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206-058
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-55 136' 13-3/8" L-80 1,489' 9-5/8" L-80 4,355' 3-1/2" L-80 7,894' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 95 sks Class G Lead 237 sks Class G tail 12-1/4" TUBING RECORD 1550 sks Class G9,284' 516 sks Type 1 cement N/A 3,500' 16" N/A 8-1/2" 9,284'3-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG WAG Gas 2/22/2025 206-058 / 325-040Hilcorp Alaska, LLC 50-133-20559-00-00 Cannery Loop Unit (CLU) 112493' FSL, 2280' FWL, Sec 4, T5N, R11W, SM, AK 146' FSL, 792' FEL, Sec 5, T5N, R11W, SM, AK N/A 4/28/2006 9,305' MD / 7,915' TVD 4,306' MD / 3,430' TVD 56' 280668.50 2396065.80 N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 ADL0324602 CASING WT. PER FT.GRADE 5/11/2006 CEMENTING RECORD N/A N/A SETTING DEPTH TVD 2393776.90 TOP HOLE SIZE AMOUNT PULLED N/A 277556.80 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A BOTTOM SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4,406'9.2#85,000 DrivenSurface N/A N/A 40# Surface 136'Surface 68# 5,595' Surface Surface 133# Surface 1,602' N/A Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 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 Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 2:06 pm, Mar 21, 2025 Suspended 2/22/2025 JSB RBDMS JSB 032725 xGDSR-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: Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Authorized Name and INSTRUCTIONS Noel Nocas, Operations Manager 907-564-5278 Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation Name at TD: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.03.21 13:26:09 - 08'00' Noel Nocas (4361) State/Prov:Alaska Country:USA 35.0'Date Completed:5/18/2006 Ground Level (above MSL):RKB (above GL):21.0' Revised By:D Ambruz Schematic Revision Date:3/11/2025 ngle @KOP and Depth:± 3° / 220 ft @ 650' MD Angle/Perfs:4º ĺ 1ºMaximum Deviation:45.6º @ 2,883' Well Name & Number:Cannery Loop #11 Lease:ADL-324602 County or Parish:Kenai Peninsula Borough TD 9,305' MD 7,915 TVD Excape System Details - 11 Excape modules placed -Green control line fired module 1 -Yellow control line fired modules 2 thru 7 -Red contol line fired modules 8 thru 11 - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB)( Beluga Zones): Mod-11 6,593' - 6,603' Not Shot UBE 6,726' - 6,746' (7/7/15) (Isolated) Mod-10 7,373' - 7,383' (Perfed 5/1/07) (Isolated) Perf: 7,383' - 7,400' (Perfed 5/1/07) (Isolated) Mod- 9 7,472' - 7,482' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 8 7,686' - 7,696' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 7 7,868' - 7,878' Not Shot Mod- 6 7,929' - 7,939' (Perfed 4/1/07) (Isolated) Perf: 7,939' - 7,946' (Perfed 4/1/07) (Isolated) Mod- 5 8,208' - 8,218' (Frac'd 9/28/06) (Isolated) Mod- 4 8,384' - 8,394' (Frac'd 9/28/06) (Isolated) Mod- 3 8,496' - 8,506' (Frac'd 9/28/06) (Isolated) Mod- 2 8,606' - 8,616' (Frac'd 9/28/06) (Isolated) Mod- 1 9,085' - 9,095' (Frac'd 9/28/06) (Isolated) Top of Cement (Bond Log) @ 4,440' MD Excape System Details - 10 Conventional flappers- Mod-1 no flapper - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module-11 6,613'Module-10 7,390'Module- 9 7,490'Module- 8 7,703' (Broken CT 9/28/2006)Module- 7 7,886'Module- 6 7,948'Module- 5 8,227' (Broken CT 9/28/2006)Module- 4 8,403' (Broken CT 9/28/2006)Module- 3 8,515'Module- 2 8,625' (Broken CT 9/28/2006) Permit #: 206-058API #: 50-133-20559-00Property Des:ADL-324602KB Elevation:56' (21'AGL)Lat:60°33' 10.707" NLong: 151°13' 07.001" WSpud Date: 04/28/2006TD Reached: 05/11/2006Rig Released:05/15/2006 CLU-11 Pad-3 2,491' FSL, 2,291' FWL Sec. 4, T5N, R11W, S.M. Tree cxn = 6-1/2" Otis PBTD 4,306' MD 3,430' TVD Velocity String 1-3/4" HO70FF (0.125" WT) Install 7/21/07; Partially removed Top Bottom MD 7,912' 8,185' TVD 6,522' 6,795' BHA: 2.5" OD x 1.5" ID grapple connector 2.5" OD x 1.5" ID x 10' weight bar w/ drain 2.5" OD x 1.135" ID NoGo profile nipple 2.48" OD x 1.5" guide nose Slickline tag EOVstrg 8225' (4/18/12) Conductor 20" X-52 131 ppf Top Bottom MD 0' 136' TVD 0' 136' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of 12.0 ppg, Type 1 cmt Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' TVD 0' 4,355' 12-1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail Production Tubing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 4,406' 9,284' TVD 3,500' 7,894' 8-1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt VELOCITY STRING FISH: Top of Coil:1-3/4" coil @ 7,912' cut with radial torch, milled down with 2.75" mill on 6/13/15 (Fill on backside of coil) Fish:4.1' of 1.0" wt bar lost 6/06/15 @ 7,919' Fish:4.0' of 1.0" wt bar lost 6/04/15 @ 8,162' Plug:PXN plug set 5/16/15 @ 8,209' Sterling C1 Interval: SCHEMATIC Cast Iron Bridge Plug @ 7,840' Dump bail 10' of cement UBE Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date UB-B 6,583' 6,592' 2-3/8" 5 Isolated 02-12-16 UB-B 6,591' 6,601' 2-1/2" 5 Isolated 04-21-21 Cast Iron Bridge Plug @ 6,700' Dump bail 10' of cement TOC 6,690' 02/10/16 UB-B @ 6 700' CINGSA Base 6,538’ MD 5,170’ TVD 9-5/8" CIBP Set @ 4350' w/ 25' cement - TOC @ 4306' (2/21/25) Cut tubing @ 4406' (2/14/25) 3-1/2" CIBP @ 6553' w/ 25' of cement - TOC 6528' (2/13/25) It ditC CINGSA Top 6,282’ MD 4,933’ TVD Page 1/2 Well Name: CLU 011 Report Printed: 3/5/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20559-00-00 Field Name:Cannery Loop State/Province:ALASKA Permit to Drill (PTD) #:206-058 Sundry #:325-040 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 Held PJSM, MIRU YJ EL, SITP 0psi, IA 0psi. PT Lubricator 250psi/2500psi. RIH with 2.80" JB/GR. Tagged high at 6520'. POOH. (Target plug set depth at ~6560'). Recovered Mud/Clay silk. M/u and RIH w/2.25' JB/GR tagged same depth of 6520'. RDMO YJ EL. Report Number 2 Report Start Date 2/8/2025 Report End Date 2/9/2025 Last 24hr Summary Tagged top of fill at 6505'KB- Bailed fill to 6534'KB PTW/PJSM. MIRU Pollard slickline. P-test 250/1,500 psi. Bail fine silt/clay/slurry from 6,505' KB to 6,533' KB. Recovered ~4 gal solids. SDFN. Report Number 3 Report Start Date 2/9/2025 Report End Date 2/10/2025 Last 24hr Summary Tagged top of fill at 6529'KB. Bailed fill to 6543'KB - Drifted tubing with 2.81 gauge ring to 6543'KB PTW/PJSM. Bail fine silt/clay/slurry from 6,529' KB to 6,543' KB. Recovered ~5 gal today. Clean tag at 6,543' KB with 2.80" gauge ring. RDMO slickline. Report Number 4 Report Start Date 2/10/2025 Report End Date 2/11/2025 Last 24hr Summary PTW/PJSM. MIRU AK E-line. P-test 250/2,500 psi. Tag fill at 6,526' KB w/ 2.75" GR/JB. RDMO E-line. Report Number 5 Report Start Date 2/11/2025 Report End Date 2/12/2025 Last 24hr Summary Tagged top of fill at 6520'SL. Bailed fill to 6529'SL - Operations ongoing 24hrs PTW/PJSM. MIRU Pollard Slickline. P-test 350/1,500 psi. SITP ~5 psi. RIH w/ 2.50" bailer. Tag @ 6520' WLM. Bail hard packed solids (clay/silt) alternating w/ 2.5", 2.0", 1.75" bailers. Ran 2.81" gauge ring after each 6-8' of progress. Continue bailing to 6532' WLM. Report Number 6 Report Start Date 2/12/2025 Report End Date 2/13/2025 Last 24hr Summary Bailing, start at 6527'SLM, End at 6535'SLM Continue Slickline bailing operations at 6,532'. Bail hard packed solids (clay/silt) alternating w/ 2.5", 2.0", 1.75" bailers. Ran 2.81" gauge ring. Current depth 6,538' slm / 6,544' corrected. Report Number 7 Report Start Date 2/13/2025 Report End Date 2/14/2025 Last 24hr Summary Bailing, Start at 6536'SLM end at NOTE- to get any fill out, requires beating down hard and getting stuck, making runs significantly longer. Very hard fill. Report Number 8 Report Start Date 2/13/2025 Report End Date 2/14/2025 Last 24hr Summary RDMO Pollard Slickline. MIRU Ak Eline. Drifted w/Gamma, CCL, & junk basket w/2.75” gauge ring to 6,555’ elm. Set 2.75” CIBP @ 6,553’ elm (Top of plug). Correlated to Ak Eline GPT/Perf record 21-April-2021. Dump bailed 9 gallons of cement on plug. Calculated TOC = 6,528’. MIT-T to 1500 psi for 15 minutes, lost 10 psi. Bleed tubing pressure to zero. RDMO Ak Eline. Report Number 9 Report Start Date 2/14/2025 Report End Date 2/15/2025 Last 24hr Summary Secure loads on trailers, Clean liner and fold, Move loads to CLU-11, Lay out liner. Set carrier and auxiliary equipment. Raise and scope up derrick. Winterize and get heat on equipment. Hook up electrical. R/u AK e-line, RIH w/ 2.25" sample bailer, Tag TOC @ 6,440', POOH, R/u test pump and MIT 3 1/2" tubing to 2,000 psi for 30 min (Good test), Witnessed by Kam St.John w/ AOGCC. R/u AK E-line. RIH w/ RCT, correlate and cut at 4406' ELM. Pass through cut and log up, see cut at 4406', POOH. Line up to circulate. Tubing pressuring up, pressure up to 3000psi w/ no returns. Rock circulation and got returns. Circulate out 9.9ppg mud from IA w/ 8.4ppg water, 432 bbls circulated. Eline RIH w/jet cutter. Correlate jet cutter with initial cut, cut at 4406' elm. POOH. E-line RIH and set 3-1/2" retrievable bridge plug at 100'elm. Tag plug to confirm set. POOH. RDMO e-line. Top off well and test plug to 3000psi, good test. Nipple down tree. Report Number 10 Report Start Date 2/15/2025 Report End Date 2/16/2025 Last 24hr Summary Pull WRP from 111' Install caps on control lines, N/u BOPE. M/u 3-1/2 test joint. Fluid pack BOPE and check for leaks. Test BOPE to Hilcorp's and AOGCC's expectations, 3-1/2" TJ, 13 -5/8" 5M BOP, 250psi/3000psi 5 minutes each. Test gas alarms and PVT, manual chokes, perform koomey drawdown. Witness waived by AOGCC's Jim Regg. R/u slick line. Pull 3-1/2" plug at 100'. RDMO slick line. R/u to reverse circulate. Reverse circulate 8.4ppg fresh water at 4bpm, 370psi. Getting solids back on b/u, circulate until returns clean up. 361bbls circulated. M/u 3-1/2" spear assembly. Spear into tubing hanger. P/u seeing hanger come off seat at 82k. Work up in 10k increment to 150k. see a total of 3'4" of pipe strech. Work pipe trying to free with no luck. Circulate 8.4ppg water at 3.12bpm, 950psi. 321bbls circulated. No solids seen at bottoms up. P/u and work pipe upt to 150k, no increase in pipe movement. R/u to circulate down tubing, p/u to 150k. Circulate down tubing at 3.1bpm, 950psi. See a decrease of 5k in weight, p/u to 150k gaing 3" of movement. Cont. pumping at same rate but do not see any additional drop in weight. R/d circ equipment. Work pipe between 90-150k trying to free with no luck. 3'7" of stretch. R/u casing jacks. Work tubing up to 200k with jacks. pp Correlate jet cutter with initial cut, cut at 4406' elm. yqp pp Ta g TOC @ 6,440', POOH, R/u test pump and MIT 3 1/2" tubing to 2,000 psigqp p , for 30 min (Good test), Witnessed by Kam St.John w/ AOGCC. Set 2.75” CIBP @ 6,553’ elm (Top of plug).,,j ggg, Correlated to Ak Eline GPT/Perf record 21-April-2021. Dump bailed 9 gallons of cement on plug. Calculated TOC = 6,528’. Page 2/2 Well Name: CLU 011 Report Printed: 3/5/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 11 Report Start Date 2/16/2025 Report End Date 2/17/2025 Last 24hr Summary Cont. working 3 1/2" tubing w/ casing jacks f/ 160K t/ 180K. Circulate and spot NXS lube. Circulate surface to surface, R/u vac truck to pump 125 bbl's of hot water (130 deg), Kick pump in and started seeing Baraklean back at pits shut down, Thinking seal is gone on hanger and spear leaking by, Discuss options w/OE, decision was made to try and back out 3 1/2" eue landing jnt and make up 3 1/2" PH6 landing jnt, Brake off 4' pup and strip casing jacks off, try using tongs to release spear, no luck. MIT 9 5/8" and 3 1/2" tubing to 3,000 psi for 30 min (good test), Wait on approval from AOGCC to break flange on top of mud cross, Got approval to move forward, Break top flange on mud cross, P/u annular and mud cross, Soft break x/o, Lower BOPE back down torque up. Pull landing joint. M/u 3- 1/2" PH-6 pup with head pin and m/u on spear assembly, close UPR and inside choke and kill. Test break between double gate and mud cross 250psi low and 3000psi high, five minutes each, good test. R/u casing jacks. m/u joint of 3-1/2" PH-6 on spear assembly. P/u w/ elevators to 150k, 4'3" of pipe stretch. Use jacks to p/u to 200k. Total pipe stretch 4'7". Report Number 12 Report Start Date 2/17/2025 Report End Date 2/18/2025 Last 24hr Summary Remove casing jacks and use tongs to try and release spear turning to the right, no luck. Try backing out 3 1/2" PH6 landing jnt w/ tongs turning to the left noticed the mark on landing jnt started coming up like it was backing out of a jnt. Discuss w/ OE plan is to continue turning string to try and do a blind back off. Back off joint. Lay down 3 1/2" PH6 jnt, x/o, spear, false hanger neck and 19.50' cut jnt, cut jnt was smashed from slip about 3.5' below false hanger. Pull 3 1/2" eue tubing, the slip bowl came up on the 3 control lines and 7/16" cable, but missing the 4 segments of slips. Have a 3 1/2" collar looking up, Total feet pulled out of hole 647.82'. RIH w/ 3 1/2" PH6 and screw into fish, R/u to circulate. P/u to 80k. Circulate 108bbls of 8.4ppg water at 4.64bpm, 580 psi. Swap to reverse circulate, circulate 250bbls water at 4.75bpm, 650psi. Getting back solids on b/u.. Wt. dropped to 72k while pumping. Hot water arrives. Circulate 115bbls 140 degree F water, spotting in IA. Work pipe to 150k for an hour. Gain 12" of pipe movement. Holding 150k, circulate 144bbls water down tubing at 4.64bpm, 700psi. Wt. dropped to 140k while circulating. Attempt to p/u to 150k, wt. broke over to 70k, continue p/u and wt fell off to 36k. L/d down joint. R/u to circulate. Attempt to reverse circulate w/ no luck. Swap to circulate the long way to clear. Pull and l/d 4 more joints, f/3386-t/3266, p/u wt 34k. well is u-tubing. Reverse circulate until well evens out. POOH from 4266' to 3550', standing back 8 stands of 3-1/2" PH-6 workstring. Recover 3, 1/4" control lines on first joint of completion and recover sacrificial cable on bottom of first stand. Remove banding, centralizers, and spool up lines. Report Number 13 Report Start Date 2/18/2025 Report End Date 2/19/2025 Last 24hr Summary Continue POOH f/3,550' t/ 1,980'standing back 3-1/2" 9.3#, L-80, EUE, 7/16" was wanting to go back downhole, put saddle clamp on cable and hooked up winch tried pulling up on cable with no luck, ended up running cable through ear of elevators and using cable clamps to pull cable up with pipe, would use winch to hold cable up to get another bit after laying jnt down, POOH laying down singles f/ 1,980' t/ surface. Total joints of EUE out of hole =139 joints, 1 hanger cut joint 19.3', 1 bottom cut joint 27.77'. Last full joint had wadded up control lines and cable causing the the cable to want to drag back in hole. M/u cleanout BHA w/ 9-5/8" casing scraper and 8-1/2" roller cone bit. Total length 11.62'. Single in hole w/ 3-1/2" EUE that was laid out and remaining pipe out of derrick. Single in on 3-1/2" PH-6 tagging fill at 4353'. R/u to wash down. Reverse circulate 8.4ppg water at 4.5bpm, 550psi, getting back dehydrated mud back at bottoms up. Start washing down from 4353'. Not washing past 4353', hitting solid. Inform OE. Continue trying to wash past while town discusses plan forward. Report Number 14 Report Start Date 2/19/2025 Report End Date 2/20/2025 Last 24hr Summary Cont trying to wash past 4353', hitting solid. Wait on OE w/ plan, decision to POOH. POOH F/ 4,353' T/ surface laying down. R/u AK E-line equipment. Run#1 RIH w/ JB and 8.25" GR, Tagged up @ 4,365', POOH, Recovered 6 bands and sludge. Run #2 RIH w/ CBL and log up from 4340' to surface. Log showing good cement to 4000'. Run #3 RIH w/ 9-5/8" CIBP to 4365', pulled CCL correlation pass. Set CIBP at 4350', confirm set plug with tag. Pressure test CIBP and 9-5/8" casing to 3000psi. Initial pressure 3300 psi, 15 min 3290psi, 30 min 3290psi. 4bbls in and out. Good test. E-line Run #4 RIH w/ 5"x30' bailer and dump 30 gallons cement on CIBP at 4350'. Report Number 15 Report Start Date 2/20/2025 Report End Date 2/21/2025 Last 24hr Summary Cont. E-line Run #5 RIH w/ 5"x30' bailer and dump 25 gallons cement, Run #6 RIH w/ 5"x30' bailer and dump 25 gallons cement, TOC @ 4,325', R/d AK E -line equipment, R/d floor, N/d BOPE, N/u dry tree, Power washing equipment getting it ready for Cat 3 inspection, Report Number 16 Report Start Date 2/21/2025 Report End Date 2/21/2025 Last 24hr Summary IA/OA=0psi. R/u pollard slick line. PT 250/2000psi, good test. RIH w/ 2.5"x6' DD bailer, tagging cement at 4306' slm (4327'KB). POOH r/d slick line. Pressure test 9 -5/8" casing and plug to 3000psi. Initial pressure 3240psi, 15 minutes 3230psi, 30 minutes 3225psi, Good test. Tag and pressure test witnessed by AOGCC's Sully Sullivan. Report Number 17 Report Start Date 2/22/2025 Report End Date 2/22/2025 Last 24hr Summary AIH Material Order for CLU-11 on 2/22/2025 on ORder#14920866-00 tagging cement at 4306' slm (4327'KB). POOH r/d slick line. Pressure test 9pp p,g ,ggg ( ) -5/8" casing and plug to 3000psi. Initial pressure 3240psi, 15 minutes 3230psi, 30 minutes 3225psi, Good test. Tag and pressure test witnessed by AOGCC's Sully Sullivan. ,yg qp un #2 RIH w/ CBL and log up from 4340' to surface. Log showing good cement to 4000'Set CIBP at 4350', confirm set plug with tag. Pressure test CIBP and 9-5/8" gp ggg ,p p , p g g casing to 3000psi. Initial pressure 3300 psi, 15 min 3290psi, 30 min 3290psi. 4bbls in and out. Good test. E-line Run #4 RIH w/ 5"x30' bailer and dump 30 gallonsgp p cement on CIBP at 4350'. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/2/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250302 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# CLU 11 50133205590000 206058 2/19/2025 AK E-LINE CBL,CIBP CLU 11 50133205590000 206058 2/13/2025 AK E-LINE CIBP END 1-65A 50029226270100 203212 1/27/2025 HALLIBURTON COILFLAG END 2-56A 50029228630100 198058 2/6/2025 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 2/2/2025 HALLIBURTON PPROF MPU F-29 50029226880000 196117 1/31/2025 HALLIBURTON MFC24 MPU L-02A 50029219980100 209147 2/17/2025 READ CaliperSurvey MPU L-36 50029227940000 197148 1/18/2025 HALLIBURTON MFC24 MPU R-144 50029238090000 224148 2/11/2025 HALLIBURTON WFL-TMD3D NCIU A-21 50883201990000 224086 2/18/2025 AK E-LINE Perf ODSN-25 50703206560000 212030 2/16/2025 READ MemoryLeakPoint PBU 06-05A 50029202980100 224115 1/15/2025 BAKER MRPM PBU 06-15A 50029204590200 224108 12/27/2024 HALLIBURTON RBT PBU 06-16B 50029204600200 223072 1/25/2025 BAKER MRPM PBU B-12B 50029203320200 224133 1/19/2025 BAKER MRPM PBU S-126B 50029233630200 224084 2/7/2025 HALLIBURTON RBT PBU V-105 50029230970000 202131 2/9/2025 HALLIBURTON IPROF PBU W-01A 50029218660100 203176 1/19/2025 AK E-LINE CBL PBU W-01B 50029218660200 224149 1/28/2025 HALLIBURTON RBT PCU 02A 50283200220100 224110 1/24/2025 AK E-LINE CIBP Please include current contact information if different from above. T40161 T40161 T40162 T40163 T40164 T40165 T40166 T40167 T40168 T40169 T40170 T40171 T40172 T40173 T40174 T40175 T40176 T40177 T40178 T40179 CLU 11 50133205590000 206058 2/19/2025 AK E-LINE CBL,CIBP CLU 11 50133205590000 206058 2/13/2025 AK E-LINE CIBP Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.03 10:15:14 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Stefan Reed Subject:Re: CLU-11 Date:Sunday, February 16, 2025 5:02:11 PM Stefan Hilcorp has conditional approval to proceed with the plan as described in the email below. Condition of approval: Test BOP flange break and any piping or valves that were knocked loose after replacing the BOP stack. Function test rams before pulling tubing. If unable to test because hanger seals are damaged, lay down hanger, then hang string with storm packer and test BOP. Regards Bryan Sent from my iPhone On Feb 16, 2025, at 4:13 PM, Stefan Reed <Stefan.Reed@hilcorp.com> wrote: Bryan, As discussed, below is what we are proposing and current conditions of the well. The CMIT was done to 3000psi. They will use NOV safety wrenches to break the connection in the stack. Get Outlook for iOS From: Wade Hudgens <Wade.Hudgens@hilcorp.com> Sent: Sunday, February 16, 2025 3:40:03 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Subject: CLU-11 We are proposing to remove the BOP Stack between the Mud Cross and Double Rams to break out the 3-1/2” EUE Landing Joint and replace it with 3-1/2” PH6 Joint. Current Well Condition is static with a tested plug and 25’ of cement isolating the perfs. The tbg has been cut and a Combo MIT-T&IA was performed. A spear was used to engage the hanger, made several attempt to pull but the tubing string free. After not being able to pull the tubing string free we made several attempts to release the spear from the hanger but was unsuccessful do due the torque rating of EUE. Once we have the 3-1/2” PH6 Joint in place it will give us the option to increase the max pull and increase the torque we need to release the spear. The information contained in this email message is confidential and may be legally privileged and is intended only forthe use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient toensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems or data. No responsibility is accepted by the company in this regard and the recipient should carry out suchvirus and other checks as it considers appropriate. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 4 Township: 5N Range: 11W Meridian: Seward Drilling Rig: N/A Rig Elevation: N/A Total Depth: 9,305 ft MD Lease No.: ADL324602 Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 136 Feet Csg Cut@ Feet Surface: 13-3/8" O.D. Shoe@ 1,602 Feet Csg Cut@ Feet Intermediate: 9-5/8" O.D. Shoe@ 5,595 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@ 9.284 Feet Tbg Cut@ 4,406 Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Bridge plug 4,350 ft 4,306 ft 9.9 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing n/a n/a n/a 9 5/8 3240 3230 3225 OA Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: This report reflects the tag and test of the 9-5/8" casing plug. This well is planned for redrill later this year. After tubing was pulled a CIBP was set @ 4,350 ft MD with 44 ft of cement dump bailed on top. I witnessed the corrolation and first 2500ft of wiereline drift but was called away from location. Operator called when on bottom and sent a photo of the wireline counter. I returned to location after wireline had pulled off the well and witnessede a passing MIT. February 21, 2025 Sully Sullivan Well Bore Plug & Abandonment Cannery Loop Unit Hilcorp Alaska LLC PTD 2060580; Sundry 325-040 Photos (4) Test Data: P Casing Removal: Brad Whitten Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2025-0221_Plug_Verification_CLU-11_ss 9 9 9 9 9 9 9 9 9 9 9 9 ¾ 99 9 9 9999 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.04.03 14:25:57 -08'00' 2025-0221_Plug_Verification_CLU-11_photos_ss Page 1 of 3 Plug Verification – Cannery Loop Unit 11 (PTD 2060580) Photos by AOGCC Inspector S. Sullivan 2/21/2025 2025-0221_Plug_Verification_CLU-11_photos_ss Page 2 of 3 Wireline counter for plug depth tag; photo courtesy of Hilcorp 2025-0221_Plug_Verification_CLU-11_photos_ss Page 3 of 3 Set up for plug pressure test Test chart MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 4 Township: 5N Range: 11W Meridian: Seward Drilling Rig: n/a Rig Elevation: n/a Total Depth: 9305 ft MD Lease No.: ADL 324602 Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 136 Feet Csg Cut@ Feet Surface: 13-3/8" O.D. Shoe@ 1602 Feet Csg Cut@ Feet Intermediate: 9-5/8" O.D. Shoe@ 5595 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@ 9284 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Bridge plug 6553 ft 6440 ft 8.6 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 2197 2156 2141 IA 0 0 0 OA 0 0 0 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: 0.7 bbls in and out for MIT. Cement Tag was high; had good cement in bailer. February 14, 2025 Kam StJohn Well Bore Plug & Abandonment CLU 11 Hilcorp Alaska LLC PTD 2060580; Sundry 325-040 Cement sample photo Test Data: P Casing Removal: Wade Hudgens Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2025-0214_Plug_Verification_CLU-11_ksj 9 9 9 9 9 9 99 9 9 9 9 9 9 9 9 9 999 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.03.25 15:11:13 -08'00' Plug Verification – Cannery Loop Unit 11 (PTD 2060580) Photo by AOGCC Inspector K. StJohn 2/14/2025 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Wednesday, February 12, 2025 4:06 PM To:Stefan Reed Cc:Donna Ambruz Subject:RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Stefan, Hilcorp has approval to set the plug below the base of the CINGSA gas storage pool & less than 50’ above the top perf. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Wednesday, February 12, 2025 4:01 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Bryan, We’ve bailed on CLU-11 with slickline for ~4days and based on our correction should be at ~6545’MD which is below the CINGSA base of 6538’MD. Just want to confirm we can set the cibp in this area. It is within 50’ of the top perf, 6583’MD and below the CINGSA. The fill is hard packed sand and difficult to bail. Thanks. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC 2 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, February 6, 2025 12:35 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Hilcorp should attempt to set the plug below the base of the CINGSA pool. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Thursday, February 6, 2025 10:58 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: Re: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Bryan, We drifted with a 2.80" GR for our 3-1/2 plug and tagged high @6520'. We are sizing down to troubleshoot but if needed can we set the plug a bit higher at the tag depth ~6520'. Thank you. -Stefan Get Outlook for iOS From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Wednesday, February 5, 2025 10:10:52 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Thank you Bryan. Regards, CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, February 5, 2025 9:16 AM To: Stefan Reed <Stefan.Reed@hilcorp.com> Subject: RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Stefan, Hilcorp has verbal approval to proceed with this revised procedure, setting a 9-5/8” CIBP at 4400’ and dumping 25’ of cement on top. The following conditions apply: 1. The plug at 6560’ must be tagged & tested to 2000 psi, with opportunity for AOGCC witness provided. 2. BOP test to 3000 psi, annular test to 2500 psi. 3. Plug at 4400’ to be tagged and tested with opportunity to AOGCC witness provided. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Wednesday, February 5, 2025 8:44 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Bryan, As discussed the plan to isolate the exape lines will be: After tubing is pulled set a 9-5/8” CIBP just above the tubing stub. AOGCC witnessed tag and test to 3000psi of plug Dump bail 25’ (~2bbls) on top of the CIBP. Redlined procedure attached. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 4 Can we please have verbal approval to begin work today. Thank you. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Tuesday, February 4, 2025 5:27 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Re: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Bryan, I think that’s a much simpler way and will achieve the same result if you’re okay with it. -Stefan Get Outlook for iOS From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, February 4, 2025 4:43:15 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Subject: RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Stefan, Do you think the dump bailed cement will stay put if you dump it somewhere without a solid base to dump it on? Why not set the CIBP in the casing just above the tubing cut instead of in the tubing, then dump bail on the CIBP? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 5 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Tuesday, February 4, 2025 3:22 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Bryan, My plan would be as follows: 1. Prior to cutting tubing set another cibp 30’-60’ below the cut depth. 2. After tubing is pulled dump bail cement to cover the tubing stub and control lines. 3. MIT casing to 3000psi I redlined the procedure as well which is attached. Thanks. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, February 3, 2025 4:50 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Subject: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Stefan, I’m reviewing your sundry application for plugging this well and have a question: 1. The Excape control lines create a conduit to flow to the perforated intervals below. How do you propose to isolate them with cement? Bryan McLellan CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 6 Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. 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): 9,305'7,912' Casing Collapse Structural Conductor Surface 1,540 psi Intermediate 3,810 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 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: Tubing Size: PRESENT WELL CONDITION SUMMARY Stefan Reed, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 324602 206-058 50-133-20559-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 9,284' 10,160 psi 1,489' Size 115' 9-5/8"5,574' 1,581' MD See Attached Schematic 6,330 psi 3,090 psi 136' 4,355' 136' 1,602' February 1, 2025 3-1/2" 9,284' Perforation Depth MD (ft): 5,595' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Cannery Loop Unit (CLU) 11CO 231A Same 7,894'3-1/2" ~1763psi 9,263' 6,700; 7,840 Length N/A; N/A N/A; N/A 7,915'6,690'5,314' Cannery Loop Beluga Gas 20" 13-3/8" See Attached Schematic m n P s 66 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 11:02 am, Jan 29, 2025 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2025.01.29 10:17:23 -09'00' 325-040 Jan 29, 2025 Tag & Pressure test plug @ 6560' to 2000 psi, 0.25 X shoe depth. Provide 24 hrs notice for AOGCC witness Tag & Pressure test CIBP @ 4400' to 3000 psi after cutting tubing. Provide 24 hrs notice for AOGCC witness February 1, 2025 10-407 X Yes 2/5/25 Bryan McLellan BOP test to 3000 psi, test annular 2500 psi BJM 2/5/25 DSR-1/31/25 X SFD 1/30/2025*&: 02/05/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.05 13:06:32 -09'00' RBDMS JSB 020625 RWO Rev. 1 Well: CLU 11 Date: 1/23/2025 Well Name: CLU-11 API Number: 50-133-20559-00-00 Current Status: Shut in gas well Permit to Drill Number: 206-058 Regulatory Contact: Donna Ambruz 777-8305 Rig: 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 BHP: ~ 1,700 psi @ 5,232’ TVD (Based on RFT data 06/2006) Max. Expected BHP: ~ 2,286 psi @ 5,232’ TVD (Based on normal gradient) Max. Potential Surface Pressure: ~ 1,763 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft) Brief Well Summary Cannery Loop Unit #11 was drilled as a Grass roots EXCAPE completion in 2006 to target gas sands in the Beluga formations. The initial perforations came with water immediately at high rates. A PLT showed most of the water flowing from the top five modules so all perfs above 7,730’ MD were squeezed which did shut off most of the water. After the squeeze, module 10 was re-shot but not frac’d and this added some gas rate. In 2007 a 1-3/4” velocity string was RIH to 8,185’ MD to help unload water. The coil tubing velocity string was found to be sanded in and successfully fished down to 7,912’ in June 2015. The rest of the fish was stuck (unable to recover) and left downhole and isolated with a plug at 7,840’ in June 2015. In July 2015 the UB-E sand was perforated and did not result in gas rate and is thought to be wet. In February 2016 the UB-E sand was isolated with a CIBP and the UB- B sand was perforated. This work brought a puff of hydrocarbon gas but the well was unable to sustain flow. Additional perforations were added to the UB-B sands in 2021 but were unsuccessful and the well has stayed shut-in. The purpose of this work/sundry is to isolate the UB-B perforations and decomplete the well in preparation for a sidetrack. Notes Regarding Wellbore Condition x 8-Jul-2024 - Slickline ran a 2.6” GR to tag depth of 6570’ SLM. Fluid level seen at 660’ SLM x 9.9ppg mud behind 3-1/2” pipe. x CINGSA Top 6282’ MD (4933’ TVD), Bottom 6538’ (5170’ TVD). E-Line Procedure 1. RU E-Line and pressure control equipment. PT lubricator to 2,500 psi High / 250 psi Low 2. RIH w/ 3-1/2” CIBP and set @ ~6560’ 3. Load tubing w/ produced water. a. Provide AOGCC 24hr notice to witness pressure test and tag of plug. 4. RIH and tag plug to confirm depth and pressure test to 1500psi 5. Dump bail 25’ of cement on top of plug (~10gals) 6. RIH and cut tubing @ ~4406’ (2’ above collar) (pressure tubing to equalize w/ 9.9ppg mud in IA) 7. RIH and cut tubing again at previous cut. This is to cut excape control lines behind tubing. 8. RD E-Line Pumping Procedure Pressure test to 2000 psi, 0.25 X shoe depth. Provide 24 hrs notice for AOGCC witness -bjm Per the CBL, the CNGSA gas storage pool is cement- isolated with excellent bond. SFD CINGSA Top 6282’ MD (4933’ TVD), Bottom 6538’ (5170’ TVD RWO Rev. 1 Well: CLU 11 Date: 1/23/2025 Ensure 12hrs has elapsed between cement dumped and pumping. 9. RU pump unit and pressure test equipment to 3000psi 10. Use source/lease water to confirm communication between tubing and IA. 11. Once TxIA communication confirmed circulate well over to water at max rate until clean returns. 12. Perform CMIT TxIA to 3000psi 13. RDMO pump truck. Workover Procedure 14. MIRU 401 workover rig 15. Install TWC, ND tree, NU BOP 16. Test BOPE ¾Test 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). ¾If 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. ¾BOPs will be closed as needed to circulate the well during this workover. 17. Pull TWC 18. Pick up on hanger 19. Pull and lay down tubing Note: record number clamps/bands for control lines and cable, save centralizers (do not drop set screws downhole) Contingency: If equipment, cable, or control line are left downhole, a casing scraper run will be made to push it to bottom. 20. RU Eline 21. Log CBL from ~4400’ to Surface 22. Set 9-5/8” CIBP @ ~4350’ (5’ above nearest collar) 23. RD Eline 24. ND BOP, NU dry hole tree 25. 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 Set CIBP at 4400' Log CBL from ~4400’ to Surface CBL Log interval over CINGSA pool Need to plug Excape lines with cement or place cement above cut lines. Per Stefan Reed email 2/5/25. -bjm 23. Tag top of plug and test to 3000psi Provide 24hr notice to AOGCC for witness 24. Dump bail 25' of cement (~2bbls) on top of plug. State/Prov:Alaska Country:USA 35.0' 2/12/2016 Well Name & Number:Cannery Loop #11 Lease:ADL-324602 County or Parish:Kenai Peninsula Borough ngle @KOP and Depth:± 3° / 220 ft @ 650' MD Angle/Perfs:4º ĺ 1ºMaximum Deviation:45.6º @ 2,883' Date Completed:5/18/2006 Ground Level (above MSL):RKB (above GL):21.0' Revised By:Donna Ambruz Downhole Revision Date:Schematic Revision Date:7/10/2024 TD 9,305' MD 7,915 TVD Excape System Details - 11 Excape modules placed -Green control line fired module 1 -Yellow control line fired modules 2 thru 7 -Red contol line fired modules 8 thru 11 - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB)( Beluga Zones): Mod-11 6,593' - 6,603' Not Shot UBE 6,726' - 6,746' (7/7/15) (Isolated) Mod-10 7,373' - 7,383' (Perfed 5/1/07) (Isolated) Perf: 7,383' - 7,400' (Perfed 5/1/07) (Isolated) Mod- 9 7,472' - 7,482' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 8 7,686' - 7,696' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 7 7,868' - 7,878' Not Shot Mod- 6 7,929' - 7,939' (Perfed 4/1/07) (Isolated) Perf: 7,939' - 7,946' (Perfed 4/1/07) (Isolated) Mod- 5 8,208' - 8,218' (Frac'd 9/28/06) (Isolated) Mod- 4 8,384' - 8,394' (Frac'd 9/28/06) (Isolated) Mod- 3 8,496' - 8,506' (Frac'd 9/28/06) (Isolated) Mod- 2 8,606' - 8,616' (Frac'd 9/28/06) (Isolated) Mod- 1 9,085' - 9,095' (Frac'd 9/28/06) (Isolated) Top of Cement (Bond Log) @ 4,440' MD Excape System Details - 10 Conventional flappers- Mod-1 no flapper - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module-11 6,613'Module-10 7,390'Module- 9 7,490'Module- 8 7,703' (Broken CT 9/28/2006)Module- 7 7,886'Module- 6 7,948'Module- 5 8,227' (Broken CT 9/28/2006)Module- 4 8,403' (Broken CT 9/28/2006)Module- 3 8,515'Module- 2 8,625' (Broken CT 9/28/2006) Permit #: 206-058API #: 50-133-20559-00Property Des:ADL-324602KB Elevation:56' (21'AGL)Lat:60°33' 10.707" NLong: 151°13' 07.001" WSpud Date: 04/28/2006TD Reached: 05/11/2006Rig Released:05/15/2006 CLU-11 Pad-3 2,491' FSL, 2,291' FWL Sec. 4, T5N, R11W, S.M. Tree cxn = 6-1/2" Otis PBTD 9,247' MD 7,857' TVD Velocity String 1-3/4" HO70FF (0.125" WT) Install 7/21/07; Partially removed Top Bottom MD 7,912' 8,185' TVD 6,522' 6,795' BHA: 2.5" OD x 1.5" ID grapple connector 2.5" OD x 1.5" ID x 10' weight bar w/ drain 2.5" OD x 1.135" ID NoGo profile nipple 2.48" OD x 1.5" guide nose Slickline tag EOVstrg 8225' (4/18/12) Conductor 20" X-52 131 ppf Top Bottom MD 0' 136' TVD 0' 136' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of 12.0 ppg, Type 1 cmt Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' TVD 0' 4,355' 12-1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail Production Tubing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 9,284' TVD 0' 7,894' 8-1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt VELOCITY STRING FISH: Top of Coil:1-3/4" coil @ 7,912' cut with radial torch, milled down with 2.75" mill on 6/13/15 (Fill on backside of coil ) Fish:4.1' of 1.0" wt bar lost 6/06/15 @ 7,919' Fish:4.0' of 1.0" wt bar lost 6/04/15 @ 8,162' Plug:PXN plug set 5/16/15 @ 8,209' Sterling C1 Interval: SCHEMATIC Cast Iron Bridge Plug @ 7,840' Dump bail 10' of cement UBE Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date UB-B 6,583' 6,592' 2-3/8" 5 Open 02-12-16 UB-B 6,591' 6,601' 2-1/2" 5 Open 04-21-21 Cast Iron Bridge Plug @ 6,700' Dump bail 10' of cement TOC 6,690' 02/10/16 UB-BCINGSA Base 6,538’ MD 5,170’ TVD UB-BCINGSA Base 6,538’ MD 5,170’ TVD State/Prov:Alaska Country:USA 35.0' 2/12/2016 Well Name & Number:Cannery Loop #11 Lease:ADL-324602 County or Parish:Kenai Peninsula Borough ngle @KOP and Depth:± 3° / 220 ft @ 650' MD Angle/Perfs:4º ĺ 1ºMaximum Deviation:45.6º @ 2,883' Date Completed:5/18/2006 Ground Level (above MSL):RKB (above GL):21.0' Revised By:Stefan Reed Downhole Revision Date:Schematic Revision Date:1/24/2025 TD 9,305' MD 7,915 TVD Excape System Details - 11 Excape modules placed -Green control line fired module 1 -Yellow control line fired modules 2 thru 7 -Red contol line fired modules 8 thru 11 - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB)( Beluga Zones): Mod-11 6,593' - 6,603' Not Shot UBE 6,726' - 6,746' (7/7/15) (Isolated) Mod-10 7,373' - 7,383' (Perfed 5/1/07) (Isolated) Perf: 7,383' - 7,400' (Perfed 5/1/07) (Isolated) Mod- 9 7,472' - 7,482' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 8 7,686' - 7,696' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 7 7,868' - 7,878' Not Shot Mod- 6 7,929' - 7,939' (Perfed 4/1/07) (Isolated) Perf: 7,939' - 7,946' (Perfed 4/1/07) (Isolated) Mod- 5 8,208' - 8,218' (Frac'd 9/28/06) (Isolated) Mod- 4 8,384' - 8,394' (Frac'd 9/28/06) (Isolated) Mod- 3 8,496' - 8,506' (Frac'd 9/28/06) (Isolated) Mod- 2 8,606' - 8,616' (Frac'd 9/28/06) (Isolated) Mod- 1 9,085' - 9,095' (Frac'd 9/28/06) (Isolated) Top of Cement (Bond Log) @ 4,440' MD Excape System Details - 10 Conventional flappers- Mod-1 no flapper - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module-11 6,613'Module-10 7,390'Module- 9 7,490'Module- 8 7,703' (Broken CT 9/28/2006)Module- 7 7,886'Module- 6 7,948'Module- 5 8,227' (Broken CT 9/28/2006)Module- 4 8,403' (Broken CT 9/28/2006)Module- 3 8,515'Module- 2 8,625' (Broken CT 9/28/2006) Permit #: 206-058API #: 50-133-20559-00Property Des:ADL-324602KB Elevation:56' (21'AGL)Lat:60°33' 10.707" NLong: 151°13' 07.001" WSpud Date: 04/28/2006TD Reached: 05/11/2006Rig Released:05/15/2006 CLU-11 Pad-3 2,491' FSL, 2,291' FWL Sec. 4, T5N, R11W, S.M. Tree cxn = 6-1/2" Otis PBTD 9,247' MD 7,857' TVD Velocity String 1-3/4" HO70FF (0.125" WT) Install 7/21/07; Partially removed Top Bottom MD 7,912' 8,185' TVD 6,522' 6,795' BHA: 2.5" OD x 1.5" ID grapple connector 2.5" OD x 1.5" ID x 10' weight bar w/ drain 2.5" OD x 1.135" ID NoGo profile nipple 2.48" OD x 1.5" guide nose Slickline tag EOVstrg 8225' (4/18/12) Conductor 20" X-52 131 ppf Top Bottom MD 0' 136' TVD 0' 136' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of 12.0 ppg, Type 1 cmt Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' TVD 0' 4,355' 12-1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail Production Tubing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 9,284' TVD 0' 7,894' 8-1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt VELOCITY STRING FISH: Top of Coil:1-3/4" coil @ 7,912' cut with radial torch, milled down with 2.75" mill on 6/13/15 (Fill on backside of coil ) Fish:4.1' of 1.0" wt bar lost 6/06/15 @ 7,919' Fish:4.0' of 1.0" wt bar lost 6/04/15 @ 8,162' Plug:PXN plug set 5/16/15 @ 8,209' Sterling C1 Interval: PROPOSED 1/24/25 Cast Iron Bridge Plug @ 7,840' Dump bail 10' of cement UBE Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date UB-B 6,583' 6,592' 2-3/8" 5 Isolated 02-12-16 UB-B 6,591' 6,601' 2-1/2" 5 Isolated 04-21-21 Cast Iron Bridge Plug @ 6,700' Dump bail 10' of cement TOC 6,690' 02/10/16 UB-B @ 6 700' CINGSA Base 6,538’ MD 5,170’ TVD 9-5/8" CIBP Set @ ~4350' Cut tubing and control lines @ ~4406'Set 3-1/2" CIBP @ ~6560' w/ 25' of cement on top. Est TOC 6535' It ditC CINGSA Top 6,282’ MD 4,933’ TVD 4400' -bjm 25' of cement 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 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 1 McLellan, Bryan J (OGC) From:McLellan, Bryan J (OGC) Sent:Wednesday, February 5, 2025 9:16 AM To:Stefan Reed Subject:RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Stefan, Hilcorp has verbal approval to proceed with this revised procedure, setting a 9-5/8” CIBP at 4400’ and dumping 25’ of cement on top. The following conditions apply: 1. The plug at 6560’ must be tagged & tested to 2000 psi, with opportunity for AOGCC witness provided. 2. BOP test to 3000 psi, annular test to 2500 psi. 3. Plug at 4400’ to be tagged and tested with opportunity to AOGCC witness provided. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Wednesday, February 5, 2025 8:44 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Bryan, As discussed the plan to isolate the exape lines will be: x After tubing is pulled set a 9-5/8” CIBP just above the tubing stub. x AOGCC witnessed tag and test to 3000psi of plug x Dump bail 25’ (~2bbls) on top of the CIBP. Redlined procedure attached. Can we please have verbal approval to begin work today. Thank you. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC 2 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Tuesday, February 4, 2025 5:27 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Re: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Bryan, I think that’s a much simpler way and will achieve the same result if you’re okay with it. -Stefan Get Outlook for iOS From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, February 4, 2025 4:43:15 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Subject: RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Stefan, Do you think the dump bailed cement will stay put if you dump it somewhere without a solid base to dump it on? Why not set the CIBP in the casing just above the tubing cut instead of in the tubing, then dump bail on the CIBP? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Tuesday, February 4, 2025 3:22 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 3 Bryan, My plan would be as follows: 1. Prior to cutting tubing set another cibp 30’-60’ below the cut depth. 2. After tubing is pulled dump bail cement to cover the tubing stub and control lines. 3. MIT casing to 3000psi I redlined the procedure as well which is attached. Thanks. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, February 3, 2025 4:50 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Subject: [EXTERNAL] CLU-11 (PTD 206-058) Plug for Redrill Sundry questions Stefan, I’m reviewing your sundry application for plugging this well and have a question: 1. The Excape control lines create a conduit to flow to the perforated intervals below. How do you propose to isolate them with cement? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 4 above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,305 feet 6700, 7840 feet true vertical 7,915 feet 7,912 feet Effective Depth measured 6,690 feet N/A feet true vertical 5,314 feet N/A feet 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 9,284' MD 7,894' TVD Packers and SSSV (type, measured and true vertical depth)N/A; N/A N/A; N/A N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 10,160psi 136' 1,489' 6,330psi 3,090psi Collapse 1,540psi 3,810psi 10,530psi Casing Structural 20" 13-3/8" 9-5/8" Length 115' 1,581' 5,574' 9,263' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 3 Casing Pressure Liner 0 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-159 0 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 5 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 206-058 50-133-20559-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 50 Cannery Loop Unit (CLU) 11 N/A ADL 324602 5,595' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Cannery Loop Unit / Beluga PoolN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 3-1/2"9,284' 4,355' 7,894' WINJ WAG 0 Water-Bbl MD 136' 1,602' 0 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Meredith Guhl at 10:00 am, May 17, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.17 09:53:31 -08'00' Taylor Wellman (2143) DSR-5/17/21BJM 8/10/21 SFD 5/20/2021RBDMS HEW 5/17/2021 Rig Start Date End Date CTU 4/21/21 4/21/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20559-00-00 206-058 Daily Operations: Well Name CLU-11 04/21/2021 - Wednesday PTW, JSA and SIMOPS. Spotted equipment, rigged up hard lines and lubricator. Bottom swab flange leaked at 500psi. Got some wrenches and tightened bolts. Tried again and still leaked. Tightened some more and slow leak but still leak. Called lead op and discussed with Clint Chanley. Decision made to change ring gasket. Clint brought one out and was changed. PT to 250 low and 2,500 psi high. RIH w/GPT tool and tie into CBL dated 2006. Found fluid level at 510' with 163 psi. Found fluid again at 3,420' at 1k scf/m at 1,255 psi. Back on line again and pushed fluid as far as we could to 6,603' and no fluid' with 1,600 psi. Ran correlation log and sent to town. Town said to add 13'. Added 13'. POOH MU spiral strip gun on line, Bleed tubing down to 1,547 psi. Grease pump started acting up and quit pumping right. Fixed grease pump while Joe w/AKE-line went to shop to get one RIH w/ 2-1/2" x 10' Spiral Strip Gun, 5 spf, 60 deg phase and tie into GPT log. Run correlation log and send to town. Town said to subtract 5' from log. Subtract 5', spot and fire gun from 6,591' to 6,601' with 1,535 psi on tubing. Lost 4 to 500 lb line tension and got it back in 12'. After 5 min - 1,536 psi, 10 min -1,537 psi, and 15 min - 1,537 psi. POOH. All shots fired. Rig down AKE-Line and Fox Energy of well. Well be moving to KBU 43-07X tomorrow morning. m 6,591' to 6,601' State/Prov:Alaska Country:USA 35.0' 2/12/2016 Well Name & Number:Cannery Loop #11 Lease:ADL-324602 County or Parish:Kenai Peninsula Borough ngle @KOP and Depth:± 3° / 220 ft @ 650' MD Angle/Perfs:4º ĺ 1ºMaximum Deviation:45.6º @ 2,883' Date Completed:5/18/2006 Ground Level (above MSL):RKB (above GL):21.0' Revised By:Donna Ambruz Downhole Revision Date:Schematic Revision Date:4/29/2021 TD 9,305' MD 7,915 TVD Excape System Details - 11 Excape modules placed -Green control line fired module 1 -Yellow control line fired modules 2 thru 7 -Red contol line fired modules 8 thru 11 - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB)( Beluga Zones): Mod-11 6,593' - 6,603' Not Shot UBE 6,726' - 6,746' (7/7/15) (Isolated) Mod-10 7,373' - 7,383' (Perfed 5/1/07) (Isolated) Perf: 7,383' - 7,400' (Perfed 5/1/07) (Isolated) Mod- 9 7,472' - 7,482' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 8 7,686' - 7,696' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 7 7,868' - 7,878' Not Shot Mod- 6 7,929' - 7,939' (Perfed 4/1/07) (Isolated) Perf: 7,939' - 7,946' (Perfed 4/1/07) (Isolated) Mod- 5 8,208' - 8,218' (Frac'd 9/28/06) (Isolated) Mod- 4 8,384' - 8,394' (Frac'd 9/28/06) (Isolated) Mod- 3 8,496' - 8,506' (Frac'd 9/28/06) (Isolated) Mod- 2 8,606' - 8,616' (Frac'd 9/28/06) (Isolated) Mod- 1 9,085' - 9,095' (Frac'd 9/28/06) (Isolated) Top of Cement (Bond Log) @ 4,440' MD Excape System Details - 10 Conventional flappers- Mod-1 no flapper - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module-11 6,613'Module-10 7,390'Module- 9 7,490'Module- 8 7,703' (Broken CT 9/28/2006)Module- 7 7,886'Module- 6 7,948'Module- 5 8,227' (Broken CT 9/28/2006)Module- 4 8,403' (Broken CT 9/28/2006)Module- 3 8,515'Module- 2 8,625' (Broken CT 9/28/2006) Permit #: 206-058API #: 50-133-20559-00Property Des:ADL-324602KB Elevation:56' (21'AGL)Lat:60°33' 10.707" NLong: 151°13' 07.001" WSpud Date: 04/28/2006TD Reached: 05/11/2006Rig Released:05/15/2006 CLU-11 Pad-3 2,491' FSL, 2,291' FWL Sec. 4, T5N, R11W, S.M. Tree cxn = 6-1/2" Otis PBTD 9,247' MD 7,857' TVD Velocity String 1-3/4" HO70FF (0.125" WT) Install 7/21/07; Partially removed Top Bottom MD 7,912' 8,185' TVD 6,522' 6,795' BHA: 2.5" OD x 1.5" ID grapple connector 2.5" OD x 1.5" ID x 10' weight bar w/ drain 2.5" OD x 1.135" ID NoGo profile nipple 2.48" OD x 1.5" guide nose Slickline tag EOVstrg 8225' (4/18/12) Conductor 20" X-52 131 ppf Top Bottom MD 0' 136' TVD 0' 136' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of 12.0 ppg, Type 1 cmt Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' TVD 0' 4,355' 12-1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail Production Tubing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 9,284' TVD 0' 7,894' 8-1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt VELOCITY STRING FISH: Top of Coil:1-3/4" coil @ 7,912' cut with radial torch, milled down with 2.75" mill on 6/13/15 (Fill on backside of coil) Fish:4.1' of 1.0" wt bar lost 6/06/15 @ 7,919' Fish:4.0' of 1.0" wt bar lost 6/04/15 @ 8,162' Plug:PXN plug set 5/16/15 @ 8,209' Sterling C1 Interval: SCHEMATIC Cast Iron Bridge Plug @ 7,840' Dump bail 10' of cement UBE Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date UB-B 6,583' 6,592' 2-3/8" 5 Open 02-12-16 UB-B 6,591' 6,6021 2-1/2" 5 Open 04-21-21 Cast Iron Bridge Plug @ 6,700' Dump bail 10' of cement TOC 6,690' 02/10/16 UB-B 6601UB-B 6,591' 6,6021 2-1/2" 5 Open 04-21-21660166016601, Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 05/10/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 11 (PTD 206-058) PERFORATING RECORD 04/22/2021 Please include current contact information if different from above. PTD: 2060580 E-set: 35110 05/11/2021 1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,305'7,912' Casing Collapse Structural Conductor Surface 1,540 psi Intermediate 3,810 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 Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng tkramer@hilcorp.com 7,915'6,690'5,314'1,763 6,700; 7,840 N/A; N/A N/A; N/A Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 324602 206-058 50-133-20559-00-00 Cannery Loop Unit (CLU) 11 Cannery Loop Unit / Beluga Pool Length Size CO 231A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 9.3# / L-80 TVD Burst 9,284' 10,160 psi MD 6,330 psi 3,090 psi 136' 1,489' 4,355' 136' 1,602' 7,894'3-1/2" 20" 13-3/8" 115' 9-5/8"5,574' 1,581' 9,284' Perforation Depth MD (ft): 5,595' See Attached Schematic 9,263' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: April 16, 2021 3-1/2" m n P t _ 66 Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:53 am, Apr 01, 2021 321-159 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.03.31 23:04:44 -08'00' Taylor Wellman (2143) DSR-4/1/21 X DLB 04/01/2021 10-404 BJM 4/9/21 Comm 4/12/21 dts 4/9 2021 JLC 4/12/2021 RBDMS HEW 4/12/2021 Well Prognosis Well: CLU-11 Date: 3/31/2021 Well Name: CLU-11 API Number: 50-133-20559-00-020 Current Status: SI Gas Well Leg: N/A Estimated Start Date: April 19, 2021 Rig: E-line Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-058 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) Second Call Engineer: Ryan Rupert (907)-777-8503 (O) (907)-301-1736 (C) AFE Number: Current BHP: ~ 1,700 psi @ 5,232’ TVD (Based on RFT data 06/2006) Max. Expected BHP: ~ 2,286 psi @ 5,232’ TVD (Based on normal gradient) Max. Potential Surface Pressure: ~ 1,763 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft) Brief Well Summary Cannery Loop Unit #11 was drilled as a Grass roots EXCAPE completion in 2006 to target gas sands in the Beluga formations. The initial perforations came with water immediately at high rates. A PLT showed most of the water flowing from the top five modules so all perfs above 7,730’ MD were squeezed which did shut off most of the water. After the squeeze, module 10 was re-shot but not frac’d and this added some gas rate. In 2007 a 1-3/4” velocity string was RIH to 8,185’ MD to help unload water. The coil tubing velocity string was found to be sanded in and successfully fished down to 7,912’ in June 2015. The rest of the fish was stuck (unable to recover) and left downhole and isolated with a plug at 7,840’ in June 2015. In July 2015 the UB-E sand was perforated and did not result in gas rate and is thought to be wet. In February 2016 the UB-E sand was isolated with a CIBP and the UB- B sand was perforated. This work brought a puff of hydrocarbon gas but the well was unable to sustain flow. The purpose of this work/sundry is to add the UB-1 sand and see if it is commercial. Notes Regarding Wellbore Condition x Well is SI, unable to sustain flow Safety Concerns x Discuss Nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter x Consider tank placement based on wind direction and current weather forecast (venting nitrogen during this job) x Ensure all crews are aware of stop job authority E-line Procedure 1. MIRU E-line and pressure control equipment. PT lubricator to 250 psi Low / 2,000 psi High. a. Tree connection is 6.5” OTIS. 2. RIH with GPT tool and find fluid level. If fluid is over the depth of the new perfs, discuss using Nitrogen with the Operations Engineer. 3. If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 4. RU perf guns. Note: This well has an unfired EXCAPE module across the zone of interest. Prior to procedure, we will pressure up and see if the module will fire. Well Prognosis Well: CLU-11 Date: 3/31/2021 5. RIH and perforate the below interval: a. Pressure up well to 1,500 psi before perforating. b. Proposed perfs also shown on the proposed schematic in red font. c. Final perfs tie-in sheet will be provided in the field for exact perf intervals. d. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. e. Use Gamma/CCL to correlate. f. Spacing allowance based on CO 231A. g. Install Crystal Gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. h. Record 5, 10 and 15 minute pressures after firing guns. 6. POOH. 7. RD E-Line. 8. Turn well over to production. E-Line Procedure (Contingency) 1. Depending on fluid level, a 3-1/2” Tubing Patch may be set across the existing UB-B perforations if they make water or sand. Slickline Procedure (Contingency) 1. Depending on fluid level, the well may be swabbed to remove water from across the new perforations. Attachments 1. Actual Schematic 2. Proposed Schematic 3. Standard Well Procedure – N2 Operations Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Upper Beluga UB-B ±6,591’ ±6,604’ +5,220’ +5,233’ ±13 State/Prov:Alaska Country:USA 35.0' 2/12/2016 Date Completed:5/18/2006 Ground Level (above MSL):RKB (above GL):21.0' Revised By:Donna Ambruz Downhole Revision Date:Schematic Revision Date:2/16/2016 ngle @KOP and Depth:± 3° / 220 ft @ 650' MD Angle/Perfs:4º ĺ 1ºMaximum Deviation:45.6º @ 2,883' Well Name & Number:Cannery Loop #11 Lease:ADL-324602 County or Parish:Kenai Peninsula Borough TD 9,305' MD 7,915 TVD Excape System Details - 11 Excape modules placed - Green control line fired module 1 - Yellow control line fired modules 2 thru 7 - Red contol line fired modules 8 thru 11 - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB)( Beluga Zones): Mod-11 6,593' - 6,603' Not Shot UBE 6,726' - 6,746' (7/7/15) (Isolated) Mod-10 7,373' - 7,383' (Perfed 5/1/07) (Isolated) Perf: 7,383' - 7,400' (Perfed 5/1/07) (Isolated) Mod- 9 7,472' - 7,482' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 8 7,686' - 7,696' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 7 7,868' - 7,878' Not Shot Mod- 6 7,929' - 7,939' (Perfed 4/1/07) (Isolated) Perf: 7,939' - 7,946' (Perfed 4/1/07) (Isolated) Mod- 5 8,208' - 8,218' (Frac'd 9/28/06) (Isolated) Mod- 4 8,384' - 8,394' (Frac'd 9/28/06) (Isolated) Mod- 3 8,496' - 8,506' (Frac'd 9/28/06) (Isolated) Mod- 2 8,606' - 8,616' (Frac'd 9/28/06) (Isolated) Mod- 1 9,085' - 9,095' (Frac'd 9/28/06) (Isolated) Top of Cement (Bond Log) @ 4,440' MD Excape System Details - 10 Conventional flappers - Mod-1 no flapper - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module-11 6,613' Module-10 7,390' Module- 9 7,490' Module- 8 7,703' (Broken CT 9/28/2006) Module- 7 7,886' Module- 6 7,948' Module- 5 8,227' (Broken CT 9/28/2006) Module- 4 8,403' (Broken CT 9/28/2006) Module- 3 8,515' Module- 2 8,625' (Broken CT 9/28/2006) Permit #: 206-058 API #: 50-133-20559-00 Property Des: ADL-324602 KB Elevation: 56' (21'AGL) Lat: 60° 33' 10.707" N Long: 151° 13' 07.001" W Spud Date: 04/28/2006 TD Reached: 05/11/2006 Rig Released: 05/15/2006 CLU-11 Pad-3 2,491' FSL, 2,291' FWL Sec. 4, T5N, R11W, S.M. Tree cxn = 6-1/2" Otis PBTD 9,247' MD 7,857' TVD Velocity String 1-3/4" HO70FF (0.125" WT) Install 7/21/07; Partially removed Top Bottom MD 7,912' 8,185' TVD 6,522' 6,795' BHA: 2.5" OD x 1.5" ID grapple connector 2.5" OD x 1.5" ID x 10' weight bar w/ drain 2.5" OD x 1.135" ID NoGo profile nipple 2.48" OD x 1.5" guide nose Slickline tag EOVstrg 8225' (4/18/12) Conductor 20" X-52 131 ppf Top Bottom MD 0' 136' TVD 0' 136' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of 12.0 ppg, Type 1 cmt Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' TVD 0' 4,355' 12-1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail Production Tubing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 9,284' TVD 0' 7,894' 8-1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt VELOCITY STRING FISH: Top of Coil: 1-3/4" coil @ 7,912' cut with radial torch, milled down with 2.75" mill on 6/13/15 (Fill on backside of coil) Fish: 4.1' of 1.0" wt bar lost 6/06/15 @ 7,919' Fish: 4.0' of 1.0" wt bar lost 6/04/15 @ 8,162' Plug: PXN plug set 5/16/15 @ 8,209' Sterling C1 Interval: SCHEMATIC Cast Iron Bridge Plug @ 7,840' Dump bail 10' of cement UBE Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date UB-B 6,583' 6,592' 2-3/8" 5 Open 02-12-16 Cast Iron Bridge Plug @ 6,700' Dump bail 10' of cement TOC 6,690' 02/10/16 UB-B State/Prov:Alaska Country:USA 35.0' 2/12/2016 Well Name & Number:Cannery Loop #11 Lease:ADL-324602 County or Parish:Kenai Peninsula Borough ngle @KOP and Depth:± 3° / 220 ft @ 650' MD Angle/Perfs:4º ĺ 1ºMaximum Deviation:45.6º @ 2,883' Date Completed:5/18/2006 Ground Level (above MSL):RKB (above GL):21.0' Revised By:Donna Ambruz Downhole Revision Date:Schematic Revision Date:10/2/2019 TD 9,305' MD 7,915 TVD Excape System Details - 11 Excape modules placed -Green control line fired module 1 -Yellow control line fired modules 2 thru 7 -Red contol line fired modules 8 thru 11 - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB)( Beluga Zones): Mod-11 6,593' - 6,603' Not Shot UBE 6,726' - 6,746' (7/7/15) (Isolated) Mod-10 7,373' - 7,383' (Perfed 5/1/07) (Isolated) Perf: 7,383' - 7,400' (Perfed 5/1/07) (Isolated) Mod- 9 7,472' - 7,482' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 8 7,686' - 7,696' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 7 7,868' - 7,878' Not Shot Mod- 6 7,929' - 7,939' (Perfed 4/1/07) (Isolated) Perf: 7,939' - 7,946' (Perfed 4/1/07) (Isolated) Mod- 5 8,208' - 8,218' (Frac'd 9/28/06) (Isolated) Mod- 4 8,384' - 8,394' (Frac'd 9/28/06) (Isolated) Mod- 3 8,496' - 8,506' (Frac'd 9/28/06) (Isolated) Mod- 2 8,606' - 8,616' (Frac'd 9/28/06) (Isolated) Mod- 1 9,085' - 9,095' (Frac'd 9/28/06) (Isolated) Top of Cement (Bond Log) @ 4,440' MD Excape System Details - 10 Conventional flappers- Mod-1 no flapper - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module-11 6,613'Module-10 7,390'Module- 9 7,490'Module- 8 7,703' (Broken CT 9/28/2006)Module- 7 7,886'Module- 6 7,948'Module- 5 8,227' (Broken CT 9/28/2006)Module- 4 8,403' (Broken CT 9/28/2006)Module- 3 8,515'Module- 2 8,625' (Broken CT 9/28/2006) Permit #: 206-058API #: 50-133-20559-00Property Des:ADL-324602KB Elevation:56' (21'AGL)Lat:60°33' 10.707" NLong: 151°13' 07.001" WSpud Date: 04/28/2006TD Reached: 05/11/2006Rig Released:05/15/2006 CLU-11 Pad-3 2,491' FSL, 2,291' FWL Sec. 4, T5N, R11W, S.M. Tree cxn = 6-1/2" Otis PBTD 9,247' MD 7,857' TVD Velocity String 1-3/4" HO70FF (0.125" WT) Install 7/21/07; Partially removed Top Bottom MD 7,912' 8,185' TVD 6,522' 6,795' BHA: 2.5" OD x 1.5" ID grapple connector 2.5" OD x 1.5" ID x 10' weight bar w/ drain 2.5" OD x 1.135" ID NoGo profile nipple 2.48" OD x 1.5" guide nose Slickline tag EOVstrg 8225' (4/18/12) Conductor 20" X-52 131 ppf Top Bottom MD 0' 136' TVD 0' 136' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of 12.0 ppg, Type 1 cmt Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' TVD 0' 4,355' 12-1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail Production Tubing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 9,284' TVD 0' 7,894' 8-1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt VELOCITY STRING FISH: Top of Coil:1-3/4" coil @ 7,912' cut with radial torch, milled down with 2.75" mill on 6/13/15 (Fill on backside of coil) Fish:4.1' of 1.0" wt bar lost 6/06/15 @ 7,919' Fish:4.0' of 1.0" wt bar lost 6/04/15 @ 8,162' Plug:PXN plug set 5/16/15 @ 8,209' Sterling C1 Interval: PROPOSED SCHEMATIC Cast Iron Bridge Plug @ 7,840' Dump bail 10' of cement UBE Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date UB-B 6,583' 6,592' 2-3/8" 5 Open 02-12-16 UB-B 6,591' 6,604' 2-3/8" 5 Proposed TBD Cast Iron Bridge Plug @ 6,700' Dump bail 10' of cement TOC 6,690' 02/10/16 UB-B STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review 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 Nitrogen Tank. 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 supplier has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Cannery Loop Field, Beluga Pool, Cannery Loop 11 Permit to Drill Number: 206-058 Sundry Number: 319-454 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.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, 1�2 Jer .Price Chair DATED this eb day of October, 2019. r 131)MSOJOCT 10 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n AAr 9F 9A0 i 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate Q ' Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter CasingEl ❑ Other: 2. Operator Name: Hilcorp Alaska, LLC 4. Current Well Class: 5. Permit to Drill Number: Exploratory ❑ Development Q , Stratigraphic ❑ Service ❑ 206-058 ' 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-133-20559-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231 ' Will planned perforations require a spacing exception? Yes ❑ No ❑✓ Cannery Loop #11 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 324602 Cannery Loop Unit / Beluga 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): 9,305' 7,915' 9,247' 7,857' 1,763 psi 7,840' 7,912' Casing Length Size MD TVD Burst Collapse Structural Conductor 115' 20" 136' 136' Surface 1,581' 13-3/8" 1,602' 1,489' 3,090 psi 1,540 psi Intermediate 5,574' 9-5/8" 5,595' 4,355' 6,330 psi 3,810 psi Production 9,263' 3-1/2" 9,284' 7,894' 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 9,284 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 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Strati ra hic g p ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: October 16th, 2019 Operations: [:]WINJ [:]WDSPL E] Suspended F-1Commencing OIL 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. Contact Christina Twogood Printed Name Be York 777-8345 Email ctwogood@hilcorp.com Title Operations Manager 777-8443 4Phone Signature Date i D u'r COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 310 f `� Plug Integrity ❑ BOP Test Q Mechanical Integrity Test ❑ Location Clearance ❑ Other: RMS �" 10CT 10 2019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception /— U Required? Yes ❑ No Subsequent Form Required: 2.APPROVED BY { 0 IG r Approved by: Y COMMISSIONER DI THE COMMISSION Date: 1 �j'T'/k %� Y 17 f�.,j,, IC G Submit Form and Form 10-403 Revis 1 015 / Approved applica i I .1 t S�' Lthe date of approvaC./,!`-Ci ('o iahments in plicate R Ilil.wp Alaska. LL Well Prognosis Well: CLU -11 Date: 10/2/2019 Well Name: CLU -11 API Number: 50-133-20559-00-020 Current Status: Shut In Gas Well Leg: N/A Estimated Start Date: October 14, 2019 Rig: N/A Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-058 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: Current BHP: — 1,700 psi @ 5,232' TDV (Based on RFT data 0612006) Max. Expected BHP: — 2,286 psi @ 5,232' TVD (Based on normal gradient) Max. Potential Surface Pressure: — 1,763 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft) Brief Well Summary Cannery Loop Unit #11 was drilled as a Grass roots EXCAPE completion in 2006 to target gas sands in the Beluga formations. The initial perforations came with water immediately at high rates. A PLT showed most of the water flowing from the top five modules so all perfs above 7,730' MD were squeezed which did shut off most of the water. After the squeeze, module 10 was re -shot but not frac'd and this added some gas rate. In 2007 a 1-3/4" velocity string was RIH to 8,185' MD to help unload water. The coil tubing velocity string was found to be sanded in and successfully fished down to 7,912' in June 2015. The rest of the fish was stuck (unable to recover) and left downhole and isolated with a plug at 7,840' in June 2015. In July 2015 the UB -E sand was perforated and did not result in gas rate and is thought to be wet. In February 2016 the UB -E sand was isolated with a CIBP and the UB - B sand was perforated. The purpose of this work/sundry is to perforate the UB -B sand. Notes Regarding Wellbore Condition • Well is SI, unable to sustain flow Safety Concerns • Discuss Nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter • Consider tank 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. MIRU E -line and pressure control equipment. PT lubricator to 250 psi Low / 2,000 psi High. a. Tree connection is 6.5" OTIS. 2. RIH with GPT tool and find fluid level. If fluid is over the depth of the new perfs, discuss using Nitrogen with the Operations Engineer. 3. If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 4. RU perfguns. H ffik.p Alk.. LL 5. RIH and perforate the below interval: Well Prognosis Well: CLU -11 Date:10/2/2019 Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT 1. Upper Beluga I UB -B ±6,594' ±6,604' +5,222' +5,232' 1±10 a. Pressure up well to 1,500 psi before perforating. b. Proposed perfs also 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. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. e. Use Gamma/CCL to correlate. f. Spacing allowance based on CO 231. g. Install Crystal Gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. h. Record 5, 10 and 15 minute pressures after firing guns. 6. POOH. 7. RD E -Line. 8. Turn well over to production. E -Line Procedure (Contingency) 1. Depending on fluid level, a 3-1/2" Tubing Patch maybe set across the existing UB -B perforations. Slickline Procedure (Contingency) 1. Depending on fluid level, the well maybe swabbed to remove water from across the new perforations. Attachments 1. Actual Schematic 2. Proposed Schematic 3. Standard Well Procedure — N2 Operations H Hileezn Alaska, LLC 50-133-20559-00 tv Des: ADL -324602 vation: 56' (2l'AGL) M' 33' 10 707" N 15113'07001"W late: 04/28/2006 ched 05/11/2006 eased: 05/15/2006 Tree cxn = 6-1/2" Otis Top of Cement (Bond Loa) @ 4,440' MD Cast Iron Bridge Plug @ 6,700' Dump bail 10' of cement TOC 6,690' 02110/16 Cast Iron Bridge Plug @ 7,840' Dump bail 10' of cement of Coil: 1-3/4" coil @ 7,912' cut with radial 1, milled down with 2.75" mill on 6113/15 4_t' of 1 0 vd bar lost 6/06115 @ 7,919' 4.0' of 1.0" wt bar lost 6104115 @ 8,162' L PXN plug set 5/16/15 @ 8,209' Velocity String 1-3/4" H070FF (0.125" WT) Install 7/21/07; Partially removed Tap, Bottom MD 7,912' 8,185' TVD 6,522' 6,795' BHA: 2.5" OD x 1.5" ID grapple connector 2.5" OD x 1.5" ID x 10' weight bar w/ drain 2.5" OD x 1.135" ID NoGo profile nipple 2.48" OD x 1.5" guide nose Slickline tag EOVstrg 8225' (4/18/12) meow a as �o��0 Ives below each gBg'4q (Broken CCTT g9122g8//2200g6) 8'5rrook 5' (BGT 9%28/2563 8,625' (Broken CT 9/28/2006) CLU -11 Pad -3 2,491' FSL, 2,291' FWL Sec. 4, T5N, R11 W, S.M. J v� Sterling Cl Interval: G` UB -B UBE SCHEMATIC Conductor 20" X-52 131 ppf Too Bottom MD 0' 136' TVD 0' 136' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of 12.0 ppg, Type 1 cmt Intermediate Casing 9-5/8" L-80 40 ppf BTC Two Bottom MD 0' 5,595' TVD 0' 4,355' 12-1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail Production Tubing 3-1/2" L-80 9.3 ppf EUE Lop Bottom 8rd MD 0' 9,284' TVD 0' 7,894' 8-1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt - 11 Excape modules placed - Green control line fired module 1 - control line fired modules 2 thru 7 - Red contol line fired modules 8 thm II - Ceramic flappervalves below each module except for module 1 1.4i UBE 6,726'- 6,746' (7/7/15) (Isolated) lox I 'air Mod -10 7,373'- 7,383' (Perfed 511/07) (Isolated) r Pert: Mod 9 7,383' - 7,400' (Perfed 511/07) (Isolated) 7472, gle @KOP and Depth: k4ed--8-- Mod 7 g7) 7,868' 7,878' Not6h9l 45.6° @ 2,883' Mod- 6 7,929'- 7,939' (Perfed 4/1107)' (Isolated) RKB (above GL): Part 7,939'- 7,946'(Perfed 4/1/07) (Isolated) Donna Ambruz Downhole Revision Date: 211 212 01 6 Mod- 5 8,208'- 8,218' (Frac'd 9/28106) (Isolated) - �T Mod- 4 8,384'- 8,394' (FraCd 9128/06) (Isolated) - Mod- 3 8,496 - 8,506' (Frac'd 9128/06) (Isolated) r Mod- 2 8,606'- 8,616' (Frac'd 9/28/06) (Isolated) TD Mod- 1 9,085'- 9,095' (Frac'd 9/28/06) (Isolated) 9,305' MD 7,915 TVD Perforation Detail Sands Too rMDI Btm (MD) Gun S'ze SPF Status Date PB- T� UB -B 6,683' 6,692' 2-3/8" 5 Open 02-12-16 Well Name & Number: Cannery Loop #11 Lease: ADL -324602 County or Parish: Kenai Peninsula Borough I State/Prov:j Alaska Country:USA gle @KOP and Depth: t 3° 1 220 ft @ 650MD Angle/Pe rfs: 4° -+ 7° Maximum Deviation: 45.6° @ 2,883' Date Completed:5/1812006 Ground Level (above MSL): 35.0' RKB (above GL): 21.0' Revised By: Donna Ambruz Downhole Revision Date: 211 212 01 6 Schematic Revision Date:I 2/16/2016 H Rilcora Alaska, LLC Tree cxn = 6-112" Otis Top of Cement (Bond Log) @ 4,440' MD Cast Iron Bridge Plug @ 6,700' Dump bail 10' of cement TOC 6,690' 02/10/16 Cast Iron Bridge Plug @ 7,840' Dump bail 10' of cement of Coil: 1-3/4" coil @ 7,912' cut with radial 1, m-8�ddown with 2.75" mill on 6/13115 on backside of colo r 4.1' of 1.0" wt bar lost 6/06/15 @ 7,919' i_ 4.0' of 1.0" wt bar lost 6/04/15 @ 8,162' 6 PXN plug set 5/16/15 @ 8,209' Velocity String 1-3/4" H070FF (0.125" VVr) Install 7/21/07; Partially removed TOD Bottom MD 7,912' 8,185' TVD 6,522' 6,795' BHA: 2.5" OD x 1.5" ID grapple connector 2.5" OD x 1.5" ID x 10' weight bar w/ drain 2.5" OD x 1.135" ID NoGo, profile nipple 2.48" OD x 1.5" guide nose Slickline tag EOVstrg 8225' (4/18/12) Ceramic flar valves below each mo u e as flaw (Broken CT 9/28/2006) (Broken CT 9/28563 (Broken CT 9/28/2006) CLU -11 Pad -3 2,491' FSL, 2,291' FWL Sec. 4, TSN, R11W, S.M. f ►r Sterling C1 Interval: Y UB -B UBE TD 9,305' MD PROPOSED SCHEMATIC Conductor 20" X-52 131 ppf Too Bottom MD 0' 136' TVD 0' 136' Surface Casing 13-3/8" L-80 68 ppf BTC LOP Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of 12.0 ppg, Type 1 cm: Intermediate Casing 9-5/8" L-80 40 ppf BTC Tog Bottom MD 0' 5,595' TVD 0' 4,355- 12-1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail Production Tubing 3-1/2" L-80 9.3 ppf EUE TOR Bottom 8rd MD 0' 9,284' TVD 0' 7,894' 8-1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt - 11 Excape modules placed - Green control line fired module 1 - control line fired modules 2 thru 7 - Red contol line fired modules 8 thru 11 - Ceramic flapper valves below each module exceptfor module 1 UBE 6,726'-6,746'(7/7/15) (Isolated) Mod -10 71373'- 7,383' (Perfed 511/07) (Isolated) Pert: Mod_ 9 Mad Q 7,383' - 7,400' (Perfed 5/1/07) (isolated) ? 4"' 7 IOy (Cored Mod 7 Mod- 6 a ocn, � 8 ' ) hnt 7,929' - 7,939' (Perfed 4/1/07) (Isolated) Pert: 7,939' - 7,946' (Perfed 4/1/07) (Isolated) Mod- 5 8,208'- 8,218' (Frac'd 9/28/06) (Isolated) Mod- 4 8,384'- 8,394' (Frac'd 9/28/06) (Isolated) Mod- 3 8,496'- 8,506' (Fradd 9/28106) (Isolated) Mod- 2 8,606'- 8,616' (Fradd 9/28/06) (Isolated) Mod- 1 9,085'- 9,095' (Frac'd 9/28/06) (Isolated) Perforation Detail PBTD Sands Tog (MDI Btm JMD) Gun Size SPF Status Date 9,247' MD UB -13 6,583' 6,592' 2318" 5 Open 02-12-16 7,857' TVD UB -B 6,594' 6,604' 2-3/8" 5 Proposed TBD Well Name & Number: Cannery Loop #11 Lease: I ADL -324602 County or Parish: Kenai Peninsula Borough State/Prov: I Alaska Country: USA gle @KOP and Depth: ± 3° / 220 ft @ 650' MD AnglelPerts: 4° -. 1° Maximum Deviation: 45.6° @ 2,883' Date Completed: 5/18/2006 Ground Level (above MSL): 35.0' RKB (above GL): 21.0' Revised By: Donna Ambruz Downhole Revision Date: 2/12/2016 Schematic Revision Date: 10/2/2019 11 STANDARD WELL PROCEDURE Hilrorp AlaAa. 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/CO2/02 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 FINALvl Page 1 of 1 .. o!leki I!O-seg Jo yluow dad („d:)W„) seg ;o lead 3!qn:) puesnoyl ti N x m Barrels of Oil per Month or Barrels of Water per Month O O o O O 0 0 O O o O 0 o O m 0 0 0 0 0 �I C6 O O e01 N N N N N N N o!leki I!O-seg Jo yluow dad („d:)W„) seg ;o lead 3!qn:) puesnoyl ti N O O O O O O O ~ O O O O O H O O O N O O N O N o!leki I!O-seg Jo yluow dad („d:)W„) seg ;o lead 3!qn:) puesnoyl ti N 20(v-oS`(S • ith Nolan Hilcorp Alaska, LLC 2— \ 0 2.9GeoTech 3800 Centerpoint Drive Anchorage, AK 99503 777-8308 Tele: 907 Ifilrnrp Ilsc.kn.1.1.{. Fax: 907 777-8510 APR 1 E-mail: snolan@hilcorp.com Af R 0 8 Zl�iu DATA LOGGED 't/13/201Co DATE 04/05/16 K BENDER To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 11 Perforation Record prints and digital data APR 2 1201 Prints: Gamma Ray-Casing Collar-Perforation Log CD1: digital Elog Data CLU-11_PERF_1OFEB16 3/25/2016 2:47 PM PDF Document 1,185 KB CLU-11_PERF_1OFEB16_Ccrrelaticn 32512016 2:52 PM LAS File 95 KB CLU-11 PERF_10FEB16_Cerrelation_l2ftS... 3/25/2016 2:53 PM LAS File 229 KB CLU-11_PERF_1OFEB16_img 3/25.12016 2:47 PM TIFF File 1,484 KB CLU-11_PERF_1OFEB16_Shccting_6583-55... 325,.'20162:54 PM LAS File 63 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: / Date: RECEWED STATE OF ALASKA • AQKA OIL AND GAS CONSERVATION COM SSION MAR 2 1 2016 • REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull Tubing U Operations shutdown U Performed: Suspend ❑ Perforate Li Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ 3rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory ❑ 206-058 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20559-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 324602 Cannery Loop#11 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Cannery Loop Unit/Beluga Pool 11.Present Well Condition Summary: Total Depth measured 9,305 feet Plugs measured 6,700&7,840 feet true vertical 7,915 feet Junk measured 7,912 feet Effective Depth measured 6,690 feet Packer measured N/A feet true vertical 5,314 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 115' 30" 136' 136' Surface 1,581' 13-3/8" 1,602' 1,489' 3,090 psi 1,540 psi Intermediate 5,574' 9-5/8" 5,595' 4,355' 6,330 psi 3,810 psi Production 9,263' 3-1/2" 9,284' 7,894' 10,160 psi 10,530 psi 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 9,284'MD 7,894'TVD Packers and SSSV(type,measured and true vertical depth) N/A;N/A 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 0 0 5 57 Subsequent to operation: 0 0 0 0 79 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations [21 Exploratory Li Development0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas 0 WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ 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: 316-044 Contact Taylor Nasse-777-8354 Email tnasse anhilcorp.com Printed Name Chad Helgeson Title Operations Manager 7.X. Signature / Phone 907-777-8405 Date 2; Form 10-404 Revised 5/2015 -IL 23r l6 RBDMS MAR 2 2 2016 Submit Original Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU-11 E-Line 50-133-20559-00 206-058 2/10/16 2/12/16 Daily Operations: 02/10/2016-Wednesday PTW and JSA. Spot equipment and rig up lubricator. Pressure test to 250 psi low and 2,500 psi high. RIH w/2.28" OD Magna Range plug and tie into Expro CBL dated 6/8/06. Run correlation log and send to town. Get ok to set plug at 6,700'.Took 7 min to set plug. Picked up 60' and went back down and tagged plug. Everything points to good set. POOH. Plug was set with 1,830 psi tubing pressure. RIH w/2-1/2" x 20' cement dump bailer, tie into Expro CBL log and tag plug at 6,700'. Pick up 5' and dump 10' of cement on top of plug. CMT in place at 1515 hrs and est TOC at 6,690'. POOH. Good dump. Rig for standby. Closed middle master with 1,794 psi on well. Will perforate on Friday if cement looks ok. Left cement sample on Mike's desk. 02/12/2016- Friday Meet at office. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. Pressure test to 250 psi low and 2,500 psi high. Arm gun.TP 1,784.3 psi. RIH w/2-3/8" x 9' Connex HC, 5 spf, 60 deg phase and tie into Halliburton Magna Range plug correlation log dated 2/10/16 (tied into Expro CBL dated 6/8/06). Run correlation log and send to town. Bleed well down to 500 psi. Town had us shift the log 12' down and send back in. Town ok shifted log. Spot gun from 6,583'to 6,592'. Fired gun with 505 psi on tubing.After 7 min pressure was at 582 psi. POOH. Gun was wet. Rig down lubricator and turn well over to field. CLU-11 Pad-3 1111 SCHEMATIC Ilileorp.tla.a,a. IAA. 2,491' FSL, 2,291' FWL Permit#: 206-058 Sec. 4, T5N, R11W, S.M. API#: 50-133-20559-00 Property Des: ADL-324602 KB Elevation: 56' (21'AGL) Lat: 60°33' 10.707"NIj Conductor Long: 151° 13'07.001"W20" X-52 131 ppf Top Otto Spud Date: 04/28/2006 B m TD Reached: 05/11/2006 MD 0' 136' Riq Released: 05/15/2006 TVD 0' 136' I ll' Surface Casinq Sterling Cl 13-3/8" L-80 68 ppf BTC Tree cxn 6-1/2"Otis Top Bottom Interval. MD 0' 1,602' TVD 0' 1,489' • 16"hole Cmt w/516 sks(228 bbls)of Top of Cement(Bond Loq) -- i UB-B 12.0 ppg,Type 1 cmt @ 4,440'MDQ It , Intermediate Casinq mil Cast Iron Bridge Plug @ 6,700' $ 9-5/8" L-80 40 ppf BTC Dump bail 10'of cement _-' Top Bottom TOC 6,690'02/10/16 -� UBE MD 0' 5,595' I ' TVD 0' 4,355' 12-1/4"hole Cmt w/95 sks(36 bbls) 12.5 ppg class G Cast Iron Bridge Plug @ 7,840' Lead,&237 sks(49 bbls) 15.8 ppg class G Tail Dump bail 10'of cement --- VELOCITY STRING FISH: ( Production Tubing 3-1/2" L-80 9.3 ppf EUE Top of Coil: 1-3/4"coil @ 7,912'cut with radial �f Top Bottom 8rd torch,milled down with 2.75"mill on 6/13/15 MD 0' 9,284' TVD 0' 7,894' Fish:4.1'of 1.0"wt bar lost 6/06/15 @ 7,919' 8-1/2"hole Cmt w/1,550 sks(325 bbls) Fish:4.0'of 1.0"wt bar lost 6/04/15 @ 8,162' ` of 15.8 ppg,class G cmt Plug:PXN plug set 5/16/15 @ 8,209' t . �.h "f Excape System Details Velocity String , . - 11 Excape modules placed 1-3/4" HO7OFF(0.125"WT) -Green control line fired module 1 Install 7/21/07;Partially removed *4` - control line fired modules 2 thru 7 Top Bottom "lit ii - contol line fired modules 8 thru 11 MD 7,912' 8,185' -Ceramic flapper valves below each module except for module 1 TVD 6,522' 6,795' i ' Perfs MD(RKB)(Beluga Zones): ! _ BHA: 2.5"OD x 1.5"ID grapple connector its) " UBE 6,726'-6,746'(7/7/15) (Isolated) 2.5"OD x 1.5"ID x 10'weight bar w/drain Di Mod-10 7,373'-7,383'(Perfed 5/1/07) (Isolated) 2.5"OD x 1.135"ID NoGo profile nipple +++��� r„ Perf: 7,383'-7,400'(Perfed 5/1/07) (Isolated) E L 4Med 9 7;42' 7,482'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) 2.48"OD x 1.5' guide nose w ° Slickline tag EOVstrg 8225' (4/18/12) } Mod 8 7,686' 7,696'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) ' Mod 7 7,868' 7,878' Not Shot 44' Mod-6 7,929'-7,939'(Perfed 4/1/07) (Isolated) Excape System Details 0 11=31 Perf: 7,939'-7,946'(Perfed 4/1/07) (Isolated) 1 Conventional flappers Mod-5 8,208'-8,218'(Frac'd 9/28/06)(Isolated) Mod-1 no trapper til Mod-4 8,384'-8,394'(Frac'd 9/28/06)(Isolated) -C oorriic s lov r valves below each -' Mod-3 8,496' 8,506'(Frac'd 9/28/06)(Isolated) mo u e as ows: Flappers MD(RKB): k.. Mod-2 8,606'-8,616'(Frac'd 9/28/06)(Isolated) Vo u e- TD Mod-1 9,085'-9,095'(Frac'd 9/28/06)(Isolated) -Vo ue- Vo u e- 9,305'MD Vo u e- 7;II: ,(Broken CT 9/28/2006) 7,915 TVD Perforation Detail Vo ue-6 7, ' Sands Top(MD) Btm(MD) Gun Size SPF Status Date Vo u e 5 roken CT g/28/2 g PBTD UB-B 6,583' 6,592' 2-3/8" 5 Open 02-12-16 Vo u e-4 8403Broken CT 9/28/2006; Vo ue 3 8,515' 9,247'MD Module-2 8,625'(Broken CT 9/28/2006) 7,857'TVD Well Name&Number: Cannery Loop#11 Lease: ADL-324602 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA gle @KOP and Depth: ±3°/220 ft @ 650'MD Angle/Perfs: 4°-.1° Maximum Deviation: 45.6°@ 2,883' Date Completed: 5/18/2006 Ground Level(above MSL): 35.0' RKB(above GL): 21.0' Revised By: Donna Ambruz Downhole Revision Date: 2/12/2016 Schematic Revision Date: 2/16/2016 ti of T� • • 4w 11/j,sA THE STATE Alaska Oil and Gas N ' of a ASI(j\ Conservation Commission 1 1 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 ALAS ' Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson *6 � `� � Operations Manager Hilcorp Alaska, LLC att�� (iSic 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Cannery Loop Field, Beluga Pool, Cannery Loop 11 Permit to Drill Number: 206-058 Sundry Number: 316-044 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, "4- -7(14 Cathy P oerster Chair DATED this LIP day of January, 2016. RBDMS JAN 1 6 2016 • 0RECEIVED . STATE OF ALASKA JAN209 ALASKA OIL AND GAS CONSERVATION COMMISSION �,S /tZ (/( APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations Q • Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate Q • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing D Other: ❑ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number: Exploratory ❑ Development Q ' 206-058 . 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20559-00 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 231 Cannery Loop#11 Will planned perforations require a spacing exception? Yes ❑ No D 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 324602 ' Cannery Loop Unit/Beluga 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): 9,305' . 7,915' • 9,247' 7,857' 1,696 psi 7,840' 7,917 Casing Length Size MD TVD Burst Collapse Structural Conductor 115' 20" 136' 136' Surface 1,581' 13-3/8" 1,602' 1,489' 3,090 psi 1,540 psi Intermediate 5,574' 9-5/8" 5,595' 4,355' 6,330 psi 3,810 psi Production 9,263' 3-1/2" 9,284' 7,894' 10,160 psi 10,530 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80 9,284 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 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 ' Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: February 9,2016 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: . Date: GAS Q • WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse-777-8354 Email tna_s seOhilcorp.corp Printed Name Chad Helgeson Title Operations Manager Signature gl/11 Phone 907-777-8405 Date j/24//6) COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑/ Spacing Exception Required? Yes ❑ No L'J Subsequent Form Required: (� 1./ V RBDMS IL JAN'2 6 201 ii, APPROVED BY Approved by: p),„...„,,,,... COMMISSIONER THE COMMISSION Date: 1-26 -/6 0 RPIce+Nrikit:lid the Submit Form and Form 10-403 Revised 11/2015 U for 12 mon;r= from he a e of approval. Attachments in Duplicate �Sp t; z_�, /(� • • Well Prognosis Well: CLU-11 Hilcorp Alaska,LL Date:1/21/2016 Well Name: CLU-11 API Number: 50-133-20559-00 Current Status: Shut In Leg: N/A Estimated Start Date: February 9, 2016 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-058 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(M) AFE Number: Current Bottom Hole Pressure: —2,340 psi @ 6,440' TVD (Based on PT Survey on 6/24/15) Maximum Expected BHP: —2,340 psi @ 6,440' TVD (Based on PT Survey on 6/24/15) Max. Potential Surface Pressure: — 1,696 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft) Brief Well Summary Cannery Loop Unit #11 was drilled as a Grass roots EXCAPE completion in 2006 to target gas sands in the Beluga formations. The initial perforations came with water immediately at high rates. A PLT showed most of the water flowing from the top five modules so all perfs above 7,730' MD were squeezed which did shut off most of the water. After the squeeze, module 10 was re-shot but not frac'd and this added some gas rate. In 2007 a 1-3/4" velocity string was RIH to 8,185' MD to help unload water. The coil tubing velocity string was found to be sanded in and successfully fished down to 7,912' in June 2015. The rest of the fish was stuck (unable to recover) and left downhole and isolated with a plug at 7,840' in June 2015. In July 2015 the UB-E sand was perforated and did not result in gas rate and is thought to be-wet The purpose of this work/sundry is to set a plug above the UB-E sand and perforate the UB-B sand.` " Notes Regarding Wellbore Condition • Well is SI, unable to sustain flow. Current SITP is 85 psi. • Prior to setting plug, pressure up well with nitrogen to attempt to push water back into the formation. E-line Procedure: 1. MIRU E-line, PT lubricator to 2,500 psi Hi 250 Low. a. Tree connection is 6.5" OTIS. b. SITP will be ±1,700 psi (Nitrogen Pressure). 2. MU 3-1/2" CIBP and setting tool. 3. RIH and set CIBP at+/-6,700'. POOH w/setting tool. 4. MU dump bailer and fill w/cement. 5. RIH and dump cement on top of CIBP (10' =4 gallons). POOH w/dump bailer. 6. RD E-line. Slickline Procedure (if indication of water in wellbore after setting plug) 7. MIRU SL and PT lubricator to 2,500 psi Hi 250 Low. 8. RIH w/swab cups and swab well dry. 9. RD SL. • • Well Prognosis Well: CLU-11 Hilcorn Alaska,LL Date: 1/21/2016 E-Line Procedure 10. MIRU e-line and pressure control equipment. PT lubricator to 2,500 psi Hi 250 Low. a. If necessary, bleed pressure down or add pressure with natural gas as requested by the RE to establish a drawdown on the formation. 11. Perforate the Upper Beluga sands with 2-3/8" 5 SPF 60 deg phased perf guns. All intervals are planned for 10 SPF so each may be shot twice. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. Proposed Perforated Intervals Sands Top (MD) Btm (MD) FT Upper Beluga UB-B ±6,583 ±6,592 ±9 12. POOH. 13. Flow well through test separator and record water and gas rates. 14. If the sand is not commercial or wet, the zone will be permanently plugged back. 15. RD e-line. Attachments: 1. Actual Schematic 2. Proposed Schematic 11 CLU-11 Pad-3 SCHEMATIC Ilil,-orp Alaska.LLC 2,491' FSL, 2,291' FWL Permit#: 206-0 Sec. 4, T5N, R11 W, S.M. API#: 50-133-20559-00 Property Des: ADL-324602 KB Elevation: 56'(21'AGL) Lat: 60°33' 10.707"N Conductor Long: 151° 13'07.001"W 11 20" X-52 131 ppf Spud Date: 04/28/2006 Top Bottom TD Reached: 05/11/2006 k MD 0' 136' 12iq Released: 05/15/2006 TVD 0' 136' Surface Casing A i 13-3/8" L-80 68 ppf BTC Tree cxn =6-1/2"Otis Top Bottom ,zs..c: '44 MD 0' 1,602' TVD 0' 1,489' 16"hole Cmt w/516 sks(228 bbls)of 12.0 ppg,Type 1 cmt Top of Cement(Bond Log) Sterling Cl @ 4,440'MD Interval: r (I UBE Intermediate Casing a 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' *' €I TVD 0' 4,355' 12-1/4"hole Cmt w/95 sks(36 bbls) 12.5 ppg class G Cast Iron Bridge Plug @ 7,840' Lead,&237 sks(49 bbls)15.8 ppg class G Tail Dump bail 10'of cement - ' ' VELOCITY STRING FISH: t! Production Tubing 3-1/2" L-80 9.3 ppf EUE Top of Coil: 1-3/4"coil©7,912'cut with radial Top Bottom 8rd torch,milled down with 2.75"mill on 6/13/15 1 MD 0' 9,284' ( ) TVD 0' 7,894' Fish:4.1'of 1.0"wt bar lost 6/06/15 @ 7,919' II 8-1/2"hole Cmt w/1,550 sks(325 bbls)of 15.8 ppg,class G cmt Fish:4.0'of 1.0"wt bar lost 6/04/15 @ 8,162' Plug:PXN plug set 5/16/15 @ 8,209' r f'S. _':s Excape System Details Velocity String ;; - 11 Excape modules placed 1-3/4" HO7OFF(0.125"WT) , rt' -Green control line fired module 1 Install 7/21/07; Partially removed �)' - control line fired modules 2 thru 7 Top Bottom contol line fired modules 8 thru 11 MD 7,912' 8,185' -Ceramic flapper valves below each module except for module 1 TVD 6,522' 6,795' Perfs MD(RKB)(Beluga Zones): Mod 11 6,593' 6,603' Not Shot BHA: UBE 6,726'-6,746'(7/7/15) 2.5"OD x 1.5"ID grapple connector 2.5"OD x 1.5"ID x 10'weight bar w/drain Mod-10 7,373' 7,383'(Cmt Sqzd 4/3/07, Perfed 5/1/07) 2.5"OD x 1.135"ID NoGo profile nipple Perf: 7,383' 7,400'(Perfed 5/1/07) 2.48"OD x 1.5"guide nose II Mod 9 7,472' 7,182'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) Mod 8 7,686' 7,696'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) Slickline tag EOVstrg 8225' (4/18/12) i Mod 7 7,868' 7,878' Not Shot i[" III Mod-6 7,929'-7,939'(Perfed 4/1/07) (Isolated) ExJO Conventional System Details 'r 0 Peri: 7,939'-7,946'(Perfed 4/1/07) (Isolated) n eflappers %, Mod-5 8,208'-8,218'(Frac'd 9/28/06)(Isolated) -Mo d- flapper 11.3 Mod-4 8,384'-8,394'(Frac'd 9/28/06)(Isolated) - moauie als m eows Ives below each Mod-3 8,496'-8,506'(Frac'd 9/28/06)(Isolated) Flappers MD(RKB): IIIMod-2 8,606'-8,616'(Frac'd 9/28/06)(Isolated) o u e- Mod-1 9,085'-9,095'(Frac'd 9/28/06)(Isolated) -11 ill u e- MI(Broken CT 9/28/2006) o ue-6 7,4 $o en CT 9%28%288 3 0 PBTD 9,305'MD 9,247 MD Module-3 8 ,625'(Broken CT 9/28/2006) 7,915 TVD 7,857'TVD Well Name&Number: Cannery Loop#11 Lease: ADL-324602 • County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA gle @KOP and Depth: t 3°/220 ft @ 650'MD Angle/Perfs: 4° 1° Maximum Deviation: 45.6°@ 2,883' Date Completed: 5/18/2006 Ground Level(above MSL): 35.0' RKB(above GL): 21.0' Revised By: Taylor Nasse Downhole Revision Date: Proposed Schematic Revision Date: 1/11/2016 .. ill CLU-11 PROPOSED Pad-3 I I ileorp Alaska,LLC 2,491' FSL, 2,291' FWL SCHEMATIC Permi . Sec. 4, T5N, R11W, S.M. API#: 50-133-20559-00 Property Des: ADL-324602 KB Elevation: 56' (21'AGL) r Lat: 60°33' 10.707"NI. Conductor Long: 151° 13'07.001"W 20" X-52 131 ppf Spud Date: 04/28/2006 Top Bottom TD Reached: 05/11/2006 MD 0' 136' Rid Released: 05/15/2006 TVD 0' 136' IIS': Surface Casing L% Sterling C1 13-3/8" L-80 68 ppf BTC Tree cxn 6 112 Oti Interval: Top Bottom e :r. MD 0' 1,602' TVD 0' 1,489' 16"hole Cmt w/516 sks(228 bbls)of Top of Cement(Bond Lou) rte. . UB: 12.0 ppg,Type 1 cmt @ 4,440'MD II ', Intermediate Casing • 9-5/8" L-80 40 ppf BTC \ Cast Iron Bridge Plug @ 6,700' I Top Bottom Dump bail 10'of cement . -r.- UBE MD 0' 5,595' - 1 TVD 0' 4,355' ; STATE OF ALASKA ALlikA OIL AND GAS CONSERVATION COM SION JAN 1 9 2016 w REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon ❑ Plug Perforations U Fracture Stimulate U Pull Tubing U Operations shutdown LI Performed: Suspend ❑ Perforate 0 Other Stimulate ❑ Alter Casing ❑ Change Approved Program 0 Plug for Redrill ❑ rrforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Pull Velocity String-FCO/N20 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory ❑ 206-058 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20559-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 324602 Cannery Loop#11 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Cannery Loop Unit/Beluga Pool 11.Present Well Condition Summary: Total Depth measured 9,305 feet Plugs measured 7,840 feet true vertical 7,915 feet Junk measured 7,912 feet Effective Depth measured 9,247 feet Packer measured N/A feet true vertical 7,857 feet true vertical N/A feet Casing Length Size MD ND Burst Collapse Structural Conductor 136' 30" 136' 136' Surface 1,602' 13-3/8" 1,602' 1,489' 3,090 psi 1,540 psi Intermediate 5,595' 9-5/8" 5,595' 4,355' 6,330 psi 3,810 psi Production 9,263' 3-1/2" 9,284' 7,894' 10,160 psi 10,530 psi 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 9,284'MD 7,894'ND Packers and SSSV(type,measured and true vertical depth) N/A;N/A 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 0 0 0 376 • Subsequent to operation: 0 0 0 0 33 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development 0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas 0 WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ 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: 315-267&315-370 Contact Taylor Nasse-777-8354 Email tnassethilcorp.com Printed NameChad Helgeson Title Operations Manager Signature (//n41,* Phone 907-777-8405 Date //MA Form 10-404 Revised 5/2015 r'" RBDMS LA. JAN 2 1 2016 Submit Original Only s • Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 05/16/2015-Saturday MIRU Slickline. Rig up lubricator and test to 250 psi low and 2,000 psi high. RIH w/ 1.25" DD bailer and bail from 2,102'to 2,109' SLM (recover thick slurry). RIH w/ 1.25" swab mandrel and swab cups to 2,088'.Tools got blown up hole. Recovered all tools in the lubricator. RIH w/ 1.25" GR to 8,209',tag XN profile. RIH w/braided line brush to 8,209', clean XN profile. RIH w/ 1.25" PXN plug, set at 8,209'. RIH w/ 1.25" prong and set in plug at 8,209'. Rig down lubricator and turn well over to field. Bleed off tubing pressure.TP-0 psi. 05/30/2015-Saturday Obtain PTW. Hold safety meeting and discuss job procedures. Review JSA and HARC. Pull pit liner. Move equipment into position. Spot Rain for Rent tanks. Vac truck haul 175 bbls of KCL from KBU 22-06Y to CLU-11. Rig up CTU equipment. Attempt to bleed off night cap flange on wellhead. Would not bleed down. Swab and master valve both leaking gas. Estimated 1,800 psi below master. Contacted production to use grease gun. Unable to use production grease gun. Dispatched Vetco Grey valve tech. Vetco grease crew arrived to grease wellhead valves. Swab valve no longer leaking. Install BOPs and continue rigging up CTU and associated equipment. Bleed down well through gas buster at 1200 hrs. Start BOP test. AOGCC 24 hr notification sent 5/29/15 @ 1640 hrs. Witness waived by Jim Regg on 5/29/15 at 2050 hrs. Draw down test good. Pressure test all rams,valves, and choke skid to 250psi low and 4,500 psi high. BOP test completed at 1800 hrs. Opened well back up to see what pressure build occurred within 6 hrs. WHP 120 psi. Bleed down WHP to zero. Calculated CT velocity string volume 17.8 bbls. Previous slick line work to set plug estimated no fluid inside velocity string. Online with pump down CT at 2.5 bbls min. 25 psi pump pressure until 5 bbls away. Pressure increased to 250-500 psi. Pumped 15.1 bbls. Rapid increase in pump pressure to 1,668psi. Start 5 minute leak off test on V string. 1,662 psi-1,518 psi. Loss of 144 psi over 5 minutes. Monitored CT annulus pressure before and after bleeding down the initial 1,800 psi WHP and also while pumping. No change in annulus pressure. Good indication CT hanger seals are holding and gas is not communicating at surface hanger. Bleed down applied pressure of 1,518 to zero. Close in well and secure location. Crews off location. Wellsite secure. • • S Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 05/31/2015-Sunday Obtain PTW. Hold safety meeting and discuss job procedures. Review SLB JSA and HARC. Fire equipment. Pick injector head. Pick up 20 ft of lubricator. Open well to see results of previous days CT v string kill. 320 psi WHP. Bleed off to tank. Small gas migrated to surface. Bleed down fast. Online with pump and 6% KCL down V string. 0.8 bbls away and pressure up to 1,600 psi. Bleed down to zero and close in well. Make up external dimple connector. Pull test coil connecotor to 25K. Pressure test connector 4,500 psi. Make up 3in GS spear with plugged off nose. Pressure up to function piston. 1,500 psi shifted piston to release dogs. Bleed down coil. Pick up into lubricator. Stab on wellhead. End of BHA zero to top hanger bolts 12.6 ft. Open master and swab. 23.5 turns. WHP 0 PSI. RIH to latch hanger. Stack 5K on hanger. Pick up looks like GS latched into hanger. Pick up to 20K and 3in GS pulls out of hanger. 3 attempts at latching and pulling out of hanger each time. Decided to pop off well and check GS tool. Popped off well. GS spear looks to be in normal operating conditions. Re- measured all OD's and Collett profile. Confirmed correct measurements for 3in GS. Decided to pull plug in nose. Will use fluid rate vs. pressure to release GS. Previous day wellhead valves were greased. Could possibly have debris and grease in GS hanger profile. Stab back on well. Pressure test lubricator to 4,500 psi. Bleed down. Online with pump. Choke open taking returns to open top tank. Stack 5K on fish while pumping 1.5 bbls a minute at 2,800 psi CT pressure. Cleaning out GS profile. Down on pump. Relax GS piston. Pick up on hanger to 25K. Looks latched. RIH to slack off weight. Open top hanger bolts 4.5 turns. Pick up on CT confirmed, moved hanger off seat. Saw burp of gas at return tank from CTxtubing annulus. Pick up from 12.6 ft to 8.7ft in gradual increments. At 80%coil yield limit of 32,000 lbs. No luck moving velocity string. BHA and coil possibly stuck in fill. Continue attempts at RIH to hanger and pulling up. Fast pulls, slow pulls, Hold at 32,000 lbs to see if weight slowly breaks back. No movement or weight loss noticed. Rigged up iron to back side of CTxtubing annuli. Online down back side while holding 32,000 lb pull. After 5 bbls away at 2.5 bbls/min noticed WHP increase to 1,367 psi. 5 bbl void seen on back side. Dropped pump rate to 2 bbls minute. Pump pressure 2,493 psi. Seems as if injecting or communicating into formation. Previous attempts at pumping annulus saw pressure build and hold. Pump pressure flat line at 2 bbls a minute and 2,493 psi. At 25 bbls away pump pressure broke back to 2,270 psi. CTxTubing volume 46 bbls. Run in to hanger top and pull up multiple times while pumping on backside at 2 bbls/min. No luck moving coil. Offline on pump and attempted to wing open choke to surge backside. No luck. 5 more attempts at slacking off and picking up. No luck. Back online with pump 2 bbls/min. Until CTxTubing volume away. 50 bbls pumped down back side. Down on pump. 3 more attempts to pull V string. No luck. Obtained free point calculation and sent to town. Stacked weight on CT hanger. Run in top lock down screws. Online down CT GS spear 1.5 bbls minute and 3,200 psi. Pick up out of GS profile. Pull above master and swab. Down on pump. Close in well and bleed off to return tank. Pop off well and rig down BHA. Stack down lubricator. Set injector head on deck. Secure well. SLB fuel equipment. Changing direction of injector head slings. While unit in maintenance they were put on backwards causing injector head to pick abnormally. Made days operations difficult to stab on and off wellhead. Wellsite secure. Crews off location. Coil crew on standby to figure out what plan forward is. • • • II Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 06/04/2015-Thursday Obtain PTW and hold safety meeting with Pollard Eline. Radial jet cutting tools on location. Rig up Pollard Eline. Checked V string pressure and annulus pressure. Both showing zero psi. Rig up 7/8" RJCT. Stab on well. Correct To RKB 21' AGL. Pressure test Pollard Eline lubricator with SLB fluid pump to 250 low and 3,500 psi high. Good test. Bleed down. Open well and RIH. Tagged 3 times on top of plug and prong at 8,186ft. Decison made to shoot hole 20 ft above tag depth.Charge depth 4ft above tag. Pick up to 8,162'to put shot 20ft above plug and prong. Puts shot 7ft above V string coil connector. Online with fluid down coil to obtain 1,000 psi on V string. Pressure bleeding off. Had to keep pump rolling at .6 bbls/min to keep 1,000 psi at surface. 1,000 psi on well, fired shot. Pick up with Eline 100 ft. No change in WHP after shot made. Online with pump down CT V string. Returns at surface 1,700 psi at 1.5 bbls/min. Increased rate to 1.8 bbls/min. Pressure building to 2,850 psi. 3,500 psi whp drop rate to 1.5 bbls/min. Tank straps show getting 1:1 returns. Eline continue to POOH. 120 bbls pumped . Bottoms up. No change in fluid color at return tank. Swab master closed. Eline popping off. Indication that charge fired. Lost 4 ft of 1in weight bar in V string. Eline rigging down. Night cap on BOPs. Lined up and pressure test stack to 4,500 psi. Pressure test good. Open well and CTxtubing annuli to take returns up back side of coil V string. Increase fluid rate down V string to 1.5 bbls/min. WHP walking up and start flat line at 3,560 psi. 1:1 returns at surface. 12 bbls pumped at 3,560 psi and pressure rapidly dropped to 0. Came offline on pump to investigate possible surface failure. Everything looked OK on the ground indicating something happened in the well. Rapid drop in pressure would suggest CT hanger seal blew out. Back online at 1.5 bbls/min, pressure slowly climbing back up. 3,650 psi WHP at 1.5 bbls a minute. Continue pumping bottoms up. 68 bbls circulated. Shut down pump and cool down N2. During cool down lined up fluid pump to pump down annulus and V string. Online 3.1 bbls/min @ 3,200 psi for 10 bbls. Pressure test N2 iron 4,500 psi. Bleed down open to CT V string. Online at 1,500 scf/min noticed instant nitrogen returns at open top tank. Indicating CT V string hanger seals not sealed. Down on N2. Called town to discuss. Decision was made to rig back and secure well until further notice. 200 bbls pumped during operation 3 bottoms up volumes obtained. Believed to have pumped 1.5 bottoms up before seals blew. Shut down equipment. Close in well and secure location. Crews off location. Gate locked. i • Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 06/06/2015-Saturday Obtain PTW, hold safety meeting and review SLB JSA. Discuss job tasks/assignments and intervention objectives. Check oils and fire equipment. Start BOP test. Draw down test good. Pressure test all rams and valves to 250 psi low and 4,500 psi high as per sundry number 315-267. 24 Hr notice sent to AOGCC on 6/5/15 @ 1321. Witness waived by Jim Regg on 6/5/15 @ 1321 BOP test completed successfully with no failures. Pick 20 ft of lubricator. Make up coil connector x over and 3in GS spear. Stab on well. Fluid pack to tank. Close in choke pressure test stack 250 low and 4,500 psi high. Pressure test good. Bleed down. Zero to hanger 11.6 ft. Open master and swab valve. Fluid pack V string. Pressure increased after.8 bbls. Fluid pack coil x tubing annuli. 4 bbls before pressure seen. RIH. Stack weight at 11.4 ft. Pull test GS spear to confirm positive latch. Slack back down to neutral weight. Back off top set of hanger lock down screws. Attempt to pull velocity string pull 35K. No movement. CT depth 4.6ft. 2nd attempt to pull. 35K no movement. Slack down on hanger and secure with lock down screws. Pumping 1.5 bbls min 3,200 psi. Pump off GS spear. Called out Pollard E-line. Lined up to pump down V string and CT V string annulus to ensure fluid path for torch run. Pumping at 4.2 bbls/min @ 3,900 psi injection pressure. Looking for pressure to break. No luck. 50 bbls pumped into formation. RIH to latch GS profile. Pull test to ensure positive latch. Slack down to zero weight. Unlock top hanger lock down screws. Attempt to pull 4 times. 35K max pull. No movement of velocity string. Set down on hanger. Lock down top hanger bolts. Online down CT at 1.5 bbls/min. Pump off velocity string. POOH. Close master and swab. Bleed off and pop off well. Rig back CT injector head. Waiting on Eline. CT crew housekeeping on location. Grease choke valves. Pick up loose trash. Eline arrived. Held SIMOPS safety meeting with Pollard, and SLB. Eline rigging up. BHA consists of 4 weight bars and 1" radial torch with 4.1 ft x 1" weight bar below charge. Stabbed on well and pressure test 3,500 psi. Bleed down and open well. RIH with Eline. Tagging up with Eline at 8,163 ft. 1 ft lower than tubing punch that was shot previous day. Possibly fill, or metal node from torch cut. Pick up and tag 3 times to ensure positive tag. Pick up to pre-determined torch depth of 7,919 ft. Parked. Verified with town that depth is correct. Fire 1 inch radial torch. Saw slight weight loss of 30-50 lbs. Start POOH. WHP and annulus pressure 0 psi. Eline at surface. Close master swab. Rig down Eline. 4.1 ft of 1in weight bar lost in hole after torch fired. Pick CT injector head. Stab 20 ft of lubricator. Make up 3in GS spear. Stab on well. Fluid pack. Pressure test to 3,500 psi. Bleed down. Open well. Online with fluid. No void. Fluid still at surface. Swap valves to pump annulus. Online. Annulus full. Fluid at surface due to pressure increase. RIH latch into GS profile. Pull test. Neutral weight. Unlock top set lock down screws. Pull to 35K no movement after torch attempt. Perform 18 cycles of neutral weight to 35,000 lbs. Pull hard at 55 ft/min from 0 lbs to 35,000 lbs. No luck. Called town to inform them of situation. Decison made to pull to 80%coil limit and hold for 30 minutes at 35,000 lbs. No break in weight or movement of CT V string. Land V string in hanger. Secure lock down screws. Online down CT. Pump off hanger. Pick up and close in master swab valve. Pop off well and stack down CTU equipment. Install night cap on BOPE. Check all ground valves. Shut down equipment and secure location. Crews off location. Gate locked. Eline will arrive 0700 hrs for 1.18" spectra jet cut run. SLB will arrive at 0900 hrs. • • Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 06/07/2015-Sunday Pollard Eline on location. Hold safety meeting, review JSA and discuss job procedures and firing depth. MIRU Pollard Eline. Make up 1.18"jet cutter. Stab on well. RIH to 7,919 to log across previous shot. Show on log at 7,919 ft. Pick up to 7,363 ft. Fired Shot. Dropped down past it and pulled out to show shot with CCL. Looks good. POOH. At surface popping off well. Rigging down Eline. Hold safety meeting wtih SLB coil hands. Review job procedures and HARC. Pick injector head and 20 ft of lubricator. Make up 3in GS spear. Stab on well. Fluid pack. Pressure test to 3,500 psi. Bleed down. Open well. Stab into hanger 11.3 ft. Pull test. Latched up. Slack off weight. Back out hanger bolts. Pick up coil. Coil coming up hole at 18K lbs. CT hanger above BOP's. Close pipe slips . Push pull test. Close pipe rams. Drop chain traction. Unscrew lubricator. Roll chains in hole. Pick injector head with crane to expose V string. 10 ft exposed. Appy traction. Cut CT string below hanger. Cut off coil connector and GS spear with hanger latched. Dress CT ends. Make up double cold roll connector. Strip back down with injector head. Screw on lubricator. Pull test coil connector to 25K. Slack weight to 17K. Open pipe rams and slip rams. Spool coil out of hole. Perform swab checks at 100 ft. Popping off well. Injector head on stand. Unstab CT velocity string from injector head. Secure V string on spooling unit. Rig down hydraulics to spooler. Rig up hydraulics on CT work string. Pick up injector head and stab on back deck of CTU. Re-spot crane. Stab 1.75in work string into injector head. Pick injector and grab 10 ft of lubricator. Make up coil connector. Pull test 20K. Stab on well. Fluid pack and pressure test lubricator 3,500 psi. Open master and swab valve. RIH. Stacked and tagged at 7,348ft. Online with KCL at 1.5 bbls a minute. Circulate bottoms up twice. Fluid clean. Cooling down N2, 94 bbls pumped. Confirmed returns were 1.5 bbls min. Getting 1:1's. Online with N2, 1,800 scf/min fluid returns at surface. Straight N2 at surface. 96 bbls returned from wellbore. POOH. WHP pinched in to 500 psi while POOH. OHH. Stack down CTU for the night. Well site secure. 96 bbls returned from wellbore. 1,300 gallons of N2 pumped. Gas detector reading 10%for a brief time. 06/08/2015- Monday Obtain PTW. Hold safety meeting with Pollard Slickline. Rig up. RIH and find fluid level at 200 ft. 181 ft RKB. Stack weight on CT V string at 7,356 ft. POOH and rig down slickline. Send pictures to town. Opened well to check tubing pressure. 400 psi. Bleed down quick. Hold safety meeting with SLB. Pick injector head and 10 ft lubricator. Make up BHA and 2.5in jet swirl nozzle. Stab on well. PT lubricator 250 low and 4,500 psi high. Bleed down. Open well and RIH. Stack weight on fish at 7,350 ft. Online with N2 at 800 scf/min. Pump N2 and return 56 bbls. Nitrogen to surface. Out of N2. Shut down pump and stay parked at depth to await transport. One hour wait. Well showing 27% lel. Bleed down to 0 psi. All returns stopped at tank. Air Liquid on location. Transferring N2 into SLB pump and transport. Online with N2. 1,200 scf/min. Nitrogen returns at surface. Called town to discuss. Decided to POOH. Shut down N2. At surface. 100 psi whp of N2 returning to tank. Continue to bleed down to zero. Swab closed. Popping off well. 56 bbls returned during first N2 lift. 2 bbls returned on second lift. 90K scf pumped first lift. 40K pumped 2nd lift. Air Liquid brought free nitrogen. Ordered 3,500 gallons. 4,100 gallons remaining. Popped off well. Shut down CTU. Secure location. 114 bbls of fluid returned from wellbore for total job. • • Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 06/10/2015-Wednesday Obtain PTW. Hold safety meeting and review 1SA with crews. Discuss job scope and proper execution. Pop off night cap. Pick injector head. Stab 25 ft of lubricator. Make up CC, DFCV, Hydraulic Disconnect, Motor and 2.785" mill. Tool OD 2.125". 15.6ft. PT BHA 250 psi low and 3,500 psi high. Bleed down. Stab on well. Oline with fluid to confirm mill is rotating. Pressure test stack to 250 psi low and 3,500 psi high. Bleed down. Open well 220 psi WHP. RIH. Stack weight at 7,349.2 ft. Pick up and come online at 2.1 bbls minute. Free spin pressure 1,530 psi. Stack weight at 7,347' 1,871 psi. 330 psi motor work. Mill on top of fish to 7,349.6 ft. Pump bottoms up. POOH. POOH to swap out BHA. At surface swab master closed. Bleed down stack. Pop off wellhead. Pressure test BHA. 250 low 3,500 psi high. Bleed down and install 2-5/8" Knight oil tools hydraulic release overshot. Stab on well. Pressure test stack 250/3,500 psi. Bleed down. Open well and RIH. RIH. Fishing details of V string. Top of 1st part 7,363 ft to next attempted cut at 7,919 ft. 2nd potential fish from 7,919 ft to 8,185 ft. (tubing punch 8,162 ft). First fish 556 ft. 2nd fish 266 ft. Or complete fish comes out at 822 ft. Parked at 7,300', perform 3 weight checks. Consistent up weight 15K. RIH stack 3K down on top of fish at 7,356 ft. Pick up clean. Stack 5K . Pick up clean. Stack 7K pick up clean. Online down CT 1.2 bbls min 3,500 psi. Stack 7K. Pick up weight clean. Online down CT surging pump from 0 psi to 3,500 psi. RIH at .3 ft/min. Trying to pop CT off tubing wall. Stack 5K down on pump. Pick up clean. Pick up 50 ft. RIH at 70 ft/min. Stack 5K. Pick up weight clean. RIH at .3 ft/min slowly stacking weight to-5K. Pick up weight clean. Stack 3K, wait 10 minutes 5K jar lick. PU weight clean. Called town to discuss further attempts at fishing before jarring down any further. Could possibly damage fishing neck or kink coil. Decison made to POOH to swap to Series 10 and motor. POOH to surface. Called Knight oil tools to have them weld a finger on a shroud to aid in pulling CT off tubing wall. Discussed the cost of leaving motor and overshot in hole. Decison was made to wait until morning to discuss further options. At surface rigging down CT. Wellsite secure. Crews off location. • I Hilcorp Alaska, LLC It It Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 06/11/2015-Thursday Obtain PTW. Hold safety meeting and discuss job sequences and associated hazards with fishing CT. Pick injector head and 35 ft of lubricator. Make up CC, DFCV,Accelerators, Hydraulic BIDI jars, disconnect. Pressure test MHA 250/3,500 psi. MU motor, x over and series 10 overshot. Tag up on pack offs. Stab on well. Pressure test stack 250/4,500 psi. Bleed down. Open master swab 25 turns. WHP 0 psi. RIH. Stack down weight at 7,355 ft. CTMD.4K down on fish. Attempt to pick up. Clean up weight 17K. No latch on fish. RIH, stack 6K . Pick up clean 17K. Came online with pump min rate to spin motor .25 bbls/min. Free spin 900 psi. RIH, slow down .5 ft/min stack down 5K. Down on pump. Pick up heavy 34K, weight dropped off to 17K. Lost fish. RIH .25 bbl min. Rotate series 10 over shot on top of fish. Stack-3K. Down on pump. Wait for down jar lick to set slips in overshot. 15 minute wait and jars fired. Pick up to 27K. 10K overpull. Wait for jars to fire. 3 minutes jars fired. No movement of fish. RIH, stack down 5K to reset jars for up lick. Attempt to pull to 45K 80%coil limit. 42K jars fired to 60K. Started POOH. Weight was heavy pulling from 7,355'to 7,195 ft. Pulling 35K to 25K and back up . Slowly dropping off at 7,195 ft. 18K pulling out of hole. Believed to be pulling CT V string out of fill on back side due to heavy consistent weight while POOH. Tagged up at stripper. Attempt swab check. Swab will not close. Fish on. Hold safety meeting for popping off well and stripping pipe to make up coil for spooling. Close pipes and slips. Set weight to confirm slips are holding. Drop traction and strip off well. Expose 5 ft of CT. Cut CT. Install double cold roll connection. Strip back down on pipe. Screw on lubricator. Corrected depth to 566 ft. Open pipes and slips. Pull fish out of hole. Perform swab checks every 100 ft until at 100 ft then every 50 ft. 17 ft left on counter. Swab check. Swab closed indicating fish removal of 556 ft. Still 266 ft in hole. Install CT cutter below lubricator. Swing crane over dumpster. RIH and cut 566 ft of CT. Trim additional 50 ft of work string coil. Stack down lubricator. Set injector head on back deck. Install BOPE night cap. Well secure. Perform chain inspection and change pack offs. Field dress tools for tomorrows fishing attempt. Wellsite secure crews off location. • • • 711 Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 06/12/2015-Friday Wait for production to arrive on location to sign permit. Fire equipment. Check oil and fuel. Obtain PTW. Hold safety meeting. Review JSA and HARC. Discuss intervention goals and steps to achieve objectives. Pick injector head and 35 ft of lubricator. MU coil connector and BHA. PT BHA 250/3,500psi. Tools string. OD 2.125" CC, DFCV, accelerator,jar, hyd disco, motor, x over, series 10 overshot with cut lip guide. Head to well. Stab on pressure test lubricator 250/4,500 psi. Open well RIH. Tag at 7,767 ft. 152 ft away from TOF. Pick up obtain circulation and free spin pressure 1,380 psi. RIH to tag depth 7,767 ft. Slow motor work. Take 50 ft bite. Circulate 10 bbls. Pick up 50 ft. RIH take 100 ft bite. Circulate 10 bbls. Annulus volume for bottoms up 45 bbls. Pump two bottoms up or 113 bbls total on top of fsh. Tag hard at 7,901 ft. Returns 1:1. Dirty returns at 45 bbls. Returns cleaned up. Down on pump. Two attempts to latch without spinning. Clean up weight. Stack 4K wait for jar lick. PU clean. Pump .5 bbls min. RIH, .2 ft/min motor free spin 1,300 psi. Stall to 2,600 psi. Down on pump. PU clean. Pick up online 1.2 bbls/min 2,300 psi. RIH .2 ft min. No weight loss but motor stall. Down on pump. PU clean. Online with pump. .75 bbls min. 2ft/min. RIH stack 5K. Offline. 5K jar lick down. Stack 4K after jar lick. PU clean. Stack 500 lbs on tag. Surge pump up and down hoping to orientate cut lip on overshot to pop over fish. Down on pump. PU clean. Online 1.3 bbls min. 12 ft/min no weight stack but motor stall. Continue to pump and stack weight while stalled. No weight break back or loss in CT pressure. Unable to make hole. Offline PU clean. Bottoms up 45 bbls.Jar down 6K. Jars fired. Stack weight. PU. Clean. Not able to latch fishing neck. 7,901 ft. POOH to check tool string. POOH. Tagged up at surface. Swab closed. Pop off well. Made calls to tool companies looking for washover pipe or burn shoe. Knight, Baker, Olgoonik, Weatherford. No luck. Decided to stack down and BOP test. Called Pollard and dispatched crews for intervention. Start BOPE test. 250 low and 4,500 high on all valves and rams. Cruz crane backed out. Pollard on location. Rigging up. RIH with LIB. No signs of CT fish. RIH with pump bailer. Bailer returns full, metal shavings and sand. Some rocks or cement. RIH with same bailer. Less fill than previous. Swap bailers to hydrostatic bailer. RIH. Turn project over to production operators. • • ti Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 06/13/2015-Saturday Obtain PTW. Hold safety meeting and review 1SA. Pick injector head and grab 35 ft of lubricator. Make up MHA. Pressure test 250 low and 4,500 high. Bleed down. Bring mill to Knight oil tools to turn down OD from 2.8" to 2.5" OD. Waiting on mill. Make up motor. Install mill. Stab on well. Pressure test stack to 250/4,500 psi. Bleed down. Zero depth to ground level 17 ft. RKB 21'. Corrected depth at zero to 4ft. Open well and RIH. RIH tag at 7,898 ft RKB. Pick up. Online down CT to start milling. Saw motor work at 7,898 ft then broke off and RIH at 5 ft a minute until hard tag at 7,901 ft. Heavy motor work at 7,901'. 1,900 psi free spin. Motor work to 2,600 and breaking back. Continued milling 7,901 ft to 7,912.3 ft. until ROP slowed down. Were not making any more new hole. POOH to check or change mill. Clean returns. Metal shavings on magnet. POOH. Swab closed. Pop off and noticed Knight mill had lost carbides in middle of mill. 12 inch chunk of CT was inside mill. Send pictures to town. Making up 2.75in mill. Stabbed on well. Pressure test low 250/4,500 psi high. Bleed down, open well and RIH. RIH. Stack weight while not pumping at 7,907.3 ft. Milling attempts at depth. New mill is more aggressive . Hard to get pattern started. 18 stalls recorded. SLB forgot to correct to RKB prior to RIH. RKB correction at 7,907.3 ft should put mill at 7,911 ft. Mill from 7,911 ft to 7,912.4 ft. Believed to be on coil or next to it. ROP stopped. CT stall. When came offline pressure dropped to 800 psi .After slight overpull on pickup pressure would drop to zero. Indications of being bit stuck on outside of mill. No luck making any more depth. Called town and decision was made to not blow down with N2 and POOH to attempt overshot fishing run following day. POOH. At surface. Swab closed. Pop off well. Rig back CTU 12. Wellsite secure. Crews off location. • • Hilcorp Alaska, LLC �.. Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 06/14/2015-Sunday Obtain PTW. Hold safety meeting wtih SLB/Cruz and Hilcorp. Discuss job procedure. Pick injector head. Stab 30 ft of lubricator. Make up BHA. Pressure test 250 low and 4,500 psi high. Make up mill and overshot. BHA 2-1/8". Overshot 2- 3/8" OD. Stab on well. Pressure test lubricator to 250/4500 psi. Open well and RIH. RIH. Stack weight at 7,911 ft. Pick up clean. Online down CT.3 bbls/min. Stack 4K. No luck latching up.Attempt to latch up multiple times. Jar down. Attempts at spinning at slow rate. 5 down licks. No luck latching 1.75in CT velocity string. Increase pump rate to 1.6 bbls min. RIH at .2 ft/min. Stack weight at 7,910.5'. Stall on motor. Weight break back and coil RIH to 7,914' and stacks weight. Down on pump. Pick up 22K.4K overpull. Looks to be latched on. Stack down 5K and wait for jar lick down to set slips. 19 minutes for jars to fire down. Pick up 32K. Latched up. Perform 21 up licks at 38,000 lbs with jars. No luck moving fish. Stack down 4K. Come online with stalled motor up to 3,500 psi. Pick up off fish. Circ pressure drops to 1,200 psi normal. OOH wt at 17K. Off fish. Called town to discuss. No luck moving fish after 20 heavy jar licks. Concerned about blowing out motor bearings. Decision was made to drop a ball and circulate fluid with N2. Parked at 7,900 ft. Drop ball to open circ sub. Ball on seat. Pressure up to 4,500 psi and shear pins. Online with N2 down CT at 1,500 scf/min. Pumped until N2 at surface and returns all gas. 77 bbls recovered from well bore. Down on pump. Shut down for hour to wait for welbore to fill up with fluid. 5% LEL at surface. During lift held 500 psi of back pressure. Monitor well for flow. WHP 578 after down on pump. Pressure bleeding down and pinching in choke. Pressure to zero psi after one hour. Online down CT with N2 at 1,500 scf/min. No increase in circ pressure indicating not lifting column of fluid. Straight N2 returns at surface with small stream of fluid. 1 bbl recovered from wellbore. Start POOH. Down on N2 at 5,000 ft. POOH to surface. Returns all N2. At surface. WHP 50 psi residual N2. Close swab. Pop off well. Rig down coil tools. Stack down lubricator. 96K N2 pumped for first lift. 2nd lift 71K pumped. 1200 gallons of N2 left. Opened well to gas buster to check for pressure. No pressure on wellhead. 4% LEL on gas detector. No audible or visual flow to tank. Close in well and secure location. Wellsite secure. Crews off location. 266 ft of fish left in hole at 7,914 ft. 1.75" coil with 2.5" OD x 12.5' long bottom hole assembly. 06/23/2015-Tuesday RU slickline. PT lubricator to 3,000 psi-test OK. RIH w/2.70" blind box and tag 7,411'. Fluid level at 3,170'. POOH. RIH w/ 2.50" DD bailer to 7,913' and tag fill. POOH. Recovered 1/8 cup of mud. RD Slickline. • • tei Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 06/24/2015-Wednesday PTW and JSA. Spot equipment and rig up lubricator. Pressure test lubricator to 250 psi low and 3,000 psi high. TP-700 psi. RIH w/2.62" GR and tie into Expro CBL log. Tag obstruction at 7,880'. Run correlation log and send to town. Get ok to set plug at 7,840'. POOH. RIH w/2.50" CIBP and tie into Pollard GR correlation log dated 6/24/15. Spot plug at 7,840'. Set plug. Lost 100 lbs on wt indicator. Picked up 30' and dropped back down and tagged plug. POOH. Good set. RIH w/2-1/2" x 20' dump bailer full of 16.6 ppg ACE cement down to 7,680' tied into Pollard correlation log. Could not get past this depth. POOH. RIH w/2" x 20' dump bailer full of 16.6 ppg ACE cement and tie into Pollard correlation log. Dump 5' of cement on top of plug at 7,840'. POOH. Good dump. RIH w/2" x 20' dump bailer full of 16.6 ppg ACE cement and tie into Pollard correlation log. Dump 5' of cement on top of plug at 7,840'. POOH. Good dump. Cement in place at 16:45 hrs.Total of 10' cement on top of plug. Est TOC at 7,830'. RIH with GPT tool, tie into Pollard correlation log and logged to 7,500'. Found fluid level at 2,950'. POOH. Rig down lubricator and turn well over to field. 07/07/2015-Tuesday PTW,JSA and SIMOPS. Spot PESI equipment and then SLB N2 truck. Rig up lubricator and rig up N2 thru choke skid. PT N2 equipment to 4,000 psi and also PT lubricator with N2 to 250 psi low and 4,000 psi high. Well had 690 psi on tubing. RIH w/GPT w/2-1/2" x 20' Connex HC, 3 spf, 60 deg phase perf gun and tie into Expro CBL log.Tools set down at 2,183'.Tried several times to get thru. Brought N2 on line at 600 scfm at 1,580 psi and went right past tight spot. Shut off N2 and tools set down at 2,500'. Brought N2 back on at 520 scfm at 1,680 psi and went right thru tight spot. Kept pumping N2 and went on down hole with tools looking for fluid level. Shut N2 down at 18,500 scf total N2 pumped at final pressure of 2,000 psi. Tools were at 6,900' when N2 was shut down. Found fluid level at 7,390'. Ran correlation log from 7,450' to 6,490' and send to town. Get ok to shoot from 6,726' to 6,746'. BHP was 2,545 psi and TP- 1,644 psi. Fired shot and BHP went to 2,531 psi and TP- 1,640.After 5 min BHP was 2,542 psi and TP 1,632 psi. Showed no warming or cooling across perf.All shots fired and bottom of gun were wet. Rigged down SLB N2 unit. Change out GPT tool to just shooting GR. RIH w/2-1/2" x 20' Connex HC, 3 spf, 60 deg phase and tie into Pollard correlation 1st run. Ran correlation log and send to town.Town said to perf from 6,714'to 6,734' (open hole log perf depth is 6,726' to 6,746').Spotted shot and fired gun with 1,497 psi on tubing. Went to 1,495 psi after shot and still 1,495 psi after 5 min. POOH. All shots fired, bottom of gun wet and TP- 1,475. Rig down lubricator and turn well over to field. 07/28/2015-Tuesday Meet at KGF office. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 psi low and 2,000 psi high.TP- 12.7 psi. RIH w/2.75" x 29" dummy plug and tag at 7,383' KB (probably module#10). POOH. Found fluid level at 71' KB. RIH with 2-1/2" bailer with bottom sealed to 126' KB.Wait couple minutes to see if bailer fills with fluid to double check fluid level. POOH. Bailer full of fluid. Rig down lubricator and turn well over to field. • ill Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date CLU-11 50-133-20559-00 206-058 5/16/15 8/14/15 Daily Operations: 07/29/2015-Wednesday PTW, SIMOPS and JSA. Rig up lubricator and N2 equipment. PT lubricator to 250 psi low and 3,000 psi high. Pump 15K SCF of N2. RIH with 2.73" fluted centralizer and tag fluid at 3,000' KB. Pump 20K scf more of N2 (35K scf total). Final pressure was 1,870 psi. RIH with same and set down at 7,390' KB (Module#10). Fluid level is below this depth. RIH with 3" GS and AD-2 stop and set down at 4,850' KB.Acted like pin had sheared. POOH and it had not sheared. RIH w/2.87" GR to 7,360' KB with no problem. POOH. RIH w/AD-2 stop and worked thru tight spot at 5,034'.Tried to set stop at 7,300'. Not very good spange action. POOH and stop was not on tools.Add 5' of stem and went back in hole and latched stop at 7,388' KB. Pull stop up to 7,300' KB and set stop. RIH w/2.76" x 21" drift to 7,300' KB and tag top of AD-2 stop. RIH w/Weatherford packing plug(72" length plug assy) and set plug. RIH and set A-stop at 7,293' KB. Rig down lubricator and turn well over to field. 08/10/2015- Monday Arrive on location. Spot up equipment. Perform JSA. Swap to .125 wire. Begin rigging up .125Wire (27) 10' 1.75" weight bar, 1.75" OJ, LSS. Pressure test lubricator to 2,500psi. Tubing @ 50psi. RIH w/2.75" Cent. Tag Fluid @ 2,626'KB. Tag top of Plug @ 7,289'KB. Lay down lubricator. Secure wellhead. Turn in permit. 08/13/2015-Thursday Arrive at Kenai Gas Field. Sign permit. Spot equipment. Perform JSA. Begin rigging up .160Wire (19) 10' 2.125" weight bar, 1.75" OJ, LSS. Pressure test lubricator to 2,500psi. Tubing @ 10psi. RIH w/2.845" Cent. Tag fluid @ 2,421'KB. Tag top of plug @ 7,317' KB. RIH w/3-1/2" tandem swab cups. Stab off, swap out cups. Fluid @ 4,000' KB. S/D with swab cups @ 5,825'KB. RIH w/tight 3-1/2" brush and 2.84'gauge ring. Work area around 5,825' KB. Tag plug again @ 7,317' KB. Made it through the tight spot with the 3-1/2" swab cups. Fluid level @ 5,850' KB. Tank strap show approx 32.6 bbls of fluid swabbed. Lay down lubricator. Secure wellhead. Turn in permit. End ticket. 08/14/2015- Friday Arrive at Kenai Gas Field. Sign permit. Perform JSA. Begin Rig up .160 wire, 12' 1.75" weight bar, 1.75" OJ, LSS. Pressure test lubricator 2,500psi. Tubing @ 10psi. RIH w/3-1/2" tandem swab cups. Tag fluid @ 5,621KB. Swab to 6,400' KB. Monitor well/flowback tank for one hour. Decision made to pull the packoff. Add 10' of lubricator. RIH w/5' prong equalizing core. S/D @ 7,319 KB'. Jar down. See no travel. No change in tubing psi (10psi). POOH. Fluid level @ 6,600'. RIH w/3" GR pulling tool. S/D @ 7,318' KB. Jar down. Could not latch, POOH. RIH w/ 10' 2.00" pump bailer. Bail top of A-stop. Bailer has two cups of sand. Metal mark. RIH w/2.75" LIB. Tag plug @ 7,3181KB. Fluid level @ 5,151' KB. Clean picture of fishneck. RIH w/3" GR pulling tool. S/D @ 7,318' KB. Jar down. Latch A-Stop and POOH. Fluid level @ 3,630' KB. RIH w/ 3" GR pulling tool. Pull packoff from 7,180' KB. Pulling heavy. Jar for 20 minutes @ 2,200#. POOH. OOH w/packoff. Full of sand. 75%of seal element missing. RIH w/3" GR pulling tool. S/D @ 7,190'KB. Work tools to 7,322' KB. Pull AD2 Slip stop. Hang up several times. Fluid level @ 1,750' KB. OOH w/AD2 slip stop. Most of seal element recovered. Final tubing 50psi. Rig down. Turn in permit. Secure wellhead. End ticket. • III CLU-11 Hulcorp Alaska.1.1k 2,491' FSL,,2,291' FWL SCHEMATIC ritliciiit#: 206-058 Sec. 4, T5N, R11 W, S.M. API#: 50-133-20559-00 y Property Des: ADL-324602 KB Elevation: 56'(21'AGL) Lat: 60°33' 10.707"N Conductor Long: 151° 13'07.001"W 20" X-52 131 ppf Spud Date: 04/28/2006 Top Bottom TD Reached: 05/11/2006 MD 0' 136' Riq Released: 05/15/2006 , TVD 0' 136' LI 1 7. Fluid 2,950' Surface Casing 13-3/8" L-80 68 ppf BTC Tree cxn =4-3/4"Otis Top Bottom ;al MD 0' 1,602' TVD 0' 1,489' 16"hole Cmt w/516 sks(228 bbls)of Top of Cement(est.) 12.0 ppg,Type 1 cmt @ 5,095'MD Sterling Cl (500'above 9-5/8"shoe) Interval: UBE Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' TVD 0' 4,355' 12-1/4"hole Cmt w/95 sks(36 bbls) 12.5 ppg class G Cast Iron Bridge Plug @ 7,840' Lead,&237 sks(49 bbls) 15.8 ppg class G Tail Dump bail 10'of cement - VELOCITY STRING FISH: 11 Production Tubing 3-1/2" L-80 9.3 ppf EUE Top of Coil: 1-3/4"coil @ 7,912'cut with radial Top Bottom 8rd torch,milled down with 2.75"mill on 6/13/15 MD 0' 9,284' ( ) TVD 0' 7,894' Fish:4.1'of 1.0"wt bar lost 6/06/15 @ 7,919' If ' 8 1/2"hole Cmt w/1,550 sks(325 bbls) Fish:4.0'of 1.0"wt bar lost 6/04/15 @ 8,162' ? ` • of 15.8 ppg,class G cmt Plug:PXN plug set 5/16/15 @ 8,209' d j f .'r + Excape System Details Velocity String l - 11 Excape modules placed 1-3/4" HO7OFF(0.125"WT) Igi -Green control line fired module 1 Install 7/21/07; Partially removed control line fired modules 2 thru 7 Top Bottom 1 s - contol line fired modules 8 thru 11 MD 7,912' 8,185' -Ceramic flapper valves below each module except for module 1 TVD 6,522' 6,795' t Perfs MD(RKB)(Beluga Zones): BHA: UBE 6,726'-6,746'(7/7/15) 2.5"OD x 1.5"ID grapple connector 2.5"OD x 1.5"ID x 10'weight bar w/drain I I, Mod-10 7,373'-7,383'(Cmt Sqzd 4/3/07,Perfed 5/1/07) 2.5"OD x 1.135"ID NoGo profile nipplePeri: 7,383'-7,400'(Perfed 5/1/07) 2.48"OD x 1.5"guide nose 11 Mod 9 7,472' 7,482'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) Slickline tag EOVstrg 8225' (4/18/12) B , Mod 8 7,686' 7,696'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) Mod 7 7,868' 7,878' Not Shot ' ^ - Mod-6 7,929'-7,939'(Perfed 4/1/07) Excapeppconventional S pe System Detailst Peri: 7,939' 7,946'(Perfed 4/1/07) nv oionaflappers ., Mod-5 8,208'-8,218'(Frac'd 9/28/06) -Mod-1ppflm � Mod-4 8,384'-8,394'(Frac'd 9/28/06) oou�e als ronows Ives below each Mod-3 8,496'-8,506'(Frac'd 9/28/06) Flappers MD(RKB): Mod-2 8,606'-8,616'(Frac'd 9/28/06) Ili e Mod-1 9,085'-9,095'(Frac'd 9/28/06) - e- e- 7; (Broken CT 9/28/2006) e 7' 4 '(�rolcen CI8/3H8883/ TD PBTD odu�e- .5 '( ro en I 9,305'MD 9,247'MD Module-2 8,625'(Broken CT 9/28/2006) 7,915 TVD 7,857'TVD Well Name&Number: Cannery Loop#11 Lease: ADL-324602 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA _ igle @KOP and Depth: ±3°/220 ft @ 650'MD Angle/Perfs: 4°-,1° Maximum Deviation: 45.6°@ 2,883' Date Completed: 5/18/2006 Ground Level(above MSL): 35.0' RKB(above GL): 21.0' Revised By: Donna Ambruz Downhole Revision Date: Proposed Schematic Revision Date: 1/4/2016 OF rif� �w\l/j, s THE STATE Alaska Oil and Gas ti�►;,-s � - �, of J j\ J(j\ Conservation Commission = 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OF ��"''_ rx Main: 907 279.1433 ALAS Fax 907.276 7542 SCANNED JUL 0 8 201 www,aogcc.alaska.gov Stan Porhola S g' Operations Engineer D 0 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Cannery Loop Field, Beluga Pool, Cannery Loop #11 Sundry Number: 315-370 Dear Mr. Porhola: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this I'7 day of June, 2015 Encl. ECEWED • STATE OF ALASKA JUN 16 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION , (.06 APPLICATION FOR SUNDRY APPROVALS AOGCC Ye--- ,)c.5.- 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool❑ Repair Well❑ Change Approved Program ry Suspend❑ Plug Perforations Q • Perforate❑ Pull Tubing❑ Time Extension 0 Operations Shutdown❑ Re-enter Susp.Well 0 Stimulate❑ Alter Casing❑ Other. ❑ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number • Exploratory ❑ Development 0 • 206-058 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ • 6.API Number. Anchorage,Alaska 99503 50-133-20559-00 7.If perforating: 8.Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? CO 231 Cannery Loop#11 ' Will planned perforations require a spacing exception? Yes ❑ No 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 324602 • Cannery Loop Unit/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): 9,305 • 7,915 ' 9,247 7,857 N/A 7,912 Casing Length Size MD ND Burst Collapse Structural . Conductor 136' 30" 136' 136' Surface 1,602' 13-3/8" 1,602' 1,489' 3,090 psi 1,540 psi Intermediate 5,595' 9-5/8" 5,595' 4,355' 6,330 psi 3,810 psi - Production 9,263' 3-1/2" 9,284' 7,894' 10,160 psi 10,530 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80 9,284 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): N/A;N/A N/A;N/A 12.Attachments: Description Summary of Proposal ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development ❑� Service 0 14.Estimated Date for 15.Well Status after proposed work: 06/29/15 Commencing Operations: Oil ❑ Gas ❑✓ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: VVI NJ ❑ GINJ ❑ WAG 0 Abandoned 0 Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Phone: 907-777-8412 Email sporhola@hilcorp.com Printed Name Stan Porhola Title Operations Engineer Wi,c7/5 Signature \, �jj Phone 907-777-8412 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Cr 315- 370 Plug Integrity ❑ BOP Test X Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No L'Jd Subsequent Form Required: /©— y.y (retv t'4- (4/3,s--247 4IP APPROVED BY / f o� Approved by: A` COMMISSIONER THE COMMISSION Date: (�!/ / / (S OR' GlaNAIlborn-rmt LC'/7'/J SubmitForm ane -Fonn 10-403(Revised 10/2012) , hs 6Wthe date of approval. Attachments in Duplicate �RBDMS C JUN 2 5 1D fes- rS/�6./6' /S . Well Prognosis Well: CLU-11 Ilikorp Alaska,LL' Date:6/15/2015 Well Name: CLU-11 API Number: 50-133-20559-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: June 29th, 2015 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-058 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: Current Bottom Hole Pressure: — 1,417 psi @ 7,694' ND (Based on BHP Survey on 4/18/12) Maximum Expected BHP: —2,560 psi @ 5,890' ND (Based on RFT from CLU-13 2/22/15) Max. Allowable Surface Pressure: — 1,971 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft) Brief Well Summary Cannery Loop Unit #11 was drilled as a Grass roots EXCAPE completion in 2006 to target gas sands in the Beluga formations. The initial perforations came with water immediately at high rates. A PLT showed most of the water flowing from the top five modules so all perfs above 7,730' MD were squeezed which did shut off most of the water. After the squeeze, module 10 was re-shot but not frac'd and this added some gas rate. In 2007 a 1-3/4" velocity string was RIH to 8,185' MD to help unload water. The well recently loaded up and has been unable to flow. The coil tubing velocity string was found to be sanded in and successfully fished down to 7,912' in June 2015.The rest of the fish is stuck (unable to recover) and left downhole after several attempts to jar free. The purpose of this work/sundry is to plugback the well below the coil tubing velocity string fish.This sundry adds steps between step#11 and step#12 of sundry 315-267. Notes Regarding Wellbore Condition • Well is SI, unable to sustain flow, built up with fill,fish left in the well. Current SITP is 500 si. E-line Procedure: 1. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. a. Tree connection is 6.5" OTIS. b. SITP will be 500 psi (Nitrogen Pressure). 2. MU 3-1/2" CIBP and setting tool. 3. RIH and set CIBP at+/-7,900'. POOH w/setting tool. 4. MU dump bailer and fill w/cement. 5. RIH and dump cement on top of CIBP (10' =4 gallons). POOH w/dump bailer. 6. RD E-line. 7. Turn well over to production. Zc7 Attachments: 1. Actual Schematic £ "�` 3?� pct 2. Proposed Schematic 31-5 (C CLU-11 Pad-3 ACTUAL Ililcorp Alaska,LLC 2,491' FSL, 2,291' FWL SCHEMATIC 1 Sec. 4, T5N, R11W, S.M. API#: 50-133-20559-00 Property Des: ADL-324602 KB Elevation: 56' (21'AGL) li Lat: 60°33' 10.707"NConductorLong: 151° 13'07.001"W20" X-52131ppfSpud Date: 04/28/2006TopBottomTD Reached: 05/11/2006 MD o' 136' Rig Released: 05/15/2006 TVD o' 136' • Surface Casing 13-3/8" L-80 68 ppf BTC Tree cxn=4-3/4"Otis Top Bottom MD 0' 1,602' 4.[LITVD 0' 1,489' ' 16"hole Cmt w/516 sks(228 bbls)of Top of Cement(est.) I I 12.0 ppg,Type 1 cmt @ 5,095'MD Sterling Cl (500'above 9-5/8"shoe) Interval: Di 6281-6537 ft MD Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' T1� TVD 0' 4,355' 7 12-1/4"• hole Cmt w/95 sks(36 bbls)12.5 ppg class G Lead,&237 sks(49 bbls)15.8 ppg class G Tail I p. VELOCITY STRING FISH: Production Tubing Top of Coil: 1-3/4"coil @ 7,912'cut with radial �_ 3 1/2" L-80 9.3 ppf EUE torch,milled down with 2.75"mill on 6/13/15 DI Top Bottom 8rd ( ) 3 . MD 0' 9,284' Fish:4.1'of 1.0"wt bar lost 6/06/15 @ 7,919' D! TVD 0' 7,894' Fish:4.0'of 1.0"wt bar lost 6/04/15 @ 8,162' j 8 i. of 15.8 ppg,class G cmt-1/2"hole Cmt w/1,550 sks(325 bbls) l Plug:PXN plug set 5/16/15 @ 8,209' _, ""�_.. _.... i ,. . . ' . . � . • Excape System Details Velocity String • ., ` 11 Excape modules placed 1-3/4" HO7OFF(0.125"WT) k+ 1J -Green control line fired module 1 Install 7/21/07; Partially removed . control line fired modules 2 thru 7 Top Bottom contol line fired modules 8 thru 11 MD 7,912' 8,185' �� -Ceramic flapper valves below each module except for module 1 TVD 6,522' 6,795' Perfs MD(RKB)(Beluga Zones): III Mod 11 6,593' 6,603' Not Shot BHA:OD x 1.5"ID grapple connector T�yy3 Mod-10 7,373'-7,383'(Cmt-Sqzd-4/3/07, Perfed 5/1/07) 2.5"2.5"OD x 1.5"ID x 10'weight bar w/drain 1!i f Perf: 7,383'-7,400'(Perfed /1/07) 2.5"OD x 1.135"ID NoGo profile nipple Mod 9 7,472' 7,482'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) 2.48"OD x 1.5"guide nose + I I Mod 8 7,686' 7,696'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) Slickline tag EOVstrg 8225' (4/18/12) :' 3 Mod 7 7,868' 7,878' Not Shot Mod-6 7,929'-7,939'(Perfed 4/1/07) Cxf.d e a si r r u taus ® ' Perf: 7,939'-7,946'(Perfed 4/1/07) n �= 2rs 151 Mod-5 8,208'-8,218'(Frac'd 9/28/06) is ...�� Ives below each *+ MN +, Mod-4 8,384'-8,394'(Frac'd mon as . .ows: 1* 1`711 9/28/06) Flappers MD(RKB): Mod-3 8,496'-8,506'(Frac'd 9/28/06) e- ' Mod-2 8,606'-8,616'(Frac'd 9/28/06) -Ite- .1 46, Mod-1 9,085'-9,095'(Frac'd 9/28/06) e- 7' ,(Broken CT 9/28/2006) e- g k CTg2g2 6 e-4 4 ' Broken CT 9%28%2$$6; e-3 ;51 TD PBTD Module-2 8,625'(Broken CT 9/28/2006) 9,305'MD 9,247'MD Module-1 NA 7,915 ND 7,857'ND Well Name&Number: Cannery Loop#11 Lease: ADL-324602 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA gle @KOP and Depth: ±3°/220 ft @ 650'MD Angle/Perfs: 4°- 1° Maximum Deviation: 45.6°@ 2,883' Date Completed: 5/18/2006 Ground Level(above MSL): 35.0' RKB(above GL): 21.0' Revised By: Stan Porhola Downhole Revision Date: 6/13/2015 Schematic Revision Date: 6/15/2015 II CLU-11 Pad-3 PROPOSED Hileorp Alaska,LL(: 2,491' FSL, 2,291' FWL SCHEMATIC perm . . .. : . Sec. 4, T5N, R11 W, S.M. API#: 50-133-20559-00 Property Des: ADL-324602 KBciii e56' (21'AGL) 0.707"N'07.001"WLLI04/28/20065/11/200605/15/2006 TVD 0' 136' ; Surface Casing 13-3/8" L-80 68 ppf BTC Tree cxn=4-3/4"Otis Top Bottom MD 0' 1,602' TVD 0' 1,489' I 16"hole Cmt w/516 sks(228 bbls)of Top of Cement(est.) 12.0 ppg,Type 1 cmt @ 5,095' MD Sterling C1 (500'above 9-5/8"shoe) Interval: ', 6281-6537 ft MD Intermediate Casing y:' 9-5/8" L-80 40 ppf BTC ti Top Bottom 7 MD 0' 5,595' Cast Iron Bridge Plug @ 7,900' 1 TVD 0' 4,355' Dump bail 10'of cement 12-1/4"hole Cmt w/95 sks(36 bbls)12.5 ppg class G ` " Lead,&237 sks(49 bbls)15.8 ppg class G Tail _* VELOCITY SYR ''' 'H: - e 1 Production Tubing Top of Coil: 1-3/4"coil @ 7,912'cut with radial 3-1/2" L-80 9.3 ppf EUE torch,milled down with 2.75"mill on 6/13/15 I I MD Top Bottom 8rd 0' 9,284' Fish:4.1'of 1.0"wt bar lost 6/06/15 @ 7,919' .\\lit kAS TVD 0' 7,894' Fish:4.0'of 1.0"wt bar lost 6/04/15 @ 8,162' % 8-1/2"hole Cmt w/1,550 sks(325 bbls) Pluq:PXN plug set 5/16/15 @ 8,209' of 15.8 ppg,class G cmt ''i Excape System Details Velocity String - 11 Excape modules placed 1-3/4" HO7OFF(0.125"WT) ,�;' I(2 -Green control line fired module 1 Install 7/21/07; Partially removed « arc - control line fired modules 2 thru 7 Top Bottom , t - contol line fired modules 8 thru 11 MD 7,912' 8,185' -Ceramic flapper valves below each module except for module 1 TVD 6,522' 6,795' w - Perfs MD(RKB)(Beluga Zones): BHA: k, �1 Mod 11 6,593' 6,603' Not Shot 2.5"OD x 1.5"ID grapple connector �� Mod-10 7,373'-7,383'(-Cmt-Sqzd-4/3/07,d-4/3/07,Perfed 5/1/07) 2.5"OD x 1.5"ID x 10'weight bar w/drain 6'P° DI f Perf: 7,383'-7,400'(Perfed 5/1/07) 2.5"OD x 1.135"ID NoGo profile nipple IA -�y� 2.48"OD x 1.5"guide nose ` R 1!�l, Mod 8 7,686' 7,696'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) Slickline tag EOVstrg 8225' (4/18/12) Mod 7 7,868' 7,878' Not Shot i Mod-6 7,929'-7,939'(Perfed 4/1/07) ER6d e a st r-i u mns S Pert 7,939'-7,946'(Perfed 4/1/07) ,�p v app2rs ' / Ijii Mod-5 8,208'-8,218'(Frac'd 9/28/06) -C'a rTic fs Ives below each 6.;i Mod-4 8,384'-8,394'(Frac'd 9/28/06) moTut e as ows: rE Mod-3 8,496'-8,506'(Frac'd 9/28/06) Flappers MD(RKB): ; o u e- Mod-2 8,606'-8,616'(Frac'd 9/28/06) o u e , 3 Mod-1 9,085'-9,095'(Frac'd 9/28/06) o u e- 7 j (Broken CT 9/28/2006) 8 o u e-4 Broken CT 9%28%2$$63 o u e-3 ' TD PBTD Module-2 8,625'(Broken CT 9/28/2006) 9,305'MD 9,247 MD Module-1 NA 7,915 TVD 7,857'TVD Well Name&Number: Cannery Loop#11 Lease:_ ADL-324602 - County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA Igle @KOP and Depth: ±3°/220 ft @ 650'MD Angle/Perfs: 4°-+1° Maximum Deviation: 45.6°@ 2,883' Date Completed: 5/18/2006 _ Ground Level(above MSL): 35.0' RKB(above GL): 21.0' Revised By: Stan Porhola Downhole Revision Date: Proposed Schematic Revision Date: 6/15/2015 � pTye • �w\��v�F/Li" THE STATE Alaska Oil and Gas ti��► M ofALASI�:A� Conservation Commission ilex __ = 333 West Seventh Avenue Vii,MGOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 A Main: 907.279 1433 ALASFax 907 276 7542 www aogcc alaska.gov SCANNED Iv1AY 1. 4 2015 Stan Porhola Operations Engineer nn ( � 056 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Cannery Loop Field, Beluga Pool, Cannery Loop #11 Sundry Number: 315-267 Dear Mr. Porhola: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, )04,, Cathy P. oerster / Chair DATED this (�day of May, 2015 Encl. IVSD • STATE OF ALASKA Ml`'i 4}�j �s ALASKA OIL AND GAS CONSERVATION COMMISSION IJTS s . APPLICATION FOR SUNDRY APPROVALS' 20 MC 25.280 1.Type of Request: Abandon 0 Plug for Redrill ❑ Perforate New Pool 0 Repair Well❑ Change Approved Program 0 Suspend❑ Plug Perforations❑ Perforate 0 • Pull Tubing❑ Time Extension 0 Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate❑ Alter Casing 0 Other. Pull Velocity String ❑✓ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Fe.„ /ift,f s Hilcorp Alaska,LLC Exploratory ❑ Development 2• 206-058 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service El • 6.API Number. Anchorage,Alaska 99503 50-133-20559-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231 Cannery Loop#11 • Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 324602 ' Cannery Loop Unit/Beluga Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 9,305 ' 7,915 ' 9,247 7,857 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 136' 30" 136' 136' Surface 1,602' 13-3/8" 1,602' 1,489' 3,090 psi 1,540 psi Intermediate 5,595' 9-5/8" 5,595' 4,355' 6,330 psi 3,810 psi Production 9,263' 3-1/2" 9,284' 7,894' 10,160 psi 10,530 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80 9,284 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): N/A;N/A N/A;N/A 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic❑ Development ❑r Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 05/11/15 Oil ❑ Gas ❑ WDSPL ❑ Suspended 0 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG 0 Abandoned 0 Commission Representative: GSTOR 0 SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Phone: 907-777-8412 Email sporhola@hilcorp.com Printed Name /�� Rh/r.----- Stanann Porhola Title Operations Engineer Signature '" Phone 907-777-8412 Date Sig /S COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Cr 3IS- 2le1 Plug Integrity ❑ BOP Testi Mechanical Integrity Test ❑ )�Loo�cation Clearancele ❑� '7 Other: L>cel..) o S:. L�L)r 7 ( /r'l A: / - I G / [ (5:. Spacing Exception Required? Yes ❑ No RI Subsequent Form Required: /0_Li(.11 APPROVED BY Approved by: 4167 / te.,...1 "� COMMISSIONER THE COMMISSION Date:S 6 .-/� ' — } Submit Forrn and Form 10-403(Revised `' QrRc1aG4tIJsAlJr 12 months frtm the date of approval. .-/attach ents m Dupiicate BDM3,�t'I MAY 1 1 2015.60,7' "-' -� ' S ' �'� IIWell:Well PrognosisCLU-11 Hilcorp Alaska,LL Date:5/04/2015 Well Name: CLU-11 API Number: 50-133-20559-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: May 11th, 2015 Rig: N/A Reg.Approval Req'd? 403 , Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-058 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907)331-8228(M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907)229-4824(M) AFE Number: Current Bottom Hole Pressure: - 1,417 psi @ 7,694' TVD (Based on BHP Survey on 4/18/12) Maximum Expected BHP: -2,560 psi @ 5,890' TVD (Based on RFT from CLU-13 2/22/15) Max. Allowable Surface Pressure: -- 1,971 psi (Based on actual reservoir conditions and gas gradient to surface(0.10psi/ft) Brief Well Summary Cannery Loop Unit #11 was drilled as a Grass roots EXCAPE completion in 2006 to target gas sands in the Beluga formations. The initial perforations came with water immediately at high rates. A PLT showed most of the water flowing from the top five modules so all perfs above 7,730' MD were squeezed which did shut off most of the water. After the squeeze, module 10 was re-shot but not frac'd and this added some gas rate. In 2007 a 1-3/4" velocity string was RIH to 8,185' MD to help unload water. The well recently loaded up and has - been unable to flow. 5l1 The purpose of this work/sundry is to pull the velocity string. cleanout fill.and add perforations in the Beluga. .11,.11,- & t.d c 5 s,:'` Notes Regarding Wellbore Condition • Well is SI, unable to sustain flow, built up with fill.Current SITP is 299 psi. s' 5j- Px S1' , Co'ed Tubing Procedure J1. MIRU Coiled Tubing, PT BOPS to 4,500 psi Hi 250 Low. V Kwc - 2. MU 1.75"grapple. RIH and engage velocity string hanger. , r l' I( I'i7`�� 3. Release hanger, POOH w/1.75"velocity string from 8,185'. 4. MU 2-1/4" mill and BHA. 5. RIH w/1.75"coil to 8,318' MD and tag top of fill. 6. Clean out fill to 9,100' MD w/6%KCI and Nitrogen. 7. Displace well fluids with Nitrogen. a. Estimated volume of displaced 6%KCI is 80 bbl. 8. Leave well with 1,000 psi Nitrogen SITP or take well to production if it unloads. 9. POOH w/coil. LD 2-1/4" mill BHA. 10. RD Coiled Tubing. 11. Turn well over to production. E-line Procedure: 12. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. a. Tree connection is 6.5"OTIS. b. SITP will be 1,000 psi (Nitrogen Pressure). • Well Prognosis Well: CLU-11 Hilcorp Alaska,LL Date:5/04/2015 13. RU 2-1/2" 6 spf Connex HC wireline guns. 14. RIH and perforate the following intervals: Zone Sands Top(MD) Btm (MD) FT SPF Beluga UBE 6,726' 6,746' 20' 6 Beluga MBX 7,280' 7,298' 18' 6 Beluga MB9 7,873' 7,903' 30' 6 a. Bleed tubing pressure to 1,000 psi before perforating. b. Proposed perfs shown on the proposed schematic in red font. c. Correlate using CBL Log dated 6/08/06(CBL Tie-in log). d. Use Gamma/CCL/to correlate. e. Record tubing pressures before and after each perforating run. f. Proposed intervals are in the Beluga Gas Pool. g. Distance to nearest well open in same sands=2,800'to CLU#4. h. Spacing allowance is based CO 231; no wells within same qtr-qtr. 15. RD E-line. 16. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Coil BOPE Schematic CLU-11 ACTUAL Pad-3 Ilile.orpAlaska.LIM 2,491' FSL, 2,291' FWL SCHEMATIC Permit 206-058 Sec. 4, T5N, R11W, S.M. API#: 50-133-20559-00 Property Des: ADL-324602 p KB Elevation: 56'(21'AGL) 1:1A Lat: 60°33' 10.707"N Conductor Long: 151° 13'07.001"Wlil 20" X-52 131 ppf Spud Date: 04/28/2006 Top Bottom TD Reached: 05/11/2006MDo' 136' Rig Released: 05/15/2006TVD 0' 136' ISurface Casing I '; 13-3/8" L-80 68 ppf BTC Tree cxn=4-3/4"Otis .` Top Bottom MD 0' 1,602' • TVD 0' 1,489' ! 16O " h hole Cmt w/516 sks(228 bbls)of Top of Cement(est.) ppg,Type 1 cmt @ 5,095'MD Sterling Cl (500'above 9-5/8"shoe) Interval: 6281-6537 ft MD Intermediate Casing 9-5/8" L-80 40 ppf BTC Velocity String t,7 Top Bottom 1-3/4" HO7OFF(0.125"WT) .'1 MD 0' 5,595' Install 7/21/07 ,` TVD 0' 4,355' Top Bottom 12-1/4"hole Cmt w/95 sks(36 bbls)12.5 ppg class G MD 0' 8,185' Lead,&237 sks(49 bbls) 15.8 ppg class G Tail TVD 0' 6,795' - BHA: 2.5"OD x 1.5"ID grapple connector fir, I Production Tubing 2.5"OD x 1.5"ID x 10'weight bar w/drain 3-1/2" L-80 9.3 ppf EUE 2.5"OD x 1.135"ID NoGo profile nipple III Top Bottom 8rd 2.48"OD x 1.5"guide nose311. MD 0' 9,284' Slickline tag EOVstrg 8225' (4/18/12) 11 y TVD 0' 7,894' _ ( r r . 8-1/2"hole Cmt w/1,550 sks(325 bbls) I v, i?. I q.2., of 15.8 ppg,class G cmt Tan 3/4"tools 4/15/15 @ 8318' I pm.. Excape System Details - 11 Excape modules placed • I -Green control line fired module 1 control line fired modules 2 thru 7 ~ contol line fired modules 8 thru 11 txcape bystem uetalis IT • -Ceramic flapper valves below each module except for module 1 4,104cinvqinApppers 'i Perfs MD(RKB)(Beluga Zones): -moerc3u €caso�ows:valves below each I f Mod 11 6,593' 6,603' Not Shot me Flappers MD(RKB): Mod-10 7,373'-7,383'(Colt -4/3FOT, Perfed 5/1/07) I 1 f Perf: 7,383'-7,400'(Perfed 5/1/07) - °o u e- Mod 9 7,472' 7,482'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) o u e- '(Broken CT 9/28/2006) I I Mod 8 7,686' 7,696'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) o u e-5 7, ) Mod 7 7,868' 7,878' Not Shot o u e- 4 ;(�roken��9/28/2$$6; Mod-6 7,929'-7,939'(Perfed 4/1/07) o u e-4 4 ( roKen / / UU ) Perf: 7,939'-7,946'(Perfed 4/1/07) /, 1[x]1 Mod-5 8,208'-8,218'(Frac'd 9/28/06) Module-3 8,625'(Broken CT 9/28/2006) �' Module-1 NA 4" i Mod-4 8,384'-8,394'(Frac'd 9/28/06) t'', 1L-51 Mod-3 8,496'-8,506'(Frac'd 9/28/06) . Mod-2 8,606'-8,616'(Frac'd 9/28/06) Mod-1 9,085'-9,095'(Frac'd 9/28/06) TD PBTD 9,305'MD 9,247'MD 7,915 TVD 7,857'TVD Well Name&Number:. Cannery Loop#11 Lease: ADL-324602 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA gle @KOP and Depth: ±3°/220 ft @ 650'MD Angle/Perfs: 4° 1° Maximum Deviation: 45.6°@ 2,883' Date Completed: 5/18/2006 Ground Level(above MSL):_ 35.0' RKB(above GL): 21.0' Revised By: Stan Porhola Downhole Revision Date: 4/15/2015 Schematic Revision Date: 5/4/2015 I CLU-11 PROPOSED Pad-3 'Warp Alaska.r.r.c 2,491' FSL, 2,291' FWL SCHEMATIC Permit#: 206-058 Sec. 4, T5N, R11 W, S.M. API#: 50-133-20559-00 Property Des: ADL-324602 KB Elevation: 56' (21'AGL) t Lat: 60°33' 10.707"N Long: 151° 13'07.001"W ; [,." 20" X-52 131 ppf Spud Date: 04/28/2006 Top Bottom TD Reached: 05/11/2006 r'' MD 0' 136' Rio Released: 05/15/2006 ( TVD 0' 136' t Surface Casing *1:113-3/8" L-80 68 ppf BTC Tree cxn=4-3/4"Otis ., Top Bottom MD 0' 1,602' I TVD 0' 1,489' 16"hole Cmt w/516 sks(228 bbls)of Top of Cement(est.) @ 5,095'MD Sterling Cl 12.0 ppg,Type 1 cmt r (500'above 9-5/8"shoe) Interval: i -.1 6281-6537 ft MD r' Intermediate Casing UBE 9-5/8" L-80 40 ppf BTC Velocity String i7 rJ Top Bottom 1-3/4" HO7OFF(0.125"WT) �� MBX MD 0' 5,595' Proposed Pull TVD 0' 4,355' Top Bottom 12-1/4"hole Cmt w/95 sks(36 bbls)12.5 ppg class G rs MD 0' 0' ' Lead,&237 sks(49 bbls) 15.8 ppg class G Tail TVD 0' 0' (f Production Tubing 3-1/2" L-80 9.3 ppf EUE ; I I Top Bottom 8rd MD 0' 9,284' TVD 0' 7,894' �' . MB9 8-1/2"hole Cmt w/1,550 sks(325 bbls) In)1 ib of 15.8 ppg,class G cmt 1 �^ Excape System Details L - 11 Excape modules placed -Green control line fired module 1 ;„ (� - control line fired modules 2 thru 7 - contol line fired modules 8 thru 11 txcape aystem uetans I!f • Ceramic flapper valves below each module except for module 1 _a,p. 9nvq:tifig�iipppers 'r Perfs MD(RKB1(Beluga Zones): .erame afsig wsalves below each II f Mod 11 6,593' 6,603' Not Shot UBE 6,726'-6,746' (Proposed) Flappers MD(RKB): I 1 f MBX 7,280'-7,298' (Proposed) • -Ilie Mod-10 7,373'-7,383'(Cmt Sqzd-4/3/07,Perfed 5/1/07) e- e- ;(Broken CT 9/28/2006) "!IT Perf: 7,383'-7,400'(Perfed 5/1/07) e-66 7, 1 Mod 9 7,472' 7,482'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) e--5 ;(�ro�Cen�� /?� /?�gg�) Mod 8 7,686' 7,696'(Frac'd 9/28/06,Cmt Sqzd 4/3/07) e-3 ,5 ( ro en / / ) - Mod 7 7,868' 7,878' Not Shot Module-2 8,625'(Broken CT 9/28/2006) % 1591 MB9 7,873'-7,903' (Proposed) Module-1 NA S' I I Mod-6 7,929'-7,939'(Perfed 4/1/07) Perf: 7,939'-7,946'(Perfed 4/1/07) Mod-5 8,208'-8,218'(Frac'd 9/28/06) ,. Mod-4 8,384'-8,394'(Frac'd 9/28/06) Mod-3 8,496'-8,506'(Frac'd 9/28/06) Mod-2 8,606'-8,616'(Frac'd 9/28/06) TD PBTD 9,305'MD 9,247'MD 7,915 TVD 7,857'TVD Well Name&Number: Cannery Loop#11 Lease: ADL-324602 County or Parish: Kenai Peninsula Borough _ State/Prov: Alaska Country: USA igle @KOP and Depth: ±3°/220 ft @ 650'MD Angle/Perfs: 4°->1° Maximum Deviation: 45.6°@ 2,883' Date Completed: 5/18/2006 Ground Level(above MSL): 35.0' RKB(above GL):_ 21.0' Revised By: Stan Porhola Downhole Revision Date: Proposed Schematic Revision Date: 5/4/2015 Cannery Loop Unit CLU-11 5/04/2015 nil.-.,ri. %I:..L.,.1.1.5 Cannery Loop#11 20X133/8X95/8x31/2 Coil Tubing BOP Lubricator to injection head r 1.75"Tandem Stripper nonI 1--Pg •' l t Blind/Shear_ 1/161. !:_Bhs1 ear 111111. / Y i , Ill.Blind/Shear III. =Immil Blind/Shear.l,'•o I AIM Min.--1 0,* Nom- 4 . 1111 Mud Cross O 4 1/16 10M X 4 1/16 10M IIIAISI( IIlK 1 I.0 '1I� "`��� illo I�1 �IIIII Outlet w/2-2 1/16 10M full Manual Manual111.1 Manual opening FMC valves 2 1/16 10M 2 1/16 10M 2 1/16 10M 2 1/16 10M Crossover spool 4 1/16 10M X 3 1/8 5M OO 4�� *c 1 . 3 0, 1\ tam J�Z� �3 �ti\o9 Valve,Swab,VG-300, r. \41 F�` O� DO ZP 3 1/16 ODMrFE,HWO, `U Ja,��1O�F '',. fie.4 �`.. i.•v71171 . 1, Off. -4'6 \F^ \ ' .41. /if_ t (:,,,, , -r,_...,,,,,'\k , ,h, c3.„,,, P Om'.. t.' , IN Valve,Upper Master, VG 300,3 1/16 10M FE, i 04\ HWO,DD trim OT iir k<''' `cV ,<`c•`� Z' yak-ya'�e � c Coiled Tubing head,Vetco .�I,• Gray,3 1/8 5M FE X . 3 1/8 5M stdd,w/1- '1 ■ 2 1/16 5M SSO { • .� ■ • . III U No Coil in head 1 \MU 1111 u1 I Ip p i 1P" .. '11 Valve,Master,VG-300, tif �r„ 3 1/16 10M FE,HWO, O �a DD trim r� C.'MI • Schwartz, Guy L (DOA) From: Stan Porhola <sporhola@hilcorp.com> Sent: Tuesday, May 05, 2015 10:38 AM To: Schwartz, Guy L(DOA) Subject: RE:CLU 11 (PTD 206-058) Guy, Forgot to include the procedure to set a PX plug in the tail of the velocity string on slickline. This will isolate the inside of the coil string. Slickline Procedure: 1. MIRU Slickline, PT lubricator to 3,000 psi Hi 250 Low. 2. RU 1.00" bailer. 3. RIH and tag fill at+/-8,318' MD. POOH. a. Collect sample of fill. 4. RU 1.25" PX plug. 5. RIH and set PX plug in PXN profile at 8,225' MD. 6. Bleed off coil pressure to confirm PX plug set. 7. RD Slickline. With coil rigged up, will pull the hanger into the lubricator, set the slip and pipe rams to isolate the coil x tubing annulus, bleed the pressure in the lubricator and remove the tubing hanger. Will have the rams setup for 1.75" OD coil. After the coil is pulled into the coil BOP stack,the pressure barrier would be the lower and upper master valves of the tree. Stan From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Tuesday, May 05, 2015 10:06 AM To: Stan Porhola Subject: CLU 11 (PTD 206-058) Stan, In pulling the Ct velocity string what are the pressure barriers after you pull it through the CT BOP stack?(will have to pull off lubricator at this point). Is there a downhole plug profile? I don't see any mention of pumping KWF before pulling the CT velocity string off-seat. Assume you are pulling the Vel String with 1.75"CT and that the rams are setup for this size . Guy Schwartz Senior 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 1 Image Project Wetl History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescar~ activity or are viewable by direct inspection of the file. ©~j - Q.Sg Well History File Identifier Organizing (aone> RES AN C for Items: Greyscale Items: ^ Poor Quality Originals: ^ Other: NOTES: BY: .,wos,ee iuuimiuuiuu DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: Date: /s/ P Project Proofing II I II ~) II I I III I I III BY: Maria Date: ~ D g /s/ Scanning Preparation _ ~ x 30 = ~ + ~_ =TOTAL PAGES p- (Count does not include covers a- BY: Maria .Date: ~ ~ I3 ~ ~Q D /s/ Production Scanning Stage 7 Page Count from Scanned File: (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: _~YES NO BY: Maria Date: /~/3/ ~~ g /s/ ~~ Stage 7 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I II II II I II II I I III ReScanned III IIiIIIIIIII IIIII BY: Maria Date: /s/ Comments about this file: Quality Checked 9 t~l ^ Rescan Needed III II~IIIII OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: ^ Other:: 10/6/2005 Well History File Cover Page.doc Marathon Alaska Production LL'C • /MO Alaska Asset Team P.O. Box 1949 Marathon Oil Kenai, AK 99611 Telephone (907) 283 -1371 Fax (907) 283 -1350 April 2, 2012 Cathy Foerster ,,....,,.�..-, Alaska Oil & Gas Conservation Commission '° " 333 W 7 Ave Anchorage, Alaska 99501 APR 3 4 2012 ti,,:r ±s. Commission Reference: 10 -404 Report of Sundry Well Operations Field: Cannery Loop Field 0 106 0 Well: Cannery Loop Unit #11 ED APR t 2012 Dear Ms Foerster, Attached for your records is the10 -404 Report of Sundry Well Operations for CLU -11 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, j • 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 . w RECE1VD STATE OF ALASKA ALAIlik OIL AND GAS CONSERVATION COMIVIDION AlltrOmoF SUNDRY WELL OPERATIONS 1. Operations pnted I.e �� 'lug Perforations U Stimulate U Other LJ MIT Test AI asing Performed: E nc �' d n g fl 0f1 I T ubin Pe rforate New Pool Waiver ❑ Time Extension ❑ Change Approved Program n Operat. S tdown n 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 206 - 058 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ 6. API Number: Kenai Alaska, 99611 - 1949 50 133 - 20559 - 00 - 00 7. Property Designation (Lease Number): 4'11'1° 8. Well Name and Number: ADL - 022$,7 3,),1-(©x} - t IQ Cannery Loop Unit # 11 9. Field /Pool(s): Cannery Loop Unit / Beluga Pool 10. Present Well Condition Summary: Total Depth measured 9,305' feet Plugs measured NA feet true vertical 7,914' feet Junk measured NA feet Effective Depth measured 9,247' feet Packer measured NA feet true vertical 7,856' feet true vertical NA feet Casing Length Size MD TVD Burst Collapse Structural Conductor 136' 20" 136' 136' 5,020 psi 1,530 psi Surface 1,602' 13 -3/8" 1,602' 1,489' 3,090 psi 1,540 psi Intermediate 5,595' 9 -5/8" 5,595' 4,355' 6,330 psi 3,810 psi Production 9,263' 3 -1/2" 9,284' 7,894' 10,160 psi 10,530 psi Liner Perforation depth: Measured depth: 7,373' - 9,095' feet True Vertical depth: 5,989' - 7,705' feet Excape 3 -1/2" L -80 9,284' MD 7,894' TVD Tubing (size, grade, MD & TVD): Velocity 1 - 3/4" HO7OFF 8,185' MD 6,795' 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 1,065 3 1,025 975 Subsequent to operation: 0 1,075 1 1,003 1,010 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run Exploratory ❑ Development 0 Service ❑ Stratigraphic ❑ Daily Report of Well Operations 15. Well Status after work: Oil U Gas LJ - WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 312 - 032 Contact Kevin Skiba (907) 283 -1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative Signature ""t< . Phone (907) 283 - 1371 Date April 2, 2012 MOMS APR 06 1/4(/ Form 10 -404 Revised 10/2010 t4.6112.-- Submit Original Only Y • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.regq(ilalaska.00v; doa .aogcc.prudhoe.bav(a)alaska.gov phoebe.brooks5alaska.0ov: tom.maunder(a)alaska.aov OPERATOR: Marathon Oil Co. FIELD 1 UNIT / 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 11 Type Inj. NA TVD 4355* Tubing 950 950 950 950 950 Interval 0 P.T.D. 206 - 058 Type test P Test psi 500 Casing Zero 550 550 535 535 P/F P Notes: *9 - 5/8" shoe OA NA NA NA NA NA Took 26 gas to fill. Recovered 26 gals. Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P /F_ Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi_ Casing P/F Notes: OA Well Type lnj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type lnj. TVD 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 1= Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle 1= 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 -032. Form 10 -426 (Revised 06/2010) MIT CLU - 11 03 01 12.xls • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, March 12, 2012 TO: Jim Regg 7 ( 3 f v P.I. Supervisor k ' `� SUBJECT: Mechanical Integrity Tests ` MARATHON OIL CO 11 FROM: Matt Herrera CANNERY LOOP UNIT 11 Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry TY NON - CONFIDENTIAL Comm Well Name: CANNERY LOOP UNIT 11 API Well Number: 50- 133 - 20559 -00 -00 Inspector Name: Matt Herrera Permit Number: 206 - 058 - Inspection Date: Insp Num: mitMFH120307102600 3/1/2012 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well r 11 Type Inj. N ' TVD IA o 550 - 550 535 . 535 - PTD 2060580 ' TypeTest 1 SPT Test psi 500 ' OA Interva OTHER I P /F P ' Tubing 950 - 950 950 950 950 Notes: Monobore completion NO OA. MIT performed for CINGSA order no. 9, undry 312 -032. Monday, March 12, 2012 Page 1 of 1 sim SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION CommisSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Kevin J. Skiba Regulatory Compliance Representative Marathon Alaska Production, LLC 0 — 05 P.O. Box 1949 Anchorage, AK 99611 -1949 Re: Cannery Loop Field, Beluga Pool, Cannery Loop Unit #11 Sundry Number: 312 -032 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. S'ncerely, / Daniel T. Seamount, Jr. Chair DATED this / day of February, 2012. Encl. Marathon Alaska Production LLC. • ink /, Alaska Asset Team Marathon Oil P.O. Box 1949 Kenai, AK 99611 Telephone (907) 283 -1371 Fax (907) 283 -1350 January 19, 2012 JAN 2 2017 Mr. Daniel Seamount . aska ;, Eias s.:0 3wisSiCkgt 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 #11 Dear Mr. Seamount, Submitted for your approval is the10 -403 Application for Sundry Approvals for CLU -11 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, ,...Q.A)ut-I IdA-02- 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 40.: 1/ OF ALASKA l/�""' b 0 „ .. (\. `" ALAS•IL AND GAS CONSERVATION COMMISSIII ,1A�, 2 3 ?O1 ?a�3� I A, APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 '4, ,,,, __ . .. ,.,.y, .:OiTE£IIISSIQr 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair well ❑ Cthati e 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 ❑ 206 -058 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ 6. API Number: Kenai Alaska, 99611 -1949 50- 133 - 20559 -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: Cannery Loop Unit # 11 . Spacing Exception Required? Yes ❑ o 0 9. Property Designation (Lease Number): G(�SCJ� 10. Field / Pool(s): A N.Q &397 ja fllpQa Cannery Loop Unit / 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): 9,305' • 7,914' • 9,247' - 7,856' - NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 136' 20" 136' 136' 5,020 psi 1,530 psi Surface 1,602' 13 -3/8" 1,602' 1,489' 3,090 psi 1,540 psi Intermediate 5,595' 9 -5/8" 5,595' 4,355' 6,330 psi 3,810 psi Production 9,263' 3 -1/2" 9,284' 7,894' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 7,373' - 9,095' 5,989' - 7,705' Excape 3 -1/2" L -80 9,284' Velocity 1 -3/4" HO7OFF 8,185' 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 12 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ei • 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 Signature ` ^ • Phone (907) 283 -1371 Date January 19, 2012 • c COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31 7_,..-03z. Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test T Location Clearance ❑ Other: IT- Subsequent Form Required: /()- 4 404 /� APPROVED BY / J Approved by: ‘ COMMISSIONER THE COMMISSION Date: (/ c / RBDMS FEB 21 201 .10- i 7.-- 0 R 1 G 1 N A L 3(,. 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 • • CLU 11 CLU 11 is currently completed to the Beluga via a 3 -1/2" Excape type completion, with the 3 -1/2" monobore having been cemented in place, in the open hole with cement being brought up above the 9- 5/8 shoe, which is set at 5595 ft MD. The Sterling interval extends from 6281 -6537 ft MD. Intermediate casing is set at 5595 ft MD, or approximately 86 ft MD above the Sterling C. Proposed Annuli to configure for routine pressure monitoring: • 3- 1/2 "x9 -5/8" tubing head • 9 -5/8 "x13 -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 1886 psi at 5595 ft MD/4355 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 surface shoe at 1489 ft MD. • CLU -11 • Permit #: 206 -058 Pad -3 11A II API #: 50- 133 - 20559 -00 -00 2,491' FSL, 2,291' FWL Marathon Oil Property Des: ADL- 324602 Sec. 4, T5N, R11 W, S.M. Alaska Production LLC.. KB Elevation: 56' (21'AGL) Lat: 60 33' 10.707" N Long: 151 13' 07.001" W Spud Date: 04/28/2006 Conductor TD Reached: 05/11/2006 I i 20" X -52 131 ppf Rig Released: 05/15/2006 Top Bottom MD 0' 136' ' TVD 0' 136' t P Surf Casing 13 -3/8" L -80 68 ppf BTC Tree cxn = 4 -3/4" Otis Top Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of Top of Cement (est.) 12.0 ppg, Type 1 cmt @ 5,095' MD Sterling C1 (500' above 9 -5/8" shoe) Interval: 6281 -6537 ft MD Intermediate Casing 9 - 5/8" L - 80 40 ppf BTC Velocity String Top Bottom 1 -3/4" HO7OFF MD 0' 5,595' Top Bottom * 1 1 TVD 0' 4,355' MD 0' 8,185' 12 -1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G TVD 0' 6,795' Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail BHA: ' 2.5" OD x 1.5" ID grapple connector _ 2.5" OD x 1.5" ID x 10' weight bar w/ drain i I Production Tubing 2.5" OD x 1.135" ID NoGo profile nipple 3 1/2" L -80 9.3 ppf EUE 2.48" OD x 1.5" guide nose id Top Bottom 8rd MD 0' 9,284' i TVD 0' 7,894' 8 -1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt Tag 1.00" swage 4/21/10 @ 8609' Excape System Details Excape System Details - 11 Excape modules placed - 10 Conventional flappers !il + - Green control line fired module 1 - Mod -1 no flapper - control line fired modules 2 thru 7 - Ceramic flapper valves below each - Red contol line fired modules 8 thru 11 module as follows: - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB)( Beluga Zones): Flappers MD (RKB): Mod 11 6,503' 6,603' Not Shot Module 11 6,613' Mod -10 7,373' - 7,383' (Cmt Sqzd 1/3/07, Perfed 5/1/07) Module -10 7,390' t Pert: 7,383' - 7,400' (Perfed 5/1/07) Module- 9 7,490' Mod 9 7,172' 7,182' (Frac'd 9/28/06, Cmt Sqzd 1/3/07) Module- 8 7,703' (Broken CT 9/28/2006) i Mod 8 7,686' 7,696' (Frac'd 9/28/06, Cmt Sqzd 1/3/07) Module- 7 7,886' .i. Mod 7 7,868' 7,878' Not Shot Module- 6 7,948' Mod- 6 7,929' - 7,939' (Perfed 4/1/07) Module- 5 8,227' (Broken CT 9/28/2006) ® Perf: 7,939' - 7,946' (Perfed 4/1/07) Module- 4 8,403' (Broken CT 9/28/2006) �L-jl Mod- 5 8,208' - 8,218' (Frac'd 9/28/06) Module 3 8,515' - am k- Mod- 4 8,384' - 8,394' (Frac'd 9/28/06) Et ';* Mod- 3 8,496' - 8,506' (Frac'd 9/28/06 Module- 2 8,625' (Broken CT 9/28/2006) ' ' ' ( 9/28/06) Module 1 NA Mod- 2 8,606' - 8,616' (Frac'd 9/28/06) ` Mod- 1 9,085' - 9,095' (Frac'd 9/28/06) TD PBTD 9,305' MD 9,247' MD 7,915 TVD 7,857' TVD Well Name & Number: Cannery Loop Unit #11 Lease: Cannery Loop Unit Municipality: Kenai Peninsula Borough State: Alaska I Country:) USA Perforations (MD): 7,472' - 9,094' (TVD): 6,082' - 7,703' Angle @ KOP and Depth: ± 3° / 220 ft @ 650' MD Angle /Perfs: 4° 1° Dated Completed: 9/28/2006 Completion Fluid: 6% KCL Revised By: Kevin Skiba Last Revison Date: 11/29/2011 • ,:.~' . *~ mow."`... ~' ~~: ~~, ~: '~~`,~~" . ~ { ~~;~ _ _ yA~ ~II ~{'~~ ,~- ~~ wr . ~f +E`. MICROFILMED 6/30/2010 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE C:\temp\Temporary Internet Files\OLK9\Microfilm_Marker.doc a~Q~ ~$ DATA SUBMITTAL COMPLIANCE REPORT 9/12/2008 Permit to Drill 2060580 Well Name/No. CANNERY LOOP UNIT 11 Operator MARATHON OIL CO API No. 50-133-20559-00-00 MD 9305 TVD 7914 Completion Date 9/28/2006 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: SP / GR-IEL-DENSITY/NEUTRON-SONIC SINGLE ARM CALIPER Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Typed/Frmt Number Name Scale Media No (data taken from Logs Portion of Master Well Data Maint Interval OH / Start Stop CH Received Comments ~~ C Las 13922 Induction/Resistivity yED C Asc Directional Survey I C Asc 13979 Mud Log f D C Pdf 13981 Formation Tester ~D C Pdf 13981 Formation Tester Ii.~ C Pdf 13981 Mud Log i ~D C Pdf 13981 Mud Log I ~~D C Asc 13981 Mud Log 5480 9350 Open 5/26/2006 Precision Energy Services 0 9305 Open 5/26/2006 Logging Contractor UNKNOWN 2998 5618 Open 7/13/2006 Plotted Mud Log w/Graphics 136 9305 Open 7/13/2006 Formation Log TVD 29-Apr- 2006 139 9305 Open 7/13/2006 Formation Log MD 29-Apr- 2006 136 9305 Open 7/13/2006 Drilling Dynamics TVD 29- Apr-2006 136 9305 Open 7/13/2006 Drilling Dynamics Log MD 29-Apr-2006 0 0 7/13/2006 Final LAS w/Graphics Well Cores/Samples Information: Name ADDITIONAL INFORMATION Well Cored? Y "lam Chips Received? -~f-fiQ' Analysis Y~ Received? Sample Interval Set Start Stop Sent Received Number Comments Daily History Received? '""'" Formation Tops 1~/ N Comments: DATA SUBMITTAL COMPLIANCE REPORT 9/12/2008 Permit to Drill 2060580 Well Name/No. CANNERY LOOP UNIT 11 Operator MARATHON OIL CO API No. 50-133-20559-00-00 MD 9305 TVD 7914 Completion Date 9/28/2006 Completion Status 1-GAS Current Status 1-GAS UIC N Compliance Reviewed By: Date: Page 1 of 2 ~~os~ Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Monday, September 10, 2007 1:50 PM To: 'Skiba, Kevin J.' Cc: Donovan Jr, Dennis M.; Ibele, Lyndon Subject: RE: CLU 11 (20S-Q58)--404 Report for 307-106 Thanks Kevin. i knave that there are a lot of "things" that can change in the wells. Looks. like some can be more variable than others. I have no further questions. Tom Maunder, PE AOGCC From: Skiba, Kevin J. [mailto:kskiba@marathonoil.com] Sent: Monday, September 10, 2007 1:46 PM To: Maunder, Thomas E (DOA) Cc: Donovan Jr, Dennis M.; Ibele, Lyndon Subject: RE: CLU 11 (206-058) -- 404 Report for 307-106 Tom, I have inserted the answers to your questions throughout your inquiry. 1 am reviewing the 404s submitted for this well and have some questions on this one. After all the squeeze work and clean out were (finally) accomplished, it is stated on April 13 that the remains of the composite SP were chased and milled to 7942'. • The composite bridge plug was milled and chased to a depth of 7,942'CTM on this date. On May 2, prior to perforating, a 2.500" blind box was ran to push the milled remains of the bridge plug further down hole. There was no sign of any remains. On May 6 bottom was wire line tagged at 8638' with the tool stuck for a while, then a TD of 8546' is stated. • I believe the work that you are describing took place on the entry date of May 2, 2007. The tag was believed to be at the bottom of Module #2 not the bottom hole TD. After the guns were recovered, a PLT tool string was run in the hole on May 26 and a "TD tag" at 8506 is stated. . The PLT survey equipment happened to pass through a tight spot at 8,420' and lightly sat down at 8,506'. We did not want to farce the tool past any other areas, in the well bore, which might cause damage to the equipment. 8,506' was not the TD of the well but the total depth that the PLT tool made it down the hole for this survey. Looking at the 404 sheet, I don't find any of these depths listed. • There were no signs of the bridge plug to document • Module #2 depth is shown in the well bore diagram • The depth at which a PLT survey starts at is not an indication of the total depth of the well A couple of questions ... Are the perforations below 8500' covered with fill? 9/10/2007 Page 2 of 2 • The well bore was cleaned out to 8,321'. We conclude bailing at this depth due to our intended coil tubing setting depth. If so, does it make sense to list 8500 on the "junk" line with a comment that it is fill? . We can not conclude there is fill in the well bore beyond 8,321'. We had reached our desired depth below the intended coil tubing setting depth of 8,185'. No further investigation was necessary. If the perfs below 8500' are indeed covered, should that be noted on the pert line? . This section asks for MD and TVD perforation depths. Fill is a changing variable in a welt bore depending on the well's ability to produce. The well pressure may change causing the well to unload carrying sand out of the well bore. Some wells have an inherent nature of varying TD depths, due to the build up and unloading of solids. We have provided the mast consistent information about the well's perforations in this section. 1 hope this better explains the well activities. Let me know if you have any more questions. Thanks, Kevin Skiba Production Technician Marathon Oil Company Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, September 07, 2007 10:22 AM To: Donovan Jr, Dennis M.; Walsh, Ken Cc: Skiba, Kevin 3. Subject: CLU 11 (206-058) -- 404 Report for 307-106 All, I am reviewing the 404s submitted for this well and have some questions on this one. After all the squeeze work and clean out were (finally} accomplished, it is stated on April 13 that the remains of the composite BP were chased and milled to 7942'. On May 6 bottom was wirelne tagged at 8638' with the tool s#uck for a while, then a TD of 8546' is stated. After the guns were recovered, a PLT toot string was run in the hole on May 26 and a "TD tag" at 8506 is stated. Looking at the 404 sheet, I don't find any of these depths listed. A couple of questions ... Are the perforations below ^8500' covered with fill? if so, does it make sense to list 8500 on the "junk° line with a comment that it is fill? If the perts below 8500' are indeed covered, should that be noted on the pert line? Thanks in advance for looking at this. Call or message with any questions. Tom Maunder, PE AOGCC 9/10/2007 ~ • ~c~1~~1011 MARATHON OI~ COf11p111~/ August 23, 2007 RECEIVED Mr. Tom Maunder AUG 2 7 2007 Alaska Oil & Gas Conservation Commission Alaska Oil & Gas Cons. Cammissian 333 W 7 Ave Anchorage, Alaska 99501 Anchorage Reference: 10-404 Report of Sundry Well Operations -Perforation Work and Cement Squeeze -Sundry #307-106 10-404 Report of Sundry Well Operations -Velocity String Installation - '`-~ Sundry #307-211 Field: Cannery Loop Gas Field Well: Cannery Loop Unit #11 (PTD- 206-058) Dear Mr. Maunder: Enclosed is the 10-404's for sundries 307-106 and 307-211. Sundry 307-106 reports the Addition of Module 6, Cement Squeeze of Module 8, 9 and 10, and re-perforation of Module 10 w/ 17' of additional feet below (7373'-7400'). Verbal approval was obtained on April 02, 2007 through email for the perforation changes and the following cement squeeze operation. All the work that pertains to verbal approval is covered in this sundry and operations report. Sundry 307-211 reports the installation of the 1.75" velocity string ran to a depth of 8185' and is reflected in the tubing portion of the 10-404. Attached with the 10-404's are operations summary reports for each job and a current wellbore diagram. Please send any sundries or pertinent documentation to Kevin Skiba at the above address listed. If you have any questions or need further information please call me at (907) 398-1362. Sincere , Dennis Donovan Production Engineer Enclosures: 10-404 Sundry of Well Ops 307-106 cc: AOGCC Operations Summary Report 3/29/07 Houston Well File 10-404 Sundry of Well Ops 307-211 Kenai Well File Operations Summary Report 7/10/07 DMD Current Well Schematic KJS • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 9071283-1371 Fax 907/283-1350 STATE OF ALASKA ALAS OIL AND GAS CONSERVATION COMMI~N REPORT OF SUNDRY WELL OPERATIONS AU G 2 7 2007 Alaska Oil & Gas Cons. Commission Anchorage 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ V-Strin Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver^ Time Extension ^ V-String Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well ^ Installation 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Marathon Oil Company Development ^~ Exploratory^ 206-058 3. Address: Stratigraphic ^ Service ^ 6. API Number: PO Box 1949, Kenai Alaska, 99611-1949 50-133-20559-00-00 7. KB Elevation (ft): 9. Well Name and Number: 21' RT-GL 56' RKB MSL CLU 11 8. Properly Designation: 10. Field/Pool(s): ADL- 324602 Canne Loo Unit / Belu a Pool 11. Present Well Condition Summary: Total Depth measured 9305' feet Plugs (measured) N/A true vertical 7914' feet Junk (measured) N/A Effective Depth measured 9247' feet true vertical 7g5i3' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 136' 20", 131#X-52 136' 136' 1,530 5,020 Surface 1602' 13-3/8", 68# L-80 1602' 1489' 3,090 1,540 Intermediate 5595' 9-5/8", 40# L-80 5595' 4355' 6,330 3,810 Production 9284' 3-1/2", 9.3# L-80 9284' 7914' 10,530 10,160 Liner Perforation depth: Measured depth: 7373' to 9094' True Vertical depth: 5982' to 7703' Tubing: (size, grade, and measured depth) 1.750" H0700FF 8185' Packers and SSSV (type and measured depth) N/A and N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 2800 3 0 776 Subsequent to operation: 0 2200 5 0 684 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory ^ Development Q Service ^ Daily Report of Well Operations Included 16. Well Status after work: Oil ^ Gas ^~ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 307-211 Contact Kevin Skiba (907) 283-1371 Printed Name Dennis M Donovan Jr Title Pro duction Engineer I (907)-283-1333 W Signature Phone (907)-398-1362 C Date 22-Aug-07 v Form 10-404 Revised 04/2006 ~.~, Su ' ~~ ~ R 1 G I N A L~ '~~ SEp ~~~°°~ ~~ • • Marathon Oil Company Page 1 of 5 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: MAINTENANCE/REPAIR Start: 7/10/2007 End: 7/15/2007 Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date :From - To Hours Code Code Phase Description of Operations 7/10/2007 14:00 - 14:30 0.50 SAFETY MTG_ SLICK 14:30 - 15:30 1.00 SAFETY MTG_ SLICK 15:30 - 15:45 0.25 RURD SLIK SLICK 15:45 - 16:30 0.75 RUNPUL SLIK SLICK 16:30 - 16:45 0.25 SAFETY MTG_ SLICK 16:45 - 17:30 I 0.751 RURD I SLIK I SLICK 7/12/2007 07:30 - 08:30 1.00 SAFETY MTG_ CTBG 08:30 - 11:00 2.50 RURD COIL CTBG 11:00 - 12:00 I 1.001 RURD I COIL I CTBG 12:00 - 14:00 2.00 RURD_ COIL CTBG 14:00 - 15:00 1.00 RURD_ COIL CTBG 15:00 - 17:00 2.00 RURD_ COIL CTBG 17:00 - 18:30 1.50 RURD COIL CTBG 18:30 - 19:00 7/13/2007 107:30 - 08:30 08:30 - 09:30 09:30 - 10:00 10:00 - 11:45 11:45-12:10 0.42 12:10 - 13:00 0.83 13:00 - 13:55 0.92 13:55 - 14:00 0.08 14:00-15:01 1.02 15:01 - 15:25 0.40 15:25 - 16:10 0.75 0.501 RURD I COIL I CTBG 1.00 ~ SAFETY ~ MTG_ ~ CTBG 1.00 RURD_ COIL CTBG 0.50 RURD_ COIL CTBG 1.75 RURD COIL CTBG CTBG CTBG CTBG CTBG CTBG CTBG CTBG 0.83 CTBG 1.00 SAFETY MTG_ SLICK 1.00 RURD_ SLIK SLICK 0.33 RURD_ SLIK SLICK 1.00 RUNPUL SLIK SLICK 16:10 - 17:00 7/14/2007 07:00 - 08:00 08:00 - 09:00 09:00 - 09:20 09:20 - 10:20 Arrive on location. Obtain Safe Work permit. Hold PJSM. Spot equipment. MIRU lubricator and tool string 1/3/4" dump bailer. Low pressure test lubricator to 150 psi with well gas. Good test. PTest lubricator with fluid to 1200 psi. RIH. Set down at 8421' KB.(Modu14 flapper @ 8418') Fall thru. Continue RIH. Tag TD. REcheck twice-TD @ 8510'. POOH OOH. Hold RD Safety meeting. Discuss lay down procedure of lubricator and tool string. RD lubricator and tool string. Rack up equipment. Turn in Permit, sign out. Leave location. Lock control room and gate. Arrive on location. Obtain Hot Work permit. Hold PJSM. Point out Flags and clean up drums from environmental clean up.. Caution about disturbing flags or relocating drums. Mark location with ground paint. Lay out liners under all equipment. Spot coil unit, second coil spool, High pressure pump, N2 unit, flow back tanks w/ gas buster, choke skid. RU crane. RU 2" hard lines to coil unit, high pressure pump, N2 pump, and choke manifold and gas buster. RU BOP's on top of tree. RU hard line to Flow cross and BOP's Set ejector head down. Thread 1-3/4" coil into ejector. Install coil connector. Pull test to 5K. Test good Test BOP's. 200 psi low/4500 psi high. Test good. Fill CTube with 18.9 bbls. Test end connector to 712 psi. Test good. Test hard line, flow back iron to 4500 psi. Test good. Install night cap on tree. Secure location for the night. Sign out and leave location. Arrive on location. Obtain Hot Work permit. Hold PJSM. Caution about disturbing flags or relocating drums. Discuss todays job scope and the possible hazards associated. PU ejector head and install on WH. Cool down N2 pumper. Displace KCL water out of coil with N2. PU 16' of lubricator. PU BHA. (weight bar-2.51" OD x 10' drain plug down, Nipple sub-2.50" ODx 8-3/4" 1.135" NoGo, Tapered nose-2.46" OD x 8.0" w plug pinned w/ 3 brass shear pins and nose cap.) All passed 1.25" GR except Nogo) PTest lubricator. Test good. RIH. WHP 850 psi. Setting depth is 8185' KB. Problem with the chain drive on the spool. Shut down to adjust motor on drive. Also shutdown to remove counter head for 2-3/8" Unit on 33-6 well. Start RIH. Tag up @ 2242'. Attempt to pass thru 5 times and are not successful. Loosen striper packoff, but doesn't help. Roll back tubing and check for egg shapes tubing. Pipe is fine. POOH to check BHA. OOH. RD off WH. Look for marks on BHA. Tapered nose shows burnish marks around circumference. Install night cap. Secure well and location for the night. Arrive on location. Obtain Hot Work permit. Hold PJSM. MIRU Pollard w/I equipment. PT lubricator to 1500 psi. Test good. RIH with 2.72" GR. See nothing @ 2242' KB. RIH to 7395" KB. Set down in Module 10 flapper @7399'. Hammer down lightly twice. Not making any hole. POOH. Printed: 8/22/2007 8:09:45 AM • • Marathon Oil Company Page 2 of 5 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: MAINTENANCE/REPAIR Start: 7/10/2007 End: 7/15/2007 Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Cotle Phase Description. of Operations - 7/14/2007 10:20 - 10:25 0.08 RURD_ SLIK SLICK Shut well in. Let pressure build up. 10:25 - 11:15 0.83 RUNPU SLIK SLICK PU 12' of 2.5" OD stiff assembly with 2.60" swage on nose. PU lubricator. 11:15 - 11:30 0.25 RURD_ SLIK SLICK PTest lubricator to 2500 psi. 11:30 - 12:00 0.50 RUNPUL SLIK SLICK RIH with 10' of 2.5" OD stiff assembly with 2.60" swage on nose. Set down @ 7385'. PU to check for sticking. Ok. Hammer down for 10 min. Tap down to 7388'. In new perfs below Module 10. 12:00 - 12:30 0.50 RUNPUL SLIK SLICK OOH. PU 2.60" LIB and lubricator. 12:30 - 12:45 0.25 RURD_ SLIK SLICK Test lubricator to 2500 psi. Test good. 12:45 - 13:30 0.75 RUNPUL SLIK SLICK RIH w/ 2.60" LIB to 7388' POOH. No good marks on LIB. 13:30 - 13:45 0.25 SLICK PTest Lubricator to 2500 psi. Test good. 13:45 - 14:00 0.25 SLICK Rerun 2.60" LIB to 7388'. POOH. 14:00 - 14:30 0.50 SLICK OOH with LIB. Two deep gouges on very outer edge if LIB. (We hit the LIB twice. Small indication of sand on the face of LIB. 14:30 - 14:50 0.33 SLICK PU 2" DD bailer. Test Lubricator to 2500 psi. Test good. 14:50 - 15:30 0.67 SLICK RIH with DD bailer. Tag up @7388' kb. Hammer down- drop thru fell to 7461'. Tap to 7470'. Gain about 90' to 7470' kb. Recover sand and cement chunks. 15:30 - 16:30 1.00 SLICK Test lubricator. Test good. RIH with 2" DD bailer. Tag TD at 7473', stuffing box leaking. POOH. Recover 1/2 bailer of sand and half water. 16:30 - 17:15 0.75 SLICK Repack stuffing box. Test lubricator. 17:15 - 18:00 0.75 SLICK RIH w/ 2.5" DD bailer to 7480' kb. tap to 7501' kb. POOH. Recover 1/2 sand and 1/2 water. 18:00 - 19:00 1.00 SLICK Test lubricator. RIH w/ same to 7528" kb tap to 7607' KB. 19:00 - 19:30 0.50 SLICK Lay down lubricator and tool string. Secure well and location for the night. 19:30 - 20:00 0.50 SLICK Open well and return to well to production. 7/16/2007 07:30 - 08:00 0.50 SAFETY MTG_ SLICK Arrive on location. Obtain Safe Work permit. Hold PJSM. 08:00 - 08:30 0.50 RURD_ SLIK SLICK PU lubricator. Ptest to 2500 psi. Test good. 08:30 - 09:45 1.25 RUNPUL SLIK SLICK RIH w/ 2-1/2" DD dumpbailer to 7528' KB tap-fall to 7689' KB.work to 7702' KB. POOH. Recover 3/4 sand -1/4 water. 09:45 - 10:00 0.25 RURD_ SLIK SLICK Ptest lubricator. 10:00 - 11:15 1.25 RUNPUL SLIK SLICK RIH w/ same to 7726'. wt. fall to 7956' kb. Tap down twice pull up no spangs, Pull up to 1600 #'s-hit ten oil jar licks. Flow well while hitting licks. hit two licks pull flee. POOH. Shut in well. bailer full of sand. 11:15 - 11:30 0.25 RURD_ SLIK SLICK Ptest lubricator. 11:30 - 12:15 0.75 RUNPUL SLIK SLICK RIH w/ same. to 7925' KB-wt fall to 8223' kb.-wt fall to 8321' KB POOH. Bailer empty. 12:15 - 12:30 0.25 SAFETY MTG_ SLICK OOH. Hold rig sown JSA. 12:30 - 13:15 0.75 RURD_ SLICK Lay down lubricator and tool string. RD. 19:30 - 20:00 0.50 RURD_ SLICK Open well and return to well to production. 7/17/2007 08:00 - 09:00 1.00 SAFETY MTG_ CTBG Arrive on location. Obtain Safe Work permit. Hold PJSM. 09:00 - 09:30 0.50 RURD_ COIL CTBG Startup equipment. Spot crane. 09:30 - 11:00 1.50 RURD_ COIL CTBG PU ejector assembly. PU 16' of lubricator. 11:00 - 11:45 0.75 RURD_ COIL CTBG PU BHA. Install ejecter on WH. BHA includes 2.60" OD x1.5" id grapple connector, 2.50" OD x1.5" id x10' I weight bar w. drain, 2.50" OD x 1.135" NoGo Profile Nipple, 2.48" OD x 1.5" id Guide nose w/ plug and cap. 11:45 - 12:10 0.42 RURD_ COIL CTBG PT shell to 950 psi. Test good. 12:10 - 15:10 3.00 RUNPUL COIL CTBG Open swab valve. RIH to 8185' KB. 15:10 - 16:30 1.33 RURD_ COIL CTBG Vetco measured span @ 13'. Backed coil out of hole 13'- to 8172' KB. Set tubing in slips. Bleed pressure off shell. Slip ejecter up coil to make cut. Cut weep hole first to check for pressure in coil. No pressure in Printed: 8/22/2007 8:09:45 AM • Marathon Oil Company Page 3 of 5 Qperations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Event Name: MAINTENANCE/REPAIR Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours ~ Code ~ Code Phase: 7/17/2007 115:10 - 16:30 I 1.331 RURD I COIL I CTBG 16:30 - 17:30 1.001 RURD COIL CTBG 17:30 - 19:10 1.671 RUNPUL COIL CTBG 19:10 - 19:30 I 0.331 RURD I COIL I CTBG 19:30 - 21:30 I 2.001 RURD I COIL I CTBG 21:30 - 22:30 I 1.001 I I CTBG 22:30 - 22:50 I 0.331 I I CTBG 22:50 - 23:30 0.67 CTBG 23:30 - 01:50 2.33 CTBG 01:50 - 02:30 I 0.671 I I CTBG 02:30 - 03:00 I 0.501 I I CTBG 7/20/2007 07:00 - 08:00 1.00 SAFETY MTG_ CTBG 08:00 - 09:00 1.00 RURD_ COIL CTBG 09:00 - 09:30 0.50 RURD COIL CTBG 09:30 - 10:30 1.00 RURD_ COIL CTBG 10:30 - 11:00 0.50 RURD COIL CTBG 11:00 - 11:30 0.50 ~ RURD_ COIL CTBG 11:30 - 11:50 ~ 0.33 ~ RURD_ COIL ~ CTBG 11:50 - 12:20 0.50 RURD_ COIL CTBG 12:20 - 13:28 1.13 RURD_ COIL CTBG 13:28 - 14:00 0.53 RURD_ COIL CTBG Spud Date: 4/27/2006 Start: 7/10/2007 End: 7/15/2007 Rig Release: Group: Rig Number: 1 Description of Operations coil. Cut coil @ 12'-10.75 ". Check cut for LEL's. None present. Prep ends of coil andd install CT grapple on both ends of coil. Pull test CT unit grapple to 25K. Test good. Pump KCL water to end of coil. Install Weatherford G Spear on coil. Pull test Hanger grapple to 20K. PU string wt. 20K. Release CT slips. Equalize pressure across Pipe rams. Open pipe rams. Lower coil to land coil in hanger. Attemp to screw in hanger locking screws. Screws not seating to proper depth. Unable to get pressure test between o-rings in hanger assembley. POOH. OOH. Inspect hanger. Appears that hanger landed about 6" high. O-rings missing. Redress hanger to rerun. Engage G Spear in hanger. MU lubricator. PTest lubricator. Test good. Lower tubing into hanger. Hanger engauged w/ screws, but won't pressure test between o-rings. Pull tubing up to replace o-rings. Stand back lubricator. Inspect hanger. O-rings gone. Recover a couple 1/2" and 3/4" chunks of o-ring, they are pretty well disinigrated. Redress hanger assembly. Replace o-rings. Wrap with duct tape. Grease very heavily. Prepare to rerun. Engage G Spear. PU tubing into riser. Kink developing in coil tubing just below tubing hanger grapple. Elect to cut tube just below kink and reattach grapple. Prep tubing cut for new grapple. Waiting on new grapple and hanger. INstall new ct grapple. Pull test connector to 26K. Pull test good. Unlock slips. Equalize pressure across pipe rams. Release pipe rams. Lower ctubing to land in hanger. Hanger landed screws installed. Test o-ring seal. No seal. Third attempt. Pressure up G Spear to 959 psi. Leave tubing in hanger. Release from tubing hanger. Pull tubing up into riser. Close swab valve. Release pressure on lubricator to gas buster. RD lubricator. Lay down 2 sections of lubricator. Stand back ejector. Close blind rams on BOP's. Install night cap on BOP's. Secure well and equipment on location for the night. Arrive on location. Obtain Safe Work permit. Hold PJSM. Startup equipment. Prepare to remove 3" BOP's Close Upper master (swab leaks). Begin to remove 3" Bop's. Notice that SSV's closed. Suspect tree lost pressure to transmitter which caused ESD. Call operations to dispach operator. Well back flowing at 9:30. Notice pressure had built to 1250 psi flowline gauge-1322 psi on pannel. V-string tube should be fine because tubing hanger leaks- pressure should have equalized across tube. Lessons learned-in future may want to pin SSV during critical operations. Remove 3" BOP stack. Install 4" BOP stack. Perform State BOP test 200/4500 psi. Wing and swab valves leaking. Cann't perform low pressure (200 psi) test. Pressure keeps building up to 600-800 psi. Call Vetco to grease valve. Wait on Vetco Gray. Clean up location and load up 3" BOP's and lubricator. Vetco arrives to grease Upper master, wing, and swab valves. Valves holding pressure. Resume pressure test. Test BOP's 200/4500 psi. Test good. PU Ejector. MU Baker GS spear. MU on WH. PT coil w/ ball in GS spear to 450 psi. Ptest Shell to 1000 psi. Printed: 8/22/2007 8:09:45 AM ~- • • Marathon Oil Company Page-4 of 5 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Event Name: MAINTENANCE/REPAIR Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From- To Hours Code Code Phase Spud Date: 4/27/2006 Start: 7/10/2007 End: 7/15/2007 Rig Release: Group: Rig Number: 1 Description of Operations 7/20/2007 114:00 - 14:30 I 0.501 RURD I COIL I CTBG 14:30 - 15:00 I 0.501 RURD I COIL I CTBG 15:00 - 15:15 I 0.251 RURD I COIL I CTBG 15:15 - 15:30 0.25 RURD_ COIL CTBG 15:30 - 15:51 0.35 RURD_ COIL CTBG 15:51 - 17:30 1.65 RURD COIL CTBG 17:30 - 18:15 I 0.751 RURD I COIL I CTBG 18:15 - 23:55 5.67 RURD COIL CTBG 23:55 - 00:20 0.42 RURD COIL CTBG 00:20 - 01:05 0.75 RURD_ COIL CTBG 01:05 - 01:45 0.67 RURD COIL CTBG 01:45 - 02:20 0.58 RURD COIL CTBG 02:20 - 06:00 3.67 RURD COIL CTBG 7/21/2007 10:00 - 11:00 1.00 SAFETY MTG_ CTBG 11:00 - 12:00 1.00 RURD_ COIL CTBG 12:00 - 12:30 0.50 SAFETY MTG_ CTBG 12:30 - 13:00 0.50 RURD COIL CTBG 13:00 - 13:56 I 0.931 RURD I COIL I CTBG 13:56 - 14:20 I 0.401 RURD I COIL I CTBG 14:20 - 14:45 I 0.421 RURD_ 1 COIL I CTBG 14:45 - 15:35 0.83 RURD_ COIL CTBG 15:35 - 16:00 0.42 RURD COIL CTBG 16:00 - 16:15 0.25 RURD_ COIL CTBG 16:15 - 16:50 0.58 RURD COIL CTBG 16:50 - 17:00 I 0.171 RURD I COIL I CTBG 17:00 - 17:20 0.33 RURD ~ COIL CTBG 17:20 - 17:30 0.17 RUNPU COIL CTBG RIH. Latch spear into hanger. Pull 25k overpull. Release hanger screws. Pull hanger up into lubricator. Bleed pressure from lubricator. Pressure CT to 700 psi to release GS spear from hanger. Disconnect lubricator. Replace O-rings on CT hanger and prepare to rerun. Reconnect GS spear to hanger. MU lubricator and re-install on BOP's. Release pipe rams and slips. RIH 10' to land tubing in hanger. Land 17K on hanger. Hanger is 1' high. PU and try to land 1' lower without success. Loose well flow to facilities. All flow is thru open valve on flow T to gas buster. Vetco unable to get o-ring seal on hanger. POOH. Close pipe rams. PUH into lubricator. Slowdown lubricator and prepare to release GS spear. GS released and have gas flow to the gas buster. Shut in gas buster and valves on flow T. Shut down to assess the situation. Mobilize vac truck, boom truck, 10' of additional lubricator and night cap. Plan way forward to circulate well dead w/ 6% KCL. RU kill line to BOP equalization valve. RU Flow back line to choke manifold PTest lines to 4500 psi. Circulate hole volume-65 bbls 6% KCL down BOP equalizer valve to kill well. Circulate additional 20 bbls to remove any gas bubbles. One for One returns during this portion of pumping. Well dead. Watch well for two hours. Then shut in to monitor well pressure in control room. Leave two BJ personnel and crane operator on location thoughout night. Arrive on location. Obtain Safe Work permit. Hold PJSM. Supervisor team meets to formulate "plan forward". Hold "Tool box talk" with all personnel about "job scope. Spot boom truck and standby lubricator/nightcap, and have it hanging form boom truck ready to install on WH.. Prepare to circulate well. PTest 2" lines to 2500 psi. WHP =zero. Circulate 68 bbls. Have full returns at 10 1/2 bbls away. Watch well for signs of gas. None noted. WHP =0, Reel pressure = 0. Release pack off. Slip chains and lift ejector. Swing ejector/ lubricator off well. Immediately install temporary lubricator/night cap. Well secure. Disassemble coil Pack-off. coil connector/ GS speer "crowned out" in lubricator. Immediately install temporary lubricator/night cap. Well secure. Disassemble coil Pack-off. Coil connector/ GS speer pulled up into pack-off assembly. I Repair Ejector pack-off assembly. PU ejector. PU 10' of lubricator. PU BHA with 3-1/2" stiff centralizer above BHA. WHP =0. Pump 16 bbls of 6% KCL. Full returns at 8 1/2 bbls away. Drain Lubricator. Remove 8' lubricator/night cap. Reinstall CT hanger. Paint lock screw groove w/ yellow paint. Install Weatherford GS speer w/ 3 1/2" centralizer and 3' "stifF' assembly above. MU 12' lubricator on WH. Pull test GS speer to 25K. Test good. Mark coil with distance to hanger. Equalize pressure across pipe rams. Release pipe rams. RIH to mark. Set weight on hanger assembly. Pull Lock down screw. Printed: 8/22/2007 8:09:45 AM • • Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Event Name: MAINTENANCE/REPAIR Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To -Hours Code Code -.Phase 7/21/2007 117:20 - 17:30 I 0.171 RUNPULI COIL I CTBG 17:30 - 17:45 0.25 RURD_ COIL CTBG 17:45 - 18:15 0.50 RURD_ COIL CTBG 18:15 - 18:55 0.67 RURD COIL CTBG 18:55 - 19:27 0.53 BLOWD COIL CTBG 19:27 - 20:08 0.68 BLOWD COIL CTBG 20:08 - 20:30 0.37 BLOWD TBG CTBG 20:30 - 20:55 0.42 BLOWD TBG CTBG 20:55 - 21:57 1.03 BLOWD TBG_ CTBG 21:57 - 22:10 0.22 BLOWD TBG CTBG 22:10 - 23:59 I 1.821 RURD I COIL I CTBG Page 5 of 5 Spud Date: 4/27/2006 Start: 7/10/2007 End: 7/15/2007 Rig Release: Group: Rig Number: 1 Description of Operations Visually see yellow mark on Lock down groove. Install Lock down screws. Pull test tubing in hanger. Ptest orings. Test good. Pump off GS spear from hanger. POOH. Bleed off WH. POOH. Bleed off WH. Hold PJSM. Prepare to Jet well in with N2. Open lubricator and remove GS spear. Measure returns tank volume 117 bbls. Cool down N2 unit. Prime up N2 pumper. Begin pumping N2 @ 500 scf/min. CTU pressure 560 psi. WHP 559 Fluid returns to surface. CTU pressure 2080 psi, WHP 2090 psi N2 500 scf/min. Increase N2 to 750 scf/min. CTU pressure 2120 psi, WHP 2147 psi. Recover 25 bbls KCL water. Recover 48 bbls KCL water. Out of N2. Close swab, and master valves. CTU pressure 1726 psi, WHP 1757 psi Pump 110,000 scf N2. Secure location for the night. RD in the morning. Marathon Oil Company Operations Summary-Report Printed: 8/22/2007 8:09:45 AM API: 50-133-20559-00 RT-GL: 21.00' RT-THF: 21.70' 2491' FSL, 2291' FWL, Sec. 4, ~; T5N, R11W, S.M. Tree cxn = 4-3/4" Otis ~ TOC (est.) - 500' above 9-5/8" shoe - Ceramic flapper valves below each module as follows: Module 1 - NA Module 2 - 8640' (Broken CT 9/28/2006) Module 3 - 8530' Module 4 - 8418' (Broken CT 9/28/2006) Module 5 - 8240' (Broken CT 9/28/2006) Module 6 - 7960' Module 7 - 7900' Module 8 - 7715' (Broken CT 9/28/2006) Module 9 - 7498' Module 10 -7399' Module 11 -6618' CLU-11 • M nlr,wrewn~oM Drive Pipe: 20", 131 ppf, X-52, to 136' RKB Surface Casing: 13-3/8", 68 ppf, L-80, BTC @ 1602' RKB, Cmt w/ 228 bbls / 516 sx. of Type 1 at 12.0 ppg. Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 5595' RKB. Cmt w/ 35.6 bbl (95 sx) of class G lead @ 12.5 ppg and 49 bbls (237 sx) Class G tail @ 15.8 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9284' RKB. Cmt w/ 1550 sx (325 bbls) of class G at 15.8 ppg 11 Excape modules placed Green control line fired module 1 Yellow control line fired modules 2 thru 7 Red contol line fired modules 8 thru 11 Ceramic flapper valves below each module xceot for module 1 Module 1 - 9084' - 9094' (Frac'd 9/28/06) Module 2 - 8607' - 8617' (Frac'd 9/28/06) Module 3 - 8498' - 8508' (Frac'd 9/28/06) Module 4 - 8383' - 8393' (Frac'd 9/28/06) Module 5 - 8205' - 8215' (Frac'd 9/28/06) 7939' - 7946' (Perfed 4/1/07) Module 6 - 7929' - 7939' (Perfed 4/1/07) Module 7 - 7868' - 7878' Not Shot Module 8 - 7686' - 7696' (Frac'd 9/28/06, Cmt Squeezed 4/3/07) Module 9 - 7472' - 7482' (Frac'd 9/28/06, Cmt Squeezed 4/3/07) Add Perfs: 7383' - 7400' (Perfed 5/1/07) Module 10 - 7373' - 7383' (Cmt Squeezed 4/3/07, Perfed 5/1/07) Module 11 - 6593' - 6603' Not Shot Well Name & Number: CLU - 11 Lease: Cannery Loop Gas Field County or Parish: Kenai State/Prov. Alaska Country: USA Perforations (MD) See Above (TVD) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completion Fluid: 6% KCL Dated Completed: 9/28/2006 Prepared By: D. Donovan Last Revison Date: 7/25/2007 TD - 9305' PBTD - 9247' • M Marathon MARATHON Oil Company August 23, 2007 ~~UE® Mr. Tom Maunder ~~~ 2 7 2007 Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Alaska Oil ~ Gas Cons. Commission Anchorage, Alaska 99501 Anchorage Reference: 10-404 Report of Sundry Well Operations -Perforation Work and Cement -~ Squeeze -Sundry #307-106 10-404 Report of Sundry Well Operations -Velocity String Installation - Sundry #307-211 Field: Cannery Loop Gas Field Well: Cannery Loop Unit #11 (PTD- 206-058) Dear Mr. Maunder: Enclosed is the 10-404's for sundries 307-106 and 307-211. Sundry 307-106 reports the Addition of Module 6, Cement Squeeze of Module 8, 9 and 10, and re-perforation of Module 10 w/ 17' of additional feet below (7373'-7400'). Verbal approval was obtained on April 02, 2007 through email for the perforation changes and the following cement squeeze operation. All the work that pertains to verbal approval is covered in this sundry and operations report. Sundry 307-211 reports the installation of the 1.75" velocity string ran to a depth of 8185' and is reflected in the tubing portion of the 10-404. Attached with the 10-404's are operations summary reports for each job and a current wellbore diagram. Please send any sundries or pertinent documentation to Kevin Skiba at the above address listed. If you have any questions or need further information please call me at (907) 398-1362. Sincere , Dennis Donovan Production Engineer Enclosures: 10-404 Sundry of Well Ops 307-106 cc: AOGCC Operations Summary Report 3/29/07 Houston Well File 10-404 Sundry of Well Ops 307-211 Kenai Well File Operations Summary Report 7/10/07 DMD Current Well Schematic KJS • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 STATE OF ALASKA ALAS OIL AND GAS CONSERVATION COMMI ION REPORT OF SUNDRY WELL OPERATIONS AUG 2 7 2007 ~~iaska Oil & Gas Cons. Commission: Anchorage 1. Operations Abandon Repair Well Plug Perforations ~ Stimulate Other Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver^ Time Extension ^ Cmt Squeeze Change Approved Program ^ Operat. Shutdown ^ Perforate 0 Re-enter Suspended Well ^ and Pert Work 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Marathon Oil Company Development ^~ Exploratory^ 206-058 3. Address: Stratigraphic ^ Service ^ 6. API Number: PO Box 1949, Kenai Alaska, 99611-1949 50-133-20559-00-00 7. KB Elevation (ft): 9. Well Name and Number: 21' RT-GL 56' RKB MSL ~ CLU 11 '~ 8. Property Designation: 10. Field/Pool(s): ADL- 324602 ~ Canne Loo Unit / Belu a Pool 11. Present Well Condition Summary: Total Depth measured 9305' ' feet Plugs (measured) N/A true vertical 7914' - feet Junk (measured) N/A Effective Depth measured 9247' ' feet true vertical 7856' ~ feet Casing Length Size MD TVD Burst Collapse Structural Conductor 136' 20", 131#X-52 136' 136' 1,530 5,020 Surface 1602' 13-3/8", 68# L-80 1602' 1489' 3,090 1,540 Intermediate 5595' 9-5/8", 40# L-80 5595' 4355' 6,330 3,810 Production 9284' 3-1/2", 9.3# L-80 9284' 7914' 10,530 10,160 Liner Perforation depth: Measured depth: 7373' to 9094' True Vertical depth: 5982' to 7703' Tubing: (size, g ade, and measured depth) N/A Packers and SSSV (type and measured depth) N/A and N/A 12. Stimulation or cement squeeze summary: Cement Squeeze of Modules 8, 9 and 10 Intervals treated (measured): Mod 8 (7686'-7696'), Mod 9 (7472'-7482'), Mod 10 (7373'-7383') Treatment descriptions including volumes used and final pressure: 8 bbl Cement Plug from 7742' to 6850', Milled out and Tested Modules to 1000 psig 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 3900 200 0 1050 Subsequent to operation: 0 2800 3 0 776 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory ^ Development Q Service ^ Daily Report of Well Operations Included 16. Well Status after work: Oil ^ Gas 0 WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 307-106 Contact Kevin Skiba (907) 283-1371 Printed Name Dennis M Donovan Jr Title Production Engineer I (907)-283-1333 W Signature Phone (907)-398-1362 C Date 22-Aug-07 Form 10-404 Revise 2006 ~ ~ ~ ~ ~ ( RS ~~ SEP 1 4 2005 I.z Submit iig~a~ n~ L i • • Marathon Oil Company Page 1 of 7 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: MAINTENANCE/REPAIR Start: 3/29/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Phase Description of Operations Date From - To Hours Code Cod e 3/29!2007 12:00 - 12:30 0.50 SAFETY MTG_ WBPREP Cover BJ JSA and complete safety checklist. 12:30 - 21:00 8.50 RURD_ COIL WBPREP MIRU coil tubing unit, spotted equipment, crane, pulled well house and spotted tanks. Placed liner for Methanol tank, supply and flow back tank. MU ground lines and BOP's. 3/30/2007 07:00 - 08:00 1.00 RURD_ COIL CTBG Arrive. Issue permit, start equipment. 08:00 - 09:00 1.00 SAFETY MTG_ CTBG Hold safety meeting. 09:00 - 12:20 3.33 RURD_ COIL CTBG Finish Rigup. 12:20 - 13:40 1.33 TEST_ BOPE CTBG Test BOP 200 / 4500 psi with test bar. Good test on Rams, Blinds, lines, and valves. 13:40 - 15:00 1.33 RURD_ COIL CTBG Injector to tree. SIWHP = 750 psi. PT stripper to 1500 psi. 15:00 - 15:20 0.33 RURD_ COIL CTBG Open well togas buster and cool down N2. 15:20 - 16:20 1.00 RUNPUL COIL CTBG Start N2 to warm up CT and RIH pumping N2 at 400, KCI at 0.3 bpm.. Water to buster at 500'. 16:20 - 17:20 1.00 CLNOU CSG_ CTBG Increase fluid rate to 1.5 BPM and jet down to 9156'. No hard fill. 17:20 - 18:20 1.00 CLNOU CSG_ CTBG Circulate well at 1.5 BPM, 400 SCF/min. Returns clean. 18:20 - 19:20 1.00 RUNPUL COIL CTBG POH while pumping N2 . SD N2 at 6000' to stabilize well. 19:20 - 20:30 1.17 PERF_ CSG_ CTBG Flow well to gas buster at 1250 psi. Turn into production system. Attempt to shoot Excape guns at Mods 6 and 10. No obvious response. 20:30 - 21:15 0.75 RURD_ COIL CTBG RIH to check for Mod 10 flapper. No Flapper. 21:15 - 22:10 0.92 RUNPUL COIL CTBG POH with well flowing to sales. 22:10 - 23:00 0.83 RURD_ COIL CTBG Rig back CT and secure well. Leave location. 3/31/2007 09:00 - 09:40 0.67 SAFETY MTG_ CMPPRF Hold safety meeting. 09:40 - 11:40 2.00 RURD_ ELEC CMPPRF Rigup Expro a-line. PU 2-3/8" spent pert gun to drift well. 11:40 - 12:30 0.83 TEST_ BOPE CMPPRF Test lubricator to 2000 psi. Good after replacing 1 O-ring. 12:30 - 14:15 1.75 RUNPUL ELEC CMPPRF RIH 10' X 2-3/8" fired gun to drift well. Work through mod 10, work through mod 8, work through mod 2. Set down at 8728' (mod 1 is at 9084'). 14:15 - 14:55 0.67 RUNPUL ELEC CMPPRF POH. 14:55 - 15:20 0.42 RURD_ ELEC CMPPRF LD spent gun and PU PLT. 15:20 - 16:30 1.17 RUNPU ELEC CMPPRF PT and RIH PLT string. 16:30 - 16:50 0.33 RUNPUL ELEC CMPPRF Start 30FPM down pass at 7250'. Spinner stopped at 7550'. Unable to clear spinner. 16:50 - 17:20 0.50 RUNPUL ELEC CMPPRF POH spinner. Spinner plugged with pert debris. 17:20 - 18:00 0.67 RURD_ ELEC CMPPRF Secure well and leave location. 4/1/2007 07:30 - 08:10 0.67 SAFETY MTG_ CMPPRF Hold safety meeting. 08:10 - 08:40 0.50 RURD_ ELEC CMPPRF Rigup Expro e-line. PU PLT string to log well. 08:40 - 08:50 0.17 TEST_ BOPE CMPPRF Test lubricator to 2000 psi. Good after replacing 1 O-ring. 08:50 - 11:00 2.17 RUNPU ELEC CMPPRF RIH PLT. Spinner stopped at 6000'. Unable to restart spinner. Make baseline P/T log with well flowing at 3MM. Down and Up passes at 60FPM. 11:00 - 12:30 1.50 RUNPUL ELEC CMPPRF SIW. Wait 1 hour for first shutin pass 12:30 - 13:30 1.00 CMPPRF Log Static temp pass after 1 hour. 13:30 - 15:30 2.00 CMPPRF Log Static temp pass after 2 hours. 15:30 - 16:20 0.83 CMPPRF Log Static temp pass after 4 hours. 16:20 - 17:10 0.83 CMPPRF POH spinner. Spinner plugged with pert debris. 17:10 - 18:00 0.83 CMPPRF Secure well and leave location. 4/2/2007 06:00 - 06:01 0.02 Shut in well due to solids production. 07:30 - 08:30 1.00 SAFETY MTG_ CMPPRF Hold safety meeting. 08:30 - 09:05 0.58 RURD_ ELEC CMPPRF Rigup Expro a-line. PU P/T string to log well. 09:05 - 09:15 0.17 TEST_ BOPE CMPPRF Test lubricator to 2000 psi. SIWHP = 1936 psi. 09:15 - 12:00 2.75 RUNPUL ELEC CMPPRF RIH with P/L tools. Tagged bottom at 9070', between mods 1 & 2. POH 12:00 - 12:15 0.25 SAFETY MTG_ CMPPRF SIWHP = 2050 psi. Hold perforating safety meeting. 12:15 - 12:30 0.25 RURD_ ELEC CMPPRF Arm and PU 2-1/8", 6 spf, 60 Deg phased gun. Printed: 8/22/2007 8:08:23 AM • Marathon Oil Company Page 2 of 7 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: MAINTENANCE/REPAIR Start: 3/29/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code rode Phase Description of Operations 4/2/2007 12:30 - 12:35 0.08 TEST_ BOPE CMPPRF Test lub to 3000 psi. 12:35 - 13:35 1.00 RUNPUL ELEC CMPPRF RIH 2-1/8" gun. Tie in and position. Open well while running nin hole an reduce flowing pressure to 1450 psi. for shooting. 13:35 - 13:40 0.08 PERF_ CSG_ CMPPRF Shoot 7932' - 7946 OH with 2-1/8", 6 spf, 60 Deg phased gun. NOTE: Excagpe gun fired. Perforated depths at 7929" - 7946'. Small positive signs from shooting. 13:40 - 14:25 0.75 RUNPUL ELEC CMPPRF POH 14:25 - 14:45 0.33 RURD_ ELEC CMPPRF LD spent gun. Excape gun fired through 2-1/8" gun plus 3' of the dummy gun above the live gun. PU 2.70" swage. 14:45 - 17:20 2.58 WORK ELEC CMPPRF RIH 2.70" swage. Attempt to work through module 8 at 7690'. Passed through module 1 time but never again. POH 17:20 - 18:00 0.67 RURD_ ELEC CMPPRF Secure well and leave location. 4/3/2007 15:00 - 15:15 0.25 SAFETY MTG_ PLUGAB Arrive @ CLU, sign in and obtain work permit 15:15 - 16:20 1.08 SAFETY MTG_ PLUGAB Hold PJSM with Expro JSA, Discussed Slips Trips Falls 16:20 - 16:25 0.08 SAFETY MTG_ PLUGAB Hold Explosives Safety Meeting 16:25 - 16:40 0.25 RURD_ ELEC PLUGAB PU Baker 3.50" Composite Bridge Plug and Pressure test to 3000 psig 16:40 - 17:56 1.27 RUNPUL ELEC PLUGAB Open valve, RIH 17:56 - 18:43 0.78 SETREL PLUG PLUGAB Pull into position and set plug @ 7730', POOH 18:43 - 19:27 0.73 RURD_ ELEC PLUGAB OOH, Bleed off Lubricator and RD 19:27 - 20:00 0.55 RURD_ ELEC PLUGAB Sign out, turn in work permit, leave location 4/4/2007 07:00 - 07:40 0.67 SAFETY MTG_ PLUGAB Hold safety meeting. Issue permit, start equipment. 07:40 - 10:40 3.00 RURD_ COIL PLUGAB Finish Rigup. Stab on injector and fill CT. 10:40 - 10:50 0.17 TEST_ BOPE PLUGAB Shell test to 2500 psi. 10:50 - 14:30 3.67 RUNPUL COIL PLUGAB RIH pumping 1.5 BPM to kill well. Tag plug at 7742' CTD. PU 10' and finish circulating well dead. 14:30 - 14:55 0.42 PUMP_ CMT_ PLUGAB Mix 8 Bbls cmt plug as per BJ instructions. 14:55 - 15:35 0.67 PUMP_ CMT_ PLUGAB Pump cement and lav in from 7742' to 6850'. 15:35 - 16:35 1.00 RUNPUL COIL PLUGAB POH while circulating well. Full returns. 16:35 - 16:50 0.25 TEST_ CMT_ PLUGAB Pressure well up to 200 psi 2 times. Leaks off slowly but stays full. Close well and WOC. 16:50 - 18:00 1.17 RURD_ COIL PLUGAB Freeze protect CT. Rig back CT and secure well. Leave location. 4/6/2007 07:00 - 07:40 0.67 SAFETY MTG_ PLUGAB Hold safety meeting. Issue permit, start equipment. 07:40 - 08:55 1.25 RURD_ COIL PLUGAB Finish Rigup. Stab on injector and fill CT. 08:55 - 10:05 1.17 TEST_ BOPE PLUGAB Full BOP Test, 250 / 4500 psi. 10:05 - 12:00 1.92 RURD_ COIL PLUGAB PU Lubricator and tools. Baker motor head assy, Motor, 2.792" 4 bladed mill. 12:00 - 12:15 0.25 TEST_ BOPE PLUGAB Shell test BOP. 12:15 - 13:15 1.00 RURD_ COIL PLUGAB Displace McOH from CT back to McOH tank. 13:15 - 13:30 0.25 TEST_ CSG_ PLUGAB Pressure test casing to 1000 psi. Good test. 13:30 - 15:30 2.00 RUNPU COIL PLUGAB RIH. 15:30 - 18:15 2.75 DRILL_ CMT_ PLUGAB Ta cement at 6884'. Drill soft cement to 7250'. Drill fairly hard cement 18:15 - 18:25 ~ 0.17 ~ INSPCT TUBE ~ PLUGAB ~ Discovered a deep cut in CT 2 wraps down. Appears to be from a piece 4/8/2007 of metal passing through the chains with the CT. Decide to POH and change pipe. 18:25 - 20:45 2.33 RUNPUL COIL PLUGAB POH. Drop circulating ball and purge CT while POH. 20:45 - 22:00 1.25 RURD_ COIL PLUGAB Rig back CT. Will bring offshore reel tomorrow and RU. 07:00 - 08:00 1.00 SAFETY MTG_ PLUGAB Hold safety meeting. Issue permit, start equipment. 08:00 - 11:40 3.67 RURD_ COIL PLUGAB Finish Rigup. Stab on injector and flush CT with 2 CT volumes. 11:40 - 12:30 0.83 RURD_ COIL PLUGAB PU Lubricator and tools. Baker motor head assy, Motor, 2.792" 4 bladed mill. 12:30 - 12:40 0.17 TEST_ BOPE PLUGAB Shell test BOP. 12:40 - 14:40 2.00 RUNPUL COIL PLUGAB RIH. Printed: 8/22/2007 5:08:23 AM • • Marathon Oil Company Operations Summary Report Page 3 of 7" i Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: MAINTENANCE/REPAIR Start: 3/29/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase pescription of Operations 4/8/2007 14:40 - 15:05 0.42 DRILL_ CMT_ PLUGAB 15:05 - 17:40 2.58 DRILL CMT PLUGAB 17:40 - 19:00 1.33 RUNPU COIL PLUGAB 19:00 - 20:00 1.00 RURD COIL PLUGAB 4/10/2007 07:00 - 07:40 0.67 SAFETY MTG_ PLUGAB 07:40 - 08:55 1.25 RURD_ SLIK PLUGAB 08:55 - 09:00 0.08 TEST_ BOPE PLUGAB 09:00 - 10:20 1.33 RUNPUL SLIK PLUGAB 10:20 - 11:45 1.42 RUNPU SLIK PLUGAB 11:45 - 12:45 1.00 RUNPUL SLIK PLUGAB 12:45 - 14:00 1.25 RUNPUL SLIK PLUGAB 14:00 - 15:00 1.00 RURD_ SLIK PLUGAB 4/11/2007 07:00 - 07:45 0.75 SAFETY MTG_ PLUGAB 07:45 - 09:35 1.83 RURD COIL PLUGAB 09:35 - 09:45 0.17 TEST_ BOPE PLUGAB 09:45 - 11:15 1.50 RUNPUL COIL PLUGAB 11:15 - 13:40 2.42 DRILL CMT PLUGAB 13:40 - 21:45 8.08 DRILL_ CMT_ PLUGAB 21:45 - 23:55 2.17 DRILL_ CMT_ PLUGAB 23:55 - 01:15 1.33 RUNPU COIL PLUGAB 01:15 - 02:00 0.75 RURD_ COIL PLUGAB 4/12/2007 10:00 - 11:00 1.00 WAITON OTHR PLUGAB 11:00 - 11:30 0.50 SAFETY MTG_ PLUGAB 11:30 - 13:10 1.67 RURD COIL PLUGAB 13:10 - 13:20 0.17 TEST_ BOPE PLUGAB 13:20 - 14:50 1.50 RUNPUL COIL PLUGAB 14:50 - 16:10 1.33 DRILL CMT PLUGAB 16:10 - 17:10 1.00 RUNPUL COIL PLUGAB 17:10 - 20:00 2.83 RURD COIL PLUGAB 4/13/2007 07:00 - 08:00 1.00 SAFETY MTG_ PLUGAB 08:00 - 10:05 2.08 RURD COIL PLUGAB 10:05 - 10:15 0.17 TEST_ BOPE PLUGAB 10:15 - 12:00 1.75 RUNPUL COIL PLUGAB 12:00 - 15:00 3.00 DRILL CMT PLUGAB 15:00 - 16:05 1.08 DRILL_ CMT_ PLUGAB 16:05 - 19:10 3.08 DRILL_ CMT_ PLUGAB 19:10 - 19:40 0.50 PUMP_ N2_ PLUGAB 19:40 - 20:15 0.58 RUNPUL COIL PLUGAB 20:15 - 21:35 1.33 REPAIR EOIP PLUGAB 21:35 - 22:30 0.92 RUNPUL COIL PLUGAB 22:30 - 23:30 1.00 RURD COIL PLUGAB Tag cement at 7276'. PU and start milling. Mill to 7356' and stall. Work mill at 7356'. Unable to make hole. Appears to be module 10 perfs at 7373' corrected depth. POH. Circulate McOH through CT whit POH. OOH. Left most of motor in hole. Rig back CT. Will return on Monday with spear and recover motor and mill. Hold safety meeting. Issue permit, start equipment. RU Slickline. PU 2.80" overshot dressed to catch 2-1/8". Test lubricator RIH with 2.80" overshot. Latch and pull 2-1/8" motor and 2.792 mill. RIH with 2.75" LIB. Tag bottom and POH. No metal marks. RIH with 2.50" pump bailer. Recovered cement pieces. RIH with 2.50" pump bailer. Recovered cement pieces. RD and release slickline. Hold safety meeting. Issue permit, start equipment. Finish Rigup. PU Lubricator and tools. Baker motor head assy, Motor, 2.72" 4 bladed mill. Shell test BOP to 1500 psi. RIH. Tag cement at 7379'. PU and start milling. Mill to 7420'. Tets mod 10 to 1000 psi. 0.25 Bbls/hour loss. Mill from 7420' to 7650'. Stalls at 7482' (mod 9) Test modules 9 and 10. Loss of 0.02 bbls in 5 min (0.25 Bbls/hour). Mill from 7650' to 7705'. Stalls at 7682 (top mod 8) Test modules 8, 9 and 10. Loss of 0.025 bbls in 5 min (0.3 Bbls/hour). POH. OOH. Rig back CT unit and secure well for night. Wait on CT crew after very late night. Hold safety meeting. Issue permit, start equipment. Finish Rigup. PU Lubricator and tools. Baker motor head assy, Motor, 2.72" 4 bladed mill. Shell test BOP to 1500 psi. RIH. Tag cement at 7708". PU and start milling. Unable to make progress. Unable to stall motor. POH. OOH. Top of motor is plugged with black fines. XCirculating sub is sheared (open). Will have Baker investigate what the fines are. Rig back CT unit and secure well for night. Hold safety meeting. Issue permit, start equipment. Finish Rigup. PU Lubricator and tools. Baker motor head assy, Motor, 2.72" 4 bladed mill. Shell test BOP to 1500 psi. RIH. Tag cement at 7705". PU and start milling. Mill through 15' cement and then add N2 at 500 SCF/min. Break through composit plug at 7728' Mill and chase plug to 7746'. SD N2. Continue milling and pushing plug down to 7942'. SD milling. Drop circulating ball and Pump down with KCI. Start N2. POH. Level wind stopped working at 6000'. Repair levelwind. POH. OOH. Rig back CT and secure well. Well is flowing to system. Printed: 8/22/2007 8:08:23 AM • Marathon Oil Company Page 4 of 7 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: MAINTENANCE/REPAIR Start: 3/29/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Description of Operations 4/14/2007 07:00 - 08:00 1.00 SAFETY MTG_ PLUGAB Hold safety meeting. Issue permit, start equipment. 08:00 - 15:30 7.50 RURD COIL PLUGAB Release equipment. Move crane to SD 3 and other equipment to KDU 4. 5/2/2007 08:00 - 08:15 0.25 SAFETY MTG_ SLICK Arrive at CLU pad 3 and Obtain work permit 08:15 - 09:20 1.08 SAFETY MTG_ SLICK Hold PJSM and Discuss JSA, Begin R/U on Slickline Unit w/ 0.108" wire 09:20 - 09:40 0.33 TEST_ BOPE SLICK PT to 1500 psig 09:40 - 10:00 0.33 RUNPUL SLIK SLICK Start in hole with 2.50" blind box 10:00 - 10:55 0.92 TAG_ BOTM SLICK Ta bottom @ 8638' KB. Tool stuck at Module 2 (8638' KB) Tool gradually coming up hole to 8546' KB 10:55 - 11:10 0.25 RUNPUL SLIK SLICK Work tool free. TD 8546' KB. POOH 11:10 - 11:30 0.33 RUNPUL SLIK SLICK OOH, WOO 11:30 - 12:00 0.50 RURD_ SLIK SLICK Rig down slickline 12:00 - 14:20 2.33 RURD_ ELEC CMPPRF RU a-line. Waiton orders to shut in well .12:20 - 12:40 0.33 SAFETY MTG_ CMPPRF Hold Explosive safety meeting 12:40 - 12:55 0.25 RURD_ ELEC CMPPRF Arm 27' 2-3/8" perforation guns 12:55 - 13:10 0.25 TEST_ BOPE CMPPRF PU gun and pressure test to 2000 psig 13:10 - 13:15 0.08 TEST_ BOPE CMPPRF Leak in lubricator connection, change O ring 13:15 - 13:25 0.17 TEST_ BOPE CMPPRF Pressure test to 2000 psig 13:25 - 15:30 2.08 RUNPU ELEC CMPPRF Open valve and RIH 15:30 - 15:45 0.25 RUNPUL ELEC CMPPRF Shut in flow line. (1000 psig) Let well build to 1250 psig 15:45 - 16:00 0.25 RUNPUL ELEC CMPPRF Run correlation pass. Tool hung up at 7550' KB 16:00 - 16:35 0.58 RUNPU ELEC CMPPRF Flow well, gun came free 16:35 - 16:40 0.08 PERF_ TBG_ CMPPRF Shut in well, let build to 1250 psig. Shoot gun (7364'-7391')CH, (7373-7400)OH, instantly built to 1450 psig. After 10min WHP-1680 psig. 1 hour later- WHP=1850 psig 16:40 - 17:45 1.08 RUNPU ELEC CMPPRF POOH 17:45 - 18:00 0.25 RUNPU ELEC CMPPRF Gun stuck in tree across the valves (wireline valve, swab, master, lower master) There was no indication that we were blown up hole from perforating underbalanced. Since we built to 1450 quickly there is a possibility that we were. 18:00 - 21:00 3.00 RUNPU ELEC CMPPRF Worked line and attempted to shut valves with no improvement, Hold meeting and Call respective parties. Setup for well kill situation. BJ pump services, rain for rent tanks. 21:00 - 06:00 9.00 WAITON TRET CMPPRF Secure well and grease unit and leave location with night watch onsite (SITP- -2100 psig) 5/3/2007 06:00 - 06:00 24.00 RURD_ PIPE SLICK Rig Up BJ Pumps, Tanks, Liners, Manlift, Lightplant, Expro sit on well 24 hrs, Prepare to dislodge guns or eline or kill the well 5/4/2007 07:30 - 09:00 1.50 RURD_ PIPE SLICK Conference call with Anchorage and Houston about well status and Program to remove the guns from the well bore, during this time the 80' manlift was delivered 09:00 - 09:30 0.50 SLICK Travel to CLU 11 and Sign in to pad 09:30 - 10:00 0.50 SLICK Expro and BJ Safety Meeting with JSA, Slips Trips and Falls, Discuss the program and what is needed to proceed work on this well. Have Marathon HES personnel attend meeting (2) 10:00 - 10:30 0.50 SLICK Re arrange vehicles so they are out of the way. Clean up the pad removing any slips trips and falls. Finish flagging off areas. 10:30 - 11:15 0.75 SLICK Have Ed from Expro go to the top of the lubricator in the 80' manlift and inspect the grease head for possible Preying of the line to determine if there is birdnesting. No apparent damage to the line, hold safety meeting to discuss the findings 11:15 - 11:30 0.25 SLICK Hold meeting and decide to pump 12 bbls of 6% KCL into well to push down toolstring. 3600 psig max pump pressure limits on lubricator Printed: 8/22/2007 8:08:23 AM • • Marathon OiI Company Operations Summary Report Page 5 of 7 Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: MAINTENANCE/REPAIR Start: 3/29/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours `Code Code Phase Description of Operations 5/4/2007 11:30 - 12:37 1.12 SLICK Pump 12 bbls of 6% KCL water down hole, Toolstring did not move, WHP dropped to 1660 and stabilized Pump Rate WHP BBL Pumped OPS 0 bpm 2150 0 Start Pumping bring to 1 bpm 1/2 2140 1 3/4 2150 1 2130 1.5 2 2135 Bring to 2 bpm in 2nd gear 2 2150 2 2120 3.5 Bring to 3 bpm in 3rd gear 2 2180 4.5 3 2160 8.5 3.72 Max 2170 10 Bring to Max pump rate in 4th gear " 2145 11 " 2120 12 1780 12 Shut down pumps and wait on pressure 0 1750 12 0 1700 12 0 1660 12 12:37 - 13:00 0.38 SLICK Shut down operations and hold safety meeting to discuss what we need to do next. Decision to kill well was made 13:00 - 15:00 2.00 SLICK Hold safety meeting during lunch and decide to shut down until tomarrow. We will go into a well kill situation tomarrow morning 15:00 - 17:00 2.00 SLICK ASRC bring over liners for around the wellhead and re-berm the dunnage 17:00 - 06:00 13.00 SLICK Have Expro sit on the well maintaining grease pounder pressure and integrity of the well overnight 5/5/2007 07:00 - 08:00 1.00 SAFETY MTG_ PMPSWB Hold Safety Meeting with BJ and Expro and discuss full JSA. Clearly identify hazards, Slips Trips and Falls. Have MOC HES onsite and attend the safety meeting. No rigup. Everything is onsite 08:00 - 09:30 1.50 PUMP_ TRET PMPSWB Notice that there is Hydrates that have formed ontop of the lubricator. Valves were only able to be turned in 2 times before locking up. Beging pumping McOH (methanol) to melt the hydrates. Pump less than a bbl ', (-30-40 gal) let sit and warm up pump truck and set up to pump down the string. Valves came back to 4.5 turns after the methanol was pumped 09:30 - 11:00 1.50 PUMP_ WTR PMPSWB Pressure up pump and lines to 3400 psig and bleed to 2200 psig (Approx WHP). Open downhole valve and pump 0.25 bbl of 6% KCL Water downhole. Lubricator and WH pressured up to 3300 psig and slowly bled down to 3000 psig. Bled off pressure to pump 0.125 bbl back to Pump. RU McOH pump and pumped less than a bbl in the lubricator. re-pressure lubricator and WH to 3300 psig. Bled off pressure to pump and call for a safety meeting 11:00 - 11:30 0.50 SAFETY MTG_ PMPSWB Hold Safety Meeting and discuss situation. Decide to Pump down well with Methanol Skid to get better rate. 11:30 - 17:00 5.50 PUMP_ TRET PMPSWB Pump Methanol Into Tree to melt ICE Pressure up to 3400 psig (bottleing up), This is a very slow process. Trickle in McOH all night long to help melt the ice. Steam on Wheels is going to come out to heat up the tree to expediate the melting. 17:00 - 06:00 13.00 PUMP_ TRET PMPSWB Have night watch on well, Continue to Pump McOH, Heat Tree, Start back in the morning, Once Ice Plug is gone proceed to well kill action Printed: 8/22/2007 8:08:23 AM • • Marathon Oil Company Page s of 7 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: MAINTENANCE/REPAIR Start: 3/29/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Phase Description of Operations Date From - To Hours Code . Code 5/5/2007 17:00 - 06:00 13.00 PUMP_ TRET PMPSWB plan 5/6/2007 07:00 - 08:00 1.00 SAFETY MTG_ PMPSWB Hold Safety Meeting with BJ and Expro and discuss full JSA. Clearly identify hazards. Review conditions of Safe Work Permit and operational plan to kill well. No rigup. Everything is onsite. Had Steam-on-Wheels heat the wellhead and tree overnight. There was an indication that the ice plug had been removed around 01:30 hrs on 5/5/07 when the trapped wellhead pressure broke back to 2180 psi and stabilized. Continued to pump methanol down well periodically to keep wellbore open and free of ice plugs. 08:00 - 09:00 1.00 PUMP_ WTR PMPSWB Start and warm up BJ pumping equipment. Lined out valves to pump down 3-1/2" casing through tie-in connection to flow line. 09:00 - 09:30 0.50 PUMP_ WTR PMPSWB Opened valves and pumped 3 bbls 6% KCL water down casing to verify that the ice plug was eliminated. 09:30 - 10:30 1.00 MIX_ PILL PMPSWB Mix 11.0 bbl BJ CleanPlug viscous pill at 80 Ib/bbl polymer loading blended to achieve a 30 min crosslinker delay time. 10:30 - 11:30 1.00 PUMP_ WTR PMPSWB Opened well with 2130 psi initial pressure. Pumped 13 bbls of 6%KCL water at 1-2 BPM followed by 11 bbls of CleanPlug visc pill. Had to decrease pump rate to 1.5 BPM to level out climbing treating pressure due to increased friction pressure as pill crosslinker began to work. Displaced pill to within 2 bbls of the top Module 10 pert at 7373' MD with 51.0 bbls of 6% KCL water. Shut down and monitored pressure falloff from 1450 psi to 530 psi. 11:30 - 12:00 0.50 SAFETY MTG_ PMPSWB Held Safety Meeting with all on site to discuss the next step of breaking the lubricator above the wireline valve after the well is determined to be dead. 12:00 - 14:00 2.00 BLOWD CSG_ PMPSWB Allowed gas bubbles to migrate to surface and performed multiple gas bleed downs until no surface pressure. Waited and observed that well was remaining dead. 14:00 - 14:30 0.50 SAFETY MTG_ PMPSWB Held Safety Meeting with Expro and MOC personnel while BJ Services personnel moved off location temporarily. Discussed again the next step of breaking the lubricator above the wireline valve. 14:30 - 15:15 0.75 PULD_ PGUN PMPSWB Unscrewed lubricator connection above the wireline valve. Pulled up on lubricator with crane and found spent pert gun moving with lubricator. Pulled gun up and closed bottom master valve. Extracted the remaing portion of the gun from the tree. LD gun and lubricator. Closed top master and swab valve. 15:15 - 18:00 2.75 RURD_ ELEC PMPSWB RDMO Expro wireline and BJ Pumping Services. Wireline was "bird-caged" from above rope socket to the grease tubes. No indication of guns stuck in the tree. Left well shut in and night capped. Released 80' manlift. ASRC vac truck hauled off gelled and produced water to disposal. 5/26/2007 07:00 - 08:00 1.00 SAFETY MTG_ CMPPRF Hold PJSM, discuss hazards, and obtain Safe Work Permit. 08:00 - 08:30 0.50 RURD_ ELEC CMPPRF Rigup Expro a-line. PU PLT string to log well. 08:30 - 08:55 0.42 TEST_ BOPE CMPPRF Test lubricator to 1500 psi. Good test. Drain lubricator. 08:55 - 10:45 1.83 RUNPU ELEC CMPPRF Open swab valve. RIH PLT. 843 psi Surface pressure. 10:45 - 11:00 0.25 RUNPU ELEC CMPPRF Sat down @ 8420' fell thru bridge. 11:00 - 11:10 0.17 RUNPUL ELEC CMPPRF Tag TD @8506'. Start 10 min. station. 11:10 - 11:28 0.30 RUNPU ELEC CMPPRF Pull to 7500'. Start 5 min station 1140.1 psi. 11:28 - 11:33 0.08 RUNPU ELEC CMPPRF End 5 min station 1130.4 psi. 11:33 - 11:46 0.22 RUNPU ELEC CMPPRF Pull to 6500'. Start 5 min station 1095.5 psi. 11:46 - 11:51 0.08 RUNPU ELEC CMPPRF End 5 min. station 1090.2 psi. 11:51 - 12:04 0.22 RUNPU ELEC CMPPRF Pull to 5500' Start 5 min station 1040.4 psi. 12:04 - 12:09 0.08 RUNPUL ELEC CMPPRF End 5 min station.1049.1psi. Printed: 8/22/2007 8:08:23 AM • • Marathon Oil Company Page 7 of 7 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: MAINTENANCE/REPAIR Start: 3/29/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Phase Description of Operations Code 5/26/2007 12:09 - 12:21 0.20 RUNPUL ELEC CMPPRF Pull to 4500'. Start 5 min station 1006.6 psi. 12:21 - 12:26 0.08 RUNPUL ELEC CMPPRF End 5 min station 1012.5 psi. 12:26 - 12:38 0.20 RUNPUL ELEC CMPPRF Pull to 3500'. Start 5 min station 979.7 psi. 12:38 - 12:43 0.08 RUNPUL ELEC CMPPRF End 5 min station 981.4 psi. 12:43 - 12:55 0.20 RUNPUL ELEC CMPPRF Pull to 2500'. Start 5 min station 943.9 psi. 12:55 - 13:00 0.08 RUNPUL ELEC CMPPRF End 5 min station 957.6 psi. 13:00 - 13:13 0.22 RUNPUL ELEC CMPPRF Pull to 1500'. Start 5 min station 918.8 psi. 13:13 - 13:18 0.08 RUNPUL ELEC CMPPRF End 5 min station 904.8 psi. 13:18 - 13:29 0.18 RUNPUL ELEC CMPPRF Pull to 500'. Start 5 min station 878.3 psi. 13:29 - 13:34 0.08 RUNPUL ELEC CMPPRF End 5 min station 905.4 psi. 13:34 - 13:41 0.12 RUNPUL ELEC CMPPRF Pull to surface. Start 10 min station 881.3 psi. 13:41 - 13:51 0.17 RUNPUL ELEC CMPPRF End 10 min station 853.5 psi. 13:51 - 13:55 0.07 RURD_ ELEC CMPPRF Shut in swab valve. RD. 17:10 - 18:00 0.83 RURD ELEC CMPPRF Secure well and leave location. Printed: 8/22/2007 8:08:23 AM • • SARAH PALlN GOV ERNOR ~1 ~-~t~BtaAT 0~ ~~+~ 333 W 7th AVENUE, SUITE 100 CO~SrjRQ~ii01` COr'~II5-7I~~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 278-1433 Dennis Donovan FAX (907) 276-7542 Production Engineer Marathon Oil Company PO Box 1949 Kenai, AK 99611-1949 Re: Cannery Loop Field, Beluga Gas Pool, CLU # 11 Sundry Number: 307-211 Dear Mr. Donovan: 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. Thank you for including the information regarding the well work operations performed between March 29 -May 26, 2007 as authorized by form 10-403 307-106. Such information is more properly submitted using form 10-404, Report of Sundry Well Operations. Please submit form 10-404. It is not 11~~ necessary to submit another copy of the operations re orts. D.~Pl~w~c coe'~Cs cecc~~+~-J Aae7i~towc,,\ c2eOC~F ~oQ1cs s~b~:~ltE~ "1 to-ypy~¢c~:~e~ ~la-~ 01. c~(as-o`1 c-e.~.nve~c' . When providing notice for a representative of the Commission to witness any ~~~ required test, contact the Commission's petroleum field inspector at (907) ~i 1-01 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Courti/}~~,s rehearing has been requested. DATED this day of e, 2 7 Encl. ~p(o bS~S f J ~~ i ~ M Marathon MARATHON Oil Company June 13, 2007 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-403 Sundry Notice Field: Cannery Loop Gas Field Well: Cannery Loop Unit # 11 Dear Mr. Maunder: Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1326 Fax 907/283-1350 ~~~~V~~ JUN ~ ~ 2007 '~iaska Qil & Gas Cans. Commission .Anchorage We propose to run a 1.75" velocity string in CLU #11. We anticipate improving the ability of the well to unload water and to increase production. Please find a 10-403, operations program, wellbore diagram, and proposed wellbore diagram attached. If you have any questions or need further information please call me at (907) 398-1362. Sincer , Denni van Production Engineer Enclosures: 10-403 Sundry Notice cc: AOGCC Operations Procedure Houston Well File Weli Schematic Kenai Well File Proposed Well Schematic DMD Operation Summary KJS - KC~,CI V CU ~~ ~ ~ ~ TATE OF ALASKA ~''~~ ,~ ALAS OIL AND GAS CONSERVATION COM SION ~ ~S JUN 2 5 2007 APPLICATION FOR SUNDRY APPROVAL~iaska {Jl ~ Gas Cons. Commission 20 AAC 25.280 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate ^ Waiver ^ Other Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ V-String Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Marathon Oil Com an Development ^ Exploratory ^ 206-058 3. Address: Stratigraphic ^ Service ^ 6. API Number: PO Box 1949, Kenai Alaska, 99611 50-133-20559-00-00' 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 ~ Cannery Loop Unit # 11 ' 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): 1~a~l1SC~ ~lO,S ~ ~14 OO 2491' FSL, 2291' FWL, Sec. 4, T5N, R11 W, S.M. 21' ~ nnery Loop Gas Field Ca 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): 9305' 7914' 9247 ~ 7856' ~ N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 136' 20" 136' 136' 1530 psi 5020 psi Surface 1602' 13/3-8" 1602' 1489' 3090 psi 1540 psi Intermediate 5595' 9-5/8" 5595' 4355' 6330 psi 3810 psi Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6593'-9094' 5221'-7703' 3-1 /2" L-80 9284' Packers and SSSV Type: N/A Packers and SSSV MD (ft): N/A 13. Attachments: Description Summary of Proposal ^ 14. Well Class after proposed work: Detailed Operations Program ~ BOP Sketch ^ Exploratory ^ Development ^~ Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: 3-Aug-07 Oil ^ Gas 0 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 Dennis Donovan Title Production Engineer Signature Phone (907) 283-1333 Date 13-Jun-07 ~ ' COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: .~ 2! ! Plug Integrity ^ BOP Test ~ Mechanical Integrity Test ^ Location Clearance ^ Other: ~o~o QS~ ~T Qo~ ~ S ~- us Q `~,~,,,~~ Subsequent Form Required: ~~`~ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: +~SiQ Form 10-403 Revised 06/2006 ~ ~`~y~'~ ~ \I H~ Submit in Duplicate ~ ~ M MARATHON MARATHON OIL COMPANY ALASKA REGION Cannery Loop Gas Field Cannery Loop Unit # 11 2007 CT Velocity String Hangoff Procedure Notes: This procedure covers work to install a 1.75" OD coil tubing velocity string to alleviate liquid loading. • Contact Vetco prior to MIRU to verify maximum hanger head ID & mandrel OD measurements. BJ CoilTech supervisor will drift all WH connections prior to rig up to insure drift ID of individual connections. 1. Obtain Real-time Flowing Temperature-Pressure Survey. Make arrangements with the Operator to blow down well to unload fluid the day before this survey work is to be done. MIRU Expro wireline. Hold PJSM. Roundtrip a gauge ring with junk basket to tag top of fill in the production liner. RIH with CCL and 1-11/16" real-time Spartec pressure-temperature tool and GR with weight bars on wireline observing tool response for indication of producing fluid level. RIH to tag fill. Correlate depth and POOH logging to about 100' above fluid level. POOH taking 3 min benches every 500'. RDMO Expro Wireline. 2. Install Coil Tubing Head. 3. Make flowline modifications for coil tubing velocity string. Plumb in and test annular flow line with a new 5K choke and ball valve to existing flowline. 4. MIRU MOC flow back equipment including open-top flowback tank, choke skid, gas buster, and flow back iron. MIRU closed-top 500 bbl Rain-for-Rent fluid supply tank. Lay liner and berm area around tank. Load fluid supply tank with 6% KCI and heat as necessary. Deliver diesel fuel manlift and two light plants. Remove well house and lock out electrical connections. 5. MIRU BJ coiled tubing unit with BJ work string (if needed to clean out fill) and Maration velocity string on reel. Rig up fluid and N2 pumps. RU pumping iron and flow back iron. 6. Nipple up BJ CT wellhead assembly (WHA1. Dual-Combi BOP (dressed for 1-3/4" CT). Function test BOP. Stab 1-3/4" CT into injector. Install BJ coil tubing connector and pull test to 15,000 lbs. Nipple up injector to W HA. 7. Pressure test surface lines and CT equipment with 6% KCL water. Pressure test pump iron (200 low/4500 high psi). Pump fluid to load CT. Pressure test CT, WHA and flow back iron to choke manifold (200/4500 psi). Pressure test BOP rams (200/4500 psi). Purge pressure test fluids w/ N2 to flowback tank and vent N2 pressure to flowback tank. 8. Cleanout fill in wellbore. (ONLY IF FILL IN WELL IS COVERING PERFORATIONS) MU BJ CoilTech. Pull BHA into lubricator and take to wellhead. RIH with BHA and clean out fill to TD or Specified Running Depth with 6% KCL water and 500 scfm of nitrogen. Quit pumping KCL water and RIH with CT unload fluid from well with nitrogen to the flowback tank. POOH and LD cleanout BHA. 9. MU CT BHA. Nipple injector off WHA. MU velocity string BHA to end of CT. Page 2 of 2 10. Nipple up iniector to WHA. Pressure test WHA using CT kill line (200/1500 psi). Bleed WHP to flow back tank. Prior to next Step, ensure that flowback line from W HA through choke manifold to gas buster is ready and available to keep TP at or below 1500 psi while RIH to eliminate possible CT collapse. This would serve as a backup if flow through the production flow line was unexpectedly curtailed or ceased. 11. RIH with coil tubing velocity string and BHA with well flowing to sales up Tubing-Coil Tubing annulus. 12. Cut coil tubing. PUH to span W HA for final landing depth. Set CT in BOP tubing/slip rams. Lock tubing/slip rams. Slack off injector chain traction and roll chains to verify slips are set. Release WHP above tubing rams to the flowback tank. Nipple injector off of WHA. Walk injector up CT. Install C plate above BOP and polish rod clamp on CT. Cut CT above BOP high enough to allow Vetco to install CT connector and hanger mandrel assembly. 13. MU Vetco Coil Tubing Hanger and Baker GS Running Tool. Swing Injector and lubricator away from WH. Vetco to connect VGCT Coil Tubing Hanger. While Vetco is making up CT hanger, BJ CoilTech to connect Baker GS tool string assembly to coil on reel trailer. Pull test CT connector to 25,000 lbs. Latch GS spear to Vetco mandrel after PU injector. 14. RIH and land Vetco CT hanger per Vetco procedures. Verify string and hanger are landed and secured per Vetco procedures. Slack off string weight to neutral. Tighten Lock Screws. Pressure test hanger between O-rings to 5000 psig with hand pump pressure test unit (Vetco Supplied). Tighten Lock Screws. 15. Release 3" GS Running Tool. Sit down weight on Hanger. Start pumping 6% KCL water at approximately 2 BPM through CT to release GS spear. Watch for weight change to verify release and pickup to unlatch spear. Stop pumping when spear is unlatched and above mandrel. 16. Purge KCL water from CT remaining on reel trailer with nitrogen. Allow N2 to vent to flowback tank, Pressure Up CT with N2 to remove shear plug and aluminum pump-off plug off the end of the CT. Pressure up CT string until shear down plug and aluminum pump-off plug release and fall down hole. 17. Purge N2 from CT remaining in the well. Allow N2 to vent to Flowback tank. Have a gas meter onsite to monitor LEL. Once methane is detected send production to sales. 18. FLOW TEST WELL TO SALES. 19. RDMO and release eauipment. RD flowback iron. Release tanks and all rental equipment to vendors. ~J API: 50-133-20559-00 RT-GL: 21.00' RT-THF: 21.70' ` 2491' FSL, 2291' FWL, Sec. 4, II^q T5N, R11W, S.M. Tree cxn = 4-3/4" Otis ~ TOC (est.) - 500' above 9-5/8" shoe Ceramic flapper valves below each iodule as follows: Module 1 - NA Module 2 - 8640' (Broken CT 9/28/2006) Module 3 - 8530' Module 4 - 8418' (Broken CT 9128/2006) Module 5 - 8240' (Broken CT 9/28/2006) Module 6 - 7960' Module 7 - 7900' Module 8 - 7715' (Broken CT 9/28/2006) Module 9 - 7498' Module 10 -7399' Module 11 -6618' CLU-11 M ~wllewrNOM Drive Pipe: 20", 131 ppf, X-52, to 136' RKB Surface Casing: 13-3/8", 68 ppf, L-80, BTC @ 1602' RKB, Cmt w/ 228 bbls / 516 sx. of Type 1 at 12.0 ppg. Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 5595' RKB. Cmt w/ 35.6 bbl (95 sx) of class G lead @ 12.5 ppg and 49 bbls (237 sx) Class G tail @ 15.8 ppg Prod. Tubing: 3-112", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9284' RKB. Cmt w/ 1550 sx (325 bbls) of class G at 15.8 ppg 11 Excape modules placed Green control line fired module 1 Yellow control line fired modules 2 thru 7 Red contol line fired modules 8 thru 11 Ceramic flapper valves below each module xcept for module 1 Module 1 - 9084' - 9094' (Frac'd 9/28/06) Module 2 - 8607' - 8617' (Frac'd 9/28/06) Module 3 - 8498' - 8508' (Frac'd 9/28/06) Module 4 - 8383' - 8393' (Frac'd 9/28/06) Module 5 - 8205' - 8215' (Frac'd 9/28/06) Perfed 4/1/07 7939' - 7946' Module 6 - 7929' - 7939' (Perfed 4/1/07) Module 7 - 7868' - 7878' Not Shot Module 8 - 7686' - 7696' (Frac'd 9/28/06) Module 9 - 7472' - 7482' (Frac'd 9/28/06) Proposed Perf 7383' - 7400' Module 10 - 7373' - 7383' (3/28107) Module 11 - 6593' - 6603' Not Shot Well Name & Number: CLU - 11 Lease: Cannery Loop Gas Field County or Parish: Kenai State/Prow. Alaska Country: USA Perforations (MD) See Above (TVD) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completion Fluid: 6% KCL Dated Completed: 9/28/2006 Prepared By: J. R. Thompson Last Revison Date: 10/11/2006 TD - 9305' PBTD - 9247' API: 50-133-20559-00 RT-GL: 21.00' PROPOSED CLU-11 • M ~~ir+u-n~oM 11 Excape modules placed Green control line fired module 1 Yellow control line fired modules 2 thru 7 Red contol line fired modules 8 thru 11 Ceramic flapper valves below each module xcept for module 1 Module 1 - 9084' - 9094' (Frac'd 9/28/06) Module 2 - 8607' - 8617' (Frac'd 9/28/06) Module 3 - 8498' - 8508' (Frac'd 9/28/06) Module 4 - 8383' - 8393' (Frac'd 9/28/06) Module 5 - 8205' - 8215' (Frac'd 9/28/06) Perfed 4/1107 7939' - 7946' Module 6 - 7929' - 7939' (Perfed 411107) Module 7 - 7868' - 7878' Not Shot Module 8 - 7686' - 7696' (Frac'd 9/28/06) Module 9 - 7472' - 7482' (Frac'd 9/28/06) Proposed Perf 7383' - 7400' Module 10 - 7373' - 7383' (3/28/07; Module 11 - 6593' - 6603' Not Shot Drive Pipe: 20", 131 ppf, X-52, to 136' RKB Surface Casing: 13-3/8", 68 ppf, L-80, BTC @ 1602' RKB, Cmt w/ 228 bbls / 516 sx. of Type 1 at 12.0 ppg. Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 5595' RKB. Cmt w/ 35.6 bbl (95 sx) of class G lead @ 12.5 ppg and 49 bbls (237 sx) Class G tail @ 15.8 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9284' RKB. Cmt w/ 1550 sx (325 bbls) of class G at 15.8 ppg Well Name & Number: CLU - 11 Lease: Cannery Loop Gas Field County or Parish: Kenai State/Prov. Alaska Country: USA Perforations (M D) See Above (TVD) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completion Fluid: 6% KCL Dated Completed: 9/28/2006 Prepared By: J. R. Thompson Last Revison Date: 10/11/2006 TD - 9305' PBTD - 9247' . • Page 1 of 3 Maunder, Thomas E (DOA) From: Thomas Maunder (tom_maunder@admin.state.ak.us] Sent: Monday, April OZ, 2007 1:28 PM To: Walsh, Ken Cc: Mullin, Mickey; Donovan Jr, Dennis M.; Ibele, Lyndon; Cissell, Wayne E. Subject: Re: RE: CLU 11(206-058) Request for Verbal to Proceed with Pert Add Changes Ken, et al, There should not be a need to send any addition sundry. The additional work is more of what was originally planned. By copy of this email, you have "verbal" approval to proceed. All of the work should be covered in the 404 report of sundry operations. Call or message with any questions. Tom Maunder, PE AOGCC Walsh, Ken wrote, On 4/2/2007 12:42 PM: Tom, Thank you for forwarding the email thread below regarding your discussions with Dennis Donovan regarding your verbal approval for CLII #11 work. Per the conversation that you and I had on the phone today, I am requesting that the AOGCC provide verbal approval to cement squeeze the open perforations in Modules 8, 9, and 10 in this well. The proposed squeeze is necessary to shut off excessive produced water influx which has resulted in multiple well cleanouts in the recent past to remove produced water and formation sand. The well is currently producing 3.9 MMscfd, 200 BWPD, at 1050 psig FTP. I have included a wellbore diagram for your review. This past weekend, Marathon ran a PLT over all the open perforations in this well from 7373' to 9094' MD. The PLT interpretation indicates that the majority of the water production is coming from the perfs at Module 8, 7686-7696' MD, which had been hydraulically fracture stimulated on 9/28/06. To accomplish this water shutoff, Marathon proposes to: 1. Set a composite bridge plug about 25' below the bottom Module 8 perforation at 7696' MD, 2. Spot a balanced cement plug with coiled tubing from the top of the composite BP at about 7720' MD to about 500' above the Module #10 top perforation at 7373' MD, 3. Achieve a 1000-1200 psig squeeze pressure. 4. RIH and jet out any excess cement to 100' above the Module #10 top perf, 5. Hold squeeze pressure while WOC, 6. Drill out cement to below the bottom perf at 7696' MD, 7. Test cement squeeze to about 1000 psig with a 6~ KCL water head. 8. If no test, resqueeze with cement, contaminating cement in wellbore with Biozan after node development, or If good test, drill out composite BP with KCL water and nitrogen, push BP to bottom and jet well in with nitrogen. 9. Install a 1-3/4' coiled tubing velocity string. L cJ ~ ~~ ~©~ ~ ~ ~~ 9/7/2007 . Page 2 of 3 For clarification, Marathon is proposing to cement squeeze Module #9 and #10 perfs with the Module #8 perfs because the Module #9 and #10 perfs do not produce commercial quantities of gas at this time {based on recent PLT interpretation). Also, the chance of getting a good cement squeeze on the first attempt is better than if a cement retainer was set above the Module #8 perfs. Should the AOGCC grant verbal permission to proceed with the aforementioned cement squeeze, Marathon would amend its Form 10-403 application to include the cement work and the other changes. verbally approved and outlined in the emails below in one submission. Marathon would like to start work to set the composite BP this afternoon and cement squeeze the intervals tomorrow, April 3. We have coiled tubing equipment rigged up on the well and wireline equipment standing by after the work performed over this past weekend. Best Regards, Ken Ken D. Walsh Senior Production Engineer Marathon Oil Company-Alaska Asset Team 907-283-1311 (office) 907-394-3060 (cell) -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Monday, April 02, 2007 11:24 AM To: Walsh, Ken Subject: [Fwd: RE: CLU 11 Request for Verbal to Proceed with Perf Add Changes] -------- Original Message -------- Subject: RE: CLU 11 Request for Verbal to Proceed with Perf Add Changes Date: Thu, 29 Mar 2007 16:42:14 -0500 From: Donovan Jr, Dennis M. <ddonovan@marathonoiL.com> __ To: Thomas Maunder <tom maunder@admin.state.ak.us> Tom, Thanks a lot for looking at this at such short notice Dennis Dennis M. Donovan Jr. Production Engineer I 907-283-1333 Office 907-398-1362 Cell *From:* Thomas Maunder [mailt.o:tom maunder@admin.state.ak.us] - -. _ _ __ *Sent:* Thursday, March 29, 2007 11:52 AM *To:* Donovan Jr, Dennis M. *Subject:* Re: CLU 11 Request for Verbal to Proceed with Perf Add Changes 9/7/200'7 Page 3 of 3 Dennis, I have looked at the sundry for this work and by copy of this message you have "verbal" approval to proceed. Call or message with any questions. Tom Maunder, PE AOGCC Donovan Jr, Dennis M. wrote, On 3/29/2007 10:46 AM: Tom, As per our discussion, this is what we intend to complete on CLU 11. I would like to request verbal approval to complete the program as follows with the following module/per adds changes. Add perforations: * A. Module 6 - 7929' - 7939' Escape (10'} and 7939' - 7946' on W/L (7' within this zone) = Total of 17' * B. Module 7 - is not going to be fired but we intend to add 7882' - 7892' (10' on W/L) = Total of 10' - module 7 is in a risky position with respect to water * C. Module 10 - 7373' - 7383' Escape (10') and ?383' - 7400' (17' on W/L) = Total of 27' * D. Module 11 - is not going to be fired Original intentions: * Module 6 - 7929'-7939' (10') - Yellow Control Line 2-7 * Module 7 - 7868'-?878' {10') - Yellow Control Line 2-7 * Module 10 - 7373'-7383' (10') - Red Control Line 8-11 * Module 11 - 6593'-6603' (10') - Red Control Line 8-11 Thank You, Dennis Dennis M. Donovan Jr. Production Engineer I 907-283-1333 Office 907-398-1362 Cell 9/7/2007 • SARAH PALIN, GOVERNOR C011TSERQ~'jjp ~ I ~ 333 W. 7th AVENUE, SUITE 100 ~~.~~ii ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Dennis Donovan Production Engineer Marathon Oil Company PO Box 1949 Kenai Alaska 99611 Re: Cannery Loop Unit, Beluga Gas Pool, CLU 11 Sundry Number: 307-106 Dear Mr. Donovan: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness. any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of thin decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DATED this day of March, 2007 Encl. 2 oC~ - os-~ M Marathon MARATHON Oil Company March 13, 2007 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 V1/ 7th Ave Anchorage, Alaska 99501 Reference: 10-403 Sundry Notice Field: Cannery Loop Unit Well: CLU-11 Dear Mr. Maunder: Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1326 Fax 907/283-1350 ~~~wE® MAR ~ 8 2007 Alaska Oil & Cas Co-IS. Anchorage Cession Cannery Loop 11 is an Escape Well with 11 Modules installed on 3.5" mono-bore tubing. Production has not been strong enough to keep the well unloaded. Tubing pressure slowly falls off while the wellbore fills with fluid. We request to perforate Modules 6,7,10, and 11; which were not initially perforated during the original completion. This will help the well unload easier. After flow testing, we intend to run a 1.75" Coil Tubing Velocity String to 6543' MD. (50' above the highest producing interval) We estimate that we will start this work on or after April 2, 2007. Once started, the work should not take more than one week's time. If you have any questions or need further information please call me at (907) 398-1362. Dennis M. Donovan Jr. Production Engineer Enclosures: 10-403 Sundry Current Well Schematic Proposed Well Schematic Operations Summary CLU 11 Perforation/V-string cc: AOGCC Houston Well File Kenai Well File DMD Program ~~ ~ ~~, ~ ~i ;~"~ L. W ice.. i ~l ~ t~ .~ STATE OF ALASKA / 'j~1-,09 ALAS OIL AND GAS CONSERVATION COM ION ~ MAR ~ $ 2007 rte, APPLICATION FOR SUNDRY APPROVALS Alaska 01 & Gas Cons. Commission 20 AAC 25.280 ~nrhnrnru~ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate ~ Waiver ^ Other ^~ Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Install 1.75" CT Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ Velocity string 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Marathon Oil Com an Development ^ Exploratory ^ 206-058 3. Address: Stratigraphic ^ Service ^ 6. API Number: ~ PO Box 1949, Kenai Alaska, 99611 50-133-20559 spa 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 ~ CLU 11 ' 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ADL - 324602' 56 FT. (21' AGL) Cannery Loop Unit /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): 9305' 7914' ., 9247 - 7856' - N/A N/A Casing Length Size MD TVD Burst Collapse Structural 136' 20", 131#, X-52 136' 136' Conductor Surface 1602' 13-3/8", 68#, L-80 1602' 1489' Intermediate Production 5595' 9-5/8", 40#, L-80 5595' 4355' Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6593'-9094' 5221'-7703' 3-1 /2" / 3-1/2" 9.3# L-80 9284' RKB Packers and SSSV Type: None in current completion Packers and SSSV MD (ft): N/A 13. Attachments: Description Summary of Proposal ^ 14. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ^ Exploratory ^ Development ^~ Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: 2-Apr-07 Oil ^ Gas Q Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ [] WINJ ^ WDSPL ^ J Commission Representative: ~~ 3j~'C~1 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba or Dennis Donovan Printed Name Dennis M. Donovan Jr. Title Production Engineer Signature Phone (907) 283-1333 Date 13-Mar-07 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integ ri ^ BOP Test '~ ty ical Inte rity Test ^ Location Clearance ^ Mechan ` t t ~ ~ ~*- Other: -~JW ~.~ ~~~ ~5-~- C+~.~ Q\Cxr. ~ ~ ~~.-,~ F ~ ~`.~SG.~D~~~V.~- , Subsequent Form Required: ~..,~~ ~~5 gF~ MAR 3 0 2007 APPROVED BY ~ ~~0~ Approved by: OMMISSIONER THE COMMISSION Date: c,~ ,f/ Form 10-403 Revised 06/2006 ~ ~ I~~~,~ ~~ Submit in Duplicate M MARATHON Marathon Oil Company Alaska Region Tuesday, June 27, 2006 CLU 11 Cannery Loop Unit Cleanout/N2, Perforate, and V-string Program WBS# History: Due to liquid loading this well was not able to hold line pressure and continue to produce. While in production the water that was made to surface also brought in sand into the wellbore. Objective: Cleanout and Kick off the well with KCL and N2, Perforate the remaining Escape zones, Break out the flappers with slickline, and Run 1.75" CT Velocity String. Procedure: 1. MIRU BJ CT Unit, Flowback-Buster-Choke, KCL water tank, Methanol tank. 2. Test BOP 200 / 4500 psi with test bar. 3. Injector to tree. PT stripper to 1500 psi. 4. Open well to gas buster and cool down N2. 5. Start N2 to warm up CT and RIH pumping N2 at 500 scfm. 6. When Tag is made on fill, POH 100', Start KCl at 1 BPM w/ N2 at 500 to load CT. 7. Clean out bridges and fill to 9150'. 8. POH while pumping water and N2 to circulate out solids. Freeze Protect with Methanol (if needed) 9. SD N2 when well will flow on its own, POH. Turn well to production system and vent N2. 10. Rig Back CT Unit 11. MIRU Pollard Wireline 12. RU Pressure Pump to fire Escape modules. Have Phil Snyder attend and confirm shots. a. Module 6 - 7929'-7939' (10') -Yellow Control Line 2-7 b. Module 7 - 7868'-7878' (10') -Yellow Control Line 2-7 ~~ ~~~` ~ ~ ~ c. Module 10 - 7373'-7383' (10') -Red Control Line 8-11 ~~~ ~,~ p{--~~5 ,b~ ~\ d. Module 11 - 6593'-6603' (10') -Red Control Line 8-11 ~'~_~` 3/, fi-0 ~1 13. Flow well and confirm change in wellbore pressure and flowrate. 14. Shut in well and let pressure stabilize (giving flappers time to close so they are able to be broken. 15. RIH w/ flapper breaker assy., sufficient weight bar, jars and oils. Attempt to break out remaining flappers. 16. RIH w/ GR to bottom to verify no shards of ceramic are left in each pocket. 17. While flowing the well. 18. MU velocity string BHA. Coil connector, 10' straight bar, X nipple, WEG. 19. Shell test 200 / 4500 psi. 20. RIH with CT velocity string, Setting depth is 6543' MD (50' above Module 1 @ 6593' MD) 21. Set slips. Walk injector up pipe and cut CT. Make up hanger assembly and GS running tool. Reconnect to CT and walk injector back down to BOP. 22. Pull test hanger to 25,000#. Hold pipe weight and open Pipe rams. RIH and land hanger @ 6543' MD on pipe. Test hanger to 5000 psig. Pump CT and release GS running tool. PU CT and close swab valve. 23. Displace methanol from CT with N2. Open swab and pressure up velocity string with N2 and shear plugs at bottom of BHA. SD N2 and close swab. 24. Bleed down CT. 25. Rig down and release CT. • API: 50-133-20559-00 RT-GL: 21.00' RT-TH F: 21.70' 2491' FSL, 2291' FWL, Sec. 4, T5N, R11 W, S.M. Tree cxn = 4-3/4" Otis ~ TOC (est.) - 500' above 9-5/8" shoe Ceramic flapper valves below each iodule as follows: Module 1 - NA Module 2 - 8640' (Broken CT 9/28/2006) Module 3 - 8530' Module 4 - 8418' (Broken CT 9/28/2006) Module 5 - 8240' (Broken CT 9/28/2006) Module 6 - 7960' Module 7 - 7900' Module 8 - 7715' (Broken CT 9/28/2006) Module 9 - 7498' Module 10 -7399' Module 11 -6618' CLU-11 M nnww-n~ow Drive Pipe: 20", 131 ppf, X-52, to 136' RKB Surface Casing: 13-3/8", 68 ppf, L-80, BTC @ 1602' RKB, Cmt w/ 228 bbls / 516 sx. of Type 1 at 12.0 ppg. Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 5595' RKB. Cmt w/ 35.6 bbl (95 sx) of class G lead @ 12.5 ppg and 49 bbls (237 sx) Class G tail @ 15.8 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9284' RKB. Cmt w/ 1550 sx (325 bbls) of class G at 15.8 ppg - 11 Excape modules placed - Green control line fired module 1 - Yellow control line fired modules 2 thru 7 - Red contol line fired modules 8 thru 11 -Ceramic flapper valves below each module except for module 1 Module 1 - 9084' - 9094' (Frac'd 9/28/06) Module 2 - 8607' - 8617' (Frac'd 9/28/06) Module 3 - 8498' - 8508' (Frac'd 9/28/06) Module 4 - 8383' - 8393' (Frac'd 9/28/06) Module 5 - 8205' - 8215' (Frac'd 9/28/06) Module 6 - 7929' - 7939' Module 7 - 7868' - 7878' Module 8 - 7686' - 7696' (Frac'd 9/28/06) Module 9 - 7472' - 7482' (Frac'd 9/28/06) Module 10 - 7373' - 7383' Module 11 - 6593' - 6603' Well Name 8~ Number: CLU - 11 Lease: Cannery Loop Gas Field County or Parish: Kenai State/Prow. Alaska Country: USA Perforations (MD) See Above (TVD) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completion Fluid: 6% KCL Dated Completed: 9/28/2006 Prepared By: J. R. Thompson Last Revison Date: 10/11/2006 TD - 9305' PBTD - 9247' • i M Mww-TMO^ CLU 11 Pro osed V-strin A lication(3/13/07) API: 50-133-20559-00 RT-GL: 21.00' RT-THF: 21.70' 2491' FSL, 2291' FWL, Sec. 4, T5N, R11W, S.M. Tree cxn = 4-3/4" Otis (est.) - 500' above 9-5/8" shoe 1.75" CT String From 0'-6543' KB - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module 1 - NA Module 2 - 8640' (Broken CT 9/28/2006) Module 3 - 8530' Module 4 - 8418' (Broken CT 9/28/2006) Module 5 - 8240' (Broken CT 9/28/2006) Module 6 - 7960' Module 7 - 7900' Module 8 - 7715' (Broken CT 9/28/2006) Module 9 - 7498' Module 10 -7399' Module 11 -6618' D Drive Pipe: 20", 131 ppf, X-52, to 136' RKB Surface Casing: 13-3/8", 68 ppf, L-80, BTC @ 1602' RKB, Cmt w/ 228 bbls / 516 sx. of Type 1 at 12.0 ppg. Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 5595' RKB. Cmt w/ 35.6 bbl (95 sx) of class G lead @ 12.5 ppg and 49 bbls (237 sx) Class G tail @ 15.8 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9284' RKB. Cmt w/ 1550 sx (325 bbls) of class G at 15.8 ppg - 11 Excape modules placed - Green control line fired module 1 -Yellow control line fired modules 2 thru 7 - Red contol line fired modules 8 thru 11 -Ceramic flapper valves below each module except for module 1 Module 1 - 9084' - 9094' (Frac'd 9/28/06) Module 2 - 8607' - 8617' (Frac'd 9/28/06) Module 3 - 8498' - 8508' (Frac'd 9/28/06) Module 4 - 8383' - 8393' (Frac'd 9/28/06) Module 5 - 8205' - 8215' (Frac'd 9/28/06) Module 6 - 7929' - 7939' (Shoot Press Up) Module 7 - 7868' - 7878' (Shoot Press Up) Module 8 - 7686' - 7696' (Frac'd 9/28/06) Module 9 - 7472' - 7482' (Frac'd 9/28/06) Module 10 - 7373' -7383' (Shoot Press Up) Module 11 - 6593' -6603' (Shoot Press Up) NOTE: ONLY A PLAN WBD Well Name & Number: CLU - 11 Lease: Cannery Loop Gas Field County or Parish: Kenai State/Prov. Alaska Country: USA Perforations (MD) See Above (TVD) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completion Fluid: 6% KCL Dated Completed: 3/13/2007 Prepared By: J. R. Thompson Last Revison Date: 03/13/2007 (DMD) TD - 9305' PBTD - 9247' • Marathon Oil Company.. Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Event Name: MAINTENANCE/REPAIR Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours Code Code Phase 11 /29/2006 ~ 08:30 - 09:00 0.50 ~ SAFETY MTG_ ~ SLICK 09:00 - 09:30 ~ 0.501 SAFETY MTG_ ~ SLICK 09:30 - 11:00 ~ 1.501 RURD_ SLIK SLICK 11:00 - 12:00 1.00 WAITON EOIP SLICK 12:00 - 13:40 1.67 INSPCT WLHD SLICK 13:40 - 14:25 I 0.751 RUNPULI SLIK I SLICK 14:25 - 15:05 I 0.671 RUNPULI SLIK I SLICK 15:05 - 18:40 3.581 RUNPUL SLIK SLICK 18:40 - 20:00 I 1.331 RURD I SLIK I SLICK 12/14/2006 08:00 - 08:15 0.25 SAFETY MTG_ SLICK 08:15 - 08:30 0.25 RURD_ SLIK SLICK 08:30 - 09:30 1.00 WAITON EOIP SLICK 09:30 - 10:40 1.17 SAFETY MTG_ SLICK 10:40 - 11:15 0.58 RURD_ SLIK SLICK 11:15 - 11:35 0.33 TEST_ PBU_ SLICK 11:35 - 12:45 1.17 RUNPU SLIK SLICK 12:45 - 13:00 0.25 RUNPU SLIK SLICK 13:00 - 13:10 0.17 TEST_ PBU_ SLICK 13:10 - 14:06 0.93 RUNPU SLIK SLICK 14:06 - 14:15 0.151 RUNPUL SLIK SLICK 14:15 - 14:30 0.25 TEST_ PBU_ SLICK 14:30 - 15:00 0.50 RUNPU SLIK SLICK 15:00 - 15:20 0.33 RUNPU SLIK SLICK 15:20 - 15:40 0.33 TEST_ PBU_ SLICK 15:40 - 16:25 0.75 RUNPU SLIK SLICK 16:25 - 16:40 0.25 RUNPU SLIK SLICK 16:40 - 16:55 0.25 TEST_ PBU_ SLICK 16:55 - 17:00 0.08 RUNPU SLIK SLICK 17:00 - 17:30 0.50 RUNPU SLIK SLICK 17:30 - 18:15 0.75 RUNPU SLIK SLICK 18:15 - RURD_ SLIK SLICK 12/15/2006 10:00 - 11:00 1.00 SAFETY MTG SLICK Page 1 of 3 Spud Date: 4/27/2006 Start: 11/28/2006 End: Rig Release: Group: Rig Number: 1 Description of Operations Arrive at KGF main office. Obtain work permit. Travel to CLU pad 3 and spot equipment Hold TGSM with Pollard and MOC. Discussed JSA and MOC Operators concerns with water production on pad. RU Slickline. Attempt to bleed off tree cap, would not bleed down. Call out Vetco to grease the Swab, Wait on Vetco Wait on Vetco to Arrive Vetco greased Swab valve. Operated 2 times and bled off. (Vetco standby for possible reoccurance, 4 Hr Min). Pressure Tested Lubricator to 1500 psig. Good test. RIH w/ 1.75" DD Bailer to 9025' KB. Tagged Fill (Module 1 covered). POOH OOH. Obtain sample of fill. MU tools for Tandem gauges (PT) Pressure Test Lubricator to 1500 psig. Good test. RIH w/ Tandem PT Gauges to 9015' KB making appropriate stops and speed on down pass. POOH. Made few 3 min stops at modules. Slickline was freezing at the packoff on the lubricator. Dis-regaurded stops for fear of freezing in the hole. POOH @ 60'/min to 6500' KB (very sticky with ice at that speed). continue at 120'/min to surface and complete static PT at surface. Check Data, RDMO Slickline Unit, Sign out @CLU Pad, Sign out @ KGF office. Arrive at KGF main office. Obtain work permit. Spot Equipment Wait on plow and sand truck Hold PJSM and Go over Expro JSA Plow truck showed up while in rig up, Start to rig up Start pressure test lubricator to 1500 psig, good test RIH w/ 2.35" Swedge and 1.5" sample bailer w/ mule shoe btm. Set down @ 8436' KB POOH hung up @ 7505' KB, try to work thru. Beat down and moved down hole to 7621' KB. Spanged Free and POOH OOH, look at tools, heavy metal marks on swedge M/U 2.75" Magnet, PressTest lub to 1000 psig, good test RIH w/ 2.75" Magnet, tag fluid level @ 2681' KB. Set down @ 7475' KB, POOH OOH and look at tools, nothing on tools (thought we had metal above the swedge the first run, that is why we ran the magnet) M/U 2.75" LIB, P/T Lubricator to 1000psig, good test RIH w/ 2.75" LIB and set down @ 7475', POOH OOH, Perforation marks on LIB M/U 5' X 2" DD Bailer, PR Lub, Test Good RIH w/ bailer, set down @ 8436' KB, POOH OOH, Bailer bottom was chewed up from hitting metal and had a small ammount of sand and ceramic in the bailer M/U 2.125" magnet, PU and Pressure Test RIH Tagged @ 8436' KB, POOH OOH. Small metal chunks on magnet, Rig down Leave Location, turn in work permit and sign out MIRU wire line equipment, held PJSM and discussed procedure. MU new pressure unit to pressure test the lubricator. Uptain work permit Printed: 3/13/2007 11:38:07 AM • Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Event Name: MAINTENANCE/REPAIR Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours Code Code. , Phase 12/15/2006 11:00 - 13:30 2.50 RURD_ SLIK SLICK 13:30 - 13:50 0.33 RURD SLIK SLICK 13:50 - 14:45 0.92 WORK~SLIK SLICK 14:45 - 16:00 1.25 WORK SLIK SLICK 16:00 - 17:30 17:30 - 17:35 17:35 - 17:45 17:45 - 17:55 17:55 - 19:00 12/16/2006 08:00 - 11:00 11:00 - 11:30 11:30 - 11:45 1.50 WORK SLIK SLICK 0.08 WORK SLIK SLICK 0.17 WORK SLIK SLICK 0.17 SAFETY MTG_ SLICK 1.08 RURD_ SLIK SLICK 3.00 SAFETY MTG_ SLICK 0.50 RURD_ SLIK SLICK 0.25 RURD SLIK SLICK 11:45 - 12:35 12:35 - 13:30 13:30 - 13:45 13:45 - 13:55 13:55 - 14:40 14:40 - 14:55 14:55 - 16:00 16:00 - 17:15 17:15 - 17:25 17:25 - 18:00 12/17/2006 07:00 - 08:00 08:00 - 08:30 08:30 - 08:35 08:35 - 09:30 09:30 - 10:20 10:20 - 10:30 10:30 - 11:20 11:20 - 11:25 11:25 - 11:30 11:30 - 11:40 0.83 WORK SLIK SLICK 0.92 WORK SLIK SLICK 0.25 WORK SLIK SLICK 0.17 WORK SLIK SLICK 0.75 WORK SLIK SLICK 0.25 WORK SLIK SLICK 1.08 WORK SLIK SLICK 1.25 WORK SLIK SLICK 0.17 SAFETY MTG_ SLICK 0.58 RURD_ SLIK SLICK 1.00 SAFETY MTG_ SLICK 0.50 RURD_ SLIK SLICK 0.08 RURD_ SLIK SLICK 0.92 WORK SLIK SLICK 0.83 WORK SLIK SLICK 0.17 WORK SLIK SLICK 0.83 WORK SLIK SLICK 0.08 WORK SLIK SLICK 0.08 WORK SLIK SLICK 0.17 WORK SLIK SLICK Page2of3~ Spud Date: 4/27/2006 Start: 11/28/2006 End: Rig Release: Group: Rig Number: 1 Description of Operations RU on well. PU new pressure test sub to top of tree. PT to 1500 psig with tools hanging in lubricator. MU 1 3/4" TS with a 2.5" lib. PT good open well to RIHI WHP= 900 psig RIH with LIB to 8222' KBD. Set down a couple of times POOH with lib. OOH with LIB, marks on sides of the LIB indicate flapper. MU 2.25" DD bailer. PU and go to luibricator. MU PT line to pump in sub. Pressure up on lubricator to test. Test good. Open well to R1H. Sat down at 8223' KBD. Work tools for 10 minutes, fell though. RIH to 8429' KBD. Sat down. Work tool string. Work bailer down to 8432' KBD. Tool stuck, work spangs tool stuck. Pu set off jars several times. Bailer came free. POOH with bailer. OOH iwth bailer. Check bailer, bailer face beat up around end. 1/2 full of sand and some water. Held PJSM to RD wire line unit. RD wire line, clean up around area, Pollard left lease. Thaw out all equipment. Held PJSM and discussed procedure. MU new pressure unit to pressure test the lubricator. Uptain work permit RU on well. PU new pressure test sub to top of tree. PT to 1500 psig with tools hanging in lubricator. MU 1 3/4" TS with a 2.25" drive down bailer. PT good, open well to RIH, WHP= 900 psig RIH with LIB to 8221' KBD. Work balier down to 8222' KBD, POOH with bailer. OOH with DD. bailer half full of sand, some water. (beach sand with some coal and flex sand). PU and go to well. MU PT lines lubricator to 1500 psig, good test. Open well, RIH. RIH with LIB to 8221' KBD. Work balier down to 8222' KBD, POOH with bailer. OOH iwth bailer. Check bailer, 1/2 full of sand and some water. PU and go to well with lubricator. MU PT lines lubricator to 1500 psig, good test. Open well, RIH. Work bailer, POOH, repeat a total of 5 bailer runs. Bail down to 8425' KBD. RIH with LIB to 8221' KBD. Work balier down to 8222' KBD, POOH with bailer. Held pre rig down safety meeting, pror to rigging down. RD wire line, clean up around area, Pollard left lease. Held PJSM and discussed procedure. MU new pressure unit to pressure test the lubricator. Uptain work permit, RU. PU tool string, lubricator, MU 2.25" DD bailer on 1.75" tool sting. PT lubricator, good test, Open well. RIH, WHP= 900 psig RIH with DD bailer to 8225' KBD. Work balier down to 8225' KBD, POOH with bailer. OOH with DD. bailer, half full of sand, some water. PU and go to well. MU PT lines lubricator to 1500 psig, good test. Open well, RIH. RIH with DD bailer to 8225' KBD. Work bailer down to 8225' KBD, POOH with bailer. OOH with bailer. Check bailer, bailer empty. MU 2.25" swedge, Go to well. PT lubricator to 1500 psig, good test. Open well, RIH. Work swedge down to same depth POOH. OOH with swedge, Marathon Oil Company Q:perations Summary Report Printed: 3/13/2007 11:38:07 AM Marathon Oil Company Page 3 of 3 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: MAINTENANCE/REPAIR Start: 11/28/2006 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Phase Description of Operations Code 12/17/2006 11:30 - 11:40 0.17 WORK SLIK SLICK swedge had marks on bottom of swedge. 11:40 - 12:20 0.67 WORK SLIK SLICK MU 2.25" DD bailer, go to well, PT to 1500 psig, good test. Open well. 12:20 - 16:00 3.67 WORK SLIK SLICK RIH with bailer to 8425' KbD, work tools, POOH with bailer, check bailer, 1/2 ful of sand water. Repeat four more runs same results. 16:00 - 17:00 1.00 WORK SLIK SLICK MU bailer RIH with DD, sat down and work tools at 8425' KBD. PU hole lost all tool action, POOH. 17:00 - 17:30 0.50 WORK SLIK SLICK Tool string lost in hole: !.75" Rs, KJ, 5' Stem, 3' Stem, KJ, OJ, SJ, XO, 4' DD bailer. less than 10' estimate on wire on top of tools. 17:30 - 17:45 0.25 WORK SLIK SLICK OOH with wire, replace packing in lubricator, MU fishing string and retie rope socket to be ready to go to well to fish tool string. 17:45 - 17:50 0.08 SAFETY MTG_ SLICK Held pre rig down safety meeting, pror to rigging down. 17:50 - 18:00 0.17 RURD_ SLIK SLICK RD wire line, clean up around area, Pollard left lease. 12/18/2006 07:00 - 08:00 1.00 SAFETY MTG_ SLICK Held PJSM and discussed tool recovery procedure. Uptain work permit. 08:00 - 08:30 0.50 RURD SLIK SLICK PU additional lubricator to handle tool string plus the fish. MU 1.75" tool string with 5' stem, 2.25" LIB. PT lubricator to 1500 psig, good test 08:30 - 09:20 0.83 WORK SLIK SLICK RIH with LIB. Tagged fish at 8411' KBD, PU tagged again. POOH with LIB. 09:20 - 09:30 0.17 WORK SLIK SLICK OOH with LIB, indicates small piece of wire with fishing neck dimple. Decide to run a 2.25" JDC. MU to tool string. RIH with JDC. 09:30 - 11:00 1.50 WORK SLIK SLICK Tagged fish at 8411' KBD, work tool string, PU fish latched. POOH with fish. 11:00 - 11:40 0,67 RURD_ SLIK SLICK OOH with fish, lay down tool string, removed extra lubricator. MU same tool string as before. PT lubricator, good test, Open well. 11:40 - 12:30 0.83 WORK SLIK SLICK RIH with DD bailer to 8440' KBD. Work balier down to 8440' KBD, POOH with bailer. 12:30 - 12:40 0.17 WORK SLIK SLICK OOH with DD. bailer, half full of sand, some water. PU and go to well. 12:40 - 12:45 0.08 WORK SLIK SLICK MU lubricator to 1500 psig, good test. Open well, RIH. 12:45 - 13:30 0.75 WORK SLIK SLICK RIH with DD bailer to 8230' KBD, (lost 10') Work balier down to 8230' KBD, POOH with bailer. 13:30 - 14:40 1.17 WORK SLIK SLICK OOH with DD. bailer, half full of sand, some water. PU and go to well. 14:40 - 14:45 0.08 WORK SLIK SLICK PT lubricator to 1500 psig, good test. Open well, RIH. 14:45 - 14:55 0.17 WORK SLIK SLICK RIH with bailer to 8433' KBD, work tools, POOH with bailer, check bailer, 1/2 ful of sand water. 14:55 - 15:10 0.25 WORK SLIK SLICK MU 2.25" DD bailer, go to well, PT to 1500 psig, good test. Open well. 15:10 - 16:00 0.83 WORK SLIK SLICK RIH with bailer to 8433' KBD, work tools, POOH with bailer, check bailer, 1/2 ful of sand water. 16:00 - 16:10 0.17 WORK SLIK SLICK MU 2.25" bailer, PT to 1300 psig, RIH with DD, sat down and work tools at 8433' KBD. POOH. 16:10 - 17:10 1.00 SAFETY MTG_ SLICK Held "let down safety meeting", pror to rigging down. 17:10 - 18:00 0.83 RURD SLIK SLICK RD wire line, clean up around area, Pollard left lease. Printed: 3/13/2007 11:38:07 AM • Marathon OiI Company Page 1 of 1 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Event Name: MAINTENANCE/REPAIR Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date. From-To Hours Code .Code .Phase 1/13/2007 109:00 - 17:00 I 8.001 RURD I COIL I MIRU 1/17/2007 07:00 - 09:30 2.50 RURD_ COIL CTBG 09:30 - 10:30 1.00 SAFETY MTG_ CTBG 10:30 - 11:00 0.50 RURD_ COIL CTBG 11:00 - 11:45 0.75 TEST BOPE CTBG 11:45 - 12:15 0.50 RURD_ COIL CTBG 12:15 - 12:45 0.50 RURD COIL CTBG 12:45 - 15:00 2.25 RUNPU COIL CTBG 15:00 - 15:50 0.83 CLNOU CSG_ CTBG 15:50 - 17:10 1.33 CLNOU CSG CTBG 17:10 - 18:00 0.83 RUNPU COIL CTBG 18:00 - 18:55 0.92 RUNPU COIL CTBG 18:55 - 20:00 1.08 RURD COIL CTBG 1/24/2007 07:00 - 08:00 1.00 RURD_ ELEC WRLN 08:00 - 10:00 2.00 RURD_ ELEC WRLN 10:00 - 10:55 0.92 RURD_ ELEC WRLN 10:55 - 11:25 0.50 TEST_ BOPE WRLN 11:25 - 12:25 1.00 RUNPU ELEC WRLN 12:25 - 13:13 0.80 RUNPU ELEC WRLN 13:13 - 13:28 0.25 RUNPU ELEC WRLN 13:28 - 13:40 0.20 TEST_ BOPE WRLN 13:40 - 14:40 1.00 RUNPU ELEC WRLN 14:40 - 15:24 0.73 RUNPU ELEC WRLN 15:24 - 16:15 0.85 RUNPU ELEC WRLN 16:15 - 16:38 0.38 RUNPU ELEC WRLN 16:38 - 17:00 0.37 RUNPU ELEC WRLN 17:00 - 17:15 0.25 RUNPU ELEC WRLN 17:15 - 17:30 0.25 RUNPU ELEC WRLN 17:30 - 18:15 0.75 RUNPU ELEC WRLN 18:15 - 19:00 0.75 RURD_ ELEC WRLN 19:00 - 19:30 0.50 RURD ELEC WRLN Spud Date: 4/27/2006 Start: 1/15/2007 End: 1/16/2007 Rig Release: Group: Rig Number: 1 Description of Operations MIRU coil tubing unit, spotted equipment, crane, pulled well house and spotted tanks. Placed liner for Methanol tank, supply and flow back tank. MU ground lines and BOP's. Arrive. Issue permit, start equipment. Hold safety meeting. Finish Rigup. Test BOP 200 / 4500 psi with test bar. Good test on Rams, Blinds, lines, and valves. Injector to tree. SIWHP = 1500 psi. PT stripper to 1500 psi. Open well to gas buster and cool down N2. Well started making water at 1050 psi WHP. Start N2 to warm up CT and RIH pumping N2 at 500. Tag at 8484' and POH to 8400'. Start KCI at 1 BPM w/ N2 at 500 to load CT. Well making water, gas, and N2 at 1500 - 1800 psi to gas buster. Well made 59 bbls water before fluid was pumped to the nozzle. Clean out bridge from 8490' to 8500'. Clean out solid fill from 8800' - 9150'. POH while pumping water and N2 to circulate out solids. After returns clean pump 7 Bbls McOH to freeze protect and SD fluid. SD N2 at 5000'. Well flowing on own at 1600 psi to gas buster. Turn well to production system and vent N2. OOH. RD CT. Turn well into production HP system. Well making 4MM at 1250 psi and slowly climbing. Leave location. Arrive @ KGF office to sign in and obtain work permit Arrive @ CLU pad, Hold PJSM. Wait for location to be plowed RU Wireline Stab lubricator and 2.45" GR and pressure test to 1000 psig start in hole w/ spangs, jars, and 2.45" GR Tagged bottom @ 8608' KB in module 2, POOH OOH, switch to PLT string Stab lubricator and PLT string and pressure test to 1000 psig Open well (4MMCFD and 730 psig) start in hole Start down pass at 30 ft/min end down pass, start 30 fUmin up pass start down pass at 60 fUmin start up pass 60 ft/min start down pass 90 ft/min start up pass 90 fUmin POOH OOH Rig down Leave location and sign out Printed: 3/13/2007 11:39:37 AM Re: CLU I 1 Request for Verbal to Proceed w~Perf Add Changes Subject: Re: CLU 11 Request for Verbal to Proceed with Perf Add Changes From: Thomas Maunder <toin_maunder@admin.state.ak.us> Date: Thu, 29 Mar 2007 11:51:39 -0800 To: "D~~n~~ti~att Jr, Dennis l~'L" ~'~I~ii~ni~~~<~n c~n~arathonoil.com-= Dennis, I have looked at the sundry for this work and by copy of this message you have "verbal" approval to proceed. Call or message with any questions. Tom Maunder, PE AOGCC Donovan Jr, Dennis M. wrote, On 3/29/2007 10:46 AM: Tom, As per our discussion, this is what we intend to complete on CLU 11. I would like to request verbal approval to complete the program as follows with the following module/per adds changes. Add perforations: • A. Module 6 - 7929' - 7939' Escape (10') and 7939' - 7946' on W/L (7' within this zone) = Total of 17' • B. Module 7 - is not going to be fired but we intend to add 7882' - 7892' (10' on W/L) =Total of 10' -module 7 is in a risky position with respect to water • C. Module 10 - 7373' - 7383' Escape (10') and 7383' - 7400' (17' on W/L) =Total of 27' • D. Module 11 - is not going to be fired Original intentions: • Module 6 - 7929'-7939' (10') -Yellow Control Line 2-7 • Module 7 - 7868'-7878' (10') -Yellow Control Line 2-7 • Module 10 - 7373'-7383' (10') -Red Control Line 8-11 • Module 11 - 6593'-6603' (10') -Red Control Line 8-11 Thank You, Dennis 1 of 2 3/29/2007 11:51 AM Re: RE: CLU 11(206-058) Request for Verba~Proceed with Perf... Subject: Re: RE: CLU 11(206-058) Request for Verbal to Proceed with Perf Add Changes From: Thomas Maunder <tom_maunder~admin.state.ak.us> Date: Mon, 02 Apr 2007 13:28:25 -0800 "I'o: "~'~llsll, Kcn" ~kd~~~al~h'~r'maralhon~~iLc~~m.~:~ CC: "Mullin, 11ick~~" ~~mmullin~«marathon~~iLcom_ "[)~~novan Jr, lhnnis ~1." ~dd~m~~<<in~~i mZrathc~nc~il.c~~iti=. "Ih~l~. L~ndc~n" ~~cibcl~"u;marath~~ni~il.cc~m%, "C'iss~fl, «'aync f; ~~ °~-~~ecissell(~i:marath~moil.conti> Ken, et al, There should not be a need to send any addition sundry. The additional work is more of what was originally planned. By copy of this email, you have "verbal" approval to proceed. All of the work should be covered in the 404 report of sundry operations. Call or message with any questions. Tom Maunder, PE AOGCC Walsh, Ken wrote, On 4/2/2007 12:42 PM: Tom, Thank you for forwarding the email thread below regarding your discussions with Dennis Donovan regarding your verbal approval for CLU #11 work. Per the conversation that you and I had on the phone today, I am requesting that the AOGCC provide verbal approval to cement squeeze the open perforations in Modules 8, 9, and 10 in this well. The proposed squeeze is necessary to shut off excessive produced water influx which has resulted in multiple well cleanouts in the recent past to remove produced water and formation sand. The well is currently producing 3.9 MMscfd, 200 BWPD, at 1050 psig FTP. I have included a wellbore diagram for your review. This past weekend, Marathon ran a PLT over all the open perforations in this well from 7373' to 9094' MD. The PLT interpretation indicates that the majority of the water production is coming from the perfs at Module 8, 7686-7696' MD, which had been hydraulically fracture stimulated on 9/28/06. To accomplish this water shutoff, Marathon proposes to: 1. Set a composite bridge plug about 25' below the bottom Module 8 perforation at 7696' MD, 2. Spot a balanced cement plug with coiled tubing from the top of the composite BP at about 7720' MD to about 500' above the Module #10 top perforation at 7373' MD, 3. Achieve a 1000-1200 psig squeeze pressure. 4. RIH and jet out any excess cement to 100' above the Module #10 top perf , 5. Hold squeeze pressure while WOC, 6. Drill out cement to below the bottom perf at 7696' MD, 7. Test cement squeeze to about 1000 psig with a 6% KCL water head. 8. If no test, resqueeze with cement, contaminating cement in wellbore with Biozan after node development, or If good test, drill out composite BP with KCL water and nitrogen, push BP to bottom and jet well in with nitrogen. 9. Install a 1-3/4' coiled tubing velocity string. For clarification, Marathon is proposing to cement squeeze Module #9 and #10 perfs with the Module #8 perfs because the Module #9 and #10 perfs do not produce commercial quantities of gas at this time (based on recent PLT interpretation). Also, the chance of getting a good cement squeeze on the first attempt is better than if a cement retainer was set 1 of 3 4/2/2007 1:29 PM Re: RE: CLU 11(206-058) Request for VerbaProceed with Perf... above the Module #8 perfs. Should the AOGCC grant verbal permission to proceed with the aforementioned cement squeeze, Marathon would amend its Form 10-403 application to include the cement work and the other changes verbally approved and outlined in the emails below in one submission. Marathon would like to start work to set the composite BP this afternoon and cement squeeze the intervals tomorrow, April 3. We have coiled tubing equipment rigged up on the well and wireline equipment standing by after the work performed over this past weekend. Best Regards, Ken Ken D. Walsh Senior Production Engineer Marathon Oil Company-Alaska Asset Team 907-283-1311 (office) 907-394-3060 (cell) -----Original Message----- From: Thomas Maunder [mailto:tom maunde7-:e:,admin.state.ak.us] Sent: Monday, April 02, 2007 11:24 AM To: Walsh, Ken Subject: [Fwd: RE: CLU 11 Request for Verbal to Proceed with Perf Add Changes] -------- Original Message -------- Subject: RE: CLU 11 Request for Verbal to Proceed with Perf Add Changes Date: Thu, 29 Mar 2007 16:42:14 -0500 From: Donovan Jr, Dennis M. <ddonovanc~marathcnoil,co-~;> To: Thomas Maunder <tom maur_der~~~admin.state.ak.us? Tom, Thanks a lot for looking at this at such short notice Dennis Dennis M. Donovan Jr. Production Engineer I 907-283-1333 Office 907-398-1362 Cell ------------------------------------------------------------------------ *From:* Thomas Maunder [mailto:tom maunder~?admin.state.ak..us] *Sent:* Thursday, March 29, 2007 11:52 AM *To:* Donovan Jr, Dennis M. *Subject:* Re: CLU 11 Request for Verbal to Proceed with Perf Add Changes ', Dennis, I have looked at the sundry for this work and by copy of this message you have "verbal" approval to proceed. Call or message with any questions. Tom Maunder, PE AOGCC Donovan Jr, Dennis M. wrote, On 3/29/2007 10:46 AM: 2 of 3 4/2/2007 1:29 PM Re: RE: CLU 11(206-058) Request for Verba~Proceed with Perf... Tom, As per our discussion, this is what we intend to complete on CLU 11. I would like to request verbal approval to complete the program as follows with the following module/per adds changes. Add perforations: * A. Module 6 - 7929' - 7939' Escape (10') and 7939' - 7946' on W/L (7' within this zone) = Total of 17' * B. Module 7 - is not going to be fired but we intend. to add 7882' - 7892' (10' on W/L) = Total of 10' - module 7 is in a risky position with respect to water * C. Module 10 - 7373' - 7383' Escape (10') and 7383' - 7400' (17' on W/L) = Total of 27' * D. Module 11 - is not going to be fired Original intentions: * Module 6 - 7929'-7939' (10') - Yellow Control Line 2-7 * Module 7 - 7868'-7878' (10') - Yellow Control Line 2-7 * Module 10 - 7373'-7383' (10') - Red Control Line 8-11 * Module 11 - 6593'-6603' (10') - Red Control Line 8-11 Thank You, Dennis Dennis M. Donovan Jr. Production Engineer I 907-283-1333 Office 907-398-1362 Cell 3 of 3 4/2/2007 1:29 PM r~ LJ API:50-133-20559-00 RT-GL: 21.00' RT-THF: 21.70' 2491' FSL, 2291' FWL, Sec. 4, T5N, R11W, S.M Tree cxn = 4-3/4" Otis TOC (est.) - 500' above 9-5/8" shoe Ceramic flapper valves below each iodule as follows: Module 1 - NA Module 2 - 8640' (Broken CT 9/28/2006 Module 3 - 8530' Module 4 - 8418' (Broken CT 9/28!2006 Module 5 - 8240' (Broken CT 9!28/2006 Module 6 - 7960' Module 7 - 7900' Module 8 - 7715' (Broken CT 9/28/2006 Module 9 - 7498' Module 10 -7399' Module 11 -6618' CLU-11 n~wRwTMOM Drive Pipe: 20", 131 ppf, X-52, to 136' RKB Surface Casing: 13-3/8", 68 ppf, L-80, BTC @ 1602' RKB, Cmt w/ 228 bbls / 516 sx. of Type 1 at 12.0 ppg. Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 5595' RKB. Cmt w/ 35.6 bbl (95 sx) of class G lead @ 12.5 ppg and 49 bbls (237 sx) Class G tail @ 15.8 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9284' RKB. Cmt w/ 1550 sx (325 bbls) of class G at 15.8 ppg 11 Excape modules placed Green control line fired module 1 Yellow control line fired modules 2 thru 7 Red contol line fired modules 8 thru 11 Ceramic flapper valves below each module xceot for module 1 Module 1 - 9084' - 9094' (Frac'd 9/28/06) Module 2 - 8607' - 8617' (Frac'd 9/28/06) Module 3 -8498' - 8508' (Frac'd 9/28/06) Module 4 - 8383' - 8393' (Frac'd 9/28/06) Module 5 - 8205' - 8215' (Frac'd 9/28/06) Perfed 4/1 /07 7939' - 7946' Module 6 - 7929' - 7939' (Perfed 4/1 /07) Module 7 - 7868' - 7878' Not Shot Module 8 - 7686' - 7696' (Frac'd 9/28/06) Module 9 - 7472' - 7482' (Frac'd 9/28/06) Proposed Perf 7383' - 7400' Module 10 - 7373' - 7383' (3!28107) Module 11 - 6593' - 6603' Not Shot Well Name 8 Number: CLU - 11 Lease: Cannery Loop Gas Field County or Parish: Kenai State/Prov. Alaska Country: USA Perforations (MD) See Above (TVD) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completi on Fluid: 6% KCL Dated Completed: 9/28/2006 Prepared By: J. R. Thompson Last Revison Date: 10/11/2006 TD - 9305' PBTD - 9247' • M Marathon MARATHQN Oil Company October 16, 2006 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Reference: Completion Report 10-407 for permit 206-058 Field: Cannery Loop Gas Field /Beluga Pool Well: CLU No. 11 (Pad 3) Dear Mr. Aubert, • Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 Alaska Oil ~ O~~ 1~~~~ ,;, ...:~~ . r.:....<~._ finch~ra~a Enclosed please find the Well Completion Report with associated attachments for Cannery Loop Unit Well No. 11. This well has been completed cased hole with a 3.5" Excape monobore production string to surface. Should you require further information, I can be reached at 713-232-9347 or 713-296- 2730, or by a-mail at JRThompson@MarathonOil.com. Sincerely, James R. Thompson Sr. Completions Engineer Enclosures: AOGCC Form 10-407 Well bore Diagram Directional Survey Well Operations Summary Report J RT/smw CLU 11 Cover Letter AOGCC 10-407.doc STATE OF ALASKA ~~~~~~~~ ALAS IL AND GAS CONSERVATION COMMIS N WELL COMPLETION OR RECOMPLETION REPORT~~VD©~~~ 206 1a. Well Status: Oil^ GasO Plugged Abandoned^ Suspended^ WAG^ 2oAAC2s.1os 2oAACZa11o GINJ^ WINJ^ WDSPL^ No. of Completions Other 1b. Well Ca 8=s ~f1fl5. Development ^~ ~;~c~$Q~y Service ^ Stratigraphic est^ 2. Operator Name: Marathon Oil Company 5. Date Comp., Susp., or Aband.: 9/28/2006 12. Permit to Drill Number: 206-058 3. Address: P. O. Box 3128, Houston, TX 77253 6. Date Spudded: April 28, 2006 13. API Number: 50-133-20559 4a. Location of Well (Governmental Section): Surface; 2491' FSL, 2291' FWL, Sec 4, T5N, R11W, S.M. 7. Date TD Reached: May 11, 2006 14. Well Name and Number: Cannery Loop Unit No. 11 (Pad 3) Top of Productive Horizon: 263' FSL, 616' FEL, Sec 5, T5N, R11 W, S.M. 8. KB Elevation (ft): 56 FT. (21' AGL) 15. Field/Pool(s): Cannery Loop Unit Total Depth: 147' FSL, 780' FEL, Sec 5, T5N, R11 W, S.M. 9. Plug Back Depth(MD+TVD): 9247' MD / 7856.51' TVD Beluga Pool 4b. Location of Well (State Base Plane Coordinates): Surface: x- 280,663.583 y- 2,396,065.617 Zone- 4 10. Total Depth (MD +TVD): 9305' MD / 7914.50'TVD 16. Property Designation: ADL - 324602 TPI: x- y- Zone- 4 Total Depth: x- y- Zone- 4 11. Depth Where SSSV Set: N/A 17. Land Use Permit: 18. Directional Survey: Yes Q No ^ 19. Water Depth, if Offshore: N/A feet MSL 20. Thickness of Permafrost: NA 21. Logs Run: SP/GR-IEL-Density/Neutron-Sonic-Single Arm Caliper. MFTs. FMI. 22. CASING, LINER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT TOP BOTTOM TOP BOTTOM PULLED 20" 131 X-52 0 136' 0 136' Driven NA NA 13 3/8" 68 L-80 0 1602' 0 1489' 16" 516 sks Type 1 cement NA 9 5/8" 40 L-80 0 5595' 0 4355' 12 1 /4" 95 sks. Class G lead 237 sks Class G tail Nq 3 1/2" 9.3 L-80 0 9284' 0 7893' 8 1/2" 1550 sks Class G 85,000 23. Perforations open to Production (MD +TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) MD RKB TVD (RKB) 3 v2" 9284' NA Module 1: 9084-9094 7693-7703 Module 2: 8607-8617 7217-7227 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Module 3: 8498-8508 7107-7117 DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Module 4: 8383-8393 6993-7003 Module 1: 9084-9094 BJ LigMning V 1800 wtr based system; 14178 Ibs prop Module 5: 8205-8215 6815-6825 Module 2: 8607-8617 BJ Lightning V 1800 wtr based system; 28001 Ibs prop Interval 6: 7932-7945 6542-6555 Module 3: 8498-8508 BJ Lightning V 1800 wtr based system; 31000 Ibs prop Interval 7: 7875-7887 6485-6497 Module 4: 8383-8393 BJ Lightning V 1600 wtr based system; 26136 Ibs prop Module 8: 7686-7696 6296-6306 Module 5: 8205-8215 BJ LigMning V 1600 wtr based system; 18750 Ibs prop Module 9: 7472-7482 6082-6092 Interval 6: 7932-7945 No frac treatment / To be perforated later Continued on back Continued on back Prop used-20/40 Ottawa & 12/20 flex sand 26. PRODUCTION TEST Date First Production: September 28, 2006 Method of Operation (Flowing, gas lift, etc.): FlOwln Date of Test: 10/10/2006 Hours Tested: 24 Production for Test Period Oil-Bbl: NA Gas-MCF: 4251 Water-Bbl: 256 Choke Size: 26/64 Gas-Oil Ratio: NA Flow Tubing Press. 1115 Casing Press: 0 Calculated 24-Hour Rate ~- Oil-Bbl: NA Gas-MCF: 4251 Water-Bbl: 256 Oil Gravity -API (corr): NA 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (att ces a Submit core chips; if none, state "none". _T~ ' . s~ ~ None ~~ t 1~ VfR f rm 2003 CONTINUED ON REVERSE CLU-11_AOGCC 10-407 Cmpl (4).xls 10/16/2006 11:35 AM ssinn s C7 8. GEOLOGIC MARKERS 29. FORMATION TESTS NAME MD TVD Include and briefly summariz ,results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". Zone Top MD Top TVD Pressure Upper Beluga 6547 5179 U Beluga 6593 5222 2000 Tyonek 9191 7801 M Beluga 7375 5985 2637 M Beluga 7474 6084 2613 M Beluga 7691 6301 2790 M Beluga 7876 6486 2483 M Beluga 7936 6546 2230 L Beluga 8216 6826 3162 L Beluga 8395 7005 3265 L Beluga 8506 7116 3604 L Beluga 8615 7225 3651 L Beluga 9096 7706 3927 30. List of Attachments: Directional Survey, Wellbore Diagram, Well Operations Summary 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Printed Name: James R. Thompson Title: Senior Production Engineer Signature: Phone: 713-296-2730 Date: October 16, 2006 ~/ ~ ~ INSTRUCTIONS General is form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for / njection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain), Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Interval 7: 7875-7887 No frac treatment / To be pertorated later Module 8: 7686-7696 BJ Lightning V 1600 water based system; 28400 Ibs prop Module 9: 7472-7482 BJ Lightning V 1600 water based system; 31000 Ibs prop Interval 10: 7372-7400 No frac treatment / To be perforated later Interval 11: 6585-6603 No frac treatment / To be pertorated later 23. Perforations open to Production (MD +TVD of Top and Bottom Interval, Size and Number; if none, state "none"): MD RKB TVD RKB Interval 10: 7372-7400 5982-6010 Interval 11: 6585-6603 5214-5231 CLU-11_AOGCC 10-407 Cmpl (4).xls 10/16/2006 11:37 AM I LJ API: 50-133-20559-00 RT-GL: 21.00' RT-TH F: 21.70' 2491' FSL, 2291' FWL, Sec. 4, TSN, R11W, S.M. Tree cxn =4-3/4" Otis ~ TOC (est.) - 500' above 9-5/8" shoe - Ceramic flapper valves below each module as follows: Module 1 - NA Module 2 - 8640' (Broken CT 9/28/2006) Module 3 - 8530' Module 4 - 8418' (Broken CT 9/28/2006) Module 5 - 8240' (Broken CT 9/28/2006) Module 6 - 7960' Module 7 - 7900' Module 8 - 7715' (Broken CT 9/28/2006) Module 9 - 7498' Module 10 -7399' Module 11 -6618' CLU-11 M ~wiewn~oN Drive Pioe: 20", 131 ppf, X-52, to 136' RKB Surtace Casing: 13-3/8", 68 ppf, L-80, BTC @ 1602' RKB, Cmt w/ 228 bbls / 516 sx. of Type 1 at 12.0 ppg. Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 5595' RKB. Cmt w/ 35.6 bbl (95 sx) of class G lead @ 12.5 ppg and 49 bbls (237 sx) Class G tail @ 15.8 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9284' RKB. Cmt w/ 1550 sx (325 bbls) of class G at 15.8 ppg 11 Excape modules placed Green control line fired module 1 Yellow control line fired modules 2 thru 7 Red contol line fired modules 8 thru 11 Ceramic flapper valves below each module except for iodule 1 Module 1 - 9084' - 9094' (Frac'd 9/28/06) Module 2 - 8607' - 8617' (Frac'd 9/28/06) Module 3 - 8498' - 8508' (Frac'd 9/28/06) Module 4 - 8383' - 8393' (Frac'd 9/28/06) Module 5 - 8205' - 8215' (Frac'd 9/28/06) Module 6 - 7929' - 7939' (No frac /Not Completed) Interval 6 - 7932' - 7945' (Perfd a-line later) Module 7 - 7868' - 7878' (No Frac /Not Completed) Interval 7 - 7875' - 7887' (Perfd a-line later) Module 8 - 7686' - 7696' (Frac'd 9/28/06) Module 9 - 7472' - 7482' (Frac'd 9/28/06) Module 10 - 7373' - 7383' (No Frac /Cot Completed) Interval 10 - 7372' - 7400' (Perfd a-line later) Module 11 - 6593' - 6603' (No Frac /Not Completed) Interval 11 - 6585' - 6603' (Perfd a-line later) Well Name & Number: CLU - 11 Lease: Cannery Loop Gas Field County or Parish: Kenai State/Prov. Alaska Country: USA Perforations (MD) See Above (TVD) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completion Fluid: 6% KCL Dated Completed: 9/28/2006 Prepared By: J. R. Thompson Last Revison Date: 10/16/2006 TD - 9305' PBTD - 9247' MARATHON Actual Wellpath Report Wellpath: MWD <0-9305> Page 1 of 8 ~~ BAKER 1~IYt~MES INTEQ Operator .. , ~ MARATHON Oil Company Slot 'slot #CLU-11 Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Facility Pad # 3 / 4 Projection System NAD27 / TM Alaska State Plane, Zone 4 (5004), US feet Software System We1lArchitectTM 1.1 North Reference True User Suthstud Scale 0.999955 Report Generated 05/16/06 at 11:37:34 Wellbore last revised 05/16/06 Database/Source file WA-Anchorage/CLU-ll.xml '• ~ ~ ~ Local coordinates Grid coordinates Geographic coordinates North [feet] East [feet] Easting [US feet] Northing [US feet] Latitude [°] Longitude [°] Slot Location 2493.43 2270.35 280663.58 2396065.62 60 33 10.625N 151 13 06.998W Facility Reference Pt 278347.08 2393615.22 60 32 46.072N 151 13 52.401 W Field Reference Pt 272978.90 2388436.21 60 31 54.076N 151 15 37.735W J MARATHON Actual Wellpath Report Wellpath: MWD <0-9305> Page 2 of 8 rr~~~ BAKER NVGNE~i INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot slot #CLU-11 Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Facility Pad # 3 / 4 ELLPATH DATA (132 sta tions) MD [feet] Inclination (°] Azimuth ]°j TVD [feet) Vert Sect [feet) North [feet] East [feet] Grid East [us survey feet] Grid North [us survey feet) DLS [°/100ft] Path Comment 0.00 0.000 0.000 0.00 0.00 0.00 0.00 280663.58 2396065.62 0.00 194.00 0.100 272.300 194.00 0.13 0.01 -0.17 280663.41 2396065.63 0.05 322.00 0.300 243.300 322.00 0.55 -0.14 -0.58 280663.00 2396065.49 0.17 439.00 0.400 273.700 439.00 1.15 -0.25 -1.26 280662.31 2396065.39 0.18 499.00 1.000 243.100 498.99 1.83 -0.47 -1.94 280661.63 2396065.18 1.14 560.00 1.200 237.300 559.98 2.99 -1.06 -2.95 280660.61 2396064.62 0.37 620.00 2.600 222.400 619.95 4.95 -2.40 -4.40 280659.14 2396063.30 2.46 680.00 5.500 225.300 679.79 9.14 -5.43 -7.36 280656.12 2396060.33 4.84 740.00 8.000 _ ___ 230.500 739.37 16.17 -10.11 -12.62 280650.77 2396055.74 4.29 805.00 11.400 236.200 803.43 27.11 -16.56 -21.46 280641.82 2396049.4b 5.43 862.00 15.900 236.500 858.81 40.52 -24.01 -32.65 280630.49 2396042.22 7.90 929.00 19.300 235.500 922.66 60.75 -35.35 -49.44 280613.50 2396031.19 5.09 992.00 22.900 234.000 981.43 83.41 -48.46 -67.94 280594.76 2396018.43 5.78 1052.00 ~ 26.900 ~ 233.000 1035.84 108.66 -63.49 -88.23 280574.19 23 96003.77 6.70 ~- _ 111_6 00 28.200 ~ 2_32.000 ___ _ 1092.58 138.26 ~ -81.52 _ -111.71 __ ~-- 280550.38 _ 2395986.19 _ ~~2.16 _ 1182.00 ; 29.600 232.400 _ 1150.36 170.15 -101.06 -136.92 280524.82 2395967.11 2.14 ~ ~~- 1245.00 32.700 232.900 1204.27 202.74 -120.83 -162.82 280498.56 - 2395947.83 - 4.94 1306.00 34.300 232.900 1255.14 236.41 -141.14 -189.67 280471.33 2395928.03 2.62 1371.00 _ 36.000 _ 232.900 _ 130_8.2_8 273.83 -163.71 -219.52 280441.08 2395906.01 2.62 1434.00 37.300 _ 232.800 1358.83 311.43 -186.42 -249.49 280410.69 2395883.86 2.07 1497.00 37.900 233.500 1408.74 349.87 -209.47 -280.25 280379.51 2395861.39 1.17 1538.00 40.600 233.500 1440.49 375.80 -224.90 -301.10 280358.38 2395846.35 6.59 1628.00 39.600 235.000 1509.33 433.75 -258.77 -348.14 280310.72 2395813.35 1.54 1691.00 40.200 235.200 1557.66 474.12 -281.89 -381.29 280277.16 2395790.85 0.97 MARATHON Actual Wellpath Report Wellpath: MWD <0-9305> Page 3 of 8 ri~~ BAKER I~IVGNES INTEQ __ .. __ ,. ~ ~ z __ .._ _ Operator MARATHON Oil Company Slot slot #CLU-I .- ._- .. -. _. - - _-~ ._ __.__~.~_ -- ~ _ `- --- - ~ - - . Area . - r. _ __ ~~ss~ ._ _.~~-- .- _ _ _ -- -- - -__ -- - Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Facility Pad # 3 / 4 LPATH DATA (132 MD Inclination feet) [ °] 1817.00 43.E 1880.00 43.' 1943.00 42.~ 2005.00 42.' 2068 00 44 . .E 2131.00 45.~ 2193.00 44.E 2257.00 42.' 2320.00 _ _ __ 42.i __ 3 3 2 .0 $ 43.: 2443.00 _ 44.' 2507.00 44.~ 2572.00 43.' 2635.00 43.E _ 2695 00 43 . .: 2760.00 43.E 2820.00 44.E 2883.00 45.E 2945.00 44.E 3014 00 44 . . 307 7.0 0 45. _ _ _ _ 3139.00 44.. 3202.00 44. 3265.00 45.. Azimuth TVD Vert Sect North East Grid East Grid North DLS [°] [feet] [feet] [feet] [feet] [us survey feet) [us survey feet) [°/100ft] 234.200 1650.99 558.69 -330.74 -450.39 280207.17 2395743.29 1.86 233.200 1696.54 602.20 -356.51 -485.46 280171.62 2395718.18 1.14 233.800 1742.54 645.24 -382.12 -520.06 280136.55 2395693.22 2.32 232.900 1788.21 687.17 -407.14 -553.70 280102.46 _ 2395668.82 1.09 232 300 1833 80 730 65 433 6 24 88 280067 44 239 643 0 0 . . . - .5 -5 . . 5 . 5 3. 9 231.600 1878.34 775.19 -461.01 -623.32 280031.86 2395616.25 1.49 231.900 1922.18 819.03 -488.16 -657.75 279996.94 2395589.75 1.33 232.900 1968.45 863.24 -515.14 -692.77 279961.42 2395563.42 3.01 231900 2014.98 905.72 -541.05 726.43 279927.29 2395538.14 1.66 00 ; 35 948 36 .9 2 9893 2 2 12 4 ~" 231.9 _ 2061. . -567.37 ~~-9 9 7 . 5 3955 . 5. Y :1.90 , 232.30 0 2104.54 990.00 _-592.94 -792.85 279859.92 2395487.49 2.5 4 232.500 2150.15 1034.90 -620.34 -828.42 279823.85 2395460.76 _ 0.52 233.700 2196.83 1080.13 -647.50 -864.59 279787.19 2395434.27 1.58 234.000 2242.38 1123.64 -673.18 -899.74 279751.57 2395409.25 0.46 0 __ j ~ ~ 234.80 2285.94 1164.89 -697.20 -933.29 279717.59 2395385.86 1.04 234.30 0 2333.13 1209.56 -723.12 -969.70 279680.70 2395360.61 0.70 232.500 2376.22 1251.31 -748.02 -1003.21 279646.73 2395336.34 2.67 232.100 2420.68 1295.93 -775.31 -1038.52 279610.93 2395309.71 1.65 232.30 0 2464.45 1339.85 -802.23 -1073.22 279575.74 2395283.44 1.63 232 2513 79 ~` ~_ _ ~'~ 831 79 1111 ~ 2795' ~ 395254 9 0 .E„ti °„ . u~ - . . . ; : _ 2 .5 ~ _ .~ 231.500 2558.49 1432.47 -859.24 -1146.22 279501.70 2395227.79 2.32 231.800 2602.41 1476.22 -886.40 -1180.54 279466.88 2395201.28 1.97 231.200 2647.34 1520.37 -913.89 -1215.09 279431.83 2395174.44 0.92 230.600 2691.93 1564.86 -941.96 -1249.63 279396.77 2395147.01 1.04 LPATH DATA (132 stations) MD [feet] Inclination [°] Azimuth [°] TVD [feet] Vert Sect [feet] North ]feet] East [feet] Grid East [us survey feet] Grid North [us survey feet] DLS (°/100ft] 3392.00 44.800 230.900 2781.73 1654.62 -998.57 -1319.35 279326.03 2395091.71 0.39 3455.00 45.100 230.900 2826.32 1699.11 -1026.64 -1353.89 279290.97 2395064.28 0.48 3518.00 45.300 230.900 2870.71 1743.79 -1054.83 -1388.58 279255.77 2395036.74 0.32 3581.00 45.400 230.500 2914.98 1788.58 -1083.22 -1423.26 279220.57 2395009.00 0.48 3644.00 45.400 231.300 2959.22 1833.42 -1111.51 -1458.08 279185.24 2394981.36 0.90 3707.00 44.400 231.500 3003.84 1877.88 -1139.25 -1492.83 279149.98 2394954.27 1.60 3769.00 44.400 231.700 3048.14 1921.25 -1166.20 -1526.82 279115.49 2394927.96 0.23 3832.00 44.300 232.400 3093.19 1965.29 -1193.28 -1561.55 279080.27 2394901.52 0.79 3895.00 44.700 232,200 3138.13 2009.44 -1220.28 _ -1596.49 279044.84 2394875.17 0.67 3959.00 _ 45.300 232.200 3183.38 2054.70 ~ -1248.02 -1632.25 279008.58 2394848.10 0.94 4022.00 45.20 0_ ~ _232.600 3227.73 2099.44 -1275.32 -1667.70 278972.63 2394821.47 0.48 4085.00 44.600 232.300 3272.36 2143.91 -1302.42 -1702.95 278936.88 2394795.02 1.01 4148.00 43.500 233.300 3317.64 2187.71 -1328.90 -1737.84 278901.51 2394769.19 - 2.07 4211.00 43.500 233.100 3363.34 2231.07 -1354.88 -1772.56 278866.31 2394743.86 ~ 0.22 4273.00 _ s~ 45.000 232.40 0 3407.75 _ 2274.33 -1381.07 -1807.00 278831.40 ~ 239471832 2.54 4337.00 45.200 231.800 452.92 3 2319.67 -1408.92 -1842.77 278795.12 2394691.14 0.73 4400.00 45.300 232.100 _ 3497.28 2364.40 -1436.50 -1878.00 278759.39 2394664.22 0.37 4463.00 44.900 231.900 3541.75 2409.03 -1463.97 -1913.17 278723.72 2394637.40 0.67 4527.00 44.800 232.600 3587.12 2454.16 -1491.60 -1948.86 278687.53 2394610.44 0.79 ~a~Q.Oa ~ ~ ' 44`~~1 , •}~~t 1)0 3631.94 2498.44 -1518.52 -1984.00 ~~ 2786~~t ~,7 .r~,'- 23~45~; ~ ~~ .. 4653.00 43.700 232.500 3677.18 2542.28 -1545.21 -2018.79 278616.62 2394558.13 1.27 4717.00 43.500 232.100 3723.53 2586.41 -1572.20 -2053.71 278581.20 2394531.80 0.53 4780.00 44.900 231.900 3768.69 2630.33 -1599.24 -2088.32 278546.10 2394505.40 2.23 4843.00 44.200 232.200 3813.59 2674.52 -1626.42 -2123.17 278510.76 2394478.87 1.16 Actual Wellpath Report gpK`~R ~ E Wellpath: MWD <0-9305> NVQNE~ MARATHON Page 4 of 8 INT t,Q MARATHON Actual Wellpath Report Wellpath: MWD <0-9305> Page 5 of 8 ri.~ BAKER F11~GMES INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot slot #CLU-11 Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Facility Pad # 3 / 4 LPATH DATA (132 MD ;feet] Inclination l°1 4970.00 45. 5033.00 45. 5097.00 45. _5160.00 45. 5224.00 45. 5286.00 44. 5348.00 43. 5412.00 42. 5475.00 41.. ~~ $537:00_ _ 41.. 5655.00 39. _~~" 5718.00 37. 5781.00 35. 5844.00 33. 5907.00 _ ~ 32. 5969.00 ~ 30.' 6033.00 30. 6095.00 29. 6159.00 27. 6222.00 25.' 6285.00 24. 6348.00 23. 6411.00 22.. 6474.00 2 L Azimuth [°J TVD [feet] Vert Sect [feet) North [feet) East [feet] Grid East [us survey feet] Grid North (us survey feet) DLS [°/100ftJ 231.700 3903.78 __2763.93 -1681.32 -2193.74 278439.18 2394425.30 1.28 232.200 3948.01 2808.78 -1708.97 -2229.07 278403.35 2394398.31 0.57 231.600 3992.95 2854.35 -1737.09 ~ ~~_-2264.93 278366.98 2394370.86 0.67 231.200 4037.15 2899.24 _ 1765.10 __ -2300.01 278331.38 2394343.51 0.48 231.400 4082.01 2944.87 ~ -1793.64 _ -2335.64 278295.23 2394315.63 0.22 231.500 4125.77 2988.78 -1821.01 ~ -2369.98 278260.39 2394288.90 1.30 230.900 4170.29 3031.91 -1848.04 -2403.61 278226.27 2394262.50 2.05 230.900 4217.10 3075.54 _ _~ -1875.57 -2437.48 278191.90 2394235.61 1.56 231.0_0_0 4263.9_9 ~ - ~ 3117.59 -~- -1902.07_ 2470.16 278158.74 -~~ 2394209.71 1.91 231.100 --- 43:10.60 ` ---- _~~.W __ 315$.4~ .- -1927.77 ?,F~Q1.95 278126.48 ~ 2394184.61 0.19 232.0_0_0 1 r __ 4400.3_3_; 3235.07 i l 975.43 -2561.96 _ 278065.60 2394138.07 1.29 231.900 4449.46 3274.50 -1999.73 -2593.01 278034.11 2394114.35 3.33 232.800 4499.97 3312.15 -2022.73 -2622.81 278003.88 2394091.90 3.29 _234.000 45_5,1.73 _ _ 3348.05 -2044.15 -2651.63 277974.67 2394071.03 3.21 235.20 0_ 4604.48 (, ~ _ 3382.48 ~ -2064.11 ~ ; -2679.71 277946.23 ~ 2394051.59 .2.31 234.200 ~ 4657.23 _ ___3415.04 -2082.93 -2706.30 277919.30 2394033.27 2.72 233.800 4712.31 3447.60 -2102.08 -2732.66 277892.59 2394014.61 0.99 232.600 4766.17 3478.32 -2120.47 -2757.26 277867.66 2393996.67 2.16 232.700 4822.54 _ 3508.61 ~ ~-2138.85 -2781.3 3 _ 277843.24 ~ 2393978.75 2.66 234.400 4878.85 ~ 3536.86 ~-2155.65 _ _ -2804.06 277820.22 ~ 2393962.38 2.67 234.900 4935.90 3563.57 -2171.11 -2825.85 277798.14 ~ 2393947.32 2.56 234.300 4993.54 3588.98 -2185.84 -2846.57 __ - 277777.15 2393932.98 1.63 234.900 5051.64 3613.32 -2199.95 -2866.43 277757.03 2393919.24 1.78 235.200 5110.17 3636.60 -2213.30 -2885.52 277737.70 2393906.25 1.60 MARATHON Actual Wellpath Report Wellpath: MWD <0-9305> Page 6 of 8 ri~~ BAKER N1~161~IES INTEQ . . . ~ ~ Operator MARATHON Oil Company Slot 'slot #Ci,U-11 '' . _ ~ Area --, ~..~ r. ,...._ .w .-_.__ . _ _.. ..._.._m_.__......... . ~._ _.... _ ~ _,~_w.~. -~-..-.u._u.w.. _w.~. --v~~_.,_._._ _....._.. __ _ _~ .___ ....-- _. _. Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Facility Pad # 3 / 4 LPATH DATA (132 stations) MD Inclination Azimuth feet] (°J [°] 6600.00 19.400 235.5 6662.00 18.400 235.1 6725.00 17.000 235.1 6788.00 15.600 234.1 6851 00 14 600 233 4 . . . 6914.00 13.300 233.9 6978.00 11.800 232.6 7041.00 10.400 230.2 71 04.00 9.300 231.0 _ 7167 00 200 8 233 . . .7 7231.00 6.70 0 236.5 7294.00 6.000 235.4 7358.00 5.000 236.1 7422.00 ___ 3.000 244.6 485 00 2 00 2 3 7 . .0 52. 7548.00 ~ 2.300 -257.4 7612.00 1.100 ~ 253.3 7674.00 _ 0.400 _ _ 271.8 7800.00 0.500 275.7 927 00 ~ 7 . ~ ; , , „*~ 8053.00 0.500 256.0 8176.00 0.500 253.2 8302.00 0.300 219.8 8430.00 0.400 211.4 TVD Vert Sect North East Grid East Grid North DLS [feet] [feet] (feet) [feet] [us survey feet] [us survey feet) [°/100fy 5228.38 3680.14 -2238.00 -2921.44 277701.33 2393882.21 1.25 5287.04 3700.20 -2249.44 -2937.95 277684.61 2393871.09 1.63 5347.06 3719.34 -2260.39 -2953.66 277668.71 2393860.42 2.22 5407.52 3737.01 _ -2270.63 -2968.07 277654.10 2393850.45 2.27 5468 35 3753 41 2280 33 2981 31 277640 69 2393841 00 1 61 . . - . . - . . . . 5529.49 3768.60 -2289.34 -2993.54 277628.30 2393832.22 2.07 5591.96 3782.50 -2297.65 -3004.69 277617.00 2393824.12 2.38 5653.78 3794.63 -2305.20 -3014.18 277607.37 2393816.74 2.34 5715.85 3805.40 -2312.05 -3022.50 277598.921 2393810.06 1.76 11 5 8 3814 98 2317 91 3030 08 91 24 2 2393804 33 1 . 77 . . - . - . . 775 . .86 5841.57 3823.27 -2322.67 -3036.87 277584.36 ~ 2393799.70 2.41 5904.19 3830.22 -2326.57 -3042.64 277578.51 2393795.91 1.13 5967.89 3836.35 -2330.03 -3047.71 277573.38 2393792.55 1.57 6031.73_ __ _3840.77 _ ~ -2332.30 _ -3051.54 277569.51 j 2393790.34 3.25 6094 67 _ 3843 42 ~ 2333 34 ~ 3054 08 277566 96 3789 35 x ~ _ 1 67 . . - . - . . ~ . ' 'n ° . 6157.63 3845.60 -2333.95 -3056.36 277564.67 ~ r 2393788.78 0.56 _ 6221.60 3847.34 -2334.41 _ -3058.20 _ _ ____ 277562.82 2393788.36 1.88 6283.59 _3848.07 ~- -2334.57 -3058.99 277562.03 2393788.21 1.18 6409.59 3848.81 -2334.50 -3059.97 _ 277561.04 2393788.30 ~ 0.08 _ 6536 58 - 3849 84 2334 64 _ 3061 16 ~ = r. ~~ 3788 1 0 19 . . - . - . 4 :. ~u. ;.9 . $ _ . 6662.58 3850.96 -2334.97 -3062.32 277558.68 2393787.87 0.08 6785.57 - .. - 3851.96 - - - -2335.26 -3063.36 277557.64 2393787.61 0.02 6911.57 3852.80 -2335.67 -3064.10 277556.90 2393787.21 0.24 7039.57 3853.54 -2336.31 -3064.54 277556.44 2393786.58 0.09 MARATHON Actual Wellpath Report Wellpath: MWD <0-9305> Page 7 of 8 ~i~.~ BAKER 1~11~GNES INTEQ Operator ~ ~ ~`' MARATHON Oil Company Slot slot #CLU-11 Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Facility Pad # 3 / 4 HOLE & CASING SECTIONS Ref Wellbore: CLU-11 Ref Well path: MWD <0-9305> String/Diameter Start MD [feet] End MD [feet] Interval [feet] Start TVD [feet] End TVD [feet] Start N/S [feet] Start E/W [feet] End N/S [feet) End E/W [feet] 16in Open Hole 0.00 1608.00 1608.00 0.00 1493.95 0.00 0.00 -251.41 -337.70 12.25in Open Hole 1608.00 5604.00 3996.00 1493.95 4361.32 -251.41 -337.70 -1955.11 -2536.14 8.Sin Open Hole 5604.00 9305.00 3701.00 4361.32 7914.50 -1955.11 -2536.14 -2343.85 -3070.6 13.375in Casing Surface 0.00 1605.00 1605.00 0.00 1491.64 0.00 0.00 -250.30 -336.13 9.625in Casing Intermediate 0.00 5594.00 5594.00 0.00 4353.71 0.00 0.00 -1951.08 -2531.06 3.Sin Liner 0.00 9305.00 9305.00 0.00 7914.50 0.00 0.00 -2343.85 -3070.63 MARATHQN Actual Wellpath Report Wellpath: MWD <0-9305> Page 8 of 8 r~r~r BAKER 1~~It'~NES INTEQ Operator ~ ~ MARATHON Oil Company Slot slot #CLU-11 Area . Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Facility Pad # 3 / 4 TARGETS' Name MD [feet] TVD [feet] North [feet] East [feet] Grid East [us survey feet] Grid North [us survey feet] Latitude [°] Longitude [°] Shape 5186.00! -2322.08 -3021.24 277600.00 2393800.00 60 32 47.754N 151 14 07.406W circle CLUl l -Upper Beluga - 4/5/06 6581.00 -2322.08 -3021.24 277600.00 2393800.00 60 32 47.754N 151 14 07.406W circle CLUll -Lower Beluga - 4/5/06 ELLPATH CO MPOSITION R ef Wellbore: CLU-11 Ref Wellpath; MWD <0-9305> Start MD [feet] End MD [feet] Tool Type Positional Uncertainty Model Log Name/Comment Wellbore 0.00 1538.00 NaviTrak NaviTrak (Standard) MWD <0-1538> CLU-11 1538.00 5537.00 NaviTrak NaviTrak (Standard) MWD <1628 -5537> CLU-11 5537.00 9305.00 NaviTrak NaviTrak (Standard) MWD <5655 -9305> CLU-11 • • Marathon Oil Company Page 1 of s Operations Summary Report. Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Event Name: ORIGINAL DRILLING Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING .Date From - To Hours Code Code Phase 4/11/2006 06:00 - 12:00 6.00 MOB RIG_ MIRU 12:00 - 18:00 6.00 RURD_ RIG_ MIRU 18:00 - 00:00 6.00 RURD RIG_ MIRU 00:00 - 06:00 6.00 RURD_ RIG_ MIRU 4/12/2006 06:00 - 12:00 6.00 RURD_ RIG_ MIRU 12:00 - 00:00 12.00 RURD RIG MIRU 4/26/2006 08:30 - 15:00 6.50 RURD RIG_ MIRU 15:00 - 16:00 1.00 REPAIR RIG_ MIRU 16:00 - 06:00 14.00 RURD_ RIG_ MIRU 4/27/2006 06:00 - 06:00 24.00 RURD_ RIG_ MIRU Spud Date: 4/27/2006 Start: 4/11/2006 End: 5/15/2006 Rig Release: Group: Rig Number: 1 Description of Operations PJSM: Load Out Carrier 8~ Pump Room. Remove Mast From Carrier. L/O Mud Boat, Boiler, GeneratorAnd Water Tank. Install Goose Neck On Sub. R/D Camp Trailiers & Welding Shop PJSM :Scope Down Sub. Load Out pits & Camp Units. Begin R/U Sub 8~ Scope Up. Set Pits, Mud Boat Generator, Boiler, & Water Tank. Spot Carrier On Mud Boat. Spot Mechanic & Electrical Shops PJSM: Run And Install Elect Service Lines. R/U Pit And Pump Units. Run water Lines. PJSM; Install Trip Tank, R/U P/B De Gasser. R/U Out Riggers. $383,500 of the daily total is Change of Scope relating to waiting on road limits and the City of Kenai permit. PJSM; Set Dog House & Frount Sub Wind Walls. Set Flow Line And Fuel Tank PJSM; R/U W/Crane Set Choke House, Panic Line, Stairs 8~ Conex Landing. Set Cat Walk& Beaver Slide Spot In # 3 Pump, R/U Choke & Flow Lines T/ Gas Buster. Run & H/U Electrical Service Lines. Clean Out Dog & Choke Houses. Complete Steam Line & Boiler R/U. Rig Up 75 % Complete @ 00:00 Hrs Begin Maintenance. 4 12/2006 00:00 Hrs PJSM, make tie on conn's, set mast /pin to carrier. Clean pits, cont RU misc plumbing /elect conn's. Repair /replace pad eye on mast (raising cyl eye), damaged during mast placement. Cont RU, prepare /raise mast, complete pit cleaning. Make various plumbing /elect conn's. Prepare for string up. PJSM (All phase changes), string up blocks, spot cuttings tank, hanson tank, MI trlr, align sub to mast, crane work, adjust desks brakes, spot Epoch unit, begin install torque tube No acc / do time 4/28/2006 06:00 - 20:00 14.00 RURD_ RIG_ MIRU PJSM, all aspects, cont RU Glacier rig #1 on CL-11 20:00 - 21:30 1.50 NUND WLHD SURDRL PJSM, install /test Vetco slip on lock starting hd. Test 500 psi / 15 min, test successful, no re-test. 21:30 - 22:30 1.00 REPAIR RIG_ SURDRL Repair bridge crane 22:30 - 06:00 7.50 NUND BOPE SURDRL PJSM, nipple up diverter system. Note: Glacier rig #1 accepted this date 2000 hrs. 4/29/2006 06:00 - 11:00 5.00 NUND BOPE SURDRL PJSM, cunt nipple up diverter system 11:00 - 12:30 1.50 REPAIR RIG_ SURDRL PJSM, repair "extend" on top drive 12:30 - 13:30 1.00 TEST_ BOPE SURDRL PJSM, test diverter system, time volume test accumulator. All tests successful, no re-test. Witness waived Mr Jim Regg AOGCC 13:30 - 17:00 3.50 CLEAN_ RIG_ SURDRL Clear floor, muffle pipe spinners. 17:00 - 19:00 2.00 PULD_ BHA_ SURDRL PJSM, MU 16" bit /spud BHA 19:00 - 19:30 0.50 DRILL_ ROT_ SURDRL Spud well, tag at 35 ft, drill ahead 16" hole 35 - 40 ft. 19:30 - 21:30 2.00 REPAIR RIG_ SURDRL Troubleshoot /repair #1 mud pump 21:30 - 01:30 4.00 REPAIR RIG_ SURDRL Troubleshoot /repair accumulator bladder. 01:30 - 03:30 2.00 DRILL_ ROT_ SURDRL Drill ahead 16" hole dretnl 40 - 151 ft. AST = 0 hrs, Rot = 1.3 hrs Printed: 10/16/2006 10:23:51 AM • • Marathon Oil Company Page 2 of 8 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: ORIGINAL DRILLING Start: 4/11/2006 End: 5/15/2006 Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To .Hours Code' Code Phase Description of Operations 4/29/2006 03:30 - 06:00 2.50 TRIP_ BHA_ SURDRL Handle BHA #1, MU dretnl assy, surface test. 4/30/2006 06:00 - 06:30 0.50 DRILL_ ROT_ SURDRL Drill ahead 16" hole dretnl 151 - 162 ft ART = .5 hrs 06:30 - 07:30 1.00 CIRC_ MUD_ SURDRL Circ /cond fluids, extreme quantity cuttings return. 07:30 - 06:00 22.50 DRILL_ ROT_ SURDRL Drill ahead 16" hole dretnl 162 - 1520 ft ART = 12.5 hrs Corm's free, no drag /torque, no gain !toss. Large amounts vegetation /petrified wood at shaker initially, returning to normal returns at 475 ft. Salt water influx at 160 ft, 280 - 3150 mg/I Up 70, Dn 61, Rot 66, SPM 330, GPM 650 No acc / do time WOB 5/20, RPM 40, SPM 5/1/2006 06:00 - 07:00 1.00 DRILL_ ROT_ SURDRL Drill ahead 16" hole dretnl 1520 - 1598 ft ART = 1 hr, AST = 0 hrs 07:00 - 08:30 1.50 CIRC_ MUD_ SURDRL Circ /cond fluids for 13 3/8 csg run Large quantities cuttings return, circ shaker clean. 08:30 - 10:30 2.00 TRIP_ WIPR SURDRL PJSM, POH wiper trip to 128 ft, no drag /gain /.loss 10:30 - 13:00 2.50 TRIP_ WIPR SURDRL PJSM, RIH wiper trip to 1560 ft, precaution wash to 1598 ft 15 ft fill. 13:00 - 13:30 0.50 DRILL_ ROT_ SURDRL Drill ahead 16" hole dretnl 1598 - 1608 ft due to fill, in prep for 13 3/8 csg run (insure csg within safe working limit 3 ft above rotary table) ART = .5 hrs, AST = 0 hrs TD csg pt at 1330 hrs. 13:30 - 15:30 2.00 CIRC_ MUD_ SURDRL Circ cond fluids for 13 3/8 csg run. Pump two hi-vis sweeps with no indication sweep return. Cont circ shaker clean. 15:30 - 17:30 2.00 TRIP_ DP_ SURDRL PJSM, POH 5" DP to BHA. No drag /swab /gain /loss Correct hole fill. SLM, no correction. 17:30 - 19:30 2.00 PULD_ BHA_ SURDRL PJSM, flow check, Lay do dretnl BHA, stand bk HWDP 19:30 - 21:30 2.00 PULD_ DP_ SURCSG PU /stand bk 24 jts 5" DP for 13 3/8 cmt job 21:30 - 00:00 2.50 RURD_ CSG_ SURCSG PJSM, place csg run equip rig floor, RU same. 00:00 - 01:30 1.50 REPAIR RIG_ SURCSG Repair top drv link tilt. 01:30 - 06:00 4.50 RUN_ CSG_ SURCSG Commence run 13 3/8 csg: MU /thread lock shoe track (Shoe, 1 jt 13 3/8, float collar) Check floats, RIH 39 jts 13 3/8, L80, BTC, 68# csg. Prepare hang off at rotary at 0600hrs. No bridge, correct displacement, no gain /loss. Shoe at 1602 ft, float collar 1556 ft. 5/2/2006 06:00 - 06:30 0.50 RURD_ CSG_ SURCSG PJSM, RD csg run equip, release csg crew. 06:30 - 09:00 2.50 RURD_ CMT_ SURCSG PJSM, RU floor /inner string tools, for 13 3/8 cmt 09:00 - 12:30 3.50 TRIP_ DP_ SURCSG PJSM, RIH stab in tool on 5" DP, space out /stab in, confirm seal. 12:30 - 13:30 1.00 CIRC_ MUD_ SURCSG Circ /cond fluids for 13 3/8 cmt. No abnormal returns. 13:30 - 16:30 3.00 PUMP_ CMT_ SURCSG PJSM, cmt 13 3/8 csg: Pump 42 bbls SAP spacer, test lines 2500 psi. Mix /pump 228 bbls 12 ppg type 1 cmt slurry. Pump 1 bbl H2o, drop wiper plug, confirm dropped Cmt to surface, displace with 25 bbls H2o, Sting out float collar, pump out wiper plug with 2 bbls H2o Circ inner string / 5 X 13 3/8 ann clean, trace cmt to surface. Cmt in place at 1550 hrs Printed: 10/16/2006 10:23:51 AM • • Legal Well Name: Common Well Name: :Marathon Oil Company Operations Summary Report CANNERY LOOP UNIT 11 CANNERY LOOP UNIT 11 ORIGINAL DRILLING GLACIER DRILLING GLACIER DRILLING Hours ~ .Code ~ Code J Phase Page 3 of 8 Event Name: Contractor Name: Rig Name: Date !From - To 5/2/2006 13:30 - 16:30 16:30 - 17:30 17:30 - 19:30 19:30 - 22:00 22:00 - 00:30 00:30 - 01:30 01:30 - 04:00 04:00 - 05:00 05:00 - 06:00 5/3/2006 06:00 - 07:00 07:00 - 08:30 08:30 - 19:00 19:00 - 21:00 21:00 - 21:30 21;30 - 01:00 01:00 - 05:00 05:00 - 06:00 5/4/2006 06:00 - 11:00 11:00 - 11:30 11:30 - 15:00 15:00 - 16:00 16:00 - 18:00 18:00 - 18:30 18:30 - 19:00 19:00 - 20:00 20:00 - 20:30 20:30 - 06:00 5/5/2006 06:00 - 12:00 12:00 - 00:00 Start: 4/11 /2006 Rig Release: Rig Number: 1 Spud Date: 4/27/2006 End: 5/15/2006 Group: Description of Operations 3.00 PUMP_ CMT_ SURCSG 5 bbls contaminate, 25 bbls 12 ppg cmt to surface. 1.00 RURD_ CMT_ SURCSG Flush BOPE, RD cmt equip, release cmt unit. 2.00 REPAIR RIG_ SURCSG Repair link tilt /top drive 2.50 TRIP_ DP_ SURCSG PJSM, POH inner string, lay do stab in tool. 2.50 NUND BOPE SURCSG PJSM, nipple do diverter system PU for cut off: 1.00 CUT_ CSG_ SURCSG PJSM, rough cut /remove 13 3/8 csg stub. 2.50 NUND BOPE SURCSG Remove diverter, rack same. 1.00 NUND WLHD SURCSG Remove start hd. 1.00 CUT_ CSG_ SURCSG PJSM, dress /final cut 13 3/8 csg. 1.00 CUT_ CSG_ SURCSG Complete Final Cut 13 3/8 Csg. & Bevel 1.50 NUND WLHD SURCSG Install Well Head, Test Slip Lock Connections To 600 psi F 10 Min (Test Good) 10.50 NUND BOPE SURCSG Pjsm; N/U Bope Set Spool, Mud Cross, Dbl Gate & Annular. N/U Kill/ Choke Lines. N/U Choke, Kill Line Valves, R/U Flow Lines& Drill Nipple. 2.00 RURD_ OTHR SURCSG Pjsm; Set Pipe Racks & R/U To P/U 5" D/P 0.50 RUNPUL WBSH SURCSG Set Wear Bushing 3.50 PULD_ DP_ SURCSG Pjsm; P/U 18 jts 5" D/P. & Stand Back. Stop P/U D/P Due To Noise (22:30hr) 4.00 TEST_ BOPE SURCSG Pjsm; M/U Test Jt. Pull Wear Bsg. R/U to test Bope. Test BOPE 250/ 3500. Rams Blind ,Pipe & Annular. Test All Related Equiptment. All Passed Perform Accumlator Drawdown Test. Witnessed waived By Jim Regg AOGC. 1.00 TEST_ CSG_ SURCSG Pull wear Bsg./ R/U Test 13 3/8 Csg. To 3000 psi F- 30 Min/ Test Good 5.00 PULD_ DP_ SURCSG PJSM; Drift, P/U And Stand Back 41 Stands 5" D/P ( 82 Joints) 0.50 RURD_ OTHR SURCSG Calibrate And Set Epoch Rig Watch (Block Height) 3.50 PULD_ BHA_ SURCSG PJSM; M/U BHA # 2 1 Bit, WB Stab, Pony D/C String Stab D/C, Change Motor AKO To 1.2 1.00 TRIP_ DP_ SURCSG RIH W 5" D/P To 1498' 2.00 DRILL_ CMT_ SURCSG Wash And Tag Cement At 1552', Clean out Cmt F- 1551 Tag F/C At 1558' Drill Shoe Track F-1557 To 1605' Clean Out Hole To 1608'. (Tag Shoe @ 1602' ) 0.50 DRILL_ ROT_ SURCSG Drill/ Rotate F- 1608' To 1628' (ART = .25 hr.) 0.50 CIRC_ MUD_ SURCSG CBU At 1628'/ To Clean Out Drilled Cmt. 1.00 CIRC_ MUD_ SURCSG Clean Out Pill Pit, Mix/ Pump 30 bbl Flo -Vis Spacer Displace Hole W 217bb1s 8.9 ppg Flo Pro Mud At 200 Stks 383 Gpm 375 psi 0.50 TEST_ LOT_ SURCSG PJSM; Run LOT (8.9 ppg MW 680psi At 1505 TVD =17.58EMW) 9.50 DRILL_ ROT_ IN1DRL Drill Survey F- 1628' To 2208' No Gain Loss Normal Tq/ Drag. Pump Sweeps For Hole Cleaning AST= 2.45 ART =3.40 ADT= 5.85 6.00 DRILL_ ROT_ IN1 DRL PTSM; Drill, Slide, Survey, F- 2208' T- 2627' Up Wt. 83k- Dn. Wt. 68k- Rt. Wt. 78k. Pump Hi Vis Sweeps to Maintain Hole Cleaning Normal TO & Drag, No Gain Of Losses To hole ART = 3 hr. AST= 1.5 12.00 DRILL_ ROT_ IN1 DRL PTSM; Drill, Slide, Survey F- 2627' T-3509' Up Wt. 115k Dn. Wt. 75k Rt .Wt 85k Pump Hi Vis Sweeps To maintain hole Cleaning Printed: 10!16/2006 10:23:51 AM • Marathon Oil Company Page 4 of 8 Operations Summary Report. Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: ORIGINAL DRILLING Start: 4/11/2006 End: 5/15/2006 Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Description of Operations 5/5/2006 12:00 - 00:00 12.00 DRILL_ ROT_ IN1DRL Normal Tq & Drag. No Gain Losses To hole Art= 4.8 Ast= 3.95 00:00 - 06:00 6.00 DRILL_ ROT_ IN1 DRL Drill, Slide Survey, F- 3509' T- 4077' Up Wt. 123K Dn. Wt. 80k Rt. Wt. 98k Pump Hi Vis Sweeps To Maintain Hole Cleaning Normal Tq & Drag. No Gain Losses To hole Art= 3.25hr. Ast= .75hr. 5/6/2006 106:00 - 08:00 08:00 - 09:00 09:00 - 12:00 2.OO~DRILL_ ~ROT_ ~IN1DRL 1.00 CIRC MUD IN1DRL 3.00 TRIP_ WIPR IN1DRL PJSM: Drill, Slide Survey F- 4077' T-4203' Up Wt.= 125k/ Dn. Wt.= 87k / Rt. Wt.= 110 k No Gain/ Losses Normal Tq. & Drag. Ast = 0 hr. Art.= 1.2 hr Pump Hi Vis Sweep. Circ. BU 1.5x Circ.Shakers Cleaned Up. Pump At 333 Spm = 650 Gpm 1450 Psi PJSM; Monitor Well, Pump Dry Job/ POH (Short Trip) F- 4203'/ T- 1590' No Gain Or Losses To Hole Normal Drag, Max Over Pull 5 To 10K Hole Slick Service Rig, Crown, Blocks, Top Drive & Carrier Repair Drum Clutch (Replace Clutch Plates) Remove Dennison Drive Line For Repair. RIH F- 1605' T- 4142' No Gain/ Losses. Normal Drag. Hole Slick. Correct Displacement Circ. Wash F-4142' T- 4203' Tag 5' Fill Drill, Slide, Survey F- 4203' T 4771' Up Wt.= 145k/ Dn. Wt.= 85k Rt. Wt.= 110 No Gain Losses, Normal Tq. Drag. Ast = 1.1 Hr. Art 3.0 Hr. Drill Slide Rotate F- 4771' T- 5278' Up Wt. = 140K Dn. Wt.= 85k Rt. Wt. = 115k No Gain Losses Normal Tq. Drag. Ast = .6 Hr. Art= 4.2 PJSM;Drill rotate,slide from 5278' to 5604' Up wt. = 55k Dn wt. = 98k rt. wt. = 120k No gain/loss normal tq. and drag Ast = 1.3 hrs. Art = 2.2 hrs. Circ. bottoms up 1x @5604' pump rate 330 spm 1750 psi 650 gal. min. POH Wiper trip from 5604' to 4203' Normal drag,max. overpull 5-10k Hole slick no gain or loss RIH from 4200' to 5570' No gain or loss normal tq drag Wash And Ream F- 5570' T- 5604' Tag 4' Fill . Circ. B/U 2x, Pump Hi Vis Sweep, Circ. hole Clean. Poh F- 5604' To 824 'SLM Normal Drag Max Over Pull 5- 10k Hole Slick. No Gain/ Loss Correct Hole Fill. No Correction To Tally PJSM; UD Bha, Drill collars, Mwd, Motor, Stab. PJSM; Pull Wear Bushing, Make Dummy Run 9 5/8 Csg. hanger C/O Pipe Rams To 9 5/S,And Test 250/ 2500 psi 12:00-13:00 1.00 SERVIC RIG_ IN1DRL 13:00-14:00 1.00 REPAIR RIG IN1DRL 14:00-16:00 2.00 TRIP WIPR IN1DRL 16:00 - 16:30 0.50 TRIP_ WIPR IN1DRL 16:30-00:00 7.50 DRILL ROT IN1DRL 00:00 - 06:00 5/7/2006 106:00 - 11:00 11:00 - 12:00 12:00 - 13:30 6.00 DRILL_ ~ROT_ ~IN1DRL 5.00 DRILL_ ~ROT_ ~INIDRL 1.00 CIRC_ MUD_ IN1DRL 1.50 TRIP_ WIPR IN1DRL 13:30 - 14:30 1.00 TRIP WIPR IN1DRL 14:30 - 15:00 0.50 TRIP_ WIPR IN1DRL 15:00 - 17:00 2.00 CIRC MUD IN1 DRL 17:00 - 20:00 3.00 TRIP_ DP_ IN1 DRL 20:00 - 00:00 4.00 TRIP_ BHA_ IN1DRL 00:00-00:30 0.50 RUNPULWBSH IN1CSG 00:30 - 01:30 ~ 1.00 ~ TEST_ ~ BOPE ~ IN1 CSG Printed: 10/16/2006 10:23:51 AM • • Marathon Oil Company Page 5 of s Operations Summary deport Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Event Name: ORIGINAL DRILLING Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date I From - To Hours Code Code ~ Phase Spud Date: 4/27/2006 Start: 4/11/2006 End: 5/15/2006 Rig Release: Group: Rig Number: 1 Description of Operations 5/7/2006 00:30 - 01:30 1.00 TEST_ BOPE INICSG 01:30 - 03:30 2.00 RURD_ CSG_ INICSG 03:30-05:00 1.50 REPAIR RIG_ IN1CSG 05:00 - 06:00 1.00 RURD CSG IN1CSG 5/8/2006 06:00-07:30 1.50 RURD_ CSG_ IN1CSG 07:30 - 11:30 4.00 RUN CSG IN1CSG 11:30 - 12:00 0.50 CIRC_ MUD_ IN1CSG 12:00 - 12:30 0.50 REPAIR RIG INICSG 12:30-17:00 ~ 4.50~TRIP_ ~EOIP ~IN1CSG 17:00 - 18:00 1.001 WASH (FILL IIN1CSG 18:00-19:30 ( 1.50~CIRC_ MUD_ ~IN1CSG 19:30 - 20:00 0.50 RURD_ OTHR IN1CSG 20:00 - 22:30 2.50 PUMP CMT INICSG 22:30-00:00 1.50 RURD_ CSG_ IN1CSG 00:00-00:30 0.50 TEST_ WLHD IN1CSG 00:30-06:00 5.50 RURD CSG INICSG 5/9/2006 106:00 - 10:00 I 4.001 TRIP I BHA I IN1CSG 10:00 - 15:30 5.50 TRIP_ DP_ IN1CSG 15:30 - 16:00 0.50 TRIP_ DP_ IN1CSG 16:00 - 17:00 1.00 TEST CSG IN1CSG 17:00 - 19:00 2.00 DRILL_ CMT_ IN1CSG 19:00 - 19:30 0.50 CIRC_ MUD_ IN1CSG 19:30-20:30 1.00 TEST LOT IN1CSG F- 5 min. (Test Passed) Remove Bails, Elevator And Drillpipe Spinners Trouble shoot And Repair Stabbing Board R/U Fill Up Tool& long Bails. R/U Weatherford Elevator ,Spider And Tongs Continue Rig Up Of Csg. Tools, Adjust Torque Tube PJSM: P/U And Bakerloc Shoe Track, Circ, Ck Floats. Run 40 jts. 9 5/8 L-80 40# BTC Csg. To 1600' Break Circulation, At 1600', Condt Mud. Trouble shoot and repair stabbing board Repair Hyd Line To Control Line. Line crimped restricting flow. Run 97 Jts 1600' To 5561' P/U Landing Jt And Vetco 9 5/8 X 13 3/8 Hanger, Tag Fill At 5574' Work Csg. Up Wt 240 K Dn 190K Break Circ & Wash Csg. F- 5574' To 5595' Land Casg. With 190k On Well Head. F/C At 5511' Shoe At 5595' Circ And Cond. Mud At 5595'. W/ 110 Spm 200 Gpm 450psi. Circ Untill Shakers Cleaned Up (Hvy Sand Returned Over Shakers) Install BJ 9 5/8 Cement Head And Cmt Lines PJSM; Test Cmt. Lines To 3000 Psi. Pump 30 bbl MCS 40 Spacer Followed By 35.6bbls Class G 12.5 ppg Lead Cmt W 2.2% SMS, +.5 CaCI +0.5 FL - 52+ 0.2 % CD- 32 + FP- 6L, Followed By 49bbls Class G 15.8 ppg Tail Cmt. W/ 0.5 FI- 63 +0.3 Cd-32 + 0.1 % ASA-301 +0.1 % R-3 + 1 Gal Per Sx FP 6L. Pump 5 bbl H2O Switch Over To Rig Pump And Displace W/ 413bb1 9.3ppg Flo Pro Mud. Displace At 5bbl Per Min 450 PSI Bump Plug With 550 Psi Over Disp. Rate CIP @ 2227 Hr. W 1050 psi. Hotd For 5 Min. Bleed Off Floats Held. 100%Returns During Cmt 8~ Displacement. PJSM R/D Cmt. Head L/D Landing Jt. Install Pack Off Test T/5000psi F- 10 Min R/D Casg. Tools Move Tong Line Adjust Torque Tube, Hang Tongs C/O Csg Rams F- 9 5/8 To 2 3/8x 5" Rams. And Test To 250/ 3500 psi C/O Shaker Screens F-175m T 210m PJSM; P/U 8~ M/U BHA#3 Orientate, Plug In & Program MWD. Pulse Test Same. RIH W/Jars And HWDP. P/U 144Jts 5" D/P, Drift And RIH To 5210' Continue RIH F- 5210' To 5430' W (Stands) R/U And Test 9 5/8 Csg. T/3000 psi F- 30 Min Test Good/ Final psi 2995psi Wash F- 5500' To 5509' Tag F/C @ 5509', Drill Float EO. And Cement To 5604' Drill Formation F- 5605 'To 5625' (New Hole) Work through Shoe At 5595' And Clean Up. Circ & Condition Mud For LOT Test At 5625' Perform Leak Off Test at 5625' MD 4376' TVD W/ 9.45 ppg M/ W. 920 psi At 4376'TVD =13.5 EMW. Printed: 10/16/2006 10:23:51 AM • ~ Marathon Oil Company Page 6 of 8 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Event Name: ORIGINAL DRILLING Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING .Date I From - To Hours Code .Code Phase Spud Date: 4/27/2006 Start: 4/11/2006 End: 5/15/2006 Rig Release: Group: Rig Number: 1 Description of Operations 5/9/2006 120:30 - 00:00 I 3.501 DRILL I ROT I PR1 DRL 00:00 - 06:00 ~ 6.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL 5/10/2006 06:00 - 06:30 0.50 CIRC_ MUD_ PR1 DRL 06:30 - 09:00 2.50 TRIP_ DP_ PR1 DRL 09:00 - 09:30 0.50 SERVIC RIG_ PR1 DRL 09:30 - 10:30 1.00 TRIP DP PR1 DRL 10:30 - 12:00 ~ 1.50 DRILL_ ~ ROT_ ~ PR1 DRL 12:00 - 18:00 ~ 6.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL 18:00 - 00:00 ~ 6.00 DRILL_ ~ ROT_ ~ PR1 DRL 00:00 - 06:00 ~ 6.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL 5/11/2006 X06:00-07:30 ~ 1.50~CIRC_ ~MUD_ ~PR1DRL 07:30 - 08:30 ~ 1.00 ~ TRIP_ ~ WIPR ~ PR1 DRL 08:30 - 09:00 0.50 SERVIC RIG_ PR1 DRL 09:00 - 10:00 1.00 TRIP WIPR PR1 DRL 10:00 - 18:00 ~ 8.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL 18:00 - 00:00 ~ 6.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL 00:00 - 06:00 ~ 6.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL 5/12/2006 ~ 06:00 - 12:00 ~ 6.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL Drill Rotate Slide F- 5625' T- 5773' Up Wt. 165k Dn. Wt. 85K Rt Wt. 115k TO 11 To 13k Ast= 1 hr Art .75 Adt= 1.75 hr. No Gain Loss Torque Increasing /Normal Drag Add 3% Lube Tex To Mud System. Drill Rotate Slide F-5773'- 6276' Up Wt. 175K Dn. 90K Rt Wt.115K TO-10 k To 13 k. Normal Tq/Drag No Gain/ Loss Circ. bottoms up@6276' D/P Pressure loss 400-500 psi POOH Looking for hole in drill pipe.Found hole in tube 1' above pin end std. #53- 4073' Service rig.Lay down bad joint. RIH 4073'-6276' No Gain/ Loss Normal Drag. Hole Slick Drill rotate slide 6276'-6340' Up wt.170K Dn. wt.90K Rot wt. 115 tq.11-13 Art 2 1/2hrs. Ast 2hrs. No gain loss Torque/ drag increasing. PJSM Drill rotate slide 6340'-6718' Up wt. 180K Dn. wt.95K Rot. wt130K Tq.12-14 No gain losses Torque/drag increasing Art 1 3/4hrs. Ast 2hrs. Max Gas 228 units Add 1/2 E/P lube Drill rotate slide 6718'-6906' Up wt. 180K Dn. wt.100K Rot wt.135 torque12-14 No gains losses Torque/drag stable Art 1 hr. Ast 2hrs. Max Gas 210 units Drill rotate, slide 6906'- 7284' Up wt. 185k Dn. wt. Rt.wt. 140 Tq . 15k Increasing No gain/ loss Art= 2 Ast= 1.5 Adt = 3.5 Increase tube-tex to 4 PJSM; Cicr.Pump Sweep For Wiper Trip At 7284' Circ At 300spm 575 gpm 1750psi. Sweep Returned W/ Increase in Cuttings. Monitor Well POOH F- 7284' T- 6089' (Wiper Trip ) No Gain Loss. Normal Drag. Hole Slick/ No Tight Spots Lube Rig, Blocks, Top Drive, Crown And Carrier RIH F- 6089' To 7220' Wash & Ream F- 7220 To- 7284' No Fill. Normal Drag/ Correct Displacement No Gain/ Loss PJSM Drill Slide Survey F- 7284' To 7663' Increase Lube Tex to 6% tq Decreased F- 16,500fp. To 10,880fp At 7580'-7663'Art 1 3/4 hr.Ast 2 1/2 hr. Up wt.180KDn wt. 125K Rot wt. 150K No Gain/ Loss. Max Gas = 580 Units Drill, Survey Rotate F-7663'-8040'Art 3 1/4 hr. Pump Hi Vis. sweep @ 8000'-6% Lube Tec Torque leveled off 9800fb Up wt.-185K Dn wt.-125K Rot wt.-155K Max Gas 540 Units Drill Survey Rotate F/8040'-8510 'Art 6 hrs. Up wt.195K Dn.130K Rot.160K Tq 5/ 11 k No gain/ loss Max Gas 615 Units Drill Survey F- 8510'-8924' Up. Wt.205K Dn. Wt. 140K Rt. Wt.170K Tq 12k Art=3 1/2hrs No Gain Loss. Printed: 10/16/2006 10:23:51 AM • ~ Marathon Oil Company Page 7 of 8 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: ORIGINAL DRILLING Start: 4/11/2006 End: 5/15/2006 Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 .:Date From - To Hours Code Code Phase Descrip#ion of Operations 5/12/2006 06:00 - 12:00 6.00 DRILL_ ROT_ PR1 DRL Pump Hi-Vis sweep@8544' 12:00 - 16:00 4.00 DRILL_ ROT_ PR1 DRL PJSM Drill Survey F-8924'-9282' Art- 1/2 hrs. Up wt.215K Dn. wt.145K Rot.wt.175K Tq.10-12 No Gain Loss 16:00 - 19:00 3.00 WAITON ORDR PR1 DRL Circ. up sample forMarathon Geo.Wait on Orders Confirm TD @ 9305' 1900Hrs 5/11/2006 19:00 - 19:30 0.50 DRILL_ ROT_ PR1 DRL Drill Survey F-9282'-9305 TD' Art-1/4 hr. Up wt.215K Dn. wt.145K Rot. wt.175K Tq.10-12 19:30 - 20:30 1.00 CIRC_ MUD_ PR1 DRL Circ.Hi Vic. Sweep for Wiper Trip Check for flow @ 9305'TD 20:30 - 21:30 1.00 TRIP_ WIPR PR1 DRL POOH for wiper trip from 9305'-8850' 20K-50K Drag/ Work Clean Up Tight Spots 21:30 - 22:00 0.50 CIRC_ MUD_ PR1 DRL Circ. Pump Dry Job 22:00 - 22:30 0.50 TRIP_ WIPR PR1 DRL Wiper trip from 8850'-8610'/ 20-50k Over pulls. Work Clean Up Tight Spots 20k-50K Drag No Gain Loss 22:30 - 00:00 1.50 REPAIR RIG_ PR1 DRL Broke chain on Drawworks replace with new chain. 00:00 - 02:30 2.50 TRIP_ WIPR PR1 DRL Wiper Trip F- 8610 T- 5550' 20k- 30k Drag Work Tight Spots. Hole Slick F- 7300' To 5550' 02:30 - 04:00 1.50 SLPCUT DLIN PR1 DRL Slip & Cut Drilling Line. Service Rig 04:00 - 06:00 2.00 TRIP_ WIPR PR1 DRL RIH (Wiper Trip) F- 5550' - T- 9305'TD Precautionary Wash To Bttm. F- 9150 To 9305' TD No Fill Hole Slick, No Gain/ Loss 5/13/2006 06:00 - 08:30 2.50 CIRC_ CFLD PR1 DRL Circ. B/U At 9305' 1700 Units Of Gas. Pump 50 bbls Hi Vis Sweep At 270spm 550 gpm 2000 psi Sweep Returned At 13,500Stks. (Calculated Hole Volume) Spot 183 bbls Mud/ LubeTex Pill. Note; Sweep Returned W/ 50% Increase In Cuttings. 08:30 - 09:00 0.50 MIX_ PILL PR1 DRL Monitor Well. 10 Min/ Mix 8~ Pump Dry Job 09:00 - 14:00 5.00 TRIP_ DP_ PR1 DRL PJSM; POOH/SLM F/ E- Logs F- 9305' T- 5595' No Over Pulls In Open Hole. Normal Drag. Correct Hole Fill. Continue POOH F-5595' T- 850' No Gain Loss/ Correct Hole Fill 14:00 - 16:00 2.00 TRIP_ BHA_ PR1 DRL PJSM; L/D HWDP, Jars, Stabs, D/C, MWD Motor And Bit. 16:00 - 16:30 0.50 CLEAN_ RIG_ PR1 EVL Clean Rig Floor/ Hold PJSM W/ Precision WLS 16:30 - 17:00 0.50 RURD_ ELEC PR1 EVL PJSM: Rig Up Precision WLS M/U E- Line Tools 17:00 - 18:00 1.00 LOG_ OH_ PR1 EVL Run Precision Quadcombo Tools.Tagged Bttm At 9298' WLM 18:00 - 23:00 5.00 LOG OH_ PR1 EVL Log W/Quad Combo F-9298'-3000' 23:00 - 00:30 1.50 LOG_ OH_ PR1 EVL POOH W/ E- Line Quadcombo Tools/ And UD. R/D PWLS Tools 00:30 - 02:30 2.00 TRIP_ DP_ PR1 EVL PJSM; M/U Mule Shoe RIHW/ 5" D/P To 5554' (SLM) 02:30 - 03:00 0.50 CIRC_ MUD_ PR1 EVL Circ B/U @ 5554' 300spm 850 psi 585gpm Max Gas At B/U = 9 Units. 03:00 - 06:00 3.00 WAITON OTHR PR1 EVL Circ Wait On MOC GEO For Pick Points, MFT Logs 5/14/2006 06:00 - 07:00 1.00 WAITON ORDR PR1 EVL Wait On MOC GEO Dept. For Mft Points 07:00 - 08:30 1.50 TRIP_ DP_ PR1 EVL RIH F- 5554'-9305'. Normal Drag/ No Gain/Loss Wash F- 9148' T- 9305' Tag Btm. No Fill 08:30 - 09:30 1.00 CIRC_ MUD_ PR1 EVL Circ. 6/U At 9305' Max Gas At B/U 1030 Units Continue Circ At 300 spm 585gpm 865 psi. 09:30 - 10:30 1.00 TRIP DP PR1 EVL POOH To 8263' And Park D/P For MFT Pressure Printed: 10/16/2006 10:23:51 AM • • Marathon Oil Company Page $ of s ...Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: ORIGINAL DRILLING Start: 4/11/2006 End: 5/15/2006 Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Description of Operations 5/14/2006 09:30 - 10:30 1.00 TRIP_ DP_ PR1 EVL Testing W/ PWLS E- Line Tools. Monitor Well W/ 10:30 - 11:00 0.50 RURD_ ELEC PRIEVL 11:00 - 16:30 5.50 LOG OH PR1 EVL 16:30 - 22:30 6.00 LOG OH PR1 EVL 22:30 - 23:30 1.00 LOG_ OH_ PR1 EVL 23:30 - 00:00 0.50 TRIP DP PR1 EVL 00:00 - 04:30 4.50 LOG OH PR1 EVL 04:30 - 05:00 0.50 LOG OH PR1 EVL 05:00 - 06:00 1.00 LOG_ OH_ PR1 EVL 5/15/2006 06:00 - 07:30 1.50 LOG OH_ PR1 EVL 07:30 - 08:30 1.00 LOG_ OH_ PR1 EVL 08:30 - 09:00 0.50 TRIP BHA PR1 EVL 09:00 - 09:30 0.50 CIRC MUD PR1 EVL 09:30 - 10:30 1.00 LOG_ OH ' PR1 EVL 10:30 - 12:00 1.50 LOG_ OH PR1 EVL 12:00 - 13:00 1.00 LOG OH PR1 EVL 13:00 - 13:30 0.50 LOG_ OH_ PR1 EVL 13:30 - 15:30 2.00 LOG_ OH_ PR1 EVL 15:30 - 16:00 0.50 LOG OH PR1 EVL 16:00 - 18:30 2.50 TRIP_ DP_ PRIEVL 18:30 - 19:00 0.50 LOG_ OH_ PR1 EVL 19:00 - 21:00 2.00 LOG OH PR1 EVL 21:00 - 22:00 1.00 RURD ELEC PR1 EVL 22:00 - 00:00 2.00 RURD_ ELEC PR1 EVL 00:00 - 04:30 4.50 LOG_ OH_ PR1 EVL 04:30 - 06:00 1.50 RURD ELEC PR1 EVL Returns To Trip Tank. No Gain Losses. R/U PWLS E- Line MFT Tools RIH W/ PWLS E-Line MFT Tools Inside D/P Log F- 9305' T-8313' POOH W/ E- Line, Clean Tools, Move D/P Pipe Pipe Free No Over Pull. RIH W/ E-Line Continue E- Line MFT Logging. F/ 9909 To 8302. POOH W/ E- Line Tools 8< L/D Move D/P To 7253' Pull 230 K To Free Pipe 60K Over PuII.Normal Up Wt 170k Dn Wt 125k Monitor Well With Returns To Trip Tank. No Gain/ Loss PJSM; M/U PWLS MFT Tools RIH Inside D/P.W E- Line & LOG from 8313 to 7350' POOH W/PWSL E- Line Clean Tool, Move D/P. 70k Over Pull To Free Pipe. Normal Up Wt. 150k Dn. Wt. 110k. RIH W PWLS E-Line/ Inside D/P. Log F- 8302-7350' Log w/MFT f-7699'-7253' POOH Break and Lay down PWLS MFT PJSM POOH w/ DP F-7253'-5554' to 9 5/8" csg. shoe. No Gain Loss CBU at csg. shoe 300 spm 900 psi (34 units of gas) Make up and run PWLS MFT to 7253' Log w/PWLS MFT F-7253'-6805' PJSM POOH w/PWLS MFT. Tools break down and clean tools. RIH w/ PWLS MFT to-6805' Log w/PWLS MFT F/6805'-6586' PJSM POOH w/PWLS MFT Lay down tools and rig down PWLS POOH w/ 5" Drill Pipe F! Open hole Log Rig up PWLS to run open hole MFT Log w/PWLS F/6838'-6518'. One MFT Test At 6518' All Others Failed Tool Unable To Peform Test PJSM POOH w/PWLS MFT and lay down tools Rig down PWLS PJSM Rig up Schlumberger to run FMI Loggs Run SWLS FMI Logs POOH W/ SWLS FMI Logging Tools And L/D Move To Completion Operations 0600hr 5/15/2006 Printed: 10/16/2006 10:23:51 AM • • Marathon Oil Company Page 1 of 1 Operations Summary Repor# (Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: ORIGINAL COMPLETION Start: 5/16/2006 End: .5/19/2006 Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Description of Operations 5/16/2006 06:00 - 07:30 1.50 TRIP_ BHA_ PR1 CSG Pjsm; P/U 8~ M/U 8 1/2 Clean Out Bha. Rih 07:30 - 11:00 3.50 TRIP_ DP_ PRICSG RIH W/ 5" Drillpipe To 9305', Wash F- 9245' T-9305' Hole Slick. No Fill At 9305' No Gain Loss 11:00 - 12:30 1.50 CIRC_ MUD_ PR1CSG Circ. Clean Hole @ 9305' At 240spm 495gpm 1450.psi) BU Gas 3335 units. Circ Cond. Mud. Mw In 9.85 /Out 9.85 12:30 - 13:00 0.50 MIX_ PILL PR1CSG Monitor Well 10min./ Mix 8~ Pump Dry Job. 13:00 - 22:00 9.00 PULD_ DP_ PR1 CSG POOH UD Drillpipe F- 9305' 22:00 - 22:30 0.50 PULD_ DP_ PR1 CSG RIH w/ 5" DP in Derrick 22:30 - 23:30 1.00 PULD_ DP_ PR1 CSG POOH UD 5" DP and BHA. For A total Of 325 Jts 5 " D/P L/D. No Gain Loss. Hole Slick. No Over Pulls 23:30 - 00:00 0.50 RUNPUL WBSH PR1 CSG Pull Wear Bushing /Clean Rig Floor 00:00 - 05:00 5.00 RURD_ CSG_ PR1 CSG Pjsm; R/D Rig Floor, D/P Handling tools; Spinners, Tongs, C/O Bails, Elevators. Install Fill Up Line. R/U Weatherford ~i Csg. Tools. Spot In Expro Spools.R/U Pollard WLS. ~ Hang Control Line Sheves, Set Short Pipe Racks. ' And Stage Modules. ', 05:00 - 06:00 1.00 RUN CSG_ PR1 CSG PJSM; M/U Shoe Track. Ck Floats. Run 3 1/2 Excape/ Csg. w/ 3 Control Lines & 1 Sac. Line 5/17/2006 06:00 - 22:00 16.00 RUN_ CSG_ PR1 CSG Cont. Run 3 1/2 Csg. (Total of 11 Modules & 276 jts.W/ 3 Control Lines & Sao.Cable To 9284'. Float Collar @ 9247 Shoe At 9284' P/U Wt 105K. S/O Wt.70K 22:00 - 00:00 2.00 CIRC_ MUD_ PR1 CSG R/U Circ Head & Lines Circ At 9289' 90 Units Gas at B/U-Up wt.-105K/Dn. wt.-70K No Gains No Losses 00:00 - 03:00 3.00 LOG_ OH_ PR1 CSG R/U Expro WLS And Run Correlation Log. 03:00 - 04:00 1.00 WAITON ORDR PR1 CSG Wait On MOC GEO. To Confirm Setting Depth Of Excape Modules. ~, 04:00 - 04:30 0.50 RURD_ CMT_ PR1 CSG PJSM; R/U Cement Head ', 04:30 - 05:30 1.00 CIRC_ MUD_ PRICSG Circ. Mix & Pump 250 bbls Inhibited Mud. 05:30 - 06:00 0.50 TEST_ EOIP PR1CSG Pump 5bbl. H2O Test Cmt Lines To 4000 Psi. Bleed Off.Mix 8< Pump 40 bbl 10.5ppg. MCS-4D Spacer. ~ 5/18/2006 06:00 - 08:00 2.00 PUMP_ CMT_ PR1CSG Cont cmt 3 1/2 excape string: Mlx /pump 1550 sks 15.8 ppg "G" 325 bbls total slurry. Drop plug, confirm dropped, pump 5 bbls H2o. Displace with 81.5 bbls KCL Bump plug with 2450 psi / 5 min, bleed, floats holding. Cmt in place /plug bumped 0740 hrs No cmt to surface, Re-cip string to 75% slurry pumped. ICP = 750 psi @ 6 bpm, FCP = 1950 psi @ 1.8 bpm 08:00 - 16:00 8.00 NUND BOPE PR1 CSG Nipple do BOPE while WOC 16:00 - 19:30 3.50 NUND EOIP PRICSG PU BOP stack, terminate excape control lines, Install /test PKF 5000 psi / 10 min, test successful, no re-test 19:30 - 23:00 3.50 NUND TREE PR1 CSG Nipple up /test prod tree 10000 psi / 10 min, test successful. Set BPV, label valves /lines. 23:00 - 06:00 7.00 RURD_ RIG_ RDMO Commence rig do /prepare move. 5/19/2006 06:00 - 06:00 24.00 RURD_ RIG_ RDMO PJSM, cont. rig dn, prepare rig for move. No acc / do time. Printed: 10/16/2006 10:25:11 AM • • Marathon Oil Company Page 1 of 5 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: ORIGINAL COMPLETION Start: 5/22/2006 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours. Code Code Phase Description of Operations 6/9/2006 08:30 - 10:00 1.50 SAFETY MTG_ PR1 CSG Issue permit and hold safety meeting. Move to CLU pad 3 10:00 - 13:50 3.83 WAITON EQIP PR1 CSG Eline supervisor to Ninilchik to assist on CT perforating 13:50 - 14:25 0.58 RURD_ ELEC PR1CSG RU to run CBL. 14:25 - 16:08 1.72 RUNPUL ELEC PR1 CSG RIH CBL. Make free pipe pass 1260' - 1050'. RIH to bottom. Tag TD at 9165' ELMD. 16:08 - 18:30 2.37 LOG_ CSG_ PR1 CSG Log main pass from 9165' ELMD to 4000' ELMD. TOC at 4500'. Very good cement. 18:30 - 19:00 0.50 RUNPUL ELEC PR1CSG POH. E-line. 19:00 - 20:00 1.00 RURD_ ELEC PR1 CSG RD Expro E-line. leave Location 9/13/2006 07:00 - 08:30 1.50 SAFETY MTG PR1 EVL MIRU slick line unit. Uptained permit and hold safety meeting. 08:30 - 10:00 1.50 SAFETY MTG PR1 EVL Discussed precedure and reviewed environmental issues. 10:00 - 11:30 1.50 LOG_ CSG_ PR1 EVL MU 1.5" tool string with 8' stem, K joint, oil jars, tandem gauges. Open well. RIH making 5 minute stops at the following depths:0, 1010', 2290', 4001', 5100', 6355', 6597', 7371', 7476', 7690', 7872', 7933', 8088', 8176', 8249'.. sat down with gauges could not get down. 11:30 - 14:50 3.33 LOG_ CSG_ PR1 EVL POOH repeating 5 minute stops listed above. OOH with gauges no marks on bottom of the gauges. MU 1.8" swedge with oil jars. RIH with same. 14:50 - 15:30 0.67 TAG_ BOTM PR1 EVL Sat down at 8250' KBD. Work tool string, was able to work through with swedge continued down hole tagged fill at 9160' KBD. POOH 15:30 - 16:30 1.00 LOG_ CSG_ PR1 EVL OOH MU tandem gauges. RIH with gauges to 8387', 8402', 8611' KBD, Make 5 minute stops and repeat stops while POOH. 16:30 - 16:45 0.25 LOG_ CSG ~ PR1 EVL Completed stops POOH. 16:45 - 17:30 0.75 RURD_ SLIK PR1 EVL OOH with gauges, check data, data good RD slick line unit. Clean up around well head. Expro left lease. 9/23/2006 08:00 - 18:00 10.00 RURD_ STIM OTHER MI 5 ea. 500 bbl tanks for fluid, open top tanks, spotted equipment around pad for rigging up to frac well. BJ blew sand into sand king. 9/26/2006 08:00 - 18:00 10.00 RURD_ STIM OTHER Spot flow back tanks on liner, set buster, sand separtor, & choke. Used crane to set flare stack and buster. 9/27/2006 06:00 - 18:00 12.00 RURD_ STIM CMPSTM Continue RU MOC flowback iron, BJ frac trucks and well test equipment. Finished mixing KCL in all frac tanks. MIRU CTU. 9/28/2006 06:00 - 12:30 6.50 RURD_ STIM CMPSTM Completed RU of frac lines, Trucks, sand kings, blender, chem add unit, frac van. 12:30 - 14:30 2.00 PERF_ CSG_ CMPSTM RU Expro firing lines. Pressure test same. open up green firing line. Pressure up to 4060 psig and fired Module 1 gun perforaing Module 1 interval from 9084 - 9094' 14:30 - 18:00 3.50 RURD_ COIL CMPSTM Completed RU of CTU. Pressure test CT lines and well test lines to 250/4500 psig. Pressure tetst CTU BOP to 250/4500 psig. Shut down for night. Plan to hold pre frac safety meeting at 10 am 9/28/2006 due to late night cement job on Glacier rig utilizing some frac personnel.. 9/29/2006 10:45 - 11:15 0.50 SAFETY MTG_ CMPSTM Hold pre job soafety meeting. Discussed frac operations, tracing and perforating operations, PPE, emergency response and muster procedures, working in wet weather 11:15 - 11:45 0.50 PUMP_ FRAC CMPSTM Perform Injection Falloff test in Module 1. Pumped total of 43 bbls 6% KCL. ISIP = 2619 psig. F.G. = 0.79 psi/ft. Monitor falloff while gelling fluid. Gf closure = 4.84 11:45 - 12:15 0.50 PUMP_ FRAC CMPSTM Frac mod 1 perfs (9084-9094' RKB) w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 9500 psi. Ramp 2.0 - 8.0 ppa. BHP started climbing. Went to flush after 27 bbls 8 ppg pumped. Flushed with 49 bbls prior to screenout. 30 bbls short of complete flush volume. Placed 14178 Ibs prop (54.5% of design) (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 288 bbls. Traced pad volumes with SC-46 and all sand stages with Ir-192. Tagged all fluid w/ ProTechnics CFT 1100 chemical tracer and field tracer EPT 1000 (cumm. load = 288 bbls Printed: 10/16/2006 10:24:32 AM • • Marathon Oil Company Page 2 of 5 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: ORIGINAL COMPLETION Start: 5/22/2006 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Phase: Description of Operations Date From - To Hours Code Code 9/29/2006 11:45 - 12:15 0.50 PUMP_ FRAC CMPSTM including injection test) (Strap chemical tanks post frac) 12:15 - 14:00 1.75 FLOW_ BACK CMPSTM Open well and flow back 75 bbls. Pump 78 bbls pad back into module 1 to clear module 2 of any proppant. 14:00 - 14:30 0.50 PUMP_ FRAC CMPSTM Perforate Module 2 from 8607 - 8617' with 3050 psig on yellow line. Frac mod 2 w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 4600 psi. Ramp 2.0 - 8.0 ppa. Placed 28001 Ibs prop (100% design) (87.5 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 251 bblsl. Traced pad volumes with SC-46 and all sand stages with Ir-192. Tagged all fluid w/ ProTechnics CFT 1200 chemical tracer (cumm. load = 539 bbls) (Strap chemical tanks post frac) 14:30 - 15:00 0.50 PUMP_ FRAC CMPSTM Perforate Module 3 from 8498 - 8508' with 4170 psig on yellow line. Frac mod 3 w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 3750 psi. Ramp 2.0 - 8.0 ppa. Placed 31000 Ibs prop (92.5% of design) (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 252 bblsl. Traced pad volumes with SC-46 and all sand stages with Ir-192. Tagged all fluid w/ ProTechnics CFT 1400 chemical tracer (cumm. load = 791 bbls) (Strap chemical tanks post frac) 15:00 - 15:30 0.50 PUMP_ FRAC CMPSTM Perforate Module 4 from 8383 - 8393' with 4970 psig on yellow line. Frac mod 4 w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 9500 psi. Ramp 2.0 - 8.0 ppa. Was on flush when BHP started rising with surface pressure sawtoothing. BHP continued to increase along with surface pressure. Treatment screened out. Placed 26136 Ibs prop (79.2% of design) (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 230 bblsl. Traced pad volumes with SC-46 and all sand stages with Ir-192. Tagged all fluid w/ ProTechnics CFT 1500 chemical tracer (cumm. load = 1021 bbls) (Strap chemical tanks post frac) 15:30 - 16:30 1.00 FLOW_ BACK CMPSTM Open well up and flow back to flowback 88 bbls to tank. Prepare to pump tubing volume when noticed dead string pressure at 400 psig, down from 2200 and firing line pressure up to 6100 psig due to thermal heating/expansion during flowback time. Think that module 5 fired. Pressure up firing line to 6300 psig as calculated safe margin for module 6 to confirm module 5 firing. 16:30 - 17:50 1.33 PUMP_ FRAC CMPSTM Frac Module 5 from 8205 - 8215' with w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 4050 psi. Ramp 2.0 - 6.0 ppa. BHP and surface pressure increasing as 6 ppg was pumped, with BHP sawtoothing. Went to flush pumping no 8 ppg. Placed 18750 Ibs prop (57% of design) (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 256 bblsl. Traced pad volumes with SC-46 and all sand stages with Ir-192. Tagged all fluid w/ ProTechnics CFT 1600 chemical tracer (cumm. load = 1277 bbls) (Strap chemical tanks post frac) Skip modules 6 and 7 and RU on red firing line. 17:50 - 18:20 0.50 PUMP_ FRAC CMPSTM Perforate Module 8 from 7686 - 7696' with 3640 psig on red line. Frac mod 8 w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 4400 psi. Ramp 2.0 - 8.0 ppa. Placed 28400 Ibs prop (96.3% of design) (87.5 % 20/40 Ottawa ~ 12.5% 12/20 Flex Sand). Tot Load = 238 bblsl. Traced pad volumes with SC-46 and all sand stages with Ir-192. Tagged all fluid w/ ProTechnics CFT 1900 chemical tracer (cumm. load = 1515 bbls) (Strap chemical tanks post frac) 18:20 - 18:45 0.42 PUMP_ FRAC CMPSTM Perforate Module 9 from 7472 - 7482' with 5580 psig on red line. Frac mod 9 w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3700 psi. Ramp 2.0 - 8.0 ppa. Placed 31000 Ibs prop (100% of design) (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 246 bblsl. Traced pad volumes with SC-46 and all sand stages with Ir-192. Tagged Printed: 10/16/2006 10:24:32 AM r~ L L~ Marathon Oil Company Page 3 of 5 Operations Summary Report. Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: ORIGINAL COMPLETION Start: 5/22/2006 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code phase Description of Operations 9/29/2006 18:20 - 18:45 0.42 PUMP FRAC CMPSTM all fluid w/ ProTechnics CFT 2000 chemical tracer (cumm. load = 1761 18:45 - 20:00 1.25 RURD STIM 20:00 - 21:30 1.50 RURD_ COIL 21:30 - 00:30 3.00 RUNPUL COIL 00:30 - 01:00 0.50 RUNPUL COIL 01:00 - 01:40 0.67 JET_ N2_ 01:40 - 03:40 03:40 - 04:00 04:00 - 05:00 2.OO~JET_ ~N2_ 0.33 ~ JET_ ~ N2_ 1.00 ~ JET_ ~ N2_ 05:00 - 06:00 I 1.001 RUNPULI COIL 9/30/2006 - 06:30 06:30 - 07:30 07:30 - 08:30 08:30 - 06:00 RUNPUL COIL 1.00 RURD_ COIL 1.00 FLOW_ TEST 21.50 FLOW_ TEST bbls) (Strap chemical tanks post frac) CMPSTM Hold RD safety meeting. RD frac lines and trucks. Clean up sand kings and blender. Transfer frac tank bottoms to CTU supply tank. CMPSTM Hold PJSM. RU CTU. Stab injector head and bop onto tree. Shell test same to 250/4500 psig. Finish transferring KCL to supply tank CMPSTM RIH with coil tubing at min fluid rate of .4 bpm. Increase rate to 1.5 bpm at 7400'. RIH and found/broke flappers at 7709', 8234', 8412', and 8634' CTM/RKB in Modules 8, 5, 4, and 2, respectively. Found module 9 flapper at 7492' CTM/RKB but could not break, bypass with pumps on. Did not find module 3 flapper at 8524' CTM/RKB. Start cooling down N2 unit. Continue RIH at 1.5 bpm to PBTD of 9205'CTM/RKB. Could not wash down further. CMPSTM Circulate 15 minutes. POOH to Module 3 flapper at 8524' CTM/RKB. Work through same with pumps on and off. Could not locate flapper. Start nitrogen adn 560 scfm and fluid at .75 bpm. POOH to Module 9 flapper. Attempt to relocate flapper at 7492' CTM/RKB without success. Intermittent slugs of flex sand and proppant to surface. CMPSTM Jet well in with fluid at .75 bpm and nitrogen at 560 scfm at 7453' CTM/RKB above perfs. Get nitrogen around corner and shut down fluid pump. Continue jetting well with 560 scfm nitrogen. CMPSTM RIH jetting w/ 500 scfm nitrooen. Tagged up on Module 9 flapper at 7492' CTM/RKB. Work pipe several times. Unable to break flapper. Jet at 7490' for 15 min. Still could not get past flapper. Increase nitrogen to 750 scfm and worked past flapper with Snider maneuver. RIH to below module 1 at 9205' PBTD CTM/RKB and jet with 750 scfm. Had to work past module 3 flapper at 8524' CTM/RKB. No confirmed break. Also worked junk through module 2 flapper cavity. Steady amounts of flex sand and proppant at gas buster. Started seeing signs of gas to surface at 0300 hrs. CMPSTM Jet from below perfs with 500 scfm nitrogen working pipe from 9205' to 9095' CTM/RKB. Total fluid recovery = 219 bbls or 12.4% of total frac load. CMPSTM Jet from below perfs with min rate nitrogen of 350 - 400 scfm nitrogen working pipe from 9205' to 9095' CTM/RKB. At 0430 fluid rate increased to 2282 bpd from 1794 bpd while decreasing nitrogen to min rate. FTP increasing also from 480 psig to 533 psig. Total fluid recovery = 300 bbls or 17 % of total frac load. At 0500 fluid rate = 1911 bpd, cumm. recovery = 340 bbls or 19.3 % of total frac load, FTP up from 533 psig to 570 psig with nitrogen at min rate. Steady amount of flex sand and proppant at gas buster CMPSTM Shut down nitrogen and started POOH with coil tubing. At 0600 CT at 2350' and well flowing 1911 bpd with 745 psig FTP. Cumm. Recovery = 426 bbls or 24.2 % of total frac load of 1761 bbls. CMPSTM Finish POOH with CT. CMPSTM Take well flow through flowline and isolate CT from flow stream. Slowdown CT of nitrogen pressure through blowdown line to gas buster. RD Injector head and stand back and secure same. Secure CT equipment. CMPSTM Place well through sand buster and well test separator on 20/64 choke and line out same to vent stack. Well producing 2.2 mmcfd, 1413 bwpd, with a 1300 psig FTP. CMPSTM Place well into high pressure sales line and continue well test program. EPT 1000 still indicates fluid contribution from module 1. As os 0600 hrs Printed: 10/16/2006 10:24:32 AM ~ • Marathon. Oit Company Page 4 of 5 Operations Summaryi Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: ORIGINAL COMPLETION Start: 5/22/2006 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date ..From - To Hours Code Code Phase Description. of Operations 9/30/2006 08:30 - 06:00 21.50 FLOW_ TEST CMPSTM 9/30/2006 well making 4.6 mmcfd, 555 bwpd, with 1330 psig FTP. Cumm water recovery = 1271 bbls or 72% of 1761 bbls frac load. Chlorides at 8800. 10/1/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM Continue to flow test and clean up well post frac. As of 0600 hrs. 10/1/2006 well making 4.5 mmcfd, 384 bwpd, on a 22/64th choke with a 1290 psig FTP. (At 1800 hrs, 9/30/2006, estimated FBHP from WAM runs indicated +/-1900 psig or 52% max drawdown on Module 1. Opened choke from a 20/64th to 22/64th at 1830 hrs on 9/30/2006.) Cumm water recovery = 1693 bbls. or 96% of 1761 bbl frac load. Chlorides down to 6000 from 8000. 10/2/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM Continued flow testing and cleaning up well. At 0930 10/1/2006 well slugged large amount of flex, proppant, and some fine gray sand. FTP down to 1170 psig from 1345 psig, gas rate down to 3.9 mmcfd from 4.7 mmcfd, water up to 600 bwpd from 373 bwpd all on 22164th choke. Well cleaned up and as of 0600 hours 10/2/2006 well producing 4.7 mmcfd, 256 bwpd, with a FTP of 1335 psig. Well still slugging occasionally. Cumm water recovery = 2100 bbls or 119% of frac total load of 1761 bbls. 10/3/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM Continued flow testing and cleaning up well. At 1140 hrs 10/2/2006 well ESD while changing out washed out sand buster choke. At 2130 hrs well shut in to clean out plugged dump lines on sand buster. As of 0600 hours 10/3/2006 well producing 4.8 mmcfd, 427 bwpd, with a FTP of 1325 psig. Well still slugging occasionally with small amounts of sand. Cumm water recovery = 2394 bbls or 136% of frac total load of 1761 bbls. 10/4/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM Continued flow testing and cleaning up well. As of 0600 hours 10/4/2006 well producing 4.4 mmcfd, 214 bwpd, with a FTP of 1235 psig on a 22/64th choke. Well still slugging occasionally with fine sand. Cumm water recovery = 2725 bbls or 155% of frac total load of 1761 bbls. 10/5/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM Continued flow testing and cleaning up well. Unplugged green line and started monitoring FBHP at module 9 at 0900 hrs 10/4/2006. Increased choke to 26/64th. As of 0600 hours 10/5/2006 well producing 4.5 mmcfd, 256 bwpd, with a FTP of 1165 psig. Well still slugging occasionally with fine sand. Cumm water recovery = 3037 bbls or 172% of frac total load of 1761 bbls. 10/6/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM Continued flow testing and cleaning up well. As of 0600 hours 10/6/2006 well producing 4.3 mmcfd, 256 bwpd, with a FTP of 1130 psig and estimated FBHP at module 9 of 1590 psig. Well still slugging occasionally with fine sand. Cumm water recovery = 3347 bbls or 190% of frac total load of 1761 bbls. 10/7/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM Continued flow testing and cleaning up well. As of 0600 hours 10/7/2006 well producing 4.4 mmcfd, 342 bwpd, with a FTP of 1140 psig and estimated FBHP at module 9 of 1590 psig. Well still slugging occasionally with fine sand. Cumm water recovery = 3653 bbls or 207% of frac total load of 1761 bbls. 10/8/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM Continued flow testing and cleaning up well. As of 0600 hours 10/8/2006 well producing 4.0 mmcfd, 256 bwpd, with a FTP of 1100 psig and estimated FBHP at module 9 of 1570 psig. Well still slugging occasionally with fine sand. Cumm water recovery = 3975 bbls or 226% of frac total load of 1761 bbls. 10/9/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM Continued flow testing and cleaning up well. As of 0600 hours 10/9/2006 well producing 4.1 mmcfd, 342 bwpd, with a FTP of 1110 psig and estimated FBHP at module 9 of 1575 psig. Well still slugging occasionally with fine sand. Cumm water recovery = 4264 bbls or 242% of frac total load of 1761 bbls. Printed: 10/16/2006 10:24:32 AM • • Marathon Oil Company Page 5 of 5 Operations Summary Report Legal Well Name: CANNERY LOOP UNIT 11 Common Well Name: CANNERY LOOP UNIT 11 Spud Date: 4/27/2006 Event Name: ORIGINAL COMPLETION Start: 5/22/2006 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From..- To Hours Code Code Phase Description of Operations 10/10/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM Continued flow testing and cleaning up well. As of 0600 hours 10/10/2006 well producing 4.2 mmcfd, 256 bwpd, with a FTP of 1095 psig and estimated FBHP at module 9 of 1590 psig. Well still slugging occasionally with fine sand. Cumm water recovery = 4522 bbls or 257% of frac total load of 1761 bbls. 10/11/2006 06:00 - 08:03 2.05 FLOW_ TEST CMPSTM Continued flow testing and cleaning up well. As of 0830 hours 10/10/2006 well producing 4.2 mmcfd, 299 bwpd, with a FTP of 1105 psig and estimated FBHP at module 9 of 1590 psig. Well still slugging occasionally with fine sand. Cumm water recovery = 4552 bbls or 258% of frac total load of 1761 bbls. i li i _. 08:03 - 18:00 9.95 __ RURD OTHR CMPSTM Turn well over to production and RD well testers. i i Printed: 10/16/2006 10:24:32 AM ,-.~~ .. ~1~~~~. ~i~ a~.d ~~~ ~~~~z~~#~~~ ~~~~~~~i~ 333 ~~"~~t'`n ~~'~nu.~, Su~t~ ~j~~ ~11aT9.°; {~~7~ ~7~-~~ i~ ~~jC ~~~~~~f~S~~~ the information contained in this fax is arrrerd below. /~hs ~eade 9®~fhisrtrar~s~i~a! page isanot rzyrewed irtitia!!y by only the irtdrvrdua! n ttre intended recipient or a representative f th s+ fax da ~ the~~rrfsrma~ on canta~nedoheresnhist any review, dissemination or capyrng o laaSe lartmediate/y notify the sander by prahi,bited. !f yaca have received this fax in error, p telephone and rztvrra this fax to the sander at the abovE address. Thank yo~- 4~. ~= rorss : An ~I~T4 ~ -~ Phone ~: Subject: ~O(o~I~L ~ ~-~~~~ Message: '~'~C~~-b`J~S/~~D-d"'~ ~ G,p~ ~ ~ rw ~ - ~= ax ~: ~l~s; ~ ~n~~~ Dat9: Q //t/~/~ Pages (inciucling / / dyer sheep-: -~~ fr you do not roc°ive ail the pag°s or ^a~~° any proolems ~roith this fax. piease aii for assistance a` (507) 753-1223_ • FRANK H. MURKOWSKI, GOVERNOR 333 W. 7"' AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 James Thompson Sr. Completion Engineer Marathon Oil Company PO Box 196168 Anchorage, AK 99519-6168 Re: Kenai Cannery Loop Unit, Beluga Gas Pool, Cannery Loop 11 Sundry Number: 306-299 Dear Mr. Thompson: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DATED this~~day of August, 2006 Encl. ~("o ~05~d • M Marathon ~I:aTMOa Oil Company August 28, 2006 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/5646489 ~~cE~~~° AU G 3 p 2006 Commission Alaska Oil & Gas Cons. Anchorage Reference: Application for Sundry Report 10-403 for permit 206-058 Field: Cannery Loop Gas Field /Beluga Well: CLU 11 Dear Mr. Aubert, Enclosed please find an Application for Sundry Approvals form 10-403 for Cannery Loop well CLU 11 and associated attachments. This well has been completed cased hole with a 3.5" Excape monobore production string to surface. Request for approval is being made to perforate, fracture stimulate the 11 Excape modules placed in the well, and vent gas during the initial post fracture treatment flowback period. Should you require further information, I can be reached at 713-232-9347 / 713-296- 2730, or by a-mail at JRThompson@MarathonOil.com. Sincerely, r~o ~~ ,~ ~~ James R. Thompson Sr. Completions Engineer Enclosures: AOGCC Form 10-403 Well bore Diagram Description Summary of proposal Request for approval to vent gas JRT STATE OF ALASKA . ~~~~ AL OIL AND GAS CONSERVATION COM~ION ~(~~J~(~ AEG 3 ~ 2~Ob `b~, APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Alaska Oil & Gas Cans. Commission 1. Type of Request: Abandon Suspend Operational shutdown Perforate ~ Waiver chorage Other Alter casing ^ Repair well ^ Plug Pertorations ^ Stimulate 0 Time Extension ^ Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: MARATHON OIL COMPANY Development ^~ % Exploratory ^ 206-058 ~ 3. Address: Stratigraphic ^ Service ^ 6. API Number: P.O. BOX 196168, ANCHORAGE ,AK 99519-6168 50-133-20559 / 7. KB Elevation (ft): 9. Well Name and Number: Height above GL (21' AGL) 56 feet CANNERY LOOP 11 8. Property Designation: 10. Field/Pools(s): ADL - 324602 CANNERY LOOP UNIT, 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): 9305' 7915' 9247' l 7856' NA NA Casing Length Size MD ~ TVD Burst Collapse Structural Conductor 115 20" 136 136 2840 1500 Surface 1581 13 3/8" 1602 1489 5020 2260 Intermediate 5574 9 5/8" 5595 4355 5750 3090 Production 9263 31/2" 9284 7893 10160 10540 Liner Perforation Depth MD (ft): ` Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): Thirteen int. 6593'-9106'. Thirteen int. 5222'-7716'. 3-1/2" L-80 9284' Packers and SSSV Type: Packers and SSSV MD (ft): N/A N/A 12. Attachments: Description Summary of Proposal ~ 13. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ ~ Development ^~ Service ^ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: /28/ 006 Oil ^ Gas ^~ Plugged ^ Abandoned ^ 16. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name James R. Thompson Title Sr. Completions Engineer Signature ~ Phone 713-232-9347 Date 8/28/2006 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: .~ p~ Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other. Subsequent Form Required: ~ C7 A d b APPROVED BY ~ ~~ O~ t COMMISSIONER THE COMMISSION D pprove y: . a e: Form 10-403 Revised 07/2005 v 6 \~ a ~~~,~~ F~D~S ~Ft., S~~' ~ 12006 / Submit in Duplicate CLU 11 Fracture Stimulation Desription Summary of Proposal Cannery Loop 11 was drilled and cased as a 3.5" Monobore Excape completion containing eleven Excape perforating modules. Each module will complete a different production interval with ten feet of perforations followed by individual fracture stimulations in each interval. Fracture stimulation operations will commence with the perforating and treatment of Module 1 followed by modules 2 through 11. All fracture stimulation operations are typically concluded in one day, unless screenouts occur. After all treatments have been performed, coiled tubing will be utilized to cleanout the wellbore of module isolation flappers and frac proppant to PBTD. The well will then be jetted in with nitrogen via the coil tubing. Once the well is flowing on its own, coil tubing will be pulled from the well and rigged down. Well testing operations will then commence and continue until an acceptable gas rate is acheived and produced frac water load volumes are at manageable levels. Once well is adequately cleaned up, well testing equipment will be rigged down and the well will be turned over to production. Request for Approval to Vent Gas Due to the nature of such fracture stimulations, large amounts of water are injected, along with the fracture proppant, that will have to be unloaded and cleaned up during the post fracture flowback/testing period. This unloading, or cleaning up period, requires the well to be vented to atmosphere until enough gas volume is achieved to flow the well into the high pressure sales gas system. The duration of this venting operation can last as little as a few hours up to a number of days based upon reservoir pressures, permeability, well performance, tubing size, and fracture placement success. For Marathon's gas well operations in the Cannery Loop Gas Field, typical vent times are less than 24 hours. However, due to the uncertainty of exactly how long CLU 11 will be required to vent to atmosphere, this request is for a maximum vent period of 48 hours with a maximum vent volume during that period of 4 MMCF of methane gas. This volume is minimized due to the utilization of the Excape completion process which enables all intervals of interest to be fracture treated on the same day and unloaded together at one time, instead of multiple frac days with multiple flowback periods each requiring the venting of gas. If you have any questions regarding this gas venting request, please get in touch with the contact person indicated on the Form 403. • API: 50-133-20559-00 RT-GL: 21.00' RT-THF: 21.70' 2491' FSL, 2291' FWL, Sec. 4, TSN, R11W, S.M. Tree cxn = 4-3/4" Otis TOC (est.) - 500' above 9-5/8" shoe Excape Svstem Details - Ceramic flapper valves below each module as follows: Flappers MD (RKBL Module 1 - NA Module 2 - 8640' Module 3 - 8530' Module 4 - 8418' Module 5 - 8240' Module 6 - 7960' Module 7 - 7900' Module 8 - 7715' Module 9 - 7498' Module 10 -7399' Module 11 -6618' CLU-11 - 11 Excape modules placed - Green control line fired module 1 - Yellow control line fired modules 2 thru 7 - Red contol line fired modules 8 thru 11 -Ceramic flapper valves below each module except for module 1 Perfs MD (RKB( Beluga Zones Module 1 - 9096' - 9106' Module 2 - 8615' - 8625' Module 3 - 8506' - 8516' Module 4 - 8395' - 8405' Module 5 - 8216' - 8226' Module 6 - 7936' - 7946' Module 7 - 7876' - 7886' Module 8 - 7691' - 7701' Module 9 - 7474' - 7484' Module 10 - 7375' - 7385' Module 11 - 6593' - 6603' Well Name & Number: CLU - 11 Lease: Cannery Loop Gas Field County or Parish: Kenai StatelProv. Alaska Country: USA Perforations (MD) See Above (TVD) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completion Fluid: 6% KCL Dated Completed: 9/28/2006 Prepared By: J. R. Thompson Last Revison Date: 8/24/2006 a M MwRwrNOw Drive Pipe: 20", 131 ppf, X-52, to 136' RKB ;! ~ Surface Casino: 13-3/8", 68 ppf, L-80, BTC .. @ 1602' RKB, Cmt w/ 228 bbls / 516 sx. of Type 1 at 12.0 ppg. Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 5595' RKB. Cmt w/ 35.6 bbl (95 sx) of class G lead @ 12.5 ppg and 49 bbls (237 sx) Class G tail @ 15.8 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9284' RKB. Cmt w/ 1550 sx (325 bbls) of class G at 15.8 ppg TD - 9305' PBTD - 9247' Marathon MARATHON Oil Company July 12, 2006 Attention: Howard Oakland Alaska Oil & Gas Conservation Commission 333 W. 7`~' Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon Cannery Loop Unit #1 Well Data CONFIDENTIAL Alaska Asset Team Northern Business Unit P.O. Box 3128 Houston, TX 77253 Telephone T13-296-2384 Fax 71399-8504 FEDERAL EXPRESS Enclosed are the following CONFIDENTIAL digital data for the above referenced well: Precision Log Data ,~ ! EIE<z484637~1octed.dpk 2484637-MAIN.Ias Epoch Mud Log Data '~'CLU11_DD.pdf t` CLU 11_~ P+~.pdf u~ CLU 11 Fnal.las Please indicate your receipt of this data by signing below and returning one copy to me at the LETTERHEAD address or fax to me at 713-499-8504. Thank you, ~~ Kaynell Zeman Geological Technician Enclosures /. Received by: / ' 1~ ~~ Date:~~ /~~~ M Marat on MARATHON Oil Company July 12, 2006 Attention: Howard Oakland Alaska Oil & Gas Conservation Commission 333 W. 7~' Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon Cannery Loop Unit # 1 Well Data CONFIDENTIAL • Alaska Asset Team Northern Business Unit P.O. Box 3128 Houston, TX 77253 Telephone 713-296-2384 Fax 71399-8504 FEDERAL EXPRESS Enclosed are the following CONFIDENTIAL digital data for the above referenced well: Precision Log Data ~f 2484637~1otted.c$~k f ;~ 2484637-MAIN.Ias V Epoch Mud Log Data `CLU11_DD.pdf '"-CLU11 DD_TVD.pdf ''--CLU11 ML MD.pdf "CLU11_ML_ND.pdf CLU 11_Final.las Please indicate your receipt of this data by signing below and returning one copy to me at the LETTERHEAD address or fax to me at 713-499-8504. Thank you, Kaynell Zeman Geological Technician Enclosures Received by:~~~/`~' 2o~-asks ~ 139~~ • ~' ~" ara =' MARATHON 1 May 24, 2006 Alaska Oil & Gas Conservation Commission Attn: Howard Oakland 333 W. 7`l' 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: 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. CLU 8 ~.:' du~_dir ao~cc.dat clu8_vectardepth.las EMAIL_Clu-8~plotted2. dpk CLU 9 <• clu9_dir_aogcc.dat clu9_reeves_field.las ~E-MAIL Marathon_CLU 9.dpk CLU 10 ~ a4-, ~~ clu_10_dir_aogcc, dat L-J CLU10_MAINDEPTH.Ias ~UZProgram Files_Reeves_WLS 7.00_Daka_Marathon_CLU 10_MFT_cam.dpk ~UZProgram Files_Reeves_WL5 7.00_Data_Marathan_CLU l0~lotted.dpk CLU 11 ~ o ~ - , ~,° ~' ~ 3 c` ~, •~ ~~ 5. clu_l i_dir aogcc.dat du_l i~rec_las.las clu_11.~rec_las_tvd.las CLU11 TVD.Ias ~CLU11 MD.las Data Marathon_CLU ll~lotted.dpk Alaska Asset Team Northern Business Unit Alaska Oil & Gas Association CLU 8, 9, 10, 11 Well Data May 24, 2006 Page 2 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 Kaynell Zeman Geological Technician Received by: Date: ~ ~~ 1 ~ ~'1 ~~ ~p Enclosures RE: CLU 11 Subject: RE: CLU 11 From: "Tank, Will" <wjtank@marathonoil.com> Date: Mon, 24 Apr 2006 06:34:04 -0500 To: Winton Aubert <wnton_aubert@admin.state:ak.us> CC: "Berga, Pete" <pkberga@marathonoiLcom> Winton, You are correct on the form 10-401. I missed that. It should be the standard 3 112" EXCAPE cornpletian. I've attached the form, corrected, with a signature for you. If you need the original, please let me know. I'll send it up to you. I'm fine with the higher test pressure. As you are aware, we always use the same BOP stack, rated to 5,000 psi, so testing higher is no problem. Please note that we are using our "standard" BOP configuration for EXCAPE. This configuration has the bottom single ram taken out of the stack to provide enough room for working below the BOP when the EXCAPE completion is being tied into the wellhead. As you have instructed in the past, we don't need to ask for a waiver on this for every job, but I wasn't sure if bumping the BOP test to 3,500 psi would put us above the automatic waiver. If so, by this a-mail, I would formally like to request a waiver from 20 ACC 25.035 (e) (1) (b), based on the reason given above. After review of the permit and approval, could someone from your office contact Pete Berga (565-3032) or Betty Veldhuis (565-3077) in our Anchorage office. They will pick up the permit from your office. Thanks, Will From: Winton Aubert [mailto:winton_aubert@admin.state.ak.us] Sent: Friday, April 21, 2006 6:24 PM To: Tank, Will Subject: CLU li Will, For CLU 11, (1) production casing is listed as 5-1/2" on the 10-401 but calculations are based on 3-1/2", and (2) considering the MASP, I believe you should test BOPE to about 3500 psi. Otherwise, there should be no problem accommodating your start date. Thanks, Winton Aubert AOGCC 907 793-1231 ___ ____ _ _ - :_-__------- --_ i~~- Content-Description: CLU 11 Form 10-401.ZIP CLU 11 Form 10-401.ZIP~j Content-Type: application/x-zip-compressed I~ Content-Encoding: base64 4/24/2006 7:47 AM 1 of 1 i % ~ - ,~ ~~d 1 3 ~ 9 ~, ~ , j d ~ t1 A a ~ ~ A ( ~ ~~~ ~ ~ ~ ~ ~~~ ~ ~ ~'~'~ ~% FRANK H. MURKOWSKI, GOVERNOR 1 gLLASSA OIL A11TD G~5 ~ ~T~+ tt~~tt~~r 1aT 9' 333 W. 7"' AVENUE, SUITE 100 CO1st7~RQ~iIO~ CQ~IISSI01` y~ ANCHORAGE, ALASKA 99501-3539 ~ PHONE (907) 279-1433 FAX (907) 276-7542 Willard Tank Advanced Senior Drilling Engineer Marathon Oil Company PO Box 3128 Houston, TX 77253 Re: Cannery Loop Unit, Cannery Loop Unit Beluga Gas Pool, CLU 11 Marathon Oil Company Permit No: 206-058 Surface Location: 2491' FSL, 2291' FWL, SEC. 4, TSN, R11W, S.M. Bottomhole Location: 169' FSL, 730' FEL, SEC. 5, TSN, R11W, S.M. Dear Mr. Tank: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been. issued. In addition, the Commission reserves the right to withdraw the permit 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 permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). C DATED this~ay of April, 2006 N cc: Department of Fish 8v Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. • • M Marathon MARATHON Oil Company April 20, 2006 Worldwide Drilling North America P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713-499-6737 °~t~.f{~ ~, ~~~ 5 Ct~ John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application Field: Cannery Loop Well: Cannery Loop Unit - CLU 11 Dear Mr. Norman ~~l~r~~. Enclosed please find the PERMIT TO DRILL application, along with the associated attachments and filing fee of $100. The intent is to drill a well in the Beluga Pool in the Cannery Loop Unit. If you require further information, I can be reached at 713-296-3273 or by a-mail at wjtank@marathonoil.com. S~in~cjer/e'~ly_, ~ Willard J. Tartik Advanced Senior Drilling Engineer Enclosures ~° STATE OF ALASKA A OIL AND GAS CONSERVATION COM~SION ~R ~~ - ' ~~ PERMIT TO DRILL 20 AAC 25.005 ~~~~ 1a. Type of Work: Drill Q Redrill ^ Re-entry ^ 1b. Current Well Class: Exploratory ^ Development Oil ^ Stratigraphic Test ^ Service ^ Development Gas ^ Multiple Zone ^ Single Zone Q 1c. Specify if well is propoged for: 11#Sw'® Coalbed Methane ^ Gas Hydrates ^ Shale Gas ^ 2. Operator Name: Marathon Oil Company 5. Bond: Blanket ^ Single Well ^ Bond No. 5194234 11. Well Name and Number: CLU 11 3. Address: P.O. Box 3128, Houston, TX 77253 6. Proposed Depth: MD: 9,418 TVD: 8,056 12. Field/Pool(s): Cannery Loop Unit 4a. Location of Well (Governmental Section): Surface: 2,491' FSL, 2,291' FWL, Sec. 4, T5N, R11W, S.M. / 7. Property Designation: ADL 324602 Beluga Pool Top of Productive Horizon: 282' FSL, 583' FEL, Sec. 5, T5N, R11 W, S.M. 8. Land Use Permit: 13. Approximate Spud Date: April 27, 2006 Total Depth: 169' FSL, 730' FEL, Sec. 5, T5N, R11 W, S.M. ~ 9. Acres in Property: 428 14. Distance to Nearest Property: 313 ft (ADL 60568) 4b. Location of Well (State Base Plane Coordinates): Surface:x - 280,663.583 y - 2,396,065.617 Zone - 4 10. KB Elevation (Height above GL): (21' AGL) 56 feet 15. Distance to Nearest Well Within Pool: 1,890 ft to CLU 7 16. Deviated wells: Kickoff depth: 500 feet Maximum Hole Angle: 43.811 degrees 17. Maximum Anticipated Pressures in psig (see 20 "25.035) Downhole: 3,770 Surface: 2,964 1 18. Casing Program: Specifications To p -Setting Depth -Bottom _. ement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" 133 L-80 PE 115' 0' 0' 136' 136' 16" 13 3/8" 68 L-80 BTC 1,586' 0' 0' 1,607' 1,500' 508 sacks 12 1/4" 40 L-80 BTC 5,603' 0' 0' 5,624' 4,406' 307 sacks 8 1/2" 17 L-80 BTC 9,397' 0' 0' 9,418' 8,056' 1,650 sacks 3 -'~s" 19. WG~ PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee ~ BOP Sketch Q Drilling Program Q Time v. Depth Plot ^ Shallow Hazard Analysis ^ Property Plat ~ Diverter Sketch ^~ Seabed Report ^ Drilling Fluid Program Q 20 AAC 25.050 requirements ^ 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Printed Name Willard J. Tank Title Advanced Senior Drilling Engineer Signature Phone 713-296-3273 Date April 20, 2006 Commission Use Only Permit to Drill Number:.2© API Number: 50- ,~ 3 ~ z~,ss Permit A prova Date: ~ . See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: Samples req'd: Yes^ Mud log req'd: Yes^ No~ T~eS ~ ~ ~ ~ ~ '~"0 3 $t~ [9 ~ S G . HZS measures: Yes^ No ectional svy req'd: Yes No^ P V D BY THEC~OMMISSION DATE: ~'~ ~~ v~ ` OMMISSIONER Form 10-401 Revised 12/2005 U K ~ ~ I ~~ ~ L ... V Submit in Duplicate • • / ~ MARATHON MARATHON OIL COMPANY DRILLING PROGRAM Cannery Loop Unit CLU 11 Original 4/20/06 Originator: W.J. Tank Drilling Superintendent: P.K. Berga North America Drilling Manager: B.J. Roy Page 1 of 13 • • 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 ............................................................................................................................................ ..9 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 Bit Summary .......................................................................................................................................................................... 12 Hydraulics Summary ............................................................................................................................................................. 12 Formation Integrity Test Procedure ....................................................................................................................................... 13 Page 2 of 13 • ~ General Well Data Well Name CLU 11 Lease/License Surface Location 2,491' FSL, 2,291' FWL, Sec. 4, T5N, R11W, S.M. WBS Code DD.06.13512.CAP.DRL Slot/Pad CLU Pad 3 Field Cannery Loop Unit Spud Date 04/27/06 (est.) KB Elev. 56 County/Province Kenai Peninsula API No. Ground Level Elev. 35 State /Country Alaska Well Class Development Perm. batum KB Total MD 9,418' Rig Contractor Glacier Drilling Water Depth N/A Total TVD 8,056' Rig Name #1 Water Protection Depth Comments: Geologic Program Summary Formation MD -RKB (ft) TVD -RKB (ft) Pore Pressure (psi) Pore Pressure (ppg) Lithology Possible Fluid Content Sterling A-8 (Not a Prod Target) 5,239 4,121 6.73 Sandstone Gas /Water Sterling B-2 (Not a Prod Target) 5,643 4,421 6.73 Sandstone Gas /Water Sterling C-1 (Not a Prod Target) 6,358 5,031 6.73 Sandstone Gas /Water Upper Beluga (Primary Target) 6,552 5,211 4.04 Sandstone Gas Middle Beluga (Primary Target) 7,227 5,866 4.04 - 8.85 Sandstone Gas Lower Beluga (Primary Target) 7,963 6,601 9.00 Coal, Silt, Shale Gas Tyonek (Not a Prod Target) 9,178 7,816 6.73 Sandstone Gas /Water Comments: Surface Location Coordinates From Lease/Block Lines 2,491' FSL, 2,291' FWL, Sec. 4, T5N, R11W, S.M. Latitude 60° 33' 10.707" N Longitude 151 ° 13' 7.001" W UTM North (Y) 2,396,065.617' UTM East (x) 280,663.583' Tolerance Depth Horizontal Displacement (ft) MD TVD +N/-S +E/-W Tolerance. Directional Target (ft) (ft) Location (Y} (X) (ft) Upper Beluga 6,526 5,186 282' FSL, 583' FEL, Sec. 5, T5N, R11W, S.M. -2,209 -2,874 Circle 250' radius Middle Beluga 7,943 6,581 169' FSL, 730' FEL, Sec. 5, T5N, R11W, S.M. -2,322 -3,021 Circle 250' radius Comments: Page 3 of 13 • • Summary of Potential Drilling Hazards Hazard Event Discussion Lost Circulation in Low Pressure Sterling and Belu a sands Control losses by using sufficiently sized LCM, including fibrous and calcium carbonate types. 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 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 +/- 5,239 MD (4,12.1' TVD) to total depth of the well. These sands will run from highly depleted to slightly above normal pressure. Lost circulation and differential sticking are potential hazards in some of the Sterling and Beluga sands. The Flo-Pro mud system that will be used to drill the well will help reduce these risks and lost circulation materials will be on location. Weighting material will available on location for proper well control.. Formation Evaluation Summary Interval LWD Electric Logs Mud Logs Surface None None None 0' - 1,607' MD Intermediate None None Basic with GCA, shale density, temperature in and out, 1,607' - 5,624' MD sample collection (10' samples). Production None Reeves Quad Combo with pressures 5,624' - 9,418' MD through pipe. Pull GR-Neutron to tie into Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Intermediate run. Completion N/A GR, CCL N/A Coring Requirements: None Comments: Page 4 of 13 Drilling Program Summary CONDUCTOR: 1. Drive 20" conductor to +/-130 ft. RKB. 2. Move in and rig up rotary drilling rig. 3. Install starting head 20" SLC x 21 1/4", 2M flanged. 4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and 16" diverter line. 5. Function test diverter and diverter valve. / SURFACE: 1. Drill a 16" hole to 1,607' MD (1,500' TVD) per the directional plan. 2. RIH with 13 3/8° casing and hang off in the elevators. Make up stab-in sub and centralizer on 5" drill pipe. TIH with inner string and latch into stab-in float collar. Cement 13 3/8° casing./Sting out, shear out drill pipe wiper plug, and circulate drill pipe clean. TOOH with inner string. 3. Cut off 13 3/8" casing. ND diverter. 4. Install 13 3/8" slip lock connection X 13 5/8" 5M flanged multibowl wellhead. j 5. NU 13 5/8" 5M BOP'S. Test BOP'S and choke manifold to 250/3960'psi. 6. Set wear bushing. 35nd 7. Test surface casing to 3,000 psi. ~'~ INTERMEDIATE: 1. PU 12 1/4" Bit and BHA. Drill out float equipment and make 20' of new hole. CBU. 2. Test shoe to leak off. Estimated EMW is 14.7 ppg. 3. Drill 12 1/4" directional hole to 5,624' MD (4,406' TVD) as per directional program, short tripping as necessary (1,000' or 24 hours, but can be extended depending on hole conditions). 4. At TD circulate hole clean. Make wiper trip. TOOH and lay down BHA. Pull wear bushing. / 5. Change out variable pipe rams with 9 5/8" casing rams. Run test plug and test casing rams to3;66II psi. 6. Run and cement 9 5/8" casing. Land hanger in multibowl wellhead. g5ao ~~ 7. Back out landing joint. Change out 9 5/8" casing rams with variable pipe rams. Run test plug and test rams to 250/3sA80~'psi. 8. Set wear bushing. Test casing to 3,000 psi. 3500 v-~~- PRODUCTION: 1. Drill float equipment and 20' of new formation w/ 8 1/2" bit. CBU. 2. Test shoe to leak off. Estimated EMW 14.7 ppg. 3. Drill 8 1/2" hole to approximately 9,418' MD (8,056' TVD) per the directional program, short tripping as necessary (1,000' or 24 hours, but can be extended depending on hole conditions). 4. At TD circulate hole clean. Make wiper trip. TOOH. 5. RU Precision. Run open hole logs as per plan. RD logging company. 6. TIH w/ 8 1/2" bit to TD for wiper trip. TOOH to 9 5/8" shoe and circulate until log evaluation is complete for picking EXCAPE ~ modules. After i s are made, trip to TD and circulate clean. TOOH and laydown BHA and drill pipe. Pull wear bushing. 7. RU and run 1/2" XCAPE casing string. RU logging company to correlate EXCAPE modules to open hole logs. RD logging company. 8. Cement 3 1/2" casing while reciprocating. Bump plug with 500 psi over displacement pressure. WOC. 9. PU 3 1/2" casing. PU BOP stack. Run control and electric lines out tubing head outlet. Set slips. Cut 3 1/2" casing. 10. LD BOP. Set 3 1/2" packoff. NU 13 5/8" 5M X 3 1/8" 5M tubing head adapter and 3 1/8" 5M tree. Test tree to 5,000 psi. 11. Rig down and move out drilling rig. Note: Drill all hole sections with 5" drillpipe. Final core points will be determined by Geology. 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 13 • Casing Program MD (tt) Connection API Ratings Casing Makeup ~ ,= o ~, Size Weight ~ O. D. Torque Hole Size m' 8 0 8 ~ v (in) Top Bottom (IbsHt) Grade T e (in) (tt-Ibs) (in) v ~ 133/8 Surface 1,607 68 L-80 BTC 14.375 N/A" 16 5,020 2,260 1,545 9 5/8 Surface 5,624 40 L-80 BTC 10.625 N/A' 12 1/4 5,750 3,090 979 31/2 Surface 9,418 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. Casing Design Casing Shoe Safety Factors Casing Size (in) Weight (Ib/tt) rade Setting Depth (TVD) Mud Wt When Set (Ib/gal) Frac. Grad (Ib/gal) Form Press (Ib/gal) Maximum Surface Pressure (psi} ~ m' o, ~ U o c ~ 13 318 68 L-80 1,500 9.0 14.7 8.5 1,036 3.18 3.23 3.59 9 5/8 40 L-80 4,406 9.5 14.7 8.6 2,964 1.62 1.42 2.48 31/2 9.3 L-80 8,056 10.0 15.0 9.0 6 1.13 2.52 1.30 Comments: Max overpull on the 3 1/2" casing must be limited to 92,000 Ibs. Maximum Anticipated Surface Pressure ~.. Casing Size (in) Setting Depth TVD (ft) MAWP * (psi) MASP ** (psi) Mud/Gas Ratio 13 3/8 1,500 3,459 1,036 0/100 9 5/8 4,406 3,910 2,964 0/100 31/2 8,056 6,903 ,96 0/100 MAWP =Maximum allowable working pressure *" MASP =Maximum anticipated surface pressure Comments: Page 6 of 13 • MASP /MAWP CALCULATIONS: Surface casing: 13 3/8" (1.607' MD. 1.500' TVD) L~ MASPfrac =((Fracture gradient at shoe + S.F.) x .052 x NDsnce) -Hydrostatic pressure of gas column at the shoe. MASPfrac = (14.7 ppg + 0.5 ppg) x .052 x 1,500' - (.1 psi/ft x 1,500') MASPfrac = 1,186 psi - 150 psi MASPfrac = 1,036 psi. MASPbnP = BHPcPe„ ncia m -Hydrostatic pressure of a gas column MASPbnP = (8.6 ppg x .052 x 4,406') - (0.1 psi/ft x 4,406') MASPbnP = 1,970 psi - 441 psi MASPbnP = 1,529 psi MASP =MASPfrac = 1,036 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 5,020) - (9.0 - 8.3) x .052 x 1,500' MAWP = 3,514 psi - 55 psi = 3,459 psi Intermediate casing: 9 5/8" (5.624' MD. 4.406' TVD) MASPfrac =((Fracture gradient at shoe + S.F.) x .052 x TVDsnca) -Hydrostatic pressure of gas column at the shoe. MASPfrac = (14.7 ppg + 0.5 ppg) x .052 x 4,406' - (.1 psi/ft x 4,406') MASPfrac = 3,483 psi -441 psi MASPfrac = 3,042 psl. MASPbnP = BHPcpen Hole fd -Hydrostatic pressure of a gas column MASPbnP = (9.0 ppg x .052 x 8,056') - (0.1 psi/ft x 8,056') MASPbnP = 3,770 psi - 806 psi MASPbnP = 2,964 psi .t MASP =MASPbnP 2,9~psi ,~ MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 5,750) - (9.5 - 9 x .052 x 4,406' MAWP = 4,025 psi -115 psi = ,91 psi Production casing: 3 1/2" (9.418' MD. 8.056' ND) MASPfrac =((Fracture gradient at shoe + S.F.) x .052 x TVDsnca) -Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg + 0.5 ppg) x .052 x 8,056' - (.1 psi/ft x 8,056') MASPfrac = 6,493 psl - 806 psi MASPfrac = 5,687 psi. MASPbnP = BHPoPan nciatd -Hydrostatic pressure of a gas column MASPbnP = (9.0 ppg x .052 x 8,056') - (0.1 psi/ft x 8,056') MASPbnP = 3,770 psi - 806 psi MASPbnP = 2,964 psi MASP =MASPbnP = ,964,tisi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x ND MAWP = (0.7 x 10,160) - (10_0~~~5~, x .052 x 8,056' MAWP = 7,112 psi - 209 psi - 90/3~.psi Page 7 of 13 • • BOPE Program Casing Test Test Casing Test Fluid Pressure Size MAWP MASP Press Density BOPS LowMigh Casing (in} (psi} (psi) (psi} (Ib/gal) Size & Ratin 9 (psi) (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Surface 13 3/8 3,459 1,036 3,000 9.0 (1) 13 5/8" 5M blind ram 250/3,989 ~m (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets {1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Intermediate 9 5/8 3,910 2,964 3,000 9.5 (1) 13 5/8" 5M blind ram 250/3s980" (1) 13-5/8" 5M drilling spool with 3-1/8" 5M 3500 outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Production 3 1/2 6,903 2,964 3,000 10.0 (1) 13 5/8" 5M blind ram 250/3,~968~' 3S~ (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets Comments: Blowout Preventers 1 The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-1/8" x 5000 psi outlets. -L 3 The choke manifold will be rated 3-1/8" x 5000 psi. It wilt include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor-boy gas buster, and avacuum-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. WGi1'" wt Gq- Page 8 of 13 • • Wellhead Eauipment Summary Component Description Casing Hanger Type Casing Head 13-5/8" 3M X 13-3/8" Slip Loc W/ 2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL1, 13 5/8" x 9 5/8" Fluted PR1 Mandrel Tubing Head 13-5/8" 3M Studded Bottom X 13-5/8" 5M Flg Top, W/ 2, 2-1116" 5M Studded Outlets, 13 5/8" x 3 1/2" Manual U,AA,PSL1,PR1 Slip Adapter Flange 13-5/8" 5M X 3-1/8" 5M W/ Seal Pocket and 3" H BPV Threads Comments: Control lines and electric cable for the EXCAPE system will be routed through the tubing head side outlet. ~ Directional Program Summary Build Turn ~ Coordinates Sec. No. Description MD (ft) TVD (ft) Rate (°/100') Rate (°/100') Dogleg (°/100') Inclination (deg) Azimuth (deg) +N/_S (tt) +E/_W (g) VS (tt) 1 Tie On 0 0 0 0 0 0 232.455 0 0 0 2 KOP 500.00 500.00 0 0 0 0 232.455 0 0 0 3 Build up Section 4.00 0 4.00 232.455 4 End of Build 1,595.27 1,491.61 4.00 0 4.00 43.811 232.455 -242.98 -316.14 398.73 5 Hold Section 0 0 0 43.811 232.455 6 End of Hold 5,371.65 4,216.77 0 0 0 43.811 232.455 -1,836.11 -2,388.95 3,013.04 7 Drop Section -2.00 0 2.00 232.455 8 End of Drop 7,562.18 6,200.00 -2.00 0 2.00 0.00 232.455 -2,322.08 -3,021.24 3,810.50 9 TD 9,418.18 8,056.00 0 0 0 0.00 232.455 -2,322.08 -3,021.24 3,810.50 Comments: Vertical section calculated from a reference azimuth of 232.45° taken from surface location to bottom hole location. Potential Well Interference: Well Distance (tt) Depth (MDR CLU 3 149.09 Surface CLU 4 163.58 500 No serious interference exists. See attached directional plan and anticollision analysis for more details. Page 9 of 13 • • Directional Surveying Summary Interval MWD Survey Magnetic Multishot Gyro Multishot Comments 0 - 1,607' X 1,607' - 5,624' X 5,624' - 9,418' X Comments: Drilling Fluid Program Summary Interval - TVD Minimum Inventory From To Density Gel (ft) (ft) (Ib/gal) Fluid Description Additives Viscosifier Barite Gel, Gelex, Soda Ash, Caustic, Barite, 0 1,500 8.6 - 9.4 Gel / Gelex Spud Mud Polypac Supreme UL Flo-Vis, Polypac Supreme UL, KCI, SafeCarb 1,500 4,406 9.1 - 9.5 6% Flo-Pro w/ Safecarb 10 & 40, Barite, Caustic, Conqor 404, Sodium Meta Bisulfate, Lubetex Flo-Vis, Polypac Supreme UL, KCI, SafeCarb 4,406 8,056 9.1 -110.0 6% Flo-Pro w/ Safecarb 10 & 40, Barite, Caustic, Conqor 404, Sodium Meta Bisulfate Comments: See mud prognosis for details. The mud system from the intermediate section will be utilized in the production hole section instead of building a new mud for that section. Sized CaCO3 (SafeCarb) will be used to control leakoff. Page 10 of 13 ~ • Drillina Fluid Specifications Interval - TVD LSRV From (ft) To (ft) Density (Ib/gal) Vis (seGgt) 1 min (Ib./100ftz) PV (cP) YP (Ib/700 ftz} Fluid Loss (cc) pH Drill Solids (%) 0 1,500 8.6 - 9.4 60 - 100 N/A 25 - 35 NC - 12 +/- 9.5 < 7 1,500 4,406 9.1 - 9.5 30,000 + 8 - 12 7 - 9 +/- 9.5 < 7.5 4,406 8,056 9.1 - 10.0 30,000 + 10 - 14 6 - 8 +/- 9.5 +/- 5 Comments: As a standard practice for long string completions, the drilling mud that will remain above the top of cement on the 3 %" production casing will be treated with corrosion inhibitor (Congor 303A) at a concentration of 1 drum per 100 barrels of drilling fluid. See mud prognosis for details. Solids Control Eauipment o ~ d ~ ' ~ ~ m N j p tll _ p! N Y tC6 ~ V ~ C C ~ t ~ N ~ N ~ ~ ~ N v 7 v 7 v ~` m ^~ Interval Comments 0 - 9,418' MD X X X X Closed Loop System, Full Containment Item Equipment Specifications (quantity, desi n type, brand, model, flow capacity, etc} Shaker 2 -Swaco Mongoose PT Desander N/A Desilter 1 -Derrick Model 0522 Mud Cleaner N/A Centrifuge 2 - MI/Swaco units Cuttings Dryer N/A Cuttings Injection Marathon G&I Facility Zero Discharge N/A 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 13 Cement Program Summary De pth Gauge Top of Cement Open Casing Size (in) MD (ft) ND (ft) Hole Size (in) MD (ft) ND (ft) Ann Vol To TOC (ft3) Slurry Vol (ft3) WOC Time (hrs) Hole Excess (%) 13 3/8 1,607 1,500 16 0 0 738 1,274 8 75 9 5,624 4,406 121/4 4,700 3,732 289 439 8 40 1/ 9,418 8,056 81/2 5,100 4,021 1,429 1,930 N/A 40 Mix Water Compressive Casing Size Density Qty Yield Slurry Vol TOC MD Qty WL FW Strength (Psi) (in) Slurry Cement Description (Ib/gal) (sx) (ft3/sx) (ft3) (ft) (gal/sx) Type (cc) (%) 8 hr 24 hr 13 3/8 Tail Type 1 Cement 12.0 508 2.51 1,274 0 11.28 Fresh 812 0 196 818 9 Lead Class "G" 12.5 89 2.10 186 4,700 11.92 Fresh 273 769 Tail Class "G" 15.8 218 1.16 253 5,124 9.31 Fresh 0 0 208 981 3 1/ Tail Class "G" 15.8 1,650 1.17 1,930 5,100 4.97 Fresh 24 0 226 2,632 (~i~r(ments: See cement prognosis for details and spacer specifications. Bit Summary Interva l - MD Type Recommended Estimated From (ft) To (ft) Size (in) Manufacturer Model No. IADC WOB (kips) RPM Rotating Hours ROP (ft/hr) 0 1,607 16 Christensen MX-1 115 1 - 4 80 - 350 1,607 5,624 12 1/4 Christensen HCM 5062 M323 Up to 52 Motor 5,624 9,418 8 1/2 Christensen HCM605 M323 Up to 25 Motor Comments: If a second bit is necessary for the 12'/e" hole a MX-C3 (IADC 137) should be used to finish this section. Back up bits for the 8'/z" hole section will consist of mill tooth and TCI tricone bits. See bit prognosis for additional information. Hydraulics Summary Rig mud pumps available are shown below. Max Press @ Displacement Liner ID Stroke 90% WP 95°~ eff Max Rate Hole Sections Used Qty Make Model (in) (in) (psi) (gallstroke) (spm/gpm) On 5 8 2,597 2.04 125 / 255 Surface 3 National OiI A600PT 5 8 2,597 2.04 125 / 255 Intermediate Well 5 8 2,597 2.04 125 / 255 Production Page 12 of 13 • • Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. Hole Standpipe Min Nozzle Depth-MD Size Pump Rate Pressure AV ECD Size (ft) (in) (gpm) (psi) (fpm) (Ib/gal) (32"s) Remarks 0 - 1, 607 16 650+ 1, 500 69 3 - 18's 1-15 1,607 - 5,624 12 1/4 662 2,000 130 6 - 13's Actual Data from CLU 8 (@ 6,722' MD) 5,624 - 9,418 8 1/2 480 2,000 249 5 - 15's Actual Data from CLU 10 (@ 8,450' MD) Comments: See separate hydraulics calculations. Annular velocities in the 16", 12 %d', and 8 %" holes were calculated using 5" drillpipe. 5" drillpipe should be used to drill all hole sections to maximize hole cleaning, while minimizing stand pipe pressure. Formation Integrity 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 IADC 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 13 of 13 Marathon Oil Well CLU 11 Diverter Flow line 21 1/4" 2M Diverter ~ 16" Automatic Knife Valve ~~ Diverter Spool uu ~ u 16" Diverter Line ~ Marathon Oil Well CLU 11 BOP Stack 13 5/8" 5M Annular Preventer 13 5/8" 5M Cross Marathon Oil Well CLU 11 Choke Manifold To Gas Buster To Blooey Line Bleed off Line to Shakers • • Surface Use Plan for Cannery Loop Unit, well CLU 11 Surface location: 2,491' FSL, 2,291' FEL, Sec. 4, T5N, R11W, S.M. 1) Existing Roads Existing roads which will be used for access to CLU 11 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 11. 3) Location of existing wells Well CLU 11 will be drilled on Cannery Loop Unit pad 3. A pad drawing is enclosed that shows existing wells. 4) Location of existing and/or proposed facilities Production facilities will be re-established on Cannery Loop Unit pad 3 for CLU 11. Currently only the facility buildings exist on the pad. 5) Location of Water Supply A water supply well exists on the pad that CLU 11 will be drilled from. This is shown on the pad drawing. 6) Construction Materials No major construction is planned on the pad at this time. Leveling of the pad for this work will be done with minimal materials needed. 7) Methods of handling waste disposal; a) Mud and Cuttings Cuttings will be dewatered on location. The cuttings and excess mud will be hauled to Pad 41-18 of the Kenai Gas Field for disposal into Well KU 24-7, a Class II disposal well (AOGCC Disposal Injection Order No.9, Permit #81-176). b) Garbage All household and approved industrial garbage will be hauled to the Kenai Peninsula Borough Soldotna Landfill c) Completion Fluids Clear fluids will be hauled to Pad 34-31 of the Kenai Gas field and injected in Well WD #1, an approved disposal well (AOGCC Permit #7-194). d) Chemicals Unused chemicals will be returned to the vendors that provided them. Efforts will be made to minimize the use of all chemicals. e) Sewage The existing sewer system on the pad will be utilized. 8) Ancillary Facilities s 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 surface CLU 11 will be drilled on an existing pad. Reclamation of the pad will occur after the abandonment of CLU 11 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) Surface 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 I am familiar with the conditions that currently exist; that the statements made in this plan are, to the best of my knowledge, true and correct; and that the work associated with operations proposed herein will be performed by Marathon Oil Company and its contractors and subcontractors in conformity with this plan and the terms and conditions under which it is approved. This statement is subject to the provisions of 18 U.S.C. 1001 for the filing of a false statement. Date: 7 ~ZG U Name and Title: ~~~~(,d~.O' Willard J. Tank, dvanced Senior Drilling Engineer Marathon Oil Company P. O. Box 3128 Houston, TX 77253 (713) 296-3277 • it ~I ~ ~~ ~I _..____ x ___ ~- -~ I 2291 `'.`. I z I --~ J w ,7 ~:. O t_- U .. ~I I # I i ~. 5 4 _ _ S EC TI ON LI N E 8 9 _ _ _ _ NOTE: SECTION LINES I ARE NOT TO SCALE NOTES 1. BASIS OF COORDINATES IS U.S.C. & G.S. TRI STATION AUDRY IN A.S.P. ZONE 4. (NAD 27) AVERAGE CONVERGENCE OF POINTS SHOWN: 01°5'58". 2. AUDRY LOCATION: LAT: 60°30'50.559"N LONG: 151 ° 16'37.445"W - NORTHING = 2,382,045.42 FASTING = 269,866.75 3. BASIS OF VERTICAL CONTROL IS NGS BENCH MARK MONUMENT "KENAI", ELEVATION = 33.267 FEET (NGVD 29). 'r ~.._ -- I ~ ' -- -- _ __-- - -- - - -- ----- AS-BUILT CANNERY 1 LOOP UNIT N0.11 WELL NORTH ~1~7~ TO'T PROJECT REVISION: 1 in jv CANNERY LOOP UNIT PAD 3 DATE. <~„~D6 OII/ VV~~L \ 1 DRAWN BV: DME ~unnnari CLU 11 WELL AS-BUILT LOCATION ~~ SURFACE LOCATION DIAGRAM SCALE: 7'=60' PROJECT NO. 0630: CONSLII.~III[J Inc. ENGINEP ORI 80X 4BB SOGDOTNA, AKNG~/6TOESTING LOCATION BOOK NO. Ofi-04 MC~ne VOICE: (907)263-0216 FAX: (907)2833265 S4 T5N R11 W SEWARD MERIDIAN, ALASKA SHEET ~ OF EMAIL: SAMCLANE MCLANECG.COM r~ CLU 1 8 DIA. WELL CELLAR ASP ZONE 4 NAD27 (t' ~ ~ ~^~ N: 2396065.617 E: 280663.583 LAT: 60°33'10.707"N LONG: 151 °13'07.001 "W " FWL = 2291' E =,E_~ ~ `" FSL = 2491' E ~_~~.:.~ U ELEV = 35.3' (MSL) SECTION 4, TOWNSHIP 5N, -~ iJ7 RANGE 11 W, SM AK ~ .. r __. ~ om- i ,_ / i li TT V/ ` - - .y •, r, t ~ i ~ N ®. ,. IT ~~ 1 I , __ ~ . ° __ . _J -- ---- - . _ ____ ~ CH.P/h '~ % X X ^ L hf_ SCALE 0 60 120 ' FEET • • ' I _=o. _~_• ~. - _•` • •• +. ?s a, r. -_~ + • 'w + _ a i ^`~ ~•a *. ~' ai14 ~. ~ _ `. 13 13 ^w 1+ =vim t :-. ~ ~ ~.-' ~ .~ ~+'- # fwi9' ±-w. s~!• ~ '_:,r, _ ~..,f -"::.y, -- - ~-I }'` ~•'_ !• - A'!. ' " _ w _ 7_'~ 4- .tom-4 •'~`A .E~ i _ -~ ,- ~ - ~7~_ ~ ~i ••+ d j ~_-__-.- - ~-='w...g..-. 4a- ~ a n=``s•.-~e =c. __ ~~;~OR~~~ ~~ B(~Ij~•DAeI .} ._ "?' ~'- 11; == ~ ~T _ 3. o-?iL 'va..=i_-r_?- ~ ],_i f i - ~•+ sr _ I r_'- '~ ~ _ ~ ~'O A ~ -r _J.C j.• Jt ~_ .1:n ~ ~w.Ni - i ~ _ ^ r~ I I 1 ' .i a .'r.'-. t-~ ,. r._ 'F -~ r ~ -.., + -y.~':.. I _ '"' ^lap~... - "in-^ ~ .c y y . •„ F~'Y. ~ L+-'L-,~.~- 4 ~ I .. ~ } .:. ~. ms's- ., NFwwoba 54tan^ _ ._ ., I _,,, _ w o, I _ - w ~ 1 r . • I - - _ 3 • 2 5 t4•!l1 JL^^kt _ _ . Jv... ~+ - 4 ~ _ ~ 4 _ 1, -< s ~ -~^! ~ _A - :~ - . ~ _ ~ ..~ I ~ - _ ... sAy= ~y ° _ s. -~' A = - . y- tee-'_~' r ' - --- ~ --- _. - - -w--- - - - • ~ I - ~- _ ~ j - 1 p~4. .~. ~ -~-lt !~ 36 l 31 ~ I I /~~ 33 ~P 3~4 ~. I 1 _ !-~ iPV^ ~ _ r s N 1\ ~' •• ~ T sN'^ ~ ' a l~ ~ ' . 1 i I M'- y - ~ ~~ , i 5 ~ -+ -- -~- - -T- ~ - anne t6 --F-- -a--~~----- ~ o '~ b. '~ • I ; ,:~--- ,Pad No. 3 ~ ~ `. ~`~,-~- _' ~ ; ~~' $ h ` ••\,\ ~` ._~\ 6`f,.~, .I `: •5 ~.~' T%' - 4 _ r._ ~ ~=-^_y~ • I f `. T 5 N .\ '~r ti - ~--- - r~~ •' X755$ ~ :c--- - - +---+ _ --- "~- \ i ^~.. ; 4 1 -- Cannery Loop No.'>1 ~ ~ t ,-~= ~--'~ °°~ ! y: ~ .:.. _ - -^~ _ ~ - ~,.., r~:. _- Pad ~ --~r. ~~a~-1. a~ I I ~_ '~'~ . I a - ~,~~ ~ r ~ Via,,. I -.'• I ~ 16>r - ~aF ~ 16 -14 .~~, 13 Q.' 1 KIS/LO~~^ w-i~''~--.lea t.•'l- 7(d0_~, - a a i • ~ .j' a~ ~4" I a ~• 19 I .._ 20. .7~ }121 ''° {~ C?'t`\~ ,~ a~24~~ ~.^. I ' -9- fi.. ~ -~. I ~.. N. . is I •+- }' -., ~ i ~_ -. . ~-' I ~. , •~ x• x i !-.• o^~ i -~. .;+. .- 1 •-''. `\~~, bo' I (J \'~'ti 67pgooo 30 I 29 ~ I "' „28 I 217 ~• I ?5..- ^ _ 25 ENA~-~ ~-~.~ .w~oc M I ~ .1 • ~+*cpio•_eto~ooc.. .,ivi.-wa~~NOe,.oe.nia ~ ~ - --' 60'3Q Y ]5 so~oorn,~ ~ .1:'i 602~m•E.I 151'0730' SCALE 1:63,360 KENAI (C-4), ALASKA (1951) Marathon Oil Company Project: Cannery Loop Unit Pad No. 3 • CANNERY LOOP UNIT zaoooooF N >]90000F N ~ 2]N600pF' N l.. 1 ~.~ tJ 151 1. ~~ .J Proved Productive Area '{}y MARATHON OIL COMPANY 00 i 120 r'L F y"4'-` „, , Top U. Beluga + + + ~ ~ ,/ r • ~~ Fj _ •y:SU '' i ~ •` ~ rs. ~ + + °„ + CLU I1 + ~ ~ M,, ,~ , .' > ' jn i v _ N ,,~. + ~` ~-, + + JV .~ !° ~~~~ 17 6 L~ + ~ + o~ ~S . ~ N ~ S r r /~ /~ /~ _ 1 I _ ~I ~ _ _. GLACIER DRILLING RIG #1 ~' MUD PITS AND PUMP ROOM LAYOUT MARATHON • • .MARATHON Oil Company Locatbn: Cook Inlet, Alaska (Kerrel Pennir~s9da) Sbt: sbt #CLU-11 Fleld: ~~rY LAP UnA WeA: CLU-11 BAK~/R r NY~illif INTEQ L)ata Lane N IQ LO981 E (Iq OL8 / yg (0) Op0 Op0 0.00 Opp O.OD Opp Opp Opp -019D8 d18,% 4pD 898.79 -x9an a999ss opo mte.a -as9xp9 .9osiu zpo aebso -ma!a9 .9a¢ta~ om aevso x.09 .9os999 oro aensp e wmn / 7w Mina em vi.n., mro s O9la- u8 lee ,roe 7nr roM aew. n +.e .awe m ~wa9p9 t a m O m .s r m m F Vertical Section (tt) 9w. , 9rh - xwp rt Azimutl~ 232A5' wAh reference 0.00 N, 0.00 E from wellhead N W `~ m ~ z ~~ ~~ J ~ ^ ^ ~ i.iusiU om N3 U O~ N C Z C a O m ZY Y C N~ .~ Q Q O ~ J C Y C C Q UU~ cv o m; ~~ ~ i J 0 • Northing (ft) MARATHON -. ~ .. l -- Operator MARATHON Oil Area Cook Inlet, Alaska i (Field Cannery Loop Unit Facility Pad # 3 / 4 Projection System North Reference Scale Wellbore last revised Location lity Reference Pt 1 Reference Pt alculation method orizontal Reference Pt ertical Reference Pt D Reference Pt eld Vertical Reference Planned Wellpath Report Wellpath: CLU-11 Ver 3 Page 1 of 6 AD27 / TM Alaska State Plane, Zone 4 (5004), US feet Localcoordinates_ North [feet] East [fee 2493.43 2270.35 ~~ Minimum curvature Slot Glacier 1 (RKB) Glacier 1 (RKB) mean sea level Slot slot #CLU-11 Well CLU-11 Wellbore CLU-11 Ver 3 Generated se/Source file Grid coordinates sa ~'~~ KKR Nu~NEs INTEQ We1lArchitectTM 1.1 ~uthstud 14/12/06 at 07:23:58 JVA-Anchorage/CLU-11 Ver 3.xm1 ^I^~^~_ Geographic coordinates Latitude (°] Longitude [°] 60 33 10.625N 151 13 06.998W 60 32 46.072N 151 13 52.401 W 60 31 54.076N 151 15 37.735W sting [US feet] Northing [US f 280663.58 2396065.62 278347.08 2393615.22 272978.90 2388436.21 Glacier 1 (RKB) to Facility Vertical Datum Glacier 1 (RKB) to mean sea level Facility Vertical Datum to Mud Line Section Origin Section Azimuth 00 feet 00 feet 0 feet I.00, E 0.00 ft • • Planned Wellpath Report SA ~~~~ Wellpath: CLU-11 Ver 3 M1~6NE~i MARATHON Page 2 of 6 INTEQ [tATHON Oil Company Slot slot #CLU-11 k Inlet, Alaska (Kenai Penninsula) Well CLU-11 eery Loop Unit Wellbore CLU-11 Ver 3 #3/4 ~.LLYA'I' H llATA (10 2 stations) fi =interp olated/extr apolated st ation NID Incliuatiou Azimuth TVD V t S t N [feet] 0.00 [°) 0 000 [°] 232 455 [feet] 0 00 er ec [feet] 0 orth [feet] East [feet] Grid East [us survey feet] Grid North [us survey feet] DLS [°/100ft) Build Rate [°/100ft] Turu Rate [°/100ft] ath Comment 100.00( . 0 000 . 0 000 . 100 00 .00 0 0 0.00 0.00 280663.58 2396065.62 0.00 0.00 0.00 200.00 . 0 000 . 0 000 . 200 00 . 0 0 0 0.00 0.00 280663.58 2396065.62 0.00 0.00 0.00 300.00 . 0 000 . 0 000 . 300 00 . 0 0 0.00 0.00 280663.58 2396065.62 0.00 0.00 0.00 400 00 . 1 O 000 . __ . .00 0.00 ______0.00 280663.58 2396065.62 0.00 0.00 0.00 . . i 0.000 400.00 0.00 0.00 0.00 280663 58 2396065 62 0 00 ' 500.00 0 000 232 455 5 00 00 0 _ . , . . 0.00 0.00 ; r "~ . _ . _ . .00 j 0.00 0.00 280663 58 2396065 62 0 00 600.00 4 000 232 45 _ _ 5 599 92 __ 3 49 -_ __ ___ __ . ~ . . 0.00 0.00 700.00' . 8 000 . 232 455 . 699 35 . -2.13 -2.77 280660.78 2396063.54 4.00 4.00 0.00 800.OOj' . 12 000 . 22 455 . 797 81 13.94 -8.49 i -11.05 280652.38 2396057.33 4.00 4.00 0.00 --- - _~ _ . - _ ~ - - . ( _____ ! 2~2.455 , . p_ _ .___ -.__-- ~ 894.82 u 31.30 ___.. 55.49 ; -19.07 -24.82 _ _.__ ___.__. - __-- - ; -33.81 -44.00 ____ _ 280638.42 ~_.____ .._~ 280618.97 ! 2396047.01 ___-_-------_ __-_ 2396032 63 _ ___4.00 _ 4 00 4.00 _ ~~~ 00 = 4 ___ 0.00 ~.~; 1000 00~- 2 0 000 232 455 989 91 8 6 . _ __ . . ~.~z OAO ~ ~ 1100.00' _ . 24 000 . 232 455 . 1082 61 _ _. 6.38 12 _ _ _ -68.49 280594.13 2396014.26 4.00 4.00 0.00 1200.OOj~ ®_ . 28 000 . 232 455 . 1172 47 3.84 -75.46 -98.19 280564.02 2395991.99 4.00 4.00 0.00 1300.00 . 32 000 . 232 455 . 1259 05 167.67 2 -102.17 ~ -132.94 280528.78 2395965.93 __4.00 4.00 0.00 400.00~ . -- 36.OOOi . -_ 232.455 . 1341.94 17.66 - 273.56 -132.64 j - -166.71 -172.57 -216.90 280488.59 280 4 43.64 ; 2395936.21 2395902 96 4.00 ~ 4 00 4.00 4 00 0.00 1500.00 j' 40 000 232 455 1420 73 ~ ~ 3 -- _ _ . . . 0.00 - °;, a 1595.27 1600.00 . 43.811 43 811 . 232.455 232 455 . 1491.61 1495 03 35.12 398.73 -204.22 ; ~ -242.98 j -265.70 -316.14 280394.15 j 280343.01 2395866.37 2395828.54 4.00 j 4.00 4.00 4.00 0.00 0.00 1700.001' . 43 811 . 232 455 . 1567 19 402.01 471 2 -244.98_ ~ ` -318.74 280340.37 2395826.59 0.00 -~ 0.00 0.00 00 . 43 811 . 2 . _ - . 4 __ ___~_i -2x7,17 _ _ __.__~__I _373.6 ________ 3 _____ 280284.72 ; 2395785.43 0.00 0.00 0.00 . . 32.455 1639.36 540.47 ; -329.35 . -428.52 280229 06 1 2395744 27 0 00 ______ 1900.001' 43 811 232 455 1711 52 6 . . . 0.00 0.00 2000.00 . 43 811 . 232 455 . 1783 68 09.69 6 -371.54 -483.41 280173.40 ; 2395703.11 0.00 0.00 0.00 2100.00 . 43 811 . 232 455 . 1855 85 78.92 74 -413.73 -538.30 280117.74 2395661.95 0.00 0.00 0.00 2200.OOt . 43 811 . 232 455 . 1928 01 8.15 -455.91 -593.19 280062.08 2395620.79 0.00 0.00 0.00 eft .L . '~',°'. ~~n~.~ . r.+...~... . `: 817.38 -498.10 .. -648.07 280006.43 _... 2395579.63 0.00 0.00 n.nn Planned Wellpath Report BA r~~~ Wellpath: CLU-11 Ver 3 MIK6IR~IES MARATHON Page 3 of 6 INTEQ EtATHON Oil Company Slot slot #CLU-11 k Inlet, Alaska (Kenai Penninsula) Well CLU-11 nery Loop Unit Wellbore CLU-11 Ver 3 #3/4 ~i.i.rA i t~ Lra t A (1 02 stations) 1' =inter polated/extr apolated sta tion MD Inclination Azimuth TVD Vert Sect N h [feet] 2400.00 [°] 43 811 [°] 232 455 [feet] 2072 34 [feet] 95 ort [feet] East [feet] Grid East [us survey feet] Grid North [us survey feet] DLS [°/100ft] Build Rate [°/100ft] Turn Rate [°/100ft ath Comment 2500.OOj~ . 43 811 . 232 455 . 2144 50 5.83 102 -582.47 -757.85 279895.11 2395497.31 0.00 0.00 0.00 2600.00' . 43 811 . 232 455 . 2216 66 5.06 10 4 -624.66 -812.74 279839.45 2395456.15 0.00 0.00 0.00 2700.OOf . 43 811 . 232 455 . 2288 83 .29 9 116 -666.85 -867.63 279783.79 2395414.98 0.00 0.00 0.00 2800 00' . 43 811 . _ . ~ 3.52 - I -709.03 -922.52 279728.14 2395373.82 - i 0.00 0.00 0.00 . . : 232.455 1 2360.99 1232.74 ' -751.22 I -977.41 279672 48 ; 2395332 66 ' 0 00 2900.00 43 811 232 455 2433 15 ~ ~ 1 . . . 0.00 0.00 LL F 3000.001' 3100.00 . 43.811 43 811 , . _ _ 232.455 232 455 . _ _ 2505.31 2577 48 i _ _ 301.97 _ ~ 1371.20 14 _ -793.41 _ ~ -835.59 -1032.30 -1087.18 279616.82 279561.16 _ 2395291.50 ~ 2395250.34 j 0.00 0.00 0.00 0.00 0.00 0.00 3200.OOfi . 43 81 . 232 455 . 2649 64 40.43 1 -877.78 -1142.07 279505.50 2395209.18 0.00 0.00 0.00 3300 00 _ . 1 43 811 . 1 23 . . ' { 509.65 ~ , -919.97 -1196.96 279449.85 ---- __ 2395168.02 ; 0.00 0.00 0.00 . . 2.455 ' 2721.80 i 1578.88 , ~ , -962.15 -1251.85 279394 19 2395126 86 ____ ! 0 00 _ __ 3400.00 43 811 232 455 2793 97 164 . . . j 0.00 0.00 3500.OOfi . 43 811 . 232 455 . 2866 13 8.11 171 -1004.34 -1306.74 279338.53 2395085.70 0.00 ~ 0.00 0.00 3600.00 . 43 811 . 232 455 _ . 2938 29 7.34 1 -1046.53 -1361.63 279282.87 2395044.54_ 0.00 0.00 0.00 3700.00 f . 43 811 . 232 455 . 3010 46 786.56 185 -1088.71 -1416.52 279227.21 _2395003.38 , 0.00 _ 0.00 0.00 3800.00' . 43.811 . 232.455 _ . ~ 3082.62 5.79 ~ 1925.02 -1130.90 _~ ' -1173.09 ~ -1471.40 -1526.291 279171.56 279115 90 j ~ 2394962.22 2394921 O5 r 0.00 O O _ 0.00 0.00 3900.00 43 811 232 455 3154 78 _ . . ~ ~U ~ 0.00 0.00 4000.00' . 43.811 _ __ . 232 455 . j ' 3226 95 1994.25 2063 48 _-1215.2_7 12 -1581.18 279060.24 2394879.89 ~ 0.00 0.00 0.00 4100.OOj~ 43 811 . 232 455 . 3299 11 . - 57.46 -1636.07 279004.58 ~ 2394838.73 ~ 0.00 0.00 0.00 . . . 3371 27 2132.70 -1299.65 -1690.96 278948.92 ~ 2394797.57 ~ 0.00 0.00 ~ 0.00 -----_ - ~ ~ 2201.93 _ -1341.83 _ ~ -1745.85 278893.27 ( 2394756.41 0 00 0 00 0 00 0 43.811 2~2.455' ,, , 3 ~' ~7~~ =1384 02 .__-1800 74 ~ LL ~ ~ 278837 61 s TM 2394715 25 ~ . ~ ~ ----~- 00 r . 0 . _ _ . _ `^ ' 4400 .0 01' 43 811 232 455 3515 60 2 . ~ ~ ~ . , ---- ~ :: , . ~ 0.00, 0.00 ' ~, _ ---- -- . . _ . 340.39 -1426.21 d 1855.63 278781 95 ~ 2394674 09 0 00 4500 OOt 43 811 232 455 3 _ ___®_ _.____ __ . , . . 0.00 0.00 . 4600.00 . 43 811 . 232 455 587.76 3659 93 2409.61 -1468.39 -1910.51 278726.29 2394632.93 0.00 0.00 0.00 4700.00 . 43 811 . 232 455 . 3732 09 2478.84 2 4 -1510.58 -1965.40 278670.63 2394591.77 0.00 0.00 0.00 . . . 5 8.07 -1552.76 -2020.29 278614.98 2394550.61 0.00 0.00 o_nn MARATHON EZATHON Oil k Inlet, Alaska I very Loop Unit #3/4 Planned Wellpath Report Wellpath: CLU-11 Ver 3 Page 4 of 6 MD [feet] Inclination [°] Azimuth [°] TVD [feet] Vert Sect [feet] 4900.00' 43.811 232.455 3876.42 2686.52 5000.00 fi 43.811 232.455 3948.58 2755.75 S 100.00f 43.811 232.455 4020.74 , 2824.98 5200.00- 43.811 232.455 _ 4092.90 j 2894.21 5300.OO~ i 43.811 ! 232.455 1 4165.07 j 2963.44 5371.65 4_3.811 , 232.455 1 4216 77 1 3013.04 5400.00 43.244 _ 232.455 _ _ 4237.33 __ 3032.56 SSOO.OOf 41.244 232.455 4311.35 3099.79 5600.00 fi _ _ 39.244 ~ ) _ 232_455 4387.68 3164.39 5700.00 j~ - - ~ 37.244 ] 232.455 , 4466.21 ~ 3226.29 5800 .00 ~' ( 35.244 232.455 4 8645 6 ~ 3285.40 5900.00- 33244 232.455 4629.52 3341.67 6000.00 31244 _2_32.455 4714.10 , 3395A2 6100.00 fi 29.244 232.455 T 4800.48 ~ _ ~ 3445.39 6200.Ofl~i _ 27244 232.455 4888.57' 3492.71` 6300.00~ 6400.00 ~~ 25.2 23.244 232.455 232.455 497826 5069.44 3536.92 3577.98 6500.00 21.244 232.455 5161.99 3615.84 6525.72' _ _20.729 ~ 232.455 5186.00_ __ 3625.05 6600.00 j' 19244 232.455 5255.81 ~ 3650.44 6700.00' 17.244] 232.455 5350.78 3681.74 6800.00fi 15.244 232.455 5446.78 3709.71 6900.00' 13244 232.455 5543.70 373431 7000.00' 11244 232.455 5641.42 3755.52 Slot slot #CLU-11 Well CLU-11 Wellbore CLU-11 Ver 3 North [feet] East [feet] Grid East [us survey feet] Grid North [us survey feet] -1637.14 -2130.07 278503.66 2394468.29 -167932 -2184.96 278448.00 2394427.12 -1721.51 -2239.85 27839234 2394385.96 -1763.70 _ -2294.74 278336.69 2394344.80 -1805.88 I -2349.62 _ 278281.03 _ ~ 2394303.64 _-1836.11 _ -2388.95 ____ 278241.15 2394274.15 -1848.01 -2404.43 278225.45 2394262.54 -1888.98 -2457.73 278171.40 2394222.57 -1928_34 , -2508.95 278119.47 2394184 16 -1966.06 ~ -2558.03 278069.70 . 239414736 -2002.09 ~ -2604.90 278022.17 239411221 -2036.38 -2649.52 277976.93 2394078.75 -2068.89 -2691.82 277934.04 2394047.03 2099 58 ~-2731.75 277893 55 ~ _ _ 2394017.09 -2128.42 i -2769 2 7 ' _ 277855:50 } ~~ 88.9.5 -215536 -218038 _ _ -280433 -2836.88 277819.95 277786.94 2393962.66 239393825 -2203.45 -2866.89 277756.51 2393915.74... -2209.06 -287420 277749.10 _ _ 2393910.27 -2224.53 _ -289433 _ 277728.69 r ____ _.__ 2393895.17 -2243.61 -2919.15 277703.52 2393876.56 -2260.66 -294132 277681.04 2393859.93 -2275.65 -2960.83 27766126 239384530 -2288.57 -2977.64 27764421 2393832.69 DLS /100ft] 0.00 0.00 0.00 0.00 0.00 0.00 2.00 2.00 _ 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2_.00 2.00 2.00 2.00 2.00 2.00 sa ~~~~ KER NuaNEs INTEQ Build Rate [°/100ft] Turu Rate [°/100ft] 0.00 0.00 0.00 0.00 0.00 0.00 0 0 0 • MARATHON ,, Operator MARATHON Oil Company Area Cook Inlet, Alaska (Kenai Penninst Field Cannery Loop Unit Facility Pad # 3 / 4 WELLPATH DATA (102 stations) fi = into MD ~ Inclination Azimuth TVD (feet) [°] [°] [feet] 7200.00'1 7.244 232.455 5838.78 7207.27j~ 7.098 232.455 5846.00 7300.00'1 5.244 232.455 5938.18 7400.00'1 _ _ 4r 232.455 6037.91 7500.00j' 1.24 24 32.455 6137.82 _7562.18 0.000`_ 2_32.455'x_ 6200.00 7600.00'1, 0.000 O.000r 6237.82 7700.00i' _ 0.000 0.000 6337.82 7800.00 0.000 0.000 6437.82 7900.00'1_ 0.000. 0.000 _ 6537.82 7943.18 0.000 232.455. 6581.001 r- - - 8000.00'1 0.000_ 0 000'_ 6637.82 8100.00~1~ 0.000 0.000 6737.82 8200.00 i 0.0_00 _0.000'__ 6837.82 8300.001' 0.000 0.000! 6937.82 8400.00~'j 0.000 0.0001 7037.82 8500.00'1 0.000 O.000j 7137.82 8600.00.1 _ 0.000 0.000 7237.82 _ 8700.00 _ 0.000 0.000 7337.8 8800.00 j~ 0.000(_ 0 000 _ ^, _ _ --- -_ ~ _ 0 000 7437.82 i 8900.00~~ 0.000 7537_82 9000.001) _ 0.000_- 0 000' _ 7637.82 9100.00 i ~_ 0.000_ 0.000i~ 7737.82 9200.00.1 0.000' 0.000 7837.82 oznn nn+ n nnn „ n„n ~,...,. ,.~ r P ila) ~rpolated/e: Vert Sect [feet] 3787.64 3788.55 3798.51 3805.91 _:3809.83 3810.50 3810.50 3810.50 3810.50 3810.50 3810.50 3810.50 3810.50 3810.50 3810.50 3810.50 3810.50 3810.50_ 3810.50 r 3810.5 _3810.50_ 3810.50 3810.50 3810.50 _ - - - - s' 'lanned Wellpath Report Wellpath: CLU-11 Ver 3 Page 5 of 6 Slot slot #CLU-11 Well CLU-11 Wellbore CLU-11 Ver 3 etrapolated station North East Grid East Grid North DLS [feet] [feet] [us survey feet] [us survey feet] [°/100ftJ -2308.14 -3003.11 277618.38 2393813.59 2.00 -2308.70 -3003.83 277617.65 2393813.05 2.00 -2314.77 ; -3011.73 277609.64 2393807.13 2.00 -2319.28' X017.60 27760.69 239380.73 2.00 - - - _ -2321 67 3020 70 277600.54 ;' 2393800.40 2.00 -- - -- ---- -r--- - --- --- -2322 08 X021.24 277600.00 ~ 2393800.00 2.00 - -~ -2322.08 ~ -3021.24 277600.00 2393800.00 ~ 0.00 -2322.08 -3021.24 277600.00 _2393800.00 j 0.00 -2322.08 i 021.24 277600.00 2393800.00 0.00 ----- - --- - ---- -2322.08 -3021.24 277600.00 j 2393800.00 0.00 -- --- -2322.08. -3021.24 277600.00_ 2393800.00 ' 0.00 2322.08 -222.08 ' - '021.24 ~ 277600.00 2393800.00 ' 0.00 - -3021.24. 277600.00 2393800.00 0 -2322 08 -3021.24 ',_ 277600.00 2393800.00 _ 0.00_ --- -2322 08 -3021.24 ; 277600.00~~ 2393800.00__ _ 0.00_ -2322.08 j -3021.24 277600.00 2393800.00 0.00 -2322.08 -3021.24 277600.00 2393800.00' 0.00 -232_2.08 ; -3021.24 277600.00_ 2393800.00 0.00 2322 08 ~~ -3021.24 277600.00 - __ 2393800.00 0.00 - . 8 3021.24 - ~_~_ 277600 00 ' 2393800.00 0.00 - - -- - 2322 08 3021.24 - - - -- - _ ~ 277600 00 2393800.00 - -- - - - - --- 0.00 -2322.08 j 3021.24 ~ 277600.00 r 2393800.00 ' 0.00 -2322.08 ~ -3021.24 277600.00 2393800.00 0.00 -2322_08 -3021.24 277600.00 2393800.00 0.00 r~~~ BAKER NuaNEs INTEQ Build Rate ~ Turn Rate 0 0.00 0.00 0.00 M MARATHON ItATHON Oil k Inlet, Alaska i very Loop Unit #3/4 Planned Wellpath Report Wellpath: CLU-11 Ver 3 Page 6 of 6 Slot slot #CLU-11 Well CLU-11 Wellbore ,CLU-11 Ver 3 r~~~ BAKER Nu~NEs INTEQ MD Inclination Azimuth TVD Vert Sect N h [feet] [°] [°] ort [feet] [feet] f t East Grid East Grid North DLS Build Rate Turu Rate ath 9400.00f 0 000 0 000 [ ee ] ]feet] 8037 82 [us survey feet] [us survey feet] [ /100ft ° ] [°/100ft] [°/100ft] omment . . . 3810.50 -2322.08 -3021.24 277600 00 2393800 00 9418.18 0 000 232 455 8056 00 38 . . 0.00 0.00 0.00 . . . 10.50 -2322.08 -3021.24 277600.00 2393800 00 0 00 0 00 . . . 0.00 TD TOLE & CASING SECTIONS R f W llb e e ore: CLU-11 Ver 3 Ref Wellpath: CLU-1 1 Ver 3 tring/Diameter S M I tart D [feet] End MD f Interval Start TVD End TVD Start N/S Start E/W End N/S End E/W 3.375in Casing Surface 0 00 [ eet] 1606 89 [feet] 1606 89 [feet] [feet] [feet] [feet) [feet] [feet] .625in Casing Intermediate . 0 00 . 5623 58 . 5623 58 0.00 1500.00 0.00 0.00 -247.89 -322.52 . . . 0.00 4406.00 0 00 0 00 1937 Sin Liner . . - .39 -2520.72 . 0.00 9418.18 9418.18 0.00 8056.00 0.00 0.00 -2322.08 -3021.24 ime MD TVD North East [feet] [feet] [feet] [feet] LUl l -Upper Beluga - 4/5/06 5186.00 -2322.08 -3021.24 CLUI l -Lower Beluga - 4/5/06 ~ 7943.18. 6581.00 ~ -2322.08 -3021.24 Grid East Grid North survey feet] [us survey fee 277600.00 239380 Latitude Longitude Shape [°] [°] 60 32 47.754N 151 14 07.406W, circle _ - --.--~_c_~~_ 60 32 47.754N 151 14 07.406W! circle ~VEY PROGRAM Ref Wellbore: CLU-11 Ver 3 Ref Wellpath: CLU-11 Ver 3 Start MD End MD Tool Type Positional Uncertainty Model Log Name/Comment Wellbore [feet] [feet] 0.00 9418.18 aviTrak aviTrak (Standard) CLU-11 Ver 3 • MARATHON • MARATHON Oil Company Locatbn: Cook Inlet, Aleaka (Kenel Pemheula) Sbt: ebt kCLU-11 F7eb: Cannery Loop Unit Well: CLU-11 Facility: Pad M 3 / 4 Wellbore• CLU-11 Ver vbl rrw.nc. ..p.rn ~ aun v. a Tru ran ~ Urgh u~ nlrwuE b OIa~Y f 1~ _ _ 7}(ib SjM~,e MNiI / TY MrYa abb PY~, Ima ~ OW 1! iM MrrvM aylh ua rMx~taa b (icM_ 1 ~~ _--.__ ~NVM PMrraK T mM _ _ oeoh r lrixa) ro min e.. rr se t«r eo.k r aw.m. n..n aw i..w ro Me M (Faa~r PW a a / sl o lar! - OaNh b hal Coor0y6r N !~ MI rMantWE b ab[ ~.. mar. u.u~w:. -. _ Traveling Cylinder: Map North o• ,eon aso• rear war near soo• roar ear ear so' ~~ BAKER HU6NES INTEQ ao• 90 2alr .en ear een Pb' IOOIr IYaf NO/r 1e0/f If0' /aNf fe0' All depths shown are Measured depths on Reference Well 160' 700 700 500 500 ITO' scw l Fcn _ ap n M MARATHON RATHON Oil Company k Inlet, Alaska (Kenai Penninsula) very Loop Unit #3/4 Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 1 of 18 Projection System NAD27 / TM Alaska State Plane, Zone 4 North Reference True Scale 0.999955 Wellbore last revised 4/12/2006 Local coordinates North [feet] East [fee Slot Location 2493.43 2270.35 Facility Reference Pt Field Reference Pt Slot slot #CLU-11 Well CLU-11 Wellbore CLU-11 Ver 3 US feet Grid coordinates ser Generated se/Source file Ming [US feet] Northing [US f 280663.58 2396065.62 278347.08 2393615.22 272978.90 2388436.21 sa ~'~~ KEG NY~MES INTEQ 1.1 at 07:27:26 orage/CLU-11 Ver Latitude [°] 60 33 10.625N 60 32 46.072N 60 31 54.076N Calculation method Minimum Curvature Glacier 1 (RKB) to Facility Vertical Datum Horizontal Reference Pt Slot Glacier 1 (RKB) to mean sea level Vertical Reference Pt Glacier 1 RKB ( ) Facility Vertical Datum to Mud Line MD Reference Pt Glacier 1 (RKB) Field Vertical Reference mean sea level POSITIONAL UNCERTAINTY CALCULATION SETTINGS Ellipse Confidence Limit 3.00 Std Dev Ellipse Start Depth 0.00 feet Surface Position Uncertainr Declination 19.60° East of TN Dip Angle 73.43° Magnetic Field Streneth . coordinates Longitude [°] 151 13 06.998W 151 13 52.401W 151 15 37.735W feet feet feet included 55411 nT Clearance Report /~i%~ Closest Approach BAKER MARATHON Reference Wellpath: CLU-11 Ver 3 NV~NEs Page 2 of 18 INTEQ . , ~ . Operator MARATHON Oil Company Slot slot #CLU-11 ]Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Ver 3 Facility Pad # 3 / 4 ANTI-COLLISIONRULE a... Rule Name E-type Closest Approach w/Hole&Csg Limit:0 StdDev:3.00 w/Surface Uncert Rule B d O Plane of Rule Closest Approach ase n Ellipsoid Separation Threshold Value 0.00 feet Subtract Casing & Hole Size yes Apply Cone of Safety no HOLE & CASING SECTIONS Ref Wellbore: CLU-11 Ver 3 Ref Wellpath: CLU-11 Ver 3 String/Diameter Start MD End MD Interval Start TVD [feet] f End TVD Start N/S Start E/W End N/S End E/W 13.375in Casing Surface [ eet] [feet] [feet] 0.00 1606 89 1606 89 0 00 [feet] [feet] [feet] [feet] [feet] 9.625in Casing Intermediate . . . 0.00 5623.58 5623 58 0 00 1500.00 4406 00 0.00 0.00 -247.89 -322.52 3.Sin Liner . . 0.00 9418.18 9418.18 0 00 . 8056 00 0.00 0.00 0 00 -1937.39 -2520.72 . . . 0.00 -2322.08 -3021.24 SURVEY PROGRAM Ref Wellbore: CLU-11 Ver 3 Ref Well ath: CLU-11 Ver 3 " Start MD End MD [feet] [feet] Tool Type Positional Uncertainty Model Log Name/Comment Wellbore . 0.00 9418.18 aviTrak aviTrak (Standard) CLU-11 Ver 3 M MARATHON EtATHON Oil k Inlet, Alaska ~ very Loop Unit #3/4 Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 3 of 18 CALCULATION RANGE & CUTOFF From: 0.00 MD To: 9418.18 MD OFFSET WELL CLEARANCE SUMMARY (12 Offset Wellpaths selected) Offset Offset Offset Offset Offset Facility Slot Well Wellbore Wellpath Pad # 3 / 4 slot #CLU-3 CLU-3 CLU-3 GMS <0-11125> Pad # 3 / 4 slot #CLU-4 CLU-4 CLU-4 GMS <0-16500> Pad #1 CLU-1 CLU-1 CLU-1 GMS <0-12010> Pad#1 CLU-1 CLU-1 CLU-1Rd GMS<0-5493'>,MWD<5493-10835'> Slot t #CLU-11 U-11 U-11 Ver 3 C-C Cutoff: 500.00 feet sA ~i~~ KER NuaNEs INTEQ Ref Min C-C Diverging Ref MD of Min Ell Min EII Se ACR MD Clear Dist from MD Min EII Sep Sep p Dvrg From Status [feet] [feet] [feet] [feet] [feet] [feet] 0.00 149.09 500.00 400.00 135 80 400 00 PASS . . 500.00 163.58 500.00 525.63 149 43 525 63 PASS . . 0.00 9706.51 0.00 0.00 9445 15 0 00 PASS . . 0.00 9299.91 0.00 0.00 9080.52 0.00 PASS Pad #1 CLU-10 CLU-10 CLU-10 MWD <0-8450'> 0.00 10801.99 0.00 0 00 10507 51 0 00 PASS Pad #1 CLU-5 CLU-5 CLU 5 . . . - MWD <0-8511>Dipmeter <8600-11420> 0.00 9147.92 0.00 0 00 8876 48 0 00 PASS Pad #1 CLU-6 CLU-6 CLU 6 . . . - MWD <0 - 8320> 0.00 7454.31 0.00 0 00 7214 21 0 00 PASS Pad #1 CLU-7 CLU-7 CLU 7 . . . Pad #i ( CLU-8 CLU-8 - CLU-8 MWD <0-10864> MWD <0-9777> ~, 0.00 0.00 7238.93 8601.86 0.00 0.00 0.00: 0 00 ~r 6994.33 j 8330 29 ; 0.00 , 0 00 i PASS PASS Pad #1 CLU-9 CLU-9 CLU 9 . . . - MWD <0-9100> 0.00 10024.72 0.00 0 00 i 9~ 732 45 0 00 PASS Pad #2 slot #CLU-2 CLU 2 CL . . . - U-2 GMS <0-10731> 0.00 12793.63 0.00 0.00 12492.27 0.00 PASS • Clearance Report ~/~~ Closest Approach BAKER ' MAQATHON Reference Wellpath: CLU-11 Ver 3 MY6NES Page 4 of 18 INTEQ ~~ ~ ~ Operator MARATHON Oil Company Slot slot #CLU-11 Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Ver 3 Facility Pad # 3 / 4 CLEARANCE DATA -Offset Wellbore: CLU-3 Offset Wellpath: GMS <0-11125> Facility: Pad # 3 / 4 Slot: slot #CLU-3 Well: CLU-3 Threshold Value=0.00 feet 1' =interpolated/extrapolated station Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD ACR [feet] [feet] [feet] [feet] [feet] [feet ] [feet] [feet] [°] [feet] [feet] feet] Status 0.00 0.00 0.00 0.00 11.00 0.00 5.72 148.98 87.80 149.09 135.98 13.12 PASS 100.001 100.00 0.00 0.00 111.00 100.00 5.72 148.98 87.80 149.09 135.97 13.12 PASS 200.001 200.00 0.00 0.00 211.00 200.00 5.72 148.98 87.80 149.09 135.94 13.15 PASS 300.001 300.00 0.00 0.00 311.00 300.00 5.72 148.98 87.80 149.09 135.89 13.21 PASS 400.001 400.00 0.00 0.00 411.00 400.00 5.72 148.98 87.80 149.09 135.80 13.29 PASS 500.00 500.00 0.00 0.00 511.00 500.00 5.72 148.98 87.80 149.09 136.00 13.09 PASS 600.001 599.92 -2.13 -2.77 610.92 599.92 5.72 148.98 87.04 151.95 138.70 13.26 PASS 700.001 699.35 -8.49 -11.05 710.35 699.35 5.72 148.98 84.92 _ 160.67 147.03 13.64 PASS _800.001 _797.81 -19.07 _ -24.82 808.81 _ __ 797.81 5.72 ___ 148.98 81.88 175.56 161.13 14.44 PASS j 900.OOt 894.82 -33.81 -44.00 906.07 895.07 ] 5.73 148.98 78.42 - 196.98. a '.181.64 ~' 15.34 PASS 1000.001 989.91 -52.64 -68.49 1005.98 994.96 6.34 147.65 74.74 224.10 207.74 16.36 PASS 1100.001 1082.61 -75.46 -98.19 1110.17 1099.00 7.71 142.47 70.94 255.16 237.55 17.61 PASS 1200.001 1172.47 -102.17 -132.94 1214.24 1202.50 10.45 131.93 66.96 289.38 270.50 18.88 PASS 1300.001 1259.05 -132.64 -172.57 1313.22 1300.33 14.19 117.49 63.15 327.71 307.70 20.01 PASS 1 000 000 04 t 1341.94 -166.71 -216.90 1401.21 ., 1387.01 18.39 102.92 59.94 372.2b 351.53 20.73 PASS 1500.001 1420.73 -204.22 -265.70 1488.93 1473.22 23.16 87.52 57.23 423.35 402.00 21.35 PASS 1595.27 1491.61 -242.98 -316.14 1569.37' 1552.12 27.73 72.44 55.14 477.44 455.25 22.19 PASS 1600.001 1495.03 -244.98 -318.74 1573.29 1555.95 27.96 71.68 55.04 480.25 458.02 22.24 PASS C-C Clearance Distance Cutoff: 500.00 feet Clearance Report ~'~~ Closest Approach BAK~~ MARATHON Reference Wellpath: CLU-11 Ver 3 NV~NE~ Page 5 of 18 INZ•E(~ RATHON Oil Company Slot slot #CLU-11 k Inlet, Alaska (Kenai Penninsula) Well CLU-11 very Loop Unit Wellbore CLU-11 Ver 3 #3/4 WELLPATH COMPOSITION Offset Wellbore: CLU-3 Offset Well ath: GMS <0-11125> Start MD End MD Tool Type Positional Uncertainty Model Log Name/Comment Wellbore [feet [feet] 0.00 11125.00 Level Rotor Gyro Level Rotor Gyro (Standard) GMS <0-11125'> CLU-3 `OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-3 Offset Wellpath: GMS <0-11125> "` MD Reference: Actual Datum (RKB) Offset T[~D & local coordinates use Reference Wellpath settings Clearance Report ~'/%/ Closest Approach BAKER MARATHON Reference Wellpath: CLU-11 Ver 3 MY6NES Page 6 of 18 INTEQ perator MARATHON Oil Com an p Y Slot slot #CLU-11 Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Meld Cannery Loop Unit Wellbore CLU-11 Ver 3 ?acility Pad # 3 / 4 ~LEARANCE DATA -Offset Wellbore: CLU-4 Offset Wellpath: GMS <0-16500> • +acility: Pad # 3 / 4 Slot: slot #CLU-4 Well: CLU-4 Threshold Value=0.00 feet ~ = interpolated/extrapolated station Ref MD Ref TVD Ref North Ref East Offset MD [feet] [feet] [feet] f t f Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD ACR [ ee ] [ eet] [feet] feet] [feet 1 [°] [feet] [feet] [feet] Status _0.00 100.001 0.00 0.00 _ 0.00 0.03 100.00 0.00 0 00 100 74 _ 0.03 __ 5.53 164_.65 100 74 _ 88.08 164.74 150.94 13.81 PASS 200.001 . . 200 00 0.00 0.00 200.26 . 5.53 164.40 200.26 5 72 164 09 88.07 88 01 164.49 150.67 13.82 PASS 300.001;' 300.00 0.00 0.00 300.44 . . 300.44 5.92 163 87 . 87 93 164.19 163 150.71 13.48 PASS . . .98 150.36 13.61 PASS „r_ . 500.00 . 500.00 . 0 00 .00 0 00 400.25 500 41 400.25 6.04 163.66 87.89 163.77 149.95 13.82 PASS 525 631 525 62 . 0 . . 500.41 6.42 163.45 87.75 163.58 149.69 13.88 PASS . 600.00 f . 599.92 - .14 -2 13 -0.18 -2 77 526.94 600 88 526.93 6.56 163.36 87.65 163.69 149.43 14.26 PASS 700.001 699.35 . -8 49 . - 11 OS• .~ . _ 700 41 600.87 7 00 40 ~ 6.83 7 25 _ 16.3.01 _ _ 86.91 166.02 151.84 14.18 PASS '~$~14:OOt --.-..- 797 81 x=' e..~_ ` -19 07 ___.__ _.. -24 8 _ . 798 5 _ . _ . ____ __ 1 _162.38 84.81 174.15 __159.43 14.72 PASS _ _ . . :; ___ . 2 .: . 7 798.5b ~ 7.65 161.84 $1 85 " ` ~ 1 6 900.001 894.82 -33 81 -44 00 ~ _ 894 83 894 82 _ __ __ _ a . ~ , • $$,5 . 172:3 __ s.: 15..63 PASS _ _ . . . . 7.75 161.63 78.57 209.79 193 32 16 47 PASS 1000.001 989.91 -52.64 -68.49 989.61 989.60 7.61 161.73 75.33 237.98 . 220 79 . 17 19 PASS 1100.001 1082.61 -75.46 -98.19 1082.61 1082.59 7.20 161.93 72.37 272.94 . 254 97 . 17 97 PASS 1200.001 1300.OOt 1172.47 1259.05 -102.17 -132.64 -132.94 -172.57 1172.29 1258 85 1172.28 1258 83 6.52 5 80 162.18 69.78 314.50 . 295.72 . 18.78 PASS 1400.001 1341.94 -166 71 -216 90 . 1347 33 . 1 . 162.53 67.55 362.57 343.00 19.57 PASS . . . 347.31 4.77 162.65 65.69 416.53 396 09 20 43 PASS 1500.001 1420.73 -204.22 -265.70 1440.82 1440.75 2.63 160.95 64.14 474.57 . 453.33 . 21 24 PASS C-C Clear ance Distan ce Cutoff: 50 0.00 feet . 400 001 400 00 0 00 0 M MARA7NOM Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 7 of 18 Operator MARATHON Oil Company Slot slot #CLU-11 Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Ver 3 sa ~'~'r ~~~ EtY6MES INTEQ :Facility Pad # 3 / 4 ,A HOLE & CASING SECTinNS OffePt wPnh,...p• r~T rr_d nam~,.~.:~,.~,_~~L_ ..,,.~ String/Diameter - - St MD - - - ----- • • ---Y»-... ~.. .aw~ -v-iv-~vv~ 30in Conductor art [feet] End MD [feet] Interval [feet] Start TVD [feet] End TVD [feet] Start N/S [feet] Start E/W [feet] End N/S [feet] End E/W [feet] 20in Casing Surface -4.00 143.00 147.00 -8.00 139.00 3.37 100.37 3.38 100.24 13 625in Casin Intermediate -4.00 2726.00 2730.00 -8.00 2693.77 3.37 100.37 -32.08 32.04 . g 9 625in Casin -4.00 8231.00 8235.00 -8.00 7976.33 3.37 100.37 -175.97 -415.21 . g Tin Liner -4.00 12221.00 12225.00 -8.00 11804.13 3.37 100.37 -344.27 -707.74 Sin Liner 12107.00 14996.00 2889.00 11694.32 14471.77 -337.76 -701.06 -518.00 -860.50 14796.00 16150.00 1354.00 14276.84 15609.20 -506.73 -852.81 -569.62 -887.50 WELLPATH COMPOSITION Offset Wellbore: CLU-4 Offset Well ath• GMS <0 16500> Start MD f t End MD Tool Type Positional Uncertainty Model Log Name/Comment [ ee ] feet] -4.00 16496.00 Level Rotor Gyro Level Rotor Gyro (Standard) GMS <0-16500'> Wellbore CLU-4 I~ OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-4 Offset Wellpath: GMS <0-16500> MD Reference. Glacier 1 (RKB) (RKB) Offset TVD & local coordinates use Reference Wellnnth cottinoc M MARATHON RATHON Oil ~ k Inlet, Alaska ~ nery Loop Unit #3/4 Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 8 of 18 of slot #CLU-11 ell CLU-11 ellbore CLU-11 Ver 3 sw E~~ ~cE~ ~[Y6NES INTEQ CLEARANCE DATA -Offset Wellbore: CLU-1 Offset Wellpath: GMS <0-12010> r Facility: Pad #1 Slot: CLU-1 Well: CLU-1 Threshold Value=0.00 feet ~ =interpolated/extrapolated station ,.. Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD 'ACR feet feet] feet [feet] feet] feet] feet feet ° feet feet [feet Status 0.00 0.00 0.00. 0.00 6480.59 5535.74 -5298.04 -5958.41 228.36 9706.51 9445.15 261.36 PASS C-C Clearance Distance Cutoff: 500.00 feet WELLPATH COMPOSITION Offset Wellbore: CLU-1 Offset Well ath: GMS <0-12010> Start MD ~ End MD Tool Type Positional Uncertainty Model fF eN re__a -2.00 ~ 12008.00 ~ Level Rotor Level Rotor Log Name/Comment ~ Wellbore GMS <0-12010'> CLU-1 'OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-1 Offset Wellpath: GMS <0-12010> MD Reference: RKB(Glacier#1) (RKB) Offset TVD & local coordinates use Reference Wellpath .cettir~¢c M MARATNOM ItATHON Oil k Inlet, Alaska i eery Loop Unit #3/4 Slot slot #CLU-11 Well CLU-11 Wellbore CLU-11 Ver 3 sa ~~~ KER ~lY6l~iE~ INTEQ .CLEARANCE DATA -Offset Wellbore: CLU-1Rd Offset Wellpath: GMS<0-5493'>,MWD<5493-10835'> ~. Facility: Pad #1 Slot: CLU-1 Well: CLU-1 .Threshold Value=0.00 feet fi = interpolated/eztrapolated station Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD ACR [feet] [feet ] [feet] [feet] [feet] [feet] [feet] [feed 1°l lfeetl tfPPri rf oa 'i c~-~.... C-C Clearance Distance Cutoff: 500.00 feet 8556. Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 9 of 18 -4297.151 -4637 227.18 9299.91 WELLPATH COMPOSITION Offset Wellbore: CLU-1Rd Offset Well ath: GMS<0-5493'>,MWD<5493-10835'> Start MD End MD Tool Type Positional Uncertainty Model Lo Name/Comment tfP.P.}~ ~f n47 g -2.00 5493.00 Level Rotor Gyro Level Rotor Gyro (S 5493.00 9741.00 NaviTrak NaviTrak (Magcorrl 9741.00 10835.00 NaviTrak NaviTrak (Maecorrl GMS <0-12010'> MWD<5750-10725'> MWD<9768-10835'> 9080.52 219.40 PASS Wellbore CLU-1 CLU-1RdPB1 CLU-1Rd :OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-1Rd Offset Wellpath: GMS<0-5493'>,MWD<5493-10835'> MD Reference: RICB(Glacier#1) (RKB) Offset TVD & local coordinates use Reference Wellpath settings Clearance Report Closest Approach MARATHON Reference Wellpath: CLU-11 Ver 3 Page 10 of 18 pera or N Oil Com an P Y Slot slot #CLU-11 Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Ver 3 #3/4 sA ~i1r KER NYf3NES INTEQ .CLEARANCE DATA -Offset Wellbore: CLU-1RdPB1 Offset Wellpath: GMS<0-5493'>,MWD<5750-10725'> Facility: Pad #1 Slot: CLU-1 Well: CLU-1 Threshold Value=0.00 feet ~' =interpolated/extrapolated station Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD ACR (feet] (feetl ffeetl ffeetl rfnnrl rr o+, «.._~, .~__~, .,.. _ o.oo ~ o.oo~ o.ool o.o0 8556. C-C Clearance Distance Cutoff: 500.00 feet -4297.15 -4637.07[ 227.18. 9299.91 219.401 PASS WELLPATH COMPOSITION Offset Wellbore: CLU-1RdPB1 Offset Well ath: GMS<0-5493'>,MWD<5750-10725'> Start MD End MD Tool Type Positional Uncertainty Model Log Name/Comment Wellbore [feet] [feet] -2.00 5493.00 Level Rotor Gyro Level Rotor Gyro (Standard) GMS <0-12010'> CLU-1 5493.00 10725.00 NaviTrak NaviTrak (Magcorrl) MWD<5750-10725'> CLU-1RdPB1 OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-1RdPB1 Offset Wellpath: GMS<0-5493'>,MWD<5'750-10725'> MD Reference: RKB(Glacier#i) (RKB) Offset TVD & local coordinates use Reference Wellpath .cettinQ.c M MARATHON [tATHON Oil C k Inlet, Alaska ~ nery Loop Unit #3/4 Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 11 of 18 of slot #CLU-11 ell CLU-11 ellbore CLU-11 Ver 3 sa ~~/ KER ~fY~NES INTEQ CLEARANCE DATA -Offset Wellbore: CLU-10 Offset Wellpath: MWD <0-8450'> Facility: Pad #1 Slot: CLU-10 Well: CLU-10 Threshold Value=0.00 feet ~ = interpolated/eztrapolated station Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist :Ellipse Sep ACR MASD ,ACR feet feet] feet feet feet feet] [feet] feet °] feet feet feet Status 0.00 0.00 0.00 0.00 3398.95 3088.17 -7702.02 -6915.57 221.92 10801.99 10507.51 294.48 PASS C-C Clearance Distance Cutoff: 500.00 feet ::HOLE & CASING SECTIONS Offset wPnhnro. !''i iT_1n nee..,.a SI7..17__LL_ s.rci~r ,n ,.. ~..., , String/Diameter Start MD E d M - -- "--..-.. ......t,«......~... , w-v-eav ~ 20in Conductor [feet] 0 00 n D [feet] Interval [feet] Start TVD [feet] End TVD [feet] Start N/S [feet] Start E/W [feet] . 123.00. 123.00 15.00 138.00 -4564.12 -4923 80 13.375in Casing 0 00 . . 1953.00 1953.00 15.00 1881.08 -4564.12 -4923 80 9.625in Casing 0 00 . . 5410.00 5410.00 15.00 4977.18 -4564.12 -4923 80 3.Sin Liner 0 00 . . 8450.00 8450.00 15.00 8016.79 -4564.12 -4923.80 End N/S End E/W [feet] [feet] -4564.23 -4923.70 -4586.33 -4809.23 -4671.83 -4385.62 -4673.68 -4378.74 WELLPATH COMPOSITION Offset Wellbore: CLU-10 Offset Well ath: MWD <0-8450'> _ " Start MD End MD Tool Type Positional Uncertainty Model Log Name/Comment [feet] [feet]. 0.00 8450.00 NaviTrak NaviTrak (Magcorrl) MWD <0-8450'> Wellbore " CLU-10 OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-10 Offset Wellpath: MWD <0-8450'> MD Reference: Glacier 1 (RKB) Offset TVD & local coordinates arse Reference Wellpath settings M MARAiNOM MARATHON Oil Cook Inlet, Alaska i Cannery Loop Unit Pad#3/4 Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 12 of 18 Slot slot #CLU-11 Well CLU-11 Wellbore CLU-11 Ver 3 sw ~t~ KER NY6NES INTEQ CLEARANCE DATA -Offset Wellbore: CLU-5 Offset Wellpath: MWD <0-8511>Dipmeter <8600-11420> 4 Facility: Pad #1 Slot: CLU-5 Well: CLU-5 Threshold Value=0.00 feet fi =interpolated/extrapolated station Ref MD Ref TVD Ref North Ref East .Offset MD Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD ;ACR [feet] [feet] [feed lfeetl Ifeetl rfPP+~ rf o+~ «..~, .~, ... .. __ __ o.oo ~ o.oo~ o.oo o.c C-C Clearance Distance Cutoff: 500.00 feet 222.801 9147 271.441 PASS WELLPATH COMPOSITION Offset Wellbore: CLU-5 Offset Well ath: MWD <0-8511>Di meter <8600-11420> .~~N Start MD End MD Tool Type Positional Uncertainty Model Log Name/Comment Wellbore [feet] [feet] 0.00 8511.00 MTC (Collar, pre-2000) MTC (Collar, pre-2000) (Standard) MWD <0-8511'> CLU-5 8511.00 11420.00 Unknown Tool Unknown Tool (Standard) Dipmeter <8600-11420'> CLU-5 'OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-5 Offset Wellpath: MWD <0-8511>Dipmeter <8600-11420> MD Reference: Actual Datum KB ~ ) Offset TVD & local coordinates use ReFerence We//north cns>;Hai • M MARATIIOM Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 13 of 18 Aerator MARATHON Oil Company Slot slot #CLU-11 Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Ver 3 Facility Pad # 3 / 4 s ~~r AK~R NY6l~iES INTEQ ,CLEARANCE DATA -Offset Wellbore: CLU-6 Offset Wellpath: MWD <0 - 8320> Facility: Pad. #1 Slot: CLU-6 Well: CLU-6 Threshold Value=0.00 feet ~ =interpolated/extrapolated station Ref MD Ref TVD ;Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD ~ ACR [feet feet] feet feet feet feet feet feet ° feet feet feet] Status 0.00. 0.00 0.00 0.00 8320.00 5291.89 -4031.07 -3363.50 219.84 7454.31 7214.21 240.10 PASS C-C Clearance Distance Cutoff: 500.00 feet WELLPATH COMPOSITION Offset Wellbore: CLU-6 Offset Well ath: MWD <0 - 8320> Start MD End MD Tool Type Positional Uncertainty Model Log Name/Comment Wellbore [feet] [feet] 0.00 8320.00 MTC (Collar, pre-2000) MTC (Collar, pre-2000) (Standard) MWD c0 - 8320> CLU-6 OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-6 Offset Wellpath: MWD <0 - 8320> MD Reference: Actual Datum (RKB) Offset T1~D & local coordinates use Reference Wellpath .cettinuc M MARATNON MARATHON Oil Company Cook Inlet, Alaska (Kenai Penninsula) Cannery Loop Unit Pad#3/4 Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 14 of 18 Slot slot #CLU-11 Well CLU-11 Wellbore CLU-11 Ver 3 sa ~/~ KKR NYt~NE~ INTEQ CLEARANCE DATA -Offset Wellbore: CLU-7 Offset Wellpath: MWD <0-10864> Facility: Pad #1 Slot: CLU-7 Well: CLU-7 Threshold Value=0.00 feet. fi = interpolated/eztrapolated station Ref MD Ref TVD Ref North Ref East :Offset MD [feet f et f t f Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD ACR e ee [ eet} [feet] [feet feet] feet ° feet feet 0.00 0.00 0.00 0.00 7061.69 4378.76 -3868.30 -4273.74 227 85 7238 93 6994 33 feet Status C-C Clearance Distance Cutoff: 500.00 feet . . . 244.60 PASS WELLPATH COMPOSITION Offset Wellbore: CLU-7 Offset Well ath: MWD <0-10864> Start MD End MD T l T [feet [feet] oo ype Positional Uncertainty Model Lo Name/Comment g Wellbore 0 00 10864 00 N iT k . . av ra NaviTrak (SAG, Magcorrl) MWD <0-10864> CLU-7 ,. OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-7 Offset Wellpath: MWD <0-10864> ~ , ~, ~ , MD Reference RKB (Glacier) (RKB) Offset TVD & local coordtnates use Reference Wellpath settings Clearance Report ~~~ Closest Approach BAKER MARATHON Reference Wellpath: CLU-11 Ver 3 MY~NES Page 15 of 18 INTEQ RATHON Oil Company Slot slot #CLU-11 k Inlet, Alaska (Kenai Penninsula) Well CLU-11 very Loop Unit Wellbore CLU-11 Ver 3 #3/4 CLEARANCE DATA -Offset Wellbore: CLU-8 Offset Wellpath: MWD <0-9777> Facility: Pad #1 Slot: CLU-8 Well: CLU-8 Threshold Value=0.00 feet ~ = interpolated/eztrapolated station Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North :Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD ACR [feet [feet [feet feet] feet feet [feet feet ° [feet feet feet `Status. 0.00 0.00 0.00 0.00 6366.19 4651.51 -5680.08 -4482.42 218.28 8601.86 8330.29 271.57 PASS C-C Clearance Distance Cutoff: 500.00 feet =WELLPATH COMPOSITION Offset Wellbore: CLU-8 Offset Well ath: MWD <0-9777> Start MD End MD Tool Type Positional Uncertainty Model Log Name/Comment Wellbore feet] [feet] 0.00 9777.00 NaviTrak NaviTrak (Magcorrl) MWD <0-9777> CLU-8 OFFSET WELLPATH MD REFERENCE -Offset Wellbore; CLU-8 Offset Wellpath: MWD <0-9777> MD Reference: RKB (Glacier 1) (RKB) Offset TVD & local coordinates use Reference Wellpath settings • M MAQIITHON ItATHON Oil Company k Inlet, Alaska (Kenai Penninsula) very Loop Unit #3/4 CLEARANCE DATA -Offset Wellbore: CLU-9 Facility: Pad #1 Slot: CLU-9 Well: CLU-9 Ref MD Ref TVD Ref North Ref East Offset MD [feet [feet [feet feet] [feet 0.00 0.00 0.00 0.00 5335.2 C-C Clearance Distance Cutoff: 500.00 feet Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 16 of 18 slot #CLU-11 ell CLU-11 ellbore CLU-11 Ver 3 sw qtr KKR ~V~N~~ INTEQ Offset Wellpath: MWD <0-9100> Threshold Value=0.00 feet ~ = interpolated/eztrapolated station Offset TVD :Offset North Offset East Aoriz Bearing C-C Clear Dist Ellipse Sep ACR MASD ACR [feet] feet [feet] ° feet feet feet Status i 4370.46 -7254.35 -5363.63 216.48 10024.72 9732.45 292.27 PASS HOLE & CASING SECTIONS Offset Wellbore: CLU-9 Offset Wellpath: MWD <0-9100> String/Diameter Start 1VID End MD Interval Start TVD End TVD Start N/S 16in Open Hole 130.00 2063.00 1933.00 144.00 1923.99 . -4606.34 12.25in Open Hole 2063.00 5994.00 3931.00 1923.99 4965.68 -4589.04 8.Sin Open Hole 5994.00 9100.00 3106.00 4965.68 8055.50 -4506.09 20in Conductor 0.00 130.00 130.00 14.00 144.00 -4606.51 13.375in Casing 0.00 2053.00 2053.00 14.00 1916.54 -4606.51 9.625in Casing 0.00 5980.00 5980.00 14.00 4952.41 -4606.51 3.Sin Liner 0.00 9100.00 9100.00 14.00 8055.50 -4606.51 Start E/W [feet] -4940.00 -4763.02 -4021.63 -4939.93 -4939.93 -4939.93 -4939.93. ~.. WELLPATH COMPOSITION Offset Wellbore: CLU-9 Offset Well ath• MWD <0-9100> End N/S [feet] End E/W [feet] -4589.04 -4763.02 -4506.09 -4021.63 -4490.54 -3956.46 -4606.34 -4940.00 -4589.27 -4765.04 -4506.21 -4022.98 -4490.54 -3956.46 Start MD [feet] End MD [feet] Tool Type Positional Uncertainty Model Log Name/Comment Wellbore 0 00 9100 00 N iT k . . av ra NaviTrak (SAG, Magcorrl) MWD <0-9100> CLU-9 MARATHON [tATHON Oil Company k Inlet, Alaska (Kenai Penninsula) very Loop Unit #3/4 Clearance Report Closest Approach Reference Wellpath: CLU-11 Ver 3 Page 17 of 18 of slot #CLU-11 ell CLU-11 ellbore CLU-11 Ver 3 sa ~~~ KER N1~l~l~IES IN~(~ '.OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-9 Offset Wellpath: MWD <0-9100> MD Reference: Glacier 1 (RKB) Offset TVD do local coordinates use Reference Wellpath settinvc • M IMARATIbN MARATHON Oil Company Cook Inlet, Alaska (Kenai Penninsula) Cannery Loop Unit Pad#3/4 Clearance Report ~ii'~ Closest Approach B~K1";R Reference Wellpath: CLU-11 Ver 3 NY~NE~ Page 18 of 18 IN'rEQ of slot #CLU-11 ell CLU-11 ellbore CLU-11 Ver 3 CLEARANCE DATA -Offset Wellbore: CLU-2 Offset Wellpath: GMS <0-10731> Facility: Pad #2 Slot: slot #CLU-2 Well: CLU-2 Threshold Value=0.00 feet ~' = interpolated/eztrapolated station Ref MD Ref TVD .Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD 'ACR [feet]. [feet feet feet feet feet feet feet ° feet feet feet `Status 0.00 0.00 0.00 0.00 24.00 0.00 1303.37 12727.06 84.15 12793.63 12492.27 301.35 PASS C-C Clearance Distance Cutoff: 500.00 feet WELLPATH COMPOSITION Offset Wellbore: CLU-2 Offset Well ath: GMS <0-10731> Start MD End MD Tool Type Positional Uncertainty Model Log Name/Comment Wellbore [feet [feet] 0.00 10731.00 Level Rotor Gyro Level Rotor Gyro (Standard) GMS <0-10731'> CLU-2 .OFFSET WELLPATH MD REFERENCE -Offset Wellbore: CLU-2 Offset Wellpath: GMS <0-10731> MD Reference: Actual Datum (RKB) Offset TVD & local coordinates use Reference Wellnnth wrr;~e~ • M MARATHON RATHON Oil k Inlet, Alaska ~ nery Loop Unit #3/4 ojection System ~rth Reference ale ellbore last revised Slot Location Facility Reference Pt Field Reference Pt Calculation method Horizontal Reference Pt Vertical Reference Pt NID Reference Pt Field Vertical Reference Wellpath Design Summary Report Wellpath: CLU-11 Ver 3 Page 1 of 2 AD27 / TM Alaska State Plane, Zone 4 (5004), US feet _ Local coordinates North [feet] East (feel ,..~ . 2493.43 2270.35 curvature Slot Glacier 1 (RK Glacier 1 (RK mean sea level Slot slot #CLU-11 Well CLU-11 Wellbore CLU-11 Ver 3 sa ~`~ KLR N~~N~~ INTEQ re system We1lArchitectTM 1.1 Suthstud Generated 04/12/06 at 07:20:16 se/Source file WA-Anchorage/CLU-11 V Grid co Ming [US feet] ordinates Northing [US feet] Geogr Latitude [°] 280663.58 2396065.62 60 33 10.625N 278347.08 2393615.22 60 32 46.072N 272978.90 2388436.21 60 31 54.076N 1 (RKB) to Facility Vertical Datum 1 (RKB) to mean sea level Vertical Datum to Mud Line coordinates Longitude [°] 151 13 06.998W 151 13 52.401W 151 15 37.735W feet feet feet MARATHON Wellpath Design Summary Report Wellpath: CLU-11 Ver 3 Page 2 of 2 r~.~ BAKER Nu~NEs INTEQ Operator MARATHON Oil Company Slot slot #CLU-11 Area Cook Inlet, Alaska (Kenai Penninsula) Well CLU-11 Field Cannery Loop Unit Wellbore CLU-11 Ver 3 #3/4 CWELLPATH DATA (7 st ations) ~ MD [feet[ lucliuatiou (°] Azimuth ° TVD Vert Sect North East Grid East Grid North DLS esigu 0.00 0.000 [ ] 232.455 [feet] 0.00 [feet[ 0.00 [feet] 0.00 [feet) 0.00 [us survey feet] 280663.58 [us survey feet) 2396065.62 [°/100ft] 0.00 Comment Tie On 500.00 0.000 232.455 500.00 0.00 0.00 0.00 280663.58 2396065.62 0.00 nd of Tangent _ 59 ~ 1491.61 ~ 73 -242.98 X16 14 280343.01 2395828.54 4.00 nd of Build (XS) 5 1.65. 4.81 1 -^` ~~.45~ ' 4_ 16.77 ^ , ~O l x.04 -1.8.36.11 f -2388 95 f X78241.15 __ , 2394274.15 0.00 ~nd of Tangent (XS) 7562 18_T 0.000 232.455 - 6200.00 3810.50 2322.08 3021 24 ' _ 277600.00 -- - -- 2393800.00 - - 2.00 ~ - -------- rEnd of Dtop (XS) 794~ 18 ~ 0.000 x...455 6581.00 , -- 1 3810.50 - - i 2322.08 I 3021.24 277600.00] 2393800.00 0.00 nd of Tangent (XS) 9418.18 0.000 232.455 8056.00 3810.50 -2322.08 j -3021.24 277600.00 ~ 2393800.00 0.00 nd of Tangent ~nvi.r, at I.A~J11\h Jr.l. 11VL~J xet weubore: CLU-11 Ver 3 Re f Wellpath: CLU-11 Ver 3 String/Diameter Start MD End MD Interval Start TVD End TVD Start N/S Start E/W End N/S End E/W [feet] [feet] [feet] [feet] [feet] [feet] [feet] [feet] [feet] 13.375in Casing Surface 0.00 1606.89 1606.89 0.00 1500.00 0.00 0.00 -247.89 -322.52 9.625in Casing Intermediate 0.00 5623.58 5623.58 0.00 4406.00 0.00 0.00 -1937.39 -2520.72 3.Sin Liner 0.00 9418.18 9418.18 0.00 8056.00 0.00 0.00 -2322.08 ~ -3021.24 i ~c~tu >< ~ Name MD [feet] TVD [feet] North [feet] East [feet] Grid East [us survey feet] Grid North [us survey feet] Latitude [°] Longitude [°] Shape CLU11 -Upper Beluga - 4/5/06 .00 2322.08 3021.24 277600.00 , 2393800.00 , 60 32 47.754N 151 14 07.406W circle 1) CLU11 -Lower Beluga - 4/5/06 7943.18 ~ 6581.00 32 22.08 -- -3021.241 277600.00: 2393800.00 60 32 47.754NI 151 14 07.406W~ circle ]SURVEY PROGRAM Ref Wellbore: CLU-11 Ver 3 Ref Wellnathe r>r.>ri_t t vP.- ~ Start MD End MD [feet] [feet] Tool Type Positional Uncertainty Model Log Name/Comment Wellbore 0.00 9418.18 aviTrak aviTrak(Standard) LU-11 Vera • • Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. INTEGRATED FLUIDS ENGINEERING PROJECT PLAN ~= - :IFE Prepared For: MARATHON OIL COMPANY Well Cannery Loop Unit #11 Kenai Peninsula, Alaska Prepared by: Tony Tykalsky Reviewed by: Mark Fairbanks Presented to: Will Tank April 6, 2006 IFE Ems' • ~~ Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Will Tank Will: • Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Enclosed is the recommended drilling fluid program for the Cannery Loop Unit #11 Well to be drilled this year. The following is a brief synopsis of the program. Overview: CLU #11 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 a 3-1/2" EXCAPE system cemented in place. Surface Interval: The surface interval will be drilled with the standard Gel/Gelex spud mud. No problems were noted in this interval while drilling Cannery Loop # 8, 9, & 10.. Intermediate Interval: This interval will be drilled with aFlo-Pro NT fluid. After drilling out the surface cement, the well will be displaced to a standard F1oPro KCl fluid. SafeCarb bridging material will be maintained according to the mud program to minimize losses to the formation. Fluid loss should be maintained @ 7 - 9 cc's API. NOTE: Since this fluid will also be used in the production interval, care should be taken to maintain recommended mud properties while drilling the intermediate interval. Production Interval: This interval will be drilled with the same fluid that was used to drill the intermediate interval. The fluid will be pre-treated with Bicarb and/or citric acid prior to drilling out the cement. Any further fluid dilutions will be made in order to keep the mud properties at the recommended specifications. Fluid loss should be maintained @ 7 - 9 cc's API for this interval. NOTE: Mud weights as high as 10.0 PPG may be needed to control coal gas at the bottom of this interval. Completion: The cement will be displaced with 6% KCl brine for the completion phase of the program. Conqor 303A and Sodium Meta Bisulfate will be added to the drilling fluid that will be left between the 3-1/2" completion string and the 9-5/8" casing on the final circulation prior to cementing.. ~~ • ~~ Tony Tykalsky Project Engineer /M-I SWACO Reference Wells: CLU #8, CLU #9, CLU #10 Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. NOTE: This program is provided as a guide only. Well conditions will always dictate fluid properties reauired. EXECUTIVE SUMMARY Our overall goal is no spills and no incidents while providing fluids and solids ~" control services to Marathon Oil Company. ., Our goal for Cannery Loop #11 is to remove drill solids from the mud system at a cost of less than $0.29 per pound. ~ ~ With the revised fluid formulation (utilizing the intermediate interval fluid for the production interval}, we expect to drill this well for a product cost of less than $23,94 per foot. With the installation of the two MI-SWACO Mongoose shakers, we expect to limit ~'~ volume usage to less than 5475 barrels. ~~ • '~ Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Interval Benchmarks and Targets Drilling Intervals Depth Benchmark 1 Benchmark 2 Benchmark 3 Benchmark 4 Interval (ft) Fluid cost per foot Volume Usage Solids Removal 0 -1607' < $6.02 ft < 1999 bbls 1607 - < $37.23 ft < 2690 bbls 5624' 5624 - < $17.45 ft < 1065 bbls 9418' Total Avg. Max. Project < $23.94 ft <5754 bbls < $0.29 Ib No Spills from Targets for Centrifuge Van Drilling Operation Interval ~~ ~`' 1~ ~_ Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Project Summary Casing Hole Casing Depth ND Mud Mud Sum Interval Size Slze Program System Weight Days Mud Cost (In) (In) (ft) (ft) Solids Control (ppg) 13 3/8" 16" 1607' 1500' Gel/telex Spud Mud 8.6 - 9.4 5 $13,819 Screens 140 - 175 mesh Desilter Centrifuge Van 9 5/8" 12-1/4" 5624' 4406' Flo-Pro w/SafeCarb 9.1 - 6 $154,645 Screens 175 - 200 < 9.5 'u mesh Desilter Centrifuge Van 3-1/2" 8-1/2" 9418' 8056' Flo-Pro w/SafeCarb 9.1 - 6 $71,187 Screens 200 - 230 10.0 mesh Desilter Centrifuge Van 3 1/2" 8-1/2" Completion 9418' 8056' 6% KCI 8.55 2 $8,877 - 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 includes the use of 2% Lubetex in the intermediate and production intervals. IFE • Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Estimated Product Usage Summary PRODUCT Surface 16" Intermediate 12-1/4" Production 8-1/2" Completion 3-1/2" Total Usage % of Total Cost M-I Bar 0 404 852 0 1256 4.21 M-I Gel 500 0 0 0 500 1.95 Gelex 20 0 0 0 20 0.14 Soda Ash 10 13 11 0 34 0.27 Caustic Soda 10 27 11 0 48 0.90 Conqor 404 0 6 4 0 10 5.61 Sodium Meta Bisulfate 20 27 11 4 62 1.92 Bicarb 10 13 11 0 34 0.27 Conqor 303 0 0 0 4 4 0.85 F1oVis 0 188 75 0 263 24.21 Desco CF 26 0 0 0 26 0.54 Polypac UL 10 94 11 0 115 8.02 KCl 0 1130 447 42 1619 13.31 Safecarb 0 807 320 0 1127 9.57 Lubetex 0 43 17 0 60 19.60 KlaGard 0 18 7 0 25 7.73 Defoam X 0 15 6 0 21 0.88 Engineer Service 5 6 6 2 19 IFE '~rrf Marathon Oil Company Well Name: Cannery Loop Unit # 11 Location: Kenai, Alaska. Offset Well Information Well Hole Size Depth PPG PV YP FL Comments CLU #8 16 120 8.6 8 15 18.8 Spud in, drill ahead 1047 8.8 15 26 18.4 Drlg ahead 1821 9.2 8 23 11.8 Drlg to casing point, run surface casing 12.25 2814 9.1 6 22 10.2 Drlg out, displace to FloPro, Run LOT, drlg ahead 4818 9.2 7 20 8.4 Drlg ahead 6252 9.3 11 23 7.8 Drlg ahead, running 3% lubricant 6722 9.3 10 25 8.6 Drig to casing point, Run 9-5/8" casing 8.5 6745 9 7 19 8.8 Drlg out, displace to FloPro, drlg ahead 7955 9.3 9 23 8.6 Drlg ahead, add lubetex to lower torque 8831 9.45 10 20 8.6 Drlg ahead 9777 9.95 12 27 8.8 Drlg to TD, weight up for gas, condition hole, log same, run tubing 8 cement same CLU #9 16 217 8.8 16 25 13.6 Spud in, drill ahead 1682 8.9 8 22 12.8 Drlg ahead, short trip OK, drlg ahead 2063 9.25 9 21 9.2 Drig to casing point, run surface casing 2063 9.2 7 20 10.4 No cment to surface, do top job. 12.25 2830 9.15 13 20 7.6 Drlg out, LOT = 15.8 ppg, drlg ahead 4575 9.1 7 19 7.2 Drlg to 4006, short trip ok, drlg ahead 5994 9.1 8 19 6.8 Drlg to csg point, wiper trip OK, POH run casing 8.5 6155 9.2 8 19 7.8 Drlg out, LOT, drlg ahead. 7460 9.4 15 22 7.2 Drlg ahead, short trip OK, drlg ahead 8842 9.7 21 20 4.5 Drlg ahead, short trip OK, drlg ahead 9100 9.8 20 20 4.7 TD well, log, stuck wireline, 9100 10.3 21 23 4.7 Weight up due to gas, cleanout run, run excape completion CLU #10 16 123 8.6 10 16 17 Spud in, drill ahead 1955 8.95 11 18 9.8 Drlg ahead 1955 9.1 14 16 9.4 Drlg to casing point, run surface casing 12.25 2610 9 8 10 8.8 Drlg out, displace to FloPro, Run LOT, drag ahead 3585 9.35 9 13 7.2 Short trip OK, 30' fill, drlg ahead 5204 9.1 12 22 6.2 Drlg ahead 5460 9.2 13 23 5.4 Drlg ahead, short trip, some coal bridging, add Asphasol Supreme 5460 9.3 13 24 5.8 Run casing, cement same, OK 8.5 6940 9.4 14 27 5.2 Drig out, LOT 13.1 EMW, drlg eahd 8103 9.4 14 28 6.8 Drlg ahead, short trip, some back reaming required 8450 9.65 18 22 5.8 Drlg ahead pump sweeps at 400' intervals 8450 10.05 18 25 6.2 TD well, log, clean out run 8450 10.05 18 22 6.2 Run and cement completion string. 1~ • ~rf Marathon Oil. Company Well Name: Cannery Loop Unit #11 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. ~ FLUID LOSS CONTROL - In the intermediate interval the API fluid loss will be maintained in the 7 - 9 cc's range. In the production interval the API fluid will be maintained between 6 - 8 cc's at all times. In addition to sufficient fluid loss agent additions, this may require adequate dilution of the mud system in order to keep reactive drill solids to a minimum . ~ LSRV - When drilling with a FloPro fluid, the low shear rate rheology should be maintained at approximately 30,000 cps. In addition to adequate additions of FloVis 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 7.5 ppb in the intermediate and production intervals through aggressive use of solids equipment and dilution as needed. ~ SHALE SHAKERS - M T ~ MIXING CONDITIONS -Whenever possible all treatments to the mud system should be made as pre-mix additions. Polymers and KCI should first be mixed in fresh water in that order and then blended into the active system over one or two circulations as needed. ~ CORROSION - Congor 404 additions should be made daily when drilling with FloPro fluid in order to maintain a Congor 404 concentration of +/- 2000 PPM. ~ CORRISION - Sodium Meta Bisulfate additions should be made daily as needed with any fluid in the hole. Maintain a DO reading of less than 3 ppm ~ SOLIDS VAN USAGE -The Solids Van should be used whenever drill solids become un- acceptably high and reduction of drill solids in the mud can be more economically done with centrifuging and dilution then just with dumping and diluting. The weight of the drilling fluid alone should not be the determining condition for when to use the Solids Van. ~ WEIGHTING UP -All increases in mud weight should be accomplished with barite additions. In the production interval, insure chloride concentration is maintained at 30,000 to minimize the need for barite additions. ~~ • ~~ Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Interval Summary -16" hole 0 - 1607' __ -- - Drilling Fluid System GeUGelex 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 - 140 - 175 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions Interval. Drilling Fluid Properties Depth Mud Funnel Yield API Drill Interval Weight Viscosity Point Fluid Loss pH Solids (ft) (ppg) (sec./qt) (lb./100ftZ) (mV30min) (%) 0 - 1607' 8.6 - 9.4 60 - 100 25 - 35 NC - 12 +/- 9.5 < 7% - Treat drill water with Soda Ash to reduce hardness. - Build spud mud with 20 - 25 PPB M-I Gel to +/- 100 seconds/quart funnel viscosity. - Lower funnel viscosity to +/- 75 after gravel zone has been drilled. - Add Gelex as needed to maintain sufficient viscosity for hole cleaning. - Increase funnel viscosity if fill on connections begins to occur. - Reduce fluid loss with additions of Polypac Supreme UL prior to running surface casing. - Add Sodium Meta Bisulfate to maintain a DO of < 3 PPM. - Condition -mud prior to cementing casing to reduce yield point and gel strengths. - Estimated volume usage for interval - 1999 barrels. - Estimated haul off volume - 3192 barrels. ^rC ~ ~ r~ ~~I ~~ • Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Interval Summary -12-1/4" hole 1607 - 5624'. Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / PolyPac Supreme UL / KCl / SafeCarb 10 & 40 / MI Bar / Caustic Soda / Conqor 404 /Sodium Meta Bisulfate / Lubetex Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended shaker screens - 175 - 200 mesh .Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval Drilling. Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (ppg) (cp.) (cps) (ml/30min) (%) 1607 - 5624' 9.1- < 9.5 8 - 12 30,000+ 7 - 9 < 7.$ < 7.5% - Use one rig pit to drill out surface casing. In other rig pits, build new F1oPro fluid using the enclosed fluid formula. - After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test - If running coals become a problem, treat with a 2 PPB addition of Asphasol D. - If torque or sliding problems occur, add 1 - 2%Lubetex. - NOTE: This fluid will __be used in the production interval. It is inherent to maintain nroner fluid properties for that purpose. - Estimated volume usage for interval - 2690 barrels. - Estimated haul off volume - 3516 barrels. - Condition mud prior to running 9-5/8" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ~~ r ~ • ~~ • Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Fluid Formula -12-1/4" Interval 12-1/4" Interval from 1607 -5624' Descri tion Mud Wei ht Wei ht Material Code Wei ht Material SG Canne Loo 9.1 - 9.2 MI Bar 4.2 In ut Unit #11 Preh drated Gel Preh drated Gel Conc. KCI Wt% Out ut -1 bbl No 6 Order of Products Concentration Volume Product Addition : Field, Ib Lab, m Field, bbl Lab, ml Usa e 1 Water 298.70 298.70 0.853 298.70 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 Flovis 2.00 2.00 0.004 1.33 Viscosit 4 Pol ac Su reme UL 2.00 2.00 0.004 1.25 Fluid Loss Control 5 Caustic Soda 0.50 0.50 0.001 0.23 H Control 6 Potassium Chloride 19.07 19.07 0.023 7.98 Inhibition 8a SafeCarb 10 10.00 10.00 0.010 3.60 Brid in A ent 8b SafeCarb 40 10.00 10.00 0.010 3.60 Brid in A ent 9 Sodium Meta Bisulfate 0.50 0.50 0.000 0.20 O en Scaven er 10 As hasol Su reme 2.00 2.00 0.006 2.08 Wellbore Stabilit If bit ballin becomes a roblem add the followin 11 D-D CWT 1.00 1.00 0.003 1.00 Reduce BHA Ballin If for ue becomes a roblem or slidin i s difficult add u to 3% of the followin 12 Lubetex 14.00 14.00 0.041 14.43 Lubricit Total 399 399 1.000 350 Calculated Mud Wei ht 9.500 Estimated Volume Usa a 2690 Barrels Total Chloride 29600 ~~ ~E • Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Interval Summary - 8-1/2" hole 5624: -.9418' _ Drilling Fluid System __ Flo-Pro Fluid Key Products Flo-Vis / Polypac Supreme UL / KCl / SafeCarb 10 & 40 / MI Bar / Caustic Soda / Conqor 404 /Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended shaker screens - 210 - 230 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval Drilling Fluid Properties Depth Mud Plastic LSRV API Drill. Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (ppg) (cp.) (cps) (ml/30min) (%) 5624 - 9418' 9.1 - 10.0* 10 -14 30,000+ 6 - 8 < 7.5 +/- 5% - Pre-treat drilling fluid with Bicarb and/or citric acid prior to drilling cement. Aggressively treat out cement contamination as soon as feasible. Build additional dilution volume to maintain proper specifications. - If running coals become a problem, treat with a 2 PPB addition of Asphasol Supreme. - Estimated additional volume for interval - 1065 barrels. - Estimated haul off volume - 3061 barrels. - NOTE: Coal gas at the bottom of this interval (+/- 9418' MD) may require mud weights as high as 10.0 PPG to control. - Condition mud prior to running 3-1/2" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen. scavenger and corrosion inhibitor. ~~ ~f • Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Dilution Formula - 8-1/2" Interval 8-/12" Interval from 5624 - 9418' Innut Descri tion Canne Loo Unit #11 .Mud Wei ht 9.1 - 10.0 Preh drated Gel No Wei ht Material Code MI BaR Preh drated Gel Conc. 'Wei ht Material SG 4.2 KCI Wt°io 6 vu~ u~ - ~ uu ~ Order of Products Concentration Volume Product Addition Field Jb Lab m Field, bbl Lab, ml Usa e 1 Water 325.19 325.19 0.929 325.19 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 FloVis Plus 2.00 2.00 0.005 1.34 Viscosi 4 Pol ac Su reme UL 2.00 2.00 0.004 1.34 Fluid Loss Control 5a SafeCarb 10 10.00 10.00 0.012 3.78 Brid in A ent 5b SafeCarb 40 10.00 10.00 0.012 3.78 Brid in A ent 6 Potassium Chloride 20.76 20.76 0.025 8.68 Inhibition 7 CONQOR 404 2.00 2.00 0.004 1.43 Corrosion Control 8 Caustic Soda 0.50 0.50 0.001 0.23 H Control 9 Sodium Meta Bisulfate 0.50 0.25 0.001 0.25 O en Scaven er If slidin or hi h for ue becomes a roblem add 1 - 2% of the followin 10 Lubetex 7.00 7.00 0.021 7.00 Lubricit If sloughing coals become a roblem add 2 - 4 b of the followin 11 As hasol Su reme 2.00 2.00 0.004 1.33 Wellbore Stabilit Mix fluid in the order listed above. Total 380.1 380.1 Estimated Volume Usa a 1065 Barrels Calculated Mud Wei ht 9.050 Total,Chloride 29600 '~ ~i • _~'~ Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Bridging Formula -12-1/4" Interval Edc r,,,y„ Opn°ra Operator: Marathon Oil Company Mez Permeeb@hy : JSO mDsrcy ~Q~~_ ~ PT I ~ R I DG ET" wen Name: Cannery Loop #11 Sand Control Devlce - - - '?"--/ Location: Cannery Loop Field :91990.200/MJ L.L.C.-M Rlphta Reserved Commanta: Sterling C-1. Upper Beluga Opilmum Bridging Agent Blend 1 0 0 cd 0 a_ ~ 0 u 0 a ..~~. 0 E U 0 0 0 V 9 8 Target e 7 S 6 4 2 1 -- 0 ~nw- uw- ~nrv- ~n w' Marv- ttcrv' Pertlcb Size (mkrotte) 1x1o' D10 DtiO • D90 D10 Tergat ! Bbnd: 0.7 I 1.4 mlcrom D50 Target ! Bbnd: 18.7 t 15.5 mlcrom D90 Target I Blend: 60.6 ! 127.3 mlcrom Optimum Blend for 0 to 100 % CPS Range Brand Neme @ridgl Jg Aaentllblbb0 Yol % B~Sab-Garb 10 IFI 10.7 57.78 D-Sa7e.Gerb 10 (M) 9.J 16.62 E-Sete-Garb 250 tC) 0.0 0.00 .. D 46.6% B 53.4°4 Simulation Accuracy Calcium Carbonaos added : 20 ktlbbl Avg Ercor 0 -100 K CPS Rango : 7.50 % Ilan Ercor 0 -100 % CPS Range : 17.01 % - Zone of interest -Sterling C-1 & Upper Beluga sands - Pore Pressure - 4.04 -Maximum Porosity - 350 mD - Measured Depth -+/- 6497' (5211' TVD) - Build additional volume as needed using the blend listed above. ~~ • • ~;'~ Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Interval Summary -Completion Procedures Corrosion Control Additive in Casing x Tubing Annulus Well Cannery Loop #11 Volumes: Tubing Volume 3-1/2" Tubing 81.97 barrels 3.50 x 2.992 x 9418 ft Annular Volume Casing x Tubing 345.11 barrels Open Hole x Tbg 120.23 barrels Total Annular Volume 465.34 Tubing Volume s1.s7 Total Hole Volume 547.31 9.625 x 8.681 @ 5624 ft MD ~ 8.500 x 3.50 @ 9418 ft MD Treatment Procedures. 1. After the 3-1/2" tubing is run and the drilling fluid is circulated and conditioned for the cement job, circulate an additional 445 barrels of drilling fluid. 2. Add 1 drum of Conqor 303A and 1 sack of Sodium Meta Bisulfate for each 90 barrels of drilling fluid pumped (4 drums 8 4 sacks total) 3. After the 345 barrels of drilling fluid with corrosion inhibitors have been pumped downhole, begin the cement job. 4. This procedure will place corrosion control in the 3-112" x 9-5/8" annulus. IFE1~"'' • ~i'~ Marathon Oil Company Well Name: Cannery Loop Unit #11 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. ~~ • • Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS Product Function Health Flammabilit Reactivi PPE ASPHASOL SUPREME Shale Inhibitor 1 1 0 J BORAX Inorganic Borate 1 0 0 E CALCIUM CHLORIDE Densifier 1 0 0 E CIRTIC ACID pH Adjuster 1 0 0 E CONCOR 303A Corrosion Inhibitor 2 1 0 E CONCOR 404 Corrosion Inhibitor 1 1 0 .1 D-D CWT Fluids Additive 2 1 0 J DEFOAM X Defoamer 1 1 0 J DESCO CF Dispersant 1 1 0 E DUAL-FLO Fluids loss reducer 1 1 0 E FORM-A-SET AK Loss circulation Material 1 1 0 E FORM-A-SET XL Fluids Additive 2 1 0 E FORM-A-SET RET Loss circulation Material 1 1 0 J HEC-10 Viscosifier 1 1 0 E FLO-VIS PLUS Viscosifier 1 1 0 E STEEL LOBE EP Oil well additive Lubricant 1 2 0 J SODIUM BICARB Alkalinity control 1 0 0 E SODIUM META Oxygen Scavenger 1 1 0 J SPERSENE CF Dispersant 1 1 0 E GELEX Bentonite Extender 1 0 0 E G-SEAL Graphite LCM 1 1 0 E KLAGARD Shale Control 0 1 0 J LUBETEX Lubricant 1 1 0 J MI BAR Weighting Agent *1 1 0 E MI GEL Viscosifiet *1 1 0 E MI SEAL F, M, C LCM *1 1 0 E IFE • __/\ ~_.. `1~ .7 Marathon Oil Company Well Name: Cannery Loop Unit #11 Location: Kenai, Alaska. MIX II F, M, C LCM *1 1 0 E NUT PLUG F, M, C LCM *1 1 0 E POLYPAC'S Fluid Loss Control *1 1 0 E Potassium Chloride Shale Inhibitor, Densifier 1 0 0 E SafeCarbs (all) Bridging * weighting agent *1 0 0 E SAFEKLEEN Surfactant 1 1 0 J SALT Densifier 1 0 0 E SAPP Dispersant *1 0 0 E SODA ASH Calcium precipitation 1 1 0 E DRILLZONE ROP Enhancer 1 1 0 J SCREENKLEEN Dispersant/Emulsifyer 1 1 0 J BIOBAN BP-PLUS Biocide 2 1 1 J GREENCIDE 25G Biocide 3 0 0 J CAUSTIC POTASH Alkalinity Control 3 0 1 X CAUSTIC SODA Alkalinity Control 3 0 1 X HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (NMIS) HAZARD RATINGS 4 -Severe hazard 3 -Serious hazazd 2 -Moderate hazard 1 -Slight hazard 0 -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 IFE • • ~'~ Marathon Oil Company Well Name: Cannery Loop Unit #11 _ Location: Kenai, Alaska. Contacts Contact Title a-mail Work Cellular Pete Berga Drilling pkberga@marathonoil.com 907 565-3032 907 231-0663 Marathon Superintendent Will Tank Drilling Engineer wjtank@marathonoil.com 713 296-3273 713 203-8398 Marathon Tony Tykalsky Project Engineer ttykalsky@miswaco.com 907 274-5011 907 227-2412 MI SWACO Bob Myles Warehouse Manager rmyles@miswaco.com 907 776-8680 907 252-4218 MI SWACO Michael Barry Senior Field barry.michael@att.net 907 260-4666 907 590-3636 MI SWACO Engineer (home) Locke Rooney Field Engineer rooneyl@alaska.net 907 235-0598 907 590-3636 MI SWACO (home) Dave Morris/ John Drilling Foremen alaska_drilling 907 283-1312 Nicholson @marathonoil.com Marathon Responsibilities - MI Project Engineer and will coordinate daily between the Marathon office, rig, warehouse, and the M-I field engineers. - Well progress will be monitored to look for any changes, which will improve the efficiency of the operation or avert trouble. - Field Engineers will monitor and supervise product inventory to include re-palletizing any products for shipment to other locations at the end of the well. - Field Engineers will communicate with office personnel (Marathon & MI SWACO) for approval of any changes in the mud program (including introduction of new products). - Field Engineers will produce a recap at the end of the well based on daily activities. Recap should include any lessons learned that may be used to provide better service on future wells. Lessons learned can include changes in procedures, product additions, equipment usage, and/or utilization of any third party service. Check No Check Date Bank Bank No Vendor N Marathon Oil Company ACCOUNTS PAYABLE DEPARTMENT Hndlg 1218926 04/18/2006 NCBAS 7780 P. O. Box 22164 5001123 Tulsa,oK 7a1z1-2164 Accts Payable Contact Center Phone 918-925-6097 HS InvpiGe;NUmbF;r InvaiceDate pQcWxtp~tNO f~,erryitcAmmenf C~QSSAmount DiscounE IzzvoieeFPayAmount L100.00 04/18/2006 1900018997 100.00 100. TOTAL: 100.00 100.0 (FOLD ON PERFORATION BELOW AND DETACH CHECK STUB BEFORE DEPOSITING) .- ~~ -~ ®® 0 ® ® °• ® ® • ® '1• - --r-.,_-__,_~__--------_.--~--_a~__~._._- - 'ORM 2501 RcV 5/00 ---- ---_. __ _ ~----- --- ---- ----- ----- ---.-- III, ~ iC 56-389/412 Ma_ rathon Oil Company,,,,,,, ACCOUNTS PAYA E BL CHECK GHECKDA'TE ~tiECK4 UML~ER~~ P. O. Box 22164 N <, TUlsa. OK 74121-2164 041t8/2~O06 `~ 121~$92C ,, PAY;OT~`iEORDEROF- VOID AF-TE,R160 DAYS 1: • ALASKA OIL & GAS CONSERVATION COMMISSION 333 WEST 7TH AVE STE 100 ANCHORAGE, AK 99501-3539 1 ..5'. I~i~/xis MA~GH AMOU ~ ~N WORDSVViTH n ~~ NATIONAL CITY BANK ~i3tlehundradand©01100Dollars Ashland, Ohio ~~. • • TRANSMITTAL LETTER CHECKLIST WELL NAME G ~~ `~ PTD# Z~! - ~ ~~ Development Service Exploratory Stratigraphic Test Non-Conventional Well Circle Appropriate Letter /Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS TEXT FOR APPROVAL LETTER WHAT (OPTIONS) APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well , (If last two digits in permit No. API No. 50- - - API number are , between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - -) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce /inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Non-Conventional production or production testing of coal bed methane is not allowed Well for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company NameZmust contact the Commission to obtain advance approval of such water well testing ro ram. Rev: 1 /25/06 C:\j ody\transmittal_checklist • + a°i ui o a~ Z ~ ~j ~ . ~ ~ ',, I 0', ~ VA N y~ N~ tlY !A~ N' UDC tlD Vh N~ N: N, N, N, N: N N N. N f/T N, N~ N' N, N, Q. Q. Q, Q, ; , , . . ~~'' C ' Q: N ~~ W , ~ v~ T N c . N. : E. 3 c ~ E, ~, o . ~ ~~. N o 0 l : V ~' ~ N i a ~ t: : : ~, o ~ : ~ j a 3' ~ l I O. ~ ~ i I II o. O ~ Y U I ~ ~ ~ ~ ~ ~ ~ : , O. ~ ~, y N: O: Q ~ a ~ ~ ~ ~ ~. o, ,~: w y 'C, O, N: ~ , moo, ~ ~ ~ a' o. ~ ~', y ~ ~ a w ~ °~ m '' c 3 ~~ ' ~ ~ ~ ~ t. ~ 4 c. ~ N N l0 T N J I ~ ~ ~ ~ y0 C. a• ~ O: O C• a f0. N~ ~ ~~ U ~ ~ C. 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