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Home My WebLink About203-150New Plugback Esets 6/21/2024 Well Name API Number PTD Number ESet Number Date Kaladachabuna 2 PB1 50-283-20169-70-00 212-157 T38946 5-3-2013 Kaladachabuna 2 PB2 50-283-20169-71-00 212-157 T38947 5-3-2013 Kaladachabuna 2 PB3 50-283-20169-72-00 212-157 T38948 5-3-2013 Kaladachabuna 2 PB4 50-283-20169-73-00 212-157 T38949 5-3-2013 ODSN-18 PB1 50-703-20624-70-00 210-142 T38950 2-18-2011 ODSN-18 PB2 50-703-20624-71-00 210-142 T38951 2-18-2011 ODSN-18 PB3 50-703-20624-72-00 210-142 T38952 2-18-2011 ODSN-18 PB4 50-703-20624-73-00 210-142 T38953 2-18-2011 ODSN-18 PB5 50-703-20624-74-00 210-142 T38954 2-18-2011 ODSN-24 PB1 50-703-20662-70-00 212-178 T38955 6-13-2013 ODSN-24 PB2 50-703-20662-71-00 212-178 T38956 6-13-2013 PBU 18-27E PB2 50-029-22321-72-00 212-131 T38957 2-12-2013 PBU 18-27E PH 50-029-22321-71-00 212-131 T38958 2-12-2013 Redoubt Unit 7 PB1 50-733-20526-70-00 203-150 T38959 10-22-2003 SP18-N05 PB1 50-629-23453-70-00 211-101 T38960 7-11-2016 3K-103 PB1 50-029-23392-70-00 208-115 T38961 2-3-2009 3K-103 PB2 50-029-23392-71-00 208-115 T38962 2-3-2009 3K-103 PB3 50-029-23392-72-00 208-115 T38963 2-3-2009 3K-103 PB4 50-029-23392-73-00 208-115 T38964 2-3-2009 3K-103 PB5 50-029-23392-74-00 208-115 T38965 2-3-2009 ODSN-25 PB1 50-703-20656-70-00 212-030 T38966 8-11-2012 ODSN-25 PB2 50-703-20656-71-00 212-030 T38967 8-11-2012 ODSN-25 PB3 50-703-20656-72-00 212-030 T38968 8-11-2012 ODSN-25 PB4 50-703-20656-73-00 212-030 T38969 8-11-2012 Redoubt Unit 7 PB1 50-733-20526-70-00 203-150 T38959 10-22-2003 • i STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: Oil ❑ Gas❑ SPLUG ❑ Other ❑ Abandoned 2 Suspended I=1 lb.Well Class: 20AAC 25.105 20AAC 25.110 Development Q Exploratory ❑ GINJ ❑ WINJ ❑ WAGE] WDSPL❑ No.of Completions: 2�4 o Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6.Date Comp.,Susp.,or 14.Permit to Drill Number/ Sundry: COOK INLET ENERGY LLC Aband.: -12.441;11"4 hp 203-150/314-646 " 3.Address: 7.Date Spudded: 15.API Number: 601 W 5TH AVE,SUITE 310,ANCHORAGE,AK 99501 9/7/2003 50-733-20526-00-00 4a.Location of Well(Governmental Section): 8.Date TD Reached: 16.Well Name and Number: Surface: 1967'FSL,223'FEL,Sec. 14,T7N,R14W,SM 12/4/2003 REDOUBT UNIT#7 Top of Productive Interval: 9.Ref Elevations: KB: 90'MSL 17.Field/Pool(s): 1483'FNL, 1667'FWL,Sec. 19,T7N,R13W,SM GL: N/A BF: N/A REDOUBT SHOAL UNDEFINED 011- Total Depth: 10.Plug Back Depth MD/TVD: 18.Property Designation: 2037'FNL,2024'FEL,Sec. 19,T7N, R13W,SM 12618'MD/10385'TVD • ADL 381203 and 374002 4b. Location of Well(State Base Plane Coordinates,NAD 27): 11.Total Depth MD/TVD: 19.Land Use Permit: Surface: x- 200675.2 y- 2449982.2 Zone- 4 15950ft MD/12332ft TVD • N/A TPI: x- 207845.5 y- 2446532.5 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 209214.2 y- 2445978.6 Zone- 4 N/A N/A 5.Directional or Inclination Survey: Yes ❑(attached) No ❑✓ 1 13.Water Depth,if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 45 (ft MSL) 12589'MD(planned) 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 potential, 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. scoltiE� MAR 0 7 2017. r� L1K�'w� ECEIVED 0- DEC 15 2016 23. CASING,LINER AND CEMENTING RECORD AOGCC WT.PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT. PULLED 36" 150 A-36 0 215 ft 0 215 ft N/A Driven 0 13 3/8" 68 L-80 0 3528 ft 0 3088 ft 18-1/2" 2700 sx 0 9 5/8" 47 L-80 0 14049 ft 0 11528 ft 12-1/4" 750 sx 0 7" 32 P-110 13708 ft 15950 ft 11262 ft 12332 ft 8-1/2" 1180 cu ft 0 24.Open to production or injection? Yes ❑ No Q 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): ABANnoN,:r) 'k 26.ACID,FRACTURE,CEMENT SQUEEZE, ETC. 4 1* Was hydraulic fracturing used during completion? Yes❑ No ❑ Per 20 AAC 25.283(i)(2)attach electronic and printed information r ;;,, 1 '-, DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED UL-- 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 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 11/2015 CONTINUED ONPAGE 2 RBQMS L'. DEC 2 2 2016 Submit ORIGINIAL onl • • 28.CORE'DATA Conventional Core(s): Yes ❑ No ❑ Sidewall Cores: Yes El 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 test Top of Productive Interval information,including reports,per 20 AAC 25.071. Upper Hemlock 14310' 11690' Clay Zone 14632' 11895' Middle Hemlock 14750' 11955' Lower Hemlock 15338' 12176' Formation at total depth: Lower Hemlock 31. List of Attachments: Wellbore schematic,daily operation summaries 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. Contact: Stephen Ratcliff Email: sratcliff@glacieroil.com Printed Name: Stephen Ratcliff Title: Sr.Drilling Engineer Signature: Yom— Phone: 907-433-3808 Date: 1 2(15`1(i 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 la: 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 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 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.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 11/2015 Submit ORIGINAL Only • RECEIVED DEC 15 216 GLACIER OC December 15th, 2016 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage,Alaska 99501 RE: Well Completion Report- Redoubt Unit#7 Cook Inlet Energy: 50-733-20526-00-00 / PTD 203-150 Dear Ms. Foerster, Cook Inlet Energy hereby submits the Well Completion Report for Redoubt Unit#7 abandonment for continued operations that include setting the whipstock and milling the window for sidetrack under Sundry#314-646. If you have any questions,please contact me at 907.433.3808. Sincerely, C � Stephen Ratcliff Sr.Drilling Engineer Cook Inlet Energy, LLC (a Glacier Oil and Gas owned company) 601 W. 5th Avenue STE 310 Anchorage,AK 99501 1 • Redoubt Unit #7 Daily Operations Summaries PTD: 203-150/API: 50-733-20526-00-00 Continue Operations under Sundry 314-646. 10/14/2016 Continue RU of Rig 35. Pick up drill pipe. 10/15/2016 Continue RU. Pick up drill pipe. Rig up test equipment. Test BOPE 250 psi low/4500 psi high (annular to 2500 psi)—good. Work on top drive. 10/16/2016 Finish testing BOPE 250 psi low/4500 psi high—good. Test witnessed by AOGCC rep, Bob V Noble. Rig down test equipment. 10/17/2016 Continue RU of Rig 35. Test 9 5/8" Casing to 3000 psi, hold for 30 min —good test. PU scraper BHA. 10/18/2016 Continue PU Scraper BHA and RIH, picking up drill pipe. RIH and tag bridge plug at 12615' MD (3' high from original depth from 12/4/2014). 10/19/2016 RU to displace and inject. Displace well with 10.2 ppg OBM at 1 to 3.5 bpm keeping up with injection rate. Circulate and condition mud. 10/20/2016 POH and LD Scraper BHA. MU 9-5/8" Whipstock assembly and orient. RIH and shallow test tools. 10/21/2016 TIH with 9-5/8" Whipstock assembly and orient. Tag bridge plug at 12,614'. PU and set whipstock anchor at 12,562' MD. Top of slide at 12,539' MD and bottom at 12,553' MD. AM j LC_ to►jU4) END of Redoubt Unit#7 P&A Operations covered under Sundry 314-646. 0 o RU-07 Actual Abandonment Schematic Version: ACTUAL Cook Inlet Energy Update: 12/15/2016 L 36" 150#A-36 215'MD 36"Conductor i 'I' .- ID-35" A-36 215'TVD 18-1/2"Hole 13 318" 68#L-80 3,528'MD A ' 12.415" BTC 3,088'TVD 12 1/4"Hole ,/I 41i TOC with No Estimated Losses @ 10,550'MD ./ -7 i!JyJ; Top of Window @ 12539'MD / / Bottom of Window @ 12553'MD Anchor set at 12562'MD *T - CIBP set at 12,618'MD/10385'TVD Oh 17111 1 TOL @ 13,708'MD 1 11,262'TVD ` 9 518" 47# L-80 14,049'MD _Emir— ID-8.681" BTC 11,528'TVD Plug 2-TOC @ 13,786'(E-line tag) 23 bbls,15.8ppg Class G Perforations Plug 1-TOC @ 14,404' 14350'-14635' --- . - = 23 bbls,15.8ppg Class G 14745'-15123' �- .' --- ^= EZSV Set @ 15050'MD — s='r..—.,r — 15340'-15667' — 7" 32# P-110 15,950'MD 8 1/2"Hole ail_ ID-6.094" Hydril 521 12,332'TVD • GLACIER RU-07B Daily Operations Summary API: 50-733-20526-01-00 Permit#: 214-191 Rig: Osprey Rig 35 Date and Footage Drilled as of 24:00 hours. Activity 21 October 2016 TD: 12,573';Mud Weight: 10.2 ppg OBM;Viscosity:79;TIH with 9-5/8" 20' Whipstock assembly and orient.Tag bridge plug at 12,614'.PU and set whipstock anchor at 12,562'MD.Top of slide at 12,539' MD and bottom at �l� _ 12,553' MD.Mill window in casing with 8-1/2" mill assembly and drill 20'of new hole from 12,553' MD to 12,573'.Spud Sidetrack @ 18:45hrs.Circulate ''1'7 and condition mud for LOT. 22 October 2016 TD: 12,573';Mud Weight: 10.2 ppg OBM;Viscosity: 106; Perform LOT to 15.0 0' ppg EMW. Flow check,well static. POH with Milling assembly and LD same. Prep for BOPE test. 23 October 2016 TD: 12,573';Mud Weight: 10.2 ppg OBM;Viscosity: 113;Test BOPE to 250 psi 0' low/4500 psi high(annular @ 2500 psi high)—good.Test witness waived by AOGCC. RD testing equipment.PU 63/4" Drilling BHA(bit, motor,MWD)and RIH while picking up 4"drill pipe.Shallow test tools at 1659'MD. 24 October 2016 TD: 12,764';Mud Weight: 10.2 ppg OBM;Viscosity:77;Continue RIH with 191' BHA on 4"drill pipe to 3100',switch to 5"drill pipe and RIH to window. Orient motor and wash to bottom at 12,573' MD. Drilled from 12,573'to 12,764',sliding as necessary. 25 October 2016 TD: 13,019';Mud Weight:10.2 ppg OBM;Viscosity:86;Continue drilling 255' from 12,764'to 13,019',sliding as necessary.Lost 200 psi Standpipe pressure. POH from 13,019'to 12,513'.Test surface equipment searching for leak—none.Continue POH to 7,075'and locate leak in drill pipe. 26 October 2016 TD: 13,300'; Mud Weight: 10.2 ppg OBM;Viscosity:90;Swap out washed 281' joint of drill pipe.TIH to 13,019' and wash to bottom.Drill from 13,019'to 13,300',working tight spots as required. 27 October 2016 TD: 13,818'; Mud Weight: 10.2 ppg OBM;Viscosity:97;Continue drilling 518' from 13,300'to 13,818'MD,sliding as needed. 28 October 2016 TD: 14,265'; Mud Weight: 10.2 ppg OBM;Viscosity:93;Continue drilling 447' from 13,818'to 14,265' MD.Circulate and condition mud for short trip. • 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION la.Well StatuWEILL COMPLETION OReRECOMPLEJION r 0 Abandoned ' nde ✓✓REQ9,RTkv lb.Well cAND LOG lass: 20AAC 25.1P. 20AAC 25.1.'♦y'0 , Development o Exploratory 0 GINJ 0 WINJ 0 WAG: WDSPL❑ No.of Completions: / Service 0 Stratigraphic Test 0 2.Operator Name: 6.Date Comp.,Suso.,or 14.Permit to Drill Number/ Sundry: COOK INLET ENERGY LLC Aband.: 12/4/2014 203-150/314-646/3/x. l 3.Address: 7.Date Spudded: 15.API Number: 601 W 5TH AVE,SUITE 310,ANCHORAGE,AK 99501 9/7/2003 50-733-20526-00-00 4a.Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: 5(7- Surface: 1967'FSL,223'FEL,Sec. 14,T7N, R14W,SM 12/4/2003 REDOUBT UNIT#7 .tib tau 7 6 Top of Productive Interval: 9. Ref Elevations: KB: 90'MS 17.Field/Pool(s): 1483'FNL, 1667'FWL,Sec. 19,T7N,R13W,SM GL: N/A BF: N/A REDOUBT SHOAL UNDEFINED Total Depth: 10.Plug Back Depth MDITVD: 18.Property Designation: 2037'FNL,2024'FEL,Sec. 19,T7N,R13W,SM 12618'MD/10385'TVD ADL 381203 and 374002 4b.Location of Well(State Base Plane Coordinates,NAD 27): 11.Total Depth MD/TVD: 19.Land Use Permit: Surface: x- 200675.2 y- 2449982.2 Zone- 4 15950ft MD/12332ft TVD N/A TPI: x- 207845.5 y- 2446532.5 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 209214.2 y- 2445978.6 Zone- 4 N/A N/A 5.Directional or Inclination Survey: Yes 0 (attached) No 0 13.Water Depth,if Offshore: 21.Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 -45- ..4U MSL) 12589'MD(planned) 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 potential, 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. SCANNED MAR 0 7 2017, RECEIVED SEP 1 6 2016 AOGCC CASING,LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT CASING GRADE FT TOP BOTTOM TOP BOTTOM PULLED 36" 150 A-36 0 215 ft 0 215 ft N/A Driven 0 13 3/8" 68 L-80 r 0 3528 ft 0 3088 ft 18-1/2" 2700 sx 0 9 5/8" 47 L-80 0 14049 ft 0 11528 ft 12-1/4" 750 sx 0 7" 32 P-110 13708 ft 15950 ft 11262 ft 12332 ft 8-1/2" 1180 cu ft 0 24.Open to production or injectichn? Yes❑ No io 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): ��Q I - �+ .�� e v 26.ACID, FRACTURE,CEMENT SQUEEZE,ETC. / (�( Was hydraulic fracturing used during completion? Yes❑ No 0 2 ' ( I �' Per 20 AAC 25.283(i)(2)attach electronic and printed information C f°'y ( -/ (� DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED VE I" ED, t...1- 27. L27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: Test Period - Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 24-Hour Rate - Form 10-407 Revise 11/2/01 CONTINUED ON PAGE 2 d2,/a //Z. dief* /L-f.3-/, RBDMS L-L SEP 1 9 2016 SubmitORIGINIALon S 28.CORE DATA Conventional Core(s): Yes ❑ No 0 Sidewall Cores: Yes 0 No 0 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 0 No 0 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 test Top of Productive Interval information,including reports,per 20 AAC 25.071. Upper Hemlock 14310' 11690' Clay Zone 14632' 11895' Middle Hemlock 14750' 11955' Lower Hemlock 15338' 12176' Formation at total depth: _Lower Hemlock 31. List of Attachments: Wellbore schematic,daily operation summaries 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. Contact: Conrad Perry Email: cperry@glacieroil.com Printed Name: Conrad P ) Title: Drilling Manager Signature: Phone: 907-727-7404 Date: INSTRUCTIONS General: This form and the require. . :chments 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 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 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.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 11/2015 Submit ORIGINAL Only • • RECEIVED II CEI sEP162015 AOGCC GLACIER September 16, 2016 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage,Alaska 99501 RE: Well Completion Report- Redoubt Unit#7 Cook Inlet Energy: 50-733-20526-00-00 / PTD 203-150 Dear Ms. Foerster, Cook Inlet Energy hereby submits the Well Completion Report for Redoubt Unit#7 abandonment. If you have any questions, please contact me at 907.727.7404. Sincerely, )?c Conrad Perry SVP-Drilling Cook Inlet Energy, LLC 601 W. 5th Avenue STE 310 Anchorage,AK 99501 1 • • RU-07 Actual Abandonment Schematic Version: ACTUAL Cook Inlet Energy_ Update:9/16/2016 * i 36" 150#A-36 215'MD 36"Conductor ID-35" A-36 215'TVD k4 18-112"Hole .4r $ Y 13 318" 68#L-80 3,528'MD 12.415" BTC 3,088'TVD C't's 12 1/4"Hole + Top of Cement with No Estimated Losses @ 10,550'MD A 5 -- - - - - CIBP set at 12,618'MD/10385'TVD "} ! TOL @ 13,708'MD 1 11,262'TVD ` 9 5/8" 47# L-80 14,049'MD : w ID-8.681" BTC 11,528'TVD Plug 2-TOC @ 13,786'(E-line tag) pw' `; ;"; 23 bbls,15 8ppg Class G Perforations ; .. ' +' 4 1. +: g c.�•1p Plug 1-TOC @ 14,404' 14350'-14635' "".1~�2 ,r ,4.4,, 23 bbls,15.8ppg Class G 14745'-15123' -" EZSV Set @ 15050'MD It 15340'-15667' Z , `' Ia 7" 32# P-110 15,950'MD 8 1/2"Hole = I ID-6.094" Hydril 521 12,332'TVD • Redoubt Unit #7 Daily Operations Summaries PTD: 203-150/API: 50-733-20526-00-00 11/18/2014 Rig Prep 11/19/2014 Continue with Rig Preparations. Fill pits. Rig up to circulate tubing. Circulate down tubing at 25 gpm at 3950 psi. 11/20/2014 Pump 100 bbls down tubing at 25 gpm, 3950 psi. Fill backside at 65 gpm, 200 psi. Took 55 bbls to fill. Reverse circulate at 65 gpm, 1900 psi, for 100 bbls. RU E-line, pressure test lubricator to 3000 psi, RIH with tubing punch to 13,423' (13 shots, 4 shots per foot, 0 phase). POOH - charges did not fire. RIH with 2"d tubing punch run to 13,423' (13 shots, 4 shots per foot, 0 phase). POOH —all shots fired. RU and circulate to clean tubing and annulus. 11/21/2014 Finish circulation. Set BPV. Nipple down tree. Cap off injection lines and run lock down pins. NU BOPE. 11/22/2014 Continue NU BOPE. 11/23/2014 Shell test BOPE, troubleshoot leaks. Pull BPV, set 2-way check. Test hanger against blind rams— good (250 psi low/4000 psi high). LD 5" test joint and PU 3-1/2"test joint. Test annular 250 psi low/2500 psi high. Test BOPE 250 psi low/4000 psi high —good. Pull 2-way check. Pull tubing hanger. POOH with 3-1/2"tubing and ESP from 13579' to 13429'. 0.14----; 11/24/2014 Continue POOH with 3-1/2"tubing, pulling ESP, from 13429'to 3200'. 11/25/2014 Finish POOH with 3-1/2"tubing and ESP. LD ESP Assembly. Test BOPE with 5" test joint—250 psi low/4000 psi high —good. Clean rig floor. Prep BHA. 11/26/2014 PU BHA and RIH on drill pipe to 12,854'. 11/27/2014 Continue RIH to 13,668' (top of liner). Circulate. RIH to 14628' and wash down to 14712', set down 20K with pump psi increase indicating fish engagement. POOH with saddle packer • • assembly from 14,712'to surface. Make up Cement Retainer and RIH on 2-7/8" stinger and drill pipe to 3,008'. 11/28/2014 Continue to RIH with Cement Retainer to 15,050'. Attempt to circulate down drill pipe with no success. RU to reverse circulate, established circulation. RU to pump down drill pipe— 2bpm/180psi. Attempt to set Cement Retainer—did not set. POOH with cement retainer. PU hydraulic set cement retainer. 11/29/2014 RIH with Cement Retainer. Circulate at 13708'. POOH to 13651' and monitor well. Troubleshoot electrical issues. RIH from 13,651' to 14,990'. Wash down from 14,990'to 15,050', set Cement Retainer. Pick up and set down on retainer with 10K and confirm set. POOH from 15,050'to 9,030'. 11/30/2014 Finish POOH and LD BHA. RU and test BOPE with 4" and 5" drill pipe at 250 psi low/4000 psi high. MU 2-7/8" stinger on drill pipe and RIH to 13,761'. 12/1/2014 Finish RIH to 15,050'. Sting into Cement Retainer and establish injection rate of 0.5bpm. Pump 42 bbls water at 4760psi. Un-sting and circulate, sting back into retainer and establish injection at 1 bpm for 38 bbls. Un-sting and RU cement equipment. Pump 23 bbls, 15.8ppg Class G cement and displace with 223 bbls water at 6 bpm. POOH to 14,077' and CBU. Wash down to 14,404' (calc TOC) with no pressure increase. RU cement equipment. Pump 23 bbls, 15.8ppg Class G cement and displace with 215 bbls water at 6 bpm. 12/2/2014 RD cementers. POOH to 13,218' and CBU. POOH and LD stinger. RU E-line. Test casing and plug to 1500 psi for 30 min —good. RIH on E-line,tag TOC at 13,786', POOH while logging Cement bond on 9-5/8" casing from top of liner to 10,250'. (CBL shows TOC in 9-5/8" at 11,800'). RD E- line. PU Cleanout BHA and RIH to 2181'. 12/3/2014 Continue RIH to 13,697' and tag 7" liner top. CBU. POOH and LD Cleanout BHA. RU E-line and RIH with Bridge plug to 3000'. 12/4/2014 Continue RIH with BP to 12,618' and set plug. POOH and RD E-line. LD Drill pipe and Secure Rig. END of Redoubt Unit#7 P&A Operations (Sundry 314-618) 5—ir' 711 cue. �°o% • • Redoubt Unit #7 Daily Operations Summaries PTD: 203-150/API: 50-733-20526-00-00 Continue Operations under Sundry 314-646. 10/14/2016 Continue RU of Rig 35. Pick up drill pipe. 10/15/2016 Continue RU. Pick up drill pipe. Rig up test equipment. Test BOPE 250 psi low/4500 psi high (annular to 2500 psi)—good. Work on top drive. 10/16/2016 Finish testing BOPE 250 psi low/4500 psi high—good. Test witnessed by AOGCC rep, Bob Noble. Rig down test equipment. 10/17/2016 Continue RU of Rig 35. Test 9 5/8" Casing to 3000 psi, hold for 30 min —good test. PU scraper BHA. 10/18/2016 Continue PU Scraper BHA and RIH, picking up drill pipe. RIH and tag bridge plug at 12615' MD (3' high from original depth from 12/4/2014). 10/19/2016 RU to displace and inject. Displace well with 10.2 ppg OBM at 1 to 3.5 bpm keeping up with injection rate. Circulate and condition mud. 10/20/2016 POH and LD Scraper BHA. MU 9-5/8" Whipstock assembly and orient. RIH and shallow test tools. 10/21/2016 TIH with 9-5/8" Whipstock assembly and orient.Tag bridge plug at 12,614'. PU and set whipstock anchor at 12,562' MD.Top of slide at 12,539' MD and bottom at 12,553' MD. �►� L c t- tv i til vin END of Redoubt Unit#7 P&A Operations covered under Sundry 314-646. Re@LL (Am- -±7 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Friday, January 16, 2015 12:43 PM efi IITviIj To: Evan Harness Cc: Conrad Perry; Schwartz, Guy L (DOA) Subject: RE: Osprey RU #7 Subdry#314-618 Does AOGCC have the test results for downhole plugs securing the wellbore? If not please submit charts. With passing test results of plugs work on BOPE would be acceptable. a1W Jim Regg ---- - Supervisor, Inspections AOGCC 907-793-1236 Sent from Samsung Mobile SCANNED J.4N 2 3 2015 Original message From: Evan Harness <Evan.Harness@cookinlet.net> Date: 01/16/2015 12:08 PM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg@alaska.gov> Cc: Conrad Perry <Conrad.Perry@cookinlet.net> Subject: Osprey RU #7 Subdry# 314-618 1 Z-L7isto Regg, James B (DOA) From: Evan Harness <Evan.Harness@cookinlet.net> Sent: Friday,January 16, 2015 1:39 PM 'WI15 To: Regg,James B (DOA) L`f Subject: Fwd: RU7 CSG Test Attachments: RU7 CSG Testdf;AFF9666-1-htrn Not Sure if AOGCC had this or not Evan K. Harness Drilling Superintendent Cook Inlet Energy evan.harness@cookinlet.net Office-907-433-3824 Cell-907-602-0355 Home-907-333-2228 Begin forwarded message: From: Osprey Expediter <Osprey.Expeditercookinlet.net> To: Evan Harness <Evan.Harness(a cookinlet.net> Subject: RU7 CSG Test Date: January 16, 2015 at 1:05:55 PM AKST Jess J Franco III Osprey Expediter/MICP (907)-776-7168 Pektc2--F- L( r( ' 7 'Z 1(.o0 11 MIDNIGHT --9000 /. 1 ----8000 ' ' C7 7G00 \ \ e/f,,, 01° 6000 ----------21-----. 5000 `\ \ \ 4 f \ �` Ul 41, 1 -.. - N b000 \ ) 00 3000 giligr O f `cs, 4)O -: - O0 t Op Op' o02p00 cs p Ap0 � 004.1. 1000 Iffir 9O O \ 0Op0 00f 1 0 #444 `0 00o 0 !I . 0 r / 0 rn y 0> 0aO rn =AO -.4 D -it o -o t, �� 3 0 _up. _..;_. i.,.:.. . . ._ . . , �y-p C7 7 - . .• .. - . '.', ' • \ (SCA: 1,c rli \ o--, (...-,2 .411:0 - G.� O 00� - _. _- O. /O 00 OOi j O • 0Gr OOO O� 40111 00 •O/ O OOpd . 44riiii- O00V 00 O O O •Oo O`1 .. 0 •00 p 0011,44S4141.11: OOOZ O03 000 O t 00b f 000 £ ifil:1) 00 . 11114‘ L ; :04111 L b . c'• 0008 _-, aommw - --, --; , __r__T_ ,-------7 0006 0 Regg, James B (DOA) From: Evan Harness <Evan.Harness@cookinlet.net> Sent: Friday, January 16, 2015 12:09 PM To: Regg, James B (DOA) Cc: Conrad Perry Subject: Osprey RU #7 Subdry# 314-618 ✓ Attachments: 01-16-15 Request to Open BOP on RU 7.pdf;, .T-A999-1-htm; RU-07B Actual Abandonment.pdf; A11004(42714-m- Friday,January 16, 2015 BOP Work on RU 7 ze5iscO Sundry#314-618 COOK INLET ENERGY January 16, 2015 MR. JIM REGG MR. REGG Cook Inlet Energy Currently has a short crew on board the Osprey Platform working on some Maintenance items on the Rig and Platform We would like to Open Up the Ram Cavities on the BOP Stack That is currently nippled up on our RU #7 Re-Drill opportunity. Current Stats of the Well is that we have completed the Abandonment phase 2 Including Pressure Test of Well Bore to 1,500psi for 30min has been completed. Current 9 5/8" Pressure is 0 When We open the Lower Ram Cavity our Barriers will be Cement Balanced on top of Retainer set at 15,050 for a E- Line tag of top of Cement at 13,786 (Abandonment Plug was Pressure Tested to 1,500psi for 30min) + Cast Iron Bridge Plug Set at 12,618 + Kill Weight Fluid to Surface Our intent would be to Change out Rams to 5" Fixed and Check Ramps -We would then Button the BOP Stack back up and Shell Test Against the Annular to 1,500psi. A Full BOP Pressure Test will be required when we fire the Rig back up to Cont work on RU #7 Let Me Know what you think Evan K. Harness Drilling Superintendent Cook Inlet Energy evan.harness@cookinlet.net Office - 907-433-3824 Cell - 907-602-0355 Home - 907-333-2228 R ctual Abandonment Schematic Version: ACTUAL Cook Inlet Ener }� January 16,2015 gy at 7 PTS() 2 .->l ,K ..; 36"Conductor w 36" 150#A-36 215'MD ID-35" A-36 215'TVD - 18-1/2"Hole J w. Top of Cement with No Estimated _ --.> r 13 3/8" 68#L-80 _ 3,528'MD Losses @ 10,550'MD $ax 12.415" BTC 3,088'ND ,p 4. 12 1/4"Hole /0 Ix - --- - c"- CIBP set at 12,618' ;'rs e}'k. ,t,... ♦ 9 5/8" 47# L-80 14,049'MD ,,,.o '1A* ID-8.681" BTC 11,528'ND F . ,"- TOL @ 13,708'MD/11,262'ND • _- <,,'% Plug 2-TOC @ 13,786' ''-° Plug 1-TOC @ 14,404' tit t • O.', -----.-"'-` Pw f ._._...,.aa' ' ' " '»a EZSV Set @ 15050'MD HH YY 8 1/2"Hole x. ,'3.__ 7" 32# P-110 15,950'MD j' ,, ID-6.094" Hydril 521 12,332'TVD · . 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"'3 - L ~O Well History File Identifier Organizing (done) o Two-sided III 11111111" 11111I o Rescan Needed ""111'11'" 111111 RjSCAN o }plor Items: vr'GreysCale Items: o Poor Quality Originals: DIGITAL DATA OVERSIZED (Scannable) o Maps: o Other Items Scannable by a Large Scanner o Diskettes, No. ~her, NolType: C:p {'Jo4F 1 OVERSIZED (Non-Scannable) o Other: o Logs of various kinds: NOTES: Dale 1/'~07 o Other:: BY: ~ /s/ mf Project Proofing BY: C Mari~ '" 11111111111 ,,11/ /s/ ~ + ß = TOTAL PAGES J /3 (Count does not include cover sheet) /s/ Scanning Preparation BY: Date: Production Scanning Stage 1 Page Count from Scanned File: l1l/=- (Count does include cover sheet) Page Count Matches Number in SCanni~g pr¡paration: YES BY: ~ Date: 7/I:>-J °7 Stage 1 If NO in stage 1, page(s) discrepancies were found: YES 11111111111111" 11/ NO /s/ Mf NO BY: Maria Date: /s/ "111111I11I" "III Scanning is complete at this point unless rescanning is required. 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Iia LL a UL 0 a CL a 0-ire I-J I I LL 7 0 0 a J_ . O C a) co CC C C C a) C a) C C E fa 0_ O. 0_ 0. a o d o O- O. � co O 0 0 0 0 0 0 0 0 0 o Ce c `) N N CO O O O O O O co O. v v co U) in �n in �n O M O j a) a) co O) 0) Q) a) 0) CO 0) d a) Z CL 0 - - Qua EwE } C13 3 W J O) 0) O 0 O N 0) 0 O CO co Z COIX a co 1 - - N N N N V V 1 W w > V 0 11 Q N m Z — 0 0 r H Q yro � 0 _ 0. CL w C a E 0 a) 0 LOL laoiti ONa .= E Vr o � 0 Q F o 1 I 5 L. o co 21- N COZ N +' D r) n I- 0 0 u ) Q wre Co CD'ICC O d Z U �I 1.7. 1' E 0 co Z co w y co w a) a) d a) j N 0 .T, O O O O O C O CO E CO 45 y U J Z Z Z Z N (4 mE N a) a) O O a) a) a) N a) O Z 0 U) 2 CO CO CO CO 0 Ll_ co Z E 1 O 7 c0) M M C) 0 m) C) M M c•) M O 0 LA o- O pO m 0) O O O O W o) Q V V V a V V Nr a C aCe) co 0 Oco ce } kN Q. y Z P. u) V) y �... Cl) co to y to E E N F., O 'O 'O V 0 V 'O 'O 'O 'O ea co J > I a a a a a a a a a a a -.to z Z ami U C, . II 0 I= 0 Cl) >,>_ E _ a) `y 7 17 7 7 7 a a 0 O D 7 y a °) r c a°i E a a w W ---W-----W w w----W----- W W w Q 0 <a 11 0 0 9 0 0 co N O Z N cn U_ n 5 0 C o Z J_ 7 aj (C F- c a o. 0 III o W w cc U ° Z Q w J G • o 5.%--1 r U = J H _ 0 r-- 2 C N W N � M CO V) 0 o W = c F- Q o Z U to z N M M N i I- CO a 0 N N prj Y 10 Ea a. U fr„l//i ,a THESTATE P 2i f; �. `{ ei,tn (c." ( z.,-- ---7--__=-12-7. L� ,I.,_/./1 '.� °`- ted/i y\JL itt _ y 333 Wes Seventh Avenue — - " C 3 Anchora e, Alaska 99501-3512 GC>1 I=.R �OR F.AN ➢ .ARNII,I. 9 iii., Mn:ci901.279 1433 Q � r ��,kF 907 %7� t- ca��E'° �� 2 2•VIA Conrad Perry S Drilling Manager �� Cook Inlet Energy, LLC 3 0 _ 6 601 W. 5th Ave., Suite 310 ,r)‘ Anchorage, AK 99501 Re: Redoubt Shoal Field, Undefined Pool, Redoubt Unit#7 Sundry Number: 314-023 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, /19...... 24_,____ Cathy P. oerster Chair T DATED this /(0 `— day of January, 2014. Encl. .ilAt_ • STAFF MEMBER t �� REC IV STATE OF ALASKA .��' 10.f it l ,�JA@�Mo.�J��' ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC RECUSED 20 AAC 25.280 1.Type of Request: Abandonu Plug for Redrill I=1 Perforate New Pool u Repair Well , Change Approved Programa p Suspend Plug Perforations Perforate El ' Pull Tubing Time Extension�* Operations Shutdown Re-enter Sus Well Stimulate Alter Casing Other: ,L -K.....1/4 'OP Y 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: COOK INLET ENERGY LLC Exploratory Development ® . 203-150 A 3.Address: 6.API Number: Stratigraphic Service 601 W.5th AVE.SUITE 310,ANCHORAGE,AK 99501 50-733-20526-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 20 AAC 25.055 REDOUBT UNIT#7• Will planned perforations require a spacing exception? Yes I__I No El 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 381203 and 374002 REDOUBT SHOAL UNDEFINED 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): rrI5 Plugs(measured): Junk(measured): 15,950' • 12,332' • 15,870' t a NONE 14,850 Casing Length Size MD TVD Burst Collapse Structural Conductor 215' 36" 215' 215' N/A N/A Surface 3,528' 13 3/8" 3,528' 3,088' 5,020 PSI 2,260 PSI Intermediate 14,049' 9 5/8" 14,049' 11,528' 6,870 PSI 4,750 PSI Production Liner 2,242' 7" 15,950" 12,332' 12,460 PSI 10,760 PSI Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 14,350'-15,667' 11,159'-12,219' 3 1/2" P-110 13,445' Packers and SSSV Type: NONE Packers and SSSV MD(ft)and TVD(ft): NONE 12.Attachments: Description Summary of Proposal ® • 13.Well Class after proposed work: Detailed Operations Program Di BOP Sketch IXI • Exploratory I I StratigraphicI I Development IXI.Service I 14.Estimated Date for 1J,yi/'f2-15.Well Status after proposed work: Commencing Operations: VV` ./tom GDC Oil ®. Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG Abandoned Commission Representative: GSTOR El SPLUG e 17.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 Conrad Perry Title Drilling Manager SignaturePhone 907-727-7404 Date 12-Jan-14 w__\ COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31`f- 023 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance Other: 11C"4 60/051; 04PP RBDM AY o 8 2014 Spacing Exception Required? Yes L1 No d Subsequent Form Required: 16 —9014 D / APPROVED BY /_ ,6 - Approved by: .." I Lis__ COMMISSIONER/ THE COMMISSION Date: ,•/�•/� �'~� 1113/ f t30`� /// Submit Form and Form 10-403(Revised 10 R I I l�pp[ove(f application is valid for 12 months from the date of approval. Attachments in Duplicate Cook Inlet Energy_ RECEIVED JAN 142a014 January 12, 2014 AOGCC Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage,Alaska 99501 Re: Application for Sundry Additional Perforations and ESP Replacement Cook Inlet Energy, LLC: Redoubt Unit#7 PTD: 203-150 Dear Ms. Foerster, Cook Inlet Energy (CIE) requests approval to replace the ESP on the Redoubt Unit#7 well in the Redoubt Unit Field of Cook Inlet. We will be re-perforating the current oil zones and adding new Hemlock perforations at 15,412'-15,432'MD (12,196'-12,201'TVD) and 15,494'45,528' MD (12,217'-12,224' TVD). An early 2013 workover failed to add these new perforations due to an obstruction in the liner. CIE intends to clean out the liner to PBTD prior to perforating. We also intend to run a Pulsed Neutron log in an attempt to determine where the water is coming in in this well. A straddle packer option is included to isolate a single water zone. Rig#35 will be used to complete this work over commencing approximately January 16, 2014. Attached please find a completed Form 10-403, current and proposed wellbore schematics, Rig Drawing, a BOP configuration diagram and work over program. If you have any questions, please contact me at (907)-727-7404. Sincerely, Conrad Perry Drilling Manager- Cook Inlet Energy 601 W.5th Avenue,Suite 310,Anchorage,AK 99501 (907)334-6745*(907)334-6735 fax Table of Contents Rig#35 Schematic 4 Current Completion 5 Proposed Wellbore Diagram 10 BOP Sketch 11 Wellhead Schematic 12 Rig #35 Schematic f.. ova . .ib. ' IJ ` J ill Ea Z VI ' I ) 4 ... 'f wows '\ li. .11 F t 1r rtw I :47 j, ..,1 : ._ Iwo eti o o .SIM. MN. _ .. .c. 1 OSPREY I r-" � 7-�Y DRILLING RIG ARRANGEMENT — EAST SIDE DWG c s"u".i`"••ra VOORHIES.... TINKHAM. V.1 t vin, ; MD OSPREY ORILLI c RIG__ .�.» '.i.. "'� ban = INIONO P`'l Current Completion Redoubt Unit#7 Current Completion February 2013 36",1506,A-36 Welded Conductor @ 215'MD/215'TVD 13-3/8",686,L-80,BTC @ 3,258'MD/3,074'TVD 100 jts 34/2",RTS,P1-1-6 Tubing X0 @ 10,464'MD • 329 jts 3-1/2",EUE Tubing 13,3360-10,464'MD })ly • • • Centrilift ESP assembly ''71 • •, top @ 13,454'MD bottom @ 13,535'MD Top of 7"Liner @ 13,708'MD/11,262'TD • • 9-5/8",476,1-80,BTC @ 14,049'MD/11,528'ND Perforations: 14,350'-14,424' 14,442'-14,505' 14,535'-14,580' 14,610'-14,635' 14,745'-14,785' 3 14,840'-14,955' 15,100-15,123' 15,340'-15,383' 15,590"-15,667' 3-3/8"guns,65PF t 7",326,P-110,Hydril 521 @ 15,950'MD/12,332'ND Workover Procedure Redoubt Unit # 7 ESP Completion Change out Summary Procedure January 2014 1. Move Rig 35 to RU #7. Fill pits with produced water. 2. Rig up and test lines. Bleed gas off of well and displace crude from RU #7 with produced water, taking returns to Kustatan via 6" gas/test pipeline. Over-displace with 100 bbls water and shut well in. a. prepare cable spools and splicing kits. b. Check all drip pans are in place and sealed c. prep for crude oil -absorbs, rig wash, etc d. The kill operation maybe completed prior to assigning rig by production. 3. Check for flow, if well is not dead continue with additional displacement until it is dead. Weight up to 8.6ppg with KCL if necessary. 4. Install BPV and N/D production tree. 5. Nipple up and test 13 5/8" BOPs to 4500 psi. Notify AOGCC of intent to test 48 hours in advance. Note:Test Rams on 3 %2" and 5". Pull Existing Completion. 6. Rig up Baker ESP spoolers. 7. Check for trapped pressure, then Pull BPV, Check well for flow. MU landing joint in tubing hanger and back out lock-down screws. 8. Pull tubing hanger. Remove ESP cable and control lines carefully from hanger. 9. Proceed pulling out the string slowly. a. Visually inspect connections and stand back tubing. b. Count bands. c. Monitor trip tank for proper hole fill up. d. Check tubing for NORMS-Scale may have been an issue with RU-7 e. Lay down all EUE tubing. PH6 will be used as workstring in liner. 10. Lay down ESP and inspect. Clean out/Logi Re-perforated 11. Pick up 6" (slightly undergauge)taper mill and RIH on 3 '/" PH6 and 5" drill pipe. Note: 7" liner is 32#. 12. RIH to +1- 15,870'. Note: previously encountered obstruction at 1_4485D'. Circulate until clean. 13. Filter produced water to <20NTU. Note: use produced water. 14. Pull out of hole. 15. Rig up and run pulsed neutron log. 16. Hold PJSM on handling guns, communications, roles and responsibilities. 17. Pick up 4 5/8" guns to perforate the following intervals 5 spf with Halliburton Millennium charges: a. 15,590'— 15,667' b. 15,494' — 15,528' (NEW) c. 15,412' — 15,432' (NEW) d. 15,340'- 15,383' e. 15,100' — 15,123' f0) I f. 14,840' — 14,955' g. 14,745' — 14,785' h. 14,610' — 14,685' i. 14,535' — 14,580' j. 14,442' — 14,505' k. 14,350' — 14,424' NOTE: Zone 14,745'—14,785' is a potential wet zone and will not be re-perfed. 18. Pick up Champ test packer and burst disk. 19. Run in with assembly on drill pipe. Short fill drill pipe last 3000'. This will give a 1,115 psi underbalance at the top perforations and potentially allow 53 bbls of oil into the well. 20. Rig up Halliburton and run GR/CCL Log. Re-space guns on depth. Re-run Gr/CCL to confirm. Work with Greg for double check correlation. 21. Set packer. Test backside to 2001psi. Rig up to rig choke. Test lines 22. Hold Firing PJSM. Drop bar, perforate well, flow fluid to surface. 23. Once brine is to surface, shut in at surface. 24. Reverse well dead over choke. Note if 53 bbl of oil enters the drill string, there will be approximately 300 psi surface pressure prior to reversing clean. 25. Check for flow. Well should be dead. 26. Unseat packer. Circulate well clean, Check for flow. 27. POH 28. PJSM prior to pulling guns through rotary. Lay down guns being aware of potential trapped pressure. OPTIONAL Straddle Packer—Water Shut-Off. A Tripoint Straddle packer may be run depending on the results of the Pulsed Neutron log. This is the procedure: 29. Make up the BHA a. Bottom 3 %" x 7" Retrievable packer / tie" b. 2 jts of 3 %" EUE tubingpacker ' c. Top 3 / x 7" Retrievable pac er d. Running Tool. e. X/031/2" EUE toPH6 30. RIH on workstring. Install 3-1/2" PH-6 RA Tag sub approx. 3 joints above running tool. 31. Position on depth according to pipe measurements. 32. Space out workstring @ surface to allow electric wireline access. 33. RIH w/ 1-11/16" or 2-1/8" GR/CCL. 34. Tie in and log packers on depth. 35. POOH and rig down electric wireline. 36. Position packers as required to isolate perforations. 37. Drop Setting Ball. 38. Pressure tubing to 3,500 PSI and hold for five minutes. 39. Bleed off applied pressure, Take 10,000# pull to determine if packer is set. 40. Release running tool (1/4 turn to the left) and POOH. Run New ESP 41. Test and inspect new ESP and new Phoenix tool before running in hole. 42. Pick up new ESP completion and RIH. a. Pump should be set in less than 1 degree/100' dogleg. b. Test cable every 1000'. c. Note that the 3/8" flat pack chemical injection line is to be run to the anode on the bottom of the ESP assembly d. 3/8" Nova Valves to be installed at top of pump assembly. 43. Monitor trip tank for proper hole filling. Splice cable as needed. At TD, confirm pipe tally, MU landing joint and set string in slips. 44. Dress hanger and control lines. Land hanger, Check cable and control line continuity. 45. Run in screws, test hanger to 5000 psi. 46. Perform final electrical checks on cable. 47. Lay down landing joint and install BPV. Observe well dead. 48. Nipple down riser and BOPE. 49. Install and test production tree. Turn over well to production. 50. Release Rig Proposed Wellbore Diagram _ Redoubt Unit #7 Proposed Completion . January 2014 I: 36",150#,A-36 Welded Conductor@ 215'MD/215' N. III j 13-3/8",68#,L-80,BTC @ 3,258'MD/3,074' TVD i 100 jts 3-1/2",RTS, PH-6 Tubing XO @ 10,464'MD } . 329 jts 3-1/2",EUE Tubing '•, 7, a 13,360-10,464'MD 5r 1 ri !le ! ."r ' F 1..s Centrilift ESP assembly i yi oi top @ 13,750' Top of7"Liner@ 13,708' MD/11,262' /in TD ■ 14' Perforations: 9-5/8",47#,L-80,BTC @ 14,049' MD/11,528' 14,350'-14,424' 14,442'-14,505' 14,535'-14,580' 14,610'-14,635' 14,745'-14,785' 14,840'-14,955' = ..o �„�(�aw 15,100-15,123' - Straddle Packer Option ��/ 15,340'-15,383' 15,590" -15,667' cover perfs 14,745' 14,785' I = ti / New Perforations: i 7",32#,P-110,Hydril521 @ 15,950' MD/12,332' �/' 15,412'-15,432'MD (� 15,494'-15,528' MD BOP Sketch 7#3,2012 5-25-12 BOP Schematic GT.'', "Rig Floor" WM:RUI KB Elevation Dote: 5/26/2012 Alleasera distances from"Rig Floor" Ilap of A1111.1Ar P f Hyciril ICerk,I 13-515"5k Annuiar ni.rrn /mil) 13-511311R hythil I II 4-CP tam, Center 4"Patri2n, 11===, MI 13 b..8"1:1.1s Hydr I iLmns I Galrar Inrl. )4 ••-• \4_ ./.7441•14114. „Tr. IP' age iliging tdolt.; ; K III I.IP* ov...I.1.4 _LI tm • 13.5:8"101,1 dr. •4"DI'rem. Cclur 4"Ran. = t.‘ 13 5.8'1C r A 3-5,1'5K aldnplc.aprml 1119141,14 4,444 _c.c1 11 IN 13 BM'ek x 1:3 we"blt Risci ui 1.1 • CC ltZA. Gligov.1 • 1 Wellhead Schematic REDOUBT UNIT#7 WELLHEAD SCHEMATIC k f--24.31- 1 111111 3-1/8 5000 16,,5 1_80.68- 1' +. 11 1-0 0 0111 .•.Nil�.3-1/8 5000 III Ii 113 C3- �1 p a ,. n _ in 0__nl 13-5/8 5000 68X 1p11 I b ALIGNMENT PIN III j� SHOWN 90'OUT OF POSITION �n��' ---- 28.00- - 2-1/16 5000 W/VR __1 _�N=-lad=:: l F. li row IISrid13-5/8 5000 68X IUy� I ; Y2-1/16 5000 W/VR 24.75- Ip-1 —I--1' yrall= I ` I f llim.)401411 ill 'fill I 19.50- I I i I ; !M 36- OD CASING 13-3/8- OD CASING 3-1/2 OD TU81NC_7' 1 9-5/8- OD,CASING ALL DIMENSIONS ARE APPROX. Cook Inlet Ener gY- Re: Application for Sundry Additional Perforations and ESP Replacement Cook Inlet Energy, LLC: Redoubt Unit#7 PTD: 203-150 Cook Inlet Energy Redoubt Shoals -Osprey Platform Well#RU7 PTD: 203-150 Osprey Platform Leg#2 Slot #2 EVENT DATE Spud date 9/7/03 TD at 15950' 12/5/03 Completed with ESP 3/25/04 Initial ESP start 3/26/04 ESP failed 1/5/08 Converted to Jet Pump 2/17 to 3/12/08 Start jet pumping Pull jet pump/ESP 05/21/11 Recomplete with ESP 07/14/11 Anticipated Pressures Bottom New Perforation 15,528' MD 12,224' TVD (.445 Reservoir pressure gradient*TVD) - .1psi/ft gas Anticpated Pressure = gradient-TVD) = (.445*12,224)-(.1*12,224) 4217 PSI 601 W.5th Avenue,Suite 310,Anchorage,AK 99501 (907)334-6745*(907)334-6735 fax Proposed Wellbore Diagram - - Redoubt Unit#7 Proposed Completion December 2013 36",150#,A-36 Welded Conductor @ 215'MD/215'ND • • �- 13-3/8",68#,L-80,BTC @ 3,258'MD/3,074'ND 100 its 3-1/2",RTS,PH-6 Tubing XO @ 10,464'MD 329 jts 3-1/2",EUE Tubing 13,3360-10,464'MD -* 7 Centrilift ESP assembly I top @ 13,750' • • ` Top of 7"Liner @ 13,708'MD/11,262'TD . Perforations: _ 9-5/8",47#,L-80,BTC @ 14,049'MD/11,528'ND 14,350'-14,424' 14,442'-14,505' 14,535'-14,580' 14,610'-14,635' 14,745'-14,785' 14,840'-14,955' >_ 15,100-15,123' 15,340'-15,383' 15,590"-15,667' 3-3/8"guns,6 SPF New Perforations: 7",32#,P-110,Hydril 521 @ 15,950'MD/12,332'ND 15,412'-15,432'MD 15,494'-15,528'MD Wellhead Schematic REDOUBT UNIT#7 WELLHEAD SCHEMATIC 1-24.31 I ! 11111 •,�.•.. 3-1/8 5000 80.68' 0,..,,, .1. ,.�,.3-1/8 5000 r C, ill It -- 18.63 p H „ n iH_ i:��tli 13-5/8 5000 689 _l1 YYYY VIII AUGNMENT PIN •1 OF PO TIO OUT OF POSITION 2-1/16 5000 W/VR 26.00 � ! y�I ;1! 101111It === 1I= - Ili 13-5/8 5000 60X ill 1 Y laillit I� 2-1/16 5000 W/VR 24.75" ! I 1 I.pI�,7i�:.riII1�' I l;�I f - I III 'r 11 I I 3 19.50- 'r1 I ma 36" OD CASING I13-3/8" OD CASING 3-1/2"OD TOBIN 19-5/8- OD,CASING ALL DIMENSIONS ARE APPROX. , Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Tuesday,January 14, 2014 10:52 AM To: 'Stephen Ratcliff' Subject: RE: RU-07 - Casing Test Steve, You are testing the casing (test packer) when you TCP perf the well in step 21. Just chart this 2000 psi test for your casing test. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office From: Stephen Ratcliff[mailto:stephen.ratcliff@:cookinlet.net] Sent: Monday, January 13, 2014 5:00 PM To: Schwartz, Guy L(DOA) Subject: RU-07 - Casing Test Guy, I haven't been able to get any concrete info on the last casing test on RU-07. I would like to continue looking throughout the files to see if I can give you an exact date of the last one. I should have something to you in the morning. Regards, Stephen Ratcliff Senior Drilling Engineer Cook Inlet Energy 601 W. 5th Avenue, Suite 310 Anchorage,AK 99501 O-(907)433-3808 C -(907)433-9738 1 STATE OF ALASKA AL. OIL AND GAS CONSERVATION COM ION REPORT OF SUNDRY WELL OPERA IONS 1. Operations Abandon U Repair Well U Plug Perforations U Perforate U Other U ESP SWAP Performed: Alter Casing ❑ Pull Tubing ❑ Stimulate - Frac ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown p Stimulate - Other ❑ Re -enter Suspended Well ❑ 1 2. Operator COOK INLET ENERGY, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development El Exploratory ❑ - 203 -150 3. Address: 601 W. 5TH AVE STE 310 ANCHORAGE, AK Stratigraphic❑ Service ❑ 6. API Number: 99501 50- 733 - 20526 -00 7. Property Designation (Lease Number): - 8. Well Name and Number: ADL 381203 and 374002 REDOUBT UNIT #7 9. Logs (List Togs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): , L N/A REDOUBT SHOAL UNDEFINED �) 11. Present Well Condition Summary: Total Depth measured 15,950' feet Plugs measured NONE feet true vertical 12,332' feet Junk measured NONE feet Effective Depth measured 15,870' feet Packer measured NONE feet true vertical 12,226' feet true vertical NONE feet Casing Length Size MD TVD Burst Collapse Structural Conductor 215' 36" 215' 215' N/A N/A Surface 3,528' 13 3/8" 3,528' 3,088' 5,020 PSI 2,260 PSI Intermediate 14,049' 9 5/8" 14,049' 11,528' 6,870 PSI 4,750 PSI Production Liner 2,242' 7" 15,950' 12,332' 12,460 PSI 10,760 PSI Perforation depth Measured depth 14,350' - 15,667' feet SCANNED MAR 2 7 2013 True Vertical depth 11,159'- 12,219' feet Tubing (size, grade, measured and true vertical depth) 3 1/2" P110 13,445' 11,047' Packers and SSSV (type, measured and true vertical depth) NONE 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 0 Subsequent to operation: (--- Pending 14. Attachments: 15. Well Class after work: — °' Copies of Logs and Surveys Run N/A Exploratory Development 0 .> Service ❑ Stratigraphic ❑ Daily Report of Well Operations ATTACHED 16. Well Status after work: Oil 0 Gas ❑ WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Nu4nber or N/A if C.O. Exempt: y 3/3 - ( 3- `/S7 3' 25 :' h Contact Courtney Rust Email courtney.rustOcookinlet.net Printed Name David Hall Title CEO Signature f D,av, p lrh. „ Phone 907 -433 -3804 Date 3/7/2013 Form 10-404 Revised 10/2012 R BDMS MAR 2 1 2013 ,w " Z J ! 3 Submit Original Only f ::: 0 0<7 .1 ;7 • Cook Inlet Energy_.ry March 20, 2013 Ms. Cathy Foerster, Chair e ® Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Report of Sundry Cook Inlet Energy, LLC: Redoubt Unit #7 Permit to Drill No: 203 -150 API No: 50- 73320526 -00 Dear Ms. Foerster, Cook Inlet Energy (CIE) hereby submits a Sundry Completion on Redoubt Unit #7 well located in Redoubt Shoal, Cook Inlet. While the ESP swap concluded February 20, 2013 our well is still cleaning up and will require additional time to develop stable flow before reporting well test volumes. In addition, we were unable to complete additional perforating as requested in the 10 -403 due to the obstruction at 14,891'. Included is a current wellbore schematic and daily workover summaries. If you have any questions, please contact me at (907)- 433 -3804. Sincerely, r r' 1 David : CEO - Cook Inlet Energy 601 W. 5 Avenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 * (907) 334 -6735 fax • • - - 1 Redoubt Unit #7 Completion I February 2013 L,.. ;,.., _... . 36", 150#, A-36 Welded Conductor @215 MD/215' TVD . ,;. _ ... . . .... . [ 13-3/8", 68#, L-80, BTC @ 3258 MD/3 074' TVD i ..._. 100 Its 3-1/2", RTS, PH-6 Tubing X0 @ 10,464 MD 329 its 3-1/2", EUE Tubing 13,3360-10,464' MD , . . . - ■'• _ 1.. Centrilift ESP assembly 1- top @ 13,454' MD • . • bottom @ 13,535' MD . , .... . . , .',• '. t fl.. - - 1 , - ? .1 .. [ Top of 7" Liner @ 13,708' MD/11,262 j ....: 9-5/8", 47#, L-80, BTC @ 14,049' MD/11,528' TVD 1 Perforations: 14,350' - 14,424' 1 14,442'- 14,505' = 14,535' - 14,580' 14,610' - 14,635' = = 14,745' - 14,785' 14,840' - 14,955' 15,100 - 15,123' = 15,340' - 15,383' 15,590" - 15,667' _ 3-3j8" 6 SPF, , _ . ' - .._.41 ii 7, 324f, P Hydril 521 @ 15,950' MD/12,332' TVD 1 ___ • • RU7 ESP Swap Daily Summary Reports 1/21/13 Prep for operations. 1/22/13 Prep for operations. 1/23/13 Prep for operations. 1/24/13 Prep for operations. 1/25/13 Prep for operations. 1/26/13 Prep for operations. 1/27/13 Prep for operations. 1/28/13 Prep for operations. Well Shut in. 1/29/13 Prep for operations. Well Shut in. 1/30/13 Prep for operations. Well Shut in. 1/31/13 Circulate down tubing. Shut in and monitor pressures. Resume Circulating. 2/1/13 Well Shut in. • 2/2/13 Continue prep for operations. 2/3/13 Continue prep for operations. 2/4/13 Continue prep for operations. Test BOPE 2/5/13 R/U Pollard's unit. RIH with 4 SPF total of 12 shots perforate tubing from 13431' to 13433' WLM, 10' ' below bottom joint collar. top of ESP pump tagged at = 13458' WLM. POH R/D Pollards. 2/6/13 CBU. Monitor well. 2/7/13 Pull tubing hanger to rig floor, remove power cable, and capillary bundle. Begin POH slowly, Hotsy Completion Assy. remove Cannon Clamps (17 cannon clamps), keep count of clamps & banding material 2/8/13 Continue to POH w/ tubing stand racked back = 83 with a total of 75 Regular Cannon Clamps. 2/9/13 Continue POH w/ ESP at 0600 hrs: pulled 95 stands 3 1/2" EUE Tubing, Removed total of 93 3 1/2" EUE Standard Cannon Clamps 2/10/13 Finished POH with 31/2 EUE Tubing, Total Cannon Clamps = 63. Baker terminated ESP and Control Lines. Pulled ESP over shives. R/U a stand to place Baker's submersible pump. Crew cleaning Rig Floor and Cannon Clamps to remove same. Broke & layed down two joints, joint perforated above BHA. Lay down ESP BHA. Found one separated connection between ESP cable and motor lead whip. Repair & pressure test choke manifold valve #3. Good test. Reported results to the AOGCC. tih with Halliburton Champ IV Packer, checking for flow every so often. Depth =5350' / Stands in hole = 57 2/11/13 Continue to RIH with Halliburton Champ IV Packer, checking for flow every so often. Depth =5350' / Stands in hole = 57. Shut down rig due to venting gas from RU 3 coil clean out. NO flow from well. Static. Continue to circulate bottom's up. 2/12/13 Set Packer with 4 wraps, P/u 125K / s/o 65K, set down on Champ IV Packer with 25K. Rigged up to test 9 5/8 ", 53.5 #/ft Casing. Tested casing with 2500 psi on chart or 30 mirAReleased pressure and unset Champ Packer. Circulating. Increasing fluid weight f/ 8.6 ppg - t/ 8.8 ppg on the fly. Used NACL2 and KCL for wt. up material. POH. 2/13/13 Test BOPE. Rigged Up Pollard Wire Line, installed lubricator, M/U & P/U tools, RIH f/ Surface -t/ 14,000'. • Could not get tools to pass 14752'. Set down three times at 14752'. Ran correlation log. Pull to 14250'. RIH & work through 14400'. Ran back to 14752'. Made second log pass. POH. R/U Weatherford, M/U 3.82' mule shoe on 3 1/2" EUE. RIH to 565'. Tubing = 100 jts 12.95# PH6 and 329 jts of 9.3# EUE in the derrick. 15 spare joints of 3.5" EUE on deck. 2/14/13 Continue to RIH with mule shoe. RIH with 100 joints of PH 6 12.95# tubing from completion string. RIH with 4" drill pipe. Rig up to circulate. Wash from 14756' to 14850'. No fill encountered. Shut down pumps, monitor well for flow, well not flowing. Slug drillpipe, Pulled 1 std. Blow down td & mud line. POH @ 14,825 2/15/13 POH with 4" drill pipe, production tubing and mule shoe. Tool up with 1.75" stem = Rope socket, 5' roller stem, knuckle joint, 5' roller stem, knuckle joint, oil jar, spang jar & 4.60" LIB. RIH, tag up on 7" TOL 13736', work thru TOL, RIH tag up on obstruction @ 14891' lightly, pick up, RIH and tag firmly w/ LIB. POH, found ESP band wrapped around top of rope socket, LIB shows deep gouges on 1- side, clean smooth face on opposite side. R/D Slickline R/U and Pull Wear Ring. Rig service. Organized drill floor. 2/16/13 P/U and M/U ESP Pump Assy. and Service equipment, Prep. Motor Intake Assy. Install Recirc pump, install P -10 Pump. Install recirc SST bundle, 1/4" Chemical lines and Tech Wire tube to MGU "Well Lift Gauge ". Begin banding Recirc tube to motor and 1/4" and Tech Wire to motor. Make connection w/ ESP Power Cable to Motor connector, (Witnessed by CIE Electrician). Install 1st Cannon Clamp 1/4" Cap. 2/17/13 Splice Flatpack and Power Cable on 1st stand of 3 1/2" EUE Completion Tubing. RIH w/ 2nd Stand of 3 1/2" tubing, perform electric integrity test to the ESP, Discharge gauge not working. POH w/ both stands removing hardware, pulled up to discharge gauge, test failed. POH to pressure sensor to perform f • • troubleshooting process. Splice Connection, check Meg readings for "Grounding ", (Good), Check Resistivity, (Good). RIH w/ 3 1/2" Completion String, C/O each connection seal on 3 1/2" EUE 8rd, SLM and Rabbit each stand. Continue RIH with 3 1/2" EUE Completion String (stand # 24), SLM / Rabbiting / C/O Stand top connection seal. Tested every 1000' resistivity, meg for ground, and well lift..Tested flat . pack to 4500 psi. Present depth 5319'. 2/18/13 Continue RIH w/ 3 1/2" EUE Completion String / ESP Ass�r. Testing electrical resistivity, meg for grounding / well lift, test Flatpack to 4500 psi. Changing out ESP Power Cable Reels and R/U to restring. Splicing ESP Power Cable. Continue RIH w/ 3 1/2" EUE Completion String / ESP Assy. Testing electrical resistivity, meg for grounding / well lift, test Flatpack to 4500 psi at 1000' intervals, SLM stand # 109 and double in derrick = 10,276' shut down to calculate # of 3 1/2" EUE singles to P/U for spacing to 7" TOL one by one for Space Out. Depth of 3 1/2" EUE + ESP = 10,463' R/U J.A.M. (Torque Turn) to torque 3 1/2" Ph6 tubing Jt.x Jt.( torque value = 7000 -8000 ftlbs). RIH with 3 1/2" PH -6, torque every joint to 7 -8K ftlbs. Total depth @ 00:00 hrs.= 11,412' 2/19/13 Continue to RIH w/ ESP on 3 1/2" EUE & PH -6 Tubing. Testing every 1000'. Test Electrical resistivity, Meg for Ground, and well lift, test Flat Pack to 4500 psi, SLM, rabbit and computerized "Torque Turn" torque check. Every joint of PH -6 = 7 to 8K ft/lbs. R/U to P/U 4" PTECH landing joint, M/U tubing Hanger, position hanger to line up ESP Power Cable penetrator. Check up / Down weights. pump fluid level , down from BOP stack. Install ESP Power Cable BIW connection, Test Good, attach Hanger Penetrator, install control lines & 25 psi check valves below hanger, Lay down Landing Joint and Install Vetco Gray's BPV into top of Tubing Hanger. Blow down Choke, Kill & Mud Lines. Removed Drip Pan, Fill Up Lines, Pony Flow Line, Bell Nipple, Choke & Kill Line. Bled Koomey pressure 2/20/13 Continue to N/D BOPE, remove from Sub base and pumping out riser to prep for removal. Attempt to pull BPV, well "U' tubing up tubing, take returns out wing valve "U" Tubing ceased and BPV pulled, 2 WCV set. • '}Cook Inlet Energy_ RECEIVED JAN 0 3 20`-, AOGCC January 3, 2013 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Zc - \ Re: Withdraw Sundry #312 -486 Cook Inlet Energy, LLC: Redoubt Unit #7 Dear Ms. Foerster, Cook Inlet Energy (CIE) hereby withdraws Sundry #312 -486. A revised and current sundry to include new perforations and correct depths has been submitted. If you have any questions, please contact me at (907)- 433 -3804. SCANNED JUL 2 b 2012 Sincerely, ,_,,,,,_.72 - ( 7 / 64 - Le David Hall CEO - Cook Inlet Energy 601 W. 5 Avenue, Suite 310, Anchorage, AK 99501 (907) 334 -6745 * (907) 334 -6735 fax OF Tit • • �j,', THE STATE Alaska Oil and Gas Conservation Commission G OVERNOR SEAN PARNELL 333 West Seventh Avenue P. Anchorage, Alaska 99501 -3572 ALA0" Main: 907.279.1433 Fax: 907.276.7542 1 04 g 2Y1 David Hall .t t 5 CEO Inlet Energy, LLC 601 West 5th Ave., Suite 310 Anchorage, AK 99501 Re: Redoubt Shoal Field, Undefined Oil Pool, Redoubt Unit #7 Sundry Number: 312 -489 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. Sincere , e' K. ∎ , orman Com issioner DATED this 3 day of January, 2013. Encl. Ktio;Miv • STATE OF ALASKA • DEC 2 7 NV ALASKA OIL AND GAS CONSERVATION COMMISSION �'Grs' APPLICATION FOR SUNDRY APPROVALS RR..+�I►► 20 AAC 25.280 / 5t' 1 i.ij 42911— 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 ' Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate 0 • Pull Tubing 0 . Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: G' O 6-5 P Ei 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: VL ` COOK INLET ENERGY LLC Exploratory ❑ Development El • 203 -150 o t1-/ 24 j l'•-- 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 601 W. 5th AVE. SUITE 310, ANCHORAGE, AK 99501 50- 733 - 20526 -00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 20 AAC 25.055 REDOUBT UNIT #7 < Will planned perforations require a spacing exception? Yes ❑ No 0 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 381203 and 374002 " REDOUBT SHOAL UNDEFINED 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): 15,950' ' 12,332' < 15,870' 12,226' NONE NONE Casing Length Size MD TVD Burst Collapse Structural Conductor 215' 36" 215' 215' N/A N/A Surface 3,528' 13 3/8" 3,528' 3,088' 5,020 PSI 2,260 PSI Intermediate 14,049' 9 5/8" 14,049' 11,528' 6,870 PSI 4,750 PSI Production Liner 2,242' 7" 15,950" 12,332' 12,460 PSI 10,760 PSI Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 14,350'- 15,667' " 11,159'- 12,219' 3 1/2" P -110 13,445' Packers and SSSV Type: NONE Packers and SSSV MD (ft) and TVD (ft): . NONE 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program IS • BOP Sketch Q • Exploratory ❑ Stratigraphic ❑ Development 0 ' Service ❑ 14. Estimated Date for 1/10/2012 15. Well Status after proposed work: Commencing Operations: 011 IS ' Gas ❑ WDSPL ❑ Suspended p 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 Courtney Rust 907 -433 -3809 Email doudnev.ruste.cookinlet.net Printed Name David Hall, CEO Title J v ` D at ? 7/�0/6e Signature Phone e i ce / c,/ ., / j COMMISSION USE ONLY Con • . ns of approval: Notify Commission so that a representative may witness Sundry Number cn 2. Plug Integrity ❑ BOP Test Er Mechanical Integrity Test ❑ Location Clearance ❑ Other: ' O SO d S G D a G tv) r 7- C1 f ow h-3-1-- rc- t v/ `v ' � �f� I ,fat. b i 713 u ,{/ RQ/�� - ■ r c / C/ C f -1,-1 , p Spacing Exception Required? Yes ❑ - • equent Form Required: 1 U 4 0 4 V111�IS JAN 0 31013 / APPROVED BY Approved by: ' / OMMISSIO R THE COMMISSION Date: VISAS Submit Form and �`v t ::rti d o 01 L • . oved application is valid for 12 months from the date off approv- ,, Attachments in Duplicat e imi, . , ?:(13. ),), ,,1;.."..„ • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION / APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 ha A153AfeWrog ram ❑ Suspend ❑ Plug Perforations ❑ Perforate 0 . Pull Tubing 0 • Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: RU ESP IS . 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Cook Inlet Energy Development Ei . Exploratory ❑ 203 -150' 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 601 W 5th Ave., Suite 310, Anchorage, AK 99501 50 -733- 20526 -00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order govems well spacing in thi 20 AAC 25.055 REDOUBT UNIT #7 • Will planned perforations require a spacing exception? Yes ❑ No El 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL 381203 c.;,nc.1 3 7y Ob 9, ? i� 110�1. REDOUBT SHOAL UNDEFINED ' 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' 6,192' 6,192' 6,192' NONE Casing Length Size MD TVD Burst Collapse Structural Conductor 215' 36" 215' 215' N/A N/A Surface 3,528' 13 3/8" 3,528' 3,088' 5,020 PSI 2,260 PSI Intermediate 14,049' 9 5/8" 14,049' 11,528' 6,870 PSI 4,750 PSI Production Liner 2,242' 7" 15,950' 12,332' 12,460 PSI 10,760 PSI Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: ; Tubing Grade: Tubing MD (ft): 14,350'- 15,667' 11,159'- 12,219' 31/2" / P -110 13,445' Packers and SSSV Type: NONE Pac -rs and SSSV MD (ft) and TVD (ft): P. ker @ 13,630MD/11,140' TVD 12. Attachments: Description Summary of Proposal IS 3. Well Class after proposed work: Detailed Operations Program 0 ' BOP Sketch El ' Exploratory ❑ Development El • Service ❑ 14. Estimated Date for 10- Jan -12 15. Well Status after proposed work: Commencing Operations: Oil El • 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 the b — of my knowledge. Contact Courtney Rust 433 -3809 Printed Name David Hall, CEO Title 11/20/2012 Signature Phone Date ,,,,,,,,,,,... COMMISSION USE ONLY j Conditions of approval: Notify Commission so that . representative may witness Sundry Number: ) Z'' V1 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: N APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Form 10-403 Revised 1/2010 ORIGINAL Submit in Duplicate • • Cook Inlet Energy gY RECEIVED DEC 212012 December 21, 2012 AOGCC Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Additional Perforations and ESP Replacement Cook Inlet Energy, LLC: Redoubt Unit #7 Dear Ms. Foerster, Cook Inlet Energy (CIE) would like approval to change the approved Sundry 312 -438 for an ESP replacement to include adding new perforations at 15 412' -15 432'MD 1 _ • •'- 12,201' TVD) and 15,494'- 15,528' MD (12,217'- 12,224' TVD) on the Redoubt Unit #7 well iir hie edoiibt - Unit FieIO of Cook Inlet. Rig #35 will be used to complete this work over commencing approximately January 5, 2013. Attached please find a completed Form 10 -403, current and proposed wellbore schematics, Rig Drawing, a BOP configuration diagram, Sundry 312 -438. 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 • Table of Contents Rig #35 Schematic 4 Current Completion 5 Workover Procedure 6 BOP Sketch 9 Wellhead Schematic 10 • 0 Rig #35 Schematic , * alow 4' II maim 'A BIZ r at !i al tri i it . •. "wow i 1 wog go TII IF . Am am '. SIII Cit 1:0110 III Ilk LOW HOW MD WA k y t , 1 • 147 IT x XI FT prialli 1., , 0 1.4 Ok i =MIL . 11 " 4 I 11, I I M i N I Fr ' 1 4 t . r , , • 1 111rAllir i Le L - 1... a A . Tir '10,10,00 , a — at IT WA 1 . T.t . , .11riumummx, : ,, jairrw , use ppE . • ,.... it k - ' ' - - - - , 20 IT IC = : r A PH rlinp—mrlor .-.,,....., , 2Za it 1 - us • " 1 ° 17 °N - MI : i *;.. r... :,....":•: ;rse ammo _ 111 0 ...cfrSV fi,J c4,4V i * - II— m*Fcx 5 It2 ::■ ' Z I . „ ...... OSPREY ' ' i DRILLING RIG ARRANGEMENT — EAST SIDE corravnx. 04 .41:PifitiP" RW'.5.: WHO& VAC twwww vim vc ; ',.—...... TINKHNA. _ 1:. VW ] ovii LiKor. I . , • . 1 . . '' ' 7 AMIIIVINIIIIM...' 1 1 • • 0 Current Completion • • Redoubt Unit #7 Completion June, 2011 i ... E I 36 ". 150#, A -36, Welded Conductor @ 215' MD /2 151VD I1► 13 - /S . t,8a. L-80. BTC @ 3,528' MD / 3.088' TVD I i 9 100 jts of 3- 1/2" RTS, PH -6 Tubing and 4.53' PH -6 pup 334 jts of 3 -1/2 ". EUE Mod, i r 1 tl Centrilift ESP Top @ 13,506' MD i Centrilift ESP assembly BTM @ 13.596' MD Y *r Top of 7" liner @ 1 3,708' MD / 11 .262' TVD 9 -5/8 ", 47 #. L -80, BTC @ 14,049' MD / 1 1,528' TVD Perforations: i 14,350' - 14,424' 14,442' - 14,505' 14,535' - 14,580' ' I 14,610'- 14,635' 14,745' - 14,785' 14,840' - 14,955' 15.100'- 15.123' 15,340' - 15,383' 1 15,590' - 15,667' 3-3/8" guns. 6 SPF f r,.. 7 ", 32 #, P -110, Hydril 521 @ 15,950' MD / 12,332' TVD • 1 Workover Procedure Redoubt Unit # 7 ESP Completion Change out Summary Procedure November 2012 1. Move Rig 35 to RU #7. Fill pits with produced water. 2. Rig up and test lines. Bleed gas off of well and displace crude from RU #7 with produced water, taking returns to Kustatan via 6" gas/ test pipeline. Over - displace with 100 bbls water and shut well in. a. prepare cable spools and splicing kits. b. Check all drip pans are in place and sealed c. prep for crude oil - absorbs, rig wash, etc. 3. Check for flow, if well is not dead continue with additional displacement until it is dead. 4. Install BPV and N/D production tree. 5. Nipple up an d test 13 5/8" _BOPS to 4500 psi. Notify AOGCC_of intent to _ �..__ test 24 hours in advance . .. Pull Existing Completion. 6. Check for trapped pressure, then Pull BPV, Check well for flow. MU landing joint in tubing hanger and back out lock -down screws. 7. Pull tubing hanger. Remove ESP cable and control lines carefully from hanger. 8. Proceed pulling out the string slowly. Visually inspect connections and stand back tubing. Count bands. Monitor trip tank for proper hole fill up. 9. RIH and PT Casing to 2500 PSI. 10. Lay down ESP and inspect. Run New ESP • 11. If multiple bands or damps are missing from pump, Rig up wireline for a junk basket/ gauge ring run to pump setting depth. If necessary PU 6" mill and RIH on Tubing to push junk downhole. 12. Rig up Pollards eLine and Shooting nipple. 13. RIH with Halliburton 3 3/8" 6 spf casing guns. Correlate depth to gr log. Shoot from • 15,412' to 15,432' MD ( 12,196' TVD to 12,201' TVD) and 15,494'- 15,528' MD ( 12,217' TVD to 12,224' TVD). Check well for flow. 14. Pull out of hole with guns, rig down eLine. 15. Test and inspect new Centrilift ESP and new Phoenix tool before running in hole. 16. Pick up new Centrilift ESP completion and RIH. Test motor every 1000'. 17. Monitor trip tank for proper hole filling. Splice cable as needed. Test ESP cable every 1000' • 18. At TD ( +1- 13,600'),confirm pipe tally, MU Hanger and landing joint. Make penetrator connection. Perform final electrical checks. 19. Dress hanger and control lines. Land hanger, run in screws, test hanger to 5000 psi. 20. Lay down landing joint and install BPV. 21. Nipple down riser and BOPE. 22. Install production tree. Tum over well to production crew. Release Rig • Proposed Wellbore Diagram Redoubt Unit #7 Completion November 2012 4 ( J 36 ", 150#, A -36, Welded Conductor @ 215' MD /2 15 13 -3/8 ", 68 11, L -80, BTC @ 3,528' MD / 3,088' TVD a ` 100 jts of 3- 1/2" RTS. PH -6 Tubing and 4.53' PH -6 pup ' 334 jts of 3 -1/2 ", EUE Mod. . is p Iii i 1 :::::::::L3:::D13 .596' MD i p i , 1 t„, . ' . - :, 3 Top of 7" liner @ 1 3.708' MD / 1 1.262' TVD 9 -5/8 ", 47 #, L -80, BTC @ 14,049' MD / 11,528' TVD ■ Perforations: 14,350' - 14,424' 14,442' - 14,505' 14,535' - 14,580' (` 14,610' - 14,635' 14,745' - 14,785' 14,840' - 14,955' 15,100' - 15.123' 1 a cici ,_ 15,340' - 15,383' 90' - 15,667' p c r f5 3 -3/8" guns, 6 SPF 7 ", 32 #, P -110, Hydril 521 @ 15,950' MD / 12,332' TVD New Perforations: 15,412'- 15,432'MD (12,196'- 12,201' TVD) 15,494' - 15,528' MD (12,217'- 12,224' TVD) 0 • BOP Sketch , 7,3,2,311 5-2-12 "C.c BOP temat:c .:,'C'y "Rig Flour" Wn11: Ra1 KB Elevation Date: 5126/2012 ___L■L Measure dfstances front "Rio Floor' il 1_1.111111.11 1 lap Ct A1111.1nr • i l Te Hydril *- -/ Icerterilyrm — --* 1 13.5,0" 5k Aonular ' • • iiiil■ . _ 1 4.-- 13-5ari Ph Hydra I , ,____ 7.11[—- 4*CP tainv • I Ccnt-, a" gam: . s y. 11 GI ni Rams I 13 UV 13IHdr I .. . .. i 1 ___ c. H - a Irqr 11,0 M M. - _ - fiailW=i , ...... . _ K u 'no D Lankk 1 ht“ _A 1 gr in 77 I al l —.... :8"10k -Iv& MINOMP•I 13-5 III wi 4" DP ram Ce 4" %..rnr. --___, •=11111•11. 1 , , i= '‘,._ • ... I.. 13 508 10 V , 345.71 5K adaptor von! -e.rel " aid 13518' 64X 13 Ye" bk iisci a . I 1 . , ,,__ o.: . Center Lc c.109ril Svnowa 1 • 1 • • Wellhead Schematic REDOUBT UNIT #7 WELLHEAD SCHEMATIC a F- - - 24.3r IN hill ., ,..l1,.. 3 -1/8 5000 8068' '�. -' 1 F EN _y1 w 3 -1/8 5000 III- . inioini - - --a 1063' :11 N. :� p � n Illi;;Ili nI 13 -5 /8 5000 58X q H d p i r , SHOWN 90' OUT NENT PIN j p SNOW MI n � I �1 . 28.0 , OF POSITION 0 N =,�. IIlL l 2 -1/16 5000 W /VR :x . y l . �l� M I iiil S 10-5/8 68X I U ! �i• 111 1 y 2 -1/16 5000 W/VR 24.75- Ip 1 = i 1._i' x':111 1 4.1 :�,..:�11: I -' _, I 19.50 - I I ' • , 1 pi Lop 1 1 I 36" OD CASING III) a l � \ I 13 -3 /8 OD CASING 3 -1/2' 00 TURIN I 9 -5/8' O0,CASING ALL DIMENSIONS ARE APPROX. , °� T� ti'�' \ \� % %y: .?. THE STATE Alaska Oil and Gas bt 'FA °fA LAS KA Conservation . Commissi � ' 333 West Seventh Avenue A GOVERNOR SEAN PARNELL °1'. TM, /* Anchorage, Alaska 99501 -3572 LA 9� Main: 907.279.1433 Fax: 907.276.7542 RECEIVED David Hall DEC 1 2012 CEO Cook Inlet Energy COOK INLET 601 West 5th Avenue, Suite 310 ENERGY Anchorage, AK 99501 Re: Redoubt Shoal Field, Undefined Oil Pool, Redoubt Unit #7 Sundry Number: 312 -438 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. Sincerely, (;./86t )/ Cathy . Foerster Chair DATED this lay of December, 2012. Encl. • • • RECEIVED c Cook Inlet Energy Nov 19 2012 AOGCC November 19, 2012 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Cook Inlet Energy, LLC: Redoubt Unit #7 Dear Ms. Foerster, Cook Inlet Energy (CIE) hereby submits a sundry application to replace the ESP. It stopped working due to a downhole short. Also, attached are a completed Form 10 -403, current and proposed wellbore schematics, Rig Drawing, and a BOP configuration diagram. Rig #35 will be used to complete this work over commencing approximately December 1, 2012 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 RECEIVED STATE OF ALASKA NOV 19 2012 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well El Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing 5 Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: RU ESP S 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Cook Inlet Energy Development 5 Exploratory ❑ 203 -150 3. A ddress : Stratigraphic ❑ Service ❑ 6. API Number: 601 W 5th Ave., Suite 310, Anchorage, AK 99501 50 -733- 20526 -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 El REDOUBT UNIT #7 9. Property Designation (Lease Number): 10. Field/Pool(s): cs ADL 381203 .►.J 37' ►'P L 31 °1 REDOUBT SHOAL UNDEFINED 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth ND (ft): Plugs (measured): Junk (measured): 12,300' 12,300' 6,192' 6,192' 6,192' NONE Casing Length Size MD ND Burst Collapse Structural Conductor 215' 36" 215' 215' N/A N/A Surface 3,528' 13 3/8" 3,528' 3,088' 5,020 PSI 2,260 PSI Intermediate 14,049' 9 5/8" 14,049' 11,528' 6,870 PSI 4,750 PSI Production Liner 2,242' 7" 15,950' 12,332' 12,480 PSI 10,760 PSI Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 14,350' - 15,667' 11,159'- 12,219' 31/2" P -110 13,445' Packers and SSSV Type: NONE Packers and SSSV MD (ft) and ND (ft): Packer @ 13,630MD/11,140' ND 12. Attachments: Description Summary of Proposal 5 13. Well Class after proposed work: Detailed Operations Program 5 BOP Sketch MI Exploratory ❑ Development 0 Service p 14. Estimated Date for 1- Dec -12 15. Well Status after proposed work: Commencing Operations: OH S Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WIND ❑ 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 Courtney Rust 433 -3809 Printed Name David Hall, CEO Title NA V/; ,R 11/19/2012 Signature Phone ate 2-J igzi-e COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ° 12._-(13-s/ Plug In BOP Test Mechanical Integrity Test Location Clearance ❑ u9 e9 tY ❑ Integrity ❑ Other: n 0 r f-� o 0 .� 'r Q / � 7 /', Sfu h t 55 d h I t Flaw 1-1-5t 1'e T '''''' a ft 5 to b1/13-7-6 gy p)- a-/c'c -) . Subsequent Form Required: 10 44 _ / APPROVED BY Approved by: ( r ,� . �cLA — COMMISSIONER THE COMMISSION Date: /2 -7_ r / Z D U Submit in Duplicate • • Table of Contents Rig #35 Schematic 4 Current Completion 5 Workover Procedure 6 BOP Sketch 8 Wellhead Schematic 9 . • • Rig #35 Schematic . _ • ----...... .., CfA 4 11 _ A Ork 1 . i 4 v, wow a I I II1_ t \ wow to 1 _ \ jr■ la - . SID CA. DOM At \ 1.3 V 11130< talo i iv& zspr \ 7 , nat C V a: K \ 1 IT \ ML1 1 / fl W I j 4 \ 1\k' I \ , 1 \ \ . it I 1 I 1 1 I 1 ' I I , I ! 1 1 11 h Wil1TP115 E3 i'zje 1 ... It . — ..../...www, _-„e_Doct .!? E 4111 1 _..... _ , , ,... , __ 3 raw p s Ro ".. ; ilT " , _ _ 4 II rar NI 4 =----- f wuRto_RE = '!szinua simi.7-1., — _ ...,-_-_-.. I 011e. IIIMMINE Mi , - IN " MI ■ .'" ' ' ' ""- ' IMMO IMO IMMII UNIIIPUNIMINIMIN a l _ , M Ft.rnow C.soF BFAI . w-4.--.---ti- PPFKIX 5 1 FT - --- IIIII OSPREY 1 1 i il _ .... ------_, , DRILLING RIG ARRANGEMENT - FAST SIDE 6ppimAt. LC ' r" '-' -- ikoRHEts..... 111001/0. t.Ir 'rAst Kt4 , 77 I 2 thild 1MM , GSITLY EIRILLF4G RIG i , ViaROMM. II ' PM 4r i ' 1,14 III = INTAID , --- — - 1 _ — . • • Current Completion • • Redoubt Unit #7 Completion June, 2011 1 I ji 36", 15071, A -36, Welded Conductor ri N 215' MD /2 15TVD , ( ii 13 -38 ". 680, L -80, BTC @ 3.528' MD / 3.088' TVD I I k 100 jts of 3. 113" RTS, PH -6 Tubing and 4.53' PH -6 pop r ,i ° �t 334 jts of 3 -1/2 ", EUf_ Mod, s t tt i 44 .Y 1 r I 11 x21 ' 7t) t . I Y nn jl. 1 Centrilift ESP Top Cm 13,506' 1 MD vit . Centrilift ESP assembly BTM @ 13,596' MD j ' ,a, 1 t f" ' «'4 Top of 7" liner CN 13.708' MD / 11,26T TVD i 9 -5/8 ", 478, L -80, BTC @ 14.049' MD / 11.528' TVD Perforations: 14,350'- 14,424' 14,442' - 14.505' I 14,535'- 14,580' 14,610' - 14,635' Iiti■ 14,745' - 14,785' A try 14.840' - 14,955'- 15.100' - 15,123' "' 15,340'- 15.383' ':, 15,590' - 15,667' e' 3 -3/8" guns. 6 SPF E .1 ft 7". 328, P -110, Hydril 521 @ 15,950' MD / 12,332' TVD • • • Workover Procedure Redoubt Unit # 7 ESP Completion Change out November 2012 1. Move Rig 35 to RU #7. Fill pits with produced water. 2. Rig up and test lines. Bleed gas off of well and displace crude from RU #7 with produced water, taking returns to Kustatan via 6" gas/ test pipeline. Over - displace with 100 bbls water and shut well in. a. prepare cable spools and splicing kits. b. Check all drip pans are in place and sealed c. prep for crude oil - absorbs, rig wash, etc. 3. Check for flow, if well is not dead continue with additional displacement until it is dead. 4. Install BPV and N/D production tree. 45 - U £r5i b A5ed 44 4 5 ? a P 5. Nipple up and test 13 5/8" BOPs to 3 0 psi. Notify AOGCC of intent to test 24 hours in advance. Pull Existing Completion. 6. Check for trapped pressure, then Pull BPV, Check well for flow. MU landing joint in tubing hanger and back out lock -down screws. 7. Pull tubing hanger. Remove ESP cable and control lines carefully from hanger. 8. Proceed pulling out the string slowly. Visually inspect connections and stand back tubing. Count bands and clamps. Monitor trip tank for proper hole fill up. 9. Lay down ESP and inspect. '� / _ P T z5 S , Run New ESP (ra.S 10. If multiple bands or clamps are missing from pump, Rig up wireline for a junk basket/ gauge ring run to pump setting depth. If necessary PU 6" mill and RIH on Tubing to push junk downhole. 11. Test and inspect new Centrilift ESP and new Phoenix tool before running in hole. 12. Pick up new Centrilift ESP completion and RIH. Test motor every 1000'. 13. Monitor trip tank for proper hole filling. Splice cable as needed. Test ESP cable every 1000' 14. At TD ( +/- 13,600'),confirm pipe tally, MU Hanger and landing joint. Make penetrator connection. Perform final electrical checks. 15. Dress hanger and control lines. Land hanger, run in screws, test hanger to 5000 psi. 16. Lay down landing joint and install BPV. 17. Nipple down riser and BOPE. 18. Install production tree. Turn over well to production crew. Release Rig • Proposed Wellbore Diagram • Redoubt Unit #7 Completion November 2012 Al +.' 36", 1508, A -36, Welded Conductor @ 215' MD /2 15'TVD *i 1 " i t [Y i I 13 -3/8 ", 688. L -80. BTC C 3.528' MD / 3.088' TVD 1 100 jts of 3- 1/2" RTS. PH -6 Tubing and 4.53' PH -6 pup , l ° 1 1 A 334 jts of 3 -1/2 ". EUE Mod. 1 Or �7 ; .� , t ( 7 p p p '' ; � i Centrilin ESP Top Or 13.506' MD l ( , Centrilifl ESP assembly BTM @ 13,596' MD i ; V y ill Top of 7" liner @ 1170W MD / 11.262' TVD PI -, 9 -5 /8 ", 474. L -80, BTC @ 14.049' MD / 11.528' TVD f Perforations: 14,350'- 14.424' 14,442' - 14.505' x 14.535' - 14.580' " 14,610' - 14,635' rye 14,745' - 14,785' *s 1110..- 14,840' - 14,955' =' 15,100'- 15.123' 12 `- 15.340'- 15,383' 15,590' - 15.667' 1 j: 3 -3/8" guns, 6 SPE 1 7 ", 328, P -110, Hydril 521 Cn 15.950' MD / 12.332' TVD r • BOP Sketch 7i3r2012 5-2E-12 10i. BOP Schematic G'ev "Rig Floor" Wall: RU1 KB Elevation Date! 512612012 L■J Measure distances from "Rio Floor'' , k 1111 uultllln lop of Annular \, Hydril 'Center 11y3ril — —*.' 13.5!8" 5k Annular I Ail m !tr �o1 :5 iM �I 13- SRi "fak Hrdlil 1 . t Iwo 1 �� • •f'Dr' lama i Ccntcr a Ram: 1_ — h � 1 0 1 rt 1 13 EM" 101. Hy1.I -_ Mind Rune 1 Il I cantarHann, it ® I I 0 Ammo III 1 n in in :II- . V)-- 1 K111 I II1 '� rl [: nil 1 I it, RIl Ail I L! - N. 13-5x'8 "Wk 89dril I� I Itii 4" DP reran Cent_r4 "R;m: I _ s; - j. i 135 V x 1358 5K edaplur span) n lgrane? to Gros nd Level 13 F! e-• X 1:i VU" 5.k. u.cf n 1K w Y • - Lill ill! dll may u nr.i �. ,- Ccntor IlloW19elBwa 1 I 0 • Wellhead Schematic REDOUBT UNIT #7 WELLHEAD SCHEMATIC 24.31 - [! 11 ., a. . O 3 -1/8 5000 t 5 , a ::‘,. ,,:: 80.68" d ragil , 3 -1/8 5000 • �i, , . 11111 . - - --$ 1863" r.. II nry III I 0) 13 -5 /8 5000 68X IN dl ALIGNM SHDWN 90' ENT PIN OUT �� _ OF P05171011 28.00 X111 2 -1/I6 5000 WIWI )/ I al S I . ,, 13 -5 /8 5000 sax u"' t III �` 2-1/16 5000 W/ea 24.75' Ir.� .1._' 50 S�'+7�'1 , i - - : i l . ;r 0 19.50 l' iI op i 36" OD CASING + ', 13 -3 /B OD CASING 3.1/2" OD TOBIN 9 -5/8' OD,CASING ALL DIMENSIONS ARE APPROX. . Cook Inlet Energy RECEIVED DEC 3 12012 AOGCC December 31, 2012 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 L Re: Withdraw Sundry #312 -438 . Cook Inlet Energy, LLC: Redoubt Unit #7 SCANNED JAN 17 Z013 Dear Ms. Foerster, Cook Inlet Energy (CIE) hereby withdraws A.piorQved Sundry #312 -438. A revised and current sundry to include new perforations hiss been submitted. 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 • 0 F ��; c v THE STATE Alaska Oil and Gas °f A riS Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue 0 . Anchorage, Alaska 99501 -3572 ALAS � Main: 907.279.1 433 13 Fax: 907.276.7542 SCANNED ,AN 2 5 2 David Hall CEO Cook Inlet Energy - 1 St 601 West 5th Avenue, Suite 310 Anchorage, AK 99501 Re: Redoubt Shoal Field, Undefined Oil Pool, Redoubt Unit #7 Sundry Number: 312 -438 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. Sincerely, athy . Foerster Chair DATED this lay of December, 2012. Encl. • • c* /RECEIVED STATE OF ALASKA . . ALASKA OIL AND GAS CONSERVATION COMMISSION ti NOV 1 291 APPLICATION FOR SUNDRY APPROVALS �� 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 • Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing Q • Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: RU ESP El 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Cook Inlet Energy' Development 0 • Exploratory ❑ 203 -150` 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 601 W 5th Ave., Suite 310, Anchorage, AK 99501 50- 733 - 20526 -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 El • REDOUBT UNIT #7 • 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL 381203 ,wk,` 37 goo.z. 11l o I 5 S (12- REDOUBT SHOAL UNDEFINED 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' 6,192' 6,192' 6,192' NONE Casing Length Size MD TVD Burst Collapse Structural Conductor 215' 36" 215' 215' N/A N/A Surface 3,528' 133/8" 3,528' 3,088' 5,020 PSI 2,260 PSI Intermediate 14,049' 9 5/8" 14,049' 11,528' 6,870 PSI 4,750 PSI Production Liner 2,242' 7" 15,950' 12,332' 12,460 PSI 10,760 PSI Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 14,350'- 15,667' 11,159'- 12,219'. 3 1/2" P -110 13,445' Packers and SSSV Type: NONE Packers and SSSV MD (ft) and TVD (ft): Packer @ 13,630MD/11,140' TVD 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch El Exploratory ❑ Development El • Service ❑ 14. Estimated Date for 1- Dec -12 • 15. Well Status after proposed work: Commencing Operations: Oil 0 • Gas ❑ WDSPL p Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ p WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Courtney Rust 433 -3809 Printed Name David Hall, CEO Title /� //� 6/ / vt ; 11/19/2012 Signature Phone Date ''' , AO COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: J l 2 - V Plug Integrity ❑ BOP Test Mechanical Integrity Test , ❑ Location Clearance ❑ Other: tz 0 p / r t I 4-5-66- - 5 - 6 1 S I l✓ a f r iv Ms- sscc/ h- f 16 "f« 1 rc 1/ r-'• cI a itt I-- 5 ra bi 1i3iTc/ prO Chi Gt /o1- -) Subsequent Form Required: RRDMS 0 7 2017 1 y 404- APPROVED BY LL11iiVV�' DEC UC 0 7 !L Approved by: ( „ _ /,,( COMMISSIONER THE COMMISSION Date: 7 2 _7_7 Form 10 -403 Revised 1/2010 (!L B / Submit in Duplicate � 24 Zo ORIGINAL � % y e • • Cook Inlet Energy_ RECEIVED NOV 19 10IZ AOGCC November 19, 2012 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Cook Inlet Energy, LLC: Redoubt Unit #7 Dear Ms. Foerster, Cook Inlet Energy (CIE) hereby submits a sundry application to replace the ESP. It stopped working due to a downhole short. Also, attached are a completed Form 10 -403, current and proposed wellbore schematics, Rig Drawing, and a BOP configuration diagram. Rig #35 will be used to complete this work over commencing approximately December 1, 2012 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 • • Table of Contents Rig #35 Schematic 4 Current Completion 5 Workover Procedure 6 BOP Sketch 8 Wellhead Schematic 9 • • , . Rig #35 Schematic ... if ..41 aux d Is IMMO rd a 02 a P.2 0 tivi 0 • 7 1, )4. Ste A. COOK A go t to V tOX INV i iWA k Mk IP SEIBICX laA" 117.11: I i f s 14 FT I JO rr rAlakt ii . , ! ;Jr z i k ra 1 I a I I 1 L I I r ) I 3 rAll q A ,, 1\ is t I - it. I k 11 1 01100115 Aim I 7 ; If 0 1 it 11111111Wam ) . ' SICE , 9 eigir . la vity It x n Rai : r . I . , Una I 111 IS 1111.1.1.1. Igi AZ II II 1, , v.. itipflak 5 112 FI RAIC611 DIP BEM li I ; + OSPREY I „.....-- k: ----------- - .. DRILLING RIG ARRANGEMENT - EAST SIDE Stu ars PvatzerARY *NM VOORHEES .... TINKWN. APPROOL Ow0 0 MAW FS 41 z7 VIL MO III' MIK tilt RIV) t I VIM °SPICY DRILLING RIG =1111C:31111111111111111111111111111111=111111111111111•1111111110=71 ' • - e A _ ' NINO • • Current Completion • • Redoubt Unit #7 Completion June, 2011 j I 1 1 I 36 ". 150N. A -36, Welded Conductor @215'MD /215'TVD 13 -3/8 ". 68 #, L-80, BTC @ 3,528' MD / 3,088' TVD 100 jts of 3- 1/2" RTS. PH -6 Tubing and 4.53' PH -6 pup I 334 jts of 3 -1/2 ", EUE Mod, • a a { ■ k 1 1 ' .S I Centrilift ESP Top @ 13,506' MD Centrilift ESP assembly BTM @ 13.596' MD • s Top of 7" liner @ 13.708' MD / 11,262' TVD if- i' 9 -5/8 ", 47 #. L-80, BTC @ 14,049' MD / 11,528' TVD Perforations: 14,350' - 14,424' 14,442' - 14,505' 14,535' - 14,580' 14,610' - 14,635' 14,745'- 14,785' 14,840' - 14,955' 15,100 - 15.123' 15,340'- 15,383' 15,590' - 15,667' 3 -3/8" guns, 6 SPF 7 ", 32 #, P -110, Hydril 521 @ 15,950' MD / 12.332' TVD • Workover Procedure Redoubt Unit # 7 ESP Completion Change out November 2012 1. Move Rig 35 to RU #7. Fill pits with produced water. 2. Rig up and test lines. Bleed gas off of well and displace crude from RU #7 with produced water, taking returns to Kustatan via 6" gas/ test pipeline. Over - displace with 100 bbls water and shut well in. a. prepare cable spools and splicing kits. b. Check all drip pans are in place and sealed c. prep for crude oil - absorbs, rig wash, etc. 3. Check for flow, if well is not dead continue with additional displacement until it is de 4. Install BPV and N/D production tree. 5 cO r S� Gt 5 7vi P ✓ 5. Nipple up and test 13 5/8" BOPs to 3 00 psi. Notify_AOGCCofintent to test 24 hours in advance. Pull Existing Completion. 6. Check for trapped pressure, then Pull BPV, Check well for flow. MU landing joint in tubing hanger and back out lock -down screws. 7. Pull tubing hanger. Remove ESP cable and control lines carefully from hanger. 8. Proceed pulling out the string slowly. Visually inspect connections and stand back tubing. Count bands and clamps. Monitor trip tank for proper hole fill up. 9. Lay down ESP and inspect. / 64 r v G� Run New ESP ■ C a 5 h 9 �S 10. If multiple bands or clamps are missing from pump, Rig up wireline for a junk basket/ gauge ring run to pump setting depth. If necessary PU 6" mill and RIH on Tubing to push junk downhole. 11. Test and inspect new Centrilift ESP and new Phoenix tool before running in hole. 12. Pick up new Centrilift ESP completion and RIH. Test motor every 1000'. 13. Monitor trip tank for proper hole filling. Splice cable as needed. Test ESP cable every 1000' 14. At TD ( +/- 13,600'),confirm pipe tally, MU Hanger and landing joint. Make penetrator connection. Perform final electrical checks. 15. Dress hanger and control lines. Land hanger, run in screws, test hanger to 5000 psi. 16. Lay down landing joint and install BPV. 17. Nipple down riser and BOPE. 18. Install production tree. Turn over well to production crew. Release Rig • • Proposed Wellbore Diagram Redoubt Unit #7 Completion November 2012 i J s 36 ", I50#, A -36, Welded Conductor @ 215' MD /2 ISTVD y i i r 13 -3/8 ". 68#, L-80. BTC @ 3,528' MD / 3,088' TVD 1 00 jts of 3- I /2" RTS. PH -6 Tubing and 4.53' PH -6 pup a4 334 jts of 3 -1/2 ", EUE Mod, if i s`', Centrilift ESP Top @ 13,506' MD " Centrilift ESP assembly BTM @ 13.596' MD ' Top of 7" liner @ 13.708' MD / 11,262' TVD PIO 9 -5/8 ", 47#, L -80, BTC @ 14,049' MD / 11,528' TVD Perforations: 14,350' - 14,424' 14,442'- 14,505' 14,535'- 14,580' �. 14,610' - 14,635' 14,745' - 14,785' 14,840' - 14,955' 15,100' - 15,123' 15,340' - 15,383' 15,590' - 15,667' 3 -3/8" guns, 6 SPF 7", 324, P -110, Hydra 521 @ 15,950' MD / 12,332' TVD • • BOP Sketch 7i3r2O1 2: 5-2!-12 10=t 60r Schemave "Ri9 Fleur" Well: R1.11 KB Elevation Date' 5126/2012 _______ ____________ - 1 Measure distances (rani "Rig For 11 1111 11111111.11 lap af Aanthar • i -\ ___\.' Hydril ICerIter Idydril — ' \ 13.5r8" 61 Annular 1 mi.= ,n n _ MINIM . '-' ■ Mil 13-503"101.. Hvdtil 4'131' C.4rdcr 4 " Ram: - '[.._.;___ = . . I-- . — 0 ' ._ / Nolumen 1 3 LAI" 1 DV. HO r I • 4 11 DI ni itzms 4 =,, trarltnr 4 Infix II =Mill , e 4101g. •.„.... ill I 1 . .1 q. ip. , I 11 , II' w:11 HF 2 --6- 4111 l MB --4' C31151.4 ill 1 i,... MI M - \ . el i mil .... 11111 13-6/II"10k tivdrit 1 , _l_ lan' 4" OP ram, C...rqt2r a" RznIs •••••••••■•• - — ammo ■11.3 • ' 13 5 I." x 1.1,5"13 5K adaptor spool ... .. , niqta,C• ei■ G nu. nd Isycl 11 I 13 5.15'ek X 13 5/8" hit Mar in _Jr ll 1 , • um lIll IS 1 L . , Ccatar t404441 5614vr4 -41 1 1 * • • Wellhead Schematic REDOUBT UNIT #7 WELLHEAD SCHEMATIC is • 24.31' a L U •.11 ; .' 3 -1/8 5000 80.68' 1 i :I MUM iimi 1 • , Rr• 1 3 -1/8 5000 ., I I mom 18.63" � N+ • n _il f 9� l li 13 -5/8 5000 606 "' I AUGNMENT PIN SHOWN 90" OUT oh �. OF POSITION 28.00' .. 2 -1/16 5000 W /VR 1 2=1=1 t_ NS � 1 l . 13 -5/8 5000 68X iu : , li I 2 -1/16 5000 W/11,2 24.75 i ..1 —1 11 6 11 11. i 19.50 'e 1 1 36" OD CASING i ' :1' 13 -3/8` OD CASING 3 -1/2' 00 TURIN I 9 -5/8' OD .CASING ALL DIMENSIONS ARE APPROX. 9 _ • • .Ferguson, Victoria L (DOA) From: courtney Rust [courtney.rust ©cookinlet.net] Sent: Wednesday, December 05, 2012 2:01 PM To: Ferguson, Victoria L (DOA) Subject: RU7 MASP Victoria, RU7 MASP= (.445 reservoir pressure gradient -.1 psi /ft gas gradient) x TVD bottom perforation =(.445 psi /ft-.1 psi /ft)x 12,219' =4215 PSI Please note that this was the original reservoir pressure and some depletion has taken place but has not been quantified. Thanks! Courtney Rust Cook Inlet Energy Project Engineer Office- 907 - 433 -3809 cell- 907 - 350 -0091 1 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg I i DATE: August 11, 2011 P. I. Supervisor (1 FROM: Lou Grimaldi SUBJECT: No Flow Verification Petroleum Inspector Cook Inlet Energy Redoubt Unit #7 PTD #2031500 Redoubt Unit k1 A4 August 11, 2011; I witnessed the No -Flow test on Cook Inlet Energy (CIE) well Redoubt Unit #7 in the Redoubt Shoal Unit. I had been in contact with the Production supervisor Ray Chumley who arranged the test and flight to the platform today. Mike Murray and Greg Morey were on board to facilitate the test. When I arrived they were well prepared for the test. I arrived on the platform to find the well open to atmosphere. The tubing and annulus were tied together with hoses to a small drip pot upstream of a large American Meter Company residential style gas meter model AL -800 (serial #03D764869). This type meter only measures volume and a flow rate must be calculated by volume divided by time. This well is a packer -less completion requiring the IA to be monitored as well as the tubing. There were calibrated electronic transmitters with local digital readouts (0.1 psi incr.) used to normally monitor the tubing /annulus pressure. A' turn block valve downstream of the "Tee" directly before the Drip Pot/Meter was used to close the flow from the tubing /annulus to atmosphere /tankage for the buildup periods. As the IA and Tubing were tied together I used the IA transmitter exclusively for "well pressure" readings. monitored three equally -timed tests each consisting of shut -in and flow periods. During the tests the tubing pressure never rose above 4.2 psi and sustained gas flow was well below 60 scf /hour ( <1 scf /min indicated), with no fluid produced to surface. The following table describes these test periods: 2011-081 1 _No- Flow_RU -7_1g. doc 1 of 2 • • Time Pressure Flow Notes PSI (scf /hr) 1215 .5 <60 Flowing to Tankage Shut -in well 1230 2.0 Well Shut -in 1245 2.3 Well Shut -in 1300 22.3 Well Shut -in 1315 2.7 Well Shut -in 600 Open well to Meter/Tankage 1330 1.9 <120 Flowing to Tankage 1345 .6 <120 Flowing to Tankage Shut -in well 1400 1.2 Well Shut -in 1415 1.9 Well Shut -in 1430 2.5 Well Shut -in 1445 3.2 Well Shut -in 600 Open well to Meter/Tankage 1500 1.1 <120 Flowing to Bleed trailer 1515 .8 <120 Flowing to Bleed trailer Shut -in well 1530 2.0 Well Shut -in 1545 2.8 Well Shut -in 1600 3.5 Well Shut -in 1615 4.2 Well Shut -in 150 Open well to Meter/Tankage 1620 2.6 <120 Flowing to Tankage 1625 1.5 90 Flowing to Tankage 1630 .9 <90 Flowing to Tankage 1645 .7 <90 Flowing to Tankage 1700 .5 <60 Flowing to Tankage Conclude test The test was concluded at this point. I observed less buildup in the second and third shut -in tests and quicker bleed down in the second and third flow tests. This well appears to meet the criteria set forth for No -Flow status. 3 Attachments: RU -7 Displacement Meter Test Sheet Photo - RU -7 No -Flow meter Photo - RU -7 No -Flow meter -drip pot Non - Confidential 2011 -0811 _No- Flow_RU- 7_1g.doc 2 of 2 • a!-1 7 CI Zo 31 sco) • No F2-U,v rrs -r MI DISPLACE..ENT METER TEST `r' - ( i CUSTOMER PRODUCER OR � Np�i A l �-^ y��t LOCATION 0 Y DATE_ i / ©I t CITY R4 C.-I � ' STATE AK J METER TYPE At. cD COMPANY ' METER 1E,20 ATMOSPHERIC TEST c, CODE NO. SERIAL NO. PRESSURE • L S PERIOD -_ FROM T I a� TO 4 lap CARTRIDGE IN PROOF - OUT PROOF SER. NO. OPEN MID CHECK OPEN MID CHECK INDICATED FLOW RATE - CFH Soo N/A JC © .5Q 0 /v 1' / 6 0 FLOW RATE - ACTUAL CFH N IPt N/A p AT CORRECTION ^f 'p, - P. hJ /jT — �� AI p► /'i T - P CORRECTION ! '• T METDRIVE (CIRCLE ONE lOft. MOOR. l000ft. VOLUME OF TEST 20 40 100 200 N IR 1,,3 i ick, �.. ` -s >' AMBIENT TEMPERATURE DEGREES F '�ZQ N f fk 7O Cd I, (P? - C 0 TEST TIME SECONDS tu t* — NIA APPARENT PROOF r 7 NIA — ? PROOF CORRECTION TO BASE SO'F 4 R C /V / r# 4. , �j` D QS 46 Adm + . 'ago gc • PROOF GRUNTER - 1 CORRECTOR TYPE SER. NO. RANGE F _•F SERIAL NO. FRONT REM DATA AS FOUND CORRECT AS LEFT TE$T TEST TEST • A /! A R A M 4 d f _ATMOS. MICRO READING PRESSURE PSIG PRESSURE MICRO READING . . PRESSURE MICRO WITH Z TEMPERATURE TEMPERATURE MICRO. READING — REMARKS I. SERIAL 1 RECORDER TYPE- NG RANGE 1 4 CYCLE STATIC TEST THERMOMETER TEST AS FOUND AS LEFT AS FOUND • AS LEFT TEST REC. TEST REC. TEST REC. / T REC. . h N " / 1 INDEX READING R AVERAGE RATE BEFORE TEST AFTER TEST .. AVERAGE RATE AFTER TEST ,� BEFORE TEST • TIME ON BY -PASS DIFFERENCE PRESSURE OF GAS BY-PASSED TE MP. _ TOTAL GAS BY-PASSED 1 Pt BINDS OR WEAR DETECTED YES ❑ NO ❑ GAS BY- PASSED ADOEO TO INDEX YES ❑ NO ❑ REMARKS / derma. ^airy •1 :laei.tq so... f Q.r ^A.4, Ors., '!*, WITNESS !� ✓ `J R • II 1 . T 0 � tp t t 2 .- 0 o M i 40 ~ u i N - s ` i � ti L , e : --_,, , . .. ,.............„.„8 R (( 1 F J � t a A In :„, ,.....,.,....,7„:,..,„:, .....u.,„ .u,,.„.. :: a r 4 .F I id A '. -�"- 1« " ti 1 0 i tE'4. Sri�: I i< • STATE OF ALASKA 7[ 31 Boil ALASKA O1ND GAS CONSERVATION COMMISSION. REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon LI Repair Well LI Plug Perforations Li Stimulate Li Other L] ESP Changeout Performed: Alter Casing ❑ Pull Tubing Perforate New Pool ❑ Waiver ❑ Time Extension Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Numb M Name: Cook Inlet Energ Development ,$y 0 Exploratory iii 16 i 3. Address: 601 W 5th Ave., Suite 310, Anchorage, AK Stratigraphic Service ❑ 6. API Number: 99501 50- 733 - 20526 -00 .^ 0 ej 7. Property Designation (Lease Number): _ 8. Well Name and Number: ADL- 381203 37 foal *. U Redoubt Unit # 7 9. Field /Pool(s): Redoubt Shoal Undefined OIL 10. Present Well Condition Summary: Total Depth measured 15,950' feet Plugs measured None feet true vertical 12,332' feet Junk measured None feet Effective Depth measured 15,870' feet Packer measured 13630' feet true vertical 12,266' feet true vertical N/A feet Casing Length Size MD / TVD Burst Collapse Structural 215 36" 215' 215' N/A N/A Conductor Surface 3,528' 13 -3/8" 3,528' 3,088' 5,020 psi 2,260 psi Intermediate 14,049' 9 -5/8" 14,049' 11,528' 6,870 psi 4,750 psi Production Liner 2,242' 7" 15,950' 12,332' 12,460 psi 10,760 psi Perforation depth Measured depth 14,350' - 15,667' feet / _ :t **E0 JUL 2 8 r E 01 True Vertical depth 11,159' - 12,219' feet Tubing (size, grade, measured and true vertical depth) 3.5 ", 9.3# t P -110 13,506'MD 11,103 TVD Packers and SSSV (type, measured and true vertical depth) None 11. Stimulation or cement squeeze summary: R-PrE ' 't Intervals treated (measured): N/A ' ; ; ; ' : Treatment descriptions including volumes used and final pressure: Aiestb a thi 6.? roiiii. Csi i rmssion 12. Representative Daily Average Productroh or Inje Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 0 Subsequent to operation: 250 60 240 180 485 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory Development 4 Service ❑ Stratigraphic ❑ Daily Report of Well Operations Yes 15. Well Status after work: ONO 0 Gas ❑ 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 -078 Contact David Hall Printed Name David Hall Title CEO Signature 0 ✓ � ` 4 Phone 907 - 344 -6745 Date 7/4/0963 p RBDMS Form 10 -404 Revised 10/2010 Submit Original Only • • Cook Inlet Energy July14, 2011 Mr. Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite 100 Qtrr ! Anchorage, Alaska 99501 ` AfAii l ; ' LA an . (t;l drOUSSiOft RE: Report of Sundry Well Operations Cook Inlet Energy: Redoubt Unit #7 Sundry #: 311 -078 Dear Mr. Seamount, Cook Inlet Energy is submitting the Sundry Well Operations Report for the work performed on its RU #7 well located on the Osprey platform. The objective of the operation was to repair the well by pulling a failed ESP completion and replacing it with a new one. The operation was performed successfully and RU #7 is currently on production. 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, Cook Inlet Energy David Hall, CEO cc: N. Sachivichik - SolstenXP • • • Redoubt Unit #7 Completion June, 2011 , . V . ! 36 ", 150#, A -36, Welded Conductor @ 215' MD /2 15'TVD Vi 5G. 13 -3/8 ", 68 #, L -80, BTC @ 3,528' MD / 3,088' TVD fl 1 00 j ts o f 3- 1/2" RTS, PH -6 Tubing and 4.53' PH -6 pup )4% . ,s ' l 334 jts of 3 -1/2 ", EUE Mod, iS d 1 vie ;04 fir I Wit?; Centrilift ESP Top @ 13,506' MD ,: " ' Centrilift ESP assembly BTM @ 13,596' MD lo ! , Top of 7" liner @ 13,708' MD / 11,262' TVD 1 1 - Ssg "MN IIIIR ,, 9 -5/8 ", 47 #, L-80, BTC @ 14,049' MD / 11,528' TVD Perforations: 14,350' - 14,424' 14,442' - 14,505' 14,535' - 14,580' 14,610' 14,635' 14,745' - 14,785' 14,840' - 14,955' eirs■_ 15,100' - 15,123' I 15,340' - 15,383' 15,590' - 15,667' I II 3 -3/8" guns, 6 SPF Ai li . i l -Atk 7 ", 32 #, P -110, Hydril 521 @ 15,950' MD / 12,332' TVD • • Cook Inlet Energy_ Summary Report of Operations Cook Inlet Energy. — Redoubt Unit 7 Start Date: 21 May, 2011 Finish Date: 14 June, 2011 May 21, 2011 Rig move from RU -1A. Turn rig around. May 22, 2011 Move substructure. May 23, 2011 Rig Up and Nipple up BOPs. May 24, 2011 Rig up, Test BOP, Repair jack leg seal. May 25, 2011 Finish rig repairs. Pull tubing hanger. POH with completion tubing. May 26, 2011 POH with ESP. May 27, 2011 Pull ESP completion. Lay down ESP. May 28, 2011 RIH with LLC pulling tool. May 29, 2011 Lay down LLC valve, make up packer retrieving tool ,RIH. SolstenXP 1 of 3 • • May 30, 2011 POOH with SC -1 packer. May 31, 2011 Rig service, repair lights in work basket. RIH tag engage, and pull free packer, POOH with packer. Lay down packer and retrieving tool. Pull Wear ring. June 1, 2011 Test BOPE 250/3000 psi: accumulator test, pull test plug, set wear ring, rig down test assy, PJSM, pick up perf guns. RIH on stands, to 5365' , replace split hydraulic hose. June 2, 2011 RIH with guns on stands, pick up singles, rig up E -line, correlate.rig down E -line, drop setting ball, pressure up tubing 2750psi, guns fired, monitor well, static -POOH with guns. Lay down tubing. June 3, 2011 POOH with guns, laying down 45 singles, POOH racking back doubles PJSM. Lay down guns all shots fired. Pull wear ring, ready to run new ESP completion. June 4, 2011 Rig up to run new ESP completion, PJSM, Pick up make up sections new ESP, test capillary lines 2500 psi, make first splice. June 5, 2011 Make cable splice half way on first joint. Test good. Start in hole, difficulty with cannon clamps - Wrong clamps for PH -6 tool joints, Wait on orders, (look for options with clamps and for new completion string.) Monitor well, prep for back load. June 6, 2011 Wait on orders, housekeeping and cleaning decks, backload boat, take on potable water and drill water, cleaning, pull and rack back 2 stands PH -6 tubing. Continue cleaning, prepare for receiving tubing. June 7, 2011 Housekeeping and scrubbing, Prep for receiving tubing. Offload 175 joints 3 -1/2 "tubing, rack and strap, Pick up tubing, test cable every 1000'. SolstenXP 2 of 3 • • June 8, 2011 Crew change, service and fuel equipment, Pick up tubing, making cable test every 1000'. Change cable spool, make cable splice and test the same. Continue picking up tubing to 8820'. June 9, 2011 Service equipment, strap another row of pipe continue picking up 9.3# L80 tubing. Test every 1000' ESP and cable. Monitor well, general housekeeping (waiting on clamps) clamps arrive in batches run stands. June 10, 2011 Crew change and service equipment. Prep hanger, make cable splice to hanger and connect chemical lines (All test's on cable and chemical lines good) land hanger test void, nipple down BOP. June 11, 2011 Wait on tree bonnet - lay down tubing racked back in doubles, prep for backload, and gather pumping iron from wellhead room. Cleaning and housekeeping. Backload boat with tubing and other equipment. June 12, 2011 Attempt test on tree bonnet, work to get good test. @0400hrs got good test to 5000psi hold 15 min. / Assemble and nipple up tree. Test 5000psi for 15 minutes good test, rotate surface and organizing equipment and decks. June 13, 2011 Cleaning decks and unit. Continue cleansing pits. Pressure wash window and substructure. Remove ram blocks clean inside BOP, disassemble mud cross valves. Remove shaker to clean shaker tank. June 14, 2011 Rig down CUDD Unit # 138. The end of RU -7A operations. SolstenXP 3 of 3 • • p etro l eu rn F REL SUBStR /7 (-' 1/1/ S Home A +d:erticin 5ubscrFptions Publications http://www.petroleumnews.com/pnads/742909650.shtml Vol. 16, No. 29 Week of July 17, 2011 Providing coverage of Alaska and northern Canada's oil and gas industry 2nd well goes into production on Alaska's reborn Osprey platform Z3 .) ° °Y-1b Osprey's revival continues. Anchorage -based Cook Inlet Energy LLC, the operator of the offshore platform in Alaska's Redoubt unit, has succeeded in bringing a second shut -in well back into production. The RU -7 well is the second to be activated recently on the Osprey platform, which was in "lighthouse mode" when Cook Inlet Energy and parent company Miller Energy Resources Inc. of Tennessee acquired it out of bankruptcy in late 2009. Using a light rig known as a hydraulic snubbing unit, Cook Inlet Energy performed a workover of RU -7 that included replacement of an electric submersible pump and wellbore optimization. "The RU -7 well has demonstrated an initial production of 250 barrels of oil per day, which more than doubled the projected flow rate of 120 BOD," Miller Energy said in a July 7 press release. RU - 1 production in June 1141 u�l�� 011 In June, Cook Inlet Energy brought the RU -1 well onstream at a rate of about 350 barrels per day. The company has big plans for Osprey, the newest and southernmost of the offshore platforms in Cook Inlet. A $17.9 million rig is under construction in Houston for the platform, and Cook Inlet Energy hopes to have it installed and drilling by year's end. • • David Hall, the company's chief executive, has told Petroleum News the first order of business is drilling four sidetracks off existing but damaged Osprey wells. Beyond this, Hall has identified 13 potential new wells from the platform. Production from Osprey and the Redoubt unit, the heart of which is the Redoubt Shoal field, goes to the shore -based Kustatan production facility on the west side of Cook Inlet. "I am pleased with the successful rework of the RU -1 and RU -7 wells and the restart of the Osprey platform and Kustatan production facility," said Scott M. Boruff, Miller Energy chief executive. Reactivating the two wells "is only scratching the surface of the enormous potential" of the Redoubt Shoal field, Boruff said. — Wesley Loy • • Page 1 of 2 Regg, James B (DOA) From: Regg, James B (DOA) g ( G51( Sent: Friday, June 03, 2011 1:29 PM It JJ To: 'David Hall' Cc: ray.chumley @cookinlet.net; Foerster, Catherine P (DOA); Aubert, Winton G (DOA) Subject: RE: RU -7 no -flow test I spoke with Commissioner Foerster about the no -flow test for Redoubt Unit #7 (PTD 2031500) and she asked me to send the following message. The Alaska Oil and Gas Conservation Commission (Commission) approved Sundry 311 -078 on March 23, 2011 for Redoubt Unit #7, authorizing CI Energy to pull tubing, repair the well, and reinstall a packerless electric submersible pump (ESP) completion. Conditions of approval for Sundry 311 -078 require CI Energy to perform a no -flow test before the new ESP completion is run in the well. The required no -flow test is intended to determine if Redoubt Unit #7 is unable to flow hydrocarbons unassisted to surface and should be representative of actual stable well producing conditions at the time the test is conducted. This is offficial notice to CI Energy that the approved Sundry 311 -078 is being CORRECTED to require the no -flow test to be performed as follows: CI Energy must perform a no -flow test per 20 AAC 25.265(k) after stable producing conditions have been demonstrated in Redoubt Unit #7. The Commission must be provided notice for opportunity to witness the no -flow test. Refer to Industry Guidance Bulletin 10 -01 for proper notification procedures. Industry Guidance Bulletin 10 -04 provides additional details about the no -flow test procedure and associated equipment. Both guidance bulletins are available on the Commission website at http: / /doa.alaska.gov /oqc /bulletins /bulletindex.html. A passing no -flow test will allow CI Energy to operate Redoubt Unit #7 without a production packer and subsurface safety valve. CI Energy may perform whatever diagnostics - including preliminary no -flow tests - to satisfy itself that the well will not flow and give confidence in committing to the planned completion. However, the Commission considers the test as noted above - after stable producing conditions have been demonstrated - to be the official no -flow test that determines if the well may be completed without a production packer and subsurface safety valve. The Commission does not require CI Energy to provide a new 10 -403 (Application for Sundry Approval); a copy of this notice will be place in our official well file. Jim Regg Inspection Supervisor AOGCC tt�� 333 W.7th Avenue, Suite 100 "i JU U I Anchorage, AK 99501 907 - 793 -1236 From: David Hall [mailto:david.hall @cookinlet.net] Sent: Thursday, June 02, 2011 2:23 PM To: Regg, James B (DOA) Cc: ray.chumley @cookinlet.net; 'David Hall' Subject: RU -7 no -flow test Jim, From my understanding you and Ray have had some dialog in regards to RU -7 no -flow test, I have attached the approved Sundry for RU 7 that states the no -flow test to be performed before the new ESP completion is ran. Also you will notice on the attached procedure between step number 23 and 24 Winton has required the No Flow test to be performed before running the new completion. 6/3/2011 Page 2 of 2 • RU -7 historically has had approximately 70% to 75% water cut under normal flowing conditions. Currently CIE plans to uphold and follow the approved Sundry #311 -078 and perform the no- flow test before running the new ESP completion as specified in the SUNDRY unless otherwise officially notified by AOGCC of any such changes. We will be re- perforating today and plan to conduct the no -flow test tomorrow prior to running completion on Saturday, June 4. CIE is respectively notifying AOGCC to witness the no -flow test tomorrow June 3. I and is not weighted RU -7 well currently is loaded produced water a d s of up . We believe the wellbore conditions while performing prescribed stipulated the rescribed no -flow test as sti ulated in the SUNDRY would be similar to normal production. Also, it was noted that the well did not take any fluids post pulling the LLC. Regards, David X Cook Inlet Energy logo David Hall Cook Inlet Energy, CEO 601 West 5th Avenue, Suite 310 Anchorage, Alaska 99501 Main Phone: 907 - 334 -6745 Direct phone: 907 - 433 -3804 Fax: 907 - 334 -6735 Cell: 907 - 317 -8239 david.hall @cookinlet.net 6/3/2011 • Aubert, Winton G (DOA) From: Bill Penrose [bill @solstenxp.com] Sent: Friday, May 27, 2011 10:54 AM To: Aubert, Winton G (DOA) Cc: 'David Hall'; Natasha Sachivichik Subject: Re -perfs In RU #7 '2 [ Co Winton, Cook Inlet Energy is currently working over Well RU #7 under the auspices of approved Sundry No. 311 -078. CIE proposes to add the following scope to the work previously approved: After the LLC valve and associated packer are retrieved from the well, the following intervals will be re- perforated: 14,350' — 14,424' 14,442' — 14,505' 14,535' — 14,580' 14,610' — 14,635' 14,745' — 14,785' All of these intervals were previously perforated and no new intervals will be opened during the proposed re- perforating operation. Regards, Perru 4e Vice President / Drilling Manager A JUN ( 1 201 SOL.STEN 'P 310 K Street, Suite 700 Anchorage, Alaska 99501 Main 907 - 279 -6900 Direct 907 - 264 -6114 Cell 907 - 250 -3113 1 Page 1 of 1 • • Aubert, Winton G (DOA) From: Aubert, Winton G (DOA) g0 lsa Sent: Tuesday, April 12, 2011 3:28 PM To: 'Bill Penrose' Cc: DOA AOGCC Prudhoe Bay Subject: RE: Variance Request Bill, Pursuant to 20 AAC 25285 (h), alternate BOPE is approved, as described below. Winton Aubert AOGCC 793 -1231 From: Bill Penrose [mailto:bill @solstenxp.com] Sent: Tuesday, April 12, 2011 3:24 PM To: Aubert, Winton G (DOA) Cc: osprey.drilling @cookinlet.net; Natasha Sachivichik Subject: Variance ance Req tot, w a pR 4 2 U1 Winton, Cook Inlet Energy requests a variance, per 20 AAC 25.285(h), from the provisions of 20 AAC 25.285(c)(9) (A) for the purposes of working over wells at Redoubt Unit from the Osprey Platform. These wells are to be worked over using a Cudd hydraulic workover unit and a 5,000 psi WP BOP stack with 2- 1/16" outlets on both the choke and kill sides. While the cited regulation requires a nominal outlet of at least three inches on the choke side, the wells at Redoubt Unit are of such low pressures and rates that a 3" or greater outlet on the choke side would not offer substantially better well control capability than the existing 2- 1/16" outlet. Attached find a diagram of the BOP stack proposed for use. Please let me know if additional information is needed. Regards, Vice President / Drilling Manager P 310 K Street, Suite 700 Anchorage, Alaska 99501 Main 907 - 279 -6900 Direct 907 - 264 -6114 Cell 907 - 250 -3113 4/14/2011 • • Cook Inlet Energy Page 1 RU -1 BOP Stack Design Worksheet.xls ?t*7 3 (S 0 O t4 t1 Cudd HWO -138 J m c(l (ZI 2-Q li Redoubt Unit - 3 13 5/8" 5K BOP Stack UP Ri: Floor 1 M : °�,* Hydril "GK" l I 4 rr Fill 1∎ ®■ el-D.,) �1 ' El 5M 44 WV.14 41 ua _ 2 1/16" valve a Mud Cross is w 1IC R 2 1/16" valve E 3 518" 5000# 1 r ' ^ - 5 gWH APR I2 LU i NS_11/13/09 • SIZIfEE AELASEA 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 David Hall CEO �� Cook Inlet Energy ado 3 .. /!, 601 W 5th Ave., Suite 310 Anchorage, AK 99501 Re: Redoubt Shoal Field, Undefined Pool, Redoubt Unit #7 Sundry Number: 311 -078 Dear Mr. Hall: ' MAR FZf it 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. Si ' erely 1y Jo or om,' is '.ner DATED this liday of March, 2011. Encl. • . ' ` Cook Inlet Energy_ ECE March 14, 2011 ��l4SSIOt! ��4St8� Mr. Dan Seamount, Chair Alaska Oil and Gas Conservation Commission 4i�,sk8 °I 81 6 8S 333 W. 7 Avenue, Suite 100 Anchorage, Alaska 99501 -3539 Re: RU #7 ESP Repair Dear Mr. Seamount, The Electric Submersible Pump (ESP) in the Redoubt Unit #7 well has failed and was left in place in 2008. Cook Inlet Energy plans to remove a 2" coiled tubing with jet pump from existing 3.5" production tubing and then use a Cudd Snubbing Unit to pull the ESP assembly and run a new assembly as outlined in the attached summary repair procedure. • Also attached are a completed Form 10 -403 for the work, a current wellbore schematic and a BOP configuration diagram for the snubbing unit to be used. If you have any questions, please contact N.Sachivichik at SolstenXP at 264 -6116. Sincerely, Cook Inlet Energy David Hall, CEO A tal ,, e ' /e Attachments: 10 -403 Application for Sundry Application Outline Procedure Completion Schematic — RU #7 11" 5M BOP Schematic Snubbing Circulation Schematic Snubbing Equipment Layout • 3/z /Lail 3 ' 1. 0 z. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 �i�age Approved Program ❑ Suspend El Plug Perforations ❑ Perforate ❑ Pull Tubing El • � C, � Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: pm. b... ES P [r 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Cook Inlet Energy Development 0 • Exploratory ❑ 203 -150 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 601 W 5th Ave., Suite 310, Anchorage, AK 99501 50- 733 - 20526 -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 D Redoubt Unit # 7 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL- 381203 Redoubt Shoal Undefined - 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): 15,950' • / 12,332 • 15,870' 12,266' Pkr w/ LLC © 13,630' None Casing Length Size MD TVD Burst Collapse Structural Conductor 215 36" 215' 215' N/A N/A Surface 3,528' 13 -3/8" 3,528' 3,088' 5,020 psi 2,260 psi Intermediate 14,049' 9 -5/8" 14,049' 11,528' 6,870 psi 4,750 psi Production Liner 2,242' 7" 15,950' 12,332' 12,460 psi 10,760 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: / Tubing Grade: Tubing MD (ft): 14,350' - 15,667' 11,159' - 12,219' 3 -1/2" P -110 13,445' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): / Baker SC -1 pkr w/ LLC valve Packer @ 13,630'D /11,104' TVD 12. Attachments: Description Summary of Proposal EI 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Development El • Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Apr -05 -2011 Commencing Operations: 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 the best of my knowledge. Conta t N.Sachivichik 575 -7156 Printed Name David Hall Title CEO �>/ Signature / XI -' � -„ / 7 , iePhone 344 -6745 ate )7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 Plug Integrity ❑ Tj ,�1 -t BOP Test� I V Mechanical Integrity Test ❑ Location Clearance ❑ RECEIVED L Other: •G St L7 N 0 € to �7 0 0O ....1 ' Aocz Lc_- t,4�{ "do - Flow Tts�" rtt,wi.vcd prid✓ €0 Yu kt.wt.Ke t li fie SSS \{ re ,,ci,ve &lo - Flow T. ' S . Alaska (I & 6as Coosa Commission Subsequent Form Required: t 0 - (( 0 c-1 • / '�st� ora O / f APPROVED BY j ot Approved by: OMMISSIONER THE COMMISSION Date: 3'2.3 ' 1 3. / Form 10 -403 Revised 1/2010 ORIGINAL RBDAAS MAR 2 2 20 : i'1i Duplicate , • . x � Cook Inlet Energy_ Redoubt Unit # 7 ESP Completion Change out Summary Procedure Coiled Tubing Removal and Cudd Unit Mobilization and Rig Up 1. Prepare platform camp to support crew. Total people on board will be approximately 35. 2. Perform any needed maintenance /repair work on cranes to prepare for supply boat transfers and well -work support. 3. RU CTU and pull coiled tubing and jet pump. 4. Bring Cudd crew aboard (before hydraulic workover unit arrives) and prepare deck for rig. 5. MU piping to displace RU #1. Pressure test piping to 3,500 psi. Bleed off gas from tubing and casing. 6. Displace crude from RU #1 with produced water, taking returns to Kustatan via 6" gas /test pipeline. Over - displace with 100 bbls water and shut well in. 7. Install BPV and N/D production tree. 8. Bring Cudd Unit aboard and rig up over RU #1. Nipple up 13 5/8" 5M riser, 11" 5M flow cross and 13 5/8" BOP stack. 9. Notify AOGCC of intent to test in 24 hours. 10. Test BOPE to 3,000 psi with AOGCC witness. i 11. Finish rigging up Cudd unit over RU -7 and function test all parts. Install absorbent pads around working area. • • Cook Inlet Energy_ Pull Existing Completion 12. Pull BPV, MU landing joint in tubing hanger and back out lock -down screws. 13. Prepare cable spools and splicing kits. 14. Pull 3" BPV 15. Pull tubing hanger. Remove ESP cable and control lines from hanger. 16. Proceed pulling out the string slowly. Monitor trip tank for proper hole fill up. 17. Lay down ESP and inspect. 18. Rig up wireline for a junk basket/ gauge ring run 19. RIH with wireline to retrieve the LLC valve set in Baker Retrieva SC -1 packer at 13,630' MD. 20. Run junk basket/ gauge ring. POOH. Rig down wireline. 21. RIH with work string and packer retrieving tool. Retrieve the Baker Retrieva SC -1. 22. Make a cleanout trip as necessary. 23. Test and inspect new Centrilift ESP and new Phoenix tool before running in hole. .�--- /Jo - r(o w 24. Pick up new Centrilift ESP completion and RIH. Test motor every 1000'. ("16A 25. Monitor trip tank for proper hole filling. Splice cable as needed. Test ESP cable every 1000' 26. At TD, confirm pipe tally, MU landing joint and set string in window slips. 27. Dress hanger and control lines. Land hanger, run in screws, test hanger to 5000 psi. 28. Lay down landing joint and install BPV. 29. Nipple down riser and BOPE. Rig down snubbing unit. 30. Install production tree. Turn over well to production crew. • . - Redoubt Unit #7 Completion March 2008 updated 5/4/09 r- 36 ", 150 #, A -36 Welded Conductor @ 215' MD /215' TVD Nine gas lift mandrels: #1 - 3031' #2 -5274' ( 9 ) 43 - 7038' MN- #4 - 8382' #5 - 9488' � #6 - 10,265' 11 ` 13 -3/8 ", 68 #, L -80, BTC @ 3,258' MD/3,074' TVD #7 - 10,874' v #8 - 11,474 #9 - 12,131' 431 jts 3 -1/2 ", RTS, PH -6 Tubing Coiled tubing w/ sliding sleeve and jet pump Pkr & tailpipe assy 13,218' - 13,244' MD Tbg perfs 13,249' - 13,261' MD Fish #2 (Pkr & tailpipe assy) 13,300' - 13,341' MD Fish #1 (Pkr & tailpipe assy) 13,341' - 13,383' MD 4 m Tbg perfs 13,361' - 13,373' MD Centrilift ESP assembly @ 13,526' MD j LLC valve set in Baker Retrieva SC -1 packer at 13,630' MD Top of 7" Liner @ 13,708' MD/11,262' TD 9-5/8", 47# L-80, BTC @ 14,049' MD /11,528' TVD Perforations: 14,350' - 14,424'. 14,442' - 14,505' 14,535' - 14,580' 14,610' - 14,635' 14,745' - 14,785' - -L 14,840' - 14,955' e 15,100 - 15,123' 15,340' - 15,383' r4 15,590" - 15,667' 3 -3/8" guns, 6 SPF 7 ", 324, P -110, Hydril 521 @ 15,950' MD/12,332' TVD • • ` Cook Inlet Energy_ q Pull Existing Completion P 12. Pull BPV, MU landing joint in tubing hanger and back out lock -down screws. �f 13. Prepare cable spools and splicing kits. fr° 14. Pull 3" BPV 15. Pull tubing hanger. Remove ESP cable and cc fitrol lines from hanger. 16. Proceed pulling out the string slowly. Mo4fitor trip tank for proper hole fill up. f ' 17. Lay down ESP and inspect. 18. Rig up wireline for a junk basket/ gauge ring run 7 19. Run junk basket/ gauge rig. POOH. Rig down wireline. 20. Test and inspect new 9/e ntrilift ESP and new Phoenix tool before running in hole. s 21. Pick up new Centrilift ESP completion and RIH. Test motor every 1000'. °' 22. Monitor tri tank for proper hole filling. Splice cable as needed. Test ESP cable every 1000' 23. At TD, c¢nfirm pipe tally, MU landing joint and set string in window slips. 24. Dress hanger and control lines. Land hanger, run in screws, test hanger to 5000 psi. 25. /Lay down landing joint and install BPV. i 26. Nipple down riser and BOPE. Rig down snubbing unit. 27 Install production tree. Turn over well to production crew. • • SWOP& in • 1 340kJackUnit Cook Inlet Energy. Well RU -7 Lift Cap:340,000 Snub 0:170,000 Cudd Pressure Control, Inc. Rotary ap:9,700ft/lbs Proposed Rigup Illustration 11" Bore Witho Rig on Location 4 A I■I'Li °I �� I � I 03- 14 -11, not to scale .. .,...,....1... L ,_ , ...:Iv.... ... , 'N .1 =emu / ' 340k Jack Unit 288" � �� A �� Snub Unit & Work Basket > p — 1 i IP - e r� K : :.1::::: Eleva ' on 1� M 845.61"(70.46') 130.8" I II Ell ■ Work Window 11" 5M BOP Stack Elevation 653.60° (54.46') ''��`' Swivel Spool 11" 5M 29" Drilling Spool 11" 5M % " > f E��- 1141ll) / T ` 2" 1 Q2 0111411111 2" Line Annular BOP 11" 5M 23.5" 4" Flow Line to Mud Pits , !. with Cias Detector & Flow Meter lin 45.2" 3 Y2" Pipe Ram, 11" 5M 55.8" Blind /Shear Ram 11" 5M 1 -7 :4 1 11 'j Flow cross 11" 5M 23.5" 11 01 , ,TI II; 3%2" Pipe rams 11" 5M 33.8" . 411 ■ 24 Top Deck Top Deck 36 5' Spool, 13 -5/8" X 11" 5M / 72" 6' Spool, 13 -5/8" 5M Elevation 192.7" (16.06') ■ 84" 7' Spool, 13 -5/8" 5M Bottom Deck Bottom Deck Well Head • • C nn D Cook Inlet Energy _ .:::: rv rrrn x Proposed Eqipment Layout for Hydraulic Operations on RU -7 Tool Container �� 8'x10', 12k Productio v Equipment � N �� , . ., ,; .... ,,.� ,. A . i , 1 „,.., , .. A i 1 @ . .\ g- 6 I �'\ ., .,'. 1 0 .„ 140' s _i:_ � �_,, Al � g Bn 16 i e g ! .r �� . ' _ 1 , � ' Z S'4 rn ' �I y r g N N s 735310 CU X U - O _,...NI , FI -F I . a-- . L______ ° L ,. ,,, iiprill 01 , --,____. p ,..,, A B ll -° Vill. IIIIIIIIry II111111 I i °l!:nn �i► r . . ti • I II ilIII :IIIIIIII s— :r 110' • • rBD1 1 • plilcsurojsrttra 340k Jack Unit Cook Inlet Enerev Lift Cap:340,000 Snub Cap:170,000 Cudd Pressure Control, Inc. Rotary Cap: 9,700ft/lbs Proposed Rigup Illustration 11" Bore r I Without Rig on Location A w v_. IC ■III■! _AII Standpipe g 1 i Mud/Gas Separator 340k 288 , .. Jack Unit Snub Unit & Work Baet --> NI /1 • I I • - 1 1J . il I I I C . - ■ ` , P 1: 1 100 bbl Mud Tank Elevation - .I - - 886.6' (73.88') 130.8„ ■II ll E Work Window - > Elevation ' .. 693.88" (57.82') 11:. 11" 5M BOP Stack 24" _ Swivel Spool 11" 5M 23.5" 4" Flow Line o n ud Pits / > 111, !,:I�IIC[I[ 2" 15W Weco Fill Line Drilling Spool 11" 5M with Gas netect & 1ow Meter + Annular BOP 11" 5M 45.2" 55.8" ' 3 %" Pipe Ram, 11" 5M — _ ' ' ". -11— _j Blind /Shear Ram 11" 5M BI e' Off 23.5" - 1 [WV , ', -,11 1'11. , 11 -;11 Flow cross 11" 5M v u'd Blow Down Line ! k-3 1 kl 3%2" Pipe rams 11" 5M ro to 1B) 33.8" k2 � c -t c-2 10 M Pump > > k� Kill Line + Choke Line c -3 Man�gld F Blow Down Lin Blow Down Line . 2 — Top Deck • p Deck r 1>6 ' ■ IL ]OMCYwke = •f P7) Manifold '�� 7' Spool, 13-5/8" 5M _ Choke Line 84 c-6 • x a 192.7" (16.06') , �� M _ b x c -9 c -5 10' Spool, 13 -5/8" 5M i l20 Bottom Deck Bottom Deck Well Head Page 1 of 1 Aubert, Winton G (DOA) From: Natasha Sachivichik [ natasha .sachivichik @solstenxp.com] Sent: Friday, March 18, 2011 12:15 PM To: David Hall; Aubert, Winton G (DOA) Cc: Bill Penrose; WMRU Drilling Foreman Subject: RU -1 and RU -7 no-flow verification tests required by AOGCC David, I talked to Winton at AOGCC earlier this morning and Winton mentioned that we need to plan to conduct a no -flow verification test after the old tubing and ESP is pulled out and after the cleanout run. The no -flow test will be done to verify the wells are still not capable of flowing to surface on their own. The tests will be witnessed by an AOGCC representative. If the no -flow tests show wells are capable of flowing to surface, we need to include a SSSSV valves in the tubing strings. Winton is copied on this e-mail to make sure I stated the AOGCC requirement accurately. Thanks, Natasha Sachivichik 3/22/2011 C~ • 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 J (DOA); Regg, James B (DOA); Fleckenstein, Robert J (DOA); Colombie, Jody J (DOA); Gary Carlson; Norman, John K (DOA); Fcerster, Catherine P (DOA); Laasch, Linda K (DOA); IongmereC~verizon.net Subject: FW: Pacific Energy files chapter-11, it's official!!! FYI. PACIFIC ENERGY RESOURCES LTD. 111 West Ocean Blvd., Suite 1240 ~ F ~ `~"~' ~ i ~~~ ~ Long Beach, California 90802 Telephone: (562) 628-1526; Fax: (562) 628-1536 Files for Chapter 11 to Facilitate a Restructuring ~®`~ - t 5 ~ 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. 310 K. Street, Suite 700 Anchorage, AK 99507 Office: 907-258-8600 Fax: 907-258-8601 • David Hall Alaska Operations Manager Main: 907-868-2133 Cell: 907-317-8239 dmhall(u~pacene~rgy.com www.paceneray com • PACIFIC ENERGY RESOURCES, LTD. 310KStreet, Suite 700 Anchorage, AK 99501 Phone: (907) 258-8600 • Fax: (907) 258-8601 July ls, 2008 Mr. Dan Seamount, Chair ~ ~ ~- ~ 7 z p n g Alaska Oil and Gas Conservation Commission Al~~~~ ~~ ~ C_~, ~ m 333 W. 7~' Avenue, Suite 100 ~- "~ ,e ~~~a~~:~~~l~tl~ Anchorage, Alaska 99s01-3639 "~~~~~~~~~'~~;~~ Re: Forest Oil Redoubt Unit #7 Jet Pump Conversion (Sundry No. 308-023) I 1Xi~~ r F Dear Mr. Seamount, Attached please find an updated Form 10-404 Report of Sundry Well Operations for the conversion of Redoubt Unit Well #7 from electric submersible pump operation to jet pump per Tom Maunder's email request on July 9, 2008. _ Additional attachments include a work description and an updated wellbore schematic. If you have any questions, please contact me at 868-2133. Sincerely, ~ `~ /~Q David Hall Alaska Operations Manager attachments a~L ~1U~. ~ ~ ~~~~ PaciSc Energy Resources Ltd., 111 West Ocean Blvd ,Suite 1240, Long Beach, CA 90802 Ph: 56228-1526 Fax: 562-628-1536 STATE OF ALASKA ALP OIL AND GAS CONSERVATION COM~ION REPORT OF SUNDRY WELL OPERATIONS ~~~ J i_l1._ :~ ~ ZOC8 (11/if'"~`~ I Ill f`,~ ~'f a'4f ~L1+~i i3 ~~yr>.Ae 7~LVY~ii 1. Operations Abandon Suspend Operation Shutdown Perforate Waix~r ~ Other '`°i'~ "`~^j`` Performed: Alter Casing ^ Repair Well ~• Plug Perforations ^ Stimulate ^ Time Extension Change Approved Program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator 4. Current Well Class: 5. Permit to Drill Number: Name: pacific Energy Corporation Development Q - Exploratory ^ 203-150 3. Address: 310 K Street, Suite 700, Anchorage, Alaska Stratigraphic^ Service ^ 6. API Number: 99501 50-733-20528-00 7. KB Elevation (ft): 9. Well Name and Number: 90' AMSL ~ Redoubt Unit #7 8. Property Designation: ~DL 3'7~C>a2 /~ ~ ' s "" 10. Field/Pool(s): }3 •a 7` j3edot i3 Undefined Oil Pool 11. Present Well Condition Summary: <"' Y Total Depth measured 15,950 feet Plugs (measured) pkr w/LLC@13,630' true vertical 12,332 feet Junk (measured) Fish @ 13,300' & 13,341' Effective Depth measured 15,870 feet true vertical 12,266 feet Casing Length Size MD TVD Burst Collapse Structural 215' 36" 215' 215' N/A N/A Conductor Surface 3,528' 13-3/8" 3,528' 3,074' 5,020 2,280 Intermediate 14,049' 9-5/8" 14,049' 11,528' 6,870 4,750 Production Liner 2,242' 7" 15,950' 12,332' 12,460 psi 10,780 psi 1-3/4" CT w/sliding sleeve and jet pump ` ~-~a i ~ I ~~ ` Perforation depth: Measured depth: 14,350' -15,667' ~~~^ ,l~` , , _ True Vertical depth: 11,723' - 12,258' Tubing: (size, grade, and measured depth) 3-1/2", P-110 & L-80, from surface to 13,445' Packers and SSSV (type and measured depth) LLC valve in BOT SC-1 pkr @ 13,630', Weatherford Arrowset pkr in tbg @ 13,218' 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 170 42 275 185 1463 Subsequent to operation: 121 - 34 191 158 4418 14. Attachments: 15. Well Class after proposed work: Copies of Logs and Surveys Run N/A Exploratory^ Development ^~ Service ^ Daily Report of Well Operations Attached 16. Well Status after proposed work: Oil^~ Gas ^ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. 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: 308-023 Contact David Hall 868-2133 Printed Name David Hall Title Production Manager ~ ~~~` ' Si nat r ~ Ph 2133 Date 7 l ~ ~~ ~ ~1C 8 g u e e., c d ~ one 86 - F6rrr1"10-404 Revised 12/200 ('1 ~ (~ ~ n I ~ ~ Q~~, JUL 2 21008 U K 'v^f I1~ ~. ~~;d~ ~-~~~~ Page 1 of 1 • . Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, Juty 09, 2008 2:41 PM To: David Hall Subject: RU 5A (202-168) and RU 7 (203-150) David, I am reviewing the latest 404s submitted regarding the jet pump activities. RU 5A - Do you have any greater detail regarding the work performed? Although pressures and depths are included, the operations report is very similar to the procedure. RU 7 -The coil tubing string installed in the well is not listed on the 404 sheet. Could you send in a new 404 sheet with the CT string detailed on a line under the current 7" liner line? Thanks in advance. Call or message with any questions. Tom Maunder, PE AOGCC 7/9/2008 • i PACIFIC ENERGY RESOURCES, LTD. 310 KStreet, Suite 700 Anchorage, AK 99501 Phone: (907) 258-8600 • Fax: (907) 258-8601 July 2, 2008 Mr. Dan Seamount, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 ~~~~ ~~,~~~fc~'~11 ~x ~',.,~ ; , ,.r ,~, ~ ~~ ^ ~ ~./ Re: Forest Oil Redoubt Unit #7 Jet Pump Conversion (Sundry No. 308-023) Dear Mr. Seamount, Attached please find a Form 10-404 Report of Sundry Well Operations for the conversion of Redoubt Unit Well #7 from electric submersible pump operation to jet pump. Additional attachments include a work description and an updated wellbore schematic. If you have any questions, please contact me at 868-2133. Sincerely, a~ ~~ __~ David Hall Production Manager attachments Pacific Energy Resources Ltd, l l l West Ocean Blvd. ,Suite 1240, Long Beach, CA 90802 Ph: 56228-1526 Fax: 562-628-1536 -~ .' STATE OF ALASKA ALA OIL AND GAS CONSERVATIONJ~h~ REPORT OF SUNDRY WELL OPERATIO.,NS . 1. Operations Abandon Suspend Operation Shutdown FF Waiver Other Performed: Alter Casing ^ Repair Well ~ Plug Perforations ^ Stimulate ^ Time Extension ^ Change Approved Program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator 4. Current Well Class: 5. Permit to Drill Num r: Name: Pacific Energy Corporation Development ^~ Exploratory ^ 3-150 3. Address: 310 K Street, Suite 700, Anchorage, Alaska Stratigraphic ^ Service ^ 6. API Number: 99501 0-733-20526-00 7. KB Elevation (ft): 9. Well Name and Number: 90' AMSL Redo t Unit #7 8. Property Designation: ~ilsc. 3$(ry3, 10. Field/Pool(s): Red 87 opt ?•g' U efined Oil Pool 11. Present Well Condition Summary: Total Depth measured 15,950 ~ feet Plugs (measu d) pkr w/LLC@13,630' true vertical 12,332 feet Junk (me red) Fish @ 13,300' & 13,341' Effective Depth measured 15,870 feet true vertical 12,286 feet Casing Length Size MD TVD Burst Collapse Structural 215' 36" 215' 215' N/A N/A Conductor Surface 3,528' 13-3/8" 3,528' 3,074' 5,020 2,260 Intermediate 14,049' 9-5/8" 14,049' 11,528' 6,870 4,750 Production Liner 2,242' 7" 15,9 12,332' 12,460 psi 10,780 psi ~UPEFtSED~~ Perforation depth: Measured depth: 14,350' -15,667' True Vertical depth: 11,723' -12,258' ~-~----- Tubing: (size, grade, and measured depth) 3-1/2", P-110 8~ L-80, from surface to 13,445' Packers and SSSV (type and measured depth) LLC valve in BOT SC-1 pkr @ 13,830•, Weatherford Arrowset pkr in tbg @ 13,219' 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volume sed and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to wel peration: 170 42 275 185 1463 Subsequen o operation: 121 ~ 34 191 158 4418 14. Attachments: 15. Well Class after proposed work: Copies of Logs and S eys Run N/A Exploratory ^ Development Q Service ^ Daily Report of We perations Attached 16. Well Status after proposed work: Oil Gas ^ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby ify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 308-023 Contact David Hall 868-2133 Printed Name David Hall Title Production Manager Signature ~ c+ ~~ Phone 868-2133 Date ~-a~ ~ t~ Form 10-404 Revised 12/2003' ~~.- 7 ~ ? • a- o$ ~.JC11V~tu~~ r' /f~ D • • RU #7 Workover Job Log 08:00 Call out at OSK dock. Haul in Schlumberger 1.75" coil and most of the equipment. 15:00 Take on potable water and off load the Champion work boat. Back load with dumpsters and 5 empty chemical totes. Pollard slick line finished last run with 2.625" gage ring. Tagged top of D&D pack off set on top of ESP pump. Rig down Pollard. Start setting in coil equipment. 10:00 hrs Call out at OSK dock. Finished loading remainder of coil equip and production chemicals. Rigging up coil equip. Notified AOGCC. John Crisp called from Prudhoe Bay. Left message with Jim Regg. 15:00 hrs. Unload work boat. Take on drill water. No back load. Boat will go off of Pacific's time at return to port. Start rigging up APRS. RU7 tubing has zero psi. Annulus bled to 250psi. Welders finishing up on RU7 power water line. Filled Schlumberger water tank with rig water added to methanol. 70/30 mix. Schlumberger tested the BOP on the stand. Rig up, test lubricator and RIH with 12' of perF guns and CCL. Tie in and perforate bottom joint of tubing above ESP. POH. Circulate at 1/4 bbl minute -returns to production. Circulated 1/2 hrs. Check circ -good. R/U bull nose, 22' of screens, pump out plug, Arrow Set 1X packer, Wire line adaptor kit, collar locator. RIH problems at 2973'. POH -tight at 1800'. Check tools. Reduced size of bottom bull plug from 2.625" to 2.55". RIH with packer and screens. Set in place in top portion of third joint up. Fire shot to set packer. Unsuccessful. Packer did not completely set. Work packer through the night to second gas lift mandrill from bottom at 11470'. Packer stuck in GLM. Pull from rope socket. POH. Rig down Pollard E line unit. Rig up slick line unit for fishing. Sent Schlumberger crew to town. RIH with 1 3/8" JDC. Did not find fish in second GLM. Tag fish at bottom Engage fish and pull to second GLM. Would not pass second GLM Run fish back to bottom. Get off of fish. POH and rig down. Send crews to town. Make arrangements for new packer. Notified Tom Maunder of the AOGCC of BOP test. Sent spare Robison ESP drive to the King Salmon Platform. R/U APRS with perforation guns. Test lubricator to 1000 psi. Found fish in third joint up from the ESP. Top of fish at 13,297'. Perforate in the lower portion of fourth joint up - 47 shots..3" to .35", from top shot at 13,280' to 13,292'. All shots fired. 2/17/2008 2/18/2008 2/19/2008 2/20/2008 2/21 /2008 2/28/2008 2/29/2008 ~ • Finish perforations for coil tubing jet pumping. Perforate top portion of fourth joint up from ESP. Shoot 34 shots from 13,267' to 13,275'. Rig down APRS. Unable to fly crew to work due to weather. Rig up APRS. Test lubricator to 1000 psi. Pick up Weatherford packer, screens and setting tool. RIH, tie in to collars. Set packer on depth above new perforations. Attempt to set packer. Packer did not set. Work tools. Work down hole. Set down on top of first fish at 13,297'. Try to POH. Drag in tool joints. Could not pass GLM at 11,470'. Pull off of rope socket. POH. Rig down. Send APRS to town. Sent in a 6' 3.5" 12.95# pup joint and the spare packer to Weatherford's Nikiski shop. RU Pollard and run 1 3/8" JDC through the GLM where APRS pulled off of the rope socket. Did not find fish. RIH and locate fish at 13,362'. Attempt to move fish down hole. Would not move. POH and rig down. Work on packer is Weatherford shop. Investigate packer and hydraulic setting tool functions. Order and air freight in packer set screws. dress and set packer four consecutive times in Weatherford Nikiski shop. Make well plans, make final packer modifications. Mobilize equipment. Rig up Schlumberger Coil Tubing Unit #1 on RU# 7 well. Test BOP to 5000 PSI Run in the hole with 2.3" bull nose. Tag fish at 13,268', moved fish down to 13,297'. Top of fish firm at 13,297' coil tubing measure. Pull tubing back out. Weld connection on coil for coil test. RU APRS with collar locator and 12' of pert gun. Test lubricator and RIH. Determine relationship of fish, collar and perfs. Perforate fifth joint up from ESP with 47 shots. Depth 13,261' to 13,249'. Rig down APRS. Rig up and attempt to drift coil with 1.25" ball. Finish drifting coil to 1.25". Pick up packer, screens and setting tool. RIH. Set Packer at 13,218'. Test to 500 psi. Good test. Pull out of hole. Make up BHA, test and RIH. Stab in, test, space out, POH and blow plug. Received Schlumberger materials for RU#1 well on Champion work boat. Rig down off of RU#7 well with coil. RIH with Pollard slick line and pull isolation sleeve from BHA. Fill well with produced water and drop jet pump. 3/1 /2008 3/2/2008 3/3/2008 3/4/2008 3/5/2008 3!8/2008 3/7/2008 3/8/2008 3/9/2008 3/10/2008 3/11 /2008 3/12/2008 Put well on production. Start moving Schlumberger coil to RU#1 well. Redoubt Unit #7 Completion March, 2008 36", 150#, A-36 Welded Conductor @215'MD/215'ND 13-3/8", 68#, L-80, BTC @ 3,258' MD/3,074' TVD 431 jts 3-1/2", RTS, PH-6 Tubing Coiled tubing w/sliding sleeve and jet pump Pkr & tailpipe asst' 13,218' - 13,259' MD Tbg perfs 13,249' - 13,261' MD Fish #2 (Pkr & tailpipe asst') 13,300' - 13,341' MD Fish #1 (Pkr & tailpipe asst') 13,341' - 13,383' MD Tbg perfs 13,361' - 13,373' MD Centrilift ESP assembly @ 13,445' MD LLC valve set in Baker Retrieva SC-1 packer at 13,630' MD Ton of 7" Liner a(7 13.708' MD/11.262' TD 9-5/8", 47#, L-80, BTC @ 14,049' MD/11,528' TVD Perforations: 14,350' - 14,424' 14,442' - 14,505' 14,535' - 14,580' 14,610' - 14,635' 14,745' - 14,785' 14,840' - 14,955' 15,100 - 15,123' 15,340' - 15,383' 15,590" - 15,667' 7", 32#, P-110, Hydril 521 @ 15,950' MD/12,332' ND • Page 1 of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, February 29, 2008 9:06 AM To: 'ospreypro' Cc: David Hall; 'AOGCC North Slope Office' Subject: RE: Redoubt Unit #7.(203-150) CT BOP test Mike, We will waive witness of the BOP test. Since no witness will be there, please chart the pressure tests. A copy of the chart should be submitted with the test report. You indicated that you had the form and had worked with Mr. Fleckenstein on filling it out. Good luck with the operations. Call or message with any questions. Also, when sending a message regarding a well please include the permit number. Tom Maunder, PE AOGCC From: ospreypro {mailto:ospreyproCalpacenengy.com] Sent: Thursday, February 28, 2008 10:57 AM To: Maunder, Thomas E (DOA) ~~~ ~~B ~ ~~~~ Cc: David Hall Subject: Redoubt Unit #7 BOP test Tom, Pacific Energy Resources plans to test the Schlumberger Coil Tubing Rig #1 on the Osprey Platform Sunday _.. _ .._ . _ _........ _....~..:.~,.,_.v.. March 2"d. The well is Redoubt Unit # 7. We fly out of XTO Heliport in Nikiski. I can be reached at 907-776-7176, Fax 907- 776-7193 or Email at ospreypro@pacene_rgy.com. Should you wish to have an inspector witness the test please call. Thank you, Mike Murray 2/29/2008 • ~ _. -,.._ '• ~ 03/0112008 DO NOT PLACE .`' :~` ~" __ ~- ~' ANY NEW MATERIAL UNDER THIS PAGE F:1LaserFiche\CvrPgs_InsertstMicrofilm Marker.doc r;~~ a~ ~ _ ~ ~ ~ }} !~ t ' ~ $ 1 Y~ ~ ~ ~ ~~ r~ g~ 4'~ e r~ ` fd ~" ~ ~, ~ ~" '~ ~ J k , g ! A..A ; r y ,~ " ~ ~~ ~ t 3 ~ r t{ S { ~ 0 pp p5 Y C ~ a F ~ ~ r..A i )lam ~ \` ~ l~ ~ ~ ~ """ ° `" ~ °' ~.• dJ l1 L `.a ~ ~~ SARAH PALIN, GOVERNOR ~D 3 CO7~T~v~~ ~~O ~ ~~1~T "-7 l o•~ u~i i 0 33 W. 7th AVENUE, SUITE 100 ANCHORAGE A ~ . l 7 11 , LASKA 99501-3539 PHONE (907) 279-1433 David Hall FAX (907) 276-7542 Production Manager Forest Oil Company 310 K Street, Suite 700 ,~~~~~ ~~ ,jA~ `~ ~~~~' Anchorage, AK 99501 Re: Redoubt Shoal Field, Undefined Oil Pool, Redoubt Unit #7 Sundry Number: 308-023 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. When providing 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 decision to Superior Court unless rehearing has been requested. DATED this y~day of January, 2008 Encl. c:~..__-~-- • • ' Forest Oil Corporation 310 K Street, Suite 700 Anchorage, Alaska 99501 • (907) 868-2133 or 7;~6-7108 Fax: (907) 258-8601 or 776-7119 January 18, 2008 ~~~~~~ /~f1 Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 W. 7"' Avenue, Suite 100 Anchorage, Alaska 99501-3539 JAN ~. ~ Zf~9$ Alaska Cil ~ Gss Cons, Cnmmsgni AI1ChQC8gB Re : RU #7 Jet Pump Completion: Dear Mr. Norman, Forest Oil Corp is proposing to produce Redoubt Unit #7 (RU #7) by means of a jet pump. The Electric Submersible Pump (ESP) in the RU #7 wE;ll has failed and will be left in place with a jet pump installed in the tubing above it. We anticipate commencinct this work on February 1. ~ The RU #7 completion includes 3-1/2" tubing which will accommodate a downhole jet pump run on 2"coil tubing. Forest planes to utilize produced water as the power fluid to drive the jet pump. Forest proposes a "standard" jet pump configuration, whereby the power fluid will go down the coil tubing and production returns up the 2" coil tubing - 3-1 /2" tubing annulus. ,~ The projected power fluid pressure at thie wellhead is near 4,800 PSIG, with a power fluid flow rate of approximate 1,200 BPD. Projected annulus return pressure at the wellhead is 200-500 PSIG with an anticipated production flow rate of 300 - 400 BPD (in excess of the power fluid). The proposed well allocation - ~ will involve subtracting power water fluid from return fluid. ~ '""~,~- !~ ~.z ~r3 Forest proposes to leave the SSV on the tubing side (power fluid side). The proposed operation of the SSV would be set to close upon the following conditions: ~~OSU.~ ~ S • PSHH @ 2,200 PSIG on the annulus. • PSLL @ 50 PSIG on the annulus. S1.r~~~GC' ~ o~ t~ • ESD, OSD, GSD. W~ ~~S`, Wellhead MAOP of 5,000~PSIG will be protected from pressure relief valves on the produced water injection \~a3 pumps onshore. If you have any questions, please contact me at 868-2133. Siq erely, ~~~ ~~~~ David Hall Production Manager Forest Oil Corporation Attachments: Sundry Application Wellhead Completion P&ID Wellbore Schematic - RU #7 Summary Procedure ~`•Z~l~~~ STATE OF ALASKA ~' ALASKA OIL AND GAS CONSERVATION COM~ION ~~~~ APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 .. JAN Y 8 20~~ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate ^ i ®tIS. OfYUT)~@f)^ Alter casing ^ Repair well ^~ ~ Plug Perforations ^ Stimulate ^ Time Extens~flC~f8~6 Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Forest Oil Corporation Development ^ Exploratory ^ 203-150 3. Address: Stratigraphic ^ Service ^ 6. API Number: 310 K St, Suite 700, Anchorage, AK 99501 50-733-20526-00 " 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 ^~ ~ Redoubt Unit #7 9. Property Designation: ~ D ~ ~7~ UUL~Z ~ 10. KB Elevation (ft): 11. Field/Pool(s): Re /°~ ~~ 90' AMSL Undefined oil pool • 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 15,950' ~ 12,332' 15,870' 12,266' Pkr w/ LLC @ 13,630' None Casing Length Size MD TVD Burst Collapse Structural Conductor 215 36" 215' 215' NIA N/A Surface 3,528' 13-3/8" 3,528' 3,088' 5,020 psi 2,260 psi Intermediate 14,049' 9-5/8" 14,049' 11,528' 6,870 psi 4,750 psi Production Liner 2,242' 7" 15,950' 12,332' 12,460 psi 10,760 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 14,350' - 15,667' 11,159' -12,219' 3-1/2" P-110 13,445' Packers and SSSV Type: Baker SC-1 pkr w/ LLC valve Packers and SSSV MD (ft): 13,630' 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development Q Service ^ 15. Estimated Date for 1-Feb-08 16. Well Status after proposed work: Commencing Operations: Oil 0 Gas ^ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name David Hall Title Production Manager ~ /~ hone Date ~ / / ~ ~ Signature ~ ` ~ Y f. ~ 868-2133 ~-~ V COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~V _ V ~3 Plug Integrity ^ BOP Test ~.. Mechanical Integrity Test ^ Location Clearance ^ Other: ~~ ©r'~ Ps l \-~J~ ~S'F~3 GS Q\U.`l~h~~ , ~V.J \ Y ~~~~-~c~.r ~~ Q~ ~ ~ ~~,'~ G e~ c~~~ F ~ ~ ~ppw Q~ ~ 0~ ~~c~c~ ~\~ti~ ~-`~ ~ S, Subsequent Form Required: ~.-{r~L `3 ~ ~ ~;,~t~ ~ ~ ~oa~ APPROVED BY /}~ Approved by: MISSIO THE COMMISSION Date:'w~ e•~ (x~ Form 10-403 Revised 06/2006 ~ t ~ I~ ~ ~ Submit in Duplicate ~ f~u.es ~ ~ Redoubt Unit #7 -Jet Pump Installation Outline Summary 1. Check well for pressure, set BPV and nipple down production tree. 2. Nipple up 3,000 psi WP riser and coil tubing BOP stack. Test BOPS to 3,000 psi. 3. Pull BPV. 4. Make a wireline gauge ring run in the 3-1/2" tubing to the top of the ESP assembly at 13,445" MD. 5. RIH perforating gun on E-line and perforate the 3-1/2" tubing with 23 holes at 13,420' MD. 6. RIH with 3-1/2" Weatherford model ER Eclipse packer on E-line and set at 13,370'. 7. Make up jet pump assembly on 2.0" coil tubing and RIH. 8. With the jet pump located at 13,360' MD, cut off the coil tubing at the surface and land out in new tubing hanger spool on top of 3-1/2" tubing hanger in wellhead. 9. Set BPV in tubing hanger. 10. Nipple down BOPE and riser. 11. Nipple up and test production tree. 12. Pull BPV. 13. Return well to production operations. Redoub~CJnit #7 Completion March, 2004 36", 150#, A-36, Welded Conductor @ 215' NID /2 15'TVD 13-3/8", 68#, L-80, BTC @ 3,528' NID / 3,088' TVD Jet pump assembly hung on coiled tubing. _,. (Packer set at 13,370' MD) 3-1/2" tbg perfd at 13,420'- 13,425' MD 431 jts 3-1/2", RTS, PH-6 Tubing Centrilift ESP assembly @ 13,445'NID ^ LLC valve set in Baker Retrieva SC-1 packer @ 13,630' NID Top of 7" liner @ 13,708' MD / 11,262' TVD 9-5/8", 47#, L-80, BTC @ 14,049' NID / 11,528' TVD Perforations: 14,350' - 14,424' 14,442' - 14,505' 14,535' - 14,580' 14,610' - 14,635' 14,745' - 14,785' 14,840' - 14,955' 15,100' - 15,123' 15,340' - 15,383' 15,590' - 15,667' 3-3/8" guns, 6 SPF 7", 32#, P-110, Hydril 521 @ 15,950' MD / 12,332' TVD Nvrr.S ; /. SrTP / bwm y;o.E °~- Q/y/..e~1 rrAfar 4.Sed AS Porvsi R a w 3- T~f 0,...P SHa.dwf CasF.yY.i'.a fro ~ paa.~,r F~ :a d„W., T 5:ny Pr4r.~a Flr.:d ~P Angv[4iS. a ~ y Ss~ ~ Tr~.k9, Poa.., ~-, :~ S4-dr. B ~ S. SSV Sef to Cla.fe o.~ lkc rwira.~.:, 5, R• Eso !~. 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Data ~ Page 1 of 1 Maunder, Thomas E (DOA) From: David Hall [DMHaII@forestoil.comj Sent: Thursday, January 18, 2047 10:00 AM To: 'Thomas Maunder' Cc: 'James Regg' ~~"~- L Sal Subject: RU7 No-Flow Test Data Attachments: No Flow Test RU7.xts; Osprey RU7 data REV3.xts; RU7 no flow fluid shots 1-12 - 1-14.x1s Tom, Attached is the data from RU7 no-flow test. Please let me know you need anymore Information, also any word on RU1 no-flow test ruling from the commissioner? Thanks, David Hatl «No Flow Test RU7.xls» «Osprey RU7 data REV3.xls» «RU7 no flow fluid shots 1-12 -1-14.xts» David Hall Production Manager Ot~ce 907-776-7108 -868-2133 Ce11907-317-8239 Fax 907-776-7119 ~~~`~ Q ~~,~.tco 1 /23/2008 i Fluid Shots RU-7 :;~o~` ~~ J i• ~ooa s5oo 6000 5500 5000 4500 4000 it ~~ 3500 3000 2500 2000 1500 1000 500 0 •oo ;~~ •~ 'a+ ''o :ate '~~, i~~ ~p `'~ as eta, :ate, :aeA 1/12/2007 Through 1/14/2007 ,III i• i• Fluid Shots RU-7 ~:p~-1S-~ 5500 5000 I I 4500 ` -' 4000 j N 3500 3000 j 2500 ~ i I 2000 i --~" 1500 I 1000 i 500 0 o + - a o a 1/13/2007 Through 1/14/2007 i 6500 6000 0 m Mtr Temp {Deg} Suction Pres {PSI} TVD {Feet} • • ~~ `~ FLUID SHOTS RU-7 ~®~+ DATE TIME liquid md. liquid tvd. PI PBHP Csg PSI 1/12/2007 18:30 8,047 6,705 1,543 1,665 890 20:30 7,745 6,462 1,605 1,728 919 23:30 7,115 5,955 1,641 1,764 911 1 /13/2007 2:30 6, 731 5,646 1, 739 1, 879 899 3:30 6, 653 5, 583 1, 731 1, 873 877 7:00 6,151 5,180 1, 595 1, 733 731 10:00 5,711 4,826 1,425 1,552 595 12:00 5,385 4,564 1,292 1,417 454 14:00 5,242 4,448 2,185 5,464 392 18:00 5,140 4, 366 1, 308 1, 505 11 21:00 5,111 4,343 1,947 2,226 0 21:30 5,035 4,282 1,995 2,274 0 22:00 4,938 4,204 1,981 2,260 0 23:00 4,780 4,077 2,071 2,350 0 23:30 4,647 3,970 2,084 2,363 0 24:00:00 1/14/2007 0:30 4,612 3,942 2,085 2,363 0 1:00 4,425 3,791 2,140 2,419 0 1:30 4,349 3,731 2,167 2,446 0 2:00 4,274 3,670 2,134 2,413 0 2:30 4,210 3,619 2,200 2,479 0 3:00 4,147 3,568 2,224 2,500 0 3:30 4,081 3,515 2,231 2,510 0 4:00 4,025 3,470 2,248 2,527 0 4:30 .3,954 3,414 2,260 2,539 0 5:00 3,895 3,366 2,266 2,545 0 5:30 3,823 3,309 2,292 2,571 0 6:00 3,768 3,264 2,338 2,617 0 6:30 3,707 3,216 2,315 2,594 0 7:00 3,654 3,173 2,317 2,596 0 7:30 3,593 3,125 2,332 2,611 0 8:00 3,538 3,080 2,353 2,632 0 8:30 3,481 3,034 2,400 2,679 0 9:00 3,426 2,991 2,345 2,624 0 9:30 3,371 2,947 2,357 2,636 0 10:00 3,323 2,909 2,380 2,659 0 10:30 3,269 2,865 2,392 2,671 0 11:30 3,168 2,784 2,415 2,694 0 12:00 3,140 2,762 2,421 2,700 0 12:30 3,070 2,706 2,437 2,715 0 13:30 2,973 2,629 2,508 2,787 0 14:30 2,883 2,558 2,827 2,806 0 15:30 2,798 2,490 2,545 2,823 0 16:30 2,718 2,426 2,561 2,840 0 17:30 2,636 2,361 2,578 2,857 0 18:30 2,558 2,299 2,595 2,874 0 19:30 2,488 2,244 2,574 2,853 0 20:30 2,413 2,184 2,581 2,860 0 Forest Oil Alaska 1/1212007 RU7 No flow Test ~~ _ ~ S Time 13:10 RU7 Shut down on Robicon modulator boa rd 14:46 Shut off power to Phoenix to change board 15:49 Powered Phoenix back up. Contacted Ji m Regg, Tom Maunder and Lou Grimaldi. Proceeded to conduct No Flow test Time Tubing Annulus Phoenix Intake Phoenix Liquid Liquid Pressure Pressure Intake PSI Discharge Levei Level 111212007 Pressure Gain Pressure Shot MD Ft. Gain 18:30 131 890 2415 2314 8,047.00 Rig up to bleed down 20:30 197 919 2546 2454 7,745.00 21:00 196 2572 2665 Start bleeding annulus into tubing 23:30 847 911 2772 2682 7,115.00 Annulus froze off, still equalizing annulus and tubing. 1113!2007 0:25 914 914 2837 2742 Annulus pressure and tubing pressure equalized, start bleeding down. 2:30 899 899 2886 2793 6,731.00 Shut down to shoot fluid level 3:15 700 870 2871 2778 Shut down to let annulus thaw out, 3:30 707 $72 2891 2795 6,653.00 Shot fluid level 4:00 872 872 2912 2844 Start bleeding again, 5:30 757 2913 2821 Tubing shut in. Bleed annulus by itself. 6:00 7:00 757 752 800 731 2895 2770 2822 2857 6,151.00 Tubing shut in. Bleeding annulus, Tubing shut in. Shot fluid level, Bleeding annulus. 8:00 752 720 2794 2885 Tubing shut in. Bleeding annulus. Freezing problems. 9:00 752 700 2883 2789 Tubing shut in. Bleeding annulus. Freezing problems. 10:00 745 595 2818 2731 5,711.00 Tubing shut in. Shot fluid level. Bleeding annulus, 11;00 734 530 2779 2681 Tubing shut in. Bleeding annulus. 12:00 731 454 2739 2650 5,385,00 Tubing shut in. Shot fluid level. Bleeding annulus. 13:00 701 Started bleeding tukHng. 14:00 356 392 2716 2581 5,242.00 Bleed tubing. Shoot fluid level. Bleed annulus 15:00 88 320 2625 2529 Bleed tubing. Bleed annulus. 16:00 16 146 2492 2405 Bad shot Bleed tubing. Shoof fluid level -bad shot. Bleed annulus 17:00 6 40 2440 2350 Bleed tubing. Bleed annulus. 18:00 5 13 2493 2384 5,140.00 Bleed tubing. Shoot fluid level. Bleed annulus 20,20 2 1 2590 97 2497 Gas meter 10' perlmin. = 600cfh , start no flow test 20,30 < 1 1 2599 9 2513 Tie in #ubing and annulus to gas meter 21:00 < 1 1 2627 28 2543 5,111.00 .Gas rate 110 cfh 21;30 < 1 < 1 2659 32 2667 5,035.00 22:00 < 1 < 1 2676 17 2584 4,938.00 Gas rate 110 cfh 22:30 < 1 < 1 2705 29 2615 Gas rate 120 cfh 23:00 < 1 < 1 2735 30 2634 4,780.00 Gas rate 70 cfh 23:50 < 1 < 1 2760 25 2669 4,647.00 Gas rate 75 cfh 24:00;00 111412007 0:30 < 1 < 1 2802 42 2710 4,61200 Gas rate 70 cfh 1:00 < 1 < 1 2828 26 2734 4,425.E Gas rate 60 cfh, bad fluid shot 1:30 < 1 < 1 2849 21 2756 4,349,00 Gas rate 80 cfh 2:00 < 1 < 1 2872 23 2784 4,274.00 Gas rate 100 cfh 2:30 < 1 < 1 2899 27 2809 4,210.00 Gas rate 60 cfh 3:00 < 1 < 1 2913 14 2821 4,147.00 Gas rate 150 cfh 3:30 < 1 < 1 2936 23 2843 4,081.00 Gas rate 80 cfh 4:00 < 1 < 1 2951 15 2860 4,025.00 Gas rate 60 cfh 4:30 < 1 < 1 2981 30 2896 3,954.OD Gas rate 60 c~ 5:00 < 1 < 1 2996 15 2906 3,895,00 Gas rate 80 cfh 5:30 < 1 < 1 3017 21 2926 3,823,00 Gas rate 80 cfh 6:00 < 1 < 1 3034 17 2944 3,768.00 Gas rate 138 cfh 6:30 < 1 < 1 3054 20 2964 3,707.D0 Gas rate 75 cfh 7:00 < 1 < 1 3065 11 2976 3,654.00 Gas rate 53 cfh 7:30 < 1 < 1 3089 24 2996 3,593,00 Gas rate 139cfh 8:00 < 1 < 1 31D5 16 3011 3,538.00 Gas rate 66 cfh 8:30 < 1 < 1 3112 7 3019 3,481,00 Gas rake BO cfh 9:00 < 1 < 1 3132 20 3040 3,426,00 Gas rate 58 cfh 9:30 < 1 < 1 3154 22 3063 3,371.00 Gas rate 54 cfh 10:00 < 1 < 1 3167 13 3078 3,323.00 Gas rate 64 cfh 10:30 < 1 < 1 3209 42 3120 3,269,00 Gas rate 54 cfh 11:00 < 1 < 1 3198 -11 3106 Gas rate 58 cfh 11:30 < 1 < 1 3207 9 3117 3,168.00 Gas rate 54 cfh 12:00 < 1 < 1 3227 20 3135 3,140.00 Gas rate 58 cfh I~ 12:30 < 1 < 1 3235 7 3144 13:00 < 1 < 1 3246 11 3152 13:30 < 1 < 1 3265 19 3177 14:00 < 1 < 1 3283 18 3186 14:30 < 1 < 1 3291 8 3200 15:00 < 1 < 1 3300 9 3205 15.30 < 1 < 1 3330 30 3239 16:00 < 1 < 1 3325 -5 3291 16:30 < 1 < 1 3379 54 3262 17:00 < 1 < 1 3357 -22 3268 17:30 < 1 < 1 3311 14 3282 18,00 < 1 < 1 3379 8 3290 18;30 < 1 < 1 3394 15 3300 19:00 < 1 < 1 3403 7 3312 19:30 < 1 < 1 3415 12 3321 20:00 < 1 < 1 3444 29 3376 20,30 < 1 < 1 3438 -6 3346 21;48 3,070.00 2,973.00 2,883.00 2,798,00 2,718.00 2,636.00 2,558.00 Gas rate 51 cfh Gas rate 58 cfh Gas rate 54 cfh Gas rate 58 cfh Gas rate 60 cfh Gas rate 43 a#h Gas rate 43 cfh Gas rate 43 cfh Gas rate 43 cfh Gas rate 41 cfh Gas rate 40 cfh Gas rate 43 cfh Gas rate 40 cfh 2,488.00 Gas rate 46 cfh Gas rate 60 cfh 2,413.00 Gas rate 56 cfh End No Flow Test. Start RU7 ESP. • c . . SARAH PALIN, GOVERNOR AI,ASIiA. OIL AlO) GAS CONSERVATION COMMISSION 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 February 22, 2007 Mr. David Hall Production Manager Forest Oil Corporation 317 K Street, Suite 700 Anchorage, Alaska 99501 RE: No-Flow Verifications Redoubt Unit 7, PTD 203-150 Dear Mr. Hall: The subsurface safety valve may be removed from service in Redoubt Unit Well 7 ("RU- T') based on the results of a no-flow test performed January 12-14, 2007. A fail-safe automatic surface safety valve system ("SVS") capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. A subsurface safety valve as provided for in 20 AAC 25.265 must be returned to service if the well demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no flow test. Redoubt Unit Well 7 is located on the Osprey Platform, offshore Cook Inlet, and is completed with an electrical submersible pump ("ESP"). The Commission approved the installation of an alternate type of subsurface safety valve known as a liquid level controller ("LLC") on September 2, 2003. The LLC is installed in a packer below the ESP, designed to provide a downhole shut in capability. Verification that the LLC is functioning properly has been difficult since installation. A modified test procedure has attempted to take advantage of opportunities when the ESP shuts down during nuisance electrical problems on the platform. Those opportunities minimize wear from starting and stopping the ESP that could lead to premature pump failure. Data gathered from downhole pressure and temperature gauges in conjunction with past ESP shut downs has been inconclusive about LLC performance, but has provided some evidence of the well's inability to sustain the flow of hydrocarbons at the surface. Forest Oil Corporation performed a "no flow test" of RU-7 on January 12-14,2007 after notifying the Alaska Oil and Gas Conservation Commission ("Commission") of an ESP .. . . Mr. David Hall February 22, 2007 Page 2 of2 shut do'WIl. The Commission was unable to witness the test. Surface wen pressures were bled do'WIl to maximize the drawdo'WIl on the formation and downhole pressures and fluid levels in the tubing were monitored for a 24-hour period subsequent to the ESP shut do'WIl. During the monitoring period, the wen demonstrated a liquid influx: rate of approximately 38 gallons per hour (based on fluid levels shot acoustically in the well during the monitoring period) with no liquids produced at surface, and a gas rate measured at the surface of approximately 65 cubic feet per hour. The liquid and gas rates at surface are below the maximum allowable rates for a no flow determination. Please retain a copy of this letter on the Osprey platform. Sincerely, Jl.Wlj'ß-'k&q James B. Regg { ( Petroleum Inspection Supervisor cc: Bob Fleckenstein _ STATE OF ALASKA _ ALASK._L AND GAS CONSERVATION COMMlsWN WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a. Well Status: Oil0 GasD Plugged U Abandoned U Suspended 0 WAG 0 1 b. Well Class: 20AAC 25.105 20AAC 25.110 Development 0 Exploratory 0 GINJD WINJD WDSPL 0 No. of Completions Other Service 0 Stratigraphic Test 0 2. Operator Name: :5~a~ltfmp., sus~f!Jf8lo¢ 12. Permit to Drill Number: Forest Oil Corporation ~ anti.: m 4 ..~ 203-150 3. Address: 6. Date Spudded: 13. API Number: 310 K Street, Suite 700, Anchorage, Alaska 99501 September 7, 2003 50-733-20526-00 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 1967' FSL, 223' FEL, Sec. 14, T7N, R14W, SM December 4,2003 RU#7 Top of Productive Horizon: 8. KB Elevation (ft): 15. Field/Pool(s): 1483' FNL, 1667' FWL, Sec. 19, T7N, R13W, SM 90' MSL Redoubt Shoal Oil Field Total Depth: ~t~ack Dep.~~Q~j 2037' FNL, 2024' FEL, Sec. 19, T7N, R13W, SM . s¡ 8 1'MD I. 3:J. , ~1 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 200675.2 y- 2449982.2 Zone- 4 15950' MD, Surf: 381203, TD:374002 TPI: x- 207845.5 y- 2446532.5 Zone- 4 11. Depth Where SSSV Set: 17. Land Use Permit: Total Depth: x- 209214.2 y- 2445978.6 Zone- 4 LLC at 13,630' N/A 18. Directional Survey: Yes 0 No 0 19. Water Depth, if Offshore: 20. Thickness of Permafrost: 45 feet MSL NIA 21. Logs Run: Hole & Cement Volumes, Dipole Shear Sonic Tool, Platform Express, Spontaneous Potential - Gamma Ray, Modular Dynamic Formation Tester, Ultrasonic Cement and Casing Imager, Correlation Log Gamma Ray/ CCL, TCP Correlation Log 22. 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 36" 150 A-36 0 215' 0 215' NIA Driven 0 13-3/8" 68 L-80 0 3,528' 0 3,088' 18-1/2" 2700 sx 0 9-5/8" 47 L-80 0 14,049' 0 11,528' 12-1/4" 750 sx 0 7" 32 P-110 13,708' 15,950' 11,262 12,332' 8-1/2" 1,180cu ft 0 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) 14350' -14424' MD (11723' -11770' TVD), 14442' -14505' MD (11781'- 3.5" 13,445' NIA 11819' TVD), 14535' -14580' MD (11838' -11864' TVD), 14610' -14635' MD (11881' -11895' TVD), 14745' -14785' MD (11953' -11972' TVD), 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 14840' -14955' MD (11999' -12050' TVD), 15100' -15123' MD (12105' - DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 12113' TVD), 15530' -15383' MD (12176' -12189' TVD), 15590' -15667' MD (12239 -12258' TVD) NIA 26. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): March 26, 2004 Electric submersible pump Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: /GaS-Oil Ratio: 3/30/2004 24 Test Period .. 49 12 443 245 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity - API (corr): Press. 1662 114 24-Hour Rate -. 49 12 443 26.5 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". RECEIVED None MAY 05 2004 ~afL .0._ ORIGiNAL Alaska Oil & Gas Cans. Cammi. SI Anchorage IOn Form 10-407 Revised 12/2003 CONTINUED ON REVERSE ~I'; 28. GEOLOGIC MARKER'" NAME TVD 29. FORMATION TESTS Include and briefly s rize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". None Upper Hemlock Clay Zone Middle Hemlock Lower Hemlock 14,310' 14,632' 14,750' 15,338' 11,690' 11,895' 11,955' 12,176' RECEIVED MAY 05 2004 Alaska Oil & Gas Cons. Commission Anchorage 30. List of Attachments: 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Bill Penrose 258-3446 Printed Name: Paula Inman Title: Production Engineer Signature: ~ Phone: 907-868-2135 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 1 a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for I njection, 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 Perforations: 14,350' - 14,424' 14,442' - 14,505' 14,535' - 14,580' 14,610' - 14,635' 14,745' - 14,785' 14,840' - 14,955' 15,100' - 15,123' 15,340' - 15,383' 15,590' - 15,661' 3-3/8" guns, 6 SPF #7 rch,2004 36", 150#, A-36, Welded Conductor @ 215' MD /2 15'TVD 13-3/8",68#, L-80, BTC @ 3,528' MD /3,088' TVD 431 jts 3-112", RTS, PH-6 Tubing Centrilift ESP assembly @ 13,445'MD LLC valve set in Baker Retrieva SC-1 packer @ 13,630' MD Top ofT' liner @ 13,708' MD /11,262' TVD 9-5/8",47#, L-80, BTC @ 14,049' MD /11,528' TVD 7",32#, P-110, Hydril521 @ 15,950' MD /12,332' TVD / e e Forest Oil Corporation Redoubt Unit #7 Well Operations Summary 0600,9/6/03 - 0600, 917/03 MW: 8.9 ppg Vis: 72 sec Take on casing and cement from boat. Check fluid system for leaks. MIU BRA and drill out conductor to 215'. Directionally drill 18-1/2" hole to 410'. 0600,917/03 - 0600, 9/8/03 MW: 9.5 ppg Vis: 97 sec Directionally drill 18-1/2" hole from 410' to 1495'. 0600,9/8/03 - 0600, 9/9/03 MW: 9.6 ppg Vis: 105 sec Directionally drill 18-1/2" hole from 1495' to 2675'. 0600,9/9/03 - 0600, 9/10/03 MW: 9.7 ppg Vis: 101 sec Directionally drill 18-112" hole 2675' to 3545'. Circulate and condition hole. 0600,9/10/03 - 0600, 9/11/03 MW: 9.6 ppg Vis: 47 sec paR. Role taking 10 bph. RIH, circ and condition hole, spot LCM pill. paR. RJU to run csg. Role taking 20 bph.. 0600,9/11/03 - 0600, 9/12/03 MW: 9.7 ppg Vis: 46 sec RJU to run casg. Run 13-3/8",68#, L-80, BTC csg to 3528'MD/3088'TVD. MIU stab-in tool and RIH. MID cmt head and hose, stab stinger. C&C hole for cementing. Cmt csg as follows: 40 bbls R20 followed by 1750 sx 12.5 ppg lead slurry and 950 sx 15.8 ppg tail slurry. Displaced w/68 bbl mud. Disengage stinger and circ DP and csg clean. 0600, 9/12/03 - 0600, 9/13/03 MW: ppg Vis: sec paR w/ stinger, clean mud pits. LID BRA f/ derrick. NID riser. NIU casing head and test. NIU valves to head and riser. NIU BOPs. 0600,9/13/03 - 0600, 9/14/03 MW: ppg Vis: sec C/O lower pipe rams. Test BOPE. PIU and SIB DP. 0600,9/14/03 - 0600, 9/15/03 MW: 9.6 ppg Vis: 180 sec Cont. PIU and SIB DP in derrick. RIH, tag cmt @ 3452'. Pump 100 bbl spacer and displace hole to OBM. paR. MIU direction drilling assy and RIH. Tag cmt @ 3452'. Drill cmt and float collar from 3452' to 3500'. Attempt to test csg to 3000 psi. Bled to 1700 in 10 min. paR. -- ..---~"_--... 0600,9/15/03 - 0600, 9/16/03 MW: 9.7ppg Vis: 220 sec tit e POR. Wait on boat w/ RTTS. MIU RTTS, Rill and set at 3497'. Pressure test Csg to 3000 psi for 30 min - OK. RIH w/ RWDP to test for circulation. Layout one bad jt. MIU 12-114" drlg BRA and RIH. Drill cmt and shoe. 0600,9/16/03 - 0600, 9/17/03 MW: 9.7 ppg Vis: 165 sec Dri1112-1I4" hole from 3545' to 3565'. Perform LOT. Leaked off at 13.55 ppg EMW. Directiona11y 001112-114" hole from 3565' to 5545'. 0600,9/17/03 - 0600, 9/18/03 MW: 9.6 ppg Directiona11y dri1112-1I4" hole 5545' to 7513'. Vis: 84 see 0600,9/18/03 - 0600, 9/19/03 MW: 9.7 ppg Directiona11yOO1112-1I4"hole 7513' to 8356'. Vis: 73 see 0600,9/19/03 - 0600, 9/20/03 MW: 9.9 ppg Vis: 80 sec Direetionally drill 12-114" hole 8356' to 8797'. POR to 7878' - packing off. Pump and back ream out of hole to 5500'. 0600,9/20/03 - 0600, 9/21103 MW: 9.6 ppg Vis: 101 sec Pump and back-ream out of hole. Tight. LID BRA. Test BOPE. MIU new BRA. 0600,9/21103 - 0600, 9/22/03 MW: 9.9 ppg Vis: 90 sec RIH. Directionally 001112-114" hole 8797' to 9585'. 0600,9/22/03 - 0600, 9/23/03 MW: 10.0 ppg Vis: 95 see Direetionally 001112-1/4" hole 9585' to 10,052'. 0600,9/23/03 - 0600, 9/24/03 MW: 10.0 ppg Vis: 100 sec DÌrectionallydri1112-1I4"hole 10,052' to 10,246'. POR. 0600, 9/24/03 - 0600, 9/25/03 MW: 10.1 ppg Vis: 111 see POR, change out BRA components. RIH. Direetionally 001112-114" hole 10,246' to 10,517'. 0600,9/25/03 - 0600, 9/26/03 MW: 10.0 ppg Directionally drill 12-114" hole 10,517' to 11,123'. Vis: 101 see 0600,9/26/03 - 0600, 9/27/03 MW: 10.1 ppg Directionally drill 12-114" hole 11,123' to 11,354'. Vis: 90 see 0600,9/27/03 - 0600, 9/28/03 MW: 10.1 ppg Vis: 90 sec Direetionally dri1112-1I4" hole 11,354' to 11,405. POR and SIB BRA. 0600,9/28/03 - 0600, 9/29/03 MW: 10.1 ppg Vis: 90 see SIB BRA. Test BOPE. PIU BRA and RIH. Tag up at 3543'. Ream to 3580'. POR and SIB BRA. e e 0600,9/29/03 - 0600, 9/30/03 MW: 10.2 ppg Vis: 135 sec Wait on 12-1/4" hole opener. MIU BRA and RllI. Wash and rotate to 3580'. Work to 3582', would go no further. POR. MIU geopilot in BRA and RllI. Control drill around obstruction to 3761 '. 0600,9/30/03 - 0600, 10/1/03 MW: 10.2 ppg Vis: 135 sec Directionally drill 12-1/4" hole to 3882', attempting to intersect original bore. Indication of entry at 3 874'. POR, SIB BRA. MIU hole opener and RllI. Would not pass 3947'. POR. 0600, 10/1/03 - 0600, 10/2/03 MW: 10.2 ppg Vis: 165 sec Finish POR. Stiffen BRA, RllI. Work hole opener, unable to go past 3946'. POR. MIU drilling BRA, RllI. Pump and ream in old hole 4335'. 0600, 10/2/03 - 0600, 10/3/03 MW: 10.2 ppg Vis: 115 sec Wash, ream and work in hole 4335' to 6400'. Run stands in free to 7491'. Role tight at 7491 '. Work tight hole. 0600, 10/3/03 - 0600, 10/4/03 MW: 10.3 ppg Vis: 147 sec POR, LID BRA. MIU clean out BRA, RllI. Ream to 7757', work tight hole at 7757'. 0600, 10/4/03 - 0600, 10/5/03 MW: 10.2 ppg Vis: 123 sec Work tight hole 7757' -7800'. Wash and ream in hole 7800' - 11405'. Directionally drill 12-1/4" hole 11405' - 11415'. C&C hole. 0600, 10/5/03 - 0600, 10/6/03 MW: lOA ppg Vis: 167 sec C&C hole. POR, numerous tight spots. Break bit and LID BRA. Test BOPE. 0600, 10/6/03 - 0600, 10/7/03 MW: 10.5 ppg Vis: 171 sec MIU BRA and RllI. Ream to 11,316'. Encountered high torque. Stuck pipe. Could rotate, could not circulate or move up or down. Jar on pipe. 0600, 107/03 - 0600, 10/8/03 Work stuck pipe. MW: 10.5 ppg Vis: 165 sec 0600, 10/8103 - 0600, 10/9/03 MW: 10.5 ppg Vis: 135 sec Work stuck pipe. R/U to perform backoff. RllI w/ string shot. Back off at 11,182' at bottom of jars. RID backoff unit. C&C hole, POR. LID 3 bent jts ofRWDP and jars. 0600, 10/9/03 - 0600, 10/10/03 MW: 10.6 ppg Vis: 135 sec MIU 12-1/4" hole opener BRA, RllI. Wash and ream to top offish. Tagged at 11,182'. Fish moved down hole to 11,233. C&C hole - recovered large amount of coal. POR. 0600, 10/10/03 - 0600, 10/11/03 MW: 10.6 ppg Vis: 167 sec It e LID hole opener BHA, MIU fishing BHA, Rill to shoe. Service rig. Rill, engage fish at 11,200'. 0600, 10/11/03 - 0600, 10/12/03 MW: 10.7 ppg Vis: 170 see Jar on fish for 7-1/2 hrs. No movement. RIU for backoff. Place backoffshot and shoot. RID backoffunit. C&C hole, POH. LID 9 spiral DC's. 0600, 10/12/03 - 0600, 10/13/03 MW: 10.6 ppg Vis: 136 sec LID fishing BHA. Left screw-in sub in hole. PIU mule shoe and 16 jts 3-1/2" DP. Rill. Tag fish at 11,200'. Circ at high spm to shear mud. Pump 500 sx Class G cmt plug into open hole at top of fish. PIU 10 stands, drop wiper dart and clear DP. POH 0600, 10/13/03 - 0600, 10/14/03 MW: 10.6 ppg Vis: 150 sec Finish POH, LID cmtg stinger and mule shoe. Test BOPE. MIU sidetracking BHA and Rill. Tag firm TOC @ 10,870'. Time-drill to 10,879' to kick off plug. 0600, 10/14/03 - 0600, 10/15/03 MW: 10.6 ppg Vis: 129 sec Time-drill 1 0,879 - 10,908'. Slide 10,908' - 10,970'. Rotary drill 1 0,970' - 11,023'. 0600, 10/15/03 - 0600, 10/16/03 MW: 10.6 ppg Vis: 142 sec Directionally drill 12-1/4" hole 11,023' -11,152'. C&C hole, POH. 0600, 10/16/03 - 0600, 10/17/03 MW: 10.7 ppg Vis: 142 sec POH. Re-build BHA. Rill. Direetionally drill 12-1/4" hole 11,152' - 11,319'. 0600, 10/17/03 - 0600, 10/18/03 MW: 10.6 ppg Directionally drill 12-1/4" hole 11,319' -11,770'. Vis: 118 sec 0600, 10/18/03 - 0600, 10/19/03 MW: 10.6 ppg Directionally drill 12-1/4" hole 11,770' - 11,962'. Vis: 1 09 sec 0600, 10/19/03 - 0600, 10/20/03 MW: 10.6 ppg Directionallydrill12-1/4"hole 11,962' -12,100'. Vis: 112 sec 0600, 10/20/03 - 0600, 10/21/03 MW: 10.6 ppg Vis: 110 sec Directionally driÌl12-1/4" hole 12,100' -12,150'. C&C hole and POH. LID bit and re-work BHA. 0600, 10/21/03 - 0600, 10/22/03 MW: 10.6 ppg Vis: 130 sec Test BOPE. Work BHA and Rill. Directionally drill 12-l/4" hole 12,150' - 12,349' . 0600, 10/22/03 - 0600, 10/23/03 MW: 10.6 ppg Direetionally drill 12-1/4" hole 12,349' - 12,598'. Vis: 102 sec e e 0600, 10/23/03 - 0600, 10/24/03 MW: 10.6 ppg Vis: 96 see Direetionally drill 12-1/4" hole 12,598' - 12,773'. 0600, 10/24/03 - 0600, 10/25/03 MW: 10.6 ppg Vis: 98 see Direetionally drill 12-1/4" hole 12,773' -12,848'. POH for new bit, laying out DP with worn hard banding. 0600, 10/25/03 - 0600, 10/26/03 MW: 10.6 ppg Vis: 97 see Cont. POH, laying out DP w/ worn hard banding. MID new bit and PID new DP. Rlli. 0600, 10/26/03 - 0600, 10/27/03 MW: 10.6 ppg Vis: 110 see Finish Rlli. Direetionally drill 12-1/4" hole 12,848' - 12,933'. 0600, 10/27/03 - 0600, 10/28/03 MW: 10.4 ppg Vis: 104 see Direetionally drill 12-1/4" hole 12,933' -13,001'. MWD pu1ser failed, POH. 0600, 10/28/03 - 0600, 10/29/03 MW: 10.4 ppg Vis: 102 see Finish POH. Test BOPE. PID add'l DP, work on BHA and Rlli. 0600, 10/29/03 - 0600, 10/30/03 MW: lOA ppg Vis: 135 see Finish Rlli. Direetionally drill 12-1/4" hole 13,001' - 13,174'. 0600,10/30/03 - 0600, 10/31/03 MW: 10.4 ppg Vis: 110 see Direetionally dri1112-1/4" hole 13,174' - 13,318'. Autotrak failed, POH. 0600,10/31/03 - 0600, 11/1/03 MW: 8.110.4 ppg Finish POH. Work on BHA, MID new bit, Rlli. Vis: 100 see 0600, 11/1/03 - 0600, 11/2/03 MW: lOA ppg Direetionallydrill12-1/4"ho1e 13,318' -13,564'. Vis: 133 see 0600, 11/2/03 - 0600, 11/3/03 MW: 10.4 ppg Direetionally drill 12-1/4" hole 13,564' - 13,740'. Vis: 118 see 0600, 11/3/03 - 0600, 11/4/03 MW: 10.5 ppg Vis: 122 see Direetionally drill 12-1/4" hole 13,740' - 13,780'. POR. Work on BHA. 0600, 11/4/03 - 0600, 11/5/03 MW: 10.7 ppg Vis: 240 see Test BOPE. M/U BHA and Rlli. Direetionally dri1112-1/4" hole 13,780'- 13,822'. 0600, 11/5/03 - 0600, 11/6/03 MW: 10.6 ppg Direetionallydrill12-1/4"hole 13,822' to 14,000'. Vis: 113 see 0600, 11/6/03 - 0600, 11/7/03 MW: 10.6 ppg Vis: 100 see tit . Short trip. Directionally drill 12-1/4" hole 14,000' to 14,051'. Work up and down through increasingly sticky open hole. 0600, 11/7/03 - 0600, 11/8/03 MW: 10.6 ppg Vis: 190 sec Work sticky hole. Unable to work back down past 12,835'. POR for stiff assy. Change BRA and Rill. 0600, 11/8/03 - 0600, 11/9/03 MW: 10.6 ppg Vis: 145 sec Rill, wash & ream to btm (14,050'). C&C hole. POR, working tight spots out. LID RWDP and BRA. 0600, 11/9/03 - 0600, 11/10/03 MW: 10.6 ppg Vis: 98 sec/ Change rams and RIU to run csg. Run 9-5/8",53#, P-110, SLRC csg. 0600, 11/10/03 - 2400, 11/11/03 MW: 10.7 ppg Vis: 204 sec Finish running casing. P/U and M/U hanger and landing joints. Suspend hanger 5' above casing head. RIU to cement. Cmt csg w/ 450 sx Class G lead at 12.5 ppg (2.10 yield), followed by 300 sx Class G tail at 15.0 ppg (1.15 yield). Displaced to ~ shoe track volume - did not bump plug. RID cement head, lines and landing joints. 0600, 11/11/03 - 0600, 11/12/03 MW: 10.7 ppg Vis: 225 sec RID casing tools, flush stack, install 9-5/8" packoff and test. Change rams and test BOPE. Transfer OBM out of mud pits to tanks and clean mud pits. 0600, 11/12/03 - 0600, 11/13/03 MW: 9.6 ppg Clean pits, flush lines. MIU 8-1/2" BRA, Rill. Vis: 235 sec 0600, 11/13/03 - 0600, 11/14/03 MW: 8.6 ppg Vis: 28 sec Rill w/ bit, tag cmt at 13,580'. Test casing to 3000 psi - OK. Drill cmt and float collar 13,580' - 14,015'. Test casing to 3000 psi - OK. Transfer OBM to storage, clean pits. Begin displacement with sea water. 0600, 11/14/03 - 0600, 11/15/03 MW: 8.8 ppg Vis: 28 sec Circ hole clean w/ sea water. LID 5" DP and 12-1/4" BRA components. 0600, 11/15/03 - 0600, 11/16/03 MW: 9.6 ppg Vis: 89 sec Finish LID BRA components. Change BOP rams. Offload equipment and tools on workboat. Mix water base mud in pits. Test BOPE. 0600, 11/16/03 - 0600, 11/17/03 MW: 9.6 ppg Vis: 64 sec Mix mud, take on drill water, backload workboat. M/U 8-1/2" drilling BRA. DP contains excessive rust. P/U and rattle DP while Rill open-ended. Circ DP clean, POR. P/U add'l DP. 0600, 11/17/03 - 0600, 11/18/03 MW: 9.8 ppg Vis: 56 sec Rill, P/U DP, to 13,400'. Replace seawater in pits w/ mud. Displace well w/ mud. P/U remainder ofDP and wash to btm. e e 0600, 11/18/03 - 0600, 11/19/03 MW: 9.6 ppg Vis: 47 see Drill emt, shoe and 20' of new hole 14,015' - 14,070'. Conduct FIT to 11.5 ppg. Direetionally drill 8-1/2" hole 14,070' - 14,212'. 0600, 11/19/03 - 0600, 11/20/03 MW: 9.6 ppg Vis: 90 see Direetionally drill 8-1/2" hole 14,212' - 14,246'. paR, work on BRA, change bit, Rill. 0600, 11/20/03 - 0600, 11/21/03 MW: 9.6 ppg Vis: 47 see Finish Rill. Direetionally drill 8-1/2" hole 14,246' to 14,306'. Autotrak signal lost. paR. LID 23 jts DP with excessive scale and rust. 0600, 11/21/03 - 0600, 11/22/03 MW: 9.7 ppg Vis: 53 see Continue LID DP. Change out BRA components and Rill. Direetionally drill 8-1/2" hole 14,306' to 14,368'. 0600, 11/22/03 - 0600, 11/23/03 MW: 9.7 ppg Vis: 80 see Direetionally drill 8-1/2" hole 14,368' -14,380'. paR for failed Autotrak. Test BOPE. Work on BRA, PIU and rattle DP. Rill. 0600, 11/23/03 - 0600, 11/24/03 MW: 9.7 ppg Vis: 52 see Finish Rill. Direetionally drill 8-1/2" hole 14,380' to 14,518'. 0600, 11/24/03 - 0600, 11/25/03 MW: 9.6 ppg Direetionally drill 8-1/2" hole 14,518' to 14,755'. Vis: 56 see 0600, 11/25/03 - 0600, 11/26/03 MW: 9.7 ppg Vis: 53 see Direetionally drill 8-1/2" hole 14,755' - 14,880'. paR. 0600, 11/26/03 - 0600, 11/27/03 MW: 9.8 ppg Vis: 60 see Finish paR, bit rung out. MIU mill and junk baskets and Rill. Work mill and junk baskets 14,880' to 14,885'. paR. 0600, 11/27/03 - 0600, 11/28/03 MW: 9.8 ppg Vis: 55 see Finish paR, LID clean out BRA. PIU drilling BRA and Rill. Direetionally drill 8-1/2" hole 14,885' to 14,992'. 0600, 11/28/03 - 0600, 11/29/03 MW: 9.8 ppg Vis: 48 see Direetionally drill 8-1/2" hole 14,992' to 15,173'. Prep to paR. 0600, 11/29/03 - 0600, 11/30/03 MW: 9.7 ppg Vis: 60 see paR. Test BOPE. Rill w/ new bit. Direetionally drill 8-1/2" hole 15,173'- 15,192'. 0600, 11/30/03 - 2400, 12/1/03 MW: 9.6 ppg Direetionally drill 8-1/2" hole 15,192' - 15,552'. Vis: 50 see e e 0600, 12/1/03 - 0600, 12/2/03 MW: 9.7 ppg Vis: 50 see DireetionallydriIl8-1/2"hole 15,552' to 15,592'. POR. Change bit, service BRA, RIH. 0600, 12/2/03 - 0600, 12/3/03 MW: 9.6 ppg Vis: 61 see RIH. Direetionally drill 8-1/2" hole 15,592' - 15,816'. 0600, 12/3/03 - 0600, 12/4/03 MW: 9.6 ppg Vis: 62 see Direetionally drill 8-1/2" hole 15,816' to 15,826'. POR, change bit, service BRA, RIH. 0600, 12/4/03 - 0600, 12/5/03 MW: 9.7 ppg Vis: 53 see RIH. Direetionally drill 8-1/2" hole 15,826' to 15,950' TD. Condition hole ./ for logs. 0600, 12/5/03 - 0600, 12/6/03 MW: 9.7 ppg Vis: 75 see C&C hole for logs. POR, LID drilling BRA. PIU TLC logging tools, RIH. 0600, 12/6/03 - 0600, 12/7/03 MW: 9.8 ppg Vis: 55 see RIH to shoe wi TLC logging tools. RIU SWS and side-entry sub. Rlli wi WL, latch into tools. RIH wi logging tools, would not pass 14,932'. Log 14,897' to 14,049'. POR wi WL, POR wi logging tools. LID logging tools. 0600, 12/7/03 - 0600, 12/8/03 MW: 10.0 ppg Vis: 55 see LID logging tools. Test BOP. PIU 8-1/2" c1eanout assy and RIH. C&C hole, POR to shoe, RIH. 0600, 12/8103 - 0600, 12/9/03 MW: 10.0 ppg Vis: 65 see C&C hole, noted pressure loss. POR looking for washout, set out 1 jt DP wi washout, RIH. C&C hole, POR, LID hole opener. PIU TLC logging tools, RIH. 0600, 12/9/03 - 0600, 12/10/03 MW: 10.0 ppg Vis: 55 see RIU SWS, RIH wi WL and latch into logging tools. Trouble shoot continuity problems - unable to work caliper. RIH wi logging tools. Log out 15,905' to 14,000'. Unlatch and POR wi WL, RID WL. POR wi logging tools, trouble shoot at surface. 0600, 12/10/03 - 0600, 12/11/03 MW: 10.1 ppg Vis: 75 see Trouble shoot caliper tool. MIU TLC tools and RIH. RIU SWS and RIH wi WL, latch up. RIH wi logging tools. Log up 15,900' to 13,812'. POR wi WL and RID. POR wi logging tools. 0600, 12/11/03 - 0600, 12/12/03 MW: 10.3 ppg Vis: 56 see POR. PIU hole opener assy, RIH to 1,017'. Circ and service rig. POR & LID hole opener. MIU GR & SP logging tools on WL and RIH. Stopped at e e 14,872'. Log out of hole, RID SWS. PIU hole opener assy and RIB. Wash to btm, C&C hole. 0600, 12/12/03 - 0600, 12/13103 MW: 10.1 ppg Vis: 57 sec C&C hole to lwr MW to 10.1 ppg. Mix and pump lubricant pill. POH & SIB BHA. RIB wi SWS MDT tool on DP to 13,700'. R/U SWS and RIB wi WL. Latch up and RIB wi logging tool. Make sets at 14,370', 14,397', 14,411' and 14,448' . 0600,12/13/03 - 0600, 12/14/03 MW: 10.1 ppg Vis: 60 sec Log wi MDT. Make sets at 14,479', 14,542', 14,570', 14,621', 14,772', 14,877' and 14,938'. Tool failed. Trouble shoot tools and wet connect - NG. POH wi logging tools, LID MDT. Pressure test BOPE. 0600, 12/14/03 - 0600, 12/15/03 MW: 10.0 ppg Vis: 55 sec Finish testing BOPE. RIB wi 8-112" hole opener assy. Circ at shoe while LID SWS and L WD tools. RIB to TD, C&C hole, POH. 0600, 12/15103 - 0600, 12/16/03 MW: 10.0 ppg Vis: 60 sec LID hole opener. Change rams to 7". PIU 2,211' of 7", 32#, P-11O Hydril 521 liner. MIU liner hanger, RIB wi liner on DP. 0600, 12/16/03 - 0600, 12/17/03 MW: 10.0 ppg Vis: 55 sec RIBwllinerto 15,920'. MlUcmthead,RIBwllinerto 15,950'. Drop ball & set 1m hgr. Shear out, test lines & cmt 1m w/210 bbl of 15.8 ppg Class G cmt. Bump plug wi 2,000 psi. Reverse out & POH wi running tool. LID 69 jts DP, mg tool and cmt head. Change pipe rams fl 7" to variable. 0600, 12/17/03 - 0600, 12/18/03 MW: 10.0 ppg Vis: 60 sec Finish changing and testing rams. PIU 6" clean out assy & 3-112" DP. RIB, tag up on Indg collar @ 15,871'. Test casing to 3,000 psi - OK. POH, LID mud motor. 0600, 12/18/03 - 0600, 12/19/03 MW: 10.0 ppg Vis: 58 sec R/U SWS USIT & CBL. RIB to 15,850', USIT would not function. Logged wi CBL to 12,800' wi 500 psi on esg. Log to 3,800' wi GR. POH, LID tools. PIU back-up USIT tool and RIB. 0600, 12/19103 - 0600, 12/20103 MW: 10.0 ppg Vis: 59 see It e RIP wi USIT to 15,500'. Logout to 12,600' wi 500 psi on csg. POR, RID SWS. PIU scraper BRA, RIH to 15,871'. CBU, short trip 50 stands, CBU. 0600, 12/20103 - 0600, 12/21/03 MW: 8.3 ppg Vis: 28 sec Pump caustic pill followed by hi-vis pill followed by second caustic pill. Displace well wi seawater. Displace well wi seawater containing 1 % scale inhibitor. POR LID DP. 0600, 12/21/03 - 0600, 12/22/03 MW: 8.3 ppg Vis: 28 sec POR LID DP. Blow dn mud, choke & kill lines. Install test plug. NID and brk dn BOP stack and associated lines. 0600, 12/22/03 - 0600, 12/23/03 MW: 8.3 ppg Vis: 28 sec Finish N/D and brk dn BOP stack. Install tbg hgr, test hgr, hgr body & void to 5,000 psi - OK. Tst tree to 3,000 psi - OK. Rig off dayrate. 0600, 3/6/04 - 0600, 3/7/04 RIU Cudd snubbing unit. Weld pad eyes for guide lines. RIU Koomey hoses and function test. Move racking beams in place, spot equipment. 0600, 3/7/04 - 0600, 3/8/04 Install scaffolding, Continue spotting equipment. Receive and unload workboat. Spot mud tanks pumps and choke manifold. Run lines to pumps and choke manifold. Install windwalls on basket. Install PVT equipment and heaterin basket. 0600, 3/8/04 - 0600, 3/9/04 Pressure test jack to 2,500 psi. Install jack and pull-test pad-eyes to 20k lbs. Rad to modify walk-around to install jack. Install jack guidelines and fall descent pole on basket. Install ladder to basket and new power hoses to jack. Install work basket, control hoses and power cables. Ran guide lines off basket and RIU gin pole. 0600, 3/9/04 - 0600, 3/10/04 RIU standpipe, run line to trip tan1e Function test jack and slips. Fill pits with drill water and circulate pits. Shut down operations due to weather - 40 knot winds wi gusts to 55 knots, temperature -39 degrees, including wind chill. Insulate choke line. Weld bracket for winch. Install light on gin pole, install test pump in connex. Install heater, Run steam lines to heater in basket. RIU WOT tongs and hoses and function test. Run steam lines to BOP. RIU BOP remote station. RIU Epoch PVT equipment and test pump. It e 0600, 3/1 0104 - 0600, 3/11/04 Function test BOPs from work basket. Function test test pump. AOGCC waived witnessing BOP test. M!U test joints to hanger. Shell test BOPs to 3,000 psi. Repair leaking chicksans, repair two lo-torque valves. Pressure to 3,000 psi - OK. Test BOPE 250/3,000 psi. Insulate chicks an lines while testing. Continue rigging up LID post, guide lines, hand rails, etc. while testing. MIU test joints, pull hanger, set wear bushing, LID test joints. Unload workboat, layout, strap and tally tubulars. R!U and tighten jack guidelines. Start PIU BRA, replace 4-R packing on Rusco directional valve. Continue PIU BRA: 6" bit, bit sub, 7" scraper, xo, 12 ea 4-3/4" DCs, 4-3/4" jars, xo to PR-6 tubing. 0600,3/11/04 - 0600,3/12/04 MW: 8.3 ppg Cont. PIU BRA. Rill, picking up 9-518" scrapers at 6,867' and 9,368'. Rill. 0600,3/12/04 - 0600,3/13/04 MW: 8.3 ppg Cont. Rill wi clean-out assy. Circ @ 5 bpm, 2000 psi. Mix and pump first spacer: 38 bbl drill water wi 110 gallons clean-up and 100# caustic soda. Second spacer: 39 bbls wtr wi 500# caustic soda. Third spacer: 40 bbls wtr wi 100# flo-vis. Fourth spacer: 40 bbls wtr wi 150# REC-10. Displace wi filtered 9.4 ppg NaCI- 5% KCI completion fluid @ 5 bpm, 2,000 psi. Short trip wi scrapers (Note: scrapers positioned at bottom, top ofliner and at 6,500' in 9-5/8" casing.) 0600,3/13/04 - 0600,3/14/04 MW: 8.3 ppg Finish POR to first scraper, then Rill. Circ brine through DE filtration unit until returns yield readings of 15 NTU, 116,000 ppm chlorides. !-1/4 circulations total. POR wi scrapers. 0600,3/14/04 - 0600,3/15104 MW: 8.3 ppg POR and LID bit and scrapers. PIU perforating gun assy. 0600,3/15104 - 0600,3/16/04 MW: 8.3 ppg Finish PIU perf assy wi 1320' guns (505' loaded), champ packer and OMNI circulating valve. Rill wi work string, filling pipe wi diesel cushion. 0600,3/16/04 - 0600,3/17/04 MW: 8.3 ppg Rill wi perf assy. Log top shot on depth at 14,350' and set packer. Pressure up to 1500 psi - guns fired. Tubing did not pressure up or flow. Bleed annulus to 500 psi and open bypass. Reverse circulate at 3 bpm, 800 psi. e e Returned 18 bbls dry pipe (by volume), 86 bbls diesel, 8 bbls gas (by volume) and 10 bbl crude. Stop and monitor well after receiving 9.4 ppg brine. Static. Circ 1.25 times bottoms up at 3 bpm, 1000 psi. No gas or crude in returns. 6.5 bbls lost during circ. Pump slug, pull pkr loose and circ prior to POR. Total losses prior to trip 45 bbls. 0600,3/17/04 - 0600,3/18/04 MW: 8.3 ppg CBU, lost 32 bbls during this circ. POR wi perf guns. LID perf assy. Total fluid lost to fm to date 78 bbls. 0600,3/18/04 - 0600,3/19/04 MW: 8.3 ppg Finish POR wi perf assy. All shots fired. Test BOPE. PIU BOT Retrieva ./ SC-l 9-5/8" production packer and RIH. Shut down due to high winds - 40- 50kts, gusting 50 kts. Continue RIH. Fluid loss to fm 1 bph. Total lost since perfing 87 bbls. 0600,3/19/04 - 0600,3/20104 MW: 9.4 ppg RIH wi 9-518" pkr. SID due to winds. Continue RIH wi pkr and set @ 13,630. POR wi pkr running tool. Total fluid lost to fm 109 bbls. 0600,3/20104 - 0600,3/21/04 MW: 9.4 ppg Finish POR wi BOT running tool. M/U SWS LLC valve and RIH. Total fluid lost to fm 133 bbls. 0600,3/21/04 - 0600,3/22/04 MW: 9.4 ppg Cont RIH wi LLC valve. Set in SC-l pkr @ 13,630'. Fill backside wi 9.4 ppg brine and POR wi running tool. Drain stack, pull wear bushing, R/U to run ESP assy. Fluid losses stopped when LLC valve set. Total losses to fm 143 bbls. 0600,03/22/04 - 0600,03/23/04 MW: 9.4 ppg PIU and M/U ESP assy and RIH wi same. RIH wi 3-1/2" TRS PR-6 production tubing, installing Cannon clamps every other jt. Splice ESP cable @ 2,636'. Install gas lift mandrels. 0600,03/23/04 - 0600,03/24/04 MW: 9.4 ppg Cont in hole wi ESP completion, installing clamps and GLMs. Splice ESP cable @ 6,580' and 10,495'. 0600, 03/24/04 - 0600, 03/25/04 MW: 9.4 ppg e e ;ý Finish Rill wi ESP completion to 13,445'. Installed total of231 Cannon clamps. MIU tbg hgr wi BPV on last jt of tbg. Splice ESP cable to hgr penetrator. RID and clean equipment. Land tbg hgr, lock dn and test to 5,000 psi - OK. RID Cudd unit. 0600, 03/25104 - 0600, 03/26/04 / RID Cudd unit. N/D BOP stack and riser. NIU production tree and terminate control lines. Test tbg head adapter to 5,000 psi for 15 min. - OK. Pull BPV, insta1l2-way check, test production tree to 5,000 psi for 30 min. - OK. Cont to pressure wash and backload Cudd unit components. 90% done. 0600, 03/26/04 - 0600, 03/27/04 RU #7 placed on production. Demob Cudd and assoc equipment from platform. Tear dn BOPE. Organize remainder of equipment for load out. e e Forest Oil Corp.,Leg#2, Slot#2 Osprey Platform, Redoubt Shoal,Cook Inlet, Alaska SURVEY LISTING Page 1 Wellbore: RU#7 Well path: MWD <0-11348'> Date Printed: 3-Mar-2004 '&1. .... INTEQ 1~lIbore RU#7 I Created 8-0ct-2003 I Last Revised 23-Nov-2003 I=~ 'Jo' #7 I ~~7:~~;~~~~0526-00 I ~~~~~t~~~~~ 200897.821 Grid IField ="~ Shœ I Eastina Northina 200897 821 I~~~ IN-".'- I ?448015.61 0 ~ R . __ FBICAN OAIliM 1927 _m .. Grid Crêåted B C.omments All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Rig #429 90.0ft above Mean Sea Level) Vertical Section is from 1966.598 222.59E on azimuth 128.68 degrees Bottom hole distance is 6137.97 Feet on azimuth 116.15 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated e e Forest Oil Corp.,Leg#2, Slot#2 Osprey Platform, Redoubt Shoal, Cook Inlet, Alaska SURVEY LISTING Page 2 Well bore: RU#7 Wellpath: MWD <0-11348'> Date Printed: 3-Mar-2004 '&1. ..,. INTEQ Wellpath (Grid Report MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing rdea/100ftl Sectionrftl 0.00 0.00 000 000 O.OON OOOE 000 -1402R3 20067523 ?LlLlQQR? ?11 q5.1111 11 311 3111 1111 95.00 0.16N 0.19W 0.32 -1403.08 200675 11L1 ')AAooa') ~&:: 190.00 0.30 330.00 190.00 0.54N 0.51W 0.11 -1403.56 200674.73 2449982.74 ?7q.1111 0.48 143.00 279.00 0.44N 040W ORR -1403.41 200674.R4 ?LlLlQQR? Rð. 315.1111 11 Ll3 ql1 1111 315.00 0.32N 0.17W 1.14 -1403.16 ?11111;75111; ')AAooa') ,,') 368.00 0.84 118.00 367.99 0.13N 0.38E 0.94 -1402.62 200675.61 2449982.34 45R.00 2.14 14ROO 457.q6 160!,; 1 R5F 1M -1400.3R ?00677OR ?LlLlQQRI1 1;11 548.00 493 136.00 547.7R 5R18 543¡:: 31q -139496 2006RO.66 2449976.39 638.00 8.77 134.00 637.12 13.37S 13.05E 4.28 -1384.28 200688.28 2449968.84 663.00 934 13R4q 661R1 16 ?1!'; 1577F 31;3 -13RO 3q ?1111&::Q1 1111 ?LlLlQQA" QQ I;qR 1111 10.89 137.43 696.27 20.778 19.R9¡:: 445 -1374.32 200695.12 2449961.43 752.00 12.99 135.00 749.10 28.82S 27.63E 4.01 -1363.24 200702.86 2449953.38 841.00 15.62 136.74 R3533 44K\!,; 4?q?F 300 -134143 20071R.15 ?LlLlQQ':t7 "R q3?00 1R 57 131; 33 922.30 64.038 61.33¡:: 3.24 -1314.93 ?1111731; 51; ,)AAo01a.17 1028.00 20.89 143.11 1012.67 88.79S 82.17E 3.39 -1283.19 200757.40 2449893.41 1122.00 21.61 145.15 1100.2R 116408 10212¡:: 110 -125037 200777.35 ?LlLlQRI;" R 1 1?17 00 ??RI1 1L11 51 1188.23 145.168 123.57¡:: 1.91 -1215.64 ')f\f\70a af\ ')AAoa~7 f\A 1309.00 25.94 138.30 1272.03 174.14S 148.06E 3.71 -1178.41 200823.29 2449808.06 1404.00 27.53 136.68 1356.R7 205.M8 17695¡:: 1R4 -11361R 200R52.1 R 2449776.57 14qR.00 ?R,R3 1?R 55 1439.76 235.588 209.59E 4.31 -1091.98 200884.82 ')AA07A&:: &::') 1593.00 31.54 123.54 1521.88 263.59S 248.23E 3.89 -1044.31 200923.46 2449718.61 1684.00 33.RO 119.94 159R4R 2R93R!,; ?qO.01 F 3?7 -qq557 ?I1I1QA" ?LI ?LlLlQI;Q? R? 177q 1111 35 LlR 116.65 1676.65 314.948 337.56¡:: 2.65 -942.4R 201012.79 ?LlLlQI;1;7 ?I; 1873.00 36.03 118.56 1752.93 340.40S 386.22E 1.32 -888.59 201061.45 2449641.81 1 ql;R 1111 35.67 117.76 1R2994 366ñ5!,; 43527¡:: Oñ2 -R33RR 20111050 ?LlLlQI; 1" "" ?01;1 00 351;0 11511q 1 ql15 53 390.768 483.79E 167 -780.94 20115q 11? ?LlLlq5q1 LILI 2157.00 36.33 114.64 1983.22 414.47S 534.94E 0.81 -726.19 201210.17 2449567.73 ??Llq 1111 31; 75 115.81 2057.14 437.R28 5R4.50¡:: O.RR -672.92 201259.73 ')AAO"AA ~o ?343.00 37.4q 115.0? ?13? I1q LlI;? 1 I;~ 1;35731" 11 qLl _1;1771 ?1113111 ql; ')AAO",)f\ f\A 2436.00 37.98 115.84 2205.64 486.60S 687.13E 0.75 -562.31 201362.36 2449495.60 ?53?00 3R.q5 115.30 2280.81 512.378 74100¡:: 1.07 -504.15 201416.23 ')AAOA&::O a~ ?6??00 37.q3 114 qR ?351.30 531; 1L1~ 7q11;5¡:: 1 15 -L1L1q 71; ?01L11;1; RR ,)AAOAAA f\A 2717.00 37.96 113.99 2426.22 560.35S 844.81E 0.64 -393.13 201520.04 2449421.85 ?R11 00 37.17 114.62 2500.73 583.938 897.03¡:: 0.94 -337.62 201572.26 ,)AAO~O~ ?7 ?qm.oo 37.0R 11550 ?574.0q 1;07L15~ qLl7 'I'll" 11 5q _?R3 1;1; ?011;?? 51; ,)AAO~7 A 7" 2997.00 37.76 116.52 2648.75 632.50S 998.66E 0.98 -227.93 201673.89 2449349.70 30qO 1111 31; q7 115.45 2722.66 657.238 1.10 -172.87 201724.62 ,)AAO~,)A 07 31R3.00 37.3R 11L1 1;3 2796.76 681.028 0.69 -118.26 201775 ,,3 ,)AAO~f\1 1q 3278.00 36.40 113.69 2872.74 704.36S 1152.33E 1.20 -63.06 201827.56 2449277.84 33711 1111 31; 115 112.88 2946.97 725.858 1 ?11? ?I;¡:: 0.64 -10.65 201877.49 ?LlLlQ?51; ':t5 341;3 00 31; 7? 112 RR 311?1 RLI 7L17 311~ . ""''' Am-- 0.72 LI? LILI ?111q?R3? ')AAO,)~A Of\ 3500.00 37.59 112.36 3051.32 755.89S 1273.72E 2.50 63.91 201948.95 2449226.31 3535 00 31;.R5 11? RR 3079.20 764.038 1 ')o~ ,)&::I:: 2.30 84.25 201968.Llq ')AAO')1a 17 :\566R6 37.00 11? qR 3104.1;7 771.4q~ 1310 RqF 11 51 10?I;R ?01qRI; 1? ')AAO?1n 71 3573.05 37.10 112.86 3109.61 772.95S 1314.32E 1.99 106.27 201989.55 2449209.26 35qR q1 37 RLI 113 LlR 31311 13 77q 13~ 1328.79E 3.21 1?1 LI? ?f\?f\f\A f\? ?AAO?f\~ f\7 361R.76 :\R.R1 11:\.q5 :\145.70 7R4 oq!'; 1 ~Af\ f\AI:: 510 1:\:\ :\? ?f\?f\1" ?Q ?LlLlQ1QR 1? 3628.07 38.91 113.65 3152.95 786.44S 1345.40E 2.29 138.96 202020.63 2449195.76 :\6:\R 70 :\q ?1 113.43 311;1.?0 7Rq 1?~ 1351 5L1¡:: 311 1L15 Ll3 ?11?0?1;.77 ?AA01 O~ f\a 364R.66 :\q66 112q? :\16R,QO 7Q1 1;1!,; 557 151 5? ?0?0:\?5Q ?LlLlQ1QI1 "Q 3659.00 39.80 112.63 3176.85 794.17S 1363.45E 2.25 157.88 202038.68 2449188.04 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Rig #429 90.0ft above Mean Sea Level) Vertical Section is from 1966.59S 222.59E on azimuth 128.68 degrees Bottom hole distance is 6137.97 Feet on azimuth 116.15 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated e e Forest Oil Corp.,Leg#2, Slot#2 Osprey Platform, Redoubt Shoal, Cook Inlet, Alaska SURVEY LISTING Page 3 Wellbore: RU#7 Well path: MWD <0-11348'> Date Printed: 3-Mar-2004 r&i. .... INTEQ WellDath {Grid' ReDort MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing dea/100ftl Sectionrftl 'II;I;R Q"I 'IQ 1;1; 112.26 31R44Ç! 7Ç!65Ç!~ 1">"" ">')E::: 277 163.Ç!7 202044.55 :".. 'I1;7R ?? 'IQ4R 11? ?R 3191.65 798.838 1">7A 7CE::: 1 Q4 169.65 ?O?O<=;O O? :">7 3688.87 39.17 111.53 3199.89 801.35S 1381.06E 5.33 176.11 202056.29 2449180.85 'II;QR QR 'IR 7<=; 111.1 Ç! 3207 7<=; R0367~ 1">0" nOE::: 466 1R21R ?O?OI;? ?1 i<;4 'I70Q ?R 'IR41; 110.75 3215.RO 805.Ç!7S 1'1Q?QR~ "I.RR 188.30 202068.21 : ?4 3720.79 38.10 110.29 3224.83 808.47S 1399.66E 3.99 195.08 202074.89 2449173.74 3731.27 377:'\ 11004 '12'1'1.10 R101;Q!=: 140<=;.70F 'I R? 2011 R 'Jo'JoRo Q"I "oj '1741 ?? "17 "IQ 110.3R 3240.Ç!Ç! R127R~ 1411 "IQ~ 400 206Ç!4 'Jo'JORI; I;? .'" 3751.11 37.03 110.80 3248.86 814.88S 1416.99E 4.45 212.62 202092.22 2449167.32 "171;0 Q7 3661 1113R 3?<=;ñ 7ñ R17.01~ 1422 <=;OF <=; <=;3 21R26 2020Ç!773 - .- .-- 1Q '177107 'Iñ.41 111.97 3264.RR 81 Ç!.23S 14?R.OQ~ 400 22400 'Jo'J10"> ">'J '" ."'.."'''' Q7 3781.29 36.10 112.83 3273.12 821.53S 1433.68E 5.83 229.80 202108.91 2449160.67 'I7QO 1R 'I<=; QI; 113.66 32R031 R23fiO~ 1A">OAOE::: 571 234.R4 - .-..-- 1;1 'IR01.0" 'I<=; ñ7 11476 32R9.12 826.20S 1AAA ')OE::: 1;4Q ?41 nn 00 3814.73 35.42 115.53 3300.25 829.58S 1451.48E 3.75 248.73 202126.71 2449152.62 "IR"IO "1"1 'I"4R 115.60 3312Ç!6 R33.4Ç!S 14"Q 1;4~ 0.46 257.55 "'''''''A''> 0.., 'IR7ñ 00 'I4.QO 11<=; ñO 3350.28 844.868 1Ao"> ">oE::: 1 ?7 ?R'I1R '14 3909.16 36.81 116.93 3377.16 853.46S 1500.79E 6.23 302.15 202176.02 2449128.74 40Q7 1;1; 'Iñ.RQ 11R.27 352R.00 905.R3S 1~OO.Q7~ 04"1 413.08 41Q"I40 'Iñ.<=;Q 11R <=;0 3604.73 933.058 1ñ<=;1 'I"F 0'14 4ñQ4"1 1" 4383.15 36.99 116.36 3756.69 985.39S 1752.21E 0.71 580.87 202427.44 2448996.81 447470 'I<=;.QO 115.Ç!5 3R30.33 100Q "17<:: 1 R01 o"l~ 122 633.Ç!7 4<=;I;Q. I; 1 'II; <=;<=; 116.38 3906.RÇ! 1034.10S 1R<=;1 "I7~ 074 I;RR 7? 10 4662.47 37.29 115.25 3981.13 1058.39S 1901.58E 1.08 743.10 202576.81 2448923.81 47"4 RR '1707 113.26 4054 7ñ 10R133~ 1Q"'J "o~ 132 7971Ç! 4R47 17 "I<=; R7 11444 4128.97 1103.518 1 <=;1 R<=;O ?1 4940.79 35.20 113.43 4205.15 1125.59S 2052.41E 0.95 902.84 202727.64 2448856.62 <=;O"l47n 'I<=; 71; 111 .55 42R1ñ2 114643~ 131 955.18 <=;1?771 'Iñ.?R 11'14'1 435685 1167.368 ?1 <=;'I."IOF 1.'11 1 007 71 '" AnnA n_ 5221.52 36.29 113.04 4432.46 1189.26S 2204.32E 0.25 1061.22 202879.55 2448792.94 <=;'11 1;. 'I<=; '11;40 113.96 450RR4 1211 fi7S o <=;Q 111546 202931.09 <=;411.41 'Iñ4ñ 111;.70 4<=;R'1.33 1?'I<=; R?!=: 1 71 1170 'IR 11 5505.27 36.53 116.50 4660.78 1260.81S 2356.79E 0.15 1224.97 203032.02 2448721.39 <=;<=;QI; o<=; '11;.47 115.56 4733.76 1284.51S ?40".'I1~ o I;? 1277.66 <=;ñQ1 Q'I 'Iñ.27 1147ñ 4810.96 1 'lOR I;R!=: ?4<=;1; 77F o <=;4 1'I'I2Q4 "'A An",..,,,, _'" 5786.02 36.29 114.66 4886.81 1331.96S 2507.35E 0.07 1386.97 203182.58 2448650.24 <=;RRO 1? 'II; "1 115.70 4Ç!6255 1355.72S 0.70 1441.26 203233. 11 A'" <=;Q7? 4R 'II; <=;0 111; ?7 5036 7Ç! 1'17Q 7Q<:: 0"17 14Q4 RI; ?O'l?R? <=;0 6065.35 36.51 115.74 5111.44 1404.01S 2656.93E 0.34 1548.76 203332.16 2448578.19 1;11;0 Q? 'II; <=;? 114.55 51RR.25 142R.1RS ---- .-- 074 1604.05 ?O'l'lR'II;'I ". '0"'" n,,> ñ?<=;4.4<=; 'Iñ.7"1 114.00 <=;?1;'I.31 1451.118 04? 1 ñ<=;R OQ 'Jo<I.ð.":>4 "0 ?44R<=;31 OQ 6345.81 36.64 114.68 5336.58 1473.61S 2808.99E 0.46 1710.97 203484.22 2448508.59 f\4'1Q.7? 'II; 7n 1144<=; 5411.90 14QI; Q?C:: 011; 171;<=; 'II; ?O"l<=;'I<=; ?'I ?4A OA 0" ')0 ñ<=;'I? ñO 370? 114 <=;'1 <=;4RI; ?? 1520.028 o 'I<=; 1R1Q'IR 'Jo"l"R" 0"1 'J4MI.ð..I;'J 1R 6627.33 37.01 115.04 5561.86 1543.93S 2962.48E 0.32 1874.74 203637.71 2448438.28 ñ7?O.7Q 'Iñ'l1 114.7Q <=;1;'11; R'I A""'''' .">~ "''''A''' n",_ 077 1Q?R Q'I 'Jo":>l':oo ":>'J 'J44041477 ñR1ñ27 3ñ31 11<=;50 <=;71'177 1<=;Q1 4ñ~ n^'" "'..,_ 0.44 1Ç!R3Ç!0 ?O"l7"1Q "0 ')AAO">CO 7A 6908.37 36.69 114.15 5787.81 1614.45S 3113.99E 0.96 2037.09 203789.22 2448367.75 7002 f\4 3<=; QQ 1144Q <=;R1;3 74 1637.468 'I1ñ4.RQF 077 20Q1 ?O ?03R40 12 ')AAO">AA 7A 700740 35.R2 1135Ç! <=;Ç!40.!'i7 1ññO.12~ ^^A_ "''''_ 05R 2145.02 'Jo"lRQO Q? ')AAO">'J'J 00 7189.93 35.92 113.68 6015.48 1681.84S 3265.31E 0.12 2197.33 203940.54 2448300.37 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Rig #429 90.0ft above Mean Sea Level) Vertical Section is from 1966.59S 222.59E on azimuth 128.68 degrees Bottom hole distance is 6137.97 Feet on azimuth 116.15 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated e e Forest Oil Corp.,Leg#2, Slot#2 Osprey Platform, Redoubt Shoal, Cook Inlet, Alaska SURVEY LISTING Page 4 Well bore: RU#7 Well path: MWD <0-11348'> Date Printed: 3-Mar-2004 '&ií. ~ INTEQ Wellcath {Grid' Recort MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing Idea/100ftl Sectionlftl 728?81 ~R4Q 114 8~ ROQO 4? ~'\1".'\'\F o Q" ??e;nAR ~. ?448?77R~ 7~7800 36.21 115.04 R1R70Q 172R.1RS ~~~~ .~~ 1'1 ':I? ?~ "'''A''A. 7.., ?AAR?"A rut 7472.21 36.17 115.10 6243.12 1751.73S 3416.88E 0.06 2359.34 204092.11 2448230.47 75RRR8 ~R.R4 114 'i4 R'\1Q.1R 1775?7~ :-I4nf 'I- o R1 ?A1':1 77 ~" ?AAR?nR QA 7658.47 36.31 114.55 R~Q2.Q7 1797 Q':\e:: n.':\R ?4RR.RR "'''A.a.., "'" "'AA"HIA ?7 7753.43 36.81 113.85 6469.24 1821.12S 3569.00E 0.68 2521.45 204244.23 2448161.08 7847.45 ~R.~4 114.?8 R544 7" '\R?O 1 "F 0"7 ?5~ ?IiA.,ae;. ':IR ?AAR1':1R ?A 7Q4125 ~R15 112Q~ RR?0.40 18RR.17~ 0.87 ~ "'''A'''A'' ..,,, 244811R03 8035.91 36.10 112.86 6696.85 1887.88S 3722.38E 0.07 2682.91 204397.61 2448094.32 81'\071 ~R.75 114.78 R77'\.14 ~~~~ ~~~ 1.'\8 ?7~7 '\1 "'''A A A""" ?448071 58 8222. QO 3R.94 117.01 R84R.Q2 ~~~~ r~~ 1 A7 ?7Q1?? ?n.d4QR.R? ?AARnA7 AA 8316.28 37.72 117.60 6921.17 1960.74S 3873.90E 0.92 2846.73 204549.13 2448021.46 R40R.~5 ~R.57 11 R.11 RQQ4.5R ."01: oce> ~~~~ .~~ 1 58 ?Q01.1A ~ "'AA,nnc 'JA 8504 71 35.82 115.5? 7072~2 ?n1n Rile:: ':IQ7A7?¡:: 1'1 RR ~ -;;"A"Aa a", 2447971.56 8599.76 36.27 115.19 7149.17 2034.59S 4025.26E 0.51 3011.04 204700.49 2447947.61 8RQ4.47 ~RRO 11~74 7??" '\7 ?057.88~ 407R 45F o Q7 ':InRe; e;7 ~R ?AA7Q?A ':I? 8755.52 36.39 113.27 727445 ?n7? ':IRe:: 410Q.7e;¡:: 1'1 e;7 ':\1Mi::1 ?n47RA QR 8782.71 36.60 113.15 7296.31 2078.74S 4124.61E 0.80 3116.19 204799.84 2447903.47 8877.RO ~758 1144? 7:<7? 01 ?1 01.8?~ 1 '\1 ':1171 AQ ~" 'J" 8975.11 36.47 113.Q4 7449.85 2125.87S 117 <\??R ':14 "'''Aa"", 7R 9067.73 36.58 113.98 7524.29 2148.26S 4280.90E 0.12 3281.65 204956.13 2447833.95 Q1R?8R ~7.n 1nQ1 7ROO 11 ?171 57~ 4'\'\'\ 41 F 1 ?1 ~ ~~;:;~. 925689 37.22 114 71 7R74n 21Q512S 4~85 54F n7e; ':I~ ?ne;nRn.77 :.144 (lSf .lJlS 9353.87 37.26 115.80 7751.94 2220.16S 4438.62E 0.68 3449.71 205113.85 2447762.04 Q448 7Q ~R~5 11504 78?7 Q4 ??AA e;7C: 44RQ.Q7F 1 07 '\"0".0" ~~r.~ 9'i44 49 36.52 115.1 ~ 7Q04Q4 ??RR R7e:: 454145F n1R ':\~ -;:;"~~.,, "''> ~. .~~.~ ".. 9637.03 36.38 115.18 7979.38 2292.04S 4591.21 E 0.15 3613.75 205266.44 2447690.17 Q7~0.~0 ~R27 11541 80'i4 5? ?':I1e; RAe:: 4R41 1RF 01Q ':IRR7 e;n ~n 9769.26 35.99 115.78 8085 QQ 2325.57-<:: A cc. ""E: 1'1 Q1 ':\RAOR7 ?n",:\,:\7 11 9823.87 35.52 116.44 8130.31 2339.61S 4690.53E 1.11 3721.02 205365.76 2447642.59 QQ17~7 34.74 115~" 8?OR.78 nR~11S 1.07 .':I~ ?nCi:11A1 R 10011.33 35.57 115.30 R?R':\.Rn ..,,,,,,,,..,,,,e> 1'1 RR ':\R?R.1 ? ""~.,,'> "'" 10101.96 35.85 114.05 8357.19 2408.33S 4835.90E 0.86 3877.44 205511.13 2447573.87 10199.29 34.71 113.77 84~R R4 24~111S 1 1R ~ 2447551.09 '\4 ?? 11:<R7 RAR 1 "R "''>0 ,,'>.,.. 1.R'\ ,:\QAR ':\" ?0""7R 1 8 "A.I~I:A. .7 10291.79 33.39 112.91 8513.31 2451.78S 4934.73E 1.58 3981.76 205609.96 2447530.42 10':\R71':\ 35.22 114.08 85Q2.06 2473.21e:: .n~ ". ~ ? n4 .dn':l':l.R1 4 10482.52 35.98 114.34 RRRQ R? "'Aa", aac ~,,~ ,,~~ n R1 40R7 ':\R ?0"70Q RR 10578.37 38.37 115.12 8745.99 2520.22S 5087.25E 2.54 4143.59 205762.48 2447461.98 10673.27 37.86 114.75 88?OR5 ?e;AA Q?e:: 1'1 e;Q ~ 10766.96 37.32 114.37 RRQA RQ ..,"'"",,"c e;1Q?':Ie;¡:: 1'1 R':\ 4?e;<=; Q? ?0<=;RR7 "R 10860.47 36.66 114.04 8969.58 2591.75S 5243.66E 0.74 4310.39 205918.89 2447390.46 10953.07 37.44 113. Q1 Q04348 2R1442S 5?Q4.R4F ORe; ~i:;.;1;:¡i:: (~ 11049.21 '\7 ?R 11? 7A Q11 Q Q1 ?R"'7 "'. c o 7R 4A?0 R1 ~~~~~~ .~ " '~'>A c" 11143.68 36.31 112.55 9195.56 2659.30S 5400.41E 1.01 4474.98 206075.64 2447322.91 1· ..,"'" ,,'" 35.73 112.R8 Q27? e;? ..,,,,,,, ".c e;Ae;?07¡:: o R1 4""R 7e; ?ORP7.'\0 ..,AA7",n. ",a 1 n?7.Q1 '\4.18 11?'\<=; Q'\4" ,,? ?700.'\Re:: <=;4QQ.??F 1 7" 4"77 77 n~~.~ .~ ?AA7?R1 RA 11348.48 34.14 112.57 9362.54 2704.77S 5509.89E 0.63 4588.86 206185.12 2447277.43 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Rig #429 90.0ft above Mean Sea Level) Vertical Section is from 1966.59S 222.59E on azimuth 128.68 degrees Bottom hole distance is 6137.97 Feet on azimuth 116.15 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated e e Forest Oil Corp.,Leg#2, Slot#2 Osprey Platform, Redoubt Shoal, Cook Inlet, Alaska SURVEY LISTING Page 2 Well bore: RU #7 ST #1 Wellpath: MWD <10921 -15950'> Date Printed: 3-Mar-2004 '&1. BAKlR IIUGIIIS INTEQ Wellpath (Grid' Report MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing r dea/1 OOftl Sectionfftl 10860.47 36.66 114.04 8969.58 2591.75S <'''A'''''''''''' 000 5713.22 ')nc:a1 Q Qa ,~^^^ '^ 109?1 97 :<R.11 11".RO 901909 1 7" "74R.R4 ')nc:ac:') nn ")AA7'>7" 1" 1 0975.37 34.83 118.23 9062.58 2621.07S 5304.40E 3.73 5778.97 205979.63 2447361.13 AAn<,nOA 35.00 119.02 9131.84 534684E 0.57 "R?R "7 ')n~n')') n7 111M "7 :<4 R9 117.44 9?:<4 09 ?R7R.0:<~ "409 7RF 0.7:< "R9R R? ')n~n¡:¡c: n1 ?LlLl7':\nLl18 11280.36 34.91 115.19 9312.65 2702.32S 5458.90E 1.34 5950.35 206134.13 2447279.89 11374.04 35.13 115.12 938937 2725.17S 0.24 6002.62 ')n~1 Q') 7a A A A"" "0 :<4 9? 113.77 9464 42 2746.93S <'<'<'<' A.... 0.88 RO":< RO ?OR?:<0.R7 "A A 7")'>" ")7 11554.80 35.28 112.93 9537.33 2767.24S 5602.49E 0.68 6103.02 206277.72 2447214.96 11652.21 35.92 113.22 961654 278947S "~"A ~"E: 0.68 6157.63 ')n~<I')a QQ ?44719? 74 1174R nR 36.18 113.69 9694.05 2811.92S 5706.41 E 0.40 R?1? 07 ?OR:<R1 R4 ^. '~A~^ ^^ 11840.25 37.02 113.50 9768.04 2833.92S 5756.77E 0.92 6265.13 206432.00 2447148.28 11921.22 37.81 114.26 9832.35 "0<''' 00" 5801.75E 1.13 6312.69 ')n~A 7~ aQ "A A7A "0 :<7 1 ?O:<1 R" :<7."9 11" 74 9919 R9 "00" A"'" <'0"" n".... OM R:<7R 4? ')n~C:,:\Q ?a 7Q 12111.40 37.59 115.08 9982.92 2903.25S 5906.89E 0.51 6425.65 206582.12 2447078.96 12219.11 37.46 113.22 1nnR¡:¡ ':\" 1.06 6489.15 ?nRR41 9R ')LlLl7nc:? 1? 1?':\10.R1 ':\7.?" 114 R':\ 1n1A1 ,)A 1 09 R"4? 9R ')n~~a? Qn 12403.59 36.71 115.13 10215.36 2976.30S 6068.16E 0.61 6597.20 206743.39 2447005.90 37.68 114.99 10?QO ?R <lnnn <lac 1.04 RR"? 4R ')n~7aA ¡:¡a ?44R9R1 R? ':\7 ':\? 114,44 10:<R:< ?" ,:\n')<I Qnc 0."':\ R70R RO ?06R4" 76 "AA"""D .n 12684.74 37.49 114.34 10438.81 3047.66S 6223.15E 0.19 6762.79 206898.38 2446934.54 12777.05 37.20 113.71 1n"1? ?n <ln7n A~C "'".,. "n.... 0.52 6816.96 ')n"aAa c:') ?44R911 7" 1?R7?':\R ':\7.4':\ 11? R9 10"RR 01 ':\09':\':\1~ 0"7 RR7? RR ')n7nn? ~n "A A "ODD 0" 12962.58 37.87 114.35 10659.43 3115.39S 6377.85E 1.10 6925.88 207053.08 2446866.81 13061.38 37.28 115.60 10737.74 <l1An Q')C 0.98 6984.41 ?n7107 R9 ?44RR41 ':\R 1:<1"1.7R :<7."9 11" 1" 1 nQna c:') ':\1R4 ':\7~ R4R? 11F 04R 70:<7 R9 ?071 "7 :<4 13246.53 36.11 113.38 10885.34 3187.748 6533.90E 1.92 7092.92 207209.13 2446794.47 1:<4':\4 4R ':\" ?':\ 111.84 11038.03 <I')')a QQC 0.67 719R ?':\ ')n7':\1n ?a ,)LlLl~7C:? ':\') 1:<"1R}\4 :<".OR 11? :<R 1110497 :<?47 R1~ 04? 7?4:<.39 2073"395 ?LlLlR7':\Ll <;Q 13614.19 34.95 112.08 11185.12 3268.84S 6730.68E 0.20 7297.22 207405.91 2446713.37 '^~^~ ^^ :<4."7 111.RO 11?RO ?Q <I,)QQ <I<IC 04" 7:<47.1 R ?n7LlC:Ll ':\n "AA"""'> 07 1379846 3"."6 110,47 113:<62? :<:<07 54~ 1 3" 7397.99 ?n7<;nLl n1 ,,)AA""7A "7 13895.38 38.67 111.18 11413.50 3328.34S 6883.43E 3.24 7453.65 207558.66 2446653.86 4? QO 11:<.42 114R3.00 :<:<"1 1:<~ 4 R7 7"111Q ?07614.11 244663107 1401107 4392 114.29 11 "00.3" 33"7.77~ ^"~^ ^".... 49" 7"2705 207629.12 ,,)AA~~,,)A A<I 14138.07 49.73 114.06 11587.21 3395.68S 7038.35E 4.58 7616.67 207713.58 2446586.53 14??Q ,,? "0.14 111.QR 11R4R.07 ':\11')':\ n':\c 710? 7RF 1 R1 7RM 0" ?07777.99 14324.19 "004 1111? 1170R R1 ':\LlLla ~ac 7170:<1F o RQ 77"3,44 ?n7¡:¡Ll<; <;Ll 14373.58 50.71 113.59 11738.31 3464.16S 7205.48E 4.08 7789.95 207880.71 2446518.04 144R1 1? "1 R1 114 17 11793.09 3491.80S 7267.92E 1 :<R 7R"".QR ?07Q4:< 1" ^. '^'"'' '" A'"'''' ,>n "4 :<? 11" Q9 11R49.RQ :<"?:<.7?~ 7:<:<R.ORF :< OR 7Q?Q 1? 20801131 """"<'0 AO 14651.59 56.80 117.31 11904.14 3559.35S 7407.04E 2.81 8006.79 208082.27 2446422.85 14747.RO RO."4 11" R" 11 Q"i4 OR <lc:a~ n')c 411 RORR Q" ')n¡:¡1C:C: ~1 1484467 61.26 110 Q? 1?OO1.?Q ':\~')a ~~C 4."0 R16872 ?n¡:¡?,:\,:\ Ll':\ 14939.99 65.74 109.64 12043.81 3659.20S 7638.20E 4.85 8249.64 208313.43 2446323.00 , ~^^ ~ ,~ R771 111 :<1 1')n¡:¡1 c:':\ ':\~¡:¡a¡:¡¡:¡c ? R? R:<:<?Q4 ?n¡:¡,:\QC: C:7 15130.20 70.34 111.11 1211544 ':\7?1 ¡:¡¡:¡e:: 780281E 2.78 8417.32 20847804 15250.59 74.22 115.03 12152.09 3766.84S 7908.26E 4.47 8527.73 208583.49 2446215.36 1"'>1A 0" 7386 114.86 1?1~Q 7~ ':\7Q? Qne:: 7"". ,,)DE: 062 8587.76 ?n¡:¡R,:\Q "1 2446189.30 :'>41:>. 1 75.39 114.69 1?1QR "n ':\¡:¡':\':\R"~ 1.53 8682.15 ?OR7?7 RO "AA"AAO"" 15454.24 74.47 115.37 12206.52 3849.39S 8086.28E 2.93 8718.30 208761.51 2446132.81 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Rig #429 90.0ft above Mean Sea Level) Vertical Section is from O.OON O.OOE on azimuth 128.68 degrees Bottom hole distance is 9430.91 Feet on azimuth 115.12 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated e e Forest Oil Corp.,Leg#2, Slot#2 Osprey Platform, Redoubt Shoal,Cook Inlet, Alaska SURVEY LISTING Page 3 Well bore: RU #7 ST #1 Wellpath: MWD <10921 -15950'> Date Printed: 3-Mar-2004 '&i. .... INTEQ Well MD[ft] North[ft] East[ft] Easting Northing All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Rig #429 90.0ft above Mean Sea Level) Vertical Section is from O.OON O.OOE on azimuth 128.68 degrees Bottom hole distance is 9430.91 Feet on azimuth 115.12 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated e e @ FOREST OIL CORPORATION .'110 oYCC'fI~r<X?t. C'7;u;(e 700 09t'nchÆPrafl<? ~ QQÍI,/M';,a .9g50 1 (907) 2.S8-86'OO · (.907) 258-86'01 (Ci'Pax) April 19, 2004 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 Re: Well Completion Report and Log: Redoubt Unit #7 Dear Mr. Norman, Enclosed please find the Well Completion Report and Log required by the AOGCC's approval of Permit to Drill #203-150 to drill and complete Well RU #7. Enclosed please find: Form 10-407 Well Completion or Recompletion Report and Log· Wellbore Schematic Summary of Daily Operations Well bore Directional Survey CD containing in digital format all logs run in the well If you have any questions or require additional information, please contact me at 868- 2135 or Bill Penrose at Fairweather at 258-3446. Sincerely, Û~" . . .' ¡! Î la¿~ -> ../ .~ Paula Inman Production Engineer - Alaska Division Enclosures RECEIVED APR 1 9 2004 Alaska Oil & Gas Cons. Commission Anchorage ORIGINAL @ . FOREST OIL . CORPORATION .510 Q/{;¿9tJCPÆ{. ¿¡l:u:W 700 QQÍJ'u:luÞra!1e~ Qx1la:Jka <9.9501 (.907) 2,5/1-/56'00 · (907) 2,78-//6'01 (dßax) January 28, 2004 Acting Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 Re: Redoubt Unit Well #7 Completion Dear Sir, Forest Oil has released the drilling rig from Redoubt Unit Well #7 after setting and cementing the 7" production liner. The well will be completed utilizing a hydraulic workover unit as outlined in the attached summary completion procedure. This is different than the completion procedure (which used the rig) submitted in the Application for Permit to Drill. Also attached are a completed Form 10-403 for the work, a summary testing and completion procedure, a wellbore schematic and a BOP configuration diagram for the snubbing unit to be used. If you have any questions, please contact me at 868-2132 or Bill Penrose at Fairweather at 258-3446. Sincerely, k~ Roy Smith Drilling Manager - Alaska Division Forest Oil Corporation RECEIVED JAN 2 8 2004 Attachments: 10-403 Application for Sundry Approvals Outline Procedure Wellbore Schematic 13-5/8" 5M BOP Schematic Alaska Oil & Gas Cons. Commission Anchorage OR\('\NAL · STATE OF ALASKA ALA' OIL AND GAS CONSERVATION COM.ON APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 W6Â- ÛJS I 12- 't /2.cOoq Î I <-'7 (1- Development Stratigraphic o D Perforate D Waiver U Annular Dispos. U Stimulate D Time Extension D Other D Re-enter Suspended Well D 5. Permit to Drill Number: 203-150/ 1. Type of Request: Abandon U Alter casing D Change approved program 0 2. Operator Name: Forest oil Corporation 3. Address: 310 K Street, Suite 700, Anchorage, AK 99501 7. KB Elevation (ft): 90' MSL 8. Property Designation: Redoubt Unit 11. Total Depth MD (ft): 15,950' Suspend D Repair well D Pull Tubing D Operational shutdown D Plug Perforations D Perforate New Pool D 4. Current Well Class: Service Exploratory D D 6. API Number: 50-733-2052~ 9. Well Name and Number: Redoubt Unit #7 / 10. Field/Pools(s): Redoubt Shoal Oilfield / Redoubt Shoal PRESENT WELL CONDITION SUMMARY Length Effective Depth MD (ft): Effective Depth TVD (ft): 15,870' 12,311' Size MD TVD Plugs (measured): N/A Junk (measured): N/A Total Depth TVD (ft): 12,332' Casing Structural Conductor Surface Intermediate Production Burst Collapse 215' 3,528' 14,049' 36" 215' 3,528' 14,049' 215' 3,088' 11,528' NIA 5,020 psi 6,870 psi NIA 2,260 psi 4,750 psi 13-3/8" 9-5/8" Liner 2,242' 7" 15,950' 12,332' 12,460 psi 10,760 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): NIA NIA NIA NIA NIA Packers and SSSV Type: NIA Packers and SSSV MD (ft): NIA 12. Attachments: Description Summary of Proposal ~ Detailed Operations Program D BOP Sketch 0 14. Estimated Date for Commencing Operations: 16. Verbal Approval: Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Bill Penrose 258-3446 Printed Name Roy Smith Title Drilling Manager ..... - Signature µ... -C.. a-li. Phone 868-2132 Date / /,;;q 7(;.1,/ I COMMISSION USE ONLY Date: 13. Well Class after proposed work: Exploratory D Development 0 15. Well Status after proposed work: 2/10/2004 Oil 0 Gas D Plugged D WAG D GINJ D WINJ D Service D Abandoned WDSPL D D Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ..307'-.?J¿) 3 Plug Integrity D BOP Test IKI Mechanical Integrity Test D Location Clearance D R E eEl V E, Other: Teç~ BOPE -fo ŠOOO P$¡· JAN '2 8 2004 ~€ý' 20 Me 'Le;. l2-~~ (~)) t\.-t~~.. ~.}SOP~'o~.. iIttd" ,.. C r' ~ ~Ø$ afl. rto Alaska 011 & uas OilS. . .~. Anchorage Subsequent F ~,,,/d: " 0 7 / / ~ I n~IGINAL BY ORDER OF App","e,Ib" I /.../ 'A /' COMMISSIONER THE COMMISSION D'te' ð/ /Jb ~f- Form ~ Revise~ -- INSTRUCTIONS ON REVERSE Su mit in DU~licate Waiver Request for Forest Oil's RU #7 Completion . . Winton, Forest Oil recently submitted to the Commission an Application for Sundry Approval for a modification to its completion plans for well RU #7. As an addendum to that request, Forest Oil further requests a waiver to the requirements of 20 AAC 25.285(e)(6) which requires that the kill and choke lines be assembled without hammer unions unless the Commission determines that those joints do not compromise the maintenance of well control. Due to the small size, portability and adaptability of the hydraulic pulling unit being used for this work, the choke line downstream of the outer choke valve and the kill line downstream of the check valve contain hammer unions. It is Forest Oil's position that the unit's choke and kill system as currently configured is sufficient for work on RU #7 and similar wells on Osprey Platform due to the under-pressured character of the reservoir. OVerall platform production history and recent fluid levels shot in shut-in wells indicate that the in situ reservoir pressure will not support a fult column of fluid in the wells. RU #7 is currently full of filtered Inlet water and will remain full until it is perforated at which time it will go on vacuum until the fluid level reaches an equilibrium level. A positive pressure is not expected to be seen at the surface at any time during;'completion operations. The chance of any pressure being observed at the surface is extremely remote and, even if it did occur, it would be of such low pressure and volume that the existing BOP system could handle it safely. As a further consequence of the benign pressure environment at Redoubt Shoal, Forest Oil proposes to modify Step 1 of its previously submitted completion procedure to call for testing the BOPE to 3,000 psi instead of the stated 5,000 psi. Please contact me at 258-3446 (office) or 250-3113 (cell) if you have any questions or require additional information. Regards, Bill 1 of 1 1/29/2004 2:36 PM . . Redoubt Unit #7 Completion Procedure for Stimulation and Testing FRAC & TEST MIDDLE HEMLOCK 1. Nipple up hydraulic pulling unit with 13-5/8", 5K BOP stack. Ensure blind shear rams are installed. Test BOP's, choke manifold, lines and valves to ~si. /1, J/é L- .t ~OéJO ""~;}ftU~~ 2. Make-up 6" bit without jets, 12 ea 4-%" drill collars with tandem casing scrapers $r 7", 32#/ft casing and 2 ea 9-5/8", 53.5#/ft casing scrapers positioned within 30' ofT' liner top and halfway in the 9-5/8". 3. Trip in hole picking up 3-W', 12.95 #/ft, P-IlO, WTS-6 tubing to PBTD of 15,871' MD. Thread protectors are to be installed on pin end on each trip. .-".. (Note: Depth needs to be corrected to new elevation with hydraulic unit.) Break circulation periodically while going in hole. The 3-112" work string will be used as the perforating and frac string. Use stabbing guides on each connection, and lightly dope pin ends with Weatherford's recommendation of pipe dope. Optimum make-up torque is 7,875 ft-lb (minimum = 7,000 ft-lb; maximum = 8,750 ft-lb). Drift the work string as it is picked up off-line (2.625"). Numerous trips with the 3-112" work string will be required throughout completion operations. Periodically change breaks while tripping the work string to distribute wear on the BTS-6 connections. 4. Circulate bottoms up and then displace wellbore with filtered 9.4 ppg, 5 % KCl ,/ completion fluid. Continue circulating until returns have an NTU reading of less than 75. 5. Make wiper trip to scrape both the 7" and 9-5/8" casing strings. ..-- 6. Pull out of hole, racking back 3-W' tubing. 7. Rig up wireline lubricator and test to 1,500 psi. 8. Rlli with cased hole MDT tools and sample at depths detennined by Production /' Engineer and/or Reservoir Engineer. 9. POR and rig down wireline. 10. Trip in hole with 6" bit without jets and clean out wellbore to PBTD. ,/ 11. Circulate and filter completion fluid. 12. POOR. . . 13. Pick-up TCP gun assembly and trip in hole. Rig up Schlumberger, run tie-in strip and /' perforate Hemlock interval. 14. Reverse out after perforating. POOH. 15. Make up Baker Production packer and trip in hole. Set packer +/- 200' above top / perforation and test backside to 1,000 psi. 16. Trip out of hole, pick-up LLC valve and run & set same in Baker production packer. / 17. Pull out of hole, laying down 3-Yz" work string. 18. Make up ESP pump assembly and trip in hole picking up 3-Yz", 9.3#/ft, L-80 & P-110 tubing to within +/- 200' of the LLC valve. Land tubing hanger in wellhead. ,/ 19. Set BPV in tubing hanger. 20. Nipple down 13-5/8" BOPE and Cudd hydraulic unit. 21. Nipple up and test 3-1/8" production tree. 22. Pull BPV. ("/ 23. Turn well over to production and demobilize equipment. Not yet perforated Welded 5'TVD 13-3/8",68#, L-80, @ Top oflìner 13,708'MD 9-5/8",47#, L-80, BTC @ 14,049'MD/l 7", P-ll0, Hydri1521 @ 340k Jack Unit Lift Cap:340,000 Snub Cap: 170,000 Rotary Cap: 9,700 ft/1bs II"Bore 288" Snub Unit & Work Basket 45.2" 55.8" 23.5" 84" Elevation 192" (16') 120" '" 9 Dee, 03 rev 0, no scale Jack Swivel Spool13c5/8" Drillíng Spool Annular BOP, Blind/Shear Ram, Flow Cross, 5M 3-1/2"Pipe 7' Spool, 13-5/8" 10' Spool, 13-5/8" 5M 340k Jack Unit Lift Cap:340,000 Snub Cap: 170,000 Rotary Cap: 9,700 ft/lbs 11" Bore 9 Dee, 03 rev 0, no scale 130.8" ".. 24" 23.5" 45.2" 55.8" 23.5" ~'~. Swivel Spool 13-5/8" "'~'"." 2" Ì5'Q~ Weco Fill Line Drilling Spool 13-5/8" 5M Annular BOP, l3-5/8" 3-l/2"Pipe Blind/ Shear Ram, 13;5/8" Flow Cross, 11" 5M 3-l/2"Pipe Ram, Choke Line 7' Spool, 13-5/8"5M 1 0' Spool, Osprey for Operations on 9 Dec., 03, revO, fb, Re: Pending 403s] .~ . . "Subject: Re: Pending 403s] From: sarah palin <spalin@mtaonline.net> Date: Fri, 23 Ian 2004 11 :40:08 -0900 To: Dan Seamount <dan_seamount@admin.state.ak.us> looks great - here's my approval. Sarah Palin Original Message ----- From: "Dan Seamount "~(.1'·' To: "Sarah H Palin" Sent: Friday, January Subject: [Fwd: Pending 403s] Here are the 403's. the 401's will come later. thanks, dan -------- Original Message -------- Subject: Pending 403s Date: Fri, 23 Jan 2004 10:04:31 -0900 From: Winton Aubert <winton aubert@a~~in.state.ak.us> ----~-_.._--~----~---- Organization: State of Alaska To: Daniel Seamount <dan seamount@admin.state.ak.us> Dan, Pending 403s are Forest Oil well RU #7 - operations shutdown (received 1/15/04), BP well 03-33A - add perforations to existing injection zone (1/21/04), Marathon well KBU 42-07 - add perforations to existing producing zone (1/22/04). WGA Iofl 1/23/2004 I: 11 PM @ . FOREST OIL . CORPORATION /y/' _CÄ _CP . /NO Q/1" ('o/tM!er - C'i/tu(e 700 QYhl<;·hO'J(aa.e, Q9Ílo,jka .9.9.501 (;7 (907) .258-8600 · (.907) 258-8601 (CjPax) January 14, 2004 Ms. Sarah Palin, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 Re: Redoubt Unit Well #7 Operational Shutdown Dear Ms. Palin, Please find attached an Application for Sundry Approval for an operational shutdown of Forest Oil's Redoubt Unit #7 well. Forest Oil has released the drilling rig from RU #7 after setting and cementing the 7" production liner. The well will await the demobilization of the platform's drilling rig and the mobilization of a hydraulic workover unit before operations recommence to test and complete RU #7 as an oil producer. The operational shutdown is expected to last from the date of rig release on December 23, 2003 until the hydraulic unit commences operations on RU #7 approximately February 4, 2004. If you have any questions, please contact me at 868-2132 or Bill Penrose at Fairweather at 258-3446. Sincerely, ~~ Roy Smith Drilling Manager - Alaska Division Forest Oil Corporation Attachment: 10-403 Application for Sundry Approvals RECEIVED JAN 1 5 2004 Alaska Oil & Gas Cons. Commission Anchorage OQfGft\f.AL . .' _ STATE OF ALASKA ALASJlllbIL AND GAS CONSERVATION COMM.N APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 )./(p fJT-5 t/1f'4- 1. Type of Request: Abandon U Alter casing 0 Change approved program 0 2. Operator Name: Forest Oil Corporation Suspend U Repair well 0 Pull Tubing 0 Operational shutdown ~ Plug Perforations 0 Perforate New Pool 0 4. Current Well Class: Perforate TI Waiver U Stimulate 0 Time Extension 0 Re-enter Suspended Well 0 5. Permit to Drill Number: Annular Dispos. U Other 0 3. Address: 310 K Street, Suite 700, Anchorage, Alaska 995001 7. KB Elevation (ft): Development 0 Stratigraphic 0 Exploratory 0 203-150 Service 0 6. API Number: 50-733-20526-00 90' MSL 9. Well Name and Number: Redoubt Unit #7 8. Property Designation: Redoubt Unit 10. Field/Pools(s): Redoubt Shoal Oil Field I Redoubt Shoal PRESENT WELL CONDITION SUMMARY 11. Total Depth MD (ft): 15,950' Casing Structu ral Conductor Surface Intermediate Production Liner 2,242' Perforation Depth MD (ft): Well not perforated Packers and SSSV Type: Total Depth TVD (ft): 12,332' Length Effective Depth MD (ft): Effective Depth TVD (ft): 15,870' 12,311' Plugs (measured): None Junk (measured): None Collapse Size MD TVD Burst 13-3/8" 9-518" 215' 3,528' 14,049' 215' 3,088' 11,528' N/A 5,020 psi 6,870 psi NIA 2,260 psi 4,750 psi 215' 3,528' 14,049' 36" Perforation Depth TVD (ft): NIA Well not yet completed Tubing Size: Well not completed Packers and SSSV MD (ft): Tubing Grade: NIA 11,640 psi 10,760 psi Tubing MD (ft): N/A 7" 15,950' 12,332' Well not yet completed Commencing Operations: 16. Verbal Approval: Commission Representative: Estimate recommencing approx 2/4/04 Date: 13. Well Class after proposed work: Exploratory 0 Development 0 Service 0 15. Well Status after proposed work: Oil 0 Gas 0 Plugged 0 Abandoned 0 WAG 0 GINJ 0 WINJ 0 WDSPL 0 12. Attachments: Description Summary of Proposal ~ Detailed Operations Program 0 BOP Sketch 0 14. Estimated Date for 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name /) Ro~ Smith / Title Drilling Manager Signature v.. J...ù::r:fO Phone 868-2132 Date COMMISSION USE ONLY Contact Bill Penrose 258-3446 I )/, d_-Á f Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3D 4- _ 0 I ç Mechanical Integrity Test 0 Location Clearance 0 Other: 40~0--~\,\'\~\,a'" ~rW((\\ \,ros~~ .-\-~ \,,>~~~ ù~~\Q~~\"""'~ RECEIVEr) S"bæq"eotFo,m Req";«'" '-\ () '"' "" """ '"' "" ~ \, \ ." <"O<v\ ~ \ '1. ~J J A N I 5 2004 Approve<t by fl¡ / ~ 0 ~M~~'~~R A L Plug Integrity 0 BOP Test 0 . ~ / Form 10-403 Revised 12/2000 Alaska Oil & Gas Cons. Commission BY ORDER OF Anchorage J_ . / THE COMMISSION Date: "ï / 2) / 1-- , INSTRUCTIONS ON REVERS~ 16ft JAM t~mim~Plicate RE: Forest Oil RU #7 Completion Report . . Tom, Certainly what's intended for this well is an operational shutdown. There's no intent to suspend the well, just to stop operations long enough to get rid of the big Nabors rig and bring in the Cudd hydraulic unit (considerably less expensive). Roy Smith is the best person to provide an estimate of when we expect to get over RU #7 with the Cudd unit and, since we'll be meeting with him tomorrow, why don't we discuss it then? Regards, Bill -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Monday, January 12, 2004 11:06 AM To: Bill Penrose Subject: Re: Forest Oil RU #7 Completion Report Bi.ll, It all depends on the timing. In an attempt to answer your question I looked at the file for a 403 requesting to suspend the well. I did not find one. I do have your email where you provided drawings of the proposed snubbing stack, etc. I am aware that operations have been halted pending the rig removal and then the wo on RU#l. This actually sounds like an operational SD rather than a suspension. When is it anticipated that operations will resume?? Tom Bill Penrose wrote: Tom, 10f2 1/16/20047:47 AM RE: Forest Oil RU #7 Completion Report . ~ ",. . I've been working under an assumption that lid better check with you on before any more time has passed by. Forest Oil finished has finished drilling RU #7 and set production casing. At this point, they've suspended well operations while they demob the rig. They intend to come back to the well to test and complete it with the Cudd hydraulic unit as soon as the rig has been removed and the hydraulic unit is finished on a workover of RU 1. I'm assuming that you want the Completion Repot within 30 days of the completion of the well for production, not within 30 days of the release of the drilling rig. Is this correct? Regards, Bill 20f2 1/16/20047:47 AM Nabors 429 / Osprey Platform ~ 'J. . . ., Gentleman, we have run & cemented our 7" production liner. The liner has been tested tI 3,000 psi for 30 min wI no pres 10ss.The drill string has been laid down. At the present time nld operations are underway. We will be installing the tubing hanger & production tree tomorrow and testing same. Plan forward will be to demobe the rig. Mike Mello I Charlie Gray Forest Oil 1 of 1 1/16/20047:48 AM Re: BOP test notification . . Subject: Re: BOP test notification Date: Mon, 03 Nov 200309:15:56 -0900 From: Jim Regg <jimJegg@admin.state.ak.us> Organization: AOGCC To: Forest-Oil Company Representative <ospreycm@starband.net> CC: Admin AOGCC Prudhoe Bay <aogcc--prudhoe_bay@admin.state.ak.us> ~iL r J1) 2(J3~ 150 Thanks for the notice; we waive our witness for the 11/4/03 BOP test. Jim Regg Forest-Oil Company Representative wrote: > Jim, We are due to do our weekly BOP test on Tuesday, NOV. 4 th. This bi t > should be pulled on or about then and if you wish to have an inspector > witness the test please contact us. (I will call the North Slope line also.) > Shelby Switzer and Mike Murray. L",,,...,,., Jim Regg <Hm regg@admin.state.ak.us> Petroleum Engineer AOGCC Administration 1 of 1 11/312003 9: 16 AM Re: Redoubt Unit #7 . e Subject: Re: Redoubt Unit #7 Date: Fri, 26 Sep 2003 13:04:29 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Rob Stinson <RDStinson@forestoil.com> Ja~--l5U Rob, You and I discussed the casing problems that have been encountered and the proposal to cement higher. Substituting the P-110 should markedly improve the strength of the design through that interval. I will put this message in the RU #7 file. Tom Maunder, PE AOGCC Rob Stinson wrote: > Tom, > > In order to increase our collapse resistance in RU #7, we have made a > change to the 9 5/8" intermediate casing. The well plan that AOGCC approved > had 95/8" 47# L-80 the entire length. We are now running 47# L-80 from > Surface to 9,730' MD and from 9,730' MD to 14,370' MD we will have 53.5# > P-11 O. Due to the higher strength of this design, we are reducing the > planned cement job down to what we have been running in the past. The > planned cement job now calls for 500' of 15.8 ppg tail and 1,500' of 12.5 > ppg lead, both with 100% excess. > > 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 9/26/2003 1 :04 PM @ 3500' Csg Test Ru#7 13 3/8 Pressure -Bbls íñ j5 .f.': - "'0 (I. Q. E :;::¡ a.. (I. E :;::¡ Õ > 8 o 00 -1 7 6 5 4 3 2 1 3500 3000 2500 2000 (I. ... :;::¡ ~ 1500 (I. ... a.. 1000 500 0 1: -500 e . c?s¡re, p( ç e ()..3fl (PíDZc:~ DATE TIME PUMP _PF BBLS I:~ 3k 'I ~ ksJ- PSI 1/t"'/03 20030915 13:57:00 13.362 0 20030915 13:58:00 15.644 0 20030915 13:59:00 15.644 0 20030915 14:00:00 141 .167 0.4 20030915 14:01 :01 351.134 0.8 20030915 14:02:01 437.859 1.6 20030915 14:03:01 483.504 1.8 20030915 14:04:01 789.325 2.3 20030915 14:05:01 1003.856 2.9 20030915 14:06:01 1188.718 3.3 20030915 14:07:01 1460.305 3.8 20030915 14:08:01 1683.965 4.2 20030915 14:09:01 1921.319 4.6 20030915 14:10:01 2179.212 5.1 20030915 14:11 :01 2302.453 5.3 20030915 14:12:01 2544.371 5.7 20030915 14:13:01 2834.217 6.3 20030915 14:14:01 2996.256 6.7 20030915 14:15:01 2943.764 6.7 20030915 14:16:00 2914.095 6.7 20030915 14:17:00 2891.273 6.7 20030915 14:18:00 3000.82 6.7 20030915 14:19:00 2991.691 6.7 20030915 14:20:00 2973.433 6.7 20030915 14:21 :00 2964.304 6.7 20030915 14:22:00 2950.611 6.7 20030915 14:23:00 2943.764 6.7 20030915 14:24:00 2936.917 6.7 20030915 14:25:00 2927.789 6.7 20030915 14:26:00 2923.224 6.7 20030915 14:27:00 2918.66 6.7 20030915 14:28:00 2914.095 6.7 20030915 14:29:00 2907.248 6.7 20030915 14:30:00 2904.966 6.7 20030915 14:31 :01 2900.402 6.7 20030915 14:32:01 2895.837 6.7 20030915 14:33:01 2891.273 6.7 20030915 14:34:01 2886.708 6.7 20030915 14:35:01 2886.708 6.7 20030915 14:36:01 2882.144 6.7 20030915 14:37:01 2877.579 6.7 20030915 14:38:01 2875.297 6.7 20030915 14:39:01 2873.015 6.7 20030915 14:40:01 2868.45 6.7 20030915 14:41 :01 2868.45 6.7 20030915 14:42:01 2863.886 6.7 20030915 14:43:01 2863.886 6.7 20030915 14:44:01 2859.321 6.7 20030915 14:45:01 2859.321 6.7 20030915 14:46:00 2854.757 6.7 20030915 14:47:00 2854.757 6.7 20030915 14:48:00 2854.757 6.7 20030915 14:49:00 2955.176 6.7 20030915 14:50:00 1462.587 6.7 20030915 14:51 :00 6.515 6.7 20030915 14:52:00 0 6.7 20030915 14:53:00 0 6.7 20030915 14:54:00 0 6.7 20030915 14:55:00 0 6.7 20030915 14:56:00 0 6.7 20030915 14:57:00 0 6.7 . lllJ'Tf fþ fAI.I\\ III I~\ U LJ /Jù.b "rÙ . [-yz JÛ FRANK H. MURKOWSKI, GOVERNOR A1tASIiA. OIL AND GAS CONSERVATION COMMISSION Robert Stinson Drilling Engineer Forest Oil Corporation 310 K Street Ste 700 Anchorage AK 99501 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Redoubt Unit #7 Forest Oil Corporation Pennit No: 203-150 Surface Location: 1960' FSL, 272' FEL, Sec. 14, T07N, R14W, SM Bottomhole Location: 2000' FNL, 1750' FEL, Sec. 19, T07N, R13W, SM Dear Mr. Stinson: Enclosed is the approved application for pennit to drill the above referenced development well. This pennit to drill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. The pennit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. Forest Oil Corporation assumes the liability of any protest to the spacing exception that may occur. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the tenns and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, ~~~- Randy Ruedrich ~ Commissioner BY ORDER OF THE COMMISSION DATED this <...day of September, 2003 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Exploration, Production and Refineries Section ~ e FOREST OIL e CORPORATION /110 dYC Dc:J¿J'Pæ(. a:a£e 700 Q9I'nchßJ'U;7£' QS;Ý¡a.1kÆZ .9,9.5'01 (907) 2/;S-S6()0 · (.907) 2,'}(5'-86'Of (0ÞŒ1) August 29,2003 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill (Form 10-401) Redoubt Unit #7 Enclosed is the Application for the Permit to Drill the Redoubt Unit #7 development well from Forest Oil's Osprey Platform. This well is planned to penetrate the Hemlock formation on structure in the Northern Fault Block. The well will be drilled using water based mud to the 13 3/8" surface casing point. We will change mud systems at this point to an oil based system. The 8 'l2" production hole will be drilled with a brine based water base mud. All mud and cuttings generated from drilling this well will be disposed of down the existing Class II disposal well, RU #Dl. We are requesting a waiver to 20 AAC 25.035 (c). If there are any questions, please contact me at 258-8600. /':;.'-..j~2~~c¿ZY..J.' ,/,. iid:'l~';-;;:;t¿¿ ""J~~""""'-"'" .,' "Robert D. Stin'Sõn- / Drilling Engineer - Alaska Division Forest Oil Corporation ORIGINAL £-A/;) e STATE OF ALASKA . ALASKA OIL AND GAS CONSERVATION ~MMISSION PERMIT TO DRILL 20 MC 25.005 1 a. Type of work Drill: X Re-Entry: 2. Name of Operator Forest Oil Corporation 310 K Street, Suite 700 Anchorage, Alaska 99501 4. Location of well at surface 1960' FSL, 272' FEL, Section 14, T07N R14W, SM At top of productive interval 1350' FNL, 1700' FWL, Section 19, T07N R13W, SM At total depth 2000' FNL, 1750' FEL, Section 19, T07N R13W, SM 12. Distance to nearest 13. Distance to nearest well property line 12,300 feet RU #6 - 1,330 feet 16. To be completed for deviated wells Kickoff depth: 200 feet 18. Casing program size Hole Casing Weight Driven 36" nla 18 1/2" 13 3/8" 68 # 12 1/4" 95/8" 47# 8 1/2" 7 5/8" 29.7# Redrill: Deepen: 1 b. Type of well Service: 3. Address Exploratory: Developement Gas: 5. Datum Elevation (DF or KB) 90' MSL 6. Property Designation Surf (381203), TO (374002) 7. Unit or property Name Redoubt Unit 8. Well number Stratigraphic Test: Single Zone: 10. Field and Pool Redoubt Shoal Oil Field Development Oil: X Multiple Zone: 11. Type Bond (see 20 Me 25.025) Type: Statewide Oil and Gas Bond RLB0001940 Amount: $200,000 15. Proposed depth (MD and TVD) Redoubt Unit #7 9. Approximate spud date 02-Seo-03 14. Number of acres in property 23,526 16,239' MD 112,401' TVD . feet 17. Anticipated pressure (see 20 MC 25.035 (e)(2)) Maximum hole angle: 73 Maximum surface 1,447 psig At total depth (TVD) 5,580 psig Setting Depth Specifications Top Bottom Quantity of cement Grade Coupling Length MD TVD MD TVD (include stage data) nla Welded 200' Surf Surf 200' 200' n/a L-80 BTC 3,500' Surf Surf 3,500' 3,052' 7106 cu ft L-80 BTC 14,370' Surf Surf 14,370' 11,756' 3164 cu ft L-80 Hyd 521 2,069' 14,170' 11,617' 16,239' 12,401 ' 470 cu ft measured true vertical 20. Attachments: Filing fee: X Property Plat: X BOP Sketch: X Drilling fluid program: X Time vs. depth plot: Refraction analysis: 21. I herby certify that the foregoing is true and correct to the best of my knowledge: Signeq(J:';--::..T¡ 7 _ Robert Stinson Title: Drilling Engineer - Alaska Division ~ Commission Use Only Permit Number '7'\ API number I Approv1 da~_ / See cover letter ..2D-,3-I5"'u 50- 73~c>52..~"OOI /2/¿)3 for other requirements Conditions of approval Samples required: I] Yes )<[ No Mud log equired: I] Yes KNo Hydrogen sulfide measures I] Yes ~No Direètional survey required ~es I] No Required working pressure for BOPE I] 2M; IX 13M; I] 5M; I] 10M; l] 15 ... ""I\T\ ~~'-(}S ~O~ S' ," ') lJ ') Other: "3.QO'O Ç?";, ß\)V -\-<è.S \- c)\~£M<t, ~C>.-\~ t ~fr"\7'-' .JfJ / _ ~_ /. I. by order of 9 /. ~ /" Approved by ¡' ~- ~ , ~ -;.. ~ Commissioner the Commission Date~/ 0')1' ()y ./ 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet true vertical feet Effective depth: measured feet true vertical feet Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length Size Plugs (measured) Junk (measured) Cemented Measured depth True vertical depth Diverter Sketch: Seabed report: Drilling program: X 20 AAC 25.050 requirements: X Date: . Form 10-401 Rev. 12-1-85 ORIGINAL Submit in triplicate e e Attachments 1. Waiver Request 2. Outline Procedure 3. Well schematic 4. Unit Boundary Plat wI Proposed Well Path 5. Drilling Fluids Program 6. Pressure Information 7. Casing Design 8. Cement Calculations 9. Directional Information 10. Well Head Schematic 11. Nabors BOP schematic 12. Nabors BOP equipment list 13. Nabors Drilling Fluid System Description '\ e . Request for Diverter Waiver Forest Oil requests that the diverter requirements in 20 MC 25.035 be waived for Redoubt Unit #7 because Redoubt Unit #1, #2, #3, #4A, #5, #5A,.#6 and #D1 were all drilled from the same general surface location without encountering any shallow gas. -/ Mud logging / gas detection on these wells also shows no presence of gas. RU #4 did encounter gas sands in the 12 W' hole section. Subsequent drill stem testing indicated that the shallower sands with "shows" were wet. RU #7 will drill these sands "off structure" .. Mud weights planned for the surface interval are 8.5 ppg at spud,'building to 9.4 ppg at the 13 3/8" casing depth, due to drilled solids. These mud densities are consistent with the nine prior wells. . . Redoubt Unit #7 OUTLINE PROCEDURE 1. Rig-up Nabors Rig 429 on Osprey Leg #2, Slot #2. 2. Install weld-on starting head on 36" Pile. 3. Nipple up 24" low pressure riser to bell nipple. 4. Mix Spud Mud. 5. Directionally drill 18 W' hole to 3,500' MD, 3,052' TVD. Note: Annular velocity and mud viscosity will be important for proper hole cleaning in 'the 36" pile. 6. Condition hole to run casing. Space out hole to allow 7' to1O' of rat hole below 13 3/8" shoe. 7. Run the 13 3/8" casing to 3,500' MD. Land the 13 3/8" on the 24" landing ring. Configure the 13 3/8" string for an 80' shoe track. 8. Run in hole with 5 W' DP and stab-in stinger/centrilizer. Pump cement job. Discharge excess returns overboard. Displace 80% of the dillpipe volume. Pick up two stands and pump down drill pipe wiper dart. POH wi stinger. Note: If there are no returns at surface, perform top-job with AOGCC witness. 9. Nipple down 24" riser. 10. Nipple up Vetco-Gray 13 5/8" 5M Multi-bowl wellhead assembly on the 13 3/8". 11. Nipple up 13 5/8" 5M high pressure riser assembly and Nabors 13 5/8" 5M BOPE. 12. Test wellhead and BOPE to 3,000 psi Notify AOGCC 24 hours prior to test. 13. RIH. Test casing to 3,000 psi. 14. Drill out cement and float equipment. 15. After drilling 20', but no more than 50' of new formation, perform Leak off Test. Note: Leak off Test will be performed with the MI/Swaco injection pump. Shut the well in and pressure up the well at 0.5 bpm. Once pressure breaks over and stops increasing, continue pumping at 0.5 bpm for 10 minutes. Record all volumes and pressures during this test and send to the Forest Oil office. 16. Change over hole to Oil Base using detailed procedure from MI. 17. Directionally drill 12 W' hole to 14,370' MD, 11,756' TVD or until the top ofthe Hemlock formation is encountered. 18. Condition hole for casing. 19. Run and cement 95/8" intermediate casing to a depth of 14,370' MD. Planned top of cement will be 9,370' MD. Hang casing with 9 5/8" mandrel hanger in wellhead. Configure casing for an 80' shoe track. 20. Back off 9 5/8" landing joint and run 9 5/8" packoff. 21. Test 95/8" packoff. 22. RIH wi 8 W' drilling assembly. Test casing to 3,000 psi. 23. Drill out cement and float equipment. e e 24. After drilling 20', but no more than 50' of new formation, perform Formation Integrity Test to 10.5 ppg EMW. Change over mud system to Flo-Pro as per the MI procedure. There is a chance we will drill the 8 W' hole with the Oil Based Mud system. 25. Directionally drill 8 W' hole to 16,239'MD /12,401' TVD. 26. Condition hole for logs. 27. Run wireline logs. 28. Condition hole, Run and cement 75/8" liner from 14,170' MD to 16,239' MD. The cement job will be pumped while rotating and reciprocating the liner. Once the plug bumps, the liner hanger will be set hydraulically and the liner top packer will be set mechanically. The entire length of7 5/8" liner will be cemented, with an 80' shoe track. Cement will be retarded to provide +/- 8 hrs pumping time. 29. Clean out liner and test lap to 3,000 psi. 30. Change over to 5% KCl. 31. Run USIT / CBL log across the 7 5/8" liner. )Þ 'P1t~~~ ~ {T"C-'? 32. Run Baker retrievable packer on wireline. Set at approximately 14,000' MD. 33. Run Sclumberger LLC-3 valve on drillpipe, set in packer. 34. Run 3 W' ESP completion, as per separate procedure. 35. Nipple up 3 1/8" production tree. Redoubt UIJ.il#7 Casing Plan Surface.ation - Leg 2, Slot 2 181/2" Hole 121/4" Hole 8 1/2" Hole e 36" K-55 200: TVD 133# Welded 200' MD 133/8" l-80 3,052' TVD 68# BTC 3,5PO' MD TOC @ 9,370' MD Top of 75/8" liner @ 14,170' MD 11,617' TVD 95/8" l-80 11,756'TVD 47# BTC 14,370' MD 75/8" 29.7# 12:401' TVD 16,239' MD l-80 Hydril 521 e e Redoubt Unit #7 DRILLING FLUID PROGRAM '\ e e Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska IFE KEY ISSUES · G & I handlinQ of cuttings while drillinQ surface interval. The Eliminator will be used to grind cuttings on both the 18-1/2" surface hole and the 12-1/4" intermediate hole. Experience gained during Well RU #5 & RU #6 along with modifications made to the Elimi~ator skid should allow for a more smooth operation. Additi~ge installed on the Osprey Platform is designed to eliminate the need for any slowdown of drilling operations due to cuttings volume gene~ · HandlinQ of cement returns and surface mud. Recommendations developed during drilling of RU #6 will be incorporated in the handling of surface cement and spud mud. · Hole cleaninQ in the 12-1/4" interval. Since this interval will be drilled with oil based mud and at an angle of 35 - 50 degrees, high rheological properties and proper drilling practices developed on RU #4 will help eliminate cuttings bed buildup. Virtual Hydraulics will be run during the drilling of this interval in order to maintain hole cleaning efficiency. · Displacement of OBM to WBM. Since the production interval will be drilled with WBM we recommend using the procedure used for OBM displacement to KCI brine to accomplish this. · Wellbore stabilitv in both the 12-1/4" interval and 8-1/2" interval. Sloughing coal may become an issue. If this is the case, we recommend Soltex additions to the mud system in the range of 2 - 6 ppb. This action should be the first measure, and if coal sloughing is still and issue, then increased mud weight should be considered. e e IFE Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska Drilling Interval Summary o - 3500' 18-1/2" Hole Handling of large volume of cuttings without impacting rig operations. Hole cleaning. Wellbore stability. Minimize waste volumes. Spud Mud: Drilling Fluid Value: $9.63/bbl Injected in disposal well. Volume Start: 500 bbls Dilution Volume: 2700 bbls Volume End: 1663 bbls Volume Notes- recommend dilution as > 1 bbllft, MI Gel, Soda Ash, Caustic Soda, Drilling Detergent, Polypac UL, SafeCarb Coarse, G-Seal Derrick Flowline Shale Shakers, Desander, Desilter/Mud Cleaner 518 Centrifuge Eliminator, MTS 14 Hammer Mill, Slurry Tank, Vacuum System, Slurry Storage Tank, Injection Pump, Shear Mill (not expected to be needed Mud Volume 3203 bbls; Cuttings/Sludge Volume 3500 bbls. Shaker Tank = 80 bbls Eliminator Tank = 100 bbls Slurry Storage Tank = 150 bbls Vacuum Slurry Tank = 50 bbls U ri ht Stora e Tank = 500 bbls 9.5 -11.0 PPG > 50 - < 70 Funnel Viscosity 10 - 20% Drill Solids Hole cleaning - maintain 6 RPM reading @ 1.2 times hole diameter (1.2 x 18.5 = > 22) Water supply - communicate with Drilling Foreman twice daily re ardin water re uirements Hole cleaning, excess drill solids, wellbore stability, Forest Oil Corporation Well Redoubt Unit #7 Osprey Platfonn, Cook Inlet, Alaska Drilling Interval Summary Interval Key Performance Indicators o - 1500 ' 1500 - 3500 8.8 -9.0 9.0- 9.6 6 - 10 6 -12 60+ 60+ > 2700 Drilling Fluid Formula Surface Hole Spud Mud Formula No 336.43 0.08 0.039 11.55 0.50 0.001 0.23 0.26 Blend with seawater in active pits in a 50:50 ratio to 6 2.54 7 0.52 8 1.35 9.63 e e IFE Forest Oil Corporation Well Redoubt Unit #7 Osprey Platfonn, Cook Inlet, Alaska Drillin Interval Discussion 0' - 3500' (MD) 13 3/8" Casing · ROP, GPM · Estimated ROP for this interval is 50 - 100 ftIhr. · Estimated flowrate of this interval is 800 GPM. · Use Virtual Hydraulics models as a guideline for flowrates and hole cleaning. · Bit balling · Drilling Detergent may be used to reduce the possibility of bit and/or BHA balling. · Hole cleaning · High viscosity Gel/Seawater sweeps may be needed to ensure cleaning of gravel zones just below the 36" drive pipe. · NOTE: Due to the large diameter hole and the deeper casing depth, a higher viscosity fluid will need to be maintained longer to insure sufficient hole cleaning. · Lost Circulation · Seepage losses may be controlled with moderate additions of SafeCarb F, M, C, and/or G-Seal · Severe lost circulation should be handled with LCM pills such as the one listed for this interval. · Add 45 barrels of spud mud to slugging pit. Mix blend of LCM products & spot across the thief zone. " SafeCarb Coarse SafeCarb Medium 15 PPB 15 PPB G-Seal 15 PPB · Casing running fluid properties · The mud should be conditioned prior to POOH to run casing. Moderate or reduce yield point and progressive gel strengths in order to reduce surge pressure while running casing. A small addition of Polypac UL should help lower the fluid loss « 20 cc's) and tighten the wall cake prior to running casing. e e IFE Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska Surface Cement Recommendations I 0' - 3500' (MD) I 13 3/8" Casing ~ Over board line should be installed at the end of the aug4r but the valve closed. ~ Uprights should be empty, eliminator tank should be down to 15 or 20 bbls and unit should be down fewer than 50 barrels prior to the cement job. ~ All pumps should be checked and in working order. The injection pump should be primed and ready. ~ Borax should be readily available in the pit room and at the eliminator tank in order to retard any cement that may surface. ~ Have Swaco personnel and MI mud engineer attend the pre-job meeting with Forrest Oil, BJ Hughes, and Nabors Drilling. ~ Determine how much fluid will be needed to displace the cement and bump the plug. Discuss any available options in case pumps go down or cement job goes bad. ~ Station the MI mud engineer in the cellar with Phenothalen indicator to monitor for cement returns. ~ Station Swaco personnel on top of uprights, in G&I unit, and at the eliminator tank with radios. Run a radio check to establish communications. ~ Returns should go over the pit room shakers and pumped from pits through the yellow transfer line to the upright tanks. ~ The pit watcher should keep close eye on shakers for cement returns. If he observes any cement returns, he should immediately direct returns to the augur. Then he should call the cellar and direct all returns to be overboarded. ~ During cement operations, the pit level should be kept low to provide a cushion in case of emergency. ~.IÆ œ~ e e IFE Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska Surface Cement Recommendations I 0' - 3500' (MD) I 13 3/8" Casing " ~ Once adequate fluid is available for displacing cement (in the pits and in the upright tanks), additional drilling fluid may be sent down the augur, into the eliminator tank, pumped over the classification shaker and injected downhole. Injection should start when slurry unit has 100 barrels of volume. ~ Once cement has entered the casing by open hole annulus, the MI mud engineer should periodically check the 4" annulus line for cement/cement contaminated mud. ~ Once cement is observed, the MI mud engineer should direct the returns to the overboard line and notify the Forest Oil Drilling Forman of this. OPTIONS ~ If yellow line is being used by BJ during cementing, take returns to eliminator tank, use vortex or galiagher pump to move fluid to uprights and unit (a hose should be installed coming off the galiagher pump to the upright tanks. ~ Try to keep fluid volume low in the safeguard and slurry tanks in order to provide for back up. ~ Have vac lid and hoses on outside tote so you can vac fluid into them if necessary. ~ Have Borax readily available to retard cement returns if they occur. Add one sack of Borax for every 2 barrels of cement returns. e e IFE Forest Oil Corporation Well Redoubt Unit #7 Osprey Platfonn, Cook Inlet, Alaska Displacement to oil base mud. ~ Roll storage tanks to heat up oil mud beginning one day prior to displacement. ~ Change out any rubber goods to diesel resistant products. '\, ~ Rig up catch pans, and any other necessary clean up equipment prior to displacement. Cuttings tanks etc.. should be in place to capture cuttings, etc. once displacement has begun. ~ With 13-5/8" casing on bottom, condition mud and reduce surface volume through injection. ~ Pump cement, drop plug, and displace cement with spud mud. ~ Drill out float collar, cement, etc., with water base mud. Treat as needed with Bicarb and/or Desco CF to reduce rheological properties for displacement purposes. After drillout and leakoff test, ship all surface volume to the G&I unit for injection. Clean surface pits. ~ Insure all G&I slurry storage capacity is available to handle spud mud and spacer volumes ~ Once pits and lines are clean and inspected, build 75 - 100 barrel water base spacer (with seawater or drill water) in appropriate pit. ~ Transfer oil mud from tanks to appropriate active pits. ~ Monitor both ends of transfer to ensure no mishaps. ~ Change shaker screens to 80 & 50 mesh for initial circulation of oil mud. ~ Displace spud mud to oil base mud starting with water spacer. Rotate and reciprocate continuously during displacement. Pump at the fastest possible flow rate. Route the spud mud and water spacer to the G&I unit for disposal. ~ After drilling ahead and oil mud has warmed up, change shaker screens to 200 & 180 mesh if possible. ~ Plan to put coarse screens (50 to 80 mesh) on the last shaker panels after trips to allow oil mud to warm up. IÆ e IFE e Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska Drilling Interval Summary 3500 - 14370' 12-1/4" Hole Handling of large volume of cuttings wiN10ut impacting rig operations. Hole cleaning. Wellbore stability. Minimize waste volumes. VersaDrill OBM: Drilling Fluid Value: $83.81 /bbl Re-use in production interval. Volume Start: 1000 bbls Dilution Volume: 6000 bbls Volume End: 1500 bbls Volume Notes- recommend dilution as> .6 bbl/ft, Mapco 200, VG-69, VersaCoat, VersaWet, VersaHRP, VersaMod, Lime, CaCI2, MI Bar (Soltex for coal stability) Derrick Flowline Shale Shakers, Desander, Desilter/Mud Cleaner 518 Centrifuge Eliminator, MTS 14 Hammer Mill, Slurry Tank, Vacuum System, Slurry Storage Tank, Injection Pump, Mud Volume 5500 bbls; Cuttings/Sludge Volume 5000 bbls. Shaker Tank = 80 bbls Eliminator Tank = 100 bbls Slurry Storage Tank = 150 bbls Vacuum Slurry Tank = 50 bbls U ri ht Stora e Tank = 500 bbls 9.5 -11.0 PPG > 50 - < 70 Funnel Viscosity 10 - 20% Drill Solids Hole cleaning - maintain 6 RPM reading @ 1.2 times hole diameter (1.2 x 12.25 = > 15), circulate until shakers cleanup prior to trips Hole cleaning, excess drill solids, well bore stability, sloughing coal r:zj 81Æ Œœ Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska Drilling Interval Summary Interval Key Performance Indicators Drilling Fluid Formula Intermediate Hole Mud Formula 1 Oil 2 VG-69 3 VERSAMOD 4 LIME 5 VERSACOAT 6 VERSAWET 7 Water 8 CAC L2 6.33 12.46 9 Wei ht Material 18.94 9.39 $83.81 e e Forest Oil Corporation Well Redoubt Unit #7 Osprey Platfonn, Cook Inlet, Alaska IFE Drillin Interval Discussion 3500 - 14370' (MD) 9-5/8" Casing · ROP, GPM ... · Estimated ROP for this interval is 30 - 60 ftIhr. · Estimated flow rate for this interval is 750 - 800 GPM. · Use Virtual Hydraulics models as a guideline for flowrates and hole cleaning. · Lost Circulation · Seepage losses may be controlled with moderate additions of G-Seal. · Severe lost circulation should be handled with LCM pills such as the one listed for this interval. · Place 35 bbls oil mud in slugging pit. Add blend of lost circulation material. Spot across theft zone. SafeCarb Medium SafeCarb Coarse G-Seal · Coal Beds · Sloughing/running coal should be treated by adding 2 - 6 ppb Soltex to the mud system depending on the severity of the problem. NOTE: Soltex additions can reduce the rheology of the mud. Be prepared to add rheology modifiers (IMG 400, VersaMod, VersaHRP), as needed to maintain proper rheology. · For severe coal sloughing, a concentrated pill consisting of 15 - 20 ppb Soltex may be spotted across the coal bed prior to POOH for a trip. A slight amount of pressure (equal to the annular pressure loss) may be applied to the pill to squeeze it into the coal bed. · Casing running fluid properties · The mud should be conditioned prior to POOH to run casing. Moderate or reduce yield point and progressive gel strengths in order to reduce surge pressure while running casing. 15 PPB 15 PPB 15 PPB I Forest Oil Corporation Well Redoubt Unit #7 Osprey Platfonn, Cook Inlet, Alaska Hydraulics Profile r:¡J VIRTUAL HYDRAULICS® 12-1/4" Interval MD: 15513 It Operator: Forest Oil Corporation SnapShot 5.5" DP TVD: 11886 It Well Name: RU#7 PV 19 YP25 Bit Size: 12.25 In. Location: Osprey Platform C1993·2OJ1 Mo! l.L.C.· AI! Rights Reserved Date: 4/2112003 Country: Geometry Depth Angle Density Oblgal) PV,YP,LSYP Temp (oF) AV(ltlmin) Hole Clean Ind Pressure Loss ('Yo) '" 99 10.0 101 10.2 10.3 0 25 1 11.8 120 122 124 126 0 2(1) I() VG G F P . 25 51! 75 100 \v t &!1 '--.. """--. .. ¡..-... --...- -'.-. c._.c_._.. ¡-.. ..-.-. .1--.. ..-- m f-... ___h. "...00..- --. ..-.... '. -.... ............ "___no .......- 3750 13.375 -.- ---.. ---- --. -- ... ---- ~CD I ~n ¡ I-- - -- L. ...-- '- I i [-... ,.-. - ..1-.- ..-i f.-- - .... ::y¡,....-. .- -- ---- I &Q T ,~ I i I i I \\ I i ¡ \ ¡ I J;U ! Æl ¡ 15513 12-1/4 I, 11885 I e e Forest Oil Corporation Well Redoubt Unit #7 Osprey Platfonn, Cook Inlet, Alaska IFE Displacement to WBM PBTD Good displacement, minimize waste generation, FloPro Drill-In Fluid: Fluid Value: $90.43 Ibbl Injection in disposal well Seawater 1100 bbls; Spacers 230 bbls Volume End 0 bbls Mapco 200, Kleen-Up, Safe Surf, Safe Solv, Citric Acid, HEC, Eliminator, MTS 14 Hammer Mill, Slurry Tank, Vacuum System, Slurry Storage Tank, Injection Pump Spacers 200 + bbls; Seawater 1100 bbls; Pit Rinse +/- 1000 bbls Shaker Tank = 80 bbls Eliminator Tank = 100 bbls Slurry Storage Tank = 150 bbls Vacuum Slurry Tank = 50 bbls U ri ht Stora e Tank = 500 bbls 9.5 -11.0 PPG 45 - 50 Funnel Viscosity 2 - 6% Drill Solids Displacement Rate> 8 BPM, Continuous Displacement without Stoppage, Transferring large amounts of fluids Poor Displacement, Spills e e Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska IFE Recommended Displacement Procedure r······· , -..... . Drill String Vol: DP1 301.64 bbrs No Pipe , Drill String Vol: DP2 . 4.97 Drill 5I.ln. VOli:I~'~ ,~ ,.......... , Csg. Annular Vol: , 596.03 bb's 1052.40 5.50 x .4.778 x 13596 ft Csg. Annular Vol: .0 HWDP. 27.80 Csg. Annular Vol: 5.97 1052.40 ... ···~~~~:~~f;!Si~Æ ,.... Total Dr . T '- Calc. Strokes: Surft ., 11188 3 .......................,...... . ......... ,............... x ..--.-.--.. .-... .... 'Pump Output .º,º8~?!L Bato . . , Spacer Make Up:, . .. , . . .§p<I¡;E!rlrºi¡tÏ~~e· ... .... !3º~35tJt>i'~ .75 '.. . .30 -35 bbl's of Map¡;o 2(j0 .~~~, i 9.625 14370 ft I\ID W.'._'·n~ww.~~'__ .._..H?p<I¡;E!r_?l§E!~!er....J~..t>.tJi·~......'_~_._.~_ x . ................. ..............~ ,40 bbi's seawater w/4 ppb Carie Acid (3 !................ i , ,. [..: sac~s) :þ . Spacer Ùieawater . !40 bbi's t~;:t" "'d,"~ . e¡¡water:~ bbi's .' .... ,...... . .. ... '.. bb's seawater w/2 drums ,Surf ...................................... ....'§p<I¡;er... '40 bbi's 40 bb's seawater w/1 drum I<lE!!n-Up Spacer 6 Seawater 's seawater w/5 ppb HEC ¡;~~l.I,.Q~.r...ph.\!I<::it.r.içj\.(;i!i;..¡¡!i!i......... ---~."--.~.--.,,., add HEC; raise pH w/Caustic Soda; add' nftfn~~ Y IT neeaea Fill pits 3 & 4 with seawater and reverse I.. . --'~ ! sweeps e e F ·1 . orest 01 CorporatIOn Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska IFE - Recommended Displacement Procedure ~ After the 9-5/8" casing is run and cemented, the surface mud volume should be aggressively centrifuged in order to remove as many drill solids as possible and lower the mud weight. '\ ~ Important: The oil mud should be used to drill out the cement and 20 feet of new hole. This will prevent the FloPro Drill-In fluid from becominQ contaminated with cement. ~ At 1.0. of the cleanout run of the 9-5/8" casing, the mud system should be circulated and centrifuged as much as possible in order to remove drill solids and lower the mud weight prior to sending the mud off for storage on location in upright tanks. ~ At this point, the surface volume should be sent to the upright tanks. The oil base spacers should be reversed into the annulus (or spotted in the work string) in order to provide more pit room for other pills. ~ The pits and all surface lines should be vacuumed of solids and thoroughly cleand at this time. ~ The pits should then be filled with seawater and all the spacers mixed. ~ All pills should be displaced with seawater until the wellbore cleans up. Displacement should be done pumping as rapidly as possible to provide maximum turbulent flow in order to remove all the oil mud in the wellbore (8+ barrels per minute). ~ Important: All slurry storage area must be empty prior to beginning displacement. This will provide for maximum storage of spacers and dirty seawater until the next injection. ~ Displaced oil mud should be routed to the upright tanks through the augur using the G & I unit for fluid transfer. ~ The bae oil spacer can be included with the oil mud. The seawater spacers should be routed to the reserve pit for separate disposal by injection. ~ Continue pumping seawater until the wellbore cleans up. ~ After it is determined the wellbore is sufficiently clean, empty the surface pits and build new FloPro Drill-In fluid using the enclosed fluid formula. Displace the seawater in the wellbore with the new fluid. clean 5% KCI brine. Use a 40-barrel HEC pill between the seawater and the FloPro fluid. · IFE e Forest Oil Corporation Well Redoubt Unit #7 Osprey Platfonn, Cook Inlet, Alaska Drilling Interval Summary 14370 -16239' 8-1/2" Hole Wellbore stability, minimize formation damage FloPro Drill-In Fluid; Drilling Fluid Value: $90.43 /bbl Volume Start: 1500 bbls Dilution Volume: 1264 bbls Volume End: 1500 Volume Notes- recommend dilution as .7/ft, Flovis, KCI, DualFlo, Lubetex, KlaGard, SafeCarb, MI Bar (Soltex for coal stability) Derrick Flowline Shale Shakers, Desander, Desilter/Mud Cleaner 518 Centrifuge Eliminator, MTS 14 Hammer Mill, Slurry Tank, Vacuum System, Slurry Storage Tank, Injection Pump Mud Volume 1000 bbls; Cuttings/Sludge Volume > 250 bbls. Shaker Tank = 80 bbls Eliminator Tank = 100 bbls Slurry Storage Tank = 150 bbls Vacuum Slurry Tank = 50 bbls U rj ht Stora e Tank = 500 bbls 9.5 -11.0 PPG > 50 - < 70 Funnel Viscosity 10 - 20% Drill Solids Excessive sliding, minimal circulation - follow drilling practices developed on RU #4, circulate until shakers cleanup prior to trips Hole Cleaning, hole stability (sloughing coal), differential sticking e e Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska IFE Drilling Interval Summary Interval Key Peñormance Indicators D lr FI -d F I rI I ng u I 0 rm u a ......... ..' ." Production Interval Drill--In FIÚidForrnüla ." .. '. Input DésêriêtiÔh Well RU #7 FloPro Drill-I n Fluid M'ûdWê,õht . 9.05 pré!ivdrâtédGél No WêiõñtiMâtêi;iâ'....Côdê 4.2 Pré!ivdrâtéd····GéICÔnê. Wê,ãñtMâtêi;iâISG .. No KCIChlõridé wéiãñt'Mâtêi;iâIPliiê'e No KClvvt% '. ....i 5 Séâiwâtét .... KCIPliiêé 0.244 >................. . NâCI·..Cfilõridé .... i\ > i··.·.'.. i" NâClvvt% ¡'i . NâCIPrìêè ···..·i oOtpOt..1···.·bbl ii" > i .. > .... ki .. ..i.. i/'>"'Ui_ /.\ i i. .... FiÄldilf' Ltâbdoo Fiéld bbl· ..·i'ii 0.00 1 Water 306.69 306.69 0.876 306.69 2 Soda Ash 0.25 0.25 0.000 o. 1 0 0.08 3 FloVis Plus 1 50 1 .50 0.003 1 .00 1 1 34 4 DualFlo 6.00 6.00 O. 01 1 4.00 9.06 5 Sioban SP Plus 0.20 0.20 O. 001 0.20 4.40 6 Caustic Soda 0.25 0.25 0.000 O. 1 2 O. 1 3 7 Potassium Chloride 1 6. 1 4 1 6. 1 4 0.01 9 6.75 3. 94 8 Lubetex 1 O. 50 1 0.50 0.031 1 0.82 22.40 9 KlaGard 7.00 7.00 0.02 1 7.29 1 4.49 If ru nnina coals become a Droblem add the followina 1 0 Soltex I 4.00 I 4.00 I O. 01 2 I 4.08 5.88 If increase mud weiaht is reauired add MI Bar Iiiiii: iiLl 380. 1 380. 1 1 .0001 3501 ¡iA·>i 9.050 ;imii i··im· >·»F.(·. 24500 G'ôšt';pêiiSãi(eêJ ;il $78.72 e e IFE Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska IFE Drillin Interval Discussion 14370 - 16239' (MD) 7 -5/8" Casing · ROP, GPM · Estimated ROP for this interval is 50 to 150 ftlhr. · Estimated flowrate for this interval is 450 - 470 GPM. · Use Virtual Hydraulics models as a guideline for flowrates and hole cleaning. · Lost Circulation · Seepage losses may be controlled with moderate additions of Safecarb and/or G-Seal. · For severe losses, place 30 bbls FloPro fluid in slugging pit. Add blend of lost circulation material. Spot across theft zone. SafeCarb Medium 10 PPB SafeCarb Coarse 10 PPB G-Seal 10 PPB · Coal Beds · Sloughing/running coal should be treated by adding 2 - 6 ppb Soltex to the mud system depending on the severity of the problem. · For severe coal sloughing, a concentrated pill consisting of 15 - 20 ppb Soltex may be spotted across the coal bed prior to POOH for a trip. A slight amount of pressure (equal to the annular pressure loss) may be applied to the pill to squeeze it into the coal bed. · Swab/Surge Pressures · Care should be taken while running in the hole and breaking circulation after an extended period of time out of the hole. Bringing up the pump rates too rapidly while the drilling fluid is cold may cause excessive annular pressure loss on the formation. While running in the hole after trips, circulation should be broken at least once at the casing shoe. At T.D. the pumps should be brought up slowly in order to allow the fluid to heat up prior to reaching normal flowrates. '\ · Casing running fluid properties · The mud should be conditioned prior to POOH to run liner. Moderate or reduce yield point and progressive gel strengths with additions of KCI brine order to reduce surge pressure while running casing. NOTE: See recommended liner running speed for this interval in Virtual Hydraulics. IFE e e Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska Completion Interval Summary PBTD Good displacement, minimize waste ge.peration, KCL Brine 5%: Fluid Value: $7.12/bbl Injection in disposal well Brine 1600 bbls Seawater 1100 bbls; Spacers 230 bbls Volume End 0 bbls KCI, SafeKleen, SafeSurf W,HEC, Conqor 303 10 micron pod filters (two filters) Eliminator, MTS 14 Hammer Mill, Slurry Tank, Vacuum System, Slurry Storage Tank, Injection Pump Spacers 200 + bbls; Seawater 1100 bbls; KCI Brine 1600 bbls Pit Rinse +/- 1000 bbls Shaker Tank = 80 bbls Eliminator Tank = 100 bbls Slurry Storage Tank = 150 bbls Vacuum Slurry Tank = 50 bbls U ri ht Stora e Tank = 500 bbls 9.5 -11.0 PPG 45 - 50 Funnel Viscosity 2 - 6% Drill Solids Displacement Rate> 8 BPM, Continuous Displacement without Stoppage, Transferring large amounts of fluids IFE e e Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska IFE Recommended Displacement Procedure " .........-.-,....-..-..'-------.---.-._--...._-.---_._-_............-_.. .: , .' . .' .. . . ., : : : vc""~~~...^~,~~_'~~m~"~~h~~~~_~~~_.~._m_..~_..._..___~~._.~.__.w...~.·_w_m.....__w,,_ -' : .... , : -. .. . ¡ ¡ ¡ : ¡ i ,.,~~,___·:_·"~'.....~·,,_.....~__..·.,,.·<_·,__..~_.'.4~~.~~·...,·~·.,·..·_.·.·..~____~__._,,,..~·.·........._..m__".........._m_.~~..""><~_.._~.m...~_..~.w : : ..1...... : : : . ............................................ .................................. _V__......,¥A_____~__._.^_._¥.A__.V~_~~_~, Volumes: Drill String Vol:: DP1 :ºe~ Csg. Annular Vol:iCsg~:_~p ... .__~_~___...__.+Ç~,2C.:4:~J?P. , Lilll1r)(<I"[)p ..................................... 70 'ft -, ",~ .....-.._--. ....... ~ ..............~,..,.~ ......~..............M..'..<..~ ". .-..< <~.~·.,.^_.·~...~·..·'..~..'M'....N. , " Total Annular Vol. m. ..Tº~ªIPriIL$~rillgyºI,Lm 1.:Qtal Hole Vol.! .................. ................,.. ................... .-.. .......- . ..~---_... W' "..,."., ...~. m."~.. Calc. Strokes: Pump Output '..-º...ºªªIlI. Spacer Make Up: .' ,..--,.~..._..~~..~...-~.~~.-_. . . .. .-. .:.......................................-.,...... ............._................m......_~.._.. . .._._.~M~~'_.'_M~...~~._~..__b·._~..,.....^_.~·~ : : : , : : .-. . ......:............................................, . ~..... .... ................-..--......-......... . ............................. .....-_.~ ................................ iª~.m ..........................................-...... ......_...........................-....-....... ...., .....m·...·......·........·.·_. ... ......................... .M.....~ ...........m" I,~·, ,,~_"'~..~.A~..'~...____...,'""=...~j . ........................... mmm.m.'m Fill pits 3 & 4 with seawater and r~~!!ò!!...ç!!ç,!!~l!!.~~I?§.. , ·.__w-"_,·_,_.·_·^'..~......·__w_., e e Forest Oil Corporation Well Redoubt Unit #7 Osprey Platform, Cook Inlet, Alaska IFE Recommended Displacement Procedure ~ After the 7-5/8" liner is run and cemented, the surface mud volume should be reduced as much as possible through injection. ~ AtT.D. of the cleanout run of the 7-5/8" liner, the mud system should be circulated and conditioned to lower gel strengths. ~ All G & I slurry storage should be empty at this time in order to provide maximum capacity for pills and seawater. ~ The pits and all surface lines should be vacuumed of solids and thoroughly cleaned at this time. ~ The pits should be filled with seawater and all the spacers mixed in the appropriate pits. ~ Begin reversing the pills down the wellbore and follow the pills with seawater. ~ Divert all water base mud and spacers to the G & I operation for disposal. ~ Continue pumping seawater until the wellbore cleans up. ~ After it is determined the wellbore is sufficiently clean, empty the surface pits and build 5% KCI brine. Displace the seawater in the wellbore with clean 5% KCI brine. Use a 40-barrel HEC pill between the seawater and KCI brine. ~ Filter the KCI brine as needed through 10-micron pod filters until acceptable turbidity readings are reached. e e REDOUBT UNIT #7 PRESSURE INFORMATION The following presents data used for calculation of anticipated surface pressures (ASP) during drilling of the Redoubt Unit # 1 and Redoubt Unit #2. Redoubt Shoal State 29690-1, P=5309 psi @ 12,070' TVD from DST #2 (as per 407 Comp Report, 1/9168) EMW = 8.46 ppg Gradient = 0.440 psi/ft Redoubt Shoal State 29690-2, P=5249 psi @ 12,202' TVD from DST #1(as per 407 Comp Report, 10/15/68) EMW = 8.27 ppg Gradient = 0.430 psi/ft Redoubt Bay Unit #1, P=4800 psi @ 10,953' TVD from DST (as per monthly drilling report, 12/13/76) EMW = 8.43 ppg Gradient = 0.438 psi/ft 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 1/3 gas gradient plus a 2/3 saltwater gradient to the surface. We have chosen this method based on no sign of gas in the Redoubt Unit #1 and Redoubt Unit #2. 1) ASP = ((FG x .052) - 0.10) x D where: ASP = Anticipated Surface Pressure in psi FG = Fracture Gradient at the casing seat in lblgal 0.052 = Conversion from lblgal to psi/ft 0.10 = gas gradient in psi/ft D = true vertical Depth of casing seat in ft RKB OR 2) ASP= FPP-( 1/3 x 0.10 x D) - (2/3 x.45 x D) where: FPP = Formation Pore Pressure at the next casing point which is tied back to surface or at TD (total depth) e e ASP Calculations Drilling below Surface Casing (13 3/8") ASP = «FG x .052)~ 0.10) x D = «13.5 x .052) - 0.10) x 3052' = 1837 psi OR ASP = (11756' x .45) - ( 1/3 x .10 x 11756') - (2/3 x .45 x 1175b") = 1372 psi Drilling below Intermediate Casing (9 5/8") ASP = «FG x .052)- 0.10) x D = «10.5 x .052) - 0.10) x 11756' = 5243 psi OR ASP = (12401' x .45) - (1/3 x.lO x 12401') - (2/3 x.45 x 12401') ~ 1447 psi ~ '6.ç,ç B-\V0 e e REDOUBT UNIT #7 CASING DESIGN Sêttin! Depth Size Specifications Top Bottom Hole Casing Weight Grade Coupling Length MD TVD MD TVD Driven 30" nla nla Welded 200' Surf. Surf. 200' 200' 181/2" 13 3/8" 68# L-80 BTC 3,500' Surf. Surf. 3,500' 3,052' 12 1/4" 9 5/8" 47# L-80 BTC 14,370' Surf. Surf. 14,370' 11,756' 8%" 7 5/8" 29.7# L-80 Hydril 521 2,069' 14,170' 11,617' 16,239' 12,401' '\ Casing Joint Strenl!;th Body Strenl!;th Burst Collapse Klbs Klbs Psi Psi 13 3/8" 68# L-80 BTC 1545 1556 5050 2260 95/8" 47# L-80 BTC 1122 1086 6870 4760 75/8" 29.7# L-80 Hydril 521 566 683 6890 4790 Desie:n Criteria Tension Burst Strai ht Hook Load - I norin Deviation and Buoyancy Full Column of Gas against deepest fonnation pressure Except for liners where a 3000 psi test pressure on top of9.6 ppg fluid is backed on the outside by a fresh water adient of 0.43 si/ft. Full evacuation on the inside backed by expected fonnation gradient of .45 si/ft. on the outside. CollaDse 13 3/8" Surface Casine: Tension = 3500' x 68# Rated = 1545 K = 238.0 K Safety Factor = 6.5 Burst = (11756 x .45) - (.10 x 11756') Rated = 5050 psi = 4115 psi Safety Factor = 1.3 CollaDse = (3052' x .45) - (.10 x 3052') Rated = 2260 psi = 1068 psi Safety Factor = 2.1 e e 9 5/8" Intermediate Casine Tension = 14370' x 47# Rated = 1086 K = 675.4 K Safety.Factor = 1.6 Burst = (12401' x .45) - (.10 x 12401') Rated = 6870 psi = 4340 psi Safety Factor = 1.6 Collapse = (11756' x .45) - (.10 x 11756') Rated = 4760 psi = 4115 psi Safety Factor = 1.2 7 5/8" Production Liner Tension = 2069' x 29.7# Rated = 566 K = 61.5 K Safety Factor = 9.2 Burst = ((12401 x .4992)+3000)-(12401 x Rated = 6890 psi .43) Safety Factor = 1.8 = 3858 psi Collapse = (12401' x .45) - (.10 x 12401') Rated = 4790 psi == 4340 psi Safety Factor = 1.1 e e REDOUBT UNIT #7 CEMENTING PROGRAM '\ Operator Name: Well Name: Job Description: Date: Forest Oil Corp REDOU8T UNr" 13-3/8" Surface ~ing, Stab-In August 25, 2003 e ~ Proposal No: 1001785078 JOB AT A GLANCE Depth (TVD) Depth (MD) 3,052 ft 3,500 ft Hole Size 18.5 in Casing SizelWeight : 13 3/8 in, 68 Ibs/ft '" Pump Via Drill Pipe 5 1/2" 0.0. (4.778" .1.0) 21.9 # Total Mix Water Required 39,162 gals Pre-Flush Water Density 40 bbls 8.4 ppg Lead Slurry Class G Cement Density Yield 2,939 sacks 12.5 ppg 2.10 cf/sack Tail Slurry Class G Cement Density Yield 833 sacks 15.8 ppg 1.15 cf/sack Displacement Drilling Mud Density 76 bbls 9.0 ppg ~~\~ Report Printed on: AuguS125, 2003 9:16 PM Page 1 Gr4109 Operator Name: Well Name: Job Description: Date: Forest Oil Corp REDOU8T UN!". 13-3/8" Surface ~ing, Stab-In August 25, 2003 e Em Proposal No: 1001785078 WELL DATA ANNULAR GEOMETRY 35.380 CASING 18.500 HOLE 200 3,500 200 3,052 ." SUSPENDED PIPES DÈPTH(ft) MEASURED I TRUE VERTICAL 3,500 3,052 Float Collar set @ Mud Density Mud Type Est. Static Temp. Est. Circ. Temp. 3,420 ft 9.00 ppg Water 8ased 880 F 850 F VOLUME CALCULATIONS 200 ft x 5.8515 cf/ft 2,800 ft x 0.8910 cflft 500 ft x 0.8910 cf/ft 80 ft x 0.8407 cf/ft with 0 % excess = with 100 % excess = with 100 % excess = with 0 % excess = TOTAL SLURRY VOLUME = 1170.3cf 4989.3 cf 891.6 cf 67.3 cf (inside pipe) 7118.5cf 1,269 bbls = Report Printed on: August 25. 2003 9:16 PM Page 2 Gr4115 Operator Name: Forest Oil Corp Well Name: REDOUBT UNIT_ Job Description: 13-3/8" Surface ðl!!llrng, Stab-In Date: August25,2003 It Lm Proposal No: 100178507B FLUID SPECIFICATIONS Pre-Flush 40.0 bbls Water @ 8.4 ppg FLUID VOLUME VOLUME CU-FT FACTOR AMOUNT AND TYPE OF CEMENT Lead Slurry 6160 I 2.1 = 2939 sacks Class G Cement + 0.4% bwoc CD- 32 + 0.3% bwoc FL-52 + 1 gals/100 sack FP-6L + 2% bwoc Sodium MetasHicate + 105.7% Fresh Water = 833 sacks Class G Cement + 0.2% bwoc R-3 + 0.3% bwoc CD-32 + 1 9als/100 sack FP-6L + 0.2% bwoc Sodium Metasilicate + 44% Fresh Water 75.8 bbls Drilling Mud @ 9 ppg Tail Slurry 959 I 1.15 Displacement 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) 11.92 4.96 Amount of Mix Fluid (gps) 11.93 4.97 Estimated Pumping Time - 70 BC (HH:MM) 5:59 4:26 Free Water (mls) @ 90 0 F @ 90 0 angle 2.0 0.5 Free Water (mls) @ 900 F @ 45 0 angle 0.0 COMPRESSIVE STRENGTH 12 hrs @ 1050 F (psi) 387 1799 24 hrs @ 1050 F (psi) 634 3116 RHEOLOGIES FLUID TEMP 600 300 200 100 6 3 Lead Slurry @ 900 F 76 56 48 40 28 21 Tail Slurry @ 900 F 117 88 78 64 37 28 Report Printed 011: August 25, 2003 9:17 PM Page 3 Gr4129 Operator Name: Well Name: Job Description: Date: Forest Oil Corp REDOUBT UNII 9-5/8" Intermedia e Casing August25,2003 e (.ill Proposal No: 100178507B JOB AT A GLANCE Depth (TVD) Depth (MD) 11,756 ft 14,370 ft Hole Size 12.25 in Casing SizelWeight : 9518 in, 47 Ibs/ft '" Pump Via 9 5/8" 0.0. (8.681" .1.0) 47 # Total Mix Water Required 17,008 gals Pre-Flush Water + 1 gpb MCS-A Density 20 bbls 8.4 ppg Weighted Spacer MCS-4D Spacer Density 30 bbls 10.5 ppg Lead Slurry Class G Cement Density Yield 1,196 sacks 12.5 ppg 2.10 cflsack Tail Slurry Class G Cement Density Yield 572 sacks 15.8 ppg 1.15 cf/sack Displacement Drilling Mud Density 1,046 bbls 9.2 ppg Report Pointed on: August 25. 2003 9:17 PM Page 6 Gr4109 Operator Name: Well Name: Job Description: Date: Forest Oil Corp REDOUBT UN'. 9-5/8" Intermedi~Casing August25,2003 e Wj Proposal No: 100178507B WELL DATA ANNULAR GEOMETRY 3,500 14,370 SUSPENDED PIPES 3,052 11,756 9.625 8.681 47 14,370 11,756 Float Collar set @ 14,290 ft Mud Density 9.20 ppg Mud Type Oil Based Est. Static Temp. 179 0 F Est. Circ. Temp. 143 0 F VOLUME CALCULATIONS 4,000 ft x 0.3132 cf/ft 1,000 ft x 0.3132 cflft 80ft x 0.4110cf/ft with 100 % excess = with 100 % excess = with 0 % excess = TOTAL SLURRY VOLUME = = 2508.0 cf 626.3 cf 32.9 cf (inside pipe) 3167.2 cf 565 bbls Report Printed on: August 25, 2003 9:17 PM Page 7 Gr4115 Operator Name: Forest Oil Corp Well Name: REDOUBT UNIT. Job Description: 9-5/8" Intermedia asing Date: August 25, 2003 e Lm Proposal No: 100178507B FLUID SPECIFICATIONS Pre-Flush Weighted Spacer 30.0 bbls MCS-4D Spacer + 6lbs/bbl MCS-D + 22.611bs/bbl Bentonite + 90 Ibs/bbl Barite, Bulk @ 10.5 ppg FLUID VOLUME VOLUME CU-FT FACTOR AMOUNT AND TYPE OFCEMENT Lead Slurry 2508 I 2.1 = 1196 sacks Class G Cement + 0.6% bwoc R-3 + 0.4% bwoc CD-32 + 0.6% bwoc FL-52 + 0.15% bwocASA-301 + 1 gals/100sack FP-6L + 1.5% bwoc Sodium Metasilicate + 105.4% Fresh Water = 572 sacks Class G Cement + 0.3% bwoc R-3 + 0.8% bwoc FL-63 + 0.3% bwoc CD-32 + 0.05% bwoc ASA-301 + 1 gals/100 sack FP-6L + 43.5% Fresh Water 1,046.1 bbls Drilling Mud @ 9.2 ppg Tail Slurry 659 I 1.15 Displacement CEMENT PROPERTIES SLURRY SLURRY NO.1 NO.2 Slurry Weight (ppg) 12.50 15.80 Slurry Yield (cflsack) 2.10 1.15 Amount of Mix Water (gps) 11.88 4.90 Amount of Mix Fluid (gps) 11.89 4.91 Estimated Pumping Time - 70 BC (HH:MM) 4:50 3:50 Free Water (mls) @ 141 0 F @ 900 angle 0.0 0.0 Free Water (mls) @ 141 0 F @ 450 angle 0.0 Fluid Loss (cc/30min) at 1000 psi and 141 0 F 217.0 64.0 COMPRESSIVE STRENGTH 12 hrs @ 1780 F (psi) 431 2326 24 hrs @ 1780 F (psi) 553 3085 RHEOLOGIES FLUID TEMP 600 300 200 100 6 3 Lead Slurry @ 141 0 F 93 59 46 31 16 16 Tail Slurry @ 141 0 F 300 219 168 112 36 35 Pilot tests will be preformed prior to loading. Slight additvie adjustments should be expected to achieve the desired slurry properties based on pilot test results. Report Printed on: August 25, 2003 9:17 PM Page 8 Gr4129 Operator Name: Well Name: Job Description: Date: Forest Oil Corp REDOUBT UNr. 7 -5/8" Productio~ner August 25, 2003 e Wj Proposal No: 100178507B JOB AT A GLANCE Depth (TVD) Depth (MD) Hole Size Liner SizelWeight : Pump Via Total Mix Water Required Pre-Flush Water + 1 gpb MCS-AG Density Weighted Spacer MCS-4D Density Cement Slurry Class G Cement Density Yield Displacement Drilling Mud Density 12,401 ft 16,239 ft 8.5 in 75/8 in, 29.7 Ibslft" Drill Pipe 5 1/2" 0.0. (4.778" .1.0) 21.9 # 7 5/8" 0.0. (6.875" .1.0) 29.7 # 1 ,996 gals 20 bbls 8.4 ppg 30 bbls 10.5 ppg 398 sacks 15.7 ppg 1 . 18 cflsack 406 bbls 9.6 ppg Report Printed on: August 25. 2003 9:17 PM Gr41 09 Page 11 Operator Name: Well Name: Job Description: Date: Forest Oil Corp REDOUBT UNI" 7 -5/8" Productio~~er August 25, 2003 e till Proposa1No:100178507B WELL DATA ANNULAR GEOMETRY SUSPENDED PIPES 7.625 6.875 Drill Pipe 5.5 (in) 00, 4.778 (in) 10, 21.9 (Ibs/ft) set @ Drill Pipe 7.625 (in) 00, 6.875 (in) 10, 29.7 (Ibs/ft) set @ Depth to Top of Liner Float Collar set @ Mud Density Mud Type Est. Static Temp. Est. Circ. Temp. VOLUME CALCULATIONS 200 ft x 0.0939 cf/ft 1,869 ft x 0.0770 cf/ft 80 ft x 0.2578 cf/ft with 0 % excess = with 200 % excess = with 0 % excess = TOTAL SLURRY VOLUME = MEASURED 16,239 12,401 14,170ft 16,159ft 14,170ft 16,159 ft 9.60 ppg Oil Based 186 0 F 150 0 F = 19 cf 431 cf 21 cf (inside pipe) 471 cf 84 bbls Report Printed on: August 25, 2003 9:17 PM Page 12 Gr41f7 Operator Name: Forest Oil Corp Well Name: REDOUBT UNIT .. Job Description: 7-5/8" Production ~r Date: August 25, 2003 e Wj Proposal No: 100178507B FLUID SPECIFICATIONS Pre-Flush Weighted Spacer FLUID VOLUME VOLUME CU-FT FACTOR Cement Slurry 471 I Displacement CEMENT PROPERTIES Slurry Weight (ppg) Slurry Yield (cf/sack) Amount of Mix Water (gps) Amount of Mix Fluid (gps) Estimated Pumping Time - 70 BC (HH:MM) Estimated Pumping Time - 100 BC (HH:MM) Free Water (mls) @ 1550 F @ 90 0 angle Fluid Loss (cc/30min) at 1000 psi and 1550 F COMPRESSIVE STRENGTH 22.5 hrs @ 190 0 F (psi) 24 hrs @ 1900 F (psi) 48 hrs @ 1900 F (psi) 30.0 bbls MCS-4D + 22.61 Ibs/bbl Bentonite + 90 Ibs/bbl Barite, Bulk + 6 Ibs/bbl MCS-D @ 10.5 ppg AMOUNT AND TYPE OF....CEMENT 1.18 = 398 sacks Class G Cement + 0.55% bwoc R-3 + 2% bwow Potassium Chloride + 0.6% bwoc CD-32 + 0.2% bwoc FL-33 + 1 gals/100 sack FP-6L + 0.2% bwoc Sodium Metasilicate + 0.9% bwoc BA-10A + 44.5% Fresh Water 405.6 bbls Drilling Mud @ 9.6 ppg SLURRY NO.1 15.70 1.18 5.02 5.03 7:46 7:50 0.0 38.0 500 1250 3329 Pilot tests will be preformed prior to loading. Slight additvie adjustments should be expected to achieve the desired slurry properties based on pilot test results. Report Plinted on: August 25, 2003 9:17 PM Page 13 Gr4129 Operator Name: Forest Oil Corp _ Well Name: REDOUBT UNI,. Date: August 25, 2003 e Wj Proposal No: 100178507B PRODUCT DESCRIPTIONS ASA-301 Additive used to reduce or eliminate free water and settling in cement slurries. BA-10A Improves cement bonding and acts as a matrix flow control agent. BA-10A is effective in a wide variety of slurries. " Barite, Bulk A naturally occuring mineral (Barium Sulfate). It is widely used as a weighting material in cement spacers and occasionally in cement slurries. It can yield a slurry density in excess of 19 Ibs/gal. Bentonite Commonly called gel, it is a clay material used as a cement extender and to control excessive free water. CD-32 A patented, free-flowing, water soluble polymer that is an efficient and effective dispersant for primary and remedial cementing. Class G Cement Intended for use as a basic cement from surface to 8000 ft as manufactured, or can be used with accelerators and retarders to cover a wide range of well depths and temperatures. FL-33 A patented cement fluid loss additive that provides exceptional fluid loss control across a wide range of temperatures, salinity conditions, and remedial cementing applications at low to high temperature ranges. FL-52 A water soluble, high molecular weight fluid loss additive used in medium to low density slurries. It is functional from low to high temperature ranges. FL-63 A non-retarding, non-viscosifying fluid loss additive particularly suited for use with coil tubing andlor close tolerance liner cementing. FL-63 is effective from low to high temperatures. Concentrations of 0.2% to 1.0% BWOC are typical. FP-6L A clear liquid that decreases foaming in slurries during mixing. MCS-4 A turbulent flow spacer system that prevents water and oil-base mud and cement contamination and water-wets the casing to increase bonding. Report Printed on: August 25. 2003 9:17 PM Page 16 Gr4163 Operator Name: Forest Oil Corp ..._ Well Name: REDOUBT UNITWI' Date: August 25, 2003 e Wj Proposal No: 100178507B PRODUCT DESCRIPTIONS (Continued) MCS-A A water-base spacer surfactant designed to effectively remove drilling mud and wall cake during cementing operations and prevent contamination of the cement slurry during placement. MCS-A is compatible with some oil-base muds, water-base muds and all common cementing systems. MCS-A is easily mixed on location, with all dry materials pre-blended at the district. Therefore, a separate batch mixer is not a necessity. MCS-AG A surfactant used in cement spacer systems to prevent mud incompatability and improve bonding. Potassium Chloride A granular salt used to reduce clay swelling caused by water-base stimulation fluids. R-3 A low temperature retarder used in a wide range of slurry formulations to extend the slurry thickening time. Sodium Metasilicate An accelerator used to decrease the thickening time of cement slurries. Sodium Metasilicate An extender used to produce an economical, low density cement slurry. Sodium Metasilicate An extender used to produce an economical, low density cement slurry. Report Printed on: August 25. 2003 9:17 PM Page 17 Gr4163 e e REDOUBT UNIT #7 DIRECTIONAL PROGRAM '\ ~"'!!5U1 Forest Oil t,1~I~L:hid ,,:.:=~~~~ Cook Inlet Osprey RU#7 WP 17 DrillQuesf Scale: 1 inch = 2500ft o 2500 Eastings(Well) 5000 7500 10000 Welf: Plan: RU#7 o ::::::- ã> ~ en 0') .!: ..c: -e o z -= o o L{) N II ..c () .!: Kop Begin Dir@ 1.000'/10011: 200.000 MD, 200.000 TVD Increase in Dir Rale @ 2.000'/1000 : 400.000 MD, 399.96ft TVD Increase in Dir Rale @ 3.000'/10011 : 550.000 MD, 549.66ft TVD Increase in Dir Rate @ 4.000'/100ft : 1383.33ft MD, 1338. 13ft TVD 9 5/8in Casing 14370.03ftMO 11756.0OOTVD Current Well Properties lW#7 T1 WI'18 11 í56'(HJ TVD 3485.20S.7177.77£ -2500 Horizontal Coordinates: Ref. Global Coordinates: Ref. Structure: Ref. Geographical Coordit'lates : RKB Elevation: 2449982.20 N. 200675.23 E 1628.80 S, 2250935.77 W 60· 41' 44.1598M N, 151~ 40' 13.5665° W 90.000 above Mean Sea Level .. ° 7 5/8in Casing !!gIn Dlr (â¡ 4.000 /10Oft: 14034.29ft MD 11512.16ft TVD 16238.62ftMD End Dir, Sfart Sail @ 50.000° : 14370.03ftMD,11756.00ftTVD 22oooo12401.0OOTVD Begin Dir @ 4.0000/100ft: 14390.03ft MD, 11768.86ft TVD I?ü~ End Dir, Start Sail @ 73.617° : 14982.01ftMD,12046.57ftTVD "",018 R(;#7 T2 W" 18 Total Depth m~~;:~,og~ 77 E -* 16238.62ftMD -5000 () 12401.00ftTVD C/) Grid North Convergence: North Reference : Units: _1.457" Grid North Feet (US Survey) Plan: RU#7 Target Data Measurement Units; ft Target Coordinate Vertical Depth Northings Name Point Type Well Well (ft) (ft) RU#7 TI Wp 18 Entry Point 11756.00 3485.20 S RU#7 T2 Wp 18 Entry Point 12401.00 4173.20 S Eastings Vertical Depth Northings Eastings Target Well Mean Sea level ASP-4 ASP-4 Shape (ft) (ft) (ft) (ft) 7177.77 E 11666.00 2446497.ooN 207853.00 E Point 8774.77 E 12311.00 2445809.00 N 209450.00 E Point o Kop Begin Dir @ 1.0000/10Oft: 200.0Oft MD, 200.00ft TVD Increase in Dir Rate @ 2.0000/100ft: 400.0Oft MD, 399.96ft TVD Increase in Dir Rate @ 3.0000/100ft : 550.0Oft MD, 549.66ft TVD 5000 30Jncrease in Dir Rate @ 4.00001100ft: 1383.33ft MD, 1338.13ft TVD End Dir, Start Sail @ 36.571° : 1762.93ftMD,1656.80ftTVD RU#7 WP 18 Proposal Data 2500 13 3IBin Casing 3500.0OOMD 3051.88ftTVD Vertical Origin: Horizontal Origin: Measurement Units: North Reference: Grid North Convergence: Well Well ft Grid North -1.457' Dogleg severity: Degrees per 100 feet (US Survey) Vertical Section Azimuth: 128.680' Vertical Section Description:Well Vertical Section Origin: 0.00 N,O.OO E ::::::- ã> ~ - Coordinate System: NAD27 Alaska State Planes, Zone 4 ..c: - Q. Q) o ro o ~ 7500 > Measured Incl. Azim. Vertical Northings Depth Depth 0.00 0.000 0.000 0.00 O.OON 200.00 0.000 0.000 200.00 O.OON 400.00 2.000 140.000 399.96 2.675 550.00 5.000 140.000 549.66 9.695 1383.33 30.000 140.000 1338.14 200.13 5 1762.93 36.571 114.806 1656.8t 320.98 5 14034.29 36.571 114.806 11512.16 3388.45 5 14370.03 50.000 115.000 11756.00 3485.205 14390.03 50.000 115.000 11768.86 3491.685 14982.01 73.617 113.029 12046.57 3701.595 16238.62 73.617 113.029 12401.00 4173.205 Eastings Vertical Dogleg Section Rate O.OOE 0.00 O.OOE 0.00 0.000 2.24E 3.42 1.000 8.13E 12.40 2.000 167.93 E 256.17 3.000 332.55 E 460.20 4.000 6969.48 E 7558.39 0.000 7177.77 E 7781.46 4.000 7191.66 E 7796.35 0.000 7665.26 E 8297.25 4.000 8774.77 E 9458.14 0.000 -= 10000 o o L{) N II ..c: () .S 9 5/8in Casing 14370.03ftMD 11756.0OOTVD 300000 Begin Dir @ 4.0000/10Oft : 14034.29ft MD, 11512.16ft TVD End Dir, Start Sail cæ 50.000° : 14370.03ftMD,11756.0OftTVD Begin Dir @ 4.ÕOoo/100ft: 14390.03ft MD, 11768.86ft TVD End Dir, Start Sail @ 73.617° : 14982.01ftMD,12046.57ftTVD 7 Slain Casing 16238.62ftMD 12401.0OftTVD Top Hem!vck, í í 756. Or!ffTVD RU#7 TI W; 18 11756.00 TV'} 3485.10 S, 7J77.ï7 E ~U;ft Rl!#7 T2 WI' 18 7Wp 18 12401.00 Tf'D ./J73.20 S. 8774.77 E Total Depth 16238.62ftMD 12401.00flTVÇ> ¡¡¡ ro 12500 () (/) o 2500 Scale: 1 inch = 2500ft 5000 7500 10000 Vertical Section Well Section Azimuth: 128.680° (Grid North) OrillQuest 3.03.02.002 Sperry-Sun Drilling Services Forest ' "/ Cook t Plan: R - RVJ¡ WP 18 posal Report 22 August, 2003 Surface Coordinates: 2449982.20 N, 200675.23 E (60041'44.1598" N, 151040'13.5665" W) Grid Coordinate System: NAD27 Alaska State Planes, Zone 4 Kelly Bushing: 90.00ft above Mean Sea Level !5J:JE!i'l""Y-SUI'1 ~I"'I '"' ¡:::'J~ tis. ~"yl CIIIŠ oil. ..wikrllDll"l CM'Ip,.,. e e Proposal Ref: pro108 Sperry-Sun Drilling Services Proposal Report for Plan: RU#7 - RU#7 WP 18 Cook Inlet Forest Oil Measured Sub-Sea Vertical Local Coordinates Global Coordinates ical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings ion Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) 0.00 0.000 0.000 -90.00 0.00 0.00 N 0.00 E 0.00 .. 200.00 0.000 0.000 110.00 200.00 O.OON 0.00 E 0.000 0.00 Kop Begin Dir @ 1.000°/1 OOft : 200.00ft MD, 200.00ft TVD 300.00 1.000 140.000 209.99 299.99 0.67 S 1.000 0.86 400.00 2.000 140.000 309.96 399.96 2.67 S 1.000 3.42 Increase in Dir Rate @ 2.0000/100ft; 500.00 4.000 140.000 409.82 499.82 6.68S 5.61 200680.84 E 2.000 8.55 400.00ft MD, 399.96ft TV. 550.00 5.000 140.000 459.66 549.66 9.69S 449972.51 N 200683.36 E 2.000 12.40 Increase in Dir Rate @ 3.0000/100ft : 550.00ft MD, 549.66ft TVD 600.00 6.500 140.000 509.41 2449968.67 N 200686.58 E 3.000 17.31 700.00 9.500 140.000 608.43 2449958.01 N 200695.52 E 3.000 30.96 800.00 12.500 140.000 706.58 2449943.40 N 200707.79 E 3.000 49.66 900.00 15.500 140.000 803.59 2449924.87 N 200723.34 E 3.000 73.38 1000.00 18.500 140.000 66.90 E 2449902.48 N 200742.13 E 3.000 102.05 1100.00 21.500 140.000 88.88 E 2449876.28 N 200764.11 E 3.000 135.58 1200.00 24.500 140.000 113.99 E 2449846.35 N 200789.22 E 3.000 173.89 1300.00 27.500 140.000 142.17E 2449812.77 N 200817.40 E 3.000 216.87 1383.33 30.000 140.000 167.93 E 2449782.07 N 200843.16 E 3.000 256.17 Increase in Dir Rate@ 4.0000/100ft: 1383.33ft MD, 1338.13ft TVD 1400.00 1352.56 206.47 S 173.37 E 2449775.73 N 200848.60 E 4.000 264.38 1500.00 1438.47 242.60 S 209.57 E 2449739.60 N 200884.80 E 4.000 315.21 1600.00 1523.02 275.33 S 251.70 E 2449706.87 N 200926.93 E 4.000 368.56 1700.00 1605.80 304.51 S 299.58 E 2449677.69 N 200974.81 E 4.000 424.17 1762.93 1656.81 320.98 S 332.55 E 2449661.22 N 201007.78 E 4.000 460.20 End Dir, Start Sail @ 36.. 1762.93ftMD,1656.80ftT '" 1800.00 36.571 114.806 1596.58 1686.58 330.25 S 352.59 E 2449651.95 N 201027.82 E 0.000 481.65 1900.00 36.571 114.806 1676.89 1766.89 355.24 S 406.68 E 2449626.96 N 201081.91 E 0.000 539.49 2000.00 36.571 114.806 1757.20 1847.20 380.24 S 460.76 E 2449601.96 N 201135.99 E 0.000 597.33 2100.00 36.571 114.806 1837.51 1927.51 405.24 S 514.85 E 2449576.96 N 201190.08 E 0.000 655.18 2200.00 36.571 114.806 1917.82 2007.82 430.23 S 568.93 E 2449551.97 N 201244.16 E 0.000 713.02 2300.00 36.571 114.806 1998.14 2088.14 455.23 S 623.02 E 2449526.97 N 201298.25 E 0.000 770.86 2400.00 36.571 114.806 2078.45 2168.45 480.23 S 677.10 E 2449501.97 N 201352.33 E 0.000 828.71 2500.00 36.571 114.806 2158.76 2248.76 505.22 S 731.19 E 2449476.98 N 201406.42 E 0.000 886.55 2600.00 36.571 114.806 2239.07 2329.07 530.22 S 785.27 E 2449451.98 N 201460.50 E 0.000 944.39 2700.00 36.571 114.806 2319.38 2409.38 555.22 S 839.36 E 2449426.98 N 201514.59 E 0.000 1002.24 22 August, 2003· 14:52 Page 20f9 DrillQuest 3.03.02.002 Sperry-Sun Drilling Services Proposal Report for Plan: RU#7· RU#7 WP 18 Cook Inlet Forest Oil Measured Sub-Sea Vertical Local Coordinates Global Coordinates Depth Inel. Azim. Depth Depth Northings Eastings Northings Eastings Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) 2800.00 36.571 114.806 2399.70 2489.70 580.22 S 893.44 E 2449401.98 N 1060.08 2900.00 36.571 114.806 2480.01 2570.01 605.21 S 947.53 E 2449376. 1117.93 3000.00 36.571 114.806 2560.32 2650.32 630.21 S 1001.61 E 2449 1175.77 3100.00 36.571 114.806 2640.63 2730.63 655.21 S 1055.70 E 244 1233.61 3200.00 36.571 114.806 2720.94 2810.94 680.20 S 1109.78 E 4493 1291.46 3300.00 36.571 114.806 2801.25 2891.25 449277.00 201839.10 E 0.000 1349.30 -- 3400.00 36.571 114.806 2881.57 2971.57 449252.00 N 201893.18 E 0.000 1407.14 3500.00 36.571 114.806 2961.88 3051.88 49227.01 N 201947.27 E 0.000 1464.99 13 3/8in Casing 3600.00 36.571 114.806 3042.19 3132.19 449202.01 N 202001.35 E 0.000 1522.83 3700.00 36.571 114.806 3122.50 3212.50 2449177.01 N 202055.43 E 0.000 1580.67 3800.00 36.571 114.806 3202.81 4.29 E 2449152.01 N 202109.52 E 0.000 1638.52 3900.00 36.571 114.806 3283.13 1488.37 E 2449127.02 N 202163.60 E 0.000 1696.36 4000.00 36.571 114.806 3363.44 1542.46 E 2449102.02 N 202217.69 E 0.000 1754.20 4100.00 36.571 114.806 3443.75 1596.54 E 2449077.02 N 202271.77 E 0.000 1812.05 4200.00 36.571 114.806 3524 1650.63 E 2449052.03 N 202325.86 E 0.000 1869.89 4300.00 955.17 S 1704.71 E 2449027.03 N 202379.94 E 0.000 1927.73 4400.00 980.17 S 1758.80 E 2449002.03 N 202434.03 E 0.000 1985.58 4500.00 1005.16S 1812.88 E 2448977.04 N 202488.11 E 0.000 2043.42 4600.00 1030.16S 1866.97 E 2448952.04 N 202542.20 E 0.000 2101.27 4700.00 1055.16 S 1921.05E 2448927.04 N 202596.28 E 0.000 2159.11 4800.00 4005.93 4095.93 1080.15 S 1975.14E 2448902.05 N 202650.37 E 0.000 2216.95 4900.00 4086.24 4176.24 1105.15S 2029.22 E 2448877.05 N 202704.45 E 0.000 2274.80 5000.00 4166.56 4256.56 1130.15 S 2083.31 E 2448852.05 N 202758.54 E 0.000 2332.64 e 5100.00 4246.87 4336.87 1155.15 S 2137.39 E 2448827.05 N 202812.62 E 0.000 2390.48 5200.00 4327.18 4417.18 1180.14S 2191.48E 2448802.06 N 202866.71 E 01>00 2448.33 5300.00 36.571 114.806 4407.49 4497.49 1205.14 S 2245.56 E 2448777.06 N 202920.79 E 0.000 2506.17 5400.00 36.571 114.806 4487.80 4577.80 1230.14 S 2299.65 E 2448752.06 N 202974.88 E 0.000 2564.01 5500.00 36.571 114.806 4568.11 4658.11 1255.13S 2353.73 E 2448727.07 N 203028.96 E 0.000 2621.86 5600.00 36.571 114.806 4648.43 4738.43 1280.13S 2407.81 E 2448702.07 N 203083.04 E 0.000 2679.70 5700.00 36.571 114.806 4728.74 4818.74 1305.13S 2461.90 E 2448677.07 N 203137.13 E 0.000 2737.54 5800.00 36.571 114.806 4809.05 4899.05 1330.12S 2515.98 E 2448652.08 N 203191.21 E 0.000 2795.39 5900.00 36.571 114.806 4889.36 4979.36 1355.12S 2570.07 E 2448627.08 N 203245.30 E 0.000 2853.23 6000.00 36.571 114.806 4969.67 5059.67 1380.12S 2624.15 E 2448602.08 N 203299.38 E 0.000 2911.07 6100.00 36.571 114.806 5049.99 5139.99 1405.12 S 2678.24 E 2448577.08 N 203353.47 E 0.000 2968.92 6200.00 36.571 114.806 5130.30 5220.30 1430.11 S 2732.32 E 2448552.09 N 203407.55 E 0.000 3026.76 22 August, 2003 - 14:52 Page 3 of9 DrillQuest 3.03.02.002 Sperry-Sun Drilling Services Proposal Report for Plan: RU#7 - RU#7 WP 18 Cook Inlet Forest Oil Measured Sub-Sea Vertical Local Coordinates Global Coordinates Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) 6300.00 36.571 114.806 5210.61 5300.61 1455.11 S 2786.41 E 3084.61 6400.00 36.571 114.806 5290.92 5380.92 1480.11 S 2840.49 E 3142.45 6500.00 36.571 114.806 5371.23 5461.23 1505.10S 2894.58 E 3200.29 6600.00 36.571 114.806 5451.55 5541.55 1530.10 S 2948.66 E 3258.14 6700.00 36.571 114.806 5531.86 5621.86 1555.10 S 3002.75 E 3315.98 6800.00 36.571 114.806 5612.17 5702.17 1580.09 S 448402.11 203732.06 E 0.000 3373.82 e 6900.00 36.571 114.806 5692.48 5782.48 1605.09 S 448377.11 N 203786.15 E 0.000 3431.67 7000.00 36.571 114.806 5772.79 5862.79 1630.09 S 448352.11 N 203840.23 E 0.000 3489.51 7100.00 36.571 114.806 5853.10 5943.10 1655.09 S 448327.11 N 203894.32 E 0.000 3547.35 7200.00 36.571 114.806 5933.42 6023.42 168 S 2448302.12 N 203948.40 E 0.000 3605.20 7300.00 36.571 114.806 6013.73 7.26 E 2448277.12 N 204002.49 E 0.000 3663.04 7400.00 36.571 114.806 6094.04 3381.34 E 2448252.12 N 204056.57 E 0.000 3720.88 7500.00 36.571 114.806 6174.35 3435.42 E 2448227.13 N 204110.65 E 0.000 3778.73 7600.00 36.571 114.806 6254.66 3489.51 E 2448202.13 N 204164.74 E 0.000 3836.57 7700.00 36.571 114.806 6334 3543.59 E 2448177.13 N 204218.82 E 0.000 3894.41 7800.00 1830.06 S 3597.68 E 2448152.14 N 204272.91 E 0.000 3952.26 7900.00 1855.06 S 3651.76E 2448127.14 N 204326.99 E 0.000 4010.10 8000.00 1880.06 S 3705.85 E 2448102.14 N 204381.08 E 0.000 4067.95 8100.00 1905.06 S 3759.93 E 2448077.14 N 204435.16 E 0.000 4125.79 8200.00 1930.05 S 3814.02 E 2448052.15 N 204489.25 E 0.000 4183.63 8300.00 6816.85 6906.85 1955.05 S 3868.10 E 2448027.15 N 204543.33 E 0.000 4241.48 8400.00 6897.16 6987.16 1980.05 S 3922.19 E 2448002.15 N 204597.42 E 0.000 4299.32 8500.00 6977.47 7067.47 2005.04 S 3976.27 E 2447977.16 N 204651.50 E 0.000 4357.16 e 8600.00 7057.78 7147.78 2030.04 S 4030.36 E 2447952.16 N 204705.59 E 0.000 4415.01 8700.00 7138.09 7228.09 2055.04 S 4084.44 E 2447927.16 N 204759.67 E !t.òOO 4472.85 8800.00 36.571 114.806 7218.41 7308.41 2080.03 S 4138.53 E 2447902.17 N 204813.76 E 0.000 4530.69 8900.00 36.571 114.806 7298.72 7388.72 2105.03 S 4192.61 E 2447877.17 N 204867.84 E 0.000 4588.54 9000.00 36.571 114.806 7379.03 7469.03 2130.03 S 4246.70 E 2447852.17 N 204921.93 E 0.000 4646.38 9100.00 36.571 114.806 7459.34 7549.34 2155.02 S 4300.78 E 2447827.18 N 204976.01 E 0.000 4704.22 9200.00 36.571 114.806 7539.65 7629.65 2180.02 S 4354.86 E 2447802.18 N 205030.09 E 0.000 4762.07 9300.00 36.571 114.806 7619.97 7709.97 2205.02 S 4408.95 E 2447777.18 N 205084.18 E 0.000 4819.91 9400.00 36.571 114.806 7700.28 7790.28 2230.02 S 4463.03 E 2447752.18 N 205138.26 E 0.000 4877.76 9500.00 36.571 114.806 7780.59 7870.59 2255.01 S 4517.12E 2447727.19 N 205192.35 E 0.000 4935.60 9600.00 36.571 114.806 7860.90 7950.90 2280.01 S 4571.20 E 2447702.19 N 205246.43 E 0.000 4993.44 9700.00 36.571 114.806 7941.21 8031.21 2305.01 S 4625.29 E 2447677.19 N 205300.52 E 0.000 5051.29 22 August, 2003 - 14:52 Page 4 of9 Dril/Quest 3.03.02.002 Sperry-Sun Drilling Services Proposal Report for Plan: RU#7 - RU#7 WP 18 Cook Inlet Forest 01/ Measured Sub-Sea Vertical Local Coordinates Global Coordinates Depth Incl. Azim. Depth Depth Northings Eastin9s Northings Eastlngs Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) 9800.00 36.571 114.806 8021.52 8111.52 2330.00 S 4679.37 E 2447652.20 N 5109.13 9900.00 36.571 114.806 8101.84 8191.84 2355.00 S 4733.46 E 2447627. 5166.97 10000.00 36.571 114.806 8182.15 8272.15 2380.00 S 4787.54 E 2447 5224.82 10100.00 36.571 114.806 8262.46 8352.46 2404.99 S 4841.63 E 244 5282.66 10200.00 36.571 114.806 8342.77 8432.77 2429.99 S 4895.71 E 4475 5340.50 10300.00 36.571 114.806 8423.08 8513.08 2454.99 S 447527.21 205625.03 E 0.000 5398.35 e 10400.00 36.571 114.806 8503.40 8593.40 2479.99 S 447502.21 N 205679.11 E 0.000 5456.19 10500.00 36.571 114.806 8583.71 8673.71 2504.98 S 47477.22 N 205733.20 E 0.000 5514.03 10600.00 36.571 114.806 8664.02 8754.02 2529.98 S 447452.22 N 205787.28 E 0.000 5571.88 10700.00 36.571 114.806 8744.33 8834.33 255 S 2447427.22 N 205841.37 E 0.000 5629.72 10800.00 36.571 114.806 0.22 E 2447402.23 N 205895.45 E 0.000 5687.56 10900.00 36.571 114.806 5274.31 E 2447377.23 N 205949.54 E 0.000 5745.41 11000.00 36.571 114.806 5328.39 E 2447352.23 N 206003.62 E 0.000 5803.25 11100.00 36.571 114.806 5382.47 E 2447327.24 N 206057.70 E 0.000 5861.10 11200.00 36.571 114.806 5436.56 E 2447302.24 N 206111.79 E 0.000 5918.94 11300.00 36.571 2704.96 S 5490.64 E 2447277.24 N 206165.87 E 0.000 5976.78 11400.00 36.571 2729.96 S 5544.73 E 2447252.24 N 206219.96 E 0.000 6034.63 11500.00 36.571 2754.95 S 5598.81 E 2447227.25 N 206274.04 E 0.000 6092.47 11600.00 36.571 2779.95 S 5652.90 E 2447202.25 N 206328.13 E 0.000 6150.31 11700.00 36. 2804.95 S 5706.98 E 2447177.25 N 206382.21 E 0.000 6208.16 11800.00 9627.76 9717.76 2829.94 S 5761.07 E 2447152.26 N 206436.30 E 0.000 6266.00 11900.00 9708.07 9798.07 2854.94 S 5815.15E 2447127.26 N 206490.38 E 0.000 6323.84 12000.00 9788.39 9878.39 2879.94 S 5869.24 E 2447102.26 N 206544.47 E 0.000 6381.69 e 12100.00 9868.70 9958.70 2904.93 S 5923.32 E 2447077.27 N 206598.55 E 0.000 6439.53 12200.00 9949.01 10039.01 2929.93 S 5977.41 E 2447052.27 N 206652.64 E 0.000 6497.37 12300.00 36.571 114.806 10029.32 10119.32 2954.93 S 6031.49 E 2447027.27 N 206706.72 E 0.000 6555.22 12400.00 36.571 114.806 10109.63 10199.63 2979.93 S 6085.58 E 2447002.27 N 206760.81 E 0.000 6613.06 12500.00 36.571 114.806 10189.94 10279.94 3004.92 S 6139.66 E 2446977.28 N 206814.89 E 0.000 6670.90 12600.00 36.571 114.806 10270.26 10360.26 3029.92 S 6193.75 E 2446952.28 N 206868.98 E 0.000 6728.75 12700.00 36.571 114.806 10350.57 10440.57 3054.92 S 6247.83 E 2446927.28 N 206923.06 E 0.000 6786.59 12800.00 36.571 114.806 10430.88 10520.88 3079.91 S 6301.92 E 2446902.29 N 206977.15 E 0.000 6844.44 12900.00 36.571 114.806 10511.19 10601.19 3104.91 S 6356.00 E 2446877.29 N 207031.23 E 0.000 6902.28 13000.00 36.571 114.806 10591.50 10681.50 3129.91 S 6410.08 E 2446852.29 N 207085.31 E 0.000 6960.12 13100.00 36.571 114.806 10671.82 10761.82 3154.90 S 6464.17 E 2446827.30 N 207139.40 E 0.000 7017.97 13200.00 36.571 114.806 10752.13 10842.13 3179.90 S 6518.25 E 2446802.30 N 207193.48 E 0.000 7075.81 22 August, 2003 - 14:52 Page 5 of9 DrillQuest 3.03.02.002 Sperry-Sun Drilling Services Proposal Report for Plan: RU#7 - RU#7 WP 18 Cook Inlet Forest Oil Measured Sub-Sea Vertical Local Coordinates Global Coordinates icaJ Depth Incl. 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Depth Depth Northings Eastings Northings Eastings ion Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) 13300.00 36.571 114.806 10832.44 10922.44 3204.90 S 6572.34 E 7133.65 13400.00 36.571 114.806 10912.75 11002.75 3229.89 S 6626.42 E 7191.50 13500.00 36.571 114.806 10993.06 11083.06 3254.89 S 6680.51 E 7249.34 13600.00 36.571 114.806 11073.37 11163.37 3279.89 S 6734.59 E 7307.18 13700.00 36.571 114.806 11153.69 11243.69 3304.89 S 6788.68 E 7365.03 13800.00 36.571 114.806 11234.00 11324.00 3329.88 S 207517.99 E 0.000 7422.87 e 13900.00 36.571 114.806 11314.31 11404.31 3354.88 S 207572.08 E 0.000 7480.71 14000.00 36.571 114.806 11394.62 11484.62 3379.88 S 207626.16 E 0.000 7538.56 14034.29 36.571 114.806 11422.16 11512.16 3388.45 S 207644.71 E 0.000 7558.39 Begin Dir @ 4.000·/1 OOft : 14034.29 MD,11512.16ftTVD 14100.00 39.199 114.852 11474.02 2446576.81 N 207681.33 E 4.000 7597.57 14200.00 43.199 114.914 11549.24 7065.84 E 2446549.10 N 207741.07 E 4.000 7661.52 14300.00 47.199 114.967 11619.69 7130.16 E 2446519.18 N 207805.39 E 4.000 7730.43 14370.03 50.000 115.000 11666.00 7177.77 E 2446497.00 N 207853.00 E 4.000 7781.46 End Dir, Start Sail @ 50.000· : 14370.03ftMD,11756.00ftTVD 9 5/8in Casing Top Hemlock Target - RU#7 T1 Wp 18, Current Target 14390.03 3491.68 S 7191.66 E 2446490.52 N 207866.89 E 0.000 7796.35 Begin Dir @ 4.000·/100ft: 14390.03 MD, 11768.86ft TVD 14400.00 50. 11775.24 3494.91 S 7198.60 E 2446487.29 N 207873.83 E 4.000 7803.79 14500.00 11746.25 11836.25 3528.07 S 7270.53 E 2446454.13 N 207945.76 E 4.000 7880.67 e 14600.00 11801.61 11891.61 3562.42 S 7346.36 E 2446419.78 N 208021.59 E 4.000 7961.34 14700.00 11851.05 11941.05 3597.80 S 7425.74 E 2446384.40 N 208100.97 E 4.000 8045.41 1~800.00 11894.31 11984.31 3634.03 S 7508.27 E 2446348.17 N 208183.50 E 41>00 8132.48 14900.00 11931.20 12021.20 3670.94 S 7593.56 E 2446311.26 N 208268.79 E 4.000 8222.13 14982.01 73.617 113.029 11956.57 12046.57 3701.59 S 7665.26 E 2446280.61 N 208340.49 E 4.000 8297.25 End Dir, Start Sail @ 73.61r : 14982.01ftMD,12046.57ftTVD 15000.00 73.617 113.029 11961.64 12051.64 3708.34 S 7681.14 E 2446273.86 N 208356.37 E 0.000 8313.87 15100.00 73.617 113.029 11989.85 12079.85 3745.87 S 7769.44 E 2446236.33 N 208444.67 E 0.000 8406.25 15200.00 73.617 113.029 12018.05 12108.05 3783.40 S 7857.73 E 2446198.80 N 208532.96 E 0.000 8498.64 15300.00 73.617 113.029 12046.26 12136.26 3820.93 S 7946.02 E 2446161.27 N 208621.25 E 0.000 8591.02 22 August, 2003 -14:52 Page 60f9 Dri"Quest~0~0,002 Sperry-Sun Drilling Services Proposal Report for Plan: RU#7· RU#7 WP 18 Forest Oil Measured Sub-Sea Vertical Local Coordinates Global Coordinates Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastin9s (ft) (ft) (ft) (ft) (ft) (ft) (ft) 15400.00 73.617 113.029 12074.46 12164.46 3858.46 S 8034.32 E 2446123.74 N 8683.40 15500.00 73.617 113.029 12102.67 12192.67 3895.99 S 8122.61 E 2446086. 8775.78 15600.00 73.617 113.029 12130.87 12220.87 3933.52 S 8210.91 E 2446 8868.17 15700.00 73.617 113.029 12159.08 12249.08 3971.05 S 8299.20 E 244 8960.55 15800.00 73.617 113.029 12187.29 12277.29 4008.58 S 8387.50 E 4459 9052.93 15900.00 73.617 113.029 12215.49 12305.49 4046.11 S 445936.0 209151.02 E 0.000 9145.31 16000.00 73.617 113.029 12243.70 12333.70 4083.64 S 445898.56 N 209239.31 E 0.000 9237.70 16100.00 73.617 113.029 12271.90 12361.90 4121.18 S 45861.02 N 209327.61 E 0.000 9330.08 16200.00 73.617 113.029 12300.11 12390.11 4158.71 S 445823.49 N 209415.90 E 0.000 9422.46 , 16238.62 73.617 113.029 12311.00 12401.00 ~ 417 S 2445809.00 N 209450.00 E 0.000 9458.14 All data is in Feet (US Survey) unless otherwise Vertical depths are relative to Well. Northings a Global Northings and Eastings are relative to N ates are relative to Grid North. to Well. anes, Zone 4. The Dogleg Severity is in Degrees Vertical Section is from Coordinate System i Grid Convergence at Based. upon Minimum C e type calculations, at a Measured Depth of 16238.62ft., The ~ottom Hole Displacement is 9716.59ft., in the Direction of 115.435° (Grid). The Along Hole Displacement is 9747.17ft, the Planned Tortuosity is 1.034°/100ft and the Directional Difficulty Index is 5.8. ,'; Cook Inlet Comment e Total Depth: 16238.62ftM D, 1240 1.00ftTVD 7 5/8in Casing Target· RU#7 T2 Wp 18, Current Target e 22 August, 2003 - 14:52 DrillQuest 3.03.02.002 Page 70f9 Forest Oil Comments Measured Depth (ft) 200.00 400.00 550.00 1383.33 1762.93 14034.29 14370.03 14390.03 14982.01 16238.62 Station Coordinates TVD Northings Eastings (ft) (ft) (ft) 200.00 0.00 N 0.00 E 399.96 2.67 S 2.24 E 549.66 9.69 S 8.13 E 1338.13 200.13 S 167.93 E 1656.80 320.98 S 332.55 E 11512.16 3388.45 S 11756.00 3485.20 S 11768.86 3491.68 S 12046.57 3701.58 S 12401.00 4173.20 S Formation Tops Formati on (Below Wel Sub-Sea D (ft) Angl 11666.00 Sperry-Sun Drilling Services Proposal Report for Plan: RU#7· RU#7 WP 18 Comment : 200.0 1100ft: 40 MD, 399.96ft TVD 100ft; 550.00ft MD, 549.66ft TVD 100ft; 1383.33ft MD, 1338.13ft TVD 762.93ftMD,1656.80ftTVD 100ft: 14034.29ft MD, 11512.16ft TVD 'r, Sta 50.000° : 14370.03ftMD,11756.00ftTVD ir @ 4. 000/100ft: 14390.03ft MD, 11768.86ft TVD , Start Sail @ 73.617° : 14982.01ftMD,12046.57ftTVD epth: 16238.62ftMD,12401.00ftTVD Penetration Point Sub-Sea Depth Northings Eastings (ft) (ft) (ft) Formation Name Cook Inlet e e 14370.03 11756.00 11666.00 22 August, 2003 -14:52 3485.20 S 7177.77 E Top Hemlock Page 80f9 Dri/IQuest 3.03.02.002 Forest Oil Casino details From Measured Vertical Depth Depth (ft) (ft) To Measured Vertical Depth Depth (ft) (ft) <Surface> 3500.00 14370.03 3500.00 14370.03 <Run-TD> <Surface> 3051.88 11756.00 3051.88 11756.00 <Run-TD> Taroets associated with this wel//Jath Target Name RU#7 T1 Wp 18 RU#7 T2 W Sperry-Sun Drilling Services Proposal Report for Plan: RU#7· RU#7 WP 18 Casing Detail 13 318in Casing 9 518in Casing 7 5/8in Casing Target Entry Coordinates TVD Northings Eastings (ft) (ft) (ft) 11756.00 3485.20S 7177.77E Mean Sea Level/Global Coordinates: 11666.00 2446497.00 N 207853.00 E Geographical Coordinates: 60041' 11.6248" N 151037' 47.6948" W Cook Inlet e Target Target Shape Type Point Current Target 12401.00 4173.20 S 8774.77 E Mean Sea Level/Global Coordinates: 12311.00 2445809.00 N 209450.00 E Geographical Coordinates: 60041' 05.2407" N 151037' 15.2938" W Point Current Target e 22 August, 2003· 14:52 DrillQuest 3.03.02.002 Page 9 of9 e 80 68" 1863" All DIMENSIONS ARE ¡t,PPROX. e REDOUBT UNIT #7 WELLHEAD SCHEMATIC \-24.31" í I 3-1/8 5000 13-5/8 5000 6BX AUGNMENT PIN SHOWN 90' OUT or POSI1lON 28.00" 24.75" 36" 00 CASING 13-3/8" 00 CASING 9- 5/8" 00. CASING 3-1/2" 00 WBlN e e Nabors Rig 429 13-5/8" 5000 psi BOP Stack Redoubt Unit #7 , 5000 psi Annular 5000 psi Blind Rams 5000 psi Pipe Rams 3" Kill Line Mud Cras I 2 2 I 3" Choke Line 1 = HCR Valve 2 = Gate Valve 5000 psi Pipe Rams 13 5/8" 5M Wellhead 13-3/8" Surface Casing 9-5/8" Intennediate e e BLOWOUT PREVENTION EQUIPMENT NABORS RIG No. 429 13-5/8" BOP Equipment 3 ea 13-5/8" x 5000 psi wp ram type preventers (Hydril) I 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, Koomey Model T20000-3S blowout preventer control unit with 280 gallon volume tank, main energy provided by two 20 HP electric motor driven triplex plunger pump charging 16 each II-gallon bladder type separate accumulator bottles. Second energy charging system consists of two air pumps. Above two energy systems backed up by six each 220 cubic feet nitrogen bottles connected to the manifold system. All above system controlled by a Model SU2KB7S S series manifold with six manual control stations at the unit. e e DRILLING FLUID SYSTEM DESCRIPTION Mud Pumps 2 ea IDECO T1600 (triplex, single acting pistons), 5000 psi fluid end discharge manifold system. Gear end equipped with electric driven lube oil pump, filtration. Pumps are driven by two each traction motors designed to stroke pumps at a maximum of 120 SPM under full load. Pumps are charged by two 40 HP, 1200 RPM Mission 5" x 6" centrifugal pumps. Mud Tank System (975 bbls Total Volume) Tank #1 (de sander tank) appx. 170 bbls. Tank #2 (mud cleaner tank) appx. 145 bbls. Tank #3 (centrifuge tank) appx. 145 bbls. Tank #4 (suction tank) appx. 44 bbls. Tank #5 (pill tank) appx. 44 bbls. Tank #6 (volume tank) appx. 430 bbls. Trip Tank appx. 40 bbls. Located in the substructure. Mud System Equipment 3 ea Derrick dual tandem shale shakers 1 ea Derrick 20 cone desilter 1 ea Geosource sidewinder mud hopper 3 ea Brandt 15 HP mud agitators 2 ea Brandt 5 HP mud agitators 3 ea Mission Magnum pumps, 6" x 8" centrifugal with 100 HP motors I ea Mission Magnum pump, 4" x 5" centrifugal with 25 HP motor 1 ea DEMCO desander, two 12" cones 1 ea Brandt Model CF-2 centrifuge "U f1-{ Welllme'lerence . e Subject: RU #7 Welllnteñerence Date: Fri, 29 Aug 2003 14:02:38 -0600 From: Rob Stinson <RDStinson@forestoil.com> To: "Tom Maunder (E-mail)..<tom_maunder@admin.state.ak.us> Tom, Sperry-Sun has run their anticollision program on our planned RU #7 development well. As you know, RU #7 will be the first well drilled from Leg #2 on the Osprey platform. The closest approach to any existing well is a 72 ft (center to center) offset with RU #6 at 2,415' MD. The ellipse of uncertainty of each well at this depth is about 10ft radius. We feel that this is a manageable close approach with an existing wellbore. Thanks, Rob Robert Stinson Drilling Engineer - Alaska Division Forest Oil Corporation (907)-868-2133 1 of 1 9/2/2003 9:4 7 AM rarest Permit e Subject: Forest Permit Date: Sun, 31 Aug 200317:05:47 -0800 From: Steve Davies <steve_davies@admin.state.ak.us> To: Tom Maunder <tom_maunder@admin.state.ak.us> Tom, RU 7 appears to need a spacing exception. I left Rob Stinson a voice mail message about this on Friday afternoon. I reviewed the file and put all info into RBDMS and put the file in your in box. The well can be drilled, just not tested or produced without the exception. I'll be out this morning. Ben is still in the hospital, and I need to go to his school to straighten out his schedule and work assignments. I'll phone in to check with you. Steve 1 of 1 e 9/2/2003 9:45 AM 'Ii FOREST Oil CORPORATION 310 K ST., STE. 700 PH. 907-258-8600 ANCHORAGE, AK 99501 1426 e ~~:'1!L::te~ ::=---____________________ ~DDlLA::·; a~ (i}fir~ National ~a::'", .;:;~ 'ž. ~ FOR l'ennit to,::"~~ <bll', i: ::5 <OOObO.: 0 < ~ ~ _~ ~~~ DATE 8/26/03 89-6/1252 e . tit TRANSMITAL LETTER CHECKLIST CIRCLE APPROPRIATE LETTERlPARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER g~··47 . '/J) 3 "-I!:::.u ,.. CHECK WHAT APPLIES ~ Rev: 07/] 0/02 C\jody\templates WELL NAME PTD# ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) PILOT (PH) SPACING EXCEPTION DRY DITCH SAMPLE "CLUE" The permit is for a new well bore segment of existing weD . Permit No, API No. . Production should continue to be reported as a function· of the original API number stated above. HOLE In accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 - 70/80) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to peñorate and produce is contingent upon issuance of a conservation order~ . . ~ spaclDg exception. r .. (Companv Name) assumes thé liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Oß ~uJ.(' ~~ «"'> Geologic Commissioner: Date: Engineering Commissioner: Date Public Commissioner Date Appr SFD Date 8/29/2003 35 36 37 38 ~S.eabedcOl')djtipl) ~uryey -<if Off-sh_oœ) Ye~ NA NA ~NA P.ermit ~D~ata~PJ~seoted on pote~ntial PveJpres~sure ~zOl')e.s ~Sei.smic_analysjs Qf .shallow gas~zPI)~S None~expe~cted bas~ed PO 9 ptfdet well.s jn~ area. Geology Appr TEM Date 9/2/2003 21 22 23 24 25 26 27 28 29 30 31 32 33 34 cao be issued wlo_ hyd(ogen sulfide measuœs Meçha_nicaLcoodjlionpf wells withil') ,t!-.OR yeri1ied (for~s~ervjce Well onJyj to_(pu~t PSig tncomments) C~hokeJDanifold compJie!> wlAPt RF'-53 (May 134) WQrk will oçcw withoytoperationshytdown Js pre!>ence_ Qf H2S gas~ probable ~B0PEs,~dp Jhey meet regulation ~BQPEpfess raiiog appropriate; J~st Jtdiver:t~r J~quiJ~d, dQes it meet reguJations DJilliog fluid program schematic_& ~~uip Jistadequat.e JtaJe-drilL has_a~ 10:403 fQr abandonment Adequatewellbofe ~eparatjo_n~Pfoposed beeo approved _Adequatetankage~ or resery~ pit ~CMT will çoveraJl C_asiog de_signs adeqya_t~ for CoT, B _& permafrpst KOOWJ1PfQduçtiye hori¡!:ons _CMT vol adequate to tie-iJ1 Jongstring to surf (:&g_ 18 19 20 ~Coodu_ctor _Surface ~casing~PJotect!> all_known USQWs _CMT v~ol adequ_ate_ to circ~ulate~ o_n ~cOl')d_uctor_ 8. SUJt c.sg Yes Y.es Yes No Yes Yes Yes NA _Yes NA Yes Yes Yes Y.es Y.es Yes NA -- Calçulaied_MASP t4~7 psi._ Planned ßpptes! press_ure_3000 psJ. Use Qf diverter has_beeI') waiyed 90 earlier weiJs" Expeçted 6HF' 8.65 EMW" Plan oed mud~ weJght No surface g<ls ~eeo,_gas 9.0 - 9.5 ppg. Wells_close spaced> but _diverge <IS drilling prpçeeds. _ Closest weJl 72' _at 24J 5' Ijft I')ot lJs~ed PO wellsc Oire_ctionat pla_n_PfQvided Rig Jo_c<lted 01') Ospr~yPJatform withsieel pits. No fe_Serve pit plan_ned. Qsprey has_Class J _disposal weJI.~ so~urceof drinkiog waterc Casjngsettiog depth of 3052' IVD SFO Engineering .~ q. z. -03 Appr Date _U_nique welt Administration 2 3 4 5 6 7 8 9 10 11 12 13 14 15 6 7 AÇMP Finding of Con.si.stençy_has bee_n issued_ for this pr9ieçt ~-- st(Îl')g_PJovided Pre-produ_ced Well _AJI weiJs_withtn 15-day wait JQcated withil') area and~s!rataauthorized bY_'ojeçtipo Prder # (put 10# in commeots>-(For Can permit P.ermit P.ermit Sufficient Jfdevi<lted, acreage~available indrilliog unjt WeJUocated in a_ defil')ed _pool WelUocated prop~r _distance_ from driJling unitb9undary~ WeHJocated p(op~rdistance from other weljs fe~ atla _Lease numb~r ~_..",' n_ame _aod Ol!mb_er Field & Pool ~nn'opriate ~ REDOUBT SHOAL, UNDEFINED OIL 114JDile _area_of review ideotified (Fpr ~ervjce w_ell 01')11[) iojeçtor; duration of pre-produgioO l.ess_ than 3 mOl')ths (For servtce well only) js_ well bore plaUI')( ¡ded _Oper_ator ol')ly affected party ~ _Qpe(ator has_apprppriate_ bon i}1 Jorce can be issl!ed wjthout )ns~ryaiiol') ord~r cao be issl!ed without "" be approved before ~d_mioistratíye apprpvaJ 720100 Initial ClasslType Y.es Yes _Y.es No Y.es No_ No Y.es Yes Yes Yes Yes Yes NA NA NA NA is adeQlJat~ to -Pfoi~ct <lny _aQlJifer th<ltcOlJld eyer conceiva~ble~serve as <I - WelJ may be driJI~d_ without .spacing e}(ception. but is approved may oot be tested orprod_uc~d uJ1tilasp<lcin-9ßxçeplion it Statewide .spacing alJows 90ly one_ oil Sr:>ACING EXCEPTION REQUJREQ: Statewtde spacing appJies. _Lowest :1 ,OOQ' of weUw Oepeodiog on_pJacement in theNE 114 of S_ection 19 p(perfs, weJlbore will be <tQOO'~ be eith.er the 21')d prod_ucer jnNW ~produçer from perfdJoterval 1l4Qf Seç per _qU<lrter 19> orth~ 2ndprQduceJ $ection" in RU #6_ prOducer. Red9ubt _Shoal pool tsclJrrentl)' lm_defined _~~__ Well Name: REDOUBT UNIT DEV I PEND GeoArea 820 7 Un 11810 Program DEV ___ Well bore seg On/Off Shore 1)ff Annular Disposal o