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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 December 13, 2021 Mr. J. Edward Jones Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Re: Location Clearances Aspen 1 (PTD #2051110) Moquawkie 1 (PTD #2030690) Kaloa 2 (PTD #2040960) Moquawkie 3 (PTD #2050800) Lone Creek 1 (PTD #1980840) Moquawkie 4 (PTD #2070840) Lone Creek 3 (PTD #2050970) Simpco Moquawkie 1 (PTD #1780470) Lone Creek 4 (PTD #2070910) Simpco Moquawkie 2 (PTD #1780880) Dear Mr. Jones: On December 20, 2019, the Alaska Oil and Gas Conservation Commission (AOGCC) received the final Well Completion Reports for the plugging and abandonment of the following wells: Aspen 1, Kaloa 2, Lone Creek 1, Lone Creek 3, Lone Creek 4, Moquawkie 1, Moquawkie 3, Moquawkie 4, Simpco Moquawkie 1, and Simpco Moquawkie 2. On June 15, 2021, AOGCC waived witness of each location status and an environmental site assessment (ESA) was conducted by Environmental Management, Inc. on June 17, 2021. AOGCC received a copy of the ESA report along with accompanying photographs of each site on December 7, 2021. Each drill site was found to be in compliance with onshore location clearance requirements as stated in 20 AAC 25.170. The AOGCC requires no further work on the subject wells or locations at this time. However, Plugging Inlet, LLC remains liable if any problems were to occur with these wells in the future. Sincerely, Jessie L. Chmielowski Jeremy M. Price Commissioner Chair, Commissioner May 13, 2020 RECEIVED MAY 18 2020 Jeremy M. Price, Chair AOGCC Alaska Oil and Gas Conservation Commission 333 West 7"' Ave., Suite 100 Anchorage, Alaska 99501 RE: Request for Information 20 AAC 25.300 Docket Number: OTH-20-035 Costs to Plug and Abandon Wells on CIRI Leases Dear Mr. Price: Regarding your letter to me of May 1, 2020, the following information is responding to your request for costs incurred to plug and abandon the following wells on mineral interests owned by Cook Inlet Regional, Inc. (CIRI): • ASPEN 1 – API 50-283-20114-00-00 • KALOA 2 – API 50-283-20107-00-00 • LONE CREEK 1– API 50-283-20096-00-00 • LONE CREEK 3 – API 50-283-20112-00-00 • LONE CREEK 4 – API 50-283-20121-00-00 • MOQUAWKIE 1 –API 50-283-10019-90-00 • MOQUAWKIE 4 – API 50-283-20120-00-00 • SIMPCO MOQUAWKIE 1 –API 50-283-20060-00-00 • SIMPCO MOQUAWKIE 2 – API 50-283-20062-00-00 Plugging Inlet, LLC, was the operator of these wells and conducted plugging and abandonment (P&A) operations between October 2018 and November 2019. Costs were tracked on the basis of vendors, not by well or activity. Thus, while some costs, totaling about $1,007,000, were paid to vendors who worked solely on the P&A of the wells (e.g., Schlumberger, Pollard Wireline, and Halliburton), most of the vendor;/contractors also worked on DR&R, cleanup, and waste disposal operations. Thus, the costs of these vendors/contractors for P&A operations were estimated on the basis of the Summary of Operations, based on the daily reports—these include camp costs, air and marine transportation, supervision, welder and roustabouts, trucking, and equipment rental. It is estimated that another $595,000 were paid to these other contractors and vendors for services supporting P&A work for a total estimated cost to P&A the 10 wells of $1,602,000, or $160,200 per well. However, one well, the Lone Creek 1, was particularly problematic to P&A due to its original construction, and the cost to P&A that well is estimated at about $244,000, leaving the average cost to P&A the other 9 wells at $151,000. For clarity, the reported $1.6 million is for actual well plugging and abandoning costs only; in addition, Inlet Plugging LLC incurred approximately $3.4 million for associated lease remediation activities, including required deconstruction & removal of surface production equipment and restoration of the sites, cleanup of contamination (mostly compressor oil leaks under buildings and some small spills), disposal of waste (including historic drill cuttings and mud solids, contaminated gravel and soil, and used oil and glycol), required Mr. Jeremy M. Price 5/13/20 Page 2 surface use payments, transportation of salvaged equipment and waste, and associated expenses. If you have any questions or require additional information, please contact me at 713-899- 8103 or by email at jejones@aurorapower.com. Sincerely, �ZG 9!Edward Jones Operations Consultant for PLUGGING INLET, LLC 6733 South Yale Avenue Tulsa, OK 74136 CC: Suzanne Settle and Colleen Miller, CIRI Thomas Redman, Jim Sullivan, Mark Can, Plugging Inlet, LLC THE STATE "ALASKA May 1, 2020 GOVERNOR MICKNE•L I. DUNLEAFY J. Edward Jones Operations Consultant Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Re: Request for Information 20 AAC 25.300 Docket Number: OTH-20-035 Dear Mr. Jones: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov The Alaska Oil and Gas Conservation Commission (AOGCC) requests documentation of the actual costs incurred to plug and abandon the following wells: • ASPEN 1 —API 50-283-20114-00-00 • KALOA 2 — API 50-283-20107-00-00 • LONE CREEK 1 —API 50-283-20096-00-00 • LONE CREEK 3 —API 50-283-20112-00-00 • LONE CREEK 4—API 50-283-20121-00-00 • MOQUAWKIE 1 —API 50-283-10019-90-00 • MOQUAWKIE 4 — API 50-283-20120-00-00 • SIMPCO MOQUAWKIE 1 —API 50-283-20060-00-00 • SIMPCO MOQUAWKIE 2 —API 50-283-20062-00-00 The wells are located on mineral interests owned by Cook Inlet Regional, Inc (CIRI). In 2017, Plugging Inlet, LLC was designated operator of record for the wells. This request is made pursuant to 20 AAC 25.300. Should you have any questions about the information request, please contact Guy Schwartz at 907-793-1226. Sincerely, v Jeremy M. Price Chair, Commissioner cc: Suzanne Settle VP Energy, Land, Resources CIRI itCIRI January 14, 2020 James Regg, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 �T ons WrInVeColprwation RE: Onshore location clearance, Plugging Inlet Site located: T12 N R12W, T12N Ri1W, T11N R12W, T12N R11W SM Dear Mr. Regg: This letter is submitted to formally request that the Alaska Oil and Gas Conservation Commission (AOGCC) withhold the site clearance at the location formerly operated by Aurora Gas, LLC. Tyonek Native Corporation (TNC) and Cook Inlet Region, Inc. (CIRI) are the majority landowners within the area and did not have the opportunity to conduct an on-site inspection prior to the 2019 snowfall. CIRI and TNC will conduct an on-site inspection of the property in the spring to ensure the site is reclaimed to the satisfaction of both landowners. TNC and CIRI appreciate the AOGCC's continued cooperation during this process. If you have any questions, please contact Suzanne Settle at (907) 263-5150 or Connie Downing at (907) 272-0707. Sincerely, Tyonek Native Corporation 1 Connie J. Downing Chief Administrative Officer Cook Inlet Region, Inc. Suzanne Settle VP, Energy and Infrastructure Colombie, Jody J (CED) From: Regg, James B (CED) Sent: Monday, January 6, 2020 12:26 PM To: Colombie, Jody J (CED) Cc: Schwartz, Guy L (CED) Subject: FW: Site Clearance - Plugging Inlet See email from CIRI below. Looks like we received the 407s for these December 20 according to the 400 -Logs. Plugging Inlet dragged out the P&As so long this past fall that we were unable to get to locations for site clearance inspections before weather turned (actually had an Inspector and CIRI rep at the airport ready to fly over for site clearance inspections but flights were canceled for weather and there has been snow on the well sites since). Wells affected are: - Aspen #1 (PTD 2051110) - Kaloa #2 (PTD 2040960) - Lone Creek #1 (PTD 1980840) - Lone Creek #3 (PTD 2050970) - Lone Creek #4 (PTD 2070910) - Moquawkie #1 (PTD 2030690) - Moquawkie #3 (PTD 2050800) - Moquawkie #4 (PTD 2070840) - Simpco Moquawkie #1 (PTD 1780470) - Simpco Moquawkie #2 (PTD 1780880) Jim Regg Supervisor, Inspections AOGCC 333 W.7'^ Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.reggPalaska.eov. From: Colleen Miller <cmiller@ciri.com> Sent: Monday, January 6, 2020 11:09 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: Connie Downing <cdowning@tyonek.com>; Suzanne Settle <SSettle@ciri.com>; David Kroto <dkroto@tyonek.com> Subject: Site Clearance - Plugging Inlet Good Morning Jim. I hope you had a great holiday! I'm writing to let you know that CIRI and Tyonek will be issuing a joint letter to request that the AOGCC withhold the site clearance on the Westside until CIRI and Tyonek have an opportunity to get boots on the ground in the spring. As always, please call me if you have any questions. Colleen 263-5117 The information contained in this CIRI email message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply email and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. The information contained in this CIRI email message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply email and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. 2 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION DEC 2 0 WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas❑ SPLUG ❑ Other ❑ Abandoned R] Suspended❑ 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAG❑ WDSPL ❑ No. of Completions: 1b. Well Class: Development E] Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Plugging Inlet, LLC 6. Date Comp., Susp., or Aband.: ` 10/24/2019 14. Permit to Drill Number / Sundry: 207-091 3 /e- 339 0' 3. Address: 66733 South Yale Ave., Tulsa, OK 74136 7. Date Spudded: 11/25/2008 15. API Number: 50-283-20121-00-00 4a. Location of Well (Governmental Section): Surface: 1219' FSL, 127' FWL, SEC 8, T1 2N, R11W, SM Top of Productive Interval: 1205' FSL, 89' FWL, SEC 8, T12N, R11 W, SM Total Depth: 1034' FSL, 340' FWL, SEC 7, T1 2N, R11 W, SM 8. Date TD Reached: 1/2/2009 16. Well Name and Number: Lone Creek #4 9. Ref Elevations: KB: 416' GL: 400' 17. Field / Pool(s): Lone Creek Undefined Gas Field 10. Plug Back Depth MD/TVD: Surf (GL - 4.5') 18. Property Designation: C-61395 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 273378.824 y- 2611312.581 Zone- 4 TPI: x- 273699.433 y- 2611309.283 Zone- 4 Total Depth: x- 273252.075 y- 2611146.189 Zone- 4 11. Total Depth MD/TVD: 2901' MD / 2902' TVD 19. DNR Approval Number: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: Yes ❑ (attached) No Q Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary No new logs were obtained in plugging operations except strip CCL's run inside tubing to set CIBP and perforate tubing. 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD HOLE SIZE CEMENTING RECORD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM PULLED 13-3/8" 68# K-55 Surf 80' Surf 80' Driven Driven 0 9-5/8" 36# K-55 Surf 765' Surf 765' 12-1/4: 80 bbl 15.8 ppg Class G 0 5-1/2" 15.5# K-55 Surf 2350' Surf 2255' 7-7/8" 125 bbl 11.5, 13.5, 15.8 ppg G 0 2-7/8" 6.5# J-55 2093' 2910' 2063' 2820' 4-3/4" 9 bbl 11.5 ppg Class G 0 3-1/2" 9.3# J-55 2910' 3000' 2820' 2902' 4-3/4" 8 bbl 15.8 ppg Class G 0 24. Open to production or injection? Yes ❑ No F�] If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): DATE cq� I D I +�� 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 2-7/8" 2093' 999', 1371', 2093' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes E] No [2]ID/Z�(` Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 1003-1076' 16.5 bbl 15.8 ppg Class G Surf -999' 23.9 bbl 15.8 ppg Class G 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): Plugging and abandonment o eration. Date of Test: Hours Tested: Production for Test Period Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casinq Press: Calculated 24 -Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Form 10-407 Revised 5/2017 DLB 03/25/205/ CONTINUED --0DSR-3 25/2020 RBDMS PAGE 2L`)DEC 2 4 20,�nSubmit ORIGINIAL only XG 3 /z �� 28. CORE DATA Conventional Core(s): Yes ❑ No ❑ Sidewall Cores: Yes ❑ No ❑ If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. No cores were taken in P&A opertaions 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑ If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval information, including reports, per 20 AAC 25.071. See original 10-407 Formation at total depth: 31. List of Attachments: Summary of Daily Operations, Wellbore Schematic, and photos of casing cut-off and marker ID plate. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, al ontolo is I reoort, oroduction or well tet results er 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Ed Jones Contact Name: Ed Jones Authorized Title: O�peraPofts, Consultant Contact Email: AuthorizedContact Phone: 713-899-8103 �� l /) i,"�%_/� Signature: l.� �h Date: </ INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: 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. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only PLUGGING INLET, LLC LONE CREEK #4 (AOGCC PERMIT No. 207-091) (API No. 50-283-20121-00) PLUG AND ABANDONMENT DAILY OPERATIONS SUMMARY FORM 10-407 7/23/17—Aurora Gas operation: RU Pollard slickline (SL), Ran gauge ring to 1076'. Ran PX plug and set in X profile in sliding sleeve (SS) at 1076'. Bled off well. RD SL. 11/17/2018—RU Pollard Hot Oil truck (HO) and pressure test tubing and IA, witnessed by Matt Herrera. Tubing: 2250 to 2200 psi in 30 minutes. IA: 2100 to 2950 psi in 30 minutes. OA - 295 psi. RU Alaska E -line (AEL). PU perf gun with CCL and RIH. Correlate and perf tubing with top at 10_50' with 10 JS. TP dropped from 180 to 0 when shot. POH. PU new perf gun. RIH, correlate and perf tubing with top at 980' with 10 JS. Circulate 1 bbl to confirm last perfs open. RD AEL and HO. 5/20/2019—RU AEL, PU 2-7/8" CIBP, RIH, tag PX plug at 1076'. Pull up and set CIBP at — 6: ((,)1 1074'. POH & RD AEL. (NOTE: this was redundant, not needed—a miscommunication). c, t L 7t 5/23/2019—RU Schlumberger to pump down tubing with returns up IA. Circulate. Test lines to 2300 psi. Mix chemicals, then mix and pump 23.9 bbl Class G cement at 15.6 ppg until good returns to surface. Shut in IA and continue to pump into perfs at 1022-1057' below packer. Pressure to 800 psi, broke back, then built again to 740 psi after 35.4 bbl pumped (16.5 bbl below Acker). Pumped additional 1/4 bbl. Shut in. RD SLB. 5/30/2019—Dig out cellar box and remove. Cut off casing and wellhead. Level casings. 6/1/2019—Mixed cement in buckets and dumped down IA and tubing to fill (20' of tubing). 6/3/2019—Added cement to fill cut-off casing. Cut mousehole at depth of casing. 6/4/2019—Topped off voids in cement in casings. 10/2/2019—Observed some minor bubbles in water covering cellar and cut-off casing. Pumped out cellar hole and flame tested cut-off casings—no sign of gas. 10/8/2019—AOGCC inspector Lou Laubenstein inspected cut-off casing—not cut deep enough. 10/9/2019—Measured for new cut-off depth. 10/11/2019—Pump water out of cellar hole. Dug down and out to expose Typar and original GL-- need to dig down and cut 1-1/2' deeper, will be 47' ' from top of pad. 10/12/2019—Re-cut casingand tubing 1-1/2' deeper. Level cut offs. 10/24/2019—AOGCC inspector Lou Laubenstein re-inspected cut-off casing—good. Weld ID marker plate on 13-3/8" conductor casing. Photographed before and after. Backfilled cellar hole and leveled. 11/14/2019—Graded location pad and photographed. 11/16-17/2019—AOGCC inspector Guy Cook unable to fly from Anchorage due to weather. Cancelled site clearance inspection. Ed Jones 12/5/2019 �_ Aurora Gas, LLC Lone Creek #4 ACTUALP&A OCTOBER 2019 PTD 207-091 API# 50-283-20121-00 Drill 12-1/4" Hole to 765' 2 7/8 6.5# 8rd EUE J-55 Tubing Beluga y an is a ac er a 1022-42' = Perf tubing with top at 1050' 1052-57' �: , Set CIBP at 1074' Sliding Sleeve (a, 1,076' with PX plug. Hydraulic -set Packer @ 1,371' Carya 2-i' 1462-82' 1497-1507' 1516-36' 1546-56' k y4' P r} 5-1/2" 15.54 Production Casing set at k 2,350' MD/ 2260' TVD. Cement in 2 i stages w/ 11.5, 13.5. & 15.8 ppg Class a' ar , Drill 7-7/8" Hole to 2,483' ' Tyonek Carya 2-4.2 2468-82', 91-96', 99-2504' TVD 2373-2409' Tyonek Carya 2-5.2 2820-2860' TVD 2722-62' Drill 4-3/4" Hole to 3,000'MD/2902' TVD Stage Tool @ 1875' Set PX plug in XN profile at 2057' HES BWB Seal Bore Packer, w/ X Nipple. Top @2,041' Inverted On -Off Tool above Arrowset Mechanical Packer @2093' w/ 2.31 profile XN nipple at 20.57' Fill at 2798' last check. 2-7/8" 6.5# 8rd EUE J-55 Tubing to 2,910' 3-1/2" 9.3# 8rd EUE J-55 Tubing to 3,000' Cemented w/ 11.5 and 15.8 ppg cement PBTD @ 2,901' (2803' TVD) � , �9' �4 • } eF' s 13-3/8" 68# Structural Conductor driven to 80' 9-5/8" 36# Surface Casing set at 765' Cement w/ 13.5 ppg Class G COMBINATION PLUG (Beluga Perfs, Surface Casing Shoe, and Surface Plugs) from 1371' (?) to ' surface—perf tubing at 9801. Circulate and squeeze 23.9 bbl Class Y4 G Cement at 15.6 ppg to surface, then F SI IA and squeeze 16.5 bbl into Beluea at 1022-1057' thru oerfs at H__ - Beluga y an is a ac er a 1022-42' = Perf tubing with top at 1050' 1052-57' �: , Set CIBP at 1074' Sliding Sleeve (a, 1,076' with PX plug. Hydraulic -set Packer @ 1,371' Carya 2-i' 1462-82' 1497-1507' 1516-36' 1546-56' k y4' P r} 5-1/2" 15.54 Production Casing set at k 2,350' MD/ 2260' TVD. Cement in 2 i stages w/ 11.5, 13.5. & 15.8 ppg Class a' ar , Drill 7-7/8" Hole to 2,483' ' Tyonek Carya 2-4.2 2468-82', 91-96', 99-2504' TVD 2373-2409' Tyonek Carya 2-5.2 2820-2860' TVD 2722-62' Drill 4-3/4" Hole to 3,000'MD/2902' TVD Stage Tool @ 1875' Set PX plug in XN profile at 2057' HES BWB Seal Bore Packer, w/ X Nipple. Top @2,041' Inverted On -Off Tool above Arrowset Mechanical Packer @2093' w/ 2.31 profile XN nipple at 20.57' Fill at 2798' last check. 2-7/8" 6.5# 8rd EUE J-55 Tubing to 2,910' 3-1/2" 9.3# 8rd EUE J-55 Tubing to 3,000' Cemented w/ 11.5 and 15.8 ppg cement PBTD @ 2,901' (2803' TVD) � : . � ���/�\� »\\\� \T � � � y� ,: .� �� ��>y % * «�� <�3' y 2 . .� .,. - — - « y�$z � � ��� k5 �(§ . ! � , � a� «� y \` y«ƒ���� di�� ^ �\ ��: / �~ � ` \4 .y\ . , 2° � /\ ,`. \� , � � � v: . . . a: � \ \�\\� ,� ^ « ..� y w ..,j }� `Z ���-. `\\. \\ �� \ � ? . ° \ �\.»` � /\ . �\ � / �° . � . \ 1 § `� � �: ' � ` � ; . z� . . :�"� � \\� \� ��� � / ^ . � � z . � . � � . ��� - . � : . � ���/�\� »\\\� \T � � � y� ,: .� �� ��>y % * «�� <�3' y 2 . .� .,. - — - « y�$z � � ��� k5 �(§ . ! � , � a� «� y \` y«ƒ���� di�� ^ �\ ��: / �~ � ` \4 .y\ . , 2° � /\ ,`. \� , � � � v: . . . a: � \ \�\\� ,� ^ « ..� y w ..,j }� `Z ���-. `\\. \\ �� \ � ? . ° \ �\.»` � /\ . �\ � / �° . � . \ 1 § `� � �: ' � ` � ; . z� . . :�"� � \\� \� ��� � / ilk a w `a y " Ks - . -'' �-._ %' _"aE.€�-+.+'.�` �. Vis' es. • - ., , '-'.�"r � �.. .. - s'+ F�.. ip 7 0 ,4 / -. _ 6733 South Yale Avenue Tulsa, OK 74136 Plugging LLC Contact: Ed Jones, Consultant/0 r,,�, 713-899-8103 (C) email: LejonesC�aurorapower.com December 17, 2019 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage AK 99507 RE: Form 10-407 Well Completion Reports for Plugging and Abandoning: Aspen 1 (WDSPL) PTD 205-111 Kaloa 2 PTD 204-096 Lone Creek 1 PTD 198-084 Lone Creek 3 PTD 205-097 Lone Creek 4 PTD 207-091 Moquawkie 1 PTD 203-069 Moquawkie 3 PTD 205-080 Moquawkie 4 PTD 207-084 Simpco Moquawkie 1 PTD 178-047 Simpco Moquawkie 2 PTD 178-088 Dear Commissioners: Enclosed are the Form 10-407 P&A Completion Reports for the above wells, formerly operated by Aurora Gas, LLC, now operated by Plugging Inlet, LLC, all on CIRI leases located on the west side of the Cook Inlet. All the wells have been plugged and abandoned as per AOGCC approved Sundry Application Form 10-403 or as revised approvals. Attached to each Form 10-407 are: 1) Summary of Daily Operations, 2) Final P&A Wellbore Diagrams, 3) Photos of the casing stubs before and after welding on ID marker plates, and 4) Four photos of each of the well (and facility, when appropriate) location pads at the end of the operations in November. Unfortunately, there remained a small amount of location work to do on 4 of the locations prior to being weathered out, but the landowner, Tyonek Native Corporation is aware of this work, and it will be completed by their subsidiary, Tyonek Contractors, when the weather and ground conditions allow. Please let me know if you need more information. v�-..,�� Thank you. / e Sincerely, dJ..dward (Ed) Jone Consultant CC: Colleen Miller, CIRI (electronic) David Kroto, Tyonek Native Corporation Tom Redman, Mark Carr, Jim Sullivan, Plugging Inlet, LLC MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg, ILl&ljq DATE: P. I. Supervisor FROM: Lou Laubenstein SUBJECT: Petroleum Inspector 10/24/19 Surface Abandonment Lone Creek #4 - Plugging Inlet LLC PTD 2070910, --Sundry 318-339 10/8/19: 1 arrived on location for the surface abandonment inspection on Lone Creek #4. David Wallingford was the Company representative on location for the day's inspection. Solid cement was confirmed at surface in the cutoff well. The casing cutoff depth was only cut to 3-4 feet below the current pad grade and not the proper depth of 3 feet minimum below original ground level — this was discussed with Mr. Wallingford. The hole was filled with debris and trash that needs to be removed prior to backfill. Also, there is another piece of casing that was used during the drilling process that should be cut off to the proper depth. I departed location and communicated the deficiencies to AOGCC Inspection Supervisor Jim Regg. 10/24/19: 1 arrived on location for a second inspection to check for proper cut-off depth of the well. The casing had been cut to the required 3 feet below natural grade satisfying the current regulation. Information on the marker plate was verified and installed. Attachments: Photos (4) 2019-1024—Surface Abandon LoneCk-4 11.docx Page 1 of 3 W r1 ? ✓ 6p^ ri y r �r �iy�{'•�'M r� �, ♦► :LLA-. N rRl..tySx"'` h;� IYFR'"R tT■�,47 .� !ll � y-f�♦ � .,��u ,r ev^� .fYl A ti'*L; �,� t � ���,�a�'�� � � i ; 10 /�,s\ AUROR Gams LOOE CREEK 0-18 2 -00-00 1 a h � • PTO e Q 3 -091 Ap "! �„ ' ro �; K .tT . • � !g" 7 ^ etre; t �� L�+: °',6c °`.. '� + +e` ,ice �, n ;^' t: •'>� - Y _ r WN" r AV. a is ...: 4�i'.t e . • +.s : s. o ''.. 4 A e MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg 1Wa 11ti �J�Qj� DATE: November 17, 2018 6_. _ P.I. Supervisor SUBJECT: Well Bore Plug & Abandonment Lone Creek #4 FROM: Matt Herrera Plugging Inlet LLC Petroleum Inspector S(p���® PTD 2070910; Sundry 318-339 Section: 8 - Township: Drilling Rig: NA Rig Elevation: Operator Rep: David Wallingford Casing/Tubing Data (depths are MD): Conductor: 13 3/8" - O.D. Shoe@ Surface: 9 5/8" - O.D. Shoe@ Intermediate: O.D. Shoe@ Production: 51/2" O.D. Shoe@ Liner: O.D. Shoe@ Tubing: 2 7/8" O.D. Tail@ Plugging Data (depths are MD): Test Data: 12N - Range: 11W Meridian: Seward ' Tubing Bridge plug ' 1085 ft Total Depth: 2901 ft (PBTD) Lease No.: C-061395 Suspend: P&A: X Casing Removal: 80 Feet Csg Cut@ Feet 765 Feet Csg Cut@ Feet Feet Csg Cut@ Feet 2350 - Feet Csg Cut@ Feet Feet Csg Cut@ Feet 2901 - Feet Tbg Cut@ Feet Type Plug Founded on Depth Btm Depth To MW Above Verified Tubing Bridge plug ' 1085 ft Wireline tag 295 Initial 15 min 30 min 45 min Result Tubing 190 190 190 P IA 2100 2050 2050 OA 295 295 295 Initial 15 min 30 min 45 min Result Tubing 2250 2200 - 2200 P IA 5 5 5 OA 295 295 295 Remarks: Pressure tests prior to pumping cement for "combination" surface plug (Tbg and IA). Attachments: Photos (2) % rev. 11-28-18 2018-1117_Plug_Verification_LoneCk-4_mh 9 Plug Verification — Lone Creek #4 (PTD 2070910) Photos by AOGCC Inspector M. Herrera 11/17/2018 Aurora Gas, uc I C ti lone Creek No.4 A API #: 50-283-20121-00 1 G Location: 1,219' FSL,127' FWL, Sec. 8, T12N, R11W, SM Permit to Orifi n: 207-091 kv 2018-1117_Plug_Verification_LoneCk-4_mh.docx Page 1 of 1 41 WAW'%, GOVERNOR BILL WALKER George Pollock Consultant Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 SGA%t*0 AUC, 3 0 2016 Re: Lone Creek Field, Undefined Gas Pool, Lone Creek Permit to Drill Number: 207-091 Sundry Number: 318-339 Dear Mr. Pollock: Alaska Oil and Gas Conservation 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1 433 Fax: 907.276.7542 www.aogcc.olaska.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. Plugging Inlet, LLC is to provide a daily operational summary to the AOGCC by email to Guy Schwartz guy.schwartz@alaska.gov and Mel Rixse melvin.rixse@alaska.gov once plugging operations start on the wells. 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. 4i DATED this day of August, 2018. Sincerely, LQ�T� Hollis S. French Chair RBDMS-(16, AUG 2910 STATE OF ALASKA ALASKA OH- AND GAS CONSERVATION COMMSS}ON APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.28D AUG 0 8 2018 5 � 1 z-� 1 I k6GCr 1. Type of Request: Abandon ❑ . Plug Perforations r� Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ suspend El Perforate El 94 Other Stimulate ❑ Pull 7ubft ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Temporary Plug ❑ 2. Operator Name: 4: Current Well Class: 5. Permit to Drill Number. Plugging inlet, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 207-091 - 3. Address: 6733 South Yate Avenue 6. API Number: Tulsa, OK 74136 50-283-20121-00 7. If perforating: $. Well Name and Number: What Regulation or Conservation Order governs well spacft, in this pond? Lone Creek #4 Will planned perforations require a spacing exception? Yes ❑ No ❑ 9. Property Designation (Lease Number): 10. Field/Pool(s): C-061395 I Lone Creek undefined Gars 11. t9RESEN ' WELL COND[TIOU UMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 3000' 2902' 2901' 2803' 500psj 1450" & 2901' None Casing Length size MD TVD Burst Collapse Structural Conductor 80' 13 3/8' 68f K55 Sty 80' 3450 psil 1950 psi Surface 765" 9 5/8" 36# K55 785 785' 3520 psi 2020 psi Jrdermediate Production 235V 5112" 1711 K55 2350' 2255' 5320 psi 4910 psi Liner Perforation Depth MD (#i): Peifioration Depth TVD (ft):ubing Size: Tuning Grade: Tubing MD (ft): 71922' - 2860' 1022' - 2762' 27/8. 6.5#f J55 2901' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Hydraulic set, HES SWB seat bore and Arrowset Mechanical Hydraulic @ 9W & 1076, BWB @ 2041' and Arrowset @ 2093' 12. Attachments: Proposal Summary El Wellbore schematic ❑✓ 93. Well Class after proposed work: Detailed Operations Program ❑ BOP Stretch ❑ Exploratory ❑ Stratigraph c ❑ Development ❑ Service 14. Estimated Date for TBD 15. Well Status after proposed work: Commencing Operations: Olt. ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS [ WAG ❑ GSTOR ❑ SPLUG El 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify thatthe foregoing is true and the procedure approved'herein wti! not be deviated from without prior written approval. Authorized Name: George Pollock Contact Name: George Pollock Authorized Title: Consultant Contact Email: ollock aurora ower.com Contact Phone: 907-351-8286 Authorized Signature: Date: 6 -Aug -18 COLURSS t. USE ONLY Conditions of approval: Notify Commission so that' a representative may witness Sundry Number: r �� Plug Integrity BOP Test ❑ Mechanical Integrity Test ❑ 'Location Ctearan+oe Other: Post Initial Necfion NIIT RegA? Yes ❑ 'No ❑ Spacing Exception Required? Yes No Subsequent Form Required: ! �� ❑ APPROVED !3Y Approved by. COMMISSIONER THE COMMISSION Date: v'-fs'�Y: R1I NAL �BDMS�au Fomr 1D-403 Revered 4/2017 Approved t the tJiBtR of approval- -/ / 14, 2 9 2O Submit Form and Aftadynents in Duplicate • CURRENT CONDITONS: • .AURORA �GAS, LLC WELL ABANDONMENT -Version 1.2 (8/28/17) Max SITP-500 psi. KB= 14.8 feet CASING: 5-1/2", 15.5# K-55 set at 2350'MD/2260'TVD. 2-7/8" 6.5# J-55 EUE Liner 2093- 2910' with 3-1/2" 9.3# J-55 shoe joints 2910-3000' MD/2902'TVD. PBTD=2901'MD/ 2803' l`VD. TUBING: 2=7/8", 6.-5# J-55 8 rd EUE, w/-10.7 ppg"KCl-NaCl-CaCl brine as packer fluid in tbg-csg annulus above top packer and with: Sliding Sleeves at: XD at 1076' (closed—opens downward— closed with PX plug set in profile); XD at 1450' (closed); XD at 1589' (closed), and 2.31" XN nipple at 2057'. Packers: HRP's at 999', and 1371' and with BWB Seal -bore Packer at 2093'w/ with Inverted On -Off tool at 2093', and Arrowset Xl Mechanical Packer at 2093' serving as Hanger for above 2 -7/8" -Line -r. (See attached well -bore and completion diagrams) CAPACITIES: 2-7/8" 6.54 Tubing: 0.00579 bbl/ft; Tubing -Casing Annulus: 0.0152 BPF; 5-1/2", 17# Casing: 0.0232 bbl/ft. Tubing volume to PBTD= 16.8 bbl Annular Volume to top Packer= 15.2 bbl PERI{S: Beluga: 1022-42' and 1052-5 7' behind sleeve at -1076' U. Tyonek (Carya'24) at 1462 -82', -1 -4}7 -l -5077,-1-51E=36',-1346 -56' U. Tyonek (Carya 2-4.2) at 2468-82', 2491-96', 2499-2504' U. Tyonek (Carya 2-5.2) at 2722-62' NOTES: 1) Well is S-shaped directional with maximum deviation of 30.4 degrees at 163 FMD. —SUMMAKY-OF_PLA Vit: RUslickline.-Fill'tuhing with3%oKC1 water or clean_produced water. RIH and pull prong and plug at 1076'. Run gauge ring on slick line, tag fluid level, and check for fill or obstgructions through XN profile at 2057'. Set PX plug in XN profile at 2057. Test PX plug and tubing to 1500 psi. Open sliding sleeves at 1589' and 1076'. RU and perforate tubing at 990' and dump 10.7 ppg KCl-NaCl-CaCI brine into tubing to kill well—add additional clean produced water (or 3% KCl) to tubing and annulus to fill if needed or to kill (not likely). Run CIBP and set in tubing at 1085'. Pick up after setting, drop down, and tag CIBP. RU cementers on tree (thru wing valve) and open =casing=(annulus) valve tfor=returns. E-stablish-circulation=pre-sure=with 5-10=bbl=KCl water at 3 -BPM. Pump 150 sx (173 cf=30.75 bbl) Class G cement (15.8 ppg, 1.15 cf/sk yield) with pump time of 4 hr at 70 degrees -7% excess and displace to surface. When good cement is seen at return line, shut casing annulus valve and continue to pump cement until all is displaced or pressure reached 1,500 psi, squeezing -the Beluga perts at 1023--57' through sliding sleeve at 1076. T'his-will squeeze -the -Beluga perfs and provide one balanced plug to meet the requirements of: 1) .plug perforated intervals,'2) surface casing shoe, and 3) surface plug. Monitor for flow or fall back. Wash out tubing casing annulus to 3-4' below GL. WOC 8 hrs, pressure test to 1500 psi. Bleed .off pressure. MI crane. Remove tree. Cut off casing strings and tubing 34' below GL. Mix any cement needed to fill any casing sting or tubing to cut-off. Weld on permanent marker cap. Call inspector. Upon approval, remove cellar and bury marker. Remove surface equipment from location. Grade location. Take soil samples for confirmation of -no contaminants. PROCEDURE: 1) Pick and move wellhouse. Notify AOGCC inspector of plans for plugging operations 2) Move:inz cementer (pump truck/mixer), bulk cement (200=sx=Cl-ass=G),�slickline/electric line combo unit, water tank with 100 bbl fresh water for cementing, mud "pit" open tank with mixing capability with 100 bbl clean produced water or 3% KCl water, open "cuttings" tank for returns. RU cement pump to :tree .through °wing valve. 3) RU wireline lubricator on tree. RIH and pull prong from PX plug at 1076' KB. Allow pressure to equalize (expect maximum of 500 psi). Check lubricator and tree for leaks. If none, pull PX plug hodve Fun 2.125"+/--ga'-lae ring (('TR, to check for fluid level and run thm XN Winnie at 2057'_ If -restrictions are found, -rumbailer, brushes, -etc. -to -clean-out to -about 2065'. Redress `P'X-plug, if needed, RIH and reset in XN nipple at 2057'. Pressure test tubing and PX plug toI �90 psi. 4) PU shifting tool and open sleeves at 1589' and 1076'. POOH. f` 5) PU and run 1-1/2' perf gun and perforate tubing at 990' to kill well by dumping 1-0:7 ppg KCI :� 0 NaCl-CaCI packer fluid from annulus into tubing. POOH. Allow tubing to stabilize, bleed off / kill any pressure. Add clean produced water or 3% KCl water to fill tubing and casing if needed to kill X11 /T-�+„ 1 , „1,,,.,,., +. 1 x11 „1„� L, ,1 ,,,. ,, , l �, n , ,.+L, __4, -1,-+ 1 1 '7 L,L,II -V1KV.11.-1-1-VLfl:l-K VILL111%, LV-1111-L1TL1l1Ul UJ-V4IV-VV-fJGiVhV1J-VV-1Lk1-V JX11-p1�11J-13 aUVUL-16../ uul). 6) -Run-CIBP and -set at 1085'. -Pick up, drop back down, and tag-CIBP. 7) COMBINATION PLUG: RU cement pumper on wing valve of tree. Open casing valve (tubing - casing annulus) and pump 10 bbl KCl waxer down tubing and establish circulation and pressure at 3 BPM— NOTE: annular fluid is 10.7 ppg KCI-NaCl-CaCI brine—catch and use subsequent wells. Mix and pump 150 sx Class G cement (172.5 cf= 3 0.7 5 bbl) accelerated for 4 hours pump time at 1/ 70 degress,15.8 ppg, 1.15 cf/sk yield) down tubing, circulating cement to surface. Catch annular brine Tor use in -subsequent wens, arvert to open tank as -soon as returns are cement colorea. when good cement is seen in the returns, shut in casing annulus valve and continue pumping until all cement is displaced or until pump pressure reaches 1500 psi—this is squeezing cement into the Beluga perfs at 1022-1057' (7% excess) through the open sliding sleeve at 1076'. This is to be a balanced plug with a squeeze below—monitor for flow or fall back. 8) When cement top is stable, disconnect cementer. Wash out tubing, and tubing -casing annulus to 3- 4' below GL. WOC 8 hours. Pressure test both sides (tubing and annulus) to 1500 psi. Release pressure. MI crane. Remove tree. -Cut oft conductor, surface, and -production casing strings and tubing 3-4'- below GL. Mix any cement needed to fill any casing sting or tubing to cut-off. -Release L ` cementers and slickline units to next location. 9) Fabricate '/4"steel marker -plate cap for 13-3/8" conductor casing, not to extend beyond casing OD, and bead -weld the following information onto marker plate; Aurora (-ias, -LLC 9 20-091 Lone Creek #4 API # 50-283-20121-00 10) Following any necessary inspections, remove cellar and bury marker. Dispose of any waste. Haul KCl water, tanks, and any support equipment to next location. 11) Remove tree and casing/tubing cut-offs, surface production equipment, trash, and any other -materials-trom the location. 'Cleanup,_grade and levellocation. 'lake soil samples and send to lab to Confirm no <contamination. NOTES: 1) Where will .likely be a combo electric line -slick line combo unit on location. Perforating tubing may be done with either slickline or electric line and CIBP's will likely be set on electric line. Ed Jones (8/28/20`17) )I/- S' I N 0 Aurora Gas, LLC Lone Creek #4 Current Configuration (Feb 2016) PTD 207-091 API# 50-283-20121-00 -EX> .146 2-7/8" x 5-'%" annulus to be filled w/ 10.7 ppg KCI-NaCl-CaCI brine Belug, 1022-42 1052-57 Carya 2-1 1462-82' 1497-1507' 1516-36' 1546-56' 5-1/2" 15.5# Production Casing set a 2,350' MD/ 2260' TVD. Cement in 2 stages w/ 11.5,13.5. & 15.8 ppg Clas Drill 7-7/8" Hole to 2,483' Tyonek Carya 2-4.2 2468-82', 91-96', 99-2504 TVD 237.3-2409' Tyonek Cary 2821 TVD 27 Drill 4-3/4" dole to 3,AAA'MD/2902' TL • 2 7/8 6S# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 80' /8" 36# Surface Casing set at 765' ment w/ 13.5 ppg Class G ,draulic Set Packer @ 499' ding Sleeve *_ 1,076' (CLOSED) (draulic-set Packer A 1,371' iding Sleeve @ 1,450' (Closed) tge Tool @ 1875' 'S BWB Seal Bore Packer, w/ X pple. Top @2,041' eerted On -Off Tool above rowset Mechanical Packer @MY 2.31;pro5le XN nipple at 2057' 1,02798' last check. .5# 8rd EUE 3-55 Tubing to 2,910' .3# 8rd EUE J-55 Tubing to 3,000' ed w/ 11.5 and 15.8 ppg cement 01' (2803' TVDt Aumm Gas, LLC , 1 ' ' ' at 2 rya 2-5.2 2D-2866' 722.62' Lone Creek #4 PROPOSED P&A (AUGUST 2017) PTD 207-091 AP1# 50-283-20121-00. 4>0 Drill 12-1/4" Hole to 765' �'r3 f 2-7/8" x 5-%" annulus is now tilled w/ 10.7 ppg KCI-NaCl-CaCl brine, which will be damped thru perfs at 990' to all open perfs above the PX plug at 2057' and tubing below CHIP.ROO BalaZ;a 1022-42' 1052-5T Carya 2- 1462-82 1497-1507 1516- 36' 1546- 56 5-1/2" 15.5# Production Casing set 2,350' MD/ 2260' TVD. Cement in. stages w/ 11.5,135: 8r 15.8 ppg Class Drill -7 -7/8" -Hole to 2483' Tyonek Carya 2-4.2 2468-82',.91-96', 99-2504' TVA 237.1-24119' Tyonek Ca 28 TVD 2 Drill 4-3/4 Hole to 3,000`MD/2902' TVD 2 7/8 6S# 8rd EUE J-55 Tubing 13-3/8" 6811 Structural Conductor driven to 80' 9- C 5/8" 36# Surface Casing set at 765' ement.w/13.5 ppg Class G CO Pe MBINATION PLUG (Beluga rfs, Surface Casing Shoe, and So so Ci Cerface Plugs) from 1371' to rfaces—perf tubing at 990'. rculate and squeeze 150 sx Class G meat to surface and into Beluga at 1402-1469' thru sleeve 1076'. Hydraulic Set Packer a� 999' Sliding Sleeve * 1,076' (Open) Se Sl t CIBP at 1085' Hydraulic -set Packer ®1,371' iding Sleeve @ 1,450' (Closed) Stage Tool @ 1875' Set -PX plug' in-XN profile at 2057' HES BWB Seal Bore Packer, w/ X Nip In Apie. Top @2,041' verted On -Off Tool above rrowset MeehanicatPacker @2093' w/ Fill2.31 profile XN nipple at 2057' at 2798' last cheek. 2-7/8"b.5#Srd EUE J-55 Tubing to 2,910' 3-I/2" 9.3# 8rd EUE J-55 Tubing to 3,000' Cemented w/ 11.5 and 15A ppg cement PBIIi' 2;901'(28WTVD) ' Schwartz, Guy L (DOA) From: George Pollock <gpollock@aurorapower.com> Sent: Thursday, August 23, 2018 5:32 PM To: Schwartz, Guy L (DOA) Subject: FW: Tyonek Native Corporation/Amaroq Surface Use Agreement Guy, The second paragraph below indicates that TNC agrees to have all gravel infrastructure, roads and pads, to remain in place after the wells are plugged and abandoned. This statement covers the sundry application for 10 wells that were submitted to AOGCC with Plugging Inlet, LLC as operator. Let me know if any further information is needed. George Pollock 907.351.8286 From: Rickhart Rowland [mailto:rrowland@tyonek.com] Sent: Thursday, August 23, 2018 4:21 PM To: George Pollock Cc: David Kroto Subject: Tyonek Native Corporation/Amaroq Surface Use Agreement Greetings George, Recently in a meeting with Jack Hively (Tyonek Contractors) and Connie Downing (TNC Chief Admin Officer) Jack explained that a Master Services Agreement was initiated some months ago. - This prompted Connie to ensure that the Surface Use Agreement is dated to the same date as the Master Services Agreement, with payment back dated for each month moving forward until November 2018. We are waiting for the TNC CEO signature. Also, related to the Kaiser Francis/Plugging Inlet Aurora Wells, TNC has notified CIRI and Kaiser Francis that TNC would like to leave all the roads and pads in place. Abandon the underground pipeline in place. Clean up all environmental spills and Remove all other items Sincerely, • :•. Fii- Land & Natural Resources Manager Tyonek Native Corporation . (907) 646-3121 Direct (907) 272-0707 Main rrowland@tvonek.com www.tvonek.com Confidentiality Warning: This e-mail contains information intended only for the use of the individual or entity named above. If the reader of this e- mail is not the intended recipient or the employee or agent responsible for delivering it to the intended recipient, any dissemination, publication or 1 STATE OF ALASKA A On- AND GAS CONSERVATIONCCDM ti)�i REST OF SUNDRY WELL OPERATIOM 1. Operations Abandon U Plug P Fracture Stixruaate U Puff Tubing U Operations stuAdowrr LJ Performed: Suspend [] Pedorate Q Other Stimulate 0 Alter Casing ❑ Chime ApprovedProgram El PlugforReddff [] Perforate New Pool ❑ Repair Weil [] Re-enter Susp Well 0 Temporary Plug 2. Operator Aurora Gas, LLC 4 Well Ciass Before Work: 5. Penma to Drilt Num Name: Development 21 Extakuatory Q Skatigaphic El Servioe ❑ 207-W1 3. Address: 3705 Arctic Blvd. #2114 Anda rage, AK 99W3 6. AP1'Nu;r1ber: 283-20121-00 7. Property Designation (Lease Number): 8. Well Name and Number: C-061395 Lone Creek #4 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): NA Lone Creek Undefined Gas 11. Present Well Condition Summary: otalmiepth-measuired-am 'feet %gs : measured =RMA_- 4fM1 7feet true vertical 2902 feet dunk measured None feet Effective Depth measured 2901 'feet Pecker measured 13D8 - 2841 feet true vertical 2803 feet true vertical 1308-2841 Meet Casing Length Size MD TVD Burst Collapse Structural Coneuctor, 80 -13 3/8 58# K55 80 :80 3450 psi 1950 psf< Surface 768 9 5J8 369 K55 765 765, 3520 psi 2020 psi Intermediate Production 2350 511217#K55 2350' 2255, 5320 psi' 4910 psi Liner Perforation depth Measured depth 1022 - 2860 feet -Twe _\6artiicai deAth -1022 -2M *6t Tubing -(size,, grade, rneasured;and true vertical depth) 27/8 6:5# ,155 2,860 2901 Packers.and SSSV, {type, measured and true vertical=depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): NA SCIANNE0 _iflCeo 13 J L"NE Treatment descriptions including volumes used and final,pressure: NA 13. Representative DailyAverage Production or Injection Data. Oil+63biri Gras-mcf,, Watef-BbIl Casing Pwssupe Tubip }Pressure Prior to well operation: 0 1 0 440 Subsequent to operation: 0 10 0 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Welt Operations fl EVtoratory [] Development Q Service C Stratigraphicc Copies of Logs and Surveys Run ❑ 16. Weill, Status after work: Oil El Gas [Z WDSPL E] . Printed and Electronic Frage Stimulation' Data Q JGSTOR E % f33 ❑ WAG [] GIIN J ® 3USP El SPLUG F] 17. 1 hereby oedify that the foregoing is true and ccs .red to the best of nay krtawfe w. y Number or NIA if C.O_ Fi empt: Authorized Name: George Pollock Corgi Nana:: Authorized Title: myrdr- Prod Ops & Eng Contad Email: gpollockCcDaurorapower.c� Authorized e: �. r " " — Dab 112312018: Contact Phone: 907.351.8286 Form 10-404 Revised 412017�/� R B D W S' V v I !? fi J o d=at rriginat Only 0 AuvorwGa&,;L-LC E Operations Summary— Set Temporary Plug I-AMOCreek#4 Well july23,2017 1430 hours Mobilize to location from TMC 1515 hours R/U WL, PT lubricator w/wellbore ;1-54-5;hours-R-1-H--w--/2.-3-3"-gattgetimg-tolOS61K-B,Tag -nip �P nipple, GOH 1615 hours RIH w/2.4' brush to 1056", brush profile, POOH 1630 hours RIH w/2,7/9" X -Line w/PX Plug to 105 ', W, set plug, POOH, 1700 hours RIH w/2" SB w/Prong to 1056', WT, set Prong, POOH 1745-Iouss -Sleed-,off-well,-monitotP-tessure-30-zminutes,i�3u.&s 1745 hours RD WL 0 • Aurora Gas, LLC Lone Creep #4 Current Configuration July 2017 Drill 12-1/4" Hole to 765' 2-7/8" x 5-%" annulus to be filled w/ 10.7 ppg KCI-NaCl-CaCl-brine Beluga 1022-42 1052-57 Carp 2-1 71462,U 3497-1507' 4516-36 -1516=56 5-1/2"'18# Production Casing set at 2,350' Cement in 2 stages w/ 11.5, 13.5. & 15.8 ppg Class G Drill 7-7/8" Hole to 2,483' Tyonek Carya 2-4.2 2468-82', 91 -96','1K1 -25M TVD 2373-2409' Tyonek Cary. 2820 TVD 27 Drill 4-3/4" Hole to 3,000'MD/2902' 11 2 7/8 6i# 8rd>EUE d-55 Tubing 13-3/8" 684 Structural Conductor driven to 80' V8" 36# 'Surface {rasing set at 765' ment w/ 13.5 ppg Class G Arautic Set Packer (& 999' ► :Ping (a� 1s 56' iding Sleeve * 1;1176' (CLOSED} �draulic-set Packer (a) 1,371' iding Sleeve Q 1,458' (Closed) idiug Sleeve *,1,919' (Closed) tge Tool (Wi 1875' 3S BWB Seal Bore Packer, w/ X pple. Top *2,041' rerted: Ou431' Tod above rowset Mechanical Packer,*M3' 231 profake XN nipple at 2057' [At -279V last cheek. .5# 8rd EUE.3.55: Tubing to 2,910' 3# 8rd EUE J-55 Tubing to 3,000' W w/ 11.5 and 15.8 ppg cement Ill' t21M3' TVM THE STATE F 1 IFOL4 mtw GOVERNOR BILL WALKER George Pollock Manager — Production, Operations, and Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Ste. 410 Anchorage, AK 99503 Re: Lone Creek Field, Undefined Gas Pool, Lone Creek 4 Permit to Drill Number: 207-091 Sundry Number: 317-434 Dear Mr. Pollock: Alaska Oil. and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov SCANNED SEP 2 7 2017, 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, ks4y-�\� Hollis S. French l Chair k� DATED this t' day of September, 2017. RMMMS v:' : Z 7 117 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ADPL CAT M FOR SUNDRY APPROVALS 7r1 AAT 7F Wn RECEIVE nPsz 4 it A 1j(7 1. Type of Request: Abandon Q Plug Perforations ❑ Fracture Stimulate ❑ Repair Well epa ❑ Operations shutdown ❑ Suspend [ Perforate ❑ Other Stimulate ❑ Pull Tubing n Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ After Casing ❑ Other. Temporary Plug ❑ 2. Operator Name: 4. Current liven Class: 5. Permit to Chill Number: Aurora Gas, LLC Exploratory ❑ Development ❑ Stralligraphic ❑ Sentice ❑ 207-091 ` 3. Address: 1400 W. Benson Blvd. Suite 410 6. API Number: Anchorage, AK 99503 50-283-20121-00 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? %U Lone Creek #4 Will planned perforations req—e a spacing exception? Yes ❑ No Z Ati 9. Property Designation (Lease Number): 10. t=ietditot(s): C-061395 j Lone Creek Undefined Gas 11• PRESEW WELL COMT,4111il SUMMARY Total Depth MD (ft)_ Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 3000' 2902' 2.901' 2803° • 500 psi 1450' & 2901' None Casing Length size MD TVD Burst Collapse Structural Conductor 80' 13 3/8" 689 K55 80' 80' 3450 psi 1950 psi Surface 765" 9 5/8" 369 K55 765 765' 3520 psi 2020 psi Intermediate Production 2350' 51/2" 179 K55 2350' 2255' 5320 psi 4910 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (4 Tuts g Size: Tubing Grade.: Tutting MD (tt): 1022'- 2860' 1022' - 2762' 2 7/8" 6.5# J55 2901' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (tt): Hydraulic set, HES BWB seal bare and Arrowset Mechanical hydraulic 40 999' & 1076, BWB @ 2041' and Armwset @ 2093' 12. Attachments: Proposal Summary .r Wellbore schematic Q 13.'Well Class after proposed work: Detailed Operations F'rograrn ❑ BOP Sketch Exploratory ❑ Str is E] Development ❑ ' Service ❑ 14. Estimated Date for TBD 15. Well Status after proposed work: Commencing : OIL ❑ WlNel` ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ , 17. t hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval_ Authorized Name: George Pollock George Pollack Contact Name: Authorized Title: Manager - P ps & Eng Contact Email: apollockaurorapower.com Contact Phone: 907-351-8286 /�� Authorized Signature: -- ' Date: 14 -Sep -17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 317-�3� Plug Integrity BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance Other: RW1WU��+ '� Y b–N r C-XAT OFTF NAARXtefL Pt.A,1� Post Initial Injection MIT Req'd? Yes ❑ No RBDMS GL- SLI'' 2 5 2037 Spacing Exception Required? Yes ❑ No Subsequent Form Required: 10 -401 APPROVED BY j Approved by: COMMISSIONER THE COMMISSION Date: 7r%" 7110/f f `T�lvl JAM `t ( jjj I t") R�&,`�i rn, 10 4tt3 Revd 4r"17aW for 12 Nie ewe of A Submit Form and • AURORA GAS, LLC WELL ABANDONMENT LONE CREEK #4 August 2017 Version 1.2 (8/21 /17) 'C ENT NNT' S: Max SITP-500 psi. KB=14.8 feet CASING: 5-1/2", 15.5# K-55 set at 2350'MD/2260'TVD. 2-7/8" 6.5# J-55 EUE Liner 2093- 2910' with 3-1/2" 9.3# J-55 shoe joints 2910-3000' MD/2902'TVD. PBTD=2901'MD/ 2803' TVD. TUBING. 2-7/8',: 6.5# J-55 9 rd BUB* wl 1`0`7 ppb KCl=NaCl=CaCI brute. as packer, fluid in, tbg-csg annuhis above top packer and with., Sliding Sleeves at: XD at 1076' (closed --opens downward— closed with PX plug set in profile); XD at 1450' (closed); XD at 1589' (closed), and 2.31" XN nipple at 2057'. Packers: HRP's at 999', and 1371' and with BWB Seal -bore Packer at 2093'w/ with Inverted On -Off tool at 2093', and Arrowset X1 Mechanical Packer at 2093' serving as Hanger .for above 2-7/8" Liner. ,(See attached well bore ,and �completion diagrams) CAPACITIES: 2-7/8" 6.5# Tubing: 0.00579 bbl/ft; Tubing -Casing Annulus: 0.0 152 BPF; 5-1/2", 17# Casing: 0.0232 bbl/ft. Tubing volume to PBTD= 16.8 bbl Annular Volume to top Packer= 15.2 bbl PERFS: Beluga: 1022-42' and 1052-57' behind sleeve at 1076' U. Tyonek (Carya.2-l) at 1462-82, 1497-1507', 1516--3`,6',1546.56' U. Tyonek (Carya2-4.2) at 2468-$2', 2491-96T, 2499-2504' U. Tyonek (Carya 2-5.2) at 2722-62' i f NOTES: 1) Well is S-shaped directional with maximum deviation of 30.4 degrees at 163 FMD. SUMMARY OF PLAN. RU slickline. Fill tubing with 3% KCI waterr or.clean produced water. RIH and pull promsand plug at "1.076'_. Run gouge -ing tin slick line, tag fluid, leveland check for fill or ,obsigrudions through XN profile at 2057. Set PX plug in XN profrle at 2057. Test PX plug,and tubing to 1500 psi. 'Open sliding sleeves at 1589' and 1076'. RU and perforate tubing at 990' and dump a 10.7 ppg KCl-NaCl-CaCI brine into tubing to kill well—add additional clean produced water (or 3% KCl) to tubing and annulus to fill if needed or to kill (not likely). Run CIBP and set in tubing at 1085'. Pick up after setting, drop down, and tag CIBP. RU cementers on tree (thru wing valve) and open casing (annulus) valve for returns. Establish circulation pressure with 5-10,bbl KCl water at 3 BPM. <. Pump ISO sx. (173 of=30.75 bbl) Class G cement (15.8 ppg, 1. 15, cflsk yield) with pump, time of 4 hr at 70 degrees -7% excess and displace to swface. When good cemwm is seers at retum lire, sh t casing annulus valve and continue to pump cement until all is displaced or pressure reached 1500 psi, squeezing the Beluga pexfs at. 1023-57'through sliding sleeve at 1076'. This will squeeze the Beluga perfs and provide one ba:1 c1 pl-4gxto;=meet the.requ mets ei 1) plug petforated inls, 2) surface casing ;shoe, and 3) mace plug. Monitor ,dor flow or sf2t13 back. Wash out Wbing casing annulus to 34' below GL. WOC 8 hrs, pressure test to 1500 psi. Bleed off pressure. MI crane. Remove tree. Cut off casing strings and tubing 34' below GL. Mix any cement needed to fill any casing sting or tubing to cut-off. Weld on permanent marker cap. Call inspector. Upon approval, remove cellar and bury marker. Remove surface equipment from location. Grade location. Take soil samples for confirmation of no contaminants. T well P/oow frad,'�. �v/ g6ovr a eq/ 6✓r a/wgfs w,i� a retkf-i' !y �i,jyy c��Or�1' piF wof [xctfr for q �ia•d /,,1 40 ie -14 ell 604C 0410 ,r hot /'cj*o;ned ShrvrM f;n 4�a 71 a wA►l �i�f �e /rma,kio� at✓/i rROCEDURR: and as focitop(t/ 6, Qtv W 1) Pick and move wellhouse. Notify AOGCC inspector of plans for plugging operations 2) Move in cementer (pump truck/mixer), bulk cement (200 .sx Class G), sslicidlne/eiectr c line combo unit, water lank -with 100 bbl fresh water 'for = men irg, nwd "fit",open tank with mixingcapability with 100 bbl clean produced water or 3% KCd water, open "matings" tank for vaurns. RU cement pump to tree through wing valve. 3) RU wireline lubricator on tree. RIH and pull prong from PX plug at 1076' KB. Allow pressure to equalize (expect maximum of 500 psi). Check lubricator and tree for leaks. If none, pull PX plug body. Run 2.125"+/- gauge ring (GR) to check for fluid level and run thru XN nipple at 2057'. If restrictions are found, run bailer, brushes, etc. to cleanout td -about 2065,x. Redress PX plug, if needed, RIH and reset in XIS nipple- at 2057'`. Pressure test tuhi°ng=and PXplug, to, 151- psi. 4) PU shifting tool and open sleeves at 1599' and` 1076'. POOH: 5) PU and run 1-1/2' perf gun and perforate tubing at 990' to kill well by dumping 10.7 ppg KCI- NaCI-CaCI packer fluid from annulus into tubing. POOH. Allow tubing to stabilize, bleed off / kill any pressure. Add clean produced water or 3% KCl water to fill tubing and casing if needed to kill well. (Total volume to fill annulus below packers with open perfs is about 12.7 bbl). 6) Rina-CIBP aaad set at 1085'. Pick,,up, drop back dowry, an&,tagCIBP. 7) COMBINATION PLUG: RU cemeat pumper on wing valve of tree. Open casing valve (tubing - casing annulus) and pump 10 bN KCl water down tubing and establish eirculation and pressure at 3 BPM— NOTE: annular fluid is 10.7 ppg KCl-NaCl-CaCI brine—catch and use subsequent wells. Mix and pump 150 sx Class G cement (172.5 cf= 30.75 bbl) accelerated for 4 hours pump time at 70 degress,15.8 ppg, 1.15 cf/sk yield) down tubing, circulating cement to surface. Catch annular brine for use in subsequent wells, divert to open tank as soon as returns are cement colored. When good cement is seen in the retums, shut in,casing anrwlus valve and continue pumping; until all cement is displaced or until pip pressure reaches 1500 psi --this is squeezing cement into the Beluga perfs at 1022-1057' (7% excess) through the open sliding sleeve at 1076'. This is to be a balanced plug with a squeeze below—monitor for flow or fall back. 8) When cement top is stable, disconnect cementer. Wash out tubing, and tubing -casing annulus to 3- 4' below GL. WOC 8 hours. Pressure test both sides(tubing and annulus to 1500 psi. Release pressure. MI crane..Remove tree. Cut off conductor, ,surface, and,production casing strings and tubing 3-4' below GL. Mix any cement needed to fill =,tiny easing ting,or tubingoto out -off. Release cementers and slickline unitsto next location. (2X -kA¢ -t T css V=DP- 'IV a►11,� IT 9) Fabricate 1/4" steel marker -plate cap for 13-3/8" conductor casing, not to extend beyond casing OD, and bead -weld the following information onto marker plate; t-kJu • Aurora Gas, LLC �({p to Qot �`' ` c�S.�►�c� �v.T e ►mss` PTD # 207-091 �N►htZY1��- P;, t��.u�E w i W-40 Done Creek #4 API # 50-283-20121-00 taill'l 10) Following any necessary inspections, remove cellar and bury marker. Dispose of any waste. Haul KCl water, tanks, and any support equipment to next location. 11) Remove tree and casing/tubing cut-offs, surface production equipment, trash, and any other materials_from,the location. Clean up, grade and Ievel location. Tape soil sees and send to lab to confirm no c(mtaminafiou. NOTES: 1) There will likely be a combo electric line -slick line combo unit on location. Perforating tubing may be done with either slickline or electric line and CIBP's will likely be set on electric line. Ed Jones (8/28/2017) Aurora Gas, LLC Lone geek #4 Current Configuration (Feb 2016) PTD 207-091 API# 50-283-24121-N Drill 12-1/4" hole to 765' 2-7/8" x 5-'/2" annulus to be filled w/ 10.7 ppg IvC1-NaCl-CaC] brine Beluga 1022-42' 1052-57' Carya 2-1 1.462-82' 1497-1507' 1516-36' 1546-56' 5-1/2" 15.5# Production Casing set at 2,350' MD/ 2260' TVD. Cement in 2 stages w/ 11.5,13.5. & 15.8 ppg Class Drill 7-7/8" Hole to 2,483' Tyonek Carya 24.2 2468-82', 91-%', 99-25W TVD 2373-2409' Tyonek Carya 2-5.2 2820-2860' TVD 2722-62' Drill 4-3/4" Bole to 3,000'MD/2902' TVD 0 2 7/8 6S# 8rd EUE J-55 Tubing ' 13-3/8'63# Structural Conductor driven to 80' 9-51" 36# Surface Casing set at 765' Cement w/ 135 ppg Class G b.. Hydraulic Set Packer (1944' Sliding Sleeve 4_i) 1,076' (CLOSED) Hydraulic -set Packer (_a)1,371' Sliding Sleeve * 1,450' (Closed) Stage Tool {x, 1875' HES BW B Seal Bore Packer, w/ X Nipple. Top k 2,041' Inverted On -Off Tool above Arrowset :Mechanical Packer @2093' w/ 231 profile XN nipple at 2057' Fill at 279V laat dwelt. 2-7/8" 6.5# 8rd EUE J-55 Tubing to 2,910' 3-1/2" 93# 3rd LM J-55 Tubing to 3,000' Cemented w/ 11.5 and 15.8 ppg cement PBTD C 2,901' (2803' TVD) 0 0 �._ w__�� nom_ ■ . w t . Lone Creek #4 PROPOSED P&A (AUGUST 2{117) PTD 207-091 API# 50-283-20121-00 Drill 12-1/4" Hole to 765' 2-7/8" x 5-'h" annulus is now Titled w/ 10.7 ppg KCI-raC1 CaCI brine, which will be dumped thru perfs at 990' to all open perfs above the PX plug at 2057' and tithing below CHIP. Beluga 1022-42' 1052-57' Carya 2-1 1462-82' 1497-1507' 151b-36' 1546-56' 5-1/2" 15.5# Production Casing set at 2,350' MD/ 2260' TVD. Cement in 2 stages w/ 11.5, 13.5. & 15.8 ppg Class Drill 7-7/8" Hole to 2,483' Tyonek Carya 2-4.2 2468,82', 91-%', "-25"' TVD 2373-2409" Tyonek Carya 2-5.2 2$29-.2$69' TVD 2722-62' Drill 4-3/4" Hole to3,000'MD/2902' TVD 2 7A 6-';# 9rd EUE 3 -5 -5 -Tubing 13,-318" 689 Structural Conductor driven to 80' 9-5/8" 36# Surface Casing set at 765' T Cement w/ 135 ppg Class G CONMENATION PLUG (Beluga Perfs, Surface Casing Shoe, and Surface Plugs) from 1371' to surface-7perf lalling at 990'. Circulate and squeeze 158 sx Class G Cement to surface and into Beluga at a , , 1402-1469' thru sleeve 10761. --- ` . Hydraulic Set Packer ®999' Sliding Sleeve 1,076' (Open) Set CHIP at 1085' 4W L Hydraulic -set Packer (ai 1,371' Sfi&ng Sleeve * 1,450' (Closed) ,) Stage Tool *e 187T Set PX jbg in Wpoollile MUM' HES BWB Seal Sore Packer, w/ X Mpple. Top ;x.2,041' Inverted On -Off Tool above Arrowset Meebanicat Packer ,2093' w/ 231 profile Xirl nipple at 2057' Fitt at 2798' last check. 2-7/8" 6.5# 8rd EUE J-55 'Tubing to 2,910' ' 3-1/2^' 9.3# 8rd Ely'E J-55 Tubing to 3,600' Cemented w/ 11.5 and 15.9 ppg cement PWB Q 2,"1' (MY TVD) THE STATE GOVERNOR BILL WALKER George Pollock SWNE® JUL 2 6 2017 Manager Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Lone Creek Field, Undefined Gas Pool, Lone Creek 4 Permit to Drill Number: 207-091 Sundry Number: 317-272 Dear Mr. Pollock: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov 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. The Alaska Oil and Gas Conservation Commission (AOGCC) approves the setting of a temporary plug in this well to provide isolation from the reservoir as a short-term barrier. This work does not meet AOGCC's regulatory requirements for suspension or plugging and abandonment of this well. Prior to relinquishing the lease back to the landowner, the operator is required by law to properly plug and abandon this well. 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, Hollis S. French Chair DATED this day of July, 2017. RBDMS I ( JUL 1 1 2017 0 0 RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AIN 16 2017 L� 1. Type of Request: Abandon El Plug Perforations n Fracture Stimulate [-1 Repair Well E] Operations shutdown 0 Suspend n PerforateEl Other StimulateEl Pull Tubing n Change Approved ProgramEl Plug for Redrill El Perforate New Pool [I Re-enter susp, well C1 After Casing n Other Temporary Plug 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Aurora Gas, LLC Exploratory ❑ Development ❑207-091 Stratigraphic Service ❑& * 3. Address: 1400 W. Benson Blvd. Suite 410 API Number.- Anchorage, AK 99503 60-283-20121-00 - 7. If perforating: 8- WeR Name and Xlumber. What Regulation or Conservation Order governs well spacing in this pool? Lone Creek #4. 1 Will planned perforations require a spacing exception? Yes EJ No E] 9. Property Designation (Lease Number): 10. FiekWool(s): /t6 17 C-061395 Lone Creek.0sktgC q� Undefined Gas 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): 3000- r 2902* 2901' 2803' 500 psi 2901 None Casing Length size No WD Burst Collapse Structural Conductor 80, 13 318" 68# K55 80' W. 3450 psi 1950 psi Surface 765" 9 51W 36# K55 765 766 3520 psi 2020 psi Intermediate Production 235V 5112" 17# K55 2350' 2255' 5320 psi 4910 psi Liner I I I I Perforation Depth MD (11): Perforation Depth TVDTubing Size: Tubing Grade: Tubing MD (ft): 1022'-2860' 1022'- 2762' 2 7/8' 6.5# J55 2901' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Hydraulic set, HES BWB seal bore and Arrowset Mechanical Hydraulic @ 999' & 1076', BWB @ 2041' and Arrowset @ 209T 12. Attachments: Proposal Summary F) Wellbore schematic [A 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory [] Stratigraphic ❑ Development ❑ service ❑ 14. Estimated Date for TBD 15. Well Status after proposed work: Commencing Operations: OIL WINJ ❑ WDSPL Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: George Pollock Contact Name: George Pollock Authorized Title: Manager - P 21�01psz-ln Contact Email: oflockaurorapower.com Contact Phone: 907-277-1003 Authorized Signature: Date: 16 -Jun -17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 2--7Z- Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test F1 Location Clearance Other: — ?0-X& 0com% Fz- f 4 )k Post Initial Injection MIT Reqd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: `0 - 4c)4 RBDms JUL 1 1 2017 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date. —4 CI& '"Ta -I 1-111"I Sbrr,#F..rd For D403,+4 -d 412017 0 Rel fal ",lid for 12 months from the date of approval. Aftachrrierds . Duphv�e '��li --& 75-47 0 . Aurora Gas,, June 16, 2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation CommissionE I +1 �r ED 333 West 7u' Avenue, Suite 100 1!' Anchorage, AK 99501 JUN 16 201? Re: Application for Sundry Approval — Set Temporary Plug A QQ Lone Creek #4 Well PTD #: 207-091 API #: 50-283-20121-00 Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to set a temporary plug to secure this onshore development well in the Lone Creek Beluga and Undesignated Gas Field on the west side of Cook Inlet, northeast of the Village of Tyonek. This well is currently shut-in, is capable of producing gas from multiple zones in the Beluga and upper Tyonek sands and is mechanically sound. / Aurora Gas is currently in Chapter 11 bankruptcy protection while attempting to reorganize and emerge with new owners/investors. This application is being submitted as part of our Reorganization Plan filed with the bankruptcy court if liquidation actions are ordered. Aurora Gas, LLC will provide all potential new owners/investors notice of the impending action before on-site activity begins. The proposed work involves setting a plug via wireline in the profile at a depth of 999' above all open perforated intervals to mechanically isolate the reservoir. After the plug is set, tubing pressure will be monitored for 30 minutes to ensure isolation. A back pressure valve will be set and the master valve repaired and then will be closed providing double isolation and the wellhead secured. A follow up pressure reading will be obtained after 24 hours to ensure the integrity of the plug. Please find the attached information as required by 20 AAC 25.110 for your review: • Form 10-403 Sundry Application • Current wellbore diagram illustrating the current well configuration. • Slickline Temporary Plug Set — Generalized Procedure If you have any questions or require any further information, please contact me at (907) 277-1003. Sincerely George Pollock Manager — Production Operations & Engineering 4645 Sweetwater Boulevard, Suite 200 * Sugarland, TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 * Anchorage, AK 99503 * (907) 277-1003 • 0 . _-.Aurora Gas, LLC Lone Creek #4 Current Configuration Feb 2016 Drill 12-1/4" Hole to 765' 2-7/8" x 5-Y:" annulus to be filled w/ 10.7 ppg KCI-NaCl-CaCI brine Belug4 1022-424 1052-57' Carya 2-1 1462-82' 1497-1507' 1516-36' 1546-56' 5-1/2" 18# Production Casing set at 2,350' Cement in 2 stages w/ 11.5, 13.5. & 15.8 ppg Class G Drill 7-7/8" Hole to 2,483' Tyonek Carya 2-4.2 2468-82', 91-%', 99-2504' TVD 2373-2409' Tyonek Carym 2820 - TVD 272 Drill 4-3/4" Hole to 3,000'MD/2902' TV. 2 7/8 65# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 80' /8" 36# Surface Casing set at 765' went w/ 13.5 ppg Class G draulic Set Packer * 999' ding Sleeve a 1,076' (CLOSED) draulic-set Packer fw�: 1,371' ding Sleeve r_& 1,450' (Closed) ding Sleeve on, 1,589' (Closed) ge Tool (a_) 1875' S BW B Seal Bore Packer, w/ X iple. Top ,*2,041' tried On -Off Tool above owset Mechanical Packer � }a.2093' L31 profile XNN nipple at 2057' at 2798' last cheek. * 8rd ELE J-55 Tubing to 2,910' 1# 8rd ELSE J-55 Tubing to 3,000' d w/ 115 and 15.8 ppg cement V (2803' TVD) 0 AURORA GAS, LLC Slickline Temporary Plug Set - Generalized Procedure June 2017 SUMMARY: This procedure describes the steps taken to set a temporary plug in wells operated by Aurora Gas, LLC to secure the well for a short term shut in. RIH with drift for the appropriate sized tool for the tubing, in most cases 2 7/8" tubing with 2.312" or 3 %" tubing with 2.812" X landing nipple profile. Set PYX plug in uppermost landing profile. If a profile is not available, RIH with tubing stop pack -off plug and set above uppermost packer. After plug is set, a negative pressure test will be performed to ensure the plug has isolated the productive intervals from the surface. Upon passing the negative pressure test, the wellhead will be secured. PROCEDURE: 1) AG Operators to shut-in well and monitor pressure while rigging up. 2) RU Pollard Wire Line and lubricator on tree after removal of tree cap. Open well to pressure test lubricator—have pressure gauge on lubricator. 3) RIH with appropriate drift for X profile and sliding sleeves in upper profile. Pass through sleeve approximately 10' to insure safe operation of setting tool. POOH. 4) RIH with PXX Plug body on X -Line running tool. Set Plug body in upper most Sliding sleeve X profile above upper most production packer in well. 5) RIH with RB retrieval tool as running tool with prong. Set Prong in Plug body and POOH. 6) Record pressure and Bleed well bore to zero PSI, Monitor for 30 minutes recording pressure readings at 15 minute intervals. 7) Test successful if no pressure increase observed. If test fails, RIH and reset plug. 8) RDMO Pollard Wire Line. 9) Secure the wellhead. 10) Move to next well. 11) After 24 hours, a pressure reading will be obtained to ensure the integrity of the plug. ,Llo .Sava. W (6/11/2017) 0 0 Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. Qc � - 0 q L Well History File Identifier Organizing (done) ❑ Two-sided III II�I�I II II� II II� ❑ Rescan Needed III IIIIIIII II III III RES N DIGITAL DATA OVERSIZED (Scannable) Co Items: ❑Diskettes, No. [I Maps: Greyscale Items: ❑ Other, No/Type: ❑ Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non -Scannable) r-] Other: ❑ Logs of various kinds: NOTES:❑ Other:: BY: Maria Date: O 7,,, /s/ Project Proofing II I II') 11 I I III I I III BY: Maria Date: 3 /s/ Scanning Preparation x 30 = + = TOTAL PAGES /51 (Count does not include cover sheet) n A BY: Maria _ Date: j n ir% 11 /sl 1/ V 1 Production Scanning Stage 1 Page Count from Scanned File: -15- ()-, (Count does include cover eet) Maria e Count Matches Number in Scanning Preparation: BY: Date: alb/ V� // Stage 1 If NO in stage 1, page(s) discrepancies were found: YES BY: Maria Date: Scanning is complete at this point unless rescanning is required. vrvifl NO iuuimummu Rescanned I!I IIIIIIIIIII VIII BY: Maria Date: /s/ Comments about this file: ou.lit,Ch,c.,, IIIIIIIIIIVIIIIIiI 10/6/2005 Well History File Cover Page. doc DATA SUBMITTAL COMPLIANCE REPORT 3/3/2011 Permit to Drill 2070910 Well Name/No. LONE CREEK 4 Operator AURORA GAS LLC API No. 50-283-20121-00-00 MD 3000 TVD 2902 Completion Date 10/21/2009 Completion Status 1 -GAS Current Status 1 -GAS UIC N REQUIRED INFORMATION Mud Log Yes Samples No Directional Survey Des1 DATA INFORMATION Types Electric or Other Logs Run: PLATFORM EXP, MDT, SLIM ACCESS, TVD/MD LOGS (data taken from Logs Portion of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH/ __ _.— -. e. __._ •�—J.. .._ n.a__a a+a_— fes.. n���...�J /�����..a.. .y a rvieuirnm imuuivai name ....W. .. .... .... ,,..,r ... _ ......_..� / og Mud Log 2 Col 80 3000 Open 2/3/2009 MD Mud log, gas ratio og Mud Log 5 Col 80 3000 Open 2/3/2009 MD Mud log, gas ratio og Mud Log 2 Col 80 2903 Open 2/3/2009 TVD Mud log, gas ratio og Mud Log 5 Col 80 2903 Open 2/3/2009 MD Engineering Log 160g Mud Log 2 Col 80 3000 Open 2/3/2009 MD Engineering Log 1og Mud Log 2 Col 80 2903 Open 2/3/2009 TVD Engineering Log og Induction/Resistivity 5 Col 2354 2986 Open 2/3/2009 Slim Access Platform, SAIT, SLDT, SPCS, GR HDBS 3 -Jan -2009 g Formation Tester 5 Col 1020 2311 Open 3/2/2009 MDT, GR Field Print 18 - Dec -2008 Log Induction/Resistivity 5 Col 50 2460 Open 3/2/2009 Array Indic, CNL, Triple Lithodensity, SP, GR, Cali —Platform Express— D C 17583 duction/Resistivity 0 2467 Open 2/13/2008 Main Pass, Dens, BHT, Nue, Mud, RMS, RCNT, CNTC, NPOR, NPHI Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments • a DATA SUBMITTAL COMPLIANCE REPORT 3/3/2011 Permit to Drill 2070910 Well Name/No. LONE CREEK 4 MD 3000 TVD 2902 ADDITIONAL INFORMATION Well Cored? Y Chips Received? �Y—htd Analysis Y / N Received? Comments: Compliance Reviewed By: Completion Date 10/21/2009 Operator AURORA GAS LLC Completion Status 1 -GAS Current Status 1 -GAS Daily History Received? N Formation Tops V N Date: API No. 50-283-20121-00-00 UIC N • STATE OF ALASKA ALAS AND GAS CONSERVATION COMMISO GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: ✓ Initial AnnualSpecial 1b. Type Test: Lj Stabilized U Non Stabilized L��j Multipoint ❑ Constant Time ❑ Isochronal ❑ Other: 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Aurora Gas, LLC 18 -Jul -09 207-091 3. Address: 6. Date TD Reached: 12. API Number: 1400 West Benson Blvd., Suite 410, Anchorage AK 99503 January 2, 2009 50- 283-20121-00-00 4a. Location of Well (Governmental Section): 7. KB Elevation above MSL (feet): 13. Well Name and Number: Surface: 1,219' FSL, 127' FWL, Sec. 8, T. 12 N., R. 11 W., S.M. 413' (DF) Lone Creek #4 Top of Productive Horizon: 8. Plug Back Depth(MD+TVD): 14. Field/Pool(s): 1,205' FSL, 89' FWL, Sec. 8, T. 12 N., R. 11 W., S.M. 2,901' MD (2,803' TVD) Lone Creek Undefined Gas Field Total Depth: 9. Total Depth (MD + TVD): 1,034' FSL, 340' FEL, Sec. 7, T. 12 N., R. 11 W., S.M. 3,000' MD, (2,902' TVD) 0 4b. Location of Well (State Base Plane Coordinates NAD 27): 10. Land Use Permit: 15. Property Designation: Surface: x- 2611312.581 y- 273738.824 Zone- 4 N/A C-061395 TPI: x- 2611309.283 y- 273699.433 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 2611146.189 y- 273262.075 Zone- 4 Multi -packer Selective w/ Sliding sleeves w/ 2-7/8" liner @ 2,093' 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 5-1/2" 17# 4.89" 2,350' 2,468-82', 2,491-96', 2,499-2,504', 2,820-60' 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 2-7/8" 6.5# 2.44" 2,910' 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocarbons: 23. Specific Gravity Flowing Fluid (G): 999', 1,371', & 2,041' N/A N/A 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): ✓❑ Tubing ❑ Casing 85.4 F° 830.4 psia @ Datum 2,762' TVDSS 14.65 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO2: % N2: % H2S: Prover: Meter Run: Taps: 2,860 2,762 0.5617 0 1.3 0 Daniel Sr. 4.026 Flange 26. FLOW DATA TUBING DATA CASING DATA No. Prover Orifice Line X Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow Size (in.) Size (in.) psig Hw F° psig F° psig F° Hr. 1 • 4 X 1.75 408.55 8.41 45 491 62 1 hr 2.. 4 X 1.75 274.15 19.36 45 459 62 1 hr 3. 4 X 1.75 190.15 40.96 45 422 1 62 1 1 hr 4. 4 X 1.75 139.918 67.24 45 394 62 1 hr 5. X Basic Coefficient Flow Temp. Pressure Gravity Factor Super Comp. Factor Rate of Flow No. (24 -Hour) h Factor Pm Fg Qi Mcfd Fb,or Fp Ft FP v 1. 15.31 59.65 423.2 1.015 1.336 1.001 1,240 2. 15.31 74.77 288.8 1.015 1.336 1.001 1 1,554 3. 15.31 91.58 204.8 1.015 1.336 1.001 1,903 El 4. 15.31 101.93 154.568 1.015 1.336 1.001 2,119 5. Form 10-421 Rev. 7/2009 CONTINUED ON REVERSE WaD,is FEB 2 3 mo in Duplicate for Separator for Flowing No. Pr Temperature Tr z Gas Fluid T Gg G 1. 0.9981 0.562 0.562 2. 0.9981 0 1 0.562 0.562 3. 0.9981 Critical Pressure 0.562 0.562 4. 0.9981 Critical Temperature 0.562 0.562 5. Form 10-421 Rev. 7/2009 CONTINUED ON REVERSE WaD,is FEB 2 3 mo in Duplicate Pc 689 pct 4747210 Pf� 725 pe 525625 No. Pt Pte Pct -Pe PW Pv2 Pc2-Pw2 Ps Pse Pf2-Ps2 1. 506 256036 218685 32 1024 473697 538 289444 236.181 2. 474 224676 250045 48 2304 472417 522 272484 253.14T- 3. 437 190969 283752 40 1600 473121 477 227529 298.096 4. 408 166464 308257 47 2209 472512 455 207025 318.6 5. 25 AOF (Mcfd) 3500 Remarks: AOF and n calculated using Ryder Scott Software, see attached plot. hereby certify that the foregoing is true and correct to the best of my knowledge. Signed �� Title Mgr. Production Ops. & Eng. DEFINITIONS OF SYMBOLS Date 2/22/2010 AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= -F-1-1Z dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas -oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back -pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia PW Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 7/2009 Side 2 0 4 These results were prepared using Reservoir Solutions Software. This is not Ryder Scott work product. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION t� l (RD6/E- WELL COMPLETION OR RECOMPLETION REPO[1T .N , OG 1a. Well Status: Oil ❑ Gas E]SPLUG ❑ Plugged ❑ Abandoned ElSuspended ❑ 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ Other ❑ No. of Completions: 1 b. `.' Development P13cploratory❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Aurora Gas, LLC 5. Date Comp., Susp., or Aband.: October 21, 2009 12. Permit to Drill Number: 207-091 3. Address: 1400 West Benson Blvd, Suite 410 Anchorage, AK. 99503 6. Date Spudded: November 25, 2008 13. API Number: 50-283-20121-00-00 4a. Location of Well (Governmental Section): Surface: 1,219' FSL, 127' FWL, Sec. 8, T. 12 N., R. 11 W., S.M. Top of Productive Horizon: SM 1,205' FSL, 89' FWL, Sec. 8, T. 12 N., R. 11 W., S.M. t`S Total Depth: 1,034' FSL, 340' FEL, Sec. 7, T. 12 N., R. 11 W., S.M. 7. Date TD Reached: January 2, 2009 14. Well Name and Number: Lone Cteek #4 8 IElevation (ft): AMSL (DF) 15. Field/Pool(s): Lone Creek Undefined Gas Field 9. Plug Baric Depth(MD+TVD): 2,901 MD (2,803 TVD) 4b. Location of Well (State Base Plane Coordinates): NAD 27 2611312.581 X - 273738.824 Zone- 4 Surface: yt-- TPH: Y 2611309.283 1 - 273699.433 Zone- 4 Total Depth: 2611146.189 1 - 273262.075 Zone- 4 10. Total Depth (MD + TVD): 3,000 MD (2,902 TVD) 16. Property Designation: C-61395 11. Depth Where SSSV Set: N/A 17. Land Use Permit: CIRI Lease 18. Directional Survey: Yes 0 No (Submit electronic and printed information per 20 AAC 25.050) 19. Water Depth, if Offshore: N/A (ft MSL) 20. Thickness of Permafrost MD/TVD: N/A 21. Logs Obtained (List all logs here and submit electronic and printed information per 20AAC25.071): Schlumberger: Platform Express, MDT, Slim Access. Halliburton: TVD/MD, Mud Logs. 22.Re-drill/Lateral Top Window MD/TVD: N/A 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMT CASING FT TOP BOTTOM TOP BOTTOM PLD 13-3/8" 68.0# K-55 surface 80' surface 80' driven rya 0 9-518" 36.0# K-55 surface 765' surface 765' 12-1/4" 80 bbl, 15.8 ppg Cl. G 0 5-1/2" 18.0# K -W surface 2,350' surface 2,255 1 7-7/8" t 125 bbl, 1'L5, 13.5,15.8 ppg Cl. G 0 3-1/2" 9.3# J-55 2,093' 1 3,000' 2,063' 1 2,902' 4-3/4" 9 bbl, 11.5 ppg Class G 0 2-7/8" 6.5# J-55 2,093' 1 2,910' 2,063' 2,820' n/a 8 bbl, 15.8 ppg Class G 0 24. Open to production or injection? Yes ❑ No ❑ If Yes, list each interval open.(MD#TVD of Top & Bottom; Perforation Size and Number): 1,022'4,042' MD (1,019'-1,039' TVD), 3.5", 6 spf 1,052'-1,057' MD (1,015'4,035' TVD), 3.5", 6 spf 1,462'-1,482' MD (1,426'-1,446' TVD), 3.5", 6 spf 1,497'-1,507' MD (1,457'-1,467' TVD), 3.5", 6 spf 1,516'-1,536' MD (1,474'-1,494' TVD), 3.5", 6 spf 1,546'-1,556' MD (1,500'-1,510' TVD), 3.5", 6 spf 2,468'-2,482' MD (2,373'-2,387' TVD), 2.0", 6 spf 2,491'-2,496' MD (2,396'-2,401' TVD), 2.0", 6 spf 2,499'-2,504' MD (2,404'-2,409' TVD), 2.0", 6 spf / 2,820'-2,860' MD (2,722'-2,762' TVD), 2.0", 6 spf 25. TUBING RECORD SIZE DEPTH SET (MD)PACKER SET (MD/TVD) 2-7/8" 2,093' 1 999', 1,371', 2,041', 2,093' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27, PRODUCTION TEST Date First Production: 7/"aw9 Method of Operation (Flowing, gas lift, etc.): flowing Date of Test: 7/18/2009 Hours Tested: 1,2 Production for Test Period Oil -Bbl: 0 Gas -MCF: 1,745 mcf/d Water -Bbl: 43.1 bbls/d Choke Size: 2", 20-24 bean Gas -Oil Ratio: I WA Flow Tubing Press. 454 Casing Press: 0 Calculated 24 -Hour Rate —.1o. Oil -Bbl: 0 Gas -MCF: 3,655 mcf/d Water -Bbl: 50 bbis/d Oil Gravity- API (core): n/a 28. CORE DATA Conventional Core(s) Acquired? Yes ❑ No ❑� Sidewall Cores Acquired? Yes ❑ No Q If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results jtper 20 AAC 25.071. .'SIV 4Ct i'f I• ��QX i 71. id i' e No cores taken. RBD MS !AN - 5 �► Form 10-407 Revised 7/2009 CONTINUED ON REVERSE Submit original only /I I , 0 • 28. GEOLOGIC MARKERS (List all formations and markers encountered): 29. FORMATION TESTS NAME MD TVD Well tested? Yes M No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if needed, Permafrost - Top n/a n/a and submit detailed test information per 20 AAC 25.071. Permafrost - Base n/a n/a 7/18/09 to 7/19/09: Perform 4 point test Beluga Tsuga 2-8 1,020' 1,017' (Carya 2-4.2 and 2-5.2 perfs are open). ISIP-688.5 psia. Tyonek Carya 2-1 1,461' 1,425' Tyonek Carya 2-4.2 2,466' 2,371' 2,468'-2,482' MD (2,373'-2,387' TVD) Tyonek Carya 2-5.2 2,818' 2,720' 2,491'-2,496' MD (2,396'-2,401' TVD) 2,499'-2,504' MD (2,404'-2,409' TVD) 2,820'-2,860' MD (2,722'-2,762' TVD) Flow well until stable at 4 points: 1,282 mcfpd at 506 psia w/ 10.4 bwpd; 1,618 mcfpd at 474 psia w/ 67.0 bwpd; 1,969 mcfpd at 437 psia w/ 37.0 bwpd; 2,111 mcfdp at 408 psia w/ 58.0 bwpd. (CAOF=3,655 mcfpd) Formation at total depth: 3,000' 2,902- 30. List of Attachments: Daily Operation Summary and Final Directional Survey. Well Schematic and Logs (previously submitted under separate cover) 31. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Aurora Gas, LLC Printed Name: Bruce D. Webb Title: Manager, Land and Regulatory Affairs Signature: Phone: (907) 277-1003 Date: 1/4/2010 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 7/2009 • AURORA GAS, LLC LONE CREEK NO.4 (AOGCC PERMIT No. 207-091) (API No. 50-283-20121-00) 0 DRILLING AND COMPLETION OPERATION SUMMARY 9/15/08-10/15/08—Construct new well pad. 11/1 1/08—Start moving equipment from Moquawkie #4 to Lone Creek 44 location. 11/12/08—Move in rig and related equipment. 11/13/08-11/15/08—Continue move in and rig up and winterize. 11/16/08—Continue rig up and winterize. Cut conductor and install slip-on head. Start NU of diverter system. 11/17/08—RU diverter system, bell nipple, flow line, diverter lines. Continue rig up and winterization. 11/18/08-11/21/08—Continue rig up and winterization. 11 /22/08—Function test diverter, knife valve, gas detectors, flow -line sensors. Make up diverter line. Haul in spud mud from Moquakie #4 and condition same. 11/24/08—State-witnessed test of diverter system and alarms (John Crisp of AOGCC}-- /J Accumulator failed. Repair Koomey system. Retest—OK. 11/25/08—PU 12-1/4" bit, 6" DC's, and RIH to 75'. PU Power Swivel. SPUD at 1645 hrs. Drill to 124'. MW -11.5 ppg. 11/26/08—Drill 12-1/4" hole to 224' w/ 6" DC's. POOH, PU 8" BHA, RIH and drill to 470'. MW -11.5 ppg. 11/27/08—Drill 12-1/4" hole to 765', surf csg point. CBU 3X, with high vis sweep. POH to 640'—tight, swabbing. Pump out of hole to 330'. CBU, recovering lots of cuttings. Cont. POH. MW -11.5 ppg. 11/28/08—Cont. POH. RIH to btm, C & C. Drop ESS tool. POH, surveying every connection. LD 8" BHA. RU to run 9-5/8" casing. Run 9-5/8" 36#, J-55 BTC surface casing. MW -11.5+ ppg. 0 0 11/29/08 -Finishing running 9-5/8" -as ing to 746' (18 jts). RU BJ. Cement casing w/ 15 bbl 13 ppg spacer followed w/ .1(387 sx)15.8 ppg Class G cement at 5 BPM. Displace w/ 46.3 bbl mud -bum plug, floats held -100% returns throughout job. RD BJ. RD diverter system. W.O.C. and W.O. weather. MW -11.6 ppg. 11/30/08-W.O.C. and W.O. welder. Rough cut 9-5/8" casing + cut off 6" of conductor. Prep casing and weld on slip flange onto 9-5/8". Test to 500 psi for 15 min. -OK. Allow to cool. 12/01/08 -NU BOPE. RU flowline and choke and kill lines. Chg rams to 3-1/2". RU to test. Start BOP test, witness waived by Jim Regg. 12/2/08 -Fin test BOP's to 250 psi/3000 psi -several failures -all repaired & retested. / RD test equipment. LD 6-1/2" DC's. 12/3/09-PU 7-7/8" bit and directional BHA. Orient and check MWD. RIH-tag cement at 642'. Test 9-5/8" casing to 1500 psi -lost 145 psi in 30 min. Retested -lost 60 psi and held. PU power swivel. Drill cement and float collar to 74,9''..ill shoe and 15' ton%�V BU 2X. Drill 7-7/8" hole to 785'. CBU. Run FIT w/ 1' 1.5, mud + 223 psi f rppg EMW. Drill directionally to 835'. Svy: 1.95 deg`at''757', 3.06 deg at 821'. -11.5 ppg. 12/4/08 -Directionally drill to 1027'--irlg break ---circ out. Drill to 1297'. CBU 2X. Short trip to shoe -no problems. Dir drill to 1487'. Last svy-26.92 deg at 1443'. MW -11.5 ppg. 12/5/08 -Directionally drill to 1793'. CBU 2X. MWD svy. Short trip to 1265' -no problems. Dir drill to 1820'. Replace swabs in pumps. Dir drill to 1987'. MW -11.5+ ppg- 12/6/08-Dir drill to 2067' and loss full returns (in coal). Fill annulus w/ fill pump - losing 2 bbl/ 5 min. w/ pump off. Mix and spot LCM pill w/ 10 ppb Barofiber and Steelseal in annulus above loss zone. Total loss -143 bbl. Circ slowly at 10 SPM while adding LCM (1 sk/20 min). Build 200 bbl mud volume at 11.1 ppg. Circ around at 10 SPM while cutting MW to 11.1 ppg. Inc pump rate to 94 SPM (normal drilling rate) - no losses. Wash to bottom. Dir drill to 2138'. MW -11.1 ppg. 12/7/08 -Dir drill to 2165' -losing mud. Slow pump and PU. Mix and pump LCM pill on bottom. PU 90' and circ. Drill to 2297'. CBU. Make 10 std wiper trip. Attempt to drill when back on bottom -apparent DH motor failure. POH to check BHA. Mud losses= 15 bb1.24 hrs. MW -11.1 ppg. 12/8/08 -Fin POH. Chg out MWD pulser. LD mud motor -lower bearing section failure. Function test BOP. PU new mud motor. RIH to 2220'. Wash to bottom -no problems. Dir drill to 2358'. No mud losses last 24 hrs. MW -11.1 ppg. 12/9/08—Dir drill to 2477'—pump pressure increase to 2250 psi at 30 SPM. POH w/ tight hole at 1080'. Mud motor seized up. LD mud motor and make up rotary drilling assembly. RIH. No losses in last 24 hours. MW -11.1 ppg. 12/10/08—Fin RIH to bottom. Drill to 2483' and lost full returns (in middle of Carya 2- 4.2 sand). Attempt to fill annulus w/o success. Mix and pump LCM pill—hole taking 100%. SI well—CP 100 psi. Monitor pressures, lube in mud and bleed off as needed. Build mud and LCM pill. Pump 35 bbl LCM pill at 0.75 bpm down annulus. Shut in. Build volume of 10.7 ppg mud. Pump down kill line and establish returns—losing 4-6 bph on %2' choke. Bleed off & open annular. Pump down DP and establish partial returns. Keep annulus full. 12/11/08—Spot LCM pill. Fill annulus. Build mud volume. Lube/bleed well as needed. Mix and spot 40 bbl LCM (at 35 ppb) pill. Build mud volume—attempt to establish circulation. Open annular—well static. Work rotate pipe—attempt to establish circulation. LD 1 it DP. Mix and pump 35 bbl LCM pill w/ 35 ppb LCM. Build volume. Lost 340 bbl last 24 hours. MW -10.8 ppg. 12/12/08 --Continue building volume. Monitor well for flow. Pump down DP every 30 minutes to prevent freezing. Clean out gas buster—packed w/ LCM. POH to 2215'— annulus is static, DP on vacuum—work tight spot. Monitor well, breaking circulation every 30 min. Lost 191 bbl last 24 hours. MW -10.8 ppg. 12/13/08—Monitor well. Mix fluid for Hydroplug. Break circ, --annulus full and static, DP dead. Circ and condition mud to 10.8 ppg at 40 SPM w/o loss. Build mud volume. RIH, wash 2280-2443'. Stage pump up from 30 too 90 SPM—started losing mud. Shut down, lost returns. Worked pipe up to 2265'. Closed rams & vent gas. Mix and pump 25 bbl Hydroplug treatment, displace w/ 15 bbl mud. POH , LD 14 its DP to 2024'. Monitor well. Build mud volume. Lost 265 bbl last 24 hours. MW -10.8 ppg. 12/14/08—Monitor well while building volume. Pump 175 bbl w/ no returns. Monitor well and build mud volume, filling hole every 30 min.—lost 89 bbl in last 6 hrs. Continue building volume, filling annulus each 30 min., loses down to 4 bph. RIH from 2025' to 2435', filling annulus each jt.—lost 57 bbl in 6.5 hr. Fill annulus w/ 10.7 ppg mud w/ LCM-15 bbl loss. Total losses last 24 hrs-336 bbl. MW -10.7 ppg. 12/15/08—Mix and pump 25 bbl Hydroplug pill, displace w/ DP volume of mud. PU to 2050', LD 14 its DP. Fill annulus, monitor well, and build volume—lost 78 bbl in 9 hr. Circ down DP at 11 SPM, got returns after 60 bbl. Lost another 38 bbl in 3-1/2 hr. Monitor well, keeping annulus full—lost 21 bbl last 6 hrs. Lost total of '13 7 bbl last 24 hrs. MW -10.7 ppg. 12/16/08—Keep backside full—took 38 bbl in 11 hrs, down to 1 bbl last 2 hr. RIH to 2247'. Monitor well—took 11 bbls. CBU at 11 SPM—took 17.5 bbl. POH, LD DP to 1960', filling DP. MW -10.7 ppg. 12/17/08 -Monitor well -no losses. CBU at 11 SPM, staging to 24 SPM -no losses. SD -mud flowing back up DP. CBU-balanced MW. POH, back reaming 1646-1580', w/ no losses. CBU at surf casing shoe. Fin POH, LD BHA. Start testing BOPE. MW - 10.7 ppg. 12/18/08 -Finish testing BOP's. RU Schlumberger. Run Array Induction log to 2462' and log out. Run CNL-FDC log. Run MDT tool to 2380' for pressure test -stuck tool at 1741' on POH. W.O. fishing tools. MW -10.7 ppg. 12/19/08-W.0 fishing tools. MU Baker and Schlumberger tools. WL rope socket won't go thru jars, grind down. MW -10.7 ppg. 12/20/08 -Finish MU fishing assembly. RIH w/ 3-3/8" overshot, extension, and CC sub. MU circ head & CBU at 1660' at 30 SPM w/ 280 psi. Worked over top of fish at 1705'. Pulled 40K -fish free. MU new rope socket and RU circ head. Pressured up and sheared out of bk disc at 2600'. Parted electric line at weak point w/ 5k overpull. POH w/ e -line. POH w/ fish on DP. LD logging and fishing tools. PU cleanout BHA. MW -10.7 ppg. 12/21/08-PU clean-out BHA & RIH to 2400'. CBU 2X, conditioning mud. DP flowing back. Mix and pump Dry Job. POH, laying down BHA. RU Schlumberger. Run MDT tool and get pressures 1592-1020'. POH. RD SLB. RIH w/ mule -shoe on DP. MW -10.7 ppg. 12/22/08 -Fin RIH w/ mule shoe to 2407'. Pump at 12 SPM w/ no returns. Work pipe and build LCM pill. Spot 25 bbl pill w/ 37 ppb LCM w/ partial returns. Work pipe to 2377'. Spot 35 bbl pill w/ 37 ppb LCM-regain full returns w/ 15 bbl in pipe. RU BJ. Pump 5 bbl water + 21.5 bbl Class G cement at 14.0 ppg + 0.5 BW. Displace w/ 12 bbl mud -full returns throughout. RD BJ. Pull up to 2000' & CBU 2X at 50 SPM w/ no losses. POH slowly. PU drilling assembly, RIH. Tag cement at 2158' and drill soft cement to 2226'. MW -10.7 ppg. 12/23/08 -Drill firm cement to 2275', then new formation to 2340'. Survey -7 deg. Drill to 2350' (92 SPM at 850 psi). CBU 2X. 10 std short trip. CBU 2X. Circ and cond. Change rams to 5-1/2". Prep to run 5-1/2" casing. MW -10.7 ppg. 12/24/08-W.0 GBR. Run 55 jts of 5-1/2" 15.5# K-55 BTC casing to 2350'. Circ and cond and W.O. BJ 8-1/2 hrs. No mud losses last 24 hrs. MW- 10.7 ppg. 12/25/08-W.O. BJ 24 hours. Circ at 45 SPM and recip 5-1/2" casing. Rack 2-7/8" tubing -clean, rabbit, and visually inspect ---cull 59 jts. MW -10.7 ppg. 12/26/08-W.O. BJ 11 hrs circ and recip 5-1/2". RU BJ. Pump 1St stage: 2 BW + 40 bbl spacer at 12.0 ppg Y3V bbl (72 sx) Class G cement at 11.5 ppg & 2.37 cf/sk. Drop opening dart, displa / 61.2 bbl, shear out & open stage tool at 3120 psi. Full returns throughout. Bleed off. CBU, recover 15 bbl spacer. MW -10.7 ppg. 12/27/08-W.O.C., circ t g tool at 45 SPM at 150 psi. Pump 2na stage: 5 B + 45 bbl spacer at 12.0 ppg �V5pglbl lead cement blend at 13.5 ppg & 1.89 cf/sk 44.$r,bbl tail cement blend at & 1.18 cf/sk + 48 bbl 10.7 ppg mud displacement. Bump plug and close stage tool at 1700 psi. Bleed back 2.5 bbl. Clean & RD BJ. Change to 2-7/8" rams. ND stack and set slips. Test to 3000 psi. NU BOP and start / BOP test. MW -10.7 ppg. 12/28/08 --Continue BOP test while cleaning pits and repairing tubing board. Annular preventer failed. Remove and replace annular. MW -10.7 ppg. 12/29/08 -Fin install new annular preventer. Fin BOP test. Install wear ring. PU 4-3/4" bit and 3-1/8" DC's. RIH on 2-7/8" tubing workstring to 1871' -tag stage tool. Displace w/ new 9.3 ppg PHPA mud. Drill stage tool 1871-74'. Wash to 2259'. Test casing to 2000 psi -OK. Drill cement and baffle at 2266'. MW -9.3 ppg. 12/30/08 -Drill cement 2266-2304', drill float collar at 2304', cement to 2350', float shoe at 2350', cement to 2360', and new hole to 23751. CBU. Drill to 2484' -lost returns. Pull up. Mix and pump LCM pill. Cut MW to 9.1 ppg & attempt to circ around. Mud lost last 24 hrs-38 bbl. MW -9.1- ppg. 12/31/08 -Circ and cond mud, reduce MW to 9.0 ppg-regain full returns. Wash to bottom at 2484'. CBU. Drill 4-3/4" hole to 2611'. CBU 2X. Start POH, swabbing. CBU-705 units of gas. Circ and cond, increase MW to 9.3 ppg-hole took 51 bbl. POH. MW -9.3 ppg. 1/1/09 -Fin POH. PU WF mud motor and insert bit. RIH w/ DC's to 400' and test mud motor -good. RIH to 1317', circ and cond, reduce MW to 9.0 ppg. Build volume while repair rig. RIH to 2435'. Circ and cond mud to 9.0 ppg. Tag fill at 2450'. Wash to bottom at 2611'. Drill 4-3/4" hole to 2710'. Lost 34 bbl mud/ 24 hrs. MW -9.0 ppg. 1/2/09 -Drill to 3000' (TD). CBU. Increase MW to 9.2 ppg + add LCM. POH to 2873' -tight w/ 15K overpull. CBU-losses negligible. POH to 2650' tight. CBU. Gas shows at 2828' (380 u -top of 2-5.2), 2880' (435 a in coal), and 2947' (228 u -top of 2-6 sand -tight). MW -9.2 ppg. 1/3/09-CBU w/ little gas or mud loss. Short trip to shoe. RIH to 3000', CBU. POH, 1St 3 stds tight. LD motor and jars. RU Schlumberger. Run #1 -AIT (array induction), #2-LDT density log, and #3-HGNS neutron log. RD SLB. PU BHA for cleanout run. MW -9.2 ppg. 1/4/09-RIH w/ rotating BHA to 1600'-CBU, to 2350'-CBU, to 2970'. Wash to bottom. Circ and cond mud. POH, LD BHA. RU to run liner. PU 3-1/2" shoe assembly. MW -9.2 ppg. 1/5/09—PU and RIH w/ 3-1/2" X 2-7/8" XO, 2-7/8" tubing (for liner), Arrowset packer, inverted on-off tool, and 2-7/8" tubing. Tag fill at 2550'— to 2595'. CBU. RIH to 2996'. Circ and RU BJ to 92ffient. Pump 5 bbl KCl water_ 9. bl (22 sx) Light Class G at 11.5 ppg (2.37 cf/sk)8.2 bl (39 sx) Class G cement at 15.8 ppg (1.18 cf/sk). Drop wiper plug and displace w/ 9.3 ppg KCl water with rig pump—bumped plug at 1100 psi. Floats held. Unable to set packer, h9AgJiner on packer slips. Release from liner and displace well w/ 9.3 ppg KCl brino cement returns. POH and LD on-off insert. 1/6/09—Test BOP'S. PU 5-1/2" casing scraper and RIH to tag liner top at 2093'. Mix 9.3 ppg brine. 1/7/09—Pump high -vis sweep and displace hole w/ clean 9.3 ppg brine. POH w/ scraper and LD. PU HES BWB seal -bore packer w/ on-off insert and RIH on 2-7/8" tubing. Stab into on-off skirt at 2093'. Build volume of 10.7 ppg KCl-NaCl-CaCI brine. Drop ball and pump up to 2000 psi to set packer. Pump up to 4600 psi to shear out ball. Test annulus to 1500 psi. Displace w/ 10.7 ppg brine. POH w/ packer setting tool. 1/8/09—Finish POH and LD setting tools. RU Schlumberger. Run CBL in 5-1/2" casing to 2039'. ND flow nipple and NU shooting flange and SLB lubricator—test to 1000 psi. Perforate: the Carya 2-1 sands at 1546-56', 1516-36',1497-1507', and 1462-82' and Beluga (Tsuga 2-8) at 1052-75' and 1022-42' in 6 runs. RD lubricator and shooting flange. Monitor well—no gains or losses. MW -10.7 ppg (KCl-CaCI brine). 1/9/09 NU flow nipple and lines. Open well—took 3 bbl to fill. RIH w/ casing scraper to 1600'. Circ and cond brine—would not clean up. POH w/ scraper and LD. PU and run HES completion string w/ seal assembly, 2 sliding sleeves, hydraulic packer, sliding sleeve, and 2nd hydraulic packer on 2-7/8" tubing, drift while RIH. Tag packer. PU and wash down to stab in. RU Pollard and run 2.25" gauge ring -tagged at 2810'. Run 2.0" GR and tag same. Displace well with clean 10.7 ppg KCl-CaCI brine. Measure to space out. 1/10/09—Spot corrosion inhibited brine in annulus. PU pups and space out. Land tubing. Set 2 -way check. Test tubing hanger seals to 3000 psi. Pull check. Pressure up and set hydris ackers at 1371' and 999'. Test annulus to 1500 psi—OK. Install �-- BPV and XD BO . NU tree—test void to 3000 psi. Pull BPV and set 2 -way check. Test tree to 30 Pull check. RU Pollard and run impression block to 2810'—flat bottom, no impression. 1/11/09—PU Pollard chisel baler and run to 2810'. Work. POH—rec cement chips w/ rubber and metal pieces. RU Pollard lubricator. Pollard truck hydraulics failed. W.O. mechanic and new crew. RU test unit. Start RD of non-essential rig equipment. 1/12/09—RIH w/ tool on survey wireline and open sliding sleeve at 1076'. RD Pollard lubricator. RU AWS lubricator. Swab FL to 1050'—rec some sand. Fluid dried up. SI to monitor pressure buildup -8 psi. Made 2 swab runs to 1050'—no recovery. RD AWS lubricator. RU Pollard lubricator. RIH and close sleeve at 1076', then open sliding sleeves at 1589' an 1449'. Sl till AM. RD floor. 1/13/09—RU to swab and run swab—tag FL at 140'. Swab to 1000' and well kicked off. Flowed to test separator and flare at L.T. 10 psi. Swab to 1065'—rec 9.7 ppg brine. Sl for 15 min -20 psi. Swab to 1065'—rec 9.2 ppg brine. Flow to test separator—small intermittent flame. RD lubricators. Release rig and rig down. 1/14/09—Continue rig down. SI well for 1 hr -12 psi. Bled off to set BPV and well started flowing—unloaded 3 bbl to trip tank, switch to test separator. Rec 8 bbl w/ last wt 8.5 ppg. Continue rig down and flowing well to test unit. Max SIP -50 psi, which bled off immediately. Bled off, set BPV. Continue rig down. 1/15-21/09—Rig down, clean up and winterize equipment, clean up location. 1/22-25/09—Move out rig and equipment. 2/12/09—RU Pollard. RIH w/ 2.25" gauge ring; tag FL at 1080' and fill at 2680'. RIH w/ shifting tool and close sleeves at 1589' and 1449'. RIH w/ 1.75" lead impression block to tag at 2680'. 2/16/09—Plowed roads to LC 4 location and camp. Move snow in Moquawkie yard to get fuel tank and other equipment. 2/17/09—Fin plowing roads. Haul fuel tank to location. BJ to location at noon for recon—back to Beluga to get coiled tubing unit (CTU), on location at 1700 hrs. Notify AOGCC of BOP test (at 1430). Spot equipment and start RU. Peak crane on location at 2100 hrs. Continue RU. 2/18/09—RU CTU. Move in and rig up small AWS mud system. Set BOP's and test. / Haul in 200 bbl produced water and add friction reducer. PU CT injector and install on tree. RIH w/ 1.75" coiled tubing and wash to 2859'. CBU. POH, circulating. Install CT lubricator and test BOP connection. PU mud motor w/ 5 -blade concave mill, and ECTD. RIH, wash to bottom at 2855'. Drill cement to 2900'. 2/19/09—Drill cement to 2901'—motor stalled, CBU. Mix 30 bbl 2% KCl in clean produced water. Pump and circ KCl water around. POH. RD CTU. Blow down coil w/ gas from LC pipeline, then purge w/ N2. Release BJ. Empty pits to LC PW tank, SD for night. 2/20/09—RU Pollard. Swab well—pulled out off rope socket & lost swab tools. FL - 810'. POH w/ slick line. RIH w/ impression block, tag fish at 955'—no wire left in hole on top of rope socket. RIH w/ fishing tool latch onto rope socket, and POH w/ fish. RIH w/ gauge ring to tag bottom. RIH w/ 10' dummy gun—set down at 1315'. Added knuckle joint and went thru w/o problem. RIH to 970' to swab—wire line parted at 667'. POH. Fished wire and swab assembly. RIH w/ 24' rigid tool w/o problem. SDFN. 2/21/09—W.O. Schlumberger. RU same. Hydrotest lubricator to 1800 psi. RIH, correlate and perforate Carya 2-5.2 at 2820-2860' in 4 runs w/ 10' 2 -in. PowerJet omega guns w/ 6 SPF w/ no pressure increase at surface. RD SLB. 3/17/09—RU Pollard. RIH w/ 2.2" gauge ring to 2905'. Run pressure survey: 37 psia, 43 deg F at surface, FL at 968.5'-38 psia and 49.6 def F; max pressure=830 psia at 85 deg F at 2860'. RIH w/ selective shifting tool and open sliding sleeves at 1589' and 1449' w/ no pressure increase. 3/19/09—RU Pollard w/ lubricator. RIH w/ 1.67" pump bailer to 2847', bail to 2885' in 5 runs. Change to 2.25" DD bailer w/ spring-loaded ball check. RIH and tag FL at 900'. Bail to 950', pull out w/ water. Make 20 more runs, FL stable at 944'. Rec about 1 bbl water. SDFN. 3/20/09—RU Pollard. Run 18.5' 2.25" bailer w/ ball check. Tag FL at 914'. POH w/ full. Make 24 more runs—FL at 944' last 2 runs. Rec +/-1-1/4 bbl. SDFN. 3/21/09—RU Pollard and run 8' 2.25" bailer. Tag FL at 928'. POH w/ sample of water. RIH w/ 2.2" gauge ring—tag fill at 2864'. RIH w/ shifting tool to 1589' and verified that all 3 sleeves were closed. RD and release Pollard. 5/22/09—RU Schlumberger and run RST Sigma log from 2839' to 723' (tag bottom at 2852'). Attempt to run SCMT cement bond log—tool failed. RD and release SLB. 5/28/09—RU SLB. Run SCMT cement bond log from 2860-2050'. RD & release SLB. 7/02/09—RU Pollard. RIH w/ 2" DD bailer to 2851', worked to 2856'. POH—rec sticky clay. FL -1000'. Run bailer 2X to 2868'—rec same clay. RIH w/2.30" gauge ring to 2868'. Run bailer 4X 2864-2885', rec clay and slurry. RIH w/ 2.30" gauge ring to 2885', edges rolled in. Ran DD bailer to 2885', rec fluid. RIH w/ 2.45" BL brush, work 2820-85'. RIH w/ bailer to 2885', rec fluid. RD and release Pollard. 7/14/09—RU Schlumberger. Run GR -CCL log and correlate to SCMT log of 5/22/09. Perforate Carya 2-4.2 at 2491-96' and 2495-2504' w/ 15' 2" PowerJet Omega gun w/ 6 SPF w/ 60 deg phasing. Perf 2468-82' w/ second gun. RD and release SLB. 7/18-19/09—RU AG test unit and perform 4 point test (Carya 2-4.2 and 2-5.2 perfs are open). ISIP-688.5 psia. Flow well until stable at 4 points: 1282 mcfpd at 506 psia w/ 10.4 bwpd; 1618 mcfpd at 474 psia w/ 67 bwpd; 1969 mcfpd at 437 psia w/ 37 bwpd; and 2111 mcfdp at 408 psia w/ 58 bwpd. (CAOF=3655 mcfpd). SI and allow to build up for 13-1/2 hours—FSIP-687.5 psia. 7/31/09—RU Pollard w/ lubricator. RIH w/ 1.75" gauge ring to 2838'. RIH w/ 1.75" DD bailer to 2838' and work to 2842'—POH—full of sand. RIH w/ tandem bhp gauges for static survey at 2831' . POH. Open well and flow until stable thru test unit. Run W 01 production spinner/pressure/temp log to 2833'—make multiple runs. POH. SI well, SDFN. (Log showed most gas is coming from 2462-82' and most water from 2499- 2504', some water from Carya 2-5.2 below 2820'). 8/l/09—RU Pollard lubricator. RIH w/ 2.00" DD bailer to 2828' and work to 2832'. POH—full of sand. Make 2 more runs, recovering sand to 2836' before flapper pin sheared. PU and run 1.75" DD bailer w/ ball check bottom to 2834'—POH full of sand. Made 4 more runs to 2844', rec sand each time. RD and release Pollard. 9/10/09—RU Pollard. RIH w/ 1.75" DD bailer to 2836'. POH full of sand. Make 5 more runs to clean out to 2844', rec sand each time, but very little last 2 runs. Also, hard bottom last 2 runs. RD and release Pollard. 10/19/09—RU Pollard. RIH w/2.26" GR to 2847'—tag fill. POH. RIH w/ BL brush to 2175' and PU thru packers and sleeves. POH. RIH w/ AD -2 stop and setting tool and set at 2683' and sheared off. POH, redress tool, RIH and reset AD -2 stop at 2510'. POH. RIH w/ GR/CCL tool and log AD -2 stop depth. RIH w/ pack -off assembly, but could not get below 2088'. POH and shorten packoff assembly—still could not get thru 2088'. POH, SDFN. 10/20/09—RU Pollard. Attempt to run shorter lower pack -offs (2) but could not get below 2088'. Ran I.5' X 2.30" seal bore receptacle to 2510'—work thru 2088'. POH. Run 1.67' X 2.30" drift—tap thru 2088', and drug back thru. POH. Run 6' X 1.91" OD pipe to 2150' w/o problem. SDFN. 10/21/09—RU Pollard. Run dummy pack -off drift to 2088' and tap thru. POH. RIH w/ lower D&D pack -off assembly and set at 2510-25081. POH. Cut and thread spacer pipe to length. Run 7.32' spacer pipe and set at 2501-08'. POH. Run upper D&D pack -off assembly (2.78' OA) to 2498-2501' and set. POH. Run AA slip -stop to 2497-98' and set. POH. RD & release Pollard. Put well on production to sales. 10/22/09—Producing to sales at rate o£°105�mcfpd at 500 psi FTP. / Ed Jones (11/13/09) Aurora Gas, LLC Lone Creek #4 Current Configuration October 2009 Drill 12-1/4" Hole to 765' 2-7/8" x 5-V2" annulus to be filled w/ 10.7 ppg KCI-NaCl-CaCI brine Beluga 1022-42 1052-57 Carya 2 1462-82 1497-1507 1516-36 1546-56 5-1/2" 184 Production Casing set at 2,350' Cement in 2 stages w/ 11.5, 13.5. & 15.8 ppg Class G Drill 7-7/8" Hole to 2,483' Tyonek Carya 2-4.2 2468-82', 91-96', 99-2504 TVA 2373-2409' Tyonek Cary 282( TVD 2" Drill 4-3/4" Hole to 3,000'MD/2902' T'.., LI 2 7/8 6.5# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 80' !8" 36# Surface Casing set at 765' ment w/ 15.8 ppg Class G ,draulic Set Packer @ 999' iding Sleeve @ 1,076' (CLOSED) Kdraulic-set Packer @ 1,371' iding Sleeve @ 1,450' (CLOSED) idine Sleeve Oil 1.589' (CLOSED) age Tool @ 1875' ES BWB Seal Bore Packer, w/ X ipple. Top @2,041' verted On -Off Tool above -rowset Mechanical Packer @2093' '2.31 profile XN nipple .5# 8rd EUE J-55 Tubing to 2,910' 3# 8rd EUE J-55 Tubing to 3,000' ed w/ 11.5 and 15.8 ppg cement 01' (2803' TVD) Sperry Drilling Serviced IN9ITE DIRECTIONAL SURVEY REPORT Aurora Gas LLC Lone Creek #4 Lone Creek Gas Field Tyonek Alaska USA AK -MW -000617438 Surveys from 0 - 710' MD are ESS Surveys. Measured Vertical Vertical Depth Inclination Direction Depth Latitude Departure Section Dogleg (feet) (degrees) (degrees) (feet) (feet) (feet) (feet) (deg/100ft) 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 TIE-IN 130.00 0.80 255.61 130.00 0.23S 0.88 W 0.91 0.62 188.00 0.90 261.14 187.99 0.40S 1.72 W 1.76 0.22 249.00 0.98 262.38 248.98 0.54S 2.71 W 2.75 0.14 313.00 1.13 266.61 312.97 0.65S 3.88 W 3.91 0.26 375.00 1.19 271.53 374.96 0.67S 5.14 W 5.12 0.19 436.00 1.31 273.33 435.94 0.61S 6.47 W 6.37 0.21 498.00 1.42 277.85 497.93 0.46S 7.94 W 7.74 0.25 560.00 1.54 283.03 559.90 0.17S 9.51 W 9.16 0.29 624.00 1.56 285.49 623.88 0.25 N 11.19 W 10.65 0.11 687.00 1.45 290.88 686.86 0.77 N 12.76 W 12.01 0.28 710.00 1.48 294.06 709.85 0.99 N 13.30 W 12.47 0.38 757.00 1.95 283.91 756.83 1.43 N 14.63 W 13.61 1.18 821.00 3.06 263.60 820.77 1.50 N 17.38 W 16.23 2.21 882.00 4.94 255.75 881.62 0.67 N 21.55 W 20.46 3.19 947.00 7.21 254.13 946.25 1.13S 28.18 W 27.33 3.51 1011.00 11.02 255.42 1009.43 3.77S 37.97 W 37.47 5.96 1072.00 15.32 256.34 1068.81 7.14S 51.44 W 51.34 7.05 1134.00 18.19 252.06 1128.18 12.06S 68.61 W 69.20 5.04 1195.00 21.13 251.72 1185.62 18.44S 88.11 W 89.71 4.81 1258.00 24.01 250.05 1243.79 26.37S 110.94 W 113.86 4.68 1320.00 26.91 247.96 1299.76 36.94S 135.81 W 140.42 4.91 1382.00 27.06 247.55 1355.01 46.59S 161.85 W 168.41 0.39 1443.00 26.92 247.71 1409.37 57.13S 187.45 W 195.96 0.25 1505.00 28.11 248.99 1464.35 67.69S 214.07 W 224.49 2.13 1569.00 30.28 249.98 1520.22 78.62S 243.31 W 255.62 3.48 1631.00 30.43 250.31 1573.72 89.26S 272.77 W 286.90 0.35 1694.00 28.30 246.17 1628.63 100.67S 301.46 W 317.65 4.66 1756.00 25.73 243.94 1683.87 112.53S 327.00 W 345.51 4.45 1819.00 23.01 244.40 1741.25 123.86S 350.39 W 371.16 4.33 1880.00 21.50 245.73 1797.70 133.60S 371.34 W 394.01 2.60 1943.00 18.82 244.49 1856.84 142.73S 391.04 W 415.50 4.31 2004.00 17.60 245.36 1914.78 150.81S 408.30 W 434.35 2.05 2068.00 14.66 246.38 1976.25 158.098 424.52 W 451.97 4.61 2131.00 11.45 245.98 2037.62 163.83S 437.55 W 466.09 5.09 2193.00 9.39 246.35 2098.59 168.37S 447.80 W 477.22 3.34 2256.00 6.55 247.78 2160.98 171.79S 455.83 W 485.89 4.52 2320.00 4.95 255.48 2224.65 173.86S 461.88 W 492.28 2.77 2381.00 4.26 262.09 2285.46 174.83S 466.67 W 497.15 1.43 CALCULATION BASED ON MINIMUM CURVATURE METHOD SURVEY COORDINATES RELATIVE TO WELL SYSTEM REFERENCE POINT TVD VALUES GIVEN RELATIVE TO DRILLING MEASUREMENT POINT VERTICAL SECTION RELATIVE TO WELL HEAD VERTICAL SECTION IS COMPUTED ALONG A DIRECTION OF 253.44 DEGREES (TRUE) A TOTAL CORRECTION OF 18.88 DEG FROM MAGNETIC NORTH TO TRUE NORTH HAS BEEN APPLIED HORIZONTAL DISPLACEMENT IS RELATIVE TO THE WELL HEAD. HORIZONTAL DISPLACEMENT(CLOSURE) AT 2381.00 FEET LONE CREEK 4 DEEPER SURVEYS MD INCLINTN AVG COS DEPTH VERT TVD (feet) (deg) INCL INCL SECTION DEPTH (feet) 0.999166 20 19.98332 2722.4 Top Current 2860 2.23 2256 6.55 9.992427 2762.3 Bottom Current PBTD 2160.98 Sperry Survey 6.88 0.992799 44 43.68316 2300 7.21 2204.663 7.325 0.991839 100 99.18389 2400 7.44 2303.847 6.93 0.992694 60 59.56166 2460 6.42 2363.409 6.245 0.994066 60 59.64395 2520 6.07 2423.053 5.81 0.994863 50 49.74315 2570 5.55 2472.796 5.045 0.996126 30 29.88378 2600 4.54 2502.68 4.035 0.997521 50 49.87606 2650 3.53 2552.556 3.115 0.998522 50 49.92612 2700 2.7 2602.482 2.475 0.999067 50 49.95336 2750 2.25 2652.435 2.345 0.999163 50 49.95813 2800 2.44 2702.393 2.32 0.99918 50 49.95902 2850 2.2 2752.352 2.28 0.999208 50 49.96042 2900 2.36 2802.313 2.075 0.999344 20 19.98689 2920 1.79 2822.3 0.895 0.999878 80 79.99024 3000 2902.29 TD PERFS 2468 6.4 0.993768 8 7.950143 2371.4 Top Proposed 2504 6.2 0.994151 44 43.74264 2407.2 Bottom Proposed 2820 2.34 0.999166 20 19.98332 2722.4 Top Current 2860 2.23 0.999243 10 9.992427 2762.3 Bottom Current PBTD 2901 2803.3 Aurora Gas, LLC ALBERT KALOA Lone Creek Lone Creek No. 4 Sperry Drilling Services Definitive Survey Report 29 December, 2009 HALLiBURTON Sperry Drilling Services Halliburton Company Definitive Survey Report Company: Aurora Gas, LLC Local Co-ordinate Reference: Well Lone Creek 4 Project: ALBERT KALOA TVD Reference: 400 + 13 @ 413.0ft (Aurora #1) Site: Lone Creek MD Reference: 400 + 13 @ 413.0ft (Aurora #1) Well: Lane Creek 4 North Reference: True Wellbore: Lone Creek No. 4 Survey Calculation Method: Minimum Curvature Design: Lone Creek No. 4 Database: ..Sperry EDM Prod .161 Project ALBERT KALOA, COOK INLET BASIN Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well Lone Creek 4 Well Position +N/ -S 0.0 ft Northing: 2,611,312.58 ft Latitude: 61'8'28.650 N +E/ -W 0.0 ft Easting: 273,738.82 ft Longitude: 151' 16'49.474 W Position Uncertainty 0.0 ft Wellhead Elevation: ft Ground Level: 400.0ft Wellbore Lone Creek No. 4 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (I (I (nT) BGGM2007 7/3/2007 19.30 73.90 55,632 Design Lone Creek No. 4 Audit Notes: Map Version: 1.0 Phase: ACTUAL Tie On Depth: 413.0 Vertical Section: Depth From (TVD) +N/ -S +E1 -W Direction +N1S (ft) (ft) (ft) (I DLS 413.0 0.0 0.0 253.44 Survey Program Date 12/29/2009 From To Survey (ft) (ft) Survey (Wellbore) Tool Name Description Start Date 436.0 2,484.0 Lorne Creek #4 Rig Surveys (Lone Creek MWD MWD - Standard 01/05/2009 Survey 1242912009 5:37:19PM Page 2 COMPASS 2003.16 Build 71 Map Map Vertical MD Inc Azi TVD TVDSS +N1S +E1 -W Northing Easting DLS Section (ft) V) (0) (ft) (ft) (ft) (ft) (ft) (ft) (°/100') (ft) Survey Tool Name 130.0 0.80 255.61 413.0 0.0 0.0 0.0 2,611,312.6 273,738.8 0.0 0.00 MWD 188.0 0.90 261.14 471.0 58.0 -0.2 -0.8 2,611,312.4 273,738.0 0.2 0.86 MWD 249.0 0.98 262.38 532.0 119.0 -0.3 -1.8 2,611,312.3 273,737.0 0.1 1.85 MWD 313.0 1.13 266.61 596.0 183.0 -0.4 -3.0 2,611,312.2 273,735.8 0.3 3.00 MWD 375.0 1.19 271.53 658.0 245.0 -0.4 -4.3 2,611,312.2 273,734.6 0.2 4.21 MWD 413.0 0.00 0.00 413.0 0.0 0.0 0.0 2,611,312.6 273,738.8 3.1 0.00 MWD 436.0 1.31 273.33 718.9 305.9 -0.4 -5.6 2,611,312.3 273,733.2 5.7 5.47 MWD 498.0 1.42 277.85 780.9 367.9 -0.2 -7.1 2,611,312.5 273,731.8 0.2 6.83 MWD 560.0 1.54 283.03 842.9 429.9 0.1 -8.6 2,611,312.8 273,730.2 0.3 8.26 MWD 624.0 1.56 285.49 906.9 493.9 0.5 -10.3 2,611,313.3 273,728.5 0.1 9.74 MWD 687.0 1.45 290.88 969.9 556.9 1.0 -11.9 2,611,313.8 273,727.0 0.3 11.10 MWD 710.0 1.48 294.06 992.9 579.9 1.2 -12.4 2,611,314.0 273,726.4 0.4 11.56 MWD 757.0 1.95 283.91 1,039.8 626.8 1.7 -13.8 2,611,314.5 273,725.1 1.2 12.71 MWD 821.0 3.06 263.60 1,103.8 690.8 1.7 -16.5 2,611,314.6 273,722.4 2.2 15.33 MWD 1242912009 5:37:19PM Page 2 COMPASS 2003.16 Build 71 Halliburton Company Definitive Survey Report Company: Aurora Gas, LLC Local Co-ordinate Reference: Well Lone Creek 4 Project: ALBERT KALOA TVD Reference: 400 + 13 @ 413.Oft (Aurora #1) Site: Larne Creek MD Reference: 400 + 13 @ 413.Oft (Aurora #1) Well: Lone Creek 4 North Reference: True Wellbore: Lone Creek No. 4 Survey Calculation Method: Minimum Curvature Design: Lorne Creek No. 4 Database: ..Sperry EDM Prod .161 Survey Map Map Vertical MD Inc Azi TVD TVDSS +W -S +E! -W Northing Easting DLS Section (ft) (°) (°) (ft) (ft) (ft) (ft) (ft) (ft) (°/100') (ftj Survey Tool Name 882.0 4.94 255.75 1,164.6 751.6 0.9 -20.7 2,611,313.9 273,718.2 3.2 19.56 MWD 947.0 7.21 254.13 1,229.3 816.3 -0.9 -27.3 2,611,312.2 273,711.5 3.5 26.43 MWD 1,011.0 11.02 255.42 1,292.4 879.4 -3.5 -37.1 2,611,309.8 273,701.7 6.0 36.56 MWD 1,072.0 15.32 256.34 1,351.8 938.8 -6.9 -50.6 2,611,306.7 273,688.1 7.1 50.45 MWD 1,134.0 18.19 252.06 1,411.2 998.2 -11.8 -67.7 2,611,302.1 273,670.9 5.0 68.30 MWD 1,195.0 21.13 251.72 1,468.6 1,055.6 -18.2 -87.2 2,611,296.1 273,651.2 4.8 88.82 MWD 1,258.0 24.01 250.05 1,526.8 1,113.8 -26.2 -110.1 2,611,288.6 273,628.3 4.7 112.97 MWD 1,320.0 26.91 247.96 1,582.8 1,169.8 -35.7 -134.9 2,611,279.5 273,603.2 4.9 139.53 MWD 1,382.0 27.06 247.55 1,638.0 1,225.0 -46.4 -161.0 2,611,269.4 273,577.0 0.4 167.53 MWD 1,443.0 26.92 247.71 1,692.4 1,279.4 -56.9 -186.6 2,611,259.3 273,551.2 0.3 195.07 MWD 1,505.0 28.11 248.99 1,747.4 1,334.4 -67.5 -213.2 2,611,249.3 273,524.3 2.1 223.60 MWD 1,569.0 30.28 249.98 1,803.2 1,390.2 -78.4 -242.4 2,611,238.9 273,494.9 3.5 254.74 MWD 1,631.0 30.43 250.31 1,856.7 1,443.7 -89.0 -271.9 2,611,228.9 273,465.2 0.4 286.02 MWD 1,694.0 28.30 246.17 1,911.6 1,498.6 -100.5 -300.6 2,611,218.0 273,436.3 4.7 316.77 MWD 1,756.0 25.73 243.94 1,966.9 1,553.9 -112.3 -326.1 2,611,206.7 273,410.6 4.5 344.63 MWD 1,819.0 23.01 244.40 2,024.2 1,611.2 -123.6 -349.5 2,611,195.8 273,386.9 4.3 370.28 MWD 1,880.0 21.50 245.73 2,080.7 1,667.7 -133.4 -370.5 2,611,186.5 273,365.8 2.6 393.13 MWD 1,943.0 18.82 244.49 2,139.8 1,726.8 -142.5 -390.2 2,611,177.7 273,345.9 4.3 414.62 MWD 2,004.0 17.60 245.36 2,197.8 1,784.8 -150.6 -407.4 2,611,170.0 273,328.5 2.0 433.47 MWD 2,068.0 14.66 246.38 2,259.3 1,846.3 -157.9 -423.7 2,611,163.0 273,312.2 4.6 451.09 MWD 2,131.0 11.45 245.98 2,320.6 1,907.6 -163.6 -436.7 2,611,157.6 273,299.0 5.1 465.20 MWD 2,193.0 9.39 246.35 2,381.6 1,968.6 -168.1 -446.9 2,611,1532 273,288.7 3.3 476.32 MWD 2,256.0 6.55 247.78 2,444.0 2,031.0 -171.6 -455.0 2,611,150.0 273,280.6 4.5 485.00 MWD 2,320.0 4.95 255.48 2,507.7 2,094.7 -173.6 -461.0 2,611,148.0 273,274.5 2.8 491.39 MWD 2,381.0 4.26 262.09 2,568.5 2,155.5 -174.6 -465.8 2,611,147.1 273,269.7 1.4 496.26 MWD 2,484.0 4.26 262.09 2,6712 2,258.2 -175.7 -473.4 2,611,146.2 273,262.1 0.0 503.83 BLIND 1229/2009 5:37:19PM Page 3 COMPASS 2003.16 Build 71 bp H QL L 1 B U R T O N COMPANY DETAILS: Aurora Gas, LLC CASING DETAILS Drilling TVD MD Name Size Lone Creek #4 750.0 750.0 8-5/8 8-5/8 Sperry Drilling Services i Calculation Method: Minimum Curvature 3474.9 3578.3 51/2" 5.1/2 Error System: ISCWSA EOW Plot Scan Method: Tray. Cylinder North WELLBORE TARGET DETAILS (MAPCO -ORDINATES) Actual vs Plan Name TVD +W -S +E/ -W Northing Easting Shape LC4 T1 3333.0 -168.1 -465.6 2611153.63 273270.03 Point SECTION DETAILS SecMD Inc Azi TVD +N/ -S +E/ -W DLeq TFace VSec Target DDIts & ERD's 1 0.0 0.00 0.00 0.0 0.0 0.0 0.0 0.00 0.0 2 750.0 0.00 0.00 750.0 0.0 0.0 0.00 0.00 0.0 3 1452.9 31.63 250.15 1417.8 642 -177.9 4.50 250.15 188.8 4 1675.5 31.63 250.15 1607.2 -103.9 -287.7 0.00 0.00 305.4 Lone Creek #4: DDI - 4.60• ERD - 0.14 5 2378.4 0.00 0.00 2275.0 -168.1 -465.6 4.50 180.00 494.2 6 3436.4 0.00 0.00 3333.0 -168.1 -465.6 0.00 0.00 494.2 LC4 T1 7 3578.4 0.00 0.00 3475.0 -168.1 -465.6 0.00 0.00 494.2 _ WELL DETAILS: Lone Creek 4 ... _.... REFERENCE INFORMATION Ground Level: 400.0 Co-ordinate (N/E) Reference: WON Lone Creek 4, True North +N/ -S +E/ -W Northing Easting Latittude Longitude Slot Vertical (TVD) Refererrc : 400 + 13 Q 413.0fl (Aurora #1) 0.0 0.0 2611312.58 273738.82 61 ° 8'28.650 N 15 f ° 16 49.474 W Measured Depth Reference: 400 + 13 a 413.OR (Aurora #1) Calculation Method: Minimum Cun azure -500 -450 -400 -350 -300 -250 -200 -150 -100 -50 0 50 100 West(-YEast(+) (100 Win) 800 1000 Lone Vertical View 8-5/8 Creek No. 4 I `I LC4 T1 Lone Creek No.4 wp03 5 1/2" 0 200 400 600 800 1000 Vertical Section at 253.44° (500 Win) 4 ALASKA OIL AND GAS CONSERVATION COMMSSION Bruce Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC 2500 City West Blvd, Suite 2500 Houston, TX 77042 Re: Lone Creek Undefined Gas, Lone Creek No. 4 Sundry Number: 309-216 Dear Mr. Webb: SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 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. Sincerely, Daniel T. Seamount, Jr. Chair DATED this - day of June, 2009 Encl. -09 / • i Aurora Gas, LLC www.aurorapower.com June 25, 2009 Tom Maunder, Senior Petroleum Engineer State of Alaska Oil and Gas Conservation Commission 333 W. 7h Avenue, Suite 100 Anchorage, AK 99501 E qV „P ,JUN 2 � c ukJy Alaska Oil & Gas Corr o6ar� res; ; Ancha%e Re: Sundry Approval Request for Liner Clean-out and Perforating Procedure Lone Creek #4 Development Gas Well, Permit to Drill No. 207-091 Dear Mr. Maunder: Pursuant to 20 AAC 25.280, Aurora Gas, LLC ("Aurora") request sundry approval to clean-out fill in the 2-7/8" liner, and perforate other zones in the Lone Creek #4 development gas well. As you know, during the drilling procedure for this well, it was necessary to revise the casing design and install a liner. Aurora plans on utilizing Pollard and Schlumberger for this operation. Attached, please find the 10-403 Application for Sundry Approval, the proposed Liner Clean-out and Perforating Procedure and a well schematic showing the current well configuration. Thank for your review and consideration of this request. Should questions arise in connection with this request, please contact Mr. Ed Jones at the Houston telephone number below. Sincerely, Bruce D. Webb Manager, Land and Regulatory Affairs attachments 1400 West Benson Blvd., Suite 410 . Anchorage, AK 99503 • (907) 277-1003 • Fax: (907) 277-1006 6051 North Course Drive, Suite 200 • Houston, TX 77072 • (713) 977-5799 • Fax: (713) 977-1347 16 STATE OF ALASKA 0 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RE(,-,-.EIVED JUN 2 ") "� Q ka j 1. Type of Request: Abandon ❑ Susper❑ Operational shutdown ❑ Perforate plt�t,V�ta� �a 9Time Olt' MISSlWer ❑ Alter casing ❑ Repair wC] Plug Perforations ❑ Stimulate Extension Change approved program C] Pull Tubi❑ Perforate New Pool ❑ Re-enter Suspended Well 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: AURORA GAS LLC Development Q Exploratory ❑ Stratigraphic ❑ Service ❑ 207-091 - 3. Address: 6. API Number: 2500 City West Blvd., Suite 2500, Houston, TX 77042 50-283-20121-00 ' 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 10 Lone Creek No. 4 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): CIRI Lease # C-061395 1 416' AMSL (DF)'- Lone Creek Undefined Gas 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): 3,000' 2,902' 2,901' 2,803' 2,901' fill @ 2,852' Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 13-3/8" 96' 96' 1,530 psi 520 psi Surface 765' 9-5/8" 765' 765' 3,520 psi 2,020 psi Intermediate 2,350' 5-1/2" 2,350' 2,255' 5,320 psi 4,910 psi Production 60' 3-1/2" 3,000' 2,902' 10,160 psi 10,530 psi Liner 821' 2-7/8" 2,910' 2,812' 7,260 psi 7,680 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 1022'-1042',1057-1057',1462'-1482', 1020'-1040',1050'-1055',1428'•1448', 2-7/8" 6.5#, J56 2,910' 1496'-1506',1516'-1536',1542'-1552', 1456'-1466',1472'-1492',1498'-1508', 2820'-2860' 2722'-2762'... Packers and SSSV Type: Hy oli Set Pakers Packers and SSSV MD (ft): 999' MD, 1,371' MD HES BWB Seal Bore, Arrowset Mech. 2,041' MD, 2,093' MD 13. Attachments: Description Summary of Proposal ID 14. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development Q Service ❑ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: July 6, 2009 Oil ❑ Gas Q - Plugged ❑ Abandoned ❑ WAG ❑ GINJ ❑ WINJ [] WDSPL ❑ 17. Verbal Approval: Date: Commission Representative: 18. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact J. Edward Jones (713) 977-5799 Printed Name Bruce D. Webb, Manager, Land and Regulatory Affairs Title Executive Vice President, Eng. and Oper. Signature Date June 25, 2009 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: Subsequent Form Required: i f7 -- 404. APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: (0 �J S tom L i` o 1QQti Form 10-403 Revised 06/2006 i� Cc CSU/ WGA 4,12612.oj Submit in Duplicate • AURORA GAS, LLC LONE CREEK 4 LINER CLEAN-OUT AND PERFORATE CARYA 2-4.2 SAND (Version 1."/25/09) NOTE: All work will be done inside 2-7/8" tubing (6.5#, J-55) and thru 3000/5000 psi 2-7/8" Vetco Tree Restriction are: 2.313" X profiles in Sliding Sleeves at 1076'; at 1450'; and at 1589'. 2.330" ID of Seal Assembly Locator at 2041', 2.313" X Nipple at 2057', and inverted X profile in inverted On -Off Tool at 2093'. PBTD=2901'. However, SLB found fill at 2852' w/ RST logging tool on 5/22/08 Carya 2-5.2 perfs at 2820-2860' are open. Sliding Sleeves are closed. SITP-15 psi. Maximum Expected Surface Pressure after perforating: 1100 psi. i See attached Well Bore Diagram. PROCEDURE: 1) RU Pollard boom truck and slick -line unit w/ lubricator. PU 2.25" gauge ring and RIH to tag bottom. POH w/ GR. PU'pump baler, RIH and clean out fill to 2900' or below 2870' and little progress is being made. Catch samples of water and sand. Note final fluid level. Release Pollard. 2) MI & RU Schlumberger crane and wireline unit. RU 3-1/2" lubricator supported by crane. PU 15' 2" PowerJet Omega w/ 6 SPF w/ gun GR/CCL . With tree valves closed, pressure test lubricator to 50 psi. Run in hole, correlate to SLB open -hole log of 1/3/09 and perforate Carya 2-4. -sand at 246842' (14'net/gross). Make one additional run w/ 15' guns to perforate the 2491-96' & 2499-2504' (10' net/14' gross) (likely underbalanced). (Will likely need gun GR on each run to correlate). RD and release SLB. 3) RU AG well test unit, including choke manifold and flare stack. 4) Flow back well and test for several hours to clean up. Get flow rate and pressure and SIP. If well will not flow, bring Pollard back to swab it in, as convenient. 5) Perform 4 -point test as per Procedure provided at that time. Ed Jones (6/25/09) Aurora Gas, LLC Lone Creek #4 Proposed Configuration Revised 2/20/09 Drill 12-1/4" Hole to 765' 2-7/8" a 5-%" annulus to be filled w/ 10.7 ppg KCl-NaCl-CaCI brine Beluga (Tsuga 2-7 1022-42 1052-57 Beluga (Tsuga 2-8.1 1462-82' 1497-1507' 1516-36' 1546-56' 5-1/2" 18# Production Casing set at 2,350' Cement in 2 stages w/ 11.5, 13.5. & 15.8 ppg Class G Drill 7-78" Hole to 2,483' Tyonek Carya 2820-: Drill 4-314" Hole to 3,000'MAR91A19M n 2 7/8 6.5# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 80' �-5/8" 36# Surface Casing set at 765' :ement w/ 13.5 ppg Class G Hydraulic Set Packer @ 999' Sliding Sleeve @ 1,076' Hydraulic -set Packer @ 1,371' Sliding Sleeve @ 1,450' Sliding Sleeve @ 1,589' age Tool @ 1875' ES BWB Seal Bore Packer, w/ X pple. Top @2,041' Inverted On -Off Tool above Arrowset Mechanical Packer @2093' w/ 2.31 profile XN nipple '6.5# 8rd EUE J-55 Tubing to 2,910' , '9.3# 8rd EUE J-55 Tubing to 3,000' oted w/ 11.5 and 15.8 ppg cement PBTD @ 2,901 LONE CREEK 4 DEEPER SURVEYS MD INCLINTN AVG COS DEPTH VERT TVD (feet) (deg) INCL INCL SECTION DEPTH (feet) 0.999166 20 19.98332 2722.4 Top Current 2860 2.23 2256 6.55 9.992427 2762.3 Bottom Current PBTD 2160.98 Sperry Survey 6.88 0.992799 44 43.68316 2300 7.21 2204.663 7.325 0.991839 100 99.18389 2400 7.44 2303.847 6.93 0.992694 60 59.56166 2460 6.42 2363.409 6.245 0.994066 60 59.64395 2520 6.07 2423.053 5.81 0.994863 50 49.74315 2570 5.55 2472.796 5.045 0.996126 30 29.88378 2600 4.54 2502.68 4.035 0.997521 50 49.87606 2650 3.53 2552.556 3.115 0.998522 50 49.92612 2700 2.7 2602.482 2.475 0.999067 50 49.95336 2750 2.25 2652.435 2.345 0.999163 50 49.95813 2800 2.44 2702.393 2.32 0.99918 50 49.95902 2850 2.2 2752.352 2.28 0.999208 50 49.96042 2900 2.36 2802.313 2.075 0.999344 20 19.98689 2920 1.79 2822.3 0.895 0.999878 80 79.99024 3000 2902.29 TD PERPS 2468 6.4 0.993768 8 7.950143 2371.4 Top Proposed 2504 6.2 0.994151 44 43.74264 2407.2 Bottom Proposed 2820 2.34 0.999166 20 19.98332 2722.4 Top Current 2860 2.23 0.999243 10 9.992427 2762.3 Bottom Current PBTD 2901 2803.3 0 ALASKA OIL AHD GAS CONSERVATION COIr MSSIOH Bruce Webb Executive Vice President Aurora Gas LLC 2500 City W. Blvd., Ste 2500 Houston TX 77042 Re: Lone Creek Undefined Gas, Lone Creek No. 4 Sundry Number: 309-044 Dear Mr. Webb: 0 SARAH PALIN, GOVERNOR 333 W 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501.3539 PHONE (907) 279-1433 FAX (907) 276-7542 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. 4e, DATED this a day of February, 2009 Encl. qq-'C�) t Sincerely, 624 J� / -21� V-cl' Cathy P. Foerster Commissioner �1,; STATE OF ALASKA rJ ALAR OIL AND GAS CONSERVATION COMMON 'B APPLICATION FOR SUNDRY APPROV,� v 20 AAC 25.280 / NB '-)if FA Oa! un"'', Commission 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown ❑ Perforate Q ' Other Q After casing ❑ Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension Change approved program ❑ Pull Tubing ❑ Perforate New Pool ❑ Re-enter Suspended Well ❑ CkgSM'4JjC- ki 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: AURORA GAS LLC Development Q Exploratory ❑ Stratigraphic ❑ Service ❑ 207-091 3. Address: 6. API Number: 2500 City West Blvd., Suite 2500, Houston, TX 77042 50-283-20121-00 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 Q Lone Creek No. 4 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): a^ /t f X;r,l /4 t'3`df CIRI Lease # C-061395 416' AMSL (DF) Lone Creek (Unde ed Gas) x' 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): 3,000' 2,902' 2,910' 2,812' tagged cmt @ 2,810' MD none Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 13-3/8" 96' 96' 1,530 psi 520 psi Surface 765' 9-5/8" 765' 765' 3,520 psi 2,020 psi Intermediate 2,350' 5-112" 2,350' 2,255' 5,320 psi 4,910 psi Production 60' 3-1/2" 3,000' 2,902' 10,160 psi 10,530 psi Liner 821' 2-718" 2,910' 2,812' 7,260 psi 7,680 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 102242',1052-57',1462-82',1496- 1020-40',1050-55',1428-48', 1456- 2-718" J-66 2,089' 1506',1516-36',1542.52' 66',1472 -92',1498 -1508 - Packers and SSSV Type: Hydrolic Set Pakers Packers and SSSV MD (ft): 999' MD, 1,371' MD HES BWB Seal Bore, Arrowset Mech. 2,041' MD, 2,093' MD 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development 10, Service ❑ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: February 16, 2009 Oil ❑ Gas Q ' Plugged ❑ Abandoned ❑ WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. Verbal Approval: Date: Commission Representative: 18. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact J. Edward Jones (713) 977-5799 Printed Name Bruce D. Webb, Manager, Land and Regulatory Affairs Title Executive Vice President, Eng. and Oper. Signature �, �� Date February 3, 2009 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: IC00 $ub�equent Form Required: L,`C)T—� APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 2-15-11:97 I ,, "ij� a -f?. 09 ROL Form 10-403 Revised 0612006 ,, [:JAL FF8 ,t. � 2009 Sub Dup'c <T M Aurora Gas, LLC www.aurorapower.com February 3, 2009 `(.',*I FEB 9 4 1009 Tom Maunder, Senior Petroleum Engineer Alaska Oil & 1Z8s Cons 9(jammissior, State of Alaska Anchorage Oil and Gas Conservation Commission 333 W. 7`b Avenue, Suite 100 Anchorage, AK 99501 Re: Sundry Approval Request for Liner Clean-out and Perforating Procedure Lone Creek #4 Development Gas Well, Permit to Drill No. 207-091 Dear Mr. Maunder: Pursuant to 11 AAC 25.280, Aurora Gas, LLC ("Aurora") request sundry approval drill out the cement, clean-out the 2-7/8" liner, and perforate at the Lone Creek #4 development gas well. As you know, during the drilling procedure for this well, it was necessary to revise the casing design and install a liner. As a result of using the liner, Aurora was unable to drill out the cement in the liner with the Aurora Well Service rig. Aurora plans on utilizing a coil tubing drilling operation. Attached, please find the 10-403 Application for Sundry Approval, the proposed Liner Clean-out and Perforating Procedure, a well schematic showing the current well configuration, and Halliburton and Weatherford completion diagrams. Thank for your review and consideration of this request. Should questions arise in connection with this request, please contact Mr. Ed Jones at the Houston telephone number below. Sincerely, Bruce D. Webb Manager, Land and Regulatory Affairs attachments 1400 West Benson Blvd., Suite 410 • Anchorage, AK 99503 • (907) 277-1003 • Fax. (907) 277-1006 6051 North Course Drive, Suite 200 • Houston, TX 77072 • (713) 977-5799 • Fax. (713) 977-1347 AURORA GAS, LLC LONE CREEK 4 LINER CLEAN-OUT AND PERFORATE (Version 1.1--2/3/09) NOTE: All work will be done inside 2-7/8" tubing (6.5", J-55) and thru 3000/5000 psi 2- 7/8" Vetco Tree—pressure is limited to 3000 psi by tree (tubing bonnet connection). Restriction are: 2.313" X profiles in Sliding Sleeves at 1076'; at 1450'; and at 1589'. 2.330" ID of Seal Assembly Locator at 2041', 2.313" X Nipple at 2057, and inverted X profile in inverted On -Off Tool at 2093'. See attached Well Bore Diagram, Halliburton Completion Diagram, and Weatherford Liner Diagram. NO PERFS WILL BE OPEN DURING CLEAN OUT. PROCEDURE: 1) When Vetco is on West side for Chevron, have them pull the BPV in tree. 2)RU Pollard boom truck and slick -line unit before moving in Coiled Tubing Unit (CTU). RIH and close sliding sleeves at 1450' and 1589'. Confirm that sleeve at 1076' is closed. Release Pollard. 3) MI (if not already there): AWS mud pit, larger indirect heaters, light plant(s), test pump. Fill pit w/ clean KCl -NaCl used brine—add clean water to make up +/-75 bbl total. Add 1 gal/1000 FRW-14 friction reducer. Mobilize Weatherford down -hole motor and mills to location. Mobilize Peak 65 -ton crane to location. 4) MI BJ Coiled Tubing Unit (CTU) and support equipment. RU CTU and pumping equipment. Fill CTU w/ +/- 27.3 bbl. Make up coil connector and pull test to 1 OK. Pressure test connector to 200/4500 psi for 10/10 minutes. 5) Make up BHA and measure & record lengths, OD's. ID's, ball sizes and rupture discs (if applicable). 6) NU BOP stack to well/tree. Pressure test via CT, pumps, stack, and flow -back manifold against crown valve to 200/4500 psi for 10/10 min. (BE SURE TREE IS ISOLATED from pressures above 3000 psi by 5000 -psi swab and master valves). (See BJ Procedure for more specific instructions regarding CT). 7) Begin RIH w/ CT at 50 fpm, slowing to 10 fpm at restrictions (see Note above). Circulate at minimum rates, about '/4 BPM. 8) RIH to 2700', performing pull tests every 1000'. Increase pump rate to I-1.1 BPM and compare to CIRCA model predictions. 9) RIH slowly to +/-2810' and tag cement. Pull up, circulate out, then start milling at 0.5 ft/min. for 10, POH 15-20' circulating out at 1-1.1 BPM. Continue milling the 10' intervals like this to 2910'. Monitor the returns for fill removal efficiency and maintain well head pressure above 150 psi. CT operator should perform pull tests as required and back reaming passes when milling thru cement to establish that coiled tubing is free from obstructions. 10) When tubing reaches 2910', circulate at bottom at 1 BPM for 15 minutes while moving CT 10' every 5 minutes to insure free movement of the tubing. Displace fluid (if dirty) with clean 6% KCl water, while moving CT. After minimum of 15 -minute bottoms up at 1 BPM, POOH at normal rates. Do NOT interrupt circulation while POOH unless absolutely necessary, to avoid fill falling back with potential to stick CT. When 300' free surface, slow speed to 30 ft/min, then to 15 ft. min. at 1501, and to 8 ft/ min at 75'. When at surface, close in at wellhead and bleed down pressure. 11) RD MO BJ CTU. 12) RU Pollard and swab fluid level down to sliding sleeve at 1076'. RD Pollard. 13) RU Schlumberger 3-1/2" lubricator supported by crane. PU 10' 2" PowerJet Omega gun w/ 6 SPF w/ gun GR/CCL . With tree valves closed, pressure test lubricator to 2000 psi. Run in hole, correlate to SLB open -hole log of 1/3/09 and perforate Carya 2-5.2 sand at 2850-2860'. Make 3 additional runs w/ 10' guns to perforate the entire interval 2820- 60' (0-200 psi underbalanced). (Will likely need gun GR on each run to correlate). RD and release SLB. Release Peak crane. 14) RU AG well test unit, including choke manifold and flare stack. 15) Flow back well and test for several hours to clean up. Get flow rate and pressure and SIP. If well will not flow, bring Pollard back to swab it in, as convenient. 16) When weather conditions allow. Perform 4 -point test as per Procedure provided at that time. Ed Jones (2/2/09) _- Aurora Gas, LLC Lone Creek #4 Actual Configuration Revised 1/15/09 Drill 12-1/4" Hole to 765' 2-7/8" x 5-%" annulus to be filled w/ 10.7 ppg KCI -NaCl -CACI brine Beluga (Tsuga2-8 1022-42 1052-57 U. iyonek (Carya 2- 1.1) 1462-82' 14%-1506' 1516-36' 5-1/2" 18# Production Casing set at 2„350' Cement in 2 stages w/ 11.5, 13.5. do 15.8 ppg Class G Drill 7-7/8" Hole to 2,483' Tyonek Carya Plann 2820-1 Drill 4-3/4" Hole to 3, 000'MD/2910'TV� 2 7/8 6.5# 8rd EUE J-55 Tubing 133/8" 68# Structural Conductor driven to 80' 1-5/8" 36# Surface Casing set at 765' :ement w/ 13.5 ppg Class G Hydraulic Set Packer @ 999' Sliding Sleeve @ —1,076' Hydraulic -set Packer @ —1,371' Sliding Sleeve @ —1,450' Sliding Sleeve @ —1,589' ige Tool at 1875' S BWB Seal Bore Packer, w/ X pple. Top @2,041' Inverted On -Off Tool @2089' Arrowset Mechanical Packer @2093' w/ 2.31 profile XN nipple sent at 2810' t 8rd EUE J-55 Tubing to 2,910' 1 8rd EUE J-55 Tubing to 3,000' w/ 11.5 and 15.8 ppg cement Estimated PBTD @ 2,910 13 HALLIBURTON ROB WARREN, FIELD SALES REP. 6900 Arctic Blvd. Anchorage, Alaska 99518 (907)275-2623 Customer AURORA GAS Customer Representative Jon West Well LONE CREEK #4 Field LONE CREEK Date 12/31/08 Casing Size 95/8 Casing Weight 36 Casing Grade From To Tubing Size 27/8 Tubing Weight 6.5 Tubing Grade J-55 Tubing Thread EUE Casing Size 51/2 Casing Weight 15.5 Casing Grade From To Pick Up Weight 17K Down Weight 16K Block Weight 8K Weight on Locator NEUTRAL 12 Liner Size 27/8 Liner Weight 6.5 Liner Grade From To Release 36,400(#12) Center of Pkr. Elem. Original RT -LDS 14.58 PBTD 2,910 Max. Deviation Deviation Thru Perfs KOP Release 36,400(#10) Center of Pkr. Elem. 1001.46(#12), 1373.62(#10), 2043.2(#6) -� 11 Completion Fluid 10.71b/gal Brine BHT BHP Perforations 1022-42, 1052-57, 1462-82, 1497-1507, 1516-36, 1546-56 Description 1. D. O.D. Length De th RT -LDS 14.58 0.00 13 TUBING HANGER 0.50 14.58 2 7/8 6.5# L-80 EUE PUP JT, PINxPIN 2.441 3.094 3.83 15.08 TBG TO SURFACE 32 JTS, 2 7/8 6.5# J-55 TBG 2.441 3.690 967.65 18.91 2 - 2 7/8 6.5# J-55 PUP JTS (2.1' & 4.18' on top) 2.441 3.690 6.28 986.56 10 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 6.13 992.84 12 5.5" HES 13-17# PHL HYD. PACKER (70850) 3.000 4.700 4.98 998.97 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 4.04 1,003.95 2 JTS 2 7/8 6.5# J-55 TBG 2.441 3.690 62.23 1,007.99 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 6.12 1,070.22 IIII A s 11 2 7/8" 6.5# 9CR HES XD SLD SLV 100159432) 2.313 3.920 4.02 1,076.34 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 4.15 1,080.36 `j 9 JTS, 2 7/8" 6.5# J-55 EUE TUBING 2.441 3.690 280.48 1,084.51 8 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 6.15 1,364.99 10 5.5" HES 13-17# PHL HYD. PACKER (70850) 3.000 4.700 4.95 1,371.14 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 4.15 1,376.09 l -1 �Jj 2 JTS, 2 7/8" 6.5# J-55 EUE TUBING 2.441 3.690 62.78 1,380.24 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 6.62 1,443.02 9 2 7/8" 6.5# 9CR HES XD SLD SLV (100159432) 2.313 3.920 4.00 1,449.64 g 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 4.22 1,453.64 4 JTS, 2 7/8" 6.5# J-55 EUE TUBING 2.441 3.690 125.00 1,457.86 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 6.16 1,582.86 :• 8 2 7/8" 6.5# 9CR HES XD SLD SLV 100159432) 2.313 3.920 3.59 1,589.02 5 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 4.17 1,592.61 z, 14 JTS, 2 7/8" 6.5# J-55 EUE TUBING 2.441 3.690435.85 1,596.78 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 8.34 2,032.63 4 7 3.00" SEAL ASSY W/ STRAIT SLOT LOCATOR 2.330 3.760 7.41 2,040.97 3 6 5.5" x 3.00" HES BWD PERM. PKR (100007193) 3.000 1 4.540 3.45 2,041.47 5 3.00" SEAL BORE EXTENTION 3.000 4.500 4.39 2,044.92 4 SEAL BORE x 2 7/8" EUE TUBING X -OVER 2.441 3.700 1.25 2,049.31 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 6.50 2,050.56 ;I 2 3 2 7/8" HES X NIPPLE 2.313" PKG BORE 2.313 3.690 0.71 2,057.06 2 7/8" 6.5# L-80 EUE TUBING JOINT 2.441 3.690 31.03 2,057.77 _ 1 2 7/8" 6.5# L-80 EUE PUP JOINT 2.441 3.690 4.20 2,088.80 2 WEATHERFORD INVERTED ON-OFF TOOL 2.313 3.000 4.74 2,093.00 1 WEATHERFORD ASX-1 MECH. PACKER 2,093.00 SEE LINER DETAIL NOTE: PHL PACKERS PINNED TO RELEASE AT 36,400LBF STRAIT SHEAR RELEASE (8 PINS DUE TO THE SMALL DISTANCE BETWEEN PACKERS THIS VALUE IS CUMMULATIVE K* ALASKA FIELD OPERATIONS Weathd Completion & Production Systems '°""D'a� ��c UM I As -Run Drawing Revision: New Page 1 Operator: Aurora State: Alaska Lease: Lone Creek County: Kenai Peninsula Well No: 4 Date prepared: 1/3/2009 Prepared by: Lyle Savage Phone: 240-8809 Company rep: Doug / John Phone: 472-7793 Completion fluid: KCI Fluid wt: 9.5# Perforations: EUE, N-80 Lower tubing: Size (in) Wt (Ib/ft) ID (in) Drift (in) Type/Thread CSG 5112 15.5 4.892 LNR1 N/A LNR2 N/A Upper tubing: 27/8 6.4 2.441 EUE, N-80 Lower tubing: EUE, N-80 No. OD (in) ID (in) Length (ft) Depth (ft) Description 2144.00 0.00 72 joints of 2 718 6.4# EUE tubing to surface 2.875 2.441 4.22 2144.00 2 7/8 EUE Pup joint 3.25 2.312 ImerUd X Inside Seel MppW 4.5 3.25 4.50 2148.22 4.5 x 2 7/8 Inverted On -Off skirt 2.875 2.44 0.67 2152.72 2 7/8 pin X pin sub 4.5 2.441 3.30 2153.39 (Top of packer) to center of element (2820') 4.625 2.441 3.60 2156.69 (Center of Element) to Bottom of Packer 2.875 2.441 748.56 2160.29 124 - 2 7/8 EUE Tubing joints @ (31.19 ea) 3.5 2.44 0.92 Cross over / 3 1/2 EUE pin x 2 7/8 EUE box 4.54 1.125 0.95 2908.77 CoNer MAX OD 3.5 2.992 5.52 2910.72 3 1/2 cross over pup joint EUE box X IBT pin 4.26 na 1.20 2916.24 HES Float Collar 3.5 2.992 6.21 3 1/2 cross over pup joint IBT box X EUE pin n U Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, February 13, 2009 1:38 PM To: 'Ed Jones' Cc: 'Chad Helgeson'; 'Bruce D Webb' Subject: RE: Lone Crk #4 (207-091) • Page 1 of 1 Ed, The ultimate test pressure is your decision. What I will note on the sundry is 3000 psi minimum CT BOP test. Thanks as well for the education regarding the various pipe sizes below the intended cleanout point. Tom Maunder, PE AOGCC From: aurorapower@gci.net [mailto:aurorapower@gci.net] On Behalf Of Ed ]ones Sent: Friday, February 13, 2009 12:57 PM To: Maunder, Thomas E (DOA) Cc: 'Chad Helgeson'; 'Bruce D Webb' Subject: RE: Lone Crk #4 (207-091) Tom, The 4500 psi test was intended only for the BJ equipment if/when isolated from the tree. The crown valve on the tree is rated for 5000 psi (as are all the valves), so the BJ equipment could be tested against the crown (swab) valve with the master and wing valves also closed and all pressure would be double -blocked from anything rated lower than 5000 psi. BJ also proposed testing their coil connector to 4500 psi. I agree that this is an overkill, as we will not be open to any pressure except what is applied from surface (BJ pumps). All the formation pressures will be isolated during the entire procedure until we perforate, after the coil tubing is released, and that is expected to be less than 1500 psi. We can certainly limit the tests to 3000 psi. (The tubing bonnet is rated to 3000 psi, but the rest of the tree is rated to 5000 psi). Please let me know if you have additional questions or concerns. Regards, Ed From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, February 13, 2009 2:48 PM To: Ed ]ones Cc: Bruce D Webb Subject: Lone Crk #4 (207-091) Ed, I am reviewing the sundry for the CT work on this well and have a question. 1. It is planned to do a 4500 psi BOP test, however the wellhead is only rated to 3000 psi and this is well in excess of the surface pressure that the well can develop. Is there a reason for the high test pressure value? I know that value is similar to what Marathon tests to, but they have 5000 psi trees. I may have other questions; however I wanted to get this one off. Bruce, As you know the phones are presently on the fritz. Would you confirm Ed gets this? My cell is presently charging. Thanks, Tom Maunder, PE AOGCC 7/1'x0009 • 0 9-5/8" X 5-1/2" X 2-7/8" OD, 3,000/5,000 PSI ASSY -,0K SP -6833; LONE CREEK #4 5-3/4"-4 ACME 2-7/8 UP TBG BOX LIFT THD ................... 'o 0 16.62" 2-1/16 5M 9.00" i 4.50"_ r 16.62" 7.31" 21.25" 2-7/8" OD TBG 2-9/16 5M 2-9/16 3M CONNECTION 7-1/16 3M 9-5/8" OD CSG 5-1/2" OD CSG 50.18" Page 1 of 2 Maunder, Thomas E (DOA) From: aurorapower@gci.net on behalf of Ed Jones Uejones@aurorapower.com] Sent: Friday, February 13, 2009 12:20 PM To: Maunder, Thomas E (DOA) Cc: 'Bruce D Webb' Subject: RE: Lone Crk #4 (207-091) — AGAIN Attachments: Lone Creek 4 AS -IX Liner.xls; LC 4 Actual Completion Diagram 011509.doc Tom, It is easy to misunderstand the configuration of this well: the bottom of the 2-7/8" tubing is at 2908.85', but then there is a 2-7/8" X 3-1/2" X-0 (0.92') that connects to a 3-1/2" landing collar at 2909.77', which is the point to which we were planning to clean out. The 3-1/2" EUE landing collar is connected to a 5.5' pup joint w/ 3-1/2" EUE box and a 3-1/2" IBT pin, which is connected to the 3-1/2" IBT float collar (at 2916.24'), which is connected to another 3-'/2" pup joint (IBT box X EUE pin) then 2 joints of 3-1/2" EUE tubing (64.90'), then another EUE X IBT pup (5.71'), and the 3-1/2" IBT float shoe, bottom at 2995.38'. Thus, if we clean out to +/-2910', we have +/-85' of cement filled shoe joints remaining. See attached diagrams. (Note that on the Weatherford liner diagram, the top of the liner is actually at 2089' (inverted On -Off tool top)—an extra stand of 2-7/8" tubing was run after the plan was put together). Due to the short time frame, we had to use the float equipment (3-1/2") and liner hanging equipment (2-7/8") that was available, so we ended up with a lot of cross -overs and a 2-7/8" liner with a 3-1/2" shoe—thus the potential for misunderstanding. Please let me know if this does not answer your questions. Thanks, Ed From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, February 13, 2009 2:54 PM To: Maunder, Thomas E (DOA); Ed Jones Cc: Bruce D Webb Subject: RE: Lone Crk #4 (207-091) -- AGAIN Ed, According to the tubular details, the 2-7/8" liner shoe is at 2910'. Instep 10 the desired cleanout depth is stated as 2910'. Is it your intent to drill out the shoe or just drill nearly to it? If it is not intended to drill out of the shoe, it is probably appropriate to limit the cleanout depth to some depth less than 2910'. 1 look forward to your replies. Tom Maunder, PE AOGCC Maunder, Thomas E (DOA) Sent:. r1 ebruary 13, 2009 11:48 AM To: Ed Jones Cc: 'Bruce D Webb' Subject: Lone Crk #4 (207-091) Ed, I am reviewing the sundry for the CT work on t � Lerf6ha uestion. 1. It is planned to do a 4500 psi BOP tes er the wellhead is on d to 3000 psi and this is well in excess of the surface pressure that ell can develop. Is there a reason for i h test pressure value? know that value is similar t arathon tests to, but they have 5000 psi trees. I`may haveot r questions; however I wanted to get this one off. 2/13/2009 Aurora Gas, LLC Lone Creek #4 Actual Configuration Revised 1/15/09 Drill 12-1/4" Hole to 765' 2-7/8" x 5 'h" annulus to be filled w/ 10.7 ppg KCI-NaCl-CaCI brine Beluga (Tsuga2-8 1022-42 1052-57 U. Tyonek (Carya 2- 1.1) 1462-82' 1496-1506' 1516-36' 5-1/2" 18# Production Casing set at 2,350' Cement in 2 stages w/ 11.5, 13.5. & 15.8 ppg Class G Drill 7-7/8" Hole to 2,483' Tyonek Carya Plann 2820 Dril14-3/4" Hole to 3,000'MD/2910'T� ., • 2 7/8 6.5# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 80' 1-5/8" 36# Surface Casing set at 765' "ement w/ 13.5 ppg Class G Hydraulic Set Packer @ 999' Sliding Sleeve @ —1,076' Hydraulic -set Packer @ —1,371' Sliding Sleeve @ —1,450' Sliding Sleeve @ —1,589' age Tool at 1875' ES BWB Seal Bore Packer, w/ X ipple. Top @2,041' Inverted On -Off Tool @2089' Arrowset Mechanical Packer @2093' w/ 2.31 profile XN nipple -ment at 2810' 18rd EUE J-55 Tubing to 2,910' 4 8rd EUE J-55 Tubing to 3,000' 1 w/ 11.5 and 15.8 ppg cement Estimated PBTD @ 2,910 Completion & Production Systems As -Run Drawing SAuI+WH Gas, LLC Revision: New 2.441 4.22 Page 1 Operator: Aurora State: Alaska Lease: Lone Creek 3.5 2.992 5.71 County: Kenai Peninsula Well No: 4 2.44 Date prepared: 1/3/2009 Prepared by: Lyle Savage 4.50 Phone: 240-8809 Company rep: Doug / John 2.44 Phone: 472-7793 Completion fluid: KCI 4.5 Fluid wt: 9.5# Perforations: (Top of packer) to center of element (2820') 2.441 Size (in) Wt (Iblft) ID (in) Drift (in) Type/Thmad CSG 51/2 15.5 4.892 LNR1 N/A LNR2 N/A Upper tubing: 27/8 6.4 2.441 EUE, N-80 Lower tubing: I EUE, N-80 No. I OD (in) I ID (in) Lensrth (ft) Depth (ft) Description I 1 1 2144.00 1 0.00 172 joints of 2 7/8 6.4# EUE tubing to surface j 2.875 2.441 4.22 2144.00 2 7/8 EUE Pup joint 3.5 2.992 5.71 3.25 2.312 3.5 2.44 Inverted X prolle in" Seal Nipple 4.5 3.25 4.50 2148.22 4.5 x 2 7/8 Inverted On -Off skirt 2.875 2.44 0.67 2152.72 2 7/8 pin X pin sub 4.5 2.441 3.30 2153.39 (Top of packer) to center of element (2820') 2.441 3.60 2156.69 (Center of Element) to Bottom of Packer El4.625 2.875 2.441 1 748.56 2160.29 24 - 2 7/8 EUE Tubing joints @ (31.19 ea) 3.5 2.992 5.71 2988.55 3 1/2 cross over pup joint EUE box X IBT pin 3.5 2.44 0.92 Cross over / 3 1/2 EUE pin x 2 7/8 EUE box 2995.38 Bottom ofHES Float Shoe 4.54 1.125 0.95 2909.77 Weatherford Landing Collar ( MAX OD ) 3.5 2.992 5.52 2910.72 3 1/2 cross over pup joint EUE box X IBTpin 3.5 2.992 5.71 2988.55 3 1/2 cross over pup joint EUE box X IBT pin 4.26 na 1.20 2916.24 HES Float Collar 2995.38 Bottom ofHES Float Shoe 3.5 2.992 6.21 3 1/2 cross over pup joint IBT box X EUE pin 3.5 2.992 1 64.90 2923.65 2- 3 1/2 tubing joints 3.5 2.992 5.71 2988.55 3 1/2 cross over pup joint EUE box X IBT pin 4.26 na 1.12 2994.26 HES Float Shoe 0.01 2995.38 Bottom ofHES Float Shoe VIP KENAI, ALASKA FIELD OPERATIONS Mp�.,.�.,.Lll�iWeatherford Completion & Production Systems OM As -Run Drawing Aurora Gas,LLC ��""� www.aurorapower.com Mr. Steve Davies Alaska Oil and Gas Conservation Commission February 11, 2009 333 W. 7`b Avenue, Suite 100 Anchorage, AK 99501 RE: Moquawkie #4 and Lone Creek #4 Dear Mr. Davies: This letter in duplicate originals transmits the data to you identified below, pursuant to Aurora Gas, LLC's obligation to you. This data is relative to operations at the Moquawkie and Lone Creek Fields, Cook Inlet, Alaska. The enclosed data consists of one CD for each well identified below. Enclosed herewith: SCHL.UMBERGER DATA CD's Moquawkie #4 Field PDS Graphics and LAS of DSUPEX/AIT Main Log Lone Creek #4 Field PDS Graphics and LAS of: �� 3 PEX/AIT, and Slim Acces PEX AIT Please signify that you have received and accepted this data by signing in the space below and returning this letter to me at the Anchorage address below or by fax to me at 907-277-1006. If you have questions, please contact me, or Ed Jones at the Houston number below. Sincerely, Bruce D. Webb Manager, Land and Regulatory Affairs it RECEIVED AND C E TED ABOV This _day of , 2009. 1400 West Benson Blvd., Suite 410 • Anchorage, AK 99503 • (907) 277-1003 • Fax: (907) 277-1006 6051 North Course Drive, Suite 200 . Houston, TX 77072 • (713) 977-5799 • Fax: (713) 977-1347 rJ 0 0 ��__'-'.:-_Aurora Gas L L C W"Yvw. a _Uro;-apmwe_-� Mr. Steve Davies February 3, 2009 Alaska Oil and Gas Conservation Commission 333 W. 7`h Avenue, Suite 100 Anchorage, AK 99501 RE: Lone Creek #4 Dear Mr. Davies: This letter in duplicate originals transmits the data to you identified below, pursuant to Aurora Gas, LLC's obligation to you. This data is relative to operations at the Moquawkie Field, Cook Inlet, Alaska. The enclosed data consists of one printed copy of each of the logs identified below. Enclosed herewith: SCHLUMBERGER LOGS Lone Creek #4 Platform Express, Array Induction / Compensated Neutron Triple-Lithodensity / SP / GR / Caliper Modular Dynamic Tester, MDT - GR Slim Access Platform, SAIT - SLDT - SPCS - GR, HGNS HALLIBURTON LOGS (Sperry Drilling Services) Lone Creek #4 Engineering TVD Log Engineering MD Logs Mud Log TVD log Mud Log MD Logs S Please signify that you have received and accepted this data by signing in the space below and returning this letter to me at the Anchorage address below or by fax to me at 907-277-1006. If you have questions, please contact me, or Ed Jones at the Houston number below. Bruce D. Webb Manager, Land and Regulatory Affairs N 06-'�-CRI RECEIVED AND ACCEPTED ABOVE DATA This _day of 92009. 1400 West Benson Blvd., Suite 410 ® Anchorage, AK 99503 a (907) 277-1003 0 Fax. (907) .277-1006 6051 North Course Drive, Suite 200 @ Houston, TX 77072 ® (713) 977-5799 s Fax. (713) 977-1347 V-0 STATE OF ALASKA ti ALA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown ❑ Perforate ❑ Waiver ❑ Other Q Alter casing Q ' Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension ❑ Change approved program Q , Pull Tubing ❑ Perforate New Pool ❑ Re-enter Suspended Well ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: AURORA GAS LLC Development Q Exploratory ❑ Stratigraphic ❑ Service ❑ 207-091 ' 3. Address: 6. API Number: 2500 City West Blvd., Suite 2600, Houston, TX 77042 50-283-20121-00 , 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 Lone Creek No. 4 ' 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): CIRI Lease # C-061395 1 415 AMSL (DF) I Lone Creek (Undesignated Gas) 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): 2483' 2387 2462 2367 Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 13-3/8" 96' 96' 1,530 psi 520 psi Surface 731' 9-5/8" 746 746 3,580 psi 1,580 psi Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type: Packers and SSSV MD (ft): 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development Q Service ❑ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: December 20, 2008 Oil ❑ Gas Q Plugged ❑ Abandoned ❑ WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. Verbal Approval: Date: Commission Representative: 18. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact J. Edward Jones (713) 977-5799 Printed Name Bruce D. Webb, Manager, Land and Regulatory Affairs Title Vice President, Engineering and Oper. Signature'— ��`?� Date 2 Ca COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test 1` Mechanical Integrity Test ❑ Location Clearance ❑ \ Other: 00C`�- ��•�rc �5Wp`Sc 7 S\ QS< M`\t�t �0%—"' (,�n�l�Cgi t cw: , GiZ Subsequent Form Required: Lon --x APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: /Z122-/ F DEC24 2006 !2•a� •08 Form 10-403 Revised 06/2006 Su it in jDuplicate Aurora Gas, LLC www.aurorapower.com Tom Maunder, Senior Petroleum Engineer December 19, 2008 State of Alaska Oil and Gas Conservation Commission 333 W. 7tb Avenue, Suite 100 Anchorage, AK 99501 Re: Sundry Approval Request for Revised Drilling Procedure Lone Creek #4 Development Gas Well, Permit to Drill No. 207-091 Dear Mr. Maunder: Pursuant tol AAC 25.280, Aurora Gas, LLC ("Aurora") request sundry approval for revised drilling and casing procedures at the Lone Creek #4 development gas well. Because drilling operations are underway, only a brief supplemental summary of the change in drilling procedures follows. A detailed drilling procedure is being prepared and will be submitted when finalized. Attached, please find the 10-403 Application for Sundry Approval, the revised casing design properties and the cementing proposal by BJ Services, Supplemental Summary of Drilling Procedure Chanizes After we are finished logging, we plan to set an open hole cement plug on bottom (2100-2450'+). We then plan to dress off the top of the plug and run 5-1/2" to 2400'. Unfortunately, we just topped our Carya 2-4.2 primary target at about 2480' (and must be losing mud into it) but did not get deep enough to see any of it (Logger TD was 2462' MD). Thus, after running the 5-1/2" casing, we are planning to drill out with 4-3/4" bit to 200-500' to look at the deeper objectives. 1) When we finish with the MDT run, we'll run no more logs --SLB should be rigged down and released. 2) RIH open-ended (do we have a mule -shoe, or some such guide?) to 2400'. Establish circulation at low rates. If losses are minimal increase the rate to +/-1 BPM. Then, lower end of open-ended drill string to 2440 -50' --if losses are more than 15% when circulating, stay at 2400', don't go deeper. If losses increase, pump coarse concentrated LCM pill. (Until the barge arrives tomorrow, we are short on mud materials if we have significant losses). 3) Mix and pump 75 sx of 14.0 ppg "Production Lead" blend as per BJ proposal --22 bbl of cement. (NOTE --BJ proposal assumed larger drill pipe for displacement --we have 3.1/2" 15.5#, w/ capacity of .0066 bbl/ft). Spot on bottom as balanced plug, displacing with 10.7 ppg mud and pull out (will result in 285' of cement in open hole w/ 9" hole size as indicated by the caliper on the log). Pull up to 2100' and circulate out. Pull a stand and WOC 6 hours, working pipe frequently to avoid any sticking in the annulus. Keep hole full. 4) After 6 hours, circulate bottoms up and slowly POH. 1400 West Benson Blvd., Suite 410 • Anchorage, AK 99503 • (907) 277-1003 • Fax: (907) 277-1006 6051 North Course Drive, Suite 200 • Houston, TX 77072 . (713) 977-5799 • Fax. (713) 977-1347 5) PU RR 7-7/8" bit and RIH w/ QC's. Tag cement. Drill cement to 2400'. Circulate out, ST and condition hole to run casing. POH, LD DP & DC's. l 6) Run 5-1/2" casing to 2400'w/ stage tool at 1900'. Will cement first stage w/ 11.5 ppg cement and 2nd stage with Production Lead and Production Tail, as per BJ Proposal. More detailed procedure will be provided for 2 -stage job. 7) We will likely drill out 200-500' with 4-3/4" bit 12 3-1/8' drill collars on 2-7/8" 8 rd ELIE tubing with 9.3 ppg mud (MDT pressure's in #3 indicated the highest pressure at 9.1 ppg at the equivalent depth and below, except that the 2-5.2 had a 9.3 ppg reading, but is has produced and been depleted in the #3. Lost circulation is more likely than pressure). Thank for your review and consideration of this request. Should questions arise in connection with this request, please contact Mr. fid Jones at the Houston telephone number below. Sincerely, 1 Bruce D. Webb Manager, Land and Regulatory Affairs attachments Lone Creek No.4 * Tensile design safety factors are calculated using pipe weight less buoyancy. Burst design safety factors are calculated at the surface using zero backup on the outside and MASP on the inside. Collapse design safety factors are calculated at the casing shoe using the maximum expected mud weight to be used at the[] shoe depth on the outside and the entire cased hole evacuated except for a gas gradient on the inside. Casing Setting Depth Rationale 0 9-5/8" 750' MD / 750' TVD Surface casing to stabilize shallow formations provide an anchor for the BOP stack and provide shoe strength in the event of a kick. 5-1/2" 2400' MD/2305 TVD Production casing to stabilize and isolate producing interval for production operations. and Intermediate Casing to isolate higher pressured gas sands from partially depleted sands. 3-1/2" 2300' MD/ 2205' TVD Production liner to liner to stabilize wellbore and isolate partially depleted sand for production operations. Casing Properties and Design Verification Casing Performance Properties: Tensile Strength Internal Collapse Size Weight Yield Resistance TVD MD MW MASP Inches lb/ft Grade Cnxn si tpsji Joint Body (ft RKB) (ft RKB) (ppg) BF fhsi 9-5/8" 36 J-55 BTC 3520 2020 639,000 564,000 750 750 9.5 0.85 549 5-1/2 15.5 K-55 BTC 4810 4040 366,000 248,000 2400 2303 10 0.85 1519 3-1/2" 9.3 J-55 EUE 6980 7400 142,500 142,500 3100 3285 9.5 0.85 1519 Design Safety Factor* Size Tensile Burst Collapse 9-5/8" 24.4 6.4 6.8 5-1/2 8.2 3.2 4.0 3-1/2" 5.5 4.6 6.1 * Tensile design safety factors are calculated using pipe weight less buoyancy. Burst design safety factors are calculated at the surface using zero backup on the outside and MASP on the inside. Collapse design safety factors are calculated at the casing shoe using the maximum expected mud weight to be used at the[] shoe depth on the outside and the entire cased hole evacuated except for a gas gradient on the inside. Casing Setting Depth Rationale 0 9-5/8" 750' MD / 750' TVD Surface casing to stabilize shallow formations provide an anchor for the BOP stack and provide shoe strength in the event of a kick. 5-1/2" 2400' MD/2305 TVD Production casing to stabilize and isolate producing interval for production operations. and Intermediate Casing to isolate higher pressured gas sands from partially depleted sands. 3-1/2" 2300' MD/ 2205' TVD Production liner to liner to stabilize wellbore and isolate partially depleted sand for production operations. 9 Alurora Gass LLC DAILY REPORT Depth: 1 2483' Date: Company: Aurora Gas, LLC AFE # LC4 DRLG 08 24 Hour Progress: 00' 0 ft/hr Rig: AWS #1 Report # 40 Last Casing: 9 5/8" 749' Well: Lone Creek #4 Days Since Spud 26 RKB/Casinghead: 14.80' Hole Section: Prod.Bit # BHA #5 Total Depth: 2483' Serial # 3 3/8" OS 3.49 Hole Size: 7 7/8" ISize OS EXT 6.24 Depth In: 2483' IMake CC JT 7.77 Depth Out: 2483' Type Drl hrs: Depth In Cir hrs.: 1.30 Depth Out Cum. Drl. Hrs: Hours Cum. Cir. Hrs: 14.00 Nozzles (TFA) PU Weight: 82 Klbs IROP Down Weight: 35 Klbs TFA Rot Weight: 42 Klbs Mud Type PHPA WOB Rotating: Weight 10.7 ppg Rotary Speed: Viscosity 45 Rotary Torque: PV/YP 45/18 Flow Rate: IPH 8.4 PSI off BTM: Water Loss 5.2 PSI on BTM: Solid Content 8.60% Sand Content 0.25% Chlorides 30,200 TOTAL = 17.50 Weather: -4 degrees (fog) Last BOPE Test: 12/18/08 Next BOPE Test: 12-25-08 Operation details and comments Slow Pump Rate #1 MP From To Hours Depth MW SPM Pressure 0:00 1:30 1.50 M/u fishing assy. 1:30 7:00 5.50 RIH w/ fishing assy. - 3 3/8" overshot / os ext / cc jt. 7:00 8:00 1.00 M/u circ head - CBU @ 1660' / 30 spm - 280 psi Slow Pump Rate #2 MP 8:00 14:30 6.50 Worked overtop of fish 1705' (slacked off to 28k) Depth MW SPM Pressure Pulled up to 40k - (fish is free) Brk connection on Jt. 55 - 2243' 10.8 ppg 32 spm 180 psi M/u new SLB rope socket - M/u circ head - Pressure up & sheared out Bk disc @ 2600 psi - R/d circ. Head Fuel Used: 1070 Gallons 14:30 15:30 1.00 Parted wireline weak point wl 5k overpull Fuel Received: 15:30 17:30 2.00 Repositioned sheave and pulled E -line w/ SLB unit Fuel on Location: 4230 Gallons 17:30 21:00 3.50 Poh w/ fish - Rack back drill pipe in derrick Daily Total: Previous Total: 21:00 23:30 2.50 Brk Baker fishing assy. - L/d logging tools - Clear rig floor - 23:30 0:00 0.50 Mobilize cleanout Bha Cum Total: 06:00 Update: Avg. Gas 41 units - Max. Gas 102 units M/u Bha - Rih to 2400'- Circ. and condition Total Hours 24.00 hole - flow check well - Poh (no mud losses) COST AWS 20000.00 Full Day Rate Tyonec 5311.00 Hands & Equipment OTI 6410.00 Trucking, Labor, Equipment HES 3750.00 Mud Logging, Gas Detection, PVT Beaconi 0.00 Medic/Expeditor Remarks: Rental 1910.00 Misc. Rental Tools & Equip. No Accidents - No incidents - No spills Air 1500.00 Charter fits. For tools ($500 each fit) $80 a person Spill Drill - 3 min. ASRC 1600.00 Co. Man Personnel On Location: Baroid 105.00 Mud Lab & Products AWS 13 HES Mud Loggers 2 ASRC 1275.00 Mud Engineer & Co Man Tyonec Cont. 5 ASRC 2 SLB 0.00 Schlumberger OTI 3 Schlumberger 4 Baker 7791.00 Baker Beacon Baker 1 30 DAILY COST 49652.00 Company Rep: Doug O lesbee 0 0 Grass LLC DAILY REPORT Depth: 1 2483' Date: - . Company: Aurora Gas, LLC AFE # LC4 DRLG 08 24 Hour Progress: 00' 0 ftlhr Rig: AWS #1 Report # 39 Last Casing:9 5/8" 749' Well: Lone Creek #4 Days Since Spud 25 RKB/Casinghead: 14.80' Hole Section: Prod. Bit # RR#3 BHA #4 Total Depth: 2483' Serial # Hole Size: 7 7/8" Size Depth In: 2477' Make Depth Out: Type Drl hrs: Depth In Cir hrs.: 0.00 Depth Out Cum. Drl. Hrs: 0.00 lHours Cum. Cir. Hrs: 0.00 Nozzles (TFA) PU Weight: 82 Klbs ROP Down Weight: 40 Klbs TFA Rot Weight: 44 Klbs Mud Type PHPA WOB Rotating: Weight 10.7 ppg Rotary Speed: Iviscosity 45 Rotary Torque: PV/YP 45/18 Flow Rate: PH 8.4 PSI off BTM: Water Loss 5.2 PSI on BTM: Solid Content 8.60% Sand Content 0.25% Chlorides 30,200 TOTAL = 0.00 Weather: 20 degrees I Last BOPE Test: 12/18/08 Next BOPE Test: 12-25-08 Operation details and comments Slow Pump Rate #1 MP From To Hours Depth MW SPM Pressure 0:00 6:00 6.00 Wire line stuck in hole @1741 since 2000 hrs on 12/18/08 6:00 Wait on overshot tool from Baker and Schlumberger tools Schlumberger go to town to gather fishing tools @ 930 Slow Pump Rate #2 MP 12:00 6.00 Meet with Baker and fly back to Beluga @1230 Depth MW SPM Pressure 12:00 14:00 2.00 Clean Green pit, mix one mud pill, Work on Quincy. Wash cellar & Choke house 14:00 MU Baker and Schlumberger tools and hang shiv, rope Fuel Used: 1536 Gallons 19:30 5.50 sockets. Fuel Received: 19:30 11 20:30 1.00 IMake up fishing tools BHA Fuel on Location: 5300 Gallons Wireline ropesocket won't go through Jars, grind off bers Daily Total: 0:00 3.50 on tools, picked up (still no go) Previous Total: Cum Total: 06:00 Update: going hole to et fish. pTotal Hours 24.00 COST AWS 19000.00 20 hrs. Full Drlg Rate - 4 hrs. stand by wire line stuck Tyonec 2511.00 Hands & Equipment OTI 6410.00 Trucking, Labor, Equipment HES 3750.00 Mud Logging, Gas Detection, PVT Beacon 750.00 Medic/Expeditor Remarks: Rental 1910.00 Misc. Rental Tools & Equip. No Accidents - No incidents - No spills Air 1500.00 Charter fits. For tools ($500 each fit) $80 a person BOP Drill I Spill Drill Personnel On Location: Baroid 641.00 Mud Lab & Products AWS 13 HES Mud Loggers 2 ASRC 2775.00 Mud Engineer & Co Man Tyonec Cont. 5 ASRC 2 HES Schlumberger OTI 3 Schlumberger 4 Baker Baker 113eacon Baker 1 Aurora Gas 1 32 DAILY COST 39247.00 Com an Rep: Jon West ,Aurora Gas, LLC DAILY REPORT Depth: 1 2483' Date: ip" so Company: Aurora Gas, LLC AFE # LC4 DRLG 08 24 Hour Progress: 00' 0 ft/hr Rig: AWS #1 Report # 38 Last Casing: 9 5/8" 749' Well: Lone Creek #4 Days Since Spud 24 RKB/Casinghead: 14.80' Hole Section: Prod. Bit # RR#3 BHA #4 Total Depth: 2483' Serial # 11171883 Hole Size: 7 7/8" ISize 7 7/8" Depth In: 2477' Make SEC -DBS Depth Out: Type QHC1S Drl hrs: Depth In 2297' Cir hrs.: 6.80 Depth Out 2483' Cum. Dri. Hrs: 0.50 Hours 9 Cum. Cir. Hrs: 10.70 lNozzles (TFA) 12 14 16 PU Weight: 82 Klbs ROP 21 ft/hr Down Weight: 40 Klbs TFA .457 Rot Weight: 44 Kibs Mud Type PHPA WOB Rotating: Weight 10.7 ppg Rotary Speed: Viscosity 45 Rotary Torque: jPV1YP 45/18 Flow Rate: PH 8.4 PSI off BTM: Water Loss 5.2 PSI on BTM: Solid Content 8.60% Sand Content 0.25% Chlorides 30,200 TOTAL = 0.00 Weather: -5 dregrees Last BOPE Test: 12/18/08 Next BOPE Test: 12-25-08 Operation details and comments Slow Pump Rate #1 MP From To Hours Depth MW SPM Pressure 0:00 4:00 4.00 Finish testing BOP - lay dw. Test plug set wear ring 4:00 5:00 1.00 Rig up Slumberger E -Line 5:00 RIH to 2462' with Array Induction log -POH w/ same Slow Pump Rate #2 MP 12:00 7.00 RIH with Compensated Newtron Depth MW SPM Pressure 12:00 Rig up MDT and run in hole 2380' - Wire line stuck 20:00 8.00 while at 1741' while POH 20:00 0:00 4.00 Stuck in hole with wire line / waiting on fishing tools Fuel Used: 1541 Gallons Fuel Received: #5 choke valve replaced and retested Fuel on Location: 6836 Gallons Crews working on cleaning Green pits while running Daily Total: Previous Total: Cum Total: 06:00 Update: e -line Ed Total Hours 24.00 Waiting on fish tools COST 51/2 casing on location AWS 19000.00 20 hrs. Full Drlg Rate - 4 hrs. stand by wire line stuck Sperry -Sun tools to go out on barge today Tyonec 2511.00 Hands & Equipment OTI 5190.00 Trucking, Labor, Equipment No recordable mud loss HES 3750.00 Mud Logging, Gas Detection, PVT Beacon 750.00 Medic/Expeditor Remarks: Rental 1910.00 Misc. Rental Tools & Equip. No Accidents - No incidents - No spills Air 1500.00 Charter fits. For tools ($500 each fit) $80 a person BOP Drill 1 min. 30 sec / Spill Drill 2 min. AWS 1100.00 Co.man Personnel On Location: Baroid 641.00 Mud Lab & Products AWS 13 HES Mud Loggers 2 ASRC 1275.00 Mud Engineer Tyonec Cont. 6 ASRC 2 HES 9350.00 Sperry DD Daily = $2800 + MWD Daily = $6550 OTI 3 Beacon 1 27 DAILY COST 46977.00 company Rep: Jon West 0 ST A E 0 nA LASK[A ALASKA OIL AKD GAS CONSERVATION COM USSION Bruce Webb VP Aurora Gas LLC 2500 City West Blvd., Ste 2500 Houston TX 77042 • SARAH PAL/N, GOVERNOR 333 W 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501.3539 PHONE (907) 279-1433 FAX (907)276-7542 Re: Lone Creek Field, Undefined Gas, Lone Creek No. 4 Sundry Number: 308-466 Dear Mr. Webb: 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. Sincerely, Daniel T. Seamount, Jr. Chair �a DATED this ZZ day of December, 2008 Encl. I� Proposal No: 1001115187F Aurora Gas LLC LONE CREEK #4 API # 50-283-20121-0000 LONE CREEK Field 7 -12N -11W Tyonek County, Alaska December 15, 2008 Well Proposal Prepared for: Prepared by: Ed Jones Kenneth Nix Vice President Engineering & Operations District Technical Supervisor Aurora Gas LLC Kenai, Alaska Addt Bus Phone 907-277-1003 Bus Phone: 713-977-5799 Email: jejones@aurorapower.com "ffpr-04� POWE RVI SION@ POW E R P R 0 • P O W L R T R A X • P O w E R L INK Service Point: Service Representatives: Kenai, AK Edwin Post Bus Phone: (907) 776-4084 Senior Dist Operations Supv (907) 659-2329 Kenai, Alaska Fax: (907) 776-4087 Bus Phone: 907.776.4084 Mobile: 907.252.1863 Gr4105 l Operator Name: Aurora Gas LLCS Well Name: LONE CREEK #4 LA Job Description: 7 7/8" Squeeze Hole Date: December 15, 2008 Proposal No: 1001115187F JOB AT A GLANCE Depth (TVD) 2,300 ft Depth (MD) 2,483 ft Hole Size 7.875 in Pump Via Casing 5" O.D. (4.154" .I.D) 21 Total Mix Water Required 403 gals Spacer Spacer Fluid 5 bbls Slurry 14 ppg Slurry 50 sacks Density 14.0 ppg Yield 1.68 cf/sack Displacement Displacement Fluid 72 bbls Report Printed on: December 18, 2008 6:01 PM STIMULATION . CEMENTING o COMPLETION SERVICES . SERVICE TOOLS . COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES . PIPELINE SERVICES . WELL CONTROL Gr<109 Operator Name: Aurora Gas LLC4 , Well Name: LONE CREEK #4 lop A Job Description: 7 7/8" Squeeze Hole Date: December 15, 2008 Proposal No: 1001115187F WELL GEOMETRY Tubing/Drill Pipe Size 5.000 in 4,154 in ID 21 lbs/ft Squeeze Temperature 83' F Est. Static Temperature 830 F FLUID SPECIFICATIONS Spacer SLURRY VOLUME VOLUME NO. CU -FT FACTOR 1 249 / 1.68 Displacement = 5.0 bbis Spacer Fluid AMOUNT AND TYPE OF CEMENT = 50 sacks Class G Cement + 2% bwoc Calcium Chloride + 0.2% bwoc ASA -301 + 10% bwoc BA -90 + 2.5% bwoc FL -62 + 0.5% bwoc Sodium Metasilicate + 71.6% Fresh Water = 71.9 bbis Displacement Fluid CEMENT PROPERTIES SLURRY NO.1 Slurry Weight (ppg) 14.00 Slurry Yield (cf/sack) 1.68 Amount of Mix Water (gps) 8.07 Squeeze Slurry to contain an additional I% CaCI prehydrated in the mix water. Total CaCI in slurry is 2% BWOC. This blend is paid for. The product material will be subtacted from the final ticket except the additional 11% CaCI . Repan Printed on: December 18, 2008 6:08 PM Gr4133 STIMULATION . CEMENTING . COMPLETION SERVICES . SERVICE TOOLS . COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES . PIPELINE SERVICES . WELL CONTROL 0 0 0 V Operator Name: Aurora Gas LLC Well Name: LONE CREEK #4 Job Description: 5 1/2" Production L Date: December 15, 2008 Proposal No: 1001115187F JOB AT A GLANCE Depth (TVD) 2,315 ft Depth (MD) 2,400 ft Hole Size 7.875 in Casing Size/Weight: 5 1/2 in, 15.5 lbs/ft Pump Via 5 1/2" O.D. (4.950" .I.D) 15.5 Total Mix Water Required 2,532 gals Stage No: 1 Float Collar set @ 2,320 ft Weighted Spacer BJ Spealbond 40 bbls Density 11.3 ppg Slurry 11.5 ppg Slurry 51 sacks Density 11.5 ppg Yield 2.37 cf/sack Displacement Displacement Fluid 55 bbis Report Printed on: December 18, 2008 6:08 PM Gr4109 STIMULATION a CEMENTING . COMPLETION SERVICES a SERVICE TOOLS . COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES a PIPELINE SERVICES o WELL CONTROL ,y >r 0 0 Operator Name: Aurora Gas LLC Well Name: LONE CREEK #4 Job Description: 5 1/2" Production L Date: December 15, 2008 Proposal No: 1001115187F JOB AT A GLANCE (Continued) Stage No: 2 Weighted Spacer Seal Bond Density Lead Slurry Inventory Lead Density Yield Tail Slurry Partial Inventory Blend Density Yield Displacement Displacement Fluid Stage Collar set @ 1,900 ft 40 bbis 12.0 ppg 124 sacks 13.5 ppg 1.84 cf/sack 183 sacks 15.8 ppg 1.18 cf/sack 45 bbis Report Printed on: December 18, 2008 6:08 PM Gr4109 STIMULATION o CEMENTING a COMPLETION SERVICES o SERVICE TOOLS a COILED TUBING PRODUCTION CHEMICALS a CASING AND TUBING RUNNING SERVICES a PIPELINE SERVICES o WELL CONTROL l c_r Operator Name: Aurora Gas LLC Well Name: LONE CREEK #4 Job Description: 5 1/2" Production Date: December 15, 2008 LOA Proposal No: 1001115187F WELL, DATA ANNULAR GEOMETRY ANNULAR I.D. PTH (in) MEASURED TRUE VERTICAL 8.835 CASING 750 750 7.875 HOLE 2,400 2,315 SUSPENDED PIPES STAGE: 1 Float Collar set @ 2,320 ft Mud Density 10.70 ppg Est. Static Temp. 87 ° F Est. Circ. Temp. 86 ° F VOLUME CALCULATIONS 500 ft x 0.1733 cf/ft with 25 % excess = 108.2 cf 80 ft x 0.1336 cf/ft with 0 % excess = 10.7 cf (inside pipe) TOTAL SLURRY VOLUME = 118.9 cf - 21 bbls STAGE: 2 self caller flat t ;000 ft Mud Dihilty 10.70 pp0 Est. Static Temp. 82 ° F Est. Circ. Temp. 80 ° F VOLUME CALCULATIONS 750 ft x 0.2607 cf/ft 150 ft x 0.1733 cf/ft 1,000 ft x 0.1733 cf/ft Report Printed on: December 18, 2008 6:08 PM with 0 % excess = with 25 % excess = with 25 % excess TOTAL SLURRY VOLUME _ 195.6 cf 32.5 cf 216.6 cf 444.6 cf 79 bbls STIMULATION , CEMENTING . COMPLETION SERVICES . SERVICE TOOLS . COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES . PIPELINE SERVICES . WELL CONTROL Gr4115 Operator Name: Aurora Gas LLC P Well Name: LONE CREEK #4 . Job Description: 5 1/2" Production Date: December 15, 2008 Proposal No: 1001115187F FLUID SPECIFICATIONS STAGE NO.:1 Weighted Spacer 40.0 bbls BJ Spealbond + 18.8 lbs/bbl Potassium Chloride + 140.4 Ibs/bbl Barite - Sacked @ 11.3 ppg VOLUME VOLUME FLUID CU -FT FACTOR AMOUNT AND TYPE OF CEMENT Slurry 119 / 2.3 = 51 sacks Class G Cement + 15% bwoc BA -90 + 0.05% bwoc Static Free + 1.2% bwoc FL -63 + 1 % bwoc CD -32 + 1 gals/100 sack FP -61- + 0.8% bwoc Sodium Metasilicate + 15% bwoc LW -7-6 + 83.7% Fresh Water Displacement 55.2 bbls Displacement Fluid CEMENT PROPERTIES SLURRY NO. 1 Slurry Weight (ppg) 11.50 Slurry Yield (cf/sack) 2.37 Amount of Mix Water (gps) 9.44 Amount of Mix Fluid (gps) 9.45 Report Printed on: December 18, 2008 6:08 PM Gr4129 STIMULATION . CEMENTING . COMPLETION SERVICES . SERVICE TOOLS . COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES . PIPELINE SERVICES . WELL CONTROL 13.5-ppg Lead Slurry to contain an additional 1% CaCI prehydrated in the mix water. Total CaCI in slurry is 2% BWOC. 15.8-ppg Tail Slurry to contain 1% CaCI prehydrated in the mix water. Total CaCI is 2% BWOC. Report Printed on: December 18, 2008 6:08 PM STIMULATION . CEMENTING . COMPLETION SERVICES . SERVICE TOOLS . COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES . PIPELINE SERVICES . WELL CONTROL Gr4129 Operator Name: Aurora Gas LLC Well Name: LONE CREEK #4 Job Description: 5 1/2" Production . Date: December 15, 2008 Proposal No: 1001115187F FLUID SPECIFICATIONS (Continued) STAGE NO.: 2 Weighted Spacer 40.0 bbls Seal Bond + 18.3 lbs/bbl Potassium Chloride + 179.5 lbs/bbl Barite - Sacked @ 12 ppg VOLUME VOLUME FLUID CU -FT FACTOR AMOUNT AND TYPE OF CEMENT Lead Slurry 228 / 1.8 = 124 sacks Class G Cement + 10% bwoc BA -90 + 2% bwoc Calcium Chloride + 2.5% bwoc FL -62 + 1 gals/100 sack FP -6L + 0.5% bwoc Sodium Metasilicate + 0.2% bwoc ASA -301 + 82,3% Fresh Water Tail Slurry 217 / 1.1 = 183 sacks Class G Cement + 2% bwoc Calcium Chloride + 0.4% bwoc R-3 + 2% bwow Potassium Chloride + 0.6% bwoc CD -32 + 1 gals/100 sack FP -61- + 0.3% bwoc Sodium Metasilicate + 1% bwoc BA -10A + 43.7% Fresh Water Displacement 45.2 bbls Displacement Fluid CEMENT PROPERTIES SLURRY SLURRY NO. 1 NO.2 Slurry Weight (ppg) 13.50 15.80 Slurry Yield (cf/sack) 1.84 1.18 Amount of Mix Water (gps) 9.27 4.92 Amount of Mix Fluid (gps) 9.28 4.93 13.5-ppg Lead Slurry to contain an additional 1% CaCI prehydrated in the mix water. Total CaCI in slurry is 2% BWOC. 15.8-ppg Tail Slurry to contain 1% CaCI prehydrated in the mix water. Total CaCI is 2% BWOC. Report Printed on: December 18, 2008 6:08 PM STIMULATION . CEMENTING . COMPLETION SERVICES . SERVICE TOOLS . COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES . PIPELINE SERVICES . WELL CONTROL Gr4129 Operator Name: Aurora Gas LLC Well Name: LONE CREEK #4 Job Description: 3 1/2" Liner Date: December 15, 2008 Proposal No: 1001115187F JOB AT A GLANCE Depth (TVD) 2,775 ft Depth (MD) 2,850 ft Hole Size 4.75 in Liner Size/Weight : 3 1/2 in, 9.3 lbs/ft Pump Via 3 1/2" 0. D. (2.992" .I.D) 9.3 Casing 3 1/2" O.D. (2.992" .I. D) 9.3 Total Mix Water Required 160 gals Weighted Spacer BJ SealBond 20 bbis Density 11.3 ppg Slurry Class G 17 sacks Density 11.5 ppg Yield 2.37 cf/sack Displacement Displacement Fluid 25 bbis Report Printed on: December 18, 2008 6:08 PM STIMULATION a CEMENTING . COMPLETION SERVICES a SERVICE TOOLS a COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES . PIPELINE SERVICES . WELL CONTROL Gr4109 " 'if Operator Name: Aurora Gas LLC* Well Name: LONE CREEK #4 LIP Job Description: 3 1/2" Liner Date: December 15, 2008 Proposal No: 1001115187F WELL DATA ANNULAR GEOMETRY ANNULARLD. DEPTH ft (in) MEASURED TRUE VERTICAL 4.950 CASING I 2,400 2,315 4.750 HOLE 2,850 2,775 SUSPENDED PIPES Drill Pipe 3.5 (in) OD, 2.992 (in) 2,770 ft ID, 9.3 (lbstft) set Drill Pipe 3.5 (in) OD, 2.992 (in) 2,300 ft ID, 9.3 (lbs/ft) set u@a Depth to Top of Liner 2,300 ft Float Collar set @ 2,850 ft Mud Density 10.80 ppg Est. Static Temp. 87 ° F Est. Circ. Temp. 88 ° F VOLUME CALCULATIONS 100 ft x 0.0668 cf/ft with 0 % excess - 7 cf 450 ft x 0.0562 cf/ft with 25 % excess - 32 cf TOTAL SLURRY VOLUME = 38 cf - 7 bbls Report Printed on: December 18, 2008 6:08 PM STIMULATION . CEMENTING . COMPLETION SERVICES . SERVICE TOOLS . COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES . PIPELINE SERVICES . WELL CONTROL Gr4117 Operator Name: Aurora Gas LLC Well Name: LONE CREEK #4 Job Description: 3 1/2" Liner Date: December 15, 2008 Proposal No: 1001115187F FLUID SPECIFICATIONS Weighted Spacer 20.0 bbls BJ SealBond + 163 lbs/bbi Barite - Sacked + 67.83 lbs/bbl Barite, Bulk + 19.82 lbs/bbl Potassium Chloride Q 11.3 ppg VOLUME VOLUME FLUID CU -FT FACTOR AMOUNT AND TYPE OF CEMENT Slurry 38 / 2.3 = 17 sacks Class G Cement + 15% bwoc BA -90 + 1.2% bwoc FL -63 + 1 % bwoc CD -32 + 0.8% bwoc Sodium Metasilicate + 15% bwoc LW -7-6 + 0.05% bwoc Static Free + 1 gals/100 sack FP -61- + 83.7% Fresh Water Displacement 24.8 bbls Displacement Fluid CEMENT PROPERTIES SLURRY Report Printed on: December 18, 2008 6:08 PM Gr4129 STIMULATION . CEMENTING . COMPLETION SERVICES . SERVICE TOOLS . COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES . PIPELINE SERVICES . WELL CONTROL NO. 1 Slurry Weight (ppg) 11.50 Slurry Yield (cf/sack) 2.37 Amount of Mix Water (gps) 9.44 Amount of Mix Fluid (gps) 9.45 Report Printed on: December 18, 2008 6:08 PM Gr4129 STIMULATION . CEMENTING . COMPLETION SERVICES . SERVICE TOOLS . COILED TUBING PRODUCTION CHEMICALS . CASING AND TUBING RUNNING SERVICES . PIPELINE SERVICES . WELL CONTROL L 1p pne'A CONDITIONS BJ Services' performance of services and sale of materials is expressly conditioned upon the applicability of the Terms and Conditions contained in the current BJ Services Price Book. The Terms and Conditions include, among other things, an indemnity in favor of BJ Services from Customer for damage to the well bore, reservoir damage, loss of the hole, blowouts and loss of control of the well, even if caused by the negligence or other fault of BJ Services. The Terms and Conditions also limit the warranties provided by the BJ Services and the remedies to which Customer may be entitled in the event of a breach of warranty by BJ Services. For these reasons, we strongly recommend that you carefully review a copy of the Terms and Conditions. If you do not have a copy of the BJ Services Price Book, you can view the Terms and Conditions on BJ Services Web Site, www.bjsorvices.com. By requesting that BJ Services perform the services described herein, Customer acknowledges that such Terms and Conditions are applicable to the services. Further, by requesting the services, Customer warrants that its representative on the well location or other service site will be fully authorized to acknowledge such Terms and Conditions by executing a Field Receipt or other document presented by BJ Services containing such Terms and Conditions. In the event that Customer and BJ Services have executed a Master Services Agreement covering the work to be performed, such Master Services Agreement shall govern in place of the Terms and Conditions. if you are interested in entering into Master Services Agreement with BJ Services, please contact us through the "Go BJ" button on the BJ Services Web Site. Report Printed on: DEC -18-08 03:08 G141 75 No - Operator: Aurora Gas LLC j Well Name: LONE CREEK #4 Date: December 15, 2008 Proposal No: 1001115187F PRODUCT DESCRIPTIONS ASA -301 Additive used to reduce or eliminate free water and settling in cement slurries. BA -10A Improves cement bonding and acts as a matrix flow control agent. BA -10A is effective in a wide variety of slurries. BA -90 An non -compacted silica fume that produces high compressive strength, low density cement slurries which prevent annular gas migration by reducing slurry permeability. It can be used in the low to high temperature ranges. BJ SealBond Spacer Forms a non invasive seal to prevent filtrate invasion into the producing formation. Trademark of PFS, LLC. Barite - Sacked A naturally occuring mineral (Barium Sulfate). It is widely used as a weighting material in cement spacers and occasionally in cement slurries. It can yield a slurry density in excess of 19 lbs/gal. Barite, Bulk A naturally occuring mineral (Barium Sulfate). It is widely used as a weighting material in cement spacers and occasionally in cement slurries. It can yield a slurry density in excess of 19 Ibstgal. CD -32 A patented, free-flowing, water soluble polymer that is an efficient and effective dispersant for primary and remedial cementing. Calcium Chloride A powdered, flaked or pelletized material used to decrease thickening time and increase the rate of strength development. Class G Cement Intended for use as a basic cement from surface to 8000 ft as manufactured, or can be used with accelerators and retarders to cover a wide range of well depths and temperatures. FL -62 A patented dry blend of water soluble polymers that are formulated to control the loss of fluid during cementing operations. A dispersant and bonding additive are proportioned to deliver consistent performance and control fluid loss in primary and squeeze cementing applications at low to moderate temperatures. FL -63 A non -retarding, non-viscosifying fluid loss additive particularly suited for use with coil tubing and/or close tolerance liner cementing. FL -63 is effective from low to high temperatures. Concentrations of 0.2% to 1.0% BWOC are typical. FP -6L A clear liquid that decreases foaming in slurries during mixing. Report Printed on: December 18, 2008 6:08 PM Gr4163 STIMULATION o CEMENTING . COMPLETION SERVICES a SERVICE TOOLS a COILED TUBING PRODUCTION CHEMICALS a CASING AND TUBING RUNNING SERVICES a PIPELINE SERVICES , WELL CONTROL . CHEMICAL SERVICES ow . w � • Operator: Aurora Gas LLC Well Name: LONE CREEK #4 Date: December 15, 2008 Proposal No: 1001115187F PRODUCT DESCRIPTIONS (Continued) LW -7-6 LW -7-6 is an unicellular silicate microsphere(hollow glass spheres) with a specific gravity of 0.37. Lowers slurry density for cementing across weak or lost circulation formations with hydrostatic pressures <6000 psi. Potassium Chloride A granular salt used to reduce clay swelling caused by water -base stimulation fluids. R-3 A low temperature retarder used in a wide range of slurry formulations to extend the slurry thickening time. Sodium Metasilicate An accelerator used to decrease the thickening time of cement slurries. Static Free An anti -static additive used to prevent air entrainment due to agglomerated particles. Can be used in Cementing and Fracturing operations to aid in the flow of dry materials. Report Printed on: December 18, 2008 6:08 PM Gr4163 STIMULATION o CEMENTING a COMPLETION SERVICES o SERVICE TOOLS s COILED TUBING PRODUCTION CHEMICALS o CASING AND TUBING RUNNING SERVICES a PIPELINE SERVICES o WELL CONTROL . CHEMICAL SERVICES Operator Name: Well Name: Date: Aurora Gas LLC LONE CREEK #4 December 15, 2008 End of Report Proposal No: 1001115187F Report Printed on: December 18, 2008 6 Grlast Maunder, Thomas E (DOA) From: aurorapower@gci.net on behalf of Ed Jones Dejones@aurorapower.com] Sent: Friday, December 19, 2008 12:22 PM To: Maunder, Thomas E (DOA) Cc: 'Bruce D Webb' Subject: RE: Lone Creek 4 (207-091) Status Tom, Will do (the plugging is only temporary, of course). Ed (Bruce, please draft this and send to me, based on yesterday's email. Thanks, Ed) From: Maunder, Thomas E (DOA) (mailto:tom.maunder@alaska.gov) Sent: Friday, December 19, 2008 11:13 AM To: Ed Jones Cc: Regg, James B (DOA); Ag Company Man; Jon West; Bruce D Webb; David Boelens; chelgeson@aurorapower.com; G Scott Pfoff; Mike Flaherty; DOA AOGCC Prudhoe Bay Subject: RE: Lone Creek 4 (207-091) Status Ed, Yes, a sundry is needed. The plugging should also be described. Tom Maunder, PE AOGCC From: aurorapower@gci.net (mailto:aurorapower@gci.net) On Behalf Of Ed Jones Sent: Thursday, December 18, 2008 6:48 PM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); 'Ag Company Man'; 'Jon West'; 'Bruce D Webb'; 'David Boelens'; cheigeson@aurorapower.com; 'G Scott Pfofr; 'Mike Flaherty'; DOA AOGCC Prudhoe Bay Subject: RE: Lone Creek 4 (207-091) Status Pagel of 3 Tom, An update on the Lone Creek 4. We got out losses stabilized (as per my last update), pulled out of the hole, tested the BOP's, and started logging this AM. We are finishing logging now, and plan to set an open hole cement plug on bottom (2100-2450'+). We then plan to dress off the top of the plug and run 5-1/2" to 2400'. Unfortunately, we just topped our Carya 2-4.2 primary target at about 2480' (and must be losing mud into it) but did not get deep enough to see any of it (Logger TD was 2462' MD). Thus, after running the 5-1/2" casing, we are planning to drill out with 4-3/4" bit to 200-500' to look at the deeper objectives. Here is the plan forward (more details to be provided as we get closer to each major operation): 1) When we finish with the MDT run, we'll run no more logs—SLB should be rigged down and released. 2) RIH open-ended (do we have a mule -shoe, or some such guide?) to 2400'. Establish circulation at low rates. If losses are minimal increase the rate to +/-1 BPM. Then, lower end of open-ended drill string to 2440-50'—if losses are more than 15% when circulating, stay at 2400', don't go deeper. If losses increase, pump coarse concentrated LCM pill. (Until the barge arrives tomorrow, we are short on mud materials if we have significant losses). 3) Mix and pump 75 sx of 14.0 ppg "Production Lead" blend as per BJ proposal --22 bbl of cement. (NOTE --BJ proposal assumed larger drill pipe for displacement --we have 3-1/2" 15.5#, w/ capacity of .0066 bbl/ft). Spot on bottom as balanced plug, displacing with 10.7 ppg mud and pull out (will result in 285' of cement in open hole w/ 9" hole size as indicated by the caliper on the log). Pull up to 2100' and circulate out. Pull a stand and WOC 6 hours, working pipe frequently to avoid any sticking in the annulus. Keep hole full. 12/22/2008 Page 2 of 3 40 4) After 6 hours, circulate bottoms up and slowly POH. 5) PU RR 7-7/8" bit and RIH w/ DC's. Tag cement. Drill cement to 2400'. Circulate out, ST and condition hole to run casing. POH, LD DP & DC's. 6) Run 5-1/2" casing to 2400'w/ stage tool at 1900'. Will cement first stage w/ 11.5 ppg cement and 2nd stage with Production Lead and Production Tail, as per BJ Proposal. More detailed procedure will be provided for 2 - stage job. 7) We will likely drill out 200-500' with 4-3/4" bit 12 3-1/8' drill collars on 2-7/8" 8 rd EUE tubing with 9.3 ppg mud (MDT pressure's in #3 indicated the highest pressure at 9.1 ppg at the equivalent depth and below, except that the 2-5.2 had a 9.3 ppg reading, but is has produced and been depleted in the #3. Lost circulation is more likely than pressure.). Detailed procedure to follow. We will submit a Sundry Application tomorrow (if needed). Regards, Ed Jones Aurora Gas, LLC From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, December 15, 2008 6:11 PM To: Ed Jones Cc: Regg, James B (DOA); Ag Company Man; Jon West; Bruce D Webb; David Boelens; chelgeson@aurorapower.com; G Scott Koff; Mike Flaherty; DOA AOGCC Prudhoe Bay Subject: RE: Lone Creek 4 (207-091) Status Ed, Keeping the hole full and attempting to remedy the lost circulation is prudent. It appears that you are having some success, although not sufficient to get out of the hole. As mentioned earlier, this is an unusual event. I don't remember other wells on the West side with a similar experience. Keep us advised of the operations and evolving plan forward. If the hole will stand full, is it your intent to increase the mud weight any? What was the final depth of the surface casing and the ultimate FIT/LOT achieved? If you have the FIT/LOT pressure plot, I'd appreciate if you would forward it. Please "copy all" at the AOGCC. Call or message with any questions. Tom Maunder, PE AOGCC From: aurorapower@gci.net [mailto:aurorapower@gci.net] On Behalf Of Ed Jones Sent: Monday, December 15, 2008 2:51 PM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); 'Ag Company Man'; 'Jon West; 'Bruce D Webb; 'David Boelens'; chelgeson@aurorapower.com; 'G Scott Koff; 'Mike Flaherty' Subject: RE: Lone Creek 4 Status Tom, Since this last report, we continue fighting lost circulation --we have gained some ground, but it doesn't appear that we will be able to drill ahead w/o cementing or casing. We pumped 2 - 25 -bbl pills of Baroid Hydro -Plug polymer, the last one early this AM. We are now at 2000', mixing mud preparing to circulate at low rates. Our losses have been about 25 bbl between 6:00 AM and noon today, starting at about 6 BPH and averaging about 4 BPH, so improving --MW 10.7 ppg, not seeing much gas at surface when static (filling the backside while mixing mud). Thus, it appears that the polymer did us some good, but not likely enough to drill ahead. We have both ordered a drillable open -hole bridge plug from Halliburton (will be in Anchorage in the AM), and have BJ working on cementing procedure and blend. Our plan preliminary forward is: 1) after mixing mud, to circulate out gas at a low pump rate; 2) run in hole, tag bottom (TD is 2483' MD), and pull out of the hole, circulating out any gas; 3) LD the MWD tool. Do weekly (delayed) BOP test. 4) If we tagged bottom near 2483', we'll likely run some logs (AIT and density/neutron in 2 runs to get as close to bottom as possible, as our primary pay is just above this LC zone); 5) a) depending upon the logs and apparent hole conditions, we will likely run the open -hole bridge plug on DP to about 10-15' off bottom, set it and run 5-1/2" casing, or b) alternatively, we may run in open-ended and set a cement plug near the bottom, POH, PU a bit, RIH and drill off top to set casing at some depth above the deepest pay. 12/22/2008 Page 3 of 3 6) Complete in whatever sands look the best on the logs. Either way we will have the option to drill a slim hole deeper in the future, if we think it is warranted. The procedure is obviously a "work in progress," and subject to change as we get more info. I will keep you informed of results and plans. Regards, Ed Jones From: Ed Jones[mailto:jejones@aurorapoweir.com] Sent: Thursday, December 11, 2008 12:13 PM To: 'Maunder, Thomas E (DOA)' Cc: 'Regg, James B (DOA)'; 'Ag Company Man'; 'Jon West'; 'Bruce D Webb'; 'David Boelens' Subject: Lone Creek 4 Status Tom, We continue fighting the lost circulation at lone Creek 4. We seem to be making progress, but we are not able to maintain circulation yet. The mud weight is 10.7 ppg, and the hole is staying full when static. However, when we circulate down the drill pipe at low rates (1 i0 SPM), we lose returns when the gas gets to surface and we shut in the annular to circulate it out thru the choke. We lost about 30 bbl overnight. We have just pumped another 40#/bbl LCM pill and are rebuilding mud volume at 0800 to try to circulate again. Regards, Ed Jones Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage) 12/22/2008 Page 1 of 1 ' • r Regg, James B (DOA) From: Regg, James B (DOA) Sent: Wednesday, December 17, 2008 11:48 AM To: 'JON ROBERTA WEST' 1 t�i� Q Cc: DOA AOGCC Prudhoe Bay; Maunder, Thomas E (DOA) Subject: RE: AWS 1 update In earlier message you indicated a possible BOPE test this afternoon; I am waiving Commission witness. In addition to test report, I'd appreciate receiving copy of the test chart(s). Thank you. Jim Regg LOAE CIDP `? Peso+, AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: JON ROBERTA WEST [mailto:jbwest@q.com] Sent: Wednesday, December 17, 2008 11:38 AM To: Regg, James B (DOA); Fleckenstein, Robert J (DOA); DOA AOGCC Prudhoe Bay Cc: Ed Jones Subject: AWS 1 update currently we are back reaming through a coal seam at starting 1647 that runs up to 1580 according to the logs, no loss and no gas 12/19/2008 STATE OF ALASKA 2/1/08 OIL AND GAS CONSERVATION COMMISSION Zell���°�la BOPE Test Report Submit to: iim.regg(a�alaska.gov doa.aogcc.prudhoe.bays_ ,alaska.gov bob.fleckenstein(a)alaska.gov Contractor: Aurora Rig No.: 1 DATE: 12/18/2008 Rig Rep.: R.Newton/Z. Young Rig Phone: 907-472-7791 Rig Fax: Operator: Aurora Op. Phone: 907-472-7793 Op. Fax: Rep.: Jon West Field/Unit & Well No.: Lone Creek #4 PTD # 207-091 Operation: Drlg: x Workover: Explor.: Test: Initial: Weekly: X Bi -Weekly Test Pressure: Rams: 250/3000 Annular: 250/1500 Valves: 250/3000 TEST DATA MISC. INSPECTIONS: FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.: P Well Sign P Upper Kelly 1 P Housekeeping: P Drl. Rig P Lower Kelly 1 P PTD On Location P Hazard Sec. P Ball Type 1 P Standing Order Posted P Inside BOP 1 P BOP STACK: Quantity Size Test Result CHOKE MANIFOLD: Annular Preventer 1 11" 3M P Quantity Test Result Pipe Rams 1 11" 3M P No. Valves 12 FP Lower Pipe Rams NA Manual Chokes 1 P Blind Rams 1 11' 3M P Hydraulic Chokes 1 P Choke Ln. Valves 1 3 1/8 5M P HCR Valves 2 3 1/8 5M P ACCUMULATOR SYSTEM: Kill Line Valves 2 3 1/8 5M P Time/Pressure Test Result Check Valve 0 NA System Pressure 3000 P Pressure After Closure 2000 P MUD SYSTEM: Visual Test Alarm Test 200 psi Attained 37sec. P Trip Tank P P Full Pressure Attained 2men.57sec. P Pit Level Indicators P P Blind Switch Covers: All stations P Flow Indicator P P Nitgn. Bottles (avg): 1880psi Meth Gas Detector P P H2S Gas Detector P P Test Results Number of Failures: 2/ Test Time: 6.5 Hours Components tested Repair or replacement of equipment will be made within 1 days. Notify the North Slope Inspector 659-3607, follow with written confirmation to Superviser at: jim.req_q(a7alaska.gov Remarks: # 5 choke valve failed and had a air leak on super choke control panel we repaired both same day. 24 HOUR NOTICE GIVEN YES X NO Waived By Jim Regg Date 12/17/08 Time 9:00 Witness Zan Young Test start 9:00 Finish 3:30 BOP Test (for rigs) BFL 2/1/08 BOP Aurora 1 BOP 12-18-08.xls Aurora Gas, Lone Creek #4 • BOP TEST 19:30 Hrs 17 -Dec -08 to 03:30 Hrs 18 -Dec -08 Choke Pressure Time 0 50 -5K 2-25 3K 5K 4-5K 19:30 14 444 i A LLLis ... . ... ... . ... .... IT, 20:00 J F Tpstin alves 10, 11 12 iLO\A( 20:30 to'ti �e Z 17,18, 9� Low 4it6g Ives 7, i8 I 4g� 21:00 Te*g',Valves 4,5, Low ........... ........ ... .......... .. ..... ..... .. . . L I.JV _ ___ __ .......... t 7 .... ....k TestrrrglValves 4,5,6 1#igh Teal Valves 3, 0 Low Testr glValyels-3;.4 -1-1 h i 22:00 ; € I 3 p € } , i f € ffff Rams t Test Dart, and Kill, Line o Testing Dart, urns aod-.KiII` Line High 22:30 I �. _. 5 ' Ad} king rsd cfua a_ uce oaf _J_ gess rebdr p .....w.. Testing ;CRO and . Ibor Sdfe L te w k I I Test�n FICRQ and E Ibor-5ofety;Val' : ; rgh s Ad}silTiasduce P f aid coal p�esslra!dr p ' € 23:00 s ig b �- 171 rBia , E ingio d TlOstrgBaHi`h 3 t Y # i . 23:30 - ----- —� I 1 g33 E € 00:00 upp elI e Lbw [ I € € er r E r € 1 r k , � r € � s t , I i E I � tt s E t E i 00:30 L 9_ ! , � Low E � € 3 F < i a i € k r 3 , ; t I °f r 01:00 i e -- E i r r 3 J # s r ' [ r s i Tp.sti n.A/IuP:#1 1 Page 1 of 1 Maunder, Thomas E (DOA) From: aurorapower@gci.net on behalf of Ed Jones Dejones@aurorapower.com] Sent: Wednesday, December 17, 2008 9:00 AM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); 'Ag Company Man'; 'Jon West; cheigeson@aurorapower.com; 'Bruce D Webb'; 'G Scott Pfoff Subject: FW: Aurora Update: Lone Creek 4 Tom, Below is an update from our Lone Creek 4 well. We have been down to 2400', circulated out with about 10% losses (less than 4 BPH), seeing no significant gas. We then pulled up to 1960' and circulated out again with minimal losses and no significant gas. We are now at 1900' circulating bottoms up. We then plan to pull up to about 800', just below the surface casing, circulate out, then POH to test the BOP's. Our general plan forward is as follows: PLAN: 1) When satisfied that well is dead and mud losses are minimal, POOH, stopping at +/- 800' to circulate out. LD MWD tool and Monel drill collars. 2) Test BOP's. Procure additional mud materials. 3) RU Schlumberger and run logs: AIT and Density/Neutron in separate runs (to get as close to bottom as possible). Closely monitor well for losses and/or gas. Run MDT if warranted. 4) Depending upon what shown on logs and how deep we can get, we will either: a) Run in w/ DP open ended and pump thick 14.0 ppg cement from about 2400'. (Procedure to be provided). POH. RIH w/ bit and BHA, dress off plug (drill cement) to 2400' or so, run 5-1/2" casing to this depth. Either complete uphole in secondary objectives, or come back next summer to deepen. b) Run open -hole bridge plug on DP as deep as we can get it (below top of 2-4.2 pay). Set. Establish circulation w/o losses. POH. Run 5-1/2" casing to plug. Cement, probably in 2 stages. Attempt completion in top of 2-4.2 pay sand (and shallower pays—triple selective completion). Please let me know if you have questions or concerns, Regards, Ed Jones From: ]ON ROBERTA WEST [mailto:jbwest@q.com] Sent: Wednesday, December 17, 2008 11:33 AM To: jim.regg@alaska.gov; bob.fleckenstein@alaska.gov; doa.aogcc.prudhoe.bay@alaska.gov Cc: Ed Jones; Dave Boelens Subject: Aurora Update We have worked our way up to 1900' and are presently circulating a second bottoms up with very little mud loss and 24 units back ground gas. We are planning on coming up to just below the shoe @746', monitoring the well and doing another bottoms up. If all is well we POH and lay down the MWD. With any luck at all we would be ready to test BOP's later this afternoon. ]on West Ph# 888-760-9925 Pusher's # 888-485-0147 12/22/2008 • Page lof Maunder, Thomas E (DOA) From: aurorapower@gci.net on behalf of Ed Jones Dejones@aurorapower.com] Sent: Tuesday, December 16, 2008 9:00 AM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); 'Ag Company Man'; 'Jon West; 'Bruce D Webb'; 'David Boelens'; chelgeson@aurorapower.com; 'G Scott Pfoff; 'Mike Flaherty'; DOA AOGCC Prudhoe Bay Subject: RE: Lone Creek 4 (207-091) Status Attachments: LC 4 9.625 Csg & Leak Off Test Excel.xls; Fit Test LC 4 ML.pdf Tom, Here are the plots of the FIT (and surface casing test), as you requested --one from pressure gauges (the Excel attachment, which shows lower pressures) and one thru the Sperry mud logging sensors (the PDF attachment). Please let me know if you would like to see any other info. Our status is much the same, we attempt to establish circulation yesterday, which we did w/ only partial returns (about 40% average). We continue to keep the hole full, currently losing about 5 BPH (we lost 137 bbl yesterday, including that lost while circulating). We are not seeing significant gas at surface. MW=10.7 ppg. Regards, Ed Jones From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, December 15, 2008 6:11 PM To: Ed Jones Cc: Regg, James B (DOA); Ag Company Man; Jon West; Bruce D Webb; David Boelens; chelgeson@aurorapower.com; G Scott Pfoff; Mike Flaherty; DOA AOGCC Prudhoe Bay Subject: RE: Lone Creek 4 (207-091) Status Ed, Keeping the hole full and attempting to remedy the lost circulation is prudent. It appears that you are having some success, although not sufficient to get out of the hole. As mentioned earlier, this is an unusual event. I don't remember other wells on the West side with a similar experience. Keep us advised of the operations and evolving plan forward. If the hole will stand full, is it your intent to increase the mud weight any? What was the final depth of the surface casing and the ultimate FIT/LOT achieved? If you have the FIT/LOT pressure plot, I'd appreciate if you would forward it. Please "copy all" at the AOGCC. . Call or message with any questions. Tom Maunder, PE AOGCC From: aG?ot%ppwer@gci.net [mailto:aurorapower@gci.net] On Behalf Of Ed Jones Sent: Monday, DRefaber 15, 2008 2:51 PM To: Maunder, Thomas E Cc: Regg, James B (DOA); 'Ag Com Man'; 'Jon West'; 'Bruce D Webb'; 'David Boelens'; chelgeson@aurorapower.com; 'G Scott Pfo , ' e Flaherty' Subject: RE: Lone Creek 4 Status Tom, Since this last report, we continue fighting lost circulation --we have gained round, but it doesn't appear that we will be able to drill ahead w/o cementing or casing. We pumped 2 - 25 -bbl pi aroid Hydro -Plug polymer, the last one early this AM. We are now at 2000'; mixing mud or to circulaterates. Our losses have been about 25 bbl between 6:00 AM and noon today, starting at about 6 BPH and avera bout 4 BPH, so improving --MW 10.7 ppg: not seeing much gas at surface when static (filling the backside while mi-XIrtil mud). Thus, it appears that the polymer did us some good, but not likely enough to drill ahead. We have both ordered a drillable open -hole bridge plug from Halliburton (will be in Anchorage in the AM), and have BJ working on cementing procedure and blend. 12/22/2008 CASING AND LEAK -OFF FRACTURE TESTS Well Name: Lone Creek #4 Csg Size/Wt/Grade: 9-5/8" 36# K-66 BTC 2 Csg Setting Depth: 746 T 179 Mud Weight: 11.5 p 5 LOT= 16.97 ppg Fluid Pumped= 0.0 B Date: 12/3/2008 Supervisor: Oglesbee / Newton MD 746 TVD pg bls Estimated Pump Output: LEAK -OFF DATA Enter Strokes Enter Pressure Here Here Enter Holding Enter Holding Time Here Pressure Here 0 212 1 199 2 190 3 179 4 173 5 169 6 7 8 167 164 163 9 162 _ 10 161 11 161 Leakoff pressure = 212 psi Hole Depth = 785 and Volume Back = 0.0 bbls 0.016 Barrels/Stroke CASING TEST DATA Enter Strokes Enter Pressure Here Here Enter Holding Enter Holding Time Here Pressure Here 0 1503 1 1497 2 1495 3 1492 4 1489 5 1485 10 15 20 1473 1461 1450 25 1447 30 1442 IL Ll F7� 4000 - - -- - ------------------ .......... 3900- 3800- 3700 - 3600- 3500- 3400- 3300 - 3200- 3100 - 3000- 2900 - 2800 2700 2600 2500- 2400- 2300- 2200- 2100- 2000- 1900- 1800 - 1700 1600 1500 c a 1400- 1300- 1200- 1100 1000 900- 800- 700 - 600--- 500 400 300-- 200-- 100 E 0 10 20 Strokes (# of) E 0 4000 - - ------------------ ............ .............. ............ ...... ........ ................................. 3900 3800 3700 3600 3500 3400 3300 3200 3100 3000 2900 2800 2700 2600 2500 2400 2300 2200 2100 2000 1900 p 1800 0. 1700 1600 1500 1400 1300 1200 1100 1000 900 Boo 700 600 500 40o--- 300 200 100 0 0 5 10 15 20 25 30 Time (Minutes) Aurora Gas, Lone Creek #4 FIT TEST 20:00 firs 03 -Dec -08 to 22:30 hrs 3 -Dec -08 SPP (psi) 0 500 1K 1.5K 2K Flow In (GPM) Time 0 75 150 225 300 Flow Out (GPM) 75 150 225 300 iL Begin Drilling 20:10 20:20 Conn @ 767.E 2 I 20:30 1 1 1 7(*'� POOH to shofor FIT 2.5K 3K 375 450 375 450 774 777 7"; 7E, 7P MIKRII7 21:30 IFIT 21:40 I 1 1 21:50 1 1 22:00 22:10 22:x:0 0 0 Maunder, Thomas E (DOA) From: aurorapower@gci.net on behalf of Ed Jones Dejones@aurorapower.com] Sent: Monday, December 15, 2008 3:43 PM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); 'Ag Company Man; 'Jon West; 'Bruce D Webb'; 'David Boeiens'; cheigeson@aurorapower.com; 'G Scott Pfoff; 'Mike Flaherty; DOA AOGCC Prudhoe Bay Subject: RE: Lone Creek 4 (207-091) Status Page 1 of 2 Tom, Regarding your questions, the mud weight will depend upon what we see when we circulate and how the hole is acting. If we don't have much gas, we'll keep it at 10.7-10.8 ppg; if we have much gas, we'll creep it up a bit. We didn't see an inordinate amount of gas at 10.7-10.8 ppg the last time we circulated --our biggest issue appears to be the loss and not the gas at this weight at this time. Regarding the FIT --the daily report shows a test to a "solid 16.97 ppg" EMW at 785'. The surface casing is set at 750'. 1 don't have the pressure plot on a good scale (only what I get from the mud logger), but I'll see if I can't get something better from the mud logger to send you. (If not, I'll forward what I have). I'll keep you informed. Regards, Ed Jones From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, December 15, 2008 6:11 PM To: Ed Jones Cc: Regg, James B (DOA); Ag Company Man; Jon West; Bruce D Webb; David Boelens; chelgeson@aurorapower.com; G Scott Pfoff; Mike Flaherty; DOA AOGCC Prudhoe Bay Subject: RE: Lone Creek 4 (207-091) Status Ed, Keeping the hole full and attempting to remedy the lost circulation is prudent. It appears that you are having some success, although not sufficient to get out of the hole. As mentioned earlier, this is an unusual event. I don't remember other wells on the West side with a similar experience. Keep us advised of the operations and evolving plan forward. If the hole will stand full, is it your intent to increase the mud weight any? What was the final depth of the surface casing and the ultimate FIT/LOT achieved? If you have the FIT/LOT pressure plot, I'd appreciate if you would forward it. Please "copy all" at the AOGCC. Call or message with any questions. Tom Maunder, PE AOGCC From: aurorapower@gci.net [mailto:aurorapower@gci.net] On Behalf Of Ed Jones Sent: Monday, December 15, 2008 2:51 PM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); 'Ag Company Man'; 'Jon West'; 'Bruce D Webb'; 'David Boelens'; chelgeson@aurorapower.com; 'G Scott Pfofr; 'Mike Flahery Subject: RE: Lone Creek 4 Status Tom, Since this last report, we continue fighting lost circulation --we have gained some ground, but it doesn't appear that we will be able to drill ahead w/o cementing or casing. We pumped 2 - 25 -bbl pills of Baroid Hydro -Plug polymer, the last one early this AM. We are now at 2000', mixing mud preparing to circulate at low rates. Our losses have been about 25 bbl between 6:00 AM and noon today, starting at about 6 BPH and averaging about 4 BPH, so improving --MW 10.7 ppg, not seeing much gas at surface when static (filling the backside while mixing mud). Thus, it appears that the polymer did us some good, but not likely enough to drill ahead. We have both ordered a drillable open -hole bridge plug from Halliburton (will be in Anchorage in the AM), and have BJ working on cementing procedure and blend. Our plan preliminary forward is: 1) after mixing mud, to circulate out gas at a low pump rate; 12/22/2008 . • Page 2 of 2 2) run in hole, tag bottom (TD is 2483' MD), and pull out of the hole, circulating out any gas; 3) LD the MWD tool. Do weekly (delayed) BOP test. 4) If we tagged bottom near 2483', we'll likely run some logs (AIT and density/neutron in 2 runs to get as close to bottom as possible, as our primary pay is just above this LC zone); 5) a) depending upon the logs and apparent hole conditions, we will likely run the open -hole bridge plug on DP to about 10-15' off bottom, set it and run 5-1/2" casing, or b) alternatively, we may run in open-ended and set a cement plug near the bottom, POH, PU a bit, RIH and drill off top to set casing at some depth above the deepest pay. 6) Complete in whatever sands look the best on the logs. Either way we will have the option to drill a slim hole deeper in the future, if we think it is warranted. The procedure is obviously a "work in progress," and subject to change as we get more info. I will keep you informed of results and plans. Regards, Ed Jones From: Ed Jones[mailto:jejones@aurorapower.com] Sent: Thursday, December 11, 2008 12:13 PM To: 'Maunder, Thomas E (DOA)' Cc: 'Regg, James B (DOA)'; 'Ag Company Man'; 'Jon West'; 'Bruce D Webb'; 'David Boelens' Subject: Lone Creek 4 Status Tom, We continue fighting the lost circulation at Lone Creek 4. We seem to be making progress, but we are not able to maintain circulation yet. The mud weight is 10.7 ppg, and the hole is staying full when static. However, when we circulate down the drill pipe at low rates (10 SPM), we lose returns when the gas gets to surface and we shut in the annular to circulate it out thru the choke. We lost about 30 bbl overnight. We have just pumped another 40#/bbl LCM pill and are rebuilding mud volume at 0800 to try to circulate again. Regards, Ed Jones Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage) 12/22/2008 Page 1 of Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, December 10, 2008 4:18 PM To: Regg, James B (DOA) Subject: RE: Lone Creek 4 Lost Circulation I agree. I remember you saying that they were "close" to TD and you were surprised by what I had in the spreadsheet. I will have a look at the hard copy file. From: Regg, James B (DOA) Sent: Wednesday, December 10, 2008 3:36 PM To: Maunder, Thomas E (DOA) Subject: RE: Lone Creek 4 Lost Circulation On 12/8 we granted Aurora's request to waive the upcoming BOPE test (due 12/9) so they could finish the well (conditioned on them performing successful function test of BOPE; I assume that was done; I received no confirmation from Aurora). Basis for their waiver request was that they only had 400 ft left to drill. I'm not convinced that basis was accurate from what I read below, and what you referenced as a permitted TD for the well in our discussion earlier today (3285 ft MD). I was not aware of well control issues when waiver was granted; I've left a msg with John Crisp to check Slope records about awareness of lost circulation at LC #4 when Aurora made the waiver request.. It may be appropriate to do a complete BOPE test once they resolve the lost circulation problems. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Maunder, Thomas E (DOA) Sent: Wednesday, December 10, 2008 3:09 PM To: Ed Jones Cc: Regg, James B (DOA); 'Bruce D Webb; 'Ag Company Man'; 'David Boelens; 'Jon West'; DOA AOGCC Prudhoe Bay Subject: RE: Lone Creek 4 Lost Circulation Ed, Thanks for the update. Interesting regarding the lost circulation, I don't remember events such as this in other wells over there. As usual, there always has to be a "first time". According to the regulations, the annular and choke manifold and any other equipment you might use will need to be tested when you are next on the bank. Tom Maunder, PE AOGCC Fro—m—.--Zaron-*oowej-@-qci.net [mailto:aurorapower@gci.net] On Behalf Of Ed Jones Sent: Wednesday, Decem r , PM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); 'Bruce D Webb'; 'Ag Company Man'; 'David Boe , ' Subject: Lone Creek 4 Lost Circulation 12/22/2008 • • Page 1 of 1 Maunder, Thomas E (DOA) From: Crisp, John H (DOA) Sent: Monday, December 08, 2008 8:56 AM To: Regg, James B (DOA) Cc: Maunder, Thomas E (DOA); Jones, Jeffery B (DOA); Scheve, Charles M (DOA); Grimaldi, Louis R (DOA); Noble, Robert C (DOA) Subject: FW: BOP VARIANCE REQUEST From: force@gci.net (mailto:force@gci.net] On Behalf Of Ag Company Man Sent: Monday, December 08, 2008 8:56 AM To: Crisp, John H (DOA) Cc: Ed Jones; Jon West Subject: BOP VARIANCE REQUEST John, Aurora gas, Lone creek #4 BOP test due prior to midnight on Dec 9th. Due to current rig operations John Crisp with the AOGCC was contacted to obtain either a 24 hour waver of notification or a 36 hour extension on testing BOP's. Mr. Crisp gave Aurora Gas permission to test BOP's prior to midnight on the 11th of December (48 hour extension) conditional upon the rig performing a function test of BOP equipment (equipment from both stations/body test). Doug Oglesbee/Jon West 12/8/2008 0 To: Bruce D Webb Subject: RE: Lone Creek 4 (207-091) Page /of �cl� Hi Bruce, I have the information and need to finish up. Would you or Ed please provide an update on Moquawkie #4? 1 think last I knew the production casing was set. Has the "packoff" been installed? Where will any gas be vented to? I look forward to your reply. Tom Maunder, PE AOGCC From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Friday, November 07, 2008 10:00 AM To: Maunder, Thomas E (DOA) Subject: Lone Creek 4 Hi Tom, Ed wanted me to check on the revised PTD for Lone Creek #4. ( 207-091) He put in a revision to the plan while I was out ( 10/22/08) and we may be moving the rig from Moquawkie to Lone Creek this weekend. Let me know when you have a few minutes. -Bruce 11 /7/2008 r MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim ReggI Z I DATE: November 24, 2008 P. I. Supervisor ' �` FROM: John Crisp, SUBJECT: Temporary Drilling Waste Petroleum Inspector Storage Areas �71_b -4)7-Ci November 24, 2008: 1 traveled to Aurora Gas, LLC's Lone Creek #4 Drilling Pad to witness Pre -Spud Diverter Function Inspection on Aurora Rig #1. AOGCC Inspector Supervisor Jim Regg requested] inspect temporary drilling waste storage areas for Lone Creek #4 & Moquawkie #4. ,001*0"Lone Creek #4 — The storage pit was being prepared for cuttings when 1 performed my Inspection. The actual location for temporary storage for Lone Creek #4 is on the Lone Creek #3 location. Aurora's Drilling Foreman Doug Oglesbee stated that the Lone Creek #4 drilling waste was scheduled to be taken to Tyonek Contractors Pad for processing. The storage pit on the Lone Creek #3 location was emergency storage only for Lone Creek #4 because of possible travel delays to Tyonek Contractors Pad. The Operator Rep assured me the emergency storage pit would be finished as per ADEC's permit instruction/guidelines. Moquawkie #4 — The temporary storage pit was found with quite a bit of snow on top of drilled solids & mound of drilled solids @ the shallow end of storage pit. Pit was lined with dense material to keep solids or any fluids from moving outside containment area. Pit liner was not proven to be of material required by ADEC. Darkness was rapidly approaching & travel back to Anchorage did not allow for further Inspection. A more thorough Inspection should be conducted at all temporary storage locations. Summary: Inspection of temporary drilling waste storage performed @ Lone Creek #4 & Moquawkie #4. Attachments: Photos r Temporary Drilling Waste Storage Areas Photos by AOOCC Inspector J. Crisp November 24, 2008 Lone Creek — temporary waste storage area construction s- 0 0 Moquawkie —temporary waste storage area construction • • Page 1 of 2 Maunder, Thomas E (DOA) From: Pirtle Bates [PBates@ciri.com] Sent: Tuesday, October 07, 2008 12:55 PM To: Bruce D Webb; Charles Akers Cc: Maunder, Thomas E (DOA); Kim Cunningham Subject: RE: Revised Pad Location for Lone Creek #4 To All: I have reviewed the revised Permit to Drill and other information attached to the below e-mail. CIRI has no objection to the location of the pad from which the proposed Lone Creek # 4 Well will be drilled, or any spacing exceptions that could be required. Should you have any questions, please feel free to contact me at the number below. Pirtle Pirtle Bates, Jr., CPL Manager, Resources CIRI 907-263-5517 From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Wednesday, October 01, 2008 10:34 AM To: Pirtle Bates; 'Charles Akers' Cc: 'Maunder, Thomas E (DOA)' Subject: Revised Pad Location for Lone Creek #4 Pirtle and Chuck, Aurora Gas has moved the location of the Lone Creek #4 pad slightly, which has resulted in the surface location of the well being changed approximately 29 feet to the northwest. The location of the pad was realigned to avoid unfavorable topography. As the surface and subsurface owners (CIRI and TNC, respectively), we would like you non -objection. See attached. Please "Reply to all" when sending back you comments. Thank you. Tom, I will be dropping the original PTD and attachments shortly. -Bruce Bruce A Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 office (907) 229-8398 cell (970) 277-1006 fax 12/22/2008 • 0 Page 2 of 2 The information contained in this CIRI e-mail message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply e-mail and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. 12/22/2008 � F ,..� j F� a nA F; j I.-.. A 11 SEL ALASKA OIL A" GAS CONSERVATION COMMSSION Bruce Webb Manager, Land & Regulatory Affairs Aurora Gas, LLC 1400 West Benson Blvd, Suite 410 Anchorage, Alaska 99503 SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Lone Creek #4 Aurora Gas, LLC Permit No: 207-091 (revised) Surface Location: 127 FWL, 1219' FSL, SEC. 8, T12N, R1 IW, SM Bottomhole Location: 341' FEL, 1060' FSL, SEC. 7, T12N, R1IW, SM Dear Mr. Webb: Enclosed is the revised approved application for permit to drill the above referenced development well. This revision was necessary due to changing the surface location prior to spud. Although this approval supersedes the permit to drill approved October 11, 2007 all requirements contained in that approval still apply. Due to the recent shallow gas event at Moquawkie #4 (207-084) you have prudently increased the initial spud mud weight recommendation to 11.5 ppg. Additional increases in mud weight should be determined based on the mud loggers assessment of gas in the mud and the wellbore conditions. Since there is a potential for encountering shallow gas -bearing sands, gas detection, PVT, and mud logging equipment must be fully operational prior to drilling out of the surface conductor pipe. You have also increased the surface hole size to 12-1/4" and plan to set 9-5/8" casing. You propose to use 12" diverter line and request a variance as allowed by 20 AAC 25.035 (h)(2). This waiver has been approved previously and is also approved for this well. This permit to drill does not exempt you from obtaining additional permits or approvals 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 0 i Lone Creek #4 Permit # 207-091 (revised) Page 2 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. Please provide at least twenty- four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659- 3607 (pager). Sincerely, Daniel T. Seamount, Jr. Chairman DATED this 7 day of November, 2008 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALA OIL AND GAS CONSERVATION COM&ION PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: Drill ❑� , Redrill ❑ Re-entry ❑ 1b. Current Well Class: Exploratory ❑ Development Oil ❑ Stratigraphic Test ❑ Service ❑ Development Gas, Multiple Zone ❑ Single Zone ❑ 1c. Specify if well is proposed for: Coalbed Methane ❑ Gas Hydrates ❑ Shale Gas ❑ 2. Operator Name: Aurora Gas LLC 5. Bond: Blanket 0 Single Well ❑ Bond No. NZS 429815 11. Well Name and Number: Lone Creek No. 4 3. Address: 1400 W. Benson Blvd Suite 410 Anchors a AK 99503 6. Proposed Depth: MD: 3,285 ' TVD: 3,100 12. Field/Pool(s): Lone Creek Gas Field 4olv-err-4 46 4a. Location of Well (Governmental Section): Surface: 127' FWL, 1,219' FSL,'Sec. 8, T12N, R11W, SM Top of Productive Horizon: 107' FWL, 1,184' FSL, Sec. 8, T12N, R11W, SM • Total Depth: 341' FEL, 1,060' FSL, Sec. 7, T12N, R11W, SM 7. Property Designation: CIRI Lease C-061395 • 8. Land Use Permit: T onek Native Co # AR -101765 13. Approximate Spud Date: 10/25/2008 a•% 9. Acres in Property: 480 (section acres) 13,804 (unit acres) 14. Distance to Nearest Property: 127• FWL / 3,833', to Unit boundary 4b. Location of Well (State Base Plane Coordinates): Surface: x - 273738.824 - 2611312.581 zone - 4 10. KB Elevation 305' MLLW - ? (Height above GL): 16' feet 15. Distance to Nearest Well Within Pool: 3,179' (LC #3) 16. Deviated wells: Kickoff depth: 770 feet Maximum Hole Angle: 42 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 1,829 psi ' Surface: 1,519 psi • 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Drilled 13-318"+ 72# K-55 BW 80' 16' 16' 96' 96' - N/A 12-1/4"• 9-5/8" 36# J-55 LTC 734 16' 16' 750' 750' -sx 7-7/8" 5-1/2" 15.5# K-55 LTC 3 269 16' 16' 3 285 3100 sx t i 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) ll 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 Property Plat 8 Diverter Sketch B Drilling Program Time v. Depth Plot , Shallow Hazard Analysis Seabed Report 8 Drilling Fluid Program ❑ 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct. Contact Printed Name Bruce D. Webb Title Manager, Land and Regulatory Affairs Signature, Phone 907 277-1003 Date October 1 2008 Commission Use Only Permit to Drill Number: 207-091 API Number: 50 - 283 - 20121 - 00 Permit Approval Date: 10/11/2007 See cover letter for other requirements. Conditions of approval: If box checked, well may not to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shale Other: �Samples req'd: Yes❑ No[� Mud log req'd: YesR No❑ 1717 /�,�% H2S measures: Yes❑ No[Y' Directional svy req'd: Yes[+ Nor-] i,-Wy IVQlr��ln © �tCr�QGE' � rte P(� /�tt•7�$ U � APPROVED BY THE COMMISSION DATE: COMMISSIONER ORIGINALForm 10-401 Revised 12/2005 Submit in Duplicate f\ STATE OF ALASKA ALA OIL AND GAS CONSERVATION COMMAtJ j U �N 2 0 2007 PERMIT TO DRILL 20 AAC 25.005 '` l -,s 03-d ' Gas Cons. C$ 1 a. Type of Work: 1 b. Current Well Class: Exploratory ❑ Drill Q Redrill ❑ Stratigraphic Test ❑ Service ❑ Re-entry ❑ Multiple Zone ❑ 2. Operator Name: Aurora Gas, LLC 3. Address: 1400 West Benson Blvd, Suite 410, Anchorage AK, 99503 4a. Location of Well (Governmental Section): Surface: 14U FWL, 1,193' FSL, Sec. 8, T12N, RI M SM Top of Productive Horizon: 107" FWL, 1,184' FSL, Sec. 8, TI 2N, R1IW, SM Total Depth: 341' FEL, 1,060' FSL, Sec. 7, T12N, R11W, SM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 273751 y- 2611286 Zone- 4 16. Deviated wells: Kickoff depth: 770 feet Maximum Hole Angle: 41 degrees 18. Casing Program: Specifications Hole Casing Weight Grade Coupling Lengt Drifted 13-3/8" 72# K-55 BW 80' 10.625 8-5/8" 32# J-55 LTC 734 7.875 5-112" 15.5# K-55 LTC 3.26! Development Oil ❑ 1c. Specify if well is proposed for. �� Development Gas Q Coalbed Methane ❑ Gas' F)yQa1es"b Single Zone ❑ Shate Gas ❑ 5. Bond: Blanket Q Sin le Well ❑ 11. Well Name and Number Bond No. /1/0.6�Z�%s(s .p7 Lone Creek No. 4 6. Proposed Depth: 12. Field/Pool(s): MD: 3,285 TVD: 3,100 7_ Pmnerty Desionation: Lone Creek Field C-061395 0 9. Acres in Property: 14. Distance to Nearest x- 640 Pr pe : K 10. KB Elevation 15. tance to Nearest Well (Height above GL): 16' feet Within Pool: 3,152' 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 1,829 psi � Surface: 1,519 psi Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks MD TVD MD TVD (including stage data) 16 16' 96' 96' N/A 16' 16' 750' - 750' - 223 sx 16' 16' 3,285- 3.100- 541 sx 119. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) I MD Intermediate 20. Attachments: Filing Fee Q BOP Sketch ❑ Drilling Program Q Time v. Depth Plot [D Shallow Hazard Analysis ❑ Property Plat El Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: Date 22, 1 hereby certify that the foregoing is true and correct. Contact Printed Name J. Edward Jones Title Exec. Vice President—Engineering and Operations Signature ' ,f '^,,�� �s�� Phone 713-977-5799 Date June 20. 2007 - Commission Use Only Permit to Drill API Number. Permit Approval See cover letter for other Number. ;;�`�'%��� 50- 283-Z6 ( — Date: -0requirements. 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. _ -t Samples req'd: Yes❑ No[rl Mud log req'd: YesR( Non HZS measures: Yes❑ NaV Directional svy req'd: YesQ" No[] DATE: !D0— //� Form 10-401 Revised 12/2005 %-ool 4N DUPLICATE 6o(;.,#2&07a— BY THE COMMISSION , COMMISSIONER in Duplicate ,mow 0 • Lone Creek No.4 Casing Properties and Design Verification Casing Performance Properties: * Tensile design safety factors are calculated using pipe weight less buoyancy. Burst design safety factors are calculated at the surface using zero backup on the outside and MASP on the inside. Collapse design safety factors are calculated at the casing shoe using the maximum expected mud weight to be used at the[] shoe depth on the outside and the entire cased hole evacuated except for a gas gradient on the inside. Casing Setting Depth Rationale 46 9-5/8" 750' MD / 750' TVD Surface casing to stabilize shallow formations provide an anchor for the BOP stack and provide shoe strength in the event of a kick. 5-1/2" 3,285' MD / 3,100' TVD Production casing to stabilize and isolate producing interval for production operations. Tensile Strength Internal Collapse Size Weight Yield Resistance TVD MD MW MASP Inches lb/ft Grade Cnxn si si Joint Body ft RKB (ft RKB) (fig) BF(As i 9-5/8" 36 J-55 BTC 3520 2020 639,000 564,000 750 750 9.5 0.85 549 5-1/2 15.5 K-55 BTC 4810 4040 366,000 248,000 3100 3285 10 0.85 1519 Design Safety Factor* Size Tensile Burst Collapse 9-5/8" 24.4 6.4 6.8 5-1/2 5.7 3.2 3.1 * Tensile design safety factors are calculated using pipe weight less buoyancy. Burst design safety factors are calculated at the surface using zero backup on the outside and MASP on the inside. Collapse design safety factors are calculated at the casing shoe using the maximum expected mud weight to be used at the[] shoe depth on the outside and the entire cased hole evacuated except for a gas gradient on the inside. Casing Setting Depth Rationale 46 9-5/8" 750' MD / 750' TVD Surface casing to stabilize shallow formations provide an anchor for the BOP stack and provide shoe strength in the event of a kick. 5-1/2" 3,285' MD / 3,100' TVD Production casing to stabilize and isolate producing interval for production operations. 500- 1,000 00- 1,000 1,500 z a m 2,500 3,000 3,500 4,000 Lone Creek #4 Days vs Depth 5 10 15 20 25 30 Days FIGURE 9 Drill 10-5/8 i i Interval Rin 9-5/8 Ca ing i I I Drill? -7/8 nterval I Log Well, Run 5-1/2 Casing, Pe�orate, Test, I Days FIGURE 9 k 0 �AGas, LLCro www.aurorapower.com Tom Maunder, Senior Petroleum Engineer State of Alaska Oil and Gas Conservation Commission 333 W. 70` Avenue, Suite 100 Anchorage, AK 99501 Re: Revised Permit to Drill No. 207-091 Revised Drilling Procedure Lone Creek #4 Development Gas Well Dear Mr. Maunder: OCT 2 2 2008 Alaska Oil & Gas Cons. Co,f sr€ ez,sior Anchorage October 22, 2008 As per our discussions, attached are 2 copies of the Revised Drilling Procedure for the Lone Creek No. 4 development well, to accompany the Revised Form 10-401, submitted on October 11, 2008. The Lone Creek #4 development gas well was originally approved by the AOGCC on October 11, 2007, Permit to Drill No. 207-091 (PTD). A spacing Exception was granted on September 13, 2007 as the bottom -hole location of the well was within 3,000 feet of the Lone Creek #3 producing well. Additionally, Aurora has revised the original casing plan and intends on installing 9-5/8" casing with a 12-1/4" hole, instead of the previously approved 8-5/8" casing and 10-5/8" hole. The attached Procedure incorporates those changes, plus specifies heavier mud weights after Aurora's experience with the nearby Moquawkie 4 and modifies the completion procedures somewhat. Should questions arise in connection with this request, please contact me at the Anchorage telephone number below. Sincerely, AURORA GAS, LLC Edward (Ed) Jones Executive Vice President attachments 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 Aurora Gas, 0 the Creek #4 Drilling Program Lone Creek #4 (Revised 10/22/08) Lone Creek #4 is a grass-roots well targeting Beluga & Tyonek Gas Production. It is located in the Lone Creek Gas Field 3,150' NNE of the Lone Creek #3 wells. Lone Creek #4 will target Upper Tyonek Carya 2-1 thru 2-6 sands with possible future production from Beluga Tsuga 2-8 sands. A spacing exemption will be required due to the proximity to Lone Creek #3. Pre Rig work Stake & survey the Lone Creek Site—GL is 400'. 2. Construct a 200' x 300' pad configured for AWS #1 with drilling support. Build sufficient cuttings containment for planned drilling program, and build containment for diverter line. 3. Install 13-3/8" conductor to 80' below ground level. Install cellar & mousehole. Cut off conductor as needed to accommodate diverter system. Drilling Procedure 1. File & insure all necessary permits and applications are in place. 2. MIRU AWS #1 in drilling configuration. 80' of 13-3/8" conductor has been pre-installed. Install 13-5/8" VG LOK head. 3. Rig up diverter & mud loggers. Test & calibrate all PVT / gas sensor equipment. Provide 24 -hr notice to AOGCC inspectors for chance to witness diverter test. 4. Notify AOGCC & pertinent agencies when ready to start drilling operations. 5. Prepare spud mud system / weight up to 11.5 ppg. Load, strap & drift 750' off 9-5/8" surface casing. 6. PU 12-1/4" mill tooth bit & drill to –750', using 8" stabilized BHA. Watch for gas in shallow coals and sands. Attempt to TD in siltstone or claystone, avoid setting surface shoe in a coal bed or sand. If possible, adjust TD to put cement head at floor. 7. Condition hole for running 9-5/8" surface casing, POOH, LD 12-1/4" BHA. 8. Run & cement new 9-5/8" 36 #, J-55 LTC casing @ 750', installing 1 centralizer /joint centered on the 0 4 joints above shoe, & 1 centralizer every 2"d joint across the collars there after. Shoe joint connection at float shoe and float collar must be Baker -Locked. Cementing will be single stage using 15.8 ppg accelerated cement at 1001/o excess volume (exact blend to be determined—also looking at a 12.0 gas -block Poz-mix blend, waiting on lab tests). Be prepared to treat cement returns with retarder. 9. RD cementers, nipple down diverter, cut casing and install 11" 3M wellhead. Prepared by Jack McDade, Rev Ed Jones Page 1 of 12 Rev. 1.2 Aurora Gas, Lone Creek #4 Drilling Program 10. RU and test 11" 3M BOP stack and 5M choke manifold. Test stack and surface equipment to 3,000 psi. Pressure test 9-5/8" casing to 1,500 psi for 15 minutes or as required on approved Permit to Drill. Mud weight to drill out should beat least 11.1 ppg (drill out weight at Lone Creek 3) at this point, do not cut back if higher, up to 11.5 ppg. 11. PU 7-7/8" Mill Tooth Bit & RIH w/ 6-'/4' collars. Drill out shoetrack. Condition / treat mud as needed for cement contamination, drill 20' new formation. Pull back into shoe & perform FIT / LOT up to 16.0 ppg EMW maximum with low volume test pump. Record results. POH & LD 6-1/4" collars. 12. PU 4-%" directional drilling assembly w/ 7-7/8" bit, motor & DIR MWD assembly, non - mag DC's, jars & HWDP as specified by Sperry proposal. 13. RIH and directionally drill 7-7/8" hole to 3,285' MD (3,100' TVD) TD per Sperry directional plan, or other as directed by Aurora Gas geologist (may be slightly shallower, depending upon top of Carya 2-6). Confirm that MW is 11.1 or more prior to reaching 900'. Monitor well and volumes carefully. Be prepared to shut well in and weight up immediately if flow or excessive gas build up in mud is noticed. Monitor hole cleaning and drilling trends, prepare to short trip if needed. Anticipated mud weights required are 11.0 ppg —12.0 ppg. Do not exceed fracture gradient determined in step 11. If possible, adjust TD to put cement head on floor. While drilling, load, tally & drift 5-1/2" casing on racks. 14. Condition hole, short trip and prepare for running wireline logs. 15. POOH, rack back drillstring and RU wireline BOP'S and lubricator and logging tools. Log 9-5/8" cased hole section w/gamma ray sensor, Log OH section with logging suite including resistivity and porosity logs as directed by Aurora Gas. RD wireline. 16. RIH w/ 7-7/8" drilling assembly to TD & condition hole for running 5-1/2" casing. Ensure cementing head has proper connections or proper cross-over and is available for quick rig up. 17. POOH while laying down drillpipe & BHA, RU to run casing. Verify cementer's equipment is ready. 18. Install 5-%2" pipe rams. 19. Run 5-1/2" 15.5# LTC K-55 casing installing I centralizer per joint centered on lst 4 joints above shoe, 1 centralizer every 2"d joint in open hole & every 3rd joint inside surface casing (use Turbolizer centralizers below/thru each pay sand and where directional inclination is greater than 10 deg). Shoe joint connection at float shoe, float collar & stage tool landing collar must be Baker -Locked (801shoetrack). While running casing, fill every 3rd joint. Be prepared to wash to bottom. 20. RU cementers, cement per attached cementing program from TD to surface. A sufficient amount of 13.5 ppg Class G lead cement will be pumped to cover from 900' up thru the annulus from the 9-5/8" shoe to surface. This will be followed by sufficient amount of 15.8 ppg Class G tail cement to cover from TD back to 900'. Excess will be calculated using caliper log dates --top of tail slurry will be determined following evaluation of the logs. Plug will be bumped with clean brine. If possible reciprocate pipe while displacing cement. Land casing & WOC. Prepared by Jack McDade, Rev Ed Jones Page 2 of 12 Rev. 1.2 Ammm GAc_ 0 Ge Creek #4 Drilling Program 21. RD cementers, nipple down stack, land casing in slips & cut casing. 22. Install 11" X 7-1/16" tubing spool, 7-1/16" X 11" DSA, mud cross and reinstall BOP stack. Pressure test BOP and surface equipment to 3,000 psi. Pressure test casing to 2,000 psi for 15 minutes and record results. 23. Install 2-7/8" pipe rams. 24. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Displace well w/ filtered KCl/NaC1 brine (wt. to be determined from MDT data). Continue to clean brine for perforating by running through centrifuge & filtering. POOH. Strap tubing on TOH to validate tally. A MORE DETAILED PROCEDURE WILL BE PROVIDED AT THIS POINT INCLUDING PERFS 25. PU wireline BOP'S & lubricator, pressure test all against casing to 1500 psi (or higher if MDT indicated higher gradients). PU GR/CBL/CCL & log 5-1/2" casing to surface. LD logging tools & PU perforating guns, RIH to depth as determined from OH logs and perforate zones of interest. Watch for pressures in casing after shooting. POOH, LD perf gun, RD wireline. 26. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Circulate perforating debris from hole. Continue centrifuging & filtering brine until cleaned up. POOH. LD bit & scraper. RU Aurora well test unit, including flare stack. 27. Pick up & assemble completion assembly which will consist of seal bore packer for sump packer to be set above deepest perforated zone, then 2 (or 3) hydraulic packers w/ sliding sleeves between packers—all sliding sleeves are to be closed and a blanking plug is to be run in the XN nipple below deepest packer. Set seal bore packer on wireline. RIH with seal assembly and remainder of completion on new 2-7/8" 6.5# J-55 8 rd tubing & set completion at appropriate depth, filling tubing as running. Space out, hang off in tubing head & lock down. Pressure tubing to 3000 psi (or as required) to test and to set packers. Install BPV. ND BOP. NU and test tree. 28. Pull BPV and RIH w/ slick line and pull blanking plug. 29. RU & swab in deepest zone. After well cleans up, perform flow test --get stabilized rate (1 hour minimum). Shut in well & record pressure buildup until stabilized with no change in one hour. DO NOT KILL, but rerun blanking plug and set in XN nipple below deepest packer. 30. Add needed KCl water cushion to tubing (1000'). Open deepest sliding sleeve. Test well as per Step 29. DO NOT KILL, but close sliding sleeve. 31. Repeat Step 30 for remaining shallower intervals (i or 2). 32. Open zones for initial production (depending upon pressures and test results—likely the 2-4.2 and deeper}—flow to clean up. Shut in. Set BPV in tree. Release rig, RD, and move rig to Lone Creek 4 location. 33. Pull BPV. Run 4 -point test of initial production zone as per Procedure provided at that time. RD test unit. 34. Clear & clean location. Hand well over to production. Prepared by Jack McDade, Rev Ed Jones Page 3 of 12 Rev. 1.2 Aurora Gas, 35. File completion reports with proper agencies. Site Access fe Creek #4 Drilling Program Lone Creel #4 will be accessible via existing gravel roads currently in use to support production operations at the Lone Creek #3 drillsite. UZI Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the Lone Creek #4 well. The Alaska Oil & Gas Conservation Commission has information on this rig and equipment as it has been in use for the last (5) years on other Aurora Gas operations. The pits, BOP system & mud equipment configuration will be the same as that used for previous work. Survey Program The 12-1/4" surface hole will be drilled vertically and the survey program will consist of Sperry multi -shot survey and supplemented with single -shot surveys as required to be obtained at 500' intervals in accordance with rules laid out in 20 AAC 25.050 (a) (1) & (2). The 7 7/8" production hole will be drilled directionally. For all directional work, directional MWD will be utilized with supplemental wellbore surveys taken at maximum of 100 ft intervals as needed, per AAC 25.050 (a)(1). Logging Program Mud loggers will be on site for the duration of drilling activities. Schlumberger will provide wireline logging services as proposed below: Lone Creek #4 Proposed Logging Program Well Section Depths OH CH Log Type 12-1/4" Surface 0'— 750' N/A: No open -hole logs planned for surface at this time. GR only in cased hole. 7-7/8"' Production Hole 750'— 3,285' Platform Express: Array Induction, Compensated Neutron, Litho -Density, SP, GR, and possibly DSI.. Also MDT and S1 wall cores. 5-1/2" Int. Csg 750'— 3,285' GR/CBL/CCL Surface — TD 0'— 3,285' Mud Logging Services BOP Equipment Aurora Gas, LLC will use the same BOP system they have been using for the last (4) years which will consist of the following: Prepared by Jack McDade, Rev Ed Jones Page 4 of 12 Rev. 1.2 0 Aurora Gas, 12-1/4" Surface Hole Re Creek #4 Drilling Program While drilling the 12-1/4" surface hole, a 13-5/8" 5M annular w/ 13-5/8" diverter spool & 12" diverter line will be used as per 20 AAC 25.035 (c)(1)(A) requiring that the diverter line outlet size be at least 16" diameter or (B) at least as large as the hole size being drilled. 7-7/8" Production Hole An 11" 3000 PSI WP Schafco (Shaffer Equivalent) BOP system will be used which is configured with an I V 3000 PSI WP annular preventer, (1) 3000 PSI WP double gate with a set of pipe rams installed sized to fit the pipe being run and a set of blind rams and (1) 11" 3000 PSI WP rated drilling spool. BOP tests will be performed to 3000 psi. The annular preventer will be tested to 1500 psi. Again, this is the same equipment Aurora has been using all along and information on the system is on file at the AOGCC. Drilling Fluids The drilling fluids will be furnished by Baroid or MI, both of whom have extensive experience with drilling activities in this area. An experienced mud engineer will be on site at all times while drilling to monitor properties and make recommendations. Drilling Fluid Properties While Drilling 12-1/4" interval to 750' Beluga Formation Base Fluid 6% KCL Density 11.5 ppg PV 22-30 YP 20-30 API Filtrate < 5 Total Solids 15-25% Gel & Polymer mud system Drilling Fluid Properties While Drilling 7-7/8" interval to 3,285' Beluga and Tyonek Formations Base Fluid 6% KCL Density 11.0 —12.0 ppg PV 22-30 YP 20-30 API Filtrate < 5 Total Solids 10-15% Polymer mud system Prepared by Jack McDade, Rev Ed Jones Page 5 of 12 Rev. 1.2 Aurora Gas, Drilling Fluid Handling System Shale Shaker, Mud Cleaner, Centrifuge, PVT monitors Drilling Waste Disposal Lone Creek #4 Drilling Program The cuttings will be mixed with Portland cement and made into blocks or foundations. Drilling mud will be held in tanks for reuse or injection at the Aspen Disposal Well. Brine will be placed in tanks for use in future wells. Prepared by Jack McDade, Rev Ed Jones Page 6 of 12 Rev. 1.2 u Aurora Gas, Casing / Cementing Program Line Creek #4 Drilling Program All casing is new. Analysis (attached) indicates casing program as designed provides adequate safety factors for this well. All casing strings with the exception of the 13-3/8" conductor will be cemented in place using industry standard casing cementing techniques utilizing a casing shoe, float equipment, top and bottom wiper plugs and centralizers installed as needed. 13-3/8" 68# K-55 Conductor Analysis and Cementing Program The conductor for Lone Creek #4 will be installed by drilling/driving the 13-3/8" pipe to 80'SS/95' RKB. Joints will welded together and a drilling shoe will be welded to the bottom joint. No cementing is required. 9-5/8" 36# J-55 LTC Surface Casing Analysis and Cementing Program The 9-5/8" surface casing will be cemented from the proposed setting depth of 750' to surface with an accelerated 15.8 ppg Class "G" cement system. Capacities: 9-5/8" Csg. Capacity =.0773 bbl/ft 9-5/8" Csg X 13-3/8" Conductor Capacity=0.0597 bbl/ft 9-5/8" Csg. x 12-1/4" OH Capacity= .0558 bbl/ft System Volume: 9-5/8" X 13-3/8" Annulus: 80 X 0.0597= 4.8 bbl 12-1/4" OH x 9-5/8" Csg: (750'-80) x.0558 bbl/ft x 2 (100 % excess) = 74.8 bbls Shoe Jt: 47' x .0773 bbl/ft = 3.6 bbls Actual volumes to be re -calculated at time of running casing due to potential variation in actual depth from planned. Cement System Weight (ppg) bbl cf sx Accelerated Class G 15.8 83.2 467 399 Yield 1.17 cf/sx Please see attached 9-5/8" surface casing analysis and specifications. 5-1/2" 15.5# K-55 BTC Production Casing Cementing Program The 5-1/2" production casing will be cemented in fully from the proposed set depth of 3,285' to surface. A 13.5 ppg lead "G" cement followed with a 15.8 ppg "G" tail cement system will be used. (The top of the 15.8 ppg may be adjusted upward following the logging program, dependent upon the location of upper most potential pay). This program is designed to insure the intended perforating / production intervals are isolated with 15.8 ppg "G" cement. Capacities: 5-'/2" 15.5# csg capacity = .0238 bbl/ft 5-'/i' 15.5# csg X 7-7/8" OH capacity =.0309 bbl/ft Prepared by Jack McDade, Rev Ed Jones Page 7 of 12 Rev. 1.2 Aurora Gas, Ile Creek #4 Drilling Program 5-'/2" 15.5# csg X 9-5/8" 36# annular capacity = .0479 bbl/ft Lead System: 9-5/8" x 5-'/2"Csg: 750' + 250' 12-1/4" open hole 750' x .0479 bbls/ft x 1 (0% excess) = 35.9 bbls Lead Cement Volume = 35.9 bbl+250' X .0309 X 1.25=43.65 bbl Tail System: 7-7/8" OH x 5-1/2 Csg: 3,285'-900'=2,385' 2,385' x .0309 bbl/ft x 1.25(25% excess) =92.1 bbls Shoe Joint: 85'x.0238 bbl/ft = 2.0 Total Tail Cement Volume = 94.1 bbls Actual volumes will be calculated at time of running casing due to potential variation in depth from planned. Cement System tem Tyye Cement Weight ppg) bbl cf sx Lead @ 1.83 cf/sx G 13.5 43.65 245 134 Tail @ 1.17 cf/sx G 15.8 94.1 528 452 Please see attached 51/2" production casing analysis and specifications. Pressure Calculations Maximum Anticipated Surface Pressure From offset wells in the immediate area and actual pressure data from the nearby offset well Lone Creek #3, maximum anticipated bottom -hole pressures should not exceed 1,785 psi at 3,500 ft. Pressures measured at the Lone Creek #3 well indicated a gradient of —.59 psi/ft with a bottom -hole pressure of 1,361 psi recorded at 2,315'. Maximum anticipated surface pressures "MASP" can be calculated by subtracting the gas gradient of .l psi/ft from pore pressure gradient of .59 psi / ft and multiplying by the total TVD depth. Maximum Anticipated Surface Pressure = (.59 - .1) * 3,100' =1,519 psi A formation integrity test to 16.0 ppg EMW @ 620' was conducted while drilling Lone Creek #3. Assuming casing shoe strength of 16.0 ppg EMW (or .832 psi/ft) our estimated Maximum Allowable Surface Pressure during the 8-1/2" interval is expected to be Maximum Allowable Surface Pressure = (.832-.1)*750'=549 psi Drilling Hazards Shallow gas Shallow gas is a known hazard which exists throughout the area. The northwest side of Cook Inlet is noteworthy for its shallow gas hazard. All responsible personnel will be made aware and a notice of such hazards will be posted in the rig doghouse. There is no record of H2S in the region, however; a gas detection system capable of detecting H2S as well as methane will be installed on the rig with detectors at the floor level, the shale shaker and in the cellar. Prepared by Jack McDade, Rev Ed Jones Page 8 of 12 Rev. 1.2 Aurora Gas, • lane Creek #4 Drilling Program Coal Seams The Cook Inlet region is rich in coal seams, inter -bedded between the sands, gravels and shales that make up the Beluga and Tyonek formations. Drilling into a coal seam will appear to be a drilling break when drilled with a tri -cone bit. The major hazard of drilling into a coal seam without observing the proper response is the risk of stuck pipe. The proper course of action for preventing stuck pipe is two -fold. First, prior to drilling, insure the drilling fluid system is up to par, per recommendations from the on-site mud engineer. The second step to successfully drilling through coals in the Cook Inlet area is to not get greedy when coals are encountered. When a coal has been encountered, pull back above coal after drilling into it, and circulate, allowing the coal to stabilize. Re-enter, drill some more, and pull back out again. Continue in this fashion until successfully through the coal bed. The key word in successfully drilling the coal beds is patience. It should be remembered that coals behave plastically, and will flow under the weight of the overburden. The deeper the coal, the more pronounced this tendency becomes. For this reason it is critical to maintain the proper weight and viscosity of the drilling fluid to properly remove the coal cuttings, and to hold flowing coals in place. Again, heed the recommended drilling fluid program and advice offered by the on-site Mud Engineer. Well Proximity Risk There is no close approach risk associated with drilling Lone Creek #4. The nearest well activity lays 2/3 of a mile SSW on the Lone Creek #3 drillsite. Other Risks Sticky bentonitic clays, boulders, lost returns & differential sticking with overbalanced muds and gas influx while cementing or swabbing while tripping pipe. Prepared by Jack McDade, Rev Ed Jones Page 9 of 12 Rev. 1.2 • Aurora Gas, Aurora Gas, LLC Lone Creek #4 Proposed Configuration Drill 12-1/4" Hole to 750' 2-7/8" x 5-'h" annulus to be displaced over to inhibited packer fluid through sleeve @1445' Beluga Tops Tsuga 2-8— 924'MD 886' TVD Not likely tested initially Tyonek Tops Carya 2-1.0 — 1,514' MD 1,329' TVD Carya 24.0 —2,325' MD 2,145' TVD Carya 24.2 — 2,486' MD 2,306' TVD Carya 2-5.2 — 2,899' MD 2,719' TVD Carya 2-6.0 — 3,100' MD 2,920' TVD Carya 2- Tyonek Perforation Intervals to be determined by open -hole logging. Carya 2- Carya 24, Carya 2-5, Carya 2-6 Drill 7 5/8" Hole to 3,285' Estimated PBTD (0, 3,205' One Creek #4 Drilling Program 7/8 6S# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor to be drilled to 80' 1-5/8" 36# Surface Casing set at 750' :ement w/15.8 ppg Gas -Block enhanced Sliding Sleeve @ — 1445' drauHc Set Packer @ 1,475' Sliding Sleeve @ —1,525' antic Set Packer @ 2,200' Sliding Sleeve @ 2,700' MD Z 7/8" 6.5# EUE 8rd Tubing w/ Seal Assembly to Retrievable Seal Bore Packer @ 2,850'MD w/ 231 profile Drill 7-7/8" Hole to 3,285' 15.5# K-55 Casing to 3,285' MD 3,100' 1) Prepared by Jack McDade, Rev Ed Jones Page 10 of 12 Rev. 1.2 Aurora Gas, 500 1,00( 1,50( Measur 2,00( 2,501 3,00 3, 50! 4,00 F - -I L J Lone Creek #4 Days vs Depth 5 10 15 20 One Creek #4 Drilling Program 25 30 Days Prepared by Jack McDade, Rev Ed Jones Page 11 of 12 Rev. 1.2 Drill 12-1/4" Interva� ! Rttn 9-5/8 C ing d depth I i Drill? -7/8 terval ! Log Well, Ru 5-1/2 Casi g, Perforat� T st, I ! ' I Days Prepared by Jack McDade, Rev Ed Jones Page 11 of 12 Rev. 1.2 Aurora Gas, 0 Lone Creek Unit #4 se Creek #4 Drilling Program Summary of Drilling Hazards POST THIS NOTICE IN DOGHOUSE � There is potential for abnormal pressured shallow gas. There is potential for stuck pipe in coals encountered while drilling from surface to TD. Short trips as dictated by drilling trends. � There is no H2S risk anticipated for this well. Due to potential for shallow gas kick, very little response time will be afforded to respond. PVT and gas detection systems must be fully operational and functioning at all times, visual flow checks and pit level monitoring are critical. CONSULT THE LONE CREEK #4 WELL PLAN FOR ADDITIONAL INFORMATION Prepared by Jack McDade, Rev Ed Jones Page 12 of 12 Rev. 1.2 �4urora Gas, LLC www.aurorapower.com Tom Maunder, Senior Petroleum Engineer State of Alaska Oil and Gas Conservation Commission 333 W. 7fl` Avenue, Suite 100 Anchorage, AK 99501 Re: Revised Permit to Drill No. 207-091. Lone Creek #4 Development Gas Well Dear Mr. Maunder: October 1, 2008 Pursuant to 11 AAC 25.015 (a) (1), Aurora Gas, LLC (Aurora) hereby requests approval to allow the drilling, perforating, completing, testing and production of the Lone Creek #4 development gas well at a location approximately 29 feet northwest of the originally permitted location in the Lone Creek Unit on the west 'side of the Cook Inlet. Attached is a revised plat depicting the location of this proposed well. The Lone Creek #4 development gas well was originally approved by the AOGCC on October 11, 2007, Permit to Drill No. 207-091 (PTD). A spacing Exception was granted on September 13, 2007 as the bottom -hole location of the well was within 3,000 feet of the Lone Creek #3 producing well. Although the surface location has moved approximately 29 feet, the location of the top of productive horizon and bottom -hole location has not moved. Therefore, additional spacing exception authorizations are not necessary. Subsequent to the originally approved Permit to Drill, Aurora has determined the well pad would be constructed much easier in a nearby location to avoid undesirable topography and still remain over the formation's structural high. Additionally, Aurora has revised the original casing plan and intends on installing 9-5/8" casing with a 12-1/4" hole, instead of the previously approved 8-5/8" casing and 10-5/8" hole. With this modification, Aurora hereby requests a variance to allow a 12" diverter line in accordance with 20 -� AAC 25.035 (h)(2). Attached is the revised PTD, copy of the previously approved PTD, a revised plat, and the revised casing properties and drilling curve. Should questions arise in connection with this request, please contact me at the Anchorage telephone number below. Sincerely, -ZefQ�) (,j Bruce D. Webb Manager, Land and Regulatory Affairs attachments 10333 Richmond Avenue, Suite 710 • Houston, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 TRANSMITTAL LETTER CHECKLIST WELL NAME' PTD# Z �� _v11 Development Service Exploratory Stratigraphic Test Non -Conventional Well FIELD: lune dp_e�4 POOL: CIS='k (�C�d ��/ �4-S Circle Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER 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 fu mpliance with 20 AAC EXCEPTION 25.055. Approval to perforate an roduce insect is contingent / upon issuance f a consery do proving a spacing V/ exception. farce S , �� 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 caught and 10' sample tervals through target zones. N� / Non -Conventional Please note the following s119cial condition of this permit: Well production or production testing of coal bed methane is not allowed 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 Name) must contact the Commission to obtain advance approval of such water well testing program. rn„ l� Rev: 1/11/2008 �Q �y Q . PTD#: 2070910 Com Administration 11 Appr Date TEM 11/7/2008 00"'M 26 27 28 29 U Field D GAS - 505500 Initial Well Name: LONE CREEK 4 Program DEV Well bore seg ❑ ;ND GeoArea 820 Unit 51260 On/Off Shore On Annular Disposal ❑ Permitfee attached--------------------------------------------- 10 Permit can be issued w/o hydrogen sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 11 Appr Date 12 Uniquewellnameandnumber-------------------------------------- 13 SFD 10/7/2008 Well located in_a_defined_pool---------------------------------------- o_ _ _ _ _ 14 Well located proper distance from drilling unit _boundary ------------------------- 15 - _ _ >3000' from boundary of the Moquawkie Unit. _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ 16 No_ _ - - _ 17 Engineering 18 _ _ - Will be only well open to the pool in Section 8. -The only other_well in_the section is Chujt 2, P&A'd in 1962. _ - - _ - 19 Appr Date TEM 11/7/2008 00"'M 26 27 28 29 U Field D GAS - 505500 Initial Well Name: LONE CREEK 4 Program DEV Well bore seg ❑ ;ND GeoArea 820 Unit 51260 On/Off Shore On Annular Disposal ❑ Permitfee attached--------------------------------------------- NA --------------------------------------------------------------------------- Permit can be issued w/o hydrogen sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ leasenumberappropriate----------------------------------------- Yes ------- CIRllease_C-Oe1395------------------------------------------------------- Uniquewellnameandnumber-------------------------------------- Yes--------------------------------------------------------------------------- _ _ _ _ _ _ _ _ Yes _ _ _ Well located in_a_defined_pool---------------------------------------- o_ _ _ _ _ _ _ - LONE CREEK, UNDEFINED GAS_- 505500_ - - _ _ _ _ _ _ _ _ _ _ _ - - - - - _ _ _ _ _ _ _ - - _ - - _ _ _ _ _ _ _ - - _ - Well located proper distance from drilling unit _boundary ------------------------- es _ _ - - - _ _ >3000' from boundary of the Moquawkie Unit. _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ Welllocated proper distance from other wells_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ _ - - _ _ _ _ SPACING EXCEPTION APPROVED BY CO 590: shallowest perf_in LC #3 is 2933' from TD of_LC_#4- _ _ _ _ _ _ _ Sufficient acreage_available in_drilling unit_ _ _ _ Yes _ _ _ _ _ _ - Will be only well open to the pool in Section 8. -The only other_well in_the section is Chujt 2, P&A'd in 1962. _ - - _ - If_devisted, is_wellbore plat -included _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ _ _ _ _ - _ _ Piottedwell course -in AOGCC's Geographix workstation; checked lease # on commercial land plat -from MapMake Operator only affected party ---------------------------------------- Yes ------- Aurora was designated operator ofthe MoquawkieUnit inFeb 2003.____________---___________-_ Operator has -appropriate bond in force _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ - _ _ _ _ _ Aurora became -100% WIO for the -unit in_Q4_of 2006. - _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ - _ _ - _ _ _ _ _ Permit can be issued without conservation order_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _No_ _ _ _ _ _ _ - SPACING EXCEPTION APPROVED BY COMMISSION_IN CO 590; -remains in effect for this re -issued permit._ - _ Permitcanbeissuedwithoutadministrative_approval------------------------- Yes -------------_------------------------------------------------------------- Canpermit -be approved before l5Aaywait---------- --------------------No---------------------------------------- ----------------------------------- Welllocatedwithin area arid -strata authorized by -Injection Order #(put_IO#in_comments)_(For_ NA____________________________________________________________________________ All wells _within 1/4_mil_e area_of review identified (For service well only) _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ - - - - - - - _ _ _ _ _ _ _ _ - _ - - _ - _ _ _ _ _ _ _ _ _ - - - - - - - - - - _ - - - Pre -produced injector. duration -of pre -production less than 3months- (Forservicewell only) NA ___________________________________________________________________________ Nonconven,gas_conformstoAS31.Q5030(j.1_.A).0-.2.A-D)------ NA---------------------------------- ------------------------------------------ Conductorstring- provided ----------------------------------------- Yes --------------------------------------------------------------------------- Swface casing -protects all -known USOWs _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - _ _ _ _ _ Surface and -production casings will protect any FW sands. -Based on_ area drilling, gas could be present at- _ _ _ _ CMT v_ol_ adequate_ to circulate_on conductor & surf csg _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ _ _ or near the surface casing shoe. - - - - _ _ _ _ _ _ _ _ _ _ _ - - - _ - _ _ _ _ _ _ _ _ - - - - _ _ _ _ _ _ _ _ _ - _ _ - _ _ CMTv_oladequaWtotie-inlongstringtosurfcsg---------------------------- Yes --------------------------------------------------------------------------- -C.MT will coverall known_productivehorizons ------------------------------ Yes --------------------_------------------------------------------------------ Casingdesigns adequate for CJ, B&_permafrost--------------------------- Yes--------------------------------------------------------------------------- Adequate tankage_or reserve pit _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ - - _ - _ Rig is- eqpipped with steel -pits. _Although relatively small, Aurora has successfully drilled similar wells _ _ _ _ _ - - _ If -a_ re -drill, has_a 10-403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA- - _ _ _ _ _ _ _ - using the -rig. Liquid drilling waste to Aspen disposal well. _Solids to be washed and_used on roads. _ - - _ _ _ _ Adsquatewellboreseparation_proposed------------------ -------- - - - - -- Yes--- ------------------------------------------------------------------------ Ifdjverter required, doesitmeetregulations--------------------------- - - -- Yes--- ------------------------------------------------------------------------ Drilling fluid program schematic & equip list adequate_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ - _ Maximum expected formation pressure 11.3 EMW.- Planned MW up to 12.0 ppg. _Spud mud minimum of_11.5_ppg _ BOPEs,-do Ahey meet regulation - - - -- ------------------------ - - - - -- Yes--- ------------------------------------------------------------------------ BOPE_press rating appropriate; test to_(put psig in comments)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ - MASP calculated at 1519 psi, 3000 -psi -BOP testplanned. _ _ _ _ - - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ - _ _ _ _ _ _ _ Choke- manifold compliesWAR RP-53(May 84)---------------------------- Yes--- ------------------------------------------------------------------------ Workwilloccurwithoutoperaiionshutdown------------------------------ - Yes--- ------------------------------------------- ----------------------- - - - - -- IspresenceofH2Sgas probable------------------------------------- No---- ------------------------------------------------------------------------ -Mechanical-condition of wells within AOR verified (For service well only) _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ - _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ - - - - - - - - - Geology 35 Permit can be issued w/o hydrogen sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ - _ _ _ _ _ H2S has -not been encountered in this area or portion of the -geologic section, but the rig will have sensors. _ _ _ - _ 36 Data -presented on potential overpressure zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ - Expected pressure gradientis 11.4 ppg-EMW.- Will- be drilled with up to_120_ppg mud._ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ Appr Date 37 Seismic_analysis of shallow gas -zones ---------------------------------- NA _ _ - - _ - _ However, shallow gas is_a known hazard in this area. Mudloggers with gas_ monitoring equipment MUST be _ _ _ _ SFD 10/7/2008 38 Seabed condition survey -(if off -shore _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ - _ _ _ _ _ operational from base of conductor to -Ta. Shaltow_gas and -noted in Summary of Drilling Hazards._ _ _ _ _ _ _ _ _ _ 39 Contact name/phone for weekly_ progress reports [exploratory only] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ _ _ - - Dry samples NOT required because_ 3 wells within 1/2 mile obtained cuttings samples across this same interval._ _ Geologic Engineering Public Re -issue of permit 207-190 required because of minor (29') change in surface location. All other aspects of the original well Commissioner: Date: Commissioner: Date C ner Date plan remain the same. Because this location change is relatively inconsequential, the spacing exception approved by CO 590 lowest perf DTS �� 7��� fit "Q '1 remains effective for this well. CO 590 was necessary because the TD of this well is —2900' from the #3. GAS D TECTION, PVT & MUDLOGGING EQUIPMENT MUST E OPERATIONAL PRIOR TO DRILshaILING BE OWLC CONDUCTOR PIPE. 0 a Q ALASKA SARAH PALIN, GOVERNOR L1V/A HAMA OIL AND ( LS333 W. 7th AVENUE, SUITE 100 CONSERVAWON COMMISSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 J. Edward Jones FAX (907) 276-7542 Executive Vice President of Operations and Engineering Aurora Gas, LLC 1400 West Benson Blvd, Suite 410 Anchorage, Alaska 99503 Re: Lone Creek #4 Aurora Gas, LLC Permit No: 207-091 Surface Location: 140 FWL, 1193' FSL, SEC. 8, T12N, R11W, SM Bottomhole Location: 341' FEL, 1060' FSL, SEC. 7, T12N, R11W, SM Dear Mr. Jones: Enclosed is the approved application for permit to drill the above referenced development well. Because of the potential for encountering shallow gas -bearing sands, gas detection, PVT, and mud logging equipment must be fully operational prior to drilling out of the surface conductor pipe. This permit to drill does not exempt you from obtaining additional permits or approvals 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. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659-3607 (pager). STATE OF ALASKA ALAS OIL AND GAS CONSERVATION COM ION PERMIT TO DRILL 70 Aar 9A nn - RECEIVED $ - s .JUN 2 9 2007 1a. Type of Work: 1b. Current Well Class: Exploratory ❑ Development Oil ❑ 1c. Specify if well is p Drill ❑ Redrill ❑ tigraphic Test ❑ Service ❑ Development Gas jQ Coalbed Methane ❑ G&AWAW ❑ Re-entry ❑ Multiple Zone ❑ Single Zone ❑ Shale Gas ❑ 2. Operator Name: 5. Bond:B anket, 4/ Single Wel 11. Well Name and Number: Aurora Gas, LLC Bond No. *e S ` 6 one Creek No. 4 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 1400 West Benson Blvd, Suite 410, chorage AK, 99503 MD: 3,285 TVD: 3,100 Lone Creek Field 4a. Location of Well (Governmental ion): 7. Property Designation: 11W, SM Surface: 140' FWL, 1,193' FSL, Sec.\T12 C-061395 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 107' FWL, 1,184' FSL, Sec. R1 1W, SM WA 9/15/2007 9. Acres in Property: 14. Distance to Nearest,- " 3oa Total Depth: 341' FEL, 1,060' FSL, Sec.11W, SM 640 Property: 1404 , 6u 4b. Location of Well (State Base Plane Coordinate 10, KB Elevation 15. Dist nce to Nearest Well Surface: x- 273751 y- 2611286 Zone- 4 (Height above GL): 16' feet Within Pool: 3,152' 16. Deviated wells: Kickoff depth: 770 feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: X41 degrees Downhole: 1,829 psi Surface: 1,519 psi 18. Casing Program: Specifications X Top - Setting Depth - I Cement Quantity, c.f. or sacks Hole Casing Weight Grade Couplingj k Length MD TVD MD TVD (including stage data) Drilled 13-3/8" 72# K-55 BW 80' 16' 16' 96' 96' N/A 10.625 8-5/8" 32# J-55 LTC X34 16' 16' 750' 750' 223 sx 7.875 5-1/2" 15.5# K-55 LTC 3X9 16' 16' 3 285 3100 541 sx 19. PRESENT WELL CONDITION SUMMARY (To pleted 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 Sine Cement Volume MD TVD Conductor/Structural Surface all 0 Intermediate Production Liner Perforation Depth MD (ft): 10 rZ Perforation Depth (ft): 20. Attachments: Filing Fee , , BOP Sketch ❑ Drilling Program (] ime v. Depth Plot I] Shallow Hazard Analysis E3Property Plat [] Diverter Sketch ❑ Seabed Report ElDril Fluid Program I] 20 AAC 25.050 requirements E] 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct. Contact Printed Name J. Edward Jones Title Exec. Vice Presiden ngineering and Operations Signature Phone 713-977-5799 Date June 20. 2007 Commission Use Only Permit to D II - � API Number- ^7 / D �d '06) Permit Approval See cover letter for other Number 50- ,S-3' Date: requirements. Conditions of approval: If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas by Nes, or gas contained in shales: Other. Samples req'd: Yes[-] Nou?", Mud log req'd: Yesp" No❑ At HZS measures: Yes❑ No[K Dire nal svy req'd: Yes[. No❑ PROVED THE COMMISSION DATE: ,i� COMMISSIONER Form 10-401 Revised 12/2005 ORIGINAL Submit in Duplicate 01 arJ. A 4urrora Gas, L?C www.aurorapower.com June 20, 2007 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7h Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Permit to Drill: Lone Creek No. 4 Dear Mr. Norman: RECEIVED JUN 2 9 2007 Alaska nil & Gas Cons. Commission Anchorage Aurora Gas, LLC hereby applies for a Permit to Drill an onshore gas development well in the Lone Creek Field about 2 miles NNE of the Lone Creek #1 Production Facility. The well is planned as a directional well targeting the Upper Tyonek Formation out of the drainage radius of Lone Creek #3. A secondary target is the shallower Beluga Tsuga 2-8 Formation. The rig to be used is the AWS #1. The rig's well control systems are on file with the Commission. Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill. 2) Fee of $100.00 payable to the State of Alaska. 3) A plat showing the surface location of the well. 4) A Time versus Depth plot. 5) Proposed casing program. 6) Proposed cementing program. 7) Proposed drilling fluid program. 8) Proposed summary drilling program. 9) Summary of Drilling Hazards. 10) Schematic of the proposed wellbore and completion. 11) Aurora Gas does not anticipate the presence of H2S in the formation to be encountered in this well. However, H2S monitoring equipment will be functioning on the rig at all times during drilling and completion operations. 12) The following are Aurora Gas' designated contacts for reporting responsibilities to the Commission: 2500 Citywest Blvd., Suite 2500 • Houston, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 Mr. John Norman Page 2 1) Completion Report (20 AAC 25.070) 2) Geologic Data and Logs (20 AAC 25.071) • Ed Jones, EVP- Engineering & Ops. (713) 977-5799 Andy Clifford, EVP - Exploration (713) 977-5799 If you have any questions or require additional information, please contact me at (713) 977-5799 or Jack McDade at (907) 351-0865. Sincerely, AURORA GAS, LLC �F I. ward Jones ecutive Vice President Engineering and Operations enclosures cc: Bruce Webb — Aurora Gas STATE OF ALASKA ALANA OIL AND GAS CONSERVATION COMMINON PERMIT TO DRILL 20 AAC 25.005 RECEIVED JtiN! 2 0 2007 I=, 0M & Gas Cons. Comm ssiot 1a. Type of Work: Drill R,Redrill ❑ Re-entry ❑ 1b. Current Well Class: Exploratory ❑ Stratigraphic Test E3 Service C] Multiple Zone ❑ Development Oil ❑ Development Gas Q Single Zone ❑ 1c. Specify if well is proposed for: Coalbed Methane ❑ Gas y' ra eslgb )qs Shale Gas ❑ 2. Operator Name: Aurora Gas, LLC 5. Bond:BI nket Q Single Well ❑ Bond No. 2� 11. Well Name and Number. Lone Creek No. 4 3. Address: 1400 West Benson Blvd, Suite 410, Anchorage AK, 99503 6. Proposed Depth: -ZIP-07 MD: 3,285 TVD: 3,100 12. Field/Pool(s): Lone Creek Field 4a. Location of Well (Governmental Section): Surface: 140' FWL, 1,193' FSL, Sec. 8, T12N, R11W, SM Top of Productive Horizon: 10T FWL, 1,184' FSL, Sec. 8, T12N, R11W, SM Total Depth: 341' FEL, 1,060' FSL, Sec. 7, T12N, R11W, SM 7. Property Designation: C-061395 8. Land Use Permit: N/A 13. Approximate Spud Date: 9/15/2007 9. Acres in Property: 640 14. Distance to Nearest +-1r/3 Pr rty: Ns 4b. Location of Well (State Base Plane Coordinates): Surface: x- 273751 y- 2611286 Zone- 4 10. KB Elevation (Height above GL): 16' i feet 15. D ance to Nearest Well Within Pool: 3,152' 16. Deviated wells: Kickoff depth: 770 feet Maximum Hole Angle: 41 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 1,829 psi +' Surface: 1,519 psi r 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Drilled 13-3/8" 72# K-55 BW 80' 16' 16' 96' - 96' N/A 10.625 8-5/8" 32# J-55 LTC 734 16' 16' 750' - 750' - 223 sx 7.875 5-1/2" 15.5# K-55 LTC 3,269 16' 16' 3 285 - 3100- 541 sx 19. 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 Q BOP Sketch ❑ Drilling Program Q Time v. Depth Plot Q Shallow Hazard Analysis ❑ Property Plat Q Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct. Printed Name J. Edward Jones Signature Date Contact Title Exec. Vice President -Engineering and Operations Phone 713-977-5799 Date June 20. 2007 Commission Use Only Permit to Drill Number: ✓�? fig% API Number. 50 ,28 -26 Permit Approval 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:C�rl- Other. Samples req'd: Yes[-] Nog?r Mud log req'd: Yes[" No❑ HZS measures: Yes[-] No[V Directional svy req'd: Yes[r No[:] APPROVED BY THE COMMISSION DATE: , COMMISSIONER Form 10-401 Revised 12/2005 Submit in Duplicate -Aurora • Gas, LLC www.aurorapower. com June 20, 2007 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 70' Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Permit to Drill: Lone Creek No. 4 Dear Mr. Norman: DECEIVED JUN 2 0 2007 Alaska Oil & Gas Cons. Commission Anchorage Aurora Gas, LLC hereby applies for a Permit to Drill an onshore gas development well in the Lone Creek Field about 2 miles NNE of the Lone Creek #1 Production Facility. The well is planned as a directional well targeting the Upper Tyonek Formation out of the drainage radius of Lone Creek #3. A secondary target is the shallower Beluga Tsuga 2-8 f Formation. The rig to be used is the AWS #1. The rig's well control systems are on file with the Commission. Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10401 Application for Permit to Drill. 2) Fee of $100.00 payable to the State of Alaska. 3) A plat showing the surface location of the well. 4) A Time versus Depth plot. 5) Proposed casing program. 6) Proposed cementing program. 7) Proposed drilling fluid program. 8) Proposed summary drilling program. 9) Summary of Drilling Hazards. 10) Schematic of the proposed wellbore and completion. 11) Aurora Gas does not anticipate the presence of H2S in the formation to be encountered in this well. However, H2S monitoring equipment will be functioning on the rig at all times during drilling and completion operations. 12) The following are Aurora Gas' designated contacts for reporting responsibilities to the Commission: 2500 Citywest Blvd., Suite 2500 • Houston, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 0 Mr. John Norman Page 2 1) Completion Report (20 AAC 25.070) 2) Geologic Data and Logs (20 AAC 25.071) E Ed Jones, EVP- Engineering & Ops. (713) 977-5799 Andy Clifford, EVP - Exploration (713)977-5799 If you have any questions or require additional information, please contact me at (713) 977-5799 or Jack McDade at (907) 351-0865. Sincerely, AURORA GAS, LLC J. Edward Jones Executive Vice President Engineering and Operations enclosures cc: Bruce Webb — Aurora Gas F , SCA Grid M AS -STAKED SURFACE LOCATION DIAGRAM p NOR SURVEYING - MAPPING rv' s v° �. 4e APPLICANT: �J �Ilt ♦ OF Akgs1 FAX: (907)283 �265 WWW.MCLANECG.COM CO mLi ing Inc 140' FWL TH* "9* �49j 00 DATE: JUNE 11, 07 00 00 00 j �� M. SCOTT McLANE.- l 04I 4928—S'� �ESSIosxv' ♦,; �.�.►.a 1.i1r GRID N:2610096.260 GRID E:273592.570 LATITUDE: 61'08'16.647"N LONGITUDE: 151 ° 16'51.967"W SEC 71 SEC 181 NOTES 1) BASIS OF COORDINATES IS ALASKA STATI PLANE NAD 27 ZONE 4 FROM A DIRECT TIE TO ADL NO. 31270. 2) BASIS OF ELEVATION IS FROM TIDAL OBSERVATION ON 9-22-93. DATUM IS MLLW. ALL ELEVATIONS SHOWN HEREON WERE TAKEN ON GROUND. 3) SECTION LINES SHOWN HEREON ARE BASED ON PROTRACTED VALUES. F SEC. . l i } AS -STAKED PAD SEC 17 LONE CREEK NO.4 WELL ENGINEERING -TESTING AS -STAKED SURFACE LOCATION DIAGRAM SURVEYING - MAPPING P.O. BOX 468 APPLICANT: �J SOLDOTNA, AK. 99669 VOICE: (907) 283-4218 FAX: (907)283 �265 WWW.MCLANECG.COM CO mLi ing Inc --` Aurora Gas, L L C PROJECT NO. I DRAWN BY: 073057 JZW DATE: JUNE 11, 07 SEC. LINE LOCATION: OFFSETS: PROTRACTED SECTION 8 1193' FSL TOWNSHIP 12 NORTH, RANGE 11 WEST 140' FWL SEWARD MERIDIAN, ALASKA Aurora Gas, 0 Lone Creek #4 Sue Creek #4 Drilling Program Lone Creek #4 is a grass-roots well targeting Beluga & Tyonek Gas Production. It is located in the Lone Creek Gas Field 3,150' NNE of the Lone Creek #3 wells. Lone Creek #4 will target Upper Tyonek Carya 2-1 thru 2-6 sands with possible future production from Beluga Tsuga 2-8 sands. A spacing exemption will be required due to the r proximity to Lone Creek #3. Pre Rig work 1. Stake & survey the Lone Creek Site. 2. Construct a 200' x 300' pad configured for AWS #1 with drilling support. Build sufficient cuttings containment for planned drilling program. 3. Install 13-3/8" conductor to 80' below ground level. Install cellar & mousehole. Cut off conductor as needed to accommodate diverter system. Drilling Procedure 1. File & insure all necessary permits and applications are in place. 2. MIRU AWS #1 in drilling configuration. 13-3/8" conductor has been pre-installed. Install 13-5/8" VG LOK head. 3. Rig up diverter & mud loggers" Test & calibrate all PVT / gas sensor equipment. Provide 24 -hr notice to AOGCC inspectors for chance to witness diverter test. 4. Notify AOGCC & pertinent agencies when ready to start drilling operations. 5. Prepare spud mud system / weight up to —9.5 ppg. Load, strap & drift 750' off 8-5/8" surface casing. 6. PU 10-5/8" mill tooth bit & drill to —750', using 6-1/4" stabilized BHA. Watch for gas in shallow coals and sands. Attempt to TD in siltstone or claystone, avoid setting surface shoe in a coal bed or sand. If possible, adjust TD to put cement head at floor. 7. Condition hole for running 8-5/8" surface casing, POOH, LD 10-5/8" BHA. 8. Run & cement new 8-5/8" 32 #, J-55 LTC casing @ 750', installing 1 centralizer / joint centered on the 1St 4 joints above shoe, & 1 centralizer every 2nd joint across the collars there after. Shoe joint connection at float shoe and float collar must be Baker -Locked. Cementing will be single stage using 14.5 ppg gas -block enhanced Type I cement at 100% excess volume. Be prepared to treat cement returns with retarder. 9. RD cementers, nipple down diverter, cut casing and install 11" 3M wellhead. Prepared by Jack McDade Page 1 of 11 Rev. 1.0 (Draft) Aurora Gas, • We Creek #4 Drilling Program 10. RU and test 11" 3M BOP stack and 5M choke manifold. Test stack and surface equipment to 3,000 psi. Pressure test 8-5/8" casing to 1,500 psi for 15 minutes or as required on approved Permit to Drill. 11. PU 7-7/8" Mill Tooth Bit & RIH w/ 6-%" collars. Drill out shoetrack. Condition / treat mud as needed for cement contamination, drill 20' new formation. Pull back into shoe & perform FIT / LOT to 16.0 ppg EMW with low volume test pump. Record results. POH & LD 6-1/4" collars. A 12. PU 4-3/" directional drilling assembly w/ 7-7/8" bit, motor & DIR MWD assembly, non - mag DC's, jars & HWDP as specified by directional hand. 13. RIH and directionally drill 7-7/8" hole to 3,285' MD (3,100' TVD) TD per directional plan, or other as directed by Aurora Gas geologist. Increase MW to 11.0 prior to reaching 900'. Monitor well and volumes carefully. Be prepared to shut well in and weight up immediately if flow or excessive gas build up in mud is noticed. Monitor hole cleaning and drilling trends, prepare to short trip if needed. Anticipated mud weights required are 11.0 ppg — 12.0 ppg. Do not exceed fracture gradient determined in step 11. If possible, adjust TD to put cement head on floor. While drilling, load, tally & drift 5-1/2" casing on racks. 14. Condition hole, short trip and prepare for running wireline logs. 15. POOH, rack back drillstring and RU wireline BOP'S and lubricator and logging tools. Log 8-5/8" cased hole section w/gamma ray sensor, Loi OH section with logging suite including resistivity and porosity logs as directed by Aurora Gas. RD wireline. 16. RIH w/ 7-7/8" drilling assembly to TD & condition hole for running 5-1/2" casing. Ensure cementing head has proper connections or proper cross-over and is available for quick rig UP. 17. POOH while laying down drillpipe & BHA, RU to run casing. Verify cementer's equipment is read . y 18. Install 5-!/2" pipe rams. %�14 19. Run 5-1/2" 15.5# LTC K-55 casing installing 1 centralizer per joint centered on 1St 4 joints above shoe, 1 centralizer every 2nd joint in open hole & every 3rd joint inside surface casing. Shoe joint connection at float shoe, float collar & stage tool landing collar must be Baker -Locked (80'shoetrack). While running casing, fill every 3rd joint. Be prepared to wash to bottom. 20. RU cementers, cement per attached cementing program from TD to surface. A sufficient amount of 13.5 ppg Class G lead cement will be pumped to cover the annulus from the 8- 5/8" shoe to surface. This will be followed by sufficient amount of 15.8 ppg Class G tail cement to cover from TD back to the 8-5/8" shoe. Excess will be calculated using caliper log data. Plug will be bumped with clean brine. If possible reciprocate pipe while displacing cement. Land casing & WOC. 21. RD cementers, nipple down stack, land casing in slips & cut casing. Prepared by Jack McDade Page 2 of 11 Rev. 1.0 (Draft) Aurora Gas, Que Creek #4 Drilling Program 22. Install 11" X 7-1/16" tubing spool, 7-1/16" X 11" DSA, mud cross and reinstall BOP stack. Pressure test BOP and surface equipment to 3,000 psi. Pressure test casing to 2,000 psi for 15 minutes and record results. 23. Install 2-7/8" pipe rams. 24. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Displace well w/ filtered KCl/NaCI brine (wt. to be determined from MDT data). Continue to clean brine for perforating by running through centrifuge & filtering. POOH. Strap tubing on TOH to validate tally. 25. PU wireline BOP's & lubricator, pressure test all. PU GR/CBL/CCL & log 5-1/2" casing to surface. LD logging tools & PU perforating guns, RIH to depth as determined from OH logs and perforate zones of interest. Watch for pressures in casing after shooting. POOH, LD perf gun, RD wireline. 26. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Circulate perforating debris from hole. Continue centrifuging & filtering brine until cleaned up. POOH. LD bit & scraper. 27. RU & RIH with test packer assembly on workstring. Connect to surface flow test equipment. RU & swab in well for flow test, record results. Kill well. 28. Repeat step 27 until all zones of interest have been evaluated for production. 29. POOH. Pull slowly to avoid swabbing in well with packer. 30. Pick up & assemble completion assembly which will use retrievable type packers, sand exclusion screens, sliding sleeves and other jewelry as necessary. Exact configuration to be determined by test results. Please see attached proposed completion scenario. Packer is to be 75' minimum above upper -most screen. RIH with completion & set completion at appropriate depth. POOH. 31. RIH with new 2-7/8" 6.5# EUE 8rd production tubing, hydraulic set retrievable packers & seal assembly, space out & stab into packer, hang off in tubing head & lock down. Install blanking plug in profile nipple at bottom of tubing. Pressure up tubing & set packers. Pressure test tubing to 2,000 psi, pull blanking plug. 32. RU & swab in well. After well cleans up perform 4 -point test. Shut in well & record pressure buildup until stabilized with no change in one hour. 33. Install BPV, nipple down & remove BOP stack. Install production tree. Tear down & remove all rig equipment. 34. Clear & clean location. Hand well over to production. 35. File completion reports with proper agencies. Site Access Lone Creel #4 will be accessible via existing gravel roads currently in use to support production operations at the Lone Creek #3 drillsite. Prepared by Jack McDade Page 3 of 11 Rev. 1.0 (Draft) Aurora Gas, • Rig *e Creek #4 Drilling Program Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the Lone Creek #4 well. The Alaska Oil & Gas Conservation Commission has information on this rig and equipment as it has been in use for the last (5) years on other Aurora Gas operations. The pits, BOP system & mud equipment configuration will be the same as that used for previous work. Survey Program The 10-5/8" surface hole will be drilled vertically and the survey program will consist of inclination only single -shot surveys to be obtained at 500' intervals in accordance with rules laid out in 20 AAC 25.050 (a) (1) & (2). The 7 7/8" production hole will be drilled directionally. For all directional work, wellbore surveys will be taken at maximum of 100 ft intervals, per AAC 25.050 (a)(1) with intervals likely to be surveyed more frequent while steering. ✓" Logging Program Mud loggers will be on site for the duration of drilling activities. Schlumberger will provide wireline logging services as proposed below: Lone Creek #4 Proposed Logging Program Well Section Depths(ft) OH CH Lo T e 12-1/4" Surface 0'— 850' N/A: No open -hole logs planned for surface at this time. GR only in cased hole. - 7-7/8" Production Hole 850'— 3,500' 7 Platform Express: Array Induction, Compensated Neutron, Litho -Density, SP, GR, and possibly DSI and/or FMI. Also MDT and Sidewall cores. 5-1/2" Int. Csg 850'— 3,500' GR/CBL/CCL Surface — TD 0' — 3,500' Mud Logging Services BOP Equipment Aurora Gas, LLC will use the same BOP system they have been using for the last (4) years which will consist of the following: 10-5/8" Surface Hole While drilling the 10-5/8" surface hole, a 13-5/8" 5M annular w/ 13-5/8" diverter spool & 12" diverter line will be used as per 20 AAC 25.035 (c)(1)(A) requiring that the diverter line outlet size be at least 16" diameter or (B) at least as large as the hole size being drilled. 7-7/8" Production Hole An 11" 3000 PSI WP Schafco (Shaffer Equivalent) BOP system will be used which is configured with an 11" 3000 PSI WP annular preventer, (1) 3000 PSI WP double gate with a set of pipe rams installed sized to fit the pipe being run and a set of blind rams and (1) 11" 3000 PSI WP rated drilling spool. BOP tests will be performed to 3000 psi. The annular preventer will be Prepared by Jack ?McDade Page 4 of 11 Rev. LU (Draft) Aurora Gas, • ge Creek #4 Drilling Program tested to 1500 psi. Again, this is the same equipment Aurora has been using all along and information on the system is on file at the AOGCC. Drilling Fluids The drilling fluids will be furnished by Baroid Drilling Fluids who has extensive experience with drilling activities in this area. An experienced mud engineer will be on site at all times while drilling to monitor properties and make recommendations. Drilling Fluid Properties While Drilling 10-5/8" interval to 750' Beluga Formation Base Fluid 6% KCL Density 9.5 — 10 ppg PV 22-30 YP 20-30 API Filtrate < 5 Total Solids 15-25% Gel & Polymer mud system Drilling Fluid Properties While Drilling 7-7/8" interval to 3,285' Beluga and Tyonek Formations Base Fluid 6% KCL Density 11.0 — 12.0 ppg PV 22-30 YP 20-30 API Filtrate < 5 Total Solids 10-15% Polymer mud system Drilling Fluid Handling System Shale Shaker, Mud Cleaner, Centrifuge, PVT monitors Drilling Waste Disposal The cuttings will be rockwashed for use on existing roads and pads. Drilling mud will be held in tanks for reuse or injection at the Aspen Disposal Well. Brine will be placed in tanks for use in future wells. Prepared by Jack McDade Page 5 of 11 Rev. 1.0 (Draft) Aurora Gas, 9 *e Creek #4 Drilling Program Casing / Cementing Program All casing is new. Analysis (attached) indicates casing program as designed provides adequate safety factors for this well. All casing strings with the exception of the 13-3/8" conductor will be cemented in place using industry standard casing cementing techniques utilizing a casing shoe, float equipment, top and bottom wiper plugs and centralizers installed as needed. 13-3/8" 72# K-55 Conductor Analysis and Cementing Program The conductor for Lone Creek #4 will be installed by drilling/driving the 13-3/8" pipe to 80'SS/96'RKB. Joints will welded together and a drilling shoe will be welded to the bottom joint. No cementing is required. 8-5/8" 32# J-55 LTC Surface Casing Analysis and Cementing Program The 8-5/8" surface casing will be cemented from the proposed setting depth of 750' to surface with a 14.5 ppg Type I, gas block enhanced cement system. Capacities: 8-5/8" Csg. Capacity =.06094 bbl/ft 8-5/8" Csg. x 10-5/8" OH Capacity --.0374 bbl/ft System Volume: 10-5/8" OH x 8-5/8" Csg: 750'x.0374 bbl/ft x 2 (100 % excess) = 56.1 bbls Shoe Jt: 40' x .06094 bbl/ft = 2.4 bbls Actual volumes to be re -calculated at time of running casing due to potential variation in actual depth from planned. The surface cement system utilizes a Gas -Block type additive to minimize potential for gas entrainment or channeling. Cement S, syy tem Weight (ppZL bbl cf sx Gas -Block enhanced Type I 14.5 58.5 328.2 223 Yield 1.47 cf/sx ��' Please see attached 8-5/8" surface casing analysis and specifications. 5-1/2" 15.5# K-55 LTC Production Casing Cementing Program The 5-1/2" production casing will be cemented in fully from the proposed set depth of 3,200' to surface. A 13.5 ppg lead "G" cement followed with a 15.8 ppg "G" tail cement system will be used. This program is designed to insure the intended perforating / production intervals are isolated with 15.8 ppg "G" cement. Capacities: 5-%2' 15.5# csg capacity = .0238 bbl/ft 5-V2" 15.5# csg X 7-7/8" OH capacity = .0309 bbl/ft Prepared by Jack McDade Page 6 of 11 Rev. 1. (Draft) Aurora Gas, 10 se Creek #4 Drilling Program 5-1/2' 15.5# csg X 8-5/8" 32# annular capacity =.0316 bbl/ft Lead System: 8-5/8" CH x 5-%2'Csg: 750' 750' x .0316 bbls/ft x 1 (0% excess) = 23.7 bbls Lead Cement Volume = 23.7 bbl Tail System: 7-7/8" OH x 5-1/2' Csg: 3,285'-750'=2,535' 2,535'x.0309 bbl/ft x 1.25(25% excess) = 97.9 bbls Shoe Joint: 40' x .0238 bbl/ft = 1 Total Tail Cement Volume = 98.9 bbls Actual volumes will be calculated at time of running casing due to potential variation in depth from planned. Cement System Type Cement Wei _ t (ppg) bbl cf sx Lead @ 1.83 cf/sx G 13.5 23.7 133 72 Tail @ 1.17 cf/sx G 15.8 97.9 549 469 Please see attached 5 1/2" production casing analysis and specifications. Pressure Calculations Maximum Anticipated Surface Pressure From offset wells in the immediate area and actual pressure data from the nearby offset well Lone Creek #3, maximum anticipated bottom -hole pressures should not exceed 1,785 psi at 3,500 ft. Pressures measured at the Lone Creek #3 well indicated a gradient of —.59 psi/ft with a bottom -hole pressure of 1,361 psi recorded at 2,315'. Maximum anticipated surface pressures "MASP" can be calculated by subtracting the gas gradient of .1 psi/ft from pore pressure gradient of .59 psi / ft and multiplying by the total TVD depth. Maximum Anticipated Surface Pressure = (.59 - .1) * 3,100' = 1,519 psi - A formation integrity test to 16.0 ppg EMW @ 620' was conducted while drilling Lone Creek #3. Assuming casing shoe strength of 16.0 ppg EMW (or .832 psi/ft) our estimated Maximum Allowable Surface Pressure during the 8-1/2" interval is expected to be Maximum Allowable Surface Pressure = (.832-.1)*750'=549 psi Drilling Hazards Shallow gas Shallow gas is a known hazard which exists throughout the area. The northwest side of Cook Inlet is noteworthy for its shallow gas hazard. All responsible personnel will be made aware and a notice of such hazards will be posted in the rig doghouse. There is no record of H2S in the region, however; a gas detection system capable of detecting H2S as well as methane will be installed on the rig with detectors at the floor level, the shale shaker and in the cellar. Prepared by Jack McDade Page 7 of 11 Rev. 1.0 (Draft) Aurora Gas, 0 fte Creek #4 Drilling Program Coal Seams The Cook Inlet region is rich in coal seams, inter -bedded between the sands, gravels and shales that make up the Beluga and Tyonek formations. Drilling into a coal seam will appear to be a drilling break when drilled with a tri -cone bit. The major hazard of drilling into a coal seam without observing the proper response is the risk of stuck pipe. The proper course of action for preventing stuck pipe is two -fold. First, prior to drilling, insure the drilling fluid system is up to par, per recommendations from the on-site mud engineer. The second step to successfully drilling through coals in the Cook Inlet area is to not get greedy when coals are encountered. When a coal has been encountered, pull back above coal after drilling into it, and circulate, allowing the coal to stabilize. Re-enter, drill some more, and pull back out again. Continue in this fashion until successfully through the coal bed. The key word in successfully drilling the coal beds is patience. It should be remembered that coals behave plastically, and will flow under the weight of the overburden. The deeper the coal, the more pronounced this tendency becomes. For this reason it is critical to maintain the proper weight and viscosity of the drilling fluid to properly remove the coal cuttings, and to hold flowing coals in place. Again, heed the recommended drilling fluid program and advice offered by the on-site Mud Engineer. Well Proximity Risk There is no close approach risk associated with drilling Lone Creek #4. The nearest well activity lays 2/3 of a mile SSW on the Lone Creek #3 drillsite. -' Other Risks Sticky bentonitic clays, boulders, lost returns & differential sticking with overbalanced muds and gas influx while cementing or swabbing while tripping pipe. Prepared by Jack McDade Page 8 of 11 Rev. 1.0 (Draft) Aurora Gas, 9 se Creek #4 Drilling Program ;v: !" Gas, LLC Lone Creek #4 Proposed Configuration Drill 10-5/8" Hole to 750' { 2-7/8" x 5-'/" annulus to be displaced over to inhibited packer fluid through sleeve @ 845' Beluga Tops Tsuga 2-8— 924'MD 886' TVD Tsuga Tyonek Tops Carya 2-1.0 — 1,514' MD 1,329' TVD Carya 24.0 — 2,325' MD 2,145' TVD Carya 24.2 — 2,486' MD 2,306' TVD Carya 2-5.2 — 2,899' MD 2,719' TVD Carya 2-6.0 — 3,100' MD 2,920' TVD Carya 2- Tyonek Perforation Intervals to be determined by open -hole logging. Carya 2- Carya 2-4. Carya 2-5. Carya 2-6 Drill 7 5/8" Hole to 3,285' Estimated PBTD @ 3,240 Prepared by Jack McDade Rev. 1.0 (Draft) 2 7/8 6.5# 8rd EUE J-55 Tubing 13-3/8" 72# Structural Conductor to be drilled to 80' I-5/8" 32# Surface Casing set at 750' gement w/ 14.5 ppg Gas -Block nhanced hiding sleeve 1 joint above packer Iydraulic Set Packer @ - 900' hiding Sleeve @ — 925' Iraulic Set Packer @ 1,475' Aiding Sleeve @ —1,525' 6.5# EUE 8rd Tubing w/ Seal ibly to Retrievable Seal Bore Packer D0' hiding Sleeve @ --2,350' MD Iydraulic Set Packer @ 2,850'MD w/ 5.31 profile XN nipple '8" 6.5# EUE 8rd Tubing & Sand elusion Screens to — 3,225' MD Drill 7-7/8" Hole to 3,285' 55.5# K-55 Casing to 3,285' MD 3,100' 1 Page 9 of 11 Aurora Gas, se Creek #4 Drilling Program CL d 0 0 Drill 10-5/8 Interval R n 8-5/8 Ca ing Drill? -7/8 Interval Lo Test, Well, Run 5- I/2 Casing, Pe orate, 500 1,000 1,500 M 2,000 h d 2 2,500 3,000 3,500 4,000 Lone Creek #4 Days vs Depth 5 10 15 20 25 30 Days Prepared by Jack McDade Page 10 of 11 Rev, 1.0 (Draft) Aurora Gas, 0 Moquawkie #4 ge Creek #4 Drilling Program Summary of Drilling Hazards POST THIS NOTICE IN DOGHOUSE � There is potential for abnormal pressured shallow gas. There is potential for stuck pipe in coals encountered while drilling from surface to TD. Short trips as dictated by drilling trends. � There is no H2S risk anticipated for this well. Due to potential for shallow gas kick, very little response time will be afforded to respond. PVT and gas detection systems must be fully operational and functioning at all times, visual flow checks and , pit level monitoring are critical. CONSULT THE LONE CREEK #4 WELL PLAN FOR ADDITIONAL INFORMATION Prepared by Jack McDade Page 11 of 11 Rev. 1.0 (Draft) Aurora Gas LLC, Rig Acceptance Checkhst Rig: Aurora Well Service #1 Well: Lone Creek #4 Inspection Date: Inspected By: I. DRILL SITE _ d. Flashing red light on crown a AUTHORIZED PERSONNEL signs _ e. Bumper sills installed on crown posted _ f. Hinge points, structural cross members free — b. HARD HAT/SAFETY GLASSES of damage, cracks, and excessive corrosion signs posted — g. Derrick ladder in safe condition _ c. NO SMOKING areas designated _ h. Crown block in good condition; regularly _ d. H2S controls if applicable maintained _ e. Escape and guy lines flagged VI. BLOWOUT PREVENTERS _f. Hard hats/Safety glasses available _ a. B.O.P. properly installed, tested for visitors _ b. Wheels and stems in place II. DOG HOUSE _ c. Stack properly stabilized — a. Adequate exits, doors installed _ d. All hydraulic lines connected properly, operate freely _ e. All unused lines capped _ b. Approved heaters used _ f. Accumulator unit properly located _ c. General housekeeping _ g. Gauges properly located — d. First aid kit and facilities _ h. Housekeeping, drainage _ e. Crew trained in first aid _ i. Choke manifold and line, secured —f. Emergency phone numbers posted _j. Blooey line used, pilot light used — g. Two-way radio provided _ k. Approved and adequate lighting _ h. Safety equipment available _ I. Signage — i. Crew wearing hard hats and safety _j. BOPE rated working pressure adequate for glasses planned work —j. Crew wearing hard -toed shoes _ k. Remote closing station properly located _ k. Proper clothing worn by crew _ I. No short bolts, loose or missing nuts I. No hazardous jewelry worn _m. Adequate number of BOPE closing methods m. NO SMOKING rules observed handrails or laid across walkways _ _ n. OSHA log posted _ accidents —n. Accumulator controls labeled, handles in _ o. B.O.P. drills, test logged open or closed position with blind handle — p. Safety meetings logged guarded q. Driller at or near controls _o. Accumulator relief line vented to hydraulic tank r. Toolpusher/Rig Manager at rig — p. Control line condition, steel or armored hose location _ q. Blast points on headers protected by _ s. Approved and adequate lighting targeted plugs —t. Hazard communication/MSDS — r. Personnel trained in operation of BOP'S, crew Sheet on site assignments for shut-in procedures posted 111. DRILLING FLOOR AREA _ s. BOPE securely braced to substructure _ a. Rotary table area _t. Mud gas separator secured _ b. Kelly bushing guard used VII. PIPE RACK AREA _ c. Controls adequate if no guard used _ a. Ends of pipe racks chocked _ d. Rotary chain drive guarded _ b. Layers of pipe chocked, spacers used _ e. All unused floor holes covered _ c. Pipe racks level, stable _f. General housekeeping, lighting _ d. Stairs with handrails provided — g. Pipe slips, dies _ e. Vee door slide, pipe stops used _ h. Racking floor area _ f. Pipe tubs and bridles _ i. Vee door gate provided, in place _ g. Derrick stand and ladder —j. Makeup and breakout tongs _ h. General housekeeping, lighting _ k. Tong snubbing lines, clamps _ i. Dead end of drilling line elevated _ I. Tong counter weights _ j. Employees not on top of pipe _ m. Tong body and jaws condition VIII. DERRICK BOARD AREA _ n. Tong safety handle pin secured _ a. Derrick ladder _ o Tong dies sharp, keeper used _ b. Derrick climber installed and used — p. Air hoist line, guide guarded _ c. Safety belt, safety catch q. Catheads _ d. Safety lines or lanyards used _ r. Catlines _ e. Derrick emergency escape line — t. Spinning chain, headache post _ f. Geronimo on line and ready for use u. Crown -O -Matic device, operating — g. Pipe fingers and tools secured —v. Drilling line _ h. Mud standpipe secured —w. Drawworks and overrunning _ i. Mudhose snubbed on both ends clutch IX. MUD PUMP AREA — x. Driller's controls —a. Drive belts, pony rods guarded — y. Hand tools, bench grinders _ b. Head and valve covers fully bolted Z. Gauges and meters functional c. Shear pin pop-off valve covered/tested XII. GENERATOR AREA _ a. Generators properly located b. All generator moving parts secured _ c. Generators properly grounded d. Cover panels on electrical control boxes _ e. Emergency lighting provided in SCR building _ f. HIGH VOLTAGE warning signs used — g. SCR doors closed, A.C. unit properly working _ h. All electrical tools grounded _ i. Condition of electrical wiring _j. Electrical wires properly strung _ k. Unused electrical outlets covered _ I. Air compressors properly guarded _ m. Air storage tanks equipped with pop-off _ n. General housekeeping, lighting _ o. Hearing protection available — p. Wiring, motors, receptacles, switches, lighting, etc. meet code requirements — q. Use of household electric outlets on rig or associated equipment prohibited _ r. Electrical control boxes marked "Danger High Voltage" and state voltage _ s. Dielectric mats in front of all electric control boxes _ t. S.O. electric cords properly routed – not tied to XIII. FUEL STORAGE TANKS _ a. Fuel storage tanks properly located b. All storage valves marked as to connects _ c. Discharge nozzles, hoses, valves d. Piping and fuel lines _ e. General housekeeping, lighting _ f. Stationary ladders on storage tanks XIV. FIRE PROTECTION _ a. Adequate fire extinguishers — b. Tanks properly vented c. Flammables in U.L. safety cans _ d. NO SMOKING rules enforced _ e. Flare area clear of combustibles _ f. Boiler and its safety controls g. Welding performed safely — h. Spark and heat arrester on engines — I. Fire extinguishers inspected, charged, tagged and sealed j. Personnel are trained in the use of portable fire extinguishers k. Flammable/combustible liquids are properly labeled and stored — I. Oily rags/waste picked up and stored in closed metal containers m. Engines equipped with spark arresting mufflers and emergency shutdown device XV. HYDROGEN SULFIDE _ a. Appropriate warning signs _ b. H2S monitors, alarms _ c. Briefing areas, breathing equipment _ d. Site specific training _ e. Contingency Plans available XVI. HOISTING EQUIPMENT _ a. Number of wraps on hoisting drum b. Drilling Line conditions, ton miles records available, slipped and cut as required — c. Condition of brake pads and flanges, brake linkage adjustment, retainer pins in place 0 • . - Il} III Sperry Drilling Services Proposal Report - Geographic 03 July= 2007 Local Coordinate Origin: Vieviing Datum: TVDs to System: North Reference: Unit System: Aurora Gas, LLC Cook Inlet Lone Creek Lone Creek 4 Lone Creek No. 4 RECEIVED UL 4 6 2007 Alaska Oil & Gas Con's C' nissiotl' Anchor e Centered on Weil Lone Creek 4 389.15 + 16 @ 405.15ft (Aurora WS #1) N True API - US Survey Feet HALLIBURTON Sperry Drilling Services Project. Cook Inlet Site: Lone Creek Well: Lone Creek Aurora Gas, LLC Wellbore: Lone Creek No. 4 Plan: Lone Creek No. 4 wp01 HALLIBURTON Sperry Drilling Services DDI = 4.61 150 ^� CASING DETAILS REFERENCE INFORMATION No ND MD Name Size Co-ordinate (N)E) Reference: Well Lone Creek 4, True North 1 750.00 750.00 8 5/8" 8-518 Vertical (TVD) Reference: 389.15 + 18 Q 405.15ft (Aurora WS #1) 2 3475.09 3580.80 5 1/2' 5-112 Measured Depth Reference: 389.15 + 16 (CD 405.15ft (Aurora WS 01) Calculation Methud: Minimum Curvature WELLBORE TAROT DETAILS (MAP CO.ORDINATES AND L.411ONG) --- Name ------ TVD +N/ -S +E/ -W Northing Eating Latitude Longitude Shape LC4 T1 3325.15 -142.35 478.70 2611153.63 273270.03 61'826.995N75196'58958W Point RECTION DETAILS COMPANY DETAILS: Aurora Gas, LLC --------------------------- Seo MD Ino Axl TVD -W-S +E/ -W 01-TFaca VSec Target Drilling 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2 760.00 040 0.00 750.00 0.00 0.00 0.00 0.00 0.00 Calculation Method: Minimum Curvature 3 4 1478,00 3247 253." 1437.29 67.42 -193.08 4.50 0.00 201.43 1654.88 32.67 253." 1587.88 -84.94 -285.82 0,00 0.00 297.98 Error System: 1SCWSA 8 2380.88 0.00 0.00 2275.15 -142.35 476.70 4.50160.00 499.42 Scan Method: Tray. Cylinder North 6 3430.88 0.00 0.00 3325.15 -142.35 .478.70 0.00 0.00 499.42 LC4 T7 Error Surface: Elliptical Conic 7 3580.86 0,00 0.00 3475.15 -142.35 478.70 0.00 0.00 499.42 WamingMethod: Rules Based WELL DETAILS: Lone Creek4 Ground Leval: a89.15 Northing Eaetlng Latitude ode node Longitude 0.00 2611288.58 273751.40 61'6'28.397N 151 ° 18'49.207W End Dir : 1476'MD, 1437.29'TVD Stan Dir 4.5°.' 100' : 1654.86' MD, 1587.86'TVD so - End C Dir : 2380.86' MD, 2275,15' TVD 0- g Total Depth: 3580.86' MD, 3475.15' TVD o - 7 -100-- r Lone Creek 4/Lone Creek No 4 wp01 LC4 T1 -200 CARYA 2.4.0 -230 - CARYA 2-4.2 CARYA 2.5 .2 CARYA 2.6.0 1.50 Stan Dir 4.5'1100': 750' MD, 750TVD - 100 ' S0 O 0 OS -50 g -100 5' TSUGA 2-8 CARYA 2-1 -150 -200 -300- -300 i -700 -650 -600 -550 -500 450 -400 -350 -300 -250 -200 -150 -100 -50 0 50 100 150 200 West( -)/East(+) (100 Olin) Project: Cook Inlet Site: Lone Creek Well: Lone Creek 4 Wellbore: Lone Creek No. 4 Plan: Lone Creek No. 4 wp01 8 11/81, 'TSUGA 2-8 1200 CARYA 2-1 42 " 1500 - LD - 1800 CARYA 2-4.0 2100 03 - 1-t 2400- CARYA 2-4.2 2700- - CARYA 2-5.2 3000-- CARYA 2-6.0 Nlwe TD 42M 411,70 U,". A27.1w 1Rwtlq 6.9- TIVI'll'-1 vl.�' Rbq HALLIBURTON Aurora Gas, LLC Sperry Drilling Services SECTION DETAILS Sec MD Ino An TVD +NI -S +FJ.W DLgg TF= VScc Tarpt 1 0,00 0,00 0.00 0.00 0'w 000 0.00 0.00 0.00 DDI 3 0(11) 0.00 750,00 0.00 000 0.00 0.00 0.00 4.61 CASING DETAILS 32 70'0 1476000 32.67 25344 1437.29 -57,42 -193.08 4.50 0,00 201.43 No TVD MID Name SIn 4 1654.86 3267 23344 15117.116 -8C94 -285.62 0.00 0,00 291.911 1 75000 750,00 853, NIS 5 2380,86 0.00 0.00 2275.15 -142,35 -478,70 4.50 ISOM 499.42 2 3475.09 3580.80 5112" 5-1t2 6 3430.86 0.00 000 3325,15 -142.33 -47870 0.00 0,00 499.42 LC4Tl 7 3580.86 000 0.00 3475.15 -142.35 -473,71) 0.00 0.00 499,42 COMPANY DETAILS: Aurora Ges, LLC FORMATION TOP DETAILS REFERENCE INFORMATION - --------- --- F--- No.TVOPsth MDPath Formation Co-ordInsta (WE) Reference. Well Lone Creek 4, True North Drilling 1 005.15 9175.54 TSUGA 2.8 Vertical (TVD) Reference: 389.15 + 15 405.1 Sft (Aurora WS #1 1 1345.151369.25 CARYA 2.1 Measured Depth Reference: 389.15 + to 1 405.1 5ft (Aurora WS .1� Calculation Method. Minimum Curvature 2155.152260.68 CARYA 2-4.0 Calculation Method: Minimum Curvature Error System: ISCWSA 2315,.,152420.96 CARYA 2-4.2 52830. 86 CARYA 2-5.2 Scan Method: Tmv. Cylinder North 0 2925.15 30300 CARYA 2-6.0 Error Surface: Elliptical Conic Warning Method! Rules Based Start Dir 4.50/100' 750' MD, 7507VO WELL DETAILS: Lone Creek 4 Ground Level: 389.15 Northing Easting Latittude Longitude Slot 000 2611286.58 273751.40 6118'28.397N 151'16'49.207W End Dir 1476' MD, 1437.29' TVD Start Dir 4.5°/100' : 1654.86' MD, 1587.86'TVD End Dir :2380.86'MD, 2275.15' TVD Total Depth : 3580.86' MD, 3475.15' TVD Lone Creek 4/Lone Creek No. 4 wp01 r FT-7-rT--7--T�-T-T-T-Fr'1 T_T7__T I T- �- T 7 -1600 -1200 -900 -800 -300 0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 Vertical Section at 253.44' (750 ft/in) 900 1200 C: (D 1500 < 1800 @ ti 2101) '� U1 2400 2700 3300 0 0 Halliburton Company Compass Proposai Report - Geographic 0 Database. Sperry EDM .11 Local Co-orrtl J gbrerrce: Well Lone Creek 4 may: Aurora Gas, LLC TVD Reb encs: 389.15 + 16 @ 405-1511 (Aurora WS #1) Project: Cook Inlet MD Reference: 389.15 + 16 @ 405.1 Sit (Aurora WS #1) Site: Lone Creek North Reference: True Well: Lore Creek 4 Surrey Calculation Method: Knimuan Curvature Wellbore: Lone Creeds No. 4 Dogleg Design: Lone Creek No. 4 wp01 Cook Inlet, USA Nap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Mum: NAD 1927 (NADCON CONUS) Nap Zone: Alaska Zone 04 Using geodetic scale factor Well Lone Creek 4 Well Position +W -S 0.00 ft Northing: 2,611,286.58 It Latitude: 61 ° 08' 28.397" N +E/ -W 0.00 ft Easting: 273,751.40 it Longitude: 151' 16'49.207"W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 389.15 ft Wellbore Lone Creek No. 4 Magnetics No" Name Sante® Date Decoration . Dip Angle Field Saength (°1 i) (nT) BGGM2007 71M007 19.30 73.90 55,632 Design Lore Creek No. 4 wp01 Audit Notes: Version: Phase: PLAN Tie On Depth: 0.00 Vertical Section: Depth From (TVD) +N1 -S +Ef- W Direction Pq (it) (n) ' (1) 0.00 0.00 0.00 253.44 Plan Summary Measured Dogleg Build Tum Depth Inctination Azimuth TVD TVDSS +w -S +E/ -4W Rate Rale Rate TFO (n) 0 r) (n) (it) (n) (n) ("noon! Cr wM (noon) C) 0.00 0.00 0.00 0.00 -405.15 0.00 0.00 0.00 0.00 0.00 0.00 750.00 0.00 0.00 750.00 344.85 0.00 0.00 0.00 0.00 0.00 0.00 1,476.00 32.67 253.44 1,437.29 1,032.14 -57.42 -193.08 4.50 4.50 0.00 0.00 1,654.86 32.67 253.44 1,587.86 1,182.71 -84.94 -285.62 0.00 0.00 0.00 0.00 2,380.86 0.00 0.00 2,275.15 1;870.00 -142.35 -478.70 4.50 -4.50 0.00 180.00 3,430.86 0.00 0.00 3,325.15 2,920.00 -142.35 -478.70 0.00 0.00 0.00 0.00 3,580.86 0.00 0.00 3,475.15 3,070.00 -142.35 -478.70 0.00 0.00 0.00 0.00 7;312 007 S-'. -- .51,7 rage s ^° Y C;rORv'r;"` ..- s;-rl€�a. j uu?f 46 • Halliburton Company Compass Proposal Report - Geographic Dalabaw. Sperry EDM .11 - Local Co-ordinid0 Reference: Well Lone Creek 4 Con4my. Aurora Gas, LLC TVD Reference: 389.15 + 16 @ 405.15ft (Aurora WS #1) Project: Cook Inlet MD Reference: 389.15 + 16 Q 405.15ft (Aurora WS #1) Site- + Lone Creek North Reference: True Wept Lone Creek 4 Surrey Calculation Meiftod: ' " Minimum Curvature Wellbore: Lone Creek No. 4 -205.15 0.00 Design: tone Creek No. 4 wrp01 273,751.40 300.00 01 map TVDSS +w -S 404111 Na rw" Easiling DL.SV Vert: iR? 11% (it) VQ � C1100nt) ( 0.00 0.00 0.00 0.00 -405.15 0.00 0.00 2,611,286.58 273,751.40 100.00 0.00 0.00 100.00 -305.15 0.00 0.00 2,611,286.58 273,751.40 200.00 0.00 0.00 200.00 -205.15 0.00 0.00 2,611,286.58 273,751.40 300.00 0.00 0.00 3W00 -105.15 0.00 0.00 2,611,286.58 273,751.40 400.00 0.00 0.00 400.00 -5.15 0.00 0.00 2,611,286.58 273,751.40 500.00 0.00 0.00 500.00 94.85 0.00 0.00 2,611,286.58 273,751.40 600.00 0.00 0.00 600.00 194.85 0.00 0.00 2,611,286.58 273,751.40 700.00 0.00 0.00 700.00 294.85 0.00 0.00 2,611,286.58 273,751.40 750.00 0.00 0.00 750.00 344.85 0.00 0.00 2,611,286.58 273,751.40 Start Dir 4.6011W : 750' MD, 7507VD - 8 5/8" 4.50 321.67 1,800.00 26.14 253.44 800.00 2.25 253.44 799.99 394.84 -0.28 -0.94 2,611,286.32 273,750.46 900.00 6.75 253.44 899.65 494.50 -2.52 -8.46 2,611,284.23 273,742.90 905.54 7.00 253.44 905.15 500.00 -2.70 -9.09 2,611,284.06 273,742.26 TSUGA 2-8 4.50 442.88 2,100.00 12.64 253.44 1,996.56 1591.41 -133.56 1,000.00 11.25 253.44 998.40 593.25 -0.97 -23.45 2,611,280.07 273,727.82 1,100.00 15.75 253.44 1,095.61 690.46 -13.63 -45.82 2,611,273.86 273,705.33 1,200.00 20.25 253.44 1,190.69 785.54 -22.43 -75.43 2,611,265.63 273,675.55 1,300.00 24.75 253.44 1,283.05 877.90 -33.34 -112.10 2,611,255.45 273,638.67 1,369.28 27.87 253.44 1,345.15 940.00 -42.09 -141.53 2,611,247.27 273,609.08 CARYA 2-1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 4.50 0.98 4.50 8.83 4.50 9.49 4.50 24.46 4.50 47.80 4.50 78.70 4.50 116.96 4.50 147.66 1,400.00 29.25 253.44 1,372.13 966.98 -46.27 -155.61 2,611,243.36 273,594.93 4.50 162.34 1,476.00 32.67 253.44 1,437.29 1032.14 -57.42 -193.08 2,611,232.96 273,557.25 4.50 201.43 End Dir : 1476' MD, 1437.29' TVD 1,500.00 32.67 253.44 1,457.50 1052.35 -61.11 -205.50 2,611,229.51 273,544.76 0.00 214.39 1,600.00 32.67 253.44 1,541.68 1136.53 -76.50 -257.24 2,611,215.14 273,492.73 0.00 268.37 1,654.86 32.67 253.44 1,587.86 1182.71 -84.94 -285.62 2,611,207.25 273,464.19 0.00 297.98 Start Dir 4.rd°(10o' : 1654.86' MD, 1587.867W 1,700.00 30.64 253.44 1,626.28 1221.13 -91.69 -308.33 2,611,200.95 273,441.35 4.50 321.67 1,800.00 26.14 253.44 1,714.23 1309.08 -105.24 -353.89 2,611,188.29 273,395.54 4.50 369.20 1,900.00 21.64 253.44 1,805.64 1400.49 -116.78 -392.69 2,611,177.52 273,356.52 4.50 409.69 2,000.00 17.14 253.44 1,899.95 1494.80 -126.24 -424.51 2,611,168.68 273,324.53 4.50 442.88 2,100.00 12.64 253.44 1,996.56 1591.41 -133.56 -449.13 2,611,161.84 273,299.77 4.50 468.57 2,200.00 8.14 253.44 2,094.90 1689.75 -138.70 -466.41 2,611,157.04 273,282.39 4.50 486.59 2,260.68 5.41 253.44 2,155.15 1750.00 -140.74 -473.27 2,611,155.14 273,275.49 4.50 493.75 CARYA 2-4.0 2,300.00 3.64 253.44 2,194.35 1789.20 -141.62 -476.24 2,611,154.31 273,272.50 4.50 496.85 2,380.86 0.00 0.00 2,275.15 1870.00 -142.35 -478.70 2,611,153.63 273,270.03 4.50 499.42 End Dir : 2380.86' MD, 2275.15' TVD 2,400.00 0.00 0.00 2,294.29 1889.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 2,420.86 0.00 0.00 2,315.15 1910.00 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 CARYA 2-4.2 2,500.00 0.00 0.00 2,394.29 1989.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 2,600.00 0.00 0.00 2,494.29 2089.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 2,700.00 0.00 0.00 2,594.29 2189.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 7)WO0711:34:47AM Page 3 of 5 COMPASS 2003.11 Budd 48 0 0 Halliburton Company Compass Proposal Report - Geographic Planied Lone Creek No. 4 wp01 Atop AD lad Admuft M ((tj TVDSS +W -S 4E/ -W DLWV sq (°i (°► 014 (ft) 2,800.00 0.00 0.00 2,694.29 2289.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 2,830.86 0.00 0.00 2,725.15 2320.00 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 CARYA 2-5.2 2,900.00 0.00 0.00 2,794.29 2389.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 3,000.00 0.00 0.00 2,894.29 2489.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 3,030.86 0.00 0.00 2,925.15 2520.00 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 CARYA 2.6.0 3,100.00 0.00 0.00 2,994.29 2589.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 3,200.00 0.00 0.00 3,094.29 2689.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 3,300.00 0.00 0.00 3,194.29 2789.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 3,400.00 0.00 0.00 3,294.29 2889.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 3,430.86 0.00 0.00 3,325.15 2920.00 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 LC4 T1 3,500.00 0.00 0.00 3,394.29 2989.14 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 3,580.86 0.00 0.00 3,475.15 3070.00 -142.35 -478.70 2,611,153.63 273,270.03 0.00 499.42 Total Depth: 3580.86' MD, 3475.15' TVD - 5112" 7/3200711:34:47AM Page 4 of 5 COMPASS 2003.11 Build 48 Halliburton Company Compass Proposal Report - Geographic Vallobaw Sperry EDM .11 LAcar: Rofwwmw. Well Lone Creek 4 Coinpaur. Aurora Gas, LLC TVV389.15 + 16 @ 405.15ft (Aurora WS #1) Cook Inlet MD , 389.15 + 16 @ 405.15ft (Aurora WS #1) SFEs:; Lone Creek Ictal* Itefolermw True 4 Lone Creek 4 Sar4W Minimum Curvature fft) (IIIIII Lone Creek No- 4 0.00 tune I Lone Creek No. 4 wp01 7.00 Pr+ogrloe#r1 FOWASIN104 Ind Palms + Aziurtua TW TV W +W -E (M fm 4 (°j (6) fft) (IIIIII 750.00 0.00 tune 905.54 7.00 253.44 905.15 -2.70 -9.09 TSUGA 2-8 1,369.28 27.87 253.44 1,345.15 -42.09 -141.53 CARYA 2-1 2,260.68 5.41 253.44 2,155.15 -140.74 -473.27 CARYA 2-4.0 2,420.86 0.00 0.00 2,315.15 -142.35 -478.70 CARYA 2-4.2 2,830.86 0.00 0.00 2,725.15 -142.35 -478.70 CARYA 2-5.2 3,030.86 0.00 0.00 2,925.15 -142.35 -478.70 CARYA 2-6.0 PW Aare W" +NtdR +Ed,W C 750.00 750.00 0.00 0.00 Start Dir 4.5°/100' : 750' MD, 750TVD 1,476.00 1,437.29 -57.42 -193.08 End Dir : 1476' MD, 143729' TVD 1,654.86 1,587.86 -84.94 -285.62 Start Dir 4.50/100': 1654.86' MD, 1587.86TVD 2,380.86 2,275.15 -142.35 -478.70 End Dir : 2380.86' MD, 2275.15' TVD 3,580.85 3,475.14 -142.35 -478.70 Total Depth: 3580.86' MD, 3475.15' TVD 7/31'200711:34:47AM Page 5 of 5 COMPASS 2003.11 Build 48 �7- Maunder, Thomas E (DOA) From: Ed Jones Dejones@aurorapower.com] Sent: Thursday, July 26, 2007 1:13 PM To: Maunder, Thomas E (DOA) Subject: RE: Moquawkie #4 0 rdgu 1 U1 1 Tom, x Lss-spoke when we discussed the production casing bit size by phone earl i talking off the top of my doing in recently do v Is and confirming this in a ion with Jack McDade, the p is indeed to run 7- 7/8" bits with either 9-5/8" or - g. Thus, please change any reference to 8-1 its e APD documents to 7-7/8" a e over e Nicolai Creek 10 wellse as emplate). Therefor ent volumes, calculated on the - ole will remain the same. Sorry for the it nvenience that my wrong answer caused. Also, to confirm my response on the other matter, we will not be in a position to drill the Moquawkie #4 until at Fast mid September and maybe later, depending upon the timing financial/ownership restructuring that Aurora is doing. Thanks, Ed Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage) From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, July 26, 2007 2:54 PM To: Ed Jones Subject: Moquawkie #4 Ed, I was making the changes, where necessary, from 7-7/8" to 8-1/2" hole in the permit package. There is one section I need you to update. The cement calculations are based on 7-7/8" hole. Upsizing to 8-1/2" without changing the planned volumes essentially eliminates your XS. I look forward to the updated numbers. Call or message with any questions. Tom Maunder, PE AOGCC 7/26/2007 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501 THE APPLICATION OF Aurora Gas, LLC for ) Conservation Order No. 590 an exception to the spacing requirements of 20 AAC ) 25.055(a)(4) to allow for the drilling, completion, ) Lone Creek No. 4 testing and regular production of the Lone Creek ) Development Gas Well No. 4 gas development well within 3,000 feet of ) another well capable of producing from the same ) September 13, 2007 pool. ) IT APPEARING THAT: Aurora Gas, LLC ("Aurora"), by a letter dated June 20, 2007 and received by the Alaska Oil and Gas Conservation Commission ("Commission") on that same day, has requested an order for an exception to the spacing requirements of 20 AAC 25.055(a)(4) to allow for the drilling, completion, testing and regular production of the Lone Creek No. 4 gas development well within 3,000 feet of another well capable of producing from the same pool. Pursuant to 20 AAC 25.540, on June 25, 2007, the Commission published in the Anchorage Daily News notice of opportunity for public hearing on July 26, 2007. 2. No protests to or comments on the application or requests for a hearing were received. 3. The Commission vacated the public hearing on July 23, 2007. FINDINGS: 1. Aurora sent notice of the application for an exception to the well spacing requirements of 20 AAC 25.055(a)(4) by certified mail to all owners, landowners, and operators of all properties within 3,000 feet of the proposed Lone Creek No. 4 well. 2. Lone Creek No. 4 is proposed as a gas development well with a surface location of 1,193 feet from the south line and 140 feet from the west line of Section 8, T12N, R11 W, Seward Meridian. The bottom hole location is 1,060 feet from the south line and 341 feet from the east line of Section 7, T12N, R11 W, Seward Meridian. 3. Lone Creek No. 4 would lie within lease C-061395, and it would penetrate reservoirs in the Beluga and Tyonek Formations. 4. Aurora is the owner and operator of lease C-061395. Cook Inlet Region, Inc. ("CIRI") is the only affected landowner. 10 I 5. Lone Creek No. 3 is an active gas producer about 2,900 feet to the southwest of Lone Creek No. 4 and is open to the Beluga Formation. 6. Lone Creek No. 4 may be completed in the Beluga Formation and Tyonek Formation reservoirs, which are typically lenticular and laterally discontinuous. However, some of the perforated zones in Lone Creek No. 4 might be continuous with those in Lone Creek No. 3. CONCLUSIONS: 1. An exception to 20 AAC 25.055(a)(4) is necessary to allow for the drilling, completion, testing and regular production of the Lone Creek No. 4 gas development well. 2. Granting a 20 AAC 25.055(a)(4) exception to allow for the drilling, completion, testing and regular production of the Lone Creek No. 4 well will not jeopardize the correlative rights of adjoining or nearby owners, operators or landowners. 3. To prevent waste of resources, Aurora must know the impact, if any, of Lone Creek No. 4 production on reservoirs penetrated by Lone Creek No. 3. NOW, THEREFORE, IT IS ORDERED: Aurora's application for an exception to the well spacing provision of 20 AAC 25.055(a)(4) for the purpose of drilling, completion, testing and regular production of the Lone Creek No. 4 well is approved on the condition that Aurora complies with the terms of all applicable Alaska and federal laws and regulations, including the requirements identified below: 1. Within 60 days after the Lone Creek No. 4 well has been in regular production for 24 months, Aurora shall provide to the Commission a technical report presenting geological, geophysical, reservoir and production information that identifies: a. whether hydraulic communication exists between Lone Creek No. 4 and Lone Creek No. 3; and b. the areal extent and volume of each gas accumulation penetrated by Lone Creek No. 4. 2. If hydraulic communication between these wells is established with reasonable certainty, Aurora shall immediately undertake appropriate measures, such as applying for pooling or unitization orders, to ensure resources are not wasted. Within 90 days after Aurora learns or should have learned of such hydraulic communication, Aurora shall report to the Commission on the success of those measures and undertake any additional measures that Conservation Order No. 590 Effective September 13, 2007 Page 2 of 3 Aurora determines are necessary or that are required by the Commission to ensure that waste of oil and gas is prevented. DONE at Anchorage, Alaska, and dated %7 Alaska Oilo�d Gas Conservation Commission ow-� Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission Cathy P. Foerster, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23`d day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10 -day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30 -day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10`h day after the application for rehearing was filed). Conservation Order No. 590 Page 3 of 3 Effective September 13, 2007 ,I -1cl�rIxI I —v uf<4t- 115003313911, 1: 2 5 2000 601: C TRANSMITTAL LETTER CHECKLIST WELL NAME (ani PTD!# Z.C>?"-C71 ✓ 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 I %TIAT I (OPTIONS) APPLIES J MULTILATERAL The permit is for a new wellbore segment of existing well (If last two digits f in I permit Yo. API No. 50- - - , I API number are between 60-69) Production should continue to be reported as a function of the f original API number stated above. PILOT KOLE i 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 ff (50- from records, data and logs j f acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION f 25.055. Approval to perforate and oroduce't is contingent upon issuance of a conservati9� order ap,�roving a spacing j ��C M exception. lr+o�-ru C' assumes the liability of any protest to the spacing exception that may occur. 1 DRY DITCH J All dry ditch sample sets submitted to the -Commission must be in i SAMPLE i 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: 1 j Non -Conventional production or production testing of coal bed methane is not allowed { j Well for (name of well) until after (Cotnpanv Name) has designed and 1 ' implemented a water well testing program to provide baseline data j on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing pcogra_cn.-- - Rev: 125i06 C:+jody\tmrtsmAa!_checkl ist ' ' £ Field & Pool LONE CREEK, UNDEFINED GAS - 505500 Well Name: LONE CREEK 4 Program DEV g Well bore seg ❑ PTD#:2070910 Company AURORA GAS LLC Initial Class/Type DEV / PEND GeoArea 820 Unit 51260 On/Off Shore On Annular Disposal Administration 1 Permit_fee attached- - - - - - - - - - - - - - - - - - Yes - _ _ _ i2 Leasenumberappropriate---------------------------- - - - - - - - - - - - Yes - - - - - --CI_RlLeaseC-061395 - - - - 3 Uniquewell_nameandnumber------------------------------------- Yes--------------------------- -------------------------------------- ------ j4 Well located in-a_define_d_pool_ - _ - _ _ _ No_ LONE CREEK, UNDEFINED -GAS_ -_505500_ _ ----- - 5 Well located proper distance from drilling unit _boundary - - - - - - - - - - . - _ - - - - - - - - - Yes - - - - - - - 4300'_west_of east boundary of_the. Moquawkie Unit, - - - - - - - - - - - - - - - - - - - - - - - - - �6 Well located proper distance from other wells_ _ - - - _ _ .. - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ _ - _ _ _ - -SPACING EXCEPTION APPROVED BY CO 59.0: shallowest perf_in LC #3 is 2933' from TD of_L_C_#4. ;7 Sufficient acreage_avail_able in drilling unit- - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes Will_be only well open to the pool in Section 8. The only other_well in -the section -is Chu -it 2, P&A'd in 1962. 8 If_deviated, is wellbore plat_included - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -N_o_ - - - - - - - 6/28/07: Requ_est_plat from Jack McDade, _ - - _ - - - - - - - - - - - - - - - - - - . - - - _ - - - - _ - - - - - - - - - - 9 Operator only affected party- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes Aurora was designated operator of the Moquawkie Unit in Feb 2003._ - - - - - - 10 Operator has -appropriate bond in force - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - _ _ - _ _ - Aurora became -100%o WIO for the_unit in -Q4_ of 2006_ _ _ - _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - - 11 Permit can be issued without conservation order No SPACING EXCEPTION APPROVED BY COMMISSI.ON_IN CO.590-- - - - - - - - - - - - Appr Date 12 -Permit- can be issued -without administrative -approval - - - - - - - - - - - - - - - - - - - - - - - - Yes - - _ - - - _ - - - - - - SFD 6/28/2007 113 Can permit be approved before 15 -day wait No j14 Well -located within area and -strata authorized by Injection Order # (put 10# in comments)_ (For NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 115 All weUs_within 1/4_mile_area_of review identified (For service well only)- - - - - - - - - - - - - - NA_ - - - - _ - - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ - - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 16 Pre -produced injector-. duration -of pre -..production Less than 3 months- (For -service well only) - NA_ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - . _ - - .. _ - - - - - _ . - 17 _N_onconven. gas conforms .toAS31.05.030(j.1_.A),Q.2.A-D) - --- -- NA- --- -- - - - - ----- --- --- - - - - --- - - - - -- - - - -- - --- -- - - - Engineering 118 Conductor string_provded - - - - - - - - - - - - - - - - Yes _ - - - - - - - - - - - - - - - - - - - - - - - - - - - 119 Surface casing_ protects all -known USDWs - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Surface and..production casings will protect any FW sands. _Based on_area_drilling, gas could be present at_ - - - - ',20 CMT-v_ol_ adequate to circ_ul_ate-on conductor & surf csg - - - - - - - - - - _ - - - - - - - Y_es - - - - - - - - or -near-the surface casing shoe. - - 121 CMT-v-ol adequate to tie-in -long string to -surf csg_ - - - - - Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .. - _ - _ _ _ _ _ _ _ _ _ 22 -C-MT will coverall known -productive horizons_ - - - - - - - - Yes _ - - - - - - - _ - - - - 23 Casing designs adequate for C,_T,B&permafrost- .. - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - .. - - - - - - - 24 Adequate tankage or reserve pit - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Rig is_equipped-with steel -pits. _Alt_hough relatively small, Aurora has successfully -drilled similar wells - 25 If_a- re -drill, has a_ 10-403 for abandonment been approved NA_ using the rig, Liquid drilling waste to Aspen disposal well. Solids_ to be washed and used on roads. 26 Adequate wellbore - I - - - - -- rop- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - I27 If_diverter required, does it meet regulations_ - - - - - - - - - Yes ---------- Appr Date 28 Drilling fluid_ program schematic_& equip -list -adequate- - - - - - - - - - - - - - - Yes Maximum expected formation pressure _11 3 EMW._ Planned _MW up to 12.0 ppg. - - - - - - - - - - - - - - - - - - - - TEM 10/10/2007 29 _B_OPEs, do they meet regulation _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ 30 _B_OPE_press rating appropriate; test to -(put psig in comments)_ Yes _ _ _ MASP calculated -at 1519 psi, 3000 psi. BOP test_planned------------- 31 Choke, manifold complies w/API_ RP -53 (May 84)_ - - - - - - - - - - Yes - 32 Work will occur without operation shutdown- - - - - - - - - - - - - - - - - - - - - - - - - Yes 33 Is presence of H2S gas probable - - - - - - - - - - - - - - - - ---- - - - - -- -- No.. - - - - - -- --- ------------------- 134 Mechanical_ condition of wells within AOR verified (For service well only) - - - - - - - - - - - - - NA_ - - - - - - - - - - - - - - - - - _ _ - - Geology 35 Permit can be issued w/o hydrogen_ sulfide measures . _ _ .. _ - Yes - - - H2S has not_ been encountered in this area or portion of the -geologic section, but the rig will -have- sensors. _ - - - _ ,36 Data presented on potential overpressure zones- - - - - - - - - - - - - - - - - - . Yes _ Expected pressure _gradient _is 11_.4 ppg_EMW._ Will -be drilled with up to_12.0_ppg mud -- - - - - - - - - - - - _ _ Appr Date 37 Seismic_ analysis of shallow gas zones - _ _ - - - - . - NA_ However, shallow gas is a known hazard in this area. Mudlo - _ ggers with gas monitoring equipment will be SFD 6/28/2007 138 Seabed condition survey -(if rf_ off -shore y ( ) - - - - - - - - - - - - _N_A- - - - - - - operational from base of conductor to_TD_. -Shallow-gas and noted in Summary of Drilling Hazards._ ,39 Contact name/phone for weekly -progress reports_ [exploratory only] _ NA. _ - Geologic Engineering c Date: Date Date SPACING EXCEPTION APPROVED BY COMMISSION IN CO 590: shallowest perf in LC 3 is 2933' from TD of LC 4. Commissioner: Commissioner: Co is ner 0
