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198-041
Imagff 'roject Well History' File Cover i~" je 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. Organizing i~o,,~l[] RESCAN Color items: [] Grayscale items: [] Poor Quality Originals: []Other: NOTES: DIGITAL DATA .~ Diskettes, No. [] Other, No/Type BY: BEVERLY ROBIN VINCENT SHERY~INDY OVERSIZED (Scannable) j" Maps: [] Other items scannable by large scanner OVERSIZED (Non-Scannable) [] Logs of various kinds [] Other Project Proofing BY; BEVERLY ROBIN VINCENT SHERYL MARIA WINDY ScanningPreparation x 30 = = TOTAL PAGES III [1111111111 II III Production Scanning Stage I PAGE COUNT FROM SCANNED FILE: ~ PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: ~ YES NO Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: ~ YES ~ NO RESCANNEDB?': BEVERLY ROBIN VINCENT SHERYL MARIA WINDY General Notes or Comments about this file: DATE: Isl Quality Checked 12/10/02Rev3NOTScanned.wpd UNSCANNED, OVERSIZED MATERIALS AVAILABLE: 1 ~(~ ~_ FILE # To request any/all of the above information, please contact: Alaska Oil & Gas Conservation Commission ~ 333 W. 7th Ave., Ste. 100 Anchorage, Alaska 99501 Voice (907) 279-1433 Fax (907) 276-7542 M Marathon MARATHON Oil Company October 25, 2007 "~~~ ~~' ~_ ~ 2007 A~~ska (~!~ ~ ~i8~ ~;titl3, CaminiS310tt Qt1GhOrR~@ Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Mr. Tom Maunder NGZI ~ ~ 201 Alaska Oil & Gas Conservation Commissiot~.~,~~~~ 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-407 Completion Report Fi I Sterlin Uni e d. g t Well: SU 41-15 Dear Mr. Maunder: Enclosed please find the 10-407 Well Completion Report and Log for Sterling Unit well SU 41-15. The wellbore was plugged and abandoned during the June /July period of 2007 in preparation for sidetracking. Also attached, for your records, is the current wellbore diagram and Operations Summary. If you have any questions or require additional information, please call me at (907) 283- 1371. Sincerely, ~15k~, Kevin Skiba Production Technician Enclosures: 10-407 Completion Report cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS CLR ' ~® STATE OF ALASKA ~~"?'~~ ALASKA OIL AND GAS CONSERVATION CO~SION ~~ ~ 2 ~ 2007 WELL COMPLETION OR RECOMPLETION REPOR'~~Ioilq~ ~aS~~_ r,,,,,,„;"_: 1a. Well Status: Oil^ Gas^ Plugged ^ Abandoned Q Suspended ^ 2oAAC 2s.1os 20AAC 25.110 GINJ^ WINJ ^ WDSPL^ WAG ^ Other^ No. of Completions: 0 1b. Well Class: AfIChOta Development ^~ Exploratory ^ Service ^ Stratigraphic Test ^ 2. Operator Name: Marathon Oil Company 5. Date Comp., Susp., or Aband.: 7/6/2007 .Permit to Drill Number: 30'1-a0 198-041 3. Address: PO Box 1949 Kenai Alaska 99611-1949 6. Date Spudded: 11/10/1998 13. API Number 50-133-20484-00-00 4a. Location of Well (Governmental Section): Surface: 2,327' FSL 437' FEL, Sec. 9, T5N, R10W, S.M. 7. Date TD Reached: 12/25/1998 14. Well Name and Number: SU 41-15 Top of Productive Horizon: NA 8. KB (ft above MSL): 30' Ground (ft MSL): 254' 15. Field/Pool(s): Total Depth: 1,091' FNL, 1,035' FEL, Sec. 15, T5N, R10W, S.M. 9. Plug Back Depth(MD+TVD): 6,275' MD 5,611' TVD Sterling Fleld /Beluga POOI 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 314,742 y- 2,390,034 Zone- 4 10. Total Depth (MD +TVD): 12,600' MD 10,559' TVD 16. Property Designation: Sterling Unit TPI: x- NA y- NA Zone- Total Depth: x- 319,367 y- 2,386,550 Zone- 4 11. SSSV Depth (MD +TVD): NA 17. Land Use Permit: 18. Directional Survey: Yes No ~ (Submit electronic and printed information per 20 AAC 25.050) 19. Water Depth, if Offshore: NA (ft MSL) 20. Thickness of Permafrost (TVD): NA 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): 22. CASING, LINER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT TOP BOTTOM TOP BOTTOM PULLED 20" 94 K-55 0' S8' 0' S8' Driven NA NA 13-3/8" 61 K-55 0' 2,271' 0' 2,270' 17-1/2" 1,186 sks NA 9-5/8" 47 P-110 0' 10,312' 0' 8,540' 12-1/4" 2,284 sks NA 7" 29 L-80 10,108' 12,590' 8,383' 8,658' 8-1/2" 708 sks NA 23. Open to production or injection? Yes ^ No Q If Yes, list each 24. TUBING RECORD interval open (MD+TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD) NA 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 9,812' - 9,440' 211 sks Class G 26. PRODUCTION TEST Date First Production: 11/4/2003 Method of Operation (Flowing, gas lift, etc.): flowing Date of Test: NA Hours Tested: Production for Test Period Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: Flow Tubing Press. Casing Press: Calculated 24-Hour Rate ~ Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity -API (corr): 27. CORE DATA Conventional Core(s) Acquired? Yes ^ No ^~ Sidewall Cores Acquired? Yes ^ No^ If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. ~1=~_ NCi! ~ ~ 2DOl ~~ I,~ Form 10-407 Revised 2/2007 O n ~ ~ ~ n) ~O~ITINUED ON REVERSE 28. GEOLOGIC MARKERS (List all formations and encountered): 29. FORMATION TESTS NAME MD TVD Well tested? Yes ~ ff yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if needed, and submit 'Permafrost -Top detailed test information per 20 AAC 25.071. Permafrost -Base Beluga 6,342' 5,662' Tyonek 10,262' 8,501' Formation at total depth: Tyonek 30. List of Attachments: O rations Summa Current Well Schematic 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Kevin Skiba (907) 283-1371 Printed Name: Cral L. Ran Title: Senoir Com letions En ineer Signature: Phone: (907) 283-1372 Date: 70/25/2007 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 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 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: ff 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: Provide a listing of intervals cored and the corcesponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 2/2007 Permit: 198-041 KB-GL: 29.71' (original KB) 4.75" Otis tree cap Lift threads - 3.161" MCA Equipped with 10K wellhead and 4", 10K valves for frac stimulation via 2- 3/8" x 7" annulus. SU 41-15 Pad 43-9 2327' FSL, 437' FEL Sec. 9, T5N, R10W, S.M. Whipstock at 6,275' (7/6/07) Cement Soueezed Perfs (Beluga Sandl: (6/30/2007) 9,440' - 9,450' 9,516' - 9,526' 9,558' - 9,536' 9,576' - 9,584' 9,616' - 9,640' 9,624' - 9,626' 9,674' - 9,682' 9,676' - 9,678' 9,694' - 9,704' 9,696' - 9,698' 9,722' - 9,736' 9,730' - 9,732' 9,800 '- 9,812' 9,806' - 9,808' 10,017'-10,026' (Beluga) 10,942'-10,955' (Tyonek) 11,034'-11,044' (Tyonek) 11,121'-11,136' (Tyonek) 11,290'-11,296' (Tyonek) 11,305'-11,316' (Tyonek) 11,322'-11,331' (Tyonek) ~~~ PBTD 6,275' TD 12,600' 7" ZXP liner-top packer @ 10,108' 7", 29 ppf, L-80, BTC liner @ 10,108' - 12,590' Cmt with 708 sks of class G Well Name & Number: SU 41-15 Proposed Lease: Sterling Unit, Beluga Pool County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA Perforations: (MD) NA (TVD): NA Date Completed: 09/09/03 RKB: 29.71' Prepared By: Kevin Skiba Last Revision Date: 10124/07 MARATHON 20", K-55 Drive pipe @ 58' 13-3/8", 61 ppf, K-55, BTC surface casing @ 2271' Cmt with 1186 sks of class G 9-5/8", BTC casing @ 10,312' 0' - 3083', 53.5 ppf, P-110 3083' - 9866', 47 ppf, P-110 9866' - 10,312', 47 ppf, L-80 Cmt with 2284 sks of class G `~ CIBP at 6,299' (7/6/07) 7" Tubino Strino - 7", 26 ppf, P-110, BTC-M tubing Baker KC1 tubing anchor at 8,196' Baker SAB 194-73 permanent packer @ 8,198' ~~ Top of 211 sack _ Cement Plug @ 9,242' (6/30/07) •_ CIBP at 9850' (9/3/03) Cement plug 9872' - 10,055' • Marathon Oil Company Operations Summary Report Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Event Name: RE-ENTRY Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date I From - To Hours Code Code Phase 6/25/2007 09:00 - 10:30 1.50 MOB RIG_ MIRU 10:30 - 21:30 11.00 MOB RIG MIRU 21:30 - 22:00 0.50 SAFETY MTG_ MIRU 22:00 - 04:00 6.00 MOB RIG MIRU 04:00 - 06:00 2.00 RURD_ RIG_ MIRU 6/26/2007 06:00 - 06:00 24.00 RURD RIG MIRU 6/27/2007 06:00 - 09:30 3.50 RURD_ RIG_ MIRU 09:30 - 05:00 19.50 SERVIC RIG WBPREP 05:00 - 06:00 1.00 TEST_ EOIP WBPREP 6/28/2007 06:00 - 08:30 2.50 TEST EOIP WBPREP 08:30 - 10:00 1.50 MIX_ FLD_ WBPREP 10:00 - 11:30 1.50 CIRC CFLD WBPREP 11:30 - 12:30 1.00 INSPCT WLHD WBPREP 12:30 - 15:30 3.00 CIRC CFLD WBPREP 15:30 - 16:00 0.50 FLOW_ CHEK WBPREP 16:00 - 17:00 1.00 MIX PILL WBPREP 17:00 - 17:30 0.50 PULL_ EOIP WBPREP 17:30 - 19:00 1.50 MIX_ PILL WBPREP 19:00 - 22:00 3.00 CIRC CFLD WBPREP 22:00 - 22:30 0.50 RURD RIG WBPREP 22:30 - 01:00 2.50 NUND TREE WBPREP 01:00 - 06:00 5.00 NUND BOPE WBPREP 6/29/2007 06:00 - 12:00 6.00 NUND ROPE WBPREP Page 1 of 10 Spud Date: 9/1/1998 Start: 6/24/2007 End: Rig Release: 9/9/2003 Group: Rig Number: 1 Description of Operations Liner was cut too short .Splice and seam weld . Move sub and center on well, Set Generator, boiler,water tank ,mud pump and pits. move carrier and set on mud boat. Level carrier. Set Stairways R/U pit's and Mud pumps,Raise derrick,Pull electrical wires. Hold safety meeting with crane operator. (Crane work) set in fuel tank,Drillers side grey iron,Start gen. and set Iights,Dog house,Choke house,Windwalls Raise mast,and hook up guide lines Spot BOP stack in gray iron.. Splice and weld on liner on cuttings tank and # 3 mud pump area. Inspect man riders Set beaver slide and stairway to conex. set cuttings tank and # 3 mud pump. Run control) lines and rig service lines Change pump liners to 4" on mud pumps.lnspect bridge cranes,hyd. hoist.Move Rig up #3 pump,change to 4" Iiners.Spot M-I van,and cement silo.Hang torque tube, Rig up service Ioop.Saver sub from 4 1/2 IF to 4" HT-38 R/U choke and kill lines. Complete R/U GD-1 Inspect Drawworks brake system. Build volume in pits 500bb1s H2o for 6% KCL. Replace pads on old brake bands.and install. Rig up BJ Cementers.lnstall cellar grating over last well. Note Install 1" HP bull plug in pressure relief valve on flow line from 32-9 well .Valve Set at 2220psi. Test surface lines,kill,choke,high pressure mud lines to 3000 psi. Cont. Test surface HP mud lines, Repair leak's Kill Line, #1 Mud pump liner, Gray lock clamp on HP manfold,rig floor. Calibrate and Test Gas Monitors. Mix 8.6ppg KCL brine. Inspect well and prepare for well kill. PJSM. Open choke to 1/4 open and circulate down 2 3/8" TBG w/8.6ppg KCL brine (initial CSG pressure 2820psi last CSG pressure 2200psi, took 2340psi to open BPV). Shut-in well due to leaking wing valve. Install threaded flange with needle valve(CSG pressure increased F/2200psi to 2500psi). PJSM. Continue to circulate TBG and bleed down annulus. Circ. pressure 25psi and not increasing.(pumped 400bb1s Annulus pressure bled F/2500psi to Opsi). Shut down pump and observeTBG on vaccum. R/D kill line. Mix more 8.6ppg KCL brine and 50bb1 LCM pill w/2.5ppb Flo-vis, 6ppb poly pack, 50ppb CaCo2 40 and 50ppb CaCo3 10. PJSM and pull PBV,Rig up kill line Pump 55 bbl. LCM pill,Spot on bottom, Let set for 1/2 hr. Pump 3 bpm, 12000 stks.,Shut down well ,flowing thru tubing. Pump LCM to suface. Pump another50 bbls.well static on csg. and tubing.No losses PJSM;Rig up on csg. 9 5/8 X 7" annulus and bleed 925 psi down to 0 psi. PJSM;set PBV Nipple down tree. Nipple up 19"-11"10M X 13 5/8"5M adaptor spool . N!U S,Rd,A 13 5/8" 5M BOP. Cont. to N/U. C/O top rams to 2 3/8" rams. Carrier bolt broke while tightening on rams. Cont to N/U riser and R/U drip pan while repare 2 Printed: 10/24/2007 4:58:07 PM • • Marathon Oil Company Page 2 of 10 Operations Summary Report Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: RE-ENTRY Start: 6/24/2007 End: Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase ~ Description of Operations 6/29/2007 06:00 - 12:00 6.00 NUND BOPE WBPREP 3/8" ram carriers. R/U mouse hole. 12:00 - 13:00 1.00 NUND BOPE WBPREP PJSM. Install 2 3/8" rams. 13:00 - 14:00 1.00 NUND BOPE WBPREP PJSM;Test 2 3/8 8rd. floor valve and dart valve. 14:00 - 15:00 1.00 NUND BOPE WBPREP PJSM;PuII BPV ,Install two way check. 15:00 - 16:30 1.50 NUND BOPE WBPREP R/U 2 3/8 Test joint,attempt test looking for leaks. 16:30 - 17:30 1.00 NUND BOPE WBPREP Open rams,check and reinstall. 17:30 - 18:00 0.50 NUND BOPE WBPREP Attempt to screw back into hanger ,O-ring pulled off,unable to screw in. Rig up trash pump and pump fluid out of BOP. 18:00 - 20:00 2.00 NUND BOPE WBPREP Attempt test,no good,Remove kill line and cripple check valve to drain stack Three more attempts to test,try to observe leak. 20:00 - 21:30 1.50 NUND BOPE WBPREP Close doors,cont. to test BOP.Redess 2 3/8 rams with new rubbers. 21:30 - 22:00 0.50 NUND BOPE WBPREP Install 2 3/8 rams with new rubber, 22:00 - 02:00 4.00 NUND ROPE WBPREP BOP test-250 si low 2000 si hi h-10 min. ea.,Test blind rams,2 3/8 rams,Choke Manifold valves # 1,2,3,4,5,6,7,8,9,10,11,12-Inside and outside kill line valves,Check valve,HCR,-2 7/8 Floor valve,and dart valve,Valves on Top Drive Perfomance test on koomey unit. 02:00 - 02:30 0.50 NUND BOPE WBPREP Rig down BOP Test equip. 02:30 - 03:30 1.00 RURD_ CSG_ CMPPUL Rig up to pull 2 3/8 tubing 03:30 - 04:30 1.00 RUNPU TBG_ CMPPUL Pick-up landing joint and make up.Back out anchor screws. 04:30 - 05:00 0.50 RUNPU TBG_ CMPPUL Pull tubing hanger free and bring to rig floor.Lay down hanger and cut chem. injection, line prep to pull out of hole. Check flow.Fluid in well static. 05:00 - 06:00 1.00 RUNPU TBG_ CMPPUL POOH Lay down 2 3/8 tubing(check for norm). 6/30/2007 06:00 - 12:00 6.00 PULD_ TBG_ CMPPUL POOH UD 2 3/8" TBG(check for norm). 12:00 - 17:30 5.50 PULD_ TBG_ CMPPUL PJSM with crew coming on. POOH UD 2 3/8" TBG (total 126jnts 4.7PPF L-80 8rd and 173jnts 4.7ppf J-55 8rd, check for norm). 17:30 - 19:30 2.00 RURD_ CSG_ CMPPUL R/D 2 3/8" handling tools.PJSM; Pick up Test tools and change rams to varibles. 19:30 - 21:00 1.50 TEST_ BOPE CMPPUL Test varible rams,floor valve and IBOP.250 psi low , 2000 psi high,for 10 min. 21:00 - 21:30 0.50 RUNPU WBSH CMPPUL Rig down test equip.set wear bushing 21:30 - 22:30 1.00 RURD_ RIG_ CMPPUL PJSM;Rig floor to pick up 4" drill pipe. 22:30 - 06:00 7.50 PULD_ DP_ CMPPUL PJSM; Make up 4" mule shoe and RIH picking up 4" drill pipe and drifting. Monitor well ,No Gains No losses 7/1/2007 06:00 - 12:00 6.00 PULD_ DP_ CMPPUL Cont. P/U 4" HT-38 DP while RIH w/mule shoe. 12:00 - 12:30 0.50 PULD_ DP_ CMPPUL PJSM. Cont. to P/U 4" DP. Tag fill@ 9725'. 12:30 - 15:00 2.50 WASH FILL CMPPUL Wash Fill F/9725' to 9825' Pumped 25bb1 sweep and circ out @ 9825'. Observed sand on shakers. 15:00 - 16:30 1.50 WASH FILL CMPPUL Cont. to wash fill F/9825' to 9839'pump 50bbls sweep @ 9839' and circ. out. Observed sand on shakers.(P/U total of 313 jnts 4" DP). 16:30 - 18:00 1.50 PUMP CMT_ CMPPUL PJSM. R/U cement line. Pump 2bbls fresh water ahead. Test lines to 1500psi. Pump 9bbls fresh water ahead. Mix and pump 211sxs Class"G" cementw/.7%FL-63, .3%CD-32, .2%R-3, .1%ASA-301, and 1 gphs FP-6L to yield 43.4bbls 15.8ppg slurry. Follow with 2bbls fresh water. Displace w/93bbls 8.6ppg KCL brine(plug F/9839' to 9260'). 18:00 - 19:00 1.00 TRIP_ DP_ CMPPUL POOH to 8800'. 19:00 - 20:00 1.00 PUMP_ CMT_ CMPPUL Install wiper dart and pump bottoms up to clear pipe. 20:00 - 00:30 4.50 TRIP_ DP_ CMPPUL PJSM;POOH and lay down muleshoe. 00:30 - 01:00 0.50 SERVIC RIG_ CMPPUL Serv. rig and top drive Printed: 10/24/2007 4:58:07 PM • • Marathon Oil Company Operations Summary Report Page 3 of 10 Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: RE-ENTRY Start: 6/24/2007 End: Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Cade Code , Phase Description of Operations 7/1/2007 7/2/2007 17/3/2007 17/4/2007 01:00 - 02:30 1.50 REPAIR RIG_ CMPPUL Work on Draworks brakes. 02:30 - 06:00 3.50 TRIP_ DP_ CMPPUL Make up bit and bit sub RIH 06:00 - 07:00 1.00 TRIP_ DP_ CMPPUL Cont. to RIH w/6 1/8" bit to 8820'. 07:00 - 08:00 1.00 WASH FILL CMPPUL Wash F/8820' to top of plug @ 9242'(set down 10k on plug with Dumps on . 08:00 - 09:00 1.00 CIRC_ MUD_ CMPPUL Circ. clean @ 9200'(275GPM, 560psi, observed some contaminated cement in returns). 09:00 - 09:30 0.50 TRIP_ DP_ CMPPUL PJSM. POOH to 9040'. 09:30 - 10:00 0.50 TEST_ CSG_ CMPPUL Test CSG to 1000 si/30min. 10:00 - 14:00 4.00 TRIP_ DP_ CMPPUL POOH to 1700'. 14:00 - 14:30 0.50 CIRC_ CFLD CMPPUL Circ. @ 1700'(250GPM 186psi). 14:30 - 15:30 1.00 SETREL PKR_ CMPPUL P/U and set 7" RTTS 27'. Release from RTTS and POOH and UD running tool. 15:30 - 16:00 0.50 TEST_ PKR_ CMPPUL Test RTTS to 1000psi/15min 16:00 - 16:30 0.50 RUNPU WBSH CMPPUL Pull Wear Ring 16:30 - 20:00 3.50 NUND BOPE CMPPUL PJSM;Nipple down BOP,flow nipple,choke and kill line,remove BOP, and spacer spool. 20:00 - 22:00 2.00 NUND WLHD CMPPUL Remove 11' 5M X 11"10M tubing head. 22:00 - 00:00 2.00 NUND BOPE CMPPUL Install DSA11"-5K X 13 5/8"-5K X 4.5" long and spacer spool 13 5/8-5K X 36" long. 00:00 - 06:00 6.00 NUND BOPE CMPPUL PJSM;Nipple up BOP ,connect choke line,install choke valve,hook up kill line. 06:00 - 08:30 2.50 NUND BOPE CMPPUL N/U BOPE. 08:30 - 09:30 1.00 TEST_ BOPE CMPPUL Shell testa ainst blind rams and RTTS 250/2000psi 10min. 09:30 - 10:30 1.00 CLEAN_ RIG_ CMPPUL Clean and clear cellar area. 10:30 - 11:30 1.00 PULD_ PKR_ CMPPUL Retrieve and UD 7" RTTS. 11:30 - 12:00 0.50 CIRC_ MUD_ CMPPUL Circ. B/U. PJSM with crew coming on. 12:00 - 13:00 1.00 TRIP_ DP_ CMPPUL POOH w/ 6 1/8" bit. 13:00 - 14:00 1.00 TEST_ BOPE CMPPUL C/O to 7" Rams and C/O to long bales. 14:00 - 14:30 0.50 TEST_ BOPE CMPPUL Test 7" Rams 250/2000 si 10min. 14:30 - 15:00 0.50 PERF_ TBG_ CMPPUL PJSM. R/U Expro E/L 15:00 - 18:00 3.00 PERF_ TBG_ CMPPUL RIH w/ 1 9/16" TBG puncher Punch holes F/8110 to 8112 4spf. Hold 500psi while shoot puncher. Did not loose pressure. Pull gun up above perfs. Attempt to Circ w/750psi. Could not circ. POOH w/TBG puncher. 18:00 - 20:00 2.00 PERF_ TBG_ CMPPUL RIH with pert. gun to 8010' Misfire no perfs.POOH with gun. 20:00 - 21:30 1.50 PERF_ TBG_ CMPPUL Change out pert gun and RIH to 8010' Misfire POOH with gun. 21:30 - 22:00 0.50 PERF_ TBG_ CMPPUL PJSM;Rig up top sheave on hanging line. 22:00 - 00:00 2.00 PERF_ TBG_ CMPPUL Make up tubing cutter for 7"- 26# pipe RIH to 8020' Pull string weight to 250K up wt.Cut tubing Cagy 8020' free POOH with wireline cutter.Up wt.=190K. 00:00 - 00:30 0.50 RURD_ ELEC CMPPUL PJSM; Rig down Expro wireline 00:30 - 02:00 1.50 CIRC_ CFLD CMPPUL PJSM;Circ. out Packer fluid between 9 5/8 "and 7" 02:00 - 06:00 4.00 PULD_ TBG_ CMPPUL PJSM;Check for flow,Lay-down 7" hanger ,POOH lay down 7"-26# Tubing. 06:00 - 14:00 8.00 PULD_ TBG_ CMPPUL POOH UD 7" TBG(flare was 8.58"check for norm). 14:00 - 14:30 0.50 RURD CSG_ CMPPUL R/D Weatherford TBG tools. 14:30 - 15:30 1.00 TEST_ CSG_ PLUGAB Test 9 5/8" CSG to 1000psi/30min(took 3bbls to 1000psi). 15:30 - 17:00 1.50 TEST_ BOPE PLUGAB C/O top rams to 2 7/8" X 5 1/2" variable rams. Test to 250/2000psi. 17:00 - 17:30 0.50 RUNPU WBSH PLUGAB Install wear bushing. 17:30 - 19:00 1.50 RURD_ CSG_ PLUGAB C/O to short bales and DP elevators. 19:00 - 21:00 2.00 PULD_ BHA_ PLUGAB PJSM;Pick up and make up BHA for bit and scraper run. Printed: 10/24/2007 4:58:07 PM Marathon Oil Company Page 4 of 10 Operations Summary Report Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: RE-ENTRY Start: 6/24/2007 End: Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase ~ Description of Operations 7/4/2007 21:00 - 00:30 3.50 TRIP_ DP_ PLUGAB RIH with 4" drill pipe. 00:30 - 02:30 2.00 CIRC_ CFLD PLUGAB Pump Hi visc. sweep and circ. clean Up Wt.=140K Dn Wt.=140K 02:30 - 04:00 1.50 TRIP^ DP_ PLUGAB PJSM; Check flow,POOH from 8020' to 5723' Stand back in derrick(+/-4900' in derrick). 04:00 - 06:00 2.00 PULD_ DP_ PLUGAB PJSM;POOH lay down 4" drill pipe from 5723'. 7/5/2007 06:00 - 07:30 1.50 PULD_ DP_ PLUGAB Cont. POOH and UD 4" DP(total 156jnts UD). 07:30 - 09:00 1.50 TRIP ~ BHA_ PLUGAB POOH rack back BHA and UD 8.5"bit,8.5" mill and 9 5/8"scraper. 09:00 - 09:30 0.50 TRIP _ BHA_ PLUGAB PJSM. M/U 4" mule shoe and RIH w/BHA. 09:30 - 12:00 2.50 TRIP_ DP_ PLUGAB PJSM. RIH w/ 78 stds 4" DP to 5648'. 12:00 -15:00 3.00 PULD_ DP_ PLUGAB PJSM. PU 65jts 5" 19.5# S-135 DP. 15:00 - 16:30 1.50 TRIP_ DP_ PLUGAB TOH and rack back 5" DP (SLM) 16:30 - 19:30 3.00 PULD_ DP_ PLUGAB PU 64 jts 5" DP. 19:30 - 21:00 1.50 TRIP_ DP_ PLUGAB TOH and rack back 5" DP (SLM) 21:00 - 23:00 2.00 PULD_ DP_ PLUGAB PU remaining 67 jts of 5" DP.(total of 196 jts 5") 23:00 - 00:30 1.50 TRIP_ DP_ PLUGAB TOH and rack back 5" DP (SLM) 00:30 - 03:30 3.00 TRIP_ DP_ PLUGAB RU to handle 4". TOH w/ 4" DP SLM 03:30 - 04:30 1.00 TRIP_ BHA_ PLUGAB TOH w/ HWDP. 04:30 - 05:00 0.50 SERVIC RIG_ PLUGAB Rig Service. 05:00 - 06:00 1.00 CHANG EQIP PLUGAB PJSM. Change Saver Sub and gripper blocks to 5". 7/6/2007 06:00 - 08:00 2.00 TRIP_ BHA_ PLUGAB P/U 9 5/8" Halliburton EZDR. M/U setting tool. RIH w/4" HWDP. UD 4 3/4"jars. 08:00 - 12:00 4.00 TRIP_ BHA_ PLUGAB RIH w/9 5/8" EZDR plug to 6299'. 12:00 - 12:30 0.50 SETREL PLUG PLUGAB PJSM. Set 9 5/8" EZDR(cD6299'. 12:30 - 16:30 4.00 TRIP_ DP_ PLUGAB POOH w/Halliburton setting tool and UD. 16:30 - 17:00 0.50 TEST_ PLUG PLUGAB Test EZDR to 1000psi/10min(took 2bbls to 1000psi). 17:00 - 19:00 2.00 NUND BOPE PLUGAB PJSM. N/D BOPE. Empty and clean mud pits. Changeout wiring.. harness on #2 carrier motor. 19:00 - 00:30 5.50 NUND WLHD PLUGAB NU Vetco 'B' 11" 5M X 11" 10M section csg. spool. Install test sleeve. Test but failed due to leaking O-ring. Remove and replace O-ring. Test flange to 5k for 10min. 00:30 - 06:00 5.50 NUND BOPE PLUGAB NU 11" 10M X 13 5/8" 5 M 19" adaptor spool N/U S,Rd,A 13 5/8" 5M ROPE. Same time mixing new Flo-pro mud system. 7/7/2007 06:00 - 07:30 1.50 NUND BOPE PLUGAB Finish NU BOPE. R/U koomey lines. R/U chain and turnbuckles. 07:30 - 12:00 4.50 TEST_ BOPE PLUGAB Test BOPE 250/3500asi 10min(witness waved AOGCC by Bob Nolag). PJSM. R/U to test BOPE. Test 250/3500psi 10min. Test annular, variable rams, 4" dart, 4" TIW, upper and lower top drive valves. Inside and outside kill line valves, check valve, maual choke line valve, HCR, manifold valves 2,5,6,7,8,9,10,11,12. 12:00 - 14:00 2.00 TEST_ BOPE PLUGAB PJSM. Test BOPE 250/3500psi 10min Blind rams, CMV 3,4. 5" TIW and IBOP. Test variable rams, annular on 5" test joint. Perform koomey test. Install wear ring. 14:00 - 15:30 1.50 SLPCUT DLIN PLUGAB PJSM. Slip and cut 33' drilling line. Adjust drawworks brake. Check COM. 15:30 - 17:00 1.50 TEST_ BOPE PLUGAB Rebuild CMV#1 and retest. Test failed. Lou Gramaldi waved test on CMV#1(parts should be in early next week). 17:00 - 21:00 4.00 PULD_ BHA_ SIDET P/U 8.5" Whipstock and mill assy w/MWD. RIH w/ HWDP. Test MWD at 300gpm. Good pulse. 21:00 - 00:30 3.50 TRIP_ DP_ SIDET TIH to 6259'. 00:30 - 02:00 1.50 SETREL PKR_ SIDET Check wts up= 125k dwn 107k. Orient whipstock toolface using MWD to 316 deg. RIH tag CIBP at 6299'. Set whipstock anchor packer. Shear off whipstock. Top of whipstock tray at 6275'. (Brass bolt set to shear at 35k dwn wt. Work several times w/ 40-50k. Finally had to put torque into drill string and continue working to shear the bolt w/ 50k dwn wt.) Printed: 10/24/2007 4:58:07 PM . Page 1 of 1 • Maunder, Thomas E (D4A) From: Skiba, Kevin J. [kskiba@MarathonOii.Com] Sent: Tuesday, October 16, 2047 1:53 PM To: Maunder, Thomas E (DOA) Cc: Icibele@MarathonOil. Com Subject: RE: SU 41-15RD (207-088) ~ C`~_ O Attachments: SU 41-15RD Drilling Operations Summary.pdf Tom, The 10-407 Sundry for abandoning the SU 41-15 well bore has not been submitted yet. I will be working on getting it out to you soon. I have attached the drilling portion of the Operations Summary for SU 41-15 / SU 41-15RD well. There are a number of people involved with the distribution of drilling information. So please disregard this attachment if someone else has already forwarded this information to you. We are currently evaluating the process that we use to distribute drilling information. We are looking at ways that we can refine and improve this process to ensure that the appropriate information gets to the AOGCC. Thanks, Kevin Slaba Production Technician Marathon Oil Company Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 ~~~~ ~~~ ~ s 200 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, October 12, 2407 10:07 AM To: Skiba, Kevin ]. Cc: Ibele, Lyndon Subject: SU 41-15RD (207-088) Kevin, I am reviewing the 407 for this well. The operations summary does not have any of the drilling details. Could you please send the reports, email is fine. Also, do you know the status of the 447 for abandoning SU 41-15? I do not find any entry in our tog that we have received the report for the recent P&A work. Thanks in advance. Call or message with any questions. Tom Maunder, PE AOGCC 10/16/2007 • ~ M 111narathon MARATHON C)il Company Marathon Oil Company Alaska Asset Team P.O. Sox 1949 Kenai, AK 99611 Telephone 907/283-1326 Fax 907/283-1350 ~~ Y ~Q July 3, 2007 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-407 Sundry Report 303-215 Field: Sterling Unit Well: SU 41-15 Dear Mr. Maunder: ~ ~~ ~~ ~~ Enclosed please find the Report of Sundry Well Operations form 10-407 for Sterling Unit 41-15 well. This report covers the recompletion to a single tubing string, perforation addition work and fracture stimulation completed from July through November of 2003. Also attached, for your records, are the Operations Summary, Current wellbore diagram, and Directional Survey. If you have any questions or require further information, please contact me at (907) 283- 1333. We are making every attempt to find and closeout pending sundry notices. Please notify us of any other pending sundry reports. Sincerely, Dennis Donovan Jr Production Engineer I Enclosures: 10-407 Sundry cc: AOGCC Well Schematic Houston Well File Operations Summary Kenai Well File Directional Survey DMD KJS JIJh ~9 6 2007 ~~iaska (~i9 ~ Cos Cans. Commission 4nchara~e ~,,~~ ~ ~ ~.~;~.~ ~ ~VED STATE OF ALASKA ~ d''~`'+~ ALA -OIL AND GAS CONSERVATION COM ION CJL ~ 6 ZOO7 WELL COMPLETION OR RECOMPLETION REPORT A D I~OG 1a. Well Status: Oil^ Gas^ Plugged ^ Abandoned ^ Suspended ^ 2o.anc2s.tos 2oanc2s.~~o _,,/ GINJ^ WINJ^ WDSPL^ WAG^ Other^ No. ofCompletio ~ ~jP"~ 1b. Well Class: ` ~ "' Development 0 ~© Service ^ StratigraphicTest^ 2. Operator Name: Marathon Oil Company 5. Date Com or Aband.: ~ ~ 12. Permit to Drill Number: ~~ ~ ~`v 198-041 . 3. Address: PO Box 1949, Kenai Alaska 99611-1949 6. Date Spudded: 11/10/1998 13. API Number: 50-133-20484-00-00' 4a. Location of Well (Governmental Section): Surface: 2327 FSL, 43T FEL, Sec. 9, T5N, R10W, S.M. 7. Date TD Reached: 12/25/1998 14. Well Name and Number: SU 41-15 - Top of Productive Horizon: 166' FNL, 2368' FEL, Sec. 15, T5N, R10W, S. M. @ 9440' 8. KB (ft above MSL): 30' Ground (ft MSL): 254' 15. Field/Pool(s): Total Depth: 1091' FNL, 1035' FEL, Sec. 15, T5N, R10W, S.M. 9. Plug Back Depth(MD+TVD): _9850' MD , 8198' TVD Sterling Field /Beluga Pool 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 314742 y- 2390034 Zone- 4 10. Total Depth (MO +TVD): 12600' ~ 10,559' ~ 16. Property Designation: Sterling Unit - TPI: x- 318119 y- 2387449 Zone- 4 Total Depth: x- 319367 y- 2386550 Zone- 4 11. SSSV Depth (MD +TVD): N/A 17. Land Use Permit: 18. Directional Survey: Yes ~ No (Submit electronic and printed information per 20 AAC 25.050) 19. Water Depth, if Offshore: NIA (ft MSL) 20. Thickness of Permafrost (TVD): N/A 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): Cement Bond Log - VDL, TCP Gun Correlation -Res Saturation Tool Sigma Mode 22. CASING, LINER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 94 K-55 0' 58' Driven Driven N/A 0 13-3/8" 61 K-55 0' 2271' 17-1/2" 1186 sks N/A 9-5/8" 47 P-110 0' 10,312' 12-1/4" 2284 sks N/A 0" 7" 29 L-80 10,108' 12,590 8-1/2" 708 sks N/A 23. Open to production or injection? YesQ No^ If Yes, list each 24. TUBING RECORD interval open (MD+TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD) TCP Perforations (9/6/2003) 7", 29# / 2-3/8", 6.5# 8,256' / 9,300' 7" PKR Baker SAB @ 8198' 9624'-9626' (8 holes, 4-5/8", 120-deg, 0.37") 9676'-9678' (8 holes, 4-5/8", 120-deg, 0.37") 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 9696'-9698' (8 holes, 4-5/8", 120-deg, 0.37") DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 9730'-9732' (8 holes, 4-5/8", 120-deg, 0.37") 9872'-10055' Cmt Plug 107sks Class G (21.4bbls) 9/2/2003 9806'-9808' (8 holes, 4-5/8", 120-deg, 0.37") 9624'-9808' Fracture 51,5001bs of 16/30 Ottawa Sand @ 2-6ppg Fracgel 753 bbl of gelled fluid on 7"X2-3/8" annulus and 40bb1 of diesel in deadstring 26. PRODUCTION TEST Date First Production: 11/4/2003 Method of Operation (Flowing, gas lift, etc.): Flowing Date of Test: 11/4/2003 Hours Tested: 228 Production for Test Period Oil-Bbl: Gas-MCF: 1588 Water-Bbl: 13.5 Choke Size: 64/64 Gas-Oil Ratio: Flow Tubing Press. 675 Casing Press: Calculated 24-Hour Rate -i Oil-Bbl: Gas-MCF: 167 Water-Bbl: 1.4 Oil Gravity -API (corr): 27. CORE DATA Conventional Core(s) Acquired? Yes ^ No ^~ Sidewall Cores Acquired? Yes ^ No ^~ If Yes to either question, list formations and intervais cored (MD+TVD of top and bottom of each), and summarize lithoiogy and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. N/A ^COMPL€TION ~ 5EP 1 2 ?DDS ~~ ~~~ Form 10-407 Revised 2/2007 O i ~' ~ ~ ~~CpNTINUED ON REVERSE ~~j ~8. GEOLOGIC MARKERS (List all form ations and en countered): 29. FORMATION TESTS NAME MD TVD Well tested? Yes / If yes list intervals and formations tested briefl , , y summarizing test results. Attach separate sheets to this form, if needed, and submit detailed test information per 20 AAC 25.071. Beluga 6342' 5662' Tyonek 10262' 8501' Formation at total depth: Tyonek 30. List of Attachments: Directional Survey, Detailed Operations Summary Report 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Kevin Skiba (907) 283.1371 Printed Name: Dennis M D novan Jr Title: Production Engineer I Signature: Phone: 907-283-1333 Date: 6/29/2007 ~1~~ 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 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). ttem 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 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: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 2/2007 M ~rnoM C] 50-133-20484 CC: 98-41 KB-GL: 29.71' (original KB) 437' FEL, 2327' FSL Sec. 9, T5N, R10W, S.M. 4.75" Otis tree cap Lift threads - 3.161" MCA Equipped with 10K wellhead and 4", 10K valves for frac stimulation via 2- 3/8" x 7" annulus. 9624' - 9626' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 9676' - 9678' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 9696' - 9698' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 9730' - 9732' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 9806' - 9808' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 (assumed plugged off during workover) 9440'-9450' 9616'-9640' 9674'-9682' 9694'-9704' 9722'-9736' 9800'-9812' SU 41-15 r: 20", K-55 Drive pipe @ 58' 13-3/8", 61 ppf, K-55, BTC surface casing @ 2271' Cmt with 1186 sks of class G 7" Tubing String - 7", 26 ppf, P-110, BTC-M tubing Baker KC1 tubing anchor at 8196' Baker SAB 194-73 permanent packer @ 8198' Re-entry guide @ 8256' 4.6 ppf, L-80 & J-55, EUE 8rd to 9300' 4' of carbide blast rings immediately below tubing hanger Baker chemical injection nipple @ 1570' w/ 1/4" control line to surface X-nipple @ 9233' ID = 1.875" Re-entry guide @ 9300' Tagged fill at 9,788' 110,003'-10,014' (Beluga) ,10,01 T-10,026' (Beluga) 10,942'-10,955' (Tyonek) 11,034'-11,044' (Tyonek) 11,121'-11,136' (Tyonek) 11,290'-11,296' (Tyonek) 11,305'-11,316' (Tyonek) 11,322'-11,331' (Tyonek) PBTD 9,850' TD 12,600' CIBP at 9850' (9/3/03) Cement plug 9872' - 10,055' 9-5l8", BTC casing @ 10,312' 0' - 3083', 53.5 ppf, P-110 3083' - 9866', 47 ppf, P-110 9866' - 10,312', 47 ppf, L-80 Cmt with 2284 sks of class G 7" ZXP liner-top packer @ 10,108' 7", 29 ppf, L-80, BTC liner @ 10,108' - 12,590' Cmt with 708 sks of class G Per AOGCC 303-215 (10-40~j Well Name & Number: SU 41-15 Lease Sterling Unit, Beluga Pool County or Parish: Kenai Peninsula State/Prov. Alaska Country: USA Perforations: (MD) (TVD) Date Completed: 11/04/03 RKB: Prepared By: Dennis Donovan Last Revision Date: 11/04/03 ~ C = c ~ C ~ c = c Marathon Oil Company Opera#ions Summary Report Page 1 of 11 Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: WORKOVER Start: 7/15/2003 End: 11/2/2003 Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code I Code Phase Description of Operations 7/25/2003 07:00 - 08:00 1.00 RURD SLIK WBPREP 08:00 - 12:30 4.50 TAG BOTM WBPREP 12:30 - 14:00 1.50 SETREL TOOL WBPREP 14:00 - 15:30 1.50 SETREL TOOL WBPREP 15:30 - 17:45 2.25 TAG BOTM WBPREP 17:45 - 19:00 1.25 RURD._ SLIK WBPREP 7/31/2003 08:00 - 17:00 9.00 GLEAN LOC SITLOC 8/1(2003 08:00 - 17:00 9.00 PREP LOC SITLOC 8/3/2003 10:00 - 19:00 9.00 PREP LOC SITLOC 8/4/2003 08:00 - 13:00 5.00 MILL FISH WBPREP 13:00 - 18:00 5.00 RURD EQIP WBPREP 8/5/2003 08:00 - 06:00 22.00 MIX_ MUD_ WBPREP 18/6/2003 08:00 - 09:15 1.25 RURD EQIP WBPREP 09:15 - 11:00 1.75 WAITON EOIP WBPREP 11:00 - 13:00 2.00 RURD EQIP WBPREP 13:00 - 19:45 6.75 CIRC MUD WBPREP 19:45 - 21:00 1.25 CIRC MUD WBPREP MIRU slickline oR, chn~. shortstring pressure = 2475 psi, longstring = 2050 psi, casing = 2475 psi. PJSM, test lubricator. RIH with 2.25" gauge ring. Having much difficulty getting through ice in the tubing from 0' to 412' until able to pump methanol down lubricator. RIH, tag pack-off at 8751' MD. RiH with 2.5" GS pulling tool with prong to 8751'. Latch and pull isolation assembly. POOH. Equalize shortstring tubing and casing. RIH with 2.5" BO shifting tool to 8751'. Attempt to shift open, sheared off. POOH. Repin and RIH. Open CMU sliding sleeve at 8751'. POOH. RIH with 2" drive down bailer. Tagged fill at 9843' MD. POOH with very small amount of Beluga sand. POOH. RDMO slickline. Removed well houses from wells SU 41-15 and SU 32-9. ND SSVs and flowlines from both wells. Prepped location for mobilization of workover rig. Kraxberger replaced existing water well pump with MOC-owned 5-hp unit. Also installed 2" outlet. S&R graded the location in preparation for the Glacier rig #1. Moved in 500-bbl vertical tank, circulating pump, loader, mud products, scaffolding, light plant, dumpster, and flowback iron. mj,gIZQPRS pipe recovery unit on lonastrina., Conduct PJSM, test lubricator. TP = 2050 psi. RIH with jet cutter for 2-7/8", 6.5 ppf tubing. Tie in with CCL; Jet cut at 9770'. leaving a 15' stub down to the next tubing joint. Longstring pressure imediately dropped to 1000 psi, then gradually fell to 600 psi. shortstring pressure and casing pressure unchanged at 2500 psi. POOH, RDMO APRs. RU Swaco 100-bbl blending unit, 500-bbl vertical tank, circulating pump for 500-bbl tank, and water supply hose. M-I blending 700-bbl of 11.0 ppg bentonite mud. RU flowback iron off of casing valve. MIRU BJ pumping unit. RU pumping lines to longstring tubing. Return lines are rigged up from the 9-5/8" casing. Conduct PJSM, test pumping lines to 5000 psi. Longstring has 1450 psi, shortstring = 2675 psi, casing = 2550 psi. Opened up casing valve to begin bleeding off pressure. Foowback line parted at union which had been improperly made up. No injuries, but near-miss documented. Shut-in well, rigged down damaged equipment. Waiting on replacement equipment. RU BJ choke skid and additional flowback iron. Held PJSM. Retested pumping iron to 5000 psi and tested flowback iron to 5000 psi. Begin pumping 11.0 ppg bentonite mud down longstring while blowing down casing annulus. Have to shut down job twice to reconfigure flowback iron due to the flowback stream making a mess. Pump a total of 465 bbl of mud by the time casing pressure was bled to zero. Continue pumping, and after pumping a total of 570 bbl getting mud returns. After circulating an additional 40 bbl of mud, returns are 9.5 PP9• Switch returns line from casing to shortstring tubing. Pressure test. shortstring tubing = 3000 psi. Bleed shortstring to flowback tank while pumping 11.0 ppg down longstring at 3 bpm. Pump 37 bbl of mud before losing prime (mud tank empty). Bled shortstring to zero. Did not 'get returns on shortstring, but well is dead. SDFN Printed: 6/27/2007 1:Q1:10 PM • Marathon Oil Company Operations Summary Report Legal Well Name: Common Well Name Event Name: Contractor Name: Rig Name: STERLING UNIT 41-15 STERLING UNIT 41-15 WORKOVER GLACIER DRILLING GLACIER DRILLING Start: 7/15/2003 Rig Release: 9/9/2003 Rig Number: 1 Page 2 of 11 Spud Date: 9/1/1998 End: 11 /2/2003 Group: Date From - To Hours Code Code Phase Description of Operations 8/7/2003 08:00 - 14:00 6.00 RURD_ EQIP WBPREP RDMO BJ purring iron, M-I blending unit, flowback tank, mud stroage tank, etc. Well SU 41-15 has no pressure on it. 20:00 - 22:00 2.00 RUNPU EQIP WBPREP Dry rod 2.5" type 'H' BPV_s in shortstring and._longstring tubing. 8/13/2003 06:00 - 12:00 6.00 RURD_ RIG_ MIRU MIRU drilling equipment Load mud boat, trailers, scope down & load 12:00 - 00:00 ~ 12.00 ~ RURD_ RIG_ 00:00 - 06:00 6.00 ~ RURD_ RIG_ 8/14/2003 ~ 06:00 - 12:00 ~ 6.00 ~ RURD_ RIG_ 12:00 - 00:00 12.00 ~ RURD_ RIG_ 00:00 - 06:00 8/15/2003 106:00 - 12:00 12:00 - 13:00 13:00 - 14:30 14:30 - 17:00 17:00 - 21:00 6.00 ~ RURD_ RIG_ 6.00 ~ RURD_ RIG_ 1.00 RURD_ EQIP 1.50 RURD EQIP 2.50 RURD_ EQIP 4.00 CIRC MUD 21:00 - 22:00 ~ 1.00 ~ RURD ~ EOIP 22:00 - 23:00 23:00 - 00:00 00:00 - 01:00 01:00 - 06:00 8/16/2003 06:00 - 12:00 12:00 - 12:30 12:30 - 16:00 1.00 RURD_ EQIP 1.00 NUND DTRE 1.00 NUND UBOP 5.00 NUND UBOP 6.001 NUND I UBOP 0.50 TEST_ EQIP 3.50 TEST EQIP 16:00 - 19:30 19:30 - 20:30 20:30 - 21:00 3.50 ~ TEST_ ~ EQIP 1.00 TEST_ EQIP 0.50 RURD EQIP out sub. MIRU Load trailers. PU matting boards, liner. RD change house. Set mats, set generator house, boiler, water tank. Spot & raise sub, mud boat, carrier, pump room, pits, slop tank. Spot camp traliers, change house, office trailer. RU parts house, mechanics shop. RU electric & lights. MIRU Level carrier, RU derrick house, continue electric RU. Prep derrick for raising, raise derrick. Install outriggers, trip tank, flow line. MIRU Pull electric lines to carrier. Install mufflers and exhaust stacks. Crain in choke and doghouse windwalls. Install flowline, panic line, stairs and carrier landings. Install catwalk and beaver slide. MIRU Install back landing and windwalls. Level carrier guide wires. Scope up derrick. R/U air, water, elec lines. R/U mud pits. Unload trailers. Install yard lights on sub base. R/U degasser. R/U console. R/U carrier tarps and cylinder socks. Repair derrick electric lines. R/U standpipe and cement lines. R/U geolograph line. R/U rotary table motor. Spot welding house and #3 mud pump house. MIRU R/U derrick cylinder skins, splash guard, standpipe manifold. R/U choke lines. R/U snubbing post, kill and fill up hoses, #3 mud pump VFD's, koomey lines, Epoch line, and C/O shaker screens. Mix mud and check koomey bottles. MIRU Inspect tugger lines. Install torque tube and top drive. Install grabber box. Function test #1 and #2 mud pumps, top drive and rotary table. WBPREP R/U long bales.. WBPREP Pull BPV's from LS and SS. Very little pressure on LS and SS. Test hanger seal to 5000psi. WBPREP R/U choke line to annulus and kill line to LS. WBPREP Open annulus valve. Annulus had 175psi bleed to 0 in 10min. Circ. well. Took 30bbls to get returns(3BPM 1000psi). Monitor returns and keep MW in @ 11.OPPG. Circ 627bb1s to get 11.Oppg mud out annulus. WBPREP C/O choke line to SS. Open SS had 400psi bled to 50psi in 5min. Shut in SS had 350psi. Circ. 73 bbls to get 11.Oppg mud up SS. Observe well to be dead. WBPREP R/D choke and kill line. Set BPV's in LS and SS. WBPREP N/D tree. WBPREP Pull tree and spot in BOP stack. WBPREP N/U 11" 5M X 13 5/8" 5M adaptor spool. N/U 13 5/8" 5M spacer spool. N/U 13 5/8" 5M R,S,Rd,A stack. WBPREP N/U choke and kill lines. CIO top rams to 2 7/8" dual rams. Install scaffolding, flowline, turnbuckles, fill up lines, trip tank, dual mousehole. Function test BOPS. WBPREP Pull BPV's and set TWC's. WBPREP Attempt to test BOPE. Leak between adaptor spool and spacer spool. Leak on Greylock connector on choke line. Tighten connections. WBPREP Test dual 2 7/8" rams, blind rams, choke line HCR, manual choke line valve, inside and outside kill line valves and check valve. Test CMV1-12 to 250/5000psi 10min. WBPREP Pull TWC's and install landing joints. CMPPUL R/U Schlumberger EL. PJSM prior to TBG punch. Schlumberger cable Printed: 6/27/2007 1:41:10 PM • Marathon Oil Company Page 3 of 11-I Opera#ions Summary Report Legal Well Name: STERLING UNIT 41-15 Common We{I Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: WORKOVER Start: 7/15/2003 End: 11/2/2003 Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To .Hours Code Code Phase Description of Operations 8/16/2003 20:30 - 21:00 0.50 RURD_ EQIP CMPPUL jumped sheave while P/U gun. 21:00 - 22:30 1.50 REPAIR EQIP CMPPUL Build new rope socket. 22:30 - 02:30 4.00 REPAIR EQIP CMPPUL Schlumberger hoist failed. Trouble shoot and repair. 02:30 - 03:00 0.50 TEST_ EQIP CMPPUL PJSM prior to punching TBG. P/U gun. Test lubricator. 03:00 - 04:30 1.50 MfLL_ FISH CMPPUL RIH w/TBG puncher. Shoot 8 holes(8835' to 8837' 5' below packer). POOH.. UD gun. 04:30 - 05:00 0.50 RURD_ EQIP CMPPUL RID Schlumberger. 05:00 - 06:00 1.00 CIRC_ MUD_ CMPPUL Circ. down LS and out annulus 36PM 1050psi. 8/17/2003 06:00 - 08:00 2.00 CIRC_ MUD_ CMPPUL Cont. circ. down LS and up annulus 3BPM 1050psi (500b1s). 08:00 - 09:30 1.50 CIRC_ MUD_ CMPPUL R/U to circ down LS and up SS 36PM 1350psi(60bbls). 09:30 - 12:00 2.50 RURD_ EQIP CMPPUL R/U Weatherford dual TBG tools. 12:00 - 14:00 2.00 RUNPU TBG_ CMPPUL PJSM prior to pulling TBG. Attempt to pull TBG and Packer. Can not release packer. Cont to work pipe while waiting for APRS to cut TBG above packer. 14:00 - 16:00 2.00 RURD_ EQIP CMPPUL R/U APRS. Safety meeting prior to cutting TBG. 16:00 - 19:00 3.00 MILL_ FISH CMPPUL RIH W/2 1/4" Jet Cutter. Cutt SS TBG @ 8798'(5' above packer). POOH. 19:00 - 22:00 3.00 MILL_ FISH CMPPUL RIH W/2 1/8" Jet Cutter. Cutt LS TBG @ 8755'(48' above packer). POOH. 22:00 - 00:30 2.50 MILL_ FISH CMPPUL Work pipe and finish cut. Pull hanger above rotary. UD hanger assy. 00:30 - 02:30 2.00 CIRC_ MUD_ CMPPUL CBU down short sting. 02:30 - 06:00 3.50 RUNPU TBG_ CMPPUL POOH and UD 2 7/8" 6.5PPF L-80 EUE TBG. 8/18/2003 .06:00 - 03:00 21.00. RUNPU TBG_ CMPPUL Cont. POOH and UD 2 7/8" 6.5PPF L-80 EUE TBG. 03:00 - 05:30 2.50 RURD_ EQIP CMPPUL R/D Weatherford. C/O to short bales and DP elevators. C/O mouseholes. 05:30 - 06:00 0.50 RURD_ EQIP CMPPUL R/U rig floor, tongs, pipe spinners, and slips. 8/19/2003 06:00 - 07:00 1.00 RURD_ EQIP CMPPUL R/U rig floor, DP tongs, DP spinners, sub racks and subs. 07:00 - 07:30 0.50 TEST_ EQIP CMPPUL R/U to test BOPE. 07:30 - 09:30 2.00 TEST_ EQIP CMPPUL Test Annular 250/3000psi 10min. Lower4" pipe rams, upper and lower kelly cock, TIW, IBOP 250/5000psi 10min. Found leak in bleeder and repaired. Perform Koomey test. Pull test plug and run wear bushing. 09:30 - 12:00 2.50 TRIP_ TOOL CMPPUL P!U Baker overshot assy. 12:00 - 00:00 12.00 TRIP_ TOOL CMPPUL RIH w/overshot assy while P/U DP. 00:00 - 00:30 0.50 MIX_ MUD_ CMPPUL Get up and down wts. Mix barite to bring wt. of mud in pits to 11.Oppg. 00:30 - 01:00 0.50 ENGAG FISH CMPPUL Engage fish @ 8733'. Dress TOF and catch in grapple. Pull 60K over and S/O. Pull 50K and fish came free. Gained 20k on wt indicator. 01:00 - 04:00 3.00 CIRC_ MUD_ CMPPUL CBU. Flow check well and pump dry job. 04:00 - 06:00 2.00 TRIP_ TOOL CMPPUL POOH w/fish(SLM). 8/20/2003 06:00 - 09:30 3.50 TRIP_ TOOL CMPPUL POOH w/fish(SLM). 09:30 - 11:00 1.50 PULD_ BHA_ CMPPUL UD overshot assy. 11:00 - 14:00 3.00 RURD_ EQIP CMPPUL R!U Weatherford. R/U long bales and dual handling equip. 14:00 - 01:00 11.00 TRIP_ TOOL CMPPUL PJSM prior to UD fish. L/D dual string fish(dual packer, TBG and blast joints). 01:00 - 03:04 2.00 RURD_ EQIP CMPPUL RiD Weatherford. CIO bales, elevators, and manse hole. 03:00 - 04:00 1.00 TEST_ EQIP CMPPUL C/O upper rams to 2 7/8" X 5 1/2" variable rams. Pull wear bushing and install test plug. 04:00 - 05:00 1.00 TEST_ EQIP CMPPUL Test upper variable rams to 250/5000psi 10min. Pull test plug and install wear bushing. 05:00 - 06:00 1.00 PULD_ BHA_ CMPPUL M/U overshot assy. 8/21/2003 06:00 - 12:00 6.00 TRIP_ TOOL CMPPUL RIH to 8766' w/8 1/8" overshot assy. P/U DP singles and tag TOF @ 9776'. 12:00 - 14:00 2.00 ENGAG FISH CMPPUL Dress TOF and catch in grapple. Work stuck TBG w/ max 85K over straight pull and jar stuck TBG. TBG did not come free. Set pipe with Printed: 6/27/2007 1:41:10 PM • Marathon Oil Company Page 4 of 11 Operations Summary Report Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: WORKOVER Start: 7/15/2003 End: 11/2/2003 Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Description of Operations 8/21/2003 12:00 - 14:00 2.00 ENGAG FISH CMPPUL 30k over on slips. 14:00 - 15:00 1.00 MILL_ FISH CMPPUL R/U APRS. PJSM prior to cutting TBG. 15:00 - 18:00 3.00 MILL_ FISH CMPPUL RIH w/2 1/8" Jet cutter. Could not pass 10007'(above liner TOP). POOH. 18:00 - 20:30 2.50 MILL_ FISH CMPPUL Stuck 2 1/8" cutter while POOH @ 525'. Pressure up on DP. Moved cutter 10' to 515' and stuck again. Work EL and pressure up on DP could not move tool 20:30 - 22:00 1.50 MILL_ FISH CMPPUL Cut EL and strip through pump-in sub. 22:00 - 22:30 0.50 MILL_ FISH CMPPUL Release overshot from fish. 22:30 - 03:00 4.50 MILL_ FISH CMPPUL POOH stripping fine to +/-9200'. PJSM with crew coming on tower (Found cutter close to a tool joint. Freed it by turning, not sure what had it in a bind. 100% recovery of line and tool). 03:00 - 06:00 3.00 TRIP_ TOOL CMPPUL POOH w/overshot assy. 8/22/2003 06:00 - 09:00 3.00 TRIP_ TOOL CMPPUL POOH w/overshot assy (Found peices of plastic thread protector on top of hollow mill). 09:00 - 12:00 3.00 TRIP_ TOOL CMPPUL C/0 elevators. Strap wash pipe. P/U 8.5" wash shoe and 5 3/4" wash pipe and M/U BHA. 12:00 - 12:30 0.50 SERVIC RIG_ CMPPUL Service rig and adjust brake. 12:30 - 17:30 5.00 TRIP_ TOOL CMPPUL RIH and tag fill @ 9803'. 17:30 - 19:00 1.50 WSHOV ISH CMPPUL Washover 2 7!8" TBG F/9803' to 9904'. 19:00 - 21:00 2.00 WSHOV ISH CMPPUL Washover 9904' to 9919'(hard ,observed coal across shakers). 21:00 - 23:30 2.50 CIRC_ MUD_ CMPPUL 23:30 - 00:00 0.50 TRIP_ TOOL CMPPUL 00:00 - 05:00 5.00 TRIP_ TOOL GMPPUL 05:00 - 06:00 1.00 TRIP TOOL CMPPUL 8/23/2003 06:00 - 07:00 1.00 TRIP_ TOOL CMPPUL 07:00 - 08:30 1.50 TRIP_ TOOL CMPPUL 08:30 - 09:30 1.00 SLPCUT DLIN CMPPUL 09:30 - 13:30 4.00 TRIP_ TOOL CMPPUL 13:30 - 16:30 3.00 WSHOV ISH CMPPUL 16:30 - 17:00 0.50 TRIP_ TOOL CMPPUL 17:00 - 17:30 0.50 CIRC_ MUD_ CMPPUL 17:30 - 23:00 5.50 TRIP_ TOOL CMPPUL 23:00 - 00:00 1.00 TRIP TOOL CMPPUL 00:00 - 00:30 0.50 TRIP TOOL CMPPUL 00:30 - 02:00 1.50 TRIP_ TOOL CMPPUL 02:00 - 05:30 3.50 TRIP_ TOOL CMPPUL 05:30 - 06:00 0.50 WSHOV ISH CMPPUL 8!24!2003 06:00 - 09:00 3.00 WSHOV ISH CMPPUL 09:00 - 15:30 6.50 TRIP_ TOOL CMPPUL 15:30 - 17:00 1.50 TRIP TOOL CMPPUL 17:00 - 17:30 0.50 TRIP TOOL CMPPUL 17:30 -.19:30 2.00 SERVIC RIG_ CMPPUL 19:30 - 00:00 4.50 TRIP_ TOOL CMPPUL 00:00 - 01:00 1.00 TRIP TOOL CMPPUL (Later note -the coal was an indication that the casing was penetrated.) Circ. clean and condition mud. POOH to above TOF @ 9776'. Pump Dryjob. POOH. Empty Junk Basket (a few small pieces of cement and coal, and some sand. One 10" long thin metal sliver). Rack back 5 3/4" wash pipe. POOH w/8 1/8" wash shoe. Ci0 wash shoes to 6". RIH. Slip and cut drill line. Cont. RIH w/6" wash shoe. Tag fill @ 9918'. W/O 9918' to 9926'(void in fill F/9923' to 9925'). Pump pressure increased indicating worn shoe. POOH to above TOF @ 9776. Check for flow. Pump dryjob. POOH w/6" Wash shoe(wave type). Rack back wash pipe(three cups of formation w/small metal shavings in junk basket). C/O wash shoe(shoe worn almost flat with taper from outside 5 3/4" at tip of shoe). 6" Drag type shoe run in hole. RIH w/BHA. Cont. RIH. Tag @ 9920'. W/O 9920' to 9922'. Cont. to W/O @ 9922'. No progress. Pump dryjob. POOH. Found TBG between 4th and 5th stand of WP. UD 135' of cut 2 7/8" TBG. TBG was bent on bottom. Cont. to POOH w/wash pipe and wash shoe. Shoe was worn smooth with 5 718" OD tapper from outside. Service rig. C/O tugger line. FtIH w/8 1/8" overshot assy. Cont. RIH P/U single DP. Tag @ 9918'. Printed: 6127/2007 1:41:10 PM r~ U u Marathon Oii Company Page 5 of 11 Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: '~ Rig Name: STERLING UNIT 41-15 STERLING UNIT 41-15 WORKOVER GLACIER DRILLING GLACIER DRILLING Spud Date: 9/1/1998 Start: 7/15/2003 End: 11/2/2003 Rig Release: 9/9/2003 Group: Rig Number: 1 Date From - To Hours Code Code Phase 18/24/2003 01:00 - 01:30 0.50 ENGAG FISH CMPPUL 01:30 - 06:00 4.50 TRIP_ TOOL CMPPUL 8/25/2003 06:00 - 08:00 2.00 TRIP_ TOOL CMPPUL 08:00 - 08:30 0.50 TRIP_ TOOL CMPPUL 08:30 - 12:00 3.50 TRIP_ TOOL CMPPUL 12:00 - 13:30 1.50 SERVIC RIG_ CMPPUL 13:30 - 20:30 7.00 TRIP_ TOOL CMPPUL 20:30 - 23:30 3.00 WSHOV ISH CMPPUL 23:30 - 00:30 1.00 WSHOV ISH CMPPUL 00:30 - 06:00 5.50 TRIP_ TOOL CMPPUL 8/26/2003 06:00 - 07:30 1.50 TRIP TOOL CMPPUL 07:30 - 08:30 1.00 TEST_ EOIP CMPPUL 08:30 - 12:00 3.50 TEST EOIP CMPPUL 12:00 - 18:30 6.50 TRIP_ TOOL CMPPUL 18:30 - 21:00 2.50 WSHOV ISH CMPPUL 21:00 - 21:30 0.50 WSHOV ISH CMPPUL 21;30 - 22:30 1.00 WSHOV ISH CMPPUL 22:30 - 00:00 1.50 CIRC_ MUD_ CMPPUL 00:00-06:00 6.00 TRIP TOOL CMPPUL 8/27/2003 06:00 - 13:00 7.00 TRIP_ TOOL CMPPUL 13:00 - 17:30 4.50 WSHOV ISH CMPPUL 17:30 - 18:30 1.00 CIRC_ MUD_ CMPPUL 18:30 - 01:00 6.50 TRIP TOOL CMPPUL 01:00 - 01:30 0.50 TRIP_ TOOL CMPPUL 01:30 - 06:00 4.50 TRIP_ TOOL CMPPUL 8/28/2003 06:00 - 07:30 1.50 TRIP_ TOOL CMPPUL 07:30 - 08:00 0.50 ENGAG FISH CMPPUL 08:00 - 14:00 6.00 TRIP_ TOOL CMPPUL 14:00 - 15:00 1.00 TRIP TOOL CMPPUL 15:00 - 17:00 2.00 TRIP_ TOOL CMPPUL 17:00 - 18:00 1.00 SLPCUT DLIN CMPPUL 18:00 - 22:30 4.50 TRIP TOOL CMPPUL 22:30 - 01:00 2.50 WSHOV ISH CMPPUL 01:00 - 04:00 3.00 WSHOV ISH CMPPUL 04:00 - 04:30 0.50 WSHOV ISH CMPPUL 04:30 - 05:00 ~ 0.50 ~ CIRC_ MUD_ ~ CMPPUL Description of Operations Work overshot assy to 9925'. POOH w/overshot assy. POOH w/8 1/8" overshot assy. UD overshot assy. No recovery. P/U 7 5/8" wash pipe and 8.5" wash shoe. Slip and cut drill line and check COM. RIH w/wash pipe and wash shoe. W/O 9922' to 9932'. W/O no progress @ 9932'. Mix and pump dry job. POOH. POOH UD JB(50# metal in JB, 2gal volume, largest piece 5"X3"). Rack back 7 5/8" wash pipe (Approx 8-10' of wadded up 2 7/8" TBG in wash shoe). R/U to test BOPE. Pull wear bushing. Set test plug. Test annular to 250/3500psi 5min. Test lower 4" pipe rams, upper variable rams 2 7/8" X 5 1/2", inner and outer kill line valves, check valve, choke HCR, choke manual valve, 1-12 CMV's, upper and lower TDS valves, blind rams, safety valve, and IBOP valve to 250/5000psi 5min. Perform Accumulator performance test. Pull test plug and install wear bushing. R/D test equipment. RIH w/ 8.5" wash shoe and 7 5/8" wash pipe. Tag @ 9931'. W/O 2 7/8" TBG 9931' to 9937'(high torque, slow washing). W/O 9937'-9990'(easy washing). W/O 9990-9998(high torque, slow washing). Pulled 60K over to free wash pipe. Lost 3' back to 9995'. CBU. Pump dryjob. POOH. Rack back 7 5/8" wash pipe. UD 8.5" shoe(wear on inside, cutting edge worn out. Several pieces of metal with 1 gallon of sand in junk basket). M/U 8.5" wash shoe. RIH. Tag @ 9995'. Washover F/9995' to 10000'(high torque and occasionally loosing hole). Circ. w/3 pumps (8.56PM 2300psi) pump dry job. POOH. UD 8.5" wash shoe(shoe very worn mostly on face. Not much external or internal wear. 20#, 2gallons metal in junk basket mostly small pieces, a few larger pieces 2" X 3" that could be casing). M/U 8 3/8" overshot assy with long extension. RIH w/overshot assy. RIH w/8 5/8"overshot. Engage fish @ 9967'(first coupling). Pull 16K over twice. POOH w/overshot assy. UD 1 cut joint of TBG 25.7', full joint of TBG 31.1', and 7.2' blast joint. Blast joint bent and necked down on broken end with some damage above break. 30# ground metal with 2 pieces of CSG largest 6" X 2 3/4" in junk basket. UD 3 joints 7 5/8" wash pipe. M/U 8.0" wash shoe and 7 5/8" wash pipe. RIH. Slip and cut drill line. Cont. RIH w/8" wash shoe and 7 518" wash pipe. Tag @ 10,000'. W/O 10,000' to 10,007'(very slow washing w/some erratic high torque). W/O 10,007' to 10,023'(increase in ROP and torque smooth). W/O @ 10,023'. Penetration stopped. P(U off bottom and lost 5'. Had some erratic high torque and over pulls working back to bottom. Worked back to 10,023' but could not wash any deeper.. Circ. Mix and pump dryjob. Printed: 6/27/2007 1:41:10 PM • Marathon OiI Company Operations Summiary Report Page 6 of 11 Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: WORKOVER Start: 7/15/2003 End: 11/2/2003 Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Sub I phase Code 8/28/2003 05:00 - 06:00 1.00 TRIP_ TOOL CMPPUL 8/29/2003 06:00 - 10:30 4.50 TRIP TOOL CMPPUL ~ 8/30/2003 8/31 /2003 9/1 /2003 9/2/2003 10:30 - 12:00 1.50 TRIP_ TOOL CMPPUL 12:00 - 13:00 1.00 SERVIC RIG_ CMPPUL 13:00 - 17:00 4.00 TRIP_ TOOL CMPPUL 17:00 - 23:30 6.50 WSHOV ISH CMPPUL 123:30 - 02:00 2.50 WSHOV ISH CMPPUL '.02:00 - 02:30 0.50 CIRC, MUD_ CMPPUL 02:30 - 06:00 3.50 TRIP TOOL CMPPUL ~ 06:00 - 09:00 3.00 _ TRIP TOOL CMPPUL 09:00 - 10:00 1.00 SERVIC RIG CMPPUL 10:00 - 12:00 2.00 SERVIC RIG_ CMPPUL 12:00 - 14:00 2.00 TRIP_ TOOL CMPPUL 14:00 - 19:00 5.00 TRIP_ TOOL CMPPUL 19:00 - 20:00 1.00 ENGAG FISH CMPPUL 20:00 - 02:00 6.00 TRIP TOOL CMPPUL 02:00 - 02:30 0.50 SERVIC RIG_ CMPPUL 02:30 - 04:00 1.50 TRIP_ TOOL CMPPUL 04:00 - 06:00 2.00 SLPCUT DLIN CMPPUL 06:00 - 07:00 1.00 SERVIC RIG_ CMPPUL 07:00 - 08:00 1.00 TRIP_ TOOL CMPPUL 08:00 - 09:30 1.50 TRIP TOOL CMPPUL 09:30 - 10:00 0.50 TRIP_ TOOL CMPPUL 10:00 - 15:00 5.00 TRIP_ TOOL CMPPUL 15:00-15:30 0.50 TRIP_ TOOL CMPPUL 15:30 -17:00 .1.50 MILL FISH CMPPUL 17:00 - 17:30 0.50 CIRC_ MUD_ CMPPUL 17:30 - 18:30 1.00 TRIP_ TOOL CMPPUL 18:30 - 02:30 8.00 TRIP TOOL CMPPUL 02:30 - 04:00 1.50 TRIP_ TOOL CMPPUL 04:00 - 06:00 2.00 LOG_ CSG_ PLUGAB 06:00 - 09:30 3.50 LOG CSG PLUGAB 09:30 - 18:00 8.50 LOG CSG PLUGAB 18:00 - 21:00 3.00 LOG CSG PLUGAB 21:00 - 21:30 0.50 LOG_ CSG_ PLUGAB 21:30 - 02:00 4.50 TRIP_ BHA_ PLUGAB 02:00 - 03:30 1.50 TRIP_ BHA_ PLUGAB 03:30 - 06:00 2.50 CIRC MUD_ PLUGAB 06:00 - 11:00 5.00 CIRC MUD' PLUGAB 11:00 - 12:00 ~ 1.00 ~ PUMP_~ CMT_ ~ PLUGAB Description of Operations POOH. POOH w/8" wash shoe and 7 5/8" wash pipe(wash shoe very worn and 30#, 2 gallons ground metal in junk basket no large pieces of metal). P/U 8 5/16" wash shoe. RIH. Service rig. Cont. RIH w/wash shoe and wash pipe. Wash down from 10,000'. Tag @ 10,023'. W/O 10,023' to 10,047'. W/O 10,047' to 10052'(observed cement across shakers). Mix and pump dryjob. ,POOH w/8 5/16"wash shoe and 7 5!8"wash pipe. 'POOH w/8 5/16" Wash shoe and wash pipe. Found 2 slabs of 9 5/8" CSG( 3.8' X 6 3/4", and 29.6' X 6 3/4"). UD pieces of CSG. R!D pipe spinners. Change oil in #1 drawworks engine. Service carrier, blocks, TDS and crown. Service spinners while wait on orders. R/U spinners. UD 8 5/16" wash shoe. P/U 7 5/8" overshot. RIH. w/overshot assy. Work overshot assy to 10,054'(no indication of catch). Mix and pump dry job. POOH w/ overshot assy. No recovery. UD overshot assy. Service carrier. M/U 6 5/8" X 8 1/2" mill assy. Slip and cut drill line. Clean and organize rig floor while wait on 8 3/8" mill. UD 6 5/8" X 8 1/2" mill assy. M/U 8 3/8" mill assy. RIH. POOH. C/O mill assy to 6 1/2"Junk mill X 8 1/2" String mill assy. RIH tagged @ 10,003'. Wash down 10,003' to 10,054'. Mill 10,054' to 10,055'(low torque very slow penitration, small slivers of coal across shaker). Circ. and mix dry job. POOH to 9700'. RIH to 10,055'. POOH(SLM, no correction). UD BHA(No wear on mills. 2 gallons formation/old mud/cement in junk baskets). C/O elevators UD wash pipe from derrrick. R/U Schlumberger. PJSM prior to running logs. M/U USIT-CBL tools. RIH w/USIT-CBL log to 9975'. USIT not working. POOH. Repair cable head. RIH to 9975'. USIT failed. POOH. C/0 USIT sonde. RIH to 9975. Run USIT-CBL log 9975' to 8600'. POOH UD USIT-CBL log(lost 8.5hrs rig time to logging tool failures). This time period was added to account for the lost 8.5hrs rig time to logging tool failures listed above. PJSM prior to running RST tools. M/U RST tools and RIH. Log RST 9975' to 8600'. POOH L/D RST R/D Schlumberger. RIH w/4"mule shoe. P/U DP singles. Tag @ 10055'. Circ, and condition mud for balance plug. Circ. and condition mud for cement balance plug. PJSM prior to cementing. Pump 10bbls water ahead. Test BJ fines to 3500psi. Pump 5 bbls ahead. Mix and pump 107sxs class"G" cement to yield 21.4bbls Printed: 6/27/2007 1:41:10 PM • Marathon Oil Company Page ~ of 11 Operations Summary Report Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: WORKOVER Start: 7/15/2003 End: 11/2/2003 Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours ~ Code Code 1 Phase Description of Operations 9/2/2003 11:00 - 12:00 1.00 PUMP CMT PLUGAB 12:00 - 12:30 0.50 PUMP CMT_ PLUGAB 12:30 - 14:00 1.50 CIRC MUD PLUGAB 14:00 - 18:30 4.50 TRIP_ BHA_ PLUGAB 18:30 - 21:30 3.00 TEST EQIP PLUGAB 21:30 - 04:30 7.00 CIRC_ MUD_ PLUGAB 04:30 - 05:00 0.50 PULD_ BHA_ PLUGAB 05:00 - 06:00 1.00 TRIP_ BHA_ PLUGAB 9/3!2003 06:00 - 10:30 4.50 TRIP_ BHA_ PLUGAB. 10:30 - 12:00 1.50 CIRC_ MUD_ PLUGAB 12:00 - 12:30 0.50 DRILL_ CMT_ PLUGAB 12:30 - 15:00 2.50 CIRC_ MUD_ PLUGAB 15:00 - 15:30 0.50 CIRC_ MUD_ PLUGAB 15:30 - 21:30 6.00 TRIP_ BHA_ PLUGAB 21:30 - 22:30 1.00 SETREL PLUG PLUGAB 22:30 - 05:00 6.50 SETREL PLUG PLUGAB 05:00 - 06:00 1.00 MIX_ MUD_ CMPRUN 9!4/2003 06:00 -13:30 7.50 MIX_ MUD_ CMPRUN 13:30 - 16:30 3.00 CIRC MUD CMPRUN 16:30 - 17:30 1.00 MONITR WELL CMPRUN 17:30 - 03:00 9.50 PULD DP CMPRUN 03:00 - 03:30 0.50 TEST_ EQIP CMPRUN 03:30 - 04:30 1.00 TEST_ EQIP CMPRUN 04:30 - 05:00 0.50 TEST_ EQIP CMPRUN 05:00 - 06:00 1.00 RURD_ EQIP CMPRUN 9/5/2003 06:00 - 07:30 1.50 RURD_ EQIP CMPRUN 07:30 - 08:30 1.00 PULD DP CMPRUN 08:30 - 09:30 1.00 REPAIR EQIP CMPRUN 09:30 - 18:30 9.00 PULD DP CMPRUN 18:30 - 19:30 1.00 RURD_ EQIP CMPRUN 19:30 - 21:00 1.50 CIRC MUD CMPRUN 21:00 - 22:00 ~ 1.00 ~ SETREL ~ PKR_ ~ CMPRUN 22:00 - 23:00 1.00 TEST_ CMPRUN 23:00 - 00:00 1.00 SETREL PKR CMPRUN 00:00 - 01:00 ~ 1.00 ~ INSPCT 'TBG ~ CMPRUN 15.8ppg slurry. Follow w/2.5bbls water. Displace w/97bbls 11.5bbg mud. POOH to 9600'. Reverse circ. 2X DP volume(got back 25bbls cement contaminated mud}. POOH. UD 8jnts DP with cement set up on outside. Pull wear bushing. Test upper variable rams, lower pipe rams, blind rams, upper and lower top drive valves, !BOP, TIW, choke manifold valves 1-12. manual choke line, HCR, inside and outside manual kill line valves, kill line check valve to 250l5000psi 5min. Test annular to 250/3500psi 5min. Perform accumulator performance test. Test gas allarms. Pull test plug. Set wear bushing. Clean pits 1, 2 and pill pit. M/U 8.5" bit and 9 5/8" scraper, 6 1/4" collars. RIH. RIH to 9750'. CBU while wait on cement. Wash down 9750' to 9870'. Drill firm cement 9870' to 9872'. Circ~and clean nits while waif on AO CC to aprove p ug engt Mix and pump dryjob. '-~ POOH(SLM). UD collars. P/U 9 5/8" EZ Drill bridge plug. RIH and set 9 5/8" EZ Drill bridge plug @ 9850'. Mix 8.6ppg KCL brine. Mix 8.6ppg KCL brine and prepare for hole displacement. Pump 50bb1 clean sweep pill. Follow with 40bb1 high vis sweep. Displace well to to 8.6ppg brine @ 9BPM. Monitor well POOH rack back 14stnds DP. POOH L/D 287jnts DP. UD Halliburton running tool Pull wear bushing. Run test plug. C/O top rams to 7". Test door seals to 250/3500psi. R/U Weatherford. Cont. R/U to run 7" TBG. PJSM prior to running 7" TBG. P/U wireline entry guide w/pump out plug. M/U 1 Joint 7" TBG. M/U SAS packer and anchor. Run 7" TBG(total 176jnts 7" 26ppf P-110 Butt-Mod TBG). C/O Weatherford TBG tongs. Run 7" TBG(total 176jnts 7" 26ppf P-110 Butt-Mod TBG). M/U 7" CSG hanger assy and landing joint. R/U to reverse circ. Drop setting ball. Reverse circ. 200bb1s 6%KCL brine w/CRW132 corrosion inhibitor into annulus. Land 7" TBG hanger(TBG tail @ 8255', PKR@8197'). PJSM before pressure up on TBG. Pressure up on TBG. Set packer w/3700psi. Cont. to pressure up to 5000psi. Could not blow out ball seat. Connect test line to annulus and test packer to 800psi/10min. Pressure up to 5000psi down TBG to blow ball seat. Could not blow ball seat. PJSM with crew coming on tower. Attempt to blow ball seat. Test pump failed. Prep 2 3/8" TBG while wait on BJ services. Printed: 6/27/2007 1:41:10 PM ~ 1 ~J a Marathon Oil Company Pages of 11 Operations Summary Report Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: WORKOVER Start: 7/15/2003 End: 11!2/2003 Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group.: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Descriptionof Operations 9/5/2003 01:00 - 02:00 1.00 SETREL PKR_ CMPRUN R/U BJ services. Test lines to 5000psi. Pressure up to 5000psi and blow ball seat. 02:00 - 03:00 1.00 RURD_ EQIP CMPRUN R/D BJ services. UD landing joint. 03:00 - 03:30 0.50 TRIP_ BHA_ CMPRUN RIH w/27jnts 4" DP. 03:30 - 04:30 1.00 SETREL PKR_ CMPRUN M/U Halliburton RTTS and storm valve. Set @ 25'. Test to 1000psi/5min. 04:30 - 06:00 1.50 NUND DBOP CMPRUN N/D BOP. 9/6/2003 06:00 - 09:00 3.00 NUND DBOP CMPRUN ND BOPE. 09:00 - 14:00 5.00 NUND UwLH CMPRUN Install 11" 5M x 11" 10M CWLT tubing head. Test seals to 10,000 psi, void to 5000 psi. 14:00 - 20:00 6.00 NUND UBOP CMPRUN NU BOPE. 20:00 - 21:00 1.00 NUND UBOP CMPRUN Install 2-3l8" rams. 21:00 - 21:30 0.50 SETREL PKR_ CMPRUN PU 2 jts DP. Unseat RTTS tool. Reseat at 50' RKB. 21:30 - 22:30 1.00 TEST_ EQIP CMPRUN PU 2-3/8" landing joint & install tubing hanger. Test 2-3/8" rams to 250 psi low/5000 psi high. Pull tubing hanger. 22:30 - 23:00 0.50 PULD_ EQIP CMPRUN Install wear bushing. 23:00 - 23:30 0.50 SETREL PKR_ CMPRUN Release & LD RTTS tool. 23:30 - 01:00 1.50 PULD_ DP_ CMPRUN LD 14 stds 4" DP. 01:00 - 02:30 1.50 PERF_ CMPPRF RU to run TCP perf guns & 2-3/8" tubing. Guns are 4-5/8", 3 spf, 120-degree phase loaded with 39.0 gm Millennium charges (entrance hole = 0.37"). Designed for limited entry, with 8 shots for every pert interval (40 holes total). 02:30 - 04:30 2.00 PERF_ CMPPRF PJSM. PU TCP pert gun assembly, firing sub, RA sub. 04:30 - 06:00 1.50 PERF_ CMPPRF PU & TIH w/ 2-3/8" tubing work string. Jt 61 out of 301 jts in hole @ report time. 9/7/2003 06:00 - 13:00 7.00 PERF_ CMPPRF PU & TIH w/ 2-3/8" tubing work string (301 jts). 13:00 - 18:00 5.00 PERF_ CMPPRF R/U Schlumberger W/L. PJSM. RIH wl GR/RST tools. Log in hole w/ GR to RA tag. Found RA tag high @ 9186' WLM. Unable to correlate w/ GR. Ran RST log across. RA tag. Good correlation. Check pipe figures, joint count off. POOH w/ W/L. 18:00 - 18:30 0.50 PERF_ CMPPRF PU 12 joints 2-3/8" tubing, tag BP @ 9850' tubing strap. PU to 9832' tubing msmt. 18:30 - 22:00 3.50 PERF_ CMPPRF RIH w/ GR/RST tools. Ran RST log across RA tag, good correlation. Put guns on depth w/ bottom of guns @ 9808', top shot @ 9624'. POOH w/ W/L. RD loggers. 22:00 - 22:30 0.50 PERF_ CMPPRF RU & drop firing bar. TCP pert guns fired @ 22:23 hrs, 9/6/2003. Perfed following Beluga intervals: 9624'-9626', 9676'-9678', --- , - 9696'-9698', 9730'-9732', & 9806' - 9808. 22:30 - 01:00 2.50 CIRC_ MUD_ CMPPRF RU & circulate B/U. 01:00 - 01:30 0.50 PULD_ DP_ CMPPRF POOH, LD 12 joints 2-3/8" tubing. 01:30 - 06:00 4.50 TRIP BHA_ CMPPRF POOH, stand back tubing. 9/8/2003 06:00 - 07:30 1.50 TRIP_ BHA_ CMPPRF FPOOH, stand back 2-3/8" tubing work string. 07:30 - 10:00 2.50 PULD_ BHA_ CMPPRF PJSM. LD spent TCP guns. All shots fired. 10:00 - 10:30 0.50 PULD EQIP CMPRUN Pull wearbushing. 10:30 - 19:00 8.50 PULD_ DP_ CMPRUN MU & RIH w/ 2-3/8" completion equipment & tubing string. Ran 126 jts, 3896.95', 2-3/8", 4.7 ppf, L-80, 8RD plus 173 jts, 5266.10', 2-3/8", 4.7 ppf, J-55, 8RD tubing plus space out pup jts wi W/L re-entry guide @ 9300', BX nipple @ 9233' & chemical injection mandrel @ 1570' w/ control line to surface. MU tubing hanger w/ BPV & landing joint, land tubing. (Original text showed the BX nipple @ 9238' and the injection mandrel at 1512', however, the running tally and wellbore schematic refer to Printed: 6/27/2007 1:41:10 PM Marathon OiF Company Page 9 of 11 Operations Summary Report .Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: WORKOVER Start: 7/15/2003 End: 11/2/2003 Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code I Phase Description of Operations 9/8/2003 10:30 - 19:00 8.50 PULD_ DP_ CMPRUN 9233' and 1570'. So text was changed.) 19:00 - 03:00 8.00 NUND DBOP CMPRUN ND BOPE. Set out stack in carrier. 03:00 - 05:00 2.00 NUND UTRE CMPRUN NU 2" 10M psi dual master valve, single wing w/ swab valve production tree. 05:00 - 06:00 1.00 TEST_ EQIP CMPRUN Pull BPV, install TWC. Test void & hanger neck to 10,000 psi. 9/9/2003 06:00 - 09:00 3.00 TEST_ EQIP CMPRUN Repack hanger neck. Test void & hanger neck to 10,000 psi, ok. Attempt to test tree. Pull TWC & reinstal{. Test tree to 250 psi low/10,000 psi high, ok. Pull TWC, install BPV. Secure well. 09:00 - 10:00 1.00 RURD_ RIG_ RDMO RD rig floor. Remove all subs & drilling tools f/ rig floor. 10:00 - 11:00 1.00 RURD_ RIG_ RDMO Load out BOP stack. 11:00 - 00:00 13.00 RURD_ RIG_ RDMO Continue RD floor. Strip & LD T/D, LD torque tube. Load out rental T/D. RD lights for crane work, unplug electrical. Crane off dog house, choke house, stairs, windwalls, floor plates & landings. Tie up hoses & service lines. Load out water tanks. 00:00 - 06:00 6.00 RURD_ RIG_ RDMO PJSM. RU carrier & derrick lights. Pull derrick cylinder skins, 3 x 12's out of derrick, choke chute. Move rig controls to carrier. RU .floor hydraulics. Remove carrier tarp. Prep doghouses. Remove beaver slide, panic line, outriggers. Release rig to CLU #1 RD @ 06:00 hrs, 9/9/2003. 9/13/2003 08:00 - 10:10 2.17 RURD_ EOIP CMPSTM RU hard lines from the BJ N2 unit to back side of well. Discussed environmental and safety issues. Reviewed the procedure prior to PT hard lines. PT lines to 3000 psig. 10:10 - 10:20 0.17 TEST_ EQIP CMPSTM PT lines good, start displacing N2 to back side of well. Returns to tank. Pump N2 at 1300 SCFM, presure = 900 psig 10:20 - 10:22 0.03 PUMP_ N2_ CMPSTM Increase rate to 2000 SCFM, pressure 1975 psig. Returns good to tank 10:22 - 12:50 2.47 PUMP - N2_ CMPSTM Monitor retuns to tank. Total recovered to tank is 397 BBLS. Shut down N2 12:50 - 13:00 0.17 PUMP_ N2_ CMPSTM Final pump pressure 3200 psig. Total of 350, 000 SCF pumped Left 2500 psig on the well 13:00 - 13:15 0.25- RURD_ EOIP CMPSTM RD N2 pumping unit. Monitor well's pressure no change still 2600 psig on the tree. 10/8/2003 08:00 - 17:00 9.00 RURD_ EQIP CMPSTM Lay liner for frac tanks. MIRU four 500-bbl frac tanks and install frac manifold. Test frac manifold. Ml 1900 bbl of diesel from KGF (leftover from frac of KBU 43-7x). RU scaffolding around wellhead. 10/27/2003 08:00 - 17:00 9.00 RURD_ EOIP CMPSTM MIRU BJ fracturing iron and Halliburton flowback iron. 10/29/2003 07:00 - 12:30 5.50 TEST_ EOIP CMPSTM Conduct prejob safety meeting and operations discussion. Pressure test frac lines to 9400 psi. Test Halliburton seperator to 1200 psi and Marathon sand buster to 4000 psi. Test line to annulus to 7000 psi. Pressure up 9-5/8" x 7"annulus to 3000 psi. 12:30 - 14:00 1.50 PUMP_ FRAC CMPSTM SITP = 2470 psi. Begin frac stimulation by pumping 3/3 SuperRheogel frac fluid down 7" x 2-3/8" annulus at 10 bpm. Simultaneously loading the deadstring with straight diesel at 1.5 bpm. Cease loading the deadstring after pumping 40 bbl. Continue pumping gel via annulus at 10 bpm until confirmed that pens are broken down. No difficulty at all breaking down perfs. Increase rate to 35 bpm, deadstring = 4900 psi. Begin staging proppant (16/30 Ottawa sand} at 2-6 ppg according to schedule. Blender having difficulty achieving 6 ppg because sand is wet in the Sand King. Reduce rate to 20 bpm, but blender still unable to keep up. Cut to flush early because unable to get sand out of the Sand King. Increased rate to 35 bpm during flush. Placed 51,500 Ibs Printed: 6/27/2007 1:41:10 PM • • - Marathon Oil. Company Operations Summary Report Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Event Name: WORKOVER Start: 7/15/2003 Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Sub Code 10/29/2003 12:30 - 14:00 1.50 PUMP FRAC 14:00 - 18:00 4.00 RURD_ EOIP 18:00 - 22:00 4.00 FLOW BACK 22:00 - 03:00 ~ 5.00 E PUMP, N2_ 03:00 - 05:20 2.33 FLOW BACK 05:20 - 06:00 0.67 WAITON EOIP 10/30/2003 06:00 - 08:30 2.50 WAITON EQIP 08:30 - 15:30 7.00 FLOW BACK 15:30 - 06:00 14.50 FLOW_ BACK 10/31/2003 06:00 - 09:00 3.00 SECUR WELL 'i 09:00 - 11:00 2.00 PUMP_ N2_ 11:00 - 13:30 2.50 FLOW BACK 13:30 - 06:00 16.50 SECUR WELL 11/3/2003 07:00 - 10:15 3.25 RURD_ SLIK 10:15 - 13:00 2.75 TAG BOTM 13:00 - 14:00 ~ 1:00 I TAG ~ BOTM 14:00 - 15:00 1.00 TAG_ BOTM 15:00 - 19:30 4.50 RUNPU SLIK 19:30 - 20:30 1.00 RURD_ SLIK 11/4/2003 14:00 - 14:40 0.67 FLOW_ 14:40 - 15:05 0.42 FLOW 15:05 - 15:10 0.08 FLOW 15:10 - 15:12 0.03 FLOW_ 15:12 - 15:14 0.03 FLOW_ 15:14 - 15:15 0.02 FLOW 15:15 - 15:30 0:25 FLOW Page 10 of 11 Spud Date: 9/1/1998 End: 11 /2/2003 Group: Description of Operations Phase CMPSTM of proppant (64% of design) in 753 bbl of gelled fluid. Reduced rate to 6 bpm for final portion of flush to the bottom pert (i.e. overflush of 14 bbl from the top perf). ISIP = 4613 psi via deadstring, 5 min = 4497 psi, 10 min = 4433 psi, 15 min = 4325 psi. Load to recover = 1172 bbl. CMPSTM RDMO frac iron with well shut in. CMPFLW Open well for flowback. SITP = 3050 psi on 2-3/8" tubing. Recovered 42 bbl of diesel before well died. CMPFLW MIRU nitrogen unit on 7" annulus. Test lines to 3500 psi, conduct prejob safety meeting. Pump nitrogen down annulus while taking returns on the tubing string. Pumped 4000 gal of nitrogen and acheived maximum pressure of 2615 psi before nitrogen turned the corner. RD nitrogen unit. CMPFLW Continue to unload well. Get nitrogen to the surface shortly after ceasing to pump nitrogen. Total recovery = 331 bbl. CMPFLW Well shut-in due to surface equipment malfunction. Air compressor supplying gas to SSV ran out of fuel, causing the well to ESD. STandby for fuel CMPFLW Well remains shut-in waiting on fuel for air compressor. CMPFLW Open well to flow. SITP = 1500 psi. Well blowing nitrogen only, not. lifting much in the way of fluid. Pressure dropping steadily. CMPFLW Shut in well. SITP = 20 psi. Total recovery = 338 bbl. CMPFLW Well shut in. CMPFLW MIRU nitrogen unit on annulus. Annulus = 650 psi, tubing = 230 psi. Conduct prejob safety and operations meeting. Test nitrogen lines to 3500 psi. Circulate nitrogen down annulus. Achieve maximum annulus pressure of 1075 psi after pumping 800 gallons of nitrogen before nitrogen turned the corner. RD nitrogen. CMPFLW Flow well to flowback tank. Lifted an incremental 25 bbl of diesel off the formation. Tubing pressure dropping along with annulus pressure, so it appears that we're simply blowing nitrogen around the tubing without lifting any fluids. No positive indication of feed-in from the formation. CMPFLW Shut in well. Total recovery = 364 bbl. SITP = 30 psi, annulus = 490 psi. CMPFLW MIRU slickline. Pre job safety meeting, test lubricator. CMPFLW RIH with 1"drivedown bailer and tubing-end locator. Tag fill at 9771'. POOH, hanging up frequently. OOH, trigger on tubing-end locator is missing. No sample from bailer. CMPFLW RIH with 1.5" drivedown bailer to 9771'. Work bailer, POOH. Good sample of mud-like material. Bagged and labeled sample for company man. CMPFLW RIH with tubing-end locator to 9400'. Locate EOT at 9317', which correlates to tagging fill at 9788' MD. POOH. CMPFLW RIH with tandem pressure gauges with. depth encoder to 9760'. Made 3-minute stops at 30', 5000', 9000', 9300', 9500', 9600', 9700', and 9760' while RIH. POOH, download gauges. CMPFLW RDMO slickline. Well remains shut in. CMPFLW Crew Arrives on Location, Held Safety Meeting CMPFLW Open well, to inlet valve on Heater CMPFLW Open well, bypass separator to tank CMPFLW Continue Flowing Well on Bypass to Tank CMPFLW Increase choke to 24/ 64ths CMPFLW Held Safety Huddle CMPFLW Fluid to Surface Printed: 6/27/2007 1'41:10 PM • ~ Marathon Qii Company Page 11 of 11 Operations Summary Report ,Legal Well Name: STERLING UNIT 41-15 Common Well Name: STERLING UNIT 41-15 Spud Date: 9/1/1998 Event Name: WORKOVER Start: 7/15/2003 End: 11/2/2003 Contractor Name: GLACIER DRILLING Rig Release: 9/9/2003 Group: Rig Name: GLACIER DRILLING Rig Number: 1 i Date From - To Hours I Code Code Phase Description of Operations 11/4/2003 15:30 - 16:00 0.50 FLOW_ CMPFLW Continue Flowing Well on Bypass to Tank -Gas only 16:00 - 16:10 0.17 FLOW CMPFLW Shut in well at inlet valve due to freezing 16:10 - 16:30 0.33 FLOW CMPFLW Start up Heater to bring up to temp 16:30 - 17:00 0.50 FLOW_ CMPFLW Shut in, monitor temp on Heater 17:00 - 17:30 0.50 FLOW_ CMPFLW Continue monitoring temperature on Heater 17:30 - 18:00 0.50 FLOW CMPFLW Continue monitoring temperature on Heater 18:00 - 18:30 0.50 FLOW CMPFLW Open inlet to separator on 16/ 64ths, drop 1.25 orifice plat 18:30 - 19:00 0.50 FLOW CMPFLW Continue Flowing Well 19:00 - 19:15 0.25 FLOW CMPFLW Continue Flowing Well 19:30 - 19:40 0.17 FLOW_ CMPFLW Held Safety Huddle Continue Flowing Well 19:40 - 20:00 0.33 FLOW_ CMPFLW Increase choke to 18/ 64ths 20:00 - 20:30 0.50 FLOW CMPFLW Continue Flowing Well 20:30 - 21:00 0.50 FLOW CMPFLW Continue Flowing Well 21:00 - 21:30 0.50 FLOW CMPFLW Continue Flowing Well 21:30 - 22:00 0.50 FLOW CMPFLW Continue Flowing Well 22:00 - 22:30 0.50 FLOW_ CMPFLW Raise orifice plate and decrease separator pressure to 400ps 22:30 - 22:46 0.27 FLOW CMPFLW Continue Flowing Well 22:46 - 22:50 0.07 FLOW CMPFLW Increase choke to 20/ 64ths 22:50 - 23:00 0.17 FLOW CMPFLW Increase choke to 30/ 64ths and decrease separator pressure 23:00 - 23:30 0.50 FLOW CMPFLW Mike Lintner Continue Flowing Well Henry McMeekin Total Hrs. 228 Continue Flowing Weli Printed: 6/2712007 1:41:10 PM j C'or MP OC OD M C O 7h OOO ~~n-, OO (Y CO Ci OG P O~ OO rl~ f~N l~>C; .~r 01~ Mf tO eN- r tti ryb NN NM f~fJ W N fd Oi m00 Vt~i P'1O lJQ wdN r OI'~ m O fde= MrN M r tp lO~, r~N pN'/~ C~ +V ro 7M, oo IA(V 0f+j V~0 ~l7 0R1 rO r6D ~r0 ~~ 00 ~O r{~ M9 G~ ~~ Ot n fr a'NV; r ~9 rO ~~ lJ += n 41 ~® ~ .= a'1V 0.- OMi,O r.- .N-W r C1 mn .-O O.n~- rr IO PMC. 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Box 1949 Kenai, AK 99611 Telephone 907/283·1326 Fax 907/283-1350 July 3, 2007 RECEIVED ,JUL 0 Ii 2007 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W ih Ave Anchorage, Alaska 99501 Alaska Oil & Gas Cons. Commission Anchoraglil Reference: 10-404 Sundry Report 304-021 Field: Sterling Unit Well: SU 41-15 SCANNED AUG 282007 \q~JOLf Dear Mr. Maunder: Enclosed please find the Report of Sundry Well Operations~4g..-1Q~'("i)t8'Hng Unit 41-15 well. This report covers the perforation addition work completed during January through July of 2004. Also attached, for your records, is the Operations Summary and a Current well bore diagram. If you have any questions or require further information, please contact me at (907) 283- 1333. We are making every attempt to find and closeout pending sundry notices. Please notify us of any other pending sundry reports. ~ ~. Dennis Donovan Jr Production Engineer I Enclosures: 10-404 Sundry Well Schematic Operations Summary cc: AOGCC Houston Well File Kenai Well File DMD KJS · STATE OF ALASKA . ~;ZRECE!VED ALAS~OIL AND GAS CONSERVATION COMMI ON - JUL 0 6 2007 REPORT OF SUNDRY WELL OPERATIONS Alaska Oil & Gas Cons, Commission 1. Operations Abandon U RepairWell U Plug Perforations U Stimulate U OtherTI AI1ChQrage Performed: Alter Casing D Pull Tubing D Perforate New Pool D WaiverD Time Extension D Added Change Approved Program D Operat. Shutdown D Perforate 0 Re-enter Suspended Well D Peñorations 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Marathon Oil Company Development 0 Exploratory D 198-041 - 3. Address: Stratigraphic D Service D 6. API Number: PO Box 1949, Kenai Alaska, 99611-1949 50-133-20484-00-00..-- 7. KB Elevation (ft): 9. Well Name and Number: 30' KB (AGL) 254 SU 41-15 /' 8. Property Designation: 10. Field/Pool(s): Sterlina Unit Sterlina Field / Beluaa Pool - 11. Present Well Condition Summary: Total Depth measured 12600' ,¡' feet Plugs (measured) 9,850' true vertical 10,559' feet Junk (measured) N/A Effective Depth measured 9,850' feet true vertical 8,198' feet Casing Length Size MD TVD Burst Collapse Structural 58' 20" 58' 58' 2110 520 Conductor 0 0 0 0 0 0 Surface 2,241' 13-3/8" 2,271' 2,270' 3090 1540 Intermediate 10,282' 9-5/8" 10,312' 8,544' 6870 4750 Production 0 0 0 0 0 0 Liner 2,482' 7" 12,590' 10,550' 8160 7020 Perforation depth: Measured depth: 9,440'-9,808' True Vertical depth: 7,904'-8,167' Tubing: (size, grade, and measured depth) 7",29# 1 2-3/8",6.5# P-110 1 L-80 8,256' 1 9,300' Packers and SSSV (type and measured depth) 7" X 9-5/8" Baker SAB permanent packer and 7" X 9-5/8" anchor and Packer @ 8,198', Anchor @ 8,196' 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A RBDMS BFl AUG 2 7 2007 Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data *approx. values due to spot production) Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 * Approx 455 0 0 *Approx615 Subsequent to operation: 0 * Approx 300-400 0 0 * Approx 600 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run No Logs/Surveys Run Exploratory D Development 0 Service D Daily Report of Well Operations Included 16. Well Status after work: Oil D Gas 0 WAG D GINJ DWINJ D WDSPL D 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ISUndry Number or N/A ifC.O. Exempt: 304-021 Contact Kevin Skiba (907) 283-1371 Printed Name J Dennis M Donovan Title Production Engineer I /\ -A ß .Tìl- (907)-283-1333 W Signature /7 X.Vi Phone (907)-398-1362 C Date 29-Jun-07 -....... -) "'-.) Form 1 0-404 Revised 04/2006 () R t G 1 N A , (q. c:¡;- J:7- \. Submit Original Only J API: 50-133-20484 AOGCC: 98-41 KB-GL: 29.71' (original KB) 437' FEL, 2327' FSL Sec. 9, T5N, R10W, S.M. 4.75" Otis tree cap Lift threads - 3.161" MCA Equipped with 10K wellhead and 4", 10K valves for frac stimulation via 2- 3/8" x 7" annulus. Active Perfs (BeluQa Sand) 9440' - 9450' 6/04 ,9516' - 9526' 6/04 9558' 9536' 6/04 , 9576' - 9584' 6/04 9616' - 9640' 6/04 9624' - 9626' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 ~ 9674' - 9682' 6/04 9676' - 9678' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 9694' - 9704' 6/04 9696' - 9698' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 9722' 9736' 3/04 9730' - 9732' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 9806' - 9808' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 Previous BeluQa Perfs (assumed plugged off during workover) 9440'-9450' 9616'-9640' 9674'-9682' 9694'-9704' 9722'-9736' 9800'-9812' SU 41 5 SU 41-15 Kenai Peninsula State/Provo Well Name & Number: County or Parish: Perforations: (MD) Date Completed: Prepared By: 09/09/03 Dennis Donovan l 13-3/8",61 ppf, K-55, BTCsurface casing @ 2271' Cmt with 1186 sks of class G 7" TubinQ StrinQ - 7", 26 ppf, P-11 0, BTC·M tubing Baker KC1 tubing anchor at 8196' Baker SAB 194-73 permanent packer @8198' Re-entry guide @ 8256' 2-3/8" TubinQ StrinQ 2-3/8",4.6 ppf, L-80 & J-55, EUE 8rd to 9300' 4' of carbide blast rings immediately below tubing hanger Baker chemical injection nipple @ 1570' w/ 1/4" control line to surface X-nipple @ 9233' ID = 1.875" Re-entry guide @ 9300' Tagged fill at 9,788' IBP at9850' (9/3/03) ement plug 9872' - 10,055' 9-5/8", BTC casing @ 10,312' 0' - 3083',53.5 ppf, P-110 3083' - 9866',47 ppf, P-110 9866' - 10,312', 47 ppf, L-80 Cmt with 2284 sks of class G 7" ZXP liner-top packer @ 10,108' 7",29 ppf, L-80, BTC liner @ 10,108' -12,590' Cmt with 708 sks of class G Per AOGCC 304-021 (10-401() Last Revision Date: ~ ~f"L YO- -N Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 1/30/2004 1/31/2004 3/22/2004 3/25/2004 ;:\!;:.3{')'-\- - 02...\ Page 1 of 3 Marathon Oil Company Operations Summary Report STERLING UNIT 41-15 STERLING UNIT 41-15 WORKOVER GLACIER DRILLING GLACIER DRILLING I Sub I From - To Hours Code Code 06:00 - 08:00 I 108:00 - 09:00 109:00 - 10:00 1 , 110:00 - 12:00 , , 106:00 - 08:30 I 108:30 - 10:30 110:30 - 11 :30 I ¡ 11:30 - 12:00 112.00 - 13.00 ¡ 13.00 - 14.00 i 14:00 - 15:00 115:00 -17:00 117:00 - 17:30 ! ¡ 17:30 - 18:30 ! 06:00 - 08:00 108:00 - 08:30 108:30 - 10:00 110:00 - 11 :30 I ! 11 :30 - 13:30 , 1'13:30 - 14:30 14:30 - 16:30 I I I [16:30 -18:00 I 06:00 - 08:00 ,08.00 - 08.30 I 108:30 - 10:30 I I i 10:30 - 12:30 I I 112:30 - 13:00 , 2.001 RURD_, ELEC I I 1.001 RURD_¡iELEC 1.00 I RURD I ELEC ! -I I 1 2.00 i RURD_I ELEC I , I I 2.501 RURD_IELEC i I 2.001 RURD_iRURD 1.001 PULD_lpGUN 0.501 TRIP -ITOOL 1.00/ TRIP I TOOL -I I . , I 1.001 FLOW-iCHEK 1.001 TRIP !TOOL I -I 2.00 I TRIP _ ¡ TOOL 0.50 I TRIP _ I TOOL I 1 1.001 RURD_IWLNC I I 2.001 RURD_IELEC 0.50 I SAFETY! MTG 1.50 'I' RURD I ELEë -I 1.50 I TRIP _ 1 TOOL , I 2.00 I TRIP _ I TOOL ! ~ 1.001 TRIP _ ¡TOOL 2.001 TRIP _ ¡TOOL I ! I I 1.50 I RURD -1 ELEe 2.001 RURD_1ELEC 0.501 SAFETY¡MTG_ I I 2.00 RURD_IELEC ) 2.001 PULD_lpGUN 0.50 SAFETYIMTG_ ¡ I ¡ i I , CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF CMPPRF Start: 1/30/2004 Rig Release: 9/9/2003 Rig Number: 1 Spud Date: 9/1/1998 End: Group: Description of Operations Standby. Meet Expro on location @ 0800. Spot Expro equipment. Attempt to start test unit. Would not start. Continue attempts to start diesel en9ine. Would not start. Note: Extreme cold: -26 F on location. Shut down operations. Move Expro unit off location. Return tomorrow AM. Wait on Expro ElL. Planned arrival at 0830. SITP = 1875 psi. MIRU Expro ElL equipment. MU lubricator. RU 1-11/16' X 14' perf gunlmag centlGRlCCL!WT bar. MU lubricator and test. Attempt to RIH. Not enough weight. Break lubricator and add extra wt. MU lubricator. Attempt to RIH. Setting down at 130' in slushnce. Pump methanol through tree/tbg with Expro test unit. Still set down at 130'. Flow well to remove ice plug while injecting methanol through DH chem injection mandrel. Stabilze well flow rate. RIH. Tag at 9745' (uncorrected). Tie-in and make depth correction. Attempt to re-enter tbg tail prior to perforating. Could not enter tbg tail. Attempt to work unfired guns into tbg tail at varied line overpulls. Work unfired guns back into tbg after approximately 2 hrs. POOH with live guns. Inspect tool string for signs wear. Rope socket showed small signs of wear. RD Expro. Note: Need to determine cause of tailpipe entry problem and determine new plan forward. Arrive at Gas field Travel to Sterling Pad wait on Expro to arrive. Held prejob safety meeting Spot Wireline and RU same. Test lubricator wi Methanol to 3000 psig. RI H with following tool string: rope socket, knuckle jt. ,15' weight stem, oil jars, spang jars, 3' weight stem, 1.750Ø gauge. TIH with gauge run to 9342' slm, ran out of tubing string and picked up back into tubing two times without problems, proceed on to 9742' slm. POOH with gauge ring. SITP 900 psig. RU the following assembly: rope socket, knuckle jt. 10' weight stem, oil jars, spang jars, knuckle jt. 25' aluminum Dummy. TIH to 9342' slm, ran out of tubing string and picked up back into tubing two times w/o any problems. TIH to 9750' slm. POOH no drag. Secure well, laydown tool string, RD lubricator and wireline unit. Travel to gas field. Travel to Sterling Gas field. Wait on Expro to arrive to begin well work Expro Arrived on location, filled out work permit, conducted safety briefing. Begin rigging up wireline, make up the following tool string: rope socket 14' sinker bars, knuckle jt, gamma gun. 14' 1 11/16" 6 SPF 0 phasing hollow carrier gun. Attempt to stab lubricator, line crossed on boom truck. Attempt to lay down luþricator. operator forgot to set drum brake spool with 5/16" line began to backlish. Layed down lubricator, de-arm perforating gun, begin to slip and cut +1-1000' of bad line. Shut down operations. held 2nd safety meeting to discuss previous Printed: 6/2712007 1 :44:14 PM -.' . . Marathon Oil Company Operations Summary Report Page 2 of 3 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date From - To STERLING UNIT 41-15 STERLING UNIT 41-15 WORKOVER GLACIER DRILLING GLACIER DRILLING Sub Hours Code Code Start: 1/30/2004 Rig Release: 9/9/2003 Rig Number: 1 Spud Date: 9/1/1998 End: Group: Phase Description of Operations 3/25/2004 12:30 - 13:00 13:00 - 14:00 0.50 SAFETY MTG_ CMPPRF events. 1.00 PUlD _ PGUN CMPPRF Rehead line make-up perforating assembly, arm gun. Pick up and stab lubricator. Test with Methanol to 3000 psi. 3.00 PERF _ TBG_ CMPPRF TIH with gun assembly to 9745' elm. run corroration log to 9200' elm. make depth correction, TIH to 9740', pull up so top shot is located 9722'. Perforate 9722'-9736' elm. 1.00 PULD_ PGUN CMPPRF POOH;ith wireline, wireling packoffbegan to leak grease from injection hose. Had minor amount fall on top of well house. Secure well, bleed-off lubricator and verify guns had fired. All shots had fired. 1.50 RURD_ ELEC CMPPRF RD wireline, put well into production. 2.25 RURD_ ELEC CMPPRF MI RU Expro E-line unit. Held PJSM discussed potential problems and environmental issues. Well shut in since yesturday. WHP= 1450 psig. o MCFD. MU tools string with 1 11/16* ,6 SPF, 0 degree phase, 3.5 gram NTX charges. Tool string consist of:R-socket, sinker bar, k-joint, . 2 ea. sinker bars, k-joint, CCl, X-over, & gun.. 14:00 - 17:00 17:00 - 18:00 6/29/2004 18:00 - 19:30 07:00 - 09:15 09:15 -10:15 1.00 PULD_ PGUN CMPPRF RIH with Run #1, (10') to re- perforate from 9, 694 - 9, 704'. PTwith WHP. WHP= 1450 psig & IA pressure = 1650 psig. No leaks. Open well, Maintaining Methanol injection while running in well. 10:15 - 12:00 1.75 PERF_ TBG_ CMPPRF Correlate CCL to tie-in log dated 3-25-2004, which was correlated to Schlumberger CBL log dated 8-31-2003. Made tie-in log to get gun on depth. On depth with gun #1, re-perforate from 9, 694' - 9, 704', fired .- gun. No indication gun fired. POOH with gun. WHP= 1490 psig. (+40 psi). Continue OOH logging up first few collars. 12:00 - 12:10 0.17 TRIP_ TOOL CMPPRF Slowed down when at the x-nipple @ 9, 233'. No problems entering the tubing or X-nipple. 12:10 - 13:00 0.83 PULD_ PGUN CMPPRF OOH with gun, BID lubricator. Layed down gun. While laying down the gun, wire was kinked in sheave. Will have to cut the wire and re-head rope socket prior to continuing to perforate. All shots fired. 13:00 - 14:20 1.33 PULD_ PGUN CMPPRF 14:20 - 16:18 1.97 PERF_ TBG_ CMPPRF 16:18 - 17:10 0.87 PULD - PGUN CMPPRF 17:10 - 18:30 1.33 TRIP_ TOOL CMPPRF 18:30 - 22:00 3.50 SECURE WELL CMPPRF 09:37 - 14:15 I 4.63 RURD_ OTHR CMPPRF Finished with re-heading rope socket. Make up firing head to gun#2. PU 8' gun and lubricator. PT lubricator with WHP. WHP= 1590 psig. RIH to 9740', correlate to get on depth to r~perforate from 9674' - 9682' (8') ELM. Fired gun .- while monitoir WHP, WHP- 1590 psig. No change POOH with #2 gun. OOH with gun #2, all shots fired. Lay down gun, pickup gun #3. PT lubricator with WHP. WHP= 1650 psig. No leaks. RIH with run #3, (8') perforate from 9576' - 9584' ELM. Get on depth - correlate to perf interval. WHP= 1650 psig, IA- 1900 psig. No change in pressure POOH with gun. OOH with gun. All shots fired. Layed down gun, secure well. Hydraluic hose blew apart at the threaded fitting on boom truck had to call in a spill. Was able to reconnect the hydralic hose and lay down boom on truck. Did not flow well, left well shut in because of potential hydrates forming in well while producing. 6/3012004 Left lease. MI RU a rental boom truck to replace the one with hydraulic line problem. Continue with rigging up lubricator to new truck & picking up lubricator from yesturday. Discussed safety and environmental concerns. Held PJSM. Moved in rental boom truck. Rigging up boom was not long enough shut down while operator went to shop to get a boom extension for boom. Arrived with boom extension. Rigged up no Printed: 612712007 1:44:14 PM · . Marathon Oil Company Page 3 of 3 Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date From - To STERLING UNIT 41-15 STERLING UNIT 41-15 WORKOVER GLACIER DRILLING GLACIER DRILLING H C Sub ours ode Code Start: 1/30/2004 Rig Release: 9/9/2003 Rig Number: 1 Spud Date: 9/1/1998 End: Group: Phase I Description of Operations 6/30/2004 09:37 - 14:15 14:15 - 18:30 4.63 RURD_ OTHR CMPPRF place to hang sheave from extension. 4.25 RURD _ OTHR CMPPRF Hydralulic hose blew again while mechanic working on the boom truck. No way to hang sheave on rental boom. Decided to shut down for day and get another boom truck or fix the original boom truck and rig up tomorrow. Decided to bring bob cat in to clean up both hydraulic oil spills today be ready for tomorrow rig up. WHP= 2200 psig. Left lease. 7/112004 07:00 - 08:15 1.25 RURD_ ELEC CMPPRF Continue with RU to perforate. Held PJSM discussed potential problems and environmental issues. Secured work permit, MU tools string with 1 11/16" , 6 SPF, 0 degree phase, 3.5 gram NTX charges. Tool string consist of:R-socket, sinker bar. k-joint, 2 ea. sinker bars, k-joint, CCL, X-over, & gun. 08:15 - 09:40 1.42 PULD - PGUN CMPPRF MU 24' gun, Go to communication black out on pad prior to arming gun. PU stab on lubricator. PT lub with WHP. WHP= 2050 psig,IA'" 2350 psig. No leaks. ~IH with run #4, perforate from 9616' - 9640' ELM, - (24'). 09:40 -10:50 1.17 PERF_ TBG_ CMPPRF Correlate to CBL, pull gun into reperf depth fired gun. POOH with gun. No change in pressure at surface. WHP= 2050 psig. 10:50 -11:55 1.08 PULD_ PGUN CMPPRF OOH with gun. BID lubricator lay down 24' gun. All shots fired. Water in gun carrier when layed down fired gun. MU 5' gun. PU . lubricator, stab on well. PT lubricator with WHP. WHP= 2050 psig. 11:55 -13:30 1.58 PERF_ TBG_ CMPPRF RIH with 5' gun to perforate from 9558' - 9563' (5'), run #5. Correlate will to perforate the 5' zone. Perforate while watching well head pressure, no change in pressure POOH with gun. 13:30 - 14:30 1.00 TRIP_ TOOL CMPPRF OOH with gun, no change in WHP. Some water in fired gun. MU gun#6. 14:30 -15:00 0.50 PULD_ PGUN CMPPRF Pickup gun and stab on lubricator. Pressure up on lubricator with well head pressure. WHP= 2050 psig. RIH with run #6, to perforate from a516 - 9526' (10').- 15:00 - 15:40 0.67 PERF_ TBG_ CMPPRF Correlate gun#6 to perf depth, perforate. POOH with gun. WHP= 2050 psig. fA= 2300 psig. 15:40 - 16:43 1.05 TRIP_ TOOL CMPPRF OOH with gun #6, BID lubricator. Lay down gun. All shots fired. MU gun#7, 10'. 16:43 - 17:20 0.62 PULD_ PGUN CMPPRF PU lubricator, stab on well. PT lubricator with WHP. WHP= 2050 psig. RIH with gun #7, to re -perforate from 9440 - 9450', (10'). - 17:20 - 18:35 1.25 PERF_ TBG_ CMPPRF Correlate gun #7 to reperforating depth at 9440 - 9450'. POOH with gun. WHP= 2100 psig. 18:35 - 22:30 3.92 RURD_ ELEC CMPPRF OOH with gun #7, all shots fired. WHP= 2100 psig. IA=2300 psig. Expro to RD equipment. Operator opening up well to production. Operator could not open control valve. will investage in AM. Expro left lease. Printed: 6/27/2007 1 :44:14 PM . . MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg K/117!<1!O( DATE: July 1, 2007 P. I. Supervisor FROM: Bob Noble, Petroleum Inspector SUBJECT: Cement Plug Tag & PT Sterling Unit41-15 Marathon PTD 198-041 Mav 14, 2007: I traveled to Marathon's SU 41-15 to witness a cement plug tag with drill pipe and pressure test. Marathon's Glacier Drilling rig was setting a whipstock to do a side track. Cement plug was placed on top of perf's at 9440'. I witnessed hard cement tagged @ 9242' with DP. Plug was tagged while circulating with no movement. 1 OK indicator weight was put on plug to verify plug's integrity. A 30 min.1 000 psi pressure test was performed on plug with no loss of pressure. Summary: Cement plug tag and PT on Marathon's SU 41-15 Attachments: None. Non Confidential 5GANNED JUL 2 0 2007 2007-0701 ]&A --'p1ug_tag_ SU _ 41-15 _bn.doc . ~1f~1fŒ (ID~ ~~~~æ~ . AI1A~JiA. OIL AlQ) GAS CONSERVATION COlWlISSION SARAH PALIN, GOVERNOR 333 W. 7th AVENUE. SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Will Tank Advanced Senior Drilling Engineer Marathon Oil Company PO Box 3128 Houston, TX 77253-3128 Re: Sterling Gas Field, Sterling Gas Pool, SU 41-15 Sundry Number: 307-204 \<\q¡.-OI.\'I 5Clt.:I\jNf.!) J U N 2 6 2007 Dear Mr. Tank: 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.''''''¿~;r' WhUe reviewing the Commission ffies with regard to this approval, it has been determined that Marathon OUCompany has not ffied Form 10-407 as required by Sundry Approval 303-215 dated August 4, 2003 nor Form 10- 404 as required by Sundry Approval 304-021 dated January 28, 2004. These work reports should be submitted to the Commission not later than July 6, 2007.. The Commission reserves the right to pursue an enforcement action regarding this matter. 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. erson may not appeal a Commission decision to Superior Court u ess 1: e 'ng has been requested. In J:j ly DATED this ~ay of June, 20071 Encl. rAtr (o.;2ffDJ ~ RECEIVED . STATE OF ALASKA . 6-/9.¿)7 ALASKA Oil AND GAS CONSERVATION COM~ION )..Cø(~) JUN 1 B Z007 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Operational shutdown D Plug Perforations D Perforate New Pool D 4. Current Well Class: Development 0 Stratigraphic D Abandon 0 Alter casing D Change approved program D 2. Operator Name: Suspend D Repair well D Pull Tubing 0 Alaska Oil & Gas Cons C }mm1SS11n Perforate D Waiver [)nchorage Other D Stimulate D Time Extension D Re-enter Suspended Well D 5. Permit to Drill Number: Exploratory D 98-41 ~ \ ~ ç; -O'-l \ Service D 6. API Number: 1. Type of Request: 3. Address: Marathon Oil Company 3201 C. Street, Suite 800, Anchorage, AK 99503 8. Well Name and Number: 50-133-20484-00 - 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line where ownership or landownership changes: Spacing Exception Required? Yes D 9. Property Designation: Sterling Unit 12. Packers and SSSV Type: 7" x 9 5/8" Baker SAB permanent packer and 7" x 9 5/8" anchor 13. Attachments: Description Summary of Proposal 0 Detailed Operations Program 0 BOP Sketch 0 15. Estimated Date for Commencing Operations: 17. Verbal Approval: Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Willard J. Tank Title Advanced Senior Drilling Engineer Total Depth MD (ft): 12,600 ./ Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Beluga - 9,440', Tyonek - 10,942' No 0 su 41-15 ,/ 10. KB Elevation (ft): 11. Field/Pool(s): (30' AGL) 254 Sterling Field I Sterling Unit Pool - PRESENT WELL CONDITION SUMMARY Effective Depth MD (ft): Effective Depth TVD (ft): Junk (measured): NIA Collapse 520 Total Depth TVD (ft): 10,559 / Length 58' Plugs (measured): 9,850 8,198 9,850 Burst Size MD 58' TVD 58' 2,110 20" 2,241' 10,282' 133/8" 9 5/8" 1,540 4,750 3,090 6,870 2,271' 1 0,312' 2,270' 8,544' 2,482' 7" Perforation Depth TVD (ft): 10,550' Tubing Grade: 8,160 7,020 Tubing MD (ft): 8,256' I 9,300' 12,590' Tubing Size: Beluga - 7,905', Tyonek - 9,054' 7",29# 123/8",6.5# P-110 I L-80 Packers and SSSV MD (ft): Packer @ 8,198', Anchor @ 8,196' 14. Well Class after proposed work: June 25,2007 Date: Exploratory D Development 16. Well Status after proposed work: Oil D Gas D WAG D GINJ D D D Service o D Abandoned WDSPL D D Plugged WINJ Signature ¿j?/¿ ~ f.-.,.. W J"'- Phone 713-296-3273 June 15, 2007 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: (q-) 7 - D2f)4 Plug Integrity ~ BOP Test jŠ.. Mechanical Integrity Test D Location Clearance D Ot~er: ßoQ~~~'t"-~~~-..,)~\ '\.~Ü,\~' c..o~\-(J.~~~~c.~\~~\~~~ ~\~~ ~~ d()OD~~\ ~'\)? ~"';;. \-- ..ç.(), 'ÑO"~\J<l'G~Q..r<J\-\Ö~~ ~"'-\/' Subsequent Form Required: '-\ C) ~ RBDMS 8fl JUN 2 {) 2007 Approv'" b~ _ ....-< ..t.r ~MISSIONER Form 10-403 Revised 06/2006 U "ï\ \ ....G.V n.... APPROVED BY THE COMMISSION ~-z~~ Date: .L- ~~mit in Duplicate . . Worldwide Drilling North America Marathon Oil Company P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713-499-6737 June 15, 2007 RECEIVED John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 JUN 1 8 Z007 Alaska Oil & Gas Cons. Commission Anchorage Reference: Approval to Plug and Abandon Field: Sterling Field Well: SU 41-15 Dear Mr. Norman Enclosed please find the APPLICATION FOR SUNDRY APPROVALS, along with the associated attachments for plugging and abandoning the current wellbore. It is our intention to submit an application shortly to sidetrack from this wellbore to a new bottom hole location. If you require further information, I can be reached at 713-296-3273 or bye-mail at wjtank@marathonoil.com. Sincerely, rl;<~ ç",- ~~ I Willard J. Tank Advanced Senior Drilling Engineer Enclosures SU 41-15 Abandonment Program . . Marathon Oil Company Alaska Originator: Will Tank Reviewed by: Pete Beraa Brian Rov 6/15/2007 MARATHON MARATHON OIL COMPANY ABANDONMENT PROCEDURE Sterling Field SU 41-15 June 15, 2007 Date (/;¿ &¡- (;, . /j-- ð ') Date Date , \ ~., t-'\.C,)., \ ATERIAL ~<'C <t 11-2 '1'fV1 c, f:> J Page 1 of 10 . . SU 41-15 Abandonment Program Marathon Oil Company Alaska 1. 1.1 1.2 1.3 1.4 1.5 2. 2.1.1. 2.1.2. 3. 4. 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.9.1. 4.9.2. 4.10 4.11 4.12 6/15/2007 TABLE OF CONTENTS Emergency Response Information.... .............................................................. ...................................... .......... 4 Directions to Location...................................................................................................................................... 4 " Rig Contact Numbers...................................................................................................................................... 4 Marathon Emergency Response Contacts .....................................................................................................4 Outside Emergency Response....................................................................................................................... 4 Marathon Contact List................................................................................................... .................................. 5 Regulatory Agency Contacts ..........................................................................................................................5 Internal Regulatory Contact............................................................................................................................ 5 External Regulatory Contact........................................................................................................................... 5 Regulatory Com pliance............. ...................................................................................................................... 5 Program Summary.......................................................................................................................................... 6 General Well Data........................................................................................................................................... 6 Working Interest Owners Information ............................................................................................................. 6 Surface Location Summary.............................................................................................................. ............... 6 Casing & Cement Summary............................................................................................................................ 7 Tubing Summary............................................................................................................................................. 7 Perforation Summary...................................................................................................................................... 7 Calculation of Maximum Anticipated Pressures (MAWP and MASP)............................................................. 8 Casing Test Pressure Calculations .................................................................................................................8 Blowout Prevention Equipment, Testing and General Procedures................................................................. 8 Function Testing....................................................................................................................... ....................... 9 Pressure Testing.......................................................................................... ................................................... 9 Wellhead Equipment Summary ..................................................................................................................... 9 Drilling Fluid Program Summary ..................................................................................................................... 9 Abandonment Program..................... ........................................................................................... ................. 10 Page 2 of 10 . . SU 41-15 Abandonment Program Marathon Oil Company Alaska Attachments Group Attachment Attached Commercial Information AFE nla DayslCost vs. Depth Curves nla Project Objectives and Scorecard nla RSO Codinq Information nla Requisitions nla Vendor List n/a Bonus Program nla Drilling Contract nla Regulatory I HES Information Emerqency Evacuation Plan nla H2S Continqency Plan n/a Requlatory Permits X Requlatory Rules and Regulations nla Risk Analysis nla Miscellaneous Proqrams (Vendors) Bit Proposal nla Cement Proposal nla Directional Plan nla Fluids Program nla Wellhead Equipment - Description/Drawings nla Drill Strinq and BHA Summary nla Riq Mobilization/Moorinq Procedure nla Geoloqicallnformation Location Map wi offsets nla Offset Data nla Proposed Formation Pore Pressure, Mud Wt & Fracture Gradient nla Temperature Curves nla Geologic Structure Maps . nla Geologic Cross Section nla Bathymetry Map nla Analysis Riser Analysis nla Station Keeping Analysis - Mooring/DP nla Stress Check Casing Design File nla Maximum Allowable Overpull nla Miscellaneous Information Well bore Diagram X Rig Elevations nla Well Location Diagram X BOP Schematic X BOP Well Control Bridging Document nla Detailed Casing Specifications nla Detailed Drill Pipe Specifications nla 6/15/2007 Page 3 of 10 . . Marathon Oil Company Alaska SU41-15 Abandonment Program 1. EmerQency Response Information 1.1 Directions to Location Method Directions Air Latitude - 60032'15.628"N Longitude - 151 °01 '51.465"W From the Kenai airport, go 0.4 mile South on North Willow Street. Turn East on Airport Way, go 0.5 miles. Turn East on Kenai Ground Spur Highway and go 7.8 miles. Turn East on Sports Lake Road and go 0.9 miles. Turn North on Conner Road and go 2.5 miles to Sterling pad 43-9. 1.2 RiQ Contact Numbers Contact Office Cell Glacier Drilling Rig 1 Inlet Drilling Tool Pusher 907-283-1314 907-394-1321 Marathon Supervisor 907-283-1312 907-394-1317 1.3 Marathon EmerQencv Response Contacts Individual Postion Main Phone Alternative Kenai Gas Field Emergency Number 907-283-6465 CERT 24 hrs Notification 1-800-MOC-CERT CERT Crisis Center Houston 713-296-4230 713-296-4237 1.4 Outside EmerQencv Response Locatiç>n Contact Phone Fire Kenai I Soldotna, Alaska 907-262-4792 Ambulance Hospital Kenai I Soldotna, Alaska Central Peninsula Hospital 907-262-4404 Kenai Police 907-283-7879 Police Kenai I Soldotna, Alaska Soldotna Police 907-262-4455 State Police 907-262-4453 Coast Guard 800-478-5555 Spill and Contamination Alaska Alaska State Spill Reporting National Response Center Oil I Toxic Chemical Spills 800-424-8802 Best Practices: 1 Policy: Post emergency notification information on rig floor, company man's and tool pushers' office Comments: 6/15/2007 Page 4 of 10 . . Marathon Oil Company Alaska SU 41-15 Abandonment Program 1.5 Marathon Contact List Contact Title Office Mobile Facsimile Home Will Tank Drilling Engineer 713-296-3273 713-203-8398 713-499-6737 832-934-2617 Pete Berga Drilling Superintendent 907-565-3032 907-529-0551 907-565-3076 907-346-3763 Bryan Roy Drilling Manager 713-296-3256 832-444-4772 713-499-6707 281-246-4686 Jennifer Enos Geologist 713-296-3319 713-408-3583 Moksh Dani Reservoir Engineer 713-296-3140 832-692-4700 Craig Rang Completion Engineer 907-283-1305 Ken Walsh Production Engineer 907-283-1311 907-394-3060 907-283-3050 John Nicholson Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313 Dan Byrd Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313 Mike Feketi Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313 Rowland Lawson Drilling Supervisor 907-283-1312 907-394-0953 907-283-1313 2. ReQulatorv AQencv Contacts 2.1.1. Internal Requlatorv Contact Office Phone 713-296-3254 Cell Phone 979-830-7927 Home Phone 979-836-9390 Facsimile 713-499-6748 Contact Chick Underwood 2.1.2. External Requlatorv Contact Contact Title I Office Phone Facsimile 24 hr Emergency PaQer AOGCC I 907-793-1236 BLM I 907-267-1442 3. ReQulatorv Compliance Regulation Requirement 20 AAC 25.035 e 10 A BOP testing interval requirement is now 14 days. 20 AAC 25.035 e 10 F Requirement for a 24 hour notice to AOGCC prior to BOP test. Comments: 6/15/2007 Page 5 of 10 . . Marathon Oil Company Alaska SU 41-15 Abandonment Program 4. Program Summary 4.1 General Well Data Well Name SU 41-15 Lease I License Surface Location 2,327' FSL, 437' FEL, Sec. 9, T5N, R10W, S.M. WBS Code DD.07.15067.CAP.DRL Slot/Pad Sterling Pad 43-9 Field Sterling Field Spud Date 06/29/07 (est.) KB (above MSL) 245' CountylProvince Kenai Peninsula API No. 50-133-20484 GL (above MSL) 224' State I Country Alaska Permit No. 98-41 Perm. Datum KB TD (MD) 12,600' TD(MD) 12,591 ' (Old KB 254') (Glacier KB 245') Rig Contractor Glacier Drilling PBTD (MD) 9,850' PBTD (MD) 9,841' (Old KB 254') (Glacier KB 245') Rig Name Glacier Rig 1 Best Practices: 1 Comments: 4.2 Workinq Interest Owners Information I Company Working Interest Address Phone Facsimile I Marathon 100% P.O. Box 196168 907-561-5311 907-565-3076 Anchorage, AK 99519-6168 4.3 Surface Location Summary Surface Location Coordinates - NAD 83 From Lease/Block Lines 2,327' FSL, 437' FEL, Sec. 9, T5N, R10W, S.M. Latitude 60° 32' 14.914" N Longitude 151°01'51.643"W UTM North (Y) 2,389,795.70' UTM East (x) 1,454,762.52' Tolerance 6/15/2007 CONFID~TERIAl Page 6 of 10 . . Marathon Oil Company Alaska SU 41-15 Abandonment Program 4.4 CasinQ & Cement Summary Casing MD (ft) TVD (ft) I I Cement Size (Old KB 254') (Old KB 254') Weight ID Drift Record (in) Top Bottom Top Bottom (Ibs/ft) Grade (in) (in) Burst Collapse (sacks) 20 0 58 0 58 K-55 Driven 13 3/8 0 2,271 0 2,270 61 K-55 12.515 12.359 3,090 1,540 1,186 95/8 0 3,038 0 3,079 53.5 P-110 8.535 8.500 . 10,900 7,930 95/8 3,038 9,866 3,079 8,209 47 P-110 8.681 8.525 9,440 5,310 2,284 95/8 9,866 10,312 8,209 8,544 47 L-80 8.681 8.525 6,870 4,750 7 10,108 12,590 8,387 10,550 29 L-80 6.184 6.059 8,160 7,020 708 Comments: Note that the 9 5/8",53.5#, P-11 0 casing is a special drift of 8.5", 4.5 TubinQ Summary Tubing Setting Depth Packer Set Size Weight MD MD (in) (Ib/ft) Grade Connection (ft) (ft) Comments Wireline entry guide @ 8,256', Baker SAB 194-73 permanent packer @ 7 26 P-110 BTC-M 8,256 8,198 8,198', and Baker KC1 tubing anchor @ 8,196'. 7" hung off in 11", 5M wellhead. 23/8 4.7 L-80 EUE 8rd 9,300 NIA BX nipple @ 9,233', Baker chemical injection nipple @ 1,570' (with 1J¡" control line), and 4' of carbide blast rings immediately below hanger. Comments: 4.6 Perforation Summary Previous Perfs Active Perfs (assumed plugged from workover) Isolated Perfs (Old KB 254') (Old KB 254') (Old KB 254') Top Bottom Top Bottom Top Bottom (ft) (ft) Zone (ft) (ft) Zone (ft) (ft) Zone 9,440 9,450 Beluga 9,440 9,450 Beluga 10,003 10,014 Beluga 9,516 9,526 Beluga 9,616 9,640 Beluga 10,017 10,026 Beluga 9,558 9,563 Beluga 9,674 9,682 Beluga 10,942 10,955 Tyonek 9,576 9,584 Beluga 9,694 9,704 Beluga 11,034 11,044 Tyonek 9,616 9,640 Beluga 9,722 9,736 Beluga 11,121 11,136 Tyonek 9,624 9,626 Beluga 9,800 9,812 Beluga 11,290 11,296 Tyonek 9,674 9,682 Beluga 11,305 11,316 Tyonek 9,676 9,678 Beluga 11,322 11,331 Tyonek 9,696 9,698 Beluga 9,694 9,704 Beluga 9,722 9,736 Beluga 9,806 9,808 Beluga Comments: See wellbore diagram for more detailed information. 6/15/2007 Page 7 of 10 . . Marathon Oil Company Alaska SU 41-15 Abandonment Program 4.7 Calculation of Maximum Anticipated Pressures (MAWP and MASP) Setting Casing Depth Size TVD MAWP' MASP .. Mud/Gas (in) (ft) (psi) (psi) Percentage 95/8 5,645 4,809 1,899 30170 . MAWP = Maximum allowable working pressure ** MASP = Maximum anticipated surface pressure if150 () r\OO The calculation method for MASPBHP has been modified from the standard AOGCC use of a Bottom Hole Pressure - 0.1 psi/ft gas gradient to what Marathon considers a more accurate Bottom Hole Pressure - 30% Mud Column - 70% Gas Column. This method follows the MMS standard for any well with a TVD of 12,000' or less. Marathon believes that constant gas monitoring and proper rig supervisor well control training will prevent the possibility of a well bore being completely evacuated with only a gas gradient remaining. Production casina: 95/8" (PBTD 9,850' MD, 8,198' TVD) Q.~~~\ ~\\? ~ l~OO ~~\ MASPbhp = BHPbottom perfs - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhp = (8.4 ppg x .052 x 8,168') - (0.3 x 8.6 ppg x .052 x 8,168') - (0.7 x 0.1 psilft x 8,168') MASPbhp = 3,567 psi -1 ,096 psi - 572 psi ,...)\~\..~~" ""~s.'? ... 3S~ '\ _ ~ \ ~ MASPbhp = 1,899 psi ( ~c::....~ - , = ~"'\ <5"0 ~~ \ h2¥7 ~ b':). MASP = MASPbhp = 1,899 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. - Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 6,870) - (8.6 -10.0) x .052 x 8,198' MAWP = 4,809 psi - 0 psi = 4,809 psi Comments: 4.8 Casinq Test Pressure Calculations Casing test pressure calculations are based on the lesser of (1) MASP, or (2) 70% of rated burst pressure of the casing adjusted for the mud weight used during the test less a 8.3 ppg back-up unless otherwise noted. AOGCC regulations state that casing pressures must be 50% of the BOP working pressure documented on the approved permit to drill. Best Practices: 1 Comments: 4.9 Blowout Prevention Equipment. Testinq and General Procedures BOP PROGRAM I I Casing Test Test Casing Test Fluid Pressure Size MAWP MASP Press Density BOPS Low/High Casing (in) (psi) (psi) (psi) (Ib/gal) Size & Rating (psi) (1) 13-5/8" 5M annular Production 95/8 4,809 1,899 (1) 13-5/8" 5M pipe ram 25012,000 2,000 8.6 (1) 135/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets 6/15/2007 CON~~L Page 8 of 10 . . Marathon Oil Company Alaska SU 41-15 Abandonment Program Blowout Preventers The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-1/8" x 5000 psi outlets. The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor-boy gas buster, and a vacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. 4.9.1. Function TestinQ Function Regularly. 4.9.2. Pressure TestinQ The Marathon Drilling Supervisor will verify all pressure tests of BOP's, surface lines, seals, casings and FIT or LOT tests. All tests are to be recorded on the IADC and daily drilling reports. Best Practices: 1 Comments: 4.10 Wellhead EQuipment Summary Component Description Casing Hanger Type 13-5/8" 5M X 13-3/8" Slip-On Weld 13 5/8" x 9 5/8" Manual Casing Head Slips Tubing Head 11" 5M X 13-5/8" 5M 11" x 7" Mandrel Hanger 11" x 2-318" Mandrel Tubing Spool 11" 1 OM X 11" 5M Hanger Adapter Flange 11" 5M X 2 1/16" 10M WI Seal Pocket and 3" H BPV Threads Best Practices: 1 Comments: 4.11 Drilling Fluid PrOQram Summary Interval- MD Minimum Inventory From To Density Gel (ft) (ft) (Ib/gal) Fluid Description Additives Viscosifier Barite 0 1,886 8.6 6% KCL Brine KCL Best Practices: 1 Comments: Page 9 of 10 6/15/2007 . . Marathon Oil Company Alaska SU 41-15 Abandonment Program Move in and rig up Glacier 1 drilling rig. Monitor pressure on 2 3/8" tubing, 2 3/8" x 7" annulus, and 7" x 9 5/8" annulus. Attempt to bleed off any pressure on the tubing and each annulus. Line up to pump 6% KCL brine down the 2 3/8" tubing, filling the well, and taking returns up the 2 3/8" x 7" annulus out the 11" 5M x 11" 1 OM tubing spool side outlet. ._~ Install BPV and nipple down tree. Nipple up adapter spool and BOP with 2 3/8" pipe rams, and ~~ms. Pull BPV and test BOP to 250/2000 psig. s.~(è. ct ~\\t& ~ Rig up to pull chemical injection line. Make up landing joint into tubing hanger and pull out of hole, laying down 2 3/8" tubing and spooling up chemical injection line. 5.,.... Pick up 4" drill pipe, open ended and TIH to last known fill level 9,788' MD (Old KB), 9,779' MD (Glacier KB). Circulate hole ~\tA\\ ~-\~\ while trying to clean out fill to the CIBP at 9,850' MD (Old KB), 9,841' MD (Glacier KB). Circulate hole clean. \)~~"> 6. Pick up approximately 1 0' off bottom, RU BJ cementers and spot 15.8 ppg balanced cement plug from PBTD to approximately 9,300' MD (Glacier KB). Pull up out of cement slowly, to approximately 8,800'. Circulate normal direction to clear pipe of any excess cement. .~ ~O ~b\~ <:..~~«:~ ~ \, \ S' ,,'\~.\~"\ , POOH with 4" drill pipe. wac. rc..c,,~\- x.~~~,J~.Ð~~~t:;."'>' Pick up 6 1/8" bit on 4" drill pipe and TIH. Tag up on cement plug to confirm top. Test cement to 1,000 psi. TOOH. Pick up RTTS packer for 7" 29# casing and storm valve. TIH with 30 jOints of 4" drill pipe followed by RTTS packer and storm valve. Set packer at approximately 25' and test to 1,000 psig for 15 minutes. Nipple down BOP. Nipple down and remove 11" 5M x 11" 10M tubing spool (This spool will be taken to have the 11" 10M flanged bored out for 9" bore). Nipple up BOP to 11" 5M flange on wellhead and test flange to 2,000 psig. Pull RTTS packer and storm valve and lay down same. POOH with 4" drill pipe. Change out ~ipe rams with 7" casing rams in single ram. Run test plug and test casing rams to 2,000 psi. Rig up wiréÍin~~~~ RIH with jet cutters for 7" casing to approximately 8,100' MD (Glacier KB). Cut 7" casing. POOH with wireline. Make up landing joint into 7" tubing hanger and pull out of hole with 7" casing, laying down. Pick up 8 3/8" bit with scraper for 9 5/8" 53.5# casing. Make a scraper run on casing to top of 7" casing stub. Circulate hole clean and TOOH. Pick up RTTS packer for 9 5/8", 53.5# casing and storm valve. TIH with 30 joints of 4" drill pipe followed by RTTS packer and storm valve. Set packer at approximately 25' and test to 1,000 psig for 15 minutes. Nipple down BOP. Nipple up 11" 5M x 11" 1 OM tubing spool. Test 11" 5M break as per Vetco procedure. Nipple up BOP to 11" 5M flange on wellhead and test flange between spool and BOP to 2':'sOO psig. \"\ See the Sidetrack Procedure for the remaining work on this well. ~"- _ \ 1\ c:cJ ·TX-~-\-~rt'S:.<>"-.J~ \C..."t\.J œ Bes~ Practices: \-Ð\~'\ \\\ "'~ l.-.\ \-\ SQ\) jj¿~ t. 10 (if") 6/15/2007 4.12 Abandonment Proqram History: Previous work on SU 41-15 has not resulted in a viable Beluga completion. The well appears to be damaged and previous re-work did not bring the well back to a viable producer. The well is currently shut-in. Objective: To abandon the current wellbore in preparation to perform a sidetrack (separate procedure). 1. 2. 3. 4. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. Comments: co Page 10 of 10 J API: 50-133-20484 AOGCC: 98-41 KB-GL: 30' (original KB) 437' FEL, 2327' FSL Sec. 9, T5N, R10W, S.M. 4.75" Otis tree cap Lift threads - 3.161" MCA Equipped with 10K welihead and 4", 1 OK valves for frac stim ulation via 2- 3/8" x 7" annulus. Active Perfs (Beluoa Sand) 9440' - 9450' 6/04 9516' - 9526' 6/04 9558' - 9563' 6/04 9576' - 9584' 6/04 9616' - 9640' 6/04 9624' - 9626' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 9674' - 9682' 6/04 9676' - 9678' (8 hoies, 4-5/8", 120-deg, 0.37") 9/03 9694' - 9704' 6/04 9696' - 9698' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 9722' - 9736' 3/04 9730' - 9732' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 9806' - 9808' (8 holes, 4-5/8", 120-deg, 0.37") 9/03 Previous Beluoa Perfs (assumed plugged off during workover) 9440'-9450' 9616' -9640' 9674'-9682' 9694'-9704' 9722'-9736' 9800' -9812' ...1 l 13-3/8", 61 ppf, K-55, BTC surface casing @ 2271' Cmt with 1186 sks of class G 7" Tubinq Strinq - 7",26 ppf, P-110, BTC-M tubing Baker KC1 tubing anchor at 8196' Baker SAB 194-73 permanent packer @ 8198' Re-entry guide @ 8256' 2-3/8" Tubino Strinq 2-3/8",4.6 ppf, L-80 & J-55, EUE 8rd to 9300' 4' of carbide blast rings immediately below tubing hanger Baker chem ical injection nipple @ 1570' w/1/4" control line to surface X-nipple @ 9233' ID = 1.875" Re-entry guide @ 9300' Tagged fill at 9,788' CIBP at 9850' (9/3/03) Cement plug 9872' - 10,055' 9-5/8", BTC casing @ 10,312' 0' 3083',53.5 ppf, P-110 3083' - 9866', 47 ppf, P-110 9866' - 10,312',47 ppf, L-80 Cmt with 2284 sks of class G 7" ZXP liner-top packer @ 10,108' 7", 29 ppf, L-80, BTC liner @ 10,108' - 12,590' Cmt with 708 sks of class G Well Name & Number: SU 41-15 Current Lease I Sterling Unit, Beluga Pooi County or Parish: Kenai Peninsula I State/Provo Alaska I Country: I USA Perforations: (MD) (TVD) I Date Completed: 09/09/031 1 RKB: I Prepared By: J. G. Eller Last Revision Date: 16/15/2007, (W.J. Tank) . . Review of Sundry Application 307-204 Marathon Oil Company Well SU 41-15 AOGCC Permit 198-041 Recommendation: I recommend approval of Sundry Application 307-204 to allow Marathon Oil Company ("Marathon") to plug and abandon the existing perforations to prepare the well for sidetracking. Discussion: On June 18,2007, the Commission received the subject Sundry application from Marathon. They requested to plug and abandon the existing perforations to prepare the well for sidetracking. They state that the well is not a viable producer and appears to be damaged. On August 4,2003, the Commission approved Marathon's sundry application (Sundry 303-215) to convert the well from a dual completion, producing from both the Tyonek and Beluga formations, into a single producer that would produce from the Tyonek and to fracture stimulate the Tyonek. This workover did not produce the desired results and on January 28,2004, the Commission approved their application (Sundry 304-021) to re- perforate the Beluga formation. This workover also did not provide the desired results. Marathon believes there is damage that is preventing the well from being a viable producer and proposes to plug and abandon the existing perforations so that the well can be sidetracked to a new bottomhole location. Production after both previous attempts at a workover was marginal at best, never being able to produce continually for an extended period of time at rates higher than 100 to 200 MCFPD. The well has not produced since January 2005. Conclusions: Based on the poor results from previous unsuccessful attempts to make this well a viable producer it appears that the current wellbore has limited value. Abandoning the existing perforations to prepare the well for sidetracking has the greatest potential of making this well a viable producer againd . Prepared by: D.S. Roby .Aj Prepared on: June 22, 2007 ~\O-\...\.~l d.~C).-..- \~~ ~~-;)\Ç \~-'-\\)L\ M '3O~-()ð-\ ~fo TO be 'fO'f J" fl let:! r , !eq5r 1Aere Qre /1/)/t(.,. 1'1 It /¡f) / 1~ e íw-O f,.¡;,f,r h'c.I.e. Tiere.. doe} /Jor ct(le"f/ fl".' 0- Io'11r f<oved. /J--r RE: SU 41-15 Workover/Plugging--Again . . Subject: RE: SU 41-15 Workover/Plugging--Again From: "Tank, Will" <wjtank@marathonoi1.com> Date: Thu, 21 Joo 2007 15:26:15 -0500 To: Thomas Maunder <tom_ maunder@admin.state.ak.us> cc: "Berga, Pete" <pkberga@marathonoi1.com> Tom, As per our phone discussion, here are the answers to the questions. Question 1: After reviewing the plans for the abandonment and the subsequent sidetrack, the description of the BOP stack on Page 9 of the Drilling Program is correct. We would plan to use a 2-ram stack (1 pipe, 1 blind) with an annular. Thus on the procedu~ on Page 10, the first pipe ram in place would be for 2 3/8" tubing. Question 2: Since this will be a 2-ram stack, the procedure on Page 10 of the Drilling Program at Step 5 should begin with the words "Change /out 2 3/8" pipe rams with variable bore rams for the 4" drillpipe. Test rams to 2,000 psi." Step 12 should be mçdified to say "variable bore rams" instead of "2 3/8" pipe rams". ./ Question 3: The red "Confidential Information" designation is a footer /' in the document. Marathon is not anticipating that this work should be ~ confidential. I will try and remember to remove this in the future. Question 4: It is our intention to spot a cement plug in the casing that would give a minimum of 100' above the top perforation. This tight formation is not expected to take any appreciable amount of cement when pressure is applied. Our current planned top of cement would be 9,300' MD. That equates to a 541' cement plug utilizing a 15.8 ppg slurry with. /' an approximate 1.17 cu. Ft. / sack. That equates to approximately 39.6 ~ bbls or 190 sacks of cement. Question 5: Pete was at the location today (6/21/07) and noted that the shut-in pressure of the well is at approximately 1,000 psi. I had calculated an MASP of 1,899 psi in the procedure, so actual values are less than predicted. Also per our discussion I will submit a letter requesting a variance for the ram configuration for the subsequent sidetrack due to the EXCAPE completion height restrictions. Thanks, Will Tank -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Thursday, June 21, 2007 2:21 PM .- To: Tank, Will Cc: Berga, Pete Subject: Re: sa 41-15 Workover/Plugging--Again Two more questions: 4. What is the cement volume planned for the plug? 5. What is the SI pressure of the well? How does this compare with the MASP value? Thanks, Tom Maunder, PE AOGCC Thomas Maunder wrote, On 6/21/2007 11:14 AM: Will and Pete, lof2 6/21/200712:30 PM RE: SU 41-15 WorkoverlPlugging--Again I am reviewing the sun~apPlicatìon to plug the well t~repare for sidetrack and have a couple of questions. 1. On page 9, the BOP stack is stated to be (from bottom) spool-blinds-pipe-annular. On page 10 in the procedure (step 3) it is stated to have the BOP equipped with 2-3/8" rams and VBRs. Would you reconcile the conflicting statements. 2. A set of DP rams will need to be installed and tested prior to making the cleanout trip in step 15. The answer to question 1 will likely answer this question as well. 3. "Confidential Information" appears in red in the footer of all the text pages. Confidential treatment of information provided to the Commission is presently afforded for the drilling of a well and for 25 months after the completion of that well. See 20 AAC 25.537. Absent a request by the operator for extended confidentiality, the information is released. The Commission well file for SU 41-15 was released to the public about March 1, 2001. Once the well file has been released subsequent wellbore work requests (10-403) and work reports (10-404 and 10-407) are placed in the public well file following any necessary internal work (approval or review) . I look forward to your reply. Call with any questions. Tom Maunder, PE AOGCC 20f2 6/21/200712:30 PM ( ( Alaska Business Unit Domestic Production Marathon P.O. Box 196168 . Anchorage, AK 99519-6168 011 Company Telephone 907/561-5311 Fax 907/564-6489 January 26, 2004 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: SU 41-15 Dear Mr. Aubert: Enclosed is the 10-403 Application for Sundry Approvals for Marathon well Sterling Unit 41- " 15. The proposed perforating work is to increase production from new and existing Beluga r Intervals sand fractured after limited entry perforating performed during the Novemberwork over. The perfs to be added are included in the enclosed procedure. The proposed work is tentatively scheduled for later this week or early next week, as soon a electric line is available. If you need any additional information, I can be reached at 907-283-1337 or bye-mail at 1deevnon(â2marathonoil.com. Please note the new phone number as I have been relocated to Kenai. Sincerely, b~~ Don Eynon Production Engineer RECEIVED Enclosures JAN .2 8 2004 Alaska Oil & G C . ]as OOS. Cormnls,sioft Anchorage ',' '.,. '. ~.. '"', ,"", fill (i'ì) 200 n 0, n 1, ().I. ~ 1 ~"I ~)~A¡N\~Et) F E B 'M ¿P ... t:o~ : ' '., ;\"'\.1,,, J l~ "..~ I I ;: ~ ,:,-:(, ,~ ir-l C7Æ- , I ~ ~ I U¡ 0 t.f It STATE OF ALASKA ( l:)ìj I)L?! ~ ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 1. Type of Request: AbandonD Suspend wellD Operation ShutdownD pertorate0 varianceD Annular DisposalD Alter casingD Repair WellD Plug PerforationsD StimulateD Time ExtensionD OtherD Change Approved ProgramO Pull TubingD Perforate New PoolO Re-enter Suspended wellD 2. Operator 4. Current Well Class: 5. Permit to Drill Number: Name: Marathon Oil Company Development[U EXP,oratory8 98-41/ 3. Address: StratigraPhiCD Service 6. API Number: P. O. Box 196168, Anchorage, AK 99519-6168 50- 133-20484/ 7. KB Elevation (ft): 9. Well name a;Ynumber: Perforate new and existing 27.8', KB-GL SU 41-15 Beluga Intervals as shown on 8. Property Designation: 10. Field/Pools(s): Detailed Operations Program Sterling Unit Sterling Unit, Beluga Pools 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft.) Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plug (measured): Junk (measured): 12600 10559 9850' N/A 9,788 fill Casing Length Size MD TVD Burst Collapse Structural 58 20" 58' 58' 2110 520 Conductor Surface 2271 13-3/8" 2271' 2270' 3090 1540 Intermediate Production 10312 9-5/8" 10312' 8544' 6870 min 4750 min Liner 2482 7" 12590' 10550' 8160 7020 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft.): Beluga.9440' Beluga - 7905' 7" 26# & 2-3/8" 4.6 7" P-11 0 & 2-3/8" J-55 7" @ 8,256', 2.3/8" @ 9300' Packers and SSSV Type: Packers and SSSV MD (ft): 9 5/8 x 7" Baker Packer 8202' 12. Attachments: Description Summary of Proposal~ 13. Well Class after proposed work: Detailed Operations Program ~ BOP Sketch -0 Exploratory D Development 0 Service D 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 28-Jan-04 Oil D Gas~ / PluggedD AbandonedO 16. Verbal Approval Date: WAG D GINJD WINJD WDSPL 0 Commission Representative 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Donald Eynon Title Production Engineer .~\, ~ Signature c~V\4 ~ Phone 907-283-1337 Date 24-Jan-04 Commission Use Only Conditions of approval: Notify Commission so that a representative may witness Plug Integrity 0 0 Mechanical Integrity Test 0 Location Clearance qAN 2 8 2004 Other: AI k 0'1 & §C/A~~E'[,; rEÐ 0 ~ 20[]f} as ai' Gas Cons. Commission I 0.- t../-O 'F Anchorage BY ORDER OF COMMISSIONER THE COMMISSION 0 ~ I G I t\L~ , -- -L ( ( Marathon Oil Company Alaska Region SU 41-15 Sterling Unit, SU Pad 32-9 Add Perforations Procedure WBS# History: SU 41-15 was recently re-completed as a single Beluga completion with a 2 3/8" velocity string at 9300'. A post rig limited entry frac did not produce the expected results, perforating new and existing interval in the Beluga is needed to increase production. Objective: Perforate additional pay. /' Procedure: 1. Ensure location and tree are prepped for wire line including liner installation and house removal if necessary. 2. MIRU wire line unit. Pressure test lubricator to 3000 psi with methanol trailer. <' 3. Perforate the following zones with 1-11/16" 6SPF 0 degree phase 3.5 gram NTX charges, retrievable guns: 9,440 - 9,450' 10' 9,516 - 9,526' 10' 9,558 - 9,563' 5' /' 9,576 - 9,584' 8' 9,616 - 9,640' 24' 9,674' - 9,682' 8' 9,694'- 9,704' 10' 9,722 - 9,736' 14' 4. Clean up location. RDMO eline, and return well to system per instruction of production engineer. Flow back to open top tank if necessary. .- (!Æ ( SU 41-15 ~/ ( M ¡ MARATHON J l API: 50-133-20484 120", K-55 Drive pipe @ 58' I AOGCC: 98-41 KB-GL: 29.71' (original KB) 437'FEL,2327'FSL Sec. 9, T5N, R10W, S.M. 13-3/8",61 ppf, K-55, BTC surface casing @ 2271' 4.75" Otis tree cap Cmt with 1186 sks of class G Lift threads - 3.161" MCA 7" Tubina Strina - 7", 26 ppf, P-11 0, BTC-M tubing Equipped with 10K wellhead and 4", 1 OK valves for frac stimulation via 2- Baker KC1 tubing anchor at 8196' 3/8" x 7" annulus. Baker SAB 194-73 permanent packer @ 8198' Re-entry guide @ 8256' 2-3/8" Tubina Strina 2-3/8",4.6 ppf, L-80 & J-55, EUE 8rd to 9300' Active Perfs (Beluaa Sand) fl. '1. 4' of carbide blast rings immediately below 9624' - 9626' (8 holes, 4-5/8", 120-deg, 0.37,,)11 tubing hanger 9676' - 9678' (8 holes, 4-5/8", 120-deg, 0.37") Baker chemical injection nipple @ 1570' 9696' - 9698' (8 holes, 4-5/8", 120-deg, 0.37") w/ 1/4" control line to surface 9730' - 9732' (8 holes, 4-5/8", 120-deg, 0.37") :I C X-nipple @ 9233' 9806' - 9808' (8 holes, 4-5/8", 120-deg, 0.37") ::I C ID = 1.875" :J I:: Re-entry guide @ 9300' Previous Beluaa Perfs ;I ç: (assumed plugged off during workover) :I C 9440'-9450' 9616'-9640' 9674'-9682' CIBP at 9850' (9/3/03) , 9694'-9704' Cement plug 9872' - 10,055' 9722'-9736' 9800'-9812' 9-5/8", BTC casing @ 10,312' 0' - 3083',53.5 ppf, P-110 3083' - 9866',47 ppf, P-110 9866' - 10,312',47 ppf, L-80 Cmt with 2284 sks of class G 7" ZXP liner-top packer @ 10,108' 7",29 ppf, L-80, BTC liner @ 10,108' - 12,590' Cmt with 708 sks of class G Well Name & Number: SU 41-15 Proposed Lease I Sterling Unit, Beluga Pool County or Parish: Kenai Peninsula I State/Provo Alaska I Country: I USA Perforations: (MD) (TVD) T Date Completed: 09/09/031 I RKB: 1 Prepared By: J. G. Eller Last Revision Date: I 09/19/031 Alaskai. ,iness Unit Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 August 1, 2003 Mr. Winton Aubert Alaska Oil and Gas Conservation Commisson Suite 100 333 West 7th Ave Anchorage, Alaska 99501 Subject: SU 41-15 Dear Mr. Aubert: Marathon proposes to workover well SU 41-15 in the Sterling Unit beginning August 8, 2003. Your prompt review of this Application for Sundry Approval is greatly appreciated. The objective of this workover is to convert well SU 41-15 into a single producer in the Tyonek Pool. Well SU 41-15 currently is configured as a dual completion in the Tyonek and Beluga Pools."'The existing Tyonek completion is currently not capable of production/As part of the workover, the existing Beluga perfs will be isolated behind 7" tubing and packer. Following the workover, the Tyonek Pool will be fracture stimulated down the 7" tubing. The well will be produced up a string of 2%" tubing following fracture stimulation. Please contact me at 907-564-6315 or iqeller~marathonoil if you need any further information. ~,, Sincerely, , ~, Production Engineer bjv Enclosure Environmentally aware for the long run. ORIGINAL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION · APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 ~1. Type of Request: Abandonl--~ Suspend Wellr'---I Operation Shutdownr---~ Perforatel-~ Variance~ Annular DisposalF--"I Alter Casingr----I Repair Welll~I Plug PerforationsE~ Stimulatel-~ Time Extension[~ OtherF~1 Change Approved Programl-~ Pull Tubingl-~ Perforate New PoolE~ Re-enter Suspended Wellr-'-I 2. Operator :4. Current Well Class: 5. Permit to Drill Number: Name: Marathon Oil Company Developmentr~ Exploratory[~ 98-41 / 3. Address: StratigraphicL-J~ Servicel~l 6. APl Number: P. O. Box 196168, Anchorage, AK 99519-6168 50- 133-20484 //' 7. KB Elevation (ft): 9. Well name and n, umber: 27.8', KB-GL Workover to single, fracture su 41-15 8. Property Designation: stimulated Tyonek completion ,10. Field/Pools(s): Sterling Unit Sterling Unit, Tyonek and Beluga Pools 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft.) ITotal Depth TVD (ft): IEffective Depth MD (ft): IEfrective Depth TVD (ft): Plug (measured): Junk (measured): 12600I 10559 I 12490I 12490 N/A 11946 Casing Length Size MD TVD Burst Collapse Structural 58 20" 58' 58' 2110 520 Conductor Surface 2271 13-3/8" 2271' 2270' 3090 1540 Intermediate Production 10312 9-5/8" 10312' 8544' 6870 men 4750 men Liner 2482 7" 12590' 10550' 8160 7020 Perforation Depth MD (ft): IPerforation Depth TVD (ft): Tubing Size: ITubing Grade: ]Tubing MD (ft.): Beluga - 9440', Tyonek 10942'ii Beluga- 7905', Tyonek 9055' I 2-7/8", 6.5#~1 L-80~1 LS - 10940', SS - 9770' Packers and SSSV Type: Packers and SSSV MD (ft): Baker GT dual at 8820', Baker model D at 10847' 12. Attachments: Description Summary of Proposall'~ 13. Well Class after proposed work: Detailed Operations Program ~ BOP Sketch ' Ix I Exploratory [-~ Development [~ Service F'-[ 14. Estimated Date for ~, 15. Well Status after proposed work: Commencing Operations: 8-Aug-03 Oill~I Gasl~I Pluggedr'~ AbandonedE~ 16. Verbal Approval Date: WAG r'--1 GINJI~I WINJI~] WDSPL Commission Representative 17. I hereby certify that the foregoing is trueft~nd correct to the best of my knowledge. Contact Printed Name~'-... ~ Gar~ /~ Title Production Engineer Signature '~,, .~" Phone 907-564-6315 Date 1-Aug-03 Commission Use Only Conditions of approval: Notify Commission so that a representative may witness ~IB . ,/ Plug Integrity I~1 BOP Test r~ Mechanical Integrity Test E~ Location Clearance E~ (,~'"' ': . . Subsequent Form Requested: '-"-'-~'""('"'" ' <:~ ........... BY ORDER OF Approved , . . ~ j2,,,,,-~ COMMISSIONER THE COMMISSION Date: by: Form 10-403 Rev~e~ .~;ubmit in duplicate Well SU 41-15 Sterling Unit WBS WO.03.09182.EXP Workover to Tyonek Single Completion Objective: Workover well SU 41-15 as a single producer in the Tyonek Pool. The completion will allow frac stimulation of the Tyonek following the)~6rk°Ver. ,,. Procedure: ' '~'; ·. · : . · 1. Mark on the tubing head with permanent marker the location of the short and long.. strings so they can be readily identified when the tree is removed.. Remove. · ' ~'~ '. · . wellhouse and ND flowlines sufficiently to move in rig substructure..Mark the: :?' .' .. cellar at the desired orientation of the new tubing head outlet.. " .... '~. · 2. Shut in shortstring and longstring production...3d**l~. U slickline0n shortstring. '..,."'· '~ . Conduct prejob safety meeting and test BOPE. RiH.withretrieving tool for .' '.....".. i..!'~..'..·'~ isolation assembly set across sliding sleeve'~at'.8751: On. 12/12/02. 'Pull isolation ' :'.. assembly, POOH. RIH with shifting tool' for 2.313','.CMU sliding, sleeve at 875i';".:.' 9".'"' r!..n.g.0ut the end'of the tubi. pg ,(9770') to tag Shift sleeve open. RIH with ~ ..::g..,a. pge ..~, :......:~..: ...... . .'. fill. P0'oH~ ,RDMO slickline:.. ". .. .' .. · . '.. . '" ": .: .' .' ..... ' "i 3. 'MIRU APRS"pipe rec..dvery'unit On the long~tring. GO .to'radio Silence, conduct .prejob. saf..el3/meeting.. "RIH.~ith jet cutter foi"2*A",.':615'.ppf tubihg (Cutter OD = .. 2~"). Tie:in ~ .wi.'th ccL:.to the long string .blast joints.., CUt the longstring tubing at .' '+9770' in. the;middle 0'f atUbing joint.:' POOH, RD from 10ngstring. · 4,. MIRU pump truck. B. lenct.600 bbl of. 1 ~.0..pPg bentonite mud as per M-I prog. .(Note: Formation pressure. of the Beluga interval is approximately 8.3 ppg and the Tyonek inte~al'is 10.6 ppg:) RU to pump down longstring and take returns on the annulus through gas buster. Conduct prejob safety meeting and test lines to .. 5000 psi. Circulate hole full of 11.0 ppg mud. When annulus is full, move return line to the shortstring tubing. Circulate 'until shortstring is also loaded with mud. RDMO pump truck. 5. Call out Vetco ~vellhead rep. Bleed off any remaining tubing and annulus pressure. Bleed pressure off of chemical injection lines. Set 2½" BPVs in the LS and SS tubing strings. Prep the tubing hangers by ~vorking the lock-do~vn pins. Pressure test tubing hanger seals. ? 6. MIRU drilling rig. Prior to ND tree confirm that no trapped pressure exists*oelow the BPVs. ND tree. Inspect lift threads on tubing hangers. (Note: Records indicate both strings have 3.160" MCA lift threads. Inform Company Man immediately if lift threads are different than expected.) NU adaptor spool (11", 5M x 13V8", 5M) and 13sA'', 5M BOPs. Lower single gate rams will be equipped J. G. Eller- July 31, 2003 Well 41-15, Workover Procedure WBS - WO.03.09182.EXP Page 2 with 4", 5M pipe rams. The upper pipe rams should be equipped with dual 27A'', 5M pipe rams. Install dual mousehole. Pull LS and SS BPVs, set 2-way checks. PU dual joints of 27/8" tubing and scyew into dual test bushing for testing dual pipe rams. Test BOPE to 250/5000 psif LD test joints, pull 2-way checks. 7. RU dual elevators, dual spiders, dog collars, and integral tongs for pulling!both strings of 2~", 6.5 ppf, L-80, EUE 8rd tubing. MU dual 27A'' EUE 8rd.',li~.~jointS.~'i: i with 3.160" MCA crossovers into tubing hanger. Load hole with.). and establish circulation down the shortstring tubing through at 8751'. Apply sized calcium carbonate LCM as needed as recommendation. :' , . .... 8. PU on LS tubing to release GT dual packer at 8820'. All tubing is ~-.7..8.."~7Z'", 6.5 PPI:,:... ' ppf, L-80, EUE 8rd Mod, which is rated to 145 mlbs ofjoint, strength':,. (l O0%). .".'-...." Coupling OD is 3.668". '' :: .. a. If unable to release packer, RIH in S$ With jet cutter for'2~'?,.6.5 ppf." tubing. Cut SS at 8786' (±5' above.the:dual pac..ker). PO.OH..i.'.Verify that"' "::.." the SS tubing is free, and work L~':.tCbing again to attempt to.bee dual '' '..'" packer ' b, .:!fPacker still won't come free, Rill in LS With'i~J.et cutter:f~0r"3½'', 9.2 ppf ::' tubing..'. Cut the LS; at 8117'6' (4-15' above.the'dual' packer.).. POOH. .' . '9....Lay'doW_n.'al!:.tiSed 2~'.".tubing and blast joint "' "' .-..: .... .... (OD. = 3.:5. ). (Note: Install thread .. pr0tect0~S 6fi both ends:of.the 2Vs" tub,ing.. '.and bla..st j0im' and ship to Tuboscope- ... "Kenai for.!0%: inspeeti6n.). Take occasional measurements for NORM while/' · . . . Note: The remaining rec0mp!etion procedure assumes that the GT dual packer came out as designed,. If the dual. packer cannot be pulled, contact Anchorage office to discuss whether tO attempt.bum-over of the GT dual packer. · 1'0. RD dual tubing handling equipment. RU single elevators, slips, and tongs for running 4", 14.0 ppf, S-135, HT-38 workstring. Lay out, tally, and rabbit 12,000' of 4" workstring. 11. Pull dual mousehole. Close the blind rams. Replace the dual 27A'', 5M rams in the upper pipe rams with variable-bore (2.875" to 5.5") 5M pipe rams. Install ....single mousehole. Open blinds, install test plug, and test BOPE as needed. Pull .??:' test plug. 12. PU 4" work string and 1200' of 5¼", 21 ppf, TSS wash pipe with 6" shoe. TIH with wash pipe on 4" drill pipe. Wash over remaining 27A'' tubing and 3.5" OD J. G. Eller- July 31, 2003 Well 41-15, Workover Procedure WBS - WO.03.09182.EXP Page 3 blast joint to the top of the model "D" packer at 10,847'. Circulate clean. POOH, laying down wash pipe. 13.PU overshot for 2~" tubing and fishing jars. TIH, latch fish. Jar loose to release packer seal assembly. POOH, LD overshot and fish. ,., , 14. PU packer burning assembly and TIH. Bum over model "D" ::" :' """ packer, at.:I.0;847,:..:.. ..... . .,., :. Attempt to push remnants to bottom of hole (at least below 12,000:".: .' '.'~TOH standing back drill pipe. LD bum-over assembly. a. If unable to push model "D" packer to + 12,000', MU pa~i~r'plucker't0 fish remnants of the model "D" packer. TIH, latch packer,;.TOH~ .. · .' '. .. 15. MU BHA with 6¼" bit, a casing scraper for 7", 29 ppf casingii:.23: Stands:.6f drill.' "' pipe, and a casing scraper for 9%", 47 & 53.5 ppf casing. TIH'..~.'th(k/it and '. scrapers on 4" workstring until the 9%" scraper tags the 7" liner:.t,0isiai'l 0,108'.. Circulate hole clean. TOH standing back drill:piPe, .LD.bit and:scr.h~er BHA.. · ..' .'i'~: · .....'.. ' .i.,..~ :. ,,, " 16. MIRU Schlumberger. Conduct prejob safetY meeting:aud test BORE.' PU and' .: RIH with USIT/CBL logs. Tie in. With .A!T.!0g of 1'.2/26/'1998, !og.!},l:,'500' - '. 10,100'.'::"POOH.. RIH with RST'.i!6g..'TJ~:~'ifi v~ith'X!'T.::!i~.g of 12~2'6/.'.:r998. Log 11,5.007' " '. ,,.: . .. , ......... . .. .... ,..-. 8~600 POOH.. LD RST to61..(Note:.,;Send'the USIT/.".CBi3:.and RST · :10g-!-d~!tat0..Anehorageright away'for analy..sis:':' It is' P0~Sible that:.the::Tyonek ' ".',',interv.~l:may.be.condemned'0n the basis O.'.f..i0ne of th~:se:.;!0gs. In:"th~/t event, the ' ' "TY°neic inte/-vai 'would be .'abandoned and:.a'"single 'cornpl~tion would be made in .. :.:., 7iihe.B l~iisa3))' · . ,.:i'.7..::PU 7" Baker 3BB cIBP (10M psi rate.d diffei:ential) and RIH on wireline. Set · ...CIBP at +i 0,150'. POOH,'RDMO Schlumberger. · .. . . . ... . 18..PU and TiH.'.with 7-9/16" polish mill and "liner top dressing mill. Record PU : · ~' and SO Weights prior to entering liner top. SO into tieback sleeve and tag. PU polishing assembly above tieback sleeve and establish circulation and rotation . (60-80 rpm). Slowly SO and monitor torque. Polish for 15 minutes or until clean. TOH, LD polish mill assembly. 19. Install BOPE test plug and close blind rams. Install 7", 5M pipe rams in upper set,~ of rams. Lower pipe rams are still equipped with 4", 5M rmus. Test BOPE as needed to 250/5000 psi. Open blinds and pull test plug. 20. Lay out, rabbit and tally 10,300' of 7", 26 ppf, P-110, BTC-Mod tubing. RU long bales, 7" elevators, spiders, dog collars, and casing tongs. TIH with 7" tubing as follows: a. 7V2" x 10' tieback seal assembly (Baker locked) J. G. Eller- July 31, 2003 Well 41-15, Workover Procedure WBS - WO.03.09182.EXP Page 4 21. 22. b. 7" orifice float collar (Baker locked) c. 2 jnts of 7", 26 ppf, P-110, BTC-Mod tubing (Baker locked) d. 7" Type I landing collar (Baker locked) e. 7", P-110 tubing f. Baker SAB packer (set at +8200' MD) g. Baker KC-122 anchor h. 7", P- 110 tubing to surface i. 7" spaceout pups j. Vetco 7" tubing hanger with 7" pup (4') k. 7" BTC landing joint (10') One joint prior to tagging liner top, rig up to circulate. Establish circulation, · record PU and SO weights. Slack off to engage seals. A pressure:increase willi' be'" seen as the second set of seals enters liner tieback sleeve. Shut.. down pump and '.:.' ~. · continue to SO until entire seal assembly is stung into tieback sleeve: ' ¥' .. (approximately 8'). Holding 300 psi, PU until pressure bleeds..off.'.'..This position . is where the first set of seals are engaged in the tiebacki:sleeve and the.ports are ': :" exposed to the annulus for cementing. Mark.'.the..pipe. .. .. ..·'~ "' · . ...'. .·'.. Space out 7" tubing and install spaceout pups and tUbing:hanger:. ·TUbing hange~:':'. '.. '~' · has 7" BTC lift threads. Sting'Seals bafk~.::into the"ti6bael~:'sleevei't6~:the point wh. ere:~th..:e ports in the sleeve wi!!,;still allOw circulation, but do n0t.land tubing at ..this..tirne. · . .. . ..:' . .: · .."..'.. ..... ,.: ...,... · . .. . 2'3 :': MIRU.:BJ Cementers..' conduct prejob safety meeting.·'MU cementing h, ead~hto · . . · ,~,. . '. ,.. : ,, . . · .' ..... . ' . ~ . ,~ ' '. . o' . ~' / ~'~ "'...7 tubing and'test hnes.to' 5000 ps~.Cement 7 tubmg'.m, place w~th,/_~,~·~/cks of · ' '' . ' " ' ; , t' i cement as per. BJ prog. 'Top' of cement should be:4-8600. Do not ~_eerd. 6 bpm , circulationirate and do not exceed 2000 psi Pump pressure. (Note: Baker SAB packer will.begin to set. at2900,psi pump p, ressure.) 24. After bumping the wiper plug, slack off on the 7" tubing to sting seals into tieback sleeve and l~nd tubing hanger. Pressure test 7" tubing to 500 psi to confirm seals .are in place. Continue to pressure up 7" tubing to 4000 psi to set Baker SAB packer. Bleed off 7" tubing, and test 7" tubing hanger seals. 25. ND BOPE and 11", 5M adaptor spool. NU 11", 1 OM tubing head and 11", 1 OM x 13%", 5M adaptor spool. NU BOPE. Upper pipe rams are still equipped with single variable-bore pipe rams and lower pipe rams are equipped with 4" pipe/' rams. Set test plug in new tubing head, test BOPE as needed to 250/5000 psi. Pull test plug. 26. PU rerun 6¼" mill tooth bit and TIH. Tag landing collar. Test 7" tubing to 5000 psi. Drill out float and cement to CIBP at +10,150'. Retest 7" tubing to 5000 psi. Drill up CIBP and push remnants to 12,000'. J. G. Eller- July 31, 2003 ( Well 41-15, Workover Procedure WBS - WO.03.09182.EXP Page 5 27. TIH with 4" workstring to + 11,800'. Clean out mud pits and blend 500 bbl of kill-weight CaC12 brine. (Note: Estimated formation pressure of the Tyonek interval is 10.6 ppg.) Also, blend a bbl Cleansweep pill. Swap the hole over to brine by circulating the Cleansweep pill and CaC12 brine at maximum rate until the returns clean up. TOH. 28. 29. 30. PU 7" RTTS and TIH. Set RTTS at 11,080'. Bullhead "~ omplet!9~::~md works~ng to bre~ down the Tyonek perfs at 11,121' - 11,1 other perfs above the RTTS. Release RTTS ~d move RTTS abo~e' al!"T:yonek...~.:' :.... perfs. ·.....' f ... ,. ' .',.~..'.. Squeeze Tyonek perfs 10,942'-11,136' /' · ' 31. POOH, LD RTTS. .. ,. 32. Drill out squeeze perfs, test. Drill out CiBp,.pUsh remnants to 11;800'. · :. , 33. TOH laying down 4" work string;::' · '"" '"' '" '"""""' ' '.'.: "... 34.'.Install'BOPE.test plugi'and'close..blind rams'..' :!nstal! 2%~;.5M pipe.rams in upper · .'.!:set of finS. Test BOPE.'as.needed to 250/5000 psi.."":open blindS, and'pull test ;plug~ · '... ..':i' '".' · · .....~.. ~)"'~ '. ., · .. ., :: . ':. .' .. ,, . .. ... · . · , . . . . . · .. · 35...RU elevators~:.slips, andt0ngs for running.2[~'.', tUbing-c'°nveyed guns followed by .. 2¼", 4.7#; EUE 8rd tubing.' Lay out,ltally}'and rabbit 11,000' of 2%"tubing. TIH ·" with completion, assembly, as follows: ..... :. a. 4%".',.6 spfTCP .guns (gross Tyonek interval = 11,290' - 11,331') b. Gun release assembly c. 1.jnt of2%", J-55'tubing d. RA tag e. 1 jnt of 2¼", J-55 tubing f. X-nipple assembly (ID = 1.875", with handling pups) g. __jnts of 2Vd', J-55 tubing h. __jnts of 2¼", L-80 tubing i. Baker chemical injection nipple (with dual-check injection valve and ¼- inch stainless steel control line banded to surface. Also with handling pups. Position injection nipple at +2300') j. '~3l ~' ~-/~ , L-80 tubing to surface. k. Space-out pups (2¼", L-80) 1. Tubing hanger pup with 4' of carbide blast rings installed immediately below the tubing hanger J. G. Eller- July 31, 2003 Well 41-15, Workover Procedure WBS - WO.03.09182.EXP Page 6 m. Vetco tubing hanger 36. MIRU Schlumberger. RIH with GR/CCL log. Tie in to AIT log of 12/26/1998. Determine pipe movement necessary to put guns on depth. POOH, RDMO Schlumberger. 37. Install spaceout pups on 2%" tubing and land 2%" tubing. Install Bpv~. Test tubing hanger seals. ND BOPE. NU 2", 10M tree. Pull BPV, set 2~waY check; . Test packoff and tree as per Vetco procedure. Pull 2-way RDMO workover rig. .. 38. Pull BPV. .. " · . . . 39. MIRU lubricator for dropping TCP firing bar. Conduct prejob safety:meeting and. test BOPE. Drop bar to fire guns monitoring tubing pressure. Perforate Tyonek: .-' interval with 4%", 6 spf, 60° phase guns as follows: '..".. · . .. ... .. 11,290' - 11,296' .. .. .. . 11,305' - 11,316' .. ". · '..'. · . · .' 11,322' 11,331' (Note:.G...~.:.are design_ ed.lto, release and' drop.~to .the..'boi~om of th.e:.h01e, upon · ." fidng; :·.Length' of 4V8'.' gun assembly in hole.'=. '." '..)'. ,-.Pd2)MO TCP.firing assembly:,'.......:. · · . . . . . ~[01"'Mmu 'B~"ni~6gen pUmPing'unit onto annulus. RU return.line off of 2%" tubing. · .'Conduct.prej0b safety.meeting and test'lines..to'.5000 ipsi. Circulate nitrogen down · the annulus; taking CaxC12 'returns off of.the tubing. Maximum anticipated surface .pressure = 3950.psi. ~4aaticipated recovery.= 389 bbl. When full volume of completion, fluid is recovered, shut in returns and pressure well with nitrogen to 4000 psi.... RDMO nitrogen unit. .. 41. MIRU BJ· fracture stimulation equipment onto SU 41-15. Run two 4", 1 OM pumping:lines to the 4'?, 1 OM annulus valves. RU flowback iron to the 2%" tubing. The 2%" tubing will serve as a deadstring during fracture operations. Conduct prejob safety meeting and test stimulation lines to 10,000 psi. Test flowback iron to 5000 psi. Fracture stimulate Tyonek interval as per separate procedure. RDMO fracturing equipment. Flow back well SU 41-15 to flowback equipment through 2%" tubing until adequately cleaned up. Produce to sales as per instructions of Production Engineer. J. G. Eller- July 31, 2003 APl: 50-133-20484 AOGCC: 98-41 KB-GL: 29.71' (original KB) 437' FEL, 2327' FSL Sec. 9, T5N, R10W, S.M. 4.75" Otis tree cap Lift threads - 3.161" MCA Equipped with 10K wellhead and 4", 10K valves for frac stimulation via 2- 3/8" x 7" annulus. Active 15errs (Tyonek Sand) 10,942'-10,955' (proposed squeeze) 11,034'-11,044' (proposed squeeze) 11,121'-11,136' (proposed squeeze) 11,290'-11,296' (proposed frac) .~ 11,305'-11,316' (proposed frac) 11,322'-11,331' (proposed frac) SU 41-15 Proposed J PBTD 12,940' TD 12,600' 20", K-55 Drive pipe @ 58' I 13-3/8", 61 ppf, K-55, BTC surface casing @ 2271' Cmt with 1186 sks of class G 7" Tubin.q Strin.q 7", 26 ppf, P-110, BTC-M tubing to 10,108' Baker SAB 194-73 permanent packer @ 8200' 7" cemented in place 8600'- 10,108' 10' Tieback seal assy @ 10,108' 7" ZXP liner-top packer @ 10,108' with 10' tieback sleeve 2-3/8" Tubing String 2-3/8", 4.6 ppf, L-80 & J-55, EUE 8rd to 11,290' 4' of carbide blast rings immediately below tubing hanger chemical injection nipple @ 2500' w/1/4" control line 4-5/8" TCP guns with auto-release assy, 11,290' - 11,331' (gross interval) 9-5/8", BTC casing @ 10,312' 0' - 3083', 53.5 ppf, P-110' 3083' - 9866', 47 ppf, P-110 9866'- 10,312', 47 ppf, L-80 Cmt with 2284 sks of class G 7" ZXP liner-top packer @ 10,108' 7", 29 ppf, L-80, BTC liner @ 10,108' - 12,590' Cmt with 708 sks of class G Well Name & Number: SU 41-15 Proposed Lease I Sterling Unit, Tyonek Pool Countyor Parish: Kenai Peninsula I State/Prov. Alaska I Country: I USA Perforations: (MD). (TVD) I Date Completed: I RKB: Prepared By: J.G. Eller I Last Revision Date: 06/19/031 Sterling Field Well SU 41-15, Pad 43-9 Marathon Oil Co. Alaska Reaion APl 50-133-20484 KB-THF: 30.00' KB-GL: 29.71' 437' FEL, 2327' FSL Sec. 9, T5N, R10W, S.M. CMU Sliding Sleeve @ 8751' wi X-profile (ID = 2.313") (closed 2/15/99) Baker model GT Dual Packer @ 8820' Beluga Sand p~rf's 9440' - 450' 9616' - 640' 9674' - 682' 9694' - 704' 9722' - 736' qB00' - 812' ., '00Y- 01,4' _..? 317'- 0,26' ~eluga pay from 9440' - 9812' was fracture stimulated with 74,500 lbs of 20/40 EeonoProp on 1/9/99. X-Nipple @ 9760' ID = 2.313 Re-Entry Guide @ 9770' Note: Tagged fill at 9792' on shortstring (8/23/99) Halliburton TruGuide injection mandrels w/1/4" (0.049" wall) injection line SS @ 822' LS @ 944' 1" injection valves installed 2/99 20", K-55 Drive Pipe @ 58' 13-3/8", 61#, K-55, BTC Casing @ 2271' Cmt w/1186 sks of class G Tubing (Shortstring & Longstring) 2-7/8", 6.5#, L-80, AB-Mod EUE 8rd Steel Blast Joint (OD = 3..500") LS 9437'-455' 9616'-643' 9668'-739' 9795'-822' 9996'-033' SS 9436'-456' 9611'-749' 7" Liner Top @ 10108' wi ZXP liner-top packer 9-5/8", BTC easing @ .10312' 0'- 3083': 53.5#, P-Il0 3083' - 9866" 47#, P-Il0 9866' - 10312': 47#, L-80 Cmt w/2284 sks of Class Note: Apparent corkscrewed tubing at 10,040' Baker model "D" Packer @ 10847' T.y'0nek Sand Perfs ~ 10,942' - 95'5' (4-5/8", 6 spf, 5' StimGun)~ ~ ~ 11,034' 044' (4-5/8", 6spf, 5' StimGun) t ki.~L~ '~.~11,121' 13.6' (4-5/8", 6 spf, 3' StimGun) ~' ,.,-- r',~V ~,I1,290 296' (4-5/8", 6 spf, no StimGun) ,'11,305' 316' (4-5/8", 6 spf, 5' StimGun) '~ : ',322' - 331' (4-5/8', 6 spf, 6' StimGun),~._a' Last Rev: IGE, 6/21/00 PBTD = 12,490' TD = 12,600' Shock absorber. @ 10865' X Nipple @ 10902' ID = 2.313" C_c, ,\ %~ --'F~64~-e-l,,o.k.e-4 a.s.t.M-l~d-3.k7400~. End of Tubing @ 10940' Top of Fill: 11,993' (3/6/00). Fish: 402' of 4-5/8" TCP gu. ns dropped to the bottom of the hole after perforating. 7", 29#, L-80, BTC liner @ 10108'- 12590' Cmt w/708 sks Marathon Oil Well SU 41-15 BOP Stack IFIow Nipple I ~ / IFIow Line I I 13 5/8" 5M Annular Preventer 13 5/8" 5M Double Ram Preventer i [Pipe Ram I IPipe Ram I [3 1/8" 5M Manually [Operated Valve 13 5/8" 5M Single Ram Preventer 2 1/16" 5M [ ~'~ IBlind Ram I '~ '3 1/8" 5M Hydraulically \ IOperated Valves ~~ !~hoke ,['~~~ Marathon OilCompany Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 January 7, 2003 Mr. Tom Maunder State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Reference: Field: Sterling Unit Field Well: SU 41-15L Regarding: Report 10-404 Submittal Dear Mr. Maunder We have completed the coiled tubing acid stimulation of the Tyonek completion in SU 41-15L. A daily operations summary has' been included for your review. The Tyonek completion was shut in prior to the stimulation and has been shut in again as the job was not successful. If you have any questions or require further information, I can be reached at 907-564- 6318 or by e-mail at DEEynon@MarathonOil.com. Sincerely, Donald Eynon Production Engineer Enclosure: Daily Operations Summary RECEIVED ,.JAN 0 9 2005 Alaska Oil a Gas Cons. CommissiOin, Anchorage g:\cmn\drlg\kgflwells\ku 11-8s~,OGCC01a.xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation Shutdown Stimulate X Plugging Pull Tubing Alter Casing Repair Well Perforate Other 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 2327' FSL, 437' FEL, Sec. 9, T5N, R10W, S.M. At top of Productive Interval 137' FNL, 2401' FEL, Sec. 15, T5N, R10W, S.M. at 9440' MD At Effective Depth IAcidized Tyonek Perfs with 7.5% HCI At Total Depth 1080' FNL, 1049' FEL, Sec. 15, T5N, R10W, S.M. 5. Type of Well: Development X Exploratory __ Stratigraphic Service 6. Datum Elevation (DF or KB) 29.71 feet KB-GLI 7. Unit or Property Name Sterling Unit 8. Well Number SU 41-15L 9. Permit Number 98-41 10. APl Number 50-133-20484-00 11. Field/Pool Sterling Field, Tyonek Pool 12. Present Well Condition Summary Total Depth: measured true vertical 12,600 feet Plugs (measured) 10,559 feet Effective Depth: measured true vertical 12,490 feet 10,455 feet Junk (measured) 11,946', TCP guns dropped after perf. Fill at 10,947' KB, MD Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: measured true vertical measured true vertical Length Size Cemented Measured Depth True Vertical Depth 58' 20" Driven 58' 58' 2271' 13 3/8" 1186 sks 2271' 2270' 10312' 9 5/8" 2284 sks 10312' 8544' 2482' 7" 708 sks 12590' 10550' Tubing (size, grade, and measured depth) LS - 10942' - 955', 11034' - 044', 11121 '-136', 11290'-296', 11305'-316', 11322'-331' MD LS- 9055'-066', 9133'-141', 9208'-221', 9355'-360', 9368'-378', 9383'-391' TVD SS- 9440'-450', 9616'-640', 9674'-682', 9694'-704', 9722'-736', 9800'-812', 10003'-014', 10017'-026'MD SS- 7905'-912', 8031'-048', 8072'-078', 8087'-094', 8107'-117', 8162'-174', 8309'-317', 8319'-326' TVD Longstring: 2-7/8", 6.5#, L-80 tubing to 10,940' Packers and SSSV (type and measured depth) Baker model GT Dual packer @ 8820' MD Baker model "D" Packer @ 10847' MD 13. Stimulation or Cement Squeeze Summary Intervals Treated (measured) LS- 10942'-955', 11034'-044', 11121'-136', 11290'-296', 11305'-316', 11322'-331' MD Treatment Description Including Volumes Used and Final Pressure 1500 gallons of 7.5% HCL/methanol mixture 14. Representative Daily Average Production or Iniection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Prior to Well Operation 0 0 0 0 (Note: Prior/subsequent volumes are for the specific intervals treated, not the well as a whole.) Subsequent to Operation 0 0 0 0 Tubing Pressure 1750 0 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations 16. Status of Well Classification as: Oil Gas X Suspended Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~z~'~~ F~ Form 10-404 Rev. 06/1 Donald Eynon Title Production Engineer JAN 9 2003 Date 01/07/03 .,,,,.,mit in Duplic;~ Summary of SU 41-15L Coiled Tubing Acid Treatment Dec. 17, 2002- RU BJ Coiltech, flow back iron, choke skid, and diffuser tank. Dec. 18, 2002- Finish RU ofBJ Coiltech, pickle coiled tubing with 300 gallons of 7.5% HCL, test BOP's, RIH to with 2" nozzle to 10,935' tag up solid, could not circulate out. Establish injection rate of.5 bpm at 3940 psi. POOH to change CT nozzle to 1.75". Blow 5 bbls methanol mixture and N2 through coil tubing, SWIFN. Dec. 19, 2002- RU BJ Coiltech, test BOP, RIH with 1.75" CT nozzle to 10,945', tag up solid, will not circulate off. Roll acid and prepare to spot. Spot 1500 gallons of 7.5% HCL/methanol mixture. Displace acid with 41 bbls of 6% kcl. Attempt to j et in well with N2, recovering muddy water and fines. Dec.20, 2002- POOH with CT to 9,250', RIH jetting w/N2, tag at 10,300', will circulate out. POOH with CT. Fill tubing with 50 bbls of 3% kcl, and shut in with 1760 psi. RD BJ Coiltech. Dec.21, 2002- RU BJ Coiltech, RIH with CT and circulate out fill to 10,946'. POOH with CT keeping hole full of 3% kcl. Shut in well. Blow down CT with N2. RDMO BJ Coiltech. Sterling Unit 41-15 well Maunder, Thomas E (DOA) • Page 1 of 1 From: Eynon, D E (Don) [DEEynonQMarathonOil.com] Sent: Saturday, December 14, 2002 2:59 PM To: Tom Maunder (E-mail) Cc: Barron, William C.; Etter, Jahn G.; Titus, Denise M.; Cisselt, Wayne E.; Erwin, Donald R.; McKibbon Jr, E A (Earl); Schemanski, Raymond L.; Gagnon, Roland M.; Wotf, Wittiam t_.; Bowen, R M (Bob); Bookey, Shannon T. Subject: Sterling Unit 41-15 well Attachments: Eynon, D E (Don).vcf 1 Tam, Here is an operational summary of our analysis of Sterling Unit 41-15 as we discussed Dec. 13th, 2002. SU 41-15 has recently had pressure on the annulus which we suspected to be from the short string sliding sleeve to the short string tubing/production casing annulus. In evaluating the problem we have diagnosed that the problem may be from the sliding sleeve and the packer. First we set a plug in the short string tailpipe below the packer and bled down the pressure in the short string and the tubing/production casing annulus 200 psi. Overnight both the short string tubing and the tubing/production casing annulus built back up to shut-in pressure of 2150 psi. An isolation sleeve was then run in and set over the short string sliding sleeve, followed by bleeding dawn the short string tubing to 950, which held for 1 hour, indicating short string tubing integrity with the isolation sleeve in place. The isolation sleeve and the tubing tail plug were then pulled, followed by running back in and setting the isolation sleeve across the short string sliding sleeve. When the short string Beluga perforations were put back on production the tubing/production casing annulus pressure dropped with the welt head pressure an short string. Throughout this procedure the shut in Tyonek tang string pressure was at 1750 psi. The production casing/surface casing annulus has no pressure on it. We have had no indications in the past of any communication between the long string Tyonek completion and the rest of the wellbore. We will continue with our planned coifed tubing acid stimulation of the long string Tyonek completion starting Tuesday, December 17th, as per your approval in our phone conversation December 13th, 2042. tf you have any questions please colt or email. Don Eynon Production Engineer Marathon Oil Company Alaska Business Unit Telephone 907-564-6318 «Eynon, D E (Don}.vcf» c~~~`~ c~ Q~~co 10/16/2007 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Suspend Operation Shutdown Alter Casing Repair Well Plugging Change Approved Program Pull Tubing Variance 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchora~ge, AK 99519-6168 4. Location of Well at Surface ,,/ .j/ ../" 2327' FSL, 437' FEL, Sec. 9, T5N, R10W, S.M. At top of Productive Interval 137' FNL, 2401' FEL, Sec. 15, T5N, R10W, S.M. at 9440' MD At Effective Depth [Acidize Tyonek Perfs with 7.5% HCI! At Total Depth 1080' FNL, 1049' FEL, Sec. 15, T5N, R10W, S.M. 5. Type of Well: Development X Exploratory Stratigraphic Service Re-enter Suspended Well Time Extension Stimulate X Perforate Other 6. Datum Elevation (DF or KB) 27.8 feet 7. Unit or Property Name Sterling Unit 8. Well Number SU 41-15 9. Permit.~gmber 98-41" 10. APl Number 50- 133-20484 ~/' 1. Field/Pool Sterling Field, Beluga and Tyonek Pool 12. Present Well Condition Summary Total Depth: measured true vertical 12,600 feet 10,559 feet Plugs (measured) N/A Effective Depth: measured true vertical 12,490 feet Junk (measured) 10,455 feet 11,946', TCP guns dropped after perf. Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: measured true vertical measured true vertical Length Size Cemented Measured Depth True Vertical Depth 58' 20" Driven 58' 58' 2271' 13 3/8" 1186 sks 2271' 2270' 10312' 9 5/8" 2284 sks 10312' 8544' 2482' 7" 708 sks 12590' 10550' Tubing (size, grade, and measured depth) LS-10942'-955',11034'-044',11121'-136',11290'-296',11305'-316',11322'-331' MD LS-9055'-066',9133'-141',9208'-221',9355'-360',9368'-378',9383'-391'TVD SS- 9440'-450', 9616'-640',9674'-682', 9694'-704', 9722'-736', 9800'-812',10003'-014',10017'-026'MD SS- 79~5~~912'~8~31'~~48'~8~72~~~78'~8~87'-~94'~81~7'~117'~8162'~174'~83~9'~317'~8319'~326'TVD Longstring:2-7/8",6.5#,L-80tubingto 10940' MD Packers and SSSV (type and measured depth) Baker model GT Dual packer @ 8820' MD Baker model "D" Packer @ 10847' MD 13. Attachments Description Summary of Proposal Detailed Operations Program X BOP Sketch 14. Estimated Date for Commencing Operation 12/17/2002 16. If Proposal was Verbally Approved Name of Approver Date Approved 15. Status of Well Classification as: Oil Gas X Service Suspended 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Date 12/10/2002 FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so representative may witness5¢"~ ~' ~:~¢,-~ '~.%'~-J~-~r~%'~ IAppr°val No. Plug Integrity BOP Test .~ Location Clearance ~r.~- -,..~ '? ~ Mechanical Integrity Testm Subsequent Form Required 10- ~ ~-.-~ L~, Approved by Order of the Commission Form 10-403 Rev. 06/15/88 r BD lS BFL ORIGINAL SIGNED BY M L. Bill Commissioner Date Su~rnit'i'n Triplicate DEC 12 2002 Well SU 41-15L WBS Sterling Unit Stimulation Procedure Objective: Utilize BJ coiled tubing to acidize the Tyonek interval of SU 41-15L using 3000 gallons of 7.5% HC1 mixture to re-establish production. Procedure: , Survey location with BJ personnel and confirm possibility of installing CT unit above well house. Review acid and flow back tankage needed for job and matting requirements for installation under all tanks and pumping equipment. . MIRU 13/4'' BJ coil tubing, pumping, and nitrogen equipment. SU 41-15S should be shut- in and built to full surface pressure (approximately 2250 psi). RU flowlines and choke manifold to clean returns tank. Blend 100 bbls of 6% KC1 brine (requires 22 lbs of KC1 per barrel of water) in suction tank. Pressure test BOPE to 250/5000 psi using fresh water or KC1 water. Pressure test pump discharge lines and coil to 6000 psi. 3. Pump 2 bbl of inhibited 7.5% HC1 acid through coil tubing to pickle pipe. Displace acid with water to returns tank. Neutralize acid with soda ash as needed. . In a clean poly tank, blend 71.5 bbl (3000 gallons) of 7.5% HC1 with additives (5% ammonium chloride base + 10% methanol + 4 gpt CI-27 + 1 gpt NE-118 + 1 gpt Inflo- 150 + 29 pptg Ferrotrol-300). All MSDS forms should be on file with the KGF operator and BJ Acidizing crew. Proper PPE includes rubber apron, gloves, face shield, and half- mask air purifying respirator. Titrate acid to verify proper concentration. Collect samples of acid blend for analysis. o RIH with standard jet wash nozzle to 10,000', fill hole w/6% KCL if not already full. Shut in CT annulus and attempt to establish injection at 1.2 bpm and a maximum CT annulus well head pressure of 4500 psi. Note: The maximum treatment pressure may be reduced pending tubing movement analysis from Baker Oil Tools. Establish PU and RI weights. o RII-I past "buckled" spot in pipe at 10,040' MD and establish PU and RI weights again. RIH to 11,400' to confirm PBTD is below perforations. Open CT annulus to flow back tank. Well SU 41-15L Acidizing Procedure Page 2 . PU to 11,330 and spot acid to top perforation at 10,942' (coil volume plus 13.25 bbls). Shut in the CT annulus, POOH at 16 fpm pumping 7.5% HC1 at 1.2 bpm and a maximum CT annulus well head pressure of 4500 psi. RIH at 16 fpm pumping 1.2 bpm back to 11,330 while pumping remaining acid. When out of acid pump 29 bbls 6%KCL to displace acid to end of coil. Open annulus to flow back tank. Start nitrogen at 1200 scfm with coil at 11,330', when nitrogen rounds end of coil POOH pumping nitrogen to unload well and initiate flow. 8. Monitor returns to obtain acid samples at beginning and end of acid recovery in Nalgene containers. 9. Monitor returns for LEL's. Continue jetting until returns are dry or until well appears to be flowing on its own. Shut down nitrogen and monitor flow while POOH. 10. If well dies or does not flow, RIH jetting with nitrogen to attempt recovery of more load fluid and initiate flow. If liquid returns are recovered check for pH and/or acid strength. DEE - December 11, 2002 Sterling Field Well SU 41-15, Pad 43-9 Marathon Oil Co., Alaska Region API 50-133-20484 KB-THF: 30.00' KB-GL: 29.71' 437' FEL, 2327' FSL Sec. 9, T5N, R10W, S.M. CMU Sliding Sleeve @ 8751' w/X-profile (ID = 2.313") (closed 2/15/99) Baker model GT Dual Packer @ 8820' Halliburton TruGuide injection mandrels w/1/4" (0.049" wall) injection line SS @ 822' LS @ 944' 1" injection valves installed 2/99 20", K-55 Drive Pipe @ 58' 13-3/8", 61#, K-55, BTC Casing @ 2271' Cmt w/1186 sks of class G Tubing (Shortstring & Longstring) 2-7/8", 6.5#, L-80, AB-Mod EUE 8rd Beluga Sand Perfs 9440'-450' 9616'-640' 9674'-682' 9694'-704' 9722'-736' 0800'-812' '003' - 0}4' ~ )17'-~26' X-Nipple @ 9760' ID = 2.313 Re-Entry Guide @ 9770' ~eluga pay from 9440' - 9812' was fracture stimulated with 74,500 lbs of 20/40 EconoProp on 1/9/99. Note: Tagged fill at 9792' on shortstring (8/23/99) Tyonek Sand Perfs 10,942'- 95'5' (4-5/8", 6 spf, 5' StimGun)' ';. 11,034' 044' (4-5/8' 6 spf, 5' StimGun). -... 11,121'- 136' (4-5/8", 6 spf, 3' StimGun) 11,290'- 296' (4-5/8", 6 spf, no StimGun) 11,305'- 316' (4-5/8", 6 spf, 5' StimGun) ',322' - 331' (4-5/8", 6 spf, 6' StimGun)~. Last Rev: JGE, 6/21/00 PBTD = 12;490' TD = 12,600' , , Steel BlastJoint(OD = 3..500") LS SS 9437'-455' 9436'-456' 9616'-643' 9611'-749' 9668'-739' 9795'-822' 9996'-033' 7" Liner Top @ 10108' w/ZXP liner-top packer 9-5/8", BTC casing @ 10312' 0'-3083': 53.5#, P-110 3083'-9866':47#, P-Il0 9866'- 10312': 47#, L-80 Cmt w/2284 sks of Class G Note: Apparent corkscrewed tubing at 10,040' Baker model "D" Packer @ 10847' Shock absorber @ 10865' X Nipple @ 10902' ID = 2.313" End of Tubing @ 10940' Top of Fill: 11,993' (3/6/00) Fish: 402' of 4-5/8" TCP guns dropped to the bottom of the hole after perforating. 7", 29#, L-80, BTC liner @ 10108' - 12590' Marathon Oil Company Mr. Tom Maunder AOGCC 333 West 7th Ave. Suite 100 Anchorage, AK 99501 Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 9071561-5311 Fax 9071564-6489 December 10, 2002 Dear Mr. Maunder: Attached is an application for sundry approval for a coiled tubing acid stimulation treatment of the Tyonek interval in well SU 41-15L, in the Sterling Unit. The treatment is based on Tyonek core testing performed by BJ. Sorry for the short notice of the job. We propose commencing operations on Dec 17th, 2002, pending your approval. Please contact me at 564-6318, or email at DEEynon@MarathonOil.com. Sincerely, Donald Eynon Production Engineer RECEIVED DEC 1 1 2002 Alaska Oil & Gas Oons. Comraission Anchorage SU 41-15 Workover Subject: SU 41-15 Workover Date: Thu, 25 Jul 2002 16:03:04 -0800 From: "Affinito, Ralph J." <RJAffinito@MarathonOil.com> To: <tom_m aunder@adm in.state.ak, us> CC: "Eynon, D E (Don)" <DEEynon@MarathonOil.com> Tom, Pursuant to our telephone conversation this e-mail is to confirm that we did not commence workover operations on the SU 41-15 well which we submitted for sundry approval dudng 2001. Please call if you require any additional information.. Sincerely, Ralph J. Affinito Marathon Oil Company - Alaska 907-564-6303 1 of 1 7/25/2002 4:02 PM AI_JtSKA INDIVIDUAL WELL PRODUCTION AS OF 07/23/2002 WELL-NAME: STERLING UNIT FIELD/POOL: STERLING, BELUGA UNDEFINED 1999 JAI~ FEB MAR APR METH FLOWING DAYS 2 OIL WTR 190 GAS 3,253 1999 TOTALS OIL WATER 328 2000 JAN FEB MAR APR METH SHUT- IN SHUT- IN SHUT- IN SHUT- IN DAYS OIL WTR GAS 2000 TOTALS OIL WATER 2001 JDRq FEB MAR APR METH SHUT- IN SHUT- IN SHUT- IN SHIIT- IN DAYS OIL WTR GAS 2001 'TOTALS OIL WATER 45 2002 JAN FEB MAR APR METH FLOWING FLOWING FLOWING FLOWING DAYS 1 24 24 29 OIL WTR 1 28 55 40 GAS 1,549 2,685 15,023 20,395 2002 TOTALS OIL WATER 410 FIELD/POOL: STERLING, TYONEK UNDEFINED 1999 JAN METH DAYS OIL WTR GAS 1999 TOTALS OIL 2000 JAN METH FLOWING DAYS 9 OIL WTR 121 GA _ 0 FEB MAR WATER FEB MAR SHUT-IN SHUT-IN 41-15 API: 133-20484-00 LEASE: FEDA028063 OPERATOR: MARATHON OIL CO SALES CD - 76 ACCT GRP - 003 ** GAS PRODUCTION ** FINAL STATUS: DEV 2-GAS CURRENT STATUS: WATER MAY JUN JUL AUG SEP OCT NOV SHUT-IN SHUT-IN FLOWING FLOWING SHUT-IN SHUT-IN SHUT-IN 14 8 138 15,842 8,198 GAS 27,293 CUM OIL CUM WATER 328 CUM GAS OCT NOV SHUT-IN SHUT-IN MAY JI3N JUL AUG SEP SHUT-IN SHUT-IN FLOWING SHUT-IN SHUT-IN 1 842 GAS 842 CUM OIL CUM WATER 328 CUM GAS MAY JIIN ~ AUG SEP OCT NOV SHUT-IN SHUT-IN SHUT-IN FLOWING SHUT-IN FLOWING FLOWING 4 41 GAS 25 173 CUM OIL ~ 3,956 3,666 5,009 , ~ CUM WATER 373 CUM GAS MAY JI3N FLOWING FLOWING 31 30 DEC 87 28,066 GAS 27,293 DEC SHUT- IN 28,135 DEC FLOWING 30 12,542 53,308 JUL AUG SEP OCT NOV DEC 199 30,929 98,647 CUM OIL CUM WATER 783 CUM GAS SALES CD - 76 ACCT GRP - 003 FINAL STATUS: DEV 2-GAS CURRENT STATUS: ** GAS PRODUCTION ** 151,955 APR MAY JI3N JUL AUG SEP OCT NOV DEC FLOWING FLOWING SHUT-IN FLOWING SHUT-IN FLOWING FLOWING FLOWING FLOWING 1 1 1 1 2 17 2 AUG SHUT- IN 50 24 95 2,840 917 73,618 CUM WATER 176 CUM GAS 4,019 176 7 12,615 96,851 830 2,012 GAS 96,851 CUM OIL APR MAY JUN JIJL FLOWING SHUT-IN FLOWING FLOWING 1 1 1 1,150 444 95 212 745 GAS 44,520 CUM OIL SEP OCT NOV DEC FLOWING FLOWING FLOWING FLOWING 5 23 22 31 59 169 3,634 153 90 CUM WATER 620 CUM GAS 86 141,371 AIJ~SKA INDIVIDUAL WELL PRODUCTION AS OF 07/23/2002 2001 JAN METH SHUT- IN DAYS OIL WTR GAS 2001 TOTALS 0IL 2002 JAN METH SHUT- IN DAYS OIL WTR GAS 2002 TOTALS OIL FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN FEB SHUT-IN WATER GAS CUM 0IL MAR APR MAY JUN JUL SHUT-IN SHUT-IN SHUT-IN SHUT-IN WATER GAS CUM OIL AUG CUM WATER SEP CUM WATER 620 OCT 620 CUM GAS NOV CUM GAS 141,371 DEC 141,371 Tubingless/Annular Flow Wells i' Subject: TubinglesslAnnular Flow Wells Date: Tue, 07 May 2002 17:27:07 -0800 From: Tom Maunder <tom_maunder@admin.state.ak. us> To: Gary Eller <jgeller@marathonoil.com> Gary, I have been working to clear out a backlog of long submitted sundry applications. One concerns a well of yours, SU 41-15. When Blair was still hear, I remember working on a well that you wanted to make tubingless. The formation pressures in that well were Iow ~350 psi and for ultimate recovery purposes, it made sense to allow that work. For 41-15 the pressure situation was different (~2000 psi) and we did not approve that application. As I was getting the documentation ready to send that application back denying approval, I thought I would inquire as to what the current situation is with regard to tubingless/annular flow wells. I have a copy of an email you sent Blair on Oct 10, 2000 that summarized the 9 wells that had then been converted to annular or tubingless flow. Could you provide an update on the well count and performance?? The wells listed at that time were: KU 21-61, KDU-51, KU 14-321, KU 11-8s, KU 24-5s, KU 43-6al, KU 1461, KU 13-61 and BC-9s. Drop a note back. I can fax a copy of the email if you'd like. Thanks. Tom Tom Maunder <tom maunder@admin.state.ak, us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 of 1 5/7/02 5:28 PM I-'ropose(:l Pump-In JOD on Well ~U 41-1 DS :i Subject: ~roposed Pump. In ,lob on Well 81.1 41.155 ~at,: Wed. ~ $ Jun 200'1 11 :$0:3~ -0800 From: "Eller, J Ga~" <JG£11er@MamthonOil.¢om> To: "Tom Maunder (E-mail)" <tom_maunder@admin.state.ak.us> Tom -As we discussed today, Marathon is proposing to pump a volume of diesel into well Sterling Unit 41-15s (Beluga Sand) within the next week or so. You suggested I write an e-mail to keep you informed although this operation probably does not require a formal sundry notice. Perhaps 200 bbl of diesel (volume still being discussed) will be displaced with nitrogen into the perfs. The purpose of this job is to try to clean up the fmc that was pumped in January 1999. The fmc gel breaks in the presence of hydrocarbons, although pure methane breaks it poorly. We have reason to believe the gel is still unbroken, and we hope we can improce fmc conductivity by pumping the diesel. Following the pumping job we'll flow back to an atmospheric tank until the well cleans up, This operation should not require coil tubing. I will inform you prior to mobilizing coil if the need arises. Please let me know if further information is needed. J. Gary Eller Operations Engineer Alaska Region, Marathon Oil Company 907-564-6315 1 of 1 6/14/01 3:33 PM ,, Jun-19-01 11:5Tam From-MARATHON OIL +9155648489 T-435 P.02/05 F-126 Alaska F~ .n Domestic Production Marathon Oil Company Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 West 7th Ave Suite 100 Anchorage, AK 99501 RE: Packerless completion on well SU 41-15 Permit Number: 98-41 Lease Designation Number; A-028063 APl Number', 50-133-20484 P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 RECEIVED JUN 1,1 2001 Mr. Tom Maunder, We plan to commence workover operations on the SU 41-15 in the Sterling Gas Field on approximately July 1, 2001, Currently the well has water to surface on the Tyonek (long string) and the Beluga production is plagued by solids production and unbroken frac gel which prevents production due to solids contamination and damage of surface treating facilities. The objective of this workover is to: · Isolate and repair possible Beluga/Tyonek hydraulic communication within the wellbore. · Evaluate the Tyonek intervals for suspected water production and remedially isolate problematic intervals returning the Tyonek to production. · Set up the well to facilitate repair of the Beluga interval. This would be for a remedial fracture stimulation and/or post-frac clean up treatment to mitigate solids production and re-establish Beluga production, The proposed completion consists of: · 2-7/8" 6.5 ppf L-80 tubing and a packer to facilitate tubing flow production from the Tyonek interval. · open ended 2-7/8" 6.5 ppf L-80 tubing to facilitate production from the Beluga interval without a dual packer, Refer to the attached proposed wellbore schematic, The approximate SBHP's are Tyonek - 5058 psia and Beluga - 3711 psia, The existing 5K tubing head.will be replaced with a 10K psig tubing head with dual 3-1/8" 10K valves on each side, This tubing head is specifically designed to facilitate a potential re-frac of the Beluga interval. Beluga production will be via the 2-7/8" open ended tubing. The original dual 2-9/16" ,5,000 psig tree will be installed on the tubing head. Tubular production from the Tyonek are identical to the current arrangement. The Beluga completion will however allow reservoir pressure to contact the tubing head and the 9-,5/8" A subsidiary of USX Corporation Environmentally aware for the long run, Jun-13-01 11:57am From-I~AI~ATHOPI OIL +9155646489 T-435 P.09/05 F-lZ6 casing directly below surface. Analysis of the surface pressures anticipated on the wellhead follows. Shut-in Beluqa Production Under normal SI conditions it will be possible for the surface pressure to reach 3184 psig_ This is assuming a gas gradient of 0.065 psi/ft from surface to the mid peff interval of 8115' TVD. However based upon historical pressure surveys and wellbore observation the pressure has only reached 2584 psig due to the presence of a minor liquid column. Under an isolated condition where the completion interval did not take fluid, the maximum pressure that could be reached at surface would be the SBHP of 3711 psia from the Beluga. Flowing Beluga. Production Typically Beluga production has been 1.5 MMCFGPD at 800-1200 psig FTP. Following a successful workover, the wellbore is planned to be continually produced up the open ended 2- 718" tubing. Annular production is not planned. Even if the Beluga Sand completion is successfully fracture stimulated, production would not be tubing-limited. Consequently, annular production of SU 41-15s would be unlikely to yield any increased production. Casing. !nteqrity The casing design in the SU 41-15 consists of 9-5/8" 47-53.5 ppf L-80 and P-110 as outlined in the table below. A breakdown of the maximum possible surface pressure under a catastrophio wellbore failure resulting in Tyonek gas at reservoir pressure migrating up the wellbore has been used. Note that the casing burst pressure at surface is well in excess of the internal casing pressure. Also note that the new tubing head is rated to 10,000 psig. OepiJ~ ...... Casing '"Casing ..... Casing El[~rst Max' Size Weight Grade _~100%) Pres ~J-3083 ........ . 9-5/8;'; 53.5 ppf P-110 10,900 ..5.,058 3,~83-9,866' 9-5/8 47 ppf ..... i5~i10 9,44.Q_... 5,058 '-"9';866-10,312'*" 9-5/8 ........ 47 ppf L-.~0_ 6,870 This is within the perforate/i)roducing interval. , , Please review this data in conjuction with the already submitted sundry. Your attention to this issue is appreciated. Please feel free to call for any additional information or to discuss any required changes 907,564-6315. Sincerely, ~ Production Engineer N:\D RLG\STERLIN G\SU41-15\Workove rV~r bjv nflow.doc RECEIVED JUN 1 3 2001 ~.'r 'q, ~:, .' o Jun-13-01 11:$?am F rom-MARATHON OIL +9155646489 T-43H P.O4/OS F-IZ6 API 50.133-20¢84 KB-TlqF: 30.00' KB-GL: 29.71' 437' FI3L, 2327' FSL Sec. 9, T5N, RIOW, S.M.' Sterling Field Well SU 41-15, Pad 43-9 Marathon Oil Co,, Alaska Region CMU Slidillg Sleeve @ S751' w/X.profile (ID = 2.313") (closed 2115199) Baker mod~l GT Dual Packer @ 8820' IlalliMrton TxnGuide injection mandrels w/l/4" (0.049" wall) injection line gS @ 822' LS @ 944' 1" injectio~ valves installM 2/99 20", K-55 Drive Pipe 13-3/8", 61#, K-55, BTC Casing @ 2271' Cmt wi 1186 sks of class G Tubing (Shomtring 2-7/8", 6.5#, L-g0, AB.MM PUB 8rd ..Beluga Sand Per~ 9440'-450' 9616'-640' 9674'-682' 9694'. 704' 9722'-736' 0~00'-'~12' ~o'003'.014' tO)lT. 026' X-Nipple @ 9760' ID = 2,313 Re-Bntry Guide @ 9770' Steel BlastIoint(OD ~ 3,500") LS SS 9437'.455' 9436'-4S6' 9616'-643' 9611'-749' 9668'-739' 9795'-822' 9996'-03Y ~i~laga pay from 9440' - 9812' was fractare stimulated with 74,500 lbs of 20/40 EconoProp on 119t99.. Note: Tagged fill at 9792' on ~hortstring RECEIVED JUN 13 200 O~l& Gas Oons. Con.r. ssa.'~ Anchorage 7" Liner Top @ 10108' wi ZXP liner-top packet 9-51~", BTC casing @ 1031,2' 0' - 3083': 53.5#, P-110 3083' - 9866': 47#, P-Il0 9866' - 10312': 47L L-80 Cmt w/2284 sks of Class G Note,.,,.,~ Apparent cnrkscrewed tubing at 10,040' Baker model "D" Packer @ 10847' Tyonek Sand Perf.~ 10,942' - 9~'5'~-4.5/8", 6 spf, 5' StimGun) 11,034'- 044' (4.5/8". 6 apf, 5' StimOnn) 11,121'- 136' (4.5/8", 6 spf, 3' 8timOan) 11,290' 296' (4-$18",6 spf, no StimGun) II,305' - 316' (4-518", 6 spf, 5' StimGun) Jl,322' - 331' (4-511t% 6 spf, 6' StimOun) Last Rev: JGE, 6/21/00 FBTD: 12,490' ID = 12,60D' Shock absorber @ 10865' X Sipple @ 10902' ID = 2.313" 15164" choke installed 317/00, Bnd of Tubing @ 10940' Top of Fill; I 1,993' (3/6/00) Fish'. 402' of 4-5/8" TCP guns dropped rd [he bottom of the hol~ after perforating. 7", 29~, L-80, BTC liner @ ~0108' - Cm w/708 Jun-13-01 11 :$Sam From-MARATHON OIL '[. +91 $S646489 T-4~ P.05/05 F-1Z6 6,15 ppf L-80 EUE J PROPOSEo WELLBORE J 20' 94 ppf K-SS dfive~ to 58' 13-~t8" 61 ppf K,.r~ BTC ~ 2271' ~-7m- s,s ppf L-e0 EUE 8rd 'fl~ for unloadi~l 1he annulus, RECEIVED JUN 2001 Ala~ Oil & &~s Cons. C~mmssl., Anchorage 2-?m" eue 8~1 'X' nipple wr2.3~3" ! ID 2-7/~" EUE etd 'x' nipple w/2,313" WL Re-entry guide i~tlng the ~ ~s JTyOe JWell Na~e & Number:. j Anale ~ ,KOP and Depth " .... I, .... . ........ "'} 'La~ .~: I,T 9~8" 47-53.S ppir ~110 & L-80 j~J 10312' 10942-109~' J /11 I . k 1103,4-1 i04~' ! Marathon OilCompany Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 9071561-5311 Fax 9071564-6489 Mr. Tom Maunder AOGCC 333 West 7th Ave. Suite 100 Anchorage, AK 99501 May 30, 2001 Dear Mr. Maunder: Attached is an application for sundry approval for a workover on well SU 41-15, Tyonek and Beluga sands, in the Sterling Unit. The workover consists of removing the current dual packer and permanent packer arraignment, and changing out the tubing head with one rated at 10,000 psi. The dual packer is being eliminated to enable pumping a future sand fracture treatment of the Beluga interval down the casing string. We will also be installing casing patches across the top three intervals of Tyonek perforations, and re- installing a permanent packer above the Tyonek with 2 7~8" production tubing to surface. A second production string will be installed to facilitate unloading the Beluga interval. A proposed wellbore schematic is included. We estimate commencing operations on June 18th, 2001. Please contact me, or Ralph Affinito if you have any questions. Sincerely, Don Eynon Production Engineer Intern 564-6302 O:\EXCEL~OGCC03SU41-15Sun.xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Alter Casing Change Approved Program Suspend Operation Shutdown Repair Well__ Plugging__ Pull Tubing Variance Name of Operator MARATHON OIL COMPANY Address P. O. Box 196168, Anchorage, AK 99519-6168 Location of Well at Surface v~ ~ ~ 2327' FSL, 437' FI=L, Sec. 9, T5N, R10W, S.M. At top of Productive Interval 137' FNL, 2401' FEL, Sec. 15, T5N, R10W, S.M. at 9440' MD At Effective Depth 5. Type of Well: DevelopmentX Exploratory~ Stratigraphic__ Service At Total Depth 1080' FNL, 1049' FEL, Sec. 15, T5N, R10W, S.M. 12. Present Well Condition Summary Total Depth: measured true vertical 12,600 feet 10,559 feet v/' Plug N/A Time Extensior Well Stimulate Other X Elevation (DF or KB) 27.8 feet 7. Unit or Property Name Sterling Unit 8. Well Number SU 41-15 9. Permit N~j:ober 98-41 v- lO. APl Number 50- 133-20484 11. Field/Pool Sterling Field, Beluga and Tyonek Pool Effective Depth: measu red true vertical 12,490 feet 10,455 feet (measured) 11,946', TCP guns dropped after perf. Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: measured true vertical Length 58' 20" Cemented Measured Depth True Vertical Depth Driven 58' 58' 2271' 1186 sks 2271' 2270' 10312' 2284 sks 10312' 8544' 2482' 708 sks 12590' 10550' LS - 10942' LS - 9055'-( ' 11034'-044', 11121'-136', 11290'-296', 11305'-316', 11322'-331' MD 9133'-141' 9208'-221' 9355'-360',9368'-378', 9383'-391' it~ ~'(:' F' i '~/~ -- --.,,.,..-,, ,, ~..., 13. 14. 16. 17. Tubing (size, grade, and measured depth) Longstring: 2-7/8", 6.5#, L-80 tubing to 10940' MD Packers and SSSV (type and measured dejTt~) Baker model GT Dual packer @ 8820' MD Baker model "D" Packer @ 10847' MD Attachments Descripti0?/Summary of Proposal Detailed Operations Program.._~X / I=stimated Date for Commencing O/~eration 115. Status of Well Classification as: 6/18/2OOl / I if Proposal was Verbally App:d IOi, Name of Approver ~Date Approved I Service I hereby certify that the/regoing is true and correct to the best of my knowledge. Signed ~,,,,/~/'~-t ~-'~ Don Ey noF~3 R CO MTit;;~SSiO~lrOud;;ti(~l LE;ginee r I nte rn A~ch0r;:~e BOP Sketch Suspended__ Date 5/29/2001 Conditions of Approval: Notify Commission so representative may witness Plug Integrity BOP Test Location Clearance Mechanical Integrity Test Subsequent Form Required 10-. · Approved by Order of the Commission IAPpr°va' N°' -- Commissioner Date Form 10-403 Rev. 06/15/88 Submit in Triplicate MARATHON OIL COMPANY ALASKA REGION Sterling Gas Field SU 41-15 Workover Procedure AFE # 1506001 1) 3) 4) 5) 6) 7) 8) Prepare wellhouse and wellhead for workover operations. A) Bleed off casing pressure (pressured with Nitrogen). B) Pump down LS and SS with 10.8 lb/gal Workover Fluid to kill well. C) Fill annulus with 10.8 lb/gal Workover Fluid (Workover fluid consists of CaCl2 in water, exact mixing recipe to be formulated by chemical used for CaCl2) RU APRS on LS. Pressure test Lubricator to 3500 psi. MU jet cutter and RIH to jet cut at 10,800 and POOH. MU jet cutter and RIH to jet cut at 8,830', below dual packer. Rig up Pollard Wireline on Short string. Test Lubricator to 3500 psi. RIH with a shifting tool for a 2.313" CMU sliding sleeve. Sleeve may be approx 400 psi overbalanced in favor of tubing. If needed apply pressure to annulus to equalize before opening sleeve. Open sliding sleeve at 8751'. POOH with shifting tool. RD Pollard WL. RU pump to annulus and cimulate 600 bbls 10.8 lb/gal Workover Fluid taking returns out SS. (This will ensure WO fluid above and below dual packer.) Bleed off trapped pressure on tubing stdngs and annulus. Install BPV's in both the short and long stdng tubing hangers. Have wellhead vendor prep all necessary wellhead and tree studs for removal. Disconnect flowlines and bleed off pressure. MIRU Glacier Ddlling Rig #1. Haul to location 12000' of 4" 14 Ib/ft HT-38 DP. Ddft ddll pipe to a 2.3" ID. Nipple down existing dual tree. NU BOP with upper pipe rams equipped with dual 2-7/8" rams and lower pipe rams equipped with single 4" rams. Remove BPV's and install two-way checks. Pressure test BOP to 250 / 5000 psig. Pull two-way checks. RU dual elevators. Haul to location: 20,800 of 2-7/8" 6.5 ppf EUE 8rd AB MOD tubing and full set of pup joints. PU on Short and Long stdngs and attempt to release Baker Model GT Dual packer at 8790'. Chemical Injection Mandrels are located on both LS (944') and SS (822') with %" (.049 wall) injection line. Maximum pull on single stdng of 2-7~8" 6.4 ppf AB-Mod EUE L-80 tubing is 144,960 lb (100%). Recommend not pulling more than 101,000 lb (70%). Packer is thought to have a 30,000 or 40,000 lb shear release ring. (40K over pull at the packer) A) If Packer releases, then TOH laying down SS, LS, packer, and SS tailpipe and proceed to Step #13. B) If packer does not release, proceed to Step #8 Operations assuminR packer does not release: RU APRS on SS. RIH on SS to chemical or jet cut tubing at 8,785' (approx 5 feet above dual packer) and POOH. RIH on LS to chemical or jet cut tubing in middle of joint approximately 100' above top of packer at 8,790. Both cutting depths may be changed on recommendation of fisherman. RD APRS. TOH laying down SS and LS 2 7/8" L-80 AB MOD tubing, while cutting injection line and bands. 10) PU the following: 11) a) 8-1/8" or 7-5/8" overshot for 9-5/8" 53.5 ppf casing dressed with a basket grapple for 2- 7/8" tubing b) 4.75" OD Bumper sub c) 4.75" OD Hydraulic Jars d) 4.75" OD Ddll collars (9) e) 4.75" OD Accelerator f) 4" HT-38 ddll pipe TIH to LS tubing fish. Latch fish and work good hold. Commence tool work to release Dual packer by jarring. a) If packer releases then COH w/packer and proceed to fishing tailpipe as per Step #13. b) If packer is stuck, then proceed to milling packer as per Step #12. 12) Prepare to mill over Baker GT dual packer. TIH with the following: a) Baker mill shoe for 9-5/8" 53.5 ppf casing and Baker GT dual packer. b) 4.75" Bumper sub c) 4.75" Hydraulic jars d) 4.75" Drill collars TIH on 4" DP to packer at approximately 8790'. Commence milling operations using 10.8 lb/gal Workover Fluid. Use 10.8 lb/gal workover Fluid throughout remainder of procedure. If inadequate circulation is being maintained then consider reverse circulating and using LCM and high viscosity sweeps as necessary. Hi-Vis Pill 10 bbls 3% KCI 2-4 vis cups pH-6 (Citric Acid) 1 sack HEC 1-2 vis cups Caustic Soda Wash over packer tdpping for new mill shoe as necessary. Once packer is free, then TOH w/shoe. TIH w/spear and retrieve packer. 13) TIH with the following to retrieve LS tailpipe fish. BHA needs to have a sufficient ID to allow a 2.125 jet cutter to pass. a) 8-1/8" or 7-5/8", (5.5" OD if fish is in 7" 29 ppf casing) OD overshot for 9-5/8" 53.5 ppf casing dressed with a control mill basket grapple for 2-7/8" tubing b) 4.75" OD Bumper sub c) 4.75" OD Hydraulic Jars d) 4.75" OD Drill collars e) 4.75" OD Accelerator f) 4" HT-38 ddll pipe Latch tubing fish and TOH laying down tubing fish. Utilize washpipe, free points, and chemical cuts as necessary if considerable fill is present. 14) PU and TIH w/metal muncher for tools stdng as follows: a) Baker mill shoe for 7" 29 ppf casing and Backer Model D Production packer. b) Bumper sub c) Hydraulic jars d) Ddll collars Use LCM as necessary along with Hi-Vis sweeps. Push packer to bottom, if it does not come out with mill, then packer can sit on bottom if the top of packer is below lower Tyonek perforations (11,331' MD). TOH w/mill shoe making spear run if necessary. 15) Make bit and scraper run in preparation for csg patch. PU the following assembly: a) Bit for 7" 29 ppf casing b) Razorback Scraper for 7" 29 ppf casing (Weatherford) One joint ddllpipe Spiral reamer dressed for 7" 29 Ib/ff casing Ddll Pipe TIH through Tyonek perforations (10,942-11,331 ') working any tight spots. RIH to 11,350' or to top of fish if packer was not retrieved in previous step. CBU. TOH to above Beluga perfs (9,440') with tools. PU Halliburton Storm Packer, set packer immediately below surface. Pressure test plug. TOH standing back DP. ND BOP and NU new 10k tubing head with 10k side outlets. Pressure Test. TIH sting into plug w/TIW valve on stdng. Test for trapped gas and release plug and TOH w/tool stdng. 16) RU Schlumberger Logging service RU Junk Basket w/6" gauge ring and run at 100 fpm max speed. Perform the following operations: a) Run Ultra Sonic Inspection Tool to check casing across Tyonek Interval for burrs, splits and deformities. Prepare to run 20' Owen casing patch over the Tyonek perfs from 11,121'-11,136' (bottom of three intervals to be patched). RIH and set patch as per Owen setting procedure on wireline. Casing patch will have a 5.5" ID following set. Patch burst/collapse are 3,060 psig / 3,830 psig respectively. Continue operation to patch Tyonek perfs from 11,034' to 11,044', and 10,942' to 10,955'. c) Pick up the following equipment as follows: I) 2-7~8" L-80 EUE 8rd wireline reentry guide II) I joint 2-7/8" 6.5 ppf EUE 8 rd AB MOD tubing III) 2-7~8" EUE 8rd 10' pup joint (pin x pin) IV) 2-7/8" L-80 EUE 8rd 'X' nipple with a 2.313" ID (box X box) V) I joint 2-7~8" 6.5 ppf EUE 8 rd AB MOD tubing VI) 2-7/8" EUE 8rd 10' pup joint (pin x pin) VII) 2-7/8" L-80 EUE 8rd 'X' nipple with a 2.313" ID (box X box) VIII) I joint 2-7/8" 6.5 ppf EUE 8 rd AB MOD tubing IX) Cross over to seal bore extension X) Baker Model D Permanent Packer with Seal Bore Extension. XI) Baker Setting Equipment. XII) Schlumberger Wireline XIII) RIH at 100 fpm maximum speed and set packer on wireline at approximately 10,800'. Setting bottom of tailpipe at least 5' above top Tyonek perforation at 10,942'. d) RD Schlumberger WL. 17) Change pipe rams to dual 2-7/8" on top and single 2 7/8" on bottom. Pressure test them to 250/5,000 psig. Change to dual 2-7/8" elevators. RU Weatherford power tongs and slips for 2-7~8" tubing. Have on location 2 floor valves for 2-7/8" EUE 8rd tubing. 18) PU completion equipment as follows: a) Locator Seal Assembly 3.25" x 10' w/molded nitrile 90 Durometer seals. b) 26 joints 2-7/8" 6.5 ppf EUE 8rd L-80 AB MOD tubing (approx 8217. c) Blast joints and tubing (2-7/8" 6.5 ppf EUE 8rd L-80 AB MOD tubing) with subs to cover the area exposed to Beluga perfs (586' Total). d) Pick up wireline re-entry guide, I Joint 2-7/8" 6.5 ppf EUE 8rd L-80 AB MOD tubing, 2.313 X nipple and RIH simultaneously with long string (approx 7400' of 2-7/8" 6.3 ppf L- 80 EUE 8rd tubing). e) Approx 240 Joints of 2-7/8" 6.5 ppf EUE 8rd L-80 AB MOD tubing. f) Halliburton TruGuide injection mandrels on both Long and Short strings, spaced apart one joint, with injection line to surface (approx 2000'). Pollard to band chemical injection line to every tubing joint. g) Approx 64 Joints of 2-7/8" 6.5 ppf EUE 8rd L-80 AB MOD tubing on each string. h) 2-7/8" 6.5 ppf EUE 8rd L-80 AB MOD tubing pups for space out. 19) Tag up on packer and land seal assembly. Mark pipe at neutral point, and determine required space out. Make up necessary space out pups and mandrel hanger, land tubing. 20) Install hanger and flange up tree. Pressure test tree and seals. Install BPV's in both tubing strings and annulus. Release rig and commence d.q down. 21) Retrieve BPV's. Hook up flowlines, well instrumentation, and building. 22) Rig up Coiled Tubing and Nitrogen on LS. Pressure test BOPE stack and lubricator to 4500 psi. RIH jetting with nitrogen at 300 to 500 SCF/min. Continue to run in hole and jet as necessary to unload well. Be aware of potential hydrate formation downhole as the well gains pressure. NOTE: Lowering BHP across Tyonek perforations and creating a differential of more than 3,830 psig (at 100% of rating) can collapse the Owen casing patches that have just been installed. CONTACTS Ralph Affinito: 907-564-6303 (w) 907-231-3775 (p) Gary Eller: 907-564-6315 (w) Wayne Cissell: 907-283-1308 (w) 907-262-3620 (p) Don Eynon: 907-564-6302 (w) 907-344-0604 (h) PROPOSED WELLBORE 20" 94 ppf K-55 driven to 58' g-7/8" 6.5 ppf L-80 EUE 8rd tbg 13-3/8" 61 ppf K-55 BTC @ 2271' 2-7/8" 6.5 ppf L-80 EUE 8rd tbg for unloading the annulus. Belu a P~ds .~440-9450'~ Belu a Perfs 9674-9682' Bel. a 2~7/8" EUE 8rd 'X' nipple w/2.313" iD 2-7/8" EUE 8rd 'X' nipple w/2,313" Oiis Csg patch w/7 75" ID isolating the B-3 Perfs Permanent Packer @ 10825' 9-5/8" 47-53~5 ppf P-110 & L-80 @ 10312' 7" 29 ppf L-80 @ 10108-12590' Sterling Field Well SU 41-15, Pad 43-9 Marathon Oil Co., Alaska Region API 50-133-20484 KB-THF: 30.00' KB-GL: 29.71' 437' FEL, 2327' FSL Sec. 9, T5N, RIOW, S.M.' CMU Sliding Sleeve @ 8751' w/X-profile (ID = 2.313") (closed 2/15/99) Baker model GT Dual Packer @ 8820' Beluga Sand Perfs 9440'-450' 9616'- 640' 9674'-682' 9694'-704' 9722'-736' 0800':812' /o'003'-014' IO)17'-026' X-Nipple @ 9760' ID = 2.313 Re-Entry Guide @ 9770' ~eluga pay from 9440' - 9812' was fracture stimulated with 74,500 lbs of 20/40 EconoProp on 1/9/99. Note: Tagged fill at 9792' on shortstring (8/23/99) Tyonek Sand Perfs, 10,942' - 95'5' (4-5/8", 6 spf, 5' StimGun) 11,034' - 044' (4-5/8", 6 spf, 5' StimGun) 11,121' - 136' (4-5/8", 6 spf, 3' StimGun) 11,290'- 296' (4-5/8", 6 spf, no StimGun) 11,305'- 316' (4-5/8", 6 spf, 5' StimGun) 11,322' - 331' (4-5/8", 6 spf, 6' StimGun) Last Rev: JGE, 6/21/00 PBTD = 12,490' TD = 12,600' Halliburton TruGuide injection mandrels w/1/4" (0.049" wall)injection line SS @ 822' LS @ 944' 1" injection valves installed 2/99 20", K-55 Drive Pipe @ 58' 13-3/8", 61#, K-55, BTC Casing @ 2271' Cmt w/1186 sks of class G Tubing (Shortstring & Longstring) 2-7/8", 6,5#, L-80, AB-Mod EUE 8rd Steel BlastJoint(OD = 3.500") LS SS 9437'-455' 9436'-456' 9616'-643' 9611'-749' 9668'-739' 9795'-822' 9996'-033' 7" Liner Top @ 10108' w/ZXP liner-top packer 9-5/8", BTC casing @ 10312' 0'- 3083': 53.5#, P-Il0 3083'-9866': 47#, P-Il0 9866'- i0312': 47#, L-80 Cmt w/2284 sks of Class G Note: Apparent corkscrewed tubing at 10,040' Baker model"D" Packer @ 10847' Shock absorber @ 10865' X Nipple @ 10902' ID = 2.313" 15/64" choke installed 3/7/00. End of Tubing @ 10940' Top of Fill: 11,993' (3/6/00) Fish: 402' of 4-5/8" TCP guns dropped to the bottom of the hole after perforating. 7", 29#, L-80, BTC liner @ 10108'- 12590' ('rnl..w/.'/n8 s~ Marathon Oil Company Alaska Region Domestic Production P.O. Box 196168 Anchorage~ AK 99519-6168 Telephone 9071561-5311 Fax 9071564-6489 Mr. Tom Maunder AOGCC 333 West 7th Ave Suite 100 Anchorage, AK 99501 May 24, 2001 RECEIVED Anchorage C°n~miss/on Dear Mr. Maunder: Attached is an application for sundry approval for a coil tubing stimulation in well SU 41-151, Tyonek Sand, in the Sterling Unit. The stimulation consists of pumping methanol and a mutual solvent into the formation matrix in order to remove a water block. The methanol will be placed with coil tubing to facilitate placement and subsequent flowback. The BOPE will be tested to 5,000 psi. Marathon appreciates the considerable safety risks associated with pumping methanol and, in conjunction with our coil tubing service provider, is taking appropriate precautions. We anticipate mobilizing coil tubing by June 7, 2001. Please contact me if you have any questions. Sincerely, Gary '~ll~e Production Engineer STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS O:\EXCE L',AOG CC03.xls 1. Type of Request: Abandon Alter Casing Change Approved Program Suspend Operation Shutdown Re-enter Suspended Well Repair Well Plugging Time Extensior Stimulate X Pull Tubing Variance Perforate Other Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface .v/ ~,~ 2327' FSL, 437' FEI_', Sec. 9, T5N, R10W, S.M. At top of Productive Interval 137' FNL, 2401' FEL, Sec. 15, T5N, R10W, S.M. at 9440' MD At Effective Depth At Total Depth 1080' FNL, 1049' FEL, Sec. 15, T5N, R10W, S.M. 5. Type of Well: Development X Exploratory Stratigraphic Service Datum Elevation (DF or KB) 27.8 feet 7. Unit or Property Name Sterling Unit 8. Well Number SU 41-151 9. Permit ~]~er 98-41 10. APl Number ./' 50- 133-20484 11. Field/Pool Sterling Field, Tyonek Pool 12. Present Well Condition Summary Total Depth: measured true vertical 12,600 feet 10,559 feet Plugs (measured) N/A Effective Depth: measu red true vertical 12,490 feet Junk (measu red) 10,455 feet 11,946', TCP guns dropped after perf. Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: measu red true vertical Length Size Cemented Measured Depth True Vertical Depth 58' 20" Driven 58' 58' 2271' 13 3/8" 1186 sks 2271' 2270' 10312' 9 5/8" 2284 sks 10312' 8544' 2482' 7" 708 sks 12590' 10550' LS - 10942' - 955', 11034' - 044', 11121 '-136', 11290'-296', 11305'-316', 11322'-331' MD LS-9055'-066',9133'-141',9208'-221', 9355'-360',9368'-378', 9383'-391' RECEIVED Tubing (size, grade, and measuied depth) Packers and SSSV (type and measured depth) Longstring: 2-7/8", 6.5#, L-80 tubing to 10940' MD Baker model GT Dual packer @ 8820' MD Baker model "D" Packer @ 10847' MD MAY 2, 5 7.001 Alaska Oil & Gas Cons. Commission Anchorage 13. Attachments Description Summary of ProposalX Detailed Operations Program.__ BOP Sketch 14. Estimated Date for Commencing Operation 1,5. Status of Well Classification as: 6/7/2OO 1 16. If Proposal was Verbally Approved Oil Gas X Suspended__ Name~,~ Approver ~ Date Approved Service 17. I hereb~tify that the forego'~ is true and correct to the best of my knowledge. Signed ~"'~~~_ ~ Gary Eller Title Production Engineer Date "e % FOR COMMISSION USE ONLYm Condition8 of Approval: ~ ~ommission ~o representative may witness ~~ ~- · ~- -- Approval ~o. . Plug Int gri~ BOP Test ~ Locabon Clearance --~ Mechanical Integri~ Tes~ ' ~ubsequent Form Required 10- ~ 5/24/2001 Approved by Order of the Commission Form 10-405 Rev. 06/15/88 ORIGINAL SIGNED BY D Taylor Seamnt, nt Commissioner Date ~_~¢/~i/ ,~ubmfJ in Triplicate 0RI®IHAL Sterling Field Well SU 41-15, Pad 43-9 Marathon Oil Co., Alaska Region API 50-133-20484 KB-THF: 30.00' KB-GL: 29.71' 437' FEL, 2327' FSL Sec. 9, T5N, RIOW, S.M.' CMU Sliding Sleeve @ 8751' w/X-profile (ID = 2.313") (closed 2/15/99) Baker model GT Dual Packer @ 8820' Beluga Sand Perfs 9440'-450' 9616'- 640' 9674'-682' 9694'-704' 9722'-736' 0800'-"8'12' Jo'003'-014' ~O)17'-026' X-Nipple @ 9760' ID = 2.313 Re-Entry Guide @ 9770' ~eluga pay from 9440' - 9812' was fracture stimulated with 74,500 lbs of 20/40 EconoProp on I/9/99. Note: Tagged fill at 9792' on shortstring (8/23/99) Tyonek Sand Perfs i0,942' - 955' (4-5/8", 6 spf, 5' StimGun) 11,034'- 044' (4-5/8", 6 spf, 5' StimGun) 11,121'- 136' (4-5/8", 6 spf, 3' StimGun) 11,290' - 296' (4-5/'8", 6 spf, no StimGun) 11,305'- 316' (4-5/8", 6 spf, 5' StimGun) tl,322'- 331' (4-5/8", 6 spf, 6' StimGun) Last Rev: JGE, 6/21/00 PBTD = 12,490' TD = 12,600' Halliburton TruGuide injection mandrels w/1/4" (0.049" wall) injection line SS @ 822' LS @ 944' 1" injection valves installed 2/99 20", K-55 Drive Pipe @ 58' 13-3/8", 61#, K-55, BTC Casing @ 2271' Cmt w/1186 sks of class G Tubing (Shortstring & Longstring) 2-7/8", 6.5#, L-80, AB-Mod EUE 8rd Steel Blast Joint (OD = 3..500") LS 9437'-455' 9616'-643' 9668'-739' 9795'-822' 9996'-033' SS 9436'-456' 9611'-749' 7" Liner Top @ 10108' w/ZXP liner-top packer 9-5/8', BTC casing @ 10312' 0'-3083':53.5#, P-Il0 3083'-9866': 47#, P-110 9866'- 10312': 47#, L-80 Cmt w/2284 sks of Class G Note: Apparent corkscrewed tubing at 10,040' Baker model"D" Packer @ 10847' Shock absorber @ 10865' X Nipple @ 10902' ID = 2.313" 15/64" choke installed 3/7/00. End of Tubing @ 10940' Top of Fill: 11,993' (3/6/00) Fish: 402' of 4-5/8' TCP guns dropped to the bottom of the hole after perforating. 7", 29#, L-80, BTC liner @ i0108' - 12590' Cmt w/708 sks alts of Annular Flow Wells Subject: Results of Annular Flow Wells Date: Tue, 10 Oct 2000 16:49:27 -0500 From: "J Gary Eller" <JGEller~MarathonOil.com> To: Blair_Wondzell~admin.state.ak.us Blair - As you have requested, I'm supplying you with some information regarding wells that we have converted to annular and tubingless flow. Marathon has converted a total of nine gas wells to annular flow. All but one of these are in the Kenai Gas Field, the ninth being in the Beaver Creek Field. Two of the eight annular flow wells in the Kenai Gas Field have this year been worked-over to allow tubingless flow. 1. Well KU 21-61, February 1998. Prior to annular conversion it flowed up 2-7/8" tubing with a peak deliverability of 3.4 MMCFD.. The annular conversion allowed it to flow up 2-7/8" tubing and 7-5/8" casing simultaneously. Deliverability increased. to 6.0 MMCFD. This well has since died due to mechanical communication with. a watered out sand. Repair operations are awaiting access to coil tubing. 2. KDU-51, February 1998. Prior to annular conversion it flowed up 3-1/2" tubing with a peak deliverability of 5.~9 MMCFD. The annular conversion allowed it to flow up 3-1/2" tubing and 9-5/8" casing simultaneously. Deliverability increased to 9.7 MMCFD'/";:~2~,~ 3. KU ~-3 February 1998. 'Prior to annular conversion it flowed up 3-1/2" tubing with a~ea~ deliverability of 5,5 MMCFD. The annular conversion allowed it to flow up 3-1/2" tubing and 9-5/8" casing simultaneously. Deliverability increased to 11.0 MMCFD. This well later died due to mechanical communication with a watered out sand. We are just now finishing up a workover to convert it to tubin~less flow up the 9-5/8" casing. No results~on ~ha~ yet. ............................... ~-~_ ..... 4. KU ll-8s, August 1998. Prior to annular conversion it flowed up 3-1/2" tubing with a peak deliverability of~ 5.5 MMCFD. The annular conversion allowed it to flow up 3-1/2" tubing and 9-5/8" casing simultaneously. Deliverability increased to 9.0 MMCFD. 5. KU 24-5s, August 1998. Prior to annular conversion it flowed up 3-1/2" tubin~ with a peak deliverability of 4~7 MMCFD. The annular conversion allowed it to flow up 3-1/2" tubing and 9-5/8" casing simultaneously. Deliverability increased to 11.7 MMCFD. 6. KU 43-6al, August 1998. Prior to annular conversion it flowed up 2-7/8" tubing with .a peak deliverability of 3.0 MMCFD. The annular conversion allowed it to flow up 2-7/8" tubing and 7-5/8" casing simultaneously. Deliverability increased to 6.3 MMCFD. This well was worked over in April 2000 allowing flow directly up the 7-5/8" casing. Deliverability increased to 14 MMCFD.' 7. KU 14-61, August 1999. August 1998. Prior to annular conversion it flowed up 2-3/8" tubing with a peak deliverability of 2.2 MMCFD. The annular conversion allowed it to flow up 2-3/8" tubing and 7" casing simultaneously. Deliverability increased to 3,9 MMCFD. 8. KTJ 13-61, August 1999. Prior to annular conversion it flowed up 3-1/2" tubin~ with a peak deliverability of 6.1 MMCFD. The annular conversion allowed it to flow up 3-1/2" tubing and 9-5/8" casing simultaneously. Deliverability increased to 11.6 MMCFD. 9. 'BC-9s, May 1998. Unlike the previous examples, this completion is designed strictly for annular flow. Prior to a workover in May 1998 this well had not produced~from the sand that is now produced annularly. Following the workover deliverability was approximatel~ 15 MMCFD, Please let me know if I can be of further assistance. 10/10/00 2:57 PM Alaska ~' ~n Domestt,, . oduction Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 July 19, 2000 Mr. Blair Wondzell Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Reference: SU 41-151 Dear Mr. Wondzell: Enclosed is the REPORT OF SUNDRY WELL OPERATIONS for well number SU 41-151. Please advise if additional information is required. I can be reached at 564-6317 or e-mailed at dmtitus@marathonoil.com. Sincerely, Denise Titus Production Engineer Enclosure RECLiVED ,JUL 2 1 2000 Alaska OJ; & Gas Co;~s.,,,.o.~m,ss,or~"' '~ ~ ~ ,Aflchora~e A subsidiary of USX Corporation Environmentally aware for the long run. gScmn\d rlg~kgf~wells~ku 11-8s~AOGCC01 a.xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation Shutdown__ Stimulate Plugging__ Pull Tubing__ Alter Casing Repair Well__ 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168~ Anchorage, AK 99519-6168 4. Location of Well at Surface 2327' FSL, 437' FEL, Sec. 9, T5N, R10W, S.M. At top of Productive Interval 137' FNL, 2401' FEL, Sec. 15, T5N, R10W, S.M. at 9440' MD At Effective Depth At Total Depth 1080' FNL~ 1049' FEL~ Sec. 15~ T5N, R10W~ S.M. 12. Present Well Condition Summary Total Depth: measured true vertical Perforate Other x 5. Type of Well: Development.~_x Exploratory __ Stratigraphic__ Service ORIGINAL 12,600 feet Plugs (measured) N/A 10,559 feet Datum Elevation (DF or KB) 27.8 feet 7. Unit or Property Name Sterlin~l Unit 8. Well Number SU 41-151 9. Permit Number 98-41 10. APl Number 50- 133-20484 ' 11. Field/Pool ~ Sterlin~l Field~ Tyonek Pool Effective Depth: measured true vertical 12,490 feet Junk (measured) 10,455 feet 11,946', TCP guns dropped after perf. Casing Length Structural 58' Conductor Surface 2271' Intermediate 10312' Production 2482' Liner Perforation Depth: Size Cemented Measured Depth True Vertical Depth 20" Driven 58' 58' 13 3/8" 1186 sks 2271' 2270' 9 5/8" 2284 sks 10312' 8544' 7" 708 sks 12590' 10550' measured true vertical LS - 9055'-066', 9133'-141 ', 9208'-221 ', 9355'-360', 9368'-378', 9383'-391' Longstring: 2-7/8", 6.5#, L-80 tubing to 10940' MD Baker model GT Dual packer @ 8820' MD Baker model "D" Packer @ 10847' MD LS-10942'-955',11034'-044',11121'-136',11290'-296',11305'-316',11322'-331' MD Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) RFCF VE[ JUL 2 1 2.000 13. Stimulation or Cement Squeeze Summary Intervals Treated (measured) Treatment Description Including Volumes Used and Final Pressure Refer to attached work history. ,~aska 01-; & Gas C,~;~s. Commi Anchorage 14. Prior to Well Operation Subsequent to Operation OiI-Bbl 0 0 Representative Daily Averaqe Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure 0 0 0 0 0 0 Tubing Pressure 2700 2700 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations 16. Status of Well Classification as: Oil Gas x Suspended Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed I D. Titus Title Production Engineer Date 07/19/OO Form 10-404 Rev. 06/15/88 Submit in Duplicate 000711 .x!s MARATHON OIL COMPANY DALLY WELL OPERATIONS REPORT PAGE 1 OF I DATE: 7/11/00 FIELD: Sterling Unit WELL #: SU 41-151 FILL DEPTH/DATE: 11,993' (3/6/00) TUBING: 2-7/8", 6.5#, L-80 CASING: 9-5/8", 53.5#, P-110 DATE LAST WL WORK: TREE CONDITION: good WORK DONE: BENCHES OPEN: Tyonek Sand PRESENT OPERATION: Jet well to unload water OTHER: AFE 0488600, Unload SU 415 long & short strings. ~ ~", ~.~'~,,~ ~ ~1~ ~.~ ~=~ ~,.~.~- SUMMARY OF OPERATIONS JUL 2 1 2000 7/10/00 MIRU 1.75" coil tubing and nitrogen unit on SU 4151. ~0~1 Anchorage 7/11/00 Test BOPE to 200/5000 psig, witnessed by Lou Grimaldi with AOGCC. Replaced leaking inside reel valve on coil tubing unit. Finished testing BOPE. Held safety & operations meeting. SITP = 3500 psig. Bled tubing to under 300 psig, well didn't unload any liquid. RIH with coil tubing circulating nitrogen at 300 SCF/min. Encountered fluid at approximately 7500' CTM. Continue to RIH to 10,000' CTM. Getting water returns. RIH to 11,000' CTM continuing to circulate nitrogen at 300 SCF/min. Reduce nitrogen rate to 125 SCF/min to see if well will flow independently. Well acts like it's dying, so increase nitrogen rate and RIH to 11,400' CTM. Circulate nitrogen at 400 SCF/min at 11,400'. Cum volume recovered so far = 20 bbl. Well not showing signs of feeding in very well. POOH circulating nitrogen. Continued to make fluid all the way out of the hole; well trying to flow but tubing pressure is dropping. At surface, isolated coil tubing and let well unload to atmosphere. Well died within minutes without the assistance of nitrogen. Shut-in well, RD coil tubing. At 8:00 a.m., well had built to 400 psi SITP. nission Vendor Equipment Daily Cost Cumulative Cost Air Liquide R&K Weaver Bros. Dowell Doyles Misc. Toloff DALLY COST: $0 CUM: REPORTED BY: G. Eller/D. Titus Alaska ~l' Tn Domestk. ,oduction Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 July 19, 2000 Mr. Blair Wondzell Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Reference: SU 41-15s Dear Mr. Wondzell: Enclosed is the REPORT OF SUNDRY WELL OPERATIONS for well number SU 41-15s. Please advise if additional information is required. I can be reached at 564-6317 or e-mailed at dmtitus@marathonoil.com. Sincerely, Denise Titus Production Engineer Enclosure RECEIVED JUL 2 1 2000 01'; i G~,~; Cons. Commission Anchorage A subsidiary of USX Corporation Environmentally aware for the long run. g:~cmn\drlg~kgf~wells~kul 1-8s~AOGCC01 a.xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation Shutdown__ Stimulate Plugging Perforate Pull Tubing__ Alter Casing Repair Well Other x 2. Name of Operator 5. Type of Well: 6. Datum Elevation (DF or KB) MARATHON OIL COMPANY Development ~ 27.8 feet 3. Address Exploratory__ 7. Unit or Property Name P. O. Box 196168~ Anchora~]e, AK 99519-6168 Stratigraphic__ Sterling] Unit 4. Location of Well at Surface Service 8. Well Number 2327' FSL, 437' FEL, Sec. 9, T5N, R10W, S.M. SU 41-15s At top of Productive Interval 9. Permit Number At137' FNL, 2401' FEL, Sec. 15, T5N, R10W, S.M. at 9440' MDEffective Depth 0 R I G I [~J~ L 10. APlO8'41Number 50- 133-20484 At Total Depth 11. Field/Pool 1080' FNL, 1049' FEL~ Sec. 15, T5N~ R10W~ S.M. Sterling Field~ Beluga Pool 12. Present Well Condition Summary Total Depth: measured 12,600 feet Plugs (measured) N/A true vertical 10,559 feet Effective Depth: measured 12,490 feet Junk (measured) 11,946', TCP guns dropped after perf. true vertical 10,455 feet Casing Length Size Cemented Measured Depth True Vertical Depth Structural 58' 20" Driven 58' 58' Conductor Surface 2271' 13 3/8" 1186 sks 2271' 2270' Intermediate 10312' 9 5/8" 2284 sks 10312' 8544' Production 2482' 7" 708 sks 12590' 10550' Liner Perforation Depth: measured SS - 9440' - 450', 9616' - 640', 9674-682', 9694'-704' 9722'-736', 9800'-812', 10003'-014', 10017'-026' MD true vertical SS - 7905'-912' 8031'-048', 8072'-078', 8087'-094', 8107'-117', 8162'-174', 8309'-317', 8319'-326' Tubing (size, grade, and measured depth) Shortstring: 2-7/8", 6.5#, L-80 tubing to 9770' MD ~'~ -~,,!~,,,,~,~ ~,~,, ~VE;~ '~ ~ ' """~ -"-"~.9 Packers and SSSV (type and measured depth) Baker model GT Dual packer @ 8820' MD ,JUL 2 1 2000 13. Stimulation or Cement Squeeze Summary ~ ,was ~,m~. C0mmissio~ Intervals Treated (measured) ,Anchorage Treatment Description Including Volumes Used and Final Pressure Refer to attached work history, 14. Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to Well Operation 0 0 0 0 0 Subsequent to Operation 0 1500 0 0 880 15. Attachments 16. Status of Well Classification as: Copies of Logs and Surveys run Daily Report of Well Operations X Oil Gas x Suspended Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~. D. Titus Title Production Engineer Date 07/19/00 Form 10-404 Rev. 06/15/88 Submit in Duplicate. MARATHON OIL COMPANY DALLY WELL OPERATIONS REPORT PAGE 1 OF 1 DATE: 7/13/00 FIELD: Sterling Unit WELL #: SU 41-15s FILL DEPTH/DATE: 9792' (8/23/99) TUBING: 2-7/8", 6.5#, L-80 CASING: 9-5/8", 53.5#, P-110 DATE LAST WL WORK: TREE CONDITION: ~lood WORK DONE: BENCHES OPEN: Belu~la Sand PRESENT OPERATION: Wash fill, jet well to unload water OTHER: AFE 0488600, Unload SU 41-15 long & short strin~ls. SUMMARY OF OPERATIONS MIRU 1.75" coil tubing and nitrogen unit on SU 41-15s. Blend 350 bbl of 3% KCl. 7/13/00 Test to 200/3000 psig. RIH with coil without circulating. SITP = 0 psi. Tag fill at 9765' CTM. Circulate 3% KCl with friction reducer at 1.7 bpm, 3050 psi. Wash loose, fine sand to 9865'. PU to 9760, circulate clean. Shut down pumps, RIH, dry tag at 9994' CTM. Resume circulation, attempt to wash past but tagging up solid. Pump a 17 bbl sweep of 3 ppb FIoVis diplaced with 3% KCl. After returns cleaned up displaced well with nitrogen at 500 SCF/min. Nitrogen at surface. Flowed well until liquids returns were negligible. RDMO coil tubing and nitrogen 7/14/00 Well producing at 1500 MCFD with 880 psig FTP, negligible liquid. RECEIVED JUL 2 1 2000 G', &~s Cons. Commission ,Anchomfie DAILY COST: $0 REPORTED BY: G. Eller/D. Titus Alaskai' on Domest~,.. 'roduction Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 July 20, 2000 Mr. Blair Wondzell Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Reference: SU 41-151 Dear Mr. Wondzell: Enclosed is the APPLICATION FOR SUNDRY APPROVALS for well SU 41-151. Please advise if additional information is required. I can be reached at 564-6317 or e-mailed at dmtitus@marathonoil.com. Sincerely, Denise Titus Production Engineer Enclosure RE, CE VED JUL 2 1 2000 Alaska Oii & Gas Cons. .Anchorage, A subsidiary of USX Corporation Environmentally aware for the long run. O:~EXCELXAOG CC02.xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Suspend ~ Operation Shutdown Alter Casing Repair Well__ Plugging Change Approved Program Pull Tubing Variance Re-enter Suspended Well Time Extension SlJmulate Perforate X Olher 12. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 2327' FSL, 437' FEL, Sec. 9, T5N, R10W, S.M. At top of Productive Interval 137' FNL, 2401' FEL, Sec. 15, T5N, R10W, S.M. at 9440' MD At Effective Depth At Total Depth 1080' FNL, 1049' FEL, Sec. 15, T5N, R10W, S.M. 5. Type of Well: Development X Exploratory Stratigraphic Service ORI61NAL Present Well Condition Summary Total Depth: measured 12,600 feet true vertical 10,559 feet Plugs (measured) N/A 6. Datum Elevation (DF or KB) 27.8 feet 7. Unit or Property Name Sterling Unit 8. Well Number SU 41-151 9. Permit Number 98-41 10. APl Number 50- 133-20484 11. Field/Pool Sterling Field, T¥onek Pool IRe-Perforate Tyonek Effective Depth: measured 12,490 feet true vertical 10,455 feet Junk (measured) 11,946', TCP guns dropped after perf. Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: measured Length Size Cemented Measured Depth True Vertical Depth 58' 20" Driven 58' 58' 2271' 13 3/8" 1186 sks 2271' 2270' 10312' 9 5/8" 2284 sks 10312' 8544' 2482' 7" 708 sks 12590' 10550' RECE - iVEE LS - 10942' - 955', 11034' - 044', 11121'-136', 11290'-296', 11305'-316', 11322'-331' MD true vertical LS - 9055'-066', 9133'-141', 9208'-221' 9355'-360', 9368'-378', 9383'-391' Tubing (size, grade, and measured depth) Longstring: 2-7/8", 6.5#, L-80 tubing to 10940' MD Packers and SSSV (type and measured depth) Baker model GT Dual packer @ 8820' MD Baker model "D" Packer @ 10847' MD JUL 2 1 DO0 ,,~Jaska 0ii & Gas Cons. C0mrni: Anch0mge 1,3. Attachments Description Summary of Proposal Detailed Operations Program X BOP Sketch 14. Estimated Date for Commencing Operation 7/28/00 16. If Proposal was Verbally Approved Rame of Approver Date Approved 15. Status of Well Classification as: Oilm Gas X Service Suspended 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Denise Titus Title Production Engineer FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so representative may witness Plug Integrity BOP Test ~ Location Clearance Mechanical Integrity Test Subsequent Form Required 10- Date 7/20/00 Approved by Order of the Commission Form 10-403 Rev. 06/15/88 IApproval No. -~00 - 1~ I SIGNED BY seamount Commissioner Date Submit in Triplicate WELL SU 41-151, AFE 0488600 STERLING UNIT RE-PERFORATE PROCEDURE Objective: Re-perforate the Tyonek sands of 41-151 Procedure: 1. MIRU Schlumberger e-line unit on 41-151. Test wire rams and lubricator to 4500 psig. 2. RIH with GR/CC1 & 1 ~l/16" weight bars. Note possible corkscrewed tubing at 10,003' SLM (have knuckle joints on location). Log from PBTD to EOT (10,940'). POOH. 3. Correlate depth to Schlumberger AIL/GR log (12/26/98). 1~ ,, 0o 4. RII-I with Enerjet, 2 ~8 , phase, 6 spf gun. 5. Perforate the following zones as shown: 11,034'- 11,044' 11,121'-11,131' 10,942'-10,955' 6. POOH. RDMO Schlumberger. 7. Flow well to system as per instruction of Production Foreman. RECE /ED JUL 2 1 2000 Alaska 07; & Gas Cons. C;ommission Anchorage Sterling Field Well SU 41-15, Pad 43-9 Marathon Oil Co., Alaska Region API 50-133-20484 KB-THF: 30.00' KB-GL: 29.71' 437' FEL, 2327' FSL Sec. 9, TSN, RIOW, S.M. CMU Sliding Sleeve @ 8751' w/X-profile (ID - 2.313") (closed 2/15/99) Baker model GT Dual Packer @ 8820' Beluga Sand Perfs 9440'-450' 9616'-640' 9674'-682' 9694'-704' 9722'-736' 9800'-812' 10003'-014' ............. 10017'-026' X-Nipple @ 9760' ID = 2.313 Re-Entry Guide @ 9770' Beluga pay from 9440' - 9812' was fracture stimulated with 74,500 lbs of 20/40 EconoProp on I/9/99. Note: Tagged fill at 9792' on shortstring (8/23/99) RECEIVED JUL 2 1 2000 A~aska O[ia Gas Cons. Commission Anchorage .Tyonek Sand Perfs 10,942'- 955' (4-5/8", 6 spf, 5' StimGun) 11,034'- 044' (4-5/8", 6 spf, 5' StimGun) 11,121' - 136' (4-5/8", 6 spf, 3' StimGun) 11,290'- 296' (4-5/8", 6 spf, no StimGun) 11,305'- 316' (4-5/8", 6 spf, 5' StimGun) 11,322'- 331' (4-5/8", 6 spf, 6' StimGun) Last Rev: JOE, 6/21/00 PBTD = 12,490' TD = 12,600' Halliburton TruGuide injection mandrels w/1/4" (0.049" wall) injection line SS @ 822' LS @ 944' 1" injection valves installed 2/99 20", K-55 Drive Pipe @ 58' 13-3/8", 61#, K-55, BTC Casing @ 2271' Cmt w/1186 sks of class G Tubing (Shortstring & Longstring) 2-7/8", 6.5#, L-80, AB-Mod EUE 8rd Steel BlastJoint(OD = 3.500") LS SS 9437'-455' 9436'-456' 9616'-643' 9611'-749' 9668'-739' 9795'-822' 9996'-033' 7" Liner Top @ 10108' w/ZXP liner-top packer 9-5/8", BTC casing @ 10312' 0'-3083': 53.5#, P-110 3083'- 9866': 47#, P-110 9866'- 10312': 47#, L-80 Cmt w/2284 sks of Class G Note: Apparent corkscrewed tubing at 10,040' Baker model"D" Packer @ 10847' Shock absorber @ 10865' X Nipple @ 10902' ID = 2.313" 15/64" choke installed 3/7/00. End of Tubing @ 10940' Top of Fill: 11,993' (3/6/00) Fish: 402' of 4-5/8" TCP guns dropped to the bottom of the hole after perforating. 7", 29#, L-80, BTC liner @ 10108'- 12590' Cmt w/708 sks ' Jun-Z3-00 10:20am From-MARATHON 01L +9155646489 T-600 P.O3/OB F-Tgl STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Typ~ of Request: Al~ndon m Alter Casing / Change Approved Program 2, Name of Operator MARATHON OIL COMPANY 3./~dd Fess P, O, Box 196168, Ancher,a,~e, AK 99519-6168 4. Location of W~II at S~face Suspend~ Operation Shutdown~ Re-enter Suspended Well ~ Repair WellI Plugging,_._. Time Extension ~ Stimulate.._.... Pull Tubing ~ Vari~mce ~ Pedorate ~ Other X s. Type ot%~l: 6. Datum Elevation (DF or K~) Development X . .2,7.8, feet Exploratory ~ Stratigraphic ~ .~ewice 12. 2327' FSL, 437' FEL, Sec. 9, TSN, R10W, At top of Productive Interval 137' FNL, 2401' FEL, Sec. 15, T5N, R10W, S.M. at 9440' MD At Effective Depth 12,$00 feet Plugs (measured) N/A 10,B69 feet 7. Unit or Property Name ~ter. llng Unit -~;'WeUNumber SU 41-16s 9. Permit Number 98-41 10. APl Number 50- 133-20484 11, Field/Pool ~ Steflin~ Field, Belu.~e, pool At Total Depth lOB0' FNL, 1049' FEL, Sec. 15, TSN, RlOW, S.M. P resent-W~'Jl"Co ndifion Summary Total Depth: measured true vertical Effective Depth: measured true vertical 12,490 feet Junk (,measured) 10,4~.~ feet 11,946', TOP guns dropped after pad. Casing ,Structural Collductor Surface lnten-nediate Production Liner Pedoration Depth: measured true vertical Lenglh ~ize Cemented Measured Deplh True Vertical Depth 58' P0" Driven 58' 88' 2271' 1,3 8/8' 1186 sks 2271' 2270' 10312' 9 .~/8" 2284 ska 1031 ~.' 8544' 2482' 7" 708 eke 12690' 10559' SS - 9440'-4B0',9616'-640',9674-682',9694'-704'9722'-736',9800'-812',10o03'-o14',10017'-026' MD ~ ~?9~8~9~2~8~31`~48~8~72~7~8~87~94~81~7~-117~'8162'-174~8~9~-,317~8~19~"3~6~ Tubing (size, grade, and measured depth) Packers and $ssv (type and measured depth) Shortstring' 2.?/8", 6.6#, L-80 tubing to 9770' MD Baker model GT Dual packer @ BB20' MD 13. Atl~achments DeSCn~tF6~'S'ummary of Proposal ~ Detailed Operations Program1 '"X 14. Estimated-D~.t~ for Commencing OpemfJ~h ~ i~'i Status of Well Claseificalion as: 6127/00 ! l~,~Fpr0p~sa w~s Verbally Approveci ......... Oil~ GasX..~. Name of ^pprover Date Approved Selvice ...... I?. I hereby certify that the foregoing is true and correci"to the best of my knowie~lge, Si~ned ~,F.~/~'Vt _ ~ Title Production Engineer FOR COM~[S-BI[ON USE ONLY C~nditions of Approval~ N~tify Commission s~ representative m~ty witness Plug Integrity BOP Test ~ Location Clearance Mechanical lnteg'""~ity Test ~ '"'"~ubsequent Fomn Required 10- .'"'--~,(C) BOP Sketch Suspended~ Approved by Order of the Commission ~orr19 10,~o-----3 Rev. 06/'15/~$ ~ii)P, IGtNAL SIGNED DY D Taylor Seamount ID~ 6/21/O0 Commissioner iff"Triplicate ' Jun-23-O0 lO:20am F rom-MAI~ATHOFI OIL +9155G4G459 T-SOO P.05/06 F-791 WELL SU 41-15, AFE 0488600 STERLING UNIT CLEAN-OUT PROCEDURE Objee. tive: Use coil tubing to jet-in well SO 41-151 (Tyonek Sand completion) which is ]oaded up with water. Also, clean out fill and return the Beluga Sand completion, SU 41-15s, to production. Procedure: 1. RU chemical injection pump on casing annulus. Pressure test casing to 3000 psig for 15 minutes. When complete, pump corrosion inhibitor into annulus. 2. MIRU nitrogen on annulus of well SU 41-15. RU to take returns off of the short-string completion. Test lines to 2500 psig. Displace annulus with nitrogen down to a depth of 4000'. No~te: Will displace approximately 219 bbl of 8.9 ppg fluid, reqairing 1200 gallons of nitrogen with 1600 psi at surface. When finished, RDMO nitrogen unit. 3. MIRU slickline on shortstring. Test BOPE to 500 psi. RH-I with shifting tool for a 2.313" CMU sliding sleeve. Close sliding sleeve at 8751'. POOH. PU' retrieving tool, RH-I, pull PX plug in X-nipple at 9760'. POOH, RD slickline. 4. RU slicldine on longstring. Test BOPE to 3000 psi. RIH with retrieving tool, pull downhole choke at 10,902'. POOH, RI)MO slicldine. 5. MIRU 13/a'' coil tubing and nitrogen on longstring. Test BOPE and lubricator to 5,000 psi, Rill jetting with nitrogen at 300 to 500 SCF/min rate. Continue to R]/-I and jet as necessary to unload well. Be aware of a historic problem spot at 10,040' (perhaps corkscrewed tubing). Also be aware of potential'hydrate formation downhole as the well gains pressure. Shut-in well, POOH, RD coil tubing. 6. RU laA'' coil tubing and nitrogen on shortstring. Test BOPE and lubricator to 3,000 psi. RIH, wash fill from 9792' to 10,100' using 3% KC1. Apply hi-vis sweeps as necessary. Below 9770' coil will be in the 95/8" casing opposite 2%" robing, so cheek pick-up weight frequently. When solids returns have cleaned up, PU to 9700' and jet welt in with nitrogen. Shut-in well, POOH, RDMO coil tubing. 7. Produce both wells as per instruction of Production Foreman. JGE June 21, 2000 N;\D~IXIx-qTI~RLINGISUal- 15\unloudbotll,WPD o Jun-23-O0 lO:20am From-MAI~ATHON OI k +915564884889 Sterling Field Well SU 41-15, Pad 43-9 Marathon Oil Co., Alaska Region T-600 P.06/06 F-791 APl 50-133-20484 KB-THF: 30.00' KB-GL: 29.71' 437' FEL, 2327' FSL Sec. 9, TSN, R10W, S.M. CMU Sliding Sleeve @ $751' wi X-profile (ID = 2.313") (closed 2115199) Baker model GT Dual Packer @ 88820' Halliburton TruOuide injection mandrels wi 1/4' (0.049" wall) injection line SS @ 822' LS @ 944' 1' injection valves installed 2/99 20', K-55 Drive Pipe ~ 58' 13-3/88"? 61#. K.55, BTC Casing @ 2271' Cml w/11886 sks of class O Tubing lSh..o_..r~.s, tring & Longstri..n.~ 2-7/8" 6,5-~,-'~280, AB-Mod EI.Tg 8rd Beluga Sattd Perfs 9440'-i~T 9616'- 640' 9674'-682' 9694'-704' 9722'-736' 9800'-812' 10003'-014' 10017'-026' X-Nipple @ 9760' ID = 2,313 Re.Entry Guide @ 9770' Beluga pay from 9440' - 9812' was fracture stimulated with 74,500 lbs of 20/40 EconoProp on 119199, Note: Tagged fill at 9792' on shortstring (8123199) Steel Blast Joint (OD = 3,500") LS SS 9437'-455' 9436'.456' 9616'-643' 9611'-749' 9668'.'739' 9795'-$22' 9996'-033' '/" Liner Top @ 10108' wi ZXP liner.top packer 9-5/8", BTC casing @ 10312' 0'- 3053': 53,5#, P-il0 3083', 9866': 47#, P.110 9866'-10312': 47#, L-gO Cml w/2254 sks of Class O Note; Apparent corkscrewed tubing at 10,040' t:/ouek ~and l'er~ , 10'7942 - 955' (4-518', 6 spt', 5' SfimGun) 11,034' - 04~' (4.5/8", 6 spf= 5' StimGun) 11,121' 136' (4-5/~", 6 spf, 3' StimOun) 1[,290' - 296' (4-5/8", 6 spf, no SdmGun) 11,305' 316' (4-5/8", 6 spf, 5' SrimG~n) 11,322' - 331' (4-518", 6 spt, 6' StimGun) Last Rev: IGE, 6121100 PBTD = 12,490' TD = 12,600' Baker model "D" Packer @ 10847' Shock absorber ~ 10865' X Nipple @ 10902' ID = 2,313" 15/6¢" choke installed 3/7100. End of Tubing @ 10940' Top of Fill: 11,99Y (,3/6/00) Fish: 402' of 4-5/8" TCP guns dropped to the bottom of the hole after peri'orating. 7", 29#, L-dO, BTC liner @ 10108'. 12590' Cml w/708 sks Alaska{~ .~ion Domestic Production Marathon Oil Company June 11. 1999 P.Q. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 LETTER OF TRANSMITTAL Alaska Oil & Gas Conservation Commission Attn: Loft Taylor 3001 Porcupine Drive .~mchorage, AK 99501-3120 The following logs are enclosed: Sterling Gas Unit ti?.}'.. C, Lt[ 1) SU 41-15 Density., Neutron Gamma Ray, Caliper **Platform Express** Run: Two December 26, 1998. Print Reproducibl 1 2) SU 41-15 Array Induction Gamma Ray, Caliper **Platform Express** Run: Two December 26, 1998. 3) SU 41-15 Dipole Shear Sonic Gamma Ray Run: ~ December.~lS~, 1998 4) SU 41-15 Dipole Shear Sonic Gamma Ray Run: Two December 26, 1998. 5) SU 41-15 Natural Gamma Ray Spectroscopy Run: Two December 26, 1998. 6) SU 41-15 Comb. Magnetic Res. Tool Gamma Ray Run: Two December 26, 1998. 7) SU 41-15 Array Induction Gamma Ray **Platform Express** Run: One December 6, 1998. A subsidiary of USX Corporation 8) SU 41-15 Natural Gamma Ray Spectrometry Run: One December 6, 1998. PleaseMARATHoNSign andOiLretUrnCOMPANycOnfirming you have received these d- Kirsten K. Gamel "' Received t~y: Enclosures Date: Environmentally aware for the long run. DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS May 21, 1999 J. Brock Riddle Marathon Oil Company P. O. Box 196168 Anchorage, Alaska 99519-6168 Subject: M~athon Sterling 41-15' aneh0ra~e. 9NY KNOWLES, GOVERNOR 3601 C STREET, SUITE 1380 ~ ANCHORAGE, ALASKA 99503-5948 PHONE: (907) 269-8800 FAX: (907) 562-3852 Dear Mr. Riddle: Marathon drilled two wells in and near the Sterling Unit last fall, Sterling 32-9 and Sterling 41-15. By letter, dated April 23, 1998, Marathon notified the Division of Oil and Gas (division) of the proposed target horizons of Sterling 41-15. Based on our estimates of the coordinates of the well drilled, the division believes that the productive intervals in 41-15 are on State of Alaska lands. The division requests information from the Sterling 41- 15 well to confirm this opinion. The Sterling 41-15 information requested is (1) the final open hole logs, both 2" and 5"; (2) final target coordinates and directional survey; (3) the intervals perforated and tested; and (4) the results of all flow tests (production rates and pressure data) and any deliverability tests. Before the two wells are put into sustained production, the division also requests a meeting with Marathon and the Bureau of Land Management to discuss the expansion of the Sterling 'Unit and Sterling Participating gxea and the formation of a new participating area(s) for the intervals in Sterling 41-15. As part of this meting, we are interested in a discussion regarding the interim payment of royalty for the production attributed to the 41-15 well. Should you have any questions .regarding the requests, please contact Mike Kotowski at 269-8812. Sincerely, Kenneth A. B Director cc: Chris ~i..b,.,.~,~.,=,BLM Well41-15.doc "Develop, Conserve, and Enhance Natural Resources for Present and Future Alaskans." Marathon Oil Company Alaska I~ .~n Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 April 22, 1999 Mr. Blair Wondzell Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Reference: Sterling Unit 32-9 Dear Mr. Wondzell: Enclosed is the Gas Well Open Flow Potential Test Report for the referenced well. Please advise if additional information is required. on Engineer JGE/nrs N:\DRLG~STERLING~,SU329.WPW A subsidiary of USX Corporation Environmentally aware for the long run. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT la. TEST: INITIAL X lb. TYPE TEST STABLILIZEDr ~1~] NON STABILIZED ANNUAL MULTIPOINT IX I CONSTANT TIME SPECIAL OTHER ISOCHRONAL _ 2. Name of Operator 7. Permit No. Marathon Oil Company 98-41 3. Address 8. APl Number 3201 C Street, Ste. 800, Anchorage, Alaska 99503-3934 50- 133-20484 4. Location of Well 9. Unit or Lease Name At surface Sterling Unit 2327' FSL, 437' FEL, Sec. 9, T5N, R10W, S.M. 10. Well Number SU 41-151 ~ " 11. Field and Pool Sterling Field 5. Elevation in feet (KB, DF etc.) 16. Lease Designation and Serial No. Tyonek Pool 27.8' KB-GLI A-028063 12. Completion Date 113. Total Depth 114. PlugbackT.D. 115. Type Completion (Describe) 1/19/99'112600' MD'112490' MDI Dual completion, cased hole 16. Csg. Size Weight per foot, lb. I.D. in inches Set at ft. Perforations: From To 7" 29# 6.184" 12590 Tyonek Sand: 10942' - 955', 11034' - 044', 17. Tbg. Size Weight per foot, lb. I.D. in inches Set at ft. 11121' - 136', 11290' - 296', 11305' - 316', 11322' - 331' MD 3~" 9.3# 2.992 5909' 18. Packer set at ft. 8820' & 10847' 119' GOR cf/bbl'-- 120' APl Liquid Hydr°carb°ns 21' Specific Gravity Fl°wing fluid (G) -- 0.566 22. Producing thru: Reservoir Temp. °F. Mean Annual Temp. °F. Barometric Pressure (Pa), psia Tbg.r~ Csg.['-"] 150 45 14.65 I I . I r°Wro 24. Flow Data Tubing Data Casing Data Choke Prover Orifice Line Size X Size Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. (in.) (in.) psig hw °F. psig °F. psig °F. Hr. 1. 3 X 2 6.6 5.4 72 4231 54 4.000 2. 3 X 2 6.7 6.9 95 3888 60 5.000 3. .... 4. 5. X Basic Coefficient .~ (24-Hour) hwPm Pressure Flow Temp. Factor Gravity Factor Super Comp. Factor Rate of Flow No. Fb or Fp Pm Ft Fg Fpv Q, Mcfd 1. 80.0 0.9887 1.329 3,800 2. 80.0 0.9680 1.329 4,700 3. 4. 5. Pg. 125 GPSA Temperature for Separator Gas for Flowing Fluid No. Pr T Tr Z Gg G 1. 532 0.566 2. 555 3. Critical Pressure 4. Critical Temperature "' 5, ' Form 10-421 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE n:\drlg\sterling\su32-9\AOGCC4PT.xls ', ., Pc 5,380 Pc2 28,944,400 Pf Pf~ 0 No. Pt PF Pc2 - Pt2 Pw Pw~ Pcz - Pw~ Ps Ps~ Pf~ - Psz 1. 4,231 17,904,746 11,039,654 - - - 2. 3,888 15,116,544 13,827,856 - - - 3. 4. 5. 25. AOF (Mcfd) 9,438 n 0.944 Remarks: Data performed with downhole pressure gauges. I hereby certi~that the foregoing ~true and correct to the best of my knowledge. Signed ~%,~~%,X~ Gary Eller Title Production Engineer Date 4/19/99 DEFINITIONS OF SYMBOLS AOF Fb Fp Fg Fpv Ft G Gg GOR hw H L n Pa Pc Pf Pm Pr Ps Pt Pw Q Tr T Z Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia. Basic orifice factor Mcfd/ ~J hw/Pm Basic critical flow prover or positive choke factor Mcfd/psia Specific gravity factor, dimensionless Super compressibility factor = ..~ 1/Z dimensionless Flowing temperature factor, dimensionless Specific gravity of flowing fluid (air = 1.00), dimensionless Specific Gravity of separator gas (air=1.00), dimensionless Gas-oil ratio, cu. ft. of gas (14.65 psia and 60° F.) per barrel oil (60° F) Meter differential pressure, inches of water Vertical depth corresponding to L, feet (TVD) Length of flow channel, feet (MD) Exponent (slope) of back-pressure equiation, dimensionless Field barometric pressure, psia Shut-in wellhead pressure, psia Shut-in pressure at vertical depth H, psia Static presssure at point of gas measurement, psia Reduced pressure, dimensionless Flowing pressure at vertical depth H, psia Flowing wellhead pressure, psia Static column wellhead pressure corresponding to Pt, psia · '.~..~.:.... Rate of flow, Mcfd (14.65 psia and 60°F.) Reduced temperature, dimensionless Absolute temperature, degrees Rankin Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the MANUAL OF BACK-PRESSURE TESTING OF GAS WELLS, Interstate Oil Compact Commission, Oklahoma City, Oklahoma Form 10-421 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE n:\drlg\sterling\su32-9\AOGCC4PT.xls IPR gauge2 Company Marathon Oil Field Sterling Unit Well SU41-151 Test Date Gauge multi-rate April 8-14, 1999 Halliburton (Pavg2-Pwf=) [psia2] versus Qg [MSCF/day] C and n I.P.R. Test type Flow after flow Reservoir Pressure AOFP C n 5379.67 psia 9437.99 MSCF/day 0.00085878, MSCF/day/psia**2n 0.943643 Test points 2 04-1999 Saphir Level 3 V2.20J Alaska F~.. Domestic Production Marathon OilCompany March 9:1999 P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 LETTER OF TRANSMITTAL Alaska Oil & Gas Conservation Commission Attn: Lori Taylor 3001 Porcupine Drive Anchorage, AK 99501-3120 Enclosed are the samples of materials collected for Sterling Gas Field SU 41-15 and SU 32-9, Section: 9, Township: 5. Range: 19. If you have any questions please contact me at 564-6412. The following logs are enclosed: Sample Materials from Sterling Unit Company Well Field Sample Type Depths From: Depths To: 1. Marathon Oil Company Sterling Unit 41-15 Sterling Dry 2280 4020 2. Marathon Oil Company Sterling Unit 41-15 Sterling Dry 4020 5730 3. Marathon Oil Company Sterling Unit 41-15 Sterling Dry 5730 6900 4. Marathon Oil Company Sterling Unit 41-15 Sterling Dry 6900 7520 5. Maratl~on Oil Company Sterling Unit 41-15 Sterling Dry 7520 8150 6. Marathon Oil Company Sterling Unit 41-15 Sterling IDry 8150 '8810 7. Marathon Oil Company Sterling Unit 41-15 Sterling Dry 8810 9500 8. Marathon Oil Company Sterling Unit 41-15 Sterling Dry 9500 10170 9. Marathon Oil Company Sterling Unit 41-15 Sterling Dry 10170 1071D' 10. Marathon Oil Company Sterling Unit 41-15 Sterling D~y 10710 11140 11. Marathon Oil Company sterling Unit 41-15 Sterling Dry 11140 11660 12. Marathon Oil Company Sterling Unit 41-15 Sterling Dry 11660 12160 13. Marathon Oil Company Sterling Unit 41-15 Sterling Dry 12160 12600 Company Well Field Sample Type Depths From: Depths TO: 1. Marathon Oil'Company Sterling Unit 32-9 Sterling Dry 2100 351~) 2. Marathon Oil Company Sterling Unit 32-9 Sterling Dry 3510 5130 3. Marathon Oil Co'mpany Sterling Unit 32-9 Sterling Dry 5130 6190 4. Marathon Oil Company Sterling Unit 32-9 Sterling ;Dry 6190 6470 5. Marathon Oil Company Sterling Unit 32-9 Sterling Dry 6470 6856 qS'-o~tt Please sign and return confirming you have received these documents. MARATHON OIL COMPANY Kirsten K. Gamel Enclosures Received By: Date: A subsidiary of USX Corporation Environmentally aware for the long run. Survey, Well SU 41-15 Subject: Survey, Well SU 41-15 Date: Wed, 03 Mar 1999 12:14:16 -0600 From: "John GEller" <JGEller~MarathonOil.com> T o: B lair_Wondzell~admin.state, ak.us Blair - In the recent completion report for well SU 41-15 (Sterling Unit, Marathon Oil Company, permit #98-41, API 50-133-20484) I made an error on the calculation of well location at total depth and at the top of the producing interval. The correct information is as follows: At top of Producing Interval (9440' MD) 137' FAIL, 2401' FEL, Sec. 15, T5N, R10W, S.M. At total depth (12600' MD) 1080' FNL, 1049' FEL, Sec. 15, T5N, R10W, S.M. Please call me at 564-6315 if you have any questions. 1 of 1 3/3/99 1:23 PM ALAS~' STATE OF ALASKA 3IL AND GAS CONSERVATION COMb(' tON WELL COMPLETION OR RECOMPLETION REPORT AND 1. Status of Well Classification of Service Well OILF] GAS[~] SUSPENDEDE'-] ABANDONED[--'] SERVICEF~ ~" .... 2. Name of Operator 7. Permit Number MARATHON OIL COMPANY 98-41 3. Address 8. APl Numb;e~' ..... Anchorage P. O. Box 196168, Anchorage, AK 99519-6168 50-133-20484 4. Location of Well at Surface ~?"7 .......... 9. Unit or Lease Name 2327' FSL, 437' FEL, Sec. 9, T5N, R10W, S.M. ...... "".. ' '~^ Sterling Unit At top of Producing Interval ' $.~.~;~-'E. 10. Well Number ~ 166' FNL, 2368' FEL, Sec. 15, T5N, R1 OW, S.M. at 9440' MD -- SU 41-15 ~i~t Total Depth ~ji~Z.'.i''. ..... : '~'~='~"~ 11 Field and Pool ' . ~, 1091' FNL, 1035' FEL, Sec. 15, T5N, R10W, S.M. ' .................. Sterling Field 5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation and Serial No. Beluga/Tyonek Pool · , 27.8' KB-GL I A-028063 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 115. Water Depth, if offshore 116. No. of Completions 11/10/98 12/25/98 1/19/99 ~1 N/A feet MSLI two 17' T°tal Depth OVID+TVD)12600' MD, 10559' TVD 18. Plug Back Depth (MD+TVD)12490, MD, 10456' TVD 19. Directional Survey Yes ~-~ No r-'] 120' Depth where SSsv setN/A feet MD 121' Thickness °f Permafr°stN/A 22. Type Electric or Other Logs Run PEX/NGT, DSI, CMR 23 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" K-55 0 58 Driven Driven N/A 13 3/8" 61# K-55 0 2271 17-1/2" 1186 sks N/A 9 5/8" 47# P-110 0 10312 12-1/4" 2284 sks N/A 7" 29# L-80 10108 12590 8-1/2" 708 sks N/A 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 2-7/8", 6.5~ 9770 (short string) 8820' & 10847' Beluga Sand: 9440' - 450', 9616' - 640', 9674' - 682', 9694' - 704', 10940 (long string) 9722' - 736', 9800' - 812', 10003' - 014', 10017' - 026' MD 7905'-912', 8031'-048', 8072'-078', 8087'-094', 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 8107'- 117', 8162'- 171', 8309'-317', 8319'-326' TVD DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Tyonek Sand: 10942' - 955', 11034' - 044', 11121' - 136', 9440' - 9812' Fractured with 74,500 lb ,~.,0f,,,,.,, 11290'-296', 11305'-316', 11322'- 331' MD 20/40 EconoProp 9055'- 066', 9133'- 141', 9208' - 221' ' 9355' - 360', 9368' - 378', 9383' - 391' TVD .... 7 '"' 79,'.-39 27. PRODUCTION TEST Date First Production I Method of Operation (Flowing, gas lift, etc.) N/A I N/A "¢'"'~":¢/'~'8/'~i'l Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS~ N/A TEST PERIOD FIowTubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (corr) Press. 24-HOUR RATE 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. N/A Form 10-407 Rev. 7-1-80 N:\drlg\sterling\su41-15~AOGCompl.xls CONTINUED ON REVERSE SIDE ORIGINAL Submit in Triplicate 29. 3O. GEOLOGIC MARKERS FORMATION TESTS Include interval tested, pressure data, all fluids recovered NAME MEAS. DEPTH TRUE VERT. DEPTH and gravity, GOR, and time of each phase. Beluga 6342' 5662' N/A Tyonek 10262' 8501' N/A 31. LIST OF ATTACHMENTS Daily operations summary, wellbore schematic, directional survey 32. I hereby ca. that the foregoing~s true and correct to the best of my knowledge Signed '~,~~~ Gary E I I er Title Production Engineer Date 2/17/99 . INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown), for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.) Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of OperatiOn: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other- explain. Item 28: If no cores taken, indicate "none". ~' ~' ~i~.~; ,~ .... ii ~.~: ,? ~' Form 10-407 N:\drlg~sterling\su41-15~,OGCompl.xls Sterling Field Well SU 41-15, Pad 43-9 Marathon Oil Co., Alaska Region AP150-133-20484 KB-THF: 30.00' KB-GL: 29.71' 437' FEL, 2327' FSL Sec. 9, T5N, R1 OW, S.M. EMU Sliding Sleeve @ 8751' w/X-profile (ID = 2.313") Baker model GT Dual Packer @ 8820' Camco sidepoeket mandrels w/I/4" chemical injection line SS @ 822' Ls @ 944' 20", K-55 Drive Pipe @ 58' 13-3/8", 61#, K-55, BTC Casing ~ 2271' Cmt w/1186 sks of class G Tubing (Shortstring & Longstring) 2-7/8", 6.5#, L-80, AB-Mod EUE 8rd Beluga Sand Perfs 9440' - 450' 9616' - 640' 9674' - 682' 9694'- 704' 9722'- 736' 9800'- 812' 10003'- 014' 10017' - 026' X-Nipple @ 9760' ID=2.313 Re-Entry Guide @ 9770' Beluga pay from 9440' - 9812' was fracture stimulated with 74,500 lbs of 20/40 EconoProp on 1/9/99. Tyonek Sand Perfs . 10,942'- 955' (4-5/8", 6 spf, 5' StimGun) 11,034' - 044' (4-5/8", 6 spf, 5' StimGun) 11,121'- 136' (4-5/8", 6 spf, 3' StimGun) 11,290' - 296' (4-5/8", 6 spf, no StimGun) 11,305'- 316' (4-5/8", 6 spf, 5' StimGun) 11,322'- 331' (4-5/8", 6 spf, 6' StimGun) Last Rev: JGE, 1/18/99 PBTD = 12,490' TD= 12,600' Steel Blast Joint (OD = 3.500") LS SS 9437'-455' 9436'-456' 9616'-643' 9611'-749' 9668'-739' 9795'-822' 9996'-033' 7" Liner Top @ 10108' w/ZXP liner-top packer 9-5/8", BTC casing @ 10312' 0' - 3083': 53.5#, P-110 3083'- 9866': 47#, P-110 9866'- 10312': 47#, L-80 Cmt w/2284 sks of Class G Baker model "D" Packer @ 10847' Shock absorber @ 10865' X Nipple @ 10902' ID = 2.313" Fish: 402' of 4-5/8" TCP guns dropped to the bottom of the hole after perforating. 7", 29#, L-80, BTC liner @ 10108'- 12590' Cmt w/708 sks DRILLING SUMARY SterlinR Unit # 41-15 9 Nov: Skid rig ahead to SU 41-15. Rig up and nipple up 20" diverter system. 10 Nov: Rig up drilling equipment. Nipple up and function test diverter system. Spud well and drill 58' - 64'. Repair diverter valve. 11 Nov: Repair valves on diverter system and function test. Drill 17-1/2" hole 64'- 1080'. 12 Nov: Drill and survey 1080'- 1503'. TOH, lay down IBS's. Drill and survey 1503' - 2080'. 13 Nov: Drilled to 2275'. CBU. Made wiper trip. CBU. POOH. R/U and ran 13-3/8" casing. 14 Nov: Circ csg. TIH w/dp tag float collar @ 2225'. Cmt csg through 5" dp 40 bbls cmt to surface. POOH w/dp and start N/D diverter system. 15 Nov: Cut off 13-3/8" surface csg. Cut head off 20" conductor. Weld 13-3/8" x 13-5/8" x 5K well head on. Let cool and test to 1230 psi. OK. N/U BOPE. 16 Nov: Finish N/U stack. Test BOPE, set wear bushing and P/U 5" dp and set back in derrick. 17 Nov: Finished P/U drill pipe. M/U BHA. RIH. Tagged cement at 2211'. Drilled cement to 2216'. Tested csg to 1500 psi. Finished drilling FLT equip and new formation to 2285'. CBU. Test shoe to 13.3 ppg EMW. Drilled 2285'- 2845'. 18 Nov: Drlg F/2845' - 3841'. Wiper trip to shoe. OK. Drlg 3841' - 4566'. 19 Nov: Drlg 4566' - 5000'. Circ and TOOH into csg shoe to 2150'. Clean mud tks. And build new mud volume. 20 Nov: Finish building FIo Pro mud volume. TIH and displace old mud out of hole. Drlg. 5000'- 5778'. 21 Nov: Drlg. F/5778-6110'. TOOH F/bit #3. CIO mud mtr and LD jars. Make up PDC bit. Bit wouldnCt go through stack. Found wear ring stuck by lower pipe rams. Opened ram doors and extracted ring. Start testing BOPE. M:\NRSDocs\DrillingVt115sum.doc - 1 - 2/99 Drillinq Summary- Sterlii..q Unit # 41-15 (Continued) 22 Nov: Test BOPE. Replace Tesco valve. P/U 75 jts. DP. Work through tight spots and W&R 875' to btm. Drlg. F/6110-6193'. 23 Nov: 24 Nov: TOOH CIO bit and mud mtr. TIH. Drlg. F/6193-6671' Drlg f/6671' - 7167'. CBU. TOOH 12 stds. f/wiper trip. 7317'. Drlg f/7167' - 25 Nov: Drlg 12-1/4" hole 7317' - 7815'. 26 Nov: Drlg 7815'- 7828'. CBU. TOOH f/PDC bit. Cut drlg line. TIH. Ream tight spots. Drlg f/7828' - 7866'. 27 Nov: 28 Nov: 29 Nov: TOOH f/bit #5 - CIO hang off sub. TIH. Drlg f/7866' - 8154'. Drlg f/8164' - 8425'. CBU. Wiper trip to 7725'. Drlg 8425' - 8540'. Drlg f/8540' - 8761'. CBU. TOOH f/bit #6. 30 Nov: Test BOPE. TIH. Drlg f/8761' - 9037'. 1 Dec: Drilled from 9037'- 9237'. CBU. Made wiper trip to 8505'. Drilled 9237' - 9385'. 2 Dec: Drlg 9385' - 9415'. TOOH f/bit #7. Cut drlg line and TIH. Drlg f/9415' - 9487'. 3 Dec: Drlg ahead 9487'- 9857'. 4 Dec: Drill 9857'- 9909'. TOH. PU bit #8. TIH. Drill 9909'- 9916'. 5 Dec: Drill 9916'- 10,140'. 6 Dec: TOH, replace bit. TIH, drill 10,140'- 10,300'. 7 Dec: 8 Dec. Drill 10,300'- 10,330'. TOH. RU electric line, log with AIT/DSI/GR to TD. Finish logging. Trip in hole to TD, circulate and condition. 09 Dec: 10 Dec. 11 Dec: Circulate and condition for casing. Trip out of hole. Run 9-5/8" casing. Finish running and cementing 9-5/8" casing. Set casing slips. Install tubing head. Install BOPS and test. Start picking up new bottom hole assembly. M:XNRSDocsXDrilling\4115sum. doc ,,. Drillinq Summary - Sterl ,~ Unit # 41-15 (Continued) 12 Dec: 13 Dec: 14 Dec: 15 Dec: 16 Dec: 17 Dec: 18 Dec: 19 Dec: 20 Dec: 21 Dec: 22 Dec: 23 Dec: 24 Dec: 25 Dec: 26 Dec: 27 Dec: 28 Dec: 29 Dec: Finish picking up 8-1/2 BHA. Trip in hole installing drill pipe rubbers. Test casing and drill out float equipment. Perform leak off test. Drill directional hole from 10,330'- 10,391' Drill 10,391'- 10,530'. Short trip to shoe. Drill 10,530'- 10,569'. Trip for new BHA. Trip in hole w/new bit and motor. Directional drill 10,569'- 10,834'. Directional drill 10,834-10,963'. Short trip to shoe. Directional drill 10,963-11,228'. Drill 11,228' - 11,344'. Take kick. Kill well. Drill 11,344' - 11,422'. Drill 11,411' - 11,434'. Short trip to shoe. Trip for bit. Drill 11,434' - 11,451' Drill directional 11,451' - 11,705'. Drill 11,705' - 11,832'. Trip for bit. Test BOPS. Finish testing BOPS. Make up BHA. Trip in hole. Drill 11,832'- 11,926'. Drill 11,926' - 12,113'. Trip for bit. Finish bit trip. Drill 12,113' - 12,173'. Drilled from 12,173' to 12,275'. Repaired mud pump. Drilled from 12,275' to 12,315'. Drilled from 12,315' to 12,356'. CBU. POOH to shoe. RIH. CBU. Circ and raised MW to 11.5 ppg. Short trip. CBU. POOH. BHA. RIH. Reamed 12,322'- 12,356'. Drilled 12,356' to 12,513'. Drlg 12,513' - 12,600'. Wiper trip 25 stds. Circ f/logs. Trip gas peaked @ 1200 units. Raise wt. 11.5- 11.7 ppg. TOOH f/logs. Flow check OK. Finish TOOH f/logs. L/D directional tools. PJU Schlumberger and log. Run NGT. Dipole Sonic- Platform Express. M/U and run CMR log in hole and log. Logging w/Schlumerger ran CMR log. RIH to condition f/csg. Finish RIH after logs. CBU. Made wiper trip to shoe. CBU. POOH to run 7" liner. M:'uNRSDocs~)rilling\4115sum.doc Drillinq Summary - Sterl ,q Unit # 41-15 (Continued) 30 Dec: 31 Dec: 1 Jan: 2 Jan: 3 Jan: 4 Jan: 5 Jan: 6 Jan: 7 Jan: 8 Jan: 9 Jan: 10 Jan: 11 Jan: 12 Jan: 13 Jan: Finish TOOH. Test BOPE. R/U Weatherford and run 57 jts 7" 29~ liner. M/U liner hanger and RIH to shoe. Circ @ shoe. Finished RIH with 7" liner on drillpipe. CBU. Set hanger with shoe at 12,590'. Circ and repair cementing unit and top drive. Cemented liner. POOH 10 stands. CBU. POOH. Lay down liner running tools. Change out and test rams. RIH wl8-112" bit. Drilled cement from 9772' to 10,108'. CBU. Test liner top, TOH. TIH with bit & scrapers. Drill out cement to 12,490'. Empty out and clean mud pits. Clean pits, displace hole with water. Short trip csg scrapers. Build completion fluid, circulate. Displace hole with completion fluid. TOH. Set CIBP on wireline. PU RTTS packer and TIH. Perforate and break down perfs 9440'- 9450', 9616'- 9626', 9674'- 9682', & 9694' - 9704'. Perforate w/Schlumberger and pump in w/rig pump. Circ. TOOH L/D RTTS. Pull wear bushing and set test plug. Start testing BOPE. Test BOPE. Trip in hole. Circ. Circulate while mob frac equipment. Circulating f/frac and R/U DS. Frac stimulate Beluga Sands. Reverse out, RD Dowell. Wash to bottom. Circulate and weight up to control flow. Weight up f/8.8 - 8.9 ppg - watch f/flow- TOOH - L/D muleshoe - P/U burn shoe - WO crossover sub - TIH. Mill over bridge plug. Monitor well & TOOH. Tight off bottom. LID burn shoe & P/U BHA #21 & TIH. Repair O ring on top drive. Drlg on EZ drill bridge plug and chase to liner top. Pump sweeps and work junk baskets. Slip drlg line. TOOH. L/D BHA#21. PJU Halliburton slickline unit and log w/Protechnic. Log 10,000'- 9,000' and repeat. PJD wireline. TIH w/6" bit and BHA #22. Drill up CIBP, chase it to bottom. TOH. RU Schlumberger, perforate Beluga Sands. M:LNRSDocs~Drilling\4115sum. doc Drillin(~ Summary - SterlE~,.q Unit # 41-15 (Continued) 14 Jan: 15 Jan: 16 Jan: 17 Jan: 18 Jan: 19 Jan: 20 Jan: Run gauge ring for 7" csg. Test BOPE. Make run with 7" csg scraper, ROH. P/U TCP guns. Finish TIH w/guns and Pkr. R/U e-line and tie in. Set packer, circulate, TOH laying down drill pipe. Lay down drill pipe and collars. Install and test dual rams. TIH with dual tubing strings. Run dual tubing strings. Finished running dual 2-7/8" tubing strings. Spaced out and landed tubing hanger. Ran gamma ray/cci log to confirm packer location. Set dual packer set BPVs. N/D BOPE. ND BOPE. NU and test tree. RD top drive. RD top drive. Fire TCP guns in Tyonek Sands, release rig. M:~qRSDocs~Drilling\4115sum.doc .... ' ....... - ' ' ' ELOW KSH- ET ........ SURVEY -ALCtJLATli N FI Job No. 0451-02263 S,de,rack No. Page. _. of .... ~ Company MARATHON OIL COMPANY Rig Contractor & No. Nabors Drilling Co.- #160 Field S_T__E__R_L_!_N_G_G _G_ ~ _S_ _F ! _E L_ D ''~ Well Name-- &-ND'--PAD-------SU43-9/SU41-,-5 Survey Section Name Definitive Survey BHI Rep. T. DUNN/DAVIS / GALE ~il~Jl"~~ WELL DATA Target-I-VD (FT) Target Coord. N/S Slot Coord. N/S 2326.80 Grid Correction 0.000 Depths Measured From: RKB ~] MSL~_~ SS[i Target Description Target Coord. E/W Slot Coord. E/W -437.18 Magn. Declination 21.660 Calculation Method MINIMUM CURVATURE Target Direction (DP) Build\Walk\DL per: 100ft[~ 30m~ 10m~ Vert. Sec. Azim. 126.06 Uagn. to Map Corr. 21.660 Map North to: ~_T.H._E_R SURVEY DATA _ Survey Survey Incl. Hole Course Vertical Total Coordinate Build Rate Walk Rate Date Tool Depth Angle Direction Length TVD Section N(+) / S(-) E(+) / W(-) DL Build (+) Right (+) Comment Type (F-r) (DD) (DD) (FT) (FT) (FT) (FI') (Per 100 F-r) Drop (-) Left (-) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TIE IN POINT 10-NOV-98 MWD 163.00 0.60 115.00 163.00 163.00 0.84 -0.36 0.77 0.37 0.37 ASSUMED AZ PEG TF SETTING 10-NOV-98 MWD 267.00 1.10 115.00 104.00 266.99 2.35 -1.01 2.17 0.48 0.48 ASSUMED AZ - MAG INTERFERENC[ 10-N OV-98 MWD 469.00 1.80 183.00 202.00 468.93 5.99 -5.00 3.76 0.85 0.35 _ -- 10-NOV-98 MWD 562.00 2.10 183.60 93.00 561.88 7.70 -8.16 3.58 0.32 0.32 __, 1 O-NOV-98 MWD 738.00 2.10 164.20 176.00 737.76 11.96 -14.48 4.26 0.40 0.00 11 -NOV-98 MWD 824.00 1.90 145.80 86.00 823.71 14.55 -17.18 5.49 0.78 -0.23 11-NOV-98 MWD 1012.00 1.70 148.20 188.00 1011.62 20.06 -22.12 8.71 0.11 -0.11 11 -NOV-98 MWD 1206.00 1.80 137.70 194.00 1205.53 25.71 -26.82 12.27 O. 17 0.05 11 -NOV-98 MWD 1395.00 1.80 143.90 189.00 1394.43 31.44 -31.42 16.02 0.10 0.00 11-NOV-98 MWD 1491.00 1.70 148.20 96.00 1490.39 34.20 -33.85 17.66 0.17 -0.10 11 -NOV-98 MWD 1586.00 1.30 150.40 95.00 1585.36 36.49 -35.98 18.93 0.43 -0.42 12-NOV-98 MWD 1678.00 1.10 157.30 92.00 1677.34 38.19 -37.70 19.79 0.27 -0.22 12-N OV-98 MWD 1871.00 1.00 154.20 193.00 1870.30 41.26 -40.93 21.24 0.06 -0.05 12-NOV-98 MWD 2219.00 0.35 163.60 348.00 2218.28 44.78 -44.68 22.86 0.19 -0.19 LAST SVY IN 17 1/2 HOLE --, 16-NOV-98 MWD 2406.00 0.40 155.30 187.00 2405.27 45.80 -45.82 23.29 0.04 0.03 17-N OV-98 MWD 2657.00 1.80 117,00 251.00 2656.22 50.46 -48.41 27.17 0.60 0.56 17-NOV-98 MWD 2794.00 4.80 115.20 137.00 2792.98 58.22 -51.83 34.28 2.19 2.19 -- 17-NOV-98 MWD 2890.00 7.40 120.50 96.00 2888.43 68.32 -56.67 43.24 2.77 2.71 5.52 17-NOV-98 MWD 2982.00 8.50 124.10 92.00 2979.54 81.01 -63.49 53.98 1.31 1.20 3.91 17-NOV-98 MWD 3080.00 9.90 126.50 98.00 3076.28 96.67 -72.57 66.75 1.48 1.43 2.45 _ 17-NOV-98 MWD 3269.00 15.60 120,60 189.00 3260.55 138.25 -95.19 101.71 3.09 3.02 -3.12 17-NOV-98 MWD 3365.00 18.00 116.60 96.00 3352.45 165.74 -108.40 126.09 2,77 2.50 -4.17 17-NOV-98 MWD 3460.00 19.10 119.90 95.00 3442.52 195.67 -122.72 152.69 1.60 1.16 3.47 Job No, 0451-02263 Sidetrack No, Page 2 of 4 Company MARATHON OIL COMPANY Rig Contractor & No, Nabors Drilling Co,- #160 Field _STERLI.N__G_G~S_?!EL_D ............... J[~V'r~~ Well Name & No, PAD SU43-9/SU41-15 Survey Section Name Definitive Survey BHI Rep, T, DUNN / DAVIS / GALE WELL DATA Target TVD ........... (__F-r) .............. Target Coord, N/S ............. Slot Coord, N/S 2326.80 Grid Correction 0,000 ..... Depths Measured From: RKB ~(j MSL['J SS~-J Target Description Target Coord, E/W ............... Slot Coord, F___./W __ -437,18 Magn, Declination 21,660 Calculation Method MINIMUM CURVATURE Target Direction (DP) Build\Walk\DL per: 100ft~ 30mE] lOm[_J Vert. Sec, Azim, 126,06 Magn, to Map Corr, 21,660 .... Map North to: OTHER SURVEY DATA Survey Survey Incl, Hole Course Vertical Total Coordinate Build Rate Walk Rate .................... Date Tool Depth Angle Direction Length 'FVD Section N(+) / S(-) E(+) / W(-) DL Build (+) Right (+) Comment Type (F-r) (DD) (DD) (F'r) (F'D (F-r) (FT) (Per 100 FT Drop (-) Left (-) 17-N OV-98 MWD 3556.00 21,30 125,80 96.00 3532.62 228,73 -140.75 180,45 3,12 2.29 6,15 17-N OV-98 MWD 3650.00 23,40 124,90 94.00 3619,55 264,47 -161,42 209,61 2,26 2.23 -0,96 __ -- 17-NOV-98 MWD 3746.00 25,50 120,10 96,00 3706,95 304,09 ~182,70 243,13 3,01 2,19 -5,00 ................................ -- 17-NOV-98 MWD 3842,00 27,60 121,30 96,00 3792.82 346,81 -204.62 280,02 2,26 2.19 1,25 17-NOV-98 MWD 3937,00 29,80 121,60 95,00 3876,14 392,28 -228,42 318,93 2,32 2,32 0,32 ............................. - 17-NOV-98 MWD 4032,00 32,50 122,10 95,00 3957.44 441,29 -254,36 360,66 2.86 2,84 0,53 _ 18-NOV-98 MWD 4127,00 35,50 123,50 95,00 4036,19 494,32 -283,15 405,30 3,26 3,16 - . 1,47 ...................................... . 18-N OV-98 MWD 4223.00 38,10 128,90 96.00 4113.07 551,77 -317,15 451,61 4,32 2,71 5,63 18-NOV-98 ........ MWD 4319,00 40,20 124,11 96,00 4187.53 612,33 -353.14 500,33 3.83 2,19 -4,99 18-N OV-98 MWD 4444,00 42,90 122,60 125,00 4281.07 695,14 -398,69 569,59 2.30 2,16 -1,21 18-NOV-98 MWD 4510,00 43,60 126,40 66,00 4329,15 740,32 -424,30 606.84 4.08 1,06 5,76 18-NOV-98 MWD 4606,00 43,60 123,70 96,00 4398,68 806,51 -462,32 661,02 1,94 0,00 -2,81 18-NOV-98 MWD 4797,00 43,20 124,80 191,00 4537,46 937.67 -536,17 769.50 0.45 -0,21 0.58 18-NOV-98 MWD 4893,00 43.40 129,80 96.00 4607,35 1003,45 -576,04 821,83 3.58 0.21 ~i~- ................................. 19-NOV-98 MWD 4989,00 43.20 126,50 96.00 4677.22 1069,22 -616,70 873,59 2,37 -0,21 -3,44 19-NOV-98 MWD 5181,00 43,40 123,30 192,00 4816.97 1200,84 -692,02 981,56 1,15 0,10 - 1,67 -- 20-NOV-98 MWD 5277,00 43,70 128,00 96,00 4886.57 1266.94 -730,55 1035,27 3,39 0,31 4,90 20-NOV-98 MWD 5373,00 43,40 126.50 96,00 4956,15 1333,07 -770,59 1087,92 1.12 -0.31 -1,56 20-NOV-98 MWD 5467.00 43,20 123,80 94,00 5024,56 1397.51 -807.70 1140,62 1.98 -0,21 -2,87 20-NOV-98 MWD 5563,00 43,30 127,70 96,00 5094.50 1463,26 -846,11 1193,98 2.79 0.10 4,06 20-NOV-98 MWD 5755,00 42,90 127,00 192,00 5234.69 1594.42 -925,70 1298,26 0,32 -0,21 -0,36 20-NOV-98 MWD 5946,00 43,50 123,70 191.00 5373.94 1725,12 -1001,31 1404,89 1,22 0,31 -1,73 22-NOV-98 MWD 6227.00 43,10 125,30 281.00 5578.45 1917,75 -1110,45 1563,70 0,42 -0,14 0,57 23-NOV-98 MWD 6419,00 43,20 124.20 192.00 5718.53 2049,02 -1185,30 1671,59 0.40 0,05 -0,57 Job No. 0451-02263 Sidetrack No. _ ........ Page ..__3__ of 4 Company MARATHON OIL COMPANY Rig Contractor & No. Nabors Drilling Co. - #160 ' Field STERLING GAS F!_E.I__D. ~t~lar~l~ Well Name & No. PAD SU43-9/SU41-15 Survey Section Name Definitive Survey _ BHI Rep. _-I',. DUNN / DAVIS / GALE WELL DATA ' Target-[VD (FT) Target Coord. N/S Slot Coord. N/S 2326.80 Grid Correction 0.000 Depths Measured From: RKB ~(j MSI'I'j SS~j Target Description Target Coord. E/W Slot Coord. E/W -437.18 Magn. Declination 21.660 Calculation Method MINIMUM CURVATURE Target Direction (OD) Build\Walk\DL per: 100ft[~ 30m~ lOm[~ Vert. Sec. Azim. 126.06 Magn. to Map Corr. 21.660 Map North to: OTHER SURVEY DATA __ Survey Survey Incl. Hole Course Total Coordinate Build Rate Walk Rate Date Tool Vertical Depth Angle Direction Length TVD Section N(+) / S(-) E(+) / W(-) DL Build (+) Right (+) Comment Type (FO (DD) (DD) (F-r) (FT) (IT) (FO (Per mO FO Drop (-) Left (-) 23-NOV-98 MWD 6611.00 43.20 125.10 192.00 5858.49 2180.41 -1260.02 1779.71 0.32 0.00 0.47 23-NOV-98 MWD 6799.00 43.20 126,50 188.00 5995.54 2309.10 -1335.30 1884.09 0.51 0.00 0.74 23-N OV-98 MWD 6990.00 43.50 132.80 191,00 6134.50 2439.82 -1418.89 1984.92 2.27 0.16 3.30 24-NOV-98 MWD 7182.00 43.70 128.90 192.00 6273.57 2571.71 -1505.45 2085.04 1.40 0.10 -2.03 --_ 24-NOV-98 MWD 7374.00 43.50 130.50 192.00 6412,61 2703.84 -1590.02 2186.91 0,58 -0.10 0.83 24-NOV-98 MWD 7566.00 43.20 127.60 192.00 6552.24 2835.43 -1673.04 2289.24 1.05 -0.16 -1.51 26-N OV-98 MWD 7853.00 42.70 128.90 287.00 6762,32 3030.83 -1794.09 2442.81 0.35 -0.17 0.45 . . 27-NOV-98 MWD 8079,00 44.40 131.60 226.00 6926.12 3186.08 -1894,72 2561.59 1.11 0.75 1.19 27-NOV-98 MWD 8271.00 44.50 129.90 192.00 7063.19 3320.08 -1982.48 2663.44 0.62 0.05 -0.89 _ 28-NOV-98 MWD 8461.00 43.70 127.50 190.00 7199.64 3452.14 -2065.16 2766.60 0.97 -O.42 -1.26 29-NOV-98 MWD 8714.00 43.30 126.00 253.00 7383,17 3626.27 -2169.36 2906.13 0.44 -0.16 -0.59 29-NOV-98 MWD 8940.00 44.30 129.50 226.00 7546.31 3782.57 -2265.13 3029.74 1.16 0.44 1.55 29-NOV-98 MWD 9132.00 44.00 123.80 192.00 7684.12 3916.19 -2344.90 3136.94 2.07 -O. 16 -2.97 30-NOV-98 MWD ................. 9323'00 44.40 123.20 191.00 7821.05 4049.21 -2418.40 3247.98 0.30 0.21 -0.31 02-DEC-98 MWD 9515.00 44,10 124.80 192.00 7958.59 4183.09 -2493.31 3359.04 0.60 -O. 16 0.83 02-DEC-98 MWD 9703.00 44,40 125.00 188.00 8093.25 4314.25 -2568.36 3466.63 0.18 0,16 0.11 -- 03-DEC-98 MWD 9802.00 45.00 128.20 99.00 8163.63 4383.87 -2609.88 3522,52 2.35 0.61 3.23 04-DEC-98 MWD 9990.00 42.60 125.10 188.00 8299.33 4513.94 -2687.59 3626.84 1.71 -1.28 -1.65 05-DEC-98 MWD 10085.00 41,30 125.60 95.00 8369.98 4577.44 -2724.33 3678.63 1.41 -1.37 0.53 06-DEC-98 MWD 10275.00 38.90 123.70 190.00 8515.31 4699.77 -2793.94 3779.27 1.42 -1.26 -1.00 12-DEC-98 MWD 10427.00 38.50 126.40 152.00 8633.95 4794.77 -2848.50 3857.06 1.14 -0.26 1.78 12-DEC-98 MWD 10509.00 38.00 127.20 82.00 8698.34 4845.53 -2878.91 3897.71 --- 01~6 -0.61 0.98 13-DEC-98 MWD 10617.00 36.10 124.20 108.00 8784.54 4910.58 -2916.90 3950.51 2.43 -1.76 -2.78 14-DEC-98 ~WE~- 10713.00 34.40 123.70 96.00 8862.94 4965.94 -2947.84 3996.47 1.80 -1.77 -0.52 Company __M~A_Fi,~_THO_N OIL COMPANY Rig Contractor & No. Nabors Drilling Co.- #160 Field STERLING GAS FIELD ~r~~,--,-,----Well Namo & No..PA_D_ .S_U43-9/SU41-15 Survey Section Name Definitive Survey BHI Rep. T. .............. MUNN / DAVIS / GALE WELL DATA Target TVD (F0 Target Coord. N/S ................ Slot Coord. N/S 2326.80 Grid Correction 0.000 _. Depths Measured From: RKB ~J MSL[-J SS[i Target Description Target Coord. F_JW Slot Coord. E/W -437.18 Magn. Declination 21.660 Calculation Method MINIMUM CURVATURE Target Direction (DM) Build\Walk\DL per: 100ftl~ 30m[~] 10m~J Vert. Sec. Azim. 126.06 Magn. to Map Corr. 21.660 Map North to: OTHER SURVEY DATA Survey Survey Incl. Hole Course Total Coordinate Build Rate Walk Rate Date Tool Vertical Depth Angle Direction Length TVD Section N(+) / S(-) E(+) / W(-)--" DL Build (+) Right (+) Commont Type (FO (DB) (DM) (FO (FT) (Fl") (FT) (Per ]00 FO Drop (-) Left (-) __ 14-DEC-98 MWD 10808.00 33.40 124.40 95.00 8941.79 5018.90 -2977.51 4040.37 1.13 -1.05 0.74 14-DEC-98 MWD 11001.00 31.80 123.20 193.00 9104.38 5122.79 -3035.37 4126.76 0.89 -0.83 -0.62 ............................... 15-DEC-98 MWD 11191.00 29.10 123.00 190.00 9268.15 5218.94 -3087.95 4207.41 1.42 -1.42 -O.11 15-DEC-98 MWD 11287.00 28.40 126.70 96.00 9352.33 5265.09 -3114.31 4245.30 1.99 -0.73 3.85 .................. -- 16-DEC-98 MWD 11380.00 27.50 127.70 93.00 9434.48 5308.67 -3140.66 4280.02 1.09 -0.97 1.08 17-DEC-98 MWD 11573.00 25.40 126.50 193.00 9607.27 5394.61 -3192.54 4348.56 1.12 -1.09 .0.62 -- 18-DEC-98 MWD 11735.00 23.80 126.60 162.00 9754.56 5462.04 -3232.69 4402.73 0.99 -0.99 0.06 19-DEC-98 MWD 11850.00 22.70 123.80 115.00 9860.22 5507.42 -3258.87 4439.80 1.36 -0.96 -2.43 20-DEC-98 MWD 12043.00 21.30 123.80 193.00 10039.16 5579.66 -3299.09 4499.88 0.73 -0.73 ~0.00 22-DEC-98 MWD 12170.00 21.30 120.10 127.00 10157.49 5625.65 -3323.49 4539.01 1.06 0.00 -2.91 . __ 23-DEC-98 MWD 12267.00 21.70 123.00 97.00 10247.75 5661.08 -3342.10 4569.29 1.17 0.41 2.99 25-DEC-98 MWD 12458.00 20.60 122.90 191.00 10425.88 5729.90 -3379.58 4627.12 0.58 -0.58 -0.05 25-DEC-98 MWD 12546.00 20.30 124.30 88.00 10508.33 5760.61 -3396,59 4652.73 0.65 -0.34 1.59 25'DEC'98 ...... MWD 12600,00 20.10 124.30 54.00 10559.01 5779,25 -3407.10 4668.13 0.37 -0.37 0.00 NO SURVEY- PROJECTION TOT. D. -- --_ --_. ORIGINAL MARATHON Oil Company Pad 43-9 SU41 - 15 slot #SU41-15 Sterling Gas Field Kenai Peninsula, Alaska RECEIVED ~,~,', 0 ~i i999 Al~ka Oil & Gas Cons. Cornmi~ion Annotate Page 1 SURVEY LISTING by Baker Hughes INTEQ Your ref : PMSS <0 - 12600> Our ref : svy5882 License : Date printed : 10-Feb-99 Date created : 13-Nov-98 Last revised : 28-Dec-98 Field is centred on n60 31 54.076,w151 1 34.674 Structure is centred on n60 31 54.076,w151 1 34.674 Slot location is n60 32 16.990,w151 1 43.413 Slot Grid coordinates are N 2390036.539, E 314753.505 Slot local coordinates are 2326.80 N 437.18 W Page 2 Projection type: alaska- Zone 4, Spheroid: Clarke - 1866 Reference North is True North 600> MARATHON Oil Company Pad 43-9,SU41-15 Sterling Gas Field,Kenai Peninsula, Alaska SURVEY LISTING Page 1 Your ref : PMSS <0 - 12 Last revised : 28-Dec-98 Page 3 Measured Inclin. Azimuth True Vert Depth Degrees Degrees Depth 0.00 0.00 0.00 0.00 163.00 0.60 115.00 163.00 267.00 1.10 115.00 266.99 469.00 1.80 183.00 468.93 562.00 2.10 183.60 561.88 738.00 2.10 164.40 737.76 824.00 1.90 145.80 823.71 1012.00 1.70 148.20 1011.62 1206.00 1.80 137.70 1205.53 1395.00 1.80 143.90 1394.43 1491.00 1.70 148.20 1490.39 1586.00 1.30 150.40 1585.36 1678.00 1.10 157.30 1677.34 1871.00 1.00 154.20 1870.30 2219.00 0.35 163.60 2218.28 RECTANGULAR COORDINATES 0.00 N 0.00 E Dogleg Deg/100ft 0.00 Vert Sect 0.00 0.36 S 0.77 E 0.37 0.84 1.01 S 2.17 E 5.00 S 3.76 E 8.16 S 3.58 E 0.48 0.85 0.32 0.40 0.79 14.48 S 4.24 E 17.18 S 5.47 E 2.35 5.99 7.70 11.96 14.53 22.13 S 8.69 E 0.11 20.05 26.83 S 12.26 E 31.42 S 16.00 E 0.17 0.10 0.17 33.85 S 17.64 E 35.98 S 18.92 E 0.43 37.71 S 19.77 E 40.93 S 21.22 E 0.27 0.06 0.19 44.69 S 22.84 E 25.70 31.43 34.19 36.47 38.18 41.25 44.77 Page 4 2406.00 26S7.00 2794.00 2890.00 2982.00 3080.00 3269.00 3365.00 3460.00 3556.00 3650.00 3746.00 3842.00 3937.00 4032.00 4127.00 0.40 1.80 4.80 7.40 8.50 9.90 15.60 18.00 19.10 21.30 23.40 25.50 27.60 29.80 32.50 35.50 155.30 117.00 115.20 120.50 124.10 126.50 120.60 116.60 119.90 125.80 124.90 120.10 121.30 121.60 122.10 123.50 2405.27 2656.22 2792.98 2888.43 2979.55 3076.28 3260.55 3352.45 3442.52 3532.62 3619.55 3706.95 3792.82 3876.14 3957.44 4036.19 45.83 S 48.41 S 51.83 S 56.68 S 63.50 S 72.57 S 95.19 S 108.41 S 122.73 S 140.76 S 161.43 S 182.70 S 204.62 S 228.43 S 254.36 S 283.16 S Page 5 23.28 E 27.16 E 34.26 E 43.22 E 53.96 E 66.73 E 101.69 E 126.07 E 152.67 E 180.44 E 209.60 E 243.12 E 280.00 E 318.91 E 360.65 E 405.28 E 0.04 0.60 2.19 2.77 1.31 1.48 3.09 2.77 1.60 3.12 2.26 3.01 2.26 2.32 2.86 3.26 45.79 50.45 58.21 68.31 81.00 96.66 138.24 165.73 195.66 228.72 264.46 304.08 346.80 392.27 441.28 494.30 4223.00 4319.00 4444.00 4510.00 4606.00 4797.00 4893.00 4989.00 5181.00 5277.00 5373.00 5467.00 5563.00 5755.00 5946.00 6227.00 6419.00 38.10 40.20 128.90 124.11 4113.07 4187.53 317.16 S 451.59 E 4.32 353.14 S 500.31 E 42.90 122.60 4281.07 398.70 S 569.57 E 43.60 126.40 4329.15 424.31 S 606.82 E 4398.68 43.60 123.70 462.32 S 661.01 E 43.20 124.80 4537.46 536.17 S 769.48 E 43.40 129.80 4607.35 576.05 S 821.82 E 43.20 126.50 4677.22 616.71 S 873.58 E 43.40 123.30 4816.97 692.02 S 981.55 E 43.70 43.40 128.00 126.50 123.80 127.70 127.00 123.70 125.30 124.20 43.20 43.30 42.90 4886.57 4956.15 5024.56 5094.50 5234.69 5373.94 5578.45 5718.53 43.50 43.10 43.20 3.83 2.30 4.08 1.94 0.45 3.58 2.37 1.15 730.56 S 1035.26 E 3.39 770.59 S 1087.90 E 807.70 S 1140.60 E 846.12 S 1193.96 E 925.71 S 1001.32 S 1298.25 E 1110.46 S 1404.87 E 1185.30 S 1563.69 E Page 6 1671.58 E 1.12 1.98 2.79 0.32 1.22 0.42 0.40 551.76 612.32 695.13 740.31 806.50 937.66 1003.44 1069.21 1200.83 1266.93 1333.06 1397.50 1463.25 1594.41 1725.11 1917.74 2049.01 6611.00 6799.00 43.20 43.20 125.10 5858.49 1260.03 S 1779.70 E 0.32 2180.40 126.50 5995.54 1335.30 S 1884.07 E 0.51 2309.09 level) . Ail data is in feet unless otherwise stated. Coordinates from slot #SU41-15 and TVD from Estimated RKB (265.00 Ft above mean sea Bottom hole distance is 5779.24 on azimuth 126.12 degrees from wellhead. Vertical section is from wellhead on azimuth 126.06 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ MARATHON Oil Company Pad 43-9, SU41-15 600> Sterling Gas Field,Kenai Peninsula, Alaska SURVEY LISTING Page 2 Your ref : PMSS <0 - 12 Last revised : 28-Dec-98 Measured Inclin. Azimuth True Vert Depth Degrees Degrees Depth 6990.00 43.50 132.80 6134.50 RECTANGULAR COORDINATES 1418.89 S 1984.90 E Dogleg Deg/lOOft 2.27 Vert Sect 2439.81 Page 7 7182.00 7374.00 7566.00 7853.00 8079.00 8270.00 8461.00 8714.00 8940.00 9132.00 9323.00 9515.00 9703.00 9802.00 9990.00 10085.00 43.70 43.50 43.20 42.70 44.40 44.50 43.70 43.30 44.30 44.00 44.40 44.10 44.40 45.00 42.60 41.30 128.90 130.50 127.60 128.90 131.60 129.90 127.50 126.00 129.50 123.80 123.20 124.80 125.00 128.20 125.10 125.60 6273.57 6412.61 6552.24 6762.31 6926.12 7062.47 7199.65 7383.17 7546.31 7684.13 7821.06 7958.59 8093.26 8163.63 8299.33 8369.98 1505.46 S 2085.03 E 1590.03 S 2186.89 E 1673.05 S 2289.22 E 1794.10 S 2442.79 E 1894.73 S 2561.57 E 1982.03 S 2662.89 E 2065.14 S 2766.60 E 2169.34 S 2906.12 E 2265.11 S 3029.74 E 2344.89 S 3136.93 E 2418.38 S 3247.97 E 2493.29 S 3359.04 E 2568.35 S 3466.63 E 2609.86 S 3522.51 E 2687.57 S 3626.83 E 2724.31 S 3678.63 E 1.40 0.58 1.05 0.35 1.11 0.63 0.97 0.44 1.16 2.07 0.30 0.60 0.18 2.35 1.71 1.41 2571.70 2703.83 2835.42 3030.82 3186.07 3319.37 3452.13 3626.26 3782.56 3916.18 4049.20 4183.08 4314.24 4383.85 4513.93 4577.43 Page 8 10275.00 10427.00 10509.00 38.90 38.50 38.00 123.70 126.40 127.20 8515.31 8633.95 8698.34 2793.92 S 3779.26 E 2848.48 S 3857.05 E 2878.89 S 3897.70 E 1.42 1.14 0.86 4699.75 4794.75 4845.51 10617.00 10713.00 10808.00 11001.00 11191.00 36.10 34.40 33.40 31.80 29.10 124.20 123.70 124.40 123.20 123.00 8784.54 8862.94 8941.79 9104.38 9268.16 2916.88 S 2947.83 S 2977.49 S 3950.51 E 3996.46 E 4040.37 E 3035.35 S 4126.75 E 3087.93 S 4207.41 E 2.43 1.80 1.13 0.89 1.42 4910.57 4965.93 5018.88 5122.78 5218.93 11287.00 11380.00 11573.00 11735.00 11850.00 28.40 27.50 25.40 23.80 22.70 126.70 127.70 126.50 126.60 123.80 9352.33 9434.48 9607.27 9754.56 9860.22 3114.30 S 3140.64 S 4245.29 E 4280.02 E 3192.52 S 4348.55 E 3232.68 S 4402.73 E 1.99 1.09 1.12 0.99 3258.86 S 4439.80 E 1.36 5265.07 5308.65 5394.59 5462.03 5507.40 12043.00 12170.00 12267.00 12458.00 21.30 21.30 21.70 20.60 123.80 120.10 123.00 122.90 10039.17 10157.50 10247.75 10425.88 3299.08 S 4499.87 E 3323.48 S 4539.00 E 3342.08 S 3379.56 S 4569.28 E 4627.11 E 0.73 1.06 1.17 0.58 5579.65 5625.64 5661.07 5729.88 Page 9 12546.00 20.30 124.30 10508.34 3396.58 S 4652.72 E 0.65 5760.60 12600.00 20.10 124.30 ECTION TO T.D. 10559.01 3407.08 S 4668.12 E 0.37 5779.23 NO SURVEY - PROJ Ail data is in feet unless otherwise stated. level) . Coordinates from slot #SU41-15 and TVD from Estimated RKB (265.00 Ft above mean sea Bottom hole distance is 5779.24 on azimuth 126.12 degrees from wellhead. Vertical section is from wellhead on azimuth 126.06 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ Page 10 600> MARATHON Oil Company Pad 43-9, SU41-15 Sterling Gas Field,Kenai Peninsula, Alaska SURVEY LISTING Page 3 Your ref : PMSS <0 - 12 Last revised : 28-Dec-98 Comments in wellpath Rectangular Coords. Comment 12600.00 10559.01 3407.08 S 4668.12 E NO SURVEY - PROJECTION TO T.D. Casing positions in string 'A' sing Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Ca ,, Casing 0.00 0.00 0.00N 0.00 0.00 0.00N 0.00E 80.00 80.00 0.00E 2270.00 2269.28 0.09S 44.99S 0.19E 20 22.94E 13 Page 11 3/8" Casing 0.00 5/8" Casing 0.00 0.00N 0.00E 10311.00 8543.35 2806.56S 3797.98E Targets associated with this wellpath Target name Revised Geographic Location T.V.D. Rectangular Coordinates Strlng DEEP (TD)Rvsd -May-97 Tyonek D-1 Rvsd 18-F -May-97 Tyonek Rvsd 18-Feb-9 -May-97 LM Beluga Rvsd 18-Fe -May-97 T/ Beluga Rvsd 18-Fe -May-97 Tyonek D-2 Rvsd 18-F -Oct-97 10655.00 9565.00 8135.00 6765.00 5925.00 9965.00 3176.63S 4330.89E 20 3176.63S 4330.89E 20 3117.14S '4250.;51E 20 1749.05S 2401.64E 20 1035.26S 1437.01E 20 3176.63S 4330.89E 24 Page 12 Alaska ~, a~on Domestic Production Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 February 16, 1999 LETTER OF TRANSMITTAL Alaska Oil & Gas Conservation Commission Attn: Lori Taylor 3001 Porcupine Drive Anchorage, AK-9-9501-3120 The following logs are enclosed: ~..~.~ Sterling Gas Unit Reproducibl 1) SU 41-15 Packer Setting Record Run: Three January 4, 1999. 2) SU 41-15 Perforating Record Run: Three January 4. 1999. 3) SU 41-15 Gamma Ray Collar Locator Log Run: Three January 4. 1999. 4) SU 41-15 Perforation Summary Log Run: One January 12. 1999. 5) SU 41-15 Depth Determination Run: One January. 14. 1999. 6) SU 41-15 Depth Determination Log Run: One January 17. 1999. 7) SU 32-9 Perforation Summary Log Run: One November 6, 1998. 8) SU 32-9 Gamma Ray/CCL Packer Setting Summary Run: One November 4. 1998. 9) SU 41-15 Caliper Gamma Ray Run: Two December 26. 1998. ,EtVED 10) SU 41-15 Density, Neutron Gamma Ray, Caliper ! 999 . 1 ~,as~.a [J.i & Gas Cons. C0mmi~ .~nch0ra~le A subsidiary of USX Corporation Environmentally aware for the long run. Alaska ~,_. =~Jon Domestic Production Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 **Platform Express** Run: Two December 26. 1998. 11) SU 41-15 Array Induction Gamma Ray: Caliper **Platform Express** Run: Two December 26, 1998. -~12) SU 41-15 Dipole Shear Sonic Gamma Ray Run: Two December 26. 1998. 13) SU 41-15 Natural Gamma Ray Spectroscopy Run: Two December 26. 1998. 14) SU 41-15 Comb. Magnetic Res. Tool Gamma Ray Run: Two December 26. 1998. 15) SU 41-15 Density. Neutron Gamma Ray, Caliper **Platform Express** Run: One December 6, 1998. 16) SU 41-15 Array Induction Gamma Ray **Platform Express** Run: One December 6, 1998. 17) SU 41-15 Natural Gamma Ray Spectrometry Run: One December 6, 1998. 18) SU 41-15 Relabeled Dipole Sonic PEX/AIT DSI Run: One December 6. 1998. 19) SU 41-15 Relabeled Dipole Sonic AITH/DSI/PEX Run: Two December 26. 1998. F ECEIVED · .~aska Oil & Gas Con.,. O0~ 1 1 1 1 20) SU 41-15 Array Induction **Platform Express** Run: One December 6. 1998. 1 1 21) SU 41-15 Density. Neutron Gamma Ray, Caliper Run: One **Platform Express** December 6, 1998. 1 1 22) SU 41-15 Natural Gamma Ray Spectrometry. Run: One December 6. 1998. 1 1 23) SU 41-15 Caliper Gamma Ray Run: Two December 26. 1998. 1 1 24) SU 41-15 Densitv. Neutron Gamma Ray, Caliper **Platform Express** Run: Two December 26. 1998. 1 1 25) SU 41-15 Natural Gamma Ray Spectroscopy Run: Two 1 A subsidiary of USX Corporation Environmentally aware for the long run. Alaska~, . .,gion Domestic Production Marathon Oil Company December 26, 1998. P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 ,_~ ~. Od 26) SU 41-15 Comb. Magnetic Res. Tool Gamma Ray Run: Two December 26. 1998. 27) SU 41-15 Array Induction. Gamma Ray, Caliper Run: Two **Platform Express* December 26, 1998. 28) Su 41-15 LIS 9 track tape Run #1 Sterling Gas Field/Marathon Oil Company: AIT/PEX/DIS/NGT/CMR Customer Tape Logged: December 6. 1998 1600BPI Start: 10376' Stop: 2132.5' Job#: 99004 (1 tape) 29) SU 41-15 LIS 9 track tape Run #2 Sterling Gas Field/Marathon (1 tape) Oil Company: AIT/PEX/NGT/DSI Customer Tape Logged: December 26, 1998 1600BPI Start: 12595.0' Stop: 10310.0' Job#: 99004 Please sign and return confirming you have received these documents. MARATHON OIL COMPANY Kirsten K. Gamel Received B~' ~~ ~ Date: A subsidiary of USX Corporation Environmentally aware for the long run. 198-041-0 Roll ltl: Start: MD 12600 TVD 10559 STERLING UNIT 41-15 50- 133-20484-00 Stop Roll it2: Start Stop Completion Date:~l/19/99 Completed Status: 2-GAS MARATHON OIL CO Current: Name ~cALIPER/GR 2 c MR/GR 2 ompletion Record DEPTH DETERM. 1 DEPTH DETERM. 1 ~'~SS/GR 2 GR/CCL 3 bL~"NGR-SPEC 1 /J~GR-SPEC 2 PACKER SETT RCD 3 PERF 3 PERF 1 ~EX-AIT/GR 1 L.~-AIT/GR/CAL 2 ~ ~'FEX-DSS/OH 1 PEX-DT/NT/GR 2 / EX-DT~T/GR 1 L/L~RELABEL DSI 1 -,.~"~LABEL DS1 2 'i~'SRVY ~,'~83 1 "~84 2 Interval Sent Received BL(dI0310-12592 OH 2/16/99 2/16/99 BL(C) 10950-12590"~q~(oa~ OH 2/16/99 2/16/99 10850-11170 Print 12/13/00 1/9/01 L~10600-10800 /'ff..)o"' ./~,c:] CH 5 2/16/99 2/16/99 I,L~R 9400-10900 t~ .,}O,n~' [~q' CH 5 2/16/99 2/16/99 10310-12592 OH 2/16/99 2/16/99 ,..>. LGR 9200-9900 o,/,,)~. CH 5 2/16/99 2/16/99 BL(C~271-10330 OH 2/16/99 2/16/99 BL(~'~" 103.! 0~12592 ~,,~IJL. OH 2/16/99 2/16/99 LGK~9200-9900 '4.,)~ q'¶ CH 5 2/16/99 2/16/99 LG~9~40-9812 ~/~lan~ tt q CH 5 2/16/99 2/16/99 LGR 9620-10026. ~-~-'~'~'" c:[ ~l CH 5 2/16/99 2/16/99 BL( )~271-10330 ~ ~ {0gX,,, OH 2/16/99 2/16/99 BL( )~10310-1.2592 ~ 1~'~°~ OH 2/16/99 2/16/99 L C~22~7 B 1-10330 OH 2/16/99 2/16/99 BL(~) 10310_12592M ~ tl~.- · Oi'! 2/16/99 2/16/99 BL(~f 2271-10330 ~ IOxx- Oit 2/16/99 2/16/99 BL(L~I50-10350 OH 2 ,' 2/16/99 2/16/99 BL(~/10150-12600 12/26/98 '[ttxTf~r~,' OH 2 2/16/99 2/16/99 BH 0-12600 OH 3/1/99 3/1/99 SCHLUM PEX-AIT/NGR/DS1 OH 2/11/99 2/16/99 SCHLUM PEX-A1T/DS1/NGR/CMR O1-I 2/11/99 2/16/99 T/C/D D Thursday, January 25, 2001 Page 1 of I MEMORANDUM TO: State of Alaska Alaska Oil and Gas Conservation Commission Robert Christenson, '~~,~ DATE: 1/5/99 Chairman THRU: Blair Wondzell, ~ P. I. Supervisor FROM' Larry V~ade~/"~, SUBJECT: Petroleum Inspector FILE NO: .DOC BOP Test Nabors 160 SU 41-15 PTD ~ January 5,1999: I left the AOGCC office and traveled to the Sterling Unit outside of Soldotna to witness a BOP test on Nordic 160. The testing started at 2:00AM. We had to retorque two flanges in the choke line as they were leaking. The choke manifold wouldn't test and water started leaking out of one of the stem housing on one of the valves. We tested the pipe rams and hydril while they overhauled the leaking valve. We then tried to retest the choke manifold but 'it wouldn't hold pressure. We then proceeded to test the choke manifold one valve at a time and found two more that were not holding pressure. We then pulled the test joint and tested the blind rams and found a blown mud seal. The rig is waiting on a frac crew and were to have the mud seals replaced and the valves that failed the pressure test repaired before doing anything else. SUMMARY: Witnessed a BOP test on Nabors 160, 4 failures, 13.5 hours. A,ttachments: a9tgafge.xls cc; NON-CONFIDENTIAL STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: X Workover: Drlg Contractor: Nabors Rig No. Operator: Marathon Oil Company Well Name: SU 41-15 Casing Size: g 5/8" Set @ 10,311 Test: Initial___..__ Weekly X Other PTD # Rep.' Rig Rep.: Location: Sec. DATE: 1/6/9g g8-142 Rig Ph.# (,9,07)229-9325 Sco# As.ay Marvin Ro~ers g T. 5N R. lOW Meddian Seward Test Pressures 250/5000 Test FLOOR SAFETY VALVES: Quan. Well Sign X Upper Kelly / IBOP 1 ~ (Gan) Drl. Rig "X Lower Kelly / IBOP 1 Hazard Sec.. X, ' Ball Type I 250/5000 X Inside BOP 1,. 250/5000 MISC. INSPECTIONS: Pressure P/F Location Gen.: ok 250/5000 P Housekeeping: ok 250/5000 'P' PTD On Location X Standing Order Posted P BOP STACK: Annular Preventer Pipe Rams Lower Pipe Rams ~' Blind Rams ~1 ~ , Choke Ln. Valves 1 , . , HCR Valves 1 Kill Line Valves 2 Check Valve Quan. Test Press. P/F Test I 250/2500 P Pressure "1' ' '250/5000 250/5000 250/5000 250/5000 250/5000 250/5O00 CHOKE MANIFOLD: P No. Valves 13 P No. Flanges 40 F Manual Chokes "'2 'P' Hydraulic Chokes 1 P ~,, 250/5000 250/5000 250/5000 Functioned Func#oned P/F ACCUMULATOR SYSTEM: ....... System Pressure 2,825 Pressure After Closure 1,650 ..... MUD SYSTEM: Visual Alarm 200 psi Attained After Closure___._ minutes 33 sec. Trip Tank X X System Pressure Attained 3 minutes ~',~5 sec. Pit Level Indicators X X Blind Switch Covers: Master: X Remote: X Flow Indicator X '~(" Nitgn. Btl's: 2150-1g00-1950-1925 Meth Gas Detector '~ X ' X Psig. ,, ,, H2S Gas Detector X ' X , , 11 .... . .......... Number of Failures: 4 ,Test Time: 13.5 Hours. Number of valves tested 20 Repair or Replacement of Failed Equipment will be made withi'n ! da~S. Notify the Inspector and follow with' ~Vritten or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-361)7 or 3687 If your call is not returned by the inspector within 12 hours please contact the P. I. Supervisor at 279-1433 REMARKS: Repairs to be made before ~loin~! in the hole. -! Distribution: orig-Weil File c - Oper./Rig c - Database c - Trip Rpt File c - Inspector STATE wITNEss REQUIRIED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Witnessed By: Larry Wade F1-021L (Rev. 12/94) ag~gafge.)ds TONY KNOWLE$, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 July 14; 1998 W. C. Barron Operations Superintendent Marathon Oil Company P O Box 196168 Anchorage, AK 99519-6168 Re; Sterling Unit SU 41-15 Marathon Oil Company Permit No: 98-41 Sur. Loc. 2327'FSL, 437'FEL, Sec. 9, TSN, RIOW, SM Btmhole Loc. 1072'FNL, 423 I'FWL, Sec. 15, TSN, R10W, SM Dear Mr. Barron: Enclosed is the approved application for permit to drill thc above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must bc tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of thc BOPE test performed before drilling below the surface casing shoe must bc given so that a representative of thc Commission may witness the test. Notice may be given by contacting thc Commission at 279-1433. Chairman BY ORDER OF THE COMMISSION dlf/Enclosures CC: Department of Fish & Game, Habitat Section w/o cncl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: THE APPLICATION OF MARATHON ) OIL COMPANY for an order granting ) an exception to spacing requirements of ) ~'-~. 20 AAC 25.055(a)(4) to provide for the ) drilling of the Sterling Unit 41-15 and ) · Sterling Unit 32-9 gas development wells ) within the Sterling Unit, east of the cityof ) Kenai. ) Conservation Order No. 426 Marathon Oil Company Sterling Unit Wells 41-15 and 32-9 May 20, 1998 IT APPEARING THAT: Marathon. Oil CompanY submitted applications dated April 23, 1998 and April 24, 1998 requesting exception tothe well spacing provisions of 20 AAC 25.055(a)(4). The first exception would allow drilling the Sterlin.g Unit 41-15 gas development well to a producing location cloSer, than 1500 .feet'to a section line in an undefined gas pool.: Ttie second would allow drilling the sterling Unit 32'9 gas development well to a producing location that is closer than 3000 :feet from another Well capable of producing from the same pool. 2. The Commission publi'shed..notice of opportunity tbr public hearing in tl~e Anchorage Daily News on May2, 1998 pursuant to 20 AAC 25.540. .,, 3. No protests to the application were receiVed. FINDINGS: 1. The Sterling Unit 41-15 .gas development well will be drilled as a deviated hole fi'om a surface location of 2327"from'the south line (FSL) and 437' from the east line (FELl of Section 9, T5N~ R10W, Seward Meridian (SM) to a bottomhole location 4208' FSL and 1049' FEL of Section 15, T5N; RI 0W, SM. The Sterling Unit 32-9 gas development well will be drilled as a deviated hole from a surface location of 2312' FSL and 449' FEL of Section 9, T5N. R1 OW, SM to a producing location of 2706' FSL and 2197' FEL of Section 9, T5N', R 1 OW. SM. , 2. Offset owners Bureau ofLand Mangement, U.Si Minerals. Management Service, Cook Inlet Region, Inc and the State of Alaska have been duly notified. , 3. An exception !o the well spacing provisions of 20 AAc 25.055 (al(4) is necessary to allow the drilling of these wells ConserYation Order No..( May 20. 1998 Page 2 CONCLUSION: Granting a spacing exception to allow drilling of the Sterling Unit 41-15 and the Sterling Unit 32-9 gas wells will not result in ~vaste nor jeopardize correlative rights. NOW, THEREFORE, IT IS ORDERED: Marathon Oil Company's applications for exception to the well spacing provisions of 20 AAC 25.055 (a)(4) for the purpose of drilling the Sterling Unit 41-15 and the Sterling Unit 32-9 gas wells are approved. DONE at Anchorage, Alaska and dated May 20, 1998. Alaska Oil and Gas Conservation Commission Cammy Oechs0~ Commissioner Alaska Oil and'Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request lbr rehearing must be received by 4:30 PM on the 23rd day/bllowing the date of the order, or next working day if a holiday Or weekend, to be timely filed. The CommisSion shall grant or refuse the application in whole or in pan within 10 days. The Commission can refuse an application by not acting on it within the I O-day period. An affected person has 30 davs from the date the Commission refuses the application or mails {or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30,day period for appeal to Superior Court runs from the date on i ..).vhich the request is deemed denied (i.e.. 10'}' day after the application tbr rehearing was filed). /~laska Region Domestic Production Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 February 26, 1998 Mr. Dave Johnston Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Reference: Sterling Unit 41-15 Dear Mr. Johnston: Enclosed is the application for permit to drill the referenced well. Please advise if additional information is required. Sincerely, W. C, Barron Operations Superintendent PKB/nrs G:\CMN~DRLG~STERLING\SU41-15~&OGCCLTR Enclosure A subsidiary of USX Corporation Environmentally aware for the long' run. g:\cmn~drlg~sterling~su44-10~AOGCCPTD.XLW STATE OF ALASKA · ALA~ ,, OIL AND GAS CONSERVATION COMM, SSION PERMIT TO DRILL 210 AAC 25.005 la. Type of Work Ddll~] Re-Drill['--] lb. Type ofwell. ExploratorYr~ Stratigraphic Test[~ r, Development oilr-'~ Re-Entry~ Deepen~ Servicer--] Development Gear-"~ single Zone~-/~,~{ © ~u~oner~ 2. Name of Operator 5. Datum Elevation (DF or KB) lO. Field and Pool MARATHON OIL COMPANY 265' KB feet '.~il~l ~ ~:~'''~' 1~ ' : ? ' 1'~'1~;~ ~'q~:''~)~ , 3. Address 6. Property Designation ' i; '~,~; '. '.ii ~' P. O. Box 196168, Anchorage, AK 99519-6168 A-028063 4. Location of Well at Surface 7. Unit or Property Name 11. Type Bond (see 20 AAC 25.025) 2327'FSL, 437'FEL, Sec. 9, T5N, R10W, S.M. Steding Unit Blanket Surety At top of Productive Interval 8. Well Number Number 249'FNL, 3100'FWL, Sec. 15, TSN, R10W, S.M. SU 41-15 5194234 At Total Depth 9. Approximate Spud Date Amount 1072'FNL, 4231'FWL, Sec. 15, T5N, R10W, S.M. 9/1/98 $200,000 12. Distance to Nearest 13. Distance to Nearest Well ~ 14. Number of Acres in Property 15. Proposed Depth (MD and TVD) Property Line 1231 feet 1600 feet 1520 12709' MD/10655' TVD feet 16, To be Completed for Deviated Wells 17. Anticipated Pressure (see 20 AAC 25.035 (e) (2)) Kickoff Depth 2468 feet Maximum Hole Angle 44 ~ Maximum Surface 3761 psig at Total Depth ('I'VD) 18. Casing Program Setting Depth Size Specifications Top Bottom Quantity of Cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" K-55 PE 80-100' 0' 0' 80-100' 80-100' 17-1/2" 13 3/8" 68 K-55 BTC 2250' 0' 0' 2250' 2250' 1990 sx 12 1/4" 9 5/8" 47/53.5 P-110 BTC 9710' 0' 0' 9710' 8030' 2200 sx 8 1/2" 7" 29 L-80 BTC 3199' 9510' 7885' 12709' 10655' 440 sx U D,i L.71 ~ I Sterling Unit SU 41-15 will be directionally drilled to an estimated total depth of 12,709' MD, 10,655' TVD. The existing ~ pad 43-9 will be expanded to a,ccomodate the drilling rig. The following documents are attached: ~ I I Drilling Program, Area Maps, Location Map, Structure Map, Surface use plan, Directional Maps, and ~ Blowout Prevention Equipment drawings. : i I : 20. Attachments Filing FeeL~J Property PlatL~J BOP SketchL~ Diverter SketchL~ Drilling ProgramL~ Drilling Fluid Programr~ Time vs Depth Plotr'-] Refraction Analysis~ Seabed ReportF] 20 AAC 25.050 Requirements[-'-~ 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Commission Use Only 2~"* ~/// 50--/',~'~' .~ 2., O ~ o~'~-~ --~' .~- / ,'~-~ ~ I For Other Requirements Conditions of Approval Samples Required DYes ~No Mud Log Required r"-'~Yes [~No Hydrogen Sulfide Measures r-]Yes ~No Directional Survey Required ~Yes r""]No Required Working Pressure for BOPE 2M F-"]3M F~5M r'"'~ 1OM LJ15M Other: Original Signed By David W. Johnston byordero, ~./~'..._.,~ Approved by Commissioner the Commission Date Form 10-401 Rev. 12-1-85 Submit in Triplicate DRILLING AND COMPLETION PROGRAM ,~' ~ARATHON OIL COMPANY ALASKA REGION WELL: SU 41-15 PAD: 43-9 SLOT: NA REVISION NO.: SURFACE LOCATION: TARGETS: Beluga-T Beluga-LM Tyonek BOTTOMHOLE LOCATION: KB ELEVATION: 265 GL ELEVATION: 235 FIELD: AFE No.: TYPE: Steding Unit Drilling: 6600298/Completion: 1503697 Exploitation DATE: 2/24/98 2327' FSL,437' FEL, Sec.9,T5N,R10W, S.M. 990' FSL, 1399' FWL, Sec. 10,T5N, R10W, S.M. 519' FSL,2045' FWL, Sec. 10,T5N, R10W, S.M. 249' FNL,3100° FWL, Sec. 15,T5N, R10W, S.M. 1072' FNL,4231' FWL, Sec 15,T5N, R10W, S.M. ft. mean S.L. (est.) ft. mean S.L. I. IMPORTANT GEOLOGIC HORIZONS: FORMATION DEPTH(MD-RKB) DEPTH(TVD-RKB) Beluga-Top 6744 5925 Tyonek 9796 8135 II. ESTIMATED FORMATION TOPS AND CONTENT: FORMATION DEPTH(MD-RKB) DEPTH(TVD-RKB) Beluga-Top Beluga-Lower middle Tyonek Tyonek D-1 Tyonek D-2 TD 6744 5925 7904 6765 9796 8135 11545 9565 11983 9965 12709 10655 POTENTIAL CONTENT Gas/Water Gas/Water Gas/Water Gas/Water Gas/Water page 1 liE WELL CONTROL EQUIPMENT i~ DIVERTER il The diverter will consist of a 20" or larger remotely operated annular and a 10" (minimum)O.D. vent line. The vent line valves will be full opening and integrated with the annular in the fail safe design as stipulated in 20AAC 25.035. The vent line will be a minimum of 100° from any source of ignition. BLOWOUT PREVENTERS The blowout preventer stack will consist of a 13 5/8" x 5000 psi annular preventer, a 13 5/8" x 5000 psi double gate ram type preventer outfitted with blind rams in the bottom and pipe rams in the top, a 13 5/8" x 5000 psi drilling spool (mud cross) equipped with a 3-1/16" x 5000 psi outlets, and a 13 5/8"x 5000 psi single gate ram type preventer outfitted with pipe rams. The choke manifold will be rated 3-1/16" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor- boy gas buster, and a vacuum-type degasser. A flow sensor will be installed in the flowline and the mudpits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. STARTING HEAD: CASING HEADS: WELLHEAD SYSTEM 20 3/4" Flange top x 20" weld on bottom. 13-5/8" 5000 PSI top x 13-3/8" sow with base plate for 20". TUBING HEAD: CHRISTMAS TREE: IV. CASING PROGRAM: TYPE Ddve pipe Surface Intermediate Production SIZE 13 3/8" 9 5/8" 7" WEIGHT 61 47/53.5 29 11" - 5000 psi top x 13 5/8"-5000 psi bottom. 3-1/8" - 5000 psi single christmas tree including two master valves, one flow tee, one swab valve one wing valve and a 3 1/8" 5000 psi top x 11" 5000 psi bottom tubing head adaptor. CASING DESCRIPTION SET SET HOLE SIZE WT. GRADE THREAD FROM TO(md/tvd) SIZE 20" 133 K-55 PE Surf 80-100/80-100 Driven 13 3/8" 61 K-55 BTC Surf 2250/2250 17 1/2" 9 5/8" 47/53.5 P-110 BTC Surf 9710/8030 12 1/4" 7" 29 L-80 BTC 9510'md 12709/10655 8 1/2" 7885'tvd CASING DESIGN SETTING FRAC GR FORM PRSS DESIGN FACTORS GRADE DEPTH,TV @ SHOE @ SHOE MASP TENSION COLL. BURST K-55 2250 12.0 1053 1262 8.14 2.82 2.49 P-110 8030. 15.5 3758 3761 4.49' 4.22 1.87 L-80 10655 17.0 4986 3761 10.21 4.10 2.28 V. CEMENTING PROGRAM SURFACE 13 3/8" @ 2250' md/2250' tvd LEAD SLURRY: Class G + required additives TOP OF CEMENT: WEIGHT: YIELD: WATER REQ.: PUMPING TIME: EXCESS (%): ESTIMATED VOLUME: Surface 13.3 ppg. 1.80 cu. ft./sk gal/sk hrs:min 100 % if no caliper is run. 1330 sk TAIL SLURRY: Class G + required additives TOP OF CEMENT: WEIGHT: YIELD: WATER REQ.: PUMPING TIME: EXCESS (%): ESTIMATED VOLUME: 1750 ft.15.8 ppg 1.17 cu. ft./sk gal/sk hrs:min 100 % if no caliper is run. 630 sk RUNNING AND CEMENTING DETAILS: ENSURE WEAR BUSHING IS REMOVED! 1. Remove thread protectors and visually inspect connections. 2. Make up float shoe and one jt of casing. M/U float collar. Check float. Fill pipe until circulating. Baker-lok connections. 3. Run remaining casing and centrilizers. M/U cementing head and test lines. 4. Circulate and reciprocate until no further gains in circulating efficiency are made. 5. Pump spacer as follows: Spacer design to be determined. 6. Drop b~ttom plug. 7. Mix and pump lead slurry. 8. Mix and pump tail slurry. 9. Drop top plug. 10. Displace cement. Reciprocate as long as possible. 11. Bump plug with 500-1000 psi over final displacement pressure. Check floats. 12. Open valve below starting flange and flush from dg floor to valve. 13. WOC. 14. N/D diverter and N/U BOPE and test. Run wear bushing. page 3 INTERMEDIATE: 9 5/8" @ 9710' md/8030' tvd LEAD SLURRY: Class G + required additives TOP OF CEMENT: WEIGHT: YIELD: WATER REQ.: PUMPING TIME: EXCESS (%): ESTIMATED VOLUME: 2000 ft. 13.3 ppg. 1.80 cu. ft./sk gal/sk hrs:min 50 % if no caliper is run. 1700 sk TAIL SLURRY: Class G + required additives TOP OF CEMENT: WEIGHT: YIELD: WATER REQ.: PUMPING TIME: EXCESS (%): ESTIMATED VOLUME 8535 ft. 15.8 ppg. 1.17 cu. ft./sk gal/sk hrs:min 50 % if no caliper is run. 500 sk RUNNING AND CEMENTING DETAILS: ENSURE WEAR BUSHING IS REMOVED! CASING RAMS INSTALLED AND TESTED. 1. Remove thread protectors and visually inspect connections. 2. Make up float shoe and 2 shoe joints. Check float. Fill pipe until circulating. 3. M/U float collar. (Baker-lok all connections to top of float collar) 4. Fill pipe until circulating. 5. Run remaining casing and centralizers. 6. M/U plug head and test all lines.. 7. Circulate until no gain in efficiency is observed. Pump spacer as follows: Spacer design to be determined. 8. Drop bottom plug. Mix and pump Lead slurry. 9. Mix and pump Tail slurry. Drop top plug. 10. Displace with mud. 11. Bump plug with 500-1000 psi over final displacement pressure. Check floats. 12. Wash out between 9 5/8" and wellhead. 13. P/U BOP stack. Set slips. N/U tubing spool. N/U BOP stack. 14. Test BOPE. Run wear bushing. page 4 PRODUCTION: 7"@ 12709'{ 10655' tvd TOL @ 9510' md/78i, .vd LEAD SLURRY: CLASS G + ADDITIVES AS REQUIRED TOP OF CEMENT: WEIGHT: YIELD: WATER REQ.: PUMPING TIME: EXCESS (%): ESTIMATED VOLUME: ft ppg. cu. ft./sk gal/sk hrs:min % over caliper. sk TAIL SLURRY: CLASS G + ADDITIVES AS REQUIRED TOP OF CEMENT: 9510 ft. WEIGHT: 15.8 ppg. YIELD: 1.17 cu. ft./sk WATER REQ.: gal/sk PUMPING TIME: hrs:min EXCESS (%): 25 % over caliper ESTIMATED VOLUME: 440 sk RUNNING AND CEMENTING DETAILS: ENSURE WEAR BUSHING IS REMOVED! CASING RAMS INSTALLED AND TESTED. 1. Remove thread protectors and visually inspect connections. 2. Make up float shoe and 3 shoe joints. Check float. Fill pipe until circulating. 3. M/U float collar. (Baker-lok all connections to top of float collar) 4. Fill pipe until circulating. 5. Run remaining casing and centalizers. M/U liner hanger, RIH to shoe. Fill pipe and break circulation. Finish RIH. 6. Circulate and reciprocate until no gains in circulating efficiency are made. 7. Pump spacer as follows: Spacer design to be determined. 8. Pump cement. Drop dart. 9. Displace cement. Reciprocate as long as possible. 10. Bump plug wi 500 psi over final circulating pressure. Check floats. 11. Set hanger. Release from hanger and CBU. POOH with DP and running tool. 12. WOC 24 hrs. 13. Clean out to TOL with 8 1/2" bit and scraper. Test liner lap. POOH. 14. Clean out liner with 6" bit and scraper. Test liner and casing. 15. Run bond log. page 5 VI. MUD pROGRAM MUD PROPERTIES DEPTH DEPTH WEIGHT VISCOSIT WATER MUD FROM TO ppg sec./qt LOSS TYPE 0' 2250' 8.6-9.0 100 + NC Gel/Water 2250' 9710' 9.0-9.5 50-70 5-10 FLO PRO/KCL 9710' 12709' 9.5-10.0 50-70 <5 FLO PRO/KCL The gel/water mud will be displaced with the FIo Pro mud system pdor to drilling the Beluga formation. MUD EQUIPMENT The solids control equipment will consist of two derrick floline cleaners, a 2-cone desander and a mudcleaner. Centrifuges supplied by MI Ddlling Fluids. Maintaining Iow ddll solids is extremely important when running the FIo Pro system. The fines possible should be run on the floline cleaners and they should be changed or patched as soon as rips develope. The mud engineer will monitor performance of the solids control equipment. Any deviation from peak performance will be reported to the dg Toolpusher and MOC rep. The dg contractor will maintain the equipment at peak performance. VII. LOGGING, TESTING, AND CORING PROGRAMS LOGGING PROGRAM SURFACE HOLE: No logging planned. INTERMEDIATE: RUN #1: AIT/DSI/LDT/CNL. RUN #2: Possibly run MRIL( CMR ) PRODUCTION: RUN #1: AIT/DSI/LDT/CNL. RUN #2: Possibly run MRIL( CMR ) COMPLETION: A Cement Bond Log (CET/GR) will be run pdor to completion. MUD LOGGING The well will be mud I(~gged from 9710' md/8030' tvd to TD and may be logged from 2250' md/tvd to TD. CORING PROGRAM None planned. TESTING PROGRAM No testing planned. VIII. BOTTOMHOLE PRESSURES AND POTENTIAL HAZARDS Hydrogen sulfide gas is not anticipated to be encountered. The Tyonek zone is expected to be normally pressured. No other known hazards. page 6 IX. OTHER INFORMATION DESC RKB KICKOFF, (Tie-in) Build at 2.5/100 END OF BUILD END OF HOLD Drop at 1.0/100 TOTAL DEPTH DIRECTIONAL PLAN MD ']'VD INCL 0 2623 4368 9796 12709 SOUTH EAST VERT AZIM COORD COORD SECTION 0 0.00 0 0 0 0 2623 0.00 126.06 0 0 0 4204 43.60 126.06 372 511 632 8135 43.60 126.60 2576 3537 4376 10655 14.47 126.06 3399 4668 5774 POTENTIAL INTERFERENCE: None DRILLING WELL DISTANCE (ft.) DEPTH (MD) DRILLING PROGRAM Dig cellar. Drive 20" to refusal(80-100'). Put liner down where rig, tanks and camp will be located. Mobilize rig to location and rig up. Weld on starting flange with valve below flange(minimum 300 psi rating) for clean out after 13 3/8" casing job.. N/U diverter and function test. Clean out 20" casing..Drill 17 1/2" hole to 2250'. Run and cement 13 3/8" casing. N/D diverter. Weld on slip on head and test. N/U BOPE and test. RIH with 12 1/4" bit and directional ddlling assembly. Test casing to 1500 psi. Drill out 13 3/8" casing and test shoe to leak off( 12.0 ppg EMW is needed). Directionally drill 12 1/4" hole to 9710'md/8030' tvd. Log. Run and cement 9 5/8" casing. Set slips and packoff. N/U wellhead and test. N/U BOPE and test. RIH with 8 1/2" bit and drilling assembly. Test casing to 3600 psi. Drill out and test shoe to leak off (12 ppg EMW is needed). Directionally ddll to 12709'. Log. Run and cement 7" liner. Clean out to TOL with 8 1/2" bit and scraper. Test liner lap to 3600 psi. Clean out liner with 6" bit and scraper. Test liner and casing to 3600 psi. Run bond log. COMPLETION: Cleanout casing and liner to PBTD. Run CET/GR. Squeeze if necessary. Displace with completion flluid. Complete as per completion program. page 7 NOTES: MASP CALCULATIONS: Surface casing. 13 3/8" MASP = Injection pressure at shoe + S.F. - Hydrostatic pressure of gas columd. MASP = (12.0 ppg + 1.0 ppg) x .052 x 2250' - (. 115 x 2250') MASP = 1521 - 259 MASP -' 1262 PSI. Intermediate/production casing. 9 5/8" MASP = Formation pressure at TD - Hydostatic pressure of gas column. MASP: 9.0 ppg x .052 x 10655' - (.115 x 10655') MASP: 4986 - 1225 MASP = 3761 PSI (note: casing design based on BOPE rating of 5000 psi) Production liner. 7" MASP = Formation pressure - Hydostatic pressure of gas column. MASP: 9,0 ppg x .052 x 10655' -(. 115 x 10655') MASP = 4986 - 1225 MASP = 3761 PSI NOTE: All casing in this design is new. page 8 MARATttON ()il Company kJl,u¢)ure . t'~ocl ,s3-9 Well : SC Field : Sterling Gcs F(elc ~_ocation : Kenai Peninsula. Alaskaj ': WELL PROFILE DATA .............. ~O ,nc D,r ~D '~ort~ £~sl V Sec~ ~ .' ~ on 3 O0 0 00 12606 0,00 0.00 0 00 COO 0 O0 ~o~ 262~ 50 C 00 ~ 26.06 2623.50 O.OO 0.00 C.00 0 O0 ~ [~e o~ ~.~ ~67~3 4360 126.O6 420401 -372.12 5110~ 63217 2.~O ~ "o~qet 6744 05 43.60 126.06 5925.00 - ~336.8~ 1835.95 2271.09 0.00 . "a,~el 790~ O1 4360 126.06 6765,00 -1807.71 2482.63 3071.0~ ~ ~' arqet 9795,85 43,60 126.06 8135.00 -2575.68 3537.32 ~375,70 O.OOJ ~ ~arqe~ ''545 24 26 11 ~26.06 9565.00 -3161.~8 ~342.38 537~.57 ~ OOJ " "c,qel t '98292 21,73 ~ 26.06 9965.00 -3266.31 4485.80 5548,98 100J ~ 2.50 '3 & '.--,t ,'tg9~2 ~447 12606 1065500 -339g.05 z668.10 577448 ~ ooI ' " ? 50 , '~.~c East (feet) -> ~ t7.50 ~5 2 50 aeg ~er ~C)C 't '.~C 600 1200 1800 2~00 3000 3500 4200 4800 27 50 32.50 9 N ~ W ~ j 6~ O 1200 TARC~ ~1 - T/ Beluga 8000 4~ O0 ~ = TGT ~ - Tyonek - ~egin Angle Drop 8500 ~9.00 37.00 35.00 9000 35.00 31.00 27.00 a 23.00 ~ : ~ TARGET ~5 - Tyone~ ' 00O0 ~ 21.00 19.00 17.00 ~ 0500 ~ 15.00 Croatia ~y ~o~es For: P BERGAJ ~[ TARG[T ~6 - TD gate ~mtte~ ' 23-re~-98 I Plot Reference ,s 5U44-t0 Version Jg. I 1 ~ CCO [ T ~ I T I I ' I I I I ; I jC~ra;nates ate en feet refecence ~lot ~SU44-IO. 0 500 1000 1500 2000 2500 ]000 3500 4000 4500' 5000 5500 6000 JTrue V' ...... ~.th.~e [.tlmotea R~B., ] ] Vertical Section (feet) -> Azimuth 126.06 with reference 0.00 N, 0.00 E from slot ~5U44-10 J I~ _ I ' oeo 50O 2000 2500 3300 ~500 ~OCO ~500 5000 5500 6000 5500 7000 7500 MA]tATHON Oil Company Pad %3- 9 SU%4-10 slot #SU44-10 Starling Gas Field Kenai Peninsula, Alaska PROPOSAL LISTING Biker Hughes INTZ<] Your ref : SU44-10 Version 99 Our ref : prop1259 License ~ Date printed ~ 23-Feb-98 Date created = 20-May-97 Last revised , 23-Fab-98 Field is centred on n60 31 54.076,w151 I 34.674 Structure is centred on n60 31 5%.076,w151 i 34.674 Slot loc&tton is n60 32 16.990,w151 I 43.413 Slot Grid coordinates are N 2390036.539, Z 314753.505 Slot local coordinates ars 2326.80 N 437.18 W Projection ~7'G)ez alaska - Zone 4, Spheroids Clarke - 1866 Reference North is True North HARATHON Oil Cc=~ny Pad 43-9,SU44-10 Sterling Gas Field,Kenai Peninsula, Alaska PROPOSAL LISTING Page 1 Your ref : SU44-10 Version #9 Last revised : 23-Feb-98 Measured Inclin. Azimuth T~ue Vert R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 00 R D I N A T ~ S Deg/100ft Sect 0.00 0.00 126.06 0.00 0.00 N 0.00 E 0.00 0.00 500.00 0.00 126.06 500.00 0.00 N 0.00 E 0.00 0.00 1000.00 0.00 126.06 1000.00 0.00 N 0.00 E 0.00 0.00 1500.00 0.00 126.06 1500.00 0.00 N 0.00 E 0.00 0.00 2000.00 0.00 126.06 2000.00 0.00 N 0.00 E 0.00 0.00 2500.00 0.00 126.06 2500.00 0.00 N 0.00 E 0.00 0.00 2623.50 0.00 126.06 2623.50 0.00 N 0.00 E 0.00 0.00 KOP 2723.50 2.50 126.06 2723.%7 1.28 S 1.76 E 2.50 2.~8 2823.50 5.00 126.06 2823.25 5.13 S 7.05 E 2.50 8.72 2923.50 7.50 126.06 2922.64 11.54 S 15.85 E 2.50 19.61 3023.50 10.00 126.06 3021.47 20.50 S 28.15 E 2.S0 34.82 3123.50 12.50 126.06 3119.54 31.98 S 43.92 E 2.50 5%.33 3223.50 15.00 126.06 3216.67 45.97 S 63.13 E 2.50 78.09 3323.50 17.50 126.06 3312.67 62.44 S 85.75 E 2.50 106.07 3423.50 20.00 126.06 3407,35 81.36 S 111.73 E 2.50 138.21 3523.50 22.50 126.06 3500.55 102.69 S 141.03 E 2.50 174.46 3623.50 25.00 126.06 3592.07 126.40 S 173.59 E 2.50 214.73 3723.50 27.50 126.06 3681.75 152.%3 S 209.34 E 2.50 258.95 3823.50 30.00 126.06 3769.42 180.74 S 248.22 E 2.50 307.05 3923.50 32.50 126.06 3854.90 211.27 S 290.15 E 2.50 358.92 4023.50 35.00 126.06 3938.04 243.97 S 335.06 E 2.50 414.47 4123.50 37.50 126.06 4018.68 278.78 S 382.86 E 2.50 473.60 4223.50 40.00 126.06 4096,66 315.62 S 433.45 E 2.50 536.19 %323.50 42.50 126.06 4171.84 354.42 S 486.75 E 2.50 602.12 4367.53 43.60 126.06 4204.01 372.12 S 511.05 E 2.50 632.17 EOC %500.00 43.60 126.06 4299.94 425.89 S 584.90 E 0.00 723.53 5000.00 43.60 126.06 4662.02 628.86 S 863.65 E 0.00 1068~34 5500.00 43.60 126.06 5024.11 831.83 S 1142.40 E 0.00 1413.16 6000.00 43.60 126.06 5386.19 1034.80 S 1421.15 E 0.00 1757.97 6500.00 43.60 126.06 5748.27 1237.77 S 1699.89 E 0.00 2102.79 6744.05 43.60 126.06 5925.00 1336.84 S 1835.95 E 0.00 7000.00 43.60 ~ 126.06 6110.35 1440.74 S 1978.64 E 0.00 7500.00 43.60 126.06 6472.43 1643.71 S 2257.39 E 0.00 7904.01 43.60 126.06 6765.00 1807.71 S 2482.63 E 0.00 8000.00 43.60 126.06 6834.51 1846.67 S 2536.14 E 0.00 2271.09 TARGET #1 - T/ Beluga 2447.60 2792.42 3071.03 TARGET #2 - L/M Beluga 3137.23 8500.00 43.60 126.06 7196.59 2049.64 S 2814.89 E ,0.00 9000.00 43.60 126.06 7558.67 2252.61 S 3093.64 E 0.00 9500.00 43.60 126.06 7920.76 2455.58 g 3372.39 E 0.00 9795.85 43.60 126.06 8135.00 2575.68 S 3537.32 E 0.00 9855.93 43.00 126.06 8178.72 2599.93 S 3570.63 E 1.00 3482.04 3826.86 4171.67 4375.70 TGT 93 - Tyonek - Begin Angle Drop 4416.90 9955.93 42.00 126.06 8252.45 2639.70 S 3625.24 E 1.00 4484.46 10055.93 41.00 126.06 8327.34 2678.70 S 3678.81 E 1.00 4550.72 10155.93 40.00 126.06 8403.38 2716.93 g 3731.31 E 1.00 4615.67 10255.93 39.00 126.06 8480.54 2754.37 S 3782.73 E 1.00 4679.27 10355.93 38.00 126.06 8558.80 2791.01 S 3833.05 E 1.00 4741.53 10455.93 37.00 126.06 8638.14 2826.85 S 3882.27 E 1.00 4802.40 10555.93 36.00 126.06 8718.52 2861.86 S 3930.35 E 1.00 4861.88 10655.93 35.00 126.06 8799.93 2896.04 S 3977.29 E 1.00 4919.95 10755.93 34.00 126.06 8882.35 2929.38 S 4023.08 E 1.00 4976.59 10855.93 33.00 126.06 8965.73 2961.87 S 4067.70 E 1.00 5031.78 All data is in feet unless otherwise stated. Coordinates from slot #5U44-10 and TVD from Estimated RKB (265.00 Ft above mean sea level). Bottom hole distance is 5774.48 on azimuth 126.06 degrees from wellhead. Total Dogleg for wellpath is 72.74 degrees. Vertical section is from wellhead on *asimuth 126.06 degrees. Calculation uses the minimum curvature method. Presented by B~ker Hughes INTEQ MARATHON Oil Com~ny Pad 43-9,SU44-10 Sterling Gas Field, Kenai Peninsula, Alaska Measured Inclin. Azimuth T~-ue Vert R E C T A N G U L A R Depth Degrees Degrees Depth C O O R D I N A T E S PROPOSA~ LISTING Page 2 YOur re~ : SU44-10 Version #9 Last revised : 23-Feb-98 Dogleg Vert Deg/100ft Sect 10955.93 32.00 126.06 9050.07 2993.50 S 4111.13 E 1.00 5085.51 11055.93 31.00 126.06 9135.33 3024.25 S 4153.37 E 1.00 5137.76 11155.93 30.00 126.06 9221.50 3054.13 S 4194.40 ~ 1.00 5188.52 11255.93 29.00 126.06 9308.53 3083.11 S 4234.21 E 1.00 5237.76 11355.93 28.00 126.06 9396.41 3111.20 S 4272.78 E 1.00 5285.47 11455.93 27.00 126.06 9485.11 3138.38 S 4310.11 E 1.00 5331.65 11545.24 26.11 126.06 9565.00 3161.88 S 4342.38 E 1.00 5371.57 11555.93 26.00 126.06 9574.60 3164.64 S 4346.18 E 1.00 5376.97 11655.93 25.00 126.06 9664.86 3189.98 S 4380.98 E 1.00 5419.32 11755.93 24.00 126.06 9755.86 3214.39 S 4414.50 E 1.00 5460.79 11855.93 23.00 126.06 9847.56 3237.87 S 4446.74 ~ 1.00 5500.66 11955.93 22.00 126.06 9939.95 3260.39 S 4477.68 E 1.00 5538.93 11982.92 21.73 126.06 9965.00 3266.31 S 4485.80 E 1.00 5548.98 12055.93 21.00 126.06 10032.99 3281.96 S 4507.30 ~ 1.00 5575.58 12155.93 20.00 126.06 10126.65 3302.58 S 4535.61 E 1.00 5610.60 12255.93 19.00 126.06 10220.92 3322.23 S 4562.60 E 1.00 56%3.98 12355.93 18.00 126.06 10315.75 3340.90 S %588.25 E 1.00 5675.71 12455.93 17.00 126.06 10411.12 3358.60 S 4612.56 E 1.00 5705.78 12555.93 16.00 126.06 10507.00 3375.32 S 4635.52 E 1.00 5734.18 12655.93 15.00 126.06 10603.36 3391.05 S 4657.12 ~ 1.00 5760.90 TARGET #4 - Tyonek D-1 TARGET #5 - Tyonek D-2 12709.32 14.47 126.06 10655.00 3399.05 S 4668.10 g 1.00 5774.48 TARGET #6 - TD All data is in feet unless otherwise stated. Coordinates from slot #SU44-10 ~nd TVD from Estimated RKB (265.00 Ft above mean sea level). Bottom hole distance is 5774.48 on asimuth 126.06 deg=ees from wellhead. Total Dogleg for wellpa~h is 72.74 degrees. Vertical section is from wellhe&d on azimuth 126.06 degrees. Calculation uses ~he minimum curvature method. Presented by Baker Hughes INTEQ MARATHON Oil Co~p~ny Pad 43-9,SU44-10 Sterling Gas Field,Kenai Peninsula, Alaska PROPOSAL LISTING Page 3 YoUT ref: SU44-10 Version Last revised : 23-Feb-98 Comments in wellpath MD TVD Rectangular Coords. C~maent 2623.50 2623.50 0.00 N 0.00 · KOP 4367.53 4204.01 372.12 S 511.05 E EOC 67%4.05 5925.00 1336.8& S 1835.95 E TARGET #1 - T/ Beluga 7904.01 6765.00 1807.71 S 2482.63 E TARGET #2 - L/M Beluga 9795.85 8135.00 2575.68 S 3537.32 E TGT #3 - Tyonek - Begin Angle Drop 11545.24 9565.00 3161.88 S 4342.38 E TARGET 94 - T~onek D-1 11982.92 9965.00 3266.31 S 4485.80 E TARGET #5 - Tyonek D-2 12709.32 10655.00 3399.05 S 4668.10 E T~RGET #6 - TD Targe=~ associated with ~hia wellpa~h Target name Geograp~£c Location T.V.D. Rectangular Coordinates Revised T~onek D-2 Rvsd 18-F 9965.00 3176.635 4330.89E 24-Oct-97 Strlng DEEP (TD)Rvsd 10655.00 3176.635 4330.89E 20-May-97 T~onek D=i Rvsd 18-F 9565.00 3176.$35 4330.89E 20-May-97 T~onek Rvsd 18-Feb-9 8135.00 3117.1%S %250.51E 20-Ma~-97 I~M Beluga Rvsd 18-Fe 6765.00 1749.055 2401.64E 20-May-97 T/ Beluga Rvsd 18-Fe 5925.00 1035.265 I&3?.01E 20-May-97 MARATHON Oil Ccgnp~ny Pad 43-9,SU44-10 Sterling Gas Field, Kenai Peninsula, Alaska Measured Inclin. Azimuth T=ue Vert R E C T A N G U L A R Depth Degrees Degrees Depth C O 0 R D I N A T E S 0.00 0.00 126.06 0.00 2326.80 N 437.18 W 500.00 0.00 126.06 500.00 2326.80 N 437.18 W 1000.00 0.00 126.06 1000.00 2326.80 N 437.18 W 1500.00 0.00 126.06 1500.00 2326.80 N 437.18 W 2000.00 0.00 126.06 2000.00 2326.80 N 437.18 W 2500.00 0.00 126.06 2500.00 2326.80 N 437.18 W 2623.50 0.00 126.06 2623.50 2326.80 N 437.18 W 2723.50 2.50 126.06 2723.47 2325.52 N 435.42 W 2823.50 5.00 126.06 2823.25 2321.67 N 430.13 W 2923.50 7.50 126.06 2922.64 2315.26 N 421.33 W 3023.50 10.00 126.06 3021.47 2306.30 N 409.03 W 3123.50 12.50 126.06 3119.54 2294.82 N 393.26 W 3223.50 15.00 126.06 3216.67 2280.83 N 37%.05 W 3323.50 17.50 126.06 3312.67 2264.36 N 351.43 W 3423.50 20.00 126.06 3407.35 2245.44 N 325.45 W 3523.50 22.50 126.06 3500.55 2224.11 N 296.15 W 3623.50 25.00 126.06 3592.07 2200.40 N 263.59 W 3723.50 27.50 126.06 3681.75 2174.37 N 227.84 W 3823.50 30.00 126.06 3769.42 2146.06 N 188.96 W 3923.50 32.50 126.06 3854.90 2115.53 N 147.03 W 4023.50 35.00 126.06 3938.04 2082.83 N 102.12 W 4123.50 37.50 126.06 4018.68 2048.02 N 54.32 W 4223.50 40.00 126.06 4096.66 2011.18 N 3.73 W 4323.50 42.50 126.06 4171.84 1972.38 N 49.57 E 4367.53 43.60 126.06 4204.01 1954.68 N 73.87 E 4500.00 43.60 126.06 4299.94 1900.91 N 147.72 S000.00 43.60 126.06 4662.02 1697.94 N 426.47 5500.00 43.60 126.06 5024.11 1494.97 N 705.22 6000.00 43.60 126.06 5386.19 1292.00 N 983.97 6500.00 43.60 126.06 5740.27 1089.03 N 1262.71 6744.05 43.60 126.06 5925.00 989.96 N 1398.77 7000.00 43.60 '126.06 6110.35 886.06 N 1541.46 7500.00 43.60 126.06 6472.43 683.09 N 1820.21 7904.01 43.60 126.06 6765.00 519.09 N 2045.45 8000.00 43.60 126.06 6834.51 480.13 N 2098.96 8500.00 43.60 126.06 7196.59 277.16 N 2377.71 9000.00 43.60 126.06 7558.67 74.19 N 2656.46 9500.00 43.60 126.06 7920.76 128.78 S 2935.21 9795.85 43.60 126.06 8135.00 248.88 S 3100.14 9855.93 43.00 126.06 8178.72 273.13 S 3133.45 PROPOSAL LISTING Page 1 Your ref : SU44-10 Version #9 Last revised : 23-Feb-98 Dogleg Vert Deg/100ft Sect 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 KOP 2.50 2.~8 2.50 8.72 2.50 19.61 2.50 34.82 2.50 54.33 2.50 78.09 2.50 106.07 2.50 138.21 2.50 174.46 2.50 214.73 2,50 258.95 2.50 307.05 2.50 358.92 2.50 414.47 2.50 473.60 2.50 536.19 2.50 602.12 2.S0 632.17 Eec 0.00 723.53 0.00 1068.34 0.00 1413.16 0.00 1757.97 0.00 2102.79 0.00 2271.09 TARGET #1 - T/ Beluga 0.00 2447.60 0.00 2792.42 0.00 3071.03 TARGET 92 - L/M Beluga 0.00 3137.23 0.00 3483.04 0.00 3826.86 0.00 4171.67 0.00 4375.70 TGT #3 - Tyonek - BegAn Angle DrOp 1.00 4416.90 9955.93 42.00 126.06 8252.45 312.90 S 3188.06 E 1.00 4484.46 10055.93 41.00 126.06 8327.34 351.90 S 3241.63 E 1.00 4550.72 10155.93 40.00 126.06 8403.38 390.13 S 3294,13 E 1.00 4615.67 10255.93 39.00 126.06 8480.54 427.57 S 3345.55 E 1.00 4679.27 10355.93 38.00 126.06 8558.80 464.21 S 3395.87 E 1.00 4741.53 10455.93 37.00 126.06 8638.14 500.05 S 3445.09 E 1.00 4802.40 10555.93 36.00 126.06 8718.52 535.06 S 3493.17 E 1.00 4861.88 10655.93 35.00 126.06 8799.93 569.24 S 3540.11 E 1.00 4919.95 10755.93 34.00 126.06 8882.35 602.58 S 3585.90 g 1.00 4976.59 10855.93 33.00 126.06 8965.73 635.07 S 3630.52 E 1.00 5031.78 All data is in feet unless otherwise stated. Coordinates from SE Corner of Sec. 9, TSN, R10W SM and TVD from Estimated RKB (265.00 Ft above mean sea level). Bottom hole distance is 5774.48 on azimuth 126.06 degrees from wellhead. Total Dogleg for wellpa~h is 72.74 degrees. Vertical section is from wellhead on azimuth 126.06 degrees. Calculation uses the mtn/~=um curvature method. Presented by Baker Hughes INTEQ MARATHON Oil Ccumpany Pad 43-9,SU44-10 Sterling Gas Field,Kenai Peninsula, Measured Inclin. Azimuth Tx-us Vert R Depth Degrees Degrees Depth C Alaska PROPOSAL LISTING Page 2 Your ref: SU44-10 Version #9 Last revised : 23-Feb-98 E C T A N G U L A R Dogleg Vert O O R D I N A T E S Deg/100ft Sect 10955.93 32.00 126.06 9050.07 666.?0 S 3673.95 E 1.00 5085.51 11055.93 31.00 126.06 9135.33 697.45 S 3716.19 E 1.00 5137.76 11155.93 30.00 126.06 9221.50 727.33 S 3757.22 E 1.00 5188.52 11255.93 29.00 126.06 9308.53 756.31 S 3797.03 E 1.00 5237.76 11355.93 28.00 126.06 9396.%1 784.40 S 3835.60 E 1.00 5285.47 11455.93 27.00 126.06 9485.11 811.58 S 3872.93 E 1.00 5331.65 11545.24 26.11 126.06 9565.00 835.08 S 3905.20 E 1.00 5371.57 TARGET #4 - Tyonek D-1 11555.93 26.00 126.06 9574.60 837.84 S 3909.00 E 1.00 5376.27 11655.93 25.00 126.06 9664.86 863.18 S 3943.80 E 1.00 5419.32 11755.93 24.00 126.06 9755.86 887.59 S 3977.32 E 1.00 5460.79 11855.93 23.00 126.06 9847.56 911.07 S 4009.56 E 1.00 5500.66 11955.93 22.00 126.06 9939.95 933.59 S 4040.50 E 1.00 5538.93 11982.92 21.73 126.06 9965.00 939.51 S 4048.62 E 1.00 5548.98 TARGET #5 - T~onek D-2 12055.93 21.00 126.06 10032.99 955.16 S 4070.12 E 1.00 5575.58 12155.93 20.00 126.06 10126.65 97~.78 S 4098.43 E 1.00 5610.60 12255.93 19.00 126.06 10220.92 995.43 S 4125.42 E 1.00 5643.98 12355.93 18.00 126.06 10315.75 1014.10 S 4151.07 E 1.00 5675.71 12455.93 17.00 126.06 10411.12 1031.80 S 4175.38 E 1.00 5705.78 12555.93 16.00 126.06 10507.00 104B.52 S 4198.34 E 1.00 5734.10 12655.93 15.00 126.06 10603.36 1064.25 S 4219.94 E 1.00 5760.90 12709.32 14.47 126.06 10655.00 1072.25 S 4230.92 1.00 5774.48 TARGKT #6 - TD All data is in feet unless otherwise stated. Coordinates from SE Corner o~ Sec. 9, TSN, R10W SM and TVD from Estimated RK~ (265.00 Ft above mean sea level). Bottom hole distance is 5774.48 on azimuth 126.06 degrees from wellhead. Total Dogleg for wellpath is 72.74 degrees. Vertical section is from wellhead on azi~auth 126.06 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ MARATHON Oil Company Pad 43-9,SU44-10 Sterling G&s Field, Kens1 Peninsula, Alaska PROPOSAL LISTING Page 3 Your ref : SU44-10 Version #9 LaSt revised : 23-Feb-98 Co~maents in wellpat, h MD TVD Rectangular Coords. Commen~ 2623.50 2623 50 %367.53 4204 01 6744.05 5925 00 7904.01 6765 00 9795.85 8115 00 11545.24 9565 00 11982.92 9965 00 12709.32 10655.00 2326 8O 1954 68 989 96 519 O9 248 88 835 O8 939 51 1072.25 417.18 w KOP 73.8? K EOC 1398.77 E TARGET #1 - T/ Beluga 2045.45 E TARGET 92 - L/M Beluga 3100.14 E TGT #3 - Tyonek - Begin Angle Drop 3905.20 E TARGET 94 - Tyonmk D-1 4048.62 E TARGET #S - Tyonek D-2 4230.92 E TARGET 96 - TD Targets associated with this wellpath m m m mmm mm m m mm m m m mm m mmm mmmmmmmmmmmmmmmmmmmmmmmmmmm Target name Geographic Location T.V,D. Rectangular Coordinates Revised Tyonek D-2 Rvsd 18-F 9965,00 849.83S 3893.71E 24-Oct-97 Strlng DEEP (TD)Rvsd 10655,00 849.83S 3893.71E 20-May-97 Tyonek D-1 Rvsd 18-F 9565.00 849.83S 3893.71E 20-May-97 Tyonek Rvsd 1B-Feb-9 8135.00 790.34S 3813.33E 20-May-97 LM Beluga Rvsd 18-Fe 6765.00 577.75N 1964.46E 20-May-97 T/ Beluga Rvsd 18-Fe 5925,00 1291.54N 999.83E 20-May-97 HA~ATHON Oil Company Pad 43-9,SU44-10 Sterling Gas Field,Kenai Peninsula, Alaska PROPOSAL LISTING Page 1 Your ref : SU44-10 Version #9 Last revised : 23=Feb-98 Measured Inclin Azimuth T=ue Vert R E C T A N G U L A R Dogleg Ver= G R I D C O O R D S Depth Degrees Degrees Depth C 00 R D I N A T E S Deg/100ft Sect Easting Northing 0.00 0.00 126.06 0.00 0.00N 0.00E 0.00 0,00 314753.51 2390036.54 500.00 0.00 126.06 500.00 0.00N 0.00E 0.00 0.00 314753.51 2390036.54 1000.00 0.00 126.06 1000.00 0.00N 0.00E 0.00 0.00 314753.51 2390036.54 1500.00 0.00 126.06 1500.00 0.00N 0.00E 0.00 0.00 314753.51 2390036.54 2000.00 0.00 126.06 2000.00 0.00N 0.00E 0.00 0.00 314753.51 2390036.54 2500.00 0.00 126.06 2500.00 0.00N 0.00E 0.00 0.00 314753.51 2390036.54 2623.50 0.00 126.06 2623.50 0.00N 0.00E 0.00 0.00 314753.51 2390036.54 2723.50 2.50 126.06 2723.47 1.285 1.76E 2.50 2.18' 314755.25 2390035.23 2823,50 5.00 126.06 2823.25 5.135 7.05E 2.50 8.72 314760.%7 2390031.30 2923,50 ?.50 126.06 2922.64 11.545 15.85E 2.50 19.61 314769.17 2390024.75 3023.50 10.00 126.06 3021.47 20.50S 28.15E 2.50 34.82 314781.33 2390015.61 3123.S0 12.50 126.06 3119.54 31.985 43.92E 2.50 54.33 314796.92 2390003.88 3223.50 15.00 126.06 3216.67 45.975 63.13E 2.50 78.09 314815.91 2389989.60 3323.50 17.50 126.06 3312,67 62.¢45 85.75E 2.50 106.07 314838.27 2389972.78 3423.50 20.00 126.06 3407.35 81.36S 111.73E 2.50 138.21 314863.95 2389953.45 3523.50 22.50 126.06 3500,55 102.695 141.03E 2.50 174.46 314892.91 2389931.67 3623.50 25.00 126.06 3592.07 126.%05 173.59E 2.50 214.73 314925.09 2389907.46 3723.50 27.50 126.06 3681.75 152.¢35 209.34E 2.50 258.95 314960.43 2389880.87 3823.50 30.00 126.06 3769.42 180.745 248.22E 2.50 307.05 314998.86 2389851.96 3923.50 32.50 126.06 3854.90 211.275 290.15E 2.50 358.92 315040.31 2389820.78 4023.50 35.00 126'.06 3938.04 243.97S 335.06E 2.50 414.47 315084.70 2389787.39 4123.50 37.50 126.06 4018.68 278.785 382.86E 2.50 473.60 315131.95 2389751.84 4223.50 40.00 126.06 4096.66 315,625 %33.45E 2.50 536.19 315181.96 2389714.22 4323.50 42.50 126.06 4171.84 35%.425 486.75E 2.50 602.12 315234.64 238967%.59 4367.53 43.60 126.06 4204.01 372.12S 511.05E 2.50 632.17 315258.66 2389656.52 %500.00 43.60 126.06 4299.94 425.895 584.90E 0.00 723.53 315331.66 2389601.60 5000.00 43.60 126.06 4662.02 628.865 863.65E 0.00 1068.34 315607.19 2389394.33 5500.00 43.60 126.06 5024.11 831.835 1142.40E 0.00 1413.16 315882.72 2389187.05 6000.00 %3.60 126.06 5386.19 1034.80S 1421.15E 0.00 1757.97 316158.25 2388979.77 6500.00 43.60 126.06 5748.27 1237.775 1699.89E 0.00 2102.79 316433.79 2388??2.49 6744.05 43.60 126.06 5925.00 1336.84g 1835.95E 0.00 2271.09 316568.27 2388671.32 7000.00 43.60 e 126.06 6110.35 1440.74S 1978.64E 0.00 2447.60 316709.32 2388565.21 7500.00 43.60 126.06 6472.43 1643.715 2257.39E 0.00 2792.42 316984.85 2388357.93 7904.01 43.60 126.06 6765.00 1807.715 2482.63E 0.00 3071.03 317207.49 2388190.45 8000.00 43.60 126.06 6834.51 1846.675 2536.14E 0.00 3137.23 317260.39 2388150.65 8500.00 43.60 126.06 7196.59 2049.645 2814.89E 0.00 3482.04 317535.92 2387943.38 9000.00 43.60 126.06 7558.67 2252.615 3093.64E 0.00 3826.86 317811.45 2387736.10 9500.00 43.60 126.06 7920.76 2455.585 3372.39E 0.00 4171.67 318086.98 2387528.82 9795.85 43.60 126.06 8135.00 2575.685 3537.32E 0.00 4375.70 318250.02 2387406.17 9855.93 43.00 126.06 8178.72 2599.935 3570.63E 1.00 4416.90 318282.94 2387381.40 9955.93 42.00 126.06 8252.45 2639.70S 3625.24E 1.00 4484.46 318336.92 2387340.79 10055.93 41.00 126.06 8327.34 2678.70S 3678.81E 1.00 4550.72 318389.87 2387300.96 10155.93 40.00 126.06 8403.38 2716.93S 3731.31E 1.00 4615.67 318441.77 2387261.92 10255.93 39.00 126.06 8480.54 2754.375 3782.73E 1.00 4679.27 318492.59 2387223.68 10355.93 38.00 126.06 8558.80 2791.015 3833.05E 1.00 4741.53 318542.34 2387186.26 10455.93 37.00 126.06 8638.14 2826.855 3882.27E 1.00 4802.40 318590.98 2387149.67 10555.93 36.00 126.06 8718,52 2861.865 3930.35E 1.00 4861.88 318638.51 2387113.91 10655.93 35.00 126.06 8799.93 2896.045 3977.29E 1.00 4919.95 318684.91 2387079.01 10755.93 34.00 126.06 8882.35 2929.385 4023.08E 1.00 %976.59 318730.17 2387044.96 10855.93 33.00 126.06 8965.73 2961.87S 4067.70E 1,00 5031.78 318774.27 2387011.78 All da:a in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #SU44-10 and TVD from Estima:ed RrB (265.00 Ft above mean sea level). Bottom hole distance is 5774.48 on azimuth 126.06 degrees from wellhead. Total Dogleg for wellpath is 72.74 degrees. vertical section is from wellhead on azimuth 126.06 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using :he Clarke - 1866 spheroid Presented by Baker Hughes INTEQ MARATHON O£1 Company Pad 43-'9,SU%4-10 Sterling Gas Field,Ksnai Peninsula, Alaska PROPOSAL LISTING Page 2 Your ref : SU&4-10 Version #9 Last revised : 23-Feb-98 Measured In¢lin Azimuth True Vert R E C T A N G U L A R Dogleg Vert G R I D C 00 R D S Depth Degrees Degrees Depth C 00 R D I N A T E S Deg/100ft Sect Easting Northing 10955.93 32.00 126.06 9050.07 2993.505 ¢111.13E 1.00 5085.51 318817.21 2386979.48 11055.93 31.00 126,06 9135.33 3024.255 %153.37E 1.00 5137.76 318858.96 2386948.07 11155.93 30.00 126,06 9221.50 3054.135 %19%.%0E 1.00 5188.52 318899.52 2386917.56 11255.93 29.00 126.06 9308.53 308].115 ¢234.21E 1.00 5237.76 318938,86 2386887.96 11355.93 28.00 126,06 9396.41 3111.205 4272.78E 1.00 5285.%7 318976.99 2386859.28 11455.93 27.00 126.06 9485.11 3138.385 %310.11E 1.00 5331.65 319013,89 2386831.52 11545.24 26.11 126.06 9565.00 3161.885 43%2.38E 1.00 5371.57 319045.79 2386807.52 11555.93 26.00 126.06 9574.60 316%.6%S %346.18E 1.00 5376.27 319049.54 2386804.70 11655.93 25.00 126.06 966%.86 3189.985 4380.98E 1.00 5%19.32 319083.94 2386778.82 11755.93 2%.00 126.06 9755.86 321%.395 441%.50E 1.00 5%60.79 319117.08 2386753.89 11855.93 23.00 126.06 9847.56 3237.875 4446.74E 1.00 5500.66 319168.94 2386729.92 11955,93 22.00 126.06 9939.95 3260.395 4477.68E 1.00 5538.93 319179.52 2386706.92 11982.92 21.73 126.06 9965.00 3266.315 4485.80E 1.00 5548.98 319187.55 2386700.88 12055,93 21,00 126.06 10032.99 3281.965 %507.30E 1.00 5575.58 319208.81 238668%.89 12155,93 20.00 126.06 10126.65 3302.585 4535.61E 1.00 5610.60 319236.79 2386663.8% 12255.93 19.00 126.06 10220.92 3322.235 4562.60E 1.00 56%3.98 319263.%6 23866%3.7? 12355.93 18.00 126.06 10315.75 3340.905 4588.25E 1.00 5675.71 319288.82 2386624.70 12%55.93 17,00 126.06 10%11.12 3358.605 ¢612.56E 1.00 5705.78 319312.85 2386606.62 12555.93 16.00 126.06 10507.00 3375.325 4635.52E 1.00 573%.18 319335.5% 2386589.55 12655.93 15.00 126.06 10603.36 3391.055 4657.12E 1.00 5760.90 319356.90 2386573.48 12709.32 1%.%? 126.06 10655.00 3399.055 %668.10E 1.00 5774.48 319367.75 2386565.32 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #SU%4-10 and TVD from Estimated RF, B (265.00 Ft above mean sea level). Bottom hole distance is 5774.48 on azimuth 126.06 degrees ~rom wellhead. Total Dogleg for wellpath is 72.7% degrees. Vertical section is from wellhead on azimuth 126.06 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and co,gu=ed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ MARATHON Oil Company Pad Sterling Gas Field, Kenai Peninsula, Alaska PROPOSAL LISTING Page 3 Your ref : SU%&-10 Version #9 Last revised : 23-Feb-98 Comments in wellpath mmw~mm~mmmgmmwmm~ MD TVD Rectangular Coords. Comment 2623.~0 2623.50 0.00N 0.00E 4367.53 %204.01 372.12S 511.05E EOC 6744.05 5925.00 1~6.84S 18~.9~K TARGET #1 - T/ Beluga 7904.01 6765.00 1807.71S 2482.6]E TARGET #2 - L/M Beluga 979~.85 8135.00 2575.68S 3537.~2E TGT ~3 - Tyonek - Begin Angle Drop 11545.24 9565.00 3161.88S %]%2.38E TARGET #4 - T~onek D-1 11982.92 9965.00 32&6.31S ¢48~,80E TARGET #~ - T~onek D-2 12709.32 10655.00 3399.05S 4668.10E TARGET 96 - TD Targets associated with ~his wellpa~h mmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmm Target name Geographic ~ocat£on T.V.D. ~e~ta~g~l&~ Coordinate~ ~evimed Tyonsk D-2 Rvsd 18-F 996~.00 3176.63S 4330.89E 24-Oct-97 Strlng DEEP (TD)Rvsd 10655.00 3176.63S 4330.89E 20-May-97 T~onek D-1 Rvsd 18-F 9565.00 3176.63S 4330.89E 20-May-97 T~onek Rvsd 18-Fab-9 813~.00 3117.1%S 4250.51E 20-M&y-97 ~M Beluga Rved 18-Fe 6765.00 1749.05S 2401.64E 20-May-97 T/ Beluga Rved 18-Fe 5925.00 10~.26S 1437.01E 20-May-9? SURFACE USE PLAN FOR STERLING SU 41-15 Surface Location: NEll4 of SE1/4, Sec. 9, T5N, R10W, S.M. 1. Existing Roads Existing roads which will be used for access to Sterling Unit SU 41-15 are shown on the attached map. Soldotna, Alaska is the nearest town to the site and is also shown on the map. 2. Access Roads to be Constructed or Reconstructed No new roads will be required to access SU 41-15. 3. Location of Existing Wells Well SU 41-15 will be drilled on pad 43-9. One well, SU 43-9, already exists on the pad and one additional well (SU 32-9) will be drilled. 4. Location of Existing and/or Proposed Facilities The locations of existing production facilities in the Sterling Unit are shown on the attached drawing. The pad (43-9) will be expanded to accommodate the drilling rig as shown in the drawing. 5. Location of Water Supply No water well exists on pad 43-9 at this time. A dedicated water supply well will be drilled to provide water for the water-based mud. 6. Construction Materials The pad, 43-9 will be expanded to accommodate the drilling rig. The sand and gravel will be obtained from the approved gravel pit in the SW/4, NE/4, Sec. 5, T6N, R10W, S.M. Other materials will be obtained from various vendors and suppliers in Alaska. 7. Methods of Handling Waste Disposal a) Mud and Cuffings Cuttings will be dewatered on location. The cuttings and excess mud will be hauled to Pad 41-18 of the Kenai Gas Field for disposal into Well KU 11-17, a Class il disposal well (AOGCC Disposal Injection Order No. 9, Permit ¢f.81-176). G:\CMN~RLG~STERLING~SU32-9~SURFUSE Surface Use Plan Sterling Unit SU 41-15 Page 2 b) Garbage All household and approved industrial garbage will be hauled to the Kenai Peninsula Borough Soldotna Landfill. c) Completion Fluids Clear fluids will be hauled to Pad 34-31 of the Kenai Gas Field and injected in Well WE #1, an approved disposal well (AOGCC Permit #7-194). d) Chemicals Unused chemicals will be returned to the vendor which provided them. Efforts will be made to minimize the use of all chemicals. e) Sewage Sewage will be hauled to the Kenai sanitation facility. 8. Ancillary Facilities A minimal camp will be established on the pad to house various supervisory and service company personnel. Approximately four railer house type structures will be r~quired for this purpose. Bottled water will be used for human consumption. Potable water will be obtained from the existing water well on the pad. Town & Country will collect and transport sanitary wastes to their ADEC approved disposal facility. No airstrip or additional structures will be necessary. 9. Wellsite Layout The wellsite layout will be determined after construction of the drilling pad. 10. Plans for Reclamation of the Surface Sterling Unit SU 41-15 will be drilled from an existing pad, which will be expanded to accommodate the drilling program. Reclamation of the pad will occur after the abandonment of SU 41'15 and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from the U.S. Fish and Wildlife Service prior to any reclamation work beginning. G:\CMN~DRLG~STERLING~J~-~SURFUSE Surface Use Plan Sterling Unit SU 41-15 Page 3 11. 12. 13. Surface Ownership The surface owner of the land in the Sterling Unit is the U.S. Fish and Wildlife Service. The minerals are under the jurisdiction of the U.S. Bureau of Land Management. Other Vehicle parking areas, as well as other areas where equipment will be set up and operating will be lined with an impervious liner to prevent spills. Operator's Representative and Certification I hereby certify that I, or persons under my direct supervision, have inspected the proposed drill site and access route; that I am familiar with the conditions that currently exist; that the statements made in this plan are, to the best of my knowledge, true and correct; and that the work associated with operations proposed herein will be performed by Marathon Oil Company and its contractors and subcontractors in conformity with this plan and the terms and conditions under which it is approved. This statement is subject to the provisions of 18 U.S.C. 1001 for the filing of a false statement. Date: ?/~~: d Na~e & Title: Marathon Oil ~'ompan~, P. O. Box 196168 Anchorage, Alaska 99519-6168 (907) 561-5311 G:\CMN~DRLG~STERLING~SU32-9~SURFUSE DIVERTER SCHEMATIC STERLING UNIT 41-15 MARATHON OIL COMPANY f , Divert er Sl)ool 10° RemOle OI)erel e(I Valve 20" CONDUCTOR 4 1/16' 4 J/J6* ~u u~J~U~. $3 .~/8' 5u H¥ORII. L M, INULAR pR~£NI£R FLC )J 5/~' 5u St~lr[R DOUBt[ BOP STACK ELEVA'flOH 5- 5/8" 5.000_//_ SHaFFER EXHIBIT A SECTION I PROPOSED BOP STACK CONFIGURATION .____ II ate / ," I - ~-Ii;;3.~Z--- !1"-",.,,i~ "-rZ~"!'~'' "~""' ~ MAU~RIAL LIST FROU SLACK EXHIBIT A SECTION I CHOKE MANIFOLD DESIGN 16'-6' ELECTRIC SHOP (8'-0" X 2a'-o") x 2o'-o')I SCR (8'-0' X 28'-0') WALKWAY 61'-6' V.O,J.UM E TANK 40'-0 X 9'-6' X 7'-0') .~ 4.60 BBLS I _ F- 1300 ~ MUD PUMP { (22'-0' X I F-,3oo ;[~ MUD PUMP STAIRS TO DRILL FLOOR SHAKER TANK (~o'-o' x 9'-6' x 7'-o') 270 BBLS /-- SHAKER TANK /(~O'-0' X 9'-6' X 7'-0') /270 BBLS / /---- DOUBLE SHAKER WATER TANK 300 BBLS FL~/ATOR TO DRILL FLOOR r- BOX ON 800 KW GEN (4 PL¢S.) O 398 (925 HP) (4. PLCS.) 153'-0' 220'-0' 39'-9 1/8' 74'-8 7/8" PIPE RACI END OF TUBULARS DE.RIPeN TH)S IS A PROPR~ETORY OESIGN Ol~ NABORS ALASKA. REP'~OOL~S~'~C,N 0ES)G'94 IS PE'RMI~iBLE ONLY IF AUTHORIZED tN WRITING '~rr~l"mh~~ ~I~ Nooor~ ~Jcsko ~,,.~g in<: . .___._ ._~ 2525 C ..o~o RIG 1 60 rm.c GENERAL ARRANGMENT BY I APPROVED B'~ CW BS OwG. NO. OCT 97 0~'~ ~ RSB Jc.£cKm :sc~ NTS 1600103A lu_rv., of 1 TO: FROM: DATE: Bob Crandall, Alaska Oil & Gas Conservation Commission Paul S. Gardner, Log Analyst, Marathon Oil Company, Anchorage February 26, 1998 RE: EXPECTED PRESSURE GRADIENT MARATHON STERLING 41-15 SEC. 1 5-T5N-RIOW PTD 10650' TVD KENAI PENINSULA BOROUGH, ALASKA Marathon expects to encounter pressure gradients not exceeding 0.5 psi/ft (Mud Weight equivalent - 9.6 ///gallon) while drilling the Sterling 41-1 5. Drilling operations will use mud weights at or below 11 ///gallon. Surrounding well data supports this expectation and plan. Two nearby wells were drilled encountering no abnormal pressure. Sterling Unit 23-15, Sec. 15-T5N-R1OW, 9.7-11.4///gallon, 1961 Sterling Unit 43-9, Sec. 9-T5N-R1 OW, 10.4-11.2 ///gallon Both wells were early wells on a new structure. Drilling operations were, as expected, cautious. Subsequent DST in the deep section of the 23-15 recovered normally pressured gas cut mud. Initial production in the Sterling in both wells was also at normal pressures. This information shows that the mud weights were excessive for the drilled intervals. The recerl't 3-D seismic data over Sterling Field has no evidence of shallow pressure anomaly. (see attached section) XC: J.V. Miesse, Exploitation Manager, Marathon Oil Company, Anchorage W.C. Barron, Drilling Superintendent, Marathon Oil Company, Anchorage o:\exploit\4315press.wpd ,m T6N- ~ A \/,4 w~,su41-15 totest E~uga, ~~ TSN - RIOW 30 29 28' 27 26 ' ¢ ~/:,,~,L~,,?,:,,,:.,,~,.~,;,,, ,,, .,,,7.,,,::,-~.;,¥;,?. . . ~?,:,¥:,'::;',.,,','.',~?,'? , ', ,, . o,ooo, 0 ~ I , I I Mike ,...':, '. ~OmGE ( ALAS~N PRODUCTION REGION ' STERLING GAS FIELD; KENAI, ALAS~ STERLING DEEP EXPLORATION WELL Februa~ 1998 HM49'I 2 Marathon Oil Company P.O. Box 196168 ANCHORAGE, ALASKA 99519-6168 OPERATOR CITY STATE _ _ _ IF REPORTABLE -- INDICATE oR I TYPE OF INTEREST RENTS SERVICES Check Request ANC 2/26/98 A (nrs) · Fi' g e' '~"e'f;~i{'"'"~'0' 'Dri' 2' S't~ri""i"~ "U~i SD "'4iLi5 · FIELD & POOL WELL PERMIT CHECKLIST COMPANY ./~?~,/,/_,,,., ¢/~V, ELL NAME.~----'/ ~./-/_'~' -,~g~',.,~'~<~ 1NIT CLASS ~'~,.¢~" ~... "- ,c:~'<¢:; ~' GEOL AREA ADMINISTRATION PROGRAM: exp,,~ dev~l~redrll [] serv [] wellbore seg; ann. disposal para req _~;~ UNIT# (2>.¢/ ?~' ::2_ ON/OFF SHORE · ,~ REMA KS 1. Permit fee attached ..................... /~-(._Y_~,~4q ~~.~_~~~ 2. Lease number appropriate ................... ~.~,,~I._,N , , ,~ /., v .,---. .... / 3. Unique well name and number .................. 4. Well located in a defined pool .................. Y / ,. Y ~ ti, ~ - . 6. 7. 8. DATE ENGINEERING Conductor string provided ................... NZ~ Surface casing protects all known USDWs ........... N CMT vol adequate to circulate on conductor & sud csg ..... N CMT vol adequate to tie-in long string to surf csg ........ N CMT will cover all known productive horizons .......... N Casing designs a. dequate for C T, B 8, permafrost ....... N Adequate tankage or reserve pit ................. N If a re-drill, has a 10-403 for abandonment been approved... ~/"l,r/~ APPR. DATE -r/ lge Well located proper distance from drilling unit boundary .... Well located proper distance from other wells .......... Sufficient acreage available in drilling unit .......... If deviated, is wellbore plat included ........... N . 9. Operator only affected party .............. ..-.-,Y(~ ~.~,.,¢~ 10. Operator has appropriate bond in force ............. (_~ ~/,~,~ 11. Permit can be issued without conservation order ....... ~,..~- --~, (~, 12 Permit can be issued without administrative approval ...... ~N.~, 13. Can permit be approved before 15-day wait ........... Adequate wellbore separation proposed ............. If diverler required, does it meet regulations .......... Drilling fluid program schematic & equip list adequate ..... BOPEs, do they meet regulation ................ Y BOPE press rating appropriate; test to ps~g. Choke manifold complies w/APl RP-53 (May 84) ........ Work will occur without operation shutdown ........... Is presence of H2S gas probable ................. GEOLOGY N N N N N N N 14. 1'5. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. ,~PR 30. Permit can be issued w/o hydrogen sulfide measures ..... YY N .~/~.,,,).z,__~ 31. Data presented on potential overpressure zones ..... 32. Seismic analysis of shallow gas zones ............. 33. Seabed condition survey (if off-shore) ............. 34. Contact name/phone for weekly,progress re[:)o, rts ..... ,~.JY N Y N {exploratory on~yj .~, p,,,.o~¢,.~. ,D~s~o"SA~ ~.~&2.~'r. ~A.~$ ~, C:.UT'7~ ~5 ~e_c~c,m<,=..~U:::, ~ )N,~,o~..~ 70 F.U-~I -~'=1, ~P¢.~ ,o~ ~u~'~-~,~ ,~,.~ 'To v~u.. ~¢..,~J . G E O L.O_O_O~: ENGINEERING' COMMISSION: Comments/Instructions' u,.)~ ~ JDH _.,-/ RNC t¢~ ,, ~ . - - · co : Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. ALASKA COMPUTING CENTER ****************************** ....... SCHLUMBERGER ....... COMPANY NAME : MARATHON OIL COMPANY WELL NAME : SU 41-15 FIELD NAME : STERLING GAS FIELD BOROUGH : KENAI STATE : ALASKA API NUMBER : 50-133-20484-00 REFERENCE NO : 99004 RECEIVED ~:~,~ 16 1999 Alaska Oil & GasCons. Commi~ion LIS Tape Verifica~ion Liscing SchlumJoerger Alaska CompuTing Cen~er i9-JAN-1999 14:26 PAGE: * ~ * * REEL H~--~EER SERVICE N.%~E DATE ORIGIN : FLiC REEL NA~]E : ? ? ~ 04 CONTINUATION # : PREVIOUS REEL COM2~IENT : .'.L~.~ATH©N C'IL SD., SU 41-15, STERLING GAS FIELD, API 50-133-20484- **** TAPE HF_q_CER SERVICE NAME : F. EJT DATE : 99/01/19 ORIGIN : FLIC TAPE NAME : 99004 CONTINUATION # : PREVIOUS TAPE COGENT : M.,IRATHON OIL CO., SU 41-15, STERLING GAS FIELD, API 50-133-20484- * * * * FILE HEADER FILE NAME : EDIT SERVICE : FLIC VERSION . O01AIO DATE : 99/0 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : ******************************************************************************* ******************************************************************************* ** ** ** ** ** SCHLUMBERGER WELL SERVICES *~ ** ** ** ******************************************************************************* ******************************************************************************* COMPANY NAME: MaraChon Oil Company WELL: SU 41-15 FIELD: Suerling Gas Field BOROUGH: Kenai STATE: Alaska API NUMBER: 50-133-20484-00 LOCATION: 2327' FSL & 437' FEL SECTION: 9 TOWNSHIP: T5N RANGE: RiOW PE.~_41~ENT DATUM: Ground LevELEVATION: 235. 483 ' LCG MEASURED FR©M KB 29.51' ABOVE PERMANENT DATUM LiS Tape Verification Listing Schlumberger Alaska Computing Cen~er 19-JA1~-!999 14:26 PAGE: ELEVATIONS KB: 265' DF: 264' GL: 235.48' DATE LOGGED: 6-DEC-1998 R~ ND~BER: One TD DRILLER: 10330' TD LOGGER: ~330' c~ASING !: 13.625" ~ DRILLER DEPTH OF 2271' AND LOGGER DEPTH OF 2271' BiT SIZE 1: 12.25" ~ 10330' TYPE FLUID IN HOLE: FLO-PRO DENSITY: 9.95 PH: 9.6 VISCOSITY: 50 FLUID LOSS: 7 MUD RESISTIVITY: FILTRATE RESISTIVITY: MUD CAKE RESISTIVITY: O. 172 ~ 65 DEGF O. 134 @ 65 DEGF 0.227 @ 65 DEGF TIME CIRCULATION ENDED: lO:O0 6-DEC~98 TIME LOGGER ON BOTTOM: 19:10 6-DEC-98 MAXIMUM TEMP RECORDED: 145 DEGF LOGGING DISTRICT: Kenai LOGGING ENGINEER: K. Mellah WITNESS: Gary Eller DATE JOB STARTED: 18-JAN-99 JOB REFERENCE NO: 99004 LDP/ANA: R KRUWELL THIS FILE CONTAINS THE MAIN LOG FILE FOR: ARRAY INDUCTION TOOL (AIT) PLATFORM EXPRESS DENSITY/NEUTRON/MICROLOG (PEX) DIPOLE SONIC IMAGER RELABELED DATA (DSI) NATURAL GA~tMA SPECTROSCOPY TOOL (NGT) DATA FORMAT SPECIFICATION RECORD SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 196 4 66 i 5 66 6 73 LIS Tape Verification Lis~ing Schlumberger Almska Computing Cen~er 19-JAN-1999 14:26 PAGE: TYPE REPR CODE VALUE 7 65 ~ 68 0.5 9 65 FT 22 66 5 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 0 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NU~4B NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUNB SAMP ELEM CODE (HEX) DEPT FT 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 GR AIT GAPI 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 CALI AIT IN 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 AOiO AIT OHN~I 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 A020 AIT OHI~N 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 A030 AIT 0H24~ 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 A060 AIT OHN~4 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 A090 AIT OHi~ 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 ATIO AIT OHiTM 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 AT20 AIT O~ 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 AT30 AIT OHMM 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 AT60 AIT OHI~ 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 ATgO AIT Ot~4~I6059223 O0 000 O0 0 1 1 1 4 68 0000000000 AFIO AIT OHl~ff~ 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 AF20 AIT OHNIM 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 AF30 AIT OHNi~I6059223 O0 000 O0 0 1 1 1 4 68 0000000000 AF60 AIT OHN~I 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 AFgO AIT OHl~4 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 TENS AIT LB 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 NPHI PEX PU-S 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 TNPH PEX PU 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 NPOR PEX PU 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 CNTC PEX CPS 60,59223 O0 000 O0 0 1 1 1 4 68 0000000000 CFTC PEX CPS 6059223 O0 000 O0 0 1 1 i 4 68 0000000000 TNRA PEX 6059223 O0 000 O0 0 1 I 1 4 68 0000000000 RTNR PEX 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 RCFT PEX CPS 6059223 O0 000 O0 0 i 1 1 4 68 0000000000 RCNT PEX CPS 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 DEVI PEX DEG 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 SGR NGT GAPI 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 CGR NGT GAPI 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 POTA NGT PU 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 THOR NGT PPM 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 URANNGT PPM 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 HCAL PEX IN 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 LIS Tape Veri£ica~ion Lis~ing 19-JAN-1999 14:26 Schlumberger Alaska Computing Cenuer PAGE: N~E SERV UNIT SERVICE API API API API FILE N%%!B NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NU~IB S~P EL~X! CODE (HEX) HDRA PEX ~7.,?C3 6059223 00 000 O0 0 1 1 ! 4 68 0000000000 PEFZ P~¥ 6059223 O0 000 O0 0 1 ! 1 4 68 0000000000 RHOZ PEX G/C3 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 HMIN PEX OHPR4. 6059223 O0 000 O0 0 1 ! 1 4 68 0000000000 HIVlNO PEX 0~ 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 RXOZ PEX OHS~ 6059223 O0 000 O0 0 i 1 1 4 68 0000000000 GR DSI GAPI 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 DTCO DSI US/F 6059223 O0 000 O0 0 1 ! 1 4 68 0000000000 DTSM DSI US/F 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 PR DSI 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 RSHC DSI 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 CHRP DSI 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 CHR2 DSI 6059223 O0 000 O0 0 i 1 1 4 68 0000000000 TENS DSI LB 6059223 O0 000 O0 0 1 1 1 4 68 0000000000 ** DATA DEPT. A02 O. AIT AT10. AIT AT~O. AIT AF60. AIT TNPH. PEX TNRA PEX DEVI PEX THOR NGT PEFZ PEX RXOZ PEX PR DSI TENS. DS I 10376. 000 -999.250 ..999.250 -999.250 -999.250 999.250 999.250 999.250 999.250 999.250 999.250 -999.250 ~999.250 DEPT. 2132.500 AO20.AIT -999.250 ATiO.AIT -999.250 AT90.AIT -999.250 AF60.AIT -999.250 TNPH. PEX 77.733 TNRA.PEX 4.850 DEVI.PEX 0.000 THOR.NGT 3.779 PEFZ.PEX -999.250 RXOZ.PEX -999.250 PR.DSI -999.250 TENS.DSI -999.250 GR A030 AT20 AFl 0 AF90 NPOR R TNR SGR URAN. RHOZ. GR. RSHC. GR A 030 AT20 AFl 0 AF~O NPOR RTNR SGR URAN. RHOZ. GR. RSHC. AIT -999.250 CALI.AIT -999.250 AOiO.AIT AIT -999.250 AO60.AIT -999.250 AO~O.AIT AIT -999.250 AT30.AIT -999.250 AT60.AIT AIT -999.250 AF20.AIT -999.250 AF30.AIT AIT -999.250 TENS.AIT -999.250 NPHI.PEX PEX -999.250 CNTC. PEX -999.250 CFTC. PEX PEX -999.250 RCFT. PEX -999.250 RCNT. PEX NGT -999.250 CGR.NGT -999.250 POTA.NGT NGT -999.250 HCAL.PEX -999.250 HDRA.PEX PEX -999.250 HMIN. PEX -999.250 H2VlNO.PEX DSI -999.250 DTCO.DSI -999.250 DTSM. DSI DSI -999.250 CHRP.DSI -999.250 CHR2.DSI AIT 58.144 CALI.AIT -999.250 AOiO.AIT AIT -999.250 AO60.AIT -999.250 AO~O.AIT AIT -999.250 AT30.AIT -999.250 AT60.AIT AIT -999.250 AF20.AIT -999.250 AF30.AIT AIT -999.250 TENS.AIT 1612.000 NPHI.PEX PEX 77.065 CNTC. PEX 966.002 CFTC. PEX PEX 4.436 RCFT. PEX 226.202 RCNT. PEX NGT 45.189 CGR.NGT 35.942 POTA.NGT NGT 1.581 HCAL.PEX -999.250 HDRA.PEX PEX -999.250 HMIN. PEX -999.250 HMNO.PEX DSI -999.250 DTCO.DSI -999.250 DTSM. DSI DSI -999.250 CHRP.DSI -999.250 CHR2.DSI -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 ~999.250 -999.250 63.769 198.319 1015.776 1.910 -999.250 -999.250 -999.250 -999.250 ** END OF DATA ** LIS Tape Verification Listing SchlumJ~erger Alaska Computing Center 19-JAN~1999 14:26 PAGE: .... FILE T~AiLER FILE NA~IE : EDIT SERVICE : i'LIC VERSION : ?O!AIO DATE : 99./01/~9 ~ REC SIZE : 1924 FILE TYPE : LAST FILE : ~** FILE HE.XDER FILE NAME : EDIT .002 SERVICE : FLIC VERSION · O01A20 DATE : 99/01/19 MAX REC SIZE : 1024 FILE TYPE : LO t~ST FILE THIS FILE CONTAINS THE REPEAT LOG FILE FOR: ARRAY INDUCTION TOOL (AIT) PLATFORM EXPRESS DENSITY/NEUTRON/MICROLOG (PEX) DIPOLE SONIC IMAGER DATA (DSI) NATURAL GAlVflVlA SPECTROSCOPY TOOL (NGT) DATA FORMAT SPECIFICATION RECORD ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 196 4 66 5 66 6 73 7 65 $ 68 0.5 9 65 FT 21 66 5 12 68 l .) 66 0 14 65 FT 15 66 68 Z6 66 1 0 66 1 LIS Tape VerificaTion LisTing Schlumberger Alaska CompuTing CenSer 19-JAN-1999 14:26 PAGE: * * SET TYPE - .CH.Zu¥ * * NAME SERV UNiT SERVICE API API API API FILE NL'%~B AFu?qB SiZE REPR PROCESS ID ORDER ~ LOG TYPE CLASS MOD NUMB S.a.~'.,P ELEM CODE (HEX) DEPT FT 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 GR AIT gAPI 6059223 OD 000 O0 0 2 1 1 4 68 0000000000 TENS AIT LB 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 CALI AIT IN 6059223 O0 000 O0 0 2 1 1 4 68 0000000000' AOiO AIT OHIVlM6059223 O0 000 O0 0 2 1 1 4 68 0000000000 A020 AIT Oh?4M 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 A030 AIT OH34M 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 A060 AIT OHPIM 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 A090 AIT O~ 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 ATiO AIT OHf4M 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 AT20 AIT Ohflv2~ 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 AT30 AIT OHPiM 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 AT60 AIT OHFIM 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 ATgO AIT OHMM 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 AFiO AIT OH;4~ 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 AF20 AIT OHP~4 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 AF30 AIT OHh~ 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 AF60 AIT OHPiM 6059223 O0 000 O0 0 2 i 1 4 68 0000000000 AFgO AIT OH3fM 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 NPHI PEX PU-S 6059223 O0 000 O0 0 2 1 i 4 68 0000000000 TNPH PEX PU 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 NPOR PEX PU 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 CNTC PEX CPS 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 CFTC PEX CPS 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 TNRA PEX 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 RTNR PEX 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 RCFT PEX CPS 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 RCNT PEX CPS 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 DEVI PEX DEG 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 SGR NGT GAPI 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 CGR NGT GAPI 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 POTA NGT PU 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 THOR NGT PPM 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 URANNGT PPM 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 HCAL PEX IN 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 HDRA PEX G/C3 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 PEFZ PEX 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 RHOZ PEX G/C3 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 HI~INPEX OHPIM 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 HMNO PEX 0fti~'I 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 RXOZ PEX OHRIM 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 GR DSI GAPI 6059223 O0 000 O0 0 2 ! 1 4 68 0000000000 TENS DSI LB 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 DTCO DSI US/F 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 DTSM DSI US/F 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 PR DSI 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 RSHC DSI 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 CHR2 DSI 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 CHRP DSI 6059223 O0 000 O0 0 2 1 1 4 68 0000000000 LIS Tape Verification Lis~ing Schlu~.~erger Alaska Computing Center 19-JAN-1999 14:z6 PAGE: * * DA TA * * DEPT. ADi O. AIT A09 O. AI T AT60.AIT AF3 ~. AI T TNPH. PEX TNRA. PEX DEVI. PEX THOR. NGT PEFZ. PEX RXOZ. PEX DTSM. DSI CHRP. DSI 10368 000 -999 250 -999 250 -999 250 -999 250 -999 250 -999 250 -999 250 -.999.250 -999.250 -999.250 139.961 0.876 GR.AIT AO20.AIT ATiO.AIT ATgO.AIT AF60.AIT NPOR.PEX RTNR.PEX SGR.NGT URAN. NGT RHOZ.PEX GR.DSI PR.DSI -999 250 -999 250 -999 250 -999 250 -999 250 -999 250 -999 250 -999 250 -999 250 -999 250 91 343 0 259 DEPT. 9466.500 GR.AIT 109.581 AOIO.AIT -999.250 AO20.AIT -999.250 Aogo. AIT -999.250 ATiO.AIT -999.250 AT60.AIT -999.250 ATgO.AIT -999.250 AF30.AIT -999.250 AF60.AIT -999.250 TNPH. PEX 28.088 NPOR.PEX 28.750 TNRA.PEX 2.963 RTNR.PEX 3.223 DEVI.PEX 43.636 SGR.NGT 71.805 THOR.NGT 8.161 URAN. NGT 1.667 PEFZ.PEX -999.250 RHOZ.PEX -999.250 RXOZ.PEX -999.250 GR.DSI -999.250 DTSM. DSI -999.250 PR.DSI -999.250 CHRP.DSI -999.250 TENS.AIT -999.250 CALI.AIT -999.250 AO30.AIT -999.250 AO60.AIT -999.250 AT20.AIT -999.250 AT30.AIT -999.250 AFiO.AIT -999.250 AF20.AIT -999.250 AFgO.AIT -999.250 NPHI.PEX -999.250 CNTC. PEX -999.250 CFTC. PEX -999.250 RCFT. PEX -999.250 RCNT. PEX -999.250 CGR.NGT -999.250 POTA.NGT -999.250 HCAL.PEX -999.250 HDRA.PEX -999.250 HMIN. PEX -999.250 HMNO. PEX -999.250 TENS.DSI 3877.000 DTCO.DSI 79.808 RSHC.DSI 1.754 CHR2.DSI 0.952 TENS.AIT 5077.000 CALI.AIT AO30.AIT -999.250 AO60.AIT AT20.AIT -999.250 AT30.AIT AFIO.AIT -999.250 AF20.AIT AF90.AIT -999.250 NPHI.PEX CNTC. PEX 2284.209 CFTC. PEX RCFT. PEX 776.097 RCNT. PEX CGR.NGT 62.053 POTA.NGT HCAL.PEX -999.250 HDRA.PEX HMIN. PEX -999.250 H~NO. PEX TENS.DSI -999.250 DTCO.DSI RSHC.DSI -999.250 CHR2.DSI -999.250 -999.250 -999.250 -999.250 28.871 755.152 2230.364 2.906 -999.250 -999.250 -999.250 -999.250 ** END OF DATA ** ~*~ FILE TRAILER FILE NAME : EDIT .002 SERVICE · FLIC VERSION : O01AIO DATE : 99/01/19 M~k' REC SIZE : 1024 FILE TYPE : LO LAST FILE : LIS Tape Verification Listing 19-J.~N-1999 !4:~ Schlumberger Alaska Computing Center PAGE: **** TAPE TRAILER SERVICE NA~IE : EDIT DATE : 99/01/19 ORIGIN : FLIC TAPE NAME : 99004 CONTI~JATION # : PREVIOUS TAPE : CO~f~IENT : ~LARATHON OIL CO., SU 41-15, STERLING GAS FIELD, API 50-133-20484- **** REEL TRAILER **** SERVICE NAME : EDIT DATE : 99/01/19 ORIGIN · FLIC REEL NAME : 99004 CONTINUATION # : PREVIOUS REEL : COI4MENT : MARATHON OIL CO., SU 41-15, STERLING GAS FIELD, API 50-133-20484- ALASKA COMPUTING CENTER ....... SCHLUMBERGER COMPANY NAME : MARATHON OIL COMPANY WELL NAME : SU 41-15 FIELD NAME : STERLING GAS FIELD BOROUGH : KENAI STATE : ALASKA API N-O~BER : 50-133-20484-00 REFERENCE NO : 99004 RECEIVED FEB 1 6 199'9' AlflSkttOil &GasCons. Commi~ion LIS Tape Verification Lis~ing 19-JAN-1999 15:14 Schlumberger Alaska Compucing Cen~er PAGE: **~* REEL HEADER SERVICE NAME : EDIT DATE : 99/01/19 ORIGIN · FLIC REEL NAME : 99004 CON~fINUATION # PREVIOUS REEL CO~94ENT : MARATHON OIL CO., SU 41-15, STERLING GAS FIELD, API 50-!33-20484- ~*~ TAPE HEADER SERVICE NAME : EDIT DATE : 99/01/19 ORIGIN : FLIC TAPE NAME : 99004 CONTINUATION # : 1 PREVIOUS TAPE : CO~IMENT · MARATHON OIL CO., SU 41-15, STERLING GAS FIELD, API 50-133-20484- **** FILE HEADER FILE NAME : EDIT .001 SERVICE : FLIC VERSION : O01AiO DATE : 99/01/19 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : ******************************************************************************* ******************************************************************************* ** ** SCHLUIgBERGER WELL SERVICES ** ******************************************************************************* COMPANY NAME: Marathon Oil Company WELL: SU 41-15 FIELD: S~erling Gas Field BOROUGH: Kenai STATE: Alaska API NUMBER: 50-133-20484-00 LOCATION: Surface: 2327' FSL & 437' FEL SECTION: 9 TOWNSHIP: T5N RANGE: RiOW PERMANENT DATUM: Ground LevELEVATION: 235.48' LOG MEASURED FROM Kelly Bussing 29.52' ABOVE PERMANENT DATUM LIS Tape Verification Lis~ing Schlumberger Alaska Computing Center 19-JAN-1999 15:14 PAGE ELEVATIONS KB: 265' DF: 264' GL: 235.48' DATE LOGGED: 26-DEC-1998 RLWNUMBER: Two ~ DRILLER: 12600' CASING 1: 9.625" ~ DRILLER DEPTH OF 10311' AND LOGGER DEPTH OF 10310' BIT SIZE 1: 8.5" ~ 12600' TYPE FLUID IN HOLE: FLO-PRO DENSITY: 11.75 PH: 9.3 VISCOSITY: 75 FLUID LOSS: 6.4 MUD RESISTIVITY: 0.189 ~ SS degf FILTRATE RESISTIVITY: 0.162 @ 55 degf MUD CAKE RESISTIVITY: 0.26 ~ 55 degf TIME CIRCULATION ENDED: 00:30 26-DEC-98 TIME LOGGER ON BOTTOM: 18:00 26-DEC-98 ~btXIMO?4 TEMP RECORDED: 150 degf LOGGING DISTRICT: Kenai LOGGING ENGINEER: K. Mellah WITNESS: Sco~ Asay JOB REFERENCE NO: 99004 LDP/ANA: R KRUWELL THIS FILE CONTAINS THE MAIN LOG FILE: ARRAY INDUCTION (AIT) PLATFORM EXPRESS DENSITY/NEUTRON/MICROLOG (PEX) NATURAL GAiV~4A SPECTROSCOPY (NGT) RELABELED DIPOLE SONIC IMAGER (DSI) COMBINABLE MAGNETIC RESONANCE TOOL (CMR) DATA FORMAT SPECIFICATION RECORD ** SET TYPE - 64EB ** TYPE REPR CODE VALUE i 66 0 2 66 0 3 73 240 4 66 1 5 66 6 73 7 65 LIS Tape Verification Lis~ing Schlumberger Alaska Computing Center 19-JAN-1999 15:14 PAGE: TYPE REPR CODE VALUE $ 68 0.5 9 65 FT il 66 4 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 0 ** SET TYPE ~ CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUmB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELE~ CODE (HEX) DEPT FT 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 GR AIT GAPI 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 TENS AIT LB 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 NPHI PEX PU-S 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 TNPH PEX PU 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 NPOR PEX PU 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CNTC PEX CPS 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CFTC PEX CPS 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 TNRA PEX 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 RTNR PEX 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 RCFT PEX CPS 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 RCNT PEX CPS 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 HCAL PEX IN 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 HDRA PEX G/C3 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 PEFZ PEX 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 RHOZ PEX G/C3 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 HMIN PEX OH~4~ 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 HMNO PEX OHMM 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 RXOZ PEX OHMS4 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 DEVI PEX DEG 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 SGR NGT GAPI 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CGR NGT GAPI 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 POTA NGT PU 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 THOR NGT PPM 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 URANNGT PPM 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CALI AIT IN 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 AOiO AIT OHiV~46081201 O0 000 O0 0 1 1 1 4 68 0000000000 A020 AIT OH~I~ 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 A030 AIT OHIO4 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 A060 AIT OHI~I~6081201 O0 000 O0 0 1 1 1 4 68 0000000000 A090 AIT OH~I~ 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 ATIO AIT OHiVi~6081201 O0 000 O0 0 1 1 1 4 68 0000000000 AT20 AIT 0t~4~ 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 AT30 AIT OHNi~I6081201 O0 000 O0 0 1 1 1 4 68 0000000000 AT60 AIT OHN!~ 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 AT90 AIT OHM 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 LIS Tape Verification Listing Schlumberger Alaska Computing Center 19-JAN-1999 15:14 PAGE: NAME SERV UNIT SERVICE API API API API FILE ~VUMB NUMB SIZE REPR PROCESS ID CRDER # LOG TYPE CLASS MOD NOWB S~P ELEM CODE ('HEX) AFiO AIT C'~ 6081201 O0 000 O0 0 1 I i 4 68 0000000000 AF20 AIT OH~M 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 AF30 AIT OH2Tq 6081201 00 000 O0 0 1 1 1 4 68 0000000000 AF60 AIT OHI~M 6081201 00 000 O0 0 1 1 1 4 68 0000000000 AFgO AIT OH~IM 6081201 O0 000 O0 0 1 1 1 4 68 0000000000' DTCO DSI US/F 6081201 00 000 O0 0 1 1 1 4 68 0000000000 DTSM DSI US/F 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 PR DSI 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 RSHC DSI 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CHRP DSI 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CHR2 DSI 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 BFV CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CFF1 CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 . CFF3 CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CFF4 CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CFF5 CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CFF6 CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CMFF CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 CMRP CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 KSDR CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 KTIM CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 TCMR CMR 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 GR CMR GAPI 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 TENS CMR LB 6081201 O0 000 O0 0 1 1 1 4 68 0000000000 ** DATA DEPT. 12628.000 GR.AIT -999.250 TENS.AIT TNPH. PEX -999.250 NPOR.PEX -999.250 CNTC. PEX TNRA.PEX -999.250 RTNR.PEX -999.250 RCFT. PEX HCAL. PEX -999.250 HDRA.PEX -999.250 PEFZ.PEX HMIN. PEX -999.250 HMNO.PEX -999.250 RXOZ.PEX SGR.NGT .-99.9.250 CGR.NGT -999.250 POTA.NGT URAN. NGT -999.250 CALI.AIT -999.250 AOiO.AIT AO30.AIT ...999.250 AO60.AIT -999.250 AO90.AIT AT20.AIT .-999.250 AT30.AIT -999.250 AT60.AIT AFiO.AIT .-999.250 AF20.AIT -999.250 AF30.AIT AFgO.AIT -999.250 DTCO.DSI -999.250 DTSM. DSI RSHC.DSI -999.250 CHRP.DSI -999.250 CHR2.DSI CFF1.CMR -999.250 CFF3.CMR -999.250 CFF4.CMR CFF6.CMR -999.250 CMFF. CMR -999.250 CMRP. CMR KTIM. CMR .-999.250 TCMR.CMR -999.250 GR.CMR DEPT. 10096.000 GR.AIT -999.250 TENS.AIT TNPH. PEX -999.250 NPOR.PEX -999.250 CNTC. PEX TNRA.PEX ..999.250 RTNR.PEX -999.250 RCFT. PEX HCAL.PEX -999.250 HDRA.PEX -999.250 PEFZ.PEX HMIN. PEX -999.250 HMNO. PEX -999.250 RXOE.PEX SGR.NGT -999.250 CGR.NGT -999.250 POTA.NGT -999.250 NPHI.PEX -999.250 CFTC. PEX -999.250 RCNT. PEX -999.250 RHOZ.PEX -999.250 DEVI.PEX · -999.250 THOR NGT -999.250 A020 AIT -999.250 ATiO AIT -999.250 AT90 AIT -999.250 AF60 AIT -999.250 PR DSI -999.250 BFV. CMR -999.250 CFFS.CMR -999.250 KSDR.CMR -999.250 TENS.CMR -999.250 NPHI.PEX -999.250 CFTC. PEX -999.250 RCNT. PEX -999.250 RHOZ.PEX -999.250 DEVI.PEX -999.250 THOR.NGT -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 LIS Tape Verification Lis~ing Schlumberger Alaska Computing Cen~er 19-JAN-1999 15:14 PAGE: URAN. NGT -999.250 3ALI.AIT AO30.AIT -999.250 AO60.AIT AT20.AIT -999.250 AT30.AIT AFIO.AIT -999.250 AF20.AIT AFgO.AIT -999.250 STCO.DSI RSHC. DSI -999.250 SHRP.DSI CFF1.CMR -999.250 3FF3.CMR CFF6.O~R -999.250 CMFF. CMR KTIM. CMR -999.250 ?CMR.CMR -999.250 AOiO.AIT -999.250 Aogo.AIT -999.250 AT60.AIT -999.250 AF30.AIT - 999.250 DTSM. DSI -999.250 CHR2.DSI -999.250 CFF4.CMR -999.250 CMRP. CMR -999.250 GR.CMR -999.250 AO20.AIT -999.250 ATiO.AIT -999.250 ATgO.AIT -999.250 AF60.AIT -999.250 PR.DSI -999.250 B.~;.CMR -999.250 CFFS.CMR -999.250 KSDR.CMR -999.250 TENS.CMR -999 250 -999 250 -999 250 -999 250 -999 250 -999 250 -999 250 -999.250 '-999.250 ** END OF DATA ** **** FILE TRAILER **** FILE NAME : EDIT .001 SERVICE : FLIC VERSION : O01AiO DATE : 99/01/19 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAME : EDIT .002 SERVICE : FLIC VERSION : O01AiO DATE : 99/01/19 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : THIS FILE CONTAINS THE REPEAT FILE: ARRAY INDUCTION (AIT) PLATFORM EXPRESS DENSITY/NEUTRON/MICROLOG (PEX) NATURAL GAMPIA SPECTROSCOPY (NGT) RELABELED DIPOLE SONIC IMAGER (DSI) ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 188 LIS Tape VerificaTion Lis~ing Schlumberger Alaska Computing Cen~er 19-JAN-1999 15:14 PAGE: TYPE REPR CODE VALUE 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT ll 66 5 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 GR AIT GAPI 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 TENS AIT LB 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 NPHI PEX PU-S 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 TNPH PEX PU 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 NPOR PEX PU 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 CNTC PEX CPS 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 CFTC PEX CPS 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 TiaRAPEX 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 RTNR PEX 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 RCFT PEX CPS 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 RCNT PEX CPS 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 HCAL PEX IN 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 HDRA PEX G/C3 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 PEFZ PEX 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 RHOZ PEX G/C3 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 H~IN PEX OPi~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 HNiNOPEX OHIO4 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 RXOZ PEX OH~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 DEVI PEX DEG 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 SGR NGT GAPI 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 CGR NGT GAPI 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 POTA NGT PU 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 THOR NGT PPM 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 URANNGT PPM 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 CALI AIT IN 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 AOIO AIT OHi~ 6081201 O0 000 O0 0 2 ! 1 4 68 0000000000 A020 AIT O~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 A030 AIT OH~4~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 A060 AIT OH~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 A090 AIT OHF~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 ATIO AIT OH~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 LIS Tape VerificaTion Listing Schlumberger Alaska Computing Center 19-JAN-1999 15:14 PAGE: NAME SERV UNIT SERVICE API API API API FILE NU~IB NO?4B SIZE REPR PROCESS ID O~ER # LOG TYPE CLASS MOD NUmB S.~IP ELE~ CODE (HEX) AT20 AIT O~"~f6081201 O0 000 O0 O' 2 1 ! 4 68 0000000000 AT30 AIT OH~ff4 6081201 O0 000 O0 0 2 ! 1 4 68 0000000000 AT60 AIT OH~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 ATgO AIT OH~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 AFiO AIT OHIfl~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 AF20 AIT OHN2~6081201 O0 000 O0 0 2 1 1 4 68 0000000000 AF30 AIT OHl~f6081201 O0 000 O0 0 2 1 1 4 68 0000000000 AF60 AIT OH~ 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 AFgO AIT OHmiC4 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 DTCO DSI [~/F 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 DTSM DSI US/F 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 PR DSI 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 RSHC DSI 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 CHR2 DSI 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 CHRP DSI 6081201 O0 000 O0 0 2 1 1 4 68 0000000000 * * DATA * * DEPT. 11656.000 GR.AIT TNPH. PEX 33.118 NPOR.PEX TNRA.PEX 2.940 RTNR.PEX HCAL.PEX 3.782 HDRA.PEX H~IN. PEX 0.215 HMNO. PEX SGR.NGT 13.341 CGR.NGT URAN. NGT 0.503 CALI.AIT AO30.AIT 7.238 AO60.AIT AT20.AIT 6.803 AT30.AIT AFiO.AIT 1.989 AF20.AIT AF90.AIT 9.205 DTCO.DSI RSHC.DSI 2.030 CHR2.DSI DEPT. 10784 TNPH. PEX 29 TNRA.PEX 2 HCAL.PEX -999 H~IN. PEX -999 SGR.NGT 89 URAN. NGT 1 AO30.AIT -999 AT20. AIT - 999 AFiO.AIT -999 AFgO.AIT -999 RSHC.DSI 1 000 GR.AIT 215 NPOR.PEX 707 RTNR.PEX 250 HDRA.PEX 250 H~NO. PEX 946 CGR.NGT 401 CALI.AIT 250 AO60.AIT 250 AT30.AIT 250 AF20.AIT 250 DTCO.DSI 914 CHR2.DSI 56 470 32 684 3 057 -999 250 0 365 8 985 3 782 9 480 7 752 6 853 80 453 0 974 78 568 25 764 3 783 -999 250 -999 250 77 808 -999 250 -999 250 -999 250 -999 250 88 658 0 000 TENS.AIT CNTC. PEX RCFT. PEX PEFZ. PEX RXOZ. PEX POTA . NGT AO10 . AIT A090 .AIT AT60 .AIT AF30. AIT DTSM. DSI CHRP. DSI TENS.AIT CNTC. PEX RCFT. PEX PEFZ.PEX RXOZ.PEX POTA.NGT AOiO.AIT Aogo.AIT AT60.AIT AF30.AIT DTSM. DSI CHRP.DSI 7370 000 2933 199 952 653 -999 250 2 052 0 245 1 989 9 453 9 861 8 445 163 321 0 941 NPHI. PEX CFTC. PEX RCNT. PEX RHOZ. PEX DEVI. PEX THOR. NGT A020 .AIT ATI O. AIT ATgO. AIT AF60.AIT PR. DSI 7148 000 NPHI. 2431 284 CFTC. 405 318 RCNT. -999 250 RHOZ. -999 250 DEVI 2 586 THOR -999 250 A020 -999 250 ATIO -999 250 AT90 -999 250 AF60 169 650 PR 0 873 PEX PEX PEX PEX PEX NGT AIT AIT AIT AIT DSI 38.425 1014.658 2905.111 -999.250 -999.250 0.991 6.856 1.989 9.212 9.817 0.340 27.121 891.367 1672.939 -999.250 33.571 6.677 -999.250 -999.250 -999.250 -999.250 0.312 END OF DATA ** LIS Tape Verification Lis~ing Schlumberger Alaska Computing CenTer 19-JAN-1999 15:~4 PAGE: **~* FILE TRAILER FILE NAME : EDIT .002 SERVICE : FLIC VERSION : O01AiO DATE : 99/01/19 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : *~ TAPE TRAILER *~ SERVICE NAME : EDIT DATE · 99/01/19 ORIGIN · FLIC TAPE NAME : 99004 CONTINUATION # : 1 PREVIOUS TAPE : COMMENT · MARATHON OIL CO., SU 41-15, STERLING GAS FIELD, API 50-133-20484- **** REEL TRAILER **** SERVICE NAME : EDIT DATE : 99/01/19 ORIGIN : FLIC REEL NAME : 99004 CONTINUATION # : PREVIOUS REEL : COMMENT : MARATHON OIL CO., SU 41-15, STERLING GAS FIELD, API 50-133-20484-
