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Home My WebLink About204-209Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ JBR 07/18/2025 InspectNo:susSTS250527140516 Well Pressures (psi): Date Inspected:4/21/2025 Inspector:Sully Sullivan If Verified, How?Other (specify in comments) Suspension Date:5/25/2024 #324-214 Tubing:0 IA:0 OA:0 Operator:Hilcorp Alaska, LLC Operator Rep:Jason Yoeman Date AOGCC Notified:4/19/2025 Type of Inspection:Initial Well Name:KENAI BELUGA UNIT 42-6 Permit Number:2042090 Wellhead Condition Valves operated easily; Gauges were appropriatly sized, in good shape and readable. Wellhead was clean. SSV, wing valve and flowline isolation valve were all closed and flagged. Well sign was correct and attached to tree. Surrounding Surface Condition The surrounding area was free of debris and well kept Condition of Cellar No visible fluid in the cellar Comments This well has a CIBP @ 5,995 ft MD with cement above to 4,035 ft MD topped with Diesel freeze protect to surface. Location was verified by survey plot. Supervisor Comments Photos (3) attached. Suspension Approval:Sundry Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Friday, July 18, 2025 9 9 9 9 9 9 9 9 9 2025-0421_Suspend_KBU_42-6_photos_ss Page 1 of 2 Suspended Well Inspection – KBU 42-6 PTD 2042090 AOGCC Inspection Rpt # susSTS250527140516 Photos by AOGCC Inspector S. Sullivan 4/21/2025 Tubing Pressure Gauge 2025-0421_Suspend_KBU_42-6_photos_ss Page 2 of 2 IA and OA Pressure Gauges 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: __________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): N/A GL: 21' BF: Total Depth: 2870.42' FSL, 4350.37' FWL, Sec. 6, T4N, R11W. S.M. 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22.Logs Obtained: N/A 23. BOTTOM 20" K-55 139 13-3/8" K-55 1,425' 9-5/8" L-80 5,363' 3-1/2" L-80 7,755' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 430 sx Lead / 170 sx Tail12-1/4" TUBING RECORD 1100 sx8,566' 470 sx N/A Surface 16" N/A 8-1/2" 8,566'3-1/2: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG WAG Gas 5/25/2024 204-209 / 323-558 & 324-214Hilcorp Alaska, LLC 50-133-20546-00-00 Kenai Beluga Unit (KBU) 42-06 FEDA028142 45' FSL, 4199' FWL, Sec. 6, T4N, R22W. S.M. N/A 11/3/2004 8,624' MD / 7,812' TVD 4,035' MD / 3,405' TVD 87' 275112.90 2362048.20 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 CASING WT. PER FT.GRADE 11/15/2004 CEMENTING RECORD N/A N/A SETTING DEPTH TVD 2364870.40 TOP HOLE SIZE AMOUNT PULLED N/A 275315.50 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A BOTTOM SIZE DEPTH SET (MD) N/A PACKER SET (MD/TVD) Surface9.3 90000 DrivenSurface N/A 40 Surface 139'Surface 68 6,172' Surface Surface 133 Surface 1,514' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information Sr Res EngSr Pet GeoSr Pet Eng Kenai / Sterling Gas Pool 6 N/A Oil-Bbl: Water-Bbl: N/A Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By Grace Christianson at 2:24 pm, Jun 14, 2024 Suspended 5/25/2024 JSB RBDMS JSB 061824 xG DSR-7/9/24 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval 31. List of Attachments: Operations Summary, Schematic 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Chad Helgeson, Operations Engineer Digital Signature with Date:Contact Email: chelgeson.hilcorp.com Contact Phone: 907-777-8405 Authorized General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Authorized Name and INSTRUCTIONS Noel Nocas, Operations Manager 907-564-5278 Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation Name at TD: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). 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. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 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. TPI (Top of Producing Interval). Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.06.14 11:57:17 - 08'00' Noel Nocas (4361) Lease: State:Alaska Country:USA Kenai Gas Field Kenai Penisula Borough Kenai Beluga Unit 42-6 6/10/2024 NA Last Revison Date:Revised By: Dated Completed: Donna Ambruz Completion Fluid:12/8/2004 Well Name & Number: Municipality: Fill cleaned out to PBD of 8,529' MD on 2/28/2014 PBTD 6,160' MD 5,351' TVD KBU 42-6 Pad 41-7 45' FSL, 4,199' FWL Sec. 6, T4N, R11W, S.M.Permit #:204-209 API #:50-133-20546-00-00 Property Des:A - 028142 KB Elevation:87' (21' AGL) Lat:60º 30' 50.56" N Long:151º 16' 37.45" W Spud Date:00:30hrs 11/3/04 Reached TD:11/15/04 Rig Released:06:00hrs 11/23/04 PA: Conductor Pipe: 20" K-55 133 ppf Top Bottom MD 0' 139 TVD 0' 139' Surface Casing: 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,514' TVD 0' 1,424' Intermediate Casing: 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,172' TVD 0' 5,363' Cmt w/ 430 sks of 12.5 ppg, Class G lead Production Tubing: 3-1/2" L-80 9.3 ppf EUE 8rd w/ 6.25" OD control line protectors Top Bottom MD 0' 8,566' TVD 0' 7,755' TD 8,624' MD 7,812' TVD Tree cxn = 4-3/4" Otis 9-5/8" x 12-1/4" TOC 3378' (CALC w 25% washout) 3-1/2" x 9-5/8" TOC 4940' (12-01-04 CBL) CIBP @ 6195' w 35' cmt top (1-31-21) Patches over Pool 5 (2/16/24) 5014-5030.75 Owen X Span 5203.5-5230.5 Owen X Span 2.375" ID Perforations Sands MD TVD Date 5.2 B5B 5019-5029 4246-4255 02-01-21 5.2 B5C 5207-5227 4421-4430 01-31-21 Pool 6 5280-5380 4489-4584 02-19-24 Control lines: red line cemented with 1 gallon on 7/2/21 yellow line cemented with 2 gallons on 7/2/21 green line cemented with 1.5 gallons on 7/2/21 Excape Module Perfs MD (RKB): Module 16 6,205' - 6,215' Module 15 6,281' - 6,291' Module 14 6,610' - 6,620' Module 13 6,650' - 6,660' Module 12 6,741' - 6,751' Module 11 6,853' - 6,863' Module 10 6,931' - 6,941' Module 9 6,985' - 6,995' Module 8 7,145' - 7,155' Module 7 7,369' - 7,379' Module 6 7,521' - 7,531'Module 5 7,671' - 7,681' Module 4 8,080' - 8,090'Module 3 8,121' - 8,131' Module 2 8,341' - 8,351'Module 1 8,415' - 8,425' CIBP milled & pushed to 5995' (2-15-24) Top of Cement: 4,035' Btm of Cement: 5,995' (5-24-24) SCHEMATIC Page 1/2 Well Name: KEU KBU 42-06 Report Printed: 6/13/2024www.peloton.com Alaska Weekly Report - Operations Jobs Actual Start Date:10/12/2023 End Date: Report Number 1 Report Start Date 2/9/2024 Report End Date 2/10/2024 Last 24hr Summary MIRU Fox CTU #8. Nippled up BOP's. Spot in work tanks. Set choke skid manifold and connected flowback iron. Filled BOP stack. Could not achieve a good BOP shell test. Troubleshot leak path to swab valve. Serviced and greased valves but was unsuccessful testing against the valve. R/d Fox CTU. Report Number 2 Report Start Date 2/12/2024 Report End Date 2/13/2024 Last 24hr Summary Change out Tree with wellhead representive Report Number 3 Report Start Date 2/13/2024 Report End Date 2/14/2024 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipement, Nipple up BOPE, Pressure test as Per Sundry 250/3000- Passed, No retests, Cut & install coil connector, Pull test to 25k, Make up BHA, Stab onto well & Load coil with H20, Pressure test connector to 3500psi, Pressure test stripper & lube as per sundry, Open valve & run in hole to tag @ 5119', Fill hole with 5 bbls fluid level @ 877', Mill from 5119' to 5120', Stall out & tag 5117.5', Work multiple times changing parameters, Unable to go past 5117.5', Pull out of hole, Drag 1k to 3k drag coming out of hole, Secure well & set down injector head. Report Number 4 Report Start Date 2/14/2024 Report End Date 2/15/2024 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, Pick up injector head & lubricator, Slip & cut 50' 1.75" coil, Pull test 25k-good, Load reel with 35 bbls, Make up coil connection & BHA 2.70", Pressure test lube to 3000 psi, Run in hole & tag @ 5145', Work string & attempt to mil (unable to mill due to irratic torque & stalls), Pull out of hole pick up 2.20" OD x 1.75" ID x 2.8" long venturi nozzle, Run in hole tag @ 5145', Work over junk to 5148' no progress so decsion made to pull out & inspect Venturi packed with metal, Secure well, Blow down reel with N2. Report Number 5 Report Start Date 2/15/2024 Report End Date 2/16/2024 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, Slip & cut 50' coil, Make up coil connector & pull test to 25k-good, Load reel with H2O, Pressure test connector to 3500 psi-good, Make up venturi BHA, Stab onto lube & pressure test 3000-good, Run in hole to tag @ 5145', Work venturi tool from 5135' to 5145', Sit on plug & pushed plug from 5145' to 5995', Pull out of hole, Pick up 2.85" mill for drift. Run in hole to 5996', Circulate & pull out of hole, Shut in & secure well, Lay down BHA & blow down reel with N2, Rig down non essential equipment & release Fox till patch is ran. Report Number 6 Report Start Date 2/16/2024 Report End Date 2/17/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up eline, Pick up & make up 2.87" JBGR with CCL, Make up lube & stab onto well, Pressure test to 250/3000-good, Run in hole to tag 5995', Pick up & make up 26.75' patch & setting tool, Run in hole & set @ 5203.5' to 5230.25', Pull out of the hole, Redress setting tool, Pick up Patch # 2- Run in the hole to set packer, CCL to TS-16.75', Top seal @ 5014' Bottom seal: 5030.75', Pull out of the hole, Rig Down & release AK Eline. Report Number 7 Report Start Date 2/17/2024 Report End Date 2/18/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in and RU fluid pump, MIT to 1830 psi for 30 min, RIH with CT and displace well to N2. Unloaded 51 bbls of fluid. Rig down and release Fox coiled tubing. Report Number 8 Report Start Date 2/19/2024 Report End Date 2/20/2024 Last 24hr Summary PJSM, Crew travel to location. RU e-line. P-test lubricator to 250/2000 psi. Perforate 5,280 - 5,380' with 2" x 20 guns (Pool 6) in five runs. Secure well. RDMO. Report Number 9 Report Start Date 2/23/2024 Report End Date 2/24/2024 Last 24hr Summary PJSM, Crew travel to location. RU Halliburton e-line. P-test lubricator to 250/2,000 psi - good test. SITP: 80 psi. PU PLT tools (pressure, temp, spinner, capacitance, CCL, GR). GIH to 5,400' and log back up to 4,000' making station stops with well shut in. Bleed well down to 15 psi. Log second pass to 5,400' and back up to 4,000' making station stops with well shut in. POH. SITP: 15 psi. Secure well. RDMO. Report Number 10 Report Start Date 5/22/2024 Report End Date 5/23/2024 Last 24hr Summary Load FOX CTU 9 (offshore package) at Fox yard, mobilized equipment to KGF. Rig up equipment and N/u BOP's. Shell test BOP's to 3000psi-good test. SDFN. Report Number 11 Report Start Date 5/23/2024 Report End Date 5/24/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up Fox Coil #9, Function & shell test all equipment, Perform pressure test with AOGCC witness Sully Sullivan, BOP test -good, No retests, Run in hole with 2-1/8" wash nozzle to 5995' tag, Load hole with 6 bbls H20, Pull out of hole & secure well, Lay down lube & injector head Report Number 12 Report Start Date 5/24/2024 Report End Date 5/25/2024 Last 24hr Summary PJSM, Crew travel to location, Pick up & Make up lube & injector head, Pressure test to 3000 psi-good, run in hole with 2-1/8" circ nozzle, Tag @ 5995', Batch mix 18 bbls 12.5# cmt, Pump 14 bbls of fluid, Lay in 17 bbls of 12.5# cmt F/5995' T/3878', Pull out of hole & secure well, WOC, Load well with 8 bbls to surface & secure well. Field: Kenai Gas Field Sundry #: 323-558 / 324-214 State: Alaska Rig/Service:Permit to Drill (PTD) #:204-209Permit to Drill (PTD) #:204-209 Wellbore API/UWI:50-133-20546-00-00 Page 2/2 Well Name: KEU KBU 42-06 Report Printed: 6/13/2024www.peloton.com Alaska Weekly Report - Operations Report Number 13 Report Start Date 5/25/2024 Report End Date 5/26/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up, Pick up lube & 2" blind box, Pressure test lube to 3000 psi- good, Run in hole to tag @ 4035', Fluid level @ surface, Rig down & release slick line, Rig down coil tubing, Release coil tubing. Report Number 14 Report Start Date 6/11/2024 Report End Date 6/12/2024 Last 24hr Summary Ops rig up triplex pump and pressure tested the IA to 1500 psi for 30 min, and tubing to 2000 psi for 30 min. Passed. Field: Kenai Gas Field Sundry #: 323-558 / 324-214 State: Alaska Rig/Service: STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KENAI BELUGA UNIT 42-6 JBR 07/22/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Fox 9 was delayed in testing initially. I was on another location when they were ready to go so I allowed them to start testing up until the draw down or until I could get there. The test chart for the 5 tests that I did not witness is attached. Upon arrival I looked over CTU set up, BOP stack, Choke manifold and documentation. All was in order. Test Results TEST DATA Rig Rep:Terrence RiasOperator:Hilcorp Alaska, LLC Operator Rep:Josh Stevenson Rig Owner/Rig No.:Fox 9 PTD#:2042090 DATE:5/23/2024 Type Operation:WRKOV Annular: Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopSTS240602144934 Inspector Sully Sullivan Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 1 MASP: 80 Sundry No: 324-214 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 0 NA Lower Kelly 0 NA Ball Type 0 NA Inside BOP 0 NA FSV Misc 0 NA 5 NTNo. Valves 2 NTManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 2 1.75 NT Annular Preventer 0 NA #1 Rams 1 1.75 NT #2 Rams 1 blind shear NT #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 2 2" FMC 5k NT HCR Valves 0 NA Kill Line Valves 2 2"FMC 5k NT Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P2400 200 PSI Attained P4 Full Pressure Attained P68 Blind Switch Covers:Pall stations Bottle precharge P Nitgn Btls# &psi (avg)P4@1100 ACC Misc NA0 NA NATrip Tank NA NAPit Level Indicators NA NAFlow Indicator NA NAMeth Gas Detector NA NAH2S Gas Detector NA NAMS Misc Inside Reel Valves 1 NT Annular Preventer NA0 #1 Rams P13 #2 Rams P14 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke NA0 HCR Kill NA0 9 9 99 9 999 9 9The test chart for the 5 tests that I did not witness is attached 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,624'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 10,540psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval:Well shall be used only for production from the gas storage pool unless the requirements of SIO 7A and 20 AAC 25.252 are met. Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 204-209 50-133-20546-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 8,566' 10,160psi 1,425' Size 139' 9-5/8"6,172' 1,514' MD See Attached Schematic 5,750psi 3,060psi 3,450psi 139' 5,363' 139' 1,514' April 19, 2024 3-1/2" 8,566' Perforation Depth MD (ft): 6,172' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Beluga Unit (KBU) 42-06CO 510C Sterling Gas Pool 6 7,755'3-1/2" ~80psi 8,566' 5,150 & 6,195 Length N/A; N/A N/A; N/A 7,812'6,160'5,351' Kenai Sterling Gas 5.2 20" 13-3/8" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Samantha Coldiron at 9:17 am, Apr 15, 2024 324-214 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.04.12 17:58:54 - 08'00' Noel Nocas (4361) Wellsite inspection required per 20 AAC 25.110(e)&(f) within 12 months of approval of this sundry. Provide 10 days notice for AOGCC witness of wellsite inspection. 10-407 SFD 4/15/2024BJM 4/25/24 DSR-4/23/24 4/25/2029 *&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.25 14:30:51 -08'00'04/25/24 RBDMS JSB 042624 Pool 6 Well: KBU 42-06 Date: 04/04/24 Well Name: KBU 42-06 API Number: 50-133-20546-00-00 Current Status: Shut In Storage Well Permit to Drill Number: 204-209 First Call Engineer: Chad Helgeson 907-229-4824 Second Call Engineer: Jake Flora 720-988-5375 Max. Expected BHP: ~ 475 psi @ 4567’ TVD (Based SI PT survey 2/21/24) Max. Potential Surface Pressure: ~ 80 psi (Based on max SI pressure) Change of Program: The procedure below is to plug back the recently added Pool 6 pool in Sundry # 323-558. The conversion of this well to a gas storage production well at KGF in Pool 6 Pool was unsuccessful. The shallower sands were isolated with patches and pressure tested, but when the zone was perforated the well would not flow and high fluid levels were found in the wellbore. Well Status KBU 42-06 is currently a shut-in pool 6 producer which has not flowed. Brief Well Summary KBU 42-06 drilled and completed in 2004 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. The well came online making over 6 MMCFD. In 2021 Sterling perfs were added without success. In February 2024 the CIBP between Sterling Pool 5 zones was milled and pushed to bottom in the well. Permanent patches were set over the open perfs. The tubing was pressure tested and coil blew down the well with N2. The Pool 6 sand was perforated and did not flow. Objective Use coil tubing and plug back pool 6 with cement squeezed into the perfs. Notes Regarding Wellbore Condition - Max deviation: 38 degrees from 1500’ – 4300’. 22 degrees at 5000’. - TOC in 3-1/2” x 9-5/8” annulus at 4940’ (12-01-2004 CBL) - TOC in 9-5/8” x 12-1/4” hole annulus calculated at 3378’ with 25% hole washout (195 bbls cmt slurry) - 5/17/2021 MITIA to 1700psi PASSED Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 2500psi high a. Provide AOGCC 24hr notice for BOP test 3. MU cementing BHA 4. RU Cement pump/skid (PT lines to 3000 psi) 5. RIH with CT to 5500’ 6. Mix and pump 12 bbls of 12-13 ppg cement with LCM 7. Spotting in cement from 5500’ to 4700’ pull coil above 4500’. Pump/squeeze cement into pool 6 zone. Do not exceed 500 psi or pump more than 4.5 bbls a. if pressures above 500 psi, wait 24hrs and tag cement with SL or coil b. If pressure does not exceed 500 psi on surface, mix and pump another ~5 bbls of cement and lay in from 5050 to 4750. And repeat squeeze attempt. gg p pg ypy conversion of this well to a gas storage production well at KGF in Pool 6 Pool was unsuccessful. Shut In Storage Well Pool 6 Well: KBU 42-06 Date: 04/04/24 8. RU SL and RIH and tag cement top (tag should be above top perf at 5280’) a. Dump bail cement with Eline to get a minimum of 25ft of cement above perfs (if necessary) 9. Pressure test tubing and pool 6 plug to 1500 psi (which will also tests patches – if above patch is above the ToC) 10. If tubing will not pass pressure test, set expandable plug below the bottom patch between 5235- 5230 a. Repeat pressure test to 1500 psi b. If necessary set another expandable plug between patches at ~5170. Dump 25ft of cement on plug c. Repeat pressure test d. If necessary set CIBP at ~4990’, place 25ft of cement on plug e. Pressure test to 1500 psi Plan is to leave the well suspended per 20 AAC 25.110. This well has potential for workover and sidetrack candidate in Kenai Gas Field. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Plan is to leave the well suspended See email describing contingency from C. Helgeson 4/23/24. If the options detailed in the email are not achieved, obtain approval from AOGCC for alternative plan. -bjm Tag should be above 4919' MD (100' above top perf at 5019' md). -bjm Lease: State:Alaska Country:USA (TVD): Angle/Perfs: Kenai Gas Field Kenai Penisula Borough Kenai Beluga Unit 42-6 2/21/2024 5,019-8,425 4,246' - 7,614' 4º ĺ 1.8º 6% KCL Last Revison Date:Revised By: Dated Completed: Chad Helgeson Completion Fluid:12/8/2004 Well Name & Number: Municipality: Angle @ KOP and Depth: Perforations (MD): ~1.6º / 100' @ 250 ft Fill cleaned out to PBD of 8,529' MD on 2/28/2014 PBTD 6,160' MD 5,351' TVD KBU 42-6 Pad 41-7 45' FSL, 4,199' FWL Sec. 6, T4N, R11W, S.M.Permit #:204-209 API #:50-133-20546-00-00 Property Des:A - 028142 KB Elevation:87' (21' AGL) Lat:60º 30' 50.56" N Long:151º 16' 37.45" W Spud Date:00:30hrs 11/3/04 Reached TD:11/15/04 Rig Released:06:00hrs 11/23/04 PA: Conductor Pipe: 20" K-55 133 ppf Top Bottom MD 0' 139 TVD 0' 139' Surface Casing: 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,514' TVD 0' 1,424' Intermediate Casing: 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,172' TVD 0' 5,363' Cmt w/ 430 sks of 12.5 ppg, Class G lead Production Tubing: 3-1/2" L-80 9.3 ppf EUE 8rd w/ 6.25" OD control line protectors Top Bottom MD 0' 8,566' TVD 0' 7,755' TD 8,624' MD 7,812' TVD Tree cxn = 4-3/4" Otis 9-5/8" x 12-1/4" TOC 3378' (CALC w 25% washout) 3-1/2" x 9-5/8" TOC 4940' (12-01-04 CBL) CIBP @ 6195' w 35' cmt top (1-31-21) Patches over Pool 5 (2/16/24) 5014-5030.75 Owen X Span 5203.5-5230.5 Owen X Span 2.375" ID Perforations Sands MD TVD Date 5.2 B5B 5019-5029 4246-4255 02-01-21 5.2 B5C 5207-5227 4421-4430 01-31-21 Pool 6 5280-5380 4489-4584 02-19-24 Control lines: red line cemented with 1 gallon on 7/2/21 yellow line cemented with 2 gallons on 7/2/21 green line cemented with 1.5 gallons on 7/2/21 Excape Module Perfs MD (RKB): Module 16 6,205' - 6,215' Module 15 6,281' - 6,291' Module 14 6,610' - 6,620' Module 13 6,650' - 6,660' Module 12 6,741' - 6,751' Module 11 6,853' - 6,863' Module 10 6,931' - 6,941' Module 9 6,985' - 6,995' Module 8 7,145' - 7,155' Module 7 7,369' - 7,379' Module 6 7,521' - 7,531'Module 5 7,671' - 7,681' Module 4 8,080' - 8,090' CIBP milled & pushed to 5995' (2-15-24) Lease: State:Alaska Country:USA (TVD): Angle/Perfs: Kenai Gas Field Kenai Penisula Borough Kenai Beluga Unit 42-6 4/3/2024 5,280-5380'4,489' - 4,584' ~19º NA Last Revison Date:Revised By: Dated Completed: Chad Helgeson Completion Fluid:12/8/2004 Well Name & Number: Municipality: Angle @ KOP and Depth: Perforations (MD): ~1.6º / 100' @ 250 ft Fill cleaned out to PBD of 8,529' MD on 2/28/2014 PBTD 6,160' MD 5,351' TVD KBU 42-6 Pad 41-7 45' FSL, 4,199' FWL Sec. 6, T4N, R11W, S.M.Permit #:204-209 API #:50-133-20546-00-00 Property Des:A - 028142 KB Elevation:87' (21' AGL) Lat:60º 30' 50.56" N Long:151º 16' 37.45" W Spud Date:00:30hrs 11/3/04 Reached TD:11/15/04 Rig Released:06:00hrs 11/23/04 PA: Conductor Pipe: 20" K-55 133 ppf Top Bottom MD 0' 139 TVD 0' 139' Surface Casing: 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,514' TVD 0' 1,424' Intermediate Casing: 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,172' TVD 0' 5,363' Cmt w/ 430 sks of 12.5 ppg, Class G lead Production Tubing: 3-1/2" L-80 9.3 ppf EUE 8rd w/ 6.25" OD control line protectors Top Bottom MD 0' 8,566' TVD 0' 7,755' TD 8,624' MD 7,812' TVD Tree cxn = 4-3/4" Otis 9-5/8" x 12-1/4" TOC 3378' (CALC w 25% washout) 3-1/2" x 9-5/8" TOC 4940' (12-01-04 CBL) CIBP @ 6195' w 35' cmt top (1-31-21) Patches over Pool 5 (2/16/24) 5014-5030.75 Owen X Span 5203.5-5230.5 Owen X Span 2.375" ID Perforations Sands MD TVD Date 5.2 B5B 5019-5029 4246-4255 02-01-21 5.2 B5C 5207-5227 4421-4430 01-31-21 Pool 6 5280-5380 4489-4584 02-19-24 Control lines: red line cemented with 1 gallon on 7/2/21 yellow line cemented with 2 gallons on 7/2/21 green line cemented with 1.5 gallons on 7/2/21 Excape Module Perfs MD (RKB): Module 16 6,205' - 6,215' Module 15 6,281' - 6,291' Module 14 6,610' - 6,620' Module 13 6,650' - 6,660' Module 12 6,741' - 6,751' Module 11 6,853' - 6,863' Module 10 6,931' - 6,941' Module 9 6,985' - 6,995' Module 8 7,145' - 7,155' Module 7 7,369' - 7,379' Module 6 7,521' - 7,531'Module 5 7,671' - 7,681' Module 4 8,080' - 8,090'Module 3 8,121' - 8,131' Module 2 8,341' - 8,351'Module 1 8,415' - 8,425' CIBP milled & pushed to 5995' (2-15-24) Proposed: Cement Top 4700' Cement bottom 5500' PROPOSED CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Chad Helgeson To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] KBU 42-06 (PTD 204-209) Suspension sundry Date:Tuesday, April 23, 2024 3:26:56 PM Bryan, As we discussed hopefully plan A works. However if we do not have cement above the top of the patches we will ensure we have enough cement above the patches to meet the plugging requirements of 20AAC25. Our plan if option A doesn’t work to isolate the Sterling Pool 5.2 with cement 100ft above the top perf laid in with coil. Plan B will be to set a CIBP within 50 ft of top perf and dump 25ft of cement on the plug. If plans change from A or this option B, we will communicate with you on plans forward. Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 22, 2024 2:30 PM To: Chad Helgeson <chelgeson@hilcorp.com> Subject: [EXTERNAL] KBU 42-06 (PTD 204-209) Suspension sundry Chad, Hilcorp’s plan A for this suspending this well meets the regs and can be approved. The contingencies steps 8-10 are not compliant. I started writing some requirements in, but I should ask you what you’d like to do. The issue is the patched perforations need to have cement placed above them. The patches are not sufficient for a P&A plug, so if you tag cement <100’ above the top of the patched perf interval, you will need to dump bail another 25 feet of cement on top, above the top of the patch. Seems like if you lay in cement from the top of junk at 5995’ md and increase cement volume, you’ll reduce the chance of something going wrong with the cement job, like light weight brine from 5500- 5995’ swapping out with the cement above it and you’ll be unlikely to need the contingencies. Do you want to adjust the procedure to account for the above? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/15/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240315 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 12/6/2023 AK E-LINE Cement-JetCut BCU 13 50133205250000 203138 2/11/2024 AK E-LINE CIBP-Perf BCU 19RD 50133205790100 219188 2/20/2024 AK E-LINE Perf-CIBP BRU 232-26 50283200770000 184138 11/26/2023 AK E-LINE GPT-PLUG-PERF BRU 244-27 50283201850000 222038 2/27/2024 AK E-LINE GPT-Perf GP ST 18742 37 (AN- 37) 50733203940000 187109 11/22/2023 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 11/3/2023 AK E-LINE GPT-PERF KBU 42-6 50133205460000 204209 2/16/2024 AK E-LINE Patch PBU L-122 50029231470000 203051 12/7/2023 AK E-LINE Patch NCIU A-12B 50883200320200 223053 12/6/2023 AK E-LINE Perf-GPT NCIU A-17 50883201880000 223031 12/10/2023 AK E-LINE Perf-GPT NCIU B-02 50883200900100 197210 3/9/2024 AK E-LINE GPT-Perf SRU 241-33B 50133206960000 221053 3/6/2024 AK E-LINE GPT-Cmnt-CIBP- Perf Please include current contact information if different from above. T38630 T38630 T38631 T38632 T38633 T38634 T38635 T38636 T38637 T38638 T38639 T38640 T38641 KBU 42-6 50133205460000 204209 2/16/2024 AK E-LINE Patch Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.18 08:49:06 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/7/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240307 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 1/9/2024 AK E-LINE GPT-Perf BCU 19RD 50133205790100 219188 1/25/2024 AK E-LINE Perf BCU 13 50133205250000 203138 12/8/2023 AK E-LINE CMT CUT END 2-34 50029216620000 186172 10/29/2023 AK E-LINE PERF KBU 42-6 50133205460000 204209 2/19/2024 AK E-LINE Perf MPU C-13 50029213280000 18567 2/15/2024 AK E-LINE Whipstock Please include current contact information if different from above. T38604 T38604 T38605 T38606 T38607 T38608 KBU 42-6 50133205460000 204209 Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.07 13:13:02 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/28/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240228 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# AN-37 50733203940000 187109 11/8/2023 HALLIBURTON RBT KBU 31-18 50133206490000 215024 2/22/2024 HALLIBURTON PressTemp KBU 42-6 50133205460000 204209 2/23/2024 HALLIBURTON PPROF KU 31-07X 50133204950000 200148 2/2/2024 HALLIBURTON PressTemp MPU C-13 50029213280000 185067 2/23/2024 READ CaliperSurvey MPU C-14 50029213440000 185088 2/23/2024 READ CaliperSurve MPU L-43 50029231900000 203224 2/14/2024 READ CaliperSurvey MPU J-08A 50029224970100 199117 1/21/2024 HALLIBURTON COILFLAG TBU M-20 50733205870000 209093 1/1/2024 HALLIBURTON COILFLAG Please include current contact information if different from above. T38535 T38536 T38537 T38538 T38539 T38540 T38541 T38542 T38543 2/29/2024 KBU 42-6 50133205460000 204209 2/23/2024 HALLIBURTON PPROF Kayla Junke Digitally signed by Kayla Junke Date: 2024.02.29 09:17:32 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Joshua Stephenson - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Subject:BOPE test report KBU 42-06 Date:Wednesday, February 14, 2024 9:54:28 AM Attachments:KBU 42-06 2-13-2024 Initial.xlsx Good Morning, Please see attached BOPE test report, If any issues please reach out. Thank you! Joshua Stephenson 505-386-8853 Joshua.stephenson@hilcorp.com Well Site Supervisor The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. .HQDL%HOXJD8QLW 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSub m it to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:8 DATE: 2/13/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #22042090 Sundry #323-558 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:N/A Valves:250/3000 MASP:1176 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NA Permit On Location P Hazard Sec.P Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 0NA Test Fluid Water Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0NAPit Level Indicators NA NA #1 Rams 1 1.75" pipe slips P Flow Indicator NA NA #2 Rams 1 Blind/Shears NA Meth Gas Detector NA NA #3 Rams 0NAH2S Gas Detector NA NA #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 2 2-1/16" valves P Time/Pressure Test Result HCR Valves 0NASystem Pressure (psi)2950 P Kill Line Valves 2 2-1/16" valves P Pressure After Closure (psi)2300 P Check Valve 0NA200 psi Attained (sec)3 P BOP Misc 0NAFull Pressure Attained (sec)12 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 1300/4 P No. Valves 5P ACC Misc 0NA Manual Chokes 2P Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 0 NA #1 Rams 28 P Coiled Tubing Only:#2 Rams 29 P Inside Reel valves 1P #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:3.0 HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 2/12/2024 @ 09:00 Waived By Test Start Date/Time:2/13/2024 9:00 (date) (time)Witness Test Finish Date/Time:2/13/2024 12:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Terence Rais Hilcorp Alaska LLC Joshua Stephenson KBU 42-06 Test Pressure (psi): trais@foxak.com Joshua.stephenson@hilcorp.com Form 10-424 (Revised 08/2022)2024-0213_BOP_Fox8_KBU_42-06 9 9 9 9 99 9 99 9 9 MEU -5HJJ From:Jacob Flora To:Brian Glasheen Subject:FW: Cementing Follow Up Report: Excape Control Lines Date:Wednesday, October 25, 2023 10:24:20 AM Boom From: Jake Flora - (C) <Jake.Flora@hilcorp.com> Sent: Monday, July 12, 2021 2:20 PM To: bryan.mclellan@alaska.gov Cc: Taylor Wellman <twellman@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Jake Flora - (C) <Jake.Flora@hilcorp.com> Subject: Cementing Follow Up Report: Excape Control Lines Bryan, Below are the ¼” control lines we squeezed with the grease pump and Halliburton’s FineCem squeeze cement on the Excape IA squeezed wells we did in early January 2021. As you will notice the lines took a varying amount of cement. The 0.25” lines have an ID of 0.152” and capacity of 0.00094 gllons/ft. 2 gallons equates to 2127’ of control line. I plan on updating the WBDs and notating the cement volume pumped on each. Let me know if there is anything additional you would like to see here- Thanks, Jake PTD Well cement volume pumped date cemented 202-091 KBU 11-08Y 2 gallons on each line (7/2/2021) 205-141 KBU 41-06 1.5 gal red, 2 gal yellow and 2 gal green (7/2/2021) 204-209 KBU 42-06 2 gal yellow, 1.5 green and 1 gal red (7/2/2021) 200-179 KBU 44-06 1 gal red and 2 gal green (7/2/2021) 207-149 KBU 14-06Y 1.5 gal green and 0.5 gal red (7/2/2021) 203-217 KBU 23-07 1 gal red, .5 gal green and 1 gal yellow (7/2/2021) 203-025 BCU-11 2 gallons on each line (7/3/2021) 204-209 KBU 42-06 2 gal yellow, 1.5 green and 1 gal red (7/2/2021) 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: *, N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,624'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 10,540psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval:Well shall be used only for production from the gas storage pool unless the requirements of SIO 7A and 20 AAC 25.252 are met. Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng brian.glasheen@hilcorp.com 907-564-5277 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Brian Glasheen, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 204-209 50-133-20546-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 8,566' 10,160psi 1,425' Size 139' 9-5/8"6,172' 1,514' MD See Attached Schematic 5,750psi 3,060psi 3,450psi 139' 5,363' 139' 1,514' October 20, 2023 3-1/2" 8,566' Perforation Depth MD (ft): 6,172' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Beluga Unit (KBU) 42-06CO 510C Sterling Gas Pool 6 7,755'3-1/2" ~1,176 psi 8,566' 5,150 & 6,195 Length N/A; N/A N/A; N/A 7,812'6,160'5,351' Kenai Sterling Gas 5.2 20" 13-3/8" See Attached Schematic m n P s 66 t 2 N *Convert to Gas Storage Production Well Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:48 pm, Oct 10, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.10.10 13:02:16 - 08'00' Noel Nocas (4361) Perforate New Pool P CT BOP test to 3000 psi 10-404 Sterling Gas Pool 6 X SFD 10/12/2023BJM 10/31/23 DSR-10/13/23 Adjust perf location on wellbore diagram submitted with 10-404, indicating perfs above 9-5/8" csg shoe. &': Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.11.01 08:55:09 -08'00'11/01/23 RBDMS JSB 110223 Pool 6 Well: KBU 42-06 Date: 10/04/2023 Well Name: KBU 42-06 API Number: 50-133-20546-00-00 Current Status: Shut In Gas Producer Leg: N/A Estimated Start Date: 10/20/23 Rig: Coil, E-Line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 204-209 First Call Engineer: Brian Glasheen 907 -545-1144 Second Call Engineer: Chad Helgeson 907-229-4824 AFE Number: Max. Expected BHP: ~ 1600 psi @ 4243’ TVD (Based on offset well data) Max. Potential Surface Pressure: ~ 1176 psi (Based on expected BHP and gas gradient to surface (0.10psi/ft)) Well Status KBU 42-06 is currently a shut-in Excape well offline since 2008. Brief Well Summary KBU 42-06 drilled and completed in 2004 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. The well came online making over 6 MMCFD. The well had a history of making solids eventually sanding up and went offline in 2007 with a brief period of low rate flow in 2008 after a coil cleanout. The well had cum’d 3.5 BCF and 20.8 MBW of water. 2021 Sterling perfs were added without success. Well did not flow. In 2021 a CIBP with 35’ of cement on top was set to isolate the Beluga to pursue up hole perfs in the Sterling. 20’ of perfs were added and did not produce, a CIBP was set to isolate and another 10’ of perfs were added above that did not produce Objective Mill CIBP, patch Sterling perfs and add Pool 6 perfs to allow additional producers in Pool 6. This will help meet peak demand during the winter months. Will only be used as a producer. Notes Regarding Wellbore Condition - Max deviation: 38 degrees from 1500’ – 4300’. 22 degrees at 5000’. -TOC in 3-1/2” x 9-5/8” annulus at 4940’ (12-01-2004 CBL) - TOC in 9-5/8” x 12-1/4” hole annulus calculated at 3378’ with 25% hole washout (195 bbls cmt slurry) - 5/17/2021 MITIA to 1700psi PASSED Procedure Coil 1.RU Coil, PT Lubricator, Mill CIBP at ~5150 and push to bottom ~6195’MD. Eline 1.RU Eline, PT Lubricator 2.Set 25’ patch over perfs 5207-5227’ MD. 3. Set 15' patch over perfs 5019-5029’ MD. 4. MIT-T 1500 psi patch Sterling perfs and add Pool 6 perfs PT lubricator to >MPSP. -bjm Pool 6 Well: KBU 42-06 Date: 10/04/2023 Coil 1.RU Coil, PT Lubricator 2. Swap well over to N2. Reverse lift fluid from well below 5,420 MD. 3. RDMO E-line Procedure (Contingency) 1. RU Eline. Test lubricator to 250/2,000 psi. 2. Perforate the below sands in pool 6 from the bottom up: Pool Sand Top MD Btm. MD Feet Pool 6 Pool 6 C1 5,280 5,380 100 3. RDMO Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil BOP Diagram 4. Nitrogen SOP bjm Lease: State:Alaska Country:USA Angle/Perfs: Revised By: Dated Completed: Brian Glasheen Completion Fluid:12/8/2004 Well Name & Number: Municipality: Angle @ KOP and Depth:~1.6º / 100' @ 250 ft Kenai Gas Field Kenai Penisula Borough Kenai Beluga Unit 42-6 10/10/2023 4º ĺ 1.8º 6% KCL Last Revison Date: Fill cleaned out to PBD of 8,529' MD on 2/28/2014 PBTD 6,160' MD 5,351' TVD KBU 42-6 Pad 41-7 45' FSL, 4,199' FWL Sec. 6, T4N, R11W, S.M.Permit #: 204-209 API #: 50-133-20546-00-00 Property Des: A - 028142 KB Elevation: 87' (21' AGL) Lat: 60º 30' 50.56" N Long: 151º 16' 37.45" W Spud Date: 00:30hrs 11/3/04 Reached TD: 11/15/04 Rig Released: 06:00hrs 11/23/04 PA: Conductor Pipe: 20" K-55 133 ppf Top Bottom MD 0' 139 TVD 0' 139' Surface Casing: 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,514' TVD 0' 1,424' Intermediate Casing: 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,172' TVD 0' 5,363' Cmt w/ 430 sks of 12.5 ppg, Class G lead Production Tubing: 3-1/2" L-80 9.3 ppf EUE 8rd w/ 6.25" OD control line protectors Top Bottom MD 0' 8,566' TVD 0' 7,755' TD 8,624' MD 7,812' TVD Tree cxn = 4-3/4" Otis 9-5/8" x 12-1/4" TOC 3378' (CALC w 25% washout) 3-1/2" x 9-5/8" TOC 4940' (12-01-04 CBL) CIBP @ 6195' w 35' cmt top (1-31-21) CIBP @ 5150' (2-1-21) SCHEMATIC Perforations Sands MD TVD Date 5.2 B5B 5019-5029 4246-4255 02-01-21 5.2 B5C 5207-5227 4421-4430 01-31-21 Control lines: red line cemented with 1 gallon on 7/2/21 yellow line cemented with 2 gallons on 7/2/21 green line cemented with 1.5 gallons on 7/2/21 Excape Module Perfs MD (RKB): Module 16 6,205' - 6,215' Module 15 6,281' - 6,291' Module 14 6,610' - 6,620' Module 13 6,650' - 6,660' Module 12 6,741' - 6,751' Module 11 6,853' - 6,863' Module 10 6,931' - 6,941' Module 9 6,985' - 6,995' Module 8 7,145' - 7,155' Module 7 7,369' - 7,379' Module 6 7,521' - 7,531' Module 5 7,671' - 7,681' Module 4 8,080' - 8,090' Module 3 8,121' - 8,131' Lease: State:Alaska Country:USA (TVD): Angle/Perfs: Kenai Gas Field Kenai Penisula Borough Kenai Beluga Unit 42-6 10/10/2023 5,019-8,425 4,246' - 7,614' 4º ĺ 1.8º 6% KCL Last Revison Date:Revised By: Dated Completed: Donna Ambruz Completion Fluid:12/8/2004 Well Name & Number: Municipality: Angle @ KOP and Depth: Perforations (MD): ~1.6º / 100' @ 250 ft Fill cleaned out to PBD of 8,529' MD on 2/28/2014 PBTD 6,160' MD 5,351' TVD KBU 42-6 Pad 41-7 45' FSL, 4,199' FWL Sec. 6, T4N, R11W, S.M.Permit #: 204-209 API #: 50-133-20546-00-00 Property Des: A - 028142 KB Elevation: 87' (21' AGL) Lat: 60º 30' 50.56" N Long: 151º 16' 37.45" W Spud Date: 00:30hrs 11/3/04 Reached TD: 11/15/04 Rig Released: 06:00hrs 11/23/04 PA: Conductor Pipe: 20" K-55 133 ppf Top Bottom MD 0' 139 TVD 0' 139' Surface Casing: 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,514' TVD 0' 1,424' Intermediate Casing: 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,172' TVD 0' 5,363' Cmt w/ 430 sks of 12.5 ppg, Class G lead Production Tubing: 3-1/2" L-80 9.3 ppf EUE 8rd w/ 6.25" OD control line protectors Top Bottom MD 0' 8,566' TVD 0' 7,755' TD 8,624' MD 7,812' TVD Tree cxn = 4-3/4" Otis 9-5/8" x 12-1/4" TOC 3378' (CALC w 25% washout) 3-1/2" x 9-5/8" TOC 4940' (12-01-04 CBL) CIBP @ 6195' w 35' cmt top (1-31-21) Patch Pool 5 PROPOSED Perforations Sands MD TVD Date 5.2 B5B 5019-5029 4246-4255 02-01-21 5.2 B5C 5207-5227 4421-4430 01-31-21 Pool 6 ±5280-5380 ±4489-4584 Proposed Control lines: red line cemented with 1 gallon on 7/2/21 yellow line cemented with 2 gallons on 7/2/21 green line cemented with 1.5 gallons on 7/2/21 Excape Module Perfs MD (RKB): Module 16 6,205' - 6,215' Module 15 6,281' - 6,291' Module 14 6,610' - 6,620' Module 13 6,650' - 6,660' Module 12 6,741' - 6,751' Module 11 6,853' - 6,863' Module 10 6,931' - 6,941' Module 9 6,985' - 6,995' Module 8 7,145' - 7,155' Module 7 7,369' - 7,379' Module 6 7,521' - 7,531' Module 5 7,671' - 7,681' Module 4 8,080' - 8,090' Pool 6 perfs are above the 9-5/8" casing shoe, shown incorrectly on this diagram. -bjm STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Brian Glasheen To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] KBU 42-06 (PTD 204-209) perf sundry Date:Tuesday, October 31, 2023 8:48:01 AM Bryan, Per conversation over the phone. Hilcorp has cemented the control line. Cement volumes pumped do not equal the entire depth down to Pool 6. Hilcorp believes the risk of cross flow is very low through control lines. There is not a way to lose storage gas, Pool 6 is a low pressure reservoir and all other reservoirs in the well are at much higher pressures. The current operation has patches being set. If we were to attempt a squeeze beforehand, we put the entire well at risk. In the event Hilcorp sees water post perforating pool 6, Hilcorp will evaluate and cement off Pool 6 to not jeopardize our storage reservoir. Thanks Brian Glasheen Ops Engineer 907-545-1144 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 24, 2023 12:01 PM To: Brian Glasheen <Brian.Glasheen@hilcorp.com> Subject: RE: [EXTERNAL] KBU 42-06 (PTD 204-209) perf sundry Brian, Do you have the records for them having been cemented? Could you forward the report to me? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Brian Glasheen <Brian.Glasheen@hilcorp.com> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Sent: Monday, October 16, 2023 9:55 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] KBU 42-06 (PTD 204-209) perf sundry Bryan, I can confirm they have been cemented from surface and if not we can cement them. Thanks Brian Glasheen Ops Engineer 907-545-1144 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, October 16, 2023 6:36 AM To: Brian Glasheen <Brian.Glasheen@hilcorp.com> Subject: [EXTERNAL] KBU 42-06 (PTD 204-209) perf sundry Jake, Is there any sustained pressure on the Excape control lines? What’s your plan to prevent flow between the pools via these lines? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Christianson, Grace K (OGC) From:Jacob Flora <Jake.Flora@hilcorp.com> Sent:Wednesday, October 25, 2023 10:24 AM To:Brian Glasheen Subject:FW: Cementing Follow Up Report: Excape Control Lines Boom From:JakeFloraͲ(C)<Jake.Flora@hilcorp.com> Sent:Monday,July12,20212:20PM To:bryan.mclellan@alaska.gov Cc:TaylorWellman<twellman@hilcorp.com>;DonnaAmbruz<dambruz@hilcorp.com>;JakeFloraͲ(C) <Jake.Flora@hilcorp.com> Subject:CementingFollowUpReport:ExcapeControlLines Bryan, Belowarethe¼”controllineswesqueezedwiththegreasepumpandHalliburton’sFineCem squeezecementontheExcapeIAsqueezedwellswedidinearlyJanuary2021.Asyouwill noticethelinestookavaryingamountofcement.The0.25”lineshaveanIDof0.152”and capacityof0.00094gllons/ft.2gallonsequatesto2127’ofcontrolline. IplanonupdatingtheWBDsandnotatingthecementvolumepumpedoneach. LetmeknowifthereisanythingadditionalyouwouldliketoseehereͲ Thanks, Jake PTDWellcementvolumepumpeddatecemented 202Ͳ091KBU11Ͳ08Y2gallonsoneachline(7/2/2021) 205Ͳ141KBU41Ͳ061.5galred,2galyellowand2galgreen(7/2/2021) 204Ͳ209KBU42Ͳ062galyellow,1.5greenand1galred(7/2/2021) 200Ͳ179KBU44Ͳ061galredand2galgreen(7/2/2021) 207Ͳ149KBU14Ͳ06Y1.5galgreenand0.5galred(7/2/2021) 2 203Ͳ217KBU23Ͳ071galred,.5galgreenand1galyellow(7/2/2021) 203Ͳ025BCUͲ112gallonsoneachline(7/3/2021) David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Hilcorp North Slope, LLC DATE: 07/21/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 42-06 (PTD 204-209) GPT-Plug-Cement-Perf 01/31/2021 Please include current contact information if different from above. 37' (6HW eceived By: 07/21/2021 By Abby Bell at 3:08 pm, Jul 21, 2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 04/07/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 42-06 (PTD 204-209) PLUG-PERF 02/01/2021 Please include current contact information if different from above. PTD: 2042090 E-Set: 34921 Received by the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y Jody Colombie at 7:57 am, Mar 05, 2021 JJ'LJLWDOO\VLJQHGE\7D\ORU :HOOPDQ '1FQ 7D\ORU:HOOPDQ RX 8VHUV 'DWH 7D\ORU:HOOPDQ RBDMS HEW 3/5/2021 Waiting on MITIA and MIT Excape lines DSR-3/5/21 SFD 3/16/2021BJM 4/26/21 ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ Ͳ>ŝŶĞ ϭͬϯϭͬϮϭ ϮͬϭͬϮϭ ϬϮͬϬϭͬϮϬϮϭͲDŽŶĚĂǇ <ͲůŝŶĞĐŽŶĚƵĐƚ:^ĂŶĚĂƉƉƌŽǀĞWdt͘D/Zh͘Z/,ǁŝƚŚϮ͘ϳϵΗũƵŶŬďĂƐŬĞƚĂŶĚŐĂƵŐĞƌŝŶŐƚŽϱ͕ϮϬϬΖƚŽĞŶƐƵƌĞƐƉŝƌĂůƐƚƌŝƉ ŐƵŶǁĂƐĐůĞĂƌ͘WKK,͘Z/,ǁŝƚŚ'Wd͘&ŝŶĚĨůƵŝĚůĞǀĞůĂƚϵϴϬΖ͘ZhũƵŵƉĞƌůŝŶĞĂŶĚƐƚĂĐŬŽƵƚŐĂƐĨƌŽŵϯϮͲϳ,ƚŽƉƵƐŚĨůƵŝĚ ůĞǀĞůĚĞĞƉĞƌ͘dƵďŝŶŐƉƌĞƐƐƵƌĞŝŶĐƌĞĂƐĞĚĨƌŽŵϮϬƉƐŝƚŽΕϵϲϬƉƐŝ͘&ůƵŝĚůĞǀĞůсϯ͕ϴϬϬΖĂŶĚĐŽŶƚŝŶƵŝŶŐƚŽŐŽĚĞĞƉĞƌ͘WKK, ƚŽŵĂŬĞƵƉ/W͘Z/,ǁŝƚŚ/W͘>ŽŐƵƉĨƌŽŵϱ͕ϭϴϬΖƚŽϰ͕ϴϬϬΖ͘^ĞŶĚĐŽƌƌĞůĂƚŝŽŶĚĂƚĂƚŽ'ĞŽ͘^ƵďƚƌĂĐƚϮΖĂŶĚƐĞƚƉůƵŐĂƚ ϱ͕ϭϱϬΖ͘Z/,ǁŝƚŚϭϬΖƐƉŝƌĂůƐƚƌŝƉŐƵŶ͘ϰƐƉĨ͕ϲϬĚĞŐƉŚĂƐŝŶŐ͕Ϯ͘ϱΗǁͬϮϱŐƌĂŵĐŚĂƌŐĞƐ͘^ĞŶĚĐŽƌƌĞůĂƚŝŽŶĚĂƚĂƚŽ'ĞŽ͕ŽŶ ĚĞƉƚŚ͘WĞƌĨŽƌĂƚĞϱ͕ϬϭϵͲϱ͕ϬϮϵΖ͘/ŶŝƚŝĂůƉƌĞƐƐсϵϴϳƉƐŝ͕ϱŵŝŶсϵϴϳƉƐŝ͕ϭϬŵŝŶсϵϴϳƉƐŝ͕ϭϱŵŝŶϵϴϲƉƐŝ͘ŽŶĨŝƌŵƐŚŽƚƐ ĨŝƌĞĚĂƚƐƵƌĨĂĐĞ͘ZDK͘,ĂŶĚǁĞůůŽǀĞƌƚŽKƉƐ͘ ϬϭͬϯϭͬϮϬϮϭͲ^ƵŶĚĂǇ <ͲůŝŶĞĐŽŶĚƵĐƚ:^ĂŶĚĂƉƉƌŽǀĞWdt͘DhϭͲϭϭͬϭϲΗ'WdĂŶĚϯͲϭͬϮΗ/W͘WdůƵďƌŝĐĂƚŽƌϮϱϬͬϮ͕ϱϬϬƉƐŝ͘dͬ/ͬϬс ϭ͕ϱϬϬͬϬͬϬ͘Z/,ǁŝƚŚ'WdĂŶĚ/W͘>ŽŐƵƉĨƌŽŵϱ͕ϰϬϬΖͲϰ͕ϴϬϬΖ͘^ĞŶĚĐŽƌƌĞůĂƚŝŽŶĚĂƚĂƚŽƚŽǁŶĂŶĚĂĚĚϱΖƚŽůŽŐ͘&ůƵŝĚ ůĞǀĞůсϱ͕ϰϰϯΖ;ĐŽƌƌĞĐƚĞĚͿ͘Z/,ĂŶĚƚĂŐĂƚϲ͕ϭϵϲΖ͘^ĞƚƉůƵŐĂƚϲ͕ϭϵϱΖ͘Z/,ǁŝƚŚϮ͘ϱΗǆϯϬΖĐĞŵĞŶƚďĂŝůĞƌĂŶĚĚƵŵƉŽŶƚŽƉŽĨ /W͘Z/,ǁŝƚŚϮ͘ϱΗǆϯϬΖĐĞŵĞŶƚďĂŝůĞƌĂŶĚĚƵŵƉŽŶƚŽƉŽĨ/W͘dŽƚĂůŽĨϯϱΖ͘dKсϲ͕ϭϲϬΖD͘Z/,ǁŝƚŚϭϬΖǆϮ͘ϱΗƐƉŝƌĂů ƐƚƌŝƉŐƵŶ͘ϲϬĚĞŐƉŚĂƐŝŶŐ͕ϰƐƉĨ͕ϮϱŐƌĂŵĐŚĂƌŐĞƐ͘^ĞŶĚĐŽƌƌĞůĂƚŝŽŶĚĂƚĂƚŽ'ĞŽ͕ƐŚŝĨƚĚŽǁŶϭϱΖ͕ƌĞƐĞŶĚĂŶĚĐŽŶĨŝƌŵ ĚĞƉƚŚƐ͘WĞƌĨŽƌĂƚĞϱ͕ϮϭϳΖͲϱ͕ϮϮϳΖ͘/ŶŝƚŝĂůƉƌĞƐƐͲϭ͕ϰϱϬƉƐŝ͕ϱŵŝŶсϭ͕ϰϱϬƉƐŝ͕ϭϬŵŝŶсϭ͕ϰϰϬƉƐŝ͕ϭϱŵŝŶсϭ͕ϰϮϬƉƐŝ͘WKK,͘ ŽŶĨŝƌŵƐŚŽƚƐĨŝƌĞĚ͘Z/,ǁŝƚŚϭϬΖǆϮ͘ϱΗƐƉŝƌĂůƐƚƌŝƉŐƵŶ͘ϲϬĚĞŐƉŚĂƐŝŶŐ͕ϰƐƉĨ͕ϮϱŐƌĂŵĐŚĂƌŐĞƐ͘^ĞŶĚĐŽƌƌĞůĂƚŝŽŶĚĂƚĂƚŽ 'ĞŽ͕ŽŶĚĞƉƚŚ͘WĞƌĨŽƌĂƚĞϱ͕ϮϬϳΖͲϱ͕ϮϭϳΖ͘/ŶŝƚŝĂůƉƌĞƐƐͲϭ͕ϯϮϬƉƐŝ͕ϱŵŝŶсϭ͕ϯϮϬƉƐŝ͕ϭϬŵŝŶсϭ͕ϯϮϬƉƐŝ͕ϭϱŵŝŶсϭ͕ϯϮϬ ƉƐŝ͘WKK,͘^ĂǁŽǀĞƌƉƵůůĂĨƚĞƌƐŚŽŽƚŝŶŐǁŚŝůĞWKK,͘EŽƐƚƌŝƉŐƵŶĂƚƐƵƌĨĂĐĞ͘ΎΎΎϭϬΖƐƉŝƌĂůƐƚƌŝƉŐƵŶůĞĨƚŝŶǁĞůůĂĨƚĞƌ ƐŚŽŽƚŝŶŐΎΎΎ͘>ĂǇĚŽǁŶƚŽŽůƐƚƌŝŶŐ͘/ŶƐƚĂůůŶŝŐŚƚĐĂƉŽŶǁŝƌĞůŝŶĞǀĂůǀĞƐ͘,ĂŶĚǁĞůůŽǀĞƌƚŽKƉƐ͘ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϰϮͲϬϲ ϱϬͲϭϯϯͲϮϬϱϰϲͲϬϬͲϬϬ ϮϬϰͲϮϬϵ WĞƌĨŽƌĂƚĞϱ͕ϬϭϵͲϱ͕ϬϮϵΖ͘ Z/,ǁŝƚŚϮ͘ϱΗǆϯϬΖĐĞŵĞŶƚďĂŝůĞƌĂŶĚĚƵŵƉŽŶƚŽƉŽĨ /W͘Z/,ǁŝƚŚϮ͘ϱΗǆϯϬΖĐĞŵĞŶƚďĂŝůĞƌĂŶĚĚƵŵƉŽŶƚŽƉŽĨ/W͘dŽƚĂůŽĨϯϱΖ͘dKсϲ͕ϭϲϬΖD͘ ƐĞƚƉůƵŐĂƚ ϱ͕ϭϱϬΖ͘ Z/,ǁŝƚŚ/W͘ WĞƌĨŽƌĂƚĞϱ͕ϮϭϳΖͲϱ͕ϮϮϳΖ WĞƌĨŽƌĂƚĞϱ͕ϮϬϳΖͲϱ͕ϮϭϳΖ MITIA to 1700 psi performed on 5/17/21 passed. See attached pressure test chart. ^ĞƚƉůƵŐĂƚ ϲ͕ϭϵϱΖ /HDVH 6WDWH$ODVND &RXQWU\86$ 79' $QJOH3HUIV .HQDL*DV)LHOG .HQDL3HQLVXOD%RURXJK .HQDL%HOXJD8QLW ĺ .&/ /DVW5HYLVRQ'DWH5HYLVHG%\ 'DWHG&RPSOHWHG 'RQQD$PEUX] &RPSOHWLRQ)OXLG :HOO1DPH 1XPEHU 0XQLFLSDOLW\ $QJOH#.23DQG'HSWK 3HUIRUDWLRQV0' a #IW )LOOFOHDQHGRXWWR3%'RI 0' RQ3%7' 0' 79' .%8 3DG )6/ ):/ 6HF715:603HUPLW $3, 3URSHUW\'HV$ .%(OHYDWLRQ $*/ /DW 1 /RQJ : 6SXG'DWHKUV 5HDFKHG7' 5LJ5HOHDVHGKUV 3$ &RQGXFWRU3LSH .SSI 7RS%RWWRP 0' 79' 6XUIDFH&DVLQJ .SSI%7& 7RS %RWWRP 0' 79' ,QWHUPHGLDWH&DVLQJ /SSI%7& 7RS %RWWRP 0' 79' &PWZVNVRISSJ&ODVV*OHDG 3URGXFWLRQ7XELQJ /SSI(8( UGZ2'FRQWUROOLQHSURWHFWRUV 7RS %RWWRP 0' 79' 7' 0' 79' 7UHHF[Q 2WLV [72& &$/&ZZDVKRXW [72& &%/ &,%3# Z FPWWRS &,%3# ^,Dd/ WĞƌĨŽƌĂƚŝŽŶƐ ^ĂŶĚƐD ds ĂƚĞ ϱ͘ϮϱϱϬϭϵͲϱϬϮϵϰϮϰϲͲϰϮϱϱ ϬϮͲϬϭͲϮϭ ϱ͘ϮϱϱϮϬϳͲϱϮϭϳϰϰϮϭͲϰϰϯϬ ϬϭͲϯϭͲϮϭ ǆĐĂƉĞDŽĚƵůĞWĞƌĨƐD;Z< 0RGXOH 0RGXOH 0RGXOH 0RGXOH 0RGXOH 0RGXOH 0RGXOH 0RGXOH 0RGXOH 0RGXOH 0RGXOH 0RGXOH 0RGXOH 0RGXOH Isolated 5217-5227 01-31-21 isolated -bjm Excape perfs isolated ϱ͘ϮϱϱϬϭϵͲϱϬϮϵϰϮϰϲͲϰϮϱϱ ϬϮͲϬϭͲϮϭ ϱ͘ϮϱϱϮϬϳͲϱϮϭϳϰϰϮϭͲϰϰϯϬ ϬϭͲϯϭͲϮϭ Iso ϱ Ϯ ϱ ϱϬϭϵ ϱϬϮϵ ϰϮϰϲ ϰϮϱϱ ϬϮ Ϭϭ Ϯϭ o Notes:0 psi on tubing, 0 psi on IA, 0 PSI on OA,took 1.9 bbls to pressue up. I had to turn the truck off for one second to check something, when I turned it back on it caused that quick drop and gain in presure on the chart. I went another 30 min from that point to be on the safe side but the actual pressure never changed. Customer:Hilcorp Customer Contact:Cole Bartlewski LSD: Job #: Date: Fluid Pumped: KBU 42-06 IA MIT WATER 2021-05-17 16:26 Ticket #: Phone #: Operator: 42-06 COLE BARTLEWSKI 907-690-2854 Total Fluid Pumped:67.2 USG 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing N2 ______________ 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,624'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 10,540psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: January 30, 2021 3-1/2" 8,566' Perforation Depth MD (ft): 6,172' See Attached Schematic 8,566' 7,755'3-1/2" 20" 13-3/8" 139' 9-5/8"6,172' 1,514' 3,060psi 3,450psi 139' 1,425' 5,363' 139' 1,514' 9.3# / L-80 TVD Burst 8,566' 10,160psi MD 5,750psi Length Size CO 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 028142 204-209 50-133-20546-00-00 Kenai Beluga Unit (KBU) 42-6 Kenai Gas Field, Sterling Gas Pool 5.2 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic jake.flora@hilcorp.com 7,812'8,529'7,718'1,176 N/A N/A; N/A N/A; N/A Perforation Depth TVD (ft): Tubing Size: Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:55 am, Jan 19, 2021 321-037 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2021.01.15 14:50:53 -09'00' Taylor Wellman SFD 1/19/2021 10-407 Post perf MIT-IA to 1500 psi DSR-1/19/21gls 1/27/21 * Perforate New Pool * Verify Control line integrity after perforating . Comm 1/28/21 dts 1/28/2021 JLC 1/28/2021 RBDMS HEW 1/29/2021 Well Prognosis Well: KBU 42-06 Date: 01/12/2021 Well Name: KBU 42-06 API Number: 50-133-20546-00-00 Current Status: Shut In Gas Producer Leg: N/A Estimated Start Date: 01/30/2021 Rig: E-Line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 204-209 First Call Engineer: Jake Flora (907) 777-8442 (720) 988-5375 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (985) 867-0665 (C) AFE Number: Max. Expected BHP: ~ 1600 psi @ 4243’ TVD (Based on offset well data) Max. Potential Surface Pressure: ~ 1176 psi (Based on expected BHP and gas gradient to surface (0.10psi/ft)) Well Status KBU 42-06 is currently a shut-in Excape well offline since 2008. Brief Well Summary KBU 42-06 drilled and completed in 2004 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. The well came online making over 6 MMCFD. The well had a history of making solids eventually sanding up and went offline in 2007 with a brief period of low rate flow in 2008 after a coil cleanout. The well had cum’d 3.5 BCF and 20.8 MBW of water. Objective In an effort to add rate and return KBU 42-06 to production, it is recommended to isolate current open Beluga gas sands and recomplete uphole in the Sterling formation. Notes Regarding Wellbore Condition - Max deviation: 38 degrees from 1500’ – 4300’. 22 degrees at 5000’. - TOC in 3-1/2” x 9-5/8” annulus at 4940’ (12-01-2004 CBL) - TOC in 9-5/8” x 12-1/4” hole annulus calculated at 3378’ with 25% hole washout (195 bbls cmt slurry) - 1/12/2021 MITIA to 1500psi PASSED - 3/25/2014 SL tag at 6849’ w 2.53” LIB Procedure E-Line 1. RU E-Line, PT Lubricator, set CIBP at ~6200’, dump 35 ft of cement on CIBP to abandon Upper Beluga perforations/production modules. 2. RU Slickline, swab well down to 6200’. 3. RU E-Line, PT Lubricator, Perforate the below zones from the bottom up: e Sterling formation. Well Prognosis Well: KBU 42-06 Date: 01/12/2021 a. Discuss wellhead pressure with OE. If necessary RU Nitrogen to pressure well prior to perforating. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Use GR/CCL to correlate against Open Hole Log provided by Geologist. Send the correlation pass to the following for confirmation. Reservoir Engineer Trudi Hallett 907.301.6657 Geologist Ben Siks 907.229.0865 d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. 4. POOH. 5. RD E-Line. 6. Turn well over to production. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Nitrogen (Contingency) 1. If Nitrogen is required to pressure up well prior to perforating: 2. MIRU Nitrogen Unit, review Nitrogen SOP, pressure well to desired perforating pressure. E-line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 3. RIH and set 3-1/2” Casing Patch or set 3-1/2” CIBP above the zone and dump 35’ of cement on top of the plug. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Well Procedure – N2 Operations Sand MD Top MD Bottom Total Footage (MD)TVD Top TVD Bottom PA Pool CO Plan to shoot Order to Shoot Estimated Reservoir Pressure P5.2_B5B ±5,016' ±5,041' 25' ±4,243' ±4,268' Sterling KENAI, STERLING 5.2 GAS CO 510A Top 10' 2 1600 PSI P5.2_B5C ±5,207' ±5,229' 22' ±4,420' ±4,442' Sterling KENAI, STERLING 5.2 GAS CO 510A Top 10' 1 1600 PSI NOTE: verify Escape control line integrity after perforating. Lease: State:Alaska Country:USA (TVD): Angle/Perfs: Revised By: Dated Completed: Jake Flora Completion Fluid:12/8/2004 Well Name & Number: Municipality: Angle @ KOP and Depth: Perforations (MD): ~1.6º / 100' @ 250 ft Kenai Gas Field Kenai Penisula Borough Kenai Beluga Unit 42-6 1/12/2021 6,205' - 8,426' 5,396' - 7,615'(TVD): 4º ĺ 1.8º 6% KCL Last Revison Date: Fill cleaned out to PBD of 8,529' MD on 2/28/2014 PBTD 8,529' MD 7,718' TVD Excape System Details - 16 Excape module system -Yellow line for fires modules 9-16 -Red contol line fires modules 2-8 -Green control line fires bottom module - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 16 6,205' - 6,215' Module 15 6,281' - 6,291' Module 14 6,610' - 6,620' Module 13 6,650' - 6,660' Module 12 6,741' - 6,751' Module 11 6,853' - 6,863' Module 10 6,931' - 6,941' Module 9 6,985' - 6,995' Module 8 7,145' - 7,155' Module 7 7,369' - 7,379' Module 6 7,521' - 7,531' Module 5 7,671' - 7,681' Module 4 8,080' - 8,090' Module 3 8,121' - 8,131' Module 2 8,341' - 8,351' Module 1 8,415' - 8,425' 9-5/8" x 12-1/4" TOC 3378' (CALC w 25% washout) 3-1/2" x 9-5/8" TOC 4940' (12-01-04 CBL) Excape System Details -15 Conventional ceramic flappers valves below each module except Mod-1 Flappers MD (RKB): Module 16 - 6,224' Module 15 - 6,300' Module 14 - 6,629' Module 13 - 6,669' Module 12 - 6,760' Module 11 - 6,872' Module 10 - 6,950' Module 9 - 7,004' Module 8 - 7,164' Module 7 - 7,387' Module 6 - 7,540' Module 5 - 7,690' Module 4 - 8,099' Module 3 - 8,140' Module 2 - 8,360' Module 1 - NA KBU 42-6 Pad 41-7 45' FSL, 4,199' FWL Sec. 6, T4N, R11W, S.M. Permit #:204-209 API #:50-133-20546-00-00 Property Des:A -028142 KB Elevation:87' (21' AGL) Lat:60º 30' 50.56" N Long:151º 16' 37.45" W Spud Date:00:30hrs 11/3/04 Reached TD:11/15/04 Rig Released:06:00hrs 11/23/04 PA: Conductor Pipe: 20" K-55 133 ppf Top Bottom MD 0' 139 TVD 0' 139' Surface Casing: 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,514' TVD 0' 1,424' Cmt w/ 470 sks of 12 ppg, Class G Intermediate Casing: 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,172' TVD 0' 5,363' Cmt w/ 430 sks of 12.5 ppg, Class G lead & 170 sks of 13.5 ppg, Class G tail Production Tubing: 3-1/2" L-80 9.3 ppf EUE 8rd w/ 6.25" OD control line protectors Top Bottom MD 0' 8,566' TVD 0' 7,755' Cmt w/ 1,100 sks of 15.8 ppg Class G TD 8,624' MD 7,812' TVD Tree cxn = 4-3/4" Otis PROPOSED Perf Sterling CIBP @ ~ 6200' Lease: State:Alaska Country:USA (TVD): Angle/Perfs: Kenai Gas Field Kenai Penisula Borough Kenai Beluga Unit 42-6 1/12/2021 6,205' - 8,426' 5,396' - 7,615'(TVD): 4º ĺ 1.8º 6% KCL Last Revison Date:Revised By: Dated Completed: Jake Flora Completion Fluid:12/8/2004 Well Name & Number: Municipality: Angle @ KOP and Depth: Perforations (MD): ~1.6º / 100' @ 250 ft Fill cleaned out to PBD of 8,529' MD on 2/28/2014 PBTD 8,529' MD 7,718' TVD Excape System Details - 16 Excape module system -Yellow line for fires modules 9-16 -Red contol line fires modules 2-8 -Green control line fires bottom module - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 16 6,205' - 6,215' Module 15 6,281' - 6,291' Module 14 6,610' - 6,620' Module 13 6,650' - 6,660' Module 12 6,741' - 6,751' Module 11 6,853' - 6,863' Module 10 6,931' - 6,941' Module 9 6,985' - 6,995' Module 8 7,145' - 7,155' Module 7 7,369' - 7,379' Module 6 7,521' - 7,531' Module 5 7,671' - 7,681' Module 4 8,080' - 8,090' Module 3 8,121' - 8,131' Module 2 8,341' - 8,351' Module 1 8,415' - 8,425' Excape System Details -15 Conventional ceramic flappers valves below each module except Mod-1 Flappers MD (RKB): Module 16 - 6,224' Module 15 - 6,300' Module 14 - 6,629' Module 13 - 6,669' Module 12 - 6,760' Module 11 - 6,872' Module 10 - 6,950' Module 9 - 7,004' Module 8 - 7,164' Module 7 - 7,387' Module 6 - 7,540' Module 5 - 7,690' Module 4 - 8,099' Module 3 - 8,140' Module 2 - 8,360' Module 1 - NA KBU 42-6 Pad 41-7 45' FSL, 4,199' FWL Sec. 6, T4N, R11W, S.M. Permit #:204-209 API #:50-133-20546-00-00 Property Des:A -028142 KB Elevation:87' (21' AGL) Lat:60º 30' 50.56" N Long:151º 16' 37.45" W Spud Date:00:30hrs 11/3/04 Reached TD:11/15/04 Rig Released:06:00hrs 11/23/04 PA: Conductor Pipe: 20" K-55 133 ppf Top Bottom MD 0' 139 TVD 0' 139' Surface Casing: 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,514' TVD 0' 1,424' Cmt w/ 470 sks of 12 ppg, Class G Intermediate Casing: 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,172' TVD 0' 5,363' Cmt w/ 430 sks of 12.5 ppg, Class G lead & 170 sks of 13.5 ppg, Class G tail Production Tubing: 3-1/2" L-80 9.3 ppf EUE 8rd w/ 6.25" OD control line protectors Top Bottom MD 0' 8,566' TVD 0' 7,755' Cmt w/ 1,100 sks of 15.8 ppg Class G TD 8,624' MD 7,812' TVD Tree cxn = 4-3/4" Otis 9-5/8" x 12-1/4" TOC 3378' (CALC w 25% washout) 3-1/2" x 9-5/8" TOC 4940' (12-01-04 CBL) passes MIT-IA 1500 psi 5015-5041 ft' 5207-5229 ft 4940 ft TOC STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. • M Marathon MARATHON Oil Company • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ~ ~.~ August 28, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field Well: Kenai Beluga Unit 42-6 Dear Mr. Maunder: ~,E ~ ~~ 208 '~ OPn'f~1SS10n Alaska Oil & Oar Dons. pnchora9a ~6~ ~,d Attached for your records is the Report of Sundry Well Operations for the clean out of KBU 42-6 well. There is no sundry number sited on the 10-404 since approval was not required to conduct this activity. 1,665' of material infiltrated the wellbore of KBU 42-6 bringing production to a halt. The well was cleaned to 8,500' utilized a coil tubing unit. Gas production was reestablished at a rate of 225 mcf/day. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Correspondences can be directed to me utilizing the address above. Sincerely, ~.~ SEF~ ~~ 200 r ...ice Kevin J. Skiba Engineering Technician Enclosures: 10-404 Sundry Report cc: Houston Well File Operations Summary Kenai Well File Current Well Schematic KJS KDW STATE OF ALASKA ~ ~~; ~ ~ ~QQ$ 9 D8 ALAS OIL AND GAS CONSERVATION COMIv~ON REPORT OF SUNDRY WELL OPERA~j~~l6i1 ~ Gam lions, Commission Ancho~a~e 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ Coil Tubing; Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver ^ Time Extension ^ Clean Out Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well ^ 2. Operator Marathon Oil Company N 4. Well Class Before Work: 5. Permit to Drill Number: ame: Development ^~ ~ Exploratory^ 204-209 3. Address: PO Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20546=00-00 7. KB Elevation (ft): 9. Well Name and Number: 87' (21' AGL) ~ Kenai Belu a Unit 42-6 8. Property Designation: 10. Field/Pool(s): A - 028142 - Kenai Gas Field /Beluga & Upper Tyonek Pools 11. Present Well Condition Summary: Total Depth measured g,g24~- feet Plugs (measured) NA true vertical 7,g12~ , feet Junk (measured) NA Effective Depth measured 8,529 ~ feet true vertical 7,71 g' . feet Casing Length Size MD TVD Burst Collapse Structural Conductor 118' 20" 139' 139' 3,060 psi 1,500 psi Surface 1,493' 13-3/8" 1,514' 1,424' 3,450 psi 1,950 psi Intermediate 6,151' 9-5/8" 6,172' 5,363' 5,750 psi 3,090 psi Production 8,545' 3-1/2" 8,566' 7,755' 10,160 psi 10,540 psi Liner Perforation depth: Measured depth: 6,205' - 8,426' True Vertical depth: 5,396' - 7,615' Tubing: (size, grade, and MD) 3-1/2" L-80 8,566' Packers and SSSV (type and measured depth) NA NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): Cleaned wellbore to 8,500' MD with coil tubing. Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 62 0 51 Subsequent to operation: 0 225 - 0 5 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development 0 - Service ^ Daily Report of Well Operations X 16. Well Status after work: Oil ^ Gas Q - WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: NA '/ Contact Kevin Skiba (907) 283-1371 Printed Name Ken D. Wal h Title Production Engineer s , f~ rn . W nature ~ IX J~- ~ Si Phone 1311 Date Au 2008 ust 28 907 283 . . g ( g , ) - _ ~L~MS BFI, Form 10-404 Revised 04/2006 ( (~ ~' ¢ ; '~`~ ~ ~``~'~ ~~P ~ ~ ~QDB Submit Original Only (~~ t `: ~ ev.s+- 4 1 6~ f . M ~ ~ Operations Summary Report ~aaarxow ®OilCorr~t~y Well Name: KENAI BELUGA UNIT 42-6 Daily Operations Report Date: 12/29/2007 Job Cate o Other 24 Hr Summary MIRU wire line unit, RIH tag fill @ 6863 KBD POOH rig down. Ops Trouble Start Time End Time Dur (hrs) Ops Code Activity Code Status Code Comment 13:00 13:30 0.50 SAFETY MTG_ AF MRIU spot up equipment. Held PJSM and discussed operations. 13:30 14:10 0.67 RURD_ SLIK AF PT lubricator to 2000 psig, WHP=1200 psig. Good test. OPen well. 14:10 15:00 0.83 WORK_ SLIK AF RIH with 1 3/4"" tool strin with a 2.0"" DD bailer. Tag fill at 6863' KBD. Tool string picking up stir y. wi oo s. 15:00 17:00 2.00 RURD_ SLIK AF RD wire line unt, secured well and cleaned up around well head. Spot equipment around next well. 17:00 19:00 2.00 RURD SLIK AF PWS left lease. _ Re ort Date: 7/12/2008 Job Cate o R&M MAINTENANCE 24 Hr Summary MIRU BJ COIL .Clean out and N2 lift to production. Ops Trouble Start7ime End Time Dur (nrs) Ops Code Activity Code. Status Code Comment 08:00 09:00 1.00 SAFETY MTG AF MIRU liner, tanks, spot crane and RU coil unit. 09:00 18:00 9.00 RURD COIL AF RU hardline to choke. Notified Jim Reggs with the AOGCC about the pending BOP test. He waved the witness. We will send the completed form to him after completion. Continue to rig up problem with swab valve and masters holding mobilized Vetco Gray to grease trees. Re ort Date: 7/13/2008 Job Cate o R&M MAINTENANCE 24 Hr Summary Test BOP. Open well, RIH clean out down to 8451' CTM, N2 lift to surface. Well did not flow on its own. Shut down to let well pressure up over ni ht. Ops Trouble Start Time End Time Dur (hrs) ,,Ops Code Activity Code Status Code Comment 06:00 07:00 1.00 SAFETY MTG AF Held PJSM discussed procedure and safety items for today operations. 07:00 08:00 1.00 RURD COIL AF Test BOP at 200 psi low/4500 psi high. -good test. PU injector and go to well. Shell tested to 2500 psig. 08:00 09:00 1.00 RURD COIL AF Open well. RIH with 1.75" coil, With coil connector, double checks, 1' straight bar and 2"jet nozzle. WHP= 1000 psig, blew down while running in hole with coil. 09.00 09:30 0.50 PUMP N2 AF Coil at 100', start fluid pump at min rate 0.25 BPM. 09:30 10:00 0.50 PUMP WTR AF Work coil down to 2660' CTM, start N2 at min rate of 360 SCFM. WHP= 0 psig. No returns. 10:00 10:30 0.50 PUMP WTR AF Work coil down to 5500' CTM, increased H2O up to 0.75 BPM with 400 SCFM N2. WHP= 0 psig. No returns to flow back tank.. 10:30 11:30 1.00 PUMP WTR AF Work coil down to 5920' CTM. Returns to flow back tank. WHP= 45 si . 11:30 12:30 1.00 PUMP WTR AF Coil at 6200' CTM, increase pump rate up to 1.0 BPM, N2 at 400 SCFM, good returns to flow back. WHP= 450 psig. 12:30 13:30 1.00 PUMP WTR AF Coil at 6490 'CTM pull test, PUW = 7000 lbs. Increase pump rate up to 1.50 BPM, PIP= 1850 psig, N2 at 400 SCFM, good returns to flow back. Sand and coal in returns. WHP= 50 psig. RI wi coi at 13:30 14:30 1.00 PUMP WTR AF Wash down to 8000' CTM, pull test, PUW = 8400 lbs. Increase pump rate up to 1.50 BPM, N2 at 400 SCFM, good returns to flow back. WHP= 350 psig. 14:30 15:30 1.00 PUMP WTR AF Work coil accross tags at 8065', 8341', & 8347' CTM. PU and wash through. PIP = 2500 psig. Returns have trace of sand and coal i Returns to flow back. WH = psig. 15:30 16:00 0.50 PUMP WTR AF Coil at 8451' ,Continue circulating with N2 and KCL. 400 SCFM and 1.5 BPM. PIP= 2516 psig, Good returns with no sand. WHP= 370 psig. 16:00 16:30 0.50 PUMP WTR AF Switched to all N2, shut down fluid pump. Increased N2 rate up to 750 SCFM. Start POOH at 10 FPM. Coil tubing reel has a problem while POOH. Reel not smooth, causes injector and coil to lung while picking up off bottom in any gear. Continue POOH. Good returns no sand, creamy, in color 16:30 17:00 0.50 PUMP N2 AF POOH with coil. Coil sticking pulling up through the lower modules. WHP= 360 psig. Total returns to Flow back 340 bbls. N2 PIP = 1430 psig, N2 @ 760 SCFM with good returns. 17:00 17:30 0.50 PUMP N2 AF Coil at 7402' CTM, N2 rate same, WHP = 102 psig. POOH at 55 FPM. 17:30 18:30 1.00 PUMP N2 AF Coil at 5545' CTM, N2 rate same, WHP = 240 psig. PIP= 880 psig, Imostly N2 at surface returns have slowed. S/d N2 pumping. www.peloton.com Report Printed: 8/28/2008 ~~~ ~ Operations Summary Report ~u-tmTxor ~Qjjny Well Name: KENAI BELUGA UNIT 42-6 i Ops Trouble Start Time Erid Time Dur (hrs) Ops Code Activity Code Status Code Comment 18:30 19:30 1.00 PUMP N2 AF H = 0 si .Returns to dribble with sli ht N2 blowin . 19:30 21:30 2.00 PUMP N2 AF Coif at surface. WHP = 0 psig. No returns. Monitor well with no change. Shut in swab. Lay down injector. Secured well and tree. BJ left lease. Daily Operations Re ort Date: 7/14/2008 Job Cate o R&M MAINTENANCE 24 Hr Summary Monitor well for pressure buildup. Ops Trouble Start Time End Time Dur (hrs) Ops Code Activity Code Status Code Comment 08:00 09:00 1.00 SAFETY MTG TA MSCT Held rig down safety meeting with crew. 09:00 12:00 3.00 RURD COIL TA MSCT Coil reef has a hydraulic problem that will require moving to shop to fix. 12:00 14:00 2.00 RURD COIL AF Clean up around well head. Trailer up all equiipment. Note: WHP= 220 psi 3 to 4 bbls of solids washed out of well. Sand mu~Tc "an sl . Re ort Date: 7/23/2008 Job Cate o R&M MAINTENANCE 24 Hr Summary MIRU Pollard to run slick line tag, PT Survey and determine fluid level. Ops Trouble Start Time End Time Dur {hrs) Ops Code Activity Code Status Code Comment ' 08:00 08:45 0.75 SAFETY MTG AF Hold PJSM. Discuss alarms, muster area, and emergency response. Discuss Pollard JSA, specific job hazards, and job assignments. Obtains SWP. 08:45 09:45 1.00 RURD SLIK AF Spot equipment. RU slick line unit. mast truck, and test pump. PU lubricator. MU tool string-RS, KJ, 10' STEM, KJ,OJ,KJ,SP, 2-1/4" DD Bailer. 09:45 10:00 0.25 TEST EOIP AF Test lubricator to 1500 psi. Test good. 10:00 11:00 1.00 RUNPUL SLIK AF RIH(1) w/ 2-1/4" DD bailer. Tag @ 6669' KB. Work thru. Fall to 6868' KB (module 11 flapper) Work tools. Cannot work thru. POOH to check tools. Recover 1 gal fluid. Jagged notch in edge of bailer mule shoe. Severe gouges on one side of bailer bottom. 11:00 11:42 0.70 RUNPUL SLIK AF RIH(2) w/ 2-1l4" DD bailer flapper bottom.. Again cannot get below 6859' KB. POOH. 11:42 12:24 0.70 RUNPUL SLIK AF RIH(3) w/ 2" DD bailer flapper bottom.. Again cannot get below 6857' KB. Loose spang action twice. POOH to down size tool string.. 12:24 13:36 1.20 RUNPUL SLiK AF RIH(4) w/ 1-1/2" tool strip w/ 1-3/4" DD bailer. (RS,KJ,10' STEM, KJ,OJ,L ork tools down to 7895' KB. Tap down. Work down to 7911'. POOH. OOH recover bailer full of malted milk shake thick ra mud. 13:36 16:21 2.75 LOG CSG AF RIH(5) w/ 1-1/4" pressure temperature gauges. 5 min stop @ surface, RIH @ 120 fpm to 6850'. Can not get thru tight spot (a)_ 6868' KB. Stop for 10 min bench @ 6850'. POOH stopping for 3 min benches @ 6000', 5000', 4000', 3000', 2000', and 1000'. Stop @ tubing hanger for 10 min bench. 16:21 17:21 1.00 RURD SLIK AF LD tool string. LD lubricator. RD slick line unit. 17:21 17:36 0.25 SECURE WELL AF Close Upper, lower, and swab valves. Secure WH and location. Turn in SWP. Sign out and leave loc. Re ort Date: 7/2612008 Job Cate o R&M MAINTENANCE 24 Hr Summary MIRU BJ Coil, flow back choke and gas buster. Test BOP's. Ops Trouble Start Time End Time Dur{hrs) Ops Code Activity .Code Status Cotle Comment 08:00 09:00 1.00 SAFETY MTG AF Hold PJSM. Discuss alarms, muster area, emergency response. Discuss BJ JSA, specific job hazards, and job assignments. 09:00 11:45 2.75 RURD COIL AF Lay liners. MIRU ASRC crane and BJ coil unit. Spot equipment. RU equipment-2" iron, hydraulic hoses. RU choke skid and gas buster. Mix 6% KCL water. 11:45 13:00 1.25 RURD COIL AF Remove tree cap. WHP 290 psi. PU and install BOP's. RU 2" chicksan from flow cross to choke and from chol\ke to gas buster. 13:00 14:00 1.00 RURD COIL AF Prep coil end. Stab pipe into injector. 14:00 15:00 1.00 TEST BOPE AF Start BOP Test. Function test. Test Blinds-250/4500 psi high. Test good. Close pipes/slips. Test pipes-250/4500 psi.. Test good. Test accumulator. Test good. 15:00 16:00 1.00 RURD COIL AF Install dimple on connector. Shut down equipment for the night. 16:00 16:30 0.50 SECURE WELL AF Close all tree valves. Install night cap. Secure well and loc for the night. Turn in permit and sign out. www.peloton.com Report Printed: 8/28/2008 ~~~ ' Operations Summary Report rrapa~xor ®(~j~~„y Well Name: KENAI BELUGA UNIT 42-6 Daily Operations Report Date: 7/27/2008 Job Cate o R&M MAINTENANCE 24 Hr Summary Clean out fill in well. Jet in w/ N2. Start Time End Time Dur (hrs) Ops Code Activity Code Ops Status Trouble Code Comment 07:30 08:30 1.00 SAFETY MTG AF Hold PJSM. Discuss alarms, muster area, and emergency response. Discuss BJ JSA, job hazards, and specific job assignments. 08:30 10:00 1.50 RURD COIL AF Spot N2 transport and crane. PU injector and carry to WH. BHA-Dimple on 1 3/4" od. 4" L, XO 2" od 4" L, straight bar 1 3/4" od. 3'L, DFCV 1 3/4" od. 11 "L, Nozzle 2" od. 4" L. Supply tank 366 bbls, (83"}. Return tank 19.5 bbls. Added 40 bbls additional KCL water for Total 406 bbls. 10:00 11:30 1.50 RUNPUL COIL AF Open swab and master valves (23 turns). RIH w/ 2" nozzle. Fill coil- 27 bbls. From PT Survey run 7/22/08. Fluid level in well 2000' S1 bbls . Fill from 7900' - 8450' (5 bbls of dirt). Coi returns to tan <. Coil @ 3200' fluid rate .28 bpm, 665 scf/m N2. 11:30 12:15 0.75 RUNPUL COIL AF N2 returns to surface Coil @ 4500'RIH, reduce N2 rate to 350 scf/m . Coil @ 6000' RIH, pumping 1600 psi .75 bpm. WHP 90 psi. 12:15 13:21 1.10 RUNPUL COIL AF Coil @ 7500' pumping .75 bpm. Pumped 100 bbls recovered 120 bbls. 13:21 14:21 1.00 RUNPUL COIL AF Coil @ 8500' pumping 1.75 bpm 350 scf/m N2 Returns 1-112 bpm black bellu a mud chunks of coal and sand and ebbles. PUH to 7800' @ 20-25 fpm washing perfs. RIH @ 25 fpm washing perfs. 14:21 14:51 0.50 RUNPUL COIL AF Coil 8500' pumping 1.75 bpm and 350 scf/m N2 WHP 150 psi. PUH @ 25 fpm washing pens. 14:51 15:03 0.20 RUNPUL COIL AF Coil @ 7300' PUH @ 25 fpm washing perfs. Cut pump rate to 3/4 BPM. 15:03 15:18 0.25 RUNPUL COIL AF Coil @ 6300'. Continue PUH. Cut fluid. Increase N2 to 1000 to displace coil (27 bbls) 15:18 15:48 0.50 RUNPUL COIL AF PUH to 5300. Good returns N2 breaks thru. RIH. 15:48 16:09 0.35 RUNPUL COIL AF Parked 7000' WHP increasin ,Waiting for N2 to break thru at surface. e ore continue IH. Well hea pressure climbing. Good water, returns-stead rate. 16:09 16:30 0.35 RUNPUL COIL AF Returns diminishing. WHP dropping. RIH. Cut N2 back to 750 scf/m. 16:30 16:45 0.25 RUNPUL COIL AF Parked 8500'. WHP increasin .Returns are real) thick, ra ,and sandy. , 16:45 18:21 1.60 RUNPUL COIL AF POOH slowly. Reduce N2 to 500 scf/m. Fluid returns diminished to a dribble. Shut off N2 @ 4800'. 18:21 19:21 1.00 RURD COIL AF OOH. Close swab to LD injector. Were still getting slight returns. Opened; well back up after about 30 minutes- Had 280 psi WHP. ODened to flowback tank. Ve froth stiff foam. Stack d like whi i flow Pressure dropped off to 20 psi. Fluid summary Pumped into well 375 bbls. Recovered-438 bbls( 375bb1s. pumped + 51bbls in well (fluid level 2000') + 6 bbls of dirt (7900' to 8500') = 432 bbls) 19:21 19:51 0.50 SECURE WELL AF Close swab and upper master valves. Install night cap. Turn in Permit and leave loc. Report Date: 7/28/2008 Job Cate o R&M MAINTENANCE 24 Hr Summary Jet in w/ N2. Start Time End. Time Dur{hrs) Ops Code Actively Cotle Ops Status Trouble Code Comment 07:30 08:30 1.00 SAFETY MTG AF Hold PJSM. Discuss alarms, muster area, and emergency response. Discuss BJ JSA, job hazards, and specific job assignments. 08:30 10:00. 1.50 RURD COIL AF PU injector. Change 1 3/4 coil BHA to dimple on CC, DFCV. straight bar, 2.0" Nozzle. 10:00 11:30 1.50 RUNPUL COIL AF WHP = 920 si , PT shell test to WHP. Open swab and master valves (23 turns). Blow wel down to open top flow back tank. RIH w/ 2" nozzle down to 4000' Pump N2 at 750 SCFM. 11:30 12:15 0.75 RUNPUL COIL AF Coil at 6000' returns to flow back tank. Returns foamy with muddy water. Good returns. WHP = 40 psig. PIP=1125 psig. Continue running in well with coil. Recovered 16 bbls fluid rom well. www.peloton.com Report Printed: 8/28/2008 •~ IVlar~on ~ Operations Summary Report ^u-aarxoN Oil Well Name: KENAI BELUGA UNIT 4~ ~~ nY ~ Ops Trouble Start Time End Time ~ Dur (hrs) Ops Code ~ Acivity Code Status Code Comment 12:15 14:15 2.00 RUNPUL COIL AF Work coil down to 8430' CTM, good returns. N2 at 750 SCFM. PIP= 1950 psig. WHP= 100 psig. Pull up hole with coil to 8430' CTM. Tag 100' higher than day before, 15' below bottom perforations. RIH with coil. Coil stuck at; 8360'. Increased N2 rate up to 1800 SCFM. PUW= 30,000 lbs. RIH with coil. Repeat cycle. Coil moving hanging up at 8360'. RIH down to 8430' CTM. Increase N2 up to 2400 SCFM. 14:15 15:15 1.00 PUMP N2 TS MDCT Returns to flow back tank, slowing. WHP= 480 psig. PIP= 1700 psig, Start pumping fluid at 1.75 BPM with 400 SCFM N2. Washed out tar et tee into gas buster, shut choke blew down and replaced far et tee Open well back up o gas us er. = psig. re urns s oppe .Open well returns back to flow back tank. PU to 34 K Ibs, RIH with coil while pumping N2 and fluid. PU weight to 46k Ibs, coil pulled free. Continue OOH with coil. 15:15 16:15 1.00 PUMP N2 TS MDCT tllina heave throuah each set of aerforations. Weight bouncing up to 30 K through each perforation then letting go. Coil above 6200' CTM, pulling smooth. N2 rate @ 720 SCFM. Good returns, fluid clear. WHP= 70 psig. Cut fluid whenn coil at 5600' CTM. Pumped 150 bbls, recoveed 192 bbls in returns. 42 bbls from well. . 16:15 17:15 1.00 PUMP N2 TS MDCT Continue OOH with coil. Coil at 2400 psig. PIP= 3770 psig, PIR= 360 SCFM. Cut N2 rate to 300 SCFM. Total N2 pumped 250 k. 17:15 18:15 1.00 RURD COIL TS MDCT OOH with coil, WHP= 0 psig, returns stopped. Shut in swab valve. Break off lubricator connection. Take injector to ground, secured well and secured well 18:15 19:15 1.00 RURD COIL AF MDCT Cleaned up around well. BJ coil tecj left lease. Daily Operations Re ort Date: 7/30/2008 Job Cate o R&M MAINTENANCE 24 Hr Summary Rig down coil spread. Dps Trouble Start Time: End Time Dur{hrs) Ops Code Activity Code Status Code Comment 07:30 08:15 0.75 SAFETY MTG AF Hold PJSM. Discuss alarms, muster area, and emergency response. Discuss BJ JSA and specific job hazards. Make job assignments. Obtain SWP. 08:15 11:15 3.00 RURD COIL AF RD coil spread. RD injector assembly. RD BOP's off WH. Knock out 2" hardline. RD gas buster and choke. Disconnect and stow hydraulic hoses. Move out equipment. PU drain/catch pans. Check out location for drips or spills. Non noted. 13" (48 bbls) solids-sand, silt, and clay left in flow back tank. www.peloton.com Report Printed: 8/28/2008 KBU 42-6 50-133-20546-00-00 Des: A - 028142 lion: 87' (21' AGL) e: 12/9/2005 Ised: 3/15/2002 Pad 14-6 45' FSL, 4,199' FWL Sec. 6, T4N, R11 W, S.M. :. Tree cxn = 4-3/4" Otis Top Of Cement (est.) @ 300' above 9-5/8" shoe - Ceramic flapper valves below each module as follows: Module 16 - 6,222' Module 15 - 6,297' Module 14 - 6,625' Module 13 - 6,666' Module 12 - 6,757' Module 11 - 6,869' Module 10 - 6,947' Module 9 - 7,001' Module 8 - 7,159' Module 7 - 7,385' Module 6 - 7,537' Module 5 - 7,687' Module 4 - 8,097' Module 3 - 8,139' Module 2 - 8,359' Module 1 - NA Fill cleaned out to 8,500' MD in July 2008 ~- t ,. ;, w '~ ,® ~• tr, a• ~a ~ :~ TD PBTD 8,624' MD 8,529' MD 7,812' TVD 7,718' TVD s M M~w-rNOM Conductor Pipe: 20" K-55 133 ppf Top Bottom MD 0' 139' ND 0' 139' Surface Casing: 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,514' rvD o' 1,a2a' Cmt w/ 470 sks of 12 ppg, Class G Surface Casing: 9-518" L-80 40 ppf BTC Top Bottom MD 0' 6,172' ND 0' 5,363' Cmt w/ 430 sks of 12.5 ppg, Class G lead & 170 sks of 13.5 ppg, Class G tail Production Tubing: 3-112" L-80 9.3 ppf EUE 8rd w/ 6.25" OD control line protectors Top Bottom MD 0' 8,566' TVD 0' 7,755' Cmt w/ 1,100 sks of 15.8 ppg Class G Excaoe System Details - 16 Excape module system - line for fires modules 9-16 - Red contol line fires modules 2-8 -Greer. control line fires bottom module - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 16 6,205' - 6,215' Module 15 6,280' - 6,290' Module 14 6,608' - 6,618' Module 13 6,648' - 6,658' Module 12 6,740' - 6,750' Module 11 6,852' - 6,862' Module 10 6,930' - 6,940' Module 9 6,984' - 6,994' Module 8 7,143' - 7,153' Module 7 7,368' - 7,378' Module 6 7,520' - 7,530' Module 5 7,670' - 7,680' Module 4 8,080' - 8,090' Module 3 8,122' - 8,132' Module 2 8,342' - 8,352' Module 1 8,416' - 8,426' Well Name & Number: Kenai Beluga Unit 42-6 Lease: Kenai Gas Field Municipality: Kenai Penisula Borough State: Alaska Country: USA Perforations (MD): 6,205' - 8,426' (TVD): 5,396' - 7,615' Angle @ KOP and Depth: Angle/Perfs: Dated Completed: 12/8/2004 Completion Fluid: 6% KCL Prepared By: Kevin Skiba Last Revison Date: 8/28/2008 KBU 42-6 Wellbore Clean Out • • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, June 11, 2008 1:05 PM To: 'Skiba, Kevin J.' Subject: RE: KBU 42-6 Wellbore Clean Out Page 1 of 1 Kevin, ~~ y - ~~ 1 A 403 is not needed for to perform this work. However, please submit the 404 when the work is completed. Call or message with any questions. Tom Maunder, PE AOGCC From: Skiba, Kevin J. [mailto:kskiba@marathonoil.com] Sent: Wednesday, June 11, 2008 11:46 AM To: Maunder, Thomas E (DOA) Subject: KBU 42-6 Wellbore Clean Out ~,~~~~ ~ ~ N ~ $ 2008 Tom, KBU 42-6 is an Excape well that has a history of producing solids, into the wellbore. The well has not sustained commercial production since November of 2007. Fill was tagged at 6,863' MD, on 12/29/07. This confirmed that the bottom 10 modules are covered over. We have been waiting on the arrival of a sand separator before flowing the well again. We want to utilize coil tubing to remove the wellbore solids before attempting to flow the well. Does the AOGCC require submission of a 10-403 Sundry to perform the coil tubing clean out work? Thanks, Kevin Skiba Engineering Technician Marathon Oil Company Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 6/18/2008 C MICROFILMED 03/01 /2008 DO NOT PLACE • ANY NEW MATERIAL UNDER THIS PAGE F:1LaserFichelCvrPgs InsertslMicrafilm Marker.~c q J u.r....- )... ~ ~ ., DATA SUBMITTAL COMPLIANCE REPORT 6/8/2007 Permit to Drill 2042090 Well Name/No. KENAI BELUGA UNIT 42-6 Operator MARATHON OIL CO API No. 50-133-20546-00-00 MD 8624 TVD 7812 Completion Date 12/9/2004 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION ~_._-,._- --~- Directional Survey ~ Mud Log No Samples No ------- DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: SP/GR=IEL-Density/Neutron-Sonic-Single Arm Caliper. MFTs (data taken from Logs Portion of Master Well Data Maint Logl Data Type [ I L-_ Well Cores/Samples Electr Digital Dataset Med/Frmt Number e Name Log Log Run Scale Media No Interval Start Stop OHI CH Received Comments A Directional Survey Log is ! required to be submitted. I This record automatically created from Permit to Drill I Module on: 10126/2004. ~ c.. /J I )- i ç-<., Information: Name Interval Start Stop Sent Received Sample Set Number Comments ADDITIONAL INFORMATION Well Cored? Y 'ID Chips Received?.---'I' I N Daily History Received? ~ ð\1 N e Formation Tops Analysis Received? .:LL.t>I--- Comments: -~----- ~ I~J~ ~I -- Compliance Reviewed By: Date: e e Alaska Asset Team Northern Business Unit Marathon Oil Company P.O. Box 3128 Houston, TX 77253 Telephone 713-296-3597 Fax 713-499-4469 March 26, 2007 FEDERAL EXPRESS Alaska Oil & Gas Conservation Commission Attn: Howard Okland 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon KEU #42-6 - API 50-133-20546-00 CONFIDENTIAL ~ rn ç- 4, Dear Mr. Okland: Enclosed is one CD containing confidential digital well data for the above referenced well, as described on the attached CD Contents document. Please indicate your receipt of this data by signing below and returning one copy to my attention at the letterhead address or fax to 713-499-4469. Thank you, Received by: dill Date: ~'ì Enclosures ;z O~-~Òc¡ Operations Summary: IJKBÛ~42:6 ~op~;';;;';;;;~s~";";~;;:~ì; Directional Data: jkb~42:6~cli;=;~r. cI~t Wire line Data: jFINAl~M~;~th~~=KBû42:6=~;,pì~t~.clpk Id FINAl_Marathon_KBU 42-6J>lotted,dpk l!) KBU42_6_MAINDEPTHJUL.las Mudlog Data: 1!JI<BU42:¡¡.I~; ';KšU42:6 DR:Ît.ÚNG D'INAMIcsMD.Pclf ;'i KBU42-6 -DRILLING -DYNAMICS - TVD .pdf iKBU42-6=MUDlOGßD.pdf - ~KBU42-6_MUDlOG_ TYD.pdf jI<BU42:¡¡.dbf Id KBU42-6_SCl.DBF Id KBU42-6_TIfD,DBF IkbU42_6r.dbf kbu42-6.hdr KBU42-6.mdx KBU42-6_SCl.MDX KBU42-6 TIfD,mdx Id kbu42-6r~mdx ~ Well Report KBU 42-6.pdf 1!1 I<BU42~¡¡R~";~;k;.I~; ~KBU 42-6 REMARKS. doc As-built Plat in PDF format. e KTU 42-6 API 50-133-20546-00 CD CONTENTS Confidential e .Å ~ "-t -~ ct } . Marathon Oil Company . Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 January 13, 2005 '!IN Jr'" . u')nun¡:; o L,,¡ ..) Winton Aubert Alaska Oil & Gas Conservation Commission 333 West ¡th Ave, Suite 100 Anchorage, AK 99501 1'1·. H~c Reference: Completion Report 10-407 for permit 204-209 Field: Kenai Gas Field - Beluga / Tyonek Well: KBU 42-6 Dear Mr. Aubert, Enclosed please find the Well Completion Report with associated attachments for Kenai Gas Field well KBU 42-6. This well has been completed cased hole with a 3.5" Excape monobore production string to surface. I apologize for the delay in getting this completion notice to you. Should you require fÙrther information, I can be reached at 907-529-0524/713-296- 2730, or bye-mail atJRThompson@MarathonOil.com. Sincerely, ~¡¿~ Warnes R. Thompson Sr. Completions Engineer Enclosures: Completion Report Directional Survey Operations Summary Wellbore Diagram . STATE OF ALASKA ALAS IL AND GAS CONSERVATION COMMleN WELL COMPLETION OR RECOMPLETION R~ORT AND LOG 1a. Well Status: OUO Gas0 Plugged 0 Abandoned U Suspended U WAG 0 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development 0 Exploratory 0 GINJO WINJO WDSPLO No. of Completions 1 Other Service 0 Stratigraphic Test 0 2. Operator Name: 5. Date Comp., susp.,~1o( 12. Permit to Drill Number: Marathon Oil Company Aband.: 12/9/ i,~ 204-209 3. Address: 6. Date Spudded: 13. API Number: P.O. Box 196198, Anchorage, AK 99519-6168 November 3, 2004 50-133-20546-00-00 48. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 45' FSL, 4199' FWL, Sec. 6, T4N, R11W, S.M. November 16,2004 KBU 42-6 Top of Productive Horizon: 8. KB Elevation (ft): 15. FieldlPool(s): 2773.06' FSL, 4372.48' FWL, Sec. 6, T4N, R11W, S.M. 87 Total Depth: 9. Plug Back Depth(MD+ TVD): Beluga I Tyonek 2870.42' FSL, 4350.37' FWL, Sec. 6, T4N, R11W, S.M. 8529' MD 17718' TVD 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 275,105.24 y- 2,362,054.15 Zone- 4 8624' MD 17812' TVD A-028142 TPI: x- 275,330.29 y- 2,364,778.32 Zone- 4 11. Depth Where SSSV Set: 17. Land Use Permit: Total Depth: x- 275310.03 y- 2364876.08 Zone- 4 NA NA 18. Directional Survey: Yes o No -0 19. Water Depth, if Offshore: 20. Thickness of Permafrost: NA feet MSL NA 21. Logs Run: SP/GR=IEL-Density/Neutron-Sonic-Single Arm Caliper. MFTs 22. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT. GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 133 K-55 0 139 0 139 Driven NA NA 13-318" 68 K-55 0 1514 0 1425 16" 470 sx NA 9-518" 40 L-80 0 6172 0 5363 12-1/4" 430 sx Lead 1170 sx Tail NA 3·112" 9.3 L-80 0 8566 0 7755 8-1/2" 1100 sx 90,000 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) MD: 8416-8426,8342-8352,8122-8132,8080-8090,7670-7680,7520- 3-1/2" 8566 NA 7530,7368-7378,7143-7153,6984-6994,6930-6940,6852-6862,6740- 6750,6648-6658,6608-6618,6280-6290,6205-6215 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. TVD: 7605-7615,7531-7541,7311-7321,7269-7279,6859-6869,6709- 6719,6557-6567,6332-6342,6174-6184,6120-6130,6042-6052,5930- DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 5940,5838-5848,5798-5808,5471-5481,5396-5406 See No. 23 23,600 to 46,000 Ibs. 20/40 Ottawa PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): December 9, 2004 Flowina Date of Test: Hours Tested: Production for Oil-BbI: Gas-MCF: Water-BbI: Choke Size: IGas-OiI Ratio: 12/17/2004 24 Test Period -. NA 6,124 144 64184th NA Flow Tubing Casing Press: Calculated Oil-BbI: Gas-MCF: Water-Bbl: Oil Gravity - API (carr): Press. 1330 0 24-Hour Rate ~ NA 6,124 144 NA 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". .,..-.'...." None Î RBDMS 8Ft .IAN 2 0 2005 1:1Æ~ 10ì\jAL Il~JlI\ :!/i12 .¡ "', ~ """~...~- '"'Form 1 0-407 Revised 12/2003 CONTINUED ON REVERSE 28. GEOLOGIC MARKE NAME TVD Beluga 6,210 5,401 Tyonek 8,052 7,241 30. List of Attachments: 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name: James R. Thompson 29. Include and briefly s detailed supporting "None" . MD 8416 8342 8122 8080 7670 7520 7368 7140 6984 6930 6852 6608 6440 6280 6234 6205 TVD 7605 7531 7311 7268 6859 6709 6557 6330 6174 6120 6041 5798 5631 5471 5425 5396 FORMATION TESTS rize test results. List intervals tested, and attach s necessary. If no tests were conducted, state Pressure 1333 3495 3286 2310 2655 2929 2059 2889 2473 1962 2586 2315 2466 2377 2339 2291 Contact: Signatur . Title: Sr. Completions Engineer Date: 1/14/2005 INSTRUCTIONS Phone: 713-296-2730 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 elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 20: True vertical thickness. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 I.. l\ I . ...' r · MARATHON Oil Company,Slot #KBU42-6 Pad 41-7, Kenai Gas Field,Kenai Peninsula, Alaska(lmported) SURVEY ITING Page 1 Wellbore: KBU42-6 Wellpath: MWD <0-8624> Date Printed: 18-Nov-2004 r&.. ... INTEQ Wellbore Name I Created I Last Revised KBU42-6 I 8-Nov-2004 I 18-Nov-2004 Well Name I Government ID I Last Revised KBU42-6 I I 5-Nov-2004 Name Slot #KBU42-6 Name Pad 41-7 Coord S stem Name AK-4 on NORTH AMERICAN DATUM 1927 datum Name Kenai Gas Field mments All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Glacier 1 (RKB) 87.0f! above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 4.40 degrees Bottom hole distance is 2829.47 Feet on azimuth 3.07 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated · MARATHON Oil Company,Slot #KBU42-6 Pad 41-7, Kenai Gas Field,Kenai Peninsula, Alaska(lmported} SURVEY ITING Page 2 Well bore: KBU42-6 Wellpath: MWD <0-8624> Date Printed: 18-Nov-2004 Bi. ..,. INTEQ WellDath (Grid) ReDort MD[ft] Inc{deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing rdAn/10Oftl Sectionrftl 0.00 0.00 0.00 0.00 O.OON O.OOE 0.00 0.00 275105.24 2362054.15 165.00 0.30 294.90 165.00 O.18N 0.39W 0.18 0.15 275104.85 2362054.34 226.00 0.80 350.50 226.00 0.67N 0.61W 1.11 0.62 275104.65 2362054.83 286.00 1.50 8.50 285.98 1.86N 0.56W 1.30 1.81 275104.72 2362056.02 346.00 2.80 3.00 345.94 4.10N 0.37W 2.19 4.06 275104.95 2362058.26 407.00 4.50 359.10 406.82 7.98N 0.33W 2.81 7.93 275105.06 2362062.13 467.00 6.90 358.60 466.51 13.94N 0.45W 4.00 13.86 275105.05 2362068.09 527.00 10.00 1.80 525.86 22.75N 0.38W 5.22 22.65 275105.29 2362076.90 587.00 12.70 4.80 584.68 34.53N 0.34E 4.60 34.46 275106.23 2362088.67 647.00 14.40 6.10 643.01 48.52N 1.68E 2.88 48.51 275107.84 2362102.63 707.00 16.30 6.00 700.86 64.32N 3.36E 3.17 64.38 275109.81 2362118.39 770.00 18.60 4.90 760.96 83.12N 5.14E 3.69 83.27 275111.95 2362137.16 832.00 19.80 4.80 819.51 103.44N 6.86E 1.94 103.66 275114.06 2362157.44 895.00 21.10 4.50 878.54 125.38N 8.65E 2.07 125.67 275116.26 2362179.34 958.00 22.10 4.50 937.11 148.50N 10.47E 1.59 148.86 275118.51 2362202.42 1020.00 24.20 4.40 994.12 172.80N 12.36E 3.39 173.24 275120.86 2362226.67 1083.00 26.00 4.00 1051.17 199.45N 14.31 E 2.87 199.96 275123.32 2362253.28 1145.00 27.00 4.10 1106.65 227.04N 16.26E 1.61 227.62 275125.80 2362280.84 1207.00 28.00 4.00 1161.65 255.60N 18.29E 1.61 256.25 275128.36 2362309.35 1272.00 29.00 4.30 1218.77 286.53N 20.53E 1.':;5 287.26 275131.19 2362340.23 1335.00 29.90 4.90 1273.63 317.41N 23.02E 1.50 318.24 275134.26 2362371.05 1398.00 31.60 5.10 1327.77 349.50N 25.83E 2.70 350.45 275137.67 2362403.08 1461.00 33.30 5.40 1380.93 383.16N 28.92E 2.71 384.25 275141.40 2362436.67 1!iQ1.00 34.30 6.40 1488.96 455.09N 36.36E 0.88 456.54 275150.20 2362508.45 1654.00 35.QO 6.60 1540.50 491.08N 40.47E 2.55 492.74 275154.99 2362544.35 1717.00 36.70 6.20 1591.27 528.14N 44.62E 1.32 530.01 275159.84 2362581.33 1781.00 38.80 5.70 1641.87 567.11N 48.68E 3.32 569.17 275164.64 2362620.21 1841.00 40.40 4.70 1688.10 605.20N 52.14E 2.87 607.41 275168.82 2362658.23 1903.00 39.60 5.00 1735.60 644.91N 55.51E 1.33 647.27 275172.93 2362697.86 1969.00 38.30 3.90 1786.92 686.27N 58.73E 2.23 688.75 275176.94 2362739.16 2032.00 38.40 2.40 1836.33 725.30N 60.88E 1.49 727.83 275179.83 2362778.13 2095.00 37.90 2.80 1885.88 764.17N 62.64E 0.89 766.73 275182.33 2362816.97 2220.00 37.60 4.10 1984.71 840.56N 67.25E 0.68 843.24 275188.37 2362893.25 2345.00 38.60 4.30 2083.08 917.48N 72.90E 0.81 920.37 275195.48 2362970.05 2470.00 36.70 3.40 2182.04 993.66N 78.03E 1.58 996.71 275202.06 2363046.11 2597.00 38.10 6.10 2282.94 1070.51N 84.45E 1.70 1073.83 275209.92 2363122.82 2722.00 39.20 4.90 2380.56 1148.21 N 91.92E 1.06 1151.88 275218.86 2363200.37 2847.00 38.80 5.40 2477.70 1226.56N 98.98E 0.41 1230.54 275227.40 2363278.56 2Q73.00 38.20 5.20 2576.31 1304.66N 106.23E 0.49 1308.97 275236.13 2363356.51 3099.00 38.30 5.50 2675.26 1382.33N 113.50E 0.17 1386.96 275244.87 2363434.02 3225.00 38.00 5.40 2774.35 1459.81N 120.90E 0.24 1464.78 275253.72 2363511.35 3287.00 37.80 5.70 2823.27 1497.72N 124.58E 0.44 1502.86 275258.12 2363549.17 3413.00 39.60 3.20 2921.61 1576.24N 130.66E 1.89 1581.62 275265.68 2363627.57 3536.00 39.20 3.00 3016.65 1654.20N 134.88E 0.34 1659.68 275271.38 2363705.43 3663.00 38.80 3.30 3115.35 1734.01 N 139.27E 0.35 1739.58 275277.28 2363785.13 3788.00 38.70 3.10 3212.84 1812.12N 143.64E 0.13 1817.80 275283.12 2363863.15 3914.00 39.00 3.60 3310.96 1891.03N 148.26E 0.34 1896.83 275289.24 2363941.95 4040.00 39.00 3.80 3408.89 1970.15N 153.37E 0.10 1976.11 275295.85 2364020.96 4165.00 39.00 3.70 3506.03 2048.65N 158.52E 0.05 2054.77 275302.48 2364099.34 4229.00 37.90 4.10 3556.15 2088.36N 161.22E 1.76 2094.57 275305.93 2364138.99 4292.00 35.20 4.50 3606.76 2125.76N 164.03E 4.30 2132.08 275309.45 2364176.34 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Glacier 1 (RKB) 87.Oft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 4.40 degrees Bottom hole distance is 2829.47 Feet on azimuth 3.07 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON Oil co!nY,Slot #KBU42-6 Pad 41-7, Kenai Gas Field,Kenai Peninsula, Alaska(lmported) SURVEY.TING Page 3 Well bore: KBU42-6 Wellpath: MWD <0-8624> Date Printed: 18-Nov-2004 '&i. ..,. INTEQ WellDath (Grid\ Re )ort MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing r dea/1 OOft Sectionrftl 4354.00 33.30 2.80 3658.00 2160.58N 166.27E 3.43 2166.97 275312.34 2364211.10 4417.00 31.90 1.90 3711.08 2194.49N 167.66E 2.35 2200.89 275314.38 2364244.98 4480.00 30.70 2.10 3764.91 2227.20N 168.80E 1.91 2233.59 275316.14 2364277.66 4543.00 29.40 2.60 3819.44 2258.72N 170.10E 2.10 2265.12 275318.03 2364309.15 4606.00 29.00 1.50 3874.43 2289.44N 171.20E 1.06 2295.82 275319.71 2364339.84 4671.00 28.10 0.80 3931.53 2320.50N 171.82E 1.48 2326.84 275320.92 2364370.88 4733.00 27.40 359.10 3986.40 2349.36N 171.80E 1.70 2355.62 275321.45 2364399.74 4796.00 26.20 359.90 4042.63 2377.76N 171.55E 1.99 2383.92 275321.73 2364428.14 485R.00 24.90 0.60 4098.56 2404.50N 171.66E 2.15 2410.59 275322.35 2364454.87 4921.00 23.70 1.40 4155.98 2430.42N 172.11E 1.98 2436.46 275323.29 2364480.77 4984.00 23.50 1.60 4213.71 2455.64N 172.77E 0.34 2461.65 275324.43 2364505.97 5047.00 22.80 1.30 4271.64 2480.40N 173.40E 1.13 2486.39 275325.52 2364Fi30.71 5112.00 21.80 2.00 4331.78 2505.05N 174.11E 1.59 2511.02 275326.70 2364555.35 5174.00 20.60 1.80 4389.58 2527.46N 174.85E 1.94 2533.42 275327.86 2364577.74 5237.00 19.60 1.30 4448.74 2549.10N 175.44E 1.61 2555.05 275328.86 2364599.36 5299.00 18.80 0.50 4507.29 2569.49N 175.76E 1.36 2575.40 275329.57 2364619.74 5362.00 18.20 359.60 4567.04 2589.48N 175.78E 1.05 2595.33 275329.97 2364639.72 5425.00 16.90 359.40 4627.10 2608.47N 175.62E 2.07 2614.26 275330.16 2364658.72 5488.00 15.10 358.60 4687.66 2625.83N 175.32E 2.88 2631.54 275330.19 2364676.08 5551.00 13.90 357.00 4748.65 2641.59N 174.72E 2.01 2647.21 275329.90 2364691.85 5615.00 12.70 359.30 4810.94 2656.31N 174.24E 2.05 2661.84 275329.69 2364706.57 5678.00 11.30 356.10 4872.56 2669.39N 173.73E 2.46 2674.85 275329.43 2364719.66 5740.00 9.80 353.80 4933.51 2680.70N 172.75E 2.51 2686.05 275328.66 2364730.98 5803.00 8.20 1.60 4995.73 2690.52N 172.29E 3.19 2695.81 275328.39 2364740.81 5865.00 7.20 3.70 5057.17 2698.82N 172.67E 1.68 2704.11 275328.92 2364749.10 5928.00 6.20 5.10 5119.74 2706.15N 173.22E 1.61 2711.46 275329.62 2364756.41 5991.00 5.00 3.20 5182.44 2712.27N 173.68E 1.93 2717.60 275330.19 2364762.53 6052.00 4.00 1.00 5243.25 2717.06N 173.87E 1.66 2722.38 275330.47 2364767.31 6116.00 4.00 358.60 5307.10 2721.52N 173.85E 0.26 2726.83 275330.54 2364771.77 6210.00 4.00 354.90 5400.87 2728.06N 173.48E 0.27 2733.33 275330.29 2364778.32 6335.00 3.90 352.70 5525.57 2736.62N 172.55E 0.15 2741.79 275329.52 2364786.90 6461.00 4.00 350.90 5651.27 2745.21N 171.31E 0.13 2750.26 275328.45 2364795.51 6587.00 4.20 351.50 5776.95 2754.11N 169.94E 0.16 2759.03 275327.24 2364804.43 6713.00 2.20 353.90 5902.75 2761.08N 169.00E 1.59 2765.91 275326.43 2364811.42 6776.00 2.00 355.10 5965.70 2763.38N 168.77E 0.33 2768.18 275326.25 2364813.72 6901.00 2.20 358.10 6090.62 2767.95N 168.51E 0.18 2772. 72 275326.07 2364818.30 7027.00 2.40 353.20 6216.52 2772.99N 168.12E 0.22 2777.71 275325.77 2364823.34 7154.00 2.20 354.00 6343.42 2778.05N 167.54E 0.16 2782.72 275325.30 2364828.41 72RO.00 2.30 352.30 6469.32 2782.96N 166.95E 0.10 2787.57 275324.80 2364833.33 7406.00 2.20 346.80 6595.22 2787.82N 166.06E 0.19 2792.34 275324.00 2364838.21 7531.00 2.10 346.90 6720.13 2792.39N 165.00E 0.08 2796.82 275323.02 2364842.79 7658.00 2.20 341.10 6847.05 2796.96N 163.68E 0.19 2801.27 275321.79 2364847.39 7784.00 2.00 337.90 6972.96 2801.29N 162.07E 0.18 2805.46 275320.26 2364851.75 7909.00 2.10 336.50 7097.88 2805.41 N 160.34E 0.09 2809.44 275318.61 2364855.90 8034.00 1.80 341.60 7222.81 2809.37N 158.80E 0.28 2813.27 275317.15 2364859.89 8161.00 1.70 331.90 7349.75 2812.93N 157.29E 0.25 2816.70 275315.70 2364863.47 8287.00 1.60 331.20 7475.70 2816.12N 155.56E 0.08 2819.75 275314.04 2364866.69 8412.00 1.90 338.30 7600.64 2819.57N 153.95E 0.30 2823.07 275312.49 2364870.18 8474.00 1.70 334.00 7662.61 2821.35N 153.17E 0.39 2824.78 275311.74 2364871.98 8575.00 1.70 337.30 7763.56 2824.08N 151.93E 0.10 2827.41 275310.56 2364874.73 8624.00 1.70 337.30 7812.54 2825.42N 151.37E 0.00 2828.70 275310.03 2364876.08 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Glacier 1 (RKB) 87.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 4.40 degrees Bottom hole distance is 2829.47 Feet on azimuth 3.07 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON Oil co!ny,Slot #KBU42-6 Pad 41-7, Kenai Gas Field,Kenai Peninsula, Alaska(lmported) SURVEV.TING Page 4 Well bore: KBU42-6 Well path: MWD <0-8624> Date Printed: 18-Nov-2004 Hi. ..,. INTEQ Comments Comment Pro'ection to TD Hole Sections Diameter Start Start Start Start End End End Start Wellbore finl MDfftl TVDfftl Northrftl Eastrftl M Drftl TVDrftl Northrttl East1ftl 16.000 0.00 0.00 O.OON O.OOE 1525.00 1434.27 418.35N 32.40E KBU42-6 121/4 1525.00 1434.27 418.35N 32.40E 6176.00 5366.95 2725.70N 173.66E KBU42-6 81/2 6176.00 5366.95 2725.70N 173.66E A624.00 7812.54 2825.42N 151.37E KBU42-6 Casinos Name Top Top Top Top Shoe Shoe Shoe Shoe Wellbore MDfftl TVDfftl Northfftl Easifftl MDlftl TVDlftl Northlftl Eastlftl 20" Conductor 0.00 0.00 O.OON O.OOE 139.00 139.00 0.13N 0.28W KBU42-6 13 3/8" Casino 0.00 0.00 O.OON O.OOE 1517.00 1427.62 413.93N 31.95E KBU42-6 9 5/8" Casino 0.00 0.00 O.OON O.OOE 6172.00 5362.96 2725.42N 173.68E KBU42-6 3 1/2" Liner 0.00 0.00 O.OON O.OOE 8624.00 7812.54 2825.42N 151.37E KBU42-6 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Glacier 1 (RKB) 87.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 4.40 degrees Bottom hole distance is 2829.47 Feet on azimuth 3.07 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated API: 50-133-20546-00 RT -GL: 21.00' RT-THF: 21.70' 45'FSL,4199'FVVL,Sec.6,T4N, R11VV, S.M. Tree cm = 4-3/4" Otis TOC (est.) - 300' above 9-5/8" shoe KBU 42..6 Excape Svstem Details - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module 1 - NA Module 2 - 8359' Module 3 - 8139' Module 4 - 8097' Module 5 - 7687' Module 6 - 7537' Module 7 - 7385' Module 8 - 7159' Module 9 - 7001 ' Module 10 -6947' Module 11 - 6869' Module 12 - 6757' Module 13 - 6666' Module 14 - 6625' Module 15 - 6297' module 16 - 6222' Well Name & Number: County or Parish: Perforations (MD) BHP: Dated Completed: Prepared By: Kenai Last Revison Date: Surface Casing: 13-318",68 ppf, K-55, STC @ 1514' Cmt wI 470 sx. of class G at 12 ppg. Int. Casing: 9-5/B", 40 ppf, L-80, BTC @ 6172' Cmt wi 430 sx of class G lead at 12.5 ppg and 170 sx of class G tail at 13.5 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-BO, EUE 8rd with 6.25" OD control line protectors to 8566' Cmt wI 1100 sx of class G at 15.8 ppg Excape System Details - Excape modules placed - Green control line fires bottom 1 modules - Red contol line fires middle 7 modules - Yellow line for fires top 8 modules - Ceramic flapper valves below each module except for module 1 Perfs MD (RKS): Module 1 - 8416 - 8426' Module 2 - 8342 - 8352' Module 3 - 8122 - 8132' Module 4 - 8080 - 8090' Module 5 - 7670 - 7680' Module 6 - 7620 - 7630' Module 7 - 7368 - 7378' Module 8 -7143 -7163' Module 9 - 6984 - 6994' Module 10 - 6930 - 6940' Module 1 1 - 6862 - 6862' Module 12 - 6740 - 6750' Module 13 - 66¿¡8 - 6658' Module 14 - 6608 - 6618' Module 15 - 6280 - 6290' Module 16 - 6206 - 6215' Alaska (TVD) USA Fluid: 6% KCL 12/1/2004 : . . KENAI BELUGA UNIT 42-6 KENAI BELUGA UNIT 42-6 ORIGINAL DRILLING 1 0/29/2004 139 (ft) 10/30/2004 139 (ft) 10/31/2004 139 (ft) 11/112004 139 (ft) 11/2/2004 139 (ft) 11/312004 462 (ft) 1114/2004 1,525 (ft) 11/5/2004 1,525 (ft) 11/6/2004 1,525 (ft) 11/7/2004 1,525 (ft) 11/8/2004 3,248 (ft) 11/9/2004 4,761 (ft) 11/10/2004 5,921 (ft) 11/11/2004 6,176 (ft) 11/12/2004 6,176 (ft) 11/13/2004 6,176 (ft) Accept rig FlWest Fork#3 @ 12:00hrs 10/28/2004. Move rig and begin RlU rig. RlU rig. RlU rig. RlU rig. RlU rig. Complete RlU rig. P/U DP. Test Diverter. P/U BHA. Spud well. Clean conductor to 139'. Drill F/139' to 462'. Drill F/462' to 1013'. Circ. Wiper trip to 20" shoe. Service Rig. TIH. Drill F/1013' to 1525'. Circ.wiper trip to 20" csg.shoe. Service rig. Repair rig. TIH, Circ Circ, POOH, UD bha. Rig up csg tools.Run Csg. TIH Stab in tool, Circ, Cmt, Circ. Pull stab in tool. woe woe. N/D diverter. Cut 13 3/8". Set out Diverter. Install wellhead. N/U BOPE Stack. Test BOPE's Test BOPE's. Set wear Bshg. Csg test. P/U drill pipe. Run RTTS. Csg test. POOH RTTS. P/U drill pipe MIU Bha#3. TIH to 1471'. Clean out shoe tract, Drill F/1525' to 1545'. Circ clean. LOT. Circ and chg fluids. Drill F/1545' to 3248' Drill F/3248' to 3843'. CBU. Wiper Trip to shoe. Service Rig. TIH. Drill F/3843' to 4761' Drilled F/4761, to 5416'. Lost circulation. Drilled F/5416' to 5921' Drill 5921 - 6130, circ I determine TD, drill 6130 - 6171, circ, wiper trip, drill 6171 - 6176, eire, POH for lost circ, spot LCM pills, POH to shoe. Monitor well, POH, UD drctnl assy, RIH 12 1/4 BHA, POH, spot LCM pills, POH to shoe, soak LCM at shoe Monitor well, POH, UD BHA #4, RlU, run 9 5/8 csg Printed: 1/12/2005 2:45:31 PM . . Legal Well Name: KENAI BELUGA UNIT 42-6 Common Well Name: KENAI BELUGA UNIT 42-6 Event Name: ORIGINAL DRILLING 11/14/2004 6,176 (ft) 11/15/2004 7,290 (ft) 11/16/2004 8,624 (ft) 11/1712004 8,624 (ft) 11/18/2004 8,624 (ft) 11/19/2004 8,624 (ft) 11/20/2004 8,624 (ft) Circ, monitor for loss, RIH 9 5/8 csg, Ind hgr, cmt, install pkf, test same, CIO rams, test, P/U bha #5, P/U 5" DP P/U DP, test csg, RIH, drill shoe track, FIT, drill 6192 - 7204, wiper trip, drill 7204 - 7290 Drill 7290 - 8624, circ, POH wiper trip to shoe Service rig, RIH wiper trip, Circ, POH wiper trip, ser rig, RIH wiper trip, circ, POH for E-Iogs, E-Iog well Run Reeves EL. M/U 8 1/2" bit and BHA. RIH.Circ. and increase MW. POOH. Trouble shoot TDS. RIH wlopen hole DP. RIH 5" DP, Circ, POH, RlU Reeves, E-Iog RFTs, RID Reeves, POH 5" DP. POOH w/DP. Printed: 1/1212005 2:45:31 PM . . KENAI BELUGA UNIT 42-6 KENAI BELUGA UNIT 42-6 ORIGINAL COMPLETION 11/20/2004 8,624 (ft) Service rig. RIH w/8 1/2" bit. Circ. clean. POOH and LID DP and BHA. Pull wear bushing and RlU to run CSG. 11/21/2004 8,624 (ft) Run 3.5" Excape completion. 11/22/2004 8,624 (ft) Correlate 31/2" Excape completion. Cement 31/2" CSG. 11/23/2004 8,624 (ft) RID rig. Printed: 1/1212005 2:46:40 PM , . , . . 12/1/2004 (ft) 12/2/2004 (ft) 12/3/2004 (ft) 12/4/2004 (ft) 12/512004 (ft) 12/612004 (ft) 12/7/2004 12/812004 12/9/2004 12/10/2004 12/11/2004 12/12/2004 12/13/2004 RU wire line unit run CBL on well Layout miscellaneous materials to prepare location for frac work. Line location and start spotting frac tanks Move in additional frac tanks and well test equipment. Start hauling mix water. Lining well location and spotting frac equipment and materials. Continue hauling mix water. Finalize laying liner and timbers for frac equipment. Started Mixing 6% KCL and heating same in frac tanks. (ft) Continue heating frac tanks. Start moving in frac trucks. sand kings. hydrator, chem add truck, and well testing equipment and lines (ft) finish RU well location for frac job. Pressure test well test and CT equipment to 4500 psig. Perofrate modoule 1 perfs from 8416-8426. (ft) Performed 16 excape frac jobs. RIH with CT and started cleaning out well to PBTD (ft) RIH with CT and cleaned out 7 of 15 excape flappers. RIH to PBTD and CBU. POOH to abover perfs and jetted well in. POOH with CT and RD same. Started unloading and flow testing well. (ft) Continued to clean up and flow test well. (ft) Continued to clean up and flow test well. (ft) Continued to clean up and flow test well. Final DIMS report Printed: 1/13/2005 9:38:08 AM . ~~~~Œ ffiJ~ ~~~~~~ . AI,ASIiA OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Willard J. Tank Advanced Senior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, Texas 77253 Re: Kenai KBU 42-6 Marathon Oil Company Pennit No: 204-209 Surface Location: 45' FSL, 4199' FWL, SEC. 6, T4N, Rll W, S.M. Bottomhole Location: 2772' FSL, 4409 FWL, SEC. 6, T4N, Rll W, S.M. Dear Mr. Tank.: Enclosed is the approved application for pennit to drill the above referenced development well. This pennit to drill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the tenns and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659-3607 (pager). BY ORDER O-E THE COMMISSION DATED tbis~ day of October, 2004 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. . . Worldwide Drilling North America Marathon Oil Company P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713-499-6737 October 19, 2004 John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 OCT2 n 2004 Reference: Drilling Permit Application Field: Kenai Gas Field Well: KBU 42-6 Dear Mr. Norman Enclosed please find the PERMIT TO DRILL application, along with the associated attachments and filing fee of $100. The intent is to drill a development well in the Beluga / / Upper Tyonek Pool in the Kenai Gas Field. No completion is desired in the Sterling pool. Please note that Marathon is requesting a waiver for 20 ACC 25.035 (e) (1) (b) requiring a *' two pipe ram stack. The request is specified on page 12 of the attached drilling prognosis. If you require further information, I can be reached at 713-296-3273 or bye-mail at wjtank@ marathonoil.com. Sincerely, " '< ~. J \\ i L 1\ I , I fl ffd''":1. ,,f ~7'V' Willard J. Tank Advanced Senior Drilling Engineer Enclosures , ..:x-¡JrP Wevt Vw JtL.f- ~~s..CtÞ1' ke p. / 2-/ t4 . OR\G\NAl 1a. Type of Work: 2. Operator Name: 3. Address: i 0lzs /ZOotf A STATE OF ALASKA .. Aù!II'~ Oil AND GAS CONSERVATION CO~SION PERMIT TO DRILL 20 AAC 25.005 ,~J;.";; n;¡ Ii.;: L,i,: t', .' 1b. Current Well Class: Exploratory U Developme~r9iLnY ~Itiple Zone 0 Stratigraphic Test 0 Service 0 DevelopmenfGas~m Single Zone 0 5. Bond: Blanket ~ Single Well U 11. Well Name and Number: Bond No. 5194234 KBU 42-6 6. Proposed Depth: 12. Field/Pool(s): MD: 8,624 TVD: 7,800 Kenai Gas Field 7. Property Designation: Beluga I Upper Tyonek Pool /' A-028142 8. Land Use Permit: Drill 0 Redrill U Re-entry 0 Marathon Oil Company P.O. Box 3128, Houston, TX 77253 4a. Location of Well (Governmental Section): Surface: 45' FSL, 4,199' FWL, Sec. 6, T4N, R11W, S.M. Top of Productive Horizon: 2,772' FSL, 4,409' FWL, Sec. 6, T4N, R11W, S.M. Total Depth: 2,772' FSL, 4,409' FWL, Sec. 6, T4N, R11W, S.M. 4b. Location of Well (State Base Plane Coordinates): Surface:x-275,107.816 y- 2,362,055.816 Zone- 4 16. Deviated wells: Kickoff depth: 250 feet Maximum Hole Angle: 38.22 degrees 18. Casing Program: Size Casing Hole Driven 20" 16" 12 1/4" 81/2" 13 3/8" 95/8" 3 1/2" 19. Total Depth MD (ft): Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Specifications Weight Grade Coupling Length 133 K-55 PE 118' 68 L-80 BTC 1,504' 40 L-80 BTC 6,168' 9.3 L-80 EUE 8,603' nC'T ç:" (? u"'" ,tc 13. Approximajß4pud Date: Novemb(r 3..,2004 9. Acres in Property: 14. Distance'1ó-Nearest 2,345 Property: 3300 ft 10. KB Elevation 15. Distance to Nearest Well (Height above GL): (21' AGL) 87 feet Within Pool: 1,850 ft. to KBU 33-6X 17. Maximum Anticipated Pressures in psig (see ~ 'liYÄAC 3-S.035) Downhole: 3,569 Surface: C.1.8.9B" Setting Depth Quantity of Cement c.f.orsacks Top Bottom MD TVD MD TVD (including stage data) 0' 0' 139' 139' 0' 0' 1,525' 1,432' 409 sacks "., / 0' 0' 6,189' 5,365' 693 sacks ../ / 0' 0' 8,624' 7,800' 1 ,224 sacks / PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Yes Yes Junk (measured): Cement Volume MD TVD Length Size Perforation Depth TVD (ft): 20. Attachments: Filing Fee ~ BOP Sketch ~ Drilling Program ~ Property Plat [;2] Diverter Sketch [;2] Seabed Report 0 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Willard J. Tank J;rJia/) \ ~.J~ ý~fr- fI Commission Use Only Permit to Drill API Number: Permit Approval Number: ::V6~'- 2-0&¡ 50- / j 3 - 20.s 716 Date: Conditions of approval : ~a required ".e ~1 H r " sulfide measures ::~M0r:.~oo P'" '-""" V - Form 10-401 Revised 06/2004 Printed Name Signature Time v. Depth Plot U Shallow Hazard Analysis U Drilling Fluid Program [;2] 20 AAC 25.050 requirements 0 Date Contact Title Advanced Senior Drilling Engineer Phone 713-296-3273 Date October 19, 2004 See cover letter for other requirements. 8 ~:~ No 'Iv( No 1] /()/~ otf I s~mit iJDuPlicate Mud log required Directional survey required Yes 0 Yes';B APPROVED BY . _ , ~TI-JE ¡¡:O¡vJMISSION UK! LJ II\J 1-\ L Date: . . MARATHON MARATHON Oil COMPANY DRilliNG PROGRAM Kenai Gas Field KBU 42-6 Original 10/19/04 Originator: W.J. Tank ;f ,(\ A /} Y'.' /'1 / /1" /'../ -,oÝ I '1:- ~' ~(/ Drilling Superintendent: P.K. BerQa North America Drilling Manager: B.J. Roy Page 1 of 14 . . Table of Contents General Well Data........................................................................................................................... ........................................3 Geologic Program Summary........................................................................................................................ ...........................3 Summary of Potential Drilling Hazards........................................................................................................................ ............4 Formation Evaluation Summary......................................................................................................................... .....................4 Drilling Program Summary....................................................................................................................... ...............................5 Casing Program....................................................................................................................... ................................................6 Casing Design........................................................................................................................ .................................................6 Maxim um Anticipated Surface Pressure...................................................................................................................... ...........6 BOPE Program....................................................................................................................... ................................................. 8 Wellhead Equipment Summary........................................................................................................................ ......................9 Directional Program Summary....................................................................................................................... .........................9 Directional Surveying Summary...... .... .... ........ ........... ........ ..... ......................... ......... ..... .... ..... ....... ...... ......... ....... ........ .........10 Drilling Fluid Program Summary........................................................................................................................................... 1 0 Drilling Fluid Specifications................................................................................................................ ....................................11 Solids Control Equipment ... ....... ............. ............................... ......... ............ ... ......... ....... ....... ....... ....... ................ ...................11 Cement Program Summary........................................................................................................................ ...........................12 Regulatory Waivers and Special Procedures ............. ................................ .......... ....... .............. ......... ...... .............................12 Bit Summary......................................................................................................................... .................................................13 Hydraulics Summary........................................................................................................................ .....................................13 Formation Integrity Test Procedure....................................................................................................................................... 14 Page 2 of 14 . . General Well Data Well Name KBU 42-6 Lease/License Surface Location 45' FSL, 4,199' FWL, Sec. 6, T4N, R11W, S.M. WBS Code DD.04.10982.CAP.DRL Slot/Pad Pad 41-7 Field Kenai Gas Field Spud Date 11/3/04 (est.) KB Elev. 87 County/Province Kenai Peninsula API No. Ground Level Elev. 66 State I Country Alaska Well Class Development Perm. Datum KB Total MD 8,624' Rig Contractor Glacier Drilling ~ Water Depth NIA Total TVD 7,800' Rig Name #1 Water Protection Depth Comments: Geoloaic Proaram Summary MD - RKB TVD - RKB Pore Pressure Pore Pressure Possible Fluid Formation (ft) (ft) (psi) (ppg) Lithology Content Sterling (Not a Prod Target) 4,248 3,572 1.0 - 6.5 Sandstone Gas I Water Upper Beluga (Not a Prod Target) 5,494 4,677 1.5-~ Sandstone Gas Middle Beluga (Primary Target) 6,201 5,377 3.8 -~/ Sandstone Gas Tyonek (Secondary Target) 8,086 7,262 5.8 - '¡fo Sandstone Gas Comments: Surface Location Coordinates From Lease/Block Lines 45' FSL, 4,199' FWL, Sec. 6, T4N, R11W, S.M. / Latitude 600 27' 34.720" N Longitude 151014' 45.216" W UTM North (Y) 2,362,055.816' UTM East (x) 275,107.816' Tolerance Horizontal Depth Displacement (ft) MD TVD +N/-S +EI-W Tolerance Directional Target (ft) (ft) Location (Y) (X) (ft) Middle Beluga 6,201 5,377 2,772' FSL, 4,409' FWL, Sec. 6, T4N, R11W, S.M. ,/ 2,727 210 Circle 250' radius Comments: Page 3 of 14 . . Summary of Potential Drillina Hazards Hazard Event Lost Circulation in Low Pressure Sterling and Beluaa sands Discussion Control losses by using sufficiently sized LCM. Comments: Potential Hazards Statement / To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC or BLM inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No H2S is anticipated. Gas sands will be encountered from +/- 4,248' MD (3,572' TVD) to total depth of the well. These sands will run from highly depleted to slightly above normal pressure. Lost circulation and differential sticking are potential hazards in some of the Sterling and Beluga sands. The Flo-Pro mud system that will be used to drill the well will help reduce these risks and lost circulation materials will be on location. Weighting material will available on location for proper well control.. Formation Evaluation Summary Interval LWD Electric Logs Mud Logs Surface None None None 0' - 1,525' MD Intermediate None None Basic with GCA, shale density, temperature in and out, 1,525' - 6,189' MD sample collection (10' samples). Production None Reeves Quad Combo & possible MDT. Basic with GCA, shale density, temperature in and out, 6,189' - 8,624' MD Pull GR-Neutron to surface inside casing. sample collection (10' samples). Completion NIA GR, CCL NIA Coring Requirements: None Comments: Page 4 of 14 . . Drillina Proaram Summary CONDUCTOR: 1. Drive 20" conductor to +/-100 ft. RKB. 2. Move in and rig up rotary drilling rig. 3. Install starting head 20" SLC x 21 1/4", 2M flanged. 4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and 16" diverter line. 5. Function test diverter and diverter valve. / SURFACE: 1. Drill a 16" hole to 1,525' MD (1,432' TVD) per the directional plan. 2. RIH with 13 3/8" casing and hang off in the elevators. Make up stab-in sub and centralizer on 5" drill pipe. TIH with inner string and latch into stab-in float collar. Cement 13 3/8" casing. Sting out, shear out drill pipe wiper plug, and circulate drill pipe clean. TOOH with inner string. 3. Cut off 13 3/8" casing. ND diverter. 4. Install 13 3/8" slip lock connection X 13 5/8" 5M flanged multibowl wellhead. 5. NU 135/8" 5M BOP'S. Test BOP'S and choke manifold to 250/2,000 psi. /' 6. Set wear bushing. 7. Test surface casing to 2,000 psi. /' INTERMEDIATE: 1. Drill out float equipment and make 20' of new hole. CBU. 2. Test shoe to leak off. Estimated EMW is 15.0 ppg. 3. Drill 12 1/4" directional hole to 6,189' MD (5,365' TVD) as per directional program, short tripping as necessary (1,000' or 24 hours, but can be extended depending on hole conditions). 4. At TD circulate hole clean. Make wiper trip. TOOH. 5. Change out variable pipe rams with 9 518" casing rams. Run test plug and test casing rams to 2,000 psi. / 6. Run and cement 9 5/8" casing. Land hanger in multibowl wellhead. 7. Back out landing joint. Change out 9 5/8" casing rams with variable pipe rams. Run test plug and test rams to 250/2,000 psi. 8. Set wear bushing. Test casing to 2,000 psi. / PRODUCTION: 7. Drill float equipment and 20' of new formation w/8 1/2" bit. CBU. Test shoe to leak off. Estimated EMW 15.0 ppg. Drill a 8 1/2" hole to 8,624' MD (7,800' TVD) per the directional program, short tripping as necessary (1,000' or 24 hours, but can be extended depending on hole conditions). At TD circulate hole clean. Make wiper trip. TOOH. RU logging company. Run open hole logs as per plan. RD logging company. TIH w/8 1/2" bit to TD for wiper trip. TOOH to 9 5/8" shoe and circulate until log evaluation is complete for picking EXCAPE modules. After picks are made, trip to TD and circulate clean. TOOH and laydown BHA and drill pipe. Pull wear bushing. RU and run 31/2" EXCAPE casing string. RU logging company to correlate EXCAPE modules to open hole logs. RD 10ggiIJY company. Cement 3 1/2" casing while reciprocating. Bump plug with 500 psi over displacement pressure. WOC. PU 3 1/2" casing. PU BOP stack. Run control and electric lines out tubing head outlet. Set slips. Cut 31/2" casing. LD BOP. Set 31/2" packoff. NU 135/8" 5M X 31/8" 5M tubing head adapter and 31/8" 5M tree. Test tree to 5,000 psi. Rig down and move out drilling rig. / 1. 2. 3. 4. 5. 6. 8. 9. 10. 11. Note: Drill all hole sections with 5" drillpipe. Perforating guns will be run on the outside of the 3 1/2" production casing with a flapper valve just below each perforating gun. Guns to be activated by control line to surface. COMPLETION: Completion will be done without a rig. Page 5 of 14 . . CasinQ Proaram MD (ft) Casing Size Weight (in) Top Bottom (lbs/ft) Grade 133/8 Surface 1,525 68 L-80 95/8 Surface 6,189 40 L-80 31/2 Surface 8,624 9.3 L-80 Comments: Connection API Ratings Type BTC BTC 8rd O.D. (in) 14.375 10.625 4.5 Makeup Torque (ft-Ibs) N/A' N/A' 3,200 Hole Size (in) 16 12 1/4 81/2 111:::- ;:, ~ m~ () !==- <tI II) =õ.B o 2,260 3,090 10,530 c: 0- ïñ ~ !g 5,020 5,750 10,160 1,545 979 207 * The make up of the buttress connection will be to the proper mark. CasinQ DesiQn Casing Shoe Safety Factors () c: Casing Setting Mud Wt Frac. Form Maximum Surface ~ .2 - ~ Size Weight Depth When Set Grad Press Pressure í!! ð ;:, (in) (lbIft) Grade (TVD) (Iblgal) (Iblgal) (Iblgal) (psi) m I- 133/8 68 L-80 1,432 9.4 15.0 8.4 782 3.12 2.54 3.94 95/8 40 L-80 5,365 9.5 15.0 7.p~\ 1,806 / 1.58 1.01 2.65 31/2 9.3 L-80 7,800 10.0 15.0 /8.8/ 1,806 1.15 2.07 1.61 l~ ~ Comments: Maximum AnticiDated Surface Pressure Setting Depth Casing Size TVD MAWP * MASP .. Mud/Gas (in) (ft) (psi) (psi) Ratio 133/8 1,432 3,432 782 / 30170 95/8 5,365 3,997 1,806 / 30170 31/2 7,800 6,909 1,806 30170 * MAWP = Maximum allowable working pressure ** MASP = Maximum anticipated surface pressure Comments: MASP 1 MAWP CALCULATIONS: Surface casino: 133/8" (1,525' MD. 1.432' TVD) MASPfrac = (Fracture gradient at shoe + S.F.) x .052 X TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg + 0.5 ppg) x .052 x 1,432' - (.1 psi/ft x 1,432') MASPfrac = 1,154 psi - 143 psi MASPfrac = 1,011 psi. Page 6 of 14 . . MASPbhp = BHP open hole td - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhp = (7.0 ppg x .052 x 5,365') - (0.3 x 9.5 ppg x .052 x 5,365') - (0.7 x 0.1 psi/ft x 5,365') MASPbhp = 1,953 psi - 795 psi - 376 psi MASPbhp = 782 psi MASP = MASPbhp = 782 psi MAWP = (0.7 x Casing Burst) - (Mud WI. - Backup Fluid WI.) x .052 x TVD MAWP = (0.7 x 5,020) - (9.4 - 8.3) x .052 x 1,432' MAWP = 3,514 psi - 82 psi = 3,432 psi Intermediate casina: 9 5/8" (6.189' MD. 5.365' TVD) MASPfrac = «Fracture gradient at shoe + S.F.) x .052 X TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg + 0.5 ppg) x .052 x 5,365' - (.1 psi/ft x 5,365') MASPfrac = 4,324 psi - 537 psi MASPfrac = 3,787 psi. MASPbhp = BHPopen holetd - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhp = (8.8 ppg x .052 x 7,800') - (0.3 x 10.0 ppg x .052 x 7,800') - (0.7 x 0.1 psi/ft x 7,800') MASPbhp = 3,569 psi - 1,217 psi - 546 psi MASPbhp = 1,806 psi MASP = MASPbhp = 1 ,806 psi / MAWP = (0.7 x Casing Burst) - (Mud WI. - Backup Fluid WI.) x .052 x TVD MAWP = (0.7 x 5,750) - (9.5 - 9.4) x .052 x 5,365' MAWP = 4,025 psi - 28 psi = 3,997 psi Production casina: 31/2" (8.624' MD. 7.800' TVD) MASPfrac = «(Fracture gradient at shoe + S.F.) x .052 X TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg + 0.5 ppg) x .052 x 7,800' - (.1 psi/ft x 7,800') MASPfrac = 6,287 psi - 780 psi MASPfrac = 5,507 psi. MASPbhp = BHPopen holetd - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhp = (8.8 ppg x .052 x 7,800') - (0.3 x 10.0 ppg x .052 x 7,800') - (0.7 x 0.1 psilft x 7,800') MASPbhp = 3,569 psi - 1,217 psi - 546 psi MASPbhp = 1 ,806 psi MASP = MASPbhp = 1,806 psi / MAWP = (0.7 x Casing Burst) - (Mud WI. - Backup Fluid WI.) x .052 x TVD MAWP = (0.7 x 10,160) - (10.0 - 9.5) x .052 x 7,800' MAWP = 7,112 psi - 203 psi = 6,909 psi Page 7 of 14 . . BOPE ProQram 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 (1) 13-5/8" 5M pipe ram Surface 133/8 3,432 782 2,000 9.4 (1) 135/8" 5M blind ram 250/2,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Intermediate 95/8 3,997 1,806 2,000 9.5 (1) 135/8" 5M blind ram 250/2,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram / Production 31/2 6,909 1,806 2,000 10.0 (1) 135/8" 5M blind ram 250/2,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets /~ / Comments: 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 L 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. f\. 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. Casing Test Pressures Casing test pressures 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. Page 8 of 14 . . Wellhead EauiDment Summary Component Description Casing Hanger Type Casing Head 13-5/8" 3M X 13-3/8" Slip Loc W/2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL 1, 13 5/8" x 9 5/8" Fluted PR1 Mandrel Tubing Head 13-5/8" 3M Studded Bottom X 13-5/8" 5M Fig Top, WI 2, 2-1116" 5M Studded Outlets, 135/8" x 31/2" Manual U,AA,PSL 1 ,PR1 Slip Adapter Flange 13-5/8" 5M X 3-118" 5M WI Seal Pocket and 3" H BPV Threads Comments: Control lines and electric cable for the EXCAPE system will be routed through the tubing head side outlet. Directional ProQram Summary Build Turn / Coordinates Sec. MD TVD Rate Rate Dogleg Inclination Azimuth +N/-S +EI-W VS No. Description (ft) (ft) (°/100') (°/100') (°/100') (deg) (deg) (ft) (ft) (ft) 1 Tie On 0 0 0 0 0 0 0 0 0 0 2 KOP 250.00 250.00 0 0 0 0 0 0 0 0 3 Build up Section 3.00 0 3.00 4.40 4 End of Build 1,524.06 1,431.65 3.00 0 3.00 38.22 4.40 408.23 31.44 409.43 5 Hold Section 0 0 0 38.22 4.40 6 End of Hold 4,289.88 3,604.53 0 0 0 38.22 4.40 2,114.41 162.83 2,120.67 7 Drop Section -2.00 0 2.00 4.40 8 End of Drop to the 6,200.98 5,377.00 -2.00 0 2.00 0.00 4.40 2,726.75 209.98 2,734.82 Target 9 TO 8,623.98 7,800.00 0 0 0 0.00 4.40 2,726.75 209.98 2,734.82 Comments: Vertical section calculated from a reference azimuth of 4.400 taken from surface location to bottom hole location. Potential Well Interference: Well KBU 11-8X KBU 33-6X KTU 24-6H KTU 32-7 KBU 43-7X Distance (ft) 46.58 56.84 90.55 96.34 103.55 DeDth (MD) 369 262 262 279 Surface No serious interference exists. See attached directional plan and anticollision analysis for more details. Page 9 of 14 c ~ o o lD ~ .<: i5. <D CJ ~ :e ~ <D 2 I- -2000 -1000 0 1000 2000 3000 4000 5000 Vertical Section at 4.40° [2500ft/in] Directional Surveying Summary c ~ o o o ~ +' 'E 1:: o ~ 'E '5 o ({J -1000 West( - )/East( +) [1000ft/in] o - 1,525' 1,525' - 6,189' 6,189' - 8,624' x x x Comments: Drilling Fluid Program Summary o 1 ,432 8.6 - 9.4 Gel I Gelex Spud Mud 1,432 5,365 9.0 - 9.5 6% Flo-Pro wI Safecarb 5,365 7,800 6% Flo-Pro wi Safecarb Comments: Gel, Gelex, Soda Ash, Caustic, Barite, Polypac Supreme UL, Sodium Meta Bisulfate Flo-Vis, Poly Pac Supreme UL, KCI, SafeCarb F&M, Barite, Caustic, Conqor 404, Sodium Meta Bisulfate Flo-Vis, PolyPac Supreme UL, KCI, SafeCarb F&M, Barite, Caustic, Conqor 404, Sodium Meta Bisulfate See mud prognosis for details. The mud system from the intermediate section will be utilized in the production hole section instead of building a new mud for that section. Sized CaCOa (SafeCarb) will be used to control leakoff. Page 10 of 14 . . Drillina Fluid Specifications Interval - TVD LSRV From To Density Vis 1 min PV YP Fluid Loss Drill Solids (ft) (ft) (Iblgal) ( seclqt) (lb.l100ff) (cP) (lb/100 ff) (cc) pH (%) 0 1 ,432 8.6 - 9.4 60 - 100 NIA 25 - 35 NC - 12 +1- 9.5 <7.5 1,432 5,365 9.0 - 9Y/~ 30,000 8 - 12 7-9 +1- 9.5 +1- 5 5,365 7,800 9.0/1o.g/ 30,000 10 - 14 6-8 +1- 9.5 +1- 5 ~ Comments: As a standard practice for long string completions, the drilling mud that will remain above the top of cement on the 3 W' production casing will be treated with corrosion inhibitor (Conqor 303A) at a concentration of 1 drum per 100 barrels of drilling fluid. See mud prognosis for details. Solids Control Eauipment c: 0 () ~ ~ '§ ? ~ 10 c: () c £' .s:; (¡j æ 0 C) en en en (¡j 'C ~ Õ ~ C) C) õ c: c: c: ~ 10 ëii 'C ë =: =: e 10 en .s:; () () ::J () ::J ::J () Interval en c c :¡¡ 0 0 0 N Comments 0- 8,624' MD X X X X Closed Loop System, Full Containment Equipment Specifications Item (quantity, design type, brand, model, flow capacity, etc) Shaker 2 - Derrick Model 2E48-90F-3T A Desander N/A Desilter 1 - Derrick Model 0522 Mud Cleaner NIA Centrifuge 2 - Ml/Swaco units Cuttings Dryer NIA Cuttings Injection Marathon G&I Facility Zero Discharge NIA Comments: The solids control equipment will consist of two flowline cleaners, a desilter, and the MI centrifuge van. Included will be equipment to de-water the underflow from the mud processing equipment to allow for disposal of the cuttings and solids by slurrification and injection into the disposal well at the KGF. Page 11 of 14 . . Cement Program Summary Depth Gauge Top of Cement Open èasing Hole Ann Vol Slurry WOC Hole Size MD TVD Size MD TVD ToTOC Vol Time Excess (in) (ft) (ft) (in) (ft) / (ft) (tf) ( ft3) (hrs) (%) 133/8 1,525 1,432 16 0 0 693 1,026 8 50 95/8 6,189 5,365 12 1/4 3,700 3,141 780 1,203 8 50 31/2 8,624 7,800 81/2 5,600 4,780 1008 1,408 NIA 35 Mix Water Compressive Casing Slurry TOe )/ Strength Size Density Qty Yield Vol MD Qty WL FW (psi) (in) Slurry Cement Description (Iblgal) (sx) (W/sx) (W) (ft) (galls x) Type (cc) (%) 8 hr 24 hr 133/8 Tail Type I Cement 12.0 409 2.51 1,026 0 11.28 Fresh 812 0 196 818 Lead Class "G" 12.5 425 2.10 892 3,700 11.97 Fresh 273 769 95/8 Tail Class "G" 15.8 268 1.16 311 5,600 4.97 Fresh 0 0 1,043 3,163 3 1/2 Tail Class "G" 15.8 1,224 1.15 1,408 5,600 4.92 Fresh 24 0 226 2,632 Comments: See cement prognosis for details and spacer specifications. Regulatorv Waivers and Special Procedures AOGCC Regulation 20 ACC 25.035 (e) (1) (b) Requirement for 2 pipe rams, one blind ram, and one annular for a API 5K or above BOP stack. Marathon is requesting a waiver from the above regulation for KBU 42-6. We are requesting that the BOP stack be ~ configured with one pipe ram instead of two, due to rig height restrictions in the running of the 3 1/2" production casing. ---/" The height restriction involves having rig crew members routing control line and electrical line through one of the tubing head outlets after the 3 1/2" casing is cemented and the BOP stack is picked up. This is prior to setting the casing on slips and cutting the casing sticking up. These lines control firing of the perforating guns and the monitoring of downhole pressure and temperature in our EXCAPE completion system. Similar waivers have been requested for EXCAPE completion wells in the Kenai Gas Field and were granted. No problems were encountered while doing this operation on any of the wells. Also due to MASP below 2,000 psi, only a 3,000 psi BOP stack would be required for this work if it was economic to change out BOP stacks for this well. If a 3,000 psi BOP stack was used then no waiver would be necessary. Utilizing the 13 5/8" 5M stack currently found on the Glacier Drilling #1 rig is more than sufficient for pressures to be encountered. I . .... '0· (J-:b -I::- No W wtV~/ y\£<L.~çq '1- '- e" tp1_£>lQ ßOIJ[ r;;Þ~ íc, ?AJ~21-{~' Page 12 of 14 . . Bit Summary Interval - MD Type Recommended Estimated From To Size WOB Rotating ROP (ft) (ft) (in) Manufacturer Model No. IADC (kips) RPM Hours (ftlhr) 0 1,525 16 Christensen MX-1 115 1 - 4 80 - 350 1,525 6,189 12 1/4 Christensen HCM406 M333 Up to 50 Motor 6,189 8,624 81/2 Christensen HCM605 M323 Up to 25 Motor Comments: If a second bit is necessary for the 12 W' hole a MX-C3 (IADC 137) should be used to finish this section. Back up bits for the 8 W' hole section will consist of mill tooth and TCI tricone bits. See bit prognosis for additional information. Hydraulics Summary Rig mud pumps available are shown below. Max Press @ Displacement @ Liner ID Stroke 90% WP 95% eft Max Rate Hole Sections Used Qty Make Model (in) (in) (psi) (gal/stroke) (sprn/gpm) On 5 8 2,597 2.04 125/255 Surface 3 National Oil A600PT 125/255 Well 5 8 2,597 2.04 Intermediate 5 8 2,597 2.04 125/255 Production Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. Hole Standpipe Min Nozzle Depth-MD Size Pump Rate Pressure AV ECD Size (ft) (in) (gpm) (psi) (fprn) (Ib/gal) (32"s) Remarks o - 1,525 3 - 18's Actual Data from CLU 8 (@ 1,821' MD) 16 662 1,700 70 1 - 15 1,525 - 6,189 12 1/4 662 2,000 130 6 - 13's Actual Data from CLU 8 (@ 6,722' MD) 6,189 - 8,624 81/2 376 2,300 195 5 - 15's Actual Data from CLU 8 (@ 9,777' MD) Comments: See separate hydraulics calculations. Annular velocities in the 16", 12 W', and 8 W' holes were calculated using 5" drillpipe. 5" drillpipe should be used to drill all hole sections to maximize hole cleaning, while minimizing stand pipe pressure. Page 13 of 14 . . Formation Intearitv Test Procedure Surface and Intermediate casing shoes will be tested to Leak-off. Prior to drilling out of casing strings, test BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak-off tests (LOT) are to be conducted as described below: 1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. 2. Pull drill string into the casing shoe and close ram preventer, and line up to the choke manifold with a closed choke. 3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the lADe and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Page 14 of 14 . Marathon Oil Well KBU 42-6 Diverter . I Flow line ~ ~ / 116" Automatic ~I = ~ \ '-- 116" Diverter Line 1 121 1/4" 2M Diverter 1 ~ I Diverter Spool Knife Valve / . Marathon Oil Well KBU 42-6 BOP Stack . I Flow Nipple I -----. I Flow Une I 13 5/8" 5M Annular Preventer . 13 5/8" 5M Double Ram Preventer I Pipe Ram I L ----. I Blind Ram I ~ 3 1/8" 5M Manually Operated Valve ŒillJ 1 Choke 1 / 1135/8" 5M Cross 135/8" 5M x 13 5/8" 5M Drilling Spool Bottom of mud cross must be 24-45" from ground level for Glacier 1 rig placement. 113 5/8" 5M Tubing Head Flange . Marathon Oil Well KBU 42-6 Choke Manifold . ITO Gas Buster ITO Blooey Line I Bleed off Line to Shakers ~ ~ ~ I~Þ q~þ q~ c ~ ~ ~ t 13" 5M Valves 2 9/16" 10M Swaco Hydraulically Operated Choke 3 1/8" 5M Manually Adjustable Choke I From BOP Stack I . . Surface Use Plan for Kenai Beluga Unit, well KBU 42-6 Surface location: Anticipated at 45' FSL, 4,199' FWL, Sec. 6, T4N, R11W, S.M. 1) Existing Roads Existing roads which will be used for access to KBU 42-6 are shown on the attached map. Kenai, 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 KBU 42-6. 3) Location of existing wells Well KBU 42-6 will be drilled on Kenai Gas Field (KGF) pad 41-7. A pad drawing is enclosed that shows existing wells and the proposed location of KBU 42-6. 4) Location of existing and/or proposed facilities The locations of existing production facilities in the KGF pad 41-7 are shown on the enclosed pad drawing. A flowline will be installed from the KBU 42-6 wellhead to an existing heater and separator. 5) Location of Water Supply A water supply well exists on the pad that KBU 42-6 will be drilled from. This is shown on the pad drawing. 6) Construction Materials No construction is planned on the pad. The recent pad expansion has already been completed and is sufficient. 7) Methods of handling waste disposal; a) Mud and Cuttings 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 24-7, a Class II disposal well (AOGCC Disposal Injection Order No.9, Permit #81-176). 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 WD #1, an approved disposal well (AOGCC Permit #7-194). d) Chemicals . . Unused chemicals will be returned to the vendors that 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 trailer house type structures will be required for this purpose. Bottled water will be used for human consumption. Potable water will be obtained from the existing water well on the pad. S & R will collect and transport sanitary wastes to their ADC approved disposal facility. No additional structures will be necessary. 9) Plans for reclamation of the surface KBU 42-6 will be drilled from an existing pad. Reclamation of the pad will occur after the abandonment of KBU 42-6 and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from CIRI Native Corporation prior to any reclamation work beginning. 10) Surface ownership The surface owner of the land in the Kenai Beluga Unit is the CIRI Native Corporation. 11) 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. , ì Date: / ð ! let/',; ¿{ i;/f/ ¡J .' d~; A I Name and Title: :'þJlJ"vL¿Î./i.JI~;,>¡"k Willard J. Tank/Advanced Senior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, TX 77253 (713) 296-3273 / . . CP981 GRID N: 2362229.724 SECTION 6. T4N. R11W. SEWARD MERIDIAN. AK GRID E: 275289.264 Elev. 64.26' \ ® aut. ... T4N we \ ~2+~ 1/'~'!!. , '" ... .., K.B.U. 42-6 'Co R12W R11W T4H R11W ",. 1921 1963 "' '" ~8 AS BUILT -J "'- X-27Q.909.840 X-273,27o.893 Y-2.382.149.810 (J) ::>18 Y-2,J62,l16.S84 ~z 4199' FWl I.J... õoi KBU 43-7X KBU J3-6X KBU 11-8)( .... ,,5 89' 11' 33" E 2361.56' _ ~ioO z ~ 5 89' 11' 33" E SECTION 6 . 1837.87' _v ~c~g~N~" 1/4 7 SECTION ~B\J'27 K~32-7 X-270.908.30 X-2.73.268.62 Y-2,J62,070.01 Y-2.J62.0J8.73 . @) @) . KBU 33-6 K1U 24-BH KIU 32-7H . . KBU 42-6 AS-BUILT KBU 44-6 0 N: 2362055.81 ~/ E: 275107.816 I:J KU 13-5 LA TITUDE: 60'27'34.720"N I:J EI KBU 41-7X KU 41-7 · LONGITUDE: 151'14' 45.216"W B KU 4J-6RD. \ Elev. 66.1' J3J43-6X E1 4199' FWL ¿ [] . KDU NO. 4 45' FSL . c=J KU 43-6A 18" DIAM. PIPE INSIDE - KDU N~. 2 K& 24-5RD CENTER 8' DIAM. CMP ......- ~LJ II iii / . KU 1,-6 KU 43-7 r '\ NOTES KGF 41-7 PAD ,. REFERENCE DA ruM IS MEAN SEA LEVEL = 0.00' FOR ELEVA1l0NS SHOWN. 2. ALL BEARINGS ARE GRID UNLESS NOTED OTHERWISE. 3. BASIS OF COORDINATES IS NGS STA1l0N AUDRY RESET IN A.S.P. ZONE 4 (NAD 27). ~""\\\" 4. KENAI GAS FIELD SURVEYS UTlUZE NGS SUPERCEDED SECTION 7 SURVEY CONTROL AS THE BASIS OF HORIZONTAL COORDINATES ,,~ OF Ai.. ff FOR STA. AUDRY RESET: _- ~ .............~~ I, LAT: 60·30'50.559"N - ~,,:.., *....:1:, LONG: 151·16'37.445"W X = 269,866.75 : c.,.: ".-Y , Y = 2,382,045.42 .... * ;' 49 IIi ". * ~ 5) SEC1l0N UNE OFFSETS DETERMINED BY DIRECT 1lES TO fill................................... , EXISTING BLM MONUMENTS RECOVERED AND SHOWN HEREON. -" , , -" ~ A ,................................... fill ., fk, :.M, SCOTT MelANy':' .... 'I " '. .' - " ~ ". 4928-5 ..' - ~. .- '1, . ,'-~~;I';';'~' ~~ ...-- ,\\\\.,-,-" P.C. Bex 41SB SDLDDTNA, AK 99669 McLANE ~ Consuli;ng C;roup CONSUL 1lNG GROUP SOlD01NA. IU.SKA 98880 ~cLane) Testing (807) 283-4218 0/15/004 AS-8UlLT SI.D ISSUED FOR RE'IIEW AlE OF SUR~ID/14/"" No. DAlE BY APP. RElllSlONS -- lOOK NO.: 043081 ~ TEL 907.2B3.421 B .AX 907.2B3.3265 "'^"CT NO.: 043081 Marathon IRAWING No..: 043081 ~ Oil Company K:ALE ,·.HIO· Alaoka Region IRAWN BY: IotSll . ENGINEER APPROVAL KENAI GAS FIELD PAD 41-7 BY DAlE \N08TH/ Ro.£CT 1s1Rucr. K,B.U. 42-6 SURFACE LOCATION DIAGRAM ROCESS "" =--y :%: ~ "'~""üI IELECT. SCAlE DWN. __ DAlE 03/14/115 F1LE NO. rIPE ORG 1100 DISC SYST DWG NO. SHT NO REV ~ INS1RIJI. CHt<D. ¿ WOOD DAlE GRID lARCH. 1"·20( APP." _ DAlE KGF 41-7 S D 00 0 00 0D01 1 0 APP. II. ....... nAT~ Souroe Map: 1951 KerHiI¡~ Alluika B~4, 1 :63 360 Marathon on Kenai Gas Area 1M4tIN F= r-----' I I ~~ I OOT I 14' X 10' I I I I I I I I I I DtJ4P I -, I 1 ,. I I ...~ I L__·___.J I I L________ I I I I I I I I I I I .--... J' , I,~\ I~ I, ,,/ ...-- ~-----1 ~-----{ r , L__.J Ii J I 1 1 r---, 11 I I r I II I I I I /I I I r I I r I ¡III t I II I I I II I I 'I II , I ~ : I as· H I I J!!i I I a "I r.b====d__,L-----..J I t -0 "'0 I I .... ICtIDMY 3' X 12' 75HP 615 U· - ..... 75'" 615 U' rïJrl t!!!!!!!J GLACIER DRILLING RIG #1---.., MUD PITS AND PUMP ROOM LAYOUT 75HP 6 Ie :5 U" .-r 5V 9L 1\-600 PT 15 If' 6X' 11" f' . I~' I ~ m._~ m._~ ----, 5V 9l A-6tIO PT œ . .... P&.L. PP" w... . sr-r 8 . J .1:"1 ¢:: 0 -400 0 N /I E 0 -0 Q) ~ C/) 400 800 1200 1600 2000 2400 2800 - ... CD CD :t:. 3200 J: Q. CD 3600 C Cã U 4000 :e ~ 4400 CD ~ r.. l- I 4800 V 5200 5600 6000 6400 6800 7200 7600 8000 8400 MARATHON Oil Company -,------_._----~ Location: Kenai Peninsula, Alaska(lmported) Field: Kenai Gas Field Installation: Pad 41·7 Slot: Slot #KBU42~ Wel/bore; KBU42~ Ver 1 Well: KBU42~ KOP 6.00 12.00 DLS: 3.00 deg/100ft 24.00 30.00 \ 0v 36.00 13 3/8" Casing I> EOC End of Hold 34.22 30.22 DLS: 2.00 deg/100ft 22.22 18.22 14.22 10.22 6.22 9 5/8" Casing I I 2.22 Middle Beluga - End of Drop _¿J L WELL PROFILE DATA Point MD ~, Ad TVD ..... .... dog"- V.Sect Tie on 0.00 0.00 4.40 0.00 0.00 0.00 0.00 0.00 KOP 250.00 0.00 4.40 250.00 000 0.00 0.00 I 0.00 Eno'ofBuJld 1524.06 36" 4.40 1431.65 408.23 31.44 3.00 409A3 End of Hold 4289.86 36." 4.40 3604.53 2114.41 162.83 0.00 2120.67 T..... 6200.98 0.00 4.40 5377.00 2726.75 209.98 2.00 127~'82 T.O. & End of Hold 8623.98 0.00 4.40 1800.00 2726.75 20996 0.00 2734,82 / 31/2" Liner j l rD -400 -0 400 800 1200 1600 2000 2400 2800 3200 Seale 1 em = 200 ft Vertical Section (feet) -> Azimuth 4.40 with reference 0.00 N, 0.00 E from Slot #KBU42-6 Scale 1 em = 100 ft -200 -0 East (feet) .> 200 400 L-1-.-~~~ 3000 .1. BAKER HUGHIS INTEQ 2800 2600 End of Hold 2400 2200 2000 1800 1600 ^ I Z 1400 g. :::T - .... 1200 = - - 1000 800 600 400 200 (f) n Q) ëõ 0 n 3 /I -200 .... 0 0 ;:þ EOC ì r 13 3/8" Casing KOP Created by : Planner Date plotted: 16-0ct-2004 Plot reference is KBU42·6 Ver 1. Ref wellpath is KBU42-6 Ver 1. Coordinates are in feet reference Slot #KBU42-6. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 87.00 ft. Plot North is aligned to TRUE North. . . MARATHON Oil Company,Slot #KBU42-6 Pad 41-7, Kenai Gas Field,Kenai Peninsula, Alaska{lmported) PROPOSAL LISTING Page 1 Wellbore; KBU42-6 Ver 1 Wellpath: KBU42-6 Ver 1 Date Printed: 16-0ct-2004 .1. ..,. INTEQ Wellbore Name I Created ~ Last Revised KBU42-6 Ver 1 I 6-0ct-2004 16-0ct-2004 Well Name I Government ID I Last .Revised KBU42-6 I I 6-0ct-2004 Name Slot #KBU42-6 Slot Latitude N60 27 34.7199 North 72.62N Installation Name I Eastina I Northin~ I Coord Svstem Name 1 North Alianment Pad 41-7 I 270916.0101 I 2362063.9749 I ÁK-4 on NORTH AMERICAN DATUM 1927 datuml True '~'.,---~--'-'- Name Kenai Gas Field Coord S stem Name AK-4 on NORTH AMERICAN DATUM 1927 datum -~-_.,~-- --~~- All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 4.40 degrees Bottom hole distance is 2734.82 Feet on azimuth 4.40 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . . MARATHON Oil Company,Slot #KBU42-6 Pad 41-7, Kenai Gas Field,Kenai Peninsula, Alaska{lmported) PROPOSAL LISTING Page 2 Wellbore: KBU42-6 Ver 1 Wellpath: KBU42-6 Ver 1 Date Printed: 16-0ct-2004 .a. 'IILu INTEQ Wellpath (Grid) Re )ort MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing f deo/1 OOftl Sectionfftl 0.00 0.00 4.40 0.00 1__ O.º~ _ O.OOE. 0.00 0.00 275107.82 -- I--- 2362055.82 100.00 0.00 4.40 100.00 O.OON O.OOE 0.00 0.00 275107.82 2362055.82 200.00 0.00 4.40 .200.00 O.OON O.OOE 0.00 0.00 275107.82 2362055.82 250.00 0.00. 4.40 250.00 O.OON O.OOE 0.00 0.00 275107.82 2362055.82 350.00 3.00 4.40 349.95 2.61N 0.20E 3.00 2.62 275108.07 2362058.42 450.00 6.00 4.40 449.63 10.43N _~ 0.80E 3.00 10.46 275108.82 2362066.23 550.00 9.00 4.40 548.77 23.44N 1.80E 3.00 23.51 275110.06 2362079.22 650.00 12.00 4.40 647.08 41.61 N 3.20E 3.00 41.74 275111.81 2362097.36 750.00 15.00 4.40 744.31 64.89N 5.00E 3.00 65.08 275114.04 2362120.59 850.00 18.00 4.40 840.18 93.20N 7.18E 3.00 93.48 275116.75 2362148.86 950.00 21.00 4.40 934.43 126.48N 9.74E 3.00 126.85 275119.95 2362182.08 1050.00 24.00 4.40 1026.81 164.63N 12.68E 3.00 165.12 275123.61 2362220.17 1150.00 27.00 4.40 1117.06 207.55N 15.98E 3.00 208.16 275127.72 2362263.02 1250.00 30.00 4.40 1204.93 255.12N 19.65E 3.00 255.87 275132.28 . 2362310.50 1350.00 33.00 4.40 1290.18 307.21N 23.66E 3.00 308.12 275137.28 2362362.51 1450.00 36.00 4.40 1372.59 363.67N 28.01 E 3.00 364.75 275142.69 2362418.88 1524.06 38.22 4.40 143ilL . 408.23N 31.44E 3.00 409.43__ f---'" 275146.97 2362463.36 -- 1600.00 38.22 4.40 __ f__H91.30 455.0m_ _ 35.04E..__ --º'.QQ....... r--4.Q6.42 27{)151.46 2362510.12 -- 1700.00 38.22 4.40__ ;--1{)69.87 516.76N 39.7gE. 0.00 518.29 275157.38 2362571.71 1800.00 38.22 4.40 1648.43 578.45N 44.55E 0.00 580.16 275163.29 2362633.29 1900.00 38.22 4.40 1726.99 640.13N 49.30E 0.00 642.~ 275169.21 2362694.88 2000.00 38.22 4.40 1805.55 701.82N 54.05E 0.00 703.90 275175.13 2362756.46 2100.00 38.22 4.40 1884.11 763.51N 58.80E 0.00 765.77 275181.04 2362818.04 2200.00 38.22 4.40 1962.68 825.20N 63.55E 0.00 827.64 275186.96 2362879.63 2300.00 38.22 4.40 2041.24 886.89N 68.30E 0.00 889.51 275192.87 2362941.21 2400.00 38.22 4.40 2119.80 948.58N 73.05E __ -~ 951.38 275198.79 2363002.80 2500.00 38.22 4.40 2198.36 1010.26N 77.80E 0.00 1013.26 275204.71 2363064.38 2600.00 38.22 4.40 2276.92 1071.95N 82.55E 0.00 1075.13 275210.62 2363125.97 2700.00 38.22 4.40 2355.49 1133.64N 87.30E 0.00 1137.00 275216.54 2363187.55 2800.00 38.22 4.40 2434.05 1195.33N 92.05E._ _0.00 _ 1198.87 .. 275222.46 2363249.14 2900.00 38.22 4.40 2512.61 1257.02N 96.80E ...... 0.00 1260.74 275228.37 2363310.72 3000.00 38.22 4.40 2591.17 1318.70N 101.55E 0.00 1322.61 275234.29 2363372.31 3100.00 38.22 4.40 2669.74 1380.39N 106.30E .~ 1384.48 275240.21 2363433.89 3200.00 38.22 4.40 2748.30 1442.08N C--..i11~ _0.00 1446.35 275246.12 2363495.48 -- 3300.00 38.22 4.40 2826.86 1503.77N 115.80E 0.00 1508.22 275252.04 2363557.06 3400.00 38.22 4.40 2905.42 1565.46N 120.55E 0.00 1570.09 275257.95 2363618.64 3500.00 38.22 4.40 2983.98 1627.15N 125.30E 0.00 1631.96 275263.87 2363680.23 3600.00 38.22 4.40 3062.55 1688.84N 130.05E 0.00 1693.84 275269.79 2363741.81 3700.00 38.22 4.40 3141.11 1750.52N 134.80E 0.00 1755.71 275275.70 2363803.40 3800.00 38.22 4.40 3219.67 1812.21N 139.55E 0.00 1817.58 275281.62 2363864.98 3900.00 38.22 4.40 3298.23 18n~ __H_.u~_ __0.00 1879.45 275287.54 2363926.57 4000.00 38.22 4.40 3376.79 1935.59N 149.06E 0.00 1941.32 275293.45 2363988.15 4100.00 38.22 4.40 3455.36 1997.28N 153.81E__ _....M.Q 2003.19 275299.37 2364049.74 4200.00 38.22 4.40 3533.92 ~6.96N 158.56E 0.00 2065.06 275305.29 - 2364111.32 4289.88 38.22 4.40 3604.53 2114.41N ._162.82E_ _.0.00 2120.67 275310.60 2364166.67 4389.88 36.22 4.40 3684.16 2174.72N 167.47E _.2.00._ _2181.16 275316.39 2364226.88 4489.88 34.22 4.40 3765.84 2232.22N - 171.90E 2.00 2238.83 275321.90 2364284.29 -- 4589.88 32.22 4.40 3849.49 2286.84N__ _..176.10E_ . 2.00 2293.62 275327.14 2364338.82 4689.88 30.22 4.40 3935.01 2338.52N . _180.08E 2.00 . ........2.~45.4L -. 275332.10 2364390.41 4789.88 28.22 4.40 4022.28 2387.20N 183.83E 2.00 2394.26 275336.77 2364439.00 4889.88 26.22 4.40 4111.20 2432.80N 187.34E 2.00 2440.01 275341.14 2364484.53 All data is in Feet unless otherwise stated Coordinates are from Slot MO's are from Rig and TVO's are from Rig ( Datum #1 87.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 4.40 degrees Bottom hole distance is 2734.82 Feet on azimuth 4.40 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . . MARATHON Oil Company,Slot #KBU42-6 Pad 41-7, Kenai Gas Field,Kenai Peninsula, Alaska(lmported) PROPOSAL LISTING Page 3 Wellbore: KBU42-6 Ver 1 Wellpath: KBU42-6 Ver 1 Date Printed: 16-0ct-2004 .i. ØWI.s INTEQ Welloath (Grid} Re )ort MD[ft) Inc{deg) Azi[deg) TVD[ft) North[ft) East[ft) Dogleg Vertical Easting Northing fdea/100ft Sectionfftl 4989.88 24.22 4.40 4201.66 2475.29N 190.62E 2.00 2482.62 275345.21 2364526.95 5089.88 22.22 4.40 4293.55 2514.60N 193.64E 2.00 2522.04 275348.98 2364566.19 5189.88 20.22 4.40 4386.77 2550.69N 196.42E 2.00 2558.24 275352.45 2364602.22 5289.88 18.22 4.40 4481.19 2583.51N 198.95E 2.00 2591.16 275355.59 2364634.99 5389.88 16.22 4.40 4576.70 2613.03N 201.22E 2.00 ] 2620.77 275358.42 2364664.46 5489.88 14.22 4.40 4673.18 2639.21 N 203.24E 2.00 2647.02 275360.94 2364690.59 5589.88 12.22 4.40 4770.53 2662.01N 205.00E 2.00 2669.89 275363.12 2364713.35 5689.88 10.22 4.40 4868.61 2681.41N 206.49E 2.00 2689.35 275364.98 2364732.72 5789.88 8.22 4.40 4967.31 2697.39N 207.72E 2.00 2705.38 275366.52 2364748.68 5889.88 6.22 4.40 5066.52 2709.93N 208.68E 2.00 2717.95 275367.72 2364761.19 5989.88 4.22 4.40 5166.10 2719.00N 209.38E 2.00 2727.05 275368.59 2364770.25 6089.88 2.22 4.40 5265.93 2724.60N 209.82E 2.00 2732.67 275369.13 2364775.84 6189.88 0.22 4.40 5365.90 2726.73N 209.981;~ 2.00 2734.80 275369.33 2364777.96 6200.98 0.00 4.40 5377.00 2726.75N 209.98E 2.00 2734.82 275369.33 2364777.98 6300.00 0.00 4.40 54 76.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 6400.00 0.00 4.40 5576.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 6500.00 0.00 4.40 5676.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 6600.00 0.00 4.40 5776.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 6700.00 0.00 4.40 5876.02 2726.75N 209.98E 0.00 2734.82__ ~_ 275369.33 2364777.98 6800.00 0.00 4.40 5976.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 6900.00 0.00 4.40 6076.02 2726.75N 209.98E _ 0.00 2734.82 275369.33 2364777.98 7000.00 0.00 4.40 6176.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 7100.00 0.00 4.40 6276.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 7200.00 0.00 4.40 6376.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 7300.00 0.00 4.40 6476.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 7400.00 0.00 4.40 6576.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 7500.00 0.00 4.40 6676.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 7600.00 0.00 4.40 6776.02 __ 2726.75N 209.98.~ O.OQ~ __2734.82 275369.33 2364777.98 7700.00 0.00 4.40 6876.02 2726.75N__ ~-209.98E __ 0.00 2734.82 275369.33 2364777.98 7800.00 0.00 4.40 6976.02 2726.7(11'L- 209.98E _0.00 2734.82 275369.33 2364777.98 7900.00 0.00 4.40 7076.02 2726.75N 209.98E __ 0.00 2734.82 275369.33 2364777.98 8000.00 0.00 4.40 7176.02 2726.75N ~_ 209.98E 0.00 I 2734.82 275369.33 2364777.98 8100.00 0.00 4.40 7276.02 2726.75~ __ 209.98E 0.00 2734.82 275369.33 2364777.98 8200.00 0.00 4.40 7376.02 2726.75N 209.98E --ºJ)O __ 2734.82 275369.33 2364777.98 8300.00 0.00 4.40 7476.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 8400.00 0.00 4.40 7576.02 2726.75N 209.98E __ 0.00 2734.82 275369.33 -~ -- 2364777.98 8500.00 0.00 4.40 7676.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 8600.00 0.00 4.40 7776.02 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 8623.98 0.00 4.40 7800.00 2726.75N 209.98E 0.00 2734.82 275369.33 2364777.98 All data is in Feet unless othelWise stated Coordinates are from Slot MOos are from Rig and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 4.40 degrees Bottom hole distance is 2734.82 Feet on azimuth 4.40 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . . MARATHON Oil Company,Slot #KBU42-6 Pad 41-7, Kenai Gas Field,Kenai Peninsula, Alaska(lmported) PROPOSAL LISTING Page 4 Well bore: KBU42-6 Ver 1 Well path: KBU42-6 Ver 1 Date Printed: 16-0ct-2004 .i. ~ INTEQ Comments MDfftl TVDfftl Northfftl Easlfftl Comment 250.00 250.00 O.OON O.OOE KOP 1524.06 1431.65 408.23N 31.44E -- !------ EOC -- 4289.88 3604.53 2114.41N 162.82E End of Hold 6200.98 5377.00 2726.75N 209.98E Middle BeJuQa - End of Drop .- 8623.98 7800.00 2726.75N 209.98E - TD ---. Hole Sections Diameter Start Start Start Start End End End Start Wellbore finl MDfftl TVDfftl Northrftl Eastfftl Morftl TVDfftl Northrftl Eastrftl 16.000 0.00 0.00 O.OON O.OOE 1525.00 1432.38 408.80N 31.48E KBU42-6 Ver 1 121/4 1525.00 1432.38__ ---.4Qß,80N 31.48E 6188.98 5365.00 2726.72N 209.98E KBU42-6 Ver 1 81/2 6188.98 5365.00 2726.72N 209.98E 8623.98 7800.00 2726.75N 209.98E KBU42-6 Ver 1 Casinas Name Top Top Top Top Shoe Shoe Shoe Shoe Wellbore MDfftl TVDfftl Northfftl Eastfftl MDfftl TVDfftl Nr·rthrftl Eastrftl 13 3/8" Casino 0.00 0.00 O.OON O.OOE 1525.00 1432.38 408.80N 31.48E KBU42-6 Ver 1 9 5/8" Casino 0.00 0.00 O.OON O.OOE 6188.98 5365.00 2726.72N 209.98E KBU42-6 Ver 1 3 1/2" Liner 0.00 0.00 O.OON O.OOE 8623.98 7800.00 2726.75N 209.98E KBU42-6 Ver 1 Name KBU42-6 M. Beluga Tgt- 10/5/04 North ft 2727.26N Latitude N60 28 1.57 Norhtin 2364780.00 All data is in Feet unless otherwise stated Coordinates are from Slot MO's are from Rig and TVD's are from Rig ( Oatum #1 87.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 4.40 degrees Bottom hole distance is 2734.82 Feet on azimuth 4.40 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated THON Oil Com location: Kenai Peninsula, Alaska(lmported) Field: Kenai Gas Field Installation: Pad 41-7 Scale 1 em :i>-!1)@1!fi (feet): East (feet) -> Seale 1 em ::: 50 ftEast t) -> -300 -200 -100 0 100 200 300 -100 -0 100 300 400 500 1900 1900 2800 2800 1800 1800 2700 4900 2700 4300 1700 1700 4700 4600 2600 4500 2600 1600 1600 MOO 4300 2500 2500 4200 1500 -I 1500 ~ 2400 2400 1400 1400 3900 2300 2300 2600 1300 1300 3600 2200 2200 1200 1200 2400 2100 2100 1100 2300 1100 3500 2000 4500 2000 ^ 1000 1000 ^ ^ ^ . . . MOO . - Z 1900 ~ .... 2700 1900 (þ 2100 0 4300 g. 900 3300 900 ;::¡, ;::¡, ::r 4200 ::r .s:: 2000 - - ~ ëir 1800 3200 1800 ëir '''' 0 800 800 !. m Z .... - - 1700 4000 1700 700 1800 700 3900 1600 3600 1600 600 600 3700 1500 2800 1500 500 500 3500 1400 2700 3500 1400 400 400 3400 2600 1300 1300 3300 300 300 2500 1200 3300 1200 2400 200 200 3100 1100 woo 1100 ¢;: (fJ¢;: (fJ 0 100 100 C') 0 £ l() ~l() 2900 m II CD 2200 -' ~ 1000 1000 -' E C') 0 C') 0 0 0 :3 ..... 2800 :3 2100 Q) II Q) II -¡¡¡ (J1- 900 900 (J1 0 o~ 0 (fJ -100 -100 ;$ (fJ ;$ -300 -200 -100 -0 100 200 300 -100 0 100 200 300 400 500 Scale 1 em ::: 50 ft<- West (feet) : East {feet) -> Seale 1 em ::: 50 ftEast (feet) -> Alaska(lmported) RATHON Oil Com Kenai Gas Field Installation: Pad 41-7 Wellbore: KBU42-6Ver 1 ._~~~..~._~..~~----- Created by: Planner i Date plotted: 16-0ct-2004 'þlófieference is KBU42-6VeiT--------- -I I. ~::~~:~~ :re~~~::;~e~e~~~~e Slot #KBU42,s. True Vertical Deptnsare ,eference Rig Datum. I I Measured Depths are referenœ Rig Datuffi. I Rig Datum: Datum #1 Rig Datum to mean Sea level: 87.00~. ,Plotr-:0¡jhisaiÌ(ned.to.l'f<UENorth. ---.J TRUE NORTH 350 o 10 340 20 250 330 320 40 310 300 290 280 270 260 230 210 160 1100 Normal Plane Travelling Cylinder - Feet AI! . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 1 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) IIi. .... INTEQ Ellipse separations are reported ONLY if BOTH wells have uncertainty data Only Depth and MaQnetic Reference Field error terms are correlated across tie points Proximities beyond ft with expansion rate of ft/1 OOOft are not reported Cutoff is calculated on CENTRE to CENTRE distance Summary data uses Closest Approach clearance calculation for all minima Hole size/CasinQs are NOT included Hole size/CasinQs are NOT subtracted from Centre-Centre distance Ellipses scaled to 2.00standard deviations. ClosinQ Factor Confidence limit of 99.80% Errors on Ref start at Slot Permanent Datum (0.00) Report uses Revised: (D-C)/E Factor Calculation We II bore Name I Created I Last Revised KBU42-6 Ver 1 I _____-º-Qct-2004 I - 16-0ct-2004 Well Name I Goyernment 10 I Last Revised KBU42-6 -~ -~--- 6-0ct-2004 Name Pad 41-7 Slot Latitude N60 27 34.7199 ~- ---.. North 72.62N East 4191.36E Name Slot #KBU42-6 Coord S stem Name _ AK-4 on NORTH AMERICAN DATUM 1927 datum Name Kenai Gas Field EastinQ 270993.1910 Coord S stem Name AK-4 on NORTH AMERICAN DATUM 1927 datum Clearance Summary Offset Offset Offset Offset Minimum MD[ft] Diverging Ellipse Ellipse Clearance Clearance Well Name Wellbore Slot Structure Distance From[ft] Separation MD[ft] Factor MD[ft] fftl rftl KBU11-8X KBU11-8X slot Pad 41-7 46.58 369.49 369.49 45.06 393.70 22.44 606.96 #KBU11-8X KBU33-6X KBU33-6X Slot Pad 41-7 56.84 262.47 262.47 55.68 311.68 26.67 688.98 #KBU33-6X KTU24-6H KTU24-6H slot #24-6 Pad 41-7 90.55 262.47 262.47 89.66 262.47 57.47 803.81 KTU24-6H KTU24-6H slot #24-6 Pad 41-7 90.55 262.47 262.47 89.66 262.47 57.47 803.81 RD KTU24-6H KTU24-6H slot #24-6 Pad 41-7 90.55 262.47 262.47 89.66 262.47 57.47 803.81 ~- (Pilon - -- ~_..~-- ---.--- -. ..-- -f--- KTU32-7 - KTU32-7 slot #32-7 Pad 41-7 96.34 278.87 278.87 95.16 .-- 278.87 50.07 688.98 KBU43-7X KBU43-7X Slot Pad 41-7 103.55 0.00 0.00 103.39 49.21 53.86 885.83 #KBU43-7X KBU42-7 KBU42-7 slot Pad 41-7 116.16 232.50 232.50 115.14 250.00 64.24 803.81 KBU~I - #KBU42-7 -"" ."- ---.- KBU 44-6 slot Pad 41-7 131.31 0.00 0.00 130.61 196.85 50.48 1000.66 #KBU44-6 All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 2 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) .¡¡. ...,. INTEQ Clearance SummarY Offset Offset Offset Offset Minimum MD[ft] Diverging Ellipse Ellipse Clearance Clearance Well Name Wellbore Slot Structure Distance From[ft] Separation MD[ft] Factor MD[ft] ~ - ----- -~ KBU33-6 KBU33-6 slot Pad 41-7 154.17 0.00 0.00 #KBU33-6 -- KTU32-7H KTU32-7H slot Pad 41-7 187.00 0.00 0.00 186.84 49.21 68.91 951.44 #KTU32-7H KU13-5 KU13-5 slot Pad 41-7 219.22 0.00 0.00 218.92 49.21 46.79 1017.06 #KTU13-5 KU43-6 KU43-6Rd slot #KU 43-6 Pad 41-7 234.65 1219.40 1219.40 228.76 1230.31 34.82 1640.42 KU43-6 KU43-6 slot #KU 43-6 Pad 41-7 234.65 1219.40 1219.40 228.76 1230.31 34.82 1640.42 KBU41-7 KBU41-7 slot #KBU Pad 41-7 272.22 262.47 262.47 269.98 262.47 69.09 623.36 41-7 KTU43-6X KTU43-6X Rd slot Pad 41-7 288.23 250.00 250.00 286.41 262.47 93.59 475.72 #KTU43-6X KTU43-6X KTU43-6X slot Pad 41-7 288.23 250.00 250.00 286.41 262.47 93.59 475.72 #KTU43-6X Surve Name Planned Error Model Standard All data is in Feet unless otherwise stated Coordinates are from Slot and TVO's are from Rig ( Oatum #1 87.0ft above mean sea level) Reference MO's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1 KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 3 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported} .1. ~ INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset . Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] .------ ---- [deal [ftl 0.00 0.00 O.OON O.OOE KTU32-7 0.13 0.13 89.22S -' 40.40E 155.6 97.95 97.94 100.00 100.00 O.OON O.OOE KTU32-7 100.39 100.39 88.905 40.51 E 155.5 97.69 97.21 200.00 200.00 O.OON O.OOE KTU32-7 200.92 200.91 87.97S 40.78E 155.1 96.96 96.10 250.00 250.00 O.OON O.OOE KTU32-7 250.91 250.90 87.395 40.91 E 154.9 96.50 95.41 278.87 278.87 0.22N 0.02E KTU32-7 280.08 280.06 86.99S 40.94E 150.5 96.34 95.16 350.00 349.95 2.61N 0.20E KTU32-7 351.39 351.37 85.98S 40.97E 150.9 97.53 96.13 450.00 449.63 10.43N 0.80E KTU32-7 451.23 451.19 84.665 40.21 E 153.0 102.95 101.15 550.00 548.77 23.44N 1.80E KTU32-7 549.68 549.62 84.195 38.08E 156.7 113.59 111.42 650.00 647.08 41.61 N 3.20E KTU32-7 646.43 646.31 84.91S 34.74E 161.2 130.40 127.81 688.98 685.12 50.08N 3.86E KTU32-7 683.63 683.46 85.59S 33.07E 163.0 138.79 136.01 750.00 744.31 64.89N 5.00E KTU32-7 741.15 740.88 87.135 29.96E 165.7 154.09 151.05 850.00 840.18 93.20N 7.18E KTU32-7 835.80 835.31 90.235 24.23E 169.7 184.28 180.77 950.00 934.43 126.48N 9.74E KTU32-7 930.66 930.00 92.815 19.36E 172.5 219.54 215.52 1050.00 1026.81 164.63N 12.68E KTU32-7 1023.65 1022.89 94.675 15.46E 174.5 259.35 254.80 1150.00 1117.06 207.55N 15.98E KTU32-7 1116.49 1115.67 95.655 12.45E 175.8 303.22 298.15 Well KTU32-7 Wellbore KTU32-7 Surve Name MWO <0-8864> Error Model MaQ Corrected All data is in Feet unless otherwise stated Coordinates are from 510t and TVO's are from Rig ( Datum #1 87.0f! above mean sea level) Reference MO's are from Rig, Offset MO's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 4 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) .1. ..,. INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] rdeal rftl 0.00 0.00 O.OON .. O.OOE KBU41-7 I 14.22 0.22 251.268 105.94E 157.1 272.68 272.30 100.00 100.00 O.OON O.OOE KBU41-7 114.22._ _....100.2~_ 251.24S 105.78E 157.2 272.60 271.30 200.00 200.00 O.OON O.OOE KBU41-7 214.65 200.65 251.198 105.32E 157.3 272.37 270.47 250.00 250.00 O.OON O.OOE KBU4H .. 265.09 251.08 251.158 105.03E 157.3 272.23 270.06 262.47 262.47 0.04N O.OOE KBU41-7 277.55 263.55 251.14S 104.93E 152.9 272.22 269.98 350.00 349.95 2.61N 0.20E KBU41-7 365.04 351.03 251.06S 104.22E 153.3 274.17 271.57 450.00 449.63 10.43N 0.80E KBU41-7 465.15 451.14 250.948 103.11E 154.1 280.68 277.63 550.00 548.77 23.44N 1.80E KBU41-7 564.45 550.43 250.798 101.92E 155.3 291.94 288.16 623.36 620.99 36.27N 2.79E KBU41-7 636.67 622.65 250.678 101.04E 156.3 303.30 298.91 Well KBU41-7 Wellbore KBU41-7 Survey Name GMS <0-7290> rams Survey Tool Level Rotor G ro Error Model Standard All data is in Feet unless otherwise stated Coordinates are from Slot and TVO's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MO's are from Rig, Offset MO's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 5 Date Printed: 16-Oct-2004 Kenai Gas Field, Kenai Peninsula, Alaska{lmported) III. .... INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] rdeal rftl 0.00 0.00 O.OON O.OOE KBU11-8X 0.02 0.02 1.278_ 48.09E 91.5 48.10 48.10 100.00 100.00 O.OON O.OOE KBU11-8X 100.06 100.06 1.25S 48.02E 91.5 48.03 47.58 200.00 200.00 O.OON O.OOE KBU11-8X 200.49 200.49 1.208 47.51E 91.5 47.53 46.69 250.00 250.00 O.OON O.OOE KBU11-8X 250.31 250.31 1.35S 47.08E 91.7 47.10 46.05 350.00 349.95 2.61N 0.20E KBU11-8X 350.10 350.09 1.76S 46.59E 91.0 46.60 45.21 369.49 369.41 3.74N 0.29E KBU11-8X 369.54 369.54 1.88S 46.52E 92.5 46.58 45.12 393.70 393.57 5.39N 0.41E KBU11-8X 393.70 393.69 2.08S 46.43E 94.8 46.61 45.06 450.00 449.63 10.43N 0.80E KBU11-8X 449.86 449.85 2.55S 46.15E 101.5 47.17 45.42 550.00 548.77 23.44N 1.80E KBU11-8X 549.26 549.24 3.08S 45.05E 116.9 50.74 48.54 606.96 604.88 33.16N 2.55E KBU11-8X 605.22 605.19 3.528 44.18E 126.6 55.49 53.02 650.00 647.08 41.61N 3.20E KBU11-8X 647.40 647.36 3.988 43.46E 133.6 60.82 58.17 750.00 744.31 64.89N 5.00E KBU11-8X 743.48 743,43 4.91S 42.27E 146.5 79.13 75.94 850.00 840.18 93.20N 7.18E KBU11-8X 837.71 837.63 6.238 43.53E 154.2 105.90 102.22 950.00 934.43 126.48N 9.74E KBU11-8X 929J)0 928.75 7.588 48.81E 157.7 139.75 135.57 1050.00 1026.81 164.63N 12.68E KBUt1-8X 1019.09 1 Q18.35 9.24S 58.04E 158.9 179.89 175.16 1150.00 1117.06 207.55N 15.98E KBU11-8X 1107.37 1105.83 10.60S 69.83E 159.2 224.98 219.65 1250.00 1204.93 255.12N 19.65E KBU11~8X 1194.91 1192.20 11.47S 84.00E 158.9 274.54 268.55 Well KBU11-8X Surve Name MWD <0-7659> All data is in Feet unless otherwise stated Coordinates are from 810t and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 6 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) ... -- INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation HighSide Distance [ft] - rdAnl rftl 0.00 0.00 O.OON O.OOE KU43-6 0.58 0.58 274.018 38.41 E 172.0 276.69 276.67 100.00 100.00 O.OON O.OOE KU43-6 103.39 103.39 273.558 38.38E 172.0 276.25 275.85 200.00 200.00 O.OON O.OOE KU43-6 210.45 210.41 I 271.078 39.04E 171.8 274.07 273.38 250.00 250.00 O.OON O.OOE KU43-6 267.27 .- 267.13 267.998 40.02E 171.5 271.50 270.64 350.00 349.95 2.61N 0.20E KU43-6 377 .22 376.59 258.02S 43.05E 166.3 265.47 264.30 450.00 449.63 10.43N 0.80E KU43-6 481.38 479.99 246.05S 46.51 E 165.6 262.28 260.75 550.00 548.77 23.44N 1.80E KU43-6 591.10 588.64 230.96S 48.15E 165.4 261.64 259.68 650.00 647.08 41.61 N 3.20E KU43-6 702.77 698.64 211.81S 46.50E 166.2 262.21 259.76 750.00 744.31 64.89N 5.00E KU43-6 836.28 826.86 175.74S 52.07E 165.3 258.71 255.69 850.00 840.18 93.20N 7.18E KU43-6 953.14 935.66 133.498 56.25E 164.6 25Q.82 247.23 950.00 934.43 126.48N 9.74E KU43-6 1059.03 1032.95 92.09S 50.75E 166.3 243.22 239.05 1050.00 1026.81 164.63N 12.68E KU43-6 1152.93 1119.05 55.:¡!1S 44.25E 168.4 240.48 235.73 1150.00 1117.06 207.55N 15.98E KU43-6 1284.91 1235.78 2.92N 25.38E 173.9 236.76 231.36 1219.40 1178.30 240.09N 18.49E KU43-6 1351.31 .. 1292.53 35.19N 13.27E 177.4 234.65 228.82 1230.31 1187.83 245.39N 18.90E KU43-6 1361.98 1301.69 40.34N 11.43E 178.0 234.66 228.76 1250.00 1204.93 255.12N 19.65E KU43-6 1381.34 1318.32 49.70N 8.15E .. 178.9 234.92 228.90.._ 1350.00 1290.18 307.21N 23.66E KU43-6 1459.29 1387.16 . . !¡4,84N 1.25W .. -178.2 243.87 237.24 1450.00 1372.59 363.67N 28.01E KU43-6 1557.86 1477.21 124.39N 7.81W -176.1 263.60 256.28 f-1524.06 1431.65 408.23N 31.44E KU43-6 1636.30 1548.20 157.22N 13.63W -174.6 280.39 272.52 1600.00 1491.30 455.07N 35.04E KU43-6 1715.15 1618.69 191.94N 20.25W -173.1 297.52 289.07 1640.42 1523.06 480.00N 36.96E KU43-6 1759.45 1657.89 212.20N 24.23W -172.2 306.01 297.22 Well KU43-6 Wellbore KU43-6Rd 8urve Name MWD <4250-5740> Error Model Basic MWD - ISCW8A - 28 JAN 03 OJH All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 7 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported} ... --=- INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] - fdeal fftl 0.00 0.00 O.OON O.OOE KU43-6 0.58 0.58 274.015 38.41 E 172.0 276.69 276.67 100.00 - 100.00 O.OON O.OOE KU43-6 103.39 103.39 273.555 38.38E 172.0 276.25 275.85 200.00 200.00 O.OON O.OOE KU43-6 210.45 210.41 271.075 39.04E 171.8 274.07 273.38 250.00 250.00 O.OON O.OOE KU43-6 267.27 267.13 267.99S 40.02E 171.5 271.50 270.64 350.00 349.95 2.61N 0.20E KU43-6 377.22 376.59 258.02S 43.05E 166.3 265.47 264.30 450.00 449.63 10.43N 0.80E KU43-6 481.38 479.99 246.055 46.51 E 165.6 262.28 260.75 550.00 548.77 23.44N 1.80E KU43-6 591.10 588.64 230.965 48.15E 165.4 261.64 259.68 650.00 647.08 41.61N 3.20E KU43-6 702.77 698.64 211.81S 46.50E 166.2 262.21 259.76 750.00 744.31 64.89N 5.00E KU43-6 836.28 826.86 175.745 52.07E 165.3 258.71 255.69 850.00 840.18 93.20N 7.18E KU43-6 953.14 935.66 133.495 56.25E 164.6 250.82 247.23 950.00 934.43 126.48N 9.74E KU43-6 1059.03 1032.95 92.09S 50.75E 166.3 243.22 239.05 1050.00 1026.81 164.63N 12.68E KU43-6 1152.93 1119.05 _55.~1S 44.25E 168.4 240.48 235.73 1150.00 1117.06 207.55N 15.98E KU43-6 1284.91 1235.78 2.92N 25.38E 173.9 236.76 231.36 -- 1219.40 1178.30 240.09N 18.49E KU43-6 1351.31 1292.53 35.J9N 13.27E 177.4 -- 234.65 228.82 1230.31 1187.83 245.39N 18.90E KU43-6 1361.98 1301.69 40.34N ._u 11.43E 178.0 234.66 228.76 1250.00 1204.93 255.12N 19.65E KU43-6 __ -1~ª-1~_<L_ . 1318.32 49.70N 8.15E 178.9 234.92 228.90 1350.00 1290.18 307.21N 23.66E__ _.._ KU43-!L ~j4~.29__ _ 1387.1Q 84.84N 1.25W -178.2 243.87 237.24 1450.00 1372.59 363.67N 28.01E KU43-6 1557.86 1477.21 124.39N 7.81W -176.1 263.60 256.28 1524.06__ . 1431.65 408.23N 31.44E KU43-6 1636.30 1548.20 157.22N 13.63W -174.6 280.39 272.52 1600.00 1491.30 455.07N 35.04E KU43-6 1715.15 1618.69 191.94N 20.25W -173.1 297.52 289.07 1640.42 1523.06 480.00N 36.96E KU43-6 1759.45 1657.89 212.20N 24.23W -172.2 306.01 297.22 Well KU43-6 KU43-6 Wellbore KU43-6 KU43-6 Surve Name GM5 <0-4129> MSS <0-5706'> All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Saker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 8 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) IIi. --=- INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East{ft] From Approach Separation Highside Distance [ft] --1------ [------ .. fdem. Iftl 0.00 0.00 O.OON O.OOE KTU24-61-L ¡----.o.09 ___ ~,08 88.03S 25.23W -164.0 91.58 91.57 100.00 100.00 O.OON O.OOE KTU24-6H 100.25 100.25 87.72S 25.72W -163.7 .-. 91.41 90.98 200.00 200.00 O.OON O.OOE KTU24-6H 200.56 200.54 86.805 27.10W -162.7 90.94 90.21 250.00 250.00 O.OON O.OOE KTU24-6H 250.70 250.67 86.12S 28.13W -161.9 90.60 89.74 262.47 262.47 0.04N O.OOE KTU24-6H 263.16 263.12 85.93S 28.42W -166.1 90.55 89.66 350.00 349.95 2.61N 0.20E KTU24-6H 348.65 348.57 85.525 31.02W -164.9 93.51 92.38 450.00 449.63 10.43N 0.80E KTU24-6H 448.32 448.18 85.815 34.53W -164.1 102.53 101.05 550.00 548.77 23.44N 1.80E KTU24-6H 547.34 547.13 85.995 38.10W -164.2 116.50 114.63 650.00 647.08 41.61N 3.20E KTU24-6H 645.40 645.13 86.195 41.58W -164.7 135.43 133.12 750.00 744.31 64.89N 5.00E KTU24-6H 742.43 742.11 86.54S 44.79W -165.7 159.42 156.65 803.81 796.08 79.50N 6.12E KTU24-6H 794.04 793.69 86.765 46.42W -166.3 174.38 171.35 850.00 840.18 93.20N 7.18E KTU24-6H 838.02 837.65 86.97S 47.75W -166.8 188.38 185.12 950.00 934.43 126.48N 9.74E KTU24-6H 932.40 931.99 87.465 50.38W -167.9 222.24 218.49 1050.00 1026.81 164.63N 12.68E KTU24-6H 1025.17 1024.74 87.89S 52.30W -169.0 260.75 256.43 1150.00 1117.06 207.55N 15.98E KTU24-61:1 1116.11 1115.67 88.175 53.37W -170.1 303.74 298.86 Well KTU24-6H Surve Name UNKN <8820-9010> Error Model All data is in Feet unless otherwise stated Coordinates are from 510t and TVD's are from Rig ( Datum #1 87.0f! above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 9 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported} .ií. ~ INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance ¡ft] Ideal Iftl 0.00 0.00 O.OON O.OOE KTU24-6H 0.09 0.08 88.035 25.23W -164.0 91.58 91.57 100.00 100.00 O.OON O.OOE KTU24-6H 100.25 100.25 87.725 25.72W -163.7 91.41 90.98 200.00 200.00 O.OON O.OOE KTU24-6H 200.56 200.54 86.805 27.10W -162.7 90.94 90.21 250.00 250.00 O.OON O.OOE KTU2~-6H 250.70 250.67 -. 86.12S 28.13W -161.9 90.60 89.74 262.47 262.47 0.04N O.OOE KTU24-6H 263.16 263.12 85.93S 28.42W -166.1 90.55 89.66 350.00 349.95 2.61N 0.20E KTU24-6H 348.65 348.57 85.52S 31.02W -164.9 93.51 92.38 450.00 449.63 10.43N 0.80E KTU24-6H 448.32 448.18 85.81S 34.53W -164.1 102.53 101.05 550.00 548.77 23.44N 1.80E KTU24-6H 547.34 547.13 85.99S 38.10W -164.2 116.50 114.63 650.00 647.08 41.61 N 3.20E KTU24-6H 645.40 645.13 86.195 41.58W -164.7 135.43 133.12 750.00 744.31 64.89N 5.00E KTU24-6H 742.43 742.11 86.54S 44.79W -165.7 159.42 156.65 803.81 796.08 79.50N 6.12E KTU24-6H 794.04 793.69 86.76S 46.42W -166.3 174.38 171.35 850.00 840.18 93.20N 7.18E KTU24-6H 838.02 837.65 86.97S 47.75W ---~ -166.8 188.38 185.12 950.00 934.43 126.48N 9.74E KTU24-6H 932.40 931.99 87.46S 50.38W -167.9 222.24 218.49 1050.00 1026.81 164.63N 12.68E KTU24-6H 1025.17__ 1024.74 87.895.__ 52.30W -169.0 260.75 256.43 1150.00 1117.06 207.55N 15.98E KTU24-6H 111Q~ 1115.67 88.175 53.37W -170.1 303.74 298.86 Well KTU24-6H Wellbore KTU24-6H RD Surve Name MWO <8844-8940> All data is in Feet unless otherwise stated Coordinates are from Slot and TVO's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MO's are from Rig, Offset MO's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 10 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska{lmported) ... ~ INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East{ft] From Approach Separation Highside Distance [ft] [deal [ftl 0.00 0.00 O.OON O.OOE KTU24-6H 0.09 0.08 88.03S 25.23W -. -164.0 91.58 91.57 100.00 100.00 O.OON O.OOE KTU24-6H 100.25 100.25 87.728 25.72W _~163.7 91.41 90.98 200.00 200.00 O.OON O.OOE KTU24-6H 200.56 200.54 86.80S 27.10W -162.7 90.94 90.21 250.00 250.00 O.OON O.OOE KTU24-6H 250.70 250.67 86.12S 28.13W -161.9 90.60 89.74 262.47 262.47 0.04N O.OOE KTU24-6H 263.16 263.12 85.93S 28.42W -166.1 90.55 89.66 350.00 349.95 2.61N 0.20E KTU24-6H 348.65 348.57 85.528 31.02W -164.9 93.51 92.38 450.00 449.63 1 0.43N 0.80E KTU24-6H 448.32 448.18 85.81S 34.53W -164.1 102.53 101.05 550.00 548.77 23.44N 1.80E KTU24-6H 547.34 547.13 85.998 38.10W -164.2 116.50 114.63 650.00 647.08 41.61 N 3.20E KTU24-6H 645.40 645.13 86.19S 41.58W -164.7 135.43 133.12 750.00 744.31 64.89N 5.00E KTU24-6H 742.43 742.11 86.54S 44.79W -165.7 159.42 156.65 803.81 796.08 79.50N 6.12E KTU24-6H 794.04 793.69 86.76S 46.42W -166.3 174.38 171.35 850.00 840.18 93.20N 7.18E KTU24-6H 838.02 837.65 86.97S .4?75W -166.8 188.38 185.12 950.00 934.43 126.48N 9.74E KTU24-6H 932.40 931.99 87.468 50.38W -167.9 222.24 218.49 1050.00 1026.81 164.63N 12.68E KTU24-6H 1025.17 1024.74 87.898 52.30W -169.0 260.75 256.43 1150.00 1117.06 207.55N 15.g8E KTU24-6H 1116.11 1115.67__ 88.178 53.37W -170.1 303.74 298.86 Well KTU24-6H Wellbore KTU24-6H 8urve Name MWO <0-10960> Error M I Standard All data is in Feet unless otherwise stated Coordinates are from Slot and TVO's are from Rig ( Oatum #1 87.0ft above mean sea level) Reference MO's are from Rig, Offset MO's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 11 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) ... --=- INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] rdeal rftl 0.00 0.00 O.OON O.OOE J<BU33-6X 0.00 4.60 2.958 56.86W - -93.0 57.12 57.12 16.40 16.40 O.OON O.OOE KBU33-6X 11.~. 16.42 2.95S 56.86W -93.0 56.94 56.74 100.00 100.00 O.OON O.OOE KBU33-6X 95.41 100.01 2.91S 56.85W -92.9 56.92 56.39 200.00 200.00 O.OON O.OOE KBU33-6X 195A3 200.03 2.818 56.80W -92.8 56.87 56.00 250.00 250.00 O.OON O.OOE KBU33-6X 245.44 250.04 2.758 56.78W -92.8 56.84 55.80 262.47 262.47 0.04N O.OOE KBU33-6X 257.90 262.50 2.73S 56.77W -97.2 56.84 55.75 311.68 311.67 0.99N 0.08E KBU33-6X 307.11 311.71 2.65S 56.74W -98.1 56.94 55.68 350.00 349.95 2.61N 0.20E KBU33-6X 345.36 349.96 2.59S 56.73W -99.6 57.17 55.79 450.00 449.63 10.43N 0.80E KBU33-6X 445.05 449.65 2.538 56.77W -107.0 59.01 57.26 550.00 548.77 23.44N 1.80E KBU33-6X 544.54 549.14 2.64S 56.33W -118.3 63.72 61.53 650.00 647.08 41.61N 3.20E KBU33-6X 643.16 647.75 2.17S 55.65W -130.5 73.35 70.63 688.98 685.12 50.08N 3.86E KBU33-6X 681.00 685.59 2.06S 55.40W -135.0 78.93 75.97 750.00 744.31 64.89N 5.00E KBU33-6X 740.19 744.78 2.018 54.98W -141.6 89.84 86.55 850.00 840.18 93.20N 7.18E KBU33-6X 836.59 841.18 ,_.~"-" 1.83S 53.91W -150.5 112.98 109.11 950.00 934.43 126.48N 9.74E KBU33-6X 931.13 935.71 1.508 52.68W -157.1 142.39 137.94 1050.00 1026.81 164.63N 12.68E KBU33-6X 1023.36 1027.9.3- f--__1.278__ 51.38W -161.9 177.84 172.81 1150.00 1117.06 207.55N 15.98E KBU33-6X 1113.97 1118.52 1.13S 50.08W -165.3 21ª~ 213.28 1250.00 1204.93 255.12N 19.65E KBU33-6X 1204.10 1208.65 0.36S 49.17W -167.8 264.61 258.44 Well KBU33-6X Wellbore KBU33-6X Surve Name MWD<0-8405'> All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 12 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) .1. ...,. INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] [deal [ft! 0.00 0.00 O.OON O.OOE KBU42-7 1---- 0.06 0.06 88.985 75.23W -139.8 116.52 116.51 100.00 100.00 O.OON O.OOE KBU42-7 I---- 100.19 100.19 88.735 75.37W -139.7 116.42 115.93 200.00 200.00 O.OON O.OOE KBU42-7 200.15 200.15 88.11S 75.75W -139.3 116.20 115.35 232.50 232.50 O.OON O.OOE KBU42-7 232.50 232.50 87.92S 75.91W -139.2 116.16 115.17 250.00 250.00 O.OON O.OOE KBU42-7 249.71 249.71 87.90S 76.00W -139.2 116.20 115.14 350.00 349.95 2.61N 0.20E KBU42-7 346.47 346.46 88.585 76.78W -144.2 119.39 118.03 450.00 449.63 10.43N 0.80E KBU42-7 441.89 441.79 92.145 78.66W -146.3 129.99 128.28 550.00 548.77 23.44N 1.80E KBU42-7 535.36 534.97 98.925 81.23W -149.5 148.52 146.37 650.00 647.08 41.61 N 3.20E KBU42-7 626.92 625.97 108.54S 84.29W -153.0 175.06 172.40 750.00 744.31 64.89N 5.00E KBU42-7 718.12 716.33 120.645 86.49W -156.6 208.74 205.51 803.81 796.08 79.50N 6.12E KBU42-7 768.96 766.63 127.98S 86.60W -158.7 229.16 225.59 850.00 840.18 93.20N 7.18E KBU42-7 811.41 808.61 134.235 85.81W -160.5 247.72 243.90 950.00 934.43 126.48N 9.74E KBU42-7 906.01 902.15 147.74S 81.71W -164.3 290.86 286.42 Well KBU42-7 Wellbore KBU42-7 Surve Name MWO <0 - 7570> rams Survev Tool _______NID'i TralL_ Error Model MaC! Corrected All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Oatum #1 87.0ft above mean sea level) Reference MO's are from Rig, Offset MO's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 13 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported} .1. --=- INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] - .. [deal [ftl 0.00 0.00 O.OON O.OOE KU13-5 3.27. -0.73 218.03S 22.77W -174.0 219.22 219.13 49.21 49.21 O.OON O.OOE KU13-5 51.02 47.02 218.19S 22.77W -174.0 219.39 218.92 100.00 100.00 O.OON O.OOE KU13-5 101.03 97.03 218.705 22.77W -174.1 219.90 219.23 200.00 200.00 O.OON O.OOE KU13-5 200.81 196.80 220.10S 22.63W -174.1 221.28 219.95 250.00 250.00 O.OON O.OOE KU13-5 250.69 246.67 220.84S 22.45W -174.2 222.00 220.32 350.00 349.95 2.61N 0.20E KU13-5 351.74 347.71 222.33S 21.94W -178.8 226.04 223.76 450.00 449.63 10.43N 0.80E KU13-5 454.60 450.57 222.93S 21.31W -179.0 234.41 231.64 550.00 548.77 23.44N 1.80E KU13-5 560.99 556.92 220.98S 19.54W -179.4 245.49 242.31 650.00 647.08 41.61N 3.20E KU13-5 672.07 667.74 214.69S 15.99W 179.9 257.85 254.14 750.00 744.31 64.89N 5.00E KU13-5 786.66 781.49 202.30S 9.98W 178.8 270.18 265.83 850.00 840.18 93.20N 7.18E KU13-5 896.81 889.88 185.26S 0.58W 177.2 282.96 277.90 950.00 934.43 126.48N 9.74E KU13-5 1012.82 1002.65 161.73S 12.97E 175.1 296.19 290.29 1017.06 996.60 151.53N 11.67E KU13-5 1089.72 1076.48 142.67S 22.97E 173.6 305.06 298.54 Well KU13-5 Wellbore KU13-5 Surve Name GMS <0-8120'> Error Model Standard All data is in Feet unless othelWise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 14 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) .a. ~ INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] Ideal Iftl 0.00 0.00 O.OON O.OOE KTU32-7H 0.00 0.00 129.535 134.87E 133.8 187.00 187.00 0.00 0.00 O.OON O.OOE KTU32-7H O.Oº-- 0.00 129.53S 134.87E 133.8 187.00 187.00 16.40 16.40 O.OON O.OOE KTU32-7H 15.97 15.97 129.58S 134.88E 133.8 187.04 186.88 49.21 49.21 O.OON O.OOE KTU32-7H - 48.50 .. 48.50 129.685 134.88E 133.9 187.11 186.84 100.00 100.00 O.OON O.OOE KTU32-7H 97.83 97.83 130.145 134.93E 134.0 187.47 187.07 200.00 200.00 O.OON O.OOE KTU32-7H 196.38 196.36 131.955 135.10E 134.3 188.88 188.19 250.00 250.00 O.OON O.OOE KTU32-7H 246.36 246.33 133.21S 135.21 E 134.6 189.85 188.95 350.00 349.95 2.61N 0.20E KTU32-7H 347.38 347.32 135.33S 135.28E 131.1 193.08 191.86 450.00 449.63 10.43N 0.80E KTU32-7H 445.33 445.25 137.435 135.54E 133.0 200.09 198.47 550.00 548.77 23.44N 1.80E KTU32-7H 544.25 544.14 139.815 135.99E 135.7 211.37 209.27 650.00 647.08 41.61N 3.20E KTU32-7H 643.08 642.95 141.69S 136.77E 138.8 226.84 224.18 750.00 744.31 64.89N 5.00E KTU32-7H 741.84 741.69 143.33S 137.06E 142.2 246.58 243.37 850.00 840.18 93.20N 7.18E KTU32-7H 838.08 837.92 144.665 137.17E 145.5 271.07 267.31 950.00 934.43 126.48N 9.74E KTU32-7tt 937.11 936.94 145.155 136.39E 149.0 299.71 295.37 951.44 935.78 126.99N 9.78E KTU32-7H 938.45 ----~ 938.29 145.145 136.38E 149.0 300.15 295.80 Well KTU32-7H Well bore KTU32-7H Surve Name MWD <() - 11857'> Error Model 5tandard All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 15 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported} IIi. ...,. INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] -- Ideol Iftl 0.00 0.00 O.OON O.OOE KTU43-6X 14.00 0.00 286.545 31.17W -173.8 288.23 288.00 100.00 100.00 O.OON O.OOE KTU43-6X 114,ºº- 100.00 286.54S 31.17W -173.8 288.23 287.42 200.00 200.00 O.OON O.OOE KTU43-6X 214.00 200.00 286.545 I 31.17W -173.8 288.23 286.77 250.00 250.00 O.OON O.OOE KTU43-6X _ 2Q.~ 250.00 286.54S 31.17W -173.8 288.23 286.44 262.47 262.47 0.04N O.OOE KTU43-6X 276.47 262.47 286.545 31.17W -178.2 288.27 286.41 350.00 349.95 2.61N 0.20E KTU43-6X 363.95 349.95 286.54S 31.17W -178.2 290.85 288.46 450.00 449.63 10.43N 0.80E KTU43-6X 463.63 449.63 286.545 31.17W -178.3 298.69 295.65 475.72 475.20 13.28N 1.02E KTU43-6X 489.20 475.20 286.54S 31.17W -178.3 301.55 298.33 Well KTU43-6X Wellbore KTU43-6X Rd Surve Name MWD <7670 - 9464'> Error Model Basic MWD - 15CW5A - 28 JAN 03 OJH All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 16 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lm ported} .1. .... INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East{ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] Ideal Iftl 0.00 0.00 O.OON O.OOE KTU43-6X 14.00 0.00 286.54S 31,J7W -173.8 288.23 288.00 100.00 100.00 O.OON O.OOE KTU43-6X 114.00 100.00 286.548 31.17W -173.8 288.23 287.42 200.00 200.00 O.OON O.OOE KTU43-6X 214.00 200.00 286.54S 31.17W -173.8 288.23 286.77 250.00 250.00 O.OON O.OO.E KTU43-6X 264.00 250.00 286.54S 31.17W -173.8 288.23 286.44 262.47 262.47 0.04N O.OOE KTU43-6X 276.47 262.47 286.548 31.17W -178.2 288.27 286.41 350.00 349.95 2.61N 0.20E KTU43-6X 363.95 349.95 286.54S 31.17W -178.2 290.85 288.46 450.00 449.63 10.43N 0.80E KTU43-6X 463.63 449.63 286.548 31.17W -178.3 298.69 295.65 475.72 475.20 13.28N 1.02E KTU43-6X 489.20 475.20 286.54S 31.17W -178.3 301.55 298.33 Well KTU43-6X Surve Name GM8 <0-8370'> All data is in Feet unless othelWise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 17 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) rI.. ---- INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVO[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] rdeal rftl 0.00 0.00 O.OON O.OOE KBU43:nL ,-~ 0.00 ._ 0.00 10J8S 102.99W :96.0 103.55 103.55 0.00 0.00 O.OON O.OOE KBU43-7X O.OO~~ ~PO 10.78S 102.99W -96.0 103.55 103.55 16.40 16.40 O.OON O.OOE KBU43-7X 16.13 16.13 10.74S 103.03W -96.0 103.59 103.42 49.21 49.21 O.OON O.OOE KBU43-7X ~ 48.94 10.66S 103.13W -95.9 103.68 103.39 100.00 100.00 O.OON O.OOE KBU43-7X 99.00 99.00 10.30S 103.56W -95.7 104.08 103.66 200.00 200.00 O.OON O.OOE KBU43-7X 198.00 197.97 8.89S 105.30W -94.8 105.70 104.98 250.00 250.00 O.OON O.OOE KBU43-7X 247.22 247.16 7.86S 106.60W -94.2 106.93 106.00 350.00 349.95 2.61N 0.20E KBU43-7X 344.21 344.06 5.88S 110.39W -98.6 111.07 109.80 450.00 449.63 10.43N 0.80E KBU43-7X 436.00 435.50 4.98S 117.99W -101.0 120.62 118.96 550.00 548.77 23.44N 1.80E KBU43-7X 530.21 528.84 5.38S 130.69W -105.2 137.05 134.92 650.00 647.08 41.61 N 3.20E KBU43-7X 623.88 621.42 7.47S 144.83W -110.5 158.06 155.37 750.00 744.31 64.89N 5.00E KBU43-7X 715.73 711.94 11.50S 159.87W -116.0 184.56 181.24 850.00 840.18 93.20N 7.18E KBU43-7X 803.21 797.93 17 .13S 174.90W -121.2 217.05 213.05 885.83 874.15 104.56N 8.05E KBU43-7X 834.50 828.61 19.70S 18Q.46W -123.0 230.33 226.05 902.23 889.63 109.97N 8.47E KBU43-7X_ ~,78 842.60 20.97S 183.03W -123.8 236.70 232.30 950.00 934.43 126.48N 9.74E KBU43-7X [=::..05 880.07 24.53S 1&9.98W -125.8 256.21 251.51 1050.00 1026.81 164.63N ~ 12.681; KBU43-7X 961.96 953.02 33.30S 204"93W -129.4 302.99 297.59 Well KBU43-7X Wellbore KBU43-7X Surve Name MWO<0-861 0'> Error Mod I Standard All data is in Feet unless otherwise stated Coordinates are from Slot and TVO's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MO's are from Rig, Offset MO's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1, KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 18 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) .1. ~ INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] - -- I-- rdeal rftl 0.00 0.00 O.OON O.O.oE KBU 44-6 0.00 ---+-- .0.00 92.87S -- 92.83E 135.0 131.31 131.31 0.00 0..00 O.OON .o.OOE KBU 44-6 0.00 1---- 0.00 92.87S 92.83E 135.0 131.31 131.31 16.40 16.40 O..oON O.OOE KBU 44-6 16.38 16.38 . 92.855 92.86E 135.0 131.31 131.12 100.00 100.00 O.OON O.OOE KBU 44-6 99.93 99.93 92.72S 93.02E 134.9 131.34 130.86 196.85 196.85 O.OON O.OOE KBU 44-6 196.28 196.28 92.36S 93.51 E 134.7 131.44 130.61 200.00 200.00 O.OON O.OOE KBU 44-6 199.43 199.42 92.35S 93.55E 134.6 131.45 130.61 250..00 250.00 O.OON O.OOE KBU 44-6 249.40 249.39 92.09S 94.12E 134.4 131.68 130.62 350.00 349.95 2.61N 0.20E KBU 44-6 349.73 349.72 91.47S 95.09E 130.3 133.62 132.23 450.00 449.63 10.43N 0.80E KBU 44-6 449.62 449.59 90.30S 96.25E 132.0 138.77 137.05 550..00 548.77 23.44N 1.80E KBU 44-6 549.51 549.43 87.96S 98.48E 134.3 147.51 145.42 650.00 647.08 41.61N 3.20E KBU 44-6 649.02 648.72 83.37S 102.91E 136.5 159.89 157.36 750.0.0 744.31 64.89N 5.00E KBU 44-6 741:!JLL _....J48.llL... . 76.53S 109.11E 138.5 175.65 172.59 850.00 840.18 93.20N 7.18E KBU 44-6 847.28 846.11 69.315 115.05E 141.0 195.14 191.48 950.00 934.43 126.48N 9.74E KBU 44-6 942.7ª~ 941.31 63.06S 119.28E 144.1 219.02 214.74 1000.66 981.48 145.20N 11.18E __....Ji~U 4~I:L 989.54 987.98 60.62S 120.91E 145.8 233.33 228.71 1017.06 996.60 151.53N 11.67E KBU 44-6 1003.62 1002.04 6.o..o5S 121.31E - 146.3 238.36 233.64 1050.00 1026.81 164.63N 12.68E KBU 44-6 1032.90 1031.29 58.985 122.06E__ 1-_ 147.5 248.97 244.06 1150.00 1117.06 207.55N 15.98E KBU 44-6 1123.62 1121.96 56.57S 123.67E 150.9 285.27 279.74 Well KBU 44-6 Wellbore KBU 44-6 Surve Name MWD <0-7440> All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company KBU42-6 Ver 1 KBU42-6 Ver 1 Slot #KBU42-6, Pad 41-7 CLEARANCE LISTING Page 19 Date Printed: 16-0ct-2004 Kenai Gas Field, Kenai Peninsula, Alaska(lm ported) ... ~ INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft) TVD[ft) North[ft) East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] -.. Ideal 1ft] 0.00 Q.OO O.OON O.OOE KBU33-6 0.00 0.00 89.93S 125.22W -125.7 154.17 0.00 0.00 O.OON O.OOE KBU33-6 0.00 0.00 89.93S 125.22W -125.7 154.17 100.00 100.00 O.OON O.OOE KBU33-6 98.68 98.68 90.348 125.48W -125.8 154.62 200.00 200.00 O.OON O.OOE KBU33-6 198.45 198.44 91.168 126.04W -125.9 155.56 250.00 250.00 O.OON O.OOE KBU33-6 248.26 248.25 91.578 126.42W -125.9 156.11 350.00 349.95 2.61N 0.20E KBU33-6 347.77 347.75 92.41S 127.38W -131.0 159.09 450.00 449.63 10.43N 0.80E KBU33-6 446.85 446.82 93.308 128.55W -132.9 165.83 550.00 548.77 23.44N 1.80E KBU33-6 545.64 545.60 94.118 130.10W -135.6 176.72 650.00 647.08 41.61N 3.20E KBU33-6 645.09 645.00 93.488 132.78W -138.5 191.69 750.00 744.31 64.89N 5.00E KBU33-6 745.01 744.79 90.248 136.63W -141.1 210.05 850.00 840.18 93.20N 7.18E KBU33-6 847.80 847.31 84.238 140.96W -143.5 231.25 950.00 934.43 126.48N 9.74E KBU33-6 956.11 954.87 72.758 145.93W -145.6 253.66 1050.00 1026.81 164.63N 12.68E KBU33-6 1068.56 1065.12 51.40S 151.41W -146.7 273.97 1150.00 1117.06 207.55N 15.98E KBU33-6 1172.96 1166.49 27.18S 157.22W -147.5 295.87 Offset Well bore Survey Tool Proarams Well I Well bore I Survev Name I -. MDlftl 8urvev Tool Error Model KBU33-6 I KBU33-6 I GMS <0-7902'> I 7902.00 8cientific KBU33-6 I KBU33-6 I MWO<0-8110> I 8110.00 Navi Trak All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 87.0ft above mean sea level) Reference MO's are from Rig, Offset MO's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Baker Hughes Incorporated . . eFE Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Will Tank Will: Enclosed is the recommended drilling fluid program for the KBU 42-6 Well to be drilled this year. The following is a brief synopsis of the program. Overview: KBU 42-6 is a development well targeting the Tyonek formation at the Kenai Gas Field. Flo-Pro fluid will be used for the intermediate and production intervals. After logging the production interval, the well will be completed with a 3-112" excape system cemented in place. Surface Interval: The surface interval will be drilled with the standard Gel/Gelex spud mud. No problems were noted in this interval while drilling KBU 24-6 and KBU 11-8X. Intermediate Interval: This interval will be drilled with a Flo-Pro NT fluid. After drilling out the surface cement, the well will be displaced to a modified Flo-Pro KCl fluid. SafeCarb bridging material will be maintained according to the mud program to minimize losses to the formation. Fluid loss should be maintained @ 7 - 9 cc's API. NOTE: Since this fluid will also be used in the production interval, care should be taken to maintain recommended mud properties while drilling the intermediate interval. Production Interval: This interval will be drilled with the same fluid that was used to drill the intermediate interval. The fluid will be pre-treated with Bicarb and/or citric acid prior to drilling out the cement. Any further fluid dilutions will be made in order to keep the mud properties at the recommended specifications. Fluid loss should be maintained @ 7 - 9 cc's API for this interval. Based on offset well history, mud wei~hts above 10.0 PPG may be required. Completion: The cement will be displaced with 6% KCI brine for the completion phase of the program. Conqor 303A and Sodium Meta Bisulfate will be added to the drilling fluid that will be left between the 3-112" completion string and the 9-5/8" casing on the final circulation prior to cementing. Tony Tykalsky Project Engineer 1M-I SW ACO Reference Wells: KBU 43-7X; KBU 42-7; KBU 24-6; KBU 11-8X NOTE: This pr02ram is provided as a 2uide onlv, Well conditions will alwavs dictate fluid properties required. r:zj _FE ~~ - Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. I:' __m'., I I Prepared For: MA TH N OIL COMPANY Well KBU 42...6 Kenai Peninsula, Alaska Prepared by: Tony Tykalsky Reviewed by: Mark Fairbanks Presented to: Will Tank October 6,2004 - -- Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Our overall goal is no spills and no incidents while providing fluids and solids control services to Marathon Oil Company. Our goal for KBU 42--6 is to remove drill solids from the mud system at a cost of than $0.23 per pound. This has been the average ror the last three years of centrifuge van operations With the revised fluid formulation (utilizing the intermediate interval fluid the production interval), we expect to drill this well for a product cost of than $23.88 per foot. Use of the MI Swaco centrifuge van for the last four years has provided an estimated savings in dilution disposal costs to Marathon Oil of over $600,000. With continued usage of our equipment, we expect to provide more savings to you during future operations. . . eFE Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Interval Benchmarks and Targets Drilling Intervals Djpth Benchmark 1 Benchmark 2 Benchmark 3 .... . " ....I:? i" Interval tftJ Fluid cost per foot Volume Usage Solids Removal 0- 1525' < $5.59 ft < 1917 bbls 1525 - 6189' < $29.69 ft < 3007 bbls 6189 - 8624' < $24.35 ft < 855 bbls Total Avg. Max. Project < $23.88 ft <5778 bbls < $0.23 Ib No Spills from Targets for Centrifuge Van Drilling Operation Interval ~ elÆ am'~ . . eFE Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Project Summary Casing Hole Casing Depth rvD Mud Mud Sum Interval Size Size Program System Weight Days Mud Cost (in) (in) (ft) (ft) Solids Control (ppg) 13 3/8" 16" 1525' 1432' GeVGelex Spud Mud 8.6 - 9.4 5 $11 ,904 Screens 150/180 mesh Desilter Centrifuge Van 9 5/8" 12-114" 6189' 5365' Flo-Pro w/SafeCarb 9.0- 10 $145,215 Screens 180 - 210 < 9.5 mesh Desilter Centrifuge Van 3-1/2" 8-1/2" 8624' 7800' Flo-Pro w/SafeCarb 9.0- 7 $63,656 Screens 230 - 210 10.0+ mesh Desilter Centrifuge Van 3 1/2" 8-1/2" Completion 8624' 7800' 6% KCI 8.55 2 $3,952 ~ Utilize all solids control equipment to minimize the build up of drill solids in the system (if possible, centrifuge the surface mud during trips to reduce drill solids). ~ Condition the mud prior to running casing for all intervals. ~ Cost include 1 % Lubetex concentration in intermediate and production interval. ~ ..FE am'~ Marathon Oil Company Well Name: KBD 42-6 Location: Kenai, Alaska. M-I Bar 0 451 684 0 1135 3.63 M-I Gel 575 0 0 0 575 2.13 Gelex 24 0 0 0 24 0.14 Soda Ash 10 15 9 0 34 0.24 Caustic Soda 10 30 9 0 49 0.61 Conqor 404 0 7 3 0 10 5.49 Sodium Meta 19 30 9 4 62 1.87 Bisulfate Bicarb 10 15 17 0 42 0.36 Conqor 303 0 0 0 4 4 0.46 Flo Vis 0 241 68 0 309 28.99 Desco CF 10 0 0 0 10 0.22 Polypac UL 10 120 34 0 164 12.24 Bioban BP Plus 0 30 68 0 98 1.03 KCI 0 1263 359 42 1664 9.97 Safecarb 0 1203 342 0 1545 12.88 Lubetex 0 24 14 0 38 13.28 EMInO 0 0 6 0 6 2.62 Citric Acid 0 0 4 0 4 0.19 Defoam X 0 45 5 0 50 2.10 Engineer Service 5 10 7 2 24 . . elÆ Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Offset Well Information Well Hole Size Depth PPG PV YP FL Comments KBU 43-7X 16" 1500 9.15 14 30 14 Spud in, drlg to casing point 12.25' 2900 9.2 5 24 16 Drlg out, disp to FloPro (no fluid loss) 4225 9.05 9 21 16.4 Drlg ahead, encounter some coal 4810 9.32 9 30 15.6 Short trip - backream - some swelling 5112 9.4 11 30 17.6 Swelling hole - lower FL with Pac 5811 9.5 13 29 8.4 POH-OK 6477 9.6 17 42 6.0 POH - ready to run casing 8.5" 6991 9.2 12 22 4.4 New mud - drlg ahead 7795 9.3 14 26 3.6 Trip OK - drlg ahead 8570 9.85 12 44 4.4 Gas increase mud weight 8610 10.6 15 28 4.6 Gas - increase mud weight KBU 42-7 17.5" 1006 8.9 12 30 11.2 Spud in, drlg to casing point 1760 9 12 19 116 Drlg out, LOT 15.6 ppg 12.25" 3455 9.3 10 17 8.9 Drlg ahead 4371 9.35 9 25 11 Trip OK 5205 9.4 14 11 5.5 Drlg ahead. some losses. 100% losses @ 4899' pump SafeCarb LCM (M & C) 5590 9.3 14 18 7.6 Drlg to csg point, spot LCM pill. lost 50 bbls during cementing 8.5" 6131 9.7 13 24 10.8 Drlg out, LOT 13.3 6733 10 15 19 8 Hole swelling, inc mud weight to 10.0 ppg 7000 9.9 15 19 7.8 Drlg ahead 7293 10.15 15 21 7.5 Orlg ahead. inc mud weight to 10.3 popg 7570 10.6 22 22 6.6 Drlg to TD increase mud weigh (gas) KBU 24-6 17.5" 1008 8.85 28 67 7.5 Spud in, drlg to casing point 1525 8.65 12 26 11.4 Sweep hole prior to running csg 12.25" 1818 8.75 7 27 6.2 Drlg out. LOT 18.4 ppg 3611 8.95 8 20 6.9 Drlg ahead 4011 9 8 16 7.8 Drlg ahead 4532 8.9 8 22 8.2 Drlg ahead 4982 9.7 9 22 10 Drlg ahead 5213 9.8 11 27 8 Drlg ahead 5505 9.6 7 14 7.8 Run csg, lost returns spot LCM pill (1289 bbl losses) 8.5" 6395 9.55 8 25 7.7 Drlg out, LOT 14.5 ppg 7420 9.6 9 27 7.5 Drlg ahead, inc mud ppg 7500 10.3 11 25 6.2 Spot 16.0 ppg pill on bottom, run liner KBU 11-8X 16" 720 9 13 32 14 Spud in, drill ahead 1517 9.05 13 12 16 Drlg to casing point, condition mud, POH to run casing 12.25" 2326 9.1 11 13 8.2 Orlg out, disp to FloPro, drlg ahead, keep mud thin for high GPM 3719 9.5 11 16 7.8 Drlg ahead, short trip OK, drlg ahead 4825 9.4 12 19 6.4 Orlg ahead. high torque, add lubetex 5334 9.5 11 22 7.2 Slow ROP, add lubetex for sliding 5611 9.7 13 21 7.5 Drlg to casing point, condition mud, POH to run casing 8.5" 6338 9.4 13 21 6.8 Drlg out, displace to new mud, drlg ahead 7402 9.85 13 21 6 Short trip OK. increase PPG to 9.8 7659 10 8 18 11.2 Orlg to TO. fluid loss increasing to to bacterail contamination, POH for logs 7659 10.2 11 14 9.1 Finish logging, run excape completion. r:!ì .IÆ ~~ . . fiR Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Plans & Procedures => COMMUNICATION - The Field Mud Engineer will communicate daily with the In-Town Project Engineer. The Project Engineer will then communicate daily with the rig Drilling Engineer. Communications should be about, but not limited to, fluid properties, hole difficulties, possible changes to the mud program, and proposals to use products not included in the mud program. => Whole Mud Losses to the Sterlng B3 and Uppern & Middle Beluga Sands - Refer to fluid formulas and the Optibridge charts for maintaining proper bridging material concentration in the mud system while drilling the intermediate and production intervals. => FLUID LOSS CONTROL - In the intermediate interval the API fluid loss will be maintained in the 7 - 9 cc's range. In the production interval the API fluid will be maintained between 6 - 8 cc's at all times. In addition to sufficient fluid loss agent additions, this may require adequate dilution of the mud system in order to keep reactive drill solids to a minimum. => INTERMEDIATE INTERVAL - Note. due to the restrictive flow properties of cold. new mud. the followina is recommended for the intermediate interval. FloVis concentration of the initial mix should be no more than 1.25 PPB. Shaker screens should be 180/180/150 until the mud warms uP. Also. whenever possible. the makeup water for the mud should be heated with steam hoses to as hiah a temperature as possible. Finallv. the pH of the make UP water should be lowered to 5+/- 6 with Citric Acid prior to addinQ FloVis. After all the FloVis is added. the pH should be increased to +/- 9.5 to yield the polymer. This will reduce the tendency for the polymer to form fish-eyes. As the drillinQ fluid heats uP. FloVis concentration should be brouaht UP to 2 PPB and the end shaker screen chanQed to 180 mesh. => DRILL SOLIDS - MBT - The MBT should be kept at less than 7.5 ppb in the intermediate and production intervals through aggressive use of solids equipment and dilution as needed. => MIXING CONDITIONS - Whenever possible all treatments to the mud system should be made as pre-mix additions. Polymers and KCI should first be mixed in fresh water in that order and then blended into the active system over one or two circulations as needed. => CORROSION - Conqor 404 additions should be made daily when drilling with FloPro fluid in order to maintain a Conqor 404 concentration of +/- 2000 PPM. => CORRISION - Sodium Meta Bisulfate additions should be made daily as needed with any fluid in the hole. Maintain a DO reading of less than 3 ppm => SOLIDS VAN USAGE - The Solids Van should be used whenever drill solids become un- acceptably high and reduction of drill solids in the mud can be more economically done with centrifuging and dilution then just with dumping and diluting. The weight of the drilling fluid alone should not be the determining condition for when to use the Solids Van. => WEIGHTING UP - All increases in mud weight should be accomplished with barite additions. In the production interval, insure chloride concentration is maintained at 30,000 to minimize the need for barite additions. ~ 81Æ rm'~ . . elÆ Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Interval Summary - 16" hole o -1525' .. Drilling Fluid System Gel/Gelex Spud Mud Key Products MI Gel / Gelex / Soda Ash / Caustic Soda / MI Bar / PolyPac Supreme UL / Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 150 - 180 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions íntel"ValDrìlting Fluid Properties Depth Mud Funnel Yield API Drill Interval Weight Viscosity Point Fluid Loss pH Solids (ft) (ppg) (sec.lqt) (lb.llOOftZ) (ml/30min) (%) 0 - 1525' 8.6 - 9.4 60 - 100 25 - 35 NC - 12 +/- 9.5 < 7.5% ~ Treat drill water with Soda Ash to reduce hardness. ~ Build spud mud with 20 - 25 PPB M-I Gel to +/- 100 seconds/quart funnel viscosity. ~ Lower funnel viscosity to +/- 75 after gravel zone has been drilled. ~ Add Gelex as needed to maintain sufficient viscosity for hole cleaning. ~ Increase funnel viscosity if fill on connections begins to occur. ~ Reduce fluid loss with additions of Poly pac Supreme UL prior to running surface casing. ~ Add Sodium Meta Bisulfate to maintain a DO of < 3 PPM. ~ Condition mud prior to cementing casing to reduce yield point and gel strengths. ~ Estimated volume usage for interval- 1917 barrels. ~ Estimated haul off volume - 3034 barrels. r:ielFE œ'"~ . . "FE Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Interval Summary -12-1/4" hole 1525 .- 6189' Drilling Fluid System Flo-ProFluid Key Products Flo- Vis / PolyPac Supreme UL / KCI/ SafeCarb 10, 40, 250 MI Bar / Caustic Soda / Conqor 404 / Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended initial shaker screens - 180/180/150 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions Interval Dmlin.g Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (ppg) (cp.) (cps) (ml/30min) (%) 1525 - 6189' 9.0-< 9.5 8- 12 30,000+ 7 - 9 < 7.5 +/- 5% ~ Use one rig pit to drill out surface casing. In other rig pits, build new Flo-Pro fluid using the enclosed fluid formula. Pre-heat makeup water with steam hoses as much as possible. ~ After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test ~ As mud heats up, increase Fl0 Vis concentration to 2 PPB and install 180 mesh shaker screens on end panel. ~ NOTE: Always add 2 - 4 PPB SafeCarb 250 in batches to replenish ground down bridging material. ~ If running coals become a problem, treat with a 2 PPB addition of Asphasol Supreme. ~ If torque or sliding problems occur, add 1 - 3% Lubetex. ~ NOTE: This fluid will be used in the production interval. It is inherent to maintain proper fluid properties for that purpose. ~ Estimated volume usage for interval- 3007 barrels. ~ Estimated haul off volume - 4079 barrels. ~ Condition mud prior to running 9-5/8" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ~.IÆ ~~ - MarathQn Oil Company Wen Name: KBU Location: Kenai, - Marathon Oil Company Wen Name: KBU 42-6 Location: Kenai, Alaska. © 1999 ·2004 M·I L.I..C. . All 1.0 0.9 0.8 c:: 0 0.7 .. ;::¡ ..C! '1: .... w Õ 0.6 <I) .!:ì tI} 0.5 <I) t:i t cu Q. 0.4 <II .~ -; :; 0.3 E ::! (.) 0.2 0.1 0 1x10·1 1x10"2 1)(10° 1x101 1x1«J2 Particle Size (microns) ny Max Permeability: 2500 mOarcy Sand Control Oev ice: 010 Targell Blend: 2.0 050 Target I Blend: 50.0 090 Target I Blend: 162.0 2.6 microns 46.3 microns 194.1 microns Brand Name B=Safe.carb 10 (F) O=Safe.carb 40 1M) E=Safe.carb 250 (C) Bridaina AClent(lb/bblJ 0.4 19.6 0.0 B 2.1% o 97.9% 1x11f Calcium Carbonate added: Av g Error 0 ·100 % CPS Range: Max Error 0 ·100 % CPS Range: 20 Ib/bbl 1.41 % 8.53 % 1x10'" ~ Zone of interest - Sterling B-3 sands ;¡.. Pore Pressure - 0.8 - 6.5 - Maximum Porosity - 2500 mD ;¡.. Measured Depth - +/- 4248' (3572' TVD) ;¡.. Build additional volume as needed usin2 the blend listed above. . . fiFE Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Interval Summary - 8-1/2" hole 6189 ...8624' Drilling Fluid System Flo-ProFluid Key Products Flo-Vis / Polypac Supreme UL / KCl / SafeCarb F & M / MI Bar / Caustic Soda / Conqor 404 / Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 210 - 230 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions Interval Drilling Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (ppg) (cp.) (cps) (mI/30min) (%) 6189 - 8624' 9.0- 10.0+ 10- 14 30,000+ 6 - 8 < 7.5 +/- 5% ~ Pre-treat drilling fluid with Bicarb and/or citric acid prior to drilling cement. Aggressively treat out cement contamination as soon as feasible. Build additional dilution volume to maintain proper specifications. ~ NOTE: Based on offset well history. mud weights 10.0 PPG or higher may be required for wellbore stability. ~ NOTE: Receive approval from Pete Berga or Will Tank prior to adding EMI 920 lubricant to the mud system. (EMI 920 may provide reduction from metal-to-metal torque) ~ If running coals become a problem, treat with a 2 PPB addition of Asphasol Supreme. ~ Estimated additional volume for interval- 855 barrels. ~ Estimated haul off volume - 2298 barrels. ~ Condition mud prior to running 3-112" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. r:!j 81Æ am'~ - Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. No 6 1 2 3 4 5a 5b 6 7 8 9 10 11 1.33 Well bore - Marathon Oil Company Wen Name: KBU 42-6 Location: Kenai, Alaska. Corrosion Control Additive in Casing x Tubing Annulus Well KBU 42-6 Volumes: Tubing barrels x Tubing barrels 3.50 x 2.992 x 8624 ft Open Hole x Tbg barrels Total Annular Volume Tubing Volume Total Hole Volume 521.56 75.03 596.59 x 8.681 @ 6189 ft MD ....... 8.500 x 3.50 @ 8624 ft MD Treatment Procedures. 1. After the 3-1/2" tubing Is run and the drilling fluid is circulated and conditioned for the cement job, circulate an additional 380 barrels of drilling fluid. 2. Add 4 drums of Conqor 303A and 4 sacks Sodium Meta Bisulfate to this 380 barrels. 3. After the 366 barrels of drilling fluid with Conqor 303A and Sodium Meta Bisulfatehave been pumped downhole. begin the cement job. 4. This rocedure will lace corrosion control in the 3·1/2" x 9-5/S" annulus. . . eFE Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. HSE Issues HANDLING OF DRilLING FLUID PRODUCTS HEALTH AND SAFETY 1. Drilling crews should be instructed in the proper procedures for handling fluid products. 2. Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab, and the office of the Drilling Forman. 3. PPE must be in good working order and be utilized as recommended by the PPE charts. 4. Product additions should be made with the intent to use complete unit amounts of products (sacks, drums, cans) as much as possible in order to minimize inventory of partial units. 5. Insure all MSDS sheets are up to date and readily available for workers to access for information. ENVIRONMENTAL 1. Insure that all product stored outside is protected from the weather. 2. Do not store partial units (sacks, etc) outside if possible. 3. Properly secure all products for shipment between job sites. 4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly secured. 5. When utilizing the centrifuge solids van, insure all hoses and connections between the van and the rig are secure. ~ .FE ~~ - Marathon Well Name: Location: Kenai, Product Function M- BAR M- Agent - Marathon Oil Company Well Name: KBU 42~6 Location: Kenai, Alaska. Product CAUSTIC SODA CAUSTIC POTASH RAX SAPP SODA ASH SODIUM BICARBONATE CITRIC ACID BIOBANBP-PLUS Function LCM . . eFE Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS) HAZARD RATINGS 4 - Severe hazard 3 - Serious hazard 2 - Moderate hazard 1 - Slight hazard o - Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX A - Safety Glasses B - Safety Glasses, Gloves C - Safety Glasses, Gloves, Synthetic Apron D - Face Shield, Gloves, Synthetic Apron E - Safety Glasses, Gloves, Dust Respirator F - Safety Glasses, Gloves, Synthetic Apron, Dust Respirator G - Safety Glasses, Gloves, Vapor Respirator H - Splash Goggles, Gloves, Synthetic Apron, Vapor Respirator I - Safety Glasses, Gloves, Dust and Vapor Respirator J - Splash Goggles, Gloves, Synthetic Apron, Dust and Vapor Respirator K - Air Line Hood or Mask, Gloves, Full Suit, Boots X - Consult your supervisor for special handling directions ~ ..FE ~~ . . eFE Marathon Oil Company Well Name: KBU 42-6 Location: Kenai, Alaska. Contacts Contact Title e-mail Work Cellular Pete Berga Drilling pkberga@marathonoil.com 907564-6319 907 231-0663 Marathon Superintendent Will Tank Drilling Engineer wjtank@marathonoil.com 713 296-3273 713 203-8398 Marathon Tony Tykalsky Project Engineer ttykalsky@miswaco.com 907 274-5011 907227-2412 MI SW ACO Gus Wik Warehouse Manager gwik@miswaco.com 907 776-8722 907776-8680 MI SW ACO Michael Barry Senior Field gratefulmen@hotmail.com 907 260-4666 907 590-3636 MI SW ACO Engineer (home) Locke Rooney Field Engineer rooneyl@alaska.net 907 235-0598 907 590-3636 MI SWACO (home) Roland Lawson I Drilling Foremen 907283-1312 Larry Myers I Dave Morris Marathon Responsibilities » MI Project Engineer and will coordinate daily between the Marathon office, rig, warehouse, and the M-I field engineers. » Well progress will be monitored to look for any changes, which will improve the efficiency of the operation or avert trouble. » Field Engineers will monitor and supervise product inventory to include re-palletizing any products for shipment to other locations at the end of the well. » Field Engineers will communicate with office personnel (Marathon & MI SW ACO) for approval of any changes in the mud program (including introduction of new products). » Field Engineers will produce a recap at the end of the well based on daily activities. Recap should include any lessons learned that may be used to provide better service on future wells. Lessons learned can include changes in procedures, product additions, equipment usage, and/or utilization of any third party service. r:zj ..FE am'~ Check No Check Date Bank Bank No Marathon Oil Company P.O. Box 3128 Houston, TX 772S3 ~æó~~~'þ"A~~BLE DEPARTMENT Acets Payable Contact Center Phone: 918-925-6097 Ði~¡;¡¡;;í{) ): . . . . . . . . . . . . . . . . . . . , . .. .. ...................... Hndlg HS 1147038 10/19/2004 NCBAS :;¡~M'!i¡i~iiit:>~ii.Mi¥Þ.¡¡M L 100.00 10/19/2004 7780 5001123 ~¡ijjijt 1900031741 TOTAL: 100.00 100.00 ~¡~~¥~f> ~ 100. 100. REC I\/E OCT 2 02004 (FOLD ON PERFORATION BELOW AND DETACH CHECK STUB BEFORE DEPOSITING) . . . 'nnn L L L ?n =L A II' I~n L 1. ?n =\R q 51~ O;LB ~ l.B 1.11' . . TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERJPARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME /~ ~q PTD# ¿ð7"-201 " X Development Service 7/?-- - C Exploration Stratigraphic CHECK WHAT ADD-ONS ~'CLUE ". APPLIES (OPTIONS) MULTI Tbe permit is for a new we))bore 'segmeDt of LATERAL existiDg weD . Permit No, API No. . (If APJ number Production. should continue to be reported as last two. (2) digits a function' of tbe original API number. stated are between 60-69) above. PILOT BOLE ]D accordance with 20 AAC 25.005(1), all (PH) records, data aDd logs acquired for the pilot bole must be dearly differentiated In botb Dame (name on permit plus PH) .' aDd API number (SO - 70/80) from records, datJI aDd Jogs acquired for we)) (Dame on permi1). SPACING The permit is approved subject ·to fuD EXCEPT] ON compliaDce with 20 AAC 25..0SS~ Approval to perforate and produce is contingeDt UpOD issuance of ~ conservation order approviDg a spaciDg e] cepdoD. (Company Name) assumes tbe liability of aDY protest 10 the spaciDg .e]CeptioD tbat may occur. DRY DITCH All dry ditch sample sets submitted to tbe SAMPLE Commission must be in no greater than 30' sample intervals from below tbe permafrost or from wbere samples are first caught aDd ] 0' sample iJiter:vals through target 7.ones. Field & Pool KENAI, UPPER TYONEK BELUGA GAS - 44857 Well Name: KENAI BELUGA UNIT 42-6 PTD#:2042090 Company MARATHON OIL CO Initial ClasslType DEV 11-GAS GeoArea 1 Permit fee attached _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 2 _LeasJ3_nllmberappropriate_ _. _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S_ 3 _U_nlqlle welln_al11J3_a!ld ou.mb_er _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 4 WellJQcatJ:!d in a defineßPool _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ _ _ _ _ _ _ 5 WellJQcatJ:!d proper _distance from driJling unitb_ounda(y_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ _ _ _ _ _ In the Kenai_unitthe olJly spacing rescticitiQnJs thatweUs must be atleast l500' Jromthe unit Þou.ndary.. 6 WellJocatJ:!d proper _distance_ from Qtber wells_ . Yes _ _ _ _ _ _ _ ThiS welLq)l)forrns_tQ thaUequirement HPG_ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ 7 _S_ufficienLacreageayailable indrillilJg unjL _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ 8 RdJ:!viated, js wellbore platincJu_ded _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ 9 _Operator onlY' affected party _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ 10 _Operator has_appropriate_bond lnJorce _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 11 PJ:!rmit call be lssu.ed wjtbout COMerva.tion order _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ Appr Date 12 pJ:! rm it. call be issu.ed wjtbQut admilJistratille_approvaJ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ RPC 10/21/2004 13 Can permit be approved before 15-day wait Yes 14 WellJocatJ:!d within area and strata _authorized byJlljectiolJ Ord_er # (putlO# in_c_ol11l11J3lltsUFor_ NA _ _ _ _ _ _ _ _ 15 _AJlwells_withinJl4J'uile_area_oJreyiewjd_elltified(ForservjcJ3wellonlY'L _ _ _ _ _ _ _ _ _ _ _ _ _ _ _NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ 16 Pre-produced illjector; durat.ionof pre-production IJ3Ss_ than 3 months_ (For_service well Qnly) _ _ _NA 17AGMPfinding9fConsi.stellcy_h_as beenisslledforJbis prolect _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _NA Program DEV On/Off Shore On Well bore seg Annular Disposal Unit Administration - - - - - - - ~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Appr WGA 18 19 20 21 22 23 24 25 26 27 Date 28 10/25/2004 29 30 31 32 33 34 _ . 20-" @ 139'. _ . - - - - - - - - - -- COlldu_ctor string_prQvided .. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ Surfaœ _casingpJQtects alLknQwn_ USDWs _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _YJ3S _ _CMT vol adec;¡uateJo circ_ulateon _cond_uctor_ & SUJtcsg _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ CMTvoladec;¡uateJotie-inJQng_stri!lgto_sllrfCSg_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ _CMTwill coYer_aU know_nprodllctiye bori;!:on_s_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ _ _ _ _ _ _C_asillg desig!ls adequa.te for CJ, B&permafrost _ _ _ _ _ YJ3S _ _ _ _ _ _ _ _Ädequate_tankage_oJ reserve pit _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ Glacier Rig L Jta re-drilL t.u~s_ a_ lO,403 for abandon_ment beJ:!1l apPJQved _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ New welL _ Adequatewellbore separatjo_n_proposed _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Jtdjvecteueq_uired, does jt meet. reguJations_ _ _ _ _ _ _ _ YJ3S _ _ _ _ _ _ _ _ _ _ _ _ _ _DJillilJg fJujd_prOQram schematic_& eq.uipJistadequat.e_ _ YJ3S _ _ _ _ _ Max MWJOcO_ppg._ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _BOPEs,_dothey meet. regulation _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ:!s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _BOPE_press ra.tillg appropriate; _testto(put psig incoml11ents) _ _ Y J3S _ _ _ Test to200Q psi. MSF> 1 a06 psi. Chokemanjfold cQmplies w/APl RF>-53.(May a4)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ WQrk will occ_ur withoutoperatio_n _shutdown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YJ3S _ Js presellce of H2S gas_ probable _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No _ _ _ _ _ _ _ _ Mecba_nicaLCOlJdjtiO!l of wells within 80S. yerified (for_s_ervjçe well onJy) _ _ _ _ _ _ _NA Engineering - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ _ _ Mequate excess, _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - Geology 35 36 Date 37 10/21/2004 38 39 PJ:!rmitßall be issu.ed wlo_ hydrogen_ s_ulfide meaSJJres _ _ _ _ _ _ _ _ YJ3S _Datapreseoted on pote_ntial oveJpressurezones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ NA _ _ _ _ _ _ _SJ3Lsl11ic_analysjs_ of sballow gas_z_olles_ _ _NA _ _SJ:!abed _conditiolJ survey (if off-shore) . . . . _ . _ _ _ . . _ . . . . _ _ _ _ _ _ _ _ _ . _ _ . NA_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . Conta_ct nam_elphOlleforweekly progress_reports [explorato(y _o!lIYl _ _ _ _ _ _ _ . _ _ _ NA _ _ _ . . _ _ _ _ _ - - - - - - - - - - ~ - ~ ~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - . - - - Appr RPC - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Geologic Commissioner: Engineering Commissioner: Date: Date Date DTJ 10/~~} ~ o o . .