in X nipple above packer at 5100' MD Created by Eric Skaalure Page 2 of 3 Z: \FEPSI\Bpenrose\Projects\Forest Oil\KF #1 Workover\KF #1WOSSsum0505.doc • • FOREST OIL CORPORATION Kustatan Facility #1 Workover Summary - 5/5/05 34. Conduct 4 point flow test on upper gas zone (4 rates, 3 hrs @ each rate). Produce well through test separator during 4 point test. Collect 3 pressurized gas samples off the test separator for laboratory compositional analysis. 35. Shut in well with downhole shut -in tool to conduct 24 hour Pressure Buildup. 36. Retrieve downhole shut -in tool and pressure /temp memory gages; verify that good data has been obtained. \g 37. Shift Sliding Sleeve to Closed Position 4271/1 fit 38. Pull Equalizing Plug from XN nipple below bottom packer 39. Swab well to create +/- 500 psi drawdown on perforations 40. Prepare to flow well. Drop bar to activiate lower TCP gun firing head to perforate interval 5353 -5365' & 5370 -5380' MD. Flow well for cleanup. Monitor for water production. Well may need to be swabbed in to initiate flow, or if significant water is produced, a coiled tubing nitrogen lift may be required to ensure cleanup. 41. If well produces water, collect 3 water samples (1 liter each) in lined containers for laboratory compositional analysis. Test Choride content on -site to establish if chorides are greater than or less than 10,000 ppm. 42. If well produces water with minimal gas after cleanup flow, shut in well and skip to Step, W . .04 43. If zone produces gas, shut -in well. RU slickline to hang off downhole shut -in tool & pressure /temp memory gages in XN nipple below packer at 5290' MD 44. Conduct 4 point flow test on lower gas zone (4 rates, 3 hrs @ each rate). Produce well through test separator during 4 point test. Collect 3 pressurized gas samples off the test separator for laboratory compositional analysis. 45. Shut in well with downhole shut -in tool to conduct 24 hour Pressure Buildup. 46. Retrieve downhole shut -in tool & pressure /temp memory gages; verify that good data has been obtained. 47. If both or either gas zone produces gas, a decision will be made on which zone to set up for production. 48. If both zones produce only water, a decision will be made to either file for a Disposal Injection Order with AOGCC for disposal into the new perforations, or *o n1� ay to recomplete the well for water disposal into the original disposal zone, based on the compositional analysis of the produced water. Created by Eric Skaalure Page 3 of 3 Z: \FEPSI\Bpenrose\Projects\Forest Oi1\KF #1 Workover\KF #1WOSSsum0505.doc ( l L 11" 5k PSI GK ANNULAR BOP SCREWED HEAD / FLANGED BOTTOM CONNECTION I I • �� - 11 " 5k PSI 2- 1/16" #5000 -.4-.401 9 1 . DOUBLE GATE PREVENTOR GATE VALVE _ STUDDED CONNECTION _ N -BUfl I -RAM 2- 1 /16" #5000 GATE VALVE 2" CHOKE L1NE _ _ 1:11i =1: 4411 III ' 41:- ' I _ T----------- 2" KILL LINE F LANGED MUD CROSS 2 -1/16" #5000 11 " 5k PSI GATE VALVE 'PE 11- - HYDRAULIC RAM SINGLE GATE STUDDED CONNECTION 2- 1/16" #5000 3"x2" DSA 3"x2" DSA GATE VALVE • NABORS ALASKA RIG 26 S 11" BLOW -OUT PREVENTOR 3 RAM STACK CONFIGURATION Zta 5 A UflIO S9 W WXM1N k 0 --..11__-- Nobwt Alako D00n8 Me. I � 2525 C Street 52te 200 • IM BOOMIOIB_BeA Anetaage. Ak sko 89503 -2639 907 -2 -600 "ma NABORS ALASKA RIG 26 S 11' BLOW -OUT PREVENTOR 3 RAM STACK CONFIGURATION 09NM BY 01111CND) BY *0550AEC BY Rf9. JOE ASTON B08 A02E — - Bac B r DESCI11.11011 SCALE N/A SALE JUNE 2005 D Nu 26S_0.3034 " 1 of I RE: KF -1 • • Subject: RE: KF -1 From: Paula Inman <PRlnman @forestoil.com> Date: Fri, 17 Jun 2005 12:06:26 -0600 To: 'Thomas Maunder' <tom_maunder@admin.state.ak.us> Tom, Doug Hupp with Schlumberger came over to view the bond log. His interpretation of the bond log shows: Good Isolation: 5150- 5300'MD t5t,, / 5420- 5460'MD qi 5475- 5490'MD 1 -4' ..z- 3 Cement but not bonded above: 5050'MD — Our bond log shows cement to 4600'MD. Based on the cement calculations top of cement should be approximately 4534' MD. Paula Inman Production Engineer Forest Oil Corporation (907) 868 -2135 office (907) 317 -8231 cell Original Message From: Thomas Maunder [ailto :tom maunder @admin.state.a Sent: Thursday, June 16, 2005 1 :41 PM To: Paula Inman Cc: Ted Kramer Subject: Re: KF -1 Paula, Have you heard from Schlumberger on the bonding of the 9 -5/8" casing ?? Also, the well drawing you submitted would indicate that the 9 -5/8" casing was cemented to surface which is not the case. The drawing should be revised to reflect the TOC based on the bond log or calculations whichever is deeper. Thanks in advance for looking into this. Tom Maunder, PE AOGCC Paula Inman wrote: Tom, 1. No, it does not authorize gas production. However, Forest has picked up the oil and gas lease associated with this location (390368) and has been in existence since 9/30/03. Currently, we have a Multiple Land Use Permit with DNR and in the process of amending this permit. Forest will produce gas in pursuant to the oil and gas lease. 2. We have looked at the bond log and it appears to have isolation above and below the zone of interest. We will call in Schlumberger to give us a further assessment. 3. It is not our intention to return the new interval to water disposal. We will be placing a composite cast iron bridge plug over the current disposal perforations so that we could re -enter the well for a disposal situation. If we were to do this work it would be performed under a new sundry to the AOGCC. At that time we would also request permission to isolate the 5300's sands with a straddle packer if non productive. I hope this helps you out. 1 of 2 6/17/2005 10:23 AM RE: KF -1 • 40 Paula Inman Production Engineer Forest Oil Corporation (907) 868 -2135 office (907) 317 -8231 cell Original Message From: Thomas Maunder [mailto:tom maunder Sent: Monday, June 13, 2005 8:25 AM To: Ted Kramer; Paula Inman Subject: KF -1 Ted and Paula, I have just started to look at the proposed recompletion and have a couple of questions /comments. 1. A "special use /authorization" from DNR is in place to allow KF -1 to operate. Does that authorize gas production as you are planning ?? Just a question since I am remembering that "true" lease had expired or lapsed prior to completing the well as the Class II injector. 2. Do you have confidence in the 7 -5/8" cement job for the intervals planned to be perforated ?? I am remembering some issues regarding the bonding when the DIO was being worked. 3. If the gas completion is not successful, you are proposing to possibly use the new perfs for disposal. Gathering the water samples (if the zones make some) as you plan is a good idea. What do you think the likelihood is to "return" to the presently completed interval ?? It may make sense to squeeze those intervals off if it doesn't look like you will return to them, although I have not completely looking into the regulations on that. Look forward to your reply. Tom Maunder, PE AOGCC Content - Type: application/vnd.ms- powerpoint KF #1PropSchemSS.ppt Content- Encoding: base64 2 of 2 6/17/2005 10:23 AM RE: KF -1 • Subject: RE: KF -1 ���^� --- From: Paula Inman <PRlnman @forestoil.com> " �.— Date: Mon, 13 Jun 2005 14:51:44 -0600 To: 'Thomas Maunder' <tom maunder @admin.state.ak.us >, Ted Kramer <TEKramer @forestoil.com> Tom, 1. No, it does not authorize gas production. However, Forest has picked up the oil and gas lease associated with this location (390368) and has been in existence since 9/30/03. Currently, we have a Multiple Land Use Permit with DNR and in the process of amending this permit. Forest will produce gas in pursuant to the oil and gas lease. 2. We have looked at the bond log and it appears to have isolation above and below the zone of interest. We will call in Schlumberger to give us a further assessment. 3. It is not our intention to return the new interval to water disposal. We will be placing a composite cast iron bridge plug over the current disposal perforations so that we could re -enter the well for a disposal situation. If we were to do this work it would be performed under a new sundry to the AOGCC. At that time we would also request permission to isolate the 5300's sands with a straddle packer if non productive. I hope this helps you out. Paula Inman Production Engineer Forest Oil Corporation " (907) 868 -2135 office (907) 317 -8231 cell Original Message From: Thomas Maunder [mailto:tom ?aunder'@ad Sent: Monday, June 13, 2005 8:25 AM To: Ted Kramer; Paula Inman Subject: KF -1 Ted and Paula, I have just started to look at the proposed recompletion and have a couple of questions /comments. 1. A "special use /authorization" from DNR is in place to allow KF -1 to operate. Does that authorize gas production as you are planning ?? Just a question since I am remembering that "true" lease had expired or lapsed prior to completing the well as the Class II injector. 2. Do you have confidence in the 7 -5/8" cement job for the intervals planned to be perforated ?? I am remembering some issues regarding the bonding when the DIO was being worked. 3. If the gas completion is not successful, you are proposing to possibly use the new perfs for disposal. Gathering the water samples (if the zones make some) as you plan is a good idea. What do you think the likelihood is to "return" to the presently completed interval ?? It may make sense to squeeze those intervals off if it doesn't look like you will return to them, although I have not completely looking into the regulations on that. Look forward to your reply. Tom Maunder, PE AOGCC 1 of 1 6/16/2005 9:35 AM / Aotl DATA SUBMITTAL COMPLIANCE REPORT 5/2/2005 Permit to Drill 2001530 Well Name /No. KUSTATAN FIELD 1 Operator FOREST OIL CORP API No. 50- 133 - 20496 -00 -00 MD 12300 TVD 12300 / Completion Date 4/1/2003 Completion Status WDSP2 Current Status WDSP2 411010 REQUIRED INFORMATION Mud Log No Samples No Directional Survey No DATA INFORMATION Types Electric or Other Logs Run: QuadCombo, Usit (data taken from Logs Portion of Master Well Data Maint) Well Log Information: Log/ Electr • Data Digital Dataset Log Log Run Interval OH / T�ypp -- Med /Frmt Number Name Scale Media No Start Stop CH Received Comments gD T 09775 1 12350 Case 1/3/2001 1 -12350 1 i/' T 09776 6284 12321 Case 1/3/2001 6284 -12321 1 D C 9776 FINAL 6284 12321 Case 1/3/2001 6284 -12321 Digital Data k6g AIT /DEN /NEU /GR/C 2/5 comp 6506 12310 Open 1/2/2001 6506 -12310 BL, Sepia and PDS eOg CAUGR 2 FINAL 6506 12310 Open 1/2/2001 6506 -12310 BL, Sepia and PDS Ldg AIT /Sonic /GR/Cal 2/5 comp 6506 12310 Open 1/2/2001 6506 -12310 BL,Sepia and / PDS Log Dipmeter /GR 5 FINAL 6700 12300 Open 1/2/2001 6700- 12300BL,Sepia,and PDS ~ Digital Drilling Open 1/2/2001 977 All digital data to be t archived on server with 01;r'(f` A_ 72 /.0 (∎ % data set numbers III / •g Mudlog 2 FINAL S f"_ /A )c3; Open 1/2/2001 Surface to TD BL, Sepia Rpt Final Report Open 1/2/2001 Surface to TD ED C 576 See Notes 1 1669 6510 Open 3/3/2003 Digital Well Logging Data Well Cores /Samples Information: Sample Interval Set I Name Start Stop Sent Received Number Comments Cuttings 1830 12300 1031 DATA SUBMITTAL COMPLIANCE REPORT 5/2/2005 Permit to Drill 2001530 Well Name /No. KUSTATAN FIELD 1 Operator FOREST OIL CORP API No. 50- 133 - 20496 -00 -00 MD 12300 TVD 12300 Completion Date 4/1/2003 Completion Status WDSP2 Current Status WDSP2 UIC Y ADDITIONAL INFORMATION Well Cored? Y Daily History Received? 0 N Chips Received? ‘'r114- Formation Tops N Analysis ?TIT Received? Comments: 4 1, A Compliance Reviewed By: Date: /z.�i� r I I a ' 0200 -153 o R S FOREST O I L C O R P O R A T I O N , lb C7{P e� • (T 700 I 1 O nP/ /c�o�iea , Cl i/rc7 9950 �� 000 258 -86OO • �90O ?s8 -8601 (max) 11 October 6, 2004 I Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue, Suite 100 Anchorage, Alaska 99501 I Attn: Mr. Jack Hartz Re: Kurtan Field #1 — Corrected Annual Report 2003 -2004 1 Dear Mr. Hartz, I I This report is to supercede the Annual Report submitted July 1, 2004. It was brought to our i I attention by AOGCC that we had reported exceeding the 2 bpm restrictions during the months of October 2003 to January 2004. When in fact, at no time during the specified time of the annual report did Forest exceed the 2 bpm rate. I ' It is our intention to increase the rate as of October 8, 2004 to 3 bpm and perform the warm back survey on October 12, 2004. If there are - - 1 1 t e e a e any questions, please contact me at 907 868 2137. ' Sincerely, Ted E. Kramer Production Manager Forest Oil Corporation RECEIVED ' OCT 0 2004 Alaska Oil & ut €;, Commission Anchorage 1 • 1 Forest Oil C r r 1 1 1 o po anon ' Kustatan Field #1 Yearly Injection Report - Produced Water April 1, 2003 to May 31, 2004 ' AOGCC KF #1 Apr -03 36,835 May -03 89,264 Jun -03 69,237 Jul -03 44,416 ' Aug -03 12,680 Sep -03 37,810 Oct -03 36,660 Nov -03 40,410 ' Dec -03 44,457 Jan -04 24,180 Feb -04 - Mar -04 - Apr -04 1,380 May -04 9,630 Total 446,959 1 I1 11 11 • IllM IllIIM VIII. lull. llll.1 lll.11 llllllll11 lllllll.1 llllllll1 llllllll1 llllllll11 = IlllM • Wellhead Pressure AOGCC Monthly Injection K1 Injection Pressure and Rate April 2003 • Annulus Pressure Volume = 36,835 bbls + Rate 5,000 __a.... _ _ _._.___ _, _ _ _._ 3 4,500 • • • • • • • • • • • • —2.5 • 4,000 • • • 3,500 — 2 • • • • • • • • 3,000 U a Gi Q ' 2,500 1.5 N Vl ca a 2,000 — 1 1,500 1,000 • — 0.5 500 • • 0 U - ■ ■ ■ ■ ■ ■ • ■ • • • • ■ • • • • ■ • • ■ , ■ • • • ■ 0 3/30/2003 4/4/2003 4/9/2003 4/14/2003 4/19/2003 4/24/2003 4/29/2003 5/4/2003 Time > > > MEM =IN MIMI AMIN MI= MI= mom =Am ammo mimo Immo mom mom moms MN N M IMM M 1111111 11111 MEI 1111111 • Wellhead Pressure AOGCC Monthly Injection K1 Injection Pressure and Rate May 2003 • Annulus Pressure Volume = 89,264 bbls f Rate BPM 6,000 - -- -- 5 — 4.5 5,000 • • • • • • • • • • • • ♦ _ 4 41\A_A, • • • • ♦ — 3.5 4,000 f • • • • •-• • — 3 3,000 2.5 cLa • — 2 • 2,000 • • • — 1.5 • • • • — 1 1,000 — 0.5 • 0 • • • • • • • • 1 1 1 i • • 1 1 1 • 1 • 1 1 1 • • • • T • • t • 0 4/29/2003 5/4/2003 5/9/2003 5/14/2003 5/19/2003 5/24/2003 5/29/2003 6/3/2003 Time O NMI M - s NMI EMS NM= iMMI - mom =moo — N =WM NM= 1 I ME MI MI — — OM ME NM — — — IIIIII IM I • Wellhead Pressure AOGCC Monthly Injection Kl Injection Pressure and Rate June 2003 • Annulus Pressure Volume = 69,237 bbls -- Rate BPM 6000 _ — 7 — 6 5000 • • • • • • • • • • • ♦ • • • • —5 4000 — 4 W L 3000 o; • a • - • 2000 • —2 • • • • • ♦ • 1000 — 1 • • ■ • ■ 0 • • • • • • • • • • ■ • • I • • • • • • • • ■ ■ , 0 5/29/2003 6/3/2003 6/8/2003 6/13/2003 6/18/2003 6/23/2003 6/28/2003 7/3/2003 Time I NM MN MN - EN= - N M I MI MO EIM 111111 111111 1111111 M • Wellhead Pressure AOGCC Monthly Injection K1 Injection Pressure and Rate July 2003 • Annulus Pressure Volume = 44,416 bbls — Rate BPM 6000 _ _— ___.____ - - 3.5 —3 5000 • • • • • • • • • • • — 2.5 4000 'Q — 2 6 5 3000 N � N {Q a —1.5 2000 • — 1 • 1000 — 0.5 0 • • u ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ . . . . . . . . . . . u . . . . , 0 6/27/2004 7/2/2004 7/7/2004 7/12/2004 7/17/2004 7/22/2004 7/27/2004 8/1/2004 8/6/2004 Time I — — — I OM — — NM NM — NM O MIN MEN • Wellhead Pressure AOGCC Monthly Injection Volume — Monthly K1 Injection Pressure and Rate August 2003 • Annulus Pressure —•— Rate 4000 - 2.5 • 3500 •--•—• • — 2 410 3000 2500 • — 1.5 c. E m � I S 2000 • • • N r N la a - 1 1500 1000 • — 0.5 500 0 • ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ • ■ ■ ■ ■ ■ ■ ■ ■ ■ • • • 0 7/28/2003 8/2/2003 8/7/2003 8/12/2003 8/17/2003 8/22/2003 8/27/2003 9/1/2003 9/6/2003 Time 1 — — — — — — iii= / — — MI NM • Wellhead Pressure AOGCC Monthly Injection KF1 Injection Pressure and Rate Sept 2003 1 Volume = 37,810 bbls • Annulus Pressure —A— Rate BPM 4,000 — 2.5 Monthly Injected Volume - 37810 bbls • 3,500 A—A—fA 1 A A • — 2 • 3,000 2,500 — 1.5 C14 I. • r 2 • • • r a. • � • • • • • • • • • 1 1,500 • • • • • 1,000 ill • - 0.5 500 • • . 0 • ■ ■ l ■ ■ ■ ■ 1 • • • • • • ■ • • ■ • • • i • ■ ■ ■ 0 8/27/2003 9/1/2003 9/6/2003 9/11/2003 9/16/2003 9/21/2003 9/26/2003 10/1/2003 10/6/2003 Time I ■ — — — — — — r — — — — ME MO — — MN MO AOGCC Monthly Injection Kl Injection Pressure and Rate October 2003 • Wellhead Pressure Volume = 36,660 bbls • Annulus Pressure —&— Rate BPM 3,500 . ___.__.____ __,______ . .— - 2.50 3,000 • • • • • • • • • • • • • • _ _ • • • • • • •- -•--•-• • • • • • • • v - 2.00 • 2,500 • • • • • • • — 1.50 2,000 a) o r , 44 • a a 1,500 — 1.00 1,000 — 0.50 • 500 0 • • • • ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ 0.00 9/26/2003 10/1/2003 10/6/2003 10/11/2003 10/16/2003 10/21/2003 10/26/2003 10/31/2003 11/5/2003 Time 1 — MN — — NM — — — MO NM — MO — — — NM Mil MINi MIN Injection • Wellhead Pressure AOGCC Monthly Kl Injection Pressure and Rate November 2003 • Annulus Pressure Volume = 36,660 bbls —a— Rate BPM 3,500 _ —. _ — - 2.50 3,000 • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • j • •• • ---• - -- • • • •• • • • • • • • -- �—a- - --a — 2.00 • I 2,500 — 1.50 2,000 L H CC L at 1,500 — 1.00 j 1,000 — 0.50 • 500 0 - , ■ ■ ■ ■ ■ ■ ■ ■ ■ rh ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ • ■ ■ ■ ■ ■ 0.00 10/26/2003 10/31/2003 11/5/2003 11/10/2003 11/15/2003 11/20/2003 11/25/2003 11/30/2003 12/5/2003 Time N M I - - - - - - - - - - - - • • Wellhead Pressure AOGCC Monthly Injection K1 Injection Pressure and Rate December 2003 • Annulus Pressure Volume = 44,457 bbls -a- Rate BPM 3,500 - -- - - - 2.00 •-- • • • • • • • • • • • • • • - - a - • • • • • • • • • • • • • - 2.00 3,000 • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • - 2.00 • 2,500 - 2.00 2,000 L � - 2.00 a 1,500 - 2.00 1,000 - 2.00 • 500 - 2.00 0 ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ • ■ ■ ■ ■ ■ ■ ■ ■ ■ • • 2.00 11/25/2003 11/30/2003 12/5/2003 12/10/2003 12/15/2003 12/20/2003 12/25/2003 12/30/2003 1/4/2004 Time AOGCC Monthly Injection Kl Injection Pressure and Rate January 2004 • Wellhead Pressure Volume = 24,180 bbls • Annulus Pressure + Rate BPM 3,000 - - 2.50 • • • • • • • • • • • • • • • • • • • • • • • • • • • • 2,500 — 2.00 2,000 — 1.50 1,500 a — 1.00 1,000 • • — 0.50 500 • • 0 • • • ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ . ■ ■ ■ ■ ■ ■ ■ 0.00 12/30/2003 1/4/2004 1/9/2004 1/14/2004 1/19/2004 1/24/2004 1/29/2004 2/3/2004 Time MOI NM NM NM IMO I= NM MN NM IM MMI MN MN • Wellhead Pressure AOGCC Monthly Injection K1 Injection Pressure and Rate April 2004 • Annulus Pressure Volume = 1,380 bbls + Rate 3,000 3.00 • 2,500 2.50 • 2,000 2.00 0. E 3 1,500 1.50 m to co a 1,000 1.00 • 500 0.50 0 . i i i i i i i Z 0.00 3/29/2004 4/3/2004 4/8/2004 4/13/2004 4/18/2004 4/23/2004 4/28/2004 5/3/2004 Time I ME — — — — — — MN MO NM AOGCC Monthly Injection • Wellhead Pressure Volume = 9,630 bbls K1 Injection Pressure and Rate May 2004 • Annulus Pressure - A - Rate 3,500 __ _ __ 2.5 3,000 • • • • • • • • —2 • ♦ • • • • 2,500 — 1.5 Q 2,000 E ELC .o co co as c y a 1,500 cc — 1 1,000 — 0.5 • 500 0 ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ 0 4/28/2004 5/3/2004 5/8/2004 5/13/2004 5/18/2004 5/23/2004 5/28/2004 6/2/2004 Time E S T O L C rte' R A `€._ { O N • r . I i /(: /i /i'ie1 e ( /.> 7 ( '( , ( /1r.; / .9 ii,i('/ 9 0 2 } ") v 6( (.J /?) 2.7,v- 6 (- ; r ) July 1, 2004 Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue, Suite 100 Anchorage, Alaska 99501 Attn: Mr. Tom Maunder Re: Kustatan Field #1 — Annual Report Dear Mr. Maunder, This report is in response to the requirements for annual surveillance reporting on the Kustatan Field #1 Class II disposal well. Rule #5 of the Disposal Injection Order #26 requires this surveillance. This well has been used for disposal of Class II produced water from Kustatan Production Facility. The well has been operating within what we consider normal parameters and has shown no sign of integrity problems. sh o g gtyp If there are any questions, please contact me at 907- 868 -2137. Sincerely, " Ted E. Kramer Production Manager 5 (- 4/ 4 '' (-e j z J (, Kow 1 Forest Oil Corporation RECEIVED 3 t ) ) SEP222004 Alaska 0i1 & Gas Cons. Commission Anchorage 1 I . Fwd: RE: 2004-0217 _ MIT_ Kustatan #1_Ig- 2.xIsj 1111 • Subject: [Fwd: RE: 2004 -0217. MIT Kustatan #1 lg 2.xls] From Thomas Maunder <tom maunder adm .us? Date Thu, 04 Mar 2004 06:47:15 0900 FYI. 4 1.\\4C Original Message Subject: RE: 2004- 0217_MIT_Kustatan #1_lg -2.xls \I& Date: Wed, 03 Mar 2004 18:09:17 -0700 From: Ted Kramer <TEKramer @forestoil.com> To: 'Thomas Maunder' <tom maunder @admin.state.ak.us> Tom, Per my previous e -mail on this subject, I wanted to let you know that that the valve and gauge on the outer annulus (casing to casing) has been installed and is operational. Ted Kramer Production Manager Forest Oil Corporation - Alaska Office 907 - 868 -2137 Fax 907 - 743 -2237 Original Message From: Thomas Maunder [mailto:tom maunder @admin.state.ak.us] Sent: Monday, February 23, 2004 11:23 AM To: Ted Kramer Subject: 2004- 0217_MIT_Kustatan #1_lg -2.xls Ted, Attached is Lou Grimaldi's report of the Kustatan #1 MIT of last week. In the comments on his report, he notes that there is not a valve on the outer annulus so he was not able to observe any pressure. 20 AAC 25.200(d) requires "...appropriate gauges and valves installed on the tubing, casing- tubing annulus and casing- casing annuli..." Arrangements should be made to equip the outer annulus with the proper valve and gauge as required by the regulations. If you have any questions, please call me. Tom Maunder, PE AOGCC 1 of 1 3/4/2004 8:36 AM II i MEMORANDUM State of Alaska TO: Rand edrich Alaska Oil and Gas Conservation Commission C missioner O /,l- SUBJECT: DATE: Wednesday, February 18, 2004 Z \ t ` Mechanical Integrity Tests THRU: Jim Regg 2eirC ( FOREST OIL CORP P.I. Supervisor 1 FROM: Lou Grimaldi KUSTATAN FIELD 1 Petroleum Inspector Src: Inspector NON- CONFIDENTIAL API Well Numbe 50- 133 - 20496 -00 -00 Insp N mitLG040218062708 Inspection Date: 2/17/2004 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well: 1 Type Inj. TVD 6180 IA 470 1630 1630 1630 .T .' TypeTest SPT Test psi 1545 OA Interval Other (describe in P/F Tubing 10 5 5 5 not Notes: Yearly Test, No gauge on O.A. Bull plugged. Type INJ. Fluid Codes Type Test Interval F =FRESH WATER INJ. M= Annulus Monitoring I= Initial Test G =GAS INJ. P= Standard Pressure Test 4 =Four Year Cycle. S =SALT WATER INJ. R= lntemal Radioactive Tracer Survey V= Required by Variance N =NOT INJECTING A= Temprature Anomaly Surve W =Test during Workover D= Differential Temprature Test O =Other (describe in notes) Wednesday, February 18, 2004 Page 1 of 1 Forest Oil Corporation K -1 Disposal Well 41 Subject: Forest Oil Corporation K -1 Disposal Well Kctc — Date: Wed, 24 Sep 2003 15:12:09 -0600 From: Ted Kramer <TEKramer @forestoil.com> p7 - 6 11- ' v To: "Tom Maunder (E- mail)" <tom_maunder @admin.state.ak.us >, Z�v' l5_3 "Jim Regg (E- mail)" <jim_regg @admin.state.ak.us> Tom and Jim, Our records show that the K -1 was put back on injection on 8- 24 -03. Since then, we have injected 43,500 BW into this well, with 1,560 of those barrels being injected just prior to the running of the temperature survey. I spoke to Rob Stinson about the completion report for K -1. Rob advised that he had sent over a hard copy showing the well bore schematic. I have attached a tiff copy of that report. Please call me with any questions or concerns. «AANCFAX100010DF.TIF » Ted Kramer Production Manager Forest Oil Corporation - Alaska Phone (907) - 868 -2137 Fax. (907) - 258 -8601 Name: AANCFAX100010DF.TIF �AANCFAX100010DF.TIF Type: TIFF Image (image /tiff) Encoding: base64 1 of 1 9/25/2003 10:19 AM i 410 0 f s F O R E S T O I L C O R P O R A T I O N , ,b 310 C?/C� Greet • C-3 ur.'l� 700 C ' ne%ra4- {,yqe, 0,W /a a 99.so7 O I'- 907) 258 -8000 • (907) 758 -860/ (19) September 11, 2003 Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue Suite 100 Anchorage, Alaska 99501 Attn: Mr. Tom Maunder Re: Kustatan Field #1 — 10-404 Mr. Maunder, Forest Oil recently re- completed the Kustatan Field #1 disposal well. Please find attached the 10-404 Report of Sundry Activities. Also attached are the wellbore schematic, daily reports and various applicable correspondence. If there are any questions, please contact me at 907 - 258 -8600. Robert D. Stinson Drilling Engineer — Alaska Division Forest Oil Corporation : a. Attachments: 10-404 SEP 1 7 20U, Welibore Schematic Daily Reports Date Modified: 9/11/03 Date Prepared: 9/11/03 rds M:\Kustatan Field\KF #1 DisposaN<F #1 Cleanout\KF #1 404 Cleanout.doc ORIGINAL • STATE OF ALASKA 0 ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown _ Stimulate _ Plugging _ Perforate X Pull Tubing X Alter casing Repair well Other 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Forest Oil Corporation Development: _ 260' MSL 3. Address Exploratory: _ 7. Unit or Property name 310 K Street, Suite 700 Stratigraphic: _ ADL 387023 Anchorage, Alaska 99501 Service: X 4. Location of well at surface 8. Well number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM Kustatan Field #1 At top of productive interval 9. Permit number / approval number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 303 -181 4017.• ! 53 At effective depth 10. API number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 50- 133 - 20496 -00 At total depth 11. Field /Pool 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM N/A 12. Present well condition summary Total depth: measured 12,300' Plugs (measured) true vertical 12,300' Effective depth: measured 12,259' Junk (measured) true vertical 12,259' Casing Length Size Cemented Measured depth True vertical depth Structural N/A N/A N/A N/A N/A Conductor 120' 20" Driven 120' 120' Surface 1,820' 13 3/8" 1478 cu ft 1,820' 1,820' Intermediate 6,500' 9 5/8" 644 cu ft 6,500' 6,500' Production (Liner) Liner 5,988' 7 5/8" 706 cu ft 12,300' 12,300' Perforation depth: measured (6,270'- 6,304'), (6,312'- 6,475'), (6,750'- 6,800') .,3 ( .g : k _, , true vertical (6,270'- 6,304'), (6,312'- 6,475'), (6,750'- 6,800') ; �M' Tubing (size, grade, and measured depth) 2 7/8" 6.5# L -80 EUE - Plastic Coated with TK2 Coating �j " . , /1s� , Packers and SSSV (type and measured depth) Baker Size 190-40 9 5/8" SC2 t', s ;, ..' a: _ ' S .., `" , ." f:� ! "limit: 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure 14. Representative Daily Average Production or Infection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation Subsequent to operation 15. Attachments 16. Status of well classsification as: Wellbore Schematic Oil _ Gas _ Suspended Service X Daily Report of Well Operations 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed: Title: Drilling Engineer, Forest Oil Corporation Date: Form 10-404 rev 06/15/88 SUBMIT I DUPLICATE a7i.. 2u ORGtNAL Kustatan Fad #1 - Completed III August 22, 2003 2 7/8" 6.4# L -80 EUE w/ T . L 2 Coating 20" K -55 133# Welded 120' MD E -22 Anchor 6,160' Baker SC2 Packer 6,161' I iL 13 3/8" L -80 XO 6,165' _ 68# BTC 1,820' MD Mill out Ext 6,166' XO 6,172' 10' tubing pup X Nipple 6,182' Tubing Joint Mule Shoe 6,216' New Perfs: 6,270'- 6,304' 6,312' - 6,475' I I � I ii 1 ,I Top of 7 5/8" Liner @ 6,312' MD � i 9 5/8" L -80 47# BTC 6,500' MD 6,750' to Pe 4.- ` :� c' \ S\ X\O 9- \ C ©v "L \ '1") 6,800' \ W _1 Q-2 ' °' 1�O Q (\ A'%\---- '% \- — t\`J �' uav o \i c— © �\0�OCF \k.\c- C \1.` v� l \ t. 0 ( 5 -UL41/4. 7 5/8" L -80 29.7# STL / FL4S 12,300' MD • • t Q R £ s F O R E S T O I L C O R P O R A T I O N 9 0 i6 310 tic± ,ee( • ('ute 700 C?Cyzc %, ,77(, CD�i-lai/c 9950/ (907 ) ?58 -8600 • (900 258 -860/ (c):5 August 27, 2003 'TIP ca 0 ' 0 '-'" 1.53 Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue Suite 100 Anchorage, Alaska 99501 Attn: Mr. Tom Maunder Re: Kustatan FWd #1 — Step Rate Test Mr. Maunder, Forest Oil recently re- completed the Kustatan Field #1 disposal well. In a letter from the AOGCC (Randy Ruedrich) dated August 15, 2003, the AOGCC stipulated that disposal operations on this well would be restricted to rates of 2 bpm or less, until "the Commission is satisfied the disposal water is isolated deeper than the base of the fresh water." Attached is a copy of that letter, along with the recently completed step -rate injection test. The step test shows that the well takes fluid readily even up to the 5 bpm rate during the test. The pressures encountered during this test reflect what we consider to be a mechanically sound disposal well that is confining disposal fluids within the desired zones. We request that the 2 bpm restriction be lifted at this time. If there are any questions, please contact me at 907 - 258 -8600. P a ID. White Drilling Manager — Alaska Division Forest Oil Corporation Attachments: AOGCC Letter dated August 15, 2003 KF #1 Step Rate Test dated August 21, 2003 KF #1 MIT dated August 20, 2003 Date Modified: 8/26/03 Date Prepared: 8/26/03 rds M:\Kustatan Field\KF #1 Disposal\KF #1 Steptest Discussion.doc i III STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Teat Email to: Bob_ Fteckensteineadmin.state,ak.us; Jim_Regg admin.state.ak.us • OPERATOR; Forest Oil Corp. - FIELD / UNIT / PAD: Kustatan Field * 1 DATE: 08/20/03 OPERATOR REP: Don Jones AOGCC REP: Packer Depth ft.) Pretest Initial 15 Min. 30 Min. Weit1K - 1 Type Inj. 1 N TVD 6,1 ing 50 751 75 75 interval P.T.D.112300 Type test 1 S Test ps Tu 1540 Casing J 4.8001 1. 16021 P Notes: Well - Type Inj. TV!) Tubing Ill P.T.D. 1=3 ME= OEM - MIN P/F Notes: WellI Type Ind TVb 1 Tubing I 1 I Intena P.T.D. I Type test Test psi Casing r P/F Notes: Type P T n i! , Type te st 1 Test psil 1 Casino 1 1 1 I IrdeP� Notes: !! Well I• - In'. l'VD Tubing Interva .... P/F P.T.D. l - Test .. i Notes: Test Details: Total bbls pumped = 2.67, after test, total Obis bled back = 2.70 TYPE INJ Codes TYPE TEST Codes INTERVAL Codes F = Fresh Water tnj M = Annulus Monitoring I = Initial Test 0 = Gas MI P = Standard Pressure Test 4 = Four Year Cyde 8 = Salt Water IN R = Interval Radioactive Tracer Survey V Required by Variance N = Not Injecting A = Temperature Anomah Survey T = Test during Worlcover 0 = Differential Temperature Test 0 = Other (describe in notes) MIT Report Form • Roviavd• 06/1 MIT Form 0747 -03 bra /r'o •r1H.4 IJti I H I Sf 4 I TG9g1 I I RS tab :/ 0 E00Z /ZZ /80 08/15/2003 17:18 9072767542 AOGCC PAGE 02 ' • • . , , ,_. „.„ 1- 1 . r,, ., { L p i u FRANK 11. MUHKOWSK1, GOVERNOR ALASKA OIL AND GAS 333 W. 7"' AVENUE. surrE 100 CONSERVATION COMMISSION - ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279 -1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. DIO 26-001 Re: Request to Extend Injection Interval in Kustatan Field Well 41. Mr. Paul White Drilling Manager — Alaska Division Forest Oil Corporation 310 K Street, Suite 700 Anchorage, AK 99501 Dear Mr. White: By letter dated August 15, 2003, Forest Oil Corporation ( "Forest ") requested authorization to add perforations and extend the injection zone in Kustatan Field Well No. 1 ("KF 1"). The subject well is a Class II disposal well supporting production from the Osprey platform. An unexpected volume of water, and the inability to keep pace with disposal of produced water led Forest to seek approval to add perforations to the well. Attempts to add deeper perforations were unsuccessful. Confinement and fracture analyses done as part of the DIO 26 concluded that any fracture should be confined to within 220 feet of the injection interval using conservative estimates of injected fluid, pressures, and rates. Temperature surveys indicate that fluids injected to date have been confmed to the authorized injection zone. The proposed injection interval as requested by Forest would be approximately 120 feet below the base of fresh watcr (determined from Logs; reference DIO 26 conclusion 5). The Commission believes that injection of produced water only with controlled rates and pressures can be accomplished in a manner that protects fresh water. Based on information provided by Forest, and the analyses performed in compliance with the previously approved DIO 26, the Commission approves Forest's request to perforate KF 1. from 6270 to 6370 feet, and 6385 to 6475 feet (all measured depths). This approval is subject to the following conditions: 1. The well must pass a mechanical integrity test as required by Rule 3 of DIO 26, 2. A baseline step rate test must be performed prior to sustained injection. 3. Forest must perform a temperature survey within 30 days of initiating disposal into the new interval(s). 4. Injection must not exceed 2 barrels per minute until the Commission is satisfied the disposed water is isolated deeper than the base of fresh water calculated to be 6150 feet (MD) in the well. DONE at Anchorage, Alaska and dated August 15, 2003. __ L e f,___Ln i frx > eA.,..., Randy Ru rich Commissioner BY ORDER OF THE COMMISSION DATED at Anchorage, Alaska and dated August 15, 2003. r Liiej Kustatan Step Rate Test August 21, 2003 5000 - - 5 r Pressure (psi) 4500 Pump Rate (bpm) - 4.5 I 4000 - - 4 • (,) .Q 3500 1 - 3.5 i 1 E N 3000 - 3 .0 a - C 2500 I t 1 - 2.5 tY c R = O t= 2000 P - 2 d 0 c t 1500 I - 1.5 0 1000 - 1 • 500 - 0.5 0 J , , I I 1 I t L 0 0 50 100 150 200 250 300 350 400 Elapsed Time (min) Kustatan Field #1 Temp Logs Subject: Kustatan Field #1 Temp ogs Date: Mon, 18 Aug 2003 11:47:53 -0600 From: Rob Stinson <RDStinson @forestoil.com> To: "Tom Maunder (E- mail)" <tom_maunder @admin.state.ak.us> CC: Paul White <PDWhite @forestoil.com> Tom, The "before" temp log was run on 6/27/03 and the "after" log was run on 7/8/03. A 300 bbl injection was performed just prior to running the second temp log. Rob Robert Stinson Drilling Engineer - Alaska Division Forest Oil Corporation (907)- 868 -2133 1 of 1 8/18/2003 10:22 AM TigAX E 0 AL / FRANK H. MURKOWSKI, GOVERNOR ALASKA OIL AND GAS 333 W. 7 H AVENUE, SUITE 100 CONSERVATION COMMISSION / ANCHORAGE, ALASKA 99501 -3539 / PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL NO. DIO 26 -001 Re: Request to Extend Injection Interval in Kustatan Field Well #1 i _ Mr. Paul White ;00 ` 3 Drilling Manager — Alaska Division Forest Oil Corporation 310 K Street, Suite 700 Anchorage, AK 99501 Dear Mr. White: By letter dated August 15, 2003, Forest Oil Corporation ( "Forest ") requested authorization to add perforations and extend the injection zone in Kustatan Field Well No. 1 ( "KF 1 "). The subject well is a Class II disposal well supporting production from the Osprey platform. An unexpected volume of water, and the inability to keep pace with disposal of produced water led Forest to seek approval to add perforations to the well. Attempts to add deeper perforations were unsuccessful. Confinement and fracture analyses done as part of the DIO 26 concluded that any fracture should be confined to within 220 feet of the injection interval using conservative estimates of injected fluid, pressures, and rates. Temperature surveys indicate that fluids injected to date have been confined to the authorized injection zone. The proposed injection interval as requested by Forest would be approximately 120 feet below the base of fresh water (determined from logs; reference DIO 26 conclusion 5). The Commission believes that injection of produced water only with controlled rates and pressures can be accomplished in a manner that protects fresh water. Based on information provided by Forest, and the analyses performed in compliance with the previously approved DIO 26, the Commission approves Forest's request to perforate KF 1 from 6270 to 6370 feet, and 6385 to 6475 feet (all measured depths). This approval is subject to the following conditions: 1. The well must pass a mechanical integrity test as required by Rule 3 of DIO 26. 2. A baseline step rate test must be performed prior to sustained injection. 3. Forest must perform a temperature survey within 30 days of initiating disposal into the new interval(s). 4. Injection must not exceed 2 barrels per minute until the Commission is satisfied the disposed water is isolated deeper than the base of fresh water calculated to be 6150 feet (MD) in the well. DONE at Anchorage, Alaska and dated August 15, 2003. Randy Ru . ch � Commissioner i �,� 41 BY ORDER OF THE COMMISSION ! z DATED at Anchorage Alaska and dated August 15, 2003. ,i.„7:3„ J L T1O r C ,, 411 _ Ill S TATE OF ALASKA i 1 ALASKA OIL AND GAS CONSERVATION COMMISSION • APPLICATION FOR SUNDRY APPROVALS g sl \, 1. Type of Request: Abandon: _ Suspend: _ Operation shutdown: _ Re -enter suspended well: _ Alter casing: _ Repair well: _ Plugging: _ Time extension: _ Stimulate: — Change approved program:)( Pull tubing: X Variance: Perforate: X Other: 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Forest Oil Corporation Development: _ 260' MSL 3. Address Exploratory: _ 7. Unit or Property name 310 K Street, Suite 700 Stratigraphic: _ N/A Anchorage, Alaska 99501 Service: X 4. Location of well at surface 8. Well number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM Kustatan Field #1 At top of productive interval 9. Permit number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 200 -153 At effective depth 10. API number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 50- 133 - 20496 -00 At total depth 11. Field /Pool 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM N/A 12. Present well condition summary Total depth: measured 12,300' Plugs (measured) true vertical 12,300' Effective depth: measured 12,259' Junk (measured) true vertical 12,259' Casing Length Size Cemented Measured depth True vertical depth Structural N/A N/A N/A N/A N/A Conductor 120' 20" Driven 120' 120' Surface 1,820' 13 3/8" Surface 1,820' 1,820' Intermediate 6,500' 9 5/8" TOC 5,000' 6,500' 6,500' Production (Liner) Liner 5,988' 7 5/8" 706 cu ft 12,300' 12,300' Perforation depth: measured 6,750' to 6,800' 6 spf P ,, true vertical 6,750' to 6,800; 6 spf Tubing (size, grade, and measured depth) 2 7/8" 6.5# L -80 EUE Modified, TK -2 Coating @ 6,322' Packers and SSSV (type and measured depth) Baker SC2 -PAH Retreivable @ 6,270' 13. Attachements Description summary of proposal: X Detailed operations program: BOP sketch: 14. Estimated date for commencing operation 15. Status of well classification as: 01- Aug -03 16. If proposal well verbally approved: Oil: _ Gas: _ Suspended: Name of ap• •ver Date approved Service: Class II Disposal 17. I hereby ce that the foregoing is true and correct to the best of my knowledge. I/1 Q Signed: %- Title: Drilling Manager, Forest Oil Corporation Date: O (II ' FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so repre ative may witness Approv No Plug integrity BOP Test Location clearance 5- 225 Mechanical Integrity Test Subsequent form required 10- LkO Approved by order of the Commissioner Commissioner ( Date 1 Form 10 -403 Rev 06/15/88 r r SUBMIT IN TRIPLICATE 0 R ,, ! ��� I 1 ' +'` I �I? -. �i J t i mt r , I Kustatan Field #1 Workover — August 2003 1. Mobilize rig to well and rig up. 2. Install BPV in tubing hanger 3. Nipple down injection tree. 4. Nipple up 11" 5M BOPs and test to 3,000 psi. BOPs will consist of a double ram and an annular preventer. The rams will be set up with blinds on top and pipe rams on the bottom. 5. Release K- anchor with right hand rotation, pull tubing and laydown. Tubing needs 5k to 8k upweight at anchor to release. Coil tubing fish should pull out with the tubing. 6. Trip in w/ drillpipe and retrieve packer. Send packer and anchor to Baker Oil Tools for re- dressing. 7. Cleanout well to 12,000' and swap over to brine. Cleanout should be made with a used 6 3 /4" PDC bit. The 7 5/8" liner never been scraped and still contains wa t T e er has neve bee sc aped a d water t based mud below the existing perforations. 8. Perforate on drillpipe. 9. Run new completion. Completion will be the same configuration as pulled and the P P � P packer will be set hydraulically by means of dropping a ball. 10. Nipple down BOPs 11. Nipple up 5M injection tree 12. Perform step test Perfs: 1.) 6,880' - 6,940' 60' 2) 6,970' - 7,015' 45' 3) 8,000' - 8,040' 40' 4) 8,060'- 8,100' 40' 5) 8,150' - 8,200' 50' 6.) 8,490' - 8,550' 60' Ku tan Field #1 Completed 4/1/03 - Class II Disposal 20" K -55 133# Welded 120' MD 2 7/8" 6.4# L -80 EUE w/ TK- 2 Coating • y ` 13 3/8" L -80 68# BTC 1,820' MD 6,268' Model "K" Anchor 6,270' Baker SC2 -PAH Retr.Pkr 1 1 6,278' 10' pup 2 7/8" I I Top of 7 5/8" Liner @ 6,312' MD 6,288' XN Nipple I ) i 6,290' 1 jt 2 7/8" (I_ !!t 6,322' WEG ! 9 5/8" L -80 47# BTC 6,500' MD 6,750' to Perforations 6 spf 6,800' 7 5/8" L -80 29.7# STL / FL4S 12,300' MD III • Kustatan Field #1 -- BOP Layout ...zrffiffrest 10 IN 11 x 5M Annular BOP ni in. IN in In ii. M. 11 x 5M Gate (blinds) — . , 11" x 5M Gate (pipe) =ael • 13 5/8" 5Mx11 "5M Tubing Head U, in 13 3/8" Slip -on x 13 5/8" 3M,; Casing Head LW ma ,U !i 11" 5M x 11" 5M Mud Cross w/ two 4" 5M outlets - -- Choke side: 4" 5M manual, 4" 5M HCR, 4" 5M x 3 1/8" 5M DSA Kill side: 4" 5M x 2 1/16" 5M DSA, 2 1/16" 5M manual, 2 1/16" 5M manual, 2 1/16" 5M check Re: KF #1 Perforations -- (200 -153) • • Subject: Re: KF #1 Perforations -- (200 -153) Date: Wed, 06 Aug 2003 14:35:11 -0800 From: Tom Maunder <tom maunder @admin.state.ak.us> To: Rob Stinson <RDStinson @forestoil.com> Rob, This acknowledges receipt of the proposed add pert intervals in Kustatan Field #1. According to DIO 26 Rule 1, disposal is authorized below 6500' and in the well. All the proposed perforations are at depths greater than 6500' md. Good luck with the workover. Please contact us if difficulties are encountered that require changing the plans. Tom Maunder, PE AOGCC Rob Stinson wrote: > Tom, > I stated in the last e-mail that we would notify you if we desired to > perforate different intervals than were on the original 10 -403. Please > replace the original perforation intervals with the intervals shown below: > 1.) 6,880' - 6,940' 60' > 2.) 6,970'- 7,015' 45' > 3.) 8,000' - 8,040' 40' > 4.) 8,060' - 8,100' 40' > 5.) 8,150' - 8,200' 50' > 6.) 8,490' - 8,550' 60' > Thanks, > Rob > Robert Stinson > Drilling Engineer - Alaska Division > Forest Oil Corporation > (907)- 868 -2133 Tom Maunder <tom_maunder @admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 of 1 8/6/2003 2:37 PM RE: Kustatan Field #1 (200 -153) • • Subject: RE: Kustatan Field #1 (200453) Date: Tue, 5 Aug 2003 15:32:33 -0600 From: Rob Stinson <RDStinson @forestoil.com> To: 'Tom Maunder' <tom_maunder @admin.state.ak.us> CC: Paul White <PDWhite @forestoil.com> The rams are currently configured with 2 7/8" pipe rams on top and blinds on the bottom. This is how we will have it configured to pull the tubing. Sorry for the confusion. Rob Original Message From: Tom Maunder [mailto:tom maunder(a�admin.state.ak.usl Sent: Tuesday, August 05, 2003 1:08 PM To: Rob Stinson Subject: Re: Kustatan Field #1 (200 -153) Rob, This acknowledges receipt of the change of plans for work on Kustatan Field #1. need one point clarified between your procedure and drawing. In the procedure you state that ram order is blinds on top and pipe on bottom, while your drawing is exactly the opposite. Which is it ?? Please have your foreman stay in touch with the Inspectors since we will desire to have someone come over for the initial BOP test. Your proposed change is acceptable. Good luck with work. Tom Maunder, PE AOGCC Rob Stinson wrote: > Tom, > Forest Oil recently encountered problems while performing the work scope > in 10 -403 #303 -181. The 1.50" coil tubing was stuck in the 2 7/8" tubing > string. While attempting to pull the coil, it parted at the surface. The > coil has been cut and retrieved, leaving the top of the coil fish at 5,900'. > We are currently mobilizing the Inlet Drilling workover rig. We will nipple > up on the well with an 11" 5M BOP (drawing is attached) and perform the > scope of work below. The only change being that we will clean out the 7 > 5/8" liner to 12,000'. We may adjust the additional perforations. If we > do, you will be notified prior to perforating. > Thanks, > Rob > 1. Mobilize rig to well and rig up. > 2. Install BPV in tubing hanger > 3. Nipple down injection tree. > 4. Nipple up 11" 5M BOPs and test to 3,000 psi. BOPs will consist of a 1 of 2 8/5/2003 3:41 PM RE: Kustatan Field #1 (200 -153) • > double ram and an annular preventer. The rams will be set up with blinds on > top and pipe rams on the bottom. > 5. Release K- anchor with right hand rotation, pull tubing and laydown. > Tubing needs 5k to 8k upweight at anchor to release. Coil tubing fish > should pull out with the tubing. > 6. Trip in w/ drillpipe and retrieve packer. Send packer and anchor to > Baker Oil Tools for re- dressing. > 7. Cleanout well to 12,000' and swap over to brine. Cleanout should be > made with a used 6 %" PDC bit. The 7 5/8" liner has never been scraped and > still contains water based mud below the existing perforations. > 8. Perforate on drillpipe. > 9. Run new completion. Completion will be the same configuration as > pulled and the packer will be set hydraulically by means of dropping a ball. > 10. Nipple down BOPs > 11. Nipple up 5M injection tree > 12. Perform step test > «KF #1 BOP.xls» > Robert Stinson > Drilling Engineer - Alaska Division > Forest Oil Corporation > (907)- 868 -2133 Name: KF #1 BOP.xls > KF #1 BOP.xls Type: Microsoft Excel Worksheet (application /vnd.ms - excel) > Encoding: base64 2 of 2 8/5/2003 3:41 PM 0 • Kustatan Field #1 -- BOP Layout Q 0 11 rt,TT7 urn m' ([ or n 11 x 5M Annular BOP 11' x 5M Gate (pipe) -" mr . �` 11 x 5M Gate (blinds) _ ,: JO w T L - 111x 111 ' , " LI 13 5/8" 5Mx11 "5M Tubing Head r-- I 13 3/8" Slip -on x 13 5/8" 3M lir Casing Head 1:111 CEO "II IV 11" 5M x 11" 5M Mud Cross w/ two 4" 5M outlets - -- Choke side: 4" 5M manual, 4" 5M HCR, 4" 5M x 3 1/8" 5M DSA Kill side: 4" 5M x 2 1/16" 5M DSA, 2 1/16" 5M manual, 2 1/16" 5M manual, 2 1/16" 5M check • • R F O R E S T O I L C O R P O R A T I O N CO i9 it) .310 cg-- 4 • c> ictte 700 0 Cc w447x. , 014x.X .9,956i O 1 V (907) 258 -8600 • (907) ,258 -8609 (max) August 1, 2003 Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue Suite 100 Anchorage, Alaska 99501 Attn: Mr. Tom Maunder Re: Kustatan Field #1 — Cleanout and Perforation Additions Mr. Maunder, , Disposal operations into the Kustatan Field #1 class II well have been hampered by what we feel is a severely gelled water base mud in the 7 5/8" x 8 '/2" hole annulus. This is the annulus exposed to the disposal fluids. The scope of the requested work is to pull the existing completion and clean the well out, down to 12,000' MD and add additional perforations to the middle and lower Tyonek. These perforations will serve as additional flow paths into the un- cemented annulus, as well as penetrating more of the formation face. A new completion string will be run after perforating. If there are any questions, please contact me at 907 - 258 -8600. 7 k Paul D. White Drilling Manager — Alaska Division Forest Oil Corporation Attachments: 10-403 Application for Sundry Approvals Outline Summary Completion Schematic— 2003 KF #1 Wellhead and BOP configuration Date Modified: 7/30/03 Date Prepared: 7/30/03 rds \\ANCFLS1\#ANC_Drilling\Kustatan Field \KF #1 Disposal\KF #1 Cleanout\KF #1 Cleanout Cover 403.doc f R 1 I STATE OF ALASKA 111 ALAS IL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon: _ Suspend: _ Operation shutdown: Re -enter suspended well: _ Alter casing: _ Repair well: Plugging: Time extension: Stimulate: X Change approved program: Pull tubing: Variance: Perforate: X Other: 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Forest Oil Corporation Development: 260' MSL 3. Address Exploratory: _ 7. Unit or Property name 310 K Street, Suite 700 Stratigraphic: _ N/A Anchorage, Alaska 99501 Service: X 4. Location of well at surface 8. Well number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM Kustatan Field #1 At top of productive interval 9. Permit number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 200 -153 At effective depth 10. API number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 50- 133 - 20496 -00 At total depth 11. Field /Pool 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM N/A 12. Present well condition summary Total depth: measured 12,300' Plugs (measured) true vertical 12,300' Effective depth: measured 12,259' Junk (measured) true vertical 12,259' Casing Length Size Cemented Measured depth True vertical depth Structural N/A N/A N/A N/A N/A Conductor 120' 20" Driven 120' 120' Surface 1,820' 13318" Surface 1,820' 1,820' Intermediate 6,500' 9 5/8" TOC 5,000' 6,500' 6,500' Production (Liner) Liner 5,988' 7 5/8" 706 cu ft 12,300' 12,300' Perforation depth: measured 6,750' to 6,800' 6 spf true vertical 6,750' to 6,800; 6 spf Tubing (size, grade, and measured depth) 2 7/8" 6.5# L -80 EUE Modified, TK -2 Coating @ 6,322' Packers and SSSV (type and measured depth) Baker SC2 -PAH Retreivable (c© 6,270' 13. Attachements Description summary of proposal: X Detailed operations program: ^ BOP sketch. . 14. Estimated date for commencing operation 15. Status of well classification as: 10- Jul -03 16. If proposal well verbally approved: Oil: — Suspended: Name of approver Date approved Service: Class II Disposal 17. I hereby certify that the foregoin is true and correct to the best of my knowledge. Signed: /.17#4----L______ Title: Production Manager, Forest Oil Corporation Date: Ve,71 3 FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Approval N3 Plug integrity, BOP Test )(4 Location clears e , Mechanical Integrity Test_ Subsequent form required 10- 50 0 0 0%W07 *CSAA Cry 7 n } Approved by order of the Commissioner Commissioner Date" vJ CAT Form 10-403 Rev 06/15/88 OJF1.1 SUBMIT IN TRIPLICATE • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 18, 2003 0600 hrs. 57 degrees, partly cloudy BJ services coil Tubing Unit Day# 1 From 1700 hrs. July 17, 2003 to 0600 hrs July 18, 2003 BJ crews and 1 — Peak oilfield Hauler operator arrived at WMRU, went thru orientation, traveled to KPF for further orientation and walk thru the job sight. Traveled to the Barge ramp off loaded equipment and transported to KPF. Set rig liner built containment berms, set and rig up equipment. Don Johnson fabricated a Poor Boy Degasser for circulating Nitrogen. Crew: 1 — Forest oil 8 — BJ services 1 — Peak 1 — APC crane operator Don Jones • • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 19, 2003 0600 hrs. 61 degrees, Clear BJ services coil Tubing Unit Day #2 From 0600 hrs. July 18, 2003 to 0600 hrs July 19, 2003 Finish rigging up, install lubricator and BOPs, Pull test coil tubing connector, make clean out BHA, visual test Rotojet tool. Make up onto wellhead , take on water, test bop from 250 to 5000 psi, (AOGCC Rep Jim Regg was notified and he waived the wittness of the test). Finish building berms around Coil tbg unit and flow return tanks. Attempted to RIH, could not pass top of Injection tree, nipple down top of tree and guide Rotojet by hand into top of tree, nipple up tree. RIH (run in hole) tag up on plug at 5362' = 960' from end of 2 7/8" tbg. At 6322'. Attempt to circulate through Rotojet appears to be plugged off. POH, (pull out of hole) Crew: 1 — Forest oil 8 — BJ services 1 — APC crane operator Cumulative cost : $ 32,955 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 20, 2003 0600 hrs. 58 degrees, Cloudy BJ services coil Tubing Unit Day # 3 From 0600 hrs. July 19, 2003 to 0600 hrs July 20, 2003 POH with Rotojet tool, remove and clean out sediment inside Rotojet , test tool, did not function. Send Rotojet in for rebuild. Make up jet nozzle and RIH, tag and wash through plug at 5362'. Continue in hole. Tag fill at 6460', clean out to 6487'. Made attempts to continue clean out, experiencing excess pull from cuttings between 2 7/8" x 1 ' /2" annulus. CBU, (circulate bottoms up). Pumped N2 sweeps to clear annulus. Appears that the well is feeding coal up into tbg. Only able to clean out tbg. to 6307', (end of tbg. At 6322'). POH, shut in Injection tree. Service and maintenance of equipment, site clean up. Crew: 1 — Forest oil 8 — BJ services 1 — APC crane operator Cumulative cost as of this morning : $ 44,992 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 21, 2003 0600 hrs. 59 degrees, Cloudy BJ services coil Tubing Unit # J158 Day #4 From 0600 hrs. July 20, 2003 to 0600 hrs July 21, 2003 Sent BJ Service crews, Weatherford Mill tool rep. And Scientific Industrial rep (memory logging) in to town. Rig down and return Unocals 200 bbl. Tank. Rig down chiksans to return tank prep for cleaning. Wait on shaker tank equipment. Crew: 1 — Forest oil 3 — BJ services 1 — APC crane operator Cumulative cost as of this morning : $ 123,252 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 23, 2003 0600 hrs. 57 degrees, Cloudy BJ services coil Tubing Unit # J158 Day # 6 From 0600 hrs. July 22, 2003 to 0600 hrs July 23, 2003 Rig down flow back tank and set aside from location, rebuild berms in preparation to receive shaker tank, centrifugal pump and filter unit. Receive Red Dog barge at 2330 hrs. offload and transport to KPF. Begin setting equipment and continue modifications to set shaker unit on shaker tank. Level tank, mount poor boy degasser onto shaker possum belly. Transport N2 pump (bad motor) and misc. Peak trailers onto barge for backload. Crew: 1 — Forest oil 8 — BJ services 1 — APC crane operator Cumulative cost as of this morning : $ 174,663 Don Jones • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 24, 2003 0600 hrs. 53 degrees, Raining BJ services coil Tubing Unit # J158 Day # 7 From 0600 hrs. July 23, 2003 to 0600 hrs July 24, 2003 Rig up shaker tank: set and weld down shale shaker onto pit, set handrails. Route electrical and test agitator and shaker unit. Install 1 — set of screens, set and makeup chiksans to cuttings tank. Makeup chiksans to poorboy degasser. Makeup jet nozzle and perform pull test, nipple up to injection tree and break circulation over shakers and check all surface circulating equipment. RIH circ. At 1 /2 bpm, tag fill at 6185' start N2 down hole at 350 scf /pm. Begin washing fill (coal) from 2 7/8" tbg. To EOT at 6322'. Wash down to 6430' in 7 5/8" casing at 20' avg. intervals. Work pipe circulating bottoms up (CBU), observed overpull, continue working pipe, good circulation. As they continued to pull pipe out of hole coil tbg. parted at 43,000 lbs. Just below injector track chains. BJ operator shut down pumps and closed in injection tree. BJ supervisor estimates the top of the fish is 70' below surface, 6360' of fish left in hole, leaving 8940' of 1 ' /2" coil tbg left on the reel. Bottom of fish est. at 6430'. Approx. 11683 Ibs off of fish in hole at 1.87 Ibs / foot. Began making phone calls for fishing tool availability with Baker and Weatherford. Nipple down lubricator and BOPE, (blow out protection equipment). Crew: 1 — Forest oil 9 — BJ services 1 — APC crane operator Cumulative cost as of this morning : $ 203,797 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 25, 2003 0600 hrs. 52 degrees, Cloudy BJ services coil Tubing Unit # J158 Day # 8 From 0600 hrs. July 24, 2003 to 0600 hrs July 25, 2003 Nipple down BJ BOPE and lubricator to allow rig up of wireline lubricator. Rig up Pollard wireline unit, make gauge ring run to clean hole and locate top of 1 ' / 2" coil tbg. fish. Tagged up on top of fish at 57" below top flange of swab valve = middle of master valve. Made impression block run to verify top of fish and shape of stub. Note: when opening all three valves on tree to test lubricator, swab valve had 20 turns to open, middle valve had 8 turns and master valve also had 8 turns. At end of wireline runs swab and middle valves now had 20 turns and master had 8 tunes, indication that fish maybe moving down hole. Continue making contacts to bring fishing tools, lubricator to KPF to fish 1 1 /2" coil tbg. AOGCC rep Jim Regg was notified of weekly BOPE test, explained status of well and was test was waived. Will renotify once back to normal operations of workover procedure. Crew: 1 — Forest oil 8 — BJ services 1 — APC crane operator Cumulative cost as of this morning : correction to BJ Services tickets included in todays cumulative costs = $ 168,135 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 26, 2003 0600 hrs. 54 degrees, Cloudy BJ services coil Tubing Unit # J158 Day #9 From 0600 hrs. July 25, 2003 to 0600 hrs July 26, 2003 Fishing tools arrived on location with Baker Tools Rep. At 2000 hrs. Function test BOPE, make up overshot BHA, perform pull test. Make up lubricator and pressure test to 5000 psi and steel hose to 8000 psi. Open wellhead, RIH tag top of fish at master valve, pick up to verify weight of fish. Appear to have latched on to fish, verified by closing middle valve 6 turns (normal = 20 turns). Work fish string while pumping at 1.25 bpm 4600 psi to clean up hole. Dispatch vac. Truck and begin mixing up FRW —14 (friction reducer) and circulate through fish at lower pressure higher rate (2.10 bpm 4100 psi) in attempt to clean hole before attempting to drive fish down to free fish before committing to pulling fish above tree valves to change out fishing assy. for a roll on sub. Est. bottom of fish at 6360' = 38' below E.O.T. Note: Observed very little cuttings (coal) over shakers during circulation period. Crew: 1 — Forest oil 9 — BJ services 1 — Baker oil tools 1 — APC crane operator Cumulative cost as of this morning : $ 193,754 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 27, 2003 0600 hrs. 57 degrees, Cloudy, Windy BJ services coil Tubing Unit # J158 Day # 10 From 0600 hrs. July 26, 2003 to 0600 hrs July 27, 2003 Mixed FRW —14 (friction reducer) into system, attempt to work pipe down hole, no go. After working pipe up hole, pull pipe into BOPE slips. Change out fishing tool assy. (observered overshot swelled and some washing) to a roll on sub. Attempt to continue to circulate through fish, pressured up, could not circulate. Rock annulus and coil tbg. With pump pressure, not successful. Confir with BJ coil tbg. techs on alternative technics to establish circulation or work pipe free. After several attempts of high pressure bleed offs while working pipe,were not successful. Pull into BOPE and cut off below roll on sub, install short lubricator and night cap on well, secure all surface equipment and set injection head in basket. Send all BJ reps to town. Begin making calls to locate 1 ' /2" coil tbg cutter and wireline unit. Crew: 1 — Forest oil 9 — BJ services 1 — Baker oil tools 1 — APC crane operator Cumulative cost as of this morning : $ 222,245 Don Jones • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 28, 2003 0600 hrs. 52 degrees, Cloudy, rain BJ services coil Tubing Unit # J158 Day # 11 From 0600 hrs. July 27, 2003 to 0600 hrs July 28, 2003 Waiting on Schlumberger 1 ' /2" coil tbg. Chemical cutter and Pollards E — line unit to be barged to Trading Bay. Note: Barge is to be scheduled for arrival today early evening, BJ crew of 3 to arrive at 1400 hrs. Crew: 1 — Forest oil 0 — BJ services 0 — APC crane operator Cumulative cost as of this morning : $ 228,342 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 29, 2003 0600 hrs. 53 degrees, Cloudy, rain BJ services coil Tubing Unit # J158 Day# 12 From 0600 hrs. July 28, 2003 to 0600 hrs July 29, 2003 Check pressure on well, 0 psi on coil tbg fish, 1 '1/2" x 2 7/8" annulus and 2 7/8" x 9 5/8" casing. BJ crew of 3 arrived, blow down coil with N2, clean out cuttings tank and shaker possum belly. Rig down N2 unit and tanks, transport to barge ramp. Accept barge at 1915 hrs. off Toad Pollard E — line unit, Schlumberger tools, and BJ BOPE, transport to KPF. Begin rigging up BOPE and stab coil tbg into injector head. Set up units: Pollard, crane, injector head and man lift for Free point of 1 '/2" coil tbg. Fish. Crew: 1 — Forest oil 3 — BJ services 1 — APC crane operator 2 — A.P.R.S. (Pipe recovery) 1 — Pollard wireline Cumulative cost as of this morning : $ 242,248 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 30, 2003 0600 hrs. 54 degrees, Cloudy, rain BJ services coil Tubing Unit # J158 Day # 13 From 0600 hrs. July 29, 2003 to 0600 hrs July 30, 2003 Stab injection coil tbg pipe, (piece of straightened coil tbg. 15' long) into injector head. Make up, cut and thread Pollards E -line with APRS free point tool into coil tbg injector pipe, install roll on sub to connect top of fish with injector pipe. RIH with E- line, tag obstruction at 4880', could not pass through. pull 20,000 # on fish to equal the 20,000 # pull weight below the rams, open rams and slips. When rams opened string gained 1000 #, top of fish at roll on sub point yielded and fish dropped back to bottom of tree at master valve. POH with wireline and free point tool, rig aside. Stab coil tbg from reel into injector head and make up fishing tools, (1 ' " overshot). RIH, work over fish and pull to above BOPE, close slips and pipe rams around top of fish to secure. Cut top of fish at spec. pipe, RIH with 1" impression block on wireline to 4875', POH. No impression was made of obstruction. RIH with 1.16 O.D. swedge, jars to 4200' taking weight, work through easily, Tag obstruction at 4875' attempt to work through, no go. POH, make up extra weight bars and prep to RIH in the A.M. secure the well. Send crew to camp. Crew: 1 — Forest oil 3 — BJ services 1 — APC crane operator 2 — A.P.R.S. (Pipe recovery) 2 — Pollard wireline Cumulative cost as of this morning : $ 264,222 Don Jones • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover July 31, 2003 0600 hrs. 52 degrees, Partly cloudy BJ services coil Tubing Unit # J158 Day # 14 From 0600 hrs. July 30, 2003 to 0600 hrs July 31, 2003 P/U extra weight bars and RIH with 1.16" swedge to 4870', hit 10 5840' to 6240' , times fell through, RIH, work through tight spots from 58 9 9 9 p could not pass 6240'. POH, make up 1" impression block RIH to 6271', POH, impression showing fill, RIH with bailer to 6272', POH, little fill (grit sediment) bottom of bailer showing metal mark of setting on profile. BJ supervisor checking depths at time of parting coil tbg. Showing jet nozzle assy. at 6270'. RIH with E -line and free point tool to make dummy run. With 22,000 # up weight on fish FPI tool RIH to 6233', no problems, POH. String E -line through Injector connection and roll on sub and into top of fish with free point tool. Connect top of fish to bottom of injector pipe. RIH with FPI tool, set down periodically from 1117' to 5918' had to make adjustments in pick up and slack off weights to get FPI to bottom at 6232'. Took FP reading from 4200' to 6200', indications of good free coil tbg at 6200'. POH, Cut and unthread tools and E -line. Secure well and send crews to camp. Crew: 1 — Forest oil 3 — BJ services 1 — APC crane operator 2 — A.P.R.S. (Pipe recovery) 2 — Pollard wireline Cumulative cost as of this morning : $ 290,549 Don Jones • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover Aug 1, 2003 0600 hrs. 52 degrees, Partly cloudy BJ services coil Tubing Unit # J158 Da y # 15 From 0600 hrs. July 31, 2003 to 0600 hrs Aug 1, 2003 Cut and thread E -line through BOPE, nipple up second set of BOPE and lubricator, RIH with 1 1/8" chemical cutter, tag up u and work through tight spot at 3989', RIH, tag up and could not pass 4850', POH. RIH with 1.16" swedge on slick line to 6271', saw afew bobbles, did not have to sto p, POH. RIH with 1 1/16" chemical cutter, work through tight spots, tag bottom at 5915',pick up to 5900', cutter did not fire, POH. Change out connector on firing head, RIH. RIH, to 5915', make cut at 5900', POH with cutter. NOTE: top of fish at ' total length of fish =370' bottom of fish at 6270'. Nipple , tota g pp le down BOPE and lubricator. Connect top of fish to coil, pull test to 23,000 #, open rams and slips, observed weight drop from 15000 # to 7500 #. POH with fish. Begin rigging down, secure well. Send crews to camp. NOTE: notified AOGCC rep. Jim Regg of well status and that we would give 24 hr. notice of initial BOPE test on Inlet Drillings C.C. # 1 rig. Crew: 1 — Forest oil 3 — BJ services 1 — APC crane operator 2 — A.P.R.S. (Pipe recovery) 2 — Pollard wireline Cumulative cost as of this morning : $ 353,076 Don Jones 111 • Forest Oil Corporation Kustatan Field # 1 Coil Tubing workover Aug 2, 2003 0600 hrs. 52 degrees, Partly cloudy BJ services coil Tubing Unit # J158 Day # 16 From 0600 hrs. Aug 1, 2003 to 0600 hrs Auq 2, 2003 Rig down Coil tbg unit, set on float trailers and transport to barge landing. Send BJ crew to town. Clean location and grade level around wellhead in preparation to receive Inlet Drilling Rig C.C. # 1 Crew: 1 — Forest oil 3 — BJ services 1 — APC crane operator Cumulative cost as of this morning: $ 327,503, BJ services cost correction is included Don Jones • Forest Oil Corporation Kustatan Field # 1 Workover Aug 7, 2003 0600 hrs. 53 degrees, Partly cloudy Inlet Drilling of Alaska, Rig C.C. # 1 Day # 7 From 0600 hrs. Aug 6, 2003 to 0600 hrs Aug 7, 2003 Nipple up BOPE, Refab and install kill line, pull BPV and install 2 — way check valve into top of tbg. Hanger. Rig up and test BOPE, choke manifold, kill line, HCR, manual valves from 250 psi to 3000 psi. Test rams, Hydril bag, floor valves from 250 to 3000 psi. Perform Koomey time test. Test gas alarms. All tests wittnessed by AOGCC rep. Continue with fab and installation of flow nipple, berm and set 2 — Rain for Rent 500 bbl tiger tanks. Fill pits with Production water. Crew: 1 — Forest oil 15 — Inlet Drilling 1 Baker Oil Tools 2 — Weatherford 1 — AOGCC 1 — Vetco Gray Cumulative cost as of this morning: Will include on tomorrows report Don Jones • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 8, 2003 0600 hrs. 57 degrees, Clear Inlet Drilling of Alaska, Rig C.C. # 1 Day # 8 From 0600 hrs. Aug 7, 2003 to 0600 hrs Aug 8, 2003 0600 —1230 hrs: Pull 2 — way check valve from tbg hanger, M/U landing joint, rig up Weatherford tbg tongs. Attempt to release K- anchor from Baker Packer set at 6270', pull 5 to 10k over string weight and begin working right hand torque down to top of packer to back out K- anchor acme thread, try different pull weights and torque sequences, not successful. 1230 —1630 hrs: Wait on APRS rep and collar locator / 2 %" jet cutter 1630 — 0030 hrs: R/U APRS, cut / thread through xo to tbg hanger from landing joint with collar locator / Jet cutter on Pollard wireline. RIH, tag up on 1 1/2" coil tbg fish at 5900', locate collar at 5869', lower and make cut on 2 7/8" tbg at 5884' = 16' above 1 % / %" fish, POH. 0030 — 0230 hrs: Breakout landing joint, rig down wireline, laydown tbg hanger. 0230 — 0600 hrs: POH, standing back 2 7/8" tbg. In derrick, checking connections on the way out of hole. Crew: 1 — Forest oil 15 — Inlet Drilling 1 — Baker Oil Tools 2 — Weatherford 1 — Vetco Gray 1 — Pollard wireline 1 - APRS Cumulative cost as of this morning: $ 160,187 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 9, 2003 0600 hrs. 56 degrees, Clear Inlet Drilling of Alaska, Rig C.C. # 1 Day # 9 From 0600 hrs. Aug 8, 2003 to 0600 hrs Aug 9, 2003 0600 — 0700 hrs: POH with 188 joints of 2 7/8" tbg, (doubles in derrick) and 14.90' stub. Fish left in hole = 15' stub, 11 joints of 2 7/8" tbg, pkr SC2, 370' of 1 ' /z" coil tbg. Fish, 10' pup, xn nipple, 1 — jt. Of 2 7 /8 "tbg, WLEG. 0700 —1030 hrs: Change rams f/ 2 7/8" to 3 W', test doors and rams f/ 250 — 3000 psi, set wear ring. 1030 —1230 hrs: Strap, drift and M/U 2 7/8" overshot assy. BHA. 1230 — 2100 hrs: Strap, drift and R1H with 3 '1" drill pipe 2100 — 2400 hrs: M/U kelly, RIH, tag up on 2 7/8" fish with 89 stand (doubles) of 3 drill pipe at 5900', 2400 — 0130 hrs: work over fish, mill top of shot stub, slide over fish 5', pick up 5k over string wt. Rotate to the right 10 turns, weight dropped off to 5k over normal string wt. 0130 — 0600 hrs: monitor well flow, static. POH slow with overshot BHA and 5k # of fish Crew: 1 — Forest oil 15 — Inlet Drilling 1 — Baker Oil Tools 1 — Weatherford Cumulative cost as of this morning: $ 196,125 Don Jones • Forest 00 Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 10, 2003 0600 hrs. 56 degrees, Clear Inlet Drilling of Alaska, Rig C.C. # 1 Day # 10 From 0600 hrs. Aug 9, 2003 to 0600 hrs Aug 10, 2003 0600 — 0730 hrs: POH, with 2 7/8" overshot and 2 7/8" tbg. Fish 0730 — 0930 hrs: L/D 2 7/8" tbg fish, (11 jts.) and Baker Packer SC -2 K — anchor. 0930 —1200 hrs: M/U BHA #2: 1 W grapple, with crows foot at 345' above overshot for stop of 1 1 /2" fish. 1200 —1800 hrs: RIH. 1800 — 2000 hrs: work over top of 1 1 /2" fish, swallow fish from 5921' to 6253', (top of pkr @ 6270'), apply 1500 psi pump pressure to fish, work fish 10k # above string wt. To 2k # below string wt. On forth reciprocation string wt. Fell off as well as pump pressure, appear to have free 1 1 /2" fish. 2000.2300 hrs: CBU, balance fluid wt. In hole and clean out I.D. of Packer, check for flow 2300 — 0400 hrs: POH, slow with 1 1 /2" fish assy. 0400 — 0600 hrs: cut 30' sections of 1 1 /2" fish and lay out V - door onto pipe rack Crew: 1 — Forest oil 15 -- Inlet Drilling 1 — Baker Oil Tools Cumulative cost as of this morning: $ 222,970 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 11, 2003 0600 hrs, 57 degrees, Cloudy, rain Inlet Drilling of Alaska, Rig C.C. # 1 Day # 11 From 0600 hrs. Aug 10, 2003 to 0600 hrs Aug 11, 2003 0600 — 0900 hrs: Lay down 330' of 1 ' /2" coil tbg fish and fishing tools 0900 — 1700 hrs: Wait on wash pipe and 9 5/8" Packer fishing tools 1700 — 1800 hrs: Make up 8 1/8" 0.D. 7 %4" I.D. wash pipe assy. (BHA # 3) 1800 — 2330 hrs: RIH, slow (wet) 2330 - 0130 hrs: Work over 1 %" coil tbg fish and begin milling on Baker Packer SC — 2 PAH from 6258' to 6261' 0130 — 0230 hrs: Appears that PKR. Has dropped down hole, observed gas breaking out in bell nipple, (trapped N2 below PKR. from Coil tbg. Project) monitor well. 0230 — 0300 hrs: Chase PKR. To 7 5/8" liner top at 6310' (bottom of PKR. Depth) 0300 — 0400 hrs: CBU through choke, monitor pit volumes and N2 break out at gas buster 0400 — 0600 hrs: Check well for flow, (well stable). POH with 8 1/8" wash pipe assy. NOTE: POH to M/U and RIH with overshot to retrieve Packer assy. Crew: 1 — Forest oil 15 Inlet Drilling 1 — Baker Oil Tools 2 — Weaver Bros. Cumulative cost as of this morning: $ 244,576 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 12, 2003 0600 hrs. 56 degrees, Cloudy, rain Inlet Drilling of Alaska, Rig C.C. # 1 Day # 12 From 0600 hrs. Aug 11, 2003 to 0600 hrs Aug 12, 2003 0600 —1030 hrs: POH and L/D BHA # 3, 1 — joint of washpipe, and mill over shoe assy. Clean out junk baskets, (3 gallons of metal shavings, pieces element rubber. 1030 —1600 hrs: M/U and RIH with BHA # 4, 7" overshot assy. 1600 — 1700 hrs: workover 1 W coil tbg and 7" top of packer, jar at 10k over string wt., on 6 attempt to jar up pulled to 15k over string wt. and fish appeared to have jarred loose with 3k over free string wt. 1700 — 2400 hrs: check for flow, POH,slow 2400 — 0130 hrs: L/D overshot, (no fish, packer), broken grapple one circle recovered, two left in hole, M/U 8'/2" O.D. x 7" I.D. burn shoe 0130 — 0600 hrs: RIH with BHA # 5 Burn shoe assy. Crew: 1 — Forest oil 15 — Inlet Drilling 1 — Baker Oil Tools 2 — Weaver Bros. Cumulative cost as of this morning: $ 261,962 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 13, 2003 0600 hrs. 56 degrees, Cloudy, rain Inlet Drilling of Alaska, Rig C.C. # 1 Day # 13 From 0600 hrs. Aug 12, 2003 to 0600 hrs Aug 13. 2003 0600 — 0700 hrs: RIH, w/ BHA #5, Burn shoe assy. 0700 — 1230 hrs: Wash junk and metal shavings, Workover 1 1 /2" coil tbg. and top of Packer at 6295', begin milling from 6295' to 6299' 1230 — 1400 hrs: Circ and wash up shavings into junk baskets 1400 — 1830 hrs: Check flow, POH with BHA #5 1830 — 2400 hrs: UD BHA, recovered Baker SC -2 PAH packer, tail pipe assy, coil tbg with coil tbg connector, double check valve sub. NOTE: Coil tbg jet assy. unscrewed left in hole = straight bar 1 1/2" o.d. 3' length and jet nozzle 1 1/2° o.d. 5" length = 41" total coil tbg fish length 2400 — 0130 hrs: P/U BHA #6, 8 ' /2" bit, 9 5/8" casing scraper, 2 — junk baskets 0130 — 0600 hrs; RIH with BHA #6, NOTE: We have 1 %" coil tbg. fishing tools ready for this A.M. flight, will fish out of 7 5/8" casing, coal settled in 7 5/8" at est. 6730'. We gave 24 hrs notice to Jim Regg AOGCC yesturday for todays BOPE test after we POH with BHA #6 Crew: 1 — Forest oil 15 — Inlet Drilling 1 — Baker Oil Tools 2 — Weaver Bros. Cumulative cost as of this morning: $ 280,898 Don Jones 2-d L 9LL L06 RgIitaed uegegsn) eT2 :SO ED ET 2n1LI • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 14, 2003 0600 hrs. 54 degrees, Cloudy, rain Inlet Drilling of Alaska, Rig C.C. # 1 Day # 14 From 0600 hrs. Aug 13, 2003 to 0600 hrs Aug 14, 2003 0600 — 0930 hrs: Work pressures to fill junk baskets (2), CBU 0930 1430 hrs: Check flow, POH w/ BHA # 6 1430 —1500 hrs: Make up BHA # 7, Roller dog junk catch assy. 1500 — 2000 hrs: RIH to 6539' 2000 — 2200 hrs: Wash F/ 6539' T/ 6723' 2200 - 0300 hrs: Change shaker screens, (lots of coal and some gas), continue washing / reaming F/ 6723' T/ 6754', (Perf. Top shot a 6750'), Encountered, high torque and slow penetration rate acts like junk or jagged perfs. NOTE; observing coal demensions: 1 1 /2" — 2" long x 1 1 /2" wide x 1" thick 0300 — 0430 hrs: CBU, clean hole 0430 — 0600 hrs: POH, w/ BHA # 7, Plan to P/U BHA # 8 = 2 mills, bottom mill 5 3/4" 6 bladed junk mill with 6 — 1/4" flow ports, bit sub, 6 %" string mill, 2 — junk baskets assy. NOTE: AOGCC Rep. Jim Regg waived weekly BOPE test Crew: 1 — Forest oil 15 — Inlet Drilling 1 — Baker Oil Tools 2 — Weaver Bros. Cumulative cost as of this morning: $ 300,934 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 15, 2003 0600 hrs. 54 degrees, Cloudy, rain Inlet Drilling of Alaska, Rig C.C. # 1 Day # 15 From 0600 hrs. Aug 14, 2003 to 0600 hrs Aug 15, 2003 0600 — 1030 hrs: Check flow, POH w/ BHA # 7, (Roller dog catch assy.) 1030 — 1300 hrs: L/D BHA # 7, shoe showing rounded O.D. gauge, piece of shoe tooth and skirt from junk basket missing, did not catch 1 1 /2" coil jet nozzle assy. fish. Monitor well, flow rate at 1 bph 1300 — 1800 hrs: P/U BHA # 8 = 3 — joints of 2 7/8" tbg with mule shoe. RIH , tag fill at 6692' (POH last trip at 6754') 1800 — 2200 hrs: Wash / Ream f/ 6692' t/ 6743', encountered high torque, could not pass, (7' from top perf at 6750') 2200 - 0400 hrs: Finish mixing Flo Vis to workover fluid system, circulate / clean up coal from hole 0400 — 0600 hrs: Check flow, POH w/ BHA # 8 Crew: 1 — Forest oil 15 — Inlet Drilling 1 — Baker Oil Tools 2 — Weaver Bros. Cumulative cost as of this morning: $ 321,660 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 16, 2003 0600 hrs. 54 degrees, Cloudy, rain Inlet Drilling of Alaska, Rig C.C. # 1 Day# 16 From 0600 hrs. Aug 15, 2003 to 0600 hrs Aug 16, 2003 0600 — 1000 hrs: POH, (wet) with BHA # 8 1000 — 1030 hrs: L/D BHA # 8 1030 — 1130 hrs: Service Rig 1130 — 1230 hrs: Strap, M/U BHA # 9 1230 — 1600 hrs: RIH 1600 — 2000 hrs: Decision was made to Perforate upper zones, POH w /BHA #9 2000 — 2400 hrs: L/D BHA and kelly 2400 — 0330 hrs: Test BOPE from 250 psi to 3000 psi 0330 — 0600 hrs: Wait on Halliburton Perforating Rep. (due to fly in at 0800 hrs) Crew: 1 — Forest oil 15 — Inlet Drilling 1 — Baker Oil Tools 2 — Weaver Bros. Cumulative cost as of this morning: $ 340,946 =n Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 17, 2003 0600 hrs. 54 degrees, Cloudy, rain Inlet Drilling of Alaska, Rig C.C. # 1 Day # 17 From 0600 hrs. Aug 16, 2003 to 0600 hrs Aug 17, 2003 0600 — 0930 hrs: Halliburton Perf. Rep. not able to fly due to bad weather 0930 —1330 hrs: RIH w/ 1 — joint of 2 7/8" tbg. and mule shoe on drill pipe, (SLM, no correction made) to 6503' 1330 —1630 hrs: Reverse circulate hole clean, displace hole with 8.3+ ppg produced water, taking returns to 500 bbl. Tiger tank 1630 — 2000 hrs: POH. NOTE: Due to bad weather fixed wing aircraft not able to fly, Halliburton rep. arrived by chopper at 1830 hrs. 2000 - 2400 hrs: Held pre job safety meeting, strap and pick up 3 3/8" Millennium mechanical perf. Guns, 6 spf, 60 degree phase, 45 caliber. 2400 — 0500 hrs: RIH w/ 258.59' of Perf. Gun assy. 0500 — 0600 hrs: Set guns to depth, bottom shot at 6475', top shot of 1 run = 6344'. M/U floor valve, lower 1 1/4" detonator bar into work string, drop at 0509 hrs. observed detonation of perf. guns at 0513 hrs. Monitor well. Crew: 1 — Forest oil 15 — Inlet Drilling 2 — Weaver Bros. 1 — Halliburton Cumulative cost as of this morning: $ 443,398 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 18, 2003 0600 hrs. 50 degrees, Partly Cloudy Inlet Drilling of Alaska, Rig C.C. # 1 Day # 18 From 0600 hrs. Aug 17, 2003 to 0600 hrs Aug 18, 2003 0600 — 0900 hrs: POH w/ Perf gun assy. # 1 (Note: Penetration of Millennium shot = 38" as per lab tests). 0900 — 1030 hrs: L/D Gun assy. (100% shot) �o 1030 — 1200 hrs: PJSM, P/U Perf gun assy. # 2 1200 — 1500 hrs: RIH 1500 — 1530 hrs: Set to depth, bottom shot at 6301', top shot at 6267', drop 1 1 /4" detonator bar at 1528 hrs. shots made at 1532 hrs. 1530 — 1600 hrs: Monitor well, flow rate at 2 — BPH 1600 — 2000 hrs: POH w/ Perf gun assy. # 2 2000 — 2130 hrs: L/D guns, (100% shot) 2130 — 2230 hrs: P/U Baker SC -2 Packer assy. = WLEG, 1 — joint of 2 7/8" tbg, "X" nipple (2.31" I.D.), 10' — pup 2 7/8" tbg, Baker Packer assy, and running tool on 3 '/2" drill pipe 2230 - 0300 hrs: RIH, slow. Encountered tight spot at 5666', (WLEG depth, 570' f/ desired WLEG depth). Attempt to work through, no go 0300 — 0600 hrs: POH, slow to prevent swabbing hole, visually monitor annulus down flow nipple the first 5 stands of drill pipe to find and set desired trip rate NOTE: POH to pick up 8 '/2" bit and 9 5/8" scraper BHA Crew: 1 — Forest oil 15 — Inlet Drilling 2 — Weaver Bros. 1 — Halliburton 1 — Weatherford 2 — BJ services 1 — Baker Oil Tools 1 — Veto Gray Cumulative cost as of this morning: $ 510,819 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 19, 2003 0600 hrs. 50 degrees, Partly Cloudy Inlet Drilling of Alaska, Rig C.C. # 1 Day # 19 From 0600 hrs. Aug 18, 2003 to 0600 hrs Auq 19, 2003 0600 —1230 hrs: POH, slow to prevent swabbing hole, visually monitor annulus down flow nipple the first 5 stands of drill pipe to find and set desired trip rate 1230 —1300 hrs: L/D Baker SC -2 Packer, observed top backup ring had been compressed and was excessively O.D. flared. NOTE; Set up air tranport to Baker Oil tools shop to be rebuilt, return to Location at 2130 hrs. 1300 — 1600 hrs: Decision was made to RIH with 8.47" gauge ring and Junk basket on Pollard Wireline. Note: Packer largest O.D. = 8.44. While gauge ring was being built up and lathed to spec. serviced rig, slip and cut 90' of drill line 1600 — 2000 hrs: Rig up Pollard Wireline equipment and thread 8.4r gauge ring / junk basket through lubricator and set lubricator into Hydril Bag 2000 — 0600 hrs: Made 4 — runs to 6247' first run recovered fine metal shavings , very little amount, second run the same recovery, third and forth run, no junk or cuttings recovered. Crew: 1 — Forest oil 15 — Inlet Drilling 2 — Weaver Bros. 1 — Weatherford 1 — BJ services 1 — Baker Oil Tools 2 — Pollard Wireline Cumulative cost as of this morning: $ 533,190 Don Jones • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 20, 2003 0600 hrs. 50 degrees, Cloudy Inlet Drilling of Alaska, Rig C.C. # 1 Day # 20 From 0600 hrs. Aug 19, 2003 to 0600 hrs Aug 20, 2003 0600 — 0730 hrs: Check Pollard gauge ring / Junk basket, (no cuttings), R/D wireline equipment 0730 — 0930 hrs: P/U Baker SC -2 Packer w/ tail pipe assy. = Muleshoe, 1 — joint 2 7/8" tbg, "X" nipple, 10' 2 7/8" pup, Pkr assy. and running tool 0930 — 1500 hrs: RIH (slow), to 6216' = muleshoe depth, perf. top shot at 6267' = muleshoe 51' above top shot, bottom of packer at 6165', top of packer at 6160' 1500 — 1730 hrs: Drop 1 7/16" steel ball, rig up BJ services, test lines to 5000 psi, set packer in stages from 1300 psi to 2900 psi, pull test (pkr set) test annulus and Pkr to 1500 psi for 15 mins, make 15 turns to the right and release running tool, pressure up and shear ball at 3975 psi, rig down BJ services 1730 — 0230 hrs: L/D 3'/2" drill pipe, running tool, drill collars from derrick. 0230 — 0600 hrs: Pull wear ring, set test plug, change rams from 3 '/2" to 2 7/8" rams, rig up to test bonnets and 2 7/8" rams f/ 250 to 3000 psi Crew: 1 — Forest oil 15 — Inlet Drilling 2 — Weaver Bros. 1 — Weatherford 1 — BJ services 1 — Baker Oil Tools Cumulative cost as of this morning: $ 557,436 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 21, 2003 0600 hrs. 52 degrees, Cloudy, rain Inlet Drilling of Alaska, Rig C.C. # 1 Day # 21 From 0600 hrs. Aug 20, 2003 to 0600 hrs Aug 21, 2003 0600 — 0730 hrs: Change rams f/ 3 '/2" to 2 7/8 ", test bonnets / rams f/ 250 psi to 3000 psi 0730 — 1630 hrs: Run 3.61' seal / anchor assy. on 2 7/8" 6.5# L -80, TK -2 I.D. coated tbg. SLM and drift from derrick, to 6129', check up /down wts. = 46 # up and 45 # down 1630 — 1800 hrs: Circulate down and wash top of Packer at 6160', stab in bottom seal on seal assy. to verify space out of tbg. hanger. Space out and install tbg. hanger (No pups needed). Set hanger 2' below Hydril bag, close bag and R/U to reverse circulate 1800 — 2100 hrs: Rev. circ. In all 360 bbls of corrosion inhibitor from production tank # 146 down 2 7/8" x 9 5/8" annulus, pump 4 bbls of diesel (freeze protection) = 60' of annulus. Land tbg. hanger, pull test to verify anchor is latched into top of Baker SC -2 Packer (over pull of 5k #) land hanger and lock down with set screws. 2100 — 2230 hrs: R/U and Perform a M.I.T. on 2 7/8" x 9 5/8" annulus with BJ services pump truck, pressure up to 1600 psi on annulus for 30 min. Tbg. pressure started at 0 psi and increased to 75 psi and held for 20 mins of 30 min test, tested top of Packer, seal assy. 2 7/8" tbg. and tbg. hanger (good test). 2230 — 0600hrs: L/D landing joint, install 2 — way check valve into tbg. hanger. Begin nippling down BOPE, clean out ram cavities and set on trailer float. Prep to nipple up Injection tree. Crew: 1 — Forest oil 14 — Inlet Drilling 2 — Weaver Bros. 1 — Weatherford 2 — BJ services 1 — Baker Oil Tools 1 — Vetco Gray • Cumulative cost as of this morning: $ 630,970 Don Jones • • Forest Oil Corporation Kustatan Field # 1 Workover, Clean out / Perforate Aug 22, 2003 0600 hrs. 52 degrees, Cloudy, rain Inlet Drilling of Alaska, Rig C.C. # 1 Day # 22 From 0600 hrs. Aug 21, 2003 to 0600 hrs Aug 22, 2003 0600 — 0930 hrs: Nipple up Injection tree, test tbg. hanger neck and void to 5000 psi for 15 mins. (good test), test tree to 5000 psi for 15 mins. (good test) 0930 —1230 hrs: R/U BJ services to Inject. tree, test lines t/ 5000 psi 1230 —1800 hrs: Perform Injection step test: Start test at 1225 hrs. start at 1 /2 bpm rate and increase at 1 /2 bpm increments at 30 min. Intervals. NOTE: Did not observe formation break down visually or through graph prints outs. Initial injection test: 1860 psi at % bpm. End of test : 5 bpm at 3430 psi, finish test at 1742 hrs. Total barrels pumped during test = 886 bbls, initial shut in pressure = 3430 psi. Formation bled to 2430 psi in 30 mins. = 1000 psi bleed off. Bled 10 bbls back to zero psi. Shut in well, Pressure increased and stabilized at 2000 psi on tree. Monitored 2 7/8" tbg x 9 5/8" casing annulus during test, observed 150 psi 5 hrs into test. (BJ services Dave Wallingford will E -mail graphs and print outs to Drilling dept.)Clean pits while testing. NOTE: Released rig at 1800 hrs. 1800 — 0600 hrs: Begin Rig down of C.C. # 1, demob to barge landing. First Barge (Red Dog) E.T.A. tonight at midnight Crew: 1 — Forest oil 14 — Inlet Drilling 3 — Weaver Bros. 2 — BJ services Cumulative cost as of this morning: $ 669,582 Don Jones ® Kustatan Step Rate Test . August 21, 2003 5000 - 5 Pressure (psi) 4500 Pump Rate (bpm) — 4.5 4000 IT 4 • co ,a 3500 — 3 -E-- L. y 3000 — 3 .. as °' C 2500 ��, 6 — 2.5 C4 c 2 O it 2000 — 2 d a) c c. `� 1500 — 1.5 1000 — 1 500 — 0.5 0 -I , , , , , , JL 0 0 50 100 150 200 250 300 350 400 Elapsed Time (min) • • PROCEDURE CIO K # 1 and Add Perfs 7/8/03 Q i Treatment Objective: Mill out X- Nipple to 6,298' r fired to deploy TCP guns to depth and retrieve. RotoJet to clean out 7 -5/8" casing from 6,850' - 7,100' or deeper as required. Deploy TCP guns on coiled tubing and perforate three (3) new sections a orstirfg to Forest Oil engineering. Equipment: 1.50" Coiled Tubing Unit BOPE Data Acquisition Unit Dual Triplex Pump Skid RotoJet Wash Tool 5K Choke Manifold Flowback Iron & Tank(s) (Forest Oil supplied) Double Flapper Check Valve Coiled Tubing Connector Crossover Sub Hydraulic Disconnect Circ. Sub, Check Valve, 1- 11/16" Motor, Diamond or Carbide Mill (2.39" - 2.41 ") (Third party supplied) High Pressure Surface Filter Nitrogen Pump with Nitrogen Tank All Necessary WH Adapters and Connections Flow Tee Procedure: 1. Rig up coiled tubing, pumping and nitrogen equipment. RU DH motor and mill. `7 jam`(/ 2. Pressure test reel, lines, fluid and nitrogen pump and BOP to 1,000 psi above maximum allowable surface pressure as specified by Forest representative. Pressure test flowback iron and choke manifold to 5000 psi. 3. RIH with BHA at ROP consistent with BJ Coiltech timeline to 6,298'. Mill X- Nipple to 6.30 ". POOH with CT and BHA. 4. LD BHA. PU RotoJet tool. RIH to 6,850', ROP to be consistent with BJ Coiltech timeline. Rotojet 7 -5/8" casing from 6,850' - 8,150'. RotoJet operation to be performed in accordance with CIRCA simulation. 5. Circulate bottoms up and POOH. LD RotoJet. PU TCP guns in 22' section. RIH to 6,880' and shoot perforations from 6,880' — 6,940' (60'), 6,965 — 7,015' (50'). POOH. / is 6 m 7 �7 6. LD spent guns. PU 115' section of TCP guns. RIH to 7,990' and shoot perforations from 7,990 — 8,105' (115'). POOH. 7. Purge CT with N2. Perform perforation breakdown with lease water at 3 -5 BPM. 8. RDMO BJ equipment. Gr4135 Ku tan Field #1 Proposed Added Perforations 20" K -55 133# Welded 120' MD 2 7/8" 6.4# L -80 EUE w/ TK- ° 2 Coating • 13 3/8" L -80 68# BTC 1,820' MD 6,268' Model "K" Anchor ~ TIJ 6,270' BakerSC2 -PAH Retr.Pkr I 6,278' 10' pup 2 7/8" Top of 7 5/8" Liner © 6,312' MD 6,288' XN Nipple 6,290' 1 jt 2 7/8" II ! 6,322' WEG 9 5/8" L -80 47# BTC 6,500' MD 6,750' to Perforations 6 spf 6,800' Existing Proposed Perfs: 6,880' - 6,940' 6,965' - 7,015' 7,990' - 8,105' Alternate Perfs: _ 7,325' - 7,440' 7 5/8" L -80 29.7# STL / FL4S 12,300' MD a • • --(tec---/d5- O R E S F O R E S T O I L C O R P O R A T I O N 19 �` �b 3/0 c �ir� �--eet • C ' ra/e 700 � C132//i c/dae, Q laJ/a 9950/ O I \- C907) 258 -8600 • 007) 2.58 -86'6i ( max) April 28, 2003 Sarah Palin , Chair Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue Suite 100 Anchorage, Alaska 99501 Re: Kustatan Field #1 — Class II Completion Ms. Palin, Kustatan Field #1 was drilled as an unsuccessful exploration well in 2000. Operations were ceased on the well until March 2003. The well has now been completed as a Class II disposal well. If there are any questions, please contact me at 907 - 258 -8600. RECEIVED Paul D. White APR 2 9 2003 Drilling Manager — Alaska Division Forest Oil Corporation Alaska Oil & Gas Cons. Commission Anchorage Attachments: 10-407 Well Completion Report and Log Completion Schematic — April 2003 Operations Log Inclination Surveys Date Modified: 4/28/03 Date Prepared: 4/28/03 rds M:\Kustatan Field\KF #1 Disposal\KF #1 Completion'KF #1 Cover 407.doc --- fREINAL *► 1 1 STATE OF ALASKA 1 • ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL: GAS: SUSPENDED: ABANDONED: SERVICE: Class I1 Disposal 2. Name of Operator 7. Permit Number Forest Oil Corporation 200 -153 3. Address 310 K Street, Suite 700 8. API Number Anchorage, Alaska 99501 50- 133 - 20496 -00 4. Location of well at surface COMP ETION k 9. Unit or Lease Name 1 3443' FNL, 1468' FWL, Section 4, TO7N, R14W, SM D,--E 2 ¢ tool • '» n/a At Top Producing Interval f '103 1 y .; ' 10. Well Number VFR'FiEO �. Kustatan Field #1 At Total Depth ? e � 1` 11. Field and Pool 3443' FNL, 1468' FWL, Section 4, TO7N, R14W, SM .:.w ^ °'' 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. 260 RKB n/a 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 15. Water Depth, if offshore 16. No. of Completions 10/16/2000 12/04/2000 04/01/2003 n/a feet MSL 1 17. Total Depth (MD +TVD) 18. Plug Back Depth (MD +TVD) 19. Directional Survey 20. Depth where SSSV set 21. Thickness of Permafrost 12,300' MD / 12,300' TVD 12,259' MD / 12,259' TVD Yes: x No: n/a n/a 22. Type Electric or Other Logs Run QuadCombo, Usit 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 133# K -55 Surf. 120' driven n/a None 13 3/8" 68# L -80 Surf. 1,820' 17 1/2" Surface None 9 5/8" 47# L -80 Surf. 6,500' 12 1/4" 643 cu ft None 7 5/8" 29.7# L -80 6,312' 12,300' 8 1/2" 678 cu ft None 24. Perforations open to Production (MD +TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 2 7/8" 6,270' 6,270' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) n/a Date of Test Hours Tested PRODUCTION FOR OIL -BBL GAS -MCF WATER -BBL CHOKE SIZE GAS -OIL RATIO TEST PERIOD => Flow Tubing Casing Pressure CALCULATED OIL -BBL GAS -MCF WATER -BBL OIL GRAVITY -API (corr) Press. 24 -HOUR RATE _> 28. CORE DATA C Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips RECEIVED APR 2 9 2003 ° g § 4,S, L!`-'? '' '' ' ' ' Alaska Oil & Gas Cons. Commission G/' Anchorage O R!GINAL Form 10 -407 ---- Rev. 7 -1 -80 CONTINUED ON REVERSE SIDE Submit in duplicate 2 • 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH SSTVD GOR, and time of each phase. Tyonek 1,820' 1,560' G -Zone 11,010' 10,750' Hemlock 11,468' 11,208' West Foreland 12,016' 11,756' RECEIVED APR 2 9 2003 Alaska Oil & Gas Cons. Commission Anchorage 31. LIST OF ATTACHMENTS Well Schematic, Daily Operations Summary, Final Directional Survey 32. I hereby ' that the foregoing is true and correct to the best of my knowledge Signed" 's ' nA Title Drilling Manager Date q d 3 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 space 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 productin intervals for only 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 (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut -in, Other- explain. Item 28: If no cores taken, indicate "none ". Form 10 -407 ORIGINAL KuStan Field #1 • Completed 4/1/03 - Class II Disposal 20" K -55 133# Welded 120' MD 2 7/8" 6.4# L -80 EUE w/ TK- 2 Coating 13 3/8" L - 68# BTC 1,820' MD 6,268' Model "K" Anchor 6,270' Baker SC2 -PAH Retr.Pkr 6,278' 10' pup 2 7/8" Topof75 /8 "Liner @6,312'MD 6,288' XN Nipple P 6,290' 1 jt 2 7/8" '■ ) ■, III 6,322' WEG 9 5/8" L -80 47# BTC 6,500' MD 6,750' to Perforations 6 spf 6,800' 7 5/8" L - 29.7# STL / FL4S 12,300' MD ._ I • sry FOREST OIL CORP. ;; Page 1 of 15 r .; r _ 5 C p rations L ar Re p ort Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 1 Date From - to H ours Code F.Code Phase Descript or raltioos; 10/12/2000 19:00 - 01 A MIRU Rigging up 10/13/2000 06:00 - 12:00 6.00 01 A MIRU Rigging up 12:00 - 06:00 18.00 01 A MIRU Rigging up 10/14/2000 06:00 - 12:00 6.00 01 A MIRU Hook up electric to top drive. Rig degasser lines. 12:00 - 00:00 12.00 01 A MIRU PJSM Rig up sub section flow line. Pull out centrifuge. Rig up stabbing board. Rig up V- doors. Help welder run 3" mud line for trip tank. Fill suction pit with water. Plumb in cellar tugger. Hook up fill -up line. Silicon cracks in pump room floor.Start berm around rig. put packing in test pump. 00:00 - 06:00 6.00 01 A MIRU Continue to rig up. 10/15/2000 06:00 - 12:00 6.00 01 A MIRU Welder working on mud fine. Put blower motor on top drive. Put bails on top drive. Test electricity on top drive.Berm around rig. Rig down rig.Fill pits with water. Welding braden head to 20" conductor. Hook up monitors and cameras. Rig up wireline machine. 12:00 - 12:30 0.50 01 A MIRU PJSM Rig up remote accumulator line. 12:30 - 18:00 5.50 01 A MIRU Welding braden head on 20" casing. 18:00 - 21:00 3.00 01 A MIRU Allow weld on head to cool. Prep equipment for nipple up, while mixing spud mud. 21:00 - 00:00 3.00 14 A MIRU Nipple up 20" diverter. 00:00 - 06:00 6.00 14 A MIRU Nipple up diverter line from cellar. Make up drilling nipple, flow line, hydraulic lines,and knife valve. 10/16/2000 06:00 - 12:00 6.00 14 A MIRU Making up driling nipple and flow line. Mixing mud. Test Hydril diverter and Knife valve. for AAOGCC test. Also Koomey test. Test OK.RoII mud pumps. Check alarms. H2S and methane gas calibrated. 12:00 - 18:00 6.00 14 A MIRU Nipple up flow nipple, flow line and fill up line. 18:00 - 20:00 2.00 25 MIRU Reading tools for spud in. 20:00 - 00:00 4.00 01 A MIRU Welder repairing slop tank. Dig trench for dump truck to haul cuttings. Lay liner and mats in trench. 00:00 - 03:00 3.00 01 A MIRU PJSM Pre -spud check list. 03:00 - 05:00 2.00 06 J DRLSUR Make up BI-IA. Tag @ 51'. Circ. check allmlines for leaks. 05:00 - 06:00 1.00 02 A DRLSUR Drilling from 51' to 65'. 10/17/2000 06:00 - 08:30 2.50 02 A DRLSUR drilling surface hole. 08:30 - 09:00 0.50 05 I DRLSUR Circulate 09:00 - 09:30 0.50 06 J DRLSUR POOH to pick up ' HWDP, 5" DP DCS, and jars. 09:30 - 16:00 6.50 26 DRLSUR Pick up 5 "DP, 5 "HWDP, and stand back in derrick. Pick up jars and stab. 16:00 - 16:30 0.50 06 J DRLSUR RIH 16:30 - 18:00 1.50 02 A DRLSUR Drilling from 96' to 208'. 18:00 - 19:00 1.00 08 E DRLSUR Work on top drive. 19:00 - 23:00 4.00 26 DRLSUR Pick up stab. and three DCs. 23:00 - 00:00 1.00 02 A DRLSUR Drilling from 208' to 218'. 00:00 - 00:30 0.50 05 I DRLSUR ! Circ. while waiting on dump truck. 00:30 - 04:00 3.50 02 A DRLSUR Drilling from 218' to 294'. 04:00 - 04:30 0.50 05 I DRLSUR Circ. hole clean. 04:30 - 05:00 0.50 11 F DRLSUR Wirelie survey @ 290'. 05:00 - 06:00 1.00 02 A DRLSUR Drlg. from 290' to 315' 10/18/2000 06:00 - 16:30 10.50 02 A DRLSUR Drilling 17 1/2" surface hole. PJSM 16:30 - 17:00 0.50 10 A DRLSUR Wireline survey. 1/2 deg. inc. 17:00 - 05:30 12.50 02 A DRLSUR Drilling surface hole. 05:30 - 06:00 0.50 05 I DRLSUR Circulate for wireline survey. 10/19/2000 06:00 - 06:30 0.50 10 A DRLSUR Wireline Inc. survey 06:30 - 09:00 2.50 02 A DRLSUR Drilling 17 1/2" surface hole. 09:00 - 09:30 0.50105 I DRLSUR Ciculate, pump pill. Printed: 04/24/2003 9:18:33 AM 1 1 • • IORES O1L CORR. Page of 1 ry 0 n Summary Rs p rt � 1 Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date Fromo, Hours °Co Phase lescrtp#ri ©fOperaticins 10/19/2000 09:30 - 11:00 1.50 06 A DRLSUR POOH, break bit off. 11:00 - 12:00 1.00 06 J DRLSUR Make up bit, run in holewith collars, service top drive. 12:00 - 13:00 1.00 08 E DRLSUR Work on top drive. 13:00 - 14:30 1.50 06 J DRLSUR Pick up three DCs. 14:30 - 16:00 1.50 07 DRLSUR Cut drlg. line. 16:00 - 17:00 1.00 06 A DRLSUR RIH 17:00 - 17•30 0.50 25 DRLSUR Circulate, orient Epoch. 17:30 - 22:30 5.00 02 A DRLSUR Drilling 17 1/2" hole. 22:30 - 23:00 0.50 05 1 DRLSUR Circulate B /U. 23:00 - 23:30 0.50 10 A DRLSUR Wireline Inc. survey. 23:30 - 06:00 6.50 02 A DRLSUR Drilling 17 1/2" surface hole. 10/20/2000 06:00 - 10:30 4.50 02 A DRLSUR Drilling surface hole 10:30 - 11:00 0.50 11 A DRLSUR Run totco angle unit on wireline. 11:00 - 11:30 0.50 05 I DRLSUR CBU 11:30 - 14:30 3.00 06 DRLSUR Trip to stabilizers 14:30 - 15:00 0.50 07 DRLSUR Clean rig floor 15:00 - 16:30 1.50 06 DRLSUR Trip in hole 16:30 - 17:00 0.50 02 A DRLSUR Drill to fit casing 17:00 - 18:30 1.50 05 F DRLSUR Circulate hole clean 18:30 - 19:30 1.00 11 DRLSUR Wireline survey 19:30 - 20:00 0.50 05 DRLSUR Pump dry job 20:00 - 00:00 4.00 06 G DRLSUR Trip out to run casing 00:00 - 01:00 1.00 06 DRLSUR Break off bit, bit sub, stand back collars 01:00 - 02:30 1.50 12 DRLSUR Pick up casing equipment 02:30 - 03:00 0.50 12 DRLSUR Safety pre job meeting. 03:00 - 04:00 1.00 12 DRLSUR Rig up to run 13 3/8" casing. 04:00 - 06:00 2.00 12 DRLSUR 1 Running casing 10/21/2000 06:00 - 10:30 4.50 12 RUN CASING 10:30 - 12:00 1.50 12 RETRIEVE CASING BACK TO SURFACE, AND CUT OFF TWO CENTRALIZERS. 12:00 - 13:30 1.50 12 CHANGE OUT BAILS 13:30 - 22:30 9.00 12 RUN CASING 22:30 - 00:00 1.50 12 RIG DOWN CIRULATING HOSE, PULL MASTER BUSHING TO CUT CASING. 00:00 - 03:00 3.00 12 CUT LANDING JOINT 4 INCHES BELOW DRILLING NIPPLE 03:00 - 04:30 1.50 12 TRIP IN THE OUT OF DERRICK, AND PICK UP 7 JOINTS OF 5" DRILL PIPE 04:30 - 05:00 0.50 12 SAFETY MEETING WHILE CIRCULATING 05:00 - 05:30 0.50 12 CIRCULATE 05:30 - 06:00 0.50 12 PRESSURE TEST LINES, BEGIN PUMPING 50 BBLS SPACER 10/22/2000 06:00 - 06:30 0.50 12 C TEST LINES TO 1500, PUMP WATER 06:30 - 08:00 1.50 12 C CEMENT JOB 08:00 - 12:00 4.00 14 A PULL ONE STAND, PUMP DOWN DRILL PIPE WIPER PLUG, RIG DOWN DIVERTER. 12:00 - 12:30 0.50 14 A REMOVE DIVERTER KNIFE 12:30 - 14:30 2.00. 12 D RIG DOWN CEMENT CIRCULATING HOSE AND HEAD- MAKE UP TOP DRIVE SAVER SUB 14:30 - 16:00 1.50 06 G TRIP OUT OF HOLE WITH STING IN ASSEMBLY - LAY DOWN 2 JTS OF 5 " DP THAT WAS NOT WIPED. 16:00 - 16:30 0.50 25 PRE JOB SAFTEY MEETING FOR WORKING ON BOP STACK. NIPPLE DOWN/ NIPPLE UP NABORS POLICY 16:30 - 19:30 3.00 14 B i RIG DOWN 20" RISER & LAY DOWN 19:30 - 20:30 1.00 14 B RIG UP SLINGS/ PICK UP ANNULAR Printed: 04/24/2003 9:18:33 AM 411 FI REST OIL' tORP Page 3 of 15 ' '" { /. - ©pe at ans surmary Rep ?Fs Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date from To Hours Code -Code Phase Description of perattor s 10/22/2000 20:30 - 21:00 0.50 14 B WELDER MADE ROUGH CUT ON 13 3/8" 21:00 - 22:30 1.50 14 B LAY DOWN CUT OFF SECTION OF 13 3/8" CSG, MOUSE HOLE, 'V' DOOR RAMP 22:30 - 00:00 1.50 14 B WELDER CUT OFF 20 ", MAKE EXPERT CUT ON 13 3/8" FOR SLIP LOCK SPOOL FROM VETCO. 00:00 - 02:30 2.50 14 B GRIND /DRESS OFF CUT ON 13 3/8" 02:30 - 03:30 1.00 14 B INSTALL VETCO GREY SLIP LOCK SPOOL AT GROUND LEVEL/ TEST TO 2000 PSI FOR 15 MINS. 03:30 - 06:00 2.50 14 B INSTALL SPACER SPOOL/DOUBLE GATE /MUD CROSS 10/23/2000 06:00 - 12:00 6.00 14 B CSGSUR NIPPLE UP HYDRIL, DRILL NIPPLE, FLOWLINE, TRIP TANK FLOW 1LINE 12:00 - 15:00 3.00 14 B CSGSUR INSTALL 'V' DOOR RAMP, MOUSE HOLE 15:00 - 19:30 4.50 07 CSGSUR REPLACE ACTUATOR VALVE AND SAVER SUB ON TOP DRIVE. 19:30 - 00:00 4.50 14 B CSGSUR CHANGE BOTTOM RAMS F/ 2 7/8" TO 5" AND RIG UP TO TEST BOP'S 00:00 - 03:00 3.00 15 A CSGSUR NIPPLE UP CHOKE LINE, FINISH RIGGING UP TO TEST 03:00 - 06:00 3.00 15 A CSGSUR TEST BOP'S 10/24/2000 06:00 - 08:30 2.50 07 DRLIN1 SET WEAR RING 08:30 - 10:30 2.00 07 DRLIN1 INSTALL DRIP PANS 10:30 - 15:00 4.50 08 DRLIN1 REPLACE ACCTUATOR VALVE ON TOP DRIVE. 15:00 - 18:00 3.00 06 DRLIN1 PRE JOB SAFETY MEETING, MAKE UP BHA #3 18:00 - 20:00 2.00 06 DRLIN1 , TRIP TO 852' 20:00 - 22:30 2.50 09 DRLIN1 SLIP AND CUT DRILL LINE. 22:30 - 23:30 1.00 15 DRLIN1 TEST TIW VALVE, NOTIFY STATE MAN OF PASSED TEST. 23:30 - 00:00 0.50 06 DRLIN1 PICK UP SINGLES, TRIP IN THE HOLE. 00:00 - 02:30 2.50 06 DRLIN1 PICK UP SINGLES, TRIP IN THE HOLE. 02:30 - 04:00 1.50 05 DRLIN1 CIRCULATE OUT CEMENT, FROM 200 GPM TO 450 GPM WHILE SLOWLY ROTATING. SHAKERS LOADED UP. 04:00 - 04:30 0.50 16 DRLIN1 PRE JOB MEETING, TEST CASING TO 3000 PSI. 04:30 - 06:00 1.50 02 DRLIN1 DRILL COLLAR, CEMENT, AND SHOE. 10/25/2000 06:00 - 09:30 3.50 02 D DRLIN1 Drill cement below float collar 09:30 - 11:00 1.50 02 D DRLIN1 Drill shoe. 11:00 - 11:30 0.50 02 A DRLIN1 Drill 20 feet of new hole. 11:30 - 12:00 0.50 05 A DRLIN1 Circulate for FIT. Mud WT in 9.0 ppg / Mud WT out 9.0 ppg 12:00 - 12:30 0.50 05 A DRLIN1 Circulate / Prejob safety meeting / Crew change / Explain what to do for FIT. 12:30 - 13:00 0.50 02 A DRLIN1 Perform FIT. 9.0 PPG mud in hole. EMW =11.0 PPG Held 190 Psi for 5 mins. Recorded on chart. 13:00 - 20:00 7.00 02 A DRLIN1 Drilling 20:00 - 20:30 0.50 05 A DRLIN1 Circulate hole clean for survey. 20:30 - 21:00 0.50 10 A DRLIN1 Angle unit survey with slick line. 21:00 - 00:00 3.00 02 A DRLIN1 Drilling 00:00 - 03:00 3.00 02 A DRLIN1 Drilling 03:00 - 03:30 0.50 05 A DRLIN1 Circulate hole clean for survey 03:30 - 04:00 0.50 10 A DRLIN1 Angle unit survey with slick line. 04:00 - 06:00 2.00 02 A DRLIN1 Drilling 10/26/2000 06:00 - 07:00 1.00 02 A DRLIN1 , Rotating ahead 07:00 - 08:00 1.00' 02 A DRLIN1 Change shaker screens 08:00 - 12:30 4.50 02 A DRLIN1 i Rotating ahead 12:30 - 13:30 1.00 05 A DRLIN1 Pump high viscosity sweep around. 13:30 - 14:00 0.50 10 A DRLIN1 Run totco angle unit on slick line. 14:00 - 14:30 0.50 05 A DRLIN1 Record slow pump rates, pump dry job. 14:30 - 18:30 4.00 06 H DRLIN1 Short trip. Printed: 04/24/2003 9:18:33 AM • FOREST OIL. CORP Page 4 Of t i ape � um i" # p r Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From -To Hours , Code Ca de Phase ; Descriptitrrt of Op ration F 10/26/2000 18:30 - 19:30 1.00 06 H DRLIN1 Service top drive & draw works. 19:30 - 00:00 4.50 06 H DRLIN1 Trip in picking up singles off pipe rack. 00:00 - 06:00 6.00 02 A DRLIN1 Rotating ahead. 10/27/2000 06:00 - 07:00 1.00 02 A DRLIN1 Drilling ahead. 07:00 - 08:00 1.00 05 A DRLIN1 Circulate while changing shaker screens. 08:00 - 09:30 1.50 02 A DRLIN1 Drilling ahead. 09:30 - 10:00 0.50 05 A DRLIN1 Circulate hole clean. 10:00 - 11:00 1.00 10 A DRLIN1 Run slick line unit for totco angle survey. 11:00 - 22:00 11.00 02 A DRLIN1 Drilling and surveying every 5 stands. 22:00 - 23:00 1.00 05 A DRLIN1 Circulate for survey, pump high vis sweep. 23:00 - 00:00 1.00 10 A DRLIN1 Run slick line unit for totco angle survey. 00:00 - 04:00 4.00 02 A DRLIN1 Drilling 04:00 - 05:00 1.00 05 A DRLIN1 Circulate, pump dry job. 05:00 - 06:00 1.00 06 J DRLIN1 Trip out of hole for PDC bit and Mud Motor. 10/28/2000 06:00 - 10:00 4.00 06 A DRLIN1 Tripping 10:00 - 12:00 2.00 06 J DRLIN1 Change bit and BHA 12:00 - 12:30 0.50 07 DRLIN1 PJSM Clean rig floor 12:30 - 16:30 4.00 06 J DRLIN1 Finish w/ BHA change RIH w/ BHA to 860'. 16:30 - 17:30 1.00 07 DRLIN1 Service rig, blocks and top drive. 17:30 - 21:30 4.00 06 J DRLIN1 TIH -P /U 5" DP (69 jts.) from pipe rack. Rabbit each jt. Fill pipe at the shoe. 21:30 - 22:00 0.50 02 A DRLIN1 Break circ. Drilling from 4265' to 4267 ADT 1/4 hr. 22:00 - 05:00 7.00 08 A DRLIN1 Flow line plugged with excessive clay returns. Attemted to jet flow line with no luck. RemoveFlow paddle and break apart flow line to clean same, while working pipe. Remove bushings, drip pan clean drilling nipple flow line and possum belly. Clean and replace. 05:00 - 06:00 1.00 05 I DRLIN1 Circulate slowly to circulate clay from hole. 10 stks. /min.Increase circulation as hole cleans up. 10/29/2000 06:00 - 08:00 2.00 05 I DRLIN1 Circulate clay from hole @ 10 to 50 SPM. 08:00 - 18:30 10.50 02 A DRLIN1 Drilling from 4267 to 4607'. 18:30 - 19:30 1.00 05 I DRLIN1 Pump Hi -Vis sweep. CBU for survey. 19:30 - 20:30 1.00 11 DRLIN1 Wireline survey @ 4509'. 3/4 Deg. 20:30 - 02:00 5.50 02 DRLIN1 Drilling from 4607' to 4796'. Set clocks back one hour for DST. 01:00 - 01:30 0.50 07 DRLIN1 Sevice top drive. 01:30 - 02:00 0.50 02 A DRLIN1 Drilling 12 1/4" hole. 02:00 - 03:00 1.00 02 DRLIN1 Two pump pressure spikes. Pump pressure increased to 3000 PSI., while drilling from 4810' to 4817'. ROP decreased to 6'- 8' /hr. 03:00 - 04:30 1.50 05 I DRLIN1 CBU @ 0 strokes due to pump pressure increase. Monitor well. Pump dry job. 04:30 - 06:00 1.50 06 DRLIN1 POOH 10/30/2000 06:00 - 08:00 2.00 06 A DRLIN1 Tripping out of hole. 08:00 - 10:00 2.00 06 J DRLIN1 Work BHA. Clean stabilizers. Bit jets plugged with rubber from mud motor. 10:00 - 10:30 0.50 07 DRLIN1 Clean rig floor. 10:30 - 11:00 0.50 06 J DRLIN1 Lay down motor, x -o sub and float sub. 11:00 - 12:00 1.00 06 J DRLIN1 Dress new bit- Change BHA. 12:00 - 12:30 0.50 07 1 DRLIN1 ! PJSM Clean rig floor. 12:30 - 15:00 2.50 06 J DRLIN1 Make up new bit and change BHA. 15:00 - 16:30 1.50 06 DRLIN1 RIH to 1763'. 16:30 - 18:00 1.50 DRLIN1 Fill pipe and circ. Service rig blocks and top drive. 18:00 - 18:30 0.50 06 DRLIN1 RIH from 1763' to 3078'. 18:30 - 19:30 1.00 05 1 DRLIN1 Fill drill pipe and circ. bottoms up. 19:30 - 20:00 0.50 06 DRLIN1 RIH from 3078' to 4817' with no problems. i I Printed: 04/24/2003 9.18:33 AM 1 I. • • FOREST ail. CORP PO: a of 15 *Qperatios Summary Repot Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date 'prom To Hoiur$y =Code Su t'hase ,l a cripti r of Opations , Cede ' 10/30/2000 20:00 - 02:30 6.50 02 A DRLIN1 Drilling 12 1/4" hole. 02:30 - 03:00 0.50 05 DRLIN1 Circ. Hi -Vis sweep. PJSM 03:00 - 04:00 1.00 11 DRLIN1 Survey ©5006'. 1/2 deg. 04:00 - 06:00 2.00 02 A DRLIN1 Drilling 12 1/4" hole. 10/31/2000 06:00 - 16:00 10.00 02 A DRLINI Rotary drilling 12 1/4" hole. 16:00 - 17:00 1.00 06 H DRLIN1 POOH six stands short trip to repair leak on top drive. 17:00 - 21:30 4.50 08 E DRLIN1 Repair oil leak on top drive. 21:30 - 22:00 0.50 06 DRLIN1 RIH from 4766' to5329'. 22:00 - 04:30 6.50 02 A DRLIN1 Drilling 12 1/4" hole. 04:30 - 05:00 0.50 07 A DRLIN1 Rig Service. 05:00 - 06:00 1.00 02 A DRLIN1 Drilling 121/4" hole. 11/01/2000 06:00 - 11:00 5.00 02 A DRLIN1 Drilling 12 1/4" hole. 11:00 - 13:00 2.00 05 1 DRLIN1 Pump Hi -Vis sweep, circulate bottoms up. Drop survey. 13:00 - 17:00 4.00 06 A DRLIN1 POOH 17:00 - 17:30 0.50 07 DRLIN1 Remove blower hose from top drive. Reset crowm -o- matic. 17:30 - 19:00 1.50 DRLIN1 POOH with BHA. Retrieve survey. 19:00 - 19:30 0.50 07 DRLIN1 Clean rig floor. 19:30 - 20:00 0.50 15 DRLIN1 Pull wear ring. Rig up to test BOPs. 20:00 - 21:30 1.50 15 DRLIN1 Test all rams, floor safety valve, choke manifold, choke and kill lines to 250/3000 psi.Pressure test annular preventor to 250/2500 psi. 21:30 - 22:30 1.00 15 DRLIN1 Rig down testing equipment and set wear ring. 22:30 - 01:00 2.50 06 DRLIN1 PJSM. Make up new bit and RIH with BHA. Strap, rabbit and pick up 9 jts. 5" HWDP. RIH to shoe. 01:00 - 02:00 1.00 07 DRLIN1 Hook up crown saver electric bell ringer. Drain oil from top drive. (overfull) Service top drive, blocks,fill pipe. 02:00 - 04:30 2.50 06 DRLIN1 RIH to 4300'. Fill pipe. 04:30 - 06:00 1.50 02 DRLIN1 Break circulation @ 5500'. Wash and ream to bottom, no fill. Drilling from 5547' to 5565'. 11/02/2000 06:00 - 16:30 10.50 02 A DRLIN1 Drilling 121/4" hole. 16:30 - 17:30 1.001 DRLIN1 Pump Hi -Vis sweep, CBU for survey. 17:30 - 18:30 1.00 11 F DRLIN1 Wireline survey @ 5840'- 1 deg. 18:30 - 03:00 8.50 02 A DRLIN1 Drilling 12 1/4' hole. Check crown o matic. O.K. 03:00 - 06:00 3.00 02 A DRLIN1 Drilling 12 1/4" hole. 11/03/2000 06:00 - 09:00 3.00 02 A DRLIN1 Drilling 12 1/4" hole. 09:00 - 10:30 1.50 05 I DRLIN1 Pump Hi -Vis sweep. circ. hole clean. 10:30 - 11:30 1.00 10 DRLIN1 Wireline survey @ 6306' PJSM 11:30 - 16:30 5.00 02 A DRLIN1 Drilling 12 1/4" hole T.D. 121/4" hole @ 6500'. 16:30 - 18:00 1.50 05 I DRLIN1 Circ. Hi -Vis sweep. CBU 18:00 - 20:30 2.50 06 C DRLIN1 POOH 10 std. short trip. Work tight hole from 5692' to 5504'. RIH. 20:30 - 22:30 2.00 05 D DRLIN1 Pump Hi -Vis sweep. Circ. hole clea, whie working and rotating pipe. 1 1/2 circulations. Mix dry job. 22:30 - 00:00 1.50 06 C DRLIN1 POOH 00:00 - 00:30 0.50 25 DRLIN1 Pump dry job, blow down top drive. 00:30 - 02:00 1.50 06 C DRLIN1 POOH SLM 02:00 - 03:30 1.50 06 DRLIN1 Pooh w/ BHA. Clean clay from stabs. Break bit. 03:30 - 04:00 0.50 07 DRLIN1 Clean rig floor. 04:00 - 05:15 1.25 11 A DRLIN1 Rig up SWS and make up logging tools. 05:15 - 06:00 0.75 11 A DRLIN1 Running in hole with SWS wireline. 11/04/2000 06:00 - 09:00 3.00 A DRLIN1 RIH with SWS. Logging. 09:00 - 10:30 1.50 11 A DRLIN1 Rig down SWS. Clean mud from tools. 10:30 - 11:00 0.50 07 DRLIN1 Clean rig floor. 11:00 - 14:00 3.00 14 E DRLIN1 Drain BOPs. Pick up test joint. Pull wear ring. Set test plug. Change bottom rams from 5" to 9 5/8 ". Test doors to 3000 PSI.Remove bales. Printed: 04 /24/2003 9:18:33 AM A ; 411 • FOREST GIB CORD; Page 6 of 15 Operations Summar Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date '‘'P, From - Ta Hours Code Phase Desortptton of Operations ' s Code 11/04/2000 11:00 - 14:00 3.00 14 E DRLIN1 Break and lay down lower IBOP valve from top drive. 14:00 - 15:00 1.00' 12 A DRLIN1 Rig up to run 9 5/8" casing. Pick up Lafluer tool. 15:00 - 16:00 1.00 12 A DRLIN1 Rig up bales, elevators and slips. 16:00 - 17:00 1.00 12 A DRLIN1 Rig up stabbing board. Rig up air line for slips. 17:00 - 17:30 0.50 12 A DRLIN1 PJSM 17:30 - 18:00 0.50 12 A DRLIN1 Make up shoe and float collar. 18:00 - 02:30 8.50 12 A DRLIN1 Run 162 jts. 9 5/8" csg. 02:30 - 04:00 1.50 12 C DRLIN1 Circ. @ 6496' 04:00 - 05:00 1.00 12 A DRLIN1 Break out and lay down Lafluer head. Blow down top drive.Make up landing joint, cement head and hose. 05:00 - 05:30 0.50 12 C DRLIN1 Break circulation and tag bottom @ 6500' while circulating.PJSM 05:30 - 06:00 0.50 12 DRLIN1 Test cmt lines to 3000PSI. OK 11/05/2000 06:00 - 08:00 2.00 12 C CSGIN1 Drop plug, 5 bbl. MESAH2O, kick out plug. Stop and reload head. Pump 43 bbl. MCS -A H2O, 72.5 bbl. lead slurry @ 12.5 ppg., 42.3 bbl. tail slurry 15.8 ppg. Drop plug 5 bbl. H2O, switch over to rig pumps. stop reciprocating casing @ 3500 strokes, bump plug @ 3970 strokes. 08:00 - 12:00 4.00 14 B CSGIN1 Pull cement hoses and drain. Prepare BOPs to pick up to set casing slips. Remove flow lines, hook up cable and cable clamp BOP lifter. 12:00 - 13:00 1.00 14 B CSGIN1 PJSM Lift stack with rig hydraulics. 13:00 - 13:30 0.50 CSGIN1 Set casing slips with 115000 #. 13:30 - 14:00 0.50 14 B CSGIN1 Cut hole in 9 5/8" casing, drain and rough cut. 14:00 - 16:30 2.50 14 B CSGIN1 Let down stack, take off cement head. Rig down hydraulic lift system. Lay down 9 5/8" cut off.Lay down elevators. 16:30 - 17:00 0.50 14 B CSGIN1 Start finish cut on 9 5/8" casing. 17:00 - 21:00 4.00 14 CSGIN1 Pick up Vetco Gray tubing spool, fill with packing. test to 3800 PSI. Test OK. 21:00 - 01:00 4.00 14 B CSGIN1 Nipple up BOP, tubing spool, change lower rams to 5 ". Nipple up flow line. Hook up turnbuckles. 01:00 - 05:00 4.00 15 A CSGIN1 Pick up test joint and test plug. Test choke manifold, upper and lower IBOP valves. Test floor valves, choke and kill line valves. Test top, bottom and blind rams - 250/4000 PSI. test hydril- 250/3000 PSI. Set wear bushing, lay down test joint. 05:00 - 06:00 1.00 14 E CSGIN1 Install drip pans under rotary table. 11/06/2000 06:00 - 09:30 3.50 14 B DRLIN1 Finish installing drip pans, hoses. Clean cellar and sub base. 09:30 - 12:30 3.00 06 J DRLIN1 RIH with 12 1/4" BHA and lay down same. 12:30 - 16:30 4.00 06 IA DRLIN1 Pick up 8 1/2" BHA. 16:30 - 18:00 1.50 06 A DRLIN1 RIH to 2031'. 18:00 - 18:30 0.50 05 I DRLIN1 Break circulation @ 2031'. 18:30 - 19:30 1.00 06 A DRLIN1 RIH to 3906'. 19:30 - 20:30 1.00 05 I DRLIN1 Break circulation @ 3906'. 20:30 - 22:00 1.50106 A DRLIN1 RIH, tagged float collar @ 6418.6'. 22:00 - 22:30 0.50 05 I DRLIN1 ! Break circulation @ 6418, CBU. 22:30 - 23:00 0.50 09 DRLIN1 Slip 100' of drilling line. 23:00 - 06:00 7.00 08 E DRLIN1 Prepare to lay down top drive. Lay down bales and elevators and remove lower IBOP.Move block hanging line. Remove kelly hose and blower hose. Lay down stabbing board. Install transport pins. Fold derrick board up. Close storm doors in board. Drain oil from top drive. Pin erection rigging to blocks and latch rigging to torque guide clamps. Release tension in torque cables. Tuen power off and disconnect electric and hydraulic cables. Unlatch from harpoon. Lay down beaver slide. Remove windwalls. 11/07/2000 06:00 - 07:00 1.00 , 01 A DRLIN2 Lower grasshopper on Can -Rig top drive and spool up electric cables and hydraulic hoses. 1 Printed: 04/24/2003 9:18:33 AM • 411 . ; FOREST OIL CORP. k Page 7 Of 15 ©peraItions Summely Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - Td ;:.Hours bode: de Phase Description Of- ations `` 11/07/2000 07:00 - 10:30 3.50 01 A DRLIN2 Tie onto top drive torque guide, pull out and lower top drive. Position and install tail roll section to same. Position truck and lower top drive and Toad on truck. 10:30 - 11:30 1.00 01 DRLIN2 Install two windwalls on sub and set beaver slide and catwalk. 11:30 - 12:00 0.50 01 DRLIN2 Prepare to install work basket on top of blocks. 12:00 - 14:00 2.00 01 DRLIN2 Weld platform to top of blocks. 14:00 - 15:30 1.50 01 DRLIN2 Run blocks to crown and dismantle top drive spear.Lower to floor. 15:30 - 17:30 2.00 01 DRLIN2 Run back to crown to dismantle spear hanger baskets. take off lower top drive rail clamps from derrick. 17:30 - 19:30 2.00 01 DRLIN2 Lay all Can -Rig parts down. 19:30 - 21:00 1.50 01 DRLIN2 Take platform off top of blocks. 21:00 - 22:30 1.50 01 DRLIN2 P/U SWIVEL &SERVICE. 22:30 - 23:30 1.00 01 DRLIN2 PREPARE TO P/U TESCO TORQUE TUBE, MAKING IT UP ON PIPE RACK. 23:30 - 00:00 0.50 01 A DRLIN2 P/U TESCO TORQUE TUBE. 00:00 - 00:30 0.50 01 DRLIN2 (PJSM W/ TESCO R/U TESCO TORQUETUBE. 00:30 - 06:00 5.50 01 DRLIN2 P/U TD. TRQ. TUBE TO RIG FLOOR, TIE ON TO BLOCKS. FINISH STACKING TRQ. TUBE UP TO RIG FLOOR. HANG SAME @ CROWN, TAKE MEASUREMENT, BOLT PATTERN TO DERRICK RAIL. UNHANG TRQ. TUBE, DROP BTM. SECTION AND NEXT 18 FT. SECTION & SWAP OUT WITH 15 FT. SECTION. 11/08/2000 06:00 - 07:00 1.00 01 A DRLIN2 FINISH HANGING TESCO TORQUE TUBE. 07:00 - 08:30 1.50 01 I DRLIN2 INSTALL T -BAR & CLAMP TO DERRICK. 08:30 - 09:00 0.50 01 A DRLIN2 HANG BLOCK HANGING LINE. 09:00 - 11:30 2.50 01 A DRLIN2 RIG UP CEMENT HOSE TO CIRC. HOLE & COND. MUD @ SLOW RATE DUE TO THICK MUD. 11:30 - 12:00 0.50 01 A DRLIN2 HOOK UP RIG UP SLINGS & SET TESCO TOP DRIVE & RACK ON RIG FLOOR. 12:00 - 13:00 1.00 01 A DRLIN2 SCREW SWIVEL INTO TOP DRIVE. 13:00 - 14:00 1.00 01 A DRLIN2 TAKE TOP DRIVE OUT OF CRADLE, RIG UP HYD. LINE. 14:00 - 15:00 1.00 01 A DRLIN2 R/U TORQUE BUSHING TO TOP DRIVE. 15:00 - 16:00 1.00 01 A DRLIN2 HOOK UP TOPDRIVE HYD. RAMS. 16:00 - 18:00 2.00 01 A DRLIN2 HANG HYD. HOSES IN DERRICK. 18:00 - 19:00 1.00 01 A DRLIN2 HOOK UP HYD. HOSES TO POWER PACK. 19:00 - 22:00 3.00 01 A DRLIN2 START UP TESCO, FUNCTION TEST & SET PRES. CONTROLS. 22:00 - 00:00 2.00 01 A DRLIN2 R/U SAVER SUB, BALES, ELEVATORS & ADJUST TORQUE BUSHING. 00:00 - 04:00 4.00 01 A DRLIN2 HOLD 15 MIN. PJSM. INSTALL TURN BUCKELS & RACHET STRAPS TO TORQUE TUBE. WRAP HYD. HOSES WITH TARP. HOOK UP STAND PIPE & KELLY HOSE. 04:00 - 04:30 0.50 01 A DRLIN2 j TEST UPPER & LOWER I.B.O.P. VALVE 4,000 & 250 P.S.I. 04:30 - 05:30 1.00 09 DRLIN2 HOLD P.J.S.M. & CUT DRLG. LINE. 05:30 - 06:00 0.50 05 DRLIN2 CIRCULATE MUD. 11/09/2000 06:00 - 07:30 1.50 05 A DRLIN2 CIRCULATE & CONDITION MUD. 07:30 - 08:00 0.50 25 DRLIN2 CASING INTEGRITY TEST TO 3,000 P.S.I. FOR 30 MIN. 08:00 - 10:00 2.00 02 D ' DRLIN2 DRILLING FLOAT COLLAR & CEMENT TO 6,430 FT. 10:00 - 10:30 0.50 01 A DRLIN2 ;CIRCULATING BOTTOMS UP. 10:30 - 12:00 1.50 01 A DRLIN2 ADD S PIPE TO TESCO GOOSE NECK, TIGHTEN SWIVAL PACKING & WRAP 75 TARP AROUND SERVICE HOSES FOR TOPDRIVE. 12:00 - 13:00 1.00, 01 A DRLIN2 FINISHED INSTALLING TARP ON TOPDRIVE SERVICE HOSES. 13:00 - 13:30 0.50 02 D DRLIN2 DRILL CEMENT F/ 6,430' TO 6,444'. 13 :30 - 14:00 0.50 05 DRLIN2 STOP DRLG. CIRCULATE CONTAMINATED MUD. Printed: 04 /24/2003 9:18:33 AM a FOREST { 1L O P` . : Page 8 of 15 erattons Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - °To 41ours Code Sub Phase Description of operations Gode 11/09/2000 14:00 - 18:00 4.00 02 D DRLIN2 DRILL F/ 6,444' TO 6,524'. 18:00 - 20:30 2.50 05 A DRLIN2 CIRC. & COND. CONTAMINATED MUD. 20:30 - 21:00 0.50 02 A DRLIN2 F.I.T. TO 10.5 @ 6,524. 21:00 - 00:00 3.00 02 A DRLIN2 DRILL FROM 6,524 TO 6,577. 00:00 - 06:00 6.00 02 A DRLIN2 DRILL FROM 6,577 TO 6,660 11/10/2000 06:00 - 08:30 2.50 02 A DRLIN2 DRLG. 8.5 HOLE 08:30 - 09:00 0.50 05 A DRLIN2 CIRC. BOTTOMS UP. 09:00 - 09:30 0.50 01 A DRLIN2 BLOW DOWN TOPDRIVE, INSTALL WIRELINE GUIDE ON SAME. 09:30 - 11:00 1.50 11 A DRLIN2 RIH W/ WIRELINE & SURVEY @ 6677'. 11:00 - 12:00 1.00 02 A DRLIN2 DRLG FROM 6,709 TO 6,721 12:00 - 00:00 12.00 02 A DRLIN2 DRLG FROM 6721 TO 6898 00:00 - 06:00 6.00 02 A DRLIN2 1 DRLG FROM 6898 TO 6898 11/11/2000 06:00 - 10:00 4.00 02 A DRLIN2 DRLG. 8.5 HOLE. 10:00 - 10:30 0.50 05 I DRLIN2 CIRC. BOTTOMS UP. 10:30 - 11:00 0.50 11 A DRLIN2 DROP SURVEY © 6987. 11:00 - 12:00 1.00 11 A DRLIN2 POOH TO SHOE. BLOW DOWN TOPDRIVE. RETRIEVE WIRELINE SURVEY. 12:00 - 13:00 1.00 11 A DRLIN2 RETRIEVE WIRELINE SURVEY.(NO RUN) SERVICE TOPDRIVE. 13:00 - 13:30 0.50 07 DRLIN2 SERVICE RIG. 13:30 - 14:00 0.50 12 D DRLIN2 WELD GUSSETS BETWEEN 20" & 13 3/8 ". 14:00 - 15:00 1.00! 26 DRLIN2 P/U 5 " DP 18 Jts to 6995 15:00 - 16:00 1.00 10 DRLIN2 Run Wireline Survey ( line broke when POH @ 5520') 16:00 - 18:00 2.00 06 DRLIN2 POH 15 STDS splice wireline - retreive survey tool 18:00 - 19:00 1.00 06 DRLIN2 Ran back to BTM 19:00 - 00:00 5.00 02 DRLIN2 DRLG F/7024' T/7066 00:00 - 05:30 ! 5.50 02 A DRLIN2 1 DRLG F/ 7066 T/ 7121 05:30 - 06:00 0.50 08 A DRLIN2 STAND BACK ONE STAND DP, TIGHTEN WASH PIPE PACKING. 11/12/2000 06:00 - 07:00 1.00 08 A DRLIN2 C/O SWIVAL WASH PIPE & PACKING. 07:00 - 12:00 5.00 02 A DRLIN2 DRLG. 8.5" HOLE f/ 7121 to 7195 ft. 12:00 - 15:30 3.50 02 A DRLIN2 DRLG. 8.5" HOLE f/ 7195 to 7233 ft. 15:30 - 16:30 1.00 05 I DRLIN2 CIRC. BTM. UP. 16:30 - 17:00 0.50 10 B DRLIN2 DROP SURVEY @ 7,213, PUMP DRY JOB. 17:00 - 17:30 0.50 08 B DRLIN2 WORK ON TOP DRIVE & BLOW DOWN. 17:30 - 22:30 5.00 06 A DRLIN2 POH. 22:30 - 00:00 1.50 06 ' J DRLIN2 P/U MUD MTR, BIT SUB, XO, RIH DCS. 00:00 - 01:00 1.00 06 J DRLIN2 M/U BHA 01:00 - 03:00 2.00 08 A DRLIN2 REPOSITION TOP DRIVE HYD. LINES & WORK ON RPM ADJ. REPOSITION KELLY HOSE. 03:00 - 06:00 3.00 06 J DRLIN2 ' RIH, TEST # 1 MUD PUMP T /FILL UP LINE. 11/13/2000 06:00 - 07:30 1.50 06 J DRLIN2 RIH w/ Mud Motor, PDC Bit 07:30 - 08:00 0.50 03 A DRLIN2 Ream f/ 7212 to 7233 ft. 08:00 - 12:00 4.00 02 A DRLIN2 Drlg 8.5" hole f/ 7233 to 7282 ft 12:00 - 00:00 12.00 02 A DRLIN2 DrIg 8.5" hole f/ 7282 to 7559 00:00 - 06:00 6.00 02 A DRLIN2 Drlg 8.5" hole f/ 7559 to 7618 11/14/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5" HOLE F/ 7618 T/ 7698. 12:00 - 18:00 6.00 02 A DRLIN2 DRLG. 8.5" HOLE F/ 7698 T/ 7795. 18:00 - 18:30 0.50 05 I DRLIN2 CIRC. BTMS. UP. 18:30 - 19:00 0.50 11 , A DRLIN2 RIG UP SHEAVE ON TOP DRIVE. TO SURVEY. 19:00 - 19:30 0.50 11 A DRLIN2 I RIH W/ WIRELINE SURVEY. 19:30 - 20:30 1.00 10 A DRLIN2 POOH w/ Wireline. Rig down topdrive survey tool 20:30 - 00:00 3.50 02 A DRLIN2 DRLG 8.5" HOLE F/ 7775 TO 7844 00:00 - 06:00 6.00 02 A DRLIN2 DRLG 8.5" HOLE F/ 7844 TO 7940 I i Printed: 04/24 /2003 9:18:33 AM • . FOREST-OIL CARP - Page 9 of It Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code Sub- Phase ; %° Description of peratio i y Cod0 11/15/2000 06:00 - 10:30 4.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 7,940 T/ 8056. 10:30 - 11:30 1.00 08 B DRLIN2 REPLACE BLOWN HYD. HOSE ON TESCO TOP DRIVE. 11:30 - 12:00 0.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8,056 T/ 8,091. 12:00 - 22:00 10.00 02 A DRLIN2 DRLG 8.5 HOL F/ 8091 TO 8273 22:00 - 22:30 0.50 02 A DRLIN2 CIRC. BOTTOMS UP TO SURVEY 22:30 - 23:00 0.50 02 A DRLIN2 RIG SHEAVE ON TOPDRIVE TO WIRELINE /MAKE UP SURVEY 23:00 - 23:30 0.50 10 A DRLIN2 RIH W/ WIRELINE SURVEY AND SURVEY @ 8212 23:30 - 00:00 0.50 A DRLIN2 SURVEY AND POOH 00:00 - 00:30 0.50 02 A DRLIN2 POOH W/ WIRELINE SURVEY 00:30 - 01:00 0.50 02 A DRLIN2 POOH W/ 10 STAND SHORT TRIP 01:00 - 02:30 1.50 02 A DRLIN2 RIH. P/U 27 JTS. DRILL PIPE F/ CATWALK 02:30 - 06:00 3.50 02 A DRLIN2 DRLG 8.5 HOLE F/ 8273 TO 8333 11/16/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5 HOLE F/8333 T/ 8371. 12:00 - 04:00 16.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8371 T/ 8552. 04:00 - 04:30 0.50 08 A DRLIN2 CHANGE SWAB , CIRC. CLEAN BIT. 04:30 - 06:00 1.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8255 T/8560. 11/17/2000 06:00 - 09:00 3.00 02 'A DRLG. 8.5" HOLE F 8560 TO 8573. 09:00 - 09:30 0.50 05 A CIRC. BOTTOMS UP 09:30 - 10:00 0.50 10 A DROPPED SURVEY @ 8552 10:00 - 12:00 2.00 06 A PUMP PILL; POOH 12:00 - 16:30 4.50 06 A POOH F 5809 TO 315 16:30 - 17:30 1.00 06 J RETRIEVE SURVEY; STAND BACK BHA, LD MUD MTR 17:30 - 20:00 2.50 25 PULL WEAR BUSHING; SANDED IN; WASHED FREE 20:00 - 21:30 1.50115 A RIG UP TO TEST B.O.P.'s 21:30 - 23:00 1.50 15 A TEST RAMS; ANNULAR; FLOOR VALVE; KELLY COCKS 23:00 - 00:00 1.00 15 B REPAIRING TWO KILL LINE VALVES 00:00 - 05:00 5.00 15 B WORKING ON KILL LINE AND CHOKE VALVES 05:00 - 06:00 1.00 15 B TESTING KOOMEY. 11/18/2000 06:00 - 07:30 1.50 26 DRLIN2 Pick up 15 jts. off walk; stand back in derrick 07:30 - 08:30 1.00 15 A DRLIN2 M/U Test Plug, test choke valve, good test. Pull plug, run wear ring. 08:30 - 12:00 3.50 25 DRLIN2 M/U BHA. Pull allenhead bolts for added flow w/ drillbit. 12:00 - 13:00 1.00 25 ' DRLIN2 Waiting on drill bit. Clean rig floor & cellar. Adjust crown warning bell 13:00 - 15:00 2.00 26 DRLIN2 Make up new 8.5 bit. RIH to 1128 ft. 15:00 - 15:30 0.50 25 DRLIN2 Change out Saver Sub on Tesco Top Drive 15:30 - 16:00 0.50 25 DRLIN2 Fill DP & flow check Teledrift tool @ 1220 16:00 - 19:00 3.00 06 J DRLIN2 TIH from 1220 to 6277 19:00 - 19:30 0.50 06 1J DRLIN2 Fill DP & spot check Teledrift tool 19:30 - 21:00 1.50, 06 J DRLIN2 TIH from 6277 to 8552 21:00 - 21:30 0.50 06 J DRLIN2 Fill DP & spot check Teledrift tool (3.5 deg) 21:30 - 00:00 2.50 02 A DRLIN2 DRLG from 8572 to 8600 00:00 - 06:00 1 6.00 02 ; A DRLIN2 DRLG from 8600 to 8678 11/19/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8678 T/ 8776 12:00 - 00:00 12.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8776 T/ 9050 00:00 - 01:30 1.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 9050 T/ 9089 01:30 - 02:00 0.50 10 'A DRLIN2 TELEDRIFT SURVEY @ 9049' (3.5 TO 4.0 DEG.) 02:00 - 06:00 4.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 9089 T/ 9180 11/20/2000 06:00 - 12:00 6.00, 02 A DRLIN2 DRLG. F/ 9180 T/ 9254 12:00 - 12:30 0.50 25 DRLIN2 ESTABLISH DRLG. PERIMETERS. NABORS SAFETY MEETING 12:30 - 13:00 0.50 07 DRLIN2 SERVICE RIG 13:00 - 00:00 11.00 02 A DRLIN2 DRLG. F/ 9254 T/ 9466 00:00 - 06:00 6.00 02 A DRLIN2 DRLG. F/ 9466 T/ 9538 11/21/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 9538 T/ 9562 12:00 - 18:00 6.00 02 A DRLIN2 DRLG. F/ 9562 T/ 9655 Printed: 04 /24/2003 9:18:33 AM • • I OREST OIL CORP. Page 10 of 15 .. Qp r i nt Ina yRepo Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 D e From - To Hears Code - Description cription of Operatipns Cody 11/21/2000 18:00 - 18:30 0.50 10 A DRLIN2 TELEDRIFT SURVEY @ 9549. 18:30 - 19:00 0.50105 I DRLIN2 CBU F/ SHORT TRIP 19:00 - 20:00 1.00 06 H DRLIN2 11 STD SHORT TRIP. F/ 9655 T/ 8624 20:00 - 20:30 0.50 07 DRLIN2 CLEAN RIG FLOOR. 20:30 - 21:00 0.50 07 DRLIN2 SERVICE RIG. 21:00 - 23:00 2.00 26 H DRLIN2 PJSM. RIH F/ 8624 T/ 9655, P/U PIPE FROM RACK & RABBIT. 23:00 - 00:00 1.00 02 A DRLIN2 DRLG F/ 9655 T/ 9660 00:00 - 06:00 6.00 02 A DRLIN2 DRLG F/ 9655 T/ 9724 11/22/2000 06:00 - 12:00 6.00 02 A DRLG 8.5" HOLE F/ 9724 TO 9795 12:00 - 18:00 6.00 02 A DRLG 8.5" HOLE F/ 9795 TO 9840 18:00 - 18:30 0.50 07 SERVICE RIG DRAWWORKS; BLOCKS; CROWN 18:30 - 06:00 11.50 02 A DRLG 8.5" HOLE F/ 9840 TO 9965 11/23/2000 06:00 - 16:00 10.00 02 A DRLIN2 Drilling 8 1/2" hole from 9965 to 9983. 16:00 - 16:30 0.50 10 A DRLIN2 Survey w/ teledrift @ 9935'. Drop totco. 16:30 - 17:00 0.50 28 DRLIN2 Monitor well, pump dry job. 17:00 - 20:00 3.00 06 A DRLIN2 POOH to 6467'. (shoe) 20:00 - 20:30 0.50 07 DRLIN2 Service Rig 20:30 - 21:00 0.50 05 I DRLIN2 Circulate bottoms up. 21:00 - 21:30 0.50 25 DRLIN2 Pre -Job safety meeting 21:30 - 05:00 7.50 08 C DRLIN2 Remove and repair high drum clutch 05:00 - 06:00 1.00 06 J DRLIN2 POOH to change bit and BHA 11/24/2000 06:00 - 09:00 3.00 06 A DRLIN2 POOH 09:00 - 12:00 3.00 06 A DRLIN2 Retrieve survey © DCs', break bit, lay down mud motor, inspect survey tool. 12:00 - 15:00 3.00 06 A DRLIN2 Service teledrift tool, pick up mud motor and new bit, RIH with BHA to 1128'. 15:00 - 17:30 2.50 06 B DRLIN2 PJSM, P/U 5" DP from pipe rack. (rabbit each joint) RIH from 1128' to 2067'. 17:30 - 18:00 0.50 07 DRLIN2 Service rig and re- adjust kelly hose to top drive. 18:00 - 23:00 5.00 06 A DRLIN2 RIH from 2067' to 6475'. Fill pipe © 3472' and 6475'. 23:00 - 00:00 1.00 07 DRLIN2 Cut and slip drilling line. 00:00 - 02:00 2.00 06 A DRLIN2 RIH from shoe, fill pipe @ 9000'. 02:00 - 02:30 0.50 03 DRLIN2 Ream from 9845' to bottom © 9984'. 02:30 - 06:00 3.50 02 A DRLIN2 Drilling 8 1/2' hole from 9984' to 10068'. 11/25/2000 06:00 - 21:00 15.00 02 A DRLIN2 Drilling 8 1/2" hole from 10068' to 10503'. ADT hrs. 21:00 - 21:30 0.50 10 A DRLIN2 Survey w/ teledrift @ 10435' -3.5 Deg. 21:30 - 02:30 5.00 02 A DRLIN2 Drilling 8 1/2" hole. 02:30 - 03:00 0.50 29 DRLIN2 Circ. bottoms up. 03:00 - 04:00 1.00 06 H DRLIN2 7Std. short trip. Hole in good shape, no fill. 04:00 - 06:00 2.00 02 A DRLIN2 Drilling 81/2" hole. Hole is taking +/- 10 bbls. /hr. fluid. 11/26/2000 06:00 - 13:30 7.50 A DRLIN2 Drill 8 1/2" hole. 13:30 - 14:00 0.50 07 DRLIN2 Service rig, draw - works, blocks and crown. 14:00 - 17:30 3.50 02 A DRLIN2 Drilling 8 1/2" hole to 10809'. 17:30 - 18:00 0.50 10 A DRLIN2 Survey with teledrift @ 10758', 3.5 deg. 18:00 - 18:30 0.50 28 DRLIN2 Monitor well, mix and pump dry job. 18:30 - 01:00 6.50 A DRLIN2 POOH to BHA. 01:00 - 02:30 1.50 06 A DRLIN2 Work BHA, lay down jars and stab. 02:30 - 04:00 1.50 15 A DRLIN2 Pull wear bushing, pick up test plug. 04:00 - 06:00 2.00 15 A DRLIN2 Test BOPs, 250/4000# 11/27/2000 06:00 - 07:00 1.00 07 DRLIN2 Put Kelly Hose on and reposition. 07:00 - 08:30 1.501 26 DRLIN2 M/U Bit; Brk Teledrift & redress; test mudmotor 08:30 - 09:30 1.00 06 J DRLIN2 TIH w/ BHA & HWDP 09:30 - 10:00 0.50 06 J DRLIN2 TIH I ' Printed: 04 /24/2003 9:18:33 AM 1 1 r • 411 FOREST L COR ? Pace 11 of 15 Ope s Sum m Re art Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Dtfte From Tip'" How Code S t Phase DeScription of Operations Code 11/27/2000 10:00 - 12:00 2.00 07 DRLIN2 Working on positioning kelly hose; interferes w/ making up drillpipe from driller's side; hose binding against pipe. 12:00 - 12:30 0.50 07 DRLIN2 Service rig; drawworks; blocks; crown. 12:30 - 18:00 5.50 06 J DRLIN2 TIH f/ 1225 to 10594; filled DP © 3471, 6295, 8910. 18:00 - 19:00 1.00 03 A DRLIN2 Ream f/ 10594 to 10806; pumped hi -vis sweep while reaming to bottom. 19:00 - 00:00 5.00 02 A DRLIN2 Drilling f/ 10806 to 10846. 00:00 - 06:00 6.00 02 A DRLIN2 Drilling f/ 10846 to 10915 11/28/2000 06:00 - 10:00 4.00 02 A DRLIN2 Drilling 8 1/2" hole. 10:00 - 12:00 2.00 02 A DRLIN2 Pump hi -vis sweep while drilling 8 1/2" hole. 12:00 - 12:30 0.50 02 A DRLIN2 Drilling 81/2" hole. 12:30 - 13:00 0.50 07 DRLIN2 Service rig, draw - works, blocks, swivel and crown. 13:00 - 21:30 8.50 02 A DRLIN2 Drilling 8 1/2' hole, pump hi -vis sweep while drilling. 21:30 - 22:00 0.50 29 DRLIN2 Circ. hole clean after hi -vis sweep for short trip, monitor well. 22:00 - 22:30 0.50 06 H DRLIN2 Short trip from 11174' to 10594'. No hole problems. 22:30 - 06:00 7.50 02 A DRLIN2 (Drilling 8 1/2' hole. 11/29/2000 06:00 - 07:00 1.00 02 A DRLIN2 I Drilling f/ 11290 to 11300 07:00 - 12:00 5.00 02 A DRLIN2 Pump up to survey depth (11258); 15 min. Drilling f/ 11300 to 11345 12:00 - 12:30 0.50 07 DRLIN2 Service rig. 12:30 - 00:00 11.50 02 A DRLIN2 Drilling f/ 11345 to 11475 00:00 - 06:00 6.00 02 A DRLIN2 Drilling f/ 11475 to 11590 11/30/2000 06:00 - 06:30 0.50 02 A DRLIN2 Drilling 8 1/2" hole from 11590' to 11598'. 06:30 - 08:30 2.00 05 I DRLIN2 Pump hi -vis sweep, circ. bottoms up and monitor well for 10 min. Pump dry job. 08:30 - 13:30 5.00 06 A DRLIN2 POOH from 11598' to inside the shoe @ 6381'. 13:30 - 14:00 0.50 08 C DRLIN2 PJSM 14:00 - 16:00 2.00 08 C DRLIN2 Move Hydromatic and work on over - riding clutch. Clutch worn out, needs replacing. Waiting on clutch parts. 16:00 - 06:00 14.00 08 C DRLIN2 Monitoring well while repairing trip -tank, changing liners in # 2 pump, circ. every six hours, continue monitoring well while waiting on clutch parts. 12/01/2000 06:00 - 10:30 4.50 08 C Blow Down Topdrive. remove Kelly Hose and goosnecks; tighten 1002 unions; have welder tack to keep from backing off agian. Install same and adjust Kelly Hose to keep away from drillpipe when tripping. Change impeller on #1 water pump. Change belts on #2 water pump. Electrician troubleshooting problem with drawworks SCR assignment. 10:30 - 12:00 1.50 08 C Dress and clean overriding clutch to be installed. Work on installing same. 12:00 - 18:00 6.00 08 C Install overide clutch. Reinstall all guards. 18:00 - 18:30 0.50 05 A Circulate and conditon mud. Pump dry job. 18:30 - 22:00 3.50 06 J Blow down topdrive. POOH. 22:00 - 00:00 2.00 Finish POOH. Check out Teledrift tool. Break off bit. 00:00 - 01:30 1.50 26 Making up new BHA w/ 8.5" bit; mud motor; teledrift tool 01:30 - 02:30 1.00 26 Pick up 18 singles of 5" drill pipe. 02:30 - 06:00 3.50 06 J ;RIH. Fill drillpipe. 12/02/2000 06:00 - 10:00 4.00 08 C DRLIN2 I REALIGN OVERRIDING CLUTCH. 10:00 - 12:00 2.00 06 A DRLIN2 I TIH; LAY DN SINGLE, WASH OUT; TIH TO 8350 12:00 - 12:30 0.50 06 A DRLIN2 RIH 12:30 - 14:00 1.50 29 DRLIN2 BREAK CIRC @ 8443; FILL PIPE & CBU 14:00 - 15:00 1.00, 06 A DRLIN2 RIH 15:00 - 16:00 1.00 03 A DRLIN2 BREAK CIRC @11623; FILL PIPE; REAM 100' TO BOTTOM 16:00 - 16:30 0.50 03 A DRLIN2 WASH TO BOTTOM; BREAK IN BIT. 16:30 - 00:00 7.50 02 A 1 DRLIN2 DRILLING F/10598 TO 11740 Printed: 04/24/2003 9:18:33 AM • FOREST OIL CORP. .' Page 12 of 15 A erations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date from - To Hours Code Sub Phase Desciiption of Opeerati s „ 12/02/2000 00:00 - 04:00 4.00 02 A DRLIN2 DRILLING F/ 11740 TO 11812 04:00 - 04:30 0.50 10 A DRLIN2 SURVEY; 3.5 DEG @11758 04:30 - 06:00 1.50 02 A DRLIN2 DRILLING F/ 11812 TO 11869 12/03/2000 i 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5" HOLE F/ 11869 T/ 11970 12:00 - 00:00 12.00 02 A DRLIN2 DRLG. F/ 11970 T/ 12165 00:00 06:00 6.00 02 A DRLIN2 DRLG. F/ 12165 T/ 12257 12/04/2000 06:00 - 09:30 3.50 02 A DRLIN2 DRLG. 8.5" HOLE F/ 12257 T/ 12300 09:30 - 10:00 0.50 A DRLIN2 PUMP UP SURVEY @ 12258 FT. STAND BACK STD. 10:00 - 12:00 2.00 05 I DRLIN2 PUMP HI VIS SWEEP CIRC. BTMS UP & RECPROCATE PIPE, MIX DRY JOB, MONITOR WELL 10 MIN. 12:00 - 12:30 0.50 28 DRLIN2 PUMP DRY JOB & BLOW DOWN TOP DRIVE. 12:30 - 22:00 9.50 06 C DRLIN2 1 P.O.H. TO SHOE- SLOW- CHECK FOR FLOW @ 9 5/8 SHOE & P.O.H. 22:00 - 22:30 0.50 06 C DRLIN2 LAY DOWN MOTOR, TELEDRIFT & 8.5 BIT. 22:30 - 00:00 1.50 11 A 1 DRLIN2 RIG UP TO LOG. 00:00 - 02:30 2.50, 11 A I DRLIN2 MAKE UP SWL TOOLS, HOLD PJSM. RIH TO WARM UP TOOLS; POOH TO LOAD SOURCE. WHEN POH TO LOAD SOURCE, TOOL HUNG UP AT 94 FT. TOOL FREED. 02:30 - 06:00 3.50 11 A DRLIN2 RIH W/ LOGGING TOOLS. 12/05/2000 06:00 - 12:00 6.00 11 A EVAL 2 RIH SWL. POOH, unload sources, laydown tools. Hang up again © 90 ft. Rope socket missing AIT standoff from bottom of tool. Make up FMI tools, RIH to warm up. Start in hole @ 10:15 hrs. w/ FMI 12:00 - 14:30 2.50 11 A EVAL 2 POOH, logging w/ FMI tools. 14:30 - 00:00 9.50 25 EVAL 2 ! Wireline logging tool stuck @ 6740 ft. Working to free. 00:00 - 06:00 6.00 25 1 EVAL 2 1 Monitoring well, waiting on fishing tools and hands. 12/06/2000 06:00 - 12:00 6.00125 EVAL 2 i MONITOR WELL W/ TRIPTANK. WAIT ON WEATHER TO RECEIVE FISHING TOOLS & SCHLUMBERGER HANDS. 12:00 - 15:00 3.00 25 EVAL 2 WAITING ON FISHING TOOLS. 115:00 - 16:30 1.50 19 B EVAL 2 P/U FISHING TOOLS, FIGURE OUT BHA,CLAMP WIRE, WAIT ON SCHLUMBERGER. 16:30 - 18:00 1.50 25 EVAL 2 PRE -JOB MEETING, PROCEDURES TO RIG UP & STRIP OVER. 18:00 - 21:00 3.00 19 B EVAL 2 RIG UP SCHLUMBERGER SHEAVE IN DERRICK, CUT & THREAD WIRELINE, RIG UP SINKER BARS, TEST WIRELINE HEAD TO 6K. 1 21:00 - 22:00 1.00 B EVAL 2 RIH BHA 1 22:00 - 00:00 2.00 19 B 1 EVAL 2 , RECUT WIRE FOR BETTER SPACING, REPOSITION SHEAVE IN !DERRICK. 00:00 - 06:00 6.00 19 B EVAL 2 STRIPPING OVER WIRELINE 12/07/2000 06:00 - 08:30 2.50 19 B EVAL 2 STRIP OVER TO SHOE 08:30 - 09:30 1.00 29 EVAL 2 CIRCULATE BOTTOMS UP PLUS DRILL PIPE VOLUME 09:30 - 10:00 0.50 06 B EVAL 2 TRIP IN HOLE TO FISH 10:00 - 11:30 ! 1.50 19 B EVAL 2 PICK UP SINGLE. FIND FISH AT 6713 111:30 - 12:00 0.50119 B EVAL 2 MAKE UP CIRCULATING SUB. PRESSURE UP AND BLOW DISC ON PUMPOUT SUB. 12:00 - 13:00 1.00 28 F 1 EVAL 2 CIRCULATE AND PUMP DRY JOB. BLOW DOWN TOPDRIVE. 13:00 - 14:00 1.00 25 EVAL 2 PRE -JOB SAFETY MEETING (R/U TO PULL WIRELINE). HANG WIRELINE. T CLAMP. RIG DOWN WIRELINE SHEAVE FROM CROWN. LATCH UP ON T CLAMP WITH RIG ELEVATORS. PULL 11,000 LBS. TO BREAK LINE AT ROPE SOCKET. 14:00 - 15:30 1.50! 19 B EVAL 2 R/U SCHLUMBERGER TO POH. WIRELINE RETRIEVED ALL LINE. 15:30 - 16:00 0.50 11 1 A , EVAL 2 RIG DOWN SCHLUMBERGER 16:00 - 21:00 5.00 06 B j EVAL 2 POOH WITH FISH. 21:00 - 22:00 1.00 25 EVAL 2 I LAY DOWN FMI TOOL AND TRISTATE FISHING TOOLS. 22:00 - 00:00 ! 2.00 26 EVAL 2 PICK UP BHA 1 Printed: 04 /24/2003 9:18.33 AM • • FORE T OIL CORP. Page 13 of 15. Orteration44timmary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From To Hours .ode 'I hose; Description of Operations 12/07/2000 00:00 - 00:30 0.50 06 EVAL 2 PJSM 15 MIN. TIH W/ HWDP 00:30 - 02:30 2.00 09 EVAL 2 CUT AND SLIP 100' OF DRILLING LINE. SERVICE RIG. 02:30 - 04:00 1.50 06 EVAL 2 TIH TO 7443 FT. REAM TIGHT SPOT (40000 DOWN, 20000 UP) 04:00 - 06:00 2.00 06 EVAL 2 TIH. TIGHT @ 7287. WORK PIPE THROUGH TWICE. CLEANED UP. 12/08/2000 06:00 - 07:30 1.50 06 H CSGIN2 TIH TO 9318' WASH & REAM TO 9348' 07:30 - 08:30 1.00 05 F CSGIN2 CIRC. HOLE CLEAN. 08:30 - 10:00 1.50 06 H CSGIN2 TIH TO 9650' CIRC. HOLE CLEAN. 10:00 - 12:00 2.00 06 H CSGIN2 TIH TO 11542' WASH & REAM TO 11589'. 12:00 - 12:30 0.50 06 H CSGIN2 TIH 12:30 - 13:00 0.50 29 CSGIN2 CBU © 11872. 13:00 - 14:00 1.00 06 H CSGIN2 TIH 14:00 - 17:00 3.00 03 A CSGIN2 REAM TO BTM. F/ 12061 T/ 12300. 17:00 - 21:30 4.50 05 F CSGIN2 PUMP 2 SWEEPS, CIRC & COND MUD. 21:30 - 22:00 j 0.50 05 F CSGIN2 PUMP 3RD SWEEP, MONITOR WELL 22:00 - 00:00 2.00 06 H CSGIN2 POOH 00:00 - 06:00 6.00 06 H CSGIN2 POOH 12/09/2000 06:00 - 09:00 3.00 06 H CSGIN2 STD BACK BHA, UD STABS, BREAK BIT. 09:00 - 10:00 1.00 15 A CSGIN2 PULL WEAR RING, SET TEST PLUG. 10:00 - 12:00 2.00 15 A , CSGIN2 CHANGE RAMS T/ 7 5/8 ". HANG STABBING BOARD. P/U CASING ELEVATOR, HANG HOSES, HOOK UP FILL -UP LINE T/ CASING. 1 12:00 - 13:30 1.50 15 A CSGIN2 TIGHTEN BOLTS ON RAM DOORS. TEST STACK TO 3000 PSI. PULL TEST PLUG, SET WEAR RING. 113:30 - 14:30 1.00 01 A CSGIN2 RIG UP WEATHERFORD. 14:30 - 15:00 0.50 25 I CSGIN2 PRE -JOB SAFETY MEETING (RUNNING CASING) 15:00 - 00:00 9.00 12 B I CSGIN2 RIH W/ 7 -5/8" LINER. HIT TIGHT SPOT @90 FT. WORKED THROUGH. CHECKED FLOAT - O.K. 00:00 - 06:00 6.00 12 B CSGIN2 RIH W/ 7 -5/8" LINER. JOINT #52 HAS DAMAGED THREADS. PULLED OUT AND RUNNING TALLY ADJUSTED ACCORDINGLY. 12/10/2000 06:00 - 07:30 1.50 12 B CSGIN2 UD casing tools; P/U and M/U hanger 07:30 - 09:00 1.50 12 B CSGIN2 UD stabbing board; M/U saver sub on top drive; clamp and safety chains. 09:00 - 11:30 2.50 12 B CSGIN2 RIH w /liner and hanger on 5" drillpipe. Hit tight spot @ 90'. Circulate, rotate 1/2 turn; work through. CBU. 11:30 - 12:00 0.50 12 B CSGIN2 RIH w/ liner hanger and liner. 12:00 - 14:30 2.50 12 B CSGIN2 RIH w/ drillpipe. Rabbit pipe. Fill pipe (10 stands) 14:30 - 15:30. 1.00 05 F CSGIN2 CBU 15:30 - 16:00 0.50 07 CSGIN2 !Work on topdrive. 1 16:00 - 17:00 1.00 12 B CSGIN2 RIH. No problems. 117:00 - 21:00 4.00 12 B CSGIN2 , Tagged bottom @ 12,300 ft. 121:00 - 00:00 3.00 05 F CSGIN2 j Circulate and reciprocate hole clean and M/U cement head. 00:00 - 01:00 1.00 29 CSGIN2 Circulate. Hold PJSM. 01:00 - 01:30 0.50 12 C CSGIN2 P/U & M/U cement top drive head. Break circulation. 01:30 - 03:30 2.00 12 C 1 CSGIN2 Test lines t/ 4500 psi. Cement liner. 03:30 - 04:00 0.50 12 C I CSGIN2 Drop plug. Displace w/ rig pump. 94 strokes /min for 4493 strokes. 04:00 - 05:00 1.00 12 D I CSGIN2 Attempt to unsting f/ liner and set packer. 05:00 - 05:30 0.50 12 D CSGIN2 Pressure up on packer to 4000 psi. Set packer and unsting from liner. 05:30 - 06:00 0.50 12 D CSGIN2 Break off cement head and pull 5 stands 12/11/2000 06:00 - 06:30 0.50 25 CSGIN2 Test casing. No test. 06:30 - 07:00 0.50 05 F CSGIN2 Circulate 2X drillpipe capacity. 107:00 - 08:00 1.00 09 CSGIN2 Slip drilling line 102'. Blow down topdrive and kill line 08:00 - 12:00 4.00 06 G CSGIN2 POOH, lay down 5" drillpipe. 1 12:00 - 16:00 4.00 25 CSGIN2 Lay down 5" drillpipe 1 I Printed: 04 /24/2003 9:18:33 AM 410 FOREST OIL CORP. Page 14 of 15 e atio is Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 dub Desdnptl¢n of Oper ations j From To Hours Code Code Phase " s� 12/11/2000 16:00 - 16:30 0.50 25 CSGIN2 Lay down Baker running tools. 16:30 - 17:30 1.00 25 CSGIN2 Left hole fluid level down. Inspect 9 -5/8" casing. Casing has hole at approximately 87.41' from rotary table. 17:30 - 18:30 1.00 25 CSGIN2 Lay down drill collars; jars; & HWDP 18:30 - 19:00 0.50 15 CSGIN2 Pulled wear ring; set test plug. 19:00 - 20:00 1.00 25 CSGIN2 Open doors on B.O.P.; change rams f/ 7" to 5 ". 20:00 - 20:30 0.50 15 CSGIN2 Tested BOP stack to 3000 psi. Tested OK 20:30 - 22:00 1.50 12 CSGIN2 Pick up cement head & break down. 22:00 - 00:00 2.00 05 CSGIN2 Clean up mud; gunning over shakers. 00:00 - 06:00 6.00 25 CSGIN2 Cleaning mud pits. 12/12/2000 06:00 - 09:30 3.50 25 CSGIN2 Clean mud pits. Transfer mud over shakers to volume pit. Clean trip tank. 09:30 - 12:00 2.50 15 B CSGIN2 Test choke manifold, outside kill line, top drive valve (low 250 psi; high 4000 psi). All valves, floor valves, Hydril (2500 psi), all rams (250 psi tow; 4000 psi high); Koomey tested. 12:00 - 18:00 6.00 25 CSGIN2 Rig down flow line; fill up line; pitcher nipple; turnbuckles; drip pans. Rig up hydraulic lift lines to stack. Pick up slings, take off choke lines. 18:00 - 19:30 1.50 25 CSGIN2 PJSM. Raising BOP stack. 19:30 - 22:30 3.00 25 CSGIN2 Raise stack 1'. Tubing hanger & 9 -5/8" pack off would not release. Worked on freeing hanger, stub came free. Removed tubing spool, installed adapter spool. 22:30 - 00:00 1.50 19 E CSGIN2 Pick up and make up fishing tools. 00:00 - 02:00 2.00 19 E CSGIN2 POOH w/ casing stub and full joint (57.84 ft.) and inspect threads. 02:00 - 06:00 4.00 i 14 B CSGIN2 Nipple up BOP, hook up flow line and pitcher nipple. 12/13/2000 06:00 - 07:00 1.00 14 B CSGIN2 Reset hydraulic pick up slings, pick up BOP stack. 07:00 - 12:00 5.00 21 CSGIN2 Fill suction pit, pump across BOP. Clean around outside shakers and dumps. Round up rental tools. Clean docks. Haul DP to to WMRU yard. 12:00 - 13:30 1.50 21 CSGIN2 Continue to clean rig while waiting on APRS. 13:30 - 14:00 0.50 19 E CSGIN2 Redress spear. Lay down single HWDP, pick up stand of HWDP. 14:00 - 16:00 2.00 19 E CSGIN2 Rig up APRS for freepoint 16:00 - 16:30 0.50 25 CSGIN2 Pre -job safety meeting (Backing out casing - string shot) 16:30 - 17:00 0.50 19 E CSGIN2 Apply reverse torque to casing string. String came free. Backed out. 17:00 - 17:30 0.50 19 E CSGIN2 POOH w/ 9 -5/8" casing 17:30 - 18:00 0.50 25 CSGIN2 Rig up to lay down casing. 18:00 - 21:30 3.50 25 CSGIN2 Lay down 10 joints 9 -5/8" BTC casing. 21:30 - 22:30 1.00 05 F CSGIN2 1 RIH w/ DP. Wash 5' over fish. Clean hole. POOH. 22:30 - 23:30 1.00 25 CSGIN2 Inspecting casing. 23:30 - 00:00 0.50 12 A CSGIN2 Run casing. Seal rings installed in each connection. Torqued to 12,000 ft lbs. 00:00 - 06:00 6.00 12 D CSGIN2 Hang BOP. Set casing slips. Prepare to cut off 9 -5/8" casing. 12/14/2000 06:00 - 07:30 1.50 14 B RDMO Back out of landing joint with x/o, cut off 24.33' of 9 5/8" csg. and lay down same. Make final cut. 07:30 - 12:00 4.50 14 B RDMO Set BOPs, pick up pick up slings. Remove spool, replace with tubing spool. 12:00 - 13:00 1.00 15 A RDMO Test pack -off void to 3000 psi. 15 min. test OK. 13:00 - 14:30 1 1.50 15 A RDMO Set wear -ring, R/U to test 9 5/8" csg., 7 5/8' csg. and liner lap. Test to 3000 psi. for 30 min. Test OK. 14:30 - 17:00 2.50 06 J RDMO RIH with 5" DP. 17:00 - 20:30 3.50 06 J RDMO Make -up bit, bit sub and float. RIH with DP. j 20:30 - 04:30 8.00 22 B RDMO Lay down 5" DP.Break down fishing tools. 04:30 - 06:00 1.50 30 1 RDMO Prepare to nipple down BOPs. 12/15/2000 06:00 - 12:00 6.00 30 RDMO Nipple down BOPs, lay down beaver slide. Printed: 04/24/2003 9:18:33 AM to J • , FOREST OIL CORP. Page 15 of 15 ©pe atia i s Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From To Hours,. C 1s Code Phase 0, scdption oftOperattons 12/15/2000 12:00 - 13:00 1.00 31 RDMO Install test plug in tbg. spool, make up kill line to tbg. spool. 13:00 - 17:00 4.00 01 B RDMO Rig down Tesco top drive, remove elevators, bails, service and hydraulic lines. Break quill loose. 17:00 - 18:00 1.00 31 RDMO Remove test plug, make up abandoment head. 18:00 - 19:00 1.00 07 RDMO Clean cellar and rig floor. 19:00 - 20:00 1.00 31 RDMO Test 9 5/8' csg., two csg. valves, master valve and tree cap from 300 to 3000 psi. Also this was test 7 5/8" csg. and liner lap. Test was witnessed by 1...Grimaldi, AAOGCC. 20:00 - 23:00 3.00 12 D RDMO Rig up to freeze protect 13 3/8" annulus and 9 5/8" csg. 30" below ground level.Blew mud out of csg. and annulus and filled with Diesel. 23:00 - 23:30 0.50 07 RDMO Clean cellar. 23:30 - 00:00 0.50 01 B RDMO PJSM Hang blocks to slip drlg to lay down top drive. Rig released @ 2400 Hrs. i Printed: 04/24 /2003 9:18:33 AM • • a Kustatan Field #1 Class II Disposal Completion March 25, 2003 0:00 to 06:00 Remove well flange, cap and valve. Nipple up BOP. Fill pits with water. March 26, 2003 06:00 to 02:00 Nipple up BOP. Rig up PVT, gas alarms and other well control items. 02:00 to 06:00 Pressure Test March 27, 2003 06:00 to 14:00 Pressure Test BOP. 14:00 to 01:00 Pick up 8.5" bit, 9 5/8" casing scraper and 2 7/8" tubing. 01:00 to 06:00 Rig to displace. Begin mixing KCL. March 28, 2003 06:00 to 18:00 Mix and pump Biozan pill. Build 8.8# KCL. Displace Well with returns to tiger tank. Haul off some loads with vac truck. 18:00 to 23:00 POH. 23:00 to 06:00 Unable to fly in service personnel due to weather. Wait on Schlumberger. March 29, 2003 06:00 to 11:00 Wait on bad weather to transport S.O.S. reps. 11:00 to 19:00 Rig up and RIH with GR. CBL. On S.O.S. wireline from 6299' (7 5/8" T.O.L. wlm), to 4600' 19:00 to 01:00 Attempt to test vsic (safety system module) on perf. Gun assy. Made a good test on vsic tool. 01:00 to 06:00 Attempt to run 20' 3 3/8" Perf gun Assy. Could not pass thru 7 5/8" liner top. Made several attempts at passing thru liner top with centralized tapered nose weight and GR. Tools, POH, Rig down wireline. Prep to RIH with 7 5/8" csg. Scraper and mill assy. • i March 30, 2003 06:00 to 10:00 OPH with Schlumberger wireline and tools (weight bars /G.R.), rig down 10:00 to 12:00 Wait on Taper nose mill and 7 5/8" csg. Scraper to clean out 7 5/8" T.O.L. and csg. 12:00 to 19:30 P/U & RIH with 6" taper nose mill, 6 3 /4" Watermelon mill and 7 5/8" csg. Scraper, P/U 9 joints of 2 78 "tbg. And 10 joints of 3 '/2 " drill pipe. 19:30 to 22:00 Tag up on fill at 6306' and wash through to 6310' = 4' of fill, continue to wash down to 6326' (periodically taking weight with 6k over pull). Appears to have cleaned up, stop pumping and RIH to 6850' 22:00 to 01:00 Rig up to and reserve circulate, until returns clean up. Dumped 30 bbls of thick contaminated mud and fill 01:00 to 06:00 POH, lay down 10 joints of 3 ' /2" drill pipe March 31, 2003 06:00 to 08:00 POH, L/D 7 5/8" csg. Scraper assy. 08:00 to 19:00 R/U S.O.S. wireline, RIH w /20' perf gun, shot successful, POH repair short in E -line, RIH with 3 runs: 2 -20' guns ans 1 -10' 3 3/8 " perf gun, 6 spf, 60 degree phase, .45 shot size, 38.5" "penetration, Bottom shot @ 6800', Top shot @ 6750' = 50' of perfs. POH and RID S.O.S. wireline and tools. 19:00 to 20:30 Pull wear ring, L/D 5 stands from derrick 20:30 to 06:00 M/U Baker SC2 9 5/8" Packer, RIH at moderate speed to WLEG depth of 6322' April 01, 2003 06:00 to 09:30 RIH w/ 9 5/8 " Baker SC2 -PAH Retrievable, retainer production packer, M/U tbg. Hanger and lower to 3' from bottom of BOP stack. 09:30 to 11:30 Displace well with corrosion inhibitor solution, (4 — drums of M.I. conqor 303) 11:30 to 13:30 Land 2 7/8 " tbg. Hanger (WLEG @ 6322', Packer set at 6270', 6310 = 7 5/8" T.O.L.) Freeze protect tbg annulus to 60' with 4 bbls of Diesel 13:30 to 17:00 Drop 1 3 /4" steel ball, test BJ steel lines to 5000 psi, set Packer with 3000 psi. Perform M.I.T. on 2 7/8" x 9 5/8" annulus to 1600 psi for 30 mins, monitor tbg pressure, (No communication, good test) Pressure up to shear ball seat, sheared at 4300 psi. Note: JeffJones w /AOGCC waived witnessing of M.I.T. but would like to be notified 2 weeks into full time injection service. 17:00 to 23:00 Set 2 — way check valve in top of tbg hanger, N/D BOPE and N/U injection tree 23:00 to 24:00 Test tbg hanger and injection tree to 5000 psi for 30 mins. (good test). Remove 2 way check valve. (place sign indicating No BPV installed on tree) { , • Kustatan Field #1 Surveys MD Inc 290 0.000 619 0.500 1,020 0.750 1,389 0.000 1,787 0.000 2,201 0.500 2,699 0.500 3,129 1.000 3,608 0.750 4,070 1.000 4,509 0.750 5,006 0.500 5,382 0.750 5,840 1.000 6,306 1.500 6,677 2.250 7,213 2.875 7,712 3.250 8,212 3.875 8,552 3.500 9,049 3.750 9,549 4.000 9,935 3.500 10,435 3.500 10,758 3.500 12,258 3.500 CSOI • Forest Oil Corporation LD —b s3 310 K Street, Suite 700 Anchorage, Alaska 99501 (907) 258 -8600 Fax: (907) 258 -8601 April 15, 2003 RECEIVED Jim Regg APR 1 5 2003 Alaska Oil and Gas Conservation Commission 333 W 7 th Avenue, suite 100 Alaska Oil & Gas Cons. Commission Anchorage, Alaska 99501 Anchorage Dear Mr. Regg: Attached please find hard copies of the temperature profile ran by Forest Oil Corporation on April 14, 2003 in support of Disposal Injection Order No.26. Also enclosed is a CD -Rom which contains the entire survey. We believe that this data fulfills the pre -start up information required by the Commission. Forest Oil Corporation awaits notification from the Commission that we may start injection into this well. Forest Oil Corporation requests this notification as soon as possible so that fluid may be taken directly into our Kustatan Production Facility for processing. I can be reached in my office at 868- 2137 or on my cell phone at 317 -8232 if there are any questions. Sincerely, Ted Kramer Production Manager Forest Oil Corporation • 41, 1 Forest Oil 1 WeII: 1 KU -1 1 Fieid: (Kustatan 104 -14-03 I Pressure (psia) Line Speed (ft/min) 100 120 140 160 180 200 220 240 260 280 300 320 340 360 ‘ _ r ' • . u -0 0 200 400 600 800 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 , IVO Pressure - Temperature Profile in hole to 6850' MD s Iva 1 Going 2. Well Shut -In ' E E . . i: ._____E___ 100° ENNFATIETEMOIEE i'IIU!II11 2.;,i 2000 1� E 1 E E E i _ Ei Y 3000 I CL W. E E EEE _ . a, O • 4000 1111 C E E liNENE00 5000 EI__ _ E �� . � EEEE _I, _ _ E IiiEEIEEEE iIE!E 1 soon ��� -- U! U ! !U! H h iIN I au PH iU E!Ii a 7000 7000 1 1 1 1 1 1 1 1 30 40 50 60 70 80 90 100 110 120 130 Temperature (Deg. F) , Well Test Solutions. LLC —Pressure — Perfs A Packer —Temperature d Report date: 04/15/2003 i • Forest Oil Weii:I KU -1 I Fie Kustatan 04 -14 -03 1 Pressure (psia) Line Speed (ft/min) 0 400 800 1200 1600 2000 2400 2800 3200 3600 -200 -150 -100 -50 0 50 1 EN Pressure - Temperature Profile ION 1. Pulling out of hole from 6850' MD Nssc,oe 1 2. Well Shut -In I 11:111111 1000 A IIII �' ■� 000 \--11g.kApervokAr-c— 11 ! i11 1 2000 P' 000 h il l _ MOWN 3000 r - a) _ t m iii.■ 9111.1.1,111 4000 =I 5000 11 � 6000 Mil ■ir Mliir 1111. - l ink MI i• ill - 000 7000 1 1 I 1 1 1 1 I I 30 40 50 60 70 80 90 100 110 120 130 Temperature (Deg. F) ; eV Well Test Solutions. LLC —Pressure — Perfs A Packer —Temperature I-m Report date: 04/15/2003 l , • 41110 D B E s F O R E S T O I L C O R P O R A T I O N 0 i e . QY Aeee( • re 700 09/wciioa e, /aiica .99501 0 IV (907) 258 -8600 • (907) 258 -8601 ( r) April 14, 2003 Sarah Palin, Chair State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 RE: Disposal Injection Order No. 26 Miscellaneous Land Use Permit MLUP /CI 03 -03 Dear Commissioner, Please fmd enclosed, as directed by the Alaska Department of Natural Resources, Division of Oil and Gas, one original Miscellaneous Land Use Permit MLUP /CI 03 -03 executed by Gary E, Carlson for Forest Oil Corporation as Permittee. If you should need anything more regarding this matter, please let me know. Sincerely, Jim Arlington Land Manager RECEIVED APR 1 4 2003 Alaska Oil & Gas Cons. Commission Anchorage • LJ L - I I FRANK H. MURKOWSKI, GOVERNOR DEPARTMENT OF NATURAL RESOURCES 550 WEST 7 AVENUE, SUITE 800 ANCHORAGE, ALASKA 99501 -3510 DIVISION OF OIL AND GAS PHONE: (907) 269 -8800 FAX: (907) 269 -8938 April 11, 2003 RECEIVED APR 1 4 2003 Forest Oil Corporation Alaska Oil & Gas Cons. Commission Attn. Jim Arlington Anchorage 310 K Street # 700 Anchorage, Alaska 99501 RE: Miscellaneous Land Use Permit MLUP /CI 03 -03 Kustatan Field #1 Injection Well LAS 24199 Dear Mr. Arlington: The Department of Natural Resources, Division of Oil and Gas ( "DNR ") approves the Forest Oil Corporation ( "the Permittee ") permit application, dated March 3, 2003, to convert the Kustatan Field #1 (KF # 1) well into a Class II waste disposal well. DNR issues this Miscellaneous Land Use Permit MLUP /CI 03 -03 to the Permittee this 1 lth day of April 2003, hereinafter the "Date of Issuance ". Upon receipt of all required approvals from the Alaska Oil and Gas Conservation Commission ( "AOGCC "), the Permittee is authorized to inject Class II wastes, as defined by the AOGCC, in the KF #1 well. The disposal is designed to occur at depths below 6,500 feet MD into the permeable sands of the middle Tyonek formation. The surface area is owned by the Permittee and also contains the Kustatan Production Facility, owned and operated by the Permittee. The KF #1 well is located on the west side of Cook Inlet, 3,443 feet from the north line and 1,468 feet from the west line of Sec. 4, T7N, R14W, S.M. The KF #1 well was drilled by the Permittee on state oil and gas lease ADL- 387023, which expired February 1, 2003. This permit is effective from the Date of Issuance for a term of five years and is subject to the following conditions: 1. This permit is subject to the provisions of 11 AAC 96.040, except as otherwise stated in this permit. The Permittee shall request an extension of this permit in writing within 90 days of the expiration date of the initial five -year term and each subsequent annual extension period. 2. The Permittee shall obtain all required approvals from the AOGCC prior to any disposal activities in the KF #1 well and shall satisfy any AOGCC bonding requirements for the permitted disposal activities. The Permittee shall notify DNR if it is found in violation of the terms of an AOGCC authorization or approval or other approval required by any agency to • • MLUP/CI 03-03 conduct the disposal activities in the KF #1 well. Permittee shall maintain a minimum $100,000 statewide miscellaneous land use bond with DNR for the purpose of securing performance with the terms of this approval. 3. The AOGCC has informed the DNR that it must designate the Permittee as the KF #1 well operator for the Permittee to obtain the AOGCC's authorization for the injection and disposal activity. Therefore, under 20 AAC 25.020, the Permittee is designated the KF #1 well operator for the sole purpose of obtaining the AOGCC's authorization to operate the well as a Class II disposal well. This limited designation of operatorship confers no other rights to the Permittee that are held by the state as owner of the subsurface estate into which the Permittee is authorized the inject waste. The Permittee shall accept the obligations of operatorship by the signature of an appropriate corporate officer in the space below and submit an original of this permit to the AOGCC. This permit will be executed in triplicate. One fully executed original to be retained by the Permittee, one submitted to AOGCC and one returned to the DNR. Permittee hereby accepts its designation as operator under 20 AAC 25.020 with all attendant responsi ities and obligations. 4 Date: 11 Printed Name: 8 4 Title: cf 49 ✓d_ 4. The state may issue oil and gas leases to third parties for the purposes of exploring for, developing, and producing oil and gas from the subsurface estate containing the KF #1 well. Upon the request of any such lessee, the Permittee shall make available records and information about the injection activities that are routinely collected or required to be reported to regulatory agencies and shall cooperate with the lessee so that the lessee may safely exercise the rights granted in the DNR oil and gas lease. 5. This permit does not authorize activity on Mental Health Trust Lands, School Trust Lands, or Park Lands. 6. The Permittee shall defend, indemnify and hold harmless the State of Alaska from and against any and all claims, damages, suits, losses, liabilities and expenses for injury to or death of persons and damage to or loss of property arising out of or in connection with the injection activity authorized under this approval by the Permittee, its contractors, subcontractors and their employees. 7. The Permittee shall allow DNR's authorized representatives to review and inspect the Permittee's operations and records to ensure compliance with the terms of this permit. 8. The Permittee shall immediately notify the DNR, Permit and Compliance Unit, in Anchorage at (907) 269 - 8776 if, during the conduct of operations, state resources are damaged or a land use conflict occurs. 9. This permit is not assignable without DNR's prior written approval. Page 2 • • MLUP /CI 03 -03 • 10. The Permittee shall perform any dismantlement, removal, and restoration to the satisfaction of the DNR commissioner. 11. Only Class II wastes, as defined by the AOGCC and produced from DNR oil and gas leases, are approved for disposal in the KF #1 well. 12.This permit is not intended to affect in any way the performance of the rights and obligations set out in paragraph 21 of lease ADL- 387023. DNR is deferring the performance of those rights and obligation by separate letter to the Permittee. This permit is consistent with the Alaska Coastal Zone Management Program and Local District Plan by the adoption of alternative measures, if any, into the project description. This Miscellaneous Land Use Permit MLUP /CI 03 -03 is issued in accordance with Alaska Statute 38.05, Alaska Miscellaneous Land Use Regulations 11 AAC 96, and Alaska Statute 46.40 and does not convey an interest in property. A person affected by this decision may appeal it, in accordance with 11 AAC 02. Any appeal must be received within 20 days from the Date of Issuance and may be mailed or delivered to Thomas E. Irwin, Commissioner, Department of Natural Resources, 550 W. 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to 1- 907 - 269 -8918, or sent by electronic mail to dnr_appeals @dnr.state.ak.us. This decision takes effect immediately. An eligible person must first appeal this decision in accordance with 11 AAC 02 before appealing this decision to Superior Court. A copy of 11 AAC 02 may be obtained from this office or any regional information office of the Department of Natural Resources. The state's approval of this application means only that the state has no objection to the operations as outlined in the application. It does not constitute certification of any property right or land status claimed by the applicant nor does it relieve the applicant of responsibility to obtain approvals or permits from other persons or governmental agencies as may also be required. If you have any questions please give me a call in Anchorage at 269 -8776, fax 269 -8943, or e-mail Matt_Rader@dnr.state.ak.us. Sincerely, Matt Rader Natural Resource Specialist e.c. Dan Bevington - KPB Mark Fink - DFG Tim Rumfelt - DEC Steve Davies —AOGCC Rick Thompson — DMLW Chris Ruff — Redoubt Unit Manager Page 3 ,04/68/2003 16:30 FAX 907 258 8601 FOREST OIL ALASKA fj001 • • FOREST OIL CORPORATION 310 K Street, Suite 700 Anchorage, Alaska 99501 { (907) 258 -8600 - Office D 0 a -Is (907) 258 -8601 - Fax TO: 71 FAX NUMBER: 276. 75? 2_ DATE: 7 �Q3 FROM: /ogh 67 PHONE NUMBER: TIME: S:,30 Total Number of Pages Including Cover Sheet: 3 ■ COMMENTS: l 1 l ),D2 ISIS S o ,� delA See r n r-r, JJ'' RLCEIV ° ECEIV 11. 2003Y 0 8 2003 Ala130il&GisConac AIasKe0i1 I P. - ` C r Anchorage _04/68/2003 16:30 FAX 907 258 8601 FOREST OIL ALASKA Cj 002 • 411 _ .. ,._...., MEMORANDUM State of Make Meeks OR sad Ram Coasenratlon Commission TO: Sarah Pair DATE: April 01, 2003 Chair SUBJECT: Mechanical nic al IntEtgrity Tests TMRU: Tom Mustier Farad Oil P.I. Supervisor KuNabt Field f1 FROM: 263-153 153 NON. ZaililitineL Packer II , Pretest Mel 15 Nil. 30 Mu. T.V.D. 8280 I=1 200 300 440 440 Wow/ 0 P.TD. r , M , • test NM ETM 1800 =I 160o 180o 1800 PJF Ira Nob= Weil T, : 1 ;. T.V.D. 17":71.11 P.T.D. -E eTed .. ___ IMO PP N Nom "`' - ETM _- T.V.D. T .. - . Irlewot P.T.D_ T,.: tea = � 7�� PIF IIIIII NOM: Wed T T.V.D. T hiervd P.T.D. I _ T r- PIF Sebes: T , . T.V.D. T tslsrvsl R.T.D. Tits . Test pal Casks - P/F Noble: No INA. Reid Cedes Type Test Interval F = FRESH WAIER eW. U- Annulus Moneadna tab Isetat Test 0 = GAS NJ. P. Standard Proems Test 4= FeurYest Code 11 WATER IMj. Rs Mimi Radisarsve Tracer Sumer IP Requbsd W Swims - N • NOT Its3ECT Aa Temperadne An Iy Sway W+ Test Owing Wc*ovar a Dot Ti enpaudre Ted 0= Osier (deeaaLe m notes) T.el'. Wails M.LT.'S performs& 1 Nwrlber of Figures! I Taw Time during teas: jyam A8a CM NIT report torn K X111003 5112100 LG. MIT ushaan . 04/0i/2003 16:30 FAX 907 258 8601 FOREST OIL ALASKA g1003 0 0 _ AOGCC Confidential •_,. `' Page 1 BPY Nod props 143111tarlt Test 0.00 0 09:10 Pined Ted 0.50 300fl Fomselloe axis Down O moor's; 01 B ear 5 Me pumped. igi6sl injection test 1 BPM = 2120 Psi. 1.00 2850 End attest 6 $PMI = 3850 Pet 2.00 3150 Tatty Bartels Pumped: az 3.00 3275 low Sterf in prweteer 2540 P. 4.00 3520 Fon wad is 2170 Pails 30 Mutes :670 Pa alNsnenos. 5.00 3850 Bed a iwels r back to 0 Psi. Infection Stop Test 4°112003 ' 4500 3500 - _ }_, i ..._Ili . 1 _ -r i f I � ■. IIIi 1 i - 1 . 1 2 5 _ . r ___6. .._.4._ .. • �llIl _ _ ! -- t ---1- loon- . .i_ ._ a 1 , ; - ' ...,. _ i _. • 1500 I 11 104 - ' , ' — -- - 500 '4 --H ; t 1 I I - Hi -- ; . I i • 1 - 0.00 ? 1.00 2.00 3.00 4.00 5.00 5.00 um to • • • • • 411/2003 • • O R f s F O R E S T O I L C O R P O R A T I O N 0 � ,�' /0 C?X- CYty - ee/ • C u � 700 � CD9f. ne4 4 -aye, C? 7a4 9950/ O 1. (907 ?.58 -8600 • (907) 258 -86'0/ (4a March 4, 2003 Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue Suite 100 Anchorage, Alaska 99501 Attn: Mr. Tom Maunder Re: Kustatan Field #1 — Class II Completion Mr. Maunder, Forest Oil ceased operations on this well in December 2000. At that time, the well was bundle tested to 3,000 psi and a master valve was installed on the wellhead. At this time we submit Application for Sundry Approvals to re -enter Kustatan Field #1 and complete the well as a Class II disposal well. A separate Application for Injection Order has been submitted for this operation. This work is planned to commence in late March. If there are any questions, please contact me at 907 - 258 -8600. Paul D. White Drilling Manager — Alaska Division Forest Oil Corporation Attachments: 10-403 Application for Sundry Approvals Plat Map — Showing KF #1 Outline Summary Original Completion — December 2000 Proposed KF #1 Completion KF #1 Wellhead and BOP configuration Date Modified: 3/4/03 Date Prepared: 2/12/02 rds M:\Kustatan Field\KF #1 Disposal KF #1 Disposal Cover 403.doc 1 STATE OF ALASKA III A. ,.7,-*„... ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS � l►l,o !'.5' 1. Type of Request: Abandon: Suspend: _ Operation shutdown: Re -enter suspended well: Alter casing: _ Repair well: _ Plugging: _ Time extension: _ Stimulate: _ Change approved program: Pull tubing: Variance: Perforate: Other: X 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Forest Oil Corporation Development: _ 260' MSL 3. Address Exploratory: _ 7. Unit or Property name 310 K Street, Suite 700 Stratigraphic: _ N/A Anchorage, Alaska 99501 Service: X 4. Location of well at surface ✓ J 8. Well number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM Kustatan Field #1 At top of productive interval 9. Permit number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 200 -153 At effective depth 10. API number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 50- 133 - 20496 -00 V At total depth 11. Field /Pool 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM N/A 12. Present well condition summary Total depth: measured • 12,300' V Plugs (measured) true vertical 12,300' f Effective depth: measured 12,259' Junk (measured) true vertical 12,259' Casing Length Size Cemented Measured depth True vertical depth Structural N/A N/A N/A N/A N/A Conductor 120' 20" Driven 120' 120' Surface 1,820' 13 3/8" Surface 1,820' 1,820' Intermediate 6,500' 9 5/8" TOC 5,000' 6,500' 6,500' Production (Liner) Liner 5,988' 7 5 /8" 706 cu ft 12,300' 12,300' Perforation depth: measured true vertical Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) 13. Attachements Description summary of proposal: X Detailed operations program: BOP sketch: X 14. Estimated date for commencing operation 15. Status of well classification as: 20- Mar -03 16. If proposal well verbally approved: Oil: _ Gas: _ Suspended: Name of approver Date approved Service: Class II Disposal 17. I hereby certify t t t foregoing is true and correct to the best of my knowledge. Signed: 4.f\-)Q. Title: Drilling Manager, Forest Oil Corporation Date: 3 I° 4 6 3 FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representatiye may witness 3000 1c3°;% COQ e�-.\- Approval No. Plug integrity BOP Test X Location clearance 303'G7io Mechanical Integrity Test )(_ Subsequent form required 10- ce_d"\rc�� Qv ( LU S-k \ix_ C cov;\ \6 c1v-as IA \ -kc t`jcL 1 Qpcin c - 1 010 (3 /v AE.c7 r,NY-A b Q n��D , : pp 4—'4/3 ` -4%./C - � roved order of the Commi ssioner Commissioner Date 3/470 Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE n9 S BFL •°- . „ 1 • I 1 1 1 1 19 20 21 f 22 1 23 24 19 1 20 1 21 1 i s , Faretand f Foreland q h St 1 I __ 1 - r r - - - -- 1 eland C1► Si t 1-A 1 30 1 29 28 27 26 25 30 II 29 } 28 I I I I I -- t 1 t - - - --T r r — -- -- T r 1 — I I 1 1 1 31 1 32 33 3• 35 1 36 31 1 32 } 33 1 1 I 1 I 1 r — • t f {{ f i f 1 1 1 i i 7 1 1 1 1 1 1 1 1 1 1 1 1 1 1 / 1 1 1 1 1 1 1 1 1 ' 1 a Moil? hour R 111 L — 6 I i '' I 4 3 1 2 1 6 1 5 4 1 +KUS A TAN `4ELD # 1 1 1 .---- 1- --- - -I--- -- - - -- I -1 r 1 1 1 7 8 9 1 11 12 7 1 8 9 1 1 1 1 - - - --r— r - -- — — — — —- - - -r -- I 16 17 16 15 14 RU 0/ — 1.3 18 1 1 17 16 iii 1 1 • U - ' ' _ fid6Nan 19 20 21 22 23 '4 RU 2 it 20 21 5 1 -- r r--- ---7-1- U — I r `r+ R 1 R_ . , , Sit St 220614 t I 30 29 28 27 26 25 30 } 29 28 - -- I—� - - II 6 1 I 1 1 1 32 33 34 1 35 1 36 31 1 32 33 I 1 Term e« 1 « I , ,St 36466 1 I 1 I I 1:78400 FORES OIL COR KILOMETERS � KILOMETERS KUSTRTRN FIELD #1 1 2 STATUTE MILES PROPOSED STATUTE MILES 0 CLASS II DISPOSAL • • FOREST OIL CORPORATION 0 E Kustatan Field #1 - Workover Scope of Work - Class II Disposal Completion o - Scope of Work: 1.) Move in and rig -up service rig. 2.) N/D production tree. The tree currently has an 11"5M x 3 1/8" 5M bonnet and (1) 3 1/8" master valve. No tubing hanger was installed. 3.) NM 11" 5 ' # 01 Tt 3O2 ¥c, - So X-) VS k 4.) Make 9 5/8" scraper run on 2 7/8" tubing, displace water base mud w/ 8.8 ppg (9 %) KCL. Note: the well is currently full of 9.6 ppg water base mud. 5.) Run USLT login 9 5/8" from 5,000 ft to 6,600 ft `-`-O L_ \ S ( 3 \ a 6.) Perforate from 6,750 if to 6,800 ft 7.) Run 9 5/8" Baker model SC retrievable hydraulic packer to 6,280 if on 2 7/8" tubing. Tubing is 2 7/8" 6.5 #, L -80 EUE with TK -2 plastic coating. The packer will be set by dropping a 1 3 /" brass ball and pressuring up to 3,000 psi. The ball can be blown from the ball seat with 3,800 psi. 8.) N /D11 "5MBOPE 9.) N/U injection tree. 11" x 2 9/16" bonnet, (2) 2 9/16" valves, cross, tree cap, and 2 1/16" wing valve. 10.) Perform Step -rate injection test upon approval from AOGCC. "k'c- N4. CC9.<>\°N v.nN \ ^MSS -\occ ���sSV1 T'CS , c) f" N® i - may C lN� S ti Page 1 of 1 03/04/03 Kustatan Fio #1 - Dec. 2000 • 20" K -55 133# Welded 120' MD 13 3/8" L -80 68# BTC 1,820' MD ti Top of 7 5/8" Liner @ 6,312' MD 4 9 5/8" L -80 47# BTC 6,500' MD 7 5/8" L -80 29.7# STL / FL4S 12,300' MD Kustatan Fi1 - Completed • II r l , * n. 20" K -55 1 133# Welded 120' MD 2 718" 6.4# L -80 EUE w/ TK. 2 Coating , ,. '14) -,k 1 13 3/8" L -80 1 1 68# BTC 1,820' MD I it 6,278' Model "K" Anchor i 1 6,280' Baker SC2 -PAH Retr.Pkr f'.r : i l 5\--.9 5\--.9 � \� 3° -��� ` � l I t 1.Z C\Q_ C-- V nO S_C-23.,\ 5 6,288' 10' pup 2 7/8" 1 I Top of 7 5/8" Liner @ 6,312' MD 6,298' XN Nipple P 6,300' 1 jt 2 7/8" N ,1 6,332' WEG - ! I ! '. 9 5/8" L -80 H 47# BTC 6,500' MD 6,750' to Perforations 6,800' 7 5/8" L -80 29.7# STL / FL4S 12,300' MD 41) Kustatan Field #1 -- BOP Layout 10/ '01 ms u. a. mM1u. 11 " x 5M Annular BOP 11" x 5M Gate (blinds) = Birk 11" x 5M Gate (pipe) r s, �► 135/8" 5M x11 " 5M Tubing Head an is , 13 3/8" Slip -on x 13 5/8" 3M Casing Head "I MI' 11" 5M x 11" 5M Mud Cross w/ two 4" 5M outlets - -- Choke side: 4" 5M manual, 4" 5M HCR, 4" 5M x 3 1/8" 5M DSA Kill side: 4" 5M x 2 1/16" 5M DSA, 2 1/16" 5M manual, 2 1/16" 5M manual, 2 1/16" 5M check a00-/ forest Oil Corporation Alaska Division 310 K Street, Suite 700 Anchorage, Alaska 99501 Phone: (907) 258 -8600 Fax: (907) 258 -8601 DATA TRANSMITTAL Date: March 3 2003 To: Bob Crandall From: Art Saltmarsh AOGCC Forest Oil Corporation 333 W. 7th Ave, Suite 100 310 K Street, Suite 700 Anchorage, AK 99501 Anchorage, AK 99501 Phone: (907) 279 -1433 Phone: (907) 868 - 2141 FAX: (907) 258 - 8601 TRANSMITTAL DESCRIPTION: Osprey Platform Location 1 CD Kustatan Field #1, 50- 733 - 20496 -00, 2 log curve files, LAS format I I Please sign below to acknowledge recei Received By: Date: Y/3/eo Pagel Date Modified:03 /03/2003 Date Prepared: 12/6/00, bk Kustatan Conversion • Subject: Kustatan Conversion Date: Mon, 28 Oct 2002 13:55:28 -0900 From: Tom Maunder <tom_maunder @admin.state.ak.us> To: Rob Stinson <RDStinson @forestoil.com >, Paul White <pdwhite @forestoil.com> Rob and Paul, I was looking at your proposal for the conversion of Kustatan #1 and had a couple of points. 1. Based on where you propose to perforate, there is a lot of casing rathole open below. Do you have any plan to install a retainer closer to the perforations to "shallow" up PBTD ?? 2. If the well is completed as you propose, will the 2 -7/8" tubing allow you to install an inflatable BP in the 7 -5/8" casing if needed ?? 3. You propose to run a USIT log in the 9 -5/8" casing above the liner. What about the 7 -5/8" liner from below the proposed perforations to the 9 -5/8" shoe ?? Thanks in advance for your looking at these issues. Tom Maunder Tom Maunder <tom maunderna,admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission CON-N-1 ®A 3 \ \-1 O - v k 7V\ -- CN.C9 L \ C \\ < cc� Ste\ k \ 6 Mc \11'k 1 of 1 12/23/2002 2:22 PM . o 4 MECHANICAL INTEGRITY REPORT ( 0 0.,.. 1S T, BUD DATZ : ( 9R0 - OPER & FIELD oc 1��5' h - :. REL S. . 1 (1 '. ;aLL NUMBER ILUS - c_A- 0.u� . r LL DATA TD 1x300 .1•fD.. \a30V TVD ; = BTD : MD TVD Casing: S Shoe: (5jj MD v TvD; DV: 't 1D Q TVD liner : 1 15k Shoe: \a30k) MD Q300 TVD ; TOP : (5 \) HD (3x).. TVD Tubing.: cr(f Packer TVD; Set at Hole Size and ; Perfs (0 to (4S CHANT CAL INTEGRITY - PART 1 Annulus Press Test: IP (( ; 15 rain \b() ; 30 min 1(000 . comments : 1�c3.ssEC� .-4- - 0 3 ct � -\. 9 P *'CR NICAI, INTEGRITY - PART #2 15.` Cement Volumes: Amt. Liner ; Csg ,)0( ; DV . Cmt vol to cover perfs Scp `'- I O� XS , ti , o.S �e rc Sc CZ M Job c s,, \,c o., z� ,,,.. ..` ,,,,v_9_, , _ :eoretical TOC Cement Bond Log (Yes or No) YeS ; In AOGCC File • \ CBL Evaluation, zone above t�to� \s cep c szvq 1Vet , '\ sct. .(tr t �,. Proau tion Log: Type ; Evaluation 3 . CONCLUSIONS : ` (� ;) 1)1/ Part 11: ' o. servo y( l '� cia.t..rpr\-- Cot.c.N`l c w / -0A a. 1`'IS Z S V \\ra \I c uss ?art r 2 • Att s,, • S b. It..) 1 • *If1-1/g-0 0 • . o R E s F O R E S T O I L C O R P O R A T I O N 1 �b .310 7 CCU �a�.et • .'t7 700 CD nc o aaye, C a..sl a ,99,501 (907) ,258 -8600 • (90) 758 -860; (max) September 27, 2002 Alaska OiI and Gas Conservation Commission 333 W. 7th Avenue Suite 100 Anchorage, Alaska 99501 Attn: Mr. Tom Maunder Re: Kustatan Field #1 — Class II Completion Mr. Maunder Forest Oil ceased operations on this well in December 2000. At that time, the well was bundle tested to 3,000 psi and a master valve was installed on the wellhead. At this time we submit Application for Sundry Approvals to re -enter Kustatan Field #1 and complete the well as a Class II disposal well. A separate Application for Injection Order will be submitted for this operation. This work will follow the final abandonment of WMRU #D1, expected to be in May 2003. If there are any questions, please contact me at 907 - 258 -8600. D \ \ Vvv-/ Paul D. White Drilling Manager — Alaska Division Forest OiI Corporation RECEIVED SEP 30 2002 Alaska 0i1 & Gas Cons. Commission Anchorage Date Modified: 9/27/02 Date Prepared: 2/12/02 rds M:\Kustatan Field\KF #1 Disposal\KF #1 Disposal Cover 403.doc I, STATE OF ALASKA Airy/ wr ALASKA RAND GAS CONSERVATION GOMMISSION ,, ova-4 , - APPLICATION FOR SUNDRY APPROVALS !) is )2./z 1. Type of Request: Abandon: _ Suspend: — Operation shutdown: Re -enter suspended well: Alter casing: _ Repair well: _ Plugging: _ Time extension: _ Stimulate: _ Change approved program: Pull tubing: Variance: Perforate: Other: X 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Forest Oil Corporation Development: _ 260' MSL 3. Address Exploratory: _ 7. Unit or Property name 310 K Street, Suite 700 Stratigraphic: _ N/A Anchorage, Alaska 99501 Service: X 4. Location of well at surface 8. Well number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM Kustatan Field #1 At top of productive interval 9. Permit number 3443' FNL, 1468' FWL, Sec. 4, 17N, R14W, SM 200 -153 At effective depth 10. API number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 50- 133 - 20496 -00 At total depth 11. Field /Pool 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM N/A 12. Present well condition summary Total depth: measured 12,300' Plugs (measured) true vertical 12,300' Effective depth: measured 12,259' Junk (measured) true vertical 12,259' Casing Length Size Cemented Measured depth True vertical depth Structural N/A N/A N/A N/A N/A Conductor 120' 20" Driven 120' 120' Surface 1,820' 133/8" Surface 1,820' 1,820' Intermediate 6,500' 9 5/8" TOC 5,000' 6,500' 6,500' Production (Liner) Liner 5,988' 7 5/8" 706 cu ft 12,300' 12,300' Perforation depth: measured true vertical RECEIVED Tubing (size, grade, and measured depth) SEP 30 2002 Packers and SSSV (type and measured depth) AIrl<aka Oil & «aa Cons, COmmi8SiOr 13. Attachements Description summary of proposal: X Detailed operations program: AINIewl‘killh: X 14. Estimated date for commencing operation 15. Status of well classification as: 01- May -03 16. If proposal well verbally approved: Oil: _ Gas: _ Suspended: Name of ap er Date approved Service: Class II Disposal 17. I hereby c rtify t at the foregoing is true and correct to the best of my knowledge. Signed: i v% �fW' — '� Title: Drilling Manager, Forest Oil Corporation Date: ' 0 a 9 FOR COMMISSION USE ONLY , t Conditions of approval: Notify Commission so representafve may witness Approval No. Plug integrity BOP Test Location clearance 'a �,-- . Mechanical Integrity Test 1, Subsequent form required 10- 91) C 'l et"Vyvco\k toc©t '_ 5 /cc" �� _ v‘ \- .�� \v \ t- (--\ c c)- Vc?: � cx\ ' \O - �'�� - /3 P.\ INk ■) \■ > >uC - ORIGINAL SIGNED BY I Prrr Approved by order of the Commissioner M L_ Bill Commissioner Date Form 10-403 Rev 06/15/88 SUBMIT IN TRIP 'BOMS BFL 1 . 0 0 r Kustatan Field #1 Class II Disposal Completion RKB 260' MSL IN AI eT4, x 2 7/8" 6.5# L -80 EUE w/ TK -2 Plastic Coating 'f Vi 0 ArCe. r4 20" 133 #,L -80 BTC 120' Driven ' ' e. itrl t p., 64 13 3/8" 68 #, L -80 BTC I li-' 1820' 17 1/2" Hole r '- TOC 5000' (Calculated) A a `` �� *= Baker Packer Model SC Retrievable 6280' 15 ot — TOL 6312' t i 'l 9 5/8" 47 #, L -80 BTC 6500' 12 1/4" Hole Perforations 6,750' to 6,800' V + . 7 -5/8" 29.7 #, L-80 STL / FL4S yiy Liner Wiper Plug 12259' 81/2 "Hole •i' ++.;, • 44:4._ . 12300' • • FOREST OIL CORPORATION Kustatan Field #1 - Workover irk Scope of Work — Class I1 Disposal Completion Scope of Work: 1.) Move in and rig -up Aurora rig. 2.) N/D production tree. The tree currently has an 11 "5M x 3 1/8" 5M bonnet and (1) 3 1/8" master valve. No tubing hanger was installed. 3.) N/U 11" 5M BOPE on 11" 5M tubing head 4.) Make scraper run to clean out 7 5/8" to 7,000 ft, displace water base mud w/ 3% KCL. Note, the well currently has no perforations, is full of 9.6 ppg water base mud and was bundle tested to 3,000 psi. r 5.) Run USIT log in 9 5/8" from 5,000 ft to 6,312 ft zr -' 15 �v� 'ZC7O0 6.) Perforate from 6,750 ft to 6,800 ft 7.) Run 9 5/8" Baker model SC retrievable hydraulic packer hydraulically to 6,280 ft on 2 7/8" completion. Tubing is 2 7/8" 6.5 #, L -80 EUE with TK -2 plastic coating. 8.) N/D 11" 5M BOPE 9.) N/U injection tree. 11" x 2 9/16" bonnet, (2) 2 9/16" valves, cross, tree cap, and 2 1/16" wing valve. 10.) Perform Step -rate injection test upon approval from AOGCC. Page 1 of 1 09/27/02 Kustatan Field #1- 200-153 4 1/ 11 Subject: Kustatan Field #1 - -200 -153 Date: Tue, 17 Sep 2002 16:26:58 -0800 From: Tom Maunder <tom ma nder a min.state.ak.us> Fr o o un de u d To: Paul White < P dwhite forestoiLcom >, Rob Stinson <RDStinson @forestoil.com> CC: Cammy Oechsli < Cammy _Oechsli ©admin.state.ak.us >, Daniel T Seamount JR < dan_seamount@admin.state.ak.us> Paul and Rob, A sundry application was filed in early September requesting to continue the operations SD on the subject well. You have indicated intentions to complete as a Class 11 disposal well "at a future date ". This note requests some further information to justify your request. 20 AAC 25.072 provides that an operational SD is limited to 12 months unless the operator shows that operational circumstances beyond the operator's control prevent resumption of operations. Your attention to this request will be appreciated. Tom Maunder, PE AOGCC Tom Maunder <tom maundercr.admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 of 1 9/17/2002 4:27 PM 111! • o R F S FOREST O I L C O R P O R A T I O N i9 �b ,3i0 CDX�CY /xe.( • C6crte 700 o i C� a4-a 9950/ (907) 958 -8600 • (:907) ?58 -8609 (C,�r) September 4, 2002 Alaska Oil and Gas Conservation Commission 333 West 7 Avenue Suite 100 Anchorage, Alaska 99501 Attn: Mr. Tom Maunder Re: Kustatan Field #1 — Operation Shutdown Mr. Maunder, We request to continue our Operations Shutdown on the Kustatan Field #1 well. Our intentions are to complete this well at a future date as a Class II disposal well to support the Kustatan Production facility. This facility is located on the same gravel pad as the well. The well was bundle tested to 3,000 psi in December of 2000. If there are any questions, please contact me at 907 - 258 -8600. Q \ C ‘ dti 4 VC:: 7 Paul D. White Drilling Manager — Alaska Division Forest Oil Corporation Date Modified: 9/4/02 Date Prepared: 9/4/02 rds M:\Kustatan Field\Stoppage 403 - 2002.doc n ? A L f II 0 STATE OF ALASKA OL55 ALASKA OIL AND GAS CONSERVATION COMMISSION ` APPLICATION FOR SUNDRY APPROVALS i �/ c 1. Type of Request: Abandon: Suspend: _ Operation shutdown: X Re -enter suspended well: _ Alter casing: _ Repair well: _ Plugging: _ Time extension: _ Stimulate: Change approved program: Pull tubing: Variance: Perforate: Other: 2. Name of Operator 5. Type of well 6. Datum elevation (DF or KB) Forest Oil Corporation Development: _ 260' MSL 3. Address Exploratory: X 7. Unit or Property name 310 K Street, Suite 700 Stratigraphic: N/A Anchorage, Alaska 99501 Service: 4. Location of well at surface f f J 8. Well number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM Kustatan Field #1 At top of productive interval 9. Permit number/ 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 200 -153 '/ I At effective depth 10. API number / 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 50 -133- 20496 -00 v At total depth 11. Field /Pool 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM N/A 12. Present well condition summary Total depth: measured 12,300' Plugs (measured) true vertical 12,300' Effective depth: measured 12,300' Junk (measured) true vertical 12,300' Casing Length Size Cemented Measured depth True vertical depth Structural N/A N/A N/A N/A N/A Conductor 120' 20" Driven 120' 120' Surface 1,820' 13 3/8" Surface 1,820' 1,820' Intermediate 6,500' 9 5/8" TOC 5,000' 6,500' 6,500' Production (Liner) Liner Perforation depth: measured true vertical Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) 13. Attachements Description summary of proposal: X Detailed operations program: _ BOP sketch: — 14. Estimated date for commencing operation 15. Status of well classification as: 10- Sep -02 16. If proposal well verbally approved: Oil: X Gas: _ Suspended: Name of approver Date approved Service: 17. I hereby c rti that the foregoing is true and correct to the best of my knowledge. Signed: Title: Drilling Manager, Forest Oil Corporation Date: 9 / 4 O Z" FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Approval No. Plug integrity BOP Test Location clearance , 302.- 2 g-I--A Mechanical Integrity Test Subsequent form required 10- `i� -V C.0h N‘Qt J ORIGINAL SIGNED BY r Approved by order of the Commissioner M L- Bill Commissioner Date 2q Form 10-403 Rev O6 /15/88 SUBMIT IN TRIPL'ICAT RRflMS BFL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown X Stimulate Plugging _ Perforate Pull Tubing Alter casing Repair well Other 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Forest Oil Corporation Development: 260' MSL 3. Address Exploratory: X 7. Unit or Property name 310 K Street, Suite 700 Stratigraphic: N/A Anchorage, Alaska 99501 Service: 4. Location of well at surface 8. Well number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM Kustatan Field #1 At top of productive interval 9. Permit number / approval number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 200 -153 At effective depth 10. API number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 50- 133 - 20496 -00 At total depth 11. Field /Pool 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM N/A 12. Present well condition summary Total depth: measured 12,300' Plugs (measured) true vertical 12,300' Effective depth: measured 12,259' Junk (measured) true vertical 12,259' Casing Length Size Cemented Measured depth True vertical depth Structural _ N/A N/A N/A N/A N/A Conductor 120' 20" Driven 120' 120' Surface 1,820' 13 3/8" 1478 cu ft 1,820' 1,820' Intermediate 6,500' 9 5/8" 644 cu ft 6,500' 6,500' Production (Liner) Liner 5,988' 7 5/8" 706 cu ft 12,300' 12,300' Perforation depth: measured true vertical R E C 8 E D Tubing (size, grade, and measured depth) FEB 2 0 2001 Packers and SSSV (type and measured depth) Alaska Oil & Gas Cons. Commissior Archorage 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure 14. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation Subsequent to operation 15. Attachments 16. Status of well classsification as: Copies of Logs and Surveys run Oil _ Gas _ Suspended Service Daily Report of Well Operations Submitted with 10-401 17. I hereby rtify t' -t the foregoing is true and correct to the best of my knowledge. Signed: \ 11 V I.— Title: Drilling Manager, Forest Oil Corporation Date: Z d Form 10-404 rev 06/15/88 SUBMI IN D PLI E ORIGINAL • 0 FOREST OIL COR Page 1 of 15 Operations Surnmary ;Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code Code Phase Description of Operations 10/12/2000 19:00 - 01 A MIRU Rigging up 10/13/2000 06:00 - 12:00 6.00 01 A MIRU Rigging up 12:00 - 06:00 18.00 01 A MIRU Rigging up 10/14/2000 06:00 - 12:00 , 6.00 01 A MIRU Hook up electric to top drive. Rig degasser lines. 12:00 - 00:00 12.00 01 A MIRU PJSM Rig up sub section flow line. Pull out centrifuge. Rig up stabbing board. Rig up V- doors. Help welder run 3" mud line for trip tank. Fill suction pit with water. Plumb in cellar tugger. Hook up fill -up line. Silicon cracks in pump room floor.Start berm around rig. put packing in test pump. 00:00 - 06:00 6.00 01 A MIRU Continue to rig up. 10/15/2000 06:00 - 12:00 6.00 01 A MIRU Welder working on mud line. Put blower motor on top drive. Put bails on top drive. Test electricity on top drive.Berm around rig. Rig down rig.Fill I pits with water. Welding braden head to 20" conductor. Hook up monitors and cameras. Rig up wireline machine. 12:00 - 12:30 0.50 01 A MIRU PJSM Rig up remote accumulator line. 12:30 - 18:00 5.50 01 A MIRU Welding braden head on 20" casing. 18:00 - 21:00 3.00 01 A MIRU Allow weld on head to cool. Prep equipment for nipple up, while mixing spud mud. 21:00 - 00:00 3.00 14 A MIRU Nipple up 20" diverter. 00:00 - 06:00 6.00 14 A MIRU Nipple up diverter line from cellar. Make up drilling nipple, flow line, hydraulic lines,and knife valve. 10/16/2000 06:00 - 12:00 6.00 14 A MIRU Making up driling nipple and flow line. Mixing mud. Test Hydril diverter and Knife valve. for AAOGCC test. Also Koomey test. Test OK. Roll mud pumps. Check alarms. H2S and methane gas calibrated. 12:00 - 18:00 6.00 14 A MIRU Nipple up flow nipple, flow line and fill up line. 18:00 - 20:00 2.00 25 MIRU Reading tools for spud in. 20:00 - 00:00 4.00 01 A MIRU Welder repairing slop tank. Dig trench for dump truck to haul cuttings. Lay liner and mats in trench. 00:00 - 03:00 , 3.00 01 A MIRU PJSM Pre -spud check list. 03:00 - 05:00 2.00 06 J DRLSUR Make up BHA. Tag @ 51'. Circ. check allmlines for leaks. 05:00 - 06:00 1.00 02 A DRLSUR Drilling from 51' to 65'. 10/17/2000 06:00 - 08:30 2.50 02 A DRLSUR drilling surface hole. 08:30 - 09:00 0.50 05 I DRLSUR Circulate 09:00 - 09:30 0.50 06 J DRLSUR POOH to pick up ' HWDP, 5" DP DCS, and jars. 09:30 - 16:00 6.50 26 DRLSUR Pick up 5 "DP, 5 "HWDP, and stand back in derrick. Pick up jars and stab. 16:00 - 16:30 0.50 06 J DRLSUR RIH 16:30 - 18:00 1.50 02 A DRLSUR Drilling from 96' to 208'. 18:00 - 19:00 ; 1.00 08 E DRLSUR Work on top drive. 19:00 - 23:00 4.00 26 DRLSUR Pick up stab. and three DCs. 23:00 - 00:00 1.00 02 A DRLSUR Drilling from 208' to 218'. 100:00 - 00:30 0.50 05 I DRLSUR Circ. while waiting on dump truck. 00:30 - 04:00 3.50 02 A DRLSUR Drilling from 218' to 294'. 04:00 - 04:30 0.50 05 I i Circ. hole clean. RECEIVED 04:30 - 05:00 0.50111 F DRLSUR Wirelie survey @ 290'. 05:00 - 06:00 1.00 02 A DRLSUR Drlg. from 290' to 315' 10/18/2000 06:00 - 16:30 10.50 02 A DRLSUR Drilling 17 1/2" surface hole. PJSM 16:30 - 17:00 0.50 10 A DRLSUR Wireline survey. 1/2 deg. inc. FEB 2 2 2001 17:00 - 05:30 12.50 02 A DRLSUR Drilling surface hole. 05:30 - 06:00 0.50 05 I DRLSUR Circulate for wireline survey. 10/19/2000 06:00 - 06:30 0.50 10 A DRLSUR Wireline Inc. survey Alaska Oil & Gas Cons. Commission 06:30 09:00 2.50 02 A DRLSUR Drilling 17 1/2" surface hole. Anchorage 09:00 - 09:30 0.50 05 I DRLSUR Ciculate, pump pill. Printed: 2/22/2001 2:56:23 PM 0 FOREST OIL CORP. Page 2 of 15 Operations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code Core Phase Description of Operations 10/19/2000 09:30 - 11:00 1.50106 A DRLSUR 1 POOH, break bit off. 11:00 - 12:00 1.00 06 J DRLSUR Make up bit, run in holewith collars, service top drive. 12:00 - 13:00 1.00 08 E DRLSUR Work on top drive. 13:00 - 14:30 1.50 06 I J DRLSUR Pick up three DCs. 14:30 - 16:00 1.50 07 1 DRLSUR Cut drlg. line. 16:00 - 17:00 1.00 06 IA DRLSUR RIH 17:00 - 17:30 0.50 25 DRLSUR Circulate, orient Epoch. 117:30 -22:30 5.00 02 ,A DRLSUR Drilling 171/2 "hole. 1 22:30 - 23:00 0.50 05 1 DRLSUR Circulate B /U. 23:00 - 23:30 0.50 10 A DRLSUR Wireline Inc. survey. 23:30 - 06:00 6.50 02 A DRLSUR Drilling 17 1/2" surface hole. 10/20/2000 106:00 - 10:30 4.50 02 IA DRLSUR Drilling surface hole 10:30 - 11:00 0.50 11 1A DRLSUR Run totco angle unit on wireline. 11:00 - 11:30 0.50 05 I DRLSUR CBU 11:30 - 14:30 i 3.00 06 DRLSUR Trip to stabilizers 14:30 - 15:00 0.50 07 DRLSUR Clean rig floor 15:00 - 16:30 1.50 06 DRLSUR Trip in hole 16:30 - 17:00 0.50 02 A DRLSUR Drill to fit casing 117:00 - 18:30 1.50 05 F DRLSUR Circulate hole clean 18:30 - 19:30 1.00 11 I DRLSUR Wireline survey 19:30 - 20:00 0.50 05 I DRLSUR Pump dry job 20:00 - 00:00 4.00 06 ' G 1 DRLSUR Trip out to run casing 00:00 - 01:00 1.00 06 1 DRLSUR Break off bit, bit sub, stand back collars 1 01:00 - 02:30 1.50 12 DRLSUR Pick up casing equipment 02:30 - 03:00 0.50 12 1 DRLSUR Safety pre job meeting. 03:00 - 04:00 1.00 12 DRLSUR Rig up to run 13 3/8" casing. 04:00 - 06:00 2.00112 DRLSUR Running casing 10/21/2000 06:00 - 10:30 4.50 12 I RUN CASING 10:30 - 12:00 1.50 12 RETRIEVE CASING BACK TO SURFACE, AND CUT OFF TWO 1 CENTRALIZERS. 12:00 - 13:30 1.50 12 CHANGE OUT BAILS 13:30 - 22:30 I 9.00 12 I RUN CASING 22:30 - 00:00 1.50 12 RIG DOWN CIRULATING HOSE, PULL MASTER BUSHING TO CUT CASING. 00:00 - 03:00 3.00 12 CUT LANDING JOINT 4 INCHES BELOW DRILLING NIPPLE 03:00 - 04:30 1.50 12 I TRIP IN THE OUT OF DERRICK, AND PICK UP 7 JOINTS OF 5" 1 DRILL PIPE 104:30 - 05:00 0.50 12 SAFETY MEETING WHILE CIRCULATING 05:00 - 05:30 0.50 12 CIRCULATE 105:30 - 06:00 0.50 12 I PRESSURE TEST LINES, BEGIN PUMPING 50 BBLS SPACER 1 10/22/2000 06:00 - 06:30 I 0.50112 IC I TEST LINES TO 1500, PUMP WATER 06:30 -08:00 1.50112 iC CEMENT JOB 08:00 - 12:00 4.00 A PULL ONE STAND, PUMP DOWN DRILL PIPE WIPER PLUG, RIG DOWN DIVERTER. 112:00 - 12:30 1 0.50 14 IA REMOVE DIVERTER KNIFE 12 :30 - 14:30 1 2.00 12 ID RIG DOWN CEMENT CIRCULATING HOSE AND HEAD- MAKE UP 1 I TOP DRIVE SAVER SUB 14:30 - 16:00 1.50 06 1G TRIP OUT OF HOLE WITH STING IN ASSEMBLY - LAY DOWN 2 JTS I OF 5 " DP THAT WAS NOT WIPED. 16:00 - 16:30 0.50 PRE JOB SAFTEY MEETING FOR WORKING ON BOP STACK. NIPPLE DOWN/ NIPPLE UP NABORS POLICY 16:30 - 19:30 3.00 14 B RIG DOWN 20" RISER & LAY DOWN 19:30 - 20:30 1.00 14 B RIG UP SLINGS/ PICK UP ANNULAR Printed: 2/22/2001 2:56:23 PM r • i FOREST OIL CORP Page 3 of 15 Operations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: l Rig Name: NABORS DRILLING Rig Number: 160 j Date From - To Hours Code Sub Phase Description of Operations Code 10/22/2000 20:30 - 21:00 0.50 14 B j WELDER MADE ROUGH CUT ON 13 3/8" 21:00 - 22:30 1.50 14 B LAY DOWN CUT OFF SECTION OF 13 3/8" CSG, MOUSE HOLE, V DOOR RAMP 22:30 - 00:00 1.50 14 B WELDER CUT OFF 20 ", MAKE EXPERT CUT ON 13 3/8" FOR SLIP I LOCK SPOOL FROM VETCO. 00:00 - 02:30 I 2.50 14 B GRIND /DRESS OFF CUT ON 13 3/8" 02:30 - 03:30 1.00 14 B INSTALL VETCO GREY SLIP LOCK SPOOL AT GROUND LEVEL/ TEST TO 2000 PSI FOR 15 MINS. 03:30 - 06:00 2.50 14 B INSTALL SPACER SPOOUDOUBLE GATE /MUD CROSS 10/23/2000 06:00 - 12:00 6.00 14 B i CSGSUR NIPPLE UP HYDRIL, DRILL NIPPLE, FLOWLINE, TRIP TANK FLOW LINE 12:00 - 15:00 3.00 14 B CSGSUR INSTALL V DOOR RAMP, MOUSE HOLE 15:00 - 19:30 4.50 07 CSGSUR REPLACE ACTUATOR VALVE AND SAVER SUB ON TOP DRIVE. 19:30 - 00:00 4.50 14 B CSGSUR CHANGE BOTTOM RAMS F/ 2 7/8" TO 5" AND RIG UP TO TEST BOP'S 00:00 - 03:00 3.00 15 A CSGSUR NIPPLE UP CHOKE LINE, FINISH RIGGING UP TO TEST 03:00 - 06:00 3.00 15 A CSGSUR TEST BOP'S 10/24/2000 06:00 - 08:30 2.50 07 DRLIN1 SET WEAR RING 08:30 - 10:30 2.00 07 DRLIN1 I INSTALL DRIP PANS 10:30 - 15:00 4.50 08 DRLIN1 REPLACE ACCTUATOR VALVE ON TOP DRIVE. 15:00 - 18:00 3.00 06 DRLIN1 PRE JOB SAFETY MEETING, MAKE UP BHA #3 18:00 - 20:00 2.00 06 DRLIN1 TRIP TO 852' 20:00 - 22:30 2.50 09 DRLIN1 SLIP AND CUT DRILL LINE. 1 22:30 - 23:30 1.00 15 1 DRLIN1 TEST TIW VALVE, NOTIFY STATE MAN OF PASSED TEST. 123:30 - 00:00 I 0.50 06 DRLIN1 !PICK UP SINGLES, TRIP IN THE HOLE. 00:00 - 02:30 2.50 06 DRLIN1 PICK UP SINGLES, TRIP IN THE HOLE. 02:30 - 04:00 1.50 05 DRLIN1 CIRCULATE OUT CEMENT, FROM 200 GPM TO 450 GPM WHILE SLOWLY ROTATING. SHAKERS LOADED UP. 04:00 - 04:30 0.50 16 1 DRLIN1 PRE JOB MEETING, TEST CASING TO 3000 PSI. 04:30 - 06:00 1.50 02 1 DRLIN1 DRILL COLLAR, CEMENT, AND SHOE. 10/25/2000 06:00 - 09:30 3.50 02 D DRLIN1 Drill cement below float collar 09:30 - 11:00 1.50 02 D DRLIN1 Drill shoe. 11:00 - 11:30 I 0.50 02 A DRLIN1 Drill 20 feet of new hole. 11:30 - 12:00 0.50 05 A DRLIN1 Circulate for FIT. Mud WT in 9.0 ppg / Mud WT out 9.0 ppg ' 12:00 - 12:30 0.50 05 A DRLIN1 Circulate / Prejob safety meeting / Crew change / Explain what to do for FIT. . 12:30 - 13:00 0.50 02 A 1 DRLIN1 Perform FIT. 9.0 PPG mud in hole. EMW =11.0 PPG Held 190 Psi for 5 1 mins. Recorded on chart. 13:00 - 20:00 7.00 02 A DRLIN1 Drilling 20:00 - 20:30 0.50 05 A DRLIN1 'Circulate hole clean for survey. 20:30 - 21:00 0.50 10 A DRLIN1 Angle unit survey with slick line. 21:00 - 00:00 I 3.00 02 A DRLIN1 Drilling 00:00 - 03:00 3.00 02 A DRLIN1 Drilling 1 03:00 - 03:30 0.50 05 A 1 DRLIN1 Circulate hole clean for survey 03:30 - 04:00 0.50 10 A DRLIN1 Angle unit survey with slick line. 04:00 - 06:00 2.00 02 I A DRLIN1 Drilling 10/26/2000 06:00 - 07:00 1.00 02 A DRLIN1 Rotating ahead 07:00 - 08:00 1.00 02 A DRLIN1 Change shaker screens 08:00 - 12:30 4.50 02 A DRLIN1 Rotating ahead 12:30 - 13:30 1.00 05 A DRLIN1 Pump high viscosity sweep around. 13:30 - 14:00 0.50 10 A DRLIN1 Run totco angle unit on slick line. 14:00 - 14:30 0.50 05 A DRLIN1 Record slow pump rates, pump dry job. 14:30 - 18:30 4.00 06 H DRLIN1 Short trip. Printed: 2/22/2001 2:56:23 PM • • FOREST OIL CORP. Page 4of 15 Operations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code Sub Phase Description of Operations Code 10/26/2000 18:30 - 19:30 1.00 06 H DRLINI Service top drive & draw works. 19:30 - 00:00 4.50 06 1 H DRLIN1 'Trip in picking up singles off pipe rack. 00:00 - 06:00 6.00 02 A DRLIN1 Rotating ahead. 10/27/2000 06:00 - 07 :00 1.00 02 A DRLIN1 ‘ Drilling ahead. 07:00 - 08:00 1.00 05 I A DRLIN1 Circulate while changing shaker screens. 08:00 - 09:30 1.50 02 A DRLIN1 Drilling ahead. 09:30 - 10:00 0.50 05 A DRLIN1 Circulate hole clean. 10:00 - 11:00 1.00 10 A DRLIN1 Run slick line unit for totco angle survey. 11:00 - 22:00 11.00 02 'A DRLIN1 Drilling and surveying every 5 stands. 22:00 - 23:00 1.00 05 1A DRLIN1 Circulate for survey, pump high vis sweep. 23:00 - 00:00 1.00 10 I A DRLIN1 Run slick line unit for totco angle survey. 00:00 - 04:00 4.00 02 A DRLIN1 Drilling 04:00 - 05:00 1.00 05 IA DRLINI Circulate, pump dry job. 05:00 - 06:00 1.00 06 J DRLIN1 Trip out of hole for PDC bit and Mud Motor. 10/28/2000 06:00 - 10:00 4.00 06 IA DRLIN1 Tripping 10:00 - 12:00 2.00 06 1J DRLIN1 Change bit and BI-IA 12:00 - 12:30 0.50 07 1 DRLIN1 PJSM Clean rig floor 12:30 - 16:30 4.00 06 J DRLINI Finish w/ BHA change RIH w/ BHA to 860'. 16:30 - 17:30 1.00 07 DRLIN1 Service rig, blocks and top drive. 17:30 - 21:30 4.00 06 1 J DRLIN1 TIH -P /U 5" DP (69 jts.) from pipe rack. Rabbit each jt. Fill pipe at the shoe. 21 :30 - 22:00 0.50 02 IA DRLIN1 Break circ. Drilling from 4265' to 4267' ADT 1/4 hr. 22:00 - 05:00 7.00 08 A DRLIN1 Flow line plugged with excessive clay returns. Attemted to jet flow line i 1 with no luck. RemoveFlow paddle and break apart flow line to clean I same, while working pipe. Remove bushings, drip pan clean drilling nipple flow line and possum belly. Clean and replace. 05:00 - 06:00 1.001 05 I DRLIN1 Circulate slowly to circulate clay from hole. 10 stks. /min.increase circulation as hole cleans up. 10/29/2000 06:00 - 08:00 2.00 , 05 , I DRLIN1 Circulate clay from hole @ 10 to 50 SPM. 08:00 - 18:30 10.50 02 A DRLIN1 Drilling from 4267' to 4607'. 18:30 - 19:30 1.00 05 I DRLIN1 Pump Hi -Vis sweep. CBU for survey. 19:30 - 20:30 1.00 11 r DRLIN1 Wireline survey @ 4509'. 3/4 Deg. 20:30 - 02:00 5.50 02 1 DRLIN1 Drilling from 4607 to 4796'. Set clocks back one hour for DST. 01:00 - 01:30 0.501 07 DRLIN1 1 Sevice top drive. 01:30 - 02:00 1 0.50 02 A DRLIN1 Drilling 12 1/4" hole. 02:00 - 03:00 1.00 02 DRLIN1 Two pump pressure spikes. Pump pressure increased to 3000 PSI., while drilling from 4810' to 4817'. ROP decreased to 6'- 8' /hr. 03:00 - 04:30 1.50 05 1 I DRLIN1 CBU @ 0 strokes due to pump pressure increase. Monitor well. Pump dry job. 04:30 - 06:00 1.50 06 DRLIN1 1 POOH 10/30/2000 06:00 - 08:00 2.00 06 A DRLIN1 Tripping out of hole. 08:00 - 10:00 2.00 06 J DRLIN1 Work BHA. Clean stabilizers. Bit jets plugged with rubber from mud i motor. 10:00 - 10:30 0.50 07 1 1 DRLIN1 Clean rig floor. 10:30 - 11:00 0.50 06 J DRLIN1 1 Lay down motor, x -o sub and float sub. 11:00 - 12:00 1.001 06 J DRLIN1 Dress new bit- Change BHA. 12:00 - 12:30 0.50 07 DRLIN1 PJSM Clean rig floor. 12:30 - 15:00 2.50 06 J DRLIN1 Make up new bit and change BHA. 15:00 - 16:30 1.50 06 DRLIN1 RIH to 1763'. 16:30 - 18:00 1.50 DRLINI Fill pipe and circ. Service rig blocks and top drive. 18:00 - 18:30 0.50 06 DRLIN1 RIH from 1763' to 3078'. 18:30 - 19:30 1.00 05 I DRLIN1 Fill drill pipe and circ. bottoms up. 19:30 - 20:00 0.50 06 DRLIN1 RIH from 3078' to 4817' with no problems. 1 I Printed: 2/22/2001 2:56:23 PM • 0 1 FOREST OIL CORP Page 5' of 15 Operations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code 5ab de Phase Description of Operations 10/30/2000 20:00 - 02:30 6.50 02 A DRLIN1 , Drilling 12 1/4" hole. 02:30 - 03:00 0.50 05 DRLIN1 Circ. Hi -Vis sweep. PJSM 03:00 - 04:00 1.00 11 DRLIN1 Survey ©5006'. 1/2 deg. I 04:00 - 06:00 1 2.00 02 A I DRLIN1 Drilling 12 1/4" hole. 10/31/2000 06:00 - 16:00 1 10.00 02 A DRLIN1 Rotary drilling 12 1/4" hole. 16:00 - 17:00 1.00 06 H DRLIN1 POOH six stands short trip to repair leak on top drive. 17:00 - 21:30 4.50 08 E DRLIN1 1 Repair oil leak on top drive. 21:30 - 22 :00 0.50 06 DRLIN1 RIH from 4766' to5329'. 22:00 - 04:30 6.50 02 A , DRLIN1 Drilling 12 1/4" hole. 04:30 - 05:00 0.50 07 A DRLIN1 Rig Service. 05:00 - 06:00 1 1.00 02 A DRLIN1 Drilling 121/4" hole. 11/1/2000 06:00 - 11:00 5.00 02 IA DRLIN1 !Drilling 12 1/4" hole. 11:00 - 13:00 i 2.00 05 1 DRLIN1 Pump Hi -Vis sweep, circulate bottoms up. Drop survey. 13:00 - 17:00 1 4.00 06 A DRLIN1 POOH 17:00 - 17:30 0.50 07 DRLIN1 Remove blower hose from top drive. Reset crowm -o- matic. 17:30 - 19:00 , 1.50 1 DRLIN1 POOH with BHA. Retrieve survey. 19:00 - 19:30 0.50 07 DRLIN1 I Clean rig floor. 19:30 - 20:00 0.50 15 1 DRLIN1 I Pull wear ring. Rig up to test BOPs. 20:00 - 21:30 1.50 15 DRLIN1 Test all rams, floor safety valve, choke manifold, choke and kill lines to 1250/3000 psi.Pressure test annular preventor to 250/2500 psi. 21:30 - 22:30 1.00 15 DRLIN1 1 Rig down testing equipment and set wear ring. 22:30 - 01:00 , 2.50 06 DRLIN1 PJSM. Make up new bit and RIH with BHA. Strap, rabbit and pick up 9 jts. 5" HWDP. RIH to shoe. 01:00 - 02:00 1.00 07 DRLIN1 Hook up crown saver electric bell ringer. Drain oil from top drive. (overfull) Service top drive, blocks,fill pipe. 02:00 - 04:30 2.50 06 1 DRLIN1 RIH to 4300'. Fill pipe. 04:30 - 06:00 1.50 02 DRLIN1 Break circulation @ 5500'. Wash and ream to bottom, no fill. Drilling from 5547' to 5565'. 11/2/2000 06:00 - 16:30 10.50 02 A DRLIN1 ' Drilling 121/4" hole. 16:30 - 17:30 , 1.00 DRLIN1 Pump Hi -Vis sweep, CBU for survey. 17:30 - 18:30 1.00 11 F DRLIN1 Wireline survey © 5840'- 1 deg. 18:30 - 03:00 8.50 02 A DRLIN1 Drilling 12 1/4' hole. Check crown o matic. O.K. 03:00 - 06:00 3.00 02 A DRLIN1 Drilling 12 1/4" hole. 11/3/2000 06:00 - 09:00 3.00 02 A I DRLIN1 Drilling 12 1/4" hole. 09:00 - 10:30 1.50 05 I DRLIN1 Pump Hi -Vis sweep. circ. hole clean. 10:30 - 11:30 1.00 10 DRLIN1 Wireline survey @ 6306' PJSM 11:30 - 16:30 5.00 02 A DRLIN1 Drilling 12 1/4" hole T.D. 121/4" hole @ 6500'. 16:30 - 18:00 1.50 05 I DRLIN1 Circ. Hi -Vis sweep. CBU 18:00 - 20:30 1 2.50 06 C DRLIN1 1 POOH 10 std. short trip. Work tight hole from 5692' to 5504'. RIH. 20:30 - 22:30 1 2.00 05 D DRLIN1 Pump Hi -Vis sweep. Circ. hole clea, whie working and rotating pipe. 1 1 1 1/2 circulations. Mix dry job. 22:30 - 00 :00 1.50 06 C I DRLIN1 POOH 00:00 - 00:30 0.50 25 1 DRLIN1 Pump dry job, blow down top drive. 00:30 - 02:00 1.50 06 C DRLIN1 1 POOH SLM 02:00 - 03:30. 1.50 06 DRLIN1 1 Pooh w/ BHA. Clean clay from stabs. Break bit. 03:30 - 04:00 0.50 07 DRLIN1 Clean rig floor. 04:00 - 05:15 1.25 11 A DRLIN1 Rig up SWS and make up logging tools. 05:15 - 06:00 0.75 11 A DRLIN1 Running in hole with SWS wireline. 11/4/2000 06:00 - 09:00 3.00 11 A DRLIN1 RIH with SWS. Logging. 09:00 - 10:30 1.50 11 A DRLIN1 Rig down SWS. Clean mud from tools. 10:30 - 11:00 0.50 07 DRLIN1 Clean rig floor. 1 11:00 - 14:00 3.00 14 E DRLIN1 Drain BOPs. Pick up test joint. Pull wear ring. Set test plug. Change bottom rams from 5" to 9 5/8 ". Test doors to 3000 PSI.Remove bales. I Printed: 2/22/2001 2:56:23 PM • 1 FOREST OIL CORP. Page 6 of 15 Operations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code C Phase Description of Operations 11/4/2000 11:00 - 14:00 3.00 14 E DRLIN1 Break and lay down lower IBOP valve from top drive. 14:00 - 15:00 1.00 12 A DRLIN1 Rig up to run 9 5/8" casing. Pick up Lafluer tool. 15:00 - 16:00 1.00 12 A DRLIN1 Rig up bales, elevators and slips. 16:00 - 17:00 1.00 12 A DRLIN1 Rig up stabbing board. Rig up air line for slips. 17:00 - 17:30 0.50 12 A DRLIN1 PJSM 17:30 - 18:00 0.50 12 A DRLIN1 Make up shoe and float collar. 18:00 - 02:30 8.50 12 ,A DRLIN1 Run 162 jts. 9 5/8" csg. 02:30 - 04:00 1.50 12 C DRLIN1 Circ. @ 6496' 104:00 - 05:00 1.00 12 A DRLIN1 Break out and lay down Lafluer head. Blow down top drive.Make up landing joint, cement head and hose. 05:00 - 05:30 0.501 1 2 C DRLIN1 Break circulation and tag bottom @ 6500' while circulating.PJSM 05:30 - 06:00 0.50 12 1 DRLIN1 Test cmt lines to 3000PSI. OK 11/5/2000 06:00 - 08:00 2.00 12 C CSGIN1 Drop plug, 5 bbl. MESAH2O, kick out plug. Stop and reload head. Pump 43 bbl. MCS -A H2O, 72.5 bbl. lead slurry @ 12.5 ppg., 42.3 bbl tail slurry 15.8 ppg. Drop plug 5 bbl. H2O, switch over to rig pumps. 1 stop reciprocating casing @ 3500 strokes, bump plug @ 3970 strokes. 08:00 - 12:00 4.00 14 B CSGIN1 Pull cement hoses and drain. Prepare BOPs to pick up to set casing slips. Remove flow lines, hook up cable and cable clamp BOP lifter. 12:00 - 13:00 1.00 14 B i CSGIN1 PJSM Lift stack with rig hydraulics. 113:00 - 13:30 0.50 CSGIN1 Set casing slips with 115000 #. 13:30 - 14:00 0.50 14 B CSGIN1 Cut hole in 9 5/8" casing, drain and rough cut. 1 14:00 - 16:30 2.50 14 B CSGIN1 Let down stack, take off cement head. Rig down hydraulic lift system. I Lay down 9 5/8" cut off.Lay down elevators. 16:30 - 17:00 0.50 14 B ICSGIN1 Start finish cut on 9 5/8" casing. 17:00 - 21:00 4.00 14 CSGIN1 Pick up Vetco Gray tubing spool, fill with packing. test to 3800 PSI. Test OK. 21 :00 - 01:00 4.00 14 B CSGIN1 Nipple up BOP, tubing spool, change lower rams to 5 ". Nipple up flow line. Hook up turnbuckles. 01:00 - 05:00 4.00 15 A CSGIN1 Pick up test joint and test plug. Test choke manifold, upper and lower IBOP valves. Test floor valves, choke and kill line valves. Test top, 1 1 bottom and blind rams - 250/4000 PSI. test hydril- 250/3000 PSI. Set I wear bushing, lay down test joint. ' 05:00 - 06:00 1.00 14 E CSGIN1 Install drip pans under rotary table. 11/6/2000 06:00 - 09:30 3.50 14 B DRLIN1 Finish installing drip pans, hoses. Clean cellar and sub base. 09:30 - 12:30 3.00 06 J DRLIN1 RIH with 12 1/4" BHA and lay down same. 112:30 - 16:30 4.00 06 A DRLIN1 Pick up 8 1/2" BHA. 16:30 - 18:00 1.50 06 A DRLIN1 I RIH to 2031'. I 18:00 - 18:30 0.50 05 I DRLIN1 1 Break circulation @ 2031'. 18:30 - 19:30 1.00 06 1A DRLIN1 RIH to 3906'. 119:30 - 20:30 1.00 05 11 DRLIN1 Break circulation @ 3906'. 20:30 - 22:00 1.50 06 A DRLIN1 RIH, tagged float collar @ 6418.6'. 22:00 - 22:30 0.50 05 I DRLIN1 Break circulation @ 6418, CBU. 22:30 - 23:00 0.50109 DRLIN1 Slip 100' of drilling line. 23:00 - 06:00 7.00 08 E DRLIN1 Prepare to lay down top drive. Lay down bales and elevators and remove lower IBOP.Move block hanging line. Remove kelly hose and 1 I blower hose. Lay down stabbing board. Install transport pins. Fold 1 derrick board up. Close storm doors in board. Drain oil from top drive. 1 Pin erection rigging to blocks and latch rigging to torque guide clamps. 1 I Release tension in torque cables. Tuen power off and disconnect electric and hydraulic cables. Unlatch from harpoon. Lay down beaver slide. Remove windwalls. 11/7/2000 06:00 - 07:00 1.00 01 A DRLIN2 Lower grasshopper on Can -Rig top drive and spool up electric cables and hydraulic hoses. Printed: 2/22/2001 2:56:23 PM • . FOREST OIL CORP. Page 7 of 15 Operations Summary Repo Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code Code Phase Description of Operations 11/7/2000 07:00 10:30 3.50 01 A DRLIN2 Tie onto top drive torque guide, pull out and lower top drive. Position ' and install tail roll section to same. Position truck and lower top drive and load on truck. 10:30 - 11:30 1.00 01 ' DRLIN2 !Install two windwalls on sub and set beaver slide and catwalk. ;11:30 - 12:00 0.50 01 DRLIN2 Prepare to install work basket on top of blocks. 12:00 - 14:00 I 2.00 01 DRLIN2 Weld platform to top of blocks. 14:00 - 15:30 1.50 01 DRLIN2 Run blocks to crown and dismantle top drive spear.Lower to floor. 15:30 - 17:30 2.00 01 DRLIN2 ' Run back to crown to dismantle spear hanger baskets. take off lower top drive rail clamps from derrick. 17:30 - 19:30 , 2.00 01 DRLIN2 Lay all Can -Rig parts down. 19:30 - 21 :00 1.50 01 DRLIN2 Take platform off top of blocks. 21:00 - 22:30 1.50 01 DRLIN2 P/U SWIVEL &SERVICE. 22:30 - 23:30 1.00 01 DRLIN2 1 PREPARE TO P/U TESCO TORQUE TUBE, MAKING IT UP ON PIPE RACK. 23:30 - 00:00 0.50 01 I A DRLIN2 P/U TESCO TORQUE TUBE. 00:00 - 00:30 0.50 01 DRLIN2 PJSM W/ TESCO R/U TESCO TORQUETUBE. 00:30 - 06:00 I 5.50 01 DRLIN2 P/U TD. TRQ. TUBE TO RIG FLOOR, TIE ON TO BLOCKS. FINISH ' STACKING TRQ. TUBE UP TO RIG FLOOR. HANG SAME @ ! CROWN, TAKE MEASUREMENT, BOLT PATTERN TO DERRICK RAIL. UNHANG TRQ. TUBE, DROP BTM. SECTION AND NEXT 18 FT. SECTION & SWAP OUT WITH 15 FT. SECTION. 11/8/2000 06:00 - 07:00 1.00 01 A DRLIN2 FINISH HANGING TESCO TORQUE TUBE. 07:00 - 08:30 1.50 01 DRLIN2 INSTALL T -BAR & CLAMP TO DERRICK. 08:30 - 09:00 1 0.50 01 A DRLIN2 HANG BLOCK HANGING LINE. 09:00 - 11:30 2.50 01 A DRLIN2 RIG UP CEMENT HOSE TO CIRC. HOLE & COND. MUD @ SLOW RATE DUE TO THICK MUD. 11:30 - 12:00 0.50 01 A DRLIN2 HOOK UP RIG UP SLINGS & SET TESCO TOP DRIVE & RACK ON 1 RIG FLOOR. 12:00 - 13:00 1.00 01 A DRLIN2 SCREW SWIVEL INTO TOP DRIVE. 13:00 - 14:00 1.00 01 A DRLIN2 TAKE TOP DRIVE OUT OF CRADLE, RIG UP HYD. LINE. 14:00 - 15:00 1.00 01 A DRLIN2 R/U TORQUE BUSHING TO TOP DRIVE. 15:00 - 16:00 1.00 01 A DRLIN2 HOOK UP TOPDRIVE HYD. RAMS. 16:00 - 18:00 2.00 01 A DRLIN2 i HANG HYD. HOSES IN DERRICK. 18:00 - 19:00 1.00 01 A DRLIN2 HOOK UP HYD. HOSES TO POWER PACK. 19:00 - 22:00 3.00 01 A DRLIN2 START UP TESCO, FUNCTION TEST & SET PRES. CONTROLS. 22:00 - 00:00 2.00 01 A DRLIN2 I R/U SAVER SUB, BALES, ELEVATORS & ADJUST TORQUE 1 BUSHING. 00:00 - 04:00 4.00 01 A DRLIN2 I HOLD 15 MIN. PJSM. INSTALL TURN BUCKELS & RACHET STRAPS ' TO TORQUE TUBE. WRAP HYD. HOSES WITH TARP. HOOK UP STAND PIPE & KELLY HOSE. 04:00 - 04:30 0.50 01 A DRLIN2 TEST UPPER & LOWER I.B.O.P. VALVE 4,000 & 250 P.S.I. 04:30 - 05:30 1.00 09 DRLIN2 I HOLD P.J.S.M. & CUT DRLG. LINE. 05:30 - 06:00 1 0.50 05 DRLIN2 CIRCULATE MUD. 11/9/2000 06:00 - 07:30 1.50 05 A DRLIN2 CIRCULATE & CONDITION MUD. 07:30 - 08:00 0.50 25 DRLIN2 CASING INTEGRITY TEST TO 3,000 P.S.I. FOR 30 MIN. 08:00 - 10:00 2.00 02 D DRLIN2 I DRILLING FLOAT COLLAR & CEMENT TO 6,430 FT. 10:00 - 10:30 0.50 01 A DRLIN2 ;CIRCULATING BOTTOMS UP. 10:30 - 12:00 1.50 01 A DRLIN2 ADD S PIPE TO TESCO GOOSE NECK, TIGHTEN SWIVAL PACKING & WRAP 75' TARP AROUND SERVICE HOSES FOR TOPDRIVE. 12:00 - 13:00 1.00 01 A DRLIN2 FINISHED INSTALLING TARP ON TOPDRIVE SERVICE HOSES. 13:00 - 13:30 0.50 02 D DRLIN2 DRILL CEMENT F/ 6,430' TO 6,444'. 13:30 - 14:00 0.50 05 DRLIN2 STOP DRLG. CIRCULATE CONTAMINATED MUD. Printed: 2/22/2001 2:56:23 PM • • FOREST OIL CORP. Page 8', of 1.6 Operations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 1 Date From - To Hours Code Sub Code Phase Description of Operations 11/9/2000 14:00 - 18:00 4.00 02 D DRLIN2 DRILL F/ 6,444' TO 6,524'. 18:00 - 20:30 2.50 05 A DRLIN2 CIRC. & COND. CONTAMINATED MUD. 20:30 - 21:00 0.50 02 A DRLIN2 F.I.T. TO 10.5 @ 6,524. 21:00 - 00:00 3.00 02 A DRLIN2 DRILL FROM 6,524 TO 6,577. 00:00 - 06:00 6.00 02 A DRLIN2 DRILL FROM 6,577 TO 6,660 11/10/2000 06:00 - 08:30 2.50 02 A DRLIN2 DRLG. 8.5 HOLE 08:30 - 09:00 0.50 05 A DRLIN2 CIRC. BOTTOMS UP. 09:00 - 09:30 0.50 01 A DRLIN2 BLOW DOWN TOPDRIVE, INSTALL WIRELINE GUIDE ON SAME. 09:30 - 11:00 1.50 11 A DRLIN2 RIH W/ WIRELINE & SURVEY @ 6677'. 11:00 - 12:00 1.00 02 A DRLIN2 DRLG FROM 6,709 TO 6,721 12:00 - 00:00 12.00 02 A DRLIN2 DRLG FROM 6721 TO 6898 00:00 - 06:00 6.00 02 A DRLIN2 DRLG FROM 6898 TO 6898 11/11/2000 06:00 - 10:00 4.00 02 A DRLIN2 DRLG. 8.5 HOLE. 10:00 - 10:30 0.50 05 I DRLIN2 ' CIRC. BOTTOMS UP. 10:30 - 11:00 0.50 11 A DRLIN2 DROP SURVEY © 6987. 11:00 - 12:00 1.00 11 A DRLIN2 I POOH TO SHOE. BLOW DOWN TOPDRIVE. RETRIEVE WIRELINE I SURVEY. 12:00 - 13:00 1.00 11 A DRLIN2 I RETRIEVE WIRELINE SURVEY.(NO RUN) SERVICE TOPDRIVE. 13:00 - 13:30 0.50 07 DRLIN2 I SERVICE RIG. 13:30 - 14:00 0.50 12 D DRLIN2 I WELD GUSSETS BETWEEN 20" & 13 3/8 ". 14:00 - 15:00 1.00 26 DRLIN2 ' P/U 5 " DP 18 Jts to 6995 15:00 - 16:00 1.00 10 DRLIN2 Run Wireline Survey ( line broke when POH @ 5520') 16:00 - 18:00 2.00 06 DRLIN2 I POH 15 STDS splice wireline - retreive survey tool 18:00 - 19:00 1.00 06 DRLIN2 I Ran back to BTM 19:00 - 00:00 5.00 02 DRLIN2 DRLG F/7024' T/7066 00:00 - 05:30 5.50 02 A DRLIN2 DRLG F/ 7066 T/ 7121 05:30 - 06:00 0.50 08 A DRLIN2 STAND BACK ONE STAND DP, TIGHTEN WASH PIPE PACKING. 11/12/2000 06:00 - 07:00 1.00 08 A DRLIN2 C/O SWIVAL WASH PIPE & PACKING. 07:00 - 12:00 5.00 02 A DRLIN2 DRLG. 8.5" HOLE f/ 7121 to 7195 ft. 12:00 - 15:30 3.50 02 A DRLIN2 DRLG. 8.5" HOLE f/ 7195 to 7233 ft. 15:30 - 16:30 1.00 05 I DRLIN2 CIRC. BTM. UP. 16:30 - 17:00 0.50 10 B DRLIN2 DROP SURVEY © 7,213, PUMP DRY JOB. 17:00 - 17:30 0.50 08 B DRLIN2 WORK ON TOP DRIVE & BLOW DOWN. 17:30 - 22:30 5.00 06 A DRLIN2 POH. 22:30 - 00:00 1.50 06 J DRLIN2 ' P/U MUD MTR, BIT SUB, XO, RIH DCS. 00:00 - 01:00 1.00 06 J DRLIN2 M/U BHA 01:00 - 03:00 2.00 08 A DRLIN2 REPOSITION TOP DRIVE HYD. LINES & WORK ON RPM ADJ. REPOSITION KELLY HOSE. 03:00 - 06:00 3.00 06 J DRLIN2 RIH, TEST # 1 MUD PUMP T /FILL UP LINE. 11/13/2000 06:00 - 07:30 1.50 06 J DRLIN2 RIH w/ Mud Motor, PDC Bit 07:30 - 08:00 0.50 03 A DRLIN2 Ream f/ 7212 to 7233 ft. 08:00 - 12:00 4.00 02 A DRLIN2 Drlg 8.5" hole f/ 7233 to 7282 ft 12:00 - 00:00 12.00 02 A DRLIN2 Drlg 8.5" hole f/ 7282 to 7559 00:00 - 06:00 6.00 02 A DRLIN2 Drlg 8.5" hole f/ 7559 to 7618 11/14/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5" HOLE F/ 7618 T/ 7698. 12:00 - 18:00 6.00 02 A DRLIN2 I DRLG. 8.5" HOLE F/ 7698 T/ 7795. 18:00 - 18:30 0.50 05 1 DRLIN2 CIRC. BTMS. UP. 18:30 - 19:00 0.50 11 A DRLIN2 RIG UP SHEAVE ON TOP DRIVE. TO SURVEY. 19:00 - 19:30 0.50 11 A DRLIN2 RIH W/ WIRELINE SURVEY. 19:30 - 20:30 1.00 10 A DRLIN2 POOH w/ Wireline. Rig down topdrive survey tool 20:30 - 00:00 3.50 02 A DRLIN2 DRLG 8.5" HOLE F/ 7775 TO 7844 00:00 - 06:00 6.00 02 A DRLIN2 DRLG 8.5" HOLE F/ 7844 TO 7940 Printed: 2/22/2001 2:56:23 PM • • FOREST OIL CORP. Pag 9 o f 15 Operations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 I Date From - To Hours Code Sub Phase ` Description of Operations Code 11/15/2000 06:00 - 10:30 4.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 7,940 T/ 8056. 10:30 - 11:30 1.001 08 B DRLIN2 REPLACE BLOWN HYD. HOSE ON TESCO TOP DRIVE. 11:30 - 12:00 0.50 02 A 1 DRLIN2 DRLG. 8.5 HOLE F/ 8,056 T/ 8,091. 12:00 - 22:00 10.00 02 A DRLIN2 DRLG 8.5 HOL F/ 8091 TO 8273 22:00 - 22:30 0.50 02 A DRLIN2 CIRC. BOTTOMS UP TO SURVEY 22:30 - 23:00 0.50 02 A DRLIN2 RIG SHEAVE ON TOPDRIVE TO WIRELINE /MAKE UP SURVEY 123:00 - 23:30 0.50 10 A DRLIN2 RIH W/ WIRELINE SURVEY AND SURVEY @ 8212 23 :30 - 00:00 0.50 10 A DRLIN2 SURVEY AND POOH 00:00 - 00:30 0.50 02 A DRLIN2 POOH W/ WIRELINE SURVEY 00:30 - 01:00 0.50 02 A DRLIN2 POOH W/ 10 STAND SHORT TRIP 01:00 - 02:30 1.50 02 A DRLIN2 RIH. P/U 27 JTS. DRILL PIPE F/ CATWALK 02:30 - 06:00 3.50 02 A DRLIN2 DRLG 8.5 HOLE F/ 8273 TO 8333 11/16/2000 106:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5 HOLE F/8333 T/ 8371. 12 :00 - 04:00 16.00 02 1A DRLIN2 DRLG. 8.5 HOLE F/ 8371 T/ 8552. 04:00 - 04:30 0.50 08 IA DRLIN2 CHANGE SWAB CIRC. CLEAN BIT. 104:30 - 06:00 1.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8255 T/8560. 11/17/2000 06:00 - 09:00 1 3.00 02 A 1 DRLG. 8.5" HOLE F 8560 TO 8573. 09:00 - 09:30 i 0.50 05 1A 1 CIRC. BOTTOMS UP 09:30 - 10:00 I 0.50 10 A DROPPED SURVEY @ 8552 ' 10:00 - 12:00 2.00 06 A PUMP PILL; POOH 12:00 - 16:30 1 4.501 06 1 A POOH F 5809 TO 315 16:30 - 17:30 1.00 06 J RETRIEVE SURVEY; STAND BACK BHA, LD MUD MTR 17:30 - 20:00 2.50 25 PULL WEAR BUSHING; SANDED IN; WASHED FREE 120:00 - 21:30 ; 1.501 15 A RIG UP TO TEST B.O.P.'s 21:30 - 23:00 1.50 15 A TEST RAMS; ANNULAR; FLOOR VALVE; KELLY COCKS 23:00 - 00:00 1.00 15 B REPAIRING TWO KILL LINE VALVES 100:00 - 05:00 5.00 15 ' B WORKING ON KILL LINE AND CHOKE VALVES 105:00 - 06:00 1.00 15 B TESTING KOOMEY. 11/18/2000 06:00 - 07:30 1.50 26 1 DRLIN2 Pick up 15 jts. off walk; stand back in derrick 07:30 - 08:30 , 1.00 15 A DRLIN2 M/U Test Plug, test choke valve, good test. Pull plug, run wear ring. 08:30 - 12:00 ' 3.50 25 DRLIN2 M/U BHA. Pull allenhead bolts for added flow w/ drillbit. 12:00 - 13:00 1.00 25 DRLIN2 Waiting on drill bit. Clean rig floor & cellar. Adjust crown warning bell 13:00 - 15:00 2.00 26 DRLIN2 Make up new 8.5 bit. RIH to 1128 ft. 115:00 - 15:30 I 0.50 25 DRLIN2 Change out Saver Sub on Tesco Top Drive 15:30 - 16 :00 0.50 25 DRLIN2 Fill DP & flow check Teledrift tool @ 1220 16:00 - 19:00 3.00 06 J DRLIN2 TIH from 1220 to 6277 19:00 - 19:30 0.50 06 J DRLIN2 Fill DP & spot check Teledrift tool 19:30 - 21:00 1.50 06 1J DRLIN2 TIH from 6277 to 8552 21:00 - 21:30 ' 0.50 06 J DRLIN2 Fill DP & spot check Teledrift tool (3.5 deg) 21:30 - 00:00 2.50 02 A DRLIN2 1 DRLG from 8572 to 8600 100:00 - 06:00 6.00 02 A DRLIN2 DRLG from 8600 to 8678 11/19/2000 106:00 - 12:00. 6.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8678 T/ 8776 12:00 - 00:00 12.00 02 A ' DRLIN2 DRLG. 8.5 HOLE F/ 8776 T/ 9050 00:00 - 01:30 1.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 9050 T/ 9089 1 01:30 - 02:00 0.50 10 A DRLIN2 TELEDRIFT SURVEY @ 9049' (3.5 TO 4.0 DEG.) 02:00 - 06:00 4.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 9089 T/ 9180 11/20/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. F/ 9180 T/ 9254 1 1 2:00 - 12:30 0.50 25 DRLIN2 ESTABLISH DRLG. PERIMETERS. NABORS SAFETY MEETING 12:30 - 13:00 0.50 07 DRLIN2 SERVICE RIG 13:00 - 00:00 11.00 02 A DRLIN2 DRLG. F/ 9254 T/ 9466 00:00 - 06:00 6.00 02 A DRLIN2 DRLG. F/ 9466 T/ 9538 11/21/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 9538 T/ 9562 12:00 - 18:00 6.00 02 A DRLIN2 DRLG. F/ 9562 T/ 9655 i 1 Printed: 2/22/2001 2:56:23 PM III/ 1 FOREST OIL CORP. Page 10 of 15 O perations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code -ode Phase Description of Operations 11/21/2000 18:00 - 18:30 0.50 10 A DRLIN2 TELEDRIFT SURVEY @ 9549. 18:30 - 19:00 0.50 05 I DRLIN2 CBU F/ SHORT TRIP 19:00 - 20:00 1.00 06 H DRLIN2 11 STD SHORT TRIP. F/ 9655 T/ 8624 20:00 - 20:30 0.50 07 DRLIN2 CLEAN RIG FLOOR. 120:30 - 21:00 0.50 07 DRLIN2 SERVICE RIG. 21:00 - 23:00 2.00 26 H DRLIN2 PJSM. RIH F/ 8624 T/ 9655, P/U PIPE FROM RACK & RABBIT. 23:00 - 00:00 1.00 02 A DRLIN2 DRLG F/ 9655 T/ 9660 00:00 - 06:00 1 6.00 02 A DRLIN2 DRLG F/ 9655 T/ 9724 11/22/2000 06:00 - 12:00 6.00 02 A DRLG 8.5" HOLE F/ 9724 TO 9795 12:00 - 18:00 6.00 02 A 1 DRLG 8.5" HOLE F/ 9795 TO 9840 18:00 - 18:30 0.50 07 SERVICE RIG DRAWWORKS; BLOCKS; CROWN 18:30 - 06:00 11.50 02 1A DRLG 8.5" HOLE F/ 9840 TO 9965 11/23/2000 106:00 - 16:00 10.00 02 A DRLIN2 Drilling 8 1/2" hole from 9965 to 9983. 16:00 - 16:30 0.50 10 A DRLIN2 Survey w/ teledrift © 9935'. Drop totco. 16:30 - 17:00 1 0.50 28 DRLIN2 Monitor well, pump dry job. 117:00 - 20:00 3.00 06 1 A DRLIN2 POOH to 6467. (shoe) 20:00 - 20:30 0.50 07 DRLIN2 Service Rig 20:30 - 21:00 0.50 05 I DRLIN2 Circulate bottoms up. 21:00 - 21:30 0.50 25 DRLIN2 Pre -Job safety meeting 21:30 - 05:00 7.50 08 C DRLIN2 Remove and repair high drum clutch 05:00 - 06:00 1.00 06 J DRLIN2 POOH to change bit and BHA 11/24/2000 06:00 - 09:00 3.00 06 A DRLIN2 POOH 09:00 - 12:00 3.00 06 A DRLIN2 Retrieve survey © DCs', break bit, lay down mud motor, inspect survey 1 tool. 12:00 - 15:00 3.00 06 A DRLIN2 Service teledrift tool, pick up mud motor and new bit, RIH with BHA to 1128'. 15:00 - 17:30 2.50 06 B DRLIN2 1 PJSM, P/U 5" DP from pipe rack. (rabbit each joint) RIH from 1128' to 2067'. 17:30 - 18:00 0.50 07 DRLIN2 Service rig and re- adjust kelly hose to top drive. 18:00 - 23:00 5.00 06 A DRLIN2 RIH from 2067' to 6475'. Fill pipe © 3472' and 6475'. 23:00 - 00:00 1.00 07 DRLIN2 I Cut and slip drilling line. 00:00 - 02:00 2.00 06 A DRLIN2 RIH from shoe, fill pipe @ 9000'. 02:00 - 02:30 0.50 03 DRLIN2 Ream from 9845' to bottom © 9984'. 02:30 - 06:00 ( 3.50 02 A DRLIN2 Drilling 8 1/2' hole from 9984' to 10068'. 11/25/2000 06:00 - 21:00 15.00 02 1 A I DRLIN2 Drilling 8 1/2" hole from 10068' to 10503'. ADT hrs. 21:00 - 21:30 0.50 10 A DRLIN2 , Survey w/ teledrift @ 10435' -3.5 Deg. 21:30 - 02:30 5.00 02 A DRLIN2 Drilling 8 1/2" hole. 1 02:30 - 03:00 0.50 29 DRLIN2 ICirc. bottoms up. 03:00 - 04:00 1.00 06 H DRLIN2 7Std. short trip. Hole in good shape, no fill 04:00 - 06:00 1 2.00 02 A DRLIN2 Drilling 81/2" hole. Hole is taking +/ -10 bbls. /hr. fluid. 11/26/2000 06:00 - 13:30 1 7.50 02 A DRLIN2 Drill 8 1/2" hole. 13:30 - 14:00 0.50 07 DRLIN2 . Service rig, draw - works, blocks and crown. 14:00 - 17:30 3.50 02 A 1 DRLIN2 I Drilling 8 1/2" hole to 10809'. 17:30 - 18:00 0.50 10 A ' DRLIN2 1 Survey with teledrift @ 10758', 3.5 deg. 18:00 - 18:30 0.50 28 DRLIN2 Monitor well, mix and pump dry job. 18:30 - 01:00 6.50 06 A DRLIN2 POOH to BHA. 01:00 - 02:30 1.50 06 A DRLIN2 Work BHA, lay down jars and stab. 02:30 - 04:00 1.50 15 A DRLIN2 Pull wear bushing, pick up test plug. 04:00 - 06:00 j 2.00 15 I A DRLIN2 Test BOPs, 250/4000# 11/27/2000 06:00 - 07:00 1.00 07 DRLIN2 1 Put Kelly Hose on and reposition. 07:00 - 08:30 1.50 26 DRLIN2 M/U Bit; Brk Teledrift & redress; test mudmotor 08:30 - 09:30 1.00 06 J DRLIN2 TIH w/ BHA & HWDP 09:30 - 10:00 0.50 06 J DRLIN2 TIH Punted. 2/22/2001 2:56:23 PM 1 • fa FOREST OIL CORP. Page 11 of 15 Operations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 , Date From - To Hours Code Sub C Phase Description of Operations 11/27/2000 10:00 - 12:00 2.00 07 DRLIN2 Working on positioning kelly hose; interferes w/ making up drillpipe from driller's side; hose binding against pipe. 12:00 - 12:30 1 0.50 07 DRLIN2 Service rig; drawworks; blocks; crown. 12:30 - 18:00 5.50 06 J DRLIN2 TIH f/ 1225 to 10594; filled DP © 3471, 6295, 8910. 18:00 - 19:00 1.00 03 A DRLIN2 Ream f/ 10594 to 10806; pumped hi -vis sweep while reaming to bottom. 19:00 - 00:00 5.00 02 A DRLIN2 Drilling f/ 10806 to 10846. 00:00 - 06:00 6.00 02 A DRLIN2 Drilling f/ 10846 to 10915 11/28/2000 06:00 - 10:00 4.00 02 A DRLIN2 Drilling 8 1/2" hole. 10:00 - 12:00 , 2.00 02 A ' DRLIN2 Pump hi -vis sweep while drilling 8 1/2" hole. 12:00 - 12:30 0.50 02 A DRLIN2 Drilling 81/2" hole. 12:30 - 13:00 0.50 07 DRLIN2 Service rig, draw- works, blocks, swivel and crown. 13:00 - 21:30 8.50 02 A DRLIN2 Drilling 8 1/2' hole, pump hi -vis sweep while drilling. 1 21:30 - 22:00 0.50 29 DRLIN2 Circ. hole clean after hi -vis sweep for short trip, monitor well. 22:00 - 22:30 0.50 06 H DRLIN2 Short trip from 11174' to 10594'. No hole problems. 22:30 - 06:00 7.50 02 A DRLIN2 Drilling 8 1/2' hole. 11/29/2000 06:00 - 07:00 1.00 A DRLIN2 Drilling f/ 11290 to 11300 07:00 - 12:00 1 5.00 02 A DRLIN2 Pump up to survey depth (11258); 15 min. Drilling f/ 11300 to 11345 112:00 - 12:30 0.50 0 DRLIN2 Service rig. 112:30 - 00:00 11.50 02 A DRLIN2 Drilling f/ 11345 to 11475 00:00 - 06:00 6.00 02 A DRLIN2 Drilling f/ 11475 to 11590 11/30/2000 06:00 - 06:30 0.50 02 A DRLIN2 Drilling 8 1/2" hole from 11590' to 11598'. 06:30 - 08:30 2.00 05 I DRLIN2 Pump hi -vis sweep, circ. bottoms up and monitor well for 10 min. Pump dry job 08:30 - 13:30 5.00 06 ' A DRLIN2 POOH from 11598' to inside the shoe © 6381'. 13:30 - 14:00 0.50 08 C DRLIN2 PJSM 14:00 - 16:00 2.00 08 C DRLIN2 Move Hydromatic and work on over - riding clutch. Clutch worn out, needs replacing. Waiting on clutch parts. 116:00 - 06:00 14.00 08 C DRLIN2 Monitoring well while repairing trip -tank, changing liners in # 2 pump, circ. every six hours, continue monitoring well while waiting on clutch !parts. 12/1/2000 06:00 - 10:30 4.50 08 C i Blow Down Topdrive. remove Kelly Hose and goosnecks; tighten 1002 1 1 unions; have welder tack to keep from backing off agian. Install same and adjust Kelly Hose to keep away from drillpipe when tripping. Change impeller on #1 water pump. Change belts on #2 water pump. Electrician troubleshooting problem with drawworks SCR assignment. 10:30 - 12:00 1.50 08 1 C Dress and clean overriding clutch to be installed. Work on installing same. 12:00 - 18:00 6.00 08 C Install overide clutch. Reinstall all guards. 18:00 - 18:30 0.50 05 A Circulate and conditon mud. Pump dry job. 18:30 - 22:00 3.50 06 J Blow down topdrive. POOH. 122:00 - 00:00 2.00 Finish POOH. Check out Teledrift tool. Break off bit. 00:00 - 01:30 1.50 26 Making up new BHA w/ 8.5" bit; mud motor; teledrift tool 01:30 - 02:30 1.00 26 Pick up 18 singles of 5" drill pipe. 102:30 - 06:00 3.50 06 J I RIH. Fill drillpipe. 12/2/2000 06:00 - 10:00 4.00 08 C DRLIN2 REALIGN OVERRIDING CLUTCH. 10:00 - 12:00 2.00 06 A DRLIN2 I TIH; LAY DN SINGLE, WASH OUT; TIH TO 8350 12:00 - 12:30 0.50 06 ,A DRLIN2 RIH 12:30- 14:00 , 1.50 29 DRLIN2 BREAK CIRC © 8443; FILL PIPE & CBU 14:00 - 15:00 1.00 06 A DRLIN2 RIH 15:00 - 16:00 1.00 03 A DRLIN2 BREAK CIRC ©11623; FILL PIPE; REAM 100' TO BOTTOM 16:00 - 16:30 0.50 03 A DRLIN2 WASH TO BOTTOM; BREAK IN BIT. 16:30 - 00:00 7.50 02 A DRLIN2 DRILLING F/10598 TO 11740 1 I Printed: 2/22/2001 2:56:23 PM 1 • • FOREST OIL CORP. Page 12 of 15 Operat S ummary R eport . Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code Sub Code Phase Description of Operations 12/2/2000 00:00 04:00 ' 4.00 02 A DRLIN2 DRILLING F/ 11740 TO 11812 04:00- 04:30 0.50 10 A DRLIN2 SURVEY; 3.5 DEG @11758 04:30 - 06:00 1.501 02 A DRLIN2 DRILLING F/ 11812 TO 11869 12/3/2000 06:00 - 12:00 , 6.00 02 A DRLIN2 DRLG. 8.5" HOLE F/ 11869 T/ 11970 12:00 -00:00 12.00 02 A DRLIN2 DRLG. F/ 11970 T/ 12165 00:00 - 06:00 i 6.00 02 A DRLIN2 DRLG. F/ 12165 T/ 12257 12/4/2000 06:00 - 09:30 3.50 02 A DRLIN2 DRLG. 8.5" HOLE F/ 12257 T/ 12300 09:30 - 10:00 0.50 10 A DRLIN2 PUMP UP SURVEY @ 12258 FT. STAND BACK STD. 10:00 - 12:00 2.00 05 1 1 DRLIN2 PUMP HI VIS SWEEP CIRC. BTMS UP & RECPROCATE PIPE, MIX DRY JOB, MONITOR WELL 10 MIN. 12:00 - 12:30 0.501 28 DRLIN2 PUMP DRY JOB & BLOW DOWN TOP DRIVE. 112:30 - 22:00 9.501 06 C DRLIN2 P.O.H. TO SHOE- SLOW- CHECK FOR FLOW @ 9 5/8 SHOE & 1 1 P.O.H. 22:00 - 22:30 0.50 06 C DRLIN2 LAY DOWN MOTOR, TELEDRIFT & 8.5 BIT. 122:30 - 00:00 1.50 11 A DRLIN2 RIG UP TO LOG. 00:00 - 02:30 2.50111 A DRLIN2 1 MAKE UP SWL TOOLS, HOLD PJSM. RIH TO WARM UP TOOLS; 1 1 POOH TO LOAD SOURCE. WHEN POH TO LOAD SOURCE, TOOL HUNG UP AT 94 FT. TOOL FREED. 02:30 - 06:00 3.50 11 A (DRLIN2 RIH W/ LOGGING TOOLS. 12/5/2000 106:00 - 12:00 6.00111 A 1 EVAL 2 RIH SWL. POOH, unload sources, laydown tools. Hang up again @ 1 1 90 ft. Rope socket missing AIT standoff from bottom of tool. Make up FMI tools, RIH to warm up. Start in hole @ 10:15 hrs. w/ FMI 12:00 - 14:30 2.50 11 A EVAL 2 POOH, logging w/ FMI tools. 114:30 - 00:00 1 9.50 25 EVAL 2 Wireline logging tool stuck @ 6740 ft. Working to free. 00:00 - 06:00 6.00 25 EVAL 2 Monitoring well, waiting on fishing tools and hands. 12/6/2000 06:00 - 12:00 6.00 25 EVAL 2 MONITOR WELL W/ TRIPTANK. WAIT ON WEATHER TO RECEIVE FISHING TOOLS & SCHLUMBERGER HANDS. 12:00 - 15:00 3.00 25 EVAL 2 WAITING ON FISHING TOOLS. 15:00 - 16:30 1.50 19 B EVAL 2 P/U FISHING TOOLS, FIGURE OUT BHA,CLAMP WIRE, WAIT ON SCHLUMBERGER. 16:30 - 18:00 1.50 25 EVAL 2 PRE -JOB MEETING, PROCEDURES TO RIG UP & STRIP OVER. 18:00 - 21:00 3.00 19 B EVAL 2 RIG UP SCHLUMBERGER SHEAVE IN DERRICK, CUT & THREAD WIRELINE, RIG UP SINKER BARS, TEST WIRELINE HEAD TO 6K. 21:00 - 22:00 1.00 06 B EVAL 2 RIH BHA 22:00 - 00:00 2.00 19 B , EVAL 2 RECUT WIRE FOR BETTER SPACING, REPOSITION SHEAVE IN DERRICK. 100:00 - 06:00 6.00 19 B EVAL 2 STRIPPING OVER WIRELINE 12/7/2000 1 06:00 - 08:30 2.50 19 B EVAL 2 STRIP OVER TO SHOE 08:30 - 09:30 1.00 29 1 EVAL 2 CIRCULATE BOTTOMS UP PLUS DRILL PIPE VOLUME 109:30 - 10:00 0.50 06 B EVAL 2 TRIP IN HOLE TO FISH 10:00 - 11:30 1.50 19 B EVAL 2 ; PICK UP SINGLE. FIND FISH AT 6713 11:30 - 12:00 1 0.50 19 B EVAL 2 MAKE UP CIRCULATING SUB. PRESSURE UP AND BLOW DISC ON PUMPOUT SUB. 12:00 - 13:00 1.00 28 F EVAL 2 CIRCULATE AND PUMP DRY JOB. BLOW DOWN TOPDRIVE. 13:00 - 14:00 1.00 25 EVAL 2 PRE -JOB SAFETY MEETING (R/U TO PULL WIRELINE). HANG 1 WIRELINE. T CLAMP. RIG DOWN WIRELINE SHEAVE FROM 1 CROWN. LATCH UP ON T CLAMP WITH RIG ELEVATORS. PULL 1 11,000 LBS. TO BREAK LINE AT ROPE SOCKET. 14:00 - 15:30 1.50 19 B EVAL 2 R/U SCHLUMBERGER TO POH. WIRELINE RETRIEVED ALL LINE. 15:30 - 16:00 0.50 11 A EVAL 2 1 RIG DOWN SCHLUMBERGER 16:00 - 21:00 5.00 06 B EVAL 2 !POOH WITH FISH. 21:00 - 22:00 1 1.00 25 EVAL 2 LAY DOWN FMI TOOL AND TRISTATE FISHING TOOLS. 22:00 - 00:00 2.00 26 EVAL 2 PICK UP BHA 1 Printed: 2/22/2001 2:56:23 PM • • FOREST OIL CORP. Page 13 of 15 Operations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code Sub Phase 1 Description of Operations 12/7/2000 00:00 - 00:30 0.50106 1 EVAL 2 PJSM 15 MIN. TIH W/ HWDP 00:30 - 02:30 2.00 09 EVAL 2 CUT AND SLIP 100' OF DRILLING LINE. SERVICE RIG. 02:30 - 04:00 1.50 06 EVAL 2 ITIH TO 7443 FT. REAM TIGHT SPOT (40000 DOWN, 20000 UP) 104:00 - 06:00 2.00 06 EVAL 2 TIH. TIGHT @ 7287. WORK PIPE THROUGH TWICE. CLEANED UP. 12/8/2000 06:00 - 07:30 1.50 06 H CSGIN2 TIH TO 9318' WASH & REAM TO 9348' 07:30 - 08:30 1.00 05 F CSGIN2 CIRC. HOLE CLEAN. 08:30 - 10:00 1.50 06 H CSGIN2 1 T11-1 TO 9650' CIRC. HOLE CLEAN. 10:00 - 12:00 2.00 06 H CSGIN2 TIH TO 11542' WASH & REAM TO 11589'. 12:00 - 12:30 0.50 06 H CSGIN2 TIH 12:30 - 13:00 0.50 29 I CSGIN2 CBU @ 11872. 13:00 - 14:00 1.00 06 H CSGIN2 TIH 14:00 - 17:00 3.00 03 .A CSGIN2 REAM TO BTM. F/ 12061 T/ 12300. 17:00 - 21:30 4.50 05 F CSGIN2 PUMP 2 SWEEPS, CIRC & COND MUD. 21:30 - 22:00 0.50 05 IF CSGIN2 PUMP 3RD SWEEP, MONITOR WELL 22:00 - 00:00 2.00106 1H CSGIN2 I POOH 00:00 - 06:00 6.00 06 H CSGIN2 1 POOH 12/9/2000 ' 06:00 - 09:00 3.00 06 1H CSGIN2 1 STD BACK BHA, UD STABS, BREAK BIT. 09:00 - 10:00 1.00 , 15 A CSGIN2 1 PULL WEAR RING, SET TEST PLUG. 10:00 - 12:00 2.00 15 A CSGIN2 CHANGE RAMS T/ 7 5/8 ". HANG STABBING BOARD. P/U CASING ELEVATOR, HANG HOSES, HOOK UP FILL -UP LINE T/ CASING. 12:00 - 13:30 1 1.50 15 A CSGIN2 TIGHTEN BOLTS ON RAM DOORS. TEST STACK TO 3000 PSI. PULL TEST PLUG, SET WEAR RING. 113:30 - 14:30 1.00 01 A CSGIN2 RIG UP WEATHERFORD. 14:30 - 15:00 0.50 25 CSGIN2 PRE -JOB SAFETY MEETING (RUNNING CASING) 15:00 - 00:00 9.00 12 1 B CSGIN2 RIH W/ 7 -5/8" LINER. HIT TIGHT SPOT @90 FT. WORKED THROUGH. CHECKED FLOAT - O.K. 00:00 - 06:00 j 6.00 12 B CSGIN2 RIH W/ 7 -5/8" LINER. JOINT #52 HAS DAMAGED THREADS. PULLED OUT AND RUNNING TALLY ADJUSTED ACCORDINGLY. 12/10/2000 06:00 - 07:30 1.50 12 B CSGIN2 UD casing tools; P/U and M/U hanger 07:30 - 09:00 1.50 12 B CSGIN2 !JD stabbing board; M/U saver sub on top drive; clamp and safety chains. ■ 09:00 - 11:30 2.50 12 B 1 CSGIN2 1 RIH w /liner and hanger on 5" drillpipe. Hit tight spot © 90'. Circulate, rotate 1/2 turn; work through. CBU. 11:30 - 12:00 0.50 1B CSGIN2 RIH w/ liner hanger and liner. 12:00 - 14:30 2.50 12 B CSGIN2 RIH w/ drillpipe. Rabbit pipe. Fill pipe (10 stands) 14:30 - 15:30 1.00 05 F CSGIN2 1 CBU 15:30 16:00 0.50 07 I CSGIN2 I Work on topdrive. 116:00 - 17:00 1.00 12 ' B CSGIN2 RIH. No problems. 17:00 - 21:00 4.00 12 B CSGIN2 Tagged bottom @ 12,300 ft. 1 21:00 - 00:00 3.00 05 F CSGIN2 Circulate and reciprocate hole clean and M/U cement head. 00:00 - 01:00 1.00 29 1 CSGIN2 Circulate. Hold PJSM. 01:00 - 01:30 j 0.50 12 C CSGIN2 P/U & M/U cement top drive head. Break circulation. 01:30 - 03:30 2.00 12 C CSGIN2 Test lines t/ 4500 psi. Cement liner. 03:30 - 04:00 0.50 12 C CSGIN2 'Drop plug. Displace w/ rig pump. 94 strokes /min for 4493 strokes. 04:00 - 05:00 1.00 12 D CSGIN2 1 Attempt to unsting f/ liner and set packer. 05:00 - 05:30 1 0.50 12 D CSGIN2 'Pressure up on packer to 4000 psi. Set packer and unsting from liner. 05:30 - 06:00 0.50 12 D CSGIN2 Break off cement head and pull 5 stands 12/11/2000 06:00 - 06:30 0.50 25 CSGIN2 Test casing. No test. 06 :30 - 07:00 0.50 05 F CSGIN2 Circulate 2X drillpipe capacity. 07:00 - 08:00 1.00 09 CSGIN2 Slip drilling line 102'. Blow down topdrive and kill line 08:00 - 12:00 4.00 06 G CSGIN2 POOH, lay down 5" drillpipe. 12:00 - 16:00 ' 4.00 25 CSGIN2 Lay down 5" drillpipe Printed: 2/22/2001 2:56:23 PM • • i FOREST OIL CORP. Page 14 of 15 Operations Summary 'Report Legal Well Name: Kustatan Field #1 Common Well Name: I N m Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - To Hours Code .Code Phase ! Description of Operations 12/11/2000 16:00 - 16:30 0.50 25 CSGIN2 1 Lay down Baker running tools. 16:30 - 17:30 1.00 25 CSGIN2 1 Left hole fluid level down. Inspect 9 -5/8" casing. Casing has hole at approximately 87.41' from rotary table. 17:30 - 18:30 1.00 25 CSGIN2 Lay down drill collars; jars; & HWDP 18:30 - 19:00 0.50 15 CSGIN2 Pulled wear ring; set test plug. 19:00 - 20:00 1 1.00 25 1 CSGIN2 Open doors on B.O.P.; change rams f/ 7" to 5 ". 20:00 - 20:30 1 0.50 15 CSGIN2 Tested BOP stack to 3000 psi. Tested OK 20:30 - 22:00 1 1.50 12 CSGIN2 Pick up cement head & break down. 22:00 - 00:00 2.00 05 1 CSGIN2 Clean up mud; gunning over shakers. 00:00 - 06:00 6.00 25 CSGIN2 Cleaning mud pits. 12/12/2000 06:00 - 09:30 3.50 25 CSGIN2 Clean mud pits. Transfer mud over shakers to volume pit. Clean trip tank. 09:30 - 12:00 2.50 15 B CSGIN2 Test choke manifold, outside kill line, top drive valve (low 250 psi; high 4000 psi). All valves, floor valves, Hydril (2500 psi), all rams (250 psi low; 4000 psi high); Koomey tested. 12:00 - 18:00 1 6.00 25 CSGIN2 Rig down flow line; fill up line; pitcher nipple; turnbuckles; drip pans. Rig up hydraulic lift lines to stack. Pick up slings, take off choke lines. 18:00 - 19:30 1.50 25 CSGIN2 PJSM. Raising BOP stack. 19:30 - 22:30 3.00 25 CSGIN2 Raise stack 1'. Tubing hanger & 9 -5/8" pack off would not release. Worked on freeing hanger, stub came free. Removed tubing spool, installed adapter spool. 22:30 - 00:00 1.50 19 E CSGIN2 Pick up and make up fishing tools. 00:00 - 02:00 2.00 19 E CSGIN2 POOH w/ casing stub and full joint (57.84 ft.) and inspect threads. 02:00 - 06:00 4.00 14 B CSGIN2 Nipple up BOP, hook up flow line and pitcher nipple. 12/13/2000 06:00 - 07:00 j 1.00 14 B CSGIN2 Reset hydraulic pick up slings, pick up BOP stack. 07:00 - 12:00 5.00 21 CSGIN2 Fill suction pit, pump across BOP. Clean around outside shakers and 1 dumps. Round up rental tools. Clean docks. Haul DP to to WMRU yard. 12:00 - 13:30 1.50 21 CSGIN2 Continue to clean rig while waiting on APRS. 13:30 - 14:00 0.50 19 E CSGIN2 Redress spear. Lay down single HWDP, pick up stand of HWDP. 14:00 - 16:00 2.00 19 E CSGIN2 Rig up APRS for freepoint 16:00 - 16:30 0.50 25 CSGIN2 1 Pre job safety meeting (Backing out casing - string shot) 16:30 - 17:00 0.50 19 E CSGIN2 'Apply reverse torque to casing string. String came free. Backed out. 17:00 - 17:30 0.50 19 E CSGIN2 POOH w/ 9 -5/8" casing 17:30 - 18:00 0.50 25 CSGIN2 Rig up to lay down casing. 18:00 - 21:30 3.50 25 CSGIN2 Lay down 10 joints 9 -5/8" BTC casing. 21:30 - 22:30 1.00 05 F CSGIN2 RIH w/ DP. Wash 5' over fish. Clean hole. POOH. 22:30 - 23:30 1.00 25 CSGIN2 Inspecting casing. 23:30 - 00:00 0.50 12 , A CSGIN2 Run casing. Seal rings installed in each connection. Torqued to 12,000 ft lbs. 00:00 - 06:00 6.00 12 D CSGIN2 Hang BOP. Set casing slips. Prepare to cut off 9 -5/8" casing. 12/14/2000 06:00 - 07:30 1.50114 1 B RDMO Back out of landing joint with x /o, cut off 24.33' of 9 5/8" csg. and lay down same. Make final cut. 07:30 - 12:00 4.50 14 B RDMO Set BOPs, pick up pick up slings. Remove spool, replace with tubing spool. 12:00 - 13:00 1.00 15 A RDMO Test pack -off void to 3000 psi. 15 min. test OK. 13:00 - 14:30 1.50 15 A RDMO Set wear -ring, R/U to test 9 5/8" csg., 7 5/8' csg. and liner lap. Test to 3000 psi. for 30 min. Test OK. 14:30 17:00 2.50 06 J RDMO RIH with 5" DP. 17:00 - 20:30 3.50 06 J RDMO Make -up bit, bit sub and float. RIH with DP. 20:30 - 04:30 8.00 22 B RDMO Lay down 5" DP.Break down fishing tools. 04:30 - 06:00 1.50 30 1 RDMO Prepare to nipple down BOPs. 12/15/2000 06:00 - 12:00 6.00130 RDMO Nipple down BOPs, lay down beaver slide. 1 Printed: 2/22 /2001 2:56:23 PM 6 • FOREST OIL CORP. P 15 of 15 Operations Summary Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 1 1 Date From - To Hours 1 Code Sub Phase Description of Operations I Code 12/15/2000 12:00 - 13:00 1.00 31 RDMO Install test plug in tbg. spool, make up kill line to tbg. spool. 13:00 17:00 4.00 01 B RDMO Rig down Tesco top drive, remove elevators, bails, service and hydraulic lines. Break quill loose. 17:00 - 18:00 1.00! 31 RDMO Remove test plug, make up abandoment head. 18:00 - 19:00 1.00 07 1 RDMO Clean cellar and rig floor. 19:00 - 20:00 1.00 31 RDMO Test 9 5/8' csg., two csg. valves, master valve and tree cap from 300 to 3000 psi. Also this was test 7 5/8" csg. and liner lap. Test was witnessed by L.Grimaldi, AAOGCC. 20:00 - 23:00 3.00 12 D RDMO Rig up to freeze protect 13 3/8" annulus and 9 5/8" csg. 30" below ground Ievel.Blew mud out of csg. and annulus and filled with Diesel 23:00 - 23:30 ! 0.50 07 RDMO Clean cellar. 23:30 - 00:00 0.50 01 B RDMO 1 PJSM Hang blocks to slip drlg to lay down top drive. Rig released @ 2400 Hrs. l j i ! ! I i Printed: 2/22/2001 2:56:23 PM f 0 0 1 Forest Oil Corporation oR 4' , k � Alaska Division 19 fr.7 16 la 310 K Street, Suite 700 , ,...1: Anchorage, Alaska 99501 Phone: (907) 258 -8600 Fax: (907) 258 -8601 DATA TRANSMITTAL Date: January 18, 2001 To: Lisa Weepie /Howard Oakland From: Barbara Murray AOGCC Forest Oil Corporation 3001 Porcupine Drive 310 K Street, Suite 700 Anchorage, AK 99501 Anchorage, AK 99501 Phone: (907) 279 -1433 Phone: (907) 258 - 8600 FAX: (907) 258 - 8601 TRANSMITTAL DESCRIPTION Well API Number Description Data From: apt Custatan #1 50 -133- 20496 -00 1-4m tape -LIS format - AIT /DSI /PEX for 1669.5' -6510' Schlumberger Kustatan #1 50- 133 - 20496 -00 1-4m tape -LIS format- AIT /DSI /PEX and SHDT Schlumberger halt picked dips for 6196'- 12321' V 1 1 ir) o °1' \ a__ ‘(\i, k V , a P . ) A _ \- .7\).J ‘ ( Q . .. SLA---6/Y71- Please sign below to acknowledge receipt. ( Received By: .p Date: I 'lLdt;GL- ( LORLFIti3 Returned to Forest Oil (Accepted By: Date Date Modified :01 /18 /2001 Kustatan #1 to AOGCC.xls /Pagel Date Prepared: 12/6/00 bk • • o R E s F O R E S T O I L C O R P O R A T I O N 0 ie 3 C7{ t • OW.4tte 700 CS /nc, aqe, C29-&rz 99507 0 1 V- (907) 258 -8600 • (907) 258 -8609 (C� x) January 12, 2001 Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: Well Completion Report and Log (Form 10 -407) Kustatan Field #1 Enclosed is Forest Oil's Well Completion Report and Log for the Kustatan Field #1 exploration well. Included are form 10 -407, well completion schematic, daily report summary and directional survey. The well was drilled as a vertical exploration well into the Hemlock formation. Due to non - commercial quantaties of oil, Forest Oil requested and was granted an Operations Shutdown on the well. This well will be used as a service well for the Redoubt Unit development. The well currently has a 11 " -5M x 3 1/8 " -5M tree adapter, 3 1/8 " -5M gate valve and 3" tree cap. The well and tree were bundle tested to 3,000 psi. If there are any questions, please contact me at 258 -8600. o (: V 7 l-lt;/Aej Paul White RECEIVED Drilling Manager - Alaska Division RECEIVED Forest Oil Corporation JAN 1 2 2001 Alaska Oil & Gas Cons. Commission Anchorage Z- . 7 . Q / . e-Y) - > , Z ",y rA-, / G_ 0 STATE OF ALASKA vro .. 4 0 ALASKA OIL AND GAS CONSERVATION COMMISSION ,1.____ WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL: GAS: SUSPENDED X ABANDONED: SERVICE: 2. Name of Operator 7. Permit Number Forest Oil Corporation 200 -153 3. Address 310 K Street, Suite 700 8. API Number Anchorage, Alaska 99501 50- 133 - 20496 -00 4. Location of well at surface - 9. Unit or Lease Name 3442' FNL, 1468' FWL, Section 4, TO7N, R14W, SM ) t' � N/A At Top Producing Interval 10. Well Number 3442' FNL, 1468' FWL, Section 4, TO7N, R14W, SM + /r_:;; Kustatan Field #1 At Total Depth o _ _ 11. Field and Pool 3 3442' FNL, 1468' FWL, Section 4, TO7N, R14W, SM '" �' � N/A 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. N/A 260 RKB ADL- 387023 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 15. Water Depth, if offshore 16. No. of Completions 10/16/00 12/3/00 12/16/00 n/a feet MSL 0 17. Total Depth (MD +TVD) 18. Plug Back Depth (MD +TVD) 19. Directional Survey 20. Depth where SSSV set 21. Thickness of Permafrost 12,300' MD / 12,300' TVD n/a Yes: x No: n/a feet MD n/a 22. Type Electric or Other Logs Run Quad Combo ,FMI 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 133# L -80 Surf. 120' driven n/a None 13 3/8" 68# L -80 Surf. 1,820' 17 1/2" 1478 cu ft None 9 5/8" 47# L -80 Surf. 6,500' 12 1/4" 644 cu ft None 7 5/8" 29.7 # L -80 6,312' 12,300' 8 1/2" 706 cu ft None 24. Perforations open to Production (MD +TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED n/a 27 PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) N/A N/A Date of Test Hours Tested PRODUCTION FOR OIL -BBL GAS -MCF WATER -BBL CHOKE SIZE GAS -OIL RATIO TEST PERIOD => Flow Tubing Casing Pressure CALCULATED OIL -BBL GAS -MCF WATER -BBL OIL GRAVITY -API (corr) Press. 24 -HOUR RATE _> 28 CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. RECEIVED No coring was done. JAN 1 2 ?nnl Alaska Oil & Gas Cons. Commission Form 10 -407 Anchorage Rev. 7 -1 -80 CONTINUED ON REVERSE SIDE Submit in duplicate 29. 1 30. S GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH SSTVD GOR, and time of each phase. 31. LIST OF ATTACHMENTS Well Schematic, Final Directional Survey 32. I hereby c- " that the foregoing is true and correct to the best of my knowledge Signed `1,J Title Drilling Manager Date ' 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 space 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 productin intervals for only 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 (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- RECENED jection, Gas Injection, Shut -in, Other - explain. Item 28: If no cores taken, indicate "none". J A N 1 2 2001 Form 10-407 Alaska Oil & Gas Cons. Commission Anchorage • • Kustatan Field #1 Completion RKB 260' MSL ri 9.5 ppg ,. Water Base Mud %.'. r+4 rbil 04 04 I+I 'I,1, r .: 20" 133 #,L -80 BTC 120' MD Driven ',X! * 13 3/8" 68 #, L -80 BTC ' ® 1820' MD 17 1/2" Hole %i t TOC 5000' MD ; A TOL 6312' MD 9 5/8" 47 #, L -80 BTC ` ` 6500' MD 12 1/4" Hole N. 7 -5/8" 29.7 #, L -80 STL / FL4S F/" � Liner Wiper Plug 12259'MD 8 1/2" Hole "' ✓ " %%'� 0 4 + f *0.# 12300' MD RECEIVED JAN 1 2 2001 Alaska Oil & Gas Cons. Commission Anchorage • FOREST OIL CORP �, = . .:R age Oper4tiont Surnma Re O Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date rm o To - Hours Cade Sub Phase ©escrtptiart of O er ons 10/12/2000 19:00 - 01 A MIRU Rigging up 10/13/2000 06:00 - 12:00 6.00 01 A MIRU Rigging up 12:00 - 06:00 18.00 01 A MIRU Rigging up 10/14/2000 06:00 - 12:00 6.00 01 A MIRU Hook up electric to top drive. Rig degasser lines. 12:00 - 00:00 12.00 01 A MIRU PJSM Rig up sub section flow line. Pull out centrifuge. Rig up stabbing board. Rig up V- doors. Help welder run 3" mud line for trip tank. Fill suction pit with water. Plumb in cellar tugger. Hook up fill -up line. Silicon cracks in pump room floor.Start berm around rig. put packing in test pump. 00:00 - 06:00 6.00 01 A MIRU Continue to rig up. 10/15/2000 06:00 - 12:00 6.00 01 A MIRU Welder working on mud line. Put blower motor on top drive. Put bails on top drive. Test electricity on top drive.Berm around rig. Rig down rig.Fill pits with water. Welding braden head to 20" conductor. Hook up monitors and cameras. Rig up wireline machine. 12:00 - 12:30 0.50 01 A MIRU PJSM Rig up remote accumulator line. 12:30 - 18:00 5.50 01 A MIRU Welding braden head on 20" casing. 18:00 - 21:00 3.00 01 A MIRU Allow weld on head to cool. Prep equipment for nipple up, while mixing spud mud. 21:00 - 00:00 3.00 14 I A MIRU Nipple up 20" diverter. 00:00 - 06:00 6.00 14 A MIRU Nipple up diverter line from cellar. Make up drilling nipple, flow line, hydraulic lines,and knife valve. 10/16/2000 06:00 - 12:00 6.00 14 A MIRU Making up driling nipple and flow line. Mixing mud. Test Hydril diverter and Knife valve. for AAOGCC test. Also Koomey test. Test OK.RoII mud pumps. Check alarms. H2S and methane gas calibrated. 12:00 - 18:00 6.00 14 A MIRU Nipple up flow nipple, flow line and fill up line. 18:00 - 20:00 2.00 25 MIRU Reading tools for spud in. 20:00 - 00:00 4.00 01 A MIRU Welder repairing slop tank. Dig trench for dump truck to haul cuttings. Lay liner and mats in trench. 00:00 - 03:00 3.00 01 A MIRU PJSM Pre -spud check list. 03:00 - 05:00 2.00 06 J DRLSUR Make up BHA. Tag @ 51'. Circ. check allmlines for leaks. 05:00 - 06:00 1.00 02 A DRLSUR .=Mfg from 51' to 65'. 10/17/2000 06:00 - 08:30 2.50 02 A DRLSUR drilling surface hole. 08:30 - 09:00 0.50 05 I DRLSUR Circulate 09:00 - 09:30 0.50 06 J DRLSUR POOH to pick up ' HWDP, 5" DP DCS, and jars. 09:30 - 16:00 6.50 26 DRLSUR Pick up 5 "DP, 5 "HWDP, and stand back in derrick. Pick up jars and stab. 16:00 - 16:30 0.50 06 1J DRLSUR RIH 16:30 - 18:00 1.50 02 A DRLSUR Drilling from 96' to 208'. 18:00 - 19:00 1.00 08 E DRLSUR Work on top drive. 19:00 - 23:00 4.00 26 DRLSUR Pick up stab. and three DCs. 23:00 - 00:00 1.00 02 A DRLSUR Drilling from 208' to 218'. 00:00 - 00:30 0.50 05 I DRLSUR Circ. while waiting on dump truck. 00:30 - 04:00 3.50 02 A DRLSUR Drilling from 218' to 294'. 04:00 - 04:30 0.50'05 I DRLSUR Circ. hole clean. RECEIVED 04:30 - 05:00 0.50 11 F DRLSUR Wirelie survey @ 290'. 05:00 - 06:00 1.00 02 A DRLSUR DrIg. from 290' to 315' 10/18/2000 06:00 - 16:30 ' 10.50 02 A DRLSUR Drilling 17 1/2" surface hole. PJSM 16:30 - 17:00 0.50 10 A DRLSUR Wireline survey. 1/2 deg. inc. JAN 1 2 2001 17:00 - 05:30 12.50 02 A DRLSUR Drilling surface hole. 05:30 - 06:00 0.50 ( 05 I DRLSUR Circulate for wireline survey. 10/19/2000 06:00 - 06:30 0.50 10 A DRLSUR Wireline Inc. survey Alaska Oil & Gas Cons. Commission 06:30 - 09:00 2.50102 A DRLSUR Drilling 17 1/2" surface hole. Anchorage 09:00 - 09:30 0.50' 05 I DRLSUR Ciculate, pump pill. Printed: 1/4/2001 9:02:44 AM • 1 • �x a FOREST OIL CORP, Page Operations Summa Re p ort 3 Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From To Hours Code Code Phase Rescriptlon of Operations 33 3 10/19/2000 09:30 - 11:00 1.50 06 A DRLSUR POOH, break bit off. 11:00 - 12:00 1.00 06 J DRLSUR Make up bit, run in holewith collars, service top drive. 12:00 - 13:00 1.00 08 E DRLSUR Work on top drive. 13:00 - 14:30 1.50 06 J DRLSUR Pick up three DCs. 14:30 - 16:00 1.50 07 DRLSUR Cut drlg. line. 16:00 - 17:00 1.00 06 A DRLSUR RIH 17:00 - 17:30 0.50 25 DRLSUR Circulate, orient Epoch. 17:30 - 22:30 5.00 02 A DRLSUR Drilling 17 1/2" hole. 22:30 - 23:00 0.50 05 I DRLSUR Circulate B /U. 23:00 - 23:30 0.50 10 A DRLSUR Wireline Inc. survey. 23:30 - 06:00 6.50 02 A DRLSUR Drilling 17 1/2" surface hole. 10/20/2000 06:00 - 10:30 4.50 02 A DRLSUR Drilling surface hole 10:30 - 11:00 0.50 11 A DRLSUR Run totco angle unit on wireline. RECEIVED E 11:00_11:30 0.50 05 I DRLSUR CBU 11:30 - 14:30 3.00 06 DRLSUR Trip to stabilizers 14:30 - 15:00 0.50 07 DRLSUR Clean rig floor JAN 1 2 2001 15:00 - 16:30 1.50 06 DRLSUR Trip in hole 16:30 - 17:00 0.50 02 A DRLSUR Drill to fit casing 17:00 - 18:30 1.50 05 F DRLSUR Circulate hole clean Alaska Oil & Gas Cons. Commission 18:30 - 19:30 1.00 11 DRLSUR Wireline survey Anchorage 19:30 - 20:00 0.50 05 DRLSUR Pump dry job 20:00 - 00:00 4.00 06 G DRLSUR Trip out to run casing n back 00:00 01:00 1.00 06 DRLSUR Break off bit, bit sub, stand ba co llars 01:00 - 02:30 1.50 12 DRLSUR Pick up casing equipment 02:30 - 03:00 0.50 12 DRLSUR Safety pre job meeting. 03:00 - 04:00 1.00 12 DRLSUR Rig up to run 13 3/8" casing. 04:00 - 06:00 2.00 12 DRLSUR Running casing 10/21/2000 06:00 - 10:30 4.50 12 RUN CASING 10:30 - 12:00 1.50 12 RETRIEVE CASING BACK TO SURFACE, AND CUT OFF TWO CENTRALIZERS. 12:00 - 13:30 1.50 12 CHANGE OUT BAILS 13:30 - 22:30 9.00 12 RUN CASING 22:30 - 00:00 1.50 12 RIG DOWN CIRULATING HOSE, PULL MASTER BUSHING TO CUT CASING. 00:00 - 03:00 3.00 12 CUT LANDING JOINT 4 INCHES BELOW DRILLING NIPPLE 03:00 - 04:30 1.50 12 TRIP IN THE OUT OF DERRICK, AND PICK UP 7 JOINTS OF 5" DRILL PIPE 04:30 - 05:00 0.50 12 SAFETY MEETING WHILE CIRCULATING 05:00 - 05:30 0.50 12 CIRCULATE 05:30 - 06:00 0.50 12 PRESSURE TEST LINES, BEGIN PUMPING 50 BBLS SPACER 10/22/2000 06:00 - 06:30 0.50 12 C TEST LINES TO 1500, PUMP WATER 06:30 - 08:00 1.50 12 C CEMENT JOB 08:00 - 12:00 4.00 14 A PULL ONE STAND, PUMP DOWN DRILL PIPE WIPER PLUG, RIG I DOWN DIVERTER. 12:00 - 12:30 0.50 14 A REMOVE DIVERTER KNIFE 12:30 - 14:30 2.00 12 D RIG DOWN CEMENT CIRCULATING HOSE AND HEAD- MAKE UP TOP DRIVE SAVER SUB 14:30 - 16:00 1.50 06 G TRIP OUT OF HOLE WITH STING IN ASSEMBLY - LAY DOWN 2 JTS OF 5 " DP THAT WAS NOT WIPED. 16:00 - 16:30 0.50 25 PRE JOB SAFTEY MEETING FOR WORKING ON BOP STACK. NIPPLE DOWN/ NIPPLE UP NABORS POLICY 16:30 - 19:30 3.00 14 B RIG DOWN 20" RISER & LAY DOWN 19:30 - 20:30 1.00 14 B RIG UP SLINGS/ PICK UP ANNULAR Printed 1/4/2001 9.02:44 AM • 1 FOREST 011 C0R gage 0;1 Operations Sumaryeport Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date, From To Hours Co de Subp, Phase De scnptlonaf O perattbris /A 10/22/2000 20:30 - 21:00 0.50 14 B WELDER MADE ROUGH CUT ON 13 3/8" 21:00 - 22:30 1.50 14 B LAY DOWN CUT OFF SECTION OF 13 3/8" CSG, MOUSE HOLE, 'V' DOOR RAMP 22:30 - 00:00 1.50 14 B WELDER CUT OFF 20 ", MAKE EXPERT CUT ON 13 3/8" FOR SLIP LOCK SPOOL FROM VETCO. 00:00 - 02:30 2.50 14 B GRIND /DRESS OFF CUT ON 13 3/8" 02:30 - 03:30 1.00 14 B INSTALL VETCO GREY SLIP LOCK SPOOL AT GROUND LEVEU TEST TO 2000 PSI FOR 15 MINS. 03:30 - 06:00 2.50 14 B INSTALL SPACER SPOOUDOUBLE GATE /MUD CROSS 10/23/2000 06:00 - 12:00 6.00 14 B CSGSUR NIPPLE UP HYDRIL, DRILL NIPPLE, FLOWLINE, TRIP TANK FLOW LINE 12:00 - 15:00 3.00 14 B CSGSUR INSTALL 'V' DOOR RAMP, MOUSE HOLE 15:00 - 19:30 4.50 07 CSGSUR REPLACE ACTUATOR VALVE AND SAVER SUB ON TOP DRIVE. 19:30 - 00:00 4.50 14 B CSGSUR CHANGE BOTTOM RAMS F/ 2 7/8" TO 5" AND RIG UP TO TEST BOP'S 00:00 - 03:00 3.00 15 A CSGSUR NIPPLE UP CHOKE LINE, FINISH RIGGING UP TO TEST 0300 0061 6:00 3.00 15 A CSGSUR TEST BOP'S 10/24/2000 06:00 - 08:30 2.50 07 DRLIN1 SET WEAR RING 08:30 - 10:30 2.00 07 DRLIN1 INSTALL DRIP PANS 10:30 - 15:00 4.50 08 DRLIN1 REPLACE ACCTUATOR VALVE ON TOP DRIVE. 15:00 - 18:00 3.00 06 DRLIN1 PRE JOB SAFETY MEETING, MAKE UP BHA #3 18:00 - 20:00 2.00 06 DRLIN1 TRIP TO 852' 20:00 - 22:30 2.50 09 DRLIN1 SLIP AND CUT DRILL LINE. 22:30 - 23:30 1.00 15 DRLIN1 TEST TIW VALVE, NOTIFY STATE MAN OF PASSED TEST. 23:30 - 00:00 0.50 06 DRLIN1 PICK UP SINGLES, TRIP IN THE HOLE. 00:00 - 02:30 2.50 06 DRLIN1 PICK UP SINGLES, TRIP IN THE HOLE. 02:30 - 04:00 1.50 05 DRLIN1 CIRCULATE OUT CEMENT, FROM 200 GPM TO 450 GPM WHILE SLOWLY ROTATING. SHAKERS LOADED UP. 04:00 - 04:30 0.50 16 DRLIN1 PRE JOB MEETING, TEST CASING TO 3000 PSI. 04:30 - 06:00 1.50 02 DRLIN1 DRILL COLLAR, CEMENT, AND SHOE. 10/25/2000 06:00 - 09:30 3.50 02 D DRLIN1 Drill cement below float collar 09:30 - 11:00 1.50 02 D DRLIN1 DriU shoe. 11:00 - 11:30 0.50 02 A DRLIN1 Drift 20 feet of new hole. 11:30 - 12:00 0.50 05 A DRLIN1 Circulate for FIT. Mud WT in 9.0 ppg / Mud WT out 9.0 ppg 12:00 - 12:30 0.50 05 A DRLIN1 Circulate / Prejob safety meeting W / Crew change / Explain what to do for FIT. 12:30 - 13:00 0.50 02 A DRLIN1 Perform FIT. 9.0 PPG mud in hole. EMW =11.O PPG Held 190 Psi for 5 mins. Recorded on chart. 13:00 - 20:00 7.00 02 A DRLIN1 Drilling 20:00 - 20:30 0.50 05 A DRLIN1 Circulate hole clean for survey. 20:30 - 21:00 0.50 10 A DRLIN1 Angle unit survey with slick line. �� 21:00 - 00:00 3.00 02 A DRLIN1 Drilling 00:00_ 03:00 3.00 02 A DRLIN1 Drilling 03:00 - 03:30 0.50 05 A DRLIN1 Circulate hole clean for survey 03:30 - 04:00 0.50 10 A DRLIN1 Angle unit survey with slick line. JA N 1 2 2001 04:00 - 06:00 2.00 02 A DRLIN1 Drilling 10/26/2000 06:00 - 07:00 1.00 02 A DRLIN1 Rotating ahead 07:00 08:00 1.00 02 A DRLIN1 Change shaker screens Alaska Oil & Gas Cons. Commission 08:00 - 12:30 4.50 02 A DRLIN1 Rotating ahead Anchorage 12:30 - 13:30 1.00 05 A DRLIN1 Pump high viscosity sweep around. 113:30 - 14:00 0.50 10 A DRLIN1 Run totco angle unit on slick line. 14:00 - 14:30 0.50 05 A DRLIN1 Record slow pump rates, pump dry job. 14:30 - 18:30 4.00 06 H DRLIN1 Short trip. Printed: 1/4/2001 9:02:44 AM • FOREST OIL .CORP Page 4 of I „a pec ions S Reps l g ff 3 3� r i Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 �s. Date Fred T o Hours Code „ ode Phase Descrlptlof of�O� era 1o)s otr 10/26/2000 18:30 - 19:30 1.00 06 H DRLINI Service top drive & draw works. 19:30 - 00:00 4.50 06 H DRLINI Trip in picking up singles off pipe rack. 00:00 - 06:00 6.00 02 A DRLIN1 Rotating ahead. � � � w VVT „� 10/27/2000 06:00 - 07:00 1.00 02 A DRLINI Drilling ahead. 07:00 - 08:00 1.00 05 A DRLINI Circulate while changing shaker screens. 08:00 - 09:30 1.50 02 A DRLIN1 Drilling ahead. 09:30 - 10:00 0.50 05 A DRLIN1 Circulate hole clean. JAN 2 2001 10:00 - 11:00 1.00 10 A DRLIN1 Run slick line unit for totco angle survey. 11:00 - 22:00 11.00 02 A DRLIN1 Drilling and surveying every 5 stands. 22:00 - 23:00 1.00 05 A DRLIN1 Circulate for survey, pump high vis sweep. AiaSka Oil & Gas Cons. C0mmiss4on 23:00 - 00:00 1.00 10 A DRLIN1 Run slick line unit for totco angle survey. Anchorage 00:00 - 04:00 4.00 02 A DRLIN1 Drilling 04:00 - 05:00 1.00 05 A DRLIN1 Circulate, pump dry job. 05:00 - 06:00 1.00 06 J DRLINI Trip out of hole for PDC bit and Mud Motor. 10/28/2000 06:00 - 10:00 4.00 06 A DRLIN1 Tripping 10:00 - 12:00 2.00 06 J DRLIN1 Change bit and BHA 12:00 - 12:30 0.50 07 DRLIN1 PJSM Clean rig floor 12:30 - 16:30 4.00 06 J DRLIN1 Finish w/ BHA change RIH w/ BHA to 860'. 16:30 - 17:30 1.00 07 DRLIN1 Service rig, blocks and top drive. 17:30 - 21:30 4.00 06 J DRLIN1 TIH -P /U 5" DP (69 jts.) from pipe rack. Rabbit each jt. Fill pipe at the shoe. 21:30 - 22:00 0.50 02 A DRLIN1 Break circ. Drilling from 4265' to 4267' ADT 1/4 hr. 22:00 - 05:00 7.00 08 A DRLIN1 Flow line plugged with excessive clay returns. Attemted to jet flow line with no luck. RemoveFlow paddle and break apart flow line to clean same, while working pipe. Remove bushings, drip pan clean drilling nipple flow line and possum belly. Clean and replace. 05:00 - 06:00 1.00 05 I DRLIN1 Circulate slowly to circulate clay from hole. 10 stks. /min.lncrease circulation as hole cleans up. 10/29/2000 06:00 - 08:00 2.00 05 1 DRLIN1 Circulate clay from hole © 10 to 50 SPM. 08:00 - 18:30 10.50 02 A DRLIN1 Drilling from 4267' to 4607'. 18:30 - 19:30 1.00 05 1 DRLIN1 Pump Hi -Vis sweep. CBU for survey. 19:30 - 20:30 1.00 11 DRLIN1 Wireline survey @ 4509'. 3/4 Deg. 20:30 - 02:00 5.50 02 DRLIN1 Drilling from 4607' to 4796'. Set clocks back one hour for DST. 01:00 - 01:30 0.50 07 DRLIN1 Sevice top drive. 01:30 - 02:00 0.50 02 A DRLIN1 Drilling 12 1/4" hole. 02:00 - 03:00 1.00 02 DRLIN1 Two pump pressure spikes. Pump pressure increased to 3000 PSI., while drilling from 4810' to 4817'. ROP decreased to 6'- 8' /hr. 03:00 - 04:30 1.50 05 I DRLIN1 CBU @ 0 strokes due to pump pressure increase. Monitor well. Pump dry job. 04:30 - 06:00 1.50 06 DRLIN1 POOH 10/30/2000 06:00 - 08:00 2.00 06 A DRLINI Tripping out of hole. 08:00 - 10:00 2.00 06 J DRLIN1 Work BHA. Clean stabilizers. Bit jets plugged with rubber from mud motor. 10:00 - 10:30 0.50 07 DRLIN1 Clean rig floor. 10:30 - 11:00 0.50 06 J DRLIN1 Lay down motor, x -o sub and float sub. 11:00 - 12:00 1.00 06 J DRLIN1 Dress new bit- Change BHA. 12:00 - 12:30 0.50 07 DRLIN1 PJSM Clean rig floor. 12:30 - 15:00 2.50 06 1 J DRLIN1 Make up new bit and change BHA. 15:00 - 16:30 1.50 06 DRLIN1 RIH to 1763'. 16:30 - 18:00 1.50 DRLIN1 Fill pipe and circ. Service rig blocks and top drive. 18:00 - 18:30 0.50 06 DRLIN1 RIH from 1763' to 3078'. 18:30 - 19:30 1.00 05 I DRLIN1 Fill drill pipe and circ. bottoms up. 19:30 - 20:00 ! 0.501 06 DRLIN1 RIH from 3078' to 4817' with no problems. Printed: 11412001 9:02'44 AM • +� } FO J I . CORP. Page(5 3 3 � � !> 11 NI Report Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date rom - To .Hobs Cider 3 Rhase DescrlptiGn of Operaticnsi' 10/30/2000 20:00 - 02:30 6.50 02 A DRLIN1 Drilling 12 1/4" hole. 02:30 - 03:00 0.50 05 DRLIN1 Circ. Hi -Vis sweep. PJSM 03:00 - 04:00 1.00 11 DRLIN1 Survey @5006'. 1/2 deg. 04:00 - 06:00 2.00 02 A DRLIN1 Drilling 12 1/4" hole. 10/31/2000 06:00 - 16:00 10.00 02 A DRLIN1 Rotary drilling 12 1/4" hole. 16:00 - 17:00 1.00 06 H DRLIN1 POOH six stands short trip to repair leak on top drive. 17:00 - 21:30 4.50 08 E DRLIN1 Repair oil leak on top drive. 21:30 - 22:00 0.50 06 DRLIN1 RIH from 4766' to5329'. 22:00 - 04:30 6.50 02 A DRLINI Drilling 12 1/4" hole. 04:30 - 05:00 0.50 07 A DRLINI Rig Service. 05:00 - 06:00 1.00 02 A DRLIN1 Drilling 121/4" hole. 11/1/2000 06:00 - 11:00 5.00 02 A DRLIN1 Drilling 12 1/4" hole. 11:00 - 13:00 2.00 05 1 DRLIN1 Pump Hi -Vis sweep, circulate bottoms up. Drop survey. 13:00 - 17:00 4.00 06 A DRLIN1 POOH 17:00 - 17:30 0.50 07 DRLIN1 Remove blower hose from top drive. Reset crowm -o- matic. 17:30 - 19:00 1.50 DRLIN1 POOH with BHA. Retrieve survey. 19:00 - 19:30 0.50 07 DRLIN1 Clean rig floor. 19:30 - 20:00 0.50 15 DRLIN1 Pull wear ring. Rig up to test BOPs. 20:00 - 21:30 1.50 15 DRLIN1 Test all rams, floor safety valve, choke manifold, choke and kill lines to 250/3000 psi.Pressure test annular preventor to 250/2500 psi. 21:30 - 22:30 1.00 15 DRLIN1 Rig down testing equipment and set wear ring. 22:30 - 01:00 2.50 06 DRLIN1 PJSM. Make up new bit and RIH with BHA. Strap, rabbit and pick up 9 jts. 5" HWDP. RIH to shoe. 01:00 - 02:00 1.00 07 DRLIN1 Hook up crown saver electric bell ringer. Drain oil from top drive. (overfull) Service top drive, blocks,fill pipe. 02:00 - 04:30 2.50 06 DRLIN1 RIH to 4300'. Fill pipe. 04:30 - 06:00 1.50 02 DRLIN1 Break circulation © 5500'. Wash and ream to bottom, no fill. Drilling from 5547' to 5565'. 11/2/2000 06:00 - 16:30 10.50 02 A DRLIN1 Drilling 121/4" hole. 16:30 - 17:30 1.00 DRLIN1 Pump Hi -Vis sweep, CBU for survey. 17:30 - 18:30 1.00 11 F DRLIN1 Wireline survey @ 5840'- 1 deg. 18:30 - 03:00 8.50 02 A DRLIN1 Drilling 12 1/4' hole. Check crown o matic. O.K. 03:00 - 06:00 3.00 02 A DRLIN1 Drilling 12 1/4" hole. 11/3/2000 06:00 - 09:00 3.00 02 A DRLIN1 Drilling 12 1/4" hole. 09:00 - 10:30 1.50 05 I DRLIN1 Pump Hi -Vis sweep. circ. hole clean. 10:30 - 11:30 1.00 10 DRLIN1 Wireline survey @ 6306' PJSM 11:30 - 16:30 5.00 02 A DRLIN1 Drilling 12 114" holeT.D. 121/4 "hole @ 6500'. 16:30 - 18:00 1.50 05 1 DRLIN1 Circ. 1i-Vis sweep. CBU 18:00 - 20:30 2.50 06 C DRLIN1 POOH 10 std. short trip. Work tight hole from 5692' to 5504'. RIH. 20:30 - 22:30 2.00 05 D DRLIN1 Pump Hi -Vis sweep. Circ. hole Ilea, whie working and rotating pipe. 1 1/2 circulations. Mix dry job. 22:30 - 00:00 1.50 06 C DRLIN1 POOH 00:00 - 00:30 0.50 25 DRLIN1 Pump dry job, blow down top drive. 00:30 - 02:00 1.50 06 C DRLIN1 POOH SLM 02:00 - 03:30 1.50 06 DRLIN1 Pooh w/ BHA. Clean clay from stabs. Break bit. 03:30 - 04:00 0.50 07 DRLIN1 Clean rig floor. RECEIVED 04:00 - 05:15 1.25 11 A DRLIN1 Rig up SWS and make up logging tools. 05:15 - 06:00 0.75 11 A DRLIN1 Running in hole with SWS wireline. 11/4/2000 06:00 - 09:00 3.00 11 A DRLIN1 RIH with SWS. Legging. JAN 1 2 2001 09:00 - 10:30 1.50 11 A DRLIN1 I Rig down SWS. Clean mud from tools. 10:30 - 11:00 0.50 07 DRLIN1 Clean rig floor. AS( R � 11:00 - 14:00 3.00 14 E DRLIN1 Drain BOPs. Pick up test joint. Pull wear ring. 5 C Iq • - bottom rams from 5" to 9 5/8 ". Test doors to 3000 PSI.Re B ': Printed: 1/4/2001 9:02:44 AM FOREST OIL CORD Page 6 of 1 � Operations Sumnrrary F; ep ` ' ... Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From l iTO Hours Cad S e .. ;ub Phase De� tior of Operatto s 4 Code �' 11/4/2000 11:00 - 14:00 3.00 14 E DRLIN1 Break and lay down lower IBOP valve from top drive. 14:00 - 15:00 1.00 12 A DRLIN1 Rig up to run 9 5/8" casing. Pick up Lafluer tool. 15:00 - 16:00 1.00 12 A DRLIN1 Rig up bales, elevators and slips. 16:00 - 17:00 1.00 12 A DRLIN1 Rig up stabbing board. Rig up air line for slips. 17:00 - 17:30 0.50 12 A DRLIN1 PJSM 17:30 - 18:00 0.50 12 A DRLIN1 Make up shoe and float collar. 18:00 - 02:30 8.50 12 A DRLIN1 Run 162 jts. 9 5/8" csg. 02:30 - 04:00 1.50 12 C DRLIN1 Circ. @ 6496' 04:00 - 05:00 1.00 12 A DRLIN1 Break out and lay down Lafluer head. Blow down top drive.Make up landing joint, cement head and hose. 05:00 - 05:30 0.50 12 C DRLIN1 Break circulation and tag bottom @ 6500' while circulating.PJSM 05:30 - 06:00 0.50 12 DRLIN1 Test cmt lines to 3000PSI. OK 11/5/2000 06:00 - 08:00 2.00 12 C CSGIN1 Drop plug, 5 bbl. MESAH2O, kick out plug. Stop and reload head. Pump 43 bbl. MCS -A H2O, 72.5 bbl. lead slurry @ 12.5 ppg., 42.3 bbl. tail slurry 15.8 ppg. Drop plug 5 bbl. H2O, switch over to rig pumps. stop reciprocating casing @ 3500 strokes, bump plug @ 3970 strokes. 08:00 - 12:00 4.00 14 B CSGIN1 Pull cement hoses and drain. Prepare BOPs to pick up to set casing slips. Remove flow lines, hook up cable and cable clamp BOP lifter. 12:00 - 13:00 1.00 14 B CSGIN1 PJSM Lift stack with rig hydraulics. 13:00 - 13:30 0.50 CSGIN1 Set casing slips with 115000 #. 13:30 - 14:00 0.50 14 B CSGIN1 Cut hole in 9 5/8" casing, drain and rough cut. 14:00 - 16:30 2.50 14 B CSGIN1 Let down stack, take off cement head. Rig down hydraulic lift system. Lay down 9 5/8" cut off.Lay down elevators. 16:30 - 17:00 0.50 14 B CSGIN1 Start finish cut on 9 5/8" casing. 17:00 - 21:00 4.00 14 CSGIN1 Pick up Vetco Gray tubing spool, fill with packing. test to 3800 PSI. Test OK. 21:00 - 01:00 4.00 14 B CSGIN1 Nipple up BOP, tubing spool, change lower rams to 5 ". Nipple up flow line. Hook up turnbuckles. 01:00 - 05:00 4.00 15 A CSGIN1 Pick up test joint and test plug. Test choke manifold, upper and lower IBOP valves. Test floor valves, choke and kill line valves. Test top, bottom and blind rams - 250/4000 PSI. test hydril- 250/3000 PSI. Set wear bushing, lay down test joint. 05:00 - 06:00 1.00 14 E CSGIN1 Install drip pans under rotary table. 11/6/2000 06:00 - 09:30 3.50 14 B DRLIN1 Finish installing drip pans, hoses. Clean cellar and sub base. 09:30 - 12:30 3.00 06 J DRLIN1 RIH with 12 1/4" BHA and lay down same- RECEIVED 12:30 - 16:30 4.00 06 A DRLIN1 Pick up 8 1/2" BHA. 16:30 - 18:00 1.50 06 A DRLIN1 RIH to 2031'. 18:00 - 18:30 0.50 05 I DRLIN1 Break circulation @ 2031'. 18:30 - 19:30 1.00 06 A DRLIN1 RIH to 3906'. JAN 1 2 2001 19:30 - 20:30 1.00 05 I DRLIN1 Break circulation @ 3906'. 20:30 - 22:00 1.50 06 A DRLIN1 RIH, tagged float collar @ 6418.6'. 22:00 - 22:30 0.50 05 I DRLIN1 Break circulation @ 6418, CBU. Alaska Oil &Gas COILS. Commission 22:30 - 23:00 0.50 09 DRLIN1 Slip 100' of drilling line. Anchorage 23:00 - 06:00 7.00 08 E DRLIN1 Prepare to lay down top drive. Lay down bales and elevators and remove lower IBOP.Move block hanging line. Remove kelly hose and blower hose. Lay down stabbing board. Install transport pins. Fold derrick board up. Close storm doors in board. Drain oil from top drive. Pin erection rigging to blocks and latch rigging to torque guide clamps. Release tension in torque cables. Tuen power off and disconnect I electric and hydraulic cables. Unlatch from harpoon. Lay down beaver slide. Remove windwalls. 11/7/2000 06:00 - 07:00 1.00 01 A DRLIN2 I Lower grasshopper on Can -Rig top drive and spool up electric cables and hydraulic hoses. Printed: 1/4/2001 9.02.44 AM v L';,„ ?RP Page 7 of 15 3 1 III FOREST- � ',:: ' ' ' z Operations Summary R Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Dte From = To Hours Code `. S tab Phas 44 ©e of D erabto t 1 Code p 11/7/2000 07:00 - 10:30 3.50 01 A DRLIN2 Tie onto top drive torque guide, pull out and lower top drive. Position and install tail roll section to same. Position truck and lower top drive and load on truck. 10:30 - 11:30 1.00 01 DRLIN2 Install two windwalls on sub and set beaver slide and catwalk. 11:30 - 12:00 0.50 01 DRLIN2 Prepare to install work basket on top of blocks. 12:00 - 14:00 2.00 01 DRLIN2 Weld platform to top of blocks. 14:00 - 15:30 1.50 01 DRLIN2 Run blocks to crown and dismantle top drive spear.Lower to floor. 15:30 - 17:30 2.00 01 DRLIN2 Run back to crown to dismantle spear hanger baskets. take off lower top drive rail clamps from derrick. 17:30 - 19:30 2.00 01 DRLIN2 Lay all Can -Rig parts down. 19:30 - 21:00 1.50 01 DRLIN2 Take platform off top of blocks. 21:00 - 22:30 1.50 01 DRLIN2 P/U SWIVEL &SERVICE. 22:30 - 23:30 1.00 01 DRLIN2 PREPARE TO P/U TESCO TORQUE TUBE, MAKING IT UP ON PIPE RACK. 23:30 - 00:00 0.50 01 A DRLIN2 P/U TESCO TORQUE TUBE. 00:00 - 00:30 0.50 01 DRLIN2 PJSM W/ TESCO R/U TESCO TORQUETUBE. 00:30 - 06:00 5.50 01 DRLIN2 P/U TD. TRQ. TUBE TO RIG FLOOR, TIE ON TO BLOCKS. FINISH STACKING TRQ. TUBE UP TO RIG FLOOR. HANG SAME @ CROWN, TAKE MEASUREMENT, BOLT PATTERN TO DERRICK RAIL. UNHANG TRQ. TUBE, DROP BTM. SECTION AND NEXT 18 FT. SECTION & SWAP OUT WITH 15 FT. SECTION. 11/8/2000 06:00 - 07:00 1.00 01 A DRLIN2 FINISH HANGING TESCO TORQUE TUBE. 07:00 - 08:30 1.50 01 DRLIN2 INSTALL T -BAR & CLAMP TO DERRICK. 08:30 - 09:00 0.50 01 A DRLIN2 HANG BLOCK HANGING LINE. 09:00 - 11:30 2.50 01 A DRLIN2 RIG UP CEMENT HOSE TO CIRC. HOLE & COND. MUD @ SLOW RATE DUE TO THICK MUD. 11:30 - 12:00 0.50 01 A DRLIN2 HOOK UP RIG UP SLINGS & SET TESCO TOP DRIVE & RACK ON L _ RIG FLOOR. 12:00 - 13:00 1.00 01 A DRLIN2 SCREW SWIVEL INTO TOP DRIVE. 13:00 - 14 :00 1.00 01 A DRLIN2 TAKE TOP DRIVE OUT OF CRADLE, RIG UP HYD. LINE. ° 0 14:00 - 15:00 1.00 01 A DRLIN2 R/U TORQUE BUSHING TO TOP DRIVE. tea,, c..1 c) 15:00 - 16:00 1.00 01 A DRLIN2 HOOK UP TOPDRIVE HYD. RAMS. 16:00 - 18:00 2.00 01 A DRLIN2 HANG HYD. HOSES IN DERRICK. v 1800 - 1900 1.00 01 A DRLIN2 HOOK UP HYD. HOSES TO POWER PACK. 2 ¢ 19:00 - 22:00 3.00 01 A DRLIN2 START UP TESCO, FUNCTION TEST & SET PRES. CONTROLS. Bo ' ,Q 22:00 - 00:00 2.00 01 A DRLIN2 R/U SAVER SUB, BALES, ELEVATORS & ADJUST TORQUE U..1 '7 C3 BUSHING. �/ Y 00:00 - 04:00 4.00 01 A DRLIN2 HOLD 15 MIN. PJSM. INSTALL TURN BUCKELS & RACHET STRAPS l'®° TO TORQUE TUBE. WRAP HYD. HOSES WITH TARP. HOOK UP STAND PIPE & KELLY HOSE. 04:00 - 04:30 0.50 01 A DRLIN2 TEST UPPER & LOWER I.B.O.P. VALVE 4,000 & 250 P.S.I. 104:30 - 05:30 1.00 09 DRLIN2 HOLD P.J.S.M. & CUT DRLG. LINE. 05:30 - 06:00 0.50 05 DRLIN2 CIRCULATE MUD. 11/9/2000 06:00 - 07:30 1.50 05 A DRLIN2 CIRCULATE & CONDITION MUD. 07:30 - 08:00 0.50 25 DRLIN2 CASING INTEGRITY TEST TO 3,000 P.S.I. FOR 30 MIN. 08:00 - 10:00 2.00 02 D DRLIN2 DRILLING FLOAT COLLAR & CEMENT TO 6,430 FT. 10:00 - 10:30 0.50 01 A DRLIN2 CIRCULATING BOTTOMS UP. 10:30 - 12:00 1.50 01 A DRLIN2 ADD S PIPE TO TESCO GOOSE NECK, TIGHTEN SWIVAL PACKING & WRAP 75' TARP AROUND SERVICE HOSES FOR 1 TOPDRIVE. 1 12:00 - 13:00 1.00 01 A DRLIN2 FINISHED INSTALLING TARP ON TOPDRIVE SERVICE HOSES. 13:00 - 13:30 0.50 02 D DRLIN2 DRILL C NT F/ 6,430' TO 6,444'.' 13:30 - 14:00 0.50 05 DRLIN2 STOP DRLG. CIRCULATE CONTAMINATED MUD. Printed: 1/4/2001 9:02:44 AM • ....,,. FOREST OIL CORP *::;........ Page8of15 Operations Summary Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date � .Pror - To ' Nor rs Code Sub Phase Qescrlption of Operations Code 11/9/2000 14:00 - 18:00 4.00 02 D DRLIN2 DRILL F/ 6,444' TO 6,524'. 18:00 - 20:30 2.50 05 A DRLIN2 CIRC. & COND. CONTAMINATED MUD. 20:30 - 21:00 0.50 02 A DRLIN2 FAT: =TO* 5 . 21:00 - 00:00 3.00 02 A DRLIN2 DRILL FROM 6,524 TO 6,577. 00:00 - 06:00 6.00 02 A DRLIN2 DRILL FROM 6,577 TO 6,660 11/10/2000 06:00 - 08:30 2.50 02 A DRLIN2 DRLG. 8.5 HOLE 08:30 - 09:00 0.50 05 A DRLIN2 CIRC. BOTTOMS UP. 09:00 - 09:30 0.50 01 A DRLIN2 BLOW DOWN TOPDRIVE, INSTALL WIRELINE GUIDE ON SAME. 09:30 - 11:00 1.50 11 A DRLIN2 RIH W/ WIRELINE & SURVEY © 6677'. 11:00 - 12:00 1.00 02 A DRLIN2 DRLG FROM 6,709 TO 6,721 12 :00 - 00:00 12.00 02 A DRLIN2 DRLG FROM 6721 TO 6898 00:00 - 06:00 6.00 02 A DRLIN2 DRLG FROM 6898 TO 6898 11/11/2000 06:00 - 10:00 4.00 02 A DRLIN2 DRLG. 8.5 HOLE. 10:00 - 10:30 0.50 05 I DRLIN2 CIRC. BOTTOMS UP. 10:30 - 11:00 0.50 11 A DRLIN2 DROP SURVEY @ 6987. 11:00 - 12:00 1.00 11 A DRLIN2 POOH TO SHOE. BLOW DOWN TOPDRIVE. RETRIEVE WIRELINE SURVEY. 12:00 - 13:00 1.00 11 A DRLIN2 RETRIEVE WIRELINE SURVEY.(NO RUN) SERVICE TOPDRIVE. 13:00 - 13:30 0.50 07 DRLIN2 SERVICE RIG. 13:30 - 14:00 0.50 12 D DRLIN2 WELD GUSSETS BETWEEN 20" & 13 3/8 ". 14:00 - 15:00 1.00 26 DRLIN2 P/U 5 " DP 18 Jts to 6995 15:00 - 16:00 1.00 10 DRLIN2 Run Wireline Survey ( line broke when POH @ 5520') 16:00 - 18:00 2.00 06 DRLIN2 POH 15 STDS splice wireline - retreive survey tool 18:00 - 19:00 1.00 06 DRLIN2 Ran back to BTM 19:00 - 00:00 5.00 02 DRLIN2 DRLG F/7024' T/7066 00:00 - 05:30 5.50 02 A DRLIN2 DRLG F/ 7066 T/ 7121 05:30 - 06:00 0.50 08 A DRLIN2 STAND BACK ONE STAND DP, TIGHTEN WASH PIPE PACKING. 11/12/2000 06:00 - 07:00 1.00 08 A DRLIN2 CIO SWIVAL WASH PIPE & PACKING. 07:00 - 12:00 5.00 02 A DRLIN2 DRLG. 8.5" HOLE f/ 7121 to 7195 ft. 12:00 - 15:30 3.50 02 A DRLIN2 DRLG. 8.5" HOLE f/ 7195 to 7233 ft. 15:30 - 16:30 1.00 05 I DRLIN2 CIRC. BTM. UP. 16 :30 - 17:00 0.50 10 B DRLIN2 DROP SURVEY © 7,213, PUMP DRY JOB. 17:00 - 17:30 0.50 08 B DRLIN2 WORK ON TOP DRIVE & BLOW DOWN. 17:30 - 22:30 5.00 06 A DRLIN2 POH. 22:30 - 00:00 1.50 06 J DRLIN2 P/U MUD MTR, BIT SUB, XO, RIH DCS. 00:00 - 01:00 1.00 06 J DRLIN2 M/U BHA 01:00 - 03:00 2.00 08 A DRLIN2 REPOSITION TOP DRIVE HYD. LINES & WORK ON RPM ADJ. REPOSITION KELLY HOSE. 03:00 - 06:00 3.00 06 J DRLIN2 RIH, TEST # 1 MUD PUMP T /FILL UP LINE. 11/13/2000 06:00 - 07:30 1.50 06 J DRLIN2 RIH w/ Mud Motor, PDC Bit RECEIVED 07:30 - 08:00 0.50 03 A DRLIN2 Ream f/ 7212 to 7233 ft. 08:00 - 12:00 4.00 02 A DRLIN2 DrIg 8.5" hole f/ 7233 to 7282 ft 12:00 - 00:00 12.00 02 A DRLIN2 DrIg 8.5" hole f/ 7282 to 7559 JAN 1 2 2001 00:00 - 06:00 6.00 02 A DRLIN2 DrIg 8.5" hole f/ 7559 to 7618 11/14/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5" HOLE F/ 7618 T/ 7698. Alaska Oil & Gas Cons. Commission 1 12:00 18:00 6.00 02 A DRLIN2 DRLG. 8.5" HOLE F/ 7698 T/ 7795. Anchorage 118:00 - 18:30 0.50 05 I DRLIN2 CIRC. BTMS. UP. 18:30 - 19:00 0.50 11 A DRLIN2 RIG UP SHEAVE ON TOP DRIVE. TO SURVEY. 19:00 - 19:30 0.50 11 A DRLIN2 RIH W/ WIRELINE SURVEY. 19:30 - 20:30 1.00 10 A DRLIN2 POOH w/ Wireline. Rig down topdrive survey tool 20:30 - 00:00 3.50 02 A DRLIN2 DRLG 8.5" HOLE F/ 7775 TO 7844 00:00 - 06:00 6.00 02 A DRLIN2 DRLG 8.5" HOLE F/ 7844 TO 7940 1 Printed: 1/4/2001 9:02:44 AM 1 • FOREST OIL CORP Page 9 of 15 Operations Summary Repot Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 To � � E u s ode , i e Phase �� Descnptlor f Qperatjorts 11/15/2000 06:00 - 10:30 4.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 7,940 T/ 8056. 10:30 - 11:30 1.00 08 B DRLIN2 REPLACE BLOWN HYD. HOSE ON TESCO TOP DRIVE. 11:30 - 12:00 0.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8,056 T/ 8,091. 12:00 - 22:00 10.00 02 A DRLIN2 DRLG 8.5 HOL F/ 8091 TO 8273 22:00 - 22:30 0.50 02 A DRLIN2 CIRC. BOTTOMS UP TO SURVEY 22:30 - 23:00 0.50 02 A DRLIN2 RIG SHEAVE ON TOPDRIVE TO WIRELINE /MAKE UP SURVEY 23:00 - 23:30 0.50 10 A DRLIN2 RIH W /WIRELINE SURVEY AND SURVEY © 8212 23:30 - 00:00 0.50 10 A DRLIN2 SURVEY AND POOH 00:00 - 00:30 0.50 02 A DRLIN2 POOH W/ WIRELINE SURVEY 00:30 - 01:00 0.50 02 A DRLIN2 POOH W/ 10 STAND SHORT TRIP 01:00 - 02:30 1.50 02 A DRLIN2 RIH. P/U 27 JTS. DRILL PIPE F/ CATWALK 02:30 - 06:00 3.50 02 A DRLIN2 DRLG 8.5 HOLE F/ 8273 TO 8333 11/16/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5 HOLE F/8333 T/ 8371. 12:00 - 04:00 16.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8371 T/ 8552. 04:00 - 04:30 0.50 08 A DRLIN2 CHANGE SWAB , CIRC. CLEAN BIT. 04:30 - 06:00 1.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8255 T/8560. 11/17/2000 06:00 - 09:00 3.00 02 A DRLG. 8.5" HOLE F 8560 TO 8573. 09:00 - 09:30 0.50 05 A CIRC. BOTTOMS UP 09:30 - 10:00 0.50 10 A DROPPED SURVEY © 8552 10:00 - 12:00 2.00 06 A PUMP PILL; POOH 12:00 - 16:30 4.50 06 A POOH F 5809 TO 315 16:30 - 17:30 1.00 06 J RETRIEVE SURVEY; STAND BACK BHA, LD MUD MTR 17:30 - 20:00 2.50 25 PULL WEAR BUSHING; SANDED IN; WASHED FREE 20:00 - 21:30 1.50 15 A RIG UP TO TEST B.O.P.'s 21:30 - 23:00 1.50 15 A TEST RAMS; ANNULAR; FLOOR VALVE; KELLY COCKS 23:00 - 00:00 1.00 15 B REPAIRING TWO KILL LINE VALVES 00:00 - 05:00 5.00 15 B WORKING ON KILL LINE AND CHOKE VALVES 05:00 - 06:00 1.00 15 B TESTING KOOMEY. 11/18/2000 06:00 - 07:30 1.50 26 DRLIN2 Pick up 15 jts. off walk; stand back in derrick 07:30 - 08:30 1.00 15 A DRLIN2 M/U Test Plug, test choke valve, good test. Pull plug, run wear ring. 08:30 - 12:00 3.50 25 DRLIN2 M/U BHA. Pull allenhead bolts for added flow w/ drillbit. 12:00 - 13:00 1.00 25 DRLIN2 Waiting on drill bit. Clean rig floor & cellar. Adjust crown warning bell 13:00 - 15:00 2.00 26 DRLIN2 Make up new 8.5 bit. RIH to 1128 ft. 15:00 - 15:30 0.50 25 DRLIN2 Change out Saver Sub on Tesco Top Drive 15:30 - 16:00 0.50 25 DRLIN2 Fill DP & flow check Teledrift tool @ 1220 16:00 - 19:00 3.00 06 J DRLIN2 TIH from 1220 to 6277 19:00 - 19:30 0.50 06 J DRLIN2 Fill DP & spot check Teledrift tool RECEiVED 19:30 - 21:00 1.50 06 J DRLIN2 TIH from 6277 to 8552 21:00 - 21:30 0.50 06 J DRLIN2 Fill DP & spot check Teledrift tool (3.5 deg) 21:30 - 00:00 2.50 02 A DRLIN2 DRLG from 8572 to 8600 JAN 1 2 2001 00:00 - 06:00 6.00 02 A DRLIN2 DRLG from 8600 to 8678 11/19/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8678 T/ 8776 Alaska Oil & Gas Cons. Commission 12:00 - 00:00 12.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 8776 T/ 9050 Anchorage 00:00 - 01:30 1.50 02 A DRLIN2 DRLG. 8.5 HOLE F/ 9050 T/ 9089 01:30 - 02:00 0.50 10 A DRLIN2 TELEDRIFT SURVEY @ 9049' (3.5 TO 4.0 DEG.) 02:00 - 06:00 4.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 9089 T/ 9180 11/20/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. F/ 9180 T/ 9254 12:00 - 12:30 0.50 25 DRLIN2 ESTABLISH DRLG. PERIMETERS. NABORS SAFETY MEETING 12:30 - 13:00 0.50 07 DRLIN2 SERVICE RIG 13:00 - 00:00 11.00 02 A DRLIN2 DRLG. F/ 9254 T/ 9466 00:00 - 06:00 6.00 02 A DRLIN2 DRLG. F/ 9466 T/ 9538 11/21/2000 06:00 - 12:00 6.00 02 A DRLIN2 DRLG. 8.5 HOLE F/ 9538 T/ 9562 12:00 - 18:00 6.00 02 A DRLIN2 DRLG. F/ 9562 T/ 9655 Printed: 1/4/2001 9:02:44 AM • 13 q2;‘, i FOREST OIL CORP f�age 10"of5 Operations Summ ar Repo a1 r s • • Legal Well Name: Kustatan Field #1 • Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From To Hours Cote r"t"e Phase Decrtptlon of O'icfattorts 11/21/2000 18:00 - 18:30 0.50 10 A DRLIN2 TELEDRIFT SURVEY © 9549. 18:30 - 19:00 0.50 05 I DRLIN2 CBU F/ SHORT TRIP 19:00 - 20:00 1.00 06 H DRLIN2 11 STD SHORT TRIP. F/ 9655 T/ 8624 20:00 - 20:30 0.50 07 DRLIN2 CLEAN RIG FLOOR. 20:30 - 21:00 0.50 07 DRLIN2 SERVICE RIG. 21:00 - 23:00 2.00 26 H DRLIN2 PJSM. RIH F/ 8624 T/ 9655, P/U PIPE FROM RACK & RABBIT. 23:00 - 00:00 1.00 02 A DRLIN2 DRLG F/ 9655 T/ 9660 00:00 - 06:00 6.00 02 A DRLIN2 DRLG F/ 9655 T/ 9724 11/22/2000 06:00 - 12:00 6.00 02 A DRLG 8.5" HOLE F/ 9724 TO 9795 12:00 - 18:00 6.00 02 A DRLG 8.5" HOLE F/ 9795 TO 9840 18:00 - 18:30 0.50 07 SERVICE RIG DRAWWORKS; BLOCKS; CROWN 18:30 - 06:00 11.50 02 A DRLG 8.5" HOLE F/ 9840 TO 9965 11/23/2000 06:00 - 16:00 10.00 02 A DRLIN2 Drilling 8 1/2" hole from 9965 to 9983. 16:00 - 16:30 0.50 10 A DRLIN2 Survey w/ teledrift © 9935'. Drop totco. 16:30 - 17:00 0.50 28 DRLIN2 Monitor well, pump dry job. 17:00 - 20:00 3.00 06 A DRLIN2 POOH to 6.467'. (shoe) 20:00 - 20:30 0.50 07 DRLIN2 Service Rig 20:30 - 21:00 0.50 05 I DRLIN2 Circulate bottoms up. 21:00 - 21:30 0.50 25 DRLIN2 Pre -Job safety meeting 21:30 - 05:00 7.50 08 C DRLIN2 Remove and repair high drum clutch 05:00 - 06:00 1.00 06 J DRLIN2 POOH to change bit and BHA 11/24/2000 06:00 - 09:00 3.00 06 A DRLIN2 POOH 09:00 - 12:00 3.00 06 A DRLIN2 Retrieve survey @ DCs', break bit, lay down mud motor, inspect survey tool. 12:00 - 15:00 3.00 06 A DRLIN2 Service teledrift tool, pick up mud motor and new bit, RIH with BHA to 1128'. 15:00 - 17:30 2.50 06 B DRLIN2 PJSM, P/U 5" DP from pipe rack. (rabbit each joint) RIH from 1128' to 2067'. 17:30 - 18:00 0.50 07 DRLIN2 Service rig and re- adjust kelly hose to top drive. 18:00 - 23:00 5.00 06 A DRLIN2 RIH from 2067' to 6475'. Fill pipe @ 3472' and 6475'. 23:00 - 00:00 1.00 07 DRLIN2 Cut and slip drilling line. 00:00 - 02:00 2.00 06 A DRLIN2 RIH from shoe, fill pipe © 9000'. 02:00 - 02:30 0.50 03 DRLIN2 Ream from 9845 to bottom @ 9984'. 02:30 - 06:00 3.50 02 A DRLIN2 Drilling 8 1/2' hole from 9984' to 10068'. 11/25/2000 06:00 - 21:00 15.00 02 A DRLIN2 Drilling 8 1/2" hole from 10068' to 10503'. ADT hrs. 21:00 - 21:30 0.50 10 A DRLIN2 Survey w /teledrift @ 10435' -3.5 Deg. 21:30 - 02:30 5.00 02 A DRLIN2 Drilling 8 1/2" hole. 02:30 - 03:00 0.50 29 DRLIN2 Circ. bottoms up. 03:00 - 04:00 1.00 06 H DRLIN2 7Std. short trip. Hole in good shape, no fill. 04:00 - 06:00 2.00 02 A DRLIN2 Drilling 81/2" hole. Hole is taking +/- 10 bbls. /hr. fluid. 11/26/2000 06:00 - 13:30 7.50 02 A DRLIN2 Drill 8 1/2" hole. 13:30 - 14:00 0.50 07 DRLIN2 Service rig, draw- works, blocks and crown. 14:00 - 17:30 3.50 02 A DRLIN2 Drilling 8 1/2" hole to 10809'. 17:30 - 18:00 0.50 10 A DRLIN2 Survey with teledrift @ 10758', 3.5 deg. RECEIVED 18:00 - 18:30 0.50 28 DRLIN2 Monitor well, mix and pump dry job. 18:30 - 01:00 6.50 06 A DRLIN2 POOH to BHA. 01:00 - 02:30 1.50 06 A DRLIN2 Work BHA, lay down jars and stab. JAN 1 2 2001 02:30 - 04:00 1.50 15 A DRLIN2 Pull wear bushing, pick up test plug. 04:00 - 06:00 2.00 15 A DRLIN2 Test BOPs, 250/4000# 1 11/27/2000 06:00 - 07:00 1.00 07 DRLIN2 Put Kelly Hose on and reposition. Alaska Oil & Gas Cons. Commission 07:00 - 08:30 1 1.50 26 DRLIN2 M/U Bit; Brk Teledrift & redress; test mudmotor Anchorage 108:30 - 09:30 1.00 06 J DRLIN2 TIH w/ BHA & HWDP 1 09:30 - 10:00 0.50 06 J DRLIN2 TIH Printed: 1/4/2001 9:02:44 AM • • FOREST OIL .CORP Page 11;of 14,, Operations Summary Report . . Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date. From '� Hours C4cfe � >�hase ,©escrlptto , 3 n�t�f peratt�sfrts qa� Curie 11/27/2000 10:00 - 12:00 2.00 07 DRLIN2 Working on positioning kelly hose; interferes w/ making up drillpipe from driller's side; hose binding against pipe. 12:00 - 12:30 0.50 07 DRLIN2 Service rig; drawworks; blocks; crown. 12:30 - 18:00 5.50 06 J DRLIN2 TIH f/ 1225 to 10594; filled DP @ 3471, 6295, 8910. 18:00 - 19:00 1.00 03 A DRLIN2 Ream f/ 10594 to 10806; pumped hi -vis sweep while reaming to bottom. 19:00 - 00:00 5.00 02 A DRLIN2 Drilling f/ 10806 to 10846. 00:00 - 06:00 6.00 02 A DRLIN2 Drilling f/ 10846 to 10915 11/28/2000 06:00 - 10:00 4.00 02 A DRLIN2 Drilling 8 1/2" hole. 10:00 - 12:00 2.00 02 A DRLIN2 Pump hi -vis sweep while drilling 8 1/2" hole. 12:00 - 12:30 0.50 02 A DRLIN2 Drilling 81/2" hole. 12:30 - 13:00 0.50 07 DRLIN2 Service rig, draw - works, blocks, swivel and crown. 13:00 - 21:30 8.50 02 A DRLIN2 Drilling 8 1/2' hole, pump hi -vis sweep while drilling. 21:30 - 22:00 0.50 29 DRLIN2 Circ. hole clean after hi -vis sweep for short trip, monitor well. 22:00 - 22:30 0.50 06 H DRLIN2 Short trip from 11174' to 10594'. No hole problems. 22:30 - 06:00 7.50 02 A DRLIN2 Drilling 8 1/2' hole. 11/29/2000 06:00 - 07:00 1.00 02 A DRLIN2 Drilling f/ 11290 to 11300 07:00 - 12:00 5.00 02 A DRLIN2 Pump up to survey depth (11258); 15 min. Drilling f/ 11300 to 11345 12:00 - 12:30 0.50 07 DRLIN2 Service rig. 12:30 - 00:00 11.50 02 A DRLIN2 Drilling f/ 11345 to 11475 00:00 - 06:00 6.00 02 A DRLIN2 Drilling f/ 11475 to 11590 11/30/2000 06:00 - 06:30 0.50 02 A DRLIN2 Drilling 8 1/2" hole from 11590' to 11598'. 06:30 - 08:30 2.00 05 I DRLIN2 Pump hi -vis sweep, circ. bottoms up and monitor well for 10 min. Pump dry job. 08:30 - 13:30 5.00 06 A DRLIN2 POOH from 11598' to inside the shoe @ 6381'. 13:30 - 14:00 0.50 08 C DRLIN2 PJSM 14:00 - 16:00 2.00 08 C DRLIN2 Move Hydromatic and work on over - riding clutch. Clutch worn out, needs replacing. Waiting on clutch parts. 16:00 - 06:00 14.00 08 C DRLIN2 Monitoring well while repairing trip -tank, changing liners in # 2 pump, circ. every six hours, continue monitoring well while waiting on clutch parts. 12/1/2000 06:00 - 10:30 4.50 08 C Blow Down Topdrive. remove Kelly Hose and goosnecks; tighten 1002 unions; have welder tack to keep from backing off agian. Install same and adjust Kelly Hose to keep away from drilipipe when tripping. Change impeller on #1 water pump. Change belts on #2 water pump. Electrician troubleshooting problem with drawworks SCR assignment. 10:30 - 12:00 1.50 08 C Dress and clean overriding clutch to be installed. Work on installing same. 12:00 - 18:00 6.00 08 C Install overide clutch. Reinstall all guards. 18:00 - 18:30 0.50 05 A Circulate and conditon mud. Pump dry job. 18:30 - 22:00 3.50 06 J Blow down topdrive. POOH. 22:00 - 00:00 2.00 Finish POOH. Check out Teledrift tool. Break off bit. o E 00:00 - 01:30 1.50 26 Making up new BHA w/ 8.5" bit; mud motor; teledrift tool > N 01:30 - 02:30 1.00 26 Pick up 18 singles of 5" drill pipe. - 06:00 3.50 06 J RIH. Fill drilipipe. a t ► 12/2/2000 06:00 - 10:00 4.00 08 C DRLIN2 REALIGN OVERRIDING CLUTCH. `c 10:00 - 12:00 2.00 06 �A DRLIN2 TIH; LAY DN SINGLE, WASH OUT; TIH TO 8350 Li ' + Z 2 12:00 - 12:30 0.50 06 A DRLIN2 RIH LL.1 12:30 - 14:00 1.50 29 DRLIN2 BREAK CIRC @ 8443; FILL PIPE & CBU 14:00 - 15:00 1.00 06 A DRLIN2 RIH �L•• Y 15:00 - 16:00 1.00 03 A DRLIN2 BREAK CIRC @11623; FILL PIPE; REAM 100' TO BOTTOM 16:00 - 16:30 0.50 03 A DRLIN2 WASH TO BOTTOM; BREAK IN BIT. d 16:30 - 00:00 7.50 02 A DRLIN2 DRILLING F/10598 TO 11740 Printed: 1/4/2001 9:02:44 AM • • 4 �' "Ilk FOREST OIL CORD ' � � P age 12 of 15 �F �� 3 O perat ions Summary R epo ,, , ,� i � a Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 S ub ,, C F Tc Hours '�de3� �„ Pha Oe t o perattb s :,,,,y,,,,,:lii: cede � ' 12/2/2000 00:00 - 04:00 4.00 02 A DRLIN2 DRILLING F/ 11740 TO F 11812 12/3/2000 06:00 - 1 6.00 02 A DRLIN2 DRLG 8 5 F/ HOLEE F/ 11869 T/ 11970 �0�� . gg° 2.00 02 A DRLIN2 JP GO° F/ 11970 T/ 12165 00:00 - 06:00 6.00 02 A 12/4/2000 06:00 - 09:30 1 3.50 02 A DRLIN2 D DI!!�: 8.5 "+1OLE / F/ 12257 12257 T/' 1 k�\\ , °' P�� 0a 09:30 - 10:00 0.50 10 A DRLIN2 PUMP UP SURVEY @ 12258 FT. STAND BACK STD. 10:00 - 12:00 2.00 05 I DRLIN2 PUMP HI VIS SWEEP CIRC. BTMS UP & RECPROCATE PIPE, MIX DRY JOB, MONITOR WELL 10 MIN. 12:00 - 12:30 0.50 28 DRLIN2 PUMP DRY JOB & BLOW DOWN TOP DRIVE. 12:30 - 22:00 9.50 06 C DRLIN2 P.O.H. TO SHOE- SLOW- CHECK FOR FLOW © 9 5/8 SHOE & P.O.H. 22:00 - 22:30 0.50 06 C DRLIN2 LAY DOWN MOTOR, TELEDRIFT & 8.5 BIT. 22:30 - 00:00 1.50 11 A DRLIN2 RIG UP TO LOG. 00:00 - 02:30 2.50 11 A DRLIN2 MAKE UPSWL TOOLS, HOLD PJSM. RIH TO WARM UP TOOLS; POOH TO LOAD SOURCE. WHEN POH TO LOAD SOURCE, TOOL HUNG UP AT 94 FT. TOOL FREED. 02:30 - 06:00 3.50 11 A DRLIN2 Rte 1 / OGG G TOOLS. 12/5/2000 06:00 - 12:00 6.00 11 A EVAL 2 RIH SWL. POOH, unload sources, laydown tools. Hang up again u 90 ft. Rope socket missing AIT standoff from bottom of tool. up FM4 tools, RIH to warm up. Start in hole @ 10:15 hrs. w/ FMI 12:00 - 14:30 2.50 11 A EVAL 2 POOH, I # FM$ texts. 14:30 - 00:00 9.50 25 EVAL 2 VdlfiiReJvgek 44Atek,667404t. Working to free. 00:00 - 06:00 6.00 25 EVAL 2 Monitoring well, waiting on fishing tools and hands. 12/6/2000 06:00 - 12:00 6.00 25 EVAL 2 MONITOR WELL W! TRIPTANK. WAIT ON WEATHER TO RECEIVE FISHING TOOLS & SCHLUMBERGER HANDS. 12:00 - 15:00 3.00 25 EVAL 2 WAITING ON FISHING TOOLS. 15:00 - 16:30 1.50 19 B EVAL 2 P/U FISHING TOOLS, FIGURE OUT BHA,CLAMP WIRE, WAIT ON SCHLUMBERGER. 16:30 - 18:00 1.50 25 EVAL 2 PRE -JOB MEETING, PROCEDURES TO RIG UP & STRIP OVER. 18:00 - 21:00 3.00 19 B EVAL 2 RIG UP SCHLUMBERGER SHEAVE IN DERRICK, CUT & THREAD WIRELINE, RIG UP SINKER BARS, TEST WIRELINE HEAD TO 6K. 21:00 - 22:00 1.00 06 B EVAL 2 RIH BHA 22:00 - 00:00 2.00 19 B EVAL 2 RECUT WIRE FOR BETTER SPACING, REPOSITION SHEAVE IN DERRICK. 00:00 - 06:00 6.00 19 B EVAL 2 STRIPPING OVER WIRELINE 12/7/2000 06:00 - 08:30 2.50 19 B EVAL 2 STRIP OVER TO SHOE 08:30 - 09:30 1.00 29 EVAL 2 CIRCULATE BOTTOMS UP PLUS DRILL PIPE VOLUME 09:30 - 10:00 0.50 06 B EVAL 2 TRIP IN HOLE TO FISH 10:00 - 11:30 1.50 19 B EVAL 2 PICK UP SINGLE. FIND FISH AT 6713 11:30 - 12:00 0.50 19 B EVAL 2 MAKE UP CIRCULATING SUB. PRESSURE UP AND BLOW DISC ON PUMPOUT SUB. 12:00 - 13:00 1.00128 F EVAL 2 CIRCULATE AND PUMP DRY JOB. BLOW DOWN TOPDRIVE. 13:00 - 14:00 1.00125 EVAL 2 PRE -JOB SAFETY MEETING (R!U TO PULL WIRELINE). HANG WIRELINE. T CLAMP. RIG DOWN WIRELINE SHEAVE FROM CROWN. LATCH UP ON T CLAMP WITH RIG ELEVATORS. PULL 11,000 LBS. TO BREAK LINE AT ROPE SOCKET. 14:00 - 15:30 1.50 19 B EVAL 2 R/U SCHLUMBERGER TO POH. WIRELINE RETRIEVED ALL LINE. 15:30 - 16:00 0.50 11 IA EVAL 2 RIG DOWN SCHLUMBERGER 16:00 - 21:00 5.00! 06 ' B EVAL 2 POOHtW Tf4 SH. 21:00 - 22:00 1.00 25 EVAL 2 LAY DOWN FMI TOOL AND TRISTATE FISHING TOOLS. 22:00 - 00:00 2.00 26 EVAL 2 PICK UP BHA I Printed: 1/4/2001 9:02:44 AM • • FOREST OIL CORD Page 13 of 15 ae ui,t �� Operat�oins S ummary :Report �, o�� 3 Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 , C t Ffom Sub 1 � ;, � >�C , ��fours Code G RI1 De�Grlptl� C?f �e 3 �, � 12/7/2000 00:00 - 00:30 0.50 06 EVAL 2 PJSM 15 MIN. TIH W/ HWDP 00:30 - 02:30 2.00 09 EVAL 2 CUT AND SLIP 100' OF DRILLING LINE. SERVICE RIG. 02:30 - 04:00 1.50 06 EVAL 2 TIH TO 7443 FT. REAM TIGHT SPOT (40000 DOWN, 20000 UP) 04:00 - 06:00 2.00 06 EVAL 2 TIH. TIGHT © 7287. WORK PIPE THROUGH TWICE. CLEANED UP. 12/8/2000 06:00 - 07:30 1.50 06 H CSGIN2 TIH TO 9318' WASH & REAM TO 9348' 07:30 - 08:30 1.00 05 F CSGIN2 CIRC. HOLE CLEAN. 08:30 - 10:00 1.50 06 H CSGIN2 TIH TO 9650' CIRC. HOLE CLEAN. C) -1,2;, 10:00 - 12:00 2.00 06 H CSGIN2 TIH TO 11542' WASH & REAM TO 11589'. E 12:00 - 12:30 0.50 06 H CSGIN2 TIH L o 12:30 - 13:00 0.50 29 CSGIN CBU @ 11872. N 13:00 - 14:00 1.00 06 H CSGIN2 TIH C.t "' 14:00 - 17:00 3.00 03 A CSGIN2 REAM TO BTM. F/ 12061 T/ 12300. LU r-- 17:00 - 21:30 4.50 05 F CSGIN2 PUMP 2 SWEEPS, CIRC & COND MUD. 21• 30 - 22:00 0.50 05 F CSGIN2 PUMP 3RD SWEEP, MONITOR WELL pp � LI � 221:00 - 00:00 2.00 06 H CSGIN2 POOH L - 3 00:00 - 06:00 6.00 06 H CSGIN2 POOH Y 12/9/2000 06:00 - 09:00 3.00 06 H CSGIN2 STD BACK BHA, UD STABS, BREAK BIT. c` i 09:00 - 10:00 1.00 15 A CSGIN2 PULL WEAR RING, SET TEST PLUG. 10:00 - 12:00 2.00 15 A CSGIN2 CHANGE RAMS T/ 7 5/8 ". HANG STABBING BOARD. P/U CASING ELEVATOR, HANG HOSES, HOOK UP FILL -UP LINE T/ CASING. 12:00 - 13:30 1.50 15 A CSGIN2 TIGHTEN BOLTS ON RAM DOORS. TEST STACK TO 3000 PSI. PULL TEST PLUG, SET WEAR RING. 13:30 - 14:30 1.00 01 A CSGIN2 RIG UP WEATHERFORD. 14:30 - 15:00 0.50 25 CSGIN2 PRE -JOB SAFETY MEETING (RUNNING CASING) 15:00 - 00:00 9.00 12 B CSGIN2 RIH W/ 7. 15:00 HIT TIGHT SPOT @90 FT. WORKED THROUGH. CHECKED FLOAT - O.K. 00:00 - 06:00 6.00 12 B CSGIN2 RIH W/ 7 -5/8" LINER. JOINT #52 HAS DAMAGED THREADS. PULLED OUT AND RUNNING TALLY ADJUSTED ACCORDINGLY. 12/10/2000 06:00 - 07:30 1.50 12 B CSGIN2 VD casing tools; P/U and M/U hanger 07:30 - 09:00 1.50 12 B CSGIN2 UD stabbing board; M/U saver sub on top drive; clamp and safety chains. 09:00 - 11:30 2.50 12 B CSGIN2 RIH w /liner and hanger on 5 "drillpipe. Hit tight spot @ 90'. Circulate, rotate 1/2 turn; work through. CBU. 11:30 - 12:00 0.50 12 B CSGIN2 RIH w/ liner hanger and liner. 12:00 - 14:30 2.50 12 B CSGIN2 RIH w/ drillpipe. Rabbit pipe. Fill pipe (10 stands) 14:30 - 15:30 1.00 05 F CSGIN2 CBU 15:30 - 16:00 0.50 07 CSGIN2 Work on topdrive. 16:00 - 17 :00 1.00 12 B CSGIN2 RIH. No problems. 17:00 - 21:00 4.00 12 B CSGIN2 Tagged bottom @ 12,300 ft. 21:00 - 00:00 3.00 05 F CSGIN2 Circulate and reciprocate hole clean and M/U cement head. 00:00 - 01:00 1.00 29 CSGIN2 Circulate. Hold PJSM. 01:00 - 01:30 � 0.50 12 C CSGIN2 P/U & M/U cement top drive head. Break circulation. 1 01:30 - 03:30 2.00 12 C CSGIN2 Test lines t/ 4500 psi. Cement liner. 03:30 - 04:00 0.50 12 C CSGIN2 Drop plug. Displace w/ rig pump. 94 strokes /min for 4493 strokes. 04:00 - 05:00 1.00 12 D CSGIN2 Attempt to unsting f/ liner and set packer. 05:00 - 05:30 0.50 12 D CSGIN2 Pressure up on packer to 4000 psi. Set packer and unsting from liner. 05:30 - 06:00 0.50 12 D CSGIN2 Break off cement head and pull 5 stands 12/11/2000 06:00 - 06:30 0.50 25 CSGIN2 Test casing. No test. 06:30 - 07:00 1 0.50 05 F CSGIN2 Circulate 2X drillpipe capacity. 07:00 - 08:00 1.00 CSGIN2 Slip drilling line 102'. Blow down topdrive and kill line 08:00 - 12:00 4.00 06 G CSGIN2 POOH, lay down 5" drillpipe. 12:00 - 16:00 4.00 25 1 CSGIN2 Lay down 5" drillpipe Printed: 1/4/2001 9:02:44 AM 1 :F Page OIL �CCJRP. , Page 14- �3 1 Operations Summary epor t Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Sub Date From"- To r e .,-u‘ Phase Descri tiara o f 4 o pere o 12/11/2000 16:00 - 16:30 0.50 25 CSGIN2 Lay down Baker running tools. 16:30 - 17:30 1.00 25 CSGIN2 Left hole fluid level down. Inspect 9-5/8" casing. Casing has hole at approximately 87.41' from rotary table. 17:30 - 18:30 1.00 25 CSGIN2 Lay down drill collars; jars; & HWDP 18:30 - 19:00 0.50 15 CSGIN2 Pulled wear ring; set test plug. 19:00 - 20:00 1.00 25 CSGIN2 Open doors on B.O.P.; change rams f/ 7" to 5 ". 20:00 - 20:30 0.50 15 CSGIN2 Tested BOP stack to 3000 psi. Tested OK 20:30 - 22:00 1.50 12 CSGIN2 Pick up cement head & break down. 22:00 - 00:00 2.00 05 CSGIN2 Clean up mud; gunning over shakers. 00:00 - 06:00 6.00 25 CSGIN2 Cleaning mud pits. 12/12/2000 06:00 - 09:30 3.50 25 CSGIN2 Clean mud pits. Transfer mud over shakers to volume pit. Clean trip tank. 09:30 - 12:00 2.50 15 B CSGIN2 Test choke manifold, outside kill line, top drive valve (low 250 psi; high 4000 psi). All valves, floor valves, Hydril (2500 psi), all rams (250 psi low; 4000 psi high); Koomey tested. 12:00 - 18:00 6.00 25 CSGIN2 Rig down flow line; fill up line; pitcher nipple; turnbuckles; drip pans. Rig up hydraulic lift lines to stack. Pick up slings, take off choke lines. 18:00 - 19:30 1.50 25 CSGIN2 PJSM. Raising BOP stack. 19:30 - 22:30 3.00 25 CSGIN2 Raise stack 1'. Tubing hanger & 9 -5/8" pack off would not release. Worked on freeing hanger, stub came free. Removed tubing spool, installed adapter spool. 22:30 - 00:00 1.50 19 E CSGIN2 Pick up and make up fishing tools. 00:00 - 02:00 2.00 19 E CSGIN2 POOH w/ casing stub and full joint (57.84 ft.) and inspect threads. 02:00 - 06:00 4.00 14 B CSGIN2 Nipple up BOP, hook up flow line and pitcher nipple. 12/13/2000 06:00 - 07:00 1.00 14 B CSGIN2 Reset hydraulic pick up slings, pick up BOP stack. 07:00 - 12:00 5.00 21 CSGIN2 Fill suction pit, pump across BOP. Clean around outside shakers and dumps. Round up rental tools. Clean docks. Haul DP to to WMRU yard. 12:00 - 13:30 1.50 21 CSGIN2 Continue to clean rig while waiting on APRS. 13:30 - 14:00 0.50 19 E CSGIN2 Redress spear. Lay down single HWDP, pick up stand of HWDP. 0 N 14:00 - 16:00 2.00 19 E CSGIN2 Rig u APRS for freepoint UNI o E 16:00 16:30 0.50 25 CSGIN2 Pre -job safety meeting (Backing out casing - string shot) o v 16:30 - 17:00 0.50 19 E CSGIN2 Apply reverse torque to casing string. String came free. Backed out. ri, '6 17:00 - 17:30 0.50 19 E CSGIN2 POOH w/ 9 -5/8" casing g 17:30 - 18:00 0.50 25 CSGIN2 Rig up to lay down casing. r { 18:00 - 21:30 3.50 25 CSGIN2 Lay down 10 joints 9 -5/8" BTC casing. 0 Z 0 ¢ 21:30 - 22:30 1.00 05 F CSGIN2 RIH w/ DP. Wash 5' over fish. Clean hole. POOH. C ° 22:30 - 23:30 1.00 25 CSGIN2 Inspecting casing. -'? 6 : 5 23:30 - 00:00 0.50 12 A CSGIN2 Run casing. Seal rings installed in each connection. Torqued to 12,000 ft lbs. d 00:00 - 06:00 6.00 12 D CSGIN2 Hang BOP. Set casing slips. Prepare to cut off 9 -5/8" casing. 12/14/2000 06:00 - 07:30 1.50 B RDMO Back out of landing joint with x /o, cut off 24.33' of 9 5/8" csg. and lay down same. Make final cut. 07:30 - 12:00 4.50 14 B RDMO Set BOPs, pick up pick up slings. Remove spool, replace with tubing spool. 12:00 - 13:00 1.00 15 A RDMO Test pack -off void to 3000 psi. 15 min. test OK. 13:00 - 14:30 1.50 15 A RDMO Set wear -ring, R/U to test 9 5/8" csg., 7 5/8' csg. and liner lap. Test to 3000 psi. for 30 min. Test OK. 14:30 - 17:00 2.50 06 J RDMO RIH with 5" DP. 17:00 - 20:30 3.50 06 J RDMO Make -up bit, bit sub and float. RIH with DP. 20:30 - 04:30 8.00 22 B RDMO Lay down 5" DP.Break down fishing tools. 04:30 - 06:00 1.50. 30 1 RDMO Prepare to nipple down BOPs. 12/15/2000 06:00 - 12:00 6.00 30 RDMO Nipple down BOPs, lay down beaver slide. Printed: 1/4/2001 9.02:44 AM • • 3 OE EST OIL -.CORP Page 15 of 1 � r „ 0 t ' n s u mr'tarT R:pc rt 3 3 Legal Well Name: Kustatan Field #1 Common Well Name: Kustatan Field #1 Spud Date: 10/16/2000 Event Name: ORIG DRILLING Start: 10/16/2000 End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Group: Rig Name: NABORS DRILLING Rig Number: 160 Date From - lours Code Cocf > tease D ptian of g 12/15/2000 12:00 - 13:00 1.00 31 RDMO Install test plug in tbg. spool, make up kill line to tbg. spool. 13:00 - 17:00 4.00 01 B RDMO Rig down Tesco top drive, remove elevators, bails, service and hydraulic lines. Break quill loose. 17:00 - 18:00 1.00 31 RDMO Remove test plug, make up abandoment head. 18:00 - 19:00 1.00 07 RDMO Clean cellar and rig floor. 19:00 - 20:00 1.00 31 RDMO Test 9 5/8' csg., two csg. valves, master valve and tree cap from 300 to 3000 psi. Also this was test 7 5/8" csg. and liner lap. Test was witnessed by L.Grimaldi, AAOGCC. 20:00 - 23:00 3.00 12 D RDMO Rig up to freeze protect 13 3/8" annulus and 9 5/8" csg. 30" below ground Ievel.Blew mud out of csg. and annulus and filled with Diesel. 23:00 - 23:30 0.50 07 RDMO Clean cellar. 23:30 - 00:00 0.50 01 B RDMO PJSM Hang blocks to slip drlg to lay down top drive. Rig released @ 2400 Hrs. ‘< o` P 4- P Printed: 1/4/2001 9:02:44 AM REC8 V ED ,J 1 2 )f;(l1 Ji 3 � ,3 F1 33 3 3 3 .W t . 3ld 3 1 9 ... 3 i i,tz i FORE L 3 '4%5 k q .l , O marts il i/ �� Page 1 of 2 7 ., 333 i ` 1} Legal Well Name: Kustatan Field #1 Spud Date: 10/16/2000 S rG` #i' °) Common Well Name: Kustatan Field #1 Start: 10/16/2000 OH 0.00 Event Name: ORIG DRILLING End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Rig Name: NABORS DRILLING Rig Number: 160 TMD: 12,258.00 (ft) TVD: 12,246.52 (ft) Calculation Method: Minimum Curvature SIT #'; TMD " Angle a zimuth . C TM TVD .; Nl- E! W 7 e+ction ',1!1/2,1,,,,:,, D€.S 3 i.` BUR ; 1- TYpe �.,. . J .:, a 'r 4 .� .i '- 1� �� 'p (�f1 :ice OH 290.00 0.000 0.000 NYN 290.00 0.00 0.00 0.00 0.00 0.00 INC OH 619.00 0.500 0.000 NYN 619.00 0.00 0.00 0.00 0.00 0.00 INC OH 1,020.00 0.750 0.000 NYN 1,019.98 4.37 0.00 4.37 0.06 0.06 INC OH 1,389.00 0.000 0.000 NYN 1,388.97 6.79 0.00 6.79 0.20 -0.20 INC OH 1,787.00 0.000 0.000 NYN 1,786.97 6.79 0.00 6.79 0.00 0.00 OH 2,201.00 0.500 0.000 NYN 2,200.96 8.60 0.00 8.60 0.12 0.12 OH 2,699.00 0.500 0.000 NYN 2,698.94 12.94 0.00 12.94 0.00 0.00 OH 3,129.00 1.000 0.000 NYN 3,128.90 18.57 0.00 18.57 0.12 0.12 OH 3,608.00 0.750 0.000 NYN 3,607.85 25.88 0.00 25.88 0.05 -0.05 OH 4,070.00 1.000 0.000 NYN 4,069.79 32.94 0.00 32.94 0.05 0.05 OH 4,509.00 0.750 0.000 NNN 0.00 0.00 0.00 0.00 0.00 0.00 INC OH 5,006.00 0.500 0.000 NNN 0.00 0.00 0.00 0.00 0.00 0.00 INC OH 5,382.00 0.750 0.000 NNN 0.00 0.00 0.00 0.00 0.00 0.00 INC OH 5,840.00 1.000 0.000 NNN 0.00 0.00 0.00 0.00 0.00 0.00 INC OH 6,306.00 1.500 0.000 NNN 0.00 0.00 0.00 0.00 0.00 0.00 OH 6,677.00 2.250 0.000 YNN 6,675.69 106.87 0.00 106.87 0.05 0.05 III OH 6,677.00 2.250 0.000 YNN 6,675.69 106.87 0.00 106.87 0.00 0.00 OH 7,213.00 2.875 0.000 YNN 7,211.15 130.83 0.00 130.83 0.12 0.12 OH 7,712.00 3.250 0.000 YNN 7,709.44 157.49 0.00 157.49 0.08 0.08 OH 7,712.00 3.250 0.000 YNN 7,709.44 157.49 0.00 157.49 0.00 0.00 OH 8,212.00 3.875 0.000 YNN 8,208.47 188.56 0.00 188.56 0.13 0.13 OH 8,212.00 3.875 0.000 YNN 8,208.47 188.56 0.00 188.56 0.00 0.00 INC OH 8,552.00 3.875 0.000 YNN 8,547.69 211.54 0.00 211.54 0.00 0.00 INC OH 8,552.00 3.500 0.000 YNN 8,547.69 211.54 0.00 211.54 0.00 0.00 OH 9,049.00 3.750 0.000 YNN 9,043.70 242.96 0.00 242.96 0.05 0.05 OH 9,549.00 4.000 0.000 YNN 9,542.56 276.75 0.00 276.75 0.05 0.05 OH 9,935.00 3.500 0.000 YNN 9,927.73 301.99 0.00 301.99 0.13 -0.13 TEL OH 9,935.00 3.000 0.000 YNN 9,927.73 301.99 0.00 301.99 0.00 0.00 Printed: 1/9/2001 3:11:19 PM ������ � CARP '�" �� r ': 3 ; Qevia for S ` x Legal Well Name: Kustatan Field #1 Spud Date: 10/16/2000 sit # u s �z► { Common Well Name: Kustatan Field #1 Start: 10/16/2000 off 0.00 Event Name: ORIG DRILLING End: 12/14/2000 Contractor Name: NABORS ALASKA DRLG Rig Release: 12/14/2000 Rig Name: NABORS DRILLING Rig Number: 160 TMD: 12,258.00 (ft) T\/D: 12,246.52 (ft) Calcul Mnimum Crvature vR# T IC Angle R 1 t a i C11 7V N/ tion E tW ethod: Mi Sectg €1LS BUFF Type • (ft) 3 ... ( ° ) { ° , . t } { „ (? (ft.', ) { ° f140ft} { ° /100{tj OH 10,435.00 3.500 0.000 YNN 10,426.92 330.34 0.00 330.34 0.10 0.10 OH 10,758.00 3.500 0.000 YNN 10,749.32 350.06 0.00 350.06 0.00 0.00 OH 11,258.00 3.500 0.000 YNN 11,248.39 380.58 0.00 380.58 0.00 0.00 OH 11,758.00 3.500 0.000 YNN 11,747.45 411.11 0.00 411.11 0.00 0.00 OH 12,258.00 3.500 0.000 YNN 12,246.52 441.63 0.00 441.63 0.00 0.00 4/.. JgN1 0 /i 1 4 �h his �� Printed: 1/9/2001 3:11:19 PM 110 • zoo' - iof-3 0 t E Forest Oil Corporation Alaska Division 0 310 K Street, Suite 700 O.1 v Anchorage, Alaska 99501 Phone: (907) 258 -8600 Fax: (907) 258 -8601 DATA TRANSMITTAL Date: January 2, 2001 To: Lisa Weepie /Howard Oakland From: Barbara Murray AOGCC Forest Oil Corporation 3001 Porcupine Drive 310 K Street, Suite 700 Anchorage, AK 99501 Anchorage, AK 99501 Phone: (907) 279 -1433 Phone: (907) 258 - 8600 FAX: (907) 258 - 8601 TRANSMITTAL DESCRIPTION wa API Number Description Data From: ; ,/Kustatan #1 50- 133- 20496 -00 1 -CD containing Digital Well Data -LAS format Epoch `/Kustatan #1 50- 133 - 20496 -00 1 -Velum - Formation Log from 52 to 12300' Epoch Austatan #1 50- 133 - 20496 -00 1- reproduced copy - Formation log from 52' to 12300' Epoch `'Kustatan #1 50- 133 - 20496 -00 1- reproduced copy - Drilling Dynamics Log 52'- 12300' Epoch Kustatan #1 50- 133 - 20496 -00 1 -Final Well Report - includes Formation Summary, Epoch Daily Activity summary, Mud reports and bit records ustatan #1 50- 133 - 20496 -00 1- Blueline Array Induction, Density, N, GR,Cal - PE Schlumberger kustatan #1 50- 133 - 20496 -00 1 -Film Array Induction, Density, N, GR, Cal - PE Schlumberger (/Kustatan #1 50- 133 - 20496 -00 1- Blueline Dipole Shear Sonic, GR, CAL, AIT Schlumberger K ustatan #1 50- 133 - 20496 -00 1 -Film Dipole Shear Sonic, GR, CAL, AIT Schlumberger ✓Kustatan #1 50- 133 - 20496 -00 1- Blueline Caliper Gamma Ray Schlumberger Kustatan #1 50- 133 - 20496 -00 1- Film Caliper Gamma Ray Schlumberger 1/Kustatan #1 50- 133 - 20496 -00 1- Blueline Formation Micro - Imager Dipmeter Mode GR Schlumberger 4ustatan #1 50- 133 - 20496 -00 1 -Film Formation Micro - Imager Dipmeter Mode, GR 4 . Schlumberger 1/Kustatan #1 50- 133 - 20496 -00 1 -CD containing Openhole AIT, PEX,DSI, and DIAa Schlumbi 1 /0___/e7/ ie — i'2 .r. cri s' c., Z;45 vl ! 4 d7 ', Please sign below to acknowledge receipt. Received By: / ,/ r Date: J ( Returned to Forest Oil Date Accepted By: Date Modified:01 /02/2001 Kustatan #1 to AOGCC.xIs /Page1 Date Prepared: 12/6/00 bk • 0 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Julie Hsser DATE: December 14, 2000 Chairman /1� SUBJECT: Suspended Well -, THRU: Tom Maunder 'd L Kustutan Field #1 ,� Petroleum Engineer Forcenergy t c) 0 t)ccc.� ,�0 « -' Exploratory FROM: Lou Grimaldi r - ��__._ ' Petroleum Inspector PTD 41110101 ., NON- CONFIDENTIAL Section: 4 Township: 7 N Range: 14 W Meridian: Seward Lease No.: Drilling Rig: Nabors 160 Rig Elevation: Total Depth: 12,300 Operator Rep.: Derry Thompson Casing/Tubing Data: Casing Removal: Conductor: 20 O.D. Shoe@ 120' Casing Cut@ Feet Surface: 13 3/8" 0.D. Shoe@ 1820' Casing Cut@ Feet 1 Intermediate: 9 5/8" O.D. Shoe@ 6500', Casing Cut@ Feet Production: 7 5/8" O.D. Shoe@ 12,300' Casing Cut@ Feet Liner: O.D. Shoe@ Casing Cut@ Feet Tubing: O.D.' Tail@ Casing Cut@ Feet Plugging Data: Type Plug Bottom Top of Cement Mud Weight Pressure Founded on (bottom up) of Cement Death Verified? above plug Test Applied Type Plug Founded on: Verified? Open Hole Bottom Drillpipe tag Perforation Bridge plug Wireline tag Annulus Balanced C.T. Tag Casing Stub Retainer No Surface I arrived to find the rig crew nippling up the "Dry Hole Tree ". Upon completion the 9 5/8" and 7 5/8 combo production casing (7 5/8" tied to 9 5/8" shoe at approx 6500')was presuure tested to 3000 psi. After a initial 125 psi drop when the pumps were shutdown and blocked, the casing pressure remained constant at 2875 psi for twenty minutes. The 2 1/16" (2) and 3 1/16" (1) valves were closed and pressure tested. The casing and "Dry Hole Tree" appeared to have integrity. During the test the 13 3/8" casing valve was open to atmosphere and no fluid was observed coming from that opening. I suggested to Derry Thompson (Force Rep) that the 9 5/8" and 13 3/8" casing strings be freeze protected or at least blown down 15- 20 feet to prevent casing and well head damage. The well sign will be placed on the tree and location secured after the rig leaves. A subsequent inspection should be performed to verify clean -up compliance. Dc: Paul White (Forcenergy) Attachments: Casing Schematic (1) Distribution: orig - Well File c - Operator c - DNR/DOG c - Database c - Rpt File c Inspector Rev.:5/28 /00 by L.R.G. Suspended Well Kustutan Field .xls 12/16/00 kAgc �s .\4 t?DC* N'Q VC) ' t k—OLI \)3\ \ - s∎tss 0411 MEMORANDUM c i " Y State of Alaska Alaska Oil and Gas Conservation Commission TO: Julie Huesser DATE: December 14, 2000 Chairman SUBJECT: Suspended Well THRU: Tom Maunder Kustutan Field #1 Petroleum Engineer Forcenergy Exploratory FROM: Lou Grimaldi Petroleum Inspector PTD #200 -155 NON- CONFIDENTIAL Section: 4 Township: 7 N Range: 14 W Meridian: Seward Lease No.: Drilling Rig: Nabors 160 Rig Elevation: Total Depth: 12,300 Operator Rep.: Derry Thompson Casing/Tubing Data: Casing Removal: Conductor: 20" O.D. Shoe@ 120' Casing Cut@ Feet Surface: 13 3/8" O.D. Shoe@ 1820' Casing Cut@ Feet Intermediate: 9 5/8" O.D. Shoe@ 6500' Casing Cut@ Feet Production: 7 5/8" O.D. Shoe@ 12,300' Casing Cut@ Feet Liner: O.D. Shoe@ Casing Cut@ Feet Tubing: O.D. Tail@ Casing Cut@ Feet Plugging Data: Type Plug Founded on Bottom Top of Cement Mud Weight Pressure (bottom up) of Cement Depth Verified? above plug Test Applied Type Plug Founded on: Verified? Open Hole Bottom Drillpipe tag Perforation Bridge plug Wireline tag Annulus Balanced C.T. Tag Casing Stub Retainer No Surface I arrived to find the rig crew nippling up the "Dry Hole Tree ". Upon completion the 9 5/8" and 7 5/8" combo production casing (7 5/8" tied to 9 5/8" shoe at approx 6500')was presuure tested to 3000 psi. After a initial 125 *drop when the pumps were shut down and bloOkeak Casing pressure remained ooristant at 2875 gal for twenty minUt e. The 2'1/16" (2) and 3 1/16" (1) valves were closed and pressure tested: The cas)ng and 'Dry Hoa4 Traps appeared to have integrity. During the test the 13 3/8" casing valve was open to atmosphere and no fluid was observed coming from that opening. I suggested to Derry Thompson (Force Rep) that the 9 5/8" and 13 3/8" casing strings be freeze protected or at least blown down 15 - 20 feet to prevent casing and well head damage. The well sign will be placed on the tree and location secured after the rig leaves. A subsequent inspection should be performed to verify clean -up compliance. cc: Paul White (Forcenergy) Attachments: Casing Schematic (1) Distribution: orig - Well File c - Operator c - DNR /DOG c - Database c - Rpt File c - Inspector Rev.:5 /28/00 by L.R.G. Suspended Well Kustutan Field .xls 1/24/01 12/08/00 FRI 16:41 FAX 907 258 8601 FORCENERGY ALASKA 01002 • • • � FOREST R E S T O I L CORPORATION R P O R A T I O N 0 P. 370 Q2 ix.:.'l • C' i lr. 700 ns1,.., ' ,cj'v. (i/ t h' .95C'/ U (907) °..5_RI101) • (s107)2.1.9- Stc0/ December 8, 2000 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Attn: Mr. Tom Maunder Re: Kustatan Field #1 — Operation Shutdown Mr. Maunder We are currently running the 7 5/8" liner to the well TO of 12,300'. This operation was approved in the previous Application for Sundry Approvals for Kustatan Field #1. We will pressure test the liner to 3,000 psi and nipple up a temporary tree on the wellhead. We have chosen to stop operations on this well until time that we can complete it as a service well for the Redoubt Unit development. We request a Sundry Approval for an Operations Shutdown on Kustatan Field #1. If there are any questions, please contact me at 907458 -8600. Rob Stinso RECEIVED Drilling Engineer Forest Oil Corporation DEC 1 1 2000 Alaska 0+1 & Gas Cons. Commission Anchorage Date Modified: 121&00 Date Prepared: 12/6100 r3 S:U(ustatan FteldlStoppage 403.doc i' r0" `F11 `16 :41 F '' t;$'- 86$1'x' ' 'f.:ry , 4' _ , ps_ 4 0 # • S TATE OF ALASKA t-1- ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon' Suspend: Operation shutdown: X Re -enter suspended well: _ After casing: Repair well: Plugging: — Time extension: Stimulate: Change approved program: Put tubing: Variance: Perforate: Other: 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Forest OiI Corporation Development: 260' MSL 3. Address Exploratory: X 7. Unit or Property name 310 K Street. Suite 700 Stratigraphic: N/A Anchorage. Alaska 99501 Service: 4. Location of well at surface 8. Well number 3443' FNL, 1468' FWL, Sec. 4, 17N, R14W, SM Kustatan Field 01 At top of productive interval 9. Permit number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 200 -153 At effective depth 10. API number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 50- 133 - 20496 -00 At total depth 11. Field/Pool 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM NIA 12. Present well condition summary Total depth: measured 12,300' Plugs (measured) true vertical 12.300' Effective depth: measured 12,300' Junk (measured) true vertical 12,300' Casing Length Size Cemented Measured depth True vertical depth Structural N/A N/A WA N/A NIA Conductor 120' 20" Driven 120' 120' Surface 1,820' 13318" Surface 1,820' 1,820' Intermediate 6,500' 9518" TOC 3,000' 6,500' 6,500' Production (Liner) Line RECEIVED Perforation depth; measured true vertical DEC 1 1 2000 ' Tubing (size. grade. and measured depth) al & Conk. Commission 0 "? / Alaska S ,anchorage Packers and SSSV (type and measured depth) 13. Attachements Description summary of proposal: X Detailed operations program: _ BOP sketch: — 14. Estimated date for commencing operation 15. Status of well dasslflcation as: 10- Dec -00 16.- ltproposal Well-verbally approved: Oft: X Gas; - Suspended: Name of approver Date approved Service: 17.1 hereby certify that the foregoing le true and correct to the best of my knowledge. /,, Signed: �� /� Title: Drilling Engineer. Forest OiI Corporation Date: / ;D o FOR COMMISSION USE ONLY r Conditions of approval: Notify Commission so representative may witness Approval No. Plug integrity BOP Test Location clearance .. ) '-'51/ _ Mechanical Integrity Test Subsequent form required 10- L '1Oy \ ith$ t COOKNCV5 r ':,i NAL SIGNEUY ._r pvlor SP'1rnount ' ApAroved try order of the Commissioner Commissioner Date 0 61 / Form 10-403 Rev 08x15188 _ - SUBMIT IN T ' - ICATE I • NOTE TO FILE Kustatan #1 (200 -153) On November 29, Force Energy called to request a change to their approved drilling program for the subject well. They proposed to deepen the setting depth of their 7 -5/8" liner since they had drilled the G zone and it was "dry". Force submitted form 403 (300- 298) on November 30. The form was passed on recommending approval. Drilling operations continued and the well reached TD about December 4. Logging commenced and I am informed that the well was not successful as originally planned. On December 6, I was contacted by Rob Stinson regarding their ongoing operations and informed that Force /Forest had determined that they did not wish to complete the well as originally planned. They proposed to run and cement the deep liner as planned then suspend the well, intending to complete the well as a water supply well for their Osprey waterflood. I informed Rob that according to our regulations, to properly suspend a well, plugs would have to be set. He indicated they would like to avoid this and we discussed a temporary shutdown of drilling or completion operations. Force /Forest has submitted a 403 requesting temporary shutdown of completion operations. In their proposal, it is indicated that following the cementing of the 7 -5/8" liner they plan to test the welibore to 3000 psi and then install a "dryhole" tree. Force did not plan to run any tubing into the well. Further discussions with Rob Stinson did not indicate that they presently would plan to conduct any operations in preparation for the water well completion. I discussed this proposal with Lou Grimaldi and it was Lou's intent to be on the well site to witness the wellbore pressure test and tree test. It was Lou and my agreement that with the wellbore properly pressure tested and the final mud weight in the welibore that the well would be satisfactorily secured Our regulations at 20 AAC 25.072 allow for a temporary shutdown of drilling or completion operations (a) if circumstances prevent the continuation of the program approved on a Permit to Drill... A temporary shutdown is approved for a initial period not to exceed 1 year per section (d). It is provided that the operator can apply for an extension. Since the initial discussions were had with Force /Forest, a problem was encountered pressure testing the welibore. I was notified of the problem the morning of December 11 and subsequent information was received by fax later the same day. Investigation has revealed that the 9 -5/8" casing has separated at about 88' rkb. Presently it is not known what could have caused the casing to fail. Force /Forest has proposed to repair the casing by fishing the upper 2 joints, backing of an additional joint and then running new casing back to surface. According to the information received from Rob Stinson and Paul White, the well is stable with the only formations open to the welibore Tying below the 13 -3/8" shoe to the top of the 9 -5/8" cement. No shows were expected through this interval and none have been reported. The mud used to TD the 12 -1/4" hole section weighed 9.3 and that mud weight remains in that annulus. • 1 I reviewed the proposed repair plans with Chuck Scheve. We are in agreement that Force has few options other than they have proposed. We discussed formation isolation provided by the remainder of the 9 -5/8" casing and the 7 -5/8" liner. Both tubular strings have been cemented and pressure tested. A liner top packer was run on top of the liner and the required steps were take to energize the packer. No pressure test of the packer could be accomplished due the casing leak. Following the repair, they still intend to temporarily stop further operations on the well. Once their repair is effected, I believe it would still be prudent to have one of the inspectors travel to the drilling location to witness the wellbore and tree pressure tests. & T. E. Maunder Petroleum Engineer December 12, 2000 W 2/11/00 MON 15:16 FAX 907 258 8601 FORCENERGY ALASKA a002 • 4110 MEMORANDUM TO: Tom Maunder VIA FAX 0 \S3 FROM: Paul White If ' V DATE: December 11, 2000 SUBJECT: Kustatan Field #1 Casing Break Repair Tom, Listed below are the remedial steps that we are taking to repair the break in the 9 5/8" intermediate casing, which is at 88' MD on Kustatan Field #1 . 1.) Nipple Down BOP to de- energize the casing slips in wellhead. 2.) Remove upper two joints of 9 5/8" casing with spear. 3.) Remove third joint (break between joints #2 and #3) with spear and a string shot. 4.) Run in with three good joints of 9 5/8" casing, screw into the existing string. 5.) Pick up the 9 5/8" and set the slips in the wellhead. Cut of the excess 9 5 /8" 6.) Nipple up the remainder of the wellhead and tree. w.)cr` \cE� ri �� ov � � �s`� ss pcoQoss� 3 c-c) 30010Qs % y R 5Q Dc b.N\ �A- \,c ESSJ- k— t � C� CSJ 5� V�Q�� �S 5���� � M� \ �SiSs� \� cAl'xry \- ZS \\ So sN.c�. �ucsc c �Q`�n w, \ P S \ �r� bcac�o '' �Sar �r�c C�S Date Modified: 12/11/00 Date Prepared: 12/11/00 rs WwNCHFLS11 #ANC_DRILLING1Kustaten FieId\CesIng Breakdoc Pagel of 1 00 MON 14:40 FAX 907 258 8601 FORCENERGY ALASKA j 001 ,, FOREST OIL CORPORATION 9 310 K Street, Suite 700 Anchorage, Alaska 99501 ' ` (907) 258 -8600 - Office (907) 258 -8601 - Fax TO; J / k rl der. - FAX NUMBER: 2 76 - % 5 DATE: /?VJr /00 — v FROM: / PHONE NUMBER: 1. LS "l TIME: Total Number of Pages Including Cover Sheet: CQMMENTS: • • 12/11/00 MON 14:40 FAX 907 258 8601 FORCENERGY ALASKA IA 002 0 0 Kustatan Field #1 Casing Schematic N. RKB 260' MSL „.. ,Iv CO L YH rs, tie . N. 20" 133 #,L -80 BTC '! A 120' MD, 120' TVD Driven ` I e*y 13 3/8" 68#, L -80 BTC' ` 1820' MD, 1820' TVD 171 /2" Hole Iv ' TOC 5000' • r`v I4 r` ,., , ? ►_4� 9 5/8" 47 #, L -80 BTC ' .' 6500' MD, 6500' TVD 12 1/4" Hole moo WI- i 0 HOLE @ 7O o F (4 74 ` 14o LE 1N () ,3 PO G ;:k Ae I TOC 10150' ■ 4 7 n E • 7 -518" 29.7 #, L -80 STL �' f � ` ,� ;� 12300' MD, 12300' TVD 8 1/2" Hole F %ti!��!��!Kti!� 1129/00 WED 15:32 FAX 907 258 8601 FORCENERGY ALASKA l 002 Forcenergy Inc November 29, 2000 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive 1 Anchorage, Alaska 99501 Attn: Mr. Blair Wondzell Re: Kustatan Field #1 Mr. Wondzell As per our phone conversation this morning, we request Sundry Approval to change the casing plan on the Kustatan Field #1 exploration well. The original well plan had us setting a 7 5/8" liner at the top of the Hemlock at approximately 11,500' and setting a 5 liner across the Hemlock formation to a depth of 13,000'. The primary reason for this was to protect the G -zone sands for possible future testing. The g -zone has been drilled and is non- productive. We now propose to continue drilling the 8'/2" hole to the bottom of the Hemlock (approximately 12,200' to 12,300') and run the 7 5/8" liner to this TD. This would avoid running an unnecessary liner and make our testing program on the Hemlock more straight forward. The 7 5/8" liner would be cemented up from TD up to 10,500'. Casing calculations have been run on this change and there are no problems with burst, tension or collapse safety factors. If there are any questions, please contact me at 907 - 258 -8600. �'� V rep- ` ?0.3 ``f e t a. �,�. Paul White �� r ®� Drilling Manager Wc�S`c � Forcenergy Inc. C.5(N - r Date Modified: 11/29/00 Date Prepared: 11/29/00 rs S:1Kustatan FieldWner 403.doc 11/29/00 WED 15:32 FAX 907 258 8601 FORCENERGY ALASKA I]]003 S STATE OF ALASKA •t ALASKA OIL AND GAS CONSERVATION COMMISSION 30 APPLICATION FOR SUNDRY APPROVALS - 1. Type of Request: Abandon: Suspend: Operation shutdown: Re -enter suspended well: — Alter casing: X Repair well; Plugging: Time extension: Stimulate: — Change approved program: Pull tubing: Variance: Perforate: Other: 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Forcenergy Inc. Development: 260' MSL 3. Address Exploratory: X 7. Unit or Property name 310 K Street, Suite 700 Stratigraphic: _ N/A Anchorage, Alaska 99501 Service: 4. Location of well at surface 8. Well number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM Kuetatan Field * At top of productive interval Q. Permit number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 200-153 At effective depth 10. API number 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 50- 133 - 20496 -00 At total depth 11. Field /Pool 3443' FNL, 1468' FWL, Sec. 4, 17N, R14W, SM N/A 12. Present well condition summary Total depth: measured 11,590' Plugs (measured) true vertical 11,590' Effective depth: measured 11,590' Junk (measured) true vertical 11,590' Casing Length Size Cemented Measured depth True vertical depth Structural N/A N/A N/A N/A N/A Conductor 120' 20" Driven 120' 120' Surface 1,820' 13 3 /8" Surface 1,820' 1,820' Intermediate 5,500' 9 5/8" TOC 5,000' ,,6,500 6,500' Production (Liner) Liner Perforation depth: measured true vertical °R , , .„ : ,., ,,,,,,,,..,;._ , - Tubing (size, grade, and measured depth) G/ 4 Packers and SSSV (type and measured depth) 13. Attachements Description summary of proposal: X Detailed operations program: _ BOP sketch: 14. Estimated date for commencing operation 15. Status of well classification as; 1-Dec-00 16, If propo II erbally approv Oil: X Gas: Suspended: Nam -' . • •ro Date approved Service: 17. I hereby cert t t the foregoing is true and correct to the best of my knowledge. Signed: Title: Drilling Manager, Forcenergy, Inc. Date: `1 2 - , `i Q■ FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Approval w N No. Plug integrity BOP Test Location clearance jag --21 Mechanical Integrity Test Subsequent form required 10- rt-,ss ■Q 1 ORIGINAL SIGNED BY ��� Approved by order of the Commissioner M. Heusser Commissioner Date // :�"� Form 10 -403 Rev 08/15/88 SUBMIT IN TRIPLICATE • USDW Protection Geologic Prognosis Kustatan Field #1 Properly cemented surface casing will protect USDW's that have salinity of less than 3,000 PPM. Well log analysis in the nearby RS ST 29690 -1 well indicates water- saturated sands below a depth of about 1,800 feet TVD have formation water salinities above 3000 ppm NaCl. Steve Davies October 12, 2000 ■ 10/11/00 WED 07:45 FAX 907 258 8601 FORCENERGY ALASKA 0 001 0 Forcenergy Inc Q 310 K Street, Suite 700 Anchorage, Alaska 99501 (907) 258 -8600 258 -8601: FAX FAX TRANSMITTAL SHEET 'y DATE: f€00/0► PAGES TO FOLLOW TO: er j P." Von qi.z. G // -, 4 k — ' ,, , FAX: 2 je 75V2 Phone: 02 7 7 — /r?3 '61; =$. %r, FROM o 4 i7 .S'Qy _ CONFIDENTIALITY NOT The information in this facsimile transmittal Is legally privileged and confidential information intended only for the use of the individual or entity named above. If the reader of this message Is not the intended recipient. you are hereby notified that any dissemination, distribution or copy of the transmittal is strictly prohibited. If you receive this transmittal in error, please immediately notify us by telephone, and return the original transmittal to us at the above address via the United States Postal Service. Thank you. rAXALA.DOc tin 1 - MESSAGE: -43 4 5 - q 6 1 17 063C a sic . `an .5 g. lo! A Bevil 4 lit t4 4 it / &.` Ii e- ® � h yeSo . %'4 3 41 P A VG ee Y 1 s4.. /fl,; c 44s7/0 old u 4 '4 r ef L..es AI 4 y s<e 23 44/A41 Cc : 7••t /1d— e frs - 10 /11 /00 WED 07:4S FAX 907 258 8601 FORCENERGY ALASKA 0 002 . • October 3, 2000 To: Paul White From Art Saltmarsh Cc: Gary Carlson John Amundsen Rob Stinson Rob Jeffery Salinities and Calculation Methods The following discussion addresses all of the available data relating to water salinities, lithologies, formations, porosities and permeabilities. A petrophysical analysis was performed on the logs from the PanAm Redoubt Shoal 29690 #1 and the PanAm West Foreland # 1 wells to determine the salinities of the formation waters in the Tyonek sands. The accompanying logs will demonstrate that salinities climb to above 10,00ppm CI, below a depth of 3000 ft. TVD, and remain at least that high to the TD of the wells. Salinities for the formations from seafloor to TD have been determined for all of the wells in the proposed location area of the West Forelands and the Redoubt area also. The method used calculates a Temperature curve, a Rwa curve from induction logs, and calculated porosities from sonic data, and utilizes a formula developed by Schlumberger Wireline. The equation is as follows: ppm CI = 5472 Rwl temp + 6.77 ) / 63.4 - 0.01255 )^ - 1.0397 1 have also reviewed the information supplied by Bob Crandall, AOGCC, concerning the EPA standards for calculating total dissolved solids (TDS) from well logs. The booklet titled Survey of Methods to Determine Total Dissolved Solids Concentrations is used by the EPA as a guideline for UIC (Underground Injection Control). 10 /11 /00 WED 07:45 FAX 907 258 8601 FORCENERGY ALASKA 0 003 • I have utilized this formula for recalculating the salinities of the Tyonek section of wells in the Redoubt Unit area. The method is essentially the same as I originally used for calculating salinities from logs, the difference being the actual conversion of Rwa to TDS. The original formula used was developed by Schlumberger from well data in Tertiary, clastic non- marine basins in Southeast Asia. Although I believe the Schlumberger method to be a closer analogy for the Cook inlet, the results from the EPA method are very close to the original calculations. I have plotted the logs and have included salinity curves of both methods for comparison. The curve named sal_slmb (red) is the calculated salinity using the Schlumberger formula, and the curve named sal_epa (green) is the EPA formula. At most depths, the curves almost overlay. There is an alternative method for calculating salinities of formation water utilizing the SP curve. In the Cook Inlet, SP logs are notoriously bad and cannot be relied on to give accurate salinity values. When salinities from a tested water zone are compared with values derived from the SP curve, there is usually a large degree of difference between the values. For this reason, the Rw (Rwa) method was selected as being more consistent and accurate. The intervals that will be penetrated at the location of the Osprey Platform from top to bottom are the Beluga/Tyonek, G-zone, Hemlock, West Foreland and the pre - Tertiary. The interval for the proposed disposal is the upper Tyonek sands. The top of the Tyonek sands is difficult to pick accurately from logs as the contact between the Tyonek and the overlying Beluga is transitional. There are no distinctive marker beds present either, but it is believed that there is approximately 1600 ft of Beluga section in the Redoubt area. In general, salinities remain high and actually increase with depth to generally over 10,000 ppm Cl, down to at least 8000' sstvd. 10 /11 /00 WED 07:46 FAX 907 258 8601 FORCENERGY ALASKA Ia004 • Confining Layers Log displays for the wells included in the report, show that the Beluga section contains thick silty / claystone sections with thin discontinuous interbedded sands. There are also numerous coals, and although they are not seals in themselves, they add to the ability of the section to confine any upward migration. The depositional environment of the Beluga is fluvial in nature, with meandering stream channel sands and overbank deposits. The Tyonek is also fluvial in nature, but consists of anastomozing stream channels. This type of environment produces a more `blanket sand' effect and is more vertically and horizontally continuous than the Beluga. Within the Tyonek, thicker coals and claystones will act as confining layers for the upward migration of fluids. Reservoir Parameters Porosities and permeabilities are good in this shallow section. The upper Tyonek sands are very friable as are the Beluga sands, and have porosities ranging from 20 -30 %. They are fine to medium grained, well rounded and well sorted. Due to these high porosities, injection into the upper Tyonek sands should pose no problems. Continuity of Upper Tyonek The seismic cross - section included in this report shows the relevant shallow section of Beluga and Tyonek. The cross-section runs from the proposed Osprey location across the location of the Redoubt Shoal State 29690 #1 well. The top of the Beluga can be seen on the well trace for the RS 10 /11 /00 WED 07:46 FAX 907 258 8601 FORCENERGY ALASKA 0005 • • St. 29690 #1 well. There appears to be good continuity within the zone we propose to disposal 10 /10 /00 TUE 10:59 FAX 907 258 8601 FORCENERGY ALASKA 0 002 • F�rcenergy Inc October 10, 2000 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Attn: Blair Wondzell Re: Application for Permit to Drill Clarifications Kustatan Field #1 This letter will clarify the questions that have arisen from the Application for Permit to Drill for the Kustatan Field #1 well. The mud and cuttings generated from the well will be hauled to the West McArthur River Facility. The cuttings will be dumped in the existing ADEC approved Drilling Waste Management cell and the liquids will be injected into West McArthur River Unit #4D, a dedicated Class II disposal well. All offset well information indicates that the in -situ pore - pressure gradient will be 0.45 psi /ft throughout the entire wellbore. However, after further review we would like to amend the Formation Integrity Test on the Surface Casing shoe to 11.0 ppg EMW. The offset well logs and seismic line were submitted last week with the request for surface hole size waiver. If there are any questions, please contact me at 258 -8600. Paul White Drilling Manager Forcenergy Inc. SiraTTEE 0 ' AilLASEn l t TONY KNOWLES, GOVERNOR ALASKA OIL AND GAS 3001 PORCUPINE DRIVE CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3192 PHONE: (907) 279 -1433 FAX: (907) 276 -7542 Paul White Drilling Manager Forcenergy Inc 310 K Street, Ste 700 Anchorage, AK 99501 Re: Kustatan Field #1 Forcenergy Inc Permit No: 200 -153 Sur. Loc. 3443'FNL, 1468'FWL, Sec. 4, T7N, R14W, SM Btmhole Loc. 3443'FNL, 1468'FWL, Sec. 4, T7N, R14W, SM Dear Mr. White: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. 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. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below the surface casing shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission at 279 -1433. incerely, */ _,--- Daniel T. Seamount, Jr. Commissioner BY ORDER OF THE COMMISSION DATED this / 3 1.. t day of October, 2000 dlf/Enclosures cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o end. 0 Forcenergy I 1 September 25, 2000 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Application for Permit to Drill (Form 10 -401) Kustatan Field #1 A Permit to Drill is requested to drill Kustatan Field #1 an oil exploration well on the West Forelands. The primary target of this well is oil in the Hemlock formation. A 5 ' /a" production liner will be run across the Hemlock if logs look favorable. The Hemlock will be tested, along with any other zones of interest that show potential from logging. If there are any questions, please contact me at 258 -8600. R6VocK?:. Paul White Drilling Manager Forcenergy Inc. Re -, , ,.. '-,,,, . „ %-tt--.1 iii.. r) OUPLI CATS ask . SAP 2 2000 tr iad ,„ STATE OF ALASKA ALASKA 01 *ND GAS CONSERVATION gliV1MISSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of work Drill: X Redrill: 1 b. Type of well Exploratory: X Stratigraphic Test: Development Oil: Re -Entry: Deepen: Service: Developement Gas: Single Zone: Multiple Zone: 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool Forcenergy Inc. 260' RKB feet N/A 3. Address 310 K Street, Suite 700 6. Property Designation N/A Anchorage, Alaska 99501 ADL- 387023 4. Location of well at surface 7. Unit or property Name 11. Type Bond (see 20 AAC 25.025) 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM N/A At top of productive interval 8. Well number Number Statewide #RLB0001940 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM Kustatan Field #1 At total depth 9. Approximate spud date Amount $200,000 3443' FNL, 1468' FWL, Sec. 4, T7N, R14W, SM 1 -Oct-CO 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and ND) property line 803 feet 3 Miles 5026 13,600 feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickoff depth: N/A Maximum hole angle: 0 Maximum surface 4556 psig At total depth (ND) 6120 psig 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) N/A 20" 133 # K-55 N/A 120' Surf Surf 120' 120' Driven 17 1/Z' 133/8" 68 # L-80 BTC 1600' Surf Surf 1600' 1600 2236 cu ft 12 1/4" 95/8" 47# L-80 BTC 6500' Surf Surf 6500' 6500' 644 cu ft 8 1/2" 75/8" 29 # L-80 Hyd 521 5200' 6300' 6300' 11500' 11500' 171 cu ft 63/4' 5 1/2" 17 # L-80 Hyd 521 1700' 11300' 11300' 13000' 13000' 206 cu ft 43/4' N/A N/A N/A N/A 600' 13000' 13000' 13600' 13600' _ N/A 19. To be completed for Redrill, Re -entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True vertical depth Conductor Surface Intermediate Production Liner Perforation depth: measured true vertical 20. Attachments: Filing fee: X Property Plat: X BOP Sketch: X Diverter Sketch: Drilling program: X Drillin_• flu program: X Time vs. depth plot: Refraction analysis: Seabed report: 20 AAC 25.050 requirements: X 21. I herby erti i that the foregoing is true and correct to the best of my knowledge: �t Signed: \ `W ' I Paul White Title: Drilling Manager Date: d L d 0 Commission Use Only Permit Num er API number �/ Approval date See cover letter % /6,3 50- / 33 • d O g. a/ 0" /p -G for other requirements Conditions of approval Samples required: ti Yes [ ] No Mud log required: NI Yes [ ] No Hydrogen sulfide measures [ ]Yes (No Directional survey required [ ] Yes Ni No 1 t ., 4 , 5\ ,�� Required working pressure for BOPE [ ] 2M; [ ] 3M; I] 5M; [ ] 10M; [ ] 15M c i� Other: juQ14s2! c lla1Pi2r pi ra4.. by order of Approved by ORIGINAL SIGI�i i _ = - '' Commissioner the Commission Date " / ' j U I aylor Sedrrrvulit RECEIVED Form 10-401 Rev. 12 -1-85 Submit in triplicate ORIGINAL sFp262000 A In.J. rloi 0 rr.... ^..-- A_Yr:_ -t -_ 1235 Received 401 for Force exploration well from Steve...got application yesterday and they want permit for SUNDAY... Kustatan Field #1 (200- 153)... plan is to drill an exploration well on the West Side. Contact Rob or Paul and left a message regarding if the spud date is real or not. cx-r3cb\v-riz> )j r c , \ Rob called @ 1320...spud date should have been changed...spud more probable October 15. D \ ' s}ar, \x Propose to use 20" diverter w/16" line and drill 17 -1/2" hole... not according to the regs. Propose to test a 3000 psi stack to 4000 psi. Looks like .a typo. 5cYX ' V CEO? 13 -3/8" casing test to 3000 psi... LOT to 10.5 @ 1600'... MASP for next hole section is 2178 psi... MW 9.2 -9.4 ht r� ors `' 1 � 1 � 9 -5/8" casing test to 3000 psi... LOT to 10.5 @ 6500'... MASP for next hole section is 3853 psi... 'N\ b� � C" OCO MW 9.0 -10.0. 7 -5/8" liner test to 3000 psi... LOT to 10.5 © 11500'... MASP for next hole section is 4355 psi... MW 9.5+ 5 -1/2" liner test not specifies... LOT to 10.5 © 13000'... MASP for next hole section is 4556 psi... MW 9.5+ Looking at casing design...All strings from 9 -5/8" down should use the MASP from TD for burst calculations. Since all are liners they all could see the MASP from TD. i - xxxxxxxxxX Attachments 1. Outline Procedure 2. Well Plan schematic 3. Unit Maps 4. Drilling Fluids Program 5. Pressure Information 6. Casing Design 7. Cement Calculations 8. Nabors BOP schematic 9. Forcenergy Wellhead Configuration 10. Nabors BOP equipment list 11. Nabors Drilling Fluid System Description 12. Drilling Hazards RECEIVED ORIGINAL c,P 262000 Alaska Oil & Gas Cons. Commission Anchorage • • Kustatan Field #1 Summary of Drilling Hazards POST THIS NOTICE IN THE DOGHOUSE AI Potential of normally pressure gas below 3,500'. AI Lost circulation is unlikely, however lost circulation potential increases when crossing faults. H2S has never been encountered in the West McArthur River Field, nor the West Forelands Field, both of which are up -dip in this structure. CONSULT THE WELL PLAN FOR ADDITIONAL INFORMATION SEP 26 2000 A! afa Oil n, r: • • Kustatan Field #1 OUTLINE PROCEDURE 1. Drive 20" conductor to 120' or refusal. 2. Move in and rig -up Nabors Rig 160. 3. Nipple up 2000 psi Diverter with 16" outlet 4. Drill 17 hole to 1,600' 5. Run and cement 13 3/8" surface casing to 1,600'. Bring cement returns back to surface. Note: Duplex cement job will be performed with a side ported float shoe. 6. Install slip -on type 13 5 /8 "JM casing head and 13 5/8" BOPE. Note: 13 5/8" 5M x 13 5/8" 3M DSA will be necessary for nipple -up. 60% 7. Test BOPE to A,000 psi (80% maximum working pressure). 8. Test casing to 3000 psi 9. Perform Formation Integrity Test to 10.5 ppg EMW. Note: Perform FIT after drilling a minimum of 20' out of the casing shoe, but no more than 50'. 10. Drill 12' /a" hole to 6,500'. 11. Run electric logs 12. Run and Cement 9 5/8" casing to 6,500'. Target top of cement is 5,000'. 13. Test casing to 3,000 psi. 14. Test BOPE to 4,000 psi (80% maximum working pressure). 15. Perform Formation Integrity Test to 10.5 ppg EMW. Note: Perform FIT after drilling a minimum of 20' out of the casing shoe, but no more than 50'. 16. Drill 8 hole to 11,500'. 17. Run electric logs 18. Run and cement 7 5/8" liner from 6,300' to 11,500'. Liner will be run on 5" drill pipe, with a hydraulic set hanger and mechanical set packer. Target top of cement will be 10,000'. 19. Change BOP ram configuration for 3 1 /2" x 5" tapered drill string. Test BOPE. 20. Test casing and liner -top packer to 3,000 psi. 21. Perform Formation Integrity Test to 10.5 ppg EMW. Note: Perform FIT after drilling a minimum of 20' out of the casing shoe, but no more than 50'. 22. Drill 6 3 /4" hole to 13,000' 23. Run and cement 5 1/2" liner from 11,300' to 13,000'. Liner will be run on a tapered 5 "and 3 1 /2" drill pipe string, with a hydraulic set hanger and mechanical set packer. The entire 5 1 /2" liner will be cemented. RECEIVED ORIGINAL °FP 26 2000 Alaska Oil & Gas Cons. Commission rr p 4 10 24. Perform Formation Integrity Test to 10.5 ppg EMW. Note: Perform FIT after drilling a minimum of 20' out of the casing shoe, but no more than 50'. 25. Drill 4 3/4 "hole to 13,600'. 26. Run electric logs across 4 3/4 " hole. 27. Plug 4 3/4 " hole with cement, with a displacement plug RECEIVED ORIGINAL C�P 262000 Alaska Oil P Gas Cons. Commission Anchorage • 0 Kustatan Field #1 Casing Design RKB 260' MSL ri l 3 1/2" 9.3 #, L -80 Tubing f # 20" 133 #,L -80 BTC ® ' 120' MD, 120' TVD Driven F . P1 4: e F yam 0. 13 3/8" 68 #, L -80 BTC l -- 4600' MD, 1600' TVD 17 1/2" Hole r ..s1 ss 9 5/8" 47 #, L -80 BTC 4 \ 6500' MD, 6500' TVD 12 1/4" Hole 0. 7 -5/8" 29.7 #, L -80 Hyd 521 ,° ri . 11500' MD, 11500' TVD 8 1/2" Hole r' r PA 5 -1/2" 17 #, L -80 Hyd 521 4d !• 13000' MD, 13000' TVD 6 3/4" Hole 4 3/4" Pilot Hole 13600' MD, 13600' TVD RECEIVED ORIGINAL sFp 262000 Alaska Oil & Gas Cons. Commission Anchorage • 410 181300 1e38 ee 184100 187000 . teepee term 19 pee 195000 197000 - 1 2468000 32 3 3 1 ? 4 1 2466000 1 T. 8 N. ! i 2464000 T. 7 N. 1 1 2462000 1 4 -f Kustatan Field No. 1 .... 0 x = 186839 feet 1 y = 2460784 fee 2460000 Datum: NAD 27 iska State Plane 4 Latitude: 60.7 15 Degress North Longitude: —151.7- •I'l Degress West 78 W 387023 \ , 2458000 I 1 8 q 1 i , 1 2456000 1 i 1 1 2454000 1 1 i 2452000 1 1 ...- If I t: 1 5 2458000 Kustatan Field No. 1: Surface/Bottom Hole Location (T. 7 N . — R. 14 W.) H„ EN; `'-.,:: 'r I-7 ORIGINAL sEp 2 6 2000 Alaska Oil & Gas Gons. Commission • 410 KUSTATAN FIELD #1 DRILLING FLUID PROGRAM Interval 0' - 1,600' Hole size = 17 1/2" Casing Size = 13 3/8" Mud type = Gel -Gelex Drilling Fluid Parameters: Weight: 9.0 - 9.4 ppg PV: 8- 10 cps YP: 35 -45 lb /100ft API Fluid Loss: n/c Funnel Viscosity 150 -250 sec /qt Total Drilled Solids 3-5% This interval may be drilled with a mud system built with fresh water, bentonite, polymer extender, barite, soda ash and caustic. A polymer may be added to the mud system for fluid loss control just prior to running the casing. • Lower hardness of make -up water with additions of Soda Ash. • Build spud system with 25 ppb pre- hydrated bentonite in make -up water. Add gelex to increase viscosity as needed. • Raise viscosity if gravel sections are encountered. • Build additional volume as needed. • Utilize all solids control equipment to control drill solids. • Maintain adequate funnel viscosity. • Pump high viscosity sweeps if hole cleaning becomes a problem. • Add 2 -4 drums of Drilling detergent to system if bit balling becomes a problem. • Estimated volume usage - 1450 barrels. CV O c; 2 6 2000 k %;Aaska E ii & Gas Cons. Commission .Anchorage • • Interval 1,600' — 6,500' Hole size = 12 Casing Size = 9 5/8" Mud type = Low Solids — Non Dispersed/Dispersed Drilling Fluid Parameters: Weight: 9.2 — 9.4 ppg PV: 10- 20 cps YP: 15 -25 lb /100ft API Fluid Loss: <14 cc's pH 9.0-9.5 Total Drilled Solids 5 -8% • Drill float collar, cement and shoe with 17 1/2" hole mud. • Treat cement contamination with Sodium Bicarbonate additions. • Build additional volume as needed. • Use all solids control equipment. • Keep drill solids below 8% through solids control equipment utilization and dilution if needed. • NOTE: If disposal becomes too difficult, disperse system as needed to tolerate more drill solids and reduce disposal cost. • Treat sloughing coal with 2 -4 ppb soltex. • Add 2 -4 drums of Drilling detergent to system if bit balling becomes a problem. • Lower fluid loss to less than 14 cc's API with Polypac UL additions prior to running casing. • Estimated volume usage —1466 barrels. EVE r p 26 2000 Alaska Oil & Gas Cons. Commission Anchorage • Interval 6,500' — 11,500' Hole size = 8 1 /2" Casing Size = 7 5/8" Mud type = Low Solids Non - Dispersed/Dispersed Drilling Fluid Parameters: Weight: 9.0 — 10.0 ppg PV: 8- 12 cps YP: 10 -20 lb /100ft API Fluid Loss: 12 -14 cc's Gel Strengths 10 -20 lb /100ft2 Total Drilled Solids 8% or less • Drill out cement, float equipment and 10 feet of new hole with mud from the 12 1 /4" interval. • Condition mud as needed to treat out cement contamination and use in this interval. • Add 2 -4 ppb Soltex to mud system if sloughing coal becomes a problem. • Maintain API fluid loss at 12 -14 cc's with Polypac UL additions. • Keep drill solids below 8% through solids equipment utilization and dilution if needed. • NOTE: If disposal becomes too difficult, disperse system as needed to tolerate more drill solids and reduce disposal cost. • Consider the use of DriIXT to enhance the performance of PDC bit runs. • KlaGard ( @4 ppb) may be added to reduce dilution and disposal costs. • Add 2 -4 drums of Drilling Detergent to system if bit balling becomes a problem. • Condition hole prior to running 7 5/8" liner (reduce progressive gel strengths as needed). • Estimated volume usage —1175 barrels. C ;.�� E [ n s \ ! \ " qzP 262000 Alaska Gil & Gas BAs. Commission Anchorage • Interval 11,500 13,000' Hole size = 6 3/4" Casing Size = 5 1 /z" Mud type = PHPA Polymer Drilling Fluid Parameters: Weight: 9.5 + ppg PV: 8- 12 cps YP: 8 -25 lb/100ft API Fluid Loss: 6 -8 cc's +/- Gel Strengths 10 -20 lb /100ft2 Total Drilled Solids 5% or less • Drill out cement, float equipment and 10 feet of new hole with mud from the 8 1/2" interval. • Build new PHPA mud system with 1 ppb FloVis; 0.5 -1.0 ppb Polyplus RD; 1 ppb Polypac UL; Caustic Soda for 9.0 pH; M -I Bar for mud weight as needed. • Build additional volume as needed. • Add 2 -4 ppb Soltex to mud system if sloughing coal becomes a problem. • Maintain API fluid loss at 6 -8 cc's with Polypac UL additions. • Keep drill solids below 5% through solids equipment utilization and dilution if needed. • Daily treatments of Polyplus RD will be needed to maintain 0.5 -1.0 ppb concentration. • KlaGard ( @4 ppb) may be added to reduce dilution and disposal costs. • Condition hole prior to running 5 1 /z" liner (reduce progressive gel strengths as needed). • Estimated volume usage —1280 RECEIVED r 'N t g rz 4,w.. Sip 26 2000 Alaska Oi & Gas Cons. Commission Anchorage • • Interval 13,000 — 13,600' Hole size = 4 3 /a" Casing Size = N/A Mud type = PHPA Polymer Drilling Fluid Parameters: Weight: 9.5+ ppg PV: 5 -10 cps YP: 10- 201b /100ft API Fluid Loss: n/c Gel Strengths 10 -20 lb /100ft2 0 Total Drilled Solids 5% or less • Drill out cement, float equipment and 10 feet of new hole with mud from the 6 3 /4" interval. • Evaluate 6 3 /4" interval fluid for use in 4 1/4" pilot hole. Condition and re -use fluid if economically feasible. • Build additional volume as needed. • Add 2 -4 ppb Soltex to mud system if sloughing coal becomes a problem. • Keep drill solids below 5% through solids equipment utilization and dilution if needed. • Daily treatments of Polyplus RD will be needed to maintain 0.5 -1.0 ppb concentration. • Estimated volume usage — 676 barrels — not including 500 barrels used from previous interval. E .. f � t %, \`J1 sip 26 2000 Alaska Oil & Gas Cons. Commission Anchorage • • KUSTATAN FIELD #1 PRESSURE INFORMATION The following presents data used for calculation of anticipated surface pressures (ASP) during drilling of the West McArthur River Unit #3ST. The pore pressure gradient information was obtained from the original bottom hole pressure surveys and RFT surveys on West McArthur River Unit #1, #2A and #3. The fracture gradient information was obtained from formation integrity tests below casing points on the West McArthur River Unit # 1, #2A and #3. Kustatan Field #1 is located down structure from the West McArthur River Field. West Forelands #1, drilled in 1962 by Pan American is on this same structure, between West McArthur River Unit and Kustatan Field #1. West Forelands #1 was a vertical exploration well drilled to a TD in the Jurassic. No abnormal pressures were encountered in this well. Based on the above information, we feel that Kustatan Field #1 will not encounter any zones with over pressured fluids. The most conservative (highest) formation pressure gradient of 8.65 ppg or .45 psi /ft was used in these calculations. Procedure for Calculating Anticipated Surface Pressure ASP is determined as the lesser of 1) surface pressure at breakdown of the formation at the casing seat with a gas gradient to the surface, or 2) formation pore pressure at the next casing point and a gas gradient to the surface. 1) ASP = ((FG x .052) - 0.115) x D where: ASP = Anticipated Surface Pressure in psi FG = Fracture Gradient at the casing seat in lb /gal 0.052 = Conversion from lb /gal to psi /ft 0.115 = gas gradient in psi /ft D = true vertical Depth of casing seat in ft RKB OR 2) ASP = FPP- (0.115 x D) where: FPP = Formation Pore Pressure at the next casing point which is tied back to surface or at TD (total depth) E 4 ,:� 0 I.. cr p 262000 Alaska Oii & Gas Cons. Commission Anchorage • • ASP Calculations Drilling below Surface Casing (13 3/8 ") ASP = ((FG x .052)- 0.115) x D = ((10.5 x .052) - 0.115) x 6500' = 2802 psi OR ASP = (6500' x .45) - (.115 x 6500') = 2178 psi Drilling below Intermediate Casing (9 5/8 ") ASP = ((FG x .052)- 0.115) x D = ((10.5 x .052) - 0.115) x 11500' = 4957 psi OR ASP = (11500' x .45) - (.115 x 11500') = 3853 psi Drilling below Drilling Liner (7 -5/8 ") ASP = ((FG x .052)- 0.115) x D = ((10.5 x .052) - 0.115) x 13000' = 5603 psi OR ASP = (13000' x .45) - (.115 x 13000') = 4355 psi Drilling below Production Liner (5 1/2 ") ASP = ((FG x .052)- 0.115) x D = ((10.5 x .052) - 0.115) x 13600' = 5862 psi OR RECEIVED ASP = (13600' x .45) - (.115 x 13600') ccp 26 2000 = 4556 psi Ataska Oil & Gas Cons. Commission C r + Anchorage R\ N • • KUSTATAN FIELD #1 CASING DESIGN Proposed Casing Setting Depth Size Specifications Top Bottom Hole Casing Weight Grade Coupling Length MD TVD MD TVD Driven 20" 133 K -55 N/A 120' Surf. Surf. 120' 120' 17 1/2" 13 3/8" 68 L -80 BT &C 1600' Surf. Surf. 1600' 1600' 12 1/4" 9 5/8" 47 L -80 BT &C 6500' Surf. Surf. 6500' 6500' 8 1/2" 7 5/8" 29 L -80 Hy 521 5200' 6300' 6300' 11500' 11500' 6'/1' 5 Yz' 17 L -80 Hy 521 1700' 11500' 11500' 13000' 13000' Casing Joint Strength Body Strength Burst Collapse K lbs K lbs Psi Psi 20" 133# K -55 2123 2125 3060 1500 13 3/8" 68# L -80 1545 1556 5050 2260 9 5/8" 47# L -80 1122 1086 6870 4760 7 5/8" 29# L -80 566 683 6890 4790 5 1/2" 17# L -80 338 397 7740 6290 Design Criteria Tension Straight Hook Load - Ignoring Deviation and Buoyancy Burst Full Column of Gas against deepest formation pressure Except for liners where a 3000 psi test pressure on top of 9.6 ppg fluid is backed on the outside by a fresh water gradient of 0.43 psi /ft. Collapse Full evacuation on the inside backed by expected formation gradient of 0.45 psi /ft on the outside. 13 -3/8" Surface Casing 68# L -80 BT &C a 1600' MD/ 1600' TVD Tension = 1600' x 68# Rated = 1545 K = 108.8 K Safety Factor = 14.2 Burst = (6500' x 0.45)- (0.115 x 6500') Rated = 5050 psi = 2178 psi Safety Factor = 2.3 Collapse = (1600' x 0.45)- (0.115 x 1600') Rated = 2260 psi = 536 psi Safety Factor = 4.2 RECEIVED c r-- P 2 6 2000 Alaska Oil & Gas Cons. Commission Anchorage • • 9 5/8" Intermediate Casing 47# L -80 BT &C (a 6500' MD/ 6500' TVD Tension = 6500' x 47# Rated = 1086 K = 305.5 K Safety Factor = 3.6 Burst = (13600' x 0.45)- (0.115 x Rated = 6870 psi 13600') Safety Factor = 1.5 = 4556 psi Collapse = (6500' x 0.45)- (0.115 x 6500) Rated = 4760 psi = 2178 psi Safety Factor = 2.2 7 -5/8" 29.0 #. Hydril 521 liner 011,500' MD/ 11,500' TVD Tension = 5200' x 29# Rated = 566K = 150.8 K Safety Factor = 3.8 Burst = ((11500 x 0.4992) + 3000)- Rated = 6890 psi (11500 x 0.43) Safety Factor = 1.8 = 3796 psi Collapse = (11500 x 0.45)- (0.115 x 11500) Rated = 4790 psi = 3853 psi Safety Factor = 1.2 5- 1/2 "17# L -80 Hydril 521 liner 13,000' MD/ 13,000' TVD Tension = 1700' x 17# Rated = 338 K = 28.9 K Safety Factor = 11.7 Burst = ((13000 x 0.4992) + 3000)- Rated = 7740 psi (13000 x 0.43) Safety Factor = 2.0 = 3900 psi Collapse = (13000 x 0.45)- (0.115 x 13000) Rated = 6290 psi = 4355 psi Safety Factor = 1.4 RECPWPD leTh c r p 2 6 2000 Alaska Oil & Gas mss. Commission Anchor • KUSTATAN FIELD #1 CEMENT DESIGN RECEiVED 4 , c7p 26 2000 Alaska Oft & Gas Cons. Commission Anchorage Operator Name: Forcenergy Gas F -ation Inc • Well Name: Kustatan #1 Job Description: Kustatan #1 Surface Date: September 15, 2000 Proposal No: 179650830F JOB AT A GLANCE Depth (TVD) 1,600 ft Depth (MD) 1,600 ft Hole Size 17.5 in Casing Size/Weight : 13 3 /8in, 68 lbs/ft Pump Via Drill Pipe 5" O.D. (4.276" .1.0) 19.5 # Total Mix Water Required 11,461 gals Pre -flush Water 50 bbls Density 8.4 ppg 1st Lead Slurry Lead Slurry 636 sacks Density 12.5 ppg Yield 2.10 cf /sack Tail Slurry Tail Slurry 776 sacks Density 15.8 ppg Yield 1.16 cf /sack Displacement Drilling Mud 28 bbls Density 9.0 ppg III _ k h s ,:.s...� 4 q q ,l [ c P26200 Alaska € Gas Cons. Commission tnrorje Gr4109 Report Printed on September 15, 200012:38 PM Page 1 Operator Name: Forcenergy Gas EIVation Inc • Well Name: Kustatan #1 . Job Description: Kustatan #1 Surface Date: September 15, 2000 Proposal No: 179650830F WELL DATA ANNULAR GEOMETRY ANNULAR I.D. (in) DEPTH(ft) MEASURED I TRUE VERTICAL 18.730 CASING 120 I 120 17.500 HOLE 1,600 1,600 SUSPENDED PIPES DIAMETER (in) WEIGHT DEPTH(ft) O.D. l.D. (lbs/ft) I MEASURED I TRUE VERTICAL 13.375 12.415 68 1,600 I 1,600 Float Collar set @ 1,520 ft Mud Density 9.00 ppg Mud Type Water Based Est. Static Temp. 69 ° F Est. Circ. Temp. 65 ° F VOLUME CALCULATIONS 120 ft x 0.9377 cf/ft with 0 % excess = 112.5 cf 880 ft x 0.6946 cf /ft with 100 % excess = 1222.6 cf 600 ft x 0.6946 cf/ft with 100 % excess = 833.6 cf 80 ft x 0.8407 cf /ft with 0 % excess = 67.3 cf (inside pipe) TOTAL SLURRY VOLUME = 2235.9 cf = 399 bbls c P 26 2000 41a3ka Oil & Gas Cons. Commission nohorNe Gr4115 Report Printed on September 15, 200012:38 PM Page 2 Operator Name: Forcenergy Gas F ation Inc • Well Name: Kustatan #1 Job Description: Kustatan #1 Surface Date: September 15, 2000 Proposal No: 179650830F FLUID SPECIFICATIONS Pre - flush 50.0 bbls Water 0 8.4 ppg VOLUME VOLUME FLUID CU-FT FACTOR AMOUNT AND TYPE OF CEMENT 1st Lead Slurry 1335 / 2.1 = 636 sacks Class G Cement + 0.5% bwoc Calcium Chloride + 0.4% bwoc CD -32 + 1 gals /100 sack FP -6L + 2% bwoc Sodium Metasilicate + 106% Fresh Water Tail Slurry 901 / 1.16 = 776 sacks Class G Cement + 1.5% bwoc Calcium Chloride + 0.3% bwoc CD -32 + 1 gals/100 sack FP-6L + 44.1% Fresh Water Displacement 28.0 bbls Drilling Mud @ 9 ppg CEMENT PROPERTIES SLURRY SLURRY NO.1 NO.2 Slurry Weight (ppg) 12.50 15.80 Slurry Yield (cf /sack) 2.10 1.16 Amount of Mix Water (gps) 11.95 4.97 Amount of Mix Fluid (gps) 11.96 4.98 nni i A c 26 2000 Alaska Oii & Gas Coots. Cer mission °'"DTI'' tor€; 5r4129 Report Printed on September 15, 200012:37 PM Page 3 Operator Name: Forcenergy Gas Illation Inc • Well Name: Kustatan #1 Job Description: Kustatan #1 Intermediate Date: September 15, 2000 Proposal No: 179650830F JOB AT A GLANCE Depth (TVD) 6,500 ft Depth (MD) 6,500 ft Hole Size 12.25 in Casing Size/Weight : 9 5 /8in, 47 lbs/ft Pump Via Casing 9 5/8" O.D. (8.681" .I.D) 47 # Total Mix Water Required 3,342 gals Pre flush Water + 1% MCS -AG 50 bbls Density 8.4 ppg Lead Slurry Inter. Lead 194 sacks Density 12.5 ppg Yield 2.10 cf /sack Tail Slurry Int. Tail 206 sacks Density 15.8 ppg Yield 1.15 cf /sack Displacement Drilling Mud 470 bbls Density 9.3 ppg rs, c4 P 26 2000 ai a Gas Co os, Ccurinion ntho? e Report Printed on September 15 , 200012:37 PM Page 6 Gr4109 Operator Name: Forcenergy Gas Eiration Inc • i Well Name: Kustatan #1 Job Description: Kustatan #1 Intermediate Date: September 15, 2000 Proposal No: 179650830F WELL DATA ANNULAR GEOMETRY ANNULAR I.D. (in) DEPTH(ft) MEASURED TRUE VERTICAL 12.415 CASING 1,600 I 1,600 12.250 HOLE 6 ,500 6,500 SUSPENDED PIPES DIAMETER (in) WEIGHT DEPTH(ft) O.D. 1 I.D. (lbs /ft) MEASURED I TRUE VERTICAL 9.625 I 8.681 I 47 I 6,500 I 6,500 1 Float Collar set @ 6,420 ft Mud Density 9.30 ppg Est. Static Temp. 113 ° F Est. Circ, Temp. 90 ° F VOLUME CALCULATIONS 1,000 ft x 0.3132 cf/ft with 30 % excess = 407.1 cf 500 ft x 0.3132 cf/ft with 30 % excess = 203.6 cf 80 ft x 0.4110 cf /ft with 0 % excess = 32.9 cf (inside pipe) TOTAL SLURRY VOLUME = 643.6 cf 115 bbls c;zp 26 2000 ,, ‘Iastfa Oil & as Co u. C' ; r'nission A i c ; ;Ar a Gr4115 Report Printed on September 15 , 2000 12:37 PM Page 7 Operator Name: Forcenergy Gas *ration Inc • Well Name: Kustatan #1 Job Description: Kustatan #1 Intermediate Date: September 15, 2000 Proposal No: 179650830F FLUID SPECIFICATIONS Pre -flush VOLUME VOLUME FLUID CU-FT FACTOR AMOUNT AND TYPE OF CEMENT Lead Slurry 407 I 2.1 = 194 sacks Class G Cement + 0.5% bwoc Calcium Chloride + 0.4% bwoc CD-32 + 1 gals/100 sack FP -6L + 2% bwoc Sodium Metasilicate + 106% Fresh Water Tail Slurry 236 / 1.15 = 206 sacks Class G Cement + 0.3% bwoc Calcium Chloride + 0.3% bwoc CD -32 + 1 gals /100 sack FP -6L + 44.1% Fresh Water Displacement 470.0 bbls Drilling Mud © 9.3 ppg CEMENT PROPERTIES SLURRY SLURRY NO. 1 NO. 2 Slurry Weight (ppg) 12.50 15.80 Slurry Yield (cf /sack) 2.10 1.15 Amount of Mix Water (gps) 11.95 4.97 Amount of Mix Fluid (gps) 11.96 4.98 zp 26 2003 •°, ;)1 Oil & Gas Cons. Ce" emission ( .v y � a f t�l�l, nrotl 4'tla Report Printed on: September 15, 200012:37 PM Page 8 Gr4129 Operator Name: Forcenergy Gas ration Inc • Well Name: Kustatan #1 Job Description: Kustatan #1 Drilling Liner Date: September 15, 2000 Proposal No: 179650830E JOB AT A GLANCE Depth (TVD) 11,500 ft Depth (MD) 11,500 ft Hole Size 8.5 in Casing Size/Weight : 7 5 /8in, 29.7 lbs/ft Pump Via Drill Pipe 5" O.D. (4.276" .I.D) 19.5 # Total Mix Water Required 733 gals Weighted Spacer MCS-4D 30 bbls Density 10.5 ppg Cement Slurry Drilling Liner 149 sacks Density 15.8 ppg Yield 1.15 cf /sack Displacement Drilling Mud 347 bbls Density 9.6 ppg c^ p 2 b 2)0 ? pp ii yy �a Co A!a sk a O'I Ca Cott,. i %4wni sio U R d nc (i rw sa`r.: (5r4159 Report Printed on September 15, 200012:37 PM Page 11 Operator Name: Forcenergy Gas Eillration Inc • Well Name: Kustatan #1 Job Description: p Kustatan #1 Drilling Liner Date: September 15, 2000 Proposal No: 179650830F WELL DATA ANNULAR GEOMETRY ANNULAR I.D. DEPTH(ft) (in) MEASURED 1 TRUE VERTICAL 8.681 CASING I 6,500 , 6,500 8.500 HOLE I 11,500 I 11,500 SUSPENDED PIPES DIAMETER (in) WEIGHT DEPTH(ft) O.D. I.D. (Ibslft) MEASURED I TRUE VERTICAL 7.625 6.875 I 29.7 I 11,500 11,500 Float Collar set @ 11,420 ft Mud Density 9.60 ppg Mud Type Water Based Est. Static Temp. 207 ° F Est. Circ. Temp. 160 ° F VOLUME CALCULATIONS 1,500 ft x 0.0770 cf/ft with 30 % excess = 150.1 cf 80 ft x 0.2578 cf/ft with 0 % excess = 20.6 cf (inside pipe) TOTAL SLURRY VOLUME = 170.7 cf 30 bbls F ?El °ter' f D _ ; ? 26 2000 0:Lnka oh& Gas Cons. Con minion 0x4115 Report Printed on. September 15, 20D0 1237 PM Page 12 Operator Name: Forcenergy Gas E411,ation Inc • W LO ell Name: Kustatan #1 r Job Description: Kustatan #1 Drilling Liner Date: September 15, 2000 Proposal No: 179650830F FLUID SPECIFICATIONS Weighted Spacer 30.0 bbls MCS -4D + 6 lbs/bbl MCS -D + 119 lbs/bbl Barite © 10.5 ppg VOLUME VOLUME FLUID CU -FT FACTOR AMOUNT AND TYPE OF CEMENT Cement Slurry 171 / 1.15 = 149 sacks Class G Cement + 0.1% bwoc R -3 + 0.3% bwoc CD -32 + 0.7% bwoc FL -33 + 1 gals/100 sack FP -6L + 43.6% Fresh Water Displacement 347.0 bbls Drilling Mud 9.6 ppg CEMENT PROPERTIES SLURRY NO. 1 Slurry Weight (ppg) 15.80 Slurry Yield (cf /sack) 1.15 Amount of Mix Water (gps) 4.92 Amount of Mix Fluid (gps) 4.93 r r zu 6 ns 2000 "'• Cas f �yX� r ota r�'f:4��,'Ja'� 0r4129 Report Printed o,,: September 15 , 2000 12 :37 PM Page 13 Operator Name: Forcenergy Gas Eiration Inc • Well Name: Kustatan #1 Job Description: Kustatan #1 Production Liner p # r n r Li e Date: September 15, 2000 Proposal No: 179650830F JOB AT A GLANCE Depth (TVD) 13,000 ft Depth (MD) 13,000 ft Hole Size 6.75 in Casing Size/Weight : 5 1/2in, 17 lbs/ft Pump Via Drill Pipe 5" O.D. (4.276" .I.D) 19.5 # Total Mix Water Required 865 gals Weighted Spacer MCS-4D 30 bbls Density 10.5 ppg Cement Slurry Liner Slurry 177 sacks Density 15.8 ppg Yield 1.17 cf /sack Displacement Drilling Mud 240 bbls Density 9.8 ppg SEP 2 6 2000 41a3ka (iii & Gas Cons, Con anChO e 004108 Report Printed on September 15 , 200012:37 PM Page 16 Operator Name: Forcenergy Gas Elkation Inc • ij Well Name: Kustatan #1 Ei Job Description: Kustatan #1 Production Liner Date: September 15, 2000 Proposal No: 179650830F WELL DATA ANNULAR GEOMETRY ANNULAR I.D. (in) DEPTH(ft) MEASURED I TRUE VERTICAL 6.875 CASING 11,500 11,500 6.750 HOLE 13,000 I 13,000 SUSPENDED PIPES DIAMETER (in) WEIGHT DEPTH(ft) O.D. I I.D. (Ibs /ft) MEASURED I TRUE VERTICAL 5.500 I 4.892 I 17 I 13,000 I 13,000 1 Float Collar set @ 12,920 ft Mud Density 9.50 ppg Mud Type Water Based Est. Static Temp. 223 ° F Est. Circ. Temp. 175 ° F VOLUME CALCULATIONS 350 ft x 0.0928 cf/ft with 0 % excess = 32.5 cf 1,500 ft x 0.0835 cf/ft with 30 % excess = 162.9 cf 80 ft x 0.1305 cf/ft with 0 % excess = 10.4 cf (inside pipe) TOTAL SLURRY VOLUME = 205.8 cf 37 bbls SEP 2 6 2000 Alaska On & Gas Cops, r , ' iC €ord9e Report Printed on: September 15 , 200012:37 PM Page 17 - Gr 4115 Operator Name: Forcenergy Gas Eation Inc • Well Name: Kustatan #1 ir Job Description: Kustatan #1 Production Liner Date: September 15, 2000 Proposal No: 179650830F FLUID SPECIFICATIONS Weighted Spacer 30.0 bbls MCS -4D + 6 lbs/bbl MCS-D + 9 lbs/bbl Potassium Chloride + 119 lbs/bbl Barite @ 10.5 ppg VOLUME VOLUME FLUID CU -FT FACTOR AMOUNT AND TYPE OF CEMENT Cement Slurry 206 / 1.17 = 177 sacks Class G Cement + 0.3% bwoc R -3 + 2% bwow Potassium Chloride + 0.5% bwoc CD- 32 + 0.6% bwoc FL -33 + 1 gals/100 sack FP -6L + 0.15% bwoc Sodium Metasilicate + 0.9% bwoc BA -10A + 43.4% Fresh Water Displacement 240.2 bbls Drilling Mud 9.8 ppg CEMENT PROPERTIES SLURRY NO.1 Slurry Weight (ppg) 15.80 Slurry Yield (cf /sack) 1.17 Amount of Mix Water (gps) 4.89 Amount of Mix Fluid (gps) 4.90 to ._ SEP 26 2000 Report Printed on September 15, 2000 12 :38 PM Page 18 Gr4129 • • Nabors Rig 160 13 -5/8" 5000 psi BOP Stack Kustatan Field #1 5000 psi Annular 5000 psi Pipe Rams 5000 psi Blind Rams 3" Kill Line ><1><E Mud Cross 3" Choke Line 1 2 2 1 1 = HCR Valve 2 = Gate Valve 5000 psi Pipe Rams \ 13 -5/8" x 11" / 11" 5M IXE Wellhead 13 -3/8" Surface Casing 9 -5/8" Int R17:2( r � uE: P 2 200,E 4j41(3 °ii CJs., i Ar�c trt,�,sil3n 0 0 - I MI 11111111111101 • i -- AM i , ,t eg \ 'fh ei 10 IIIV -M= Th LL.I. /-65ik -i1-405--- 97-1/2' E ........ L H nr ILLI. co It 1 - .... ., ..........,__H_ 11 5,000 . `71 1111 i Imo , 1 11 25.50" r_ H....._], or, 0 _, 1 • 40 0, ____I ;to 7 1 i 1 • • m t - ii H7.7,1, • --- t _ it . WI: r MI 1: 4T, ----' 28.00' 1111 - 1 Mit —_ H 0 1 : zo 1 .._. - ,,i !,.:i•,4 SEP 2 6 2000 • .••• • • ----- 13-3/8" OD CSG . Aja3k Oii a 9-5/8" OD CSG G as ("a Cr '. "IrCh0/4e, 3-1/2" OD TBG ALL DIMENSIONS ARE APPROX. A 1 IS ID SWE & FCE ENGINEERING ACAD 1%1WIP ASEA BROWN BOVER1 AB Vetco Gray 13-3/8 X 9-5/8 X 3-1/2 OD, 5M MSP ASSY 11 FILE i REFERENCE: F DRAWING NO. DRAWN BY: C. RICE DATE, 18 SEP 2000 FORCENERGY ---i 1 EN G APPR.: DATE: 11 SCALE NA 'PROJECT NO.: II SP , i • BLOWOUT PREVENTION EQUIPMENT NABORS RIG No . 160 13 -5/8" BOP Equipment 1 ea 13 -5/8" x 5000 psi wp ram type preventers, double (Shaffer) 1 ea 13 -5/8" x 5000 psi wp ram type preventers, single (Shaffer) 1 ea 13 -5/8" x 5000 psi wp annular preventer (Hydril) 1 ea 13 -5/8" x 5000 psi wp drilling spool with 2 ea 4" side outlets (choke and kill), HCR and manual valves on both choke and kill lines. 1 ea BOP accumulator, Valvcon, 300 psi w /12 bottles, 180 gallons, and (1) 80 gallon Valvcon accumulator. Accumulator pump, Gardner - Denver Triplex, Model PQ 172, air pump Model G7E. 8 bottles nitrogen backup. 1 ea Valvcon, 6 station, remote control panel 1 ea Thornhill Craver, automatic choke 3 "- 10,000 psi with control choke panel 1 lot Hydraulic pipe and fittings from manifold to BOP stack. DRILLING FLUID SYSTEM DESCRIPTION Mud Pumps 2 ea Continental Emsco F -1300 triplex mud pumps 7" x 12, 1300 HP with (2) C -E pulsation dampeners, Model M822, each pump equipped with (2) 752 GE traction motors, cooled with ambient air. Each pump charged by a 5 x 6 Mission Magnum I with 50 HP AC motor. Mud Tank System (1035 bbls Total Volume) Tank #1 (shaker tank) appx. 270 bbls. Three compartments which include desander, desilter suction compartment and cutting trap compartment equipped with shale shakers, degasser, poor boy degasser, and mud guns in top skidded section. Tank #2 (volume tank) appx. 460 bbls. One compartment equipped with desander, desilter, mud cleaner, mud guns and mud agitators in top skidded section. Ja ka of / 6 2000 n cc • mocha, 04'ssion f Tank #3 (suction tank) app x. 305 bbls. Three compartments, two of which are pill its, 1 thru 65 bbls; one 55 bbl equipped with mud guns, mud agitators, mud P � mixing hopper, and chemical barrel in top skidded section. Mud System Equipment 1 ea Derrick dual tandem shale shaker 1 ea Drilco degasser 1 ea Swaco 518 High Speed Centrifuge 1 ea Picenco 16 cone desilter 1 ea Pioneer sidewinder mud mixer 4 ea Brandt 7 -1/2 HP mud agitators 4 ea Mission Magnum pumps, 5' x 6' centrifugal with 50 HP GE Electric Motors 1 ea Pioneer desander, 2 cone, Model S -2 -12 6 ea Dahlory 3" mud guns v[P ^ 2 6 LOt?3 At s k a t1rP ,. ••.lTll�iDR o MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Dan Seamount 1.)\, DATE: August 23, 2000 Commissioner SUBJECT: Blowout Preventer Test THRU: Blair Wondzell r , Nabors 160 P.I. Supervisor wort o Force Energy / Tomcat Kustatan Field 1 FROM: Jeff Jones -t J ' 200 -153 Petroleum Inspector Kustatan Field NON- CONFIDENTIAL Operator Rep.: Robert Wall Op. phone: 776 -3954 Op. E -Mail: Contractor Rep.: Gary Gibson Rig phone: 776 -6513 Rig E -Mail: • Test Pressures Rams: 3000 Annular: 2000 Choke: 3000 TEST DATA MISC. INSPECTIONS: FLOOR VALVES: MUD SYSTEM: Visual Alarm P/F P/F Quantity P/F Trip Tank P P Location Gen.: P Sign: P Upper Kelly 1 P Pit Level Indicators P P Housekeeping: P Rig cond: P Lower Kelly 1 P Flow Indicator P P PTD On Location P Hazard: P Ball Type 1 P Meth Gas Detector P F Standing Order: P Inside BOP 1 F H2S Gas Detector P P BOP STACK: Quantity Size P/F ACCUMULATOR SYSTEM: Annular Preventer 1 13 5/8" P CHOKE MANIFOLD: Time /Psi P/F Pipe Rams 1 5" P Quantity P/F System Pressure 2900 P Lower Pipe Rams 1 5" P No. Valves 13 P After Closure 1500 P Blind Rams 1 13 5/8" P Man. Chokes 2 P 200 psi Attained :28 sec. P Choke Ln. Valves 1 3 1/8" P Hyd. Chokes 1 P Full Pressure 3:16 P HCR Valves 1 3 1/8" P Blind Covers (All Stations): P Kill Line Valves 2 2 1/8" P N2 Bottles (avg): 4/2000 P Check Valve N/A Testis Details Saturday, October 21. 2000: I traveled to Force Energy's Tomcat exploratory well Kustatan Field 1, to witness the initial BOPE Test on Nabors Rig 160. Due to mechanical difficulties experienced while nippling up BOPE, the testing was delayed until 0330 hrs. on Monday, 10/23/00. Once begun, the testing proceeded smoothly with Nabors representative Gary Gibson on hand to expedite the procedure. Two failures were witnessed; the methane gas alarm failed to activate the audible alarm and the inside BOP floor valve failed the pressure test. I was contacted on Tuesday, 10/24/00 by Al Lunda, Nabors Drlg. supervisor, who ' ormed me that both failures had been repaired and passed a re-test. The rig and it's equipment appeared clean and in good condition, and the location well organized. Summary: I witnessed the initial BOPE Test on and a gas detection alarm system test on Nabors Rig 160, drilling Force Energy's Tomcat exploratory well Kustatan Field 1. Of thirty-nine components tested, two failures were witnessed. Both failures were corrected and passed a re-test within 24 hours. Total Test Time: 4.5 hrs. Number of failures: 2 Attachments: 0 cc: BOP Nabors 160 10 -23 -00 JJ3.xls 1 026 I FORCENERGY INC. I , ;" PH. 907- 258 -8600 IA 310 K STE. STE. 700 A ANCHORAGE, AK 99501 8 9- 6/1252 September 26, 2000 = DATE PAY • TO THE * ** Alaska Oil & Gas Conservation Commission * ** 4 C ORDER OF ** 100.00 ** i ** One hundred and 00 /100 * * � ® 1 DOLLARS o . :., . 'I ill 1 . First Nat Bank %. I © of Anchorage / / 47 io ii FOR P e r m i t Tomcat X#eAr"' AP - 00 L0 2611' : 1 2 5 2000 60 : 0 2 L i 4 L3 01 • fa j WELL PERMIT CHECKLI T COMPANY rr ___....[ �� WELL NAME re.g. 'lj PROGRAM: exp dev redril sery wellbore seg ann. disposal para req I . FIELD & POOL J�� '� i�,' IT CLASS X {� 1 LIXXt f o f c GEOL AREA L_� UNIT# A • . �- O /OFF SHORE ran r ADMINISTRATION 1. Permit fee attached 40.0 N 1 2. Lease number appropriate. 40 N 3. Unique well name and•number.. Y,N 1 4. Well located in a defined pool. f E /Pr41 - /( 5. Well located proper distance from drilling unit boundary. . . . Y - C .-etch �?",�ru� ;'9 i -). , 20 7/C Z�. S I , )CI ` 6. Well located proper distance from other wells. N 7. Sufficient acreage available in drilling unit. Y N 4s ,c e; 44,c-e, 8. If deviated, is wellbore plat included. 0✓4 . Y N 9. Operator only affected party. tr. N 10. Operator has appropriate bond in force 41.6 11. Permit can be issued without conservation order N APPR DATE 12. Permit can be issued without administrative approval. 40 N CP e t ZV LD 13. Can permit be approved before 15 -day wait. 0 N 0 ENGINEERING 14. Conductor string provided S N / �ry Z W 15. Surface casing protects all known USDWs. ', Y N e - 4-e 4-e-. +i y 1.cr-�c� , ,� -- Z 16. CMT vol adequate to circulate on conductor & surf csg N <J 17. CMT vol adequate to tie -in long string to surf csg Y N 1 -I 18. CMT will cover all known productive horizons : N CC 19. Casing designs adequate for C, T, B & permafrost. N C 20. Adequate tankage or reserve pit. N 73 21. If a re- drill, has a 10 -403 for abandonment been approved. . . AM- 22. Adequate wellbore separation proposed. N --I 23. If diverter required, does it meet regulations N Re.coat App 000k A O,J 04 064141 tr-4._ 24. Drilling fluid program schematic & equip list adequate & N rn 25. BOPEs, do they meet regulation N - APPR - DA E 26. BOPE press rating appropriate; test to$ c c) psig N Z ( a, " ,,.- ( ( 27. Choke manifold complies w /API RP -53 (May 84) a N 28. Work will occur without operation shutdown 0 - , - I 29. Is presence of H2S gas probable. Y '' Apo 'oao Le-fkr r,-0 44, ) • 4 • es .1' ` - +' 4 4' a 2 1 ll�.c- >Yi *Pm.? fin Pe �,G9fjt> >1�., A+ 1�? /t lvo a a 5 L /// - ., / I GEOLOGY 30. Permit can be issued w/o hydrogen sulfide meal, s. . . . . (::).N end-i ire. r� €l( rC f ° /6 E V CO 1 . / rfttr i F �Pi x'(14 '`; J ezlbilcr,i - 31. Data presented on potential overpressure zon y dpp +-€.55u1,t. c'�(.5trvtd - 1 - 4t - Lii--k1'ti '7 41:a.6 5ecifccli. ' I v:�trt°- .0 / ` r ' 32. Seismic analysis of shallow gas zones c '! N /1/‘ ;- .t. •s) ,�- s .S4 /(, A) ` 1“ :,. e.e /2/ S 4/k t -- /t, S/i , �. D APR DATE 33. Seabed condition survey (if off- shore) 44 Y N ems c t rt a .1 S I. s4ci`c. • i a.-r.- icy- %!-evA it, I I' co 34. Contact name /phone for weekly progress reports (exploratory only N i-ei..44_,/ ' /AJ . 2s-s- 5"6 x m ANNULAR DISPOSAL35. With proper cementing records, this plan / D (A) will contain waste in a suitable receiving zone Y N APPR DATE (B) will not contaminate freshwater; or cause ling w ste . Y N to surface; (C) will not impair mechanical integrity the well us d for disposal' N (D) will not damage producing form on or impair r overy f a Y N pool; and (E) will not circumvent 20 MC 5.252 or 20 AA 5.412. Y N GEOLOGY: ENGINEERING: UIC/ nul CO Comments /Instructions: SF � Ad I t ° itt,�,WM 1J • M c: \msoffice \wordian\diana \checklist (rev. 02/17/00) • 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 information, 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. _•== = ,� FIRM TO HARD; MOD BRITTLE; TOUGH; COM - __ =a.- - �' — " - ' T APPEARS AS TABULAR CTGS WITH DISTINCT { : ,`., EDGES; MATTE TO SLI SHINY SMOOTH _ .........,� ............... .. VERY CAL SCAT I ; p ":�- ; , i :� ; _; r ,::_, ; TEXTURE, MOD AL OCC V C; S , O - - _ _ - THIN LAMS OF CALCITE. ( 1 : ===- ==_:= ! TUFFACEOUS CLAYSTONE = BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS STICKY _ _ - - = - - -- TO STIFF OR MOD RUNNY CLAY; RARELY I T; - , APPEARS AS POORLY INDURATED LUMPY T t ;:=::';'4:',7-77:7;•1.44.4,7:7;:::: -CTGS; MATTE LUSTER; SMOOTH TO MOD GRITTY :•_.,•�:,.:_r: TEXTURE; NON TO LOCALLY MOD CALC; COM _ - - - _ - ; J ASHY STREAKS; SCAT TO COM VOLC GLASS __L SHARDS; SCAT TO COM BLACK PINPOINT 'SPECKS. -= . :� COAL = BLACK TO OCC DUSKY BROWNISH :...J__... - ...� .z _� CRUMBLY BLAC B FIRLY T M TO OCC M OCC MOD OD HARD; LEO SLI ; O TOUGH; T •z:•_ ;i:_ Sri :i_:. .� : RESINOUS LUSTER; SLI ROUGH SURFACE " " TEXTURE; SCAT ASHY LAMS; RARE PINPOINT 3 GAS BUBBLES ON FRAC SURFACES. i>n N S AND /SANDSTONE = LIGHT GRAY TO WHITE 0 k , OVERALL•, FINE TO COARS E DOM FINE TO MED �t , GRAIN RE GRANULE SIZ GRAINS; ANGOLA 1 - q : 1 i T ROUNDED, DOM SUBANGULAR, POORLY �____ ' '- -+ t ; � ? _ i C1,2 : SORTED; COMPOSED OF 70% QUARTZ, 30% IG/ ' ' I METANOLC LITHICS; GRAINS ARE LOOSE IN 'SAMPLE;SLI TO MOD ACID REACTION r ' : - INDICATES CALCITE TRACES ON GRAIN SURFS; - 3 k `'` " "`' ` " ` "`` `'' D COM CLUMPS OF CLAY MATRIX MATERIAL; • - ? J r. EST POOR TO FAIR POR AND PERM; NO OIL ' >• + r : INDICATORS. _;.7:-'---:- "' .. ' : TUFFACEOUS CLAYSTONE = GRAY TO BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS STICKY TO STIFF CLAY; MATTE LUSTER; MOD '- ' " - "'" j GRITTY TEXTURE; NON TO VERY SLI CALC; :: COM ASHY STREAKS; SCAT TO COM VOLC GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPKS. \ CARBONACEOUS SHALE = DRK BROWN TO BLK; O ;� , FIRM TO HARD; MOD BRITTLE; TOUGH; COM -1:1.:;, ! • :.:: , _ _ ! APPEARS AS TABULAR CTGS; MATTE TO SLI - _ - = - ! SHINY LUSTER; ROUGH TEXTURE; SLI CALC. TUFFACEOUS CLAY STONE = GRAY TO BROWNISH > ; k + DOWN TIME GAS 5w : GRAY; VERY SOFT TO SOFT; DOM APPEARS AS __•_i._itis'.. + STICKY TO STIFF CLAY; MATTE LUSTER; MOD _= G. GRITTY TEXTURE; NON TO VERY SLI CALC; `=''=`;: COM ASHY STREAKS; SCAT TO COM VOLC GLASS • _ _ - - - « > SHARDS; SCAT TO COM BLACK PINPOINT SPKS. ; ;..: : :-..;,: : : : 4; : . 10/31/2000 ` :....,5-. FINE TO . . •.....• = : ON OARS S COARSE, DOM LIGHT GRAY OVERALL; F N --"-.r.---.7." _.. . TO C S, D M FINE TO MEDIUM, 70% QUARTZ, :: <•:z• = �• � « J ROUNDED, DOM SUBANGULAR, 70 :< *s^ \\ 518u 4 30% LITHICS; DISAGGREGATED IN SAMPLE; _+ --. _ ' > ?s' > +::a < * . GAS 1 OX C 3 2,1 ... COM CALCITE FRAGS; VIGOROUS ACID RXN; , SURVEY 5382' . .<. o GI OM CLAY MATRIX ATERIAL FREE N SMPLE ..: -•:- EST FAIR P OR TR AND PERM NO OIL INDICATORS a � J • _ COAL = BLACK, OCC DUSKY YELSH BROWN; %I , C _ : FIRM TO MOD HARD; BRITTLE TO MOD • ''_' TOUGH; SMALL IRREG AND HACKLY CTGS; •" ' y SLI RESINOUS LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; RARE ASHY LAM RARE PINPOINT GAS BUBBLES ON ._ S SURFACES. r J / _ MW 93 : :VIS 67 kJ _ - - — — , � + TUFFACEOUS CLAYSTONE = LT TO MED <, BROWNISH GRAY; VERY SOFT TO SOFT; INCR '' AMOUNT OF SAMPLE IS MOD TO VERY SOLUBLE '''''-._:L . :.. _ >: CLAY; STICKY TO CREAMY; VERY RARE LUMPY _i_i + « CUTTINGS; MATTE LUSTER; SMOOTH TEXTURE; > NON TO OCC SLI CALC; ASHY APPEARANCE; COM SPECKS; NO OIL INDICATORS. NOTE: ABUNDANT NUT PLUG IN SAMPLES. c500 ROP = g -;i5 _ - - - _ _ , ,, c0 ;0 ; . Total G as 100x10 D Meth C 100K0 • ciao Avg W 66 ,-. 0 . ''°�' i 0 c0 C1g9 as 100} COAL = BLACK TO OCC DUSKY BROWNISH ' _ '' , BLACK; FIRM TO OCC MOD HARD; BRITTLE; _•i_i ' • ' CRUMBLY TO OCC MOD TOUGH; MATTE TO SLI ' '- E RESINOUS LUSTER; SLI ROUGH SURFACE ^<:. -m TEXTURE; SCAT ASHY LAMS; RARE PINPOINT ::: : `` ' D• GAS BUBBLES ON FRAC SURFACES. r<k+ O MW 9.3 O8 #5 MADE 7301 25 I- RS. + . + ! �}}D 122u VIS 72 NB #6 STC MO5S .. k J X01/2000: +.:• - y J J ¢ A ND LIGHT GRAY OVERALL, CLASTS U RANG E `�S - FROM FINE TO COARSE, DOM MEDIUM SIZE, ` ANGULAR TO ROUNDED, DOM SUBANGULAR : - :n: >t: >: +.;;J.;ts ». ° R ND; MOD SORTED; COMPOSED OF a . TO SUB ROUND; ' + ' ' y C -2,1 70% QUARTZ, 30% METANOLC LITHICS; THIN -, ' >:::': >!a;:* a, STREAKS OF COAL; EST FAIR POR AND PERM; NO OIL INDICATORS. °" ` ' : y r < �3 SAND/CONGLOMERATE = LIGHT GRAY TO WHITE —'! Os :� +: > s:�z; ± a.�s : « +.: + C� OVERALL; CLASTS RANGE FROM FINE TO : C + • r r ` y ' ? : GRANULE SIZE, DOM MED RANGE; ANGULAR O : - ;i::i:;:� :: a D C.2,1 SURROUND POORLY SORTED COMPOSED OF ::::9-: 70% QUARTZ, 30% LITHICS; THIN STREAKS OF "_' "• " ; SANDSTONE ARE WELL CEMENTED AND DRILL :::1:-T a �T3 ::« . > ,.. ,. , ; SLOWER; EST FAIR TO GOOD POR AND PERM; .. ... . : NO OIL INDICATORS. t TO WELL ROUNDED, DOM SUBANGULAR TO m ur_ : TUFFACEOUS CLAYSTONE = LIGHT TO MED • ' ' BROWNISH GRAY; VERY SOFT TO SOFT; DOM + r -+ ' APPEARS AS THICK, PASTY CLAY WITH COM �:: _,::•:= SLI FIRM LUMPY SHAPED CTGS; MATTE, / — n:1 , TEXTURE; DOM NON CALC, OCC TO VERY C M ::: - -_ . ' • CALC; SCAT TO COM ASHY BLEBS. ".. : COAL = BLACK TO OCC DUSKY BROWNISH "--::-.-:..., ''' '- BLACK; FIRM TO OCC MOD HARD; BRITTLE; '`'` "" r :' CRUMBLY TO OCC MOD TOUGH; MATTE TO SLI O RESINOUS LUSTER; SLI ROUGH SURFACE = _ TEXTURE; SCATTERED LAMS OF TUFFACEOUS G J CLAYSTONE; RARE ASHY LAMS; __ .._. _._.._._ MW 9.3 VIS 72 ....... ......... y L ,' _ __- . : TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM • - BROWNISH GRAY; VERY SOFT TO SOFT; DOM PASTY CLAY; MATTE, EARTHY LUSTER; MOD y 44- '•R =T :' :', ' :: GRITTY TEXTURE; DOM NON CALC; ASHY - • � j: ' . APPEARANCE; COM SPECKS. SAND = LIGHT GRAY OVERALL; CLAST RANGE J _: ___,�:_. FROM FINE TO COARSE; DOM FINE TO MED; g1A10.111 A17 Tn el twang I ncn. u...al, ni.<. +�.. : Forest Oil Corporation Kustatan Field #1 Application for Disposal Injection Order Class II 44 04 °A 19 7 : 16 \O/ February 28, 2003 W I I March 7, 2003 1 Mr. Rob Stinson Forest Oil Corpration 1 1 1 310 K St. Anchorage, AK 99501 I Dean Mr. Stinson, Attached you will find a FracPro PT simulation report for the Kustatan Field #1 well. FracPro PT I was able to simulate injection down the annulus of the 7 -5/8" casing at a rate of 2.3 bpm with a 100 mesh sand concentration of 5.0 ppg. Simulation for 370 days of continuous injection was performed. I The results of the simulation indicate the fracture created from continuous injection will be contained within a zone of approx. 220' (6,688' to 6,908') near the perforated interval. The I increasing stress associated with deeper sands and shales prevented fracture growth downwards and there is sufficient stress difference between the sand -shale layers to prevent upward growth of the fracture. I Reservoir layers of sand -shale sequences were determined from the electronic log provided for the Kustatan Field #1 well. The reservoir model was assumed to be an oil reservoir (worst case) and was not modeled below 8,000'. Performing a simulation over the entire 4,800' of annular I space and all of it's layers for 370 days would result in an array of data too large to handle at the current time. Since the fracture did not grow to below this depth, it should be assumed that reservoir layer data below this depth is inconsequential. I If you have any question regarding this simulation or report, please feel free to give me a call at any time at 661 - 396 -4441. I Thank you, I J. Jay Garner Pacific Region, Manager, City Sales /Alaska I BJ Services Company jgarner(bjservices.com I RECEIVED Cc: Internal Customer File MAR 10 2003 I ..., y (hl & Gas Cons. Cor nu8Slof Anchorage 1 1 I I I I I FracproPT 10.1 Hydraulic Fracture Analysis 1 I Date: March 7, 2003 Well Name: Kustatan #1 Location: I Formation: Job Date: 3/7/03 Filename: Kustatan #1 Disposal I Fracture Geometry Summary Fracture Half- Length (ft) 1994 Propped Half- Length (ft) 0 ' Total Fracture Height (ft) 221 Total Propped Height (ft) 0 Depth to Fracture Top (ft) 6688 Max. Fracture Width (in) 0.11 Depth to Fracture Bottom (ft) 6908 Avg. Fracture Width (in) 0.05 Equivalent Number of Multiple Fracs 1.0 Avg. Proppant Concentration (Ib/ft 0.00 I Fracture Slurry Efficiency 0.00 All values reported are for a single fracture t Model has run until 447552.00 min Fracture Conductivity Summary I Avg. Conductivity (wlDamage) (mD•ft) 0.0 Avg. Frac Width (Closed on prop) (in) 0.00 Dimensionless Conductivity 0.00 Ref. Formation Permeability (mD) 7.50e +01 Proppant Damage Factor 0.50 Proppant Permeability (mD) 20000 I All values reported are for a single fracture Fracture Pressure Summary I Model Net Pressure (psi) 32 BH Fracture Closure Stress (psi) 5255 Observed Net Pressure (psi) 0 ( Closure Stress Gradient (psi/ft) 0.776 I 1 FracproPT 10.1 I Fracture Pressure Summary Hydrostatic Head (psi) 4430 Surface Pressure (psi) 884 Averages reported during Main Frac Operations Summary Total Clean Fluid Pumped (bbls) 1030973 Total Proppant Pumped (klbs) 176356.3 Total Slurry Pumped (bbls) 1030973 Total Proppant in Fracture (klbs) 0.0 Pad Volume (bbls) 0 Avg. Hydraulic Horsepower (hp) 50 Pad Fraction ( %) 0 Max. Hydraulic Horsepower (hp) 50 Main Fluid DISPOSAL Main Proppant 100 -Mesh FLUID Averages reported during Main Frac 1 1 1 1 1 2 FracproPT roPT 10.1 I Il Fracture Dimensions Fracture Growth History I End of Time Fracture Fracture Fracture Avg. Model Net Slurry Equivalent Stage # (mm:ss) Half- Height Width at Fracture Pressure Efficiency Number of Length (ft) Well Width (psi) Multifracs I (ft) (in) (in) 1 370:days 1994 221 0.109 0.050 32 0.00 1.0 All values reported are for a single fracture I Proppant and Fluid Properties by Stage Proppant Distribution by Stage I Stage Proppant Type Proppant Stage Distance from Avg. Proppant Avg. Proppant Avg. Proppant # Concentration Wellbore Concentration Conductivity Volume I (ppg) (ft) (Ib /ft (mD•ft) Fraction 1 100 -Mesh 5.00 1979.2 0.00 0.0 0.000 1 100 -Mesh 5.00 1756.1 0.00 0.0 0.000 1 100 -Mesh 5.00 1189.5 0.00 0.0 0.000 I 1 100 -Mesh 5.00 415.7 0.00 0.0 0.000 I Fluid Properties by Stage Stage Fluid Type Slurry Rate Distance from Avg. Fluid Avg. Fluid Avg. Shear # (bpm) Wellbore Temperature Viscosity Rate I (ft) ( °F) (cp) (1 /sec) 1 DISPOSAL FLUID 2.30 1979.2 195 1.0 0.0 1 DISPOSAL FLUID 2.30 1756.1 195 1.0 0.0 I 1 DISPOSAL FLUID 2.30 1189.5 195 1.0 0.0 1 DISPOSAL FLUID 2.30 415.7 195 1.0 0.0 I Design Treatment Schedule Stage Elapsed Fluid Clean Prop Stage Slurry Proppant # Time Type Volume Conc Prop. Rate Type I min.sec (kgal) (ppg) (klbs) (bpm) Wellbore Fluid DISPOSAL FLUID 2.3 1 370:days DISPOSAL FLUID 42000.0 5.00 210000.0 2.30 100 -Mesh I Design clean volume (kgal) 42000.0 Design proppant pumped (klbs) 210000.0 Design slurry volume (kgal) 51496.9 I Treatment Totals I Proppant and Fluid Material Quantity Units Unit Discnt Cost Cost ( %) ($) I ($) DISPOSAL FLUID 999999.88 bbls 0.00 0.0 0.00 100 -Mesh 209999.98 klbs 70.00 0.0 14699999.00 I 3 FracproPT 10.1 Fluid Parameters Fluid Name DISPOSAL FLUID Vendor MISCELLANEOUS System GENERAL Description 10.5 ppg fluid with solids Initial Viscosity (cp) 1.01 Initial n' 1.000 Initial k' (lbf.sAn/ft 2.100e -05 ' Viscosity @ 4.0 hours (cp) 1.01 n' @ 4.0 hours 1.000 k' @ 4.0 hours (Ibf•s "nlft 2.100e -05 I Gel Density 1.25 Spurt Loss (gallft 0.0 Wall Building (ft/min' /2) 0.0 Flowrate #1 (bpm) 10.00 I Fric Press #1 (psi /1000 ft) 47.30 Flowrate #2 (bpm) 20.00 Fric Press #2 (psi /1000 ft) 161.0 ' Flowrate #3 (bpm) 40.00 Fric Press #3 (psi11000 ft) 548.3 Wellbore Friction Multiplier 0.100 ' All Fluid info is at a reservoir temperature of 195.0 ( °F) All Viscosities at Shear Rate of 511 (1 /sec) Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction Multiplier. Friction is displayed for longest wellbore segment 1 4 FracproPT 10.1 1 'Y • i Leakoff Parameters Reservoir type Oil I Filtrate to reservoir fluid perm. ratio, Kp /KI 1 Reservoir pore pressure (psi) 2947 Initial fracturing pressure (psi) 5755 I Reservoir fluid compressibility (1 /psi) 5.00e -06 Filtrate viscosity (cp) 1.00 Reservoir viscosity (cp) 2.00 Porosity 0.15 I Gas Leakoff Percentage 100.00 Reservoir Parameters I Reservoir temperature ( °F) 195.00 Depth to center of Perfs (ft) 6775 Perforated interval (ft) 50 I Initial frac depth (ft) 6775 Layer Parameters I Layer # Top of Stress Top of Young's Poisson's Top of Total Ct PoreFluid zone (psi) zone modulus ratio zone (ft/min %) perm. I (ft) (ft) (psi) (ft) (m D) 1 0.0 5525 0.0 6.0e +06 0.25 0.0 0.000e +00 O.00e +00 2 6500.0 5074 6500.0 4.0e +06 0.22 6500.0 6.403e -03 1.00e +01 3 6593.0 5650 6593.0 6.0e +06 0.25 6593.0 0.000e +00 0.00e +00 I (11% 4 6702.0 4766 6702.0 2.0e +06 0.20 6702.0 1.754e -02 7.50e +01 5 6724.0 5255 6724.0 4.0e +06 0.22 6724.0 6.403e -03 1.00e +01 6 6838.0 4861 6838.0 2.0e +06 0.20 6838.0 1.754e -02 7.50e +01 I 7 6856.0 5375 6856.0 4.0e +06 0.22 6856.0 6.403e -03 1.00e +01 (1 ®c _ 8 7015.0 5489 7015.0 4.0e +06 0.22 7015.0 6.403e -03 1.00e +01 9 7150.0 5086 7150.0 2.0e +06 0.20 7150.0 1.754e -02 7.50e +01 10 7176.0 6144 7176.0 6.0e +06 0.25 7176.0 0.000e +00 0.00e +00 I 11 7281.0 5226 7281.0 2.0e +06 0.20 7281.0 1.754e -02 7.50e +01 12 7440.0 6407 7440.0 6.Oe +06 0.25 7440.0 0.000e +00 0.00e +00 13 7635.0 5428 7635.0 2.0e +06 0.20 7635.0 1.754e -02 7.50e +01 I 14 7655.0 6551 7655.0 6.0e +06 0.25 7655.0 0.000e +00 0.00e +00 15 7758.0 5526 7758.0 2.Oe +06 0.20 7758.0 1.754e -02 7.50e +01 16 7808.0 6712 7808.0 6.0e +06 0.25 7808.0 0.000e +00 0.00e +00 17 7984.0 5669 7984.0 2.0e +06 0.20 7984.0 1.754e -02 7.50e +01 I I I I 5 FracproPT 10.1 I Lithology Parameters I Layer # Top of Lithology Top of Fracture Top of Composite zone zone Toughness zone Layering (ft) (ft) (psi•in' /2) (ft) Effect 1 1 0.0 Shale 0.0 2000 0.0 1.00 2 6500.0 50/50 6500.0 1500 6500.0 1.00 3 6593.0 Shale 6593.0 2000 6593.0 1.00 4 6702.0 Sandstone 6702.0 1000 6702.0 1.00 I 5 6724.0 50/50 6724.0 1500 6724.0 1.00 6 6838.0 Sandstone 6838.0 1000 6838.0 1.00 7 6856.0 50/50 6856.0 1500 6856.0 1.00 8 7015.0 50/50 7015.0 1500 7015.0 1.00 I 9 7150.0 Sandstone 7150.0 1000 7150.0 1.00 10 7176.0 Shale 7176.0 2000 7176.0 1.00 11 7281.0 Sandstone 7281.0 1000 7281.0 1.00 I 12 7440.0 Shale 7440.0 2000 7440.0 1.00 13 7635.0 Sandstone 7635.0 1000 7635.0 1.00 14 7655.0 Shale 7655.0 2000 7655.0 1.00 I 15 7758.0 Sandstone 7758.0 1000 7758.0 1.00 16 7808.0 Shale 7808.0 2000 7808.0 1.00 17 7984.0 Sandstone 7984.0 1000 7984.0 1.00 I I I I I I I I I I 6 FracproPT 10.1 1 I Wellbore and Perforated Intervals I ,---- Drilled Hole Configuration Length Segment Type Eff Diam Bit Diam I (ft) (in) (in) 5800 Open Hole 8.750 8.750 I Casing Configuration Length Segment Type Casing ID Casing OD Weight Grade I (ft) (in) (in) (lb/ft) 4800 Free Casing 6.875 7.625 29.700 L -80 1000 Cemented Casing 6.875 7.625 29.700 L -80 ' nfi Surface Line and Tubing Configuration g I Length Segment Type Tubing ID (ft) (in) Tubing OD Weight Grade (in) (lb /ft) 6332 Tubing 2.441 2.875 6.400 L -80 I Total frac string volume (bbls) 55.8 Pumping down Tubing I Perforated Intervals // Interval #1+ "' Top of Perfs - TVD (ft) 6750 0 I Bot of Perfs - TVD (ft) 6800 Top of Perfs - MD (ft) 6750 Bot of Perfs - MD (ft) 6800 I Perforation Diameter (in) 0.500 # of Perforations 300 I Path Summary Segment Length MD TVD Dev Ann OD Ann ID Pipe ID I Type (ft) (ft) (ft) (deg) (in) (in) (in) Tubing 6332 6332 6332 0.0 0.000 0.000 2.441 OpenHole 168 6500 6500 0.0 0.000 0.000 6.875 Casing 250 6750 6750 0.0 0.000 0.000 6.875 I I I 7 FracproPT 10.1 LETTER OF APPL ICATION ize I F O R E S T O I L C O R P O R A T I O N J o . ;//' /i -77,, , 7 o ' }i(i /C 2/ :. / , 2 , S'- .S'f / • i. 9( -// °. ∎6( / 7'' %i1 2 I February 27, 2003 I Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 I Attention: Commissioner Dan Seamount I Re: Kustatan Field #1 well Application for a disposal injection order I Dear Commissioner Seamount: Forest Oil Corporation requests authorization to inject Class II waste fluids into permeable sands of the middle Tyonek Formation, at depths below 6500 feet TVD in its Kustatan Field #1 well. The well was drilled as an unsuccessful exploration well in 2000. I The vertical well is located approximately 3443 feet from the north line, 1468 feet from the west line of Section 4, TO7N, R14W, Seward Meridian. Forest Oil is the surface owner at the well's location. I Enclosed is Forest Oil's application for a disposal order. Please call me if you or your staff have any questions about this request or require additional information. Forest I Oil will be pleased to meet with you or answer any question you or your staff may have. Thank you. I I I Paul D. White Drilling Manager — Alaska Division Forest Oil Corporation I S: \1307 - Forest 011\1307-009 \ 1307-009-200 \U1C cover Itr.doc I I I' O > Z 0 D ---1 r m m Z -I m CJ) 1 ' 1 TABLE OF CONTENTS I LETTER OF APPLICATION 1 SECTIONS 1 1. Plat — showing the location proposed, completed, or abandoned boreholes within a 1 /4 mile radius of the proposed disposal well. 1 2. List Of Operators — list of all operators and surface owners within a' /4 mile radius of the disposal well. 1 3. Affidavit — showing that all operators and surface owners within 1/4 mile have been provided a copy of this application. 1 4. Disposal Formation — providing name, description, depth, and thickness of the disposal formation and of the confining zones. I 5. Disposal Well Logs - if not already on file with the AOGCC. I 6. Mechanical Integrity — mechanical condition of the disposal well and how mechanical integrity will be demonstrated. 1 7. Wastes To Be Disposed — a list of the oilfield wastes to be disposed. 8. Injection Pressure — estimated average and maximum injection pressure. I 9. Confining Zone Fractures — evidence to support a commission finding that fractures will not propagate thru the confining zone. 10. Water Quality — a standard laboratory water analysis of the disposal zone. 1 11. Aquifer Exemption — reference to any applicable freshwater exemption issued and comment on the need for one. 1 12. Mechanical Condition — of all boreholes within a I/4 mile radius. 1 1 1 I 1 Noe ' KUSTATAN FIELD #1 WELL WELLSBOREHOLES WITHIN 1 /4 MILE ' DISPOSAL INTO THE TYONEK FORMATION DIO Section 1 As shown on the attached plat, there are no oil and gas wells within 'Aa mile of the Kustatan Field #1 well. There are two domestic source water wells drilled and operated ' by Forest Oil on the gravel pad with the Kustatan Field #1 well. 1 1 I 1 1 1 I I I I I f 7 5 l - r , T T l r 1 1 rT - } 1 -- i - _ 1 1 I f r 19 20 21 j 22 j 23 24 19 1 20 21 � r a=" Foreland 1 1 I f I r I Foreland (Pt St 1 f T } _ 30 29 28 27 26 25 30 c}relan29 28 St 1 -A I _ I j - - -T- r r — — — I I - - I I 1 I = 31 32 33 3• 35 j 36 31 1 32 33 1 1 I I 1 1 i i 6 TK 4 3 1 2 1 1 a McAr hur Riv IA - 6 j 5 f - U$ ; 'A TAN ' jELD # 1 4 _ � I I - - - - - - - — — — — } -I- T -- -- I 1 _ - 7 8 9 : I 11 12 7 8 9 - I 18 17 16 15 14 RU p1 13 18 17 16 I • , btf: U ` R ij 6 Plan 19 20 21 22 23 r 4 RU 20 21 r 5 -1111 — r r - - -- - -- F - -- — -u_5,4 -r R r l Redouit Sli St 2206x1 1 r 30 29 28 27 26 25 30 29 28 --- 1 I r - - A - -_ r r r I r 33 I 31 32 33 34 j 35 36 31 32 r Tenne I . $t 36465 1 I 1 [ I FOREST OIL CORP 1:78400 I KILOMETERS 01 1 2 KILOMETERS KUSTATAN FIELD #1 CLASS PROPOSED DISPOSAL STATUTE MILES 0 1 2 STATUTE MILES .......... i.• r• roves �� 1 KUSTATAN FIELD #1 WELL LIST OF OWNERS AND OPERATORS DIO Section 2 ' Surface Owners within 1 /4 mile: ' USS 12121 Lot 1. Legal description: SEWARD MERIDIAN ' T.7N., R.14W. Section 3 SW' /4SW1/2NW1/4 W1/2 W'/2S W' /4 ' Section 4 S' /2S' /2NE SE' /4SE' /4NW'/4 fractional NE1/4NE' /4SW1/4 ' fractional N'/2SE' /4 fractional S'/2SE' /4 Containing approximately 160 acres. Howard Evans, Jr., 2013 N. 17th, Springfield, OR 97477 Marcella Henrie, 13731 Capstan, Anchorage, AK 99516 ' Sheila Stabe, 411 Beach Rd., Altoona, WI 54720 Dennis Haugdahl, 8001 Medellin Circle, #B, Anchorage, AK 99507 Jean Orth & Wanda Haugdahl ' Mailed c/o Branch of Realty Bureau of Indian Affairs ' West- Central Alaska Field Office 3601 "C" Street, Suite 1100 Anchorage, Alaska 99503 -5947 1 Public Site Easement (ARD Bk 3289 Pg 922) State of Alaska, Department of Natural Resources Division of Mining, Land & Water 550 W. 7th Avenue, Suite 1070 Anchorage, Alaska 99501 -3560 ' Mineral Estate within '/4 mile: ' State of Alaska, Department of Natural Resources Division of Oil & Gas 550 W. 7th Avenue, Suite 800 Anchorage, Alaska 99501 -3560 Tai - ,RAC PRO( 3 2 e cif i:C:d iT7T•7 ∎91iNAIIi - 1 � il Cil i7F^G!:7 o H 12 7 e t eDxvAC E 9111.eR I _ E! 111111111• ➢Ya =E.LD 7T .7 BSI iLYtr1 014 1 MI 111111=1=1•4i6S11.:1=TTFT:Fain ! \ PMD / u I t 9 ]fl MT1 IS ,e 17 si♦ip7iRSS Td'S79 — --/ / met ■1111111111iSI ■dR-P 11111E7.7711 ■ii111111=dAL 1=717Z1h1 X461 1!x47 X37 22 23 24 19 20 I _ . — .. _ _ ∎n. )ib ° #5 �^.tw^.F7 a a M11=91111111=1,01, wort ° A �SL) �:5: fi7 ,g7 N X04 =N MI s:ri: � 7 �� 1:-4. �i ilNAi � 27 23 n. 30 19 MilMEEAiPTA•> 111111111731 / 2 �gil le i? i'^ °•T. 36 \ �g%i =NUN i'F7KSL7 31 • / ' 3 ' �g6Jil::li ��iti1 34 T} / -' \ I3 �gil�ell!i ii' r 3 \ X �.5( S^"' "C1i'.S 3 / • �'J MIM M1111111.1,4,, y:. �^ v%l o 5 vi \ N 11.9;.1 I. s° Tyr / , ON/MESJ i::t:. t:3717747 REDOUBT BAY 11.11 il•:lc isT'77 !L7 ' / LOTl iL.S tSL111tT/YC! MIN ti � kJ! ib il: s.T.. 7 ►91 iifR E":'Tlr7 well iL:w . eil mom !1 -0wilm' -1'- V:. 1 VICINITY MAP Scale I'' I ►:1 iL: tad i.T!.'k'L^1 i..i iP?Rll i � \ =►;I il•:C:4 s'T 1r 2 ifC4 ?) D V 3 c � ���• ' �RSIfie!: -1 � 555 i�NRfV wave SIlE EASEMENT iN� -E,RI gi; t:1 �%'i 71.'7 EASEMENT (1 ACRE) - -1 — ARD 81t S2e9 PC 922 .1. 32,„ R' "bA 5 COT ! II S Miner AG 11/11 �� DESCRIPTION • ' I Situated in the State of Alaska rr� Kenai Peninsula Baaa I \ / \ Cook Inlet within Redoubt Bay appmaimauly 20 miles r Al FV.D w �L , / City of Kcnei within Township 7 North. Range 14 Wes AA / bounded and described as Dlhwa -_ \ / / / / Pt19uc SITE EASEMENT 0 UNNAMED LAKE PARCEL 1 1 \ / EASEMENT (1 ACRE) ARD BK 32e9 PG 922 ac V.S. Survey No. 1999 mm. cording to the official plat in fi \ + . / / / • Land Man agee located within the Anchorage Ran h 1998 MEANDER kME • ` District. Stale M mar containing 1 acres .r is • ,� DNDINM NICK MATER PARCEL 2 4e v \ ` EASEMENT AC 25 MDE �/ I. h Lm 1 U.S. Survey Nn. 45 according w the official plat ARD BK 3289 PC 922 / 1 Land Management. eated x1161, t6, Anchorage Recto \ Disrict. State of Alaska containing 1 M154 5acresrmaeo ` \ { / • PARCEL3 / / \ / Lot 2 U.S. Survey No. 4537 according to the official pla \ -- --- / - Lend Management. xx th located e Anchorage Norm ag< \` LOT 1 MS ARM' ACt 4St7. Dsmel State of Alaska eom ac n nmg 45x1 TOM a kW \ / EMAIL PARCEL 4 7 i/ AIL - B C3 Lot 2 U.S. Survey No. 12121 according to the official p - . / — 1Z /W a Land Management. located within the Am:b o tie Rare I / /// \ \ \ — • — • / / I S District. Stale of Masks, containing IM1I I,Ilxrts mime (/��A�_�� PARCEL S / //� \ \ INS 910500 / \ 1Y' LOT \ ,,„ \ \,.. RUSTATAN 1i" 1 Tract B U.S. Survey No. 363 according to the offtcal pi • Land Man agemrnt. located with" the Ane hoage Ream \ A / \ 5%. \ IAsmct Stale of Alaska containing HIMlniar 111 / 1 Rtf.AK USE SITE \ / \ Y. EA4MENT (1 ACRE) °� l COT t CMS M2 f \ ,i c. a,QD BR 3269 PG 922 1 Itlit r I \ SEE mum B ; \ � .s u ° 'R' 1 s. $ , C. / •N n • ea r � • ° A a le ss / c , _ _ —.a.. — ..--. \ 0 c _ » ,� . N': • ANTENNA. stoner a714oi I 0 �' I \ 7� , �. \ I1L'dNY�LSt 1 tm nms u I 0 `°b" TRA B U.S SURVEY 3 L „,, 4 4 U.S. SURVEY IM 1999, )• 998 MEANDER LINE 4 1'N ' q , AND 2 U.S. SURVEY N( " AND LOT 2 U.S. SURVEY 1 / \ Ce uEAN 01*9 'ME \ M us sorter ma ..dt7 \ STATE OF ALASK \ ICS � 11� — — KENA PENINSULA BOI ANTE 107! \ ANCHORAGE RECORDING BIN To Foo*oorgy Inc., and Pacific cs Northw 4 \ NORTH This 1510certify that this map 09 plat and11 I y 4 a which it is based were made (i) in aee«dar 0 � :as 5' "Minimum Standard Detail Requirements 1 (^ If' pS t.SbR1ET ' AGSM Land Title Surveys. ' jointly estab(i• IAN '64•4' , k ,k • ° adopted by ALTA and ACS' in (991, am •_ • ••• GRAPH SCALE _ the accuracy standards (as adopted by AL7 0 and in cfTect on tin fax: of this CCHif satiOt G = on 's "Rural” Survey including heart I. 2.4 and m f u >m ) property sunny �d contains 316.614 arcs r m LEGEND AND NOTES I "ee .9. - 7 a, NOOSE 9oAROrAu '' / FOUND STANDARD BIM BRASS CAP .- 40- Pray 4, ATTACHED TO REGULATION POST 1. 'i' AS DESCRIBED IN THE OFFICIAL RECORD. ?- ti ip \ • FOUND 2 _" DIAM. CONCRETE FILLED IRON PIPE. Swv y.d Ry. ; a • FOUND NATIONAL GEODETIC CONTROL STATION MCLANE CONSULTING GROUP ; \ a - A. • AS DESCRIBED IN THE OFFICIAL RECORD. Engineers, Surveyors and Planners l I :s..,, SPA, f% P.O. Box 468 Soldotna, AK 99669 M. Scott McLane Irks 1 AFFIDAVIT OF NOTICE TO OPERATORS AND SURFACE OWNERS TO THE ALASKA OIL & GAS CONSERVATION COMMISSION In the Matter of the Application for ) Disposal Injection Order, Class II, ) pursuant to 20 AAC 25.250 (c)(3), ) AFFIDAVIT OF PAUL WHITE submitted by Forest Oil Corporation ) Paul White, upon being duly sworn, did depose and state: 1. That he is over 19 years of age and has personal knowledge of the matters set forth herein; ' 2. That on February 28, 2003, he was employed by Forest Oil Corporation as a drilling manager; 3. That he is authorized to make this Affidavit on behalf of Forest Oil Corporation; 4. Pursuant to 20 AAC 25.250 (c)(3) he made a reasonable effort to ascertain all operators and surface owners within a one — quarter mile radius of the Kustatan Field ( "KF ") #1 well, ' which is proposed as a disposal or storage well. The names and addresses of the operators and surface owners ascertained are set forth on the address list contained in section 2 of the Application for Disposal Injection Order, Class II, dated February 28, 2003, submitted to the Alaska Oil and Gas 1 Conservation Commission by Forest Oil Corporation regarding the KF #1 well (the "Application "); 5. On February 28, 2003, pursuant to 20 AAC 25.250 (c)(3), he sent a copy by certified mail of the Application to all operators and surface owners he previously ascertained to be ' within a one — quarter mile radius of the KF #1 well; 6. That the above information is true and correct to the best of his knowledge, ' information and belief. Subscribed and sworn to on February 28, 2003. Paul White STATE OF ALASKA ) ) SS: THIRD JUDICIAL DISTRICT ) I HEREBY CERTIFY that on the 28 day of February 2003 before me, James D. Arlington, a notary public of the State of Alaska, personally appeared Paul White, and made his oath /affirmation in due form of law that the matters and facts set forth in the Affidavit of Paul White are true. AS WITNESS my hand and notarial seal. Notary Public, State of Alaska My Commission Expires: March 13, 2005 ' KUSTATAN FIELD # 1 WELL DISPOSAL FORMATION DIO Section 4 ' The Tyonek formation is Tertiary in age and is composed of fine to medium grained sandstones, with interbedded claystones, siltstones and coals. The Tyonek is approximately 9,000 feet thick and was deposited in a meadering - fluvial depositional ' setting. Individual stream channels sands are generally laterally continuous and can be as much as 100 feet thick. The interbedded siltstones, claystones and coals are considered to be over -bank deposits in this type of setting, and act as vertical confining zones. 1 1 1 1 1 KUSTATAN FIELD #1 WELL MECHANICAL INTEGRITY FOR DISPOSAL INTO THE TYONEK FORMATION DIO Section 6 The Kustatan Field #1 well is currently completed with 20" conductor driven to 120' MD, 13 -3/8" casing cemented at 1820' MD, 9 -5/8" casing cemented at 6500' MD and 7- 5/8" liner cemented at 12,300' MD. There is no tubing in the well and it is filled with 9.6 ppg water base mud. The well will be entered to prepare it for disposal operations. The following work and testing will be performed: 1. The water base mud will be displaced with 9% KCL and the USIT log will be run from 5000 to 6312 ft. (top of liner) to demonstrate the adequacy of the 9 -5/8" shoe cement job — this constitutes demonstration of Mechanical Integrity Part II. 2. The 7 -5/8" liner will be perforated from 6750 to 6800 ft. A Baker retrievable hydraulic packer will be run on 2 -7/8" 6.5 #, L -80, EUE, TK -2 plastic coated tubing and set at 6280 ft. The BOPE will be removed and a 5000 psi injection tree will be installed and tested. The tubing -casing annulus will be pressure tested to 1600 psi (.25psilft x 6280ft) to demonstrate Mechanical Integrity Part I. 1 1 1 1 1 1 1 1 KUSTATAN FIELD #1 WELL ' CLASS II WASTES FOR DISPOSAL INTO THE TYONEK FORMATION DIO Section 7 Only class II wastes will be disposed of into the middle Tyonek Formation of the Kustatan Field #1 well. The main fluid will be produced water from the Redoubt Shoal Oil Field including the Kustatan Production Facility. However, at times it may be necessary to dispose of other Class II fluids. 1 Following is a complete list of Class II fluids which may be injected for disposal into the middle Tyonek Formation of the Kustatan Field #1 well: • produced water, • drilling, completion, and workover fluids, • rig wash fluids, 1 • drilling mud slurries, • NORM scale slurries, • tank bottoms, • boiler blowdown • other fluids brought to the surface in connection with oil and gas development activities. 1 1 1 1 1 1 1 1 1 #1 WELL KUSTATAN FIELD INJECTION PRESSURE FOR DISPOSAL INTO THE TYONEK FORMATION DIO Section 8 Disposal into the middle Tyonek Formation in Kustatan Field #1 well is expected to be at about the same or lower injection pressures than are experienced while injecting into the upper Tyonek Formation of the Redoubt Unit #D -1 well. These pressures averaged about 3600 psig with maximum pressures of about 4500 psig. ' Based on the above described experience, Forest estimates that in the Kustatan Field #1 well the average disposal injection pressure will be about 3600 psig and the maximum disposal injection pressure will be about 4500 psig. I • KUSTATAN FIELD #1 WELL FRACTURE ANALYSIS FOR DISPOSAL INTO THE TYONEK FORMATION DIO Section 9 ' The concern when conducting underground disposal of fluids is that they not contaminate g gr l� Y overlying freshwaters. To insure no contamination, there must be overlying confining ' zones between the disposal formation and the freshwater sands (also, the casing must be cemented so that disposal fluids cannot flow up the annulus between the casing and the formation). In addition, disposal operations must be conducted at pressures that will not fracture the overlying confining zone ' An extensive fracture analysis was performed on sands in the upper Tyonek Formation in the Redoubt Unit #D -1 well (RU #D -1). This analysis (copy attached) was performed for Forest Oil Company by BJ Services Company, U.S.A. The simulations showed that the ' injected fluids were fully contained in the described sand groups which constitute a part of the upper Tyonek Formation. Simulations were run on two sand groups with total simulated injection of almost 60,000 barrels; the effects only extended 54.6 and 56.8 feet into the disposal zone. The RU #D -1 well is approximately 3 miles from the KF #1 well; the Tyonek Formation ' appears to be correlatable between the wells. The intended disposal interval in KF #1 is in the middle Tyonek, below the simulated zone (upper Tyonek) in RU #D -1. Disposal into the middle Tyonek in the KF #1 is even farther from the overlying ' confining zones than the simulation performed in the upper Tyonek in RU #D -1. Therefore, Forest believes that there is an even lower possibility of fracturing the confining zone in KF - #1 than in RU #D -1, 1 1 1 1 1 1 1 1 1 . • ' April 24, 2001 Mr. Rob Stinson Forest Oil Corporation I 310 K. Street, Suite 700 Anchorage, Alaska 99501 1 Dear Mr. Stinson, BJ Services Company, USA welcomes the opportunity to provide Forest Oil Corporation with ' the attached fracture simulations for the RUDI well. As requested simulations have been performed for Sands No's 3, 4 and 5 as a group and for Sand No. 12 as a discreet package. I The simulations are based on the treatment parameters and LAS well log data provided by Forest Oil Corporation previously. Each simulation includes a total volume of 1,000,000 gallons (23,810 bbls) of a 10.5 ppg fluid system transporting 5 ppg 100 mesh sand at a pump rate of 5 ' bpm. The resulting simulator output data shows the injected fluids to be fully contained within the sand packages described above. For you review you will find output data in numeric and plot formats. BJ Services Company is proud to offer Forest Oil Corporation the highest quality products and services currently available in the oil and gas industry. We have enjoyed an excellent business relationship with Forest Oil in the past and we look forward to a continued success. Should you have any questions concerning the information discussed in this letter or any of our products and services please contact me at our Pacific Region Office (907) 349 -6518. ' Res ctfully, ' . Jay am BJ ' RVI 9"' COMPANY, U.S.A. Corporate Account Manager ' cc: Internal Customer Distribution ' B) Services Company, U.S.A. • 6927 Old Seward Hwy., Suite 105 • Anchorage, AK 99518 Office: (907) 349 -6518 • Fax: (907) 349 -1486 1 1 FracproPT10.0 1 ! Hydraulic Fracture Analysis • ▪ j Date: April 24, 2001 Wellname: Redoubt Unit#1 I Location: Cook Inlet Basin, Alaska. Formatting: Sand#3, #4, #5 Job Date: 4/18/2001 12:44:44 PM Filename: Ru -1 -345 1 Fracture Geometry Summary I Fracture Half- Length (ft) 0 Propped Half- Length (ft) 0 Total Fracture Height (ft) 0 Total Propped Height (ft) 0 Depth to Fracture Top (ft) 3784 Max. Fracture Width (in) 0.01 Depth to Fracture Bottom (ft) 3784 Avg. Fracture Width (in) 0.01 I Equivalent Number of Multiple Fracs 1.0 Avg. Proppant Concentration (Ib /fP) 0.00 Fracture Slurry Efficiency 0.00 I ; All values reported are for a single fracture Model has run until 5849.00 min I Fracture Conductivity Summary Dimensionless Conductivity 0.00 Ref. Formation Permeability (mD) 1000.0 Proppant Damage Factor 0.50 Proppant Permeability (mD) 20000 1 All values reported are for a single fracture I Fracture Pressure Summary Mode! Net Pres §use (ow -530 BH Fracture @losure Stress- (psi) 274& Observed Net Pressure (psi) 0 Closure Stress Gradient (psi/ft) 0.726 1 Hydrostatic Head (psi) _ 2474 Surface Pressure (psi) _ 0 Averages reported during Main Frac 1 Fracture Geometry Summary Total Clean Fluid Pumped (bbls) 29184 Total Proppant Pumped (klbs) 5000.9 I Total Slurry Pumped (bbls) 29184 Total Proppant in Fracture (klbs) 0.0 Pad Volume (bbls) 0 Avg. Hydraulic Horsepower (hp) 117 Pad Fraction ( %) 0 Max. Hydraulic Horsepower (hp) 38176 Main Fluid DISPOSAL Main Proppant 100 -Mesh FLUID ' Averages reported during Main Frac 1 FracproPT10.0 1 C:UBG Documents\Ru -1 -345 1 1 1 1 Concentration of Proppant in Fracture (Ib /ft Stage # Length UpperHt LowerHt Upper Conc Lower Conc (ft) (ft) (ft) (IbIW) (Ib/ft I 1 54.6 54.6 54.6 0.00 0.00 1 Fracture Conductivity (mD•ft) Stage # Length UpperHt LowerHt Upper Cond Lower Cond I (ft) (ft) (ft) (mD•ft) (mD•ft) 1 54.6 54.6 54.6 0.00 0.00 1 Treatment Schedule 1 Stage Elapsed Fluid Clean Prop Stage Slurry Proppant # Time Type Volume Conc. Prop. Rate Type min.sec (kgal) (ppg) (klbs) (bpm) I Wellbore Fluid DISPOSAL 3.0 FLUID 1 5838:39 DISPOSAL 1000.0 5.00 5000.0 5.00 100 -Mesh I FLUID 2 5848:39 SHUT -IN 0.0 0.00 0.0 0.00 1 Scheduled clean vol (kgal) 1000.00 Scheduled sand total (klbs) 5000.00 Scheduled slurry vol (kgal) 1226.12 1 1 1 1 I 1 1 i d FracproPT10.0 2 C:UBG DocumentstRu -1 -345 1 � All Fluid info is at a reservoir temperature of 140.0 (°F) ' All Viscosities at Shear Rate of 511 (1 /sec) Fluid Parameters ' Fluid Name DISPOSAL FLUID Initial Rheology I Viscosity n' 1.01 1.000 k' 2.100e -05 Rheology @ 4.0 hours Viscosity 1.01 n 1.000 k' 2.100e -05 1 Get Density 1.25 Spurt Loss 0.0 Wall Building 0.0 I Flowrate #1 10.00 Fric Press #1 17.66 Flowrate #2 20.00 ' Fric Press #2 64.11 Flowrate #3 40.00 Fric #3 232.7 1NB Fric Mult 0.100 1 ' Welibore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction ' Multiplier. Viscosity is displayed ih (op) K' is displayed in (Ibf•s ^n/ft ' Gel Density is displayed as (sg) Spurt Loss is displayed in (gal /ft Wall Building is displayed in (ft/min %) ' Friction pressure is displayed in (psi /1000 ft) Flowrate is displayed in (bpm) Friction is displayed for longest welibore segment I FracproPT10.0 5 C:UBG Documents\Ru -1 -345 1 I1' LeakoffParameters I Reservoir type Gas Filtrate to reservoir fluid perm. ratio, Kp/KI 10 Reservoir pore pressure (psi) 1646 Initial fracturing pressure (psi) 3248 I Reservoir fluid compressibility (1 /psi) 6.08e -004 • Cold filtrate viscosity (cp) 1.00 • Hot filtrate viscosity (cp) 1.00 I Cold reservoir viscosity (cp) 0.03 Hot reservoir viscosity (cp) 0.03 Porosity 0.10 Gas Leakoff Percentage 100.00 Reservoir Parameters I Reservoir temperature ( °F) 140.00 Depth to center of Perfs (ft) 3784 Perforated interval (ft) 162 1 Initial frac depth (ft) 3784 Layer Parameters ' Layer # Top of Stress Top of Young's Poisson's Top of Total Ct PoreFtuid zone (psi) zone modulus ratio zone (ft/min%) perm. (ft) (ft) (psi) (ft) (md) ' 1 0.0 1278 0.0 2.0e +006 0.20 0.0 1.812e -001 1.00e +003 2 1800.0 2155 1800.0 5.0e +006 0.25 1800.0 5.730e -004 1.00e -002 3 3269.8 2396 3269.8 2.0e +006 0.20 3269.8 1.812e -001 1.00e +003 4 3478.8 3004 3478.8 5.0e +006 _ 0.25 3478.8 5.730e -004 1.00e -002 I 5 3589.7 2748 3589.7 2.0e +006 0.20 3589.7 1.812e -001 1.00e +003 6 4150:2 3545 4150.2 5.0e+006 0.25 4150.2 _ 5.730e-004 1.00e -002 7 4191.6 3008 4191.6 2.0e +006 0.20 4191.6 1.812e -001 1.00e +003 I 8 4281.6 3683 4281.6 5.0e +006 9 4384.6 3248 4384.6 2.0e +006 0.25 4281.6 5.730e -004 1.00e -002 0.20 4384.6 1.812e -001 1.00e +003 10 4763.5 4196 4763.5 5.0e +006 0.25 4763.5 5.730e -004 1.00e -002 I 11 5108.6 3645 5108.6 2.0e +006 0.20 5108.6 1.812e -001 1.00e +003 12 5158.6 4473 5158.6 5.0e +006 0.25 5158.6 5.730e -004 1.00e-002 13 5366.8 3894 5366.8 2.0e +006 0.20 5366.8 1.812e -001 1.0Oe +003 14 5601.4 4806 5601.4 5.0e +006 0.25 5601.4 5.730e -004 1.00e -002 15 5707.0 4091 5707.0 2.0e +006 0.20 5707.0 1.812e -001 1.00e +003 16 5818.2 4945 5818.2 5.Oe +006 0.25 5818.2 5.730e -004 1.00e -002 i . I 1 I FracproPTl0.0 6 C:\JBG Documents\Ru -1 -345 1 1 ff ` 1 Lithology Parameters Layer # Top of Lithology Top of Fracture Top of Tip ' zone (ft) zone Toughness zone Effects (ft) (psi•in %) (ft) Factor 1 0.0 Sandstone 0.0 1000 0.0 1.00 2 1800.0 Coal/Clystne 1800.0 1000 1800.0 1.00 I I 3 3269.8 Sandstone 3269.8 1000 3269.8 1.00. 4 3478.8 Coal/Clystne 3478.8 1000 3478.8 1.00 5 3589.7 Sandstone 3589.7 1000 3589.7 1.00 ' 6 4150.2 Coal/Clystne 4150.2 1000 4150.2 1.00 7 4191.6 Sandstone 4191.6 1000 4191.6 1.00 8 4281.6 Coal/Clystne 4281.6 1000 4281.6 1.00 _ ' 9 4384.6 Sandstone 4384.6 1000 4384.6 1.00 10 4763.5 Coal/Clystne 4763.5 1000 4763.5 1.00 11 5108.6 Sandstone 5108.6 1000 5108.6 1.00 12 5158.6 Coal /Clystne 5158.6 1000 5158.6 1.00 ' 13 5366.8 Sandstone 5366.8 1000 5366.8 1.00 14 5601.4 Coal/Clystne 5601.4 1000 5601.4 1.00 15 5707.0 Sandstone 5707.0 1000 5707.0 1.00 1 16 5818.2 ,Coal/Clystne 5818.2 _ 1000 5818.2 1.00 1 1 1 I I I 1 ' FracproPT10.0 5 C:UBG Documents\Ru -1 -345 i Wellbore Configuration ' Segment Segment Tubing ID Tubing OD Casing ID Length Type (in) (in) (in) (ft) ' 3320 Tubing 2.992 0.000 0.000 931 Casing 0.000 0.000 6.875 Tubular Goods are defined to the TOP of the deepest set of perforations that are being modeled. I Frac #1 Top of Perfs - ND (ft) 3702 Bot of Perfs - ND (ft) 3865 Perf Diameter (in) 0.330 # of Perfs 600 1 Near Wellbore Friction Parameters & Perf -- Time Flow Rate Flow Rate Delta P Perf Coeff (min:sec) #1 #2 (psi) Multiplier (bpm) (bpm) 0:00 0.00 0.00 0.00 1.00 1 1 1 1 1 1 FracproPT10.0 6 C:UBG Documents\Ru -1 -345 INN ion NNE Imo INN EN Imo drit w NNE i NINO bt Unit #1 Stress P rofile Redou 3660 , , I 1 I 1 1 I I I I 3680 7" T - 1 7 T - 1 I I I I I I I I I I I I i I 1 1 -� - E 3710 �- _4. —I ---- �- - - -- - -- I I ! I 1 I 1 1 1 I 1 T 3740 -� T T �i — �` ., I 1 I I 1 1 • & 1 V ! I 1 , . 1 1 3770 ,; i- - - - - -{ ---- -{ - - -- - - - -�— -- {- - - - - 1 1 I 1 1 I I I I I 1 I I 3800 ,i_ _1_ J J L 1 I 1 I ! 111 I K o >� I 1 1 I 1 I I I 3830 ` I t if. - 1 / / t' rt _ I I I J I I I I f I I Y'^ 1 I 1 1 1 I o 3860 4- -� 1-- t } I I I 1 I I i I 1 I 1 I I I I I I I 3890 1 I 1 T- 1 7 r 7 -t I I I I 1 1 I I 1 1 1 I I 1 I I I I I ,F,',.::.:1,.,:./..•!:.-,.:- Perm e�bflity } - - -- � " — ^ - -� 1'"• —'" - - - - ^— - } • 3920 ;11 I I I I ! I 1 ® ::I' I �h I I I I 1 I 3950 ! I I 1 J 1 2000 2503 3000 3800 4000 150 113 75 38 0 38 75 113 150 1 Closure $ tress (Psi) Propped Length (ft) Hydraulic length (ft ... ,..t. :,..;, 4 ,;. ce -, i0. .' , .' ,. : 6. 1 - , : t., - , -:- . , . i.-..,il.44•?-,4.4:44,,•: '. -,. ' :-.:'.-:.::`;• :-.:■:: ',::',..' • ...."‹,:.‘: :•.;,;‘-':":::-::::.::-...-::::::.: 1 , .44r4i•, '■-..;,!..: t 4 t , . -. J 1 ? : :' , :.:::': : :•;'-'.::.:--;•-: \ '''';' s ',•' - • '-. • '‘ ' ...., --'--.' .. , . , - .. ., . , .. ...::1-, ,: :`'-';';‘' • -‘,. 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Ammktmo4 4 ritigt,40.: -r t 4,::%%?4W.b,:7Nri . 1 • T''',..''; • yetetn--.4 ." . ,.:51;.--" ' '.a,4, ,P• P,4-*04:,.',4 , " -- ' , Af'$•-' ,4, 4 - ,.,- - ,!: 0001 I 0'0 900+ 900+n O00 0001 adS.Trau `crAi Gui ructun O u e"ood oiod s.) snInpoini IIIIIIIIIIMUGEn £ V Z `i sPurS ANA 20 1 _ . I — — — MN MN — — — — NM — OM In Mill — — MN — MN l i l L 1 FracproPT10.0 Hydraulic Fracture Analysis 1 ! Date: April 24, 2001 Weliname: Redoubt Unit#1 I Location: lntet Basin, Alaska. Formatting: Sand#12 Job Date: 4/18/2001 12:44:44 PM 1 Filename: Ru -1 -12 Fracture Geometry Summary Fracture Half- Length (ft) 0 Propped Half- Length (ft) 0 Total Fracture Height (ft) 0 Total Propped Height (ft) 0 _ Depth to Fracture Top (ft) 5477 Max. Fracture Width (in) 0.01 I Depth to Fracture Bottom (ft) 5477 Avg. Fracture Width (in) 0.01 Equivalent Number of Multiple Fracs 1.0 ,Avg. Proppant Concentration (Ib/ft 0.00 Fracture Slurry Efficiency _ 0.00 1 All values reported are for a single fracture Model has run until 5849.00 min 1 Fracture Conductivity Summary Dimensionless Conductivity 0.00 Ref. Formation Permeability (mD) 1000.0 I Proppant Damage Factor 0.50 Proppant Permeability (mD) 20000 All values reported are for a single fracture Fracture Pressure Summary Model Net Pressure (psi) - 744 BR Fracture - Closure - Stress (psij -3894 1 Observed Net Pressure (psi) Hydrostatic Head (psi) 0 Closure Stress Gradient (psi/ft) 0.711 3581 Surface Pressure (psi) 0 Averages reported during Main Frac Fracture Geomet ry Summary 1 Total Clean Fluid Pumped (bbls) 29185 Total Proppant Pumped (klbs) 5000.9 Total Slurry Pumped (bbls) 29185 Total Proppant in Fracture (klbs) 0.0 Pad Volume (bbls) 0 Avg. Hydraulic Horsepower (hp) 48 Pad Fraction ( %) 0 Max. Hydraulic Horsepower (hp) 102 I Main Fluid DISPOSAL Main Proppant 100 -Mesh FLUID 1 Averages reported during Main Frac 1 1 FracproPT10.0 1 C:UBG Documents\Ru -1 -12 1 1 Concentration of Proppant in Fracture (Ib /ft Stage # Length UpperHt LowerHt Upper Conc Lower Conc I (t) (ft) (ft) (Ib /ft (Ib /ft) 54.8 54.8 54.8 0.00 0.00 1 Fracture Conductivity (mD•ft) Stage # Length UpperHt LowerHt Upper Cond Lower Cond (ft) (ft) (ft) (mD•ft) (mD•ft) 1 54.8 54.8 54.8 0.00 0.00 I Treatment Schedule Stage Elapsed Fluid Clean Prop Stage Slurry Proppant # Time Type Volume Conc. Prop. Rate Type I min.sec (legal) (ppg) (klbs) (bpm) Wellbore Fluid DISPOSAL 7.2 FLUID 1 5838:39 DISPOSAL 1000.0 5.00 5000.0 5.00 100 -Mesh I FLUID 2 5848:39 SHUT -IN 0.0 0.00 0.0 0.00 1 Scheduled clean vol (kgal) 1000.00 Scheduled sand total (klbs) 5000.00 Scheduled slurry vol (kgal) 1226.12 1 1 1 1 1 1 .I 1 FracproPT10.0 2 C:UBG Documents\Ru -1 -12 1 All Fluid info is at a reservoir temperature of 140.0 ( °F) All Viscosities at Shear Rate of 511 (1 /sec) i Fluid Parameters 1 Fluid Name DISPOSAL FLUID Initial Rheology ' Viscosity n' 1.01 1.000 k' 2.100e -05 U Rheology @ 4.0 hours Viscosity 1.01 n' 1.000 k' 2.100e -05 Gel Density 1.25 Spurt Loss 0.0 Wall Building 0.0 Flowrate #1 10.00 Fric Press #1 17.66 Flowrate #2 20.00 Fric Press #2 64.11 Flowrate #3 40.00 Fric Press #3 232.7 WB Fric Mult 0.100 Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction 1 Multiplier. Viscosity is displayed in (cp) K is displayed in (Ibf•s ^n/ft Gel Density is displayed as (sg) Spurt Loss is displayed in (gal/ftz) Wall Building is displayed in (ft/min %) ' Friction pressure is displayed in (psi/1000 ft) Flowrate is displayed in (bpm) Friction is displayed for longest wellbore segment 1 1 FracproPT10.0 3 C :UBG DocumentsTu -1 -12 1 I LeakoffParameters 1 Reservoir type Gas Filtrate to reservoir fluid perm. ratio, Kp/KI 10 Reservoir pore pressure (psi) 2383 I Initial fracturing pressure (psi) 4394 Reservoir fluid compressibility (1 /psi) 4.20e -004 Cold filtrate viscosity (cp) 1.00 Hot filtrate viscosity (cp) 1.00 I Cold reservoir viscosity (cp) 0.03 Hot reservoir viscosity (cp) 0.03 Porosity 0.10 I Gas Leakoff Percentage 100.00 Reservoir Parameters 1 Reservoir temperature ( °F) 140.00 Depth to center of Perfs (ft) 5477 Perforated interval (fi) 84 1 Initial frac depth (ft) 5477 Layer Parameters Layer # Top of Stress Top of Young's Poisson's Top of Total Ct PoreFluid z one (psi) zone modulus ratio zone (ft/min' /z) perm. (ft) (ft) (psi) (ft) (md) 1 1 2 0.0 1278 0.0 2.0e +006 _ 0.20 180 0.0 2.025e-001 1.00e +003 1800.0 1825 1800.0 3.Oe +005 0.45 1800.0 2.025e -001 1.00e +003 3 3269.8 2396 3269.8 2.0e +006 _ 0.20 3269.8 2.0250 -001 1.00e +003 4 3478.8 3004 3478.8 5.0e +006 0.25 3478.8 6.404e -004 1.00e -002 I 5 3589.7 2748 3589.7 2.0e +006 0.20 3589.7 2.025e -001 1.00e +003 6 - 4150.2 - 3545 4150.2 - 5.0e+006 0.25 4t50:2 - 6 :404e -004 1.00ec00 -2 7 4191.6 3008 4191.6 2.0e +006 0.20 4191.6 2.025e -001 1.00e +003 I 8 4281.6 3683 4281.6 5.0e +006 0.25 4281.6 6.404e -004 1.00e -002 9 4384.6 3248 4384.6 2.0e +006 0.20 4384.6 2.025e -001 1.00e +003 10 4763.5 4196 4763.5 5.0e +006 0.25 4763.5 6.404e -004 1.00e -002 1 i 11 5108.6 3645 5108.6 2.0e +006 0.20 5108.6 2.025e -001 1.00e +003 12 5158.6 4473 5158.6 5.0e +006 0.25 5158.6 6.404e -004 1.00e -002 13 5366.8 3894 5366.8 2.0e +006 0.20 5366.8 2.025e -001 1.00e +003 14 5601.4 4806 5601.4 5.0e +006 0.25 5601.4 6.404e -004 1.00e -002 I 15 5707.0 4091 5707.0 2.0e +006 0.20 5707.0 2.025e -001 1.00e +003 16 5818.2 4945 5818.2 5.0e +006 0.25 5818.2 6.404e -004 1.00e -002 1': f 1 1 1 FracproPT10.0 4 C:UBG Documents\Ru -1 -12 I Lithology Parameters Layer # Top of Lithology Top of Fracture Top of Tip ' zone (ft) zone Toughness zone Effects (ft) (psi-in%) (ft) Factor 1 0.0 Sandstone 0.0 1000 0.0 1.00 2 1800.0 Bitum Coal 1800.0 500 1800.0 1.00 3 3269.8 Sandstone 3269.8 1000 3269.8 1.00 4 3478.8 Coal / Clystne 3478.8 1000 3478.8 1.00 5 3589.7 Sandstone 3589.7 1000 3589.7 1.00 6 4150.2 Coal / Clystne 4150.2 1000 4150.2 1.00 7 4191.6 Sandstone 4191.6 1000 4191.6 1.00 8 4281.6 Coal / Clystne 4281.6 1000 4281.6 1.00 1 9 4384.6 Sandstone 4384.6 1000 4384.6 1.00 10 4763.5 Coal/Clystne 4763.5 1000 4763.5 1.00 11 5108.6 Sandstone 5108.6 1000 5108.6 1.00 ' 12 5158.6 Coal/Clystne 5158.6 1000 5158.6 1.00 13 5366.8 Sandstone 5366.8 1000 5366.8 1.00 14 5601.4 Coal /Clystne 5601.4 1000 5601.4 1.00 15 5707.0 Sandstone 5707.0 1000 5707.0 1.00 1 16 5818.2 Coal/Clystne 5818.2 1000 5818.2 1.00 1 1 1 1 1 1 1 1 FracproPTl0.0 5 C:UBG Documents\ Ru -1 -12 1 1 It Welibore Configuration ' Segment Segment Tubing ID Tubing OD Casing ID Length Type (in) (in) (in) (ft) 3320 Tubing 2.992 0.000 0.000 3085 Casing 0.000 0.000 6.875 1 Tubular Goods are defined to the TOP of the deepest set of perforations that are being modeled. 1 Frac #1 Top of Perfs - TVD (ft) 5435 Bot of Perfs - TVD (ft) 5519 Perf Diameter (in) 0.330 # of Perfs 600 Near Welibore Friction Parameters & Perf - ' Time Flow Rate Flow Rate Delta P Perf Coeff (min:sec) #1 #2 (psi) Multiplier (bpm) (bpm) 0:00 0.00 0.00 0.00 1.00 1 1 1 1 1 FracproPTl0.0 6 C:UBG Documents\Ru -1 -12 NI ima ma am --- _.,......, =I EN No am .._ I= MA ...._._. IIII1 MINI 1.11 II. aill .......... 11111111 Redou bt Unit#1 1 1 1 1 1 1 i 1 — r 1 1 T 1 1 1 7 s profile 1 1 1 Stress . , • ...„,..:„..„.t*,...,:,::::;::: 1 ...-...,,,.).,!?; 1 1 --1 1 4 1 7 1 -1- 1 : .... r: ....: ...,....,l. ::,:i'..-,..:.....:-..,,,,,•,-.:,., - r - -- 1 1 . ..1. . ;:'';': ::''' ..::-... :.,:', .;!);::. ::'...,.: .',5'.:•• ..i. 1 1 1 1 1 ..''''.. 1 -1 1 1 1 .. ....-77•,:',;.1'..:::.....:,:.;'..;..:',...',::,::; 1 -1- 1 71 1 7 4- 1 1 T 1 5500 .:,..,...,.":.::':::::,:-..,::::1';.;::•;.:.).;:::::.,:;:2i,ii.;1;..:::,.:,:s..:',.-•:.:•:.:....;,..:...;.:;:,. • 1 1 1 i I ' '' '..:.• ' 1:.::::. .-. -.•'.:‘,''':':;;::..4''':::::.:',...:::;?.....,::::14,...:,;*,1t.,:;:. 1 1 1 1 1 - -...:.:.•':::....1.---;-. r .' • ,..,,,-.;;;,..7,;:;.-777."*,:;,'i:':';',''';',..‘'.,,''''. 1 1 7 1 - 5350 .. 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', i ,:..■ ''. f4;:: ..:::f ''.4.' '. " I I 38 Length (ft) 1 1 1 0 Hydraulic Long ,..„.::.:c.;,...,:?;i::.C.7.., 1 1 38 :1:;. ' ., ,: ., : , .. ,,, :-. - :',-"'. ( 75 PermeabliitY 4: 2:01; 113 (ft) ,.....c:: .',,."..A.:';.;.',P,N9.:;:,e4.:;',..`,' , d Length 5620 if '."is '' ' '' : ;' 4 : High :,.:;:,--;;',.1..:;-:, eoco 15°: - 7114 .,.......-.. . : '' '.. - 5253 4500 3750 (PO ProPPe 5660 stress 3003 Closur e 1 3-D Wellbore View 111 1i1141 �.(III11 1 .. � 1000 � ft J . - 2000 ft 3000 ft. .,. 1 4000 ft 1 ' .... ::-'1:-7...;:- :. .. . . -1..:-.::::.::';'....:::::.::::''''.... 5000 ft • - 6000 ft 7000 ft 1 I ; 1 1 I 1 1 - KUSTATAN FIELD #1 WELL WATER QUALITY DIO Section 10 The middle Tyonek sands below 6500 feet measured depth and down to the top of the ' G -Zone (approximately 11,000 feet measured depth) display chlorides generally between 10,000 — 30,000 ppm Cl. I 1 I 1 KUSTATAN FIELD #1 WELL AQUIFER EXEMPTION CONSIDERATION ' DISPOSAL INTO THE TYONEK FORMATION DIO AgExempl 1 1 Wire -line log analytical techniques, which are compliant with EPA recommended ' methods as described in "Survey of Methods to Determine Total Dissolved Solids Concentrations ", (KEDA Project No. 30 -956), were used to characterize formation water ' salinities in the middle Tyonek Formation in the KF #1 well. Wire -line log analysis from the middle Tyonek Formation in the KF# I well shows the ' proposed Class II disposal injection zone contains water with a chloride concentration of 10,000 to 30,000 ppm which equates to a total dissolved solids (IDS) concentration higher than 10,000 mg/1. Because of this high chloride/ TDS content, an aquifer exemption is not needed. I KUSTATAN FIELD #1 WELL ' MECHANICAL CONDITION OF NEAR BY BOREHOLES DIO Section #12 There are no wells or boreholes, abandoned, shut -in or operating, within 1 /4 mile of the Kustatan Field #1 well. The nearest well /borehole is the RU #D -1 well which is approximately 15,000 feet away. There are two domestic source water wells drilled and ' operated by Forest Oil on the gravel pad with the Kustatan Field #1 well. These wells are shallower than 500 ft each. 1 1 1 1 1 I 1 1 0 0 O z 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE REQUEST OF Injection FOREST ) Order No. XX OIL CORPORATION for a ) Disposal Injection Order for ) Middle Tyonek Formation the Kustatan Field #1 well, ) Kustatan Field Sec.1, T7N, R14W, Seward ) Well Kustatan Field #1 Meridian, offshore Cook Inlet. ) March , 2003 1 IT APPEARING THAT: 1. Forest Oil Corporation ( "Forest ") submitted an application, dated 2003, requesting that the Alaska Oil and Gas Conservation Commission issue a disposal injection order to allow Class II disposal in the Kustatan Field #1 well 2. The Commission published notice of an opportunity for a public hearing in the Anchorage Daily News and Peninsula Clarion on March 2003. 3. The Commission did not receive any protest or request for a public hearing. FINDINGS: II 1. In correspondence dated , 2003 Forest requested an order authorizing Class II disposal into the middle Tyonek Formation in the Kustatan Field #1 Well (KF #1). 2. The Kustatan Field #1 Well is located approximately 3443' from the north line and 1468' from the west line of Section 4, Township 7 North, Range 14 West, Seward Meridian. Forest Oil Corporation (Forest) is the only operator within a one- quarter mile radius of the proposed disposal operation. 3. Forest has provided an affidavit showing that they provided a copy of the application for disposal to the , the only surface owner within a one - quarter mile radius of the proposed disposal project. 4. Wire line log analytical techniques, which are compliant with EPA recommended methods as described in "Survey of Methods to Determine Total Dissolved Solids Concentrations ", (KEDA Project No. 30 -956), were used to characterize formation water salinities in the middle Tyonek Formation in the KF #1. 1 1 I OM i Disposal Injection Order # Page 2 of 6 Kustatan Field #1 Well 1 5. Wire -line log analysis from the KF #1 well show the proposed Class II disposal I injection zone contains waters with total dissolved solids (TDS) concentration generally between 10,000 and 30,000 ppm Chlorides. I 6. Perforations in the KF #1 well will be between 6750' and 6800' measured depth (MD), within sandstones of the middle Tyonek Formation. 1 7. In the Kustatan area the middle Tyonek Formation sandstones are fluvial deposits, which tend to be laterally continuous over several miles. Porosities typically range from 10% to 20% and permeabilities range from 50 to the 100's of millidarcies. 8. The middle Tyonek Formation contains numerous laterally continuous clay I stones, siltstones and coals that have been shown to be effective confining zones. In the interval 5000 - 6000 feet, above the proposed disposal operations in KF #1, these rock types represent approximately 40% of all lithologies. In the I underlying formation, the confining lithologies constitute approximately 20% of the formation. 9. At the top of the proposed disposal zone in the KF #1 well, the nearest well I (abandoned, shut -in, or operating) is the RU #D1 well at a distance of over 15,000 ft. There are two domestic source water wells drilled and operated by Forest Oil on the gravel pad with the Kustatan Field #1 well. 1 10. The proposed disposal interval is overlain and confined by siltstones, coals I and shales within the Tyonek and Beluga Formations which will prevent vertical migration of Class II wastes into formation waters with TDS content Tess than 3000 mg /I. 1 11. A cement bond log and cement records will be reviewed to confirm that the KF #1 well is adequately cemented to isolate the proposed disposal interval from 1 freshwater sources. 12. The well is currently completed with 20" conductor driven to 120' MD, 13 -3/8" I casing cemented at 1820' MD, 9 -5/8" casing cemented at 6500' MD, and 7 5/8" liner cemented at 12,300' MD. The well will be worked over and completed with a 2 -7/8" tubing string with packer set at 6280'. 1 13. The well will have passed an initial mechanical integrity test before disposal begins. 1 14. The waste stream will consist of produced water, drilling, completion and workover fluids, rig wash, drilling mud slurries, NORM scale, tank bottoms, and I other fluids brought to the surface in connection with oil and gas development activity. 1 1 Disposal Injection Order # Page 3 of 6 Kustatan Field #1 Well 1 15. Forest estimates that the average volume of fluids to be disposed will be approximately 1500 barrels per day, with a maximum volume of 5000 barrels per day. The average and maximum density of injected fluids will be 10.0 pounds per gallon (ppg) and 11.5 ppg, respectfully. 16. Forest estimates the surface injection pressure will not exceed 4000 psi at an injection rate of 5 barrels per minute (bpm). Average anticipated surface injection pressure is 3600 psi. 17. For DIO 22 Forest provided fracture modeling simulations of the upper Tyonek Formation assuming 23,810 barrels of 10.5 ppg fluid system transporting 5 ppg 100 mesh sand at a rate of 5 bpm. The resulting simulator output data showed the injected fluids to be fully contained within the intervals modeled (at 3784' MD and at 5477' MD). It is reasonable to assume that fluids injected at deeper intervals, middle Tyonek in the KF #1, will also be contained within their respective receiving intervals. 18. Fracture propagation within the disposal interval is an integral part of the process of placing waste slurries into the disposal interval. Fractures will be created as disposal zone porosity and permeability is occluded by the deposition of solids in pore spaces. Fractures provide pathways to transport waste fluids to unfilled areas within the disposal zone. 19. Forest will perform a step rate test to establish optimum injection rates and pressures. The step rate will be incrementally increased to pump rates 100% in excess of the maximum anticipated injection rates for waste disposal. Pressure falloff data will be collected at the end of the step rate test. 20. Reservoir surveillance techniques include but are not limited to step rate injection tests, monitoring operation parameters, estimating dimensions of disposal fracture or disposal storage volume, and detecting changes in disposal zone characteristics. CONCLUSIONS: 1. The application requirements of 20 AAC 25.252 have been met. 2. Waste fluids authorized for disposal under this order will consist exclusively of the following Class II fluids: produced water, drilling, completion and workover fluids, rig wash, drilling mud slurries, NORM scale, tank bottoms, and other fluids brought to the surface in connection with oil and gas development activity. 3. Permeable strata, which can reasonably be expected to contain the total volume of disposal fluid anticipated for this project, are present in the middle Tyonek Formation. 5. Waste fluids will be contained within appropriate receiving intervals by confining lithologies, cement isolation of the wellbore and operating conditions. 1 Disposal Injection Order # Page 4 of 6 Kustatan Field #1 Well 6. Disposal injection operations in the KF #1 well will be conducted at rates and pressures below those estimated to fracture the confining zones. 7. Evaluation of operational performance data and reservoir surveillance data will confirm that the confining zones are not being fractured. 8. Surveillance of disposal material placement, daily monitoring of operational parameters, and demonstration of mechanical integrity prior to injection and every two years thereafter will reasonably assure the waste fluids are contained within the disposal interval. 9. Disposal injection operations in the KF #1 well will not cause waste, jeopardize correlative rights, or impair ultimate recovery. NOW, THEREFORE, IT IS ORDERED Rule 1 Authorized Injection Strata for Disposal Class II oil field waste fluids may be injected in conformance with Alaska Administrative Code Title 20, Chapter 25, for disposal into the middle Tyonek 1 Formation, between the depths of 6750' and 6800' MD in the Kustatan Field #1 Well. Rule 2 Authorized Fluids This authorization is limited to Class II waste fluids as follows: produced water, drilling, completion and workover fluids, rig wash, drilling mud slurries, NORM scale, tank bottoms, and other fluids brought to the surface in connection with oil and gas development activity on the Osprey platform. Rule 3 Demonstration of Tubing /Casing Annulus Mechanical Integrity The tubing /casing annulus must be tested for mechanical integrity prior to the start of disposal operations and every two years thereafter. Rule 4 Surveillance Operating parameters including disposal rate, disposal pressure, annulus pressures and volume of slurry pumped must be monitored and reported according to the requirements of 20 AAC 25.432. Rule 5 Notification The operator must immediately notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. Rule 6 Administrative Action 1 1 Disposal Injection Order # Page 5 of 6 P J Kustatan Field #1 Well I Upon request or its own volition, the Commission may administratively revise and t reissue this order or any of its rules upon proper showing that the change is based on sound engineering practices, will not allow waste fluids to escape from I the disposal zone, and will not cause waste. Rule 7 Statewide Requirements I Except where a rule stated above substitutes for a statewide requirement, statewide requirements under 20 AAC 25 apply in addition to the above rules. 1 DONE at Anchorage, Alaska, and dated March , 2003. Daniel T. Seamount, Jr., Commissioner 1 Alaska Oil and Gas Conservation Commission 1 Randy Ruedrich, Commissioner Alaska Oil and Gas Conservation Commission 1 Sarah Palin, Commissioner I Alaska Oil and Gas Conservation Commission 1 I . 1 I 1 1 1 1 1 Forcenew KUSTATAN FORCENERGY #1 Section 4- T7N -R14W SM Kenai Borough, Alaska December 3, 2000 John Morris, Sr. Logging Geologist George Baker, Sr. Logging Geologist [l EPOCH TABLE OF CONTENTS 1 WELL RESUME 2 FORMATION SUMMARY 3 DAILY ACTIVITY SUMMARY 4 RIG UTILIZATION 5 DRILLING PROGRESS 6 MUD REPORTS AND BIT RECORDS El C 0 Well Resume FORCENERGY KUSTATAN FORCENERGY #1 Coordinates: 3443' FNL, 1468' FWL, SEC 4, T7N,R14W,SM Elevation: KB: 260' AMSL County: Kenai Borough State: Alaska API Index: 50- 133 - 20496 -00 Spud Date: 10/16/2000 Contractor: Nabors Alaska Drilling Rig: #160 —Land Logging Unit: #14 Geologists: John Morris, Jerry Stafford, George Baker Lowell Price, M.A. Hussain, Andrew Buchanan Co. Geologist: Art Saltmarsh Log Interval: 52' to 12300' Dates: 10/16/2000 to 12/3/2000 Mud Types: Spud Mud to 1820', LSND to 12300" Casing Data: 13 3/8" @ 1820' 9 5/8 " @ 6500' 7 5/8" liner @ T.D. Hole Size: 17'/" to 1820' 12 1/4" to 6500' 8 'Y" to 12300' FORMATION SUMMARY Forcenergy, Inc. Kustatan Forcenergy #1 Kenai Borough, Alaska 1820 SAND = CLEAR TO WHITE TO TRANSL WHT, TR BLACK, DRK GRAY, OCC GREEN, LOW CRS TO UPPER COARSE, SUBANG TO SUB ROUNDED, OCC ANGULAR, UNCONSOL, DOM LITHICS, META - ARGIL. 1855 COAL = DRK BRONISH TO BLACK; SOFT TO PITHY TO OCC FIRM; SLI BRITTLE; OCC TR MUSHY; ARGIL IP; DULL MATTE LUSTER; FLKY FIBOROUS TEX; OCC GRADING TO LO GRADE LIGNITE. 1885 SAND = WHITE TO CLEAR TO MED GRAY; MNR GRN; LOW MED TO LOW VERY COARSE; TR FINE; SUB ANG TO SUB ROUNDED; TRACE ANGULAR; DOM MOD SPHER; MINOR TO MOD AMOUNTS FSPR; DOM LITHICS W /QTZ OR QTZITE; TR MUSC; SCAT LIGNITE; NO OIL INDICATORS. 1925 COAL = BLACK TO DARK BROWN; SOFT TO PITHY TO OCC FIRM; TRACE BRITTLE; HACKLY TO FLKY CTGS; OCC THIN LAMS W /COATINGS OF FINE TO LOW MED SAND; DOM FIBOROUS TEX; TRACE LOW GRADE COAL. 1955 COAL = BLACK TO DARK BROWN; SOFT TO VERY FIRM; TRACE BRITTLE; HACKLY TO FLKY CTGS; OCC THIN LAMS; DOM FIBOROUS TEX; DULL MATTE LUSTER; TRACE LOW GRADE COAL. 1985 SAND = INCR ANGULAR; INCR CLEAR QTZ; GREEN CHLOR LITHICS; CLR, WHITE, DRK GRAY, GRN, LT GRAY, TR RED; VERY FINE • • TO FINE GRAINED; TRACE LOW MED; ANG TO ROUNDED; LOW SPHER; LITHS + QTZ MNR FSPR; TR MICA; PERSIST LIGN FRAGS. 2020 TUFFACEOUS CLAYSTONE = WHITE TO LT GRY; OCC BRN; SOFT TO VERY SLI FIRM; MUSHY IP DULL LUSTER; COM LAMS; SILTY, CARB MAT, MICA. 2045 COAL = DRK BROWN BLACK TO BLACK; PITHY TO VERY FIRM; OCC HARD; HACKLY TO FLKY CTGS; DULL MATTE LUSTER; TRACE SUBVIT; DOM FIBOROUS TEX; TRACE LOW GRADE COAL. 2075 SAND = WHITE TO CLEAR TO LT GRAY TO DARK GRAY, TR AMBER TO GREEN; FINE TO LOWER MED GRAINED; ANGULAR TO SUB ANGULAR; POORLY SORTED; OCC CLUSTER CMTD W SLTY CL MTRX; LITHICS DOM META - SEDS, TR MICA. 2110 SAND = VERY LT GRAY TO WHITE TO CLEAR; VERY FINE TO VERY FINE UPPER; SUBANG TO SUBROUNDED; MODERATE SPHERICITY; MOD TO POOR SORTING; SOME CLAY MATRIX; MOD AMOUNTS FELD, MICA. 2140 TUFFACEOUS CLAYSTONE = LIGHT GRAY; VERY SOFT; MOD EARTHY LUSTER; ASHY TEXTURE; SILTY; SCAT ORANGE BROWN ORGANIC REM; CARB STREAKS. 2165 SAND = WHITE TO CLEAR TO LT GRAY; TRACE AMBER TO GREEN; FINE TO LOWER COARSE; SUB ANGULAR TO SUB ROUNDED; MOSTLY UNCONSL; OCC CLUSTER CMTD WITH SILTY CLAY MTRX; MICA. 2195 TUFFACEOUS CLAYSTONE = DRK GRAY TO MED GRAY; SOFT TO OCC TRACE FIRM; BLOCKY; VERY CARBONACEOUS GRADING TO OCC LIGNITE; DULL TO CHALKY LUSTER. 2230 COAL = BROWNISH BLACK TO BLACK; PRED FIRM; GRAD TO OCC GARB SHALE; DULL • S EARTHY LUSTER; SOME SMOOTH LIGNITIC COALS; OCC LAMINATED; PLATY TO SUB PLATY; MOD TO VERY ARGIL GRADING TO CARB CLAYSTONE. 2265 TUFFACEOUS CLAYSTONE = MED TO DRK BRNSH GRY TO BRNSH BLK; SOFT TO MUSHY; DULL LUSTER; SMOOTH TEXTURE; OCC TO VERY SILTY; CARBONACEOUS IP. 2290 SAND = WHITE TO TRANSL WHITE, CLEAR, LT TO DRK GRAY, AMBER, OCC GREEN, TRACE RED; LOW FINE TO LOW COARSE; DOM LOW MED TO LOW CRS; POORLY SORTED; ANG TO SUB ANGULAR; MOD SPHER; UNCONS; QTZ W /ABD LITHICS; MINOR FSPR; TRACE CHLOR FLAKES; NO OIL INDICATORS. 2330 SAND = WHITE TO TRANSL WHITE TO CLEAR, SOME AMBER TO GREEN TO BLACK; FINE TO LOW MED TO OCC COARSE GRAINED; ANG TO SUB ANGULAR TO OCC SUB ROUNDED; MOD SPHER; TRACE FSPR; TRACE MICA; TR CHLOR FLAKES. 2365 COAL = DRK BROWN BLACK TO BLACK; FIRM TO OCC VERY FIRM; BRITTLE TO SPLNTRY; RSNS TO GREASY; OCC SBVIT LUSTER; STRIATED TEXTURE. 2390 SAND = WHITE TI TRANSL WHITE TO LT GRY; SOME AMBER TO GREEN TO BLACK; FINE TO UPPER MED GRAINED; ANGULAR TO SUB ANGULAR; TRACE SUB ROUNDED; MOD SPHER; UNCONS; MOD AMOUNTS FSPR; PERSIST LIG FRAGS; NO OIL INDICATORS. 2425 TUFFACEOUS CLAYSTONE = LIGHT GRAY TO WHITE, OCC PALE YELSH BROWN; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY WITH COM SLI FIRM LUMPS; RARELY APPEARS AS ROUGH, IRREGULAR POORLY INDURATED CUTTINGS; MATTE, EARTHY LUSTER WITH SCAT MICROSPARKLES; GRITTY, GRAINY TEXTUR; NON CALC; COM ASHY STREAKS AND BLEBS; COM BLACK PINPOINT SPECKS; NO OIL. • ! 2475 SAND = LIGHT GRAY OVERALL, DOM CLEAR, TRANSL WHITE, LT TO MED GREENISH GRAY; CLASTS RANGE FROM VERY FINE TO GRANULE; DOM FINE TO MEDIUM SIZE; ANGULAR TO ROUNDED, DOM ANGULAR TO SUBANGULAR; MOD SORTED IN THE FINE TO MEDIUM RANGE; COMPOSED OF 80% QUARTZ, 10% CHERT, 10% LITHICS; ESTIMATED GOOD POROSITY AND PERM; NO OIL INDICATORS. 2525 COAL = BLACK TO DUSKY BROWN; FIRM TO OCC MOD HARD; CRUMBLY TO BRITTLE; MATTE TO SLI SHINY LUSTER; SLI ROUGH SURF TEXTURE OCC WOODY APPEARANCE; OCC THIN LAMS OF CLAYSTONE; DOM IRREG CTGS, OCC PLATY TO BLOCKY. 2560 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; OCC AS POORLY INDURATED IRREG CUTTINGS; MATTE LUSTER WITH SCAT SPARKLES; GRITTY, ASHY TEXTURE WITH COM GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPECKS; NO OIL INDICATORS. 2600 SAND = LIGHT GRAY OVERALL, DOM CLEAR, TRANSL WHITE, LT TO MED GREENISH GRAY; CLASTS RANGE FROM VERY FINE TO MEDIUM; DOM FINE TO MEDIUM SIZE; SUBANG TO ROUNDED, DOM SUBANG TO SUBROUND; MOD SORTED IN THE FINE TO MEDIUM RANGE; COMPOSED OF 80% QUARTZ, 10% CHERT, 10% LITHICS; ESTIMATED GOOD POROSITY AND PERM; NO OIL INDICATORS. 2650 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; OCC AS POORLY INDURATED IRREG CUTTINGS; MATTE LUSTER WITH SCAT SPARKLES; GRITTY, ASHY TEXTURE WITH COM GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPECKS; NO OIL 2690 COAL = BLACK TO DUSKY BROWN; FIRM TO OCC MOD HARD; CRUMBLY TO BRITTLE; MATTE TO • • HINY LUSTER; SLI ROUGH SURF TEXTURE SLI S LUSTER; OCC WOODY APPEARANCE; OCC THIN LAMS OF CLAYSTONE; DOM IRREG CTGS, OCC PLATY TO BLOCKY. 2725 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; OCC AS POORLY INDURATED IRREG CUTTINGS; MATTE LUSTER WITH SCAT SPARKLES; GRITTY, ASHY TEXTURE WITH COM GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPECKS; NO OIL 2765 COAL = BLACK TO DUSKY BROWN; FIRM TO OCC MOD HARD; CRUMBLY TO BRITTLE; MATTE TO SLI SHINY LUSTER; SLI ROUGH SURF TEXTURE OCC WOODY APPEARANCE; OCC THIN LAMS OF CLAYSTONE; DOM IRREG CTGS, OCC PLATY TO BLOCKY. 2800 SAND = LIGHT GRAY OVERALL, DOM CLEAR, TRANSL WHITE, COM MED TO DK GRAY; CLASTS RANGE FROM VERY FINE TO MEDIUM; DOM FINE TO MEDIUM SIZE; SUBANG TO ROUNDED, DOM SUBANG TO SUBROUND; MOD SORTED IN THE FINE TO MEDIUM RANGE; COMPOSED OF 60% QUARTZ, 10% CHERT, 30% LITHICS; ESTIMATED GOOD POROSITY AND PERM; NO OIL INDICATORS. 2850 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; OCC AS POORLY INDURATED IRREG CUTTINGS; MATTE LUSTER WITH SCAT SPARKLES; GRITTY, ASHY TEXTURE WITH COM GLASS SHARDS. 2885 SAND = LIGHT GRAY OVERALL, DOM CLEAR, TRANSL WHITE, COM MED TO DK GRAY; CLASTS RANGE FROM V FINE TO MED GRAIN, DOM FINE TO MEDIUM SIZE; SUBANG TO ROUNDED, DOM SUBANG TO SUBROUND; MOD SORTED IN THE FINE TO MEDIUM RANGE; COMPOSED OF 60% QUARTZ, 10% CHERT, 30% LITHICS; ESTIMATED GOOD POROSITY AND PERM; NO OIL INDICATORS. • 2935 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; OCC AS POORLY INDURATED IRREG CUTTINGS; MATTE LUSTER WITH SCAT SPARKLES; GRITTY, ASHY TEXTURE WITH COM GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPECKS; NO OIL 2975 SAND = LIGHT GRAY OVERALL, DOM CLEAR, TRANSL WHITE, COM MED TO DK GRY, OCC GREEN; RANGES FROM V F TO GRANULE SZ; DOM FINE TO MEDIUM SIZE; ANGULAR TO ROUNDED, DOM SUBANG TO SUBROUND; MOD SORTED IN THE FINE TO MEDIUM RANGE; COMPOSED OF 70% QUARTZ, 10% CHERT, 20% LITHICS; ESTIMATED GOOD POROSITY AND PERM; NO OIL INDICATORS. 3025 COAL = BLACK TO DUSKY BROWN; FIRM TO OCC MOD HARD; CRUMBLY TO BRITTLE; MATTE TO SLI SHINY LUSTER; SLI ROUGH SURF TEXTURE OCC WOODY APPEARANCE; OCC THIN LAMS OF CLAYSTONE; DOM IRREG CTGS, OCC PLATY TO BLOCKY. 3060 SAND = LIGHT GRAY OVERALL, DOM CLEAR, TRANSL WHITE, COM MED TO DK GRY, OCC GREEN; RANGES FROM V F TO COARSE, DOM FINE TO MEDIUM SIZE; ANGULAR TO ROUNDED, DOM SUBANG TO SUBROUND; MOD SORTED IN THE FINE TO MEDIUM RANGE; COMPOSED OF 70% QUARTZ, 10% CHERT, 20% LITHICS; ESTIMATED GOOD POROSITY AND PERM; NO OIL INDICATORS. 3110 SAND = LT GRY TO CLEAR TO WHITE; SOME MED TO DRK GRAY; TRACE GREEN; VERY FINE OCC LOWER COARSE GRAINED; ANGULAR TO ROUNDED; DOM SUB ANGULAR TO SUB ROUNDED; MOD SORTED; COMPOSED OF 70% QUARTZ, 10% CHERT, 20% LITHICS; NO OIL INDICATORS. 3150 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS • I AMORPHOUS CLAY LUMPS; OCC AS POORLY INDURATED, MUSHY CTGS; MATTE, ERTHY LSTR WITH SCAT SPARKLES; GRITTY, GRAINY TEX; COM ASHY BLEBS; COM VOLC GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPECKS. 3190 SAND = LT GRY TO CLEAR TO WHITE; SOME MED TO DRK GRAY; TRACE GREEN; VERY FINE OCC LOWER COARSE GRAINED; ANGULAR TO ROUNDED; DOM SUB ANGULAR TO SUB ROUNDED; MOD SORTED; COMPOSED OF 70% QUARTZ, 10% CHERT, 20% LITHICS; NO OIL INDICATORS. 3230 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; OCC AS POORLY INDURATED, MUSHY CTGS; MATTE, ERTHY LSTR WITH SCAT SPARKLES; GRITTY, GRAINY TEX; COM ASHY BLEBS; COM VOLC GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPECKS. 3270 SAND = VERY LIGHT GRAY TO WHITE OVERALL; DOM CLEAR, TRANSL WHITE, OCC LT TO MED GRAY, OCC LT GREEN; VERY FINE TO COARSE, DOM VERY FINE TO MED; ANGULAR TO ROUNDED DOM SUBANGULAR TO SUBROUND; MOD SRTD; COMPOSED OF 60% QUARTZ, 30% LITHICS, 10% CHERT; FEW GRAINS WITH CALCITE CRUST ON SURFS; EST FAIR TO GOOD POR AND PERM. 3315 TUFFACEOUS CLAYSTONE = LIGHT GRAY TO LIGHT BROWNISH GRAY; VERY SOFT TO OCC SOFT; DOM APPEARS AS THICK TO RUNNY CLAY WITH COM SLI FIRM LUMPS; RARELY APPEARS AS POORLY INDURATED IRREG SHAPED CTGS; MATTE, EARTHY LUSTER WITH SCAT TO COM SPARKLES; SMOOTH TO VERY GRITTY TEXTURE; NON TO OCC VERY SLI CALC; COM ASHY ZONES. 3380 SAND = VERY LIGHT GRAY OVERALL, DOM TRANSL WHITE, CLEAR, OCC LT MED GRAY, LT GREEN, BLACK; VERY FINE TO MEDIUM; DOM FINE RANGE; SUBANGULAR TO SUBROUND; MOD WELL SORTED; COMPOSED OF 80% • • QUARTZ, 20% LITHICS; ESTIMATED FAIR TO GOOD POROSITY AND PERM; VERY SLIGHT ACID REACTION; NO EVID OF MATRIX; NO OIL INDICATORS. 3430 COAL = BLACK TO OCC DUSKY BROWN; FIRM; MOD BRITTLE; HACKLY TO OCC BLOCKY CTGS; MATTE TO SLI SHINY LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; SCAT LAMS OF ASH; SCAT STREAKS OF TUFFACEOUS CLAYSTONE; OCC VERY ARGILLACEOUS, GRADES IN PART TO CARBONACEOUS SHALE. 3470 SAND = VERY LIGHT GRAY OVERALL, DOM TRANSL WHITE, CLEAR, OCC LT MED GRAY, LT GREEN, BLACK;FINE TO MEDIUM GRAIN, DOM FINE RANGE; SUBANGULAR TO SUBROUND; MOD WELL SORTED; COMPOSED OF 70% QUARTZ, 30% LITHICS; ESTIMATED FAIR TO GOOD POROSITY AND PERM; VERY SLIGHT ACID REACTION; NO EVID OF MATRIX; NO OIL INDICATORS. 3520 SAND /CONGLOMERATE =LT GRY OVERALL, DOM TRANSL WHITE, CLEAR, OCC LT MED GRAY, LT GREEN, BLACK;FINE TO GRANULE RANGE, DOM MED RANGE; ANG TO SUBROUND; MOD WELL SORTED; COMPOSED OF 70% QUARTZ, 30% LITHICS; ESTIMATED FAIR TO GOOD POROSITY AND PERM; VERY SLIGHT ACID REACTION; NO EVID OF MATRIX; NO OIL INDICATORS. 3570 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; OCC AS POORLY INDURATED, MUSHY CTGS; MATTE, ERTHY LSTR WITH SCAT SPARKLES; GRITTY, GRAINY TEX; COM ASHY BLEBS; COM VOLC GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPECKS. 3610 COAL = BLACK TO OCC DUSKY BROWN; FIRM; MOD BRITTLE; HACKLY TO OCC BLOCKY CTGS; MATTE TO SLI SHINY LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; SCAT LAMS OF ASH; SCAT STREAKS OF TUFFACEOUS • • CLAYSTONE; OCC VERY ARGILLACEOUS, GRADES IN PART TO CARBONACEOUS SHALE. 3660 TUFFACEOUS CLAY = LIGHT BROWNISH GRAY; VERY SOFT TO SOFT;DOM APPEARS AS AMORPH OUS CLAY LUMPS;OCC AS POORLY INDURATED , MUSHY CTGS; MATTE, EARTHY LSTR WITH SCAT SPARKLES; GRITTY,GRAINY TEX; COM ASHY BL EBS;COM VOLC GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPECKS. 3700 COAL = BLACK TO OCC DUSKY BROWN, FIRM; MODERATELY BRITTLE; HACKLY TO OCC BLOCKY CTGS; MATTE TO SLI SHINY LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE SHINY LUSTER; SCAT LAMS OF ASH; SCAT STREAKS OF TUFFACEOUS CLAYSTONE; OCC VERY ARGILLACEOUS, GRADES IN PART TO CARBONACEOUS SHALE. 3745 SAND = VERY LIGHT GRAY OVERALL, DOM TRANSL WHITE, CLEAR, OCC LT MED GRAY, LT GREEN, BLACK; VERY FINE TO MEDIUM GRAINED; DOM FINE RANGE; SUBANGULAR TO SUBROUNDED; MOD WELL SORTED; COMPOSED OF 80% QUARTZ, 20% LITHICS; EST GOOD POROSITY AND PERM; VERY SLIGHT ACID REACTION; ON OIL INDICATORS. 3790 SAND = VERY LIGHT GRAY TO TRANSL WHITE, CLEAR, LT GREEN TO BLACK; VERY FINE TO LOWER MED GRAINED; DOM FINE RANGE; SUBANGULAR TO SUBROUNDED; MOD WELL SORTED; COMPSED OF 70% QUARTZ, 30% LITHICS; ESTIMATED FAIR TO GOOD POROSITY AND PERM; SLIGHT TO VERY GOOD ACID REACTION; NO OIL INDICATORS. 3835 TUFFACEOUS SILTSTONE = MINOR AMOUNTS; GRADES TO TUFFACEOUS CLAYSTONE; LT MED GRAY TO DARK GRAY; FIRM; SLI FRIABLE; SPRKLING LUSTER; MICA; OCC CARBONACEOUS INCL; ABD BLACK SPECKS. 3865 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY TO LT GRAY; VERY SOFT TO SOFT; DOM • • APPEARS AS AMORPHOUS CLAY LUMPS; MATTE, EARTHY LUSTER; WITH SCATTERED SPARKLES; GRITTY, GRAINY TEXTURE; COM VOLC GLASS SHARDS; COM BLACK PINPOINT SPECKS. 3905 SAND = WHITE TO CLEAR TO LT GRAY, SOME GREEN TO BLACK; VERY FINE TO MEDIUM GRAINED; DOM FINE RANGE; SUBANGULAR TO SUBROUNDED; MOD WELL SORTED; COMPOSED OF 70% QUARTZ, 30% LITHICS; ESTIMATED FAIR POROSITY AND PERM; NO OIL INDICATOR 3940 COAL = BLACK TO DUSKY BROWN; FIRM TO V FIRM; MOD BRITTLE; HACKLY TO OCC BLKY CTGS; MATTE LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; SCAT LAMS OF ASH. 3965 SAND /CONGLOMERATE = LT GRAY OVERALL; DOM TRANSL WHITE, TR CLEAR, LT MED GRAY, LT GREEN, BLACK; FINE TO LOWER MED RANGE; ANGULAR TO SUBANGULAR; POOR SORTING; COMPOSED OF 60% QUARTZ, 40% LITHICS, V GOOD ACID REACTION; NO OIL INDICATORS. 4000 SAND = LT GRY TOWHT TO TRANSL WHITE, TR GREEN TO BLACK; FINE TO MEDIUM GRAINED; DOM FINE RANGE; SUBANGULAR TO SUBROUNDED MOD WELL SORTED; COMPOSED OF 70% QTZ, 30% LITHIC; VERY GOOD ACID REACTION; EST FAIR POROSITY AND PERM; NO OIL INDICATOR 4035 COAL = BLACK TO OCC DARK BROWN; FIRM TO VERY FIRM; MOD BRITTLE; HACKLY TO OCC BLOCKY CTGS; MATTE TO SHINY LUSTER; SMOOTH TO SLI ROUGH TEXTURE; SCAT LAMS OF ASH; GRADES IN PART TO CARBONACEOUS SHALE. 4070 TUFFACEOUS CLAYSTONE = LIGHT GRAY TO MED GRAY, SOME BROWNISH GRAY; VERY SOFT TO OCC SOFT; DOM APPEARS AS THICK LUMPS; MATTE, EARTHY LUSTER; SCAT TO COM SPARKLES; GRITTY TEXTURE; NON TO OCC VERY SLI CALC; COM ASHY ZONES. 4105 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH • • GRAY TO LT GRAY; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; MATTE, EARTHY LUSTER; WITH SCATTERED SPARKLES; GRITTY, GRAINY TEXTURE; COM VOLC GLASS SHARDS; COM BLACK SPECKS. 4140 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL; COM CLEAR, TRANSL WHITE, LT TO MED GRAY, LT GREEN, BLACK; FINE TO GRAN SZ RANGE, DOM MED GRAIN; ANGULAR TO ROUNDED, DOM SUBANGULAR; POORLY SRTD; COMPOSED OF 70% QUARTZ, 30% IGNEOUS/ META LITHICS; UNCONS IN SAMPLE; SLIGHT ACID REACTION; ESTIMATED FAIR TO GOOD POR AND PERM; NO OIL INDICATORS. 4190 COAL = BLACK TO DUSKY BROWN; FIRM TO V FIRM; MOD BRITTLE; HACKLY TO OCC BLKY CTGS; MATTE LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; SCAT LAMS OF ASH. 4215 TUFFACEOUS CLAYSTONE = LIGHT GRAY WITH OCC BRNSH HUES; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; MATTE, EARTHY LUSTER; WITH SCATTERED SPARKLES; GRITTY, GRAINY TEXTURE; COM VOLC GLASS SHARDS; COM BLACK PINPOINT SPECKS. 4270 TUFFACEOUS CLAYSTONE = LIGHT GREY WITH OCC BRNSH HUES;VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; MATTE, EARTHY LUSTER; WITH SCATTERED SPARKLES; GRITTY, GRAINY TEXTURE; COM VOLC GLASS SHARDS; COM BLACK PINPOINT SPECKS. 4310 SAND = LT GRY TO WHITE TO TRANSL WHITE FINE TO MEDIUM GRAINED; SUB ANG TO SUB RND; MOD SRTD; MAINLY QTZ WITH LITHIC GRAINS; FAIR POROSITY; NO SHOWS. 4335 COAL = BLACK TO OCC DARK BROWN; FIRM TO VERY FIRM; MOD BRITTLE; HACKLY TO OCC OF ASH; GRADES IN PART TO CARBONACEOUS SHALE. • 4360 SAND = WHITE TO CLEAR TO LT GRAY, SOME GREEN TO RED TO BLACK; VERY FINE TO MED GRAINED; DOM FINE RANGE; SUBANGULAR TO SUBROUNDED; MOD WELL SORTED; COMPOSED OF 70% QUARTZ, 30% LITHICS; ESTIMATED FAIR TO GOOD POROSITY AND PERM; NO OIL INDICATORS. 4400 TUFFACEOUS CLAYSTONE = LIGHT GRAY TO MED GRAY; SOME BROWNISH GRAY; VERY SOFT TO OCC SOFT; DOM APPEARS AS THICK LUMPS; MATTE, EARTHY LUSTER; SCAT COM SPARKLES; GRITTY TEXTURE; NON TO V I I SLI CALC; COM ASHY ZONES. 4435 SAND = WHITE TO CLEAR TO LT GRAY; COM CLEAR; TRANSL WHT, GREEN TO BLACK; FINE TO LOWER MED GRAINED; DOM FINE GRN; SUBANGULAR TO SUBROUNDED; FAIR TO POORLY SORTED; COMPOSED OF 60% QTZ, 40% IGN /META LITHICS; UNCONS IN SAMPLE; SLI ACID REACTION; ESTIMATED FAIR TO GOOD POROSITY AND PERM; NO OIL IND. 4480 SAND = LIGHT GRAY TO WHITE TO TRANSL WHITE, TRACE GREEN TO BLACK; FINE TO MEDIUM GRAINED; DOM FINE RANGE; SUBANGULAR TO SUBROUNDED; MOD WELL SORTED; COMPOSED OF 70% QUARTZ, 30% LITHICS; POOR TO OCC FAIR ACID REACTION; ESTIMATED FAIR POROSITY AND PERM; NO OIL INDICATORS 4525 COAL = BLACK TO DUSKY DARK BROWN; FIRM TO VERY FIRM; MOD BRITTLE; HACKLY TO OCC BLOCKY CTGS; MATTE LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; SCAT LAMS OF ASH. 4555 SAND = CLEAR TO WHITE TO TRANSL WHITE; LIGHT GRAY TO OCC MED GRAY, TR GREEN TO MOD AMOUNTS BLACK; FINE TO LOWER MEDIUM GRAINED; DOM FINE RANGE; ANGULAR TO SUBANGULAR; SOME SUBROUNDED; POOR SORTING; COMPOSED OF 65% QUARTZ, 35% • • LITHICS; SLI ACID REACTION; EST FAIR POR AND PERM; NO OIL INDICATORS. 4600 TUFFACEOUS CLAYSTONE = LIGHT GRAY WITH OCC BROWNISH HUES; VERY SOFT TO SOFT; DOM APPEARS AS AMORPHOUS CLAY LUMPS; MATTE, EARTHY LUSTER; WITH SCATTERED SPARKLES; GRITTY TEXTURE; COM VOLC GLASS SHARDS; COM BLACK PINPOINT SPKS. 4635 SAND = LT GRAY TO TRANSL WHITE TO WHT; COM CLEAR, MED GRAY TO GREEN TO BLK; FINE TO MIDDLE MED GRAINED; DOM FINE RANGE; SUBANGULAR TO SUBROUNDED; POOR SORTING; COMPOSED OF 70% QUARTZ, 30% LITHICS; EST FAIR POROSITY AND PERM; NO OIL INDICATORS. 4675 SAND = LT GRAY TO WHITE TO CLEAR, SOME TRACE GREEN TO BLACK; FINE TO LOWER MEDIUM GRAINED; DOM FINE RANGE; SUB ANGULAR TO SUBROUNDED; POOR TO FAIR SORTING; COMPOSED OF 65% QUARTZ, 35% LITHICS; SLI ACID REACTION; EST FAIR POR AND PERM; NO OIL INDICATORS; SOME COAL LAMS IN SAND. 4720 TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM GRAY WITH OCC SLI BROWNISH HUES; VERY SOFT TO SOFT, OCC SLI FIRM; APPEARS AS AMORPHOUS CLAY WITH COM SLI FIRM LUMPS; RARELY AS POORLY INDURATED CTGS WITH LUMPY HABIT; MATTE, EARTHY LUSTER; GRITTY, GRAINY TEXTURE; NON TO SLI CALC. 4760 SAND = LT GRAY TO WHITE TO CLEAR, SOME TRACE GREEN TO BLACK; FINE TO LOWER MEDIUM GRAINED; DOM FINE RANGE; SUB ANGULAR TO SUBROUNDED; POOR TO FAIR SORTING; COMPOSED OF 70% QUARTZ, 30% LITHICS; SLI ACID REACTION; EST FAIR POR AND PERM; NO OIL INDICATORS; SOME COAL LAMS IN SAND. 4820 TUFFACEOUS CLAYSTONE = LOGGED AFTER TRIP, SAMPLES VERY POOR; LIGHT GRAY TO Y • • MED GRY TO OCC SLI BROWNISH HUES; VERY SOFT TO SOFT; APPEARS AS AMORPHOUS CLAY LUMPS; LUMPY HABIT; MATTE, EARTHY LUSTER; CARBONACEOUS IN PART; LUS GRAINY PART; TEXTURE. 4860 SAND = LT GRAY TO WHITE TO CLEAR, SOME TRACE GREEN TO BLACK; FINE TO LOWER MEDIUM GRAINED; DOM FINE RANGE; SUB ANGULAR TO SUBROUNDED; POOR TO FAIR SORTING; COMPOSED OF 70% QUARTZ, 30% LITHICS; SLI ACID REACTION; EST FAIR POR AND PERM; NO OIL INDICATORS; SOME COAL LAMS IN SAND. 4905 SAND = LT GRAY TO WHITE TO CLEAR, SOME TRACE GREEN TO BLACK; FINE TO LOWER COARSE GRAINED; DOM MED RANGE; SUB ANGULAR TO SUBROUNDED; POOR TO FAIR SORTING; COMPOSED OF 70% QUARTZ, 30% LITHICS; SLI ACID REACTION; EST FAIR POR AND PERM; NO OIL INDICATORS; SOME COAL LAMS IN SAND. 4950 COAL = BLACK TO DUSKY DARK BROWN; FIRM TO VERY FIRM; MOD BRITTLE; HACKLY TO OCC BLOCKY CTGS; MATTE LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; SCAT LAMS OF ASH; SCAT GAS BUBBLES ON SURFS. 4980 SAND = LT GRAY TO WHITE TO CLEAR, SOME TRACE GREEN TO BLACK; FINE TO LOWER COARSE GRAINED; DOM MED RANGE; SUB ANGULAR TO SUBROUNDED; POOR TO FAIR SORTING; COMPOSED OF 70% QUARTZ, 30% LITHICS; SLI ACID REACTION; EST FAIR POR FAIR TO POOR POR AND PERM; NO OIL. 5035 TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM GRAY; VERY SOFT TO SOFT; DOM APPEARS AS RUNNY TO STIFF CLAY WITH COM SLI FIRM LUMPS; OCC AS VERY POORLY INDUR- ATED ROUGHLY FORMED CTGS; MATTE LUSTER SMOOTH TO MOD GRITTY TEXTURE; NON TO OCC SLI CALC; COMMON ASHY ZONES; COM VOLC GLASS SHARDS; SCAT TO COM BLACK • • PINPOINT SPECKS. 5085 CARBONACEOUS SHALE = DARK GRAY TO BLACK; FIRM TO HARD; MOD BRITTLE; TOUGH; COM APPEARS AS TABULAR CTGS WITH DISTINCT EDGES; MATTE TO SLI SHINY LUSTER; SMOOTH TEXTURE; MOD TO OCC VERY CALC; SCAT THIN LAMS OF CALCITE. 5120 TUFFACEOUS CLAYSTONE = BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS STICKY TO STIFF OR MOD RUNNY CLAY; RARELY APPEARS AS POORLY INDURATED LUMPY CTGS; MATTE LUSTER; SMOOTH TO MOD GRITTY TEXTURE; NON TO LOCALLY MOD CALC; COM ASHY STREAKS; SCAT TO COM VOLC GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPECKS. 5170 COAL = BLACK TO OCC DUSKY BROWNISH BLACK; FIRM TO OCC MOD HARD; BRITTLE; CRUMBLY TO OCC MOD TOUGH; MATTE TO SLI RESINOUS LUSTER; SLI ROUGH SURFACE TEXTURE; SCAT ASHY LAMS; RARE PINPOINT GAS BUBBLES ON FRAC SURFACES. 5205 SAND /SANDSTONE = LIGHT GRAY TO WHITE OVERALL; FINE TO COARSE, DOM FINE TO MED GRAIN; RARE GRANULE SIZE GRAINS; ANGULAR TO ROUNDED, DOM SUBANGULAR; POORLY SORTED; COMPOSED OF 70% QUARTZ, 30% IG/ METANOLC LITHICS; GRAINS ARE LOOSE IN SAMPLE; SLI TO MOD ACID REACTION INDICATES CALCITE TRACES ON GRAIN SURFS; COM CLUMPS OF CLAY MATRIX MATERIAL; EST POOR TO FAIR POR AND PERM; NO OIL INDICATORS. 5265 TUFFACEOUS CLAYSTONE = GRAY TO BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS STICKY TO STIFF CLAY; MATTE LUSTER; MOD GRITTY TEXTURE; NON TO VERY SLI CALC; COM ASHY STREAKS; SCAT TO COM VOLC GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPKS. 5300 CARBONACEOUS SHALE = DRK BROWN TO BLK; • • FIRM TO HARD; MOD BRITTLE; TOUGH; COM APPEARS AS TABULAR CTGS; MATTE TO SLI SHINY LUSTER; ROUGH TEXTURE; SLI CALC. 5325 TUFFACEOUS CLAYSTONE = GRAY TO BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS STICKY TO STIFF CLAY; MATTE LUSTER; MOD GRITTY TEXTURE; NON TO VERY SLI CALC; COM ASHY STREAKS; SCAT TO COM VOLC GLASS SHARDS; SCAT TO COM BLACK PINPOINT SPKS. 5360 SAND @ 5370 = LIGHT GRAY OVERALL;FINE TO COARSE, DOM FINE TO MEDIUM; ANG TO ROUNDED, DOM SUBANGULAR; 70% QUARTZ, 30% LITHICS; DISAGGREGATED IN SAMPLE; COM CALCITE FRAGS; VIGOROUS ACID RXN; COM CLAY MATRIX MATERIAL FREE IN SAMPLE; EST FAIR POR AND PERM; NO OIL INDICATORS 5400 COAL = BLACK, OCC DUSKY YELSH BROWN; FIRM TO MOD HARD; BRITTLE TO MOD TOUGH; SMALL IRREG AND HACKLY CTGS; SLI RESINOUS LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; RARE ASHY LAMS; RARE PINPOINT GAS BUBBLES ON SURFACES. 5455 TUFFACEOUS CLAYSTONE = LT TO MED BROWNISH GRAY; VERY SOFT TO SOFT; INCR AMOUNT OF SAMPLE IS MOD TO VERY SOLUBLE CLAY; STICKY TO CREAMY; VERY RARE LUMPY CUTTINGS; MATTE LUSTER; SMOOTH TEXTURE; NON TO OCC SLI CALC; ASHY APPEARANCE; COM SPECKS; NO OIL INDICATORS. 5495 NOTE: ABUNDANT NUT PLUG IN SAMPLES. 5505 COAL = BLACK TO OCC DUSKY BROWNISH BLACK; FIRM TO OCC MOD HARD; BRITTLE; CRUMBLY TO OCC MOD TOUGH; MATTE TO SLI RESINOUS LUSTER; SLI ROUGH SURFACE TEXTURE; SCAT ASHY LAMS; RARE PINPOINT GAS BUBBLES ON FRAC SURFACES. 5555 SAND = LIGHT GRAY OVERALL; CLASTS RANGE • FROM FINE TO COARSE, DOM MEDIUM SIZE; ANGULAR TO ROUNDED, DOM SUBANGULAR TO SUBROUND; MOD SORTED; COMPOSED OF 70% QUARTZ, 30% METANOLC LITHICS; THIN STREAKS OF COAL; EST FAIR POR AND PERM; NO OIL INDICATORS. 5595 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL; CLASTS RANGE FROM FINE TO GRANULE SIZE, DOM MED RANGE; ANGULAR TO WELL ROUNDED, DOM SUBANGULAR TO SUBROUND; POORLY SORTED; COMPOSED OF 70% QUARTZ, 30% LITHICS; THIN STREAKS OF SANDSTONE ARE WELL CEMENTED AND DRILL SLOWER; EST FAIR TO GOOD POR AND PERM; NO OIL INDICATORS. 5645 TUFFACEOUS CLAYSTONE = LIGHT TO MED BROWNISH GRAY; VERY SOFT TO SOFT; DOM APPEARS AS THICK, PASTY CLAY WITH COM SLI FIRM LUMPY SHAPED CTGS; MATTE, EARTHY LUSTER; SMOOTH TO MOD GRITTY TEXTURE; DOM NON CALC, OCC MOD TO VERY CALC; SCAT TO COM ASHY BLEBS. 5685 COAL = BLACK TO OCC DUSKY BROWNISH BLACK; FIRM TO OCC MOD HARD; BRITTLE; CRUMBLY TO OCC MOD TOUGH; MATTE TO SLI RESINOUS LUSTER; SLI ROUGH SURFACE TEXTURE; SCATTERED LAMS OF TUFFACEOUS CLAYSTONE; RARE ASHY LAMS; 5735 TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM BROWNISH GRAY; VERY SOFT TO SOFT; DOM PASTY CLAY; MATTE, EARTHY LUSTER; MOD GRITTY TEXTURE; DOM NON CALC; ASHY APPEARANCE; COM SPECKS. 5765 SAND = LIGHT GRAY OVERALL; CLAST RANGE FROM FINE TO COARSE; DOM FINE TO MED; ANGULAR TO SUBROUNDED; MOD SORTED; COMPOSED 70% QUARTZ, 30% LITHICS; THIN STREAKS OF COAL; EST FAIR POROSITY AND PERM; ON OIL INDICATORS. 5800 TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM • BROWNISH GRAY; SOFT TO VERY SOFT; INCR AMOUNT OF SAMPLE IS MOD TO VERY SOLUBLE CLAY; STICKY; MATTE LUSTER; SMOOTH TO SLI GRITTY TEXTURE; NON TO SLI CALC; ASHY APPEARANCE; COM SPECKS. 5835 COAL = BLACK TO DRK BRN; FIRM TO MOD HRD BRITTLE; CRUMBLY TO MOD TOUGH; MATTE TO RESINOUS LUSTER; SCATTERED LAMS OF TUFFACEOUS CLAYSTONE. 5860 SAND /CONGLOMERATE = LT GRY TO WHT TO LT GRN; FINE TO GRANULE SIZE CLASTS; ANG TO SOME WELL RDD; POOR SORTING; COMPOSED OF 70% QTZ, 30% LITHICS; THIN STREAKS OF SANDSTONE PRESENT; EST FAIR TO MOD POROSITY AND PERM; NO OIL INDICATORS. 5895 COAL = BLACK TO DARK BROWN; FIRM TO OCC VERY HARD; BRITTLE; OCC CRUMBLY TO VERY TOUGH; MATTE TO RESINOUS LUSTER; SCATTER LAMS OF TUFFACEOUS CLAYSTONE; SLI ROUGH TO SMOOTH SURFACE TEXTURE; SCAT ASH LAMS. 5930 TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM BROWNISH GRAY; VERY SOFT TO SOFT; DOM PASTY CLAY; MATTE, EARTHY LUSTER; MOD GRITTY TEXTURE; DOM NON CALC; ASHY APPEARANCE. 5960 COAL = BLACK TO DRK BROWNISH BLACK; FIRM TO OCC MOD HARD; BRITTLE; CRUMBLY TO OCC MOD TOUGH; MATTE TO RESINOUS LUSTER; SLI ROUGH TO SMOOTH SURFACE TEXTURE; SCAT ASHY LAMS; RARE PINPOINT GAS BUBBLES ON FRAC SURFACES. 6000 TUFFACEOUS CLAYSTONE = LIGHT TO MED BROWNISH GRAY; VERY SOFT TO SOFT; APPEARS DOM AS CLAY; APPEARS ONLY RARELY AS VERY POORLY INDURATED LUMPY CTGS; MATTE, EARTHY LUSTER; SMOOTH TO MOD GRITTY TEXTURE; NON TO OCC MOD CALC; ASHY IN PART; COM VOLC GLASS SHARDS. • 6040 COAL = BLACK TO DARK BROWN; FIRM TO OCC MOD HARD; BRITTLE; OCC CRUMBLY TO VERY TOUGH; MATTE TO RESINOUS LUSTER; SCATTER LAMS OF TUFFACEOUS CLAYSTONE; SLI ROUGH TO SMOOTH SURFACE TEXTURE; SCAT ASH LAMS. 6075 TUFFACEOUS CLAYSTONE = LIGHT TO MED BROWNISH GRAY; VERY SOFT TO SOFT; APPEARS DOM AS CLAY; APPEARS ONLY RARELY AS VERY POORLY INDURATED LUMPY CTGS; MATTE, EARTHY LUSTER; SMOOTH TO MOD GRITTY TEXTURE; NON TO OCC MOD CALC; ASHY IN PART; COM VOLC GLASS SHARDS. 6130 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL; CLASTS RANGE FROM FINE TO GRANULE SZ, DOM MED TO COARSE RANGE; ANGULAR TO ROUNDED, DOM SUBANGULAR TO SUBROUND; POORLY SORTED; COMPOSED OF 70% QUARTZ, 30% METANOLC LITHICS; UNCONS IN SAMPLE; SLIGHT ACID REACTION; ESTIMATED FAIR TO GOOD POR AND PERM; 6175 TUFFACEOUS CLAYSTONE = LIGHT TO MED BROWNISH GRAY; VERY SOFT TO SOFT; APPEARS DOM AS CLAY; APPEARS ONLY RARELY AS VERY POORLY INDURATED LUMPY CTGS; MATTE, EARTHY LUSTER; SMOOTH TO MOD GRITTY TEXTURE; NON TO OCC MOD CALC; ASHY IN PART; COM VOLC GLASS SHARDS. 6215 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL; CLASTS RANGE FROM FINE TO GRANULE SZ, DOM MED TO COARSE RANGE; ANGULAR TO ROUNDED, DOM SUBANGULAR TO SUBROUND; POORLY SORTED; COMPOSED OF 70% QUARTZ, 30% METANOLC LITHICS; GRAINS ARE LOOSE IN SAMPLE; SLIGHT ACID REACTION FROM CALCITE ON GRAIN SURFS; COM CHUNKS OF CLAY MATRIX IN SAMPLE; EST FAIR TO GOOD POR AND PERM; NO OIL INDICATORS. 6275 COAL = BLACK; FIRM TO MOD HARD; BRITTLE, MOD TOUGH; HACKLY AND IRREG CTGS; • SLI RESINOUS LUSTER; SMOOTH TEXTURE; RARE CLAYSTONE LAMS; RARE PINPOINT GAS BUBBLES ON CTGS SURFACES. 6305 SAND = LIGHT GRAY TO WHITE OVERALL; CLASTS RANGE FROM VERY FINE TO COARSE; DOM FINE TO MEDIUM SZ; ANGULAR TO ROUND- ED; DOM SUBANGULAR TO SUBROUND; MOD SORTED IN THE FINE TO MEDIUM RANGE; 70% QUARTZ, 30% METANOLC LITHICS; EST FAIR POR AND PERM; NO OIL. 6345 SAND = LT GRY TO WHT; CLASTS RANGE FROM VF TO COARSE; DOM FINE; ANG TO RDD; DOM SUBANG TO SUBRDD; MOD SORTED; 70% QTZ, 30% LITHICS; NO OIL INDICATORS. 6370 COAL = BLACK TO DRK BRN; FIRM TO MOD HARD; BRITTLE; MOD TOUGH; HACKLY AND IRREG CTGS; RESINOUS LUSTER; SMOOTH TEXTURE; RARE CLAYSTONE LAMS; RARE PINPOINT GAS BUBBLES ON CTGS SURFACES. 6400 TUFFACEOUS CLAYSTONE = LIGHT TO MED BROWNISH GRAY; VERY SOFT TO SOFT; APPEARS DOM AS CLAY; MATTE, EARTHY LUSTER; SMOOTH TO MOD GRITTY TEXTURE; NON TO SLI CALC; ASHY IN PART; COM VOLC GLASS SHARDS. 6435 SAND /CONGLOMERATE = LT GRY TO WHT; FINE TO GRANULE SIZE; ANG TO SUBANG; POORLY SORTED; 70% QTZ, 30% LITHICS; GRN ARE LOOSE IN SAMPLE; EST FAIR POROSITY AND PERM; NO OIL INDICATORS. 6465 COAL = BLACK TO DARK BROWNISH BLACK; FIRM TO MOD HARD; BRITTLE, MOD TOUGH; HACKLY AND IRREG CTGS; RESINOUS LUSTER; SMOOTH TEXTURE; RARE CLAYSTONE LAMS; TRACE PINPOINT BUBBLES ON SURFACES. 6505 SAND = LIGHT GRAY TO WHITE OVERALL; CLASTS RANGE FROM VERY FINE TO COARSE; DOM FINE TO MEDIUM SZ; ANGULAR TO ROUNDED; DOM SUB ANGULAR TO RND • MOD SRTD 70% QUARTZ, 30% META/VOLC LITHICS; EST FAIR POROSITY AND PERM; NO OIL INDICATOR. 6545 TUFFACEOUS CLAYSTONE = LIGHT TO MED BROWNISH GRAY; VERY SOFT TO SOFT; APPEARS DOM AS CLAY; MATTE, EARTHY LUSTER; SMOOTH TO MOD GRITTY TEXTURE; NON TO SLI CALC; ASHY IN PART; COM VOLC GLASS SHARDS. 6580 SAND = LIGHT GRAY TO WHITE OVERALL; CLASTS RANGE FROM VERY FINE TO MEDIUM; DOM FINE TO MEDIUM SZ; ANGULAR TO ROUNDED; DOM SUB ANGULAR TO RND; MOD SRTD; 70% QUARTZ, 30% META/VOLC LITHICS; EST FAIR POROSITY AND PERM; NO OIL INDICATORS. 6620NOTE: ABUNDANT SOLTEX IN SAMPLES. 6630 SAND = LIGHT GRAY TO WHITE OVERALL; CLASTS RANGE FROM VERY FINE TO MEDIUM, DOM FINE RANGE; ANGULAR TO SUBROUND; MODERATELY WELL SORTED; COMPOSED OF 70% QUARTZ, 30% META/VOLC LITHICS; SCAT MUSCOVITE; GRAINS ARE LOOSE IN SAMPLE; SOME GRAINS WITH THIN CALCITE CRUSTS; MODERATE ACID REACTION; SCAT TO COMMON CLAY /CLAYSTONE MATRIX MATERIAL; ESTIMATED FAIR POR AND PERM; NO OIL INDICATORS. 6705 COAL = BLACK; BRITTLE; FIRM TO MOD HARD; BRITTLE TO MOD TOUGH; SMALL IRREG AND HACKLY CTGS; SLI RESINOUS LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; RARE ASHY LAMS; RARE PINPOINT GAS BUBBLES ON SURFACES. 6740 SAND = LIGHT GRAY TO WHITE OVERALL; DOM FINE RANG; ANGULAR TO SUB RND; MOD SRTD; COMPOSED OF 70% QUARTZ, 30% META/VOLC LITHICS; SCAT MUSCOVITE; SOME GRAINS WITH THIN CALCITE CRUSTS; GOOD ACID REACTION; CLAYSTONE MATRIX; • • ESTIMATED FAIR POR AND PERM; NO OIL INDICATOR. 6785 SAND = LIGHT GRAY TO WHITE; FINE TO MEDIUM GRAINED; MOD SRTD; ANGULAR TO LITHICS; FAIR POROSITY AND PERM; NO OIL INDICATOR. 6810 COAL = BLACK TO DARK BROWNISH BLACK; FIRM TO MOD HARD; BRITTLE; MOD TOUGH; RESINOUS LUSTER; RARE CLAYSTONE LAMS; TRACE PINPOINT BUBBLES ON SURFACES; RARE ASHY LAMS; 6840 SAND = LIGHT GRAY WHITE OVERALL; CLASTS RANGE FROM VERY FINE TO MEDIUM; DOM FINE TO MEDIUM SZ; ANGULAR TO LITHICS; EST FAIR POROSITY AND PERM; NO OIL INDICATORS. 6870 TUFFACEOUS CLAYSTONE = LT TO MED BRNSH GRAY; SOFT TO SLI FIRM; MUSHY TO OCC SLI CRUMBLY; MATTE, EARTHY LUSTER; SMOOTH TO SLI GRITTY TEXTURE; NON TO OCC SLI CALC; ASHY; COM SHARDS OF VOLC GLASS; COM BLACK PINPOINT SPECKS; SCAT GARB STREAKS. 6910 COAL = BLACK TO DARK BROWNISH BLACK; FIRM TO MOD HARD; BRITTLE; MOD TOUGH; RESINOUS LUSTER; RARE CLAYSTONE LAMS; TRACE PINPOINT BUBBLES ON SURFACES; RARE ASHY LAMS; 6940 CARBONACEOUS SHALE = BLACK TO OCC DARK REDDISH BLACK; FIRM TO MOD HARD; TOUGH; MATTE EARTHY TO VERY SLI RESINOUS LUSTER; SLI GRITTY TEXTURE; NON TO SLI CALC; COM LIGNITE STREAKS; POOR FISS. 6970 SAND = LIGHT GRAY OVERALL; CLASTS RANGE FROM VERY FINE TO MEDIUM, DOM FINE GRAINED; ANGULAR TO ROUNDED, DOM SUB - ANGULAR TO SUBROUND; MOD SORTED; COMPOSED OF 60% QUARTZ, 40% VOLC /META • • 7015 SAND = WHITE TO GRAY SL GRAY GREEN; FINE TO MEDIUM GRAINED; SUB ANGULAR TO ROUNDED; MOD SRTD; COMPOSED OF MAINLY QUARTZ, MINOR VOLC /META; FAIR POROSITY AND PERM; NO OIL INDICATOR. 7050 TUFFACEOUS CLAYSTONE = LT TO MED BRNSH GRAY; SOFT TO SLI FIRM; MUSHY TO OCC SLI CRUMBLY; MATTE, EARTHY LUSTER; SMOOTH TO SLI GRITTY TEXTURE; NON TO OCC SLI CALC; ASHY. 7080 SAND = CLEAR TO TRANLUCENT TO LT GRAY; FINE TO MEDIUM GRAINED; SUB ANGULAR TO ROUNDED; MOD SRTD; COMPOSED OF MAINLY QUARTZ, MINOR VOLC /META; NO SHOWS. 7125 TUFFACEOUS CLAYSTONE = LT TO MED BROWN - GRAY, IN PART LT TO MED BEIGE; SOFT TO SOFT; SUB BLOCKY TO MIN BLOCKY, SUB FISSILE TO FISSILE; WAXY LUSTER; SMOOTH TO GRITTY; NON TO WK CALCAREOUS; ASHY. 7155 COAL = BLACK TO DARK BROWNISH BLACK; MOD HARD; BRITTLE; RESINOUS LUSTER; SUB CONCHOIDAL TO CONCHOIDAL FRACTURES. 7175 SAND = WHITE TO OF WHITE, GRAY TO LIGHT GRAY, TRANSPARENT, LOOSE; FINE TO MED GRND; MOD SRTD; RND TO SUB RND; FAIR POROSITY AND PERM; NO OIL INDICATOR. 7205 CONGLOMERATE = LOOSE GRAINS, FROSTED, COARSE TO LOWER MEDIUM; SUB ANGULAR TO SUB ROUNDED; FAIR TO POORLY SRTD, RED TO GREEN CHERT;OCC CARBONACEOUS MATERIAL IN MATRIX; NO OIL INDICATOR. 7250 COAL = BLACK; FIRM TO MOD HARD; BRITTLE; MOD TOUGH; FINE TO 5MM CTGS WITH COM CONCHOIDAL FRACTURE SURFS; RESINOUS LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; RARE ASHY LAMS. • 7280 SAND = WHITE TO OFF WHT,GRAY TO DARK GRAY; FINE TO MEDIUM GRAINED, SUB ANG TO SUB RND, MOD SRTD; CLAY MATRIX WITH CARBONACEOUS MATERIAL EMBEDED IN GRAINS; POOR TO FAIR POROSITY WITH GOOD PERM; NO OIL INDICATOR. 7315 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY; SOFT,APPEARS AS AMORPHOUS CLAY LUMPS; POORLY INDURATED; PASTY, GUMMY GRAINY TEX; COM VOLC ASH BLEBS. 7340 COAL = BLACK TO DUSKY BROWN; FIRM TO OCC MOD HRD; CRUMBLY TO BRITTLE; SLI SHINY LUSTER; OCC WOODY APPEARANCE; OCC THIN LAMS OF CLAYSTONE; PLATY, BLOCKY AT PLACES. 7370 CONGLOMERATE /SAND = LIGHT GRAY TO TRANSLUCENT WHITE; UPPER COARSE AT PLACE FINE SUB ANG TO SUB RND; COMPOSED OF QUARTZ AND RED CHERT; MOD TO WELL SRTD; NO OIL INDICATORS PRESENT. 7400 TUFFACEOUS CLAYSTONE = LIGHT BROWNISH GRAY TO PINKISH GRAY; MOD INDURATED; MUSHY, PASTY, EARTHY TO GREASY LUSTER; GRADING TO SILTSTONE WITH CARBONACEOUS LAMINAE. 7430 SAND = WHITE TO OFF WHITE, GRAY TO DARK GRAY; FINE TO MEDIUM GRAINED; SUB ANG TO SUB RND; MOD SRTD; FAIR POROSITY AND PERM; NO OIL INDICATORS. 7455 SAND = LIGHT GRAY TO WHITE OVERALL; CLASTS RANGE FROM VERY FINE TO COARSE; DOM FINE TO MEDIUM SZ; ANGULAR TO RND; DOM SUB ANGULAR TO SUBRND; MOD SRTD; 70% QUARTZ, 30 %METANOLC LITHICS; EST FAIR POR AND PERM; NO OIL. 7490 TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM BROWNISH GRAY; VERY SOFT TO SOFT; APPEARS DOM AS CLAY; MATTE, EARTHY • LUSTER; SMOOTH TO MOD GRITTY TEXTURE; NON TO SLI CALC; ASHY IN PART; COM VOLC GLASS SHARDS. 7525 CONGLOMERATIC SAND = CLEAR TO TRANSLU- CENT, MINOR OPAQUE /LT GRAY; FINE TO LOCALLY COARSE GRAIN (DOMINANTLY FINE TO MED GRAIN); SUB ROUNDED TO ANGULAR (SUB ANGULAR BEING MOST PREVALENT); POOR TO MODERATELY SORTED; NO CEMENTED FRAG- MENTS OBSERVED - ALL INDIVIDUAL GRAINS (QUARTZ); NO SHOWS 7585 TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM BROWNISH GRAY; SOFT TO MOD SOFT; COMMON CLAY; TACKY; DULL, EARTHY LUSTER; COMMON GRITTY TEXTURE, LOCALLY SMOOTH; NON TO SLIGHTLY CALCAREOUS; ASHY IN PART; MINOR TO LOCALLY COMMON GLASS SHARDS. 7620 COAL = BLACK TO DARK BROWNISH BLACK; FIRM TO LOCALLY MOD HARD; SUB BRITTLE TO BRITTLE; PLATY TO SUBBLOCKY; RESINOUS LUSTER; SMOOTH TO VERY LOCAL PITTED SURFACES; COMMON CONCHOIDAL FRACTURES. 7650 TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM BROWNISH GRAY; SOFT TO MOD FIRM; COMMON CLAY; TACKY; DULL, EARTHY LUSTER; COMMON GRITTY TEXTURE, LOCALLY SMOOTH; NON TO SLIGHTLY CALCAREOUS; ASHY IN PART; MINOR TO LOCALLY COMMON GLASS SHARDS. 7685 SAND = LIGHT GRAY TO WHITE OVERALL; FINE TO MEDIUM GRAINED; ANGULAR TO RND; DOM SUB ANGULAR TO SUB ROUNDED; MOD SRTD IN THE FINE TO MEDIUM RANGE; 70% QURTZ, 30 %METANOLC LITHICS; EST FAIR POR AND PERM; NO OIL. 7700TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM BROWNISH GRAY; SOFT TO MOD SOFT; COMMON CLAY; DULL, EARTHY LUSTER, SMOOTH; NON TO SLI CALC; MINOR TO LOCALLY COMMON GLASS SHARDS; ABUNDANT COAL CAVING. • 7750 SAND = WHITE TO CLEAR TO LT GRAY; VERY FINE TO OCC COARSE GRAINED; DOM FINE TO MED; SUBANGULAR TO SUBROUNDED; VERY CALC; OFF WHITE TO LT GRAY CALC MATRIX; SOME SECONDARY XLN CALC. 7780 COAL = BLACK TO DARK BROWNISH BLACK; FIRM TO MOD HRD; SUB BRITTLE TO BRITTLE; PLATY TO SUB BLOCKY; RESINOUS LUSTER; SMOOTH TO VERY LOCAL PITTED SURFACES; COMMON CONCHOIDAL FRACTURES. 7810 SAND /SANDSTONE = LIGHT GRAY TO WHITE OVERALL; COM BLACK; VERY FINE TO MEDIUM, DOM FINE RANGE CLASTS; ANGULAR TO SUB ROUND, DOM SUBANG TO SUBROUND; MOD SORTED; COMPOSED OF 70% QUARTZ, 30% I II META/VOLC LITHICS; FRIABLE WHEN CONSOL; CLAY MATRIX, VARIABLE GRAIN /MATRIX SUPPORT; CALCITE CEMENT; EST POOR TO FAIR POR AND PERM; NO OIL INDICATORS. 7860 COAL = BLACK, OCC DARK BROWNISH BLACK; FIRM TO MOD HARD; BRITTLE, MOD TOUGH; SLI RESINOUS LUSTER; SMOOTH TO V SLI ROUGH SURFACE TEXTURE; SPLINTERY, PLATY, BLOCKY CTGS; COM CONCH FRAC SURFS. 7910 TUFFACEOUS CLAYSTONE = LT TO MED BROWNISH GRAY, OCC LT GRAY; SOFT TO RARELY MOD FIRM, RARELY MOD HARD; DOM MUSHY, OCC CRUMBLY, RARELY MOD TOUGH; MATTE, EARTHY LUSTER; SMOOTH TO SLI GRITTY TEXTURE; NON TO LOCALLY MOD CALC; RARELY VERY CALCAREOUS; COM ASHY BLEBS; COM BLACK PINPOINT SPECKS; NO STRUCTURE. 7960 SAND = LT GRAY OVERALL; CLASTS RANGE FROM VERY FINE TO MEDIUM, DOM FINE RANGE; ANGULAR TO ROUNDED, DOM SUB - ANGULAR TO SUBROUND; MOD SORTED; COMPOSED OF 70% QUARTZ, 30% META/VOLC LITHICS; LOOSE IN SAMPLES; SLI ACID RXN; • 7995 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL, COM LT GREEN, SCAT RED- DISH ORANGE; CLASTS RANGE FROM FINE TO PEBBLE FRAGS; ANGULAR TO ROUNDED, COM BIT SHEARED GRAINS; POORLY SORTED; COMPOSED OF 80% QUARTZ, 20% META/OLC LITHICS; COM GREENSTONE, SCAT JASPER; LOOSE IN SAMPLE; NO EVID OF MATRIX OR CEMENTATION; EST GOOD POR AND PERM; NO OIL INDICATORS. 8050 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE COM LIGHT GREEN,SCAT REDISH ORANGE; ANG TO RND; CLASTS RANGE FN TO COARSE; POORLY SRTD; COMPOSED OF 50% QUARTZ,20% META NOLC LITHICS; COM GREENSTONE, SCAT JASPER, GOOD POR AND PERM; NO OIL. 8085 SAND /CONGLOMERATE = CLEAR TO WHITE TO LT GRAY; SOME LT GREEN TO OCC REDDISH; CLASTS RANGE FROM FINE TO OCC PEBBLE SIZE; ANGULAR TO ROUNDED; COMMON BIT SHEARED GRAINS; POORLY SORTED; AT 8114 TO 8118 LIGHT BROWN OIL STAIN ON OCC GRAINS; NO FLUOR; GOOD GREENISH YELLOW CUT; GOOD RING CUT. 8130 CARBONACEOUS SHALE = BLACK TO DARK BROWN AT PLACES REDDISH BROWN; MED HRD; GUMMY, PASTY, FISSILE AND SPLINTERY; CALC AT PLACES. 8155 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL; FINE TO PEBBLE SIZE; ANG TO RND POORLY SRTD; MAINLY QUARTZ WITH MINOR AMOUNT OF METANOLC; AMBER COLOR CHERT; LOOSE IN SAMPLES; GOOD POR AND PERM; NO OIL INDICATOR. 8195 TUFFACEOUS CLAYSTONE = LT TO MED BRN EARTHY LUSTER; SMOOTH TO GRITTY TEXTURE MOD CALC; COM ASHY BLEBS; COM BLACK PIN POINT SPECKS; NO STRUCTURE. 8225 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL; LT GRN, SCAT REDISH ORANGE; • FINE TO PEBBLE FRAGS; ANG TO RND; POORLY SRTD; 90% QUARTZ, 10% METANOLC LITHICS; SCAT JASPER; MOD CMT; FAIR POR AND GOOD PERM; NO SHOWS. 8275 ASH FLOW TUFF = (TRACE AMOUNTS) WHITE, PALE YELSH BROWN; SOFT TO MOD FIRM; CRUMBLY; FLAKY TO LUMPY CTGS; MATTE TO CHALKY LUSTER; SMOOTH TO MOD GRITTY TEXTURE; NON TO OCC SLI CALC; FAINT TO MOD BRIGHT LT YELLOW MINERAL FLUOR. 8310 COAL = BLACK; FIRM TO MODERATELY HARD; MODERATELY TOUGH; BRITTLE; SMALL TO 5 MM BLOCKY, HACKLY CTGS; COM CON- , CTGS; CHOIDAL FRACTURE SURFACES; SLI RESI- NOUS LUSTER; SMOOTH TO SLI ROUGH SURFACE TEXTURE; RARE ASHY LAMS. 8345 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL; GRN, SCAT REDDISH ORANGE; FINE TO PEBBLE FRAGS; ANG TO RND; POORLY SRTD 90% QUARTZ, 10% META NOLC LITHICS; SCAT JASPER; MOD CMT; FAIR POR AND GOOD PERM; NO SHOWS. 8380.0 TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM BRN GRY; SOFT; MUSHY TO CRUMBLY; IRREG FRACTURE; DULL, OCC SHINY; SCAT GARB SPECKS. 8405 COAL = BLACK, FIRM TO MOD HRD; MOD TOUGH BRITTLE; BLOCKY;CONCHOIDAL FRACTURE SURFACES; SL RESINOUS LUSTER; SMOOTH TO ROUGH TEXTURE; RARE ASHY LAMS; CARBONACEOUS IN PART. 8435 SANDSTONE = LIGHT GRAY TO WHITE; LIGHT GREEN; FINE TO MEDIUM GRAINED; SUBANGULAR TO SUBROUNDED; MOD SRTD; FAIR POR; NO SHOWS. 8460 COAL = BLACK; FIRM TO MOD HRD; MOD TOUGH; BRITTLE; BLOCKY;CONCHOIDAL FRAC SURFACES; SL RESINOUS LUSTER; DOM SMOOTH TO SLI ROUGH SURFACE • • TEXTURE; RARE ASHY LAMS. 8490 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL, COM BLACK, LT GREEN, OCC RED - ISH ORANGE; CLASTS RANGE FROM MED TO PEBBLE FRAGS; ANGULAR TO ROUNDED; COM BIT SHEARED GRAINS; POORLY SORTED; COMPOSED OF 80% QUARTZ, 20% LITHICS; LOOSE IN SAMPLE; EST GOOD POR AND PERM; NO OIL INDICATORS. 8550 TUFFACEOUS CLAYSTONE = LIGHT TO MEDIUM BRN GRY; SOFT; MUSHY TO CRUMBLY; IRREG FRACTURE; DULL, OCC SHINY; SCAT CARB SPECKS; MASSIVE TO SLI PLATY CUTTINGS HABIT; CLAYEY TO SILTY TEXTURE; SILTY IN PART. 8585 SANDSTONE = LIGHT GRAY TO WHITE; PREDOM LOOSE GRAINS; LOWER COARSE TO MEDIUM GRAINED; SUBANGULAR; MOD SORTED; SOME GRAIN SUPPORTED SPECIMENS; CLAY MATRIX; TRACE CHERT; 90% QTZ; 10% LITHICS; TRACE AMOUNTS OF REDBROWN GRAINS; EST GOOD POROSITY AND PERMEABILITY; NO SAMPLE SHOWS. 8630 TUFFACEOUS CLAYSTONE = MEDIUM DARK GRAY TO GRAYBROWN; FIRM TO MOD SOFT; MASSIVE TO SLI PLATY CUTTINGS; IRREGULAR FRACTURE; SLI SILTY; CLAYEY TO SLI SILTY TEXTURE; VERY FINE CARBONACEOUS MATERIAL; NON TO VSLI CALCAREOUS. 8665 COAL = BLACK; MOD HARD; SPLINTERY TO SCALY CUTTINGS; BLOCKY TO OCC CONCHOIDAL FRACTURE; SLI RESINOUS LUSTER; SMOOTH TEXTURE; THICKLY BEDDED; OCC VISIBLE GAS BLEEDING FROM FRACTURES. 8715 TUFFACEOUS CLAYSTONE = MEDIUM GRAY TO BROWNISH GRAY; SOFT TO FIRM; MASSIVE TO SLI PLATY CUTTINGS; IRREG FRACTURE; CARBONACEOUS SPECKS AND STREAKS; SILTY TO CLAYEY TEXTURE; i • INTERBEDDED WITH COAL. 8750 SANDSTONE = LIGHT GRAY TO WHITE; MAINLY LOOSE GRAINS; FINE TO MEDIUM GRND; SUBANGULAR; MOD SORTED; SOME TRACE CHERT; 90% QTZ; 10% LITHICS; TRACE AMOUNTS OF REDBROWN GRAINS; EST GOOD POROSITY AND PERMEABILITY; NO SAMPLE SHOWS. 8790 TUFFACEOUS CLAYSTONE = MEDIUM DARK TO BROWNISH GRAY; SOFT TO FIRM; MASSIVE TO SLI PLATY CUTTINGS; IRREG FRACTURE; CARBONACEOUS SPECKS AND STREAKS; SILTY TO CLAYEY TEXTURE. 8820 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL, COM BLACK, LT GREEN, OCC RED - ISH ORANGE; CLASTS RANGE FROM MED TO PEBBLE FRAGS; ANGULAR TO ROUNDED; COM BIT SHEARED GRAINS; POORLY SORTED; IN PARTS METANOLC LITHICS; FAIR POR AND PERM; NO SHOWS. 8860 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL, COM BLACK, LT GREEN, OCC RED - ISH ORANGE; CLASTS RANGE FROM MED TO PEBBLE FRAGS; ANGULAR TO ROUNDED; MOD SRTD; META NOLC LITHICS GRAINS; FAIR POR AND PERM; NO SHOWS. 8895 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL, COM BLACK, LT GREEN, OCC RED - ISH ORANGE; CLASTS RANGE FROM MED TO PEBBLE FRAGS; ANGULAR TO ROUNDED; MOD SRTD; META NOLC LITHICS GRAINS; NO SHOWS. 8930 COAL = BLACK, OCC DARK BROWNISH BLACK; TO SCALY CUTTINGS; BLOCKY TO OCC CONCHOIDAL FRACTURE; SLI RESINOUS LUSTER; SMOOTH TEXTURE; THICKLY ROUGH TEXTURE; RARE ASHY LAMS. 8960 SAND /CONGLOMERATE = LIGHT GRAY TO WHITE OVERALL, COM BLACK, LT GREEN, OCC RED- • ISH ORANGE; CLASTS RANGE FROM MED TO PEBBLE FRAGS; ANGULAR TO ROUNDED; l i MOD SRTD; META NOLC LITHICS GRAINS; POOR TO FAIRSHOW; FLUOR, MODERATE TO FAIR CUT GOLDEN COLOR. 9000 SAND /CONGLOMERATE = LT GRAY TO WHITE OCC GREEN TO RED; CLAST RANGE FROM FINE TO PEBBLE RANGE; ANGULAR TO SUB ROUNDED; POOR SORTING; 70% QUARTZ 30% METANOLC; GOOD TO FAIR POROSITY AND PERM. 9035 SANDSTONE = PREDOM LOOSE GRAINS; CLEAR TO TRANSPARENT; PREDOM MEDIUM GRAINED; TRACE AMTS OF LOWER COARSE GRAINS; WELL SORTED; ANGULAR TO SUBANGULAR; LOW TO MOD SPHERICITY; NO MATRIX PRESERVED; 95% QTZ; MINOR AMTS OF JASPER AND CHERT; EST GOOD POROSITY AND PERM. 9080 SANDSTONE = LIGHT GRAY TO WHITE; SOFT; MEDIUM TO FINE GRAINED; WELL SORTED; ANGULAR TO SUBANGULAR; MOD SPHERICITY; GRAIN SUPPORTED; CLAY MATRIX; OCC VERY CLAYEY; TR AMOUNTS OF CHERT; SOME CARB MATERIAL; EST FAIR POROSITY AND PERM. 9115 COAL = BLACK TO DARK BROWNISH BLACK; MOD SOFT; BRITTLE; SUB BLOCKY TO PLATY; RESINOUS LUSTER; SUB CONCHOIDAL TO CON - CHOIDAL FRACTURES; SMOOTH TEXTURE; HACKLY CUTTINGS. 9145 SANDSTONE = CLEAR TO TRANSLUCENT /LIGHT GRAY; SOFT; PREDOMINANTLY LOOSE GRAINS; FINE TO MEDIUM GRAIN; MOD WELL SORTED; GRAIN SUPPRTED; MATRIX NOT PRESERVED, PROBABLY CLAY MATRIX; SUBROUNDED TO SUBANGULAR; NO SHOWS. 9180 CONGLOMERATIC SANDSTONE = CLEAR TO TRANSLUCENT TO LT TO MED GRAY; SOFT; FINE TO COARSE GRAINED; POORLY SRTD; CLAYEY MATRIX; MINOR LOCAL CALCITE • CEMENT (DULL YELLOW MINERAL FLUOR); COMMON ANGULAR; LT TO MED GRAY CHERT FRAGMENTS; NO SHOWS 9220 TUFFACEOUS CLAY STONE = DARK BROWN TO GRAY BROWN; FIRM; SBPLATY TO MASSIVE; IRREGULAR FRACTURE; VERY CARBONACEOUS; CLAYEY TO SILTY TEXTURE;ABNT LOOSE SAND GRAINS; INTERBEDDED W/ COAL. 9250 COAL = BLACK TO DARK BROWNISH BLACK; MOD SOFT; BRITTLE; SUBBLOCKY TO PLATY; FRAC SURFACES; SL RESINOUS LUSTER; HACKLY CUTTINGS. 9275 CONGLOMERATIC SANDSTONE = CLEAR TO TRANSLUCENT TO LT TO MED GRAY; SOFT; FINE TO COARSE GRAINED; POORLY SRTD; COMMON ANGULAR, LT TO MED GRAY CHERT FRAGMENTS; NO SHOWS. 9305 COAL = BLACK TO DARK BROWNISH BLACK; MOD SOFT; BRITTLE; SUBBLOCKY TO PLATY; FRAC SURFACES; SL RESINOUS LUSTER; HACKLY CUTTINGS. 9330 TUFFACEOUS CLAY STONE = DARK BROWN TO GRAY BROWN; FIRM; SBPLATY TO MASSIVE; IRREGULAR FRACTURE; CARBONACEOUS AT PLACES;OCC SLI TO MODERATELY SILTY; NON TO V SLI CALC. 9360 CONGLOMERATIC SANDSTONE = CLEAR TO TRANSLUCENT TO LT TO MED GRAY; SOFT; FINE TO COARSE GRAINED; POORLY SRTD; COMMON ANGULAR, LT TO MED GRAY CHERT FRAGMENTS; NO SHOWS. 9390 TUFFACEOUS SILTSTONE = BROWN TO GRAY BROWN; FIRM; SBPLATY TO MASSIVE; IRREGULAR FRACTURE;CARBONACEOUS AT PLACES. 9415 SAND = CLEAR TO WHITE AT PLACES TRANSLUCENT TO LT TO MED GRAY; SOFT; FINE TO COARSE GRAINED; POORLY SRTD; • • COMMON ANGULAR, LT TO MED GRAY CHERT FRAGMENTS; NO SHOWS. 9445 CONGLOMERATE = PREDOM LOOSE GRAINS; CLAST SIZE RANGES FROM PEBBLE TO FINE GRAINED; ANGULAR TO SUBROUNDED; POORLY SORTED; MOD SPHERICITY; BIT IMPACTED GRAINS; NO MATRIX PRESERVED; 60% QTZ, VARICOLORED GRAINS, 20% CHERT; 20% IGN/ META; NO SHOWS. 9485 COAL = BLACK; FIRM TO SLI HARD; PLATY TO SPLINTERY CUTTINGS; BLOCKY TO PLANAR FRACTURE; SLI RESINOUS LUSTER; SMOOTH TO IRREGULAR TEXTURE; THINLY INTERBEDDED W /CLAYSTONES. 9515 TUFFACEOUS CLAYSTONE = MEDIUM GRAY TO GRAYBROWN TO MEDIUM BROWN; FIRM; SLI PLATY CUTTINGS; IRREG FRACTURE DULL EARTHY LUSTER; SMOOTH TO SILTY TEXTURE; COMMONLY VERY SILTY AND VERY CARBONACEOUS; INTERBEDDED WITH COAL. 9550 COAL = BLACK; FIRM TO SLI HARD; PLATY TO SPLINTERY CUTTINGS; BLOCKY TO PLANAR FRACTURE; SLI RESINOUS LUSTER; SMOOTH TO IRREGULAR TEXTURE; THINLY INTERBEDDED W /CLAYSTONES. 9580 SANDSTONE = LIGHT GRAY; FINE LOWER TO COARSE ; ANGULAR TO SUBROUND; LOW SPHERICITY; POORLY SORTED; PITTED TO FROSTED SURFACE TEXTURE; SAND APPEAR PREDOMINANTLY AS DISAGGRATED GRAINS; VERY POORLY CEMENTED; GRAIN SUPPORTED W/ TUFF CLAY / SILTSTONE MATRIX IN PART; ESTIMATED FAIR TO GOOD POROSITY; 70% QTZ 20% CHERT, 10% LITHIC AND DARK MIN; GRAINS SHOW TRACE VERY LIGHT YEL -GN FLORO W/ SLOW WEAK YEL -GN CUT. 9640 CONGLOMERATE = PREDOM LOOSE GRAINS; SOME HARD PRESERVED SPECIMENS; SPECKLED WHITE AND BLACK; CLAST SIZE FROM PEBBLE TO MEDIUM GRAINED; POORLY SORTED; • • ANGULAR TO SUBROUNDED; LOW SPHERICITY; GRAIN SUPPORTED; SILICEOUS; SOME PIECES ARE FUSED QUARTZ; 80% QUARTZ; 20% LITHICS(META -IGN TO SILTSTONE); ABUNDANT CHERT; TRACE AMOUNTS OF JASPER; SOME PIECES ARE VERY COALY; NO SAMPLE SHOWS. 9710 COAL = BLACK TO DARK BROWNISH BLACK; FIRM TO MOD HARD; BRITTLE, MOD TOUGH; RESINOUS LUSTER; SMOOTH TO VERY LOCAL ROUGH SURFACE TEXTURE; SPLINTERY, PLATY, TO COMMON SUBBLOCKY TO BLOCKY; COMMON SUBCONCHOIDAL TO CONCHOIDAL FRACTURES. 9750 SANDSTONE = CLEAR TO TRANSLUCENT /LIGHT GRAY; SOFT; PREDOMINANTLY LOOSE GRAINS; FINE TO MEDIUM GRAIN; MOD WELL SORTED; GRAIN SUPPRTED; MATRIX NOT PRESERVED, PROBABLY CLAY MATRIX; SUB ROUNDED TO SUB ANGULAR; NO SHOWS. 9785 TUFFACEOUS SILTSTONE = LIGHT TO MEDIUM GRAY; SOFT; MUSHY; EARTHY FRACTURE; MASSIVE CUTTINGS; EARTHY /OCC SPARKLY LUSTER; GRITTY /CLAYEY TEXTURE; VISIBLE RELIC GLASS SHARDS; ABNT TUFF CLAY MTX. 9815 TUFFACEOUS CLAYSTONE = LIGHT GRAY TO WHITISH GRAY; MUSHY;SOFT; EARTHY FRACTURE; MASSIVE CTGS; EARTHY /OCC SPARKLY LUSTER; MATTE/CLAYEY TEXTURE; HYDROPHILIC IP; RARE CARBONACEOUS IP; VIS GLASS SHARDS IP. 9850 COAL = BLACK TO DARK BROWNISH BLACK; FIRM TO MOD HARD; BRITTLE, MOD TOUGH; RESINOUS LUSTER; SMOOTH TO VERY LOCAL ROUGH SURFACE TEXTURE; SPLINTERY, PLATY, TO COMMON SUBBLOCKY TO BLOCKY; COMMON SUBCONCHOIDAL TO CONCHOIDAL FRACTURES. 9890 SANDSTONE = WHITE TO LIGHT GRAY; HARD; PREDOM LOOSE GRAINS; CLAST SIZE RANGES FROM UPPER COARSE TO LOWER MEDIUM • • GRAINED; ANGULAR TO SUBANGULAR; POORLY SORTED; LOW SPHERICITY; ABUNDANT CHERT AND JASPER; GRAIN SUPPORTED; PRESERVED PIECES ARE GRAINED SUPPORTED, SILICEOUS, AND EXHIBIT FUSED QUARTZ; 80% QTZ; 10% CHERT AND JASPER;10% LITHICS; PRESERVED PIECES EXHIBIT POOR POROSITY; NO SAMPLE FLUOR OR CUT. 9950 NOTE: BECAUSE OF VERY SLOW DRILL RATES SAMPLE QUALITY VERY POOR FROM 9960 TO 9983. 9970 TUFFACEOUS SILTSTONE = MEDIUM GRAY TO GRAY BROWN; FIRM TO SLI HARD; SLI PLATY CUTTINGS; IRREGULAR FRACTURE; SILTY TEXTURE; V SLI CALC; CARB MATERIAL. 9995 CONGLOMERATIC SANDSTONE = WHITE TO LIGHT GRAY; SLI HARD; CLAST SIZE RANGES FROM PEBBLE TO LOWER MEDIUM GRAINED; ANGULAR TO SUBROUNDED; MOD SORTED; LOW TO MOD SPHERICITY; GRAIN SUPPORTED CALCITE CEMENT IN PRESERVED PIECES; 90% QTZ; 10% LITHICS AND CHERT FRAGMENTS OCC DULL YELLOW MINERAL FLUORESCENCE (CALCITE) NO SAMPLES SHOWS OR CUTS 10045 COAL = BLACK; MOD HARD; SPLINTERY TO BLOCKY CUTTINGS HABIT; BLOCKY TO PLANAR FRACTURE; RESINOUS LUSTER; SMOOTH TO ROUGH TEXTURE; TR AMBER; SOME BLEEDING GAS ESCAPING FROM FRACTURES. 10075 SANDSTONE = LIGHT GRAY; PREDOM LOOSE GRAINS; CLAST SIZES RANGE FROM LOWER COARSE TO FINE GRAINED; SUBANGULAR TO SUBROUNDED; LOW TO MOD SPHERICITY; POORLY SORTED; MATRIX TO GRAIN SUPPORTED SOME WHITE, SOFT, MATRIX MATERIAL IN SAMPLES; CARBONACEOUS CLAY MATRIX; 90% QUARTZ; 10% LITHICS; NO SAMPLE FLUORESCENCE OR CUTS. 10125 SANDSTONE = PREDOM LOOSE GRAINS; TR AMTS OF LIGHT GRAY; LOWER COARSE TO FINE GRAINED; BECOMING CLEANER WITH NO CLAY MATRIX MATERIAL; SUBROUNDED; POORLY SORTED; MOD SPHERICITY; GRAIN SUPPORTED WITH CALCITE MATRIX; 95% QUARTZ W/ MINOR AMTS OF CHERT /JASPER; TRACE UNDIFF GREEN GRAINS; EST GOOD POROSITY AND PERMEABILITY; NO SAMPLE FLUORESCENCE OR CUT. 10180 COAL = BLACK; MOD HARD; SPLINTERY TO PLATY CUTTINGS; CONCHOIDAL TO BLOCKY FRACTURE; RESINOUS TO SLI VITREOUS O S EOUS LUSTER; SMOOTH TO ROUGH TEXTURE; SOME GAS BLEEDING FROM FRACTURES. 10210 SANDSTONE = CLEAR TO OCC LT GRAY; PREDOM LOOSE GRAINS; LWR COARSE TO LWR FINE GRAINS; PREDOM SUBROUND TO SUBANGULAR; LOW SPHR; MOD WELL SORTED; GRAIN SUPPORT W/ OCC WH MATRIX MATERIAL IN CONS CHIPS; 95% CLR QTZ GRNS; EST GOOD POROSITY AND PERM, NO VIS 0 STN, FLORO OR CUT. 10265 SANDSTONE = LT GRAY W/ BROWNISH GRAY; MEDIUM TO LOWER COARSE; VERY ANGULAR LOW SPHR; MOD SORTED; WELL CONSOLIDATED IN PART; GRAIN SUPPORTED W/ BROWN TO WHITE ASH /SILTY MATRIX; CALC CMT; EST VERY POOR INTERGRANULAR POROSITY AND PERM; MTX SHOWS PALE ORANGE- YELLOW FLORO WITH NO CUT. 10310 SANDSTONE = CLEAR TO LT GRAY; PREDOM UNCONSOLIDATED; FINE LOWER TO MEDIUM; MODERATE TO OCC GOOD SORTING; SUBANG TO ROUND; MODERATE SPHR; GRAIN SUPPORTED; NO VIS CMT IN UNCONS SAND; WH TUFF ASH/ LT BRN TUFF SLTST MTX IN PART; EST GOOD POROSITY /PERM; POOR VIS SAMPLE FLORO; SLOW, WEAK, YELLOW -GREEN FLOROSCENT CUT W/ YELLOW -GREEN RESIDUAL RING. 10360 SAND = CLEAR W. OCC LT GRAY; PREDOM UNCONS; VERY FINE UPPER TO COARSE; SUBANG TO PREDOM SUBROUND; MODERATE SPHR; V POOR SORTING; GRAIN SUPPORTED; OCC WH TUFF ASH MTX; EST GOOD POROSITY/ PERM; NO VIS SPL FLORO; SLOW, WK, YEL -GN FLORO CUT W/ YEL -GN RESIDUAL RING. 10400 COAL = BLACK; MOD HARD; SPLINTERY TO PLATY CUTTINGS; CONCHOIDAL TO BLOCKY FRACTURE; SLI RESINOUS LUSTER; IRREGULAR TEXTURE; CARBONACEOUS. 10425 SAND =WHITE TO LT GRAY; PREDOM UNCONS; VERY FINE UPPER TO COARSE; SUBANG TO PREDOM SUBROUND; MODERATE SPHR; MODSRTD; GRAIN SUPPORTED; CLAY /ASH MTX; FAIR POR / PERM. FLUOR; VERY WEAK YELLOW GREEN TO VERY WEAK FAINT YELLOW CUT. 10465 COAL = BLACK; MOD HARD; SPLINTERY TO PLATY CUTTINGS; CONCHOIDAL TO BLOCKY FRACTURE; SLI RESINOUS LUSTER; IRREGULAR TEXTURE; CARBONACEOUS. 10490 SAND =WHITE TO LT GRAY; PREDOM UNCONS; VERY FINE UPPER TO COARSE; SUBANG TO PREDOM SUBROUND; MODERATE SPHR; MODSRTD; GRAIN SUPPORTED; FAIR POR / PERM; NO FLUOR. 10520 TUFFACEOUS CLAYSTONE = LT BROWN TO GRAYISH BROWN; FIRM; SLI PLATY TO MASSIVE; IRREGULAR FRACTURE; SILTY TEXTURE; EARTHY LUSTER; ABUNDANT CARB MATERIAL AND STREAKS. 10550 COAL = BLACK; MOD HARD; PLATY TO FLAKY CUTTINGS; BLOCKY TO SPLINTERY FRACTURE; RESINOUS TO VITREOUS LUSTER; SMOOTH TO ROUGH TEXTURE; INTERBEDDED W /CLAYSTONE. 10575 TUFFACEOUS CLAYSTONE = MEDIUM GRAY TO BROWNISH GRAY; SOFT TO FIRM; MASSIVE TO SLI PLATY CUTTINGS; IRREG FRACTURE; CARBONACEOUS SPECKS AND STREAKS; SILTY TO CLAYEY TEXTURE; INTERBEDDED WITH COAL. • • 10610 TUFFACEOUS SILTSTONE = MEDIUM GRAY TO GRAY BROWN; FIRM TO SLI HARD; SLI PLATY CUTTINGS; IRREGULAR FRACTURE; SILTY TEXTURE; V SLI CALC; CARB MATERIAL. 10635 SANDSTONE = CLEAR TO TRANSLUCENT TO VERY LIGHT GRAY; FINE TO MEDIUM GRAIN; MOD HARD WHERE CEMENTED WITH DOLOMITIC TO WK CALCAREOUS CEMENT; COMMONLY SEEN AS LOOSE GRAINS; SUBROUNDED TO SUBANG- ULAR; MOD SORTED; MOD SPHERICITY; COMMON META - SEDIMENTS; DULL YEL MIN FLUOR; NO VISIBLE POROSITY; NO SHOWS. 10680 TUFFACEOUS CLAYSTONE = LT BROWN TO GRAYISH BROWN; FIRM; SLI PLATY TO MASSIVE; IRREGULAR FRACTURE; SILTY TEXTURE; EARTHY LUSTER; ABUNDANT CARB MATERIAL AND STREAKS. 10725 COAL = BLACK; HARD; SPLINTERY TO PLATY CUTTINGS; CONCHOIDAL TO BLOCKY FRACTURE; SLIGHTLY RESINOUS LUSTER; SMOOTH TO ROUGH TEXTURE; OCC TUFFACEOUS CLAYSTONE LAMINATIONS. 10755 TUFFACEOUS SILTSTONE = MEDIUM GRAY TO BROWNISH GRAY; TOUGH TO CRUMBLY; BLOCKY FRAC; MASS CUTTINGS; EARTHY LUSTER; GRITTY TO OCC CLAYEY TEXTURE; ABNT CARBONACEOUS LAMINAE. 10785 SANDSTONE = CLEAR AND LIGHT GRAY; PREDOM UNCONSOLIDATED GRAINS; VERY FINE UPPER TO BIT FRAC COARSE /PEBBLE; POORLY SORT; V ANGULAR TO OCC SUBROUND; LOW SPHR; OCC WHITE TUFF ASH MTX; V P PORO /PERM. 10815 TUFFACEOUS CLAYSTONE = LIGHT GRAY; SOFT; MUSHY; MASSIVE CUTTINGS; CLAYEY TO RARE SILTY TEXTURE; EARTHY LUSTER; OCCASIONAL CARBONACEOUS MATERIAL AND VOLCANIC SHARDS. 10845 SANDSTONE = LIGHT GRAY; MOD HARD; FINE GRAINED; GRADING TO TUFFACEOUS SILTSTONE • • SUBANGULAR; WELL SORTED; CLAY TO CLAY/ ASH MATRIX; VERY CARBONACEOUS; OCC SOME LT GRAY TO WHITE ASH; VERY DIRTY; NO SAMPLE FLUOR OR CUTS. 10880 COAL = BLACK; MOD HARD TO FIRM; PLATY TO BLOCKY CUTTINGS; SPLINTERY TO CONCHOIDAL FRACTURE; SMOOTH TO ROUGH TEXTURE; SLI RESINOUS LUSTER; W /SOME MINORS AMTS OF CARB SHALE. 10910 TUFFACEOUS SILTSTONE = MEDIUM GRAY TO BROWNISH GRAY; TOUGH TO CRUMBLY; BLOCKY FRAC; MASS CUTTINGS; EARTHY LUSTER; GRITTY TO OCC CLAYEY TEXTURE; ABNT CARBONACEOUS LAMINAE. 10940 SANDSTONE = CLEAR TO TRANSLUCENT /LIGHT GRAY; SOFT; PREDOMINANTLY LOOSE GRAINS; FINE TO MEDIUM GRAIN; MOD WELL SORTED; GRAIN SUPPRTED; MATRIX SEEN AS SOFT, WHITE CLAY GLOBULES; SUBROUNDED TO ANGULAR; NO SHOWS. 10975 COAL = BLACK; MOD HARD TO FIRM; PLATY TO BLOCKY CUTTINGS; SPLINTERY TO CONCHOIDAL FRACTURE; SMOOTH TO ROUGH TEXTURE; SLI RESINOUS LUSTER. 11000 TUFFACEOUS CLAYSTONE = LIGHT GRAY TO GRAYISH BROWN; SOFT TO HARD; MASSIVE TO BLOCKY TO OCC SPLINTERY CUTTINGS; CLAYEY TO ROUGH TEXTURE; EARTHY DULL LUSTER; COMMON THIN LAMINAE; OCC CONTORTED; COM FINE DISSEMINATED CARBONACEOUS MATERIAL. 11035 SANDSTONE = LT RED BROWN TO TAN; UNCONS AND VERY HARD; VERY FINE TO BIT FRAC COARSE AND PEBBLE SIZE; POORLY SORTED; SUBROUND TO PREDOMINANTLY SUBANGULAR AND ANGULAR; LOW SPHERICITY; NO VIS CMT; GRAIN SUPPORTED; TUFF ASH MTX IN PART; 70% QTARTZ, 10% DARK MINERALS, 10% CARB MATERIAL, 10% QUARZITE; CONSOLIDATED SANDSTONE APPEARS AS GNEISSIC ROCKS. • • 11100 CARBONACEOUS SHALE = BROWNISH BLACK; HARD; TOUGH TO BRITTLE IN PART; BLOCKY TO PLANAR FRACTURE; MASSIVE TO PLATY CUTTINGS; EARTHY TO VITREOUS TO SPARKLY LUSTER; GRITTY TO SMOOTH TO OCC SILTY TEXTURE; COMMONLY APPEARS SHISTOSE; COMMON CHLORTN AND BIOTITN; OCC PYRITE SAMPLE SHOWS MINERAL ALTERATION AND RECRYSTALIZATION; EVIDENT SHEARING. 11150 SANDSTONE = WH & LT RED -BRN TO TAN; HARD TO V HARD; OF TO CRS AND CRS GRANULAR AND MASSIVE; PRLY SRTD; ANG TO SBRND; LOW SPHR; NO VIS CMT; INTERSTICES FILLED W/ META MINS; SHISTOSE AND GNIESSIC FISSILITY; COM MICA; COM REXLTN 11185 SANDSTONE = PREDOM LOOSE GRAINS; LT GRAY; PRESERVED PIECES SLI HARD; LOWER MEDIUM TO FINE GRAINED; SUBANGULAR TO SUBROUNDED; MOD WELL SORTED; LOW TO MODERATE SPHERICITY; ABNT MICA; MATRIX SUPPORTED; SILICEOUS W/TRACE TO MOD I I AMOUNTS OF WHITE CLAY(MATRIX MATERIAL) IN SAMPLES; 90% QUARTZ; 10% CHERT TO META FRAGMENTS; OCC SCATTERED CARB MATERIAL; EST GOOD POROSITY AND PERM; NO SAMPLE SHOWS. 11245 TUFFACEOUS CLAYSTONE = MEDIUM TO LIGHT GRAY; SOFT TO FIRM; MASSIVE TO SLI PLATY IRREGULAR FRACTURE; EARTHY LUSTER; SLI SILTY TO GRITTY TEXTURE; OCC SOME SCATTERED CARBONACEOUS MATERIAL; OCC VERY SILTY. 11280 COAL = BLACK; MOD HARD TO FIRM; PLATY TO BLOCKY CUTTINGS; SPLINTERY TO CONCHOIDAL FRACTURE; SMOOTH TO ROUGH TEXTURE; SLI RESINOUS LUSTER; W /SOME MINORS AMTS OF CARB SHALE. 11325 SANDSTONE = WHITE AND LIGHT TO RED - BROWN; VERY HARD AND UNCONS IP; LOWER FINE TO COARSE; MASSIVE AND GRANULAR IN PART; POORLY SORTED; VERY • • LOW SPHERICITY;COMMONLY RECRYSTALLIZED QUARTZ GRAINS; NO VISIBLE CEMENT; INTERSTICES FILLED WITH METAMORPHIC MINERALS, CHLORITE, BOITITE, MUSCOVITE, HORNBLENDE, TOURMALINE, ECT; NO VISIBLE POROSITY, MATRIX FLUORESCES PALE YELLOW; GNEISSIC FABRICATED; NO CUT. 11385 COAUCARBONACEOUS SHALE = BLACK AND DARK BROWN; HARD TO BRITTLE; BLOCKY TO PLANAR FRACTURE; MASSIVE TO PLATY CTGS; SPARKLY TO VITREOUS LUSTER; SCHISTOSE; COMMON METAMORPHIC MINERALS, MICA, PYRITE, OCC HORNBLENDE. 11420 CARBONACEOUS SHALE = LT GRAY TO TAN; STIFF TO BRITTLE; SPLINTERY TO BLKY FRAC FLAKY ELONGATE CUTTINGS; EARTHY TO WAXY LUSTER; SMOOTH TEXTURE; FISSILE; VERY UNIFORM; HYDROPHILLIC. 11450 SANDSTONE = LIGHT GRAY; OCC LT TAN PREDOM LOOSE GRAINS; FINE GRAINED; WELL SORTED; SUBANGULAR TO SUBROUNDED; MOD SPHERICITY; SILICEOUS TO WHITE CLAY MATRIX MATERIAL; OCC THIN BLACK CARB STREAKS; OCC THIN MICA STREAKS; INTERBEDDED WITH COALY\CARBONACEOUS BEDS; NO SHOWS. 11495 CONGLOMERATE AT 11515 = PREDOM LOOSE GRAINS; SOME BIT IMPACTED GRAINS; CLAST SIZE RANGES FROM PEBBLE TO FINE GRAINED; POORLY SORTED; LOW TO MODERATE SPER; ANGULAR TO SUBROUNDED; ABUNDANT CALCITE CEMENT; 50% QUARTZ; 20% CHERT; 30% LITHICS; CHERT RANGES FROM JASPER TO DARK GRAY IN COLOR; ABUNDANT DULL YELLOW FLUORESCENCE /CALCITE MINERAL FLUORESCENCE; NO CUTS. 11550 CONGLOMERATE = LOOSE GRAINS; NO MATRIX PRESERVED; CLAST SIZE RANGES FROM PEBBLE TO FINE GRAINED; RARE MEDIUM GRAINS ADHERING TO PEBBLE FRAGS W /SILI CEMENT; POORLY SORTED; ANGULAR TO SUBROUNDED; • ABNT CALCITE FRAGMENTS(POSS MATRIX); 60% QUARTZ; 20% CALCITE; 20% LITHICS; 20% DULL YELLOW MINERAL FLUORESCENCE (CALCITE) NO CUTS. 11600 SANDSTONE = CLEAR TO LIGHT GRAY; FINE LOWER TO BIT FRACTURED COARSE AND PEBBLE GRAINS; PREDOMINANTLY ANGULAR TO SUBANG WITH OCC SUBROUND; LOW SPHERICITY; POORLY SORTED; OCCURS PREDOMINANTLY AS UNCONSOLIDATED GRAINS; NO VISIBLE CEMENT OR MATRIX MATERIAL; 70% QUARTZ; 20% QUARTZITE; 10% LITHIC FRAGMENTS AND METAMORPHIC MINERALS; ESTIMATED VERY POOR TO POOR INTERGRANULAR POROSITY; NO VISIBLE FLUORESCENCE OR CUT. 11660 SANDSTONE /CONGLOMERATE = CLEAR TO LIGHT GRAY; FINE LOWER TO BIT FRACTURED COARSE AND PEBBLE SIZE CLASTS; VERY ANGULAR TO OCCASIONAL SUBROUND; LOW SPHERICITY; POORLY SORTED; PREDOMINANTLY FRESH FRACTURED TO PITTED TO OCCASIONAL FROST SURFACE TEXTURE; NO VISIBLE CEMENT; PRED UNCONSOLIDATED GRAINS; NO VISIBLE MATRIX COMMON METAMORPHIC MINERALS; NO SHOWS, FLUORESCENCE, OR CUT. 11715 SANDSTONE = PREDOM LOOSE GRAINS; TR TO <10% SANDSTONE FRAGS; LIGHT GRAY; ABNT CLEAR TO TRANSLUCENT GRAINS; LOWER MED TO FINE GRAINED; ANGULAR TO SUBROUNDED; MOD WELL SORTED; MATRIX SUPPORTED; WHITE CLAY MATRIX TO CALC; MINOR DULL YELLOW FLUORESCENCE; NO CUTS. 11755 CONGLOMERATE = PREDOM LOOSE GRAINS; SOME LT GRAY SS SPECKLED BLACK WITH LITHICS; CLAST SIZE FROM PEBBLE TO LOWER MEDIUM GRAINED; ANGULAR TO SUBROUNDED; PRLY SORTED; GRAIN SUPPORTED WITH SILICEOUS CEMENT; OCC SOME WHITE CLAY ADHERING TO LITHIC FRAGS; ABNT CHLORITE; 60% QTZ, 40% LITHIC FRAGMENTS; OCC BRN TO GREEN MICA FLAKES IN MATRIX; INCR LOOSE WHITE CLAY(MATRIX MATERIAL) AT 11820; NO • i SAMPLE FLUOR TO RARE DULL YELLOW CALCITE MINERAL FLUORESCENCE; NO CUTS. 11835 SANDSTONE = PREDOM LOOSE GRAINS; TR TO <10% SANDSTONE FRAGS; LIGHT GRAY; ABNT CLEAR TO TRANSLUCENT GRAINS; LOWER MED TO FINE GRAINED; ANGULAR TO SUBROUNDED; MOD WELL SORTED; MATRIX SUPPORTED; WHITE CLAY MATRIX TO CALC; MINOR DULL YELLOW FLUORESCENCE; NO CUTS. 11875 COAL = BLACK, OCC DARK BROWNISH BLACK; FIRM TO MOD HARD; BRITTLE, MOD TOUGH; SLI RESINOUS LUSTER; SMOOTH TO V SLI ROUGH SURFACE TEXTURE; SPLINTERY, PLATY, BLOCKY CTGS; COM CONCH FRAC SURFACE. 11910 SANDSTONE = CLEAR TO TRANSLUCENT /LIGHT GRAY; SOFT; PREDOMINANTLY LOOSE GRAINS; FINE TO MEDIUM GRAINED; MOD WELL SORTED; GRAIN SUPPORTED; LOCAL PRESERVED WHITE CLAY MATRIX; SUBROUNDED TO SUBANGULAR; NO SHOWS. 11945 CONGLOMERATIC SANDSTONE = CLEAR AND LIGHT GRAY; FINE LOWER TO COARSE AND PEBBLE SIZE GRAINS; VERY ANGULAR TO OCCASIONAL SUBROUND; LOW SHPERICITY; POORLY SORTED; MAJORITY OF GRAINS HAVE FRESH FRACTURED SURFACES; PREDOMINANTLY UNCONSOLIDATED GRAINS; NO VISIBLE CMT; NO VISIBLE MATRIX MATERIAL; COMMON META MINERALS; 70% QUARTZ, 20% QUARTZITE; 10% LITHIC FRAGMENTS AND META MINERALS; ESTIMATED POOR TO MODERATE PORO;RARE PRESERVED SPECIMENS (W /MATRIX INTACT) EXHIBIT EVEN LIGHT BROWN OIL STAINING W /BRI YELLOW OIL FLUOR; CUTS FROM THE ABOVE ARE SLO STRMG W/ LT BROWN OIL RING 12025 CARBONACEOUS SHALE /COAL = MEDIUN TO DARK BROWN TO BLACK; BRITTLE TO CRUMBLY; PLANAR AND IRREGULAR FRACTURE; MASSIVE TO PLATY CUTTINGS; EARTHY TO VITREOUS LUSTER;SMOOTH AND GRITTY TEXTURE; CARB • • MAT APPEARS AS V THIN LAMINAE. 12060 SANDSTONE = CLEAR TO LIGHT GRAY; VERY FINE UPPER TO MEDIUM UPPER; SUBANGULAR TO SUBROUND; MODERATLY SORTED; LOW TO MODERATE SPHERICITY; NO VISIBLE CEMENT; ASH MATRIX DECREASING FROM 12035; ESTIMATED POOR INCREASING TO GOOD POROSITY; DULL YELLOW - ORANGE FLORO; WEAK TO MODERATE YELLOW FLUORESCENT CUT; 12105 TUFFACEOUS CLAYSTONE = WHITE TO BIEGE; PLIABLE; SOFT; BLOCKY TO IRREGULAR FRACTURE; MASSIVE CUTTINGS; DULL EARTHY LUSTER; MATTE TEXTURE; OCCASIONAL VISIBLE GLASS SCARDS. 12135 CONGLOMERATIC SANDSTONE = WH TO LT GY HARD; FINE TO CRS W/ PEBBLE; PR SORT; LOW SHPR; ANG TO OCC SUBRD; PREDOM FRESH FRACT SURF TEX; SIL CMT; GRNS APPEAR WELDED /REXLZED; EST VERY PR PORO; NO VIS FLORO; QUESTIONABLE CUT - W/TR FREE OIL - PROBABLE CVGS FROM ABOVE 12175 SANDSTONE = ABUNDANT LOOSE GRAINS; LIGHT GRAY; LAMINATED WITH THIN BLACK COALY STREAKS; LOOSE GRAINS ARE UPPER COARSE TO FINE GRAINED; PRESERVED PIECES ARE MEDIUM TO FINE GRAINED; MOD SORTED; SUBANGULAR TO SUBROUNDED; MOD SPHER; PRESERVED MATRIX EXHIBITED SILT TO CALC CEMENT; GRAIN SUPPORTED W /ABNT CARB MAT; 10% DULL YELLOW MNRL FLOR FROM CALCITE; NO SAMPLE SHOWS OR OIL FLUOR. 12230 SANDSTONE = LT GRAY TO LT GREENISH GRAY; MOD HARD; UPPER MEDIUM TO FINE GRAINED; ANGULAR TO SUBANGULAR; MOD WELL SORTED; LOW SPHER; GRAIN TO MATRIX SUPPORTED; V SILICEOUS; SOME GREEN GRAINS; TRACE AMTS OF BRICK RED VOL SPECKS; POOR TO TIGHT EST POR AND PERM; NO SAMPLE SHOWS W /CLAYSTONES AND VERY THIN COALS. 12275 CLAYSTONE = VERY LIGHT GRAY; SOFT; • MASSIVE CUTTINGS; IRREG FRAC; DULL LUSTER; SMOOTH TEXTURE; OCC SILTY TO SANDY; SLI CALCAREOUS; INTBD W/ TUFFACEOUS SILTSTONE AND TT SS. 12305 NOTE: TOTAL DEPTH OF 12300 WAS REACHED ON 12/3/2000 I r II [11 EPOCH • RIG ACTIVITIES Forcenergy, Inc. Kustatan Forcenergy #1 Kenai Borough, Alaska 10/16/2000 Spud well; drill from 51' to 96'; pull out of hole; pick up heavy weight drill and standard drill pipe. 10/17/2000 Drill ahead 17.5" hole. 10/18/2000 Drill to 1116'. Trip for Bit #2. Trip in and resume drilling. 10/19/2000 Drill to 1800'. 10/20/2000 Drill to casing point at 1820'. Ran 13 3/8" casing. Hit boulders at 200 ft. Pull out of hole and remove centralizers. Ran casing back in. Hole was tight and had to pump down to 600 ft. Prepare to cement casing. 10/21/2000 Cement 13 3/8" casing. Nipple up BOP's. Drilling mud diluted with water pumped from cellars. 10/22/2000 Continue to nipple up BOP's. 10/23/2000 Continue to nipple up. Test casing to 3000psi. 10/24/2000 Drilled cement and shoe. Ran FIT test to 11.0 ppg equivalent mud weight. Resume drilling formation. 10/25/2000 Drilling ahead to 3000'. Encountered some tight hole and swabbing at 2200 -2300 ft. 10/26/2000 Pumped high viscosity sweep and short tripped at 3168'. Drill ahead to 3700' 10/27/2000 Drill to 4265'. Trip out of hole for new bit #4. Circulate bottoms up after trip. Flowline plugged with clay after bottom's up. Clean flowline. 10/28/2000 Drilling ahead. Pump sweeps while drilling. Drill to 4450'. Running centrifuge to decrease mud weight. 10/29/2000 Drill to 4817'. Pull out of hole for plugged bit. Bit was plugged with rubber. Staged into hole at the I shoe and at 3000' to prevent flowline plugging. 10/30/2000 Drilling from 5081' to 5421'. Rate of penetration decreased through this section. 10/31/2000 Drilled from 5421' to 5515'. Rate of penetration decreasing. Pull out of hole for new bit. Test BOP'S. Pick up 7 joints of heavyweight drill pipe and trip into hole. 11/1/2000 Finish tripping into hole. Wash and ream from 5500' to 5547'. Drill from 5547' to 5879'. Pump high velocity sweep around. Run deviation survey. Drill from 5879' to 6136'. Drilling numerous coals. 11/2/2000 Drill to casing point at 6500'. Circulate sweep around. Short trip 10 stands. Pull out of hole. Begin running wireline Togs. 11/3/2000 Run wireline logs. Rig up and run 9.625" casing. Run to TD with no problems. Circulate and condition hole for cement. 11/4/2000 Cement casing. Nipple up BOP's. Test BOP's. 11/5/2000 Finish testing BOP's. Install drip pans. Lay down BHA. Pick up BHA for 8.5" hole and run in hole to allow room to change Canrig top drive to Tesco. Rig down Canrig. 11/6/2000 Rig down Canrig top drive. Begin installing Tesco top drive. 11/7/2000 Rig up Tesco top drive. 11/8/2000 Finish rigging up top drive. Test casing to 3000psi. Drill out cement. Circulate and condition mud prior to FIT. Run FIT to 10.5 ppg equivalent mud weight. Resume drilling. Drill to 6580'. 11/9/2000 Drill to 6709'. Run deviation survey. Survey was 2.5 degrees. Drill from 6709' to 6900'. 11/10/2000 Drill from 6933' to 7024'. Drop 3 inclination surveys with no results. Wireline broke on third try. Pull out of hole to 5520' to retrive. Run in hole and drill to 7111' 11/11/2000 Drill from 7111' to 7233'. Run deviation survey @ 7213'. Pull out of hole for new bit. Put on mudmotor and PDC bit and run in hole. 11/12/2000 Continue running in hole with new BHA. Drill from 7212' to 7560'. • • 11/13/2000 Drilling from 7595' to 7775'. Run wireline deviation survey. Survey was 3.25 degrees inclination. Drill from 7775' to 7844'. 11/14/2000 Drill to from 7844' to 8100'. 11/15/2000 Drill to 8273'. Run wireline survey. Pull 10 stand short trip.Drill to 8450' 11/16/2000 Drill slowly ahead to 8573' 11/17/2000 Trip for new bit at 8573'. Test BOP's. Trip in and resume drilling. Drill to 8600' 11/18/2000 Drilling ahead to 9070'. 11/19/2000 Drilling ahead to 9460'. 11/20/2000 Drilling ahead to 9670' 11/21/2000 Drilling ahead. Short trip at 9655'. Drill to 9920'. 11/22/2000 Drilling ahead to 9983'. Pull out of hole for new bit. Working on rig high clutch. 11/23/2000 Continue trip into hole with new bit. No fill on trip. 11/24/2000 Trip into hole. Resume drilling. Drill to 10530'. 11/25/2000 Drill to 10574'. Circulation bottoms up and short trip at 10574'. Resume drilling. 11/26/2000 Drill to 10809'. Circulate bottoms up. Trip for bit. Test BOP's. Trip in and resume drilling. Drill to 10860'. 11/27/2000 Drill ahead. Drill to 11200'. 11/28/2000 Drilling ahead. Pump high velocity sweep. Drill ti 11200' and circulate sweep. Short trip to 10594' without problems. Drill ahead to 11470'. 11/29/2000 Drill to 11598'..Start to come out of hole for new bit. Trip up to shoe. Repair clutch. • • 11/30/2000 Wait on parts and repair clutch. Trip out of hole for new bit. 12/1/2000 Trip in with new BHA. Trip in hole to 8443'. Fill pipe and circulate bottoms up. Trip in hole to TD. Wash bottom and break in bit. Resume drilling. Drill to 11740' 12/2/2000 Take inclination survey at 11812'. Resume drilling. Drill to 12170' 12/3/2000 Drill to TD of 12300' at 9:30am. Circulate bottoms up. Condition hole. Pull out of hole for logging run. Logging operations. 12/4/2000 Run logging operations. • • EPOCH RIG HOURS FORCENERGY KUSTATAN FORCENERGY #1 U' 0 CO > 0 I w v ,� � a =, J � z v � Q � � a ¢ z �_ a 1- w Q I m D - E w w w D c� a 0 = CO I- O 0 CO 0 co U I- co cc ec Ir E 2 0 co I- 0 1- 10/16/00 3.00 21.00 24.00 10/17/00 11.50 9.50 0.50 1.50 r 1.00 ' 24.00 10/18/00 23.00 0.50 0.50 24.00 10/19/00 4.00 14.00 1.00 1.50 2.50 1.00 24.00 10/20/00 1.00 5.00 1.50 2.00 9.00 5.00 0.50 24.00 10/21/00 0.50 1.50 21.50 0.50 24.00 10/22/00 1.50 8.50 13.50 0.50 24.00 10/23/00 21.00 3.00 24.0U 10/24/00 3.00 1.50 5.00 4.50 1.50 4.50 2.50 1.00 0.50 24.00 10/25/00 15.50 1.00 2.00 5.00 0.50 24.00 10/26/00 11.56 0.50 1.50 8.50 1.00 1.00 24.00 10/27/00 17.50 2.001 3.50 1.00 24.00 10/28/00 2.00 0.50 1.00 12.00 1.00 7.50 24.00 10/29/00 16.50 1.00 4.50 1.50 0.50 24.00 10/30/00 6.00 8.50 1.00 3.00 4.50 1.00 24.00 10/31/00 17.50 1.50 0.50 4.50 24.00 11/1/00 1.50 5.00 3.50 8.50 1.00 1.50 3.00 24.0U 11/2/00 22.06 1.00 1.00 I 24.00 11/3/00 1.50 8.00 1.00 5.50 5.50 2.00 0.50 24.00 11/4/00 2.00 _ 13.50 4.50 3.00 1.00 24.00 11/5/00 ' 2.00 1.00 17.00 4.00 24.00 11/6/00 7.00 2.00 4.00 10.50 i 0.50 24.00 11/7/00 23.50 0.50 24.00 11/8/00 0.50 22.00 1.00 0.50 24.00 11/9/00 13.00 5.00 '2.50 2.50 1.00 24.0U 11/10/00 21.50 1.50 0.50 0.50 24.00 11/11/00 14.50 2.50 0.50 4.00 1.5d 0.56 0.50 24.0U 11/12/00 2.50 8.50 0.50 1.00 8.00 3.50 24.00 11/13/00 22.00 1.50 0.50 24.011 11/14/00 21.50 2.00 0.50 24.00 11/15/00 18.50 2.00 0.50 2.00 1.06 24.0U 11/16/00 _ 23.50 0.56 24.00 11/17/00 1.00 3.00 0.50 0.50 6.50 6.00 6.50 24.00 11/18/00 23.50 0.50 24.00 11/19/00 23.50 0.50 24.00 11/20/00 23.00 0.50 0.50 24.011 11/21/00 19.00 0.50 0.50 3.00 1.06 24.00 11/22/00 23.50 0.50 24.011 • • 11/23/00 10.00 0.50 1.00 4.00 0.50 7.50 0.50 24.00 11/24/00 6.00 3.50 12.50 0.50 0.50 1.00 ' 24. Ud 11/25/00 22.00 0.50 0.50 1.00 24.00 11/26/00 1.50 11.00 0.50 0.50 6.50 0.50 3.50 24.00 11/27/00 1.50 11.00 7.00 0.50 3.00 1.00 ' 24.00 11/28/00 22.50 0.50 0.50 0.50 24.00 11/29/00 23.50 0.50 24.00 11/30/00 0.50 2.00 5.00 16.00 0.50 24.00 12/1/00 1.50 0.50 8.00 14.00 24.00 12/2/00 13.00 0.50 3.00 3.50 4.00 24.00 12/3/00 24.00 24.00 12/4/00 0.50 3.50 0.50 2.50 9.50 7.50 24.00 0 U Z O .' J d I - W 0 0 Z = I- W U C a J J Z U W J > U a > Q D W d IC-6 W = R D IX E W W W D o - a 0 a Zi I- Ott 0 u) U 1- U) r4 fx w Ei 2 O (/) 1- o 0 0 O 0 0 0 0 0 o O o 0 o O o 0 0 O 0 0 to o 0 to to to to o o to o to 0 N M N: o f CO O N. N O 4 4 Lt) � N IL() N 1() A- N- CO x- 1L) (0 .- t() _ 14) N CO Rig Utilization 700.00 600.00 580.00 • x.. ® BHA 500.00 — • DRILL 0 SURVEY ID CIRCULATE ei ■ TRIP 400.00 ® SERVICE RIG ■REPAIR RIG ❑ REAM 300.00 — • RUN & CMT CSG ■ WIRELINE LOG ❑ NIPPLE UP - -DOWN ❑ SLIP /CUT 200.00 — — •TEST 149.00 •OTHER • 100.00 a 57.00 67.50 52.00 50.50 51.50 23.50 25.50 37.00 10.50 . 12.50 14.00 5.50 0.00 .: 1 RIG UTILIZATION 0 %2o 3% 4% 4% 1% � • ■ BHA • DRILL ❑ SURVEY 4% ❑ CIRCULATE 1% ■TRIP SERVICE RIG • REPAIR RIG 6% ❑REAM • RUN & CMT CSG 1% • RIG UP /DOWN l lipr 49% '❑WIRELINE LOG ® NIPPLE UP - -DOWN ■ SLIP /CUT • 13 ■TEST ■ OTHER 1 5% 2% FORCENERGY KUSTATAN FORCENERGY #1 DRILLING PROGRESS o I I I , I TI I 1 i V I Cr) tC) N- O) - C) U) N- d) c- CO IC) N- 0) e- M IC) N- 6) - CO U) N- O) r r T- N N N (N N C) CO M C) M t7 V V - 2000 • - 4000 - 6000 m o - 8000 — -10000 -- • -12000 — -14000 Days FORCENERGY KUSTATAN FORCENERGY #1 DAILY MUD REPORTS e EPOCH DATE DEPTH MW VIS PV YP GELS FL FILTER SOLIDS SAND pH CI- OIL ppg CAKE % % ppm % 10/17/00 315' 9.0 75 11 31 32/35/36 5 0.50 8.0 200 0 10/18/00 997' 9.0 67 17 19 15/28/38 5 0.25 8.0 500 0 10/19/00 1549' 9.1 72 18 28 24/38/55 5 0.25 8.0 500 0 10/20/00 1820' 9.3 65 13 15 13/19/25 7 0.25 8.0 500 0 10/21/00 1820' 9.2 65 13 15 13/19/25 7 0.25 8.0 500 0 . 10/22/00 1820' 9.0 48 18 15 4/10/15 5 0.25 8.0 500 0 10/23/00 1820' 8.9 48 18 15 4/10/15 5 0.25 8.0 500 0 10/24/00 1820' 9.0 45 12 6 2/4/6 5 0.25 8.0 500 0 10/25/00 2749' 9.2 45 19 9 4/12/22 6 0.25 10.0 500 0 10/26/00 3408' 9.2 53 21 15 4/12/32 6 0.25 10.0 500 0 10/27/00 4265' 9.4 54 20 14 5/20/50 7 0.25 9.0 500 0 10/28/00 4267' 9.3 60 26 18 5/20/55 7 0.25 9.0 500 0 10/29/00 4457' 9.5 52 20 14 6/28/50 8 0.25 8.5 500 0 10/30/00 5081' 9.5 48 15 15 8/30/55 8 0.25 8.0 500 0 10/31/00 5421' 9.3 67 14 28 15/54/78 10.0 3 7 0.25 8.4 600 0 11/1/00 5547' 9.3 72 14 33 12/45/62 10.8 2 6.5 TR 8.0 600 0% 11/2/00 6136' 9.3 52 18 22 9/36/38 10.4 3 6.5 0.25 9.0 600 TR 11/3/00 6500' 9.3 56 18 24 11/37/43 10.0 3 7.2 0.50 9.0 600 TR 11/4/00 6500' 9.3 74 17 28 16/42/49 9.6 3 7.2 0.25 8.5 600 TR 11/5/00 6500' 9.4 72 17 29 17/44/52 9.6 3 8 0.25 8.0 600 TR 11/6/00 6500' 9.3 45 9 12 11/44/62 11.8 3 6.8 0.25 7.8 600 TR • 11/7/00 6500' 9.2 46 9 13 11/44/61 11.6 3.5 6.5 0.00 7.8 600 0% 11/8/00 6500' 9.2 46 9 13 14/44/61 11.6 3.5 6.5 0.00 7.8 600 0% 11/9/00 6643' 9.3 50 10 18 10/25/38 11.2 2 6.5 0.50 9.8 600 0% 11/10/00 6933' 9.40 43 10 20 8/18/30 9.0 2 8 0.25 9.5 600 0% 11/11/00 7111' 9.2 45 10 22 8/17/26 7.8 .15 6.5 0.00 8.8 600 0% 11/12/00 7213' 9.4 45 12 22 8/22/30 7.6 2 8 0.25 8.5 600 0% 11/13/00 7595' 9.4 44 12 20 8/21/28 7.6 2 8 0.25 8.5 600 0% 11/14/00 7915' 9.4 45 14 18 8/31/37 8.4 2 8 0.00 9.0 600 0% 11/15/00 8300' 9.3 44 13 12 6/20/30 9.0 2 8 0.00 9.0 600 0% 11/16/00 8573' 9.3 58 15 15 9/26/28 9.6 2 7 0.00 9.0 600 0% 11/17/00 8572' 9.3 58 15 15 9/26/28 9.6 2 7 0.00 9.0 600 0% FORCENERGY E cH KUSTATAN FORCENERGY #1 DAILY MUD REPORTS Li po DATE DEPTH MW VIS PV YP GELS FL FILTER SOLIDS SAND pH CI- OIL ppg CAKE % % ppm % 11/18/00 8657' 9.3 46 10 17 12/25/30 9.4 2 7 0.00 9.0 600 0% 11/19/00 9122' 9.3 45 10 15 12/45/58 9.0 3 7 0.00 9.0 600 0% 11/20/00 9521' 9.3 44 9 16 10/42/45 10.0 2 7 0.00 9.0 600 0% 11/21/00 9720' 9.3 45 9 19 15/40/45 10.2 2 7 0.00 9.5 600 0% 11/22/00 9963' 9.2 45 11 19 18/60/63 10.2 2 7 0.00 9.0 600 0% 11/23/00 9983' 9.1 45 9 19 15/40/45 10.2 2 6 0.00 9.0 600 0% 11/24/00 10014' 9.3 46 10 19 14/38/45 10.2 2 7 0.00 9.0 600 0% 11/25/00 10574' 9.3 47 10 16 15/44/50 10.0 2 7 0.00 9.0 600 0% • 11/26/00 10809' 9.3 47 10 18 14/43/48 11.0 3 7 0.00 9.5 600 0% 11/27/00 10885' 9.2 44 9 17 14/40/41 10.2 3 7 0.00 9.5 600 0% 11/28/00 11270' 9.2 43 10 18 14/42/45 10.8 3 7 0.00 9.5 600 0% 11/29/00 11490' 9.3 43 10 18 10/42/52 9.4 3 7 0.20 9.5 600 0% 11/30/00 11598' 9.5 55 12 18 10/28/45 7.5 2 8 0.20 9.5 600 0% 12/1 /00 11598' 9.5 46 10 12 6/17/22 8.6 2 8 0.25 9.5 700 TR 12/2/00 11821' 9.5 45 11 20 9/25/28 9.0 2 8 0.20 9.1 700 TR 12/3/00 12210' 9.4 43 9 17 8/18/24 8.2 2 7.5 0.20 9.0 700 TR 12/4/00 12300 9.2 48 11 24 10/18/25 8 2 6.5 0.20 9.2 700 TR • BIT RECORD 1 g FORCENERGY BIT GRADING I O D L G O W N U U O A T H KUSTATAN FORCENERGY #1 N T L C U H Y E E L A G E R R T E R P C I U R R H 0 C L O O A N H L JETS TOTAL AVG W W R A E BIT SERIAL SIZE (In 32nds) DEPTH DEPTH FEET BIT AVG AVG AVG PUMP S S R D NUMBER NUMBER INCHES MAKE TYPE 1 2 3 4 IN POOH DRILLED HOURS FT /HR WOB RPM PSI 1 LR6109 17.5 STC MSDGHCPS 16 16 16 12 51 1116 1065 32.5 37 3.8 60 685 5 4 ER NM E IN WT PR 2 LP2576 17.5 STC MEDSSH 18 18 18 12 1116 1820 704 13.25 53 13 96 1464 3 4 WT ALL E 1/4 CT TD 3 LW5238 12.25 STC FGS+ 15 15 18 10 1820 4265 2445 39.5 82 28 98 1422 4 5 WT ALL AE 1/8 ER PR 4 JR7513 12.25 GEO PDC 11 11 11 11 4265 4817 552 14.89 37 10 95 1910 6 8 BT ALL X IN ER PP 5 LW584 12.25 STC FGS+ 12 12 16 14 4817 5547 730 25.26 29 30 102 2394 4 4 WT ALL E 1/16 SS PR 6 LR0135 12.25 STC MO5S OD /CL 12 12 12 14 5547 6500 953 26.85 36 32 100 2797 2 2 BT M E IN NO TD 7 LW3152 8.5 STC 15MFDGPS 12 12 13 13 6500 7233 733 54 14 24 65 2505 2 2 CT G R IN ER HR 8 H42928 8.5 HTC DS75H 14 14 14 14 7233 8573 1340 60 22 8 51 2294 7 8 RO 1ITE NA IN OC PR 9 21321 8.5 HTC DS7OFNPV 14 14 14 14 8573 9983 1410 82.75 17 8 47 2524 NOT GRADED 10 E46DE 8.5 HTC MXR 18DD 18 18 16 9983 10806 823 56.75 15 26 61 3040 5 7 BT ALL E IN EC PR 11 L8420D87 8.5 HTC MX20DX 18 18 16 10809 11598 789 51.07 16 27 58 3055 3 4 BT MG E IN WT HR 12 LW5897 8.5 STC 20MFDGPS 18 18 16 11598 12300 702 36.88 19 26 59 3110 4 7 5 ALL E 3/16 ER TD 0
