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Home My WebLink About204-005Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ JBR 10/03/2025 InspectNo:susGDC250820115936 Well Pressures (psi): Date Inspected:8/21/2025 Inspector:Guy Cook If Verified, How?Other (specify in comments) Suspension Date:2/21/2025 #325-045 Tubing:0 IA:10 OA: Operator:Hilcorp Alaska, LLC Operator Rep:Zachary Rohr Date AOGCC Notified:8/20/2025 Type of Inspection:Initial Well Name:CANNERY LOOP UNIT 08 Permit Number:2040050 Wellhead Condition The wellhead tree is a single swab valve only. Looks to be in good condition with the expected amount of surface rust with a wellhead that is exposed to the elements. Surrounding Surface Condition Good clean pad gravel. The well is protected with a couple of cement blocks and some old equipment frames of some sort. Condition of Cellar Trash in the cellar. Comments The location of the well was verified by pad map. Supervisor Comments Photos (6) attached Suspension Approval:Sundry Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Friday, October 3, 2025            2025-0821_Suspend_CLU-8_photos_gc Page 1 of 3 Suspended Well Inspection – CLU-8 PTD 2040050 AOGCC Inspection Rpt # susGDC250820115936 Photos by AOGCC Inspector G. Cook 8-21-2025 2025-0821_Suspend_CLU-8_photos_gc Page 2 of 3 Well cellar debris 2025-0821_Suspend_CLU-8_photos_gc Page 3 of 3 Tree Cap pressure gauge IA pressure gauge 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): GL: BF: Total Depth: 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-55 121 13-3/8" K-55 1,636 9-5/8" L-80 4,941 3-1/2" L-80 7,910 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 Sr Res EngSr Pet GeoSr Pet Eng Kenai C.L.U./ Beluga Gas N/A Oil-Bbl: Water-Bbl: Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing N/A Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 68# 6,722 Surface Surface 133# Surface 1,810 SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 5,108'9.2#85,000 DrivenSurface N/A N/A 40# Surface 121Surface CASING WT. PER FT.GRADE 2/9/2004 CEMENTING RECORD N/A N/A SETTING DEPTH TVD 2390711.10 TOP HOLE SIZE AMOUNT PULLED N/A 276565.90 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 50-133-20534-00-00 Cannery Loop Unit (CLU) 08207' FSL, 492'' FEL, Sec. 7, T5N, R11W, S.M. 2,342' FSL, 1731' FEL, Sec. 8, T5N, R11W, S.M. N/A 1/25/2004 9,777' MD / 7,941' TVD 5,033' MD / 3,708' TVD 42 272489.70 2388653.20 N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 ADL0373302/ADL0324602/FEE-TR73 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG WAG Gas 2/21/2025 204-005 / 325-045Hilcorp Alaska, LLC 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, 555 sx12-1/4" TUBING RECORD 1430 sx9,746 512 sx N/A 3,756 16" N/A 8-1/2: 9,7463-1/2" Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 3:14 pm, Mar 19, 2025 Suspended 2/21/2025 JSB RBDMS JSB 032825 xG DSR-4/7/25BJM 11/10/25 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval 31. List of Attachments: Well Operations Summary, Schematic 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Stefan Reed, Operations Engineer Digital Signature with Date:Contact Email:stefan.reed@hilcorp.com Contact Phone: 206-518-0400 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: Formation Name at TD: 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). 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. 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. 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: 2025.03.19 13:47:29 - 08'00' Noel Nocas (4361) _____________________________________________________________________________________ Updated by DMA 03-12-25 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Kenai Gas Field Well: CLU 08 Last Completed: 2004 API: 50-133-20534-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surface 121' 13-3/8"Surface 68 / K-55 / BTC 12.415 Surface 1,810' 9-5/8"Intermediate 40 / L-80 / BTC-MOD 8.835 Surface 6,722' TUBING DETAIL 3-1/2"Tubing 9.3 / L-80 / MOD 8RD 2.992 5,108’9,746' EXCAPE SYSTEM/JEWELRY DETAIL No Depth(MD)Depth(TVD)Item 20 5,070’ 3,731’ 9-5/8” CIBP w/ 25’ Cement – TOC @ 5,033’ 2/13/25 19 5,108’3,756’Tubing Cut 2/8/25 18 5,234’3,837’Tubing Cut 17 6,950’ 5,147’ 3-1/2” CIBP w/ 25’ Cement – TOC @ 6,925’ 2/7/25 16 6,952'5,149'BHP Tank Bottom @ 6,987' MD 15 7,046'5,237'Module #15 w/ conv. Flapper 14 7,149'5,333'Module #14 w/ conv. Flapper 13 7,251'5,430'Module #13 w/ conv. Flapper 13A 7,302’ 5,479' 3-1/2” Slimhole CIBP w/35’ cement – TOC @ 7,267’ 9/12/19 12 7,316'5,492'Module #12 w/ conv. Flapper 11 7,419'5,592'Module #11 w/ conv. Flapper 10 7,475'5,646'Module #10 w/ conv. Flapper 9 7,597'5,765'Module #9 w/ conv. Flapper 8 7,707'5,873'Module #8 w/ conv. Flapper 7 7,941' 6,105' Module #7 w/ Weatherford Straddle/Iso Pkr 6/15/10 6 8,001'6,165'Module #6 w/ conv. Flapper 5 8,306'6,470'Module #5 w/ conv. Flapper 4 8,385'6,549'Module #4 w/ conv. Flapper 3 8,428'6,592'Module #3 w/ conv. Flapper 2 8,515'6,679'Module #2 w/ conv. Flapper 1 N/A N/A Module #1 - No Flapper EXCAPE SYSTEM DETAILS - 15 Excape modules placed -Green control line fires bottom 7 modules. -Red control line fires top 8 modules. -Blue line for BHP monitoring. - Ceramic flapper valves below each module. CEMENTING DETAIL Casing Detail 13-38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type-1 cmt, 100% returns, 40 bbls to surface 9-5/8"12-1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G 3-1/2"8-1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt FLAPPER DETAIL Beluga Perfs Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Status Perf 16 6,993’7,003’5,187’5,196’10’Isolated Mod 15 7,027'7,037'5,219'5,228'10'Isolated Mod 14 7,130'7,140'5,315'5,325'10'Isolated Mod 13 7,232'7,242'5,412'5,422'10'Isolated Mod 12 7,297'7,307'5,474'5,484'10'Isolated Mod 11 7,400'7,410'5,573'5,583'10'Isolated Mod 10 7,456'7,466'5,627'5,637'10'Isolated Mod 9 7,578'7,588'5,746'5,756'10'Isolated Mod 8 7,688'7,698'5,854'5,864'10'Isolated Mod 7 7,922'7,932'6,086'6,096'10'Isolated Mod 6 7,982'7,992'6,146'6,156'10'Isolated Mod 5 8,287'8,297'6,451'6,461'10'Isolated Mod 4 8,366'8,376'6,530'6,540'10'Isolated Mod 3 8,409'8,419'6,573'6,583'10'Isolated Mod 2 8,496'8,506'6,660'6,670'10'Isolated Mod 1 8,990'9,000'7,154'7,164'10'Isolated Straddle Packer Assembly * Top of packer @ 7,941' MD RKB FISH DETAIL @ 7,168’ 07/05/22 2.72” X 7’ Paragon Pkr Milled to slips W/ Lamar spear, w/ 3” GS w/ 1-1/2” broken sucker rod looking up, 7/5/22 Page 1/2 Well Name: CLU 008 Report Printed: 3/5/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20534-00-00 Field Name:Cannery Loop State/Province:ALASKA Permit to Drill (PTD) #:204-005 Sundry #:325-045 Rig Name/No: Jobs Actual Start Date:1/30/2025 End Date: Report Number 1 Report Start Date 2/6/2025 Report End Date 2/7/2025 Last 24hr Summary PTW/PJSM. MIRU Yellowjacket E-line. P-test 250/2,500 psi. Run 2.80" GR/JB to 7,030'. SDFN. Report Number 2 Report Start Date 2/7/2025 Report End Date 2/8/2025 Last 24hr Summary PTW/PJSM. Set 2.75" CIBP at 6,950'. Tag CIBP to confirm set depth and conduct 2,000 psi p-test for 30 min (Note: witness waived by Jim Regg 2/7/25 @ 9:15am). Dump bail 25' of cement on top of CIBP. Cut tubing at 5,234' with jet cutter. RDMO E-line. Lay out liner. Set carrier and auxiliary equipment. Raise and scope up derrick. Winterize and get heat on equipment. Hook up electrical. Fill pits with water. Hook up circulating lines. Report Number 3 Report Start Date 2/8/2025 Report End Date 2/9/2025 Last 24hr Summary Continue rigging up circulating equipment. Attempt to reverse circulate could not get returns and kept pressuring up to 1,500 psi. Switch back and forth between reverse and forward circulating surging the mud pump. Continue working pressure up to 3,000 psi, unable to break circulation. R/U YJ E-line and RIH w/ 2.50" jet cutter, Pressure up to 500 psi, Make cut @ 5,108', Pressure fell off to 350 psi, No returns. Pressure up to 1,500 psi started getting returns, POOH w/ E-line. Circulate long way 680 bbls to get 8.4 ppg water in and out. E-line RIH w/ 2.50" jet cutter and make cut at 5108' to cut control lines. RDMO YJ e-line. Attempt to set BPV, unable to thread in. Try to chase threads with no luck. Get AK e-line headed out to set 3-1/2" retrievable plug. Get donut for testing. R/u Ak e-line. Report Number 4 Report Start Date 2/9/2025 Report End Date 2/10/2025 Last 24hr Summary RIH w/ 3 1/2" retrievable plug & set @ 100', R/d AK E-line. Pressure test plug to 3,000 psi (good test), N/d production tree, N/u BOPE, R/u floor, railings, and stairs. Install tarps around cellar and get heat on stack. Fluid pack BOPE. Test BOPE to Hilcorp's and AOGCC's expectations, 3-1/2" TJ, 13-5/8" 5M BOP, 250psi/3000psi 5 minutes each. Witness waived by AOGCC's Jim Regg. R/u slick line and pull 3-1/2" plug. RDMO slick line. M/u 3-1/2" spear assembly. Cut the 3 control lines and feed into IA. Spear into 3-1/2" tubing hanger, BOLD. P/u seeing hanger unseat at 60k, 13k over calculated string weight w/ blocks. P/u to 110k over. C Work pipe up to 110k over trying to work free. Rotate pipe w/ tongs to try and free up w/ no luck. Calculated stuck point is above 1000'. Reverse circulate surface to surface w/ 100k overpull on string. No significant decrease in overpull while circulating. Continue to work tubing up to 110k overpull. Report Number 5 Report Start Date 2/10/2025 Report End Date 2/11/2025 Last 24hr Summary Mix 1 drum of lube and spot on backside @ 3,200 stks away started getting pebbles come across screens, continue circulating until it cleaned up, Circulated a total of 195 bbl's, Check stretch F/ 46K T/ 67K still only had 2" no change, Worked pipe F/ 80K T/150K, No change, Discuss plan forward with OE on pumping lube down to 5,108', Spot lube Down to 5,108'. Check pipe stretch, no change. Rig up Fox energy pump. Reverse circulate a total of 400 bbl's at 5 bpm, 650psi, FCP 530psi. Saw some solids at initial BU and cleared up. Spear into tubing, work tubing, no increased movement in pipe. Release spear and lay down. R/u YJ e-line. Run CBL in 3-1/2" tubing to 5100' logging out at 50 fpm. Sent log to OE for review. M/u free point tool, run free point tool in hole, check free point at 2000', 1000', and 500' with a starting wt of 60k and p/u to 85k. Showing between 20-30% free at those depths. Report Number 6 Report Start Date 2/11/2025 Report End Date 2/12/2025 Last 24hr Summary E-line could only make it to 2,644' w/ free point tool, POOH, release spear, R/d and release YJ E-line equipment. R/u up test unit and MIT IA t/ 2,000 psi, (Good test). Get casing jack and handling equipment from dock. Discuss plan forward with OE. Plan is to reverse circulate and spot hot water, Rig up casing jack while waiting. R/u Fox energy pump, reverse circulate 120 bbl's of 120 deg water and spot in IA f/surface to 1,875'. Latch up and pull on elevators, worked pipe f/ 80K t/ 150K, broke over at 130k to 60k. Got hanger close to casing jack and shut down to remove jacks. Pull hanger and 14.15' hanger joint (60k p/u wt.). Remove hanger slips. Recovered 3 control lines and sacrificial cable under slips. L/d hanger and hanger joint. POOH standing back 3-1/2"MOD EUE 9.3# L-80 tubing, cutting bands, removing centralizers, and spooling control lines and cable from 5108' to 955'. Initial p/u wt started at 60k and dropped to 32k after pulling 2 joints. Report Number 7 Report Start Date 2/12/2025 Report End Date 2/13/2025 Last 24hr Summary Cont POOH standing back 3-1/2"MOD EUE 9.3# L-80 tubing, cutting bands, removing centralizers, and spooling control lines and cable from 955' to surface. RIH w/ 8 1/2" bit, 9 5/8" casing scraper, bit sub, X/O, total BHA length 14.29, strap in hole, 3-1/2"MOD EUE 9.3# L-80 tubing, F/ surface t/5,001' w/ 3-1/2"MOD EUE 9.3# L-80 tubing, Started taking wt. Circulate B/U, getting thick mud continue circulating until fluid cleaned up. Strip rotating head on, Wash down, reverse circulating at 5 bpm, 500psi, from 5001' to top of tubing stump at 5108'. Circulate additional 2 BU on bottom, returns are clean w/ no solids. Prep for POOH. POOH l/d 3-1/2" MOD EUE from 51208' to surface. Break out and l/d 9-5/8" cleanout assembly. R/d pipe skate. R/u YJ e-line. M/u CBL tool. Report Number 8 Report Start Date 2/13/2025 Report End Date 2/14/2025 Last 24hr Summary E-line Run #1 RIH w/ 3-1/8" CCL, 2-3/4" SCBL, Send CBL log to OE, M/u 9-5/8"(7.71" OD) CIBP on #20 ST and 3-1/8" CCL (11' from CCL to CIBP). Run #2 RIH w/ 9-5/8" CIBP to 5,087' and make correlation pass .Set CIBP at 5,070', confirm set with tag, POOH. MIT 9 5/8" casing to 2,000 psi for 30 min, (Good test), RIH w/ 5" x 30' dump bailer spot 25' of 16ppg cement (80 gallons) on top of CIBP, Total of 3 runs, R/d YJ E-line equipment R/d floor, N/d BOPE. N/u dry hole tree. Lay over derrick, r/d auxiliary equipment and prep for transport. Load and organize trailers. g, ( ) () CIBP at 5,070', confirm set with tag, POOH. MIT 9 5/8" casing to 2,000 psi for 30 min, (Good test Cut tubing at 5,234' with jet cutter. y Set 2.75" CIBP at 6,950'. Tag CIBP to confirm set depth and conduct 2,000 psi p-test for 30 min (Note: witness waived by Jim Regg 2/7/25 @ 9:15am).gp ,p spot 25' of 16ppg cement (80 gallons) on top of CIBP, Total of 3 run ,, Page 2/2 Well Name: CLU 008 Report Printed: 3/5/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 9 Report Start Date 2/21/2025 Report End Date 2/22/2025 Last 24hr Summary Tag cement @ 5033'swlm IA/OA=0psi. R/u pollard slick line. Unable to m/u lubricator on otis connection. Change out otis flange. Stab on Lubricator. PT lucricator, have connection leaking. Pop off and change out O-ring. PT 250/2000psi, good test. RIH w/ 2.5"x6' DD bailer, tagging cement at 5033' slm. POOH r/d slick line. Pressure test 9-5/8" casing and plug to 2000psi. Initial pressure 2265psi, 15 minutes 2247psi, 30 minutes 2247psi, Good test. Tag and pressure test witnessed by AOGCC's sully Sullivan.Ta g and pressure test witnessed by AOGCC's sully Sullivan. gg ,g tagging cement at 5033' slm. POOH r/d slick line. Pressure test 9-5/8" casingpg and plug to 2000psi. I MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 7 Township: 5N Range: 11W Meridian: Seward Drilling Rig: n/a Rig Elevation: n/a Total Depth: 9,777 ft MD Lease No.: ADL 0373302 Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 121 Feet Csg Cut@ Feet Surface: 13-3/8" O.D. Shoe@ 1,810 Feet Csg Cut@ Feet Intermediate: 9-5/8" O.D. Shoe@ 6,722 Feet Csg Cut@ Feet Production: O.D. Shoe@ Feet Csg Cut@ Feet Liner: O.D. Shoe@ Feet Csg Cut@ Feet Tubing: 3-1/2" O.D. Tail@ 9,746 Feet Tbg Cut@ 5,258 Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Bridge plug 5,070 ft MD 5,033 ft MD 10.4 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing n/a n/a n/a 9 5/8 2265 2247 2247 OA 0 0 0 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Brad Whitten Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): This report reflects the tag and test of the 9-5/8 inch casing plug. This well is planned for redrill later this year. The CIBP was set at 5,070 ft MD with 37 ft of cmt dump bailed on top. February 21, 2025 Sully Sullivan Well Bore Plug & Abandonment Cannery Loop Unit Hilcorp Alaska LLC PTD 2040050; Sundry 325-045 Photos (3) Test Data: P Casing Removal: rev. 3-24-2022 2025-0221_Plug_Verification_CLU-08_ss 9 9 99 99 9 9 9 9 9 9 99 99 999 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.04.03 13:59:41 -08'00' 2025-0221_Plug_Verification_CLU-8_photos_ss Page 1 of 2 Plug Verification – Cannery Loop Unit (PTD 2040050) Photos by AOGCC Inspector S. Sullivan 2/21/2025 2025-0221_Plug_Verification_CLU-8_photos_ss Page 2 of 2 Slickline setup for plug tag Setup for pressure test of plug 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: 2/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250216 Well API #PTD #Log Date Log Company Log Type AOGCC Eset # BRU 232-04 50283100230000 132037 1/18/2025 AK E-LINE Perf CLU 08 50133205340000 204005 2/13/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 1/2/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 12/13/2024 YELLOWJACKET SCBL CLU 7 50133205310000 203191 1/25/2025 YELLOWJACKET SCBL IRU 44-36 50283200890000 193022 1/21/2025 AK E-LINE Plug/Perf KALOTSA 10 50133207320000 224147 2/11/2025 YELLOWJACKET SCBL KALOTSA 9 50133207310000 224145 1/26/2025 YELLOWJACKET SCBL KBU 22-06Y 50133206500000 215044 1/11/2025 YELLOWJACKET SCBL KU 13-06A 50133207160000 223112 1/12/2025 YELLOWJACKET SCBL MRU M-25 50733203910000 187086 1/15/2024 AK E-LINE PPROF NCIU A-21 50883201990000 224086 1/6/2024 AK E-LINE Plug/Perf PBU 06-05A 50029202980100 224115 1/14/2025 HALLIBURTON RBT PBU 09-35B 50029213140200 224122 2/3/2025 HALLIBURTON RBT PBU B-12B 50029203320200 224133 1/20/2025 HALLIBURTON RBT PBU D-12 50029204430000 180015 12/19/2024 BAKER SPN PBU F-08B 50029201350200 212040 1/27/2025 HALLIBURTON RBT PBU NK-41A 50029227780100 197158 12/18/2024 YELLOWJACKET CBL PBU S-100A 50029229620100 224083 1/5/2025 HALLIBURTON RBT Revision Explanation: Annotations added to processed log. Please include current contact information if different from above. 162-037 T40080 T40081 T40082 T40082 T40083 T40084 T40085 T40086 T40087 T40088 T40089 T40090 T40091 T40092 T40093 T40094 T40095 T40096 T40097 CLU 08 50133205340000 204005 2/13/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.18 13:06:47 -09'00' 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): 9,777'7,168' Casing Collapse Structural Conductor 1,500 psi Surface 1,950 psi Intermediate 3,090 psi Production 10,530 psi 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: 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 N/A; N/A N/A; N/A 7,941'7,267'5,445' Kenai C.L.U.Beluga Gas 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Cannery Loop Unit (CLU) 08CO 231A Same 7,910'3-1/2" ~450psi 9,746' 7,267' Length February 5, 2025 3-1/2" 9,746' Perforation Depth MD (ft): 6,722' See Attached Schematic 5,750 psi 3,060 psi 3,450 psi 121' 4,941' 121' 1,810' Size 121' 9-5/8"6,722 1,810' MD Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 9,746' 10,160 psi 1,636' 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 ADL0373302/ADL0324602/FEE-TR73 204-005 50-133-20534-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Stefan Reed, Operations Engineer AOGCC USE ONLY Tubing Grade: stefan.reed@hilcorp.com 206-518-0400 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: 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 Grace Christianson at 10:30 am, Jan 30, 2025 325-045 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2025.01.30 09:19:29 -09'00' Provide AOGCC opportunity to witness pressure test to 2000 psi and tag of tubing plug at 6950' md and to witness tag and test to 2000 psi of 9-5/8" casing plug at 5250' MD. X DSR-1/31/25BJM 2/7/25 BOP test to 3000 psi, annular test to 2500 psi 10-407 Yes 2/6/25 Bryan McLellan X SFD 1/30/2025*&: 2/7/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.07 15:18:54 -09'00' RBDMS JSB 021025 RWO Rev. 1 Well: CLU 08 Date: 1/14/2025 Well Name: CLU 08 API Number: 50-133-20534-00-00 Current Status: Shut in gas well Permit to Drill Number: 204-005 Regulatory Contact: Donna Ambruz 777-8305 Rig: Slk,Eline, Pump, 401 First Call Engineer: Stefan Reed (206) 518-0400 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Current Bottom Hole Pressure: 982 psi @ 5,321’ TVD Based on A-15 RFT data of UB 3 sand on 4/2020 Maximum Expected BHP: 982 psi @ 5,321’ TVD Based on A-15 RFT data of UB 3 sand on 4/2020 Maximum Potential Surface Pressure: ~450 psi @ 5,321’ TVD Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary CLU 08 was drilled in 2004 as a grassroots monobore with Excape completion to target gas sands in the Beluga formation. In May 2010 the well loaded up, was swabbed and bailed and patch was set across Module 7. In February 2013 the patch across Module 7 was removed. In April 2013 the patch, slickline fish tools and wire were deemed lost in hole after a two month fishing ordeal. A new patch was set across Module 7 and the well was swabbed for a significant amount of time to get it flowing. In February 2019 the well loaded up. In 2019 a plug was set above Module 12 and additional perforations were added in the UB sands. A paragon packer was set at 7010’ following the UB perfs. The well produced on steady decline until 2022. An attempt to fish the paragon packer was made in April 2022 but was unsuccessful. The well has not sustained production since. The purpose of this work/sundry is to isolate the UB perforations and prepare the well for a sidetrack. Notes Regarding Wellbore Condition x Paragon packer fish is @ 7,168’ CTM x 10.4ppg mud in 3-1/2”x9-5/8” annulus. x CINGSA Top 6694’MD (4917’TVD), Base 6945’MD (5142’ TVD) x Excape control lines have x1 flo-tek centralizer type control line protectors on each joint and SS bands above and below each connection. Slickline Procedure 1. RU Slickline and pressure control equipment. PT lubricator to 2,500 psi High / 250 psi Low 2. Drift w/ 2.75” GR to ~7100’. Look for fluid level. 3. RDMO E-Line Procedure 4. RU E-Line and pressure control equipment. PT lubricator to 2,500 psi High / 250 psi Low 5. Set 3-1/2” CIBP @ ~6950’ 6. Load tubing w/ lease/produced water. a. Provide AOGCC 24hr notice to witness pressure test and tag of plug. 7. Tag plug to confirm location and pressure test to 1500psi. 8. Dump bail 25’ of cement on top of plug (~10gals) 9. RIH and cut tubing @ ~5258’, 2’ above collar. (Pressure up tubing to equalize w/ annulus.) 10. RIH and cut tubing again at previous cut. This is to cut excape control lines behind tubing. Pressure test to 2000 psi. -bjm RWO Rev. 1 Well: CLU 08 Date: 1/14/2025 11. RDMO Eline. Pumping Procedure 12. RU pump unit and pressure test equipment. 13. Use source/lease water to confirm TxIA communication. 14. Once TxIA communication is confirmed, circulate the well over to water at max rate until clean returns. 15. Perform CMIT TXIA to 3000psi 16. RDMO pump truck Workover Procedure 17. MIRU 401 workover rig. 18. Install TWC, ND tree, NU BOP 19. Test BOPE ¾ Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. (Notify AOGCC 24 hours in advance of test to allow them to witness test). ¾ If the BOP is used to shut in on the well in a well control situation or if BOP equipment could be compromised, ALL BOP components utilized for well control or compromised must be tested prior to the next trip into the wellbore. ¾ BOPs will be closed as needed to circulate the well during this workover. 20. Pull TWC 21. Pick up on hanger 22. Pull and lay down tubing. 23. RU Eline 24. Log CBL from ~5250’ to surface. a. Contingent Drift w/ Junk basket/GR if not all bands recovered. 25. Set 9-5/8” CIBP @ ~5200’ (5’ above nearest collar) 26. RD Eline 27. ND BOP, NU dry hole tree 28. RDMO Rig 401 Attachments: 1. Current Schematic 2. Proposed Schematic 3. Rig 401 BOP Diagram 13-5/8” 4. CBL Log interval over CINGSA pool. Excape lines must be isolated with cement plug after cutting tubing. See attached email from Stefan Reed 2/6/25 with plan to set CIBP slightly deeper at 5250' MD and dump bail 25' of cement on top. Allow AOGCC opportunity to witness tag and pressure test of plug to 2000 psi. -bjm Provide 24 hrs notice for AOGCC opportunity to witness pressure test. -bjm _____________________________________________________________________________________ Updated by DMA 07-10-24 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Kenai Gas Field Well: CLU 08 Last Completed: 2004 API: 50-133-20534-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surface 121' 13-3/8"Surface 68 / K-55 / BTC 12.415 Surface 1,810' 9-5/8"Intermediate 40 / L-80 / BTC-MOD 8.835 Surface 6,722' TUBING DETAIL 3-1/2"Tubing 9.3 / L-80 / MOD 8RD 2.992 Surface 9,746' EXCAPE SYSTEM/JEWELRY DETAIL No Depth(MD)Depth(TVD)Item 16 6,952'5,149'BHP Tank Bottom @ 6,987' MD 15 7,046'5,237'Module #15 w/ conv. Flapper 14 7,149'5,333'Module #14 w/ conv. Flapper 13 7,251'5,430'Module #13 w/ conv. Flapper 13A 7,302’ 5,479' 3-1/2” Slimhole CIBP w/35’ cement – TOC @ 7,267’ 9/12/19 12 7,316'5,492'Module #12 w/ conv. Flapper 11 7,419'5,592'Module #11 w/ conv. Flapper 10 7,475'5,646'Module #10 w/ conv. Flapper 9 7,597'5,765'Module #9 w/ conv. Flapper 8 7,707'5,873'Module #8 w/ conv. Flapper 7 7,941' 6,105' Module #7 w/ Weatherford Straddle/Iso Pkr 6/15/10 6 8,001'6,165'Module #6 w/ conv. Flapper 5 8,306'6,470'Module #5 w/ conv. Flapper 4 8,385'6,549'Module #4 w/ conv. Flapper 3 8,428'6,592'Module #3 w/ conv. Flapper 2 8,515'6,679'Module #2 w/ conv. Flapper 1 N/A N/A Module #1 - No Flapper EXCAPE SYSTEM DETAILS - 15 Excape modules placed -Green control line fires bottom 7 modules. -Red control line fires top 8 modules. -Blue line for BHP monitoring. - Ceramic flapper valves below each module. CEMENTING DETAIL Casing Detail 13-38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type-1 cmt, 100% returns, 40 bbls to surface 9-5/8"12-1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G 3-1/2"8-1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt FLAPPER DETAIL Beluga Perfs Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Status Perf 16 6,993’7,003’5,187’5,196’10’Open Mod 15 7,027'7,037'5,219'5,228'10'Open Mod 14 7,130'7,140'5,315'5,325'10'Open Mod 13 7,232'7,242'5,412'5,422'10'Open Mod 12 7,297'7,307'5,474'5,484'10'Isolated Mod 11 7,400'7,410'5,573'5,583'10'Isolated Mod 10 7,456'7,466'5,627'5,637'10'Isolated Mod 9 7,578'7,588'5,746'5,756'10'Isolated Mod 8 7,688'7,698'5,854'5,864'10'Isolated Mod 7 7,922'7,932'6,086'6,096'10'Isolated Mod 6 7,982'7,992'6,146'6,156'10'Isolated Mod 5 8,287'8,297'6,451'6,461'10'Isolated Mod 4 8,366'8,376'6,530'6,540'10'Isolated Mod 3 8,409'8,419'6,573'6,583'10'Isolated Mod 2 8,496'8,506'6,660'6,670'10'Isolated Mod 1 8,990'9,000'7,154'7,164'10'Isolated Straddle Packer Assembly * Top of packer @ 7,941' MD RKB FISH DETAIL @ 7,168’ 07/05/22 2.72” X 7’ Paragon Pkr Milled to slips W/ Lamar spear, w/ 3” GS w/ 1-1/2” broken sucker rod looking up, 7/5/22 _____________________________________________________________________________________ Updated by SAR 28-Jan-2024 PROPOSED Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Kenai Gas Field Well: CLU 08 Last Completed: 2004 API: 50-133-20534-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surface 121' 13-3/8"Surface 68 / K-55 / BTC 12.415 Surface 1,810' 9-5/8"Intermediate 40 / L-80 / BTC-MOD 8.835 Surface 6,722' TUBING DETAIL 3-1/2"Tubing 9.3 / L-80 / MOD 8RD 2.992 Surface 9,746' EXCAPE SYSTEM/JEWELRY DETAIL No Depth(MD)Depth(TVD)Item 16 6,952'5,149'BHP Tank Bottom @ 6,987' MD 15 7,046'5,237'Module #15 w/ conv. Flapper 14 7,149'5,333'Module #14 w/ conv. Flapper 13 7,251'5,430'Module #13 w/ conv. Flapper 13A 7,302’ 5,479' 3-1/2” Slimhole CIBP w/35’ cement – TOC @ 7,267’ 9/12/19 12 7,316'5,492'Module #12 w/ conv. Flapper 11 7,419'5,592'Module #11 w/ conv. Flapper 10 7,475'5,646'Module #10 w/ conv. Flapper 9 7,597'5,765'Module #9 w/ conv. Flapper 8 7,707'5,873'Module #8 w/ conv. Flapper 7 7,941' 6,105' Module #7 w/ Weatherford Straddle/Iso Pkr 6/15/10 6 8,001'6,165'Module #6 w/ conv. Flapper 5 8,306'6,470'Module #5 w/ conv. Flapper 4 8,385'6,549'Module #4 w/ conv. Flapper 3 8,428'6,592'Module #3 w/ conv. Flapper 2 8,515'6,679'Module #2 w/ conv. Flapper 1 N/A N/A Module #1 - No Flapper EXCAPE SYSTEM DETAILS - 15 Excape modules placed -Green control line fires bottom 7 modules. -Red control line fires top 8 modules. -Blue line for BHP monitoring. - Ceramic flapper valves below each module. CEMENTING DETAIL Casing Detail 13-38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type-1 cmt, 100% returns, 40 bbls to surface 9-5/8"12-1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G 3-1/2"8-1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt FLAPPER DETAIL Beluga Perfs Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Status Perf 16 6,993’7,003’5,187’5,196’10’Isolated Mod 15 7,027'7,037'5,219'5,228'10'Isolated Mod 14 7,130'7,140'5,315'5,325'10'Isolated Mod 13 7,232'7,242'5,412'5,422'10'Isolated Mod 12 7,297'7,307'5,474'5,484'10'Isolated Mod 11 7,400'7,410'5,573'5,583'10'Isolated Mod 10 7,456'7,466'5,627'5,637'10'Isolated Mod 9 7,578'7,588'5,746'5,756'10'Isolated Mod 8 7,688'7,698'5,854'5,864'10'Isolated Mod 7 7,922'7,932'6,086'6,096'10'Isolated Mod 6 7,982'7,992'6,146'6,156'10'Isolated Mod 5 8,287'8,297'6,451'6,461'10'Isolated Mod 4 8,366'8,376'6,530'6,540'10'Isolated Mod 3 8,409'8,419'6,573'6,583'10'Isolated Mod 2 8,496'8,506'6,660'6,670'10'Isolated Mod 1 8,990'9,000'7,154'7,164'10'Isolated Straddle Packer Assembly * Top of packer @ 7,941' MD RKB FISH DETAIL @ 7,168’ 07/05/22 2.72” X 7’ Paragon Pkr Milled to slips W/ Lamar spear, w/ 3” GS w/ 1-1/2” broken sucker rod looking up, 7/5/22 9-5/8” CIBP set at ~5200’ 3-1/2” CIBP set at ~6950’ w/ 25’ of cement on top. Est TOC 6925’ Tubing cut @ ~5250’ See attached email from Stefan Reed 2/6/25 with plan to place cement on CIBP to isolate the cut Excape lines. -bjm 13-5/8" GK Annular Height: 54.125" Weight: 14,000 LBS 13-5/8"TYPE U Double BOP Height: 56" Width: 112" Weight 14,800 LBS TOP RAMS 2-7/8" TO 5"" MULTI-RAMS BOTTOM RAMS BLIND RAMS 13-5/8"Mud Cross W/ 4- 1/16" outlets Height:28.5" Width 31" Dual 4-1/16" 5M Manual Gate valves 4-1/16" 5M Manual Gate valve & 4-1/16" HCR Full Mud Cross Assy. width w/ valves installed Weight: 2200 lbs. Kill side Choke side Height Addition for Ring Gaskets: 0" BOP Total Height: 11.55' BOP Total weight: 31,000 LBS 13-5/8" 5m BOP Package W/ 4-1/16" 5M Valves Good Cement Top of CINGSA @ 6694' MD 9-5/8" Casing Shoe @ 6722' MD Good Cement Bottom of CINGSA @ 6945' MD Upper Beluga perfs 6993'-7003' Good Cement Sundry Application Well Name______________________________ (PTD _________; Sundry _________) Plug for Re-drill Well Workflow This process is used to identify wells that are suspended for a very short time prior to being re-drilled. Those wells that are not re-drilled immediately are identified every 6 months and assigned a current status of "Suspended." Step Task Responsible 1 The initial reviewer will check to ensure that the "Plug for Redrill" box in the upper left corner of Form 10-403 is checked. If the "Abandon" or "Suspend" boxes are also checked, cross out that erroneous entry and initial it on the Form 10-403. Geologist 2 If the “Abandon” box is checked in Box 15 (Well Status after proposed work) the initial reviewer will cross out that checkbox and instead, check the "Suspended" box and initial those changes. Geologist The drilling engineer will serve as quality control for steps 1 and 2. Petroleum Engineer (QC) 3 When the RA2 receives a Form 10-403 with a check in the "Plug for Redrill" box, they will enter the Typ_Work code "IPBRD" into the History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." Research Analyst 2 4 When the RA2 receives Form 10-407, they will check the History tab in RBDMS for the IPBRD code. If IPBRD is present and there is no evidence that a subsequent re-drill has been completed, the RA2 will assign a status of SUSPENDED to the well bore in RBDMS. The RA2 will update the status on the 10-407 form to SUSPENDED, and date and initial this change. If the RA2 does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. Research Analyst 2 5 When the Form 10-407 for the redrill is received, the RA2 will change the original well's status from SUSPENDED to ABANDONED. Research Analyst 2 6 The first week of every January and July, the RA2 and a Geologist or Reservoir Engineer will check the "Well by Type Work Outstanding" user query in RBDMS to ensure that all Plug for Redrill sundried wells have been updated to reflect current status. At this same time, they will also review the list of suspended wells for accuracy and assign expiration dates as needed. Research Analyst 2 Geologist or Reservoir Engineer 204-005 325-045 SFD 1/30/2025 CLU-08 SFD 1/30/2025 By Anne Prysunka at 3:04 pm, Jul 27, 2022 5HJJ-DPHV%2*& )URP%URRNV3KRHEH/2*& 6HQW7KXUVGD\-XO\30 7R&ROH%DUWOHZVNL &F5HJJ-DPHV%2*& 6XEMHFW5(>(;7(51$/@5()R[(QHUJ\&78&/8 $WWDFKPHQWV)R[[OV[ )ROORZ8S)ODJ)ROORZXS )ODJ6WDWXV)ODJJHG dŚĂŶŬǇŽƵ͘/͛ǀĞĂƚƚĂĐŚĞĚĂƌĞǀŝƐĞĚƌĞƉŽƌƚĐŽƌƌĞĐƚŝŶŐƚŚĞWdηƚŽƌĞĨůĞĐƚϮϬϰϬϬϱϬ͘WůĞĂƐĞƵƉĚĂƚĞǇŽƵƌĐŽƉǇ͘ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗ŽůĞĂƌƚůĞǁƐŬŝфĐďĂƌƚůĞǁƐŬŝΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗tĞĚŶĞƐĚĂǇ͕:ƵůǇϲ͕ϮϬϮϮϵ͗ϯϰD dŽ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗Z͗΀ydZE>΁Z͗&ŽǆŶĞƌŐǇdhϴϲͬϮϮͬϮϮ>hͲϬϴ dŚĂŶŬƐĨŽƌƚŚĞĐĂƚĐŚDĂ͛Ăŵ͘/ŚĂǀĞĂĚĚĞĚƚŚĞƌĞƋƵŝƌĞĚŝŶĨŽĂŶĚĂƚƚĂĐŚĞĚ͘ &ROH%DUWOHZVNL +LOFRUS$ODVND//& 6U:HOOVLWH6XSHUYLVRU5LJ0DQDJHU (PDLOFEDUWOHZVNL#KLOFRUSFRP 2IILFH &HOO +LOFRUS$ODVND//& ŽŵƉĂŶǇďƵŝůƚŽŶŶĞƌŐǇ &ƌŽŵ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ĞŶƚ͗dŚƵƌƐĚĂǇ͕:ƵŶĞϯϬ͕ϮϬϮϮϰ͗ϭϮWD dŽ͗ŽůĞĂƌƚůĞǁƐŬŝфĐďĂƌƚůĞǁƐŬŝΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗΀ydZE>΁Z͗&ŽǆŶĞƌŐǇdhϴϲͬϮϮͬϮϮ>hͲϬϴ ŽůĞ͕ dŚĞϮϰŚƌŶŽƚŝĐĞĚĂƚĞĂŶĚƚŝŵĞǁĂƐďůĂŶŬ͖ƉůĞĂƐĞĂĚǀŝƐĞ͘ dŚĂŶŬǇŽƵ͕ &DQQHU\/RRS8QLW 37' WŚŽĞďĞ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗ŽůĞĂƌƚůĞǁƐŬŝфĐďĂƌƚůĞǁƐŬŝΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗DŽŶĚĂǇ͕:ƵŶĞϮϳ͕ϮϬϮϮϭϭ͗ϰϬWD dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх͖ ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх Đ͗ŽŶŶĂŵďƌƵǌфĚĂŵďƌƵǌΛŚŝůĐŽƌƉ͘ĐŽŵх͖:ƵĂŶŝƚĂ>ŽǀĞƚƚфũůŽǀĞƚƚΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗&ŽǆŶĞƌŐǇdhϴϲͬϮϮͬϮϮ>hͲϬϴ 'ŽŽĚĞǀĞŶŝŶŐ͕ ƚƚĂĐŚĞĚŝƐƚŚĞKWƚĞƐƚƌĞƉŽƌƚĨŽƌ&ŽǆdhϴŽŶ>hͲϬϴƉĞƌĨŽƌŵĞĚϲͬϮϮͬϮϮ &ROH%DUWOHZVNL +LOFRUS$ODVND//& 6U:HOOVLWH6XSHUYLVRU (PDLOFEDUWOHZVNL#KLOFRUSFRP 2IILFH &HOO +LOFRUS$ODVND//& ŽŵƉĂŶǇďƵŝůƚŽŶŶĞƌŐǇ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:8 DATE: 6/22/22 Rig Rep.: Rig Phone: (907)887-1766 Operator: Op. Phone:(907)632-4113 Rep.: E-Mail Well Name: PTD #2040050 Sundry #322-215 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/3500 Annular:NA Valves:250/3500 MASP:450 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 0NA Standing Order Posted NA Misc.NA 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 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 1.75" BS P Flow Indicator NA NA #2 Rams 1 1.75" PS P Meth Gas Detector NA NA #3 Rams 0 N/A NA H2S Gas Detector NA NA #4 Rams 0 N/A NA MS Misc 0NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA Quantity Test Result Choke Ln. Valves 2 2"P Inside Reel valves 1P HCR Valves 0 N/A NA Kill Line Valves 2 2"P Check Valve 0 N/A NA ACCUMULATOR SYSTEM: BOP Misc 0 N/A NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)2500 P Quantity Test Result 200 psi Attained (sec)5 P No. Valves 5P Full Pressure Attained (sec)13 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): N/A NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:4.5 Hours Repair or replacement of equipment will be made within N/A days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/21/22@19:34 Waived By Test Start Date/Time:6/22/2022 9:00 (date) (time)Witness Test Finish Date/Time:6/22/2022 13:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Accumulator precharge pressure 1400 psi Terence Rais Hilcorp Alaska Cole Bartlewski CLU-08 Test Pressure (psi): cbartlewski@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0622_BOP_Fox8_CLU-8 9 9 99 9 9 9 9 9 9 9 MEU -5HJJ 5HJJ-DPHV%2*& )URP.DUVRQ.R]XE&NNR]XE#KLOFRUSFRP! 6HQW7KXUVGD\-XQH30 7R5HJJ-DPHV%2*&'2$$2*&&3UXGKRH%D\%URRNV3KRHEH/2*& 6XEMHFW%23(WHVW)R[&78&/8&DQQHU\/RRS8QLW $WWDFKPHQWV)R[&/8%237HVW[OV[ 'ŽŽĚĨƚĞƌŶŽŽŶ͕ ƚƚĂĐŚĞĚŝƐƚŚĞKWƚĞƐƚĨŽƌŵĨŽƌ&ŽǆϴĐŽŝůƚƵďŝŶŐƵŶŝƚŽŶĂŶŶĞƌǇ>ŽŽƉ>hͲϬϴ͘ ZĞŐĂƌĚƐ͕ KarsonKozub ǣΪͳȋͻͲ͹Ȍͷ͹ͲǦͳͺͲͳ ̷Ǥ &ƌŽŵ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх ^ĞŶƚ͗dƵĞƐĚĂǇ͕:ƵŶĞϮϴ͕ϮϬϮϮϴ͗ϰϯD dŽ͗<ĂƌƐŽŶ<ŽǌƵďͲ;ͿфŬŬŽǌƵďΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗΀ydZE>΁Z͗K'dĞƐƚtŝƚŶĞƐƐEŽƚŝĨŝĐĂƚŝŽŶZĞƋƵĞƐƚ͗KW͕&Žǆdhϴ͕>hͲϬϴ͕ĂŶŶĞƌǇ>ŽŽƉhŶŝƚ K'ǁŝƚŶĞƐƐŝƐǁĂŝǀĞĚ ^ĞŶƚǀŝĂƚŚĞ^ĂŵƐƵŶŐ'ĂůĂǆǇ^ϮϭhůƚƌĂϱ'͕ĂŶdΘdϱ'ƐŵĂƌƚƉŚŽŶĞ ͲͲͲͲͲͲͲͲKƌŝŐŝŶĂůŵĞƐƐĂŐĞͲͲͲͲͲͲͲͲ &ƌŽŵ͗ΗĐĞĚͲƐǀĐͲŽŐĐĨŽƌŵƐ;ƐƉŽŶƐŽƌĞĚͿΗфĐĞĚͲŽŐĐͲũŽƚĨŽƌŵƐΛĂůĂƐŬĂ͘ŐŽǀх ĂƚĞ͗ϲͬϮϴͬϮϮϳ͗ϰϴD;'DdͲϬϵ͗ϬϬͿ dŽ͗KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗K'dĞƐƚtŝƚŶĞƐƐEŽƚŝĨŝĐĂƚŝŽŶZĞƋƵĞƐƚ͗KW͕&Žǆdhϴ͕>hͲϬϴ͕ĂŶŶĞƌǇ>ŽŽƉhŶŝƚ 7RKHOSSURWHFW\RXUSULY DF\0LFURVRIW2IILFHSUHYHQWHGDXWRPDWLFGRZQORDGRIWKLVSLFWXUHIURPWKH,QWHUQHWMRWIRUPFRP YƵĞƐƚŝŽŶŶƐǁĞƌ dǇƉĞŽĨdĞƐƚZĞƋƵĞƐƚĞĚ͗KW ZĞƋƵĞƐƚĞĚdŝŵĞĨŽƌ /ŶƐƉĞĐƚŝŽŶϬϲͲϮϵͲϮϬϮϮϴ͗ϬϬD >ŽĐĂƚŝŽŶ&Žǆdhϴ͕>hͲϬϴ͕ĂŶŶĞƌǇ>ŽŽƉhŶŝƚ 6RPHSHRSOHZKRUHFHLYHGWKLVPHVVDJHGRQ WRIWHQJHWHPDLOIURPNNR]XE#KLOFRUSFRP/HDUQZK\WKLVLVLPSRUWDQW &$87,217KLVHPDLORULJLQDWHGIURPRXWVLGHWKH6WDWHRI$ODVNDPDLOV\VWHP'RQRWFOLFNOLQNVRURSHQ DWWDFKPHQWVXQOHVV\RXUHFRJQL]HWKHVHQGHUDQGNQRZWKHFRQWHQWLVVDIH &DQQHU\/RRS8QLW 37' EĂŵĞ<ĂƌƐŽŶ<ŽǌƵď ͲŵĂŝůŬŬŽǌƵďΛŚŝůĐŽƌƉ͘ĐŽŵ WŚŽŶĞEƵŵďĞƌ;ϵϬϳͿ ϱϳϬͲϭϴϬϭ ŽŵƉĂŶǇ,ŝůĐŽƌƉ KƚŚĞƌ/ŶĨŽƌŵĂƚŝŽŶ͗KWƚĞƐƚĨŽƌĐŽŝůƚƵďŝŶŐŵŝůůŝŶŐĂŶĚĐůĞĂŶͲŽƵƚ ^ƵďŵŝƐƐŝŽŶ/͗ϱϯϮϮϰϬϱϬϬϰϱϵϱϵϮϰϲϲϭ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:8 DATE: 6/29/22 Rig Rep.: Rig Phone: (907)887-1766 Operator: Op. Phone:(907)570-1801 Rep.: E-Mail Well Name: PTD #2040050 Sundry #322-215 Operation: Drilling: Workover: X Explor.: Test: Initial: Weekly: X Bi-Weekly: Other: Rams:250/3500 Annular:N/A Valves:250/3500 MASP:450 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 0NA Standing Order Posted NA Misc.NA 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 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 1.75" BS P Flow Indicator NA NA #2 Rams 1 1.75" PS P Meth Gas Detector NA NA #3 Rams 0 N/A NA H2S Gas Detector NA NA #4 Rams 0 N/A NA MS Misc 0NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA Quantity Test Result Choke Ln. Valves 2 2"P Inside Reel valves 1P HCR Valves 0 N/A NA Kill Line Valves 2 2"P Check Valve 0 N/A NA ACCUMULATOR SYSTEM: BOP Misc 0 N/A NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)2500 P Quantity Test Result 200 psi Attained (sec)4 P No. Valves 5P Full Pressure Attained (sec)14 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): N/A NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:3.0 Hours Repair or replacement of equipment will be made within N/A days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/22/22 07:48hrs Waived By Test Start Date/Time:6/29/2022 7:30 (date) (time)Witness Test Finish Date/Time:6/29/2022 10:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Accumulator precharge pressure 1400 psi Terence Rais Hilcorp Alaska Karson Kozub CLU-08 Test Pressure (psi): kkozub@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0629_BOP_Fox8_CLU-08 9 999 99 9 9 9 9 9 MEU -5HJJ 5HJJ-DPHV%2*& )URP0LFKDHO+LEEHUW&0LFKDHO+LEEHUW#KLOFRUSFRP! 6HQW)ULGD\0D\$0 7R5HJJ-DPHV%2*&%URRNV3KRHEH/2*&'2$$2*&&3UXGKRH%D\ &F-XDQLWD/RYHWW&KDG+HOJHVRQ 6XEMHFW&/8%23(7HVW5HSRUW $WWDFKPHQWV&/8%237HVW[OV[ 'ŽŽĚĞǀĞŶŝŶŐ͕ ƚƚĂĐŚĞĚŝƐƚŚĞKWƚĞƐƚƌĞƉŽƌƚƉĞƌĨŽƌŵĞĚǁŝƚŚ&ŽǆŶĞƌŐǇdhϴ͘WůĞĂƐĞůĞƚŵĞŬŶŽǁŝĨƚŚĞƌĞĂƌĞĂŶǇƋƵĞƐƚŝŽŶƐ͘ dŚĂŶŬƐ͕ DŝĐŚĂĞů,ŝďďĞƌƚ tĞůůƐŝƚĞ^ƵƉĞƌǀŝƐŽƌ ,ŝůĐŽƌƉůĂƐŬĂ ϵϬϳͲϵϬϯͲϱϵϵϬ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:8 DATE: 5/24/22 Rig Rep.: Rig Phone: (907)887-1766 Operator: Op. Phone:(907)632-4113 Rep.: E-Mail Well Name: PTD #2040050 Sundry #322-215 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/3500 Annular:N/A Valves:250/3500 MASP:450 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 0NA Standing Order Posted NA Misc.NA 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 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 1.75" BS P Flow Indicator NA NA #2 Rams 1 1.75" PS P Meth Gas Detector NA NA #3 Rams 0 N/A NA H2S Gas Detector NA NA #4 Rams 0 N/A NA MS Misc 0NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA Quantity Test Result Choke Ln. Valves 2 2"P Inside Reel valves 1P HCR Valves 0 N/A NA Kill Line Valves 2 2"P Check Valve 0 N/A NA ACCUMULATOR SYSTEM: BOP Misc 0 N/A NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)2500 P Quantity Test Result 200 psi Attained (sec)4 P No. Valves 5P Full Pressure Attained (sec)11 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): N/A NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:3.5 Hours Repair or replacement of equipment will be made within N/A days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 5/23/22 1:07PM Waived By Test Start Date/Time:5/24/2022 12:00 (date) (time)Witness Test Finish Date/Time:5/24/2022 15:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Accumulator precharge pressure 1400 psi Terence Rais Hilcorp Alaska Michael Hibbert CLU-08 Test Pressure (psi): Michael.Hibbert@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0524_BOP_Fox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a &DQQHU\/RRS8QLW&/8 3 W V )RUP5HYLVHG$SSURYHGDSSOLFDWLRQLVYDOLGIRUPRQWKVIURPWKHGDWHRIDSSURYDO By Samantha Carlisle at 10:09 am, Apr 19, 2022 'LJLWDOO\VLJQHGE\'DQ0DUORZH '1FQ 'DQ0DUORZH RX 8VHUV 'DWH 'DQ0DUORZH %-0 '/%'65 ; 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Use Gamma/CCL to correlate H ,QVWDOO&U\VWDOJDXJHVRUYHULI\37VDUHRSHQWR6&$'$EHIRUHSHUIRUDWLQJ5HFRUGWXELQJ SUHVVXUHVEHIRUHDQGDIWHUHDFKSHUIRUDWLQJUXQDWPLQPLQDQGPLQLQWHUYDOVSRVW VKRW f.7KHVHVDQGVDUHJRYHUQHGE\&RQVHUYDWLRQ2UGHU$TVD distance from bottom CINGSA to Top Shot UB4 is 219’ ϭϳ͘ZͲ>ŝŶĞ͘ ϭϴ͘dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ƵƌƌĞŶƚ^ĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘^ƚĂŶĚĂƌĚtĞůůWƌŽĐĞĚƵƌĞʹEϮKƉĞƌĂƚŝŽŶƐ CINGSA to Top Shot UB4 is 219’ 7KHVHVDQGVDUHJRYHUQHGE\&RQVHUYDWLRQ2UGHU$TVD distance from bottomJ\ '/% BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇ,ϬϰͬϭϴͬϮϮ ^,Dd/&RRN,QOHW%DVLQ$ODVND 0LGGOH*URXQG6KRDO /DVW&RPSOHWHG 2LO:HOO!:DWHULQMHFWRU!*DVSURGXFHU IRU3ODWIRUP <ĞŶĂŝ'ĂƐ&ŝĞůĚ tĞůů͗>hϬϴ >ĂƐƚŽŵƉůĞƚĞĚ͗ϮϬϬϰ W/͗ϱϬͲϭϯϯͲϮϬϱϯϰͲϬϬͲϬϬ ^/E'd/> ^ŝǌĞdǇƉĞtƚͬ'ƌĂĚĞͬŽŶŶ/dŽƉƚŵ ϮϬΗŽŶĚƵĐƚŽƌϭϯϯͬ<ͲϱϱͬEͬϭϴ͘ϳϯ^ƵƌĨĂĐĞϭϮϭΖ ϭϯͲϯͬϴΗ^ƵƌĨĂĐĞϲϴͬ<ͲϱϱͬdϭϮ͘ϰϭϱ^ƵƌĨĂĐĞϭ͕ϴϭϬΖ ϵͲϱͬϴΗ/ŶƚĞƌŵĞĚŝĂƚĞϰϬͬ>ͲϴϬͬdͲDKϴ͘ϴϯϱ^ƵƌĨĂĐĞϲ͕ϳϮϮΖ dh/E'd/> ϯͲϭͬϮΗdƵďŝŶŐϵ͘ϯͬ>ͲϴϬͬDKϴZϮ͘ϵϵϮ^ƵƌĨĂĐĞϵ͕ϳϰϲΖ yW^z^dDͬ:t>Zzd/> EŽĞƉƚŚ;DͿĞƉƚŚ;dsͿ/ƚĞŵ ϭϲϲ͕ϵϱϮΖϱ͕ϭϰϵΖ,WdĂŶŬŽƚƚŽŵΛϲ͕ϵϴϳΖD ϭϱϳ͕ϬϭϬ͛ϱ͕ϮϬϯ͛Ϯ͘ϳϮ͟yϳ͛WĂƌĂŐŽŶWŬƌϭϭͬϭϴͬϭϵ ϭϱϳ͕ϬϰϲΖϱ͕ϮϯϳΖDŽĚƵůĞηϭϱǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭϰϳ͕ϭϰϵΖϱ͕ϯϯϯΖDŽĚƵůĞηϭϰǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭϯϳ͕ϮϱϭΖϱ͕ϰϯϬΖDŽĚƵůĞηϭϯǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭϯϳ͕ϯϬϮ͛ ϱ͕ϰϳϵΖ ϯͲϭͬϮ͟^ůŝŵŚŽůĞ/Wǁͬϯϱ͛ ĐĞŵĞŶƚʹdKΛϳ͕Ϯϲϳ͛ϵͬϭϮͬϭϵ ϭϮϳ͕ϯϭϲΖϱ͕ϰϵϮΖDŽĚƵůĞηϭϮǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭϭϳ͕ϰϭϵΖϱ͕ϱϵϮΖDŽĚƵůĞηϭϭǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭϬϳ͕ϰϳϱΖϱ͕ϲϰϲΖDŽĚƵůĞηϭϬǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϵϳ͕ϱϵϳΖϱ͕ϳϲϱΖDŽĚƵůĞηϵǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϴϳ͕ϳϬϳΖϱ͕ϴϳϯΖDŽĚƵůĞηϴǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϳϳ͕ϵϰϭΖ ϲ͕ϭϬϱΖ DŽĚƵůĞηϳǁͬtĞĂƚŚĞƌĨŽƌĚ ^ƚƌĂĚĚůĞͬ/ƐŽWŬƌϲͬϭϱͬϭϬ ϲϴ͕ϬϬϭΖϲ͕ϭϲϱΖDŽĚƵůĞηϲǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϱϴ͕ϯϬϲΖϲ͕ϰϳϬΖDŽĚƵůĞηϱǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϰϴ͕ϯϴϱΖϲ͕ϱϰϵΖDŽĚƵůĞηϰǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϯϴ͕ϰϮϴΖϲ͕ϱϵϮΖDŽĚƵůĞηϯǁͬĐŽŶǀ͘&ůĂƉƉĞƌ Ϯϴ͕ϱϭϱΖϲ͕ϲϳϵΖDŽĚƵůĞηϮǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭEͬEͬDŽĚƵůĞηϭͲEŽ&ůĂƉƉĞƌ yW^z^dDd/>^ ͲϭϱǆĐĂƉĞŵŽĚƵůĞƐƉůĂĐĞĚ Ͳ'ƌĞĞŶĐŽŶƚƌŽůůŝŶĞĨŝƌĞƐďŽƚƚŽŵϳŵŽĚƵůĞƐ͘ ͲZĞĚĐŽŶƚƌŽůůŝŶĞĨŝƌĞƐƚŽƉϴŵŽĚƵůĞƐ͘ ͲůƵĞůŝŶĞĨŽƌ,WŵŽŶŝƚŽƌŝŶŐ͘ ͲĞƌĂŵŝĐĨůĂƉƉĞƌǀĂůǀĞƐďĞůŽǁĞĂĐŚŵŽĚƵůĞ͘ DEd/E'd/> ĂƐŝŶŐĞƚĂŝů ϭϯͲϯϴΗϭϲΗŚŽůĞŵƚǁͬƐŬƐ;ϮϮϵďďůͿŽĨϭϮ͘ϬƉƉŐ͕dǇƉĞͲϭĐŵƚ͕ϭϬϬйƌĞƚƵƌŶƐ͕ϰϬďďůƐƚŽƐƵƌĨĂĐĞ ϵͲϱͬϴΗϭϮͲϭͬϰΗŚŽůĞŵƚǁͬ>ĞĂĚϯϮϬƐŬƐ;ϭϮϬďďůƐͿϭϮ͘ϱƉƉŐŽĨĐůĂƐƐ'͕dĂŝůϮϯϱƐŬƐ;ϰϴ͘ϱďďůƐͿϭϱ͘ϴƉƉŐĐůĂƐƐ' ϯͲϭͬϮΗϴͲϭͬϮΗŚŽůĞŵƚǁͬϭ͕ϰϯϬƐŬƐ;ϮϵϯďďůƐͿŽĨϭϱ͘ϴƉƉŐ͕ĐůĂƐƐ'Đŵƚ &>WWZd/> ĞůƵŐĂ WĞƌĨƐ dŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ&d^ƚĂƚƵƐ DŽĚϭϲϲ͕ϵϵϯ͛ϳ͕ϬϬϯ͛ϱ͕ϭϴϳ͛ϱ͕ϭϵϲ͛ϭϬ͛KƉĞŶ DŽĚϭϱϳ͕ϬϮϳΖϳ͕ϬϯϳΖϱ͕ϮϭϵΖϱ͕ϮϮϴΖϭϬΖKƉĞŶ DŽĚϭϰϳ͕ϭϯϬΖϳ͕ϭϰϬΖϱ͕ϯϭϱΖϱ͕ϯϮϱΖϭϬΖKƉĞŶ DŽĚϭϯϳ͕ϮϯϮΖϳ͕ϮϰϮΖϱ͕ϰϭϮΖϱ͕ϰϮϮΖϭϬΖKƉĞŶ DŽĚϭϮϳ͕ϮϵϳΖϳ͕ϯϬϳΖϱ͕ϰϳϰΖϱ͕ϰϴϰΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϭϭϳ͕ϰϬϬΖϳ͕ϰϭϬΖϱ͕ϱϳϯΖϱ͕ϱϴϯΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϭϬϳ͕ϰϱϲΖϳ͕ϰϲϲΖϱ͕ϲϮϳΖϱ͕ϲϯϳΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϵϳ͕ϱϳϴΖϳ͕ϱϴϴΖϱ͕ϳϰϲΖϱ͕ϳϱϲΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϴϳ͕ϲϴϴΖϳ͕ϲϵϴΖϱ͕ϴϱϰΖϱ͕ϴϲϰΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϳϳ͕ϵϮϮΖϳ͕ϵϯϮΖϲ͕ϬϴϲΖϲ͕ϬϵϲΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϲϳ͕ϵϴϮΖϳ͕ϵϵϮΖϲ͕ϭϰϲΖϲ͕ϭϱϲΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϱϴ͕ϮϴϳΖϴ͕ϮϵϳΖϲ͕ϰϱϭΖϲ͕ϰϲϭΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϰϴ͕ϯϲϲΖϴ͕ϯϳϲΖϲ͕ϱϯϬΖϲ͕ϱϰϬΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϯϴ͕ϰϬϵΖϴ͕ϰϭϵΖϲ͕ϱϳϯΖϲ͕ϱϴϯΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϮϴ͕ϰϵϲΖϴ͕ϱϬϲΖϲ͕ϲϲϬΖϲ͕ϲϳϬΖϭϬΖ/ƐŽůĂƚĞĚ DŽĚϭϴ͕ϵϵϬΖϵ͕ϬϬϬΖϳ͕ϭϱϰΖϳ͕ϭϲϰΖϭϬΖ/ƐŽůĂƚĞĚ ^ƚƌĂĚĚůĞWĂĐŬĞƌƐƐĞŵďůǇ ΎdŽƉŽĨƉĂĐŬĞƌΛϳ͕ϵϰϭΖDZ< BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇ,ϬϰͬϭϵͬϮϮ WZKWK^&RRN,QOHW%DVLQ$ODVND 0LGGOH*URXQG6KRDO /DVW&RPSOHWHG 2LO:HOO!:DWHULQMHFWRU!*DVSURGXFHU IRU3ODWIRUP <ĞŶĂŝ'ĂƐ&ŝĞůĚ tĞůů͗>hϬϴ >ĂƐƚŽŵƉůĞƚĞĚ͗ϮϬϬϰ W/͗ϱϬͲϭϯϯͲϮϬϱϯϰͲϬϬͲϬϬ ^/E'd/> ^ŝǌĞdǇƉĞtƚͬ'ƌĂĚĞͬŽŶŶ/dŽƉƚŵ ϮϬΗŽŶĚƵĐƚŽƌϭϯϯͬ<ͲϱϱͬEͬϭϴ͘ϳϯ^ƵƌĨĂĐĞϭϮϭΖ ϭϯͲϯͬϴΗ^ƵƌĨĂĐĞϲϴͬ<ͲϱϱͬdϭϮ͘ϰϭϱ^ƵƌĨĂĐĞϭ͕ϴϭϬΖ ϵͲϱͬϴΗ/ŶƚĞƌŵĞĚŝĂƚĞϰϬͬ>ͲϴϬͬdͲDKϴ͘ϴϯϱ^ƵƌĨĂĐĞϲ͕ϳϮϮΖ dh/E'd/> ϯͲϭͬϮΗdƵďŝŶŐϵ͘ϯͬ>ͲϴϬͬDKϴZϮ͘ϵϵϮ^ƵƌĨĂĐĞϵ͕ϳϰϲΖ yW^z^dDͬ:t>Zzd/> EŽĞƉƚŚ;DͿĞƉƚŚ;dsͿ/ƚĞŵ ϭϲϲ͕ϵϱϮΖϱ͕ϭϰϵΖ,WdĂŶŬŽƚƚŽŵΛϲ͕ϵϴϳΖD ϭϱϳ͕ϬϭϬ͛ϱ͕ϮϬϯ͛Ϯ͘ϳϮ͟yϳ͛WĂƌĂŐŽŶWŬƌϭϭͬϭϴͬϭϵ ϭϱϳ͕ϬϰϲΖϱ͕ϮϯϳΖDŽĚƵůĞηϭϱǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭϰϳ͕ϭϰϵΖϱ͕ϯϯϯΖDŽĚƵůĞηϭϰǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭϯϳ͕ϮϱϭΖϱ͕ϰϯϬΖDŽĚƵůĞηϭϯǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭϯϳ͕ϯϬϮ͛ ϱ͕ϰϳϵΖ ϯͲϭͬϮ͟^ůŝŵŚŽůĞ/Wǁͬϯϱ͛ ĐĞŵĞŶƚʹdKΛϳ͕Ϯϲϳ͛ϵͬϭϮͬϭϵ ϭϮϳ͕ϯϭϲΖϱ͕ϰϵϮΖDŽĚƵůĞηϭϮǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭϭϳ͕ϰϭϵΖϱ͕ϱϵϮΖDŽĚƵůĞηϭϭǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭϬϳ͕ϰϳϱΖϱ͕ϲϰϲΖDŽĚƵůĞηϭϬǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϵϳ͕ϱϵϳΖϱ͕ϳϲϱΖDŽĚƵůĞηϵǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϴϳ͕ϳϬϳΖϱ͕ϴϳϯΖDŽĚƵůĞηϴǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϳϳ͕ϵϰϭΖ ϲ͕ϭϬϱΖ DŽĚƵůĞηϳǁͬtĞĂƚŚĞƌĨŽƌĚ ^ƚƌĂĚĚůĞͬ/ƐŽWŬƌϲͬϭϱͬϭϬ ϲϴ͕ϬϬϭΖϲ͕ϭϲϱΖDŽĚƵůĞηϲǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϱϴ͕ϯϬϲΖϲ͕ϰϳϬΖDŽĚƵůĞηϱǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϰϴ͕ϯϴϱΖϲ͕ϱϰϵΖDŽĚƵůĞηϰǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϯϴ͕ϰϮϴΖϲ͕ϱϵϮΖDŽĚƵůĞηϯǁͬĐŽŶǀ͘&ůĂƉƉĞƌ Ϯϴ͕ϱϭϱΖϲ͕ϲϳϵΖDŽĚƵůĞηϮǁͬĐŽŶǀ͘&ůĂƉƉĞƌ ϭEͬEͬDŽĚƵůĞηϭͲEŽ&ůĂƉƉĞƌ yW^z^dDd/>^ ͲϭϱǆĐĂƉĞŵŽĚƵůĞƐƉůĂĐĞĚ Ͳ'ƌĞĞŶĐŽŶƚƌŽůůŝŶĞĨŝƌĞƐďŽƚƚŽŵϳŵŽĚƵůĞƐ͘ ͲZĞĚĐŽŶƚƌŽůůŝŶĞĨŝƌĞƐƚŽƉϴŵŽĚƵůĞƐ͘ ͲůƵĞůŝŶĞĨŽƌ,WŵŽŶŝƚŽƌŝŶŐ͘ ͲĞƌĂŵŝĐĨůĂƉƉĞƌǀĂůǀĞƐďĞůŽǁĞĂĐŚŵŽĚƵůĞ͘ DEd/E'd/> ĂƐŝŶŐĞƚĂŝů ϭϯͲϯϴΗϭϲΗŚŽůĞŵƚǁͬƐŬƐ;ϮϮϵďďůͿŽĨϭϮ͘ϬƉƉŐ͕dǇƉĞͲϭĐŵƚ͕ϭϬϬйƌĞƚƵƌŶƐ͕ϰϬďďůƐƚŽƐƵƌĨĂĐĞ ϵͲϱͬϴΗϭϮͲϭͬϰΗŚŽůĞŵƚǁͬ>ĞĂĚϯϮϬƐŬƐ;ϭϮϬďďůƐͿϭϮ͘ϱƉƉŐŽĨĐůĂƐƐ'͕dĂŝůϮϯϱƐŬƐ;ϰϴ͘ϱďďůƐͿϭϱ͘ϴƉƉŐĐůĂƐƐ' ϯͲϭͬϮΗϴͲϭͬϮΗŚŽůĞŵƚǁͬϭ͕ϰϯϬƐŬƐ;ϮϵϯďďůƐͿŽĨϭϱ͘ϴƉƉŐ͕ĐůĂƐƐ'Đŵƚ &>WWZd/> ĞůƵŐĂ WĞƌĨƐ dŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ&d^ƚĂƚƵƐ DŽĚϭϲϲ͕ϵϵϯ͛ϳ͕ϬϬϯ͛ϱ͕ϭϴϳ͛ϱ͕ϭϵϲ͛ϭϬ͛KƉĞŶ DŽĚϭϱϳ͕ϬϮϳΖϳ͕ϬϯϳΖϱ͕ϮϭϵΖϱ͕ϮϮϴΖϭϬΖKƉĞŶ DŽĚϭϰϳ͕ϭϯϬΖϳ͕ϭϰϬΖϱ͕ϯϭϱΖϱ͕ϯϮϱΖϭϬΖKƉĞŶ hϰцϳ͕ϭϳϴ͛цϳ͕ϭϴϰ͛цϱ͕ϯϲϭ͛цϱ͕ϯϲϭ͛цϲWƌŽƉŽƐĞĚ hϰцϳ͕ϮϬϲ͛цϳ͕Ϯϭϴ͛цϱ͕ϯϴϳ͛цϱ͕ϯϵϵ͛цϭϮWƌŽƉŽƐĞĚ DŽĚϭϯϳ͕ϮϯϮΖϳ͕ϮϰϮΖϱ͕ϰϭϮΖϱ͕ϰϮϮΖϭϬΖKƉĞŶ DŽĚϭϮϳ͕ϮϵϳΖϳ͕ϯϬϳΖϱ͕ϰϳϰΖϱ͕ϰϴϰΖϭϬΖ/ƐŽůĂƚĞĚ 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SEP 2019 CLU 8 x CLU 98 T6w1D3D 08 EP19 CL1LQ8._TMD3D_GBSEPI9_img CLU 08 TIVIM_06SEP19 DECEIVE® NOV 0 4 2019 A®GCC 9,116120102:25PM PDF Document 9/15/2019 2:25 PM TIFF File 9/16/2019 2:22 PM LAS Fite Please include current contact information if different from above. 4,789 KB 9„139 KB 4,094 KB Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 ( L --F. From: Schwartz, Guy L (CED) Sent: Monday, October 28, 2019 2:41 PM To: To York'; Davies, Stephen F (CED); Roby, David S (CED) Cc: Chris Walgenbach; Anthony McConkey, 'John Lau' Subject: RE: [EXTERNAL] RE: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Bo, Hilcorp has approval to flow CLU -08 with the following conditions: 1) Flow CLU -08 with isolation plug in place to insure UB -B zone material balance data is accurate. 2) Update flowing P/Z vs cum material balance data at least weekly and provide plots to both CINGSA and AOGCC on a monthly basis. 3) Take static (SIWHP) pressures as needed to confirm the static P/Z plot correlate. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guv schwartz@alaska aov). From: Bo York <byork@hilcorp.com> Sent: Monday, October 28, 2019 6:43 AM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov>; Roby, David S (CED) <dave. roby@alaska.gov> Cc: Chris Walgenbach <cwalgenbach@hilcorp.com>; Anthony McConkey <amcconkey@hilcorp.com> Subject: RE: [EXTERNAL] RE: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Guy, Steve, and Dave, Latest pressures through yesterday presented below. S-2 and S-3 are the CINGSA wells. Please let me know if you'd like to discuss. Hilcorp's positions remains that we would like to bring CLU -08 BOL as laid out in the below messages. Thank you. Bo Thank you. Bo York Hilcorp Alaska LLC Kenai Operations Manager byork(c@Hilcoro.com 907.777.8345 907.727.9247 cell From: John Lau[mailto:John.Lau@enstarnaturalgas com] Sent: Friday, October 25, 2019 9:54 AM To: Bo York <byork(o)hilcoro.com>; Matthew Federle <Matthew.Federle@enstarnaturalgas com>; 'Schwartz, Guy L (CED)' <guy.schwartz@alaska.gov>; 'Davies, Stephen F (CED)' <steve.davies@alaska.gov>; 'dave.roby@alaska.gov' <dave. robv@a laska.gov> Cc: Chris Walgenbach <cwalgenbach@hilcoro.com>; Anthony McConkey <amcconkev@hilcoro.com> Subject: RE: [EXTERNAL] RE: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand In Comparing CLU -08 to CLUS-3 is not necessarily the best indicator. S-3 was not perforated in the lower internals and has always lagged the other 4 wells in the semiannual shut in tests. Abetter comparison might be with S-2 which is currently at a pressure of 1505 psi. We would prefer to leave SLU-8 shut in until we finish this Monday. We would also like to define a process where both entities to collaborate production data associated with CINGSA and the Hilcorp wells that may be perforated in the upper Beluga sands. John John J Lau PE ENSTAR Natural Gas Vice President Operations John. Lau@enstarnaturalgas.com (907)-334-7736 Office (907)-244-3980 Cell From: Bo York <byork@hilcoro.com> Sent: Friday, October 25, 2019 8:56 AM To: Matthew Federle <Matthew.Federle @enstarnaturalgas com>; John Lau <John.Lau @enstarnaturalgas com>; 'Schwartz, Guy L (CED)' <guy.schwartz@alaska.gov>, 'Davies, Stephen F (CED)' <steve.davies@alaska.gov>; 'dave.roby@alaska.gov' <dave.robv@alaska gov> Cc: Chris Walgenbach <cwalgenbach@hilcorp.com>; Anthony McConkey <amcconkev@hilcoro.com> Subject: RE: [EXTERNAL] RE: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand EXTERNAL EMAIL Use caution when opening links and attachments, replying to requests for information and when prompted to enter User IDs or Passwords. Fiefdi Cannery Loop Current Status: Flowing IM Wp: 0.000 Mstb Qcond: 0.000 Math • Legend ■• FlowingprC" 12e 11e 100 900 Soo 700 600 5W 400 300 200 Origi leas- Place 10D 0 1.00 0.10 0.20 0.30 0.40 "0 0.60 0.70 0.80 0.90 1.00 1.10 1.20 1,30 1.40 1.50 Cumulative Gas Production (Bscf) From: Matthew Federle [mailto:Matthew.Federle@enstarnaturalgas com] Sent: Thursday, October 24, 2019 12:43 PM To: Bo York <byork@hilcorp.com>; 'Schwartz, Guy L (CED)' <guy.schwartz(c@alaska.gov>; 'Davies, Stephen F (CED)' <steve.davies@alaska.gov>; 'dave.roby@alaska.gov' <dave.robv@alaska.gov> Cc: Chris Walgenbach <cwalgenbach@hilcorp.com>; Anthony McConkey <amcconkev@hilcorp.com>; Jason Westervelt <Jason.Westervelt@enstarnaturaleas.com>; John Lau <John.Lau@enstarnaturaigas.com> Subject: RE: [EXTERNAL] RE: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Until CINGSA has the opportunity to review the data we would prefer the well remains shut in. Our current surface pressure in CLU -08 (PTD 204-005) is now 1533.3 psi as of noon. CINGSA continues to be stable at 1,421 psi in their Well #3. The CLU -08 pressure continues to slowly climb, having climbed about 6 psi in the last 24 hours. So at this point our pressure differential between CLU -08 and CINGSA Well #3 is 112 psi and growing, indicating that we are not in communication with the Sterling C sands (CINGSA storage sands). Given that our pressure continues to diverge from the CINGSA pressure, I am requesting to pull the plug we set in CLU -08 below our open perfs in the Upper Beluga (UB) — B sand and put the well back on production. Keeping the well shut in through the duration of the CINGSA shut in will not provide any additional information that we would use to make a decision on bringing the well BOL. Some added information is presented below for the lateral distance between CLU -08 and CINGSA #3. CINGSA #3 well is the closest well to CLU -08 at about 425' at around 4,950' TVD as depicted in the below graphic. The two crosses are placed at the 4,950' depth. In case you can't read it very well, the top track is CLU -08 and the bottom track is CINGSA #3. �PUn W. - A[ewtC-mny Lecp UrM01fCsnnay lmap VrMt O&'Cimury Letup Unrt901 }.�E V8°itt❑'JFINE°ot+ ylyswF }eJ}kk- ManrrY +Ak.Y {e ; Ljgi 13 Etl- 7 JS- — Y E34k YY Y 1{11 M J I Based on the divergent pressures (112 psi and growing) and competent cement observed from the CBL, again, Hilcorp is planning on putting CLU -08 back on line. Bo York Hilcorp Alaska LLC Kenai Operations Manager bvork@Hilcorp.com 907.777.8345 907.727.9247 cell From: Bo York Sent: Wednesday, October 16, 2019 2:44 PM To:'Schwartz, Guy L (CED)' <guy.schwartz@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.¢ov>; 'dave.roby@alaska.gov' <dave.robv@alaska.gov> Subject: RE: [EXTERNAL] RE: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Guy and Steve - See my notes below in red. We had a very good discussion with CINGSA on the plan. Let me know if you have additional questions or would like to discuss more. Bo York Hilcorp Alaska LLC Kenai Operations Manager bvork@Hilcorp.com 907.777.8345 907.727.9247 cell From: Schwartz, Guy L (CED)[mailto:suy.schwartz@alaska.zov] Sent: Wednesday, October 16, 2019 11:13 AM To: Bo York <byork@hilcory.com>; Davies, Stephen F (CED) <steve.davies@alaska.gov> Cc: Roby, David 5 (CED) <dave.robv@alaska.gov> Subject: [EXTERNAL] RE: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Bo, The AOGCC is in general agreement with your plan forward. Before we move forward, here are a few questions and requests that came up during internal discussions. 1) Has CINGSA been notified of this potential communication between UB -B and Sterling C Gas Storage Sands? Yes, we had a call with Matt Federle at CINGSA this afternoon and discussed the issue and our plan forward. Matt and his team are more than happy to facilitate our pressure testing to ensure there is no communication (either way) between our UB -B and the Sterling C. If not, please do so and inform them of Hilcorp's planned path forward. 2) AOGCC has no CBL on record for CLU -8. Please supply a printed copy or a scanned image of the CBL in Aif or .pdf format. We are working to get a file size I can email. If we can't get it reduced we will bring over a hard copy and the file on a thumb drive. 3) After isolating the UB -B sand is Hilcorp planning on any flow period before shutting in CLU -8? If so, how long will that flow period be? (this data could be used for PTA analysis) Hilcorp will plan on setting the plug Friday and will continue to flow the well for 3 days to establish a baseline with just the UB -B flowing. CINGSA is shutting in at 0700 on Monday, 21 Oct. We will continue to flow until 1800 hrs on 21 Oct then SI CLU -08. 4) What equipment are you planning on using to capture data on CLU -8? We will use a silicone crystal gauge (+/- .02 psi accuracy) taking readings every 10 seconds. 5) How long is Hilcorp planning to monitor pressure in CLU -8 before applying to resume regular production? Hilcorp will keep the well SI and monitor the pressure through the CINGSA SI which is scheduled for 7 days. Based on the SI pressures, we will make a determination of what to do when CINGSA comes 4. Early flowing material balance calculations (rate transient analysis) shows a recoverable volume of -1.3 BCF, which is far from CINGSA's volume of 12-16 BCF. PROPOSED PATH FORWARD Intent is to verify/confirm that CLU -08 is not in communication with the Sterling C Gas Storage sand. The plan is to isolate the UB -B perforations and shut the well in for a pressure build-up. We are getting a Hilcorp owned 3-1/2" Paragon packer and setting tool flown down from the slope and some parts FeclExed up from the lower 48. Plan is to have all parts in hand and set the plug no later than Friday, 18 Oct. The well will be SI immediately following the setting of the plug. CINGSA is currently scheduled for maintenance downtime starting the end of this week. Following completion of their work (estimated 7-10 days), we will then monitor CLU -08's WHP as CINGSA is brought back on-line for storage production. This test is not due to any concerns regarding pressure communication, but rather a verification to confirm no pressure communication is taking place. If CLU -08 is in communication with the Sterling C, the CLU -08 pressure build up should level out at the same SI pressure as the Sterling C Gas Storage sand, and after CINGSA returns to production, a slow drop in pressure should be very apparent in CLU -08's WHP readings mirroring the pressure drop in the CINGSA storage pool. However, if, as we suspect, the CLU -08 pressure build is different from the Sterling C Gas Storage sand, or no pressure drop is observed after CINGSA is brought back on-line, we can conclude that CLU -08's UB -13 perforations are not in communication with the Sterling C. Please let me know if you would like to discuss the proposed path forward, require additional information, or have any questions. Thank you both for fielding our call quickly today and discussing this. Bo York Hilcorp Alaska LLC Kenai Operations Manager bvork@Hilcorp.com 907.777.8345 907.727.9247 cell The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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. 11 ALASKA E-LINE SERVICES 421 -71 -7, e07 ;2-2-00 ,,r EMMmm om ON 0 ri MENEM 'M HER, m lit M w -m MENEM .1 M Mm M MM WIMMI M M MENEM I MMMMEM WmAl I$ NOM MIN mmagam Imam min 0 Iffial ,SEENI—m �__wwi_Qi MOs EMMMMM ME mman EMF.VY=Wr.;AW MMMMM M MM WE lirl-lams-I NEW "M M MM BELEM Elimllmsmimp 1A MMMEMM MMM M 1200 00 RevGR (GAP[) 0 LTEN (lb) 2200 ------------------------------------- — 421 -71 -7, e07 ;2-2-00 ,,r Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Hilcnq,:u.nk., ITC E-mail: doudean@hilcorp.com DATE 10/17/2019 To: Alaska Oil & Gas Conservation Commission Guy Schwartz q 333 W 7th Ave Ste 100 Fc Anchorage, AK 99501 .4.771 octzs 800010 The Expro Group CD: GR -CCL -CBL -SONIC RADIAL BOND LOG 11 APR 2004 Please include current contact information if different from above. 204005 31373, Please acknowledge receipt 4y-s+gning and returning one copy of this transmittal or FAX to 907 777.8337 Received By: i \', A p \ � I Date: Davies, Stephen Stephen F (CED) From: Bo York <byork@hilcorp.com> Sent: Wednesday, October 16, 2019 2:44 PM To: Schwartz, Guy L (CED); Davies, Stephen F (CED); Roby, David S (CED) Subject: RE: [EXTERNAL] RE: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Guy and Steve - See my notes below in red. We had a very good discussion with CINGSA on the plan. Let me know if you have additional questions or would like to discuss more. Bo York Hilcorp Alaska LLC Kenai Operations Manager bvork@Hilcorp.com 907.777.8345 907.727.9247 cell From: Schwartz, Guy L (CED)[mailto:guy.schwartz@alaska.govl Sent: Wednesday, October 16, 2019 11:13 AM To: Bo York <byork@hilcorp.com>; Davies, Stephen F (CED) <steve.davies@alaska.gov> Cc: Roby, David S (CED) <dave.robv@alaska.gov> Subject: [EXTERNAL] RE: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Bo, The AOGCC is in general agreement with your plan forward. Before we move forward, here are a few questions and requests that came up during internal discussions. 1) Has CINGSA been notified of this potential communication between UB -B and Sterling C Gas Storage Sands? Yes, we had a call with Matt Federle at CINGSA this afternoon and discussed the issue and our plan forward. Matt and his team are more than happy to facilitate our pressure testing to ensure there is no communication (either way) between our UB -B and the Sterling C. If not, please do so and inform them of Hilcorp's planned path forward. 2) AOGCC has no CBL on record for CLU -8. Please supply a printed copy or a scanned image of the CBL in .tif or .pdf format. We are working to get a file size I can email. If we can't get it reduced we will bring over a hard copy and the file on a thumb drive. 3) After isolating the UB -B sand is Hilcorp planning on any flow period before shutting in CLU -8? If so, how long will that flow period be? (this data could be used for PTA analysis) Hilcorp will plan on setting the plug Friday and will continue to flow the well for 3 days to establish a baseline with just the UB -B flowing. CINGSA is shutting in at 0700 on Monday, 21 Oct. We will continue to flow until 1800 hrs on 21 Oct then SI CLU -08. 4) What equipment are you planning on using to capture data on CLU -8? We will use a silicone crystal gauge .02 psi accuracy) taking readings every 10 seconds 5) How long is Hilcorp planning to monitor pressure in CLU -8 before applying to resume regular production? Hilcorp will keep the well SI and monitor the pressure through the CINGSA SI which is scheduled for 7 days. Based on the 51 pressures, we will make a determination of what to do when CINGSA comes BOL. Tentatively, the planned as discussed with CINGSA today will be to leave CLU -08 SI while bringing on all but one of the CINGSA wells (probably well #3 as it is currently 51 and will probably have the best pressure data). We will leave CLU -08 SI while watching the pressure adjust once CINGSA is BOL to demonstrate there is no communication. We will work closely with CINGSA on coordinating this test and share pressure data back and forth 6) For comparison, AOGCC will require from Hilcorp a copy of CINGSA's pressure data along with Hilcorp's pressure data for CLU -08. (Not sure which well they use for monitoring reservoir, but the closer to CLU -8 the better.) Hilcorp will discuss and coordinate with CINGSA to obtain this data. More than likely it will be the CINGSA Well k3. 7) On all future schematic drawings for all CLU wells, Hilcorp must depict the top and base of the Sterling C Gas Storage Sands and provide corresponding measured depths and TVDs. Concur To ensure continued integrity of the overlying gas storage pool, the AOGCC and Hilcorp should move toward revising Conservation Order No. 231 to establish a vertical set -back distance (vertical buffer) below the gas storage pool that will apply to future perforating and/or fracturing operations within the Beluga Gas Pool. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending if to you, contact Guy Schwartz at (907-793-1226 ) or (Guv.schwortz@oloska.aov). From: Bo York <bvork@hilcorp.com> Sent: Tuesday, October 15, 2019 6:27 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Guy and Steve - Below is the current situation with CLU -08 and the Sterling C Gas Storage sand and our proposed path forward. CURRENTSTATUS The base of the CINGSA Sterling C Gas Storage sand in CLU -08 is at 5143' TVD. The Beluga UB -B sand was perforated on 9/25/2019 from 5188'-5196'TVD, approximately 45' TVD below the Sterling C Gas Storage sand. The well is currently online flowing at —3,500 mcf at —700 psig. There is the following evidence to believe CLU -08 is not currently in communication with the CINGSA Gas Storage Sand: 1. The most shallow perforation in CLU -08 prior to 9/25/2019 was shot from 5219'-5228'TVD, only 31'TVD below the latest perf interval and 76' TVD below the Sterling C Gas Storage Sand. The interval was also fracture stimulated — part of the original 'Excape' completions by Marathon. 2. CLU -08 had loaded up in March 2019. This likely would not have happened had the well been in communication with the Sterling C. 3. The CBL run in CLU -08 shows good cement bond between Sterling C sand and UB -B. 4. Early flowing material balance calculations (rate transient analysis) shows a recoverable volume of —1.3 BCF, which is far from CINGSA's volume of 12-16 BCF. PROPOSED PATH FORWARD Intent is to verify/confirm that CLU -08 is not in communication with the Sterling C Gas Storage sand. The plan is to isolate the UB -B perforations and shut the well in for a pressure build-up. We are getting a Hilcorp owned 3-1/2" Paragon packer and setting tool flown down from the slope and some parts FedExed up from the lower 48. Plan is to have all parts in hand and set the plug no later than Friday, 18 Oct. The well will be SI immediately following the setting of the plug. CINGSA is currently scheduled for maintenance downtime starting the end of this week. Following completion of their work (estimated 7-10 days), we will then monitor CLU -08's WHP as CINGSA is brought back on-line for storage production. This test is not due to any concerns regarding pressure communication, but rather a verification to confirm no pressure communication is taking place. If CLU -08 is in communication with the Sterling C, the CLU -08 pressure build up should level out at the same SI pressure as the Sterling C Gas Storage sand, and after CINGSA returns to production, a slow drop in pressure should be very apparent in CLU -08's WHP readings mirroring the pressure drop in the CINGSA storage pool. However, if, as we suspect, the CLU -08 pressure build is different from the Sterling C Gas Storage sand, or no pressure drop is observed after CINGSA is brought back on-line, we can conclude that CLU -08's UB -B perforations are not in communication with the Sterling C. Please let me know if you would like to discuss the proposed path forward, require additional information, or have any questions. Thank you both for fielding our call quickly today and discussing this. Bo York Hilcorp Alaska LLC Kenai Operations Manager byork@Hilcorp.com 907.777.8345 907.727.9247 cell The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error. please notify the sender immediately by return e-mail and permanently delete the copy you received. 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. Davies, Stephen F (CED) From: Schwartz, Guy L (CED) Sent: Wednesday, October 16, 2019 11:13 AM To: Bo York, Davies, Stephen F (CED) Cc: Roby, David S (CED) Subject: RE: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Bo, The AOGCC is in general agreement with your plan forward. Before we move forward, here are a few questions and requests that came up during internal discussions. 1) Has CINGSA been notified of this potential communication between UB -B and Sterling C Gas Storage Sands? If not, please do so and inform them of Hilcorp's planned path forward. 2) AOGCC has no CBL on record for CLU -8. Please supply a printed copy or a scanned image of the CBL in Jif or .pdf format. 3) After isolating the UB -B sand is Hilcorp planning on any flow period before shutting in CLU -8? If so, how long will that flow period be? (this data could be used for PTA analysis) 4) What equipment are you planning on using to capture data on CLU -8? 5) How long is Hilcorp planning to monitor pressure in CLU -8 before applying to resume regular production? 6) For comparison, AOGCC will require from Hilcorp a copy of CINGSA's pressure data along with Hilcorp's pressure data for CLU -08. (Not sure which well they use for monitoring reservoir, but the closer to CLU -8 the better.) 7) On all future schematic drawings for all CLU wells, Hilcorp must depict the top and base of the Sterling C Gas Storage Sands and provide corresponding measured depths and TVDs. To ensure continued integrity of the overlying gas storage pool, the AOGCC and Hilcorp should move toward revising Conservation Order No. 231 to establish a vertical set -back distance (vertical buffer) below the gas storage pool that will apply to future perforating and/or fracturing operations within the Beluga Gas Pool. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate store or federal law. If you are an unintended recipient of this c --mail, please delete it, without first saving or forwarding if, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at 1907-793-1226 I or QLuy sch ortzq�alaska aovl. From: Bo York <byork@hilcorp.com> Sent: Tuesday, October 15, 2019 6:27 PM To: Schwartz, Guy L (CED) <guy.schwa rtz@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Guy and Steve - Below is the current situation with CLU -08 and the Sterling C Gas Storage sand and our proposed path forward. Davies, Stephen F (CED) From: Bo York <byork@hilcorp.com> Sent: Tuesday, October 15, 2019 6:27 PM To: Schwartz, Guy L (CED); Davies, Stephen F (CED) Subject: Cannery Loop Unit - CLU -08 and the Sterling C Gas Storage Sand Guy and Steve - Below is the current situation with CLU -08 and the Sterling C Gas Storage sand and our proposed path forward. CURRENTSTATUS The base of the CINGSA Sterling C Gas Storage sand in CLU -08 is at 5143' TVD. The Beluga UB -B sand was perforated on 9/25/2019 from 5188'-5196'TVD, approximately 45' TVD below the Sterling C Gas Storage sand. The well is currently online flowing at -3,500 mcf at -700 psig. There is the following evidence to believe CLU -08 is not currently in communication with the CINGSA Gas Storage Sand: 1. The most shallow perforation in CLU -08 prior to 9/25/2019 was shot from 5219'-5228'TVD, only 31'TVD below the latest perf interval and 76' TVD below the Sterling C Gas Storage Sand. The interval was also fracture stimulated - part of the original 'Excape' completions by Marathon. 2. CLU -08 had loaded up in March 2019. This likely would not have happened had the well been in communication with the Sterling C. 3. The CBL run in CLU -08 shows good cement bond between Sterling C sand and UB -B. 4. Early flowing material balance calculations (rate transient analysis) shows a recoverable volume of -1.3 BCF, which is far from CINGSA's volume of 12-16 BCF. Intent is to verify/confirm that CLU -08 is not in communication with the Sterling C Gas Storage sand. The plan is to isolate the UB -B perforations and shut the well in for a pressure build-up. We are getting a Hilcorp owned 3-1/2" Paragon packer and setting tool flown down from the slope and some parts FeclExed up from the lower 48. Plan is to have all parts in hand and set the plug no later than Friday, 18 Oct. The well will be SI immediately following the setting of the plug. CINGSA is currently scheduled for maintenance downtime starting the end of this week. Following completion of their work (estimated 7-10 days), we will then monitor CLU -08's WHP as CINGSA is brought back on-line for storage production. This test is not due to any concerns regarding pressure communication, but rather a verification to confirm no pressure communication is taking place. If CLU -08 is in communication with the Sterling C, the CLU -08 pressure build up should level out at the same SI pressure as the Sterling C Gas Storage sand, and after CINGSA returns to production, a slow drop in pressure should be very apparent in CLU -08's WHP readings mirroring the pressure drop in the CINGSA storage pool. However, if, as we suspect, the CLU -08 pressure build is different from the Sterling C Gas Storage sand, or no pressure drop is observed after CINGSA is brought back on-line, we can conclude that CLU -08's UB -B perforations are not in communication with the Sterling C. Please let me know if you would like to discuss the proposed path forward, require additional information, or have any questions. Thank you both for fielding our call quickly today and discussing this. Bo York Hilcorp Alaska LLC Kenai Operations Manager bvork@Hilcoro.com 907.777.8345 907.727.9247 cell The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon LJ Plug Perforations El Fracture Stimulate Ll Pull Tubing Ll Operations shutdown Li Performed: Suspend ❑ Perforate ❑� Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Nitrogen ❑� 2. Operator 4. Well Class Before Work: Name: Hilcorp Alaska, LLC 5. Permit to Drill Number: Development 0 Exploratory ❑ 204-005 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6. API Number: AK 99503 50-133-20534-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0373302/ADLO324602/FEE-TR73 Cannery Loop Unit 08 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Kenai C.L.U. / Beluga Gas Pool 11. Present Well Condition Summary: Total Depth measured 9,777 feet Plugs measured 7,267 feet true vertical 7,941 feet Junk measured 8,365 feet Effective Depth measured 7,267 feet Packer measured 7,941 feet true vertical 5,445 feet true vertical 6,105 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 100' 20" 121' 121' 3,060psi 1,500psi Surface 1,810 13-3/8" 1,810' 1,636' 3,450psi 1,950psi Intermediate 6,722 9-5/8" 6,722' 4,941' 5,750psi 3,090psi Production 9,746' 3-1/2" 9,746' 7,910' 10,160psi 10,530psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3# / L-80 9,746' MD 7,910' TVD N/A; N/A N/A Packers and SSSV (type, measured and true vertical depth) Isolation Pur 7,941' MD 6,105' TVD 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 396 Subsequent to operation: 0 3561 1 1127 704 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations [] Exploratory❑ Development p ❑ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas 4 WDSPL Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-383 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: 1ramer(r>7hilcoro.com Authorized Signature: Date: I vC 1- Z-01 Contact Phone: 777-8420 Form 10-404 Revised 4/2017 ('/ /� RBDMS±-� OCT 0 9 2019 Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU -08 E -Line 1 50-133-20534-00-00 204-005 9/11/19 1 9/25/19 Daily Operations: 09/11/2019 - Wednesday PTW, JSA with Halliburton E -line. Discuss SIMOPS with SLB coil crews. Rig up E -line unit. Make up BHA Gamma/CCL, firing head and CIBP. CCL to top of CIBP 13'. Legacy oil tools CIBP for setting in 3.5" tubing 5.7 ppf- 10.2 ppf. 2.7" OD Big boy plug for Go 1-11/16" tools PN# 000-2750-0000. Stab on well. PT stack 250/3,000 psi. Bleed down. Open well and RIH. WHP 650 psi. Pull correlation pass. Send to town. ON depth. Park CCL at 7,273' Puts top of plug at 7,286', 750 line tension. Attempt to fire/set CIBP. Voltage increased but no AMP or no short occurred. Attempt to reset software and troubleshoot. No luck. POOH with plug to surface. HES crew looking for cause of mis-fire. All tools check out with volt meter. E -line supervisor believes it to be the Gamma tool. Remove Gamma tool and run CCL only. Stab on well. RIH . Pull correlation pass from 7,350'-6,900'. Discuss with Geologist and Reservoir engineer new set depth of 7,294'. Send log to town. On depth. CCL to top of plug 85. Drop back down to 7,350'. Log OOH and park CCL at 7,285.5' puts top of plug at 7,294'. 720 lbs line tension. Attempt to fire. No short noticed. Reset control panel. Had voltage and amperage. Possible set. Log up to 7,100'. RIH to tag CIBP at 7,294'. Plug is not set. No tag found. POOH to surface to inspect tools. At surface. Close upper master and swab. Pop off well. Break down BHA. Plug recovered. Inspect firingpd and igniter. Found Igniter smashed. Previous igniter wasn't rebuilt and debris was left in This caused new igniter to be -Igniter crushed when installed into igniter bore. Lay down lu ricator. Remove wireline valves and install night cap. Found wire was smashed. Re -head E -line. Well secure. SDFN. 09/12/2019 - Thursday PTW, JSA with Halliburotn E -line. Rig up E -line. RIH with 3.5" Legacy oil tools CIBP. 2.7" OD. Log correlation strip from 7,350'-7,000'. Send log to town. On depth. Set CIBP @ 7,302'. CCL depth 7,289'. Line tension dropped form 827 lbs to 623 lbs. Pick up and RIH tag CIBP. Good set. POOH to surface. Make up 40'x 2.25" ID dump bailer. Mix cement. RIH with 40' dump bailer. Tag to of CIBP @ 7,302'. Pick up 10' and dump cement. POOH,to surface. Break down 10' of bailer. Mix Cement Load 30' dump bailer. Stab on well. RIH Dump cement @ 7,278'. POOH. Calculated cement top 7,267'. Tagged up at surface. Rig down E -line. 09/25/2019- Wednesday PTW, ISA and SIMOPS with AKE-Line, SLB N2 and Pollard SL. Spot and rig up equipment while field pressured tested the IA to 1,200 psi and went down to 1,140 psi in 30 min. PT SLB N2 hard lines AKE-Line lubricator to 250 psi low and 3,500 psi high. RIH w/GPT tool, tie into Halliburton PNL log Start pushing fluid away with N2. Broke over at 1,100 psi. Found fluid level at 7,120' and still pushing fluid away after we shut off N2. Run correlation log and send to town. Town said we werel-2 foot high. RIH w/ 2-3/8" x 10' HC Razor, 6 spf, 60 deg phase and tie into GPT. Run correlation log and send to town. Town change pert depth to 6,993' to 7,003'. Spot shot and pressured up to 1,500 psi with N2 and fired shot. Good indication of firing. POOH. All shots fired and gun was dry. Rig down SLB N2 and AKE-Line. used 1300 gal N2 and Have 631 gals left. l� M L� l� H Hilcorn Alaska, LLC 2e 13-B,g J TOC (eft.) 6,42Z 9,1 TCC 7,267 M12-19 SCHEMATIC Kenai Gas Field Well: CLU 08 Last Completed: 2004 API: 50-133-20534-00-S01 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 133 / K-55 / N/A 18.73 Surface 121' 13-3/8" Surface 68 / K-55 / BTC 12.415 Surface 1,810' 9-5/8" Intermediate 40/L-80/BTC-MOD 8..45 Surface 6,722' 10 Straddle Packer AssembN ' a19 'Top of packer @±7,917'MD RKB �6 r �1 5 L . 4 21!9,hp edto } 8,365'm4/15/2013 •T3 l� 2 } tw 1 Tag*9A5VWw/ z.c'c�1 Vzkmo TD=9,777 MD/7,941'TVD PSTD=7,267 MD/5,445' TVD Zone �bbbbbb' /� G 1 3-1/2" Btm (MD) Top (TVD) TUBING DETAIL 12-1/4" hale Cmt w/ Lead 320 sks (120 bbls) 12.5 pp of class G, Tail 235 sks (48.5 bbls)15.8 ppg class G Tubing 9.3 / L-80 /MOD 8RD 2.992 Su face 9,746' 6,994' c, ter(-) 5,188' 5,196' JEWELRY DETAIL Open r No Depth(MO) Depth(TVD) Item 16 6,952' 5,149' BHP Tank Bottom @ 6,987' MD Beluga 7,130' 15 7,046' 5,237' Module #15 w/ conv. Flapper Open Beluga 14 7,149' 5,333' Module #14 w/ mnv. Flapper ' Open 13 7,251' 5,430' Module #13 w/conv. Flapper :• yt'E SWy b,Q,��w �!✓N.,,L, 13A 7,302' 5,479' 3-1/2" Slimhole CIBP w/35' cement - TOC @ 7,267' 9/12/19 12 7,316' 5,492' Module #12 w/conv. Flapper Beluga EXCAPE SYSTEM DETAILS 11 7,419' 51592' Module #11 w/conv. Flapper 5 -15 Excape modules placed 10 7,475' 5,646' Module #10 w/ conv. Flapper 10' - Green control line fires bottom 7 modules. 9 71597' 51,765' Module #9w/conv. Flapper -,75 - Red control line fires top 8 modules. - Blue line for BHP monitoring. 8 7,707' 5,873' Module #8w/conv. Flapper 7 7,941' 6,105' Module #7 w/ Isolation Packer 14 - Ceramic flapper valves below each module. 6 8,001' 6,165' Module#6w/conv. Flapper 5 8,306' 6,470' Module #5 w/ conv. Flapper 6,451' 6,461' 13 - �13A ' 12 4 8,385' 6,549' Module #4 w/ conv. Flapper 3 8,428' 6,592' Module#3w/conv. Flapper 2 8,515' 6,679' Module#2w/conv. Flapper 1 N/A N/A Module#1-No Flapper 8,496' 8,506' 6,660' 6,670' 11 Isolated Beluga 8,990' 9,000' -„ 7,164' 10' PERFORATION DETAIL 10 Straddle Packer AssembN ' a19 'Top of packer @±7,917'MD RKB �6 r �1 5 L . 4 21!9,hp edto } 8,365'm4/15/2013 •T3 l� 2 } tw 1 Tag*9A5VWw/ z.c'c�1 Vzkmo TD=9,777 MD/7,941'TVD PSTD=7,267 MD/5,445' TVD Zone Top (MD) Btm (MD) Top (TVD) Rtm (TVD) 12-1/4" hale Cmt w/ Lead 320 sks (120 bbls) 12.5 pp of class G, Tail 235 sks (48.5 bbls)15.8 ppg class G Status Beluga 6,994' 7,003' 5,188' 5,196' 10' Open Beluga 7,027' 7,037' 5,219' 5,228' ' Open Beluga 7,130' 7,140' 5,315' 5,325' ' In Open Beluga 7,232' 7,242' 5,412' 5,422' ' Open Beluga 7,297' 7,307' 5,474' 5,484' ' Isolated Beluga 7,400' 7,410' 5,573' 5,583' 10' Isolated Beluga 7,456' 7,466' 5,627' 5,637' 10' Isolated Belu a 7,578' 7,588' 51746' 5,756' 10' Isolated Beluga 7,688' 7,698' 5,854' 5,864' 10' Isolated Beluga 7,922' 7,932' 6,086' 6,096' 10' Isolated Beluga 7,982' 7,992' 6,146' 6,156' 10' Isolated Beluga 8,287' 8,297' 6,451' 6,461' 10' Isolated Beluga 8,366' 8,376' 6,530' 6,540' 30' Isolated Beluga 8,409' 8,419' 6,573' 6,583' 10' Isolated Beluga 8,496' 8,506' 6,660' 6,670' 10' Isolated Beluga 8,990' 9,000' 7,154' 7,164' 10' Isolated CEMENTING DETAIL Casing Detail 13-38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type -1 cmt, 100% returns, 40 bbls to surface 9-5/8" 12-1/4" hale Cmt w/ Lead 320 sks (120 bbls) 12.5 pp of class G, Tail 235 sks (48.5 bbls)15.8 ppg class G 3-1/2" 8-1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt Updated by DMA 10-04-19 THE STATE OIALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai C.L.U. Field, Beluga Gas Pool, Cannery Loop Unit 08 Permit to Drill Number: 204-005 Sundry Number: 319-383 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, /�� Js'ie&l./�Ilowski Commissioner DATED this 22 -day of August, 2019. RBDMS-/LfA/AU6 2 3 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Art, CT --F- 1"i 1P 9 ^•,n 1. Type of Request: Abandon ❑ Plug Perforations ❑� • Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate I] ' Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Nitrogen Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q. Slratigraphic❑ Service ❑ 204-005 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20534-00-00 - 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO231 Will planned perforations require a spacing exception? Yes LJ No ❑ Cannery Loop Unit OS 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0373302/ADLO324602/FEE-TR73 Kenai C.L.U. Field / Beluga Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,777' 7,941' 8,365' 6,529' 1,821 psi N/A 8,365' Casing Length Size MD TVD Burat Collapse Structural Conductor 121' 20" 133' 133' 3,060 psi 1,500 psi Surface 1,810' 13-3/8" 1,810' 1,636' 3,450 psi 1,950 psi Intermediate 6,722 9-5/8" 6,722' 4,941' 5,750 psi 3,090 psi Production g7g6' 3-112" 9,746' 7,910' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3# / L-80 9,746' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A; N/A N/A; N/A 12. Attachments: Proposal Summary ♦ Wellbore schematic r 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: September 4, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑� WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 777-8345 Contact Name: Christina Twogood Authorized Title: Operations Manager Contact Email: CtwO ood hi1cor .COM /^r Contact Phone: 777-8443 -w Authorized Signature: Date 7`� 1 COMMISSIONASE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: I,4' Post Initial Injection MIT Req'd? Yes ❑ No❑ / U Li RBDMSIqus 2 3 2oign Spacing Exception Required? Yes ❑ No L,.�,y/ Subsequent Form Required: 0 ` 1 / • APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: I,? 111, -2, r� 1�'A�� Submit Form and Form 104 3 Revised 4/2017 Approved app" h v 11 r!)i�1 Om the date of approval Attachments Attachments in Duplicate //7 r� �s Zz iy ff Hilmrp Alnekn, L[.0 AT M9 U 21'Rshp Ww 8,365'.4/15/2013 TQM 9145BMJ w/ 2.6'Ga 1/2/2010 SCHEMATIC Kenai Gas Field Well: CLU 08 Last Completed: 2004 API: 50-133-20534-00-S01 CASING DETAIL Size Tye Wt/Grade/Conn ID Top I Btm 20" Conductor 133/x-55/N/A 18.73 Surface 121' 13- 3/6/8" Surface 68/K-55/BTC 12.415 Surface 1,810' 9-5/8" Intermediate 40/L-80/BTC-MOD 8.835 Surface 6,722' TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / MOD 8RD 1 2.992 1 Surface 1 9,746' JEWELRY DETAIL EXCAPE SYSTEM DETAILS 1s _-15 Ezcape modules placed - Green control line fires bottom 7 modules. 15 - Red control line fires top 8 modules. - Blue line for BHP monitoring. 74 - Ceramic flapper valves below each module. ;13 �. ,12 7 5 5 2 I TD= 9,777 / PBTD=9,709' a Straddle Packer Assembly Top of packer @ 27,917' MD RKB No Depth(MD) Depth(TVD) Item 16 6,952' 5,149' BHP Tank Bottom @ 6,987' MD 35 7,046' 5,237' Module#15 w/ conv. Flapper 14 7,149' 5,333' Module#14 w/ conv. Flapper 13 7,251' 5,430' Module #13 w/ conv. Flapper 12 7,316' 5,492' Module#12 w/ conv. Flapper 11 7,419' 5,592' Module#11w/conv. Flapper 30 7,475' 5,646' Module#10 w/ conv. Flapper 9 7,597' 5,765' Module #9 w/conv. Flapper 8 7,707' 5,873' Module #8 w/ conv. Flapper 7 7,941' 6,105' Module #7 w/ Isolation Packer 6 8,001' 6,165' Module #6w/conv- Flapper 5 8,306' 6,470' Module #5 w/ conv. Flapper 4 8,385' 6,549' Module #4 w/ conv. Flapper 3 8,428' 6,592' Module #3 w/ conv. Flapper 2 8,515' 6,679' Module #2 w/ conv. Flapper 1 N/A N/A Module #I. Flapper PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status Beluga 7,027' - 7,037' 5,219' 5,228' 10' Open Beluga 7,130' 7,140' 5,315' 5,325' 10' Open Beluga 7,232' - 7,242' 5,412' 5,422' 10' Open Beluga 7,297' 7,307' 5,474' 5,484' 10' Open Beluga 7,400' 7,410' 5,573' 5,583' 10' Open Beluga 7,456' 7,466' 5,627' 5,637' 10' Open Beluga 7,578' - 7,588' 5,746' 5,756' 10' Open Beluga 7,688' 7,698' 5,854' S,864' 10' 1 Open Beluga 7,922' 7,932' 6,086' 6,096' 10' Open Beluga 7,982' - 7,992' 6,146' 6,156' 10' Open Beluga 8,287' - 8,297' 6,451' 6,461' 10' Oen Beluga 8,366' 8,376' 6,530' 6,540' 10' Open Beluga 8,409' 8,419' 6,573' 6,583' 10' Open Beluga 8,496' 8,506' 6,660' 6,670' 10' Open Beluga 81990' 91000' 7,154' 7,164' 10' Open CEMENTING DETAIL Casing Detail 13-3 1 16 hole Cmt w/ sks (229 bbl) of 12.0 Type -1 cmt, 100% returns, 40 bbls to surface 9-5/8" 12-1/4" hole Cmt w/ Lead 320 sks 120 bbls)12,5 ppg of class G, Tail 235 sks (48.5 bbis) 15.8 ppg class G 3-1/2" 1 8-1/2" hole Cmt w/ 1,430 sks (293 bbis) of 15.8 ppg, class G cmt Revised By: TDF 5/28/2013 n Hilcnry Alaxkn, Lt,C 2m recT.ss sn , 17 21'Rsh pahed to 8,N6 m 4715/3013 Thy 9,458'W,V 26%R =010 5 4 3 1 TD= 9,777 / PBTD=9,707 PROPOSED SCHEMATIC Kenai Gas Field Well: CLU 08 Last Completed: 2004 API: 50-13 3-20534-00-SO1 CASING DETAIL SizeT pe Wt/Grade/Conn ID I Top I Btm 20" Conductor 133/K-55/N/A 18.73 1 Surface I 123' 13-3/8" Surface 68/K-55/BTC 12.415 Surface I 1,810' 9-5/8" Intermediate 40/L-80/BTC-MOD 8.835 Surface 1 6,722' TUBING DETAIL 3-1/2" Tubing 9.3/L-80/MODSRD 1 2.992 1 Surface9,746' EXCAPE SYSTEM DETAILS - 15 Excape modules placed - Green control line fires bottom 7 modules. - Red control line fires top 8 modules. a- Blue line for BHP monitoring. - Ceramic flapper valves below each module Straddle Packer AssembN • Top of packer @ t7,917' MD RKB rl�a 4 JEWELRY DETAIL No Depth(MD) Depth(TVD) Item 16 6,952' 5,149' BHP Tank Bottom @ 6,987' MD 35 7,046' 5,237' Module #15 w/ conv. Flapper 14 7,149' 5,333' Module#14 w/ conv. Flapper 13 7,251' 5,430' Module #13 w/ conv. Flapper 12 7,316' 5,492' Module#12 w/ conv. Flapper 11 7,419' 5,592' Module #11 w/ conv. Flapper 10 7,475' 5,646' Module#10 w/ conv. Flapper 17 7,564 5,728' 3-1/2"Slimhole Cl BP 9 7,597' 5,765' Module #9 w/ conv. Fla per 8 7,707' 5,873' Module #8 w/ conv. Flapper 7 7,941' 6,105' Module #7 w/ Isolation Packer 6 8,001' 6,165' Module #6 w/ conv. Flapper 5 8,306' 6,470' Module #5 w/ conv. Flapper 4 8,385' 6,549' Module #4 w/ conv. Flapper 3 8,428' 6,592' Module #3w/conv. Flapper 2 8,515'6,679' 5,746' Module #2w/conv. Flapper 1 N/A N/A Module #1 -No Flapper PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Stm (TVD) FT Status Beluga 6,985' 7,000' 5,180' 5,405' 15' Proposed Beluga 7,027' 7,037' 5,219' 5,228' 10' Open Beluga 7,130' 7,140' 5,315' 5,325' 10' Open Beluga 7,200' 7,225' 5,381' 5,405' 25' Proposed Beluga 7,232' 7,242' 5,412' 5,422' 10' Open Beluga 7,297' 7,307' 5,474' 5,484' 10' Open Beluga 7,400' 7,410' S,573' 5,583' 10' Open Beluga 7,456' 1 7,466' 5,627' 1 5,637' 10' 1 Open Beluga 7,578' 1 7,588' 5,746' 5,756' 10' Open Beluga 7,688' 7,698' 5,854' 5,864' 10' Open Beluga 7,922' 7,932' 6,086' 6,096' 10' Open Belu a 7,982' 7,992' 6,146' 6,156' 10' Open Beluga 8,287' 8,297' 6,451' 6,461' 30' Open Beluga 8,366' 8,376' 6,530' 6,540' 10' Open Beluga 8,409' 8,419' 6,573' 6,583' 10' Open CEMENTING DETAIL Casing Detail 13-38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type -1 cmt, 100% returns, 40 bbls to surface 9-5/8" 12-1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks 148.5 bbls)15.8 ppg class G 3-1/2" 8-1/2" hole Cmt w/ 1,430 sks (293 bbis) of 15.8 p9g, class G curt Revised By: CMT 8/16/2019 U nilcom Alaska. LU Well Prognosis Well: CLU 08 Date:08/16/2019 Well Name: CLU 08 API Number: 50-133-20584-00 Current Status: Shut -In Gas Well Leg: N/A Estimated Start Date: September 4, 2019 Rig: E -Line Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 208-185 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (987) 867-0665 (C) AFE Number: Current Bottom Hole Pressure: -500 psi @ 5,194' TVD (Based on 8/15/19 RFT data (depleted)) -2,400 psi @ 5,405' TVD (Based on 8/15/19 RFT data) Maximum Expected BHP: - 2,362 psi @ 5,405' TVD (Based on normal gradient) Max. Allowable Surface Pressure: - 1,821 psi @ 5,405' TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary CLU 08 was drilled in 2004 as a grassroots monobore with Excape completion to target gas sands in the Beluga formation. In May 2010 the well loaded up, was swabbed and bailed and patch was set across Module 7. In February 2013 the patch across Module 7 was removed. In April 2013 the patch, slickline fish tools and wire were deemed lost in hole after a two month fishing ordeal*A new path was set across Module 7 and the well was swabbed for a significant amount of time to get it flowing. In April 2015 a PLT survey was run. In February 2019 the well loaded up. In March 2019 the well was swabbed with no luck and then drifted with 2.80" and 2.72" swedges past Module 9 at -7,600' MD. In May 2019 the well was drifted with a 2.72" gauge ring to Module 11 at -7,400' MD and got stuck. The equipment was recovered but the run failed to reach Module 9 as planned. 1.5V i The purpose of this work is to isolate the intervals at and below Module 9 and perforate the Beluga UB -B and UB -G Sands. Notes Regarding Wellbore Condition • Well is currently shut-in. • May have issues getting CIBP to depth (details above) Safety Concerns Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. Considertank placement based on wind direction and current weather forecast (venting nitrogen during this job). • Ensure all crews are aware of stop job authority. E -Line Procedure 1. RU E -Line and pressure control equipment. PT lubricator to 3,000 psi High / 250 psi Low. a. Tree connection is 6-1/2" OTIS H nilmm Alaska, LD Well Prognosis Well: CLU 08 Date: 08/16/2019 2. RIH with GPT tool and find fluid level. If fluid level is over the depth to shoot the new perfs, discuss using Nitrogen with the Operations Engineer. 3. If needed, RU Nitrogen Truck and pressure up on well to push water back into formation. Use GPT Tool to confirm if fluid level is below interval to pert. 4. RIH with a slimhole 3-1/2" CIBP and set at 7,650' MD. Dump bail 35' of cement on top. POOH. a. Perform adrift run prior to RIH with CIBP. 5. RU wireline guns. 6. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) I FT SPF Upper Beluga UB -B 6,985' 7,000' 5,180' 5,194' 15' 6 Upper Beluga UB -G 7,200' 7,225' 5,381' 5,405' 25' 6 a. Pressure up tubing to 500 psi before perforating. b. Proposed perfs shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact pert intervals. d. Use Gamma/CCL to correlate. e. The perforations in the table above are located in the Beluga Gas Pool based on Conservation Order No. 231. f. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g. Record 5, 10 and 15 minute pressures after firing guns. RD E -Line. 8. Turn well over to production. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Well Procedure—N2 Operations STANDARD WELL PROCEDURE llacnrp Alaska, LLC NITROGEN OPERATIONS 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 02 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. 12/08/2015 FINAL v1 Page 1 of 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 4`11''z 9- " E IAv EED IUL 16 2019 1. Operations Abandon LJ Plug Perforations LJ Fracture Stimulate LJ Pull Tubing Li Operations shutdown Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Patch Excape Mod. #9 ❑Q 2. Operator Hilcorp Alaska, LLC 4. Well Class Before Work: 15. Permit to Drill Number: Name: Development Q Exploratory ❑ Stratigraphic❑ Service ❑ 204-005 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-133-20534-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0373302/ADLO324602/FEE-TR73 Cannery Loop Unit 08 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Kenai C.L.U. / Beluga Gas Pool 11. Present Well Condition Summary: Total Depth measured 9,777 feel Plugs measured N/A feet true vertical 7,941 feet Junk measured 8,365' feet Effective Depth measured 8,365' feet Packer measured 7,941 feet true vertical 6,529' feet true vertical 6,105 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 100' 20" 121' 121' 3,060psi 1,500psi Surface 1,789' 13-3/8" 1,810' 1,636' 3,450psi 1,950psi Intermediate 6,701' 9-5/8" 6,722' 4,941' 6,870psi 4,750psi Production 9,725' 3-1/2" 9,746' 7,910' 10,160psi 10,530psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3# / L-80 9,746' MD 7,910' TVD N/A; N/A N/A Packers and SSSV (type, measured and tme vertical depth) Isolation Pkr 7,941' MD 6,105' TVD 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 1 0 0 0 0 61 Subsequent to operation: 10 0 0 0 61 14. Attachments (required per 20 AAc 25.070, 25.071, a 25.283) 15. Well Class after work: Daily Report of Well Operations F] Exploratory[] Development ❑✓ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas r WDSPL LJ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-119 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramerrrDhilcoro.com 1 j, Authorized Signature: Dale: 1 " , �^1 '1 O M Contact Phone: 777-8420 Form 10404 Revsied 412017 / ',�.�t` 7/{iOABDMSLfG�JUL 1 02019 Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU -08 E -Line 50-133-20534-00-00 1 204-005 3/20/19 6/19/19 Daily Operations: 03/20/2019- Wednesday Sign in and mobe to location. PTW and JSA. Spot and rig up equipment. PT lubricator to 250 psi low and 3,500 psi high. TP 61 psi. RIH w/ 2.76" GRx6' wt bar x 2.76' Swedge and tie into Expro CBL. Set down at 7,046' (Mod 15), pick up and go thru obstruction down to 7,672'. Stopped there but didn't set down. Ran correlation log and send to town. This was a drift run for patch. POOH. Make up patch. RIH w/ 2.75" x 16' Owens patch and tie into Expro CBL log. Patch set down at 6,808' (above mod and in tubing). Worked tools from 6,808 to 6,785' with tool string wt between 1,300 lb and 2,200 lbs. Called town and discussed. Decision made to work our way up 50 Ib at a time until we got free or pull out of rope socket. Pulled up to 2,250 lbs and wait 5 min. Went back down to 800 lbs and tools fell back to 6,808'. Pulled back up to 2,250 lbs and waited 5 min. Tools didn't move up hole. Picked up to 2,300 lbs and tools pulled free after 2 min. Picked up to 6,600 ' and went back down hole slow just to see if obstruction was still there. Tools set down at 6,808'. Pulled 600 lbs to free tools again. POOH with no problem. Got all tools back. Didn't see any marks on tools. Rig down equipment and turn well back over to field. 69 psi on tubing. NOTE: I have slickline coming out in morning. E -line will get ready to go to Pax 8 Friday and Saturday. Will be back on this well Monday. 03/21/2019 -Thursday Arrive @ Office. Perform JSA - Gain Permit approval. Discuss Job Scope. Depart for Cannery. Arrive @ Cannery. Begin Rig Up on Cannery -08. Begin P.T. to 3,500# -Test good. RIH W/ 2.80 GR to 3,200'. Begin falling slowly (possibly a -line grease) pump diesel, begin falling at normal, rate fall to 6,815'KB set down, wt fall to 7,568'KB wt fall to 7,669'KB set down, wt, no spangs. POOH make several passes at 6,815'KB, clear. POOH. RIH W/ 2.70" X 20' DUMMY TO 6,967'KB SET DOWN - PICK UP - TOOLS STUCK- WT- 1800 LBS OIL JAR. LICKS FOR 1 HOUR, TOOLS COME FREE, POOH, OOH W/ DUMMY, NO SIGNIFICANT MARKS. SLIP CUT 50' WIRE - REHEAD. RIH W/ 2.70" X 10' DUMMY TO 6,967'KB SET DOWN LIGHTLY - WT TO COME FREE (STICKY) POOH. RIH W/ 2.67" SWEDGE W/ 1.75" X 5.5' STEM W/ 2.74" CENTRALIZER TO 6,967'KB BOBBLE THROUGH TO 7,1311KB SET DOWN WT FALL TO 7,620'KB DO NOT TAG, POOH. RIH W/ 2.76" SWEDGE, 2.72" FLUTED CENTRALIZER, 2.74" FUTED CENTRALIZER (LOA 31.5") TO 7,420'KB SET DOWN, PICK UP, FALL TO 7,633'KB, DO NOT TAG, POOH, RAN AS A DRIFT FOR A PACKER. RIG DOWN W/L, CLEAN AREA. MOB TO PWL SHOP. 05/22/2019- Wednesday Sign in. Mobe to location. PTW, JSA and SIMOPS w/Weatherford. Rig up lubricator, PT to 250 psi low and 3,500 psi high. TP - 150 psi, RIH w/ 2.72" x 16.39' dummy gun as a drift for patch and set down between 7,400' and 7,410' (Mod 11). Tried several times at regular speed and then hit it a little harder and went down to 7,650'. Did not set down. Came back upto 7,400' and had to pull 1,000 Ib over to get free. Got out of hole and drift had some deep marks on it that looked like pert holes made them. Called town and discussed, RIH w/ 2.72" x 4' dummy gun as a drift for bottom packer and set down between 7,400' and 7,410' (Mod 11). Could not get any deeper. Called town and discussed. Weatherford will check on some packers with smaller OD's on them, Rig down lubricator and turn well over to field. 06/19/2019- Wednesday Engineering visited with Weatherford. Weatherford cannot turn down straddle packer. Will have to redesign workover. Will need a rig. Close out Sundry. I Ta (Do.) 4," SCHEMATIC Kenai Gas Field Well: CLU 08 Last Completed: 2004 API: 50 -133 -20534 -00 -SOI CASING DETAIL Size Type Wt/ Grade/ Conn ID Top B 20" Conductor 133 / K-55 / N/A 18.73 Surface 121' 13- 3/8" Surface 68 / K-55 / BTC 12.415 Surface 1,810' 9-5/8" Intermediate I 40/L-80/BTC-MOD 8.835 Surface 1 6,722' TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / MOD 8RD 1 2.992 1 Surface 1 9,746' JEWELRY DETAIL ESYSTEMYSTEM DETAILS �t6e modules placed ntrol line fires bottom 7 modules. 15ol line fires top 8 modules. for BHP monitoring.1aflapper valves below each module. 9 I Straddle Packer AssembN " Top of packer @ ±7,917' MD RKB ri'Rsh pnladb Depth(MD) a Item $3R'm4�15J7D13 6,952' 5,149' 3 15 7,046' 5,237' 2 14 7,149' 5,333' Module#14 w/conv. Flapper 13 7,251' 5,430' Module#13 w/conv. Flapper T%gcH9,4 W./ 2SGR 1/1/2010 7,316' 5,492' '.• 44( 7,419' f Module#11 w/conv. Flapper 10 7,475' 5,646' Module#10w/conv. Flapper 9 7,597' 1 5,765' TO 9,777 / PBTD= 9,709 No Depth(MD) Depth(TVD) Item 16 6,952' 5,149' BHP Tank Bottom @ 6,987' MD 15 7,046' 5,237' Module #15 w/ conv. Flapper 14 7,149' 5,333' Module#14 w/conv. Flapper 13 7,251' 5,430' Module#13 w/conv. Flapper 12 7,316' 5,492' Module #12 w/ conv. Flapper 11 7,419' 5,592' Module#11 w/conv. Flapper 10 7,475' 5,646' Module#10w/conv. Flapper 9 7,597' 1 5,765' Module #9 w/ conv. Flapper 8 7,707' 5,873' Module #8 w/ conv. Flapper 7 7,941' 6,105' Module #7 w/ Isolation Packer 6 8,001' 6,165' Module #6 w/ conv. Flapper 5 8,306' 6,470' Module #5 w/ conv. Flapper 4 8,385' 6,549' Module #4 w/ conv. Flapper 3 8,428' 6,592' Module #3 w/ conv. Flapper 2 8,515' 6,679' Module #2 w/ conv. Flapper 1 N/A N/A Module #1 -No Flapper PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status Beluga 7,027' 7,037' 5,219' 5,228' 30' Open Beluga 7,130' 7,140' 5,315' 5,325' 30' Open Beluga 7,232' 7,242' 5,412' 5,422' 10' Open Beluga 7,297' 7,307' 5,474' 5,484' 10' Open Beluga 7,400' 7,410' 5,573' 5,583' 30' Open Beluga 7,456' 7,466' 5,627' 5,637' 10' Open Beluga 7,578' 7,588' 5,746' 5,756' 10' Open Beluga 7,688' 7,698' 5,854' 5,864' 10' 1 Open Beluga 7,922' 7,932' 6,086' 6,096' 10' Open Beluga 7,982' 7,992' 6,146' 6,156' 10' Open Beluga 8,287' 8,297' 6,451' 6,461' 10' Open Beluga 8,366' 8,376' 6,530' 6,540' 10' Open Beluga 8,409' 8,419' 6,573' 6,583' 10' Open Beluga 8,496' 8,506' 6,660' 6,670' 10' Open Beluga 8,990' 9,000' 7,154' 7,164' 10' Open CEMENTING DETAIL Casing 1 Detail 13-38" 1 16" hole Cmt w/ sks 1229 bbl of 12.0 ppg, Type -1 cmt, 100% returns, 40 bbls to surface 9-5/8" 12-1/4" hole Cmt w/ Lead 320 sks (120 bbls)12.5 ppg of class G, Tall 235 sks (48.5 bbls) 15.8 pg class G 3-1/2" 8.1/2" hole Cmt w/ 1,430 sks (293 bbis) of 15.8 ppg, class G cmt Revised By: TDF 5/28/2013 THE STATE °f11. GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai C.L.U. Field, Beluga Gas Pool, CLU 08 Permit to Drill Number: 204-005 Sundry Number: 319-119 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.a ogcc.a laska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this f g day of March, 2019. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 MAR 12 2M 'e Vit, i 'F -:e;, �`�s a.s i..r 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 ❑ Patch Excape Mod. #9 Other: Q 2. Operator Name: 4. Current Well Class: 5. Pennit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 204-005 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20534-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO231 v Will planned perforations require a spacing exception? Yes ❑ No � ❑ Cannery Loop Unit OS 9. Property Designation (Lease Number):. . 10. Field/Pool(s): r ADL0373302/ADLO324602/FEE-TR73 Kenai C.L.U. Field / Beluga Gas Pool it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,777' 7,941' 8,365' 6,529' 1,941 NIA 8,365' Casing Length Size MD TVD Burst Collapse Structural Conductor 100' 20" 121' 121' 3,060 psi 1,500 psi Surface 1,789' 13-3/8" 1,810' 1,636' 3,450 psi 1,950 psi Intermediate 6,701 9-5/8" 6,722' 14,941' 6,870 psi 4,750 psi Production 9,725' 3-1/2" 9,746 7,910' 70,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3# / L-80 9,746' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Isolation Packer & N/A 7,941 (MD) 6,105 (TVD) & N/A 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: March 25, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS Q WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: So York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: 1kramerJ@hi1c-0r9 corn Contact Phone: 777-8420 � �� ZD � Authorized Signature: Date: 1 OV COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 I (_•/1 �-v' I Yq I Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test E]Location Clearance ❑ Other: RBDMSirz-" MAR h 2019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: ) APPROVED BY j/ Approved by: COMMISSIONER THE COMMISSION Date: / �� 7 3//y//,i 3 Submit Form and Form 10403 Revised 4/2017 App applica[iORdiV K he date of approval. Attach ents in Du ca e ,4, 74 V it -•e_314, U Hacory Ala.ka LD Well Prognosis Well: CLU 08 Date: 3/6/2019 Well Name: CLU - 08 API Number: 50-133-20534-00 Current Status: Gas Producer Leg: Estimated Start Date: 3/25/2019 Rig: E -line Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 204-005 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Bo York 1 (907) 777-8345 (0) (907) 727-9247 (C) AFE Number: Current Bottom Hole Pressure: —2,517 psi Based on original res. Pressure Maximum Expected BHP: --2,517 psi @ 5,756' TVD Other open zones are depleted Max. Predicted Surface Pressure: —1,941 psi Based on .1 psi/foot gas gradient Brief Well Summary CLU -08 was drilled 2004 with an Escape completion. The well produced gas only until mid -2006 when the water production started at 50-100 BWPD. In 6/2010 a 20' tubing patch was installed over the perforations from 7,922'-7,932'. A production log ran in 2015 indicated that Module # 9 is making all water. The purpose of this work is the run an isolation patch and shut off module # 9 (Perls 7,578 — 7588'). Brief Procedure 1. MIRU Slick line and test BOPE to 250psi low/3,500 psi high. 2. RIH with SL and 2-1/2"DD bailer/ GR to +/-7,895'. 3. RD Slickline. 4. MIRU E -line. Pressure test lubricator to 3,500 psi. 5. PU patch for 3-1/2" 9.2# tubing. RIH and set Isolation Patch across Excape Module #9 according to Manufacturers setting instructions. POOH W/ E -line. 6. Rig down E -line. 7. Turn Well over to production. Attachments: 1. Schematic 2. Proposed Schematic 133/8";'• TCC (el.) 4,aJfr .►: i T1CI84.I6A22' �>: ss/a• tt _ 7 Type 8.365'cn 4/15/2013 :t•�, .- 6 Btm ij 5 LV`71 133 / K-55 / N/A 18.73 ;S2 121' 4 2f Rsh Ndhed to Size Type 8.365'cn 4/15/2013 •, 'vs 3 Btm 20" Conductor 133 / K-55 / N/A 18.73 ;S2 121' 13- 3/8" Surface 68/K-55/BTC 12.415 M" t Ta�d%458MDw/ Module #13 w/ conv. Flapper 9-5/8" 2.6•GR 1/]/2010 f4 (y Surface 6,722' 5,592' Module #11 w/ conv. Flapper 10 71475' 5,646' TD= 9,777 / PBTD=9,709' 9 SCHEMATIC Kenai Gas Field Well: CLU 08 Last Completed: 2004 API: 50-133-20534-00-501 CASING DETAIL C Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 133 / K-55 / N/A 18.73 Surface 121' 13- 3/8" Surface 68/K-55/BTC 12.415 Surface 1,810' Module #13 w/ conv. Flapper 9-5/8" Intermediate 40/L-80/BTC-MOD 8.835 Surface 6,722' 5,592' TUBING DETAIL 3-1/2" Tubing 9.3/L-80/MOD8RD 1 2.992 1 Surface 1 9,746 " JEWELRY DETAIL 15 Ezcape modules placed Green control fine fires bottom 7 modules. Red control line fires top 8 modules. Blue line for BHP monitoring. Ceramic flapper valves below each module. Straddle Packer Assembly • Top of packer @ ±7,917' MD RKB No Depth(MD) Depth(TVD) Item 16 6,952' 5,149' BHP Tank Bottom @ 6,987' MD 35 7,046' 5,237' Module #15 w/ conv. Flapper 14 7,149' 5,333' module #14 w/ conv. Flapper 13 7,251' 5,430' Module #13 w/ conv. Flapper 12 7,316' 5,492' Module #12 w/ conv. Flapper 11 7,419' 5,592' Module #11 w/ conv. Flapper 10 71475' 5,646' Module #10 w/ cons. Flapper 9 7,597' 5,765' Module #9 w/ conv. Flapper 8 7,707' 1 5,873' Module #8 w/ conv. Flapper 7 7,941' 6,105' module #7w/ Isolation Packer 6 8,001' 6,165' Module #6 w/ conv. Flapper 5 8,306' 6,470' Module #5 w/ conv. Flapper 4 8,385' 6,549' Module #4 w/ conv. Flapper 3 8,428' 6,592' Module #3 w/ conv. Flapper 2 8,515' 6,679' Module #2 w/ conv. Flapper 1 N/A N/A Module #1- No Flapper PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FF Status Beluga 7,027' 7,037' 5,219' 5,228' 10' Open Beluga 7,130' 7,140' 5,315' 5,325' SO' Open Beluga 7,232' 7,242' 5,412' 5,422' 10, Open Beluga 7,297' 7,307' 5,474' 5,484' 10, Open Beluga 7,400' 7,410' 5,573' 5,583' 10' Open Beluga 7,456' 7,466' 5,627' 5,637' 10' Open Beluga 7,578' 7,588' 5,746' 5,756' 10' Open Beluga 7,688' 7,698' 5,854' 1 5,864' 1O' 1 Open Beluga 7,922' 7,932' 6,086' 6,096' 10' Open Beluga 7,982' 7,992' 6,146' 6,156' 30' Open Beluga 8,287' 8,297' 6,451' 6,461' 30' O en Beluga 8,366' 8,376' 6,530' 6,540' 30' Open Beluga 8,409' 8,419' 6,573' 6,583' 10' Open Beluga 8,496' 8,506' 6,660' 6,670' 10' Open Beluga 8,990' 9,000' 7,154' 7,164' 10' Open CEMENTING DETAIL Casing Detail 13-38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type -1 cmt, 100% returns, 40 bbls to surface 9-5/8" 12-1/4" hole Cmt w/ Lead 320 sks (120 bbls)12,5 ppg of class G, Tail 235 sks (48.5 bbls)15.8 ppg class G 3-1/2" 8-1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt Revised By: TDF 5/28/2013 H Hilcara Alaska. LLC 2a' >3 Va. TX(Rt)4,8W 21'Rsh hedto 8,385'm4/15/2013 Tagged9,45 Ww/ 2GGR1/2/2010 PROPOSED Kenai Gas Field Well: CLU 08 Last Completed: 2004 API: 50 -133 -20534 -00 -SOI CASING DETAIL TUBING DETAIL 3-1/2" Tubing 9.3/L-80/MODSRD 1 2.992 1 Surface 1 9,746' JEWELRY DETAIL EXCAPE SYSTEM DETAILS _-15 Excape modules placed - Green control line fires bottom 7 modules. - Red control line fires top 8 modules. - Blue line for BHP monitoring. - Ceramic flapper valves below each module. i1 o r� �SVsdde Ply ,.]SJ 9±7,%5' 1/l rf :j FJ5 {4 3 . J 2 „ 117✓ 1 1 k. r) <- r 1 Tl) 9,777 / PBTD=9,709 Straddle Packer Assembly • Top of packer @1±7,917' MD RKB No Size Type Wt/ Grade/ Conn ID Top Btm BHP Tank Bottom @ 6,987' MD 20" Conductor 133 / K-55 / N/A 18.73 Surface 121' 13- Surface 68/K-55/BTC 12.415 Surface 1,810' -71 7,316' 3/8" Module#12 w/conv. Flapper 11 7,419' 5,592' Module#11W/conv. Flapper 9-5/8" Intermediate 40/L-80/BTC-MOD 8.835 Surface 6,722' ±5,763' TUBING DETAIL 3-1/2" Tubing 9.3/L-80/MODSRD 1 2.992 1 Surface 1 9,746' JEWELRY DETAIL EXCAPE SYSTEM DETAILS _-15 Excape modules placed - Green control line fires bottom 7 modules. - Red control line fires top 8 modules. - Blue line for BHP monitoring. - Ceramic flapper valves below each module. i1 o r� �SVsdde Ply ,.]SJ 9±7,%5' 1/l rf :j FJ5 {4 3 . J 2 „ 117✓ 1 1 k. r) <- r 1 Tl) 9,777 / PBTD=9,709 Straddle Packer Assembly • Top of packer @1±7,917' MD RKB No Depth(MD) Depth(TVD) Item 16 6,952' 5,149' BHP Tank Bottom @ 6,987' MD 15 7,046' 5,237' Module#15 w/conv. Flapper 14 7,149' 5,333' Module#14 w/conv. Flapper 13 7,251' 5,430' Module#13 w/conv. Flapper 12 7,316' 5,492' Module#12 w/conv. Flapper 11 7,419' 5,592' Module#11W/conv. Flapper 30 7,475' 5,646' Module#10 w/conv. Flapper 9 ±7,595' ±5,763' Module #9 w/ Isolation Packer 8 7,707' 5,873' Module #8 w/ conv. Flapper 7 7,941' 1 6,105' Module #7 w/ Isolation Packer 6 8,001' 6,165' Module #6w/conv. Flapper 5 8,306' 6,470' Module #5 w/ conv. Flapper 4 8,385' 6,549' Module #4 w/ conv. Flapper 3 8,428' 6,592' Module #3 w/ conv. Flapper 2 8,515' 6,679' module #2w/conv. Flapper 1 N/A N/A Module #1 -No Flapper PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status Beluga 7,027' 7,037' 5,219' 5,228' 10' Open Beluga 7,130' 7,140' 5,315' 5,325' 10' Open Beluga 7,232' 7,242' 5,412' 5,422' 30' Open Beluga 7,297' 7,307' 5,474' 5,484' 10' Open Beluga 7,400' 7,410' 5,573' 5,583' 30' Open Beluga 7,456' 7,466' 5,627' 5,637' 10' Open Beluga 7,578' 7,588' 5,746' 5,756' 10, Open Beluga 7,688' 7,698' 5,854' 1 5,864' 10' 1 Open Beluga 7,922' 7,932' 6,086' 6,096' 10' Open Beluga 7,982' 7,992' 6,146' 6,156' 10'Open Beluga 8,287' 8,297' 6,451' 6,461 10. Open Beluga 8,366' 8,376' 6,530' 6,540' 10' Open Beluga 8,409' 8,419' 6,573' 6,583' 30' Open Beluga 8,496' 8,506' 6,660' 6,670' 10' Open Beluga 8,990' 9,000' 7,154' 7,164' 10' Open CEMENTING DETAIL Casing Detail 13-38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type -1 cmt, 100% returns, 40 bbls to surface 9-5/8" 12-1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G 3-1/2" 8-1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt Revised By: JLL 03/06/19 t STATE OF ALASKA • , .. t,,, a b .4 AI 411kA OIL AND GAS CONSERVATION COMMISSION >,,, 0 '' 15013 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1. Operations Abandon ❑ • Repair Well U Plug Perforations (J Perforate [i • Other [J Tubing Patch Performed: Alter Casing ❑ Pull Tubing ❑ Stimulate - Frac ❑ Waiver 0 Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re -enter Suspended Well 0 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC • Development el , Exploratory ❑ 204 -005 ' 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic ❑ Service ❑ 6. API Number: Anchorage, Alaska 99503 50- 133 - 20534 -00 • 7. Property Designation (Lease Number): 8. Well Name and Number: • ADL0373302/ADL0324602/FEE -TR73 Cannery Loop Unit 08 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s):. N/A Kenai C.L.U. Field / Beluga Gas Pool • 11. Present Well Condition Summary: Total Depth measured 9,777 feet ' Plugs measured N/A feet true vertical ` 7,941 feet Junk measured 8,365' feet Effective Depth measured 8,365' feet Packer measured N/A feet true vertical 6,529' feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 100' 20" 121' 121' 3,060psi 1,500psi Surface 1,789' 13 -3/8" 1,810' 1,636' 3,450psi 1,950psi ! Intermediate 6,701' 9 -5/8" 6,722' 4,941' 6,870psi 4,750psi Production 9,725' 3 -1/2" 9,746' 7,910' 10,160psi 10,530psi Liner Perforation depth Measured depth See Attached Schematic SCANNED JU 1 w 2013 True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 3 -1/2" 9.3# / L -80 9,746' 7,910' Packers and SSSV (type, measured and true vertical depth) N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: N/A intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A '13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 5,000 167 0 272 Subsequent to operation: 0 1,000 110 0 140 14. Attachments: 15. Well Class after work: C opies of Logs and Surveys Run N/A Exploratory ii Development Q ' Service ❑ Stratigraphic ❑ iUaily Report of Well Operations X 16. Well Status after work: Oil ❑ Gas in • WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 313 -095 Contact Jeremy Mardambek Email jmardambek Printed Name Jeremy Mardambek Title Reservoir Engineer Signature Phone 907 - 777 -8388 v.�`( Date 5/28/2013 Form 10 404 Revised 10/2012 %�— C'74.3 R BDMS J UN - 5 2U;., Submit Original Only • Kenai Gas Field 11 0 WeII: CLU 08 SCHEMATIC Last Completed: 2004 Ilileoru Alaska, LLC API: 50- 133 - 20534 -00 -501 CASING DETAIL *, Size Type Wt/ Grade / Conn ID Top Btm r 20" Conductor 133 / K -55 / N/A 18.73 Surface 133' 04 13 Surface 68 / K -55 / BTC 12.415 Surface 1,810' 20" „ 3/8" N' s i 9 - 5/8" Intermediate 40 / L -80 / BTC -MOD 8.835 Surface 6,722' ,4 A TUBING DETAIL >'1 I 3 - 1/2" Tubing 9.3 / L - 80 / MOD 8RD 2.992 Surface I 9,746' 13-3/8" II JEWELRY DETAIL TOC(Fst.)4,E00' 9.,. ,, i I. N, No Depth(MD) Depth(TVD) Item Lc, L i 16 6,952' 5,149' BHP Tank Bottom @ 6,987' MD 15 7,046' 5,237' Module #15 w/ cony. Flapper *4 v4 14 7,149' 5,333' Module #14 w/ cony. Flapper 0 !,11), 13 7,251' 5,430' Module #13 w/ cony. Flapper ', ( 12 7,316' 5,492' Module #12 w/ cony. Flapper 44 11 7,419' 5,592' Module #11 w/ conv. Flapper TOC(Fst.)6,422' t " 10 7,475' 5,646' Module #10 w/ conv. Flapper 9-5/8" P g tviik 9 7,597' 5,765' Module #9 w/ conv. Flapper '' EXCAPE SYSTEM DETAILS 8 7,707' 5,873' Module #8 w/ conv. Flapper '16 __ 15 Excape modules placed 7 7,941' 6,105' Module #7 w/ conv. Flapper iii - Green control line fires bottom 7 modules. 6 8,001' 6,165' Module #6 w/ conv. Flapper .,,, i 15 - Red control line fires top 8 modules. 5 8,306' 6,470' Module #5 w/ conv. Flapper t 1 4! - Blue line for BHP monitoring. 4 8,385' 6,549' Module #4 w/ conv. Flapper r - Ceramic flapper valves below each module. 3 8,428' 6,592' Module #3 w/ conv. Flapper 14 2 8,515' 6,679' Module #2 w/ conv. Flapper x, �13 1 N/A N/A M odule #1- No Flapper i PERFORATION DETAIL 4 . I 12 Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status 4 1', 7 '11 Beluga 7,027' 7,037' 5,219' 5,228' 10' Open Beluga 7,130' 7,140' 5,315' 5,325' 10' Open I 4 10 Beluga 7,232' 7,242' 5,412' 5,422' 10' Open 1' `� E ` �eluga 7,297' 7,307' 5,474' 5,484' 10' Open P43 i t � 9 Straddle Packer Assembly i * Top of packer @ ±7,917' MD RKB Beluga 7,400' 7,410' 5,573' 5,583' 10' Open 0 /Beluga 7,456' 7,466' 5,627' 5,637' 10' Open 14 ,t. f i " 8 Beluga 7,578' 7,588' 5,746' 5,756' 10' Open to Beluga 7,688' 7,698' 5,854' 5,864' 10' Open Beluga 7,922' 7,932' 6,086' 6,096' 10' Open i Beluga 7,982' 7,992' 6,146' 6,156' 10' Open 1 7 P Beluga 8,287' 8,297' 6,451' 6,461' 10' Open , , Beluga 8,366' 8,376' 6,530' 6,540' 10' Open "' 4 I Beluga 8,409' 8,419' 6,573' 6,583' 10' Open a . 6 Beluga 8,496' 8,506' 6,660' 6,670' 10' Open 41/4' It Beluga 8,990' 9,000' 7,154' 7,164' 10' Open i 5 4 CEMENTING DETAIL 21' Fish pushed to ell Casing Detail 8,365' on 4/15/2013 ., ■ � 1 't' 3 13 -38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type -1 cmt, 100% returns, 40 bbls to surface 9 - 5/8" 12 -1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G 2 4 �' t 3-1/2" 8 - 1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt 1 a 1 ili Tagged 9,458'MDw/ 2.6 "GR 1/2/2010 i gr TD = 9,777' / PBTD = 9,709' Revised By: TDF 5/28/2013 • • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU 08 50- 133 - 20534 -00 -00 204 -005 4/9/13 4/27/13 • a. erei iY.p_. ...... 4/3/2013- Wednesday No operations to report 4/4/2013 - Thursday No operations to report 4/5/2013 - Friday No operations to report 4/6/2013 - Saturday No operations to report 4/7/2013 - Sunday Mobilize rig to location. 4/8/2013 - Monday Continue to modilize rig to location. 4/9 /2013 - Tuesday Installed derrick and sand drum back on carrier. N/U rig tank, rig pump, and manifolds. Installing rest of equipment. Filled up rig tank w/ FSW. Unloaded new BOPE. WO the other two cmt blocks. • a . • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU 08 50- 133 - 20534 -00 -00 204 -005 4/9/13 4/27/13 Daily 4/10/2013 - Wednesday RU derrick and ran guy wires to blocks. Rig up equitment. Tbg had 800 psi. Bled off pressure. Pumped 60 bsw down the tbg at 2 bpm 0 psi. installed back pressure valve in the tbg. ND tree. NU bope. 4/11/2013 - Thursday Performed AOGCC BOPE test, witness was waived by Jim Regg. Tested annular to 250psi low / 2,500psi hi h and associated BOPE to 250psi low / 2,500psi high. WIH pu wash shoe and 237 jts of 1 1/2" work string. 4/12/2013 - Friday FIH w/ wash nozzle and tagged top of fish at 7,854' tm. No sand on top of fish. Unable to cir. Washed off TOF w/ no returns. POOH. Nozzle had metal mark on btm. WIH w/ wire grab. Sat down on TOF and rotated a round. PUH and had 8k over wt. SOOH dragging. FOOH. Did not have fish, WIH w/ same BHA. Have trouble w/ tongue. 4/13/2013 - Saturday Fixed tongues. Tagged fish high at 7,844' tm and tapped down to org place at 7,854'. Rotated tbg on TOF. PUH and had no extra wt. Dropped down and tried several more times w/ no success. POOH. Had metal marks higher on inside of wire grab. WIH w/ single wire grab. Tagged TOF and rotated grab . PU and had 12k over wt and slipped off. Dropped back down and repeated the same w/ no success. POOH. WIH w/ cut -rite lip guide, 3' extenion, OS, BJS, OJS,and Tbg. Rotated over and jarred down-on-fish. PUH and pulled 28k over and jars went off. Lost wt. Jarred down on fish several times. Did not incresed wt. POOH. Recovered wireline tools and old straddle pkr pulling tool. WIH w/ new gs pulling tool. Attempted to relase STR pkr w/ on success. POOH. Left GS tool in hole. WIH open ended. 4/14/2013 - Sunday Screw onto GS tool. Unable to latch STR pkr. Tried several times w/ no success. POOH. Slip was broke off of GS. Rebuilt GS tool. WIH w/ GS tool. Latched pkr w/ tool. Pull up to 28k and OJS went off. Lost wt. Relatch and would slip out pulling 5 -8k wt. Tried several times w/ same result. POOH. Build spear. WIH w/ spear. Tagged TOF at 7,854' and chased down to ±7,886'. Speared pkr. POOH and had over pull up hole 2,000'. FOOH. Did not have pkr. WIH w/ split wire grab. 4/15/2013 - Monday FIH w/ wire grab and chased fish (stra pkr) down to 8,365'. Checked w/ anchorage. Change in orders. POOH, LD 1 -1/2" tbg and wire grab. Waited on WL. RIH w/ bottom pkr and sat down at ±7,680'. Unable to get past. POOH. RIH w/ 2.74 gr same size as pkr and sat down at 7,680'. PU and dropped thru spot and went down to 8,360'. POOH. RIH w/ bottom pkr again and sat down at 7,680'. Unable to get past spot. 4/16/2013 - Tuesday RU SLU . RIH w/ 2.79 swedging tool and went thru spot at 7,680'. Sat down at 7,935'. Unable to get thru at that spot. Ran a assorted amounted of WL tools. Still setting down at 7,935' but incounter pieces of junk in differant depths in the tbg. Carring pieces down and up hole. Below tools and above tools. Have piece of junk at 100'. RIH w/ split wire grab and went to ±7,950' w/ piece of junk. RIH w/ 2.79 swedging tool. Jarring down on junk. Junk get on top of tools and hung up. Worked free. POOH. RIH w/ 2.74 x 10' dummy down to 7,386'. POOH and shorten tool string w/ dummy. RIH. ' • 11 Hilcorp Alaska LLC W eekly Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU 08 50- 133 - 20534 -00 -00 204 -005 4/9/13 4/27/13 ios Dait t? erat n Y, 4/17/2013 - Wednesday Pressure test lubricator to WIH w/ btm pkr of stra pkr and stopped at 7,680'. Unable to work by. POOH. Had pkr turn down from 2.74" to 2.72 ". WIH w/ pkr and hung up at 1,800'. Unable to work free. Set pkr. RD polard wl. RU polard slu. RIH w/ gs pulling tool. Latched pkr. Jarred pkr free. POOH. Recovered pkr. RD slu. ET back pressure valve. ND bope. NU tree. Started rigging down. 4/18/2013 - Thursday Pressure test lubricator to 250psi low / 2,000psi high. Pulled back pressure valve. RU polard sI. RIH w/ 2.75" down to 7,791' and worked tool thru. Went to 8,000'. RIH w/ 2.80 tool. Worked thru at 7,791'. RIH w. 2.75 dummy. Worked thru spot at 7,791' and went down to 8,000'. SIFN. 4/19/2013 - Friday Pressure test lubricator to 250psi low / 2,000psi high. RIH w/ 2.80 swedging tool to 8,000'. POOH. RIH w/ bottom pkr of stra pkr and seta (7949 )RIH w/ seal assembly jt of 2 -3/8" tbg and top pkr hung up at 7,643'. Worked free. SOOH and hung up at 7,550'. Unable to work free. Set top pkr. POOH. SIFN. 4/20/2013 - Saturday No operations to report. 4/21/2013 - Sunday No operations to report. 4/22/2013 - Monday No operations to report. 4/23/2013 - Tuesday No operations to report. • • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU 08 50- 133 - 20534 -00 -00 204 -005 4/9/13 4/27/13 Dai IY p ... 4/24/2013 - Wednesday RU SLU. RIH w/ 2 -3/8" spacer jt. Latched into btm pkr of stra pkr. Sheared off. POOH. RD SLU. RU ELU. RIH w/ top pkr. Got stuck at 7,550'. Unable to work free. Set pkr. POOH. RD ELU. RU SLU. RIH w/ gs pulling tool. Latched pkr. Unable to pull free. Lost tool action . 4/25/2013 - Thursday POOH w/ top pkr. 4/26/2013 - Friday RIH w/ haliburton top pkr, sat down at 7,250'. Unable to work past spot. POOH pkr. Checked w/ anchorage. Change in plans, waiting on top pkr. 4/27/2013 - Saturday RU SLU. RIH w/ DND pack -off. Set pack -off on top of rest of stra pack at ±7,917'. Top of tool at ±7,910'( slm at 7,898'). RD pollard. turn well over to gaugers. W/O COMPLETE. TEST PENDING . 4/28/2013 - Sunday No operations to report. 4/29/2013 - Monday Swabing on well. Made 85 bbls. fluid level @ 2,400' 4/30/2013 - Tuesday No operations to report. • • Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, April 09, 2013 12:39 PM To: 'Shane Bennett - (C)' Subject: RE: CLU -08 20'4 Z O `( d 0 S Shane, Ok for the BOP's .. I will put this 7" BOP in the well file. As far as pulling the velocity string .. you can do that . Just notify inspectors of the upcoming BOP test for the CTU unit. You should have the sundry by then anyway. Guy Schwartz SCANNED JUL 0 4 2013 Senior Petroleum Engineer AOGCC 907- 444 -3433 cell 907 -793 -1226 office From: Shane Bennett - (C) [m iItosbennett_;) N tbom] Sent: Tuesday, April 09, 2013 11:48 AM To: Schwartz, Guy L (DOA) Cc: Tom Fouts Subject: CLU-08 Guy on the 10 -403, submitted for the CLU -08. The BOP schematic is a 11 ", we are changing it to a 7" due to the smaller OD pipe being used to fish with. I am attaching the 7" BOP Schematic to exchange out or I can bring it to you. Shane One other thing, you have the 10 -403 for the KDU -02, coil tubing can pull the coil string on the 13 if that's ok with you? Shane Bennett - (C) Operations Engineer—Alaska i)E -ii sett Midcolkcom O (907) 777 -8425 C (325) 203 -7487 H (325) 643 -2405 1 • • Cannery Loop Unit 7" BOP SCHEMATIC CLU -08 4/9/2013 iliirurp ;%Ia •ka, L1,(: L t Pte. " o 0 f 7 t2 { P0O 5 height in Feet e, me- T, zma Annula' 2.54 OAL 7 1/16" SM Hydriil annular —. , BOP 3.59 041 Element # 8117 -03 -12 D -Spool 1.56 OAL Total I 7.69 j OAL 1 2- 1/16 " Packers dressed to 1.900" t it 7- 1/16" SM all side outlets have, E ' blind flanges on them. - -�- - ,p :: z w Blind Rams . ♦". "i' •s ' MAIL « DSA 4'1/16" 5M to 2 -1/16" 10M 2- 1/16" 10 M , - i ‘11,,,, i r II I - € * i 2 1/16" 1OM HCR Manual c -:._. I Manual HCR 7 -1/16" 5M isi its -.a ,." ' u.. 1.96' OAL 3.00' OAL 7 =1/16" 5M _ 7 -1/16" SM lit yiaora a, * Vi i" Pa in tee P V OF 7'4 • • w * I / /7" ,v THE STATE Alaska (• fit a. Gas _ _ = ALASKA Conservation COirifiliSSi011 G OVERNOR SEAN PARNELL 333 West Seventh Avenue OF Q. Anchorage, Alaska 99501 -3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Chris Myers ) D4— 00S Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive Anchorage, AK 99503 SCANNED APR 0 8 2013 Re: Kenai C.L.U. Field, Beluga Gas Pool, Cannery Loop Unit 08 Sundry Number: 313 -163 Dear Mr. Myers: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P.A' oerster (� Chair DATED this J' day of April, 2013. Encl. • 1:::: 4t rs STATE OF ALASKA eC ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS A ( CC 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well '1.3 Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ 4" t3 Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other j77 ?4ch I©• `'I 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: JJ Hilcorp Alaska, LLC Exploratory ❑ Development 151 - 204 -005 • 3. Address: • Stratigraphic ❑ Service ❑ 6. API Number. 3800 Centerpoint Drive, Anchorage AK, 99503 50- 133 - 20534 -00 7, If perforating: 8: Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? Rule #3 of CO231 Will planned perforations require a spacing exception? Yes ❑ No p Cannery Loop Unit 08 - 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL0373302/ADL0324602/FEE -TR73 Kenai C.L.U. Field / Beluga Gas Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9,777' - 7,941 . 9,709' 7,895' N/A 7,895' (Fish) Casing Length th Size MD TVD Burst Collapse Structural Conductor 100' 20" 121' 121' 3,060 psi 1,500 psi Surface 1,789' 13 -3/8" 1,810' 1,636' 3,450 psi 1,950 psi Intermediate 6,701 9 -5/8" 6,722' 4,941' 6,870 psi 4,750 psi • Production 9,725' 3 -1/2" 9,746' 7,910' 10,160 psi 10,530 psi Liner 1 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Proposed Schematic See Proposed Schematic 3 -1/2" 9.3# / L -80 9,746'1 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A N/A 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch El Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 4/8/2013 Oil ❑ Gas Q , WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: N/A WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Shane Bennett Email sbennett(p,hilcorD.com Printed Name Ch s Myers Title Operations Manager i , : ` y nature �� Phone 907- 777 -8333 Date 4/2/2013 r bb�� COMMISSION USE ONLY j • :onditions of approval: Notify Commission so that a representative may witness Sundry Number: 313 —i (0 3 Plug Integrity ❑ BOP Test [Y Mechanical Integrity Test ❑ Location Clearance ❑ .other: .. —'o / OSc. $o P l s r- BDMS APR 0 8 spacin Exception Required? Yes ❑ No , Subsequent Form Required: f p - `b/ APPROVED BY Approved by: �. / ; COMMISSIONER THE COMMISSION Date: (1.-- -5 — / 3 o R� approval. Y - �3 Submit Form and �'� e s d 0 " Approved application is valid for 12 months from the date of approval. Attactir in Duplicate ' 1 4, / • • Well Prognosis Well: CLU O8 Hilcorp Alaska, LI) Date: 4/2/2013 Well Name: CLU - 08 API Number: 50- 133 - 20534- 00 -S01 Current Status: Gas Producer Leg: Estimated Start Date: 2/25/2013 Rig: Cloverleaf Rig 4 Reg. Approval Req'd? 10 -403 Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts 777 -8398 Permit to Drill Number: 204 -107 First Call Engineer: Shane Bennett (907) 777 -8425 (0) (325) 203 -7487 (M) Second Call Engineer: Chris Myers (907) 777 -8333 (0) (907) 398 -9955 (M) AFE Number: Current Bottom Hole Pressure: —900 psi Calculated from performance Maximum Expected BHP: —1,200 psi @ 6,000' TVD Max. Anticipated Surface Pressure: —650 psi Assumed from performance Brief Well Summary CLU -08 was drilled 2004 with an Escape completion. The well produced gas only until mid -2006 when the . water production started at 50 -100 BWPD. In 6/2010 a 20' temporary tubing patch was installed over the perforations from 7,922'- 7,932' based on faulty log analysis. This did stop some water production but also cut off 2 MMSCFD of gas production. Justification: Tubing patch installed over the wrong set of perfs. CL -01 pad should be able to handle the additional water. Recommendation: My inspection of the analysis done on the spinner logs indicates the log analysis is incorrect and the majority of the water production is from the bottom and second set of perfs at 8,990' and 8,496'. Punch 2 -3 /8 spacer joint covering the perforations from 7,992'- 7,932' and production should return to 4 MMSCFI?. _ D -CH 0 Risks: `� 7 � Wall between casing and patch could be full of solids, either way we would have to punch spacer joint to pull patch for equalization, if we had to pull, which is the plan in the near future. Pulling a tubing patch that has been downhole for 2+ years. Summary Procedure 1. MIRU Slick line and test BOPE to 250psi low /4,000psi high. 2. RIH with SL and 2- 1 /2 "DD bailer to +/- 7,895'. 3. RD Slickline. 4. MIRU Cloverleaf Rig. r'5e` PA re-if 5. ND /NU BOP, test BOPE to 250psi low/ 2,500psi high with a AOGCC witness present.. 9Y 6. PU /MU 1.8125 (series 150) overshot, 1.375 (series 150) grapple, 92) 36" extensions and crossover to r S pick -up 2 -3/8" tubing.. It U� 7. RIH to TOF +/-7,895' and latch fish. c'1 8. POOH and lay down fish /fish assembly. i!� 9. RIH with new Straddle Packer and set with rig. 10. POOH LD tubing assembly. 11. Rig down Cloverleaf Rig. 12. Turnover to production. Attachments: As- built, Proposed and BOP Schematics. 14 Kenai Gas Field • • WeII:CLU08 SCHEMATIC Last Com ple ted: 2004 llilcorp Alaska, LLC API: 50- 133 - 20534 -00 -501 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K -55 / N/A 18.73 Surface 133' A 20 >' - , 3/8" Surface 68 / K -55 / BTC 12.415 Surface 1,810' e t 9 -5/8" Intermediate 40 / L -80 / BTC -MOD 8.835 Surface 6,722' TUBING DETAIL " 3 -1/2" 1 Tubing I 9.3 / L -80 / MOD 8RD 2.992 Surface 1 9,746' 13 -3/8" j JEWELRY DETAIL TOC(Est.)4,800'÷L., - �, No Depth(MD) Depth(TVD) Item 1 6,952' 5,149' BHP Tank Bottom @ 6,987' MD t74 R 2 7,046' 5,237' Module #15 w/ cony. Flapper 3 7,149' 5,333' Module #14 w/ cony. Flapper �' 4 7,251' 5,430' Module #13 w/ cony. Flapper ti' 5 7,316' 5,492' Module #12 w/ conv. Flapper w' 6 7,419' 5,592' Module #11 w/ conv. Flapper TOC(Est.)6,422' 1i• r 7 7,475' 5,646' Module #10 w/ conv. Flapper 9-5/8" " ` it 8 7,597' 5,765' Module #9 w/ conv. Flapper ir EXCAPE SYSTEM DETAILS 9 7,707' 5,873' Module #8 w/ conv. Flapper ° 1 = 15 Excape modules placed 10 7,941' 6,105' Module #7 w/ conv. Flapper - Green control line fires bottom 7 modules. 11 8,001' 6,165' Module #6 w/ conv. Flapper .44Itt ' - i 2 - Red control line fires top 8 modules. 12 8,306' 6,470' Module #5 w/ conv. Flapper Blue l ine for BH moni 13 8,385' 6,549' Module #4 w/ conv. Flapper 3 Cer amic flapp valves bel ow each module. 14 8,428' 6,592' Module #3 w/ conv. Flapper MAI 15 8,515' 6,679' Module #2 w/ conv. Flapper t. 16 N/A N/A Module #1- No Flapper Nir i . i 5 PERFORATION DETAIL . ' Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status 9 s 1 6 Beluga 7,027' 7,037' 5,219' 5,228' 10' Open Zir Beluga 7,130' 7,140' 5,315' 5,325' 10' Open ii e ` 7 Weatherford Straddle packer Beluga 7,232' 7,242' 5,412' 5,422' 10' Open assembly (Fishl Beluga 7,297' 7,307' 5,474' 5,484' 10' Open - Tagged @ 7,895' 8 Beluga 7,400' 7,410' 5,573' 5,583' 10' Open On 3/27/2013 Beluga Beluga 7,456' 7,466' 5,627' 5,637' 10' Open 10' Open 10' Open 10' Open 1 s e -Punched 4 holes into Packer 7,578' 7,588' 5,746' 5,756' on 2/27/203 Beluga 7,688' 7,698' 5,854' 5,864' Beluga 7,922' 7,932' 6,086' 6,096' I e Beluga 7,982' 7,992' 6,146' 6,156' 10' Open l ' X Beluga 8,287' 8,297 6,451' 6,461' 10' Open L 17(.4. Beluga 8,366' 8,376' 6,530' 6,540' 10' Open ',�" Beluga 8,409' 8,419' 6,573' 6,583' 10' Open 10' Open 11 Beluga 8,496' 8,506' 6,660' 6,670' 10' Open Beluga 8,990' 9,000' 7,154' 7,164' �1 �12 I ' 13 CEMENTING DETAIL ° ' 1. Casing Detail 1 14 13 -38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type -1 cmt, 100% returns, 40 bbls to surface 4. 9 -5/8" 12 -1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G l 15 3 -1/2" 8 -1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt 1..,. 1 446 Tagged 9,458'MDw/ e 2.6 "GR 1/2/2010 � 0 TD = 9,777' / PBTD = 9,709' Revised By: TDF 4/1/2013 . ` � • • Kenai Gas Field • W PROPOSED ed: 2004 Iii!corp Alaska, LLC API: 50- 133 - 20534 -00 -501 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K -55 / N/A 18.73 Surface 133' li a 13- 20 3/8 Surface 68 / K -55 / BTC 12.415 Surface 1,810' 9 -5/8" Intermediate 40 / L -80 / BTC-MOD 8.835 Surface 6,722' TUBING DETAIL 3 -1/2" 1 Tubing 9.3 / L -80 / MOD 8RD I 2.992 I Surface 9,746' ?i 3 / g JEWELRY DETAIL TOC (Est.) 4,804 e � No Depth(MD) Depth(TVD) Item ` t a 1 6,952' 5,149' BHP Tank Bottom @ 6,987' MD 2 7,046' 5,237' Module #15 w/ cony. Flapper i 3 7,149' 5,333' Module #14 w/ cony. Flapper At 4 7,251' 5,430' Module #13 w/ cony. Flapper ' ( 5 7,316' 5,492' Module #12 w/ cony. Flapper f 6 7,419' 5,592' Module #11 w/ cony. Flapper TOC(Est.) 6,422' 1 _ e 7 7,475' 5,646' Module #10 w/ cony. Flapper 9 s /fY'F 8 7,597' 5,765' Module #9 w/ conv. Flapper 1:3 ty EXCAPE SYSTEM DETAILS 9 7,707' 5,873' Module #8 w/ conv. Flapper 1 _- 15 Excape modules placed 10 7,941' 6,105' Module #7 w/ conv. Flapper i f, - Green control line fires bottom 7 modules. 11 8,001' 6,165' Module #6 w/ cony. Flapper etZ a 2 - Red control line fires top 8 modules. 12 8,306' 6,470' Module #5 w/ cony. Flapper I , - Blue line for BHP monitoring. 13 8,385' 6,549' Module #4 w/ cony. Flapper s3 - Ceramic flapper valves below each module. 14 8,428' 6,592' Module #3 w/ cony. Flapper i t I 15 8,515' 6,679' Module #2 w/ cony. Flapper a ' L. ,I 14 4 16 N/A N/A Module #1- No Flapper PERFORATION DETAIL 'F 1, 5 Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status P e '`" 6 Beluga 7,027' 7,037' 5,219' 5,228' 10' Open r Beluga 7,130' 7,140' 5,315' 5,325' 10' Open ;1 I : 7 Beluga 7,232' 7,242' 5,412' 5,422' 10' Open Beluga 7,297' 7,307' 5,474' 5,484' 10' Open Install Straddle Packer Assembly Beluga 7,400' 7,410' 5,573' 5,583' 10' Open 8 *Top of packer @ 17,911' MD R Beluga 7,456' 7,466' 5,627' 5,637' 10' Open .,,i * WI I i 9 Beluga 7,578' 7,588' 5,746' 5,756' 10' Open i Beluga 7,688' 7,698' 5,854' 5,864' 10' Open • Beluga 7,922' 7,932' 6,086' 6,096' 10' Open L'-3 *r # € . Beluga 7,982' 7,992' 6,146' 6,156' 10' Open 1 r . 5 Beluga 8,287' 8,297' 6,451' 6,461' 10' Open ` Beluga 8,366' 8,376' 6,530' 6,540' 10' Open t t y Beluga 8,409' 8,419' 6,573' 6,583' 10' Open , ; " Beluga 8,496' 8,506' 6,660' 6,670' 10' Open ' Beluga 8,990' 9,000' 7,154' 7,164' 10' Open 12 t I 13 CEMENTING DETAIL 4 1 :1 1 ( Casing Detail W i t 'I i 14 13 -38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type -1 cmt, 100% returns, 40 bbls to surface t e 9 -5/8" 12 -1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G e 4 0 15 3 - 1/2" 8 -1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt Mc '1 16 Tagged 9,458'MD w/ 2.6 "GR 1/2/2010 411 . 1 , s TD = 9,777' / PBTD= 9,709' Revised By: TDF 4/1/2013 Cloverleaf #4 BOP • 3.98' 111 111 111111 t11 Itt 111 111 111'111 Coitid1 1.54 r �� ii' 27/8.5 vanables 11 "•5000 - p� a6 Sind 101 Qp ; lilr 111 1 . '111 lit , 00 4 ' Choke and Ka valves ? \‘‘6,04. 2 111610M ?Title- 'e h k 051' 06 One a dw ee1 .1111 - 111 111'111 111 111 2.00 ;t M ' I a e w121 /1851 - i M ; _ I • x _ 11l Ill 111111 111`:,' t r. a .,r s i. " ,yam $ .':::t,,,,,;'' . ,r.; ,- e fi 1@ , STATE OF ALASKA ` ALASKA OIL AND GAS CONSERVATION COMMISSION ` '` , REPORT OF SUNDRY WELL OPERATIONS AOG CC 1. Operations Abandon U Repair Well U Plug Perforations U Perforate U Other u Tubing Punch Performed: Alter Casing 0 . Pull Tubing ❑ Stimulate - Frac ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development El Exploratory ❑ 204 -005 3 Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic ❑ Service ❑ 6. API Number: Anchorage, Alaska 99503 (50 133 20534 -00 *'Q 7. Property Designation (Lease Number): 8. Well Name and Number: , ADL0373302/ADL0324602/FEE -TR73 Cannery Loop Unit 08 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): N/A Kenai C.L.U. Field / Beluga Gas Pool 1 1. Present Well Condition Summary: Total Depth measured 9,777 feet Plugs measured N/A feet true vertical 7,941 feet Junk measured 7,895 feet Effective Depth measured 7,895 feet Packer measured N/A feet true vertical 6,059 feet true vertical N/A feet 1 Casing Length Size MD TVD Burst Collapse Structural ' Conductor 100' 20" 121' 121' 3,060psi 1,500psi Surface 1,789' " 13 -3/8" 1,810' 1,636' 3,450psi 1,950psi Intermediate 6,701' 9 -5/8" 6,722' 4,941' 6,870psi 4,750psi Production 9,725' 3 -1/2" 9,746' 7,910' 10,160psi 10,530psi 1. Liner Perforation depth Measured depth See Attached Schematic SCANNED APR 0 4 2013 True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 3 -1/2" 9.3# / L -80 9,746' 7,910' Packers and SSSV (type, measured and true vertical depth) N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A • Treatment descriptions including volumes used and final pressure: N/A 113. Representative Daily Average Production or Injection Data . Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 5,000 167 0 272 Subsequent to operation: 0 0 0 0 0 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory Development 0 - Service ❑ Stratigraphic ❑ )ady Report of Well Operations X 16. Well Status after work: 00 ❑ — Gas 0 WDSPL ❑ L" GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ I "7. 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: 313 -095 Contact Shane Bennett Email sbennettahilcorp.com Printed Name Jerem ardambek Title Reservoir Engineer Signature / Phone 907 - 777 -8388 Date % A 77 Form 10 -404 Revised 10/2012 �_ MS APR 0 3 1013 � Y K ' " ` // Submit Original Only Kenai Gas Field II W 0 SCHEMATIC Last ell: Completed: CLU 8 2004 Hilcorp Alaska, LLC API: 50- 133 - 20534- 00 -S01 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm p 20" Conductor 133 / K -55 / N/A 18.73 Surface 133' 13- zo' 3/8 .. Surface 68 / K -55 / BTC 12.415 Surface 1,810' 9 -5/8" Intermediate 40 / L -80 / BTC -MOD 8.835 Surface 6,722' TUBING DETAIL k, I 3 -1/2" 1 Tubing 9.3 / L -80 / MOD 8RD I 2.992 1 Surface 9,746' i r i 3 0 � JEWELRY DETAIL roc(Est.) 4,8 o ÷., No Depth(MD) Depth(TVD) Item • ? ' b 1 6,952' 5,149' BHP Tank Bottom @ 6,987' MD rd i 2 7,046' 5,237' Module #15 w/ cony. Flapper 3 7,149' 5,333' Module #14 w/ conv. Flapper y 4 7,251' 5,430' Module #13 w/ conv. Flapper cx Ni 5 7,316' 5,492' Module #12 w/ conv. Flapper ' :., 6 7,419' 5,592' Module #11 w/ conv. Flapper TOC(Est.) 6,422' s ' t 7 7,475' 5,646' Module #10 w/ conv. Flapper 95/x'4 V 8 7,597' 5,765' Module #9w /cony. Flapper EXCAPE SYSTEM DETAILS 9 7,707' 5,873' Module #8 w/ conv. Flapper :, ri 1 _- 15 Excape modules placed 10 7,941' 6,105' Module #7 w/ conv. Flapper .v - Green control line fires bottom 7 modules. 11 8,001' 6,165' Module #6 w/ conv. Flapper 2 - Red control line fires top 8 modules. 12 8,306' 6,470' Module #5 w/ conv. Flapper 1 - Blue line for BHP monitoring. 13 8,385' 6,549' Module #4 w/ conv. Flapper - Ceramic flapper valves below each module. 14 8,428' 6,592' Module #3 w/ conv. Flapper I, 3 15 8,515' 6,679' Module #2 w/ conv. Flapper � 4 16 N/A N/A Module #1- No Flapper i I ik ., PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status r. I 6 Beluga 7,027' 7,037' 5,219' 5,228' 10' Open t ? Beluga 7,130' 7,140' 5,315' 5,325' 10' Open i ,,, 7 Weatherford Straddle packer Beluga 7,232' 7,242' 5,412' 5,422' 10' Open F ,.� ti assembly (Fish] 44 Beluga 7,297' 7,307' 5,474' 5,484' 10' Open N lip L 4, 8 - Tagged @ 7,895' Beluga 7,400' 7,410' 5,573' 5,583' 10' Open d On 3/27/2013 Beluga 7,456' 7,466' 5,627' 5,637' 10' Open 9 - Punched 4 holes into Packer Beluga 7,578' 7,588' 5,746' 5,756' 10' Open 5,864' 10' Open on 2/27/203 a Beluga 7,688' 7,698' 5,854' " Beluga 7,922' 7,932' 6,086' 6,096' 10' Open j �: 1D Beluga 7,982' 7,992' 6,146' 6,156' 10' Open - Beluga 8,287' 8,297' 6,451' 6,461' 10' Open Beluga 8,366' 8,376' 6,530' 6,540' 10' Open i *,...2 s , Beluga 8,409' 8,419' 6,573' 6,583' 10' Open +` 11 Beluga 8,496' 8,506' 6,660' 6,670' 10' Open 4.:, Beluga 8,990' 9,000' 7,154' 7,164' 10' Open 12 # I 13 C DETAIL Casing Detail M4 13 -38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type -1 cmt, 100% returns, 40 bbls to surface • ` 9 -5/8" 12 -1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G ;115 3 -1/2" 8 -1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt qt Olt i ' 16 Tagged 9,458' MD w/ 2.6 "GR 1/2/2010 a 1 ! b k j 1D. 9,777' / PBTD =9,709' Revised By: TDF 4/1/2013 • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU -08 50- 133 - 20534 -00 -00 204 -005 2/26/13 =_t-Lqh1 Daily pera ions = ;, _ Tr��Ir Il p�� I(IIIGl�i ,�= , 2/27/2013 - Wednesday , 111 , Spot equipment, PTW and JSA. Run line thru grease tubes and put rope socket on line. Build tubing punch gun. TP 700 psi. PT lubricator to 250 psi low and 2,500 psi high. RIH with 1- 11/16" x 3.5' tubing punch (loaded with 4 green nose perf pods, equally spaced out) and tie into schematic at the volume tank at 6,952'. Went down and tagged up approx 1' in the pkr at 7,912'. Work tools and tagged snap latch seal at approx 7,934' (ID - 1.75 "). Tried a few times to get thru but could not. Logged from there back up to volume tank. Counted the module and flapper and depths. Spotted tubing punch and punched 4 holes from 7,919' to 7,922.5'. TP was 720 psi when gun was shot. Saw no pressure change but saw tool string wt change. Had to work tools 350 Ibs over string wt to get tools moving. Pulled up to 7,700' and waited 20 min. Went back down and tried to get thru packer at 7,913'. Tools stuck again and got free. POOH. After 5 min TP was down to 700 psi, 8 min was 698 psi, 23 min was 680 psi. Rig down lubricator and turn well over to production. TP 630 psi off tree gauge. 2/28/2013 - Thursday No operations to report. 3/1/2013 - Friday 4 , r No operations to report. 3/2/2013 - Saturday �� ; P ' P1i,1 ' No operations to report. 3/3/2013 - Sunday 4 . = . .v i No operations to report. 3/4/2013 - Monday No operations to report. 3/5/2013 - Tuesday PT lubricator to 250 psi low and 2,500 psi high. RIH with 2 -1/4" x 7' pump bailer and bailed from 7,711' KB to 7,743' (12 runs) with bailer full of formation sand. Fluid level was at 4,600' +/- at start with TP at 150 psi. and 5,387' with 375 psi on tubing at ✓ end of shift. Went on 24 hr with 2 crews. Crew change at midnight. PTW, JSA. RIH with 2 -1/4" x 7' pump bailer and bailed from 7,741' KB to 7,743' KB (2 runs). Bailer full of sand. On second run noticed fluid level at 4,900'. Checked TP and it was down to 200 psi. Tag up at 7,741' on both runs and bailed to 7,743'. Waited 45 min to see if fill comes in. RIH and tag at 7,739'. We are getting 3/4 to full bailer of sand out each run. Saw fluid level at 4,650' KB with still 200 psi on tubing. • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU -08 50- 133 - 20534 -00 -00 204 -005 2/27/13 3/6/2°13- Wednesday Making multiple runs(11) w/ 2 -1/4" DD bailer. Bailing sand from 7,745'kb to 7,751'kb. Run 2 prong wire grab to 7,751'kb. Work tools. No latch. POOH No wire. Run 2 -1/2" JDC to 7,751'kb. WT No latch up. POOH. Run 2 -1/2" pump bailer from 7,751'kb to 7,756 "kb. Run 2 -1/2" DD bailer to 7,759'kb. Run 2 -1/2" LIB to 7,759'kb. Tap once. POOH LIB shows wire marks. Recover 8" piece of wire around neck of LIB. Make two runs with 2 prong grab. Grabs came back empty. Call w/I supervisor. 3/7/2013 - Thursday Standing by waiting for tools. Run 2 -1/2" RB "baited" w/ 3 -1/2" wirefinder and spear to 7,759'kb. Latch fish -wire. Hit four 1,600# jar licks. PUH to 7,648'kb dragging 2,200 #. Pull free. Still have 250 -300# overpull. POOH. OOH No Wire Lost one barb on prong. Run same to 7,586'kb. WT POOH OOH recover 1' of bent wire. Crew change out. RIH w/ 2 prong wire grab to 7,558'kb latch fish. PUH Get hung up in module #14 work tools. POOH. Recover 3' of wire. RIH w/ 2 prong wire grab to 7,670'kb. Latch wire POOH Recover 4' of wire and a complete flapper ring. RIH w/ same to 7,759'kb. Latch wire PUH 300# heavy POOH Recover ball of wire. Approximately 32' of wire. RIH w/ 2 prong grab to 7,856'kb. This is deeper than last run. Continue running 2 prong wire grab. Recovering 1' of wire. ; Run 2 -1/2" JDC to 7,858'kb. Unable to latch fish. Run pump bailer. Recover 1 cup of sand. Run multiple runs w/ 2 -1/2" DD bailer to 7,864'kb Recovering 1/3 of a bailer of sand and 4" piece of wire in bailer. Make two runs w/ 2 prong wire grab to 7,864'kb No wire recovered. 3/8/2013 - Friday Run 2 -1/2" DD bailer to 7,839'kb. Bailer 1/2 full of sandRun same to 7,864'kb Recover 1 cup of sand. Rin 2 -1/2" LIB to 7,864'kb. Tap down once. LIB indicates sand, but no wire marks or indication of rope SocketContinue bailing w/ 2 -1/2" pump bailer. Run 2 -1/2" JDC to 7,858'kb. Getting good bites. Keep working tools. Latch fish and hitting 3,200-3,600# jar licks. Think we are seeing two sets of jars -the small set on lower tool string and the upper long strokes. Possible movement - slippage of fishJarred free. Broke something. OOH Dogs on pulling tool are bent. Recover small piece of wire in pulling tool. Re -run same. No latch -ups. OOH Piece of wire in tool. Run 2 -1/2" pump bailer. Recovered 1' of sand in bailerRlH w/ 2 -1/2" (HD) JDC to 7,861'kb. Friction bites. OOH Metal marks on skirtRun 2 prong wire grab to 7,858'kb. Friction bites. OOH No wire. Bail to 7,866'kb and bailer comes back empty. Ran 2 -1/2" LIB to 7,867'kb. Tap down once. OOH LIB has slight depression in center. No help. Ran 2 -1/2" RB. Unable to latch fish. Lost spangs POOH Oil jars failed. RIH w/ 2 prong wire grab to 7,868'kb. OOH No wireRun 2 -1/2" pump bailer to 7,867'. Comes back empty. Run 2 -1/2" LIB Tap down twice. OOH LIB has two sets of 1/8" deep wire marks near center. Run center spear to 7,870'kb. No bites.Run 2 -1/2" RB w/ brass pin to see if we can get a latch. Latch. Jar twice and shear off. 3/9/2013 - Saturday • • Run 2 -1/2" JDC to 7,866'kb. WT fell to 7,871'kb. WT but would not latch. Possible pin sheared. OOH Pin not sheared. Re- pin.RIH w/ same to 7,868'kb. Beat down to 7,871'kb. Friction bites not latch POOH to check pin. Not sheared. RIH w/ same to 7,872'kb. Beat down. Latch fish but pulls free after a single jar lick. Three times. RIH w/ 2 prong wire grab tp 7,870'kb. No wireRlH w/ 1 -3/4" magnet to 7,870'kb. WT. OOH recover fine metal shavings but no wire. Change crew. RIH/ 2 -1/4" pump bailer. Bail sand. Recover 1/4 bailer full. Continue bailing. RIH w/ 2 -1/2" (HD) JDC to 7,872'kb. Latch Pull 2,900# jar lick. Jar free. Latch Hit 2,350# jar lick. Jar free. Hit 1,900# spang licks. OOH Wire marks on JDCRun 3 prong grab. Good overpulls. POOH bent up wire grabRun 2 -1/2" JDC to 7,872'kb. Hit 2,100- 2,200# jar Ticks but pull free. Run 2 prong wire grab to 7,874'kb. Getting good grabls. Hit 2,000# jar lick. Pulled free POOH No wire. Make three runs w/ 2 -1/2" JDC Getting 2,000 and 3,000# friction bites. OOH Wire marks on face of JDC. Run 2 prong wire grab to 7,877'kb. Good friction bites. OOH Prongs bent inwardRun 2 -1/2" pump bailer to 7,877'kb. Change to Daylight Savings. OOH Bailer empty. RIH w/ 2 -1/2" JDC "baited" w/ 2.80" 0 bannion overshot to 1,500' and sat down. POOH. RIH w/ same "baited" w/ 2.32" overshot to 7869'kb. WT to 7,878'kb. Can not engage fish. POOH. 3/10/2013 - Sunday No operations to report. 3/11/2013 - Monday No operations to report. 3/12/2013 - Tuesday No operations to report. 11 Hilcorp Alaska LLC W eekly Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU 08 50- 133 - 20534 -00 -00 204 -005 2/27/13 N � a "u� =` . i � 1 i�l� 9 ry � i � i ° 'HI�III��I�I��'9 6� z.; ,�� `, Ii �m� IP I�._ k=� 1101) 41 �tl". "- "` � �'��m '� 1 1: 111 9I�� 1 11�� 14 3/20/2013 - Wednesday Start equipment. Make 360 bbls 6% KCL. Install XO flange /BOP'S on top of tree. Attach hydraulic lines to BOP's. Notified AOGCC on Monday 3/18/2013 via website of upcomming BOPE test. No response from Mr Regg. Called Mr. Regg Tuesday about 11:00 am. Mr. Regg waived witness at that time. Steam on Wheels begins heating fluid tank. Visually function test Dual Combi BOP's. Circulate lines with MEOH. Pressure test blind /shear rams 250 psi low /4500 psi high. Test good. Install test bar in pipe rams. Pressure test pipe /slip rams 250 psi low /4500 psi high. Test good. Test accumulator. Install pig catcher on coil. Carry injectror to wellhead. Pump 3 bbls MEOH into coil. Launch coil pig. Pump 31 bbls behind pig. Taking returns to MEOH tank. Set injector back in craddle. Recover pig from coil. RD for the night. 3/20Q13- Thursday Hold PJSM. Start equipmet. PU 26' of lubricator. Install coil grapple. Pull test to 25K. Grapple slipped on coil. Cut off coil. Install new coil grapple. Pull test to 25K. Test good. PU DFCV, CTT jars, Hydraulic disconnect, Dual circ sub, y ankee screwdriver, and 1.90" ID mule shoe. Displace coil over to 6% KCL. Work srew driver - picking up and setting down on fish. POOH. Tattle tale pins in muleshoe not broken. Did not get down over rope socket. PU 2.38" ID overshot. Displace coil to 50/50 MEOH. Suspend operations for the night. Pumped 100 bbls of KCL into well. 3/22/2013 - Friday Hold PJSM. Discuss JSA. Displace coil to 6% KCL water. RIH w/ Yankee screwdriver and 2.38 "ID muleshoe. Tag at 7,882.5' ctm. Set 50014 on screwdriver. PU Increase setting weight to 5,000 #. Repeat setting down procedure twenty eight times, causing 7 complete rotations of the mule shoe. Work tool to 7,884.6' ctm. POOH. No tattle tail pins broken in mule shoe(Didn't get over RS). PU VPI Motor and 2.72" mill w/ 1.86 "ID. RIH to tag depth 7,856' ctm. Begin milling. Have some depth control issues, resulting in stalling the motor at 7,853 -54'. Continue milling. Increase pump rate to 1.25 BPM. Appears to be milling wire. PU above tag depth 2'. Start motor at 7,850', but motor stalls before we can begin RIH. PU to 7,834', Start motor at 1.5 BPM. Motor stalls again before we begin RIH. POOH Pulling heavy. OOH. No wire. Missing a few carbides on mill. Displace coil to MEOH. Warm stack equipment for the night with night crane and coil operators. 3/23/2013 - Saturday s �sF . Hold PJSM. Discuss JSA. Discuss yesterdays events and milling operations w/ Pete I, BOT fisherman, and coil supt. Decided to check for wire in well. S/L unit available. Stand down coil unit ancd crane. Wait on slickline unit. RU slickline unit. PU 60' of lubricator. MU standard 1 -3/4" tool string. PTest lubricator. RIH w/ 3 -1/2" wirefinder and wire spear. Set down 266' high. RIH w. 3 -1/2" wirefinder and two prong grab. PUH heavy. Bent wirefinder in flapper modure. Pulled hard thru every flapper housing coming out of hole. RIH w/ two prong wire grab to 7,889'kb. This is 15' deeper than any previous run. RIH w/ fluted centralizer, 2 -1/5" magnet to 7,890'kb. OOH recover 1 small piece of wire and 1/4 Cup milling fines. RIH w/ fluted cemtralizer and 2 -1/4" LIB to 7,890'kb. Tap down 3 times to 7,891'. POOH. OOH face of LIB is clean but must be within a couple feet of fish. Discuss and decide to bail fill in the morning. RD for the night. 3/24/2013 - Sunday • • • RU slickline unit. SITP 130 psi. RIH(1) w/ 2" DD bailer to 7,889'kb. OOH bailer 1/2 full. Wire marks on lip of mule shoe. RIH(2) 2/ 2 -1/2" pump bailer to 7,890'kb. OOH bailer half full pasty mud. RIH(3) w/ same to 7,890'kb. Work to 7,893'. OOH bailer empty. RIH(4) w/ 2 -1/2" fluted cemtralizer and 2 -1/2" LIB to 7,891'kb. Tap down three times. to 7,891'kb. TOOH Wire marks around outer edge of LIB and a "divit" in the center perhaps caused by a bent piece of wire. RIH(5) w/ single prong wire spear to 7,891'kb. Three good 1,300# bites. OOH No wire. RIH(6) centralizer and 2 prong grab to 7,890'kb. Getting bites. No wire.RIH(7) w/ alligator grab to 7,890'kb. No bite. LD slickline for the night. Cut wire and re -pack stuffing box. 3/25/2013 - Monday Hold PJSm. SITP 135 psi. PU lubricator and standard 1 -3/4" tool strgRlH(1) 2 -1/2" pump bailer to 7,700'. Can't get below flapper pocket at 7,707'. POOH Add knuckle joint. RIH(2) w/ 2 -1/2" pump bailer to 7,883'kb. WT OOH recover 3/4 bailer fulIRIH(3) w/ 2 -1/2" DD bailer to 7,884'kb. WT to 7,891'kb. OOH recover 3/4 full bailer. RIH(4) w/ 2 -1/2" pump to 7890'kb ; RIH(5) w/ 2 -1/2" LIB to 7893.5'kb OOH see wire mark on outside edge. No marks in center. RIH(6) w/ 2- 7/8(2.25 "OD) wire finder and small 2 prong wire grab to 7,894'kb. WT to 7,897'. Getting good bites. Continue working to 7,898'. Getting 1,100- 1,400# bites before slipping off. ContinueWT to 7,899' getting 1,700- 2,000# pulls. RIH(7) w/ 2 -1/2" RB down to 7,896'. WT good bite to 2,300 #. Continue WT but no good bites. RIH(8) 2 -1/2" JDC w/ 2.66 skirt. Set down at 7,890'. This is the same spot that the pump bailer set down earlier. This is probably our wire ball on the wall of the pipe -like a stent in an aurtory. RD slickline for the night. Move equipment out of the way for coil RD tomorrow. 3/26/2013 - Tuesday Rigging down. • • II Hilcorp Alaska LLC W eekly Operations Summary Well Name API Number Well Permit Number Start Date En d D ate yy +} y CLU 08 50- 1 - 20534 -00 -00 204 -005 2/ 3/28/13 �i ( c eriiti 4 � 'i 4� K _ f III d t , �'� d i Y 3 1 d1� +` i =a"'� 3 r 41� Y ( w41 Gi . G : � �w 1 I � � la �. GIy F , aG G 1,,, :— _ alb.. 3/27/2013 - Wednesday i 1, Hold PJSM and discuss JSA. PU standard 1 -3/4" tool string. PU 70 of lubricator. SITP 260 psi. Pressure test lubricator to 250 psi low and 2,500 psi high. RIH(1) w/ single prong wire g to 7,92'k W tool area suspe w IatchRIH(2) w/ different single prong wire grab to 7,892' WT rab No bites , b. POOH. ork RIH(3) thru w/ 2 this 1/2" SB for to 7,895'kb. cted WT ire Good bites to 2,400# ; RIH(4) w/ 2 -1/4" pump bailer to 7,891'kb WT. OOH recover 1' of dirt. RIH(5) w/ 2 -1/2" SB to 7,892'. W ball. T No poor bites. Pull up to 2,200# but slip off. RIH(6) w/ 2 -1 DD bailer to 7c,895'kb. OOH recover 18" of dirt. RIH(7) w/ 2 1/2" split skirt SB to 7,895'kb. WT Set down on fish, PU to 2,400 #. Ho, , lick to 2,000 #. ldweight Still holding slowly on. falling Slack off. off PU to again recock to 2 jars 500 #. and Slowly slipps falls to 2,000# before slipping off. PU again to 2,500 #. Hit jar offContinue working SB. More bites but no solid hook up. RD and move offsite. No operations to report. 3/28/ 3/29/2013 013 - Fri y 4: 4 � No operations to report. ) 3 r . / t No operations to report. 3/31/2013 -Sunday 30 2013 - Saturday No operations to report. 4/1/2013 - Monday No operations to report. 4/2/2013 - Tuesday No operations to report. • • Schwartz, Gu y L (DOA) From: Schwartz, Guy L(DOA) Sent: Friday, March 01, 2013 1:37 PM To: 'Tom Fouts' Cc: Keith Elliott;Jeremy Mardambek;Chris Myers;Shane Bennett- C Subject: RE:Operation Update/Modification request for CLU-0 PTD:204-005 t You have verbal approval to reset the upper section of patch (with tubing punches) and restore the patches integrity. Submit all well work in the final 10-404 report that is submitted. Guy Schwartz Senior Petroleum Engineer AOGCC SCANNED JUL 2 9 2013 907-444-3433 cell 907-793-1226 office From:Tom Fouts [ma ltc_ttouts,o h'Icorp,fore;] Sent: Friday, March 01, 2013 12:54 PM To: Schwartz, Guy L(DOA) Cc: Keith Elliott; Jeremy Mardambek; Chris Myers; Shane Bennett- (C) Subject: Operation Update/ Modification request for CLU-08 PTD: 204-005 Guy, We have completed the attached procedure in its entirety. Unfortunately the well began producing water which killed gas production. The request is to go back in and install a new tubing patch while we are still on location. Can you please advise what necessary steps need to be taken to make this happen? Thanks, Tom Fouts I Ops/Reg Tech Hilcorp Alaska, LLC/ Direct: (907) 777-8398 Mobile: (907}351-5749 1 • w ` \ I %% 6■ 9 THE STATE Alaska Oil and as of l LLl 1sKA Conservation Commission q GOVERNOR SEAN PARNELL 333 West Seventh Avenue F �. Anchorage, Alaska 99501 -3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Shane Bennett HEM �IPR 1 1 2Q Operations Engineer Hilcorp Alaska, LLC _ 0 3800 Centerpoint Drive a,O 4 Anchorage, AK 99503 Re: Kenai C.L.U. Field, Beluga Gas Pool, Cannery Loop Unit 08 Sundry Number: 313 -095 Dear Mr. Bennett: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P Foerster Chair DATED this day of February, 2013. Encl. • 0 RECEIVED STATE OF ALASKA FEB 2 5 2013 _ ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS OGCC 20 AAC 25.280 11 Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other. Tubing Punch el • 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development El 2-. c - = ' `--,/ / . 2 7 . ( 3 3. Address: Stratigraphic ❑ Service El 6. API Number. 3800 Centerpoint Drive, Anchorage AK, 99503 50- 133 - 20534 -00 • 7. If perforating: Z 3 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? Rule #3 of C00 ,23$ 2.2," l '3 Will planned perforations require a spacing exception? Yes ❑ No 6 Cannery Loop Unit 08 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL0373302/ADL0324602/FEE -TR73 Kenai C.L.U. Field / Beluga Gas Pool • 11. • PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9,777' 7,941 • 9,709' 7,873' N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 100' 20" 121' 121' 3,060 psi 1,500 psi Surface 1,789' 13-3/8" 1,810' 1,636' 3,450 psi 1,950 psi I Intermediate 6,701 9 -5/8" 6,722' 4,941' 6,870 psi 4,750 psi Production 9,725' 1 3 -1/2" 9,746' 7,910' 10,160 psi 10,530 psi Liner ,Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Proposed Schematic See Proposed Schematic 3 -1/2" 9.3# / L -80 9,746'1 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A N/A 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Q 1 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 2/25/2013 Oil ❑ Gas 0 ■ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: N/A WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Shane Bennett Email sbennett aahilcorp.com Printed Name v , e L' Title Operations Engineer Signatur- D/ \ Phone 907- 777 -8425 Date 2/25/2013 J — COMMISSION USE ONLY Con• "ions of approval: Notify Commission so that a representative may witness Sundry Number: .51 fj n ...oil 5 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test E] Location Clearance ❑ ,ther: '; . R BDMS MAR 0 1 201.3 , Spacing Exception Required? Yes ❑ No ❑ Subsequent Form Required: / G _ `� O '--r (2.1,, APPROVED BY Approved by: P COMMISSIONER THE COMMISSION Date: 2 -- /3 4 92)(Ailer Submit Form and r t3t A L Approved application is valid for 12 m nths from the date of approval. Attachments in Duplicate • • Well Prognosis Well: CLU 08 Hilcorp Alaska, LL Date: 2/20/2013 Well Name: CLU - 08 API Number: 50- 133 - 20534- 00 -S01 Current Status: Gas Producer Leg: Estimated Start Date: 2/25/2013 Ri : Cloverleaf Rig g g 4 Reg. Approval Req'd? 10 -403 Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts 777 -8398 Permit to Drill Number: 204 -107 First Call Engineer: Shane Bennett (907) 777 -8425 (0) (325) 203 -7487 (M) Second Call Engineer: Chris Myers (907) 777 -8333 (0) (907) 398 -9955 (M) AFE Number: Current Bottom Hole Pressure: —900 psi Calculated from performance Maximum Expected BHP: —1,200 psi @ 6,000' TVD Max. Anticipated Surface Pressure: —650 psi Assumed from performance Brief Well Summary CLU -08 was drilled 2004 with an Escape completion. The well produced gas only until mid -2006 when the water production started at 50 -100 BWPD. In 6/2010 a 20' temporary tubing patch was installed over the perfs at 7922 -7932 based on faulty log analysis. This did stop some water production but also cut off 2 MMSCFD of gas production. Justification: Tubing patch installed over the wrong set of perfs. CL -01 pad should be able to handle the additional water. - Recommendation: My inspection of the analysis done on the spinner Togs indicates the log analysis is incorrect and the majority of • the water production is from the bottom and second set of perfs at 8990 and 8496. Punch 2 3 /8 spacer joint covering the perfs at 7992 -7932 and production should return to 4 MMSCFD. Risks: Wall between casing and patch could be full of solids, either way we would have to punch spacer joint to pull patch for equalization, if we had to pull, which is the plan in the near future. Pulling a tubing patch that has been downhole for 2+ years. ** *Note saying cap string was pulled in 8/2010 but check first * ** Summary Procedure 1. RU Slick line and test lubricator to 250psi low /2,500psi. 2. RIH with 1 11/16 to max of 1 y" gauge ring, crossover, spang jars, oil jars and stem and tag, ( + / -) 7928' no deeper, record depth, POOH. 3. RIH GR /CBL, from 5,700' to 500'. 4. RU E -Line and test lubricator to 250psi low /2,500psi. 5. RIH GR /CCL /15' tubing punch, 4pf, correlated with Tie in log and gauge assembly to +/- 7928'. 6. Punch 5'bottom of 2 3 18 spacer joint, punch 5' middle of 2 3 /8 spacer joint and punch 5' top of 2 3 /8 spacer joint, total holes 30holes, well has casing perforations behind spacer joint. 7. POOH E-Line watching weight for changes of trip e atc gpr essur ean d i h egtr n oaych n ag p in. 8. RD E -line. . • • Well Prognosis Well: CLU 08 Hilcorp Alaska, LL Date: 2/20/2013 Attachments: 1. As -built Well Schematic 2. Proposed Well Schematic • i Permit #: 204 -005 C L U - 8 l! ' ♦ `` . '" API #: 50- 133 - 20534- 00 -S01 Marathon Oil Prop. Des: P 1 Alaska Production LLC. KB Elevation: 42' (21' AGL) 208' FSL, 486' FEL WBS #: DD.03.09594.CAP.CMP.01 Sec 7, T5N, R11W, S.M. con X: 272,484.840 20" K -55 133 ppf Y: 2,388,660.970 Top Bottom Spud: 01/25/2004 MD 0' 122' TD: 02/8/2004 TVD 0' 122' Riq Released: 02/13/2004 @ 06:00 hrs. LLI PA: Surface Casing 13 -3/8" K -55 68 ppf BTC Top Bottom MD 0' 1,810' TVD 0' 1,636' Tree crossing = 4 - 3/4" Otis A 6" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type-1 cmt, 100% returns, 40 bbls to surface Top of Cement (est.) Intermediate Casing 4,800' MD Sterling C1 9 - 5/8" L - 80 40 ppf BTC - MOD @ 6,422 MD (300' above 9 - 5/8" shoe) ^ Interval: MD T O p Bottom 6,722' +1 6690 -6945 ft MD TVD 0• 4,941' 12 -1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G Excape System Details . BHP monitoring line (yellow) volume tank located from 6,952' - 6,987' Production Tubing 3 -1/2" L 0 9.3 ppf Mod 8rd To Bottom Weatherford Straddle packer assembly �) MD 9,746 *Mod #7 (6/15/10) ? TVD 0' 7,910' * Top of packer @ 7,911' MD RKB -D 8 -1/2" hole Cmt w/ 1,430 sks (293 bbls) of * WEA ER Packer (ID: 1.812 ") = 2.87' ) 15.8 ppg, class G cmt 3,600# to release » r *2-3/6' spacer pipe (ID: 1.995')= 20.1' * WEA Snap latch seal (ID: 1.75')= 0.95' 1 . 3,600# to release [ Excape System Details * WEA ER Packer (ID: 1.812 ") = 2.69' ll [ - 15 Excape modules placed B- - Green control line fires bottom 7 modules 1 l } - Red contol line fires top 8 modules ) P t ��" - line for BHP monitoring r - Ceramic flapper valves below each �� module Excape System Details 1 - - 14 Conventional flappers e . L Beluga Perfs (MD): - Mod. 1 - no flapper Module 15 = 7,027'- 7,037' - - Ceramic flapper valves below Module 14 = 7,130'- 7,140' each module as follows: D j Module 13 = 7,232'- 7,242' • Flappers MD (RKB): I Module 12 = 7,297' -7,307 Module 15 = 7,046' 0 t C ' Module 11 = 7,400'- 7,410' Module 14 = 7,149' Di f 7: Module 10 = 7,456- 7,466' Module 13 = 7,251' Module 9 = 7,576- 7,588' - Module 12 = 7,316' DI f Module 8 = 7,686- 7,698' Module 11 = 7,419' _. - - - , • ' , • - ' Patched 6/15/10. Module 10 = 7,475' f Module 6 = 7,982' - 7,992' , Module 9 = 7,597' Module 5 = 8,287' - 8,297' • Module 8 = 7,707' II Module 4 = 8,366' - 8,376' Module 7 = 7,941' ∎ , Module 3 = 8,409' - 8,419' - Module 6 = 8,001' �� Module 2 = 8,496' - 8,506' Module 5 = 8,306' / Module 1 = 8,990'- 9,000' in Module 4 = 8,385' Tagged @: 4. Module 3 = 8,428' 9,430' MD w/ 2.74" GR (12/17/09) EN Module 2 = 8,515' 9,458' MD w/ 2.60" GR (1/2/10) Module 1 = NA TD PBTD 9,777' MD 9,709' MD 7,941' TVD 7,873' TVD Well Name & Number: Cannery Loop Unit # 8 Lease: Cannery Loop Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country:I USA Perforations (MD): 7,027' - 9,000' Perf (TVD): 5,219' - 7,165' Angle @ KOP & Depth: 5.05° / 100 ft @ 250' MD Angle @ Perfs: 22° -. 0.5° Date Completed: 4/28/2004 Ground Level: 21' (Above MSL) I RKB: I 21' (AGL) Revised by Kevin Skiba Revision Date: 11/29/2011 r • • Kenai Gas Field • Well: CLU 08 PROPOSED Last Completed: 2004 Hilcorp Alaska, LLC API: 50- 133 - 20534- 00 -S01 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm f 20" Conductor 133 / K -55 / N/A 18.73 Surface 133' a 20 , w 3/8" Surface 68 / K -55 / BTC 12.415 Surface 1,810' I V ' 9 -5/8" Intermediate 40 / L -80 / BTC -MOD 8.835 Surface 6,722' .44 1 TUBING DETAIL A 3 -1/2" 1 Tubing 9.3 / L -80 / MOD 8RD 1 2.992 Surface 1 9,746' ow 13-3/8" t JEWELRY DETAIL Toc(Est) 4,800' h' No Depth(MD) Depth(TVD) Item 4!; t 1 6,952' 5,149' BHP Tank Bottom @ 6,987' MD „';. ) „ 2 7,046' 5,237' Module #15 w/ cony. Flapper ` 3 7,149' 5,333' Module #14 w/ cony. Flapper it E 4 7,251' 5,430' Module #13 w/ conv. Flapper `;+ 5 7,316' 5,492' Module #12 w/ conv. Flapper >' f' 6 7,419' 5,592' Module #11 w/ conv. Flapper - roc (Est.)6,azY �' t1, 7 7,475' 5,646' Module #10 w/ conv. Flapper 9-sir X1t :- ),s 8 7,597' 5,765' Module #9 w/ conv. Flapper ! ' EXCAPE SYSTEM DETAILS 9 7,707' 5,873' Module #8 w/ conv. Flapper J 1 _ 15 Excape modules placed 10 7,941' 6,105' Module #7 w/ conv. Flapper - Green control line fires bottom 7 modules. 11 8,001' 6,165' Module #6 w/ conv. Flapper t 4i, i 2 - Red control line fires top 8 modules. 12 8,306' 6,470' Module #5 w/ conv. Flapper ``' - - Blue line for BHP monitoring. 13 8,385' 6,549' Module #4 w/ conv. Flapper ' , S ' ,, - Ceramic flapper valves below each module. 14 8,428' 6,592' Module #3 w/ conv. Flapper s i 3 ., rr, 15 8,515' 6,679' Module #2 w/ conv. Flapper th Y',;. 4 16 N/A N/A Module #1- No Flapper :� 4+, �,, Weatherford Straddle Decker PERFORATION DETAIL td l re', 5 assembl f , ;' ; * Mod #7 (6/15/10) Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status �, 1 ' + . 6 * Top of packer @ 7,911' MD RKB Beluga 7,027' 7,037' 5,219' 5,228' 10' Open dy* 8 * WEA ER Packer (ID: 1.812 ") = Beluga 7,130' 7,140' 5,315' 5,325' 10' Open ' '"-:,ii " i " ` 7 3,600# to release Beluga 7,232' 7,242' 5,412' 5,422' 10' Open 'y i, ,, .t * * 2 - 3/8" spacer pipe (ID: 1.9951= Beluga 7,297' 7,307' 5,474' 5,484' 10' Open 1 '. 20.1' Beluga 7,400' 7,410' 5,573' 5,583' 10' Open . ` i Beluga 7,456' 7,466' 5,627' 5,637' 10' Open et, 1 ; * g Beluga 7,578' 7,588' 5,746' 5,756' 10' Open t, "+ w,, Beluga 7,688' 7,698' 5,854' 5,864' 10' Open ` *�' Beluga 7,922' 7,932' 6,086' 6,096' 10' Open •; Beluga 7,982' 7,992' 6,146' 6,156' 10' Open i 0= 1 10 Beluga 8,287' 8,297' 6,451' 6,461' 10' Open 4 +..4 ', Beluga 8,366' 8,376' 6,530' 6,540' 10' Open '' s, sr Beluga 8,409' 8,419' 6,573' 6,583' 10' Open _, - 7°, ,..11 Beluga 8,496' 8,506' 6,660' 6,670' 10' Open VA 1.1,4 Beluga 8,990' 9,000' 7,154' 7,164' 10' Open 11 *t z ; 12 'At tit P ROPOSED TUBING PUNCH DETAIL I 13 Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT / 6 ` 1. 1 ±7,929' ±6,088' ±6,093' 5' / s 1 ±7,930' ±7,935' ±6,094' ±6,099' 5' ✓✓✓ ±7,936' ±7,941' ±6,100' ±6,105' 5' rlo 1 P 15 Note: TOP of Spacer in Module #7 is from 7,924' to 7,944' I A a 16 CEMENTING DETAIL Tagged9,458'MDw/ Casing Detail 2.6"GR 1/2/2010 v it _ �� 13 -38" 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type -1 cmt, 100% returns, 40 bbls to surface s 9 -5/8" 12 -1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G i _.V ��' 6 . w . 3 -1/2" 8 -1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt TD= 9,777' / PBTD= 9,709' Revised By: TDF 2 -25 -2013 • Marathon Alaska Production LL i r �.,�� Alaska Asset Team Marathon it P.O. Box 1949 Kenai, AK 99611 Telephone (907) 283 -1371 Fax (907) 283 -1350 March 30, 2012 4 NMED APR 0 5 201 RFCENED Cathy Foerster Alaska Oil & Gas Conservation Commission APR 333 W 7 Ave Gay �,nch Conora 9 s, Commission Anchorage, Alaska 99501 Reference: 10 -404 Report of Sundry Well Operations Field: Cannery Loop Field �V Well: Cannery Loop Unit #8 Dear Ms Foerster, 'zi;ANNED APR 0 5 2012 Attached for your records is the10 -404 Report of Sundry Well Operations for CLU -8 well. This report covers the MIT testing work performed in preparation for gas injection into the CINGSA Gas Storage project. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Sincerely, i i <J2ArtA.A-' * la-42-- Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10 -404 Report of Sundry Well Operations cc: Houston Well File MIT Test form Kenai Well File (2) KJS • STATE OF ALASKA ALASIPOIL AND GAS CONSERVATION COMMION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Repair Well Plug Perforations S timulate Other ✓ P H P LJ 9 H H MIT Test u Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Marathon Alaska Production LLC Development Q Exploratory 204 - 005 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ 6. API Number: Kenai Alaska, 99611 - 1949 50 133 - 20534 - 00 - 00 7. Property De, ig n (Lease Number): .. 8. Well Name and Number: Lt ADL - 324602 37330;_ r)< 1(L " Canner Loc.). Unit #8 9. Field /Pool(s): -.- Cannery Loop Field / Beluga Pool - --- -' `� N t , 10. Present Well Condition Summary: Total Depth measured 9,777' feet Plugs measured NA oil ' 2012. true vertical 7,941' feet Junk measured NA fr t ,,�. Cammissioa Effective Depth measured 9,709' feet Packer measured NA ' , y , . , true vertical 7,873' feet true vertical NA feet "' - Casing Length Size MD TVD Burst Collapse Structural Conductor 100' 20" 121' 121' 3,060 psi 1,500 psi Surface 1,789' 13 -3/8" 1,810' 1,636' 3,450 psi 1,950 psi Intermediate 6,701' 9 -5/8" 6,722' 4,941' 6,870 psi 4,750 psi Production 9,725' 3 -1/2" 9,746' 7,910' 10,160 psi 10,530 psi Liner Perforation depth: Measured depth: 7,027' - 9,000' feet True Vertical depth: 5,219' - 7,165' feet Tubing (size, grade, MD & TVD): Excape Tubing 3 -1/2" L -80 9,746' MD 7,910' TVD SSSV: NA NA MD NA TVD Packers and SSSV (type, MD & TVD): Packers: NA NA MD NA TVD 11. Stimulation or cement squeeze summary: Intervals treated (measured): Performed MIT test in preparation for the CINGSA gas storage project. Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 3,225 150 1 395 Subsequent to operation: 0 3,025 150 1 393 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run Exploratory ❑ Development El ^ Service ❑ Stratigraphic ❑ Daily Report of Well Operations 15. Well Status after work: Oil ❑ Gas U— WDSPLLi GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 312 - 029 Contact Kevin Skiba (907) 283 -1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative Signature jA)'ttiu .%3 a Phone (907) 283 -1371 Date March 30, 2012 it RBDMS APR 0 4 2012 1 /I // t-- Form 10 -404 Revised 10/2010 Submit Original Only a `/7/2- • • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.regq(o�alaska.00v; doa.aoocc.prvdhoe.bay(a alaska.gov; phoebe.brooks aaalaska.gov; tom.maunder(8 alaska.00v OPERATOR: Marathon Oil Co. FIELD I UNIT 1 PAD: KGF /Cannery Loop DATE: 03/01/12 OPERATOR REP: Mike Sulley AOGCC REP: Matt Herrera Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. / Well CLU 8 Type Inj. NA ND 4941* Tubing 420 420 420 420 Interval 0 A P.T.D. 204 -005 Type test P Test psi 500 Casing 20 540 530 527 P/F P Notes: *9 - 5/8" shoe OA NA NA NA NA Took 29 gas to fill. Recovered 29 gals. Well Type Inj. ND Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type In]. ND Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type In]. ND Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type In]. ND Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey T = Test during Workover W = Water D = Differential Temperature Test 0 = Other (describe in notes) This well is a producer. Testing 3 -1/2 x 9 -5/8" annulus. Test was performed in accordance w/ Storage Injection Order NO. 9, Rule 5 Sundry Number 312 -029 Form 10 -426 (Revised 06/2010) MIT CLU 03 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: Monday, March 12, 2012 Rel =� � P.I. Supervisor 1 5I V. SUBJECT: Mechanical Integrity Tests MARATHON OIL CO 08 FROM: Matt Herrera CANNERY LOOP UNIT 08 Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry Z NON- CONFIDENTIAL Comm Well Name: CANNERY LOOP UNIT 08 API Well Number: 50- 133 - 20534 -00 -00 Inspector Name: Matt Herrera Insp Num: mitMFH120307102321 Permit Number: 204 -005 -0 Inspection Date 3/1/2012 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Weil 08 ' Type Inj. N ' 1 TVD 1 IA 20 J 540 , 530 527 - PTD i 2040050 - TypeTest SPT Test psi 500 , OA Interv OTHER P/F , P � Tubing 420 420 420 420 Notes: Monobore completion NO OA. MIT performed for CINGSA order no. 9 Sundry 312 -029. tQV/ JU �D 2 Monday, March 12, 2012 Page I of 1 • • SITETIE J I' SEAN PARNELL, GOVERNOR ALASKA OIL ANI) GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Kevin Skiba Regulatory Compliance Representative O © 5 Marathon Alaska Production, LLC � PO Box 1949 Kenai, AK 99611 Re: Cannery Loop Unit, Beluga Pool, Cannery Loop Unit #8 Sundry Number: 312 -029 Dear Mr. Skiba: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Chair DATED this / J day of February, 2012. Encl. Marathon Alaska Production LLC (r \\ jj Alaska Asset Team Marathon Oil P.O. Box 1949 Marathon , 1 Kenai, AK 99611 Telephone (907) 283 -1371 Fax (907) 283 -1350 OFF IVED January 19, 2012 JAN 2012 Mr. Daniel Seamount t}t�t11SS113 Alaska Oil & Gas Conservation Commission 333 W 7 Ave Anchorage, Alaska 99501 Reference: 10 -403 Application for Sundry Approvals Field: Cannery Loop Field Well: Cannery Loop Unit #08 Dear Mr. Seamount, Submitted for your approval is the10 -403 Application for Sundry Approvals for CLU -08 well. Marathon proposes to perform a Mechanical Integrity Test of the wellbore to comply with the Storage Injection Order No. 9, Rule 5: Demonstration of Mechanical Integrity. Please find attached the Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) Mechanical Test Plan which provides a summary and background for the test, the details that relate to the subject well, and a current wellbore schematic, depicting the Sterling C1 interval depths. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Sincerely, ° K(..12/1 r Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10 -403 Application for Sundry Approvals cc: AOGCC CINGSA SIO 9 Mechanical Integrity Test Plan Houston Well File Current Well Schematic Kenai Well File (2) KJS ' k / \l/ STATE OF ALASKA JAN 2 ` 2012 /1►`', 7 ALAS AND GAS CONSERVATION COMMITS IQ 'V AP PLICA TION FOR SUNDRY APPROVALS �)�x�� Gil Gas 0r!io Camrr)Iss y !�:�w�wr ^�'� 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair well ❑ Change approved program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Specify: Time Extension ❑ Operational shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter casing ❑ Other: Perform MIT Test 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Marathon Alaska Production LLC Development 0 Exploratory ❑ 204 - 005. 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ 6. API Number: Kenai Alaska, 99611 -1949 50 - 133 - 20534 - 00 - 00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No D Cannery Loop Unit #8 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL - 324602 - Cannery Loop Field / Beluga Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9,77T , 7,941' ' 9,709' 7,873' NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 100' 20" 121' 121' 3,060 psi 1,500 psi Surface 1,789' 13 -3/8" 1,810' 1,636' 3,450 psi 1,950 psi Intermediate 6,701' 9 -5/8" 6,722' 4,941' 6,870 psi 4,750 psi Production 9,725' 3 -1/2" 9,746' 7,910' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 7,027' - 9,000' 5,219' - 7,165' Exscape 3 -1/2" L -80 9,746' Packers and SSSV Type: SSSV: NA Packers and SSSV MD (ft) and TVD (ft): SSSV: NA Packers: NA Packers: NA 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development is ' Service ❑ 14. Estimated Date for 15. Well Status after proposed work: February 1, 2012 Commencing Operations: Oil ❑ Gas 0 . WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283 -1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative Id_ 4 Signature P (907) 283 -1371 Date January 19, 2012 COMMISSION USE ONLY �j /� Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ✓ 1 J2. 6 \ Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test Location Clearance ❑ Other: �S p Subsequent Form Required: JO 146 \ APPROVED BY Approved by: / i '; COMMISSIONER THE COMMISSION Date: ( ) 1 A 2 • 1 0R1G1NA 4 2012 5� I FEB 1 IN. Form 10 -403 Revised 1/2010 Submit in Duplicate • • Cook Inlet Natural Gas Storage Alaska, LLC Proposed Mechanical Integrity Test Plan Cannery Loop Sterling C Gas Storage Pool Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) requested by application dated July 27, 2010, a storage injection order from the Alaska Oil and Gas Conservation Commission (AOGCC) authorizing injection for the underground storage of natural gas in the Sterling C Gas Storage Pool of the Cannery Loop Unit. The AOGCC held a public hearing on October 19 -20, 2010 during which CINGSA presented oral and written testimony concerning the project. By Order, the AOGCC issued Storage Injection Order No. 9 (SIO 9) dated November 19, 2010, granting CINGSA the authority to commence the injection of gas for underground storage subject to certain Conclusions and Rules, all as more fully outlined in SIO 9. Two of the key requirements imposed on CINGSA as a condition of SIO 9 are that CINGSA 1) demonstrate the mechanical integrity of all storage injection wells and existing pool wells before injection commences (Rule 5 Demonstration of Mechanical Integrity), and 2) maintain surveillance of operating parameters for storage and offset wells to provide continued assurance that gas remains confined to the Sterling C Gas Storage Pool (Conclusion 8). Following, is the methodology CINGSA proposes to employ to demonstrate the mechanical integrity of all existing pool wells and maintain continued surveillance of the Pool to assure that gas remains confined to the Sterling C Pool. All new gas storage wells will be tested in accordance with 20 AAC 25.412 (c)(d). CINGSA proposes to satisfy the requirements of Conclusion 8 and Rule 5 of SIO 9 through routine monitoring of the annulus pressure of existing wells, and via pressure testing the annulus of certain wells to demonstrate their mechanical integrity, plus the tubing string of certain other wells. Table 1 provides a summary of the scope of CINGSA's proposed measures to satisfy the requirements of Conclusion 8 and Rule 5. The rationale for monitoring pressure of certain annuli and performing a mechanical integrity test is more fully summarized for each individual well below. Table 2 provides a depth reference to the Sterling C1 interval, from Sterling C1 Top to U. Beluga Top, by well. Routine monitoring and recording of annulus pressure will help identify whether any gas may be leaking from the Sterling C Pool or other formations. CINGSA proposes a monthly monitoring and reporting frequency to satisfy the requirements of Conclusion 8. CINGSA proposes to conduct a mechanical integrity pressure tests on the annulus of the wells listed in Table 1 to satisfy the requirements of Rule 5. CINGSA proposes a maximum test pressure of 500 psi for 30 minutes since most of the wells are not completed with tubing set on a packer, and thus, are not in the same configuration contemplated in 20 AAC 252. • • Table 1 Proposed Routine Monitoring and Mechanical Integrity Test Plan Cook Inlet Natural Gas Storage Alaska, LLC Well Name Current Status Annulus for MIT Routine Monitor Annulus CLU 1RD Producing 4 1/2 x 7 4 1/2 x 7 and 7 x 9 5/8 CLU 3 Inactive 3 1/2 x 9 5/8 3 1/2 x 9 5/8 CLU 4 Inactive 3 1/2 x 13 5/8 3 1/2 Tbg, 3 1/2 x 13 5/8, and 13 5/8 x 20 CLU 5 Inactive 3 1/2 Tbg x 9 5/8 3 1/2 Tbg, 3 1/2 x 9 5/8, and 9 5/8 x 13 3/8 CLU 6 P & A Sterling C 4 1/2 Tbg 4 1/2 tbg and 4 1/2 x 7 CLU 7 Producing 3 1/2 x 9 5/8 3 1/2 x 9 5/8 and 9 5/8 x 13 3/8 CLU 8 / Producing 3 1/2 x 9 5/8 3 1/2 x 9 5/8 and 9 5/8 x 13 3/8 CLU 9 Producing 3 1/2 x 9 5/8 3 1/2 x 9 5/8 and 9 5/8 x 13 3/8 CLU 10 Planned P & A 3 1/2 Tbg and 3 1/2 x 9 5/8 3 1/2 x 9 5/8 and 9 5/8 x 13 3/8 CLU 11 Producing 3 1/2 x 9 5/8 3 1/2 x 9 5/8 and 9 5/8 x 13 3/8 CLU 12 P & A'd Sterling C None 9 5/8 Csg Table 2 Cannery Loop Wells, Sterling C interval, Sterling C1 Top to U. Beluga Top Well Name Sterling C depth interval, MD Sterling C depth interval, TVDSS CLU 1RD 5815 -6155 -4927 to -5155 CLU 3 5313 -5574 -4963 to -5205 CLU 4 5171 -5409 -4971 to -5198 CLU 5 6063 -6300 -4856 to -5081 CLU 6 7782 -8114 -4876 to -5099 CLU 7 7700 -7965 -4858 to -5095 CLU 8 / 6690 -6945 -4871 to -5101 CLU 9 5942 -6195 -4860 to -5102 CLU 10 5372 -5614 -4883 to -5125 CLU 11 6281 -6537 -4876 to -5113 CLU 12 7264 -7522 -4920 to -5158 IP CLU 8 CLU 8 is currently completed to the Beluga via a 3 -1/2" Excape type completion. A 3 -1/2" monobore string was cemented in place, in the open hole with cement being brought up above the 9 -5/8 shoe, which is at 6722 ft MD. The Sterling interval extends from 6690 -6945 ft MD, thus, the intermediate shoe is set approximately 32 ft below the top of the Sterling C. Marathon has indicated the well is currently producing at a high water rate making sustaining production challenging. Proposed Annuli to configure for routine pressure monitoring: • 3 -1/2" x 9 -5/8" tubing head • 9 -5/8" x 13 -3/8" casing head Proposed Mechanical Integrity Test Procedure: • Perform a 500 psi pressure test of the 3 -1/2" x 9 -5/8" annulus being mindful of the low pressure on the inside of the tubing and of collapse. CINGSA proposes a 30 minute test duration with no more than a 10 percent change in pressure during that time interval being required for a valid test. • The proposed pressure test will apply an approximate differential of 2139 psi at 6722 ft MD/4941 ft TVD, per the following assumptions: an approximate 500 psi internal tubing pressure at TVD, a fresh water hydrostatic gradient in the annulus, and the 500 psi of applied surface pressure. (Assumed intermediate casing shoe depth for differential calculation.) • A test of the 9 5/8" x 13 3/8" annulus is not recommended since it would most likely serve as a leak off test of the surface casing shoe at 1810 ft MD. • 4 . Permit #: 204 -005 CLU - 8 API #: 50- 133- 20534- 00 -S01 Marathon Oil Prop. Des: P 1 Alaska Production LLC KB Elevation: 42' (21' AGL) 208' FSL, 486' FEL WBS #: DD.03.09594.CAP.CMP.01 X: 272,484.840 Sec. 7, T5N, R11W, S.M Conductor 20" K -55 133 ppf Y: 2,388,660.970 Top Bottom Spud: 01/25/2004 MD 0' 122' TD: 02/8/2004 [11'.'1:.1 TVD 0 122 Riq Released: 02/13/2004 @ 06:00 hrs. li PA: Surface Casing 13 -3/8" K -55 68 ppf BTC Tom Bottom MD 0' 1,810• TVD 0' 1,636' Tree crossin 4 - 3/4" Otis hole Cmt w/ sks (229 bbl) of 12.0 ppg, g = Type-1 cmt, 100 % returns, 40 bbls to surface Top of Cement (est.) ,.► - - Intermediate Casing @ 4,800' MD R Sterling C1 9 TVD L -80 40 ppf BTC -MOD Interval: Top 0' Bottom • @ 6,422' MD (300' above 9 - 5/8" shoe) 6690 - 6945 ft MD MD o 6,�6,722' TVD 4,941' ' 12 -1/4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G Excape System Details BHP monitoring line (yellow) volume tank located from 6,952' - 6,987' Production Tubing e, 3 -1/2" L -80 9.3 ppf Mod 8rd Top Bottom Weatherford Straddle packer assembly - � MD 0' 9,746' * Mod #7 (6/15/10) TVD 0' 7,910' * Top of packer @ 7,911' MD RKB 4 - j 8 -1/2" hole Cmt w/ 1,430 sks (293 bbls) of * WEA ER Packer (ID: 1.812 ") = 2.87' 15.8 ppg, class G cmt 3,600# to release 1 k* * 2 -3/8" spacer pipe (ID: 1.995 ") = 20.1' _` * WEA Snap latch seal (ID: 1.75 ") = 0.95' it , 3,600# to release Excape System Details * WEA ER Packer (ID: 1.812 ") = 2.69' I I ' - 15 Excape modules placed - Green control line fires bottom 7 modules y - Red contol line fires top 8 modules - line for BHP monitoring i - Ceramic flapper valves below each module Excape System Details .. -14 Conventional flappers 1 t . Beluga Perfs (MD): • - Mod. 1 - no flapper I , Module 15 = 7,027'- 7,037' - Ceramic flapper valves below Module 14 = 7,130'- 7,140' each module as follows: j Module 13 = 7,232'- 7,242' Flappers MD (RKB): DI Module 12 = 7,297' -7,307 Module 15 = 7,046' r Module 11 = 7,400'- 7,410' Module 14 = 7,149' Dif Module 10 = 7,456' - 7,466' Module 13 = 7,251' ) Module 9 = 7,578' - 7,588' Module 12 = 7,316' qi f Module 8 = 7,688' - 7,698' Module 11 = 7,419' r�{� Module 7 " 7, - -932 Patched 6/15/10 Module 10 = 7,475' Di Module 6 = 7,982'- 7,992' Module 9 = 7,597' Module 5 = 8,287' - 8,297' Module 8 = 7,707' DI Module 4 = 8,366' - 8,376' Module 7 = 7,941' Module 3 = 8,409' - 8,419' Module 6 = 8,001' . Module 2 = 8,496-8,506' Module 5 = 8,306' Module 1 = 8,990'- 9,000' Module 4 = 8,385' Tagged (a: Is Module 3 = 8,428' 9,430' MD w/ 2.74" GR (12/17/09) lol , Module 2 = 8,515' 9,458' MD w/ 2.60" GR (1/2/10) Module 1 = NA TD PBTD 9,777' MD 9,709' MD 7,941' TVD 7,873' TVD Well Name & Number: Cannery Loop Unit # 8 Lease: Cannery Loop Gas Field Municipality: Kenai Peninsula Borough State: Alaska I Country:) USA Perforations (MD): 7,027' - 9,000' Perf (TVD): 5,219' - 7,165' Angle @ KOP & Depth: 5.05° / 100 ft @ 250' MD Angle @ Perfs: 22° -, 0.5° Date Completed: 4/28/2004 Ground Level: 21' (Above MSL) I RKB: I 21' (AGL) Revised by: Kevin Skiba Revision Date: 11/29/2011 • IUlarathon Alaska Production LLB MARATHON July 27, 2010 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Mara~n Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 R~~IEIVED JUL ~ a ZOiil Alaska E~ ~ Cs~ Clltu. C~rrr!missior~ -~cndr.+ae Reference: 10-404 Report of Sundry Well Operations ~(,~-" ~d~ Field: Cannery Loop Unit Well: Cannery Loop Unit #8 ,,~ Dear Mr. Aubert: Attached for your records is the10-404 Report of Sundry Well Operations for CL-8 well. This report covers the work performed to install a 3/8" stainless steel capillary string to a setting depth of 8,970'. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, V~,~, Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS STATE OF ALASKA ALASKA AND GAS CONSERVATION COMMISSI~ REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ Installed Capillary Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver^ Time Extension ^ String Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well ^ 2. Operator 4. Well Class Before Work: Permit to Drill Number: Name: Marathon Alaska Production LLC Development ^~ Exploratory^ 204-005 3. Address: PO Box 1949 Stratigraphic ^ Service ^ .API Number: Kenai Alaska, 99611-1949 50-133-20534-00 (~~ 7. Property Designation (Lease Number): `~ ~~ 8. Well Name and Nu er: ADL - 324602 rJ ~ Canne Loo Unit #8 9. Field/Pool(s): Cannery Loop Field /Beluga Pool 11. Present Well Condition Summary: Total Depth measured 8,777' feet Plugs (measured) NA feet true vertical 7,941' feet Junk (measured) Nq feet Effective Depth measured 9,709' feet Packer (measured) NA feet true vertical 7,g73' feet (true vertical) NA feet Casing Length Size MD TVD Burst Collapse Structural Conductor 121' 20" 121' 121' 3,060 psi 1,500 psi Surface 1,789' 13-3/8" 1,810' 1,636' 3,450 psi 1,950 psi Intermediate 6,701' 9-5/8" 6,722' 4,941' 6,870 psi 4,7 50 psi Production 9,725' 3-1 /2" 9,746' 7,910' psi 10,1~~~ ~ ~ 0 \/ Liner V V Perforation depth: Measured depth: 7,02T - 9,000' ! L~ ~-. ~° ;~ 2 ' ' CO~111SS10f1 A~~85k~ ~ ~t ~$g ~i ~~ True Vertical depth: 5,219 - 7 ,165 • Excape 3-1/2" L-80 ~ ~ 9,746' ~OOMD"~~ 7,910' TVD Tubing (size, grade, MD &TVD): Capillary String 3/8" 2205 Stainless Steel 8,970' MD 7,134' TVD SSSV: NA Packers and SSSV (type, MD &TVD): Packers: NA 11. Stimulation or cement squeeze summary: Intervals treated (measured): A 3/8" stainless steel cap illary string was installed to a setting depth of 8,970' MD. Treatment descriptions including volumes used and final pressure : 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 115 Subsequent to operation: 0 4,500 106 0 206 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development ^~ Service ^ Daily Report of Well Operations X 15. Well Status after work: Oil Gas ~ WDSPL GSTOR ^ WAG ^ GIN J^ WINJ ^ SPLUG ^ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: NA Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative Signature ~ ~ Phone (907) 283-1371 Date July 27, 2010 v L~11 Form 10-404 Revised 7/2009 11o~S ~L Submit Original Only '= Marathon l7~rations Summary Report by Job ,,,~~, ~~~~ Y Well Name: CANNERY LoQP UNIT 08 Daily Operations Re ort Date: 7112010 Job Cate o R&M MAINTENANCE 24 Hr Summary MIRU DynaCoil to install temporary cap string Start Time End Time Dur hrs 0 s Code Activi Code Ops Status Trouble Code Comment 07:30 08:00 0.50 SAFETY MTG Obtain SW Permit. 08:00 09:30 1.50 LOAD TRCK Dispatch DynaCoil truck to PU cap string spool. 09:30 10:00 D.50 SAFETY MTG Arrive on location. Well flowing 60-100 psi. water and foam. Drop 2 soap sticks. Hold PJSM . Discussed -Alarms- red lights for fire, blue lights for gas emission, sirens for audible alarms. Wind direction and Muster area, emergency vehicle, emergency phone numbes. Emphasized hand safety and focusing on the job. 10:D0 11:12 1.20 RURD COIL Spat equipment. Install pack off assembly. Install 318" coil in injector. Set fluid control valve @ 3500 psi. Pull test BHA to 600 psi. Test good. Carry injector to WH. 11:12 11:24 0.20 TEST EQIP PT packoffto 2000 psi. Test good. 11:24 13:24 2.00 RUNPUL COIL RIH w/ 3~8" coil. Well flowing 20 psi, no water. 13:24 14:42 1.30 RUNPUL COIL Land coil @ 8970' kb. Set slips. Set Ratiguns. 14:42 14:57 0.25 PUMP TRET Strart pumping foamer @ 15 gall day. 14:57 15:21 0.4D KURD COIL RD DynaCoil unit. 15:21 15:33 0.20 PUMP TRET DynaCoil pressures up to 600 psi. Indicates faomer out the BHA. 15:33 03:33 12.00 SECURE WELL Secure well. Turn well over to night watch. The following morning well turned over to production-well flowing 1.2 MMcf/d. www.peloton.com Page 1/1 Report Printed: 7/2712010 50-133-20534-00-S01 levation: 42' (21' AGL) #: DD.03.09594.CAP.CMP.01 272,484.840 2,388,660.970 _ 01/25/2004 02/8/2004 released: 02/13/2004 @ 06:00 hrs. Tree crossing = 4-3/4" Otis @ 4,800' MD Excage Svstem Details BHP monitoring line (yellow) volume tank located from 6,952' - 6,987' Mod #7 (6/15/10) Top of packer @ 7,911' MD RKB 'WEA ER Packer (ID: 1.812")= 2.87' 3,600# to release 2-3/8"spacer pipe (ID: 1.995")= 20.1' 'WEA Snap latch seal (ID: 1.75")= 0.95' 3,600# to release WEA ER Packer (ID: 1.812")= 2.69' - 14 Conventional flappers - Mod. 1 - no flapper - Ceramic flapper valves below each module as follows: Module 15 = 7,046' Module 14 = 7,149' Module 13 = 7,251' Module 12 = 7,316' Module 11 = 7,419' Module 10 = 7,475' Module 9 = 7,597' Module 8 = 7,707' Module 7 = 7,941' Module 6 = 8,001' Module 5 = 8,306' Module 4 = 8,385' Module 3 = 8,428' Module 2 = 8,515' Module 1 = NA CLU - 8 Pad 1 208' FSL, 486' FEL Sec. 7, T5N, R11W, S.M. Capillary String 3/8" 2205 Stainless Steel Tom Bottom MD Surf 8,970' TVD Surf 7,134' (Installed on 7/1/10) , --~ ~ `"k' ~~ c _--7ri tr c Taaaed Cc~: .~'" 9,430' MD w/ 2.74" GR (12/17/09) 9,458' MD w/ 2.60" GR (1/2/10) ^;a ~% TD PBTD 9,777' MD 9,709' MD 7,941' TVD 7,873' TVD M ~llt,ww-TMON Conductor 20" K-55 133 ppf T~ Bottom MD 0' 122' TVD 0' 122' Surface Casing 13-3/8" K-55 68 ppf BTC Two Bottom MD 0' 1,810' TVD 0' 1,636' 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type-1 cmt, 100 % returns, 40 bbls to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC-MOD Two Bottom MD 0' 6,722' TVD 0' 4,941' 12-1/4" hole Cmt w/ Lead 320 sks (120 bbls)12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G Production Tubing 3-1/2" L-80 9.3 ppf Mod 8rd Tom Bottom MD 0' 9,746' TVD 0' 7,910' 8-1/2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt 15 Excage modules placed -Green control line fires bottom 7 modules - Red contol line fires top 8 modules - line for BHP monitoring -Ceramic flapper valves below each module Module 15 = 7,027'-7,037' Module 14 = 7,130'-7,140' Module 13 = 7,232'-7,242' Module 12 = 7,297'-7,307 Module 11 = 7,400'-7,410' Module 10 = 7,456'-7,466' Module 9 = 7,578'-7,588' Module 8 = 7,688'-7,698' Me'' 'w,~7 - 7;922' 7,932' Patched 6/15/10 Module 6 = 7,982'-7,992' Module 5 = 8,287'-8,297' Module 4 = 8,366'-8,376' Module 3 = 8,409'-8,419' Module 2 = 8,496'-8,506' Module 1 = 8,990'-9,000' Well Name & Number: Cannery Loop Unit # 8 Lease: Cannery Loop Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 7,027' - 9,000' Perf (TVD): 5,219' - 7,165' Angle @ KOP & Depth: 5.05° / 100 ft @ 250' MD Angle @ Perfs: 22° -~ 0.5° Date Completed: 4/28/2004 Ground Level: 21' (Above MSL) RKB: 21' (AGL) Revised by: Kevin Skiba Revision Date: 7/27/2010 • IVlarathon N{ARaTHON Alaska PraCluctian LLC June 21, 2010 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Mar~on Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 .=IIJN ~ ~ ~.~1(! Ataaka ©ii & COa+ Ces~:. Commission ~rtpt~~r~t~p Reference: 10-404 Report of Sundry Well Operations ©OS. Field: Cannery Loop Unit ~D Well: Cannery Loop Unit #8 _, r~ ~ ~ ~; Dear Mr. Aubert: ~~~~~ liwi,~° ="~ " ~ `~ Attached for your records is the10-404 Report of Sundry Well Operations for CL-8 well. This report covers the work performed to install a straddle patch across the #7 Excape module. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS STATE OF ALASKA ALASKA AND GAS CONSERVATION COMMISSI~ REPORT OF SUNDRY WELL OPERATIONS ~~ a~r3a~20[d 1. Operations Abandon Repair Well Plug Perforations timulate Other ~ Installed Straddle Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver^ Time Extension ^ Patch Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-en er Suspended Well ^ 2. Operator 4. Well Class Before Work: Permit to Drill Number: Name: Marathon Alaska Production LLC Development ^~ Exploratory^ 204-005 3. Address: PO Box 1949 Stratigraphic ^ Service ^ ~ .API Number: ? Kenai Alaska, 99611-1949 50-133-20534-00-59'I' 7. Property Designation (Lease Number): ~ s 8. Well Name and Number: ADL - 324602 ~ ~,~' ~fl ~Canne Loo Unit #8 9. Field/Pool(s): w~ V~G4" Cannery Loop Field / Beluga ~ ool 11. Present Well Condition Summary: Total Depth measured 9,777' feet Plugs (measured) Nq feet true vertical 7,g41' feet Junk (measured) NA feet / Packer (measured) NA feet Effective Depth measured 9,709' feet true vertical 7,873' feet (true vertical) NA feet Casing Length Size MD ` TVD Burst Collapse Structural Conductor 121' 20" 121' 121' 3,060 psi 1,500 psi Surface 1,789' 13-3/8" 1,810' 1,636' 3,450 si ~~ Intermediate 6,701' 9-5/8" 6,722' 4,941' 6,870 ~i~~ si Production 9,725' 3-1/2" 9,746' 7,910' 10,160 psi 10,530 psi Liner ~lU~ 2~ 201Q Perforation depth: Measured depth: 7,027 - 9,000' ~ Alaska Qlf ~ has Cat«. Comm-"` ;;" Ancht~r~t~g True Vertical depth: 5,219' - 7,165' Excape 3-1/2" L-80 9,746' 7,910' TVD Tubing (size, grade, MD &TVD): Capillary String TVD SSSV: NA Packers and SSSV (type, MD &TVD): Packers: NA 11. Stimulation or cement squeeze summary: Intervals treated (measured): Astraddle patch was placed across the Module #7 perforations to isolate infiltrating water. Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 186 0 74 Subsequent to operation: 0 0 - 0 12 13. Attachments: .Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development ^~ Service ^ Daily Report of Well Operations X .Well Status after work: Oil Gas ~ WDSPL GSTOR ^ WAG ^ GINJ^ WINJ ^ SPLUG ^ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 310-174 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative ~ 1, Signature ~ ~ Phone (907) 283-1371 Date June 16, 2010 Form 10-404 Revised 7/2009 ~DMS JUN 2 ~ .1010 Submit Original Only Marathon erations Summary Report by Job Nngarxo~ +flil COmparly Well Name: CANNERY LOOP UNIT 08 Qtr(Qtr, Blodt, Sec. Town, Range Field Name License No. State/Province Country 6007005N011W01 CANNERY LOO P UNIT ALASKA USA Casing Flange Elevation (ft) Ground Elevation (ft) KB- Casing Flange Disf anoe(fq KB-Ground Distanoe(fq Spud Date Rig Release Date Re ort Date: 6/15CL010 Job Cate o WORi{OVER 24 Hr Summary MIRU Expro wireline. RIH w/ 2.74" GR, sitting down in M od 6 (/983. WT and unable to pass POOH. RIH and seta 20' straddle packer across the water producer (Mod 7) to shut off perfs, 7922'-7932' MD RKB. Top of straddle packer: 7911'. Min ID: 1.75". Attempt to flaw well with no luck, continue flowing well to atmosphere. RD Expro. Ops Trouble Start Time End Time Dur hrs 0 s Code Activi Code Status Code Comment 07:30 09:00 1.50 SAFETY MTG AF Held PJSM w/Expro and operator. Discussed job procedures, emergency procedures, and crane operations. Obtained safe work permit. 09:00 10:30 1.50 RURD ELEC AF RU wireline truck and equipment. MU tool string and lubricator and stab on well. 10:30 11:00 0.50 TEST BOPE AF PT lubricator to 1500 psi. Good test. 11:00 12:45 1.75 RUNPUL ELEC AF RIH w! RS, 14' weight bar, CCL, OJ, SSJ, and 2.74" OD GR. Sat down in Module 6(7983' MD RKB). WT and unable to pass, POOH. 12:45 13:00 0.25 SAFETY MTG AF Held JSA for explosives. 13:00 15:30 2.50 SETREL PKR AF RIH w/ RS, weight bar, CCL, MSST, 3 1C2 ER WLAK, and Weatherford 3 1!2 ER packer. Sat down in Module 10, WT and fell through. Set center of packer element @ 7935'. POOH. 15:30 16:00 0.50 PULD PKR AF Break tools and MU upper packer and straddle assembly. 16:00 16:15 0.25 SAFETY MTG AF Held JSA for explosives. 16:15 18:45 2.50 SETREL PKR AF Arm setting tool and RIH wl RS, weight bar, CCL, MSST, 3 1/2 ER WLAK, Weatherford 3 1/2 ER packer, 2 3P8" x 20'tubing, and snap latch seal y assembly. Sat down in Module 8 and WT ~25x before falling. Latch upper assembly into lower packer and confirm latch w/ 7501bs overpull. Set top of upper packer @ 7911'. POOH while attempting to swab well onto production. 18:45 19:45 1.00 RURD ELEC AF LD lubricator and tool string. RD wireline truck and equipment. Sign out, turn in safe work permit, and leave location. 19:45 06:00 10.25 FLOW BACK AF Flow well to atmosphere and attempt to bring on. Summary of straddle packer assembly across Module 7 perfs (T922'-7932' MD RKBJ: i Top of3 1C1 Weatherford ER packer: 7911'. Center of bottom element on lower packer: 7935'. Min ID: 1.75" @ 7931' (Snap latch seal assembly) 3600# overpull required to pull assembly www.peloton.com Report Printed: 6!16!2010 50-133-20534-00-S01 levation: 42' (21' AGL) #: DD.03.09594.CAP.CMP.01 272,484.840 2,388,660.970 _ 01 /25/2004 02/8/2004 released: 02/13/2004 @ 06:00 hrs. ~~ .~ ~~ M MARATHON Conductor 20" K-55 133 ppf TOE Bottom MD 0' t22' TVD 0' 122' Surface Casing 13-3/8" K-55 68 ppf BTC T~ Bottom MD 0' 1,810' TVD 0' 1,636' 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type-1 cmt, 100 % returns, 40 bbls to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC-MOD Tom Bottom MD 0' 6,722' TVD 0' 4,941' 12-114" hole Cmt wl Lead 320 sks (120 bbls)12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G Production Tubing 3-1/2" L-80 9.3 ppf Mod Srd Tom Bottom MD 0' 9,746' TVD 0' 7,910' 8.112" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt Excape System Details - 15 Excape modules placed -Green control line fires bottom 7 modules - Red contol line fires top 8 modules - line for BHP monitoring - Ceramic flapper valves below each module Beluga Perfs (MD): Module 15 = 7,027'-7,037' Module 14 = 7,130'-7,140' Module 13 = 7,232'-7,242' Module 12 = 7,297'-7,307 Module 11 = 7,400'-7,410' Module 10 = 7,456'-7,466' Module 9 = 7,578'-7,588' Module 8 = 7,688'-7,698' ModUIL ' - ' n''`''' n'''' Patched o^^/15/10 Module 6 = 7,982'-7,992' Module 5 = 8,287'-8,297' Module 4 = 8,366'-8,376' Module 3 = 8,409'-8,419' Module 2 = 8,496'-8,506' Module 1 = 8,990'-9,000' Well Name & Number: Cannery Loop Unit # 8 Lease: Cannery Loop Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 7,027' - 9,000' Perf (TVD): 5,219' - 7,165' Angle @ KOP 8 Depth: 5.05° 1100 ft @ 250' MD Angle @ Perfs: 22° -~ 0.5° Date Completed: 4/28/2004 Ground Level: 21' (Above MSL) RKB: 21' (AGL) Revised by: Kevin Skiba Revision Date: 6/16/2010 CLU - 8 Pad 1 208' FSL, 486' FEL Sec. 7, T5N, R11W, S.M. CLU-8 Straddle Patch ~ • Page 1 of 1 Aut~rt, Winton G (DOA) From: Skiba, Kevin J. [kskba~marathonoil.com] Sent: Monday, June 14, 2010 9:01 AM To: Aubert, Winton G (DOA) Cc: Mullin, Mickey; Skiba, Kevin J. Subject: CLU-8 Straddle Patch ~Zo ~ - DO 5 F 1~~R:r1'~rl TrY +i `^' 4~ j V :4 t .c: L. lJ b tY Winton, Thanks for working to expedite the CLU-8 sundry. The reason that we asked you to progress this request, if possible, is to prevent further damage to near wellbore production formation. We had hoped to patch off CLU-8's most prolific water producing zone (Module #7) in December of 2009. Unfortunately we were unable to drift down to that interval during our preliminary evaluation. We thus postponed the straddle patch idea pending further evaluation. Even though the infiltrating water created production challenges, our operators were able to keep the well flowing (~2.Smm/day). The well needed to be shut-in during the LNGturn-around, which concluded on May 8~'. We were unable to reestablish production after this shut-in. The well gave us reason for optimism during a week long attempt at swabbing the water out. We just could not turn the corner and kick the well off. We then decided to attempt drifting to bottom. We were able to tag bottom with small diameter tools. We then spent 2 days swaging and were able to open the diameter to the desired dimension. Production from the Cannery Loop wells has become more challenging. As stated above, we hoped to shut offthe water producing zone as quickly as possible to minimize formation damage. We appreciate your efforts at expediting this approval. This will allow us to address this situation in the timeliest manor. Thanks again, Kevin Skiba Regulatory Compliance Representative Marathon Alaska Production LLC Office (907) 283-1371 Cell (907) 394-1880 Fax (907) 283-1350 6/15/2010 • ~~a~[~ 0~ Q~Q~~Q /,~..~.E..~~..~ Kevin J. Skiba Regulatory Compliance Technician <<, `~~~~ Marathon Alaska Production, LLC ..~, y `~~~' ~~" ~. r ~,;~~~: ~ 0 ~ p OvT' P.O. Box 1949 w'~'ay ~' Kenai, AK 99611-1949 Re: Cannery Loop Field, Beluga Pool, Cannery Loop Unit #8 Sundry Number: 310-174 Dear Mr. Skiba: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seamount, Jr. Chair DATED this ~ ~ day of June, 2010. Encl. ~~ IVlarathon ~'BARaTHON ®Alaska Production LLC June 7, 2010 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Reference: 10-403 Application for Sundry Approvals Field: Cannery Loop Well: Cannery Loop Unit #8 Dear Mr. Aubert: Mara3Ron Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 aoy.-oos Submitted for your approval is the10-403 Application for Sundry Approvals for CLU-8 well. Marathon proposes to isolate the excessive water production from the 7,922' - 7,932' MD perforations with a Weatherford straddle patch. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ~~ Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10-403 Application for Sundry Approvals Detailed Operations Program Current Well Schematic Proposed Well Schematic cc: AOGCC Houston Well File Kenai Well File KJS MAM 'mot j~~~a STATE OF ALASKA ALASKA AND GAS CONSERVATION COMMISS~ APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 i~6~~~V~~~~~5~ JUN 0 ~ 201Q ~~a ~ JiQl~to ~tASka Od ~ aga Cet>,-. Comr~ls:laln 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown^ Perforate ^ Waiver~~Or J~e Other ^~ Alter casing ^ Repair well ^ Plug Perforations ~~ timulate ^ Time Extension ^ Install straddle Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ patch 2. Operator Name: Marathon Alaska Production LLC 4. Current Well Class: 5. Permit to Drill Number: Development ^ Exploratory ^ 204-005 3. Address: p0 Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20534-00-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: S i E i R ^ D Cannery Loop Unit #8 pac ng xcept on equired? Yes No 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ADL - 324602 42' (21' AGL) Cannery Loop Field /Beluga Pool 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9,777' 7,941' 9,709' 7,873' NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 121' 20" 121' 121' 3,060 psi 1,500 psi Surface 1,789' 13-3/8" 1,810' 1,636' 3,450 psi 1,950 psi Intermediate 6,701' 9-5/8" 6,722' 4,941' 6,870 psi 4,750 psi Production 9,725' 3-1/2" 9,746' 7,910' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): ~ 7,027' - 9,000' 5,219' - 7,165' Excape 3-1 /2" L-80 9,746' Capillary Packers and SSSV Type: Packers and SSSV MD (ft): NA NA 13. Attachments: Description Summary of Proposal ^ 14. Well Class after proposed work: Detailed Operations Program Q BOP Sketch ^ Exploratory ^ Development ~ Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: June 10, 2010 Oil ^ Gas ^~ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Technician Signature ~ ~ hone (907) 283-1371 Date ~ 0 c COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~~ O .. `~ Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: Subsequent Form Required: ` ~ ~. ~O 4- - APPROVED BY ~ ~ ~ ~, ~ ~ A roved b : COMMISSIONER THE COMMISSION Date: pp y Form 10-403 Revised 06/2006 ~ R ~ r t I i,MS JUN 15 bmit in Duplicate ~J M MARATHON U MARATHON ALASKA PRODUCTION LLC ALASKA ASSET TEAM CLU 8 Kenai Gas Field Straddle Packer Procedure WBS # W0.09.21515.CAP.001 r _.. APPROVALS: C~it~ ~2~ ~9~'Program Writer ./yG.`,".~, ~V~;[t~irt ~2/4~1 y~ Mickey Mullin T Lyvlydo-wlUe~i 12/9/09 Lyndon Ibele Well Status: FW HP - 400 # 5.2 MMCF/D 175 BW/D History: Excessive water production resulting in risk to stabilized gas production indicated the necessity to shut off water production from the interval 7,922 - 7,932' MD (Module 7). The PLT run on 7/22/2009 indicated that this interval was providing the vast majority of the water production from the well as interpreted by John S. David with Flowex, LLC. The last tag was at 9472' (below mod 1) with a 2.25" gauge ring on 7/23/09. The gauge ring tagged module 15 but passed through. Objectives: This procedure covers work to install a 2.375" OD x 24' (2.74" max OD)(see complete straddle dimensional data at bottom). Weatherford straddle packer will be installed across perforations at 7,922 - 7,932' MD to shut off the excessive water production from the perforations in Module 7. This assembly is designed to be run in two runs via E-line and pulled in two runs via slickline if removal is necessary. Resources: 1. slickline - To run dummy packer assembly 2. Electric Line - To run and set straddle packer 3. Weatherford wireline setting adapter f/ multi stage setting tool (MSST), and MSST 4. Weatherford straddle packer (see packer assembly sheet for dimensional and pinning requirements) -contains: a. (2) 3 %" ER Packers w/W LEG b. (1) 20' jt of 2 3/8" tbg cut w/ NU 10 round threads c. (1) 3 %2" SO tie-back receptacles d. Wireline setting adapter f/ multi stage setting tool (MSST) e. Owen MSST 5. Rental Equipment - Manlift. Light plant and heater depending on the season. Straddle Packer Procedure CLR Page 1 12/04/2009 r~ L J Procedure: U 1. MIRU rental equipment. Deliver diesel-fueled man-lift and two light towers. 2. De-energize electrical and remove wellhouse (if necessary). Move in crane. Pull wellhouse and set out of the work area. Note: Wellhouses are larger at Cannery Loop -Larger Crane req. MIRU Pollard Slick line Unit to run 2.75" GAUGE RING. Hold PJSM, complete work permit form, and complete fall protection checklist. Discuss with operators at which points in the job the well will be shut in and reopened and how to coordinate flowing the well. Discuss whether well should be flowed between runs. PU pump-in tee and wireline valve to Otis tree cap connection. PU lubricator and pull centralized 2.75" OD swage, spang jars, oil jars, stem, and weight bars into lubricator. Pressure test lubricator with methanol water (winter season) to 250/2000 psi. Bring Gauge rings 2.60" - 2.70" to accurately determine what size will pass if the 2.75" does not pass. 4. Shut in well and RIH w/ 2.75" Gauge ring. RIH with 2.75" gauge ring, crossover, spang jars, oil jars, and stem on slickline and tag. POOH. 5. RIH w/ 24' x 2.375" dummy packer assembly. RIH with bottom 2.74" dummy packer element, 20' section of 2.375" OD straddle sleeve, and top 2.74" OD dummy packer element, crossover, bait sub, spang jars, oil jars, and stem on slickline to 7,950' MD. POOH. 6. Return well to production and RDMO Pollard Wireline. 7. MIRU_Expro Wireline Unit to set straddle packer across 7,912 - 7,936 MD a. Hold PJSM, complete work permit form, and complete fall protection checklist. Discuss with operators at which points in the job the well will be shut in and reopened and how to coordinate flowing the well b. MU wireline valve with pump-in sub to 4-1/16" 10K tree. c. MU and PU sufficient 5" lubricator to seta 22' long straddle packer. d. MU setting tool with 3 %2" Weatherford ER packer, wireline setting adapter, Owen MSST, and CCL. Hold Explosives Safety Meeting and arm setting tool. PU tools into lubricator and test to 2000 psi. Shut in well. RIH to desired space out to set lower packer @ 7,936' tied into Expro Dual Receiver Radial Bond Log dated April 11, 2004. Set lower assembly. POOH and LD setting tool. e. Re-dress setting tool and make up SO tie-back, 20' of 2 3/8" tubing, SO tie-back, 3 %2" Weatherford ER packer, wireline setting adapter, Owen MSST, and CCL. Hold Explosives Safety Meeting and re-arm setting tool. PU tools into lubricator and quick test to 2000 psi. f. RIH w/upper assembly and slow speed when approaching lower packer @ 7,936' MD. Latch upper assembly on lower packer and confirm latch w/ 800 # overpull. Set upper packer and POOH. LD setting tool and LD lubricator. g. RDMO Expro. h. Flow test well through test separator with particular emphasis on measuring the daily produced water and gas volumes at a stabilized FTP. Flow well to production facility. Request Operators to put into test when stabilized, to determine success of water-isolation. Straddle Packer Procedure CLR Page 2 12/04/2009 • Straddle Packer Dimensional and Pressure Data: Burst = 5,000 psi Collapse = 5,000 psi ER packer OD = 2.74" ER packer ID = 1.812" SO tie-back receptacle OD = 2.72" SO tie-back receptacle OD = 1.75" Spacer tubing OD = 2.375" Spacer tubing ID = 1.994" Min ID after setting = 1.75" CLU 8 Wellbore Diagram link CLU 8 Proposed WBD Link Straddle Packer Considerations. Instructions. and Planning • It is mandatory that the Weatherford straddle packer specifications be consulted and reviewed with the electric line provider (Expro at this time) to ensure that the packer can be run and set properly. Straddle packer dimensions can be obtained from the following site: http://www.Weatherford.com/weatherford/grouos/public/documents/intervention/wi oroductinformation.hcso A gauge ring alone will not provide sufficient proof or comfort that the straddle packer can be run and set. A dummy packer assembly which mimics the packer length and tubular OD and uses the same short (end) assemblies without the setting tools installed should be run past the target interval with slickline. If the dummy can be run and retrieved easily, the straddle packer should not be a problem to install. Ensure that the personnel running the straddle packer are knowledgeable and trained properly. At this time, Ed Hawker and Justin Weaver, with Expro Wireline in Nikiski, AK, are the only known personnel who have this experience and training in Alaska. It is necessary to consult them with considerations on straddle packer length, as we are limited by lubricator length and crane height. Straddle Packer Procedure CLR Page 3 12/04/2009 204-005 50-133-20534-00-00 levation: 42' (21' AGL) #: DD.03.09594.CAP.CMP.01 272,484.840 2,388,660.970 I: 01 /25/2004 02/8/2004 teleased: 02/13/2004 @ 06:00 hrs. CLU - 8 Pad 1 208' FSL, 486' FEL Sec. 7, T5N, R11W, S.M. / :}±' TOC (est.) @ 4,800' MD ~~+ ~~ TOC (est.) @ 300' above °'1 9-5/8" shoe at 6,422' MD Excape Svstem Details BHP monitoring line (yellow) volume ` tank located from 6,952' - 6,987' ~'A Excape Svstem Details - 14 Conventional flappers - Mod. 1 - no flapper - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module 15 = 7,046' Module 14 = 7,149' Module 13 = 7,251' Module 12 = 7,316' Module 11 = 7,419' Module 10 = 7,475' Module 9 = 7,597' Module 8 = 7,707' Module 7 = 7,941' Module 6 = 8,001' Module 5 = 8,306' Module 4 = 8,385' Module 3 = 8,428' Module 2 = 8,515' Module 1 = NA Tagged @ 9,430' MD (12/17/09) with 2.74" GR ~~ TD PBTD 9,777' MD 9,709' MD 7,941' TVD 7,873' TVD M M~iurxo>M Conductor 20" K-55 133 ppf Top Bottom MD 0' 122' TVD 0' 122' Surface Casing 13-3/8" K-55 68 ppf BTC Tom Bottom MD 0' 1,810' TVD 0' 1,636' 16" hole Cmt w/ sks (229 bbl) of 12.0 ppg, Type-1 cmt, 100 % returns, 40 bbls to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC-MOD Tom Bottom MD 0' 6,722' TVD 0' 4,941' 12-1 /4" hole Cmt w/ Lead 320 sks (120 bbls) 12.5 ppg of class G, Tail 235 sks (48.5 bbls) 15.8 ppg class G Production Tubing 3-1/2" L-80 9.3 ppf Mod 8rd ToQ Bottom MD 0' 9,746' TVD 0' 7,910' 8-1 /2" hole Cmt w/ 1,430 sks (293 bbls) of 15.8 ppg, class G cmt - 15 Excape modules placed -Green control line fires bottom 7 modules - Red contol line fires top 8 modules - line for BHP monitoring - Ceramic flapper valves below each module Module 15 = 7,027'-7,037' Module 14 = 7,130'-7,140' Module 13 = 7,232'-7,242' Module 12 = 7,297'-7,307 Module 11 = 7,400'-7,410' Module 10 = 7,456'-7,466' Module 9 = 7,578'-7,588' Module 8 = 7,688'-7,698' Module 7 = 7,922'-7,932' Module 6 = 7,982'-7,992' Module 5 = 8,287'-8,297' Module 4 = 8,366'-8,376' Module 3 = 8,409'-8,419' Module 2 = 8,496'-8,506' Module 1 = 8,990'-9,000' Well Name & Number: Cannery Loop Unit # 8 Lease: Cannery Loop Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 7,027' - 9,000' Perf (ND): 7,027' - 9,000' Angle @ KOP & Depth: 5.05° / 100 ft @ 250' MD Angle @ Perfs: 22° ~ 0.5° Date Completed: 4/28/2004 Ground Level: 21' (Above MSL) RKB: 21' (AGL) Revised by: Craig Rang Revision Date: 3-18-2010 Proposed CLU #8 50-133-20534-00-00 levation: 42' (21' AGL) #: DD.03.09594.CAP.CMP.01 272,484.840 2,388,660.970 _ 01 /25/2004 02/09/2004 leleased: 02/13/2004 @ 06:00 hrs. Tree crossing = 4-3/4" Otis TOC (est.) - 300' above 9-5/8" shoe Excape System Details BHP monitoring line (yellow) volume tank located from 6,952' - 6,987' Ceramic flapper valves below each iodule as follows: Module 15 - 7,053' Module 14 - 7,156' Module 13 - 7,258' Module 12 - 7,322' Module 11 - 7,426' Module 10 - 7,482' Module 9 - 7,604' Module 8 - 7,714' Module 7 - 7,948' Module 6 - 8,008' Module 5 - 8,312' Module 4 - 8,392' Module 3 - 8,436' Module 2 - 8,522' Module 1 - NA Tag 9472' 7/22/2009 1" Swage w/ 2.25" centralizer Pad 1 208' FSL, 486' FEL Sec. 7, TSN, R11W, S.M. i t • M MuurNOM Drive Pipe: 20", 133 ppf, K-55 to 122' Surface Casing: 13-3/8", 68 ppf, K-55, BTC @ 1,810' Cmt w/ 229 bbls. of class G at 12 ppg Int. Casing: 9-5/8", 47 ppf, L-80, BTC @ 6,722' Cmt w/ 320 sks of class G lead at 12.5 ppg and 235 sx of class G tail at 15.8 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9,746' Cmt w/ 1,430 sks of class G at 15.8 ppg ~;~ ~ >~ y~~ ~ , ~'~ WeatherFord Straddle ~'" Mod 7 Dec 09 ~A ~ ~a '~' ' ~ ~ 1 ° ~e, [ '+M 9.~ y. ~ ~ ~ 'e -~~ .~ °, ^, s: :~,. ~. TD PBTD 9,777' MD 9,709' MD 7,941' TVD 7,873' TVD Excape modules placed :en control line fires bottom 7 contol line fires top 8 modules line for BHP monitoring mic flapper valves below each 15 - 7,027'-7,037' 14 - 7,130'-7,140' 13 - 7,232'-7,242' 12 - 7,297'-7,307 11 - 7,400'-7,410' 10 - 7,456'-7,466' 9 - 7,578'-7,588' 8 - 7,688'-7,698' le 6 - 7,982'-7,992' le 5 - 8,287'-8,297' le 4 - 8,366'-8,376' le 3 - 8,409'-8,419' le 2 - 8,496'-8,506' le 1 - 8,990'-9,000' Dec09 Well Name & Number: Cannery Loop Unit 8 Lease: Cannery Loop Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 7,027' - 9,000' (TVD): 7,000' - 8,968' Angle/Perfs: Angle @ KOP and Depth: Dated Completed: 4/28/2004 Completion Fluid: 6% KCL Revised By: James Ostroot Last Revison Date: 7/24/2009 Revised By: Mickey Mullin Last Revison Date: 12/10/2009 • • - ~~- ,il~=-- MICROFILMED 03/01/2008 DO NOT PLACE ~ ~~ ~< rv ANY NEW MATERIAL UNDER THIS PAGE F: ~I.aserFiche\CvrPgs_Inserts\Microfilm_Maricer. doc ;( K M) .\~ ~ DATA SUBMITTAL COMPLIANCE REPORT 4/24/2006 Permit to Drill 2040050 Well Name/No. CANNERY LOOP UNIT 8 Operator MARATHON OIL CO Sr/cd- lJ-dOA. ~ <hi ~ API ~o. 50-133-20534-00-00 MD 9777 ~ TVD 7941". " Completion Date 4/28/2004· Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: SP/GR-IEL-Density/Neurton-Sonic-Single Arm Caliper (data taken from Logs Portion of Master Well Data Maint Logl Data Type I Electr Digital Dataset Med/Frmt Number Name Log Log Scale Media Run No Interval OH I Start Stop CH Received Comments . Well CoreslSamples Information: Name Interval Start Stop Sent Received Sample Set Number Comments ADDITIONAL INFORMATION Well Cored? y~ Chips Received? Yì1ot- Formation Tops éJ IN ð/N Daily History Received? Analysis Received? .~ Comments: s..... nvH-~ t: ~ . Compliance Reviewed By: ~ Date: À<-f~NN4 -- . Marathon Oil Company R.ECE'VED ,) ~~ ,."".: ~,. May 24, 2006 ~~~:a g, Alaska Oil & Gas Conservation Commission Attn: Howard Oakland 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon: Cannery Loop Unit 8 Marathon: Cannery Loop Unit 9 Marathon: Cannery Loop Unit 10 Marathon: Cannery Loop Unit 11 CONFIDENTIAL Dear Mr. Oakland: . Alaska Asset Team Northern Business Unit P.O. Box 3128 Houston, TX 77253 Telephone 713-296-2384 Fax 713-499-8504 FEDERAL EXPRESS The following confidential well data is enclosed for the above referenced wells. This digital data includes directional surveys, openhole logs (LAS format) and prints (dpk format) for each well. CLU8 - ^'c t.{ - C> ~~ #- I J Of;.,'! ~ clu8_dir _aogcc,dat l!} clu8 _ vectardepth .Ias .. EMAIL_ Clu-8 "plotted2. dpk CLU9 IiJ du9 _dir _aogcc, dat l!) du9 Jeeves _field, las WE-MAIL Marathon_CLU 9,dpk CLU 10 'd o¿; - 10(.:, IiJ clu_l0_dir _aogcc,dat l!) CLU 1 0 _MAINDEPTH, las f!fUZProgr am Files_Reeves_WLS 7.00 _Data_Marathon_ CLU 10 _MFT _com ,dpk f!fUZProgram Files_Reeves_WLS 7.00_Data_Marathon_CLU lO""plotted,dpk CLU 11 gee., - O~"j) IiJ du_ll_dir _aogcc.dat l!) dU_ll"'precJas, las l!) du_ll"'precJas_tvd,las l!) CLU 11 TIJD, las l!)CLU11 MD.las W Data_Mar athon_ CLU 11"'plotted, dpk Alaska Oil & Gas Association CLU 8, 9, 10, 11 Well Data .,. May 24, 2006 Page 2 . . þ Please indicate your receipt of this data by signing below and returning one copy to me at the letterhead address or fax to 713-499-8504. Thank you, MARATHON OIL COMPANY Lei- \ ¡ , Kaynell Zéman Geological Technician Received by: oiLI Date: P\ ~ M~ ~~ Enclosures e Marathon Oil Company May 17, 2004 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 Reference: Completion Report 10-407 for permit 2()4.()()5 Field: Cannery Loop Unit Gas Field / Beluga Well: CLU - 8 Dear Mr. Aubert, e Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561·5311 Fax 907/564-6489 Enclosed please find the Well Completion Report with associated attachments for Cannery Loop Unit well No.8. 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 further information, I can be reached at 907-529-0524 / 713-296- 2730, or bye-mail atJRThompson@MarathonOil.com. Sincerely, {t:~~7- Sr. Completions Engineer Enclosures: Completion Report Directional Survey Operations Summary Wellbore Diagram RECf=I\f[: Mh: 1 ~ 2004 Alaska Oil 1St ~<¡Ji\ '".i").d.,';;!(H¡ Anchor~ge It STATE OF ALASKA e ALASKA Oil AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG OilO GINJ 0 WINJO 1a. Well Status: Gas~ Plugged 0 Abandoned 0 20AAC 25.105 WDSPLO No. of Completions 2. Operator: Name: Marathon Oil Company 3 Address: P.O. Box 196168, Anchorage, AK 99519-6168 4a. Location of Well (Governmental Section): Surface: 208'FSL,486'FEL,Sec. 7, T5N, R11W, S.M. Top of Productive 2,233.47' FSL, 3,343.94' FWL, Sec. 8, T5N, R11W, S.M. Horizon: Total Depth: 2,340.69' FSL, 3,551.52' FWL, Sec. 8, T5N, R11W, S.M. 4b. Location of Well (State Base Plane Coordinates): Surface: x- 272,484.840 y- 2,388,660.970 Zone- 4 TPI x- 276,352.950 y- 2,390,612.540 Zone- 4 Total Depth x- 276,562.560 y- 2,390,715.760 Zone- 4 18. Directional Survey: Yes~ NOO 21. Logs Run: SP/GR-IEL-Density/Neutron-Sonic-Single Arm Caliper Suspended 0 W AGO 20AAC 25.110 Other 5. Date Comp., Susp., or Aband: 4/28/2004 6. Date Spudded: 1/25/2004 7. Date TD Reached: 2/9/2004 8. KB Elevation (ft.): 42 9. Plug Back Depth (MD + TVD): 9709' MD / 7873' TVD 10. Total Depth (MD+TVD): 9777' MD /7941' TVD 11. Depth where SSSV Set: NA feet MD 19. Water Depth, if Offshore: NA feet MSL 1b. Well Class: Development Exploratory ŒJ Service Stratigraphic Test 0 Permit to Drill Number: 204-005 API Number: 50- 133-20534-00-00 14. Well Name and Number Cannery Loop Unit NO.8 15. FieIdlPool(s): Beluga 16. Property Designation: Lease 604650,603304,605036,605831 17. Land Use Permit: NA 20. Thickness of Permafrost: NA 22. CASING, LINER AND CEMENTING RECORD CASING WI. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT SIZE FT. TOP BOTTOM TOP BOTTOM PULLED 20" 133.0 K-55 0 122 0 122 Driven NA Na 13-318" 68.0 K-55 0 1810 0 1636 16" 512 sx NA 9-5/8" 47.0 L-80 0 6722 0 4941 12-1/4" 555 sx NA 3-1/2" 9.3 L-80 0 9746 0 7910 8-1/2" 1430 sx 85,000 23. Perforations Open to Production (MD + TVD of Top and Bottom Interval, Size, and Number; if none, state "none"): MD: 7027-7037, 7130-7140, 7232-7242, 7297-7307, 7400-7410, 7456-7466, 7578-7588,7688-7698,7922-7932,7962-7992, 8287-8297, 8366-8376, 8409-8419, 8496-8506, 8990-9000 TVD: 5219-5228,5315-5325,5412-5422,5474-5484, 5573-5583, 5627-5637, 5746-5756,5854-5884,6085-6095,6146-6156,6451-8461, 8530-6540, 6573-6583, 6659-6669,7154-7184 Form 10-407 Revised 4/2003 24. SIZE 3-1/2" TUBING RECORD DEPTH SET (MD) 9746 PACKER SET (MD) NA 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED See No. 23 20,000 to 29,000 Ibs 20/40 Ottawa Sand Flowing Water-Bbl: NA Water-Bbl: 283 CONTINUED ON REVERSE SIDE 26. PRODUCTION TEST Date of First Production: 2/2/2004 IMethod of Operation (Flowing, Gas Lift, etc.): Date of Test: Hours Tested: Production for Oil-Bbl: Gas- MCF: 5/2/2004 24 Test Period -~ NA NA Flow. Tubing Casing Pressure Calculated Oil-Bbl: Gas- MCF: Press: 1360 0 24-Hour Rat¡-~ NA 9770 27. CORE DATA BrieL~~~ Q!}i~logy, porosity, fractures, apparent dips and presence of oil, gas, or water (attach separate sheet, if nessary). SUtfii~ê-l:hJj)s\Alìnóne, state "none". I~J """ "BFL JUt( 0 '1 ' ORIG\NAL Choke Size: GaS-Oil Ratio: 34/64th NA oil Gravity - API (corr): NA RECEIVED MAY 1 9 2004 Alaska Oil & Gas Cons. Comm ssion Anchorage c,¡:; e e NAME GEOLOGIC MARKERS MD 29. FORMATION TESTS 28. TVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary, If no tests were conducted, state "None". None None RECEI\/E MAY :1 9 2004 Alaska Oìl & Gas Cons. Anchorage 30. List of Attachments: Directional Survey, Operations summary, Wellbore Diagram 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name James R. Thomspon Signature~R,,~ Title Sr. Completions Engineer Phone 907-529-0524 / 713-296-2730 Date 5/12/2004 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1 a: Classification of Service Wells: Gas Injection, Water Injection, Water-Altemating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex.50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). Item 27: If no cores taken, indicate "none.". Item 28: List all test information. If none, state "None". Form 10-407 Revised 4/2003 .. e e Legal Well Name: CANNERY LOOP UNIT 8 Common Well Name: CANNERY LOOP UNIT 8 Event Name: ORIGINAL DRILLING Start Date: 1/21/2004 End Date: 1/23/2004 122 (ft) 1/24/2004 122 (ft) 1/25/2004 122 (ft) 1/26/2004 1,350 (ft) 1/27/2004 1,821 (ft) 1/28/2004 1,821 (ft) 1/29/2004 1,821 (ft) 1/30/2004 1,821 (ft) 1/31/2004 3,262 (ft) 2/1/2004 5,192 (ft) 2/2/2004 6,385 (ft) 2/312004 6,722 (ft) 2/4/2004 6,722 (ft) 21512004 6,722 (ft) 2/612004 6,959 (ft) 2/7/2004 8,203 (ft) 2/8/2004 9,148 (ft) 2/9/2004 9,777 (ft) RDMO to CLU #8, begin rig up Rig up on CLU #8 RIU on CLU #8, troubleshoot top drive, handle BHA #1 Troubleshoot top drv, spud well, drill ahead, circ, POH wiper trip, repair top drv, slip drlg line, RIH wiper trip, drill ahead. Drill to 1821, circ, wiper trip, circ, POH, UD BHA, RIU run 13318 csg Run I Cmt 13 3/8 esg, NID, NIU BOPE Test wellhead, N/U BOPE, test, CIO top drv safety valve PIU 5" DP, cut drlg line, service rig, RIH drctnl assy, drill float I emt, circ for test. Test csg, drill shoe I formation, displace, LOT, drill ahead 12 1/4 hole Drill to 3818, eire, wiper trip, drill to 4818, cire, wiper trip, drill to 5192 Drill 5818, wiper trip, drill 6298, trip for washout, drill ahead 12 1/4 hole Drill, eire samples, wiper trip, CIC etC, POH for csg, RIU, RIH 9 5/8 csg Run 9-518" casing to 6,722'. Cement wI 555 total sxs. Set and test WH packoffto 5,000 psi. RIU and test BOPE. Test BOPE, TIH wI BHA #3. Tested 9-518" casing to 2,050 psi. Cleaned out 9-5/8" shoe track and drilled 23' new formation to 6,745'. Displaced to new 9.0 ppg mud. Perform LOT to 13.28 ppg EMW. Drill f/6,745' to 6,959'. Drill 8-1/2" directional hole from 6,959' to 8,203'. CBU for wiper trip at 8,203. CBU. Wiper trip from 8,203' to 6,722' Drill from 8,203' to 8,823'. TOH for washout and TBIH. Drill from 8,832' to 9,148'. Drilled f/9,148' to 9,526. POOH (17) stds for washout. Drill f/9,526' to 9,707'. CBU. Drill 9,707' to 9,777'. Hole TD'd. CBU. Printed: 5/1312004 4:28:37 PM e e Legal Well Name: CANNERY LOOP UNIT 8 Common Well Name: CANNERY LOOP UNIT 8 Event Name: ORIGINAL DRILLING Start Date: 1/21/2004 End Date: 2/10/2004 9,777 (ft) Wiper trip to casing shoe and TBIH to 9,777'. CBU and weight up to 10.2 ppg. TOOH. Run quad combo E-Line logs from 9,742' to 5,300'. Printed: 511312004 4:28:37 PM e e Legal Well Name: CANNERY LOOP UNIT 8 Common Well Name: CANNERY LOOP UNIT 8 Event Name: ORIGINAL COMPLETION Start Date: 2/19/2004 End Date: 2/1112004 9,777 (ft) TIH to 3,200'. S&C drill line. TIH to TO 9,777'. CBU. TOOH UD DP. 2/12/2004 9,777 (ft) UD HWDP. Pulled wearbushing. RIU casing tools. Began running 3-112" casing I Excape completion system to 6,200'. 2/13/2004 9,777 (ft) Finsih P/U 3-1/2" casing wI EXCAPE system to 9,746'. CBU. E-Line GR correlation log. Cement casing wI 1430 sxs. woe 2/14/2004 9,777 (ft) WOC, N/D BOP's. Set slips on 3-1/2" casing. Set and test packoff. NIU tree and test same. Rig down the rig and release rig to Well KBU 23-7. *** Final Report*** Printed: 511312004 4:29:00 PM " e e Legal Well Name: CANNERY LOOP UNIT 8 Common Well Name: CANNERY LOOP UNIT 8 Event Name: ORIGINAL COMPLETION Start Date: 4/21/2004 End Date: 4/22/2004 (ft) 4/23/2004 (ft) 4/26/2004 (ft) 4/27/2004 (ft) 4/2812004 4/29/2004 4/30/2004 5/112004 5/2/2004 Spot frac tanks and prepare location for remaining frac, flowback, and coil tubing equipment. Continued hauling water from KGF to CLU 8 frac tanks. Spotted crane at wellhead. Continued riggin up frac tanks, equipment and lines. Continue rigging up frac equipment. Spotted frac trucks and flowback test equipment. Finished blowing frac sand. (ft) Completed frac rig up operations. Tested frac lines to 9300 psig. Tested coil and flowback lines to 4500 psig. Perforated Module 1 perfs (ft) Hold PJSM. Performed 15 Excape fracture treatments. RD frac equipment and RU CT. RIH wI CT and clean out well to PBTD of 9673' MD. Broke module 15 and possibly module 3 flappers. Jet well in w N2. POOH and RD CT. Prepare to open well for testing. (ft) Prepare facilities safety systems to flow well. Opened up well and began unloading and testing operations. As of 05304/30/2004 well cleaning up and flowing 7.56 MMCFD, 370 BWPD, on a 28/64th choke and 1400 psig FTP. (ft) (ft) Flow tested well on a 32/64th choke. Increased choke to 34/64th and flow tested well. Well now flowing 9.77 MMCFD. 283 BWPD. with a 1360 psig FTP. 5/3/2004 (ft) Flow test well for 24 hrs. 5/4/2004 (ft) Flow test well for 24 hours. 5/812004 (ft) RID well testers and turned well over to Production. Printed: 511312004 4:29:22 PM API: 50-133-20534 RT-GL: 21.00' RT-THF: 21.70' 208'FSL,486'FEL,Sec.7,T5N, R11W, S.M. Tree cxn = 4-3/4" Otis TOC (est.) - 300' above 9-5/8" shoe Excape Svstem Details - BHP monitoring line volume tank located from 6952' - 6987' Excape System Details - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module 1 - NA Module 2 - 8522' Module 3 - 8436' Module 4 - 8392' Module 5 - 8312' Module 6 - 8008' Module 7 - 7948' Module 8 - 7714' Module 9 . 7604' Module 10 . 7482' Module 11 . 7426' Module 12· 7322' Module 13· 7258' Module 14- 7156' Module 15 - 7053' Well Name &. Number: County or Parish: Perfor~tions (MD) I BHP: Dated Completed: Prepared By: BHT: CLU #8 TD - 9777' PBTD . 9709' CLU #8 Kenai I Lease: State/Provo Completion Fluid: J. R. Thompson Last Revison Date: ¡Drive Pipe: 20",133 ppf, K-55 to 122' Surface Casing: 13-3/8",68 ppf, @ 1810' Cmt wI 229 bbls. of class G at 12 ppg Int. Casing: 9-5/8", 47 ppf,L-80, BTC @ 6722' Cmt wI 320 sks of class G lead at 12.5 ppg and 235 sx of class G tail at 15.8 ppg Prod. TubinQ: 3-1/2", 9.3 ppf, L-80, with 6.25" OD control line protectors to 9746' Cmt wI 1430 sks of class G at 15.8 ppg ExcapeSystem Details . 15 E:xcape modules placed . Green control line fires bottom 7 modules - Red contolline fires top 8 modules - Yellow line for BHP monitoring " Ceramic flapper valves below each module Perfs MD (RKB): Module 1 . 8990'-9000' Module 2 . 8496'-8506' Module 3 - 8409'·8419' Module 4 . 8366'-8376' Module 5 . 8287'-8297' Module 6 . 7982'-7992' Module 7 - 7922'-7932' Module 8 - 7688'-7698' Module 9 - 7578'-7588' Module 10·7456'-7466' Module 11 - 7400'-7410' Module 12 - 7297'-7307 Module 13 - 7232'-7242' Module 14-7130'-7140' Module 15 - 7027'-7037' Cannery Loop Gas Fi(\jld Alaska Country: (WD) JUSA 6% KCL 2/25/2004 e e MARATHON Oil Company Pad U CLU-8 CLU-8 Cannery Loop Unit Cook Inlet, Alaska SUR V E Y LIS TIN G by Baker Hughes INTEQ Your ref Our ref License MWD <0-9777> svy7015 Date printed Date created Last revised 26-Apr-2004 26-Jan-2004 26-Apr-2004 Field is centred on n60 31 54.076,w151 15 37.735 Structure is centred on n60 31 54.076,w151 15 37.735 Slot location is n60 31 56.196,wI51 15 47.694 Slot Grid coordinates are N 2388660.968, E 272484.840 Slot local coordinates are 215.26 N 498.30 W Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North e e MARATHON Oil Company SURVEY LISTING Page 1 Pad U, CLU-8 Your ref MWD <0-9777> Cannery Loop Unit,Cook Inlet, Alaska Last revised : 26-Apr-2004 Measured Inclin. Azimuth True Vert R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/100ft Sect 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 200.00 0.53 68.73 200.00 0.34 N 0.86 E 0.27 0.92 260.00 2.59 70.71 259.97 0.88 N 2.40 E 3.43 2.53 321.00 3.52 73.61 320.88 1.87 N 5.50 E 1. 55 5.73 381.00 5.16 74.13 380.71 3.13 N 9.86 E 2.73 10.18 442.00 5.69 72.97 441. 44 4.76 N 15.39 E 0.89 15.83 503.00 5.86 69.76 502.13 6.72 N 21. 20 E 0.60 21. 88 563.00 7.00 66.63 561.75 9.23 N 27.43 E 1. 99 28.56 624.00 8.21 66.47 622.21 12.45 N 34.84 E 1. 98 36.61 685.00 11. 09 59.02 682.34 17.21 N 43.86 E 5.14 46.82 745.00 14.50 52.21 740.85 24.78 N 54.75 E 6.20 59.98 808.00 15.07 52.66 801.76 34.58 N 67.50 E 0.92 75.83 870.00 16.84 52.04 861.37 45.00 N 80.99 E 2.87 92.63 931. 00 19.52 54.44 919.32 56.36 N 96.25 E 4.56 111. 43 994.00 20.88 56.67 978.45 68.65 N 114.19 E 2.48 133.04 1058.00 24.00 60.10 1037.60 81. 41 N 135.01 E 5.28 157.41 1121. 00 27.74 63.52 1094.28 94.34 N 159.25 E 6.39 184.89 1183.00 32.32 65.11 1147.94 107.76 N 187.21 E 7.50 215.88 1246.00 32.40 65.85 1201.16 121. 75 N 217.89 E 0.64 249.54 1308.00 32.98 66.53 1253.34 135.27 N 248.53 E 1.11 282.94 1371. 00 34.43 65.65 1305.74 149.44 N 280.48 E 2.43 317.81 1432.00 35.37 65.21 1355.77 163.95 N 312.22 E 1. 60 352.65 1494.00 37.49 64.63 1405.66 179.56 N 345.57 E 3.46 389.42 1556.00 39.96 64.84 1454.02 196.11 N 380.64 E 3.99 428.16 1618.00 41. 57 63.43 1500.98 213.78 N 417.06 E 2.99 468.62 1681.00 44.13 61. 62 1547.16 233.56 N 455.06 E 4.51 511.45 1766.00 47.41 61.76 1606.45 262.44 N 508.68 E 3.86 572 . 35 1811. 00 47.45 62.67 1636.89 277.89 N 538.00 E 1. 49 605.49 1874.00 47.95 61. 55 1679.29 299.68 N 579.18 E 1.54 652.09 1937.00 48.15 61. 28 1721. 40 322.10 N 620.32 E 0.45 698.94 2000.00 47.98 61. 80 1763.51 344.44 N 661.52 E 0.67 745.80 2063.00 48.87 62.66 1805.31 366.39 N 703.22 E 1. 74 792.93 2126.00 50.02 63.82 1846.28 387.94 N 745.96 E 2.30 840.78 2189.00 50.99 64.22 1886.34 409.23 N 78 9. 67 E 1. 62 889.37 2252.00 51.08 63.98 1925.96 430.63 N 833.73 E 0.33 938.32 2314.00 50.45 63.98 1965.18 451.70 N 876.89 E 1.02 986.32 2377 . 00 50.02 63.93 2005.47 472.96 N 920.39 E 0.69 1034.72 2440.00 50.54 63.45 2045.73 494.44 N 963.83 E 1.01 1083.16 2503.00 51.01 62.86 2085.57 516.48 N 1007.38 E 1. 04 1131. 96 2566.00 50.80 61. 90 2125.30 539.14 N 1050.70 E 1.23 1180.85 2629.00 50.37 61. 55 2165.30 562.20 N 1093.56 E 0.81 1229.52 2692.00 50.16 60.47 2205.57 585.68 N 1135.94 E 1.36 1277.96 2755.00 50.76 60.94 2245.68 609.45 N 1178.31 E 1.11 1326.53 2818.00 50.88 59.85 2285.48 633.58 N 1220.77 E 1. 35 1375.34 2881. 00 50.77 59.54 2325.28 658.22 N 1262.93 E 0.42 1424.14 2945.00 51.04 60.59 2365.64 683.01 N 1305.98 E 1.34 1473.77 3008.00 51.02 61. 20 2405.26 706.83 N 1348.77 E 0.75 1522.74 3070.00 50.38 60.91 2444.53 730.05 N 1390.76 E 1.09 1570.71 3132.00 50.24 61. 04 2484.12 753.20 N 1432.47 E 0.28 1618.41 3196.00 49.70 61. 21 2525.29 776.86 N 1475.39 E 0.87 1667.41 All data is in feet unless otherwise stated. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level). Bottom hole distance is 4566.18 on azimuth 62.16 degrees from wellhead. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company SURVEY LISTING Page 2 Pad #1, CLU-8 Your ref MWD <0-9777> Cannery Loop Unit,Cook Inlet, Alaska Last revised : 26-Apr-2004 Measured Inclin. Azimuth True Vert R E C TAN G U LA R Dogleg Vert Depth Degrees Degrees Depth COO R D I N A T E S Deg/100ft Sect 3259.00 49.54 60.87 2566.10 800.10 N 1517.38 E 0.48 1715.40 3321. 00 49.98 61.21 2606.15 823.02 N 1558.79 E 0.82 1762.71 3384.00 49.74 61. 60 2646.77 846.07 N 1601. 07 E 0.61 1810.87 3447.00 49.84 61. 90 2687.44 868.84 N 1643.46 E 0.40 1858.98 3509.00 50.00 62.06 2727.36 891.12 N 1685.33 E 0.32 1906.42 3570.00 49.60 61. 94 2766.73 913.00 N 1726.47 E 0.67 1953.01 3633.00 49.58 61. 52 2807.57 935.72 N 1768.72 E 0.51 2000.98 3696.00 50.06 62.02 2848.22 958.48 N 1811.13 E 0.97 2049.12 3758.00 50.33 62.57 2887.91 980.63 N 1853.30 E 0.81 2096.74 3821. 00 49.74 61.72 2928.38 1003.19 N 1895.99 E 1. 40 2145.03 3883.00 50.24 61. 21 2968.24 1025.87 N 1937.71 E 1. 02 2192.51 3946.00 50.02 61. 24 3008.62 1049.15 N 1980.09 E 0.35 2240.86 4008.00 49.83 61.29 3048.54 1071.96 N 2021.69 E 0.31 2288.30 4069.00 49.69 61.14 3087.94 1094.38 N 2062.50 E 0.30 2334.86 4130.00 50.12 61.86 3127.23 1116.64 N 2103.51 E 1.15 2381. 52 4193.00 50.50 62.56 3167.47 1139.24 N 2146.39 E 1.05 2430.00 4256.00 50.35 62.76 3207.60 1161. 55 N 2189.53 E 0.34 2478.55 4319.00 50.23 62.84 3247.85 1183.70 N 2232.64 E 0.21 2527.01 4382.00 49.98 62.73 3288.26 1205.80 N 2275.62 E 0.42 2575.35 4445.00 50.01 62.63 3328.76 1227.95 N 2318.49 E 0.13 2623.60 4509.00 49.73 62.57 3370.01 1250.47 N 2361. 94 E 0.44 2672 . 53 4573.00 50.12 62.22 3411. 21 1273.16 N 2405.34 E 0.74 2721. 50 4635.00 50.44 62.13 3450.83 1295.42 N 2447.51 E 0.53 2769.19 4695.00 49.99 62.35 3489.23 1316.90 N 2488.31 E 0.80 2815.30 4756.00 49.93 62.22 3528.47 1338.62 N 2529.65 E 0.19 2862.00 4818.00 49.94 61.99 3568.38 1360.82 N 2571. 59 E 0.28 2909.45 4881.00 49.36 61.88 3609.17 1383.41 N 2613.96 E 0.93 2957.46 4943.00 49.61 61. 96 3649.44 1405.59 N 2655.54 E 0.41 3004.60 5005.00 49.79 62.06 3689.55 1427.79 N 2697.30 E 0.32 3051. 88 5066.00 49.36 62.15 3729.10 1449.51 N 2738.34 E 0.71 3098.32 5129.00 49.27 62.00 3770.17 1471.88 N 2780.55 E 0.23 3146.09 5192.00 50.76 61. 84 3810.65 1494.61 N 2823.14 E 2.37 3194.36 5256.00 50.73 61. 83 3851.15 1518.00 N 2866.83 E 0.05 3243.92 5319.00 50.22 61.76 3891.24 1540.96 N 2909.65 E 0.81 3292.51 5382.00 49.86 61.81 3931.71 1563.79 N 2952.20 E 0.57 3340.80 5445.00 49.56 61. 94 3972.45 1586.45 N 2994.58 E 0.50 3388.86 5508.00 49.43 62.17 4013.36 1608.90 N 3036.90 E 0.35 3436.76 5570.00 49.19 62.36 4053.79 1630.77 N 3078.51 E 0.45 3483.77 5632.00 48.79 62.08 4094.47 1652.58 N 3119.90 E 0.73 3530.55 5695.00 47.97 62.00 4136.31 1674.66 N 3161. 50 E 1. 31 3577.65 5758.00 46.54 62.49 4179.07 1696.21 N 3202.44 E 2.34 3623.91 5822.00 45.28 62.32 4223.60 1717.50 N 3243.18 E 1. 98 3669.88 5884.00 44.51 63.04 4267.52 1737.58 N 3282.06 E 1. 49 3713.64 5948.00 43.16 63.07 4313.69 1757.67 N 3321. 57 E 2.11 3757.96 6010.00 41.81 63.42 4359.41 1776.52 N 3358.96 E 2.21 3799.82 6073.00 40.69 63.40 4406.77 1795.11 N 3396.10 E 1. 78 3841. 35 6137.00 39.67 63.01 4455.67 1813.73 N 3432.96 E 1. 64 3882.63 6199.00 38.68 63.28 4503.73 1831.42 N 3467.90 E 1. 62 3921.79 6263.00 37.25 62.52 4554.19 1849.35 N 3502.95 E 2.35 3961.15 6325.00 35.89 62.50 4603.98 1866.40 N 3535.72 E 2.19 3998.09 All data is in feet unless otherwise stated. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level). Bottom hole distance is 4566.18 on azimuth 62.16 degrees from wellhead. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad U, CLU-8 Cannery Loop Unit,Cook Inlet, Alaska Measured Inclin. Azimuth True Vert R E C TAN G U L A R Depth Degrees Degrees Depth COO R DIN ATE S 6389.00 6452.00 6514.00 6578.00 6640.00 34.65 33.71 32.27 30.77 29.63 6779.00 6842.00 6905.00 6967.00 7029.00 26.30 24.29 23.47 22.30 20.75 7092.00 7154.00 7215.00 7277.00 7339.00 20.24 19.26 18.08 16.62 15.74 7402.00 7466.00 7529.00 7592.00 7655.00 15.09 14.39 13 .20 11.98 10.57 7718.00 7777 . 00 7839.00 7901.00 7963.00 8026.00 8088.00 8149.00 8212.00 8275.00 8338.00 8401.00 8464.00 8527.00 8590.00 8652.00 8714.00 8777.00 8841. 00 8904.00 8967.00 9030.00 9093.00 9155.00 9219.00 9282.00 9345.00 9408.00 9471. 00 9534.00 61.75 61. 93 61.96 62.11 61.38 61. 42 61.15 60.85 60.90 61. 98 61. 08 62.60 63.11 62.81 62.47 63.03 62.52 59.06 56.70 58.18 9.32 8.31 7.40 5.36 2.99 61.23 61.60 60.64 60.92 55.89 1.54 1.29 1.21 1.04 1.02 52.95 87.15 96.97 104.21 107.68 0.95 0.83 0.78 0.68 0.66 100.29 96.95 89.90 99.07 93.46 0.65 0.63 0.60 0.66 0.78 93.98 96.39 91. 28 85.74 86.89 0.69 0.58 0.53 0.50 0.48 82.69 73.42 79.83 46.18 65.59 0.50 0.46 0.50 0.49 0.46 45.05 50.43 44.38 47.97 34.12 4656.23 4708.35 4760.35 4814.91 4868.49 4991.25 5048.20 5105.81 5162.93 5220.60 5279.62 5337.97 5395.76 5454.93 5514.48 5575.21 5637.10 5698.29 5759.77 5821.55 5883.61 5941. 91 6003.33 6064.94 6126.77 6189.72 6251.70 6312.69 6375.68 6438.67 6501. 66 6564.65 6627.64 6690.64 6753.63 6815.63 6877.63 6940.62 7004.62 7067.61 7130.61 7193.60 7256.60 7318.60 7382.60 7445.59 7508.59 7571.59 7634.59 7697.58 1883.68 N 1900.38 N 1916.26 N 1931. 95 N 1946.71 N 1977.91 N 1990.84 N 2003.20 N 2014.93 N 2025.82 N 2036.33 N 2046.22 N 2055.13 N 2063.54 N 2071. 47 N 2079.14 N 2086.59 N 2093.90 N 2101.19 N 2107.83 N 2113.33 N 2117.66 N 2121. 75 N 2125.11 N 2127.43 N 2128.86 N 2129.39 N 2129.35 N 2129.13 N 2128.82 N 2128.55 N 2128.41 N 2128.35 N 2128.29 N 2128.21 N 2128.17 N 2128.10 N 2128.06 N 2128.08 N 2128.13 N 2128.20 N 2128.34 N 2128.48 N 2128.72 N 2129.02 N 2129.33 N 2129.68 N 2130.04 N 2130.42 N 2130.81 N e SURVEY LISTING Page 3 Your ref MWD <0-9777> Last revised : 26-Apr-2004 Dogleg Vert Deg/100ft Sect 3568.39 E 3599.59 E 3629.38 E 3658.93 E 3686.41 E 3743.63 E 3767.23 E 3789.54 E 3810.60 E 3830.58 E 3849.97 E 3868.43 E 3885.81 E 3902.28 E 3917.62 E 3932.51 E 3946.99 E 3960.10 E 3971.74 E 3982.11 E 3991. 50 E 3999.43 E 4006.85 E 4012.87 E 4016.74 E 4018.77 E 4020. 13 E 4021.46 E 4022.67 E 4023.76 E 4024.81 E 4025.78 E 4026.66 E 4027.46 E 4028.19 E 4028.90 E 4029.59 E 4030.26 E 4030.96 E 4031.75 E 4032.56 E 4033.24 E 4033.83 E 4034.31 E 4034.75 E 4035.19 E 4035.58 E 4035.97 E 4036.36 E 4036.70 E 2.05 1.50 2.32 2.35 1. 93 4035.05 4070.44 4104.20 4137.65 4168.84 2.40 3.20 1. 32 1. 89 2.58 4234.01 4260.92 4286.42 4310.53 4333.27 0.95 1. 78 1. 95 2.36 1.43 4355.33 4376.28 4395.80 4414.29 4431. 56 1.06 1.11 2.30 2.10 2.28 4448.31 4464.59 4479.60 4493.29 4505.57 2.15 1. 71 1. 48 3.29 3.86 4516.44 4525.48 4533.95 4540.84 4545.34 2.31 1.40 0.37 0.35 0.10 4547.81 4549.26 4550.41 4551. 38 4552.20 0.23 0.21 0.18 0.24 0.11 4553.00 4553.79 4554.54 4555.22 4555.83 0.02 0.05 0.10 0.13 0.19 4556.43 4557.01 4557.58 4558.22 4558.94 0.17 0.24 0.13 0.48 0.26 4559.68 4560.35 4560.94 4561.47 4562.01 0.28 0.10 0.10 0.05 0.19 4562.53 4563.05 4563.55 4564.08 4564.56 All data is in feet unless otherwise stated. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level). Bottom hole distance is 4566.18 on azimuth 62.16 degrees from wellhead. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company SURVEY LISTING Page 4 Pad U, CLU-8 Your ref MWD <0-9777> Cannery Loop Unit,Cook Inlet, Alaska Last revised : 26-Apr-2004 Measured Inclin. Azimuth True Vert R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/IOOft Sect 9597.00 0.41 12.67 7760.58 2131.24 N 4036.89 E 0.27 4564.93 9660.00 0.50 19.64 7823.58 2131. 71 N 4037.03 E 0.17 4565.28 9723.00 0.55 29.13 7886.58 2132.24 N 4037.27 E 0.16 4565.74 9777.00 0.55 29.13 7940.58 2132.69 N 4037.52 E 0.00 4566.17 Projection to TD All data is in feet unless otherwise stated. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level). Bottom hole distance is 4566.18 on azimuth 62.16 degrees from wellhead. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ · e e MARATHON Oil Company Pad n, CLU-8 Cannery Loop Unit,Cook Inlet, Alaska SURVEY LISTING Page 5 Your ref MWD <0-9777> Last revised : 26-Apr-2004 Comments in wellpath ==================== MD TVD Rectangular Coords. Comment ----------------------------------------------------------------------------------------------------------- 9777.00 7940.58 2132.69 N 4037.52 E Projection to TD Casing positions in string 'A' =================~============ Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing ----------------------------------------------------------------------------------------------------------- 0.00 0.00 0.00 0.00 0.00 0.00 O.OON O.OON O.OON O.OOE O.OOE O.OOE 1810.00 6722.00 9777.00 1636.21 4940.45 7940.58 277.55N 1965.53N 2132.69N 537.34E 3720.92E 4037.52E 13 3/8 Casing 9 5/8 Casing 3 1/2 Liner Targets associated with this wellpath ===================================== Target name Geographic Location T.V.D. Rectangular Coordinates Revised ----------------------------------------------------------------------------------------------------------- CLU-8 - T/M Beluga - 276554.000,2390718.000,0.0000 5803.00 2134.68N 4029.18E 26-Nov-2003 · Œ (ill !Æ~!Æ - j I I , , FRANK H. MURKOWSKI, GOVERNOR AI,ASIiA. OIL AND GAS CONSERVATION COMMISSION Willard J. Tank Senior Drilling Engineer Marathon Oil Company PO Box 196168 Anchorage AK 99519 ¡ ¡ I / 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Cannery Loop Unit CLU #8 Marathon Oil Company Pennit No: 204-005 Surface Location: 208' FSL, 486' FEL, Sec. 7, T5N, RllW, SM Bottomhole Location: 2342' FSL, 765' FEL, Sec. 8, T5N, RIIW, SM 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 terms and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, Sarah Palin Chair BY ORDER OF THE COMMISSION DATED thisk day of January, 2004 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. e e STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: Drill0 Re-entryD RedrillD 1 b. Current Well Class: Stratigraphic TestD EXPloratoryD serviceD 2. Operator Name: Marathon Oil Company 3. Address: P.O. Box 196168, Anchorage, AK 99519-6168 4a. Location of Well (Govemmental Section): Surface: 208' FSL, 486' FEL, Sec. 7, T5N, R11W, S.M. Top of Productive Horizon: 2,322' FSL, 803' FEL, Sec. 8, T5N, R11W, S.M. Total Depth: 2,342' FSL, 765' FEL, Sec. 8, T5N, R11W, S.M. 4b. Location of Well (State Base Plane Coordinates): Surface: x- 272,484.840' y- 2,388,660.968' Zone- 4 16. Deviated Wells: Kickoff Depth: 250 18. Casing Program: Size Casing 20" 133/8" 9 5/8" 31/2" 50.11 0 ft. Maximum Hole Angle: Specifications 5. Bond: 0 Blanket D SingleWellD Ilsl2-cotD,/ RECEIVED DEC 3 1 2003 \-UGA- ~Iaska Oil & Gas Cons. Commìss¡( Anchorage Multiple zoneD /~ Single zone0 Development oilD Development Gas 0 11. Well Name and Number: CLU #8 /. Bond No. 5194234 6. Proposed Depth: MD: 9,734' TVD: 7,871' 7. Property Designation: Lease No. 604650,603304,605036,605831 8. Land Use Permit: NIA 9. Acres in Property: (57.25), (440.310), (427.829), (66.140) 10. KB elevation (Height Above GL): 42 (21' above GL) feet 17. Anticipated Pressure (see 20 AAC 25.035) Max. Downhole Pressure: 3,684 Setting Depth psig. 12. Field/Pool(s): Field - Cannery Loop Unit Pool - Beluga 13. Approximate Spud Date: 1/2412004 14. Distance to Nearest Property: 20' (Lease No. 605036) 15. Distance to Nearest Well within Pool: 1,500' to CLU #5 ./ Max. Surface Pressure: 1,905 psig. Quantity of Cement c.f. or sacks. (Including Stage Data) Hole Driven Weight 133# 68# 40# 9.2# Grade Coupling Length MD TVD MD TVD K-55 PE +1- 100' 0' 0' 100' 100' K-55 BTC 1,758' 0' 0' 1,800' 1,628' L-80 BTC 6,928' 0' 0' 6,970' 5,141' L-80 EUE 9,692' 0' 0' 9,734' 7,871' PRESENT WELL CONDITION SUMMARY (to be completed for Redrill and Re-Entry Operations) Total Depth TVD (ft.) Plugs (measured) Effective depth MD (ft) Effective Depth TVD(ft): + I - 500 sks. +1-471 sks. + 1-1,224 sks. 16" 121/4" 8112" 19. Total Depth MD (ft): Casing Length Perforation Depth MD (ft): 20. Attachments: Filing Fee 0 BOP Sketch 0 Property Plat0 Diverter Sketch 0 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Title Senior Drilling Engineer Commission Use Only I Permit Approval :2. <.:> 5 .3 ~ Date: DYes ~NO ~NO Printed Name Willard J. Tank AÀ~./Jr\ /1. ¡,. )//./Þ * ~L/ v Signature Permit to Drill Number: ..2 0 7' - O¡? .r; IAPI Number: 50- 133 Conditions of approval: Samples required Other: Hydrogen sulfide measures DYes Te..;.t ~oPE .-c ~øo" t'â. Approved by: Original Signed By Sam" f'atin Form 10-401 Revised 3/2003 Top Bottom Size Cement Volume Perforation Depth TVD (ft): Drilling program0 Time v. Depth PlotD Seabed ReportD Drilling Fluid program0 Contact Phone 907-564-6310 Junk (measured) MD TVD Shallow Hazard AnalysisD 20 AAC 25.050 ReqUirementsD Date: Date 12/31/2003 , u DL1 DYes Mud log required Directional survey required COMMISSIONER BY ORDER OF THE COMMISSION ORIGINAL I See cover letter for other requirements. ~NO DNO ~Yes Date: 1 hP4 Submit in duplicate e e MARATHON MARATHON Oil COMPANY DRilliNG PROGRAM Cannery loop Unit ClU #8 Original 12/31/03 Originator: Drilling Superintendent: North America Drilling Manager: W.J. Tank 1 n A :)1/( ¿i.. l ~/ P.K. Berqa B.J. Roy Page 1 of 14 e e 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 Maximum Anticipated Surface Pressure ............................................... ..... .............. ............... .... ......... ........ .................... .......6 BOPE Program....................................................................................................................... .................................................8 Wellhead Equipment Summary ................. ............ ..... ........ ....... .......... .................. .......... ... ...... ........ ....... ....... ..... ......... ....... ...8 Directional Program Summary ..................... .............................................. .............. ............. ...... ............... ...... ............... ........9 Directional Surveying Summary .... ................... ....... ........ ........... ............ ......... .... ....... ................... ............................. ...... .....10 Drilling Fluid Program Summary ......... ................................... .............. ............................... ...... ......... ................. ... ....... ........10 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 Name Surface Location SloVPad KBElev. Ground Level Elev. Perm. Datum Water Depth Water Protection Depth Comments: e e CLU #8 208' FSL, 486' FEL, Sec. 7, T5N, R11W, S.M. / CLU Pad 1 Field Cannery Loop Unit 42 County/Province Kenai Peninsula 21 State I Country Alaska KB TotalMD 9,734' NIA TotalTVD 7,871' WBS Code Spud Date API No. Well Class Rig Contractor Rig Name Development Glacier Drilling ./ #1 Geoloaic Proaram Summary Sterling B-2 Sterling C-1 Upper Beluga Middle Beluga Lower Beluga Tyonek Formation (Not a Prod Target) (Not a Prod Target) (Secondary Target) (Primary Target) (Secondary Target) (Not a Prod Target) Comments: Target Middle Beluga Comments: DD.03.09594.CAP.DRL 1/24/04 (est.) MD - RKB TVD___RKB Pore Pressure Pore Pressure Possible Fluid (ft) (ft) (psi) (ppg) Content 5,973 4,317 8.60 Sandstone Gas I Water 6,732 4,928 6.73 Sandstone Gas I Water 6,971 5,142 4.04 Sandstone Gas 7,664 5,803 8.85 Sandstone Gas 8,416 6,553 8. 8!? .~') Sandstone Gas 9,634 7,771 ~ Coal, Silt, Shale Gas Surface Location Coordinates 208' FSL, 486' FEL, Sec. 7, T5N, R11W, S.M. / 60031' 56.196" 151015' 47.694" 2,388,660.968' 272,484.840' MD (ft) 7,664 TVD (ft) 5,803 Location Horizontal Displacement (ft) +N/-S +E/-W (Y) (X) 2,114 3,991 (ft) Circle 250' radius // 2,322' FSL, 803' FEL, Sec. 8, T5N, R11W, S.M. Page 3 of 14 e e Summary of Potential Drillina Hazards Hazard Lost Circulation in Low Pressure Sterling and Beluga sands Well bore Interference with existing wells Discussion Control losses by using sufficiently sized LCM. Control using anticollision calculations and monitoring of MWD magnetics interference. 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 +/- 5,973' MD (4,317' TVD) to total depth of the well. These sands will run from normal pressured to highly depleted and lost circulation and differential sticking are potential hazards. 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. Some well interference hazard exist with the CLU #1 RD, CLU #6, and to a lesser extent CLU #5. Mitigation of this interference will be handled by anticollision analysis and careful observance of magnetic interference seen with MWD equipment. Gyro steering can be performed if necessary. Formation Evaluation Summary Interval Surface 0' - 1,800' MD Intermediate 1,800' - 6,970' MD Production 6,970' - 9,734' MD Completion Electric Logs Mud Logs None None None None None Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Basic with GCA, shale density, temperature in and out, sample collection (10' samples). NIA None Quad Combo, on drill pipe messenger. Pull GR-Neutron to surface inside casing. GR, CCL NIA Coring Requirements: None Comments: Page 4 of 14 e e Drillina Proaram Summary CONDUCTOR: 1. 2. 3. 4. 5. Drive 20" conductor to +/-100 ft. RKB. Move in and rig up rotary drilling rig. Install starting head 20" SLC x 21 1/4", 2M flanged. Nipple up 21 1/4", 2M diverter, 16" diverter'0lve, and 16" diverter line. Function test diverter and diverter valve. / SURFACE: 1. Drill a 16" hole to 1,800' MD (1,628' rvD) per the directional plan. 2. RIH with 133/8" 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/~si. /" 6. Set wear bushing. Š ð 00 'vJC:fr 7. Test surface casing to 1,000 psi. INTERMEDIATE: 1. 2. 3. 4. 5. 6. 7. Drill out float equipment and make 20' of new hole. C7BU. Test shoe to leak off. Estimated EMW is 15.0 ppg. Drill 12 1/4" directional hole to 6,970' MD (5,141' rvD) as per directional program, short tripping every 1,000' or 24 hours. / At TD circulate hole clean. Make wiper trip. TOOH. 3D"0 Change out variable pipe rams with 9 5/8" casing rams. Run test plug and test casing rams to~ psi. Run and cement 9 5/8" casing. Land hanger in multibowl wellhead. Back out landing joint. Change out 9 5/8" casing rams with variable pipe rams. Run test plug and test pipe rams to 250/~ psi. ~ooo Set wear bushing. Test casing to 2,000 psi. /" 8. PRODUCTION: 6. Drill float equipment and 20' of new formation w/8 1/2" bit. CBU. Test shoe to leak off. Estimated EMW 13.0 ppg. /' Drill a 81/2" hole to 9,734' MD (7,871' rvD) per the directional program, short tripping every 1,000' or 24 hours. At TD circulate hole clean. Make wiper trip. TOOH. RU logging company. Run open hole logs on drill pipe, round trip to TD. TOOH and laydown BHA and drill pipe. bushing. Download log data. RD logging company. RU and run 31/2" EXCAPE casing string. RU logging company to correlate EXCAPE modules to open hole logs. 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 ri~l. Pull wear / RD logging 1. 2. 3. 4. 5. 7. 8. 9. 10. Note: 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 e Casina Proaram e MD (ft) Connection API Ratings Casing Q) c Makeup - --- ~...:::- 0 Cñ ~ ëii ro rJ ëii 0- Size Weight O.D. Torque Hole Size :J $ =0- C g CD 0 ~ Q) (in) Top Bottom (Ibs/ft) Grade Type (in) (ft-Ibs) (in) () I- 133/8 Surface 1,800 68 K-55 BTC 14.375 N/A * 16 3,450 1,950 1,300 95/8 Surface 6,970 40 L-80 BTC 10.625 NIA * 12 1/4 5,750 3,090 979 31/2 Surface 9,734 9.3 L-80 8rd 4.5 3,200 81/2 10,160 10,530 207 Comments: * The make up of the buttress connection will be to the proper mark. Casina Desian Setting Depth (TVD) 1,628 5,141 7,871 133/8 95/8 31/2 68 40 9.3 K-55 L-80 L-80 Comments: Maximum Anticipated Suñace Pressure ( 13 3/8 1,628 2,322 95/8 5,141 3,972 3 1/2 7,871 6,948 * MAWP = Maximum allowable working pressure ** MASP = Maximum anticipated surface pressure Comments: MASP / MAWP CALCULATIONS: Surface casinq: 133/8" (1,800' MD, 1,628' TVD) Mud Wt When Set (Ib/gal) 9.4 9.6 ~'l." Frac. Grad (Ib/gal) 15.0 13.0 15.1 Casing Shoe Factors Form Press (Ib/gal) 8.6 6.7 9.0 661 1,905 1,905 2.17 1.61 1.16 1.93 1.07 2.12 2.53 2.62 1.60 Ratio 661 30/70 1,905 30170 1,905 30/70 MASPfrac = «Fracture gradient at shoe + SF) x .052 X TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg + 0.5 ppg) x .052 x 1,628' - (.1 psi/ft x 1,628') MASPfrac = 1,312 psi - 163 psi MASPfrac = 1,149 psi. Page 6 of 14 e e MASPbhp = BHPopen hole td - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhp = (6.7 ppg x .052 x 5,141') - (0.3 x 9.6 ppg x .052 x 5,141') - (0.7 x 0.1 psi/ft x 5,141') MASPbhp = 1,791 psi - 770 psi - 360 psi MASPbhp = 661 psi MASP = MASPbhp = 661 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. - Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 3,450) - (9.4 - 8.3) x .052 x 1,628' MAWP = 2,415 psi - 93 psi = 2,322 psi Intermediate casinQ: 95/8" (6,970' MD, 5,141' TVD) MASPfrac = «Fracture gradient at shoe + S.F.) x .052 X TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (13.0 ppg + 0.5 ppg) x .052 x 5,141' - (.1 psi/ft x5, 141') MASPfrac = 3,609 psi - 514 psi MASPfrac = 3,095 psi. MASPbhp = BHPopen hole td - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhp = (9.0 ppg x .052 x 7,871')- (0.3 x 10.0 ppg x .052 x 7,871') - (0.7 x 0.1 psi/ft x 7,871') MASPbhp = 3,684 psi -1,228 psi - 551 psi . ID loofo +. ~ "'tvk ' MASPbhp = 1,905 psi -= 2~Cf7 pi. tM...(,~ ~.t,. µ W6A- MASP = MASPbhp = 1 ,905 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. - Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 5,750) - (9.6 - 9.4) x .052 x5,141' MAWP = 4,025 psi - 53 psi = 3,972 psi Production casinQ: 31/2" (9,734' MD, 7,871' TVD) MASPfrac = «Fracture gradient at shoe + SF) x .052 X TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.1 ppg + 0.5 ppg) x .052 x 7,871' - (.1 psi/ft x 7,871') MASPfrac = 6,385 psi - 787 psi MASPfrac = 5,598 psi. MASPbhp = BHPopen hole td - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhp = (9.0 ppg x .052 x 7,871') - (0.3 x 10.0 ppg x .052 x 7,871') - (0.7 x 0.1 psi/ft x 7,871 ') MASPbhp = 3,684 psi - 1,228 psi - 551 psi MASPbhp = 1,905 psi MASP = MASPbhp = 1 ,905 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. - Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 10,160) - (10.0 - 9.6) x .052 x 7,871' MAWP = 7,112 psi - 164 psi = 6,948 psi Page 7 of 14 e BOPE Proaram Casing Casing Size (in) Casing Test Test Fluid Press Density (psi) (Ib/gal) MAWP (psi) MASP (psi) Surface 133/8 2,322 661 1,000 9.4 Intermediate 95/8 3,972 1,905 2,000 9.6 Production 31/2 6,948 1,905 2,000 10.0 Comments: Blowout Preventers e BOPS Size & Rating (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets Test Pressure Low/High (psi) ~~ 250/2-;900-' ~t 3000 250/~ 30DO 250/~ /' The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-118" x 5000 psi outlets. /' /" The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor-boy gas buster, and a vacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. 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. Description 13-5/8" 3M X 13-3/8" Slip Loc WI 2, 2" LPG, Landing Base for 20" Conductor, U, AA, PSL 1, PR1 13-5/8" 3M Studded Bottom X 13-5/8" 5M Fig Top, WI 2, 2-1116" 5M Studded Outlets, U,AA,PSL 1,PR 1 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. Wellhead Equipment Summary Component Casing Head Tubing Head Page 8 of 14 Casing Hanger Type 13 5/8" x 9 5/8" Fluted Mandrel 135/8" x 31/2" Manual Slip e - Directional Proaram Summary Build Turn Coordinates Sec. MD TVD Rate Rate Dogleg Inclination Azimuth +N/-S +E/-W VS No. Description (ft) (ft) (°/100') (°/100') (°/100') (deg) (deg) (ft) (ft) (ft) Tie On 0 0 0 0 0 0 0 0 0 0 2 KOP 250 250 0 0 0 0 62.09 0 0 0 3 1"t Build up Section 2.0 0 2.0 62.09 End of 1st Build 750 747.47 2.0 0 2.0 10.00 62.09 20.38 38.46 43.52 :!,<iBuíld up Section 4.0 0 4.0 62.09 End of 2nd Build 1,752.77 1,597.79 4.0 0 4.0 50.11 62.09 250.73 473.24 535.56 Hold Section 0 0 0 50.11 62.09 End of Hold 5,658.19 4,102.35 0 0 0 50.11 62.09 1,653.60 3,121.15 3,532.14 Drop Section -2.0 0 2.0 62.09 End of Drop to the 8,163.74 6,300.47 -2.0 0 2.0 0 62.09 2,134.68 4,029.18 4,559.73 Target TO 9,734.27 7,871.00 0 0 0 0 62.09 2,134.68 4,029.18 4,559.73 Comments: Vertical section calculated from a reference azimuth of 62.09° taken from surface location to bottom hole location. Potential Well Interference: Well CLU #1 RD CLU #6 CLU #5 CLU #7 Distance (ft) 38.7 76.3 101.2 263.8 Depth (MD) 1,100 1,270 1,680 1 ,430 Wellbore interference will need to be closely monitored. See attached directional plan and anticollision analysis for more details. Page 9 of 14 e 0- " " ~ ~ 0 0 0 0 0 ~ '" ;S +' go 4000 0 ~ " 0 u ~ .~ > t 2 ,... rJ': " " I ' -2000 -1000 " 'I"" I ' , " ,i i i i'; : : ¡, , ,':' 1000 2000 3000 4000 5000 6000 Vertical Section at 62.09° [3000ft/in] Directional Survevinn Summary o - 1,800' 1,800' - 6,970' 6,970' - 9,734' MWD Survey X X X Comments: Drillinn Fluid Pronram Summary 0 1,658 8.6 - 9.4 ,/ 1,658 5,141 9.0 - 9.6 / 5,141 7,871 9.0 - 9.6 Gel I Gelex Spud Mud 6% FIe-Pro wI Safecarb 6% FIe-Pro wI Safecarb Comments: e West(-)/East(+) [I 500ft/in] Gyro if needed for interference check. Gel, Gelex, Soda Ash, Caustic, Barite, Polypac Supreme UL Flo-Vis, PoluPac UL, KCI, SafeCarb F&M, Ashphasol Supreme, Lubetex, Caustic, Conqor 404, SafeScav NA Flo-Vis, DualFlo, KCI, Greencide 25G, SafeCarb F, KlaGard, Barite, Caustic, Conqor 404, SafeScav NA See mud prognosis for details. Sized CaC03 (SafeCarb) will be used to controlleakoff into the low pressure zones. Page 10 of 14 e e Drilling Fluid Specifications Interval .,..TVD LSRV From To Density Vis 1 min PV (ft) (ft) (lb/gal) (sedqt) (lb.l100tr) (cP) 0 1,658 8.6 - 9.4 60 - 100 1,658 5,141 9.0 - 9.6 / 40,000 8 - 14 5,141 7,871 9.0 - 9.6 40,000 10 - 14 Comments: YP Fluid Loss Drill Solids (lb/100 tr) (cc) pH (%) 25 - 35 NC - 12 +1- 9.5 <7 7 - 10 +1- 9.5 +1- 5 <5 +1- 9.5 +1- 5 Solids Control Equipment :¡¡ -g ~ g¡ ,¡¡ Q) Q) Q Q c ... .2 Q) Q) õ ~ ~ Q) co Q :s -£ rJ) rJ) rJ) g> g> is ~ ~ ~ ü ü N 0- 9,734' MD x x x x Closed Loop System, Full Containment Equipment Specifications design type, brand, model, flow capaci 2 - Derrick ModeI2E48-90F-3TA Desahder NI A Desilter 1 - Derrick Model 0522 Cleaner NIA CentrifugE¡ 2 - Ml/Swaco units NIA Marathon G&I Facility 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 Proaram Summary Dept~ Gauge Top of Cement Open Casing Hole Ann Vol Slurry WOC Hole Size MD TVD Size MD TVD To TOC Vol Time Excess (in) (ft) (ft) (in) (ft) (ft) (ft3) (ft3) (hrs) (%) 133/8 1,800 1,628 16 0 0 757 1,240 8 50 95/8 6,970 5,141 12 1/4 5,400 ../ 3,937 2,223 772 8 50 31/2 9,734 7,871 81/2 6,700 ../ 4,900 1,001 1 ,457 NIA 50 TOC Yield MD Qty FW Slurry (ft3/sx) (ft) (gal/sx) (%) 8 hr Lead 133/8 Tail Type I Cement 12 500 2.48 1,240 0 10.74 Fresh 812 0 500 1,183 Lead Class "G" 12.5 240 2.10 504 5,400 ./ 11.95 Fresh 95/8 Tail Class "G" 15.7 231 1.16 268 5,970 4.95 Fresh Lead 3 1/2 6,700 ./ Tail Class "G" 15.7 1,224 1.19 1,457 5.00 Fresh 24 0 500+ 2,431 Comments: See cement prognosis for details and spacer specifications. Reaulatorv Waivers and Special Procedures I AOGCC Regulation 20 ACC 25.035 (e) (1) (b) I 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 CLU #8. 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 31/2" 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 both the Kenai Gas Field and Beaver Creek 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. ~ . _ ¡J 0 WcJ...\L.#-ý M.u ~~ Q \ - b" P c; ~ t rì ~...~ r, t.. ~()OO fW. W6~ Page 12 of 14 Bit Summary Interval +MD From To (ft) (ft) o 1,800 1,800 6,970 6,970 9,734 Comments: e e Type Recörrnnended Estimåted Size WOB Rotating ROP (in) Manufacturer Model No. IADC (kips) RPM Hours (ftIh r) 16 Christensen MX-1 115 1 - 4 80 - 350 12 1/4 Christensen MX-C1 117 25-50 80 - 300 81/2 Christensen HCM605 M323 41 Motor The 16" hole section will be drilled with a rerun bit MX-1 (IADC 115). If a second bit is necessary for the 12 y...' hole a MX-C3 (IADC 137) should be used to finish this section. Back up bits for the 8 Y2" hole section will consist of mill tooth and TCI tricone bits. See bit prognosis for additional information. Hvdraulics Summary Rig mud pumps available are shown below. Qty 3 National Oil Well A600PT 5 5 5 (in) 8 8 8 Max Press @ 90% WP (psi) 2,597 2,597 2,597 Surface Intermediate Production Displacement @ 2.04 2.04 2.04 125/255 125/255 125/255 Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. o - 1,800 1,800 - 6,970 121/4 6,970 - 9,734 Comments: 16 Pump Rate (gpm) 523 Standpipe Pressure (psi) 1,300 Actual Data from CLU #7 ECD (Ib/gal) 3-18's 1 - 15 3 - 18's 1 -16 5 - 15's 55 669 2,050 131 Actual Data from CLU #7 81/2 465 2,200 203 Actual Data from KBU #43-7X See separate hydraulics calculations. Annular velocities in the 16" and 12 %" holes were calculated using 5" drillpipe, and the 8 %" was calculated using 4" drillpipe. Page 13 of 14 · e Formation InteQritv 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 e 121 1/4" 2M Diverter 1-. I Diverter Spool "> I I" . Marathon Oil Well CLU #8 Diverter e I Flow line / I I / 116" Automatic Knife Valve ~¡ /- /' " / /' "'- I I í \ '--~ I 1\ 116" Diverter Line e e Marathon Oil Well CLU #8 BOP Stack I Flow Nipple I þ 113 5/8" 5M Annular I Preventer . "> 1 I) 113 5/8" 5M Double Ram Preventer Ie -----. 21/16"5M Ie Check Valve 121/16" 5M Manually 1 \ Operated Valves 1 ) {'-''J.. 1 " DIOIODI0IIJDI0IIJrn ŒITCI 1135/8"5MCross I ~I: ~~\ 1135/8" 5M x 13 5/8" 5M Drilling Spool I Flow line I I / ~ 1 1 < I Pipe Ram I ~ / I Blind Ram I ~/ 131/8" 5M Manually 1 Operated Valve < 1 /1 JI ~mDI®1IJDI0IIJ t " / 13 1/8" 5M Hydraulically I Operated Valve ...... I í ~ Bottom of mud cross must be 24-45" from ground level for Glacier 1 rig placement. 113 5/8" 5M Tubing Head Flange e Marathon Oil Well CLU #8 Choke Manifold e ,/ ITO Gas Buster ITO Blooey Line I I Bleed off Line to Shakers œi œi œi ç::::::;¡ ç::::::;¡ ç::::::;¡ ~J [ ~J [~ 000 C=:j C=:j C=:j C Q ~ œi œi ~ ~ ¡;:::::::;J []J@[l][I[Œ]f ~ []J@[l] , I œi t 13" 5M Valves i 2 9/16" 10M Swaco lJ 131/8" 5M Manually Hydraulically Operated Adjustable Choke Choke I From BOP Stack e e Suñace Use Plan for Cannery Loop Unit, well CLU #8 Surface location: 208' FSL, 486' FEL, Sec. 7, T5N, R11W, S.M. 1) Existing Roads Existing roads which will be used for access to CLU #8 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 CLU #8. 3) Location of existing wells Well CLU #8 will be drilled on Cannery Loop Unit pad 1. A pad drawing is enclosed that shows existing wells. 4) Location of existing andlor proposed facilities The locations of existing production facilities in the CLU pad 1 are shown on the enclosed pad drawing. These facilities will be upgraded to handle the additional gas production. 5) Location of Water Supply A water supply well exists on the pad that CLU #8 will be drilled from. This is shown on the pad drawing. 6) Construction Materials No construction is planned on the pad. 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 e e) Sewage The existing sewer system on the pad will be utilized. 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. The camp will utilize the existing sewer system. 9) Plans for reclamation of the suñace CLU #8 will be drilled on an existing pad. Reclamation of the pad will occur after the abandonment of CLU #8 and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from the U.S. Fish and Wildlife Service prior to any reclamation work beginning. 10) Suñace ownership The surface owner of the land in the Cannery Loop Unit is Marathon Oil Company. 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 1 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. . / z /, ì /6 3 A ;7 /1.1 0 /1.. ~ Name and Title: -;/1/.J:..itvð IT' ~~ Willard J. Tank, $'enior Drilling Engineer Marathon Oil Company P.O. Box 196168 Anchorage. Alaska 99519-6168 (907) 564-63110 Date: ) ) ) ) ~ ~ GENERAL NOTES CANNERY LO(JP UNIT NO.1 EXISTING CONDITIONS 1) BASIS OF COORDINATES IS U.S.C. & G.S. TRI STATION AUDRY IN ALASKA STATE PLANE NAD 27 ZONE 4. 2) BASIS OF ELEVATION IS MEAN SEA LEVEL = 0.00' FOR ELEVATIONS SHOWN. 3) BEARINGS SHOWN HEREON ARE GRID UNLESS OTHERWISE NOTED. 4) AUDRY LOCATION: N: 2382045.42 E: 269866.75 5) 3" SECTION CORNER MONUMENT IN MON BOX SERVES AS A TBM WITH AN ELEVATION = 24.66'. 6) OBJECTS, LOCATIONS. AND TOPOGRAPHY HEREON REPRESENT AS-BUILT CONDITIONS AS SURVEYED MOST RECENTLY ON 10/1/03. 7) EXISTING RESERVE PIT IS INACTIVE AND RECEIVED ADEC CLOSURE IN 1998. 8) CANNERY ROAD. ROYAL STREET, AND BOW PICKER LANE ARE EXISTING GRAVEL ROADS SUITABLE FOR HEAVY CONSTRUCTION EQUIPMENT. 9) MARATHON'S GLACIER DRILL RIG IS CURRENTLY SET UP ON WELL CLU NO.1 AND IS EXPECTED TO REMAIN IN PLACE FOR DURATION OF CONSTRUCTION. CONTRACTOR MUST CONDUCT HIS ACTIVITIES IN SUCH A MANNER AS NOT TO INTERRUPT DRILL RIG ACTIVITY UNLESS PRIOR APPROVAL GRANTED BY MOC. ~ WCMC CORNER 3" MONUMENT N: 2388470.36 E: 271528.88 ELEV. = 22.47' 8 ~ 17 -OHE I ~ 30' ---;( >< ~ W SCALE '11 0 50 100 I I I FEET @) MONITOR WELL :s 1/16 COR. ~ -0 X >r - - }( PROPERTY LINE 7 8 I,- J'0~~ 0'.,, ' o",~' - -',,:::= -:-'-"O..,~ X, "',....." ' e.,.' ... - J,' 0", ----' L, !x(\&[~'~~;~;G - -- '~~'~~~T~V~L~~~~~V1~:;-' 'S~~7' ""~" I ')" ~ 50'-T ? " '\~ \ \ . . . . . . ») ) LO \.,,(~v ~~5:~ , '~~Jì\.'" " ," "~' :',', .0.5%...., , "'1' ;~/ìi'I"II:' ~ -.-.-~. ".~~. ~- . " .. ':'" .,-~ .~... . ,j )1/1"1 ¡ @\: .~ ~ ...' ,':~- 'T() ....--~" I _. . ., /,' :/j~~' 1 Z· , ----.... - ~------=- --" ---- ../j<//~/f/f "." \ CONTRO~. POI \IT #2 .' '11'\\:\' 1-,j/,. /;/ /\ - ..r-- ----~ -,,, ---- - - - ~-.....c r--, ---::::-:., ~_··_-'.l'":·.?:.,,'z·..·;; . ,,,-I N: 238867.7.54 >< r--...3 ¡)1\~~~~~"r.~Rœ~AD-CXPA&s~'20~ - .'-"-/ ~~-- .,~:~?\~:,.c" _:C~.'.'.'...'~'_':'::...:."'....::':..·...:-:c-:-ë.....,................ ~. -" 1>< E:2729_1100, <D ~()-:;:o.'" "':::'V- ___ g '" '" - L. -¡;¡--'..,.. '.:.j . ..... '.",. .~;;~~ I ELEV. - 21.60 I " ~.. -. ~CLU NO.8 I *DANGER* 486' .. - . "k; ,.. ..... \" ~..., ~L ~¡ ; PROPOSED WELL Ii BURIED FLOW LINES FEL ~ EXISTING~------r- CONTROL POINT #1 STAKED LOCATION CULVERT N: 2388690.15 GRID N:2388660.968 · REBOILER D. E: 272373.67 , WATER WELL ~i?T~~~~:~~3f.~6.196" l·-;¡.' 194' & HEATER ---r- ELEV. = 20.79 BUILDING \ LONGITUDE: -151°15'47.694" CLU NO. 1 ~ CLU NO.7 FEL BUILDING :s: ~ GAS WELL PROPOSED WELL >< c:: wI WELL HOUSE CLU NO.5 STAKED LOCATION ~ GAS WELL GRID N:2388631.433 wI WELL HOUSE ~i~~~~~~6~3~:;5.960" LONGITUDE: -151°15'41.853" o M .-- W w a:: .-- en -I ~ o a:: >< o LO w z ~ a:: w ~ ü ë: :s: o aJ TRACT A KENAI SPIT SUBDIVISION NO.2 208' FSL 0 ~ l~ CLU NO.6 GAS WELL wI WELL HOUSE D EXISTING GRAVEL PAD ELEVATION = 21' ± 184' FSL OVERHEAD PIPE SYSTEM ~ ~~~~TOR WASTE WATER BUILDING CONTROL ---EI ~ ""'1 BUILDING [-.-J Ð ~ >< o . o I x BUILDING ,/ / __~ x x~ \ OVERHEAD PIPE SYSTEM [ SEPARATOR x , "- ~-- PROPERTY LINE WATER LINE BURIED 5' ± WL WL ~ x- x 30' GATE ~p 30' GATE x~~x o :t '" ~- 7 8 ~ ··8 17 88 && 88 CHAIN LINK FENCE x - ~~ x x x 50' CANNERY ROAD 83'RJW { KENAI CITY LIMITS , , , , SECTION CORNER 3" MONUMENT N: 2388444.45 E: 272967.50 ELEV. = 24.66' ""'òF\\\II,, :"'~'''''''~~!'' -~.., ¡1i~" £..~.(+t.'~...........\.~.~ :: := \\ -:~=-,f ',,'.................,...: IIII~~'" >- !II ::::¡¡ P5 z o ¡::: a. CE u VI w CI w :;¡ III !!! 3: w 5 w a: I- z w ::J U ~ « CI > w a: >- Z z « <.9 a... 0 V) ¿ Z w 0 0 !:::: .....J Z > U ::> U --.J c- O oz 00 Z .....J - V) 0 >- Z æ: « I w a... I- Z X « z w ~ «0 « U« ¿ a... íf· ~ I") ~ J::: ~ '" ~ I") o ó z ] S; '" o I I") o d z :.: 8 ] 9 w ¡¡: I") '" ~ "' o ri ~ o ~ en ~ « CI :.: i 9 w ¡¡: I/') fØ ~ ~ ~ ~m~ ~ ~!:~ \j- ~''''''8' \")\ ~~g.. :e \")\ ~.: x S :;¡.!: i71~«¡ ~ -m ~~: 6 \.) I- ä:1II Ñ1J Qt: ~¡~i j ~ð~~ \.) ~~gà ¿ z~..... 311. ,. i5 ~ ~ DRAWN BY: CRM CHECKED BY: SAM HORZ. SCAlE: ,. = 60' VERT. SCALE: N/A SHEET: 52 1 : Marathon Oil Company Project: Cannery Loop Unit No.8 CANNERY LOOP UNIT 2$OCOOF'S I Proved Productive Area MARATHON COMPANY 1: :12000 ALASKA BUSINESS UNIT C.)),N:NERY LOOP UNIT DEVELOPME;J::IT 240000QF N 2390000F N 2380000F N 00 " e e #1'4' I~. I I I L________ I I I I I I I I J I t ,,--....., Il~\ I..,O~ I, J I, , I . I ...-- . ~------I ~-----l~ r , L__.J OJ J 1 I I r--' II I I II I I II I I . " I I 15 I" I I ~ .. I <II II 1 , ~ II I ¡ I. II I ¡ ¡ : I I = I r.!:====.::I--,L.------'I I I _'"' ...'"' I I L I \oJ '.... I ! r-----' I I I I ŒNTRIFU6E! I UNIT I I 4' ( 1t\' I I I I I I I I I I DlIf> I I -, I 1 t. I I ,-, I L....____.J KtIJMY 3' X 12' Jîlllllll 75... 615 U· ;:-2 .,. ; t .. .... ... . re ...... . .~ _ 1IIUH '- 751P 6115 U' GLACIER DRILLING RIG #1 MUD PITS AND PU.MP ROOM LAYOUT ~ 75.... fi II :5 U· ~ . .. . .. '" ~ . I~I . ~... 751P 61C:i 11· - ~",..~t " .. "'. !l o . ... .. 5V 9L 11-6110 fOT . [.::. I ';ë w !i: w: :E: 5W 9L A-6IIO PT ~ .:. - i - -. [¡J a . . r ~..~. . . .. ... I'U. PP' ~ w... m.... m._~ 13'-r ....., 1.:r:..1 ~..~ e e MARATHON Oil Company M Structure : Pad # 1 Well: CLU-ß MARATHON ! Field: Cannery Loop Unit Location: Cook Inlet, Alaska -- 4 o - 400 - 800 - 1200 - 1600 - 2000 - 2400 - ,..-..... 2800 - -+- (l) (l) '+- "-..../ 3200 - £ -+- 0.. (l) 3600 - 0 0 4000 - Ü -+- L (l) > 4400 - (l) :J L 4800 - l- I V 5200 - 5600 - 6000 - 6400 - 6800 - 7200 - 7600 - 8000 - KOP o 2.00 o 4.00 DlS: 2.00 deg per 100 It 6.00 8.00 10.00 16.00 20.00 2~~~0 OlS: 4.00 deg per 1 DO It 32.00 36.00 44.00 ~'v 50.11 EOC 13 3/8 Casing o TANGENT ANGLE 50.11 DEG East (feet) -> 0 500 1000 1500 2000 2500 3000 3500 4000 4500 2500 9 ^ I - 1500 ~'t Z 0 íJ'ð ::¡ - 1000 :J Q?-' ,.-.., - CD ('0 - 500 ~ C'~ '--/ /'" /J - 0 1-0 J /<) --& C'c> 0" WELL PROFILE DATA //) :p ----- ...."1_____ ""'00 1(l'>I!ofliJiid Begin Drop 50.11 46.00 42.00 38.00 34.00 32.00 30.00 28.00 / . 2600\"~ 9 5 8 Casing 24.00b 22.00 20.00 18.00 16.00 14.00 12.00 !Tœqe1 oaol I 2.001 "001 000 DlS: 2.00 deg per 100 ft 1,·,,- TC*E'dC!HO", 62.09 AZIMUTH 4560' TO TD ***Plone of Proposal*** , CLU-8 - T /M Beluga - 11/26/063 DlS: 2.00 deg per 100 ft 8.00 6.00 4.000 EOD 2.00: TRUE TARGET ANGLE 0.00 DEG / ,3 1/2 Liner ,U Created by bmichoel Dote plotted : 23~Dec-2a03 400 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 Plot Reference is CLU-8 Ver 2, Coordinc¡tes ore In feet referençe ClU-6. True Vertical Depths orc reference RK8 (Glacier 1). r~i. BAKER HU_ INTEQ 800 Vertical Section (feet) -> Azimuth 62.09 with reference 0.00 N, 0.00 E from CLU-8 e e MARATHON Oil Company Pad #l CLU-8 CLU-8 Cannery Loop Unit Cook Inlet, Alaska PRO P 0 S ALL 1ST I N G by Baker Hughes INTEQ Your ref Our ref License CLU-8 Ver 2 prop5593 Date printed Date created Last revised 23-Dec-2003 22-Dec-2003 23-Dec-2003 Field is centred on n60 31 54.076,w151 15 37.735 Structure is centred on n60 31 54.076,w151 15 37.735 Slot location is n60 31 56.196,w151 15 47.694 Slot Grid coordinates are N 2388660.968, E 272484.840 Slot local coordinates are 215.26 N 498.30 W Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North e MARATHON Oil Company Pad #1,CLU-8 Cannery Loop Unit,Cook Inlet, Alaska Measured Inclin. Azimuth True Vert Depth Degrees Degrees Depth 0.00 250.00 350.00 450.00 550.00 650.00 750.00 800.00 900.00 1000.00 8.00 10.00 12.00 16.00 20.00 1100.00 1200.00 1300.00 1400.00 1500.00 24.00 28.00 32.00 36.00 40.00 1600.00 1700.00 1752.77 2000.00 2500.00 44.00 48.00 50.11 50.11 50.11 3000.00 3500.00 4000.00 4500.00 5000.00 50.11 50.11 50.11 50.11 50.11 5500.00 5658.19 5663.74 5763.74 5863.74 50.11 50.11 50.00 48.00 46.00 5963.74 6063.74 6163.74 6263.74 6363.74 44.00 42.00 40.00 38.00 36.00 6463.74 6563.74 6663.74 6763.74 6863.74 34.00 32.00 30.00 28.00 26.00 6963.74 7063.74 7163.74 7263.74 7363.74 24.00 22.00 20.00 18.00 16.00 7463.74 7563.74 7663.74 7763.74 7863.74 14 .00 12.00 10.00 8.00 6.00 0.00 0.00 2.00 4.00 6.00 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 0.00 250.00 349.98 449.84 549.45 648.70 747.47 796.54 893.55 988.64 1081. 34 1171. 20 1257.79 1340.67 1419.46 1493.76 1563.21 1597.79 1756.34 2076.99 2397.64 2718.29 3038.94 3359.60 3680.25 4000.90 4102.35 4105.91 4171. 51 4239.71 4310.42 4383.55 4459.01 4536.73 4616.58 4698.50 4782.36 4868.07 4955.53 5044.62 5135.25 5227.30 5320.65 5415.20 5510.82 5607.41 5704.84 5803.00 5901. 76 6001.01 R E C TAN G U L A R COO R DIN ATE S 0.00 N 0.00 N 0.82 N 3.27 N 7.35 N 13.05 N 20.38 N 24.84 N 36.17 N 50.63 N 68.16 N 88.68 N 112.08 N 138.26 N 167.08 N 198.40 N 232.06 N 250.73N 339.53 N 519.14 N 698.74 N 878.35 N 1057.96 N 1237.56 N 1417.17 N 1596.78 N 1653.60 N 1655.59 N 1690.92 N 1725.16 N 1758.26 N 1790.19 N 1820.90 N 1850.36 N 1878.53 N 1905.38 N 1930.88 N 1954.99 N 1977.69 N 1998.94 N 2018.72 N 2037.02 N 2053.79 N 2069.03 N 2082.72 N 2094.84 N 2105.37 N 2114.30 N 2121. 62 N 2127 .33 N 0.00 E 0.00 E 1.54 E 6.17 E 13.87 E 24.64 E 38.46 E 46.89 E 68.26 E 95.56 E 128.66 167.39 211.56 260.96 315.35 374.47 E 438.02 E 473.24 E 640.86 E 979.87 E 1318.87 E 1657.88 E 1996.88 E 2335.89 E 2674.89 E 3013.90 E 3121.15 E 3124.91 E 3191. 60 E 3256.22 E 3318.70 E 3378.96 E 3436.93 E 3492.54 E 3545.71 E 3596.39 E 3644.52 E 3690.03 E 3732.87 E 3772.98 E 3810.32 E 3844.85 E 3876.51 E 3905.28 E 3931.11 E 3953.98 E 3973.86 E 3990.72 E 4004.54 E 4015.31 E Dogleg Deg/100ft 2.00 2.00 4.00 4.00 4.00 E /4.00 E 4.00 E 4.00 E 4.00 E 4.00 e PROPOSAL LISTING Page 1 Your ref CLU-8 Ver 2 Last revised : 23-Dec-2003 Vert Sect 0.00 0.00 2.00 2.00 2.00 0.00 0.00 KOP 1. 75 6.98 15.69 27.88 43.52 53.06 77.25 108.15 145.60 189.43 239.42 295.32 356.88 4.00 4.00 4.00 0.00 0.00 423.78 495.70 535.56 EOC 725.25 1108.89 0.00 0.00 0.00 0.00 0.00 1492.54 1876.18 2259.83 2643.47 3027.11 0.00 0.00 2.00 2.00 2.00 3410.76 3532.14 Begin Drop 3536.39 3611. 86 3684.99 2.00 2.00 2.00 2.00 2.00 3755.70 3823.89 3889.49 3952.42 4012.60 2.00 2.00 2.00 2.00 2.00 4069.96 4124.42 4175.92 4224.40 4269.79 2.00 2.00 2.00 2.00 2.00 4312.05 4351.13 4386.96 4419.52 4448.75 2.00 2.00 2.00 2.00 2.00 4474 . 63 4497.13 4516.21 4531.85 4544.03 All data is in feet unless otherwise stated. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Bottom hole distance is 4559.73 on azimuth 62.09 degrees from wellhead. Total Dogleg for wellpath is 100.22 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company PROPOSAL LISTING Page 2 Pad #1,CLU-8 Your ref CLU-8 Ver 2 Cannery Loop Unit, Cook Inlet, Alaska Last revised : 23-Dec-2003 Measured Inclin. Azimuth True Vert R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/10Oft Sect 7963.74 4.00 62.09 6100.63 2131. 41 N 4023.01 E 2.00 4552.75 8063.74 2.00 62.09 6200.49 2133.86 N 4027.64 E 2.00 4557.98 8163.74 0.00 62.09 6300.47 2134.68 N 4029.18 E 2.00 4559.73 EOD 8500.00 0.00 62.09 6636.73 2134.68 N 4029.18 E 0.00 4559.73 9000.00 0.00 62.09 7136.73 2134.68 N 4029.18 E 0.00 4559.73 9500.00 /D.OO 62.09 7636.73 2134.68 N 4029.18 E 0.00 4559.73 9734.27 0.00 62.09 7871.00 2134.68 N 4029.18 E 0.00 4559.73 All data is in feet unless otherwise stated. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level Bottom hole distance is 4559.73 on azimuth 62.09 degrees from wellhead. Total Dogleg for wellpath is 100.22 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad #l, CLU-8 Cannery Loop Unit, Cook Inlet, Alaska MD TVD ----------------------------------------------------------------------------------------------------------- 250.00 1752.77 5658.19 8163.74 250.00 1597.79 4102.35 6300.47 Top MD Top TVD Rectangular Coords. 0.00 N 250.73N 1653.60 N 2134.68 N 0.00 £ 473.24 £ 3121.15 £ 4029.18 £ Comments in wellpath ---------~---~------ ---------~---------- Comment KOP £OC Begin Drop £OD e PROPOSAL LISTING Page 3 Your ref CLU-8 Ver 2 Last revised : 23-Dec-2003 Rectangular Coords. Casing positions in string 'AI Rectangular Coords. ------------------------------ ------------------------------ Bot MD Bot TVD Casing ----------------------------------------------------------------------------------------------------------- 13 3/8 Casing 9 5/8 Casing 3 1/ 2 Liner 0.00 0.00 0.00 Target name 0.00 0.00 0.00 O.OON O.OON O.OON 0.00£ 0.00£ 0.00£ 1628.08 5140.97 7871.00 267.69N 2019.91N 2134.68N Targets associated with this wellpath 1800.00 6970.00 9734.27 ------------------~------------------ ------------------------------------- Geographic Location 505.26E 3812.57£ 4029.18£ 2134.68N Rectangular Coordinates 4029.18£ 26-Nov-2003 ----------------------------------------------------------------------------------------------------------- Revised T.V.D. CLU-8 - T/M Beluga - 276554.000,2390718.000,0.0000 5803.00 e e MARATHON Oil Company Pad #1 CLU-8 CLU-8 Cannery Loop Unit Cook Inlet, Alaska PRO P 0 S ALL I S TIN G by Baker Hughes INTEQ Your ref Our ref License CLU-8 Ver 2 prop5593 Date printed Date created Last revised 23-Dec-2003 22-Dec-2003 23-Dec-2003 Field is centred on n60 31 54.076,w151 15 37.735 Structure is centred on n60 31 54.076,w151 15 37.735 Slot location is n60 31 56.196,w151 15 47.694 Slot Grid coordinates are N 2388660.968, E 272484.840 Slot local coordinates are 215.26 N 498.30 W Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North e MARATHON Oil Company Pad #l,CLU-8 Cannery Loop Unit, Cook Inlet, Alaska Measured Inclin Depth Degrees 0.00 250.00 350.00 450.00 550.00 650.00 750.00 800.00 900.00 1000.00 8.00 10.00 12.00 16.00 20.00 1100.00 1200.00 1300.00 1400.00 1500.00 24.00 28.00 32.00 36.00 40.00 1600.00 1700.00 1752.77 2000.00 2500.00 44.00 48.00 50.11 50.11 50.11 3000.00 3500.00 4000.00 4500.00 5000.00 50.11 50.11 50.11 50.11 50.11 5500.00 5658.19 5663.74 5763.74 5863.74 50.11 50.11 50.00 48.00 46.00 5963.74 6063.74 6163.74 6263.74 6363.74 44.00 42.00 40.00 38.00 36.00 6463.74 6563.74 6663.74 6763.74 6863.74 34.00 32.00 30.00 28.00 26.00 6963.74 7063.74 7163.74 7263.74 7363.74 24.00 22.00 20.00 18.00 16.00 7463.74 7563.74 7663.74 7763.74 7863.74 14.00 12.00 10.00 8.00 6.00 Azimuth Degrees 0.00 0.00 2.00 4.00 6.00 62.09 62.09 62.09 62.09 62.09 True Vert Depth 0.00 250.00 349.98 449.84 549.45 648.70 747.47 796.54 893.55 988.64 1081. 34 1171. 20 1257.79 1340.67 1419.46 1493.76 1563.21 1597.79 1756.34 2076.99 2397.64 2718.29 3038.94 3359.60 3680.25 4000.90 4102.35 4105.91 4171.51 4239.71 4310.42 4383.55 4459.01 4536.73 4616.58 4698.50 4782.36 4868.07 4955.53 5044.62 5135.25 5227.30 5320.65 5415.20 5510.82 5607.41 5704.84 5803.00 5901.76 6001.01 e PROPOSAL LISTING Page 1 Your ref CLU-8 Ver 2 Last revised 23-Dec-2003 R E C TAN G U L A R Dogleg COO R DIN ATE S Deg/l00ft O.OON O.OON 0.82N 3.27N 7.35N 13.05N 20.38N 24.84N 36 . 17N 50.63N 68.16N 88.68N 112.08N 138.26N 167.08N 198.40N 232.06N 250.73N 339.53N 519.14N 698.74N 878.35N 1057.96N 1237.56N 1417 . 17N 1596.78N 1653.60N 1655.59N 1690.92N 1725.16N 1758.26N 1790.19N 1820.90N 1850.36N 1878.53N 1905.38N 1930.88N 1954.99N 1977.69N 1998.94N 2018.72N 2037.02N 2053.79N 2069.03N 2082.72N 2094.84N 2105.37N 2114.30N 2121.62N 2127.33N O.OOE O.OOE 1.54E 6.17E 13.87E 24.64E 38.46E 46.89E 68.26E 95.56E 128.66E 167.39E 211.56E 260.96E 315.35E 374.47E 438.02E 473.24E 640.86E 979.87E 1318.87E 1657.88E 1996.88E 2335.89E 2674.89E 3013.90E 3121.15E 3124.91E 3191.60E 3256.22E 3318.70E 3378.96E 3436.93E 3492.54E 3545.71E 3596.39E 3644.52E 3690.03E 3732.87E 3772.98E 3810.32E 3844.85E 3876.51E 3905.28E 3931.11E 3953.98E 3973.86E 3990.72E 4004.54E 4015.31E 0.00 0.00 2.00 2.00 2.00 0.00 0.00 1. 75 6.98 15.69 Vert Sect G RID Easting COO R D S Northing 2388660.97 2388660.97 2388661. 76 2388664.12 2388668.05 2388673.55 2388680.60 2388684.91 2388695.82 2388709.76 2388726.65 2388746.42 2388768.98 2388794.20 2388821.97 2388852.15 2388884.59 2388902.57 2388988.15 2389161.22 2389334.30 2389507.37 2389680.44 2389853.52 2390026.59 2390199.66 2390254.42 2390256.34 2390290.38 2390323.38 2390355.27 2390386.04 2390415.63 2390444.02 2390471.17 2390497.05 2390521.61 2390544.85 2390566.72 2390587.20 2390606.26 2390623.89 2390640.06 2390654.74 2390667.93 2390679.61 2390689.75 2390698.36 2390705.42 2390710.92 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Bottom hole distance is 4559.73 on azimuth 62.09 degrees from wellhead. Total Dogleg for wellpath is 100.22 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 62.09 2.00 2.00 4.00 4.00 4.00 27.88 43.52 53.06 77.25 108.15 4.00 4.00 4.00 4.00 4.00 145.60 189.43 239.42 295.32 356.88 4.00 4.00 4.00 0.00 0.00 423.78 495.70 535.56 725.25 1108.89 0.00 0.00 0.00 0.00 0.00 1492.54 1876.18 2259.83 2643.47 3027.11 0.00 0.00 2.00 2.00 2.00 3410.76 3532.14 3536.39 3611.86 3684.99 2.00 2.00 2.00 2.00 2.00 3755.70 3823.89 3889.49 3952.42 4012.60 2.00 2.00 2.00 2.00 2.00 4069.96 4124.42 4175.92 4224.40 4269.79 2.00 2.00 2.00 2.00 2.00 4312.05 4351.13 4386.96 4419.52 4448.75 2.00 2.00 2.00 2.00 2.00 4474.63 4497.13 4516.21 4531.85 4544.03 272484.84 272484.84 272486.40 272491. 07 272498.85 272509.72 272523.68 272532.19 272553.78 272581.35 272614.77 272653.89 272698.50 272748.39 272803.32 272863.02 272927.21 272962.78 273132.06 273474.43 273816.80 274159.17 274501. 54 274843.90 275186.27 275528.64 275636.96 275640.76 275708.11 275773.37 275836.47 275897.33 275955.87 276012.03 276065.73 276116.92 276165.52 276211.48 276254.74 276295.26 276332.97 276367.84 276399.82 276428.87 27 6454.96 276478.06 276498.13 276515.16 276529.12 276539.99 e e MARATHON Oil Company PROPOSAL LISTING Page 2 Pad #1,CLU-8 Your ref CLU-8 Ver 2 Cannery Loop Unit, Cook Inlet, Alaska Last revised 23-Dec-2003 Measured Inclin Azimuth True Vert R E C T A N G U L A R Dogleg Vert G RID C o 0 R D S Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/100ft Sect Easting Northing 7963.74 4.00 62.09 6100.63 2131.41N 4023.01E 2.00 4552.75 276547.77 2390714.85 8063.74 2.00 62.09 6200.49 2133.86N 4027.64E 2.00 4557.98 276552.44 2390717.21 8163.74 0.00 62.09 6300.47 2134.68N 4029.18E 2.00 4559.73 276554.00 2390718.00 8500.00 0.00 62.09 6636.73 2134.68N 4029.18E 0.00 4559.73 27 6554.00 2390718.00 9000.00 0.00 62.09 7136.73 2134.68N 4029.18E 0.00 4559.73 276554.00 2390718.00 9500.00 0.00 62.09 7636.73 2134.68N 4029.18E 0.00 4559.73 276554.00 2390718.00 9734.27 0.00 62.09 7871.00 2134.68N 4029.18E 0.00 4559.73 27 6554.00 2390718.00 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Bottom hole distance is 4559.73 on azimuth 62.09 degrees from wellhead. Total Dogleg for wellpath is 100.22 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ - MARATHON Oil Company Pad #l,CLU-8 Cannery Loop Unit, Cook Inlet, Alaska MD TVD ----------------------------------------------------------------------------------------------------------- 250.00 1752.77 5658.19 8163.74 250.00 1597.79 4102.35 6300.47 Top MD Top TVD Rectangular Coords. O.OON 250.73N 1653.60N 2134.68N O.OOE 473.24E 3121.15E 4029.18E Comments in wellpath -------------------- -------------------- Comment KOP EOC Begin Drop EOD e PROPOSAL LISTING Page 3 Your ref CLU-8 Ver 2 Last revised : 23-Dec-2003 Rectangular Coords. Casing positions in string 'AI Rectangular Coords. ------------------------------ ------------------------------ Bot MD Bot TVD 0.00 0.00 0.00 0.00 0.00 0.00 ----------------------------------------------------------------------------------------------------------- Casing Target name O.OON O.OON O.OON O.OOE O.OOE O.OOE 1800.00 6970.00 9734.27 1628.08 5140.97 7871.00 267.69N 2019.91N 2134.68N Targets associated with this wellpath ------------------------------------- ------------------------------------- Geographic Location T.V.D. 505.26E 3812.57E 4029.18E 2134.68N Rectangular Coordinates 4029.18E 26-Nov-2003 13 3/8 Casing 9 5/8 Casing 3 1/ 2 Liner ----------------------------------------------------------------------------------------------------------- Revised CLU-8 - T/M Beluga - 276554.000,2390718.000,0.0000 5803.00 0 a Structure : Pad #1 Well CLU-8 Field Cannery Loop Unit Location Cook Inlet, Alaska East > 50 0 50 100 200 250 300 350 400 450 500 550 600 650 700 400 ~ 400 350 - 350 300 - - 300 /\ 250 1- 250 /\ ----. Z +- 200 - 200 () 0 () 't- '-..-/ .£: 150 - ',50 +- I- 0 Z 100 100 50 - 50 6'00 .if ~ i 50 , ¡- 50 50 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 4200 East -> t 2200 L " 2000 /' if' /''' ../' '9'.;0.0 .ß '51,s 0 1800 " 00 !\ if' /' 7, ^ ./" "? ""°0 I /0 1500 r--.. " 0 .;- ß () Q) 1400 "- - 1400 '-..-/ 1200 - 1200 0 Z 1000 ¡- 1000 800 800 600 - - 600 '000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3500 3800 4000 4200 st ( -> bm;chúei Jl om a 23-Dec-2003 Plet ;$ CLU-B Vet 2. Structure : Pad # 1 Well: CLU-8 Depth~ ore reference RK6 (Glacier Field: Cannery Loop Unit Location: Cook Inlet, Alaska ~ '/'1 i\i \j 300 (\ u 10 340 o o 30 ,320 10 50 60 290 70 2 80 270 90 2 00 250 1 1 0 40 120 'Î n L u 30 220 140 21 200 160 190 180 70 l\j 0 01 FJlo e veil 9 Cyiinde AI depths show ¡-e Meos red depths on Reference Well e e MARATHON Oil Company Pad #1 CLU-8 CLU-8 Cannery Loop Unit Cook Inlet, Alaska 3-D M I N I MUM D I S TAN C E C LEA RAN C E R E paR T by Baker Hughes INTEQ Your ref CLU-8 Ver 2 Our ref prop5593 License Date printed 23-Dec-2003 Date created 22-Dec-2003 Last revised 23-Dec-2003 Field is centred on n60 31 54.076,w151 15 37.735 structure is centred on n60 31 54.076,w151 15 37.735 Slot location is n60 31 56.196,w151 15 47.694 Slot Grid coordinates are N 2388660.968, E 272484.840 Slot local coordinates are 215.26 N 498.30 W Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North Report is limited to clearances less than 200 feet Object wellpath DECREASING CLEARANCES of less than 1000 feet are indicated by an asterisk, e.g. 487.4* GMS <0-11125'>"CLU-3,Pad # 3 / GMS <0-16500'>"CLU-4,Pad # 3 / GMS <0-10731'>"CLU-2,Pad #2 GMS <0-12010'>"CLU-1,Pad #1 Dipmeter <8600-11420'>"CLU-5,Pad #1 MWD <5493 -10725>"CLU#lRdPB1,Pad #1 MWD <9741-10835"CLU-1Rd,Pad #1 PMSS <0 - 8320>"CLU-6,Pad #1 CLU-7 Version #2"CLU-7,Pad #1 MWD <O-????>"CLU-7,Pad #1 Closest approach with 3-D Last revised Distance 6-May-1995 6514.5 6-May-1995 5328.4 5-May-1995 18080.2 5-May-1995 38.7 19-Mar-1997 101.2 10-Nov-2003 38.7 10-Nov-2003 38.7 19-5ep-2000 76.3 15-Nov-2003 293.2 22-Dec-2003 263.8 Minimum Distance method M.D. Diverging from M.D. 8960.0 8960.0 9734.3 9734.3 8540.0 9640.0 1110.0 9720.0 1680.0 9580.0 1110.0 8480.0 1110.0 8480.0 1270.0 2440.0 250.0 9734.3 1430.0 1430.0 e MARATHON Oil Company Pad #l, CLU-8 Cannery Loop Unit/Cook Inlet, Alaska M.D. T.V.D. Reference wellpath Rect Coordinates 0.0 100.0 200.0 250.0 262.5 0.0 100.0 200.0 250.0 262.5 275.0 287.5 300.0 312.5 325.0 275.0 287.5 300.0 312.5 325.0 337.5 350.0 362.5 375.0 387.5 337.5 350.0 362.5 375.0 387.4 400.0 412.5 425.0 437.5 450.0 399.9 412.4 424.9 437.4 449.8 462.5 475.0 487.5 500.0 512.5 462.3 474.8 487.2 499.7 512.1 525.0 537.5 550.0 562.5 575.0 524.6 537.0 549.5 561.9 574.3 587.5 600.0 612.5 625.0 637.5 586.7 599.1 611.5 623.9 636.3 650.0 662.5 675.0 687.5 700.0 648.7 661.1 673.4 685.8 698.2 712.5 725.0 737.5 750.0 758.3 710.5 722.8 735.2 747.5 755.7 766.7 775.0 783.3 791.7 800.0 763.9 772.0 780.2 788.4 796.5 810.0 806.3 O.ON O.ON O.ON O.ON O.ON O.lN O.lN 0.2N 0.3N 0.5N 0.6N 0.8N 1. ON 1. 3N 1. 5N 1. 8N 2.2N 2.5N 2.9N 3.3N 3.7N 4.1N 4.6N 5.1N 5.6N 6.2N 6.7N 7.3N 8.0N 8.6N 9.3N 10.0N 10.7N 11. 5N 12.3N 13.lN 13.9N 14.7N 15.6N 16.5N 17.4N 18.4N 19.4N 20.4N 21.1N 21.8N 22.5N 23.3N 24.0N 24.8N 25.8N 7.0E 7.8E 8.7E 9.6E 10.6E 11.7E 12.7E 13.9E 15.0E 16.3E 17.5E 18.9E 20.2E 21.7E 23.1E 24.6E 26.2E 27.8E 29.5E 31. 2E 32.9E 34.7E 36.6E 38.5E 39.8E 41. IE 42.5E 43.9E 45.4E 46.9E 48.8E Object wellpath O.OE O.OE O.OE O.OE O.OE 2.0 102.0 202.0 252.0 264.5 M.D. T.V.D. 0.0 100.0 200.0 250.0 262.5 275.0 287.5 300.0 312.5 325.0 337.5 350.0 362.5 375.0 387.4 399.9 412.4 424.9 437.4 449.8 462.3 474.8 487.2 499.6 512.1 524.5 537.0 549.3 561.8 574.2 586.6 599.1 611.5 623.8 636.5 648.9 661. 3 673.9 686.3 698.7 711.1 723.5 735.8 748.2 756.4 764.6 772.9 781.1 789.3 797.7 807.6 e CLEARANCE LISTING Page 1 Your ref CLU-8 Ver 2 Last revised : 23-Dec-2003 GMS <0-12010'>"CLU-1,Pad #1 Rect Coordinates Horiz Minim Bearing Dist TCyl Dist 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 20.0S 20.0S 20.1S 20.2S 20.3S 20.4S 20.4S 20.4S 20.3S 20.2S 20.1S 19.9S 19.6S 19.3S 18.9S 18.5S 18.0S 17.6S 17.2S 16.8S 16.3S 15.8S 15.3S 14.6S 110.6E 110.6E 110.6E 11 0 . 6E 11 0 . 6E 11 0 . 6E 110.6E 110.6E 110.6E 110.6E 11 0 . 6E 11 0 . 6E 110.6E 110.6E 11 0 . 6E 11 0 . 6E 11 0 . 6E 110.6E 11 0 . 6E 110.6E 11 0 . 6E 11 0 . 6E 11 0 . 6E 110.6E 11 0 . 6E 11 0 . 6E 11 0 . 6E 11 0 . 6E 11 0 . 5E 11 0 . 5E 11 0 . 5E 11 0 . 5E 11 0 . 5E 11 0 . 5E 110.5E 11 0 . 5E 11 0 . 5E 11 0 . 5E 11 0 . 6E 11 0 . 6E 110.6E 11 0 . 7E 11 0 . 8E 111.0E 111. IE 111. 2E 111 . 4E 111. 5E 111.7E 111 . 9E 112.2E 100.2 100.2 100.2 100.2 100.2 100.2 100.3 100.3 100.4 100.5 100.6 100.7 100.9 101.1 101. 2 101. 5 101.7 101.9 102.2 102.5 102.8 103.1 103.5 103.9 104.3 112.3 112.3 112.3 112.3 112.3* 112.3 112.3 112.3 112.3 112.3* O.lE 0.2E 0.4E 0.6E 0.9E 277.0 289.5 302.0 314 .5 327.0 112.2* 112.1 * 112.0* 111.8* 111.6* 112.3* 112.1 * 112.0* 111.8* 111.6* 1.2E 1.5E 2.0E 2.4E 2.9E 339.5 352.0 364.5 377.0 389.4 111. 3* 111.0* 110.6* 110.2* 109.8* 111.3* 111. 0* 110.7* 110.3* 109.8* 3.5E 4.1E 4.7E 5.4E 6.2E 401.9 414.4 426.9 439.4 451.8 109.3* 108.7* 108.2* 107.6* 106.9* 109.4* 108.8* 108.3* 107.7* 107.1* 464.3 476.8 489.2 501.6 514 .1 526.5 539.0 551.3 563.8 576.2 588.6 601.1 613.5 625.9 638.5 650.9 663.3 675.9 688.3 700.8 713.1 725.5 737.8 750.2 758.4 766.7 774.9 783.2 791. 4 799.9 809.7 106.2* 105.5* 104.8* 104.0* 103.1* 106.4* 105.7* 105.0* 104.2* 103.4* 104.8 105.2 105.8 106.3 106.9 102.3* 101.4* 100.5* 99.5* 98.5* 102.5* 101.7* 100.8* 99.8* 98.9* 107.6 108.3 109.0 109.7 110.5 97.9* 96.9* 95.8* 94.8* 93.7* 97.6* 96.5* 95.5* 94.4* 93.3* 111.2 112.0 112.8 113.6 114.5 92 .5* 91.4* 90.2* 89.0* 87.7* 92 .1* 91.0* 89.8* 88.5* 87.2* 115.3 116.2 117.0 117.9 118.5 86.0* 84.7* 83.3* 82.0* 81.1* 86.4* 85.1* 83.8* 82.5* 81.6* 119.1 119.7 120.4 121.0 121.7 80.2* 79.3* 78.4* 77.4* 76.4* 80.7* 79.8* 78.9* 77.9* 77.0* 122.5 75.2* 75.8* All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company CLEARANCE LI8TING Page 2 Pad #1,CLU-8 Your ref CLU-8 Ver 2 Cannery Loop Unit, Cook Inlet, Alaska Last revised : 23-Dec-2003 Reference wellpath Object wellpath GM8 <0-12010'>"CLU-l,Pad #1 Horiz MinIm TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 820.0 816.1 26.9N 50.7E 819.6 817.4 13.98 112.5E 123.4 74.0* 74.6* 830.0 825.8 27.9N 52.7E 829.9 827.6 13.08 112.8E 124.2 72.7* 73.3* 840.0 835.5 29.0N 54.7E 839.7 837.4 12.18 113.1E 125.1 71.4* 72 .0* 850.0 845.3 30.1N 56.8E 850.0 847.7 11. 08 113.5E 126.0 70.1* 70.7* 860.0 855.0 31. 3N 59.0E 859.9 857.5 9.98 113.9E 126.9 68.7* 69.4* 870.0 864.6 32.4N 61. 2E 869.7 867.2 8.78 114 . 3E 127.8 67.2* 68.0* 880.0 874.3 33.6N 63.5E 880.0 877.5 7.48 114 . 8E 128.7 65.8* 66.5* 890.0 883.9 34.9N 65.9E 889.9 887.2 6.18 115.3E 129.7 64.3* 65.0* 900.0 893.6 36.2N 68.3E 899.9 897.1 4.78 115.8E 130.7 62.7* 63.5* 910.0 903.2 37.5N 70.7E 909.7 906.8 3.28 116. 3E 131. 8 61.2* 62.0* 920.0 912.7 38.8N 73.3E 919.5 916.5 1. 78 116.9E 132.9 59.6* 60.4* 930.0 922.3 40.2N 75.8E 929.3 926.1 0.28 117 . 4E 134.1 58.1* 58.8* 940.0 931. 8 41.6N 78.5E 939.2 935.8 1.4N 118. IE 135.4 56.6* 57.2* 950.0 941.4 43.0N 81. 2E 949.0 945.5 3.0N 118.7E 136.9 55.0* 55.7* 960.0 950.9 44.5N 83.9E 958.7 955.1 4.6N 119.4E 138.4 53.5* 54.1* 970.0 960.3 46. ON 86.8E 968.6 964.8 6.3N 120.1E 140.0 52.0* 52.6* 980.0 969.8 47.5N 89.6E 978.4 974.4 7.9N 120.8E 141.7 50.6* 51.1* 990.0 979.2 49.0N 92.6E 988.1 984.0 9.6N 121.6E 143.6 49.2* 49.7* 1000.0 988.6 50.6N 95.6E 997.9 993.5 11.4N 122.4E 145.6 47.8* 48.2* 1010.0 998.0 52.2N 98.6E 1007.9 1003.3 13 .2N 123.2E 147.8 46.4* 46.9* 1020.0 1007.4 53.9N 101. 7E 1017.6 1012.8 15.0N 124.0E 150.2 45.2* 45.5* 1030.0 1016.7 55.6N 104.9E 1027.3 1022.4 16.8N 124.8E 152.8 43.9* 44.3* 1040.0 1026.0 57.3N 108.1E 1037.3 1032.2 18.7N 125.7E 155.5 42.8* 43.1* 1050.0 1035.3 59. ON 111.4E 1047.0 1041.6 20.6N 126.5E 158.6 41.8* 42.0* 1060.0 1044.6 60.8N 114.7E 1056.7 1051.1 22.4N 127.3E 161. 9 40.9* 41. 0* 1070.0 1053.8 62.6N 118. IE 1066.7 1060.8 24.4N 128.1E 165.3 40.1* 40.2* 1080.0 1063.0 64.4N 121.6E 1076.3 1070.3 26.3N 128.9E 169.1 39.5* 39.5* 1090.0 1072.2 66.3N 125.1E 1085.9 1079.6 28.3N 129.8E 173.0 39.0* 39.0* 1100.0 1081. 3 68.2N 128.7E 1095.6 1089.0 30.2N 130.6E 177.1 38.8* 38.8* 1110.0 1090.5 70.1N 132.3E 1105.5 1098.7 32.3N 131. 4E 181. 3 38.7* 38.7* 1120.0 1099.6 72 .ON 13 6. OE 1115.1 1108.0 34.2N 132.2E 185.7 38.9 38.9 1130.0 1108.6 74.0N 13 9. 7E 1124.6 1117.3 36.3N 133.0E 190.0 39.3 39.4 1140.0 1117.6 76.0N 143.5E 1134.5 1126.9 38.4N 133.8E 194.4 40.0 40.1 1150.0 1126.7 78.1N 14 7 . 3E 1144.0 1136.2 40.4N 13 4. 6E 198.6 40.8 41.1 1160.0 1135.6 80.1N 151. 2E 1153.5 1145.4 42.5N 135.4E 202.8 42.0 42.3 1170.0 1144.6 82.2N 155.2E 1163.0 1154.7 44.6N 13 6. 2E 206.7 43.3 43.8 1180.0 1153.5 84.3N 159.2E 1172.8 1164.2 46.8N 13 7. OE 210.5 44.9 45.6 1190.0 1162.4 86.5N 163.3E 1182.2 11 73.3 48.9N 13 7. 8E 214.1 46.7 47.6 1200.0 1171.2 88.7N 167.4E 1191.6 1182.5 51. ON 138.6E 217.4 48.7 49.9 1210.0 1180.0 90.9N 171. 6E 1201.3 1191. 9 53.3N 13 9. 4E 220.5 50.9 52.3 1220.0 1188.8 93.1N 175.8E 1210.7 1201.0 55.4N 14 0 . 2E 223.4 53.2 55.0 1230.0 1197.5 95.4N 180.1E 1220.1 1210.0 57.6N 141.0E 226.0 55.8 57.9 1240.0 1206.3 97.7N 184.4E 1229.4 1219.1 59.9N 141.7E 228.4 58.5 60.9 1250.0 1214.9 100.0N 188.8E 1239.0 1228.4 62.2N 142.5E 230.7 61.3 64.2 1260.0 1223.6 102.4N 193.2E 1248.3 1237.3 64.4N 14 3. 3E 232.8 64.3 67.6 1270.0 1232.2 104.8N 197.7E 1257.6 1246.3 66.7N 144.0E 234.6 67.3 71.1 1280.0 1240.8 107.2N 202.3E 1267.1 1255.5 69.0N 144.8E 236.4 70.6 74.8 1290.0 1249.3 109.6N 206.9E 1276.3 1264.4 71. 3N 145.6E 238.0 73.9 78.7 1300.0 1257.8 112.1N 211.6E 1285.5 1273.3 73.6N 14 6. 3E 239.5 77.3 82.7 1310.0 1266.2 114.6N 216.3E 1294.7 1282.1 75.9N 14 7. OE 240.8 80.9 86.8 1320.0 1274.7 11 7. IN 221. OE 1304.0 1291.1 78.3N 147.8E 242.1 84.5 91.1 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company CLEARANCE LISTING Page 3 Pad #1, CLU-8 Your ref CLU-8 Ver 2 Cannery Loop Unit, Cook Inlet, Alaska Last revised : 23-Dec-2003 Reference wellpath Object wellpath GMS <0-12010'>"CLU-l,Pad #1 Horiz MinIm TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 1330.0 1283.1 119 . 7N 225.8E 1313.2 1299.9 80.7N 14 8. 5E 243.3 88.2 95.5 1340.0 1291.4 122.2N 230.7E 1322.2 1308.6 83.0N 14 9. 2E 244.3 92 .1 100.0 1350.0 1299.7 124.8N 235.6E 1331.3 1317.4 85.4N 149.9E 245.3 96.0 104.7 13 60.0 1308.0 127.5N 240.6E 1340.5 1326.2 87.9N 150.6E 246.2 100.0 109.5 1370.0 1316.2 130.1N 245.6E 1349.5 1334.8 90.3N 151. 3E 247.1 104.1 114.5 1380.0 1324.4 132.8N 250.7E 1358.5 1343.4 92.7N 152.0E 247.9 108.2 119.5 13 90.0 1332.6 135.5N 255.8E 1367.5 1352.1 95.2N 152.7E 248.6 112.5 124.7 1400.0 1340.7 138.3N 261. OE 1376.4 1360.7 97.6N 153.3E 249.3 116.8 130.0 1410.0 1348.7 141.0N 266.2E 1385.3 1369.2 100.lN 154.0E 249.9 121.2 135.5 1420.0 1356.8 143.8N 271.4E 1394.2 1377.6 102.5N 154.6E 250.5 125.7 141.0 1430.0 13 64.8 146.6N 276.8E 1403.1 1386.2 105.1N 155.3E 251.1 130.2 146.7 1440.0 1372.7 14 9 . 5N 282.1E 1411.9 1394.6 107.5N 155.9E 251.6 134.8 152.5 1450.0 1380.6 152.3N 287.5E 1420.7 14 03.0 11 0 . ON 156.5E 252.1 139.5 158.4 14 60.0 1388.5 155.2N 293.0E 1429.4 1411.3 112.6N 157.1E 252.6 144.3 164.5 1470.0 1396.3 158.2N 298.5E 1438.3 1419.8 115.1N 157.7E 253.0 149.1 170.7 1480.0 1404.0 161.1N 304.1E 1446.9 1428.1 11 7 . 7N 158.4E 253.4 154.0 177.0 14 90.0 1411. 8 164.1N 309.7E 1455.6 1436.3 120.2N 159.0E 253.8 158.9 183.4 1500.0 1419.5 167.1N 315.4E 1464.2 1444.5 122.7N 159.5E 254.1 163.9 189.9 1510.0 1427.1 170.1N 321.1E 1472 . 9 14 52.8 125.4N 160.1E 254.5 169.0 196 .5 1520.0 1434.7 173.1N 326.8E 1481. 4 1460.9 127.9N 160.7E 254.8 174.1 203.3 1530.0 1442.2 176.2N 332.6E 1489.9 1469.0 130.5N 161. 3E 255.1 179.3 210.2 1540.0 1449.7 179.3N 338.4E 1498.7 1477 . 4 133.2N 161. 9E 255.4 184.6 217 .1 1550.0 1457.2 182.4N 344.3E 1507.1 1485.4 135.7N 162.5E 255.6 189.9 223.9 1560.0 14 64 . 6 185.6N 350.3E 1515.5 1493.3 138.4N 163.0E 255.8 195.2 230.7 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad #1,CLU-8 Cannery Loop Unit, Cook Inlet, Alaska M.D. T.V.D. Reference wellpath Rect Coordinates 980.0 990.0 1000.0 1010.0 1020.0 969.8 979.2 988.6 998.0 1007.4 1030.0 1040.0 1050.0 1060.0 1070.0 1016.7 1026.0 1035.3 1044.6 1053.8 1080.0 1090.0 11 00.0 1110.0 1120.0 1063.0 1072.2 1081.3 1090.5 1099.6 1130.0 1140.0 1150.0 1160.0 11 70.0 1108.6 1117.6 1126.7 1135. 6 1144.6 1180.0 1190.0 1200.0 1210.0 1220.0 1153.5 1162.4 1171.2 1180.0 1188.8 1230.0 1240.0 1250.0 1260.0 1270.0 1197.5 1206.3 1214.9 1223.6 1232.2 1280.0 1290.0 1300.0 1310.0 1320.0 1240.8 1249.3 1257.8 1266.2 1274.7 1330.0 1340.0 1350.0 1360.0 1370.0 1283.1 1291. 4 1299.7 1308.0 1316.2 1380.0 1390 . 0 1400.0 1410.0 1420.0 1324.4 1332.6 1340.7 1348.7 1356.8 1430.0 1440.0 14 50 . 0 14 60.0 14 70.0 13 64 . 8 1372.7 1380.6 1388.5 1396.3 1480.0 1404.0 47.5N 49.0N 50.6N 52.2N 53.9N 55.6N 57.3N 59.0N 60.8N 62.6N 64.4N 66.3N 68.2N 70.1N 72. ON 74.0N 76.0N 78.1N 80.1N 82.2N 84.3N 86.5N 88.7N 90.9N 93.1N 95.4N 97.7N 100.0N 102.4N 104.8N 107.2N 109.6N 112.1N 114.6N 11 7 . IN 119 . 7N 122.2N 124.8N 127 . 5N 130.1N 132.8N 135.5N 138 .3N 141.0N 143.8N 146.6N 14 9 . 5N 152.3N 155.2N 158.2N 161.1N 89.6E 92.6E 95.6E 98.6E 101.7E 104.9E 108.1E 111.4E 114 . 7E 118 . IE 121. 6E 125.1E 128.7E 132.3E 13 6. DE 13 9. 7E 143.5E 14 7. 3E 151.2E 155.2E 159.2E 163.3E 167.4E 171. 6E 175.8E 180.1E 184.4E 188.8E 193.2E 197.7E 202.3E 206.9E 211. 6E 216.3E 221. DE 225.8E 230.7E 235.6E 240.6E 245.6E 250.7E 255.8E 261. DE 266.2E 271 . 4E 276.8E 282.1E 287.5E 293.0E 298.5E 304.1E Object we11path 973.1 983.0 991.2 1001.1 1011.0 1019.3 1029.2 1039.1 1047.7 1057.6 1067.4 1077.3 1086.2 1096.1 1105.9 1114.9 1124.7 1134.5 1143.3 1153.1 1162.9 1171. 6 1181.4 1191.2 1200.9 1209.6 1219.4 1229.2 1238.0 1247.7 1257.5 1266.4 1276.1 1285.8 1294.5 1304.2 1313.9 1323.6 1332.2 1341.8 1351. 5 13 60 . 2 1369.8 1379.5 1388.3 13 98.0 1407.6 1417.2 1426.2 1435.8 1445.4 M.D. T.V.D. 940.8 950.5 958.5 968.2 977.8 985.9 995.5 1005.1 1013.5 1023.1 1032.7 1042.2 1050.8 1060.4 1069.9 1078.5 1088.0 1097.5 1105.9 1115.4 1124.8 1133.1 1142.5 1151.9 1161.2 1169.5 1178.9 1188.2 1196.5 1205.8 1215.1 1223.5 1232.7 1241.9 1250.2 1259.3 1268.5 1277.6 1285.7 1294.8 1303.8 1311.9 1321.0 1330.0 1338.2 1347.2 1356.1 1365.0 1373.4 1382.2 1391.1 e CLEARANCE LISTING Page 4 Your ref CLU-8 Ver 2 Last revised : 23-Dec-2003 Dipmeter <8600-11420'>"CLU-5,Pad #1 TCyl Dist Rect Coordinates Horiz Minim Bearing Dist 3.7N 4.8N 5.8N 6.9N 8.1N 9.1N 10.4N 11.7N 12.8N 14 .2N 15.5N 16.9N 18.2N 19.6N 21.1N 22.4N 23.9N 25.4N 26.8N 28.4N 30.0N 31. 4N 33.0N 34.7N 36.4N 37.9N 39.6N 41. 3N 42.9N 44.7N 46.5N 48.2N 50. ON 51.8N 53.5N 55.3N 57.2N 59.1N 60.8N 62.7N 64.7N 66.4N 68.4N 70.5N 72 .3N 74.4N 76.5N 78.6N 80.6N 82.8N 85.0N 282.5E 284.3E 285.7E 287.5E 289.4E 290.9E 292.8E 294.7E 296.4E 298.4E 300.4E 302.4E 304.2E 306.3E 308.4E 310.3E 312.4E 314.5E 316.5E 318.7E 320.9E 322.8E 325.1E 327.4E 329.7E 331. 8E 334.1E 336.5E 338.7E 341.2E 343.6E 345.9E 348.4E 350.9E 353.2E 355.7E 358.3E 360.9E 363.3E 366.0E 368.7E 371 . 2E 374.0E 376.8E 379.4E 382.3E 385.2E 388.2E 391. DE 394.0E 397.0E 102.8 103.0 103.3 103.5 103.7 104.0 104.2 104.5 104.8 105.0 105.3 105.6 105.9 106.2 106.5 106.8 107.1 107.5 107.9 108.2 108.6 109.1 109.4 109.8 110.3 199.9 198.8* 197.7* 196.6* 195.4* 201.2 200.2* 199.1* 198.0* 196.9* 194.2* 193.0* 191.7* 190.5* 189.2* 195.7* 194.5* 193.3* 192.1* 190.9* 187.8* 186.5* 185.1* 183.7* 182.2* 189.6* 188.3* 187.0* 185.7* 184.3* 180.7* 179.2* 177.7* 176.1* 17 4.6* 182.9* 181.4* 180.0* 178.5* 176.9* 173.0* 171. 3* 169.7* 168.0* 166.3* 175.4* 173.8* 172.2* 170.5* 168.9* 110.8 111.2 111.7 112.2 112.7 164.6* 162.9* 161. 2* 159.5* 157.7* 167.2* 165.5* 163.8* 162.1* 160.3* 113.2 113.9 114.4 115.0 115.7 155.9* 154.1* 152.3* 150.5* 148.7* 158.6* 156.8* 155.0* 153.2* 151. 4 * 116.4 117.0 117.7 118.5 119.3 149.5* 147.7* 145.8* 144.0* 142.1 * 14 6.9* 145.1 * 143.2* 141.4* 139.6* 120.0 120.9 121.7 122.5 123.5 137.8* 136.1* 134.3* 132.5* 130.8* 140.3* 138.4* 136.6* 134.8* 132.9* 124.4 125.3 126.2 127.3 128.3 129.1* 127.4* 125.7* 124.0* 122.4* 131.2* 129.4* 127.6* 125.9* 124.2* 129.3 120.8* 122.5* All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level). Total Dogleg for we11path is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company CLEARANCE LISTING Page 5 Pad #1,CLU-8 Your ref CLU-8 Ver 2 Cannery Loop Unit, Cook Inlet, Alaska Last revised : 23-Dec-2003 Reference wellpath Object wellpath Dipmeter <8600-11420'>"CLU-5,Pad #1 Horiz Minim TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 1490 . 0 1411.8 164.1N 309.7E 1454.6 1399.5 87.1N 399.9E 130.5 119.2* 120.8* 1500.0 1419.5 167.1N 315.4E 1464.2 1408.3 89.3N 403.0E 131. 6 117.7* 119.2* 1510.0 1427.1 170.1N 321.1E 1473.7 1417.0 91. 6N 406.1E 132.7 116.2* 117.6* 1520.0 1434.7 17 3. IN 326.8E 1483.0 1425.5 93.8N 409.2E 133.9 114.8* 116.1* 1530.0 14 42 .2 176.2N 332.6E 14 92.6 1434.2 96 .1N 412.4E 135.1 113.3* 114.5* 1540.0 1449.7 179.3N 338.4E 1502.1 1442.9 98.4N 415.5E 136.4 112.0* 113.1* 1550.0 1457.2 182.4N 344.3E 1511.7 1451. 6 100.7N 418.7E 137.7 110.7* 111.7* 1560.0 14 64 . 6 185.6N 350.3E 1521.1 1460.2 103.0N 421.9E 139.1 109.4* 110.3* 1570.0 1472.0 188.7N 356.3E 1530.5 1468.8 105.3N 425.1E 140.5 108.2* 109.0* 1580.0 1479.3 191. 9N 362.3E 1540.0 1477.4 107.6N 428.3E 141.9 107.1* 107.8* 1590.0 1486.5 195.2N 368.4E 1549.5 1486.0 11 0 . ON 431. 5E 143.4 106.1* 106.7* 1600.0 1493.8 198.4N 374.5E 1558.9 1494.5 112.3N 434.8E 145.0 105.1* 105.6* 1610.0 1500.9 201.7N 380.6E 1568.3 1503.1 114.6N 438.0E 146.6 104.2* 104.6* 1620.0 1508.0 204.9N 386.8E 1577.8 1511.6 11 7. ON 441. 2E 148.3 103.5* 103.8* 1630.0 1515.1 208.3N 393.1E 1587.2 1520.1 119.4N 444.5E 149.9 102.8* 103.0* 1640.0 1522.1 211 . 6N 399.4E 1596.6 1528.6 121.8N 447.8E 151.7 102.3* 102.4* 1650.0 1529.1 214 . 9N 405.7E 1606.2 1537.2 124.2N 451.2E 153.4 101.8* 101.9* 1660.0 1536.0 218.3N 412.1E 1615.6 1545.6 126.6N 454.6E 155.1 101. 5* 101. 5* 1670.0 1542.9 221.7N 418.5E 1624.9 1554.0 129.1N 458.0E 156.9 101.3* 101. 3* 1680.0 1549.7 225.2N 425.0E 1634.7 1562.7 131.7N 461. 5E 158.6 101. 2* 101. 2* 1690.0 1556.5 228.6N 431. 5E 1644.0 1571.0 134.2N 465.0E 160.5 101.3 101.3 1700.0 1563.2 232.1N 438.0E 1653.4 1579.3 13 6. 7N 468.5E 162.3 101.4 101. 5 1708.8 1569.1 235.1N 443.8E 1661.6 1586.6 138.9N 471 . 5E 163.9 101.7 101.7 1717.6 1574.9 238.2N 449.6E 1670.3 1594.3 141. 3N 474.9E 165.4 102.0 102.2 1726.4 1580.7 241.3N 455.5E 1678.5 1601.5 143.5N 478.0E 167.0 102.5 102.7 1735.2 1586.4 244.4N 461.4E 1687.2 1609.2 146.0N 481.4E 168.5 103.0 103.3 1744.0 1592.1 247.6N 467.3E 1695.5 1616.4 148.3N 484.6E 170.1 103.7 104.1 1752.8 1597.8 250.7N 473.2E 1703.6 1623.6 150.6N 487.8E 171. 7 104.4 104.9 1800.0 1628.1 267.7N 505.3E 1749.4 1663.2 163.8N 506.4E 179.3 109.6 110.6 1900.0 1692.2 303.6N 573.1E 1849.1 1747.6 194.8N 549.5E 192.2 124.4 126.1 2000.0 1756.3 339.5N 640.9E 1948.9 1829.9 227.7N 595.4E 202.1 141.4 143.5 2100.0 1820.5 375.5N 708.7E 2052.7 1912.5 263.9N 646.8E 209.0 157.3 159.0 2200.0 1884.6 411 . 4N 77 6. 5E 2158.0 1993.4 303.2N 701.5E 214.7 170.7 172 .0 2300.0 1948.7 447.3N 844.3E 2263.2 2071.5 344.9N 758.4E 220.0 181.5 182.1 2400.0 2012.9 483.2N 912.1E 2371. 0 2147.3 390.1N 820.2E 224.6 187.5 187.7 2500.0 2077.0 519.1N 979.9E 2476.6 2219.2 435.7N 882.7E 229.3 191.4 191.5 2600.0 2141.1 555.1N 1047.7E 2577.0 2285.9 478 . 6N 944.3E 233.5 193.7 193.7 2700.0 2205.3 591. ON 1115.5E 2676.1 2351.8 520.5N 1005.2E 237.4 196 .5 196.6 2800.0 2269.4 626.9N 1183.3E 2775.3 2417.9 562.7N 1066.0E 241.3 199.8 199.9 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Total Dogleg for wel1path is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ - MARATHON Oil Company Pad #l, CLU-8 Cannery Loop Unit, Cook Inlet, Alaska M.D. T.V.D. Reference wel1path Rect Coordinates 0.0 100.0 200.0 250.0 262.5 0.0 100.0 200.0 250.0 262.5 275.0 287.5 300.0 312.5 325.0 275.0 287.5 300.0 312.5 325.0 337.5 350.0 362.5 375.0 387.5 337.5 350.0 362.5 375.0 387.4 400.0 412.5 425.0 437.5 450.0 399.9 412.4 424.9 437.4 449.8 462.5 475.0 487.5 500.0 512.5 462.3 474.8 487.2 499.7 512.1 525.0 537.5 550.0 562.5 575.0 524.6 537.0 549.5 561.9 574.3 587.5 600.0 612.5 625.0 637.5 586.7 599.1 611.5 623.9 636.3 650.0 662.5 675.0 687.5 700.0 648.7 661.1 673.4 685.8 698.2 712.5 725.0 737.5 750.0 758.3 710.5 722.8 735.2 747.5 755.7 766.7 775.0 783.3 791.7 800.0 763.9 772.0 780.2 788.4 796.5 810.0 806.3 O.ON O.ON O.ON O.ON O.ON O.lN O.lN 0.2N 0.3N 0.5N 0.6N 0.8N 1. ON 1.3N 1. 5N 1. 8N 2.2N 2.5N 2.9N 3.3N 3.7N 4.1N 4.6N 5.1N 5.6N 6.2N 6.7N 7.3N 8.0N 8.6N 9.3N 10.0N 10.7N 1l.5N 12.3N 13 .1N 13.9N 14.7N 15.6N 16.5N 17.4N 18.4N 19.4N 20.4N 21.1N 21.8N 22.5N 23.3N 24.0N 24.8N 25.8N 7.0E 7.8E 8.7E 9.6E 10.6E 11. 7E 12.7E 13.9E 15.0E 16.3E 17.5E 18.9E 20.2E 21.7E 23.1E 24.6E 26.2E 27.8E 29.5E 31. 2E 32.9E 34.7E 36.6E 38.5E 39.8E 41.1E 42.5E 43.9E 45.4E 46.9E 48.8E Object wellpath O.OE O.OE O.OE O.OE O.OE 0.0 100.0 200.0 250.0 262.5 M.D. T.V.D. 0.0 100.0 200.0 250.0 262.5 275.0 287.5 300.0 312.5 325.0 337.5 350.0 362.5 375.0 387.4 399.9 412.4 424.9 437.4 449.8 462.3 474.8 487.2 499.6 512.1 524.5 537.0 549.3 561. 8 574.2 586.6 599.1 611.5 623.8 636.5 648.9 661.3 673.9 686.3 698.7 711.1 723.5 735.8 748.2 756.4 764.6 772.9 781.1 789.3 797.7 807.6 e CLEARANCE LI8TING Page 6 Your ref CLU-8 Ver 2 Last revised : 23-Dec-2003 MWD <5493 -10725>"CLU#lRdPB1,Pad #1 Rect Coordinates Horiz Minim Bearing Dist 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 19.98 20.08 20.08 20.18 20.28 20.38 20.48 20.48 20.48 20.38 20.28 20.18 19.98 19.68 19.38 18.98 18.58 18.08 17.68 17.28 16.88 16.38 15.88 15.38 14.68 1l0.6E 11 0 . 6E 11 0 . 6E 11 0 . 6E 1l0.6E 11 0 . 6E 11 0 . 6E 11 0 . 6E 1l0.6E 1l0.6E 1l0.6E 1l0.6E 1l0.6E 11 0 . 6E 1l0.6E 11 0 . 6E 11 0 . 6E 1l0.6E 1l0.6E 11 0 . 6E 1l0.6E 11 0 . 6E 11 0 . 6E 11 0 . 6E 1l0.6E 11 0 . 6E 11 0 . 6E 1l0.6E 11 0 . 5E 11 0 . 5E 11 0 . 5E 11 0 . 5E 1l0.5E 11 O. 5E 11 0 . 5E 1l0.5E 11 O. 5E 11 0 . 5E 11 0 . 6E 1l0.6E 11 0 . 6E 11 0 . 7E 11 0 . 8E 111.0E 11l.lE 111. 2E 111.4E 111. 5E 111. 7E 111.9E 112.2E 100.2 100.2 100.2 100.2 100.2 100.2 100.3 100.3 100.4 100.5 100.6 100.7 100.9 101.1 101.2 101. 5 101.7 101. 9 102.2 102.5 102.8 103.1 103.5 103.9 104.3 104.8 105.2 105.8 106.3 106.9 107.6 108.3 109.0 109.7 110.5 111.2 112.0 112.8 113.6 114 .5 115.3 116.2 117.0 117.9 118.5 119.1 119.7 120.4 121. 0 121.7 122.5 TCyl Dist 112.3 112.3 112.3 112.3 112.3* 112.3 112.3 112.3 112.3 112.3* O.lE 0.2E 0.4E 0.6E 0.9E 275.0 287.5 300.0 312.5 325.0 112.2* 112.1 * 112.0* 111.8* 111.6* 112.3* 112.1 * 112.0* 111.8* 111.6* 1.2E 1. 5E 2.0E 2.4E 2.9E 337.5 350.0 362.5 375.0 387.4 111.3* 111.0* 11 0.6* 110.2* 109.8* 111. 3* 111.0* 110.7* 110.3* 109.8* 3.5E 4.1E 4.7E 5.4E 6.2E 399.9 412.4 424.9 437.4 449.8 109.3* 108.7* 108.2* 107.6* 106.9* 109.4* 108.8* 108.3* 107.7* 107.1* 462.3 474.8 487.2 499.6 512.1 524.5 537.0 549.3 561. 8 574.2 586.6 599.1 611.5 623.9 636.5 648.9 661.3 673.9 686.3 698.8 711.1 723.5 735.8 748.2 756.4 764.7 772.9 781.2 789.4 797.9 807.7 106.2* 105.5* 104.8* 104.0* 103.1* 106.4* 105.7* 105.0* 104.2* 103.4* 102.3* 101.4* 100.5* 99.5* 98.5* 102.5* 101.7* 100.8* 99.8* 98.9* 97.6* 96 .5* 95.5* 94.4* 93.3* 97.9* 96.9* 95.8* 94.8* 93.7* 92.1* 91. 0* 89.8* 88.5* 87.2* 92 .5* 91. 4 * 90.2* 89.0* 87.7* 86.0* 84.7* 83.3* 82.0* 81.1* 86.4* 85.1* 83.8* 82.5* 81.6* 80.2* 79.3* 78.4* 77.4* 76.4* 80.7* 79.8* 78.9* 77.9* 77.0* 75.2* 75.8* All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level). Total Dogleg for wel1path is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad #1,CLU-8 Cannery Loop Unit, Cook Inlet, Alaska M.D. T.V.D. Reference wellpath Rect Coordinates 820.0 830.0 840.0 850.0 860.0 816.1 825.8 835.5 845.3 855.0 870.0 880.0 890.0 900.0 910.0 864.6 874.3 883.9 893.6 903.2 920.0 930.0 940.0 950.0 960.0 912.7 922.3 931.8 941.4 950.9 970.0 980.0 990.0 1000.0 1010.0 960.3 969.8 979.2 988.6 998.0 1020.0 1030.0 1040.0 1050.0 1060.0 1007.4 1016.7 1026.0 1035.3 1044.6 1070.0 1080.0 1090.0 1100.0 1110.0 1053.8 1063.0 1071.2 1081.3 1090.5 1120.0 1130.0 1140.0 1150.0 1160.0 1099.6 1108.6 1117.6 1126.7 1135.6 11 70.0 1180.0 1190.0 1200.0 1210.0 1144.6 1153.5 1162.4 1171.2 1180.0 1220.0 1230.0 1240.0 1250.0 1260.0 1188.8 1197.5 1206.3 1214.9 1223.6 1270.0 1280.0 1290.0 1300.0 1310.0 1232.2 1240.8 1249.3 1257.8 1266.2 1320.0 1274.7 26.9N 27.9N 29.0N 30.1N 31. 3N 32.4N 33.6N 34.9N 36.2N 37.5N 38.8N 40.2N 41.6N 43.0N 44.5N 46.0N 47.5N 49. ON 50.6N 52.2N 53.9N 55.6N 57.3N 59. ON 60.8N 62.6N 64.4N 66.3N 68.2N 70.1N n. ON 74.0N 76.0N 78.1N 80.1N 82.2N 84.3N 86.5N 88.7N 90.9N 93.1N 95.4N 97.7N 100.0N 102.4N 104.8N 107.2N 109.6N 112 . IN 114.6N 11 7 .1N 50.7E 52.7E 54.7E 56.8E 59.0E 61.2E 63.5E 65.9E 68.3E 70.7E 73.3E 75.8E 78.5E 81. 2E 83.9E 86.8E 89.6E 92.6E 95.6E 98.6E 101.7E 104.9E 108.1E 111.4E 114.7E 118. IE 121.6E 125.1E 128.7E 132.3E 13 6. OE 13 9. 7E 14 3. 5E 14 7. 3E 151.2E 155.2E 159.2E 163.3E 167.4E 171. 6E 175.8E 180.1E 184.4E 188.8E 193.2E 197.7E 202.3E 206.9E 211 . 6E 216.3E 221.0E Object wellpath 817.6 827.9 837.7 848.0 857.9 867.7 878.0 887.9 897.9 907.7 966.6 976.4 986.1 995.9 1005.9 1015.6 1025.3 1035.3 1045.0 1054.7 1064.7 1074.3 1083.9 1093.6 1103.5 1113.1 1122.6 1132 . 5 1142.0 1151.5 1161.0 1170.8 1180.2 1189.6 1199.3 1208.7 1218.1 1227 . 4 1237.0 1246.3 1255.6 1265.1 1274.3 1283.5 1292.7 13 02 . 0 M.D. T.V.D. 817.4 827.6 837.4 847.7 857.5 867.2 877.5 887.2 897.1 906.8 917.5 927.3 937.2 947.0 956.7 916.5 926.1 935.8 945.5 955.1 e CLEARANCE LI5TING Page 7 Your ref CLU-8 Ver 2 Last revised : 23-Dec-2003 MWD <5493 -10725>"CLU#lRdPB1,Pad #1 Rect Coordinates Horiz MinIm Bearing Dist 13.95 13.05 12.15 11.05 9.95 8.75 7.45 6.15 4.75 3.25 1. 75 0.25 1.4N 3.0N 4.6N 6.3N 7.9N 9.6N 11.4N 13 .2N 15.0N 16.8N 18.7N 20.6N 22.4N 24.4N 26.3N 28.3N 30.2N 32.3N 34.2N 36.3N 38.4N 40.4N 42.5N 44.6N 46.8N 48.9N 51. ON 53.3N 55.4N 57.6N 59.9N 62.2N 64.4N 66.7N 69.0N 71. 3N 73.6N 75.9N 78.3N 112.5E 112.8E 113.1E 113.5E 113. 9E 114 . 3E 114.8E 115.3E 115.8E 116.3E 116.9E 11 7. 4E 118. IE 118.7E 119.4E 120.1E 120.8E 121. 6E 122.4E 123.2E 124.0E 124.8E 125.7E 126.5E 127.3E 128.1E 128.9E 129.8E 130.6E 131. 4E 132.2E 133.0E 133.8E 134.6E 135.4E 13 6. 2E 137.0E 13 7. 8E 138.6E 139.4E 14 0 . 2E 141. OE 141.7E 142.5E 14 3. 3E 144.0E 144.8E 145.6E 14 6. 3E l47.0E 147.8E 123.4 124.2 125.1 126.0 126.9 127.8 128.7 129.7 130.7 131. 8 132.9 134.1 135.4 136.9 138.4 140.0 141.7 143.6 145.6 147.8 150.2 152.8 155.5 158.6 161. 9 165.3 169.1 173.0 177.1 181. 3 185.7 190.0 194.4 198.6 202.8 206.7 210.5 214.1 217.4 220.5 223.4 226.0 228.4 230.7 232.8 234.6 236.4 238.0 239.5 240.8 242.1 TCyl Dist 74.0* 72.7* 71.4* 70.1* 68.7* 74.6* 73.3* 71 .0* 70.7* 69.4* 964.8 974.4 984.0 993.5 1003.3 1012.8 1022.4 1032.2 1041. 6 1051.1 1060.8 1070.3 1079.6 1089.0 1098.7 11 08.0 1117.3 1126.9 1136.2 1145.4 1154.7 1164.2 1173.3 1182 . 5 1191. 9 1201. 0 1210.0 1219.1 1228.4 1237.3 1246.3 1255.5 1264.4 1273.3 1282.1 1291.1 67.2* 65.8* 64.3* 62.7* 61.2* 68.0* 66.5* 65.0* 63.5* 62.0* 59.6* 58.1* 56.6* 55.0* 53.5* 60.4* 58.8* 57.2* 55.7* 54.1* 52.0* 50.6* 49.2* 47.8* 46.4* 52.6* 51.1* 49.7* 48.2* 46.9* 45.2* 43.9* 42.8* 41.8* 40.9* 45.5* 44.3* 43.1* 42.0* 41.0* 40.1* 39.5* 39.0* 38.8* 38.7* 40.2* 39.5* 39.0* 38.8* 38.7* 38.9 39.3 40.0 40.8 42.0 38.9 39.4 40.1 41.1 42.3 43.3 44.9 46.7 48.7 50.9 43.8 45.6 47.6 49.9 52.3 53.2 55.8 58.5 61.3 64.3 55.0 57.9 60.9 64.2 67.6 67.3 70.6 73.9 77 .3 80.9 71.1 74.8 78.7 82.7 86.8 84.5 91.1 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level). Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company CLEARANCE LISTING Page 8 Pad #1,CLU-8 Your ref CLU-8 Ver 2 Cannery Loop Unit, Cook Inlet, Alaska Last revised : 23-Dec-2003 Reference wellpath Obj ect wellpath MWD <5493 -10725>"CLU#lRdPBl,Pad #1 Horiz Minim TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 1330.0 1283.1 119.7N 225.8E 1311.2 1299.9 80.7N 148.5E 243.3 88.2 95.5 1340.0 1291.4 122.2N 230.7E 1320.2 1308.6 83.0N 14 9. 2E 244.3 92.1 100.0 1350.0 1299.7 124.8N 235.6E 1329.3 1317.4 85.4N 149.9E 245.3 96.0 104.7 1360.0 1308.0 127.5N 240.6E 1338.5 1326.2 87.9N 150.6E 246.2 100.0 109.5 1370.0 1316.2 130.1N 245.6E 1347.5 1334.8 90.3N 151.3E 247.1 104.1 114.5 1380.0 1324.4 132.8N 250.7E 1356.5 1343.4 92.7N 152.0E 247.9 108.2 119.5 1390.0 1332.6 135.5N 255.8E 13 65.5 1352.1 95.2N 152.7E 248.6 112.5 124.7 1400.0 1340.7 138.3N 261. OE 1374.4 1360.7 97.6N 153.3E 249.3 116.8 130.0 1410.0 1348.7 141.0N 266.2E 1383.3 1369.2 100.IN 154.0E 249.9 121.2 135.5 1420.0 1356.8 143.8N 271.4E 1392.2 1377.6 102.5N 154.6E 250.5 125.7 141.0 1430.0 1364.8 146.6N 27 6. 8E 1401.1 1386.2 105.IN 155.3E 251.1 130.2 146.7 1440.0 1372.7 149.5N 282.1E 1409.9 1394.6 107.5N 155.9E 251.6 134.8 152.5 1450.0 1380.6 152.3N 287.5E 1418.7 1403.0 110. ON 156.5E 252.1 139.5 158.4 14 60 . 0 1388.5 155.2N 293.0E 1427.4 1411.3 112.6N 157.1E 252.6 144.3 164.5 14 70.0 1396.3 158.2N 298.5E 1436.3 1419.8 115.1N 157.7E 253.0 149.1 170.7 1480.0 1404.0 161. IN 304.1E 1444.9 1428.1 11 7. 7N 158.4E 253.4 154.0 177.0 1490.0 1411.8 164.1N 309.7E 1453.6 1436.3 120.2N 159.0E 253.8 158.9 183.4 1500.0 1419.5 167.1N 315.4E 14 62.2 1444.5 122.7N 159.5E 254.1 163.9 189.9 1510.0 1427.1 170.1N 321. IE 1470.9 1452.8 125.4N 160.1E 254.5 169.0 196.5 1520.0 1434.7 173.1N 326.8E 1479.4 1460.9 127.9N 160.7E 254.8 174.1 203.3 1530.0 1442.2 176.2N 332.6E 1487.9 1469.0 130.5N 161. 3E 255.1 179.3 210.2 1540.0 1449.7 179.3N 338.4E 1496.7 1477.4 133.2N 161. 9E 255.4 184.6 217.1 1550.0 1457.2 182.4N 344.3E 1505.1 1485.4 135.7N 162.5E 255.6 189.9 223.9 1560.0 14 64.6 185.6N 350.3E 1513.5 1493.3 138.4N 163.0E 255.8 195.2 230.7 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad #1,CLU-8 Cannery Loop Unit, Cook Inlet, Alaska M.D. T.V.D. Reference wellpath Rect Coordinates 0.0 100.0 200.0 250.0 262.5 0.0 100.0 200.0 250.0 262.5 275.0 287.5 300.0 312.5 325.0 275.0 287.5 300.0 312.5 325.0 337.5 350.0 362.5 375.0 387.5 337.5 350.0 362.5 375.0 387.4 400.0 412.5 425.0 437.5 450.0 399.9 412.4 424.9 437.4 449.8 462.5 475.0 487.5 500.0 512.5 462.3 474.8 487.2 499.7 512.1 525.0 537.5 550.0 562.5 575.0 524.6 537.0 549.5 561.9 574.3 587.5 600.0 612.5 625.0 637.5 586.7 599.1 611. 5 623.9 636.3 650.0 662.5 675.0 687.5 700.0 648.7 661.1 673.4 685.8 698.2 712.5 725.0 737.5 750.0 758.3 710.5 722.8 735.2 747.5 755.7 766.7 775.0 783.3 791.7 800.0 763.9 772.0 780.2 788.4 796.5 810.0 806.3 O.ON O.ON O.ON O.ON O.ON O.lN O.lN 0.2N 0.3N 0.5N 0.6N 0.8N 1. ON 1. 3N 1. 5N 1. 8N 2.2N 2.5N 2.9N 3.3N 3.7N 4.1N 4.6N 5.1N 5.6N 6.2N 6.7N 7.3N 8.0N 8.6N 9.3N 10.0N 10.7N 11.5N 12.3N 13 .1N 13.9N 14.7N 15.6N 16.5N 17.4N 18.4N 19.4N 20.4N 21.1N 21. 8N 22.5N 23.3N 24.0N 24.8N 25.8N 7.0E 7.8E 8.7E 9.6E 10.6E 11.7E 12.7E 13.9E 15.0E 16.3E 17.5E 18.9E 20.2E 21.7E 23.1E 24.6E 26.2E 27.8E 29.5E 31. 2E 32.9E 34.7E 36.6E 38.5E 39.8E 41.1E 42.5E 43.9E 45.4E 46.9E 48.8E Object we11path O.OE O.OE O.OE O.OE O.OE 0.0 100.0 200.0 250.0 262.5 M.D. T.V.D. 0.0 100.0 200.0 250.0 262.5 275.0 287.5 300.0 312.5 325.0 337.5 350.0 362.5 375.0 387.4 399.9 412.4 424.9 437.4 449.8 462.3 474.8 487.2 499.6 512.1 524.5 537.0 549.3 561. 8 574.2 586.6 599.1 611.5 623.8 636.5 648.9 661.3 673.9 686.3 698.7 711.1 723.5 735.8 748.2 756.4 764.6 772.9 781.1 789.3 797.7 807.6 e CLEARANCE LISTING Page 9 Your ref CLU-8 Ver 2 Last revised : 23-Dec-2003 MWD <9741-10835"CLU-1Rd,Pad #1 Rect Coordinates Horiz Minim Bearing Dist 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 19.9S 20.0S 20.0S 20.1S 20.2S 20.3S 20.4S 20.4S 20.4S 20.3S 20.2S 20.1S 19.9S 19.6S 19.3S 18.9S 18.5S 18.0S 17.6S 17.2S 16.8S 16.3S 15.8S 15.3S 14.6S 110.6E 11 0 . 6E 11 0 . 6E 110.6E 11 0 . 6E 110.6E 11 0 . 6E 11 0 . 6E 110.6E 11 0 . 6E 110.6E 11 0 . 6E 11 0 . 6E 11 0 . 6E 11 0 . 6E 110.6E 11 0 . 6E 110.6E 110.6E 11 0 . 6E 11 0 . 6E 110.6E 110.6E 110.6E 110.6E 11 0 . 6E 110.6E 110.6E 11 0 . 5E 110.5E 11 0 . 5E 110.5E 11 0 . 5E 11 0 . 5E 110.5E 11 0 . 5E 11 O. 5E 11 0 . 5E 110.6E 110.6E 11 0 . 6E 11 O. 7E 11 0 . 8E 111. OE 111. IE 111. 2E 111.4E 111. 5E 111 . 7E 111 . 9E 112.2E 100.2 100.2 100.2 100.2 100.2 100.2 100.3 100.3 100.4 100.5 100.6 100.7 100.9 101.1 101. 2 101. 5 101.7 101. 9 102.2 102.5 102.8 103.1 103.5 103.9 104.3 104.8 105.2 105.8 106.3 106.9 TCyl Dist 112.3 112.3 112.3 112.3 112.3* 112.3 112.3 112.3 112.3 112.3* O.lE 0.2E 0.4E 0.6E 0.9E 275.0 287.5 300.0 312.5 325.0 112.2* 112.1 * 112.0* 111.8* 111.6* 112.3* 112.1 * 112.0* 111. 8* 111.6* 1.2E 1. 5E 2.0E 2.4E 2.9E 337.5 350.0 362.5 375.0 387.4 111. 3* 111.0* 110.6* 110.2* 109.8* 111. 3* 111. 0 * 110.7* 110.3* 109.8* 3.5E 4.1E 4.7E 5.4E 6.2E 399.9 412.4 424.9 437.4 449.8 109.3* 108.7* 108.2* 107.6* 106.9* 109.4* 108.8* 108.3* 107.7* 107.1* 462.3 474.8 487.2 499.6 512.1 524.5 537.0 549.3 561. 8 574.2 586.6 599.1 611. 5 623.9 636.5 648.9 661. 3 673.9 686.3 698.8 711.1 723.5 735.8 748.2 756.4 764.7 772.9 781.2 789.4 797.9 807.7 106.2* 105.5* 104.8* 104.0* 103.1* 106.4* 105.7* 105.0* 104.2* 103.4* 102.3* 101.4* 100.5* 99.5* 98.5* 102.5* 101.7* 100.8* 99.8* 98.9* 107.6 108.3 109.0 109.7 110.5 97.6* 96.5* 95.5* 94.4* 93.3* 97.9* 96.9* 95.8* 94.8* 93.7* 111.2 112.0 112.8 113.6 114.5 92.5* 91. 4 * 90.2* 89.0* 87.7* 92 .1* 91.0* 89.8* 88.5* 87.2* 115.3 116.2 117.0 117.9 118.5 86.4* 85.1* 83.8* 82.5* 81.6* 86.0* 84.7* 83.3* 82.0* 81.1* 119.1 119.7 120.4 121. 0 121. 7 80.7* 79.8* 78.9* 77.9* 77 .0* 80.2* 79.3* 78.4* 77 .4* 76.4* 122.5 75.2* 75.8* All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level). Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad #1,CLU-8 Cannery Loop Unit, Cook Inlet, Alaska M.D. T.V.D. Reference wellpath Rect Coordinates 820.0 830.0 840.0 850.0 860.0 816.1 825.8 835.5 845.3 855.0 870.0 880.0 890.0 900.0 910.0 864.6 874.3 883.9 893.6 903.2 920.0 930.0 940.0 950.0 960.0 912.7 922.3 931.8 941.4 950.9 970.0 980.0 990.0 1000.0 1010.0 960.3 969.8 979.2 988.6 998.0 1020.0 1030.0 1040.0 1050.0 1060.0 1007.4 1016.7 1026.0 1035.3 1044.6 1070.0 1080.0 1090.0 1100.0 1110.0 1053.8 1063.0 1071.2 1081.3 1090.5 1120.0 1130.0 1140.0 1150.0 1160.0 1099.6 1108.6 1117.6 1126.7 1135. 6 11 70.0 1180.0 1190.0 1200.0 1210.0 1144.6 1153.5 1162.4 1171.2 1180.0 1220.0 1230.0 1240.0 1250.0 1260.0 1188.8 1197.5 1206.3 1214.9 1223.6 1270.0 1280.0 1290.0 1300.0 1310.0 1232.2 1240.8 1249.3 1257.8 1266.2 1320.0 1274.7 26.9N 27.9N 29. ON 30.1N 31. 3N 32.4N 33.6N 34.9N 36.2N 37.5N 38.8N 40.2N 41.6N 43.0N 44.5N 46.0N 47.5N 49.0N 50.6N 52.2N 53.9N 55.6N 57.3N 59. ON 60.8N 62.6N 64.4N 66.3N 68.2N 70.1N n. ON 74.0N 76.0N 78.1N 80.1N 82.2N 84.3N 86.5N 88.7N 90.9N 93.1N 95.4N 97.7N 100.0N 102.4N 104.8N 107.2N 109.6N 112.1N 114.6N 11 7 . IN 101.7E 104.9E 108.1E 111.4E 114.7E 118. IE 121. 6E 125.1E 128.7E 132.3E 13 6. OE 13 9. 7E 143.5E 147.3E 151. 2E 155.2E 159.2E 163.3E 167.4E 171 . 6E 175.8E 180.1E 184.4E 188.8E 193.2E 197.7E 202.3E 206.9E 211.6E 216.3E 221.0E Object wellpath 50.7E 52.7E 54.7E 56.8E 59.0E 61.2E 63.5E 65.9E 68.3E 70.7E 73.3E 75.8E 78.5E 81. 2E 83.9E 86.8E 89.6E 92.6E 95.6E 98.6E 966.6 976.4 986.1 995.9 1005.9 M.D. T.V.D. 817.6 827.9 837.7 848.0 857.9 817.4 827.6 837.4 847.7 857.5 e CLEARANCE LI8TING Page 10 Your ref CLU-8 Ver 2 Last revised : 23-Dec-2003 MWD <9741-10835"CLU-IRd,Pad #1 Rect Coordinates 13.98 13 .08 12.18 11.08 9.98 8.78 7.48 6.18 4.78 3.28 1. 78 0.28 1. 4N 3.0N 4.6N 6.3N 7.9N 9.6N l1.4N 13 .2N 15.0N 16.8N 18.7N 20.6N 22.4N 24.4N 26.3N 28.3N 30.2N 32.3N 34.2N 36.3N 38.4N 40.4N 42.5N 44.6N 46.8N 48.9N 51. ON 53.3N 55.4N 57.6N 59.9N 62.2N 64.4N 66.7N 69.0N 71. 3N 73.6N 75.9N 78.3N 112.5E 112.8E 113. IE 113.5E 113.9E 114.3E 114.8E 115.3E 115.8E 116 . 3E 116.9E 11 7. 4E 118. IE 118.7E 119.4E 120.1E 120.8E 121.6E l22.4E 123.2E 124.0E 124.8E 125.7E 126.5E 127.3E 128.1E 128.9E 129.8E 130.6E 131. 4E 132.2E 133.0E 133.8E 134.6E 135.4E 13 6. 2E 137.0E 13 7. 8E 13 8. 6E 13 9. 4E 140.2E 141.0E 141.7E 14 2. 5E 143.3E 144.0E 144.8E 145.6E 146.3E 14 7. OE 14 7. 8E Horiz Min'm Bearing Dist 123.4 124.2 125.1 126.0 126.9 127.8 128.7 129.7 130.7 131. 8 132.9 134.1 135.4 136.9 138.4 140.0 141.7 143.6 145.6 147.8 150.2 152.8 155.5 158.6 161. 9 165.3 169.1 173.0 177.1 181. 3 185.7 190.0 194.4 198.6 202.8 206.7 210.5 214.1 217.4 220.5 223.4 226.0 228.4 230.7 232.8 234.6 236.4 238.0 239.5 240.8 242.1 TCyl Dist 74.0* 71.7* 71.4* 70.1* 68.7* 74.6* 73.3* 71.0* 70.7* 69.4* 1015.6 1025.3 1035.3 1045.0 1054.7 1064.7 1074.3 1083.9 1093.6 1103.5 1113.1 1122.6 1132.5 1142.0 1151. 5 1161.0 1170.8 1180.2 1189.6 1199.3 1208.7 1218.1 1227.4 1237.0 1246.3 1255.6 1265.1 1274.3 1283.5 1292.7 1302.0 867.7 878.0 887.9 897.9 907.7 867.2 877.5 887.2 897.1 906.8 67.2* 65.8* 64.3* 62.7* 61.2* 68.0* 66.5* 65.0* 63.5* 62.0* 917.5 927.3 937.2 947.0 956.7 916.5 926.1 935.8 945.5 955.1 59.6* 58.1* 56.6* 55.0* 53.5* 60.4* 58.8* 57.2* 55.7* 54.1* 964.8 974.4 984.0 993.5 1003.3 1012.8 1022.4 1032.2 1041.6 1051.1 1060.8 1070.3 1079.6 1089.0 1098.7 1108.0 1117.3 1126.9 1136.2 1145.4 1154 . 7 1164.2 1173.3 1182.5 1191. 9 1201.0 1210.0 1219.1 1228.4 1237.3 1246.3 1255.5 1264.4 1273.3 1282.1 1291.1 52.0* 50.6* 49.2* 47.8* 46.4* 52.6* 51.1* 49.7* 48.2* 46.9* 45.2* 43.9* 42.8* 41.8* 40.9* 45.5* 44.3* 43.1* 42.0* 41.0* 40.1* 39.5* 39.0* 38.8* 38.7* 40.2* 39.5* 39.0* 38.8* 38.7* 38.9 39.3 40.0 40.8 42.0 38.9 39.4 40.1 41.1 42.3 43.3 44.9 46.7 48.7 50.9 43.8 45.6 47.6 49.9 52.3 53.2 55.8 58.5 61.3 64.3 55.0 57.9 60.9 64.2 67.6 67.3 70.6 73.9 77 .3 80.9 71.1 74.8 78.7 82.7 86.8 84.5 91.1 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level). Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company CLEARANCE LISTING Page 11 Pad #1, CLU-8 Your ref CLU-8 Ver 2 Cannery Loop Unit, Cook Inlet, Alaska Last revised : 23-Dec-2003 Reference wellpath Object wellpath MWD <9741-10835"CLU-IRd,Pad #1 Horiz MinIm TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 1330.0 1283.1 119 . 7N 225.8E 1311.2 1299.9 80.7N 148.5E 243.3 88.2 95.5 1340.0 1291. 4 122.2N 230.7E 1320.2 1308.6 83.0N 149.2E 244.3 92.1 100.0 1350.0 12 99.7 124.8N 235.6E 1329.3 1317.4 85.4N 149.9E 245.3 96.0 104.7 13 60.0 1308.0 127 . 5N 240.6E 1338.5 1326.2 87.9N 150.6E 246.2 100.0 109.5 1370.0 1316.2 130.1N 245.6E 1347.5 1334.8 90.3N 151.3E 247.1 104.1 114.5 1380.0 1324.4 132.8N 250.7E 1356.5 1343.4 92.7N 152.0E 247.9 108.2 119.5 1390.0 1332.6 135.5N 255.8E 13 65.5 1352.1 95.2N 152.7E 248.6 112.5 124.7 1400.0 1340.7 138.3N 261.0E 1374.4 1360.7 97.6N 153.3E 249.3 116.8 130.0 1410.0 1348.7 141.0N 266.2E 1383.3 1369.2 100.lN 154.0E 249.9 121.2 135.5 1420.0 1356.8 143.8N 271 . 4E 13 92.2 1377.6 102.5N 154.6E 250.5 125.7 141.0 1430.0 1364.8 146.6N 27 6. 8E 1401.1 1386.2 105.1N 155.3E 251.1 130.2 146.7 1440.0 1372.7 149.5N 282.1E 1409.9 1394.6 107.5N 155.9E 251. 6 134.8 152.5 1450.0 1380.6 152.3N 287.5E 1418.7 1403.0 110. ON 156.5E 252.1 139.5 158.4 1460.0 1388.5 155.2N 293.0E 1427.4 1411.3 112.6N 157.1E 252.6 144.3 164.5 1470.0 1396.3 158.2N 298.5E 1436.3 1419.8 115.1N 157.7E 253.0 149.1 170.7 1480.0 1404.0 161. IN 304.1E 1444.9 1428.1 11 7. 7N 158.4E 253.4 154.0 177.0 1490.0 1411.8 164.1N 309.7E 1453.6 1436.3 120.2N 159.0E 253.8 158.9 183.4 1500.0 1419.5 167.1N 315.4E 14 62.2 1444.5 122.7N 159.5E 254.1 163.9 189.9 1510.0 1427 .1 170.1N 321. IE 1470.9 1452.8 125.4N 160.1E 254.5 169.0 196 .5 1520.0 1434.7 173.1N 326.8E 1479.4 14 60.9 127.9N 160.7E 254.8 174.1 203.3 1530.0 1442.2 176.2N 332.6E 1487.9 1469.0 130.5N 161. 3E 255.1 179.3 210.2 1540.0 1449.7 179.3N 338.4E 1496.7 1477.4 133.2N 161. 9E 255.4 184.6 217.1 1550.0 1457.2 182.4N 344.3E 1505.1 1485.4 135.7N 162.5E 255.6 189.9 223.9 1560.0 1464.6 185.6N 350.3E 1513.5 14 93.3 138.4N 163.0E 255.8 195.2 230.7 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company CLEARANCE LISTING Page 12 Pad #1, CLU-8 Your ref CLU-8 Ver 2 Cannery Loop Unit, Cook Inlet, Alaska Last revised : 23-Dec-2003 Reference wellpath Object wellpath PMSS <0 - 8320>"CLU-6,Pad #1 Horiz Minim TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 0.0 0.0 O.ON O.OE 0.7 0.2 94.2S 21. 5E 167.1 96.6 96.6 100.0 100.0 O.ON O.OE 101. 2 100.7 93.8S 21.6E 167.0 96 .3* 96.3* 200.0 200.0 O.ON O.OE 201. 8 201. 3 92.6S 21.7E 166.8 95.2* 95.2* 250.0 250.0 O.ON O.OE 251. 6 251.1 91. 9S 21.9E 166.6 94.5* 94.5* 262.5 262.5 O.ON O.OE 264.1 263.6 91.8S 21.9E 166.6 94.4* 94.4* 275.0 275.0 O.lN O.lE 276.6 276.1 91. 6S 22.0E 166.6 94.3* 94.3* 287.5 287.5 O.lN 0.2E 289.1 288.6 91. 5S 22.0E 166.6 94.1* 94.1* 300.0 300.0 0.2N 0.4E 301. 6 301.1 91. 3S 22.1E 166.7 94.1* 94.1* 312.5 312.5 0.3N 0.6E 314.2 313.7 91.25 22.1E 166.8 94.0* 94.0* 325.0 325.0 0.5N 0.9E 326.7 326.2 91.05 22.2E 166.9 93.9* 93.9* 337.5 337.5 0.6N 1.2E 339.2 338.6 90.85 22.3E 167.0 93.8* 93.8* 350.0 350.0 0.8N loSE 352.0 351. 5 90.65 22.4E 167.2 93.8* 93.8* 362.5 362.5 1. ON 2.0E 364.5 364.0 90.4S 22.5E 167.4 93.7* 93.7* 375.0 375.0 1.3N 2.4E 377 .0 376.5 90.2S 22.6E 167.6 93.6* 93.7* 387.5 387.4 1. 5N 2.9E 389.5 389.0 89.95 22.7E 167.8 93.6* 93.6* 400.0 399.9 1. 8N 3.5E 402.5 401.9 89.6S 22.8E 168.1 93.5* 93.5* 412.5 412.4 2.2N 4.1E 414.9 414.4 89.45 23.0E 168.3 93.5* 93.5* 425.0 424.9 2.5N 4.7E 427.4 426.9 89.0S 23.1E 168.6 93.4* 93.4* 437.5 437.4 2.9N 5.4E 440.5 439.9 88.7S 23.3E 168.9 93.3* 93.3* 450.0 449.8 3.3N 6.2E 453.0 452.4 88.3S 23.5E 169.3 93.2* 93.2* 462.5 462.3 3.7N 7.0E 465.9 465.3 87.8S 23.7E 169.6 93.1* 93.1* 475.0 474.8 4.1N 7.8E 478.4 477.8 87.4S 24.0E 170.0 93.0* 93.0* 487.5 487.2 4.6N 8.7E 490.9 490.3 86.95 24.3E 170.3 92.9* 92.9* 500.0 499.7 5.1N 9.6E 503.7 503.1 86.4S 24.6E 170.7 92 .8* 92.8* 512.5 512.1 5.6N 10.6E 516.2 515.6 85.9S 25.0E 171. 0 92.7* 92.7* 525.0 524.6 6.2N 11.7E 528.9 528.2 85.3S 25.5E 171.4 92.6* 92.6* 537.5 537.0 6.7N 12.7E 541. 4 540.7 84.7S 26.0E 171. 7 92.5* 92 .5* 550.0 549.5 7.3N 13.9E 554.0 553.3 84.15 26.7E 172.0 92 .4* 92.4* 562.5 561.9 8.0N 15.0E 566.5 565.8 83.55 27.4E 172.3 92 .4* 92.4* 575.0 574.3 8.6N 16.3E 579.0 578.3 82.9S 28.2E 172.6 92 .3* 92 .3* 587.5 586.7 9.3N 17.5E 592.1 591.3 82.25 29.1E 172.8 92.3* 92 .3* 600.0 599.1 10.0N 18.9E 604.6 603.7 81.4S 30.1E 173.0 92.2* 92.2* 612.5 611.5 10.7N 20.2E 618.1 617 .1 80.5S 31. 2E 173.1 92.1* 92 .1* 625.0 623.9 11.5N 21.7E 631.6 630.5 79.55 32.5E 173.2 91.9* 91.9* 637.5 636.3 12.3N 23.1E 644.1 642.9 78.5S 33.7E 173.4 91.6* 91.6* 650.0 648.7 13 .1N 24.6E 657.6 656.3 77 .35 35.1E 173.4 91. 3* 91.3* 662.5 661.1 13.9N 26.2E 670.1 668.7 76.1S 36.5E 173.4 90.9* 90.9* 675.0 673.4 14.7N 27.8E 683.5 681.9 74.7S 38.2E 173.4 90.4* 90.5* 687.5 685.8 15.6N 29.5E 696.8 695.0 73.35 39.9E 173.3 89.9* 90.0* 700.0 698.2 16.5N 31. 2E 709.2 707.2 71.85 41. 6E 173.2 89.4* 89.5* 712.5 710.5 17.4N 32.9E 722.5 720.2 70.25 43.6E 173.0 88.8* 88.9* 725.0 722.8 18.4N 34.7E 735.4 732.9 68.5S 45.7E 172.8 88.2* 88.3* 737.5 735.2 19.4N 36.6E 747.9 745.1 66.8S 47.7E 172.6 87.5* 87.6* 750.0 747.5 20.4N 38.5E 760.4 757.3 65.25 49.8E 172 .5 86.8* 86.9* 758.3 755.7 21.1N 39.8E 768.8 765.5 64.05 51. 2E 172.3 86.4* 86.5* 766.7 763.9 21. 8N 41.1E 777.2 773.7 62.9S 52.6E 172.2 86.0* 86.1* 775.0 772.0 22.5N 42.5E 785.5 781.8 61.75 54.0E 172 .2 85.6* 85.7* 783.3 780.2 23.3N 43.9E 793.8 789.9 60.6S 55.5E 172 .1 85.2* 85.3* 791. 7 788.4 24.0N 45.4E 802.1 798.0 59.5S 56.9E 172.1 84.9* 84.9* 800.0 796.5 24.8N 46.9E 810.5 806.1 58.35 58.4E 172 .1 84.5* 84.6* 810.0 806.3 25.8N 48.8E 820.3 815.7 57.0S 60.2E 172.1 84.1* 84.2* All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Total Dogleg for wel1path is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company CLEARANCE LI8TING Page 13 Pad #1,CLU-8 Your ref CLU-8 Ver 2 Cannery Loop Unit, Cook Inlet, Alaska Last revised : 23-Dec-2003 Reference wellpath Object we11path PM88 <0 - 8320>"CLU-6,Pad #1 Horiz Minim TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 820.0 816.1 26.9N 50.7E 830.4 825.5 55.68 62.1E 172 .1 83.8* 83.8* 830.0 825.8 27.9N 52.7E 840.4 835.2 54.28 64.0E 172 .2 83.5* 83.5* 840.0 835.5 29. ON 54.7E 850.4 844.9 52.98 65.9E 172.2 83.1* 83.2* 850.0 845.3 30.1N 56.8E 860.6 854.9 51.48 68.0E 172.2 82.9* 82.9* 860.0 855.0 31. 3N 59.0E 870.6 864.6 50.08 70.0E 172.3 82.6* 82.6* 870.0 864.6 32.4N 61. 2E 880.6 874.2 48.68 72 .1E 172 .3 82.3* 82.3* 880.0 874.3 33.6N 63.5E 890.8 884.1 47.18 74.3E 172.4 82.1* 82.1* 890.0 883.9 34.9N 65.9E 900.8 893.8 45.68 76.5E 172.4 81.8* 81.9* 900.0 893.6 36.2N 68.3E 910.8 903.4 44.28 78.8E 172.5 81.6* 81.6* 910.0 903.2 37.5N 70.7E 921.2 913 .3 42.68 81.2E 172.6 81.4* 81.4* 920.0 912.7 38.8N 73.3E 931. 2 922.9 41.18 83.5E 172.7 81.2* 81. 2* 930.0 922.3 40.2N 75.8E 941. 2 932.5 39.68 85.9E 172.8 81.0* 81.1 * 940.0 931. 8 41.6N 78.5E 951.6 942.5 38.08 88.4E 172.9 80.9* 80.9* 950.0 941.4 43.0N 81. 2E 961.6 952.1 36.48 90.8E 173.1 80.7* 80.7* 960.0 950.9 44.5N 83.9E 971.6 961. 6 34.88 93.2E 173.3 80.6* 80.6* 970.0 960.3 46. ON 86.8E 982.0 971.6 33.28 95.8E 173.5 80.4* 80.4* 980.0 969.8 47.5N 89.6E 992.0 981.1 31. 58 98.3E 173.7 80.3* 80.3* 990.0 979.2 49.0N 92.6E 1002.0 990.7 29.98 100.8E 174.0 80.2* 80.2* 1000.0 988.6 50.6N 95.6E 1012.0 1000.2 28.28 103.4E 174.3 80.1* 80.1* 1010.0 998.0 52.2N 98.6E 1022.6 1010.3 26.48 106.1E 174.6 80.0* 80.0* 1020.0 1007.4 53.9N 101.7E 1032.5 1019.7 24.78 108.7E 174.9 79.9* 79.9* 1030.0 1016.7 55.6N 104.9E 1043.3 1029.9 22.88 111. 6E 175.1 79.8* 79.8* 1040.0 1026.0 57.3N 108.1E 1053.3 1039.3 21.08 114 . 4E 175.4 79.6* 79.6* 1050.0 1035.3 59.0N 111 . 4E 1064.1 1049.5 19.08 11 7. 4E 175.6 79.5* 79.5* 1060 . 0 1044.6 60.8N 114.7E 1074.0 1058.9 17.08 120.2E 176.0 79.3* 79.3* 1070.0 1053.8 62.6N 118.1E 1084.8 1069.0 14.98 123.3E 176.2 79.1* 79.2* 1080.0 1063.0 64.4N 121.6E 1094.8 1078.3 12.98 126.2E 176.6 79.0* 79.0* 1090.0 1072.2 66.3N 125.1E 1105.6 1088.3 10.78 129.4E 176.8 78.8* 78.8* 1100.0 1081. 3 68.2N 128.7E 1115.6 1097.6 8.68 132.5E 177.2 78.6* 78.6* 1110.0 1090.5 70.1N 132.3E 1125.6 1106.9 6.58 135.5E 177.6 78.4* 78.4* 1120.0 1099.6 72. ON 13 6. OE 1136.4 1116.9 4.28 138.8E 177.8 78.2* 78.2* 1130.0 1108.6 74.0N 139.7E 1146.3 1126.1 2.08 142.0E 178.3 78.0* 78.0* 1140.0 1117.6 76.0N 143.5E 1156.3 1135.3 0.2N 145.1E 178.8 77 .8* 77.8* 1150.0 1126.7 78.1N 14 7. 3E 1167.1 1145.3 2.7N 148.6E 179.1 77.7* 77.7* 1160.0 1135.6 80.1N 151.2E 1177.1 1154.4 5.0N 151. 8E 179.6 77.5* 77 .5* 1170.0 1144.6 82.2N 155.2E 1187.1 1163.6 7.3N 155.0E 180.1 77 .3* 77.3* 1180.0 1153.5 84.3N 159.2E 1197.9 1173.5 9.8N 158.6E 180.5 77.2* 77.2* 1190.0 1162.4 86.5N 163.3E 1207.9 1182.6 12.2N 161. 9E 181.1 77 .0* 77 .0* 1200.0 1171.2 88.7N 167.4E 1217.8 1191.6 14.6N 165.2E 181.7 76.9* 76.9* 1210.0 1180.0 90.9N 171. 6E 1228.6 1201.4 17.3N 168.9E 182.1 76.7* 76.7* 1220.0 1188.8 93.1N 175.8E 1238.6 1210.5 19.7N 172 . 2E 182.8 76.6* 76.6* 1230.0 1197.5 95.4N 180.1E 1248.5 1219.5 22.2N 175.7E 183.5 76.5* 76.5* 1240.0 1206.3 97.7N 184.4E 1259.3 1229.2 25.0N 179.4E 184.0 76.4* 76.4* 1250.0 1214.9 100.0N 188.8E 1269.2 1238.2 27 .5N 182.8E 184.7 76.4* 76.4* 1260.0 1223.6 102.4N 193.2E 1279.1 1247.1 30.1N 186.3E 185.5 76.3* 76.3* 1270.0 1232.2 104.8N 197.7E 1289.9 1256.8 32.9N 190.1E 186.1 76.3* 76.3* 1280.0 1240.8 107.2N 202.3E 1299.8 1265.7 35.6N 193.6E 187.0 76.3 76.3 1290.0 1249.3 109.6N 206.9E 1309.8 1274.6 38.3N 197.1E 187.8 76.3 76.3 1300.0 1257.8 112.1N 211. 6E 1320.5 1284.2 41. 2N 201. OE 188.5 76.4 76.4 1310.0 1266.2 114.6N 216.3E 1330.4 1293.0 43.9N 204.5E 189.4 76.5 76.5 1320.0 1274.7 11 7 . IN 221.0E 1340.4 1301.8 46.7N 208.1E 190.4 76.6 76.6 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1 ) (42.00 Ft above mean sea level) . Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad #1,CLU-8 Cannery Loop Unit, Cook Inlet, Alaska M.D. T.V.D. Reference wellpath Rect Coordinates 1330.0 1340.0 1350.0 1360.0 1370.0 1283.1 1291 . 4 1299.7 1308.0 1316.2 1380.0 1390.0 1400.0 1410.0 1420.0 1324.4 1332.6 1340.7 1348.7 1356.8 1430.0 1440.0 1450.0 14 60.0 1470.0 13 64 . 8 1372.7 1380.6 1388.5 1396.3 1480.0 14 90.0 1500.0 1510.0 1520.0 1404.0 1411. 8 1419.5 1427.1 1434.7 1530.0 1540.0 1550.0 1560.0 1570.0 1442.2 1449.7 1457.2 1464.6 1472.0 1580.0 1590.0 1600.0 1610.0 1620.0 14 79.3 1486.5 1493.8 1500.9 1508.0 1630.0 1640.0 1650.0 1660.0 1670.0 1515.1 1522.1 1529.1 1536.0 1542.9 1680.0 1690.0 1700.0 1708.8 1717.6 1549.7 1556.5 1563.2 1569.1 1574.9 1726.4 1735.2 17 44.0 1752.8 1800.0 1580.7 1586.4 1592 .1 1597.8 1628.1 1900.0 2000.0 2100.0 2200.0 2300.0 1692.2 1756.3 1820.5 1884.6 1948.7 2400.0 2012.9 119.7N 122 . 2N 124.8N 127.5N 130.1N 132.8N 135.5N 138.3N 141. ON 143.8N 146.6N 149.5N 152.3N 155.2N 158.2N 161.1N 164 . IN 167.1N 170.1N 173.1N 17 6. 2N 179.3N 182.4N 185.6N 188.7N 191. 9N 195.2N 198.4N 201.7N 204.9N 208.3N 211. 6N 214.9N 218.3N 221.7N 225.2N 228.6N 232.1N 235.1N 238.2N 241. 3N 244.4N 247.6N 250.7N 267.7N 303.6N 339.5N 375.5N 411.4N 447.3N 483.2N 225.8E 230.7E 235.6E 240.6E 245.6E 250.7E 255.8E 261. OE 266.2E 271.4E 276.8E 282.1E 287.5E 293.0E 298.5E 304.1E 309.7E 315.4E 321. IE 326.8E 332.6E 338.4E 344.3E 350.3E 356.3E 362.3E 368.4E 374.5E 380.6E 386.8E 393.1E 399.4E 405.7E 412.1E 418.5E 425.0E 431. 5E 438.0E 443.8E 449.6E 455.5E 461.4E 467.3E 473.2E 505.3E 573.1E 640.9E 708.7E 77 6. 5E 844.3E 912.1E Object wellpath 1351.1 1361.0 1370.9 1381.7 1391.6 1401. 5 1412.4 1422.3 1432.2 1443.1 1453.0 1464.1 1473.9 1483.8 14 94.9 1504.8 1514.7 1525.8 1535.7 1547.0 1556.9 1566.8 1578.4 1588.3 1598.2 1609.9 1619.8 1631. 5 1641.4 1651. 3 1663.0 1672.9 1684.6 1694.5 1706.3 1716.2 1727.9 1737.8 17 48.2 1756.9 1765.6 1776.0 1784.8 1795.3 1845.6 1948.6 2053.9 2161.1 2263.6 2363 . 2 2460.7 M.D. T.V.D. 1311.4 1320.2 1328.9 1338.4 1347.2 1355.9 13 65.4 1374.0 1382.6 1392.1 1400.7 1410.2 1418.6 1427.1 1436.5 1444.9 14 53.2 1462.6 1470.8 1480.3 1488.5 1496.6 1506.2 1514.2 1522.3 1531.7 1539.6 1549.0 1556.9 1564.7 1573.9 1581. 6 1590.6 1598.2 1607.1 1614.5 1623.2 1630.5 1638.2 1644.5 1650.9 1658.4 1664.6 1672.1 1707.1 1776.1 1843.5 1906.1 1960.8 2011.0 2059.5 e CLEARANCE LISTING Page 14 Your ref CLU-8 Ver 2 Last revised : 23-Dec-2003 PMSS <0 - 8320>"CLU-6,Pad #1 Rect Coordinates 49.7N 52.5N 55.3N 58.4N 61. 3N 64.2N 67.4N 70.4N 73.4N 76.7N 79.8N 83.2N 86.3N 89.4N 93.0N 96.2N 99.4N 103.0N 106.3N 110.1N 113.4N 116.8N 120.8N 124.3N 127.7N 131.9N 135.5N 139.8N 143.4N 147.1N 151.5N 155.2N 159.7N 163.5N 168.1N 172 . ON 176.6N 180.6N 184.7N 188.2N 191. 7N 195.9N 199.5N 203.8N 224.5N 268.9N 316.6N 369.0N 421. 5N 472 . 9N 523.3N 212.1E 215.7E 219.4E 223.4E 227.1E 230.9E 235.0E 238.8E 242.6E 247.0E 250.9E 255.3E 259.4E 263.5E 268.1E 272.3E 276.5E 281. 3E 285.6E 290.6E 295.0E 299.5E 304.8E 309.3E 313.9E 319.4E 324.1E 329.7E 334.5E 339.3E 345.1E 350.1E 356.0E 361. IE 367.3E 372 . 5E 378.8E 384.2E 389.9E 394.8E 399.6E 405.5E 41 0 . 5E 416.5E 446.0E 508.3E 573.7E 643.1E 712.0E 781. OE 848.9E Horiz Bearing 191.1 192.1 193.1 194.0 195.0 196.1 197.0 198.1 199.2 200.0 201.1 202.0 203.1 204.2 205.0 206.1 207.2 208.0 209.1 209.9 210.9 212.0 212.7 213.7 214.8 215.5 216.6 217.4 218.4 219.4 220.2 221.2 222.0 222.9 223.7 224.6 225.4 226.2 226.9 227.7 228.4 229.0 229.8 230.4 234.0 241. 8 251.2 264.4 278.9 292.0 302.4 Minim Dist TCyl Dist 76.7 76.9 77.1 77.4 77.7 76.8 76.9 77 .2 77 .4 77.7 78.0 78 .4 78.8 79.2 79.7 78.1 78.4 78.9 79.3 79.8 80.2 80.7 81. 2 81.8 82.4 80.3 80.8 81. 4 82.0 82.6 83.0 83.7 84.4 85.1 85.8 83.2 83.9 84.6 85.3 86.0 86.6 87.3 88.1 88.9 89.7 86.8 87.6 88.4 89.2 90.0 90.5 91. 3 92 .2 93.0 93.9 90.8 91. 6 92.5 93.3 94.2 94.7 95.6 96.4 97.3 98.1 95.1 95.9 96.7 97.6 98.4 98.9 99.6 100.4 101.1 101.8 99.1 99.9 100.7 101.4 102.1 102.5 103.2 103.9 104.7 107.8 102.8 103.5 104.3 105.0 108.0 111.5 112.4 108.1* 100.3* 92.4* 111. 6 112.4 108.3* 100.6* 92.6* 88.1* 88.1* All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company CLEARANCE LISTING Page 15 Pad U, CLU-8 Your ref CLU-8 Ver 2 Cannery Loop Unit, Cook Inlet, Alaska Last revised : 23-Dec-2003 Reference wellpath Object wellpath PMSS <0 - 8320>"CLU-6,Pad #1 Horiz MinIm TCyl M.D. T.V.D. Reet Coordinates M.D. T.V.D. Reet Coordinates Bearing Dist Dist 2500.0 2077.0 519.1N 979.9E 2558.2 2108.5 573.4N 916.7E 310.7 89.0 89.1 2600.0 2141.1 555.1N 1047.7E 2655.2 2157.2 623.7N 983.9E 317.1 95.0 95.4 2700.0 2205.3 591. ON 1115.5E 2752.8 2205.5 675.4N 1051. 2E 322.7 106.1 106.9 2800.0 2269.4 626.9N 1183.3E 2850.0 2253.4 72 6. 5N 1118.5E 327.0 119.8 121.3 2900.0 2333.5 662.8N 1251.1E 2947.0 2301.0 778. ON 1185.5E 330.4 136.5 138.7 3000.0 2397.6 698.7N 1318.9E 3046.7 2350.9 830.2N 1254.2E 333.8 153.8 156.1 3100.0 2461. 8 734.7N 1386.7E 3143.4 2399.8 880.6N 1320.7E 335.7 171.8 175.0 3200.0 2525.9 770.6N 1454.5E 3238.2 2448.0 931.1N 1384.8E 336.5 191. 5 195.9 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from CLU-8 and TVD from RKB (Glacier 1) (42.00 Ft above mean sea level) . Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 62.09 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ II.~ÞI" I CLU-8 JIll [5593] CLU-8 Ver 2 I iIIIIIII we 11 head M.D. [f] Inc. Dir. TVD [f] N/S [f] E/W [f] Polar crd.[f] Curv. _IIIJ ... _ _ __ _____________ _____ 0.00 62.085 250.00 N 0.00 E 0.00 _____________ 750.00 DIIII 62.085 747.47 N 20.38 E 38.46 _____________ 1752.77 50.11 62.085 1597.79 N 250.73 E 473.24 _____________ 5658.19 50.11 62.085 4102.35 N 1653.60 E 3121.15 _____________ 7663.74. 62.085 ~uu ~'I~ ~ _____________ 8163.74 62.085 6300.47 N 2134.68 E 4029.18 _____________ 9734.27 0.00 62.085 1fiþII.... N 2134.68 E 4029.18 _____________ liþlWJBiDOI"'=!.íI1:m.0M8DJ'- Vrt Ref: RKB (Glacier 1) Hrz Ref: CLU-8 North on true Units : feet Tf DLS I 100 Ft ~prt'n- T4 'e of ~tation 0.00 Tie 0.00 EoIH/EoDH 43.52 KOP/EoB/EoDH 535.56 EoB/EoDH 3532.14 EoIH/EoDH 4516.21 EoD/EoDH/Target 4559.73 EoD/EoDH 4559.73 EoIH/EoDH e -------- ----- ------- -------- ---------- ---------- ------------- ----- ---- -------- --------------------- -------- ----- ------- -------- ---------- ---------- ------------- ----- ---- -------- --------------------- -------- ----- ------- -------- ---------- ---------- ------------- ----- ---- -------- --------------------- -------- ----- ------- -------- ---------- ---------- ------------- ----- ---- -------- --------------------- -------- ----- ------- -------- ---------- ---------- ------------- ----- ---- -------- --------------------- liDR Plan Options ill Delete field jig Insert station iDI Delete station I __n;¡ic;¡¡C¡iI~ T.V.D : Polar: 4559.73 62.09 Direction: 62.09 N/S coordinate: N 2134.68 Latitude: n60 32 17.213 N/S coord: N 0.00 E/W coordinate: E 4029.18 Longitude: w151 14 27.15 E/W coord: E 0.00 ~ Difflension #1 : --~L~ <- Rotation froffl North : ______ Shape : Difflension #2 : ________ Thickness: ________ Tgt offset froffl wellpath? : Yes c i r'c 1 e e e ~ ~- ~IFE .--.. Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. INTEGRATED FL I 5 ENGINEERING ROJECT PLAN ~ . ~)IFE œu:J Prepared For: MARATHON OIL COMPANY Well Cannery Loop Unit #8 Kenai Peninsula, Alaska Prepared by: Tony Tykalsky Reviewed by: Hal Martins Presented to: Will Tank Revised December 29th, 2003 ~IFE~ e e ~ ---. "' IFE < ~ - Marathon Oil Company Well Name: Cannery Loop Unit #8 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 Cannery Loop #8 Well to be drilled next year. The following is a brief synopsis of the program. Overview: CLU #8 is a development well targeting the Beluga and Tyonek formations at the Cannery Loop Field. Flo-Pro fluid will be used for the intermediate and production intervals. After logging the production interval, the well will be completed with 3 W' excape liner cemented in place. Surface Interval: The surface interval will be drilled with the standard GellGelex spud mud. Based on offset well data, no problems are anticipated during this interval. Intermediate Interval: This interval will be drilled with a Flo-Pro fluid. After drilling out the surface cement, the well will be displaced to a standard 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: Differential sticking may have occurred in CLU #6 with a 9.85 PPG mud weight. Production Interval: This interval will be drilled with the modified Flo- Pro fluid. After drilling out the intermediate cement and 20 - 25 feet of new hole, the well will be displaced to a modified Flo-Pro KCl fluid. Fluid loss should be maintained @ < 6 cc's API for this interval. Completion: This program assumes the well will be completed with 6% KCl brine. Tony Tykalsky Project Engineer M-I Drilling Fluids Reference Wells: CLU #6, CLU #1 RD NOTE: This pr02;ram is provided as a 2;uide only. Well conditions will always dictate fluid properties required. P!119IFE ~ ....... -v 'IFE ~ ~ - ~ ~ IIIFE e e Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. EXECUTIVE SUMMARY Our overall goal is no M-I/Swaco HSE incidents while providing fluids and solids control services to our customer. Our goal for CLU #8 is to remove drill solids from the mud system at a cost of less than $0.23 per pound. This has been the average for the last three years of centrifuge van operations With the revised fluid formulation (increasing the fluid agent concentration and maintaining a lower fluid loss), we expect to minimize formation damage and hole enlargement in the production interval as demonstrated on KBU 43-7X. Use of the MI Swaco centrifuge van for the last three years has provided an estimated savings in dilution and disposal costs to Marathon Oil of over $500,000. With continued usage of our equipment, we expect to provide more savings to you during future operations. ~ ~IFE ~ e e Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Interval Benchmarks and Targets Drilling Intervals Depth Interval (ft) Benchmark 1 Benchmark 2 Benchmark 3 Benchmark Fluid cost per foot Volume Usage Solids Removal 0-1800' > $6.17 ft < 1743 bbls 1800 - 6970' > $43.22 ft < 3638 bbls 6970 - 9734' > $32.66 ft < 1584 bbls Total Project Targets for Drilling Interval Avg. < $33.37 Max. < 6965 bbls < $0.23 Ib No Spills ITom Centrifuge Van Operation . rnJI;lFE ~ e - Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Project Summary Casing Hole Casing Depth TVD Mud Mud Sum Interval Size Size Program System Weight Days Mud Cost (in) (in) (ft) (ft) Solids Control (ppgy/ , 13 3/8" 16" 1800' 1628' Gel/Gelex Spud 8.6~/ 5 $14,480 Mud Screens 150/180 mesh Desilter Centrifuge Van /) 95/8" 12-114" 6970' 5141' Flo-Pro 9.00/ 10 $230,201 wlSafeCarb Screens 180 - 210 mesh Desilter Centrifuge Van 3-1/2" 8-1/2" 9734' 7871' Flo-Pro 9.0f} 7 $94,636 w/SafeCarb Screens 230 - 210 mesh Desilter Centrifuge Van 3 1/2" 8-1/2" Completion 9664' 7871' 6% KCl 8.55 2 $8,616 ~ 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 does not include any considerations for whole mud losses. ~ Cost includes 1 % Lubetex concentration for intermediate and production interval. r:JIPlFE ~ e e ~IÆ Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Product Usage Summary M-I Bar 0 189 238 0 427 1.6 M-I Gel 342 0 0 0 342 1.4 Gelex 19 0 0 0 19 0.1 Soda Ash 11 19 8 0 38 0.2 Caustic Soda 15 38 16 0 69 0.5 Congor 404 0 9 5 0 14 4.8 SafeScav NA 3 9 4 0 16 1.8 Bicarb 15 19 16 0 50 0.3 Congor 303 0 0 0 6 6 .9 FloVis 0 339 127 3 469 27.3 Desco CF 10 0 0 0 10 .5 DualFlo 0 0 158 0 158 3.8 Polypac UL 12 151 0 0 163 735 Greencide 25G 0 0 2 0 2 1 Bioban BP Plus 0 302 127 0 429 2.8 KCl 0 1584 665 273 2522 9.4 Safecarb 0 1509 634 0 2134 11.1 SafeKleen 0 1 1 1 3 .4 Lubetex 0 43 18 0 61 13.2 Defoam X 0 42 18 0 60 1.6 Klagard 0 33 0 0 33 6.8 Engineer Service 5 10 7 2 24 ~ ~IFE œm e e - ~IFE ----- Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Offset Well Information Well Hole Size Depth PPG PV YP FL Comments CLU #6 8.5 1847 9.1 12 18 10 Spud in, drill ahead 2983 9.5 15 25 10.4 Drilg to T.D., trip & run casing (top job required) 6.125 3747 8.75 8 16 8 Drill ahead 5227 8.95 9 26 7.2 Drlg to 5069, short trip 6083 9 11 24 7 Drlg ahead 7044 9.2 11 30 6.4 Drlg ahed, gels climbing 8320 9.4 12 27 7.6 Drlg to T.D., backream as needed 8320 9.6 12 39 7.2 Logging, hit bridge @ 7800' 8320 9.7 12 44 9.6 Drill Pipe logs, hit bridge @ 7800' 8320 9.85 14 37 8.8 RIH, clean out run, POH, run casing, stuck @ 8124', add 2% Lubetex 8320 9.05 6 18 6.2 Reduce mud weight, work casing free, run to T.D., cement casing CLU #1 RD 8.5 6049 9.1 10 24 4.8 Mill window & drill ahead 8491 9.5 12 44 6.4 Short trip - backream (Beluga relaxing?) - add 3% Lubetex to aid sliding 9051 9.6 13 41 6.8 Increasing clays & volcanics require more dilution and Klagard 9322 9.55 11 33 6.6 Short trip much better 9434 9.65 12 37 6.5 Trip for bit, RIH, tight @ 5950 - 6200' 9739 9.65 12 38 6.8 Short trip, drlg to 9739', wiper trip, CBU, POH for logs, tight @ 6074' r:zJ-.IFE ~ e e §IÆ Marathon Oil Company Well Name: Cannery Loop Unit #8 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 A8 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 at less than 6 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. It is particularly important to maintain a low hardness «200 ppm Ca) for effective use of DualFlo, therefore cement contamination should be completely treated as rapidly as possible prior to adding DualFlo to control or reduce fluid loss. NOTE: If additions of DualFlo do not appear to be lowering the fluid loss adequately, then switch to additions of Polypac Supreme SL after consultation with town. => LSRV - When drilling with a FloPro fluid, the low shear rate rheology should be maintained around 40,000 cps. In addition to adequate additions of Flo Vis Plus, this will also require keeping reactive drill solids to a minimum in order to reduce or eliminate false and unwanted high LSRV. => DRILL SOLIDS - MBT - The MBT should be kept at less than 5 ppb in the production interval 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 KCl 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 - SafeScav NA additions should be made daily as needed with any fluid in the hole. Maintain a DO reading of less than 3 ppm => GREENCIDE 25G ADDITIONS - Greencide 25G additions should be made daily when drilling in the production interval, in the range of 5 gallons per day. => SOLIDS V AN 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. r'J4 ~IFE ~ e e Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Interval Summary -16" hole o - 1800' Drilling Fluid System GellGelex Spud Mud Key Products MI Gel / Gelex / Soda Ash / Caustic Soda / MI Bar / PolyPac Supreme UL 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 Interva.l Drilling Fluid Properties Depth Mud Funnel Yield API Drill Interval Weight Viscosity Point Fluid Loss pH Solids (ft) (ppg) (sec.lqt) (lb.llOOft2) (mI/30min) (%) " 0- 1800' / 60 - 100 NC - 12 +/- 9.5 <7% 8.6 - 9.4 25 - 35 ~ Treat drill water with Soda Ash to reduce hardness. ~ Build spud mud with 20 - 25 PPB M-I Gel to +/- 100 sec.qt 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 ofPolypac Supreme UL prior to running surface casing. ~ Add 2 - 5 PPB ofM-I Seal Fine to mud system if seepage losses becomes a problem.. ~ Condition mud prior to cementing casing to reduce yield point and gel strengths. ~ Estimated volume usage for interval- 1743 barrels. ~ Estimated haul off volume - 3581 barrels. r:JaIFE ~ - e Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Interval Summary -12-1/4" hole 1800 - 6970' Drilling Fluid System Flo-Pro Fluid Key Products FIo-Vis / PolyPac UL / KCl/ SafeCarb F & M, Asphasol Supreme / Lubetex / KlaGard / Caustic Soda / Conqor 404 / SafeScav NA Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 210 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 pH Solids (ft) (ppg) ( cp.) ( cps ) (ml/30min) (%) 1800 - 3500' 9.0- 9.4 8 -12 40,000 8 - 10 +/- 9.5 +/- 5% 3500 - 6970' 9.4-9.6/ 10 - 14 40,000 7-9 +/- 9.5 +/- 8% ~ Use one rig pit to drill out surface casing. In other rig pits, build new Flo-Pro fluid using the enclosed formula. ~ After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test. ~ Maintain DO reading of less than 3 ppm with additions of SaveScav NA. ~ Maintain Conqor 404 concentration of 2000+ ppm. ~ If running coals become a problem, increase Asphasol Supreme additions. ~ Estimated volume usage for interval- 3638 barrels. ~ Estimated haul off volume - 6029 barrels. ~ Condition mud prior to running 9-5/8" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ~ ~IFE ~ e e Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Output - 1 bbl Concentration Volume Fie.ld, Ib Lab,gm Field, bblLab,ml Water 298.70 298.70 0.853 298.70 Soda Ash 0.25 0.25 0.000 0.10 Flovis 2.00 2.00 0.004 1.33 Polypac Supreme UL 2.00 2.00 0.004 1.25 Caustic Soda 0.50 0.50 0.001 0.23 Potassium Chloride 19.07 19.07 0.023 7.98 KlaGard 6.00 6.00 0.018 6.25 SafeCarb F 10.00 10.00 0.010 3.60 SafeCarb M 10.00 10.00 0.010 3.60 Asphasol Supreme 2.00 2.00 0.006 2.08 If bit balling becomes a problem, add the following: D-D CWT I 1.00 I 1.00 I 0.003 I 1.00 Reduce BHA Balling If torque becomes a problem, or sliding is difficult, add up to 5% of the fOllowing: Lubetex 14.00 14.00 0.041 14.43 Intermediate Interval Fluid Formula 12-1/4" Interval from 1800 - 6970' Description Mud Weight Weight Material Code Weight Material SG Input Cannery Loop Unit #8 9.1 - 9.2 Prehydrated Gel MI Bar PrehYdratêd 4.2 KCI Wt% 6 No Order of Addition 1 2 3 4 5 6 7 8 9 10 Products 11 12 Total Calculated Mud Weight Total Chloride 399 399 9.500 29600 1.000 350 Estimated Volume Usage ~IFE ~ Reduce Hardness Viscosity Fluid Loss Control pH Control Inhibition Inhibition Bridging Agent Bridging Agent Wellbore Stability Lubricity 3638 Barrels Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. 1.0- 0.9-- c: 0 '§ 0.7-- ..c¡ .¡: '!i) Õ 0.6 (þ N ii) d> 0.5 -¡; t '" Q. (þ Ok- .2 1ii :¡ E 0.3 :; U 0.2-- 0.1 1~10'2 DilCo. Loop #8 Canary Loop Sterling C·1 Sands Max Permeability: Sand Control Device: 350 mQi!rcy © 1999·2001 M·I L.L.C . All Rights Reserved D10 Target I Blend; 0.7 D50 Target I Blend: 18.7 D90 Target I Blend: 60.6 1.4 15.5 127.3 microns microns microns ![Irand Name B=Safe-Carb 10 (F) D=Safe-Carb 40 (M) E=Safe-Carb 250 (C) 0.0 Calcium Carbonate added; Avg Error 0 - 100 % CPS Max Error 0 - 100 % CPS Range: 20 ¡b/bbl 3.50 % % Particle Size (microns) IFE e e - ~IFE --- Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Interval Summary - 8-1/2" hole 6970 - 9734' Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / DualFlo / KCl/ Greencide 25G / SafeCarb F, KlaGard / MI Bar / Caustic Soda / Conqor 404 / SafeScav NA 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 Interv~d Drilling Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss pH Solids (ft) (ppg) (cp.) ( cps ) (mIl30min) (%) 6970 - 9734' 9.0 - 9.6 / 10 - 14 40,000 <5 +/- 9.5 +/- 5% ~ Use one rig pit for drilling out intermediate casing. In other rig pits, build new Flo-Pro fluid using the enclosed formula. ~ If running coals become a problem, treat with a 2 PPB addition of Asphasol Supreme. ~ Periodic additions of Greencide 25G will be needed to control bacteria build-up. ~ Estimated volume usage for interval- 1584 barrels. ~ Estimated haul off volume - 2457 barrels. ~ Condition mud prior to running 3-1/2" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. r:zJ-.IFE ~ e ~ ,-~IFE -. e Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Production Interval Fluid Formula 8-/12" Interval from 6970 - 9734' Description Mud Weight Weight Material Code Weight Material SG Weight Material Price Sea Water Sea Salt M-I Gel M-I Gel Price Input Cannery Loop Unit #8 9.05 Prehydrated .Gel SafeCarb Prehydrated GeICö!?ìc. 2.8 KCI Chloride 0.35 KCI Wt% No KCI Price No NaCI Chloride NaCI Wt% NaCI Price Order of Addition 1 2 3 4 bA 5B 6 7 8 9 10 11 12 13 Output - 1 bbl Condentration Field. Ib Lab, gm Water 325.19 325.19 Soda Ash 0.25 0.25 FloVis Plus 1.25 1.25 DualFlo 6.00 6.00 SafeCarb Fine 14.00 14.00 SafeCarb Medium 6.00 6.00 Potassium Chloride 20.76 20.76 Greencide 25G 0.25 0.25 CONQOR 404 2.00 2.00 Caustic Soda 0.50 0.50 SafeScav NA 0.25 0.25 If Bit balling becomes a rrOblem, add the following D-D 4.00 I 4.00 I 0.011 I 4.00 If sliding or high torque becomes a problem add 1 - 3% of the following Lubetex I 7.00 I 7.00 I 0.021 I 7.00 If sloughing coals become a problem add 2 - 4 ppb of the followinQ Asphasol Supreme I 2.00 I 2.00 I 0.004 I 1.33 Mix fluid in the order listed above. Wait for 1 - 2 circulations before adding SafeScav NA to the system. Alternate additions of Greencide 25G and SafeScav NA as needed. Maintain 5 - 6 ppb concentration of DualFlo to maintain as Iowa API fluid loss as possible. Plan on daily additions of DualFlo to achieve> 6.0 cc's API Fluid Loss Reduce concentration of FloVis as needed to maintain rheology. Products I Volume Field, bbl 0.929 0.000 0.003 0.011 0.015 0.006 0.025 0.001 0.004 0.001 0.001 Total I Calculated Mud Weight Total Chloride No 6 0.2516 L~b" rril 325.19 0.10 0.84 4.00 5.30 2.30 8.68 0.30 1.43 0.23 0.25 Reduce Hardness Viscosity Fluid Loss Control Bridging Agent Bridging Agent Inhibition Biocide Corrosion Control pH Control Oxygen Scavenger Reduce BHA Balling Lubricity Well bore Stability 380.1 9.050 29600 Estimated Volume Usage I 1 584 Barrels 380.1 ~IFE ~ Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. 0.9 c: :8 ~ ~ Ij¡ i5 (j) N üj (j) Ü ''2 '" 0... (j) ~ '" :; E ~ u O.2~ 0.1 1~10-2 © 1999-2001 114-1 L.U: - All Rights Reserved Particle Size (microns) Max. Permeability: Sand Control Device : 25 mDarcy i DiD Target ¡ Blend: 0.2 D50 Target ¡ Blend: 5.0 D90 Target ¡ Blend: 16.2 0.9 microns 9.2 microns 23.5 microns Range BridainQ Aaent (lblbblVol % 20.0 100.00 0.0 0.00 0.0 0.00 Brand Name B=Safe-Carb 10 (F) D=Safe-Carb 40 (M) E=Safe-Carb 250 (C) B 100.0% Calcium Carbonate added: Avg Error 0 - 100 % CPS Range: Max Error 0 - 100 % CPS Range: 20 Iblbbl 7.06 % 18.17 % IFE e e Marathon Oil Company Well Name: Cannery Loop Unit #8 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. r:':7 4 ~IFE ~ Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Product M-I BAR M-I GEL GELEX FLOVIS DUAL-FLO POLYPAC XCD HEC Safe-Carb F,M,C LO WATE Nut Plug M-I Seal F, M, C Mix II F,M,C DESCO CF SPERSENE CF TANNATHIN VENTROL 401 SALT (Solar) BROMIDE (NaBr) & Brine Solution POTASSIUM CHLORIDE - function Weighting Agent Viscosity control Bentonite Extender Viscosifier Modified Starch Fluid Loss Reducer Viscosifyer Loss Circulation Material Bridging and weighting agent Weighting agent Loss Circulation Material Loss circulation Material Loss circulation Materia! Dispersant Dispersant Dispersant Surfactant Densifier Densifier Shale Inhibitor IFE Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Product CAUSTIC SODA CAUSTIC POTASH BORAX SAPP SODA ASH SODIUM BiCARBONATE CiTRIC ACID BIOBAN BP-PLUS GREEN CIDE 25G - DEFOAM X - G-SEAL KLA-GARD LUBE TEX CWT Con cor 404 SAFEKLEEN AsphasoiD Soltex SafeScav NA Function Alkalinity control pH Modifier Inorganic Borate Sodium Pyrophosphate Alkalinity control Alkalinity control pH Adjuster Biocide Biocide Defoamer Sized graphite LCM Shale Control agent Lubricant Detergent Corrosion Inhibitor Drilling fluid additive Shale Inhibitor Shale Inhibitor Oxygen Scavenger IFE e e Marathon Oil Company Well Name: Cannery Loop Unit #8 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 r:zJ-.IFE ~ e e ....... -- 'IFE -~ ----- Marathon Oil Company Well Name: Cannery Loop Unit #8 Location: Kenai, Alaska. Project Team Bob Williams Senior Engineer Floyd Faulkner Senior Engineer III II Craig Bieber District Manager t ~ t ~ Deen Bryan Tech Service 11II . Gus Wik I Warehouse Manager . MI Project Engineer and Tech Service Engineer will coordinate 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. Project Team Title Home Cellular Craig Bieber District Manager 907 345-1239 907 229-1196 Deen Bryan Tech Service 907373-2713 907223-1634 Tony Tykalsky Project Engineer 907376-4613 907 227-2412 Gus Wik Warehouse Manager 907776-8722 907776-8680 ~4 ~IFE ~ e e Alaska Region Domestic Production Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 December 31,2003 Sarah Palin Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 RECEIVED DEC 3 1 2003 Alaska Oil & Gas Cons. Commission Anchorage Reference: Drilling Permit Application Field: Cannery Loop Well: Cannery Loop Unit - CLU 8 Dear Ms. Palin Enclosed please find the PERMIT TO DRILL application, along with the associated attachments and filing fee of $100. The intent is to drill a Beluga development well in the Cannery Loop Unit. No completion is desired in either the Sterling or Tyonek pools. Please note that Marathon is requesting a waiver for 20 ACe 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 907-564-6310 or bye-mail at wjtank@marathon.com. Sincerely, þ~}.c~. Willard J. Tank Senior Drilling Engineer Enclosures RECEI\/~I) DEC 3 1 2003 Alaska Oil & Gas COil;'. ..J¡¡ul¡¡SSlon Anchorage e e 1108488 12/30/2003 NC8AS 7780 5001123 Marathon Oil Company P. O. Box 3128 Houston, TX 77253 ~g¿gU¡Nl~irt; Y~~LE DEPARTMENT Aeets Payable - Cus10mer Serv Phone: 713-296-4336 Hndlg Check No Cheek Date Sank Bank ND Vendor No Al nVoÙ:eÒIl1~Do(j\JmentNr" Remi1 cornmen! 12/24/20Ò3 1900036111 CLU #8 - SEND TO BETTY V£LDHÜrS X484 TOTAL: A0100.00 100.00 100.00 100.00 RECEr JED DEC 3 1 ZOO3 C nvn'SS\on t)"\ & Gas Ctns. 0 "\as~a \ "nchÐt8Ue (FOLD ON PERFORATION BELOW AND DETACH CHECK STUB SEFORE DEPOSITING) _'I..«..).tf~~ :11~1~~-)."'1¡!~':I~IINtII :'~Wt"~1~I.tJil::tl'i:I:(~~":'~~t~<t:{'111~lt.~1:f:t~"ir'J"=*,..'I::II.I~I~:J:I{'}!j!CtImV~1l~!:fI'[~:{']:1ill~lIil~c. 5RÑì25~ÎÔÕ-·-··-·-·~'_·~---·~--""--~-'·'----~~~--~-·---~~··.-....._.-....._._-'_.~---...._._--_..~~._~-_._-....,---~._.~._---.~.~--~~._~-~....._~.................-....... 1780 58-38B/41 ;¡ NATIONAL CITY SANK Ashlanf4f Ohio e . TRANSMJT AL LETTER CHECKLIST CIRCLE APPROPRIA TIt LETTER/P ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME PTD# CHECK WBA T APPLffiS ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) Pll..OT (PH) "CLUE" Tbe permit is for a new wellbore segment of existing well Permit No, API No. Productionsbould continue to be reported as a function' of tbe original API number. stated above. BOLE In accordance witb 20 AAC 25.005(1), all records, data and logs acquired for tbe pilot bole must be clearly differentiated in botb name (name on permit plus PH) and API Dumber (50 70/80) from records, data and logs acquired for we)) (name on permit). SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\tempJates Tbe permit is approved subject ·to full compliance witb 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Companv Name) assumes tbe liability of any protest to tbe spacing exception tbat may occur. An dry ditcb sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. o o Well bore seg Annular Disposal Program DEV On/Off Shore On Unit Well Name: CANNERY LOOP UNIT 8 1-GAS GeoArea DEV e Yes Yes y~s y~s y~s Yes Yes Yes y~s y~s Y~s Yes Yes NA .NA NA NA Initial ClasslType 448575 KENAI. C.L.U. BELUGA GAS Company MARATHON OIL CO P~rmit fee attache.d. .Leas~ .number ^,,,,.,,{,.,^.] I'Q ''''0.11 na ~l1Jb_er I in pool. I pr j ,nce. from driJling unitbound.a1"Y. from otber welJs u..-..' "p.' ,,,te. Field & Pool .U.nlq",,. '0"". Well Wet Wel locat~d proper .dlstance .S.ufficient ^ .If d~viate( in drilliog unjt il)cJuded ",creag.e.ayailable js wellbore plat .O-perator onl~ affected party .O-perator bas. appropriate. bond lnJorce cao be lssued without c.ao be lSSll.ed wjtbout Can permit 1-,..,. "'nn.r^'r'I""I-I .......~.... .We.II'~~~·^· " .AJI w )f review id~otifjed (For ~e[Vj~ )v.eU onl~) Pre-I i on.of pre--pr09uc;tionl~s~ than 3. months (For co.nserva.tion order administratil.'e. approval 15-day wait UIIi;; wl""'l""',.....,,""'u Uwlure in.comm~ots)(for 10# lojectioo Ord~r # (put ."v".,,,,d wlthin area and.strata .authorlzed by. .selYlce well onJy) 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 7 PTD#: 2040050 Administration P~rmit P~rmit Date 1/212004 Appr RPC Me~uate exce~s. GlacierRig New wel Max MW9ß ppg. e 905 psi.. NlSF' Testto.30QOpsi Yes y~s y~s No y~s y~s Yes NA y~s y~s y~s y~s .Y~s Yes y~s No. NA. .A{:MP. Fïnding .of COllslsteocy h.as bee.n issued. for.tbis project. .C.ooductor .S.ucfac~ .casing. proted$. all.kflowll USQWs st(lng.provid~d .CMT vol adeq u.ate to circ]Jlate. o.nconductor 8,; SUJf. <:$g CMT vol ad~Qu.ate to tie-lnJong .string tosucf C$g. .CMT will coyeraJl know.nproduc;tiye bori¡1:0llS C..T.. B&.permafrost for Agequate.tan.kage.or re.selYe pit .C.asiog desi.gos adequa.te be~o apPJoved Jf.a.re-drilt bas.a 1.0:403 for abandonment .Mequatewellbore separatjo.n .pro-pose9 JfdNerter Jequired, does it me~t reguJa.tions. Drilliog fluid program sc.hematic.& eq.uip Jistadequate .BOP.Es,do.they meet reguJa.tion tn.comments) (May 84) withoutoperatio.nsbutdown I~ pre~ence. of H2S gas. prob.able 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 Engineering Date 1/5/2004 Appr WGA (pu.t psig .test to .C.hoke.manifold compJies w/APIRF'-53 Work will occ.ur ra.tiOQ appropriate; B.OPEpress MechanlcaLcoodjtloo pf wells wlthin ,ð,OR verified (for. s.ervjce w~1J only) y~s NA NA .NA. .NA c.ao be lSSll.ed wlo. hYdrogen. s.ulfide meas]Jres P~rmit .Data.presented on. pote.ntial pveJpressure .zones 35 36 37 38 39 Geology Appr RPC Date 1/2/2004 .S~lsmic.analysjs. of sbaJlow gaszooes S~abed .condjtipo survey.(if off-shore) ~ ,IÕ ~ate Contact namelp/1oneJorwe~kly progress reports [explorato1"Y .0olYl Public Commissioner Date Engineering Commissioner: Date: / (( (4- Geologic Commissioner: DJ;s'